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"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0169/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0171 | Supporting & Related Material | "2002-05-06T04:00:00" | null | epa | 2024-06-07T20:31:39.738159 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0171/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0172 | Supporting & Related Material | "2002-04-29T04:00:00" | null | epa | 2024-06-07T20:31:39.738842 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0172/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0173 | Supporting & Related Material | "2002-05-07T04:00:00" | null | epa | 2024-06-07T20:31:39.739604 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0173/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0174 | Supporting & Related Material | "2002-04-19T04:00:00" | null | epa | 2024-06-07T20:31:39.740299 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0174/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0175 | Supporting & Related Material | "2002-04-12T04:00:00" | null | epa | 2024-06-07T20:31:39.740985 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0175/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0176 | Supporting & Related Material | "2002-05-21T04:00:00" | null | epa | 2024-06-07T20:31:39.741698 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0176/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0177 | Supporting & Related Material | "2002-05-30T04:00:00" | null | epa | 2024-06-07T20:31:39.742455 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0177/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0178 | Supporting & Related Material | "2002-05-30T04:00:00" | null | epa | 2024-06-07T20:31:39.743224 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0178/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0179 | Supporting & Related Material | "2002-06-24T04:00:00" | null | epa | 2024-06-07T20:31:39.744031 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0179/content.txt"
} |
|
EPA-HQ-OAR-2001-0014-0180 | Supporting & Related Material | "2002-07-17T04:00:00" | null | epa | 2024-06-07T20:31:39.744832 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2001-0014-0180/content.txt"
} |
|
EPA-HQ-OAR-2002-0005-0001 | Supporting & Related Material | "2002-06-04T04:00:00" | null | Docket
NO:
OAR
2002
0005
0001
Criteria
for
the
Certification
and
Recertification
of
the
Waste
Isolation
Pilot
Plant's
Compliance
with
the
Disposal
Regulations;
Alternative
Provisions
Background
Information
Document
for
Amendments
to
40
CFR
194.8
(b)
U.
S.
Environmental
Protection
Agency
Office
of
Radiation
and
Indoor
Air
Washington,
DC
20460
July
2002
TABLE
OF
CONTENTS
I.
INTRODUCTION
...........................................................
1
A.
Current
Provisions
and
Summary
of
Pertinent
Elements
........................
1
B.
Waste
Components
and
Waste
Descriptions
.................................
2
B.
1
Radiological
Waste
Components
...................................
3
B.
2
Non
Radiological
Waste
Components
...............................
5
B.
3
General
Waste
Descriptions
......................................
5
C.
Description
of
Waste
Generators
.........................................
6
D.
Current
Inspection
Process
..............................................
8
II.
DESCRIPTION
OF
TECHNICAL
ELEMENTS
EXAMINED
........................
12
DURING
INSPECTIONS
A.
Acceptable
Knowledge
................................................
13
A.
1.
Overview
of
Technical
Elements
.................................
13
A.
2.
Technical
Description
of
System
or
Measurement
Device(
s)
............
14
A.
3.
Effect
of
Waste
Matrix
Type
on
Measurement
.......................
17
A.
4.
Scope
of
Possible
EPA
Approvals
for
Acceptable
Knowledge
..........
17
B.
Nondestructive
Assay
(NDA)
...........................................
18
B.
1
Overview
of
Technical
Elements
..................................
18
B.
2:
Technical
Description
of
System
or
Measurement
Device(
s)
............
19
B.
2.1
General
System
Information
.............................
19
B.
2.2
Neutron
Systems
.......................................
21
B.
2.3
Passive
Active
Neutron
Counters
.........................
23
B.
2.4
Photon
Emission
and
NDA
...............................
23
B.
2.5
Gamma
Ray
Spectrometry
Systems
........................
25
B.
2.6
Calorimetry
Instruments
................................
25
B.
3:
Effect
of
Waste
Matrix
or
Waste
Type
on
Measurement
................
25
B.
3.1
Neutron
Counting
Systems
...............................
26
B.
3.2
Photon
Measuring
Systems
..............................
27
B.
4
Scope
of
Possible
EPA
Approvals
for
Nondestructive
Assay
............
27
C.
Visual
Examination
and
Radiography
.....................................
28
C.
1
Overview
of
Technical
Elements
.................................
29
C.
1.1
RTR
Document
Review
..................................
29
C.
1.2
Additional
Verification
RTR
.............................
31
C.
1.3
VE
Document
Review
..................................
33
C.
1.4
Additional
Verification
VE
..............................
35
C.
2
Technical
Description
of
System
or
Measurement
Device(
s)
...........
37
C.
2.1
Radiography
..........................................
37
C.
2.2
Visual
Examination
....................................
38
C.
3
Effect
of
Waste
Matrix
or
Waste
Type
on
Measurement
...............
39
C.
4
Scope
of
Possible
EPA
Approvals
for
Radiography
and
Visual
Exam
....
39
D.
WIPP
Waste
Information
System
and
Data
Validation
........................
40
D.
1
Overview
of
Technical
Elements
.................................
40
D.
1.1
Data
Validation/
Verification
and
WWIS
Inspection
Components
41
D.
1.2
Demonstration
of
WWIS
Implementation
..................
42
D.
1.3
Personnel
Qualifications
...............................
42
D.
2
Technical
Description
of
Measurement
Device
......................
43
D.
3
Effect
of
Waste
Matrix
or
Waste
Type
on
Measurement
................
43
D.
4
Scope
of
EPA
Approvals
for
Data
Validation/
Verification
and
the
WWIS
..
44
III.
SUMMARY
OF
RESULTS
AND
LESSONS
LEARNED
...........................
45
A.
Summary
of
Results
...................................................
45
B.
Lessons
Learned
......................................................
50
IV.
SUMMARY
OF
PUBLIC
COMMENTS
ON
EPA
INSPECTIONS
....................
52
V.
CONCLUSIONS
...........................................................
56
REFERENCES
...............................................................
57
ACRONYM
LIST
A&
PCT
Active
and
Passive
Computed
Tomography
AK
Acceptable
Knowledge
Am
Americium
APNEA
Active
and
Passive
Neutron
Examination
and
Assay
ASME
American
Society
of
Mechanical
Engineers
BID
Background
Information
Document
BIR
Baseline
Inventory
Report
CA
Compliance
Assessment
CAO
U.
S.
Department
of
Energy
Carlsbad
Area
Office
(now
the
Carlsbad
Field
Office)
CAR
Corrective
Action
Report
CBFO
U.
S.
Department
of
Energy
Carlsbad
Field
Office
CCA
Compliance
Certification
Application
CCD
Charge
Collection
Device
CCP
Centralized
Characterization
Project
Cf
Californium
CH
TRU
Contact
Handled
Transuranic
Waste
Cm
Curium
CPR
cellulosics,
plastics,
rubber
Cs
Cesium
CT
Computed
Tomography
DOE
U.
S.
Department
of
Energy
DR
Digital
Radiography
DTP
Detailed
Technical
Procedure
EEG
Environmental
Evaluation
Group
eV
Electron
Volt
FRAM
Fixed
Energy
Response
Function
Analysis
with
Multiple
Efficiencies
FY
Fiscal
Year
GEA
Gamma
Energy
Assay
2
H
Deuterium
3
H
Tritium
HANDSS
55
Handling
and
Segregating
System
He
Helium
HENC
High
Efficiency
Neutron
Counter
HPGe
High
Purity
Germanium
IDC
Item
Description
Code
INEEL
Idaho
National
Engineering
and
Environmental
Laboratory
IPAN
Imaging
Passive
Active
Neutron
Counter
KV
Kilovolt
kVp
kilovolts
peak
LANL
Los
Alamos
National
Laboratory
LDA
Linear
Diode
Array
LLNL
Lawrence
Livermore
National
Laboratory
MCS
Mobile
Characterization
Services
msec
Millisecond
NCR
Nonconformance
Reports
NDA
Nondestructive
Assay
NDE
Nondestructive
Evaluation
NMC
Neutron
Multiplicity
Counters
NMED
New
Mexico
Environment
Department
Np
Neptunium
NQA
Nuclear
Quality
Assurance
NRC
U.
S.
Nuclear
Regulatory
Commission
NTS
Nevada
Test
Site
OJT
On
The
Job
Training
ORIA
EPA
Office
of
Radiation
and
Indoor
Air
PA
Performance
Assessment
PADC
Passive
Active
Drum
Counter
PAN
Passive
Active
Neutron
PCB
polychlorinated
biphenyls
PDP
Performance
Demonstration
Program
Pu
Plutonium
QA
Quality
Assurance
QAPjP
Quality
Assurance
Project
Plan
QAPP
Quality
Assurance
Program
Plan
QC
Quality
Control
RCRA
Resource
Conservation
and
Recovery
Act
of
1976
RFETS
Rocky
Flats
Environmental
Technology
Site
RH
TRU
Remote
Handled
Transuranic
Waste
RTG
Radioisotopic
Thermal
Generators
RTR
Real
Time
Radiography
SGS
Segmented
Gamma
Scanner
SGSAS
Segmented
Gamma
Scanner
Assay
System
SOP
Standard
Operating
Procedures
Sr
Strontium
SRIC
Southwest
Research
and
Information
Center
SRS
Savannah
River
Site
SWEPP
SGRS
Stored
Waste
Examination
Pilot
Plant
Gamma
Ray
Spectrometer
SWEPP
PAN
Stored
Waste
Examination
Pilot
Plant
Passive
Active
Neutron
Counter
TGS
Tomographic
Gamma
Scanners
TGS
CAN
Tomographic
Gamma
Can
Scanners
TMFA
Transuranic
and
Mixed
Waste
Focus
Area
TRU
Transuranic
TRUCON
Transuranic
Package
Transporter
II
Content
Codes
TSDF
Treatment,
Storage,
Disposal,
Recycling
Facilities
TWBIR
Transuranic
Waste
Baseline
Inventory
Report
U
Uranium
UCL90
Upper
90
Percent
Confidence
Limit
V
Volt
VE
Visual
Examination
VEE
VE
Expert
WAC
Waste
Acceptance
Criteria
WAGS
Waste
Assay
Gamma
Spectrometer
WAP
Waste
Analysis
Plan
WIPP
Waste
Isolation
Pilot
Plant
WMC
Waste
Matrix
Code
WMP
Waste
Material
Parameters
WWIS
WIPP
Waste
Information
System
1
I.
INTRODUCTION
The
purpose
of
this
Background
Information
Document
(BID)
is
to
explain
the
Agency's
Waste
Isolation
Pilot
Plant
(WIPP)
transuranic
(TRU)
waste
generator
inspection
process
in
support
of
alternative
provisions
for
40
CFR
Part
194.8,
"Approval
Process
for
Waste
Shipment
from
Waste
Generator
Sites
for
Disposal
at
the
WIPP."
Specifically,
the
Agency
is
proposing
to
revise
section
194.8(
b).
This
document
presents:
I.
The
current
regulatory
provisions
and
the
basis
for
inspections,
a
summary
of
wastes
that
require
inspection,
and
an
overview
of
the
current
inspection
approach.
II.
A
summary
discussion
of
the
major
technical
elements
examined
during
waste
characterization
inspections
at
generator
sites,
including
acceptable
knowledge
(AK),
nondestructive
assay
(NDA),
radiography
(such
as
real
time
radiography,
or
RTR),
visual
examination
(VE),
and
data
validation/
data
transfer
(via
the
WIPP
Waste
Information
System,
or
WWIS).
These
discussions
present
what
inspectors
examined
and
how
the
results
impact
EPA's
assessment
of
the
waste
characterization
process.
Technical
descriptions
of
measurement
and
examination
devices
are
included,
as
well
as
discussion
of
the
impact
of
different
waste
matrices
on
the
effectiveness
of
the
measuring
or
examination
device,
and
the
range
of
waste
types
that
the
Agency
may
be
able
to
approve
in
the
course
of
an
inspection.
III.
A
summary
of
results
and
general
conclusions
reached
by
Agency
inspectors
from
May
1998
through
the
present.
This
section
identifies
the
number,
scope,
and
results
of
technical
inspections
at
the
generator/
storage
sites.
IV.
Examples
of
public
comments
on
inspection
notices
and
docketed
materials.
V.
Conclusions.
I.
A
Current
Provisions
and
Summary
of
Pertinent
Elements
As
specified
in
§194.24(
b)(
2)
of
the
Compliance
Criteria,
the
U.
S.
Department
of
Energy
(DOE)
was
required
to
conduct
an
analysis
to
identify
waste
components
important
to
performance
assessment
(PA).
Section
194.24(
c)
deals
with
the
identification
of
waste
limits
associated
with
these
critical
components,
as
well
as
how
the
limits
are
included
in
performance
assessments
(§
194.32)
and
compliance
assessments
(§
194.54).
In
addition,
DOE
must
specify
how
waste
components
will
be
identified,
quantified,
tracked,
and
controlled.
Important
components
are
summarized
in
Section
I.
B
of
this
BID.
Waste
characterization,
as
defined
in
§194.24(
c),
is
necessary
to
ensure
that
waste
emplaced
in
the
repository
is
consistent
with
the
parameters
established
in
the
performance
2
assessment
(§
194.32)
and
compliance
assessment
(§
194.54),
and
that
limitations
(or
constraints)
on
radionuclides
and
other
waste
components
established
by
EPA's
certification
decisions
are
not
exceeded.
Waste
characterization
is
also
used
to
ensure
that
the
actual
waste
inventory
is
consistent
with
the
waste
inventory
estimates
presented
in
DOE's
Baseline
Inventory
Report
(BIR),
which
was
used
in
performance
and
compliance
assessment
(PA
and
CA)
calculations.
Waste
characterization
activities
performed
by
DOE
to
demonstrate
compliance
with
§194.24(
c)
include
a
"system
of
controls,"
involving
characterization
techniques
as
well
as
waste
tracking
and
WIPP
inventory
identification
and
management.
In
the
WIPP
certification
rulemaking,
EPA
evaluated
waste
characterization
information
provided
by
DOE
in
its
Compliance
Certification
Application
(CCA)
and
amended
the
Compliance
Criteria
by
adding
section
194.8.
Section
194.8
specifies
the
waste
characterization
approval
process
for
DOE
waste
generator
sites.
Condition
3
of
the
certification
provides
that
DOE
may
not
ship
waste
to
the
WIPP
from
any
waste
stream
other
than
wastes
from
specified
waste
streams
until
EPA
has
approved
processes
for
characterizing
such
waste
streams
in
accordance
with
the
section
194.8
approval
process.
Section
194.8(
b)
requires
that,
"[
f]
or
each
waste
stream
or
group
of
waste
streams
at
a
site
proposed
for
disposal
at
WIPP,"
DOE
must
provide
information
on
how
process
knowledge
will
be
used
for
waste
characterization
of
the
waste
stream(
s),
and
must
implement
a
system
of
controls
at
the
site,
in
accordance
with
§194.24(
c)(
4).
Section
194.8(
b)
also
states
that
EPA
will
conduct
an
".
.
.
an
inspection
of
a
Department
audit
for
the
purpose
of
evaluating
the
use
of
process
knowledge
and
the
implementation
of
a
system
of
controls
for
each
waste
stream
or
group
of
waste
streams
at
a
waste
generator
site."
Moreover,
DOE
must
demonstrate
that
each
site
has
procedures
in
place
to
communicate
with
DOE's
WIPP
Waste
Information
System
(WWIS).
The
WWIS
is
an
electronic
database
that
contains
information
related
to
the
characterization,
certification,
shipment,
and
emplacement
of
TRU
waste
at
the
WIPP.
In
accordance
with
section
194.8,
EPA
must
announce
scheduled
inspections
in
the
Federal
Register,
place
relevant
DOE
documents
in
the
docket,
and
solicit
public
comment
on
those
documents
for
at
least
30
days.
EPA
also
must
provide
written
audit
or
inspection
decisions
and
place
these
decisions
in
the
public
dockets.
Section
194.8
also
provides
that
subsequent
to
any
positive
determination
of
compliance
under
this
approval
process,
EPA
intends
to
conduct
inspections,
in
accordance
with
§194.21
and
§194.24(
h),
to
confirm
the
continued
compliance
of
the
programs
approved.
The
results
of
such
inspections
are
made
available
to
the
public
through
the
Agency's
public
dockets,
as
described
in
§194.67.
I.
B
Waste
Components
and
Waste
Descriptions
As
required
by
§
194.24(
b)(
2)
and
§
194.24(
c),
DOE
identified
the
waste
components
that
were
expected
to
have
a
significant
effect
on
disposal
system
performance
and
the
emplacement
limits
for
these
components
in
Chapter
4
(Table
4
10)
of
the
Compliance
Certification
Application
and
in
Appendices
WCA
and
WCL
(Docket
A
93
02,
Item
II
G
1,
Volume
XIX).
DOE
must
3
determine
the
quantities
of
these
components
in
TRU
waste
containers.
Based
on
DOE's
analysis,
EPA
regulates
the
waste
components
discussed
below.
I.
B.
1
Radiological
Waste
Components
As
discussed
in
Section
24.
A.
6
of
CARD
24
(Docket
A
93
02,
Item
V
B
2),
EPA
concluded
that
DOE
appropriately
identified
ten
isotopes
most
significant
to
the
PA,
which
EPA
listed
as
241
Am,
244
Cm,
137
Cs,
238
Pu,
239
Pu,
240
Pu,
241
Pu,
90
Sr,
233
U,
and
234
U
(the
cesium
and
strontium
isotopes
and
233
U
are
important
to
remote
handled
TRU
waste).
These
ten
isotopes
significant
to
PA
comprise
about
99
percent
of
the
EPA
units
anticipated
within
the
WIPP
waste
inventory.
CARD
31,
Application
of
Release
Limits,
contains
an
explanation
of
EPA
units
for
radioisotopes
(Docket
A
93
02,
Item
V
B
2).
EPA
determined
that
about
90
percent
of
the
total
anticipated
inventory
of
6.55
x
10
6
curies
at
closure
is
expected
to
be
contributed
by
the
following
seven
isotopes:
241
Am,
238
Pu,
239
Pu,
240
Pu,
241
Pu,
244
Cm,
and
234
U
(Figure
1).
See
also
EPA's
Technical
Support
Document
for
Section
194.24:
Consolidated
Technical
Support
Document
–
Compliance
Certification
Review
of
Waste
Characterization
Requirements
(Docket
A
93
02,
Item
V
B
15).
DOE
identified
the
following
ten
radionuclides
in
Appendix
WCL
(Docket
A
93
02,
Item
II
G
,Volume
XIX)
as
subject
to
identification
and
quantification:
°
238
Pu,
239
Pu,
240
Pu,
and
242
Pu;
°
241
Am;
°
233
U,
234
U,
and
238
U;
°
90
Sr;
and
°
137
Cs.
EPA
examines
tracking
of
the
Appendix
WCL
list
during
inspections
because
the
amount
of
241
Pu
and
244
Cm
may
be
derived
from
measurements
of
isotopes
on
the
WCL
list.
DOE
must
track
these
isotopes
against
the
inventory
estimates
used
in
the
performance
assessment
(the
inventory
estimates
are
listed
in
CARD
31,
Table
3).
As
stated
in
Appendix
WCL,
"[
T]
he
performance
assessment
is
sensitive
to
relative
changes
in
inventory
curie
content
as
a
function
of
radionuclide
decay
and
ingrowth
over
time.
The
magnitude
of
change
in
the
total
curie
content
depends
on
the
initial
ratios
of
the
total
activities
of
the
assayed
radionuclides
at
the
time
of
repository
closure.
Accordingly,
the
results
of
the
performance
assessment
analysis
are
conditional
on
the
ratios
assumed.
.
.."
Consequently,
the
inventory
estimates
upon
which
EPA's
initial
certification
is
based
function
as
constraints
on
the
amount
of
the
key
isotopes
that
may
be
disposed
in
the
WIPP.
Changes
to
the
inventory
estimates
would
necessitate
further
analysis
by
DOE
of
the
effect(
s)
on
the
performance
assessment,
and
perhaps,
a
modification
of
the
certification.
Figure
1.
Percentage
of
Total
Inventory
Contributed
by
PA
Significant
Isotopes
(Curies)
4
Pu
240
2.89%
U
234
0.01%
All
Others
11.93%
Cm
244
0.43%
Am
241
6.02%
Pu
239
10.69%
Pu
241
32.94%
Pu
238
35.09%
Source:
EPA
T
echnical
S
upport
Document
for
Section
194.24
(Air
Docket
A
93
02,
Item
V
B
15,
Section
4.2.3)
I.
B.
2
Non
Radiological
Waste
Components
5
In
addition,
DOE
identified
other
waste
components
that
were
expected
to
have
a
significant
effect
on
disposal
system
performance
and
which
require
limits
(Appendix
WCL,
Table
WCL
1).
The
non
radiological
waste
components
with
limiting
values
are:
°
Ferrous
metals
(iron):
minimum
of
2x10
7
kilograms;
°
Cellulosics/
plastic/
rubber:
maximum
of
2x10
7
kilograms;
°
Free
water
emplaced
with
waste:
maximum
of
1684
cubic
meters;
and
°
Nonferrous
metals
(metals
other
than
iron):
minimum
of
2x10
3
kilograms
I.
B.
3
General
Waste
Descriptions
EPA
examines
general
waste
descriptions
prepared
by
DOE
sites
to
understand
how
radiological/
non
radiological
components
are
grouped
and
assessed.
Wastes
can
be
assigned
waste
material
parameters
that
encompass
those
components
with
limiting
values
identified
by
DOE.
The
DOE
identified
(Appendix
BIR
of
the
CCA)
the
following
12
different
waste
material
parameters
and
3
different
contents
packaging
materials
which
are
tracked
by
sites
and
which
allows
quantification
of
non
radionuclide
waste
components:
Waste
Material
Parameters
°
Iron
base
metal/
alloys
°
Aluminum
base
metal/
alloys
°
Other
metal/
alloys
°
Other
inorganic
materials
°
Vitrified
materials
°
Cellulosics
°
Rubber
°
Plastics
°
Solidified
inorganic
materials
°
Solidified
organic
materials
°
Cement
(solidified)
°
Soils
Contents
Packaging
Materials
°
Steel
°
Plastic
°
Lead
(for
RH
TRU
waste
only)
Waste
generator
sites
typically
group
waste
by
"waste
streams,"
which
are
defined
as
".
.
.
waste
material
generated
from
a
single
process
or
from
an
activity
that
is
similar
in
material,
physical
form,
and
hazardous
constituents"
(Appendix
WAP).
Waste
streams
are
not
defined
by
6
their
radionuclide
content,
but
instead
are
grouped
by
chemical,
physical,
and
process
similarities.
The
Transuranic
Waste
Baseline
Inventory
Report
(TWBIR,
Appendix
BIR)
identified
569
different
waste
streams
that
will
be
emplaced
in
the
repository.
These
wastes
are
also
be
categorized
into
broader
Summary
Waste
Category
Groups,
defined
as
S5000
(debris),
S4000
(soil/
gravel),
and
S3000
(solidified)
waste.
Generator
sites
tend
to
group
waste
by
Summary
Waste
Category
Group
for
inspection
purposes.
I.
C
Description
of
Waste
Generators
The
wastes
to
be
emplaced
in
the
WIPP
originate
from
generator/
storage
sites
within
the
DOE
Weapons
Complex
and
National
Laboratories.
Waste
must
be
defense
related
TRU
waste,
and
the
range
of
wastes
at
each
generator/
storage
site
is
dependent
upon
the
site's
past
and
current
missions.
The
generator/
storage
sites
and
the
volumes
of
contact
handled
TRU
(CH
TRU)
and
RH
TRU
waste
expected
are
identified
in
Table
1.
Table
1
Anticipated
Waste
Volumes
for
Disposal
at
WIPP
7
Storage
Generator
Site
Anticipated
CH
TRU
Waste
(cubic
meters)
Anticipated
RH
TRU
Waste
(cubic
meters)
Ames
Laboratory
0.42
None
Reported
Argonne
National
Laboratory
East
140
None
Reported
Argonne
National
Laboratory
West
750
1,300
Battelle
Columbus
Laboratories
None
Reported
580
Bettis
Atomic
Power
Laboratory
120
6.7
Energy
Technology
Engineering
Center
1.7
0.89
Hanford
Site*
46,000
22,000
INEEL*
29,000
220
Lawrence
Livermore
National
Laboratory*
940
None
Reported
LANL*
18,000
190
Mound
Plant
270
None
Reported
Nevada
Test
Site*
630
None
Reported
Oak
Ridge
National
Laboratory*
1600
2,900
Paducah
Gaseous
Diffusion
Plant
1.9
None
Reported
Pantex
Plant
0.62
None
Reported
RFETS*
5,100
None
Reported
Sandia
National
Laboratory
14
None
Reported
Savannah
River
Site*
9,600
None
Reported
Teledyne
Brown
Engineering
0.21
None
Reported
U.
S.
Army
Material
Command
2.5
None
Reported
University
of
Missouri
Research
Center
1.0
None
Reported
Totals
110,000
27,000
CH
TRU
=
contact
handled
transuranics;
INEEL
=
Idaho
National
Engineering
and
Environmental
Laboratory;
LANL
=
Los
Alamos
National
Laboratories;
RFETS
=
Rocky
Flats
Environmental
Technology
Site;
RH
TRU
=
remote
handled
transuranics
(*)
Major
Sites
Source:
DOE
CCA,
Chapter
4.
These
totals
do
not
include
wastes
excluded
at
the
time
of
the
Compliance
Application
(i.
e.,
uncharacterized
and
classified
wastes).
There
are
additional
wastes
that
could
be
added
to
the
anticipated
inventory
in
the
event
that
the
classified
waste
streams
are
declassified
or
the
unclassified
wastes
are
identified
and
characterized.
Waste
streams
from
three
of
the
eight
major
sites
(Savannah
River,
Rocky
Flats,
and
Los
Alamos
National
Laboratories
[LANL]),
are
expected
to
contribute
over
85
percent
of
the
total
activity
for
seven
key
isotopes.
1
The
potential
contents
of
a
waste
stream
or
group
of
waste
streams
determine
which
processes
can
be
used
to
adequately
characterize
the
waste.
For
example,
if
acceptable
knowledge
information
suggests
that
the
waste
form
is
heterogeneous,
the
site
should
select
a
nondestructive
assay
technique
appropriate
for
such
waste
in
order
for
adequate
measurements
to
be
obtained.
Radiography
and
visual
examination
help
both
to
confirm
and
quantify
waste
components,
such
as
cellulosics,
rubbers,
plastics,
and
metals.
Once
the
nature
of
the
waste
has
been
confirmed,
the
assay
techniques
then
quantify
the
radioactive
isotopes
in
the
waste.
In
the
given
example,
a
TRU
waste
site
may
be
able
to
characterize
either
a
wide
range
of
heterogeneous
waste
streams
or
only
a
few.
Under
the
current
regulation,
the
scope
of
a
particular
inspection
is
determined
by
a
site's
stated
limits
on
the
applicability
of
proposed
waste
characterization
processes.
2
Process
knowledge
refers
to
knowledge
of
waste
characteristics
derived
from
information
on
the
materials
or
processes
used
to
generate
the
waste.
This
information
may
include
administrative,
procurement,
and
quality
control
documentation
associated
with
the
generating
process,
or
past
sampling
and
analytic
data.
Usually,
the
major
elements
of
process
knowledge
include
information
about
the
process
used
to
generate
the
waste,
material
inputs
to
the
process,
and
the
time
period
during
which
the
waste
was
generated.
EPA
has
used
the
term
"acceptable
knowledge"
synonymously
with
"process
knowledge."
Acceptable
knowledge
is
discussed
further
in
Section
II.
8
I.
D
Current
Inspection
Process
EPA
evaluates
the
ability
of
each
generator
site's
waste
characterization
program
to
adequately
characterize
TRU
waste
through
the
inspection
process
as
established
in
§194.8(
b).
Inspections
at
generator/
storage
sites
are
conducted
to
verify
that
characterization
activities
are
performed
in
accordance
with
approved
site
procedures
and
that
the
characterization
activities
are
adequate
and
appropriate
to
characterize
and
quantify
waste
from
specific
waste
streams
and
waste
containers
so
that
the
waste
will
not
exceed
the
approved
limits.
By
approving
waste
characterization
systems
and
processes,
EPA
concludes
the
following:
(1)
the
site
personnel
are
capable
of
identifying
and
measuring
the
radioactive
components
(such
as
plutonium)
in
the
TRU
waste
that
must
be
tracked
for
compliance
1
;
and
(2)
the
characterization
program
can
demonstrate
that
the
waste
stream(
s)
examined
meet
Condition
3
of
the
Compliance
Certification
Criteria.
The
approval
process
described
at
40
CFR
194.8(
b)
requires
DOE
to
provide
EPA
with
two
types
of
information:
(1)
information
on
process
knowledge
2
for
waste
streams
proposed
for
disposal
at
WIPP,
and
(2)
information
on
the
system
of
controls
in
place
at
the
generator
site.
The
Agency
solicits
public
comments
on
DOE
site
documentation
and
announces
the
date
of
the
upcoming
inspection.
An
EPA
inspection/
surveillance
team
visits
the
site
to
verify
that
process
knowledge
and
other
elements
of
the
system
of
controls
are
technically
adequate
and
being
implemented
properly.
Specifically,
the
EPA
inspection/
surveillance
team
verifies
compliance
with
40
CFR
194.24(
c)(
4),
which
states:
Any
compliance
application
shall:
Provide
information
which
demonstrates
that
3
The
introductory
text
of
paragraph
40
CFR
194.24(
c)
states:
"For
each
waste
component
identified
and
assessed
pursuant
to
[40
CFR
194.24(
b)],
the
Department
shall
specify
the
limiting
value
(expressed
as
an
upper
or
lower
limit
of
mass,
volume,
curies,
concentration,
etc.),
and
the
associated
uncertainty
(i.
e.,
margin
of
error)
for
each
limiting
value,
of
the
total
inventory
of
such
waste
proposed
for
disposal
in
the
disposal
system."
9
a
system
of
controls
has
been
and
will
continue
to
be
implemented
to
confirm
that
the
total
amount
of
each
waste
component
that
will
be
emplaced
in
the
disposal
system
will
not
exceed
the
upper
limiting
value
or
fall
below
the
lower
limiting
value
described
in
the
introductory
text
of
paragraph
(c)
of
this
section.
3
The
system
of
controls
shall
include,
but
shall
not
be
limited
to:
measurement;
sampling;
chain
of
custody
records;
record
keeping
systems;
waste
loading
schemes
used;
and
other
documentation.
As
waste
generator
sites
establish
waste
characterization
programs
for
new
waste
streams
(or
groups
of
waste
streams),
the
Agency
assesses
their
compliance
with
the
requirements
of
Sections
194.24(
c)(
3)
through
(5).
The
Agency
conducts
inspections
at
each
site
to
evaluate
the
use
of
process
knowledge
and
the
establishment
of
a
system
of
characterization
and
controls
for
each
waste
stream
or
group
of
waste
streams.
The
typical
elements
that
are
subject
to
inspection
include
NDA,
VE
and/
or
Radiography,
AK,
and
software
controls
to
include
operation
and
interface
with
the
WWIS.
Elements
related
to
the
control
of
characterization
systems,
such
as
training
records
and
document
control,
are
also
subject
to
inspection.
The
scope
of
a
specific
inspection
is
dictated
by
the
systems
that
are
in
use
for
a
group
of
waste
streams,
how
many
of
these
systems
have
been
previously
inspected
and
approved
by
the
Agency,
and
if
the
nature
of
the
waste
stream
changes
the
performance
of
any
elements
of
the
characterization
system.
For
EPA
to
confirm
that
a
system
of
controls
has
been
adequately
executed,
DOE
must
demonstrate
that
measurement
techniques
and
other
control
methods
can
be
implemented
for
waste
streams
that
DOE
plans
to
emplace
in
the
WIPP.
The
number
of
waste
streams
or
groupings
of
waste
streams
that
can
be
approved
is
dependent
upon
how
well
the
generator
site
systems
perform
for
a
variety
of
wastes.
While
EPA
can
and
has
approved
relatively
broad
groupings
that
mirror
the
specific
authorization
being
sought
by
sites,
EPA
has
also
restricted
its
approval
to
those
waste
streams
it
felt
could
be
adequately
characterized
by
the
systems
examined.
The
Agency's
compliance
decision
is
conveyed
by
a
letter
from
EPA
to
DOE.
A
copy
of
the
letter,
as
well
as
the
results
of
the
inspection(
s),
are
placed
in
EPA's
docket.
To
summarize,
the
approval
process
for
site
specific
waste
characterization
controls
is
as
follows
(See
Figure
2):
a.
One
or
more
Federal
Register
notices
for
the
inspection
and
placement
of
related
documents
in
the
docket;
b.
30
day
public
comment
period
on
docketed
information
from
the
site
to
be
inspected;
10
A
fe
d
er
a
l
r
e
g
i
s
t
e
r
n
o
t
i
c
e
f
o
r
t
h
e
i
n
s
p
e
c
t
i
o
n
o
f
a
s
i
t
e
a
n
d
pla
c
e
m
e
nt
of
r
e
l
a
t
e
d
s
i
t
e
p
r
o
c
e
d
u
r
e
s
a
n
d
r
e
p
o
r
t
s
i
n
t
h
e
d
o
c
k
e
t
A
g
e
n
c
y
p
r
e
p
a
r
e
s
f
o
r
s
i
t
e
i
n
s
p
e
c
t
i
o
n
/a
u
d
i
t
b
y
c
omple
t
i
n
g
t
h
e
f
o
l
l
o
w
i
n
g
t
a
s
k
s
:
°
Pr
e
p
a
r
a
t
i
o
n
o
f
d
r
a
f
t
c
h
e
c
kl
ists
°
R
e
vie
w
of
si
te
p
r
o
c
e
d
u
r
e
s
a
n
d
r
e
p
o
r
t
s
°
Mo
di
f
i
c
a
t
i
o
n
o
f
c
h
e
c
k
l
i
s
t
s
a
s
n
e
e
d
e
d
b
a
s
e
d
u
p
o
n
si
t
e
s
p
e
ci
f
ic
pro
c
e
d
u
r
e
s
C
o
n
d
u
ct
Si
t
e
I
n
s
p
e
c
t
i
o
n
/A
u
d
i
t
Fig
ur
e
2
Si
te
A
p
pro
v
al
Pro
c
e
s
s
c.
Performance
of
site
inspection
based
on
information
provided
by
DOE:
°
Review
of
site
procedures
and
other
information,
and
modification
of
EPA
checklists,
if
necessary,
to
incorporate
site
specific
information;
°
On
site
verification
of
the
technical
adequacy
or
qualifications
of
personnel,
procedures,
and
equipment
by
means
of
interviews,
demonstrations,
and
completion
of
checklists;
and
d.
Preparation
of
report
documenting
EPA's
inspection(
s)
and
written
notice
to
DOE
of
EPA's
compliance
decision.
Under
40
CFR
194.21
and
194.24(
h),
EPA
is
authorized
to
perform
follow
up
inspections
to
verify
that
a
TRU
waste
site
is
shipping
waste
that
belongs
only
to
those
waste
streams
or
groups
of
waste
streams
that
have
been
characterized
by
the
approved
processes.
In
the
event
that
the
inspection
finds
that
the
generator/
storage
site
is
not
adequately
meeting
the
waste
characterization
requirements
of
§§
194.24(
c)(
3)
through
(5),
the
agency
will
not
certify
the
generator/
storage
site
until
the
inadequacies
are
resolved
and
the
resolution
verified
usually
through
further
inspection.
11
A
federal
register
notice
for
the
inspection
of
a
site
and
placement
of
related
site
procedures
and
reports
in
the
docket
Agency
prepares
for
site
inspection/
audit
by
completing
the
following
tasks:
°Preparation
of
draft
checklists
°Review
of
site
procedures
and
reports
°Modification
of
checklists
as
needed
based
upon
site
specific
procedures
Has
the
Agency
determined
that
the
site
should
be
certified
based
upon
inspection
results?
(Y/
N)
Agency
grants
approval
for
audited
scope
Conduct
Site
Inspection/
Audit
Yes
No
Figure
2
Site
Approval
Process
12
II.
DESCRIPTION
OF
TECHNICAL
ELEMENTS
EXAMINED
DURING
INSPECTIONS
Specific
waste
characterization
processes,
techniques,
and
elements
important
to
demonstrating
40
CFR
194.24(
c)
compliance
are
examined
by
EPA
during
inspections,
including:
°
Acceptable
Knowledge
(AK).
AK
is
a
program
whereby
historic
process
data
and
other
data
are
assembled,
assessed,
and
evaluated
to
calculate
the
radionuclide
content,
in
terms
of
both
overall
quantity
and
the
presence
of
specific
isotopes.
This
information
is
typically
compared
to
assay
and
other
measured
data
to
assess
the
viability
of
the
AK
results,
but
also
often
provides
direct
information
used
by
NDA
personnel
in
the
form
of
a
"check"
for
NDA,
as
a
source
of
isotopic
information,
or
as
a
direct
replacement
for
NDA
measurements
when
sites
believe
their
AK
information
is
preferable
to
that
obtained
through
measurement.
At
present,
sites
are
required
to
analyze
all
TRU
waste
containers
to
determine
isotopic
contents
and
confirm
AK.
°
Nondestructive
Assay
(NDA).
NDA
systems
are
used
to
detect
radionuclide
content,
including
the
quantity
and
isotopic
distribution.
These
systems
typically
involve:
1)
neutron
systems
(e.
g.,
Passive
Active
Neutron
(PAN)
system)
for
quantification
of
a
plutonium
isotope;
and/
or
2)
Segmented
Gamma
Scanner
(SGS),
or
a
comparable
system,
typically
used
to
identify
specific
radioisotopes.
Currently,
all
waste
containers
are
assayed
to
quantify
10
WIPP
tracked
radionuclides.
In
certain
properly
justified
cases,
isotopic
information
was
obtained
from
AK.
°
Real
time
Radiography
(RTR).
RTR
records
continuous
x
ray
of
drum
contents
that
is
used
to
verify
waste
material
parameters
and
the
correctness
of
the
waste
matrix
code
identified
by
AK,
as
well
as
to
quantify
cellulosics,
plastic,
and
rubbers.
°
Visual
Examination
(VE).
The
process
of
opening
a
statistically
determined
number
of
waste
drums
and
manually
examining
and
recording
their
contents
is
called
VE.
VE
is
used
as
a
quality
control
check
of
RTR.
°
WIPP
Waste
Information
System
(WWIS).
WWIS
is
a
data
tracking
and
validation
system
that
includes
data
collection
and
entry
at
the
site,
and
transmission
to
and
receipt
of
data
at
the
WIPP
site.
These
techniques
are
discussed
in
more
detail
in
the
following
subsections.
EPA
requirements
and
expectations
for
these
techniques
are
derived
both
from
40
CFR
194.24
and
DOE's
own
program
requirements,
as
presented
in
the
CCA
and
revised
over
time
with
EPA's
review
and
approval.
13
II.
A
Acceptable
Knowledge
AK
is
generally
defined
as
the
use
of
process
information
or
other
waste
generator
data
to
determine
waste
content.
AK
is
a
Resource
Conservation
and
Recovery
Act
of
1976
(RCRA)
characterization
process
that
has
been
adopted
by
DOE
as
a
TRU
waste
characterization
methodology
applicable
to
the
radioactive,
as
well
as
the
hazardous,
portion
of
the
waste.
To
date,
two
guidance
documents
address
AK
(EPA
1994,
EPA
1997),
both
of
which
address
characterization
of
the
hazardous,
not
radioactive,
portion
of
the
waste
using
AK.
The
concept
has
been
extended
by
DOE
to
encompass
the
radioactive
portion
of
TRU
waste,
with
the
TRU
waste
AK
characterization
requirements
presented
in
attachment
WAP
of
the
CCA,
as
well
as
in
the
1995
WIPP
TRU
Quality
Assurance
Project
Plan
(QAPjP)
referenced
in
the
CCA.
In
joint
EPA/
NRC
guidance
(1997),
which
is
primarily
applicable
to
low
level
mixed
waste,
EPA
recognized
the
use
of
AK
to
make
RCRA
hazardous
waste
determinations.
The
guidance
does
not,
however,
speak
to
the
use
of
AK
to
determine
radioactive
component
content,
except
to
state
that
the
NRC
does
not
describe
specific
testing
requirements
for
waste
to
determine
if
it
is
radioactive
(10
CFR
20.2006
requires
that
the
waste
manifest
include,
as
completely
as
practicable,
the
radionuclide
identity
and
quantity
and
the
total
radioactivity).
The
1994
and
1997
guidances
both
state
that
the
use
of
waste
knowledge
by
a
generator
and/
or
treatment,
storage,
disposal,
recycling
facilities
(TSDF)
to
characterize
mixed
waste
is
allowed
–
and
even
recommended
–
to
eliminate
unnecessary
or
redundant
waste
testing.
EPA
broadly
interprets
AK
to
include:
°
Process
knowledge,
which
is
detailed
information
on
waste
obtained
from
existing
published
or
documented
waste
analysis
data,
from
a
waste
generator's
records
,
or
from
wastes
generated
by
processes
similar
to
that
which
generated
the
waste;
°
Available
records
of
radionuclides
analysis;
or
°
Combinations
of
both,
supplemented
by
confirmatory
analysis.
II.
A.
1
Overview
of
Technical
Elements
AK
is
used
by
DOE
in
the
context
of
radioactive
waste
characterization
to
provide
the
following:
°
Waste
stream
identification
°
Radionuclide
isotopic
content,
°
Isotopic
ratios,
°
Low
level
vs.
TRU
designation
°
Overall
radioactivity
based
on
facility
records
and
process
information
14
°
Physical
waste
type
°
Waste
material
parameter
content
As
indicated
in
Section
I,
DOE
is
required
to
identify
and
quantify
specific
WIPP
tracked
isotopes,
additional
isotopic
information
to
support
waste
limits
presented
in
the
CCA,
as
well
as
inventory
estimates
presented
in
Attachment
BIR
of
the
CCA.
Additionally,
waste
material
parameters
require
identification.
AK
is
used
to
obtain
available
information
pertaining
to
these
required
parameters,
and
this
information
is
available
to
NDA
and
nondestructive
evaluation
(NDE)
personnel
to
facilitate
their
measurement
activities.
Additionally,
information
derived
via
AK
is
compared
to
that
obtained
by
NDA
measurement
to
assess
the
accuracy
of
AK
data.
II.
A.
2
Technical
Description
of
System
or
Measurement
Device(
s)
AK
requirements
are
presented
in
the
WIPP
QAPjP
(Docket
A
93
02,
Item
II
G
1,
Reference
201),
as
well
as
Appendix
WAP
to
the
CCA.
Since
submission
of
the
CCA,
DOE
has
removed
AK
requirements
from
the
QAPjP
because
it
was
redundant
with
the
RCRA
Waste
Analysis
Plan
(WAP)
with
respect
to
AK
requirements.
As
such,
EPA
uses
the
most
recent
version
of
the
WAP
as
the
governing
document
for
AK
requirements.
AK
is
gathered,
evaluated,
and
assessed
following
a
specific
process
committed
to
by
the
DOE
in
its
CCA
via
associated
attachments
and
references.
This
process,
which
is
examined
by
EPA
during
inspections,
includes:
°
Assembling
AK
information;
°
Compiling
AK
documentation
into
an
auditable
record
(i.
e.,
the
process
should
include
review
of
AK
information
to
determine
the
waste
material
parameters
and
radionuclides
present,
as
well
as
source
info
discrepancy
resolution);
°
Assigning
waste
streams/
waste
matrix
codes;
°
Identifying
physical
forms,
waste
material
parameters,
and
radionuclides
(including,
if
possible,
isotopic
ratios);
°
Resolving
data
discrepancies;
°
Identifying
management
controls
for
discrepant
items/
containers/
waste
streams;
°
Confirming
AK
information
with
other
analytical
results
by
comparing
AK
characterization
data
with
that
obtained
through
NDA,
NDE,
and/
or
visual
examination,
including
discrepancy
resolution;
and
°
Auditing
of
AK
records.
EPA
examines
these
elements
during
inspections
to
ensure
that
the
process
is
being
followed.
Specifically,
EPA
examines
whether
procedures
demonstrate
a
logical
progression
from
general
facility
information
to
more
detailed
waste
stream
specific
information.
EPA
examines
whether
the
site's
TRU
waste
management
program
has
procedures
to
determine:
15
°
Waste
categorization
schemes
(e.
g.,
consistent
definitions
of
waste
streams)
and
terminology,
°
Breakdown
of
the
types
and
quantities
of
TRU
waste
generated/
stored
at
the
site,
and
°
How
waste
is
tracked
and
managed
at
the
generator
site,
including
historical
and
current
operations.
As
indicated
previously,
EPA
is
particularly
concerned
about
the
completeness
and
accuracy
of
data
collection
with
respect
to
those
elements
critical
to
continued
compliance.
Data
gathered
under
the
AK
process
should
support
identification
of
radionuclides
and
parameters
important
to
WIPP
performance,
as
well
as
information
useful
when
assessing
the
accuracy
of
PA
inventory
assumptions
presented
in
the
BIR.
EPA
examines
the
AK
process
to
see
whether
radionuclide
origin
is
documented
and
that
information
is
collected
for:
°
241
Am,
238
Pu,
239
Pu,
240
Pu,
242
Pu,
233
U,
234
U,
238
U,
90
Sr,
137
Cs,
and
unexpected
radionuclides,
°
Ferrous
metals
(in
containers),
°
Cellulosics,
plastics,
rubber,
and
°
Nonferrous
metals
(in
containers).
In
addition
to
this
information,
EPA
expects
AK
information
to
be
properly
managed
and
recorded
by
following
procedures
requiring
that:
°
AK
information
be
compiled
in
an
auditable
record,
including
a
road
map
for
all
applicable
information.
°
A
reference
list
be
provided
that
identifies
documents,
databases,
QA
protocols,
and
other
sources
of
information
that
support
AK
information.
°
The
overview
of
the
facility
and
TRU
waste
management
operations
in
the
context
of
the
facility's
mission
be
correlated
to
specific
waste
stream
information.
°
Correlations
between
waste
streams,
with
regard
to
time
of
generation,
waste
generating
processes,
and
site
specific
facilities
be
clearly
described.
For
newly
generated
wastes,
the
rate
and
quantity
of
waste
to
be
generated
shall
be
defined.
°
Nonconforming
waste
be
segregated.
The
AK
record
must
contain
the
following
items:
°
A
map
of
the
site
that
identifies
the
areas
and
facilities
involved
in
TRU
waste
generation,
treatment,
and
storage;
°
Facility
mission
description
related
to
TRU
waste
generation
and
management;
°
Description
of
the
operations
that
generate
TRU
waste
at
the
site
and
process
information,
including:
Area(
s)
or
building(
s)
from
which
the
waste
stream
was
or
is
generated,
Estimated
waste
stream
volume
and
time
period
of
generation,
Waste
generating
process
description
for
each
building
or
area,
16
Process
flow
diagrams,
if
appropriate,
Generalized
material
inputs
or
other
information
that
identifies
the
radionuclide
content
of
the
waste
stream
and
the
physical
waste
form;
and
°
Types
and
quantities
of
TRU
waste
generated,
including
historical
generation
through
future
projections.
Additionally,
EPA
expects
sites
to
collect
additional
"supplemental,"
or
supporting
information
as
available
to
bolster
information
included
in
the
AK
record,
which
may
include
but
not
be
limited
to
historical
safeguard
data
(for
radionuclides),
waste
package
information,
shipping
records,
etc.
As
a
test
of
AK
data
viability,
NDE
and
NDA
information
are
compared
to
AK
data
to
assess
AK
information
accuracy
(this
is
sometimes
called
"confirmation").
EPA
examines
whether
reevaluation
of
AK
is
performed,
if
NDE/
NDA
or
VE
identify
waste
to
be
of
a
different
waste
matrix
category
(such
as
sludges
vs.
debris)
or
radionuclide
content.
The
reevaluation
should
include,
as
applicable,
waste
reassignment
to
a
new
waste
stream
and
repackaging,
if
appropriate.
All
of
the
requisite
AK
data
are
assembled
in
an
AK
Summary
that
compiles
and
summarizes
information
collected,
including
the
basis
for
all
waste
stream
designations.
EPA
examines
the
AK
Summary
for
several
elements,
including
but
not
limited
to
whether
the
AK
Summary
addresses
radionuclide
content
of
waste,
how
detailed
this
information
is,
the
nature
of
supporting
documentation,
completeness
of
the
AK
Summary
with
respect
to
inclusion
of
all
pertinent
AK
data,
accuracy
of
process
discussions
within
the
AK
Summary,
traceability
of
AK
information
on
a
drum/
container
basis,
and
AK
accuracy
calculations
(which
are
generally
included
in
documents
outside
of
the
AK
Summary).
EPA
examines
the
AK
process
and
the
accuracy
and
viability
of
the
information
obtained
through
this
process.
As
part
of
this
examination,
EPA
performs
a
traceability
analysis
where
drums
are
randomly
selected
and
AK
data
pertinent
to
those
drums
examined.
This
activity
includes
not
only
historic
AK
information,
but
NDA
and
NDE
data
collected
under
EPA/
WIPPapproved
programs,
and
comparison
of
these
data
to
AK
to
demonstrate
that
the
complete
characterization
process
is
attainable
and
approveable.
Additionally,
EPA
examines
the
interface
between
NDA,
NDE,
and
AK
to
see
how
information
is
shared
and
used
between
the
various
characterization
processes.
AK
is
intended
to
serve
as
the
"starting
point"
from
which
basic
waste
information
is
assembled
and
examined;
this
information
is
then
used
to
varying
degrees
by
the
NDE
and
NDA
personnel
when
performing
radionuclide
assay
or
x
rays
to
assess
drum
waste
material
and
prohibited
item
contents.
AK
information
is
available
to
NDA
operators
to
use
when
performing
drum
analysis
as
a
source
of
matrix
information
and
radionuclide
content
information
against
which
measurements
are
"checked."
Also,
NDA
often
relies
on
AK
to
provide
isotopic
information,
including
isotopic
ratios.
On
a
case
by
case
basis,
EPA
has
allowed
this
AK
information,
if
demonstrated
to
be
viable
and
of
exceptional
quality,
to
be
used
in
the
radionuclide
characterization
process.
For
17
example,
EPA
has
allowed
a
site
to
define
the
isotopic
distribution
using
AK,
but
has
required
verification
of
one
or
two
isotopes
in
each
drum
to
confirm
the
AK
identified
isotopes
of
a
number
of
radionuclides.
Specifically,
EPA
has
allowed
a
site
(RFETS)
to
identify
weapons
grade
plutonium
isotopic
distributions
for
plutonium
isotopes
using
AK,
but
has
required
measurement
of
two
isotopes
in
each
container
to
confirm
the
AK
isotopes.
II.
A.
3
Effect
of
Waste
Matrix
Type
on
Measurement
The
viability
of
the
AK
process
is
more
directly
related
to
the
adequacy
of
AK
information
available
than
to
the
waste
matrix
type.
Generator
facilities
are
currently
assembling
AK
information
on,
and
characterizing
wastes
with,
the
best
available
AK
information.
These
wastes
typically
have
a
significant
body
of
information
available
through
site
records,
process
information,
historic
assay,
etc.,
and
the
resulting
AK
data
assembly,
assessment,
and
verification
process
is
generally
successful.
However,
existing
wastes
to
be
characterized
in
the
future
may
have
much
less
historic
information
available,
which
means
that
the
AK
process
aspect
of
waste
characterization
could
have
varying
degrees
of
success
with
respect
to
collection
of
mandatory
and
supplemental
information,
acquisition
of
radionuclide
data,
etc.
Therefore,
the
AK
process
is
not
so
much
affected
by
the
waste
matrix,
but
instead
by
the
age
of
the
waste,
the
historic
information
available
for
the
waste,
and
the
success
of
data
collection
efforts
by
the
generator
sites.
II.
A.
4
Scope
of
EPA
Approvals
for
AK
EPA
typically
approves
site
AK
on
a
Summary
Waste
Category
basis,
primarily
because
sites
themselves
limit
the
approvals
being
sought
to
this
categorization.
However,
EPA's
overall
approval
of
any
given
site
may
be
limited
to
groups
within
the
Summary
Waste
Category
group,
depending
upon
the
technical
viability
of
the
various
characterization
processes.
For
example,
even
if
AK
approval
extends
to
all
retrievably
stored
waste,
overall
approval
could
be
limited
if
NDA
approval
can
only
be
extended
to
a
specific
type
of
waste.
EPA
also
approves
the
AK
process
for
relatively
large
groups
of
wastes
that
are
not
necessarily
restricted
by
Summary
Waste
Category
Groupings.
For
example,
wastes
generated
at
Rocky
Flats
and
currently
in
storage
at
INEEL
tend
to
have
relatively
complete
data
records,
regardless
of
the
Summary
Waste
Category
group
in
question.
Even
if
there
is
little
AK
information,
EPA
can
and
has
extended
approval
of
the
process
if
the
site
is
able
to
demonstrate
a
thorough
understanding
of
the
AK
process.
In
short,
EPA
may
approve
whatever
is
appropriate
given
a
site's
ability
to
characterize
waste
using
the
AK
process.
AK
approval
is
restricted
by
the
quantity
and
quality
of
AK
data,
not
by
the
waste
type.
II.
B
Nondestructive
Assay
(NDA)
NDA
is
used
to
identify
and
quantify
the
radioactive
constituents
in
a
container.
Waste
to
be
disposed
of
at
WIPP
is
assayed
on
a
container
basis
to
quantify
the
activity
of
the
18
radionuclides,
particularly
those
identified
in
the
transuranic
waste
baseline
inventory
report
TWBIR
as
most
important
to
the
PA,
and
to
demonstrate
that
the
waste
in
the
container
meets
the
definition
of
TRU
waste.
II.
B.
1
Overview
of
Technical
Elements
NDA
examines
the
ten
isotopes
requiring
quantification,
as
well
as
additional
isotopes.
The
ten
isotopes
are:
°
238
Pu,
239
Pu,
240
Pu,
and
242
Pu;
°
241
Am;
°
233
U,
234
U,
and
238
U;
°
90
Sr;
and
°
137
Cs.
In
addition
to
the
isotopes
listed
as
important
to
PA
and
requiring
quantification,
the
waste
characterization
program
also
is
responsible
for
adequately
calculating
the
emplaced
activities
of
the
isotopes
contributing
to
the
Waste
Unit
(in
this
case,
the
activity
of
the
TRU
alpha
emitting
isotopes
in
Table
4
8
of
the
CCA).
Section
4.4.1
of
the
CCA
states,
Collectively,
those
elements
of
the
waste
characterization
program
that
support
long
term
regulatory
compliance
include
the
determination
of
the
radionuclide
inventory
(for
purposes
of
normalizing
radionuclide
releases
as
required
for
comparison
with
40
CFR
Part
191.13(
a)),
the
identification
of
the
physical
and
chemical
waste
form
inventories
(if
applicable),
and
the
verification
that
no
wastes
are
emplaced
in
the
WIPP
that
exceed
the
disposal
system's
safety
and/
or
performance
limitations.
The
normalization
requirement
in
Table
1
referenced
in
40
CFR
Part
191.13(
a)
necessitates
knowledge
of
the
EPA
Waste
Unit,
defined
as
the
total
curies
divided
by
one
million.
EPA
has,
as
part
of
the
inspection
program,
also
required
DOE
to
quantify
isotopes
other
than
those
identified
as
important
in
the
CCA
or
40
CFR
Part
191.
These
additional
isotopes
are
usually
necessary
to
support
the
technical
adequacy
of
the
assay
values
for
isotopes
identified
as
important
to
PA.
Typically,
EPA
may
require
a
site
to
ensure
that
DOE
identify
and
account
for
isotopes
that
may
interfere
with
the
assay
of
isotopes
identified
as
important
to
PA.
One
example
of
additional
required
isotopes
is
237
Np
at
LANL,
when
LANL
was
employing
the
Fixed
Energy
Response
Analysis
using
Multiple
Efficiencies
(FRAM)
system
for
gamma
spectroscopy.
Another
example
is
the
presence
of
244
Cm
or
252
Cf
in
waste
planned
for
assay
using
passive
neutron
methods.
These
special
cases
are
documented
in
the
EPA
inspection
report,
and
are
usually
specific
to
a
given
system
and
a
given
type
of
waste.
19
II.
B.
2
Technical
Description
of
System
or
Measurement
Device(
s)
To
demonstrate
compliance
with
40
CFR
194.24(
c),
DOE
described
general
methods
for
accomplishing
NDA
in
the
CCA.
DOE
described
more
detailed
requirements
for
NDA
programs
in
Chapter
9
of
the
Waste
Characterization
Quality
Assurance
Program
Plan
(QAPP),
a
document
that
has
since
been
replaced
by
the
Waste
Acceptance
Criteria
(WAC)
document.
Each
waste
generator
site
describes
their
specific
NDA
program,
and
how
the
program
complies
with
the
upper
tier
EPA
and
DOE
requirements,
in
a
Quality
Assurance
Project
Plan
(QAPjP).
Site
operating
procedures
for
each
instrument
or
method
are
then
written
to
implement
the
QAPjP
requirements,
along
with
any
other
specific
instrument
or
site
dependent
requirements.
NDA
systems
typically
include
data
collection
and
analysis
software
that
performs
quality
related
functions.
In
accordance
with
40
CFR
194.22
any
NDA
system
used
to
support
EPA
characterization
requirements
must
adhere
to
the
American
Society
of
Mechanical
Engineers
(ASME)
Nuclear
Quality
Assurance
(NQA)
Requirements
for
Software
(ASME,
1990).
Radioactive
components
in
waste
to
be
disposed
of
at
WIPP
may
be
characterized
by
radiochemistry
or
NDA.
NDA
methods
are
by
far
the
preferred
techniques
for
performing
radioassay,
as
they
generally
have
greater
throughput
and
produce
lower
human
exposures
than
do
radiochemistry
techniques.
II.
B.
2.1
General
NDA
System
Information
The
NDA
techniques
approved
for
use
on
WIPP
waste
containers
are
classified
as
active
or
passive.
Passive
NDA
methods
measure
spontaneously
emitted
radiation
produced
by
natural
decay
of
the
radioactive
isotopes
inside
the
waste
container.
Active
NDA
methods
measure
radiation
produced
by
artificially
generated
reactions
in
the
waste
material.
Active
NDA
systems
used
for
assay
of
TRU
waste
generate
reactions
in
the
heavy
metals
within
the
waste
using
a
low
intensity
beam
of
neutrons.
Presently,
most
waste
is
characterized
using
passive
active
neutron
(PAN)
counters
and
gamma
ray
spectrometry
systems.
A
small
fraction
of
the
waste,
primarily
from
the
production
of
radioisotopic
thermal
generators
(RTG),
is
characterized
by
calorimetry
instruments.
The
neutron
counting
systems
being
used
for
NDA
of
WIPP
waste
containers
are
designed
to
provide
quantification
of
the
plutonium
isotopes
in
TRU
waste.
Neutrons
are
naturally
produced
by
only
a
small
number
of
isotopes;
the
rate
at
which
neutrons
of
certain
energies
are
produced
by
the
waste
container
provides
a
good
measure
of
the
quantity
of
these
isotopes.
Passive
neutron
counting
systems
detect
these
naturally
occurring
neutrons
and
use
various
computational
techniques
to
relate
their
quantity
to
isotopic
activities.
Many
NDA
systems
using
neutron
counting
are
also
capable
of
active
counting.
In
the
active
mode,
a
low
intensity
beam
of
neutrons
is
fired
into
the
waste
container.
This
neutron
beam
20
will
produce
a
series
of
reactions
in
the
fissionable
and
fissile
isotopes
within
the
waste,
with
the
number
of
particles
produced
by
the
reactions
being
proportional
to
the
amount
of
fissile
and
fissionable
isotopes
present
in
the
waste.
The
external
detectors
then
count
these
particles
and
convert
the
particle
response
to
source
strength.
By
using
active
NDA
methods
and
special
sensitive
neutron
detectors,
even
very
small
quantities
of
plutonium
in
the
waste
containers
can
be
detected
and
quantified.
The
gamma
ray
measurement
systems
being
used
to
characterize
WIPP
waste
containers
are
based
on
two
basic
principals.
First,
almost
all
radioactive
materials
produce
gamma
rays.
Second,
the
gamma
ray
pattern
produced
by
any
isotope
is
unique
to
that
isotope;
no
two
isotopes
produce
the
same
number
of
gamma
rays
having
the
same
energies.
Given
a
detector
with
good
enough
resolution
to
count
the
various
gamma
rays
individually
and
a
method
to
determine
what
the
gamma
ray
energy
patterns
mean,
it
is
possible
to
quantitatively
determine
the
isotopes
present
in
a
waste
sample.
Modern
radiation
detectors
coupled
to
sophisticated
computer
programs
that
solve
the
energy
pattern
for
the
presence
of
certain
isotopes
are
capable
of
performing
this
task
for
a
large
number
of
isotopes.
The
gamma
measurement
systems
approved
for
use
in
characterizing
WIPP
waste
are
capable
of
quantifying
the
presence
of
many
of
the
isotopes
defined
by
40
CFR
Part
191,
even
in
the
presence
of
potential
interfering
isotopes
and
background
radiation.
When
the
gamma
and
neutron
NDA
systems
are
used
together,
these
systems
provide
information
about
the
radiological
content
of
a
waste
container.
The
information
that
can
be
produced
by
the
WIPP
waste
NDA
systems
includes,
but
is
not
limited
to,
239
Pu
equivalent
activity,
239
Pu
fissile
gram
equivalent,
total
alpha
activity,
the
decay
heat
of
waste
containers,
and
the
activity
of
the
isotopes
of
interest
to
the
performance
assessment
and
the
applicable
regulations.
The
purpose
of
these
data
relative
to
long
term
repository
compliance
with
40
CFR
Parts
191
and
194
is
to
establish
the
radionuclide
content
emplaced
in
the
repository.
All
assay
systems
using
radiation
detection
methods
must
be
calibrated
using
a
variety
of
standards
that
simulate
the
various
waste
compositions,
source
distributions
and
interferences
common
to
the
waste
streams
originating
from
a
particular
generator
site.
AK
enhances
the
NDA
systems
by
providing
advance
information
on
the
radiological
characteristics
of
a
waste
stream,
which
allows
the
NDA
systems
to
be
made
particularly
sensitive
to
that
type
of
waste
by
developing
realistic
calibration
standards.
Calibration
records
and
expected
system
performance
curves
are
compared
against
the
actual
results
of
the
measurements
performed
on
the
waste
containers.
II.
B.
2.2
Neutron
Systems
Because
they
have
no
charge,
and
are
not
purely
an
electromagnetic
packet
like
gamma
rays,
neutrons
have
a
unique
set
of
interactions
with
matter.
They
do
not
interact
with
the
electron
cloud
around
a
nucleus,
but
rather
with
the
nucleus
itself.
Thus,
when
a
material
absorbs
neutrons,
the
neutrons
are
interacting
with
and
changing
the
nuclei
of
the
atoms
in
the
absorbing
material,
21
which
can
produce
a
number
of
secondary
reactions.
Neutron
interactions
with
nuclei
may
result
in
the
disappearance
of
the
neutron
and
its
replacement
by
secondary
radiations,
or
a
significant
change
in
the
neutron's
energy
or
direction.
It
may
even
result
in
the
fragmentation
of
the
nucleus
with
which
it
is
interacting
in
a
process
known
as
fission.
The
secondary
radiations
produced
by
neutron
interactions
are
usually
heavy
charged
particles;
it
is
these
charged
particles
produced
by
the
conversion
of
the
neutron
energy
that
are
seen
by
neutron
detectors,
as
discussed
below.
Generally,
the
type
and
probability
of
the
various
neutron
interactions
with
any
given
type
of
nucleus
depend
strongly
on
the
energy
of
the
neutron.
NDA
systems
do
not
require
exact
measures
of
neutron
energy.
For
NDA
purposes,
neutrons
can
simplistically
be
divided
into
two
categories
based
on
their
energy:
high
energy
or
"fast"
neutrons,
and
low
energy
or
"slow"
neutrons,
using
an
arbitrary
energy
division
of
approximately
0.5
electron
volts
(eV).
Neutrons
are
measured
indirectly
by
detecting
secondary
particles
resulting
from
interactions
of
neutrons
with
target
nuclei.
These
possible
interactions
include:
°
(n,
p)
or
(n,
a)
reactions
where
a
nucleus
absorbs
a
neutron
and
emits
a
charged
particle,
which,
along
with
the
recoil
product
nucleus,
causes
ionization
in
the
detector;
°
Neutron
induced
fission,
or
(n,
f)
reactions,
where
the
detector
registers
ionization
produced
by
the
fission
fragments
or
the
prompt
or
delayed
neutrons
and
photons;
and/
or
°
Neutron
scattering,
where
the
recoil
nucleus
produces
ionization
in
the
detector.
The
(n,
p),
(n,
a)
and
(n,
f)
reactions
are
of
greatest
interest
for
neutron
detection
because
they
produce
secondary
radiations
(i.
e.,
charged
particles
that
can
be
detected
directly).
The
neutron
detectors
most
widely
used
in
NDA
systems
are
gas
proportional
detectors
filled
with
a
light
isotope
of
helium
(
3
He).
These
detectors
are
commonly
called
helium
tubes.
A
neutron
detection
system
typically
contains
many
helium
tubes,
maintained
under
an
applied
voltage,
or
electric
field.
The
neutron
helium
reaction
of
interest
is
shown
below:
3
He
+
n
6
3
H
+
p
+
0.764
MeV
The
term
"cross
section"
is
used
to
describe
the
probability
of
interaction.
Helium
is
used
because
it
has
a
high
cross
section
for
interaction
with
thermal,
or
low
energy,
neutrons,
which
provides
a
high
detection
efficiency
and
pulse
height
resolution.
The
charge
liberated
by
the
neutron
helium
interaction
produces
initial
ionizations
of
helium
gas.
By
maintaining
the
appropriate
electric
field
within
the
gas,
the
number
of
secondary
ionizations
produced
is
proportional
to
those
produced
initially,
while
the
number
of
actual
ion
pairs
is
multiplied
by
a
factor
of
many
thousands.
The
detection
system
collects
the
ion
pairs
as
charge
which,
with
proper
calibration,
is
correlated
with
the
number
of
neutron
interactions
and
therefore
the
sample
reaction
rate.
22
Because
the
probability
of
neutrons
interacting
with
target
materials
is
a
strong
inverse
function
of
the
neutron's
energy,
high
energy
neutrons
produced
by
spontaneous
or
induced
fission
("
fast"
neutrons)
must
be
slowed
before
they
can
be
efficiently
detected.
This
occurs
through
multiple
collisions
with
atoms
in
the
materials
within
the
detection
system
(i.
e.,
polyethylene,
graphite,
etc.).
Neutron
cross
sections
for
a
given
target
nucleus
are
interaction
specific
(i.
e.,
there
is
a
different
cross
section
for
fission,
elastic
scattering,
inelastic
scattering,
(n,
p)
reaction,
etc.),
and
each
is
strongly
dependent
on
the
neutron
energy.
Cross
sections
are
also
material
specific.
Certain
isotopes
have
large
cross
sections
for
various
reactions,
which
may
make
them
a
preferred
material
for
neutron
detection
systems.
The
main
source
of
neutrons
of
interest
to
NDA
result
from
spontaneous
or
induced
nuclear
fission,
which
is
the
disintegration
of
an
atomic
nucleus
into
two
or
more
lighter
fragments.
In
general,
isotopes
of
plutonium
and
uranium
have
a
low
rate
of
spontaneous
fission
compared
to
the
rate
for
other
decay
modes,
such
as
alpha
emission.
This
is
particularly
so
for
heavy
radionuclides
with
odd
numbers
of
neutrons
and
odd
mass
number,
but
these
isotopes
frequently
have
a
high
thermal
neutron
fission
cross
section,
which
means
these
isotopes
can
be
made
to
undergo
induced
fission
by
bombardment
with
low
energy
neutrons.
Examples
of
these
isotopes
are
233
U,
235
U
and
239
Pu.
Plutonium
isotopes
with
even
mass
numbers
(
238
Pu,
240
Pu,
and
242
Pu)
undergo
higher
rates
of
spontaneous
fission,
and
for
240
Pu
the
rates
of
spontaneous
fission
and
alpha
emission
are
close.
This
is
important
as
240
Pu
is
typically
present
as
an
impurity
in
weapons
grade
plutonium
and
is
a
component
of
TRU
wastes.
Assays
of
TRU
wastes
by
measuring
the
neutrons
emitted
by
spontaneous
fission
are
called
"passive"
mode
assays.
Passive
mode
measurements
count
neutrons
produced
by
isotopes
with
significant
likelihood
of
decay
by
spontaneous
fission,
including
238
Pu,
240
Pu,
242
Pu,
and
244
Cm.
Neutrons
are
also
emitted
by
TRU
radionuclides
in
response
to
induced
fission
caused
by
bombardment
with
energetic
neutrons
supplied
by
the
measurement
system.
Such
assays
measuring
induced
neutrons
are
called
"active"
mode
assays.
Active
mode
assays
provide
information
for
239
Pu
and
241
Pu,
as
well
as
other
fissile
isotopes
present
in
the
TRU
waste
being
assayed
(e.
g.,
235
U),
that
fission
takes
place
in
response
to
neutrons
supplied
by
the
measurement
system.
II.
B.
2.3
Passive
Active
Neutron
Counters
PAN
counters
are
used
to
quantify
the
amount
of
a
fissile
or
fissionable
nuclide
inside
a
container.
More
precisely,
these
systems
quantify
the
amount
of
a
particular
radionuclide
that
would
result
in
the
number
of
counts
observed.
This
is
referred
to
as
the
effective
mass.
For
active
measurements,
the
239
Pu
effective
mass
is
measured,
while
for
passive
measurements,
the
240
Pu
effective
mass
is
measured.
To
convert
the
effective
mass
measured
into
the
true
mass
of
each
of
the
radionuclides
present,
the
ratio
of
each
nuclide
to
that
of
the
primary
nuclide
being
measured
must
be
known.
These
ratios
can
be
measured
using
a
gamma
ray
spectrometry
system,
described
in
the
following
section.
To
quantify
the
effective
mass
of
239
Pu
or
240
Pu,
fast
neutrons
from
induced
or
spontaneous
23
fissions
are
detected
and
counted.
Since
two
or
more
neutrons
usually
result
from
a
fission
event,
neutron
counters
are
operated
in
coincidence
mode.
In
coincidence
mode,
an
event
is
only
counted
when
two
or
more
neutrons
are
individually
detected.
Most
PAN
counters
consist
of
a
large
number
of
individual
neutron
detectors
surrounding
the
container
being
assayed.
The
most
common
type
of
neutron
detector
used
is
a
3
He
tube,
which
is
a
long
cylindrical
proportional
gas
counter
filled
with
3
He.
Since
the
probability
of
detection
in
a
3
He
tube
is
much
greater
for
thermal
neutrons
than
for
fast
neutrons,
3
He
tubes
are
usually
surrounded
by
a
moderator.
Fast
neutrons
lose
energy
through
numerous
collisions
in
the
moderator
until
they
are
reduced
in
energy,
or
"thermalized."
As
previously
described,
a
PAN
counter
in
passive
mode
counts
neutrons
from
spontaneously
fissioning
nuclides,
such
as
240
Pu.
In
active
mode
the
PAN
system
counts
neutrons
generated
in
the
waste
container
after
the
container
is
exposed
to
fast
neutrons
from
an
external
source,
which
induce
fissile
nuclides
in
the
waste
to
fission.
The
most
common
source
of
fast
neutrons
is
a
D
T
neutron
generator,
although
other
sources,
such
as
252
Cf
sources
can
also
be
used.
A
D
T
neutron
generator
creates
14
MeV
neutrons
by
accelerating
deuterium
(
2
H)
nuclei
into
a
tritium
(
3
H)
target.
Proper
use
and
calibration
of
a
PAN
system
requires
tests
using
known
sources
in
order
to
evaluate
system
efficiency.
Additionally,
the
environmental
neutron
signal
must
be
measured
in
order
to
remove
background
signals
that
are
not
contributed
by
the
waste
components.
Both
the
efficiency
and
the
background
signal
must
be
periodically
checked
in
order
to
ensure
data
quality
is
not
degraded.
II.
B.
2.4
Photon
Emission
and
NDA
Photons
in
the
general
sense
are
packets
of
electromagnetic
energy,
and
are
the
basic
constituents
of
any
electromagnetic
energy,
including
visible
light.
When
these
photons
are
generated
by
de
excitation
reactions
in
an
atomic
nucleus,
they
are
often
referred
to
as
gamma
radiation
or
gamma
rays.
Gamma
photons
are
essentially
the
same
as
x
rays,
but
have
different
origins:
gamma
radiation
is
emitted
during
changes
in
the
state
of
nuclei,
while
x
rays
are
emitted
during
changes
in
the
state
of
inner
or
more
tightly
bound
electrons.
Gamma
radiation
is
a
penetrating
radiation
best
attenuated
by
dense
materials
like
concrete,
lead,
etc.
Gamma
emissions
occur
at
discrete
energies
that
are
characteristic
of
specific
radionuclide
transitions,
enabling
their
identification
by
spectroscopic
techniques,
as
discussed
below.
Gamma
photon
emissions
range
in
energy
from
approximately
one
thousand
electron
volts
(1
KeV)
to
almost
ten
million
electron
volts
(10
MeV).
For
purposes
of
NDA
isotopic
measurements
of
plutonium,
the
photon
emissions
of
interest
occur
between
the
energies
of
approximately
40
to
640
KeV;
for
uranium,
the
photon
emissions
of
interest
occur
between
approximately
100
KeV
and
1
MeV
in
energy.
Their
electromagnetic
nature
causes
photons
to
interact
strongly
with
the
charged
electrons
in
the
atoms
of
all
matter.
The
photon
gives
up
energy
to
an
electron,
which
then
is
released
from
24
its
parent
atom
and
collides
with
other
atoms,
liberating
more
electrons.
The
total
charge
released
is
proportional
to
the
photon
energy,
since
the
higher
the
photon
energy
the
more
energy
is
available
to
release
electrons.
The
charge
resulting
from
this
cascade
of
released
electrons
is
then
collected,
causing
a
signal
indicating
the
presence
of
the
gamma
photon.
The
magnitude
of
the
signal
tells
the
energy
of
the
photon
since
the
electrical
signal
output
to
the
detector
is
proportional
to
the
energy
deposited
in
the
detector.
After
a
large
number
of
these
gamma
photons
have
been
detected,
a
graph
of
the
number
of
gamma
photons
measured
versus
the
energy
of
the
photons
can
be
displayed.
This
graph,
or
spectrum,
results
in
a
"fingerprint"
of
specific
radionuclides
since
the
gamma
photon
energy
release
pattern
is
unique
for
each
isotope.
With
the
appropriate
calibration,
the
spectrum
allows
identification
and
quantification
of
photon
emitting
radionuclides
in
various
media.
There
are
many
types
of
materials
suitable
for
use
in
photon
detectors.
The
NDA
systems
of
interest
primarily
use
modern
solid
state
detectors
constructed
from
germanium,
in
which
the
charge
produced
by
the
photon
interactions
is
collected
directly.
Germanium
is
the
semiconductor
material
of
choice
for
modern
photon
detectors
due
to
its
nearly
ideal
electronic
characteristics
that
allow
electrons
and
"electron
holes"
to
move
freely.
The
ionization
charge
resulting
from
the
photon
interaction
within
the
detector
is
swept
to
an
electrode
by
the
high
electric
field
in
the
semiconductor
material
produced
by
the
voltage
applied
to
the
detector
with
the
system's
high
voltage
power
supply.
The
charge
is
converted
to
a
voltage
pulse
by
a
preamplifier;
this
voltage
is
then
amplified
and
sent
to
a
multi
channel
analyzer,
which
displays
the
spectrum
of
gamma
counts
detected
versus
energy.
Spectroscopic
evaluation,
including
radionuclide
identification
by
energy
peak
pattern,
background
correction,
pulse
height
determination,
etc.,
can
then
be
performed
on
the
spectrum
either
manually
or
by
computer.
By
applying
calibration
and
correction
factors
appropriate
to
the
waste
matrix,
container,
and
radionuclides,
the
spectroscopic
data
can
be
transformed
into
concentrations
of
specific
photon
emitting
TRU
radionuclides.
II.
B.
2.5
Gamma
Ray
Spectrometry
Systems
Gamma
ray
spectrometry
systems
are
used
to
quantify
the
amount
of
individual
radionuclides,
or
to
measure
the
ratio
of
different
radionuclides,
by
detecting
gamma
ray
emissions.
Because
radionuclides
emit
gamma
rays
of
discrete
energies,
the
quantity
of
individual
radionuclides
can
be
related
to
the
number
of
gamma
rays
detected
at
a
specific
energy.
Effective
use
of
gamma
ray
spectrometry
systems
requires
the
user
to
define
the
system
efficiency
and
resolution.
These
parameters
must
be
periodically
checked
to
ensure
the
system
is
providing
consistent
results.
The
radiological
background
present
at
the
detector
must
also
be
defined
in
order
to
calculate
accurate
results
for
the
radionuclide
quantities
present
in
the
waste.
The
background
gamma
ray
spectrum
must
be
periodically
measured
in
order
to
ensure
that
unintended
errors
are
not
introduced
into
the
results.
Most
gamma
ray
spectrometry
systems
involve
one
or
more
high
resolution
detectors,
with
high
purity
germanium
(HPGe)
being
the
most
common.
These
detectors,
typically
about
three
inches
in
diameter
and
three
inches
in
length,
are
positioned
alongside
the
container.
In
many
25
systems,
commonly
referred
to
as
scanners,
a
collimator
is
used
so
that
the
detector
only
detects
gamma
rays
emitted
from
a
portion
of
the
container.
The
detector,
or
more
commonly
the
container,
is
then
translated
until
the
entire
container
is
measured.
Some
gamma
ray
scanners
incorporate
a
transmission
source
to
correct
for
gamma
ray
attenuation
in
the
container.
These
collimated
radioactive
sources
are
positioned
directly
opposite
of
the
detector.
Shutters
are
often
used
to
shield
the
source
from
the
detector
when
it
is
not
being
used.
II.
B.
2.6
Calorimetry
Instruments
Calorimetry
instruments
are
used
to
quantify
radionuclides
for
waste
containers
that
contain
significant
quantities
of
238
Pu.
The
high
specific
activity
of
238
Pu,
used
primarily
for
radioisotopic
thermal
generators,
results
in
a
measurable
heat
flux
that
can
be
correlated
to
the
activity
of
the
radionuclides
in
question.
Like
neutron
counters,
isotopic
ratios
must
be
known
in
order
to
relate
the
heat
flux
to
the
activities
of
individual
radionuclides.
Calorimetry
has
only
been
used
in
a
limited
number
of
instances,
and
EPA
has
approved
its
use
only
at
Rocky
Flats.
II.
B.
3
Effect
of
Waste
Matrix
or
Waste
Type
on
Measurement
The
applicability
of
PAN
counters
and
gamma
ray
spectrometry
systems
to
characterize
waste
to
be
disposed
of
at
WIPP
depends
primarily
on
the
matrix
properties
of
the
waste
and
the
types
and
quantities
of
radionuclides
present.
For
neutron
counters,
the
matrix
parameters
of
primary
interest
are
the
neutron
absorption
and
moderating
properties.
Large
quantities
of
hydrogen
containing
materials
will
enhance
neutron
moderation,
making
active
measurements,
and
to
a
lesser
extent
passive
measurements,
more
difficult.
The
presence
of
any
materials
that
enhance
neutron
capture
will
make
any
neutron
measurements,
active
or
passive,
more
difficult.
Passive
and
active
neutron
counters
work
best
with
radionuclides
having
large
cross
sections
for
induced
fission
and
high
spontaneous
fission
rates,
respectively.
Matrix
parameters
that
affect
gamma
ray
systems
are
matrix
density
and
the
effective
atomic
number.
Denser
materials
and
materials
with
high
atomic
numbers
(Z)
absorb
more
gamma
rays
than
less
dense,
lower
Z
number
materials,
resulting
in
increased
gamma
ray
attenuation
and
poorer
signal
to
source
ratios.
Gamma
ray
spectrometry
systems
are
best
suited
to
detect
radionuclides
that
emit
gamma
rays
at
energies
between
about
50
keV
and
1
MeV
with
a
high
probability,
or
branching
ratio.
Specific
issues
related
to
waste
properties
are
described
in
the
following
sections
for
each
of
the
neutron
and
gamma
detection
methods.
II.
B.
3.1
Neutron
Counting
Systems
PAN
counters
typically
must
account
for
the
following:
°
Radionuclide
source
(source)
heterogeneity.
Most
neutron
systems
are
calibrated
26
assuming
that
sources
are
uniformly
distributed
throughout
the
container
volume.
When
sources
are
not
uniformly
distributed,
but
are
instead
concentrated
in
parts
of
the
drum,
the
system
will
underestimate
or
overestimate
the
239
Pu
or
240
Pu
effective
mass.
°
Matrix
heterogeneity.
In
addition
to
a
uniformly
distributed
source,
most
neutron
calibrations
are
done
for
matrices
whose
neutron
absorption
and
moderation
properties
are
assumed
to
be
the
same
throughout
the
volume
of
the
container.
Like
non
uniform
source
distributions,
non
uniform
matrices
can
result
in
an
underestimation
or
overestimation
of
the
239
Pu
or
240
Pu
effective
mass.
°
Source
self
shielding.
If
the
fissile
material
is
concentrated
in
a
small
volume
(i.
e.,
a
lump)
the
inner
material
is
shielded
from
interrogating
neutron
flux
during
an
active
measurement.
This
effect,
referred
to
as
self
shielding,
can
result
in
an
underestimation
of
the
239
Pu
effective
mass.
This
problem
is
not
significant
in
passive
mode,
where
the
mean
free
path
of
the
fast
neutrons
is
much
larger
than
the
size
of
the
fissile
mass.
°
Interfering
nuclides.
Any
fissile
or
spontaneously
fissioning
nuclides,
such
as
244
Cm,
not
accounted
for
in
the
determination
of
the
isotopic
ratios
will
result
in
an
incorrect
estimation
of
the
individual
radionuclide
activities
and
any
derived
quantities.
Containers
are
often
rotated
during
the
measurement
to
reduce
the
effect
of
source
and
matrix
heterogeneity
on
the
measurement.
Some
neutron
counters
incorporate
imaging
algorithms
to
measure
the
spatial
variations
in
the
source
distribution
and
the
matrix
properties.
II.
B.
3.2
Photon
Measuring
Systems
Gamma
ray
systems
are
affected
by
many
of
the
source
and
matrix
effects
that
affect
neutron
counters,
including
source
heterogeneity,
matrix
heterogeneity,
and
source
self
shielding.
°
Source
heterogeneity.
Like
neutron
counters,
most
gamma
ray
systems
are
calibrated
for
uniformly
distributed
sources,
and
nonuniform
source
distributions
are
likely
to
result
in
underestimation
or
overestimation
of
radionuclide
activities.
°
Matrix
heterogeneity.
Gamma
ray
system
calibrations
generally
assume
that
gamma
attenuation
properties
are
uniform
throughout
the
volume
of
the
container.
Spatial
variations
in
these
properties,
namely
the
density
and
effective
atomic
number,
can
cause
the
radionuclide
activities
to
be
incorrectly
estimated.
°
Source
self
absorption.
Concentrated
masses,
or
lumps,
of
high
Z
materials,
such
as
uranium
and
plutonium,
can
result
in
underestimation
of
the
radionuclide
activity.
Unlike
the
self
shielding
effect
in
active
neutron
measurements,
the
difficulty
in
gamma
spectrometry
arises
when
gamma
rays
from
the
interior
of
the
mass
are
absorbed
before
escaping
the
lump.
27
°
Interfering
radionuclides.
Some
radionuclides
emit
gamma
rays
very
close
in
energy
to
those
being
measured.
If
not
properly
accounted
for,
these
interfering
radionuclides
can
result
in
the
incorrect
determination
of
radionuclide
activities
and/
or
isotopic
ratios.
Like
neutron
counters,
effects
due
to
source
and
matrix
heterogeneity
can
be
significantly
reduced
by
rotating
the
container
during
the
measurement.
Additionally,
segmented
gamma
scanners,
using
transmission
sources,
can
account
for
spatial
variations
in
the
source
activity
and
matrix
attenuation
properties
as
a
function
of
height.
A
number
of
systems
also
use
computed
tomography
(CT)
to
measure
the
matrix
properties
and
source
distribution
in
three
dimensions.
II.
B.
4
Scope
of
EPA
Approvals
for
Nondestructive
Assay
EPA
approves
NDA
methods
for
a
waste
stream
or
group
of
waste
streams
based
on
the
demonstrated
capability
of
the
NDA
system
to
quantify
the
radiological
properties
of
the
waste
stream
(s).
This
approach
has
been
used
because
of
the
194.8(
b)
language
specifying
waste
stream
examinations,
and
also
because
DOE
generator
sites
most
often
test
and
qualify
their
NDA
instruments
to
a
given
set
of
waste
as
defined
by
waste
streams.
This
approach,
however,
has
led
to
some
problems
during
waste
certification
inspections
because
waste
streams
are
generally
defined
by
physical
properties
rather
than
by
radiological
properties.
While
there
is
some
correlation
between
the
effectiveness
of
a
given
NDA
method
and
the
physical
properties
of
the
waste
material
(e.
g.,
a
highly
absorbing
or
moderating
matrix
like
organic
sludge),
in
practice
this
approval
system
has
frequently
resulted
in
limited
approvals
relative
to
the
total
population
of
waste
intended
for
approval.
A
few
sites,
such
as
INEEL
and
LANL,
currently
attempt
to
define
their
assay
programs
as
a
process
applicable
to
broad
ranges
of
wastes
that
are
defined
by
their
radiological
and
nuclear
properties
of
interest
to
the
assay
method
(e.
g.,
moderator/
absorber
index
for
neutron
systems),
rather
than
strictly
by
waste
stream
or
Summary
Waste
Category
Group.
Other
generator
sites,
such
as
Savannah
River,
have
programs
that
are
designed
around
the
waste
stream
intended
for
shipment.
A
radioassay
system
should
be
capable
of
characterizing
waste
containers,
provided
the
important
matrix
properties
of
the
containers
are
within
the
bounds
for
which
the
system
is
calibrated.
For
neutron
systems,
the
absorption
and
moderating
properties
of
the
matrix
are
of
primary
interest.
Density
and
atomic
number
of
the
waste
are
of
primary
interest
for
gamma
spectrometry
systems.
Since
NDA
systems,
particularly
neutron
systems,
often
use
different
parameters
to
characterize
the
matrix
properties,
it
is
difficult
to
establish
standard
limits
for
matrix
characteristics
or
to
compare
calibration
limits
from
one
instrument
to
another.
II.
C
Visual
Examination
and
Radiography
Radiography
(e.
g.,
RTR)
is
a
nondestructive,
qualitative
and
quantitative
technique
that
involves
x
ray
scanning
of
waste
container
contents.
It
is
used
to
identify
and
quantify
waste
28
material
parameters
important
to
PA,
such
as
cellulosic,
plastic,
and
rubber
content.
Radiography
also
is
used
to
identify
items
such
as
liquids,
pyrophorics,
explosives,
compressed
gas
cylinders,
and
sealed
containers
larger
than
4
liters,
which
are
prohibited
from
disposal
by
DOE.
Unlike
nondestructive
assay,
no
radiological
analysis
is
done
with
this
technique.
Radiography
is
considered
to
be
both
qualitative
and
quantitative
because
measurements
are
made
by
an
operator
who
views
a
real
time
x
ray
scan
of
the
contents
of
a
waste
container
(e.
g.,
drum
or
standard
waste
box)
to
estimate
values
for
parameters
of
interest.
For
example,
the
operator
(based
on
experience,
on
the
job
training,
and
drum
aids)
estimates
the
container
fill
percentage
(i.
e.,
the
percentage
of
the
drum
filled
with
waste),
the
volume
of
"combustible"
materials,
metals,
etc.
Visual
Examination
(VE)
involves
opening
of
waste
containers
in
glove
boxes
or
other
controlled
structures
and
manually
cataloging
the
contents.
VE
is
currently
used
as
either
a
confirmation
of
Nondestructive
Examination
(NDE)
which
to
date
has
been
RTR
or
as
a
replacement
for
NDE.
Visual
verification
(which
differs
from
VE
in
that
the
visual
verification
process
is
used
during
repackaging
and
no
videotape
records
are
kept)
is
also
used.
Sites
are
required
to
conduct
VE
on
newly
generated
waste,
on
a
statistically
selected
population
of
waste
containers
examined
through
radiography,
and
on
waste
containers
that
the
site
was
unable
to
characterize
using
either
radiography
and/
or
NDA
due
to
the
presence
of
an
interfering
material,
such
as
lead
shielding.
The
results
of
the
VE
of
the
statistically
selected
population
of
waste
containers
is
used
by
the
site
to
verify
waste
container
determinations
(and
measurements)
made
through
radiography.
The
site
is
required
to
calculate
miscertification
rates
on
an
annual
basis
and,
based
on
these
calculations
(and
estimates
of
the
number
of
waste
containers
to
be
radiographed
in
the
coming
year),
determine
the
required
number
of
waste
containers
to
undergo
VE
in
the
following
year.
II.
C.
1
Overview
of
Technical
Elements
EPA
typically
views
actual
radiography
and
VE
activities
during
inspections,
as
well
as
supporting
documentation
and
procedures.
At
a
minimum,
radiography
and
VE
should
provide
the
following:
°
Identification
of
cellulosics,
plastics,
and
rubber,
including
quantities;
°
Identification
of
prohibited
items,
including
liquids;
and
°
Confirmation
of
Summary
Waste
Category
Group
and
Waste
Matrix
Code.
Under
the
CH
TRU
program,
every
retrievably
stored
container
must
be
examined
to
determine
the
cellulosics,
plastics,
rubber
(CPR),
and
prohibited
item
content
using
RTR.
Alternatively,
containers
can
be
examined
either
visually
or
by
a
different
NDE
technology,
such
as
CT
or
digital
radiography
(DR),
if
RTR
is
not
possible.
Newly
generated
wastes
do
not
have
to
be
examined
using
RTR
because
the
packaging
process
would
exclude
the
inclusion
of
prohibited
items.
II.
C.
1.1
RTR
Document
Review
29
EPA
examines
site
specific
documents
and
information
related
to
any
of
the
following
areas
during
inspections:
°
Replicate
Scans.
The
sites
must
document
that
the
imaging
system
characteristics
of
the
monitoring
system
are
verified
on
a
routine
basis
and
that
independent
replicate
scans
and
replicate
observations
of
the
audio/
video
output
of
the
RTR
process
are
performed
under
uniform
conditions
and
procedures.
C
Independent
Observations.
The
sites
must
document
that
independent
observations
of
RTR
scans
are
performed
during
each
work
shift.
C
System
Capabilities.
The
site
must
document
that
its
RTR
system
is
appropriate
and
is
capable
of
characterizing
the
typical
waste
configurations
and
parameters
observed
at
the
site.
C
Procedures.
The
site
must
have
procedures
for
ensuring
that
the
RTR
system
is
tested,
inspected,
and
maintained
in
accordance
with
manufacturer
instructions.
In
addition,
EPA
expects
the
site's
procedures
to
address
the
following:
The
RTR
system
is
calibrated
through
observation
of
a
test
pattern
at
the
beginning
and
end
of
each
work
shift
(when
operating).
The
RTR
system
must
be
able
to
be
adjusted
to
obtain
optimum
contrast
and
resolution
using
a
line
pair
gauge
or
equivalent
device.
Data
management
is
sufficient
to
ensure
that
the
RTR
results
for
every
waste
container
are
documented,
validated,
and
ultimately
verified
by
VE
of
a
randomly
selected
statistical
population
of
waste
containers.
The
RTR
examination
is
captured
on
both
audio/
video
and
documents
the
following
types
of
information
necessary
for
WIPP
WAC
certification:
Item
description
code
(IDC),
TRUCON
code
(Transuranic
Package
Transporter
II
Content
Code),
Presence
or
absence
of
free
liquids,
Content
inventory,
and
Description
of
contents
packaging
materials.
The
following
types
of
information
resulting
from
the
RTR
examination
must
be
recorded:
Waste
container
identification
number;
Date
of
radiography
examination;
TRUCON
code,
IDC,
and
Waste
Matrix
Code,
as
applicable;
30
Any
changes
made
to
Waste
Matrix
Code;
Presence
or
absence
of
waste
container
liner;
Estimated
inventory
of
waste
container
contents;
Description
of
contents
packaging
materials,
including
the
number
of
layers
of
packaging;
Audio/
videotape
identification
number;
Estimate
of
each
applicable
waste
material
parameter
weight;
Identification
of
quality
control
(QC)
replicate;
and
An
operator/
reviewer
signature
and
date
block.
Explicit
guidance
is
included
to
account
for
materials
that
interfere
with
the
RTR
examination
(e.
g.,
lead
liners,
leaded
gloves,
stabilized
wastes
or
cement,
etc.).
Prohibited
items
must
be
identified
and
procedures
followed
to
ensure
that
the
proper
steps
are
taken
to
isolate
the
particular
waste
container.
Appropriate
measures
can
be
taken
when
conditions
adverse
to
quality
occur.
C
Reporting.
EPA
examines
the
data
reports
prepared
by
the
site.
Each
data
report
batch
may
not
include
more
than
20
waste
containers.
The
data
reports
must
contain
the
following
types
of
records:
RTR
data
forms,
RTR
reports,
RTR
videotape,
and
Identification
of
any
nonconformance
reports
(NCRs)
and
variances
pertinent
to
the
data
package.
C
C
Data
Quality
Characteristics.
The
site
should
have
a
procedure
for
correctly
calculating
and
reporting
the
relative
percent
difference
between
the
estimated
waste
material
parameter
weights
(as
determined
by
the
RTR
operator)
and
these
same
parameters
as
determined
visually
(i.
e.,
precision).
The
site
must
also
have
a
procedure
for
documenting
the
accuracy
with
which
the
matrix
parameter
category
can
be
determined
through
VE
of
a
randomly
selected
statistical
subpopulation
of
waste
containers.
The
site
must
prepare
and
validate
RTR
data
forms
and
audio/
videotape
for
100
percent
of
the
waste
containers
examined
(i.
e.,
completeness).
The
site
must
also
document
the
comparability
of
the
matrix
parameter
category
determined
by
RTR
with
the
matrix
parameter
category
determined
by
VE
(i.
e.,
comparability).
II.
C.
1.2
Additional
Verification
(RTR)
During
the
course
of
the
on
site
inspection
of
the
radiography
system
and
site
operating
procedures,
the
EPA
inspection
team
both
observes
the
radiography
operation
and
interviews
31
radiography
operators
and
other
DOE/
contractor
personnel
to
assess
how
well
the
radiography
process
is
being
implemented.
As
part
of
the
EPA
inspection
team's
observation
of
the
radiography
operation,
the
inspection
team
both
views
videotaped
recordings
of
previously
radiographed
waste
containers
and
observes
the
actual
operation
of
the
radiography
equipment.
The
EPA
inspection
team
notes
the
presence
of
required
equipment,
adherence
to
procedures,
and
documentation
of
all
activities.
For
example,
the
EPA
inspection
team
inspects
the
radiography
booth
and
asks
the
radiography
operators
to
point
out
all
of
the
required
radiographic
equipment,
as
described
originally
in
the
TRU
QAPP
(Section
10)
and
Methods
Manual
(CCA
Reference
No.
210),
and
subsequently
in
the
WAP:
C
A
shielded
room
that
is
properly
ventilated
and
lighted,
C
An
x
ray
producing
device,
C
Controls
which
allow
the
operator
to
vary
voltage,
typically
between
150
400
kV,
C
An
imaging
system
that
typically
includes
a
fluorescent
screen
and
a
low
light
television
camera,
C
An
enclosure
for
radiation
protection,
C
A
waste
container
handling
system
(including
a
turntable
dolly
assembly),
C
An
audio/
video
recording
system,
C
Safety
interlocks,
and
C
An
operator
control
and
data
acquisition
station.
As
part
of
the
inspection
activities,
the
radiography
operator
is
required
to
demonstrate
the
operation
of
the
radiography
equipment,
including
estimation
of
waste
materials'
parameters
and
volumes,
and
data
entry.
The
EPA
inspection
team
also
interviews
the
radiography
operators
and
DOE
staff/
contractors
involved
in
certifying
and
tracking
operator
training
to
ensure
that
a
formal
operator's
training
program
exists
and
is
completely
implemented.
The
EPA
inspection
team
requires
the
training
staff
and
radiography
operators
to
demonstrate
through
actual
radiography
equipment
operation
and
training
file
documentation
that
operator
training
includes
the
following,
at
a
minimum:
C
Formal
training
Project
requirements,
State
and
federal
regulations,
Basic
principles
of
radiography,
Radiographic
image
quality,
and
Radiographic
scanning
techniques.
C
Application
techniques
32
Radiography
of
waste
forms,
Standards,
codes,
and
procedures
for
radiography,
and
Site
specific
instruction.
C
On
the
job
training
System
operation,
Identification
of
packaging
configurations,
Identification
of
WMPs,
Weight
and
volume
estimation,
and
Identification
of
prohibited
items.
The
EPA
inspection
team
observes
the
operator's
examination
of
a
radiography
test
drum
(either
in
real
time
or
by
reviewing
videotape)
and
expects
to
see
the
operator
satisfactorily
identify
its
content.
The
EPA
inspection
team
reviews
the
contents
of
the
radiography
test
drum
to
ensure
that
the
following
required
elements
are
present:
C
Aerosol
can
with
puncture,
C
Horsetail
bag,
C
Pair
of
coveralls,
C
Empty
bottle,
C
Irregular
shaped
pieces
of
wood,
C
Empty
one
gallon
paint
can,
C
Full
container,
C
Aerosol
can
with
fluid,
C
One
gallon
bottle
with
three
tablespoons
of
fluid,
C
One
gallon
bottle
with
one
cup
of
fluid
(upside
down),
C
Leaded
glove
or
leaded
apron,
and
C
Wrench.
Training
drums
must
contain
all
of
the
required
test
elements.
The
EPA
inspection
team
requests
the
radiography
operator
to
discuss
how
the
site
has
determined
that
the
test
drum
contained
test
elements
that
were
typical
of
what
might
be
encountered
at
the
site
(both
content
and
packaging
density).
EPA
expects
there
to
be
a
process
for
ensuring
that
the
RTR
operators
receive
standardized
training
and
certification,
recertification,
retraining,
and
on
the
job
training
with
oversight
from
appropriately
qualified
RTR
operators.
RTR
operators
must
have
sufficient
experience
to
operate
the
RTR
system.
EPA
expects
RTR
operators
to
be
instructed
in
the
specific
waste
generating
practices
and
typical
packaging
configurations
expected
for
each
matrix
parameter
category
or
IDC.
33
EPA
inspectors
examine
the
procedures
for
ensuring
that
this
training
occurs,
as
well
as
operator
training/
experience
records
to
ensure
that
the
personnel
operating
the
RTR
system
are
qualified
and
appropriately
trained.
Inspectors
also
interview
the
RTR
operators
and
observes
their
operation
of
the
RTR
system.
EPA
expects
the
generator
sites
to
provide
procedures
regarding
the
operation
of
the
RTR
system,
and
RTR/
VE
records
(see
below)
that
document
that
the
required
technical
elements
are
adequately
addressed
by
these
procedures.
EPA
may
require
the
generator
site
to
provide
RTR
data
packages
and
RTR/
VE
comparison
sheets,
including
calculations
of
miscertification
rates
and
other
information
pertinent
to
making
the
determination
that
the
generator
site
has
a
system
of
controls
in
place
that
adequately
meets
the
requirements
of
§194.24(
c)(
4).
II.
C.
1.3
VE
Document
Review
EPA
examines
VE
documents
and
information
related
to
any
of
the
following
areas
during
inspections:
C
Documentation.
The
VE
procedure
ensures
that
the
inventory
of
unopened
contents
includes
a
description
and
documented
weight
of
all
waste
items,
residual
materials,
poly
liners,
contents
packaging
materials,
and
waste
material
parameters.
C
Reference
Tables.
The
site's
VE
procedure
has
reference
tables,
updated
as
necessary,
to
facilitate
the
development
of
weight
estimates
and
assignment
of
wastes
to
waste
material
parameters,
also
updated
as
necessary
during
the
process.
The
site
must
establish
standard
nomenclature
and
volumetric
conversion
factors.
C
VE
Data.
VE
staff
record
a
description
of
the
location,
container,
and
estimated
volume
of
any
detected
liquid.
All
empty
containers
must
be
weighed
and
recorded,
with
the
gross
weight
of
each
container
recorded
on
the
VE
data
form.
The
site
must
also
record
the
total
number
of
bags
or
packages
found
in
each
waste
container.
Replicate
weight
measurements
must
also
be
made.
C
Miscertification
Rate.
The
site
must
have
a
procedure
to
select
a
random
statistical
sample
of
waste
containers
for
VE
and
correctly
calculate
and
report
an
annual
miscertification
rate.
The
site
may
use
INEEL's
historical
miscertification
rate
of
2
percent
to
calculate
the
number
of
waste
containers
that
must
be
visually
examined
during
the
first
year
of
program
activities.
However,
the
site
must
also
have
a
procedure
for
establishing
a
site
specific
miscertification
rate
that
is
based
on
the
last
12
(or
more)
months
of
certification
activities.
C
Radiography
Check.
EPA
expects
that
site
procedures
require
the
use
of
data
from
VE
to
check
the
matrix
parameter
category
and
waste
material
parameter
weight
estimates
as
determined
by
radiography.
34
C
Replacement
Containers.
The
facility
must
have
a
procedure
for
selecting
replacement
waste
containers.
The
site's
replacement
strategy
should
be
restricted
to
a
waste
stream
or
waste
stream
lot
that,
through
the
random
selection
process,
happened
to
have
container(
s)
identified
for
VE.
The
procedure
must
ensure
that
VE
is
performed
on
the
replacement
container.
Once
containers
have
been
visually
examined,
the
upper
90
percent
confidence
limit
(UCL90)
for
the
proportion
miscertified
must
be
correctly
calculated.
EPA
expects
the
site
to
use
the
hypergeometric
distribution
for
the
UCL90
calculation.
C
Data
Management.
The
site
must
have
a
procedure
for
data
management
that
is
sufficient
to
ensure
that
the
VE
results
for
every
waste
container
examined
are
documented
and
validated.
C
Documentation.
VE
examination
must
be
captured
on
both
audio
and
video
to
document
IDC,
TRUCON
code,
the
presence
or
absence
of
free
liquids
and
other
prohibited
items,
content
inventory,
and
a
description
of
contents
packaging
materials.
C
Data
Reports.
The
site
must
ensure
that
data
reports
are
prepared
on
a
per
batch
basis,
which
includes
no
more
than
20
waste
containers,
and
the
data
reports
must
contain
VE
data
forms,
VE
reports,
VE
videotape(
s),
and
identification
of
any
NCRs
and
variances
pertinent
to
the
data
package.
The
site's
data
reporting
procedures
should
ensure
that
the
following
types
of
information
resulting
from
the
VE
are
recorded:
Waste
container
identification
number,
Date
of
VE,
TRUCON
code,
IDC,
and
Waste
Matrix
Code,
as
applicable,
Any
changes
made
to
the
Waste
Matrix
Code,
Presence
or
absence
of
waste
container
liner,
Estimated
inventory
of
waste
container
contents,
Description
of
contents
packaging
materials,
including
the
number
of
layers
of
packaging,
Audio/
videotape
identification
number,
Estimate
of
each
applicable
waste
material
parameter
weight,
Identification
of
QC
replicate,
and
Operator/
reviewer
signature
and
date
blocks.
C
Interfering
Items.
The
site's
VE
procedure
should
provide
explicit
guidance
on
how
to
handle
materials
that
interfere
with
the
examination,
such
as
metal
containers,
discolored
plastic
bags,
stabilized
wastes
or
cement,
etc.
Also,
the
site's
VE
procedure
must
require
that
prohibited
items
be
identified
and
that
the
proper
steps
be
taken
to
isolate
a
waste
container
with
prohibited
items.
C
Discrepancy
Resolution.
EPA
expects
the
site
to
have
a
procedure
for
resolving
35
discrepancies
between
VE
QC
checks
and
between
RTR
and
VE
observations,
and
to
ensure
that
appropriate
measures
can
be
taken
when
conditions
adverse
to
quality
occur.
II.
C.
1.4
Additional
Verification
VE
During
the
course
of
the
on
site
inspection
of
VE
activities
and
site
operating
procedures,
the
inspection
team
observes
VE
activities
and
interviews
VE
experts
and
other
personnel
to
assess
how
well
the
VE
process
is
being
implemented.
As
part
of
the
inspection
team's
observation
of
the
VE,
the
inspection
team
views
videotaped
recordings
of
previously
examined
waste
containers
and
observes
the
actual
VE
of
waste
containers
(when
possible).
Inspectors
note
the
presence
of
required
equipment,
adherence
to
procedures,
and
documentation
of
all
activities.
For
example,
the
EPA
inspection
team
inspects
the
VE
glove
box
(or
room)
and
ask
the
VE
experts
to
point
out
all
of
the
required
equipment,
as
described
in
DOE's
Method
Manual
(CCA
Reference
No.
210),
as
listed
in
the
following
bullets:
C
Check
weights
(certified
to
National
Institute
of
Standards
and
Technologies
standards),
C
Scales,
C
Torque
wrenches,
C
Airflow
meters,
C
Platform
scale,
C
Empty
55
gallon
drums,
C
Remote
drum
handler,
C
Knifes,
scissors,
platform
ladder,
dolly/
drum
mover,
leather
gloves,
plastic
bags,
tape,
towels,
decontamination
solution,
secondary
containment
bags,
permanent
markers,
rubber
and/
or
surgical
gloves,
C
Video
camera,
C
Audio
recording
system,
and
C
Glove
box
or
negative
pressure
containment
area.
The
EPA
inspection
team
also
interviews
the
VE
experts
and
other
personnel
involved
in
certifying
and
tracking
operator
training
to
ensure
that
a
formal
operator's
training
program
exists
and
is
complete.
There
must
be
a
standardized
training
program
for
visual
inspection
examiners
that
includes
both
formal
classroom
and
on
the
job
training
(OJT).
The
program
must
be
specific
to
the
generator
site
and
includes
the
various
waste
configurations
generated/
stored
at
the
site.
The
EPA
inspection
team
interviews
the
VE
experts
to
determine
whether
(and
the
extent
to
which)
they
have
received
training
on
the
specific
waste
generating
processes,
typical
packaging
configurations,
and
waste
material
parameters
expected
to
be
found
in
each
matrix
parameter
category
at
the
site.
EPA
expects
the
VE
training
program
to
include:
°
Formal
training
Project
requirements,
36
State
and
federal
regulations,
Application
techniques,
and
Site
specific
instruction.
°
On
the
job
training
Identification
of
packaging
configurations,
Identification
of
waste
material
parameters,
Weight
and
volume
estimation,
and
Identification
of
prohibited
items.
EPA
expects
sites
to
provide
procedures
regarding
the
performance
of
VE.
EPA
also
expects
generator
sites
to
provide
VE
data
packages
and
RTR/
VE
comparison
sheets,
including
calculations
of
miscertification
rates
and
other
information
pertinent
to
making
the
determination
that
the
generator
site
has
a
system
of
controls
in
place
that
adequately
meets
the
requirements
of
194.24(
c)(
4).
II.
C.
2
Technical
Description
of
System
or
Measurement
Device(
s)
II.
C.
2.1
Radiography
Radiographic
systems
include
not
only
real
time
systems,
but
new
systems
that
are
currently
being
brought
on
line
at
DOE
sites.
These
new
systems
may
offer
advantages
over
RTR
with
respect
to
system
resolution,
etc.
Real
Time
Radiography
Sites
are
currently
conducting
NDE
examination
of
all
waste
containers
using
standard
radiography
techniques
(i.
e.,
an
x
ray
tube,
an
image
intensifier,
and
a
charge
coupled
device
camera).
As
part
of
the
RTR
process,
the
RTR
operator
(or
drum
handler)
loads
up
to
three
waste
containers
onto
a
rolling
sled
that
is
then
moved
into
the
RTR
vault.
The
drum(
s)
is
placed
on
a
turntable
that
the
operator
uses
to
rotate
the
drum
and
the
x
ray
system
components
automatically
move
up
and
down
to
smoothly
transition
through
the
entire
height
of
the
drum
(with
every
revolution
the
height
of
the
x
ray
system
components
change
to
allow
for
an
automated,
complete
scan
of
the
entire
container
from
top
to
bottom).
Some
sites
do
not
employ
a
turn
table
that
automatically
moves
up
and
down,
but
rely
instead,
on
the
operator
to
manually
adjust
the
height
of
the
drum
manually
to
obtain
a
scan
of
100
percent
of
the
drum's
height.
The
x
ray
producing
device
has
controls
that
allow
the
operator
to
vary
the
voltage,
thereby
controlling
image
quality.
It
is
typically
possible
to
vary
the
voltage,
between
150
to
430
kilovolts
(KV),
to
provide
an
optimum
degree
of
penetration
through
the
waste.
For
example,
high
density
material
should
be
examined
with
the
x
ray
device
set
on
the
maximum
voltage
to
ensure
maximum
penetration
through
the
waste
container.
Low
density
material
should
be
37
examined
at
lower
voltage
settings
to
improve
contrast
and
image
definition.
The
imaging
system
typically
uses
a
fluorescent
screen
and
a
low
light
television
camera.
To
perform
radiography,
the
waste
container
is
scanned
while
the
operator
views
the
television
screen.
The
RTR
operator
controls
the
entire
process
from
a
remote
operator's
booth
and
the
entire
exam
is
recorded
on
audio/
video
tape
(some
sites
use
optical
disks).
The
operator
then
records
the
data
using
data
sheets;
however,
several
sites
use
automated
data
entry
systems.
For
example,
INEEL
RTR
operators
use
an
automated
data
entry
system,
which
has
a
series
of
screens
designed
to
capture
the
required
information.
The
RTR
examination
results
are
used
by
the
site
to
verify
that
the
physical
waste
form
matches
the
waste
stream
description,
to
document
the
waste
matrix
code
group,
to
estimate
waste
material
parameters
and
drum
utilization,
to
confirm
AK,
and
to
identify
prohibited
items.
Sites
also
compare
the
radiography
RTR
examination
results
with
those
obtained
through
VE
to
calculate
miscertification
rates
on
an
annual
basis
and,
based
on
these
calculations
(and
the
expected
number
of
waste
drums
to
be
processed
next
year)
determine
the
required
number
of
waste
containers
to
undergo
VE
in
the
following
year.
II.
C.
2.2
Visual
Examination
Sites
are
currently
conducting
VE
on
a
statistically
selected
subpopulation
of
waste
containers
examined
through
radiography,
and
any
waste
container
that
the
site
was
unable
to
characterize
through
radiography
due
to
the
presence
of
an
interfering
material,
such
as
lead
shielding.
As
part
of
the
VE
process,
the
VE
team
typically
opens
each
waste
container
in
a
specially
designed
glove
box
that
is
approximately
15
feet
long
and
operated
under
a
negativepressure
environment.
At
some
sites,
core
sampling
is
also
conducted
in
this
glove
box.
Although
the
VE
process
is
relatively
straightforward,
it
is
a
physically
demanding
and
intensive
operation
and
typically
consists
of
the
VE
technicians
performing
the
following
steps:
C
Load
the
waste
drum
at
the
back
end
of
the
glove
box,
C
Remove
the
drum
lid
and
empty
the
drum's
contents
in
the
middle
portion
of
the
glove
box,
C
Open
every
individual
waste
package
or
bag,
and
C
Manually
sort
and
categorize
waste
materials
for
subsequent
weighing
and
repackaging
at
the
front
end
of
the
glove
box.
The
entire
process
is
conducted
under
the
supervision
of
the
VE
expert
(VEE)
and
is
recorded
on
both
audio/
video
tape
and
waste
container
inventory
sheets.
The
VE
results
are
used
by
the
site
to
verify
waste
form,
confirm
and/
or
identify
prohibited
items,
and
verify
drum
utilization
and
waste
material
parameter
estimates
made
through
radiography.
The
VEE
also
assesses
the
need
to
open
individual
bags
or
packages
of
waste.
If
individual
bags/
packages
are
not
opened,
estimated
weights
are
recorded.
Estimated
weights
are
established
through
the
use
of
historically
derived
waste
weight
tables
and
an
estimation
of
the
waste
volumes.
It
may
not
be
possible
to
see
through
inner
bags
because
of
discoloration,
dust,
or
because
inner
containers
are
38
sealed.
In
these
instances,
documented
AK
can
be
used
to
identify
the
matrix
parameter
category
and
estimated
waste
material
parameter
weights.
If
AK
is
insufficient
for
individual
bags/
packages,
actual
weights
of
waste
items,
residual
materials,
contents
packaging
materials,
or
waste
material
parameters
are
recorded.
The
sites
also
compare
the
VE
data
to
that
obtained
through
radiography
to
calculate
miscertification
rates
on
an
annual
basis
and,
based
on
these
calculations
(and
the
expected
number
of
waste
drums
to
be
processed
next
year),
determine
the
required
number
of
waste
containers
to
undergo
VE
in
the
following
year.
II.
C.
3
Effect
of
Waste
Matrix
or
Waste
Type
on
Measurement
As
discussed
previously,
the
RTR
operator
can
vary
the
voltage
to
provide
an
optimum
degree
of
penetration
through
the
waste.
For
example,
high
density
material
needs
to
be
examined
with
the
x
ray
device
set
on
the
maximum
voltage
to
ensure
maximum
penetration
through
the
waste
container.
In
comparison,
low
density
materials
need
to
be
examined
at
lower
voltage
settings
to
improve
contrast
and
image
definition.
For
example,
containers
with
lead
liners
or
containers
filled
with
sludges
or
stabilized
(or
cemented)
wastes
cannot
be
readily
penetrated
by
the
x
ray
energy.
Thus,
containers
with
lead
liners,
or
other
containers
whose
contents
prevent
full
examination,
are
either
repackaged
or
examined
using
VE.
Radiography
systems
also
can
have
difficulty
detecting
cellulosics
in
lead
lined
drums
because
a
higher
energy
x
ray
must
be
used
to
scan
through
the
lead
lining.
The
higher
energy
xray
scans
past
the
cellulosics
as
well.
Similarly,
sites
may
be
unable
to
differentiate
between
cellulosics
and
plastics,
as
low
density
materials
can
appear
very
similar.
Densely
packed
drums
with
highly
heterogeneous
waste
materials
can
be
difficult
to
characterize,
as
can
bottles
and
cans
that
are
completely
filled
with
liquid
(there
is
no
observable
meniscus
during
container
motion).
VE
is
a
physically
demanding
task
and
densely
packed
drums
can
take
a
long
time
to
be
completely
examined;
however,
as
long
as
sufficient
time
and
working
space
are
available
there
should
be
no
reduction
in
data
quality.
Likewise,
waste
containers
packed
with
fine
particles
(e.
g.,
soda
ash,
graphite,
or
incinerator
residue)
can
present
a
housekeeping
problem,
but
also
can
be
examined
as
long
as
sufficient
time
and
working
space
are
available.
Inner
containers
that
are
opaque
or
are
packed
with
sharp
metal
objects
are
challenging
and
must
be
handled
with
care.
Opaque
containers
are
generally
opened,
unless
the
VEE
is
able
to
determine
what
the
contents
of
the
container
are
based
on
AK.
The
handling
of
waste
packages
containing
sharp
metallic
objects
is
minimized
and
often
times
set
aside
for
repackaging
so
as
not
to
present
undue
risks
to
the
VE
personnel.
II.
C.
4
Scope
of
EPA
Approvals
for
Radiography
and
Visual
Examination
All
types
of
CH
TRU
wastes
may
be
examined
using
RTR,
except
for
those
that
are
packed
in
lead
lined
containers
or
have
been
stabilized.
Also,
all
types
of
CH
TRU
wastes
may
be
39
examined
using
VE,
except
for
those
that
have
been
stabilized.
EPA's
approvals
with
respect
to
RTR
and
VE
have
been
limited
to
date
by
the
scope
of
the
approval
sought
by
the
sites.
Reinspection
would
be
required
with
the
introduction
of
new
systems
(e.
g.,
DR/
CT,
VE
technique),
or
specific
wastes
(e.
g.
RH
TRU
waste,
lead
lined
drums).
II.
D
WIPP
Waste
Information
System
and
Data
Validation
To
ensure
that
the
sites
ship
only
waste
that
conforms
with
the
waste
component
requirements
established
by
DOE,
a
system
of
controls
must
be
implemented
that
includes
tracking
of
information
about
waste
destined
for
the
WIPP.
For
this
purpose,
DOE
uses
a
computerized
waste
tracking
system,
the
WIPP
Waste
Information
System
(WWIS).
The
WWIS
is
a
data
transfer
system
whereby
waste
characterization
and
other
information
is
input
electronically
at
generator
sites
and
is
transferred
to
WIPP
prior
to
waste
shipment.
Additionally,
EPA
examines
the
data
validation
and
verification
processes
for
checking
data
ultimately
input
into
the
WWIS.
II.
D.
1
Overview
of
Technical
Elements
When
EPA
conducts
inspections
to
verify
compliance
with
§194.24(
c)(
4),
EPA
reviews
the
WWIS
for
the
following
items:
C
The
total
quantity
of
waste
(volumetrically);
C
The
quantity
of
the
important
non
radionuclide
waste
components
for
which
DOE
has
identified
limits;
C
Radionuclide
activity
for
the
ten
WIPP
radionuclides;
C
Radionuclide
activity
uncertainty;
C
Radionuclide
mass;
C
Radionuclide
mass
uncertainty;
C
TRU
alpha
activity;
C
TRU
alpha
activity
uncertainty;
C
Verification
data;
C
Verification
method;
40
C
Visual
examination
of
container;
C
WAC
certification
data;
C
Waste
Matrix
Code
(WMC);
and
C
General
location
of
the
waste
in
WIPP.
II.
D.
1.1
Data
Validation/
Verification
and
WWIS
Inspection
Components
EPA
inspects
the
following
components
of
the
systems
of
control
for
tracking
WIPP
waste
parameters:
°
Documentation.
The
inspection
team
first
reviews
site
documentation
including,
but
not
limited
to,
Standard
Operating
Procedures
(SOPs),
Detailed
Technical
Procedures
(DTPs),
and
QAPjPs.
These
are
reviewed
to
ensure
that
technical
elements
are
adequately
addressed,
that
the
applicable
WAC
and
WAP
technical
elements
and
requirements
are
adequately
addressed
in
site
procedures
or
other
documents,
and
that
the
technical
results
of
procedure
implementation
are
adequate.
°
Data
Collection
and
Entry.
EPA
examines
the
overall
data
collection
and
date
entry
process
for
consistent
implementation
to
ensure
data
integrity
and
accuracy.
Procedures
are
also
examined
to
ensure
that
they
are
acceptable
and
allow
for
submitting
data
to
WIPP
via
the
WWIS
system.
°
Data
Validation.
EPA
ensures
that
procedures
exist
and
are
technically
adequate
for
reviewing/
validating
waste
characterization
data
prior
to
submittal
to
WIPP
via
WWIS.
°
Data
Requirements.
The
Agency
also
determines
whether
data
are
collected
and
formatted
consistently
with
requirements
of
WWIS,
including:
Container
number
TRU
alpha
activity
Site
identifier
TRU
alpha
activity
uncertainty
Waste
stream
profile
number
Matrix
code
TRU
alpha
activity
concentration
TRUCON
code
Decay
heat
TRU
alpha
activity
Decay
heat
uncertainty
concentration
uncertainty
Packaging
number
239
Pu
equivalent
activity
Assembly
identifier
239
Pu
fissile
gram
equivalent
Handling
code
239
Pu
fissile
gram
equivalent
Waste
type
code
uncertainty
Radionuclide
name
Packaging
layers
41
Radionuclide
activity
Alpha
surface
contamination
Radionuclide
activity
uncertainty
Dose
rate
Radionuclide
mass
Sample
identifier
Radionuclide
mass
uncertainty
Sample
type
Waste
material
parameter
weight
Sample
date
Radioassay
method
Analyte
Assay
date
Analyte
concentration
Characterization
method
Analyte
detection
method
Characterization
method
date
Shipment
number
°
Data
Security.
Procedures
should
be
in
place
to
ensure
that
data
in
the
system
are
secure.
°
WWIS
Verification.
Procedures
should
be
in
place
to
verify
data
submitted
to
the
WIPP
via
the
WWIS
system.
The
sites
must
provide
any
container
specific
tracking
reports
(e.
g.,
WWIS
Waste
Container
Data
Reports),
data
validation
forms,
and
other
information
as
needed
to
determine
that
the
site
has
a
system
of
controls
in
place
that
adequately
meets
the
requirements
of
§194.24(
c)(
4).
II.
D.
1.2
Demonstration
of
WWIS
Implementation
EPA
inspection
team
observes
a
demonstration
of
data
entry
and
submittal
to
the
WIPP
site
via
the
WWIS
system
and
interviews
system
operators
and
data
tracking/
validation
officials
to
assess
the
extent
to
which
the
specified
processes
are
being
implemented.
The
inspection
team
observes
adherence
to
procedures,
proper
documentation
of
required
data
(e.
g.,
validation
at
the
project
level,
verification
of
data
received
from
the
WWIP
site
after
submittal
of
characterization
data),
and
results
of
system
operation.
No
specific
analytical
equipment
is
required
for
this
process
other
than
the
WWIS
itself
and
any
other
site
specific
data
entry
systems
used
to
convey
site
information
to
the
WWIS,
including
any
computerized
systems
for
implementing
data
validation
procedures.
EPA
expects
the
sites
to
provide
a
demonstration
of
their
data
systems,
the
ability
to
transmit
and
receive
data
from
the
WWIS
system,
and
the
ability
to
verify
that
accurate
data
have
been
input
into
the
WWIS
system.
EPA
inspectors
examine
the
data
system
used
to
collect
waste
characterization
data
to
ensure
that
all
appropriate
data
fields
required
for
entry
into
the
WWIS
are
accounted
for
and
that
the
data
are
transferrable
to
WWIS
either
manually
or
electronically.
Further,
EPA
evaluates
the
quality
of
the
input
data,
by
reviewing
data
packages
at
the
point
of
project
level
data
validation
(the
point
at
which
data
are
input
into
the
WWIS
for
submittal
to
WIPP).
EPA
expects
a
demonstration
of
the
site's
ability
to
ensure
connectivity
with
the
WWIS
and
that
data
can
be
transmitted
via
the
WWIS
to
WIPP
and
received
from
WIPP
as
entered
into
the
site's
individual
data
system.
II.
D.
1.3
Personnel
Qualifications
42
EPA
checks
that
personnel
conducting
validation/
review
and
verification
and
entry
of
waste
characterization
data
into
the
WWIS
data
system
are
qualified
to
enter
data
and
verify
accuracy
of
waste
characterization
data
for
wastes
destined
for
disposal
at
WIPP.
Specifically,
EPA
examines
procedures
for
ensuring
that
training
occurs
and
operator
training/
experience
records
for:
°
Initial
WWIS
orientation
°
Using
the
WIPP
Waste
Information
System
User's
Manual
for
Use
by
Shippers/
Generators
(DOE/
CAO
97
2273)
°
Site
specific
procedures
for
manual
or
electronic
data
entry
into
WWIS.
II.
D.
2
Technical
Description
of
Measurement
Device
As
previously
described,
the
WWIS
is
an
electronic
database
that
contains
information
related
to
the
characterization,
certification,
shipment,
and
emplacement
of
TRU
waste
at
the
WIPP.
The
data
are
required
to
ensure
that
waste
destined
for
WIPP
meets
applicable
regulatory
conditions,
including
radionuclide
data
on
CH
and
RH
TRU
waste,
cumulative
activity
of
RH
waste,
and
amount
of
important
waste
material
parameters
(e.
g.,
cellulosics).
Individual
generator
sites
are
responsible
for
inputting
waste
data
into
the
WWIS
system
externally.
Generator
sites
have
developed
their
own
unique
systems
for
collecting
the
information
needed
to
be
transmitted
to
WWIS,
including
worksheets,
electronic
spreadsheets,
and
fully
integrated
electronic
data
systems.
Regardless
of
the
mechanism
for
collecting
data,
each
generator
site
is
responsible
for
verifying
and
validating
all
required
data
prior
to
submittal
to
WIPP
via
the
WWIS
system.
In
the
CCA,
DOE
stated
that
the
WWIS
tracks
waste
components
and
associated
uncertainties
against
their
upper
and
lower
limits
and
provides
notification
before
the
waste
component
limits
are
exceeded,
in
accordance
with
40
CFR
Part
194.24(
e)(
1)
and
(2).
Each
site
has
determined
its
own
approach
for
submitting
TRU
waste
characterization
data
to
WIPP
for
shipments
for
disposal.
In
some
cases,
sites
have
developed
separate
databases
to
track
data
generation,
validation,
and/
or
data
submittal
to
WIPP.
At
other
sites,
the
data
input
system
is
manual,
which
may
result
in
a
higher
degree
of
uncertainty
in
data
quality.
However,
issues
with
respect
to
data
quality
may
also
arise
at
sites
using
electronic
data
collection,
verification,
and
transmittal.
For
example,
EPA
observed
during
an
inspection
at
INEEL
that
personnel
had
the
ability
to
change
data
without
receiving
proper
approval
for
such
changes.
II.
D.
3
Effect
of
Waste
Matrix
or
Waste
Type
on
Measurement
The
WWIS
and
data
validation
programs
at
sites
are
not
impacted
by
waste
type,
with
the
exception
of
RH
TRU
waste.
EPA
determined
in
its
initial
certification
that
DOE
did
not
provide
any
waste
characterization
methods
for
RH
TRU
waste,
nor
was
there
discussion
specific
to
how
DOE
will
quantify
the
RH
TRU
waste.
All
of
the
waste
characterization
discussions
in
Chapter
4
43
of
the
CCA
concern
CH
TRU
waste,
except
for
Chapter
4,
Table
4
13
(p.
4
49),
which
is
entitled
"Applicable
CH
and
RH
TRU
Waste
Component
Characterization
Methods."
Furthermore,
DOE
provided
no
discussion
regarding
the
applicability
of
CH
TRU
waste
characterization
methods
to
RH
TRU
waste.
Therefore,
the
effectiveness
of
existing
WWIS
procedures
and
methods
has
yet
to
be
demonstrated
for
RH
TRU
waste
streams.
II.
D.
4
Scope
of
EPA
Approvals
for
Data
Validation/
Verification
and
the
WWIS
The
range
of
waste
types
that
EPA
may
approve
at
any
given
time
is
not
affected
by
the
WWIS
or
the
data
validation
processes,
with
the
exception
of
RH
TRU
waste
as
described
in
section
D.
3.
To
date,
approvals
have
not
specifically
been
limited
by
waste
type,
although
they
may
be
limited
due
to
other
factors
(e.
g.
NDA).
44
III.
SUMMARY
OF
RESULTS
AND
LESSONS
LEARNED
III.
A
Summary
of
Results
Implementation
of
the
inspection
process
described
in
Sections
I
and
II
has
resulted
in
a
program
whereby
EPA
is
compelled
to
provide
authorizations
that
either
mirror
that
sought
by
the
site
(i.
e.,
for
given
waste
streams
or
Summary
Waste
Category
Groups),
or
is
less
than
that
sought
by
a
site
due
to
system
limitations.
Consequently,
EPA
is
required
to
revisit
sites
multiple
times
as
new
systems,
wastes,
or
other
elements
arise.
Table
2
presents
inspections
performed
by
EPA
to
date
under
the
authority
of
§
194.8(
b)
and
the
scope
of
the
resulting
approvals.
As
shown
in
this
Table,
EPA
has
inspected
7
sites,
ranging
from
one
to
9
times
each.
The
broadest
approval
given
by
EPA
has
been
for
specific
Summary
Waste
Category
Groups
of
Retrievably
Stored
Waste
(i.
e.,
debris
waste
at
RFETS),
while
the
most
limited
approval
was
for
a
single
waste
stream
at
the
SRS,
although
this
limited
approval
was
all
that
SRS
sought
at
the
time
of
the
inspection.
DOE
sites
that
have
been
authorized
by
EPA
to
ship
waste
to
the
WIPP
have
adequate
waste
characterization
programs
overall.
In
some
instances,
EPA
was
unable
to
complete
an
inspection
because
of
the
site's
limited
implementation
of
activities
within
the
scope
of
the
inspection.
45
Table
2
§
194.8(
b)
Inspections
Performed
by
EPA
as
of
January,
2002
Generator
Site
Date
of
Inspection
Type
of
Inspection
Inspection
Scope
Elements
Examined
Scope
of
EPA
Approval
Rocky
Flats
(RFETS)
EPA
RFETS
6.98
8
June
22
25,
1998
194.8
Contact
handled
debris
waste
NDA,
AK,
RTR,
VE,
WWIS/
DV
Characterization
program
was
approved,
with
NDA
approval
limited
to
the
use
of
IQ
3
SGS
and
WM3100
PNC
RFETS
EPA
RFETS
4.99
8
April
27
28,
1999
194.8
Leco
crucibles
and
pyrochemical
salt
NDA,
AK,
VE
Characterization
program
was
approved
and
broadened
to
include
Leco
Crucibles
and
pyrochemical
salt,
with
NDA
approval
expanded
to
include
the
use
of
calorimetry
(CAL/
GAMMA)
RFETS
EPA
RFETS
11.99
8
November
16
18,
1999
194.8
Wet
residue,
dry
residue,
pyrochemical
salts,
incinerator
ash
(including
Leco
crucibles
and
magnesium
oxide
inserts)
NDA/
gravimetric
techniques,
AK,
WWIS/
DV
Characterization
program
was
approved
and
broadened
to
include
wet/
dry
residue,
pyrochemical
salts,
and
incinerator
ash,
with
NDA
approval
expanded
to
include
SGS
Can
Counters,
SGS
Drum
Counters,
and
the
TGS
RFETS
EPA
RFETS
9.00
8
September
18
21,
2000
194.8
Residues
NDA
Characterization
program
was
approved,
with
NDA
approval
expanded
to
include
NMC,
two
new
TGS
CAN
Scanners,
and
a
skid
mounted
Tomographic
Gamma
Can/
Drum
Scanner
RFETS
EPA
RFETS
1.01
8
January
29
February
2,
2001
194.8
Contact
Handled
Retrievably
Stored
Debris/
Solids
NDA
Inspection
postponed
by
DOE
RFETS
EPA
RFETS
5.01
8
May
14
17,
2001
194.8
Debris
waste
NDA,
WWIS/
DV,
VE,
RTR
Limited
approval
of
SuperHENC,
Building
569
PADC,
Building
569
Tomographic
Gamma
Scanner.
Generator
Site
Date
of
Inspection
Type
of
Inspection
Inspection
Scope
Elements
Examined
Scope
of
EPA
Approval
46
INEEL
EPA
INEEL
7.98
8
July
28
30,
1998
194.8
Contact
handled
retrievably
stored
debris
waste
generated
at
Rocky
Flats
AK,
NDA,
VE,
RTR,
WWIS/
DV
Limited
characterization
program
was
approved
for
only
inorganic
solids
and
graphite
debris
waste,
with
NDA
limited
to
Canberra
IQ2
and
SWEPP
PAN
INEEL
EPA
INEEL
5.99
8
May
17
21,
1999
Originally
planned
to
be
194.8,
revised
to
194.24
Scheduled
to
examine
solids,
debris,
soils,
gravels.
AK,
NDA,
RTR,
WWIS/
DV
Elements
of
system
examined
were
inconclusive
with
regard
to
wastes
examined;
EPA
instead
verified
that
previously
approved
system
was
being
adequately
maintained
INEEL
EPA
INEEL
4.00
8
April
24
28,
2000
194.8
Contact
handled
retrievably
stored
debris
waste
generated
at
Rocky
Flats
NDA,
WWIS/
DV,
VE,
RTR
Characterization
program
was
approved
and
broadened
to
include
all
CH
retrievably
stored
debris
waste
generated
at
Rocky
Flats.
NDA
approval
broadened
to
include
SWEPP
SGRS
and
PAN
systems
INEEL
EPA
INEEL
12.00
8
December
5
7,
2000
and
one
day
follow
up
on
January
8,
2001
194.8
Contact
handled
retrievably
stored
homogenous
solids
(S3000)
waste
generated
at
Rocky
Flats
AK,
NDA
Characterization
program
was
approved
and
broadened
to
include
homogenous
solids;
NDA
approval
expanded
to
include
SWEPP
SGRS
and
PAN
systems
re
examined
for
subject
waste
INEEL
EPA
INEEL
7.01
8
July
25
26,
2001
194.8
Contact
handled
retrievably
stored
homogenous
solids
and
debris
waste
generated
at
Rocky
Flats
NDA
Characterization
program
was
approved;
NDA
system
approval
broadened
to
include
WAGS
INEEL
EPA
INEEL
10.01
8
October
29
31,
2001
194.8
Organic
sludge
NDA,
AK
Inspection
postponed
by
DOE
SRS
EPA
SRS
11.00
8
November
6
17,
2000
194.8
Waste
stream
SR
T001
221F
HET
(a
contacthandled
debris
waste)
AK,
NDA,
VE,
RTR,
WWIS/
DV
Characterization
program
approved
for
one
waste
stream;
NDA
approved
use
of
PAN
and
SGS
systems
Generator
Site
Date
of
Inspection
Type
of
Inspection
Inspection
Scope
Elements
Examined
Scope
of
EPA
Approval
47
SRS
EPA
SRS
9.01
8
September
24
26,
2001
194.8
Retrievably
stored,
contact
handled
debris
waste
generated
at
SRS
and
limited
to
waste
streams
SRW027
221F
HET
A
HET
E
AK,
NDA,
VE,
RTR,
WWIS/
DV
Inspection
postponed
by
DOE
SRS
EPA
CCP
10.01
8
October
15
19,
2001
194.8
Retrievably
stored,
contact
handled
debris
waste
generated
at
SRS
and
limited
to
waste
streams
SRW027
221F
HET
A
HET
E
AK,
NDA,
VE,
RTR,
WWIS/
DV
All
elements
approved
for
CCP
systems
at
SRS
only
(i.
e.,
CCP
VE,
IPAN/
GEA,
RTR,
WWIS).
SRS
EPA
SRS
12.01
8
December
12
16,
2001
194.8
Retrievably
stored,
contact
handled
debris
waste
generated
at
SRS
and
limited
to
waste
streams
SRW027
221F
HET
A
HET
E
AK,
NDA
Report
pending.
LANL
EPA
LANL
6.99
8
June
14
18,
1999
194.8
Contact
handled,
retrievably
stored
debris
and
solidified
homogenous
solid
wastes
(S5000
and
S3000)
AK,
NDA,
VE,
RTR,
WWIS/
DV
All
elements
approved,
NDA
systems
approved
were
the
TGS
and
HENC
NTS
EPA
NTS
6.99
8
June
7
11,
1999
194.8
Contact
handled
debris
waste
AK,
NDA,
VE,
RTR,
WWIS/
DV
Waste
characterization
program
did
not
adequately
characterize
the
proposed
waste;
approval
denied.
Hanford
EPA
HAN
1.00
8
January
24
28,
2000
194.8
Contact
handled
debris
waste
AK,
NDA,
VE,
RTR,
WWIS/
DV
Characterization
program
was
approved
for
contact
handled
debris
waste;
NDA
systems
approved
were
two
GEA
systems
and
one
IPAN
system
Generator
Site
Date
of
Inspection
Type
of
Inspection
Inspection
Scope
Elements
Examined
Scope
of
EPA
Approval
48
Hanford
EPA
HAN
12.01
8
December
17
21,
2001
194.8
Contact
handled
debris
and
solid
waste
NDA,
VE
Approved
to
characterize
CH
debris
waste
using
the
SGSAS
NDA
system
and
CH
solids
using
VE
process
during
repackaging.
AK
=
Acceptable
Knowledge;
CAL/
GAMMA
=
Calorimetry;
CBFO
=
DOE
Carlsbad
Field
Office;
CCP
=
Centralized
Characterization
Project;
DOE
=
U.
S.
Department
of
Energy;
DR/
CT
=
Digital
Radiography/
Computed
Tomography;
DV
=
Data
Validation;
GEA
=
Gamma
Energy
Assay;
EPA
=
U.
S.
Environmental
Protection
Agency;
HENC
=
High
Efficiency
Neutron
Counter;
HGPe
=
High
Purity
Germanium;
INEEL
=
Idaho
National
Engineering
and
Environmental
Laboratory;
IPAN
=
Imaging
Passive
Active
Counter
;
LANL
=
Los
Alamos
National
Laboratories;
LLNL
=
Lawrence
Livermore
National
Laboratory;
NDA
=
Nondestructive
Assay;
NMC
=
Neutron
Multiplicity
Counter;
NTS
=
Nevada
Test
Site;
PADC
=
Passive
Active
Drum
Counter;
RFETS
=
Rocky
Flats
Environmental
Technology
Site;
RTR
=
Real
Time
Radiography;
SGS
=
Segmented
Gamma
Scanner;
SGSAS
=Segmented
Gamma
Scan
Assay
System
;
SRS
=
Savannah
River
Site;
SWEPP
SGRS
=
Stored
Waste
Examination
Pilot
Plant
Gamma
Ray
Spectrometer
;
SWEPP
PAN
=
Stored
Waste
Examination
Pilot
Plant
Passive
Active
Neutron
Counter
;
TGS
CAN
=
Tomographic
Gamma
Scanner;
TRU
=
Transuranic;
VE
=
Visual
Examination;
WAGS
=
Waste
Assay
Gamma
Spectrometer;
WIPP
=
Waste
Isolation
Pilot
Plan;
WWIS
=
WIPP
Waste
Information
System
49
III.
B
Lessons
Learned
As
a
result
of
our
site
inspection
experience
we
have
identified
a
number
of
general
observations,
or
"lessons
learned,"
related
to
waste
characterization
activities.
°
Implementation
of
waste
characterization
is
not
consistent
across
sites.
Because
one
generator
site
is
capable
of
implementing
an
adequate
program
does
not
mean
that
other
sites
that
use
the
same
equipment
are
also
implementing
an
adequate
program.
For
example,
while
EPA
has
approved
the
use
of
Mobile
Characterization
System
(MCS)
NDA
at
RFETS
(Inspection
EPA
RFETS
6.98
8;
Air
Docket
A
98
49,
Item
II
A4
4),
EPA
has
not
allowed
the
use
of
the
same
equipment
at
Nevada
Test
Site
due
to
concerns
regarding
quality
control,
measurement
performance,
and
documentation
(Inspection
EPA
6.99
8;
Air
Docket
A
98
49,
Item
II
A4
9).
°
Sites
have
not
been
able
to
characterize
all
of
their
wastes
at
the
time
of
inspection,
and
approvals
have
been
sought
and
given
based
on
sites'
own
limitations.
For
example,
Savannah
River
Site
originally
sought
and
was
granted
EPA
approval
for
characterization
of
a
single
waste
stream,
and
wrote
procedures
specific
to
that
waste
stream
(Inspection
EPA
SRS
11.00
8;
Air
Docket
A
98
49,
Item
II
A4
16).
EPA
may
extend
approvals
for
all
waste
types
in
some
areas,
but
in
other
instances
the
limitation
is
warranted.
For
example,
use
of
the
WWIS
for
data
transmittal
is
not
conditioned
on
waste
type,
but
the
method
of
nondestructive
analysis
may
be.
INEEL
initially
developed
procedures
and
characterization
activities
focusing
only
on
inorganic
solids
and
graphite
debris
waste
(Inspection
EPA
INEEL
7.98
8,
Air
Docket
A
98
49,
Item
II
A4
2).
Consequently,
a
single,
one
size
fits
all
approval
typically
is
not
possible
for
all
waste
types
and
processes
at
a
site.
°
AK
and
NDA
personnel
sometimes
do
not
communicate
adequately,
resulting
in
the
use
of
AK
data
by
NDA
personnel
that
the
AK
personnel
did
not
know
existed.
For
example,
Hanford
Site
NDA
personnel
used
AK
radioassay
information
to
help
determine
isotopic
distribution,
but
this
information
was
not
provided
to
the
AK
personnel,
included
in
the
AK
record,
or
integrated
into
AK
Summary
documentation.
The
AK
NDA
linkage
is
crucial
when
AK
is
used
directly
by
NDA
personnel,
and
EPA
inspectors
examine
AK
NDA
interface
issues
as
part
of
the
evaluation
of
the
overall
characterization
program.
Problems
with
the
interface
reflect
a
loss
of
control
over
use
of
important
data
by
a
site.
°
EPA
has
performed
some
inspections
for
which
only
limited
examples
of
procedural
implementation
were
provided
by
the
site.
Only
a
few
waste
containers
were
fully
characterized,
and
it
was
difficult
to
determine
how
the
system
would
function
once
the
process
was
fully
operational.
For
example,
initial
approval
of
the
INEEL
waste
characterization
system
for
solids/
solidified
waste
was
sought
based
on
full
characterization
of
only
a
single
drum
of
waste
(Inspection
EPA
INEEL
12.00
8;
Air
Docket
A
98
49,
Item
II
A4
15).
In
such
instances,
it
is
essential
that
rigorous
application
50
of
controls
be
maintained
after
approval
is
given
and
production
level
characterization
begins.
In
the
case
of
INEEL,
EPA
found
that
this
site
inadvertently
shipped
waste
characterized
using
an
NDA
system
that
was
not
yet
approved
by
EPA,
necessitating
more
inspections
by
EPA.
(Inspection
EPA
INEEL
7.01
8;
Air
Docket
A
98
49,
Item
II
A4
17).
Once
EPA
has
given
the
initial
approval
to
a
site's
overall
program,
it
is
useful
to
perform
"system
check"
inspections
on
a
regular
basis.
The
frequency
of
inspections
may
lessen
as
the
site
demonstrates
institutional
control
over
the
characterization
process.
EPA
should
have
flexibility
in
scheduling
inspections,
and
this
flexibility
should
be
independent
of
DOE's
own
inspection
process.
°
Often
EPA
inspectors
arrive
at
a
site
to
find
that
the
lower
tier
procedures
that
they
reviewed
in
advance
have
been
revised
by
the
site,
in
response
to
earlier
CBFO
inspections
and
surveillances
or
for
other
reasons.
EPA
has
experienced
this
problem
at
every
site.
This
situation
interferes
with
the
smooth
progress
of
the
inspection
plan,
because
inspectors
must
take
the
time
to
compare
the
procedures
and
understand
the
changes
before
proceeding
with
the
substance
of
the
inspection.
°
Consistent
with
40
CFR
194.8(
b),
EPA's
approach
to
site
approvals
has
been
to
authorize
characterization
only
for
certain
waste
streams
or
groupings
of
waste
streams
(i.
e.,
Summary
Waste
Category
Groups).
Consistent
with
its
QA
procedures,
DOE's
approach
has
been
to
certify
sites'
characterization
programs
overall
and
then
authorize
shipment
only
of
waste
streams
presented
by
the
site.
This
difference
in
approach
to
site
approvals/
certification
has
been
confusing
for
DOE
sites,
particularly
during
EPA's
early
inspections
in
1998
and
1999.
51
IV.
SUMMARY
OF
PUBLIC
COMMENTS
ON
EPA
INSPECTIONS
This
section
presents
several
examples
of
the
public
comments
that
EPA
has
received
on
their
inspection
results.
As
of
January
2002,
we
have
published
a
total
of
twenty
one
Federal
Register
notices
related
to
those
inspections.
In
response
to
the
twenty
one
notices,
we
have
received
nine
sets
of
comments.
Of
the
comments
received,
four
were
from
the
Environmental
Evaluation
Group
(or
EEG,
New
Mexico's
independent
scientific
oversight
organization
for
the
WIPP)
and
focused
specifically
on
documents
in
the
docket
[see
Docket
A
98
49,
Category
II
A3,
Items
11,
21,
22,
and
31].
EEG
observers
usually
attend
EPA
inspections,
and
so
have
the
opportunity
to
discuss
their
comments
directly
with
DOE
personnel
during
the
inspection.
Other
than
comments
from
EEG,
we
received
five
sets
of
comments.
Four
of
these
sets
were
requests
to
extend
the
public
comment
period,
which
we
did
in
one
instance
[see
Docket
A98
49,
Category
II
A3,
Items
3,
8,
27,
and
30],
and
the
remaining
set
contained
specific
comments
on
documents
in
the
docket
[see
Docket
A
98
49,
Category
II
A3,
Item
29].
We
respond
to
comments
sent
to
the
docket
in
our
inspection
reports,
which
are
filed
in
Docket
A
98
49,
Category
II
A4.
Representative
examples
of
comments
are
presented
below.
EPA
INEEL
7.01
8
(July
25
26,
2001);
Air
Docket
A
98
49,
Item
II
A4
17
EPA
received
two
sets
of
comments
in
EPA
Air
Docket
A
98
49
in
response
to
our
Federal
Register
notice
of
July
13,
2001.
The
comments
are
filed
as
(1)
Item
II
A3
27
and
(2)
IIA3
29.
Examples
of
significant
comments
follows.
Issue
A:
Information
provided
in
Docket
A
98
49
was
not
sufficient
to
enable
the
public
or
EPA
to
reach
conclusions
about
the
compliance
of
the
WAGS
system.
Therefore,
EPA
should
extend
the
public
comment
period.
1.
Based
on
the
documents
in
the
docket,
it
is
impossible
for
EPA
or
the
public
to
know
how
many
drums
were
certified
using
the
WAGS
system
because
none
of
the
documents
in
the
docket
describe
what
characterization
and
quality
assurance
(QA)
procedures
were
used
on
the
1,917
drums
with
waste
in
the
69
shipments
that
INEEL
made
to
WIPP
between
December
7,
2000
and
June
27,
2001
(INEEL
shipments
KN001201
and
1202,
IN010031
to
010097
WIPP
Waste
Information
System
data).
[1]
2.
The
docket
provides
no
basis
for
EPA,
or
the
public,
to
conclude
that
the
WAGS
System
actually
operated
in
a
manner
equivalent
to
the
SGRS
system
for
any
or
all
of
the
period
that
it
was
being
used
as
part
of
the
waste
characterization
process.
[1]
3.
Neither
EPA,
nor
the
public,
can
conclude
that
the
drums
shipped
to
WIPP
were
adequately
characterized,
so
the
question
of
what
should
now
be
done
with
those
drums
at
WIPP
cannot
be
answered
based
on
documents
currently
available
to
the
public.
We
believe
that
52
EPA
cannot
make
any
decision
about
the
status
of
those
drums
without
adequate
documentation
being
made
available
to
the
public.
[1]
4.
Based
on
the
documents
in
the
docket,
we
cannot
conclude
that
the
WAGS
system
meets
the
quality
assurance
requirements
of
40
CFR
194.8(
a).
[1]
5.
Based
on
the
documents
in
the
docket,
we
also
cannot
conclude
that
the
WAGS
system
meets
the
waste
characterization
requirements
of
40
CFR
194.8(
b).
[1]
6.
The
docket
provides
no
documentation
regarding
how
INEEL
or
EPA
determined
which
drums
were
characterized
using
the
WAGS
system,
how
the
WAGS
system
was
used
and
how
its
use
changed
during
the
time
period
in
question,
as
to
the
nature
of
the
process
knowledge
documentation
for
those
drums,
or
other
relevant
information.
Thus,
based
on
what
is
available
in
the
docket,
the
public
cannot
adequately
comment
on
the
status
of
those
drums,
nor
does
EPA
have
adequate
information
to
make
its
determinations.
[1]
7.
As
specified
in
its
Federal
Register
notice
of
July
13,
2001
(66
Fed.
Reg.
36723),
EPA
is
providing
its
normal
30
day
public
comment
period
on
"waste
characterization
program
documents."
However,
the
current
situation
is
not
normal,
it
is
the
most
complex
yet
faced
by
EPA
involving
a
site's
waste
characterization
program.
In
such
an
abnormal
situation,
a
longer
public
comment
period
is
necessary,
and
it
is
clearly
allowed
by
40
CFR
194.8.
In
addition,
the
fact
that
important
documents
are
not
yet
available
necessitates
an
extension
of
the
public
comment
period
to
allow
public
comment
on
the
appropriate
documentation.
[1]
Response
to
Issue
A:
We
decided
not
to
extend
the
comment
period.
We
believe
that
30
days
was
sufficient
time
to
allow
the
public
to
raise
questions
or
concerns
about
the
WAGS
system,
and
that
the
information
that
we
docketed
was
appropriate,
for
the
reasons
explained
below.
When
we
open
a
comment
period
under
40
CFR
194.8,
the
primary
purpose
of
the
public
comment
period
is
to
allow
the
public
to
provide
potentially
relevant
information
to
EPA
or
to
raise
compliance
concerns
or
questions,
so
that
EPA
is
aware
of
those
concerns
and
questions
and
can
seek
resolution
to
them
prior
to
making
a
final
compliance
decision.
Any
specific
processes
or
waste
streams
about
which
we
are
seeking
public
input
are
defined
in
the
inspection
notice
that
we
provide
in
the
Federal
Register.
As
we
explained
in
our
May
1998
Certification
Decision
(see,
for
example,
EPA
Air
Docket
A
93
02,
Item
V
C
1,
pp.
2
8
to
2
11
and
6
26),
EPA's
compliance
decision
under
194.8
must
be
based
on
our
independent
inspections
of
waste
characterization
processes.
Inspections
involve
review
of
many
different
documents,
interviews
with
staff,
and
on
site
demonstrations,
which
are
then
summarized
and
made
public
in
our
inspection
reports.
It
is
neither
possible
nor
appropriate
to
attempt
to
place
all
information
that
may
be
relevant
to
the
scope
of
our
inspection
in
our
docket
before
we
conduct
an
inspection.
53
We
docketed
key
documents
that
we
determined
were
pertinent
to
the
proposed
WAGS
system.
In
light
of
the
WAGS
related
nonconformance
that
we
identified
in
June
2001
(see
Issue
B
below),
and
in
anticipation
of
public
concern,
we
included
additional
DOE
documents
that
directly
pertained
to
the
nonconformance.
It
was
not
our
expectation
that
the
public
would
be
able
to
reach
conclusions
about
either
the
WAGS
system's
technical
adequacy
or
the
WAGS
related
nonconformance
based
solely
on
the
docketed
materials.
EPA
makes
the
determination
of
compliance
following
a
site
inspection.
With
regard
to
comment
A.
1,
we
obtained
objective
evidence
during
our
July
2
3
inspection
at
INEEL
that
established
the
status
of
all
drums
characterized
by
the
WAGS
system
and
shipped
to
the
WIPP
site.
This
information
is
contained
in
our
report
for
inspection
no.
EPAINEEL
7.01
24
(Docket
A
98
49,
Item
II
A1
28).
EPA
RFETS
4.99
8
(April
27
28,
1999);
Air
Docket
A
98
49,
Item
II
A4
6
EPA
received
one
set
of
comments
from
the
EEG
in
response
to
the
items
announced
in
the
Federal
Register
on
March
25,
1999
(64
FR
14418).
The
letter
from
EEG,
dated
April
23,
1999,
may
be
found
in
EPA
Air
Docket
A
98
49,
Item
II
A3
11.
Below
are
some
examples
of
significant
issues
raised
in
EEG's
letter
and
EPA's
response
to
those
issues.
EPA
inspectors
discussed
some
of
the
issues
with
DOE
Carlsbad
Field
Office
(CAO)
personnel
(Sam
Vega,
Van
Bynum,
and
Mark
Doherty)
and
RFETS
personnel
(Gerald
O'Leary
and
Mark
Castagneri)
during
the
inspection,
in
the
presence
of
Ben
Walker
of
EEG.
EEG
Issue
D:
Sites
such
as
RFETS
must
meet
requirements
for
certain
waste
material
parameters
that
have
not
been
shown
to
affect
the
WIPP's
performance.
RFETS
should
consider
the
relative
importance
of
waste
material
parameters.
1.
The
RFETS
QAPjP
follows
the
CAO's
Transuranic
Waste
Characterization
Quality
Assurance
Program
Plan
(TRU
Waste
QAPP,
CAO
94
1010,
Revision
0)
in
continuing
to
consider
all
of
the
TWBIR
waste
material
parameters
equally.
.
.
[The
RFETS
QAPjP],
and
the
overall
RFETS
TRU
waste
program,
should
develop
training
and
awareness
of
the
relative
importance
of
obtaining
defensible
measurements
for
the
two
types
of
waste
material
parameters
[i.
e.,
cellulosics/
plastics/
rubbers
and
ferrous
metals]
that
have
been
shown
to
be
important
to
containment
of
waste
in
the
repository.
EPA's
Response
to
Issue
D:
This
comment
suggests
that,
by
treating
"all
of
the
TWBIR
waste
material
parameters
equally,"
RFETS
(and
DOE
generally)
may
be
compromising
in
some
fashion
the
analysis
of
waste
parameters
that
are
central
to
compliance
with
EPA's
disposal
regulations.
EPA
did
not
find
evidence
during
the
inspection
to
support
the
claim
that
RFETS
is
not
properly
accounting
for
the
important
waste
parameters.
As
for
other
parameters,
EPA
does
not
have
a
basis
to
require
54
programmatic
changes
in
the
WIPP
project
unless
they
are
shown
to
be
necessary
for
compliance
with
our
regulations.
EEG
Issue
N:
The
docketed
items
were
well
done
but
may
be
insufficient
for
assessing
RFETS
compliance.
1.
[EEG's]
comments.
.
.
should
be
considered
as
describing
deviations
in
what,
for
the
most
part,
appears
to
be
a
very
well
planned
program
adequate
to
meet
the
EPA's
waste
characterization
planning
requirements
specified
in
40
CFR
194.8.
.
.
The
EEG
does,
however,
point
out
that
documentation
the
EPA
may
need
for
thorough
analysis
of
RFETS
compliance
with
40
CFR
194
may
not
be
covered
by
the
documents
provided
to
the
WIPP
docket
for
public
review.
EPA's
Response
to
Issue
N:
EPA
agrees
that
the
RFETS
TRU
Waste
Management
Manual
and
Quality
Assurance
Project
Plan
are
well
prepared
documents.
EPA
cannot
rely
solely
on
such
documents,
however,
to
evaluate
transuranic
waste
sites'
quality
assurance
and
waste
characterization
programs.
As
we
have
noted
elsewhere,
inspections
and
inspections
are
appropriate
mechanisms
for
verifying
compliance
with
Conditions
2
and
3
of
our
certification
of
the
WIPP
(see,
for
example,
63
FR
27359).
Prior
to,
during,
and
after
inspections
EPA
may
review
a
wide
variety
of
procedures,
records,
and
data
in
order
to
reach
a
determination
that
the
programs
under
review
are
adequately
established
and
executed.
EPA
requires
DOE
to
submit
a
site's
top
governing
documents
prior
to
an
inspection
to
afford
the
public
an
opportunity
to
comment
on
the
site's
programs
and
to
raise
issues
that
the
Agency
should
consider
in
deciding
whether
or
not
to
approve
those
programs.
55
V.
CONCLUSIONS
EPA's
inspection
process
examines
the
technical
elements
important
to
demonstrating
compliance
with
40
CFR
194.24
waste
characterization
systems
of
control.
EPA
inspectors
examine
Acceptable
Knowledge
(i.
e.,
the
historical
documentation
that
provides
radionuclide,
waste
material
parameter,
and
other
information),
Nondestructive
Assay
(for
radionuclide
quantifications),
Visual
Examination/
Radiography
(to
assess
physical
waste
contents),
and
data
transfer
and
data
validation.
Evaluation
of
these
technical
elements
is
sufficiently
comprehensive
to
assess
the
technical
adequacy
of
the
system
of
controls
for
waste
characterization.
Inspections
conducted
to
date
have
demonstrated
that
the
application
of
technical
elements
listed
above
varies
considerably
from
site
to
site.
The
regulatory
language
governing
site
inspections
has
led
EPA
to
respond
to
issues
involving
one
or
more
technical
elements
by
restricting
the
scope
of
site
approval.
As
a
result,
EPA
inspectors
must
return
to
an
approved
site
if
the
site
seeks
to
ship
additional
waste
streams,
use
equipment
not
previously
inspected,
or
make
significant
changes
to
procedures
or
methods
for
waste
characterization.
56
REFERENCES
EPA
1994.
U.
S.
Environmental
Protection
Agency.
Waste
Analysis
at
Facilities
that
Generate,
Treat,
Store,
and
Dispose
of
Hazardous
Waste.
EPA
Office
of
Solid
Waste.
Directive
Number
9938.4
03.
April
26,
1994.
EPA/
NRC
1997.
U.
S.
Environmental
Protection
Agecy
&
U.
S.
Nuclear
Regulatory
Commission.
Joint
NRC/
EPA
Guidance
on
Testing
Requirements
for
Mixed
Radioactive
and
Hazardous
Waste.
62
FR
62079
62094.
November
20,
1997.
| epa | 2024-06-07T20:31:39.760384 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0005-0001/content.txt"
} |
EPA-HQ-OAR-2002-0005-0003 | Proposed Rule | "2002-08-09T04:00:00" | Criteria for the Certification and Recertification of the Waste Isolation
Pilot Plant’s Compliance with the Disposal Regulations; Alternative Provisions [A-98-49-VI-A-1] | Friday,
August
9,
2002
Part
II
Environmental
Protection
Agency
40
CFR
Part
194
Criteria
for
the
Certification
and
Recertification
of
the
Waster
Isolation
Pilot
Plant's
Compliance
With
the
Disposal
Regulations;
Alternative
Provisions;
Proposed
Rule
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Federal
Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
194
[FRL–
7255–
4]
RIN
2060–
AJ07
Criteria
for
the
Certification
and
Recertification
of
the
Waste
Isolation
Pilot
Plant's
Compliance
with
the
Disposal
Regulations;
Alternative
Provisions
AGENCY:
Environmental
Protection
Agency
(EPA).
ACTION:
Proposed
rule.
SUMMARY:
The
Environmental
Protection
Agency
(``
EPA,
''
or
``
the
Agency''
or
``
we'')
is
proposing
to
revise
the
``
Criteria
for
the
Certification
and
Recertification
of
the
Waste
Isolation
Pilot
Plant's
Compliance
with
the
Disposal
Regulations,
''
which
are
used
to
determine
whether
the
Department
of
Energy's
Waste
Isolation
Pilot
Plant
(``
WIPP'')
will
comply
with
EPA's
``
Environmental
Radiation
Protection
Standards
for
Management
and
Disposal
of
Spent
Nuclear
Fuel,
High
Level
and
Transuranic
Radioactive
Wastes.
''
The
following
proposed
revisions
are
included
in
today's
action:
addition
of
a
mechanism
to
address
minor
changes
to
the
provisions
of
the
Compliance
Criteria;
changes
to
the
approval
process
for
waste
characterization
programs
at
Department
of
Energy
transuranic
sites;
changes
to
allow
for
the
submission
of
copies
of
compliance
applications
and
reference
materials
in
alternative
format;
and
replacement
of
the
term
``
process
knowledge''
with
``
acceptable
knowledge.
''
The
proposed
changes
do
not
lessen
the
requirements
for
complying
with
the
Compliance
Criteria.
Moreover,
these
changes
will
have
no
effect
on
the
technical
approach
that
EPA
employs
when
conducting
independent
inspections
of
the
waste
characterization
capabilities
at
DOE
waste
generator
sites.
EPA
is
conducting
this
proposed
action
in
accordance
with
the
procedures
for
substituting
alternative
provisions
of
the
Compliance
Criteria.
Today's
notice
marks
the
beginning
of
a
120
day
public
comment
period
on
this
proposed
action.
DATES:
EPA
requests
comments
on
all
aspects
of
these
proposed
revisions.
If
you
wish
to
submit
comments
on
this
proposal,
you
must
do
so
by
December
9,
2002.
ADDRESSES:
Send
your
comments
to:
Air
Docket,
Room
M–
1500,
U.
S.
Environmental
Protection
Agency,
401
M
Street,
SW.,
Mail
Code
6102,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR–
2002–
0005.
Comments
may
be
submitted
electronically,
by
mail,
by
facsimile,
or
through
hand
delivery/
courier.
Follow
the
detailed
instructions
as
provided
in
Section
B
of
the
SUPPLEMENTARY
INFORMATION
section.
FOR
FURTHER
INFORMATION
CONTACT:
Agnes
Ortiz;
telephone
number:
(202)
564–
9310;
postal
address:
Radiation
Protection
Division,
Mail
Code
6608J,
U.
S.
Environmental
Protection
Agency,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC,
20460.
SUPPLEMENTARY
INFORMATION:
General
Information
A.
How
Can
I
Get
Copies
of
This
Document
and
Other
Related
Information?
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
OAR–
2002–
0005.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
received,
and
other
information
related
to
this
action.
Although
a
part
of
the
official
docket,
the
public
docket
does
not
include
Confidential
Business
Information
(CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at:
Air
Docket,
Room
M–
1500,
U.
S.
Environmental
Protection
Agency,
401
M
Street,
SW.,
Mail
Code
6102,
Washington,
DC
20460.
This
Docket
Facility
is
open
from
8:
30am–
5
pm,
Monday
through
Friday,
excluding
legal
holidays.
The
Air
Docket
telephone
number
is
202–
260–
7548.
You
may
access
this
Federal
Register
document
electronically
through
the
EPA
Internet
under
the
``
Federal
Register''
listings
at
http://
www.
epa.
gov/
fedrgstr/.
An
electronic
version
of
the
public
docket
is
available
through
EPA's
electronic
public
docket
and
comment
system,
EPA
Dockets.
You
may
use
EPA
Dockets
at
http://
www.
epa.
gov/
edocket/
to
submit
or
view
public
comments,
access
the
index
listing
of
the
contents
of
the
official
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,
''
then
key
in
the
appropriate
docket
identification
number.
Certain
types
of
information
will
not
be
placed
in
the
EPA
Dockets.
Information
claimed
as
CBI
and
other
information
whose
disclosure
is
restricted
by
statute,
which
is
not
included
in
the
official
public
docket,
will
not
be
available
for
public
viewing
in
EPA's
electronic
public
docket.
EPA's
policy
is
that
copyrighted
material
will
not
be
placed
in
EPA's
electronic
public
docket
but
will
be
available
only
in
printed,
paper
form
in
the
official
public
docket.
To
the
extent
feasible,
publicly
available
docket
materials
will
be
made
available
in
EPA's
electronic
public
docket.
When
a
document
is
selected
from
the
index
list
in
EPA
Dockets,
the
system
will
identify
whether
the
document
is
available
for
viewing
in
EPA's
electronic
public
docket.
Although
not
all
docket
materials
may
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
identified
in
Section
B
under
General
Information.
EPA
intends
to
work
towards
providing
electronic
access
to
all
of
the
publicly
available
docket
materials
through
EPA's
electronic
public
docket.
For
public
commenters,
it
is
important
to
note
that
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
in
paper,
will
be
made
available
for
public
viewing
in
EPA's
electronic
public
docket
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
EPA's
electronic
public
docket.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Public
comments
submitted
on
computer
disks
that
are
mailed
or
delivered
to
the
docket
will
be
transferred
to
EPA's
electronic
public
docket.
Public
comments
that
are
mailed
or
delivered
to
the
Docket
will
be
scanned
and
placed
in
EPA's
electronic
public
docket.
Where
practical,
physical
objects
will
be
photographed,
and
the
photograph
will
be
placed
in
EPA's
electronic
public
docket
along
with
a
brief
description
written
by
the
docket
staff.
For
additional
information
about
EPA's
electronic
public
docket
visit
EPA
Dockets
online
or
see
67
FR
38102,
May
31,
2002.
B.
How
and
To
Whom
Do
I
Submit
Comments?
You
may
submit
comments
electronically,
by
mail,
by
facsimile,
or
through
hand
delivery/
courier.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
comment.
Please
ensure
that
your
comments
are
submitted
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Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
within
the
specified
comment
period.
Comments
received
after
the
close
of
the
comment
period
will
be
marked
``
late.
''
EPA
is
not
required
to
consider
these
late
comments.
However,
late
comments
may
be
considered
if
time
permits.
If
you
wish
to
submit
CBI
or
information
that
is
otherwise
protected
by
statute,
please
follow
the
instructions
in
Section
C
under
General
Information.
Do
not
use
EPA
Dockets
or
e
mail
to
submit
CBI
or
information
protected
by
statute.
1.
Electronically
If
you
submit
an
electronic
comment
as
prescribed
below,
EPA
recommends
that
you
include
your
name,
mailing
address,
and
an
e
mail
address
or
other
contact
information
in
the
body
of
your
comment.
Also
include
this
contact
information
on
the
outside
of
any
disk
or
CD
ROM
you
submit,
and
in
any
cover
letter
accompanying
the
disk
or
CD
ROM.
This
ensures
that
you
can
be
identified
as
the
submitter
of
the
comment
and
allows
EPA
to
contact
you
in
case
EPA
cannot
read
your
comment
due
to
technical
difficulties
or
needs
further
information
on
the
substance
of
your
comment.
EPA's
policy
is
that
EPA
will
not
edit
your
comment,
and
any
identifying
or
contact
information
provided
in
the
body
of
a
comment
will
be
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket,
and
made
available
in
EPA's
electronic
public
docket.
If
EPA
cannot
read
your
comment
due
to
technical
difficulties
and
cannot
contact
you
for
clarification,
EPA
may
not
be
able
to
consider
your
comment.
Your
use
of
EPA's
electronic
public
docket
to
submit
comments
to
EPA
electronically
is
EPA's
preferred
method
for
receiving
comments.
Go
directly
to
EPA
Dockets
at
http://
www.
epa.
gov/
edocket,
and
follow
the
online
instructions
for
submitting
comments.
To
access
EPA's
electronic
public
docket
from
the
EPA
Internet
home
page,
select
``
Information
Sources,
''
``
Dockets,
''
and
``
EPA
Dockets.
''
Once
in
the
system,
select
``
search,
''
and
then
key
in
Docket
ID
No.
OAR–
2002–
0005.
The
system
is
an
``
anonymous
access''
system,
which
means
EPA
will
not
know
your
identity,
e
mail
address,
or
other
contact
information
unless
you
provide
it
in
the
body
of
your
comment.
Comments
may
be
sent
by
electronic
mail
(e
mail)
to
a
and
r
docket@
epa.
gov
Attention
Docket
ID
No.
OAR–
2002–
0005.
In
contrast
to
EPA's
electronic
public
docket,
EPA's
e
mail
system
is
not
an
``
anonymous
access''
system.
If
you
send
an
e
mail
comment
directly
to
the
Docket
without
going
through
EPA's
electronic
public
docket,
EPA's
e
mail
system
automatically
captures
your
e
mail
address.
E
mail
addresses
that
are
automatically
captured
by
EPA's
e
mail
system
are
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket,
and
made
available
in
EPA's
electronic
public
docket.
You
may
submit
comments
on
a
disk
or
CD
ROM
that
you
mail
to
the
mailing
address
identified
in
Section
A
under
General
Information.
These
electronic
submissions
will
be
accepted
in
WordPerfect
or
ASCII
file
format.
Avoid
the
use
of
special
characters
and
any
form
of
encryption.
2.
By
Mail
Send
your
comments
to:
Air
Docket,
Room
M–
1500,
U.
S.
Environmental
Protection
Agency,
401
M
Street,
SW.,
Mail
Code
6102,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR–
2002–
0005.
3.
By
Hand
Delivery
or
Courier
Deliver
your
comments
to:
Air
Docket,
Room
M–
1500,
U.
S.
Environmental
Protection
Agency,
401
M
Street,
SW.,
Mail
Code
6102,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR–
2002–
0005.
Such
deliveries
are
only
accepted
during
the
Docket's
normal
hours
of
operation
as
identified
in
Section
A
under
General
Information.
4.
By
Facsimile
Fax
your
comments
to:
(202)
260–
4400,
Attention
Docket
ID.
No.
OAR–
2002–
0005.
C.
How
Should
I
Submit
CBI
to
the
Agency?
Do
not
submit
information
that
you
consider
to
be
CBI
electronically
through
EPA's
electronic
public
docket
or
by
e
mail.
You
may
claim
information
that
you
submit
to
EPA
as
CBI
by
marking
any
part
or
all
of
that
information
as
CBI
(if
you
submit
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
as
CBI
and
then
identify
electronically
within
the
disk
or
CD
ROM
the
specific
information
that
is
CBI).
Information
so
marked
will
not
be
disclosed
except
in
accordance
with
procedures
set
forth
in
40
CFR
part
2.
In
addition
to
one
complete
version
of
the
comment
that
includes
any
information
claimed
as
CBI,
a
copy
of
the
comment
that
does
not
contain
the
information
claimed
as
CBI
must
be
submitted
for
inclusion
in
the
public
docket
and
EPA's
electronic
public
docket.
If
you
submit
the
copy
that
does
not
contain
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
clearly
that
it
does
not
contain
CBI.
Information
not
marked
as
CBI
will
be
included
in
the
public
docket
and
EPA's
electronic
public
docket
without
prior
notice.
If
you
have
any
questions
about
CBI
or
the
procedures
for
claiming
CBI,
please
consult
the
person
identified
in
the
FOR
FURTHER
INFORMATION
CONTACT
section.
D.
What
Should
I
Consider
as
I
Prepare
My
Comments
for
EPA?
You
may
find
the
following
suggestions
helpful
for
preparing
your
comments:
1.
Explain
your
views
as
clearly
as
possible.
2.
Describe
any
assumptions
that
you
used.
3.
Provide
any
technical
information
and/
or
data
you
used
that
support
your
views.
4.
If
you
estimate
potential
burden
or
costs,
explain
how
you
arrived
at
your
estimate.
5.
Provide
specific
examples
to
illustrate
your
concerns.
6.
Offer
alternatives.
7.
Make
sure
to
submit
your
comments
by
the
comment
period
deadline
identified.
8.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
response.
It
would
also
be
helpful
if
you
provided
the
name,
date,
and
Federal
Register
citation
related
to
your
comments.
Abbreviations
Used
in
This
Document
AK—
Acceptable
knowledge
Am—
Americium
APA—
Administrative
Procedure
Act
ASME—
American
Society
of
Mechanical
Engineers
BID—
Background
information
document
CAR—
Corrective
Action
Required
CARD—
Compliance
Application
Review
Document
CBFO—
Carlsbad
Field
Office
CCA—
Compliance
Certification
Application
CFR—
Code
of
Federal
Regulations
CH—
Contact
handled
Cs—
Cesium
DOE—
Department
of
Energy
EEG—
Environmental
Evaluation
Group
EPA—
Environmental
Protection
Agency
INEEL—
Idaho
National
Energy
and
Engineering
Laboratory
LANL—
Los
Alamos
National
Laboratory
NDA—
Nondestructive
Assay
NPRM—
Notice
of
Proposed
Rulemaking
NTS—
Nevada
Test
Site
NQA—
Nuclear
Quality
Assurance
ORNL—
Oak
Ridge
National
Laboratory
PK—
Process
knowledge
Pu—
Plutonium
QA—
Quality
assurance
QAPP—
Quality
Assurance
Project
Plan
QAPjP—
Quality
Assurance
Project
Plan
RC—
Radiochemistry
RCRA—
Resource
Conservation
Recovery
Act
RFETS—
Rocky
Flats
Environmental
Technology
Site
RTR—
Real
time
radiography
SRS—
Savannah
River
Site
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Vol.
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/
Friday,
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9,
2002
/
Proposed
Rules
Sr—
Strontium
TRU—
Transuranic
U—
Uranium
VE—
Visual
inspection
WAC—
Waste
Acceptance
Criteria
WAP—
Waste
Acceptance
plan
WC—
Waste
characterization
WIPP—
Waste
Isolation
Pilot
Plant
WIPP
LWA—
WIPP
Land
Withdrawal
Act
WWIS—
WIPP
Waste
Information
System
Table
of
Contents
I.
What
Is
WIPP?
II.
What
Is
the
Purpose
of
Today's
Proposed
Action?
III.
How
Is
EPA
Revising
the
Process
for
Establishing
Alternative
Provisions
in
§
194.6?
A.
What
Are
the
Current
Requirements
in
§
194.6?
B.
What
Changes
Are
Proposed
for
§
194.6?
C.
How
Has
EPA
Addressed
the
Alternative
Provision
Analysis
Required
by
§
194.6?
IV.
How
Is
EPA
Revising
the
Approval
Process
for
Waste
Shipment
from
Waste
Generator
Sites
for
Disposal
at
WIPP
in
§
194.8(
b)?
A.
What
Are
the
Current
Requirements
in
§
194.8(
b)?
B.
What
Are
the
Proposed
Changes
to
§
194.8(
b)?
C.
How
Has
EPA
Addressed
the
Alternative
Provision
Analysis
Required
by
§
194.6?
V.
How
Is
EPA
Revising
the
Submission
of
Compliance
Applications
and
Reference
Materials
Requirements
in
§§
194.12
and
194.13?
A.
What
Are
the
Current
Requirements
in
§§
194.12
and
194.13?
B.
What
Are
the
Proposed
Changes
to
§§
194.12
and
194.13?
C.
How
Has
EPA
Addressed
the
Alternative
Provision
Analysis
Required
by
§
194.6?
VI.
How
Is
EPA
Revising
the
Waste
Characterization
Requirements
in
§
194.24(
c)(
3)?
A.
What
Are
the
Current
Waste
Characterization
Requirements
in
§
194.24(
c)(
3)?
B.
What
Are
the
Proposed
Changes
to
§
194.24(
c)(
3)?
C.
How
Has
EPA
Addressed
the
Alternative
Provision
Analysis
Required
by
§
194.6?
VII.
Administrative
Reuquirments
A.
Executive
Order
12866
B.
Regulatory
Flexibility
Act
C.
Paperwork
Reduction
Act
D.
Unfunded
Mandates
Reform
Act
E.
Executive
Order
12898
F.
National
Technology
Transfer
&
Advancement
Act
of
1995
G.
Executive
Order
13045:
Children's
Health
Protection
H.
Executive
Order
13132:
Federalism
I.
Executive
Order
13175:
Consultation
and
Coordination
With
Indian
Tribal
Governments
J.
Executive
Order
13211:
Energy
Effects
I.
What
Is
WIPP?
The
Waste
Isolation
Pilot
Plant
(``
WIPP'')
is
a
disposal
system
for
transuranic
radioactive
waste.
Developed
by
the
Department
of
Energy
(``
DOE''
or
``
the
Department''),
the
WIPP
is
located
near
Carlsbad
in
southeastern
New
Mexico.
Transuranic
(TRU)
radioactive
wastes
are
emplaced
2,150
feet
underground
in
an
ancient
layer
of
salt
that
will
eventually
``
creep''
and
encapsulate
the
waste
containers.
The
WIPP
has
a
total
capacity
of
6.2
million
cubic
feet
of
TRU
waste.
Development
and
construction
of
the
WIPP
was
authorized
under
Section
213
of
the
Department
of
Energy
National
Security
and
Military
Applications
of
Nuclear
Energy
Authorization
Act
of
1980
(Public
Law
No.
96–
164,
93
U.
S.
Stat.
1259,
1265).
WIPP
was
authorized
as
a
defense
activity
of
the
Department
of
Energy
to
demonstrate
the
safe
disposal
of
radioactive
wastes
resulting
from
the
defense
activities
and
programs
of
the
United
States.
Pursuant
to
Section
7
of
the
WIPP
Land
Withdrawal
Act
(Public
Law
No.
102–
579,
as
amended
by
Public
Law
No.
104–
201)
(WIPP
LWA),
disposal
operations
at
WIPP
are
limited
to
a
total
volume
of
6.2
million
cubic
feet
of
transuranic
radioactive
waste.
Section
2(
18)
of
the
WIPP
LWA
defines
TRU
waste
as
waste
containing
more
than
100
nanocuries
of
alphaemitting
transuranic
isotopes
per
gram
of
waste,
with
half
lives
greater
than
20
years.
This
definition
excludes
highlevel
radioactive
waste,
waste
determined
by
DOE
with
the
concurrence
of
EPA
to
not
need
such
isolation,
or
waste
that
the
Nuclear
Regulatory
Commission
has
approved
for
disposal
on
a
case
by
case
basis,
consistent
with
NRC
regulations.
Most
TRU
waste
proposed
for
disposal
at
WIPP
consists
of
items
that
have
become
contaminated
as
a
result
of
activities
associated
with
the
production
of
nuclear
weapons
(or
with
the
cleanup
of
nuclear
weapons
production
facilities),
such
as,
rags,
equipment,
tools,
protective
gear,
and
sludges.
Some
TRU
waste
is
contaminated
with
hazardous
wastes
regulated
under
the
Resource
Conservation
and
Recovery
Act
(42
U.
S.
C.
6901–
6992k)(
RCRA).
The
waste
proposed
for
disposal
at
WIPP
is
currently
stored
at
Federal
facilities
across
the
United
States,
including
locations
in
Colorado,
Idaho,
New
Mexico,
Nevada,
Ohio,
South
Carolina,
Tennessee,
and
Washington.
Section
8(
c)
of
the
WIPP
LWA
required
EPA
to
promulgate
criteria,
pursuant
to
Section
4
of
the
Administrative
Procedure
Act
(APA),
for
EPA's
certification
of
the
WIPP's
compliance
with
the
radioactive
waste
disposal
regulations
at
40
CFR
Part
191.
On
February
9,
1996,
EPA
published
the
final
``
Criteria
for
the
Certification
and
Re
Certification
of
the
Waste
Isolation
Pilot
Plant's
Compliance
With
the
40
CFR
Part
191
Disposal
Regulations'
(61
FR
5224)
(Compliance
Criteria).
Section
8(
d)
of
the
WIPP
LWA
set
forth
specific
procedures
governing
the
certification
of
the
WIPP.
Section
8(
d)(
1)
required
DOE
to
submit
a
complete
compliance
application
by
October
31,
1996.
Section
8(
d)(
1)
also
provided
that
EPA
had
the
authority
to
request
any
additional
information
necessary
for
the
Agency's
determination
of
compliance.
Section
8(
d)(
2)
required
that
EPA
complete
its
certification
decision
within
one
year
of
receipt
of
the
DOE's
application.
(EPA
clarified
at
§
194.11
of
the
Compliance
Criteria
that,
consistent
with
legislative
intent,
EPA's
certification
decision
would
be
due
within
one
year
of
receipt
of
a
complete
compliance
application.)
EPA
determined
DOE's
compliance
application
to
be
complete
on
May
22,
1997
(62
FR
27996).
EPA
determined
on
May
18,
1998,
that
DOE
had
demonstrated
that
the
WIPP
will
comply
with
EPA's
radioactive
waste
disposal
regulations
at
Subparts
B
and
C
of
40
CFR
part
191.
EPA's
certification
determination
permitted
the
WIPP
to
begin
accepting
transuranic
waste
for
disposal,
provided
that
other
applicable
environmental
regulations
were
met
and
once
a
30
day
statutory
waiting
period
had
elapsed.
EPA
based
its
decision
on
a
thorough
review
of
all
the
information
submitted
by
DOE,
independent
technical
analyses,
and
all
significant
public
comments
submitted
during
a
nominal
120
day
comment
period.
EPA's
certification,
however,
was
subject
to
four
specific
conditions.
Thus,
EPA
amended
the
WIPP
compliance
criteria
at
40
CFR
part
194
to
include
an
appendix
setting
forth
the
four
conditions
on
the
certification
of
compliance.
These
conditions
related
to
(1)
design
of
the
panel
closure
system
(which
is
intended
over
the
long
term
to
block
brine
flow
between
waste
panels
in
the
WIPP);
(2)
and
(3)
activities
conducted
at
waste
generator
sites
that
produce
the
transuranic
waste
proposed
for
disposal
in
the
WIPP
(specifically
with
respect
to
quality
assurance
and
waste
characterization);
and
(4)
passive
institutional
controls.
Subsequent
to
the
initial
certification,
EPA
continues
to
have
an
oversight
role
at
the
WIPP.
First,
Section
9
of
the
WIPP
LWA
requires
that
DOE
submit
biennial
documentation
of
continued
compliance
with
specified
laws,
regulations,
and
permit
requirements.
Second,
§
194.4
of
the
Compliance
Criteria
requires
that
DOE
submit
periodic
reports
on
any
activities
or
conditions
at
the
WIPP
that
differ
significantly
from
the
information
contained
in
the
most
recent
compliance
application.
EPA
may
also,
at
any
time,
request
additional
information
from
DOE
regarding
the
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Vol.
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No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
WIPP
to
determine
if
regulatory
action
is
required
concerning
the
certification.
Third,
Section
8(
f)
of
the
WIPP
LWA
requires
at
least
five
years
after
the
initial
certification
and
every
five
years
thereafter,
that
DOE
submit
to
EPA
and
the
State
of
New
Mexico
documentation
of
continued
compliance
with
the
Part
191
radioactive
waste
disposal
regulations.
In
accordance
with
§
194.64
of
the
Compliance
Criteria,
documentation
of
continued
compliance
will
be
made
available
in
EPA's
dockets,
and
the
public
will
be
provided
at
least
a
30
day
period
during
which
to
submit
comments.
EPA's
decision
on
recertification
will
be
announced
in
the
Federal
Register.
II.
What
Is
the
Purpose
of
Today's
Proposed
Action?
EPA
proposes
to
revise
certain
provisions
of
the
Compliance
Criteria
at
40
CFR
part
194.
Specifically,
EPA
is
proposing
to
(1)
revise
the
process
for
establishing
``
alternative
provisions''
in
§
194.6;
(2)
revise
the
approval
process
in
§
194.8
for
waste
characterization
processes
at
TRU
waste
generator
sites
for
disposal
at
WIPP;
(3)
revise
the
requirements
in
§§
194.12
and
194.13
for
submission
of
compliance
applications
and
reference
materials;
and
(4)
change
the
term
``
process
knowledge''
to
``
acceptable
knowledge''
in
§
194.24(
c)(
3).
The
proposed
revisions
are
intended
to
ensure
that
40
CFR
Part
194
remains
comprehensive,
appropriate,
and
based
upon
current
knowledge
and
information.
The
Agency
solicits
comments
on
this
proposal.
Section
194.6
of
the
Compliance
Criteria
imposes
specific
requirements
for
substitution
of
``
alternative
provisions''
of
the
Criteria.
Such
alternative
provisions
must
be
promulgated
pursuant
to
Section
4
of
the
APA.
Also,
in
proposing
the
alternative
provisions
EPA
must
describe
how
the
proposed
changes
comport
with
the
radioactive
waste
disposal
regulations
at
40
CFR
part
191,
the
reasons
why
the
existing
provisions
appear
inappropriate,
and
the
costs,
risks,
and
benefits
of
compliance
with
the
new
provisions.
Finally,
EPA
must
provide
for
a
public
comment
period
of
120
days
and
hearings
in
New
Mexico,
and
fully
consider
the
public
comments
that
are
received.
Today's
Notice
of
Proposed
Rulemaking
(NPRM)
is
organized
so
that,
for
each
of
the
proposed
revisions,
the
preamble
addresses
the
following
topics:
A.
What
are
the
current
requirements?;
B.
What
are
the
proposed
changes?;
and
C.
How
has
EPA
addressed
the
Alternative
Provision
Analysis
required
by
§
194.6?
III.
How
Is
EPA
Revising
the
Process
for
Establishing
Alternative
Provisions
in
§
194.6?
A.
What
Are
the
Current
Requirements
in
§
194.6?
Section
194.6
establishes
procedures
applicable
to
substitution
of
alternative
provisions
of
the
Compliance
Criteria.
As
discussed
above,
such
substitutions
require
notice
and
comment
rulemaking,
pursuant
to
Section
4
of
the
APA.
In
addition,
§
194.6
stipulates
that
EPA's
NPRM
address
specific
aspects
of
the
proposed
substitution,
include
a
public
comment
period
of
at
least
120
days,
and
public
hearings
in
New
Mexico.
B.
What
Changes
Are
Proposed
for
§
194.6?
EPA
is
proposing
to
revise
§
194.6
to
add
a
rulemaking
process
for
substituting
``
minor
alternative
provisions''
of
the
Compliance
Criteria.
The
process
for
substituting
``
minor
alternative
provisions''
would
include:
(1)
Rulemaking
pursuant
to
Section
4
of
the
APA;
(2)
publication
of
the
proposed
changes
in
the
Federal
Register,
together
with
information
describing
how
the
changes
conform
with
the
disposal
regulations,
the
reasons
why
the
changes
are
needed,
and
the
benefits
of
compliance
with
the
minor
changes;
(3)
a
public
comment
period
of
at
least
30
days;
and
(4)
publication
in
the
Federal
Register
of
the
final
notice
after
public
comments
received
have
been
fully
considered.
EPA
is
also
proposing
to
add
the
following
definition
of
``
minor
alternative
provision''
to
§
194.2:
``
minor
alternative
provision
means
an
alternative
provision
to
the
Compliance
Criteria
that
clarifies
a
regulatory
provision,
or
does
not
substantively
alter
the
existing
regulatory
requirement.
''
C.
How
Has
EPA
Addressed
the
Alternative
Provision
Analysis
Required
by
§
194.6?
The
Agency
wants
to
have
the
ability
to
make
insignificant
changes
to
the
Compliance
Criteria
in
an
expedited
time
frame
to
facilitate
WIPP's
continued
compliance
with
our
regulations.
The
provisions
for
substituting
minor
alternative
provisions
could,
for
example,
be
used
to
modify
the
Compliance
Criteria
to
change
regulatory
terminology
to
more
clearly
express
the
Agency's
intended
meaning
or
to
clarify
expectations.
Substitution
of
``
minor
alternative
provisions''
would
not
in
any
way
substantively
modify
the
Compliance
Criteria
requirements.
1.
Why
Do
the
Existing
Provisions
in
§
194.6
Appear
Inappropriate?
In
certain
specific
contexts,
discussed
below,
EPA
considers
the
existing
provisions
to
be
inappropriate
because
they
are
unnecessarily
stringent.
When
§
194.6
was
promulgated,
EPA
was
beginning
the
process
of
formal
regulation
of
the
WIPP.
EPA
had
not
yet
even
received
the
DOE's
compliance
certification
application.
EPA
now
has
engaged
in
close
regulatory
oversight
of
the
WIPP
for
over
six
years.
EPA
has
engaged
in
post
certification
oversight
of
the
WIPP
for
almost
four
years.
During
that
time,
EPA
has
gained
substantial
experience
and
insight
into
this
regulatory
process.
While
§
194.6,
as
originally
drafted,
was
intended
to
address
all
changes
to
the
Compliance
Criteria,
EPA
now
realizes
that
there
may
be
modifications
to
the
Compliance
Criteria
that,
while
useful,
are
not
sufficiently
significant
to
require
the
stringent
procedures
currently
set
forth
in
§
194.6.
EPA's
oversight
experience
indicates
that
minor
revisions
to
the
Compliance
Criteria
requirements
may
improve
implementation
and
consistency
in
regulatory
compliance.
EPA
believes
that
today's
proposal
includes
several
examples
of
minor
revisions
that
would
be
appropriately
addressed
by
a
less
stringent
process
than
currently
available
under
§
194.6.
For
example,
EPA
is
proposing
to
replace
the
term
``
process
knowledge''
in
§
194.24(
c)(
3)
with
the
term
``
acceptable
knowledge''
(see
section
VI
of
the
preamble).
This
minor
revision
is
intended
to
acknowledge
that
``
acceptable
knowledge''
is
the
term
EPA
has
used
consistently
since
the
WIPP
was
certified.
EPA
is
also
proposing
to
permit
DOE
to
submit
fewer
printed
recertification
compliance
applications
than
currently
required
in
the
Compliance
Criteria.
These
proposed
revisions
do
not
substantively
alter
the
intent
or
the
approach
to
verifying
compliance
with
the
waste
characterization
requirements
in
any
way,
but
improve
the
clarity
of
and
more
clearly
reflect
the
intent
of
the
Compliance
Criteria.
Such
minor
revisions
should
not
require
a
120
day
public
comment
period,
nor
necessitate
a
public
hearing.
We
propose
that
a
30
day
comment
period
is
sufficient
for
the
public
to
provide
the
Agency
with
relevant
input
on
such
minor
revisions
of
the
Compliance
Criteria.
In
addition
to
the
publication
of
the
NPRM
in
the
Federal
Register,
EPA
intends
to
announce
the
proposal
on
the
Agency's
website
and
place
all
relevant
supporting
materials
in
the
Agency's
public
docket.
For
all
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Vol.
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154
/
Friday,
August
9,
2002
/
Proposed
Rules
1
The
term
``
waste
characterization,
''
as
we
use
it
with
regard
to
the
WIPP
repository
and
the
numerous
waste
generator
sites,
encompasses
a
wide
array
of
activities,
all
of
which
serve
to
determine
what
is
inside
any
given
container
of
transuranic
waste
and
to
control
that
container
until
DOE
places
it
in
the
WIPP
for
disposal.
Stated
generally,
the
Compliance
Criteria
for
waste
characterization
in
§
194.24
require
DOE
to:
Determine
which
waste
components
(such
as
ferrous
metals)
and
characteristics
(e.
g.,
acidity)
are
relevant
to
the
WIPP's
performance;
show
how
they
affect
performance;
and
identify
and
track
significant
waste
components
as
they
are
placed
in
the
WIPP.
The
last
of
these
activities
is
the
subject
of
§
194.8(
b).
The
waste
characterization
requirements
are
discussed
in
great
detail
in
the
preamble
to
the
May
18,
1998,
Certification
Decision
final
rule.
(63
FR
27389–
27393)
2
The
term
``
waste
stream''
means
wastes
derived
from
a
single
process
or
activity
that
are
similar
in
material,
physical
form,
isotopic
makeup,
and
hazardous
constituents.
(Certification
Decision
proposed
rule
62
FR
58813.)
3
Process
knowledge
(``
PK'')
refers
to
knowledge
of
waste
characteristics
derived
from
information
generated
contemporaneously
with
the
waste
on
the
materials
or
processes
used
to
generate
the
waste.
This
information
may
include
administrative,
procurement,
and
quality
control
documentation
associated
with
the
generating
process,
or
past
sampling
or
analytical
data.
Usually,
the
major
elements
of
process
knowledge
include
information
about
the
process
used
to
generate
the
waste,
material
inputs
to
the
process,
and
the
time
period
during
which
the
waste
was
generated.
(Certification
Decision
final
rule
63
FR
27390.)
4
The
system
of
controls
for
waste
characterization
includes,
but
is
not
limited
to:
Measurement,
sampling,
chain
of
custody
records,
record
keeping
systems,
waste
loading
schemes
used,
and
other
documentation.
40
CFR
194.24(
c)(
4).
5
The
term
``
waste
component''
means
``
an
ingredient
of
the
total
inventory
of
the
waste
that
influences
a
waste
characteristic''.
40
CFR
194.2.
The
term
``
waste
characteristic''
means
``
a
property
of
the
waste
that
has
an
impact
on
the
containment
of
waste
in
the
disposal
system''.
40
CFR
194.2.
The
important
waste
components
with
regard
to
the
WIPP's
compliance
are
radionuclides,
ferrous
and
nonferrous
metals,
organic
materials
such
as
paper
and
rubber,
and
free
water.
6
The
WWIS
is
described
in
Chapter
4
(page
4–
35)
of
the
WIPP
Compliance
Certification
Application
as
``
a
computerized
data
management
system
used
*
*
*
to
gather,
store,
and
process
information
pertaining
to
transuranic
(TRU)
waste
destined
for
or
disposed
at
the
WIPP.
''
[Air
Docket
A–
93–
02,
Item
II–
G–
1.]
substitutions
of
alternative
provisions
that
are
not
minor
alternative
provisions,
as
defined
in
this
document
(for
example,
the
addition,
deletion,
or
significant
revision
of
a
requirement),
EPA
will
continue
to
comply
with
the
current
requirements
of
§
194.6.
EPA
defines
a
``
minor
alternative
provision''
as
an
alternative
provision
that
``
clarifies
a
regulatory
provision,
or
does
not
substantively
alter
the
existing
regulatory
requirement.
''
Thus,
revisions
that
do
not
alter
the
intent
or
the
approach
to
verifying
compliance
of
an
existing
regulatory
requirement
are
considered
to
constitute
minor
alternative
provisions.
For
example,
today's
proposed
revisions
to
§§
194.2,
194.12,
194.13,
and
194.24(
c)(
3)
are
examples
of
minor
changes.
The
proposed
revisions
to
§§
194.6
and
194.8(
b),
however,
are
examples
of
nonminor
alternative
provisions.
2.
How
Do
the
Proposed
Changes
in
§
194.6
Comport
with
40
CFR
part
191?
The
proposed
changes
for
§
194.6
comport
fully
with
the
radioactive
waste
disposal
regulations
at
40
CFR
part
191.
The
WIPP
must
comply
with
EPA's
radioactive
waste
disposal
regulations
located
at
Subparts
B
and
C
of
40
CFR
part
191.
These
regulations
limit
the
amount
of
radioactive
materials
that
may
escape
from
a
disposal
facility,
and
are
intended
to
protect
individuals
and
ground
water
resources
from
dangerous
levels
of
radioactive
contamination.
The
Compliance
Criteria
implement
and
interpret
the
general
disposal
regulations
specifically
for
the
WIPP,
and
constitute
the
basis
on
which
EPA's
certification
decision
was
made.
Section
194.6
was
included
in
the
Compliance
Criteria
to
ensure
that
any
amendments
to
the
Criteria
would
be
effected
through
the
same
rigorous
rulemaking
procedure
under
which
the
original
Criteria
were
promulgated.
The
proposed
amendment
to
§
194.6
would
not
substantively
alter
the
scope
of
those
requirements.
The
Compliance
Criteria
would
continue
to
include
the
current
process
established
in
§
194.6
to
revise
40
CFR
part
194.
The
principle
difference
between
the
existing
and
proposed
new
provisions
is
the
addition
of
a
revision
process
for
minor
changes.
This
new
revision
process
would
not
substantively
affect
the
Compliance
Criteria's
implementation
of
40
CFR
part
191.
3.
What
Are
the
Costs,
Risks,
and
Benefits
of
Compliance
with
the
New
Provisions
in
§
194.6
?
As
part
of
our
implementation
efforts
for
the
1998
certification
decision,
we
will
continue
to
develop
revisions
to
the
Compliance
Criteria,
as
we
deem
necessary,
based
on
lessons
learned
from
our
oversight
experience.
This
is
our
first
revision
to
the
Compliance
Criteria
since
the
initial
certification
decision
in
1998.
There
will
be
no
increased
costs
for
EPA
as
a
result
of
the
proposed
revision.
Rather,
EPA
believes
that
it
is
reasonable
to
expect
significant
savings
over
the
period
of
active
regulation
of
the
WIPP.
The
proposed
revision
will
shorten
rulemakings
where
appropriate
and
eliminate
a
requirement
for
public
hearings
in
instances
where
the
impact
of
changes
would
be
small
and
public
interest
may
reasonably
be
expected
to
be
low.
Moreover,
EPA
does
not
expect
DOE
to
incur
additional
costs,
since
the
implementation
of
§
194.6
is
solely
EPA's
responsibility.
EPA
does
not
anticipate
any
increased
risks
related
to
the
implementation
of
the
proposed
revision.
Rather,
we
anticipate
that
EPA's
regulatory
activities
will
become
more
efficient,
and
that
EPA
will
be
able
to
implement
necessary
minor
revisions
to
the
Compliance
Criteria
that
are
designed
to
improve
implementation
and
consistency
in
regulatory
compliance.
The
benefits
of
the
proposed
revision
to
§
194.6
are
several.
First,
the
Agency,
would
be
able
to
make
minor
revisions
to
the
Compliance
Criteria
in
a
timely
fashion.
Making
these
types
of
revisions
in
a
shorter
timeframe
will
enhance
compliance
with
40
CFR
part
194.
Second,
the
public
will
continue
to
have
an
opportunity
to
review
and
comment
on
proposed
minor
revisions.
Third,
the
Agency
will
continue
to
hold
public
hearings
in
New
Mexico
for
major
revisions
to
the
Compliance
Criteria.
Fourth,
DOE
will
be
able
to
implement
minor
revisions
faster,
therefore,
this
proposed
revision
will
contribute
to
safer
and
more
cost
effective
disposal
of
radioactive
wastes.
IV.
How
Is
EPA
Revising
the
Approval
Process
for
Waste
Shipment
From
Waste
Generator
Sites
for
Disposal
at
WIPP
in
§
194.8(
b)?
A.
What
Are
the
Current
Requirements
in
§
194.8(
b)?
Section
194.8(
b)
describes
the
process
by
which
EPA
reviews
and
approves
WIPP
related
waste
characterization
activities
1
at
DOE
transuranic
waste
sites.
At
present,
for
each
waste
stream
or
group
of
waste
streams
2
other
than
those
approved
in
our
final
certification
decision,
DOE
must
provide
information
on
how
a
waste
site
uses
process
knowledge
3
to
characterize
those
streams
(§
194.8(
b)(
1)(
i)).
The
DOE
also
must
implement
a
system
of
controls
4
that
confirms
that
the
total
quantity
of
important
waste
components
5
in
the
WIPP
does
not
exceed
limits
established
by
the
final
Certification
Decision
(§
194.8(
b)(
1)(
ii)).
In
order
to
show
EPA
that
the
system
of
controls
is
effective,
DOE
must
demonstrate
each
TRU
waste
site's
measurement
techniques
and
control
methods,
and
must
demonstrate
that
data
about
waste
components
are
properly
transferred
from
the
waste
sites
to
the
WIPP
Waste
Information
System
(WWIS).
6
To
evaluate
compliance
with
the
above
mentioned
requirements,
we
must
inspect
and
approve
each
DOE
transuranic
waste
site
that
wishes
to
ship
waste
to
the
WIPP
for
disposal.
We
must
inspect
the
site's
use
of
process
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Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
7
EPA
specifically
addressed
public
comments
concerning
the
importance
of
Condition
3
in
EPA's
Response
to
Comments
Document
for
the
Certification
Decision.
See
EPA
Air
Docket
A–
93–
02,
Item
V–
C–
1,
pages
2–
5
to
2–
9.
knowledge
and
witness
a
demonstration
of
waste
characterization
processes
for
each
waste
stream,
or
group
of
waste
streams,
that
the
site
intends
to
ship.
If
a
site
receives
our
approval
to
ship
a
single
waste
stream,
that
site
cannot
ship
a
different
waste
stream
until
we
perform
an
additional
inspection
under
authority
of
§
194.8(
b).
EPA
imposed
these
requirements
as
a
condition
of
the
certification
to
ensure
full
compliance
with
the
waste
characterization
regulations
at
§
194.24(
c).
Once
DOE
has
submitted
waste
characterization
program
plans
for
a
given
site,
we
place
the
plans
in
our
docket
and
publish
one
or
more
notices
in
the
Federal
Register
that
announce
the
availability
of
the
plans
and
our
intent
to
inspect
the
site
on
a
specific
date
(§
194.8(
b)(
2)).
We
also
open
a
comment
period
of
at
least
30
days
for
others
to
comment
on
the
waste
site's
plans.
After
the
inspection,
we
notify
DOE
of
our
compliance
determination
by
letter,
and
place
the
letter
and
the
report
of
the
inspection
in
our
docket
(§
194.8(
b)(
3)).
Finally,
we
perform
follow
up
inspections
at
a
site
to
verify
the
continuing
compliance
of
approved
waste
characterization
programs
(§
194.8(
b)(
4)).
The
following
two
subsections
explain
the
purpose
of
the
requirements
described
above
and
the
basic
elements
of
a
waste
characterization
inspection.
1.
What
Is
the
Purpose
of
EPA's
Waste
Characterization
Inspections?
The
purpose
of
EPA
inspections
at
DOE
sites
is
to
verify
that
TRU
waste
sites
are
characterizing
and
tracking
the
waste
such
that
EPA
is
confident
that
the
volume
and
characteristics
of
the
wastes
conform
with
the
requirements
of
the
WIPP
LWA
and
the
specific
conditions
of
the
Certification
Decision.
The
requirements
set
forth
at
§
194.8(
b)
establish
a
process
by
which
EPA
determines
whether
DOE
is
in
compliance
with
Condition
3
of
the
Certification
Decision.
Condition
3
states,
``[
t]
he
Secretary
[of
Energy]
shall
not
allow
shipment
of
any
waste
from
any
additional
LANL
[Los
Alamos
National
Laboratory]
waste
stream(
s)
or
from
any
waste
generator
site
other
than
LANL
for
disposal
at
the
WIPP
until
the
Agency
has
approved
the
processes
for
characterizing
those
waste
streams
for
shipment
using
the
process
set
forth
in
§
194.8.''
(40
CFR
part
194,
Appendix
A.)
Accordingly,
§
194.8(
b)
sets
forth
procedural
requirements
for
EPA's
approval
of
DOE
TRU
waste
sites
to
ship
specific
waste
streams
or
groups
of
waste
streams
to
WIPP.
The
basis
for
applying
Condition
3
to
the
WIPP
project
is
rooted
in
our
rationale
for
the
waste
characterization
criteria
in
§
194.24.
We
developed
these
criteria
because,
``
in
order
to
make
meaningful
predictions
about
the
performance
of
the
WIPP
over
long
periods
of
time,
it
is
necessary
to
have
a
good
understanding
of
the
characteristics
of
the
waste
proposed
to
be
emplaced
in
the
disposal
system.
''
(Compliance
Criteria
proposed
rule,
60
FR
5771).
We
required
DOE
to
show,
in
its
compliance
application
for
the
WIPP,
that
a
``
system
of
controls''
was
in
place
to
ensure
that
``
the
actual
characteristics
of
waste
will
be
identified
before
the
waste
is
emplaced
in
the
WIPP.
''
(60
FR
5772).
The
DOE
developed
an
extensive
set
of
technical
and
quality
assurance
requirements
with
which
all
transuranic
waste
sites
must
comply
before
shipping
waste
to
the
WIPP
for
disposal.
At
the
time
of
application,
DOE
had
incorporated
these
requirements
into
such
documents
as
the
Quality
Assurance
Program
Plan
(QAPP),
Waste
Acceptance
Criteria
(WAC),
and
Quality
Assurance
Project
Plan
(QAPjP).
However,
DOE
did
not
submit
the
necessary
information
about
all
transuranic
waste
site
programs
in
the
application.
At
the
time
that
DOE
submitted
the
CCA,
most
sites
had
not
begun
the
complex
process
of
complying
with
the
WIPP
waste
characterization
requirements
and
the
information
therefore
was
not
available
to
EPA
during
the
certification
process.
(Certification
Decision
proposed
rule
62
FR
58813–
58814).
Consequently,
we
were
not
able
to
determine
during
the
certification
rulemaking
that
the
technical
and
quality
assurance
requirements
for
waste
characterization
activities
had
been
established
and
properly
executed
at
all
transuranic
waste
sites.
LANL
was
the
only
transuranic
waste
site
to
demonstrate
during
the
certification
rulemaking
that
it
could
meet
the
waste
characterization
requirements
for
certain
wastes.
Therefore,
as
stated
in
Condition
3
of
the
certification,
EPA
only
authorized
DOE
to
ship
legacy
debris
waste
from
LANL
to
the
WIPP.
DOE
was
not
authorized
to
ship
other
than
legacy
debris
waste
from
LANL,
or
any
waste
streams
from
other
TRU
waste
sites,
until
DOE
had
demonstrated
the
ability
to
properly
characterize
these
wastes.
DOE's
Carlsbad
Field
Office
(CBFO),
which
operates
the
WIPP,
is
responsible
for
maintaining
compliance
with
EPA's
waste
characterization
requirements.
DOE
transuranic
waste
sites
vary
considerably
with
regard
to
the
types
of
waste
they
characterize
and
the
manner
in
which
they
implement
the
program
requirements
of
CBFO.
Therefore,
confirmation
that
waste
characterization
is
adequate
must
take
place
where
waste
characterization
occurs,
that
is,
at
the
transuranic
waste
sites
themselves.
(Certification
Decision
final
rule,
63
FR
27392).
Inspections
of
waste
characterization
programs
at
individual
sites
are
the
best
way
for
us
to
verify
that
the
sites
have
identified
the
actual
characteristics
of
the
waste.
During
inspections,
we
have
access
to
the
site
personnel
who
perform
the
work,
to
the
facilities
and
equipment
used
at
the
site,
and
to
the
operators'
extensive
documentation.
Direct
observation
of
the
site's
activities
greatly
increases
our
confidence
in
their
effectiveness.
Confidence
in
the
results
of
waste
characterization
is
particularly
important
at
this
early
stage
of
disposal,
when
DOE
is
characterizing
waste
that
TRU
waste
sites
packaged
years
before
the
establishment
of
the
WIPP
Compliance
Criteria.
7
2.
What
Are
the
Elements
of
an
EPA
Waste
Characterization
Inspection?
After
EPA
determines
that
an
inspection
is
necessary,
we
define
the
scope
of
the
inspection
based
on
information
provided
by
DOE.
We
then
prepare,
and
share
with
DOE,
a
checklist
for
each
of
the
activities
that
we
will
inspect.
During
the
inspection,
our
evaluation
of
a
site's
waste
characterization
activities
typically
involves
the
activities
listed
below.
EPA
inspectors
may
or
may
not
perform
these
and
other
activities
depending
on
the
scope
of
the
inspection.
Review
procedures,
records
of
the
maintenance
and
calibration
of
equipment
and
instruments,
and
personnel
training
files.
Interview
responsible
personnel
(such
as
equipment
operators)
and
site
managers
overseeing
program
implementation.
Observe
analytical
testing
of
waste
drums
selected
by
EPA
inspectors
to
ensure
that
approved
procedures
are
followed
and
an
instrument
is
capable
of
analyzing
a
given
waste
stream.
Observe
equipment
operation
to
determine
whether
the
operator
has
deviated
from
the
procedures
and
why
and
how
the
deviation
may
haven
affected
the
waste
characterization.
Review
waste
stream
data
reports.
Track
waste
characterization
data
through
various
phases
of
its
generation
and
confirmation
and
eventual
inclusion
in
the
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Register
/
Vol.
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No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
8
In
the
context
of
its
194.8
inspections,
EPA
has
defined
a
finding
as
``
a
determination
that
a
specific
item
or
activity
is
not
in
compliance
with
40
CFR
part
194.''
Similarly,
EPA
has
defined
a
concern
as
``
an
opinion
that
a
specific
item
or
activity
may
lead
to
noncompliance
with
40
CFR
part
194
at
a
future
time''.
The
inspectors'
determinations
are
recorded
in
the
checklist
for
each
activity
that
we
inspect.
At
the
end
of
each
inspection,
we
prepare
an
inspection
report.
The
completed
checklists
are
included
in
the
inspection
report.
The
inspection
report
also
describes
any
findings
or
concerns
that
the
inspectors
identified,
and
states
whether
EPA
requires
a
response
showing
how
any
unresolved
finding
or
concern
was
resolved.
8
It
is
sometimes
necessary
to
return
to
a
site
to
confirm
the
adequate
resolution
of
a
finding.
After
a
site
is
approved,
EPA
may
review
the
site's
progress
on
issues
that
we
identified
previously
during
a
subsequent
compliance
inspection.
B.
What
Are
the
Proposed
Changes
to
§
194.8(
b)?
Section
194.8
will
continue
to
describe
the
process
by
which
EPA
will
inspect
and
approve
waste
characterization
activities
at
TRU
waste
sites.
However,
we
are
proposing
to
alter
the
process
so
that
the
individual
waste
generator
sites
will
only
need
one
§
194.8
approval
from
EPA
to
conduct
waste
characterization
activities
related
to
all
on
site
waste
streams.
This
single
§
194.8
approval
will,
however,
specify
any
limitations
on
the
approval
that
will
necessitate
additional
inspections
by
EPA.
Any
such
additional
inspections
will
be
conducted
under
authority
of
§
194.24(
h),
not
under
§
194.8.
The
second
key
change
is
that
the
opportunity
for
public
comment
will
come
after
EPA
has
completed
its
inspection,
but
before
EPA
has
approved
the
site.
Therefore,
EPA
will
request
public
comment
on
the
Agency's
inspection
report
and
proposed
compliance
decision
for
a
site
under
§
194.8.
The
revised
process
by
which
the
Agency
will
verify
compliance
with
Condition
3
of
the
certification
is
described
below,
followed
by
an
explanation
of
the
two
principal
procedural
changes
that
result
from
the
revisions.
Under
today's
proposal,
first,
we
require
DOE
to
implement
waste
characterization
programs
and
processes
in
accordance
with
§
194.24(
c)(
4)
to
confirm
that
the
total
amount
of
each
waste
component
that
will
be
emplaced
in
the
WIPP
will
not
exceed
the
upper
limiting
value
or
fall
below
the
lower
limiting
value
described
in
the
introductory
text
of
paragraph
(c)
of
§
194.24.
Waste
characterization
processes
include
the
collection
and
use
of
acceptable
knowledge;
destructive
and/
or
nondestructive
techniques
for
identifying
and
measuring
waste
components;
and
the
validation,
control,
and
transmittal
to
the
WIPP
Waste
Information
System
database
of
waste
characterization
data
in
accordance
with
§
194.24(
c)(
4).
Second,
DOE
must
notify
EPA
in
writing
that
a
waste
characterization
program
at
a
transuranic
waste
site
is
prepared
to
characterize
waste
destined
for
disposal
at
the
WIPP.
The
Department
will
also
send
documents
that
explain
the
site's
system
of
controls
for
waste
characterization,
including
the
use
of
acceptable
knowledge,
as
described
in
§
194.24(
c)(
4).
Third,
EPA
will
conduct
a
baseline
inspection
of
the
waste
characterization
program
at
the
site
to
verify
that
an
adequate
system
of
controls
has
been
established
in
plans
and
technical
procedures,
and
that
those
plans
and
procedures
are
adequately
implemented.
The
inspection
will
include
a
demonstration
by
DOE
of
the
following:
collection
and
appropriate
use
of
acceptable
knowledge
data;
destructive
and
nondestructive
techniques
for
measuring
waste
components
identified
in
accordance
with
§
194.24(
b)(
2),
performed
on
the
wastes
proposed
for
disposal;
verification
of
the
qualifications
of
the
personnel
responsible
for
performing
waste
characterization
activities;
and
the
validation,
control,
and
transmittal
to
the
WIPP
Waste
Information
System
database
of
waste
characterization
data,
in
accordance
with
§
194.24(
c)(
4).
It
may
be
necessary
to
conduct
follow
up
inspection
activities
or
continuation
of
the
baseline
inspection
in
order
to
obtain
additional
information
and/
or
confirm
the
implementation
of
corrective
actions.
Fourth,
EPA
will
announce
in
the
Federal
Register
our
proposed
Baseline
Compliance
Decision
to
accept
the
site's
compliance
with
§
194.24(
c)(
4).
In
the
notice,
we
will
solicit
public
comment
on
the
relevant
inspection
report(
s)
and
all
supporting
materials
that
we
rely
upon
in
making
our
proposed
Baseline
Compliance
Decision.
These
materials
will
be
placed
in
the
public
docket
described
in
§
194.67.
The
notice
will
describe
any
limitations
on
approved
waste
streams
or
waste
characterization
processes
and
identify
(through
tier
designations)
what
changes
to
the
approved
waste
characterization
process
must
be
reported
to
and
approved
by
EPA
before
they
can
be
implemented.
EPA
will
designate
significant
changes
as
Tier
1;
minor
changes
will
be
designated
as
Tier
2.
The
notice
will
open
a
30
day
public
comment
period
on
the
proposed
compliance
decision.
Fifth,
after
the
end
of
the
public
comment
period
our
written
final
Baseline
Compliance
Decision
will
be
conveyed
in
a
letter
from
the
Administrator's
authorized
representative
to
DOE.
DOE
will
comply
with
any
reporting
requirements
identified
in
the
Baseline
Compliance
Decision
and
the
accompanying
inspection
report.
A
section
summarizing
significant
comments
and
issues
arising
from
comments
received
on
the
compliance
decision,
as
well
as
the
Administrator's
response
to
those
comments
and
issues,
will
be
included
in
our
final
inspection
report
and
will
be
made
available
to
the
public
through
our
public
docket.
A
copy
of
our
compliance
decision
letter
will
also
be
placed
in
the
docket.
Last,
after
a
site
receives
our
Baseline
Compliance
Decision,
EPA
will
conduct
inspections
under
§
194.24(
h)
to
confirm
the
continued
compliance
of
the
programs
approved
and/
or
to
verify
the
adequacy
of
any
tier
assigned
changes
to
the
waste
characterization
processes
not
authorized
by
our
Baseline
Compliance
Decision.
DOE
must
report
to
EPA
any
changes
as
identified
in
the
inspection
report
of
our
Baseline
Compliance
Decision.
The
reporting
will
inform
EPA's
decision
whether
to
perform
follow
up
inspections.
The
results
of
EPA's
inspections
will
be
made
available
to
the
public
through
the
public
docket.
If
we
determine
that
the
system
of
controls
used
by
the
site
is
not
adequate
to
characterize
certain
waste
streams,
then
the
site
may
not
dispose
of
materials
from
those
waste
streams
at
the
WIPP
until
the
Agency's
findings
have
been
adequately
resolved.
1.
Changes
to
the
Scope
of
EPA
Approvals
of
Waste
Characterization
Programs
Under
the
proposed
new
provisions,
EPA
will
issue
a
proposed
Baseline
Compliance
Decision
that
describes
what
we
inspected
and
found
to
be
technically
adequate
and
also
identifies
DOE's
subsequent
reporting
requirements
for
the
waste
characterization
program
in
question.
The
various
elements
of
the
waste
characterization
program
will
be
tiered,
and
the
basis
for
the
tiering
will
be
described
in
the
inspection
report
that
accompanies
the
proposed
Baseline
Compliance
Decision.
The
proposed
tiering
approach
is
a
mechanism
by
which
EPA
can
specify
which
changes
to
an
approved
waste
characterization
program
require
EPA
approval
before
waste
characterized
by
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Federal
Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
that
program
is
disposed
of
in
the
WIPP.
TRU
waste
sites
would
have
a
clear
understanding
of
which
changes
must
be
approved
by
EPA
prior
to
shipment
and
disposal.
The
tiering
of
elements
of
the
system
of
controls
for
waste
characterization
will
vary
depending
on
the
type
of
analytical
systems
that
a
site
has
demonstrated,
the
types
of
retrievably
stored
waste
at
a
site,
and
the
type
and
quality
of
information
the
site
has
compiled
to
describe
waste
contents.
The
proposed
tiered
approach
applies
only
to
waste
characterization
activities
subject
to
§
194.8(
b)
requirements.
We
propose
to
institute
two
tiering
levels.
Tier
1
designation
will
be
given
to
activities
for
which
changes
have
a
potentially
significant
impact
on
compliance
with
EPA
regulations,
such
as
changes
that
directly
affect
measurements
and/
or
estimates
of
isotopes
and
other
limited
waste
components.
Tier
1
activities
are
those
for
which
EPA
approval
would
be
necessary
prior
to
shipment
and
disposal
of
waste.
For
example,
EPA
approval
would
be
necessary
if
a
site
introduced
a
new
radioassay
technique,
because
radioassay
is
a
critical
element
of
the
system
of
waste
characterization
controls.
Technical
areas
that
are
likely
to
be
subject
to
Tier
1
designation
are
acceptable
knowledge
and
radioassay.
DOE
will
be
required
to
submit
documentation
to
EPA
in
advance
that
describes
planned
changes
to
Tier
1
activities.
This
documentation
will
inform
EPA's
decision
regarding
which
actions,
such
as
performance
of
an
inspection,
are
necessary
in
order
to
approve
the
changes.
Tier
2
activities
are
those
for
which
EPA
approval
would
not
be
necessary
prior
to
shipment
and
disposal
of
waste.
An
approved
site
could
implement
changes
to
elements
of
the
waste
characterization
program
with
Tier
2
designation
without
first
being
inspected
or
approved
by
EPA.
However,
DOE
must
report
changes
in
the
manner
prescribed
by
EPA
in
the
Baseline
Compliance
Decision.
DOE's
reporting
of
changes
to
Tier
2
activities
will
assist
EPA
with
the
planning
of
follow
up
inspections
at
sites.
Tier
2
designation
will
be
given
to
activities
that
have
a
minor
impact
on
compliance
with
the
WIPP
Compliance
Criteria
or
are
sufficiently
standardized
that
they
would
not
be
expected
to
change
significantly.
For
example,
the
actual
operation
of
radiographic
equipment
does
not
vary
greatly
from
machine
to
machine
or
from
site
to
site.
Also,
minor
revisions
to
procedures
are
a
regular
part
of
operations
and
usually
serve
to
clarify
or
improve
work
processes.
Technical
areas
that
are
likely
to
be
subject
to
Tier
2
designation
are
radiography
and
visual
examination.
The
required
reporting
by
DOE
of
Tier
2
changes
will
enable
EPA
to
monitor
the
overall
waste
characterization
program
at
a
site
and
develop
targeted
inspection
plans
for
continuing
compliance
inspections.
When
we
approve
a
waste
characterization
program,
we
will
assign
tiering
designations
based
chiefly
on
the
following
topics:
the
extent
to
which
a
process
was
demonstrated
at
the
time
of
our
§
194.8(
b)
inspection(
s);
quality
of
documentation;
the
range
of
possible
waste
streams
at
a
site;
the
demonstrated
proficiency
of
waste
characterization
personnel;
and
the
site's
compliance
with
DOE's
waste
acceptance
criteria
for
the
WIPP,
as
reviewed
and
approved
by
EPA.
Our
inspection
report
will
describe
EPA's
requirements
for
reporting
of
changes
to
waste
characterization
activities,
including
the
scope
and
frequency
of
reporting.
Sites
that
have
not
been
authorized
by
EPA
to
ship
waste
to
the
WIPP
under
the
current
provisions
of
§
194.8(
b)
will
be
subject
to
the
new
process
immediately
after
we
issue
the
final
version
of
this
rule.
For
sites
that
already
have
received
EPA's
approval
to
ship
certain
waste
streams,
we
are
proposing
to
reinspect
those
sites
using
the
revised
process.
In
other
words,
we
will
perform
a
full
scope
inspection
at
approved
sites
(Hanford
Site,
Idaho
National
Energy
and
Environment
Laboratory,
Los
Alamos
National
Laboratory,
Rocky
Flats
Environmental
Technology
Site,
and
the
Savannah
River
Site)
in
order
to
reset
the
Baseline
Compliance
Decision
based
on
current
activities
at
the
sites.
We
will
place
our
proposed
compliance
decision
for
each
approved
site
in
our
docket
and
open
comment
on
it.
TRU
waste
sites
with
an
approved
waste
characterization
program
may
continue
to
ship
waste
within
the
scope
of
the
existing
approval
while
the
baseline
inspection
process
is
taking
place,
provided
that
they
continue
to
operate
in
accordance
with
the
WIPP
Compliance
Criteria.
DOE
has
initiated
an
effort
called
the
Central
Characterization
Project
(CCP)
to
assist
small
quantity
TRU
waste
sites
with
the
completion
of
the
waste
characterization
activities
required
by
EPA
and
State
agencies.
Under
the
CCP,
a
single
DOE
contractor
assumes
responsibility
for
the
characterization
of
a
site's
transuranic
waste.
The
CCP
sends
a
mobile
waste
characterization
laboratory
to
the
site
to
complete
certain
activities,
such
as
radioassay.
EPA
has
approved
the
CCP's
operation
at
the
Savannah
River
Site,
where
it
was
first
tested
[Air
Docket
A–
98–
49,
Item
II–
A4–
19].
Under
the
existing
provisions
for
§
194.8,
EPA
must
first
inspect
and
approve
the
CCP
at
each
site,
for
each
waste
stream
or
group
of
waste
streams.
Under
the
proposed
new
provisions,
EPA
approval
under
§
194.8(
b)
will
still
be
required
for
CCP
operations
at
each
site.
However,
once
we
have
approved
the
CCP
at
a
site,
the
CCP
will
be
approved
to
characterize
all
waste
streams
at
that
site.
Moreover,
any
subsequent
inspections
by
EPA
will
be
performed
under
§
194.24(
h).
The
same
processes
described
above
for
TRU
waste
sites
will
apply
to
our
compliance
decisions
for
the
CCP.
2.
Changes
to
Public
Notice
of
Waste
Characterization
Inspections
Under
the
existing
provisions
of
§
194.8(
b),
EPA
opens
comment
on
DOE
waste
characterization
plans
each
time
that
we
plan
to
inspect
a
waste
characterization
program
at
a
site,
if
that
program
involves
new
waste
streams
or
changes
to
the
system
of
waste
characterization
controls.
We
announce
comment
periods
and
dates
of
inspections
in
the
Federal
Register.
Because
each
site
has
multiple
waste
streams
and
evolving
waste
characterization
programs,
we
have
opened
multiple
comment
periods
on
different
documents
for
each
site
that
we
have
approved
to
ship
waste.
We
respond
to
the
relevant
comments
that
we
receive
in
our
inspection
reports,
and
docket
the
inspection
reports
and
compliance
decisions.
Under
the
new
provisions
of
§
194.8(
b),
EPA
will
request
comment
on
our
proposed
Baseline
Compliance
Decision
for
each
site,
which
includes
the
results
of
our
inspection(
s)
in
the
form
of
an
inspection
report,
and
any
appropriate
supporting
documentation,
such
as
objective
evidence
in
support
of
Agency
findings.
We
will
open
comment
periods
only
in
relation
to
baseline
inspections
under
§
194.8(
b).
We
will
continue
to
respond
to
the
relevant
comments
that
we
receive
in
our
inspection
reports,
and
to
docket
the
inspection
reports
and
compliance
decisions.
The
results
of
subsequent
inspections
of
waste
characterization
programs
that
we
perform,
including
for
the
purpose
of
approving
Tier
1
changes,
will
be
placed
in
our
docket.
In
addition
to
these
steps,
we
plan
to
continue
to
announce
our
inspections
and
other
WIPP
related
activities
on
our
WIPP
home
page
at
www.
epa.
gov/
radiation/
wipp
and
our
WIPP
Information
Line
(1–
800–
331–
9477).
We
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Federal
Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
9
The
existing
provisions
were
designed
to
address
the
fact
that
at
the
time
of
certification,
DOE
was
able
to
demonstrate
the
effectiveness
of
the
proposed
system
of
controls
for
waste
characterization
only
for
certain
waste
streams
at
Los
Alamos
National
Laboratory
[see
63
FR
27390].
10
EPA
has
prepared
a
document
entitled
``
Background
Information
Document
for
§
194.8(
b)
Modification''
(Air
Docket
OAR–
2002–
0005–
0001),
which
explains
in
more
detail
the
technical
elements
examined
during
waste
characterization
inspections,
summarizes
EPA's
inspection
experiences
to
date,
and
presents
lessons
learned.
This
document
expands
and
complements
this
preamble
discussion
for
the
proposed
revisions
to
§
194.8(
b).
encourage
the
public
to
visit
our
Website
and
to
contact
us
with
questions
or
information
regardless
of
whether
we
have
opened
a
public
comment
period.
(Comments
in
response
to
an
announcement
in
the
Federal
Register
should
be
sent
directly
to
the
EPA
docket
specified
in
the
announcement.)
C.
How
Has
EPA
Addressed
the
Alternative
Provision
Analysis
Required
by
§
194.6?
The
proposed
changes
to
§
194.8(
b)
are
needed
to
increase
the
options
available
to
EPA
in
implementing
our
regulatory
oversight
of
DOE's
waste
characterization
program,
and
to
simplify
the
public
notice
process.
1.
How
Do
the
Proposed
Changes
Comport
With
40
CFR
part
191?
Considered
individually
and
as
a
group,
the
proposed
changes
comport
fully
with
the
radioactive
waste
disposal
regulations
at
40
CFR
part
191.
The
inclusion
of
requirements
for
waste
characterization
in
order
to
implement
the
disposal
regulations
was
established
by
the
rulemaking
that
resulted
in
the
WIPP
Compliance
Criteria
at
40
CFR
part
194.
Today's
proposed
changes
do
not
alter
the
scope
of
the
part
191
requirements.
The
Compliance
Criteria
will
continue
to
apply
waste
characterization
requirements
to
the
WIPP
project.
The
principal
difference
between
the
existing
and
proposed
provisions
is
the
process
by
which
EPA
verifies
compliance
with
the
provisions
and
notifies
the
public
of
that
process.
This
new
process
will
not
substantively
affect
the
Compliance
Criteria's
implementation
of
EPA's
radioactive
waste
disposal
regulations
at
40
CFR
part
191.
Moreover,
EPA
believes
that
the
proposed
changes
to
the
194.8
approval
process
will
allow
for
more
meaningful
public
participation.
2.
Why
Do
the
Existing
Provisions
Appear
Inappropriate?
EPA
considers
the
existing
provisions
inappropriate
for
the
reasons
explicated
below.
EPA
explained
the
basis
for
the
existing
provisions
in
the
May
18,
1998,
Certification
Decision
final
rule
(63
FR
27354).
9
The
importance
of
independently
verifying
the
adequacy
of
waste
characterization
activities
conducted
by
DOE
has
not
grown
any
less
relevant.
However,
our
experience
with
site
inspections
since
the
1998
certification
decision
has
raised
two
key
issues
that
we
believe
must
be
addressed
through
alternative
provisions.
First,
for
a
variety
of
reasons,
the
focus
of
the
existing
provisions
on
waste
streams
as
the
determining
factor
for
initiation
of
an
inspection
is
overly
restrictive
for
EPA.
The
requirement
at
§
194.8(
b)(
1)
that
DOE
must
demonstrate
the
system
of
controls
for
each
waste
stream
or
group
of
waste
streams
reflects
the
fact
that
some
waste
streams
are
better
documented
than
others.
Consequently,
there
may
be
variations
in
how
a
given
site
uses
information
in
the
acceptable
knowledge
(AK)
record
in
relation
to
the
AK
confirmatory
program
that
DOE
employs
under
the
terms
of
the
Certification
Decision.
DOE
sites
must
report
to
WIPP
as
part
of
the
TRU
waste
tracking
requirement
on
a
container
basis,
quantities
of
10
WIPPtracked
radionuclides
(americium
241,
cesium
137,
plutonium
238,
plutonium239
plutonium
240,
plutonium
242,
strontium
90,
uranium
233,
uranium234
and
uranium
238)
disposed
of
at
the
WIPP.
Reporting
on
a
container
basis
may
require
sites
to
perform
additional
waste
analysis
if
using
the
site
compiled
AK
is
not
adequate
to
estimate
these
radionuclides.
Similarly,
sites
are
responsible
for
reporting
the
quantities
of
cellulosics,
paper,
and
rubber
(CPR)
present
in
each
waste
container.
During
the
certification
rulemaking,
we
were
concerned
about
the
need
to
monitor
the
effect
of
these
variances
on
the
quality
of
waste
characterization
data.
Section
194.8(
b)
was
therefore
constructed
such
that
changes
to
the
system
of
controls,
in
addition
to
the
introduction
of
new
waste
streams,
would
be
sufficient
cause
to
require
separate
approval.
As
explained
in
the
194.8
BID
document,
EPA's
regulatory
experience
over
the
past
four
years
suggests
that
this
narrow
focus
on
specific
waste
streams
is
no
longer
necessary.
Second,
the
public
notice
process
described
in
§
194.8(
b)
has
not
yielded
the
level
of
comment
that
we
anticipated.
As
demonstrated
by
the
quantity
and
type
of
comments
we
have
received
following
publication
of
inspection
announcements
in
the
Federal
Register,
the
process
may
actually
be
a
source
of
confusion
for
the
public.
Each
of
these
issues
is
discussed
below.
a.
Why
are
the
existing
provisions
overly
restrictive
for
EPA?
EPA
now
has
several
years
of
experience
with
inspections
at
DOE
sites
where
waste
characterization
takes
place.
Since
certifying
the
WIPP
in
May
1998,
we
have
completed
over
twenty
inspections
under
authority
of
§
194.8.
We
also
have
completed
numerous
other
inspections
of
waste
characterization
activities
under
authority
of
§§
194.21
and
194.24(
h).
We
conducted
the
§
194.8
inspections
at
Los
Alamos
National
Laboratory,
Rocky
Flats
Environmental
Technology
Site,
Idaho
National
Engineering
and
Environmental
Laboratory,
the
Nevada
Test
Site,
the
Savannah
River
Site,
and
the
Hanford
Site.
In
addition,
we
inspected
the
operation
of
the
DOE
Central
Characterization
Program
(CCP)
at
the
Savannah
River
Site.
We
approved
all
of
the
programs
we
inspected
except
for
the
Nevada
Test
Site.
We
also
have
observed
DOE
audits
at
Lawrence
Livermore
Laboratory
and
Battelle
Columbus
Laboratory
for
the
purpose
of
learning
about
the
system
of
waste
characterization
controls
those
sites
are
developing.
10
Based
on
this
experience,
we
have
determined
that
the
existing
provisions
constrain
EPA's
ability
to
apply
limited
resources
to
a
burgeoning
waste
characterization
program
for
maximum
regulatory
benefit.
Under
the
existing
provisions,
we
must
conduct
a
§
194.8
inspection
at
a
site
if
any
of
the
following
conditions
is
true:
the
site
has
not
previously
been
approved
by
EPA
to
ship
waste;
the
site
seeks
approval
for
one
or
more
new
waste
streams
that
will
be
characterized
using
approved
processes;
the
site
seeks
approval
for
one
or
more
new
waste
streams
that
will
be
characterized
using
at
least
one
new
or
revised
process;
or
the
site
seeks
approval
to
introduce
a
new
or
revised
process
to
characterize
one
or
more
previously
approved
waste
streams.
DOE
is
currently
engaged
in
waste
characterization
at
five
major
sites,
and
plans
to
begin
operations
at
four
or
more
additional
sites
in
the
near
future.
The
number
of
DOE
sites
that
ultimately
will
ship
waste
to
the
WIPP
could
grow
to
approximately
two
dozen.
There
are
or
will
be
hundreds
of
waste
streams
at
these
sites,
and
the
methods
used
to
characterize
them
will
change
as
sites
acquire
new
instruments
and
techniques.
Consequently,
the
expansion
of
DOE's
national
transuranic
waste
shipment
program
could
lead
to
an
indefinite
expansion
of
EPA's
inspection
program.
If
EPA
must
complete
a
§
194.8
inspection
for
each
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Federal
Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
11
For
quality
assurance
purposes,
we
verify
that
data
validation
occurs
in
accordance
with
site
procedures,
and
that
properly
qualified
and
independent
QA
personnel
review
the
data.
This
step
takes
place
during
a
QA
audit
or
inspection.
For
technical
purposes,
we
independently
verify
the
quality
of
a
sample
of
data.
This
step
takes
place
during
a
waste
characterization
inspection.
12
Currently,
EPA
is
able
to
conduct
such
a
broad
scope
inspection.
However,
new
processes
and/
or
waste
streams
must
be
inspected
under
§
194.8(
b),
and
previously
approved
processes
and/
or
waste
streams
must
be
inspected
under
§§
194.21
and
194.24(
h).
Today's
proposal
would
allow
EPA
to
review
new
processes
and
waste
streams
under
§
194.24(
h)
after
a
site
has
been
initially
approved
under
§
194.8(
b).
new
waste
stream,
group
of
waste
streams,
or
waste
characterization
process,
the
demands
of
this
inspection
regime
will
overwhelm
our
resources.
We
believe
that
it
is
appropriate
to
amend
the
Compliance
Criteria
to
increase
the
flexibility
of
our
waste
characterization
inspection
program.
At
present,
the
most
restrictive
factor
in
the
existing
provisions
is
that
§
194.8(
b)
requires
EPA
to
issue
approvals
that
are
specific
to
individual
waste
streams
or
groups
of
waste
streams.
Our
experience
with
DOE's
waste
characterization
activities
since
1998
has
shown
that
there
are
multiple
factors
that
must
be
considered
when
verifying
technical
adequacy,
including
but
not
limited
to
waste
groupings.
Moreover,
for
purposes
of
waste
characterization
as
required
under
the
Compliance
Criteria,
the
applicable
waste
groupings
at
the
site
are
often
of
limited
relevance.
Typically,
DOE
TRU
waste
sites
define
and
delineate
waste
streams
on
the
basis
of
factors
related
to
hazardous
components
of
the
waste,
not
radiological
waste
components.
Thus,
while
the
waste
stream
groupings
may
have
significant
relevance
for
RCRA
purposes,
they
are
often
of
less
relevance
for
purposes
of
waste
characterization
requirements
conducted
under
authority
of
the
WIPP
LWA.
In
order
to
approve
a
site's
waste
characterization
program,
we
must
be
confident
that
the
site
is
capable
of
identifying
and
reporting
waste
components
(particularly
certain
radioisotopes)
identified
in
the
1998
Certification
Decision
as
important
to
compliance
(see
Compliance
Application
Review
Document
(CARD)
31,
Air
Docket
A–
93–
02,
Item
V–
B–
2).
As
DOE
stated
in
Chapter
4
of
the
Compliance
Certification
Application
(Air
Docket
A–
93–
02,
Item
II–
G–
1),
a
combination
of
qualitative
and
quantitative
methods
would
be
used
to
identify
and
report
waste
components.
These
methods
are:
acceptable
knowledge,
which
provides
information
about
waste
stream
contents
and
the
processes
that
generated
the
waste;
nondestructive
examination
of
waste
containers
using
radiographic
techniques,
which
provides
qualitative
estimates
of
physical
waste
components;
destructive
and
nondestructive
examination
of
waste
containers
using
radioassay
techniques,
which
was
the
only
quantitative
means
proposed
by
DOE
to
quantify
radioisotopic
components;
destructive
(visual)
examination
of
sampled
containers
to
confirm
the
results
of
radiography
through
direct
observation
and
measurement;
and
data
reporting
via
the
WIPP
Waste
Information
System
(WWIS).
Confirmation
of
data
validity
at
various
points
is
an
integral
part
of
these
processes.
11
All
of
these
technical
processes
constitute
the
``
system
of
controls''
specified
in
§
194.24(
c)(
4).
The
demonstrated
effectiveness
of
a
given
element
of
the
system
of
controls
may
or
may
not
be
constrained
by
the
specific
features
of
a
waste
stream.
A
TRU
waste
site's
implementation
of
certain
elements
of
the
system
of
controls,
such
as
the
WWIS,
may
not
change
at
all
from
one
waste
stream
to
the
next.
In
contrast,
which
nondestructive
assay
techniques
may
be
effective
for
a
given
waste
stream
depends
in
part
on
the
physical
form
of
the
waste
and
the
quality
of
the
acceptable
knowledge
for
that
waste.
The
result
most
often
has
been
that
we
have
defined
limitations
on
approved
waste
streams
based
on
the
element
of
the
system
of
controls
whose
effectiveness
is
tied
most
closely
to
the
characteristics
of
individual
waste
streams,
that
is,
nondestructive
assay
(NDA).
We
have
limited
(or
narrowed)
our
approvals
to
certain
NDA
equipment
because
factors
such
as
the
calibration
and
physical
location
of
an
individual
instrument
are
important
to
the
technical
adequacy
of
the
method,
and
because
instrument
performance
varies
based
on
the
radioisotopes
in
a
waste
container.
DOE
may
only
ship
waste
streams
characterized
with
certain
equipment;
otherwise,
EPA
must
conduct
another
§
194.8
inspection
to
approve
new
equipment.
Our
new
approach
to
waste
characterization
inspections,
with
the
new
tiering
approach,
will
require
DOE
to
report
changes
such
as
the
introduction
of
new
nondestructive
assay
equipment,
but
will
allow
EPA
to
determine
whether
an
inspection
is
needed
for
the
new
equipment.
Under
Tier
2,
it
is
possible
that
a
``
desktop''
review
of
procedures
and
data
packages
will
be
sufficient
to
demonstrate
the
similarity
of
a
new
process
to
an
approved
process.
Alternatively,
under
Tier
1,
EPA
will
have
flexibility
to
schedule
an
inspection
whose
scope
covers
multiple
processes
and
waste
streams,
etc.
12
Ultimately,
the
critical
factor
in
our
decision
making
on
the
initial
approval
is
how
effectively
TRU
waste
sites
set
and
enforce
appropriate
limitations
on
the
usage
of
certain
techniques,
and
how
carefully
they
confirm
and
control
the
results
of
those
techniques.
Issuance
of
our
approval
under
§
194.8(
b)
means
that
we
have
found
that
the
site
developed
appropriate
procedures
for
waste
characterization
processes;
the
site
properly
implemented
those
procedures;
and
we
are
confident,
based
on
our
independent
evaluation,
that
the
data
reported
to
the
WWIS
are
properly
controlled.
We
will
continue
to
make
this
assessment
during
the
initial
§
194.8
inspection(
s)
at
a
site.
Under
the
existing
provisions,
introduction
of
any
waste
streams
or
processes
outside
the
scope
of
the
initial
approval
necessitates
potentially
many
more
§
194.8(
b)
inspections.
The
changes
that
we
are
proposing
today
will
not
alter
our
authority
to
limit
the
scope
of
any
site
approval.
Rather,
the
changes
will
enable
EPA
to
determine
independently
whether
a
subsequent
inspection
is
appropriate,
and
when
it
should
occur.
We
reserve
the
authority
to
specify
any
appropriate
limitations
on
the
waste
streams
that
may
be
shipped
and
the
processes
that
may
be
used
to
characterize
waste.
b.
How
can
the
public
notice
process
for
§
194.8
inspections
be
improved?
Under
the
existing
provisions,
EPA
must
publish
a
notice
in
the
Federal
Register
announcing
a
scheduled
inspection
under
authority
of
§
194.8(
b)(
2).
In
the
same
notice
or
a
separate
notice,
we
must
solicit
public
comment
for
at
least
thirty
days
on
waste
characterization
program
plans
and
other
documents
relevant
to
the
inspection.
DOE
sends
these
plans
and
other
documents
to
EPA
and
we
place
copies
in
our
public
docket
and
supplemental
dockets.
After
the
comment
period
has
ended,
we
notify
DOE
by
letter
of
our
compliance
determination
and
place
the
resulting
inspection
reports
in
our
dockets
(§
194.8(
b)(
3)).
In
our
1998
Certification
Decision,
we
explained
the
rationale
for
the
process
described
in
§
194.8(
b).
In
particular,
we
explained
that
our
compliance
decision
must
be
based
on
our
independent
inspections
of
waste
characterization
processes.
Inspections
involve
review
of
many
different
documents,
interviews
with
staff,
and
on
site
demonstrations,
which
are
then
summarized
and
made
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Federal
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/
Vol.
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No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
public
in
our
inspection
reports
[see,
for
example,
EPA
Air
Docket
A–
93–
02,
Item
V–
C–
1,
pp.
2–
8
to
2–
11
and
6–
26].
We
are
not
able
to
provide
all
potentially
relevant
information
in
our
dockets
when
we
open
a
public
comment
period.
Under
the
existing
provisions,
we
open
comment
on
the
top
tier
program
plans
that
describe
the
fundamental
requirements
for
and
organization
of
waste
characterization
activities
at
a
site,
plus
additional
procedures
if
appropriate
to
the
scope
of
the
inspection.
Such
documents
inform
our
preparation
for
an
inspection
and
are
sufficient
to
allow
the
public
to
raise
compliance
concerns
or
questions,
or
provide
additional
information
to
EPA,
so
that
we
are
aware
of
that
information
prior
to
reaching
a
compliance
decision.
We
refrain
from
reaching
a
final
compliance
decision
until
we
have
reviewed
and
responded
to
public
comment.
Our
inspection
reports
reference
the
specific
materials
that
we
reviewed
at
the
site
and
contain
objective
evidence
in
support
of
our
findings.
As
mentioned
above,
we
have
completed
a
significant
number
of
inspections
under
authority
of
§
194.8(
b)
since
May
1998.
We
have
published
a
total
of
twenty
one
Federal
Register
notices
related
to
those
inspections.
In
response,
we
received
only
nine
sets
of
comments,
which
we
believe
to
be
low.
Also,
several
comments
consisted
of
requests
to
extend
a
public
comment
period,
which
suggests
there
may
be
a
misunderstanding
of
the
purpose
of
the
comment
period
under
current
procedures
(that
is,
to
comment
on
the
waste
characterization
documents
in
the
docket
and/
or
raise
concerns
to
EPA).
Specifically,
at
least
one
of
the
requests
argued
that
an
extension
was
appropriate
so
that
information
other
than
the
waste
characterization
plans
and
procedures
could
be
docketed
and
reviewed
by
the
public.
Both
of
these
factors
indicate
that
the
existing
provisions
for
public
notice
are
not
optimal
for
either
EPA
or
the
public.
There
is
also
evidence
to
suggest
that
the
conditions
that
necessitate
additional
§
194.8
inspections
at
an
approved
site
may
not
be
widely
understood,
even
within
the
DOE
transuranic
waste
complex.
The
most
serious
example
occurred
in
July
2001,
when
EPA
learned
that
waste
was
shipped
from
DOE's
Idaho
site
(INEEL)
and
disposed
of
in
the
WIPP
despite
having
been
assayed
by
equipment
that
had
not
approved
by
EPA
following
inspection.
INEEL
had
received
our
approval
to
use
certain
waste
characterization
processes
on
certain
waste
streams
in
1999,
but
the
equipment
in
question
was
not
included
in
the
previous
approval.
During
an
inspection
to
investigate
the
nonconformance,
we
learned
that
its
cause
was
an
isolated
failure
to
follow
document
control
procedures.
Nevertheless,
our
interviews
with
site
personnel
and
Carlsbad
Field
Office
personnel
revealed
confusion
over
whether
a
§
194.8(
b)
inspection
(including
public
notice)
was
required
for
the
new
equipment
(see
Air
Docket
A–
98–
49,
Item
II–
A1–
28).
In
response
to
these
issues,
the
new
public
notice
process
that
we
are
proposing
would
change
three
key
aspects.
First,
each
site
would
be
inspected
only
once
under
§
194.8(
b),
therefore
only
one
comment
period
would
be
opened
for
each
site
under
§
194.8.
Second,
EPA
would
solicit
comment
not
only
on
DOE
documentation,
but
also
on
our
baseline
inspection
report(
s)
and
proposed
compliance
decision
for
each
site.
The
comment
period
would
begin
after
we
have
completed
all
necessary
inspections
and
assembled
the
inspection
report(
s).
Third,
the
inspection
report
resulting
from
a
site's
§
194.8(
b)
baseline
inspection(
s)
would
identify
and
explain
EPA's
tier
assignments
for
DOE
reporting
of
changes
to
the
approved
waste
characterization
processes,
based
on
the
conditions
and
maturity
of
the
waste
characterization
program
particular
to
that
site.
This
reporting
would
inform
EPA
that
a
site
has
implemented
or
is
considering
changes
to
the
approved
waste
characterization
processes.
For
those
changes
requiring
EPA
approval,
we
would
perform
follow
up
inspections
prior
to
allowing
changes
in
the
site's
system
of
controls,
or
in
the
waste
streams
shipped
from
the
site.
We
believe
that
this
approach
is
more
straightforward
than
the
existing
provisions
and
should
serve
to
reduce
any
confusion
about
the
public
notice
process
that
may
exist.
3.
What
Are
the
Costs,
Risks,
and
Benefits
of
Compliance
With
the
Alternative
Provisions?
Since
1998,
we
have
conducted
over
twenty
inspections
under
§
194.8(
b),
at
an
average
cost
of
approximately
$22,350
each
(this
estimate
includes
contractor
travel
and
technical
support
plus
labor
and
travel
costs
of
EPA
personnel).
These
inspections
were
conducted
to
approve
both
new
waste
streams
and
new
waste
characterization
processes
proposed
by
DOE.
DOE
has
identified
569
different
waste
streams
as
potentially
eligible
for
disposal
at
the
WIPP
facility
[Air
Docket
A–
93–
02,
Item
II
G–
1,
Vol.
s
III
IV,
Appendix
BIRTransuranic
Baseline
Inventory
Report].
If
we
were
to
continue
to
approve
site
waste
characterization
activity
on
a
waste
stream
basis,
the
costs
and
logistics
of
our
inspection
schedule
would
rapidly
become
unmanageable.
DOE
incurs
costs
as
a
result
of
being
inspected
by
EPA.
Operations
may
be
interrupted
to
some
extent
while
key
personnel
respond
to
the
inquiries
of
inspectors
and
operators
respond
to
EPA's
requirements
for
testing
of
equipment.
The
additional
reporting
requirements
introduced
by
the
proposed
new
provisions
also
represent
costs
to
DOE.
However,
we
do
not
anticipate
that
the
long
term
costs
to
DOE
due
to
the
proposed
new
provisions
will
be
greater
than
at
present.
The
risk
associated
with
the
proposed
new
provisions
is
the
same
as
that
which
exists
for
the
existing
provisions.
There
is
always
a
possibility
that
a
compliance
issue
may
continue
undetected
by
EPA
for
a
period
of
time,
leading
to
the
improper
placement
of
waste
in
the
repository.
With
regard
to
this
possibility,
we
note
several
important
considerations.
First,
EPA
will
maintain
a
rigorous
inspection
program
for
WIPP
waste
characterization
activities.
Second,
DOE
is
required
to
maintain
an
active
quality
assurance
program
that
audits
waste
characterization
programs
on
an
annual
basis
for
compliance
with
applicable
regulatory
requirements.
Last,
as
the
operator
of
the
WIPP,
DOE
is
responsible
for
maintaining
the
quality
of
waste
characterization
programs.
As
a
regulator
of
the
WIPP,
EPA's
role
is
to
verify
independently
that
DOE
is
adequately
maintaining
quality.
The
combination
of
DOE's
internal
quality
assurance
audits
and
EPA's
independent
regulatory
inspections
has
proven
able
to
identify
compliance
issues
and
correct
them.
Therefore,
we
conclude
that
the
proposed
new
provisions
do
not
carry
greater
risks
for
compliance
with
the
disposal
regulations
than
the
existing
provisions.
The
benefits
of
the
new
provisions
were
described
in
the
preceding
section.
We
expect
site
shipment
activity
to
increase
as
approved
waste
generator
sites
incorporate
new
waste
streams
to
their
current
characterization
activities
and
new
waste
generator
sites
seek
EPA
approval
for
their
shipments
for
the
first
time.
Under
the
proposed
new
provisions,
EPA
will
have
more
control
over
our
inspection
schedule,
which
will
enable
us
to
manage
limited
resources
for
maximum
regulatory
benefit.
The
proposed
changes
will
not
alter
EPA's
technical
approach
to
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Federal
Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
inspections
of
the
waste
characterization
capabilities
at
DOE
waste
generator
sites.
Inspections
will
continue
to
involve
in
depth
interviews
of
personnel,
careful
reviews
of
analytical
procedures,
and
demonstrations
of
waste
characterization
techniques
and
equipment.
We
will
approve
only
sites
that
can
effectively
characterize
wastes
destined
for
disposal
at
the
WIPP.
Once
those
sites
are
approved,
we
will
continue
to
oversee
their
programs
through
ongoing
inspections.
Additionally,
we
expect
that
the
changes
to
the
public
notice
process
that
we
are
proposing
will
make
the
comment
period
for
inspections
more
relevant.
The
public
will
now
have
an
opportunity
to
review
and
comment
on
EPA's
proposed
decisions
and
inspection
reports
prior
to
site
approvals.
Finally,
the
new
provisions
will
be
beneficial
to
DOE
because
reporting
requirements
for
DOE
will
be
established
on
a
site
by
site
basis.
It
will
be
clearer
to
the
sites
when
a
particular
change
in
their
activities
will
trigger
review,
inspection,
or
approval
on
EPA's
part.
Also,
DOE
will
be
able
to
implement
changes
in
the
Tier
2
elements
of
their
waste
characterization
activities
without
prior
approval.
Sites
with
more
effective
waste
characterization
programs,
including
sites
that
successfully
demonstrate
the
applicability
of
waste
characterization
controls
to
the
broadest
possible
spectrum
of
waste
at
the
time
of
EPA's
inspection,
are
likely
to
have
more
activities
listed
in
Tier
2
than
sites
with
less
effective
programs.
V.
How
Is
EPA
Revising
the
Submission
of
Compliance
Applications
and
Reference
Materials
Requirements
in
§§
194.12
and
194.13?
A.
What
Are
the
Current
Requirements
in
§§
194.12
and
194.13?
Section
194.12
of
the
Compliance
Criteria
requires
DOE
to
submit
30
copies
of
the
compliance
applications
and
any
accompanying
materials
to
the
Administrator
in
printed
form.
This
provision
also
applies
to
the
compliance
applications
periodically
submitted
by
DOE
for
re
certification
of
compliance.
Section
194.13
requires
that
10
printed
copies
of
referenced
materials
be
submitted
to
the
Administrator,
unless
such
materials
are
generally
available.
B.
What
Are
the
Proposed
Changes
to
§§
194.12
and
194.13?
EPA
proposes
to
revise
§
194.12
by
changing
the
number
of
copies
of
compliance
applications
in
printed
form
from
30
to
5
(one
original
and
four
printed
copies).
In
addition,
the
Agency
is
revising
§
194.12
to
require
that
DOE
submit
10
complete
compliance
applications
in
alternative
format
(e.
g.,
compact
disk)
or
other
approved
format.
Also,
the
Agency
is
proposing
to
revise
§
194.13
by
changing
the
number
of
copies
in
printed
form
of
the
reference
materials
from
10
to
5
and
to
require
DOE
to
submit
10
copies
of
reference
materials
in
alternative
format
(e.
g.,
compact
disk)
or
other
approved
format.
C.
How
Has
EPA
Addressed
the
Alternative
Provision
Analysis
Required
by
§
194.6?
The
proposed
changes
to
§§
194.12
and
194.13
are
intended
to
minimize
the
number
of
copies
in
printed
form
that
need
to
be
submitted
and
to
allow
for
the
submission
of
compliance
applications
and
reference
materials
in
alternative
format
(e.
g.,
compact
disk).
The
use
of
alternative
format
will
facilitate
compliance
with
40
CFR
part
194
requirements
because
it
will
expedite
EPA's
evaluation
of
the
compliance
application
and
reduce
costs
associated
with
the
review
of
compliance
applications
and
reference
materials.
Receipt
of
application
materials
in
alternative
format
will
also
improve
information
sharing
with
the
public
by
enabling
the
Agency
to
more
easily
make
these
materials
available
via
the
Internet.
1.
Why
Do
the
Existing
Provisions
in
§§
194.12
and
194.13
Appear
Inappropriate?
The
existing
provisions
in
§§
194.12
and
194.13
are
inappropriate
because
EPA
does
not
need
DOE
to
deliver
30
printed
copies
of
the
complete
compliance
application,
nor
10
printed
copies
of
all
reference
materials.
In
1996,
when
the
Compliance
Criteria
were
finalized,
the
Agency
required
that
30
copies
of
the
compliance
application
and
10
copies
of
the
referenced
material
be
submitted
for
use
in
our
review
and
evaluation
activities.
Printed
form
copies
were
necessary
because
the
Agency
had
a
limited
time
period
for
review
and
the
complexity
of
the
application
material
required
many
reviewers.
Also,
EPA
placed
copies
of
these
documents
in
various
public
dockets.
EPA's
requirements
for
the
submission
of
compliance
applications
and
reference
materials
have
changed
since
the
promulgation
of
the
Compliance
Criteria
in
1996.
If
material
is
submitted
in
alternative
format
(e.
g.,
compact
disk)
or
other
approved
format
instead
of
printed
matter,
it
is
only
necessary
to
have
5
printed
copies
of
the
compliance
application
and
5
printed
copies
of
the
reference
materials
not
included
in
previous
compliance
applications
(provided
that
the
information
has
remained
true
and
accurate)
for
our
four
public
dockets
(including
an
official
copy
for
EPA).
New
advances
in
information
management
require
the
use
of
new
submission
methods,
such
as
the
use
of
alternative
format
(e.
g.,
compact
disk).
Information
and
data
in
alternative
format
are
easier
to
view,
share,
navigate,
and
analyze.
However,
current
regulatory
language
in
§§
194.12
and
194.13
does
not
allow
for
the
submission
of
compliance
applications
and
reference
materials
in
alternative
format.
Therefore,
today's
action
proposes
to
revise
the
regulatory
language
in
these
sections
to
require
alternative
format
(or
other
approved
format)
submission
of
both
compliance
application
(also
re
certification
applications)
and
reference
materials.
2.
How
Do
the
Proposed
Changes
in
§§
194.12
and
194.13
Comport
With
40
CFR
Part
191?
The
proposed
changes
to
§§
194.12
and
193.13
comport
fully
with
the
radioactive
waste
disposal
regulations
at
40
CFR
part
191.
The
inclusion
of
submission
requirements
for
compliance
applications
and
reference
materials
in
order
to
implement
the
disposal
regulations
was
established
by
the
rulemaking
that
resulted
in
the
WIPP
Compliance
Criteria
at
40
CFR
part
194.
Today's
proposed
changes
do
not
alter
the
scope
of
those
requirements.
The
Compliance
Criteria
would
continue
to
apply
submission
requirements
to
the
WIPP
project.
The
principle
differences
between
the
existing
and
proposed
new
provisions
are
that
the
number
of
printed
copies
to
be
submitted
to
EPA
has
been
reduced
considerably
and
alternative
format
(or
other
approved
format)
submission
of
compliance
applications
and
reference
materials
is
now
required.
The
proposed
revisions
to
this
part
do
not
impact
the
Compliance
Criteria's
implementation
of
40
CFR
part
191.
3.
What
Are
the
Costs,
Risks,
and
Benefits
of
Compliance
With
the
New
Provisions
in
§§
194.12
and
194.13?
Sections
194.12
and
194.13
require
DOE
to
submit
a
specified
number
of
copies
in
printed
form
of
the
compliance
application
and
reference
materials.
This
provision
also
applies
to
the
compliance
applications
periodically
submitted
by
DOE
for
recertification
of
compliance.
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Federal
Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
13
This
definition
is
consistent
with
EPA's
and
DOE's
use
of
the
term
``
acceptable
knowledge''
during
the
WIPP
certification
rulemaking.
See,
for
example:
Air
Docket
A–
93–
02,
Item
II–
G–
1,
page
4–
45;
Item
V–
B–
2,
Compliance
Application
Review
Document
(CARD)
24,
page
24–
1;
and
63
FR
27390,
footnote
32.
14
Examples
of
processes
or
operations
that
create
transuranic
waste
are
molding
of
plutonium
with
crucibles,
laboratory
analysis
of
radioactive
samples,
and
chemical
separation
of
plutonium
from
other
materials.
The
number
and
types
of
processes
in
use
at
a
DOE
site
depends
on
the
nature
and
complexity
of
the
site's
mission.
proposed
revisions
reduce
the
number
of
copies
required
and
requires
submission
of
compliance
applications
and
references
in
alternative
format
(or
other
approved
format).
We
do
not
anticipate
any
cost
increase
related
to
our
implementation
of
the
changes
to
§§
194.12
and
194.13.
These
changes
will
improve
our
ability
to
view,
share,
navigate,
print,
and
analyze
submitted
materials.
We
expect
to
be
able
to
conduct
our
review
of
compliance
applications
in
a
more
efficient
and
cost
effective
manner.
Also,
the
implementation
of
these
changes
will
facilitate
our
ability
to
share
information
with
the
public
in
a
more
timely
fashion.
As
we
received
information
and
data
in
alternative
format,
it
would
be
easier
to
post
this
information
in
our
webpage.
Similarly,
we
do
not
anticipate
that
DOE
will
experience
any
cost
increase
as
a
result
of
their
compliance
activities
with
this
part
because
the
technology
to
produce
alternative
format
submittals
exists
and
is
currently
in
use.
We
do
not
anticipate
any
significant
risks
related
to
the
implementation
of
the
proposed
revisions
to
this
part.
Submission
of
information
and
data
in
other
than
paper
form
is
a
widely
accepted
process
that
will
ease
the
transfer
of
information
between
DOE
and
EPA
and
therefore,
improve
compliance
with
40
CFR
part
194.
In
summary,
the
benefits
of
the
proposed
revisions
for
§§
194.12
and
194.13
are
several.
First
the
Agency
will
benefit
from
an
improved
evaluation
process
and
reduced
costs
associated
with
the
review
of
compliance
applications
and
reference
materials.
Second,
the
public
will
be
able
to
have
better
and
faster
access
to
information
used
in
support
of
WIPP
compliance
activities.
This
change
will
improve
the
public's
ability
to
participate
more
actively
in
the
public
comment
process.
Third,
the
proposed
changes
to
§§
194.12
and
194.13
are
intended
to
reduce
the
number
of
copies
in
printed
form
that
must
be
submitted,
thereby
reducing
paper
usage.
VI.
How
Is
EPA
Revising
the
Waste
Characterization
Requirements
in
§
194.24(
c)(
3)?
A.
What
Are
the
Current
Waste
Characterization
Requirements
in
§
194.24(
c)(
3)?
Section
194.24,
waste
characterization,
generally
requires
DOE
to
identify,
quantify,
and
track
the
chemical,
physical,
and
radiological
components
of
the
waste
destined
for
disposal
at
WIPP
that
may
influence
disposal
system
performance.
Section
194.24(
c)(
3)
requires
DOE
to
demonstrate
that
the
use
of
process
knowledge
to
quantify
waste
components
conforms
with
the
quality
assurance
(QA)
requirements
outlined
in
§
194.22.
To
demonstrate
compliance
DOE
must
have
information
and
documentation
to
substantiate
that
process
knowledge
data
acquired
and
used
during
waste
characterization
activities
are
in
compliance
with
the
QA
requirements.
EPA
verifies
compliance
with
this
requirement
through
inspections,
where
EPA
conducts
proper
review
of
such
information
to
determine
whether
use
of
process
knowledge
data
is
appropriate
and
reliable.
B.
What
Are
the
Proposed
Changes
to
§
194.24(
c)(
3)?
The
Agency
is
proposing
to
revise
§
194.24(
c)(
3)
by
replacing
the
term
``
process
knowledge''
with
the
term
``
acceptable
knowledge.
''
The
term
``
acceptable
knowledge''
has
been
the
term
used
by
EPA
and
DOE
since
DOE
submitted
the
Compliance
Certification
Application,
during
both
the
certification
rulemaking
and
subsequent
site
inspections.
Use
of
the
term
``
acceptable
knowledge''
in
§
194.24(
c)(
3)
in
lieu
of
``
process
knowledge''
will
not
alter
our
technical
approach
to
verifying
compliance
during
an
inspection;
rather,
it
will
reflect
our
actual
practice
more
accurately.
For
consistency
with
the
change
being
proposed
today
for
§
194.24(
c)(
3),
the
Agency
is
also
proposing
to
add
the
following
definition
of
``
acceptable
knowledge''
to
§
194.2:
``
Acceptable
knowledge
means
any
information
about
the
process
used
to
generate
waste,
material
inputs
to
the
process,
and
the
time
period
during
which
the
waste
was
generated,
as
well
as
data
resulting
from
the
analysis
of
waste
conducted
prior
to
or
separate
from
the
waste
certification
process
authorized
by
EPA's
Certification
Decision,
to
show
compliance
with
Condition
3
of
the
certification
decision
(40
CFR
part
194,
Appendix
A).
''
13
Section
194.2
is
contained
in
Subpart
A
(General
Provisions)
of
the
rule,
which
describes
the
purpose
and
scope
of
the
regulation,
clarifies
terms,
specifies
dates,
and
imparts
a
range
of
administrative
information.
Section
194.2
focuses
on
providing
an
explanation
of
all
terms
and
abbreviations
contained
in
40
CFR
part
194
for
clarification
purposes.
C.
How
Has
EPA
Addressed
the
Alternative
Provision
Analysis
Required
by
§
194.6?
The
proposed
changes
for
both
§§
194.2
and
194.24(
c)(
3)
are
intended
to
clarify
exactly
what
information
EPA
requires
from
DOE.
EPA
expects
that
with
these
changes,
acceptable
knowledge
(AK)
will
be
more
clearly
identified
as
an
integral
part
of
the
system
of
controls
for
waste
characterization
and
will
require
DOE
to
provide
information
about
the
entire
system
of
controls
(including
AK)
and
implement
the
systems
at
each
site.
Again,
these
proposed
changes
in
terminology
do
not
alter
our
technical
approach
to
verifying
compliance
during
an
inspection,
but
will
reflect
our
actual
practice
more
accurately.
1.
Why
Do
the
Existing
Provisions
in
§
194.24(
c)(
3)
Appear
Inappropriate?
We
do
not
consider
the
existing
provisions
in
§
194.24(
c)(
3)
to
be
fully
inappropriate
because
process
knowledge
remains
a
crucial
component
of
the
waste
characterization
system
of
controls.
However,
the
Agency
seeks
to
improve
communication
with
DOE
and
the
public
and
the
use
of
consistent
and
clear
language
is
an
important
factor
towards
meeting
that
goal.
Section
194.24(
c)(
3)
is
used
to
verify
compliance
in
the
collection
and
appropriate
use
of
process
knowledge
during
waste
characterization,
and
that
the
procedures
adhere
to
the
quality
assurance
requirements
identified
in
§
194.22.
During
the
EPA
inspection
of
a
TRU
waste
site,
we
review
the
establishment
and
implementation
of
procedures
for
collection
and
use
of
process
knowledge,
demonstration
of
waste
characterization
processes,
and
the
qualifications
and
practices
of
technical
personnel.
The
term
``
process
knowledge,
''
as
currently
used
by
EPA
in
the
Compliance
Criteria,
incorporates
information
about
the
process
or
operation
that
led
to
the
creation
of
the
transuranic
waste.
14
The
term
``
acceptable
knowledge''
includes
process
knowledge,
any
data
resulting
from
analysis
of
waste
prior
to
WIPP
waste
characterization,
and
any
other
information
about
the
physical
form
of
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/
Vol.
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154
/
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August
9,
2002
/
Proposed
Rules
the
waste
and
its
base
components.
The
two
terms
are
related;
process
knowledge
is
a
subset
of
acceptable
knowledge.
In
Chapter
4
of
the
Compliance
Certification
Application,
DOE
used
the
term
``
acceptable
knowledge''
and
explained
that
this
term
incorporates
``
information
regarding
the
physical
form
of
the
waste,
the
base
materials
composing
the
waste,
and
the
process
that
generates
the
waste.
''
DOE
derived
this
usage
from
an
EPA
document
entitled,
``
Waste
Analysis
at
Facilities
that
Generate,
Treat,
Store,
and
Dispose
of
Hazardous
Waste:
A
Guidance
Manual
(EPA530–
R–
94–
024,
April
1994.''
This
guidance
defines
AK
broadly
as
including
process
knowledge,
waste
analysis
data
from
waste
generators,
and
records
of
analysis
performed.
A
hazardous
waste
treatment,
storage,
and
disposal
facility
when
accepting
hazardous
waste
for
management
may
test
waste
to
confirm
that
the
hazardous
waste
determination
done
by
a
generator
is
accurate
and
the
facility
indeed
can
handle
that
particular
waste
type.
The
referenced
guidance
document
applies
specifically
to
compliance
with
the
Resource
Conservation
and
Recovery
Act;
however,
its
definition
of
AK
is
consistent
with
the
definition
that
we
are
proposing
for
use
in
the
WIPP
Compliance
Criteria.
It
is
important
that
both
EPA
and
DOE
have
the
same
understanding
on
the
terminology
applicable
to
the
requirements
in
§
194.24(
c)(
3).
The
use
of
the
term
``
process
knowledge''
in
the
Compliance
Criteria
to
date
has
not
interfered
with
DOE's
compliance
with
the
terms
and
conditions
of
the
certification.
However,
EPA
seeks
to
avoid
the
possibility
for
miscommunication
now
or
in
the
future.
2.
How
Do
the
Proposed
Changes
in
§
194.24(
c)(
3)
Comport
With
40
CFR
part
191?
The
proposed
changes
to
§
194.24(
c)(
3)
comport
fully
with
the
radioactive
waste
disposal
regulations
at
40
CFR
part
191.
The
inclusion
of
requirements
for
waste
characterization
requirements
in
order
to
implement
the
disposal
regulations
was
established
by
the
rulemaking
that
resulted
in
the
WIPP
Compliance
Criteria
at
40
CFR
part
194.
Today's
proposed
changes
do
not
alter
the
scope
of
those
requirements.
The
Compliance
Criteria
would
continue
to
apply
waste
characterization
requirements
to
the
WIPP
project.
The
principle
difference
between
the
existing
and
proposed
new
provisions
is
the
replacement
of
the
term
process
knowledge
with
acceptable
knowledge.
The
use
of
the
new
term
would
not
substantively
affect
the
Compliance
Criteria's
implementation
of
40
CFR
part
191.
3.
What
Are
the
Costs,
Risks,
and
Benefits
of
Compliance
with
the
New
Provisions
in
§
194.24(
c)(
3)?
We
do
not
anticipate
any
cost
increase
related
to
our
implementation
of
the
changes
to
§
194.24(
c)(
3).
EPA
will
continue
to
conduct
waste
characterization
oversight
in
the
same
manner
as
before.
Similarly,
we
do
not
anticipate
that
DOE
will
experience
any
cost
increase
as
a
result
of
their
compliance
activities
with
this
part.
Essentially,
DOE
will
continue
to
comply
with
the
requirement
of
this
part
as
they
previously
have.
We
do
not
anticipate
any
risks
related
to
the
implementation
of
the
proposed
revisions
to
this
part.
The
Agency
anticipates
that
the
use
of
the
term
acceptable
knowledge
will
serve
to
enhance
communication
with
the
regulated
party
and
therefore,
compliance
with
40
CFR
part
194.
The
benefits
of
the
proposed
revisions
for
§
194.24(
c)(
3)
are
two
fold.
First,
the
proposed
changes
will
not
affect
the
actual
technical
approach
to
verifying
compliance
during
our
independent
audits
and
inspections
of
the
relevant
WIPP
activities.
Therefore,
EPA
will
continue
to
enforce
the
waste
characterization
requirements
in
the
Compliance
Criteria
and
ensure
that
DOE's
waste
characterization
programs
are
properly
implemented.
Second,
the
clarification
of
the
applicable
terminology
will
ensure
that
no
confusion
arises
regarding
the
specific
waste
characterization
information
required
for
compliance.
VII.
Administrative
Requirements
A.
Executive
Order
12866
Under
Executive
Order
12866,
(58
FR
51735;
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
(4)
raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
it
has
been
determined
that
this
rule
is
not
a
``
significant
regulatory
action.
''
B.
Regulatory
Flexibility
Act
The
Regulatory
Flexibility
Act
(``
RFA'')
generally
requires
an
agency
to
conduct
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
not
for
profit
enterprises,
and
small
governmental
jurisdictions.
This
proposed
rule
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities
because
it
sets
forth
requirements
which
apply
only
to
Federal
agencies.
Therefore,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
C.
Paperwork
Reduction
Act
This
proposed
action
does
not
impose
an
information
collection
burden
under
the
provisions
of
the
Paper
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
The
Compliance
Criteria
in
40
CFR
part
194
requirements
are
applicable
only
to
both
DOE
and
EPA
and
do
not
establish
any
form
of
collection
of
information
from
the
public.
D.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(``
UMRA''),
Public
Law
104–
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Pursuant
to
Title
II
of
the
UMRA,
we
have
determined
that
this
regulatory
action
is
not
subject
to
the
requirements
of
sections
202
and
205,
because
this
action
does
not
contain
any
``
federal
mandates''
for
State,
local,
or
tribal
governments
or
for
the
private
sector.
This
rule
applies
only
to
Federal
agencies.
E.
Executive
Order
12898
Pursuant
to
Executive
Order
12898
(59
FR
7629,
February
16,
1994),
entitled
``
Federal
Actions
to
Address
Environmental
Justice
in
Minority
Populations
and
Low
Income
Populations,
''
the
Agency
has
considered
environmental
justice
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Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
related
issues
with
regard
to
the
potential
impacts
of
this
action
on
the
environmental
and
health
conditions
in
low
income,
minority,
and
native
American
communities.
We
have
complied
with
this
mandate.
However,
the
requirements
specifically
set
forth
by
the
Congress
in
the
Waste
Isolation
Pilot
Plant
Land
Withdrawal
Act
(Pub.
L.
102–
579),
which
prescribes
EPA's
role
at
the
WIPP,
did
not
provide
authority
for
EPA
to
examine
impacts
in
the
communities
in
which
wastes
are
produced,
stored,
and
transported,
and
Congress
did
not
delegate
to
EPA
the
authority
to
consider
the
issue
of
alternative
locations
for
the
WIPP.
During
the
development
of
the
existing
provisions
in
40
CFR
part
194,
the
EPA
involved
minority
and
lowincome
populations
early
in
the
rulemaking
process.
In
1993,
EPA
representatives
met
with
New
Mexico
residents
and
government
officials
to
identify
the
key
issues
that
concern
them,
the
types
of
information
they
wanted
from
EPA,
and
the
best
ways
to
communicate
with
different
sectors
of
the
New
Mexico
public.
The
feedback
provided
by
this
group
of
citizens
formed
the
basis
for
EPA's
WIPP
communications
and
consultation
plan.
To
help
citizens
(including
a
significant
Hispanic
population
in
Carlsbad
and
the
nearby
Mescalero
Indian
Reservation)
stay
abreast
of
EPA's
WIPP
related
activities,
the
Agency
developed
many
informational
products
and
services.
The
EPA
translated
into
Spanish
several
documents
regarding
WIPP,
including
educational
materials
and
fact
sheets
describing
EPA's
WIPP
oversight
role
and
the
radioactive
waste
disposal
standards.
The
EPA
also
established
a
toll
free
WIPP
Information
Line,
recorded
in
both
English
and
Spanish,
providing
the
latest
information
on
upcoming
public
meetings,
publications,
and
other
WIPP
related
activities.
The
EPA
also
developed
a
mailing
list,
which
includes
many
lowincome
minority,
and
native
American
groups,
to
systematically
provide
interested
parties
with
copies
of
EPA's
public
information
documents
and
other
materials.
Even
after
the
final
rule,
in
1998,
EPA
has
continued
to
implement
outreach
services
to
all
WIPP
communities
based
on
the
needs
determined
during
the
certification.
This
proposed
action
does
not
add
or
delete
any
certification
criteria.
The
proposal
would
revise
the
public
notice
process
for
the
approval
of
waste
characterization
activities
at
DOE
waste
generator
sites,
which
produce
and
store
wastes
destined
for
disposal
at
WIPP.
Affected
communities
and
the
public
in
general
would
have
the
opportunity
to
comment
on
EPA's
proposed
waste
generator
site
approval
decision.
The
existing
provision
does
not
offer
such
opportunity.
The
proposed
revision
makes
the
public
comment
period
more
meaningful
to
all
communities.
The
Agency
also
intends
to
continue
its
outreach
activities
to
make
information
on
waste
characterization
activities
more
accessible
by
using
the
Internet,
EPA
information
line,
and
fact
sheets.
F.
National
Technology
Transfer
&
Advancement
Act
of
1995
Section
12
of
the
National
Technology
Transfer
&
Advancement
Act
of
1995
is
intended
to
avoid
``
re
inventing
the
wheel.
''
It
aims
to
reduce
costs
to
the
private
and
public
sectors
by
requiring
federal
agencies
to
draw
upon
any
existing,
suitable
technical
standards
used
in
commerce
or
industry.
To
comply
with
the
Act,
EPA
must
consider
and
use
``
voluntary
consensus
standards,
''
if
available
and
applicable,
when
implementing
policies
and
programs,
unless
doing
so
would
be
``
inconsistent
with
applicable
law
or
otherwise
impractical.
''
We
have
determined
that
this
regulatory
action
is
not
subject
to
the
requirements
of
National
Technology
Transfer
&
Advancement
Act
of
1995
as
this
rulemaking
is
not
setting
any
technical
standards.
G.
Executive
Order
13045:
Children's
Health
Protection
This
rule
is
not
subject
to
Executive
Order
13045,
entitled
``
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks''
(62
FR
19885,
April
23,
1997),
because
it
does
not
involve
decisions
on
environmental
health
risks
or
safety
risks
that
may
disproportionately
affect
children.
H.
Executive
Order
13132:
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.
''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.
''
This
proposed
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
This
proposed
action
revises
specific
portions
of
the
Compliance
Criteria
in
40
CFR
part
194.
These
criteria
are
applicable
only
to
both
DOE
(operator)
and
EPA
(regulator)
of
the
WIPP
disposal
facility.
Thus,
Executive
Order
13132
does
not
apply
to
this
rule.
In
the
spirit
of
Executive
Order
13132,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
State
and
local
governments,
EPA
specifically
solicits
comment
on
this
proposed
rule
from
State
and
local
officials.
I.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(65
FR
67249,
November
9,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.
''
This
proposed
rule
does
not
have
tribal
implications,
as
specified
in
Executive
Order
13175.
This
proposed
action
revises
specific
portions
of
the
Compliance
Criteria
in
40
CFR
part
194.
The
Compliance
Criteria
are
applicable
only
to
Federal
agencies.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.
In
the
spirit
of
Executive
Order
13175,
and
consistent
with
EPA
policy
to
promote
consultation
and
coordination
with
Indian
Tribal
Governments,
EPA
specifically
solicits
comment
on
this
proposed
rule
from
Tribal
officials.
J.
Executive
Order
13211:
Energy
Effects
This
proposed
rule
is
not
subject
to
Executive
Order
13211,
``
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(66
FR
28355
(May
22,
2001))
because
it
is
not
a
significant
regulatory
action
under
Executive
Order
12866.
List
of
Subjects
in
40
CFR
Part
194
Environmental
protection,
Administrative
practice
and
procedure,
Nuclear
materials,
Radionuclides,
Plutonium,
Radiation
Protection,
Uranium,
Transuranics,
Waste
Treatment
and
Disposal.
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Federal
Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
Dated:
July
30,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
set
out
in
the
preamble,
40
CFR
Part
194
is
proposed
to
be
amended
as
follows.
PART
194—
CRITERIA
FOR
THE
CERTIFICATION
AND
RECERTIFICATION
OF
THE
WASTE
ISOLATION
PILOT
PLANT'S
COMPLIANCE
WITH
THE
40
CFR
PART
191
DISPOSAL
REGULATIONS
1.
The
authority
citation
for
Part
194
continues
to
read
as
follows:
Authority:
Pub.
L.
102–
579,
106
Stat.
4777,
as
amended
by
Public
Law
104–
201,
110
Stat.
2422;
Reorganization
Plan
No.
3
of
1970,
35
FR
15623,
Oct.
6,
1970,
5
U.
S.
C.
app.
1;
Atomic
Energy
Act
of
1954,
as
amended,
42
U.
S.
C.
2011–
2296
and
10101–
10270.
2.
Section
194.2,
is
amended
by
adding
definitions
in
alphabetical
order
for
``
acceptable
knowledge''
and
``
minor
alternative
provision''
to
read
as
follows:
§
194.2
Definitions.
*
*
*
*
*
Acceptable
knowledge
means
any
information
about
the
process
used
to
generate
waste,
material
inputs
to
the
process,
and
the
time
period
during
which
the
waste
was
generated,
as
well
as
data
resulting
from
the
analysis
of
waste,
conducted
prior
to
or
separate
from
the
waste
certification
process
authorized
by
EPA's
Certification
Decision,
to
show
compliance
with
Condition
3
of
the
certification
decision
(Appendix
A
of
this
part).
*
*
*
*
*
Minor
alternative
provision
means
an
alternative
provision
to
the
Compliance
Criteria
that
clarifies
a
regulatory
provision,
or
does
not
substantively
alter
the
existing
regulatory
requirements.
*
*
*
*
*
3.
Section
194.6
is
revised
to
read
as
follows:
§
194.6
Alternative
provisions.
The
Administrator
may,
by
rule
pursuant
to
5
U.
S.
C.
553,
substitute
for
any
of
the
provisions
of
this
part
alternative
provisions,
or
minor
alternative
provisions,
in
accordance
with
the
following
procedures:
(a)
Alternative
provisions
may
be
substituted
after:
(1)
Alternative
provisions
have
been
proposed
for
public
comment
in
the
Federal
Register
together
with
information
describing
how
the
alternative
provisions
comport
with
the
disposal
regulations,
the
reasons
why
the
existing
provisions
of
this
part
appear
inappropriate,
and
the
costs,
risks
and
benefits
of
compliance
in
accordance
with
the
alternative
provisions;
(2)
A
public
comment
period
of
at
least
120
days
has
been
completed
and
public
hearings
have
been
held
in
New
Mexico;
(3)
The
public
comments
received
have
been
fully
considered;
and
(4)
A
notice
of
final
rulemaking
is
published
in
the
Federal
Register.
(b)
Minor
alternative
provisions
may
be
substituted
after:
(1)
The
minor
alternative
provisions
have
been
proposed
for
public
comment
in
the
Federal
Register
together
with
information
describing
how
they
comport
with
the
disposal
regulations,
the
reasons
why
the
existing
provisions
of
this
part
appear
inappropriate,
and
the
benefit
of
compliance
in
accordance
with
the
minor
alternative
provision;
(2)
A
public
comment
period
of
at
least
30
days
has
been
completed
for
the
minor
alternative
provisions
and
the
public
comments
received
have
been
fully
considered;
(3)
A
notice
of
final
rulemaking
is
published
in
the
Federal
Register
for
the
minor
alternative
provisions.
4.
Section
194.8
is
amended
by
revising
paragraph
(b)
to
read
as
follows:
§
194.8
Approval
process
for
waste
shipment
from
waste
generator
sites
for
disposal
at
the
WIPP.
*
*
*
*
*
(b)
Waste
Characterization
Programs
at
Transuranic
Waste
Sites.
The
Agency
will
establish
compliance
with
Condition
3
of
the
certification
using
the
following
process.
(1)
DOE
will
implement
waste
characterization
programs
and
processes
in
accordance
with
§
194.24(
c)(
4)
to
confirm
that
the
total
amount
of
each
waste
component
that
will
be
emplaced
in
the
disposal
system
will
not
exceed
the
upper
limiting
value
or
fall
below
the
lower
limiting
value
described
in
the
introductory
text
of
paragraph
(c)
of
§
194.24.
Waste
characterization
processes
will
include
the
collection
and
use
of
acceptable
knowledge;
destructive
and/
or
nondestructive
techniques
for
identifying
and
measuring
waste
components;
and
the
validation,
control,
and
transmittal
to
the
WIPP
Waste
Information
System
database
of
waste
characterization
data,
in
accordance
with
§
194.24(
c)(
4).
(2)
The
Agency
will
verify
the
compliance
of
waste
characterization
programs
and
processes
identified
in
paragraph
(b)(
1)
of
this
section
using
the
following
process.
(i)
DOE
will
notify
EPA
by
letter
that
a
transuranic
waste
site
is
prepared
to
ship
waste
to
the
WIPP
and
has
established
adequate
waste
characterization
processes
and
programs.
DOE
also
will
provide
the
relevant
waste
characterization
program
plans
and
documentation.
EPA
may
request
additional
information
from
DOE.
(ii)
EPA
will
conduct
a
baseline
inspection
at
the
site
to
verify
that
adequate
waste
characterization
program
plans
and
technical
procedures
have
been
established,
and
that
those
plans
and
procedures
are
effectively
implemented.
The
inspection
will
include
a
demonstration
or
test
by
the
site
of
the
waste
characterization
processes
identified
in
paragraph
(b)(
1)
of
this
section.
If
an
inspection
does
not
lead
to
approval,
we
will
a
send
an
inspection
report
to
DOE
identifying
deficiencies
and
place
the
report
in
the
public
docket
described
in
§
194.67.
More
than
one
inspection
may
be
necessary
to
resolve
compliance
issues.
(iii)
The
Agency
will
announce
in
the
Federal
Register
a
proposed
Baseline
Compliance
Decision
to
accept
the
site's
compliance
with
§
194.24(
c)(
4).
In
the
notice,
we
will
solicit
public
comment
on
the
relevant
inspection
report(
s)
and
any
supporting
materials,
which
will
be
placed
in
the
public
docket
described
in
§
194.67.
The
proposal
will
describe
any
limitations
on
approved
waste
streams
or
waste
characterization
processes
and
identify
(through
tier
designations)
what
changes
to
the
approved
waste
characterization
processes
must
be
reported
to
and
approved
by
EPA
before
they
can
be
implemented.
(iv)
Our
written
decision
regarding
compliance
with
the
requirements
for
waste
characterization
programs
and
processes
described
in
paragraph
(b)(
1)
of
this
section
will
be
conveyed
in
a
letter
from
the
Administrator's
authorized
representative
to
DOE.
EPA
will
not
issue
a
compliance
decision
until
after
the
end
of
the
public
comment
period
described
in
paragraph
(b)(
2)(
iii)
of
this
section.
EPA's
compliance
decision
will
respond
to
significant
and
timely
received
comments.
A
copy
of
our
compliance
decision
will
be
placed
in
the
public
docket
described
in
§
194.67.
DOE
will
comply
with
any
requirements
identified
in
the
compliance
decision
and
the
accompanying
inspection
report.
(3)
Subsequent
to
any
positive
determination
of
compliance
as
described
in
paragraph
(b)(
2)(
iv)
of
this
section,
the
Agency
intends
to
conduct
inspections,
in
accordance
with
§
194.24(
h),
to
confirm
the
continued
compliance
of
approved
waste
characterization
programs
and
processes
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51946
Federal
Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
at
transuranic
waste
sites.
EPA
will
make
the
results
of
these
inspections
available
to
the
public
in
the
dockets
described
in
§
194.67.
(i)
If
the
Agency
determines,
at
a
subsequent
inspection
of
an
approved
transuranic
waste
site,
that
waste
characterization
programs
or
processes
are
not
adequately
established
or
implemented,
then
we
may
suspend
shipments
and
disposal
of
affected
and
potentially
affected
waste
streams,
or
take
other
action
in
accordance
with
§
194.4(
b)(
1)
and
(2),
until
we
determine
that
the
deficiencies
have
been
adequately
resolved.
(ii)
[Reserved]
5.
Section
194.12
is
revised
to
read
as
follows:
§
194.12
Submission
of
compliance
applications.
Unless
otherwise
specified
by
the
Administrator
or
the
Administrator's
authorized
representative,
5
copies
of
any
compliance
application(
s),
any
accompanying
materials,
and
any
amendments
thereto
shall
be
submitted
in
a
printed
form
to
the
Administrator's
authorized
representative.
In
addition,
DOE
shall
submit
10
copies
of
the
complete
application
in
alternative
format
(e.
g.,
compact
disk)
or
other
approved
format,
as
specified
by
the
Administrator's
authorized
representative.
6.
Section
194.13
is
revised
to
read
as
follows:
§
194.13
Submission
of
reference
materials.
Information
may
be
included
by
reference
into
compliance
applications(
s),
provided
that
the
references
are
clear
specific
and
that
unless,
otherwise
specified
by
the
Administrator
or
the
Administrator's
authorized
representative,
5
copies
of
reference
information
are
submitted
to
the
Administrator's
authorized
representative.
Reference
materials
that
are
widely
available
in
standard
text
books
or
reference
books
need
not
to
be
submitted.
Whenever
possible,
DOE
shall
submit
10
copies
of
reference
materials
in
alternative
format
(e.
g.,
compact
disk)
or
other
approved
format,
as
specified
by
the
Administrator's
authorized
representative.
7.
Section
194.24
is
amended
by
revising
paragraph
(c)(
3)
to
read
as
follows:
§
194.24
Waste
characterization.
*
*
*
*
*
(c)
*
*
*
(3)
Provide
information
that
demonstrates
that
the
use
of
acceptable
knowledge
to
quantify
components
in
waste
for
disposal
conforms
with
the
quality
assurance
requirements
of
§
194.22.
*
*
*
*
*
[FR
Doc.
02–
19796
Filed
8–
8–
02;
8:
45
am]
BILLING
CODE
6560–
50–
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| epa | 2024-06-07T20:31:39.791493 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0005-0003/content.txt"
} |
EPA-HQ-OAR-2002-0007-0001 | Supporting & Related Material | "2002-07-23T04:00:00" | null | Docket
NO:
OAR
2002
0005
0001
Criteria
for
the
Certification
and
Recertification
of
the
Waste
Isolation
Pilot
Plant's
Compliance
with
the
Disposal
Regulations;
Alternative
Provisions
Background
Information
Document
for
Amendments
to
40
CFR
194.8
(b)
U.
S.
Environmental
Protection
Agency
Office
of
Radiation
and
Indoor
Air
Washington,
DC
20460
July
2002
TABLE
OF
CONTENTS
I.
INTRODUCTION
........................................................
1
A.
CurrentProvisionsandSummaryofPertinentElements.......................
1
B.
WasteComponentsandWasteDescriptions
...............................
2
B.
1RadiologicalWasteComponents
.................................
3
B.
2Non
RadiologicalWasteComponents
.............................
5
B.
3GeneralWasteDescriptions
.....................................
5
C.
DescriptionofWasteGenerators
.......................................
6
D.
CurrentInspectionProcess
............................................
8
II.
DESCRIPTIONOFTECHNICALELEMENTSEXAMINED
.....................
12
DURING
INSPECTIONS
A.
Acceptable
Knowledge
..............................................
13
A.
1.
OverviewofTechnicalElements................................
13
A.
2.
TechnicalDescriptionofSystemor
MeasurementDevice(
s)
...........
14
A.
3.
EffectofWasteMatrixTypeonMeasurement
.....................
17
A.
4.
Scope
of
Possible
EPA
Approvals
for
Acceptable
Knowledge
..........
17
B.
NondestructiveAssay(
NDA)
.........................................
18
B.
1OverviewofTechnicalElements
................................
18
B.
2:
TechnicalDescriptionofSystemor
MeasurementDevice(
s)
...........
19
B.
2.1
General
System
Information
............................
19
B.
2.2
Neutron
Systems
.....................................
21
B.
2.3
Passive
Active
Neutron
Counters
.........................
23
B.
2.4
Photon
Emission
and
NDA
.............................
23
B.
2.5
Gamma
Ray
Spectrometry
Systems
.......................
25
B.
2.6
Calorimetry
Instruments
...............................
25
B.
3:
EffectofWasteMatrixor
WasteTypeonMeasurement
..............
25
B.
3.1
Neutron
Counting
Systems
..............................
26
B.
3.2
Photon
Measuring
Systems
.............................
27
B.
4ScopeofPossibleEPAApprovalsforNondestructiveAssay
...........
27
C.
VisualExaminationandRadiography
...................................
28
C.
1
OverviewofTechnicalElements
................................
29
C.
1.1
RTR
Document
Review
................................
29
C.
1.2
Additional
Verification
RTR
............................
31
C.
1.3
VE
Document
Review
.................................
33
C.
1.4
Additional
Verification
VE
.............................
35
C.
2
TechnicalDescriptionofSystemor
MeasurementDevice(
s)...........
37
C.
2.1
Radiography
........................................
37
C.
2.2
Visual
Examination
..................................
38
C.
3
EffectofWasteMatrixor
WasteTypeonMeasurement..............
39
C.
4
ScopeofPossibleEPAApprovalsforRadiographyandVisualExam....
39
D.
WIPPWasteInformationSystemandDataValidation
......................
40
D.
1
OverviewofTechnicalElements................................
40
D.
1.1
Data
Validation/
Verification
and
WWIS
Inspection
Components
41
D.
1.2
Demonstration
of
WWIS
Implementation
..................
42
D.
1.3
Personnel
Qualifications
..............................
42
D.
2
TechnicalDescriptionofMeasurementDevice
.....................
43
D.
3
EffectofWasteMatrixor
WasteTypeonMeasurement
..............
43
D.
4
Scope
of
EPA
Approvals
for
Data
Validation/
Verification
and
the
WWIS
.
44
III.
SUMMARY
OF
RESULTS
AND
LESSONS
LEARNED
........................
45
A.
SummaryofResults
................................................
45
B.
LessonsLearned
...................................................
50
IV.
SUMMARYOFPUBLICCOMMENTSONEPAINSPECTIONS.................
52
V.
CONCLUSIONS........................................................
56
REFERENCES
............................................................
57
ACRONYM
LIST
A&
PCT
Active
and
Passive
Computed
Tomography
AK
Acceptable
Knowledge
Am
Americium
APNEA
Active
and
Passive
Neutron
Examination
and
Assay
ASME
American
Society
of
Mechanical
Engineers
BID
Background
Information
Document
BIR
Baseline
Inventory
Report
CA
Compliance
Assessment
CAO
U.
S.
Department
of
Energy
Carlsbad
Area
Office
(now
the
Carlsbad
Field
Office)
CAR
Corrective
Action
Report
CBFO
U.
S.
Department
of
Energy
Carlsbad
Field
Office
CCA
Compliance
Certification
Application
CCD
Charge
Collection
Device
CCP
Centralized
Characterization
Project
Cf
Californium
CH
TRU
Contact
Handled
Transuranic
Waste
Cm
Curium
CPR
cellulosics,
plastics,
rubber
Cs
Cesium
CT
Computed
Tomography
DOE
U.
S.
Department
of
Energy
DR
Digital
Radiography
DTP
Detailed
Technical
Procedure
EEG
Environmental
Evaluation
Group
eV
Electron
Volt
FRAM
Fixed
Energy
Response
Function
Analysis
with
Multiple
Efficiencies
FY
Fiscal
Year
GEA
Gamma
Energy
Assay
2
H
Deuterium
3
H
Tritium
HANDSS
55
Handling
and
Segregating
System
He
Helium
HENC
High
Efficiency
Neutron
Counter
HPGe
High
Purity
Germanium
IDC
Item
Description
Code
INEEL
Idaho
National
Engineering
and
Environmental
Laboratory
IPAN
Imaging
Passive
Active
Neutron
Counter
KV
Kilovolt
kVp
kilovolts
peak
LANL
Los
Alamos
National
Laboratory
LDA
Linear
Diode
Array
LLNL
Lawrence
Livermore
National
Laboratory
MCS
Mobile
Characterization
Services
msec
Millisecond
NCR
Nonconformance
Reports
NDA
Nondestructive
Assay
NDE
Nondestructive
Evaluation
NMC
Neutron
Multiplicity
Counters
NMED
New
Mexico
Environment
Department
Np
Neptunium
NQA
Nuclear
Quality
Assurance
NRC
U.
S.
Nuclear
Regulatory
Commission
NTS
Nevada
Test
Site
OJT
On
The
Job
Training
ORIA
EPA
Office
of
Radiation
and
Indoor
Air
PA
Performance
Assessment
PADC
Passive
Active
Drum
Counter
PAN
Passive
Active
Neutron
PCB
polychlorinated
biphenyls
PDP
Performance
Demonstration
Program
Pu
Plutonium
QA
Quality
Assurance
QAPjP
Quality
Assurance
Project
Plan
QAPP
Quality
Assurance
Program
Plan
QC
Quality
Control
RCRA
Resource
Conservation
and
Recovery
Act
of
1976
RFETS
Rocky
Flats
Environmental
Technology
Site
RH
TRU
Remote
Handled
Transuranic
Waste
RTG
Radioisotopic
Thermal
Generators
RTR
Real
Time
Radiography
SGS
Segmented
Gamma
Scanner
SGSAS
Segmented
Gamma
Scanner
Assay
System
SOP
Standard
Operating
Procedures
Sr
Strontium
SRIC
Southwest
Research
and
Information
Center
SRS
Savannah
River
Site
SWEPP
SGRS
Stored
Waste
Examination
Pilot
Plant
Gamma
Ray
Spectrometer
SWEPP
PAN
Stored
Waste
Examination
Pilot
Plant
Passive
Active
Neutron
Counter
TGS
Tomographic
Gamma
Scanners
TGS
CAN
Tomographic
Gamma
Can
Scanners
TMFA
Transuranic
and
Mixed
Waste
Focus
Area
TRU
Transuranic
TRUCON
Transuranic
Package
Transporter
II
Content
Codes
TSDF
Treatment,
Storage,
Disposal,
Recycling
Facilities
TWBIR
Transuranic
Waste
Baseline
Inventory
Report
U
Uranium
UCL90
Upper
90
Percent
Confidence
Limit
V
Volt
VE
Visual
Examination
VEE
VE
Expert
WAC
Waste
Acceptance
Criteria
WAGS
Waste
Assay
Gamma
Spectrometer
WAP
Waste
Analysis
Plan
WIPP
Waste
Isolation
Pilot
Plant
WMC
Waste
Matrix
Code
WMP
Waste
Material
Parameters
WWIS
WIPP
Waste
Information
System
1
I.
INTRODUCTION
The
purpose
of
this
Background
Information
Document
(BID)
is
to
explain
the
Agency's
Waste
Isolation
Pilot
Plant
(WIPP)
transuranic
(TRU)
waste
generator
inspection
process
in
support
of
alternative
provisions
for
40
CFR
Part
194.8,
"Approval
Process
for
Waste
Shipment
from
Waste
Generator
Sites
for
Disposal
at
the
WIPP."
Specifically,
the
Agency
is
proposing
to
revise
section
194.8(
b).
This
document
presents:
I.
The
current
regulatory
provisions
and
the
basis
for
inspections,
a
summary
of
wastes
that
require
inspection,
and
an
overview
of
the
current
inspection
approach.
II.
A
summary
discussion
of
the
major
technical
elements
examined
during
waste
characterization
inspections
at
generator
sites,
including
acceptable
knowledge
(AK),
nondestructive
assay
(NDA),
radiography
(such
as
real
time
radiography,
or
RTR),
visual
examination
(VE),
and
data
validation/
data
transfer
(via
the
WIPP
Waste
Information
System,
or
WWIS).
These
discussions
present
what
inspectors
examined
and
how
the
results
impact
EPA's
assessment
of
the
waste
characterization
process.
Technical
descriptions
of
measurement
and
examination
devices
are
included,
as
well
as
discussion
of
the
impact
of
different
waste
matrices
on
the
effectiveness
of
the
measuring
or
examination
device,
and
the
range
of
waste
types
that
the
Agency
may
be
able
to
approve
inthe
course
ofaninspection.
III.
A
summary
of
results
and
general
conclusions
reached
by
Agency
inspectors
from
May
1998
through
the
present.
This
section
identifies
the
number,
scope,
and
results
of
technical
inspections
at
the
generator/
storage
sites.
IV.
Examples
of
public
comments
on
inspection
notices
and
docketed
materials.
V.
Conclusions.
I.
A
Current
Provisions
and
Summary
of
Pertinent
Elements
As
specified
in
§194.24(
b)(
2)
of
the
Compliance
Criteria,
the
U.
S.
Department
of
Energy
(DOE)
was
required
to
conduct
an
analysis
to
identify
waste
components
important
to
performance
assessment
(PA).
Section
194.24(
c)
deals
with
the
identification
of
waste
limits
associated
with
these
critical
components,
as
well
as
how
the
limits
are
included
in
performance
assessments
(§
194.32)
and
compliance
assessments
(§
194.54).
In
addition,
DOE
must
specify
how
waste
components
will
be
identified,
quantified,
tracked,
and
controlled.
Important
components
are
summarized
in
Section
I.
B
of
this
BID.
Waste
characterization,
as
defined
in
§194.24(
c),
is
necessary
to
ensure
that
waste
2
emplaced
in
the
repository
is
consistent
with
the
parameters
established
in
the
performance
assessment
(§
194.32)
and
compliance
assessment
(§
194.54),
and
that
limitations
(or
constraints)
on
radionuclides
and
other
waste
components
established
by
EPA's
certification
decisions
are
not
exceeded.
Waste
characterization
is
also
used
to
ensure
that
the
actual
waste
inventory
is
consistent
with
the
waste
inventory
estimates
presented
in
DOE's
Baseline
Inventory
Report
(BIR),
which
was
used
in
performance
and
compliance
assessment
(PA
and
CA)
calculations.
Waste
characterization
activities
performed
by
DOE
to
demonstrate
compliance
with
§194.24(
c)
include
a
"system
of
controls,"
involving
characterization
techniques
as
well
as
waste
tracking
and
WIPP
inventory
identification
and
management.
In
the
WIPP
certification
rulemaking,
EPA
evaluated
waste
characterization
information
provided
by
DOE
in
its
Compliance
Certification
Application
(CCA)
and
amended
the
Compliance
Criteria
by
adding
section
194.8.
Section
194.8
specifies
the
waste
characterization
approval
process
for
DOE
waste
generator
sites.
Condition
3
of
the
certification
provides
that
DOE
may
not
ship
waste
to
the
WIPP
from
any
waste
stream
other
than
wastes
from
specified
waste
streams
until
EPA
has
approved
processes
for
characterizing
such
waste
streams
in
accordance
with
the
section
194.8
approval
process.
Section
194.8(
b)
requires
that,
"[
f]
or
each
waste
stream
or
group
of
waste
streams
at
a
site
proposed
for
disposal
at
WIPP,"
DOE
must
provide
information
on
how
process
knowledge
will
be
used
for
waste
characterization
of
the
waste
stream(
s),
and
must
implement
a
system
of
controls
at
the
site,
in
accordance
with
§194.24(
c)(
4).
Section
194.8(
b)
also
states
that
EPA
will
conduct
an
"...
aninspectionofa
Department
audit
for
the
purpose
of
evaluating
the
use
of
process
knowledge
and
the
implementation
of
a
system
of
controls
for
each
waste
stream
or
group
of
waste
streams
at
a
waste
generator
site."
Moreover,
DOE
must
demonstrate
that
each
site
has
procedures
in
place
to
communicate
with
DOE's
WIPP
Waste
Information
System
(WWIS).
The
WWIS
is
an
electronic
database
that
contains
information
related
to
the
characterization,
certification,
shipment,
and
emplacement
of
TRU
waste
at
the
WIPP.
In
accordance
with
section
194.8,
EPA
must
announce
scheduled
inspections
in
the
Federal
Register,
place
relevant
DOE
documents
in
the
docket,
and
solicit
public
comment
on
those
documents
for
at
least
30
days.
EPA
also
must
provide
written
audit
or
inspection
decisions
and
place
these
decisions
in
the
public
dockets.
Section
194.8
also
provides
that
subsequent
to
any
positive
determination
of
compliance
under
this
approval
process,
EPA
intends
to
conduct
inspections,
in
accordance
with
§194.21
and
§194.24(
h),
to
confirm
the
continued
compliance
of
the
programs
approved.
The
results
of
such
inspections
are
made
available
to
the
public
through
the
Agency's
public
dockets,
as
described
in
§194.67.
I.
B
Waste
Components
and
Waste
Descriptions
As
required
by
§
194.24(
b)(
2)
and
§
194.24(
c),
DOE
identified
the
waste
components
that
were
expected
to
have
a
significant
effect
on
disposal
system
performance
and
the
emplacement
3
limits
for
these
components
in
Chapter
4
(Table
4
10)
of
the
Compliance
Certification
Application
and
in
Appendices
WCA
and
WCL
(Docket
A
93
02,
Item
II
G
1,
Volume
XIX).
DOE
must
determine
the
quantities
of
these
components
in
TRU
waste
containers.
Based
on
DOE's
analysis,
EPA
regulates
the
waste
components
discussed
below.
I.
B.
1
Radiological
Waste
Components
As
discussed
in
Section
24.A.
6
of
CARD
24
(Docket
A
93
02,
Item
V
B
2),
EPA
concluded
that
DOE
appropriately
identified
ten
isotopes
most
significant
to
the
PA,
which
EPA
listed
as
241
Am,
244
Cm,
137
Cs,
238
Pu,
239
Pu,
240
Pu,
241
Pu,
90
Sr,
233
U,
and
234
U
(the
cesium
and
strontium
isotopes
and
233
U
are
important
to
remote
handled
TRU
waste).
These
ten
isotopes
significant
to
PA
comprise
about
99
percent
of
the
EPA
units
anticipated
within
the
WIPP
waste
inventory.
CARD
31,
Application
of
Release
Limits,
contains
an
explanation
of
EPA
units
for
radioisotopes
(Docket
A
93
02,
Item
V
B
2).
EPA
determined
that
about
90
percent
of
the
total
anticipated
inventory
of
6.
55
x
10
6
curies
at
closure
is
expected
to
be
contributed
by
the
following
seven
isotopes:
241
Am,
238
Pu,
239
Pu,
240
Pu,
241
Pu,
244
Cm,
and
234
U
(Figure
1).
See
alsoEPA's
Technical
Support
Document
for
Section
194.24:
Consolidated
Technical
Support
Document
–
Compliance
Certification
Review
of
Waste
Characterization
Requirements
(Docket
A
93
02,
Item
V
B
15).
DOE
identified
the
following
ten
radionuclides
in
Appendix
WCL
(Docket
A
93
02,
Item
II
G
,Volume
XIX)
as
subject
to
identification
and
quantification:
°
238
Pu,
239
Pu,
240
Pu,
and
242
Pu;
°
241
Am;
°
233
U,
234
U,
and
238
U;
°
90
Sr;
and
°
137
Cs.
EPA
examines
tracking
of
the
Appendix
WCL
list
during
inspections
because
the
amount
of
241
Pu
and
244
Cm
may
be
derived
from
measurements
of
isotopes
on
the
WCL
list.
DOE
must
track
these
isotopes
against
the
inventory
estimates
used
in
the
performance
assessment
(the
inventory
estimates
are
listed
in
CARD
31,
Table
3).
As
stated
in
Appendix
WCL,
"[
T]
he
performance
assessment
is
sensitive
to
relative
changes
in
inventory
curie
content
as
a
function
of
radionuclide
decay
and
ingrowth
over
time.
The
magnitude
of
change
in
the
total
curie
content
depends
on
the
initial
ratios
of
the
total
activities
of
the
assayed
radionuclides
at
the
time
of
repository
closure.
Accordingly,
the
results
of
the
performance
assessment
analysis
are
conditional
on
the
ratios
assumed.
.
.."
Consequently,
the
inventory
estimates
upon
which
EPA's
initial
certification
is
based
function
as
constraints
on
the
amount
of
the
key
isotopes
that
may
be
disposed
in
the
WIPP.
Changes
to
the
inventory
estimates
would
necessitate
further
analysis
by
DOE
of
the
effect(
s)
on
the
performance
assessment,
and
perhaps,
a
modification
of
the
certification.
4
Pu
240
2.89%
U
234
0.01%
All
Others
11.
93%
Cm
244
0.43%
Am
241
6.02%
Pu
239
10.
69%
Pu
241
32.
94%
Pu
238
35.
09%
Figure
1.
Percentage
of
Total
Inventory
Contributed
by
PA
Significant
Isotopes
(Curies)
Source:
EPA
Technical
Support
Document
for
Section
194.24
(Air
Docket
A
93
02,
Item
V
B
15,
Section
4.2.3)
5
I.
B.
2
Non
Radiological
Waste
Components
In
addition,
DOE
identified
other
waste
components
that
were
expected
to
have
a
significant
effect
on
disposal
system
performance
and
which
require
limits
(Appendix
WCL,
Table
WCL
1).
The
non
radiological
waste
components
with
limiting
values
are:
°
Ferrous
metals
(iron):
minimum
of
2x10
7
kilograms;
°
Cellulosics/
plastic/
rubber:
maximum
of
2x10
7
kilograms;
°
Free
water
emplaced
with
waste:
maximum
of
1684
cubic
meters;
and
°
Nonferrous
metals
(metals
other
than
iron):
minimum
of
2x10
3
kilograms
I.
B.
3
General
Waste
Descriptions
EPA
examines
general
waste
descriptions
prepared
by
DOE
sites
to
understand
how
radiological/
non
radiological
components
are
grouped
and
assessed.
Wastes
can
be
assigned
waste
material
parameters
that
encompass
those
components
with
limiting
values
identified
by
DOE.
The
DOE
identified
(Appendix
BIR
of
the
CCA)
the
following
12
different
waste
material
parameters
and
3
different
contents
packaging
materials
which
are
tracked
by
sites
and
which
allows
quantification
of
non
radionuclide
waste
components:
Waste
Material
Parameters
°
Iron
base
metal/
alloys
°
Aluminum
base
metal/
alloys
°
Other
metal/
alloys
°
Other
inorganic
materials
°
Vitrified
materials
°
Cellulosics
°
Rubber
°
Plastics
°
Solidified
inorganic
materials
°
Solidified
organic
materials
°
Cement
(solidified)
°
Soils
Contents
Packaging
Materials
°
Steel
°
Plastic
°
Lead
(for
RH
TRU
waste
only)
6
Waste
generator
sites
typically
group
waste
by
"waste
streams,"
which
are
defined
as
"...
wastematerialgeneratedfromasingleprocessor
fromanactivitythatissimilar
in
material,
physical
form,
and
hazardous
constituents"
(Appendix
WAP).
Waste
streams
are
not
defined
by
their
radionuclide
content,
but
instead
are
grouped
by
chemical,
physical,
and
process
similarities.
The
Transuranic
Waste
Baseline
Inventory
Report
(TWBIR,
Appendix
BIR)
identified
569
different
waste
streams
that
will
be
emplaced
in
the
repository.
These
wastes
are
also
be
categorized
into
broader
Summary
Waste
Category
Groups,
defined
as
S5000
(debris),
S4000
(soil/
gravel),
and
S3000
(solidified)
waste.
Generator
sites
tend
to
group
waste
by
Summary
Waste
Category
Group
for
inspection
purposes.
I.
C
Description
of
Waste
Generators
The
wastes
to
be
emplaced
in
the
WIPP
originate
from
generator/
storage
sites
within
the
DOE
Weapons
Complex
and
National
Laboratories.
Waste
must
be
defense
related
TRU
waste,
and
the
range
of
wastes
at
each
generator/
storage
site
is
dependent
upon
the
site's
past
and
current
missions.
The
generator/
storage
sites
and
the
volumes
of
contact
handled
TRU
CHTRU
and
RH
TRU
waste
expected
are
identified
in
Table
1.
7
Table
1
Anticipated
Waste
Volumes
for
Disposal
at
WIPP
Storage
Generator
Site
Anticipated
CH
TRU
Waste
(cubic
meters)
Anticipated
RH
TRU
Waste
(cubic
meters)
Ames
Laboratory
0.
42
None
Reported
Argonne
National
Laboratory
East
140
None
Reported
Argonne
National
Laboratory
West
750
1,
300
Battelle
Columbus
Laboratories
None
Reported
580
Bettis
Atomic
Power
Laboratory
120
6.
7
Energy
Technology
Engineering
Center
1.
7
0.
89
Hanford
Site*
46,000
22,000
INEEL*
29,
000
220
Lawrence
Livermore
National
Laboratory*
940
None
Reported
LANL*
18,000
190
Mound
Plant
270
None
Reported
Nevada
Test
Site*
630
None
Reported
Oak
Ridge
National
Laboratory*
1600
2,900
Paducah
Gaseous
Diffusion
Plant
1.
9
None
Reported
Pantex
Plant
0.
62
None
Reported
RFETS*
5,
100
None
Reported
Sandia
National
Laboratory
14
None
Reported
Savannah
River
Site*
9,
600
None
Reported
Teledyne
Brown
Engineering
0.
21
None
Reported
U.
S.
Army
Material
Command
2.
5
None
Reported
University
of
Missouri
Research
Center
1.
0
None
Reported
Totals
110,000
27,000
CH
TRU
=
contact
handled
transuranics;
INEEL
=
Idaho
National
Engineering
and
Environmental
Laboratory;
LANL
=
Los
Alamos
National
Laboratories;
RFETS
=
Rocky
Flats
Environmental
Technology
Site;
RH
TRU
=
remote
handled
transuranics
(*)
Major
Sites
Source:
DOE
CCA,
Chapter
4.
These
totals
do
not
include
wastes
excluded
at
the
time
of
the
Compliance
Application
(i.
e.,
uncharacterized
and
classified
wastes).
There
are
additional
wastes
that
could
be
added
to
the
anticipated
inventory
in
the
event
that
the
classified
waste
streams
are
declassified
or
the
unclassified
wastes
are
identified
and
characterized.
Waste
streams
from
three
of
the
eight
major
1
The
potential
contents
of
a
waste
stream
or
group
of
waste
streams
determine
which
processes
can
be
used
to
adequately
characterize
the
waste.
For
example,
if
acceptable
knowledge
information
suggests
that
the
waste
form
is
heterogeneous,
the
site
should
select
a
nondestructive
assay
technique
appropriate
for
such
waste
in
order
for
adequate
measurements
to
be
obtained.
Radiography
and
visual
examination
help
both
to
confirm
and
quantify
waste
components,
such
as
cellulosics,
rubbers,
plastics,
and
metals.
Once
the
nature
of
the
waste
has
been
confirmed,
the
assay
techniques
then
quantify
the
radioactive
isotopes
in
the
waste.
In
the
given
example,
a
TRU
waste
site
may
be
able
to
characterize
either
a
wide
range
of
heterogeneous
waste
streams
or
only
a
few.
Under
the
current
regulation,
the
scope
of
a
particular
inspection
is
determined
by
a
site's
stated
limits
on
the
applicability
of
proposed
waste
characterization
processes.
2
Process
knowledge
refers
to
knowledge
of
waste
characteristics
derived
from
information
on
the
materials
or
processes
used
to
generate
the
waste.
This
information
may
include
administrative,
procurement,
and
quality
control
documentation
associated
with
the
generating
process,
or
past
sampling
and
analytic
data.
Usually,
the
major
elements
of
process
knowledge
include
information
about
the
process
used
to
generate
the
waste,
material
inputs
to
the
process,
and
the
time
period
during
which
the
waste
was
generated.
EPA
has
used
the
term
"acceptable
knowledge"
synonymously
with
"process
knowledge."
Acceptable
knowledge
is
discussed
further
in
Section
II.
8
sites
(Savannah
River,
Rocky
Flats,
and
Los
Alamos
National
Laboratories
[LANL]),
are
expected
to
contribute
over
85
percent
of
the
total
activity
for
seven
key
isotopes.
I.
D
Current
Inspection
Process
EPA
evaluates
the
ability
of
each
generator
site's
waste
characterization
program
to
adequately
characterize
TRU
waste
through
the
inspection
process
as
established
in
§194.8(
b).
Inspections
at
generator/
storage
sites
are
conducted
to
verify
that
characterization
activities
are
performed
in
accordance
with
approved
site
procedures
and
that
the
characterization
activities
are
adequate
and
appropriate
to
characterize
and
quantify
waste
from
specific
waste
streams
and
waste
containers
so
that
the
waste
will
not
exceed
the
approved
limits.
By
approving
waste
characterization
systems
and
processes,
EPA
concludes
the
following:
(1)
the
site
personnel
are
capable
of
identifying
and
measuring
the
radioactive
components
(such
as
plutonium)
in
the
TRU
waste
that
must
be
tracked
for
compliance
1
;
and
(2)
the
characterization
program
can
demonstrate
that
the
waste
stream(
s)
examined
meet
Condition
3
of
the
Compliance
Certification
Criteria.
The
approval
process
described
at
40
CFR
194.8(
b)
requires
DOE
to
provide
EPA
with
two
types
of
information:
(1)
information
on
process
knowledge
2
for
waste
streams
proposed
for
disposal
at
WIPP,
and
(2)
information
on
the
system
of
controls
in
place
at
the
generator
site.
The
Agency
solicits
public
comments
on
DOE
site
documentation
and
announces
the
date
of
the
upcoming
inspection.
An
EPA
inspection/
surveillance
team
visits
the
site
to
verify
that
process
knowledge
and
other
elements
of
the
system
of
controls
are
technically
adequate
and
being
implemented
properly.
Specifically,
the
EPA
inspection/
surveillance
team
verifies
compliance
with
40
CFR
194.24(
c)(
4),
3
The
introductory
text
of
paragraph
40
CFR
194.24(
c)
states:
"For
each
waste
component
identified
and
assessed
pursuant
to
[40
CFR
194.24(
b)],
the
Department
shall
specify
the
limiting
value
(expressed
as
an
upper
or
lower
limit
of
mass,
volume,
curies,
concentration,
etc.),
and
the
associated
uncertainty
(i.
e.,
margin
of
error)
for
each
limiting
value,
of
the
total
inventory
of
such
waste
proposed
for
disposal
in
the
disposal
system."
9
which
states:
Any
compliance
application
shall:
Provide
information
which
demonstrates
that
a
system
of
controls
has
been
and
will
continue
to
be
implemented
to
confirm
that
the
total
amount
of
each
waste
component
that
will
be
emplaced
in
the
disposal
system
will
not
exceed
the
upper
limiting
value
or
fall
below
the
lower
limiting
value
described
in
the
introductory
text
of
paragraph
(c)
of
this
section.
3
The
system
of
controls
shall
include,
but
shall
not
be
limited
to:
measurement;
sampling;
chain
of
custody
records;
record
keeping
systems;
waste
loading
schemes
used;
and
other
documentation.
As
waste
generator
sites
establish
waste
characterization
programs
for
new
waste
streams
(or
groups
of
waste
streams),
the
Agency
assesses
their
compliance
with
the
requirements
of
Sections
194.24(
c)(
3)
through
(5).
The
Agency
conducts
inspections
at
each
site
to
evaluate
the
use
of
process
knowledge
and
the
establishment
of
a
system
of
characterization
and
controls
for
each
waste
stream
or
group
of
waste
streams.
The
typical
elements
that
are
subject
to
inspection
include
NDA,
VE
and/
or
Radiography,
AK,
and
software
controls
to
include
operation
and
interface
with
the
WWIS.
Elements
related
to
the
control
of
characterization
systems,
such
as
training
records
and
document
control,
are
also
subject
to
inspection.
The
scope
of
a
specific
inspection
is
dictated
by
the
systems
that
are
in
use
for
a
group
of
waste
streams,
how
many
of
these
systems
have
been
previously
inspected
and
approved
by
the
Agency,
and
if
the
nature
of
the
waste
stream
changes
the
performance
of
any
elements
of
the
characterization
system.
For
EPA
to
confirm
that
a
system
of
controls
has
been
adequately
executed,
DOE
must
demonstrate
that
measurement
techniques
and
other
control
methods
can
be
implemented
for
waste
streams
that
DOE
plans
to
emplace
in
the
WIPP.
The
number
of
waste
streams
or
groupings
of
waste
streams
that
can
be
approved
is
dependent
upon
how
well
the
generator
site
systems
perform
for
a
variety
of
wastes.
While
EPA
can
and
has
approved
relatively
broad
groupings
that
mirror
the
specific
authorization
being
sought
by
sites,
EPA
has
also
restricted
its
approval
to
those
waste
streams
it
felt
could
be
adequately
characterized
by
the
systems
examined.
The
Agency's
compliance
decision
is
conveyed
by
a
letter
from
EPA
to
DOE.
A
copy
of
the
letter,
as
well
as
the
results
of
the
inspection(
s),
are
placed
in
EPA's
docket.
To
summarize,
the
approval
process
for
site
specific
waste
characterization
controls
is
as
follows
(See
Figure
2):
a.
One
or
more
Federal
Register
notices
for
the
inspection
and
placement
of
related
10
A
f
e
d
e
r
a
l
r
e
g
i
s
t
e
r
n
o
t
i
c
e
f
o
r
t
h
e
i
n
s
p
e
c
t
i
o
n
o
f
a
s
i
t
e
a
n
d
p
l
a
c
e
m
e
n
t
o
f
r
e
l
a
t
e
d
s
i
t
e
p
r
o
c
e
d
u
r
e
s
a
n
d
r
e
p
o
r
t
s
i
n
t
h
e
d
o
c
k
e
t
A
g
e
n
c
y
p
r
e
p
a
r
e
s
f
o
r
s
i
t
e
i
n
s
p
e
c
t
i
o
n
/
a
u
d
i
t
b
y
c
o
m
p
l
e
t
i
n
g
t
h
e
f
o
l
l
o
w
i
n
g
t
a
s
k
s
:
°
P
r
e
p
a
r
a
t
i
o
n
o
f
d
r
a
f
t
c
h
e
c
k
l
i
s
t
s
°
R
e
v
i
e
w
o
f
s
i
t
e
p
r
o
c
e
d
u
r
e
s
a
n
d
r
e
p
o
r
t
s
°
M
o
d
i
f
i
c
a
t
i
o
n
o
f
c
h
e
c
k
l
i
s
t
s
a
s
n
e
e
d
e
d
b
a
s
e
d
u
p
o
n
s
i
t
e
s
p
e
c
i
f
i
c
p
r
o
c
e
d
u
r
e
s
C
o
n
d
u
c
t
S
i
t
e
i
g
u
r
e
2
S
i
t
e
A
p
p
r
o
v
a
l
P
r
o
c
e
s
s
documents
in
the
docket;
b.
30
day
public
comment
period
on
docketed
information
from
the
site
to
be
inspected;
c.
Performance
of
site
inspection
based
on
information
provided
by
DOE:
°
Review
of
site
procedures
and
other
information,
and
modification
of
EPA
checklists,
if
necessary,
to
incorporate
site
specific
information;
°
On
site
verification
of
the
technical
adequacy
or
qualifications
of
personnel,
procedures,
and
equipment
by
means
of
interviews,
demonstrations,
and
completion
of
checklists;
and
d.
Preparation
of
report
documenting
EPA's
inspection(
s)
and
written
notice
to
DOE
of
EPA's
compliance
decision.
Under
40
CFR
194.21
and
194.24(
h),
EPA
is
authorized
to
perform
follow
up
inspections
toverifythata
TRUwaste
site
is
shippingwaste
thatbelongsonlytothose
wastestreams
or
groups
of
waste
streams
that
have
been
characterized
by
the
approved
processes.
In
the
event
that
the
inspection
finds
that
the
generator/
storage
site
is
not
adequately
meeting
the
waste
characterization
requirements
of
§§
194.24(
c)(
3)
through
(5),
the
agency
will
not
certify
the
generator/
storage
site
until
the
inadequacies
are
resolved
and
the
resolution
verified
usually
through
further
inspection.
11
A
federal
register
notice
for
the
inspection
of
a
site
and
placement
of
related
site
procedures
and
reports
in
the
docket
Agency
prepares
for
site
inspection/
audit
by
completing
the
following
tasks:
°Preparation
of
draft
checklists
°Review
of
site
procedures
and
reports
°Modification
of
checklists
as
needed
based
upon
site
specific
procedures
Has
the
Agency
determined
that
the
site
should
be
certified
based
upon
inspection
results?
(Y/
N)
Agency
grants
approval
for
audited
scope
Conduct
Site
Inspection/
Audit
Yes
No
Figure
2
Site
Approval
Process
12
II.
DESCRIPTION
OF
TECHNICAL
ELEMENTS
EXAMINED
DURING
INSPECTIONS
Specific
waste
characterization
processes,
techniques,
and
elements
important
to
demonstrating
40
CFR
194.24(
c)
compliance
are
examined
by
EPA
during
inspections,
including:
°
Acceptable
Knowledge
(AK).
AK
is
a
program
whereby
historic
process
data
and
other
data
are
assembled,
assessed,
and
evaluated
to
calculate
the
radionuclide
content,
in
terms
of
both
overall
quantity
and
the
presence
of
specific
isotopes.
This
information
is
typically
compared
to
assay
and
other
measured
data
to
assess
the
viability
of
the
AK
results,
but
also
often
provides
direct
information
used
by
NDA
personnel
in
the
form
of
a
"check"
for
NDA,
as
a
source
of
isotopic
information,
or
as
a
direct
replacement
for
NDA
measurements
when
sites
believe
their
AK
information
is
preferable
to
that
obtained
through
measurement.
At
present,
sites
are
required
to
analyze
all
TRU
waste
containers
to
determine
isotopic
contents
and
confirm
AK.
°
Nondestructive
Assay
(NDA).
NDA
systems
are
used
to
detect
radionuclide
content,
including
the
quantity
and
isotopic
distribution.
These
systems
typically
involve:
1)
neutron
systems
(e.
g.,
Passive
Active
Neutron
(PAN)
system)
for
quantification
of
a
plutonium
isotope;
and/
or
2)
Segmented
Gamma
Scanner
(SGS),
or
a
comparable
system,
typically
used
to
identify
specific
radioisotopes.
Currently,
all
waste
containers
are
assayed
to
quantify
10
WIPP
tracked
radionuclides.
In
certain
properly
justified
cases,
isotopic
information
was
obtained
from
AK.
°
Real
time
Radiography
(RTR).
RTR
records
continuous
x
ray
of
drum
contents
that
is
used
to
verify
waste
material
parameters
and
the
correctness
of
the
waste
matrix
code
identified
by
AK,
as
well
as
to
quantify
cellulosics,
plastic,
and
rubbers.
°
Visual
Examination
(VE).
The
process
of
opening
a
statistically
determined
number
of
waste
drums
and
manually
examining
and
recording
their
contents
is
called
VE.
VE
is
used
as
a
quality
control
check
of
RTR.
°
WIPP
Waste
Information
System
(WWIS).
WWIS
is
a
data
tracking
and
validation
system
that
includes
data
collection
and
entry
at
the
site,
and
transmission
to
and
receipt
of
data
at
the
WIPP
site.
These
techniques
are
discussed
in
more
detail
in
the
following
subsections.
EPA
requirements
and
expectations
for
these
techniques
are
derived
both
from
40
CFR
194.24
and
DOE's
own
program
requirements,
as
presented
in
the
CCA
and
revised
over
time
with
EPA's
review
and
approval.
13
II.
A
Acceptable
Knowledge
AK
is
generally
defined
as
the
use
of
process
information
or
other
waste
generator
data
to
determine
waste
content.
AK
is
a
Resource
Conservation
and
Recovery
Act
of
1976
(RCRA)
characterization
process
that
has
been
adopted
by
DOE
as
a
TRU
waste
characterization
methodology
applicable
to
the
radioactive,
as
well
as
the
hazardous,
portion
of
the
waste.
To
date,
two
guidance
documents
address
AK
(EPA
1994,
EPA
1997),
both
of
which
address
characterization
of
the
hazardous,
not
radioactive,
portion
of
the
waste
using
AK.
The
concept
has
been
extended
by
DOE
to
encompass
the
radioactive
portion
of
TRU
waste,
with
the
TRU
waste
AK
characterization
requirements
presented
in
attachment
WAP
of
the
CCA,
as
well
as
in
the
1995
WIPP
TRU
Quality
Assurance
Project
Plan
(QAPjP)
referenced
in
the
CCA.
In
joint
EPA/
NRC
guidance
(1997),
which
is
primarily
applicable
to
low
level
mixed
waste,
EPA
recognized
the
use
of
AK
to
make
RCRA
hazardous
waste
determinations.
The
guidance
does
not,
however,
speak
to
the
use
of
AK
to
determine
radioactive
component
content,
except
to
state
that
the
NRC
does
not
describe
specific
testing
requirements
for
waste
to
determine
if
it
is
radioactive
(10
CFR
20.2006
requires
that
the
waste
manifest
include,
as
completely
as
practicable,
the
radionuclide
identity
and
quantity
and
the
total
radioactivity).
The
1994
and
1997
guidances
both
state
that
the
use
of
waste
knowledge
by
a
generator
and/
or
treatment,
storage,
disposal,
recycling
facilities
(TSDF)
to
characterize
mixed
waste
is
allowed
–
and
even
recommended
–
to
eliminate
unnecessary
or
redundant
waste
testing.
EPA
broadly
interprets
AK
to
include:
°
Process
knowledge,
which
is
detailed
information
on
waste
obtained
from
existing
published
or
documented
waste
analysis
data,
from
a
waste
generator's
records
,
or
from
wastes
generated
by
processes
similar
to
that
which
generated
the
waste;
°
Available
records
of
radionuclides
analysis;
or
°
Combinations
of
both,
supplemented
by
confirmatory
analysis.
II.
A.
1
Overview
of
Technical
Elements
AK
is
used
by
DOE
in
the
context
of
radioactive
waste
characterization
to
provide
the
following:
°
Waste
stream
identification
°
Radionuclide
isotopic
content,
°
Isotopic
ratios,
°
Low
level
vs.
TRU
designation
14
°
Overall
radioactivity
based
on
facility
records
and
process
information
°
Physical
waste
type
°
Waste
material
parameter
content
As
indicated
in
Section
I,
DOE
is
required
to
identify
and
quantify
specific
WIPP
tracked
isotopes,
additional
isotopic
information
to
support
waste
limits
presented
in
the
CCA,
as
well
as
inventory
estimates
presented
in
Attachment
BIR
of
the
CCA.
Additionally,
waste
material
parameters
require
identification.
AK
is
used
to
obtain
available
information
pertaining
to
these
required
parameters,
and
this
information
is
available
to
NDA
and
nondestructive
evaluation
(NDE)
personnel
to
facilitate
their
measurement
activities.
Additionally,
information
derived
via
AK
is
compared
to
that
obtained
by
NDA
measurement
to
assess
the
accuracy
of
AK
data.
II.
A.
2
Technical
Description
of
System
or
Measurement
Device(
s)
AK
requirements
are
presented
in
the
WIPP
QAPjP
(Docket
A
93
02,
Item
II
G
1,
Reference
201),
as
well
as
Appendix
WAP
to
the
CCA.
Since
submission
of
the
CCA,
DOE
has
removed
AK
requirements
from
the
QAPjP
because
it
was
redundant
with
the
RCRA
Waste
Analysis
Plan
(WAP)
with
respect
to
AK
requirements.
As
such,
EPA
uses
the
most
recent
version
of
the
WAP
as
the
governing
document
for
AK
requirements.
AK
is
gathered,
evaluated,
and
assessed
following
a
specific
process
committed
to
by
the
DOE
in
its
CCA
via
associated
attachments
and
references.
This
process,
which
is
examined
by
EPA
during
inspections,
includes:
°
Assembling
AK
information;
°
Compiling
AK
documentation
into
an
auditable
record
(i.
e.,
the
process
should
include
review
of
AK
information
to
determine
the
waste
material
parameters
and
radionuclides
present,
as
well
as
source
info
discrepancy
resolution);
°
Assigning
waste
streams/
waste
matrix
codes;
°
Identifying
physical
forms,
waste
material
parameters,
and
radionuclides
(including,
if
possible,
isotopic
ratios);
°
Resolving
data
discrepancies;
°
Identifying
management
controls
for
discrepant
items/
containers/
waste
streams;
°
Confirming
AK
information
with
other
analytical
results
by
comparing
AK
characterization
data
with
that
obtained
through
NDA,
NDE,
and/
or
visual
examination,
including
discrepancy
resolution;
and
°
Auditing
of
AK
records.
EPA
examines
these
elements
during
inspections
to
ensure
that
the
process
is
being
followed.
Specifically,
EPA
examines
whether
procedures
demonstrate
a
logical
progression
from
general
facility
information
to
more
detailed
waste
stream
specific
information.
15
EPA
examines
whether
the
site's
TRU
waste
management
program
has
procedures
to
determine:
°
Waste
categorization
schemes
(e.
g.,
consistent
definitions
of
waste
streams)
and
terminology,
°
Breakdown
of
the
types
and
quantities
of
TRU
waste
generated/
stored
at
the
site,
and
°
How
waste
is
tracked
and
managed
at
the
generator
site,
including
historical
and
current
operations.
As
indicated
previously,
EPA
is
particularly
concerned
about
the
completeness
and
accuracy
of
data
collection
with
respect
to
those
elements
critical
to
continued
compliance.
Data
gathered
under
the
AK
process
should
support
identification
of
radionuclides
and
parameters
important
to
WIPP
performance,
as
well
as
information
useful
when
assessing
the
accuracy
of
PA
inventory
assumptions
presented
in
the
BIR.
EPA
examines
the
AK
process
to
see
whether
radionuclide
origin
is
documented
and
that
information
is
collected
for:
°
241
Am,
238
Pu,
239
Pu,
240
Pu,
242
Pu,
233
U,
234
U,
238
U,
90
Sr,
137
Cs,
and
unexpected
radionuclides,
°
Ferrous
metals
(in
containers),
°
Cellulosics,
plastics,
rubber,
and
°
Nonferrous
metals
(in
containers).
In
addition
to
this
information,
EPA
expects
AK
information
to
be
properly
managed
and
recorded
by
following
procedures
requiring
that:
°
AK
information
be
compiled
in
an
auditable
record,
including
a
road
map
for
all
applicable
information.
°
A
reference
list
be
provided
that
identifies
documents,
databases,
QA
protocols,
and
other
sources
of
information
that
support
AK
information.
°
The
overview
of
the
facility
and
TRU
waste
management
operations
in
the
context
of
the
facility's
mission
be
correlated
to
specific
waste
stream
information.
°
Correlations
between
waste
streams,
with
regard
to
time
of
generation,
waste
generating
processes,
and
site
specific
facilities
be
clearly
described.
For
newly
generated
wastes,
the
rate
and
quantity
of
waste
to
be
generated
shall
be
defined.
°
Nonconforming
waste
be
segregated.
The
AK
record
must
contain
the
following
items:
°
A
map
of
the
site
that
identifies
the
areas
and
facilities
involved
in
TRU
waste
generation,
treatment,
and
storage;
°
Facility
mission
description
related
to
TRU
waste
generation
and
management;
°
Description
of
the
operations
that
generate
TRU
waste
at
the
site
and
process
information,
including:
16
Area(
s)
or
building(
s)
from
which
the
waste
stream
was
or
is
generated,
Estimated
waste
stream
volume
and
time
period
of
generation,
Waste
generating
process
description
for
each
building
or
area,
Process
flow
diagrams,
if
appropriate,
Generalized
material
inputs
or
other
information
that
identifies
the
radionuclide
content
of
the
waste
stream
and
the
physical
waste
form;
and
°
Types
and
quantities
of
TRU
waste
generated,
including
historical
generation
through
future
projections.
Additionally,
EPA
expects
sites
to
collect
additional
"supplemental,"
or
supporting
information
as
available
to
bolster
information
included
in
the
AK
record,
which
may
include
but
not
be
limited
to
historical
safeguard
data
(for
radionuclides),
waste
package
information,
shipping
records,
etc.
As
a
test
of
AK
data
viability,
NDE
and
NDA
information
are
compared
to
AK
data
to
assess
AK
information
accuracy
(this
is
sometimes
called
"confirmation").
EPA
examines
whether
reevaluation
of
AK
is
performed,
if
NDE/
NDA
or
VE
identify
waste
to
be
of
a
different
waste
matrix
category
(such
as
sludges
vs.
debris)
or
radionuclide
content.
The
reevaluation
should
include,
as
applicable,
waste
reassignment
to
a
new
waste
stream
and
repackaging,
if
appropriate.
All
of
the
requisite
AK
data
are
assembled
in
an
AK
Summary
that
compiles
and
summarizes
information
collected,
including
the
basis
for
all
waste
stream
designations.
EPA
examines
the
AK
Summary
for
several
elements,
including
but
not
limited
to
whether
the
AK
Summary
addresses
radionuclide
content
of
waste,
how
detailed
this
information
is,
the
nature
of
supporting
documentation,
completeness
of
the
AK
Summary
with
respect
to
inclusion
of
all
pertinent
AK
data,
accuracy
of
process
discussions
within
the
AK
Summary,
traceability
of
AK
information
on
a
drum/
container
basis,
and
AK
accuracy
calculations
(which
are
generally
included
in
documents
outside
of
the
AK
Summary).
EPA
examines
the
AK
process
and
the
accuracy
and
viability
of
the
information
obtained
through
this
process.
As
part
of
this
examination,
EPA
performs
a
traceability
analysis
where
drums
are
randomly
selected
and
AK
data
pertinent
to
those
drums
examined.
This
activity
includes
not
only
historic
AK
information,
but
NDA
and
NDE
data
collected
under
EPA/
WIPPapproved
programs,
and
comparison
of
these
data
to
AK
to
demonstrate
that
the
complete
characterization
process
is
attainable
and
approveable.
Additionally,
EPA
examines
the
interface
between
NDA,
NDE,
and
AK
to
see
how
information
is
shared
and
used
between
the
various
characterization
processes.
AK
is
intended
to
serve
as
the
"starting
point"
from
which
basic
waste
information
is
assembled
and
examined;
this
information
is
then
used
to
varying
degrees
by
the
NDE
and
NDA
personnel
when
performing
radionuclide
assay
or
x
rays
to
assess
drum
waste
material
and
prohibited
item
contents.
AK
information
is
available
to
NDA
operators
to
use
when
performing
drum
analysis
as
a
17
source
of
matrix
information
and
radionuclide
content
information
against
which
measurements
are
"checked."
Also,
NDA
often
relies
on
AK
to
provide
isotopic
information,
including
isotopic
ratios.
On
a
case
by
case
basis,
EPA
has
allowed
this
AK
information,
if
demonstrated
to
be
viable
and
of
exceptional
quality,
to
be
used
in
the
radionuclide
characterization
process.
For
example,
EPA
has
allowed
a
site
to
define
the
isotopic
distribution
using
AK,
but
has
required
verification
of
one
or
two
isotopes
in
each
drum
to
confirm
the
AK
identified
isotopes
of
a
number
of
radionuclides.
Specifically,
EPA
has
allowed
a
site
(RFETS)
to
identify
weapons
grade
plutonium
isotopic
distributions
for
plutonium
isotopes
using
AK,
but
has
required
measurement
of
two
isotopes
in
each
container
to
confirm
the
AK
isotopes.
II.
A.
3
Effect
of
Waste
Matrix
Type
on
Measurement
The
viability
of
the
AK
process
is
more
directly
related
to
the
adequacy
of
AK
information
available
than
to
the
waste
matrix
type.
Generator
facilities
are
currently
assembling
AK
information
on,
and
characterizing
wastes
with,
the
best
available
AK
information.
These
wastes
typically
have
a
significant
body
of
information
available
through
site
records,
process
information,
historic
assay,
etc.,
and
the
resulting
AK
data
assembly,
assessment,
and
verification
process
is
generally
successful.
However,
existing
wastes
to
be
characterized
in
the
future
may
have
much
less
historic
information
available,
which
means
that
the
AK
process
aspect
of
waste
characterization
could
have
varying
degrees
of
success
with
respect
to
collection
of
mandatory
and
supplemental
information,
acquisition
of
radionuclide
data,
etc.
Therefore,
the
AK
process
is
not
so
much
affected
by
the
waste
matrix,
but
instead
by
the
age
of
the
waste,
the
historic
information
available
for
the
waste,
and
the
success
of
data
collection
efforts
by
the
generator
sites.
II.
A.
4
Scope
of
EPA
Approvals
for
AK
EPA
typically
approves
site
AK
on
a
Summary
Waste
Category
basis,
primarily
because
sites
themselves
limit
the
approvals
being
sought
to
this
categorization.
However,
EPA's
overall
approval
of
any
given
site
may
be
limited
to
groups
within
the
Summary
Waste
Category
group,
depending
upon
the
technical
viability
of
the
various
characterization
processes.
For
example,
even
if
AK
approval
extends
to
all
retrievably
stored
waste,
overall
approval
could
be
limited
if
NDA
approval
can
only
be
extended
to
a
specific
type
of
waste.
EPA
also
approves
the
AK
process
for
relatively
large
groups
of
wastes
that
are
not
necessarily
restricted
by
Summary
Waste
Category
Groupings.
For
example,
wastes
generated
at
Rocky
Flats
and
currently
in
storage
at
INEEL
tend
to
have
relatively
complete
data
records,
regardless
of
the
Summary
Waste
Category
group
in
question.
Even
if
there
is
little
AK
information,
EPA
can
and
has
extended
approval
of
the
process
if
the
site
is
able
to
demonstrate
a
thorough
understanding
of
the
AK
process.
In
short,
EPA
may
approve
whatever
is
appropriate
given
a
site's
ability
to
characterize
waste
using
the
AK
process.
AK
approval
is
restricted
by
the
quantity
and
quality
of
AK
data,
not
by
the
waste
type.
18
II.
B
Nondestructive
Assay
(NDA)
NDA
is
used
to
identify
and
quantify
the
radioactive
constituents
in
a
container.
Waste
to
be
disposed
of
at
WIPP
is
assayed
on
a
container
basis
to
quantify
the
activity
of
the
radionuclides,
particularly
those
identified
in
the
transuranic
waste
baseline
inventory
report
TWBIR
as
most
important
to
the
PA,
and
to
demonstrate
that
the
waste
in
the
container
meets
the
definition
of
TRU
waste.
II.
B.
1
Overview
of
Technical
Elements
NDA
examines
the
ten
isotopes
requiring
quantification,
as
well
as
additional
isotopes.
The
ten
isotopes
are:
°
238
Pu,
239
Pu,
240
Pu,
and
242
Pu;
°
241
Am;
°
233
U,
234
U,
and
238
U;
°
90
Sr;
and
°
137
Cs.
In
addition
to
the
isotopes
listed
as
important
to
PA
and
requiring
quantification,
the
waste
characterization
program
also
is
responsible
for
adequately
calculating
the
emplaced
activities
of
the
isotopes
contributing
to
the
Waste
Unit
(in
this
case,
the
activity
of
the
TRU
alpha
emitting
isotopes
in
Table
4
8
of
the
CCA).
Section
4.
4.
1
of
the
CCA
states,
Collectively,
those
elements
of
the
waste
characterization
program
that
support
long
term
regulatory
compliance
include
the
determination
of
the
radionuclide
inventory
(for
purposes
of
normalizing
radionuclide
releases
as
required
for
comparison
with
40
CFR
Part
191.13(
a)),
the
identification
of
the
physical
and
chemical
waste
form
inventories
(if
applicable),
and
the
verification
that
no
wastes
are
emplaced
in
the
WIPP
that
exceed
the
disposal
system's
safety
and/
or
performance
limitations.
The
normalization
requirement
in
Table
1
referenced
in
40
CFR
Part
191.13(
a)
necessitates
knowledge
of
the
EPA
Waste
Unit,
defined
as
the
total
curies
divided
by
one
million.
EPA
has,
as
part
of
the
inspection
program,
also
required
DOE
to
quantify
isotopes
other
than
those
identified
as
important
in
the
CCA
or
40
CFR
Part
191.
These
additional
isotopes
are
usually
necessary
to
support
the
technical
adequacy
of
the
assay
values
for
isotopes
identified
as
important
to
PA.
Typically,
EPA
may
require
a
site
to
ensure
that
DOE
identify
and
account
for
isotopes
that
may
interfere
with
the
assay
of
isotopes
identified
as
important
to
PA.
One
example
19
of
additional
required
isotopes
is
237
Np
at
LANL,
when
LANL
was
employing
the
Fixed
Energy
Response
Analysis
using
Multiple
Efficiencies
(FRAM)
system
for
gamma
spectroscopy.
Another
example
is
the
presence
of
244
Cm
or
252
Cf
in
waste
planned
for
assay
using
passive
neutron
methods.
These
special
cases
are
documented
in
the
EPA
inspection
report,
and
are
usually
specific
to
a
given
system
and
a
given
type
of
waste.
II.
B.
2
Technical
Description
of
System
or
Measurement
Device(
s)
To
demonstrate
compliance
with
40
CFR
194.24(
c),
DOE
described
general
methods
for
accomplishing
NDA
in
the
CCA.
DOE
described
more
detailed
requirements
for
NDA
programs
in
Chapter
9
of
the
Waste
Characterization
Quality
Assurance
Program
Plan
(QAPP),
a
document
that
has
since
been
replaced
by
the
Waste
Acceptance
Criteria
(WAC)
document.
Each
waste
generator
site
describes
their
specific
NDA
program,
and
how
the
program
complies
with
the
upper
tier
EPA
and
DOE
requirements,
in
a
Quality
Assurance
Project
Plan
(QAPjP).
Site
operating
procedures
for
each
instrument
or
method
are
then
written
to
implement
the
QAPjP
requirements,
along
with
any
other
specific
instrument
or
site
dependent
requirements.
NDA
systems
typically
include
data
collection
and
analysis
software
that
performs
quality
related
functions.
In
accordance
with
40
CFR
194.22
any
NDA
system
used
to
support
EPA
characterization
requirements
must
adhere
to
the
American
Society
of
Mechanical
Engineers
(ASME)
Nuclear
Quality
Assurance
(NQA)
Requirements
for
Software
(ASME,
1990).
Radioactive
components
in
waste
to
be
disposed
of
at
WIPP
may
be
characterized
by
radiochemistry
or
NDA.
NDA
methods
are
by
far
the
preferred
techniques
for
performing
radioassay,
as
they
generally
have
greater
throughput
and
produce
lower
human
exposures
than
do
radiochemistry
techniques.
II.
B.
2.1
General
NDA
System
Information
The
NDA
techniques
approved
for
use
on
WIPP
waste
containers
are
classified
as
active
or
passive.
Passive
NDA
methods
measure
spontaneously
emitted
radiation
produced
by
natural
decay
of
the
radioactive
isotopes
inside
the
waste
container.
Active
NDA
methods
measure
radiation
produced
by
artificially
generated
reactions
in
the
waste
material.
Active
NDA
systems
used
for
assay
of
TRU
waste
generate
reactions
in
the
heavy
metals
within
the
waste
using
a
low
intensity
beam
of
neutrons.
Presently,
most
waste
is
characterized
using
passive
active
neutron
(PAN)
counters
and
gamma
ray
spectrometry
systems.
A
small
fraction
of
the
waste,
primarily
from
the
production
of
radioisotopic
thermal
generators
(RTG),
is
characterized
by
calorimetry
instruments.
The
neutron
counting
systems
being
used
for
NDA
of
WIPP
waste
containers
are
designed
to
provide
quantification
of
the
plutonium
isotopes
in
TRU
waste.
Neutrons
are
20
naturally
produced
by
only
a
small
number
of
isotopes;
the
rate
at
which
neutrons
of
certain
energies
are
produced
by
the
waste
container
provides
a
good
measure
of
the
quantity
of
these
isotopes.
Passive
neutron
counting
systems
detect
these
naturally
occurring
neutrons
and
use
various
computational
techniques
to
relate
their
quantity
to
isotopic
activities.
Many
NDA
systems
using
neutron
counting
are
also
capable
of
active
counting.
In
the
active
mode,
a
low
intensity
beam
of
neutrons
is
fired
into
the
waste
container.
This
neutron
beam
will
produce
a
series
of
reactions
in
the
fissionable
and
fissile
isotopes
within
the
waste,
with
the
number
of
particles
produced
by
the
reactions
being
proportional
to
the
amount
of
fissile
and
fissionable
isotopes
present
in
the
waste.
The
external
detectors
then
count
these
particles
and
convert
the
particle
response
to
source
strength.
By
using
active
NDA
methods
and
special
sensitive
neutron
detectors,
even
very
small
quantities
of
plutonium
in
the
waste
containers
can
be
detected
and
quantified.
The
gamma
ray
measurement
systems
being
used
to
characterize
WIPP
waste
containers
are
based
on
two
basic
principals.
First,
almost
all
radioactive
materials
produce
gamma
rays.
Second,
the
gamma
ray
pattern
produced
by
any
isotope
is
unique
to
that
isotope;
no
two
isotopes
produce
the
same
number
of
gamma
rays
having
the
same
energies.
Given
a
detector
with
good
enough
resolution
to
count
the
various
gamma
rays
individually
and
a
method
to
determine
what
the
gamma
ray
energy
patterns
mean,
it
is
possible
to
quantitatively
determine
the
isotopes
present
in
a
waste
sample.
Modern
radiation
detectors
coupled
to
sophisticated
computer
programs
that
solve
the
energy
pattern
for
the
presence
of
certain
isotopes
are
capable
of
performing
this
task
for
a
large
number
of
isotopes.
The
gamma
measurement
systems
approved
for
use
in
characterizing
WIPP
waste
are
capable
of
quantifying
the
presence
of
many
of
the
isotopes
defined
by
40
CFR
Part
191,
even
in
the
presence
of
potential
interfering
isotopes
and
background
radiation.
When
the
gamma
and
neutron
NDA
systems
are
used
together,
these
systems
provide
information
about
the
radiological
content
of
a
waste
container.
The
information
that
can
be
produced
by
the
WIPP
waste
NDA
systems
includes,
but
is
not
limited
to,
239
Pu
equivalent
activity,
239
Pu
fissile
gram
equivalent,
total
alpha
activity,
the
decay
heat
of
waste
containers,
and
the
activity
of
the
isotopes
of
interest
to
the
performance
assessment
and
the
applicable
regulations.
The
purpose
of
these
data
relative
to
long
term
repository
compliance
with
40
CFR
Parts
191
and
194
is
to
establish
the
radionuclide
content
emplaced
in
the
repository.
All
assay
systems
using
radiation
detection
methods
must
be
calibrated
using
a
variety
of
standards
that
simulate
the
various
waste
compositions,
source
distributions
and
interferences
common
to
the
waste
streams
originating
from
a
particular
generator
site.
AK
enhances
the
NDA
systems
by
providing
advance
information
on
the
radiological
characteristics
of
a
waste
stream,
which
allows
the
NDA
systems
to
be
made
particularly
sensitive
to
that
type
of
waste
by
developing
realistic
calibration
standards.
Calibration
records
and
expected
system
performance
curves
are
compared
against
the
actual
results
of
the
measurements
performed
on
the
waste
21
containers.
II.
B.
2.2
Neutron
Systems
Because
they
have
no
charge,
and
are
not
purely
an
electromagnetic
packet
like
gamma
rays,
neutrons
have
a
unique
set
of
interactions
with
matter.
They
do
not
interact
with
the
electron
cloud
around
a
nucleus,
but
rather
with
the
nucleus
itself.
Thus,
when
a
material
absorbs
neutrons,
the
neutrons
are
interacting
with
and
changing
the
nuclei
of
the
atoms
in
the
absorbing
material,
which
can
produce
a
number
of
secondary
reactions.
Neutron
interactions
with
nuclei
may
result
in
the
disappearance
of
the
neutron
and
its
replacement
by
secondary
radiations,
or
a
significant
change
in
the
neutron's
energy
or
direction.
It
may
even
result
in
the
fragmentation
of
the
nucleus
with
which
it
is
interacting
in
a
process
known
as
fission.
The
secondary
radiations
produced
by
neutron
interactions
are
usually
heavy
charged
particles;
it
is
these
charged
particles
produced
by
the
conversion
of
the
neutron
energy
that
are
seen
by
neutron
detectors,
as
discussed
below.
Generally,
the
type
and
probability
of
the
various
neutron
interactions
with
any
given
type
of
nucleus
depend
strongly
on
the
energy
of
the
neutron.
NDA
systems
do
not
require
exact
measures
of
neutron
energy.
For
NDA
purposes,
neutrons
can
simplistically
be
divided
into
two
categories
based
on
their
energy:
high
energy
or
"fast"
neutrons,
and
low
energy
or
"slow"
neutrons,
using
an
arbitrary
energy
division
of
approximately
0.
5
electron
volts
(eV).
Neutrons
are
measured
indirectly
by
detecting
secondary
particles
resulting
from
interactions
of
neutrons
with
target
nuclei.
These
possible
interactions
include:
°
(n,
p)
or
(n,
)
reactions
where
a
nucleus
absorbs
a
neutron
and
emits
a
charged
particle,
which,
along
with
the
recoil
product
nucleus,
causes
ionization
in
the
detector;
$
Neutron
induced
fission,
or
(n,
f)
reactions,
where
the
detector
registers
ionization
produced
by
the
fission
fragments
or
the
prompt
or
delayed
neutrons
and
photons;
and/
or
$
Neutron
scattering,
where
the
recoil
nucleus
produces
ionization
in
the
detector.
The
(n,
p),
(n,
)
and
(n,
f)
reactions
are
of
greatest
interest
for
neutron
detection
because
they
produce
secondary
radiations
(i.
e.,
charged
particles
that
can
be
detected
directly).
The
neutron
detectors
most
widely
used
in
NDA
systems
are
gas
proportional
detectors
filled
with
a
light
isotope
of
helium
(
3
He).
These
detectors
are
commonly
called
helium
tubes.
A
neutron
detection
system
typically
contains
many
helium
tubes,
maintained
under
an
applied
voltage,
or
electric
field.
The
neutron
helium
reaction
of
interest
is
shown
below:
3
He
+n
3
H
+
p
+
0.764
MeV
22
The
term
"cross
section"
is
used
to
describe
the
probability
of
interaction.
Helium
is
used
because
it
has
a
high
cross
section
for
interaction
with
thermal,
or
low
energy,
neutrons,
which
provides
a
high
detection
efficiency
and
pulse
height
resolution.
The
charge
liberated
by
the
neutron
helium
interaction
produces
initial
ionizations
of
helium
gas.
By
maintaining
the
appropriate
electric
field
within
the
gas,
the
number
of
secondary
ionizations
produced
is
proportional
to
those
produced
initially,
while
the
number
of
actual
ion
pairs
is
multiplied
by
a
factor
of
many
thousands.
The
detection
system
collects
the
ion
pairs
as
charge
which,
with
proper
calibration,
is
correlated
with
the
number
of
neutron
interactions
and
therefore
the
sample
reaction
rate.
Because
the
probability
of
neutrons
interacting
with
target
materials
is
a
strong
inverse
function
of
the
neutron's
energy,
high
energy
neutrons
produced
by
spontaneous
or
induced
fission
("
fast"
neutrons)
must
be
slowed
before
they
can
be
efficiently
detected.
This
occurs
through
multiple
collisions
with
atoms
in
the
materials
within
the
detection
system
(i.
e.,
polyethylene,
graphite,
etc.).
Neutron
cross
sections
for
a
given
target
nucleus
are
interaction
specific
(i.
e.,
there
is
a
different
cross
section
for
fission,
elastic
scattering,
inelastic
scattering,
(n,
p)
reaction,
etc.),
and
each
is
strongly
dependent
on
the
neutron
energy.
Cross
sections
are
also
material
specific.
Certain
isotopes
have
large
cross
sections
for
various
reactions,
which
may
make
them
a
preferred
material
for
neutron
detection
systems.
The
main
source
of
neutrons
of
interest
to
NDA
result
from
spontaneous
or
induced
nuclear
fission,
which
is
the
disintegration
of
an
atomic
nucleus
into
two
or
more
lighter
fragments.
In
general,
isotopes
of
plutonium
and
uranium
have
a
low
rate
of
spontaneous
fission
compared
to
the
rate
for
other
decay
modes,
such
as
alpha
emission.
This
is
particularly
so
for
heavy
radionuclides
with
odd
numbers
of
neutrons
and
odd
mass
number,
but
these
isotopes
frequently
have
a
high
thermal
neutron
fission
cross
section,
which
means
these
isotopes
can
be
made
to
undergo
induced
fission
by
bombardment
with
low
energy
neutrons.
Examples
of
these
isotopes
are
233
U,
235
U
and
239
Pu.
Plutonium
isotopes
with
even
mass
numbers
(
238
Pu,
240
Pu,
and
242
Pu)
undergo
higher
rates
of
spontaneous
fission,
and
for
240
Pu
the
rates
of
spontaneous
fission
and
alpha
emission
are
close.
This
is
important
as
240
Pu
is
typically
present
as
an
impurity
in
weapons
grade
plutonium
and
is
a
component
of
TRU
wastes.
Assays
of
TRU
wastes
by
measuring
the
neutrons
emitted
by
spontaneous
fission
are
called
"passive"
mode
assays.
Passive
mode
measurements
count
neutrons
produced
by
isotopes
with
significant
likelihood
of
decay
by
spontaneous
fission,
including
238
Pu,
240
Pu,
242
Pu,
and
244
Cm.
Neutrons
are
also
emitted
by
TRU
radionuclides
in
response
to
induced
fission
caused
by
bombardment
with
energetic
neutrons
supplied
by
the
measurement
system.
Such
assays
measuring
induced
neutrons
are
called
"active"
mode
assays.
Active
mode
assays
provide
information
for
239
Pu
and
241
Pu,
as
well
as
other
fissile
isotopes
present
in
the
TRU
waste
being
assayed
(e.
g.,
235
U),
that
fission
takes
place
in
response
to
neutrons
supplied
by
the
measurement
system.
23
II.
B.
2.3
Passive
Active
Neutron
Counters
PAN
counters
are
used
to
quantify
the
amount
of
a
fissile
or
fissionable
nuclide
inside
a
container.
More
precisely,
these
systems
quantify
the
amount
of
a
particular
radionuclide
that
would
result
in
the
number
of
counts
observed.
This
is
referred
to
as
the
effective
mass.
For
active
measurements,
the
239
Pu
effective
mass
is
measured,
while
for
passive
measurements,
the
240
Pu
effective
mass
is
measured.
To
convert
the
effective
mass
measured
into
the
true
mass
of
each
of
the
radionuclides
present,
the
ratio
of
each
nuclide
to
that
of
the
primary
nuclide
being
measured
must
be
known.
These
ratios
can
be
measured
using
a
gamma
ray
spectrometry
system,
described
in
the
following
section.
To
quantify
the
effective
mass
of
239
Pu
or
240
Pu,
fast
neutrons
from
induced
or
spontaneous
fissions
are
detected
and
counted.
Since
two
or
more
neutrons
usually
result
from
a
fission
event,
neutron
counters
are
operated
in
coincidence
mode.
In
coincidence
mode,
an
event
is
only
counted
when
two
or
more
neutrons
are
individually
detected.
Most
PAN
counters
consist
of
a
large
number
of
individual
neutron
detectors
surrounding
the
container
being
assayed.
The
most
common
type
of
neutron
detector
used
is
a
3
He
tube,
which
is
a
long
cylindrical
proportional
gas
counter
filled
with
3
He.
Since
the
probability
of
detection
in
a
3
He
tube
is
much
greater
for
thermal
neutrons
than
for
fast
neutrons,
3
He
tubes
are
usually
surrounded
by
a
moderator.
Fast
neutrons
lose
energy
through
numerous
collisions
in
the
moderator
until
they
are
reduced
in
energy,
or
"thermalized."
As
previously
described,
a
PAN
counter
in
passive
mode
counts
neutrons
from
spontaneously
fissioning
nuclides,
such
as
240
Pu.
In
active
mode
the
PAN
system
counts
neutrons
generated
in
the
waste
container
after
the
container
is
exposed
to
fast
neutrons
from
an
external
source,
which
induce
fissile
nuclides
in
the
waste
to
fission.
The
most
common
source
of
fast
neutrons
is
a
D
T
neutron
generator,
although
other
sources,
such
as
252
Cf
sources
can
also
be
used.
A
D
T
neutron
generator
creates
14
MeV
neutrons
by
accelerating
deuterium
(
2
H)
nuclei
into
a
tritium(
3
H)
target.
Proper
use
and
calibration
of
a
PAN
system
requires
tests
using
known
sources
in
order
to
evaluate
system
efficiency.
Additionally,
the
environmental
neutron
signal
must
be
measured
in
order
to
remove
background
signals
that
are
not
contributed
by
the
waste
components.
Both
the
efficiency
and
the
background
signal
must
be
periodically
checked
in
order
to
ensure
data
quality
is
not
degraded.
II.
B.
2.4
Photon
Emission
and
NDA
Photons
in
the
general
sense
are
packets
of
electromagnetic
energy,
and
are
the
basic
constituents
of
any
electromagnetic
energy,
including
visible
light.
When
these
photons
are
generated
by
de
excitation
reactions
in
an
atomic
nucleus,
they
are
often
referred
to
as
gamma
24
radiation
or
gamma
rays.
Gamma
photons
are
essentially
the
same
as
x
rays,
but
have
different
origins:
gamma
radiation
is
emitted
during
changes
in
the
state
of
nuclei,
while
x
rays
are
emitted
during
changes
in
the
state
of
inner
or
more
tightly
bound
electrons.
Gamma
radiation
is
a
penetrating
radiation
best
attenuated
by
dense
materials
like
concrete,
lead,
etc.
Gamma
emissions
occur
at
discrete
energies
that
are
characteristic
of
specific
radionuclide
transitions,
enabling
their
identification
by
spectroscopic
techniques,
as
discussed
below.
Gamma
photon
emissions
range
in
energy
from
approximately
one
thousand
electron
volts
(1
KeV)
to
almost
ten
million
electron
volts
(10
MeV).
For
purposes
of
NDA
isotopic
measurements
of
plutonium,
the
photon
emissions
of
interest
occur
between
the
energies
of
approximately
40
to
640
KeV;
for
uranium,
the
photon
emissions
of
interest
occur
between
approximately
100
KeV
and
1
MeV
in
energy.
Their
electromagnetic
nature
causes
photons
to
interact
strongly
with
the
charged
electrons
in
the
atoms
of
all
matter.
The
photon
gives
up
energy
to
an
electron,
which
then
is
released
from
its
parent
atom
and
collides
with
other
atoms,
liberating
more
electrons.
The
total
charge
released
is
proportional
to
the
photon
energy,
since
the
higher
the
photon
energy
the
more
energy
is
available
to
release
electrons.
The
charge
resulting
from
this
cascade
of
released
electrons
is
then
collected,
causing
a
signal
indicating
the
presence
of
the
gamma
photon.
The
magnitude
of
the
signal
tells
the
energy
of
the
photon
since
the
electrical
signal
output
to
the
detector
is
proportional
to
the
energy
deposited
in
the
detector.
After
a
large
number
of
these
gamma
photons
have
been
detected,
a
graph
of
the
number
of
gamma
photons
measured
versus
the
energy
of
the
photons
can
be
displayed.
This
graph,
or
spectrum,
results
in
a
"fingerprint"
of
specific
radionuclides
since
the
gamma
photon
energy
release
pattern
is
unique
for
each
isotope.
With
the
appropriate
calibration,
the
spectrum
allows
identification
and
quantification
of
photon
emitting
radionuclides
in
various
media.
There
are
many
types
of
materials
suitable
for
use
in
photon
detectors.
The
NDA
systems
of
interest
primarily
use
modern
solid
state
detectors
constructed
from
germanium,
in
which
the
charge
produced
by
the
photon
interactions
is
collected
directly.
Germanium
is
the
semiconductor
material
of
choice
for
modern
photon
detectors
due
to
its
nearly
ideal
electronic
characteristics
that
allow
electrons
and
"electron
holes"
to
move
freely.
The
ionization
charge
resulting
from
the
photon
interaction
within
the
detector
is
swept
to
an
electrode
by
the
high
electric
field
in
the
semiconductor
material
produced
by
the
voltage
applied
to
the
detector
with
the
system's
high
voltage
power
supply.
The
charge
is
converted
to
a
voltage
pulse
by
a
preamplifier;
this
voltage
is
then
amplified
and
sent
to
a
multi
channel
analyzer,
which
displays
the
spectrum
of
gamma
counts
detected
versus
energy.
Spectroscopic
evaluation,
including
radionuclide
identification
by
energy
peak
pattern,
background
correction,
pulse
height
determination,
etc.,
can
then
be
performed
on
the
spectrum
either
manually
or
by
computer.
By
applying
calibration
and
correction
factors
appropriate
to
the
waste
matrix,
container,
and
radionuclides,
the
spectroscopic
data
can
be
transformed
into
concentrations
of
specific
photon
emitting
TRU
radionuclides.
25
II.
B.
2.5
Gamma
Ray
Spectrometry
Systems
Gamma
ray
spectrometry
systems
are
used
to
quantify
the
amount
of
individual
radionuclides,
or
to
measure
the
ratio
of
different
radionuclides,
by
detecting
gamma
ray
emissions.
Because
radionuclides
emit
gamma
rays
of
discrete
energies,
the
quantity
of
individual
radionuclides
can
be
related
to
the
number
of
gamma
rays
detected
at
a
specific
energy.
Effective
use
of
gamma
ray
spectrometry
systems
requires
the
user
to
define
the
system
efficiency
and
resolution.
These
parameters
must
be
periodically
checked
to
ensure
the
system
is
providing
consistent
results.
The
radiological
background
present
at
the
detector
must
also
be
defined
in
order
to
calculate
accurate
results
for
the
radionuclide
quantities
present
in
the
waste.
The
background
gamma
ray
spectrum
must
be
periodically
measured
in
order
to
ensure
that
unintended
errors
are
not
introduced
into
the
results.
Most
gamma
ray
spectrometry
systems
involve
one
or
more
high
resolution
detectors,
with
high
purity
germanium
(HPGe)
being
the
most
common.
These
detectors,
typically
about
three
inches
in
diameter
and
three
inches
in
length,
are
positioned
alongside
the
container.
In
many
systems,
commonly
referred
to
as
scanners,
a
collimator
is
used
so
that
the
detector
only
detects
gamma
rays
emitted
from
a
portion
of
the
container.
The
detector,
or
more
commonly
the
container,
is
then
translated
until
the
entire
container
is
measured.
Some
gamma
ray
scanners
incorporate
a
transmission
source
to
correct
for
gamma
ray
attenuation
in
the
container.
These
collimated
radioactive
sources
are
positioned
directly
opposite
of
the
detector.
Shutters
are
often
used
to
shield
the
source
from
the
detector
when
it
is
not
being
used.
II.
B.
2.6
Calorimetry
Instruments
Calorimetry
instruments
are
used
to
quantify
radionuclides
for
waste
containers
that
contain
significant
quantities
of
238
Pu.
The
high
specific
activity
of
238
Pu,
used
primarily
for
radioisotopic
thermal
generators,
results
in
a
measurable
heat
flux
that
can
be
correlated
to
the
activity
of
the
radionuclides
in
question.
Like
neutron
counters,
isotopic
ratios
must
be
known
in
order
to
relate
the
heat
flux
to
the
activities
of
individual
radionuclides.
Calorimetry
has
only
been
used
in
a
limited
number
of
instances,
and
EPA
has
approved
its
use
only
at
Rocky
Flats.
II.
B.
3
Effect
of
Waste
Matrix
or
Waste
Type
on
Measurement
The
applicability
of
PAN
counters
and
gamma
ray
spectrometry
systems
to
characterize
waste
to
be
disposed
of
at
WIPP
depends
primarily
on
the
matrix
properties
of
the
waste
and
the
types
and
quantities
of
radionuclides
present.
For
neutron
counters,
the
matrix
parameters
of
primary
interest
are
the
neutron
absorption
and
moderating
properties.
Large
quantities
of
hydrogen
containing
materials
will
enhance
neutron
moderation,
making
active
measurements,
and
to
a
lesser
extent
passive
measurements,
more
difficult.
The
presence
of
any
materials
that
26
enhance
neutron
capture
will
make
any
neutron
measurements,
active
or
passive,
more
difficult.
Passive
and
active
neutron
counters
work
best
with
radionuclides
having
large
cross
sections
for
induced
fission
and
high
spontaneous
fission
rates,
respectively.
Matrix
parameters
that
affect
gamma
ray
systems
are
matrix
density
and
the
effective
atomic
number.
Denser
materials
and
materials
with
high
atomic
numbers
(Z)
absorb
more
gamma
rays
than
less
dense,
lower
Z
number
materials,
resulting
in
increased
gamma
ray
attenuation
and
poorer
signal
to
source
ratios.
Gamma
ray
spectrometry
systems
are
best
suited
to
detect
radionuclides
that
emit
gamma
rays
at
energies
between
about
50
keV
and
1
MeV
with
a
high
probability,
or
branching
ratio.
Specific
issues
related
to
waste
properties
are
described
in
the
following
sections
for
each
of
the
neutron
and
gamma
detection
methods.
II.
B.
3.1
Neutron
Counting
Systems
PAN
counters
typically
must
account
for
the
following:
$
Radionuclide
source
(source)
heterogeneity.
Most
neutron
systems
are
calibrated
assuming
that
sources
are
uniformly
distributed
throughout
the
container
volume.
When
sources
are
not
uniformly
distributed,
but
are
instead
concentrated
in
parts
of
the
drum,
the
system
will
underestimate
or
overestimate
the
239
Pu
or
240
Pu
effective
mass.
$
Matrix
heterogeneity.
In
addition
to
a
uniformly
distributed
source,
most
neutron
calibrations
are
done
for
matrices
whose
neutron
absorption
and
moderation
properties
are
assumed
to
be
the
same
throughout
the
volume
of
the
container.
Like
non
uniform
source
distributions,
non
uniform
matrices
can
result
in
an
underestimation
or
overestimation
of
the
239
Pu
or
240
Pu
effective
mass.
$
Source
self
shielding.
If
the
fissile
material
is
concentrated
in
a
small
volume
(i.
e.,
a
lump)
the
inner
material
is
shielded
from
interrogating
neutron
flux
during
an
active
measurement.
This
effect,
referred
to
as
self
shielding,
can
result
in
an
underestimation
of
the
239
Pu
effective
mass.
This
problem
is
not
significant
in
passive
mode,
where
the
mean
free
path
of
the
fast
neutrons
is
much
larger
than
the
size
of
the
fissile
mass.
$
Interfering
nuclides.
Any
fissile
or
spontaneously
fissioning
nuclides,
such
as
244
Cm,
not
accounted
for
in
the
determination
of
the
isotopic
ratios
will
result
in
an
incorrect
estimation
of
the
individual
radionuclide
activities
and
any
derived
quantities.
Containers
are
often
rotated
during
the
measurement
to
reduce
the
effect
of
source
and
matrix
heterogeneity
on
the
measurement.
Some
neutron
counters
incorporate
imaging
algorithms
to
measure
the
spatial
variations
in
the
source
distribution
and
the
matrix
properties.
II.
B.
3.2
Photon
Measuring
Systems
27
Gamma
ray
systems
are
affected
by
many
of
the
source
and
matrix
effects
that
affect
neutron
counters,
including
source
heterogeneity,
matrix
heterogeneity,
and
source
self
shielding.
$
Source
heterogeneity.
Like
neutron
counters,
most
gamma
ray
systems
are
calibrated
for
uniformly
distributed
sources,
and
nonuniform
source
distributions
are
likely
to
result
in
underestimation
or
overestimation
of
radionuclide
activities.
$
Matrix
heterogeneity.
Gamma
ray
system
calibrations
generally
assume
that
gamma
attenuation
properties
are
uniform
throughout
the
volume
of
the
container.
Spatial
variations
in
these
properties,
namely
the
density
and
effective
atomic
number,
can
cause
the
radionuclide
activities
to
be
incorrectly
estimated.
$
Source
self
absorption.
Concentrated
masses,
or
lumps,
of
high
Z
materials,
such
as
uranium
and
plutonium,
can
result
in
underestimation
of
the
radionuclide
activity.
Unlike
the
self
shielding
effect
in
active
neutron
measurements,
the
difficulty
in
gamma
spectrometry
arises
when
gamma
rays
from
the
interior
of
the
mass
are
absorbed
before
escaping
the
lump.
$
Interfering
radionuclides.
Some
radionuclides
emit
gamma
rays
very
close
in
energy
to
those
being
measured.
If
not
properly
accounted
for,
these
interfering
radionuclides
can
result
in
the
incorrect
determination
of
radionuclide
activities
and/
or
isotopic
ratios.
Like
neutron
counters,
effects
due
to
source
and
matrix
heterogeneity
can
be
significantly
reduced
by
rotating
the
container
during
the
measurement.
Additionally,
segmented
gamma
scanners,
using
transmission
sources,
can
account
for
spatial
variations
in
the
source
activity
and
matrix
attenuation
properties
as
a
function
of
height.
A
number
of
systems
also
use
computed
tomography
(CT)
to
measure
the
matrix
properties
and
source
distribution
in
three
dimensions.
II.
B.
4
Scope
of
EPA
Approvals
for
Nondestructive
Assay
EPA
approves
NDA
methods
for
a
waste
stream
or
group
of
waste
streams
based
on
the
demonstrated
capability
of
the
NDA
system
to
quantify
the
radiological
properties
of
the
waste
stream
(s).
This
approach
has
been
used
because
of
the
194.8(
b)
language
specifying
waste
stream
examinations,
and
also
because
DOE
generator
sites
most
often
test
and
qualify
their
NDA
instruments
to
a
given
set
of
waste
as
defined
by
waste
streams.
This
approach,
however,
has
led
to
some
problems
during
waste
certification
inspections
because
waste
streams
are
generally
defined
by
physical
properties
rather
than
by
radiological
properties.
While
there
is
some
correlation
between
the
effectiveness
of
a
given
NDA
method
and
the
physical
properties
of
the
waste
material
(e.
g.,
a
highly
absorbing
or
moderating
matrix
like
organic
sludge),
in
practice
this
approval
system
has
frequently
resulted
in
limited
approvals
relative
to
the
total
population
of
waste
intended
for
approval.
A
few
sites,
such
as
INEEL
and
LANL,
currently
attempt
to
define
28
their
assay
programs
as
a
process
applicable
to
broad
ranges
of
wastes
that
are
defined
by
their
radiological
and
nuclear
properties
of
interest
to
the
assay
method
(e.
g.,
moderator/
absorber
index
for
neutron
systems),
rather
than
strictly
by
waste
stream
or
Summary
Waste
Category
Group.
Other
generator
sites,
such
as
Savannah
River,
have
programs
that
are
designed
around
the
waste
stream
intended
for
shipment.
A
radioassay
system
should
be
capable
of
characterizing
waste
containers,
provided
the
important
matrix
properties
of
the
containers
are
within
the
bounds
for
which
the
system
is
calibrated.
For
neutron
systems,
the
absorption
and
moderating
properties
of
the
matrix
are
of
primary
interest.
Density
and
atomic
number
of
the
waste
are
of
primary
interest
for
gamma
spectrometry
systems.
Since
NDA
systems,
particularly
neutron
systems,
often
use
different
parameters
to
characterize
the
matrix
properties,
it
is
difficult
to
establish
standard
limits
for
matrix
characteristics
or
to
compare
calibration
limits
from
one
instrument
to
another.
II.
C
Visual
Examination
and
Radiography
Radiography
(e.
g.,
RTR)
is
a
nondestructive,
qualitative
and
quantitative
technique
that
involves
x
ray
scanning
of
waste
container
contents.
It
is
used
to
identify
and
quantify
waste
material
parameters
important
to
PA,
such
as
cellulosic,
plastic,
and
rubber
content.
Radiography
also
is
used
to
identify
items
such
as
liquids,
pyrophorics,
explosives,
compressed
gas
cylinders,
and
sealed
containers
larger
than
4
liters,
which
are
prohibited
from
disposal
by
DOE.
Unlike
nondestructive
assay,
no
radiological
analysis
is
done
with
this
technique.
Radiography
is
considered
to
be
both
qualitative
and
quantitative
because
measurements
are
made
by
an
operator
who
views
a
real
time
x
ray
scan
of
the
contents
of
a
waste
container
(e.
g.,
drum
or
standard
waste
box)
to
estimate
values
for
parameters
of
interest.
For
example,
the
operator
(based
on
experience,
on
the
job
training,
and
drum
aids)
estimates
the
container
fill
percentage
(i.
e.,
the
percentage
of
the
drum
filled
with
waste),
the
volume
of
"combustible"
materials,
metals,
etc.
Visual
Examination
(VE)
involves
opening
of
waste
containers
in
glove
boxes
or
other
controlled
structures
and
manually
cataloging
the
contents.
VE
is
currently
used
as
either
a
confirmation
of
Nondestructive
Examination
(NDE)
which
to
date
has
been
RTR
or
as
a
replacement
for
NDE.
Visual
verification
(which
differs
from
VE
in
that
the
visual
verification
process
is
used
during
repackaging
and
no
videotape
records
are
kept)
is
also
used.
Sites
are
required
to
conduct
VE
on
newly
generated
waste,
on
a
statistically
selected
population
of
waste
containers
examined
through
radiography,
and
on
waste
containers
that
the
site
was
unable
to
characterize
using
either
radiography
and/
or
NDA
due
to
the
presence
of
an
interfering
material,
such
as
lead
shielding.
The
results
of
the
VE
of
the
statistically
selected
population
of
waste
containers
is
used
by
the
site
to
verify
waste
container
determinations
(and
measurements)
made
through
radiography.
The
site
is
required
to
calculate
miscertification
rates
on
an
annual
basis
and,
based
on
these
calculations
(and
estimates
of
the
number
of
waste
containers
to
be
radiographed
in
the
coming
year),
determine
the
required
number
of
waste
containers
to
undergo
29
VE
in
the
following
year.
II.
C.
1
Overview
of
Technical
Elements
EPA
typically
views
actual
radiography
and
VE
activities
during
inspections,
as
well
as
supporting
documentation
and
procedures.
At
a
minimum,
radiography
and
VE
should
provide
the
following:
°
Identification
of
cellulosics,
plastics,
and
rubber,
including
quantities;
°
Identification
of
prohibited
items,
including
liquids;
and
°
Confirmation
of
Summary
Waste
Category
Group
and
Waste
Matrix
Code.
Under
the
CH
TRU
program,
every
retrievably
stored
container
must
be
examined
to
determine
the
cellulosics,
plastics,
rubber
(CPR),
and
prohibited
item
content
using
RTR.
Alternatively,
containers
can
be
examined
either
visually
or
by
a
different
NDE
technology,
such
as
CT
or
digital
radiography
(DR),
if
RTR
is
not
possible.
Newly
generated
wastes
do
not
have
to
be
examined
using
RTR
because
the
packaging
process
would
exclude
the
inclusion
of
prohibited
items.
II.
C.
1.1
RTR
Document
Review
EPA
examines
site
specific
documents
and
information
related
to
any
of
the
following
areas
during
inspections:
°
Replicate
Scans.
The
sites
must
document
that
the
imaging
system
characteristics
of
the
monitoring
system
are
verified
on
a
routine
basis
and
that
independent
replicate
scans
and
replicate
observations
of
the
audio/
video
output
of
the
RTR
process
are
performed
under
uniform
conditions
and
procedures.
Independent
Observations.
The
sites
must
document
that
independent
observations
of
RTR
scans
are
performed
during
each
work
shift.
System
Capabilities.
The
site
must
document
that
its
RTR
system
is
appropriate
and
is
capable
of
characterizing
the
typical
waste
configurations
and
parameters
observed
at
the
site.
Procedures.
The
site
must
have
procedures
for
ensuring
that
the
RTR
system
is
tested,
inspected,
and
maintained
in
accordance
with
manufacturer
instructions.
In
addition,
EPA
expects
the
site's
procedures
to
address
the
following:
The
RTR
system
is
calibrated
through
observation
of
a
test
pattern
at
the
beginning
and
end
of
each
work
shift
(when
operating).
The
RTR
system
must
be
30
able
to
be
adjusted
to
obtain
optimum
contrast
and
resolution
using
a
line
pair
gauge
or
equivalent
device.
Data
management
is
sufficient
to
ensure
that
the
RTR
results
for
every
waste
container
are
documented,
validated,
and
ultimately
verified
by
VE
of
a
randomly
selected
statistical
population
of
waste
containers.
The
RTR
examination
is
captured
on
both
audio/
video
and
documents
the
following
types
of
information
necessary
for
WIPP
WAC
certification:
Item
description
code
(IDC),
TRUCON
code
(Transuranic
Package
Transporter
II
Content
Code),
Presence
or
absence
of
free
liquids,
Content
inventory,
and
Description
of
contents
packaging
materials.
The
following
types
of
information
resulting
from
the
RTR
examination
must
be
recorded:
Waste
container
identification
number;
Date
of
radiography
examination;
TRUCON
code,
IDC,
and
Waste
Matrix
Code,
as
applicable;
Any
changes
made
to
Waste
Matrix
Code;
Presence
or
absence
of
waste
container
liner;
Estimated
inventory
of
waste
container
contents;
Description
of
contents
packaging
materials,
including
the
number
of
layers
of
packaging;
Audio/
videotape
identification
number;
Estimate
of
each
applicable
waste
material
parameter
weight;
Identification
of
quality
control
(QC)
replicate;
and
An
operator/
reviewer
signature
and
date
block.
Explicit
guidance
is
included
to
account
for
materials
that
interfere
with
the
RTR
examination
(e.
g.,
lead
liners,
leaded
gloves,
stabilized
wastes
or
cement,
etc.).
Prohibited
items
must
be
identified
and
procedures
followed
to
ensure
that
the
proper
steps
are
taken
to
isolate
the
particular
waste
container.
Appropriate
measures
can
be
taken
when
conditions
adverse
to
quality
occur.
Reporting.
EPA
examines
the
data
reports
prepared
by
the
site.
Each
data
report
batch
may
not
include
more
than
20
waste
containers.
The
data
reports
must
contain
the
31
following
types
of
records:
RTRdataforms,
RTR
reports,
RTR
videotape,
and
Identification
of
any
nonconformance
reports
(NCRs)
and
variances
pertinent
to
the
data
package.
Data
Quality
Characteristics.
The
site
should
have
a
procedure
for
correctly
calculating
and
reporting
the
relative
percent
difference
between
the
estimated
waste
material
parameter
weights
(as
determined
by
the
RTR
operator)
and
these
same
parameters
as
determined
visually
(i.
e.,
precision).
The
site
must
also
have
a
procedure
for
documenting
the
accuracy
with
which
the
matrix
parameter
category
can
be
determined
through
VE
of
a
randomly
selected
statistical
subpopulation
of
waste
containers.
The
site
must
prepare
and
validate
RTR
data
forms
and
audio/
videotape
for
100
percent
of
the
waste
containers
examined
(i.
e.,
completeness).
The
site
must
also
document
the
comparability
of
the
matrix
parameter
category
determined
by
RTR
with
the
matrix
parameter
category
determined
by
VE
(i.
e.,
comparability).
II.
C.
1.2
Additional
Verification
(RTR)
During
the
course
of
the
on
site
inspection
of
the
radiography
system
and
site
operating
procedures,
the
EPA
inspection
team
both
observes
the
radiography
operation
and
interviews
radiography
operators
and
other
DOE/
contractor
personnel
to
assess
how
well
the
radiography
process
is
being
implemented.
As
part
of
the
EPA
inspection
team's
observation
of
the
radiography
operation,
the
inspection
team
both
views
videotaped
recordings
of
previously
radiographed
waste
containers
and
observes
the
actual
operation
of
the
radiography
equipment.
The
EPA
inspection
team
notes
the
presence
of
required
equipment,
adherence
to
procedures,
and
documentation
of
all
activities.
For
example,
the
EPA
inspection
team
inspects
the
radiography
booth
and
asks
the
radiography
operators
to
point
out
all
of
the
required
radiographic
equipment,
as
described
originally
in
the
TRU
QAPP
(Section
10)
and
Methods
Manual
(CCA
Reference
No.
210),
and
subsequently
in
the
WAP:
A
shielded
room
that
is
properly
ventilated
and
lighted,
An
x
ray
producing
device,
Controls
which
allow
the
operator
to
vary
voltage,
typically
between
150
400
kV,
An
imaging
system
that
typically
includes
a
fluorescent
screen
and
a
low
light
television
camera,
An
enclosure
for
radiation
protection,
A
waste
container
handling
system
(including
a
turntable
dolly
assembly),
32
An
audio/
video
recording
system,
Safety
interlocks,
and
An
operator
control
and
data
acquisition
station.
As
part
of
the
inspection
activities,
the
radiography
operator
is
required
to
demonstrate
the
operation
of
the
radiography
equipment,
including
estimation
of
waste
materials'
parameters
and
volumes,
and
data
entry.
The
EPA
inspection
team
also
interviews
the
radiography
operators
and
DOE
staff/
contractors
involved
in
certifying
and
tracking
operator
training
to
ensure
that
a
formal
operator's
training
program
exists
and
is
completely
implemented.
The
EPA
inspection
team
requires
the
training
staff
and
radiography
operators
to
demonstrate
through
actual
radiography
equipment
operation
and
training
file
documentation
that
operator
training
includes
the
following,
at
a
minimum:
Formal
training
Project
requirements,
State
and
federal
regulations,
Basic
principles
of
radiography,
Radiographic
image
quality,
and
Radiographic
scanning
techniques.
Application
techniques
Radiography
of
waste
forms,
Standards,
codes,
and
procedures
for
radiography,
and
Site
specific
instruction.
On
the
job
training
System
operation,
Identification
of
packaging
configurations,
Identification
of
WMPs,
Weight
and
volume
estimation,
and
Identification
of
prohibited
items.
The
EPA
inspection
team
observes
the
operator's
examination
of
a
radiography
test
drum
(either
in
real
time
or
by
reviewing
videotape)
and
expects
to
see
the
operator
satisfactorily
identify
its
content.
The
EPA
inspection
team
reviews
the
contents
of
the
radiography
test
drum
to
ensure
that
the
following
required
elements
are
present:
33
Aerosol
can
with
puncture,
Horsetail
bag,
Pair
of
coveralls,
Empty
bottle,
Irregular
shaped
pieces
of
wood,
Empty
one
gallon
paint
can,
Full
container,
Aerosol
can
with
fluid,
One
gallon
bottle
with
three
tablespoons
of
fluid,
One
gallon
bottle
with
one
cup
of
fluid
(upside
down),
Leaded
glove
or
leaded
apron,
and
Wrench.
Training
drums
must
contain
all
of
the
required
test
elements.
The
EPA
inspection
team
requests
the
radiography
operator
to
discuss
how
the
site
has
determined
that
the
test
drum
contained
test
elements
that
were
typical
of
what
might
be
encountered
at
the
site
(both
content
and
packaging
density).
EPA
expects
there
to
be
a
process
for
ensuring
that
the
RTR
operators
receive
standardized
training
and
certification,
recertification,
retraining,
and
on
the
job
training
with
oversight
from
appropriately
qualified
RTR
operators.
RTR
operators
must
have
sufficient
experience
to
operate
the
RTR
system.
EPA
expects
RTR
operators
to
be
instructed
in
the
specific
waste
generating
practices
and
typical
packaging
configurations
expected
for
each
matrix
parameter
category
or
IDC.
EPA
inspectors
examine
the
procedures
for
ensuring
that
this
training
occurs,
as
well
as
operator
training/
experience
records
to
ensure
that
the
personnel
operating
the
RTR
system
are
qualified
and
appropriately
trained.
Inspectors
also
interview
the
RTR
operators
and
observes
their
operation
of
the
RTR
system.
EPA
expects
the
generator
sites
to
provide
procedures
regarding
the
operation
of
the
RTR
system,
and
RTR/
VE
records
(see
below)
that
document
that
the
required
technical
elements
are
adequately
addressed
by
these
procedures.
EPA
may
require
the
generator
site
to
provide
RTR
data
packages
and
RTR/
VE
comparison
sheets,
including
calculations
of
miscertification
rates
and
other
information
pertinent
to
making
the
determination
that
the
generator
site
has
a
system
of
controls
in
place
that
adequately
meets
the
requirements
of
§194.24(
c)(
4).
II.
C.
1.3
VE
Document
Review
EPA
examines
VE
documents
and
information
related
to
any
of
the
following
areas
during
inspections:
34
Documentation.
The
VE
procedure
ensures
that
the
inventory
of
unopened
contents
includes
a
description
and
documented
weight
of
all
waste
items,
residual
materials,
poly
liners,
contents
packaging
materials,
and
waste
material
parameters.
Reference
Tables.
The
site's
VE
procedure
has
reference
tables,
updated
as
necessary,
to
facilitate
the
development
of
weight
estimates
and
assignment
of
wastes
to
waste
material
parameters,
also
updated
as
necessary
during
the
process.
The
site
must
establish
standard
nomenclature
and
volumetric
conversion
factors.
VE
Data.
VE
staff
record
a
description
of
the
location,
container,
and
estimated
volume
of
any
detected
liquid.
All
empty
containers
must
be
weighed
and
recorded,
with
the
gross
weight
of
each
container
recorded
on
the
VE
data
form.
The
site
must
also
record
the
total
number
of
bags
or
packages
found
in
each
waste
container.
Replicate
weight
measurements
must
also
be
made.
Miscertification
Rate.
The
site
must
have
a
procedure
to
select
a
random
statistical
sample
of
waste
containers
for
VE
and
correctly
calculate
and
report
an
annual
miscertification
rate.
The
site
may
use
INEEL's
historical
miscertification
rate
of
2
percent
to
calculate
the
number
of
waste
containers
that
must
be
visually
examined
during
the
first
year
of
program
activities.
However,
the
site
must
also
have
a
procedure
for
establishing
a
site
specific
miscertification
rate
that
is
based
on
the
last
12
(or
more)
months
of
certification
activities.
Radiography
Check.
EPA
expects
that
site
procedures
require
the
use
of
data
from
VE
to
check
the
matrix
parameter
category
and
waste
material
parameter
weight
estimates
as
determined
by
radiography.
Replacement
Containers.
The
facility
must
have
a
procedure
for
selecting
replacement
waste
containers.
The
site's
replacement
strategy
should
be
restricted
to
a
waste
stream
or
waste
stream
lot
that,
through
the
random
selection
process,
happened
to
have
container(
s)
identified
for
VE.
The
procedure
must
ensure
that
VE
is
performed
on
the
replacement
container.
Once
containers
have
been
visually
examined,
the
upper
90
percent
confidence
limit
(UCL90
)
for
the
proportion
miscertified
must
be
correctly
calculated.
EPA
expects
the
site
to
use
the
hypergeometric
distribution
for
the
UCL90
calculation.
Data
Management.
The
site
must
have
a
procedure
for
data
management
that
is
sufficient
to
ensure
that
the
VE
results
for
every
waste
container
examined
are
documented
and
validated.
Documentation.
VE
examination
must
be
captured
on
both
audio
and
video
to
document
IDC,
TRUCON
code,
the
presence
or
absence
of
free
liquids
and
other
prohibited
items,
35
content
inventory,
and
a
description
of
contents
packaging
materials.
Data
Reports.
The
site
must
ensure
that
data
reports
are
prepared
on
a
per
batch
basis,
which
includes
no
more
than
20
waste
containers,
and
the
data
reports
must
contain
VE
data
forms,
VE
reports,
VE
videotape(
s),
and
identification
of
any
NCRs
and
variances
pertinent
to
the
data
package.
The
site's
data
reporting
procedures
should
ensure
that
the
following
types
of
information
resulting
from
the
VE
are
recorded:
Waste
container
identification
number,
DateofVE,
TRUCON
code,
IDC,
and
Waste
Matrix
Code,
as
applicable,
Any
changes
made
to
the
Waste
Matrix
Code,
Presence
or
absence
of
waste
container
liner,
Estimated
inventory
of
waste
container
contents,
Description
of
contents
packaging
materials,
including
the
number
of
layers
of
packaging,
Audio/
videotape
identification
number,
Estimate
of
each
applicable
waste
material
parameter
weight,
Identification
of
QC
replicate,
and
Operator/
reviewer
signature
and
date
blocks.
Interfering
Items.
The
site's
VE
procedure
should
provide
explicit
guidance
on
how
to
handle
materials
that
interfere
with
the
examination,
such
as
metal
containers,
discolored
plastic
bags,
stabilized
wastes
or
cement,
etc.
Also,
the
site's
VE
procedure
must
require
that
prohibited
items
be
identified
and
that
the
proper
steps
be
taken
to
isolate
a
waste
container
with
prohibited
items.
Discrepancy
Resolution.
EPA
expects
the
site
to
have
a
procedure
for
resolving
discrepancies
between
VE
QC
checks
and
between
RTR
and
VE
observations,
and
to
ensure
that
appropriate
measures
can
be
taken
when
conditions
adverse
to
quality
occur.
II.
C.
1.4
Additional
Verification
VE
During
the
course
of
the
on
site
inspection
of
VE
activities
and
site
operating
procedures,
the
inspection
team
observes
VE
activities
and
interviews
VE
experts
and
other
personnel
to
assess
how
well
the
VE
process
is
being
implemented.
As
part
of
the
inspection
team's
observation
of
the
VE,
the
inspection
team
views
videotaped
recordings
of
previously
examined
waste
containers
and
observes
the
actual
VE
of
waste
containers
(when
possible).
Inspectors
note
the
presence
of
required
equipment,
adherence
to
procedures,
and
documentation
of
all
activities.
For
example,
the
EPA
inspection
team
inspects
the
VE
glove
box
(or
room)
and
ask
the
36
VE
experts
to
point
out
all
of
the
required
equipment,
as
described
in
DOE's
Method
Manual
(CCA
Reference
No.
210),
as
listed
in
the
following
bullets:
Check
weights
(certified
to
National
Institute
of
Standards
and
Technologies
standards),
Scales,
Torque
wrenches,
Airflow
meters,
Platform
scale,
Empty
55
gallon
drums,
Remote
drum
handler,
Knifes,
scissors,
platform
ladder,
dolly/
drum
mover,
leather
gloves,
plastic
bags,
tape,
towels,
decontamination
solution,
secondary
containment
bags,
permanent
markers,
rubber
and/
or
surgical
gloves,
Video
camera,
Audio
recording
system,
and
Glove
box
or
negative
pressure
containment
area.
The
EPA
inspection
team
also
interviews
the
VE
experts
and
other
personnel
involved
in
certifying
and
tracking
operator
training
to
ensure
that
a
formal
operator's
training
program
exists
and
is
complete.
There
must
be
a
standardized
training
program
for
visual
inspection
examiners
that
includes
both
formal
classroom
and
on
the
job
training
(OJT).
The
program
must
be
specific
to
the
generator
site
and
includes
the
various
waste
configurations
generated/
stored
at
the
site.
The
EPA
inspection
teaminterviews
the
VE
experts
to
determine
whether
(and
the
extent
to
which)
they
have
received
training
on
the
specific
waste
generating
processes,
typical
packaging
configurations,
and
waste
material
parameters
expected
to
be
found
in
each
matrix
parameter
category
at
the
site.
EPA
expects
the
VE
training
program
to
include:
°
Formal
training
Project
requirements,
State
and
federal
regulations,
Application
techniques,
and
Site
specific
instruction.
°
On
the
job
training
Identification
of
packaging
configurations,
Identification
of
waste
material
parameters,
Weight
and
volume
estimation,
and
Identification
of
prohibited
items.
EPA
expects
sites
to
provide
procedures
regarding
the
performance
of
VE.
EPA
also
37
expects
generator
sites
to
provide
VE
data
packages
and
RTR/
VE
comparison
sheets,
including
calculations
of
miscertification
rates
and
other
information
pertinent
to
making
the
determination
that
the
generator
site
has
a
system
of
controls
in
place
that
adequately
meets
the
requirements
of
194.24(
c)(
4).
II.
C.
2
Technical
Description
of
System
or
Measurement
Device(
s)
II.
C.
2.1
Radiography
Radiographic
systems
include
not
only
real
time
systems,
but
new
systems
that
are
currently
being
brought
on
line
at
DOE
sites.
These
new
systems
may
offer
advantages
over
RTR
with
respect
to
system
resolution,
etc.
Real
Time
Radiography
Sites
are
currently
conducting
NDE
examination
of
all
waste
containers
using
standard
radiography
techniques
(i.
e.,
an
x
ray
tube,
an
image
intensifier,
and
a
charge
coupled
device
camera).
As
part
of
the
RTR
process,
the
RTR
operator
(or
drum
handler)
loads
up
to
three
waste
containers
onto
a
rolling
sled
that
is
then
moved
into
the
RTR
vault.
The
drum(
s)
is
placed
on
a
turntable
that
the
operator
uses
to
rotate
the
drum
and
the
x
ray
system
components
automatically
move
up
and
down
to
smoothly
transition
through
the
entire
height
of
the
drum
(with
every
revolution
the
height
of
the
x
ray
system
components
change
to
allow
for
an
automated,
complete
scan
of
the
entire
container
from
top
to
bottom).
Some
sites
do
not
employ
a
turn
table
that
automatically
moves
up
and
down,
but
rely
instead,
on
the
operator
to
manually
adjust
the
height
of
the
drum
manually
to
obtain
a
scan
of
100
percent
of
the
drum's
height.
The
x
ray
producing
device
has
controls
that
allow
the
operator
to
vary
the
voltage,
thereby
controlling
image
quality.
It
is
typically
possible
to
vary
the
voltage,
between
150
to
430
kilovolts
(KV),
to
provide
an
optimum
degree
of
penetration
through
the
waste.
For
example,
high
density
material
should
be
examined
with
the
x
ray
device
set
on
the
maximum
voltage
to
ensure
maximum
penetration
through
the
waste
container.
Low
density
material
should
be
examined
at
lower
voltage
settings
to
improve
contrast
and
image
definition.
The
imaging
system
typically
uses
a
fluorescent
screen
and
a
low
light
television
camera.
To
perform
radiography,
the
waste
container
is
scanned
while
the
operator
views
the
television
screen.
The
RTR
operator
controls
the
entire
process
from
a
remote
operator's
booth
and
the
entire
exam
is
recorded
on
audio/
video
tape
(some
sites
use
optical
disks).
The
operator
then
records
the
data
using
data
sheets;
however,
several
sites
use
automated
data
entry
systems.
For
example,
INEEL
RTR
operators
use
an
automated
data
entry
system,
which
has
a
series
of
screens
designed
to
capture
the
required
information.
The
RTR
examination
results
are
used
by
38
the
site
to
verify
that
the
physical
waste
form
matches
the
waste
stream
description,
to
document
the
waste
matrix
code
group,
to
estimate
waste
material
parameters
and
drum
utilization,
to
confirm
AK,
and
to
identify
prohibited
items.
Sites
also
compare
the
radiography
RTR
examination
results
with
those
obtained
through
VE
to
calculate
miscertification
rates
on
an
annual
basis
and,
based
on
these
calculations
(and
the
expected
number
of
waste
drums
to
be
processed
next
year)
determine
the
required
number
of
waste
containers
to
undergo
VE
in
the
following
year.
II.
C.
2.2
Visual
Examination
Sites
are
currently
conducting
VE
on
a
statistically
selected
subpopulation
of
waste
containers
examined
through
radiography,
and
any
waste
container
that
the
site
was
unable
to
characterize
through
radiography
due
to
the
presence
of
an
interfering
material,
such
as
lead
shielding.
As
part
of
the
VE
process,
the
VE
team
typically
opens
each
waste
container
in
a
specially
designed
glove
box
that
is
approximately
15
feet
long
and
operated
under
a
negativepressure
environment.
At
some
sites,
core
sampling
is
also
conducted
in
this
glove
box.
Although
the
VE
process
is
relatively
straightforward,
it
is
a
physically
demanding
and
intensive
operation
and
typically
consists
of
the
VE
technicians
performing
the
following
steps:
Load
the
waste
drum
at
the
back
end
of
the
glove
box,
Remove
the
drum
lid
and
empty
the
drum's
contents
in
the
middle
portion
of
the
glove
box,
Open
every
individual
waste
package
or
bag,
and
Manually
sort
and
categorize
waste
materials
for
subsequent
weighing
and
repackaging
at
the
front
end
of
the
glove
box.
The
entire
process
is
conducted
under
the
supervision
of
the
VE
expert
(VEE)
and
is
recorded
on
both
audio/
video
tape
and
waste
container
inventory
sheets.
The
VE
results
are
used
by
the
site
to
verify
waste
form,
confirm
and/
or
identify
prohibited
items,
and
verify
drum
utilization
and
waste
material
parameter
estimates
made
through
radiography.
The
VEE
also
assesses
the
need
to
open
individual
bags
or
packages
of
waste.
If
individual
bags/
packages
are
not
opened,
estimated
weights
are
recorded.
Estimated
weights
are
established
through
the
use
of
historically
derived
waste
weight
tables
and
an
estimation
of
the
waste
volumes.
It
may
not
be
possible
to
see
through
inner
bags
because
of
discoloration,
dust,
or
because
inner
containers
are
sealed.
In
these
instances,
documented
AK
can
be
used
to
identify
the
matrix
parameter
category
and
estimated
waste
material
parameter
weights.
If
AK
is
insufficient
for
individual
bags/
packages,
actual
weights
of
waste
items,
residual
materials,
contents
packaging
materials,
or
waste
material
parameters
are
recorded.
The
sites
also
compare
the
VE
data
to
that
obtained
through
radiography
to
calculate
miscertification
rates
on
an
annual
basis
and,
based
on
these
calculations
(and
the
expected
number
of
waste
drums
to
be
processed
next
year),
determine
the
required
number
of
waste
containers
to
undergo
VE
in
the
following
year.
39
II.
C.
3
Effect
of
Waste
Matrix
or
Waste
Type
on
Measurement
As
discussed
previously,
the
RTR
operator
can
vary
the
voltage
to
provide
an
optimum
degree
of
penetration
through
the
waste.
For
example,
high
density
material
needs
to
be
examined
with
the
x
ray
device
set
on
the
maximum
voltage
to
ensure
maximum
penetration
through
the
waste
container.
In
comparison,
low
density
materials
need
to
be
examined
at
lower
voltage
settings
to
improve
contrast
and
image
definition.
For
example,
containers
with
lead
liners
or
containers
filled
with
sludges
or
stabilized
(or
cemented)
wastes
cannot
be
readily
penetrated
by
the
x
ray
energy.
Thus,
containers
with
lead
liners,
or
other
containers
whose
contents
prevent
full
examination,
are
either
repackaged
or
examined
using
VE.
Radiography
systems
also
can
have
difficulty
detecting
cellulosics
in
lead
lined
drums
because
a
higher
energy
x
ray
must
be
used
to
scan
through
the
lead
lining.
The
higher
energy
xray
scans
past
the
cellulosics
as
well.
Similarly,
sites
may
be
unable
to
differentiate
between
cellulosics
and
plastics,
as
low
density
materials
can
appear
very
similar.
Densely
packed
drums
with
highly
heterogeneous
waste
materials
can
be
difficult
to
characterize,
as
can
bottles
and
cans
that
are
completely
filled
with
liquid
(there
is
no
observable
meniscus
during
container
motion).
VE
is
a
physically
demanding
task
and
densely
packed
drums
can
take
a
long
time
to
be
completely
examined;
however,
as
long
as
sufficient
time
and
working
space
are
available
there
should
be
no
reduction
in
data
quality.
Likewise,
waste
containers
packed
with
fine
particles
(e.
g.,
soda
ash,
graphite,
or
incinerator
residue)
can
present
a
housekeeping
problem,
but
also
can
be
examined
as
long
as
sufficient
time
and
working
space
are
available.
Inner
containers
that
are
opaque
or
are
packed
with
sharp
metal
objects
are
challenging
and
must
be
handled
with
care.
Opaque
containers
are
generally
opened,
unless
the
VEE
is
able
to
determine
what
the
contents
of
the
container
are
based
on
AK.
The
handling
of
waste
packages
containing
sharp
metallic
objects
is
minimized
and
often
times
set
aside
for
repackaging
so
as
not
to
present
undue
risks
to
the
VE
personnel.
II.
C.
4
Scope
of
EPA
Approvals
for
Radiography
and
Visual
Examination
All
types
of
CH
TRU
wastes
may
be
examined
using
RTR,
except
for
those
that
are
packed
in
lead
lined
containers
or
have
been
stabilized.
Also,
all
types
of
CH
TRU
wastes
may
be
examined
using
VE,
except
for
those
that
have
been
stabilized.
EPA's
approvals
with
respect
to
RTR
and
VE
have
been
limited
to
date
by
the
scope
of
the
approval
sought
by
the
sites.
Reinspection
would
be
required
with
the
introduction
of
new
systems
(e.
g.,
DR/
CT,
VE
technique),
or
specific
wastes
(e.
g.
RH
TRU
waste,
lead
lined
drums).
40
II.
D
WIPP
Waste
Information
System
and
Data
Validation
To
ensure
that
the
sites
ship
only
waste
that
conforms
with
the
waste
component
requirements
established
by
DOE,
a
system
of
controls
must
be
implemented
that
includes
tracking
of
information
about
waste
destined
for
the
WIPP.
For
this
purpose,
DOE
uses
a
computerized
waste
tracking
system,
the
WIPP
Waste
Information
System
(WWIS).
The
WWIS
is
a
data
transfer
system
whereby
waste
characterization
and
other
information
is
input
electronically
at
generator
sites
and
is
transferred
to
WIPP
prior
to
waste
shipment.
Additionally,
EPA
examines
the
data
validation
and
verification
processes
for
checking
data
ultimately
input
into
the
WWIS.
II.
D.
1
Overview
of
Technical
Elements
When
EPA
conducts
inspections
to
verify
compliance
with
§194.24(
c)(
4),
EPA
reviews
the
WWIS
for
the
following
items:
The
total
quantity
of
waste
(volumetrically);
The
quantity
of
the
important
non
radionuclide
waste
components
for
which
DOE
has
identified
limits;
Radionuclide
activity
for
the
ten
WIPP
radionuclides;
Radionuclide
activity
uncertainty;
Radionuclide
mass;
Radionuclide
mass
uncertainty;
TRU
alpha
activity;
TRU
alpha
activity
uncertainty;
Verification
data;
Verification
method;
Visual
examination
of
container;
WAC
certification
data;
Waste
MatrixCode
(WMC);
and
41
General
location
of
the
waste
in
WIPP.
II.
D.
1.1
Data
Validation/
Verification
and
WWIS
Inspection
Components
EPA
inspects
the
following
components
of
the
systems
of
control
for
tracking
WIPP
waste
parameters:
°
Documentation.
The
inspection
team
first
reviews
site
documentation
including,
but
not
limited
to,
Standard
Operating
Procedures
(SOPs),
Detailed
Technical
Procedures
(DTPs),
and
QAPjPs.
These
are
reviewed
to
ensure
that
technical
elements
are
adequately
addressed,
that
the
applicable
WAC
and
WAP
technical
elements
and
requirements
are
adequately
addressed
in
site
procedures
or
other
documents,
and
that
the
technical
results
of
procedure
implementation
are
adequate.
°
Data
Collection
and
Entry.
EPA
examines
the
overall
data
collection
and
date
entry
process
for
consistent
implementation
to
ensure
data
integrity
and
accuracy.
Procedures
are
also
examined
to
ensure
that
they
are
acceptable
and
allow
for
submitting
data
to
WIPP
via
the
WWIS
system.
°
Data
Validation.
EPA
ensures
that
procedures
exist
and
are
technically
adequate
for
reviewing/
validating
waste
characterization
data
prior
to
submittal
to
WIPP
via
WWIS.
°
Data
Requirements.
The
Agency
also
determines
whether
data
are
collected
and
formatted
consistently
with
requirements
of
WWIS,
including:
Container
number
TRU
alpha
activity
Site
identifier
TRU
alpha
activity
uncertainty
Waste
stream
profile
number
Matrix
code
TRU
alpha
activity
concentration
TRUCON
code
Decay
heat
TRU
alpha
activity
Decay
heat
uncertainty
concentration
uncertainty
Packaging
number
239
Pu
equivalent
activity
Assembly
identifier
239
Pu
fissile
gram
equivalent
Handling
code
239
Pu
fissile
gram
equivalent
Waste
type
code
uncertainty
Radionuclide
name
Packaging
layers
Radionuclide
activity
Alpha
surface
contamination
Radionuclide
activity
uncertainty
Dose
rate
Radionuclide
mass
Sample
identifier
Radionuclide
mass
uncertainty
Sample
type
42
Waste
material
parameter
weight
Sample
date
Radioassay
method
Analyte
Assay
date
Analyte
concentration
Characterization
method
Analyte
detection
method
Characterization
method
date
Shipment
number
°
Data
Security.
Procedures
should
be
in
place
to
ensure
that
data
in
the
system
are
secure.
°
WWIS
Verification.
Procedures
should
be
in
place
to
verify
data
submitted
to
the
WIPP
via
the
WWIS
system.
The
sites
must
provide
any
container
specific
tracking
reports
(e.
g.,
WWIS
Waste
Container
Data
Reports),
data
validation
forms,
and
other
information
as
needed
to
determine
that
the
site
has
a
system
of
controls
in
place
that
adequately
meets
the
requirements
of
§194.24(
c)(
4).
II.
D.
1.2
Demonstration
of
WWIS
Implementation
EPA
inspection
team
observes
a
demonstration
of
data
entry
and
submittal
to
the
WIPP
site
via
the
WWIS
system
and
interviews
system
operators
and
data
tracking/
validation
officials
to
assess
the
extent
to
which
the
specified
processes
are
being
implemented.
The
inspection
team
observes
adherence
to
procedures,
proper
documentation
of
required
data
(e.
g.,
validation
at
the
project
level,
verification
of
data
received
from
the
WWIP
site
after
submittal
of
characterization
data),
and
results
of
system
operation.
No
specific
analytical
equipment
is
required
for
this
process
other
than
the
WWIS
itself
and
any
other
site
specific
data
entry
systems
used
to
convey
site
information
to
the
WWIS,
including
any
computerized
systems
for
implementing
data
validation
procedures.
EPA
expects
the
sites
to
provide
a
demonstration
of
their
data
systems,
the
ability
to
transmit
and
receive
data
from
the
WWIS
system,
and
the
ability
to
verify
that
accurate
data
have
been
input
into
the
WWIS
system.
EPA
inspectors
examine
the
data
system
used
to
collect
waste
characterization
data
to
ensure
that
all
appropriate
data
fields
required
for
entry
into
the
WWIS
are
accounted
for
and
that
the
data
are
transferrable
to
WWIS
either
manually
or
electronically.
Further,
EPA
evaluates
the
quality
of
the
input
data,
by
reviewing
data
packages
at
the
point
of
project
level
data
validation
(the
point
at
which
data
are
input
into
the
WWIS
for
submittal
to
WIPP).
EPA
expects
a
demonstration
of
the
site's
ability
to
ensure
connectivity
with
the
WWIS
and
that
data
can
be
transmitted
via
the
WWIS
to
WIPP
and
received
from
WIPP
as
entered
into
the
site's
individual
data
system.
II.
D.
1.3
Personnel
Qualifications
EPA
checks
that
personnel
conducting
validation/
review
and
verification
and
entry
of
43
waste
characterization
data
into
the
WWIS
data
system
are
qualified
to
enter
data
and
verify
accuracy
of
waste
characterization
data
for
wastes
destined
for
disposal
at
WIPP.
Specifically,
EPA
examines
procedures
for
ensuring
that
training
occurs
and
operator
training/
experience
records
for:
°
Initial
WWIS
orientation
°UsingtheWIPP
Waste
Information
System
User's
Manual
for
Use
by
Shippers/
Generators
(DOE/
CAO
97
2273)
°
Site
specific
procedures
for
manual
or
electronic
data
entry
into
WWIS.
II.
D.
2
Technical
Description
of
Measurement
Device
As
previously
described,
the
WWIS
is
an
electronic
database
that
contains
information
related
to
the
characterization,
certification,
shipment,
and
emplacement
of
TRU
waste
at
the
WIPP.
The
data
are
required
to
ensure
that
waste
destined
for
WIPP
meets
applicable
regulatory
conditions,
including
radionuclide
data
on
CH
and
RH
TRU
waste,
cumulative
activity
of
RH
waste,
and
amount
of
important
waste
material
parameters
(e.
g.,
cellulosics).
Individual
generator
sites
are
responsible
for
inputting
waste
data
into
the
WWIS
system
externally.
Generator
sites
have
developed
their
own
unique
systems
for
collecting
the
information
needed
to
be
transmitted
to
WWIS,
including
worksheets,
electronic
spreadsheets,
and
fully
integrated
electronic
data
systems.
Regardless
of
the
mechanism
for
collecting
data,
each
generator
site
is
responsible
for
verifying
and
validating
all
required
data
prior
to
submittal
to
WIPP
via
the
WWIS
system.
In
the
CCA,
DOE
stated
that
the
WWIS
tracks
waste
components
and
associated
uncertainties
against
their
upper
and
lower
limits
and
provides
notification
before
the
waste
component
limits
are
exceeded,
in
accordance
with
40
CFR
Part
194.24(
e)(
1)
and
(2).
Each
site
has
determined
its
own
approach
for
submitting
TRU
waste
characterization
data
to
WIPP
for
shipments
for
disposal.
In
some
cases,
sites
have
developed
separate
databases
to
track
data
generation,
validation,
and/
or
data
submittal
to
WIPP.
At
other
sites,
the
data
input
system
is
manual,
which
may
result
in
a
higher
degree
of
uncertainty
in
data
quality.
However,
issues
with
respect
to
data
quality
may
also
arise
at
sites
using
electronic
data
collection,
verification,
and
transmittal.
For
example,
EPA
observed
during
an
inspection
at
INEEL
that
personnel
had
the
ability
to
change
data
without
receiving
proper
approval
for
such
changes.
II.
D.
3
Effect
of
Waste
Matrix
or
Waste
Type
on
Measurement
The
WWIS
and
data
validation
programs
at
sites
are
not
impacted
by
waste
type,
with
the
exception
of
RH
TRU
waste.
EPA
determined
in
its
initial
certification
that
DOE
did
not
provide
any
waste
characterization
methods
for
RH
TRU
waste,
nor
was
there
discussion
specific
to
how
44
DOE
will
quantify
the
RH
TRU
waste.
All
of
the
waste
characterization
discussions
in
Chapter
4
of
the
CCA
concern
CH
TRU
waste,
except
for
Chapter
4,
Table
4
13
(p.
4
49),
which
is
entitled
"Applicable
CH
and
RH
TRU
Waste
Component
Characterization
Methods."
Furthermore,
DOE
provided
no
discussion
regarding
the
applicability
of
CH
TRU
waste
characterization
methods
to
RH
TRU
waste.
Therefore,
the
effectiveness
of
existing
WWIS
procedures
and
methods
has
yet
to
be
demonstrated
for
RH
TRU
waste
streams.
II.
D.
4
Scope
of
EPA
Approvals
for
Data
Validation/
Verification
and
the
WWIS
The
range
of
waste
types
that
EPA
may
approve
at
any
given
time
is
not
affected
by
the
WWIS
or
the
data
validation
processes,
with
the
exception
of
RH
TRU
waste
as
described
in
section
D.
3.
To
date,
approvals
have
not
specifically
been
limited
by
waste
type,
although
they
may
be
limited
due
to
other
factors
(e.
g.
NDA).
45
III.
SUMMARY
OF
RESULTS
AND
LESSONS
LEARNED
III.
A
Summary
of
Results
Implementation
of
the
inspection
process
described
in
Sections
I
and
II
has
resulted
in
a
program
whereby
EPA
is
compelled
to
provide
authorizations
that
either
mirror
that
sought
by
the
site
(i.
e.,
for
given
waste
streams
or
Summary
Waste
Category
Groups),
or
is
less
than
that
sought
by
a
site
due
to
system
limitations.
Consequently,
EPA
is
required
to
revisit
sites
multiple
times
as
new
systems,
wastes,
or
other
elements
arise.
Table
2
presents
inspections
performed
by
EPA
to
date
under
the
authority
of
§
194.8(
b)
and
the
scope
of
the
resulting
approvals.
As
shown
in
this
Table,
EPA
has
inspected
7
sites,
ranging
from
one
to
9
times
each.
The
broadest
approval
given
by
EPA
has
been
for
specific
Summary
Waste
Category
Groups
of
Retrievably
Stored
Waste
(i.
e.,
debris
waste
at
RFETS),
while
the
most
limited
approval
was
for
a
single
waste
stream
at
the
SRS,
although
this
limited
approval
was
all
that
SRS
sought
at
the
time
of
the
inspection.
DOE
sites
that
have
been
authorized
by
EPA
to
ship
waste
to
the
WIPP
have
adequate
waste
characterization
programs
overall.
In
some
instances,
EPA
was
unable
to
complete
an
inspection
because
of
the
site's
limited
implementation
of
activities
within
the
scope
of
the
inspection.
46
Table
2
§
194.8(
b)
Inspections
Performed
by
EPA
as
of
January,
2002
Generator
Site
Date
of
Inspection
Type
of
Inspection
Inspection
Scope
Elements
Examined
Scope
of
EPA
Approval
Rocky
Flats
(RFETS)
EPA
RFETS
6.98
8
June
22
25,
1998
194.8
Contact
handled
debris
waste
NDA,
AK,
RTR,
VE,
WWIS/
DV
Characterization
program
was
approved,
with
NDA
approval
limited
to
the
use
of
IQ
3
SGS
and
WM3100
PNC
RFETS
EPA
RFETS
4.99
8
April
27
28,
1999
194.8
Leco
crucibles
and
pyrochemical
salt
NDA,
AK,
VE
Characterization
program
was
approved
and
broadened
to
include
Leco
Crucibles
and
pyrochemical
salt,
with
NDA
approval
expanded
to
include
the
use
of
calorimetry
(CAL/
GAMMA)
RFETS
EPA
RFETS
11.99
8
November
16
18,
1999
194.8
Wet
residue,
dry
residue,
pyrochemical
salts,
incinerator
ash
(including
Leco
crucibles
and
magnesium
oxide
inserts)
NDA/
gravimetric
techniques,
AK,
WWIS/
DV
Characterization
program
was
approved
and
broadened
to
include
wet/
dry
residue,
pyrochemical
salts,
and
incinerator
ash,
with
NDA
approval
expanded
to
include
SGS
Can
Counters,
SGS
Drum
Counters,
and
the
TGS
RFETS
EPA
RFETS
9.00
8
September
18
21,
2000
194.8
Residues
NDA
Characterization
program
was
approved,
with
NDA
approval
expanded
to
include
NMC,
two
new
TGS
CAN
Scanners,
and
a
skid
mounted
Tomographic
Gamma
Can/
Drum
Scanner
RFETS
EPA
RFETS
1.01
8
January
29
February
2,
2001
194.
8
Contact
Handled
Retrievably
Stored
Debris/
Solids
NDA
Inspection
postponed
by
DOE
RFETS
EPA
RFETS
5.01
8
May
14
17,
2001
194.8
Debris
waste
NDA,
WWIS/
DV,
VE,
RTR
Limited
approval
of
SuperHENC,
Building
569
PADC,
Building
569
Tomographic
Gamma
Scanner.
Generator
Site
Date
of
Inspection
Type
of
Inspection
Inspection
Scope
Elements
Examined
Scope
of
EPA
Approval
47
INEEL
EPA
INEEL
7.
98
8
July
28
30,
1998
194.8
Contact
handled
retrievably
stored
debris
waste
generated
at
Rocky
Flats
AK,
NDA,
VE,
RTR,
WWIS/
DV
Limited
characterization
program
was
approved
for
only
inorganic
solids
and
graphite
debris
waste,
with
NDA
limited
to
Canberra
IQ2
and
SWEPP
PAN
INEEL
EPA
INEEL
5.
99
8
May
17
21,
1999
Originally
planned
to
be
194.8,
revised
to
194.24
Scheduled
to
examine
solids,
debris,
soils,
gravels.
AK,
NDA,
RTR,
WWIS/
DV
Elements
of
system
examined
were
inconclusive
with
regard
to
wastes
examined;
EPA
instead
verified
that
previously
approved
system
was
being
adequately
maintained
INEEL
EPA
INEEL
4.
00
8
April
24
28,
2000
194.8
Contact
handled
retrievably
stored
debris
waste
generated
at
Rocky
Flats
NDA,
WWIS/
DV,
VE,
RTR
Characterization
program
was
approved
and
broadened
to
include
all
CH
retrievably
stored
debris
waste
generated
at
Rocky
Flats.
NDA
approval
broadened
to
include
SWEPP
SGRS
and
PAN
systems
INEEL
EPA
INEEL
12.
00
8
December
5
7,
2000
and
one
day
follow
up
on
January
8,
2001
194.
8
Contact
handled
retrievably
stored
homogenous
solids
(S3000)
waste
generated
at
Rocky
Flats
AK,
NDA
Characterization
program
was
approved
and
broadened
to
include
homogenous
solids;
NDA
approval
expanded
to
include
SWEPP
SGRS
and
PAN
systems
re
examined
for
subject
waste
INEEL
EPA
INEEL
7.
01
8
July
25
26,
2001
194.8
Contact
handled
retrievably
stored
homogenous
solids
and
debris
waste
generated
at
Rocky
Flats
NDA
Characterization
program
was
approved;
NDA
system
approval
broadened
to
include
WAGS
INEEL
EPA
INEEL
10.
01
8
October
29
31,
2001
194.
8
Organic
sludge
NDA,
AK
Inspection
postponed
by
DOE
SRS
EPA
SRS
11.
00
8
November
6
17,
2000
194.8
Waste
stream
SR
T001
221F
HET
(a
contact
handled
debris
waste)
AK,
NDA,
VE,
RTR,
WWIS/
DV
Characterization
program
approved
for
one
waste
stream;
NDA
approved
use
of
PAN
and
SGS
systems
Generator
Site
Date
of
Inspection
Type
of
Inspection
Inspection
Scope
Elements
Examined
Scope
of
EPA
Approval
48
SRS
EPA
SRS
9.
01
8
September
24
26,
2001
194.8
Retrievably
stored,
contact
handled
debris
waste
generated
at
SRS
and
limited
to
waste
streams
SRW027
221F
HET
A
HET
E
AK,
NDA,
VE,
RTR,
WWIS/
DV
Inspection
postponed
by
DOE
SRS
EPA
CCP
10.01
8
October
15
19,
2001
194.8
Retrievably
stored,
contact
handled
debris
waste
generated
at
SRS
and
limited
to
waste
streams
SRW027
221F
HET
A
HET
E
AK,
NDA,
VE,
RTR,
WWIS/
DV
All
elements
approved
for
CCP
systems
at
SRS
only
(i.
e.,
CCP
VE,
IPAN/
GEA,
RTR,
WWIS).
SRS
EPA
SRS
12.
01
8
December
12
16,
2001
194.
8
Retrievably
stored,
contact
handled
debris
waste
generated
at
SRS
and
limited
to
waste
streams
SRW027
221F
HET
A
HET
E
AK,
NDA
Report
pending.
LANL
EPA
LANL
6.
99
8
June
14
18,
1999
194.8
Contact
handled,
retrievably
stored
debris
and
solidified
homogenous
solid
wastes
(S5000
and
S3000)
AK,
NDA,
VE,
RTR,
WWIS/
DV
All
elements
approved,
NDA
systems
approved
were
the
TGS
and
HENC
NTS
EPA
NTS
6.99
8
June
7
11,
1999
194.
8
Contact
handled
debris
waste
AK,
NDA,
VE,
RTR,
WWIS/
DV
Waste
characterization
program
did
not
adequately
characterize
the
proposed
waste;
approval
denied.
Hanford
EPA
HAN
1.00
8
January
24
28,
2000
194.
8
Contact
handled
debris
waste
AK,
NDA,
VE,
RTR,
WWIS/
DV
Characterization
program
was
approved
for
contact
handled
debris
waste;
NDA
systems
approved
were
two
GEA
systems
and
one
IPAN
system
Generator
Site
Date
of
Inspection
Type
of
Inspection
Inspection
Scope
Elements
Examined
Scope
of
EPA
Approval
49
Hanford
EPA
HAN
12.01
8
December
17
21,
2001
194.
8
Contact
handled
debris
and
solid
waste
NDA,
VE
Approved
to
characterize
CH
debris
waste
using
the
SGSAS
NDA
system
and
CH
solids
using
VE
process
during
repackaging.
AK
=
Acceptable
Knowledge;
CAL/
GAMMA
=
Calorimetry;
CBFO
=
DOE
Carlsbad
Field
Office;
CCP
=
Centralized
Characterization
Project;
DOE
=
U.
S.
Department
of
Energy;
DR/
CT
=
Digital
Radiography/
Computed
Tomography;
DV
=
Data
Validation;
GEA
=
Gamma
Energy
Assay;
EPA
=
U.
S.
Environmental
Protection
Agency;
HENC
=
High
Efficiency
Neutron
Counter;
HGPe
=
High
Purity
Germanium;
INEEL
=
Idaho
National
Engineering
and
Environmental
Laboratory;
IPAN
=
Imaging
Passive
Active
Counter
;
LANL
=
Los
Alamos
National
Laboratories;
LLNL
=
Lawrence
Livermore
National
Laboratory;
NDA
=
Nondestructive
Assay;
NMC
=
Neutron
Multiplicity
Counter;
NTS
=
Nevada
Test
Site;
PADC
=
Passive
Active
Drum
Counter;
RFETS
=
Rocky
Flats
Environmental
Technology
Site;
RTR
=
Real
Time
Radiography;
SGS
=
Segmented
Gamma
Scanner;
SGSAS
=Segmented
Gamma
Scan
Assay
System
;
SRS
=
Savannah
River
Site;
SWEPP
SGRS
=
Stored
Waste
Examination
Pilot
Plant
Gamma
Ray
Spectrometer
;
SWEPP
PAN
=
Stored
Waste
Examination
Pilot
Plant
Passive
Active
Neutron
Counter
;
TGS
CAN
=
Tomographic
Gamma
Scanner;
TRU
=
Transuranic;
VE
=
Visual
Examination;
WAGS
=
Waste
Assay
Gamma
Spectrometer;
WIPP
=
Waste
Isolation
Pilot
Plan;
WWIS
=
WIPP
Waste
Information
System
50
III.
B
Lessons
Learned
As
a
result
of
our
site
inspection
experience
we
have
identified
a
number
of
general
observations,
or
"lessons
learned,"
related
to
waste
characterization
activities.
°
Implementation
of
waste
characterization
is
not
consistent
across
sites.
Because
one
generator
site
is
capable
of
implementing
an
adequate
program
does
not
mean
that
other
sites
that
use
the
same
equipment
are
also
implementing
an
adequate
program.
For
example,
while
EPA
has
approved
the
use
of
Mobile
Characterization
System
(MCS)
NDA
at
RFETS
(Inspection
EPA
RFETS
6.
98
8;
Air
Docket
A
98
49,
Item
II
A4
4),
EPA
has
not
allowed
the
use
of
the
same
equipment
at
Nevada
Test
Site
due
to
concerns
regarding
quality
control,
measurement
performance,
and
documentation
(Inspection
EPA
6.
99
8;
Air
Docket
A
98
49,
Item
II
A4
9).
°
Sites
have
not
been
able
to
characterize
all
of
their
wastes
at
the
time
of
inspection,
and
approvals
have
been
sought
and
given
based
on
sites'
own
limitations.
For
example,
Savannah
River
Site
originally
sought
and
was
granted
EPA
approval
for
characterization
of
a
single
waste
stream,
and
wrote
procedures
specific
to
that
waste
stream
(Inspection
EPA
SRS
11.
00
8;
Air
Docket
A
98
49,
Item
II
A4
16).
EPA
may
extend
approvals
for
all
waste
types
in
some
areas,
but
in
other
instances
the
limitation
is
warranted.
For
example,
use
of
the
WWIS
for
data
transmittal
is
not
conditioned
on
waste
type,
but
the
method
of
nondestructive
analysis
may
be.
INEEL
initially
developed
procedures
and
characterization
activities
focusing
only
on
inorganic
solids
and
graphite
debris
waste
(Inspection
EPA
INEEL
7.
98
8,
Air
Docket
A
98
49,
Item
II
A4
2).
Consequently,
a
single,
one
size
fits
all
approval
typically
is
not
possible
for
all
waste
types
and
processes
at
a
site.
°
AK
and
NDA
personnel
sometimes
do
not
communicate
adequately,
resulting
in
the
use
of
AK
data
by
NDA
personnel
that
the
AK
personnel
did
not
know
existed.
For
example,
Hanford
Site
NDA
personnel
used
AK
radioassay
information
to
help
determine
isotopic
distribution,
but
this
information
was
not
provided
to
the
AK
personnel,
included
in
the
AK
record,
or
integrated
into
AK
Summary
documentation.
The
AK
NDA
linkage
is
crucial
when
AK
is
used
directly
by
NDA
personnel,
and
EPA
inspectors
examine
AKNDA
interface
issues
as
part
of
the
evaluation
of
the
overall
characterization
program.
Problems
with
the
interface
reflect
a
loss
of
control
over
use
of
important
data
by
a
site.
°
EPA
has
performed
some
inspections
for
which
only
limited
examples
of
procedural
implementation
were
provided
by
the
site.
Only
a
few
waste
containers
were
fully
characterized,
and
it
was
difficult
to
determine
how
the
system
would
function
once
the
process
was
fully
operational.
For
example,
initial
approval
of
the
INEEL
waste
characterization
system
for
solids/
solidified
waste
was
sought
based
on
full
characterization
of
only
a
single
drum
of
waste
(Inspection
EPA
INEEL
12.00
8;
Air
51
Docket
A
98
49,
Item
II
A4
15).
In
such
instances,
it
is
essential
that
rigorous
application
of
controls
be
maintained
after
approval
is
given
and
production
level
characterization
begins.
In
the
case
of
INEEL,
EPA
found
that
this
site
inadvertently
shipped
waste
characterized
using
an
NDA
system
that
was
not
yet
approved
by
EPA,
necessitating
more
inspections
by
EPA.
(Inspection
EPA
INEEL
7.
01
8;
Air
Docket
A98
49,
Item
II
A4
17).
Once
EPA
has
given
the
initial
approval
to
a
site's
overall
program,
it
is
useful
to
perform
"system
check"
inspections
on
a
regular
basis.
The
frequency
of
inspections
may
lessen
as
the
site
demonstrates
institutional
control
over
the
characterization
process.
EPA
should
have
flexibility
in
scheduling
inspections,
and
this
flexibility
should
be
independent
of
DOE's
own
inspection
process.
°
Often
EPA
inspectors
arrive
at
a
site
to
find
that
the
lower
tier
procedures
that
they
reviewed
in
advance
have
been
revised
by
the
site,
in
response
to
earlier
CBFO
inspections
and
surveillances
or
for
other
reasons.
EPA
has
experienced
this
problem
at
every
site.
This
situation
interferes
with
the
smooth
progress
of
the
inspection
plan,
because
inspectors
must
take
the
time
to
compare
the
procedures
and
understand
the
changes
before
proceeding
with
the
substance
of
the
inspection.
°
Consistent
with
40
CFR
194.8(
b),
EPA's
approach
to
site
approvals
has
been
to
authorize
characterization
only
for
certain
waste
streams
or
groupings
of
waste
streams
(i.
e.,
Summary
Waste
Category
Groups).
Consistent
with
its
QA
procedures,
DOE's
approach
has
been
to
certify
sites'
characterization
programs
overall
and
then
authorize
shipment
only
of
waste
streams
presented
by
the
site.
This
difference
in
approach
to
site
approvals/
certification
has
been
confusing
for
DOE
sites,
particularly
during
EPA's
early
inspections
in
1998
and
1999.
52
IV.
SUMMARY
OF
PUBLIC
COMMENTS
ON
EPA
INSPECTIONS
This
section
presents
several
examples
of
the
public
comments
that
EPA
has
received
on
their
inspection
results.
As
of
January
2002,
we
have
published
a
total
of
twenty
one
Federal
Register
notices
related
to
those
inspections.
In
response
to
the
twenty
one
notices,
we
have
received
nine
sets
of
comments.
Of
the
comments
received,
four
were
from
the
Environmental
Evaluation
Group
(or
EEG,
New
Mexico's
independent
scientific
oversight
organization
for
the
WIPP)
and
focused
specifically
on
documents
in
the
docket
[see
Docket
A
98
49,
Category
IIA3
Items
11,
21,
22,
and
31].
EEG
observers
usually
attend
EPA
inspections,
and
so
have
the
opportunity
to
discuss
their
comments
directly
with
DOE
personnel
during
the
inspection.
Other
than
comments
from
EEG,
we
received
five
sets
of
comments.
Four
of
these
sets
were
requests
to
extend
the
public
comment
period,
which
we
did
in
one
instance
[see
Docket
A98
49,
Category
II
A3,
Items
3,
8,
27,
and
30],
and
the
remaining
set
contained
specific
comments
on
documents
in
the
docket
[see
Docket
A
98
49,
Category
II
A3,
Item
29].
We
respond
to
comments
sent
to
the
docket
in
our
inspection
reports,
which
are
filed
in
Docket
A98
49,
Category
II
A4.
Representative
examples
of
comments
are
presented
below.
EPA
INEEL
7.
01
8
(July
25
26,
2001);
Air
Docket
A
98
49,
Item
II
A4
17
EPA
received
two
sets
of
comments
in
EPA
Air
Docket
A
98
49
in
response
to
our
Federal
Register
notice
of
July
13,
2001.
The
comments
are
filed
as
(1)
Item
II
A3
27
and
(2)
IIA3
29.
Examples
of
significant
comments
follows.
Issue
A:
Information
provided
in
Docket
A
98
49
was
not
sufficient
to
enable
the
public
or
EPA
to
reach
conclusions
about
the
compliance
of
the
WAGS
system.
Therefore,
EPA
should
extend
the
public
comment
period.
33.
Based
on
the
documents
in
the
docket,
it
is
impossible
for
EPA
or
the
public
to
know
how
many
drums
were
certified
using
the
WAGS
system
because
none
of
the
documents
in
the
docket
describe
what
characterization
and
quality
assurance
(QA)
procedures
were
used
on
the
1,
917
drums
with
waste
in
the
69
shipments
that
INEEL
made
to
WIPP
between
December
7,
2000
and
June
27,
2001
(INEEL
shipments
KN001201
and
1202,
IN010031
to
010097
WIPP
Waste
Information
System
data).
[1]
34.
The
docket
provides
no
basis
for
EPA,
or
the
public,
to
conclude
that
the
WAGS
System
actually
operated
in
a
manner
equivalent
to
the
SGRS
system
for
any
or
all
of
the
period
that
it
was
being
used
as
part
of
the
waste
characterization
process.
[1]
35.
Neither
EPA,
nor
the
public,
can
conclude
that
the
drums
shipped
to
WIPP
were
adequately
characterized,
so
the
question
of
what
should
now
be
done
with
those
drums
at
53
WIPP
cannot
be
answered
based
on
documents
currently
available
to
the
public.
We
believe
that
EPA
cannot
make
any
decision
about
the
status
of
those
drums
without
adequate
documentation
being
made
available
to
the
public.
[1]
36.
Based
on
the
documents
in
the
docket,
we
cannot
conclude
that
the
WAGS
system
meets
the
quality
assurance
requirements
of
40
CFR
194.8(
a).
[1]
37.
Based
on
the
documents
in
the
docket,
we
also
cannot
conclude
that
the
WAGS
system
meets
the
waste
characterization
requirements
of
40
CFR
194.8(
b).
[1]
38.
The
docket
provides
no
documentation
regarding
how
INEEL
or
EPA
determined
which
drums
were
characterized
using
the
WAGS
system,
how
the
WAGS
system
was
used
and
how
its
use
changed
during
the
time
period
in
question,
as
to
the
nature
of
the
process
knowledge
documentation
for
those
drums,
or
other
relevant
information.
Thus,
based
on
what
is
available
in
the
docket,
the
public
cannot
adequately
comment
on
the
status
of
those
drums,
nor
does
EPA
have
adequate
information
to
make
its
determinations.
[1]
39.
As
specified
in
its
Federal
Register
notice
of
July
13,
2001
(66
Fed.
Reg.
36723),
EPA
is
providing
its
normal
30
day
public
comment
period
on
"waste
characterization
program
documents."
However,
the
current
situation
is
not
normal,
it
is
the
most
complex
yet
faced
by
EPA
involving
a
site's
waste
characterization
program.
In
such
an
abnormal
situation,
a
longer
public
comment
period
is
necessary,
and
it
is
clearly
allowed
by
40
CFR
194.8.
In
addition,
the
fact
that
important
documents
are
not
yet
available
necessitates
an
extension
of
the
public
comment
period
to
allow
public
comment
on
the
appropriate
documentation.
[1]
Response
to
Issue
A:
We
decided
not
to
extend
the
comment
period.
We
believe
that
30
days
was
sufficient
time
to
allow
the
public
to
raise
questions
or
concerns
about
the
WAGS
system,
and
that
the
information
that
we
docketed
was
appropriate,
for
the
reasons
explained
below.
When
we
open
a
comment
period
under
40
CFR
194.8,
the
primary
purpose
of
the
public
comment
period
is
to
allow
the
public
to
provide
potentially
relevant
information
to
EPA
or
to
raise
compliance
concerns
or
questions,
so
that
EPA
is
aware
of
those
concerns
and
questions
and
can
seek
resolution
to
them
prior
to
making
a
final
compliance
decision.
Any
specific
processes
or
waste
streams
about
which
we
are
seeking
public
input
are
defined
in
the
inspection
notice
that
we
provide
in
the
Federal
Register.
As
we
explained
in
our
May
1998
Certification
Decision
(see,
for
example,
EPA
Air
Docket
A
93
02,
Item
V
C
1,
pp.
2
8
to
2
11
and
6
26),
EPA's
compliance
decision
under
194.8
must
be
based
on
our
independent
inspections
of
waste
characterization
processes.
Inspections
involve
review
of
many
different
documents,
interviews
with
staff,
and
on
site
demonstrations,
which
are
then
summarized
and
made
public
in
our
54
inspection
reports.
It
is
neither
possible
nor
appropriate
to
attempt
to
place
all
information
that
may
be
relevant
to
the
scope
of
our
inspection
in
our
docket
before
we
conduct
an
inspection.
We
docketed
key
documents
that
we
determined
were
pertinent
to
the
proposed
WAGS
system.
In
light
of
the
WAGS
related
nonconformance
that
we
identified
in
June
2001
(see
Issue
B
below),
and
in
anticipation
of
public
concern,
we
included
additional
DOE
documents
that
directly
pertained
to
the
nonconformance.
It
was
not
our
expectation
that
the
public
would
be
able
to
reach
conclusions
about
either
the
WAGS
system's
technical
adequacy
or
the
WAGSrelated
nonconformance
based
solely
on
the
docketed
materials.
EPA
makes
the
determination
of
compliance
following
a
site
inspection.
With
regard
to
comment
A.
1,
we
obtained
objective
evidence
during
our
July
2
3
inspection
at
INEEL
that
established
the
status
of
all
drums
characterized
by
the
WAGS
system
and
shipped
to
the
WIPP
site.
This
information
is
contained
in
our
report
for
inspection
no.
EPAINEEL
7.
01
24
(Docket
A
98
49,
Item
II
A1
28).
EPA
RFETS
4.
99
8
(April
27
28,
1999);
Air
Docket
A
98
49,
Item
II
A4
6
EPA
received
one
set
of
comments
from
the
EEG
in
response
to
the
items
announced
in
the
Federal
Register
on
March
25,
1999
(64
FR
14418).
The
letter
from
EEG,
dated
April
23,
1999,
may
be
found
in
EPA
Air
Docket
A
98
49,
Item
II
A3
11.
Below
are
some
examples
of
significant
issues
raised
in
EEG's
letter
and
EPA's
response
to
those
issues.
EPA
inspectors
discussed
some
of
the
issues
with
DOE
Carlsbad
Field
Office
(CAO)
personnel
(Sam
Vega,
Van
Bynum,
and
Mark
Doherty)
and
RFETS
personnel
(Gerald
O'Leary
and
Mark
Castagneri)
during
the
inspection,
in
the
presence
of
Ben
Walker
of
EEG.
EEG
Issue
D:
Sites
such
as
RFETS
must
meet
requirements
for
certain
waste
material
parameters
that
have
not
been
shown
to
affect
the
WIPP's
performance.
RFETS
should
consider
the
relative
importance
of
waste
material
parameters.
1.
The
RFETS
QAPjP
follows
the
CAO's
Transuranic
Waste
Characterization
Quality
Assurance
Program
Plan
(TRU
Waste
QAPP,
CAO
94
1010,
Revision
0)
in
continuing
to
consideralloftheTWBIRwastematerialparametersequally...[
TheRFETSQAPjP],
and
the
overall
RFETS
TRU
waste
program,
should
develop
training
and
awareness
of
the
relative
importance
of
obtaining
defensible
measurements
for
the
two
types
of
waste
material
parameters
[i.
e.,
cellulosics/
plastics/
rubbers
and
ferrous
metals]
that
have
been
shown
to
be
important
to
containment
of
waste
in
the
repository.
EPA's
Response
toIssue
D:
This
comment
suggests
that,
by
treating
"all
of
the
TWBIR
waste
material
parameters
55
equally,"
RFETS
(and
DOE
generally)
may
be
compromising
in
some
fashion
the
analysis
of
waste
parameters
that
are
central
to
compliance
with
EPA's
disposal
regulations.
EPA
did
not
find
evidence
during
the
inspection
to
support
the
claim
that
RFETS
is
not
properly
accounting
for
the
important
waste
parameters.
As
for
other
parameters,
EPA
does
not
have
a
basis
to
require
programmatic
changes
in
the
WIPP
project
unless
they
are
shown
to
be
necessary
for
compliance
with
our
regulations.
EEG
Issue
N:
The
docketed
items
were
well
done
but
may
be
insufficient
for
assessing
RFETS
compliance.
1.
[EEG's]
comments...
shouldbeconsideredasdescribingdeviationsinwhat,
for
themost
part,
appears
to
be
a
very
well
planned
program
adequate
to
meet
the
EPA's
waste
characterization
planning
requirements
specified
in
40
CFR
194.8...
TheEEGdoes,
however,
point
out
that
documentation
the
EPA
may
need
for
thorough
analysis
of
RFETS
compliance
with
40
CFR
194
may
not
be
covered
by
the
documents
provided
to
the
WIPP
docket
for
public
review.
EPA's
Response
toIssue
N:
EPA
agrees
that
the
RFETS
TRU
Waste
Management
Manual
and
Quality
Assurance
Project
Plan
are
well
prepared
documents.
EPA
cannot
rely
solely
on
such
documents,
however,
to
evaluate
transuranic
waste
sites'
quality
assurance
and
waste
characterization
programs.
As
we
have
noted
elsewhere,
inspections
and
inspections
are
appropriate
mechanisms
for
verifying
compliance
with
Conditions
2
and
3
of
our
certification
of
the
WIPP
(see,
for
example,
63
FR
27359).
Prior
to,
during,
and
after
inspections
EPA
may
review
a
wide
variety
of
procedures,
records,
and
data
in
order
to
reach
a
determination
that
the
programs
under
review
are
adequately
established
and
executed.
EPA
requires
DOE
to
submit
a
site's
top
governing
documents
prior
to
an
inspection
to
afford
the
public
an
opportunity
to
comment
on
the
site's
programs
and
to
raise
issues
that
the
Agency
should
consider
in
deciding
whether
or
not
to
approve
those
programs.
56
V.
CONCLUSIONS
EPA's
inspection
process
examines
the
technical
elements
important
to
demonstrating
compliance
with
40
CFR
194.24
waste
characterization
systems
of
control.
EPA
inspectors
examine
Acceptable
Knowledge
(i.
e.,
the
historical
documentation
that
provides
radionuclide,
waste
material
parameter,
and
other
information),
Nondestructive
Assay
(for
radionuclide
quantifications),
Visual
Examination/
Radiography
(to
assess
physical
waste
contents),
and
data
transfer
and
data
validation.
Evaluation
of
these
technical
elements
is
sufficiently
comprehensive
to
assess
the
technical
adequacy
of
the
system
of
controls
for
waste
characterization.
Inspections
conducted
to
date
have
demonstrated
that
the
application
of
technical
elements
listed
above
varies
considerably
from
site
to
site.
The
regulatory
language
governing
site
inspections
has
led
EPA
to
respond
to
issues
involving
one
or
more
technical
elements
by
restricting
the
scope
of
site
approval.
As
a
result,
EPA
inspectors
must
return
to
an
approved
site
if
the
site
seeks
to
ship
additional
waste
streams,
use
equipment
not
previously
inspected,
or
make
significant
changes
to
procedures
or
methods
for
waste
characterization.
57
REFERENCES
EPA
1994.
U.
S.
Environmental
Protection
Agency.
Waste
Analysis
at
Facilities
that
Generate,
Treat,
Store,
and
Dispose
of
Hazardous
Waste.
EPA
Office
of
Solid
Waste.
Directive
Number
9938.4
03.
April
26,
1994.
EPA/
NRC
1997.
U.
S.
Environmental
Protection
Agecy
&
U.
S.
Nuclear
Regulatory
Commission.
Joint
NRC/
EPA
Guidance
on
Testing
Requirements
for
Mixed
Radioactive
and
Hazardous
Waste.
62
FR
62079
62094.
November
20,
1997.
| epa | 2024-06-07T20:31:39.810918 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0007-0001/content.txt"
} |
EPA-HQ-OAR-2002-0007-0002 | Supporting & Related Material | "2002-07-23T04:00:00" | null | PART
194—
CRITERIA
FOR
THE
CERTIFICATION
AND
RE
CERTIFICATION
OF
THE
WASTE
ISOLATION
PILOT
PLANT'S
COMPLIANCE
WITH
THE
40
CFR
PART
191
DISPOSAL
REGULATIONS
§
194.2
Definitions.
Acceptable
knowledge
means
any
information
about
the
process
used
to
generate
waste,
material
inputs
to
the
process,
and
the
time
period
during
which
the
waste
was
generated,
as
well
as
data
resulting
from
the
analysis
of
waste,
conducted
prior
to
or
separate
from
the
waste
certification
process
authorized
by
EPA's
Certification
Decision,
to
show
compliance
with
Condition
3
of
the
certification
decision
(
Appendix
A
of
this
part).
Minor
alternative
provision
means
an
alternative
provision
to
the
Compliance
Criteria
that
clarifies
a
regulatory
provision,
or
does
not
substantively
alter
the
existing
regulatory
requirements.
§
194.6
Alternative
provisions.
The
Administrator
may,
by
rule
pursuant
to
5
U.
S.
C.
553,
substitute
for
any
of
the
provisions
of
this
part
alternative
provisions,
or
minor
alternative
provisions,
in
accordance
with
the
following
procedures:
(a)
Alternative
provisions
may
be
substituted
after:
(1)
Alternative
procedures
have
been
proposed
for
public
comment
in
the
Federal
Register
together
with
information
describing
how
the
alternative
provisions
comport
with
the
disposal
regulations,
the
reasons
why
the
existing
provisions
of
this
part
appear
inappropriate,
and
the
costs,
risks
and
benefits
of
compliance
in
accordance
with
the
alternative
provisions;
(2)
A
public
comment
period
of
at
least
120
days
has
been
completed
and
public
hearings
have
been
held
in
New
Mexico;
(3)
The
public
comments
received
have
been
fully
considered;
and
(4)
A
notice
of
final
rulemaking
is
published
in
the
Federal
Register.
(b)
Minor
alternative
provisions
may
be
substituted
after:
(1)
The
minor
alternative
provisions
have
been
proposed
for
public
comment
in
the
Federal
Register
together
with
information
describing
how
the
alternative
minor
revision
or
update
comport
with
the
disposal
regulations,
the
reasons
why
the
existing
regulation
of
this
part
requires
the
minor
revision
or
update,
and
the
benefit
of
compliance
in
accordance
with
the
alternative
minor
revision
or
update;
(2)
A
public
comment
period
of
at
least
30
days
have
been
completed
for
the
minor
revisions
or
updates
and
the
public
comments
received
have
been
fully
considered;
(3)
A
notice
of
final
rulemaking
is
published
in
the
Federal
Register
for
the
minor
revisions
or
updates.
§
194.8
Approval
Process
for
Waste
Shipment
from
Waste
Generator
Sites
for
Disposal
at
the
WIPP.
(b)
Waste
Characterization
Programs
at
Transuranic
Waste
Sites.
The
Agency
will
establish
compliance
with
Condition
3
of
the
certification
using
the
process
set
forth
below.
(1)
DOE
will
implement
waste
characterization
programs
and
processes
in
accordance
with
§
194.24(
c)(
4)
to
confirm
that
the
total
amount
of
each
waste
component
that
will
be
emplaced
in
the
disposal
system
will
not
exceed
the
upper
limiting
value
or
fall
below
the
lower
limiting
value
described
in
the
introductory
text
of
paragraph
(c)
of
§
194.24.
Waste
characterization
processes
will
include
the
collection
and
use
of
acceptable
knowledge;
destructive
and/
or
nondestructive
techniques
for
identifying
and
measuring
waste
components;
and
the
validation,
control,
and
transmittal
to
the
WIPP
Waste
Information
System
database
of
waste
characterization
data,
in
accordance
with
§
194.24(
c)(
4).
(2)
The
Agency
will
verify
the
compliance
of
waste
characterization
programs
and
processes
identified
in
paragraph
(b)(
1)
of
this
section
using
the
process
set
forth
below.
(i)
DOE
will
notify
EPA
by
letter
that
a
transuranic
waste
site
is
prepared
to
ship
waste
to
the
WIPP
and
has
established
adequate
waste
characterization
processes
and
programs.
DOE
also
will
provide
the
relevant
waste
characterization
program
plans
and
documentation.
EPA
may
request
additional
information
from
DOE.
(ii)
EPA
will
conduct
a
baseline
inspection
at
the
site
to
verify
that
adequate
waste
characterization
program
plans
and
technical
procedures
have
been
established,
and
that
those
plans
and
procedures
are
effectively
implemented.
The
inspection
will
include
a
demonstration
or
test
by
the
site
of
the
waste
characterization
processes
identified
in
paragraph
(b)(
1)
of
this
section.
If
an
inspection
does
not
lead
to
approval,
we
will
a
send
an
inspection
report
to
DOE
identifying
deficiencies
and
place
the
report
in
the
public
docket
described
in
§
194.67.
More
than
one
inspection
may
be
necessary
to
resolve
compliance
issues.
(iii)
The
Agency
will
announce
in
the
Federal
Register
a
proposed
Baseline
Compliance
Decision
to
accept
the
site's
compliance
with
§
194.24(
c)(
4).
In
the
notice,
we
will
solicit
public
comment
on
the
relevant
inspection
report(
s)
and
any
supporting
materials,
which
will
be
placed
in
the
public
docket
described
in
§
194.67.
The
proposal
will
describe
any
limitations
on
approved
waste
streams
or
waste
characterization
processes
and
identify
tier
assignments
for
the
site's
reporting
of
changes
to
the
approved
waste
characterization
processes
that
we
deem
necessary
in
light
of
the
site's
demonstrated
capabilities
at
the
time
of
our
inspection(
s).
(iv)
Our
written
decision
regarding
compliance
with
the
requirements
for
waste
characterization
programs
and
processes
described
in
paragraph
(b)(
1)
of
this
section
will
be
conveyed
in
a
letter
from
the
Administrator's
authorized
representative
to
DOE.
EPA
will
not
issue
a
compliance
decision
until
after
the
end
of
the
public
comment
period
described
in
paragraph
(b)(
2)(
iii)
of
this
section.
EPA's
compliance
decision
will
respond
to
significant
and
timely
received
comments.
A
copy
of
our
compliance
decision
will
be
placed
in
the
public
docket
described
in
§
194.67.
DOE
will
comply
with
any
reporting
requirements
identified
in
the
compliance
decision
and
the
accompanying
inspection
report.
(3)
Subsequent
to
any
positive
determination
of
compliance
as
described
in
paragraph
(b)(
2)(
iv)
of
this
section,
the
Agency
intends
to
conduct
inspections,
in
accordance
with
§
194.24(
h),
to
confirm
the
continued
compliance
of
approved
waste
characterization
programs
and
processes
at
transuranic
waste
sites.
EPA
will
make
the
results
of
these
inspections
available
to
the
public
in
the
dockets
described
in
§
194.67.
(i)
If
the
Agency
determines,
at
a
subsequent
inspection
of
an
approved
transuranic
waste
site,
that
waste
characterization
programs
or
processes
are
not
adequately
established
or
implemented,
then
we
may
suspend
shipments
and
disposal
of
affected
and
potentially
affected
waste
streams,
or
take
other
action
in
accordance
with
§§
194.4(
b)(
1)
and
(2),
until
we
determine
that
the
deficiencies
have
been
adequately
resolved.
(ii)
[Reserved]
§
194.12
Submission
of
compliance
applications.
Unless
otherwise
specified
by
the
Administrator
or
the
Administrator's
authorized
representative,
5
copies
of
any
compliance
application(
s),
any
accompanying
materials,
and
any
amendments
thereto
shall
be
submitted
in
a
printed
form
to
the
Administrator's
authorized
representative.
In
addition,
DOE
shall
submit
10
copies
of
the
complete
application
in
alternative
format
(e.
g.,
compact
disk)
or
other
approved
format,
as
specified
by
the
Administrator's
authorized
representative.
§
194.13
Submission
of
reference
materials.
Information
may
be
included
by
reference
into
compliance
applications(
s),
provided
that
the
references
are
clear
specific
and
that
unless,
otherwise
specified
by
the
Administrator
or
the
Administrator's
authorized
representative,
5
copies
of
reference
information
are
submitted
to
the
Administrator's
authorized
representative.
Reference
materials
that
are
widely
available
in
standard
text
books
or
reference
books
need
not
to
be
submitted.
Whenever
possible,
DOE
shall
submit
10
copies
of
reference
materials
in
alternative
format
(e.
g.,
compact
disk)
or
other
approved
format,
as
specified
by
the
Administrator's
authorized
representative.
§
194.24
Waste
characterization.
(c)(
3)
Provide
information
that
demonstrates
that
the
use
of
acceptable
knowledge
to
quantify
components
in
waste
for
disposal
conforms
with
the
quality
assurance
requirements
of
§
194.22.
| epa | 2024-06-07T20:31:39.831498 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0007-0002/content.txt"
} |
EPA-HQ-OAR-2002-0021-0001 | Proposed Rule | "2002-07-30T04:00:00" | National Emission Standards for Hazardous Air Pollutants: Site Remediation [A-99-20-III-A-1] | Tuesday,
July
30,
2002
Part
II
Environmental
Protection
Agency
40
CFR
Part
63
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Site
Remediation;
Proposed
Rule
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Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[FRL–
7241–
6]
RIN
2060–
AH41
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Site
Remediation
AGENCY:
Environmental
Protection
Agency
(EPA).
ACTION:
Proposed
rule.
SUMMARY:
This
action
proposes
National
Emission
Standards
for
Hazardous
Air
Pollutants
(NESHAP)
under
the
authority
of
section
112
of
the
Clean
Air
Act
(CAA)
for
the
site
remediation
source
category.
The
EPA
has
determined
that
site
remediation
activities
can
be
major
sources
of
organic
hazardous
air
pollutants
(HAP)
(including
benzene,
ethyl
benzene,
toluene,
vinyl
chloride,
xylenes)
and
other
volatile
organic
compounds
(VOC).
The
range
of
potential
human
health
effects
associated
with
exposure
to
these
organic
HAP
and
VOC
include
cancer,
aplastic
anemia,
upper
respiratory
tract
irritation,
liver
damage,
and
neurotoxic
effects
(e.
g.,
headache,
dizziness,
nausea,
tremors).
The
proposed
rule
would
implement
section
112(
d)
of
the
CAA
by
requiring
those
affected
site
remediation
activities
to
meet
emissions
limitations,
operating
limit,
and
work
practice
standards
reflecting
the
application
of
the
maximum
achievable
control
technology
(MACT).
When
implemented,
we
estimate
that
the
proposed
rule
would
reduce
annual
regulated
HAP
emissions
from
the
source
category
by
approximately
50
percent
or
570
megagrams
per
year
(Mg/
yr)
(630
tons
per
year
(tpy))
and
reduce
nationwide
VOC
emissions
by
3,680
Mg/
yr
(4,050
tpy).
DATES:
Comments.
Submit
comments
on
or
before
September
30,
2002.
Public
Hearing.
If
anyone
contacts
the
EPA
requesting
to
speak
at
a
public
hearing
by
September
19,
2002,
a
public
hearing
will
be
held
on
August
27,
2002.
ADDRESSES:
Comments.
By
U.
S.
Postal
Service,
send
comments
(in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(6102),
Attention
Docket
Number
A–
99–
20,
U.
S.
EPA,
1200
Pennsylvania
Avenue,
NW,
Washington,
DC
20460.
In
person
or
by
courier,
deliver
comments
(in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(6102),
Attention
Docket
Number
A–
99–
20,
U.
S.
EPA,
401
M
Street,
SW,
Washington,
D.
C.
20460.
The
EPA
requests
that
a
separate
copy
also
be
sent
to
the
contact
person
listed
below
(see
FOR
FURTHER
INFORMATION
CONTACT).
Public
Hearing.
If
a
public
hearing
is
held,
it
will
be
begin
at
10:
00
a.
m.
and
will
be
held
at
the
new
EPA
facility
complex
in
Research
Triangle
Park,
North
Carolina,
or
at
an
alternate
site
nearby.
You
should
contact
Ms.
JoLynn
Collins,
Waste
and
Chemical
Processes
Group,
Emission
Standards
Division,
U.
S.
EPA
(C439–
03),
Research
Triangle
Park,
NC
27711,
telephone
(919)
541–
5671
to
request
a
public
hearing,
to
request
to
speak
at
a
public
hearing,
or
to
find
out
if
a
hearing
will
be
held.
Docket.
Docket
No.
A–
99–
20
contains
supporting
information
used
in
developing
the
standards.
The
docket
is
located
at
the
U.
S.
EPA,
401
M
Street,
SW,
Washington,
DC
20460,
in
Room
M–
1500,
Waterside
Mall
(ground
floor),
and
may
be
inspected
from
8:
30
a.
m.
to
5:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
Copies
of
docket
materials
may
be
obtained
by
request
from
the
Air
Docket
by
calling
(202)
260–
7548.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.
FOR
FURTHER
INFORMATION
CONTACT:
Mr.
Greg
Nizich,
Waste
and
Chemical
Processes
Group,
Emission
Standards
Division
(C439–
03),
U.
S.
EPA,
Research
Triangle
Park,
NC
27711,
telephone
number
(919)
541–
3078,
facsimile
number
(919)
541–
0246,
electronic
mail
address
``
nizich.
greg@
epa.
gov''.
SUPPLEMENTARY
INFORMATION:
Comments.
Comments
and
data
may
be
submitted
by
electronic
mail
(e
mail)
to:
``
a
and
r
docket@
epa.
gov.
''
Electronic
comments
must
be
submitted
as
an
ASCII
file
to
avoid
the
use
of
special
characters
and
encryption
problems.
Comments
will
also
be
accepted
on
disks
in
WordPerfect
file
format.
All
comments
and
data
submitted
in
electronic
form
must
note
the
docket
number:
A–
99–
20.
No
confidential
business
information
(CBI)
should
be
submitted
by
e
mail.
Electronic
comments
may
be
filed
online
at
many
Federal
Depository
libraries.
Commenters
wishing
to
submit
proprietary
information
for
consideration
must
clearly
distinguish
such
information
from
other
comments
and
clearly
label
it
as
CBI.
Send
submissions
containing
such
proprietary
information
directly
to
the
following
address,
and
not
to
the
public
docket,
to
ensure
that
proprietary
information
is
not
inadvertently
placed
in
the
docket:
Attention
Mr.
Greg
Nizich,
c/
o
OAQPS
Document
Control
Officer,
U.
S.
EPA
(C404–
02),
RTP,
NC
27711.
The
EPA
will
disclose
information
identified
as
CBI
only
to
the
extent
allowed
by
the
procedures
set
forth
in
40
CFR
part
2.
If
no
claim
of
confidentiality
accompanies
a
submission
when
it
is
received
by
the
EPA,
the
information
may
be
made
available
to
the
public
without
further
notice
to
the
commenter.
Public
Hearing.
Persons
interested
in
presenting
oral
testimony
or
inquiring
whether
a
hearing
is
to
be
held
should
contact
Ms.
JoLynn
Collins
of
the
EPA
at
(919)
541–
5671
at
least
2
days
before
the
public
hearing.
Persons
interested
in
attending
the
public
hearing
must
also
call
Ms.
Collins
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
the
proposed
standards.
Docket.
The
docket
is
an
organized
and
complete
file
of
all
the
information
considered
by
the
EPA
in
the
development
of
the
proposed
rule.
The
docket
is
a
dynamic
file
because
material
is
added
throughout
the
rulemaking
process.
The
docketing
system
is
intended
to
allow
members
of
the
public
and
potentially
affected
industries
to
readily
identify
and
locate
documents
so
that
they
can
effectively
participate
in
the
rulemaking
process.
Along
with
the
proposed
and
promulgated
standards
and
their
preambles,
the
contents
of
the
docket
will
serve
as
the
record
in
the
case
of
judicial
review.
(See
section
307(
d)(
7)(
A)
of
the
CAA.)
The
regulatory
text
and
other
materials
related
to
the
proposed
rule
are
available
for
review
in
the
docket,
or
copies
may
be
mailed
on
request
from
the
Air
Docket
by
calling
(202)
260–
7548.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.
Worldwide
Web
(WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
the
proposed
rule
is
also
available
on
the
WWW
through
the
Technology
Transfer
Network
(TTN).
Following
signature,
a
copy
of
the
proposed
rule
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules
at
the
following
address:
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(919)
541–
5384.
Background
Information.
The
background
information
for
the
proposed
rule
is
not
contained
in
a
formal
background
information
document.
Background
information
we
used
in
developing
the
proposed
rule
is
presented
in
technical
memoranda
that
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
we
have
included
in
Docket
No.
A–
99–
20.
Regulated
Entities.
Categories
and
entities
potentially
regulated
by
this
action
include:
Category
NAICS*
Examples
of
regulated
entities
Industry
......................................
325211
325192
325188
32411
49311
49319
48611
42269
42271
Site
remediation
activities
at
businesses
at
which
organic
materials
currently
are
or
have
been
in
the
past
stored,
processed,
treated,
or
otherwise
managed
at
the
facility.
These
facilities
include
organic
liquid
storage
terminals,
petroleum
refineries,
chemical
manufacturing
facilities,
and
other
manufacturing
facilities
with
collocated
site
remediation
activities.
Federal
Government
..................
................
Federal
agency
facilities
that
conduct
site
remediation
activities.
*
North
American
Industry
Classification
System
(NAICS)
code.
Representative
industrial
codes
at
which
site
remediation
activities
have
been
or
are
currently
conducted
at
some
but
not
all
facilities
under
a
given
code.
The
list
is
not
necessarily
comprehensive
as
to
the
types
of
facilities
at
which
a
site
remediation
cleanup
may
potentially
be
required
either
now
or
in
the
future.
This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
This
table
lists
the
types
of
entities
that
we
are
now
aware
could
potentially
be
regulated
by
this
action.
A
comprehensive
list
of
North
American
Industry
Classification
System
(NAICS)
codes
cannot
be
compiled
for
businesses
or
facilities
potentially
regulated
by
the
proposed
rule
due
to
the
nature
of
activities
regulated
by
the
source
category.
The
industrial
code
alone
for
a
given
facility
does
not
determine
whether
the
facility
is
or
is
not
potentially
subject
to
the
proposed
rule.
The
proposed
rule
may
be
applicable
to
any
type
of
business
or
facility
at
which
a
site
remediation
is
conducted
to
clean
up
media
contaminated
with
organic
HAP
and
other
hazardous
material.
Thus,
for
many
businesses
and
facilities
subject
to
the
proposed
rule,
the
regulated
sources
(i.
e.,
the
site
remediation
activities)
are
not
the
predominant
activity,
process,
operation,
or
service
conducted
at
the
facility.
In
these
cases,
the
industrial
code
indicates
a
primary
product
produced
or
service
provided
at
the
facility
rather
than
the
presence
of
a
site
remediation
performed
to
support
the
predominant
function
of
the
facility.
For
example,
NAICS
code
classifications
where
site
remediation
activities
are
currently
being
performed
at
some
but
not
all
facilities
include,
but
are
not
limited
to,
petroleum
refineries
(NAICS
code
32411),
industrial
organic
chemical
manufacturing
(NAICS
code
3251xx)
and
plastic
materials
and
synthetics
manufacturing
(NAICS
code
3252xx).
However,
we
are
also
aware
of
site
remediation
activities
potentially
subject
to
the
proposed
rule
being
performed
at
facilities
listed
under
NAICS
codes
for
refuse
systems,
waste
management,
business
services,
miscellaneous
services,
and
nonclassifiable.
To
determine
whether
your
facility
is
regulated
by
the
action,
you
should
carefully
examine
the
applicability
criteria
in
the
proposed
rule.
If
you
have
questions
regarding
the
applicability
of
the
proposed
rule
to
a
particular
entity,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section
of
this
document.
Outline.
The
following
outline
is
provided
to
assist
you
in
reading
this
preamble.
I.
Background
A.
What
is
the
source
of
authority
for
development
of
the
proposed
rule?
B.
What
is
a
site
remediation?
C.
Why
is
site
remediation
a
unique
NESHAP
source
category?
D.
What
are
the
sources
of
organic
HAP
emissions
from
site
remediation
activities?
E.
What
are
the
potential
health
effects
associated
with
organic
HAP
emitted
from
site
remediation
activities?
F.
What
is
the
relationship
of
the
proposed
rule
to
other
EPA
regulatory
actions
affecting
site
remediation
activities?
G.
What
criteria
are
used
in
the
development
of
NESHAP?
II.
Summary
of
the
Proposed
Rule
A.
Who
is
affected
by
the
proposed
rule?
B.
What
are
the
affected
sources?
C.
What
are
the
standards
for
process
vents?
D.
What
are
the
standards
for
remediation
material
management
units?
E.
What
are
the
standards
for
equipment
leaks?
F.
What
are
requirements
for
remediation
material
sent
off
site?
G.
What
are
the
general
compliance
requirements?
H.
What
are
the
testing
and
initial
compliance
requirements?
I.
What
are
the
continuous
compliance
provisions?
J.
What
are
the
notification,
recordkeeping,
and
reporting
requirements?
K.
What
are
the
implications
of
this
NESHAP
for
Clean
Air
Act
title
V
requirements?
L.
What
are
the
implications
of
this
NESHAP
for
Clean
Air
Act
New
Source
Review
Requirements?
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
What
is
the
scope
of
the
source
category
to
be
regulated?
B.
How
did
we
select
the
pollutants
to
be
regulated?
C.
How
did
we
select
the
affected
source
to
be
regulated?
D.
How
did
we
determine
MACT
for
the
affected
sources?
E.
How
did
we
select
the
format
of
the
proposed
standards?
F.
How
did
we
select
the
testing
and
initial
compliance
requirements?
G.
How
did
we
select
the
continuous
compliance
requirements?
H.
How
did
we
select
the
notification,
recordkeeping,
and
reporting
requirements?
IV.
Summary
of
Environmental,
Energy,
and
Economic
Impacts
A.
What
are
the
emissions
reductions?
B.
What
are
the
cost
impacts?
C.
What
are
the
economic
impacts?
D.
What
are
the
non
air
quality
health,
environmental,
and
energy
impacts?
V.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Executive
Order
13132,
Federalism
C.
Executive
Order
13175,
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
F.
Unfunded
Mandates
Reform
Act
of
1995
G.
Regulatory
Flexibility
Act
(RFA)
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(SBREFA),
5
U.
S.
C.
601
et
seq.
H.
Paperwork
Reduction
Act
I.
National
Technology
Transfer
and
Advancement
Act
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
I.
Background
A.
What
Is
the
Source
of
Authority
for
Development
of
the
Proposed
Rule?
Section
112
of
the
CAA
requires
us
to
list
categories
and
subcategories
of
major
sources
and
area
sources
of
HAP
and
to
establish
NESHAP
for
the
listed
source
categories
and
subcategories.
The
category
of
major
sources
covered
by
today's
proposed
rule
was
listed
on
July
16,
1992
(57
FR
31576).
Major
sources
of
HAP
are
defined
by
section
112
of
the
CAA
to
be
those
sources
that
emit
or
have
the
potential
to
emit
at
least
10
tpy
of
any
single
HAP
or
25
tpy
of
any
combination
of
HAP.
As
a
supplement
to
the
list
of
source
categories
published
on
July
16,
1992,
the
EPA
developed
the
publication
entitled
``
Documentation
of
Developing
the
Initial
Source
Category
List''
(EPA–
450/
3–
91–
030,
July
1992).
This
document
contains
descriptions
of
the
types
of
activities
included
within
each
source
category
of
major
sources.
This
document
states
that
future
information
may
be
used
to
refine
the
source
category
descriptions
(EPA–
450/
3–
91–
030,
page
A–
2).
We
included
site
remediation
on
the
NESHAP
source
category
list
to
address
HAP
emissions
from
technologies
and
work
practices
used
to
clean
up
or
reduce
chemical
contamination
in
soils,
groundwater,
other
types
of
contaminated
media
and
other
materials
at
those
facilities
that
are
major
sources
of
HAP
as
defined
by
section
112(
a)(
1)
of
the
CAA.
During
the
initial
development
of
the
proposed
rule,
we
obtained
additional
information
regarding
the
cleanup
of
contamination
from
leaking
underground
storage
tanks
at
those
facilities
that
are
not
associated
with
industrial
or
manufacturing
facilities
and
where
the
predominant,
if
not
only,
potential
source
of
HAP
emissions
is
the
remediation
cleanup
activity
itself
(e.
g.,
cleanup
of
contaminated
soil
or
groundwater
due
to
a
leaking
underground
tank
at
a
small
commercial
business,
farm,
or
private
residence).
Our
analysis
shows
that
the
HAP
emissions
from
a
typical
cleanup
of
contamination
from
the
size
and
types
of
underground
tanks
commonly
used
at
these
facilities
to
store
motor
fuels
or
heating
oils
is
significantly
below
the
major
source
levels
(i.
e.,
10
tpy
of
a
single
HAP
or
25
tpy
of
all
HAP)
(see
docket
A–
99–
20).
Therefore,
we
plan
to
modify
our
initial
description
for
the
site
remediation
source
category
to
exclude
remediation
activities
at
residential
and
farm
sites,
and
from
leaking
underground
storage
tanks
located
at
gasoline
service
stations
(businesses
typically
associated
with
NAICS
codes
447110
and
447190).
The
source
category
description
will
be
revised
at
the
next
update
of
the
source
category
list
as
required
under
CAA
section
112(
c).
B.
What
Is
a
Site
Remediation?
A
site
remediation
is
performed
in
response
to
the
release
of
hazardous
substances
into
the
environment
(e.
g.,
soil,
groundwater,
or
other
environmental
media).
It
involves
taking
appropriate
action
to
remove,
store,
treat,
and/
or
dispose
of
the
hazardous
substances
to
the
extent
necessary
to
protect
human
health
and
the
environment.
The
term
``
cleanup''
generally
refers
to
the
activities
performed
to
address
the
hazardous
substance
contamination.
This
term
frequently
is
used
interchangeably
with
the
term
``
remediation.
''
Site
remediations
can
be
performed
to
address
hazardous
substance
contamination
resulting
from
either
past
or
current
human
activities.
Examples
of
such
activities
include
accidental
releases
of
chemical
substances;
undetected
leaks
in
tanks
or
pipelines;
releases
from
the
use
of
incorrectly
designed
or
poorly
maintained
equipment
for
the
management
of
materials
containing
hazardous
substances;
improper
disposal
of
hazardous
substances
in
surface
impoundments,
containers,
waste
piles,
or
landfills;
and
abandoned
hazardous
substances.
Organic
materials
such
as
chlorinated
hydrocarbons,
petroleum
products,
polycyclicaromatic
hydrocarbons,
and
phenols
are
emitted
into
the
air
from
site
remediations.
Site
remediations
are
also
performed
to
clean
up
contamination
from
the
release
of
heavy
metals
(most
commonly
lead,
chromium,
arsenic,
and
cadmium)
and
other
inorganic
hazardous
substances.
Some
site
remediations
address
contamination
resulting
from
management
practices
used
at
a
given
facility
for
special
types
of
waste
materials
such
as
mixed
wastes
(wastes
containing
both
radioactive
and
nonradioactive
hazardous
constituents)
and
low
level
radioactive
wastes.
The
actions
taken
at
a
given
contamination
site
to
protect
human
health
and
the
environment
vary
depending
on
site
specific
conditions
such
as
the
composition,
physical
form,
and
quantity
of
the
hazardous
substance
and
the
relative
degree
of
contamination.
Typically,
remediation
or
cleanup
activities
involve
a
contaminated
media
of
one
physical
form
or
another
(e.
g.,
contaminated
soil
or
groundwater).
However,
at
some
sites
remediation
or
cleanup
involves
materials
other
than
contaminated
media;
this
might
include,
for
example,
wastes
left
in
tanks
and
containers
or
other
``
pure''
materials
in
the
environment
that
do
not
include
media
(e.
g.,
oil
pumped
from
below
ground).
We
use
the
term
``
remediation
material''
for
both
contaminated
media
and
pure
materials
that
are
remediated.
At
some
sites,
the
remediation
material
is
left
undisturbed
and
containment
techniques
are
used
to
prevent
or
significantly
reduce
further
migration
of
the
contaminants
to
surrounding
soils
or
to
underlying
groundwater
aquifers
(e.
g.,
installation
of
a
physical
barrier
or
cap
on
the
surface
of
a
contaminated
landfill).
At
many
sites,
the
remediation
material
is
treated
to
remove
or
destroy
the
hazardous
substance,
transform
the
hazardous
substance
into
a
nonhazardous
form,
or
reduce
the
concentration
of
the
hazardous
substance
below
a
threshold
level.
Treatment
processes
are
available
that
allow
the
remediation
material
to
be
treated
in
place
(commonly
referred
to
as
``
in
situ''
treatment).
Other
treatment
processes
require
first
extracting
the
remediation
material
from
the
ground
and
then
placing
it
in
a
treatment
unit
located
at
the
site
(commonly
referred
to
as
``
ex
situ''
treatment).
Alternatively,
all
of
the
remediation
material
may
be
extracted
from
the
site
and
the
remediation
material
sent
offsite
to
a
facility
for
treatment
or
disposal,
as
appropriate
for
the
form
and
characteristics
of
the
remediation
material
(e.
g.,
contaminated
soils
trucked
to
a
hazardous
waste
treatment,
storage,
and
disposal
facility;
or
contaminated
groundwater
discharged
through
a
sewer
system
to
a
publicly
owned
treatment
works).
C.
Why
Is
Site
Remediation
a
Unique
NESHAP
Source
Category?
The
development
of
a
NESHAP
for
site
remediation
presents
a
unique
set
of
considerations
unlike
any
other
source
category
for
which
we
have
established
a
NESHAP.
The
sole
purpose
of
conducting
a
site
remediation
is
to
clean
up
an
existing
environmental
problem.
Any
HAP
emissions
from
site
remediation
are
the
direct
result
of
the
remedial
activities
or
operations
taken
with
the
intent
of
protecting
human
health
and
the
environment
from
exposure
to
hazardous
substances.
The
HAP
emissions
do
not
result
from
processing
or
refining
raw
material,
manufacturing
a
product,
distributing
a
product
to
consumers,
or
even
managing
waste
to
avoid
an
environmental
problem.
In
developing
a
NESHAP
for
site
remediation,
careful
consideration
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
must
be
given
to
establishing
a
proposed
rule
that
balances
the
need
for
effective
HAP
emissions
control
with
the
overall
goal
of
removing
the
threat
to
human
health
and
the
environment
posed
by
the
hazardous
substances
in
the
remediation
material.
Site
remediation
cannot
be
categorized
by
a
particular
industry
sector
or
group
of
industry
sectors.
Site
remediation
potentially
may
be
conducted
at
any
type
of
business
or
facility
at
which
contamination
has
occurred
due
to
past
events
or
current
activities
at
the
facility.
These
facilities
may
be
privately
or
government
owned.
Site
remediation
is
also
performed
at
facilities
that
have
closed
or
have
been
abandoned.
Implementation
problems
resulting
from
the
fact
that
a
Site
Remediation
NESHAP
would
potentially
be
applicable
to
facilities
across
a
wide
spectrum
of
industry
sectors
are
not
insurmountable.
We
have
promulgated
NESHAP
for
some
source
categories
that
also
affect
multiple
industry
sectors.
For
example,
many
types
of
businesses
and
federal
facilities
in
the
United
States
have
operations
subject
to
the
Off
Site
Waste
and
Recovery
Operations
(OSWRO)
NESHAP
under
40
CFR
part
63,
subpart
DD.
Establishing
a
NESHAP
for
this
type
of
broad
based
source
category,
however,
does
affect
the
regulatory
approach
and
format
used
as
well
as
how
to
evaluate
the
impacts
of
the
proposed
rule.
For
the
NESHAP
source
categories
defined
in
terms
of
a
specific
industrial
or
manufacturing
sector,
the
facilities
comprising
the
source
category
(or,
in
some
cases,
subcategories
within
the
source
category)
share
similar
processes
and
emissions
points.
In
contrast
to
these
NESHAP
source
categories,
the
HAP
emissions
sources
in
the
site
remediation
source
category
are
dependent
on
site
specific
factors.
These
factors
determine
the
remedy
required
for
a
cleanup
and,
thereby,
the
sources
and
level
of
air
emissions
released,
if
any,
by
implementing
activities
associated
with
the
selected
remedy.
Another
consideration
is
the
finite
period
for
which
a
site
remediation
is
conducted.
The
objective
of
a
site
remediation
is
to
mitigate
a
detected
risk
to
public
health
or
the
environment
by
successfully
completing
the
cleanup
of
the
area
contaminated
by
a
hazardous
substance.
For
NESHAP
source
categories
associated
with
industrial
processes
or
product
distribution,
the
air
emission
sources
typically
remain
in
operation
for
many
years
(i.
e.,
10
years,
20
years,
or
even
longer
for
some
sources).
Once
an
existing
source
reaches
the
end
of
its
useful
service
life,
it
is
often
reconstructed
or
replaced
with
a
new
source.
In
contrast,
the
air
emission
sources
associated
with
site
remediations
cease
to
exist
once
the
remediation
cleanup
criteria
are
achieved.
Depending
on
site
specific
facts
such
as
the
extent
of
the
contamination
and
the
type
of
remediation
activities
needed,
the
life
span
of
a
given
site
remediation
may
be
a
short
period
lasting
several
weeks
to
a
more
extended
period
lasting
several
years.
Even
for
those
site
remediation
activities
requiring
a
number
of
years
to
complete,
it
is
important
to
recognize
that
ultimately
the
remediation
activities
at
a
facility
will
be
completed,
and
the
air
emission
sources
will
no
longer
exist.
D.
What
Are
the
Sources
of
Organic
HAP
Emissions
From
Site
Remediation
Activities?
Site
remediation
activities
may
emit
HAP.
The
levels
of
organic
HAP
emissions
at
any
given
facility
at
which
a
cleanup
of
remediation
material
is
being
conducted
depends
on
sitespecific
factors
including
the
type
of
processes
used
and
activities
conducted;
the
quantity,
organic
HAP
composition,
and
other
characteristics
of
the
remediation
material;
and
the
time
required
to
complete
the
cleanup.
The
following
sections
briefly
summarize
potential
types
of
HAP
emission
sources
related
to
site
remediation
activities.
1.
In
situ
Treatment
Processes
In
situ
treatment
processes
are
available
for
cleanup
of
soils
and
groundwater
contaminated
with
hazardous
organic
substances.
The
in
situ
processes
most
frequently
in
use
at
existing
remediation
sites
physically
extract
volatile
and
semi
volatile
organics
by
inducing
controlled
air
flow
through
the
remediation
material.
Examples
of
these
processes
are
soil
vapor
extraction
for
contaminated
soil
and
air
sparging
for
contaminated
groundwater.
If
not
controlled,
the
organic
vapors
extracted
from
the
soil
or
aqueous
media
are
released
directly
to
the
atmosphere.
Bioremediation
is
another
category
of
in
situ
treatment
process
that
is
commonly
used
to
remove
organic
contaminants.
These
processes
are
destruction
processes
based
on
stimulating
microbes
in
the
soil
or
groundwater
to
grow
using
the
organic
contaminant
compound
as
a
food
and
energy
source.
A
variety
of
other
chemical,
thermal,
and
physical
treatment
processes
also
have
been
used
in
limited
numbers
of
in
situ
applications.
Organic
HAP
emissions
from
in
situ
treatment
processes
primarily
occur
through
a
process
vent.
A
process
vent
is
a
pipe
or
duct
that
extends
above
ground
level
through
which
an
air
or
gas
stream
from
the
remediation
process
is
exhausted
to
the
atmosphere.
Emissions
occur
at
the
point
at
which
the
organic
vapor
stream
exits
the
process
vent
outlet
into
the
atmosphere.
Because
in
situ
treatment
allows
the
contaminated
material
to
be
treated
in
place,
the
primary
HAP
emissions
points
for
in
situ
treatment
processes
are
process
vents.
Avoiding
the
need
to
first
extract
the
contaminated
media
eliminates
potential
HAP
sources
associated
with
accumulating,
handling,
storing,
and
treating
the
remediation
material
in
aboveground
units.
2.
Ex
situ
Treatment
Processes
Ex
situ
treatment
processes
also
remove,
destroy,
or
transform
the
contaminants
but
first
require
the
contaminated
media
to
be
extracted
from
the
ground
or
water
body
before
it
can
be
treated.
For
a
given
site,
using
an
ex
situ
treatment
process
in
place
of
an
in
situ
treatment
process
generally
allows
the
remediation
to
be
completed
in
a
shorter
period;
it
also
provides
greater
control
of
the
consistency
of
the
treatment
results
because
of
the
ability
to
mix
the
extracted
materials
and
better
adjust
the
process
parameters
for
optimal
performance.
However,
total
remediation
costs
likely
will
be
higher
using
an
ex
situ
treatment
because
of
additional
costs
for
material
extraction
and
handling,
worker
protection,
treated
residual
disposal,
and
other
factors.
Many
ex
situ
processes
treat
the
extracted
material
in
a
tank,
vessel,
reactor,
combustion
unit,
or
similar
type
of
contained
process
unit.
Extracted
material
for
some
ex
situ
treatment
processes
is
treated
directly
on
the
land
surface
or
in
a
surface
impoundment.
The
ex
situ
treatment
processes
frequently
used
at
remediation
sites
are
groundwater
pump
and
treat,
solidification/
stabilization,
and
incineration.
Thermal
desorption,
bioremediation,
and
air
stripping
are
also
types
of
ex
situ
treatment
technologies
commonly
used
for
cleanup
of
soils
and
groundwater
contaminated
with
hazardous
organic
substances.
Solidification/
stabilization
technologies
are
primarily
used
to
treat
metals
and
other
types
of
inorganic
contaminants.
In
general,
these
technologies
have
limited
effectiveness
for
treatment
of
organics.
Solidification
and
stabilization
processes
reduce
the
mobility
of
a
contaminant
by
physically
binding
or
enclosing
it
within
a
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Proposed
Rules
stabilized
mass
(solidification),
or
by
chemically
binding
to
a
stabilizing
agent
(stabilization).
Incineration
can
be
used
to
destroy
organics
in
contaminated
soils
and
other
contaminated
solid
wastes
by
combustion
at
high
temperatures
(i.
e.,
870
to
1,200
C
(1,400
to
2,200
F)).
The
contaminated
material
is
burned
in
a
rotary,
circulating
bed,
fluidized
bed,
or
other
type
of
combustor.
Often
an
auxiliary
fuel
such
as
natural
gas
is
also
burned
to
initiate
and
sustain
combustion
of
the
contaminated
material.
Treatment
of
contaminated
materials
by
incineration
is
most
frequently
conducted
by
sending
the
material
to
a
permanent,
off
site
incinerator
facility,
although
mobile
incinerators
are
available
and
sometimes
brought
on
site.
Incinerators
used
to
treat
remediation
wastes
are
subject
to
existing
air
emission
regulations.
We
promulgated
interim
standards
for
the
NESHAP
for
hazardous
waste
combustion
sources
under
40
CFR
part
63,
subpart
EEE
with
final
standards
to
be
promulgated
by
June
14,
2005.
If
the
remediation
wastes
are
classified
as
hazardous
under
the
Resource
Conservation
and
Recovery
Act
(RCRA)
subtitle
C
regulations,
the
waste
must
be
burned
in
a
RCRApermitted
incinerator.
Incinerators
required
to
meet
the
hazardous
waste
combustion
NESHAP
or
RCRA
standards
use
extensive
air
pollution
control
systems
to
achieve
emissions
limitation
standards
for
organics,
particulate
matter,
metals,
and
chloride
emissions.
These
systems
treat
the
incinerator
exhaust
gas
stream
to
control
emissions
of
particulate
matter,
acid
gases,
and
other
pollutants.
Thermal
desorption
is
another
process
used
for
treating
contaminated
soils.
Unlike
incineration,
the
process
is
not
designed
to
destroy
organics
but
instead
to
physically
separate
the
organics
from
the
media.
The
contaminated
soil
or
other
material
is
heated
in
a
vessel
to
volatilize
organic
compounds.
Two
common
vessel
designs
are
the
rotary
dryer
and
thermal
screw.
The
bed
temperatures
and
residence
times
used
for
the
process
are
at
a
level
that
will
volatilize
selected
organic
contaminants
but
will
typically
not
oxidize
them.
A
carrier
gas
or
vacuum
system
is
used
to
vent
the
volatilized
organics
from
the
vessel
to
a
gas
stream
treatment
system
where
the
organic
vapors
are
removed
or
destroyed.
The
organic
contaminants
typically
are
either
removed
through
condensation
followed
by
carbon
adsorption,
or
they
are
destroyed
in
a
secondary
combustion
chamber
or
a
catalytic
oxidizer.
The
thermal
desorption
process
is
used
at
site
remediation
activities
for
the
separation
of
organics
from
refinery
wastes,
hydrocarbon
contaminated
soils,
coal
tar
wastes,
wood
treating
wastes,
creosote
contaminated
soils,
pesticides,
and
paint
wastes.
Many
of
these
process
units
are
transportable
and
are
temporarily
set
up
at
the
remediation
site
for
the
duration
of
the
cleanup.
Air
stripping
is
a
physical
separation
process
widely
used
to
remove
volatile
organics
from
contaminated
groundwater.
Air
stripping
involves
the
mass
transfer
of
VOC
from
the
water
to
air
by
contacting
the
water
with
an
induced
air
flow.
For
groundwater
remediation,
the
air
stripping
process
is
typically
conducted
by
pumping
the
groundwater
from
extraction
wells
to
a
packed
tower
or
an
aeration
tank.
Air
strippers
can
be
operated
continuously
or
in
a
batch
mode
where
the
air
stripper
is
intermittently
fed
from
a
collection
tank.
Using
batch
mode
operation
improves
the
air
stripper
performance
consistency
and
energy
efficiency
compared
to
a
continuously
operated
unit
because
mixing
in
the
storage
tanks
provides
a
uniform
feed
water
composition.
The
typical
packed
tower
air
stripper
uses
a
spray
nozzle
at
the
top
of
a
tower
to
distribute
the
contaminated
water
over
packing
in
the
column.
A
fan
or
blower
forces
air
upward
from
the
bottom
of
the
tower
countercurrent
to
the
water
flow.
A
sump
at
the
bottom
of
the
tower
collects
decontaminated
water
while
a
vent
on
the
top
of
the
tower
discharges
the
air/
vapor
stream.
Depending
on
the
organic
concentrations
in
the
groundwater
and
local
air
permitting
requirements,
the
vent
stream
may
be
discharged
directly
to
the
atmosphere
or
through
an
appropriate
organic
air
emission
control
device
such
as
activated
carbon
adsorber,
catalytic
vapor
oxidizer,
or
thermal
vapor
oxidizer.
Aeration
tanks
strip
VOC
by
bubbling
air
into
an
open
top
tank
through
which
contaminated
water
flows.
A
forced
air
blower
and
a
distribution
manifold
are
designed
to
provide
good
air
water
contact
without
the
need
for
any
packing
materials.
If
the
aeration
tank
is
uncovered,
the
stripped
VOC
are
emitted
to
the
atmosphere.
Bioremediation
technologies
are
successfully
used
to
clean
up
excavated
soils,
dredged
sludges
and
sediments,
and
pumped
groundwater
contaminated
with
petroleum
hydrocarbons,
solvents,
pesticides,
wood
preservatives,
and
other
organic
chemicals.
These
processes
rely
on
indigenous
or
inoculated
micro
organisms
(e.
g.,
fungi,
bacteria,
and
other
microbes)
to
degrade
organic
contaminants
found
in
the
soil
or
groundwater
by
metabolism.
In
the
presence
of
sufficient
oxygen
(aerobic
conditions)
and
other
nutrient
elements,
microorganisms
convert
many
organic
compounds
to
carbon
dioxide,
water,
and
microbial
cell
mass.
In
the
absence
of
oxygen
(anaerobic
conditions),
microorganisms
convert
the
organic
compounds
to
methane,
limited
amounts
of
carbon
dioxide,
and
trace
amounts
of
hydrogen
gas.
For
ex
situ
biotreatment
of
contaminated
soils
and
dredged
sediments,
the
excavated
material
is
first
processed
to
physically
separate
stones
and
other
debris.
The
contaminated
solids
are
then
mixed
with
water
to
a
predetermined
concentration
dependent
upon
the
concentration
of
the
contaminants,
the
rate
of
biodegradation,
and
the
physical
nature
of
the
soils.
This
soil
slurry
is
placed
in
a
reactor
vessel
(i.
e.,
a
bioreactor)
and
mixed
with
nutrients
and,
in
some
cases,
other
additives.
If
the
process
is
an
aerobic
process,
air
or
oxygen
is
blown
into
the
reactor.
When
biodegradation
is
complete,
the
soil
slurry
is
dewatered
using
clarifiers,
pressure
filters,
vacuum
filters,
sand
drying
beds,
or
centrifuges.
Use
of
ex
situ
bioreactors
often
is
favored
over
using
an
in
situ
bioremediation
process
for
heterogenous
soils,
low
permeability
soils,
or
when
a
shorter
remediation
period
is
required.
Biodegradation
processes
are
used
at
many
industrial
facilities
to
treat
process
wastewaters
containing
organics.
These
same
processes
can
be
used
to
treat
contaminated
groundwater
containing
organics.
At
those
remediation
sites
where
bioremediation
is
used
to
treat
contaminated
groundwater
pumped
from
the
ground,
the
common
practice
is
to
discharge
the
water
either
to
the
facility's
existing
process
wastewater
treatment
facility
or
directly
to
a
sewer
for
treatment
at
an
off
site
wastewater
treatment
facility.
As
an
alternative
to
conducting
biodegradation
in
a
bioreactor
or
other
type
of
enclosed
vessel,
land
treatment
and
land
farming
are
open
biodegradation
processes
performed
on
top
of
the
ground
surface.
For
these
processes,
the
extracted
material
is
applied
on
top
of
the
ground
in
thin,
lined
beds
or,
in
some
cases,
tilled
directly
back
into
the
upper
soil
layer.
Aerobic
microbes
decompose
the
organic
compounds
contained
in
the
applied
material.
The
material
is
periodically
turned
over
or
tilled
to
aerate
the
waste.
Organic
emissions
are
generated
due
to
the
volatilization
of
organics
from
the
exposed
surface
of
the
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Vol.
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2002
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Proposed
Rules
materials
primarily
during
initial
application
and
tilling.
After
application
and
tilling,
organic
emissions
continue
to
occur
from
the
material
mixture,
although
at
a
decreasing
rate,
until
nearly
all
of
the
volatile
organics
originally
in
the
applied
material
are
either
emitted
or
biologically
degraded.
Like
in
situ
treatment
processes,
primary
sources
of
HAP
emissions
from
many
types
of
ex
situ
treatment
processes
are
process
vents.
However,
unlike
in
situ
treatment
processes,
there
are
other
potential
HAP
emissions
sources
associated
with
ex
situ
treatment
processes
because
the
contaminated
media
is
extracted
from
the
ground
and
subsequently
managed
at
the
facility
as
essentially
a
waste
material.
Even
if
treatment
of
the
material
is
not
performed
at
the
facility,
any
tanks,
containers,
and
other
types
of
equipment
used
to
handle
and/
or
temporarily
store
the
material
before
it
is
shipped
off
site
are
potential
sources
of
air
emissions.
These
potential
HAP
emissions
sources
are
discussed
in
the
next
section.
3.
Other
Extracted
Media
Sources
Material
extraction
activities.
Depending
on
the
characteristics
of
the
remediation
material
and
the
extraction
method
used,
organic
HAP
may
be
emitted
by
the
extraction
activities.
Soils,
sludges,
and
sediments
are
frequently
extracted
using
heavy
construction
equipment.
Volatilization
of
organics
from
the
freshly
exposed
surfaces
of
the
extracted
materials
can
release
organic
HAP
into
the
atmosphere.
Tanks.
Tanks
can
be
used
at
a
facility
to
accumulate,
temporarily
store,
or
treat
extracted
materials
containing
organics.
These
tanks
can
either
be
open
tanks
(i.
e.,
the
surface
of
the
waste
material
is
exposed
directly
to
the
atmosphere)
or
covered
tanks
(i.
e.,
the
surface
of
the
waste
material
is
enclosed
by
a
roof
or
cover).
Organic
HAP
emissions
result
from
the
volatilization
of
organic
containing
materials
placed
in
the
tank,
and
the
subsequent
release
of
these
organic
vapors
to
the
atmosphere.
For
open
tanks,
the
organic
vapors
released
from
the
surface
of
the
material
are
dispersed
immediately
into
the
atmosphere
by
diffusion
and
wind
effects.
Covering
a
tank
(referred
to
as
a
``
fixed
roof
tank'')
significantly
lowers
organic
emissions
compared
to
open
tanks.
However,
organic
HAP
emissions
still
occur
from
fixed
roof
tanks
from
the
displacement
of
organic
vapors
that
have
collected
in
the
enclosed
space
above
the
surface
of
the
stored
material
through
vents
on
the
tank
roof.
This
displacement
occurs
during
tank
filling
operations
when
the
vapors
are
pushed
out
through
the
tank
vents
by
the
rising
level
of
material
in
the
tank
(commonly
referred
to
as
``
working
losses'')
and
to
a
lesser
extent,
when
the
volume
of
the
vapor
in
the
tank
is
increased
by
fluctuations
in
ambient
temperature
or
pressure
(commonly
referred
to
as
``
breathing
losses''.)
The
quantity
of
organic
emissions
from
a
fixed
roof
tank
varies
depending
on
volatility
of
the
organic
constituents
in
the
extracted
materials.
Separators.
Separators
are
used
to
separate
oil
or
organics
from
water.
Organic
emissions
from
these
sources
are
similar
to
those
occurring
from
open
top
wastewater
treatment
tanks.
Containers.
Containers
such
as
drums,
dumpsters,
and
roll
off
boxes
may
be
used
to
accumulate,
store,
and
treat
extracted
materials.
Organic
HAP
emissions
from
containers
can
result
from
several
emission
mechanisms.
Organic
emissions
occur
during
loading
of
liquid,
slurry,
and
sludge
waste
materials
into
containers
due
to
the
displacement
of
organic
vapors
to
the
atmosphere
through
container
openings
by
the
rising
level
of
material
in
the
container.
Once
loaded,
containers
that
remain
open
to
the
atmosphere
are
an
emission
source
when
organics
evaporate
from
the
exposed
surface
of
the
material
placed
in
the
container.
Surface
Impoundments.
Although
extracted
groundwater,
slurries,
and
sludge
materials
are
managed
in
tanks
at
most
site
remediations,
these
materials
under
special
circumstances
may
be
managed
in
surface
impoundments.
A
surface
impoundment
is
an
earthen
pit,
pond,
or
lagoon.
Organic
emissions
from
surface
impoundments
occur
as
organics
evaporate
from
the
exposed
surface
of
the
materials
placed
in
the
impoundment.
Surface
impoundments
containing
organic
containing
materials
may
have
high
organic
emissions
because
of
the
large
exposed
surface
area
and
the
extended
residence
time
that
materials
remain
in
the
impoundment
(sometimes
weeks
or
months).
Transfer
Equipment.
Organic
HAP
emissions
can
potentially
occur
during
the
transfer
of
a
material
if
the
transfer
system
is
open
to
the
atmosphere.
Volatilization
of
organics
from
the
exposed
surfaces
of
the
extracted
materials
can
release
organic
HAP
into
the
atmosphere.
Examples
of
such
systems
include
individual
drain
systems
(with
all
associated
drains,
junction
boxes,
and
sewer
lines),
channels,
flumes,
gravity
operated
conveyors
(such
as
a
chute),
and
mechanically
powered
conveyors
(such
as
a
belt
or
screw
conveyor).
Equipment
Leaks.
Leaks
from
pumps,
valves,
and
other
ancillary
equipment
needed
to
operate
material
handling
and
treatment
processes
can
be
a
potential
source
of
organic
HAP
emissions.
Organic
vapors
can
be
emitted
directly
to
the
atmosphere
by
flowing
through
small
openings
created
in
worn
or
defective
pump
and
valve
packings,
flange
gaskets,
or
other
types
of
equipment
seals.
In
addition,
organic
emissions
occur
when
liquids
leak
outside
the
equipment
exposing
the
leaked
fluid
to
the
ambient
air.
Emissions
result
when
organics
contained
in
the
drip,
puddle,
or
pool
of
leaked
liquid
evaporate
into
the
atmosphere.
Although
the
quantity
of
organic
emissions
from
a
single
leak
is
small,
when
many
equipment
leaks
occur
at
a
facility,
the
total
organic
HAP
emissions
from
equipment
leaks
can
be
significant.
E.
What
Are
the
Potential
Health
Effects
Associated
With
Organic
HAP
Emitted
From
Site
Remediation
Activities?
The
range
of
potential
human
health
effects
associated
with
exposure
to
organic
HAP
and
VOC
include
cancer,
aplastic
anemia,
upper
respiratory
tract
irritation,
liver
damage,
and
neurotoxic
effects
(e.
g.,
headache,
dizziness,
nausea,
tremors).
Thus,
the
proposed
rule
has
the
potential
for
providing
both
cancer
and
noncancer
related
health
benefits.
The
following
is
a
summary
of
the
potential
health
effects
associated
with
exposure
to
some
of
the
primary
HAP
emitted
from
site
remediation
activities.
1.
Benzene
Acute
(short
term)
inhalation
exposure
of
humans
to
benzene
may
cause
drowsiness,
dizziness,
and
headaches,
as
well
as
eye,
skin,
and
respiratory
tract
irritation,
and,
at
high
levels,
unconsciousness.
Chronic
longterm
inhalation
exposure
has
caused
various
disorders
in
the
blood,
including
reduced
numbers
of
red
blood
cells
and
aplastic
anemia,
in
occupational
settings.
Reproductive
effects
have
been
reported
for
women
exposed
by
inhalation
to
high
levels,
and
adverse
effects
on
the
developing
fetus
have
been
observed
in
animal
tests.
Increased
incidence
of
leukemia
(cancer
of
the
tissues
that
form
white
blood
cells)
has
been
observed
in
humans
occupationally
exposed
to
benzene.
We
have
classified
benzene
as
a
Group
A,
known
human
carcinogen.
2.
Ethyl
benzene
Acute
exposure
to
ethyl
benzene
in
humans
results
in
respiratory
effects
such
as
throat
irritation
and
chest
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Proposed
Rules
constriction,
irritation
of
the
eyes,
and
neurological
effects
such
as
dizziness.
Chronic
exposure
to
ethyl
benzene
by
inhalation
in
humans
has
shown
conflicting
results
regarding
its
effects
on
the
blood.
Animal
studies
have
reported
effects
on
the
blood,
liver,
and
kidneys
from
chronic
inhalation
exposures.
No
information
is
available
on
the
developmental
or
reproductive
effects
of
ethyl
benzene
in
humans,
but
animal
studies
have
reported
developmental
effects,
including
birth
defects
in
animals
exposed
via
inhalation.
We
have
classified
ethyl
benzene
in
Group
D,
not
classifiable
as
to
human
carcinogenicity.
3.
Toluene
Humans
exposed
to
toluene
for
short
periods
may
experience
irregular
heartbeat
and
effects
on
the
central
nervous
system
(CNS)
such
as
fatigue,
sleepiness,
headaches,
and
nausea.
Repeated
exposure
to
high
concentrations
may
induce
loss
of
coordination,
tremors,
decreased
brain
size,
and
involuntary
eye
movements,
and
may
impair
speech,
hearing,
and
vision.
Chronic
exposure
to
toluene
in
humans
has
also
been
indicated
to
irritate
the
skin,
eyes,
and
respiratory
tract,
and
to
cause
dizziness,
headaches,
and
difficulty
with
sleep.
Children
exposed
to
toluene
before
birth
may
suffer
CNS
dysfunction,
attention
deficits,
and
minor
face
and
limb
defects.
Inhalation
of
toluene
by
pregnant
women
may
increase
the
risk
of
spontaneous
abortion.
We
have
developed
a
reference
concentration
of
0.4
milligrams
per
cubic
meters
(mg/
m
3
)
for
toluene.
Inhalation
of
this
concentration
or
less
over
a
lifetime
would
be
unlikely
to
result
in
adverse
noncancer
effects.
No
data
exist
that
suggest
toluene
is
carcinogenic.
We
have
classified
toluene
in
Group
D,
not
classifiable
as
to
human
carcinogenicity.
4.
Vinyl
Chloride
Acute
exposure
to
high
levels
of
vinyl
chloride
in
air
has
resulted
in
CNS
effects
such
as
dizziness,
drowsiness,
and
headaches
in
humans.
Chronic
exposure
to
vinyl
chloride
through
inhalation
has
resulted
in
liver
damage
to
humans.
Human
and
animal
studies
show
adverse
effects
that
raise
a
concern
about
potential
reproductive
and
developmental
hazards
to
humans
from
exposure
to
vinyl
chloride.
Cancer
is
a
major
concern
from
exposure
to
vinyl
chloride
via
inhalation,
as
vinyl
chloride
exposure
has
been
shown
to
increase
the
risk
of
a
rare
form
of
liver
cancer
in
humans.
We
have
classified
vinyl
chloride
as
a
Group
A,
known
human
carcinogen.
5.
Xylenes
Acute
inhalation
of
mixed
xylenes
(a
mixture
of
three
closely
related
compounds)
in
humans
may
cause
irritation
of
the
nose
and
throat,
nausea,
vomiting,
gastric
irritation,
mild
transient
eye
irritation,
and
neurological
effects.
Chronic
inhalation
of
xylenes
in
humans
may
result
in
CNS
effects
such
as
headaches,
dizziness,
fatigue,
tremors,
and
incoordination.
Other
reported
effects
include
labored
breathing,
heart
palpitation,
severe
chest
pain,
abnormal
electrocardiograms,
and
possible
effects
on
the
blood
and
kidneys.
We
have
classified
xylenes
in
Group
D,
not
classifiable
as
to
human
carcinogenicity.
6.
Volatile
Organic
Compounds
By
requiring
facilities
to
reduce
organic
HAP
emitted
from
site
remediation
activities,
the
proposed
rule
would
also
reduce
emissions
of
those
VOC
that
are
not
HAP
but
contribute
to
adverse
human
health
affects.
Many
VOC
react
photochemically
with
nitrogen
oxides
in
the
atmosphere
to
form
tropospheric
(low
level)
ozone.
A
number
of
factors
affect
the
degree
to
which
VOC
emission
reductions
will
reduce
ambient
ozone
concentrations.
Human
laboratory
and
community
studies
have
shown
that
exposure
to
ozone
levels
that
exceed
the
national
ambient
air
quality
standards
(NAAQS)
can
result
in
various
adverse
health
impacts
such
as
alterations
in
lung
capacity
and
aggravation
of
existing
respiratory
disease.
Animal
studies
have
shown
increased
susceptibility
to
respiratory
infection
and
lung
structure
changes.
The
VOC
emissions
reductions
resulting
from
the
proposed
rule
will
reduce
low
level
ozone
and
have
a
positive
impact
toward
minimizing
these
health
effects.
Among
the
welfare
impacts
from
exposure
to
air
that
exceeds
the
ozone
NAAQS
are
damage
to
some
types
of
commercial
timber
and
economic
losses
for
commercially
valuable
crops
such
as
soybeans
and
cotton.
Studies
have
shown
that
exposure
to
excessive
ozone
can
disrupt
carbohydrate
production
and
distribution
in
plants.
This
can
lead
in
turn
to
reduced
root
growth,
reduced
biomass
or
yield,
reduced
plant
vigor
(which
can
cause
increased
susceptibility
to
attack
from
insects
and
disease
and
damage
from
cold),
and
diminished
ability
to
successfully
compete
with
more
tolerant
species.
In
addition,
excessive
ozone
levels
may
disrupt
the
structure
and
function
of
forested
ecosystems.
F.
What
Is
the
Relationship
of
the
Rule
to
Other
EPA
Regulatory
Actions
Affecting
Site
Remediation
Activities?
Existing
requirements
for
site
remediations
conducted
under
the
Comprehensive
Environmental
Response
and
Compensation
Liability
Act
(CERCLA)
and
RCRA
programs
are
administered
under
the
oversight
of
EPA's
Office
of
Solid
Waste
and
Emergency
Response
(OSWER).
A
site
remediation
may
be
regulated
under
one
of
three
OSWER
programs.
1.
Superfund
Removal
and
Remedial
Actions
Remediation
activities
under
the
Superfund
program
are
exempt
from
the
requirements
of
the
proposed
rule.
See
discussion
in
section
II.
A
of
this
preamble.
2.
RCRA
Corrective
Actions
Remediation
activities
under
the
RCRA
Corrective
Action
program
are
exempt
from
the
requirements
of
the
proposed
rule.
See
discussion
in
section
II.
A
of
this
preamble.
3.
Underground
Storage
Tanks
Subtitle
I
of
RCRA
directs
the
EPA
to
establish
regulatory
programs
to
prevent,
detect,
and
clean
up
releases
from
underground
storage
tanks
(UST)
containing
petroleum
or
hazardous
substances
listed
under
section
101(
14)
of
CERCLA
(petroleum
is
specifically
excluded
from
this
CERCLA
list).
The
EPA's
Office
of
Underground
Storage
Tanks
is
responsible
for
developing
and
implementing
the
UST
program.
Federal
regulations
for
UST
have
been
developed
which
specify
requirements
for
tank
notification,
interim
prohibition,
new
tank
standards,
reporting
and
recordkeeping
requirements
for
existing
tanks,
corrective
action,
financial
responsibility,
compliance
monitoring
and
enforcement,
and
approval
of
State
programs.
The
technical
standards
are
codified
in
40
CFR
part
280
and
40
CFR
part
281
with
the
list
of
CERCLA
hazardous
substances
in
40
CFR
part
302.4.
The
EPA
is
authorized
under
subtitle
I
to
delegate
UST
regulatory
authority
to
approved
State
programs.
States
with
delegated
authority
administer
and
enforce
their
own
approved
UST
program
instead
of
the
Federal
regulations.
There
are
currently
25
States
and
the
District
of
Columbia
with
approved
UST
programs.
Each
of
the
approved
State
UST
programs
is
codified
in
40
CFR
part
282.
In
the
other
States
without
an
approved
UST
program,
EPA
administers
and
enforces
the
Federal
regulations.
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Vol.
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Tuesday,
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30,
2002
/
Proposed
Rules
An
UST
is
a
tank
having
a
capacity
greater
than
110
gallons
for
which
the
volume
of
the
tank
(including
the
volume
of
any
connected
underground
pipes)
is
10
percent
or
more
beneath
the
surface
of
the
ground.
The
major
category
of
UST
regulated
under
this
program
are
tanks
used
to
store
petroleum
and
petroleum
based
substances
including
crude
oil,
motor
fuels,
jet
fuels,
distillate
fuel
oils,
residual
fuel
oils,
lubricants,
petroleum
solvents,
and
used
oils.
The
regulations
also
apply
to
underground
tanks
used
to
store
any
hazardous
substance
defined
in
section
101(
14)
of
CERCLA
but
are
not
regulated
as
a
hazardous
waste
under
RCRA
subtitle
C.
The
regulations
do
not
apply
to
underground
tanks
used
for
a
number
of
specific
applications
listed
in
the
applicability
and
definition
sections
of
the
rules.
The
owners
and
operators
of
petroleum
or
hazardous
substance
UST
systems
must
clean
up
any
spills,
leaks,
or
other
releases
from
the
tank
into
groundwater,
surface
water,
or
subsurface
soils.
Subpart
F
under
40
CFR
part
280
specifies
the
general
requirements
for
a
release
response
and
for
corrective
action.
The
specific
requirements
are
determined
based
on
the
site
specific
circumstances.
In
cases
where
contamination
of
soil
or
groundwater
has
occurred,
the
site
remediation
may
proceed
according
to
a
corrective
action
plan
approved
by
the
EPA
or
the
designated
State
or
local
agency
responsible
for
implementing
the
UST
program
at
the
UST
site.
Under
the
subpart
F
requirements,
this
plan
must
provide
for
adequate
protection
of
human
health
and
the
environment
as
determined
by
the
site
specific
factors
including
an
exposure
assessment.
G.
What
Criteria
Are
Used
in
the
Development
of
NESHAP?
Section
112
of
the
CAA
requires
that
we
establish
NESHAP
for
the
control
of
HAP
from
both
new
and
existing
sources.
The
CAA
requires
the
NESHAP
to
reflect
the
maximum
degree
of
reduction
in
emissions
of
HAP
that
is
achievable.
This
level
of
control
is
commonly
referred
to
as
MACT.
The
MACT
floor
is
the
minimum
control
level
allowed
for
NESHAP
and
is
defined
under
section
112(
d)(
3)
of
the
CAA.
In
essence,
the
MACT
floor
ensures
that
standards
are
set
at
levels
that
assure
that
all
major
sources
achieve
the
level
of
control
at
least
as
stringent
as
that
already
achieved
by
the
better
controlled
and
lower
emitting
sources
in
each
source
category
or
subcategory.
For
new
sources,
the
MACT
floor
cannot
be
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
bestcontrolled
similar
source.
The
MACT
standards
for
existing
sources
can
be
less
stringent
than
standards
for
new
sources,
but
they
cannot
be
less
stringent
than
the
average
emission
limitations
achieved
by
the
bestperforming
12
percent
of
existing
sources
in
the
category
or
subcategory
(or
the
best
performing
5
sources
for
categories
or
subcategories
with
fewer
than
30
sources).
In
developing
MACT,
we
also
consider
control
options
that
are
more
stringent
than
the
floor.
We
may
establish
standards
more
stringent
than
the
floor
based
on
the
consideration
of
cost
of
achieving
the
emissions
reductions,
any
health
and
environmental
impacts,
and
energy
requirements.
II.
Summary
of
the
Proposed
Rule
The
proposed
rule
would
amend
title
40,
chapter
I,
part
63
of
the
Code
of
Federal
Regulations
by
adding
a
new
subpart
GGGGG—
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Site
Remediation.
The
following
is
a
summary
of
the
requirements
for
the
proposed
rule.
A.
Who
is
Affected
by
the
Proposed
Rule?
1.
General
Applicability
The
proposed
rule
would
affect
owners
and
operators
of
facilities,
with
certain
exceptions
described
below,
that
are
major
sources
of
HAP
emissions,
where
a
MACT
activity
is
also
conducted,
and
at
which
a
site
remediation
is
performed.
All
three
criteria
must
exist
for
the
rule
to
apply.
For
the
purpose
of
implementing
the
proposed
rule,
a
site
remediation
is
one
or
more
activities
or
processes
used
to
remove,
destroy,
degrade,
transform,
or
immobilize
organic
HAP
constituents
in
soils,
sediments,
groundwater,
surface
waters,
or
other
types
of
solid
or
liquid
environmental
media
as
well
as
pure
materials
that
are
not
mixed
with
environmental
media.
2.
Major
Source
Determination
A
major
source
of
HAP
is
defined
under
CAA
section
112
as
any
stationary
source
or
group
of
stationary
sources
located
within
a
contiguous
area
and
under
common
control
that
emits,
or
has
the
potential
to
emit,
any
single
HAP
at
a
rate
of
10
tons
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
25
tons
or
more
per
year.
In
determining
whether
or
not
your
facility
is
a
major
source,
you
would
consider
all
sources
of
HAP
emissions
or
potential
emissions
at
your
facility.
A
major
source
determination
includes
consideration
of
a
facility's
potential
to
emit
(PTE)
as
well
as
actual
emissions.
The
PTE
is
the
maximum
capacity
of
a
stationary
source
to
emit
under
its
physical
and
operational
design.
Any
physical
or
operational
limitations
on
the
source
to
emit
an
air
pollutant,
including
air
pollution
control
equipment
and
restrictions
on
hours
of
operation,
or
on
the
type
or
amount
of
material
combusted,
stored,
or
processed,
is
treated
as
part
of
the
source's
design
if
the
limitation
is
enforceable
by
the
EPA
Administrator.
There
are
a
number
of
tools
and
resources
available
to
assist
an
owner
or
operator
in
estimating
and
inventorying
their
facility's
or
source's
HAP
emissions.
For
example,
our
Air
Clearinghouse
for
Inventories
and
Emission
Factors
(CHIEF)
website
(www.
epa.
gov/
ttn/
chief/
software/
airchief)
provides
the
public
and
private
sector
users
access
to
air
emission
data
specific
to
estimating
the
types
and
quantities
of
pollutants
that
may
be
emitted
from
a
variety
of
sources.
For
those
sources
or
emission
points
most
typically
associated
with
site
remediation
activities
(such
as
tanks
and
surface
impoundments),
our
WATER9
computer
program
provides
an
analytical
model
for
estimating
compound
specific
air
emissions
from
waste
and
wastewater
collection,
storage,
and
treatment
systems.
For
additional
information
on
determining
if
your
source
is
a
major
source,
EPA
policy
memoranda
and
other
guidance
on
major
source
determinations
and
PTE
can
be
found
on
the
Internet
at
www.
epa.
gov/
ttn/
oarpg
under
``
OAR
Policy
and
Guidance
Information''
or
on
the
Air
Toxics
Website
at
www.
epa.
gov/
ttn/
atw/
pte/
ptepa
3.
MACT
Activity
A
``
MACT
activity''
is
defined
as
a
non
remediation
activity
that
is
covered
by
one
of
the
listed
major
source
categories.
This
list
is
compiled
pursuant
to
CAA
section
112(
c)
and
was
first
published
on
July
16,
1992
(57
FR
31576).
The
list
is
updated
periodically
with
the
most
recent
update
published
in
the
Federal
Register
on
February
12,
2002
(67
FR
6521).
The
term
``
covered''
here
does
not
mean
that
the
nonremediation
activity
is
necessarily
subject
to
a
MACT
standard,
just
that
the
activity
is
included
within
the
scope
of
a
particular
MACT
source
category.
4.
Exemptions
The
proposed
rule
would
not
apply
to
site
remediations
we
are
specifically
excluding
from
applicability.
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
a.
CERCLA
Cleanups
and
RCRA
Corrective
Action
The
proposed
rule
exempts
sites
addressed
under
CERCLA
authority
and
corrective
action
activities
initiated
under
permits
or
orders,
including
such
activities
under
authorized
state
programs,
at
RCRA
Treatment,
Storage
and
Disposal
facilities.
Superfund
National
Priorities
List
(NPL)
sites
have
extensive
contamination
that
often
require
many
years
of
study
to
determine
a
permanent
remedy.
Superfund
sites
are
regulated
under
a
program
created
by
CERCLA
that
was
enacted
in
1980
and
amended
by
the
Superfund
Amendments
and
Reauthorization
Act
in
1986.
The
Superfund
program
is
designed
to
protect
public
health
and
the
environment
while
providing
the
flexibility
to
use
effective
and
innovative
remediation
approaches
that
best
suit
the
site
specific
conditions
at
each
CERCLA
site
(CERCLA
section
121).
The
Superfund
program
conducts
extensive
evaluation
of
the
contamination
at
each
NPL
site
(see
40
CFR
300.430).
As
part
of
the
evaluation
process,
a
decision
document
(i.
e.,
Record
of
Decision
(ROD))
is
developed
for
response
actions,
documenting
the
extent
of
contamination
and
the
cleanup
method(
s)
to
be
used
at
the
site.
Under
this
process,
a
site
specific
analysis,
considering
the
impacts
to
air,
soil
and
groundwater,
is
conducted
and
an
appropriate
remedy
is
selected.
During
the
ROD
process,
the
general
public
is
given
the
opportunity
for
input
in
the
decision
making
process
through
public
hearings
and
submission
of
written
comments.
The
public
plays
an
important
role
in
identifying
and
characterizing
site
specific
factors,
such
as
the
type
of
contaminants,
the
level
and
extent
of
contamination
and
other
site
specific
factors.
We
believe
this
procedure
results
in
selection
of
the
best
plan
for
cleaning
up
each
site
and
achieving
the
program's
goals.
As
implemented
under
the
requirements
of
RCRA,
hazardous
waste
treatment,
storage
and
disposal
facilities
(TSDF)
must
obtain
a
permit
specifying
requirements
for
managing
hazardous
waste.
As
a
condition
of
obtaining
this
permit,
facilities
are
required
to
undertake
corrective
action
addressing
releases
of
hazardous
waste
and
hazardous
constituents
from
units
at
the
facility
which
do
not
themselves
require
RCRA
permits
(solid
waste
management
units)
(RCRA
section
3004(
u)).
For
such
designated
contamination
areas
at
TSDF,
requirements
for
the
cleanup
of
the
contamination
are
included
in
the
facility's
RCRA
permit,
or
Federal
Order
where
applicable.
Such
cleanup
activities
are
known
as
``
corrective
actions.
''
Although
RCRA
is
a
separate
program
from
Superfund,
the
RCRA
permitting
or
Federal
Order
process
for
TSDF
share
several
significant
characteristics
with
Superfund
cleanup
activities
at
NPL
sites.
First,
it
is
also
the
intent
of
the
RCRA
Corrective
Action
program
to
protect
public
health
and
the
environment
while
allowing
flexibility
in
choosing
solutions
to
eliminate
or
reduce
site
contamination.
Second,
RCRA
permitting
and
Federal
Order
procedures
involve
the
public
in
the
decision
making
process
through
informal
public
meetings,
public
hearings
or
written
comment.
Finally,
an
extensive
site
specific
evaluation
is
performed
at
the
RCRA
facility
to
evaluate
the
extent
of
the
contamination,
while
considering
appropriate
remedies
through
a
multimedia
(i.
e.,
air,
soil,
groundwater)
perspective.
We
believe
that
requiring
remediation
activities
at
Superfund
NPL
sites
and
at
permitted
or
Federal
Order
RCRA
corrective
action
sites
to
meet
the
requirements
of
this
proposed
rule
could
either
create
incentives
to
avoid
cleanup,
or
result
in
the
selection
of
a
remediation
approach
that
is
less
desirable,
protective
or
permanent
(e.
g.,
capping
or
containing
the
contaminated
media
instead
of
permanently
removing
or
treating
the
contaminants).
(Cf.
Louisiana
Environmental
Action
Network
v.
EPA,
172
F.
3d
65,
67,
70
(D.
C.
Cir.
1999)
(EPA
lacks
authority
in
many
instances
to
compel
excavation
of
wastes,
so
that
imposition
of
requirements
on
excavated
wastes
discourages
more
protective
remediations;
EPA
may
permissibly
adjust
rules
applicable
to
excavated
wastes
to
avoid
this
result.))
Furthermore,
we
believe
that
these
existing
programs
are
the
most
appropriate,
comprehensive
and
effective
regulatory
approach
to
address
air
emissions
resulting
from
site
remediation
activities
at
sites
addressed
using
CERCLA
authority
and
RCRA
corrective
action
sites
and
to
avoid
transfer
from
one
medium
to
another.
b.
Other
Exemptions
The
proposed
rule
would
not
apply
to
site
remediation
activities
involving
the
cleanup
of
radioactive
mixed
waste
managed
in
accordance
with
all
applicable
regulations
under
Atomic
Energy
Act
and
Nuclear
Waste
Policy
Act
authorities.
Another
applicability
exemption
is
provided
for
those
site
remediations
performed
to
clean
up
remediation
material
containing
little
or
no
organic
HAP.
The
proposed
rule
would
not
apply
to
any
facility
for
which
the
owner
or
operator
demonstrates
that
the
total
annual
organic
HAP
mass
content
of
the
remediation
material
to
be
cleaned
up
at
the
facility
is
less
than
one
Mg/
yr.
5.
Application
of
Once
In,
Always
In
Policy
Due
to
the
potential
short
term
nature
of
site
remediations,
we
have
evaluated
how
the
proposed
rule
fits
with
existing
policies
for
CAA
section
112
standards.
Our
current
policy
is
that
once
a
facility
or
source
is
subject
to
a
MACT
standard,
it
remains
subject
to
that
standard
as
long
as
the
affected
source
definition
or
criteria
are
met.
This
is
called
the
``
once
in,
always
in''
policy.
Because
of
the
uniqueness
of
this
source
category
and
the
nature
of
the
activities
that
are
being
regulated
in
the
proposed
rule,
we
have
evaluated
how
our
once
in,
always
in
policy
should
apply
relative
to
the
site
remediation
source
category.
The
existing
policy
may
affect
facilities
that
conduct
site
remediations
in
situations
where
a
facility
is
presently
an
area
source
and
the
remediation
activities
would
increase
the
total
facility
PTE
such
that
the
facility
exceeds
the
10/
25
tons
of
HAP
criteria
for
a
major
source
under
CAA
section
112.
Because
the
facility
is
now
considered
a
major
source
of
HAP,
another
operation
at
the
facility,
such
as
a
manufacturing
process,
would
now
be
subject
to
NESHAP
for
other
source
categories
located
at
their
facility.
Furthermore,
after
the
remediation
is
completed,
the
facility
would,
in
terms
of
emissions,
essentially
be
back
to
where
it
was
as
an
area
source
(assuming
no
change
in
the
facility
plant
operations).
Under
the
once
in,
always
in
policy,
the
facility
would
remain
subject
to
the
NESHAP
that
was
triggered
by
the
short
term
change
of
source
status
from
area
to
major
brought
about
by
the
site
remediation
activity.
In
the
situation
described
above,
we
believe
the
once
in,
always
in
policy
would
create
an
obvious
disincentive
for
owners
or
operators
to
engage
in
site
remediations,
particularly
since
voluntary
remediation
would
be
affected
by
the
proposed
rule.
Our
intent
is
to
not
prescribe
requirements
that
create
incentives
to
avoid
a
cleanup
or
result
in
the
selection
of
less
desirable
or
less
protective
or
permanent
remediation
approaches.
Therefore,
we
have
determined
that
the
once
in,
always
in
policy
does
not
apply
relative
to
the
site
remediation
source
category
for
those
facilities
that
are
area
sources
prior
to
and
after
the
cleanup
activity.
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
The
above
application
of
the
once
in,
always
in
policy
to
site
remediation
activities
addresses
the
issue
of
a
facility's
MACT
obligation
after
completing
a
remediation
activity.
We
believe
a
situation
could
occur,
based
on
language
in
the
CAA,
that
this
policy
does
not
address.
Specifically,
certain
area
sources
for
non
remediation
activities
could
become
major
sources
once
a
remediation
activity
begins
operation.
While
the
facility
would
have
no
MACT
obligation
(Site
Remediation
MACT
or
otherwise)
after
completing
all
remediation,
compliance
with
a
nonremediation
MACT
standard
may
be
required
due
to
the
increase
in
PTE
from
the
remediation
activity.
An
example
of
this
situation
would
be
an
area
source
chemical
processing
plant
not
currently
subject
to
the
Hazardous
Organic
NESHAP
(HON),
but
with
manufacturing
operations
covered
by
that
MACT
standard.
After
operating
for
many
years
as
an
area
source,
the
facility
initiates
a
remediation
operation
that
increases
its
PTE
to
major
source
levels.
Since
the
facility
is
now
a
major
source
of
HAP,
the
facility
would
have
to
comply
with
the
HON
for
the
operations
covered
by
that
MACT
standard.
Furthermore,
since
the
compliance
dates
for
the
various
processes
regulated
by
the
HON
have
all
passed,
any
controls
required
by
the
HON
would
have
to
be
in
place
at
the
time
the
facility
became
a
major
source
as
specified
by
the
HON.
Prior
to
commencing
the
remediation
activity,
the
facility
may
find
it
preferable
to
install
federally
enforceable
controls
on
certain
emission
points
and
maintain
area
source
status
to
avoid
becoming
subject
to
the
industry
relevant
MACT
standard.
We
realize
this
option
is
not
achievable
in
every
case.
6.
Exemption
of
Short
Duration
Site
Remediations
The
EPA
is
proposing
to
exempt
sources
from
the
requirements
of
the
proposed
rule
where
the
contamination
requiring
remediation
occurs
within
7
days
prior
to
the
remediation
activity.
This
exemption
is
intended
to
apply
to
contamination
commonly
caused
by
a
spill
where
the
cleanup
is
initiated
soon
after
the
spill
event
and
is
of
very
short
duration
(i.
e.,
typically
30
days
or
less).
The
purpose
of
this
exemption
is
to
encourage
prompt
attention
to
remediating
contaminant
spills
and
leakages.
Although
the
Agency
is
not
proposing
any
other
duration
based
exemptions
in
the
proposed
rule,
it
is
possible
that
other
duration
based
exemptions
may
be
appropriate
in
light
of
the
policy
goal
of
encouraging
voluntary
site
remediations
to
remove
risk
to
human
health
and
the
environment.
For
example,
there
may
be
some
site
remediations
that
can
be
completed
in
the
time
required
by
this
proposal
to
modify
relevant
permits;
it
may
make
sense
in
cases
like
this
to
complete
the
remediation
activity
as
quickly
as
possible
without
waiting
for
paperwork
modifications
to
be
completed.
The
Agency
requests
comment
on
which
situations,
if
any,
might
be
appropriate
for
further
duration
based
exemptions
to
today's
proposed
rule.
B.
What
Are
the
Affected
Sources?
The
proposed
rule
defines
three
groups
of
affected
sources,
(1)
process
vents,
(2)
remediation
material
management
units,
and
(3)
equipment
leaks.
The
affected
source
for
process
vents
is
the
entire
group
of
process
vents
associated
with
both
in
situ
and
ex
situ
remediation
activities.
The
affected
source
for
remediation
material
management
units
is
the
entire
group
of
tanks,
surface
impoundments,
containers,
oil/
water
separators,
and
transfer
systems
used
to
store,
transfer,
treat,
or
otherwise
manage
remediation
material.
The
affected
source
for
equipment
leaks
is
the
entire
group
of
remediation
equipment
components
(pumps,
valves,
etc.)
that
contain
or
contact
remediation
material
having
a
total
organic
HAP
concentration
equal
to
or
greater
than
10
percent
by
weight,
and
are
intended
to
operate
for
300
hours
or
more
during
a
calendar
year.
C.
What
Are
the
Standards
for
Process
Vents?
The
proposed
rule
would
establish
emission
limitation
and
operating
standards
for
certain
process
vents
associated
with
site
remediation
treatment
processes.
The
same
standards
would
apply
to
both
in
situ
and
ex
situ
treatment
processes.
These
standards
would
apply
to
the
entire
group
of
affected
process
vents
associated
with
all
of
the
treatment
processes
used
for
your
site
remediation.
The
standards
would
be
the
same
for
existing
and
new
sources.
The
air
emission
control
requirements
under
the
proposed
rule
would
not
apply
to
certain
process
vent
streams
with
low
flow,
low
HAP
concentration
characteristics.
A
process
vent
would
be
exempted
from
the
air
emission
control
requirements
of
the
NESHAP
if
the
owner
or
operator
determines
the
process
vent
stream
flow
rate
to
be
less
than
0.005
standard
cubic
meters
per
minute.
Also
exempted
would
be
those
process
vent
streams
having
a
flow
rate
less
than
6.0
standard
cubic
meters
per
minute
and
a
total
HAP
concentration
in
the
vent
stream
less
than
20
parts
per
million
by
volume
(ppmv).
This
process
vent
exemption
requires
that
both
the
process
vent
flow
rate
and
the
organic
HAP
concentration
criteria
be
met
to
qualify
for
the
exemption.
A
process
vent
would
also
be
exempted
from
the
air
emission
control
requirements
if
the
HAP
concentration
of
the
remediation
material
being
treated
by
the
vented
process
is
less
than
10
parts
per
million
by
weight
(ppmw).
Under
the
proposed
rule,
you
would
have
two
compliance
options
for
the
affected
process
vents.
The
first
option
would
be
to
reduce
the
total
organic
HAP
emissions
from
all
affected
process
vents
at
the
facility
to
a
level
less
than
1.4
kilograms
per
hour
(kg/
h)
(approximately
3.0
pounds
per
hour)
and
2.8
Mg/
yr
(approximately
3.1
tpy).
You
would
have
to
achieve
both
of
these
mass
emission
limitations
to
comply
with
this
option
under
the
proposed
rule.
If
the
total
organic
HAP
emissions
from
all
affected
process
vents
associated
with
your
site
remediation
exceed
either
the
hourly
or
annual
mass
emission
limitation
then
you
would
need
to
use
appropriate
controls
to
reduce
the
emission
levels
to
comply
with
the
emission
limitations.
If
you
can
meet
both
of
the
total
organic
HAP
mass
emission
limitations
using
no
controls
or
the
existing
controls
you
already
have
in
place
to
meet
federally
enforceable
organic
emission
standards,
then
no
additional
controls
would
be
required
under
the
proposed
rule
for
your
affected
process
vents.
As
an
alternative
to
complying
with
the
mass
emission
limits,
a
second
option
proposed
under
the
proposed
rule
would
be
to
reduce
the
total
organic
HAP
emissions
from
all
of
the
affected
process
vents
by
at
least
95
weight
percent.
At
sites
with
multiple
affected
process
vent
streams,
you
may
comply
with
this
option
by
a
combination
of
controlled
and
uncontrolled
process
vent
streams
that
achieve
the
95
percent
reduction
standard
on
an
overall
massweighted
average.
For
those
process
vent
streams
controlled
by
venting
to
a
control
device,
the
closed
vent
system
and
control
device
would
need
to
meet
certain
requirements
specified
in
the
proposed
rule.
D.
What
Are
the
Standards
for
Remediation
Material
Management
Units?
The
proposed
rule
would
establish
emissions
limitation
and
operating
standards
for
certain
remediation
management
units
(i.
e.,
units
associated
with
the
management
of
remediation
materials).
For
those
remediation
material
management
units
required
to
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
use
air
emission
controls,
the
proposed
rule
would
establish
by
source
type
(i.
e.,
tanks,
oil
water
separators,
containers,
surface
impoundments,
transfer
systems)
separate
sets
of
emission
limitation,
operating
limit,
and
work
practice
standards
as
appropriate
for
each
source
type.
The
standards
would
be
the
same
for
existing
and
new
sources.
Air
emission
controls
would
be
required
on
a
remediation
material
management
unit
used
to
manage
remediation
material
having
an
organic
HAP
(VOHAP)
concentration
equal
to
or
greater
than
500
ppmw.
Remediation
material
with
a
VOHAP
concentration
of
less
than
500
ppmw
is
not
required
to
be
managed
in
controlled
units.
The
proposed
rule
also
provides
an
exemption
that
would
allow
an
owner
or
operator
to
selectively
designate,
on
a
site
specific
basis,
certain
individual
units
to
be
exempt
from
the
air
emission
control
requirements
regardless
of
the
VOHAP
concentration
of
the
remediation
material
placed
in
the
unit.
Application
of
this
discretionary
exemption
by
the
owner
or
operator
would
be
limited
based
on
remediation
material
organic
HAP
content.
Under
this
provision,
the
total
annual
organic
HAP
mass
content
of
the
regulated
remediation
material
placed
in
all
of
the
units
designated
by
the
owner
or
operator
as
exempt
units
could
not
exceed
1
Mg/
yr
as
determined
in
accordance
with
the
procedures
specified
in
the
proposed
rule.
Determination
of
VOHAP
concentration
can
be
made
by
either
direct
measurement
of
samples
of
the
remediation
material
or
through
use
of
knowledge
of
the
remediation
material
(i.
e.,
application
of
owner/
operator
expertise
using
appropriate
information
regarding
the
remediation
material).
In
using
direct
measurement,
the
VOHAP
concentration
of
the
collected
samples
would
be
measured
using
Method
305
in
40
CFR
part
63,
appendix
A.
As
an
alternative
to
using
Method
305,
you
would
be
allowed
to
determine
the
organic
HAP
concentration
using
any
one
of
the
several
alternative
test
methods,
as
applicable
to
the
remediation
material
stream,
and
then
adjust
the
test
results
using
factors
specified
in
the
proposed
rule
to
determined
the
VOHAP
concentration.
The
VOHAP
determination
using
direct
measurement
for
a
given
remediation
material
unit
would
be
based
on
samples
collected
prior
to
placing
the
remediation
material
in
the
unit
at
any
point
you
choose
before
the
organic
constituents
in
the
material
have
the
potential
to
volatilize
and
be
released
to
the
atmosphere.
For
example,
you
may
sample
the
remediation
material
stream
at
the
point
where
it
is
extracted
from
the
ground
(``
point
of
extraction''
as
defined
in
the
proposed
rule).
Alternatively,
you
may
choose
to
sample
the
remediation
material
stream
within
the
remediation
material
unit
(provided
that
organic
constituents
in
the
material
have
not
been
allowed
to
volatilize
and
be
released
to
the
atmosphere,
as
specified
in
the
proposed
rule).
Allowing
the
use
of
knowledge
to
determine
the
VOHAP
concentration
of
a
remediation
material
provides
flexibility
for
the
owner
or
operator
to
use
any
appropriate
information
to
determine
VOHAP
concentration
of
a
remediation
material.
The
basis
for
knowledge
of
the
remediation
material
could
include
existing
information
collected
by
the
owner
or
operator
for
other
purposes
or
new
information
collected
specifically
for
the
VOHAP
remediation
material
determination.
For
remediation
material
management
units
downstream
of
the
contaminated
area
in
particular,
it
is
important
to
note
that
the
determination
of
the
VOHAP
concentration
is
made
within
each
remediation
material
management
unit.
This
approach
simplifies
the
determination
process
for
varying
treatment
processes
and
addresses
both
the
situation
of
management
of
a
single
remediation
stream
or
management
of
two
or
more
material
streams
combined
(either
remediation
or
non
remediation,
or
both).
If
a
single
material
stream,
or
combination
of
streams,
have
a
VOHAP
concentration
of
500
ppmw
or
greater
in
the
management
unit,
then
the
unit
is
subject
to
the
air
emission
control
requirements
for
the
particular
unit
as
specified
in
the
proposed
rule.
Once
the
VOHAP
concentration
falls
below
the
500
ppmw
action
level,
the
material
need
not
be
managed
in
controlled
units.
If
the
HAP
concentration
is
increased
to
500
ppmw
or
more
in
a
downstream
unit,
that
unit
will
need
control.
For
example,
a
facility
remediation
project
involves
a
pump
and
treat
system
that
generates
groundwater
with
more
than
500
ppmw
VOHAP,
measured
as
it
exits
the
groundwater
pumping/
piping
system.
It
is
initially
pumped
into
a
holding
tank
managing
the
single
remediation
stream.
The
remediation
material,
the
groundwater
in
this
case,
has
a
VOHAP
concentration
greater
than
500
ppmw,
and,
therefore,
the
holding
tank
would
be
subject
to
the
tank
standards
under
the
proposed
rule.
From
the
holding
tank,
the
groundwater
is
sent
to
a
larger
mixing
tank
where
the
groundwater
is
mixed
with
other
wastewater
streams,
where
the
combined
VOHAP
concentration
is
less
than
500
ppmw,
and
the
resultant
mixture
is
treated
to
adjust
the
pH
of
the
mixture.
Because
the
VOHAP
concentration
of
the
combined
streams
is
below
500
ppmw,
the
mixing
tank
would
not
be
subject
to
the
tank
standards
under
the
proposed
rule.
Following
this
mixing
operation,
the
combined
wastewater
is
sent
to
an
onsite
wastewater
treatment
system.
Since
the
mixture
leaving
the
mixing
tank
has
a
VOHAP
concentration
of
less
than
500
ppmw,
all
downstream
processes
and
management
units
(e.
g.,
tanks,
surface
impoundments,
containers
or
transfer
systems)
would
not
be
subject
to
the
control
requirements
for
remediation
material
management
units
unless
the
concentration
is
increased
to
500
ppmw
or
greater
through
phase
separation
or
other
method.
In
general,
we
expect
remediation
streams
to
be
managed
separately
so
a
stream
would
be
managed
in
controlled
units
until
it
is
treated
to
reduce
the
concentration
below
500
ppmw.
We
believe,
however,
that
in
some
cases
a
remediation
stream
may
be
combined
with
one
or
more
streams
and
treated
downstream
from
the
mixing
point.
Mixing
merely
for
the
purposes
of
dilution
is
not
allowed,
but
if
mixing
occurs
to
facilitate
treatment
(i.
e.,
to
treat
all
streams
in
a
centralized
operation),
and
the
resulting
stream
has
a
VOHAP
concentration
below
500
ppmw,
then
that
stream
does
not
have
to
be
managed
in
controlled
units.
We
realize
this
approach
deviates
somewhat
from
other
rules
regulating
wastewater
type
management
or
treatment
units
that
require
air
emission
controls
after
the
VOHAP
concentration
falls
below
500
ppmw
due
to
mixing.
For
site
remediation
operations,
this
is
an
appropriate
approach
since
we
believe
remediation
activities
are
typically
of
a
limited
duration,
relatively
low
flow
in
comparison
to
facilitywide
wastewater
management
operations,
and
often
treated
effectively
in
a
facility
wide
treatment
system.
We
do
not
want
to
create
obstacles
that
could
inhibit
overall
treatment
effectiveness.
Moreover,
we
believe
remediation
streams
would
get
some
level
of
HAP
reduction,
and,
thus,
emission
reduction,
through
biological
treatment
within
a
facility's
wastewater
treatment
system.
1.
Tanks
The
proposed
rule
would
establish
emission
limitation
and
work
practice
standards
to
control
organic
HAP
emissions
from
those
tanks
managing
remediation
material
having
an
average
VOHAP
concentration
equal
to
or
greater
than
the
500
ppmw
action
level.
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Federal
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
For
those
tanks
required
to
meet
the
air
emission
control
requirements,
you
would
need
to
achieve
one
of
two
levels
of
control.
The
required
level
of
control
would
be
determined
by
the
tank
design
capacity
and
the
maximum
HAP
vapor
pressure
of
the
extracted
material
in
the
tank.
For
each
tank
required
to
use
Level
1
controls,
you
would
be
required
to
comply
with
the
existing
40
CFR
part
63,
subpart
OO—
National
Emission
Standards
for
Tanks—
Level
1.
For
these
tanks,
you
could
also
comply
with
the
proposed
rule
by
using
Level
2
controls
if
you
choose
to
do
so.
For
each
tank
required
to
use
Level
2
controls,
you
would
have
five
compliance
options
under
the
proposed
rule.
The
compliance
alternatives
provided
under
the
proposed
rule
would
allow
you
to
either:
(1)
Use
a
fixed
roof
tank
with
an
internal
floating
roof;
(2)
use
an
external
floating
roof
tank;
(3)
vent
the
tank
through
a
closed
vent
system
to
a
control
device
that
meets
the
requirements
specified
in
the
proposed
rule;
(4)
locate
an
open
tank
inside
an
enclosure
vented
through
a
closed
vent
system
to
a
control
device
that
meets
the
requirements
specified
in
the
proposed
rule;
or
(5)
use
a
pressurized
tank
that
operates
as
a
closed
system
during
normal
operations.
The
specific
technical
requirements
for
each
of
these
alternatives
are
implemented
under
the
proposed
rule
by
cross
referencing
the
existing
Tank
Level
2
control
standards
in
40
CFR
63.685(
d)
of
the
OSWRO
NESHAP.
2.
Containers
The
proposed
rule
would
establish
emission
limitation
and
work
practice
standards
to
control
organic
HAP
emissions
from
containers
having
a
design
capacity
greater
than
0.1
cubic
meters
(approximately
26
gallons)
used
to
manage
remediation
material
having
a
VOHAP
concentration
of
500
ppmw
or
more.
For
those
containers
required
to
use
air
emission
controls,
you
would
need
to
achieve
one
of
three
levels
of
control
that
would
be
determined
by
the
container
design
capacity,
the
organic
content
of
the
extracted
material
in
the
container,
and
whether
the
container
is
used
for
a
waste
stabilization
process.
You
would
be
required
to
comply
with
the
specified
requirements
for
the
applicable
control
level
in
the
existing
40
CFR
part
63,
subpart
PP—
National
Emission
Standards
for
Containers.
Except
for
containers
used
for
waste
stabilization,
these
standards
would
require
that
you
manage
the
extracted
material
in
containers
that
use
covers
according
to
the
requirements
specified
in
the
proposed
rule.
Should
affected
containers
be
used
for
a
waste
stabilization
process,
containers
would
be
required
to
be
vented
to
a
control
device.
Application
of
the
container
standards
and
the
various
levels
of
control
is
illustrated
in
the
following
example.
In
the
situation
where
contaminated
soil
(i.
e.,
the
remediation
material
in
this
case)
is
excavated
and
placed
in
a
dump
truck
(i.
e.,
a
container
under
the
definitions
used
in
the
proposed
rule),
the
truck
containing
the
soil
would
be
required
to
meet
Level
1
controls
if
the
VOHAP
concentration
is
equal
to
or
greater
than
500
ppmw
and
the
criteria
for
Level
2
controls
is
not
met.
If
this
were
the
case,
as
it
likely
would
be
in
most
remediation
situations,
then
a
cover
such
as
tarp
covering
the
remediation
material
would
be
adequate
to
meet
the
Level
1
control
requirements.
If
the
vapor
pressure
and
VOHAP
concentration
were
such
that
Level
2
controls
were
required
then
a
more
strenuous
set
of
controls
would
apply.
3.
Surface
Impoundments
For
each
surface
impoundment
required
to
use
air
emission
controls,
you
would
be
required
to
comply
with
the
existing
40
CFR
part
63,
subpart
QQ—
National
Emission
Standards
for
Surface
Impoundments.
Under
this
subpart,
you
must
meet
one
of
two
options:
(1)
Use
a
cover
over
the
surface
impoundment
and
vent
through
a
closed
vent
system
to
a
control
device;
or
(2)
use
a
floating
membrane
cover
designed
and
operated
according
to
requirements
specified
in
the
proposed
rule.
4.
Oil
Water
and
Organic
Water
Separators
For
each
oil
water
or
organic
water
separator
required
to
use
air
emission
controls,
you
would
be
required
to
comply
with
the
existing
40
CFR
part
63,
subpart
VV—
National
Emission
Standards
for
Oil
Water
and
OrganicWater
Separators.
Under
this
subpart,
you
must
meet
one
of
three
options:
(1)
Use
a
floating
roof
on
the
separator;
(2)
use
a
cover
over
the
separator
that
is
vented
through
a
closed
vent
system
to
a
control
device;
or
(3)
use
a
pressurized
separator
designed
and
operated
according
to
requirements
specified
in
the
proposed
rule.
5.
Material
Transfer
Systems
For
each
individual
drain
system
required
to
use
air
emission
controls,
you
would
be
required
to
comply
with
the
existing
40
CFR
part
63,
subpart
RR—
National
Emission
Standards
for
Individual
Drain
Systems.
For
transfer
systems
required
to
use
air
emission
controls
other
than
individual
drain
systems,
you
would
be
required
to
comply
with
one
of
three
options:
(1)
Use
covers;
(2)
use
continuous
hardpiping
or
(3)
use
an
enclosure
vented
to
a
control
device.
E.
What
are
the
Standards
for
Equipment
Leaks?
The
proposed
rule
would
establish
work
practice
and
equipment
standards
to
control
organic
HAP
emissions
from
leaks
in
pumps,
compressors,
pressure
relief
devices,
sampling
connection
systems,
open
ended
valves
or
lines,
valves,
flanges
and
other
connectors,
and
product
accumulator
vessels
that
either
contain
or
contact
a
regulated
material
that
is
a
fluid
(liquid
or
gas)
and
has
a
total
organic
HAP
concentration
equal
to
or
greater
than
10
percent
by
weight.
These
work
practice
and
equipment
standards
would
not
apply
to
equipment
that
operates
less
than
300
hours
per
calendar
year.
You
would
have
the
option
of
complying
with
the
provisions
of
either
40
CFR
part
63,
subpart
UU—
National
Emission
Standards
for
Equipment
Leaks—
Control
Level
1
or
40
CFR
part
63,
subpart
UU—
National
Emission
Standards
for
Equipment
Leaks—
Control
Level
2.
Both
of
these
subparts
require
you
to
implement
a
leak
detection
and
repair
program
(LDAR)
and
to
make
certain
equipment
modifications.
F.
What
Are
the
Requirements
for
Remediation
Material
Sent
Off
Site?
Under
the
proposed
rule,
if
you
transfer
remediation
material
containing
organic
HAP
to
another
party,
another
facility,
or
receive
it
from
another
facility,
this
material
would
need
to
be
managed
according
to
the
provisions
of
this
subpart.
In
other
words,
if
the
material
has
a
VOHAP
concentration
of
500
ppmw
or
more,
as
determined
according
to
the
procedure
in
the
proposed
rule,
then
at
the
new
facility
this
material
would
need
to
be
managed
in
units
that
meet
the
air
emission
control
requirements
under
the
Site
Remediation
NESHAP
for
the
applicable
remediation
material
management
unit
type
(i.
e.,
tank,
containers,
etc.).
Similarly,
any
treatment
process
used
for
the
transferred
remediation
material
would
need
to
meet
the
process
vent
control
requirements.
G.
What
Are
the
General
Compliance
Requirements?
Under
the
proposed
rule,
you
would
be
required
to
meet
each
applicable
emission
limitation
and
work
practice
standard
in
the
proposed
rule
at
all
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
times,
except
during
periods
of
startup,
shutdown,
and
malfunction.
You
must
develop
and
implement
a
written
startup,
shutdown,
and
malfunction
plan
for
your
site
remediation
according
to
the
provisions
of
40
CFR
63.6(
e)(
3).
Also
with
regard
to
compliance,
it
is
important
to
note
that
under
the
provisions
of
the
proposed
rule,
if
an
affected
source
(i.
e.,
a
remediation
management
or
treatment
unit)
is
subject
to
and
complying
with
the
control
requirements
under
another
part
61
or
part
63
standard
(e.
g.,
has
either
installed
air
emission
controls
or
has
taken
other
actions
to
reduce
HAP
emissions
to
levels
dictated
by
the
other
part
61
or
part
63
standards)
then
the
affected
source
is
exempt
from
the
control
requirements
of
the
proposed
rule
in
40
CFR
63.7883
through
40
CFR
63.7933.
However,
the
source
must
be
controlling
air
emissions
under
the
other
rule;
the
exemption
under
the
proposed
rule
does
not
apply
if
the
source
is
merely
exempt
from
the
control
requirements
of
the
other
rule
and
has
not
taken
action
to
limit
HAP
emissions.
H.
What
Are
the
Testing
and
Initial
Compliance
Requirements?
Initial
compliance
for
process
vents
would
be
demonstrating
that
either:
(1)
The
total
organic
HAP
emissions
from
all
affected
process
vents
is
less
than
1.4
kg/
h
and
2.8
Mg/
yr;
or
(2)
the
total
organic
HAP
emissions
from
all
of
the
affected
process
vents
is
reduced
by
at
least
95
weight
percent.
Initial
compliance
for
remediation
material
units
would
be
demonstrating
that
either:
(1)
The
VOHAP
concentration
of
the
remediation
material
managed
in
the
unit
is
below
the
500
ppmw
action
level;
or
(2)
the
unit
meets
all
applicable
air
emission
control
requirements
for
the
unit.
If
a
control
device
is
used,
initial
compliance
is
determined
by
either:
(1)
Performing
a
performance
test
according
to
40
CFR
63.7
of
the
general
provisions
and
using
specific
EPA
reference
test
methods;
or
(2)
performing
a
design
evaluation
according
to
procedures
specified
in
the
proposed
rule.
You
also
must
establish
your
operating
limits
for
the
control
device
based
on
the
values
measured
during
the
performance
test
or
determined
by
the
design
evaluation.
I.
What
Are
the
Continuous
Compliance
Provisions?
To
demonstrate
continuous
compliance
with
the
applicable
emission
limitations
and
work
practice
standards
under
the
proposed
rule,
you
would
perform
periodic
inspections
and
continuous
monitoring
of
certain
types
of
air
pollution
control
equipment
you
use
to
comply
with
the
proposed
rule.
In
those
situations
when
a
deviation
from
the
operating
limits
specified
for
a
control
device
is
indicated
by
the
monitoring
system
or
when
a
damaged
or
defective
component
is
detected
during
an
inspection,
you
must
implement
the
appropriate
corrective
measures.
To
demonstrate
continuous
compliance
with
an
emission
limitation
for
a
given
source,
you
would
continuously
monitor
air
emissions
or
operating
parameters
appropriate
to
the
type
of
control
device
you
are
using
to
comply
with
the
standard,
and
keep
a
record
of
the
monitoring
data.
Compliance
is
demonstrated
by
maintaining
each
of
the
applicable
parameter
values
within
the
operating
limits
established
during
the
initial
compliance
demonstration
for
the
control
device.
There
are
different
requirements
for
demonstrating
continuous
compliance
with
the
work
practice
standards,
depending
on
which
standards
are
applicable
to
a
given
emission
source.
To
ensure
that
the
control
equipment
used
to
meet
an
applicable
work
practice
standard
is
properly
operated
and
maintained,
the
proposed
rule
would
require
that
you
periodically
inspect
and
monitor
this
equipment.
When
a
cover
is
used
to
comply
with
a
work
practice
standard,
you
must
visually
inspect
the
cover
periodically
and
keep
records
of
the
inspections.
In
addition,
for
external
floating
roofs,
seal
gap
measurements
must
be
performed
on
the
secondary
seal
once
per
year
and
on
the
primary
seal
every
5
years.
Leak
detection
monitoring
using
Method
21
would
be
required
for
certain
types
of
covers
to
ensure
gaskets
and
seals
are
in
good
condition,
and
for
closed
vent
systems
to
ensure
all
fittings
remain
leak
tight.
In
general,
annual
inspection
and
leak
detection
monitoring
of
covers
is
proposed.
Annual
inspection
and
leak
detection
monitoring
would
be
required
for
closed
vent
systems.
Any
defects
or
conditions
causing
failures
detected
by
an
inspection
or
monitoring
need
to
be
promptly
repaired
and
records
of
the
repairs
kept.
You
would
be
allowed
to
use
an
alternative
to
the
monitoring
required
by
these
proposed
standards.
If
you
choose
to
do
so,
you
would
be
required
to
request
approval
for
alternative
monitoring
according
to
the
procedures
in
40
CFR
63.8
of
the
General
Provisions.
J.
What
Are
the
Notification,
Recordkeeping,
and
Reporting
Requirements?
The
proposed
rule
would
require
you
to
keep
records
and
file
reports
consistent
with
the
notification,
recordkeeping,
and
reporting
requirements
of
the
General
Provisions
of
40
CFR
part
63,
subpart
A.
Two
basic
types
of
reports
are
required:
initial
notification
and
semiannual
compliance
reports.
The
initial
notification
report
advises
the
regulatory
authority
of
applicability
for
existing
sources
or
of
construction
for
new
sources.
The
initial
compliance
report
demonstrates
that
compliance
has
been
achieved.
This
report
contains
the
results
of
the
initial
performance
test
or
design
evaluation,
which
includes
the
determination
of
the
reference
operating
parameter
values
or
range
and
a
list
of
the
processes
and
equipment
subject
to
the
standards.
Subsequent
compliance
reports
describe
any
deviations
of
monitored
parameters
from
reference
values;
failures
to
comply
with
the
startup,
shutdown,
and
malfunction
plan
(SSMP)
for
control
devices;
and
results
of
LDAR
monitoring
and
control
equipment
inspections.
Records
required
under
the
proposed
standards
must
be
kept
for
5
years,
with
at
least
2
of
these
years
being
on
the
facility
premises.
These
records
include
copies
of
all
reports
that
you
have
submitted
to
the
responsible
authority,
control
equipment
inspection
records,
and
monitoring
data
from
control
devices
demonstrating
that
operating
limits
are
being
maintained.
Records
from
the
LDAR
program
and
storage
vessel
inspections,
and
records
of
startups,
shutdowns,
and
malfunctions
of
each
control
device
are
needed
to
ensure
that
the
controls
in
place
are
continuing
to
be
effective.
K.
What
Are
the
Implications
of
This
NESHAP
for
Clean
Air
Act
Title
V
Requirements?
1.
What
is
the
title
V
Program?
This
program
is
a
permit
program
established
under
title
V
of
the
CAA
in
1990.
A
title
V
permit
is
intended
to
consolidate
all
of
the
air
pollution
control
requirements
into
a
single
operating
permit
for
a
source's
air
pollution
activities.
2.
Under
what
circumstances
am
I
required
to
obtain
a
title
V
permit
for
my
remediation
activity?
Title
V
requires
all
major
sources
to
obtain
permits
(see
40
CFR
70.3,
or
40
CFR
71.3).
Major
source
status
is
triggered
for
a
source
under
title
V
when
actual
emissions
or
potential
to
emit
meets
or
exceeds
certain
major
source
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
thresholds
(see
definition
of
major
source
at
40
CFR
70.2,
or
40
CFR
71.2).
Although
a
source
subject
to
the
Site
Remediation
MACT
will
be
major
for
title
V
purposes
based
on
emissions
of
HAP,
title
V
also
requires
permits
for
sources
that
are
major
for
other
air
pollutants,
(e.
g.,
the
criteria
pollutants).
Sources
that
are
subject
to
the
Site
Remediation
MACT,
by
virtue
of
being
major
sources,
will
typically
have
to
obtain
an
operating
permit,
if
they
don't
already
have
one,
or
modify
their
existing
permit
under
title
V
(either
40
CFR
part
70
or
71).
An
option
for
avoiding
major
source
status
under
title
V
for
some
sources
that
are
not
major
prior
to
the
remediation
activity
is
voluntarily
requesting
practicallyenforceable
limitations
(often
operation
or
emissions
related)
to
reduce
their
potential
to
emit
or
actual
emissions
to
levels
below
the
major
source
thresholds.
This
option
should
be
pursued
through
your
permitting
authority.
3.
Who
is
responsible
for
obtaining
the
title
V
permit
for
a
remediation
activity?
Typically
the
party
responsible
for
obtaining
the
title
V
major
source
permit
will
be
either:
(1)
The
owner
or
operator
of
the
site
remediation
equipment
or
activities,
or
(2)
the
owner
or
operator
of
the
source
already
existing
at
the
facility
that
is
covered
by
another
MACT
source
category
activity
(the
other
collocated
source).
The
decision
as
to
who
should
apply
for
the
permit
in
any
specific
case
will
be
made
on
a
case
by
case
basis
(site
dependent)
and
should
be
evaluated
in
consultation
with
the
permitting
authority,
however,
normal
practice
will
be
to
issue
the
permit
to
the
entity
that
has
common
control
of
all
activities
at
the
facility.
Under
the
definition
of
major
source
used
for
HAP
in
40
CFR
part
70
or
71,
all
activities
within
a
contiguous
area
under
common
control
will
be
aggregated
(grouped)
together
as
a
single
source
to
determine
major
source
status.
While
the
source
is
ultimately
responsible
for
making
these
determinations,
permitting
authorities
will
commonly
assist
sources
in
this
task.
Also
note
that
the
question
of
who
may
be
required
to
apply
for
the
permit
will
likely
be
affected
by
the
way
that
pre
construction
review
permits
(also
referred
to
as
New
Source
Review
or
NSR
permits)
were
issued
to
such
sources.
Initial
NSR
permits
are
required
prior
to
the
commencement
of
construction
activities,
while
initial
title
V
operating
permits
are
required
generally
after
commencement
of
operations.
Thus,
permitting
authorities
are
likely
to
follow
decisions
made
in
issuing
NSR
permits
when
looking
at
this
question
for
title
V
purposes.
4.
If
I
already
have
a
title
V
permit,
is
a
modification
required
for
my
remediation
activity?
When
there
is
a
major
source
in
a
MACT
source
category
that
already
has
a
title
V
operating
permit,
and
a
site
remediation
activity
commences
operation
at
the
same
facility
and
all
activities
at
the
facility
are
considered
part
of
the
same
source
(i.
e.,
under
common
ownership
and
control),
permitting
authorities
will
require
the
previously
issued
operating
permit
to
either
be
reopened
or
revised
to
reflect
the
new
applicable
requirements
of
the
Site
Remediation
MACT.
Permit
reopening
under
40
CFR
70.7(
f),
or
40
CFR
71.7(
f),
is
required
when
a
major
source
has
a
permit,
there
are
3
years
or
more
left
on
the
term
of
the
permit,
and
we
promulgate
a
new
MACT
standard
(or
other
applicable
requirement)
that
applies
to
the
source.
For
such
sources,
if
less
than
3
years
is
left
on
the
permit
term,
the
State
may
generally
wait
until
renewal
to
update
the
permit.
On
the
other
hand,
modifications
under
40
CFR
70.7(
e),
or
40
CFR
71.7(
e),
are
required
when
a
source
has
a
permit
and
the
source
becomes
subject
to
the
MACT
standard
after
the
standard
is
promulgated
(in
most
cases,
these
will
be
significant
modifications
under
40
CFR
70.7(
e)(
4),
or
40
CFR
71.7(
e)(
3),
but
in
some
circumstances
other
permit
modification
procedures
may
apply).
5.
If
I
have
an
existing
title
V
permit,
do
I
have
to
wait
for
completion
of
the
permit
modification
before
I
begin
the
remediation
activity?
In
general,
when
site
remediation
activities
are
not
addressed
or
prohibited
by
your
existing
operating
permit,
you
may
commence
such
activities
at
any
time
prior
to
the
finalization
of
any
formal
title
V
permit
modification
procedures.
However,
when
permit
modification
is
required
due
to
a
new
remediation
activity
and
the
new
activity
conflicts
with
(or
is
expressly
prohibited
by)
the
existing
permit
terms
or
conditions,
the
permit
must
be
formally
revised
prior
to
commencing
operation
of
such
activities
or
you
will
be
in
violation
of
the
permit
prior
to
their
revision.
6.
The
increase
in
potential
to
emit
from
a
remediation
activity
will
make
my
facility
a
major
source
overall,
but
only
for
a
limited
time.
Am
I
required
to
get
a
title
V
permit?
What
activities
can
occur
before
my
title
V
permit
is
issued?
All
major
sources
are
required
by
40
CFR
70.5(
a)(
1),
or
40
CFR
71.5(
a)(
2)
to
submit
their
permit
application
no
later
than
12
months
after
they
commence
operation,
but
State
law
could
require
it
sooner.
After
that,
40
CFR
70.7(
a)(
2),
or
40
CFR
71.7(
a)(
2),
allows
permitting
authorities
up
to
18
months
to
issue
the
final
permit,
but
State
law
may
also
require
issuance
sooner.
Major
sources
that
expect
to
operate
for
12
months
or
more
obviously
must
submit
a
permit
application
in
all
cases.
Sources
that
expect
to
operate
less
than
12
months
(or
whatever
deadline
the
State
sets)
may
decide
not
to
prepare
a
permit
application,
at
the
risk
of
operating
past
that
deadline
without
submitting
the
required
application.
Also
note
that
policies
concerning
the
permitting
of
such
sources
may
vary
from
State
to
State;
so
it
is
also
a
good
idea
to
contact
your
permitting
authority
concerning
the
steps
necessary
to
fulfill
your
obligations
under
the
operating
permit
program.
7.
What
are
the
requirements
for
remediation
equipment
that
moves
from
one
facility
to
another
after
completing
each
remediation
activity?
Permitting
authorities
will
decide
how
to
permit
such
sources
on
a
caseby
case
basis,
taking
into
account
the
particular
circumstances
known
to
them
at
that
time.
Many
permitting
authorities
have
policies
or
specific
rules
to
address
the
permitting
of
portable
sources,
or
other
activities
of
short
duration,
which
are
usually
those
expected
to
operate
less
than
1
or
2
years
at
any
one
location,
and
which
are
expected
to
operate
in
more
than
one
location
during
a
typical
5
year
permit
term.
In
addition,
40
CFR
70.6(
e),
or
40
CFR
71.6(
e),
addressing
temporary
sources,
allows
permitting
authorities
to
issue
a
single
operating
permit
for
a
major
source
that
will
operate
in
multiple
locations
during
its
5
year
permit
term.
8.
My
facility's
current
operations
are
covered
by
an
existing
title
V
permit,
do
I
have
the
option
of
obtaining
a
separate
title
V
permit
for
a
new
remediation
activity?
In
some
cases,
permitting
authorities
have
authority
to
issue
multiple
operating
permits
to
a
single
source,
and
if
this
is
the
case,
they
may
agree
to
issue
a
separate
permit
for
the
remediation
activities.
Although
title
V
permits
are
typically
thought
of
as
a
single
permit
that
covers
all
the
applicable
requirements
and
all
emissions
units
at
a
single
source,
the
CAA
allows
permitting
authorities
to
issue
multiple
permits
to
a
single
source.
Such
issuance
would
be
consistent
with
title
V
as
long
as
the
assemblage
of
permits
for
a
single
major
source
addresses
all
applicable
requirements
at
all
subject
emission
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
1
Connecticut,
Delaware,
Maine,
Maryland,
Massachusetts,
New
Hampshire,
New
Jersey,
New
York,
Pennsylvania,
Rhode
Island,
Vermont,
and
Washington,
DC.
units
(in
the
same
way
that
a
single
major
source
permit
would).
L.
What
Are
the
Implications
for
This
NESHAP
for
Clean
Air
Act
New
Source
Review
Requirements?
This
NESHAP
does
not
change
any
of
the
existing
requirements
under
the
NSR
program.
The
questions
and
answers
within
this
section
summarize
the
NSR
program
and
a
source's
general
requirements
under
this
program.
1.
How
is
the
NSR
program
structured?
The
NSR
program
is
divided
into
three
parts:
Nonattainment
NSR
for
major
sources,
Prevention
of
Significant
Deterioration
(PSD)
for
major
sources,
and
minor
source
NSR.
The
term
``
NSR''
is
used
to
refer
to
both
the
overall
program,
and
to
the
requirements
that
apply
in
nonattainment
areas
(e.
g.,
nonattainment
NSR).
Nonattainment
NSR
applies
to
large
facilities
(major
sources)
located
in
areas
where
air
quality
is
unhealthy
to
breathe
—i.
e.
where
the
NAAQS
for
a
CAA
pollutant
is
not
being
met.
These
areas
are
called
nonattainment
areas.
Note:
The
term
major
source
as
it
applies
to
the
NSR
program
is
discussed
in
detail
in
the
July
23,
1996
Federal
Register
(61
FR
38429)).
Nonattainment
NSR
for
major
sources
of
certain
pollutants
also
applies
in
the
federally
designated
ozone
transport
region
(OTR),
which
consists
of
eleven
northeastern
states.
1
Prevention
of
significant
deterioration
(PSD)
applies
to
major
sources
located
in
areas
where
air
quality
is
currently
acceptable—
i.
e.
where
the
NAAQS
for
a
CAA
pollutant
is
being
met.
These
are
called
attainment
areas.
Minor
NSR
applies
to
smaller
sources
and
modifications
that
contribute
to
air
pollution
throughout
the
country.
2.
Who
runs
the
NSR
and
PSD
programs?
The
NSR
program
is
administered
by
State
and
local
air
pollution
permitting
authorities,
who
are
responsible
for
issuing
all
permits.
Each
state
or
local
permitting
authority
is
required
to
incorporate
NSR
and
PSD
requirements
into
its
State
Implementation
Plan
(SIP),
which
is
the
State's
plan
to
ensure
progress
toward,
or
maintenance
of,
attainment
of
all
NAAQS.
A
State's
PSD
program
may
be
SIP
approved
or
delegated.
If
the
State
designs
its
own
program,
EPA
may
approve
it
so
long
as
it
meets
the
criteria
listed
in
Federal
PSD
regulations.
Otherwise,
the
State
may
take
delegation
of
the
Federal
PSD
program,
as
it
is
written
in
the
Federal
PSD
regulations.
A
State's
nonattainment
NSR
program
must
be
a
SIP
approved
program
meeting
the
criteria
listed
in
Federal
NSR
regulations.
3.
Who
is
subject
to
major
NSR
and
PSD
requirements?
No
one
may
begin
constructing
a
new
major
stationary
source
or
undertake
a
major
modification
at
an
existing
stationary
source
without
obtaining
an
NSR
or
PSD
permit
from
the
permitting
authority.
The
new
major
source
would
not
need
an
NSR
or
PSD
permit
unless
it
had
new
potential
emissions
that
qualify
as
major.
Moreover,
an
existing
major
source
that
undertakes
a
major
modification
is
subject
to
NSR
or
PSD
only
if
there
is
a
significant
increase
in
emissions.
4.
Do
sources
always
need
an
NSR
permit
for
a
construction
project?
Sources
may
avoid
major
NSR
or
PSD
altogether
by
not
increasing
their
emissions
(e.
g.,
by
making
changes
that
do
not
increase
emissions,
by
installing
controls
on
one
part
of
the
facility
to
offset
increases
at
another
part
of
the
facility,
or
by
agreeing
to
emission
limits
in
their
permit).
Alternatively,
facilities
may
comply
with
NSR
by
including
modern
controls
in
conjunction
with
an
upgrade
project
or
a
new
facility.
5.
How
long
does
the
process
take
to
complete?
The
EPA
estimates
that
the
average
time
it
takes
to
get
a
major
NSR
or
PSD
permit
is
about
7
months
from
receipt
of
the
permit
application.
6.
When
NSR
or
PSD
applies,
what
must
sources
do?
a.
Major
Nonattainment
NSR
in
Nonattainment
Areas
New
and
existing
major
sources
undertaking
major
modifications
subject
to
nonattainment
NSR
must
apply
state
of
the
art
emission
controls
that
meet
the
lowest
achievable
emissions
rate
(referred
to
as
LAER).
The
LAER
is
based
on
the
most
stringent
emission
limitation
in
any
State's
SIP,
or
achieved
in
practice
by
the
source
category
under
review.
To
get
a
permit,
the
applicant
must
also
offset
its
emission
increase
by
securing
emissions
reductions
offsets
from
other
sources
in
the
area.
The
amount
of
the
offset
must
be
as
great
or
greater
than
the
new
increase,
and
is
based
on
the
severity
of
the
area's
nonattainment
classification.
The
more
polluted
the
air
is
where
the
source
is
locating
or
expanding,
the
greater
the
emissions
reductions
required
to
offset
the
proposed
increase.
Offsets
must
be
real
reductions
in
emissions,
not
otherwise
required
by
the
CAA,
and
must
be
enforceable
by
the
EPA.
Each
applicant
must
also
conduct
an
analysis
of
``
alternative
sites,
sizes,
production
processes,
and
environmental
control
techniques
*
*
*
(that)
demonstrates
that
benefits
of
the
proposed
source
significantly
outweigh
the
environmental
and
social
costs
of
its
location,
construction,
or
modification.
''
The
applicant
must
also
certify
that
all
other
sources
operating
within
the
State
are
operating
in
compliance
with
the
CAA
and
SIP
requirements.
Finally,
the
public
must
be
given
adequate
notice
and
opportunity
to
comment
on
each
permit
application.
b.
Prevention
of
Significant
Deterioration
in
Attainment
Areas
New
major
sources
and
existing
sources
that
undertake
major
modifications
that
are
subject
to
PSD
must
apply
best
available
control
technology
(BACT).
The
BACT
determination
ultimately
made
by
the
permitting
authority
allows
for
a
consideration
of
energy,
environmental,
and
economic
impacts
and
other
costs
on
a
case
by
case
basis
that
is
specific
to
the
facility's
situation.
The
permitting
authority
then
specifies
an
emission
limit
for
the
source
that
represents
BACT.
Each
PSD
applicant
must
also
perform
an
air
quality
analysis
to
demonstrate
that
the
new
emission
increase
will
not
cause
or
contribute
to
a
violation
of
any
applicable
NAAQS
or
result
in
a
significant
deterioration
of
the
air
quality.
Finally,
each
applicant
must
also
conduct
an
analysis
to
ensure
that
the
increase
does
not
result
in
adverse
impact
on
air
quality
related
values,
including
visibility,
that
affect
designated
Class
I
areas,
such
as
wilderness
areas
and
national
parks.
c.
Minor
NSR
For
sources
not
otherwise
covered
by
major
PSD
or
NSR,
the
CAA
requires
permitting
authorities
to
regulate
construction
and
modifications
to
ensure
that
the
NAAQS
are
achieved.
State
programs
have
widely
varying
requirements.
Some
are
comprehensive,
while
others
provide
numerous
exclusions.
Some
require
a
technology
review,
in
addition
to
air
quality
modeling.
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
What
Is
the
Scope
of
the
Source
Category
To
Be
Regulated?
As
we
discussed
in
section
I.
A
of
this
preamble,
site
remediation
is
one
of
the
approximately
170
categories
of
sources
included
on
the
NESHAP
source
category
list.
The
facilities
included
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Federal
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
within
the
scope
of
this
source
category
include
sites
at
which
the
cleanup
is
required
to
comply
with
requirements
under
a
State
regulatory
program
as
well
as
sites
at
which
cleanups
are
performed
on
a
voluntary
basis.
In
section
II.
A
of
this
preamble,
we
discuss
how
statutory
directives
under
RCRA
and
CERCLA
direct
us
to
address
the
control
of
air
emissions
from
certain
site
remediations
and
that
those
activities
under
the
RCRA
Corrective
Action
and
CERCLA
authorities
are
exempt
from
the
requirements
of
the
proposed
rule.
B.
How
Did
We
Select
the
Pollutants
To
Be
Regulated?
The
specific
chemicals,
compounds,
or
groups
of
compounds
designated
by
Congress
to
be
HAP
are
listed
in
CAA
section
112(
b).
Included
on
the
list
are
organic
and
inorganic
chemicals.
From
this
list
of
HAP,
we
selected
the
specific
HAP
to
be
regulated
under
this
NESHAP
for
site
remediations.
1.
Organic
HAP
Organic
HAP
potentially
can
be
emitted
from
site
remediations
at
many
different
types
of
facilities.
We
considered
but
decided
not
to
select
all
of
the
organic
HAP
listed
under
section
112(
b)
for
regulation
in
the
Site
Remediation
NESHAP.
Instead,
we
decided
to
be
consistent
with
the
approach
we
used
for
the
OSWRO
NESHAP
as
well
as
other
NESHAP
promulgated
for
source
categories
with
large
diversity
in
the
organic
chemical
constituents
present
in
the
materials
managed
at
any
given
facility
and
instead
regulate
on
the
basis
of
a
surrogate
that
reasonably
ensures
MACT
control
of
the
organic
HAP
present.
See
National
Lime
v.
EPA,
238
F.
3d,
(D.
C.
Cir.
2000,
upholding
use
of
surrogates
in
establishing
MACT
standards).
When
we
developed
the
organic
HAP
list
for
the
OSWRO
NESHAP,
we
evaluated
each
organic
chemical
or
chemical
group
listed
as
a
HAP
in
CAA
section
112(
b)
with
respect
to
its
potential
to
be
emitted
from
a
waste
management
or
recovery
operation.
The
criteria
used
to
characterize
and
evaluate
emission
potential
was
based
on
a
chemical
constituent's
Henry's
law
constant,
evaluation
of
the
aqueous
and
organic
volatility
characteristics
of
the
chemical,
and
the
ability
of
the
analytical
test
methods
to
quantitate
the
chemical.
Based
on
our
evaluation,
we
selected
98
specific
organic
HAP
compounds
or
compound
groups
to
be
regulated
under
the
proposed
rule
(Table
1
to
40
CFR
part
63,
subpart
DD.).
Although
the
OSWRO
NESHAP,
by
an
exclusion
under
the
rule
applicability,
does
not
apply
to
units
managing
wastes
from
site
remediations,
the
data
base
that
we
used
to
select
the
list
of
organic
HAP
for
the
OSWRO
NESHAP
included
remediation
wastes
sent
to
hazardous
waste
TSDF.
We
believe
that
this
data
base
is
also
representative
of
the
range
of
organic
HAP
chemicals
having
the
potential
to
be
emitted
from
the
sites
requiring
cleanup
of
media
contaminated
with
volatile
or
semivolatile
organics
and
other
remediation
material.
Therefore,
we
are
proposing
that
same
list
of
organic
HAP
used
for
the
OSWRO
NESHAP
also
be
used
for
the
Site
Remediation
NESHAP.
This
list
is
presented
in
Table
1
to
proposed
Subpart
GGGGG.
We
request
comment
on
the
proposal
to
use
this
list
of
organic
HAP
for
the
Site
Remediation
NESHAP.
2.
Inorganic
HAP
The
types
of
inorganic
compounds
listed
as
HAP
in
CAA
section
112(
b)
that
are
most
likely
to
be
in
contaminated
media
requiring
remediation
are
heavy
metals
(i.
e.,
antimony,
arsenic,
beryllium,
cadmium,
chromium
cobalt,
lead,
manganese,
mercury,
nickel,
and
selenium).
A
widely
used
remediation
approach
for
cleanup
of
soils,
sludges,
or
sediments
contaminated
with
heavy
metals
involves
excavating
the
contaminated
media,
treating
the
remediation
material
in
a
solidification
or
stabilization
process,
and
disposing
of
the
treated
material
in
an
appropriate
landfill
(which
may
be
on
site
or
an
off
site
facility).
Metals
in
the
contaminated
soil
are
immobilized
by
the
added
binder
material
used
for
the
fixation
process.
In
situations
where
groundwater
is
contaminated
with
heavy
metals,
site
remediation
typically
involves
extracting
the
groundwater
by
pumping
it
to
the
surface
and
then
removing
the
metals
by
a
physical
or
chemical
process
(e.
g.,
precipitation,
ion
exchange).
The
metals
remain
in
the
wet
precipitate
or
other
extraction
media
and
are
not
released
to
the
atmosphere.
For
some
site
remediations
involving
the
cleanup
of
media
containing
both
metals
and
organic
contaminates,
the
extracted
remediation
waste
is
burned
in
an
incinerator
or
other
combustion
device.
Metal
HAP
contained
in
the
remediation
waste
vaporize
at
high
combustion
temperatures
or
become
airborne
as
fine
particles
and
can
remain
in
combustion
gases
in
either
a
gaseous
or
particulate
form.
Any
metal
HAP
contained
in
the
combustion
gases
that
is
not
captured
and
removed
by
a
control
device
is
emitted
to
the
atmosphere.
Based
on
our
information
regarding
the
cleanup
of
media
contaminated
with
metals
or
other
inorganic
HAP,
many
of
the
remediation
techniques
used
do
not
release
the
inorganic
HAP
to
the
atmosphere.
In
cases
where
remediation
material
containing
inorganic
HAP
is
burned
in
an
incinerator,
the
incinerator
used
must
already
meet
air
standards
under
the
CAA
and
RCRA
that
limit
organic,
particulate
matter,
metals,
and
chloride
emissions.
(See,
e.
g.
40
CFR
part
263,
subpart
EEE
(MACT
standards
for
hazardous
waste
combustion
sources).)
Therefore,
we
are
proposing
that
metals
and
other
inorganic
compounds
listed
as
HAP
in
CAA
section
112(
b)
not
be
regulated
by
this
Site
Remediation
NESHAP.
We
are
specifically
requesting
comment
on
this
proposal
and,
in
particular,
would
appreciate
receiving
data
regarding
the
sources
and
quantity
of
inorganic
HAP
emissions
from
site
remediations
and
available
control
technologies
applicable
to
the
sources
in
order
to
either
support
or
revise
our
decision
not
to
regulate
inorganic
HAP
emissions
under
this
NESHAP.
C.
How
Did
We
Select
the
Affected
Source
To
Be
Regulated?
For
the
purpose
of
implementing
a
NESHAP
under
40
CFR
part
63,
``
affected
source''
is
defined
to
mean
the
stationary
source,
or
portion
of
a
stationary
source
that
is
regulated
by
a
relevant
standard
or
other
requirement
established
pursuant
to
section
112
of
the
CAA.
Each
relevant
standard
is
to
designate
the
affected
source
for
the
purposes
of
that
standard.
Within
a
source
category,
we
must
decide
which
of
the
sources
of
HAP
emissions
(i.
e.,
emission
points
or
groupings
of
emission
points)
to
which
the
proposed
rule
applies.
One
option
for
the
Site
Remediation
NESHAP
is
to
define
the
affected
source
as
the
entire
set
of
activities
performed
for
a
given
site
remediation
such
as
the
cleanup
of
contaminated
soil
or
the
cleanup
of
contaminated
groundwater.
The
affected
source
would
consist
of
the
mix
of
emission
points
for
the
sequence
of
activities
in
which
the
contaminated
media
or
other
remediation
material
is
extracted
(if
needed),
stored,
conveyed,
treated,
or,
otherwise
handled
at
the
facility.
Under
this
broad
definition
option,
a
separate
emission
limitation
for
MACT
would
be
determined
for
the
entire
group
of
emission
points
associated
with
a
site
remediation
to
clean
up
the
contaminated
soil.
Another
emission
limitation
for
MACT
would
be
determined
for
the
entire
group
of
emission
points
associated
with
a
site
remediation
to
clean
up
the
contaminated
groundwater.
Unlike
the
NESHAP
source
categories
that
can
be
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Proposed
Rules
readily
characterized
by
one
or
several
standardized
process
configurations
which
are
used
throughout
the
industrial
segment
representing
the
source
category,
the
operations
used
for
all
contaminated
soil
or
contaminated
groundwater
remediations
cannot.
The
activities,
equipment
configurations,
and
sequencing
of
operations
used
are
not
consistent
from
site
remediation
to
site
remediation.
Therefore,
we
concluded
that
this
option
is
not
an
appropriate
approach
for
defining
the
affected
sources
for
the
Site
Remediation
NESHAP.
Another
option
we
considered
is
to
define
the
affected
source
in
terms
of
common
groupings
of
processes
and
equipment
used
for
management
and
cleanup
of
contaminated
media
and
other
remediation
materials
(i.
e.,
tanks,
containers,
process
vents,
and
equipment
leaks).
Under
this
option,
MACT
is
determined
for
each
emission
source
group.
We
believe
that
this
option
is
an
appropriate
way
to
define
the
affected
source
for
the
Site
Remediation
NESHAP.
Designating
the
affected
source
to
be
a
group
of
similar
emission
point
types
ensures
that
air
emission
controls
of
equivalent
performance
are
applied
at
the
same
time
to
all
of
the
units
used
to
manage
a
remediation
material
stream.
Also,
this
approach
to
defining
sources
is
consistent
with
other
NESHAP
for
related
waste
management
operations
(e.
g.,
the
OSWRO
NESHAP).
Therefore,
for
the
Site
Remediation
NESHAP,
we
determined
separate
MACT
for
common
groups
of
emission
point
sources.
The
first
group
of
common
emission
points
designated
to
be
an
affected
source
for
the
Site
Remediation
NESHAP
is
the
group
of
pipes,
stacks,
or
ducts
that
allow
the
passage
of
gases,
vapors,
or
fumes
containing
organic
HAP
to
the
atmosphere
from
any
treatment
process
used
at
the
facility
to
remove,
destroy,
or
otherwise
transform
the
hazardous
substances
in
remediation
material.
These
pipes,
stacks,
and
ducts
are
collectively
referred
to
as
process
vents
in
the
proposed
rule.
The
process
vent
may
be
either
associated
with
an
in
situ
process
(e.
g.,
soil
vapor
extraction
used
to
treat
contaminated
soil)
or
ex
situ
process
(e.
g.,
air
stripper
used
to
treat
contaminated
ground
water,
or
thermal
desorption
unit
used
to
treat
contaminated
soil).
For
the
purposes
of
applying
the
standards,
a
process
vent
is
neither
a
vent
that
operates
as
a
safety
device
nor
a
stack
or
duct
used
to
exhaust
combustion
products
from
a
boiler,
furnace,
incinerator,
or
other
enclosed
combustion
device
that
is
being
used
to
treat
a
remediation
waste
or
material.
If
these
combustion
devices
are
being
used
as
an
air
pollution
control
device
to
control
air
emissions
then
the
vent
could
be
subject
to
the
standards.
The
next
group
of
common
emission
points
designated
to
be
an
affected
source
for
the
Site
Remediation
NESHAP
is
the
group
of
units
used
at
the
facility
which
handle,
temporarily
store,
or
otherwise
manage
the
remediation
material
once
it
has
been
extracted
from
the
ground.
This
group
of
sources
includes
units
that
treat
extracted
contaminated
media
but
do
not
use
a
process
vent
(e.
g.,
a
tank
used
for
biological
degradation
treatment
of
contaminated
groundwater).
These
units
are
tanks,
containers,
surface
impoundments,
oil
water
and
organicwater
separators,
individual
drain
systems,
and
other
stationary
transfer
or
conveyance.
The
units
regulated
under
this
affected
source
designation
are
collectively
referred
to
as
remediation
material
management
units
in
the
propose
rule.
A
third
group
of
common
emission
points
designated
to
be
an
affected
source
for
the
Site
Remediation
NESHAP
is
the
group
of
equipment
components
prone
to
emitting
organic
HAP
as
a
result
of
liquid
or
vapor
leaks.
This
group
of
equipment
consists
of
pumps,
compressors,
agitators,
pressure
relief
devices,
sampling
connection
systems,
open
ended
valves
and
lines,
valves,
connectors,
and
instrumentation
systems
that
contain
or
contact
remediation
material
once
it
has
been
extracted
from
the
ground.
We
have
identified
two
other
types
of
remediation
activities
that
may
emit
organic
HAP
but
do
not
belong
in
any
of
the
above
three
affected
source
groups.
These
activities
are
the
excavation
of
contaminated
soil
and
land
treatment
process
for
contaminated
soils,
sediments,
and
sludges.
Excavation
of
contaminated
soil
involves
the
use
of
heavy
machinery
to
dig
up
the
soil.
The
excavated
material
is
then
either
placed
directly
into
dump
trucks
for
transport
offsite
or
moved
to
another
location
at
the
facility
for
storage
or
treatment.
Land
treatment
processes
are
open
biodegradation
processes
in
which
the
contaminated
soil,
sediment,
or
sludge
is
excavated,
re
applied
in
shallow
layers
on
the
ground
surface,
and
periodically
turned
over
or
tilled
to
aerate
the
applied
material.
The
organic
contaminants
are
neutralized,
destroyed
or
transformed
by
biological
actions
of
microbes
in
the
materials.
Our
information
indicates
that
there
are
no
add
on
controls
currently
in
use
to
control
organic
emissions
from
these
activities,
nor
are
we
aware
of
any
practical
work
practices
or
process
modification
that
can
be
implemented
to
reduce
organic
HAP
emissions
from
these
activities.
Therefore,
we
are
proposing
not
to
develop
standards
under
this
NESHAP
for
either
excavation
operations
or
land
treatment
activities.
We
specifically
request
comment
on
the
technical
and
practical
feasibility
of
controlling
HAP
emissions
from
these
remediation
activities,
actual
HAP
emissions
rates
that
occur,
and
the
costs
of
applying
any
applicable
controls.
D.
How
Did
We
Determine
MACT
for
the
Affected
Sources?
Section
112(
d)(
3)
of
the
CAA
specifies
that
the
MACT
standards
for
existing
sources
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
existing
sources
for
categories
and
subcategories
with
30
or
more
sources.
There
are
many
more
than
30
site
remediations
being
conducted
nationwide.
Therefore,
the
MACT
floor
for
existing
sources
at
site
remediations
is
established
by
the
best
performing
12
percent
of
existing
sources.
We
reviewed
our
information
for
site
remediations
to
find
an
approach
for
identifying
the
best
performing
12
percent
of
existing
sources,
arraying
the
data
for
each
category
of
emission
point.
Our
data
includes
individual
existing
sites
where
remediation
activities
use
add
on
air
emission
controls
(e.
g.,
venting
air
strippers
through
carbon
adsorbers,
management
of
remediation
wastes
in
covered
tanks).
However,
there
are
remediation
sites
in
our
data
base
at
which
no
air
emission
controls
are
used.
The
use
of
air
emission
controls
at
a
given
location
depends
on
a
combination
of
factors
including,
but
not
limited
to,
the
type
and
extent
of
contamination
requiring
cleanup,
the
nature
of
the
site
remediation
activities
used
for
the
cleanup,
and
the
requirements
imposed
by
the
agency
having
oversight
of
the
site
remediation.
Determining
a
MACT
floor
based
on
use
of
control
measures
other
than
addon
controls
(e.
g.,
fuel
switching,
material
substitution
or
reformulation,
process
modification,
material
recycling
within
the
process)
is
not
technically
appropriate
for,
or
applicable
to,
the
site
remediation
source
category.
This
source
category
addresses
HAP
emissions
that
are
released
from
the
cleanup
of
pre
existing
environmental
contamination
problems.
By
the
time
the
need
for
site
remediation
has
been
identified,
the
opportunity
has
passed
for
applying
any
pollution
prevention
or
source
reduction
techniques.
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
The
use
of
add
on
air
emission
controls
by
some
existing
site
remediation
activities
indicates
that
the
average
emission
limitation
being
achieved
by
the
best
performing
12
percent
of
these
sources
is
at
some
level
above
applying
no
controls
(i.
e.,
the
emission
limitation
achieved
by
best
performing
12
percent
of
the
sources
is
greater
than
zero).
The
difficulty
we
are
presented
with
is
not
having
the
information
to
determine
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
existing
sources
at
site
remediations
nationwide.
We
do
not
have
comprehensive
nationwide
facility
survey
data
by
which
we
can
state,
with
a
reasonable
level
of
confidence,
that
the
sources
for
which
we
do
have
air
emission
control
data
do
indeed
represent
the
top
12
percent
of
the
best
performing
existing
sources
nationwide.
These
sources
may
represent
well
more
than
the
top
12
percent
but
there
also
is
the
possibility
that
the
sources
represent
less
than
the
top
12
percent.
We
do
not
have
the
data
needed
to
definitively
calculate
the
statistical
distribution
of
air
emission
controls
used
at
existing
remediation
sites
nationwide.
Obtaining
nationwide
counts
of
existing
site
remediation
activities
is
not
a
trivial
task
given
the
uniqueness
of
the
site
remediation
source
category.
Many
site
remediations
are
voluntary
actions
and
are
not
reported
for
inclusion
in
existing
EPA
site
remediation
data
bases.
Furthermore,
some
existing
site
remediations
are
performed
to
address
a
unique
contamination
situation
and
may
not
be
relevant
to
site
remediations
that
are
performed
in
the
future.
A
comprehensive
information
collection
survey
to
collect
the
needed
data
would
require
very
significant
time
and
resource
commitments
by
both
us
and
the
survey
respondents,
and
would
not
necessarily
provide
us
with
all
of
the
information
we
need.
In
addition,
it
is
not
clear
that
on
going
remediation
activities
have
the
available
data
needed
to
adequately
characterize
the
source
category.
Given
the
uniqueness
of
the
site
remediation
source
category,
the
extent
of
information
currently
available
to
us,
and
the
complexities
of
gathering
additional
meaningful
information,
we
decided
to
forgo
statistically
computing
an
emission
limitation
or
identifying
a
specific
control
technology
that
represents
the
MACT
floor
for
site
remediations.
The
MACT
floor
for
existing
affected
sources
is
some
level
of
air
emission
control
beyond
no
controls.
Because
the
provisions
of
section
112
allow
us
to
select
MACT
for
a
source
category
that
is
more
stringent
than
the
MACT
floor
(provided
that
the
control
level
selected
is
technically
achievable
and
that
we
consider
the
cost
of
achieving
the
emissions
reductions,
any
non
air
quality
health
and
environmental
impacts,
and
energy
requirements
associated
with
the
selected
control
level
(CAA
section
112(
d)(
2)),
we
chose
to
select
the
MACT
technology
directly.
To
select
a
MACT
technology
from
alternatives
beyond
the
MACT
floor
for
each
affected
source,
we
looked
at
the
types
of
air
emission
controls
required
under
national
air
standards
for
sources
similar
to
those
sources
that
potentially
may
be
associated
with
site
remediations.
These
air
standards
are
NESHAP
for
other
source
categories,
particularly
the
OSWRO
NESHAP
under
40
CFR
part
63,
subpart
DD,
and
the
air
standards
for
RCRA
hazardous
waste
treatment,
disposal,
and
facilities
under
subparts
AA,
BB,
and
CC
in
40
CFR
parts
264
and
265
(RCRA
Air
Rules).
The
control
levels
established
by
the
emission
limitation
and
work
practices
we
are
proposing
here
are
being
implemented
at
existing
sources
subject
to
these
similar
rules;
this
demonstrates
that
the
control
levels
are
technically
achievable.
As
stated
in
the
previous
paragraph,
these
control
requirements
and
action
levels
already
exist
in
either
the
RCRA
Air
Rules
or
the
OSWRO
NESHAP,
or
both.
Given
that
these
existing
rules
specify
control
requirements
for
sources
similar
to
those
comprising
the
affected
source
group
for
the
Site
Remediation
NESHAP,
and
that
sources
already
regulated
by
these
existing
standards
will
likely
manage
and/
or
treat
remediation
material
regulated
by
the
Site
remediation
NESHAP
also,
we
believe
that
the
requirements
within
these
existing
rules
represent
industry
practice
for
remediation
activities
and
therefore
MACT
for
the
Site
Remediation
NESHAP.
Nevertheless,
we
recognize
that
the
existing
standards
were
designed
for
controlling
emissions
from
ongoing
industrial
activities
that
would
continue
for
many
years,
rather
than
for
limited
duration
activities
such
as
site
remediations.
The
Agency
requests
comment
on
the
appropriateness
of
using
the
existing
standards
for
limited
duration
site
remediations.
E.
How
Did
We
Select
the
Format
of
the
Proposed
Standards?
The
proposed
standards
for
the
Site
Remediation
NESHAP
consist
of
a
combination
of
several
formats:
numerical
emission
limits
and
operating
limits,
equipment
standards,
and
work
practice
standards.
We
selected
the
formats
for
each
of
the
proposed
standards
to
be
consistent
with
the
formats
used
in
other
NESHAP
for
similar
organic
HAP
sources.
F.
How
Did
We
Select
the
Testing
and
Initial
Compliance
Requirements?
The
Site
Remediation
NESHAP
would
control
three
different
groups
of
emission
points:
process
vents,
remediation
material
management
units,
and
equipment
leaks.
The
control
technologies
and
work
practices
used
to
control
these
emission
point
groups
would
have
different
testing
and
initial
compliance
requirements.
The
methods
proposed
for
testing
and
for
demonstrating
initial
compliance
with
the
proposed
standards
are
consistent
with
those
in
other
NESHAP
that
require
using
these
same
control
technologies
and
work
practices.
We
selected
the
performance
testing
requirements
to
demonstrate
compliance
with
the
control
device
emission
limits
based
on
the
use
of
the
applicable
EPA
test
methods.
We
propose
in
the
proposed
rule
to
use
EPA
Methods
1,
1A,
2,
2A,
2C,
2D,
3,
4,
9,
18
(total
organic
HAP
or
total
organic
compounds),
22,
25,
25A,
305
and
316
of
40
CFR
part
60,
appendix
A,
and
SW
846
9095A.
Consistent
with
the
National
Technology
Transfer
and
Advancement
Act
(NTTAA),
we
conducted
searches
to
identify
potential
voluntary
consensus
standards
that
could
be
used
in
place
of
these
EPA
methods.
As
discussed
further
in
section
V.
H
of
this
preamble,
no
applicable
voluntary
consensus
standards
were
identified
as
practical
alternatives
to
the
EPA
Methods
included
in
the
proposed
rule.
G.
How
Did
We
Select
the
Continuous
Compliance
Requirements?
Continuous
monitoring
is
required
under
each
NESHAP
so
that
we
can
determine
whether
a
source
remains
in
compliance
following
the
initial
compliance
determination.
When
determining
appropriate
monitoring
options,
we
considered
the
availability
and
feasibility
of
a
number
of
monitoring
strategies
ranging
from
continuous
emission
monitoring
to
process
and
control
device
parameter
monitoring.
Monitoring
of
control
device
operating
parameters
is
considered
most
appropriate
for
many
other
similar
emission
sources
and,
therefore,
we
have
included
this
as
the
primary
monitoring
approach
in
these
proposed
standards.
We
selected
operating
parameters
for
the
following
types
of
control
devices
that
are
reliable
indicators
of
control
device
performance:
thermal
and
catalytic
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
2
Value
reported
in
$2000.
For
the
economic
impact
analysis,
EPA
adjusted
this
estimate
to
$1997
using
a
cost
factor
(0.9753)
developed
from
the
Chemical
Engineering
Composite
Plant
Cost
Index.
Thus,
the
total
annual
compliance
costs
in
$1997
is
$7.96
million.
oxidizers,
flares,
adsorbers,
condensers,
boilers,
incinerators,
and
process
heaters.
In
general,
we
are
proposing
selected
parameters
and
monitoring
provisions
that
were
included
in
the
OSWRO
NESHAP.
Sources
would
monitor
these
parameters
to
demonstrate
continuous
compliance
with
the
emission
limits
and
operating
limits.
H.
How
Did
We
Select
the
Notification,
Recordkeeping,
and
Reporting
Requirements?
The
required
notifications
and
other
reporting
are
based
on
the
General
Provisions
in
subpart
A
of
40
CFR
part
63.
The
initial
notification
and
the
semiannual
compliance
reports
include
information
on
the
remediation
material
and
affected
site
remediation
activities,
and
they
require
any
changes
to
this
information
to
be
reported
in
subsequent
reports.
Similarly,
records
are
required
that
will
enable
an
inspector
to
verify
the
facility's
compliance
status.
Due
to
the
nature
of
control
devices
that
would
be
installed
on
site
remediation
processes
and
the
emissions
being
controlled,
we
have
determined
that
control
device
parameter
monitoring
is
appropriate
in
this
circumstance.
The
required
records
and
reports
are
necessary
to
allow
the
regulatory
authority
to
verify
that
the
source
is
continuing
to
comply
with
the
standards.
IV.
Summary
of
Environmental,
Energy,
and
Economic
Impacts
A.
What
Are
the
Emissions
Reductions?
We
estimated
nationwide
organic
HAP
emissions
from
the
site
remediations
potentially
subject
to
the
proposed
rule
based
on
the
information
available
to
us
including
remediation
waste
quantity
and
treatment
practice
data
for
the
year
1997
and
earlier.
Nationwide
organic
HAP
emissions
from
regulated
sources
are
estimated
to
be
approximately
1,140
Mg/
yr.
Nationwide
VOC
emissions
from
regulated
sources
are
estimated
to
be
approximately
7,360
Mg/
yr.
(Although
not
all
VOC
are
organic
HAP,
we
may
permissibly
note
the
air
benefits
from
controlling
non
HAP
pollutants
such
as
VOC
when
considering
a
MACT
standard.
(See
S.
Rep.
101–
228,
101st
Cong.
1st
sess.
172)
We
estimate
that
implementation
of
the
proposed
rule
would
reduce
these
nationwide
air
emissions
by
approximately
50
percent
to
570
Mg/
yr
of
HAP
and
3,680
Mg/
yr
of
VOC.
B.
What
Are
the
Cost
Impacts?
The
nationwide
total
capital
investment
cost
and
the
annual
operating
cost
of
the
control
equipment
required
to
meet
the
proposed
standards
are
estimated
to
be
$17.6
million
and
$5.8
million
per
year,
respectively.
When
fully
implemented,
the
proposed
rule
is
estimated
to
result
in
a
total
annual
cost
of
$8.2
million
per
year.
C.
What
Are
the
Economic
Impacts?
The
proposed
rule
would
affect
owners
and
operators
of
facilities,
subject
to
the
exceptions
described
in
section
I.
A
of
this
preamble,
that
are
major
sources
of
HAP
emissions
and
at
which
a
site
remediation
is
conducted
to
clean
up
media
or
other
material
contaminated
with
any
of
the
organic
HAP
substances
listed
in
the
proposed
rule.
Because
of
the
nature
of
activities
regulated
by
the
source
category,
a
comprehensive
list
of
NAICS
codes
cannot
be
compiled
for
businesses
or
facilities
potentially
regulated
by
this
action.
As
a
result,
the
economic
impact
analyses
focused
on
a
set
of
industries
from
the
1997
Biennial
Reporting
System
(BRS)
database
that
were
known
to
be
large
quantity
generators
of
hazardous
waste
and
who
were
remediating
hazardous
waste
as
part
of
a
site
remediation.
We
believe
that
the
data
provides
an
adequate
overview
of
the
potential
impacts
of
the
proposed
rule.
However
we
recognize
that
the
actual
industries
directly
impacted
by
the
proposed
rule
in
the
year
the
proposed
rule
is
implemented
and
the
costs
incurred
by
these
industries
may
differ
somewhat
from
the
set
of
industries
identified
in
the
1997
BRS
data
and
the
costs
assigned
to
these
industries
for
the
purposes
of
the
economic
analysis.
In
general,
we
did
not
find
evidence
of
significant
impacts
at
the
industry
level.
From
the
BRS
data,
over
80
industries
were
predicted
to
have
annual
compliance
costs
as
a
result
of
the
proposed
rule,
and
15
industries
accounted
for
91
percent
of
the
national
compliance
cost
estimate
of
$8.16
million
2
.
We
employed
an
engineering
or
financial
analysis
to
estimate
impacts,
which
takes
the
form
of
the
ratio
of
compliance
costs
to
the
value
of
sales
(cost
to
sales
ratio
(CSR)).
We
calculated
CSR
for
12
industries
and
found
all
had
CSR
below
0.02
percent.
The
CSR
are
less
than
the
lower
quartile
return
on
sales
for
all
industries
with
profitability
data
available.
We
did
not
compute
CSR
for
the
remaining
three
industries
because
revenue
data
were
not
available.
The
CSR
will
likely
overstate
the
impact
on
firms
and
understate
the
impact
on
consumers.
The
CSR
assumes
that
there
are
no
changes
in
the
market
as
a
result
of
the
higher
costs
of
production
faced
by
the
firms
and
that
the
firms
continue
to
produce
the
same
quantities,
sell
at
the
same
price
and
absorb
the
full
amount
of
the
compliance
costs.
Small
business
impacts
were
particularly
difficult
to
assess
because
of
the
uncertainty
over
the
facilities
that
will
actually
be
impacted
by
the
proposed
rule.
As
a
result,
we
concluded
that
sufficient
data
and
related
information
did
not
exist
to
conduct
a
small
business
screening
analysis.
D.
What
Are
the
Non
Air
Quality
Environmental
and
Energy
Impacts?
Compliance
with
the
standards
in
the
proposed
rule
requires
using
types
of
control
equipment
commonly
in
use
to
control
organic
emissions
from
process
sources
at
many
of
the
industrial
facilities
at
which
site
remediations
are
most
likely
to
occur.
The
non
air
environmental
and
energy
impacts
associated
with
implementing
the
requirements
of
the
proposed
rule
primarily
are
expected
to
result
from
the
operation
of
these
control
devices.
No
significant
adverse
water,
solid
waste,
or
energy
impacts
are
expected
as
a
result
of
the
proposed
rule.
V.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(58
FR
51735,
October
4,
1993),
the
EPA
must
determine
whether
the
regulatory
action
is
``
significant''
and,
therefore,
subject
to
review
by
the
Office
of
Management
and
Budget
(OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(1)
Have
an
annual
effect
on
the
economy
of
$100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(2)
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(3)
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
or
loan
programs,
or
the
rights
and
obligations
of
recipients
thereof;
or
(4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
It
has
been
determined
that
the
proposed
rule
is
not
a
``
significant
regulatory
action''
under
the
terms
of
Executive
Order
12866
and
is,
therefore,
not
subject
to
OMB
review.
B.
Executive
Order
13132,
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(64
FR
43255,
August
10,
1999),
requires
the
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.
''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.
''
Under
Section
6
of
Executive
Order
13132,
the
EPA
may
not
issue
a
regulation
that
has
federalism
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,
unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
State
and
local
governments,
or
the
EPA
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
The
EPA
also
may
not
issue
a
regulation
that
has
federalism
implications
and
that
preempts
State
law
unless
the
EPA
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
The
proposed
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
the
proposed
rule.
C.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(65
FR
67249,
November
6,
2000),
requires
the
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.
''
``
Policies
that
have
tribal
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
the
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes.
''
Under
section
5(
b)
of
Executive
Order
13175,
EPA
may
not
issue
a
regulation
that
has
tribal
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,
unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
tribal
governments,
or
EPA
consults
with
tribal
officials
early
in
the
process
of
developing
the
proposed
regulation.
Under
section
5(
c)
of
Executive
Order
13175,
EPA
may
not
issue
a
regulation
that
has
tribal
implications
and
that
preempts
tribal
law,
unless
the
Agency
consults
with
tribal
officials
early
in
the
process
of
developing
the
proposed
regulation.
The
EPA
has
concluded
that
the
proposed
rule
may
have
tribal
implications
since
site
remediation
activities
could
be
conducted
on
tribal
lands.
We
do
not
have
any
information
identifying
specific
remediation
activities
being
conducted
at
this
time.
However,
it
will
neither
impose
substantial
direct
compliance
costs
on
tribal
governments,
nor
preempt
State
law.
Thus,
the
requirements
of
sections
5(
b)
and
5(
c)
of
the
Executive
Order
do
not
apply
to
the
proposed
rule.
Consistent
with
EPA
policy,
EPA
nonetheless
has
made
attempts
to
invite
tribal
representatives
to
participate
in
the
rulemaking
activities
early
in
the
process
of
developing
this
proposed
rule
to
permit
them
to
have
meaningful
and
timely
input
into
its
development.
We
have
contacted
tribal
representatives
and
groups
directly
to
notify
them
of
this
proposed
rule
development
activity
and
to
solicit
their
participation.
Despite
these
efforts,
EPA
has
not
been
contacted
by
tribal
representatives
to
participate
in
the
rulemaking
process
to
date.
In
the
spirit
of
Executive
Order
13175,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
tribal
governments,
EPA
specifically
solicits
comment
on
the
proposed
rule
from
tribal
officials.
D.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(1)
is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(2)
concerns
an
environmental
health
or
safety
risk
that
the
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
the
EPA
must
evaluate
the
environmental
health
or
safety
effects
of
the
proposed
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
EPA.
The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5–
501
of
the
Executive
Order
has
the
potential
to
influence
the
regulation.
The
proposed
rule
is
not
subject
to
Executive
Order
13045
because
it
is
based
on
technology
performance
and
not
on
health
or
safety
risks.
No
children's
risk
analysis
was
performed
because
no
alternative
technologies
exist
that
would
provide
greater
stringency
at
a
reasonable
cost.
Furthermore,
the
proposed
rule
has
been
determined
not
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866.
E.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
The
proposed
rule
is
not
subject
to
Executive
Order
13211,
``
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(66
FR
28355,
May
22,
2001)
because
it
is
not
a
significant
regulatory
action
under
Executive
Order
12866.
F.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(UMRA),
Public
Law
104–
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
the
EPA
generally
must
prepare
a
written
statement,
including
a
costbenefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
by
State,
local,
and
tribal
governments,
in
aggregate,
or
by
the
private
sector,
of
$100
million
or
more
in
any
1
year.
Before
promulgating
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Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
the
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
the
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
of
why
that
alternative
was
not
adopted.
Before
the
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
The
EPA
has
determined
that
the
proposed
rule
does
not
contain
a
Federal
mandate
that
may
result
in
expenditures
of
$100
million
or
more
for
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
The
maximum
total
annual
cost
of
the
proposed
rule
for
any
year
has
been
estimated
to
be
about
$23.4
million.
Thus,
today's
proposed
rule
is
not
subject
to
the
requirements
of
sections
202
and
205
of
the
UMRA.
In
addition,
the
EPA
has
determined
that
the
proposed
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments
because
it
contains
no
requirements
that
apply
to
such
governments
or
impose
obligations
upon
them.
Therefore,
today's
proposed
rule
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.
G.
Regulatory
Flexibility
Act
(RFA)
As
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(SBREFA),
5
U.
S.
C.
601
et
seq.
Under
the
Regulatory
Flexibility
Act,
the
Agency
must
prepare
a
Regulatory
Flexibility
Analysis
unless
the
Administrator
certifies
that
the
rule,
if
promulgated,
will
not
impose
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
The
Courts
consistently
have
held
that
the
provisions
of
the
RFA
apply
only
with
respect
to
small
entities
that
are
subject
to
the
proposed
rule.
The
proposed
rule
sets
minimum
standards
to
be
met
when
parties
engage
in
future
site
remediation
activities,
but
it
does
not
itself
require
any
party
to
undertake
such
activities.
States
may
choose
to
direct
a
party
to
undertake
site
remediation,
or
parties
may
undertake
remediation
activities
voluntarily.
Today's
action
places
no
requirement
on
any
party
to
initiate
site
remediation
activities.
The
EPA
anticipates
that
parties
that
undertake
site
remediation
activities
generally
will
do
so
voluntarily
and
that
the
impact
of
the
proposed
rule
on
those
parties
would
not
be
significant.
Further,
because
States
and
other
parties
will
decide
whether
to
undertake
site
remediation
activities,
it
is
extremely
difficult,
if
not
impossible,
to
predict
how
many
or
what
types
of
small
entities
will
undertake
such
activities.
In
addition,
the
proposed
rule
is
structured
to
avoid
impacts
on
small
businesses.
The
proposed
rule
specifically
excludes
from
its
scope
remediation
activities
conducted
at
gasoline
stations,
farm
sites
and
residential
sites
(on
the
ground
that
these
remediation
activities
would
not
exceed
the
threshold
for
major
sources).
Moreover,
the
proposed
rule
would
apply
only
to
remediation
sites
located
at
a
facility
that
is
a
major
source
under
the
CAA
and
engages
in
a
``
MACT
activity''
(defined
as
a
nonremediation
activity
covered
in
the
MACT
list
of
major
source
categories
pursuant
to
CAA
section
112(
c)).
Such
sources
tend
to
be
large
businesses.
The
proposed
rule
also
contains
emissions
thresholds
that
are
not
likely
to
apply
to
small
businesses.
For
example,
the
proposed
rule
exempts
sources
where
the
total
annual
quantity
of
HAP
contained
in
all
extracted
remediation
material
at
the
facility
is
less
than
1
Mg/
yr.
For
these
reasons,
I
certify
that
the
rule,
if
promulgated,
will
not
impose
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
H.
Paperwork
Reduction
Act
We
will
submit
the
information
collection
requirements
in
the
proposed
rule
for
approval
to
the
Office
of
Management
and
Budget
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
An
Information
Collection
Request
(ICR)
document
has
been
prepared
by
EPA
(ICR
No.
2062.01)
and
you
may
obtain
a
copy
from
Susan
Auby
by
mail
at
U.
S.
EPA,
Office
of
Environmental
Information,
Collection
Strategies
Division
(2822T),
1200
Pennsylvania
Avenue,
NW,
Washington,
DC
20460,
by
e
mail
at
auby.
susan@
epa.
gov,
or
by
calling
(202)
566–
1672.
A
copy
may
also
be
downloaded
off
the
Internet
at
http://
www.
epa.
gov/
icr.
The
information
requirements
are
not
effective
until
OMB
approves
them.
The
information
requirements
are
based
on
notification,
recordkeeping,
and
reporting
requirements
in
the
NESHAP
General
Provisions
(40
CFR
part
63,
subpart
A),
which
are
mandatory
for
all
operators
subject
to
national
emission
standards.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(42
U.
S.
C.
7414).
All
information
submitted
to
the
EPA
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
EPA
policies
set
forth
in
40
CFR
part
2,
subpart
B.
The
proposed
rule
would
require
maintenance
inspections
of
the
control
devices
but
would
not
require
any
notifications
or
reports
beyond
those
required
by
the
General
Provisions
in
subpart
A
to
40
CFR
part
63.
The
recordkeeping
requirements
require
only
the
specific
information
needed
to
determine
compliance.
The
annual
monitoring,
reporting,
and
recordkeeping
burden
to
affected
sources
for
this
collection
(averaged
over
the
first
3
years
after
the
effective
date
of
the
promulgated
rule)
is
estimated
to
be
341,737
labor
hours
per
year,
with
a
total
annual
cost
of
$17.7
million
per
year.
These
estimates
include
a
one
time
performance
test
and
report
(with
repeat
tests
where
needed),
one
time
submission
of
an
SSMP
with
semiannual
reports
for
any
event
when
the
procedures
in
the
plan
were
not
followed,
semiannual
compliance
reports,
maintenance
inspections,
notifications,
and
recordkeeping.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
Agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
the
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Comments
are
requested
on
the
Agency's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
By
U.
S.
Postal
Service,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
EPA
(2822T),
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460,
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
St.,
NW.,
Washington,
DC
20503,
marked
``
Attention:
Desk
Officer
for
EPA''.;
or
by
courier,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
EPA
(2822T),
1301
Constitution
Avenue,
NW.,
Room
6143,
Washington,
DC
20460
(202)
566–
1700.
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
July
30,
2002,
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
August
29,
2002.
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
this
proposal.
I.
National
Technology
Transfer
and
Advancement
Act
Under
section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(NTTAA)
(Public
Law
No.
104–
113,
all
Federal
agencies
are
required
to
use
voluntary
consensus
standards
(VCS)
in
their
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
requires
Federal
agencies
to
provide
Congress,
through
annual
reports
to
OMB,
with
explanations
when
an
agency
does
not
use
available
and
applicable
VCS.
The
proposed
rulemaking
involves
technical
standards.
The
EPA
proposes
in
the
proposed
rule
to
use
EPA
Methods
1,
1A,
2,
2A,
2C,
2D,
3,
4,
9,
18
(total
organic
HAP
or
total
organic
compounds),
22,
25,
25A,
305
and
316
of
40
CFR
part
60,
appendix
A,
and
Method
9095A
in
SW
846,
``
Test
Methods
for
Evaluating
Solid
Waste,
Physical/
Chemical
Methods.
''
Consistent
with
the
NTTAA,
EPA
conducted
searches
to
identify
VCS
in
addition
to
these
EPA
methods.
No
applicable
VCS
were
identified
for
EPA
Methods
included
in
the
proposed
rule.
The
search
for
emissions
measurement
procedures
identified
12
VCS
as
potential
alternatives
to
the
EPA
methods
specified
in
the
proposed
rule.
Following
further
evaluation,
the
EPA
determined
that
ten
of
these
12
standards
identified
for
measuring
emissions
of
HAP
or
surrogates
subject
to
emissions
standards
in
the
proposed
rule
were
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rule.
Therefore,
the
EPA
does
not
intend
to
adopt
these
standards.
The
reasons
for
the
determinations
of
these
nine
methods
are
discussed
below.
The
standard
ISO
10780:
1994,
``
Stationary
Source
Emissions—
Measurement
of
Velocity
and
Volume
Flowrate
of
Gas
Streams
in
Ducts,
''
is
impractical
as
an
alternative
to
EPA
Method
2
in
the
proposed
rule.
This
standard,
ISO
10780:
1994,
recommends
the
use
of
L
shaped
pitots,
which
historically
have
not
been
recommended
by
EPA
because
the
Stype
design
has
large
openings
which
are
less
likely
to
plug
up
with
dust.
The
standard
ASTM
D3464–
96,
``
Standard
Test
Method
Average
Velocity
in
a
Duct
Using
a
Thermal
Anemometer,
''
is
impractical
as
an
alternative
to
EPA
Method
2
for
the
purposes
of
the
proposed
rule
primarily
because
applicability
specifications
are
not
clearly
defined,
(e.
g.,
range
of
gas
composition,
temperature
limits).
Also,
the
lack
of
supporting
quality
assurance
data
for
the
calibration
procedures
and
specifications,
and
certain
variability
issues
that
are
not
adequately
addressed
by
the
ASTM
standard
limit
EPA's
ability
to
make
a
definitive
comparison
of
the
method
in
these
areas.
The
VCS
ASTM
D6060
(in
review
2000),
``
Practice
for
Sampling
of
Process
Vents
with
a
Portable
Gas
Chromatograph,
''
is
an
impractical
alternative
for
EPA
Method
18
for
the
purposes
of
the
proposed
rule
because
it
lacks
acceptance
criteria
for
calibration,
details
on
using
other
collection
media
(e.
g.,
solid
sorbents),
and
reporting/
documentation
requirements
that
are
included
in
EPA
Method
18.
The
VCS
ASTM
D6420–
99,
``
Standard
Testing
Method
for
Determination
of
Gaseous
Organic
Compounds
by
Direct
Interface
Gas
Chromatography
Mass
Spectrometry
(GC/
MS),
''
also
is
an
impractical
alternative
for
EPA
Method
18
for
the
purposes
of
the
proposed
rule.
This
method
only
detects
25
of
the
98
specific
organic
HAP
constituents
subject
to
regulation
by
the
proposed
rule.
The
specific
organic
HAP
composition
of
the
remediation
material
to
be
cleaned
up
is
often
unknown
and
using
a
method
to
determine
compliance
with
total
organic
HAP
emissions
limitations
that
only
detects
a
narrow
subset
of
the
entire
group
of
98
organic
HAP
compounds
subject
to
the
proposed
rule
is
not
appropriate.
Method
18
is
the
only
method
currently
available
to
ensure
that
all
98
HAP
compounds
regulated
by
the
proposed
rule
are
accounted
for
in
the
computation
of
the
total
organic
HAP
emissions
from
an
affected
source.
We
request
comment
on
our
decision
not
to
include
ASTM
method
D6420–
99.
Two
VCS,
EN
12619:
1999
``
Stationary
Source
Emissions
Determination
of
the
Mass
Concentration
of
Total
Gaseous
Organic
Carbon
at
Low
Concentrations
in
Flue
Gases—
Continuous
Flame
Ionization
Detector
Method''
and
ISO
14965:
2000(
E)
``
Air
QualityDetermination
of
Total
Nonmethane
Organic
Compounds
Cryogenic
Preconcentration
and
Direct
Flame
Ionization
Method,
''
are
impractical
alternatives
to
EPA
Method
25A
for
the
purposes
of
this
rulemaking
because
the
standards
do
not
apply
to
solvent
process
vapors
in
concentrations
greater
than
40
ppm
for
EN
12619
and
10
ppm
carbon
for
ISO
14965.
Methods
with
whose
upper
limits
are
this
low
are
too
limited
to
be
useful
in
measuring
source
emissions,
which
are
expected
to
be
much
higher.
Four
of
the
nine
VCS
are
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rule
because
they
are
too
general,
too
broad,
or
not
sufficiently
detailed
to
assure
compliance
with
EPA
regulatory
requirements:
ASTM
D3796–
90
(Reapproved
1996),
``
Standard
Practice
for
Calibration
of
Type
S
Pitot
Tubes,
''
for
EPA
Method
2;
ASME
C00031
or
PTC
19–
10–
1981—
Part
10,
``
Flue
and
Exhaust
Gas
Analyses,
''
for
EPA
Method
3;
ASTM
E337–
84
(Reapproved
1996),
``
Standard
Test
Method
for
Measuring
Humidity
with
a
Psychrometer
(the
Measurement
of
Wet
and
Dry
Bulb
Temperatures),
''
for
EPA
Method
4;
and
ASTM
D3154–
91,
``
Standard
Method
for
Average
Velocity
in
a
Duct
(Pitot
Tube
Method),
''
for
EPA
Methods
1,
2,
2C,
3,
and
4.
Two
of
the
11
VCS
identified
in
this
search
were
not
available
at
the
time
the
review
was
conducted
for
the
purposes
of
the
proposed
rule
because
they
are
under
development
by
a
voluntary
consensus
body:
ASME/
BSR
MFC
13M,
``
Flow
Measurement
by
Velocity
Traverse,
''
for
EPA
Method
1
(and
possibly
2);
and
ASME/
BSR
MFC
12M,
``
Flow
in
Closed
Conduits
Using
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Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
Multiport
Averaging
Pitot
Primary
Flowmeters,
''
for
EPA
Method
2.
While
we
are
not
proposing
to
include
these
two
VCS
in
today's
proposed
rule,
the
EPA
will
consider
the
standards
when
they
are
finalized.
The
EPA
takes
comment
on
the
compliance
demonstration
requirements
in
the
proposed
rule
and
specifically
invites
the
public
to
identify
potentially
applicable
VCS.
The
commenter
should
also
explain
why
this
regulation
should
adopt
these
VCS
in
lieu
of
or
in
addition
to
EPA's
standards.
Emission
test
methods
and
performance
specifications
submitted
for
evaluation
should
be
accompanied
with
a
basis
for
the
recommendation,
including
method
validation
data
and
the
procedure
used
to
validate
the
candidate
method
(if
a
method
other
than
Method
301,
40
CFR
part
63,
Appendix
A
was
used).
Section
63.2406
and
Table
5
of
the
proposed
subpart
GGGGG
list
the
EPA
testing
methods
and
performance
standards
included
in
the
proposed
rule.
Most
of
the
standards
have
been
used
by
States
and
industry
for
more
than
10
years.
Nevertheless,
under
§
63.7(
f)
of
subpart
A
of
40
CFR
part
63,
the
proposed
rule
also
allows
any
State
or
source
to
apply
to
the
EPA
for
permission
to
use
an
alternative
method
in
place
of
any
of
the
EPA
testing
methods
or
performance
standards
listed
in
the
proposed
rule.
List
of
Subjects
in
40
CFR
Part
63
Environmental
protection,
Air
pollution
control,
Hazardous
substances,
Reporting
and
recordkeeping
requirements.
Dated:
July
3,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
stated
in
the
preamble,
title
40,
chapter
I,
part
63,
of
the
Code
of
the
Federal
Regulations
is
proposed
to
be
amended
as
follows:
PART
63—[
AMENDED]
1.
The
authority
citation
for
part
63
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401,
et
seq.
2.
Part
63
is
amended
by
adding
subpart
GGGGG
to
read
as
follows:
Subpart
GGGGG—
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Site
Remediation
What
This
Subpart
Covers
Sec.
63.7880
What
is
the
purpose
of
this
subpart?
63.7881
Am
I
subject
to
this
subpart?
63.7882
What
activities
at
my
facility
does
this
subpart
cover?
63.7883
When
do
I
have
to
comply
with
this
subpart?
Emissions
Limitations
and
Work
Practice
Standards
63.7890
What
emissions
limitations
and
work
practice
standards
must
I
meet?
General
Compliance
Requirements
63.7900
What
are
my
general
requirements
for
complying
with
this
subpart?
63.7901
What
requirements
must
I
meet
if
I
transfer
remediation
material
to
another
party,
another
facility,
or
receive
remediation
material
from
another
facility?
Testing
and
Initial
Compliance
Requirements
63.7910
By
what
date
must
I
conduct
performance
tests
or
other
initial
compliance
demonstrations?
63.7911
When
must
I
conduct
subsequent
performance
tests?
63.7912
What
tests,
design
evaluations,
and
other
procedures
must
I
use?
63.7913
What
are
my
monitoring
installation,
operation,
and
maintenance
requirements?
63.7914
How
do
I
demonstrate
initial
compliance
with
the
emissions
limitations
and
work
practice
standards?
Continuous
Compliance
Requirements
63.7920
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
63.7921
How
do
I
demonstrate
continuous
compliance
with
the
emissions
limitations
and
work
practice
standards?
Notifications,
Reports,
and
Records
63.7930
What
notifications
must
I
submit
and
when?
63.7931
What
reports
must
I
submit
and
when?
63.7932
What
records
must
I
keep?
63.7933
In
what
form
and
how
long
must
I
keep
my
records?
Other
Requirements
and
Information
63.7940
What
parts
of
the
General
Provisions
apply
to
me?
63.7941
Who
implements
and
enforces
this
subpart?
63.7942
What
definitions
apply
to
this
subpart?
Tables
to
Subpart
GGGGG
of
Part
63
Table
1
to
Subpart
GGGGG
of
Part
63—
Hazardous
Air
Pollutants
Table
2
to
Subpart
GGGGG
of
Part
63—
Emissions
Limitations
for
Process
Vent
Affected
Sources
Table
3
to
Subpart
GGGGG
of
Part
63—
Emissions
Limitations
for
Remediation
Material
Management
Unit
Affected
Sources
Table
4
to
Subpart
GGGGG
of
Part
63—
Operating
Limits
and
Associated
Work
Practices
for
Control
Devices
Table
5
to
Subpart
GGGGG
of
Part
63—
Work
Practice
Standards
Table
6
to
Subpart
GGGGG
of
Part
63—
Requirements
for
Performance
Tests
Table
7
to
Subpart
GGGGG
of
Part
63—
Initial
Compliance
With
Emissions
Limitations
Table
8
to
Subpart
GGGGG
of
Part
63—
Initial
Compliance
with
Work
Practice
Standards
Table
9
to
Subpart
GGGGG
of
Part
63—
Continuous
Compliance
with
Emissions
Limitations
Table
10
to
Subpart
GGGGG
of
Part
63—
Continuous
Compliance
with
Operating
Limits
Table
11
to
Subpart
GGGGG
of
Part
63—
Continuous
Compliance
with
Work
Practice
Standards
Table
12
to
Subpart
GGGGG
of
Part
63—
Requirements
for
Reports
Table
13
to
Subpart
GGGGG
of
Part
63—
Applicability
of
General
Provisions
to
Subpart
GGGGG
Subpart
GGGGG—
National
Emission
Standards
for
Hazardous
Air
Pollutants—
Site
Remediation
What
This
Subpart
Covers
§
63.7880
What
is
the
purpose
of
this
subpart?
This
subpart
establishes
national
emissions
limitations
and
work
practice
standards
for
hazardous
air
pollutants
(HAP)
emitted
from
site
remediation
activities.
This
subpart
also
establishes
requirements
to
demonstrate
initial
and
continuous
compliance
with
the
emissions
limitations
and
work
practice
standards.
§
63.7881
Am
I
subject
to
this
subpart?
(a)
This
subpart
covers
remediation
activities
within
the
site
remediation
source
category,
which
excludes
remediation
at
gasoline
stations,
farm
sites
and
residential
sites.
(b)
This
subpart
applies
to
you
if
you
meet
all
of
the
criteria
listed
in
paragraphs
(b)(
1)
and
(2)
of
this
section:
(1)
You
own
or
operate
a
site
remediation
activity
that
is
collocated
within
a
facility
with
other
sources
that
are
individually
or
collectively
a
major
source
of
HAP
emissions;
and
(2)
A
MACT
activity,
as
defined
in
§
63.7942,
is
performed
at
the
facility.
(c)
Remediation
means
the
cleanup
of
remediation
material.
For
the
purposes
of
this
subpart,
monitoring
or
measuring
contamination
levels
through
wells,
or
by
sampling,
is
not
considered
to
be
remediation.
(d)
A
major
source
of
HAP
is
any
stationary
source
or
group
of
stationary
sources
located
within
a
contiguous
area
and
under
common
control
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
9.07
megagrams
(10
tons)
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
22.68
megagrams
(25
tons)
or
more
per
year.
A
source
that
is
not
a
major
source
is
an
area
source.
(e)
You
are
not
subject
to
the
requirements
of
this
subpart
if
any
of
the
criteria
in
paragraphs
(d)(
1)
through
(7)
of
this
section
apply.
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
(1)
Your
facility
is
an
area
source;
or
(2)
A
MACT
activity
is
not
performed
at
your
facility;
or
(3)
You
are
not
conducting
a
remediation
activity
at
your
facility;
or
(4)
You
do
not
have
an
affected
source
involved
in
any
remediation
activity
conducted
at
the
facility;
or
(5)
Your
facility
is
a
research
and
development
facility,
consistent
with
section
112(
b)(
7)
of
the
CAA.
(6)
The
remediation
is
performed
under
the
authority
of
the
Comprehensive
Environmental
Response
and
Compensation
Liability
Act.
(7)
Your
remediation
activity
is
a
corrective
action:
(i)
At
a
Resource
Conservation
and
Recovery
Act
(RCRA)
Treatment,
Storage
and
Disposal
facility
(TSDF)
permitted
either
by
the
U.
S.
Environmental
Protection
Agency
(EPA)
or
under
a
state
program
authorized
by
EPA
under
RCRA
section
3006;
(ii)
At
an
interim
status
TSDF
conducted
under
an
order
imposed
by
EPA
or
a
state
program
authorized
for
corrective
action
under
RCRA
section
3006;
or
(iii)
at
any
facility
as
required
by
orders
authorized
under
RCRA
section
7003.
(f)
You
are
not
subject
to
the
requirements
of
this
subpart,
except
for
the
recordkeeping
requirements
in
§
63.7933,
if
all
remediation
activities
at
your
facility
subject
to
this
subpart
are
completed
and
you
have
notified
the
Administrator
in
writing
that
all
remediation
activities
subject
to
this
subpart
are
completed.
All
future
remediation
activity
meeting
the
applicability
criteria
in
paragraph
(b)
of
this
section
must
comply
with
the
requirements
of
this
subpart.
§
63.7882
What
activities
at
my
facility
does
this
subpart
cover?
(a)
This
subpart
applies
to
each
new,
reconstructed,
or
existing
remediation
affected
source.
The
emissions
sources
listed
in
paragraphs
(b)(
1)
through
(3)
of
this
section
located
at
a
facility
meeting
the
criteria
specified
in
§
63.7881(
a)
constitute
the
affected
source:
(b)(
1)
Process
vents.
The
affected
source
is
the
entire
group
of
process
vents
associated
with
both
in
situ
and
ex
situ
remediation.
(2)
Remediation
material
management
units.
The
affected
source
is
the
entire
group
of
tanks,
surface
impoundments,
containers,
oil/
water
separators,
organic/
water
separators
and
transfer
systems
involved
in
remediation.
For
the
purpose
of
implementing
the
standards
under
this
subpart,
a
unit
that
meets
the
definition
of
a
tank
or
container
that
is
also
equipped
with
a
vent
that
serves
as
a
process
vent
for
processes
including,
but
not
limited
to,
air
stripping
and
solvent
extraction,
as
defined
in
§
63.7942,
is
not
a
remediation
material
management
unit,
but
instead
is
a
process
vent
and
is
to
be
included
in
the
appropriate
affected
source
group
under
paragraph
(b)(
1)
of
this
section.
(3)
Equipment
leaks.
The
affected
source
is
the
entire
group
of
equipment
components
(pumps,
valves,
etc.)
involved
in
remediation,
meeting
both
of
the
conditions
specified
in
paragraphs
(b)(
3)(
i)
and
(ii)
of
this
section.
If
either
of
these
conditions
do
not
apply
to
an
equipment
component,
then
that
component
is
not
part
of
the
affected
source
for
equipment
leaks.
(i)
The
equipment
component
contains
or
contacts
remediation
material
having
a
total
HAP
concentration
equal
to
or
greater
than
10
percent
by
weight;
and
(ii)
The
equipment
component
is
intended
to
operate
for
300
hours
or
more
during
a
calendar
year
in
remediation
material
service,
as
defined
in
§
63.7942.
(c)
Exceptions.
(1)
Facility
wide
exemption.
You
are
exempt
from
the
requirements
of
this
subpart
where
the
total
annual
quantity
of
HAP
contained
in
all
extracted
remediation
material
at
the
facility
(including
HAP
emitted
from
process
vents)
is
less
than
1
megagram
per
year.
For
your
facility
to
be
exempt
under
the
provisions
of
this
paragraph,
you
must
meet
the
requirements
in
paragraphs
(c)(
1)(
i)
through
(iii)
of
this
section.
(i)
You
must
prepare
an
initial
determination
of
the
total
annual
HAP
quantity
in
the
extracted
remediation
material
at
the
facility.
This
determination
is
based
on
the
total
quantity
of
HAP
in
Table
1
of
this
subpart
as
determined
at
the
point
ofextraction
for
each
remediation
material
component.
The
quantity
of
HAP
contained
in
vent
streams
from
in
situ
remediation
operations
must
be
included
in
the
determination
of
the
total
annual
organic
HAP
quantity
in
Table
1
of
this
subpart.
The
HAP
quantity
in
the
vent
streams
must
be
determined
prior
to
any
control
devices.
(ii)
You
must
prepare
a
new
determination
whenever
the
extent
of
changes
to
the
quantity
or
composition
of
the
remediation
material
extracted
at
the
facility
could
cause
the
total
annual
HAP
quantity
in
Table
1
of
this
subpart
in
the
extracted
remediation
material
to
exceed
1
megagram
per
year.
(iii)
You
must
maintain
documentation
to
support
your
determination
of
the
total
annual
HAP
quantity
in
the
extracted
remediation
material.
This
documentation
must
include
the
basis
and
data
used
for
determining
the
HAP
content
of
the
extracted
remediation
material.
(2)
Affected
source
exemption.
Any
affected
source
that
is
also
subject
to
another
subpart
under
40
CFR
part
61
or
40
CFR
part
63,
where
you
are
controlling
the
HAP
in
Table
1
of
this
subpart
that
are
emitted
from
the
source
in
compliance
with
the
provisions
specified
in
the
other
applicable
subpart
under
part
61
or
63,
is
exempt
from
the
requirements
of
§§
63.7883
through
63.7933.
(3)
Process
vents.
You
are
exempt
from
the
requirements
of
§§
63.7890
through
63.7933
for
process
vents
if
any
of
the
criteria
listed
in
paragraphs
(c)(
3)(
i)
through
(iv)
of
this
section
are
met,
except
that
the
records
of
the
determination
of
these
criteria
must
be
maintained
as
required
in
§
63.7932(
a)(
4):
(i)
Affected
process
vents
where
the
emissions
of
HAP
in
Table
1
of
this
subpart
from
all
vents
at
the
facility
involved
in
remediation
are
below
1.4
kilograms
per
hour
(3
pounds
per
hour)
and
2.8
megagrams
per
year
(3.1
tons
per
year)
as
determined
by
the
procedures
specified
in
§
63.7912(
f).
(ii)
Individual
process
vents
associated
with
ex
situ
remediation
operations
that
manage
remediation
material
with
a
Table
1
(of
this
subpart)
HAP
concentration
less
than
10
parts
per
million
by
weight
(ppmw).
The
HAP
concentration
must
be
determined
in
accordance
with
the
procedures
specified
in
§
63.7912(
a).
Documentation
must
be
prepared
by
the
owner
or
operator
and
maintained
at
the
facility
to
support
the
determination
of
the
remediation
material
concentration.
This
documentation
must
include
identification
of
each
process
vent
exempted
under
this
paragraph
and
any
test
results
used
to
determine
the
HAP
concentration.
(iii)
Individual
process
vents
where
you
determine
that
the
process
vent
stream
flow
rate
is
less
than
6.0
cubic
meters
per
minute
(m
3
/min)
at
standard
conditions
(as
defined
in
40
CFR
63.2)
and
the
total
HAP
concentration
is
less
than
20
parts
per
million
by
volume
(ppmv).
The
process
vent
stream
flow
rate
and
total
HAP
concentration
must
be
determined
in
accordance
with
the
procedures
specified
in
§
63.694(
m).
For
the
purposes
of
this
subpart,
when
you
read
the
term
``
HAP
listed
in
Table
1
of
this
subpart''
in
40
CFR
Subpart
DD,
you
should
refer
to
Table
1
of
this
Subpart.
Documentation
must
be
prepared
by
the
owner
or
operator
and
maintained
at
the
facility
to
support
the
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/
Vol.
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No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
determination
of
the
process
vent
stream
flow
rate
and
total
HAP
concentration.
This
documentation
must
include
identification
of
each
process
vent
exempted
under
this
paragraph
and
the
test
results
used
to
determine
the
process
vent
stream
flow
rate
and
total
HAP
concentration.
You
must
perform
a
new
determination
of
the
process
vent
stream
flow
rate
and
total
HAP
concentration
when
the
extent
of
changes
to
operation
of
the
unit
on
which
the
process
vent
is
used
could
cause
either
the
process
vent
stream
flow
rate
to
exceed
the
limit
of
6.0
m
3
/min
or
the
total
HAP
concentration
to
exceed
the
limit
of
20
ppmv.
(iv)
Individual
process
vents
where
you
determine
that
the
process
vent
stream
flow
rate
is
less
than
0.005
m
3
/
min
at
standard
conditions
(as
defined
in
40
CFR
63.2).
The
process
vent
stream
flow
rate
must
be
determined
in
accordance
with
the
procedures
specified
in
§
63.694(
m).
Documentation
must
be
prepared
by
the
owner
or
operator
and
maintained
at
the
facility
to
support
the
determination
of
the
process
vent
stream
flow
rate.
This
documentation
must
include
identification
of
each
process
vent
exempted
under
this
paragraph
and
the
test
results
used
to
determine
the
process
vent
stream
flow
rate.
(4)
Remediation
material
management
units.
You
are
exempt
from
the
requirements
of
§§
63.7890
through
63.7932
for
units
where
any
of
the
criteria
listed
in
paragraphs
(c)(
4)(
i)
or
(ii)
of
this
section
are
met,
except
that
the
records
of
the
determination
of
these
criteria
must
be
maintained
as
required
in
§
63.7932(
a)(
4):
(i)
The
volatile
organic
HAP
(VOHAP)
concentration
of
the
remediation
material
managed
in
the
unit
is
less
than
500
ppmw.
You
must
follow
the
requirements
in
§
63.7912(
a)
to
demonstrate
that
the
VOHAP
concentration
of
the
remediation
material
is
less
than
500
ppmw.
Once
the
VOHAP
concentration
has
been
determined
to
be
less
than
500
ppmw,
all
management
units
downstream
from
the
point
of
determination
are
exempt
from
the
control
requirements
of
this
subpart
unless
a
remediation
process
is
used
that
concentrates
all,
or
part
of,
the
remediation
material
being
managed
in
the
unit
such
that
the
VOHAP
concentration
equals
or
exceeds
500
ppmw
(e.
g.,
free
product
separation).
(ii)
At
your
discretion,
one
or
a
combination
of
remediation
material
management
units
may
be
exempted
from
the
requirements
in
this
subpart
when
the
quantity
of
total
annual
HAP
in
Table
1
of
this
subpart
placed
in
the
units
exempted
under
this
paragraph
is
less
than
1
megagram
per
year.
For
the
units
to
be
exempted
from
the
requirements
of
this
subpart,
you
must
meet
the
requirements
in
§
63.683(
b)(
2)(
ii)(
A)
and
(B).
You
may
change
the
units
selected
to
be
exempted
under
this
paragraph
by
preparing
a
new
designation
for
the
exempt
units
as
required
by
§
63.683(
b)(
2)(
ii)(
A)
and
performing
a
new
determination
as
required
by
§
63.683(
b)(
2)(
ii)(
B).
(5)
Tanks
and
surface
impoundments.
You
are
exempt
from
the
requirements
of
§§
63.7890
(excluding
§
63.7890(
a))
through
63.7932
for
any
tank
or
surface
impoundment
used
for
biological
treatment
processes
where
the
requirements
of
§
63.683(
b)(
2)(
iii)(
A)
or
(B)
and
monitored
in
accordance
with
§
63.684(
e)(
4)
are
met,
except
that
the
records
of
the
determination
of
these
criteria
must
be
maintained
as
required
in
§
63.7932(
a)(
4).
(6)
Cleanup
of
any
contamination
where
removal
or
treatment
of
the
material
begins
within
seven
days
from
the
time
that
the
contamination
occurs.
The
cleanup
process
should
be
continuous
(i.
e.,
performed
every
workday)
and
typically
completed
in
30
days
or
less.
(7)
Radioactive
mixed
waste
managed
in
accordance
with
all
applicable
regulations
under
the
Atomic
Energy
Act
and
the
Nuclear
Waste
Policy
Act
authorities.
(d)
An
affected
source
is
a
new
affected
source
if
you
commenced
construction
of
the
affected
source
after
July
30,
2002
and
you
meet
the
applicability
criteria
in
§
63.7881
at
the
time
you
commenced
construction.
(e)
An
affected
source
is
reconstructed
if
you
meet
the
criteria
as
defined
in
§
63.2
of
subpart
A
of
this
part.
(f)
An
affected
source
is
existing
if
it
is
not
new
or
reconstructed.
§
63.7883
When
do
I
have
to
comply
with
this
subpart?
(a)
If
you
have
a
new
or
reconstructed
affected
source,
you
must
comply
with
this
subpart
according
to
the
guidance
in
paragraphs
(a)(
1)
and
(2)
of
this
section.
(1)
If
you
startup
your
affected
source
before
the
effective
date
of
the
subpart,
then
you
must
comply
with
the
emissions
limitations
and
work
practice
standards
in
this
subpart
no
later
than
the
effective
date
of
the
subpart.
If
you
startup
your
affected
source
before
the
effective
date
of
the
subpart,
but
the
affected
source
will
not
operate
on
or
after
the
effective
date
of
the
subpart,
then
that
affected
source
is
not
subject
to
any
of
the
requirements
contained
in
this
subpart.
(2)
If
you
startup
your
affected
source
after
the
effective
date
of
the
subpart,
then
you
must
comply
with
the
emissions
limitation
and
work
practice
standards
in
this
subpart
upon
startup
of
your
affected
source.
(b)
If
you
have
an
existing
affected
source,
you
must
comply
with
the
emissions
limitations
and
work
practice
standards
for
existing
sources
no
later
than
3
years
after
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register].
If
you
have
an
existing
affected
source
that
will
not
be
in
operation
on
or
after
3
years
after
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register],
then
the
affected
source
is
not
subject
to
any
of
the
requirements
contained
in
this
subpart.
(c)
If
you
have
an
area
source
that
increases
its
emissions
or
its
potential
to
emit
such
that
it
becomes
a
major
source
of
HAP,
paragraphs
(c)(
1)
and
(2)
of
this
section
apply:
(1)
Any
portion
of
the
existing
facility
that
is
a
new
affected
source
or
a
new
reconstructed
source
must
be
in
compliance
with
this
subpart
upon
startup.
(2)
All
other
parts
of
the
source
must
be
in
compliance
with
this
subpart
by
no
later
than
3
years
after
it
becomes
a
major
source.
(d)
You
must
meet
the
notification
requirements
in
§
63.7931(
a)
according
to
the
schedule
in
§
63.7931(
b)
and
in
subpart
A
of
this
part.
Some
of
the
notifications
must
be
submitted
before
you
are
required
to
comply
with
the
emissions
limitations
and
work
practice
standards
in
this
subpart.
Emissions
Limitations
and
Work
Practice
Standards
§
63.7890
What
emissions
limitations
and
work
practice
standards
must
I
meet?
(a)
You
must
meet
each
emissions
limitation
for
process
vent
affected
sources
in
Table
2
of
this
subpart
that
applies
to
you.
(b)
You
must
meet
each
emissions
limitation
for
remediation
material
management
unit
affected
sources
in
Table
3
of
this
subpart
that
applies
to
you.
(c)
You
must
meet
each
operating
limit
in
Table
4
of
this
subpart
that
applies
to
you.
In
lieu
of
the
operating
limits
in
Table
4
of
this
subpart,
you
may
choose
to
establish
an
operating
limit
based
on
total
organic
or
HAP
emissions
concentration
using
a
continuous
emissions
monitoring
system
(CEMS).
In
this
case,
the
average
outlet
total
organic
or
HAP
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
concentration
in
any
24
hour
period
must
not
exceed
the
average
concentration
established
during
the
performance
test
(see
§
63.7913(
f)).
(d)
You
must
meet
each
work
practice
standard
in
Table
5
of
this
subpart
that
applies
to
you.
(e)
As
provided
in
§
63.6(
g),
you
may
request
approval
from
the
EPA
to
use
an
alternative
to
the
work
practice
standards
in
this
section.
If
you
apply
for
permission
to
use
an
alternative
to
the
work
practice
standards
in
this
section,
you
must
submit
the
information
described
in
§
63.6(
g)(
2).
General
Compliance
Requirements
§
63.7900
What
are
my
general
requirements
for
complying
with
this
subpart?
(a)
You
must
be
in
compliance
with
the
emissions
limitations
(including
operating
limits)
and
the
work
practice
standards
in
this
subpart
at
all
times,
except
during
periods
of
startup,
shutdown,
and
malfunction.
(b)
You
must
always
operate
and
maintain
your
affected
source,
including
air
pollution
control
and
monitoring
equipment,
according
to
the
provisions
in
§
63.6(
e)(
1)(
i).
(c)
You
must
develop
and
implement
a
written
startup,
shutdown,
and
malfunction
plan
(SSMP)
according
to
the
provisions
in
§
63.6(
e)(
3).
(d)
For
each
monitoring
system
required
in
this
section,
you
must
develop
and
make
available
for
inspection
by
the
permitting
authority,
upon
request,
a
site
specific
monitoring
plan
that
addresses
the
following:
(1)
Installation
of
the
continuous
monitoring
system
(CMS)
sampling
probe
or
other
interface
at
a
measurement
location
relative
to
each
affected
process
unit
such
that
the
measurement
is
representative
of
control
of
the
exhaust
emissions
(e.
g.,
on
or
downstream
of
the
last
control
device);
(2)
Performance
and
equipment
specifications
for
the
sample
interface,
the
pollutant
concentration
or
parametric
signal
analyzer,
and
the
data
collection
and
reduction
system;
and
(3)
Performance
evaluation
procedures
and
acceptance
criteria
(e.
g.,
calibrations).
(e)
In
your
site
specific
monitoring
plan,
you
must
also
address
the
following:
(1)
Ongoing
operation
and
maintenance
procedures
in
accordance
with
the
general
requirements
of
§
63.8(
c)(
1),
(3),
(4)(
ii),
(7),
and
(8);
(2)
Ongoing
data
quality
assurance
procedures
in
accordance
with
the
general
requirements
of
§
63.8(
d);
and
(3)
Ongoing
recordkeeping
and
reporting
procedures
in
accordance
with
the
general
requirements
of
§
63.10(
c),
(e)(
1),
and
(e)(
2)(
i).
(f)
You
must
conduct
a
performance
evaluation
of
each
CMS
in
accordance
with
your
site
specific
monitoring
plan.
(g)
You
must
operate
and
maintain
the
CMS
in
continuous
operation
according
to
the
site
specific
monitoring
plan.
§
63.7901
What
requirements
must
I
meet
if
I
transfer
remediation
material
to
another
party,
another
facility
or
receive
remediation
material
from
another
facility?
(a)
You
may
elect
to
transfer
remediation
material
to
an
on
site
remediation
operation
not
owned
or
operated
by
the
owner
or
operator
of
the
remediation
material,
or
to
an
off
site
treatment
operation.
If
you
manage
remediation
material
meeting
the
criteria
in
§
63.7882
you
must
comply
with
the
requirements
in
paragraphs
(a)(
1)
through
(4)
of
this
section.
(1)
The
owner
or
operator
transferring
the
remediation
material
must:
(i)
Comply
with
the
provisions
specified
in
§§
63.7890
through
63.7933
of
this
subpart
for
each
affected
source
that
manages
remediation
material
prior
to
shipment
or
transport.
(ii)
Include
a
notice
with
the
shipment
or
transport
of
each
remediation
material
item.
The
notice
must
state
that
the
remediation
material
contains
organic
HAP
that
are
to
be
treated
in
accordance
with
the
provisions
of
this
subpart.
When
the
transport
is
continuous
or
ongoing
(for
example,
discharge
to
a
publicly
owned
treatment
works),
the
notice
must
be
submitted
to
the
treatment
operator
initially
and
whenever
there
is
a
change
in
the
required
treatment.
(2)
You
may
not
transfer
the
remediation
material
unless
the
transferee
has
submitted
to
the
EPA
a
written
certification
that
the
transferee
will
manage
and
treat
the
remediation
material
received
from
a
source
subject
to
the
requirements
of
this
subpart
in
accordance
with
the
requirements
of
§§
63.7890
through
63.7933.
The
certifying
entity
may
revoke
the
written
certification
by
sending
a
written
statement
to
the
EPA
and
the
owner
or
operator
providing
at
least
90
days
notice
that
the
certifying
entity
is
rescinding
acceptance
of
responsibility
for
compliance
with
the
regulatory
provisions
listed
in
this
paragraph.
Upon
expiration
of
the
notice
period,
you
may
not
transfer
the
remediation
material
to
the
treatment
operation.
(3)
By
providing
this
written
certification
to
the
EPA,
the
certifying
entity
accepts
responsibility
for
compliance
with
the
regulatory
provisions
listed
in
paragraph
(a)(
2)
of
this
section
with
respect
to
any
shipment
of
remediation
material
covered
by
the
written
certification.
Failure
to
abide
by
any
of
those
provisions
with
respect
to
such
shipments
may
result
in
enforcement
action
by
the
EPA
against
the
certifying
entity
in
accordance
with
the
enforcement
provisions
applicable
to
violations
of
these
provisions
by
owners
or
operators
of
sources.
(4)
Written
certifications
and
revocation
statements
to
the
EPA
from
the
transferees
of
remediation
material
must
be
signed
by
the
responsible
official
of
the
certifying
entity,
provide
the
name
and
address
of
the
certifying
entity,
and
be
sent
to
the
appropriate
EPA
Regional
Office
at
the
addresses
listed
in
40
CFR
63.13.
Such
written
certifications
are
not
transferable
by
the
treater.
Testing
and
Initial
Compliance
Requirements
§
63.7910
By
what
date
must
I
conduct
performance
tests
or
other
initial
compliance
demonstrations?
(a)
For
existing
sources,
you
must
conduct
performance
tests
within
180
calendar
days
after
the
compliance
date
that
is
specified
for
your
source
in
§
63.7883(
b).
(b)
For
new
sources,
you
must
conduct
initial
performance
tests
and
other
initial
compliance
demonstrations
according
to
the
provisions
in
§
63.7(
a)(
2)(
i)
and
(ii).
§
63.7911
When
must
I
conduct
subsequent
performance
tests?
For
non
flare
control
devices,
you
must
conduct
the
performance
testing
required
in
Table
6
of
this
subpart
at
any
time
the
EPA
requires
you
to
in
accordance
with
section
114
of
the
CAA.
§
63.7912
What
tests,
design
evaluations,
and
other
procedures
must
I
use?
(a)
Determination
of
average
VOHAP
concentration
of
material
prior
to,
or
at,
the
point
of
management
or
treatment.
This
section
specifies
the
testing
methods
and
procedures
required
for
determining
the
average
VOHAP
concentration
for
remediation
material.
(1)
These
methods
may
be
used
to
determine
the
average
VOHAP
concentration
of
any
material
listed
in
(a)(
1)(
i)
through
(iii)
of
this
section.
(i)
A
single
remediation
material
stream;
or
(ii)
Two
or
more
remediation
material
streams
that
are
combined
prior
to,
or
within,
a
management
or
treatment
unit
or
operation;
or
(iii)
Remediation
material
that
is
combined
with
one
or
more
nonVerDate
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
remediation
material
streams
prior
to,
or
within,
a
management
or
treatment
operation
or
unit.
(2)
The
average
VOHAP
concentration
of
a
material
must
be
determined
using
either
direct
measurement
as
specified
in
paragraph
(a)(
3)
of
this
section
or
by
knowledge
as
specified
in
paragraph
(a)(
4)
of
this
section.
(3)
Direct
measurement
to
determine
VOHAP
concentration.
(i)
Sampling.
Samples
of
each
material
stream
must
be
collected
from
the
container,
pipeline,
or
other
device
used
to
deliver
each
material
stream
prior
to
entering
the
treatment
or
management
unit
in
a
manner
such
that
volatilization
of
organics
contained
in
the
sample
is
minimized
and
an
adequately
representative
sample
is
collected
and
maintained
for
analysis
by
the
selected
method.
(A)
The
averaging
period
to
be
used
for
determining
the
average
VOHAP
concentration
for
the
material
stream
on
a
mass
weighted
average
basis
must
be
designated
and
recorded.
The
averaging
period
can
represent
any
time
interval
that
the
owner
or
operator
determines
is
appropriate
for
the
material
stream
but
must
not
exceed
1
year.
For
streams
that
are
combined,
an
averaging
period
representative
for
all
streams
must
be
selected.
(B)
No
less
than
four
samples
must
be
collected
to
represent
the
complete
range
of
HAP
compositions
and
HAP
quantities
that
occur
in
each
material
stream
during
the
entire
averaging
period
due
to
normal
variations
in
the
material
stream(
s).
Examples
of
such
normal
variations
are
variation
of
material
HAP
concentration
within
a
contamination
area
or
seasonal
variations
in
non
remediation
material
quantity.
(C)
All
samples
must
be
collected
and
handled
in
accordance
with
written
procedures
prepared
by
the
owner
or
operator
and
documented
in
a
site
sampling
plan.
This
plan
must
describe
the
procedure
by
which
representative
samples
of
the
material
stream(
s)
are
collected
such
that
a
minimum
loss
of
organics
occurs
throughout
the
sample
collection
and
handling
process
and
by
which
sample
integrity
is
maintained.
A
copy
of
the
written
sampling
plan
must
be
maintained
on
site
in
the
facility
operating
records.
An
example
of
an
acceptable
sampling
plan
includes
a
plan
incorporating
sample
collection
and
handling
procedures
in
accordance
with
the
requirements
specified
in
``
Test
Methods
for
Evaluating
Solid
Waste,
Physical/
Chemical
Methods,
''
EPA
Publication
No.
SW–
846
or
Method
25D
in
40
CFR
part
60,
appendix
A.
(ii)
Analysis.
Each
collected
sample
must
be
prepared
and
analyzed
in
accordance
with
either
one
of
the
methods
listed
in
§
63.694(
b)(
2)(
ii),
or
any
current
EPA
Contracts
Lab
Program
method
(or
future
revisions)
capable
of
identifying
all
the
HAP
in
Table
1
of
this
subpart.
(iii)
Calculations.
The
average
VOHAP
concentration
C
on
a
massweighted
basis
must
be
calculated
by
using
the
results
for
all
samples
analyzed
in
accordance
with
paragraph
(a)(
3)(
ii)
of
this
section
and
Equation
1
of
this
section
as
follows:
C
Q
Q
C
T
i
i
n
=
×
×
(
)
i=
1
1
(Eq.
1)
where:
C
=
Average
VOHAP
concentration
of
the
material
on
a
mass
weighted
basis,
ppmw.
i=
Individual
sample
``
i''
of
the
material.
n
=
Total
number
of
samples
of
the
material
collected
(at
least
4
per
stream)
for
the
averaging
period
(not
to
exceed
1
year).
Qi
=
Mass
quantity
of
material
stream
represented
by
Ci,
kilograms
per
hour
(kg/
hr).
QT
=
Total
mass
quantity
of
all
material
during
the
averaging
period,
kg/
hr.
Ci
=
Measured
VOHAP
concentration
of
sample
``
i''
as
determined
in
accordance
with
the
requirements
of
(a)(
3)(
ii)
of
this
section,
ppmw.
(4)
Knowledge
of
the
material
to
determine
VOHAP
concentration.
(i)
Documentation
must
be
prepared
that
presents
the
information
used
as
the
basis
for
the
owner's
or
operator's
knowledge
of
the
material
stream's
average
VOHAP
concentration.
Examples
of
information
that
may
be
used
as
the
basis
for
knowledge
include:
material
balances
for
the
source(
s)
generating
each
material
stream;
species
specific
chemical
test
data
for
the
material
stream
from
previous
testing
that
are
still
applicable
to
the
current
material
stream;
test
data
for
material
from
the
contamination
area(
s)
being
remediated;
or
other
knowledge
based
on
information
included
in
manifests,
shipping
papers,
or
waste
certification
notices.
(ii)
If
test
data
are
used
as
the
basis
for
knowledge,
then
the
owner
or
operator
must
document
the
test
method,
sampling
protocol,
and
the
means
by
which
sampling
variability
and
analytical
variability
are
accounted
for
in
the
determination
of
the
average
VOHAP
concentration.
For
example,
an
owner
or
operator
may
use
HAP
concentration
test
data
for
the
material
stream
that
are
validated
in
accordance
with
Method
301
in
40
CFR
part
63,
appendix
A
of
this
part
as
the
basis
for
knowledge
of
the
material.
This
information
must
be
provided
for
each
material
stream
where
streams
are
combined.
(iii)
An
owner
or
operator
using
species
specific
chemical
concentration
test
data
as
the
basis
for
knowledge
of
the
material
may
adjust
the
test
data
to
the
corresponding
average
VOHAP
concentration
value
which
would
be
obtained
had
the
material
samples
been
analyzed
using
Method
305.
To
adjust
these
data,
the
measured
concentration
for
each
individual
HAP
chemical
species
contained
in
the
material
is
multiplied
by
the
appropriate
species
specific
adjustment
factor
(fm305)
listed
in
Table
1
of
this
subpart.
(iv)
In
the
event
that
the
Administrator
and
the
owner
or
operator
disagree
on
a
determination
of
the
average
VOHAP
concentration
for
a
material
stream
using
knowledge,
then
the
results
from
a
determination
of
VOHAP
concentration
using
direct
measurement
as
specified
in
paragraph
(a)(
3)
of
this
section
must
be
used
to
establish
compliance
with
the
applicable
requirements
of
this
subpart.
The
Administrator
may
perform
or
request
that
the
owner
or
operator
perform
this
determination
using
direct
measurement.
(b)
You
must
conduct
either
each
performance
test
in
Table
6
of
this
subpart
that
applies
to
you
or
each
design
analysis
specified
in
§
63.693(
d)(
2)(
ii),
(e)(
2)(
ii),
(f)(
2)(
ii),
or
(g)(
2)(
i)(
B)
that
applies
to
you.
(c)
You
must
conduct
each
performance
test
according
to
the
requirements
in
§
63.7(
e)(
1)
and
under
the
specific
conditions
that
this
subpart
specifies
in
Table
6
of
this
subpart.
(d)
You
must
conduct
three
separate
test
runs
for
each
performance
test
required
in
this
section,
as
specified
in
§
63.7(
e)(
3).
Each
test
run
must
last
at
least
1
hour.
During
the
performance
test
conducted
according
to
this
section,
you
must
collect
the
appropriate
operating
parameter
monitoring
system
data
(see
Table
4
of
this
subpart),
average
the
operating
parameter
data
over
each
test
run,
and
set
operating
limits,
whether
a
minimum
or
maximum
value,
based
on
the
average
of
values
for
each
of
the
three
test
runs.
If
you
use
a
control
device
design
analysis
to
demonstrate
control
device
performance,
then
the
minimum
or
maximum
operating
parameter
value
must
be
established
based
on
the
control
device
design
analysis
and
supplemented,
as
necessary,
by
the
control
device
manufacturer
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49425
Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
recommendations
or
other
applicable
information.
(e)
Compliance
with
control
device
percent
reduction
requirement.
You
must
use
Equations
2,
3
and
4
of
this
section
to
determine
initial
and
ongoing
compliance
with
the
control
device
percent
reduction
limit
in
Table
2
of
this
subpart
for
the
combination
of
all
affected
process
vents
at
the
facility.
You
must
use
Equations
2,
3
and
5
of
this
section
to
determine
initial
and
ongoing
compliance
with
the
control
device
percent
reduction
limit
in
Table
3
of
this
subpart
for
remediation
material
management
units,
except
that
the
references
to
uncontrolled
vents
for
Equations
2
and
3
of
this
section
do
not
apply.
(1)
To
calculate
control
device
inlet
and
outlet
concentrations
use
Equations
2
and
3
as
follows:
E
K
CMQ
i
ijij
n
i
=
j=
2
1
(Eq.
2)
E
K
CMQ
o
ojoj
n
o
=
j=
2
1
(Eq.
3)
Where:
Cij,
Coj
=
Concentration
of
sample
component
j
of
the
gas
stream
at
the
inlet
and
outlet
of
the
control
device,
dry
basis,
parts
per
million
by
volume.
For
uncontrolled
vents,
Cij
=
Coj
and
equal
the
concentration
exiting
the
vent;
Ei,
Eo
=
Mass
rate
of
total
organic
compounds
(TOC)
(minus
methane
and
ethane)
or
total
HAP,
from
Table
1
of
this
subpart,
at
the
inlet
and
outlet
of
the
control
device,
respectively,
dry
basis,
kilogram
per
hour.
For
uncontrolled
vents,
Ei
=
Eo
and
equal
the
concentration
exiting
the
vent;
Mij,
Moj
=
Molecular
weight
of
sample
component
j
of
the
gas
stream
at
the
inlet
and
outlet
of
the
control
device,
respectively,
gram/
gram
mole.
For
uncontrolled
vents,
Mij
=
Moj
and
equal
the
gas
stream
molecular
weight
exiting
the
vent;
Qi,
Qo
=
Flowrate
of
gas
stream
at
the
inlet
and
outlet
of
the
control
device,
respectively,
dry
standard
cubic
meters
per
minute
(dscm/
min).
For
uncontrolled
vents,
Qi
=
Qo
and
equals
the
flowrate
exiting
the
vent;
K2
=
Constant,
2.494
×
10
¥
6
(parts
per
million)
¥
1
(gram
mole
per
standard
cubic
meter)(
kilogram/
gram)
(minute/
hour,
where
standard
temperature
(gram
mole
per
standard
cubic
meter)
is
20C;
n
=
the
number
of
components
in
the
sample.
(2)
To
calculate
control
device
emissions
reductions
for
process
vents
use
Equation
4
of
this
section
as
follows:
R
E
E
E
V
i
n
o
n
i
n
=
×
j=
j=
j=
1
1
1
100
(Eq.
4)
Where:
Rv
=
Overall
emissions
reduction
for
all
affected
process
vents,
percent
Ei
=
Mass
rate
of
TOC
(minus
methane
and
ethane)
or
total
HAP,
from
Table
1
of
this
subpart,
at
the
inlet
to
the
control
device,
or
exiting
the
vent
for
uncontrolled
vents,
as
calculated
in
this
section,
kilograms
TOC
per
hour
or
kilograms
HAP
per
hour;
Eo
=
Mass
rate
of
TOC
(minus
methane
and
ethane)
or
total
HAP,
from
Table
1
of
this
subpart,
at
the
outlet
to
the
control
device,
or
exiting
the
vent
for
uncontrolled
vents,
as
calculated
in
this
section,
kilograms
TOC
per
hour
or
kilograms
HAP
per
hour.
For
vents
without
a
control
device,
Eo
=
Ei;
n
=
number
of
affected
source
process
vents.
(3)
To
calculate
control
device
emissions
reductions
for
remediation
material
management
units
use
Equation
5
of
this
section
as
follows:
R
E
E
E
cd
i
o
i
=
×
100
(Eq.
5)
Where:
Rcd
=
Control
efficiency
of
control
device,
percent.
Ei
=
Mass
rate
of
TOC
(minus
methane
and
ethane)
or
total
HAP
at
the
inlet
to
the
control
device
as
calculated
under
paragraph
(e)(
1)
of
this
section,
kilograms
TOC
per
hour
or
kilograms
HAP
per
hour.
Eo
=
Mass
rate
of
TOC
(minus
methane
and
ethane)
or
total
HAP
at
the
outlet
of
the
control
device,
as
calculated
under
paragraph
(e)(
1)
of
this
section,
kilograms
TOC
per
hour
or
kilograms
HAP
per
hour.
(4)
If
the
vent
stream
entering
a
boiler
or
process
heater
is
introduced
with
the
combustion
air
or
as
a
secondary
fuel,
the
weight
percent
reduction
of
total
HAP
or
TOC
(minus
methane
and
ethane)
across
the
device
must
be
determined
by
comparing
the
TOC
(minus
methane
and
ethane)
or
total
HAP
in
all
combusted
vent
streams
and
primary
and
secondary
fuels
with
the
TOC
(minus
methane
and
ethane)
or
total
HAP
exiting
the
device,
respectively.
(f)
Compliance
with
the
total
organic
mass
emissions
rate.
(1)
The
requirements
of
paragraphs
(f)(
2)
through
(4)
of
this
section
must
be
used
to
determine
compliance
with
the
emissions
rate
limits
in
Table
2
of
this
subpart.
(2)
Initial
and
ongoing
compliance
with
the
total
organic
mass
flow
rates
specified
in
Table
2
of
this
subpart
must
be
determined
using
Equation
6
of
this
section
as
follows:
E
Q
CMW
h
sd
ii
n
=
[
]
[
]
i=
1
6
10
0.0416
(Eq.
6)
Where:
Eh
=
Total
organic
mass
flow
rate,
kg/
h;
Qsd
=
Volumetric
flow
rate
of
gases
entering
or
exiting
control
device
(or
exiting
the
process
vent
if
no
control
device
is
used),
as
determined
by
Method
2,
dscm/
h;
n=
Number
of
organic
compounds
in
the
vent
gas;
Ci
=
Organic
concentration
in
ppm,
dry
basis,
of
compound
i
in
the
vent
gas,
as
determined
by
Method
18;
MWi
=
Molecular
weight
of
organic
compound
i
in
the
vent
gas,
kg/
kg
mol;
0.0416
=
Conversion
from
molar
volume,
kg
mol/
m
3
(@
293
K
and
760
mm
Hg);
10
¥
6
=
Conversion
from
ppm,
ppm
¥
1
.
(3)
Ongoing
compliance
with
the
annual
total
organic
emissions
rate
specified
in
Table
2
of
this
subpart
must
be
determined
using
Equation
7
of
this
section
as
follows:
E
EH
A
h
=
(
)
(
)
(Eq.
7)
Where:
EA
=
Total
organic
mass
emissions
rate,
kilograms
per
year;
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49426
Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
Eh
=
Total
organic
mass
flow
rate
for
the
process
vent,
kg/
h;
H
=
Total
annual
hours
of
operation
for
the
affected
unit,
h.
(4)
Ongoing
compliance
with
the
total
organic
emissions
limit
from
all
affected
process
vents
at
the
facility
in
Table
2
of
this
subpart
must
be
determined
by:
(1)
summing
the
total
hourly
organic
mass
emissions
rates
(Eh
as
determined
in
Equation
6
of
this
section);
and
(ii)
summing
the
total
annual
organic
mass
emissions
rates
(EA,
as
determined
in
Equation
7
of
this
section)
for
all
affected
process
vents
at
the
facility.
(g)
Compliance
with
HAP
concentration
limit.
(1)
To
determine
compliance
with
the
enclosed
combustion
device
total
HAP
concentration
limits
specified
in
Table
2
of
this
subpart,
you
must
use
either
Method
18,
40
CFR
part
60,
appendix
A,
or
Method
25A,
40
CFR
part
60,
appendix
A,
to
measure
either
TOC
(minus
methane
and
ethane)
or
total
HAP.
Alternatively,
any
other
method
or
data
that
have
been
validated
according
to
Method
301
of
appendix
A
of
this
part,
may
be
used.
The
following
procedures
must
be
used
to
calculate
ppmv
concentration,
corrected
to
3
percent
oxygen:
(2)
The
minimum
sampling
time
for
each
run
must
be
1
hour,
in
which
either
an
integrated
sample
or
a
minimum
of
four
grab
samples
must
be
taken.
If
grab
sampling
is
used,
then
the
samples
must
be
taken
at
approximately
equal
intervals
in
time,
such
as
15
minute
intervals
during
the
run.
(3)
The
TOC
concentration
or
total
HAP
concentration
must
be
calculated
according
to
paragraph
(g)(
3)(
i)
or
(ii)
of
this
section.
(i)
The
TOC
concentration
is
the
sum
of
the
concentrations
of
the
individual
components
and
must
be
computed
for
each
run
using
Equation
8
of
this
section
as
follows:
C
C
X
TOC
ji
n
x
=
i=
i=
1
1
(Eq.
8)
Where:
CTOC
=
Concentration
of
total
organic
compounds
minus
methane
and
ethane,
dry
basis,
parts
per
million
by
volume.
Cji
=
Concentration
of
sample
component
j
of
sample
i,
dry
basis,
parts
per
million
by
volume.
n
=
Number
of
components
in
the
sample.
X
=
Number
of
samples
in
the
sample
run.
(ii)
The
total
HAP
concentration
must
be
computed
according
to
Equation
8
in
paragraph
(g)(
3)(
i)
of
this
section,
except
that
only
HAP
listed
in
Table
1
of
this
subpart
must
be
summed.
(4)
The
TOC
concentration
or
total
HAP
concentration
must
be
corrected
to
3
percent
oxygen
according
to
paragraphs
(g)(
4)(
i)
and
(ii)
of
this
section.
(i)
The
emissions
rate
correction
factor
or
excess
air,
integrated
sampling
and
analysis
procedures
of
Method
3B,
40
CFR
part
60,
appendix
A,
must
be
used
to
determine
the
oxygen
concentration.
The
samples
must
be
taken
during
the
same
time
that
the
samples
are
taken
for
determining
TOC
concentration
or
total
HAP
concentration.
(ii)
The
TOC
and
HAP
concentration
must
be
corrected
for
percent
oxygen
by
using
Equation
9
of
this
section
as
follows:
C
C
O
c
m
=
9
2d
17.9
20.%
(Eq.
9)
Where:
Cc
=
TOC
concentration
or
total
HAP
concentration
corrected
to
3
percent
oxygen,
dry
basis,
parts
per
million
by
volume.
Cm
=
TOC
concentration
or
total
HAP
concentration,
dry
basis,
parts
per
million
by
volume.
%O2d
=
Concentration
of
oxygen,
dry
basis,
percent
by
volume.
(h)
You
must
conduct
each
design
evaluation
of
a
control
device
according
to
the
specific
requirements
for
the
control
device
in
§
63.693(
c)
through
(h).
For
the
purposes
of
this
subpart,
when
you
read
the
term
``
HAP
listed
in
Table
1
of
this
subpart''
in
40
CFR
Subpart
DD,
you
should
refer
to
Table
1
of
this
subpart.
(i)
You
may
not
conduct
performance
tests
during
periods
of
startup,
shutdown,
or
malfunction,
as
specified
in
§
63.7(
e)(
1).
(j)
When
conducting
testing
to
comply
with
a
HAP
or
TOC
reduction
efficiency
limit,
you
must
conduct
simultaneous
sampling
at
the
inlet
and
outlet
of
the
control
device.
You
must
conduct
inlet
sampling
after
the
final
product
recovery
device.
If
a
vent
stream
is
introduced
with
the
combustion
air
or
as
an
auxiliary
fuel
into
a
boiler
or
process
heater,
the
location
of
the
inlet
sampling
sites
must
be
selected
to
ensure
that
the
measurement
of
total
HAP
concentration
or
TOC
concentration
includes
all
vent
streams
and
primary
and
secondary
fuels
introduced
into
the
boiler
or
process
heater.
(k)
When
complying
with
the
emissions
rate
limit
in
row
(1)(
b)
of
Table
2
of
this
subpart
or
a
HAP
or
TOC
emissions
concentration
limit
in
Table
3
of
this
subpart,
you
must
conduct
sampling
at
the
outlet
of
the
control
device.
(l)
If
you
use
Method
18,
40
CFR
part
60,
appendix
A,
either
an
integrated
sample
or
a
minimum
of
four
grab
samples
must
be
taken.
If
you
use
grab
sampling,
then
you
must
take
the
grab
samples
at
approximately
equal
intervals
in
time
(such
as
15
minutes)
during
the
run.
Also,
you
must
first
determine
which
HAP
are
present
in
the
inlet
gas
stream
using
knowledge
of
the
remediation
material
or
the
screening
procedure
described
in
Method
18,
40
CFR
part
60,
appendix
A,
quantify
the
emissions
for
all
HAP
identified
as
present
in
the
inlet
gas
stream
for
both
the
inlet
and
outlet
gas
streams
of
the
control
device.
(m)
If
you
use
Method
25A,
40
CFR
part
60,
appendix
A,
you
must
calibrate
the
instrument
in
accordance
with
the
monitoring
plan
of
§
63.7900
using
the
single
organic
HAP
representing
the
largest
percent
by
volume
of
the
emissions.
The
Method
25A,
40
CFR
part
60,
appendix
A,
results
are
acceptable
if:
(1)
the
response
from
the
high
level
calibration
gas
is
at
least
20
times
the
standard
deviation
of
the
response
from
the
zero
calibration
gas
when
the
instrument
is
zeroed
on
its
most
sensitive
scale,
and
(2)
the
span
value
of
the
analyzer
must
be
less
than
100
ppmv.
(n)
You
must
conduct
each
CMS
performance
evaluation
according
to
the
requirements
in
§
63.8(
e).
§
63.7913
What
are
my
monitoring
installation,
operation,
and
maintenance
requirements?
(a)
You
must
install,
operate,
and
maintain
each
CMS
according
to
the
requirements
in
§
63.695(
a)
through
(d),
(e)(
1)
and
(e)(
2).
In
addition,
you
must
collect
and
analyze
temperature,
flow,
pressure,
or
pH
data
according
to
the
requirements
in
paragraphs
(a)(
1)
through
(4)
of
this
section:
(1)
To
calculate
a
valid
hourly
value,
you
must
have
at
least
three
of
four
equally
spaced
data
values
(or
at
least
two,
if
that
condition
is
included
to
allow
for
periodic
calibration
checks)
for
that
hour
from
a
CMS
that
is
not
out
of
control
according
to
the
monitoring
plan
referenced
in
§
63.7900.
(2)
To
calculate
the
average
emissions
for
each
averaging
period,
you
must
have
at
least
75
percent
of
the
hourly
averages
for
that
period
using
only
block
hourly
average
values
that
are
based
on
valid
data
(i.
e.,
not
from
out
of
control
periods).
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49427
Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
(3)
Determine
the
hourly
average
of
all
recorded
readings.
(4)
Record
the
results
of
each
inspection,
calibration,
and
validation
check.
(b)
For
each
temperature
monitoring
device,
you
must
meet
the
requirements
in
paragraph
(a)
of
this
section
and
also
meet
the
requirements
in
paragraphs
(b)(
1)
through
(8)
of
this
section:
(1)
Locate
the
temperature
sensor
in
a
position
that
provides
a
representative
temperature.
(2)
For
a
noncryogenic
temperature
range,
use
a
temperature
sensor
with
a
minimum
measurement
sensitivity
of
2.2
C
or
0.75
percent
of
the
temperature
value,
whichever
is
larger.
(3)
For
a
cryogenic
temperature
range,
use
a
temperature
sensor
with
a
minimum
measurement
sensitivity
of
2.2
C
or
2
percent
of
the
temperature
value,
whichever
is
larger.
(4)
Shield
the
temperature
sensor
system
from
electromagnetic
interference
and
chemical
contaminants.
(5)
If
a
chart
recorder
is
used,
it
must
have
a
sensitivity
in
the
minor
division
of
at
least
20
F.
(6)
Perform
an
electronic
calibration
at
least
semiannually
according
to
the
procedures
in
the
manufacturer's
owners
manual.
Following
the
electronic
calibration,
you
must
conduct
a
temperature
sensor
validation
check
in
which
a
second
or
redundant
temperature
sensor
placed
nearby
the
process
temperature
sensor
must
yield
a
reading
within
16.7
C
of
the
process
temperature
sensor's
reading.
(7)
Conduct
calibration
and
validation
checks
any
time
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
temperature
range
or
install
a
new
temperature
sensor.
(8)
At
least
monthly,
inspect
all
components
for
integrity
and
all
electrical
connections
for
continuity,
oxidation,
and
galvanic
corrosion.
(c)
For
each
flow
measurement
device,
you
must
meet
the
requirements
in
paragraphs
(a)(
1)
through
(4)
and
paragraphs
(c)(
1)
through
(5)
of
this
section:
(1)
Locate
the
flow
sensor
and
other
necessary
equipment
such
as
straightening
vanes
in
a
position
that
provides
a
representative
flow.
(2)
Use
a
flow
sensor
with
a
minimum
measurement
sensitivity
of
2
percent
of
the
flow
rate.
(3)
Reduce
swirling
flow
or
abnormal
velocity
distributions
due
to
upstream
and
downstream
disturbances.
(4)
Conduct
a
flow
sensor
calibration
check
at
least
semi
annually.
(5)
At
least
monthly,
inspect
all
components
for
integrity,
all
electrical
connections
for
continuity,
and
all
mechanical
connections
for
leakage.
(d)
For
each
pressure
measurement
device,
you
must
meet
the
requirements
in
paragraph
(a)(
1)
through
(4)
and
paragraphs
(d)(
1)
through
(7)
of
this
section.
(1)
Locate
the
pressure
sensor(
s)
in
or
as
close
to
a
position
that
provides
a
representative
measurement
of
the
pressure.
(2)
Minimize
or
eliminate
pulsating
pressure,
vibration,
and
internal
and
external
corrosion.
(3)
Use
a
gauge
with
a
minimum
measurement
sensitivity
of
0.5
inch
of
water
or
a
transducer
with
a
minimum
measurement
sensitivity
of
1
percent
of
the
pressure
range.
(4)
Check
pressure
tap
pluggage
daily.
(5)
Using
a
manometer,
check
gauge
calibration
quarterly
and
transducer
calibration
monthly.
(6)
Conduct
calibration
checks
any
time
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
pressure
range
or
install
a
new
pressure
sensor.
(7)
At
least
monthly,
inspect
all
components
for
integrity,
all
electrical
connections
for
continuity,
and
all
mechanical
connections
for
leakage.
(e)
For
each
pH
measurement
device,
you
must
meet
the
requirements
in
paragraph
(a)(
1)
through
(4)
and
paragraphs
(e)(
1)
through
(4)
of
this
section:
(1)
Locate
the
pH
sensor
in
a
position
that
provides
a
representative
measurement
of
pH.
(2)
Ensure
the
sample
is
properly
mixed
and
representative
of
the
fluid
to
be
measured.
(3)
Check
the
pH
meter's
calibration
on
at
least
two
points
every
8
hours
of
process
operation.
(4)
At
least
monthly,
inspect
all
components
for
integrity
and
all
electrical
connections
for
continuity.
(f)
Alternative
to
parametric
monitoring
for
any
control
device.
As
an
alternative
to
the
parametric
monitoring
required
in
paragraphs
(a)
through
(e)
of
this
section,
you
may
install,
calibrate,
and
operate
a
CEMS
to
measure
the
control
device
outlet
total
organic
emissions
or
organic
HAP
emissions
concentration.
The
CEMS
used
on
combustion
control
devices
must
include
a
diluent
gas
monitoring
system
(for
O2
or
CO2)
with
the
pollutant
monitoring
system
in
order
to
correct
for
dilution
(e.
g.,
to
0
percent
excess
air).
You
must
verify
the
performance
of
the
CEMS
initially
according
to
the
procedures
in
Performance
Specification
8
(for
a
total
organic
emissions
CEMS)
or
Performance
Specification
9
(for
a
HAP
emissions
CEMS)
and
Performance
Specification
3
(for
an
O2
or
CO2
CEMS)
of
appendix
B
of
40
CFR
part
60.
The
relative
accuracy
provision
of
Performance
specification
8,
sections
2.4
and
3
need
not
be
conducted.
You
must
prepare
a
sitespecific
monitoring
plan
for
operating,
calibrating,
and
verifying
the
operation
of
your
CEMS
in
accordance
with
the
requirements
in
§§
63.8(
c),
(d),
and
(e).
You
must
establish
the
emissions
concentration
operating
limit
according
to
paragraphs
(f)(
1),(
2),
and
(3)
of
this
section.
(1)
During
the
performance
test
required
by
§
63.7912,
you
must
monitor
and
record
the
total
organic
or
HAP
emissions
concentration
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
(2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
total
organic
or
HAP
emissions
concentration
maintained
during
the
performance
test.
The
average
total
organic
or
HAP
emissions
concentration,
corrected
for
dilution
as
appropriate,
is
the
maximum
operating
limit
for
your
control
device.
(3)
Use
the
CEMS
data
to
verify
that
the
daily
(24
hour)
average
total
organic
or
HAP
emissions
concentration
remain
below
the
established
operating
limit.
§
63.7914
How
do
I
demonstrate
initial
compliance
with
the
emissions
limitations
and
work
practice
standards?
(a)
You
must
demonstrate
initial
compliance
with
each
emissions
limitation
and
work
practice
standard
that
applies
to
you
according
to
Tables
7
and
8
of
this
subpart.
(b)
You
must
establish
each
sitespecific
operating
limit
in
Table
4
of
this
subpart
that
applies
to
you
according
to
the
requirements
in
§
63.7912
and
Table
6
of
this
subpart.
(c)
You
must
submit
the
Notification
of
Compliance
Status
containing
the
results
of
the
initial
compliance
demonstration
according
to
the
requirements
in
§
63.7931(
e).
Continuous
Compliance
Requirements
§
63.7920
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
(a)
You
must
monitor
and
collect
data
according
to
this
section
and
the
monitoring
plan
of
§
63.7900.
(b)
Except
for
monitor
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
(including,
as
applicable,
calibration
checks
and
required
zero
and
span
adjustments),
you
must
monitor
continuously
(or
collect
data
at
all
required
intervals)
at
all
times
that
the
affected
source
is
operating.
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(c)
You
may
not
use
data
recorded
during
monitoring
malfunctions,
associated
repairs,
out
of
control
periods
and
required
quality
assurance
or
control
activities
in
data
averages
and
calculations
used
to
report
emissions
or
operating
levels,
nor
may
such
data
be
used
in
fulfilling
a
minimum
data
availability
requirement,
if
applicable.
You
must
use
all
the
data
collected
during
all
other
periods
in
assessing
the
operation
of
the
control
device
and
associated
control
system.
§
63.7921
How
do
I
demonstrate
continuous
compliance
with
the
emissions
limitations,
operating
limits
and
work
practice
standards?
(a)
You
must
demonstrate
continuous
compliance
with
each
emissions
limitation,
operating
limit
and
work
practice
standard
in
Tables
2
through
5
of
this
subpart
that
applies
to
you
according
to
methods
specified
in
Tables
9,
10,
and
11
of
this
subpart.
(b)
You
must
report
each
instance
in
which
you
did
not
meet
each
emissions
limitation
and
each
operating
limit
in
Tables
9
and
10
of
this
Subpart
that
apply
to
you.
This
includes
periods
of
startup,
shutdown,
and
malfunction.
You
must
also
report
each
instance
in
which
you
did
not
meet
the
requirements
in
Table
11
of
this
subpart
that
apply
to
you.
These
instances
are
deviations
from
the
emissions
limitations
and
work
practice
standards
in
this
subpart.
These
deviations
must
be
reported
according
to
the
requirements
in
§
63.7931.
(c)
During
periods
of
startup,
shutdown,
and
malfunction,
you
must
operate
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan.
(d)
Consistent
with
§§
63.6(
e)
and
63.7(
e)(
1),
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
not
violations
if
you
demonstrate
to
the
Administrator's
satisfaction
that
you
were
operating
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan.
We
will
determine
whether
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
violations,
according
to
the
provisions
in
§
63.6(
e).
Notification,
Reports,
and
Records
§
63.7930
What
notifications
must
I
submit
and
when?
(a)
You
must
submit
all
of
the
notifications
in
§§
63.7(
b)
and
(c),
63.8(
e),
63.8(
f)(
4)
and
(6),
and
63.9(
b)
through
(h)
that
apply
to
you.
(b)
As
specified
in
§
63.9(
b)(
2),
if
you
start
up
your
affected
source
before
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register],
you
must
submit
an
Initial
Notification
not
later
than
120
calendar
days
after
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register].
(c)
As
specified
in
§
63.9(
b)(
3),
if
you
start
up
your
new
or
reconstructed
affected
source
on
or
after
the
effective
date,
you
must
submit
an
Initial
Notification
no
later
than
120
calendar
days
after
initial
startup.
(d)
If
you
are
required
to
conduct
a
performance
test,
you
must
submit
a
notification
of
intent
to
conduct
a
performance
test
at
least
60
calendar
days
before
the
performance
test
is
scheduled
to
begin
as
required
in
§
63.7(
b)(
1).
(e)
If
you
are
required
to
conduct
a
performance
test,
design
evaluation,
or
other
initial
compliance
demonstration
as
specified
in
Tables
6,
7,
or
8
of
this
subpart,
you
must
submit
a
Notification
of
Compliance
Status
according
to
§
63.9(
h)(
2)(
ii).
(1)
For
each
initial
compliance
demonstration
required
in
Tables
7
or
8
of
this
subpart
that
does
not
include
a
performance
test,
you
must
submit
the
Notification
of
Compliance
Status
before
the
close
of
business
on
the
30th
calendar
day
following
the
completion
of
the
initial
compliance
demonstration.
(2)
For
each
initial
compliance
demonstration
required
in
Tables
6,
7
or
8
of
this
subpart
that
includes
a
performance
test
conducted
according
to
the
requirements
in
Table
6
of
this
subpart,
you
must
submit
the
Notification
of
Compliance
Status,
including
the
performance
test
results,
before
the
close
of
business
on
the
60th
calendar
day
following
the
completion
of
the
performance
test
according
to
§
63.10(
d)(
2).
§
63.7931
What
reports
must
I
submit
and
when?
(a)
You
must
submit
each
report
in
Table
12
of
this
subpart
that
applies
to
you.
(b)
Unless
the
Administrator
has
approved
a
different
schedule
for
submission
of
reports
under
§
63.10(
a),
you
must
submit
each
report
by
the
date
in
Table
12
of
this
subpart
and
according
to
the
requirements
in
paragraphs
(b)(
1)
through
(5)
of
this
section:
(1)
The
first
compliance
report
must
cover
the
period
beginning
on
the
compliance
date
that
is
specified
for
your
affected
source
in
§
63.7883
and
ending
on
June
30
or
December
31,
whichever
date
is
the
first
date
following
the
end
of
the
first
calendar
half
after
the
compliance
date
that
is
specified
for
your
source
in
§
63.7883.
(2)
The
first
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
follows
the
end
of
the
first
calendar
half
after
the
compliance
date
that
is
specified
for
your
affected
source
in
§
63.7883.
(3)
Each
subsequent
compliance
report
must
cover
the
semiannual
reporting
period
from
January
1
through
June
30
or
the
semiannual
reporting
period
from
July
1
through
December
31.
(4)
Each
subsequent
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
is
the
first
date
following
the
end
of
the
semiannual
reporting
period.
(5)
For
each
affected
source
that
is
subject
to
permitting
regulations
pursuant
to
40
CFR
part
70
or
40
CFR
part
71,
and
if
the
permitting
authority
has
established
dates
for
submitting
semiannual
reports
pursuant
to
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
you
may
submit
the
first
and
subsequent
compliance
reports
according
to
the
dates
the
permitting
authority
has
established
instead
of
according
to
the
dates
in
paragraphs
(b)(
1)
through
(4)
of
this
section.
(c)
The
compliance
report
must
contain
the
information
in
paragraphs
(c)(
1)
through
(7)
of
this
section:
(1)
Company
name
and
address.
(2)
Statement
by
a
responsible
official,
including
that
official's
name,
title,
and
signature,
certifying
the
truth,
accuracy
and
completeness
of
the
content
of
the
report.
(3)
Date
of
report
and
beginning
and
ending
dates
of
the
reporting
period.
(4)
Any
changes
to
the
information
listed
in
paragraph
(d)
of
this
section
that
have
occurred
since
the
last
report.
(5)
If
you
had
a
startup,
shutdown
or
malfunction
during
the
reporting
period
and
you
took
actions
consistent
with
your
startup,
shutdown,
and
malfunction
plan,
the
compliance
report
must
include
the
information
in
§
63.10(
d)(
5)(
i).
(6)
If
there
are
no
deviations
from
any
emissions
limitations
(emissions
limit
or
operating
limit)
that
applies
to
you
and
there
are
no
deviations
from
the
requirements
for
work
practice
standards
in
Table
11
of
this
subpart,
a
statement
that
there
were
no
deviations
from
the
emissions
limitations
or
work
practice
standards
during
the
reporting
period.
(7)
If
there
were
no
periods
during
which
the
CMS
and
operating
parameter
monitoring
systems
were
out
of
control
as
specified
in
§
63.8(
c)(
7),
a
statement
that
there
were
no
periods
during
the
which
the
CMS
was
out
of
control
during
the
reporting
period.
(d)
For
each
deviation
from
an
emissions
limitation
(emissions
limit,
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Proposed
Rules
operating
limit)
and
for
each
deviation
from
the
requirements
for
work
practice
standards
in
Table
11
of
this
subpart
that
occurs
at
an
affected
source
where
you
are
not
using
a
CMS
to
comply
with
the
emissions
limitations
or
work
practice
standards
in
this
subpart,
the
compliance
report
must
contain
the
information
in
(c)(
1)
through
(4)
of
this
section,
and
paragraphs
(d)(
1)
and
(2)
of
this
section.
This
includes
periods
of
startup,
shutdown,
and
malfunction.
(1)
The
total
operating
time
of
each
affected
source
during
the
reporting
period.
(2)
Information
on
the
number,
duration,
and
cause
of
deviations
(including
unknown
cause,
if
applicable),
as
applicable,
and
the
action
taken
to
correct
the
cause
of
the
deviation.
(e)
For
each
deviation
from
an
emissions
limitation
(emissions
limit,
operating
limit)
occurring
at
an
affected
source
where
you
are
using
a
CMS
in
accordance
with
the
monitoring
plan
of
§
63.7900
to
comply
with
the
emissions
limitation
in
this
subpart,
you
must
include
the
information
in
paragraphs
(c)(
1)
through
(4),
and
paragraphs
(e)(
1)
through
(12)
of
this
section.
This
includes
periods
of
startup,
shutdown,
and
malfunction.
(1)
The
date
and
time
that
each
malfunction
started
and
stopped.
(2)
The
date
and
time
that
each
CMS
was
inoperative,
except
for
zero
lowlevel
and
high
level
checks.
(3)
The
date,
time
and
duration
that
each
CMS
was
out
of
control,
including
the
information
in
§
63.8(
c)(
8).
(4)
The
date
and
time
that
each
deviation
started
and
stopped,
and
whether
each
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction
or
during
another
period.
(5)
A
summary
of
the
total
duration
of
the
deviation
during
the
reporting
period
and
the
total
duration
as
a
percent
of
the
total
source
operating
time
during
that
reporting
period.
(6)
A
breakdown
of
the
total
duration
of
the
deviations
during
the
reporting
period
into
those
that
are
due
to
startup,
shutdown,
control
equipment
problems,
process
problems,
other
known
causes,
and
other
unknown
causes.
(7)
A
summary
of
the
total
duration
of
CMS
downtime
during
the
reporting
period
and
the
total
duration
of
CMS
downtime
as
a
percent
of
the
total
source
operating
time
during
that
reporting
period.
(8)
An
identification
of
each
hazardous
air
pollutant
that
was
monitored
at
the
affected
source.
(9)
A
brief
description
of
the
process
units.
(10)
A
brief
description
of
the
CMS.
(11)
The
date
of
the
latest
CMS
certification
or
audit.
(12)
A
description
of
any
changes
in
CMS,
processes,
or
controls
since
the
last
reporting
period.
(f)
Each
affected
source
that
has
obtained
a
title
V
operating
permit
pursuant
to
40
CFR
part
70
or
40
CFR
part
71
must
report
all
deviations
as
defined
in
this
subpart
in
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A).
If
an
affected
source
submits
a
compliance
report
pursuant
to
Table
12
of
this
subpart
along
with,
or
as
part
of,
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
and
the
compliance
report
includes
all
required
information
concerning
deviations
from
any
emissions
limitation(
including
any
operating
limit),
or
work
practice
requirement
in
this
subpart,
submission
of
the
compliance
report
must
be
deemed
to
satisfy
any
obligation
to
report
the
same
deviations
in
the
semiannual
monitoring
report.
However,
submission
of
a
compliance
report
must
not
otherwise
affect
any
obligation
the
affected
source
may
have
to
report
deviations
from
permit
requirements
to
the
permit
authority.
§
63.7932
What
records
must
I
keep?
(a)
You
must
keep
records
as
described
in
paragraphs
(a)(
1)
through
(4)
of
this
section:
(1)
A
copy
of
each
notification
and
report
that
you
submitted
to
comply
with
this
subpart,
including
all
documentation
supporting
any
Initial
Notification
or
Notification
of
Compliance
Status
that
you
submitted,
according
to
the
requirements
in
§
63.10(
b)(
1)
and
(b)(
2)(
xiv).
(2)
The
records
in
§
63.6(
e)(
3)(
iii)
through
(v)
related
to
startups,
shutdowns,
and
malfunctions.
(3)
Results
of
performance
tests.
(4)
The
records
of
initial
and
ongoing
determinations
for
affected
sources
that
are
exempt
from
control
requirements
under
this
subpart.
(b)
For
each
CMS,
you
must
keep
the
records
as
described
in
paragraphs
(b)(
1)
and
(2)
of
this
section:
(1)
Records
described
in
§
63.10(
b)(
2)(
vi)
through
(xi)
that
apply
to
your
CMS.
(2)
Performance
evaluation
plans,
including
previous
(i.
e.,
superseded)
versions
of
the
plan
as
required
in
§
63.8(
d)(
3).
(c)
You
must
keep
the
records
required
in
Tables
9,
10,
and
11
of
this
subpart
to
show
continuous
compliance
with
each
emissions
limitation
and
work
practice
standard
that
applies
to
you.
§
63.7933
In
what
form
and
how
long
must
I
keep
my
records?
(a)
Your
records
must
be
in
a
form
suitable
and
readily
available
for
expeditious
review,
according
to
§
63.10(
b)(
1).
(b)
As
specified
in
§
63.10(
b)(
1),
you
must
keep
your
files
of
all
information
(including
all
reports
and
notifications)
for
5
years
following
the
date
of
each
occurrence,
measurement,
maintenance,
action
taken
to
correct
the
cause
of
a
deviation,
report,
or
record.
(c)
You
must
keep
each
record
on
site
for
at
least
2
years
after
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record,
according
to
§
63.10(
b)(
1).
You
can
keep
the
records
offsite
for
the
remaining
3
years.
(d)
If,
after
the
remediation
activity
is
completed,
there
is
no
other
remediation
activity
at
the
facility,
and
you
are
no
longer
the
owner
of
the
facility,
you
may
keep
all
records
for
the
completed
remediation
activity
at
an
offsite
location
provided
you
notify
the
Administrator
in
writing
of
the
name,
address
and
contact
person
for
the
offsite
location.
Other
Requirements
and
Information
§
63.7940
What
parts
of
the
General
Provisions
apply
to
me?
Table
13
of
this
subpart
shows
which
parts
of
the
General
Provisions
in
§
63.1–§
63.15
apply
to
you.
§
63.7941
Who
implements
and
enforces
this
subpart?
(a)
This
subpart
can
be
implemented
and
enforced
by
us,
the
EPA,
or
a
delegated
authority
such
as
your
State,
local,
or
tribal
agency.
If
the
EPA
Administrator
has
delegated
authority
to
your
State,
local,
or
tribal
agency,
then
that
agency,
in
addition
to
the
EPA,
has
the
authority
to
implement
and
enforce
this
subpart.
You
should
contact
your
EPA
Regional
Office
(see
list
in
§
63.13)
to
find
out
if
this
subpart
is
delegated
to
your
State,
local,
or
tribal
agency.
(b)
In
delegating
implementation
and
enforcement
authority
of
this
Subpart
to
a
State,
local,
or
tribal
agency
under
section
40
CFR
part
63,
Subpart
E,
the
authorities
contained
in
paragraph
(c)
of
this
section
are
retained
by
the
Administrator
of
EPA
and
are
not
transferred
to
the
State,
local,
or
tribal
agency.
(c)
The
authorities
that
cannot
be
delegated
to
State,
local,
or
tribal
agencies
are
as
follows.
(1)
Approval
of
alternatives
to
the
non
opacity
emissions
limitations
and
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
work
practice
standards
in
§
63.7890(
a)
through
(d)
under
§
63.6(
g).
(2)
Approval
of
major
changes
to
test
methods
under
§
63.7(
e)(
2)(
ii)
and
(f)
and
as
defined
in
§
63.90.
(3)
Approval
of
major
changes
to
monitoring
under
§
63.8(
f)
and
as
defined
in
§
63.90.
(4)
Approval
of
major
changes
to
recordkeeping
and
reporting
under
§
63.10(
f)
and
as
defined
in
§
63.90.
§
63.7942
What
definitions
apply
to
this
subpart?
Terms
used
in
this
subpart
are
defined
in
the
CAA,
in
40
CFR
63.2,
the
General
Provisions
of
this
part,
and
in
this
section.
If
the
same
term
is
defined
in
another
subpart
and
in
this
section,
it
will
have
the
meaning
given
in
this
section
for
purposes
of
this
subpart.
Air
stripping
means
a
desorption
operation
employed
to
transfer
one
or
more
volatile
components
from
a
liquid
mixture
into
a
gas
(air)
either
with
or
without
the
application
of
heat
to
the
liquid.
Packed
towers,
spray
towers
and
bubble
cap,
sieve,
or
valve
type
plate
towers
are
among
the
process
configuration
used
for
contacting
the
air
and
a
liquid.
Boiler
means
an
enclosed
combustion
device
that
extracts
useful
energy
in
the
form
of
steam
and
is
not
an
incinerator
or
a
process
heater.
Closed
vent
system
means
a
system
that
is
not
open
to
the
atmosphere
and
is
composed
of
hard
piping,
ductwork,
connections,
and,
if
necessary,
fans,
blowers,
or
other
flow
inducing
device
that
conveys
gas
or
vapor
from
an
emissions
point
to
a
control
device.
Closure
device
means
a
cap,
hatch,
lid,
plug,
seal,
valve,
or
other
type
of
fitting
that
prevents
or
reduces
air
pollutant
emissions
to
the
atmosphere
by
blocking
an
opening
in
a
cover
when
the
device
is
secured
in
the
closed
position.
Closure
devices
include
devices
that
are
detachable
from
the
cover
(e.
g.,
a
sampling
port
cap),
manually
operated
(e.
g.,
a
hinged
access
lid
or
hatch),
or
automatically
operated
(e.
g.,
a
spring
loaded
pressure
relief
valve).
Container
means
a
portable
unit
used
to
hold
material.
Examples
of
containers
include,
but
are
not
limited
to
drums,
dumpsters,
roll
off
boxes,
bulk
cargo
containers
commonly
known
as
portable
tanks
or
totes,
cargo
tank
trucks,
dump
trucks
and
tank
rail
cars.
Continuous
record
means
documentation
of
data
values
measured
at
least
once
every
15
minutes
and
recorded
at
the
frequency
specified
in
this
subpart.
Continuous
recorder
means
a
data
recording
device
that
either
records
an
instantaneous
data
value
at
least
once
every
15
minutes
or
records
15
minutes
or
more
frequent
block
averages.
Continuous
seal
means
a
seal
that
forms
a
continuous
closure
that
completely
covers
the
space
between
the
edge
of
the
floating
roof
and
the
wall
of
a
tank.
A
continuous
seal
may
be
a
vapor
mounted
seal,
liquid
mounted
seal,
or
metallic
shoe
seal.
A
continuous
seal
may
be
constructed
of
fastened
segments
so
as
to
form
a
continuous
seal.
Control
device
means
equipment
used
for
recovering
or
oxidizing
organic
vapors.
Examples
of
such
equipment
include
but
are
not
limited
to
carbon
adsorbers,
condensers,
vapor
incinerators,
flares,
boilers,
and
process
heaters.
Cover
means
a
device
that
prevents
or
reduces
air
pollutant
emissions
to
the
atmosphere
by
forming
a
continuous
barrier
over
the
remediation
material
managed
in
a
unit.
A
cover
may
have
openings
(such
as
access
hatches,
sampling
ports,
gauge
wells)
that
are
necessary
for
operation,
inspection,
maintenance,
and
repair
of
the
unit
on
which
the
cover
is
used.
A
cover
may
be
a
separate
piece
of
equipment
which
can
be
detached
and
removed
from
the
unit
(such
as
a
tarp)
or
a
cover
may
be
formed
by
structural
features
permanently
integrated
into
the
design
of
the
unit.
Deviation
means
any
instance
in
which
an
affected
source
subject
to
this
subpart,
or
an
owner
or
operator
of
such
a
source:
(1)
Fails
to
meet
any
requirement
or
obligation
established
by
this
subpart,
including
but
not
limited
to
any
emissions
limitation
(including
any
operating
limit),
or
work
practice
standard;
(2)
Fails
to
meet
any
term
or
condition
that
is
adopted
to
implement
an
applicable
requirement
in
this
subpart
and
that
is
included
in
the
operating
permit
for
any
affected
source
required
to
obtain
such
a
permit;
or
(3)
Fails
to
meet
any
emissions
limitation,
(including
any
operating
limit),
or
work
practice
standard
in
this
subpart
during
startup,
shutdown,
or
malfunction,
regardless
of
whether
or
not
such
failure
is
permitted
by
this
subpart.
Emissions
limitation
means
any
emissions
limit,
opacity
limit,
operating
limit,
or
visible
emissions
limit.
Emissions
point
means
an
individual
tank,
surface
impoundment,
container,
oil/
water,
organic/
water
separator,
transfer
system,
vent,
or
enclosure.
Enclosure
means
a
structure
that
surrounds
a
tank
or
container,
captures
organic
vapors
emitted
from
the
tank
or
container,
and
vents
the
captured
vapor
through
a
closed
vent
system
to
a
control
device.
Equipment
means
each
pump,
pressure
relief
device,
sampling
connection
system,
valve,
and
connector
used
in
remediation
material
service
at
a
facility.
External
floating
roof
means
a
pontoon
type
or
double
deck
type
cover
that
rests
on
the
liquid
surface
in
a
tank
with
no
fixed
roof.
Facility
means
all
contiguous
or
adjoining
property
that
is
under
common
control
including
properties
that
are
separated
only
by
a
road
or
other
public
right
of
way.
Common
control
includes
properties
that
are
owned,
leased,
or
operated
by
the
same
entity,
parent
entity,
subsidiary,
or
any
combination
thereof.
A
unit
or
group
of
units
within
a
contiguous
property
that
are
not
under
common
control
(e.
g.,
a
wastewater
treatment
unit
located
at
the
facility
but
is
owned
by
a
different
company)
is
a
different
facility.
Fixed
roof
means
a
cover
that
is
mounted
on
a
unit
in
a
stationary
position
and
does
not
move
with
fluctuations
in
the
level
of
the
liquid
managed
in
the
unit.
Flame
zone
means
the
portion
of
the
combustion
chamber
in
a
boiler
or
process
heater
occupied
by
the
flame
envelope.
Floating
roof
means
a
cover
consisting
of
a
double
deck,
pontoon
single
deck,
or
internal
floating
cover
which
rests
upon
and
is
supported
by
the
liquid
being
contained,
and
is
equipped
with
a
continuous
seal.
HAP
means
hazardous
air
pollutants.
Hard
piping
means
pipe
or
tubing
that
is
manufactured
and
properly
installed
in
accordance
with
relevant
standards
and
good
engineering
practices.
Individual
drain
system
means
a
stationary
system
used
to
convey
wastewater
streams
or
residuals
to
a
remediation
material
management
unit
or
to
discharge
or
disposal.
The
term
includes
hard
piping,
all
drains
and
junction
boxes,
together
with
their
associated
sewer
lines
and
other
junction
boxes
(e.
g.,
manholes,
sumps,
and
lift
stations)
conveying
wastewater
streams
or
residuals.
For
the
purpose
of
this
subpart,
an
individual
drain
system
is
not
a
drain
and
collection
system
that
is
designed
and
operated
for
the
sole
purpose
of
collecting
rainfall
runoff
(e.
g.,
stormwater
sewer
system)
and
is
segregated
from
all
other
individual
drain
systems.
Internal
floating
roof
means
a
cover
that
rests
or
floats
on
the
liquid
surface
(but
not
necessarily
in
complete
contact
with
it
inside
a
tank
that
has
a
fixed
roof).
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Federal
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
Light
material
service
means
the
container
is
used
to
manage
remediation
material
for
which
both
of
the
following
conditions
apply:
the
vapor
pressure
of
one
or
more
of
the
organic
constituents
in
the
remediation
material
is
greater
than
0.3
kilopascals
(kPa)
at
20
C
and
the
total
concentration
of
the
pure
organic
constituents
having
a
vapor
pressure
greater
than
0.3
kPa
at
20
C
is
equal
to
or
greater
than
20
percent
by
weight.
Liquid
mounted
seal
means
a
foam
or
liquid
filled
continuous
seal
mounted
in
contact
with
the
liquid
in
a
unit.
MACT
activity
means
a
nonremediation
activity
that
is
covered
by
a
category
of
major
sources
listed
pursuant
to
section
112(
c)
of
the
CAA.
An
activity
is
a
MACT
activity
whether
or
not
it
is
subject
to
the
control
requirements
of
its
appropriate
MACT
standard(
s).
Maximum
HAP
vapor
pressure
means
the
sum
of
the
individual
HAP
equilibrium
partial
pressure
exerted
by
remediation
material
at
the
temperature
equal
to
either:
the
monthly
average
temperature
as
reported
by
the
National
Weather
Service
when
the
remediation
material
is
stored
or
treated
at
ambient
temperature;
or
the
highest
calendarmonth
average
temperature
of
the
remediation
material
when
the
remediation
material
is
stored
at
temperatures
above
the
ambient
temperature
or
when
the
remediation
material
is
stored
or
treated
at
temperatures
below
the
ambient
temperature.
For
the
purpose
of
this
subpart,
maximum
HAP
vapor
pressure
is
determined
using
the
procedures
specified
in
§
63.694(
j).
For
the
purpose
of
this
subpart,
when
you
read
the
term
``
Table
3
or
Table
4
of
this
subpart''
in
§
63.694(
j)
you
should
refer
to
Table
3
of
this
subpart.
Media
means
materials
found
in
the
natural
environment
such
as
soil,
ground
water,
surface
water,
and
sediments,
or
a
mixture
of
such
materials
with
liquids,
sludges,
or
solids
which
is
inseparable
by
simple
mechanical
removal
processes
and
is
made
up
primarily
of
media.
This
definition
does
not
include
debris
(as
defined
in
40
CFR
268.2).
Metallic
shoe
seal
means
a
continuous
seal
that
is
constructed
of
metal
sheets
which
are
held
vertically
against
the
wall
of
the
tank
by
springs,
weighted
levers,
or
other
mechanisms
and
is
connected
to
the
floating
roof
by
braces
or
other
means.
A
flexible
coated
fabric
(envelope)
spans
the
annular
space
between
the
metal
sheet
and
the
floating
roof.
No
detectable
organic
emissions
means
no
escape
of
organics
to
the
atmosphere
as
determined
using
the
procedure
specified
in
63.694(
k).
Oil/
water
separator
means
a
separator
as
defined
for
this
subpart
that
is
used
to
separate
oil
from
water.
Operating
parameter
value
means
a
minimum
or
maximum
value
established
for
a
control
device
or
treatment
process
parameter
which,
if
achieved
by
itself
or
in
combination
with
one
or
more
other
operating
parameter
values,
determines
that
an
owner
or
operator
has
complied
with
an
applicable
emissions
limitation
or
standard.
Organic/
water
separator
means
a
separator
as
defined
for
this
subpart
that
is
used
to
separate
organics
from
water.
Point
of
extraction
means
the
point
where
you
first
extract
the
remediation
material
prior
to
placing
the
remediation
material
in
a
management
unit
or
other
unit,
but
before
the
first
point
where
the
organic
constituents
in
the
remediation
material
have
the
potential
to
volatilize
and
be
released
to
the
atmosphere.
For
the
purpose
of
applying
this
definition
to
this
subpart,
the
first
point
where
the
organic
constituents
in
the
remediation
material
have
the
potential
to
volatilize
and
be
released
to
the
atmosphere
is
not
a
fugitive
emissions
point
due
to
an
equipment
leak
from
any
of
the
following
equipment
components:
pumps,
compressors,
valves,
connectors,
instrumentation
systems,
or
safety
devices.
Process
heater
means
an
enclosed
combustion
device
that
transfers
heat
released
by
burning
fuel
directly
to
process
streams
or
to
heat
transfer
liquids
other
than
water.
Process
vent
means
any
open
ended
pipe,
stack,
duct,
or
other
opening
intended
to
allow
the
passage
of
gases,
vapors,
or
fumes
to
the
atmosphere
and
this
passage
is
caused
by
mechanical
means
(such
as
compressors,
vacuumproducing
systems
or
fans)
or
by
process
related
means
(such
as
volatilization
produced
by
heating).
For
the
purposes
of
this
subpart,
a
process
vent
is
neither
a
safety
device
(as
defined
in
this
section)
nor
a
stack,
duct
or
other
opening
used
to
exhaust
combustion
products
from
a
boiler,
furnace,
heater,
incinerator,
or
other
combustion
device.
Remediation
material
means
material,
including
contaminated
media,
which
is
managed
as
a
result
of
implementing
remedial
activities
required
under
Federal,
State
or
local
authorities,
or
voluntary
remediation
activity.
Remediation
material
management
unit
means
a
tank,
container,
surface
impoundment,
oil/
water
separator,
organic/
water
separator
or
transfer
system
used
to
manage
remediation
material.
Remediation
material
service
means
any
time
when
a
pump,
compressor,
agitator,
pressure
relief
device,
sampling
connection
system,
open
ended
valve
or
line,
valve,
connector,
or
instrumentation
system
contains
or
contacts
remediation
material.
Responsible
official
means
responsible
official
as
defined
in
40
CFR
70.2.
Safety
device
means
a
closure
device
such
as
a
pressure
relief
valve,
frangible
disc,
fusible
plug,
or
any
other
type
of
device
which
functions
exclusively
to
prevent
physical
damage
or
permanent
deformation
to
a
unit
or
its
air
emissions
control
equipment
by
venting
gases
or
vapors
directly
to
the
atmosphere
during
unsafe
conditions
resulting
from
an
unplanned,
accidental,
or
emergency
event.
For
the
purpose
of
this
subpart,
a
safety
device
is
not
used
for
routine
venting
of
gases
or
vapors
from
the
vapor
headspace
underneath
a
cover
such
as
during
filling
of
the
unit
or
to
adjust
the
pressure
in
this
vapor
headspace
in
response
to
normal
daily
diurnal
ambient
temperature
fluctuations.
A
safety
device
is
designed
to
remain
in
a
closed
position
during
normal
operations
and
open
only
when
the
internal
pressure,
or
another
relevant
parameter,
exceeds
the
device
threshold
setting
applicable
to
the
air
emissions
control
equipment
as
determined
by
the
owner
or
operator
based
on
manufacturer
recommendations,
applicable
regulations,
fire
protection
and
prevention
codes,
standard
engineering
codes
and
practices,
or
other
requirements
for
the
safe
handling
of
flammable,
combustible,
explosive,
reactive,
or
hazardous
materials.
Separator
means
a
remediation
material
management
unit,
generally
a
tank,
used
to
separate
oil
or
organics
from
water.
A
separator
consists
of
not
only
the
separation
unit
but
also
the
forebay
and
other
separator
basins,
skimmers,
weirs,
grit
chambers,
sludge
hoppers,
and
bar
screens
that
are
located
directly
after
the
individual
drain
system
and
prior
to
any
additional
treatment
units
such
as
an
air
flotation
unit
clarifier
or
biological
treatment
unit.
Examples
of
a
separator
include,
but
are
not
limited
to,
an
API
separator,
parallel
plate
interceptor,
and
corrugated
plate
interceptor
with
the
associated
ancillary
equipment.
Single
seal
system
means
a
floating
roof
having
one
continuous
seal.
This
seal
may
be
vapor
mounted,
liquidmounted
or
a
metallic
shoe
seal.
Sludge
means
sludge
as
defined
in
§
260.10
of
this
chapter.
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Proposed
Rules
Soil
means
unconsolidated
earth
material
composing
the
superficial
geologic
strata
(material
overlying
bedrock),
consisting
of
clay,
silt,
sand,
or
gravel
size
particles
(sizes
as
classified
by
the
U.
S.
Soil
Conservation
Service),
or
a
mixture
of
such
materials
with
liquids,
sludges,
or
solids
which
is
inseparable
by
simple
mechanical
removal
processes
and
is
made
up
primarily
of
soil.
Solvent
extraction
means
an
operation
or
method
of
separation
in
which
a
solid
or
solution
is
contacted
with
a
liquid
solvent
(the
two
being
mutually
insoluble)
to
preferentially
dissolve
and
transfer
one
or
more
components
into
the
solvent.
Stabilization
process
means
any
physical
or
chemical
process
used
to
either
reduce
the
mobility
of
contaminants
in
media
or
eliminate
free
liquids
as
determined
by
Test
Method
9095—
Paint
Filter
Liquids
Test
in
``
Test
Methods
for
Evaluating
Solid
Waste,
Physical/
Chemical
Methods,
''
EPA
Publication
No.
SW–
846,
Third
Edition,
September
1986,
as
amended
by
Update
I,
November
15,
1992.
(As
an
alternative,
you
may
use
any
more
recent,
updated
version
of
Method
9095
approved
by
the
EPA).
A
stabilization
process
includes
mixing
remediation
material
with
binders
or
other
materials,
and
curing
the
resulting
remediation
material
and
binder
mixture.
Other
synonymous
terms
used
to
refer
to
this
process
are
fixation
or
solidification.
A
stabilization
process
does
not
include
the
adding
of
absorbent
materials
to
the
surface
of
remediation
material,
without
mixing,
agitation,
or
subsequent
curing,
to
absorb
free
liquid.
Surface
impoundment
means
a
unit
that
is
a
natural
topographical
depression,
man
made
excavation,
or
diked
area
formed
primarily
of
earthen
materials
(although
it
may
be
lined
with
man
made
materials),
which
is
designed
to
hold
an
accumulation
of
liquids.
Examples
of
surface
impoundments
include
holding,
storage,
settling,
and
aeration
pits,
ponds,
and
lagoons.
Tank
means
a
stationary
unit
that
is
constructed
primarily
of
nonearthen
materials
(such
as
wood,
concrete,
steel,
fiberglass,
or
plastic)
which
provide
structural
support
and
is
designed
to
hold
an
accumulation
of
liquids
or
other
materials.
Temperature
monitoring
device
means
a
piece
of
equipment
used
to
monitor
temperature
and
having
an
accuracy
of
±
1
percent
of
the
temperature
being
monitored
expressed
in
degrees
Celsius
(
C)
or
±
1.2
degrees
°
C,
whichever
value
is
greater.
Transfer
system
means
a
stationary
system
for
which
the
predominant
function
is
to
convey
liquids
or
solid
materials
from
one
point
to
another
point
within
waste
management
operation
or
recovery
operation.
For
the
purpose
of
this
subpart,
the
conveyance
of
material
using
a
container
(as
defined
of
this
subpart)
or
self
propelled
vehicle
(e.
g.,
a
front
end
loader)
is
not
a
transfer
system.
Examples
of
a
transfer
system
include
but
are
not
limited
to
a
pipeline,
an
individual
drain
system,
a
gravityoperated
conveyor
(such
as
a
chute),
and
a
mechanically
powered
conveyor
(such
as
a
belt
or
screw
conveyor).
Treatment
process
means
a
process
in
which
remediation
material
is
physically,
chemically,
thermally,
or
biologically
treated
to
destroy,
degrade,
or
remove
hazardous
air
pollutants
contained
in
the
material.
A
treatment
process
can
be
composed
of
a
single
unit
(e.
g.,
a
steam
stripper)
or
a
series
of
units
(e.
g.,
a
wastewater
treatment
system).
A
treatment
process
can
be
used
to
treat
one
or
more
remediation
material
streams
at
the
same
time.
Vapor
mounted
seal
means
a
continuous
seal
that
is
mounted
such
that
there
is
a
vapor
space
between
the
liquid
in
the
unit
and
the
bottom
of
the
seal.
Volatile
organic
hazardous
air
pollutant
concentration
or
VOHAP
concentration
means
the
fraction
by
weight
of
the
HAP
listed
in
Table
1
of
this
subpart
that
are
contained
in
the
remediation
material
as
measured
using
Method
305,
40
CFR
part
63,
appendix
A
and
expressed
in
terms
of
parts
per
million
(ppm).
As
an
alternative
to
using
Method
305,
40
CFR
part
63,
appendix
A,
you
may
determine
the
HAP
concentration
of
the
remediation
material
using
any
one
of
the
other
test
methods
specified
in
§
63.694(
b)(
2)(
ii).
When
a
test
method
specified
in
§
63.694(
b)(
2)(
ii)
other
than
Method
305
in
appendix
A
of
this
part
is
used
to
determine
the
speciated
HAP
concentration
of
the
contaminated
material,
the
individual
compound
concentration
may
be
adjusted
by
the
corresponding
fm305
listed
in
Table
1
of
this
subpart
to
determine
a
VOHAP
concentration.
Work
practice
standard
means
any
design,
equipment,
work
practice,
or
operational
standard,
or
combination
thereof,
that
is
promulgated
pursuant
to
section
112(
h)
of
the
CAA.
As
stated
in
§§
63.7882
(c)(
1)(
i)
and
(ii),
(c)(
2),
(c)(
3)(
i)
through
(iii);
63.7912(
a)(
3)(
ii),
(g)(
3)(
ii),
(h);
and
63.7942;
you
must
use
the
information
in
the
following
table
to
determine
the
total
annual
HAP
quantity
in
the
extracted
remediation
material
at
the
facility:
TABLE
1
TO
SUBPART
GGGGG
OF
PART
63—
HAZARDOUS
AIR
POLLUTANTS
CAS
No.
a
Compound
Name
fm
305
75070
.........................................
Acetaldehyde
.................................................................................................................................
1.000
75058
.........................................
Acetonitrile
.....................................................................................................................................
0.989
98862
.........................................
Acetophenone
................................................................................................................................
0.314
107028
.......................................
Acrolein
..........................................................................................................................................
1.000
107131
.......................................
Acrylonitrile
....................................................................................................................................
0.999
107051
.......................................
Allyl
chloride
...................................................................................................................................
1.000
71432
.........................................
Benzene
(includes
benzene
in
gasoline)
......................................................................................
1.000
98077
.........................................
Benzotrichloride
(isomers
and
mixture)
.........................................................................................
0.958
100447
.......................................
Benzyl
chloride
..............................................................................................................................
1.000
92524
.........................................
Biphenyl
.........................................................................................................................................
0.864
542881
.......................................
Bis(
chloromethyl)
ether
b
..................................................................................................................
0.999
75252
.........................................
Bromoform
.....................................................................................................................................
0.998
106990
.......................................
1,3
Butadiene
.................................................................................................................................
1.000
75150
.........................................
Carbon
disulfide
.............................................................................................................................
1.000
56235
.........................................
Carbon
Tetrachloride
.....................................................................................................................
1.000
43581
.........................................
Carbonyl
sulfide
.............................................................................................................................
1.000
133904
.......................................
Chloramben
...................................................................................................................................
0.633
108907
.......................................
Chlorobenzene
...............................................................................................................................
1.000
67663
.........................................
Chloroform
.....................................................................................................................................
1.000
107302
.......................................
Chloromethyl
methyl
ether
b
...........................................................................................................
1.000
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/
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July
30,
2002
/
Proposed
Rules
TABLE
1
TO
SUBPART
GGGGG
OF
PART
63—
HAZARDOUS
AIR
POLLUTANTS—
Continued
CAS
No.
a
Compound
Name
fm
305
126998
.......................................
Chloroprene
...................................................................................................................................
1.000
98828
.........................................
Cumene
.........................................................................................................................................
1.000
94757
.........................................
2,4
D,
salts
and
esters
..................................................................................................................
0.167
334883
.......................................
Diazomethane
c
...............................................................................................................................
0.999
132649
.......................................
Dibenzofurans
................................................................................................................................
0.967
96128
.........................................
1,2
Dibromo
3
chloropropane
........................................................................................................
1.000
106467
.......................................
1,4
Dichlorobenzene(
p)
.................................................................................................................
1.000
107062
.......................................
Dichloroethane
(Ethylene
dichloride)
.............................................................................................
1.000
111444
.......................................
Dichloroethyl
ether
(Bis(
2
chloroethyl
ether)
.................................................................................
0.757
542756
.......................................
1,3
Dichloropropene
......................................................................................................................
1.000
79447
.........................................
Dimethyl
carbamoyl
chloride
c
........................................................................................................
0.150
57147
.........................................
1,1
Dimethyl
hydrazine.
64675
.........................................
Diethyl
sulfate
................................................................................................................................
0.0025
77781
.........................................
Dimethyl
sulfate
.............................................................................................................................
0.086
121697
.......................................
N,
N
Dimethylaniline
.......................................................................................................................
0.0008
51285
.........................................
2,4
Dinitrophenol
............................................................................................................................
0.0077
121142
.......................................
2,4
Dinitrotoluene
...........................................................................................................................
0.0848
123911
.......................................
1,4
Dioxane
(1,4
Diethyleneoxide)
................................................................................................
0.869
106898
.......................................
Epichlorohydrin
(1
Chloro
2,3
epoxypropane)
...............................................................................
0.939
106887
.......................................
1,2
Epoxybutane
............................................................................................................................
1.000
140885
.......................................
Ethyl
acrylate
.................................................................................................................................
1.000
100414
.......................................
Ethyl
benzene
................................................................................................................................
1.000
75003
.........................................
Ethyl
chloride
(Chloroethane)
........................................................................................................
1.000
106934
.......................................
Ethylene
dibromide
(Dibromoethane)
............................................................................................
0.999
107062
.......................................
Ethylene
dichloride
(1,2
Dichloroethane)
......................................................................................
1.000
151564
.......................................
Ethylene
imine
(Aziridine)
..............................................................................................................
0.867
75218
.........................................
Ethylene
oxide
...............................................................................................................................
1.000
75343
.........................................
Ethylidene
dichloride
(1,1
Dichloroethane)
....................................................................................
Glycol
ethers
d
that
have
a
Henry's
Law
constant
value
equal
to
or
greater
than
0.1
Y/
X(
1.8
X
10–
6
atm/
gm
mole/
m
3
)
at
25
C.
1.000
[e]
118741
.......................................
Hexachlorobenzene
.......................................................................................................................
0.97
87683
.........................................
Hexachlorobutadiene
.....................................................................................................................
0.88
67721
.........................................
Hexachloroethane
..........................................................................................................................
0.499
110543
.......................................
Hexane
...........................................................................................................................................
1.000
78591
.........................................
Isophorone
.....................................................................................................................................
0.506
58899
.........................................
Lindane
(all
isomers)
.....................................................................................................................
1.000
67561
.........................................
Methanol
........................................................................................................................................
0.855
74839
.........................................
Methyl
bromide
(Bromomethane)
..................................................................................................
1.000
74873
.........................................
Methyl
chloride
(Choromethane)
...................................................................................................
1.000
71556
.........................................
Methyl
chloroform
(1,1,1
Trichloroethane)
....................................................................................
1.000
78933
.........................................
Methyl
ethyl
ketone
(2
Butanone)
.................................................................................................
0.990
74884
.........................................
Methyl
iodide
(Iodomethane)
.........................................................................................................
1.000
108101
.......................................
Methyl
isobutyl
ketone
(Hexone)
...................................................................................................
0.979
624839
.......................................
Methyl
isocyanate
..........................................................................................................................
1.000
80626
.........................................
Methyl
methacrylate
.......................................................................................................................
0.999
1634044
.....................................
Methyl
tert
butyl
ether
....................................................................................................................
1.000
75092
.........................................
Methylene
chloride
(Dichloromethane)
..........................................................................................
1.000
91203
.........................................
Naphthalene
...................................................................................................................................
0.994
98953
.........................................
Nitrobenzene
..................................................................................................................................
0.394
79469
.........................................
2
Nitropropane
...............................................................................................................................
0.989
82688
.........................................
Pentachloronitrobenzene
(Quintobenzene)
...................................................................................
0.839
87865
.........................................
Pentachlorophenol
.........................................................................................................................
0.0898
75445
.........................................
Phosgene
c
......................................................................................................................................
1.000
123386
.......................................
Propionaldehyde
............................................................................................................................
0.999
78875
.........................................
Propylene
dichloride
(1,2
Dichloropropane)
..................................................................................
1.000
75569
.........................................
Propylene
oxide
.............................................................................................................................
1.000
75558
.........................................
1,2
Propylenimine
(2
Methyl
aziridine)
..........................................................................................
0.945
100425
.......................................
Styrene
...........................................................................................................................................
1.000
96093
.........................................
Styrene
oxide
.................................................................................................................................
0.830
79345
.........................................
1,1,2,2
Tetrachloroethane
..............................................................................................................
0.999
127184
.......................................
Tetrachloroethylene
(Perchloroethylene)
.......................................................................................
1.000
108883
.......................................
Toluene
..........................................................................................................................................
1.000
95534
.........................................
o
Toluidine
.....................................................................................................................................
0.152
120821
.......................................
1,2,4
Trichlorobenzene
..................................................................................................................
1.000
71556
.........................................
1,1,1
Trichloroethane
(Methyl
chlorform)
......................................................................................
1.000
79005
.........................................
1,1,2
Trichloroethane
(Vinyl
trichloride)
.........................................................................................
1.000
79016
.........................................
Trichloroethylene
...........................................................................................................................
1.000
95954
.........................................
2,4,5
Trichlorophenol
.....................................................................................................................
0.108
88062
.........................................
2,4,6
Trichlorophenol
.....................................................................................................................
0.132
121448
.......................................
Triethylamine
.................................................................................................................................
1.000
540841
.......................................
2,2,4
Trimethylpentane
..................................................................................................................
1.000
108054
.......................................
Vinyl
acetate
..................................................................................................................................
1.000
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
1
TO
SUBPART
GGGGG
OF
PART
63—
HAZARDOUS
AIR
POLLUTANTS—
Continued
CAS
No.
a
Compound
Name
fm
305
593602
.......................................
Vinyl
bromide
.................................................................................................................................
1.000
75014
.........................................
Vinyl
chloride
.................................................................................................................................
1.000
75354
.........................................
Vinylidene
chloride
(1,1
Dichloroethylene)
....................................................................................
1.000
1330207
.....................................
Xylenes
(isomers
and
mixture)
......................................................................................................
1.000
95476
.........................................
o
Xylenes
.......................................................................................................................................
1.000
108383
.......................................
m
Xylenes
......................................................................................................................................
1.000
106423
.......................................
p
Xylenes
.......................................................................................................................................
1.000
Notes:
fm
305
=
Fraction
measure
factor
in
Method
305,
40
CFR
part
63,
appendix
A
of
this
part.
a
CAS
numbers
refer
to
the
Chemical
Abstracts
Services
registry
number
assigned
to
specific
compounds,
isomers,
or
mixtures
of
compounds.
b
Denotes
a
HAP
that
hydrolyzes
quickly
in
water,
but
the
hydrolysis
products
are
also
HAP
chemicals.
c
Denotes
a
HAP
that
may
react
violently
with
water.
d
Denotes
a
HAP
that
hydrolyzes
slowly
in
water.
e
The
fm
305
factors
for
some
of
the
more
common
glycol
ethers
can
be
obtained
by
contacting
the
Waste
and
Chemical
Processes
Group,
Office
of
Air
Quality
Planning
and
Standards,
Research
Triangle
Park,
NC
27711.
As
stated
in
§§
63.7890(
a)
and
63.7912(
e),
(f)(
1)
through
(4),
(g)(
1),
and
(k),
you
must
meet
each
emissions
limitation
for
process
vent
affected
sources
in
the
following
table
that
applies
to
you:
TABLE
2
TO
SUBPART
GGGGG
OF
PART
63.—
EMISSIONS
LIMITATIONS
FOR
PROCESS
VENT
AFFECTED
SOURCES
For
.
.
.
You
must
meet
the
following
emissions
limitation
.
.
.
1.
All
new
and
existing
affected
source
process
vents
associated
with
remediation
activities.
a.
For
each
24
hour
period,
reduce
emissions
of
HAP,
listed
in
Table
1
of
this
subpart,
or
TOC
(minus
methane
and
ethane)
from
all
affected
process
vents
by
95
weight
percent
by
venting
emissions
through
a
closed
vent
system
to
any
combination
of
control
devices
meeting
the
requirements
of
§
63.693.
Instead
of
achieving
the
performance
specifications
listed
in
§
63.693(
d)
through
(g),
you
must
meet
a
performance
level
for
each
control
device
necessary
to
achieve
the
95%
control
level
for
all
process
vents
combined;
or
b)
For
each
period
specified,
reduce
emissions
of
TOC
(minus
methane
and
ethane)
from
all
affected
source
process
vents
at
the
facility
below
1.4
kg/
h
(3.0
lb/
h)
and
b.
8
mg/
yr
(3.1
tons/
yr).
Instead
of
achieving
the
performance
specifications
listed
in
§
63.693(
d)
through
(g),
you
must
meet
a
performance
level
for
each
control
device
necessary
to
achieve
the
overall
emissions
rate
limit
for
all
process
vents
(whether
controlled
or
uncontrolled)
combined.
As
stated
in
§§
63.7890(
b),
63.7912
(e)
and
(k),
and
63.7942,
you
must
meet
each
emissions
limitation
for
remediation
material
management
unit
affected
sources
in
the
following
table
that
applies
to
you:
TABLE
3
TO
SUBPART
GGGGG
OF
PART
63.—
EMISSIONS
LIMITATIONS
FOR
REMEDIATION
MATERIAL
MANAGEMENT
UNIT
AFFECTED
SOURCES
For
each
.
.
.
Where
.
.
.
Then
you
must
.
.
.
1.
New
and
existing
tank
that
is
an
affected
source
with
a
design
capacity
less
than
38
cubic
meters
(m
3
)
(10,000
gallons).
a.
The
maximum
HAP
vapor
pressure
of
the
remediation
material
in
the
tank
is
less
than
76.6
kilopascals
(kPa)
(11.1
psia).
i.
For
each
24
hour
period,
reduce
emissions
of
HAP,
listed
in
Table
1
of
this
subpart,
or
TOC
(minus
methane
and
ethane)
by
95
weight
percent
(or,
for
combustion
devices,
to
an
exhaust
concentration
of
20
parts
per
million
by
volume,
on
a
dry
basis,
corrected
to
3%
oxygen)
by
venting
emissions
through
a
closed
vent
system
to
any
combination
of
control
devices
meeting
the
requirements
of
§
63.693;
or
ii.
Comply
with
one
of
the
work
practice
standards
(control
level
1
or
2)
specified
in
Table
5,
item
1
of
this
subpart.
2.
New
and
existing
tank
that
is
an
affected
source
with
a
design
capacity
greater
than
or
equal
to
38
m
3
and
less
than
151
m
3
(40,000
gallons).
a.
The
maximum
HAP
vapor
pressure
of
the
remediation
material
in
the
tank
is
less
than
13.1
kPa
(1.9
psia).
Same
as
Table
3,
items
1(
a)
of
this
subpart;
3.
New
and
existing
tank
that
is
an
affected
source
with
a
design
capacity
greater
than
or
equal
to
38
m
3
and
less
than
151
m
3
(40,000
gallons).
a.
The
maximum
HAP
vapor
pressure
of
the
remediation
material
in
the
tank
is
greater
than
or
equal
to
13.1
kPa
(1.9
psia).
i.
Same
as
Table
3,
item
1(
a)
of
this
subpart;
or
ii.
Comply
with
the
work
practice
standards
(for
control
level
2)
specified
in
Table
5,
item
2
of
this
subpart.
4.
New
and
existing
tank
that
is
an
affected
source
with
a
design
capacity
greater
than
or
equal
to
151
m
3
.
a.
The
maximum
HAP
vapor
pressure
of
the
remediation
material
in
the
tank
is
less
than
0.7
kPa
(0.1
psia).
Same
as
Table
3,
item
1(
a)
of
this
subpart.
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
3
TO
SUBPART
GGGGG
OF
PART
63.—
EMISSIONS
LIMITATIONS
FOR
REMEDIATION
MATERIAL
MANAGEMENT
UNIT
AFFECTED
SOURCES—
Continued
For
each
.
.
.
Where
.
.
.
Then
you
must
.
.
.
5.
New
and
existing
tank
that
is
an
affected
source
with
a
design
capacity
greater
than
or
equal
to
151
m
3
.
a.
The
maximum
HAP
vapor
pressure
of
the
remediation
material
in
the
tank
is
greater
than
or
equal
to
0.7
kPa
(0.1
psia).
i.
Same
as
Table
3,
item
1(
a)
of
this
subpart;
or
ii.
Comply
with
the
work
practice
standards
(for
control
level
2)
specified
in
Table
5,
item
2
of
this
subpart.
6.
New
and
existing
container
that
is
an
affected
source.
a.
The
design
capacity
is
greater
than
0.1
m
3
(26
gallons)
and
less
than
or
equal
to
0.46
m
3
(119
gallons).
i.
Same
as
Table
3,
item
1(
a)
of
this
subpart;
or
ii.
Comply
with
one
of
the
work
practice
standards
(control
level
1,
2
or
3)
specified
in
Table
5,
items
3
or
4
of
this
subpart.
7.
New
and
existing
container
that
is
an
affected
source.
a.
The
design
capacity
is
greater
than
0.46
m
3
and
the
container
is
not
in
light
material
service
as
defined
in
§
63.7942.
i.
Same
as
Table
3,
item
1(
a)
of
this
subpart;
or
ii.
Comply
with
one
of
the
work
practice
standards
(control
level
1,
2
or
3)
specified
in
Table
5,
item
3
or
4
of
this
subpart.
8.
New
and
existing
container
that
is
an
affected
source.
a.
The
design
capacity
is
greater
than
0.46
m
3
and
the
container
is
in
light
material
service
as
defined
in
§
63.7942.
i.
Same
as
Table
3,
item
1(
a)
of
this
subpart;
or
ii.
Comply
with
one
of
the
work
practice
standards
(control
level
2
or
3)
specified
in
Table
5,
item
4
or
5
of
this
subpart.
9.
New
and
existing
container
that
is
an
affected
source.
a.
The
design
capacity
is
greater
than
0.1
m
3
and
the
container
is
used
for
a
stabilization
process.
i.
Comply
with
one
of
the
following
whenever
the
remediation
material
is
exposed
to
the
atmosphere:
(1)
The
requirements
of
Table
3,
item
1(
a)
of
this
subpart;
or
(2)
The
work
practice
standards
(for
control
level
3)
specified
in
Table
5,
item
4
of
this
subpart.
10.
New
and
existing
surface
impoundment
that
is
an
affected
source.
i.
Same
as
Table
3,
item
1(
a)
of
this
subpart;
or.
ii.
Comply
with
one
of
the
work
practice
standards
specified
in
Table
5,
items
6
or
7
of
this
subpart.
11.
New
and
existing
oil/
water
separator
and
organic/
water
separator.
i.
Same
as
Table
3,
item
1(
a)
of
this
subpart,
or.
ii.
Comply
with
one
of
the
work
practice
standards
specified
in
Table
5,
items
8
or
9
of
this
subpart.
As
stated
in
§§
63.7890(
c),
63.7912(
d),
63.7914(
b)
and
63.7942,
you
must
meet
each
operating
limit
in
the
following
table
that
applies
to
you:
TABLE
4
TO
SUBPART
GGGGG
OF
PART
63.—
OPERATING
LIMITS
AND
ASSOCIATED
WORK
PRACTICES
FOR
CONTROL
DEVICES
For
.
.
.
You
must
.
.
.
1.
Each
existing
and
each
new
affected
source
using
a
thermal
incinerator
to
comply
with
an
emissions
limit
in
Table
2
and
3
of
this
subpart
a.
Maintain
the
daily
average
firebox
temperature
greater
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test.
b.
Maintain
the
daily
average
total
organic
or
HAP
concentration
at
the
outlet
less
than
or
equal
to
the
concentration
established
during
the
performance
test
(applies
for
CEMS
only).
2.
Each
existing
and
each
new
affected
source
using
a
catalytic
incinerator
to
comply
with
an
emissions
limit
in
Table
2
and
3
of
this
subpart
a.
replace
the
existing
catalyst
bed
with
a
bed
that
meets
the
replacement
specifications
established
during
the
design
evaluation
or
performance
test
before
the
age
of
the
bed
exceeds
the
maximum
allowable
age
established
during
the
design
evaluation
or
performance
test;
and
b.
Maintain
the
daily
average
temperature
at
the
inlet
of
the
catalyst
bed
greater
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test.
c.
Maintain
the
daily
average
total
organic
or
HAP
concentration
at
the
outlet
less
than
or
equal
to
the
concentration
established
during
the
performance
test
(applies
for
CEMS
only).
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
4
TO
SUBPART
GGGGG
OF
PART
63.—
OPERATING
LIMITS
AND
ASSOCIATED
WORK
PRACTICES
FOR
CONTROL
DEVICES—
Continued
For
.
.
.
You
must
.
.
.
3.
Each
existing
and
each
new
affected
source
using
a
condenser
to
comply
with
an
emissions
limit
in
Table
2
and
3
of
this
subpart.
a.
Maintain
the
daily
average
condenser
exit
temperature
less
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test.
b.
Maintain
the
daily
average
total
organic
or
HAP
concentration
at
the
outlet
less
than
or
equal
to
the
concentration
established
during
the
performance
test
(applies
for
CEMS
only).
4.
Each
existing
and
each
new
affected
source
using
a
carbon
adsorption
system
with
adsorbent
regeneration
to
comply
with
an
emissions
limit
in
Table
2
and
3
of
this
subpart.
a.
Replace
the
existing
adsorbent
in
each
segment
of
the
bed
with
an
adsorbent
that
meets
the
replacement
specifications
established
during
the
design
evaluation
or
performance
test
before
the
age
of
the
adsorbent
exceeds
the
maximum
allowable
age
established
during
the
design
evaluation
or
performance
test
in
accordance
with
§
63.693(
d)(
2)
through
(4);
and
b.
Maintain
the
frequency
of
regeneration
greater
than
or
equal
to
the
frequency
established
during
the
design
evaluation
or
performance
test
in
accordance
with
§
63.693(
d)(
2)
through
(4);
and
c.
Maintain
the
1
hour
average
total
regeneration
stream
mass
flow
during
the
adsorption
bed
regeneration
cycle
greater
than
or
equal
to
the
stream
mass
flow
established
during
the
design
evaluation
or
performance
test
in
accordance
with
§
63.693(
d)(
2)
through
(4);
and
d.
Maintain
the
1
hour
average
temperature
of
the
adsorption
bed
during
regeneration
(except
during
the
cooling
cycle)
greater
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test
in
accordance
with
§
63.693(
d)(
2)
through
(4);
and
e.
Maintain
the
1
hour
average
temperature
of
the
adsorption
bed
after
regeneration
(and
within
15
minutes
after
completing
any
cooling
cycle)
less
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test
in
accordance
with
§
63.693(
d)(
2)
through
(4).
f.
Maintain
the
daily
average
total
organic
or
HAP
concentration
at
the
outlet
less
than
or
equal
to
the
concentration
established
during
the
performance
test
in
accordance
with
§
63.693(
d)(
2)
(applies
for
CEMS
only).
5.
Each
existing
and
each
new
affected
source
using
a
carbon
adsorption
system
without
adsorbent
regeneration
to
comply
with
an
emissions
limit
in
Table
2
and
3
of
this
subpart.
a.
Replace
the
existing
adsorbent
in
each
segment
of
the
bed
with
an
adsorbent
that
meets
the
replacement
specifications
established
during
the
design
evaluation
or
performance
test
before
the
age
of
the
adsorbent
exceeds
the
maximum
allowable
age
established
during
the
design
evaluation
or
performance
test
in
accordance
with
§
63.693(
d)(
2);
and
b.
Maintain
the
1
hour
average
temperature
of
the
adsorption
bed
less
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test
in
accordance
with
§
63.693(
d)(
2).
c.
Maintain
the
daily
average
total
organic
or
HAP
concentration
at
the
outlet
less
than
or
equal
to
the
concentration
established
during
the
performance
test
(applies
for
CEMS
only).
6.
Each
existing
and
each
new
affected
source
using
a
boiler
or
process
heater
to
comply
with
an
emissions
limit
in
Table
2
and
3
of
this
subpart.
a.
Maintain
the
daily
average
firebox
temperature
within
the
operating
level
established
during
the
performance
test.
b.
Maintain
the
daily
average
total
organic
or
HAP
concentration
at
the
outlet
less
than
or
equal
to
the
concentration
established
during
the
performance
test
(applies
for
CEMS
only).
7.
Each
existing
and
each
new
affected
source
using
a
flare
to
comply
with
an
emissions
limit
in
Table
2
and
3
of
this
subpart.
a.
Operate
the
flare
at
all
times
when
emissions
may
be
vented
to
it
and
with
no
visible
emissions
in
accordance
with
§
63.11(
b)(
4);
and
b.
Maintain
the
presence
of
a
flame
at
all
times
inaccordance
with
§
63.11(
b)(
5);
and
c.
Meet
the
heat
content
specification
in
§
63.11(
b)(
6)(
ii)
and
the
maximum
tip
velocity
specifications
in
§
63.11(
b)(
8)
or
(7),
or
meet
the
requirements
in
§
63.11(
b)(
6)(
i).
d.
Maintain
the
daily
average
total
organic
or
HAP
concentration
at
the
outlet
less
than
or
equal
to
the
concentration
established
during
the
performance
test
(applies
for
CEMS
only).
As
stated
in
§
63.7890(
d),
you
must
meet
each
work
practice
standard
in
the
following
table
that
applies
to
you:
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49437
Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
5
TO
SUBPART
GGGGG
OF
PART
63.—
WORK
PRACTICE
STANDARDS
For
each
.
.
.
You
must
.
.
.
1.
New
or
existing
tank
that
is
an
affected
source
meeting
any
set
of
capacity
and
vapor
pressure
limits
specified
in
Table
3,
items
1,
2
or
4
of
this
subpart.
a.
As
an
alternative
to
the
emissions
limit
in
Table
3
of
this
subpart,
comply
with
the
requirements
of
subpart
OO
(control
level
1)
of
this
part;
or
b.
Comply
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
2.
New
or
existing
tank
that
is
an
affected
source
meeting
any
set
of
capacity
and
vapor
pressure
limits
specified
in
Table
3,
items
3
or
5
of
this
subpart.
As
an
alternative
to
the
emissions
limit
in
Table
3
of
this
subpart,
comply
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
3.
New
or
existing
container
that
is
an
affected
source
{
meeting
any
set
of
capacity
limits
specified
in
Table
3,
items
6
or
7
of
this
subpart
that
is
not
vented
to
a
control
device.
a.
As
an
alternative
to
the
emissions
limit
in
Table
3
of
this
subpart,
comply
with
the
requirements
of
§
63.922
(control
level
1);
or
b.
Comply
with
the
requirements
of
§
63.923
(control
level
2).
4.
New
or
existing
container
that
is
an
affected
source
{
meeting
any
set
of
capacity
limits
specified
in
Table
3,
items
6,
7,
8
or
9
of
this
subpart
that
is
vented
to
a
control
device.
As
an
alternative
to
the
emissions
limit
in
Table
3
of
this
subpart,
comply
with
the
requirements
of
§
63.924
(control
level
3).
5.
New
or
existing
container
that
is
an
affected
source
{
meeting
the
capacity
limits
specified
in
Table
3,
item
8
of
this
subpart
that
is
not
vented
to
a
control
device.
As
an
alternative
to
the
emissions
limit
in
Table
3
of
this
subpart,
comply
with
the
requirements
of
§
63.923
(control
level
2).
6.
New
or
existing
surface
impoundment
that
is
an
affected
source
that
is
not
vented
to
a
control
device.
Install
a
floating
membrane
cover
designed
to
meet
specifications
in
§
63.942(
a)
through
(c).
The
membrane
must
float
on
the
surface
at
all
times
during
normal
operations.
7.
New
or
existing
surface
impoundment
that
is
an
affected
source
that
is
vented
through
a
closed
vent
system
to
a
control
device.
a.
Install
a
cover
meeting
the
requirements
in
§
63.943(
b)
and
(c);
and
b.
Design
and
operate
the
closed
vent
system
in
accordance
with
the
requirements
of
§
63.693.
8.
New
and
existing
oil/
water
separator,
or
organic/
water
separator
that
is
an
affected
source
that
is
not
vented
to
a
control
device.
Follow
the
requirements
of
§§
63.1042
(fixed
roof),
63.1043
(floating
roof),
or
63.1045
(pressurized
roof),
as
appropriate.
9.
New
and
existing
oil/
water
separator,
or
organic/
water
separator
that
is
an
affected
source
that
is
vented
through
a
closed
vent
system
to
a
control
device.
a.
Follow
the
requirements
of
§
63.1044;
and
b.
design
and
operate
the
closed
vent
system
in
accordance
with
the
requirements
of
§
63.693.
10.
New
and
existing
equipment
component
that
is
an
affected
source
Comply
with
the
requirements
of
subpart
TT
(control
level
1);
or
subpart
WW
(control
level
2).
11.
New
and
existing
transfer
system
that
is
an
affected
source
............
a.
For
individual
drain
systems,
as
defined
in
this
subpart,
comply
with
the
requirements
of
subpart
RR;
and
b.
For
transfer
systems,
other
than
individual
drain
systems,
comply
with
the
requirements
of
§
63.689(
c).
As
stated
in
§§
63.7911(
a),
63.7912(
b)
and
(c),
63.7914(
b),
and
63.7930(
e)(
2),
you
must
conduct
the
performance
testing
required
in
the
following
table
at
any
time
the
EPA
requires
for
non
flare
control
devices
in
accordance
with
section
114
of
the
CAA:
TABLE
6
TO
SUBPART
GGGGG
OF
PART
63.—
REQUIREMENTS
FOR
PERFORMANCE
TESTS
For
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.
1.
New
and
existing
affected
source
process
vents,
tanks,
containers,
surface
impoundments,
oil/
water
separators,
and
organic/
water
separators
complying
with
a
HAP
or
TOC
reduction
efficiency
limit
in
Table
2
or
3
of
this
subpart,
an
emissions
rate
limit
in
Table
2
of
this
subpart,
or
an
emissions
concentration
limit
in
Table
3
of
this
subpart.
Select
sampling
port
locations
and
the
number
of
traverse
points.
Method
1
or
1A
of
40
CFR
part
60,
appendix
A
of
§
63.7(
d)(
1)(
i).
Sampling
sites
must
be
located
at
the
inlet
(if
emissions
reduction
or
destruction
efficiency
testing
is
required)
and
outlet
of
the
control
device
and
prior
to
any
releases
to
the
atmosphere
2.
New
and
existing
affected
source
process
vents,
tanks,
containers,
surface
impoundments,
oil/
water
separators,
and
organic/
water
separators
complying
with
a
HAP
or
TOC
reduction
efficiency
limit
in
Table
2
or
3
of
this
subpart
or
an
emissions
rate
limit
in
Table
2
of
this
subpart.
Determine
velocity
and
volumetric
flow
rate.
Method
2,
2A,
2C,
2D,
2F,
or
2G
of
appendix
A
to
part
60
of
this
chapter.
For
HAP
or
TOC
reduction
efficiency
or
emissions
rate
testing;
not
necessary
for
determining
compliance
with
20
ppmv
concentration
limit.
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
6
TO
SUBPART
GGGGG
OF
PART
63.—
REQUIREMENTS
FOR
PERFORMANCE
TESTS—
Continued
For
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.
3.
New
and
existing
affected
source
process
vents,
tanks,
containers,
surface
impoundments,
oil/
water
separators,
complying
with
a
HAP
or
TOC
reduction
efficiency
limit
in
Table
2
or
3
of
this
subpart
or
an
emissions
rate
limit
in
Table
2
of
this
subpart.
Conduct
gas
molecular
weight
analysis.
Method
3,
3A,
or
3B
in
appendix
A
to
part
60
of
this
chapter.
For
flow
rate
determination
only.
4.
New
and
existing
affected
source
process
vents,
tanks,
containers,
surface
impoundments,
oil/
water
separators,
and
organic/
water
separators
complying
with
an
emissions
concentration
limit
in
Table
3
of
this
subpart.
Measure
O2
concentration
Method
3A
or
3B
in
appendix
A
to
part
60
of
this
chapter.
For
correcting
HAP
and
TOC
concentrations
measured
from
combustion
control
device
to
3%
O2
for
comparing
to
20
ppmv
concentration
limit.
See
§
63.7912(
f)(
4).
5.
New
and
existing
affected
source
process
vents,
tanks,
containers,
surface
impoundments,
oil/
water
separators,
and
organic/
water
separators
complying
with
a
HAP
or
TOC
reduction
efficiency
limit
in
Table
2
or
3
of
this
subpart,
an
emissions
rate
limit
in
Table
2
of
this
subpart,
or
an
emissions
concentration
limit
in
Table
3
of
this
subpart.
Measure
moisture
content
of
the
stack
gas.
Method
4
in
appendix
A
to
part
60
of
this
chapter.
For
flow
rate
determination
and
correction
to
dry
basis.
6.
New
and
existing
affected
source
process
vents,
tanks,
containers,
surface
impoundments,
oil/
water
separators,
and
organic
water
separators
complying
with
a
HAP
or
TOC
reduction
efficiency
limit
in
Table
2
or
3
of
this
subpart.
a.
Measure
organic
HAP
concentration
at
inlet
and
outlet
locations.
b.
Measure
TOC
concentration
at
inlet
and
outlet
locations.
i.
Method
18
in
appendix
A
to
part
60
of
this
chapter.
i.
Method
18
or
Method
25A
or
Method
25
in
appendix
A
to
part
60
of
this
chapter.
(1)
The
organic
HAP
used
for
the
calibration
gas
for
Method
25A
must
be
the
single
organic
HAP
representing
the
largest
percent
by
volume
of
emissions
and
(2)
during
the
performance
test
or
a
design
evaluation
you
must
establish
the
operating
parameter
limits
within
which
total
organic
HAP
emissions
are
reduced
by
95
weight
percent
(or
to
the
level
necessary
to
meet
the
emissions
rate
limits
in
Table
2
of
this
subpart
or
to
20
ppmv
exhaust
concentration.
7.
All
affected
source
process
vents
associated
with
remediation
activities
complying
with
the
emissions
rate
limit
in
item
(1)(
b)
of
Table
2
of
this
subpart.
Measure
organic
HAP
at
the
outlet
location.
Method
18
in
appendix
A
to
part
60
of
this
chapter.
8.
New
and
existing
affected
source
tanks,
containers,
surface
impoundments,
oil/
water
separators,
and
organic
water
separators
complying
with
a
HAP
or
TOC
emissions
concentration
limit
in
Table
3
of
this
subpart.
a.
Measure
organic
HAP
at
the
outlet
location.
b.
Measure
TOC
at
the
outlet
location.
i.
Method
18
in
appendix
A
to
part
60
of
this
chapter.
i.
Method
18
in
appendix
A
to
part
60
of
this
chapter,
or.
ii.
Method
25A
in
appendix
A
to
part
60
of
this
chapter
Use
the
following
table
to
determine
if
you
have
demonstrated
initial
compliance
for
each
affected
source
in
Table
2
or
3
of
this
subpart
and
for
process
vents
in
Table
2
of
this
subpart:
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
7
TO
SUBPART
GGGGG
OF
PART
63.—
INITIAL
COMPLIANCE
WITH
EMISSIONS
LIMITATIONS
For
.
.
.
For
the
following
emissions
limitation
.
.
.
You
have
demonstrated
initial
compliance
if
...
1.
Each
affected
source
listed
in
Table
2
or
3
of
this
subpart.
Reduce
total
organic
HAP,
listed
in
Table
1
of
this
subpart,
or
TOC
emissions
by
at
least
95
weight
percent.
Total
organic
HAP,
listed
in
Table
1
of
this
subpart,
or
TOC
emissions,
based
on
the
results
of
the
performance
testing
specified
in
Table
6
of
this
subpart,
are
reduced
by
at
least
95
weight
percent;
and
you
have
a
record
of
the
operating
requirement(
s)
listed
in
Table
4
of
this
subpart
for
the
process
unit
over
the
performance
test
during
which
emissions
did
not
exceed
95
weight
percent.
2.
Each
affected
source
listed
in
Table
3
of
this
subpart.
Limit
emissions
of
total
HAP,
listed
in
Table
1
of
this
subpart,
or
TOC
concentration
to
20
ppmv.
The
average
total
HAP,
listed
in
Table
1
of
this
subpart,
or
TOC
emissions,
measured
using
the
methods
in
Table
6
of
this
subpart
over
the
3
hour
initial
performance
test,
do
not
exceed
20
ppmv;
and
you
have
a
record
of
the
operating
requirement(
s)
listed
in
Table
4
of
this
subpart
for
the
process
unit
over
the
performance
test
during
which
emissions
did
not
exceed
20
ppmv.
3.
Affected
source
process
vents
listed
in
Table
2
of
this
subpart.
Reduce
total
HAP,
listed
in
Table
1
of
this
subpart,
or
TOC
emissions
below
1.4
kg/
h
(3.0
lb/
hr)
and
2.8
Mg/
yr
(3.1
ton/
yr).
The
average
total
HAP,
listed
in
Table
1
of
this
subpart,
or
TOC
emissions,
measured
using
the
methods
in
Table
6
of
this
subpart
over
the
3
hour
initial
performance
test,
do
not
exceed
1.4
kg/
h
(3.0
lb/
hr);
and
you
have
a
record
of
the
operating
requirement
s)
listed
in
Table
4
of
this
subpart
for
the
process
unit(
s)
over
the
performance
test
during
which
emissions
did
not
exceed
1.4
kg/
h
(3.0
lb/
hr).
Use
the
following
table
to
determine
if
you
have
demonstrated
initial
compliance
for
tanks;
containers;
surface
impoundments;
oil/
water
separators
or
organic/
water
separators;
equipment;
closed
vent
systems;
and
transfer
systems:
TABLE
8
TO
SUBPART
GGGGG
OF
PART
63.—
INITIAL
COMPLIANCE
WITH
WORK
PRACTICE
STANDARDS
For
each
*
*
*
For
the
following
work
practice
standard
*
*
*
You
have
demonstrated
initial
compliance
if
***
1.
Tank
complying
with
the
requirements
of
subpart
OO
(control
level
1)
of
this
part.
Install
a
fixed
roof
designed
and
operated
in
accordance
with
§
63.902.
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
installed
a
fixed
roof
that
meets
the
specifications
in
§
63.902,
you
have
performed
the
initial
inspection
following
installation
of
the
roof
in
accordance
with
§
63.906,
and
you
have
a
record
documenting
the
roof
design
and
inspection
results
2.
Tank
complying
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
Operate
a
fixed
roof
tank
with
an
internal
floating
roof
(IFR)
in
accordance
with
§
63.685(
e).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
installed
an
IFR
that
meets
the
applicable
specifications
in
§
63.685(
e),
you
have
performed
the
initial
inspection
following
installation
of
the
IFR
in
accordance
with
§
63.695(
b)(
1),
and
you
have
a
record
documenting
the
IFR
design
and
inspection
results.
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
8
TO
SUBPART
GGGGG
OF
PART
63.—
INITIAL
COMPLIANCE
WITH
WORK
PRACTICE
STANDARDS—
Continued
For
each
*
*
*
For
the
following
work
practice
standard
*
*
*
You
have
demonstrated
initial
compliance
if
***
3.
Tank
complying
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
Install
an
external
floating
roof
(EFR)
designed
and
operated
in
accordance
with
§
63.685(
f).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
installed
an
EFR
that
meets
the
specifications
in
§
63.685(
f),
you
have
performed
the
initial
inspection
following
installation
of
the
EFR
in
accordance
with
§
63.695(
b)(
2)(
i),
and
you
have
a
record
documenting
the
EFR
design
and
inspection
results.
4.
Tank
complying
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
Vent
the
tank
to
a
control
device
in
accordance
with
§
63.685(
g).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
installed
a
fixed
roof
that
meets
the
applicable
specifications
in
§
63.685(
g)(
1)
and
(b),
you
have
performed
the
initial
inspection
following
installation
of
the
fixed
roof
in
accordance
with
§
63.695(
b)(
3),
and
you
have
a
record
documenting
the
fixed
roof
design
and
inspection
results.
5.
Tank
complying
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
Use
a
pressure
tank
designed
and
operated
in
accordance
with
§
63.685(
h).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
designed
a
pressure
tank
meeting
the
applicable
specifications
in
§
63.685(
h),
and
you
have
a
record
documenting
the
tank
design.
6.
Tank
complying
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
A
tank
located
inside
an
enclosure
in
accordance
with
§
63.685(
i).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
the
enclosure
meets
the
applicable
specifications
in
§
63.685(
i),
you
have
performed
the
initial
inspection
in
accordance
with
§
63.685(
i)(
1),
and
you
have
a
record
documenting
the
enclosure
design
and
inspection
results.
7.
Container
complying
with
§
63.922
(level
1
controls).
Install
a
cover
meeting
the
requirements
of
§
63.922
whenever
remediation
material
is
in
the
container.
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
the
cover
meets
§
63.922
and
you
have
visually
inspected
the
container
and
its
cover
and
closure
devices
for
visible
cracks,
holes,
gaps,
or
other
open
spaces
within
24
hours
after
the
material
is
placed
in
the
container
and
maintain
a
record
of
the
inspection
8.
Container
complying
with
§
63.923
(level
2
controls).
Install
a
cover
meeting
the
requirements
of
§
63.923
and
be
installed
whenever
remediation
material
is
in
the
container.
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
the
cover
meets
§
63.923
and
you
have
visually
inspected
the
container
and
its
cover
and
closure
devices
for
visible
cracks,
holes,
gaps,
or
other
open
spaces
within
24
hours
after
the
material
is
placed
in
the
container
and
maintain
a
record
of
the
inspection
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
8
TO
SUBPART
GGGGG
OF
PART
63.—
INITIAL
COMPLIANCE
WITH
WORK
PRACTICE
STANDARDS—
Continued
For
each
*
*
*
For
the
following
work
practice
standard
*
*
*
You
have
demonstrated
initial
compliance
if
***
9.
Container
complying
with
§
63.924
(level
3
controls).
Vent
the
container
through
a
closed
vent
system
(CVS)
to
a
control
device
according
to
the
specifications
of
§
63.924(
b).
You
have
met
the
work
practice
standard,
and
for
containers
vented
inside
an
enclosure,
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that,
you
meet
the
requirements
of
§
63.924(
c)(
1).
Note:
see
item
number
17
of
this
table
for
work
practice
requirements
for
closed
vent
systems.
10.
Surface
impoundment
subject
to
§
63.940
that
is
not
vented
to
a
control
device.
Install
a
floating
membrane
cover
designed
in
accordance
with
specifications
in
§
63.942(
a)
through
(c).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
installed
a
floating
membrane
cover
the
meets
the
specifications
in
§
63.942(
b),
you
have
performed
the
initial
inspection
following
installation
of
the
cover
in
accordance
with
§
63.946(
a)(
2),
and
you
have
a
record
documenting
the
cover
design
and
inspection
results.
11.
Surface
impoundment
subject
to
§
63.940
that
is
vented
to
a
control
device.
Install
a
cover
designed
in
accordance
with
specifications
in
§
63.943(
b).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
installed
a
cover
the
meets
the
specifications
in
§
63.943(
b),
you
have
performed
the
initial
inspection
following
installation
of
the
cover
as
required
by
§
63.946(
b)(
1)(
ii),
and
you
have
a
record
documenting
the
cover
design
and
inspection
results.
12.
Oil/
water
separator,
or
organic/
water
separator
complying
with
§
63.1042.
Install
a
fixed
roof
designed
in
accordance
with
the
specifications
in
§
63.1042(
b).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
installed
a
fixed
roof
that
meets
the
specifications
in
§
63.1042(
b),
you
have
performed
the
initial
inspection
following
installation
of
the
fixed
roof
as
required
by
§
63.1047(
a),
and
you
have
a
record
documenting
the
fixed
roof
design
and
inspection
results.
13.
Oil/
water
separator,
or
organic/
water
separator
complying
with
§
63.1043.
Install
a
floating
roof
designed
in
accordance
with
the
specifications
in
§
63.1043(
b).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
installed
a
floating
roof
that
meets
the
specifications
in
§
63.1043(
b),
you
have
performed
the
initial
inspection
following
installation
of
the
floating
roof
as
required
by
§
63.1047(
b),
and
you
have
a
record
documenting
the
floating
design
and
inspection
results.
14.
Oil/
water
separator,
or
organic/
water
separator
complying
with
§
63.1044.
Install
a
fixed
roof
designed
in
accordance
with
the
specifications
in
§
63.1044(
b)
and
vent
headspace
to
a
control
device
through
a
CVS.
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
installed
a
fixed
roof
that
meets
the
specifications
in
§
63.1044(
b),
you
have
performed
the
initial
inspection
following
installation
of
the
fixed
roof
as
required
by
§
63.1047(
c),
and
you
have
a
record
documenting
the
fixed
roof
design
and
inspection
results.
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
8
TO
SUBPART
GGGGG
OF
PART
63.—
INITIAL
COMPLIANCE
WITH
WORK
PRACTICE
STANDARDS—
Continued
For
each
*
*
*
For
the
following
work
practice
standard
*
*
*
You
have
demonstrated
initial
compliance
if
***
15.
Oil/
water
separator,
or
organic/
water
separator
that
is
complying
with
§
63.1045.
Operate
the
separator
as
a
closed
system
in
accordance
with
the
specifications
in
§
63.1045(
b).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
the
separator
operates
as
a
closed
system,
you
have
performed
the
no
detectable
organic
emissions
test
required
in
§
63.1046,
and
you
have
a
record
documenting
the
separator
design
and
inspection
results.
16.
Item
of
equipment
.......................................
Carry
out
a
leak
detection
and
repair
program
to
comply
with
the
requirements
of
subpart
TT
(control
level
1);
or
subpart
WW
(control
level
2)..
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
equipment
subject
to
the
work
practice
requirements
has
been
identified
and
you
make
available
written
specifications
for
the
leak
detection
and
repair
program
or
equivalent
control
approach.
17.
Closed
vent
system
(CVS)
conveying
emissions
to
a
control
device.
Design
and
operate
the
CVS
in
accordance
with
the
specifications
in
§
63.693.
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
CVS
meets
the
specifications
in
§
63.695(
c)
and
you
perform
the
initial
inspection
required
by
§
63.695(
c)(
1)(
i)
and
have
a
record
documenting
the
design
and
inspection
results.
18.
Transfer
system
that
is
an
individual
drain
system
complying
with
the
applicable
requirements
in
subpart
RR.
Meet
the
design
and
operating
requirements
in
§
63.962(
a).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
designed
the
applicable
controls
in
accordance
with
§
63.962(
a)
and
(b)
and
performed
the
initial
inspection
requirements
in
§
63.964(
a)(
1)(
iv)
and
have
a
record
documenting
the
design
and
inspection
results.
Systems
conveying
emissions
through
a
CVS
to
a
control
device
should
meet
the
requirements
in
item
17
of
this
table.
19.
Transfer
system
that
is
not
an
individual
drain
system
and
complies
with
the
requirements
in
§
63.689(
c).
Design
and
operate
a
transfer
system
using
covers
in
accordance
with
§
63.689(
d).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
designed
and
installed
the
covers
as
required
by
§
63.689(
d)(
1)
through
(5),
performed
the
inspection
requirements
in
§
63.695(
d)(
2)
and
have
a
record
documenting
the
design
and
inspection
results.
20.
Transfer
system
that
is
not
an
individual
drain
system
and
complies
with
the
requirements
in
§
63.689(
c).
Design
and
operate
a
transfer
system
using
hard
piping
in
accordance
with
§
63.689(
c)(
2).
You
have
met
the
work
practice
standard
and
as
part
of
the
Notification
of
Compliance
Status,
you
submit
a
signed
statement
that
you
have
installed
the
hard
piping
as
specified
in
§
63.689(
c)(
2).
Use
the
following
table
to
determine
if
you
have
demonstrated
continuous
compliance
for
each
unit
in
Table
2
or
3
of
this
subpart:
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
9
TO
SUBPART
GGGGG
OF
PART
63.—
CONTINUOUS
COMPLIANCE
WITH
EMISSIONS
LIMITATIONS
For*
*
*
For
the
following
emissions
limitation
*
*
*
You
have
demonstrated
continuous
compliance
by
*
*
*
1.
Each
unit
listed
in
Table
2
or
3
of
this
subpart
a.
Reduce
total
organic
HAP,
listed
in
Table
1
of
this
subpart,
or
TOC
emissions
by
at
least
95
weight
percent,
i.
Performing
CMS
monitoring
and
collecting
data
according
to
§§
63.7914,
63.7921,
and
63.7930;
ii.
Maintaining
the
site
specific
operating
limits
within
the
ranges
established
during
the
design
evaluation
or
performance
test;
and
iii.
Continuously
monitoring
and
recording
the
total
organic
or
HAP
concentration
at
least
every
15
minutes,
reducing
the
CEMS
data
to
1
hour
and
then
24
hour
block
averages,
and
maintaining
the
24
hour
block
average
total
organic
or
HAP
concentration
less
than
or
equal
to
the
concentration
established
during
the
performance
test;
and
iv.
Keeping
the
applicable
records
required
in
§
63.10.
2.
Each
unit
listed
in
Table
3
of
this
subpart...
Limit
emissions
of
total
HAP,
listed
in
Table
1
of
this
Subpart,
or
TOC
concentration
of
20
ppmv.
Same
as
in
item
1
of
Table
9
of
this
Subpart
3.
Each
unit
listed
in
Table
2
or
3
of
this
subpart
Limit
emissions
of
total
HAP,
listed
in
Table
1
of
this
subpart,
to
below
1.4
kg/
hr
(3.0
lb/
hr)
and
2.8
Mg/
yr
(3.1
ton/
yr).
Same
as
in
item
1
of
Table
9
of
this
subpart.
Use
the
following
table
to
determine
if
you
have
demonstrated
continuous
compliance
for
each
affected
source
unit
in
Table
2
or
3
of
this
subpart:
TABLE
10
TO
SUBPART
GGGGG
OF
PART
63.—
CONTINUOUS
COMPLIANCE
WITH
OPERATING
LIMITS
For
*
*
*
For
the
following
operating
limit
*
*
*
You
must
demonstrate
continuous
compliance
by
*
*
*
1.
Affected
source
using
a
thermal
oxidizer
to
comply
with
an
emissions
limit
in
Table
2
or
3
of
this
subpart.
a.
Maintain
the
hourly
average
firebox
temperature
greater
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test.
i.
Continuously
monitoring
and
recording
firebox
temperature
every
15
minutes
and
maintaining
the
hourly
average
firebox
temperature
greater
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
2.
Affected
source
using
a
catalytic
oxidizer
to
comply
with
an
emissions
limit
in
Table
2
or
3
of
this
subpart.
a.
Replace
the
existing
catalyst
bed
with
a
catalyst
bed
that
meets
the
replacement
specifications
established
during
the
design
evaluation
or
performance
test
before
the
age
of
the
bed
exceeds
the
maximum
allowable
age
established
during
the
design
evaluation
or
performance
test.
i.
Replacing
the
existing
catalyst
bed
with
a
catalyst
bed
that
meets
the
replacement
specifications
established
during
the
design
evaluation
or
performance
test
before
the
age
of
the
bed
exceeds
the
maximum
allowable
age
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
b.
Maintain
the
hourly
average
temperature
at
the
inlet
of
the
catalyst
bed
greater
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test.
i.
Continuously
monitoring
and
recording
the
temperature
at
the
inlet
of
the
catalyst
bed
at
least
every
15
minutes
and
maintaining
the
hourly
average
temperature
at
the
inlet
of
the
catalyst
bed
greater
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
c.
Maintain
the
hourly
average
temperature
difference
across
the
catalyst
bed
greater
than
or
equal
to
the
minimum
temperature
difference
established
during
the
design
evaluation
or
performance
test.
i.
Continuously
monitoring
and
recording
the
temperature
at
the
outlet
of
the
catalyst
bed
every
15
minutes
and
maintaining
the
hourly
average
temperature
difference
across
the
catalyst
bed
greater
than
or
equal
to
the
minimum
temperature
difference
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
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49444
Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
10
TO
SUBPART
GGGGG
OF
PART
63.—
CONTINUOUS
COMPLIANCE
WITH
OPERATING
LIMITS—
Continued
For
*
*
*
For
the
following
operating
limit
*
*
*
You
must
demonstrate
continuous
compliance
by
*
*
*
3.
Affected
source
using
a
condenser
to
comply
with
an
emissions
limit
in
Table
2
or
3
of
this
subpart.
a.
Maintain
the
hourly
average
condenser
exit
temperature
less
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test.
i.
Continuously
monitoring
and
recording
the
temperature
at
the
exit
of
the
condenser
at
least
every
15
minutes
and
maintaining
the
hourly
average
condenser
exit
temperature
less
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
4.
Affected
source
using
an
adsorption
system
with
adsorbent
regeneration
to
comply
with
an
emissions
limit
in
Table
2
or
3
of
this
subpart.
a.
Replace
the
existing
adsorbent
in
each
segment
of
the
bed
with
an
adsorbent
that
meets
the
replacement
specifications
established
during
the
design
evaluation
or
performance
test
before
the
age
of
the
adsorbent
exceeds
the
maximum
allowable
age
established
during
the
design
evaluation
or
performance
test.
i.
Replacing
the
existing
adsorbent
in
each
segment
of
the
bed
with
an
adsorbent
that
meets
the
replacement
specifications
established
during
the
design
evaluation
or
performance
test
before
the
age
of
the
adsorbent
exceeds
the
maximum
allowable
age
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
b.
Maintain
the
frequency
of
regeneration
greater
than
or
equal
to
the
frequency
established
during
the
design
evaluation
or
performance
test.
i.
Maintaining
the
frequency
of
regeneration
greater
than
or
equal
to
the
frequency
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
c.
Maintain
the
total
regeneration
stream
mass
flow
during
the
adsorption
bed
regeneration
cycle
greater
than
or
equal
to
the
stream
mass
flow
established
during
the
design
evaluation
or
performance
test.
i.
Continuously
monitoring
and
recording
the
total
regeneration
stream
mass
flow
during
the
adsorption
bed
regeneration
cycle
and
maintaining
the
flow
greater
than
or
equal
to
the
stream
mass
flow
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
d.
Maintain
the
hourly
temperature
of
the
adsorption
bed
during
regeneration
(except
during
the
cooling
cycle)
greater
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test.
i.
Continuously
monitoring
and
recording
the
hourly
temperature
of
the
adsorption
bed
during
regeneration
(except
during
the
cooling
cycle)
and
maintaining
the
hourly
temperature
greater
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
e.
Maintain
the
hourly
temperature
of
the
adsorption
bed
after
regeneration
(and
within
15
minutes
after
completing
any
cooling
cycle)
less
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test.
i.
Continuously
monitoring
and
recording
the
hourly
temperature
of
the
adsorption
bed
after
regeneration
(and
within
15
minutes
after
completing
any
cooling
cycle)
and
maintaining
the
hourly
temperature
less
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
5.
Affected
source
using
an
adsorption
system
without
adsorbent
regeneration
to
comply
with
an
emissions
limit
in
Table
2
or
3.
a.
Replace
the
existing
adsorbent
in
each
segment
of
the
bed
with
an
adsorbent
that
meets
the
replacement
specifications
established
during
the
design
evaluation
or
performance
test
before
the
age
of
the
adsorbent
exceeds
the
maximum
allowable
age
established
during
the
design
evaluation
or
performance
test.
i.
Replacing
the
existing
adsorbent
in
each
segment
of
the
bed
with
an
adsorption
that
meets
the
replacement
specifications
established
during
the
design
evaluation
or
performance
test
before
the
age
of
the
adsorbent
exceeds
the
maximum
allowable
age
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
10
TO
SUBPART
GGGGG
OF
PART
63.—
CONTINUOUS
COMPLIANCE
WITH
OPERATING
LIMITS—
Continued
For
*
*
*
For
the
following
operating
limit
*
*
*
You
must
demonstrate
continuous
compliance
by
*
*
*
b.
Maintain
the
hourly
temperature
of
the
adsorption
bed
less
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test.
i.
Continuously
monitoring
and
recording
the
hourly
temperature
of
the
adsorption
bed
and
maintaining
an
hourly
temperature
less
than
or
equal
to
the
temperature
established
during
the
design
evaluation
or
performance
test;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
6.
Affected
source
using
a
flare
to
comply
with
an
emissions
limit
in
Table
2
or
3
of
this
subpart.
a.
Maintain
a
pilot
flame
present
in
the
flare
at
all
times
that
vapors
are
not
being
vented
to
the
flare
(§
63.11(
b)(
5)).
i.
Continuously
operating
a
device
that
detects
the
presence
of
the
pilot
flame;
and
ii.
Keeping
the
applicable
records
required
in
§
63.695(
e).
b.
Maintain
a
flare
flame
at
all
times
that
vapors
are
being
vented
from
the
emissions
source
(§
63.11(
b)(
5)).
i.
Maintaining
a
flare
flame
at
all
times
that
vapors
are
being
vented
from
the
emissions;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
c.
Operate
the
flare
with
no
visible
emissions,
except
for
up
to
5
minutes
in
any
2
consecutive
hours
(§
63.11(
b)(
4)).
i.
operating
the
flare
with
no
visible
emissions
exceeding
the
amount
allowed;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10
d.
Operate
the
flare
with
an
exit
velocity
that
is
within
the
applicable
limits
in
§
63.11(
b)(
6),
(7),
and
(8).
i.
Operating
the
flare
within
the
applicable
exit
velocity
limits;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
e.
Operate
the
flare
with
a
net
heating
value
of
the
gas
being
combusted
greater
than
the
applicable
minimum
value
in
§
63.11(
b)(
6)(
ii).
i.
Operating
the
flare
with
the
gas
net
heating
value
within
the
applicable
limit;
and
ii.
Keeping
the
applicable
records
required
in
§
63.10.
Use
the
requirements
in
the
following
table
to
demonstrate
continuous
compliance
for
tanks;
containers;
surface
impoundments;
oil/
water
separators
or
organic/
water
separators;
equipment;
closed
vent
systems;
and
transfer
systems:
TABLE
11
TO
SUBPART
GGGGG
OF
PART
63.—
CONTINUOUS
COMPLIANCE
WITH
WORK
PRACTICE
STANDARDS
For
each
*
*
For
the
following
work
practice
standard
*
*
*
You
must
demonstrate
continuous
compliance
by
*
*
*
1.
Tank
complying
with
subpart
OO
(control
level
1)
of
this
part.
a.
install
a
fixed
roof
designed
and
operated
in
accordance
with
the
applicable
specifications
in
§
63.902.
i.
following
the
inspection
and
repair
procedures
in
§
63.906(
a)
and
(b);
and
ii.
keeping
the
records
required
in
§
63.907.
2.
Tank
complying
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
a.
operate
a
fixed
roof
tank
with
an
internal
floating
roof
(IFR)
in
accordance
with
§
63.685(
e).
i.
following
the
inspection
and
repair
requirements
in
§
63.695(
b)(
1)
and
(4);
and
ii.
keeping
the
records
required
in
§
63.696.
3.
Tank
complying
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
a.
install
an
external
floating
roof
(EFR)
designed
and
operated
in
accordance
with
§
63.685(
f).
i.
following
the
inspection
and
repair
requirements
in
§
63.695(
b)(
2)
and
(4);
and
ii.
keeping
the
records
required
in
§
63.696(
d).
4.
Tank
complying
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
a.
vent
the
tank
through
a
closed
vent
system
(CVS)
to
a
control
device
in
accordance
with
§
63.685(
g).
i.
following
the
inspection
and
repair
requirements
in
§
63.695(
b)(
3)
and
(4);
and
ii.
following
the
inspection
and
monitoring
requirements
for
the
CVS
in
§
63.695(
c)(
1)–
(3);
and
iii.
keeping
the
records
required
in
§
63.696(
e).
5.
Tank
complying
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
use
a
pressure
tank
designed
and
operated
in
accordance
with
§
63.685(
h).
operating
the
pressure
tank
at
all
times
in
accordance
with
the
specifications
in
§
63.685(
h).
6.
Tank
complying
with
the
requirements
of
§
63.685(
d)
(control
level
2)
of
this
part.
a.
a
tank
located
inside
an
enclosure
in
accordance
with
§
63.685(
i).
i.
meeting
the
recordkeeping
requirements
of
§
63.696(
f);
and
ii.
meeting
the
requirements
for
a
closed
vent
system
specified
in
item
19
of
this
table.
7.
Container
complying
with
§
63.922
(level
1
controls).
install
a
cover
meeting
the
requirements
of
§
63.922
whenever
remediation
material
is
in
the
container.
following
the
inspection
and
repair
requirements
in
§
63.926(
a)(
2)
and
(3).
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Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
11
TO
SUBPART
GGGGG
OF
PART
63.—
CONTINUOUS
COMPLIANCE
WITH
WORK
PRACTICE
STANDARDS—
Continued
For
each
*
*
For
the
following
work
practice
standard
*
*
*
You
must
demonstrate
continuous
compliance
by
*
*
*
8.
Container
complying
with
§
63.923
(level
2
controls).
install
a
cover
meeting
the
requirements
of
§
63.923
whenever
remediation
material
is
in
the
container.
following
the
inspection
and
repair
requirements
in
§
63.926(
c)(
2)
and
(3).
9.
Container
complying
with
§
63.924
(level
3
controls).
a.
vent
the
container
through
a
closed
vent
system
(CVS)
to
a
control
device
according
to
the
specifications
of
§
63.924(
b).
i.
following
the
inspection
and
monitoring
requirements
for
the
CVS
in
§
63.695(
c)(
1)–
(3);
and
ii.
keeping
the
records
required
in
§
63.927.
10.
Surface
impoundment
complying
with
the
applicable
requirements
in
subpart
QQ
that
is
not
vented
to
a
control
device.
install
a
floating
membrane
cover
designed
according
to
the
specifications
in
§
63.942(
a)–
(b)
and
maintain
the
membrane
floating
on
the
liquid
surface
at
all
times.
maintaining
the
membrane
floating
on
the
liquid
surface
and
visually
inspecting
the
membrane
at
least
once
every
year,
making
a
first
attempt
at
repair
of
any
defects
within
5
calendar
days
of
detection,
completing
repair
within
45
calendar
days
of
detection,
and
keeping
the
records
required
in
§
63.947(
a).
11.
Surface
impoundment
that
is
a
new
or
existing
affected
source
subject
to
subpart
QQ
that
is
vented
to
a
control
device.
install
a
cover
designed
to
meet
the
applicable
specifications
in
§
63.943(
b);
and
vent
the
emissions
through
a
closed
vent
system
(CVS)
to
a
control
device.
maintaining
a
cover
on
the
surface
impoundment
in
accordance
with
the
specifications
in
§
63.943(
c),
visually
inspecting
the
cover
in
accordance
with
§
63.946(
b),
repairing
any
defects
as
specified
in
§
63.946(
c),
and
keeping
a
record
of
the
inspection
as
required
in
§
63.947;
Note:
see
item
no.
19
in
this
Table
for
CVS
requirements.
12.
Oil/
water
separator,
or
organic/
water
separator
complying
with
§
63.1042.
install
a
fixed
roof
designed
to
meet
specifications
in
§
63.1042(
b).
performing
the
inspection
required
by
§
63.1047(
a)
once
every
calendar
year,
and
maintaining
the
records
required
by
§
63.1048.
13.
Oil/
water
separator,
or
organic/
water
separator
complying
with
§
63.1043.
install
a
floating
roof
designed
to
meet
specifications
in
§
63.1043(
b).
performing
the
inspections
required
by
§
63.1047(
b),
and
maintaining
the
records
required
by
§
63.1048.
14.
Oil/
water
separator,
or
organic/
water
separator
that
is
complying
with
§
63.1044.
install
a
fixed
roof
designed
to
meet
the
specifications
in
§
63.1044(
b)
and
vent
headspace
to
a
control
device
through
a
CVS.
performing
a
visual
inspection
of
the
fixed
roof
at
least
once
every
calendar
year
under
§
63.1047(
c)(
1)(
ii),
operating,
inspecting
and
monitoring
the
CVS
in
accordance
with
the
requirements
in
§
63.693,
and
keeping
the
records
required
by
§
63.1048.
15.
Oil/
water
separator,
or
organic/
water
separator
that
is
complying
with
§
63.1045.
operate
the
separator
as
a
closed
system
in
accordance
with
the
specifications
in
§
63.1045(
b).
operating
the
separator
as
a
closed
system
and
performing
the
no
detectable
organic
emissions
test
required
by
§
63.1046.
16.
Piece
of
equipment
complying
with
either
subpart
TT
or
WW
of
this
part.
carry
out
a
leak
detection
and
repair
program
complying
with
the
requirements
of
subpart
TT
(control
level
1)
or
subpart
WW
(control
level
2).
meeting
the
monitoring,
repair
and
recordkeeping
requirements
of
either
subpart
TT
or
subpart
WW.
17.
Affected
source
conveying
emissions
to
a
control
device
using
a
closed
vent
system
(CVS).
a.
design
and
operate
the
CVS
in
accordance
with
the
specifications
in
§
63.693.
i.
following
the
inspection,
repair
and
monitoring
requirements
in
§
63.695(
c)(
1)
through
(3);
and
ii.
keeping
the
records
required
by
§
63.696(
a).
For
the
purposes
of
this
subpart,
the
term
``
Table
2
of
this
subpart''
in
40
CFR
Part
63
Subpart
DD
means
``
Table
13''.
18.
Transfer
system
that
is
an
individual
drain
system
complying
with
the
applicable
requirements
in
subpart
RR.
a.
meet
the
design
and
operating
requirements
in
§
63.962(
a).
i.
following
the
operating
requirements
in
§
63.962(
b),
the
inspection
and
repair
requirements
in
§
63.964(
a)
and
(b);
and
ii.
keeping
the
records
required
by
§
63.965(
a).
iii.
systems
conveying
emissions
through
a
CVS
to
a
control
device
should
meet
the
requirements
in
item
19
of
this
table.
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PsN:
30JYP2
49447
Federal
Register
/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
11
TO
SUBPART
GGGGG
OF
PART
63.—
CONTINUOUS
COMPLIANCE
WITH
WORK
PRACTICE
STANDARDS—
Continued
For
each
*
*
For
the
following
work
practice
standard
*
*
*
You
must
demonstrate
continuous
compliance
by
*
*
*
19.
Transfer
system
that
is
not
an
individual
drain
system
and
complies
with
the
requirements
in
§
63.689(
c).
a.
transfer
system
using
covers
in
accordance
with
§
63.689(
d).
i.
following
the
operating
requirements
in
§
63.689(
d)(
5)
and
the
inspection
and
repair
requirements
in
§
63.695(
d);
and
ii.
keeping
the
records
required
by
§
63.696.
Use
the
following
table
to
determine
which
reports
to
submit:
TABLE
12
TO
SUBPART
GGGGG
OF
PART
63.—
REQUIREMENTS
FOR
REPORTS
You
must
submit
a(
n)
*
*
*
The
report
must
contain
*
*
*
You
must
submit
the
report
*
*
*
1.
Compliance
report
........................................
a.
A
statement
that
there
were
no
deviations
from
the
emissions
limitations
and
work
practice
standards
during
the
reporting
period
if
there
are
no
deviations
from
any
emissions
limitations
(emissions
limit,
operating
limit,
opacity
limit,
and
visible
emissions
limit)
that
applies
to
you,
and
there
are
no
deviations
from
the
requirements
for
work
practice
standards
in
Table
11
of
this
subpart
that
apply
to
you.
If
there
were
no
periods
during
which
the
CMS,
including
CEMS,
COMS,
and
operating
parameter
monitoring
systems,
was
out
of
control
as
specified
in
§
63.8(
c)(
7),
a
statement
that
there
were
no
periods
during
the
which
the
CMS
was
out
of
control
during
the
reporting
period;
and.
i.
Semiannually
according
to
the
requirements
in
§
63.7931(
b).
b.
The
information
in
§
63.7931(
c)
and
(d)
if
you
have
a
deviation
from
any
emissions
limitation
(emissions
limit,
operating
limit,
opacity
limit,
and
visible
emissions
limit)
or
work
practice
standard
during
the
reporting
period;
and.
i.
Semiannually
according
to
the
requirements
in
§
63.7931(
b).
c.
The
information
in
§
63.7931(
c)
and
(d)
if
there
were
periods.
i.
Semiannually
according
to
the
requirements
in
§
63.7931(
b).
2.
immediate
startup,
shutup,
shutdown,
and
malfunction
report
if
you
had
a
startup,
shutdown
or
malfunction
during
the
reporting
period
that
is
not
consistent
with
your
startup
shutdown,
and
malfunction
plan.
a.
Actions
taken
for
the
event
..........................
i.
by
fax
or
telephone
within
2
working
days
after
starting
actions
inconsistent
with
the
plan.
b.
The
information
in
§
63.10(
d)(
5)(
ii)
...............
i.
by
letter
within
7
working
days
after
the
end
of
the
event
unless
you
have
made
alternative
arrangements
with
the
permitting
authority
As
stated
in
§
63.7940,
you
must
comply
with
the
applicable
General
Provisions
requirements
according
to
the
following
table:
TABLE
13
TO
SUBPART
GGGGG
OF
PART
63.—
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
GGGGG
Citation
Subject
Brief
description
Applies
to
subpart
GGGGG
§
63.1
.......................................
Applicability
.............................
Initial
Applicability
Determination;
Applicability
After
Standard
Established;
Permit
Requirements;
Extensions,
Notifications
Yes
§
63.2
.......................................
Definitions
...............................
Definitions
for
part
63
standards
..............................................
Yes.
§
63.3
.......................................
Units
and
Abbreviations
.........
Units
and
abbreviations
for
part
63
standards
........................
Yes.
§
63.4
.......................................
Prohibited
Activities
................
Prohibited
Activities;
Compliance
date;
Circumvention,
Severability
Yes.
§
63.5
.......................................
Construction/
Reconstruction
...
Applicability;
applications;
approvals
.......................................
Yes.
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Vol.
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No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
13
TO
SUBPART
GGGGG
OF
PART
63.—
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
GGGGG—
Continued
Citation
Subject
Brief
description
Applies
to
subpart
GGGGG
§
63.6(
a)
..................................
Applicability
.............................
GP
apply
unless
compliance
extension
GP
apply
to
area
sources
that
become
major.
Yes.
§
63.6(
b)(
1)–(
4)
........................
Compliance
Dates
for
New
and
Reconstructed
sources.
Standards
apply
at
effective
date;
3
years
after
effective
date;
upon
startup;
10
years
after
construction
or
reconstruction
commences
for
112(
f).
Yes.
§
63.6(
b)(
5)
..............................
Notification
..............................
Must
notify
if
commenced
construction
or
reconstruction
after
proposal.
Yes.
§
63.6(
b)(
6)
..............................
[Reserved]
..............................
.
§
63.6(
b)(
7)
..............................
Compliance
Dates
for
New
and
Reconstructed
Area
Sources
That
Become
Major.
Area
sources
that
become
major
must
comply
with
major
source
standards
immediately
upon
becoming
major,
regardless
of
whether
required
to
comply
when
they
were
an
area
source.
Yes.
§
63.6(
c)(
1)–(
2)
........................
1.
Compliance
Dates
for
Existing
Sources.
a.
Comply
according
to
date
in
subpart,
which
must
be
no
later
than
3
years
after
effective
date.
.................................................
b.
For
112(
f)
standards,
comply
within
90
days
of
effective
date
unless
compliance
extension.
Yes.
§
63.6(
c)(
3)–(
4)
........................
[Reserved]
..............................
.
§
63.6(
c)(
5)
..............................
Compliance
Dates
for
Existing
Area
Sources
That
Become
Major.
Area
sources
that
become
major
must
comply
with
major
source
standards
by
date
indicated
in
subpart
or
by
equivalent
time
period
(for
example,
3
years).
Yes.
§
63.6(
d)
..................................
[Reserved]
..............................
.
§
63.6(
e)(
1)–(
2)
........................
1.
Operation
&
Maintenance
..
a.
Operate
to
minimize
emissions
at
all
times
.........................
Yes.
b.
Correct
malfunctions
as
soon
as
practicable
......................
Yes.
c.
Operation
and
maintenance
requirements
independently
enforceable;
information
Administrator
will
use
to
determine
if
operation
and
maintenance
requirements
were
met.
Yes.
§
63.6(
e)(
3)
..............................
1.
Startup,
Shutdown,
and
malfunction
Plan
(SSMP).
a.
Requirement
for
SSM
and
startup,
shutdown,
and
Malfunction
plan.
Yes
b.
Content
of
SSMP
.................................................................
Yes.
§
63.6(
f)(
1)
...............................
Compliance
Except
During
SSM.
You
must
comply
with
emissions
standards
at
all
times
except
during
SSM.
Yes.
§
63.6(
f)(
2)–(
3)
.........................
Methods
for
Determining
Compliance.
Compliance
based
on
performance
test,
operation
and
maintenance
plans,
records,
inspection.
Yes.
§
63.6(
g)(
1)–(
3)
........................
Alternative
Standard
...............
Procedures
for
getting
an
alternative
standard
.......................
Yes.
§
63.6(
h)
..................................
Opacity/
Visible
Emissions
(VE)
Standards.
Requirements
for
opacity
and
visible
emissions
limits
............
Yes.
However,
there
are
no
opacity
standards.
§
63.6(
h)(
1)
..............................
Compliance
with
opacity/
VE
Standards.
You
must
comply
with
Opacity/
VE
emissions
limitations
at
all
times
except
during
SSM.
Yes.
However,
there
are
no
opacity
standards.
§
63.6(
h)(
2)(
i)
...........................
Determining
Compliance
with
Opacity/
VE
Standards.
If
standard
does
not
state
test
method,
use
Method
9
for
opacity
and
Method
22
for
VE.
Yes.
However,
there
are
no
opacity
standards.
§
63.6(
h)(
2)(
ii)
..........................
[Reserved].
§
63.6(
h)(
2)(
iii)
.........................
Using
Previous
Tests
to
Demonstrate
Compliance
with
Opacity/
VE
Standards.
Criteria
for
when
previous
opacity/
VE
testing
can
be
used
to
show
compliance
with
this
rule.
Yes.
However,
there
are
no
opacity
standards.
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
13
TO
SUBPART
GGGGG
OF
PART
63.—
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
GGGGG—
Continued
Citation
Subject
Brief
description
Applies
to
subpart
GGGGG
§
63.6(
h)(
3)
..............................
[Reserved].
§
63.6(
h)(
4)
..............................
Notification
of
Opacity/
VE
Observation
Date.
Must
notify
Administrator
of
anticipated
date
of
observation
..
Yes.
However,
there
are
no
opacity
standards.
§
63.6(
h)(
5)(
i),
(iii)(
v)
..............
Conducting
Opacity/
VE
Observations
Dates
and
Schedule
for
conducting
opacity/
VE
observations
Yes.
However,
there
are
no
opacity
standards.
§
63.6(
h)(
5)(
ii)
..........................
Opacity
Test
Duration
and
Averaging
Times.
Must
have
at
least
3
hours
of
observation
with
thirty,
6
minute
averages.
No.
§
63.6(
h)(
6)
..............................
Records
of
Conditions
During
Opacity/
VE
observations.
Must
keep
records
available
and
allow
Administrator
to
inspect
Yes.
However,
there
are
no
opacity
standards.
§
63.6(
h)(
7)(
i)
...........................
Report
COMS
Monitoring
Data
from
Performance
Test.
Must
submit
COMS
data
with
other
performance
test
data
....
No.
§
63.6(
h)(
7)(
ii)
..........................
Using
COMS
instead
of
Method
9.
Can
submit
COMS
data
instead
of
Method
9
results
even
if
rule
requires
Method
9,
but
must
notify
Administrator
before
performance
test.
No.
§
63.6(
h)(
7)(
iii)
.........................
Averaging
time
for
COMS
during
performance
test.
To
determine
compliance,
must
reduce
COMS
data
to
6
minute
averages.
No.
§
63.6(
h)(
7)(
iv)
.........................
COMS
requirements
...............
Owner/
operator
must
demonstrate
that
COMS
performance
evaluations
are
conducted
according
to
§§
63.8(
e),
COMS
are
properly
maintained
and
operated
according
to
63.8(
c)
and
data
quality
as
§
63.8(
d).
No.
§
63.6(
h)(
7)(
v)
..........................
Determining
Compliance
with
Opacity/
VE
Standards.
COMS
is
probative
but
not
conclusive
evidence
of
compliance
with
opacity
standard,
even
if
Method
9
observation
shows
otherwise.
Requirements
for
COMS
to
be
probative
evidence
proper
maintenance,
meeting
PS
1,
and
data
have
not
been
altered.
Yes.
However,
there
are
no
opacity
standards.
§
63.6(
h)(
8)
..............................
Determining
Compliance
with
Opacity/
VE
Standards.
Administrator
will
use
all
COMS,
Method
9,
and
Method
22
results,
as
well
as
information
about
operation
and
maintenance
to
determine
compliance.
Yes.
However,
there
are
no
opacity
standards.
§
63.6(
h)(
9)
..............................
Adjusted
Opacity
Standard
.....
Procedures
for
Administrator
to
adjust
an
opacity
standard
...
No.
§
63.6(
i)(
1)–(
14)
.......................
Compliance
Extension
............
Procedures
and
criteria
for
Administrator
to
grant
compliance
extension.
Yes.
§
63.6(
j)
...................................
Presidential
Compliance
Exemption
President
may
exempt
source
category
from
requirement
to
comply
with
rule.
Yes.
§
63.7(
a)(
1)–(
2)
........................
Performance
Test
Dates
........
Dates
for
Conducting
Initial
Performance
Testing
and
Other
Compliance
Demonstrations.
Must
conduct
180
days
after
first
subject
to
rule.
Yes.
§
63.7(
a)(
3)
..............................
Section
114
Authority
.............
Administrator
may
require
a
performance
test
under
CAA
Section
114
at
any
time.
Yes.
§
63.7(
b)(
1)
..............................
Notification
of
Performance
Test.
Must
notify
Administrator
60
days
before
the
test
...................
Yes.
§
63.7(
b)(
2)
..............................
Notification
of
Rescheduling
...
If
rescheduling
a
performance
test
is
necessary,
must
notify
Administrator
5
days
before
scheduled
date
of
rescheduled
date.
Yes.
§
63.7(
c)
..................................
1.
Quality
Assurance/
Test
Plan.
a.
Requirement
to
submit
site
specific
test
plan
60
days
before
the
test
or
on
date
Administrator
agrees
with:.
Yes.
i.
Test
plan
approval
procedures
.............................................
Yes.
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
13
TO
SUBPART
GGGGG
OF
PART
63.—
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
GGGGG—
Continued
Citation
Subject
Brief
description
Applies
to
subpart
GGGGG
ii.
Performance
audit
requirements
..........................................
Yes.
iii.
Internal
and
External
QA
procedures
for
testing
................
Yes.
§
63.7(
d)
..................................
Testing
Facilities
.....................
Requirements
for
testing
facilities
............................................
Yes.
§
63.7(
e)(
1)
..............................
Conditions
for
Conducting
Performance
Tests.
Performance
tests
must
be
conducted
under
representative
conditions.
Cannot
conduct
performance
tests
during
SSM.
Not
a
violation
to
exceed
standard
during
SSM.
Yes.
§
63.7(
e)(
2)
..............................
Conditions
for
Conducting
Performance
Tests.
Must
conduct
according
to
rule
and
EPA
test
methods
unless
Administrator
approves
alternative.
Yes.
§
63.7(
e)(
3)
..............................
1.
Test
Run
Duration
..............
a.
Must
have
three
test
runs
of
at
least
one
hour
each
..........
Yes.
b.
Complaince
is
based
on
arithmetic
mean
of
three
runs
.....
Yes.
c.
Conditions
when
data
from
an
additional
test
run
can
be
used.
Yes.
§
63.7(
f)
...................................
Alternative
Test
Method
.........
Procedures
by
which
Administrator
can
grant
approval
to
use
an
alternative
test
method.
Yes.
§
63.7(
g)
..................................
1.
Performance
Test
Data
Analysis.
a.
Must
include
raw
data
in
performance
test
report
...............
Yes.
b.
Must
submit
performance
test
data
60
days
after
end
of
test
with
the
Notification
of
Compliance
Status.
Yes.
c.
Keep
data
for
5
years
..........................................................
Yes.
§
63.7(
h)
..................................
Waiver
of
Tests
......................
Procedures
for
Administrator
to
waive
performance
test
........
Yes.
§
63.8(
a)(
1)
..............................
Applicability
of
Monitoring
Requirements
Subject
to
all
monitoring
requirements
in
standard
.................
Yes.
§
63.8(
a)(
2)
..............................
Performance
Specifications
....
Performance
Specifications
in
appendix
B
of
part
60
apply
...
Yes.
§
63.8(
a)(
3)
..............................
[Reserved].
§
63.8(
a)(
4)
..............................
Monitoring
with
Flares
............
Unless
your
rule
says
otherwise,
the
requirements
for
flares
in
63.11
apply.
Yes.
§
63.8(
b)(
1)
..............................
Monitoring
...............................
Must
conduct
monitoring
according
to
standard
unless
Administrator
approves
alternative.
Yes.
§
63.8(
b)(
2)–(
3)
........................
1.
Multiple
Effluents
and
Multiple
Monitoring
Systems.
a.
Specific
requirements
for
installing
monitoring
systems
.....
Yes.
b.
Must
install
on
each
effluent
before
it
is
combined
and
before
it
is
released
to
the
atmosphere
unless
Administrator
approves
otherwise.
Yes.
c.
If
more
than
one
monitoring
system
on
an
emissions
point,
must
report
all
monitoring
system
results,
unless
one
monitoring
system
is
a
backup.
Yes.
§
63.8(
c)(
1)
..............................
Monitoring
System
Operation
and
Maintenance.
Maintain
monitoring
system
in
a
manner
consistent
with
good
air
pollution
control
practices.
Yes.
§
63.8(
c)(
1)(
i)
...........................
Routine
and
Predictable
SSM
Follow
the
SSM
plan
for
routine
repairs.
Keep
parts
for
routine
repairs
readily
available.
Reporting
requirements
for
SSM
when
action
is
described
in
SSM
plan.
Yes.
§
63.8(
c)(
1)(
ii)
..........................
SSM
not
in
SSMP
..................
Reporting
requirements
for
SSM
when
action
is
not
described
in
SSM
plan.
Yes.
§
63.8(
c)(
1)(
iii)
.........................
1.
Compliance
with
Operation
and
Maintenance
Requirements
a.
How
Administrator
determines
if
source
complying
with
operation
and
maintenance
requirements.
Yes.
b.
Review
of
source
O&
M
procedures,
records,
Manufacturer's
instructions,
recommendations,
and
inspection
of
monitoring
system.
Yes.
§
63.8(
c)(
2)–(
3)
........................
1.
Monitoring
System
Installation
a.
Must
install
to
get
representative
emissions
and
parameter
measurements.
Yes.
b.
Must
verify
operational
status
before
or
at
performance
test.
Yes.
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
13
TO
SUBPART
GGGGG
OF
PART
63.—
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
GGGGG—
Continued
Citation
Subject
Brief
description
Applies
to
subpart
GGGGG
§
63.8(
c)(
4)
..............................
Continuous
Monitoring
System
(CMS)
Requirements.
CMS
must
be
operating
except
during
breakdown,
out
ofcontrol
repair,
maintenance,
and
high
level
calibration
drifts.
No.
§
63.8(
c)(
4)(
i)–(
ii)
.....................
Continuous
Monitoring
System
(CMS)
Requirements.
COMS
must
have
a
minimum
of
one
cycle
of
sampling
and
analysis
for
each
successive
10
second
period
and
one
cycle
of
data
recording
for
each
successive
6
minute
period
CEMS
must
have
a
minimum
of
one
cycle
of
operation
for
each
successive
15
minute
period.
Yes.
However,
COMS
are
not
applicable
Requirements
for
CPMS
are
listed
§§
63.7900
and
63.7913.
§
63.8(
c)(
5)
..............................
COMS
Minimum
Procedures
..
COMS
minimum
procedures
....................................................
No.
§
63.8(
c)(
6)
..............................
CMS
Requirements
................
Zero
and
High
level
calibration
check
requirements
...............
Yes.
However
requirements
for
CPMS
are
addressed
in
§§
63.7900
and
63.7913.
§
63.8(
c)(
7)–(
8)
........................
CMS
Requirements
................
Out
of
control
periods,
including
reporting
...............................
Yes.
§
63.8(
d)
..................................
CMS
Quality
Control
...............
Requirements
for
CMS
quality
control,
including
calibration,
etc.
Must
keep
quality
control
plan
on
record
for
5
years.
Keep
old
versions
for
5
years
after
revisions.
Yes.
§
63.8(
e)
..................................
CMS
Performance
Evaluation
Notification,
performance
evaluation
test
plan,
reports
...........
Yes.
§
63.8(
f)(
1)–(
5)
.........................
Alternative
Monitoring
Method
Procedures
for
Administrator
to
approve
alternative
monitoring
Yes.
§
63.8(
f)(
6)
...............................
Alternative
to
Relative
Accuracy
Test.
Procedures
for
Administrator
to
approve
alternative
relative
accuracy
tests
for
CEMS.
No.
§
63.8(
g)(
1)–(
4)
........................
Data
Reduction
.......................
COMS
60
minute
averages
Calculated
over
at
least
36
evenly
spaced
data
points.
CEMS
1
hour
averages
computed
over
at
least
4
equally
spaced
data
points.
Yes.
However,
COMS
are
not
applicable
Requirements
for
CPMS
are
addressed
in
§§
63.7900
and
63.7913.
§
63.8(
g)(
5)
..............................
Data
Reduction
.......................
Data
that
can't
be
used
in
computing
averages
for
CEMS
and
COMS.
No.
§
63.9(
a)
..................................
Notification
Requirements
......
Applicability
and
State
Delegation
...........................................
Yes.
§
63.9(
b)(
1)–(
5)
........................
1.
Initial
Notifications
..............
a.
Submit
notification
120
days
after
effective
date.
...............
Yes.
b.
Notification
of
intent
to
construct/
reconstruct;
Notification
of
commencement
of
construct/
reconstruct;
Notification
of
startup.
Yes.
c.
Contents
of
each
..................................................................
Yes.
§
63.9(
c)
..................................
Request
for
Compliance
Extension
Can
request
if
cannot
comply
by
date
or
if
installed
BACT/
LAER.
Yes.
§
63.9(
d)
..................................
Notification
of
Special
Compliance
Requirements
for
New
Source.
For
sources
that
commence
construction
between
proposal
and
promulgation
and
want
to
comply
3
years
after
effective
date.
Yes.
§
63.9(
e)
..................................
Notification
of
Performance
Test.
Notify
Administrator
60
days
prior
...........................................
Yes.
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
13
TO
SUBPART
GGGGG
OF
PART
63.—
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
GGGGG—
Continued
Citation
Subject
Brief
description
Applies
to
subpart
GGGGG
§
63.9(
f)
...................................
Notification
of
VE/
Opacity
Test
Notify
Administrator
30
days
prior
...........................................
No.
§
63.9(
g)
..................................
Additional
Notifications
When
Using
CMS.
Notification
of
performance
evaluation;
notification
using
COMS
data;
notification
that
exceeded
criterion
for
relative
accuracy.
Yes.
However,
there
are
no
opacity
standards.
§
63.9(
h)(
1)–(
6)
........................
Notification
of
Compliance
Status.
Contents;
Due
60
days
after
end
of
performance
test
or
other
compliance
demonstration,
except
for
opacity/
VE,
which
are
due
30
days
after;
when
to
submit
to
Federal
vs.
State
authority.
Yes.
§
63.9(
i)
...................................
Adjustment
of
Submittal
Deadlines
Procedures
for
Administrator
to
approve
change
in
when
notifications
must
be
submitted.
Yes.
§
63.9(
j)
...................................
Change
in
Previous
Information
Must
submit
within
15
days
after
the
change
..........................
Yes.
§
63.10(
a)
................................
1.
Recordkeeping/
Reporting
...
a.
Applies
to
all,
unless
compliance
extension
........................
Yes.
b.
When
to
submit
to
Federal
vs.
State
authority
....................
Yes.
c.
Procedures
for
owners
of
more
than
1
source
....................
Yes.
§
63.10(
b)(
1)
............................
1.
Recordkeeping/
Reporting
...
a.
General
Requirements
.........................................................
Yes..
b.
Keep
all
records
readily
available
........................................
Yes.
c.
Keep
for
5
years
..................................................................
Yes.
§
63.10(
b)(
2)(
i)–(
iv)
..................
1.
Records
related
to
Startup,
Shutdown,
and
Malfunction.
a.
Occurrence
of
each
of
operation
(process
equipment)
.......
Yes.
b.
Occurrence
of
each
malfunction
of
air
pollution
equipment
Yes.
c.
Maintenance
on
air
pollution
control
equipment
..................
Yes.
d.
Actions
during
startup,
shutdown,
and
malfunction
.............
Yes.
§
63.10(
b)(
2)(
vi)
and
(x)–(
xi)
...
1.
CMS
Records
.....................
a.
Malfunctions,
inoperative,
out
of
control
..............................
Yes.
b.
Calibration
checks
................................................................
Yes.
c.
Adjustments,
maintenance
...................................................
Yes.
§
63.10(
b)(
2)(
vii)–(
ix)
...............
1.
Records
..............................
a.
Measurements
to
demonstrate
compliance
with
emissions
limitations.
Yes.
b.
Performance
test,
performance
evaluation,
and
visible
emissions
observation
results.
Yes.
c.
Measurements
to
determine
conditions
of
performance
tests
and
performance
evaluations.
Yes.
§
63.10(
b)(
2)(
xii)
......................
Records
..................................
Records
when
under
waiver
....................................................
Yes.
§
63.10(
b)(
2)(
xiii)
.....................
Records
..................................
Records
when
using
alternative
to
relative
accuracy
test
.......
No.
§
63.10(
b)(
2)(
xiv)
.....................
Records
..................................
All
documentation
supporting
Initial
Notification
and
Notification
of
Compliance
Status.
Yes.
§
63.10(
b)(
3)
............................
Records
..................................
Applicability
Determinations
.....................................................
Yes.
§
63.10(
c)
................................
Records
..................................
Additional
Records
for
CMS
....................................................
No.
§
63.10(
d)(
1)
............................
General
Reporting
Requirements
Requirement
to
report
..............................................................
Yes.
§
63.10(
d)(
2)
............................
Report
of
Performance
Test
Results.
When
to
submit
to
Federal
or
State
authority
.........................
Yes.
§
63.10(
d)(
3)
............................
Reporting
Opacity
or
VE
Observations
What
to
report
and
when
.........................................................
No.
§
63.10(
d)(
4)
............................
Progress
Reports
....................
Must
submit
progress
reports
on
schedule
if
under
compliance
extension.
Yes.
§
63.10(
d)(
5)
............................
Startup,
Shutdown,
and
Malfunction
Reports.
Contents
and
submission
.........................................................
Yes.
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/
Vol.
67,
No.
146
/
Tuesday,
July
30,
2002
/
Proposed
Rules
TABLE
13
TO
SUBPART
GGGGG
OF
PART
63.—
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
GGGGG—
Continued
Citation
Subject
Brief
description
Applies
to
subpart
GGGGG
§
63.10(
e)(
1)–(
2)
.....................
Additional
CMS
Reports
.........
Must
report
results
for
each
CEM
on
a
unit;
written
copy
of
performance
evaluation;
3
copies
of
COMS
performance
evaluation.
Yes.
However,
COMS
are
not
applicable
§
63.10(
e)(
3)
............................
Reports
...................................
Excess
Emissions
Reports
......................................................
No.
§
63.10(
e)(
3)(
i)–(
iii)
..................
Reports
...................................
Schedule
for
reporting
excess
emissions
and
parameter
monitor
exceedance
(now
defined
as
deviations).
No.
§
63.10(
e)(
3)(
iv)–(
v)
.................
1.
Excess
Emissions
Reports
a.
Requirement
to
revert
to
quarterly
submission
if
there
is
an
excess
emissions
and
parameter
monitor
exceedance
(now
defined
as
deviations)..
No.
b.
Provision
to
request
semiannual
reporting
after
compliance
for
one
year.
No.
c.
Submit
report
by
30th
day
following
end
of
quarter
or
calendar
half.
No.
d.
If
there
has
not
been
an
exceedance
or
excess
emissions
(now
defined
as
deviations),
report
contents
is
a
statement
that
there
have
been
no
deviations.
No.
§
63.10(
e)(
3)(
iv)–(
v)
.................
Excess
Emissions
Reports
.....
Must
submit
report
containing
all
of
the
information
in
§
63.10(
c)(
5–
13),
§
63.8(
c)(
7–
8).
No.
§
63.10(
e)(
3)(
vi)–(
viii)
..............
Excess
Emissions
Report
and
Summary
Report.
Requirements
for
reporting
excess
emissions
for
CMSs
(now
called
deviations).
Requires
all
of
the
information
in
§
63.10(
c)(
5–
13),
§
63.8(
c)(
7–
8).
No.
§
63.10(
e)(
4)
............................
Reporting
COMS
data
............
Must
submit
COMS
data
with
performance
test
data
.............
No.
§
63.10(
f)
.................................
Waiver
for
Recordkeeping/
Reporting
Procedures
for
Administrator
to
waive
.....................................
Yes.
§
63.11
.....................................
Flares
......................................
Requirements
for
flares
............................................................
Yes.
§
63.12
.....................................
Delegation
...............................
State
authority
to
enforce
standards
........................................
Yes.
§
63.13
.....................................
Addresses
...............................
Addresses
where
reports,
notifications,
and
requests
are
sent.
Yes.
§
63.14
.....................................
Incorporation
by
Reference
....
Test
methods
incorporated
by
reference
.................................
Yes.
§
63.15
.....................................
Availability
of
Information
.......
Public
and
confidential
information
..........................................
Yes.
[FR
Doc.
02–
17360
Filed
7–
29–
02;
8:
45
am]
BILLING
CODE
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50–
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| epa | 2024-06-07T20:31:39.842499 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0021-0001/content.txt"
} |
EPA-HQ-OAR-2002-0022-0001 | Proposed Rule | "2002-08-09T04:00:00" | Federal Implementation Plans Under the Clean Air Act
for Indian Reservations in Idaho, Oregon and
Washington | 51802
Federal
Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
change
to
the
existing
approved
information
collection.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
the
collection
of
information
displays
a
valid
control
number
assigned
by
OMB.
Drafting
Information
The
principal
author
of
this
document
was
Francis
W.
Foote,
Office
of
Regulations
and
Rulings,
U.
S.
Customs
Service.
However,
personnel
from
other
offices
participated
in
its
development.
List
of
Subjects
in
19
CFR
Part
12
Bonds,
Customs
duties
and
inspection,
Entry
of
merchandise,
Imports,
Prohibited
merchandise,
Reporting
and
recordkeeping
requirements,
Restricted
merchandise.
Proposed
Amendment
to
the
Regulations
For
the
reasons
stated
above,
it
is
proposed
to
amend
Part
12
of
the
Customs
Regulations
(19
CFR
Part
12)
as
set
forth
below.
PART
12—
SPECIAL
CLASSES
OF
MERCHANDISE
1.
The
authority
citation
for
Part
12
continues
to
read
in
part
as
follows:
Authority:
5
U.
S.
C.
301;
19
U.
S.
C.
66,
1202
(General
Note
23,
Harmonized
Tariff
Schedule
of
the
United
States
(HTSUS)),
1624;
*
*
*
*
*
2.
A
new
center
heading
and
new
§
12.145
are
added
to
read
as
follows:
Steel
Products
§
12.145
Entry
of
certain
steel
products.
Except
in
the
case
of
merchandise
that
is
eligible
for
informal
entry
under
§
143.21
of
this
chapter,
in
any
case
in
which
a
steel
import
license
number
is
required
to
be
obtained
under
regulations
promulgated
by
the
U.
S.
Department
of
Commerce,
that
license
number
must
be
included
on
the
entry
summary,
Customs
Form
7501,
or
on
an
electronic
equivalent.
Robert
C.
Bonner,
Commissioner
of
Customs.
Approved:
August
6,
2002.
Timothy
E.
Skud,
Deputy
Assistant
Secretary
of
the
Treasury.
[FR
Doc.
02–
20165
Filed
8–
8–
02;
8:
45
am]
BILLING
CODE
4820–
02–
P
DEPARTMENT
OF
TRANSPORTATION
Federal
Highway
Administration
23
CFR
Part
630
[FHWA
Docket
No.
FHWA–
2001–
11130]
RIN
2125–
AE29
Work
Zone
Safety
AGENCY:
Federal
Highway
Administration
(FHWA),
DOT.
ACTION:
Notice
of
public
meetings.
SUMMARY:
The
FHWA
published
an
Advance
Notice
of
Proposed
Rulemaking
(ANPRM)
on
February
6,
2002
(67
FR
5532),
to
obtain
comments
on
the
current
work
zone
safety
regulation.
The
purpose
of
the
ANPRM
was
to
seek
comments
regarding
improvements
that
can
be
made
to
its
regulation
on
Traffic
Safety
in
Highway
and
Street
Work
Zones
to
better
address
work
zone
mobility
and
safety
concerns.
On
June
6,
2002,
the
comment
period
closed,
and
the
FHWA
began
to
analyze
the
comments
provided.
This
meeting
is
being
held
to
highlight
the
reasons
for
the
ANPRM,
present
a
summary
of
the
comments
received,
and
discuss,
based
on
the
comments
received,
the
possible
impacts
that
a
rulemaking
might
have
on
the
current
regulation.
DATES:
The
meetings
will
be
held
Thursday,
August
29,
Thursday,
September
19,
and
Wednesday,
September
25,
2002
from
10:
00
to
2:
00
p.
m.
ADDRESSES:
Cambridge
Systematics,
4445
Willard
Avenue,
Suite
300,
Chevy
Chase,
MD
20815.
Telephone:
(301)
347–
0100
and
Fax:
(301)
347–
0101.
FOR
FURTHER
INFORMATION
CONTACT:
Materials
associated
with
this
meeting
may
be
examined
at
the
office
of
Cambridge
Systematics,
4445
Willard
Avenue,
Suite
300,
Chevy
Chase,
MD
20815.
Persons
needing
further
information
or
who
request
to
speak
at
this
meeting
should
contact
Mike
Harris
at
PB
Farradyne,
Inc.
by
telephone
at
(703)
742–
5759
or
by
Fax
at
(703)
742–
5989.
The
U.
S.
DOT
contact
is
Scott
Battles,
FHWA,
400
Seventh
Street,
SW.,
Washington,
D.
C.
20590,
(202)
366–
4372.
Office
hours
are
from
7:
45
a.
m.
to
4:
15
p.
m.,
e.
t.,
Monday
through
Friday,
except
for
legal
holidays.
SUPPLEMENTARY
INFORMATION:
Electronic
Access
An
electronic
copy
of
this
document
may
be
downloaded
by
using
a
computer,
modem,
and
suitable
communications
software
from
the
Government
Printing
Office's
Electronic
Bulletin
Board
Service
at
(202)
512–
1661.
Internet
users
may
reach
the
Office
of
the
Federal
Register's
home
page
at:
http://
www.
nara.
gov/
fedreg
and
the
Government
Printing
Office's
web
site
at
http://
www.
access.
gpo.
gov.
Authority:
23
U.
S.
C.
106,
109,
115,
315,
320,
and
402(
a);
23
CFR
1.32;
49
CFR
1.48;
sec.
1051,
Pub.
L.
102–
240,
105
Stat.
2001;
sec.
358(
b),
Pub.
L.
104–
59,
109
Stat.
625.
Issued
on:
August
6,
2002.
Gary
E.
Maring,
Director,
Office
of
Freight
Management
and
Operations.
[FR
Doc.
02–
20249
Filed
8–
8–
02;
8:
45
am]
BILLING
CODE
4910–
22–
P
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
49
[Docket
#:
A–
2000–
25;
FRL–
7254–
3]
RIN
2012–
AA01
Federal
Implementation
Plans
Under
the
Clean
Air
Act
for
Indian
Reservations
in
Idaho,
Oregon
and
Washington
AGENCY:
Environmental
Protection
Agency
(EPA).
ACTION:
Proposed
rule;
notice
to
re
open
the
public
comment
period
and
to
hold
a
public
hearing.
SUMMARY:
Today,
EPA
is
re
opening
the
public
comment
period
on
EPA's
notice
of
proposed
rulemaking
``
Federal
Implementation
Plans
(FIPs)
under
the
Clean
Air
Act
(CAA)
for
Indian
Reservations
in
Idaho,
Oregon,
and
Washington,
''
published
March
15,
2002
at
67
FR
11748.
The
original
90
day
public
comment
period
closed
on
June
13,
2002
but
several
commenters
requested
additional
time
to
provide
comments
on
the
proposal
and
one
commenter
requested
a
public
hearing.
In
response
to
these
requests,
EPA
will
re
open
the
comment
period
and
provide
an
additional
60
days
for
interested
and
affected
parties
to
submit
comments.
The
new
comment
period
will
close
on
October
10,
2002.
In
addition,
EPA
will
hold
a
public
hearing
to
receive
comments
on
the
proposed
rule
on
September
10,
2002,
beginning
at
7
p.
m.
Pacific
Daylight
Time
(PDT)
at
the
Liberty
Theater
in
Toppenish,
WA.
All
comments
received
by
EPA
during
the
public
comment
period
will
be
considered
in
the
final
rulemaking.
DATES:
Comments.
Comments
must
be
received
or
postmarked
no
later
than
October
10,
2002.
Public
Hearing.
A
public
hearing
will
be
held
on
September
10,
2002,
beginning
at
7
p.
m.
PDT
at
the
Liberty
Theater
in
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Federal
Register
/
Vol.
67,
No.
154
/
Friday,
August
9,
2002
/
Proposed
Rules
Toppenish,
WA.
Additional
requests
for
a
public
hearing
must
be
received
by
EPA
no
later
than
August
23,
2002.
ADDRESSES:
Comments.
Written
comments
should
be
addressed
to:
David
Bray,
Office
of
Air
Quality
(OAQ–
107),
U.
S.
EPA
Region
10,
1200
Sixth
Avenue,
Seattle,
WA
98101–
1128.
Comments
may
also
be
submitted
by
email
to
``
bray.
dave@
epa.
gov.
''
Please
cite
the
administrative
docket,
#A–
2000–
25,
upon
which
you
are
providing
comment.
Public
Hearing.
The
hearing
on
September
20,
2002
will
take
place
at
7
p.
m.
PDT
at
the
Liberty
Theater,
211
S.
Toppenish
Avenue,
Toppenish,
WA.
Docket.
Docket
A–
2000–
25,
containing
all
information
supporting
this
action
is
available
for
public
inspection
and
copying
between
8:
30
a.
m.
and
5:
30
p.
m.
Eastern
Daylight
Time
at
EPA's
Central
Docket
Section,
Office
of
Air
and
Radiation,
Room
1500
(M–
6102),
401
M
Street,
SW.,
Washington,
DC
20460.
EPA's
Central
Docket
Section
is
scheduled
to
move
between
August
12
and
August
27,
and
material
will
not
be
available
for
viewing
in
Washington,
DC,
during
this
time.
After
August
27,
2002,
the
docket
will
be
available
for
public
inspection
and
copying
between
8:
30
a.
m.
and
5:
30
p.
m.
Eastern
Daylight
Time
at
EPA's
Air
and
Radiation
Docket
and
Information
Center,
1301
Constitution
Avenue,
NW.,
Room
B108,
Mail
Code
6102T,
Washington
DC
20460.
The
docket
is
also
available
between
8:
30
a.
m.
and
3:
30
p.
m.
PDT
at
EPA
Region
10,
Office
of
Air
Quality,
10th
Floor,
1200
Sixth
Avenue,
Seattle,
Washington
98101.
A
reasonable
fee
may
be
charged
for
copies.
A
copy
of
the
March
15,
2002
proposed
rule
and
all
comments
submitted
as
of
June
13,
2002,
are
available
at
the
Toppenish
Library,
1
South
Elm,
Toppenish,
WA
98948
during
regular
library
hours.
Web
site.
Information
on
this
proposed
rulemaking
is
also
available
on
EPA
Region
10's
Web
site
at:
www.
epa.
gov/
r10earth/
tribalairrules.
htm.
FOR
FURTHER
INFORMATION
CONTACT:
David
Bray,
Office
of
Air
Quality
(OAQ–
107),
U.
S.
EPA
Region
10,
1200
Sixth
Avenue,
Seattle,
WA
98101–
1128,
(206)
553–
4253.
SUPPLEMENTARY
INFORMATION:
On
March
15,
2002
(67
FR
11748),
EPA
solicited
public
comment
on
its
proposal
to
promulgate
Federal
Implementation
Plans
(FIPs)
under
the
Clean
Air
Act
(CAA)
for
39
Indian
reservations
in
Idaho,
Oregon,
and
Washington.
The
FIPs
would
include
basic
air
quality
regulations
for
the
protection
of
communities
on
those
Indian
reservations.
These
rules
would
be
implemented
and
enforced
by
EPA.
EPA
received
requests
to
extend
the
public
comment
period
to
allow
more
time
to
review
the
proposal
and
to
prepare
comments.
EPA
also
received
a
request
on
behalf
of
the
residents
of
the
Yakama
Indian
Reservation
to
hold
a
public
hearing.
As
a
result
of
the
requests
to
extend
the
public
comment
period,
EPA
is
reopening
the
comment
period
for
60
days.
All
comments
received
or
postmarked
by
October
10,
2002
will
be
considered
in
the
development
of
a
final
rule.
A
copy
of
all
comments,
including
the
requests
to
extend
the
public
comment
period,
have
been
placed
into
the
docket
and
may
be
reviewed
during
normal
business
hours
at
the
locations
listed
above.
Interested
parties
are
invited
to
comment
on
all
aspects
of
EPA's
March
15,
2002
proposal.
Comments
should
be
addressed
to
David
Bray
at
the
address
listed
above.
EPA
also
invites
interested
parties
to
provide
comments
at
a
public
hearing
to
be
held
on
September
10,
2002
at
7
p.
m.
PDT
at
the
Liberty
Theater
in
Toppenish,
WA.
Dated:
July
24,
2002.
L.
John
Iani,
Regional
Administrator,
Region
10.
[FR
Doc.
02–
19440
Filed
8–
8–
02;
8:
45
am]
BILLING
CODE
6560–
50–
P
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
52
[NC93–
200122a;
FRL–
7206–
8]
Approval
and
Promulgation
of
Implementation
Plans
North
Carolina:
Approval
of
Revisions
to
The
Open
Burning
Regulations
Within
the
Forsyth
County
Local
Implementation
Plan
AGENCY:
Environmental
Protection
Agency
(EPA).
ACTION:
Proposed
rule.
SUMMARY:
The
EPA
is
proposing
to
approve
the
Local
Implementation
Plan
(LIP)
revision
submitted
by
the
Forsyth
County
Environmental
Affairs
Department,
through
the
State
of
North
Carolina,
for
the
purpose
of
amending
regulations
relating
to
open
burning,
transportation
conformity,
and
the
general
provisions
section
of
the
Air
Quality
Permits
subchapter.
In
the
Final
Rules
section
of
this
Federal
Register,
the
EPA
is
approving
the
Forsyth
county
LIP
revision
as
a
direct
final
rule
without
prior
proposal
because
the
Agency
views
this
as
a
noncontroversial
submittal
and
anticipates
no
adverse
comments.
A
detailed
rationale
for
the
approval
is
set
forth
in
the
direct
final
rule.
If
no
significant,
material,
and
adverse
comments
are
received
in
response
to
this
rule,
no
further
activity
is
contemplated.
If
EPA
receives
adverse
comments,
the
direct
final
rule
will
be
withdrawn
and
all
public
comments
received
will
be
addressed
in
a
subsequent
final
rule
based
on
this
rule.
The
EPA
will
not
institute
a
second
comment
period
on
this
document.
Any
parties
interested
in
commenting
on
this
document
should
do
so
at
this
time.
DATES:
Written
comments
must
be
received
on
or
before
September
9,
2002.
ADDRESSES:
All
comments
should
be
addressed
to:
Randy
Terry
at
the
EPA,
Region
4
Air
Planning
Branch,
61
Forsyth
Street,
SW.,
Atlanta,
Georgia
30303–
8960.
Copies
of
the
State
submittal(
s)
are
available
at
the
following
addresses
for
inspection
during
normal
business
hours:
Environmental
Protection
Agency,
Region
4,
Air
Planning
Branch,
61
Forsyth
Street,
SW.,
Atlanta,
Georgia
30303–
8960.
Randy
Terry,
404/
562–
9032.
Forsyth
County
Environmental
Affairs
Department,
537
North
Spruce
Street,
Winston
Salem,
North
Carolina
27101.
North
Carolina
Department
of
Environment
and
Natural
Resources,
512
North
Salisbury
Street,
Raleigh,
North
Carolina
27604.
FOR
FURTHER
INFORMATION
CONTACT:
Randy
B.
Terry
at
404/
562–
9032,
or
by
electronic
mail
at
terry.
randy@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
For
additional
information
see
the
direct
final
rule
which
is
published
in
the
Rules
section
of
this
Federal
Register.
Dated:
April
1,
2002.
A.
Stanley
Meiburg,
Acting
Regional
Administrator,
Region
4.
[FR
Doc.
02–
20226
Filed
8–
8–
02;
8:
45
am]
BILLING
CODE
6560–
50–
P
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
271
[FRL–
7256–
6]
Rhode
Island:
Final
Authorization
of
State
Hazardous
Waste
Management
Program
Revisions
AGENCY:
Environmental
Protection
Agency
(EPA).
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| epa | 2024-06-07T20:31:39.887643 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0022-0001/content.txt"
} |
EPA-HQ-OAR-2002-0023-0001 | Proposed Rule | "2002-08-07T04:00:00" | Motor Vehicle and Engine Compliance Program Fees for:
Light-Duty Vehicles; Light-Duty Trucks; Heavy-Duty
Vehicles and Engines; Nonroad Engines and Motorcycles;
Proposed Rule | Wednesday,
August
7,
2002
Part
III
Environmental
Protection
Agency
40
CFR
Parts
85
and
86
Motor
Vehicle
and
Engine
Compliance
Program
Fees
for:
Light
Duty
Vehicles;
Light
Duty
Trucks;
Heavy
Duty
Vehicles
and
Engines;
Nonroad
Engines
and
Motorcycles;
Proposed
Rule
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Federal
Register
/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
85
and
86
[AMS–
FRL–
7250–
1]
RIN
2060–
AJ62
Motor
Vehicle
and
Engine
Compliance
Program
Fees
for:
Light
Duty
Vehicles;
Light
Duty
Trucks;
Heavy
Duty
Vehicles
and
Engines;
Nonroad
Engines;
and
Motorcycles
AGENCY:
Environmental
Protection
Agency.
ACTION:
Notice
of
proposed
rulemaking.
SUMMARY:
Today's
action
proposes
to
update
the
current
Motor
Vehicle
and
Engine
Compliance
Program
(MVECP)
fees
regulation
under
which
fees
are
collected
for
certification
and
compliance
activities
related
to
lightduty
vehicles
and
trucks,
heavy
duty
highway
vehicles
and
engines,
and
highway
motorcycles.
Today's
action
proposes
to
update
the
fees
regulations
to
reflect
increased
costs
of
administering
the
compliance
programs
already
covered
within
the
existing
MVECP
fee
program.
In
addition,
EPA
is
proposing
to
add
a
fee
program
for
the
nonroad
compliance
programs
that
have
been
implemented
since
the
initial
MVECP
fees
regulation
including
certain
nonroad
compression
ignition,
locomotive,
and
small
spark
ignition
engines.
EPA
is
also
proposing
to
add
a
fee
program
for
other
nonroad
categories
including
recreational
vehicles
(including
snowmobiles,
off
road
motorcycles
and
all
terrain
vehicles),
recreational
marine
compression
ignition
engines
and
the
remaining
nonroad
large
spark
ignition
engines
(engines
over
37
kW)
compliance
programs
for
which
emission
standards
have
been
proposed
but
not
yet
finalized.
Also
included
in
this
proposal
are
fees
for
marine
spark
ignition/
inboard
sterndrive
engines;
the
emission
standards
for
these
engines
are
under
development
but
not
yet
proposed.
DATES:
Comments:
Send
written
comments
on
this
document
by
October
19,2002.
Hearings:
We
will
hold
a
public
hearing
on
September
19,
2002.
The
hearing
will
begin
at
10
a.
m.
and
continue
until
all
testimony
has
been
presented.
If
you
want
to
testify
at
the
hearing,
notify
either
contact
person
below
by
September
12,
2002.
See
Section
VII.
A.
and
B.
of
the
SUPPLEMENTARY
INFORMATION
section
of
this
document
for
more
information
about
public
hearings
and
comment
procedures.
ADDRESSES:
Comments:
You
may
send
written
comments
in
paper
form
or
by
e
mail.
We
must
receive
them
by
the
date
indicated
under
DATES
above.
Send
paper
copies
of
written
comments
(in
duplicate,
if
possible)
to
either
contact
person
listed
below
or
by
e
mail
to
``
otaqfees@
epa.
gov''.
In
your
correspondence,
refer
to
Docket
A–
2001–
09.
EPA's
air
docket
makes
materials
related
to
this
rulemaking
available
for
review
in
EPA
Air
Docket
No.
A–
2001–
09.
Until
August
26,
2002,
the
docket
is
located
at
The
Air
Docket,
401
M.
Street,
SW.,
Washington,
DC
20460,
and
may
be
viewed
in
room
M1500
between
8
a.
m.
and
5:
30
p.
m.,
Monday
through
Friday.
The
telephone
number
is
(202)
260–
7548
and
the
facsimile
number
is
(202)
260–
4400.
After
August
26,
2002,
the
Air
Docket
will
be
located
at
room
B–
108,
1301
Constitution
Avenue,
NW.,
Washington,
DC
20460.
A
reasonable
fee
may
be
charged
by
EPA
for
copying
docket
material.
Hearings:
We
will
hold
a
public
hearing
at
the
Towsley
Auditorium,
Morris
Lawrence
Building,
Washtenaw
Community
College,
Ann
Arbor,
MI.
See
Section
VII.
A.
and
B.
for
more
information
about
public
hearings
and
comment
procedures.
FOR
FURTHER
INFORMATION
CONTACT:
Lynn
Sohacki,
Certification
and
Compliance
Division,
U.
S.
Environmental
Protection
Agency,
2000
Traverwood,
Ann
Arbor,
Michigan
48105,
Telephone
734–
214–
4851,
Internet
e
mail
``
sohacki.
lynn@
epa.
gov,
''
or
Trina
D.
Vallion,
734–
214–
4449,
Internet
e
mail
``
vallion.
trina@
epa.
gov.
''
SUPPLEMENTARY
INFORMATION:
Regulated
Entities
Entities
potentially
regulated
by
this
action
are
those
which
manufacture
or
seek
certification
(``
manufacturer''
or
``
manufacturers'')
of
new
motor
vehicles
and
engines
(including
both
highway
and
nonroad).
The
table
below
shows
the
category,
North
American
Industry
Classification
System
(NAICS)
Codes,
Standard
Industrial
Classification
(SIC)
Codes
and
examples
of
the
regulated
entities:
Category
NAICS
Codes
1
SIC
Codes
2
Examples
of
potentially
regulated
entities
Industry
.................................................................
333111
3523
Farm
Machinery
and
Equipment
Manufacturing.
Industry
.................................................................
333112
3524
Lawn
and
Garden
Tractor
and
Home
Lawn
and
Garden
Equipment
Manufacturing.
Industry
.................................................................
333120
3531
Construction
Machinery
Manufacturing.
Industry
.................................................................
333131
3532
Mining
Machinery
and
Equipment
Manufacturing.
Industry
.................................................................
333132
3533
Oil
&
Gas
Field
Machinery.
Industry
.................................................................
333210
3553
Sawmill
&
Woodworking
Machinery.
Industry
.................................................................
333924
3537
Industrial
Truck,
Tractor,
Trailer,
and
Stacker
Machinery
Manufacturing
Industry
.................................................................
333991
3546
Power
Driven
Handtool
Manufacturing.
Industry
.................................................................
336111
3711
Automotive
and
Light
Duty
Motor
Vehicle
Manufacturing.
Industry
.................................................................
336120
3711
Heavy
Duty
Truck
Manufacturing.
Industry
.................................................................
336213
3716
Motor
Home
Manufacturing.
Industry
.................................................................
336311
3592
Motor
Vehicle
Gasoline
Engine
and
Engine
Parts
Manufacturing
Industry
.................................................................
336312
3714
Gasoline
Engine
&
Engine
Parts
Manufacturing.
Industry
.................................................................
336991
3751
Motorcycle,
Bicycle,
and
Parts
Manufacturing.
Industry
.................................................................
336211
3711
Motor
Vehicle
Body
Manufacturing.
Industry
.................................................................
333618
3519
Gasoline,
Diesel
&
dual
fuel
engine
Manufacturing.
Industry
.................................................................
811310
7699
Commercial
&
Industrial
Engine
Repair
and
Maintenance.
Industry
.................................................................
336999
3799
Other
Transportation
Equipment
Manufacturing.
Industry
.................................................................
421110
....................
Independent
Commercial
Importers
of
Vehicles
and
Parts.
Industry
.................................................................
333612
3566
Speed
Changer,
Industrial
High
speed
Drive
and
Gear
Manufacturing
Industry
.................................................................
333613
3568
Mechanical
Power
Transmission
Equipment
Manufacturing.
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Federal
Register
/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
1
Nonroad
engines
are
defined
in
40
CFR
89.2.
It
is
a
general
term
which
encompasses
all
the
regulated
subclasses
including,
but
not
limited
to,
both
CI
and
SI
engines
used
in:
farm
and
construction
equipment,
marine
applications,
recreation
applications,
and
locomotives.
2
Manufacturer,
as
used
in
this
NPRM,
means
all
entities
or
individuals
requesting
certification,
including,
but
not
limited
to,
Original
Equipment
Manufacturers,
ICIs,
and
vehicle
or
engine
converters.
Category
NAICS
Codes
1
SIC
Codes
2
Examples
of
potentially
regulated
entities
Industry
.................................................................
333618
3519
Other
Engine
Equipment
Manufacturing.
1
North
American
Industry
Classification
System
(NAICS)
2
Standard
Industrial
Classification
(SIC)
system
code.
This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
EPA
is
now
aware
could
potentially
be
regulated
by
this
proposed
action.
Other
types
of
entities
not
listed
in
the
table
could
also
be
regulated.
To
determine
whether
your
product
would
be
regulated
by
this
proposed
action,
you
should
carefully
examine
the
applicability
criteria
in
title
40
of
the
Code
of
Federal
Regulations,
parts
86,
89,
90,
91,
92
and
94;
also
parts
1045,
1048,
and
1051
when
those
Parts
are
finalized.
If
you
have
questions
regarding
the
applicability
of
this
proposed
action
to
a
particular
product,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Obtaining
Rulemaking
Documents
Through
the
Internet
The
preamble
and
regulatory
language
of
today's
proposal,
and
the
Motor
Vehicle
and
Engine
Compliance
Program
Cost
Analysis
document
(which
is
an
explanation
how
we
determined
EPA's
costs
to
conduct
the
MVECP
and
the
proposed
fees
to
cover
the
program)
are
also
available
electronically
from
the
EPA
Internet
Web
site.
This
service
is
free
of
charge.
The
official
EPA
version
is
made
available
on
the
day
of
publication
on
the
primary
Web
site
listed
below.
The
EPA
Office
of
Transportation
and
Air
Quality
also
publishes
these
notices
on
the
secondary
Web
site
listed
below.
(1)
http://
www.
epa.
gov/
docs/
fedrgstr/
EPA–
AIR/
(either
select
desired
date
or
use
Search
feature)
(2)
http://
www.
epa.
gov/
OTAQ/
(look
in
``
What's
New''
or
under
the
specific
rulemaking
topic)
Please
note
that
due
to
differences
between
the
software
used
to
develop
the
document
and
the
software
into
which
the
document
may
be
downloaded,
changes
in
format,
page
length,
etc.
may
occur.
Table
of
Contents
I.
Introduction
A.
Overview
B.
What
Programs
Are
Covered
by
the
Fees?
II.
Background
A.
Basis
for
Action
under
the
Clean
Air
Act
and
Other
Legal
Authority
B.
How
Do
EPA's
Compliance
Programs
Work?
C.
How
Does
this
Rulemaking
Affect
the
Proposed
Recreational
Vehicles
Rule
and
Future
Rules?
D.
How
Does
the
Fuel
Economy
Program
Work?
III.
Proposed
Fee
System
A.
What
Agency
Costs
Are
Recoverable
by
Fees?
B.
What
OTAQ
Activities
Are
Not
Included
in
the
Agency's
Proposed
Fee
Program?
C.
How
did
the
Agency
Analyze
the
Costs
of
the
Compliance
Programs?
D.
Proposed
Fee
Schedule
E.
Will
the
Fees
Automatically
Increase
to
Reflect
Future
Inflation?
F.
Comments
on
the
Proposed
Fee
System
IV.
Fee
Collection
and
Transactions
A.
Procedure
for
Paying
Fees
B.
What
is
the
Implementation
Schedule
for
Fees?
C.
What
Happens
to
the
Money
That
Is
Collected
by
the
Fees
Program?
D.
Can
I
Qualify
for
a
Reduced
Fee?
E.
What
Is
the
Refund
Policy?
V.
What
Other
Options
Were
Considered
by
EPA
When
Proposing
this
Rule?
A.
Separate
Fees
for
Other
ICI
Categories
Beyond
Light
Duty
B.
Start
Updating
Fees
for
Cost
of
Inflation
in
2004
Model
Year
VI.
What
Is
the
Economic
Impact
of
this
Proposed
Rule?
VII.
How
Can
I
Participate
in
the
Rulemaking
Process?
A.
How
to
Make
Comments
and
Use
the
Public
Docket
B.
Public
Hearings
VIII.
What
are
the
Administrative
Requirements
for
this
Proposal?
A.
Executive
Order
12866:
Administrative
Designation
and
Regulatory
Analysis
B.
Regulatory
Flexibility
Act
(RFA),
as
amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(SBREFA),
5
USC
601
et.
seq
C.
Paperwork
Reduction
Act
D.
Unfunded
Mandates
Reform
Act
E.
National
Technology
Transfer
and
Advancement
Act
F.
Executive
Order
13045:
Children's
Health
Protection
G.
Executive
Order
13132:
Federalism
H.
Executive
Order
13211:
Energy
Effects
I.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
I.
Introduction
A.
Overview
EPA
is
proposing
to
update
the
current
MVECP
fees
regulation
which
assesses
fees
for
the
EPA's
certification
and
compliance
activities
related
to
highway
vehicles
and
engines
and
to
incorporate
new
fees
for
certification
and
compliance
activities
related
to
nonroad
1
engines.
Currently,
fees
are
collected
for
certification
and
compliance
activities
related
to
lightduty
vehicles
and
trucks,
heavy
duty
highway
vehicles
and
engines,
and
highway
motorcycles.
Today's
action
proposes
to
update
the
fees
regulations
to
reflect
the
increased
costs
of
administering
the
compliance
programs
already
covered
within
the
existing
MVECP
fee
program
and
to
add
a
fee
program
for
the
nonroad
compliance
programs
we
have
implemented
since
the
initial
MVECP
fees
regulation
including
nonroad
compression
ignition,
marine
spark
ignition
outboard/
personal
water
craft,
locomotive,
and
small
spark
ignition
(less
than
or
equal
to
19
kW)
engines.
We
are
also
proposing
to
add
a
fee
program
for
recreational
vehicles
(including,
but
not
limited
to,
snowmobiles,
off
road
motorcycles
and
all
terrain
vehicles),
recreational
marine
compression
ignition
engines
and
large
spark
ignition
nonroad
engines
(over
19
kW)
compliance
programs.
Also
included
in
this
proposal
are
fees
for
marine
spark
ignition/
inboardsterndrive
engines.
Hence,
under
this
new
proposal
all
manufacturers
and
Independent
Commercial
Importers
(ICIs)
of
light
duty
vehicles
(LDVs),
light
duty
trucks
(LDTs),
heavy
duty
vehicles
(HDVs),
heavy
duty
highway
engines
(HDEs),
nonroad
spark
and
compression
ignition
engines
(NR),
marine
compression
and
spark
ignition
engines
(including
recreational
applications),
locomotives,
highway
and
off
road
motorcycles
(MCs),
and
recreational
vehicles
would
be
subject
to
fees.
Table
II–
B.
1
below
lists
the
vehicle
and
engine
classes
that
are
affected
by
today's
proposed
action.
A
certificate
of
conformity
is
generally
required
when
a
manufacturer
2
decides
to
market
new
vehicles
or
engines
in
the
United
States
(see
discussion
below
for
complete
discussion
of
when
a
certificate
of
conformity
is
required).
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Federal
Register
/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
3
Part
C
of
the
CAA,
as
amended,
pertains
to
Clean
Fuel
Vehicles.
4
A
certification
request
is
defined
as
a
manufacturer's
request
for
certification
evidenced
by
the
submission
of
an
application
for
certification,
Engine
System
Information
(ESI)
data
sheet,
or
ICI
Carry
Over
data
sheet.
Before
issuing
that
certificate,
EPA
must
perform
certain
activities
necessary
to
ensure
compliance
with
regulations
implemented
within
the
Motor
Vehicle
and
Engine
Compliance
Program
(MVECP).
The
MVECP
includes
all
activities
conducted
by
EPA
that
are
associated
with
certification,
fuel
economy,
Selective
Enforcement
Auditing
(SEA),
and
in
use
compliance
monitoring
and
audits.
Such
MVECP
activities
include:
Providing
certification
assistance
during
the
preproduction
phase;
pre
certification
confirmatory
testing
of
vehicles;
laboratory
correlation;
certification
compliance
audits
and
investigations;
conducting
fuel
economy
selection,
testing,
and
labeling;
selective
enforcement
audits
(SEA);
providing
manufacturers
and
ICIs
with
CAFE
calculations;
monitoring
of
in
use
vehicles
and
engines;
monitoring/
data
review
of
mandatory
production
line
(PLT)
and
in
use
testing;
and
Agencyrun
in
use
surveillance
and/
or
recall
tests.
In
accordance
with
the
Clean
Air
Act,
as
amended
in
1990
(CAA),
and
the
Independent
Office
of
Appropriations
Act
(IOAA),
EPA
is
authorized
to
collect
fees
for
specific
services
it
provides
to
manufacturers.
Section
217
of
the
CAA
(42
U.
S.
C.
7552)
permits
the
EPA
to
establish
fees
to
recover
all
reasonable
costs
associated
with
(1)
new
vehicle
or
engine
certification
under
section
206(
a)
or
part
C,
3
(2)
new
vehicle
or
engine
compliance
monitoring
and
testing
under
section
206(
b)
or
part
C,
and
(3)
in
use
vehicle
or
engine
compliance
monitoring
under
section
207(
c)
or
part
C.
Secondly,
the
authority
to
collect
fees
is
also
provided
by
the
IOAA
(31
U.
S.
C.
9701)
which
permits
a
government
agency
to
establish
fees
for
a
service
or
thing
of
value
provided
by
the
agency
to
an
identifiable
recipient.
Finally,
Office
of
Management
and
Budget
(OMB)
Circular
No.
A–
25
Revised,
establishes
Federal
policy
regarding
fees
assessed
for
Government
services
and
for
the
sale
or
use
of
Government
goods
or
resources
and
provides
guidance
for
agency
implementation
of
charges
and
the
deposition
of
collections.
The
MVECP
fees
have
been
in
existence
since
1992.
The
first
fees
regulations
(57
FR
30055)
were
published
on
July
7,
1992,
establishing
MVECP
fees
to
recover
all
reasonable
costs
associated
with
certification
and
compliance
programs
within
the
Office
of
Transportation
and
Air
Quality
(OTAQ),
then
called
Office
of
Mobile
Sources
(OMS).
In
1999,
under
the
Compliance
Assurance
Program
(CAP
2000)
regulations
(64
FR
23906),
the
provisions
for
fees
were
updated
to
reflect
several
changes
in
the
costs
of
the
MVECP.
The
fees
regulations
were
further
modified
by
a
regulatory
amendment
published
on
March
7,
2000
(65
FR
11904).
This
amendment,
which
is
applicable
to
original
equipment
manufacturers
(OEMs)
and
aftermarket
conversion
manufacturers,
allows
a
fee
waiver
for
small
volume
engine
families
of
alternatively
fueled
vehicles
that
are
certified
to
the
Clean
Fuel
Vehicle
standards
for
model
years
(MY)
2000
through
2003.
Since
the
initial
MVECP
fees
regulation,
EPA
has
incurred
additional
costs
and
will
continue
to
incur
cost
in
supporting
these
current
light
duty
and
heavy
duty
compliance
programs
(including
Tier
2
and
new
heavy
duty
engine
regulations),
and
new
compliance
programs
and
testing
requirements
for
nonroad.
Today's
action
proposes
to
update
the
MVECP
fee
provisions
to
reflect
these
changes.
Manufacturers
receive
certification
and
compliance
services
by
initiating
a
certification
request
and
an
application
for
certification.
4
By
determining
the
EPA
activities
and
associated
costs
within
the
MVECP,
we
calculated
a
fee
for
each
certification
request
type.
The
certification
request
types
are
described
in
more
detail
later
in
this
proposal.
Each
request
for
a
certificate
of
conformity
within
a
certification
request
type
is
potentially
subject
to
an
equal
amount
of
EPA
expenditure
related
to
the
applicable
certification,
fuel
economy,
SEA,
and
in
use
compliance
monitoring
and
audit
programs,
thus
EPA
believes
it
is
fair
and
equitable
to
calculate
fees
in
a
manner
whereby
the
cost
for
each
certificate
within
a
certification
request
type
is
the
same.
In
summary,
today
we
are
proposing
to
collect
fees
under
the
authority
of
the
IOAA
and
section
217
of
the
CAA
to
ensure
that
the
MVECP
is
self
sustaining
to
the
extent
possible.
In
essence,
this
proposed
regulation
will
require
those
manufacturers
specially
benefitting
from
the
services
provided
under
the
MVECP
to
bear
the
EPA's
cost
of
administering
the
program
on
their
behalf.
B.
What
Programs
Are
Covered
by
the
Fees?
EPA
has
a
number
of
different
services
it
provides
under
the
MVECP.
Under
the
MVECP,
fees
are
collected
to
recover
the
cost
of
services
associated
with:
(1)
New
vehicle
or
engine
certification;
(2)
new
vehicle
or
engine
compliance
monitoring
(including
selective
enforcement
auditing
(SEA)
and
production
line
testing
(PLT));
(3)
in
use
vehicle
or
engine
compliance
monitoring
and
testing;
and
(4)
the
fuel
economy
program.
These
services
include:
pre
production
certification
assistance;
confirmatory
testing
of
vehicles;
laboratory
correlation;
certification
compliance
audits
and
investigations;
conducting
fuel
economy
selection,
testing,
and
labeling;
selective
enforcement
audits
(SEA);
providing
manufacturers
and
ICIs
with
CAFE
´
calculations;
monitoring
of
in
use
vehicles
and
engines;
monitoring/
data
review
of
mandatory
production
line
and
in
use
testing;
and
Agency
run
inuse
surveillance
and/
or
recall
tests.
The
proposed
fees
reflect
the
cost
of
these
activities.
In
addition
to
those
services
just
mentioned,
EPA
also
conducts
activities
for
which
a
fee
is
not
being
proposed
at
this
time.
These
activities
include
regulation
development
and
policy,
emission
factors
determination,
air
quality
assessment
and
analysis,
air
quality
initiatives,
and
support
of
state
inspection
and
maintenance
(I/
M)
programs.
Under
the
currentMVECP
fees
regulation
these
activities
are
not
covered.
II.
Background
A.
Basis
for
Action
Under
the
Clean
Air
Act
and
Other
Legal
Authority
We
are
amending
current
fees
and
setting
new
fees
within
the
MVECP
fees
regulation
under
the
authority
of
section
217
of
the
Clean
Air
Act
(CAA).
EPA
is
authorized
under
section
217
of
the
CAA,
as
amended
by
Public
Law
101–
549,
section
225,
to
establish
fees
for
specific
services
it
provides
to
vehicle
and
engine
manufacturers.
The
CAA
provides
in
pertinent
part:
(a)
Fee
Collection.—
Consistent
with
section
9701
of
title
31,
United
States
Code,
the
Administrator
may
promulgate
(and
from
time
to
time
revise)
regulations
establishing
fees
to
recover
all
reasonable
costs
to
the
Administrator
associated
with—
(1)
New
vehicle
or
engine
certification
under
section
206(
a)
or
part
C,
(2)
New
vehicle
or
engine
compliance
monitoring
and
testing
under
section
206(
b)
or
part
C,
and
(3)
In
use
vehicle
or
engine
compliance
monitoring
and
testing
under
section
207(
c)
or
part
C;
The
Administrator
may
establish
for
all
foreign
and
domestic
manufacturers
a
fee
schedule
based
on
such
factors
as
the
Administrator
finds
appropriate
and
equitable
and
nondiscriminatory,
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Federal
Register
/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
5
See
http://
www.
whitehouse.
gov/
omb/
circulars/
a025/
a025.
html
the
text
of
which
is
also
contained
in
the
EPA
Air
Docket
No.
A–
2001–
09.
6
See
57
FR
30055
(July
7,
1992).
7
See
Engine
Manufacturers
Association
v.
EPA,
20
F.
3d
1177
(D.
C.
Cir.
1994).
8
42
U.
S.
C.
7547.
including
the
number
of
vehicles
or
engines
produced
under
a
certificate
of
conformity.
In
the
case
of
heavy
duty
and
vehicle
manufacturers,
fees
shall
not
exceed
a
reasonable
amount
to
recover
an
appropriate
portion
of
such
reasonable
costs.
EPA
is
also
authorized
under
the
Independent
Offices
Appropriation
Act
of
1952
to
establish
fees
for
Government
services
and
things
of
value
that
it
provides.
This
provision,
originally
designated
as
31
U.
S.
C.
483(
a),
was
codified
into
law
on
September
13,
1982,
at
31
U.
S.
C.
9701.
This
provision
encourages
Federal
regulatory
agencies
to
recover,
to
the
fullest
extent
possible,
costs
provided
to
identifiable
recipients.
The
relevant
text
states:
(a)
It
is
the
sense
of
Congress
that
each
service
or
thing
of
value
provided
by
an
agency
*
*
*
to
a
person
*
*
*
is
to
be
self
sustaining
to
the
extent
possible.
(b)
The
head
of
an
agency
*
*
*
may
prescribe
regulations
establishing
the
charge
for
a
service
or
thing
of
value
provided
by
the
agency.
Regulations
prescribed
by
the
heads
of
executive
agencies
are
subject
to
policies
prescribed
by
the
President
and
shall
be
uniform
as
practicable.
Each
charge
shall
be—
(1)
Fair;
and
(2)
Based
on—
(A)
Costs
to
the
Government;
(B)
The
value
of
the
service
or
thing
to
the
recipient;
(C)
Public
policy
or
interest
served;
and
(D)
Other
relevant
facts.
EPA
also
intends
to
follow,
and
is
guided
by,
the
Office
of
Management
and
Budget's
Circular
No.
A–
25
(Revised),
5
which
establishes
Federal
policy
regarding
fees
assessed
for
Government
services
and
for
the
sale
or
use
of
Government
goods
or
resources
and
was
issued
under
the
authority
of
the
IOAA.
Included
in
the
Circular's
objectives
are
ensuring
that
each
service
provided
by
an
agency
to
a
specific
recipient
be
self
sustaining,
and
to
promote
the
efficient
allocation
of
the
Nation's
resources
by
establishing
charges
for
special
benefits
provided
to
a
recipient
that
are
at
least
as
great
as
costs
to
the
Government
of
providing
the
special
benefits.
Subsequent
to
EPA's
initial
rulemaking
that
set
forth
the
fees
for
the
MVECP,
6
the
U.
S.
Court
of
Appeals
for
the
D.
C.
Circuit,
upon
reviewing
EPA's
authority
to
collect
fees
under
the
IOAA
and
section
217,
held
that
for
the
regulated
industry,
a
certificate
of
conformity
is
deemed
a
benefit
specific
to
the
recipient,
for
purposes
of
the
provision
of
the
Independent
Offices
Appropriation
Act
(IOAA);
thus
authorizing
a
federal
agency
to
collect
fees
from
a
beneficiary
of
service
or
thing
of
value
the
federal
agency
provides
in
order
to
make
the
service
self
sustaining
to
the
extent
possible.
7
The
court
held
that
because
the
Compliance
Program
confers
a
specific,
private
benefit
upon
the
manufacturers,
the
EPA
can
lawfully
recoup
from
them
the
reasonable
cost
of
the
program.
Court
decisions
have
also
provided
guidance
on
the
criteria
to
be
used
in
implementing
fee
schedules
under
the
IOAA
when
user
fees
are
being
charged
for
special
benefits.
See
National
Cable
Television
Ass'n
v.
Federal
Communications
Comm'n,
554
F.
2d
1094
(D.
C.
Cir.
1976);
Electronic
Industries
Association
v.
Federal
Communications
Comm'n,
554
F.
2d
1109
(D.
C.
Cir.
1976);
and
Capital
Cities
Communications,
Inc.
v.
Federal
Communications
Comm'n,
554
F.
2d
1135
(D.
C.
Cir.
1976).
These
decisions
indicate
the
following
factors
are
relevant
in
developing
a
fee
program:
1.
An
agency
may
impose
a
reasonable
charge
on
recipients
for
an
amount
of
work
from
which
the
recipients
benefit.
The
fees
must
be
for
specific
services
to
specific
persons.
2.
The
fees
may
not
exceed
the
cost
to
the
agency
in
rendering
the
service.
3.
An
agency
may
recover
the
full
cost
of
providing
a
service
to
an
identifiable
beneficiary
regardless
of
the
incidental
public
benefits
which
may
flow
from
the
service.
An
agency,
when
it
proposes
a
fee
pursuant
to
the
IOAA
to
recover
special
benefits,
should
also
address
the
following
matters
set
out
in
Electronic
Industries
Ass'n
v.
Federal
Communications
Comm'n,
554
F.
2d
at
1117:
1.
The
agency
must
justify
the
assessment
of
a
fee
by
a
clear
statement
of
the
particular
service
or
benefit
for
which
it
seeks
reimbursement.
2.
The
agency
must
calculate
the
cost
basis
for
each
fee
by:
a.
Allocating
specific
expenses
of
the
cost
basis
of
the
fee
to
the
smallest
practical
unit;
b.
Excluding
expenses
that
serve
an
independent
public
interest;
and
c.
Providing
public
explanation
of
the
specific
expenses
included
in
the
cost
basis
for
a
particular
fee,
and
an
explanation
of
the
criteria
used
to
include
or
exclude
a
particular
item.
3.
The
fee
must
be
set
to
return
the
cost
basis
at
a
rate
that
reasonably
reflects
the
cost
of
the
services
performed
and
valued
conferred
on
the
payor.
As
detailed
in
today's
proposal
and
in
the
Motor
Vehicle
and
Engine
Compliance
Program
Cost
Analysis,
EPA
believes
it
has
fulfilled
all
of
these
aims
in
developing
this
proposal.
EPA
believes
that
all
the
fees
included
in
this
proposal
are
justified
based
on
the
tests
for
fee
recovery
relating
to
special
benefits
applicable
under
IOAA.
In
addition,
EPA
believes
that
CAA
section
217
gives
EPA
additional
support
for
imposing
fees
for
the
programs
specified
in
that
section.
Section
217
authorizes
EPA
to
establish
fees
``[
c]
onsistent''
with
the
IOAA
``
to
recover
all
reasonable
costs
to
the
Administrator
associated''
with
certification,
SEA
testing
and
in
use
compliance
programs.
This
section
establishes
Congress'
position
that
the
specified
programs
provide
the
type
of
benefit
and
have
the
type
of
costs
that
are
appropriately
recoverable
under
the
IOAA.
In
addition
to
collecting
fees
for
new
highway
vehicles
and
engines,
EPA
believes
section
217
also
authorizes
the
collection
of
fees
for
EPA
certification
and
compliance
activities
related
to
new
nonroad
vehicles
and
engines.
As
noted
above,
section
217
sets
forth
the
authority
for
EPA
to
collect
fees
for:
new
vehicle
or
engine
certification
activities
conducted
under
section
206(
a)
of
the
CAA,
new
vehicle
or
engine
compliance
monitoring
and
testing
under
section
206(
b)
of
the
CAA
(including
such
activities
as
SEA
and
PLT
testing),
and
in
use
vehicle
or
engine
compliance
monitoring
and
testing
under
section
207(
c)
of
the
CAA.
Section
213
of
the
CAA
8
creates
a
statutory
program
which
mirrors
that
Congress
created
for
the
regulation
of
new
highway
vehicles
and
engines.
The
nonroad
standards
created
under
section
213
are
in
fact
subject
to
the
same
requirements
(e.
g.,
sections
206,
207,
208,
and
209)
and
implemented
in
the
same
manner
(including
certification,
SEA,
and
in
use
testing)
under
the
same
sections
(as
those
referenced
in
section
217)
as
regulations
for
new
highway
vehicles
and
engines
under
section
202
(with
modifications
to
the
implementing
nonroad
regulations
as
the
Administrator
deems
appropriate).
Therefore,
because
EPA's
certification
and
compliance
activities
related
to
new
nonroad
vehicles
and
engines
are
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Federal
Register
/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
9
CAA
Sec.
213(
d)
requires
that
the
standards
for
nonroad
engines
or
vehicles
under
Sec.
213
be
enforced
in
the
same
manner
as
standards
prescribed
under
section
202.
As
such,
EPA
applies
the
provisions
of
Sec.
203
to
nonroad
vehicles
and
engines.
10
See
CAA
Sec.
202(
b)(
3).
It
is
also
defined
in
the
applicable
Title
40
regulations
for
the
applicable
class
of
vehicle
or
engine
covered.
pursuant
to
sections
206
and
207
and
because
the
text
of
section
217
authorizes
the
collection
of
fees
for
activities
under
such
sections
without
limiting
it
to
new
highway
vehicles
and
engines,
EPA
believes
collecting
fees
for
new
nonroad
vehicles
and
engines
certification
and
compliance
activities
under
section
217
is
appropriate
as
an
additional
compliance
requirement.
EPA
also
believes
that
the
IOAA
creates
an
additional
and
independent
authority
for
EPA
to
collect
such
fees
due
to
the
same
special
and
unique
benefits
that
manufacturers
of
both
new
highway
and
nonroad
vehicle
and
engine
manufacturers
receive
from
EPA
under
the
certification
and
compliance
services.
Moreover,
by
providing
authority
to
recover
``
all
reasonable
costs
*
*
*
associated''
with
the
programs,
Congress
has
given
EPA
authority
to
impose
fees
on
a
basis
that
can
extend
beyond
the
specific
criteria
used
in
interpreting
the
IOAA.
See
Florida
Power
&
Light
Co.
v.
United
States,
846
F.
2d
765
(DC
Cir.
1988),
cert
denied,
109
S.
Ct.
1952
(1989).
If
any
commenters
believe
that
any
fee
proposed
by
EPA
for
recovery
for
the
programs
identified
in
CAA
section
217
is
not
recoverable
under
the
IOAA,
the
commenters
are
requested
to
discuss
whether,
in
their
view,
the
fees
would
be
recoverable
under
the
``
all
reasonable
costs
associated''
test
found
in
section
217
and
should
do
so
in
light
of
the
court
decision
noted
above.
Additionally,
if
any
commenters
believe
that
any
fee
proposed
by
EPA
for
recovery
is
not
identified
or
authorized
by
section
217,
the
commenters
are
requested
to
identify
which
portions
of
the
fee
program
are
not
identified
or
authorized
and
why
the
provisions
of
the
IOAA
would
not
provide
such
authorization.
As
noted
in
more
detail
in
the
reduced
fee
section
of
today's
preamble,
EPA
also
believes
that
section
217
and
the
IOAA
allow
the
Agency
to
set
fees
for
specific
small
volume
engine
families
and
invites
comments
on
this
as
well.
B.
How
Do
EPA's
Compliance
Programs
Work?
Certification
Section
203(
a)
9
of
the
CAA
requires
that
a
manufacturer
of
new
motor
vehicles
and
new
motor
vehicle
engines
obtain
a
certificate
of
conformity
prior
to
the
distribution
into
commerce,
sale,
or
offering
for
sale,
or
the
introduction,
or
delivery
for
introduction,
into
commerce,
within
the
United
States
of
such
new
motor
vehicles
or
engines.
The
certificate
of
conformity
covers
a
defined
group
of
vehicles
or
engines
and
has
a
specified
duration
referred
to
as
the
model
year
(MY).
``
Model
year''
is
defined
in
the
CAA
10
to
be
the
manufacturer's
annual
production
period
(as
determined
by
the
Administrator)
which
includes
January
1
of
the
calendar
year.
If
the
manufacturer
has
no
annual
production
period,
the
term
``
model
year''
means
the
calendar
year.
For
some
industries,
such
as
the
light
duty
vehicle
industry,
the
model
year
typically
begins
before
the
calendar
year;
for
example,
the
2003
model
year
might
run
from
August
1,
2002
to
July
31,
2003.
For
other
industries
it
is
synonymous
with
the
calendar
year
and
runs
from
January
1
to
December
31.
In
some
cases
a
model
year
may
be
longer
than
twelve
months.
However,
in
all
cases
the
model
year
refers
to
an
annual
production
period.
Consequently
new
certificates
must
be
issued
each
year.
For
marine
vessels
covered
under
the
voluntary
IMO
program,
a
letter
of
compliance
is
issued
instead
of
a
certificate
of
compliance.
For
purposes
of
the
fee
rulemaking,
the
letter
of
compliance
will
be
treated
the
same
as
a
certificate
of
compliance.
In
this
case
a
request
for
certification
shall
mean
a
request
for
the
voluntary
IMO
letter
of
compliance.
Although
such
letters
of
compliance
are
not
a
requirement
under
title
II
of
the
CAA,
EPA
believes
that
it
provides
special
and
unique
benefits
to
the
manufacturers
of
marine
vessels
that
seek
and
receive
EPA
services
in
order
to
receive
letters
of
compliance.
As
explained
above,
EPA
believes
that
the
IOAA
provides
the
basis
by
which
to
collect
fees
for
this
activity.
As
further
discussed
below,
EPA
is
also
considering
and
inviting
comment
on
whether
to
finalize
fees
for
industry
categories
that
may
not
yet
have
final
emission
standards
regulations,
as
part
of
the
overall
final
fees
regulation
promulgated
from
today's
proposal
or
to
issue
such
fees
requirements
at
the
time
the
emission
standards
themselves
become
final.
EPA
anticipates
promulgating
fees
for
marine
vessels
covered
under
the
voluntary
IMO
program
as
part
of
final
fees
regulation
associated
with
today's
proposal.
The
group
of
vehicles
or
engines
covered
by
a
certificate
of
conformity
is
called
either
an
``
engine
family''
or
a
``
test
group''
depending
on
the
applicable
class
of
vehicles
or
engines.
While
the
terminology
changes
between
classes,
the
basic
certification
unit
(or
group)
is
designed
to
accomplish
the
same
purpose.
Only
vehicles
or
engines
which
are
expected
to
exhibit
similar
emission
characteristics
and
deterioration
are
combined
together
into
a
single
group.
Table
II.
B–
1,
below,
summarizes
the
name
of
these
basic
certification
groups,
the
location
of
the
general
certification
and
compliance
program
rules,
and
the
typical
number
of
certificates
which
are
issued
for
each
class
of
vehicles
and
engines
covered
by
this
proposal.
The
number
of
certificates
in
the
following
table
are
projections.
If
there
is
a
certification
program
currently
active
for
the
class,
the
number
of
certificates
are
based
on
latest
actual
numbers.
For
other
industries,
the
number
of
certificates
is
based
on
projections
gathered
from
the
discussions
with
manufacturers
and
information
presented
when
the
Agency
proposed
and/
or
finalized
the
rules
pertaining
to
the
industry.
TABLE
II.
B–
1.—
CLASSES
OF
CERTIFICATES,
THEIR
UNIT,
NUMBER
OF
CERTIFICATES
AND
REGULATIONS
Class
of
vehicles/
engines
Basic
certification
unit
Number
of
certs
Location
or
future
location
of
general
certification
regulations
Light
Duty
Vehicles
&
Trucks
(LD)
....................................
Test
Group
.........................................
411
40
CFR
Part
86,
Subpart
S.
Highway
motorcycles
(MC)
................................................
Engine
Family
.....................................
174
40
CFR
Part
86,
Subpart
E
Heavy
duty
Highway
Engines
............................................
Engine
Family
.....................................
130
40
CFR
Part
86,
Subpart
A.
Nonroad
CI
Engines
...........................................................
Engine
Family
.....................................
603
40
CFR
Part
89.
Heavy
duty
Vehicle
Evap
...................................................
Evap
Family
........................................
42
40
CFR
Part
86,
Subpart
M.
Marine
SI
Outboard/
PWC
..................................................
Engine
Family
.....................................
155
40
CFR
Part
91.
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Federal
Register
/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
TABLE
II.
B–
1.—
CLASSES
OF
CERTIFICATES,
THEIR
UNIT,
NUMBER
OF
CERTIFICATES
AND
REGULATIONS—
Continued
Class
of
vehicles/
engines
Basic
certification
unit
Number
of
certs
Location
or
future
location
of
general
certification
regulations
Marine
CI
a
>
37
kW
..........................................................
Engine
Family
.....................................
40
40
CFR
Part
94.
International
Maritime
Organization
b
.................................
Engine
Family
.....................................
9
Small
Nonroad
SI
...............................................................
Engine
Family
.....................................
546
40
CFR
Part
90
Locomotives
&
Locomotive
Engines
..................................
Engine
Family
.....................................
10
40
CFR
Part
92.
Large
Nonroad
SI
(>
19
kW)
c
............................................
Engine
Family
.....................................
50
40
CFR
Part
1048.
Recreational
Marine
CI>
37
kW
c
........................................
Engine
Family
.....................................
25
40
CFR
Part
94.
Marine
SI
Inboard
/Sterndrive
d
..........................................
Engine
Family
.....................................
50
40
CFR
Part
1045.
Recreational
c
(including
Off
road
MC,
ATV's,
Snowmobiles
Engine
Family
.....................................
100
40
CFR
Part
1051.
(
a
The
rules
for
these
classes
are
finalized
but
not
yet
implemented;
numbers
are
estimates.
(
b
The
International
Maritime
Organization
(IMO)
has
established
procedures
for
obtaining
a
letter
of
compliance
with
the
MARPOL
73/
78
Annex
6
which
have
not
yet
been
ratified
by
the
U.
S.
A.
Manufacturers
of
such
engines
may
voluntarily
comply
with
these
requirements.
EPA
has
agreed
to
issue
a
letter
of
compliance
for
such
manufacturers
who
voluntarily
comply
with
the
MARPOL
73/
78
Annex
6
emission
requirements.
(
c
The
rules
for
these
classes
are
proposed
but
not
yet
finalized;
numbers
are
estimates.
(
d
The
rules
for
these
classes
are
under
development
but
not
yet
finalized;
numbers
are
estimates.
To
obtain
a
certificate,
the
manufacturers
must
perform
the
required
testing
and
fulfill
other
requirements
specified
in
the
applicable
regulations
listed
in
the
above
table.
When
the
manufacturer
has
satisfied
itself
that
it
has
complied
with
all
the
requirements,
it
submits
an
application
for
certification
for
review
by
the
Agency.
EPA
processes
these
applications
and
makes
a
determination
of
conformance
with
the
CAA
and
the
applicable
regulations.
If
the
vehicle
or
engine
satisfies
the
prescribed
emission
standards
and
otherwise
complies
with
the
applicable
provisions
of
the
regulations,
EPA
issues
a
certificate
of
conformity
for
the
group
(e.
g.,
engine
family).
The
certification
process
includes,
but
is
not
limited
to,
review
of
the
application
for
certification,
review
of
the
manufacturer's
durability
and
deterioration
determination,
review
of
emission
data
for
test
engine
selection,
review
of
the
manufacturer's
justification
that
auxiliary
emission
control
devices
(AECDs)
are
not
defeat
devices,
and
certification
request
processing
and
computer
support.
Other
activities
related
to
the
certification
process
include
auditing
the
applicant's
testing
and
data
collection
procedures,
laboratory
correlation,
and
EPA
confirmatory
testing
and
compliance
inspections
and
investigations
related
to
certification.
The
certification
program
also
covers
ICI
manufacturers
review
and
processing
and
approval
for
final
importation
of
vehicles
and
engines.
SEA
and
PLT
EPA
conducts
new
vehicle
or
engine
compliance
monitoring
in
the
form
of
Agency
conducted
Selective
Enforcement
Audits
(SEA)
or
manufacturer
conducted
production
line
testing
(PLT)
programs.
The
purpose
of
these
programs
is
to
assure
that
the
vehicles
that
are
actually
being
produced
comply
with
the
emission
standards.
The
certification
portion
of
the
MVEPC
demonstrates
that
the
vehicles
are
designed
to
pass
the
standards
for
the
vehicles'
useful
life
through
testing
of
pre
production
prototype
vehicles
or
engines.
The
SEA
or
PLT
testing
also
serves
as
some
additional
proof
of
in
use
compliance
for
certain
programs
(where
in
use
testing
is
more
difficult)
by
addressing
the
prototype
to
production
effects
on
emissions.
SEA
activities
include
the
selection
and
testing
of
vehicles
and
engines
off
the
assembly
line
at
various
production
plants
around
the
world
to
determine
compliance
with
emission
standards.
PLT
programs
require
the
manufacturer
(rather
than
EPA)
to
test
a
percentage
of
engines
as
they
leave
the
production
line.
In
either
case,
if
a
substantial
number
of
vehicles
or
engines
fail
to
meet
the
emission
standards
the
manufacturer
could
be
required
to
cease
production
of
the
failing
vehicles
until
the
manufacturer
had
demonstrated
that
a
new
version
of
the
vehicle
complied
with
the
standard.
The
manufacturer
may
also
be
required
to
recall
(see
discussion
below
for
the
meaning
of
a
recall)
failing
vehicles
or
engines
which
have
been
introduced
into
commerce.
In
Use
Programs
EPA
further
ensures
compliance
with
the
CAA
through
a
variety
of
in
use
testing
and
in
use
defect
investigations.
These
activities
include
investigations
into
potential
emission
related
defects
vehicles
and
engines
and
various
types
of
in
use
compliance
programs.
In
use
compliance
activities
ensure
that
vehicles
and
engines
continue
to
meet
emission
standards
throughout
their
useful
life.
The
type
of
in
use
programs
conducted
by
the
Agency
vary
between
the
classes
of
vehicles
and
engines.
These
variations
contribute
to
the
different
fee
amounts
which
the
Agency
is
proposing
for
different
classes.
(See
Section
IV
of
the
Motor
Vehicle
and
Engine
Compliance
Program
Cost
Analysis,
available
in
the
docket,
for
details
of
how
the
Agency
calculated
the
fee
amounts).
In
all
cases,
should
the
Administrator
of
EPA
determine,
by
whatever
means,
that
a
substantial
number
of
any
class
or
category
of
vehicles
or
engines,
although
properly
maintained
and
used,
do
not
comply
with
their
applicable
regulations
when
in
actual
use
throughout
their
useful
life,
the
Agency
requires
the
manufacturer
to
submit
a
plan
to
remedy
the
nonconformity
of
the
vehicles
or
engines.
The
implementation
of
the
plan
to
remedy
vehicles
is
called
a
recall.
The
Agency
uses
data
from
Selective
Enforcement
Audits
(SEA),
manufacturer
supplied
production
line
testing
(PLT),
Agency
run
in
use
surveillance
and/
or
recall
tests
conducted
on
a
dynamometer
and/
or
on
the
road
,
manufacturer
run
in
use
verification
program
(IUVP)
testing,
manufacturer
run
engine
testing
and
manufacturer
supplied
defect
reports
to
evaluate
in
use
emissions
performance
for
the
various
classes
of
engines
and
vehicles
which
are
certified.
For
recall
and
surveillance
testing,
the
Agency
recruits
vehicles
from
their
owners
and
conducts
tests
either
on
a
dynamometer
or
on
the
road
using
mobile
emission
measurement
equipment.
The
IUVP
program
only
applies
to
light
duty
vehicles
and
medium
duty
passenger
vehicles;
it
requires
manufacturers
to
conduct
a
specified
amount
of
testing
on
in
use
vehicles
which
they
procure
from
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Federal
Register
/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
11
Current
CAFE
´
standards
are
27.5
mpg
for
cars
and
20.7
mpg
for
trucks.
12
Current
fines
are
$5.50
per
tenth
of
an
mpg
beneath
the
standard
multiplied
by
the
total
number
of
vehicles
in
the
fleet
average.
Manufacturers
are
allowed
to
carry
forward
or
carry
back
credits
up
to
three
years
to
offset
short
falls
calculated
in
other
years.
owners.
Defect
reporting
(DR)
generally
requires
manufacturers
to
notify
the
Agency
when
an
emission
related
defect
occurs
on
more
than
25
vehicles
or
engines
in
use.
The
specific
programs
currently
employed
by
the
Agency
to
assure
inuse
compliance
for
the
various
classes
of
vehicles
and
engines
are
summarized
in
the
following
paragraphs.
This
list
is
being
provided
to
document
the
activities
considered
in
the
analysis
for
proposed
fees.
The
Agency
may
at
any
time
perform
other
investigations
and/
or
use
other
sources
of
data
to
make
compliance
determinations
of
in
use
vehicles
and
engines.
The
selection
of
which
in
use
tools
are
used
by
the
Agency
for
each
industry
is
based
on
the
in
use
compliance
needs.
Each
of
the
industries
are
subject
to
different
regulations
which
establish
different
requirements.
When
the
applicable
regulations
require
the
manufacturer
to
supply
some
form
of
in
use
data,
production
line
data,
or
aged
engine
testing;
this
information
makes
it
easier
for
the
Agency
to
monitor
compliance
in
actual
use.
Consequently
for
those
industries
the
Agency
can
spend
less
of
its
own
effort
to
collect
data.
For
the
light
duty
and
highway
motorcycle
programs,
the
Agency
conducts
an
in
use
surveillance
and
recall
program
where
individual
owner's
vehicles
are
recruited
and
tested
by
the
Agency.
This
data
is
augmented
by
manufacturer
run
in
use
data
to
fulfill
the
requirements
of
the
inuse
verification
program
(IUVP)
for
light
duty
vehicles.
The
Agency
also
reviews
defect
reports
submitted
by
the
manufacturers
for
potential
in
use
problems.
Although
there
is
authority
for
the
Agency
to
conduct
SEA
testing,
EPA
does
not
currently
conduct
SEA
testing
for
light
duty
vehicles.
For
heavy
duty
highway
vehicles
and
nonroad
vehicles,
the
Agency
conducts
SEAs
and
on
the
road
emission
measurements
of
engines
installed
in
inuse
vehicles.
EPA
may
also
remove
engines
from
heavy
duty
highway
and
nonroad
vehicles
for
laboratory
testing
when
problems
are
found
using
onvehicle
measurement
equipment.
For
other
classes
of
engines
such
as
marine
SI
outboards
and
personal
water
craft
(PWC),
manufacturers
are
required
to
age
engines
in
fleets
and
then
perform
testing
on
the
engine.
C.
How
Does
This
Rulemaking
Affect
the
Proposed
Recreational
Vehicles
Rule
and
Future
Rules?
We
are
proposing
fees
for
Large
Nonroad
SI
(>
19
kW),
Recreational
Marine
CI,
Marine
SI
Inboard
and
Sterndrive
engines,
Recreational
engines
(including
Off
Road
Motorcycles
(MC),
All
terrain
Vehicles
(ATVs),
and
Snowmobiles)
even
though
emission
regulations
currently
do
not
exist
for
those
classes.
As
discussed
previously,
the
Agency
has
proposed
and
is
in
the
process
of
finalizing
emission
standards
(See
66
FR
51098,
(October
10,
2001))
or
is
in
the
process
of
preparing
to
propose
emission
standards
for
these
industries.
The
fees
listed
in
the
Table
III.
D–
1,
below,
will
apply
only
after
the
applicable
regulations
are
effective
for
these
classes
of
engines.
The
fees
are
due
only
when
a
manufacturer
is
making
a
request
for
certification.
We
are
proposing
fees
for
these
classes
at
this
time
because
enough
is
known
of
the
anticipated
Agency
costs
for
the
MVECP
for
these
programs
and
the
projected
number
of
certificates
to
accurately
calculate
proposed
fees.
The
fees
proposed
for
these
programs
represent
a
reasonable
but
somewhat
conservative
and
low
estimate
Agency
cost
and
assume
either
low
levels
of
EPA
monitoring
or
monitoring
through
manufacturer
run
PLT
and
in
use
testing.
In
the
event
that
the
programs
for
these
classes
of
engines
significantly
change,
the
Agency
will
revise
the
applicable
fee
by
a
separate
regulation.
Today's
proposal
of
potential
fees
for
these
classes
in
no
way
prejudges
the
outcome
of
the
ongoing
emission
standards
rulemakings.
D.
How
Does
the
Fuel
Economy
Program
Work?
The
Agency
is
proposing
to
continue
the
current
provisions
which
incorporate
the
fuel
economy
program
costs
into
a
single
fee
due
at
the
time
of
certification
for
light
duty
vehicles.
The
fuel
economy
program
applies
to
light
duty
vehicles
only.
There
are
three
separate
programs:
fuel
economy
labeling
and
Guide
publication,
gas
guzzler
tax,
and
corporate
average
fuel
economy
(CAFE
´
).
The
fuel
economy
labeling
program
is
a
public
information
program
which
is
designed
to
provide
the
public
accurate
fuel
economy
information
for
comparison
purposes.
All
light
duty
vehicles
are
required
to
have
a
fuel
economy
label
before
they
can
be
introduced
into
commerce.
The
label
values
are
also
published
in
the
Fuel
Economy
Guide
(a
joint
publication
with
the
Department
of
Energy,
DOE)
and
published
on
the
internet
on
two
web
sites
(http://
www.
fueleconomy.
gov
and
http://
www.
epa.
gov/
autoemissions).
EPA
reviews
manufacturers'
testing,
conducts
confirmatory
testing,
audits
the
manufacturers'
label
calculations,
and
determines
the
classification
of
vehicles.
EPA
receives
approximately
1000
label
calculations
in
a
typical
model
year.
The
fuel
economy
label
program
is
mandated
by
the
Energy
Policy
and
Conservation
Act
(EPCA),
42
U.
S.
C.
620,
and
is
codified
in
regulations
in
40
CFR
part
600.
The
gas
guzzler
tax
program
is
designed
to
discourage
the
purchase
of
vehicles
with
particularly
poor
fuel
economy
through
a
tax
program
administered
by
the
Internal
Revenue
Service
(IRS).
Vehicles
with
a
combined
fuel
economy
value
below
22.5
mpg
must
pay
a
tax
which
starts
at
the
rate
of
$1000
per
vehicle.
EPA
determines
potential
gas
guzzlers
as
part
of
the
labeling
process;
the
final
determination
of
the
tax
liability
is
made
by
the
IRS.
The
gas
guzzler
program
is
mandated
by
the
Gas
Guzzler
Tax
Law
and
is
codified
in
regulations
in
40
CFR
part
600.
The
CAFE
´
program
is
designed
to
reduce
fuel
consumption,
reduce
dependence
on
foreign
oil,
and
to
reduce
greenhouse
gas
emissions
from
new
light
duty
vehicles.
Manufacturers
are
required
to
meet
specified
average
fuel
economy
values.
Separate
values
are
specified
for
cars
and
trucks.
11
If
manufacturers
fail
to
meet
the
specified
standards
they
are
required
to
pay
a
fine.
12
The
Department
of
Transportation
(DOT)
administers
the
CAFE
´
program
and
collects
the
fines.
Many
additional
vehicle
tests
are
required
to
calculate
the
CAFE
´
values.
EPA
reviews
manufacturers'
testing
and
conducts
confirmatory
testing
as
necessary.
EPA
also
calculates
the
CAFE
´
values;
typically
50
CAFE
´
are
processed
each
year.
The
CAFE
´
program
is
mandated
by
the
Energy
Policy
and
Conservation
Act
(EPCA),
42
U.
S.
C.
620,
and
is
codified
in
regulations
in
40
CFR
part
600.
The
fuel
economy
and
light
duty
certification
program
have
substantial
overlap.
Both
programs
collect
fuel
economy
and
emissions
data.
Emissiondata
vehicles
provide
both
emissions
and
fuel
economy
data
on
engine
families
for
which
the
manufacturer
submits
a
certification
request.
Further,
fuel
economy
data
vehicles
are
tested
for
emissions
and
must
comply
with
the
emission
standards.
Only
then
can
the
fuel
economy
data
be
used
in
the
fuel
economy
program.
Thus,
each
program
generates
data
to
support
the
other
and
to
support
decisions
on
both
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/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
13
The
Motor
Vehicle
and
Engine
Compliance
Program
cost
is
contained
the
EPA
Air
docket
No.
A–
2001–
09
and
is
on
the
EPA
OTAQ
website.
certification
and
fuel
economy.
This
interrelationship
has
allowed
EPA
to
streamline
the
certification
program
and
procedures,
thereby
minimizing
costs
directly
incurred
by
the
industry
as
well
as
by
EPA.
Every
vehicle
that
is
certified
must
also
receive
a
fuel
economy
label
and
will
ultimately
be
included
in
the
CAFE
´
for
that
manufacturer.
For
these
reasons,
it
is
unnecessary,
for
fee
purposes,
to
distinguish
between
the
efforts
expended
on
fuel
economy
and
certification.
Consequently,
the
Agency
is
proposing
to
continue
its
current
practice
of
assessing
light
duty
vehicle
fees
based
on
certification
of
test
groups
and
including
the
costs
for
the
fuel
economy
activities
in
that
single
fee.
III.
Proposed
Fee
System
A.
What
Agency
Costs
Are
Recoverable
by
Fees?
Today's
notice
proposes
a
fee
program
to
recover
those
costs
incurred
by
EPA
in
conducting
the
MVECP
as
authorized
under
the
CAA
and
the
IOAA.
These
costs,
incurred
by
EPA
while
conducting
new
vehicle
and
engine
certification
which
includes
EPA
precertification
testing,
certification
compliance
audits
and
investigations,
fuel
economy
labeling,
CAFE
´
calculations
and
certificate
processing;
new
vehicle
and
engine
compliance
monitoring
and
testing
which
includes
SEAs
and
review
of
manufacturer
production
line
test
data;
and
in
use
vehicle
or
engine
compliance
monitoring
which
includes
testing
of
inuse
vehicles
and
engines,
in
use
audits
and
reviewing
manufacturers'
in
use
test
data.
The
proposed
fees
are
based
on
all
recoverable
direct
and
indirect
costs
associated
with
administering
these
activities.
Recoverable
costs
include
all
labor,
operating
and
program
costs
associated
with
the
activities
listed
above.
Direct
labor
costs
consist
of
the
personnel
compensation
or
pay
and
benefits
for
the
people
that
directly
administer
the
MVECP.
Indirect
labor
costs
consist
of
the
personnel
compensation
or
pay
and
benefits
for
the
people
that
support
the
employees
that
directly
administer
the
MVECP.
This
includes
support
staff,
computer
technicians
in
the
lab,
managers,
etc.
Operating
costs
include
all
costs
for
contracts,
parts,
supplies
and
infrastructure,
excluding
labor
costs
that
are
used
to
support
the
MVECP.
Examples
of
these
costs
include
travel
costs,
building
space,
computer
support
and
training
for
people
who
work
directly
on
the
MVECP.
Program
Costs
are
those
of
specific
compliance
activities
conducted
for
individual
industries.
These
include
the
costs
of
testing
either
at
the
NVFEL
or
at
a
contracted
facility,
engine
procurement
for
testing,
equipment
for
testing
and
equipment
used
in
analyzing
the
test
data.
The
overall
EPA
overhead
cost
is
also
included
in
the
analysis.
The
overall
EPA
overhead
costs
are
costs
incurred
by
other
parts
of
the
EPA
that
support
the
people
working
directly
on
the
MVECP.
See
the
Motor
Vehicle
and
Engine
Compliance
Program
Cost
Analysis
13
for
further
discussion.
These
costs
are
all
costs
of
providing
a
certificate
of
conformity
and
the
related
compliance
activities
which
allows
vehicle
and
engine
manufacturers
an
opportunity
to
introduce
such
vehicles
and
engines
into
commerce
within
the
United
States,
and
are,
therefore,
recoverable
by
fees
as
stated
in
the
Independent
Offices
Appropriation
Act
and
the
Office
of
Management
and
Budget's
Circular
No.
A–
25
discussed
in
Section
II.
A
above.
A
more
complete
description
of
the
agency
costs
that
are
recoverable
by
fees
is
in
the
Motor
Vehicle
and
Engine
Compliance
Program
Cost
Analysis,
Section
III.
A.
B.
What
OTAQ
Activities
Are
Not
Included
in
the
Agency's
Proposed
Fee
Program?
EPA
conducts
numerous
activities
related
to
certification
and
mobile
source
air
pollution
control,
in
general,
for
which
it
is
not
proposing
to
charge
a
fee
at
this
time.
These
activities
include
but
are
not
limited
to:
regulation
development,
emission
factor
testing,
air
quality
assessment,
support
of
state
inspection
and
maintenance
programs
and
research.
For
a
more
complete
description
of
OTAQ's
programs,
see
Section
II.
D
of
the
Motor
Vehicle
and
Engine
Compliance
Program
Cost
Analysis.
C.
How
Did
the
Agency
Analyze
the
Costs
of
the
Compliance
Programs?
The
proposed
fees
were
based
on
the
Agency's
projected
costs
of
providing
certification
and
related
compliance
programs
to
manufacturers
in
the
2003
model
year.
To
determine
these
projected
costs,
we
conducted
an
indepth
analysis
and
detailed
all
of
the
direct
and
indirect
costs
incurred
by
EPA
to
operate
the
MVECP.
Budget
data
from
2001
was
used
as
a
baseline
since
it
is
the
most
current
data
available.
Cost
estimates
for
future
compliance
programs
are
based
on
estimates
for
the
equipment,
labor
and
contract
needs
required
to
support
new
compliancerelated
programs
and
regulations
and
was
collected
through
discussions
with
senior
management.
The
full
discussion
of
the
methods
and
numbers
used
in
the
analysis
is
contained
in
the
``
Motor
Vehicle
and
Engine
Compliance
Program
Fees
Cost
Analysis.
''
EPA
determined
that
by
2003,
significant
laboratory
equipment
modernization
will
be
required
to
satisfactorily
test
vehicle
and
engines
at
the
lower
emission
levels
associated
with
Tier
2
and
new
diesel
engine
emission
standards.
Consequently,
an
appropriate
portion
of
the
cost
of
this
laboratory
upgrade
($
10
million
dollars
of
the
total
$14
million
dollar
upgrade)
was
included
in
the
cost
analysis
that
supports
this
proposal.
The
10
million
dollar
projected,
recoverable
cost
was
amortized
over
10
years
for
an
annual
cost
of
1
million
dollars.
Refer
to
the
Motor
Vehicle
and
Engine
Compliance
Program
Fees
Cost
Analysis
for
a
complete
discussion
of
the
laboratory
upgrade
costs.
EPA
is
exploring
the
possibility
of
a
partnership
with
industry
through
a
Cooperative
Research
and
Development
Agreement
(CRADA)
that
would
fully
develop
and
deploy
the
National
Low
Emission
Vehicle
Compliance/
Correlation
Test
Site
at
the
National
Vehicle
and
Fuel
Emissions
Laboratory.
A
CRADA
agreement
may
reduce
the
cost
of
the
laboratory
modernization.
In
the
event
the
EPA
enters
into
such
a
CRADA
and
the
agreement
results
in
a
significant
cost
savings,
EPA
may
adjust
the
fees
in
a
future
rulemaking.
However,
at
this
time
EPA
believes
it
is
appropriate
to
include
in
the
costs
to
be
recovered
by
today's
proposal,
those
projected
actual
costs
associated
with
the
laboratory
equipment
modification,
as
such
modification
is
necessary
to
conduct
the
MVECP.
Another
cost
that
was
projected
for
2003
is
the
cost
of
a
robust
highway
and
nonroad
engine
compliance
program,
discussed
in
more
detail
in
Section
V.
B
of
Motor
Vehicle
and
Engine
Compliance
Program
Cost
Analysis
available
in
the
docket.
These
costs
and
the
laboratory
modernization
costs
were
projected
for
2003
and
are
included
in
the
cost
study
because
they
will
be
incurred
by
the
EPA
as
part
of
the
MVECP
in
2003.
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Federal
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/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
D.
Proposed
Fee
Schedule
Today's
action
proposes
the
following
fees
for
each
certification
request:
TABLE
III.
D–
1—
PROPOSED
FEE
SCHEDULE
Category
Certificate
type
a
Fee
LD,
excluding
ICIs
.........................................................................
Fed
Certificate
.............................................................................
$33,911
LD,
excluding
ICIs
.........................................................................
Cal
only
Certificate
......................................................................
16,958
MDPV,
excluding
ICIs
...................................................................
Fed
Certificate
.............................................................................
33,911
MDPV,
excluding
ICIs
...................................................................
Cal
only
Certificate
......................................................................
16,958
Complete
SI
HDVs,
excluding
ICIs
...............................................
Fed
Certificate
.............................................................................
33,911
Complete
SI
HDVs,
excluding
ICIs
...............................................
Cal
only
Certificate
......................................................................
16,958
ICIs
for
the
following
industries:
LD,
MDPV,
or
Complete
SI
HDVs.
All
Types
......................................................................................
8,394
MC
HW,
including
ICIs
..................................................................
All
Types
......................................................................................
2,416
HD
HW,
including
ICIs
..................................................................
Fed
Certificate
.............................................................................
30,437
HD
HW,
including
ICIs
..................................................................
Cal
only
Certificate
......................................................................
827
HDV
(evap),
including
ICIs
...........................................................
Evap
Certificate
...........................................................................
827
NR
CI,
including
ICIs,
but
excluding
Locomotives,
Marine
and
Recreational
engines.
All
Types
......................................................................................
2,156
NR
SI,
including
ICIs
.....................................................................
All
Types
......................................................................................
827
All
Marine,
including
ICIs
..............................................................
All
Types
and
IMO
.......................................................................
827
All
Recreational
b
,
including
ICIs,
but
excluding
marine
engines
All
Types
......................................................................................
827
Locomotives,
including
ICIs
..........................................................
All
Types
......................................................................................
827
a
Fed
and
Cal
only
Certificate
and
IMO
is
defined
in
40
CFR
85.2402
b
Recreational
means
the
engines
subject
to
40
CFR
1051
which
includes
off
road
motorcycles,
all
terrain
vehicles
and
snowmobiles.
The
Agency
is
proposing
fees
for
Large
Nonroad
SI
(>
19
kW),
Recreational
Marine
CI,
Marine
SI
Inboard
and
Sterndrive
engines,
Recreational
engines
(including
Off
Road
MC,
ATV's,
and
Snowmobiles)
even
though
emission
regulations
currently
do
not
exist
for
those
classes.
The
Agency
has
proposed
(See
66FR
51098,
published
on
October
5,
2001)
or
is
in
the
process
of
proposing
regulations
for
these
classes.
The
fees
listed
in
the
above
table
will
apply
only
after
the
applicable
regulations
are
effective
for
these
classes
of
engines.
The
fees
are
due
only
when
a
manufacturer
is
making
a
request
for
certification.
It
may
be
worth
noting
again,
that
we
are
considering
whether
to
finalize
the
fees
for
these
yet
to
be
regulated
industries
within
the
final
rule
based
on
today's
fee
proposal
or
to
finalize
the
fees
associated
with
these
yet
to
be
regulated
industries
in
the
emission
regulations
covering
such
industries.
E.
Will
the
Fees
Automatically
Increase
To
Reflect
Future
Inflation?
One
factor
that
could
keep
EPA
from
recovering
the
full
cost
of
conducting
the
MVECP
is
inflation.
To
help
mitigate
the
effects
of
inflation,
the
Agency
is
proposing
that
fees
be
automatically
adjusted
annually
by
the
change
in
the
Consumer
Price
Index
starting
with
the
2005
model
year.
The
Agency
is
proposing
a
formula
for
manufacturers
to
use
to
calculate
the
applicable
calculate
beginning
with
the
2005
model
year.
Starting
with
the
2005
model
year,
fees
will
be
calculated
using
the
following
equation:
FeesMY
=
Feesbase
×
(CPIMY
¥
2/
CPI2002)
Where:
FeesMY
is
the
applicable
fee
for
the
model
year
of
the
certification
request.
Feesbase
is
the
applicable
fee
from
paragraph
(a)
of
this
section.
CPIMY
¥
2
is
the
consumer
price
index
for
all
U.
S.
cities
using
the
``
U.
S.
city
average''
area,
``
all
items''
and
``
not
seasonally
adjusted''
numbers
calculated
by
the
Department
of
Labor
listed
for
the
month
of
July
of
the
year
two
years
before
the
model
year.
(e.
g.,
for
the
2005
MY
the
CPI
used
in
the
equation
will
be
calculated
based
on
the
date
of
July,
2003).
CPI2002
is
the
consumer
price
index
for
all
U.
S.
cities
using
the
``
U.
S.
city
average''
area,
``
all
items''
and
``
not
seasonally
adjusted''
numbers
calculated
by
the
Department
of
Labor
for
December,
2002.
The
applicable
CPI
results
calculated
by
the
Department
of
Labor
are
currently
published
on
the
following
internet
address:
http://
stats.
bls.
gov/
cpihome.
htm
by
choosing
the
data
option
link
for
``
Consumer
Price
Index—
All
Urban
Consumers
(Current
Series)
'',
then
selecting
``
U.
S.
city
average''
area,
``
all
items''
and
``
not
seasonally
adjusted''.
The
Agency
invites
comment
on
alternate
ways
to
adjust
fees
for
inflation.
As
a
convenience
for
manufacturers
and
to
avoid
errors
in
calculation,
the
Agency
intends
to
provide,
via
a
guidance
letter,
a
listing
of
applicable
fees
calculated
from
the
above
equation
for
each
model
year
beginning
with
the
2005
model
year.
The
Agency
invites
comments
regarding
potential
procedures
for
notification
of
the
new
fee
amounts.
F.
Comments
on
the
Proposed
Fee
System
The
Agency
requests
comments
on
the
proposed
fee
system
including
the
``
Vehicle
and
Engine
Compliance
Program
Fees
Cost
Analysis,
''
recoverable
costs,
costs
not
recovered,
the
allocation
of
recoverable
costs
by
compliance
industry,
and
the
fees
per
certificate.
Comments
can
refer
to
this
preamble,
the
proposed
regulations
and
the
cost
analysis.
IV.
Fee
Collection
and
Transactions
A.
Procedure
for
Paying
Fees
Fees
must
be
paid
in
advance
of
receiving
a
certificate.
For
each
certification
request,
evidenced
by
an
application
for
certification,
ESI
data
sheet,
or
ICI
Carryover
data
sheet,
manufacturers
and
ICIs
will
submit
a
MVECP
Fee
Filing
Form
(filing
form)
and
the
appropriate
fee
in
the
form
of
a
corporate
check,
money
order,
bank
draft,
certified
check,
or
electronic
funds
transfer
[wire
or
Automated
Clearing
House
(ACH)],
payable
in
U.
S.
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Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
14
Typically,
this
will
be
the
first
February
15
after
a
certificate
expires.
Certificates
generally
expire
on
December
31
of
the
model
year.
dollars,
to
the
order
of
the
U.
S.
Environmental
Protection
Agency.
The
filing
form
and
accompanying
fee
will
be
sent
to
the
address
designated
on
the
filing
form.
EPA
will
not
be
responsible
for
fees
received
in
other
than
the
designated
location.
Applicants
will
continue
to
submit
the
application
for
certification
to
the
National
Vehicle
and
Fuel
Emission
Laboratory
(NVFEL)
in
Ann
Arbor,
Michigan
or
to
the
Engine
Programs
Group
in
Washington,
DC.
To
ensure
proper
identification
and
handling,
the
check
or
electronic
funds
transfer
and
the
accompanying
filing
form
will
indicate
the
manufacturer's
corporate
name,
the
EPA
standardized
test
group
or
engine
family
name.
The
full
fee
is
to
accompany
the
filing
form.
Partial
payments
or
installment
payments
will
not
be
permitted.
If
submitting
a
wire
or
an
ACH
payment
the
full
fee
payment
does
not
include
the
extra
fee
a
banking
institution
may
charge
to
process
the
wire
or
ACH.
The
Agency
invites
comment
on
methods
of
streamlining
the
fee
payment
process
while
maintaining
the
requirement
that
fees
are
paid
in
advance
of
certification
services.
B.
What
Is
the
Implementation
Schedule
for
Fees?
The
fee
schedule
proposed
today
will
apply
to
2003
and
later
model
year
vehicles
and
engines.
This
proposal
will
not
apply
to
2003
model
year
certification
requests
received
by
EPA
prior
to
the
effective
date
of
the
regulations,
providing
that
they
are
complete
and
include
all
required
data.
C.
What
Happens
to
the
Money
That
Is
Collected
by
the
Fees
Program?
Any
fees
collected
for
administering
the
MVECP
will
be
deposited
in
a
special
fund
in
the
United
States
Treasury.
D.
Can
I
Qualify
for
a
Reduced
Fee?
EPA
believes
that
an
expansive
fee
reduction
policy
could
violate
the
very
premise
underlying
section
217
of
the
CAA:
to
reimburse
the
government
for
the
specific
regulatory
services
provided
to
an
applicant.
Nevertheless,
EPA
recognizes
that
there
may
be
instances,
in
the
case
of
small
engine
families,
where
the
full
proposed
fee
may
represent
an
unreasonable
economic
burden.
Therefore,
EPA
is
proposing
to
continue
the
current
two
part
test
which,
if
met,
would
qualify
an
applicant
for
a
reduction
of
a
portion
of
the
certification
fee.
A
reduced
fee
is
available
when:
(1)
The
certificate
is
to
be
used
for
the
sale
of
vehicles
or
engines
within
the
U.
S.;
and
(2)
The
full
fee
for
the
certification
request
exceeds
1%
of
the
projected
aggregate
retail
value
of
all
vehicles
or
engines
covered
by
that
certificate.
The
proposed
requirement
that
the
certificate
request
pertain
to
U.
S.
vehicle/
engine
sales
is
intended
to
exclude
fee
reductions
for
certificates
used
to
support
foreign
vehicle
or
engine
sales.
This
provision
is
carried
over
from
the
current
fees
rules.
These
certificates
are
not
required
and
represent
extra
effort
expended
by
the
Agency
beyond
that
which
is
mandated
in
U.
S.
laws
or
regulations.
Further,
the
Certificate
of
Conformity
does
not
distinguish
between
U.
S.
and
foreign
sales,
therefore,
although
the
manufacturer's
intention
may
be
to
certify
vehicles
for
a
foreign
market,
there
is
nothing
to
prohibit
the
sale
of
these
vehicles
in
the
U.
S.
Consequently,
the
Agency
is
proposing
that
it
is
inappropriate
to
reduce
the
cost
of
these
certificates
below
the
actual
cost
to
the
Agency.
For
the
first
time
EPA
is
also
proposing
that
the
reduced
fee
will
be
the
larger
of
1%
of
the
aggregate
retail
value
of
the
vehicles
and
engines
covered
by
the
certificate
or
a
minimum
fee
of
$300.
The
$300
minimum
fee
represents
the
lowest
level
of
fee
that
is
cost
effective
for
the
Agency
to
collect
and
still
represents
actual
costs
incurred
by
the
Agency
in
providing
services.
As
noted
below,
the
Agency
is
proposing
two
potential
``
pathways''
by
which
a
manufacturer
can
seek
to
pay
a
reduced
fee.
Under
either
pathway
the
minimum
that
a
manufacturer
will
be
required
to
pay
is
$300.
The
Agency
invites
comment
on
the
concept
of
a
minimum
fee
and
the
amount
of
the
minimum
fee.
The
Agency
is
proposing
two
separate
pathways
by
which
a
manufacturer
can
request
and
pay
a
reduced
fee
amount.
One
of
the
purposes
of
these
pathways
is
to
clarify
when
manufacturers
are
required
to
determine
the
value
of
the
vehicles
or
engines
actually
sold
under
a
certificate
and
to
either
pay
additional
fees
or
seek
a
refund
if
necessary.
Under
the
first
pathway,
the
Agency
is
proposing
that
manufacturers
seeking
a
reduced
fee
include
in
their
certification
application
a
statement
that
the
reduced
fee
is
appropriate
under
the
criteria
and
a
calculation
of
the
amount
of
the
reduced
fee.
The
manufacturer's
evaluation
and
submission
of
a
fee
amount
under
this
reduced
fee
provision
is
subject
to
EPA
review
or
audit.
A
manufacturer's
statement
that
it
is
eligible
for
a
reduced
fee
can
be
rejected
by
EPA
if
the
Agency
finds
that
manufacturer's
evaluation
does
not
meet
the
eligibility
requirements
for
a
reduced
fee,
the
amount
of
the
reduced
fee
was
improperly
calculated,
the
manufacturer
failed
to
meet
the
requirements
to
calculate
a
final
reduced
fee
using
actual
sales
data,
or
the
manufacturer
failed
to
pay
the
net
balance
due
between
the
initial
and
final
reduce
fee
calculation
(see
below
for
discussion
of
the
final
fee
calculation,
reporting
and
payment
proposals).
If
the
manufacturer's
statement
of
eligibility
or
request
of
a
reduced
fee
is
rejected
by
EPA
then
EPA
may
require
the
manufacturer
to
pay
the
full
fee
normally
applicable
to
it
or
EPA
may
adjust
the
amount
of
the
reduced
fee
that
is
due
or
EPA
may
require
the
manufacturer
to
utilize
the
special
fee
provisions
(the
second
pathway)
which
are
explained
below.
To
aid
our
review,
the
Agency
is
proposing
that
the
applicant
for
a
reduced
fee
also
provide
EPA
with
a
report
(called
a
``
report
card'').
This
report
shall
include
the
total
number
of
vehicles
ultimately
covered
by
the
certificate
(the
report
card
shall
include
information
on
all
certificates
held
by
the
manufacturer
that
were
issued
with
a
reduced
fee),
a
calculation
of
the
actual
final
reduced
fee
due
for
each
certificate
which
is
derived
by
adding
up
the
total
number
of
vehicles
and
their
sales
prices,
a
statement
of
the
total
initial
fees
paid
by
the
manufacturer
and
the
total
final
fees
due
for
the
manufacturer.
Manufacturers
will
be
required
to
submit
the
report
card
within
30
days
of
the
end
of
the
model
year,
14
EPA
believes
this
is
reasonable
as
manufacturers
should
have
final
figures
for
each
certificate
by
this
time.
Manufacturers
will
be
required
to
``
true
up''
or
submit
the
final
reduced
fee
due
as
calculated
within
the
report
card
within
45
days
of
the
end
of
the
model
year.
The
Agency
is
proposing
to
not
require
payment
of
the
balance
when
the
amount
is
less
than
$500
for
a
manufacturer.
(The
Agency
requests
comment
on
these
special
provisions.)
In
addition,
EPA
may
require
that
manufacturers
submit
a
report
card,
with
the
same
or
similar
information
as
noted
above,
for
previous
model
years.
The
purpose
of
such
report
card
would
be
to
give
EPA
assurance
that
the
manufacturer
has
demonstrated
a
continuous
capability
of
submitting
the
necessary
year
to
year
report
cards
and
that
appropriate
fees
have
been
paid.
This
will
assist
EPA
in
its
determination
as
to
whether
a
manufacturer
is
capable
of
adequately
projecting
its
annual
sales
for
reduced
fee
purposes
and
whether
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Proposed
Rules
the
manufacturer
shall
remain
eligible
for
the
reduced
fee
provisions.
Under
the
second
pathway,
EPA
is
also
proposing
special
provisions
for
fee
payment
that
are
available
for
manufacturers
which,
due
to
the
nature
of
their
business,
may
be
unable
to
make
good
estimates
of
the
aggregate
projected
retail
value
of
all
the
vehicles
or
engines
to
be
covered
by
the
requested
certificate.
Examples
of
manufacturers
that
may
be
unable
to
estimate
the
number
of
vehicles
and
engines
covered
by
a
certificate
are
those
that
modify
customer
owned
vehicles
(as
done
by
some
ICIs
and
aftermarket
alternative
fuel
converters)
that
are
uncertain
how
many
owners
will
approach
them
to
perform
this
service.
Under
the
special
provisions,
manufacturers
that
obtain
prior
approval
from
the
Agency
may
pay
1.0%
of
the
retail
selling
price
of
5
vehicles,
engines
or
conversions
when
applying
for
a
certificate.
Manufacturers
under
this
pathway
will
be
required
to
submit
the
same
report
card
and
true
up
the
actual
amount
of
reduced
fee
that
is
due
in
the
same
manner
as
described
above
under
the
first
pathway.
Under
either
pathway,
if
a
manufacturer
fails
to
report
within
30
days
or
pay
the
balance
due
by
45
days
of
the
end
of
the
model
year,
then
EPA
may
refuse
to
approve
future
reduced
fee
requests
from
that
manufacturer.
In
addition,
if
a
manufacturer
fails
to
report
within
30
days
and
pay
the
balance
due
by
45
days
of
the
end
of
the
model
year
as
noted
above
then
the
Agency
may
deem
the
applicable
certificate
as
void
ab
initio.
In
the
case
of
vehicles
or
engines
which
have
originally
been
certified
by
an
OEM
but
are
being
modified
to
operate
on
an
alternative
fuel,
EPA
is
proposing
that
the
cost
basis
for
the
reduced
fee
amount
be
the
value
added
by
the
conversion,
not
the
full
cost
of
the
vehicle
or
engine.
On
the
other
hand,
ICI
vehicles
or
engines
certificates
cover
vehicles
or
engines
which
are
imported
into
the
U.
S.
A.
and
that
were
not
originally
certified
by
an
OEM.
As
such,
EPA
costs
associated
with
proving
various
MVECP
services
for
these
vehicles
has
not
yet
been
recovered.
Since
the
Agency
has
not
received
a
fee
payment
for
the
``
base
vehicle''
or
the
vehicle
imported
before
its
conversion
to
meet
U.
S.
emissions
requirements,
we
are
proposing
that
the
cost
basis
for
calculating
a
reduced
fee
for
an
ICI
certification
shall
be
based
upon
the
full
cost
of
the
vehicle
or
engine
rather
than
the
cost
or
value
of
the
conversion.
As
noted
above,
EPA
is
already
proposing
a
fee
of
$8,394
for
certain
types
of
ICI
certificates
as
EPA
has
determined
the
costs
of
MVECP
services
provided
for
such
certificates
regardless
of
the
number
of
vehicles
included
under
such
certificates.
However,
we
recognize
that
this
fee
or
the
full
fee
associated
with
other
types
of
certificates
may
represent
an
unreasonable
economic
burden
on
smaller
businesses
or
on
the
price
of
vehicles
in
smaller
classes
under
a
certificate.
Therefore,
EPA
is
proposing
to
retain
its
current
requirement
that
manufacturers
pay
a
fee
based
on
1%
of
the
aggregate
retail
sales
price
(or
value)
of
the
vehicles
covered
by
a
certificate
as
EPA
believes
this
best
represents
the
proper
balance
between
recovering
the
MVECP
costs
without
imposing
an
unreasonable
economic
burden.
EPA
invites
comment
on
the
continued
use
of
the
1%
multiplier.
For
ICI
requests
EPA
proposes
to
continue
the
current
requirement
to
calculate
the
full
cost
of
a
vehicle
based
on
a
vehicle's
average
retail
price
listed
in
the
National
Automobile
Dealer's
Association
(NADA)
price
guide.
By
using
the
NADA
price
guide
to
establish
a
vehicle's
retail
sales
price
(or
value),
EPA
ensures
uniformity
and
fairness
in
charging
fees.
Further,
it
avoids
problems
associated
with
abuse,
such
as
falsification
of
entry
documents,
in
particular,
sales
receipts.
Where
the
NADA
price
guide
does
not
provide
the
retail
price
of
a
vehicle,
and
in
the
case
of
engines,
the
applicant
for
a
reduced
fee
must
demonstrate
to
the
satisfaction
of
the
Administrator,
the
actual
market
value
of
the
vehicle
or
engine
in
the
United
States
at
the
time
of
final
importation.
When
calculating
the
aggregate
retail
sales
price
of
vehicles
or
engines
under
the
reduced
fee
provisions
such
calculation
must
not
only
include
vehicles
and
engines
actually
sold
but
also
those
modified
under
the
modification
and
test
options
in
40
CFR
85.1509
and
40
CFR
89.609
and
those
imported
on
behalf
of
a
private
or
another
owner.
EPA
is
continuing
the
current
exemption
of
fees
for
small
volume
certification
requests
for
vehicles
using
alternative
fuels
through
the
2003
model
year.
EPA
believes
that
this
program
has
completed
its
purpose
of
providing
a
short
term
relief
for
alternative
fuel
conversion
manufacturers.
Therefore,
starting
with
the
2004
model
year,
EPA
is
no
longer
including
this
exemption
for
alternative
fuel
convertors,
and
such
convertors
shall
be
subject
to
the
same
fee
provisions
as
other
manufacturers.
This
includes
the
reduced
fee
provisions.
We
believe
that
this
fee
reduction
proposal
will
provide
adequate
relief
for
small
entities
that
would
otherwise
have
been
harmed
by
a
standardized
fee.
It
is
important
to
note
that
this
fee
reduction
does
not
raise
the
fees
for
other
manufacturers;
EPA
will
simply
collect
less
funds.
The
Agency
invites
comment
on
the
necessity
of
a
reduced
fee
provision.
E.
What
Is
the
Refund
Policy?
Instances
may
occur
in
which
an
applicant
submits
a
filing
form
with
the
appropriate
fee,
has
an
engine
system
combination
undergo
a
portion
of
the
certification
process,
but
fails
to
receive
a
signed
certificate.
Under
the
current
rules,
the
Agency
offers
the
manufacturer
a
partial
refund
in
those
situations.
The
Agency
retains
a
portion
of
the
fee
to
pay
for
the
work
which
has
already
been
done.
This
policy
has
been
difficult
to
administer
and
required
substantial
Agency
oversight.
Consequently,
we
have
included
a
simplified
refund
policy
in
today's
proposal.
When
a
certificate
has
not
been
issued,
the
applicant
will
be
eligible
to
receive,
upon
request,
a
full
refund
of
the
fee
paid.
Optionally,
in
lieu
of
a
refund,
the
manufacturer
may
apply
the
fee
to
another
certification
request.
The
new
refund
policy
will
not
reduce
the
money
collected
by
the
Agency
because
the
fee
schedule
proposed
today
is
based
on
the
number
of
certificates
actually
issued
rather
than
the
number
of
certification
requests.
The
Agency
also
considered
not
allowing
any
refunds
if
the
manufacturer
overpaid
based
on
their
own
projections.
However,
the
Agency
was
concerned
there
could
be
cases
where
sales
were
significantly
lower
than
expected
and
the
overpayment
amount
would
be
significant.
Also,
the
Agency
does
not
want
to
encourage
manufacturers
to
systematically
underproject
the
reduced
fees
on
the
fear
that
they
might
significantly
overpay
and
be
unable
to
obtain
a
refund.
On
the
other
hand,
processing
refunds
costs
the
Agency
time
and
money
and
there
is
a
potential
for
a
large
number
of
small
refunds
that
would
be
not
be
cost
effective
for
EPA
to
process
or
for
the
manufacturer
to
request.
Therefore,
the
Agency
is
proposing
to
only
consider
refund
requests
for
a
minimum
of
$500
overpayment.
The
Agency
invites
comment
on
this
issue.
V.
What
Other
Options
Were
Considered
by
EPA
When
Proposing
This
Rule?
A.
Separate
Fees
for
Other
ICI
Categories
Beyond
Light
Duty
EPA
considered
continuing
the
current
provisions
which
charge
the
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Federal
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/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
same
fee
for
ICI
and
OEM
manufacturers.
However,
when
the
Agency
examined
the
costs
associated
with
ICI
and
OEM
manufacturers,
we
found
the
costs
associated
with
administering
the
light
duty
ICI
program
was
lower
than
for
light
duty
OEM
manufacturers.
Consequently,
today's
proposal
includes
lower
fees
for
lightduty
ICI
certificate
requests.
EPA
considered
calculating
separate
fees
for
other
ICI
industries
beyond
light
duty.
Currently,
EPA
has
issued
ICI
certificates
only
for
highway
motorcycles
in
addition
to
light
duty.
In
this
case,
the
costs
to
the
Agency
for
the
MVECP
for
motorcycles
and
ICI
motorcycles
are
essentially
the
same.
EPA
expects
that
when
other
industries
have
ICI
certification
requests
that
the
Agency
will
a
similar
amount
of
effort
on
the
ICI
manufacturers
as
the
OEM
manufacturers.
Consequently,
the
Agency
believes
that
ICI
and
OEM
fees
would
be
similar
for
all
the
categories
other
than
light
duty.
For
that
reason,
today's
proposal
does
not
establish
separate
fees
for
ICI
manufacturers
other
than
the
for
the
light
duty
ICIs.
B.
Start
Updating
Fees
for
Cost
of
Inflation
in
2004
Model
Year
EPA
considered
updating
MVECP
fees
for
the
cost
of
inflation
at
the
start
of
model
year
(MY)
2004.
We
also
considered
waiting
one
year
to
apply
inflation
costs
to
fees.
We
are
proposing
to
postpone
this
update
for
one
year
and
apply
inflation
costs
in
2005
MY.
The
Agency
invites
comment
on
updating
the
fees
before
the
start
of
MY
2005.
VI.
What
Is
the
Economic
Impact
of
This
Proposed
Rule?
This
proposed
rule
will
not
have
a
significant
impact
on
the
majority
of
vehicle
and
engine
manufacturers.
The
cost
to
industry
will
be
a
relatively
small
value
per
unit
manufactured
for
most
engine
system
combinations.
EPA
expects
to
collect
about
18
million
dollars
annually.
This
averages
out
to
approximately
50
cents
per
vehicle
or
engine
sold
annually.
However,
for
engine
system
combinations
with
low
annual
sales
volume,
the
cost
per
unit
could
be
higher.
To
remove
the
possibility
of
serious
financial
harm
on
companies
producing
only
low
sales
volume
designs,
the
regulations
adopted
today
include
a
reduced
fee
provision
for
small
volume
engine
families
to
reduce
the
burden
of
fees.
These
provisions
should
alleviate
concerns
about
undue
economic
hardship
on
small
volume
manufacturers.
Refer
to
the
Regulatory
Flexibility
Act
section,
Section
VIII.
B,
below,
for
more
discussion
on
this
topic.
VII.
How
Can
I
Participate
in
the
Rulemaking
Process?
A.
How
To
Make
Comments
and
Use
the
Public
Docket
EPA
welcomes
comments
on
all
aspects
of
this
proposed
rulemaking.
Commenters
are
especially
encouraged
to
give
suggestions
for
changing
any
aspects
of
the
proposal.
All
comments,
with
the
exception
of
proprietary
information
should
be
addressed
to
the
EPA
Air
Docket
Section,
Docket
No.
A–
2001–
09
(see
ADDRESSES).
Commenters
who
wish
to
submit
proprietary
information
for
consideration
should
clearly
separate
such
information
from
other
comments
by
(1)
labeling
proprietary
information
``
Confidential
Business
Information''
and
(2)
sending
proprietary
information
directly
to
the
contact
person
listed
(see
FOR
FURTHER
INFORMATION
CONTACT)
and
not
to
the
public
docket.
This
will
help
insure
that
proprietary
information
is
not
inadvertently
placed
in
the
docket.
If
a
commenter
wants
EPA
to
use
a
submission
labeled
as
confidential
business
information
as
part
of
the
basis
for
the
final
rule,
then
a
nonconfidential
version
of
the
document,
which
summarizes
the
key
data
or
information,
should
be
sent
to
the
docket.
Information
covered
by
a
claim
of
confidentiality
will
be
disclosed
by
EPA
only
to
the
extent
allowed
and
by
the
procedures
set
forth
in
40
CFR
part
2.
If
no
claim
of
confidentiality
accompanies
the
submission
when
EPA
receives
it,
the
submission
may
be
made
available
to
the
public
without
notifying
the
commenters.
B.
Public
Hearings
Anyone
wishing
to
present
testimony
about
this
proposal
at
the
public
hearing
(see
DATES)
should,
if
possible,
notify
the
contact
person
(see
FOR
FURTHER
INFORMATION
CONTACT)
by
September
12,
2002.
The
contact
person
should
be
given
an
estimate
of
the
time
required
for
the
presentation
of
testimony
and
notification
of
any
need
for
audio/
visual
equipment.
Testimony
will
be
scheduled
on
a
first
come,
first
serve
basis.
A
sign
up
sheet
will
be
available
at
the
registration
table
the
morning
of
the
hearing
for
scheduling
those
who
have
not
notified
the
contact
earlier.
This
testimony
will
be
scheduled
on
a
first
come,
first
serve
basis
to
follow
the
previously
scheduled
testimony.
EPA
requests
that
approximately
50
copies
of
the
statement
or
material
to
be
presented
be
brought
to
the
hearing
for
distribution
to
the
audience.
In
addition,
EPA
would
find
it
helpful
to
receive
an
advanced
copy
of
any
statement
or
material
to
be
presented
at
the
hearing
at
least
one
week
before
the
scheduled
hearing
date.
This
is
to
give
EPA
staff
adequate
time
to
review
such
material
before
the
hearing.
Such
advanced
copies
should
be
submitted
to
the
contact
person
listed.
The
comment
period
will
be
kept
open
until
October
19,
2002,
and
therefore
will
remain
open
for
30
days
following
the
hearing.
All
such
submittals
should
be
directed
to
the
Air
Docket
Section,
Docket
No.
A–
2001–
09
(see
ADDRESSES).
The
hearing
will
be
conducted
informally,
and
technical
rules
of
evidence
will
not
apply.
A
written
transcript
of
the
hearing
will
be
placed
in
the
above
docket
for
review.
Anyone
desiring
to
purchase
a
copy
of
the
transcript
should
make
individual
arrangements
with
the
court
reporter
recording
the
proceedings.
VIII.
What
Are
the
Administrative
Requirements
for
This
Proposal?
A.
Executive
Order
12866:
Administrative
Designation
and
Regulatory
Analysis
Under
Executive
Order
12866
(58
FR
51735
October
4,
1993),
EPA
must
determine
whether
this
proposed
regulatory
action
is
``
significant''
and
therefore
subject
to
Office
of
Management
and
Budget
(OMB)
review
and
the
requirements
of
this
Executive
Order.
The
Order
defines
a
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(1)
Have
an
annual
effect
on
the
economy
of
$100
million
or
more
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
(4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
the
Executive
Order
12866,
it
has
been
determined
that
this
rule
is
a
``
significant
regulatory
action''
because
this
rulemaking
materially
alters
user
fees.
As
such,
this
action
was
submitted
to
OMB
for
review.
Changes
made
in
response
to
OMB
suggestions
or
recommendations
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Vol.
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152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
15
The
average
costs
of
the
fees
per
vehicle
or
engine
(fee
per
unit)
for
the
specific
fee
categories
of
Highway
Motorcycle,
Light
Duty,
Light
Duty
ICI,
Heavy
Duty
Highway
CI
and
SI
and
Nonroad
CI
categories
are
shown
in
Worksheet
2,
Appendix
C,
of
the
Motor
Vehicle
and
Engine
Compliance
Program
Cost
Analysis
available
in
EPA
Air
Docket
No.
A–
2001–
09.
will
be
documented
in
the
public
record.
B.
Regulatory
Flexibility
Act
(RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(SBREFA),
5
U.
S.
C.
601
et
seq
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedures
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
proposed
rule
on
small
entities,
small
entity
is
defined
as:
(1)
A
small
business
that
meets
the
definition
for
business
based
on
SBA
size
standards;
(2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(3)
a
small
organization
that
is
any
not
for
profit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
Table
VIII.
B–
1
provides
an
overview
of
the
primary
SBA
small
business
categories
potentially
affected
by
this
regulation.
This
list
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
regarding
entities
likely
to
be
regulated
by
this
proposed
action.
TABLE
VIII.
B–
1.—
PRIMARY
SBA
SMALL
BUSINESS
CATEGORIES
POTENTIALLY
AFFECTED
BY
THIS
PROPOSED
REGULATION
Industry
NAICS
a
Codes
Defined
by
SBA
as
a
small
business
If:
b
Farm
Machinery
and
Equipment
Manufacturing
.............................................................................................
333111
<500
employees.
Lawn
and
Garden
Tractor
and
Home
Lawn
and
Garden
Equipment
Manufacturing
.....................................
333112
<500
employees.
Construction
Machinery
Manufacturing
...........................................................................................................
333120
<750
employees.
Mining
Machinery
and
Equipment
Manufacturing
...........................................................................................
333131
<500
employees.
Turbine
and
Turbine
Generator
Set
Unit
Manufacturing
.................................................................................
333611
<1,000
employees.
Speed
Changer,
Industrial
High
speed
Drive
and
Gear
Manufacturing
.........................................................
333612
<500
employees.
Mechanical
Power
Transmission
Equipment
Manufacturing
..........................................................................
333613
<500
employees.
Other
Engine
Equipment
Manufacturing
.........................................................................................................
333618
<1,000
employees.
Nonroad
SI
engines
.........................................................................................................................................
333618
<1,000
employees.
Internal
Combustion
Engines
..........................................................................................................................
333618
<1,000
employees.
Industrial
Truck,
Tractor,
Trailer,
and
Stacker
Machinery
...............................................................................
333924
<750
employees.
Power
Driven
Handtool
Manufacturing
............................................................................................................
333991
<500
employees.
Automobile
Manufacturing
...............................................................................................................................
336111
<1000
employees.
Light
Truck
and
Utility
Vehicle
Manufacturing
.................................................................................................
336112
<1000
employees.
Heavy
Duty
Truck
Manufacturing
....................................................................................................................
336120
<1000
employees.
Fuel
Tank
Manufacturers
.................................................................................................................................
336211
<1000
employees.
Gasoline
Engine
and
Engine
Parts
Manufacturing
.........................................................................................
336312
<750
employees.
Aircraft
Engine
and
Engine
Parts
Manufacturing
............................................................................................
336412
<1000
employees.
Railroad
Rolling
Stock
Manufacturing
.............................................................................................................
336510
<1000
employees.
Boat
Building
and
Repairing
............................................................................................................................
336612
<
500
employees.
Motorcycles
and
motorcycle
parts
manufacturers
...........................................................................................
336991
<500
employees.
Snowmobile
and
ATV
manufacturers
..............................................................................................................
336999
<500
employees.
Independent
Commercial
Importers
of
Vehicles
and
parts
.............................................................................
421110
<100
employees.
Engine
Repair
and
Maintenance
.....................................................................................................................
811310
<$
5
million
annual
receipts
Notes:
a
North
American
Industry
Classification
System.
b
According
to
SBA's
regulations
(13
CFR
part
121),
businesses
with
no
more
than
the
listed
number
of
employees
or
dollars
in
annual
receipts
are
considered
``
small
entities''
for
purposes
of
a
regulatory
flexibility
analysis.
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
this
proposed
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
A
review
of
rulemakings
that
set
emissions
standards
for
the
industries
affected
by
today's
proposed
rule,
including
those
manufacturers
affected
by
the
recreational
vehicle
proposed
rule,
showed
that
approximately
108
small
businesses
that
will
be
paying
fees.
EPA
examined
the
cost
of
the
proposed
fees
and
determined
that
the
average
cost
for
manufacturers
of
all
sizes,
across
industry
sectors,
is
approximately
$.
41
per
vehicle
or
engine.
15
In
addition,
under
the
reduced
fee
provisions
described
above
in
Section
IV.
D.,
the
fee
a
manufacturer
would
pay
will
not
exceed
1.0
percent
of
the
aggregate
retail
sales
price
of
the
vehicles
or
engines
covered
by
a
certificate
request
or
a
minimum
fee
of
$300.
The
reduced
fee
provision
limits
the
impact
of
this
proposed
rule
on
small
entities
to
1.0
percent
of
the
aggregate
retail
sales
price
or
a
minimum
fee
of
$300.
EPA
believes
that
in
a
very
small
number
of
cases,
the
1.0
percent
reduced
fee
amount
will
be
less
than
the
$300
minimum
fee.
The
minimum,
$300
fee
is
a
modest
amount
and
will
only
be
required
when
engine
families
have
less
than
$30,000
aggregate
retail
sales
price.
While
the
minimum
fee
would
represent
an
impact
greater
than
1.0
percent
of
the
aggregate
retail
sales
price,
the
$300
amount
will
not
have
a
significant
economic
impact
on
the
manufacturers
that
pay
it.
This
amount
would
represent
a
modest
cost
of
doing
business.
The
following
is
an
example
of
a
reduced
fee
calculation:
If
a
light
duty
vehicle
manufacturer
has
an
engine
family
of
2
vehicles
that
are
sold
for
$35,000
per
vehicle,
under
the
proposed
fee
schedule
the
full
fee
would
be
$33,911,
or
$16,958
per
engine
family
($
16,956
or
$8,479
per
vehicle,
respectively),
depending
upon
whether
the
engine
family
is
certified
as
a
Federal
vehicle
or
California
only
engine
family.
Under
the
proposal,
the
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Federal
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/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
reduced
fee
would
be
1.0
percent
of
the
aggregate
retail
sales
price
of
the
vehicles
($
70,000),
or
$700
(or
$350
per
vehicle)
as
shown
below:
2
*
$35,000
*
0.01
=
$700
In
another
example,
a
manufacturer
of
small
nonroad
spark
ignition
engines
certifies
an
engine
family
of
500
engines
that
are
sold
for
$50
apiece.
In
this
case,
under
the
proposed
fee
schedule
the
full
fee
would
be
$827.
Under
the
reduced
fee
provisions,
the
manufacturer
would
determine
1
percent
of
the
total
retail
sales
price
of
the
engines
and
determine
whether
this
amount
is
less
than
the
full
fee
or
the
minimum
fee
of
$300.
The
aggregated
retail
sales
price
of
the
engines
is
$25,000;
1.0
percent
of
that
is
$250.
Therefore,
the
manufacturer
pays
the
minimum
fee
of
$300
(or
$.
60
per
engine).
500
*
$50
*
.01
=
$250
$250
<
$300
minimum
fee
Fee
=
$300
EPA
also
had
a
fees
rule
briefing
which
was
offered
in
Ann
Arbor,
MI,
to
regulated
industries
on
August
29,
2001.
The
purpose
of
the
briefing
was
to
give
businesses
enough
time
to
plan
for
fees
in
their
2003
FY
budgets.
We
continue
to
be
interested
in
the
potential
impacts
of
the
proposed
fees
on
small
entities
and
welcome
comments
on
issues
related
to
such
impacts.
C.
Paperwork
Reduction
Act
The
information
collection
requirements
in
this
proposed
rule
have
been
submitted
for
approval
to
the
Office
of
Management
and
Budget
(OMB)
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
An
Information
Collection
Request
(ICR)
document
has
been
prepared
by
EPA
(ICR
No.
)
and
a
copy
may
be
obtained
from
Susan
Auby
by
mail
at
Collection
Strategies
Division;
U.
S.
Environmental
Protection
Agency
(2822);
1200
Pennsylvania
Ave.,
NW,
Washington,
DC
20460,
by
email
at
farmer.
sandy@
epamail.
epa.
gov,
or
by
calling
(202)
260–
4901.
A
copy
may
also
be
downloaded
off
the
internet
at
http://
www.
epa.
gov/
icr.
The
information
to
be
collected
is
necessary
to
assure
that
the
fees
collected
are
properly
credited
to
the
both
the
firm
paying
them
and
the
specific
product
to
be
certified.
In
addition,
under
some
circumstances,
a
fee
may
be
reduced
or
refunded;
information
collected
will
be
used
to
verify
that
such
action
is
appropriate.
Except
for
reduced
fees
and
refunds,
the
submission
of
information
is
mandatory.
The
collection
is
authorized
by
the
Clean
Air
Act
(42
U.
S.
C.
7552)
and
the
Independent
Offices
Appropriations
Act
(31
U.
S.
C.
9701).
Information
collected
will
be
available
to
the
public.
EPA
estimates
that
1600
certifications
will
be
requested
annually
of
which
180
will
qualify
for
a
reduced
fee.
In
addition,
approximately
50
fee
refunds
will
be
processed
each
year.
The
total
burden
of
these
projected
responses
per
year
is
500
hours;
an
average
of
18
minutes
per
response.
There
are
no
capital,
start
up,
operation,
maintenance
or
other
costs
associated
with
this
collection.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
Agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
Chapter
15.
Comments
are
requested
on
the
Agency's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
Send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division;
U.
S.
Environmental
Protection
Agency
(2822);
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460;
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
St.,
NW.,
Washington,
DC
20503,
marked
``
Attention:
Desk
Officer
for
EPA.
''
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
August
7,
2002,
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
September
6,
2002.
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
this
proposal.
D.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(UMRA),
Public
Law
104–
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
action
on
state,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
by
state,
local,
and
tribal
governments,
in
the
aggregate,
or
by
the
private
sector,
of
$100
million
or
more
in
any
one
year.
Before
promulgation
of
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost
effective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
we
establish
any
regulatory
requirement
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
we
must
develop,
under
section
203
of
the
UMRA,
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
our
regulatory
proposals
with
significant
federal
intergovernmental
mandates.
The
plan
must
also
provide
for
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
Today's
proposed
rule
contains
no
Federal
mandates
for
state,
local,
or
tribal
governments.
Nor
does
this
proposed
rule
have
Federal
mandates
that
may
result
in
the
expenditures
of
$100
million
or
more
in
any
year
by
the
private
sector
as
defined
by
the
provisions
of
Title
II
of
the
UMRA
as
the
total
cost
of
the
fee
program
is
estimated
to
be
below
20
million
dollars.
Nothing
in
the
proposed
rule
would
significantly
or
uniquely
affect
small
governments.
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Federal
Register
/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
E.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(NTTAA),
Public
Law
104–
113,
12(
d)
(15
U.
S.
C.
272),
directs
the
EPA
to
use
voluntary
consensus
standards
(VCS)
in
its
regulatory
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices,
etc.)
that
are
developed
or
adopted
by
voluntary
consensus
standard
bodies.
The
NTTAA
requires
EPA
to
provide
Congress,
through
OMB,
explanations
when
the
Agency
decides
not
to
use
available
and
applicable
voluntary
consensus
standards.
EPA
welcomes
comments
on
this
aspect
of
the
proposed
rulemaking
and,
specifically,
invites
the
public
to
identify
potentially
applicable
voluntary
consensus
standards
and
to
explain
why
such
standards
should
be
used
in
this
regulation.
F.
Executive
Order
13045:
Children's
Health
Protection
Executive
Order
13045:
``
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks''
(62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(1)
Is
determined
to
be
economically
significant
as
defined
under
Executive
Order
12866,
and
(2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
the
Agency
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.
EPA
believes
this
proposed
rule
is
not
subject
to
the
Executive
Order
because
it
is
not
an
economically
significant
regulatory
action
as
defined
by
Executive
Order
12866.
In
addition,
this
proposed
rule
is
not
subject
to
the
Executive
Order
because
it
does
not
involve
decisions
based
on
environmental
health
or
safety
risks
that
may
disproportionately
affect
children.
Today's
proposed
rule
seeks
to
implement
a
fees
program
and
is
expected
to
have
no
impact
on
environmental
health
or
safety
risks
that
would
affect
the
public
or
disproportionately
affect
children.
G.
Executive
Order
13132:
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.
''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.
''
This
proposed
rule
will
not
have
federalism
implications.
It
will
not
have
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
This
proposed
rule
will
impose
no
direct
compliance
costs
on
states.
Thus,
the
requirements
of
section
6
of
Executive
Order
13132
do
not
apply
to
this
rule.
In
the
spirit
of
Executive
Order
13132,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
State
and
local
governments,
EPA
specifically
solicits
comment
on
this
proposed
rule
from
State
and
local
officials.
H.
Executive
Order
13211:
Energy
Effects
This
proposed
rule
is
not
a
``
significant
energy
action''
as
defined
in
Executive
Order
13211,
``
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(66
FR
28355
(May
22,
2001)
because
it
will
not
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.
Further,
we
have
determined
that
this
proposed
rule
is
not
likely
to
have
any
adverse
energy
effects.
I.
Executive
Order
13175:
Consultation
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.
''
This
proposed
rule
does
not
have
tribal
implications.
It
will
not
have
substantial
direct
effects
on
tribal
governments,
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
The
requirements
proposed
by
this
action
impact
private
sector
businesses,
particularly
the
vehicle
and
engine
manufacturing
industries.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.
List
of
Subjects
40
CFR
Part
85
Environmental
protection,
Confidential
business
information,
Imports,
Labeling,
Motor
vehicle
pollution,
Reporting
and
recordkeeping
requirements,
Research,
Warranties.
40
CFR
Part
86
Environmental
protection,
Administrative
practice
and
procedure,
Air
Pollution
Control,
Confidential
business
information,
Diesel,
Gasoline,
Fees,
Imports,
Incorporation
by
reference,
Labeling,
Motor
vehicle
pollution,
Motor
vehicles,
Reporting
and
recordkeeping
requirements.
Dated:
July
17,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
set
forth
in
the
preamble,
title
40,
chapter
I
of
the
Code
of
Federal
Regulations
is
proposed
to
be
amended
as
follows:
PART
85—
CONTROL
OF
AIR
POLLUTION
FROM
MOBILE
SOURCES
1.
The
Authority
for
part
85
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401–
7671q.
2.
Add
a
new
Subpart
Y
to
Part
85
to
read
as
follows:
Subpart
Y—
Fees
for
the
Motor
Vehicle
and
Engine
Compliance
Program
Sec.
85.2401
To
whom
do
these
requirements
apply?
85.2402
[Reserved]
85.2403
What
definitions
apply
to
this
subpart?
85.2404
What
abbreviations
apply
to
this
subpart?
85.2405
How
much
are
the
fees?
85.2406
Can
I
qualify
for
reduced
fees?
85.2407
Can
I
get
a
refund
if
I
don't
get
a
certificate
or
overpay?
85.2408
How
do
I
make
a
fee
payment?
85.2409
Deficiencies
85.2410
Special
provisions
applicable
to
the
2003
model
year
only.
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Federal
Register
/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
Subpart
Y—
Fees
for
the
Motor
Vehicle
and
Engine
Compliance
Program
§
85.2401
To
whom
do
these
requirements
apply?
(a)
This
subpart
prescribes
fees
manufacturers
must
pay
for
the
motor
vehicle
and
engine
compliance
program
(MVECP)
activities
performed
by
the
EPA.
The
prescribed
fees
and
the
provisions
of
this
subpart
apply
to
manufacturers
of:
(1)
Light
duty
vehicles
(cars
and
trucks)
(See
40
CFR
Part
86);
(2)
Medium
Duty
Passenger
Vehicles
(See
40
CFR
Part
86);
(3)
Complete
gasoline
fueled
highway
heavy
duty
vehicles
(See
40
CFR
Part
86);
(4)
Heavy
duty
highway
diesel
and
gasoline
engines
(See
40
CFR
Part
86);
(5)
On
highway
motorcycles
(See
40
CFR
Part
86);
(6)
Nonroad
compression
ignition
engines
(See
40
CFR
Part
89);
(7)
Locomotives
(See
40
CFR
Part
92);
(8)
Marine
diesel
and
gasoline
engines
(See
40
CFR
Parts
91,
94,
or
1045
and
MARPOL
73/
78,
as
applicable);
(9)
Small
nonroad
spark
ignition
engines
(engines
19kW)
(See
40
CFR
Part
90);
(10)
Recreational
vehicles
(including,
but
not
limited
to,
snowmobiles,
allterrain
vehicles
and
off
highway
motorcycles)
(See
40
CFR
Part
1051);
(11)
Heavy
duty
highway
gasoline
vehicles
(evaporative
emissions
certification
only)
(See
40
CFR
Part
86);
and
(12)
Large
nonroad
spark
ignition
engines
(engines
>
19
kW)
(See
40
CFR
Part
1048).
(b)
This
subpart
applies
to
manufacturers
that
submit
2003
and
later
model
year
certification
requests
received
on
or
after
[60
days
after
the
date
of
publication
of
the
final
rule].
(c)
Certification
requests
for
the
2003
model
year
which
are
complete,
contain
all
required
data,
and
are
received
prior
to
[60
days
after
the
date
of
publication
of
the
final
rule]
are
subject
to
the
provisions
of
40
CFR
part
86,
subpart
J.
(d)
Nothing
in
this
subpart
will
be
construed
to
limit
the
Administrator's
authority
to
require
manufacturer
or
confirmatory
testing
as
provided
in
the
Clean
Air
Act,
including
authority
to
require
manufacturer
in
use
testing
as
provided
in
section
208
of
the
Clean
Air
Act.
§
85.2402
[Reserved]
§
85.2403
What
definitions
apply
to
this
subpart?
(a)
The
following
definitions
apply
to
this
subpart:
Agency
or
EPA
means
the
U.
S.
Environmental
Protection
Agency.
Body
Builder
means
a
manufacturer,
other
than
the
OEM,
who
installs
certified
on
highway
HD
engines
into
equipment
such
as
trucks.
California
only
certificate
is
a
Certificate
of
Conformity
issued
by
EPA
which
only
signifies
compliance
with
the
emission
standards
established
by
California.
Certification
request
means
a
manufacturer's
request
for
certification
evidenced
by
the
submission
of
an
application
for
certification,
ESI
data
sheet,
or
ICI
Carryover
data
sheet.
A
single
certification
request
covers
one
test
group,
engine
family,
or
engine
system
combination
as
applicable.
For
HDV
evaporative
certification,
the
certification
request
covers
one
evaporative
family.
Consumer
Price
Index
means
the
consumer
price
index
for
all
U.
S.
cities
using
the
``
U.
S.
city
average''
area
,
``
all
items''
and
``
not
seasonally
adjusted''
numbers
calculated
by
the
Department
of
Labor.
Federal
certificate
is
a
Certificate
of
Conformity
issued
by
EPA
which
signifies
compliance
with
emission
requirements
in
40
CFR
part
85,
86,
89,
90,
91,
92,
94,
1045,
1048,
and/
or
1051
as
applicable.
Filing
form
means
the
MVECP
Fee
Filing
Form
to
be
sent
with
payment
of
the
MVECP
fee.
Fuel
economy
basic
engine
means
a
unique
combination
of
manufacturer,
engine
displacement,
number
of
cylinders,
fuel
system,
catalyst
usage,
and
other
characteristics
specified
by
the
Administrator.
MARPOL
73/
78
is
the
international
treaty
regulating
disposal
of
wastes
generated
by
normal
operation
of
vessels
(Title:
International
Convention
for
the
Prevention
of
Pollution
from
Ships).
Recreational
means
the
engines
subject
to
40
CFR
1051
which
includes
off
road
motorcycles,
all
terrain
vehicles,
and
snowmobiles.
(b)
The
definitions
contained
in
the
following
parts
also
apply
to
this
subpart.
If
the
term
is
defined
in
paragraph
(a)
of
this
section
then
that
definition
will
take
precedence.
(1)
40
CFR
Part
85;
(2)
40
CFR
Part
86;
(3)
40
CFR
Part
89;
(4)
40
CFR
Part
90;
(5)
40
CFR
Part
91;
(6)
40
CFR
Part
92;
(7)
40
CFR
Part
94;
(8)
40
CFR
Part
1045;
(9)
40
CFR
Part
1048;
and
(10)
40
CFR
Part
1051.
§
85.2404
What
abbreviations
apply
to
this
subpart?
The
abbreviations
in
this
section
apply
to
this
subpart
and
have
the
following
meanings:
Cal—
California;
CI—
Compression
Ignition
(Diesel)
cycle
engine;
CPI—
Consumer
Price
Index;
ESI—
Engine
System
Information;
EPA—
U.
S.
Environmental
Protection
Agency;
Evap—
Evaporative
Emissions;
Fed—
Federal;
HD—
Heavy
duty
engine;
HDV—
Heavy
duty
vehicle;
HW—
On
Highway
versions
of
a
vehicle
or
engine;
ICI—
Independent
Commercial
Importer;
IMO—
International
Maritime
Organization;
LD—
Light
Duty
including
both
LDT
and
LDV;
LDT—
Light
duty
truck;
LDV—
Light
duty
vehicle;
MARPOL—
An
IMO
treaty
for
the
control
of
marine
pollution;
MC—
Motorcycle;
MDPV—
Medium
Duty
Passenger
Vehicle;
MVECP—
Motor
Vehicle
and
Engine
Compliance
Program;
MY—
Model
Year;
NR—
Nonroad
version
of
a
vehicle
or
engine;
OEM—
Original
equipment
manufacturer;
SI—
Spark
Ignition
(Otto)
cycle
engine.
§
85.2405
How
much
are
the
fees?
(a)
Fees
for
the
2003
and
2004
model
years.
The
fee
for
each
certification
request
is
in
the
following
table:
Category
Certificate
type
Fee
(1)
LD,
excluding
ICIs
...................................................................
Fed
Certificate
.............................................................................
33,911
(2)
LD,
excluding
ICIs
...................................................................
Cal
only
Certificate
......................................................................
16,958
(3)
MDPV,
excluding
ICIs
.............................................................
Fed
Certificate
.............................................................................
33,911
(4)
MDPV,
excluding
ICIs
.............................................................
Cal
only
Certificate
......................................................................
16,958
(5)
Complete
SI
HDVs,
excluding
ICIs
.........................................
Fed
Certificate
.............................................................................
33,911
(6)
Complete
SI
HDVs,
excluding
ICIs
.........................................
Cal
only
Certificate
......................................................................
16,958
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152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
Category
Certificate
type
Fee
(7)
ICIs
for
the
following
industries:
LD,
MDPV,
or
Complete
SI
HDVs.
All
Types
......................................................................................
8,394
(8)
MC
HW,
including
ICIs
............................................................
All
Types
......................................................................................
2,416
(9)
HD
HW,
including
ICIs
............................................................
Fed
Certificate
.............................................................................
30,437
(10)
HD
HW,
including
ICIs
..........................................................
Cal
only
Certificate
......................................................................
827
(11)
HDV
(evap),
including
ICIs
....................................................
Evap
Certificate
...........................................................................
827
(12)
NR
CI,
including
ICIs,
but
excluding
Locomotives,
Marine
and
Recreational
engines.
All
Types
......................................................................................
2,156
(13)
NR
SI,
including
ICIs
.............................................................
All
Types
......................................................................................
827
(14)
All
Marine,
including
ICIs
.......................................................
All
Types
and
IMO
.......................................................................
827
(15)
All
Recreational,
including
ICIs,
but
excluding
marine
engines
All
Types
......................................................................................
827
(16)
Locomotives,
including
ICIs
...................................................
All
Types
......................................................................................
827
(b)
Fees
for
2005
model
year
and
beyond.
(1)
Starting
with
the
2005
model
year,
the
fees
due
for
each
certification
request
will
be
calculated
using
an
equation
which
adjusts
the
fees
in
paragraph
(a)
of
this
section
for
the
change
in
the
consumer
price
index.
(2)
Fees
for
2005
model
year
and
later
certification
requests
will
be
calculated
using
the
following
equation.
FeesMY
=
Feesbase
×
(CPIMY–
2
/
CPI2002)
Where:
FeesMY
is
the
applicable
fee
for
the
model
year
of
the
certification
request.
Feesbase
is
the
applicable
fee
from
paragraph
(a)
of
this
section.
CPIMY–
2
is
the
consumer
price
index
for
all
U.
S.
cities
using
the
``
U.
S.
city
average''
area
,
``
all
items''
and
``
not
seasonally
adjusted''
numbers
calculated
by
the
Department
of
Labor
listed
for
the
month
of
July
of
the
year
two
years
before
the
model
year.
(e.
g.,
for
the
2005
MY
use
the
CPI
based
on
the
date
of
July,
2003).
CPI2002
is
the
consumer
price
index
for
all
U.
S.
cities
using
the
``
U.
S.
city
average''
area
,
``
all
items''
and
``
not
seasonally
adjusted''
numbers
calculated
by
the
Department
of
Labor
for
December,
2002.
(c)
A
single
fee
will
be
charged
when
a
manufacturer
seeks
to
certify
multiple
evaporative
families
within
a
single
engine
family
or
test
group.
(d)
A
body
builder,
who
exceeds
the
maximum
fuel
tank
size
for
a
HDV
that
has
been
certified
by
an
OEM
and
consequently
makes
a
request
for
HDV
certification,
must
pay
a
separate
fee
for
each
certification
request.
The
fee
will
be
that
listed
in
paragraphs
(a)
and
(b)
of
this
section,
paragraph
(c)
does
not
apply.
§
85.2406
Can
I
qualify
for
reduced
fees?
(a)
Eligibility
Requirements.
To
be
eligible
for
a
reduced
fee,
the
following
conditions
must
be
satisfied:
(1)
The
certificate
is
to
be
used
for
sale
of
vehicles
or
engines
within
the
United
States;
and
(2)
The
full
fee
for
certification
request
for
a
MY
exceeds
1.0%
of
the
aggregate
projected
retail
sales
price
of
all
vehicles
or
engines
covered
by
that
certificate.
(b)
Initial
Reduced
Fee
Calculation.
(1)
If
the
requirements
of
paragraph
(a)
of
this
section
are
satisfied,
the
fee
to
be
paid
by
the
applicant
(the
``
initial
reduced
fee'')
will
be
the
greater
of:
(i)
1.0%
of
the
aggregate
projected
retail
sales
price
of
all
the
vehicles
or
engines
to
be
covered
by
the
certification
request;
or
(ii)
A
minimum
fee
of
$300.
(2)
For
vehicles
or
engines
that
are
converted
to
operate
on
an
alternative
fuel
using
as
the
basis
for
the
conversion
a
vehicle
or
engine
which
is
covered
by
an
existing
OEM
certificate
of
conformity,
the
cost
basis
used
in
this
section
must
be
the
aggregate
projected
retail
value
added
to
the
vehicle
or
engine
by
the
conversion
rather
than
the
full
cost
of
the
vehicle
or
engine.
To
qualify
for
this
provision,
the
applicable
OEM
certificate
must
cover
the
same
sales
area
and
model
year
as
requested
certificate
for
the
converted
vehicle
or
engine.
(3)
For
ICI
certification
requests,
the
cost
basis
of
this
section
must
be
the
aggregate
projected
retail
cost
of
the
entire
vehicle(
s)
or
engine(
s),
not
just
the
value
added
by
the
conversion.
If
the
vehicles/
engines
covered
by
an
ICI
certificate
are
not
being
offered
for
sale,
the
manufacturer
shall
use
the
fair
retail
market
value
of
the
vehicles/
engines
as
the
retail
sale
price
required
in
this
section.
For
an
ICI
certification
request,
the
retail
sales
price
(or
fair
retail
market
value)
must
be
based
on
the
applicable
National
Automobile
Dealer's
Association
(NADA)
appraisal
guide
and/
or
other
evidence
of
the
actual
market
value.
(4)
The
aggregate
cost
used
in
this
section
must
be
based
on
the
total
projected
sales
of
all
vehicles
and
engines
under
a
certificate,
including
vehicles
and
engines
modified
under
the
modification
and
test
option
in
40
CFR
85.1509
and
89.609.
The
projection
of
the
number
of
vehicles
or
engines
to
be
covered
by
the
certificate
and
their
projected
retail
selling
price
must
be
based
on
the
latest
information
available
at
the
time
of
the
fee
payment.
(5)
A
manufacturer
may
submit
a
reduced
fee
as
described
in
paragraphs
(a)
and
(b)(
1)
through
(b)(
4)
of
this
section
if
it
is
accompanied
by
a
certification
from
the
manufacturer
that
the
reduced
fee
is
appropriate
under
this
section.
The
reduced
fee
shall
be
deemed
approved,
unless
EPA
determines
that
the
criteria
of
this
section
have
not
been
met.
The
Agency
may
make
such
determination
either
before
or
after
EPA
issues
a
certificate
of
conformity.
If
the
Agency
determines
that
the
requirements
of
this
section
have
not
been
met,
EPA
may:
(i)
Require
that
future
reduced
fee
eligibility
determinations
be
made
by
the
Agency;
(ii)
Require
that
the
manufacturer
for
future
reduced
fee
requests
use
the
special
provisions
contained
in
paragraph
(b)
(7);
or
(iii)
Deny
future
reduced
fee
requests
and
require
submission
of
the
full
fee
payment
until
such
time
as
the
manufacturer
demonstrates
to
the
satisfaction
of
the
Administrator
that
its
reduced
fee
submissions
are
based
on
accurate
date
and
that
final
fee
payments
are
made
within
45
days
of
the
end
of
the
model
year.
(6)
If
the
reduced
fee
is
denied
by
the
Administrator,
the
applicant
will
have
30
days
from
the
date
of
notification
of
the
denial
to
submit
the
appropriate
fee
to
EPA
or
appeal
the
denial.
(7)
The
following
special
provisions
are
available
for
manufacturers
which
meet
the
requirements
of
paragraph
(a)
of
this
section
but,
due
to
the
nature
of
their
business,
are
unable
to
make
good
estimates
of
the
aggregate
projected
retail
sales
price
of
all
the
vehicles
or
engines
to
be
covered
by
the
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Federal
Register
/
Vol.
67,
No.
152
/
Wednesday,
August
7,
2002
/
Proposed
Rules
certification
request
as
required
in
paragraph
(b)(
1)
of
this
section.
EPA
may
also
require
a
manufacturer
to
use
these
special
provisions
rather
than
the
process
described
in
paragraph
(b)(
5)
of
this
section
if
EPA
makes
such
a
determination
under
paragraph
(b)(
5)(
ii)
of
this
section.
(i)
A
manufacturer's
request
to
use
of
these
provisions
requires
advance
Agency
approval
and
will
be
based
on
a
determination
of
whether
the
requirements
of
this
section
have
been
met.
The
request
to
use
these
provisions
shall
be
made
prior
to
the
submission
of
its
application
for
certification.
The
manufacturer
shall
provide
as
part
of
this
request:
(A)
A
statement
that
the
eligibility
requirements
of
paragraph
(a)
of
this
section
are
satisfied;
and
(B)
The
reasons
why
it
is
unable
to
make
a
good
estimate
of
the
aggregate
projected
retail
sales
price
of
all
the
vehicles
or
engines
to
be
covered
by
the
certification
request
as
required
in
paragraph
(b)(
1)
of
this
section.
(ii)
If
the
request
is
approved,
the
initial
reduced
fee
is
the
greater
of:
(A)
1%
of
the
retail
selling
price
of
5
vehicles,
engines,
or
conversions,
as
appropriate;
or
(B)
A
minimum
fee
of
$300.
(c)
Final
Reduced
Fee
Calculation
and
Adjustment.
(1)
Within
30
days
of
the
end
of
the
model
year,
the
manufacturer
shall
submit
a
model
year
reduced
fee
payment
report
covering
all
certificates
issued
in
the
model
year
for
which
the
manufacturer
has
paid
a
reduced
fee.
This
report
will
include:
(i)
The
fee
amount
paid
at
certification
time;
(ii)
The
total
actual
number
of
vehicles
covered
by
the
certificate;
(iii)
A
calculation
of
the
actual
final
reduced
fee
due
for
each
certificate;
and
(iv)
A
difference
between
the
total
fees
paid
and
the
total
final
fees
due
for
the
manufacturer.
(2)
The
final
reduced
fee
shall
be
calculated
using
the
procedures
of
paragraph
(b)
of
this
section
but
using
actual
numbers
rather
than
projections.
(3)
If
the
difference
calculated
in
paragraph
(c)(
1)(
iv)
of
this
section
exceeds
$500
which
is
due
to
the
Agency,
then
the
manufacturer
shall
pay
any
difference
due
between
the
initial
reduced
fee
and
the
final
reduced
fee
using
the
provisions
of
§
85.2408.
This
payment
shall
be
paid
within
45
days
of
the
end
of
the
model
year.
The
total
fees
paid
for
a
certificate
shall
not
exceed
the
applicable
full
fee
of
§
85.2405.
If
a
manufacturer
fails
to
make
complete
payment
within
45
days
or
to
submit
the
report
under
paragraph
(c)(
1)
of
this
section
then
the
Agency
may
void
ab
initio
the
applicable
certificate.
EPA
may
also
refuse
to
grant
reduced
fee
requests
submitted
under
paragraph
(b)(
5)
or
(b)(
7)
of
this
section.
(4)
If
the
initial
reduced
fee
paid
exceeds
the
final
reduced
fee
then
the
manufacturer
may
request
a
refund
using
the
procedures
of
§
85.2407.
(5)
Manufacturers
must
retain
in
their
records
the
basis
used
to
calculate
the
projected
sales
and
fair
retail
market
value
and
the
actual
sales
and
retail
price
for
the
vehicles
and
engines
covered
by
each
certificate
that
is
issued
under
the
reduced
fee
provisions
of
this
section.
This
information
must
be
retained
for
a
period
of
at
least
three
years
after
the
issuance
of
the
certificate
and
must
be
provided
to
the
Agency
within
30
days
of
request.
Manufacturers
are
also
subject
to
the
applicable
maintenance
of
records
requirements
of
Part
86,
Subpart
A.
If
a
manufacturer
fails
to
maintain
the
records
or
provide
such
records
to
EPA
as
required
by
this
paragraph
then
EPA
may
void
ab
initio
the
certificate
for
which
such
records
shall
be
kept.
§
85.2407
Can
I
get
a
refund
if
I
don't
get
a
certificate
or
overpay?
(a)
Full
Refund.
The
Administrator
may
refund
the
total
fee
imposed
by
§
85.2405
if
the
applicant
fails
to
obtain
a
certificate
and
requests
a
refund.
(b)
Partial
Refund.
The
Administrator
may
refund
a
portion
of
a
reduced
fee,
paid
under
§
85.2406,
due
to
a
decrease
in
the
aggregate
projected
retail
sales
price
of
the
vehicles
or
engines
covered
by
the
certification
request.
(1)
Partial
refunds
are
only
available
for
certificates
which
were
used
for
the
sale
of
vehicles
or
engines
within
the
United
States.
(2)
Requests
for
a
partial
refund
may
only
be
made
once
the
model
year
for
the
applicable
certificate
has
ended.
Requests
for
a
partial
refund
must
be
submitted
no
later
than
six
months
after
the
model
year
has
ended.
(3)
EPA
will
only
consider
requests
which
result
in
at
least
a
$500
refund.
Smaller
amounts
of
money
will
not
be
refunded,
nor
can
they
be
credited
to
other
certification
fee
payments
due
to
the
Agency.
(4)
Requests
for
a
partial
refund
must
include
all
the
following:
(i)
A
statement
that
the
applicable
certificate
was
used
for
the
sale
of
vehicles
or
engines
within
the
United
States.
(ii)
A
statement
of
the
fee
amount
paid
(the
reduced
fee)
under
the
applicable
certificate.
(iii)
The
actual
number
of
vehicles
or
engines
produced
under
the
certificate
(whether
or
not
the
vehicles/
engines
have
been
actually
sold).
(iv)
The
actual
retail
selling
or
asking
price
for
the
vehicles
or
engines
produced
under
the
certificate.
(v)
The
calculation
of
the
reduced
fee
amount
using
actual
production
levels
and
retail
prices.
The
calculated
reduced
fee
amount
may
not
be
less
than
$300
under
the
provisions
of
§
85.2406(
b)(
1)(
ii).
(vi)
The
calculated
amount
of
the
refund.
Refund
requests
for
less
than
$500
will
not
be
considered
under
the
provisions
of
paragraph
(b)(
3)
of
this
section.
(c)
Refunds
due
to
errors
in
submission.
The
Agency
will
approve
requests
from
manufacturers
to
correct
errors
in
the
amount
or
application
of
fees
if
the
manufacturer
provides
satisfactory
evidence
that
the
change
is
due
to
an
accidental
error
rather
than
a
change
in
plans.
Requests
to
correct
errors
must
be
made
to
the
Administrator
as
soon
as
possible
after
identifying
the
error.
The
Agency
will
not
consider
requests
to
reduce
fee
amounts
due
to
errors
that
are
reported
more
than
90
days
after
the
issuance
of
the
applicable
certificate
of
conformity.
(d)
In
lieu
of
a
refund,
the
manufacturer
may
apply
the
refund
amount
to
the
amount
due
on
another
certification
request.
(e)
A
request
for
a
full
or
partial
refund
of
a
fee
or
a
report
of
an
error
in
the
fee
payment
or
its
application
must
be
submitted
in
writing
to:
U.
S.
Environmental
Protection
Agency,
Vehicle
Programs
and
Compliance
Division,
Fee
Program
Specialist,
National
Vehicle
and
Fuel
Emission
Laboratory,
2000
Traverwood,
Ann
Arbor,
MI
48105.
§
85.2408
How
do
I
make
a
fee
payment?
(a)
All
fees
required
by
this
subpart
must
be
paid
by
money
order,
bank
draft,
certified
check,
corporate
check,
or
electronic
funds
transfer
payable
in
U.
S.
dollars
to
the
order
of
the
Environmental
Protection
Agency.
(b)
A
completed
fee
filing
form
must
be
sent
to
the
address
designated
on
the
form
for
each
fee
payment
made.
(c)
Fees
must
be
paid
prior
to
submission
of
an
application
for
certification.
The
Agency
will
not
process
applications
for
which
the
appropriate
fee
(or
reduced
fee
amount)
has
not
been
fully
paid.
(d)
If
EPA
denies
a
reduced
fee,
the
proper
fee
must
be
submitted
within
30
days
after
the
notice
of
denial,
unless
the
decision
is
appealed.
If
the
appeal
is
denied,
then
the
proper
fee
must
be
submitted
within
30
days
after
the
notice
of
the
appeal
denial.
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/
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152
/
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7,
2002
/
Proposed
Rules
§
85.2409
Deficiencies.
(a)
Any
filing
pursuant
to
this
subpart
that
is
not
accompanied
by
a
completed
fee
filing
form
and
full
payment
of
the
appropriate
fee
is
deemed
to
be
deficient.
(b)
A
deficient
filing
will
be
rejected
and
the
amount
paid
refunded,
unless
the
full
appropriate
fee
is
submitted
within
a
time
limit
specified
by
the
Administrator.
(c)
EPA
will
not
process
a
request
for
certification
associated
with
any
filing
that
is
deficient
under
this
section.
(d)
The
date
of
filing
will
be
deemed
the
date
on
which
EPA
receives
the
full
appropriate
fee
and
the
completed
fee
filing
form.
§
85.2410
Special
provisions
applicable
to
the
2003
model
year
only.
(a)
For
the
2003
model
year,
the
fees
specified
in
sec.
85.2405
of
this
part
will
be
waived
for
any
light
duty
vehicle,
light
duty
truck,
or
heavy
duty
engine
certification
request
that
meets
the
small
volume
sales
requirements
of
40
CFR
86.1838–
01
or
86.098–
14,
as
applicable,
and:
(1)
Is
a
dedicated
gaseous
fueled
vehicle
or
engine;
or
(2)
Receives
a
certificate
of
conformity
with
the
LEV,
ILEV,
ULEV,
or
ZEV
emissions
standards
in
40
CFR
part
88.
(b)
This
section
does
not
apply
to
2004
model
year
and
later
vehicles
or
engines.
PART
86—
CONTROL
OF
EMISSIONS
FROM
NEW
AND
IN
USE
HIGHWAY
VEHICLES
AND
ENGINES
3.
The
Authority
for
Part
86
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401–
7671q.
Subpart
J—[
Amended]
4.
Section
86.903–
93
is
revised
to
read
as
follows:
§
86.903–
93
Applicability.
(a)
This
subpart
prescribes
fees
to
be
charged
for
the
MVECP
for
the
1993
through
2003
model
year.
The
fees
charged
will
apply
to
all
manufacturers'
and
ICIs',
LDVs,
LDTs,
HDVs,
HDEs,
and
MCs.
Nothing
in
this
subpart
shall
be
construed
to
limit
the
Administrator's
authority
to
require
manufacturer
or
confirmatory
testing
as
provided
in
the
Clean
Air
Act,
including
authority
to
require
manufacturer
in
use
testing
as
provided
in
section
208
of
the
Clean
Air
Act.
(b)
The
fees
prescribed
in
this
subpart
are
replaced
by
the
requirements
of
40
CFR
part
85,
subpart
Y
for
2003
and
later
certification
requests
received
on
or
after
[60
days
after
the
date
of
publication
of
the
final
rule].
(c)
The
fees
prescribed
in
this
subpart
will
only
apply
to
those
2003
model
year
certification
requests
which
are
complete,
include
all
data
required
by
this
title,
and
are
received
by
the
Agency
prior
to
[60
days
after
the
date
of
publication
of
the
final
rule].
[FR
Doc.
02–
19563
Filed
8–
6–
02;
8:
45
am]
BILLING
CODE
6560–
50–
P
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| epa | 2024-06-07T20:31:39.893704 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0023-0001/content.txt"
} |
EPA-HQ-OAR-2002-0024-0001 | Proposed Rule | "2002-08-14T04:00:00" | Control of Emissions From Spark-Ignition Marine Vessels and Highway Motorcycles | Wednesday,
August
14,
2002
Part
II
Environmental
Protection
Agency
40
CFR
Parts
86,
90,
1045,
1051
and
1068
Control
of
Emissions
From
Spark
Ignition
Marine
Vessels
and
Highway
Motorcycles;
Proposed
Rule
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Federal
Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
86,
90,
1045,
1051,
and
1068
[AMS–
FRL–
7253–
8]
RIN
2060–
AJ90
Control
of
Emissions
From
SparkIgnition
Marine
Vessels
and
Highway
Motorcycles
AGENCY:
Environmental
Protection
Agency
(EPA).
ACTION:
Notice
of
proposed
rulemaking.
SUMMARY:
In
this
action,
we
are
proposing
evaporative
emissions
standards
for
marine
vessels
that
use
spark
ignition
engines
(including
sterndrive,
inboard,
and
outboard
engines
and
personal
watercraft)
and
we
discuss
our
plans
to
propose
standards
in
the
future
regulating
exhaust
emissions
from
spark
ignition
marine
engines.
This
action
also
proposes
new
emission
standards
for
highway
motorcycles,
including
motorcycles
of
less
than
50
cubic
centimeters
in
displacement.
This
action
is
related
to
our
proposal
for
emission
standards
for
several
sources
that
cause
or
contribute
to
air
pollution.
On
October
5,
2001
we
published
proposed
standards
for
large
spark
ignition
engines
such
as
those
used
in
forklifts
and
airport
tugs;
recreational
vehicles
using
sparkignition
engines
such
as
off
highway
motorcycles,
all
terrain
vehicles,
and
snowmobiles;
and
recreational
marine
diesel
engines.
Nationwide,
marine
evaporative
hydrocarbon
(HC)
emissions
contribute
to
ozone,
and
motorcycles
contribute
to
ozone,
carbon
monoxide
(CO),
and
particulate
matter
(PM)
nonattainment.
These
pollutants
cause
a
range
of
adverse
health
effects,
especially
in
terms
of
respiratory
impairment
and
related
illnesses.
The
proposed
standards
would
help
states
achieve
and
maintain
air
quality
standards.
In
addition,
the
proposed
evaporative
emission
standards
would
help
reduce
acute
exposure
air
toxics
and
the
proposed
motorcycle
exhaust
standards
would
help
reduce
exposure
to
CO,
air
toxics,
and
PM
for
operators
and
other
people
close
to
emission
sources.
They
would
also
help
address
other
environmental
problems,
such
as
visibility
impairment
in
our
national
parks.
We
believe
that
manufacturers
would
be
able
to
maintain
or
even
improve
the
performance
of
their
products
in
certain
respects
when
producing
engines
and
vessels
meeting
the
proposed
standards.
In
fact,
we
estimate
that
the
evaporative
emission
standards
would
reduce
fuel
consumption
by
enough
to
offset
any
costs
associated
with
the
evaporative
emission
control
technology.
Overall,
the
gasoline
fuel
savings
associated
with
the
anticipated
changes
in
technology
resulting
from
the
rule
proposed
in
this
notice
are
estimated
to
be
about
31
million
gallons
per
year
once
the
program
is
fully
phased
in
(2030).
The
proposal
also
has
several
provisions
to
address
the
unique
limitations
of
smallvolume
manufacturers.
DATES:
Comments:
Send
written
comments
on
this
proposal
by
November
8,
2002.
See
Section
VII
for
more
information
about
written
comments.
Hearings:
We
will
hold
a
public
hearing
on
September
17,
2002
starting
at
9:
30
a.
m.
EDT.
This
hearing
will
focus
on
issues
related
to
highway
motorcycles.
In
addition,
we
will
hold
a
public
hearing
on
September
23,
2002
starting
at
9:
30
a.
m.
EDT.
This
hearing
will
focus
on
issues
related
to
marine
vessels.
If
you
want
to
testify
at
a
hearing,
notify
the
contact
person
listed
below
at
least
ten
days
before
the
hearing.
See
Section
VII
for
more
information
about
public
hearings.
ADDRESSES:
Comments:
You
may
send
written
comments
in
paper
form
or
by
e
mail.
We
must
receive
them
by
November
8,
2002.
Send
paper
copies
of
written
comments
(in
duplicate
if
possible)
to
the
contact
person
listed
below.
You
may
also
submit
comments
via
e
mail
to
``
MCNPRM@
epa.
gov.
''
In
your
correspondence,
refer
to
Docket
A–
2000–
02.
Hearings:
We
will
hold
a
public
hearing
for
issues
related
to
highway
motorcycles
on
September
17
at
the
Ypsilanti
Marriott
at
Eagle
Crest,
Ypsilanti,
Michigan
(734–
487–
2000).
We
will
host
a
public
hearing
for
issues
related
to
marine
vessels
on
September
23
at
the
National
Vehicle
and
Fuel
Emission
Laboratory,
2000
Traverwood
Dr.,
Ann
Arbor,
Michigan
(734–
214–
4334).
See
Section
VII,
``
Public
Participation''
below
for
more
information
on
the
comment
procedure
and
public
hearings.
Docket:
EPA's
Air
Docket
makes
materials
related
to
this
rulemaking
available
for
review
in
Public
Docket
Nos.
A–
2000–
01
and
A–
2000–
02
at
the
following
address:
U.
S.
Environmental
Protection
Agency
(EPA),
Air
Docket
(6102),
Room
M–
1500
(on
the
ground
floor
in
Waterside
Mall),
401
M
Street,
SW.,
Washington,
DC
20460
between
8
a.
m.
to
5:
30
p.
m.,
Monday
through
Friday,
except
on
government
holidays.
You
can
reach
the
Air
Docket
by
telephone
at
(202)
260–
7548,
and
by
facsimile
(202)
260–
4400.
We
may
charge
a
reasonable
fee
for
copying
docket
materials,
as
provided
in
40
CFR
part
2.
FOR
FURTHER
INFORMATION
CONTACT:
Margaret
Borushko,
U.
S.
EPA,
National
Vehicle
and
Fuels
Emission
Laboratory,
2000
Traverwood,
Ann
Arbor,
MI
48105;
Telephone
(734)
214–
4334;
FAX:
(734)
214–
4816;
E
mail:
borushko.
margaret@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Regulated
Entities
This
proposed
action
would
affect
companies
that
manufacture
or
introduce
into
commerce
any
of
the
engines
or
vehicles
that
would
be
subject
to
the
proposed
standards.
These
include:
Marine
vessels
with
sparkignition
engines
and
highway
motorcycles.
This
proposed
action
would
also
affect
companies
buying
engines
for
installation
in
vessels
and
motorcycles.
There
are
also
proposed
requirements
that
apply
to
those
who
rebuild
any
of
the
affected
engines.
Regulated
categories
and
entities
include:
Category
NAICS
codes
a
SIC
codes
b
Examples
of
potentially
regulated
entities
Industry
........................................................
........................
3732
Manufacturers
of
marine
vessels.
Industry
........................................................
811310
7699
Engine
repair
and
maintenance.
Industry
........................................................
336991
........................
Motorcycles
and
motorcycle
parts
manufacturers.
Industry
........................................................
421110
........................
Independent
Commercial
Importers
of
Vehicles
and
Parts.
a
North
American
Industry
Classification
System
(NAICS).
b
Standard
Industrial
Classification
(SIC)
system
code.
This
list
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
particular
activities
may
be
regulated
by
this
action,
you
should
carefully
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Federal
Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
1
See
66
FR
51098.
2
Diesel
cycle
engines,
referred
to
simply
as
``
diesel
engines''
in
this
document,
may
also
be
referred
to
as
compression
ignition
(or
CI)
engines.
These
engines
typically
operate
on
diesel
fuel,
but
other
fuels
may
also
be
used.
Otto
cycle
engines
(referred
to
here
as
spark
ignition
or
SI
engines)
typically
operate
on
gasoline,
liquefied
petroleum
gas,
or
natural
gas.
3
While
we
characterize
emissions
of
hydrocarbons,
this
can
be
used
as
a
surrogate
for
volatile
organic
compounds
(VOC),
which
is
broader
group
of
compounds.
examine
the
proposed
regulations.
You
may
direct
questions
regarding
the
applicability
of
this
action
to
the
person
listed
in
FOR
FURTHER
INFORMATION
CONTACT.
Obtaining
Electronic
Copies
of
the
Regulatory
Documents
The
preamble,
regulatory
language,
Draft
Regulatory
Support
Document,
and
other
rule
documents
are
also
available
electronically
from
the
EPA
Internet
Web
site.
This
service
is
free
of
charge,
except
for
any
cost
incurred
for
internet
connectivity.
The
electronic
version
of
this
proposed
rule
is
made
available
on
the
day
of
publication
on
the
primary
Web
site
listed
below.
The
EPA
Office
of
Transportation
and
Air
Quality
also
publishes
official
Federal
Register
notices
and
related
documents
on
the
secondary
Web
site
listed
below.
1.
http://
www.
epa.
gov/
docs/
fedrgstr/
EPA–
AIR/
(either
select
desired
date
or
use
Search
feature)
2.
http://
www.
epa.
gov/
otaq/
(look
in
What's
New
or
under
the
specific
rulemaking
topic)
Please
note
that
due
to
differences
between
the
software
used
to
develop
the
documents
and
the
software
into
which
the
document
may
be
downloaded,
format
changes
may
occur.
Table
of
Contents
I.
Introduction
A.
Overview
B.
How
Is
this
Document
Organized?
C.
What
Categories
of
Vessels
and
Vehicles
are
Covered
in
This
Proposal?
D.
What
Requirements
Are
We
Proposing?
E.
Why
Is
EPA
Taking
This
Action?
F.
Putting
This
Proposal
into
Perspective
II.
Public
Health
and
Welfare
Effects
of
Emissions
from
Covered
Engines
A.
Background
B.
What
Are
the
Public
Health
and
Welfare
Effects
Associated
With
Emissions
From
Nonroad
Engines
and
Motorcycles
Subject
to
the
Proposed
Standards?
C.
What
Is
the
Inventory
Contribution
of
These
Sources?
III.
Evaporative
Emission
Control
from
Boats
A.
Overview
B.
Boats/
Fuel
Systems
Covered
By
This
Proposal
C.
Proposed
Evaporative
Emission
Requirements
D.
Demonstrating
Compliance
E.
General
Compliance
Provisions
F.
Proposed
Testing
Requirements
G.
Special
Compliance
Provisions
H.
Technological
Feasibility
IV.
Sterndrive
and
Inboard
Marine
Engines
V.
Highway
Motorcycles
A.
Overview
B.
Motorcycles
Covered
by
This
Proposal
C.
Proposed
Standards
D.
Special
Compliance
Provisions
E.
Technological
Feasibility
of
the
Standards
VI.
Projected
Impacts
A.
Environmental
Impact
B.
Economic
Impact
C.
Cost
per
Ton
of
Emissions
Reduced
D.
Additional
Benefits
VII.
Public
Participation
A.
How
Do
I
Submit
Comments?
B.
Will
There
Be
a
Public
Hearing?
VII.
Administrative
Requirements
A.
Administrative
Designation
and
Regulatory
Analysis
(Executive
Order
12866)
B.
Regulatory
Flexibility
Act
C.
Paperwork
Reduction
Act
D.
Intergovernmental
Relations
E.
National
Technology
Transfer
and
Advancement
Act
F.
Protection
of
Children
(Executive
Order
13045)
G.
Federalism
(Executive
Order
13132)
H.
Energy
Effects
(Executive
Order
13211)
I.
Plain
Language
I.
Introduction
A.
Overview
Air
pollution
is
a
serious
threat
to
the
health
and
well
being
of
millions
of
Americans
and
imposes
a
large
burden
on
the
U.
S.
economy.
Ground
level
ozone,
carbon
monoxide,
and
particulate
matter
are
linked
to
potentially
serious
respiratory
health
problems,
especially
respiratory
effects
and
environmental
degradation,
including
visibility
impairment
in
our
precious
national
parks.
Over
the
past
quarter
century,
state
and
federal
representatives
have
established
emission
control
programs
that
significantly
reduce
emissions
from
individual
sources.
Many
of
these
sources
now
pollute
at
only
a
small
fraction
of
their
pre
control
rates.
This
proposal
is
part
of
a
new
effort
that
further
addresses
these
air
pollution
concerns
by
proposing
national
standards
regulating
emissions
from
several
types
of
nonroad
engines
and
vehicles
that
are
currently
unregulated
by
establishing
standards
for
nonroad
engines
and
vehicles,
as
required
by
Clean
Air
Act
section
213(
a)(
3).
The
first
part
of
this
effort
was
a
proposal
published
on
October
5,
2001
which
included
industrial
spark
ignition
engines
such
as
those
used
in
forklifts
and
airport
tugs;
recreational
vehicles
such
as
off
highway
motorcycles,
allterrain
vehicles,
and
snowmobiles;
and
recreational
marine
diesel
engines.
1
This
action,
the
second
part,
includes
evaporative
emission
standards
for
marine
vessels
with
spark
ignition
engines
and
their
fuel
systems.
2
In
addition,
we
are
proposing
new
emission
standards
for
highway
motorcycles.
The
proposed
standards
for
motorcycles
reflect
the
development
of
emission
control
technology
that
has
occurred
since
we
last
set
standards
for
these
engines
in
1978.
Including
highway
motorcycles
in
this
proposal
is
also
appropriate
as
we
consider
new
emission
standards
for
the
counterpart
off
highway
motorcycle
models.
Nationwide,
the
sources
covered
by
this
proposal
are
significant
contributors
to
mobile
source
air
pollution.
Marine
evaporative
emissions
currently
account
for
1.3
percent
of
mobile
source
hydrocarbon
(HC)
emissions,
and
highway
motorcycles
currently
account
for
about
1.1
percent
of
mobile
source
HC
emissions,
0.4
percent
of
mobilesource
carbon
monoxide
(CO)
emissions,
0.1
percent
of
mobile
source
oxides
of
nitrogen
(NOX)
emissions,
and
0.1
percent
of
mobile
source
particulate
matter
(PM)
emissions.
3
The
proposed
standards
would
reduce
exposure
to
these
emissions
and
help
avoid
a
range
of
adverse
health
effects
associated
with
ambient
ozone
and
PM
levels,
especially
in
terms
of
respiratory
impairment
and
related
illnesses.
In
addition,
the
proposed
standards
would
help
reduce
acute
exposure
air
toxics
and
PM
for
persons
who
operate
or
who
work
with
or
are
otherwise
active
in
close
proximity
to
these
sources.
They
would
also
help
address
other
environmental
problems
associated
with
these
sources,
such
as
visibility
impairment
in
our
national
parks
and
other
wilderness
areas
where
recreational
vehicles
and
marine
vessels
are
often
used.
This
proposal
follows
EPA's
Advance
Notice
of
Proposed
Rulmaking
(ANRPM)
published
on
December
7,
2000
(65
FR
76797).
In
that
Advance
Notice,
we
provided
an
initial
overview
of
possible
regulatory
strategies
for
nonroad
vehicles
and
engines
and
invited
early
input
to
the
process
of
developing
standards.
We
received
comments
on
the
Advance
Notice
from
a
wide
variety
of
stakeholders,
including
the
engine
industry,
the
equipment
industry,
various
governmental
bodies,
environmental
groups,
and
the
general
public.
These
comments
are
available
for
public
viewing
in
Docket
A–
2000–
01.
The
Advance
Notice,
the
related
comments,
and
other
new
information
provide
the
framework
for
this
proposal.
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/
Vol.
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No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
4
For
this
proposal,
we
consider
the
United
States
to
include
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.
B.
How
Is
This
Document
Organized?
This
proposal
covers
both
marine
vessels
and
highway
motorcycles
and
many
readers
may
only
be
interested
in
one
or
the
other
of
theses
applications.
We
have
attempted
to
organize
the
document
in
a
way
that
allows
each
reader
to
focus
on
the
application
of
particular
interest.
The
Air
Quality
discussion
in
Section
II
is
general
in
nature,
however,
and
applies
to
the
proposal
as
a
whole.
The
next
three
sections
contain
our
proposal
for
the
marine
vessels
and
highway
motorcycles
that
are
the
subject
of
this
action.
Section
III
presents
the
proposed
evaporative
emission
program
for
marine
vessels
using
spark
ignition
engines.
Section
IV
discusses
our
intentions
for
controlling
exhaust
emissions
from
spark
ignition
marine
engines
in
the
future.
Section
V
contains
our
proposed
highway
motorcycle
standards.
Section
VI
summarizes
the
projected
impacts
and
a
discussion
of
the
benefits
of
this
proposal.
Finally,
Sections
VII
and
VIII
contain
information
about
public
participation,
how
we
satisfied
our
administrative
requirements,
and
the
statutory
provisions
and
legal
authority
for
this
proposal.
The
remainder
of
this
Section
I
summarizes
important
background
information
about
this
proposal,
including
the
engines
covered,
the
proposed
standards,
and
why
we
are
proposing
them.
C.
What
Categories
of
Vessels
and
Vehicles
Are
Covered
in
This
Proposal?
1.
Which
Marine
Vessels
Are
Covered
in
This
Proposal?
We
are
proposing
evaporative
emission
requirements
for
marine
vessels
that
use
any
kind
of
spark
ignition
(SI)
engine,
including
boats
using
sterndrive,
inboard,
and
outboard
engines
and
personal
watercraft.
These
vessels
are
currently
unregulated
for
evaporative
emissions.
Although
we
are
not
proposing
exhaust
emission
standards
for
SI
marine,
we
discuss
our
intent
for
a
future
emission
control
program.
This
proposal
covers
new
vessels
that
are
used
in
the
United
States,
whether
they
are
made
domestically
or
imported.
4
A
more
detailed
discussion
of
the
meaning
of
the
terms
``
new,
''
``
imported,
''
as
well
as
other
terms
that
help
define
the
scope
of
application
of
this
proposal,
is
contained
in
Section
III.
B
of
this
preamble.
2.
Which
Highway
Vehicles
Are
Covered
in
This
Proposal?
We
are
proposing
standards
for
new
highway
motorcycles,
including
those
with
engines
with
displacements
of
less
than
50
cubic
centimeters
(cc).
The
federal
emission
standards
for
highway
motorcycles
were
established
over
twenty
years
ago.
Technology
has
advanced
significantly
over
the
last
two
decades,
and
many
advancements
are
currently
being
used
on
highway
motorcycles
in
California
and
elsewhere
in
the
world.
Despite
these
advancements,
highway
motorcycles
currently
produce
more
harmful
emissions
per
mile
than
driving
a
car,
or
even
a
large
SUV.
(This
discrepancy
will
become
even
larger
when
the
Tier
2
emissions
standards
for
passenger
cars
and
SUVs
take
effect
starting
in
2004,
when
SUVs
will
have
to
meet
the
same
set
of
standards
as
passenger
cars.)
Present
technology
already
in
use
on
highway
motorcycles
can
be
applied
easily
and
cost
effectively
to
achieve
additional
improvements
in
emissions.
California,
which
has
separately
regulated
motorcycles,
recently
adopted
more
advanced
emissions
standards
in
several
stages.
New
emission
standards
and
test
procedures
have
also
been
proposed
or
finalized
internationally.
Proposing
more
stringent
standards
nationwide
will
reduce
emissions
from
these
engines,
which
operate
predominantly
in
warmer
weather
when
ozone
formation
is
a
greater
concern.
In
addition,
we
believe
it
is
important
to
consider
the
emissions
standards
for
highway
motorcycles
in
the
context
of
setting
standards
for
off
highway
motorcycles.
Some
degree
of
consistency
between
the
standards
for
these
related
products
may
allow
manufacturers
to
transfer
technologies
across
product
lines.
(At
the
same
time,
we
recognize
that
there
are
other
factors
which
may
argue
for
treating
these
categories
differently.)
D.
What
Requirements
Are
We
Proposing?
Clean
Air
Act
section
213
directs
EPA
to
establish
standards
which
achieve
the
greatest
degree
of
emission
reductions
from
nonroad
engines
and
vehicles
achievable
through
the
application
of
technology
that
will
be
available,
giving
appropriate
consideration
to
cost,
noise,
energy,
and
safety
factors.
Other
requirements
such
as
certification
procedures,
engine
and
vehicle
labeling,
and
warranty
requirements
are
necessary
for
implementing
the
proposed
program
in
an
effective
way.
For
vessels
that
use
spark
ignition
marine
engines,
we
are
proposing
emission
standards,
beginning
in
2008,
that
would
reduce
evaporative
hydrocarbon
emissions
by
more
than
80
percent.
To
meet
these
standards,
manufacturers
would
need
to
design
and
produce
fuel
systems
that
prevent
gasoline
vapors
from
escaping.
While
we
are
not
proposing
exhaust
emission
standards
for
spark
ignition
marine
engines
at
this
time,
we
are
participating
with
California
and
industry
representatives
in
a
technology
development
program
that
is
evaluating
the
feasibility
of
using
catalyst
controls
on
these
engines.
We
considered
setting
emission
standards
for
sterndrive
and
inboard
marine
engines
in
this
rulemaking,
but
have
decided
not
to
pursue
these
standards
at
this
time.
We
instead
intend
to
propose
exhaust
emission
standards
for
these
engines
after
the
results
of
this
development
program
are
available.
We
also
intend
at
that
time
to
review,
and
if
appropriate,
propose
to
update
emission
standards
for
outboard
and
personal
watercraft
engines
based
on
the
results
of
the
ongoing
catalyst
test
program.
With
respect
to
highway
motorcycles,
section
202(
a)(
3)(
E)
of
the
Clean
Air
Act
states,
in
part:
``
In
any
case
in
which
such
standards
are
promulgated
for
such
emissions
from
motorcycles
as
a
separate
class
or
category,
the
Administrator,
in
promulgating
such
standards,
shall
consider
the
need
to
achieve
equivalency
of
emission
reductions
between
motorcycles
and
other
motor
vehicles
to
the
maximum
extent
practicable.
''
Given
that
it
has
been
more
than
twenty
years
since
the
first
(and
only)
federal
emission
regulations
for
motorcycles
were
implemented,
we
believe
it
is
consistent
with
the
Act
to
set
new
standards
for
highway
motorcycles.
Thus,
for
highway
motorcycles
we
are
proposing
to
harmonize
with
the
California
program,
but
with
some
additional
flexibilities.
This
is
a
two
phase
program
that
would
result
in
reductions
of
HC+
NOX
of
about
50
percent
when
fully
phased
in.
E.
Why
Is
EPA
Taking
This
Action?
There
are
important
public
health
and
welfare
reasons
supporting
the
standards
proposed
in
this
document.
As
described
in
Section
II,
these
sources
contribute
to
air
pollution
which
causes
public
health
and
welfare
problems.
Emissions
from
these
engines
contribute
to
ground
level
ozone
and
ambient
CO
and
PM
levels.
Exposure
to
ground
level
ozone,
CO,
and
PM
can
cause
serious
respiratory
problems.
These
emissions
also
contribute
to
other
serious
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Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
5
This
study
is
avaialble
in
docket
A–
92–
28.
6
The
Clean
Air
Act
limits
the
role
states
may
play
in
regulating
emissions
from
new
motor
vehicles
and
nonroad
engines.
California
is
permitted
to
establish
emission
standards
for
new
motor
vehicles
and
most
nonroad
engines;
other
states
may
adopt
California's
programs
(sections
209
and
177
of
the
Act).
The
Act
specifies
the
power
rating
minimum
in
terms
of
horsepower
for
farm
and
construction
equipment
(175
hp
=
130
kW).
environmental
problems,
including
visibility
impairment.
F.
Putting
This
Proposal
Into
Perspective
This
proposal
should
be
considered
in
the
broader
context
of
EPA's
nonroad
and
highway
vehicle
emission
control
programs;
state
level
programs,
particularly
in
California;
and
international
efforts.
Each
of
these
are
described
in
more
detail
below.
1.
EPA's
Emission
Control
Programs
a.
EPA's
nonroad
process.
Clean
Air
Act
section
213(
a)(
1)
directs
us
to
study
emissions
from
nonroad
engines
and
vehicles
to
determine,
among
other
things,
whether
these
emissions
``
cause,
or
significantly
contribute
to,
air
pollution
that
may
reasonably
be
anticipated
to
endanger
public
health
or
welfare.
''
Section
213(
a)(
2)
further
required
us
to
determine
whether
emissions
of
CO,
VOC,
and
NOX
from
all
nonroad
engines
significantly
contribute
to
ozone
or
CO
emissions
in
more
than
one
nonattainment
area.
If
we
determine
that
emissions
from
all
nonroad
engines
were
significant
contributors,
section
213(
a)(
3)
then
requires
us
to
establish
emission
standards
for
classes
or
categories
of
new
nonroad
engines
and
vehicles
that
in
our
judgment
cause
or
contribute
to
such
pollution.
We
may
also
set
emission
standards
under
section
213(
a)(
4)
regulating
any
other
emissions
from
nonroad
engines
that
we
find
contribute
significantly
to
air
pollution.
We
completed
the
Nonroad
Engine
and
Vehicle
Emission
Study,
required
by
Clean
Air
Act
section
213(
a)(
1),
in
November
1991.
5
On
June
17,
1994,
we
made
an
affirmative
determination
under
section
213(
a)(
2)
that
nonroad
emissions
are
significant
contributors
to
ozone
or
CO
in
more
than
one
nonattainment
area.
We
also
determined
that
these
engines
make
a
significant
contribution
to
PM
and
smoke
emissions
that
may
reasonably
be
anticipated
to
endanger
public
health
or
welfare.
In
the
same
document,
we
set
a
first
phase
of
emission
standards
(now
referred
to
as
Tier
1
standards)
for
landbased
nonroad
diesel
engines
rated
at
or
above
37
kW.
We
recently
added
a
more
stringent
set
of
Tier
2
and
Tier
3
emission
levels
for
new
land
based
nonroad
diesel
engines
at
or
above
37
kW
and
adopted
Tier
1
standards
for
land
based
nonroad
diesel
engines
less
than
37
kW.
Our
other
emission
control
programs
for
nonroad
engines
are
listed
in
Table
I.
F–
1.
This
proposal
takes
another
step
toward
the
comprehensive
nonroad
engine
emission
control
strategy
envisioned
in
the
Act
by
proposing
an
emission
control
program
for
the
remaining
unregulated
nonroad
engines.
TABLE
I.
F–
1.—
EPA'S
NONROAD
EMISSION
CONTROL
PROGRAMS
Engine
category
Final
rule
Date
Land
based
diesel
engines
37
kW—
Tier
1
...........................................................................................
56
FR
31306
June
17,
1994.
Spark
ignition
engines
19
kW—
Phase
1
................................................................................................
60
FR
34581
July
3,
1995.
Spark
ignition
marine
................................................................................................................................
61
FR
52088
October
4,
1996.
Locomotives
..............................................................................................................................................
63
FR
18978
April
16,
1998.
Land
based
diesel
engines—
Tier
1
and
Tier
2
for
engines
<
37
kW—
Tier
2
and
Tier
3
for
engines
37
kW.
63
FR
56968
October
23,
1998.
Commercial
marine
diesel
........................................................................................................................
64
FR
73300
December
29,
1999.
Spark
ignition
engines
19
kW
(Non
handheld)—
Phase
2
.....................................................................
64
FR
15208
March
30,
1999.
Spark
ignition
engines
19
kW
(Handheld)—
Phase
2
.............................................................................
65
FR
24268
April
25,
2000.
b.
National
standards
for
marine
engines.
In
the
October
1996
final
rule
for
spark
ignition
marine
engines,
we
set
standards
only
for
outboard
and
personal
watercraft
engines.
We
decided
not
to
finalize
emission
standards
for
sterndrive
or
inboard
marine
engines
at
that
time.
Uncontrolled
emission
levels
from
sterndrive
and
inboard
marine
engines
were
already
significantly
lower
than
the
outboard
and
personal
watercraft
engines.
We
did,
however,
leave
open
the
possibility
of
revisiting
the
need
for
emission
standards
for
sterndrive
and
inboard
engines
in
the
future.
c.
National
standards
for
highway
motorcycles.
National
standards
for
highway
motorcycles
were
first
established
in
the
1978
model
year.
Interim
standards
were
effective
for
the
1978
and
1979
model
years,
and
final
standards
took
effect
with
the
1980
model
year.
These
standards
remain
in
effect
today,
unchanged
from
more
than
two
decades
ago.
These
standards,
which
have
resulted
in
the
phase
out
of
two
stroke
engines
for
highway
motorcycles
above
50cc
displacement,
achieved
significant
reductions
in
emissions.
The
level
of
technology
required
to
meet
these
standards
is
widely
considered
to
be
comparable
to
the
pre
catalyst
technology
in
the
automobile.
However,
for
the
past
two
decades,
other
agencies
in
Europe,
Asia,
and
California
have
caused
motorcycle
emission
controls
to
keep
some
pace
with
the
available
technology.
It
is
clear
that
the
impact
of
the
current
federal
standards
on
technology
was
fully
realized
by
the
mid
1980's,
and
that
the
international
and
other
efforts
have
been
the
recent
driving
factor
in
technology
development
for
motorcycle
emissions
control.
2.
State
Initiatives
Under
Clean
Air
Act
section
209,
California
has
the
authority
to
regulate
emissions
from
new
motor
vehicles
and
new
motor
vehicle
engines.
California
may
also
regulate
emissions
from
nonroad
engines,
with
the
exception
of
new
engines
used
in
locomotives
and
new
engines
used
in
farm
and
construction
equipment
rated
under
130
kW.
6
So
far,
the
California
Air
Resources
Board
(California
ARB)
has
adopted
requirements
for
four
groups
of
nonroad
engines:
(1)
Diesel
and
Ottocycle
small
off
road
engines
rated
under
19
kW;
(2)
new
land
based
nonroad
diesel
engines
rated
over
130
kW;
(3)
land
based
nonroad
recreational
engines,
including
all
terrain
vehicles,
off
highway
motorcycles,
go
carts,
and
other
similar
vehicles;
and
(4)
new
nonroad
SI
engines
rated
over
19
kW.
They
have
approved
a
voluntary
registration
and
control
program
for
existing
portable
equipment.
Other
states
may
adopt
emission
standards
set
by
California
ARB,
but
are
otherwise
preempted
from
setting
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Register
/
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157
/
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August
14,
2002
/
Proposed
Rules
emission
standards
for
new
engines
or
vehicles.
In
contrast,
there
is
generally
no
federal
preemption
of
state
initiatives
related
to
the
way
individuals
use
individual
engines
or
vehicles.
a.
SI
Marine
engines.
California
ARB
developed
exhaust
emission
standards
for
SI
marine
engines
through
two
rulemakings.
In
1998,
they
adopted
standards
for
outboards
and
personal
watercraft
that
have
three
stages.
Beginning
with
the
2001
model
year,
manufacturers
must
meet
the
2006
EPA
national
averaging
standard
for
engines
sold
in
California.
In
addition,
they
require
two
more
phases
in
2004
and
2008
which
reduce
the
standards
an
additional
20
and
60
percent,
respectively,
beyond
the
EPA
standards.
Last
year,
California
ARB
also
adopted
exhaust
emission
standards
for
sterndrive
and
inboard
marine
engines.
These
standards
cap
HC+
NOX
emissions
at
15
g/
kW
hr
beginning
in
2003.
In
2007,
45
percent
of
each
manufacturer's
product
line
must
meet
5
g/
kW
hr
HC+
NOX.
This
production
fraction
becomes
75
percent
in
2008
and
100
percent
in
2009.
Manufacturers
will
likely
need
to
use
catalytic
converters
to
meet
this
standard.
As
part
of
the
emission
control
program
for
sterndrive
and
inboard
marine
engines,
California
ARB
has
committed
to
performing
a
review
of
emission
control
technology
in
conjunction
with
the
industry,
U.
S.
Coast
Guard,
and
EPA.
They
intend
to
hold
a
technology
review
in
2003,
and
if
necessary,
hold
another
technology
review
in
2005.
The
technology
review
will
focus
on
applying
catalytic
control
to
marine
engines
operating
in
boats
on
the
water.
EPA
is
working
with
these
groups
to
continue
to
assess
technical
concerns
related
to
introducing
catalysts
on
these
marine
engines.
b.
Highway
motorcycles.
Motorcycle
emission
standards
in
California
were
originally
identical
to
the
federal
standards.
However,
California
ARB
has
revised
their
standards
several
times
to
bring
them
to
their
current
levels.
In
the
1982
model
year
the
standards
were
modified
to
tighten
the
HC
standard
from
5.0
g/
km
to
1.0
or
1.4
g/
km,
depending
upon
engine
displacement.
California
adopted
an
evaporative
emission
standard
of
2.0
g/
test
for
1983
and
later
model
year
motorcycles,
and
later
amended
the
regulations
for
1988
and
later
model
year
motorcycles,
resulting
in
standards
of
1.0
g/
km
HC
for
engines
under
700cc
and
1.4
g/
km
HC
for
700cc
and
larger
engines.
In
1999
California
ARB
finalized
new
standards
for
Class
III
highway
motorcycles
that
will
take
effect
in
two
phases—``
Tier
1''
standards
starting
with
the
2004
model
year,
followed
by
``
Tier
2''standards
starting
with
the
2008
model
year.
The
Tier
1
standard
is
1.4
g/
km
HC+
NOX,
and
the
Tier
2
standard
is
0.8
g/
km
HC+
NOX.
The
CO
standard
remains
at
12.0
g/
km.
3.
Actions
in
Other
Countries
a.
European
action—
Recreational
Marine
Engines.
The
European
Commission
has
proposed
emission
standards
for
recreational
marine
engines,
including
both
diesel
and
gasoline
engines.
These
requirements
would
apply
to
all
new
engines
sold
in
member
countries.
The
numerical
emission
standards
for
SD/
I
marine
engines,
are
shown
in
Table
I.
F–
2.
Table
I.
F–
2
also
presents
average
baseline
emissions
based
on
data
that
we
have
collected.
These
data
are
presented
in
Chapter
4
of
the
Draft
Regulatory
Support
Document.
We
have
received
comment
that
we
should
apply
these
standards
in
the
U.
S.,
but
the
proposed
European
emission
standards
for
SD/
I
marine
engines
may
not
result
in
a
decrease
in
emissions,
and
based
on
emissions
information
we
now
have,
would
in
some
cases
allow
an
increase
in
emissions
from
current
designs
of
engines
operated
in
the
U.
S.
TABLE
I.
F–
2.—
PROPOSED
EUROPEAN
EMISSION
STANDARDS
FOR
FOUR
STROKE
SPARK
IGNITION
MARINE
ENGINES
Pollutant
Emission
standard
(g/
kW
hr)
Baseline
emissions
(g/
kW–
hr)
NOX
......................................................................................................................................................................
15.0
9.7
HC
........................................................................................................................................................................
a
7.2
5.8
CO
........................................................................................................................................................................
a
154
141
a
For
a
150
kW
engine;
decreases
slightly
with
increasing
engine
power
rating.
b.
Highway
motorcycles.
Under
the
auspices
of
the
United
Nations/
Economic
Commission
for
Europe
(UN/
ECE)
there
is
an
ongoing
effort
to
develop
a
global
harmonized
world
motorcycle
test
cycle
(WMTC).
The
objective
of
this
work
is
to
develop
a
scientifically
supported
test
cycle
that
accurately
represents
the
in
use
driving
characteristics
of
motorcycles.
The
United
States
is
also
a
participating
member
of
UN/
ECE.
This
is
an
ongoing
process
that
EPA
is
actively
participating
in,
but
that
will
not
likely
result
in
an
action
until
sometime
in
2003
or
2004.
If
an
international
test
procedure
is
agreed
upon
by
the
participating
nations,
we
plan
to
initiate
a
rulemaking
process
to
propose
adopting
the
global
test
cycle
as
part
of
the
U.
S.
regulations.
The
European
Union
(EU)
recently
finalized
a
new
phase
of
motorcycle
standards,
which
will
start
in
2003,
and
are
considering
a
second
phase
to
start
in
2006.
The
2003
European
standards
are
more
stringent
than
the
existing
Federal
standards,
being
somewhat
comparable
to
the
California
Tier
1
standards
taking
effect
in
2004.
The
standards
being
considered
for
2006,
along
with
a
revised
test
cycle
(as
an
interim
cycle
to
bridge
between
the
current
EU
cycle
and
a
possible
WMTC
cycle
in
the
future)
are
likely
to
be
proposed
soon
by
the
EU.
As
of
April
2002
the
2006
European
standards
and
test
cycle
are
being
considered
and
debated
by
the
European
Parliament
and
the
European
Commission.
Many
other
nations,
particularly
in
southeast
Asia
where
low
displacement
two
stroke
motorcycles
are
ubiquitous,
have
established
standards
that
could
be
considered
quite
stringent.
Taiwan,
in
particular,
is
often
noted
for
having
some
of
the
most
stringent
standards
in
the
world,
but
India,
China,
Japan,
and
Thailand,
are
moving
quickly
towards
controlling
what
is,
in
those
nations,
a
significant
contributor
to
air
pollution
problems.
4.
Recently
Proposed
EPA
Standards
for
Nonroad
Engines
This
proposal
is
the
second
part
of
an
effort
to
control
emissions
from
nonroad
engines
that
are
currently
unregulated
and
for
updating
Federal
emissions
standards
for
highway
motorcycles.
The
first
part
of
this
effort
was
a
proposal
published
on
October
5,
2001
for
emission
control
from
large
sparkignition
engines
such
as
those
used
in
forklifts
and
airport
tugs;
recreational
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Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
vehicles
using
spark
ignition
engines
such
as
off
highway
motorcycles,
allterrain
vehicles,
and
snowmobiles;
and
recreational
marine
diesel
engines.
The
October
5,
2001
proposal
includes
general
provisions
in
proposed
40
CFR
part
1068
that
address
the
applicability
of
nonroad
engine
standards,
which
could
be
relevant
to
commenters.
With
regard
to
Large
SI
engines,
we
proposed
a
two
phase
program.
The
first
phase
of
the
standards,
to
go
into
effect
in
2004,
are
the
same
as
those
recently
adopted
by
the
California
Air
Resources
Board.
In
2007,
we
propose
to
supplement
these
standards
by
setting
limits
that
would
require
optimizing
the
same
technologies
but
would
be
based
on
a
transient
test
cycle.
New
requirements
for
evaporative
emissions
and
engine
diagnostics
would
also
start
in
2007.
For
recreational
vehicles,
we
proposed
emission
standards
for
snowmobiles
separately
from
offhighway
motorcycles
and
all
terrain
vehicles.
For
snowmobiles,
we
proposed
a
first
phase
of
standards
for
HC
and
CO
emissions
based
on
the
use
of
clean
carburetion
or
2
stroke
electronic
fuel
injection
(EFI)
technology,
and
a
second
phase
of
emission
standards
for
snowmobiles
that
would
involve
use
of
direct
fuel
injection
2
stroke
and
some
4
stroke
technology.
For
off
highway
motorcycles
and
all
terrain
vehicles,
we
proposed
standards
based
mainly
on
moving
these
engines
from
2
stroke
to
4
stroke
technology.
In
addition,
we
proposed
a
second
phase
of
standards
for
all
terrain
vehicles
that
could
require
some
catalyst
use.
For
marine
diesel
engines,
we
proposed
to
extend
our
commercial
marine
diesel
engine
standards
to
diesel
engines
used
on
recreational
vessels.
These
standards
would
phase
in
beginning
in
2006.
II.
Public
Health
and
Welfare
Effects
of
Emissions
From
Covered
Engines
A.
Background
This
proposal
contains
regulatory
strategies
to
control
evaporative
emissions
from
marine
vessels
that
use
spark
ignition
engines.
Spark
ignition
marine
vessels
include
vessels
that
use
sterndrive
and
inboard
engines
as
well
as
outboards
and
personal
watercraft.
Most
of
these
vessels
are
recreational,
but
there
are
some
commercial
vessels
that
use
spark
ignition
engines
as
well.
The
standards
we
are
proposing
in
this
document
for
marine
vessels
may
require
changes
to
the
fuel
system
or
fuel
tank.
We
are
also
proposing
revised
standards
for
highway
motorcycles.
The
current
HC
and
CO
emission
standards
for
highway
motorcycles
were
set
in
1978
and
are
based
on
1970s
technology.
The
proposed
standards
are
harmonized
to
California's
emission
limits,
but
also
include
new
requirements
for
under
50
cc
motorcycles.
Nationwide,
marine
vessels
and
onhighway
motorcycles
are
an
important
source
of
mobile
source
air
pollution
(see
section
II–
C).
We
determined
that
marine
vessels
that
use
spark
ignition
engines
cause
or
contribute
to
ozone
and
carbon
monoxide
pollution
in
more
than
on
nonattainment
area
in
an
action
dated
February
7,
1996
(61
FR
4600).
These
engines
continue
to
contribute
to
these
problems
because
they
are
primarily
used
in
warm
weather
and
therefore
their
HC,
NOX,
CO,
and
PM
emissions
contribute
to
ozone
formation
and
ambient
PM
and
CO
levels,
and
because
they
are
primarily
used
in
marinas
and
commercial
ports
that
are
frequently
located
in
nonattainment
areas
such
as
Chicago
and
New
York.
Evaporative
emissions
from
marine
vessels
are
also
significant
for
similar
reasons
and
because
the
emissions
occur
all
the
time
rather
than
just
when
the
engine
is
running.
Similarly,
onhighway
motorcycles
are
typically
used
in
warm,
dry
weather
when
their
HC
and
NOX
emissions
are
most
likely
to
form
ozone,
thus
adding
to
ground
level
ozone
levels
and
contributing
to
ozone
nonattainment.
We
expect
that
implementation
of
the
proposed
standards
would
result
in
about
a
50
percent
reduction
in
HC
emissions
and
NOX
emissions
from
highway
motorcycles
in
2020.
We
expect
that
the
proposed
standards
would
result
in
about
a
56
percent
reduction
in
evaporative
HC
emissions
from
marine
vessels
using
spark
ignition
engines
in
2020
(see
Section
VI
below
for
more
details).
These
emission
reductions
would
reduce
ambient
concentrations
of
ozone,
and
fine
particles,
which
is
a
health
concern
and
contributes
to
visibility
impairment.
The
standards
would
also
reduce
personal
exposure
for
people
who
operate
or
who
work
with
or
are
otherwise
in
close
proximity
to
these
engines
and
vehicles.
As
summarized
below
and
described
more
fully
in
the
Draft
Regulatory
Support
Document
for
this
proposal,
many
types
of
hydrocarbons
are
air
toxics.
By
reducing
these
emissions,
the
proposed
standards
would
provide
assistance
to
states
facing
ozone
air
quality
problems,
which
can
cause
a
range
of
adverse
health
effects,
especially
in
terms
of
respiratory
impairment
and
related
illnesses.
States
are
required
to
develop
plans
to
address
visibility
impairment
in
national
parks,
and
the
reductions
proposed
in
this
rule
would
assist
states
in
those
efforts.
B.
What
Are
the
Public
Health
and
Welfare
Effects
Associated
With
Emissions
From
Nonroad
Engines
and
Motorcycles
Subject
to
the
Proposed
Standards?
Marine
vessels
that
use
spark
ignition
engines
and
highway
motorcycles
generate
emissions
that
contribute
to
ozone
formation
and
ambient
levels
of
PM,
and
air
toxics.
This
section
summarizes
the
general
health
effects
of
these
pollutants.
National
inventory
estimates
are
set
out
in
Section
II.
C,
and
estimates
of
the
expected
impact
of
the
proposed
control
programs
are
described
in
Section
VI.
Interested
readers
are
encouraged
to
refer
to
the
Draft
Regulatory
Support
Document
for
this
proposal
for
more
in
depth
discussions.
1.
Health
and
Welfare
Effects
Associated
with
Ground
Level
Ozone
and
its
Precursors
Volatile
organic
compounds
(VOC)
and
NOX
are
precursors
in
the
photochemical
reaction
which
forms
tropospheric
ozone.
Ground
level
ozone,
the
main
ingredient
in
smog,
is
formed
by
complex
chemical
reactions
of
VOCs
and
NOX
in
the
presence
of
heat
and
sunlight.
Hydrocarbons
(HC)
are
a
large
subset
of
VOC,
and
to
reduce
mobile
source
VOC
levels
we
set
maximum
emissions
limits
for
hydrocarbon
and
particulate
matter
emissions.
A
large
body
of
evidence
shows
that
ozone
can
cause
harmful
respiratory
effects
including
chest
pain,
coughing,
and
shortness
of
breath,
which
affect
people
with
compromised
respiratory
systems
most
severely.
When
inhaled,
ozone
can
cause
acute
respiratory
problems;
aggravate
asthma;
cause
significant
temporary
decreases
in
lung
function
of
15
to
over
20
percent
in
some
healthy
adults;
cause
inflammation
of
lung
tissue;
produce
changes
in
lung
tissue
and
structure;
may
increase
hospital
admissions
and
emergency
room
visits;
and
impair
the
body's
immune
system
defenses,
making
people
more
susceptible
to
respiratory
illnesses.
Children
and
outdoor
workers
are
likely
to
be
exposed
to
elevated
ambient
levels
of
ozone
during
exercise
and,
therefore,
are
at
a
greater
risk
of
experiencing
adverse
health
effects.
Beyond
its
human
health
effects,
ozone
has
been
shown
to
injure
plants,
which
has
the
effect
of
reducing
crop
yields
and
reducing
productivity
in
forest
ecosystems.
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/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
7
National
Air
Quality
and
Emissions
Trends
Report,
1999,
EPA,
2001,
at
Table
A–
19.
This
document
is
available
at
http://
www.
epa.
gov/
oar/
aqtrnd99/.
The
data
from
the
Trends
report
are
the
most
recent
EPA
air
quality
data
that
have
been
quality
assured.
A
copy
of
this
table
can
also
be
found
in
Docket
No.
A–
2000–
01,
Document
No.
II–
A–
64.
8
National
Air
Quality
and
Emissions
Trends
Report,
1998,
March,
2000,
at
28.
This
document
is
available
at
http://
www.
epa.
gov/
oar/
aqtrnd98/.
The
data
from
the
Trends
report
are
the
most
recent
EPA
air
quality
data
that
have
been
quality
assured.
A
copy
of
this
table
can
also
be
found
in
Docket
No.
A–
2000–
01,
Document
No.
II–
A.–
63.
9
National
Air
Quality
and
Emissions
Trends
Report,
1998,
March,
2000,
at
32.
This
document
is
available
at
http://
www.
epa.
gov/
oar/
aqtrnd98/.
The
data
from
the
trends
report
are
the
most
recent
EPA
air
quality
data
that
have
been
quality
assured.
A
copy
of
this
table
can
also
be
found
in
Docket
No.
A–
2000–
01,
Document
No.
II–
A–
63.
10
Additional
information
about
this
modeling
can
be
found
in
our
Regulatory
Impact
Analysis:
Heavy
Duty
Engine
and
Vehicle
Standards
and
Highway
Diesel
Fuel
Sulfur
Contro
Requirements,
document
EPA420–
R–
00–
026,
December
2000.
This
document
is
available
at
http://
www.
epa.
gov/
otaq/
diesel.
htm#
documents
and
in
Docket
No.
1–
2000–
01,
Document
No.
II–
A–
13.
11
We
also
performed
ozone
air
quality
modeling
for
the
western
United
States
but,
as
described
further
in
the
air
quality
technical
support
document,
model
predictions
were
well
below
corresponding
ambient
concentrations
for
out
heavy
duty
engine
standards
and
fuel
sulfur
control
rulemaking.
Because
of
poor
model
performance
for
this
region
of
the
country,
the
results
of
the
Western
ozone
modeling
were
not
relied
on
for
that
rule.
12
Regulatory
Impact
Analysis:
Heavy
Duty
Engine
and
Vehicle
Standards
and
Highway
Diesel
Fuel
Sulfur
Control
Requirements,
US
EPA,
EPA420–
R–
00–
026,
December
2000,
at
II–
14,
Table
II.
A–
2.
Docket
No.
A–
2000–
01,
Document
Number
II–
A–
13.
This
document
is
also
available
at
http:/
/www.
epa.
gpa.
gov/
otaq/
diesel/
htm#
documents.
13
Additional
information
about
theses
studies
can
be
found
in
Chapter
2
of
``
Regulatory
Impact
Analysis:
Heavy
Duty
Engine
and
Vehicle
Standards
and
Highway
Diesel
Fuel
Sulfur
Control
Requirements,
''
December
2000,
EPA420–
R–
00–
026.
Docket
No.
A–
2000–
01,
Document
Number
II–
A–
13.
This
document
is
also
available
at
http://
www.
epa.
gov/
otaq/
diesel.
htm#
documents.
14
A
copy
of
this
data
can
be
found
in
Air
Docket
A–
2000–
01,
Document
No.
II–
A–
80.
15
Memorandum
to
Docket
A–
99–
06
from
Eric
Ginsburg,
EPA,
``
Summary
of
Model
Adjusted
Ambient
Concentrations
for
Certain
Levels
of
Ground
Level
Ozone
over
Prolonger
Periods,
''
November
22,
2000,
at
Table
C,
Control
Scenario—
2020
Populations
In
Eastern
Metropolitan
Counties
with
Predicted
Daily
8
Hour
Ozone
greater
than
or
equal
to
0.080
ppm.
Docket
A–
2000–
01,
Document
Number
II–
B–
13.
There
is
strong
and
convincing
evidence
that
exposure
to
ozone
is
associated
with
exacerbation
of
asthmarelated
symptoms.
Increases
in
ozone
concentrations
in
the
air
have
been
associated
with
increases
in
hospitalization
for
respiratory
causes
for
individuals
with
asthma,
worsening
of
symptoms,
decrements
in
lung
function,
and
increased
medication
use,
and
chronic
exposure
may
cause
permanent
lung
damage.
The
risk
of
suffering
these
effects
is
particularly
high
for
children
and
for
people
with
compromised
respiratory
systems.
Ground
level
ozone
today
remains
a
pervasive
pollution
problem
in
the
United
States.
In
1999,
90.8
million
people
(1990
census)
lived
in
31
areas
designated
nonattainment
under
the
1
hour
ozone
NAAQS.
7
This
sharp
decline
from
the
101
nonattainment
areas
originally
identified
under
the
Clean
Air
Act
Amendments
of
1990
demonstrates
the
effectiveness
of
the
last
decade's
worth
of
emission
control
programs.
However,
elevated
ozone
concentrations
remain
a
serious
public
health
concern
throughout
the
nation.
Over
the
last
decade,
declines
in
ozone
levels
were
found
mostly
in
urban
areas,
where
emissions
are
heavily
influenced
by
controls
on
mobile
sources
and
their
fuels.
Twentythree
metropolitan
areas
have
realized
a
decline
in
ozone
levels
since
1989,
but
at
the
same
time
ozone
levels
in
11
metropolitan
areas
with
7
million
people
have
increased.
8
Regionally,
California
and
the
Northeast
have
recorded
significant
reductions
in
peak
ozone
levels,
while
four
other
regions
(the
Mid
Atlantic,
the
Southeast,
the
Central
and
Pacific
Northwest)
have
seen
ozone
levels
increase.
The
highest
ambient
concentrations
are
currently
found
in
suburban
areas,
consistent
with
downwind
transport
of
emissions
from
urban
centers.
Concentrations
in
rural
areas
have
risen
to
the
levels
previously
found
only
in
cities.
Particularly
relevant
to
this
proposal,
ozone
levels
at
17
of
our
National
Parks
have
increased,
and
in
1998,
ozone
levels
in
two
parks,
Shenandoah
National
Park
and
the
Great
Smoky
Mountains
National
Park,
were
30
to
40
percent
higher
than
the
ozone
NAAQS
over
part
of
the
last
decade.
9
To
estimate
future
ozone
levels,
we
refer
to
the
modeling
performed
in
conjunction
with
the
final
rule
for
our
most
recent
heavy
duty
highway
engine
and
fuel
standards.
10
We
performed
ozone
air
quality
modeling
for
the
entire
Eastern
U.
S.
covering
metropolitan
areas
from
Texas
to
the
Northeast.
11
This
ozone
air
quality
model
was
based
upon
the
same
modeling
system
as
was
used
in
the
Tier
2
air
quality
analysis,
with
the
addition
of
updated
inventory
estimates
for
2007
and
2030.
The
results
of
this
modeling
were
examined
for
those
37
areas
in
the
East
for
which
EPA's
modeling
predicted
exceedances
in
2007,
2020,
and/
or
2030
and
the
current
1
hour
design
values
are
above
the
standard
or
within
10
percent
of
the
standard.
This
photochemical
ozone
modeling
for
2020
predicts
exceedances
of
the
1
hour
ozone
standard
in
32
areas
with
a
total
of
89
million
people
(1999
census)
after
accounting
for
light
and
heavy
duty
on
highway
control
programs.
12
We
expect
the
NOX
and
HC
control
strategies
contained
in
this
proposal
for
marine
vessels
that
use
spark
ignition
engines
and
highway
motorcycles
will
further
assist
state
efforts
already
underway
to
attain
and
maintain
the
1
hour
ozone
standard.
In
addition
to
the
health
effects
described
above,
there
exists
a
large
body
of
scientific
literature
that
shows
that
harmful
effects
can
occur
from
sustained
levels
of
ozone
exposure
much
lower
than
0.125
ppm.
13
Studies
of
prolonged
exposures,
those
lasting
about
7
hours,
show
health
effects
from
prolonged
and
repeated
exposures
at
moderate
levels
of
exertion
to
ozone
concentrations
as
low
as
0.08
ppm.
The
health
effects
at
these
levels
of
exposure
include
transient
pulmonary
function
responses,
transient
respiratory
symptoms,
effects
on
exercise
performance,
increased
airway
responsiveness,
increased
susceptibility
to
respiratory
infection,
increased
hospital
and
emergency
room
visits,
and
transient
pulmonary
respiratory
inflammation.
Prolonged
and
repeated
ozone
concentrations
at
these
levels
are
common
in
areas
throughout
the
country,
and
are
found
both
in
areas
that
are
exceeding,
and
areas
that
are
not
exceeding,
the
1
hour
ozone
standard.
Areas
with
these
high
concentrations
are
more
widespread
than
those
in
nonattainment
for
that
1
hour
ozone
standard.
Monitoring
data
indicates
that
334
counties
in
33
states
exceeded
these
levels
in
1997–
99.
14
The
Agency's
most
recent
photochemical
ozone
modeling
forecast
that
111
million
people
are
predicted
to
live
in
areas
that
are
at
risk
of
exceeding
these
moderate
ozone
levels
for
prolonged
periods
of
time
in
2020
after
accounting
for
expected
inventory
reductions
due
to
controls
on
light
and
heavy
duty
onhighway
vehicles.
15
2.
Health
and
Welfare
Effects
Associated
With
Particulate
Matter
Highway
motorcycles
contribute
to
ambient
particulate
matter
through
direct
emissions
of
particulate
matter
in
the
exhaust.
Both
marine
vessels
and
highway
motorcycles
contribute
to
indirect
formation
of
PM
through
their
emissions
of
organic
carbon,
especially
HC.
Organic
carbon
accounts
for
between
27
and
36
percent
of
fine
particle
mass
depending
on
the
area
of
the
country.
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Federal
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/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
16
EPA
adopted
a
policy
in
1996
that
allows
areas
with
PM10
exceedances
that
are
attributable
to
natural
events
to
retain
their
designation
as
unclassifiable
if
the
State
is
taking
all
reasonable
measures
to
safeguard
public
health
regardless
of
the
sources
of
PM10
emissions.
17
Memorandum
to
Docket
A–
99–
06
from
Eric
O.
Ginsburg,
Senior
Program
Advisor,
``
Summary
of
1999
Ambient
Concentrations
of
Fine
Particulate
Matter,
''
November
15,
2000.
Air
Docket
A–
2000–
01,
Docket
No.
II–
B–
12.
For
information
regarding
estimates
for
future
PM2.5
levels,
See
information
about
the
Regulatory
Model
System
for
Aerosols
and
Deposition
(REMSAD)
and
our
modeling
protocols,
which
can
be
found
in
the
Regulatory
Impact
Analysis:
Heavy
Duty
Engine
and
Vehicle
Standards
and
Highway
Diesel
Fuel
Sulfur
Controls
Requirements,
document
EPA
420–
R–
00–
026,
December
2000.
Docket
No.
A–
2000–
01,
Document
No.
A–
II–
13.
This
document
is
also
available
at
http://
www.
epa.
gov/
otaq/
diesel.
htm#
documents.
Also
see
Technical
Memorandum,
EPA
Air
Docket
A–
99–
06,
Eric
O.
Ginsburg,
Senior
Program
Advisor,
Emissions
Monitoring
and
Analysis
Division,
OAQPs,
Summary
of
Absolute
Modeled
and
Model
Adjusted
Estimates
of
Fine
Particulate
Matter
for
Selected
Years,
December
6,
2000,
Table
P–
2.
Docket
Number
2000–
01,
Document
Number
II–
B–
14.
18
Memorandum
to
Docket
A–
99–
06
from
Eric
O.
Ginsburg,
Senior
Program
Advisor,
``
Summary
of
Absolute
Modeled
and
Model
Adjusted
Estimates
of
Fine
Particulate
Matter
for
Selected
Years,
''
December
6,
2000.
Air
Docket
A–
2000–
01,
Docket
No.
II–
B–
14.
19
EPA
(1996)
Review
of
the
National
Ambient
Air
Quality
Standards
for
Particulate
Matter:
Policy
Assessment
of
Scientific
and
Technical
Information
OAQPS
Staff
Paper.
EPA–
452/
R–
96–
013.
Docket
Number
A–
99–
06,
Documents
Nos.
II–
A–
18,
19,
20,
and
23.
The
particulate
matter
air
quality
criteria
documents
are
also
available
at
http://
www.
epa.
gov/
ncea/
partmatt.
htm.
20
EPA
recently
finalized
a
list
of
21
Mobile
Source
Air
Toxics,
including
VOCS,
metals,
and
diesel
particulate
matter
and
diesel
exhaust
organic
gases
(collectively
DPM+
DEOG).
66
FR
17230,
March
29,
2001.
21
See
our
Mobile
Source
Air
Toxics
final
rulemaking,
66
FR
17230,
March
29,
2001,
and
the
Technical
Support
Document
for
that
rulemaking.
Docket
No.
A–
2000–
01,
Documents
Nos.
II–
A–
42
and
II–
A–
30.
Particulate
matter
represents
a
broad
class
of
chemically
and
physically
diverse
substances.
It
can
be
principally
characterized
as
discrete
particles
that
exist
in
the
condensed
(liquid
or
solid)
phase
spanning
several
orders
of
magnitude
in
size.
All
particles
equal
to
and
less
than
10
microns
are
called
PM10.
Fine
particles
can
be
generally
defined
as
those
particles
with
an
aerodynamic
diameter
of
2.5
microns
or
less
(also
known
as
PM2.5),
and
coarse
fraction
particles
are
those
particles
with
an
aerodynamic
diameter
greater
than
2.5
microns,
but
equal
to
or
less
than
a
nominal
10
microns.
Particulate
matter,
like
ozone,
has
been
linked
to
a
range
of
serious
respiratory
health
problems.
Scientific
studies
suggest
a
likely
causal
role
of
ambient
particulate
matter
(which
is
attributable
to
several
of
sources
including
mobile
sources)
in
contributing
to
a
series
of
health
effects.
The
key
health
effects
categories
associated
with
ambient
particulate
matter
include
premature
mortality,
aggravation
of
respiratory
and
cardiovascular
disease
(as
indicated
by
increased
hospital
admissions
and
emergency
room
visits,
school
absences,
work
loss
days,
and
restricted
activity
days),
aggravated
asthma,
acute
respiratory
symptoms,
including
aggravated
coughing
and
difficult
or
painful
breathing,
chronic
bronchitis,
and
decreased
lung
function
that
can
be
experienced
as
shortness
of
breath.
Observable
human
noncancer
health
effects
associated
with
exposure
to
diesel
PM
include
some
of
the
same
health
effects
reported
for
ambient
PM
such
as
respiratory
symptoms
(cough,
labored
breathing,
chest
tightness,
wheezing),
and
chronic
respiratory
disease
(cough,
phlegm,
chronic
bronchitis
and
suggestive
evidence
for
decreases
in
pulmonary
function).
Symptoms
of
immunological
effects
such
as
wheezing
and
increased
allergenicity
are
also
seen.
Epidemiology
studies
have
found
an
association
between
exposure
to
fine
particles
and
such
health
effects
as
premature
mortality
or
hospital
admissions
for
cardiopulmonary
disease.
PM
also
causes
adverse
impacts
to
the
environment.
Fine
PM
is
the
major
cause
of
reduced
visibility
in
parts
of
the
United
States,
including
many
of
our
national
parks.
Other
environmental
impacts
occur
when
particles
deposit
onto
soils,
plants,
water
or
materials.
For
example,
particles
containing
nitrogen
and
sulphur
that
deposit
on
to
land
or
water
bodies
may
change
the
nutrient
balance
and
acidity
of
those
environments.
Finally,
PM
causes
soiling
and
erosion
damage
to
materials,
including
culturally
important
objects
such
as
carved
monuments
and
statues.
It
promotes
and
accelerates
the
corrosion
of
metals,
degrades
paints,
and
deteriorates
building
materials
such
as
concrete
and
limestone.
The
NAAQS
for
PM10
were
established
in
1987.
The
most
recent
PM10
monitoring
data
indicate
that
14
designated
PM10
nonattainment
areas
with
a
projected
population
of
23
million
violated
the
PM10
NAAQS
in
the
period
1997–
99.
In
addition,
there
are
25
unclassifiable
areas
that
have
recently
recorded
ambient
concentrations
of
PM10
above
the
PM10
NAAQS.
16
Current
1999
PM2.5
monitored
values,
which
cover
about
a
third
of
the
nation's
counties,
indicate
that
at
least
40
million
people
live
in
areas
where
longterm
ambient
fine
particulate
matter
levels
are
at
or
above
16
µ
g/
m
3
(37
percent
of
the
population
in
the
areas
with
monitors).
17
According
to
our
national
modeled
predictions,
there
were
a
total
of
76
million
people
(1996
population)
living
in
areas
with
modeled
annual
average
PM2.5
concentrations
at
or
above
16
µ
g/
m
3
(29
percent
of
the
population).
18
This
16
µ
g/
m
3
threshold
is
the
low
end
of
the
range
of
long
term
average
PM2.5
concentrations
in
cities
where
statistically
significant
associations
were
found
with
serious
health
effects,
including
premature
mortality.
19
We
expect
the
PM
reductions
that
result
from
control
strategies
contained
in
this
proposal
will
further
assist
state
efforts
already
underway
to
attain
and
maintain
the
PM
NAAQS.
3.
Health
Effects
Associated
with
Air
Toxics
In
addition
to
the
human
health
and
welfare
impacts
described
above,
emissions
from
the
engines
covered
by
this
proposal
also
contain
several
Mobile
Source
Air
Toxics,
including
benzene,
1,3
butadiene,
formaldehyde,
acetaldehyde,
and
acrolein.
20
The
health
effects
of
these
air
toxics
are
described
in
more
detail
in
Chapter
1
of
the
Draft
Regulatory
Support
Document
for
this
rule.
Additional
information
can
also
be
found
in
the
Technical
Support
Document
for
our
final
Mobile
Source
Air
Toxics
rule.
21
The
hydrocarbon
controls
contained
in
this
proposal
are
expected
to
reduce
exposure
to
air
toxics
and
therefore
may
help
reduce
the
impact
of
these
engines
on
cancer
and
noncancer
health
effects.
C.
What
Is
the
Inventory
Contribution
of
These
Sources?
The
spark
ignition
marine
vessels
and
highway
motorcycles
that
would
be
subject
to
the
proposed
standards
contribute
to
the
national
inventories
of
pollutants
that
are
associated
with
the
health
and
public
welfare
effects
described
in
Section
II.
B.
To
estimate
nonroad
engine
and
vehicle
emission
contributions,
we
used
the
latest
version
of
our
NONROAD
emissions
model.
This
model
computes
nationwide,
state,
and
county
emission
levels
for
a
wide
variety
of
nonroad
engines,
and
uses
information
on
emission
rates,
operating
data,
and
population
to
determine
annual
emission
levels
of
various
pollutants.
Emission
estimates
for
highway
motorcycles
were
developed
using
information
on
the
certification
levels
of
current
motorcycles
and
updated
information
on
motorcycle
use
provided
by
the
motorcycle
industry.
A
more
detailed
description
of
the
modeling
and
our
estimation
methodology
can
be
found
in
the
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Rules
Chapter
6
of
the
Draft
Regulatory
Support
Document.
Baseline
emission
inventory
estimates
for
the
year
2000
for
the
marine
vessels
and
highway
motorcycles
covered
by
this
proposal
are
summarized
in
Table
II.
C–
1.
This
table
shows
the
relative
contributions
of
the
different
mobilesource
categories
to
the
overall
national
mobile
source
inventory.
Of
the
total
emissions
from
mobile
sources,
evaporative
emissions
from
sparkignition
marine
vessels
contribute
about
1.3
percent
of
HC.
Highway
motorcycles
contribute
about
1.1
percent,
0.1
percent,
0.4
percent,
and
0.1
percent
of
HC,
NOX,
CO,
and
PM
emissions,
respectively,
in
the
year
2000.
Our
draft
emission
projections
for
2020
for
the
spark
ignition
marine
vessels
and
highway
motorcycles
that
would
be
subject
to
the
proposed
standards
show
that
emissions
from
these
categories
are
expected
to
increase
over
time
if
left
uncontrolled.
The
projections
for
2020
are
summarized
in
Table
II.
C–
2
and
indicate
that
the
evaporative
emissions
from
marine
vessel
are
expected
to
contribute
1.8
percent
of
mobile
source
HC,
and
motorcycles
are
expected
to
contribute
2.3
percent,
0.2
percent,
0.6
percent,
and
0.1
percent
of
mobile
source
HC,
NOX,
CO,
and
PM
emissions
in
the
year
2020.
Population
growth
and
the
effects
of
other
regulatory
control
programs
are
factored
into
these
projections.
TABLE
II.
C–
1.—
MODELED
ANNUAL
EMISSION
LEVELS
FOR
MOBILE
SOURCE
CATEGORIES
IN
2000
[Thousand
short
tons]
Category
NOX
HC
CO
PM
Tons
Percent
of
mobile
source
Tons
Percent
of
mobile
source
Tons
Percent
of
mobile
source
Tons
Percent
of
mobile
source
Highway
Motorcycles
..................
8
0.
1
35
0.5
331
0.4
0.4
0.1
Marine
SI
Evaporative
...................
0
0.
0
108
1.3
0
0.
0
0
0.
0
Marine
SI
Exhaust
32
0.2
708
9.6
2,144
2.8
38
5.4
Nonroad
Industrial
SI
>
19
kW
.........
306
2.3
247
3.2
2,294
3.0
1.6
0.2
Recreational
SI
......
13
0.1
737
9.6
2,572
3.3
5.7
0.8
Recreation
Marine
CI
........................
24
0.2
1
0.
0
4
0.
0
1
0.
1
Nonroad
SI
<
19
kW
......................
106
0.8
1,460
19.1
18,359
23.6
50
7.2
Nonroad
CI
.............
2,625
19.5
316
4.1
1,217
1.6
253
36.2
Commercial
Marine
CI
........................
977
7.3
30
0.4
129
0.2
41
5.9
Locomotive
.............
1,192
8.9
47
0.6
119
0.2
30
4.3
Total
Nonroad
........
5,275
39
3,646
48
26,838
35
420
60
Total
Highway
........
7,981
59
3,811
50
49,813
64
240
34
Aircraft
....................
178
1
183
2
1,017
1
39
6
Total
Mobile
Sources
..............
13,434
100
7,640
100
77,668
100
699
100
Total
Man
Made
Sources
..............
24,538
......................
18,586
......................
99,747
......................
3,095
......................
Mobile
Source
percent
of
Total
Man
Made
Sources
..............
55%
......................
41%
......................
78%
......................
23%
......................
TABLE
II.
C–
2.—
MODELED
ANNUAL
EMISSION
LEVELS
FOR
MOBILE
SOURCE
CATEGORIES
IN
2020
[Thousand
short
tons]
Category
NOX
HC
CO
PM
Tons
Percent
of
mobile
source
Tons
Percent
of
mobile
source
Tons
Percent
of
mobile
source
Tons
Percent
of
mobile
source
Highway
Motorcycles
..................
14
0.2
58
0.9
572
0.6
0.8
0.1
Marine
SI
Evaporative
...................
0
0.
0
114
1.8
0
0.
0
0
0.
0
Marine
SI
Exhaust
58
0.9
284
4.6
1,985
2.2
28
4.4
Nonroad
Industrial
SI
>
19
kW
.........
486
7.8
348
5.6
2,991
3.3
2.4
0.4
Recreational
SI
......
27
0.4
1,706
27.7
5,407
3.3
7.5
1.2
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Vol.
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157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
TABLE
II.
C–
2.—
MODELED
ANNUAL
EMISSION
LEVELS
FOR
MOBILE
SOURCE
CATEGORIES
IN
2020—
Continued
[Thousand
short
tons]
Category
NOX
HC
CO
PM
Tons
Percent
of
mobile
source
Tons
Percent
of
mobile
source
Tons
Percent
of
mobile
source
Tons
Percent
of
mobile
source
Recreation
Marine
CI
........................
39
0.6
1
0.
0
6
0.
0
1.5
0.2
Nonroad
SI
<
19
kW
......................
106
1.7
986
16.0
27,352
30.5
77
12.2
Nonroad
CI
.............
1,791
28.8
142
2.3
1,462
1.6
261
41.3
Commercial
Marine
CI
........................
819
13.2
35
0.6
160
0.2
46
7.3
Locomotive
.............
611
9.8
35
0.6
119
0.1
21
3.3
Total
Nonroad
........
3,937
63
3,651
59
39,482
44
444
70
Total
Highway
........
2,050
33
2,276
37
48,906
54
145
23
Aircraft
....................
232
4
238
4
1,387
2
43
7
Total
Mobile
Sources
..............
6,219
100
6,165
100
89,775
100
632
100
Total
Man
Made
Sources
..............
16,195
......................
16,234
......................
113,443
......................
3,016
Mobile
Source
percent
of
Total
Man
Made
Sources
..............
38%
......................
38%
......................
79%
......................
21%
......................
III.
Evaporative
Emission
Control
From
Boats
A.
Overview
Evaporative
emissions
refer
to
hydrocarbons
released
into
the
atmosphere
when
gasoline,
or
other
volatile
fuels,
evaporate
from
a
fuel
system.
These
emissions
come
from
four
primary
mechanisms:
hot
soak,
diurnal
heating,
vapor
displacement
during
refueling,
and
permeation
from
tanks
and
hoses.
Hot
soak
emissions
occur
when
fuel
evaporates
from
hot
engine
surfaces
such
as
parts
of
the
carburetor
as
a
result
of
engine
operation.
These
are
minimal
on
fuel
injected
engines.
Control
of
hot
soak
emissions
involves
the
engine
manufacturer
rather
than
the
tank
manufacturer.
Currently,
most
fuel
tanks
in
boats
are
vented
to
atmosphere
through
vent
hoses.
Diurnal
emissions,
which
represent
about
20
percent
of
the
evaporative
emissions
from
boats,
occur
as
the
fuel
in
the
tank
and
fuel
lines
heats
up
due
to
increases
in
ambient
temperature.
As
the
fuel
heats,
it
forms
hydrocarbon
vapor
which
is
vented
to
the
atmosphere.
Refueling
emissions
are
vapors
that
are
displaced
from
the
fuel
tank
to
the
atmosphere
when
fuel
is
dispensed
into
the
tank
and
only
represent
a
small
portion
of
the
total
evaporative
emissions.
Permeation
refers
to
when
fuel
penetrates
the
material
used
in
the
fuel
system
and
is
most
common
through
plastic
fuel
tanks
and
rubber
hoses.
This
permeation
makes
up
the
majority
of
the
evaporative
emissions
from
fuel
tanks
and
hoses.
Table
III.
A–
1
presents
our
national
estimates
of
the
evaporative
hydrocarbon
emissions
from
boats
using
spark
ignition
engines
for
2000.
TABLE
III.
A–
1.—
ESTIMATED
EVAPORATIVE
EMISSIONS
FROM
TANKS/
HOSES
IN
2000
Evaporative
emission
component
HC
[tons]
Diurnal
breathing
losses
...............
22,700
Permeation
through
the
fuel
tank
26,600
Permeation
through
hoses
...........
43,200
Refueling
vapor
displacement
......
6,700
Hot
Soak
.......................................
260
Total
evaporative
emissions
..
100,000
This
section
describes
the
new
provisions
proposed
for
40
CFR
part
1045,
which
would
apply
only
to
boat
manufacturers
and
fuel
system
component
manufacturers.
This
section
also
discusses
proposed
test
equipment
and
procedures
(for
anyone
who
tests
fuel
tanks
and
hoses
to
show
they
meet
emission
standards)
and
proposed
general
compliance
provisions
(for
boat
manufacturers,
fuel
system
component
manufacturers,
operators,
repairers,
and
others).
We
are
proposing
performance
standards
intended
to
reduce
permeation
and
diurnal
evaporative
emissions
from
boats
using
spark
ignition
engines.
The
proposed
standards,
which
would
apply
to
new
boats
starting
in
2008,
are
nominally
based
on
manufacturers
reducing
these
sources
of
evaporative
emissions
by
about
80
percent
overall.
Because
of
the
many
small
businesses
that
manufacture
boats
and
fuel
tanks,
we
are
proposing
a
flexible
compliance
program
that
is
intended
to
help
minimize
the
burden
of
meeting
the
proposed
requirements.
Based
on
a
database
maintained
by
the
U.
S.
Coast
Guard,
we
estimate
that
there
are
nearly
1,700
boat
builders
producing
boats
that
use
engines
for
propulsion.
At
least
1,200
of
these
boat
builders
install
gasoline
fueled
engines
and
would
therefore
be
subject
to
the
evaporative
emission
control
program
discussed
below.
Our
understanding
is
that
more
than
90
percent
of
the
boat
builders
identified
so
far
would
be
considered
small
businesses
as
defined
by
the
Small
Business
Administration
for
SIC
code
3732.
Some
of
these
boat
builders
construct
their
own
fuel
tanks
either
out
of
aluminum
or
fiberglass
reinforced
plastic.
However,
the
majority
of
fuel
tanks
used
by
boat
builders
are
purchased
from
fuel
tank
manufacturers.
We
have
determined
that
fuel
tank
manufacturers
sell
approximately
550,000
fuel
tanks
per
year
for
gasoline
storage
on
boats.
The
market
is
divided
into
manufacturers
that
produce
plastic
tanks
and
manufacturers
that
produce
aluminum
tanks.
We
have
identified
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Proposed
Rules
nine
companies
that
make
plastic
marine
fuel
tanks
with
total
sales
of
approximately
440,000
units
per
year.
Of
these
plastic
tanks,
about
20
percent
are
portable
while
the
rest
are
installed.
We
have
determined
that
there
are
at
least
five
companies
that
make
aluminum
marine
fuel
tanks
with
total
sales
of
approximately
110,000
units
per
year.
All
but
one
of
the
fuel
tank
manufacturers
that
we
have
identified
are
small
businesses
as
defined
by
the
Small
Business
Administration
for
SIC
Code
3713.
Our
understanding
is
that
there
are
four
primary
manufacturers
of
marine
hose
used
in
fuel
supply
lines
and
venting.
At
least
two
of
these
four
manufacturers
produce
hoses
for
other
transportation
sources
as
well
and
already
supply
low
permeation
hoses
that
would
meet
our
proposed
standards.
Only
one
U.
S.
manufacturer
of
fill
neck
hose
has
been
identified.
The
rest
is
shipped
from
overseas.
B.
Boats/
Fuel
Systems
Covered
by
This
Proposal
Generally
speaking,
this
proposed
rule
would
cover
the
fuel
systems
of
all
new
marine
vessels
with
spark
ignition
(SI)
engines.
We
include
boats
and
fuel
systems
that
are
used
in
the
United
States,
whether
they
are
made
domestically
or
imported.
In
the
ANPRM,
we
discussed
exhaust
and
evaporative
emissions
from
boats
using
only
sterndrive
or
inboard
engines.
As
discussed
later
in
Section
IV,
we
are
not
proposing
exhaust
emission
standards
for
these
engines
at
this
time.
We
are,
however,
proposing
to
expand
the
scope
of
the
evaporative
emission
standards
discussed
in
the
ANPRM,
because
we
see
no
significant
technological
differences
between
fuel
tanks
and
hoses
used
for
sterndrive
or
inboard
engines
and
those
used
for
other
SI
marine
engines.
In
fact,
fuel
tank
and
hose
manufacturers
often
sell
their
products
without
knowing
what
type
of
marine
engine
will
be
used
with
it.
1.
Why
Does
This
Apply
Only
to
Marine
Vessels
Using
Spark
Ignition
Engines?
Spark
ignition
marine
engines
generally
use
gasoline
fuel
while
compression
ignition
marine
engines
generally
use
diesel
fuel.
We
are
proposing
evaporative
emission
standards
only
for
boats
using
sparkignition
engines
because
diesel
fuel
has
low
volatility
and,
therefore,
does
not
evaporate
readily.
In
fact,
the
evaporative
emissions
from
boats
using
diesel
fuel
are
already
significantly
lower
than
standards
we
are
proposing
for
boats
using
spark
ignition
marine
engines.
2.
Would
the
Proposed
Standards
Apply
to
All
Vessels
Using
SI
Engines
or
Only
to
New
Vessels?
The
scope
of
this
proposal
is
broadly
set
by
Clean
Air
Act
section
213(
a)(
3),
which
instructs
us
to
set
emission
standards
for
new
nonroad
engines
and
new
nonroad
vehicles.
Generally
speaking,
the
proposed
rule
is
intended
to
cover
all
new
vessels.
Once
the
emission
standards
apply
to
these
vessels,
individuals
or
companies
must
get
a
certificate
of
conformity
from
us
before
selling
them
in
the
United
States.
This
includes
importation
and
any
other
means
of
introducing
engines
and
vehicles
into
commerce.
The
certificate
of
conformity
(and
corresponding
label)
provide
assurance
that
manufacturers
have
met
their
obligation
to
make
engines
that
meet
emission
standards
over
the
useful
life
we
specify
in
the
regulations.
3.
How
Do
I
Know
if
My
Vessel
Is
New?
We
are
proposing
to
define
``
new''
consistent
with
previous
rules.
Under
the
proposed
definition,
a
vessel
is
considered
new
until
its
title
has
been
transferred
to
the
ultimate
purchaser
or
the
vessel
has
been
placed
into
service.
Imported
vessels
would
also
be
considered
to
be
new.
4.
When
Would
Imported
Vessels
Need
to
Meet
the
Proposed
Emission
Standards?
The
proposed
emissions
standards
would
apply
to
all
new
vessels
in
the
United
States.
According
to
Clean
Air
Act
section
216,
``
new''
includes
vessels
that
are
imported
by
any
person,
whether
freshly
manufactured
or
used.
All
vessels
imported
for
introduction
into
commerce
would
need
an
EPAissued
certificate
of
conformity
to
clear
customs,
with
limited
exemptions
(as
described
below).
Any
marine
vessel
built
after
these
emission
standards
take
effect
and
subsequently
imported
into
the
U.
S.
would
be
a
new
vessel
for
the
purpose
of
the
regulations
proposed
in
this
document.
This
means
it
would
need
to
comply
with
the
applicable
emission
standards.
For
example,
a
marine
vessel
manufactured
in
a
foreign
country
in
2004,
then
imported
into
the
United
States
in
2008,
would
be
considered
``
new.
''
This
provision
is
important
to
prevent
manufacturers
from
avoiding
emission
standards
by
building
vessels
abroad,
transferring
their
title,
and
then
importing
them
as
used
vessels.
5.
Would
the
Proposed
Standards
Apply
to
Exported
Vessels?
Vessels
intended
for
export
would
generally
not
be
subject
to
the
requirements
of
the
proposed
emissioncontrol
program.
However,
vessels
that
are
exported
and
subsequently
reimported
into
the
United
States
would
need
to
be
certified.
6.
Are
There
Any
New
Vessels
That
Would
Not
Be
Covered?
We
are
proposing
to
extend
our
basic
nonroad
exemptions
to
the
engines
and
vehicles
covered
by
this
proposal.
These
include
the
testing
exemption,
the
manufacturer
owned
exemption,
the
display
exemption,
and
the
national
security
exemption.
These
exemptions
are
described
in
more
detail
under
Section
III.
E.
3.
In
addition,
the
Clean
Air
Act
does
not
consider
vessels
used
solely
for
competition
to
be
nonroad
vehicles,
so
they
are
exempt
from
meeting
the
proposed
emission
standards.
C.
Proposed
Evaporative
Emission
Requirements
Our
general
goal
in
designing
the
proposed
standards
is
to
develop
a
program
that
will
achieve
significant
emission
reductions.
The
standards
are
designed
to
``
achieve
the
greatest
degree
of
emission
reduction
achievable
through
the
application
of
technology
the
Administrator
determines
will
be
available
for
the
engines
or
vehicles
to
which
such
standards
apply,
giving
appropriate
consideration
to
the
cost
of
applying
such
technology
within
the
period
of
time
available
to
manufacturers
and
to
noise,
energy,
and
safety
factors
associated
with
the
application
of
such
technology.
''
Section
213(
a)(
3)
of
the
Clean
Air
Act
also
instructs
us
to
first
consider
standards
equivalent
in
stringency
to
standards
for
comparable
motor
vehicles
or
engines
(if
any)
regulated
under
section
202,
taking
into
consideration
technological
feasibility,
costs,
and
other
factors.
1.
What
are
the
Proposed
Evaporative
Emission
Standards?
We
are
proposing
to
require
reductions
in
diurnal
emissions,
fuel
tank
permeation,
and
fuel
system
hose
permeation
from
new
vessels
beginning
in
2008.
The
proposed
standards
are
presented
in
Table
III.
C–
1
and
represent
more
than
a
25
percent
reduction
in
diurnal
emissions
and
a
95
percent
reduction
in
permeation
from
both
plastic
fuel
tanks
and
from
hoses.
Section
III.
F.
1
presents
the
test
procedures
associated
with
these
proposed
standards.
Test
temperatures
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Proposed
Rules
are
presented
in
Table
III.
C–
1
because
they
represent
an
important
parameter
in
defining
the
emission
levels.
The
proposed
fuel
tank
venting
and
permeation
standards
are
based
on
the
total
capacity
of
the
fuel
tank
as
described
below.
The
proposed
hose
permeation
standards
are
based
on
the
inside
surface
area
of
the
hose.
We
are
not
proposing
standards
for
hot
soak
and
refueling
emissions,
as
described
above,
at
this
time.
TABLE
III.
C–
1.—
PROPOSED
EVAPORATIVE
STANDARDS
Evaporative
emission
component
Proposed
emission
standard
Test
temperature
Diurnal
Venting
.............................................................
1.1
g/
gallon/
day
............................................................
22.2–
35.6
C
(72–
96
F)
Fuel
tank
permeation
...................................................
0.08
g/
gallon/
day
..........................................................
40
C
(104
F)
Hose
permeation
..........................................................
5
g/
m
2
/day
....................................................................
(15
g/
m
2
/day
with
15%
methanol
blend)
.....................
23
C
(73
F)
The
proposed
emission
standards
are
based
on
our
evaluation
of
several
fuel
system
technologies
(described
in
Section
III.
H)
which
vary
in
cost
and
in
efficiency.
The
proposed
implementation
date
gives
manufacturers
about
five
years
to
comply
after
we
expect
to
issue
final
standards
.
As
discussed
in
more
detail
in
Section
III.
H.
1,
this
would
help
minimize
costs
by
allowing
fuel
tank
manufacturers
time
to
implement
controls
in
their
tanks
as
designs
normally
turnover
as
opposed
to
forcing
turnover
premature
to
normal
business
practice.
There
are
a
multiplicity
of
tank
sizes
and
shapes
produced
every
year
and
the
cost
and
efficiency
of
the
available
emission
control
technologies
will
vary
with
these
different
configurations.
In
determining
the
proposed
standards,
we
considered
costs
and
focused
on
straightforward
approaches
that
could
potentially
be
used
by
all
businesses.
As
discussed
in
Section
H.
3,
we
believe
that
the
approaches
in
this
proposal
would
comply
with
U.
S.
Coast
Guard
safety
requirements
for
fuel
systems.
Given
all
this,
in
the
2008
time
frame,
we
believe
an
average
reduction
of
at
least
80
percent
in
total
evaporative
emissions
from
new
boats
can
be
achieved,
considering
the
availability
and
cost
of
technology,
lead
time,
noise,
energy
and
safety.
We
request
comment
on
the
proposed
standards
and
implementation
dates,
on
the
units
used
for
the
fuel
tank
permeation
standards
(i.
e.
g/
gallon/
day
versus
g/
m
2
/day),
and
on
the
certification
provisions
discussed
below.
We
are
also
interested
in
comments
regarding
the
cost
of
implementing
the
proposed
standards.
Commenters
are
encouraged
to
provide
specific
data
when
possible.
2.
Will
Averaging,
Banking
and
Trading
Be
Allowed
Across
a
Manufacturer's
Product
Line?
An
emission
credit
program
is
an
important
factor
we
take
into
consideration
in
setting
emission
standards
that
are
appropriate
under
Clean
Air
Act
section
213.
An
emissioncredit
program
can
reduce
the
cost
and
improve
the
technological
feasibility
of
achieving
standards,
helping
to
ensure
the
attainment
of
the
standards
earlier
than
would
otherwise
be
possible.
Manufacturers
gain
flexibility
in
product
planning
and
the
opportunity
for
a
more
cost
effective
introduction
of
product
lines
meeting
a
new
standard.
Emission
credit
programs
also
create
an
incentive
for
the
early
introduction
of
new
technology,
which
would
allow
certain
vessels
to
be
used
to
evaluate
new
technology.
This
can
provide
valuable
information
to
manufacturers
on
the
technology
before
they
apply
it
throughout
their
product
line.
This
early
introduction
of
lower
emitting
technology
improves
the
feasibility
of
achieving
the
standards
and
can
provide
valuable
information
for
use
in
other
regulatory
programs
that
may
benefit
from
similar
technologies.
Emission
credit
programs
may
involve
averaging,
banking,
and
trading
(ABT).
Averaging
allows
a
manufacturer
to
certify
one
or
more
products
at
an
emission
level
less
stringent
than
the
applicable
emission
standard,
as
long
as
the
increased
emissions
are
offset
by
products
certified
to
a
level
more
stringent
than
the
applicable
standard.
The
over
complying
products
generate
credits
that
can
be
used
by
the
undercomplying
products.
Compliance
is
determined
on
a
total
mass
emissions
basis
to
account
for
differences
in
production
volume
and
tank
sizes
among
emission
families.
The
average
of
all
emissions
for
a
particular
manufacturer's
production
must
be
at
or
below
that
level
of
the
applicable
emission
standard.
Early
banking
allows
a
manufacturer
to
certify
early
and
generate
credits
for
modifying
their
fuel
system
to
the
2008
compliance
strategy.
In
2008
and
later,
the
banking
program
would
allow
a
manufacturer
to
generate
credits
and
retain
them
for
future
use.
Trading
involves
the
sale
of
banked
credits
from
one
company
to
another.
We
believe
there
is
a
variety
of
technology
options
that
could
be
used
to
meet
the
proposed
standards
for
diurnal
emissions.
By
using
different
combinations
of
these
technologies,
manufacturers
will
be
able
to
produce
products
that
achieve
a
range
of
emission
reductions.
However,
certain
technologies
may
be
more
appropriate
for
different
applications.
In
some
cases,
manufacturers
may
need
flexibility
in
applying
the
emission
control
technology
to
their
products.
For
this
reason,
we
are
proposing
that
the
1.1
g/
gallon/
day
diurnal
emission
standard
be
based
a
corporate
average
of
a
manufacturer's
total
production.
To
meet
this
average
level,
manufacturers
would
be
able
to
divide
their
fuel
tanks
into
different
emission
families
and
certify
each
of
their
emission
families
to
a
different
Family
Emissions
Level
(FEL).
The
FELs
would
then
be
weighted
by
sales
volume
and
fuel
tank
capacity
to
determine
the
average
level
across
a
manufacturer's
total
production.
An
additional
benefit
of
a
corporate
average
approach
is
that
it
provides
an
incentive
for
developing
new
technology
that
can
be
used
to
achieve
even
larger
emission
reductions.
Participation
in
the
ABT
program
would
be
voluntary.
Any
manufacturer
could
choose
to
certify
each
of
its
evaporative
emission
control
families
at
levels
which
would
meet
the
1.1
g/
gallon/
day
proposed
standard
and
would
then
comply
with
the
average
by
default.
Some
manufacturers
may
choose
this
approach
as
the
could
see
it
as
less
complicated
to
implement.
The
following
is
an
example
of
how
the
proposed
averaging
program
for
diurnal
emissions
could
give
a
boat
manufacturer
flexibility
in
its
production.
Suppose
a
boat
builder
was
selling
10
boats,
three
with
100
gallon
fuel
tanks
and
seven
with
50
gallon
fuel
tanks.
In
this
case,
the
boat
builder
constructs
its
own
fuel
tanks
believes
that
an
open
vent
configuration
without
any
emission
control
is
necessary
for
the
vessel
application
using
the
100
gallon
tanks.
However,
the
manufacturer
is
able
to
use
closed
vent
fuel
tanks
with
a
2.0
psi
pressure
relief
valve
in
the
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157
/
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August
14,
2002
/
Proposed
Rules
smaller
fuel
tanks.
Using
the
design
certification
levels
described
in
Section
III..
F.
3,
the
100
gallon
fuel
tanks
would
have
an
FEL
of
1.5
g/
gallon/
day
and
the
50
gallon
fuel
tanks
would
have
an
FEL
of
0.7
g/
gallon/
day.
The
manufacturer
would
generate
debits
for
the
three
boats
with
100
gallon
fuel
tanks
using
the
following
equation:
Debits
=
(1.5
g/
gallon
¥
1.1
g/
gallon)
×
3
tanks
×
100
gallon/
tank
=
120
g
The
manufacturer
would
need
to
use
credits
to
cover
these
debits.
The
boats
certified
using
a
closed
vent
with
a
2.0
psi
pressure
relief
valve
in
this
example
would
generate
the
following
credits:
Credits
=
(1.1
g/
gallon
¥
0.7
g/
gallon)
×
7
tanks
×
50
gallon/
tank
=
140
g
Because
the
credits
are
larger
than
the
debits
in
this
example,
the
boat
builder
would
meet
the
proposed
corporate
average
standard
by
certifying
these
ten
boats.
We
also
propose
to
allow
manufacturers
to
bank
and
trade
emission
credits.
We
are
proposing
that
emission
credits
generated
under
this
program
have
no
expiration,
with
no
discounting
applied.
The
credits
would
belong
to
the
entity
that
certifies
the
fuel
tank.
In
the
above
example,
the
manufacturer
would
have
20
grams
of
credits
(140
g
¥
120
g
=
20
g)
that
it
could
bank,
either
for
trading
or
for
later
model
year
averaging.
Beginning
in
2004,
we
propose
to
allow
early
banking
for
diurnal
evaporative
emissions.
Under
this
program,
manufacturers
generate
early
credits
in
2004
through
2007
for
adding
new
evaporative
emission
control
technology
which
would
reduce
diurnal
emissions.
These
credits
could
be
banked
and
then
used
in
2008
and
later.
As
a
precaution
against
creating
an
opportunity
for
windfall
credits
to
be
generated
from
fuel
systems
already
below
the
average
baseline
level
we
would
only
allow
credits
to
be
generated
below
the
proposed
standard.
The
following
is
an
example
of
how
early
emission
credits
could
be
generated.
In
this
example,
a
boat
builder
sells
20
boats
in
the
2004
to
2007
time
period,
each
with
a
50
gallon
fuel
tank.
If
this
boat
builder
decided
to
sell
one
boat
per
year
with
a
sealed
tank
and
a
1.5
psi
pressure
relief
valve
(0.9
g/
gallon/
test),
the
boat
builder
would
be
able
to
generate
emission
credits
using
the
following
equation:
Credits
=
(1.1
g/
gallon
¥
0.9
g/
gallon/
test)
×
4
tanks
×
50
gallon/
tank
=
40
g
Over
this
time
period,
the
boat
builder
would
not
generate
any
emission
debits.
Therefore,
the
boat
builder
would
have
40
grams
of
credits
that
it
could
use
in
2008
and
later.
We
request
comment
on
the
proposed
ABT
program
for
diurnal
emissions.
We
are
supportive
of
the
concept
of
ABT
in
general.
An
ABT
program
can
reduce
cost
and
improve
technological
feasibility,
and
provide
manufacturers
with
additional
product
planning
flexibility.
This
allows
EPA
to
consider
emissions
standards
with
the
most
appropriate
level
of
stringency
and
lead
time,
as
well
as
providing
an
incentive
for
the
early
introduction
of
new
technology.
However,
while
we
are
open
to
the
idea
of
including
the
program
in
the
rule,
we
are
not
at
this
time
proposing
to
allow
ABT
for
meeting
the
proposed
fuel
tank
and
hose
permeation
standards.
In
preliminary
discussions,
manufacturers
indicated
a
desire
to
meet
requirements
directly
rather
than
using
an
ABT
concept.
From
EPA's
perspective
including
an
ABT
program
in
the
rule
creates
a
long
term
administrative
burden
that
is
not
worth
taking
on
if
the
industry
does
not
intend
to
take
advantage
of
the
flexibility.
While
we
believe
that
all
fuel
tanks
and
fuel
hoses
can
meet
the
proposed
permeation
standards
using
straight
forward
technology
as
discussed
in
Section
III.
H,
industry
may
find
value
in
an
early
banking
program,
especially
for
fuel
tanks.
Under
this
concept,
industry
could
certify
some
tanks
early
in
exchange
for
time
to
delay
some
tanks.
This
could
potentially
be
done
on
a
oneon
one
basis,
or
perhaps
on
a
volumetric
exchange
basis.
In
addition,
we
do
not
preclude
the
value
of
an
averaging
and
trading
program
as
a
compliance
flexibility
to
meet
the
proposed
permeation
standards
which
represent
a
95
percent
reduction
in
permeation.
We
request
comment
on
whether
we
should
adopt
an
ABT
program
for
hose
and
fuel
tank
permeation
emissions.
3.
Would
These
Standards
Apply
to
Portable
Fuel
Tanks
as
Well?
For
personal
watercraft
and
most
boats
using
SD/
I
or
large
outboard
engines,
the
fuel
tanks
are
permanently
mounted
in
the
vessel.
However,
small
boats
using
outboard
engines
may
have
portable
fuel
tanks
that
can
be
removed
from
the
boat
and
stored
elsewhere.
Because
these
fuel
tanks
are
not
sold
as
part
of
a
boat,
we
would
not
require
boat
builders
that
use
only
portable
fuel
tanks
to
certify
to
the
proposed
evaporative
emission
standards
described
above
for
fuel
tanks.
The
fuel
tank
manufacturer
would
have
to
certify
to
the
fuel
tank
diurnal
and
permeation
standards.
For
this
purpose,
we
would
consider
a
portable
fuel
tank
to
be
one
that
is
not
permanently
mounted
on
the
boat,
has
a
handle,
and
has
no
more
than
12
gallons
of
fuel
capacity.
Portable
fuel
tanks
generally
have
a
quick
connect
that
is
used
to
detach
the
fuel
line
between
the
engine
and
tank.
Once
the
fuel
line
is
detached,
this
quick
connect
will
close.
In
addition,
these
tanks
generally
have
a
valve
that
either
closes
automatically
when
the
tank
is
disconnected
from
the
engine
or
a
valve
that
can
be
closed
by
the
user
which
will
prevent
vapors
from
escaping
from
the
tank
when
it
is
stored.
We
propose
to
allow
design
based
certification
of
portable
fuel
tanks
to
the
diurnal
emission
standard
based
on
the
criteria
that
they
seal
automatically
when
the
tank
is
disconnected
from
the
engine
and
that
they
meet
the
proposed
fuel
tank
permeation
standard.
We
believe
that
the
diurnal
emissions
from
a
typical
portable
fuel
tank
would
be
well
below
the
proposed
standard
provided
that
it
is
sealed
when
not
in
use.
Because
the
emission
control
depends
on
user
practices,
(such
as
disconnecting
the
tank
after
use)
we
propose
not
allowing
any
credits
to
be
generated
for
diurnal
emissions.
We
request
comment
on
allowing
designbased
certification
of
portable
fuel
tanks
that
have
valves
that
must
be
closed
by
the
user.
4.
Is
EPA
Proposing
Voluntary
``
Blue
Sky''
Emissions
Standards?
Several
state
and
environmental
groups
and
manufacturers
of
emissions
controls
have
supported
our
efforts
to
develop
incentive
programs
to
encourage
the
use
of
emission
control
technologies
that
go
beyond
federal
emission
standards.
In
the
final
rule
for
land
based
nonroad
diesel
engines,
we
included
a
program
of
voluntary
standards
for
low
emitting
engines,
referring
to
these
as
``
Blue
Sky
Series''
engines
(63
FR
56967,
October
23,
1998).
Since
then,
we
have
included
similar
programs
in
several
of
our
other
nonroad
rules.
The
general
purposes
of
such
programs
are
to
provide
incentives
to
manufacturers
to
produce
clean
products
as
well
as
create
market
choices
and
opportunities
for
environmental
information
for
consumers
regarding
such
products.
The
voluntary
aspects
of
these
programs,
which
in
part
provides
an
incentive
for
manufacturers
willing
to
certify
their
products
to
more
stringent
standards
than
necessary,
is
an
important
part
of
the
overall
application
of
``
Blue
Sky
Series''
programs.
We
are
proposing
a
voluntary
Blue
Sky
Series
standard
for
diurnal
emissions
from
marine
fuel
tanks.
Under
this
proposal
we
are
targeting
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Federal
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/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
22
``
Public
Hearing
to
Consider
Amendments
to
the
Spark
Ignition
Marine
Engine
Regulations,
''
Mail
Out
#MSC
99–
15,
June
22,
1999
(Docket
A–
2000–
01,
Document
II–
A–
27).
close
to
a
95
percent
reduction
in
diurnal
evaporative
emissions
beyond
the
proposed
mandatory
diurnal
emission
standards
as
a
qualifying
level
for
Blue
Sky
fuel
tanks.
The
proposed
Blue
Sky
standard
is
0.1
g/
gallon/
day,
which,
as
discussed
in
Section
III.
F.
3,
could
be
met
through
the
use
of
technologies
such
as
a
low
permeation
bladder
fuel
tank.
Creating
a
voluntary
standard
for
low
diurnal
emissions
will
be
an
important
step
in
advancing
emission
control
technology.
While
these
are
voluntary
standards,
they
become
binding
on
tanks
produced
under
that
certificate
once
a
manufacturer
chooses
to
participate.
EPA
certification
will
therefore
provide
protection
against
false
claims
of
environmentally
beneficial
products.
A
manufacturer
choosing
to
certify
a
fuel
tank
under
this
approach
must
comply
with
all
the
proposed
certification
requirements
including
useful
life,
warranty,
and
other
general
compliance
provisions.
This
program
would
become
effective
when
we
finalize
this
rule.
For
the
program
to
be
most
effective,
however,
incentives
should
also
be
in
place
to
motivate
the
production
and
sale
of
lower
emitting
fuel
tanks.
We
solicit
ideas
that
could
encourage
the
creation
and
use
of
these
incentive
programs
by
users
and
state
and
local
governments.
We
believe
it
is
important
that
such
incentive
programs
lead
to
a
net
benefit
to
the
environment;
therefore,
we
are
proposing
that
fuel
tanks
with
the
Blue
Sky
designation
not
generate
extra
ABT
credits
for
demonstrating
compliance
with
this
proposed
standard.
We
also
request
comment
on
additional
measures
we
could
take
to
encourage
development
and
introduction
of
low
emission
control
technology.
Finally,
we
request
comment
on
the
Blue
Sky
approach
in
general
as
it
would
apply
to
marine
fuel
tanks.
5.
What
Is
Consumer
Choice
Labeling?
California
ARB
has
recently
proposed
consumer/
environmental
label
requirements
for
outboard
and
personal
watercraft
engines.
Under
this
approach,
manufacturers
would
label
their
engines
or
vehicles
based
on
their
certified
emission
level.
California
has
proposed
three
different
labels
to
differentiate
varying
degrees
of
emission
control—
one
for
meeting
the
EPA
2006
standard,
one
for
being
20
percent
lower,
and
one
for
being
65
percent
below.
More
detail
on
this
concept
is
provided
in
the
docket.
22
We
are
considering
a
similar
approach
to
labeling
the
vessels
subject
to
this
proposal.
This
would
apply
especially
to
consumer
products.
Consumer
choice
labeling
would
give
people
the
opportunity
to
consider
varying
emission
levels
as
a
factor
in
choosing
specific
models.
This
may
also
give
the
manufacturer
an
incentive
to
produce
more
of
their
cleaner
models.
A
difficulty
in
designing
a
labeling
program
is
in
creating
a
scheme
that
communicates
information
clearly
and
simply
to
consumers.
Also,
some
are
concerned
that
other
organizations
could
use
the
labeling
provisions
to
mandate
certain
levels
of
emission
control,
rather
than
relying
on
consumer
choice
as
a
market
based
incentive.
We
request
comment
on
this
approach
for
marine
vessels.
D.
Demonstrating
Compliance
1.
How
Would
I
Certify
My
Products?
We
are
proposing
to
apply
our
emission
standards
to
vessels,
but
allow
certification
of
fuel
tanks
and
hoses
separately.
For
both
cases,
we
are
proposing
a
certification
process
similar
to
our
existing
program
for
other
mobile
sources.
In
the
existing
program,
manufacturers
test
representative
prototype
designs
and
submit
the
emission
data
along
with
other
information
to
EPA
in
an
application
for
a
Certificate
of
Conformity.
As
discussed
in
Section
III.
F.
3,
we
are
proposing
to
allow
manufacturers
to
certify
based
on
either
design
(for
which
there
is
data)
or
emissions
testing.
If
we
approve
the
application,
then
the
manufacturer's
Certificate
of
Conformity
allows
the
manufacturer
to
produce
and
sell
the
vessels
or
fuel
systems
described
in
the
application
in
the
U.
S.
We
are
proposing
that
manufacturers
certify
their
vessels,
fuel
tanks,
or
hoses
by
grouping
them
into
emission
families.
Under
this
approach,
vessels,
fuel
tanks,
or
hoses
systems
expected
to
have
similar
emission
characteristics
would
be
classified
in
the
same
emission
family.
The
emission
family
definition
is
fundamental
to
the
certification
process
and
to
a
large
degree
determines
the
amount
of
testing
required
for
certification.
To
address
a
manufacturer's
unique
product
mix,
we
may
approve
using
broader
or
narrower
emission
families.
Once
an
emission
family
is
certified,
we
would
require
every
vessel,
fuel
tank,
or
hose
a
manufacturer
produces
from
the
emission
family
to
have
a
label
with
basic
identifying
information.
The
proposed
regulation
text
details
the
proposed
requirements
for
design
and
content
of
the
labels.
We
request
comment
on
this
approach.
2.
Who
Will
be
Responsible
for
Certifying
the
Vessel
or
Fuel
System?
Every
boat
powered
by
a
sparkignition
marine
engine
and
every
portable
fuel
tank
would
have
to
be
covered
by
an
emissions
certificate
(or
separate
certificates
for
fuel
tanks
and
hoses).
The
proposed
regulations
require
that
compliance
to
the
emission
standards
must
be
demonstrated
before
the
sale
of
the
boat
(or
tank,
in
the
case
of
portable
fuel
tanks).
However,
to
allow
additional
flexibility
in
complying
with
standards,
we
propose
to
allow
tank
and
hose
manufacturers
to
certify
their
product
lines
separately.
Therefore,
if
a
boat
builder
were
to
use
certified
fuel
tanks
and
hoses,
the
boat
builder
could
rely
on
the
tank
and
hose
manufacturers'
certificates.
The
boat
builder
would
only
need
to
state
that
they
are
using
components
that,
combined,
will
meet
the
proposed
standard
and
properly
install
the
fuel
system.
We
request
comment
on
this
approach.
3.
How
Long
Would
My
Vessel
or
Fuel
System
Have
To
Comply?
Manufacturers
would
be
required
to
build
vessels
that
meet
the
emission
standards
over
each
vessel's
useful
life.
The
useful
life
we
adopt
by
regulation
is
intended
to
reflect
the
period
during
which
vessels
are
designed
to
properly
function
without
being
remanufactured.
We
propose
a
regulatory
useful
life
of
ten
years
for
marine
evaporative
emission
control.
This
is
consistent
with
the
regulatory
useful
life
for
outboard
marine
engines.
We
use
the
same
useful
life
based
on
the
belief
that
engines
and
boats
are
intended
to
have
the
same
design
life.
We
request
comment
on
the
proposed
useful
life
requirement.
4.
What
Warranty
Requirements
Apply
to
Certified
Vessels
and
Fuel
Systems?
Consistent
with
our
current
emissioncontrol
programs,
we
are
proposing
that
manufacturers
provide
a
design
and
defect
warranty
covering
emissionrelated
components.
For
marine
vessels,
we
propose
that
the
fuel
systems
be
warranted
for
five
years
for
the
emission
related
components.
The
proposed
regulations
would
require
that
the
warranty
period
must
be
longer
than
this
minimum
period
we
specify
if
the
manufacturer
offers
a
longer
warranty
for
the
fuel
system
or
any
of
its
components;
this
includes
extended
warranties
on
the
fuel
system
or
any
of
its
components
that
are
available
for
an
extra
price.
See
the
proposed
regulation
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Federal
Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
23
``
Interim
Tampering
Enforcement
Policy,
''
EPA
memorandum
from
Norman
D.
Shulter,
Office
of
General
Counsel,
June
25,
1974
(Docket
A–
2000–
01;
document
II–
B20).
24
EPA
acted
to
adjust
the
maximum
penalty
amount
in
1996
(61
FR
69364,
December
31,
1996).
See
also
40
CFR
part
19.
language
for
a
description
of
which
components
are
emission
related.
We
request
comment
on
whether
the
warranty
provisions
should
apply
only
to
the
certificate
holder
or
to
all
manufacturers
of
the
fuel
system
components
used
by
the
certificate
holder.
If
an
operator
makes
a
valid
warranty
claim
for
an
emission
related
component
during
the
warranty
period,
the
manufacturer
is
generally
obligated
to
replace
the
component
at
no
charge
to
the
operator.
The
manufacturer
may
deny
warranty
claims
if
the
operator
failed
to
do
prescribed
maintenance
that
contributed
to
the
warranty
claim.
We
are
also
proposing
a
defect
reporting
requirement
that
applies
separate
from
the
emission
related
warranty
(see
Section
III.
E.
6).
In
general,
defect
reporting
applies
when
a
manufacturer
discovers
a
pattern
of
component
failures,
whether
that
information
comes
from
warranty
claims,
voluntary
investigation
of
product
quality,
or
other
sources.
We
request
comment
on
the
proposed
warranty
and
defect
reporting
requirements.
E.
General
Compliance
Provisions
This
section
describes
a
wide
range
of
compliance
provisions
that
would
apply
to
marine
vessels
(or
fuel
tanks
or
hoses
as
appropriate)
and
are
the
same
as
those
recently
proposed
for
the
nonroad
engines
September
2001
(see
66
FR
51098).
Several
of
these
provisions
apply
not
only
to
manufacturers,
but
also
to
operators,
and
others.
The
following
discussion
of
the
general
compliance
provisions
reflects
the
organization
of
the
proposed
regulatory
text.
For
ease
of
reference,
the
subpart
designations
are
provided.
We
request
comment
on
all
these
provisions.
1.
Miscellaneous
Provisions
(Part
1068,
Subpart
A)
This
proposed
regulation
contains
some
general
provisions,
including
general
applicability
and
the
definitions
that
apply
to
40
CFR
part
1068.
Other
provisions
concern
good
engineering
judgment,
how
we
would
handle
confidential
information;
how
the
EPA
Administrator
delegates
decisionmaking
authority;
and
when
we
may
inspect
a
manufacturer's
facilities,
vessels,
or
records.
The
process
of
testing
for
evaporative
emissions
(or
certifying
based
on
design)
and
preparing
an
application
for
certification
requires
the
manufacturer
to
make
a
variety
of
judgments.
Section
1068.5
of
the
proposed
regulations
describes
the
methodology
we
propose
to
use
to
evaluate
concerns
related
to
manufacturers'
use
of
good
engineering
judgment
in
cases
where
the
manufacturer
has
such
discretion.
If
we
find
a
problem
in
these
areas,
we
would
take
into
account
the
degree
to
which
any
error
in
judgment
was
deliberate
or
in
bad
faith.
This
subpart
is
consistent
with
provisions
in
the
final
rule
for
light
duty
highway
vehicles
and
commercial
marine
diesel
engines.
2.
Prohibited
Acts
and
Related
Requirements
(Part
1068,
Subpart
B)
The
proposed
provisions
in
this
subpart
lay
out
a
set
of
prohibitions
for
manufacturers
and
operators
to
ensure
that
vessels
comply
with
the
emission
standards.
These
provisions
are
summarized
below,
but
readers
are
encouraged
to
review
the
proposed
regulatory
text.
These
provisions
are
intended
to
help
ensure
that
each
new
vessel
or
portable
tank
sold
or
otherwise
entered
into
commerce
in
the
United
States
is
certified
to
the
relevant
standards.
a.
General
prohibitions
(§
1068.100).
This
proposed
regulation
contains
several
prohibitions
consistent
with
the
Clean
Air
Act.
Under
this
proposal,
no
one
may
sell
a
vessel
or
portable
fuel
tank
in
the
United
States
without
a
valid
certificate
of
conformity
issued
by
EPA,
deny
us
access
to
relevant
records,
or
keep
us
from
entering
a
facility
to
test
or
inspect
vessels
or
fuel
system
components.
In
addition,
no
one
may
remove
or
disable
a
device
or
design
element
that
may
affect
an
vessel's
emission
levels,
or
manufacture
any
device
that
will
make
emission
controls
ineffective,
which
we
would
consider
tampering.
We
have
generally
applied
the
existing
policies
developed
for
tampering
with
highway
engines
and
vehicles
to
nonroad
engines.
23
Other
proposed
prohibitions
reinforce
manufacturers'
obligations
to
meet
various
certification
requirements.
We
would
also
prohibit
selling
parts
that
prevent
emission
control
systems
from
working
properly.
Finally,
for
vessels
that
are
excluded
for
certain
applications
(i.
e.
solely
for
competition),
we
would
generally
prohibit
using
these
vessels
in
other
applications.
These
proposed
prohibitions
are
the
same
as
those
that
apply
to
other
applications
we
have
regulated
in
previous
rules.
Each
prohibited
act
has
a
corresponding
maximum
penalty
as
specified
in
Clean
Air
Act
section
205.
As
provided
for
in
the
Federal
Civil
Penalties
Inflation
Adjustment
Act
of
1990,
Pub.
L.
10–
410,
these
maximum
penalties
are
in
1970
dollars
and
should
be
periodically
adjusted
by
regulation
to
account
for
inflation.
The
current
penalty
amount
for
each
violation
is
$27,500.
24
b.
In
service
systems
(§
1068.110).
The
proposed
regulations
would
prevent
manufacturers
from
requiring
owners
to
use
any
certain
brand
of
aftermarket
parts
and
give
the
manufacturer
responsibility
for
servicing
related
to
emissions
warranty,
leaving
the
responsibility
for
all
other
maintenance
with
the
owner.
This
proposed
regulation
would
also
reserve
our
right
to
do
testing
(or
require
testing)
to
investigate
potential
defeat
devices,
as
authorized
by
the
Act.
3.
Exemptions
(Part
1068,
Subpart
C)
We
are
proposing
to
include
several
exemptions
for
certain
specific
situations.
Most
of
these
are
consistent
with
previous
rules.
We
highlight
the
new
or
different
proposed
provisions
in
the
following
paragraphs.
In
general,
exempted
vessels
would
need
to
comply
with
the
requirements
only
in
the
sections
related
to
the
exemption.
Note
that
additional
restrictions
could
apply
to
importing
exempted
vessels
(see
Section
III.
E.
4).
Also,
we
are
also
proposing
that
we
may
require
manufacturers
(or
importers)
to
add
a
permanent
label
describing
that
the
vessel
or
fuel
system
component
is
exempt
from
emission
standards
for
a
specific
purpose.
In
addition
to
helping
us
enforce
emission
standards,
this
would
help
ensure
that
imported
vessels
clear
U.
S.
Customs
without
difficulty.
a.
Testing.
Anyone
would
be
allowed
to
request
an
exemption
for
vessels
or
fuel
system
components
used
only
for
research
or
other
investigative
purposes.
b.
Manufacturer
owned
vessels
and
fuel
systems.
Vessels
and
fuel
system
components
that
are
used
by
manufacturers
for
development
or
marketing
purposes
could
be
exempted
from
regulation
if
they
are
maintained
in
the
manufacturers'
possession
and
are
not
used
for
any
revenue
generating
service.
They
would
no
longer
be
exempt
if
they
were
later
offered
for
sale.
c.
Display
vessels
or
fuel
systems.
Boat
builders
and
fuel
system
component
manufacturers
would
get
an
exemption
if
the
vessels
or
fuel
systems
are
for
display
only.
They
would
no
longer
be
exempt
if
they
were
later
offered
for
sale.
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Federal
Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
d.
National
security.
Manufacturers
could
receive
an
exemption
for
vessels
or
portable
fuel
tanks
they
can
show
are
needed
by
an
agency
of
the
federal
government
responsible
for
national
defense.
For
cases
where
the
vessels
will
not
be
used
on
combat
applications,
the
manufacturer
would
have
to
request
the
exemption
with
the
endorsement
of
the
procuring
government
agency.
e.
Exported
vessels.
Vessels
and
portable
fuel
tanks
that
will
be
exported
to
countries
that
don't
have
the
same
emission
standards
as
those
that
apply
in
the
United
States
would
be
exempted
without
need
for
a
request.
This
exemption
would
not
be
available
if
the
destination
country
has
the
same
emission
standards
as
those
in
the
United
States.
f.
Competition
vessels.
New
vessels
that
are
used
solely
for
competition
are
excluded
from
regulations
applicable
to
nonroad
equipment.
For
purposes
of
our
certification
requirements,
a
manufacturer
would
receive
an
exemption
if
it
can
show
that
it
produces
the
vessel
specifically
for
use
solely
in
competition.
In
addition,
vessels
that
have
been
modified
for
use
in
competition
would
be
exempt
from
the
prohibition
against
tampering
described
above
(without
need
for
request).
The
literal
meaning
of
the
term
``
used
solely
for
competition''
would
apply
for
these
modifications.
We
would
therefore
not
allow
the
vessel
to
be
used
for
anything
other
than
competition
once
it
has
been
modified.
This
also
applies
to
someone
who
would
later
buy
the
vessel,
so
we
would
require
the
person
modifying
the
vessel
to
remove
or
deface
the
original
label
and
inform
a
subsequent
buyer
in
writing
of
the
conditions
of
the
exemption.
The
exemption
would
no
longer
apply.
4.
Imports
(Part
1068,
Subpart
D)
In
general,
the
same
certification
requirements
would
apply
to
vessels
whether
they
are
produced
in
the
U.
S.
or
are
imported.
This
proposed
regulation
also
includes
some
additional
provisions
that
would
apply
if
someone
wants
to
import
an
exempted
or
excluded
vessel.
For
example,
the
importer
would
need
written
approval
from
us
to
import
any
exempted
vessel;
this
is
true
even
if
an
exemption
for
the
same
reason
doesn't
require
approval
for
vessels
produced
in
the
U.
S.
All
the
proposed
exemptions
described
above
for
new
vessels
would
also
apply
to
importation,
though
some
of
these
apply
only
on
a
temporary
basis.
If
we
approve
a
temporary
exemption,
it
would
be
available
only
for
a
defined
period
and
could
require
the
importer
to
post
bond
while
the
vessel
is
in
the
U.
S.
There
are
several
additional
proposed
exemptions
that
would
apply
only
to
imported
vessels.
—Identical
configuration:
This
would
be
a
permanent
exemption
to
allow
individuals
to
import
vessels
that
were
designed
and
produced
to
meet
applicable
emission
standards.
These
vessels
may
not
have
the
emission
label
only
because
they
were
not
intended
for
sale
in
the
United
States.
—Repairs
or
alterations:
This
would
be
a
temporary
exemption
to
allow
companies
to
repair
or
modify
vessels.
—Diplomatic
or
military:
This
would
be
a
temporary
exemption
to
allow
diplomatic
or
military
personnel
to
use
uncertified
vessels
during
their
term
of
service
in
the
U.
S.
We
request
comment
on
all
the
proposed
exemptions
for
domestically
produced
and
imported
vessels.
5.
Selective
Enforcement
Audit
(Part
1068,
Subpart
E)
Clean
Air
Act
section
206(
b)
gives
us
the
authority
and
discretion
in
any
program
with
vehicle
or
engine
emission
standards
to
do
selective
enforcement
auditing
of
production
vessels
and
fuel
systems.
The
proposed
regulation
text
describes
the
audit
procedures
in
greater
detail.
We
intend
generally
to
rely
on
inspecting
manufacturers'
designs
to
ensure
they
comply
with
emission
standards.
However,
we
would
reserve
our
right
to
do
selective
enforcement
auditing
if
we
have
reason
to
question
the
emission
testing
conducted
or
data
reported
by
the
manufacturer.
6.
Defect
Reporting
and
Recall
(Part
1068,
Subpart
F)
We
are
proposing
provisions
for
defect
reporting.
Specifically,
we
are
proposing
that
manufacturers
tell
us
when
they
learn
of
a
defect
occurring
25
times
or
more
for
emission
families
with
annual
sales
up
to
10,000
units.
This
threshold
of
defects
would
increase
proportionately
for
larger
families.
While
these
thresholds
would
depend
on
sales,
counting
defects
would
not
be
limited
to
a
single
emission
family.
For
example,
if
a
manufacturer
learns
that
operators
reported
25
cases
of
problems
with
a
limiting
orifice
from
three
different
low
volume
models
spread
over
five
years,
that
would
trigger
the
need
to
file
a
defect
report.
This
information
could
come
from
warranty
claims,
customer
complaints,
product
performance
surveys,
or
anywhere
else.
The
proposed
regulation
language
in
§
1068.501
also
provides
information
on
the
thresholds
for
triggering
a
further
investigation
for
where
a
defect
report
is
more
likely
to
be
necessary.
We
request
comment
on
the
proposed
defect
reporting
provisions.
Under
Clean
Air
Act
section
207,
if
we
determine
that
a
substantial
number
of
vessels,
fuel
tanks,
or
hoses
within
an
emission
family,
although
properly
used
and
maintained,
do
not
conform
to
the
appropriate
emission
standards,
the
manufacturer
will
be
required
to
remedy
the
problem
and
conduct
a
recall
of
the
noncomplying
emission
family.
However,
we
also
recognize
the
practical
difficulty
in
implementing
an
effective
recall
program
for
marine
vessels.
It
would
likely
be
difficult
to
properly
identify
all
the
affected
owners.
The
response
rate
for
affected
owners
or
operators
to
an
emissionrelated
recall
notice
is
also
a
critical
issue
to
consider.
We
recognize
that
in
some
cases,
recalling
noncomplying
marine
vessels
may
not
achieve
sufficient
environmental
protection,
so
our
intent
is
to
generally
allow
manufacturers
to
nominate
alternative
remedial
measures
to
address
most
potential
noncompliance
situations.
We
expect
that
successful
implementation
of
appropriate
alternative
remediation
would
obviate
the
need
for
us
to
make
findings
of
substantial
nonconformity
under
section
207
of
the
Act.
We
would
consider
alternatives
nominated
by
a
manufacturer
based
on
the
following
criteria;
the
alternatives
should—
(1)
Represent
a
new
initiative
that
the
manufacturer
was
not
otherwise
planning
to
perform
at
that
time,
with
a
clear
connection
to
the
emission
problem
demonstrated
by
the
emission
family
in
question;
(2)
Cost
more
than
foregone
compliance
costs
and
consider
the
time
value
of
the
foregone
compliance
costs
and
the
foregone
environmental
benefit
of
the
emission
family;
(3)
Offset
at
least
100
percent
of
the
emission
exceedance
relative
to
that
required
to
meet
emission
standards;
and
(4)
Be
possible
to
implement
effectively
and
expeditiously
and
to
complete
in
a
reasonable
time.
These
criteria
would
guide
us
in
evaluating
projects
to
determine
whether
their
nature
and
burden
is
appropriate
to
remedy
the
environmental
impact
of
the
nonconformity.
However,
in
no
way
would
the
consideration
of
such
a
provision
diminish
our
statutory
authority
to
direct
a
recall
if
that
is
deemed
the
best
course
of
action.
We
request
comment
on
this
approach
to
addressing
the
Clean
Air
Act
provisions
related
to
recall.
In
addition,
we
request
comment
on
the
proposed
requirement
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/
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/
Proposed
Rules
25
Reid
Vapor
Pressure
(psi).
This
is
a
measure
of
the
volatility
of
the
fuel.
9
RVP
represents
a
typical
summertime
fuel
in
northern
states.
26
Hot
soak
emissions
are
those
caused
by
residual
heat
in
the
engine
and
exhaust
system
immediately
after
the
engine
is
shut
down.
Running
loss
emissions
are
those
caused
by
engine
and
exhaust
heat
while
the
engine
is
operating.
27
Draft
SAE
Information
Report
J1769,
``
Test
Protocol
for
Evalution
of
Long
Term
Permeation
Barrier
Durability
on
Non
Metallic
Fuel
Tanks,
''
(Docket
A–
2000–
01,
document
IV–
A–
24).
to
keep
recall
related
records
until
three
years
after
a
manufacturer
completes
all
responsibilities
under
a
recall
order.
7.
Public
Hearings
(Part
1068,
Subpart
G)
According
to
this
regulation,
manufacturers
would
have
the
opportunity
to
challenge
our
decision
to
suspend,
revoke,
or
void
an
emission
family's
certificate.
This
also
applies
to
our
decision
to
reject
the
manufacturer's
use
of
good
engineering
judgment
(see
§
1068.5).
Part
1068,
subpart
G
describes
the
proposed
procedures
for
a
public
hearing
to
resolve
such
a
dispute.
F.
Proposed
Testing
Requirements
In
order
to
obtain
a
certificate
allowing
sale
of
products
meeting
EPA
emission
standards,
manufacturers
generally
must
show
compliance
with
such
standards
through
emission
testing.
40
CFR
part
86
details
specifications
for
test
equipment
and
procedures
that
apply
to
highway
vehicle
evaporative
emission
testing.
We
propose
to
base
the
SI
marine
evaporative
emission
test
procedures
on
this
part.
However,
we
propose
to
modify
this
test
procedure
somewhat
to
more
accurately
reflect
the
anticipated
technology
for
meeting
the
evaporative
emission
standards
proposed
in
this
rule.
We
are
also
proposing
designbased
certification
as
an
alternative
to
performing
specific
testing.
1.
What
Are
the
Proposed
Test
Procedures
for
Measuring
Diurnal
Emissions?
We
propose
that
the
evaporative
emission
test
will
be
representative
of
ambient
temperatures
ranging
from
22
C
to
36
C
(72
F
to
96
F).
Emissions
would
be
measured
in
a
Sealed
Housing
for
Evaporative
Determination
(SHED)
over
a
72
hour
period.
The
fuel
tank
would
be
set
up
in
the
SHED
and
sealed
except
for
the
vent(
s).
The
fuel
tank
would
be
set
up
in
the
SHED
with
all
hoses,
seals,
and
other
components
attached.
The
fuel
tank
would
be
filled
completely
and
drained
to
40
percent
capacity
with
9
RVP
test
fuel
and
soaked
with
an
open
vent
until
the
fuel
reached
22
C.
25
Immediately
after
the
fuel
reaches
this
temperature,
the
SHED
would
be
purged,
and
the
diurnal
temperature
cycling
would
begin.
The
temperature
cycle
is
actually
three
repeats
of
a
24
hour
diurnal
trace
and
is
described
in
Chapter
4
of
the
Draft
Regulatory
Support
Document.
During
the
test
a
minimum
of
5
mph
wind
speed
would
be
simulated
using
a
fan.
The
final
g/
gallon/
day
result
is
based
on
the
highest
mass
emission
rate
from
these
three
24
hour
cycles,
divided
by
the
fuel
tank
capacity.
Fuel
tank
capacity
refers
the
maximum
amount
of
fuel
in
the
tank
under
in
use
conditions.
These
proposed
test
procedures
are
designed
to
simulate
near
worst
case
conditions
for
a
typical
boat.
We
believe
that
typical
in
use
fuel
tanks
will
rarely
be
exposed
to
a
temperature
cycle
larger
than
24
F
in
a
single
day.
However,
in
special
applications
where
the
fuel
tank
is
exposed
to
direct
sunlight,
the
tank
temperature
can
change
much
more
than
24
F
over
the
course
of
a
single
day.
Therefore,
we
are
proposing
that
special
test
procedures
that
simulate
the
radiant
effect
of
sunlight
be
used
to
test
fuel
tanks
that
will
be
exposed
to
direct
sunlight.
We
would
not
require
this
for
exposed
fuel
tanks
that
are
shielded
from
the
sun.
This
diurnal
cycle
is
consistent
with
the
test
requirements
in
40
CFR
part
86
for
highway
vehicles.
However,
the
test
procedure
for
highway
vehicles
includes
engine
operation
and
hot
soaks.
26
One
purpose
of
the
engine
operation
is
to
purge
the
charcoal
canister
that
collects
evaporative
emissions
in
highway
applications.
However,
we
are
excluding
engine
operation
from
the
evaporative
test
procedures
for
boats
using
SI
marine
engines
because
we
do
not
anticipate
the
use
of
charcoal
canisters
in
these
applications.
Another
purpose
of
running
the
engine
and
the
purpose
of
the
hot
soaks
is
to
measure
evaporative
emissions
due
to
the
heating
of
the
engine
and
exhaust
system.
However,
this
would
significantly
increase
the
difficulty
of
the
SHED
testing
due
to
the
large
size
of
most
boats.
Because
most
boats
are
operated
only
50
hours
per
year,
these
running
loss
and
hot
soak
emissions
are
considerably
smaller
than
diurnal
and
permeation
emissions.
In
addition,
most
of
the
emission
control
strategies
that
could
be
used
to
meet
the
proposed
standards
would
also
reduce
running
loss
and
hot
soak
emissions.
We
request
comment
on
the
proposed
test
procedures
for
determining
evaporative
emissions
from
boats
using
SI
marine
engines.
2.
What
Are
the
Proposed
Test
Procedures
for
Measuring
Permeation
Emissions?
a.
Fuel
tanks.
We
propose
that
tank
permeation
be
based
on
a
test
procedure
consistent
with
the
Coast
Guard
requirements
in
33
CFR
183.620.
Specifically,
the
rate
of
permeation
from
the
tank
will
be
measured
at
40
C
using
the
same
test
fuel
as
for
the
diurnal
testing.
We
request
comment
on
using
40
C
as
the
test
temperature
or
if
23
C
should
be
used
to
be
consistent
with
the
hose
testing.
Our
understanding
is
that
40
C
represents
higher
temperatures
that
may
be
seen
in
an
engine
compartment
during
operation
while
23
C
represents
typical
ambient
conditions.
If
a
lower
test
temperature
were
used,
the
standards
would
need
to
be
adjusted
appropriately.
Based
on
data
presented
in
Chapter
4
of
the
draft
RSD,
the
standards
would
have
to
be
reduced
on
the
order
of
50
percent
for
every
10
C
reduction
in
test
temperature.
We
also
request
comment
on
using
ASTM
Fuel
``
C''
and
a
15%
methanol
blend
to
be
consistent
with
the
hose
permeation
test
procedures
or
on
using
10%
ethanol
consistent
with
on
highway
evaporative
emission
testing.
The
tank
would
have
to
be
filled
and
soaked
for
a
minimum
of
60
days
to
ensure
that
permeation
emissions
are
accurately
reflected
in
the
test
procedure.
The
tank
would
be
sealed
during
testing,
and
care
would
have
to
be
made
that
the
environment
in
which
the
tank
was
tested
was
continuously
purged
of
vapor
to
prevent
the
saturation
of
vapor
with
hydrocarbons
around
the
outside
of
the
tank.
Permeation
would
be
measured
through
weight
loss
in
the
tank
or
using
equivalent
procedures.
We
also
request
comment
on
whether
we
should
require
specific
durability
test
procedures
for
fuel
tanks.
Such
durability
tests
could
include
pressure
vacuum
cycle
testing,
slosh
testing,
and
temperature
cycling.
Information
on
these
tests
is
included
in
the
docket.
27
b.
Hoses.
We
propose
to
use
the
current
practices
for
measuring
permeation
from
marine
hoses
that
are
specified
in
SAE
J
1527.
Under
this
procedure,
the
hose
is
tested
at
23
C
with
both
ASTM
Fuel
``
C''
(50%
toluene,
50%
isooctane)
and
with
a
blend
on
fuel
``
C''
with
15%
methanol.
SAE
J
1527
sets
permeation
limits
for
hose
of
100
g/
m
2
/day
for
fuel
C
and
300
g/
m
2
/day
for
the
15%
methanol
blend.
Consistent
with
this
relationship,
we
propose
to
allow
the
permeation
rate
to
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Vol.
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No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
be
three
times
higher
than
the
proposed
standard
for
fuel
C
when
the
hose
is
tested
on
the
15%
methanol
blend.
Because
permeation
rates
double,
roughly,
with
every
10
C
increase
in
temperature,
the
test
procedure
has
a
large
effect
on
emissions
measured
for
a
given
hose
material.
In
addition,
the
temperature
effects
may
be
greater
for
some
materials
than
for
others.
For
low
permeation
non
metal
fuel
lines
used
in
automotive
applications,
the
current
practices
are
specified
in
SAE
J
2260
and
SAE
J
1737.
Under
these
test
procedures,
the
hose
permeation
is
measured
at
60
C
with
an
85%
15%
blend
of
fuel
``
C''
and
methanol.
We
request
comment
on
using
the
higher
test
temperature
in
the
automotive
test
procedure.
We
also
request
comment
on
requiring
testing
using
a
10%
ethanol
blend
consistent
with
on
highway
evaporative
emission
testing.
3.
Could
I
Certify
Based
on
Engineering
Design
Rather
Than
Through
Testing?
We
recognize
that
performing
SHED
testing
could
be
cost
prohibitive
for
many
fuel
tank
manufacturers
or
boat
builders.
In
addition,
many
of
the
technologies
that
can
be
used
to
reduce
evaporative
emissions
are
straightforward
design
strategies.
For
these
reasons,
we
propose
that
manufacturers
have
the
option
of
certifying
to
the
diurnal
evaporative
emission
requirements
based
on
fuel
system
designs,
as
described
in
the
proposed
regulations.
Test
data
would
be
required
to
certify
fuel
tanks
and
hoses
to
the
proposed
permeation
standards.
However,
we
would
allow
carryover
of
test
data
from
year
to
year
for
a
given
emission
control
design.
We
believe
the
cost
of
testing
tanks
and
hose
designs
for
permeation
would
be
considerably
lower
than
running
variable
temperature
diurnal
testing.
In
addition,
the
data
could
be
carried
over
from
year
to
year,
and
there
is
a
good
possibility
that
the
broad
emission
family
concepts
under
consideration
could
lead
to
minimum
testing.
For
instance,
a
hose
manufacturer
could
test
its
hose
design
once,
and
all
the
boat
builders
who
use
this
hose
could
incorporate
this
data
in
their
certification
applications.
We
are
proposing
design
based
certification
to
the
tank
permeation
standard
for
one
case.
We
would
consider
an
aluminum
fuel
tank
to
meet
the
design
criteria
for
a
low
permeation
fuel
tank.
However,
we
would
not
consider
this
design
to
be
any
more
effective
than
a
low
permeation
fuel
tank
for
the
purposes
of
any
sort
of
credit
program.
Although
aluminum
is
impermeable,
seals
and
gaskets
used
on
the
fuel
tank
may
not
be.
The
design
criteria
for
the
seals
and
gaskets
would
be
that
either
they
would
not
have
a
total
exposed
surface
area
exceeding
1000
mm
2
,
or
the
seals
and
gaskets
would
have
to
be
made
of
a
material
with
a
permeation
rate
of
10
g/
m
2
/day
or
less
at
23
C.
The
rest
of
this
section
discusses
designs
that
we
propose
to
be
acceptable
for
design
based
certification
to
the
proposed
diurnal
emission
standard.
The
emission
data
we
used
to
develop
these
proposed
design
options
are
presented
in
Chapter
4
of
the
Draft
Regulatory
Support
Document.
Additional
testing
may
help
us
more
precisely
set
the
appropriate
emission
levels
associated
with
each
design.
Manufacturers
wanting
to
use
designs
other
than
those
we
discuss
here
would
have
to
perform
the
above
test
procedures
for
their
design.
However,
once
a
new
design
is
proven,
we
could
add
this
new
design
to
the
list
of
designs
for
this
certification
flexibility
and
assign
it
to
the
appropriate
averaging
bin.
For
example,
if
several
manufacturers
were
to
pool
their
resources
to
test
a
diurnal
emission
control
strategy
and
submit
this
data
to
EPA,
we
would
consider
this
particular
strategy
and
emission
level
as
a
new
design
level
for
design
based
certification.
We
request
comment
on
the
concept
of
design
based
certification
and
on
the
technologies
and
associated
emission
levels
discussed
below.
Section
III.
H.
3
presents
a
more
detailed
description
of
what
each
of
these
technologies
are
and
how
they
can
be
used
to
reduce
evaporative
emissions.
We
have
identified
several
technologies
for
reducing
diurnal
emissions
from
marine
fuel
tanks.
The
design
levels
proposed
below
represent
our
understanding
of
the
effectiveness
of
various
emission
control
technologies
over
the
proposed
test
procedure.
Table
III.
F.
1
summarizes
design
based
emission
levels
associated
with
several
emission
control
strategies.
These
control
strategies
are
discussed
in
more
detail
after
the
table.
Manufacturers
would
be
required
to
submit
information
demonstrating
that
the
components
they
use
would
be
durable
over
the
useful
life
of
the
vessel.
For
tanks
that
allow
pressure
build
up,
a
low
pressure
vacuum
relief
valve
would
also
be
necessary
for
the
engine
to
be
able
to
draw
fuel
during
operation.
Also,
in
the
cases
where
anti
siphon
valves
are
used
with
these
designs,
the
antisiphon
system
would
have
to
be
designed
such
that
fuel
could
not
spill
out
through
this
valve
when
the
system
is
under
pressure.
TABLE
III.
F–
1.—
EMISSION
LEVELS
FOR
DESIGN
BASED
CERTIFICATION
TO
THE
PROPOSED
DIURNAL
EMISSION
STANDARD
Emission
level
[g/
gallon/
day]
Technology
1.5
........................
Baseline
(open
vent
with
a
normal
length
vent
hose).
1.3
........................
Near
zero
pressure
limited
flow
orifice
and
insulation
(R
value
15),
or
closed
vent,
0.5
psi
relief
valve.
1.1*
.......................
Closed
vent,
1.0
psi
relief
valve.
0.9
........................
Closed
vent,
1.5
psi
relief
valve.
0.7
........................
Closed
vent,
2.0
psi
relief
valve.
0.5
........................
Closed
vent,
0.5
psi
relief
valve
with
a
volume
compensating
air
bag.
0.1
........................
Bladder
fuel
tank.
*
Proposed
average
standard
for
diurnal
emissions.
1.5
g/
gal/
test:
Typical
fuel
tanks
used
in
boats
currently
have
an
open
vent
to
the
atmosphere
through
a
vent
hose.
This
vent
is
intended
to
prevent
pressure
from
building
up
in
the
fuel
tank.
This
uncontrolled
fuel
tank
configuration
would
be
considered
to
be
at
this
level
based
on
the
data
presented
in
Chapter
4
of
the
Draft
RSD.
1.3
g/
gal/
test:
The
design
criteria
for
this
level
would
be
a
fuel
tank
with
a
near
zero
pressure
limited
flow
orifice
and
insulation.
The
limited
flow
orifice
would
be
defined
as
having
a
maximum
cross
sectional
area
defined
by
the
following
equation:
Area
[mm
2
]
=
0.04
x
fuel
tank
capacity
[gallons].
For
example,
a
20
gallon
tank
would
need
an
orifice
with
no
more
than
a
1
mm
diameter.
This
size
orifice
is
sufficient
to
limit
diffusion
of
hydrocarbons
without
causing
significant
pressure
to
build
in
the
fuel
tank.
The
design
criteria
for
the
insulation
would
be
to
use
insulation
having
at
least
an
R
value
of
15
(see
section
III.
H.
3.
b).
1.3
g/
gal/
test:
An
alternative
design
criterion
for
this
level
would
be
a
sealed
fuel
tank
with
a
pressure
relief
valve
that
would
open
at
a
pressure
of
0.5
psi.
1.1
g/
gal/
test:
The
design
criterion
for
this
level
would
be
a
sealed
fuel
tank
with
a
pressure
relief
valve
that
would
open
at
a
pressure
of
1.0
psi.
0.9
g/
gal/
test:
The
design
criterion
for
this
level
would
be
a
sealed
fuel
tank
with
a
pressure
relief
valve
that
would
open
at
a
pressure
of
1.5
psi.
0.7
g/
gal/
test:
The
design
criterion
for
this
level
would
be
a
sealed
fuel
tank
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/
Wednesday,
August
14,
2002
/
Proposed
Rules
with
a
pressure
relief
valve
that
would
open
at
a
pressure
of
2.0
psi.
0.5
g/
gal/
test:
The
design
criterion
for
this
level
would
be
a
volumecompensating
air
bag
used
in
conjunction
with
a
0.5
psi
pressurerelief
valve
if
the
bag
is
designed
to
fill
25
percent
of
the
fuel
tank
capacity
when
inflated.
This
bag
would
have
no
leaks
to
the
fuel
tank
and
would
be
constructed
out
of
a
non
permeable
material.
0.1
g/
gal/
test:
The
design
criterion
for
this
level
would
be
to
use
a
bladder
tank.
The
bladder
would
have
to
be
sealed
and
built
of
low
permeable
material.
This
bladder
would
collapse
as
fuel
was
drawn
out
of
it
and
expand
when
refueled
thereby
eliminating
the
vapor
space
needed
for
diurnal
vapor
generation.
G.
Special
Compliance
Provisions
The
scope
of
this
proposal
includes
many
boat
and
fuel
tank
manufacturers
that
have
not
been
subject
to
our
regulations
or
certification
process.
Many
of
these
manufacturers
are
small
businesses
for
which
a
typical
regulatory
program
may
be
burdensome.
This
section
describes
the
proposed
special
compliance
provisions
designed
to
address
this
concern.
As
described
in
Section
VIII.
B,
the
report
of
the
Small
Business
Advocacy
Review
Panel
addresses
the
concerns
of
small
manufacturers
of
gasoline
fuel
tanks
for
marine
applications
and
small
boat
builders
that
use
these
tanks.
To
identify
representatives
of
small
businesses
for
this
process,
we
used
the
definitions
provided
by
the
Small
Business
Administration
for
fuel
tank
manufacturers
and
boat
builders
(less
than
500
employees).
Twelve
small
businesses
agreed
to
serve
as
smallentity
representatives.
These
companies
represented
a
cross
section
of
both
gasoline
and
diesel
engine
marinizers,
as
well
as
boat
builders.
In
this
industry
sector,
we
believe
some
of
the
burden
reduction
approaches
presented
in
the
Panel
Report
should
be
applied
to
all
businesses.
All
of
the
marine
fuel
tank
manufacturers
except
for
one
qualify
as
small
businesses.
We
believe
the
purpose
of
these
options
is
to
reduce
the
potential
burden
on
companies
for
which
fixed
costs
cannot
be
distributed
over
a
large
product
line.
For
this
reason,
we
often
times
also
consider
the
production
volume
when
making
decisions
regarding
flexibilities.
The
one
fuel
tank
manufacturer
not
qualifying
as
a
small
business
still
has
low
production
volumes
of
marine
fuel
tanks,
thus
we
believe
some
flexibilities
should
be
made
available
to
this
manufacturer
as
well.
Three
of
the
five
burden
reduction
approaches
discussed
in
the
Panel
Report
are
design
based
certification,
allowance
to
use
emission
credits
with
design
based
certification,
and
a
5
year
lead
time
with
early
banking.
As
discussed
above,
we
are
proposing
these
approaches
for
all
manufacturers
certifying
marine
fuel
tanks
to
the
proposed
evaporative
emission
standards.
This
section
discusses
the
other
two
approaches
in
the
Panel
Report
and
how
we
propose
to
apply
them
to
the
marine
industry.
1.
Broadly
Defined
Product
Certification
Families
To
certify
to
the
evaporative
emission
standards,
we
propose
that
manufacturers
would
have
to
classify
their
vessels,
fuel
tanks,
or
hoses
in
emission
families
based
on
having
similar
emission
characteristics.
We
would
expect
to
differentiate
families
by
fuel
type,
diurnal
control
technology,
and
the
tank
and
hose
material/
treatment.
The
manufacturer
would
then
certify
each
of
these
evaporative
emission
families.
The
purpose
of
emission
families
has
traditionally
been
to
reduce
testing
burden
by
allowing
a
family
to
be
certified
based
on
the
test
results
from
its
highest
emitting
member.
For
highway
evaporative
emission
requirements,
each
manufacturer
divides
its
products
into
several
evaporative
emission
families
based
on
characteristics
of
the
fuel
system.
These
characteristics
include:
fuel
type,
charcoal
canister
type
and
capabilities,
seals,
valves,
hoses,
and
tank
material.
The
manufacturer
then
has
to
certify
each
of
these
evaporative
emission
families.
Unlike
highway
vehicles,
evaporative
emission
controls
for
marine
vessels
are
not
likely
to
rely
on
charcoal
canisters
as
a
control
technology.
Furthermore,
most
or
all
SI
marine
engines
will
use
gasoline
and
most
manufacturers
do
not
make
both
plastic
and
aluminum
fuel
tanks.
Most
manufacturers
will
therefore
have
very
few
emission
families
and
it
will
be
unlikely
that
emission
families
could
be
much
broader
than
discussed
here.
In
addition,
broadening
emission
families
may
not
reduce
compliance
burden,
considering
the
proposed
design
based
certification
approach.
However,
we
request
comment
on
whether
there
are
reasonable
ways
to
broaden
these
engine
families,
and
whether
or
not
small
businesses
would
benefit
from
any
such
broadened
definitions.
2.
Hardship
Provisions
for
Small
Businesses
Producing
Marine
Fuel
Tanks
There
are
two
types
of
hardship
provisions.
The
first
type
of
hardship
program
would
allow
small
businesses
to
petition
EPA
for
additional
lead
time
(e.
g.,
up
to
3
years)
to
comply
with
the
standards.
A
small
manufacturer
would
have
to
make
the
case
that
it
has
taken
all
possible
business,
technical,
and
economic
steps
to
comply
but
the
burden
of
compliance
costs
would
have
a
significant
impact
on
the
company's
solvency.
A
manufacturer
would
be
required
to
provide
a
compliance
plan
detailing
when
and
how
it
would
achieve
compliance
with
the
standards.
Hardship
relief
could
include
requirements
for
interim
emission
reductions
and/
or
purchase
and
use
of
emission
credits.
The
length
of
the
hardship
relief
decided
during
review
of
the
hardship
application
would
be
up
to
one
year,
with
the
potential
to
extend
the
relief
as
needed.
The
second
hardship
program
would
allow
companies
to
apply
for
hardship
relief
if
circumstances
outside
their
control
cause
the
failure
to
comply
(i.
e.,
supply
contract
broken
by
parts
supplier)
and
if
the
failure
to
sell
the
subject
vessels
would
have
a
major
impact
on
the
company's
solvency.
See
the
proposed
regulatory
text
in
40
CFR
1068.240
and
1068.241
for
additional
details.
H.
Technological
Feasibility
We
believe
there
are
several
strategies
that
manufacturers
can
use
to
meet
our
proposed
evaporative
emission
standards.
We
have
collected
and
will
continue
to
collect
emission
test
data
on
a
wide
range
of
evaporative
emission
control
technology.
The
design
based
certification
levels
discussed
above
are
based
on
this
test
data
and
we
may
amend
the
list
of
approved
designs
and
emission
levels
as
more
data
become
available.
1.
Implementation
Schedule
There
are
several
strategies
available
to
reduce
evaporative
emissions
(diurnal
and
permeation)
from
marine
fuel
tanks.
Some
of
these
may
require
changes
to
the
tank
design,
structure,
and
material
that
would
cause
a
change
in
the
molds
used
to
make
the
plastic
tanks.
These
molds
need
to
be
replaced
periodically
as
part
of
normal
manufacturing
practices.
Small
manufacturers
using
rotational
molding
to
produce
plastic
fuel
tanks
have
commented
that
the
molds
covering
the
majority
of
their
production
line
have
about
a
five
year
life
before
replacement.
However,
for
the
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/
Vol.
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No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
production
fuel
tanks,
they
may
use
their
molds
for
10
to
15
years.
They
have
stated
that
their
costs
would
be
greatly
reduced
if
they
could
turn
over
fuel
tank
molds
in
a
manner
more
consistent
with
their
current
business
practice,
rather
than
doing
so
solely
in
response
to
an
evaporative
control
requirement.
We
recognize
that
tank
manufacturers
and
boat
builders
will
need
time
to
choose
and
implement
the
evaporative
emission
control
strategies
that
work
best
for
them.
We
believe
the
implementation
date
of
2008,
coupled
with
the
option
for
early
banking,
provides
sufficient
lead
time
beyond
the
anticipated
publication
of
the
final
rule.
This
5
year
lead
time
is
consistent
with
the
general
turnover
schedule
of
most
molds
used
in
plastic
fuel
tank
production.
We
request
comment
whether
there
are
small
entities
whose
product
line
is
dominated
by
tanks
for
which
the
molds
are
turned
over
at
a
slower
rate.
Surface
treatments
to
reduce
tank
permeation
are
widely
used
today
in
other
container
applications
and
the
technology
and
production
facilities
needed
to
conduct
this
process
exist.
While
there
is
definitely
value
in
an
organized
approach
to
compliance
on
the
part
of
the
manufacturers,
the
lead
time
requirement
is
largely
driven
by
modifications
needed
to
comply
with
the
diurnal
requirements.
EPA
requests
comment
on
the
feasibility
of
implementing
the
tank
permeation
requirement
in
2006
or
2007.
Low
permeation
marine
hose
is
used
today
on
some
vessels
that
is
close
to
meeting
the
proposed
standards.
In
addition,
the
development
time
for
new
hose
designs
is
on
the
order
of
1–
2
years.
Therefore,
we
request
comment
on
whether
an
earlier
implementation
date
for
the
proposed
permeation
standards
for
marine
hoses
would
be
appropriate.
We
are
proposing
an
implementation
date
for
hose
permeation
standards
of
2008,
consistent
with
the
fuel
tank
standards,
because
hose
fitting
modifications
may
be
required
which
could
affect
tank
design.
Manufacturers
have
commented
that
low
permeation
hoses
require
special
connection
fittings
with
better
tolerances
than
seen
on
many
fittings
today.
Automotive
fuel
lines
also
already
exist
that
meet
the
proposed
permeation
standards.
However,
manufacturers
have
raised
concerns
with
the
cost
of
applying
these
less
flexible
fuel
lines
in
marine
applications.
In
any
case,
using
these
automotive
fuel
lines
would
probably
also
require
fitting
changes.
EPA
requests
comment
on
the
feasibility
of
implementing
the
hose
permeation
requirement
in
2006
or
2007.
2.
Standard
Levels
We
tested
several
diurnal
emissioncontrol
strategies
using
the
procedures
discussed
in
VI.
D.
1.
Based
on
this
testing
we
believe
there
are
several
emission
control
technologies
that
could
be
used
to
significantly
reduce
diurnal
emissions.
Also,
we
have
identified
several
strategies
for
reducing
permeation
emissions
from
fuel
tanks
and
hoses.
We
recognize
that
some
of
these
technologies
may
be
more
desirable
than
others
for
some
manufacturers,
and
we
recognize
that
different
strategies
for
equal
emission
reductions
may
be
better
for
different
applications.
Specific
examples
of
technology
that
could
be
used
to
meet
the
proposed
standards
would
be
fuel
tank
with
a
1
psi
valve
in
the
vent,
a
fluorinated
plastic
fuel
tank,
and
hose
constructed
with
a
thermoplastic
barrier.
We
present
several
other
technological
approaches
below.
3.
Technological
Approaches
We
believe
several
emission
control
technologies
can
be
used
to
reduce
evaporative
emissions
from
marine
fuel
tanks.
In
addition,
there
are
a
few
technologies
that
are
used
in
other
applications
that
may
not
be
as
effective
here.
The
advantages
and
disadvantages
of
various
emission
control
strategies
are
discussed
below.
Chapter
4
of
the
Draft
Regulatory
Support
Document
presents
more
detail
on
these
technologies
and
Chapter
5
provides
information
on
the
estimated
costs.
a.
Closed
fuel
vent
with
pressure
relief.
Evaporative
emissions
are
formed
when
the
fuel
heats
up,
evaporates,
and
passes
through
the
vent
into
the
atmosphere.
By
closing
that
vent,
evaporative
emissions
are
prevented
from
escaping.
However,
as
vapor
is
generated,
pressure
builds
up
in
fuel
tank.
Once
the
fuel
cools
back
down,
the
pressure
subsides.
The
U.
S
Coast
Guard
safety
regulations
(33
CFR
part
183)
require
that
fuel
tanks
be
able
to
withstand
pressure
up
to
3
psi
and
must
be
able
to
pass
a
pressure
impulse
test
which
cycles
the
tank
from
0
to
3
psi
25,000
times.
The
Coast
Guard
also
requires
that
these
fuel
tanks
be
vented
such
that
the
pressure
in
the
tank
in
use
never
exceeds
80
percent
of
the
pressure
that
the
tank
is
designed
to
withstand
without
leaking.
The
American
Boat
and
Yacht
Council
makes
the
additional
recommendation
that
the
vent
line
should
have
a
minimum
inner
diameter
of
7
Ú16
inch
(HÐ
24.13).
However,
these
recommended
practices
also
note
that
``
there
may
be
EPA
or
state
regulations
that
limit
the
discharge
of
hydrocarbon
emissions
into
the
atmosphere
from
gasoline
fuel
systems.
The
latest
version
of
these
regulations
should
be
consulted.
''
To
prevent
pressure
from
building
too
high,
we
first
considered
a
2
psi
pressure
relief
valve.
This
is
a
typical
automotive
rating
and
is
within
the
Coast
Guard
requirements.
With
this
valve,
vapors
would
be
retained
in
the
tank
until
2
psi
of
pressure
is
built
up
in
the
tank
due
to
heating
of
the
fuel.
Once
the
tank
pressure
reached
2
psi,
just
enough
of
the
vapor
would
be
vented
to
the
atmosphere
to
maintain
2
psi
of
pressure.
As
the
fuel
cooled,
the
pressure
would
decrease.
We
estimate
that
this
would
achieve
about
a
55
percent
reduction
in
evaporative
emissions
over
the
proposed
test
procedure.
A
1
psi
valve
would
achieve
a
reduction
of
about
half
of
this
over
the
proposed
test
procedure.
However,
in
use,
this
reduction
could
be
much
greater
because
the
test
procedure
is
designed
to
represent
a
hotter
than
average
day.
On
a
more
mild
day
there
could
be
less
pressure
buildup
in
the
tank
and
the
valve
may
not
even
need
to
open.
As
discussed
in
Chapter
4
of
the
draft
RSD,
we
tested
fuel
tanks
for
diurnal
emissions
with
pressure
relief
valves
ranging
from
0.4
to
2.2
psi.
With
the
use
of
a
sealed
system,
a
low
pressure
vacuum
relief
valve
would
also
be
necessary
so
air
could
be
drawn
into
the
tank
to
replace
fuel
drawn
from
the
tank
when
the
engine
is
running.
Manufacturers
of
plastic
fuel
tanks
have
expressed
concern
that
their
tanks
are
not
designed
to
operate
under
pressure.
For
instance,
although
they
will
not
leak
at
3
psi,
rotationally
molded
fuel
tanks
with
large
flat
surfaces
could
begin
deforming
at
pressures
as
low
as
0.5
psi.
At
higher
pressures,
the
deformation
would
be
greater.
This
deformation
would
affect
how
the
tank
is
mounted
in
the
boat.
Also,
fuel
tank
manufacturers
commented
that
some
of
the
fittings
or
valves
used
today
may
not
work
properly
under
even
2
psi
of
pressure.
Finally,
they
commented
that
backup
pressure
relief
valves
would
be
necessary
for
safety.
We
believe
that,
with
enough
lead
time,
fuel
tank
manufacturers
will
be
able
to
redesign
their
fuel
tanks
to
be
more
resistant
to
deformation
under
pressure.
By
reducing
the
size
of
flat
areas
on
the
tank
through
adding
contours
to
the
tank,
or
by
increasing
the
thickness
of
the
tank
walls,
the
fuel
tanks
can
be
designed
to
resist
deformation
under
pressure.
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Vol.
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157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
28
R
value
measures
resistance
to
heat
flow
and
is
defined
in
16
CFR
460.5.
29
The
Ideal
Gas
Law
states
that
pressure
and
volume
are
inversely
related.
By
increasing
the
volume
of
the
vapor
space,
the
pressure
can
be
held
constant.
plastic
fuel
tanks
are
generally
sealed
without
any
pressure
relief
and
are
designed
to
withstand
any
pressure
that
may
occur
under
these
conditions.
We
also
believe
that
if
certain
fittings
and
valves
cannot
withstand
pressure
today,
they
can
be
designed
to
do
so.
In
addition,
we
are
proposing
a
standard
which
can
be
met
with
a
1
psi
valve
which
we
believe
would
require
significantly
less
modification
to
current
tanks
than
designing
for
3
psi
of
pressure.
In
developing
this
level
we
considered
first
2.0
psi
valves
which
is
consistent
with
on
highway
fuel
tanks
and
is
below
the
Coast
Guard
tank
pressure
requirement.
However,
we
proposed
a
standard
based
on
a
1.0
psi
pressure
relief
valve
to
give
manufacturers
some
margin
to
minimize
fuel
tank
deflection
under
pressure.
Although
we
do
not
consider
this
to
be
a
feasibility
issue,
we
recognize
that
if
the
tank
were
to
deflect
too
much
in
use
that
either
the
fuel
tank
compartment
would
have
to
be
enlarged
to
accommodate
this
expansion
or
a
smaller
fuel
tank
would
need
to
be
used.
We
request
comment
on
this
issue.
Below,
we
discuss
strategies
that
could
be
used
in
conjunction
with
a
sealed
system
to
minimize
the
build
up
of
pressure
in
the
fuel
tank.
Such
technologies
are
insulation,
volumecompensating
air
bags,
and
bladder
fuel
tanks.
With
the
use
of
these
technologies,
the
same
emission
reductions
could
be
achieved
with
a
pressure
relief
valve
set
to
allow
lower
vent
pressures.
Finally
the
structure
of
the
proposed
standards
gives
manufacturers
the
flexibility
to
meet
the
emission
limits
without
building
up
pressure
in
the
fuel
tank.
b.
Limited
flow
orifice.
An
alternative
to
using
a
pressure
relief
valve
to
hold
vapors
in
the
fuel
tank
would
be
to
use
a
limited
flow
orifice.
This
would
essentially
be
a
plug
in
the
vent
line
with
a
pin
hole
in
it
that
would
be
small
enough
to
limit
vapor
flow
out
of
the
fuel
tank.
However,
the
orifice
size
may
be
so
small
that
there
would
be
a
risk
of
fouling.
In
addition,
an
orifice
designed
for
a
maximum
of
2
psi
under
worst
case
conditions
may
not
be
very
effective
at
lower
temperatures.
We
tested
a
17
gallon
tank
with
a
75
micron
diameter
limited
flow
orifice
over
the
proposed
diurnal
test
procedure
and
saw
close
to
a
25
percent
reduction
in
diurnal
emissions.
The
peak
pressure
in
this
test
was
1.6
psi.
c.
Insulated
fuel
tank.
Another
option
we
evaluated
was
insulating
either
the
fuel
tank
or
the
compartment
around
the
fuel
tank.
Rather
than
capturing
the
vapors
in
the
fuel
tank,
we
minimize
the
fuel
heating,
which
therefore
minimizes
the
vapor
generation.
This
could
be
used
in
conjunction
with
a
limited
flow
orifice
to
reduce
the
loss
of
vapor
through
the
vent
line
due
to
diffusion.
Our
test
data
suggest
that
a
50
percent
reduction
in
emissions
over
the
proposed
test
procedure
can
be
achieved
using
insulation
with
an
Rvalue
of
15.
28
However,
it
should
be
noted
that
today's
fuel
tanks,
when
installed
in
boats,
have
some
amount
of
``
inherent
insulation.
''
This
is
especially
true
for
boats
that
remain
in
the
water.
This
inherent
insulation
is
considered
in
our
baseline
emission
factors.
Additional
control
could
be
achieved
with
the
use
of
a
pressure
relief
valve
coupled
with
an
insulated
tank.
Note
that
an
insulated
tank
could
maintain
the
same
emission
control
while
using
a
pressure
relief
valve
that
allowed
lower
peak
pressures,
compared
with
a
tank
that
was
not
insulated.
The
method
of
insulation
would
have
to
be
consistent
with
U.
S.
Coast
Guard
fuel
system
requirements.
These
requirements
regulate
the
resistance
to
fuels,
oils
and
other
chemicals,
water
adsorption,
compressive
strength,
and
density
of
foam
used
to
encase
fuel
tanks.
In
addition,
the
Coast
Guard
requirements
protect
against
corrosion
of
metal
fuel
tanks
due
to
foam
pulling
away
from
the
fuel
tank
causing
water
to
be
trapped
or
from
improper
drainage.
There
are
several
methods
that
could
be
used
to
insulate
the
fuel
tank
while
maintaining
safe
practices.
These
methods
include
an
insulation
barrier
within
the
walls
of
the
fuel
tank,
insulating
the
compartment
that
the
tank
is
in
rather
than
the
tank
itself,
and
foaming
the
tank
in
place
by
filling
the
entire
compartment
the
tank
is
in.
The
Coast
Guard
requirements
and
potential
insulation
strategies
are
discussed
further
in
Chapter
3
of
the
Draft
Regulatory
Support
Document.
d.
Volume
compensating
air
bag.
Another
concept
for
minimizing
pressure
in
a
sealed
fuel
tank
is
through
the
use
of
a
volume
compensating
air
bag.
The
purpose
of
the
bag
is
to
fill
up
the
vapor
space
in
the
fuel
tank
above
the
fuel.
By
minimizing
the
vapor
space,
the
equilibrium
concentration
of
fuel
vapors
occupies
a
smaller
volume,
resulting
in
a
smaller
mass
of
vapors.
As
the
equilibrium
vapor
concentration
increases
with
increasing
temperature,
the
vapor
space
expands,
which
forces
air
out
of
the
bag
through
the
vent
to
atmosphere.
Because
the
bag
volume
decreases
to
compensate
for
the
expanding
vapor
space,
total
pressure
inside
the
fuel
tank
stays
very
close
to
atmospheric
pressure.
29
Once
the
fuel
tank
cools
as
ambient
temperature
goes
down,
the
resulting
vacuum
in
the
fuel
tank
will
make
the
bag
expand
again
by
drawing
air
from
the
surrounding
ambient.
Our
test
results
showed
that
pressure
could
be
kept
below
0.8
psi
using
a
bag
with
a
capacity
equal
to
25
percent
of
the
fuel
tank
capacity.
Therefore,
the
use
of
a
volumecompensating
air
bag
could
allow
a
manufacturer
to
reduce
the
pressure
limit
on
its
relief
valve.
We
are
still
investigating
materials
that
would
be
the
most
appropriate
for
the
construction
of
these
bags.
The
bags
would
have
to
hold
up
in
a
fuel
tank
for
several
years
and
resist
permeation,
while
at
the
same
time
being
light
and
flexible.
One
such
material
we
are
considering
is
fluorosilicon
fiber.
Also,
the
bag
would
have
to
be
positioned
to
avoid
interfering
with
other
fuel
system
components
such
as
the
fuel
pick
up
or
catching
on
any
sharp
edges
in
the
fuel
tank.
We
estimate
that
this
would
be
more
expensive
than
using
a
pressure
relief
valve
with
some
reinforcement
of
the
fuel
tank
for
pressure;
however,
it
is
also
more
effective
at
emission
control
and
would
minimize
pressure
in
the
fuel
tank.
e.
Bladder
fuel
tank.
Probably
the
most
effective
technology
for
reducing
diurnal
emissions
from
marine
fuel
tanks
is
through
the
use
of
a
collapsible
fuel
bladder.
In
this
concept,
a
low
permeation
bladder
is
installed
in
the
fuel
tank
to
hold
the
fuel.
As
fuel
is
drawn
from
the
bladder,
the
vacuum
created
collapses
the
bladder.
Therefore,
there
is
no
vapor
space
and
no
pressure
build
up
from
fuel
heating.
Because
the
bladder
is
sealed,
there
would
be
no
vapors
vented
to
atmosphere.
This
option
could
also
significantly
reduce
emissions
during
refueling
that
would
normally
result
from
dispensed
fuel
displacing
vapor
in
the
fuel
tank.
We
have
received
comments
that
this
would
be
cost
prohibitive
because
it
could
increase
costs
from
30
to
100
percent
depending
on
tank
size.
However,
bladder
fuel
tanks
have
positive
safety
implications
as
well
and
are
already
sold
by
at
least
one
manufacturer
to
meet
market
demand
in
niche
applications.
f.
Charcoal
canister.
The
primary
evaporative
emission
control
device
used
in
automotive
applications
is
a
charcoal
canister.
With
this
technology,
vapor
generated
in
the
tank
is
vented
through
a
charcoal
canister.
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Federal
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/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
30
Society
of
Automotive
Engineers
Surface
Vehicle
Standard,
``
Marine
Fuel
Hoses,
''
SAE
J
1527
(Docket
AÐ
2000Ð
01;
document
IVÐ
AÐ
19).
activated
charcoal
collects
and
stores
the
hydrocarbons.
Once
the
engine
is
running,
purged
air
is
drawn
through
the
canister
and
the
hydrocarbons
are
burned
in
the
engine.
These
charcoal
canisters
generally
are
about
a
liter
in
size
and
have
the
capacity
to
store
three
days
of
vapor
over
the
test
procedure
conditions.
This
technology
does
not
appear
to
be
attractive
for
marine
fuel
tanks
because
boats
may
sit
for
weeks
at
a
time
without
the
engine
running.
Once
the
canister
is
saturated,
it
provides
no
emission
control.
g.
Floating
fuel
and
vapor
separator.
Another
concept
used
in
some
stationary
engine
applications
is
a
floating
fuel
and
vapor
separator.
Generally
small,
impermeable
plastic
balls
are
floated
in
the
fuel
tank.
The
purpose
of
these
balls
is
to
provide
a
barrier
between
the
surface
of
the
fuel
and
the
vapor
space.
However,
this
strategy
does
not
appear
to
be
effective
for
marine
fuel
tanks.
Because
of
the
motion
of
the
boat,
the
fuel
sloshes
and
the
barrier
would
be
continuously
broken.
Even
small
movements
in
the
fuel
could
cause
the
balls
to
rotate
and
transfer
fuel
to
the
vapor
space.
In
addition,
the
unique
geometry
of
many
fuel
tanks
could
cause
the
balls
to
collect
in
one
area
of
the
tank.
h.
Low
permeability
fuel
tanks.
We
estimate
that
more
than
a
quarter
of
the
evaporative
emissions
from
boats
with
plastic
fuel
tanks
come
from
permeation
through
the
walls
of
the
fuel
tanks.
In
highway
applications,
non
permeable
plastic
fuel
tanks
are
produced
by
blow
molding
a
layer
of
ethylene
vinyl
alcohol
or
nylon
between
two
layers
of
polyethylene.
However,
blow
molding
has
high
fixed
costs
and
therefore
requires
high
production
volumes
to
be
cost
effective.
For
this
reason,
this
manufacturing
technique
is
generally
only
used
for
portable
fuel
tanks
which
are
generally
produced
in
higher
volumes.
For
these
tanks,
however,
multi
layer
fuel
tank
construction
may
be
an
inexpensive
and
effective
approach
to
controlling
permeation
emissions
Manufacturers
of
rotationally
molded
plastic
fuel
tanks
generally
have
low
production
volumes
and
have
commented
that
they
could
not
produce
their
tanks
with
competitive
pricing
in
any
other
way.
Currently,
they
use
cross
link
polyethylene
which
is
a
low
density
material
that
has
relatively
high
rate
of
permeation.
One
material
that
could
be
used
as
a
low
permeation
alternative
in
the
rotational
molding
process
is
nylon.
The
use
of
nylon
in
the
construction
of
these
fuel
tanks
would
reduce
permeation
by
more
than
95
percent
when
compared
to
cross
link
polyethylene
such
as
is
used
today.
Another
type
of
barrier
technology
for
fuel
tanks
would
be
to
treat
the
surfaces
of
a
plastic
fuel
tanks
with
fluorine.
The
fluorination
process
causes
a
chemical
reaction
where
exposed
hydrogen
atoms
are
replaced
by
larger
fluorine
atoms
which
a
barrier
on
surface
of
the
fuel
tank.
In
this
process,
fuel
tanks
are
be
stacked
in
a
steel
container.
The
container
is
then
be
voided
of
air
and
flooded
with
fluorine
gas.
By
pulling
a
vacuum
in
the
container,
the
fluorine
gas
is
forced
into
every
crevice
in
the
fuel
tanks.
As
a
result
of
this
process,
both
the
inside
and
outside
surfaces
of
the
fuel
tank
would
be
treated.
As
an
alternative,
for
tanks
that
are
blow
molded,
the
inside
surface
of
the
fuel
tank
can
be
exposed
to
fluorine
during
the
blow
molding
process.
A
similar
barrier
strategy
is
called
sulfonation
where
sulfur
trioxide
is
used
to
create
the
barrier
by
reacting
with
the
exposed
polyethylene
to
form
sufonic
acid
groups
on
the
surface.
Either
of
these
processes
can
be
used
to
reduce
gasoline
permeation
by
more
than
95
percent.
Achieving
reductions
at
this
level
repeatedly
would
require
tanks
with
consistent
material
quality,
amount,
and
composition
including
pigments
and
any
additive
packages.
This
would
enable
process
and
efficiency
optimization
and
consistency
in
the
effectiveness
of
surface
treatment
processes.
Over
the
first
month
or
so
of
use,
polyethylene
fuel
tanks
can
expand
by
as
much
as
three
percent
due
to
saturation
of
the
plastic
with
fuel.
Manufacturers
have
raised
the
concern
that
this
hydrocarbon
expansion
could
affect
the
effectiveness
of
surface
treatments
like
fluorination
or
sulfonation.
We
believe
that
this
will
not
have
a
significant
effect
on
the
effectiveness
of
these
surface
treatments.
The
California
Air
Resources
Board
has
performed
extensive
permeation
testing
on
portable
fuel
containers
with
and
without
these
surface
treatments.
Prior
to
the
permeation
testing,
the
tanks
were
prepared
by
first
performing
a
durability
procedure
where
the
fuel
container
is
cycled
a
minimum
of
1000
times
between
5
psi
and
1
psi.
In
addition,
the
fuel
containers
are
soaked
with
fuel
for
a
minimum
of
four
weeks
prior
to
testing.
Their
test
data,
presented
in
Chapter
4
of
the
draft
RSD,
show
that
fluorination
and
sulfonation
are
still
effective
after
this
durability
testing.
The
U.
S.
Coast
Guard
has
raised
the
issue
that
any
process
applied
to
marine
fuel
tanks
to
reduce
permeation
would
also
need
to
pass
Coast
Guard
flame
resistance
requirements.
We
are
not
aware
of
any
reason
that
a
fluorination
or
sulfonation
surface
treatment
would
affect
the
flame
resistance
of
a
marine
fuel
tank.
Since
this
issue
was
raised,
we
contracted
to
have
a
fluorinated
fuel
tank
tested.
This
tank
passed
the
U.
S.
Coast
Guard
flame
resistance
test.
Also,
about
a
third
of
marine
fuel
tanks
used
today
are
made
of
aluminum.
Hydrocarbons
do
not
permeate
through
aluminum.
We
request
comment
on
the
lowpermeable
materials
and
strategies
discussed
above,
and
other
options
that
are
available,
for
use
in
marine
fuel
tanks
and
on
their
cost
and
effectiveness.
i.
Low
permeability
hoses.
We
also
estimate
that
permeation
through
fuel
and
vapor
hoses
make
up
more
40
percent
of
the
evaporative
emissions
from
boats.
This
fraction
is
higher
for
boats
using
aluminum
fuel
tanks,
because
they
are
inherently
low
in
tank
permeation
emissions.
By
replacing
rubber
hoses
with
low
permeability
hoses,
evaporative
emissions
through
the
fuel
supply
and
vent
hoses
can
be
reduced
by
more
than
95
percent.
Marine
fuel
hoses
are
designated
as
either
Type
A
or
B
and
eitherClass
1
or
2.
30
Type
A
hose
passes
the
U.
S.
Coast
Guard
fire
test
while
Type
B
represents
hose
that
has
not
passed
this
test.
Class
1
hose
is
intended
for
fuel
feed
lines
where
the
hose
is
normally
in
contact
with
fuel
and
has
a
permeation
limit
of
100
g/
m2/
day
at
23
C.
Class
2
hose
is
intended
for
vent
lines
and
fuel
fill
necks
where
fuel
is
not
continuously
in
contact
with
the
hose
and
has
a
permeation
limit
of
300
g/
m2/
day
at
23
C.
In
general
practice,
most
boat
builders
use
Class
1
hose
for
vent
lines
as
well
as
fuel
lines
to
prevent
having
to
carry
two
hose
types.
However,
most
fuel
fill
necks,
which
have
a
much
larger
diameter
and
are
constructed
differently,
are
Class
2
hose.
Marine
hose
with
permeation
rates
of
less
than
one
tenth
of
the
Class
1
permeation
limit
is
also
used
by
some
boat
builders
today
for
fuel
and
vent
lines.
Given
sufficient
lead
time,
we
believe
that
hose
manufacturers
can
modify
their
designs
to
use
thicker
barriers
or
lower
permeating
materials
to
further
reduce
the
permeation
rates
from
this
hose.
Low
permeability
fuel
supply
and
vent
hoses
produced
today
are
generally
constructed
in
one
of
two
ways:
either
with
a
low
permeability
layer
or
by
using
a
low
permeability
rubber
blend.
One
hose
design,
already
used
in
some
marine
applications,
uses
a
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Rules
thermoplastic
layer
between
two
rubber
layers
to
control
permeation.
This
thermoplastic
barrier
may
either
be
nylon
or
ethyl
vinyl
acetate.
In
automotive
applications,
other
barrier
materials
are
used
such
as
fluoroelastomers
and
fluoroplastics
such
as
Teflon
.
An
added
benefit
of
low
permeability
lines
is
that
some
fluoropolymers
can
be
made
to
conduct
electricity
and
therefore
can
prevent
the
buildup
of
static
charges.
Currently,
fuel
fill
necks
used
in
marine
applications
generally
are
not
made
with
barrier
layers
and
permeate
more
than
fuel
supply
lines.
However,
hoses
are
produced
for
chemical
applications
by
the
same
companies,
using
the
same
process,
that
include
barrier
layers.
This
same
production
methodology
could
be
used
for
marine
fuel
hoses.
Also,
EPA
also
expects
low
permeability
fill
neck
hoses
to
be
used
in
automotive
applications
in
the
2004
as
a
result
of
the
Tier
2
motor
vehicle
evaporative
emission
standards.
An
alternative
approach
to
reducing
the
permeability
of
marine
hoses
would
be
fluorination.
This
process
would
be
performed
in
a
manner
similar
to
discussed
above
for
fuel
tanks.
Fuel
lines
used
to
meet
the
proposed
standards
would
also
have
to
meet
Coast
Guard
specifications
in
33
CFR
183
which
include
a
flame
resistance
test.
Although
the
automotive
standard,
SAE
J
2260,
does
not
specifically
include
a
flame
resistance
test
like
that
included
in
the
Coast
Guard
specifications,
manufacturers
generally
design
(and
test)
their
hoses
to
be
flame
resistant.
4.
Summary
EPA
believes
that
the
proposed
standards
for
evaporative
emissions
from
boats
using
spark
ignition
marine
engines
reasonably
reflect
what
manufacturers
can
achieve
through
the
application
of
available
technology.
Marine
fuel
tank
manufacturers
and
boat
builders
will
need
to
use
the
five
years
of
lead
time
to
select,
design,
and
produce
evaporative
emission
control
strategies
that
will
work
best
for
their
product
line.
We
expect
that
meeting
these
requirements
will
pose
a
challenge,
but
one
that
is
feasible
taking
into
consideration
the
availability
and
cost
of
technology,
lead
time,
noise,
energy,
and
safety.
The
role
of
these
factors
is
presented
in
detail
in
Chapters
3
and
4
of
the
draft
RSD.
We
believe
there
are
several
options
that
can
be
used
to
reduce
diurnal
emissions
from
marine
fuel
tanks.
This,
coupled
with
the
proposed
emissioncredit
program
for
diurnal
emissions,
gives
manufacturers
flexibility
in
how
they
choose
to
comply
with
the
proposed
standards.
We
believe
the
most
likely
approach
meeting
the
proposed
emission
diurnal
standard
will
be
for
manufacturers
to
use
a
closed
vent
with
a
1
psi
pressure
relief
valve.
Although
we
evaluated
several
technologies
that
have
the
potential
to
achieve
larger
emission
reductions,
we
believe
that
more
stringent
standards
are
not
appropriate
at
this
time.
This
industry
is
primarily
made
up
of
small
manufacturers
and
would
likely
need
more
time
to
develop
technology
options
for
further
emission
control.
In
addition,
there
are
a
wide
range
of
fuel
tank
designs
and
applications
in
the
recreational
marine
market,
and
the
technologies
discussed
above
may
not
be
appropriate
for
all
applications.
Given
these
issues,
and
U.
S.
Coast
Guard
requirements,
we
believe
that
the
flexibility
given
in
the
proposed
diurnal
requirements
is
appropriate.
The
proposed
permeation
standards
are
based
on
the
effective
application
of
low
permeable
materials
or
surface
treatments.
This
is
essentially
a
step
change
in
technology;
therefore,
we
believe
that
even
if
we
were
to
propose
a
less
stringent
permeation
standard,
these
technology
options
would
likely
still
be
used.
In
addition,
this
technology
is
relatively
inexpensive
and
can
achieve
meaningful
emission
reductions.
The
proposed
standards
are
expected
to
achieve
a
95
percent
reduction
in
permeation
emissions
from
marine
fuel
tanks
and
hoses.
We
believe
that
more
stringent
standards
could
result
in
significantly
more
expensive
materials
without
large
additional
emission
reduction.
We
request
comment
on
our
proposed
permeation
emission
standards.
IV.
Sterndrive
and
Inboard
Marine
Engines
This
section
describes
our
current
thinking
regarding
exhaust
emissions
from
sterndrive
and
inboard
marine
engines
(SD/
I).
We
are
not
proposing
SD/
I
exhaust
emission
standards
at
this
time.
We
are
investigating
whether
the
application
of
catalysts
on
marine
engines
could
be
a
cost
effective
way
to
control
emissions.
We
believe,
that
setting
catalyst
forcing
standards
now
would
be
premature,
given
the
open
issues
related
to
catalyst
use
in
the
marine
environment.
However,
we
are
continuing
our
efforts
to
develop
and
demonstrate
catalytic
control
on
SD/
I
marine
engines
in
the
laboratory
and
inuse
and
will
place
new
information
in
the
docket
when
it
is
available.
In
fact,
we
intend
to
follow
with
another
rulemaking
in
the
future
that
will
address
exhaust
emissions
from
SD/
I
engines
once
we
have
collected
more
information.
We
intend
to
include
outboards
and
personal
watercraft
in
this
rulemaking
as
well.
There
are
three
primary
approaches
that
we
believe
could
be
used
to
reduce
exhaust
emissions
from
sterndrive
and
inboard
marine
engines.
The
first
is
through
lower
emission
calibration
of
the
engine,
especially
through
the
use
of
electronic
fuel
injection.
This
could
be
implemented
quickly,
but
would
only
result
in
small
emission
reductions.
The
second
approach
would
be
through
the
use
of
exhaust
gas
recirculation
(EGR)
which
could
be
used
to
get
a
40
to
50
percent
reduction
in
NOX.
Although
this
would
be
feasible,
it
would
not
be
nearly
as
effective
at
controlling
emissions
as
the
third
approach
of
using
catalytic
control.
We
believe
catalytic
control
could
be
used
to
achieve
much
larger
emission
reductions
than
either
of
the
first
two
approaches;
therefore,
we
intend
to
implement
catalyst
based
standards
as
soon
as
we
believe
it
is
feasible.
We
believe
we
can
implement
these
stringent
standards
sooner
if
we
do
not
set
an
interim
standard
based
on
EGR.
Manufacturers
have
raised
concerns
that
if
they
were
to
focus
on
designing
for
an
EGR
based
standard,
it
would
divert
resources
needed
for
catalyst
development.
We
are
in
the
process
of
resolving
technical
issues
with
the
use
of
catalysts
in
a
marine
environment.
Ongoing
testing
has
shown
promising
results;
we
believe
that,
in
the
near
future,
continued
efforts
will
resolve
the
remaining
issues
raised
by
the
marine
industry
and
by
Coast
Guard.
One
issue
is
that
operation
in
the
marine
environment
could
result
in
unique
durability
problems
for
catalysts.
Another
issue
to
be
addressed
in
developing
this
technology
is
ensuring
that
salt
water
does
not
reach
the
catalyst
so
that
salt
does
not
accumulate
on
the
catalyst
and
reduce
its
efficiency.
A
third
issue
is
addressing
any
potential
safety
concerns.
As
discussed
in
Section
I.
F,
California
ARB
has
recently
put
into
place
HC+
NOX
exhaust
emission
standards
for
SD/
I
marine
engines.
These
standards
include
a
cap
on
baseline
emission
levels
in
2003
followed
by
catalystforcing
standards
(5
g/
kW
hr
HC+
NOX)
phased
in
from
2007
through
2009.
These
standards
are
contingent
on
technology
reviews
in
2003
and
2005.
ARB
and
industry
have
agreed
on
a
catalyst
development
program
for
marine
engines
over
the
next
several
years.
We
will
participate
in
and
monitor
catalyst
development
efforts
for
marine
engines
over
the
next
few
years.
Since
the
ANPRM,
we
have
collected
laboratory
emission
data
on
a
SD/
I
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Rules
31
Carroll,
J.,
White,
J.,
``
Marine
Gasoline
Engine
Testing,
''
Prepared
by
Southwest
Research
Institute
for
the
Environmental
Protection
Agency
and
the
California
Air
Resources
Board,
EPA
Contract
68Ð
CÐ
98Ð
169,
WA
2Ð
11,
September
2001
(Docket
AÐ
2000Ð
01;
document
IVÐ
AÐ
91).
marine
engine
through
a
joint
effort
with
ARB,
engine
marinizers,
and
Southwest
Research
Institute.
31
We
collected
baseline
emission
data
as
well
as
emission
data
from
closed
loop
control,
exhaust
gas
recirculation,
and
several
catalyst
concepts.
This
work
included
catalyst
packaging
strategies
designed
to
prevent
water
reversion
to
the
catalyst.
With
the
combination
of
closed
loop
electronic
control
and
EGR,
we
saw
a
reduction
of
22
percent
HC+
NOX
and
39
percent
CO
from
baseline.
A
catalyst
was
placed
in
a
stock
riser
extension
which
resulted
in
a
74
percent
reduction
in
HC+
NOX
and
46
percent
reduction
in
CO
from
baseline.
Other
catalyst
configurations
were
also
tested
with
varying
emissions
reductions
depending
on
their
design.
In
the
testing
discussed
above,
the
74
percent
reduction
in
HC+
NOX
was
achieved
using
a
two
catalysts
with
a
combined
volume
of
less
than
1.5
liters
on
a
SD/
I
engine
with
a
7.4
liter
total
engine
displacement.
SD/
I
marine
engines
sold
today
generally
range
from
3.0
to
8.1
liters
of
total
cylinder
displacement.
A
smaller
engine
would
need
less
catalyst
volume
for
the
same
emissions
reduction.
Further
information
on
the
emission
reductions
associated
with
SD/
I
emission
control
strategies
and
associated
costs
will
be
included
in
future
rulemaking
documents.
As
discussed
above,
we
are
working
with
the
marine
industry,
ARB,
and
Coast
Guard
on
technology
assessment
of
catalytic
converters
on
sterndrive
and
inboard
marine
engines.
However,
we
do
not
believe
this
technology
has
been
sufficiently
demonstrated
for
us
to
set
national
standards
based
on
implementation
of
catalyst
technology
at
this
time.
We
will
also
need
to
consider
other
factors
such
as
cost
and
energy
impacts
in
determining
appropriate
levels
of
standards.
As
we
work
towards
low
emission
marine
engines
through
catalyst
technology
for
SD/
I
we
also
intend
to
investigate
this
technology
for
use
on
outboards
and
personal
watercraft
(OB/
PWC).
We
believe
many
of
the
same
issues
with
applying
catalysts
to
SD/
I
marine
engines
also
apply
to
OB/
PWC
marine
engines.
In
addition,
the
annual
emissions
contribution
of
OB/
PWC
marine
is
several
times
larger
than
the
contribution
from
SD/
I
marine
engines
so
there
is
the
potential
for
significant
additional
reductions
from
OB/
PWC.
Therefore,
we
intend
to
look
into
the
feasibility
and
cost
effectiveness
of
applying
catalytic
control
to
outboards
and
personal
watercraft
as
well.
Manufacturers
have
argued
that
the
development
effort
required
for
EGR
may
detract
resources
from
catalyst
development.
We
are
sensitive
to
this
issue
and
are
not
proposing
EGR
based
standards
at
this
time
as
it
could
ultimately
slow
industry's
ability
to
meet
catalyst
based
standards.
Clearly,
the
greatest
potential
for
emission
reductions
is
through
the
use
of
catalysts
and
we
wish
to
implement
standards
as
soon
as
feasible.
However,
if
it
were
to
become
apparent
that
catalysts
would
not
be
feasible
for
SI
marine
engines
in
the
time
frame
of
the
California
ARB
technology
reviews,
we
would
contemplate
proposal
of
a
standard
based
on
EGR.
EGR
has
been
used
in
automotive
applications
for
decades
and
we
believe
there
are
no
significant
technical
hurdles
for
applying
this
inexpensive
technology
to
marine
engines.
Although
current
marine
engines
do
not
generally
have
a
port
for
exhaust
gas
recirculation,
the
electronic
fuel
injection
systems
are
capable
of
controlling
an
EGR
valve
and
control
feedback
loop.
Given
enough
lead
time,
we
believe
manufacturers
could
apply
this
technology
effectively
on
SI
marine
engines.
We
request
comment
on
the
feasibility
of
applying
electronic
fuel
injection,
exhaust
gas
recirculation,
catalysts,
or
other
technology
that
could
be
used
to
reduce
emissions
from
SI
marine
engines.
We
also
request
comment
on
the
costs
and
corresponding
potential
emission
reductions
from
using
these
technologies,
as
well
as
any
potential
effects
on
engine
performance,
safety,
and
durability.
V.
Highway
Motorcycles
We
are
proposing
revised
exhaust
emission
standards
for
highway
motorcycles.
This
section
includes
background
material,
a
description
of
the
proposed
standards
and
other
important
provisions,
and
a
discussion
of
the
technological
feasibility
of
the
proposed
standards.
A.
Overview
In
general,
we
are
proposing
to
harmonize
the
federal
exhaust
emission
standards
for
all
classes
of
motorcycles
with
those
of
the
California
program,
but
on
a
delayed
schedule
relative
to
implementation
in
California.
For
Class
I
and
Class
II
motorcycles,
this
would
mean
meeting
exhaust
emission
standards
that
apply
today
in
California.
For
Class
III
motorcycles,
this
would
mean
meeting
the
two
tiers
of
exhaust
emission
standards
that
California
ARB
has
put
in
place
for
future
model
years.
The
existing
federal
CO
standard
of
12.0
g/
km
would
remain
unchanged.
The
process
by
which
manufacturers
certify
their
motorcycles,
the
test
procedures,
the
driving
cycle,
and
other
elements
of
the
federal
program
would
also
remain
unchanged.
We
are
also
proposing
standards
for
the
currently
unregulated
category
of
motorcycles
with
engines
of
less
than
50cc
displacement.
1.
What
Are
Highway
Motorcycles
and
Who
Makes
Them?
Motorcycles
come
in
a
variety
of
two
and
three
wheeled
configurations
and
styles.
For
the
most
part,
however,
they
are
two
wheeled,
self
powered
vehicles.
EPA
regulations
currently
define
a
motorcycle
as
``
any
motor
vehicle
with
a
headlight,
taillight,
and
stoplight
and
having:
two
wheels,
or
three
wheels
and
a
curb
mass
less
than
or
equal
to
793
kilograms
(1749
pounds)
''
(See
40
CFR
86.402Ð
98).
Both
EPA
and
California
regulations
sub
divide
highway
motorcycles
into
classes
based
on
engine
displacement.
Table
V.
AÐ
1
below
shows
how
these
classes
are
defined.
TABLE
V.
A–
1.—
MOTORCYCLE
CLASSES
Motorcycle
class
Engine
displacement
(cubic
centimeters)
Class
I
.......................
50*–
169
Class
II
......................
170–
279
Class
III
.....................
280
and
greater
*
This
proposal
would
extend
Class
I
to
include
<50cc.
It
is
important
to
note
that
this
definition
excludes
off
highway
motorcycles
from
the
regulatory
definition
of
motorcycle.
This
is
because
the
term
``
motor
vehicle,
''
as
used
in
the
Act,
applies
only
to
vehicles
``
designed
for
transporting
persons
or
property
on
a
street
or
highway''
(CAA
section
216).
In
addition,
EPA
has
promulgated
regulations,
in
40
CFR
85.1703,
that
elaborate
on
the
Act's
definition
of
motor
vehicles
and
set
forth
three
criteria,
which,
if
any
one
is
met,
would
cause
a
vehicle
not
to
be
considered
a
motor
vehicle
under
the
regulations,
and
therefore
not
subject
to
requirements
applicable
to
motor
vehicles.
These
criteria
are:
(1)
The
vehicle
cannot
exceed
a
maximum
speed
of
25
miles
per
hour
over
a
level
paved
surface;
or
(2)
The
vehicle
lacks
features
customarily
associated
with
safe
and
practical
street
or
highway
use,
including
such
things
as
a
reverse
gear
(except
motorcycles),
a
differential,
or
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Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
32
``
2000
Motorcycle
Statistical
Annual'',
Motorcycle
Industry
Council
(Docket
AÐ
2000Ð
01;
document
IIÐ
DÐ
192).
33
DealerNews,
volume
37,
no.
2,
February
2001
(Docket
AÐ
2000Ð
01;
document
IIÐ
DÐ
190).
safety
features
required
by
state
and/
or
Federal
law;
or
(3)
The
vehicle
exhibits
features
which
render
its
use
on
a
street
or
highway
unsafe,
impractical,
or
highly
unlikely,
including
tracked
road
contact
means,
an
inordinate
size,
or
features
ordinarily
associated
with
military
combat
or
tactical
vehicles
such
as
armor
and/
or
weaponry.
Thus,
vehicles
not
meeting
the
criteria
noted
above
are
not
covered
by
the
proposed
emission
standard
for
motorcycles,
because
they
fail
to
meet
the
definition
of
motor
vehicle
in
the
Clean
Air
Act
and
in
40
CFR
85.1703.
Vehicles
that
are
not
considered
to
be
a
motor
vehicle
under
these
statutory
and
regulatory
provisions
are
generally
considered
under
the
Clean
Air
Act
to
be
nonroad
vehicles.
In
an
earlier
proposal,
we
discussed
proposed
emission
standards
for
nonroad
recreational
vehicles,
a
category
which
includes
off
highway
motorcycles
(66
FR
51098,
October
5,
2001).
Also
falling
into
the
nonroad
definition
category
are
the
mopeds
and
scooters
that
do
not
meet
the
definition
of
``
motor
vehicle,
''
i.
e.,
the
smaller
cousins
of
the
mopeds
and
scooters
that
are
currently
considered
highway
motorcycles
and
certified
as
Class
I
motorcycles.
In
other
words,
if
a
moped
or
scooter
or
similar
``
motorbike''
cannot
exceed
25
miles
per
hour,
it
is
not
considered
a
motor
vehicle,
but
it
is
instead
categorized
as
a
nonroad
recreational
vehicle
and
would
be
subject
to
the
emission
standards
recently
proposed
for
offhighway
motorcycles.
Furthermore,
vehicles
that
otherwise
meet
the
motorcycle
definition
(i.
e.,
are
highway
motorcycles
as
opposed
to
offhighway
motorcycles)
but
have
engine
displacements
less
than
50
cubic
centimeters
(cc)
(generally,
youth
motorcycles,
most
mopeds,
and
some
motor
scooters)
are
currently
not
required
to
meet
EPA
standards.
Also
currently
excluded
are
motorcycles
which,
``
with
an
80
kg
(176
lb)
driver,
*
*
*
cannot:
(1)
Start
from
a
dead
stop
using
only
the
engine;
or
(2)
Exceed
a
maximum
speed
of
40
km/
h
(25
mph)
on
level
paved
surfaces''
(e.
g.,
some
mopeds).
Most
scooters
and
mopeds
have
very
small
engine
displacements
and
are
typically
used
as
short
distance
commuting
vehicles.
Motorcycles
with
larger
engine
displacement
are
more
typically
used
for
recreation
(racing
or
touring)
and
may
travel
long
distances.
The
currently
regulated
highway
category
includes
motorcycles
termed
``
dual
use''
or
``
dual
sport,
''
meaning
that
their
designs
incorporate
features
that
enable
them
to
be
competent
for
both
street
and
nonroad
use.
Dual
sport
motorcycles
generally
can
be
described
as
street
legal
dirt
bikes,
since
they
often
bear
a
closer
resemblance
in
terms
of
design
features
and
engines
to
true
offhighway
motorcycles
than
to
highway
cruisers,
touring,
or
sport
bikes.
These
dual
sport
motorcycles
tend
to
fall
in
Class
I
or
Class
II.
The
larger
displacement
Class
III
motorcycles
are
by
far
the
most
common
motorcycles
in
the
current
U.
S.
market.
Of
the
175
engine
2002
families
certified
as
of
January
2002
by
manufacturers
for
sale
in
the
U.
S.,
151
fall
in
the
Class
III
category,
representing
more
than
93
percent
of
projected
sales.
Most
of
these
are
quite
far
from
the
bottom
limit
of
Class
III
motorcycles
(280cc);
more
than
three
quarters
of
projected
2002
highway
motorcycle
sales
are
above
700cc,
with
engine
displacements
exceeding
1000cc
for
the
most
powerful
``
superbikes,
''
large
cruisers,
and
touring
bikes.
The
average
displacement
of
all
certified
engine
families
is
about
980cc,
and
the
average
displacement
of
certified
Class
III
engine
families
is
above
1100cc.
The
sales
weighted
average
displacement
of
2002
highway
motorcycles
is
about
1100cc.
Class
I
and
Class
II
motorcycles,
which
together
make
up
less
than
seven
percent
of
projected
2002
sales
and
only
24
out
of
175
certified
2002
engine
families,
consist
mostly
of
dual
sport
bikes,
scooters,
and
entry
level
sportbikes
and
cruisers.
According
to
the
Motorcycle
Industry
Council,
in
1998
there
were
about
5.4
million
highway
motorcycles
in
use
in
the
United
States
(565,000
of
these
were
dual
sport).
Total
sales
in
1999
of
highway
motorcycles
was
estimated
to
be
about
387,000,
or
about
69
percent
of
motorcycle
sales.
About
15,000
of
these
were
dual
sport
motorcycles.
32
Recent
figures
for
the
2000
calendar
year
show
that
retail
sales
approached
438,000
highway
motorcycles,
about
19,000
of
which
were
dual
sport
bikes.
33
Six
companies
account
for
about
95
percent
of
all
motorcycles
sold
(Honda,
Harley
Davidson,
Yamaha,
Kawasaki,
Suzuki,
and
BMW).
All
of
these
companies
except
Harley
Davidson
and
BMW
also
manufacture
off
highway
motorcycles
and
ATVs
for
the
U.
S.
market.
Harley
Davidson
is
the
only
company
of
these
six
that
is
manufacturing
highway
motorcycles
in
the
U.
S.
for
the
domestic
market.
Dozens
of
other
companies
make
up
the
remaining
five
percent.
Many
of
these
are
small
U.
S.
companies
manufacturing
anywhere
from
a
few
dozen
to
a
few
thousand
motorcycles,
although
importers
and
U.
S.
affiliates
of
larger
international
companies
also
contribute
to
the
remaining
five
percent.
See
the
draft
Regulatory
Support
Document
for
more
information
regarding
the
makeup
of
the
industry.
As
of
the
2002
model
year,
all
highway
motorcycles
with
engines
greater
than
50cc
displacement
are
powered
by
four
stroke
engines.
(Prior
to
the
2002
model
year,
Kawasaki
was
certifying
a
100cc
two
stroke
dual
sport
motorcycle
to
the
federal
emission
standards.)
In
the
scooter
and
moped
segment
with
engines
under
50cc
displacement,
two
stroke
engines
have
traditionally
outnumbered
four
strokes,
although
that
appears
to
be
changing.
In
particular,
Honda
is
now
marketing
a
2002
49cc
four
stroke
scooter.
Of
the
several
dozen
manufacturers
in
the
under
50cc
market,
about
a
third
are
offering
four
stroke
engines.
Therefore,
as
of
the
2002
model
year,
it
appears
that
about
one
third
of
the
sales
of
scooters
and
mopeds
under
50cc
are
powered
by
four
stroke
engines.
2.
What
Is
the
History
of
Emission
Regulations
for
Highway
Motorcycles?
Emissions
from
highway
motorcycles
have
been
regulated
for
more
than
20
years.
While
the
federal
requirements
have
remained
unchanged
since
the
initial
standards
were
adopted
more
than
20
years
ago,
regulations
in
California,
Europe,
and
many
nations
around
the
world
have
been
periodically
updated
to
reflect
the
availability
of
technology
and
the
need
for
additional
emission
reductions.
a.
EPA
regulations.
In
1977
EPA
issued
a
Final
Rule
(42
FR
1126,
Jan.
5,
1977),
which
established
interim
exhaust
emission
standards
effective
for
the
1978
and
1979
model
years
and
ultimate
standards
effective
starting
with
the
1980
model
year.
The
interim
standards
ranged
from
5.0
to
14.0
g/
km
HC
depending
on
engine
displacement,
while
the
CO
standard
of
17.0
g/
km
applied
to
all
motorcycles.
The
standards
and
requirements
effective
for
1980
and
later
model
year
motorcycles,
which
do
not
include
NOX
emission
standards,
remain
in
effect
today.
While
the
final
standards
did
not
differ
based
on
engine
displacement,
the
useful
life
over
which
these
standards
must
be
met
ranged
from
12,000
km
(7,456
miles)
for
Class
I
motorcycles
to
30,000
km
(18,641
miles)
for
Class
III
motorcycles.
Crankcase
emissions
from
motorcycles
have
also
been
prohibited
since
1980.
There
are
no
current
federal
standards
for
evaporative
emissions
from
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Federal
Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
34
California
ARB,
October
23,
1998
``
Proposed
Amendments
to
the
California
On
Road
Motorcycle
Regulation''
Staff
Report:
Initial
Statement
of
Reasons
(Docket
AÐ
2000Ð
01;
document
IIÐ
DÐ
12).
35
The
ECEÐ
40
cycle
is
used
by
several
countries
around
the
world
for
motorcycle
emission
testing.
It
has
its
origins
in
passenger
car
driving,
being
derived
from
the
European
ECEÐ
15
passenger
car
cycle.
The
speed
time
trace
is
simply
a
combination
of
straight
lines,
resulting
in
a
``
modal''
cycle,
rather
than
the
transient
nature
of
the
U.
S.
Federal
Test
Procedure
(FTP).
motorcycles.
The
current
federal
standards
are
shown
in
Table
V.
AÐ
2.
TABLE
V.
A–
2.—
CURRENT
FEDERAL
EXHAUST
EMISSION
STANDARDS
FOR
MOTORCYCLES
Engine
size
HC
(g/
km)
CO
(g/
km)
All
..................................
5.0
12.0
b.
California
ARB
regulations.
Motorcycle
exhaust
emission
standards
in
California
were
originally
identical
to
the
federal
standards
that
applied
to
1978
through
1981
model
year
motorcycles.
The
definitions
of
motorcycle
classes
used
by
California
ARB
continue
to
be
identical
to
the
federal
definitions.
However,
California
ARB
has
revised
its
standards
several
times
in
bringing
them
to
their
current
levels
(see
Table
V.
AÐ
3).
In
the
1982
model
year
the
standards
were
modified
to
tighten
the
HC
standard
from
5.0
g/
km
to
1.0
or
1.4
g/
km,
depending
on
engine
displacement.
California
adopted
an
evaporative
emission
standard
of
2.0
g/
test
for
all
three
motorcycle
classes
for
1983
and
later
model
year
motorcycles.
California
later
amended
the
regulations
for
1988
and
later
model
year
motorcycles
to
further
lower
emissions
and
to
make
the
compliance
program
more
flexible
for
manufacturers.
The
1988
and
later
standards
could
be
met
on
a
corporate
average
basis,
and
the
Class
III
bikes
were
split
into
two
separate
categories:
280
cc
to
699
cc
and
700
cc
and
greater.
These
are
the
standards
that
apply
in
California
now.
Like
the
federal
standards,
there
are
currently
no
limits
on
NOX
emissions
for
highway
motorcycles
in
California.
Under
the
corporate
average
scheme,
no
individual
engine
family
is
allowed
to
exceed
a
cap
of
2.5
g/
km
HC.
Like
the
federal
program,
California
also
prohibits
crankcase
emissions.
TABLE
V.
A–
3.—
CURRENT
CALIFORNIA
HIGHWAY
MOTORCYCLE
EXHAUST
EMISSION
STANDARDS
Engine
size
(cc)
HC
(g/
km)
CO
(g/
km)
50–
279
..........................
1.0
12.0
280–
699
........................
1.0
12.0
700
and
above
..............
1.4
12.0
In
November
1999,
California
ARB
adopted
new
exhaust
emission
standards
for
Class
III
motorcycles
that
would
take
effect
in
two
phases
Tier
1
standards
starting
with
the
2004
model
year,
followed
by
Tier
2
standards
starting
with
the
2008
model
year
(see
Table
V.
AÐ
4).
Existing
California
standards
for
Class
I
and
Class
II
motorcycles,
which
have
been
in
place
since
1982,
remain
unchanged,
as
does
their
evaporative
emissions
standard.
As
with
the
current
standards
in
California,
manufacturers
will
be
able
to
meet
the
requirements
on
a
corporate
average
basis.
Perhaps
most
significantly,
California
ARB's
Tier
1
and
Tier
2
standards
control
NOX
emissions
for
the
first
time
by
establishing
a
combined
HC+
NOX
standard.
California
ARB
made
no
changes
to
the
CO
emission
standard,
which
remains
at
12.0
g/
km,
equivalent
to
the
existing
federal
standard.
In
addition,
California
ARB
is
providing
an
incentive
program
to
encourage
the
introduction
of
Tier
2
motorcycles
before
the
2008
model
year.
This
incentive
program
allows
the
accumulation
of
emission
credits
that
manufacturers
can
use
to
meet
the
2008
standards.
Like
the
federal
program,
these
standards
will
also
apply
to
dualsport
motorcycles.
TABLE
V.
A–
4.—
TIER
1
AND
TIER
2
CALIFORNIA
CLASS
III
HIGHWAY
MOTORCYCLE
EXHAUST
EMISSION
STANDARDS
Model
year
Engine
displacement
HC+
NOX
(g/
km)
CO
(g/
km)
2004
through
2007
(Tier
1)
...............................................
280
cc
and
greater
...........................................................
1.4
12.0
2008
and
subsequent
(Tier
2)
..........................................
280
cc
and
greater
...........................................................
0.8
12.0
California
ARB
also
adopted
a
new
definition
of
small
volume
manufacturer
that
will
take
effect
with
the
2008
model
year.
Currently
and
through
the
2003
model
year,
all
manufacturers
must
meet
the
standards,
regardless
of
production
volume.
Smallvolume
manufacturers,
defined
in
California
ARB's
recent
action
as
a
manufacturer
with
California
sales
of
combined
Class
I,
Class
II,
and
Class
III
motorcycles
not
greater
than
300
units
annually,
do
not
have
to
meet
the
new
standards
until
the
2008
model
year,
at
which
point
the
Tier
1
standard
applies.
California
ARB
intends
to
evaluate
whether
the
Tier
2
standard
should
be
applied
to
small
volume
manufacturers
in
the
future.
34
c.
International
regulations.
The
European
Commission
(EC)
recently
finalized
a
new
phase
of
motorcycle
standards,
which
will
start
in
2003,
and
the
EC
intends
a
second
phase
to
start
in
2006.
Whereas
the
current
European
standards
make
a
distinction
between
two
stroke
and
four
stroke
engines,
the
proposed
standards
would
apply
to
all
motorcycles
regardless
of
engine
type.
The
2003
standards
would
require
emissions
to
be
below
the
values
shown
in
Table
V.
AÐ
5,
as
measured
over
the
European
ECEÐ
40
test
cycle.
35
The
standards
considered
for
2006
are
still
in
a
draft
form
and
have
not
yet
been
officially
proposed,
but
the
expectation
is
that
they
will
be
considerably
more
stringent.
In
addition
to
taking
another
step
in
reducing
motorcycle
emissions,
the
2006
standards
may
incorporate
an
improved
motorcycle
test
cycle,
as
noted
below.
The
standards
in
the
following
table
apply
to
motorcycles
of
less
than
50cc
(e.
g.,
scooters
and
mopeds)
only
if
the
motorcycle
can
exceed
45
kilometers
per
hour
(28
miles
per
hour).
Starting
in
2002
motorcycles
of
less
than
50cc
that
cannot
exceed
45
kilometers
per
hour
(28
miles
per
hour)
are
subject
to
a
new
HC+
NOX
standard
of
1.2
grams
per
kilometer
and
a
CO
standard
of
1.0
gram
per
kilometer.
TABLE
V.
A–
5.—
EUROPEAN
COMMISSION
2003
MOTORCYCLE
EXHAUST
EMISSION
STANDARDS
HC
(g/
km)
CO
(g/
km)
NOX
(g/
km)
1.2
5.5
0.3
Many
other
nations
around
the
world,
particularly
in
South
Asia
where
twostroke
mostly
small
displacement
motorcycles
can
be
a
majority
of
the
vehicle
population,
have
also
recently
improved
their
emission
standards
or
are
headed
that
way
in
the
next
several
years.
For
example,
Taiwan
has
adopted
an
HC+
NOX
standard
of
1.0
gram
per
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157
/
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August
14,
2002
/
Proposed
Rules
36
The
IDC,
although
not
a
transient
cycle
like
the
FTP,
appears
to
be
the
only
cycle
currently
in
use
that
is
based
on
actual
measurements
of
motorcycles
in
use.
37
A
motorcycle
is
a
``
motor
vehicle''
as
defined
under
section
216
of
the
Clean
Air
Act,
which
states
that
``[
t]
he
motor
vehicle'
means
any
self
propelled
vehicle
designed
for
transporting
persons
or
property
on
a
street
or
highway.
''
38
See
Mobile
Source
Enforcement
Memorandum
No.
1A,
Interim
Tampering
Enforcemetn
Policy,
Office
of
Enforcement
and
General
Council,
June
25,
1974
(Docket
AÐ
2000Ð
01;
document
IVÐ
AÐ
27).
(http://
www.
epa.
gov/
oeca/
aed/
comp/
hcomp.
html)
kilometer
for
all
two
strokes
starting
in
2003
(as
tested
on
the
European
ECEÐ
40
test
cycle).
(Four
stroke
motorcycle
engines
will
have
to
meet
at
standard
of
2.0
grams
per
kilometer.)
India
has
proposed
a
standard
for
all
motorcycles
of
1.3
grams
per
kilometer
HC+
NOX
in
2003
and
1.0
grams
per
kilometer
HC+
NOX
in
2005
(as
tested
on
the
Indian
Drive
Cycle,
or
IDC).
36
China
has
adopted
the
European
standards
described
above,
implementing
them
in
2004,
a
year
later
than
Europe.
d.
Test
cycle.
In
the
ANPRM
we
requested
comment
on
the
adequacy
of
the
current
test
cycle
(the
Federal
Test
Procedure,
or
FTP)
for
representing
the
highway
motorcycle
operation.
We
suggested
that
the
existing
US06
test
cycle
(more
aggressive
accelerations
and
higher
speeds
than
the
FTP)
or
another
more
representative
test
cycle
might
be
appropriate
for
highway
motorcycles.
In
addition,
we
noted
the
effort
underway
under
the
auspices
of
the
United
Nations/
Economic
Commission
for
Europe
(UN/
ECE)
to
develop
a
global
harmonized
world
motorcycle
test
cycle
(WMTC),
and
requested
comment
on
adopting
such
a
test
cycle.
The
objective
of
the
WMTC
project
is
to
develop
a
scientifically
supported
test
cycle
that
accurately
represents
the
in
use
driving
characteristics
of
highway
motorcycles.
The
advantages
of
such
a
test
cycle
are
numerous.
First,
the
industry
could
have
a
single
test
cycle
to
meet
emission
standards
in
many
countries
(the
process
recognizes
that
nations
will
have
differing
emission
standards
due
the
varying
air
pollution
concerns).
Second,
the
test
cycle
could
potentially
be
better
than
the
existing
FTP
in
that
it
intends
to
better
represent
how
a
wide
range
of
riders
drive
their
motorcycles.
Similar
comments
were
submitted
on
this
issue
by
the
Motorcycle
Industry
Council
(MIC)
and
by
Harley
Davidson
Motor
Company.
In
general
MIC
and
Harley
Davidson
stated
that
while
pursuing
a
global
emissions
test
procedure
for
motorcycles
makes
good
business
sense,
the
timing
of
the
ongoing
international
process
is
not
consistent
with
the
current
EPA
rulemaking
to
establish
new
motorcycle
standards.
At
this
time
we
are
not
proposing
any
modifications
to
the
highway
motorcycle
test
cycle.
We
continue
to
be
involved
in
the
WMTC
process
and
are
hopeful
that
a
test
cycle
meeting
the
stated
objectives
can
be
agreed
on
by
the
international
participants.
Although
a
draft
test
cycle
has
been
developed,
several
issues
remain
unresolved
and
it
will
likely
be
a
couple
of
years
before
a
new
cycle
can
be
issued
as
a
global
technical
regulation
under
the
process
established
by
a
1998
international
agreement.
Under
that
process,
if
a
test
cycle
is
brought
to
a
vote
and
the
United
States
votes
in
the
affirmative,
we
will
then
be
committed
to
initiating
a
rulemaking
that
may
lead
to
a
proposal
to
adopt
the
new
test
cycle.
We
request
comment
on
the
best
way
to
transition
to
a
new
global
test
cycle
in
the
future,
should
that
time
come.
Among
the
many
options
we
could
consider
are:
an
immediate
transition;
a
phasing
in
of
the
new
cycle
and
a
phasing
out
of
the
FTP;
or
a
phasing
in
of
the
new
cycle
while
maintaining
the
FTP
as
an
option
for
a
specified
number
of
years.
e.
Consumer
modifications.
Many
motorcycle
owners
personalize
their
motorcycles
in
a
variety
of
ways.
This
is
one
of
the
aspects
of
motorcycle
ownership
that
is
appealing
to
a
large
number
of
motorcycle
owners,
and
they
take
their
freedom
to
customize
their
bikes
very
seriously.
However,
there
are
some
forms
of
customization
that
are
not
legal
under
the
provisions
of
Clean
Air
Act
section
203(
a),
which
states
that
it
is
illegal:
``
for
any
person
to
remove
or
render
inoperative
any
device
or
element
of
design
installed
on
or
in
a
motor
vehicle
or
motor
vehicle
engine
in
compliance
with
regulations
under
this
title
...
after
such
sale
and
delivery
to
the
ultimate
purchaser*
*
*''
In
other
words,
under
current
law,
owners
of
motor
vehicles
37
cannot
legally
make
modifications
that
cause
the
emissions
to
exceed
the
applicable
emissions
standards,
and
they
cannot
remove
or
disable
emission
control
devices
installed
by
the
manufacturer.
38
We
use
the
term
``
tampering''
to
refer
specifically
to
actions
that
are
illegal
under
Clean
Air
Act
section
203;
the
term,
and
the
prohibition,
do
not
apply
generally
to
the
wide
range
of
actions
that
a
motorcycle
enthusiast
can
take
to
personalize
his
or
her
motorcycle,
but
only
to
actions
that
remove
or
disable
emission
control
devices
or
cause
the
emissions
to
exceed
the
standards.
We
know,
from
anecdotal
reports
and
from
some
data
collected
from
in
use
motorcycles,
that
a
portion
of
the
motorcycle
riding
population
has
removed,
replaced,
or
modified
the
original
equipment
on
their
motorcycles.
This
customization
can
include
changes
that
can
be
detrimental
(or,
in
some
cases,
possibly
beneficial)
to
the
motorcycle's
emission
levels.
The
ANPRM
sought
comments
and
data
that
could
better
help
us
understand
the
nature
of
the
issue,
such
that
our
proposal
could
be
made
with
the
best
understanding
possible
of
current
consumer
practices.
We
did
not
intend
to
suggest
that
we
would
be
revising
the
existing
tampering
restrictions
to
prohibit
many
of
the
things
that
motorcycle
owners
are
now
doing
legally.
The
proposed
emissions
standards,
if
adopted
by
EPA,
would
not
change
this
``
tampering''
prohibition,
which
has
been
in
place
for
more
than
20
years.
Owners
would
still
be
free
generally
to
customize
their
motorcycles
in
any
way,
as
long
as
they
do
not
disable
emission
controls
or
cause
the
motorcycle
to
exceed
the
emission
standards.
They
would
also
be
free,
as
they
are
now,
to
perform
routine
maintenance
on
their
motorcycles
to
restore
or
maintain
the
motorcycle
engine
and
related
components
in
their
original
condition
and
configuration.
This
proposal
would
increase
the
number
of
motorcycle
models
employing
emission
reduction
technologies
such
as
sequential
fuel
injection,
pulse
air
injection,
and
catalytic
converters.
We
request
comment
on
the
impact,
if
any,
that
these
technologies
could
have
on
the
difficulty
and/
or
cost
of
routine
maintenance
or
other
legal
modifications
performed
by
or
for
the
consumer.
As
discussed
below
and
in
the
draft
RSD,
we
do
not
anticipate
detrimental
impacts
to
the
performance
ch
aracteristics
of
motorcycles
that
will
meet
the
proposed
emission
standards.
We
request
comment
and
supporting
data
on
potential
performance
impacts
(positive
and
negative)
of
these
technologies.
B.
Motorcycles
Covered
by
This
Proposal
Highway,
or
``
street
legal,
''
motorcycles
are
covered
by
the
proposal
described
in
this
section.
EPA
regulations
currently
define
a
``
motorcycle''
as
``
any
motor
vehicle
with
a
headlight,
taillight,
and
stoplight
and
having:
two
wheels,
or
three
wheels
and
a
curb
mass
less
than
or
equal
to
793
kilograms
(1749
pounds).
''
(See
40
CFR
86.402Ð
98).
This
definition
would
continue
to
apply;
therefore,
the
term
``
motorcycle''
would
continue
to
refer
only
to
highway
motorcycles.
In
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/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
addition,
these
``
motorcycles''
that
are
currently
subject
to
emissions
standards
would
be
subject
to
the
proposed
standards.
However,
we
are
also
proposing
to
modify
the
regulations
to
include
some
motorcycles
that
are
currently
excluded
from
the
emission
regulations,
as
described
below.
EPA
regulations
currently
exclude
motorcycles
(i.
e.,
motor
vehicles
that
meet
the
definition
of
``
motorcycle''
stated
above)
from
the
emission
standards
requirements
based
on
several
criteria
laid
out
in
40
CFR
86.401
97.
First,
motorcycles
are
excluded
if
they
have
an
engine
displacement
of
less
than
50cc.
Second,
a
motorcycle
is
excluded
if,
with
an
80
kg
(176
lb)
driver,
it
cannot
start
from
a
dead
stop
using
only
the
engine
or
exceed
40
kph
(25
mph)
on
a
level
paved
surface.
These
provisions
have
the
effect
of
excluding
many
mopeds,
youth
motorcycles,
and
some
scooters
from
having
to
comply
with
any
emission
standards
requirements.
As
discussed
above,
motorcycle
like
vehicles
that
cannot
exceed
25
miles
per
hour
are
not
considered
motor
vehicles,
and
thus
would
be
regulated
under
the
nonroad
recreational
vehicle
standards
proposed
earlier
this
year
(66
FR
51098,
October
5,
2001).
Highway
motorcycles
with
engine
displacements
less
than
50cc
are
generally
most
mopeds,
as
well
as
some
motor
scooters
(``
scooters,
''
or
sometimes,
``
motorbikes'').
Many
of
these
vehicles
are
powered
by
49cc
twostroke
engines,
although
four
stroke
engines
are
becoming
more
popular.
Honda,
for
example,
will
no
longer
be
marketing
any
two
stroke
street
use
motorcycles
as
of
the
2003
model
year;
everything,
including
their
49cc
scooter,
will
be
powered
by
a
four
stroke
engine.
We
are
proposing
to
revise
two
aspects
of
the
regulations
such
that
we
would
require
most
of
these
currently
excluded
vehicles
to
meet
emission
standards
in
the
future.
First,
the
general
exclusion
for
motorcycles
under
50cc
would
be
changed
such
that
no
motorcycles
would
be
excluded
from
the
emission
standards
on
the
basis
of
engine
displacement
alone.
Second,
the
definition
of
Class
I
motorcycles
would
be
revised
to
accommodate
motorcycles
under
50cc
(i.
e.,
a
Class
I
motorcycle
would
be
defined
as
a
motorcycle
with
an
engine
displacement
of
less
than
170cc).
The
standards
that
would
apply
to
these
vehicles
are
described
in
the
following
section.
It
is
important
to
note
that
the
motorcycle
like
vehicles
under
50cc
that
cannot
be
defined
as
a
motor
vehicle
(e.
g.,
one
that
can't
exceed
25
mph),
continue
to
be
excluded
from
these
standards;
they
would,
however,
be
covered
by
the
recently
proposed
standards
for
nonroad
recreational
vehicles
(66
FR
51098,
October
5,
2001).
We
request
comment
on
our
proposed
regulation
of
this
previously
unregulated
category
of
motorcycle.
The
cost
per
ton
of
controlling
emissions
from
motorcycles
with
less
than
50cc
displacement
engines
is
higher
than
for
the
proposed
standards
for
larger
motorcycles.
However,
the
scooters
and
mopeds
are
very
likely
to
be
operated
exclusively
within
populated
urban
areas.
Scooters
and
mopeds,
by
virtue
of
their
limited
speeds,
are
not
appropriate
for
use
on
highways;
these
small
two
wheelers
are
often
purchased
for
limited
commuting
within
large
urban
areas
or
college
campuses.
Thus,
it
is
likely
that
the
air
quality
benefits
of
controlling
emissions
from
these
engines
would
be
greater
than
indicated
by
the
cost
per
ton
comparison
alone.
We
request
comments
on
the
merits
of
applying
standards
to
these
vehicles.
Parties
have
raised
concerns
regarding
the
potential
for
losses
in
environmental
benefits
from
the
highway
use
of
offhighway
motorcycles.
Because
the
standards
are
different
today
offhighway
motorcycles
do
not
currently
have
emissions
standards)
and
would
be
somewhat
different
under
our
proposed
standards,
emissions
reductions
potentially
could
be
lost
if
consumers
purchased
off
highway
motorcycles
for
highway
use
on
a
widespread
basis.
State
requirements
vary
considerably
and
in
some
states
it
may
be
difficult
to
meet
requirements
by
modifying
an
offhighway
motorcycle,
while
in
others
it
may
require
only
a
few
minor
modifications.
We
request
comment
on
current
practices
and
the
potential
for
this
to
occur
in
the
future.
We
also
request
comment
on
steps
we
could
reasonably
take
to
address
air
pollution
concerns
associated
with
highway
use
of
off
highway
motorcycles.
C
.
Proposed
Standards
1.
What
Are
the
Proposed
Standards
and
Compliance
Dates?
In
general,
we
are
proposing
to
harmonize
the
federal
exhaust
emission
standards
for
all
classes
of
motorcycles
with
those
of
the
California
program,
but
on
a
delayed
schedule
relative
to
implementation
in
California.
(The
exception
would
be
motorcycles
with
engines
of
less
than
50cc
displacement,
which
are
not
currently
regulated
by
California,
for
which
we
are
also
proposing
standards.)
For
Class
I
and
Class
II
motorcycles
as
currently
defined,
this
would
mean
meeting
exhaust
emission
standards
that
apply
now
in
California
(and
have
applied
since
1982).
For
Class
III
motorcycles,
this
would
mean
meeting
the
two
tiers
of
exhaust
emission
standards
that
California
ARB
has
put
in
place
for
future
model
years.
The
existing
federal
CO
standard
of
12.0
g/
km
would
remain
unchanged.
The
process
by
which
manufacturers
certify
their
motorcycles,
the
test
procedures,
the
driving
cycle,
and
other
elements
of
the
federal
program
would
remain
unchanged.
In
the
development
of
this
proposal
following
the
publication
of
the
ANPRM
we
considered
several
regulatory
alternatives.
These
included:
no
revision
to
the
standards,
harmonization
with
one
of
the
``
tiers''
of
California
standards
(current,
2004
Tier
1,
2008
Tier
2),
more
stringent
standards
than
those
in
place
in
California,
or
possibly
different
implementation
timing.
We
also
considered
various
alternatives
designed
to
reduce
the
burden
on
small
manufacturers
(these
are
presented
in
section
VII.
B
on
the
Regulatory
Flexibility
Act).
After
considering
comments
on
the
ANPRM,
we
believe
that
the
standards
should
be
revised.
The
existing
Federal
standards
were
established
more
than
twenty
years
ago,
and
it
is
clear
that
emission
control
technology
has
advanced
a
great
deal
in
that
time.
California
has
continued
to
revise
their
standards
to
maintain
some
contact
with
current
technology,
and
manufacturers
have
generally
(but
not
uniformly)
responded
by
producing
motorcycles
for
sale
nationwide
that
meet
the
more
stringent
California
standards.
Thus,
in
large
part
the
existing
federal
standards
has
been
superseded
because
of
the
preponderance
of
manufacturers
that
have
responded
in
this
way.
Those
arguing
against
new
emission
standards
often
cite
the
fact
that
motorcycles
are
typically
far
cleaner
than
the
existing
federal
standards
require.
Although
we
agree,
we
see
this
fact
as
a
reason
for
improving
emission
standards
and
as
evidence
that
the
current
federal
standards
are
out
of
touch
with
the
reality
of
today's
technology.
We
believe
it
is
most
appropriate
at
this
time
to
propose
harmonizing
with
the
California
exhaust
emission
standards,
as
opposed
to
other
options
discussed
in
the
ANPRM.
For
example,
the
dissimilarities
between
on
and
offhighway
motorcycles
do
not
encourage
a
one
size
fits
all
approach
for
all
motorcycles
(this
opinion
is
supported
by
a
significant
number
of
those
who
commented
on
the
ANPRM).
Offhighway
motorcycles
are
powered
predominantly
by
two
stroke
engines,
whereas
highway
motorcycles
are
all
powered
by
four
stroke
engines
as
of
the
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Proposed
Rules
39
See
comments
on
the
ANPRM
from
HarleyDavidson
and
the
Motorcycle
Industry
Council,
available
in
the
public
docket
for
review
(Docket
AÐ
2000Ð
01;
document
IIÐ
DÐ
48).
40
Based
on
analysis
of
motorcycle
emissions
certification
data.
2002
model
year.
On
and
off
highway
motorcycle
engines
also
lie
at
vastly
different
ends
of
the
size
spectrum.
The
average
highway
motorcycle
sold
today
has
a
displacement
of
nearly
1000cc,
whereas
almost
90
percent
of
offhighway
motorcycle
engines
have
an
engine
displacement
of
less
than
350cc.
In
addition,
on
and
off
highway
motorcycles
are
used
in
very
different
ways;
finding
a
set
of
standards
and
a
test
procedure
that
adequately
represents
the
typical
range
of
operation
for
both
types
would
therefore
be
extremely
challenging.
On
highway
motorcycle
manufacturers
have
commented
that,
to
the
extent
the
standards
are
revised,
harmonization
with
California,
rather
than
a
distinctly
different
set
of
standards,
is
preferable
because
it
eliminates
the
possibility
of
needing
two
distinct
product
lines
for
California
and
Federal
regulations.
39
Delaying
implementation
of
the
California
standards
on
a
nationwide
basis
by
two
years
would
provide
an
opportunity
for
manufacturers
to
gain
some
experience
with
the
technology
needed
to
meet
the
new
standards.
Two
years
provides
time
for
technology
optimization
and
cost
reduction.
Providing
a
longer
delay
could
potentially
provide
the
option
of
a
further
decrease
in
the
level
of
the
emission
standards,
given
that
the
technological
feasibility
of
the
California
standards
has
been
adequately
demonstrated
(at
least
one
manufacturer
is
already
selling
a
motorcycle
meeting
the
2008
California
standards).
However,
this
would
be
a
tradeoff
against
a
more
timely
introduction
of
the
new
standards.
We
also
evaluated
whether
the
federal
motorcycle
program
should
incorporate
averaging
provisions,
as
the
California
program
does.
Given
the
desire
of
most
manufacturers
to
manufacture
a
motorcycle
for
nationwide
sale,
such
a
program
without
averaging
would
not
be
desirable
because
it
would
not
provide
the
flexibility
needed
to
meet
the
California
and
federal
requirements
together
and
could
have
at
least
potentially
led
to
a
somewhat
less
stringent
Federal
standard.
Therefore,
we
are
proposing
to
provide
an
averaging
program
comparable
to
California's.
EPA
uses
the
term
``
useful
life''
to
describe
the
period
(usually
years
and/
or
miles)
over
which
the
manufacturer
must
demonstrate
the
effectiveness
of
the
emission
control
system.
For
example,
the
``
useful
life''
of
current
passenger
cars
is
10
years
or
100,000
miles,
whichever
first
occurs.
It
does
not
mean
that
a
vehicle
is
no
longer
useful
or
that
the
vehicle
must
be
scrapped
or
turned
in
once
these
limits
are
reached.
The
term
has
no
effect
on
the
owners'
ability
to
ride
their
motorcycles
for
as
long
as
they
want.
In
the
ANPRM
we
requested
comment
on
whether
the
current
definitions
of
useful
life
for
the
three
motorcycle
classes
remains
appropriate,
given
that
these
definitions
were
established
more
than
20
years
ago.
For
example,
we
question
whether,
given
that
the
average
distance
traveled
per
year
for
highway
motorcycles
is
around
4,200
km
(2,600
miles),
the
useful
life
for
Class
III
motorcycles
of
30,000
km
(18,680
miles)
is
really
appropriate.
A
typical
motorcycle
would
reach
the
useful
life
mileage
in
about
seven
years
at
that
rate.
Based
on
data
received
from
an
industry
trade
group,
we
estimated
an
average
operating
life
of
12.5
years
for
onhighway
motorcycles.
We
request
comment
on
extending
the
useful
life
by
up
to
10,000
km
(6,200
miles)
to
reflect
a
value
more
consistent
with
actual
use.
a.
Class
I
and
Class
II
motorcycles.
We
are
proposing
that
Class
I
and
Class
II
motorcycles
would
have
to
meet
the
current
California
ARB
exhaust
emission
standards
on
a
nationwide
basis
starting
with
the
2006
model
year.
These
standards,
which
have
been
in
place
in
California
since
1982,
are
1.0
g/
km
HC
and
12.0
g/
km
CO,
as
measured
on
the
existing
Federal
Test
Procedure
(FTP)
for
motorcycles.
In
addition
to
applying
to
motorcycles
currently
in
Class
I
and
Class
II
(i.
e.,
those
over
50cc),
we
are
also
proposing
that
these
standards
apply
to
those
motorcycles
encompassed
by
the
proposed
revised
Class
I
definition,
which
would
include
the
previouslyexcluded
engines
under
50cc,
as
described
above.
As
discussed
in
further
detail
below,
we
are
considering
ways
of
including
Class
I
and
Class
II
motorcycles
in
the
overall
emissions
averaging
program,
and
request
comment
on
this
issue.
Class
I
motorcycles
as
currently
defined
are
currently
tested
on
a
version
of
the
Federal
Test
Procedure
(FTP)
that
has
lower
top
speeds
and
reduced
acceleration
rates
relative
to
the
FTP
that
is
used
for
Class
II
and
III
motorcycles.
The
Class
I
FTP
has
a
top
speed
of
just
under
60
km/
hr,
or
around
37
mph,
whereas
the
Class
II/
III
FTP
has
a
top
speed
of
just
over
90
km/
hr,
or
just
above
55
mph.
By
proposing
to
define
motorcycles
with
engine
displacements
of
less
than
50cc
as
Class
I
motorcycles,
these
``
new''
Class
I
motorcycles
would
likewise
be
tested
on
the
Class
I
FTP.
We
believe
that
this
use
of
this
test
cycle
is
feasible
and
appropriate
for
the
new
Class
I
motorcycles
(many
are
advertised
with
a
top
speed
in
the
range
of
40Ð
50
mph).
We
request
comment
on
the
feasibility
of
the
proposed
test
cycle
for
motorcycles
with
engine
displacements
of
less
than
50cc;
in
particular,
we
request
comment
on
whether
experience
in
meeting
existing
European
or
Asian
requirements
provides
any
insight
on
this
issue.
We
request
comment
on
alternative
test
cycles
and
certification
options,
including
whether
the
cycle
required
for
low
speed,
small
displacement
scooters
and
mopeds
in
Europe
should
be
used
or
allowed
by
EPA.
Despite
the
fact
that
virtually
all
Class
I
and
Class
II
motorcycles
already
meet
and
certify
to
these
standards,
40
we
are
proposing
nationwide
implementation
in
2006
for
two
reasons.
First,
there
are
those
motorcycles
under
50cc
that
require
some
lead
time
to
meet
new
standards.
Second,
any
averaging
provisions,
if
finalized,
that
would
provide
flexibility
in
meeting
the
Class
I
and
Class
II
standards
would
not
be
useful
until
the
2006
model
year,
when
some
exchange
of
emission
credits
between
the
three
motorcycle
classes
may
be
allowed
(see
the
request
for
comment
on
averaging
flexibilities
for
Classes
I
and
II
in
section
C.
2
below).
Nevertheless,
we
request
comment
on
the
2006
implementation
date,
and
whether
it
should
be
earlier
for
the
current
Class
I
and
II
motorcycles,
given
that
all
2002
motorcycles
in
these
classes
are
already
certified
at
emission
levels
that
would
meet
the
proposed
standards.
For
example,
we
could
implement
standards
for
the
over
50cc
motorcycles
in
2004
and
for
those
under
50cc
in
2006.
We
recognize,
as
discussed
in
detail
below,
that
the
U.
S.
is
a
small
market
for
scooters
and
mopeds
with
engine
displacements
of
under
50cc,
and
that
many
of
the
factors
that
are
currently
driving
technology
development
are
actions
by
the
governments
in
the
major
world
markets
for
these
types
of
twowheelers
A
U.
S.
attempt
to
drive
technology
to
achieve
emission
limits
more
stringent
or
sooner
than
those
applicable
in
the
largest
scooter
markets
(South
Asia,
Europe)
might
result
in
some
manufacturers
choosing
to
withdraw
from
the
U.
S.
market,
rather
than
develop
specific
technologies
to
address
U.
S.
requirements.
(This
appeared
to
occur
in
the
mid
to
late1980's
when
new
California
standards,
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Proposed
Rules
combined
with
fairly
active
advertising
by
Honda,
drove
the
European
manufacturers
from
the
U.
S.
market.)
For
the
Class
I
motorcycles
under
50cc,
we
therefore
request
comment
on
the
cost
and
technology
that
would
be
associated
with
standards
within
a
range
of
1.0
to
2.0
grams
per
kilometer
HC
(or
HC+
NOX).
We
believe
that,
in
view
of
the
standards
that
apply
or
will
soon
apply
in
many
of
the
major
scooter
markets
around
the
world
(see
Table
V.
AÐ
6),
that
a
standard
in
this
range
is
similar
to
standards
in
other
countries
and
would
allow
the
use
of
similar
technologies
for
U.
S.
standards.
Standards
in
this
range
would
be
intended
to
allow
the
U.
S.
to
be
more
certain
that
we
would
receive
the
same
scooters
being
marketed
in
the
rest
of
major
scooter
markets.
TABLE
V.
A–
6.—
SUMMARY
OF
CURRENT
AND
FUTURE
WORLDWIDE
EMISSION
STANDARDS
FOR
MOTORCYCLES
LESS
THAN
50CC
DISPLACEMENT
Country
HC
CO
NOX
HC+
NOX
Test
cycle
Notes
European
Union
......................
................
6.0
................
3.0
ECE
R47
Current
(``
Euro1'').
................
1.0
................
1.2
ECE
R47
2002
(``
Euro
2'').
Switzerland
.............................
0.5
0.5
0.1
................
ECE
R47
Current.
India
........................................
................
2.0
................
2.0
India
Drive
(IDC)
Current.
................
1.3
................
1.3
India
Drive
(IDC)
2003
Proposed.
................
1.0
................
1.0
India
Drive
(IDC)
2005
Proposed.
China
.......................................
................
6.0
................
3.0
ECE
R47
Current.
................
1.0
................
1.2
ECE
R47
2005.
Japan
......................................
5.26
14.4
0.14
................
ISO
6460
Current
2
stroke.
2.93
20.0
0.51
................
ISO
6460
Current
4
stroke.
Korea
......................................
4.0
8.0
0.1
................
ECE
R47
Current.
Singapore
................................
5.0
12.0
................
................
FTP
Current.
Taiwan
....................................
................
3.5
2.0
................
ECE
R47
Current.
................
7.0
................
1.0
ECE
R47
2003
2
stroke.
................
7.0
................
2.0
ECE
R47
2003
4
stroke.
Thailand
..................................
3.0
4.5
................
................
ECE
R40
Current.
b.
Class
III
Motorcycles.
We
are
proposing
to
harmonize
the
federal
Class
III
motorcycle
standards
with
the
exhaust
emission
standards
of
the
recently
finalized
California
program.
Specifically,
we
propose
to
adopt
the
Tier
1
standard
of
1.4
g/
km
HC+
NOX
starting
in
the
2006
model
year,
and
the
Tier
2
standard
of
0.8
g/
km
starting
in
the
2010
model
year.
Because
both
HC
and
NOX
are
ozone
precursors,
this
new
standard
would
better
reduce
ozone
than
an
HC
only
standard.
Implementation
on
a
nationwide
basis
would
therefore
take
place
starting
two
model
years
after
implementation
of
identical
exhaust
emission
standards
in
California,
ensuring
that
manufacturers
have
adequate
lead
time
to
plan
for
these
new
standards.
As
described
below
in
further
detail,
these
standards
can
be
met
on
a
corporate
average
basis.
As
noted
earlier,
California
ARB
plans
a
technology
progress
review
in
2006
to
evaluate
manufacturers'
progress
in
meeting
the
Tier
2
standards.
We
plan
to
participate
in
that
review
and
work
with
California
ARB,
intending
to
make
any
appropriate
adjustments
to
the
standards
or
implementation
schedule
if
warranted.
For
example,
if
California
ARB
determines
in
the
review
process
that
the
standards
are
achievable,
but
in
2010
rather
than
2008,
we
could
follow
with
a
rulemaking
that
would
consider
appropriate
adjustment
to
the
federal
requirements.
2.
Could
I
Average,
Bank,
or
Trade
Emission
Credits?
To
provide
flexibility
in
meeting
the
standards,
we
are
proposing
to
adopt
an
emission
credit
program
comparable
to
the
existing
California
ARB
regulations,
and
requesting
comment
on
some
additional
flexibility
relative
to
California
ARB's
program
that
could
be
included
in
our
proposed
program.
There
is
currently
no
federal
emissioncredit
program
for
highway
motorcycles.
As
proposed,
the
program
allows
manufacturers
to
meet
the
standards
on
a
fleet
average
basis
(i.
e.,
an
averaging
program).
Under
the
emission
credit
program,
manufacturers
would
be
able
to
balance
the
certified
HC+
NOX
emissions
of
their
Class
III
motorcycles
so
that
the
salesweighted
HC+
NOX
emissions
level
meets
the
applicable
standard.
This
means
that
some
engine
families
may
have
HC+
NOX
emissions
below
the
standards,
while
others
have
HC+
NOX
emissions
higher
than
the
standards.
For
enforcement
purposes,
manufacturers
are
required
to
specify
a
certification
limit,
or
``
Family
Emission
Limit''
for
each
engine
family.
For
example,
one
of
a
manufacturer's
Class
III
engine
families
could
be
certified
at
1.7
g/
km
HC+
NOX;
this
would
be
allowable
under
the
California
regulations
if
the
sales
weighted
average
of
all
the
manufacturer's
engine
families
met
the
applicable
1.4
or
0.8
g/
km
HC+
NOX
standard.
As
discussed
below,
EPA
is
proposing
early
credits
provisions
where
credits
may
be
banked
prior
to
the
beginning
of
the
program.
In
several
other
emissions
control
programs,
EPA
allows
manufacturers
to
bank
credits
after
the
start
of
the
program
for
future
use,
or
trade
them
to
another
manufacturer.
In
general,
EPA
has
been
supportive
of
these
additional
flexibilities
and
sees
the
potential
for
added
value
here
as
a
means
to
reduce
cost
and
provide
additional
compliance
flexibility
as
needed
*
*
*
California's
current
program,
however,
does
not
contain
banking
(except
for
early
banking)
and
trading
provisions
and
manufacturers
have
not
shown
an
interest
in
such
provisions.
Harmonization
with
California
has
been
the
overarching
concern.
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and
trading
provisions
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14,
2002
/
Proposed
Rules
that
are
out
of
step
with
the
California
program
may
have
little
use
because
manufacturers
plan
on
carrying
over
their
California
products
nationwide.
In
addition,
such
provisions
complicate
the
certification
and
compliance
protocols
because
EPA
must
set
up
systems
for
tracking
credits
and
these
systems
must
be
established
even
if
the
use
of
the
credit
provisions
is
unlikely.
Because
EPA
believes
banking
and
trading
provisions
would
complicate
the
program,
EPA
is
requesting
comment
on
them
rather
than
proposing
them.
EPA
requests
comment
on
an
approach
where
manufacturers
would
establish
HC+
NOX
family
emissions
limits
(FELs)
that
are
either
below
the
standard,
for
generating
credits,
or
above
the
standard,
for
using
credits.
These
FELs,
in
effect,
become
the
standard
for
the
individual
family.
This
would
be
similar
in
nature
to
the
program
for
heavy
duty
engines
(see
40
CFR
86.004Ð
15),
but
without
transient
conversion
factors.
Those
commenting
in
support
of
credit
banking
and
trading
are
encouraged
to
also
provide
detailed
comments
on
any
related
provisions
which
would
need
to
be
considered
in
establishing
the
program
for
generating
and
using
credits
such
as
credit
life,
discounts
(if
any),
cross
displacement
class
trading
issues,
etc.
To
maintain
equity,
California
ARB
adopted
a
cap
on
Family
Emission
Limits
of
2.5
g/
km
HC
for
all
individual
engine
families
under
the
existing
emission
credit
program
(i.
e.,
for
Class
III
motorcycles).
Because
the
2.5
g/
km
HC
only
standard
was
in
effect
in
California
before
the
emission
credit
program
was
adopted,
the
2.5
g/
km
cap
continues
to
prevent
manufacturers
from
selling
motorcycles
with
emissions
higher
than
the
previous
standard.
Based
on
this
reasoning,
we
are
proposing
a
similar
cap.
However,
because
the
current
federal
standard
is
5.0
g/
km,
we
are
proposing
an
emissions
cap
on
individual
engine
families
of
5.0
g/
km
HC+
NOX.
This
will
provide
the
added
benefit
of
enabling
manufacturers
to
retain
some
of
the
federally
certified
engine
families
that
might
otherwise
have
had
some
difficulty
meeting
the
somewhat
lower
cap
specified
by
California.
Manufacturers
producing
these
higher
emitting
models
would
need
to
offset
these
emissions
with
other
models
certified
below
the
standard.
To
provide
additional
flexibility
for
manufacturers,
we
are
requesting
comment
on
the
possible
benefits
of
incorporating
Class
I
and
Class
II
motorcycles
into
the
averaging
program
described
above.
This
could
be
done
in
various
ways.
One
option
would
be
to
define
the
proposed
Class
I
and
Class
II
HC
only
standard
of
1.0
g/
km
as
an
averaging
standard,
either
within
each
class
or
for
Class
I
and
Class
II
combined.
However,
we
believe
this
option
would
be
of
limited
use,
given
the
small
number
of
engine
families
in
these
motorcycle
classes.
A
second
option
would
be
to
develop
a
credit
program
similar
to
that
in
place
for
the
California
Low
Emission
Vehicle
Program.
Under
this
type
of
program,
for
example,
credits
accumulated
by
Class
III
motorcycles
could
be
used
to
offset
``
debits''
accumulated
in
one
or
both
of
the
other
classes.
Credits
would
be
accumulated
by
having
a
sales
weighted
fleet
average
value
of
the
class
below
the
applicable
standard,
while
debits
would
result
from
having
a
class
fleetaverage
value
above
the
standard.
A
third
option
would
be
to
allow
the
certification
of
Class
I
and
II
motorcycles
to
the
Class
III
``
averaging
set.
''
In
other
words,
under
this
option
the
combined
sales
weighted
fleet
average
of
Class
I,
II,
and
III
motorcycles
would,
at
the
manufacturer's
option,
be
certified
to
the
Tier
1
and
Tier
2
fleet
average
HC+
NOX
standards.
We
request
comment
on
the
value
of
provisions
of
this
nature,
and
on
the
advantages
and
disadvantages
of
each
of
these
basic
approaches.
We
also
request
comment
on
whether
there
are
any
adaptations
of
this
averaging
program
that
would
improve
the
flexibility
for
small
volume
manufacturers.
To
encourage
early
compliance,
we
are
also
proposing
incentives
in
the
emission
credit
program
similar
to
those
in
place
in
California,
with
timing
adjusted
due
to
the
differing
federal
implementation
schedule.
We
believe
such
incentives
will
encourage
manufacturers
to
introduce
Tier
2
motorcycles
nationwide
earlier
than
required
by
this
proposal.
In
addition,
we
believe
some
manufacturers
can
reduce
emissions
even
further
than
required
by
the
Tier
2
standard;
we
would
like
to
encourage
the
early
introduction
of
these
very
low
emission
vehicles.
This
proposal
would
provide
incentives
for
early
compliance
by
assigning
specific
multiplier
factors
based
on
how
early
a
manufacturer
produces
a
Tier
2
motorcycle
and
a
motorcycle
certified
at
0.4
g/
km
HC+
NOX;
these
multipliers
are
shown
in
Table
V.
CÐ
1.
Because
we
expect
the
Tier
2
technologies
to
become
more
widespread
as
2010
approaches,
the
multipliers
decrease
linearly
in
value
from
2006
until
2010,
when
the
early
compliance
incentive
would
no
longer
have
any
value
(i.
e.,
the
multiplier
has
a
value
of
1.0)
and
the
program
would
terminate.
As
shown
in
Table
V.
CÐ
1,
each
unit
of
early
Tier
2
motorcycles
(those
certified
at
0.8
g/
km
HC+
NOX)
would
count
as
Y
motorcycles
at
0.8
g/
km
HC+
NOX
for
purposes
of
corporate
averaging
in
2010,
where
Y
is
1.5
for
those
motorcycles
sold
during
model
years
(MY)
2003
through
2006,
1.375
for
those
sold
in
MY
2007,
1.250
for
those
sold
in
MY
2008,
and
1.125
for
those
sold
in
MY
2009.
A
similar
set
of
multipliers
is
shown
in
Table
V.
CÐ
1
for
pre
MY
2010
motorcycles
certified
even
lower
at
0.4
g/
km
HC+
NOX.
TABLE
V.
C–
1.—
MULTIPLIERS
TO
ENCOURAGE
EARLY
COMPLIANCE
WITH
THE
PROPOSED
TIER
2
STANDARD
AND
BEYOND
Model
year
sold
Multiplier
(Y)
for
use
in
MY
2010
corporate
averaging*
Early
tier
2
Certified
at
0.4
g/
km
HC+
NOX
2003
through
2006
1.5
3.0
2007
........................
1.375
2.5
2008
........................
1.250
2.0
2009
........................
1.125
1.5
*
Early
Tier
2
motorcycles
and
motorcycles
certified
to
0.4
g/
km
are
counted
cumulatively
toward
the
MY
2010
corporate
average.
In
2010
and
later
model
years
the
program
would
become
a
basic
averaging
program,
where
each
manufacturer
would
have
to
meet
the
applicable
HC+
NOX
standard
on
a
fleetaverage
basis.
See
the
proposed
regulations
at
§
86.449.
3.
Is
EPA
Proposing
Blue
Sky
Standards
for
These
Engines?
We
are
not
proposing
Blue
Sky
Standards
for
motorcycles
at
this
time.
Under
the
proposed
averaging
program
there
is
an
incentive
to
produce
very
clean
motorcycles
early,
but
it
is
of
limited
duration.
However,
several
possible
approaches
could
include
a
Blue
Sky
program,
such
as
the
ones
discussed
for
marine
evaporative
emissions
earlier
in
this
document.
For
example,
a
Blue
Sky
standard
could
be
set
at
the
0.4
g/
km
HC+
NOX
level
used
under
the
proposed
averaging
program.
We
request
comment
on
whether
a
Blue
Sky
program
is
desirable
for
motorcycles,
and
what
standards
would
be
appropriate
for
such
a
program.
4.
Do
These
Standards
Apply
to
Alternative
Fueled
Engines?
The
proposed
emission
standards
would
apply
to
all
motorcycles,
regardless
of
fuel.
Although
the
federal
numerical
emission
standards
have
not
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Vol.
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/
Wednesday,
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14,
2002
/
Proposed
Rules
been
updated
in
more
than
twenty
years,
the
regulations
were
revised
twice
in
the
1990's
to
apply
the
standards
to
certain
alternative
fueled
motorcycles.
In
1990
the
emission
standards
became
applicable
to
methanol
fueled
motorcycles
(see
54
FR
14539,
Apr.
11,
1989),
and
in
1997
the
standards
became
applicable
to
natural
gas
fueled
and
liquified
petroleum
gas
fueled
motorcycles
(see
59
FR
48512,
Sept.
21,
1994).
We
propose
to
apply
the
emission
standards
for
highway
motorcycles,
regardless
of
fuel.
This
would
have
the
effect
of
including
any
motorcycles
that
operate
on
diesel
fuel.
We
do
not
believe
the
provisions
in
this
proposal
create
any
unique
issues
for
motorcycles
powered
by
alternative
fuels.
However,
we
request
comment
on
whether
there
are
unique
aspects
to
motorcycles
fueled
with
these
alternative
fuels
(if
there
are
any
such
motorcycles)
that
would
make
the
proposed
standards
particularly
challenging
or
infeasible.
5.
Should
Highway
and
Off
Highway
Regulations
Be
Integrated?
We
recognize
that
many
motorcycle
manufacturers
produce
both
on
and
offhighway
motorcycles
and
are
interested
in
receiving
comment
on
integrating
the
two
sets
of
requirements
into
a
single
part
of
the
regulations.
Currently,
EPA
regulations
for
highway
motorcycles
are
in
40
CFR
part
86,
while
the
proposed
regulations
for
recreational
vehicles
and
engines
are
in
40
CFR
part
1051.
Given
that
the
proposed
requirements
for
offhighway
motorcycles
and
ATVs
would
duplicate
many
of
the
requirements
that
apply
to
highway
motorcycles
(such
as
test
procedures
and
certification
protocol),
it
may
be
appropriate
to
integrate
the
highway
motorcycle
requirements
with
the
recreational
vehicle
requirements
in
part
1051.
This
may
help
manufacturers
with
both
on
and
off
highway
products
by
eliminating
differing
or
inconsistent
paperwork
or
testing
requirements
for
the
different
products.
We
request
comment
on
the
value
of
centralizing
the
requirements
in
this
way.
6.
Is
EPA
Proposing
Production
Line
Testing
Requirements
for
Highway
Motorcycles?
Production
line
testing
requirements
have
never
been
required
for
highway
motorcycles,
but
we
are
seeking
comment
on
them
as
part
of
this
proposal.
However,
we
recognize
that
production
line
testing
may
serve
as
a
valuable
tool
to
ensure
that
newly
assembled
engines
control
emissions
at
least
as
well
as
the
prototype
models
used
for
certification.
We
believe
testing
highway
motorcycles
from
the
production
line
would
add
little
additional
burden
and
could
easily
be
incorporated
into
the
existing
production
line
quality
checks
that
most
manufacturers
routinely
perform.
In
fact,
some
nonroad
engine
manufacturers
use
emission
measurements
as
part
of
their
standard
quality
control
protocol
at
the
assembly
line
to
ensure
proper
engine
functioning.
Also,
we
would
waive
testing
requirements
for
manufacturers
with
consistently
good
emission
results.
We
request
comment
on
extending
to
highway
motorcycles
the
productionline
testing
requirements
recently
proposed
for
nonroad
engines
and
vehicles
(66
FR
51098).
If
such
requirements
were
extended
to
highway
motorcycles,
we
request
comment
on
the
impact
of
such
requirements
on
smaller
manufacturers
and
whether
such
requirements
should
apply
to
small
manufacturers
(i.
e.,
those
with
less
than
3,000
annual
unit
sales).
In
the
absence
of
production
line
testing
we
are
not
likely
to
allow
post
certification
changes
to
be
made
to
the
Family
Emission
Limits
(FELs)
applicable
to
a
given
engine
family
under
the
emissions
averaging
program.
7.
What
Test
Fuel
Is
Specified
for
Emission
Testing
of
Motorcycles?
The
specifications
for
gasoline
to
be
used
by
the
EPA
and
by
manufacturers
for
emission
testing
can
be
found
in
40
CFR
86.513Ð
94.
These
regulations
also
specify
that
the
fuel
used
for
vehicle
service
accumulation
shall
be
``
representative
of
commercial
fuels
and
engine
lubricants
which
will
be
generally
available
through
retail
outlets.
''
During
the
last
twenty
years
of
regulation
of
motorcycle
emissions,
the
fuel
specifications
for
motorcycle
testing
have
been
essentially
identical
to
those
for
automotive
testing.
However,
on
February
10,
2000,
EPA
issued
a
final
rule
entitled
``
Tier
2
Motor
Vehicle
Emissions
Standards
and
Gasoline
Sulfur
Control
Requirements''
(65
FR
6697,
Feb.
10,
2000).
In
addition
to
finalizing
a
single
set
of
emission
standards
that
will
apply
to
all
passenger
cars,
light
trucks,
and
larger
passenger
vehicles
(e.
g.,
large
SUVs),
the
rule
requires
the
introduction
of
lowsulfur
gasoline
nationwide.
To
provide
consistency
with
the
fuels
that
will
be
in
the
marketplace,
the
rule
amended
the
test
fuel
specifications,
effective
starting
in
2004
when
the
new
standards
will
take
effect.
The
principal
change
that
was
made
was
a
reduction
in
the
allowable
levels
of
sulfur
in
the
test
fuel,
from
a
maximum
of
0.10
percent
by
weight
to
a
range
of
0.0015
to
0.008
percent
by
weight.
Given
that
low
sulfur
fuel
will
be
the
existing
fuel
in
the
marketplace
when
our
proposed
program
would
take
effect
(and
therefore
required
for
service
accumulation),
we
propose
to
amend
the
motorcycle
test
fuel
to
reflect
the
true
nature
of
the
fuels
available
in
the
marketplace.
Doing
so
would
remove
the
possibility
that
a
test
could
be
conducted
with
an
unrealistically
high
level
of
sulfur
in
the
fuel.
8.
Highway
Motorcycle
Evaporative
Emissions
In
addition
to
California's
exhaust
emission
standards,
California
ARB
has
also
established
evaporative
emission
standards
for
highway
motorcycles.
These
standards
took
effect
with
the
1983
model
year
for
Class
I
and
II
motorcycles,
and
the
1984
model
year
for
Class
III
motorcycles.
An
initial
evaporative
emission
standard
that
applied
for
two
model
years
was
set
at
6.0
grams
of
hydrocarbons
per
test.
Following
two
model
years
at
this
level,
the
standard
was
reduced
to
a
more
stringent
2.0
grams
of
hydrocarbons
per
test
for
all
motorcycle
classes.
This
is
the
currently
applicable
standard,
and
it
was
not
changed
during
California's
recent
revisions
to
their
motorcycle
exhaust
emission
standards.
We
believe
that
it
is
not
necessary
at
this
time
to
propose
adopting
broad
evaporative
emission
standards
such
as
California's.
The
fuel
tanks
are
generally
small,
resulting
in
diurnal
and
refueling
emissions
that
we
expect
to
be
proportionately
low.
The
use
rates
of
motorcycles
is
likewise
low,
and
we
expect
that
hot
soak
emissions
will
be
low
as
well.
California
has
unique
air
quality
concerns
that
may
prompt
the
State
to
pursue
and
select
emissions
controls
that
we
may
find
unnecessary
for
a
national
program.
However,
our
investigation
into
the
hydrocarbon
emissions
related
to
permeation
of
fuel
tanks
and
fuel
hoses
with
respect
to
marine
applications
has
raised
a
new
emissions
concern
that
has
a
broad
reach
across
many
different
vehicle
types.
Permeation
of
fuel
tanks
and
hoses
is
one
of
four
components
of
a
vehicle's
evaporative
emissions.
The
other
three
primary
evaporative
components
are:
hot
soak
emissions,
which
occur
when
fuel
evaporates
from
hot
engine
surfaces;
diurnal
emissions,
which
occur
when
fuel
in
tanks
and
hoses
heats
up
in
response
to
increases
in
ambient
temperature;
and
refueling
emissions,
which
occur
when
fuel
vapors
are
displaced
from
the
tank
during
refueling.
As
described
in
section
III,
the
permeation
emissions
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Proposed
Rules
from
boats
outweigh
other
evaporative
emissions
significantly;
in
fact,
permeation
from
tanks
and
hoses
results
in
more
emissions
than
the
other
three
types
of
evaporative
emissions
combined.
Given
this,
we
are
assessing
other
vehicle
types,
including
highway
motorcycles,
off
road
motorcycles,
and
all
terrain
vehicles,
that
may
use
fuel
tanks
or
hoses
with
less
than
optimal
control
of
permeation
emissions.
The
fact
that
the
fuel
tanks
in
these
types
of
vehicles
are
generally
small
does
not
significantly
affect
the
importance
of
these
emissions;
it
is
the
fact
that
permeation
is
occurring
every
hour
of
every
day
when
there
is
fuel
in
the
tank
that
results
in
the
significance
of
emissions
related
to
permeation.
Section
III.
H
of
this
preamble,
as
well
as
the
Draft
Regulatory
Support
Document,
detail
some
of
the
technological
strategies
that
may
be
employed
to
reduce
fuel
permeation.
The
application
of
several
of
these
technologies
to
highway
motorcycles
appears
to
be
relatively
straightforward,
with
little
cost
and
essentially
no
adverse
performance
or
aesthetic
impacts.
These
technologies,
which
are
already
available
and
which
appear
to
be
relatively
inexpensive,
could
reduce
permeation
of
tanks
and
hoses
by
95
percent
or
more.
In
addition,
the
control
technology
may
pay
for
itself
in
many
instances
due
to
positive
fuel
consumption
impacts.
We
request
comment
on
finalizing
standards
that
would
require
low
permeability
fuel
tanks
on
highway
motorcycles,
starting
with
the
2006
model
year.
We
would
presume
that
the
metal
fuel
tanks
that
equip
most
highway
motorcycles
would
already
meet
the
low
permeability
requirement,
and
thus,
there
would
be
no
need
for
any
fuel
tank
design
or
material
changes
on
the
vast
majority
of
highway
motorcycles.
However,
many
if
not
all
of
the
dual
sport
motorcycles
are
equipped
with
plastic
fuel
tanks,
as
are
some
motorcycles
in
the
sport
or
super
sport
categories.
These
motorcycles,
under
the
type
of
regulation
that
we
are
requesting
comment
on,
would
have
to
employ
metal
tanks
or
plastic
fuel
tanks
using
one
of
the
barrier
technologies
(e.
g.,
a
fluorination
or
sulfonation
treatment)
described
in
section
III.
H
to
meet
the
standards.
We
expect
that
any
standards
finalized
would
be
similar
in
design
to
those
proposed
regarding
fuel
tank
permeation
for
marine
engines,
as
discussed
earlier
in
this
preamble.
Retail
sales
data
from
Dealernews
for
the
2001
calendar
year
indicates
that
sales
of
motorcycles
in
the
sport
category
amounted
to
just
over
20
percent
of
total
highway
motorcycle
sales,
and
dual
sport
motorcycles
were
a
much
smaller
4
percent
of
the
total.
We
may
then
conservatively
estimate
that
approximately
25
percent
of
current
motorcycles
now
have
plastic
tanks
that
would
need
upgrading.
This
is
a
conservative
estimate
for
two
reasons:
(1)
Some
of
these
motorcycles
are
probably
using
metal
tanks;
and
(2)
it
is
highly
likely
that
some
of
the
existing
plastic
tanks
have
already
been
upgraded
with
a
barrier
treatment
in
order
to
meet
the
California
evaporative
emission
requirements.
We
are
interested
in
collecting
more
information
regarding
the
degree
to
which
plastic
fuel
tanks
are
used
on
highway
motorcycles,
and,
to
the
extent
they
are,
what
if
any
measures
have
been
taken
by
manufacturers
to
reduce
permeation
emissions.
Highway
motorcycle
fuel
tanks
range
in
capacity
from
just
over
one
gallon
on
some
small
scooters
to
about
7.5
gallons
on
some
large
touring
and
sport
touring
motorcycles.
Most
of
the
sport
and
super
sport
motorcycles
appear
to
have
fuel
tanks
that
fall
generally
in
the
range
of
4
to
6
gallons,
while
dual
sport
motorcycles
may
be
slightly
smaller
on
average,
perhaps
typically
in
the
3
to
5
gallon
range.
If
we
select
5
gallons
as
a
conservative
estimate
of
the
average
size
of
the
fuel
tanks
for
those
types
of
motorcycles
most
likely
to
have
to
employ
one
of
the
fuel
tank
barrier
technologies,
the
additional
cost
per
tank
(assuming
fluorination
treatment)
is
estimated
to
be
about
$3.25
(see
section
5.2.1
of
the
Draft
Regulatory
Support
Document).
We
estimate
that
shipping,
handling,
and
overhead
costs
would
be
an
additional
$0.85,
resulting
in
a
total
average
cost
of
about
$4.10.
Therefore,
the
average
industry
wide
price
increase
that
would
be
associated
with
a
requirement
of
this
nature
would
be
about
$1.00.
We
also
request
comment
on
promulgating
standards
that
would
require
the
use
of
low
permeability
fuel
hoses
on
all
highway
motorcycles,
starting
in
the
2006
model
year.
Like
low
permeation
fuel
tanks,
it
is
very
likely
that
some
manufacturers
have
already
addressed
permeation
from
the
fuel
hoses
on
some
of
their
product
line
due
to
the
California
evaporative
emission
requirements.
However,
we
will
conservatively
estimate
that
no
current
motorcycles
are
equipped
with
fuel
hoses
that
significantly
reduce
or
eliminate
permeation.
The
cost
of
a
fuel
line
with
low
permeation
properties
is
estimated
to
be
about
$1.30
per
foot
(see
section
5.2.1
of
the
Draft
Regulatory
Support
Document).
Highway
motorcycles
are
estimated
to
have
about
one
to
two
feet
of
fuel
line
on
average;
thus,
using
the
average
cost
and
a
fuel
line
length
of
18
inches,
we
estimate
an
average
industry
wide
price
increase
associated
with
a
low
permeation
fuel
line
requirement
to
be
about
$2.00
per
motorcycle.
We
therefore
estimate
that
the
total
increased
cost
per
motorcycle
that
would
result
from
requiring
low
permeation
fuel
tanks
and
fuel
hoses
would
be
about
$3.00.
We
are
interested
in
collecting
more
information
regarding
fuel
hoses
currently
used
on
highway
motorcycles,
in
particular
regarding
the
typical
length,
the
material,
and
the
permeation
properties.
We
request
comment
on
the
form
these
standards
would
take
(e.
g.,
whether
there
should
be
absolute
numerical
limits
or
percentage
reduction
requirements,
if
we
determined
they
were
appropriate.)
We
also
request
comment
on
implementing
requirements
such
as
those
described
above
by
allowing
the
manufacturer
to
submit
a
statement
at
the
time
of
certification
that
the
fuel
tanks
and
hoses
used
on
their
products
meet
standards,
specified
materials,
or
construction
requirements
based
on
testing
results.
For
example,
a
manufacturer
using
plastic
fuel
tanks
could
state
that
the
engine
family
at
issue
is
equipped
with
a
fuel
tank
with
a
low
permeability
barrier
treatment
such
as
fluorination.
Fuel
hoses
could
be
certified
as
being
manufactured
in
compliance
with
certain
accepted
SAE
specifications.
These
certification
statements
could
be
done
on
an
engine
family
basis,
or
possibly
a
blanket
statement
could
cover
a
manufacturer's
entire
product
line.
EPA
expects
that
95
percent
reductions
over
uncontrolled
emission
levels
for
permeation
are
achievable
for
plastic
fuel
tanks.
These
reductions
imply
a
tank
permeability
standard
of
about
0.024
g/
gal/
day
for
fuel
tanks.
For
fuel
hoses,
we
would
consider
the
proposed
standards
for
marine
hoses
of
5
grams
per
square
meter
per
day.
We
request
comment
on
these
and
other
options
that
would
enable
regulation
and
enforcement
of
low
permeability
requirements.
As
was
discussed
earlier
regarding
marine
evaporative
emissions,
California
ARB
and
EPA
have
conducted
permeation
testing
with
regard
to
evaporative
emissions
from
HDPE
plastic
tanks.
There
are
8
data
points
for
tanks
of
3.9
to
7.5
gallons
capacity.
The
permeation
rates
varied
from
0.2
to1.0
grams
per
gallon
per
day
with
an
average
value
of
0.75
g/
gal/
day.
This
data
was
based
on
tests
with
an
average
temperature
of
about
29
C.
As
discussed
in
Chapter
4
of
the
draft
RSD,
temperature
has
a
first
order
effect
on
the
rate
of
permeation.
Roughly,
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Proposed
Rules
permeation
doubles
with
every
10
C
increase
in
temperature.
For
the
5
gallon
tank
discussed
above,
at
23
C,
the
average
emission
rate
is
about
0.50
g/
gal/
day
or
2.5
g/
day.
For
the
purposes
of
this
analysis
we
assumed
a
fuel
hose
with
an
inside
diameter
of
about
1cm
(
3
Ú8
inch)
and
a
permeation
rate
of
550
grams
per
square
meter
per
day
at
23
C.
This
permeation
rate
is
based
on
the
SAE
J30
requirement
for
R7
fuel
hose,
the
type
of
hose
found
on
a
small
sample
of
motorcycles
we
examined.
For
the
18
inch
hose
mentioned
above
this
yields
an
emission
rate
of
7.5
g/
day.
Combining
the
average
emission
rates
determined
for
the
fuel
tanks
and
fuel
hoses
above
and
adjusting
for
the
25
percent
of
tanks
that
would
be
affected
by
permeation
standards
yields
a
daily
average
emission
rate
of
8.1
g/
day
(7.5
g/
day
+
(0.25
x
2.5
g/
day)).
The
total
combined
tank
and
hose
emission
rate
for
those
motorcycles
that
we
estimate
will
require
fuel
tank
treatments
(25
percent
of
motorcycles)
is
9.9
g/
day
(7.5
g/
day
+
2.5
g/
day).
Table
V.
CÐ
2
presents
national
totals
for
permeation
emissions
from
motorcycles.
These
permeation
estimates
are
based
on
the
emission
rates
discussed
above
and
population,
turnover,
and
temperature
projections
discussed
in
Chapter
6
of
the
draft
RSD.
TABLE
V.
C–
2.—
PROJECTED
MOTORCYCLE
PERMEATION
HYDROCARBON
EMISSIONS
[short
tons]
Calendar
year
Baseline
Control
Reduction
2005
..........
14,600
14,600
0
2010
..........
16,900
10,800
6,100
2015
..........
19,200
6,010
13,200
2020
..........
21,500
1,950
19,600
2030
..........
26,200
317
25,900
The
average
lifetime
of
a
typical
motorcycle
is
estimated
to
be
about
12.5
years.
Permeation
control
techniques
can
reduce
emissions
by
95
percent
for
tanks
and
more
than
99
percent
for
hoses.
Multiplying
this
efficiency
and
these
emission
rates
by
12.5
years
and
discounting
at
7
percent
yields
lifetime
per
motorcycle
emission
reductions
of
0.0013
tons
for
the
fuel
tank,
0.017
tons
for
the
fuel
hose,
and
0.019
tons
on
average
overall.
In
turn,
using
the
cost
estimates
above,
these
emission
reductions
yield
HC
cost
per
ton
values
of
$794
for
the
5
gallon
tank,
$112
for
the
fuel
hose,
and
$160
for
the
average
overall.
Because
evaporative
emissions
are
composed
of
otherwise
useable
fuel
that
is
lost
to
the
atmosphere,
measures
that
reduce
evaporative
emissions
can
result
in
potentially
significant
fuel
savings.
For
a
motorcycle
with
a
5
gallon
fuel
tank,
we
estimate
that
the
low
permeability
measures
discussed
in
this
section
could
save
9.6
gallons
over
the
12.5
year
average
operating
lifetime,
which
translates
to
a
discounted
lifetime
savings
of
$6.75
at
an
average
fuel
price
of
$1.10
per
gallon.
Combining
this
savings
with
an
estimated
cost
per
motorcycle
of
$3.00
results
in
a
discounted
lifetime
savings
per
motorcycle
of
$3.75.
The
cost
per
ton
of
the
evaporative
emission
reductions
described
above
is
$160;
however,
if
the
fuel
savings
are
included,
the
estimated
cost
per
ton
is
actually
$
203.
This
means
that
the
fuel
savings
are
larger
than
the
cost
of
using
low
permeation
technology.
D.
Special
Compliance
Provisions
While
the
highway
motorcycle
market
is
dominated
by
large
companies,
there
are
over
30
small
businesses
manufacturing
these
products.
They
are
active
in
both
the
federal
and
California
markets.
California
has
been
much
more
active
than
EPA
in
setting
new
requirements
for
highway
motorcycles,
and
indeed,
the
California
requirements
have
driven
the
technology
demands
and
timing
for
highway
motorcycle
emission
controls.
We
have
developed
our
special
compliance
provisions
partly
in
response
to
the
technology,
timing,
and
scope
of
the
requirements
that
apply
to
the
small
businesses
in
California's
program.
The
provisions
discussed
below
would
reduce
the
economic
burden
on
small
businesses,
allowing
harmonization
with
California
requirements
in
a
phased,
but
timely
manner.
We
propose
that
the
flexibilities
described
below
will
be
available
for
small
entities
with
highway
motorcycle
annual
sales
of
fewer
than
3,000
units
per
model
year
(combined
Class
I,
II,
and
III
motorcycles)
and
fewer
than
500
employees.
These
provisions
are
appropriate
because
of
the
significant
research
and
development
resources
may
be
necessary
to
meet
the
proposed
emission
standards.
These
provisions
would
reduce
the
burden
while
ensuring
the
vast
majority
of
the
program
is
implemented
to
ensure
timely
emission
reductions.
We
also
understand
that
many
small
highway
motorcycle
manufacturers
market
``
classic''
and
``
custom''
motorcycles,
often
with
a
``
retro''
appearance,
that
tends
to
make
the
addition
of
new
technologies
a
uniquely
resourceintensive
prospect.
1.
Delay
of
Proposed
Standards
We
propose
to
delay
compliance
with
the
Tier
1
standard
of
1.4
g/
km
HC+
NOX
until
the
2008
model
year
for
smallvolume
manufacturers.
We
are
proposing
a
Tier
1
standard
beginning
in
the
2006
model
year
for
highway
motorcycles.
Small
manufacturers
are
required
to
meet
the
Tier
1
standard
in
2008
in
California.
Given
that
the
California
requirements
apply
in
2008
for
small
businesses,
we
seek
comment
on
whether
additional
time
is
needed
for
small
businesses
to
comply
with
the
federal
program.
The
current
California
regulations
do
not
require
small
manufacturers
to
comply
with
the
Tier
2
standard
of
0.8
g/
km
HC+
NOX.
The
California
Air
Resources
Board
found
that
the
Tier
2
standard
represents
a
significant
technological
challenge
and
is
a
potentially
infeasible
limit
for
these
small
manufacturers.
We
share
the
California
ARB's
concern
regarding
this
issue.
As
noted
above,
many
of
these
manufacturers
market
a
specialty
product
with
a
``
retro''
simplicity
that
may
not
easily
lend
itself
to
the
addition
of
advanced
technologies
like
catalysts.
However,
the
ARB
has
acknowledged
that,
in
the
course
of
their
progress
review
planned
for
2006,
they
will
revisit
their
small
manufacturer
provisions.
Therefore,
we
plan
to
participate
with
the
ARB
in
the
2006
progress
review
as
these
provisions
are
revisited,
and
delay
making
decisions
on
the
applicability
to
small
businesses
of
Tier
2
or
other
revisions
to
the
federal
regulations
that
are
appropriate
following
the
review.
2.
Broader
Engine
Families
Small
businesses
have
met
EPA
certification
requirements
since
1978.
Nonetheless,
certifying
motorcycles
to
revised
emission
standards
has
cost
and
lead
time
implications.
Relaxing
the
criteria
for
what
constitutes
an
engine
or
vehicle
family
could
potentially
allow
small
businesses
to
put
all
of
their
models
into
one
vehicle
or
engine
family
(or
more)
for
certification
purposes.
Manufacturers
would
then
certify
their
engines
using
the
``
worst
case''
configuration
within
the
family.
This
is
currently
allowed
under
the
existing
regulations
for
small
volume
highway
motorcycle
manufacturers.
We
propose
that
these
provisions
remain
in
place.
3.
Exemption
From
Production
Line
Testing
There
is
currently
no
mandatory
production
line
testing
requirement
for
highway
motorcycles.
The
current
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/
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No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
41
``
Emissions
Trading
for
Small
Businesses'',
Final
Report,
Jack
Faucett
Associates,
March
2002,
http://
www.
sba.
gov/
advo/
research/
rs216tot.
pdf
(Docket
AÐ
2000Ð
01;
document
IVÐ
AÐ
26).
regulations
allow
us
to
request
production
vehicles
from
any
certifying
manufacturer
for
testing.
We
are
proposing
no
changes
to
these
existing
provisions
at
this
time.
4.
Averaging,
Banking,
and
Trading
An
emission
credit
program
allows
a
manufacturer
to
produce
and
sell
engines
and
vehicles
that
exceed
the
applicable
emission
standards,
as
long
as
the
excess
emissions
are
offset
by
the
production
of
engines
and
vehicles
emitting
at
levels
below
the
standards.
The
sales
weighted
average
of
a
manufacturer's
total
production
for
a
given
model
year
must
meet
the
standards.
An
emission
credit
program
typically
also
allows
a
manufacturer
to
bank
credits
for
use
in
future
model
years,
as
well
as
buy
credits
from,
or
sell
credits
to,
other
manufacturers.
Emission
credit
programs
are
generally
made
available
to
all
manufacturers,
though
special
provisions
for
small
businesses
could
be
created
to
increase
flexibility.
We
therefore
propose
an
emission
credit
program
for
highway
motorcycles
similar
to
that
discussed
above
in
V.
C.
2.
for
all
motorcycle
manufacturers.
For
the
reasons
described
in
section
V.
C.
2.,
we
are
not
proposing
post
implementation
emissions
credits
banking
and
trading
provisions,
but
are
requesting
comment
on
them.
This
is
not
consistent
with
the
Panel's
recommendations
for
small
entities.
We
request
comment
on
the
usefulness
of
banking
and
trading
for
small
entities.
For
additional
information
on
this
subject,
commenters
may
review
a
report
prepared
for
the
Small
Business
Administration
on
credits
programs,
``
Emissions
Trading
for
Small
Business'',
for
ideas
on
how
such
programs
could
be
useful
for
small
entities.
41
5.
Hardship
Provisions
We
are
proposing
two
types
of
provisions
to
address
unusual
hardship
circumstances
for
motorcycle
manufacturers.
The
first
type
of
hardship
program
would
allow
small
businesses
to
petition
EPA
for
additional
lead
time
(e.
g.,
up
to
3
years)
to
comply
with
the
standards.
A
small
manufacturer
would
have
to
make
the
case
that
it
has
taken
all
possible
business,
technical,
and
economic
steps
to
comply
but
the
burden
of
compliance
costs
would
have
a
significant
impact
on
the
company's
solvency.
A
manufacturer
would
be
required
to
provide
a
compliance
plan
detailing
when
and
how
it
would
achieve
compliance
with
the
standards.
Hardship
relief
could
include
requirements
for
interim
emission
reductions
and/
or
purchase
and
use
of
emission
credits.
The
length
of
the
hardship
relief
decided
during
review
of
the
hardship
application
would
be
up
to
one
year,
with
the
potential
to
extend
the
relief
as
needed.
The
second
hardship
program
would
allow
companies
to
apply
for
hardship
relief
if
circumstances
outside
their
control
cause
the
failure
to
comply
(i.
e.,
supply
contract
broken
by
parts
supplier)
and
if
the
failure
to
sell
the
subject
engines
would
have
a
major
impact
on
the
company's
solvency.
See
the
proposed
regulatory
text
in
40
CFR
1068.240
and
1068.241
for
additional
details.
In
light
of
the
California
requirements,
which
do
not
include
hardship
provisions,
we
request
comment
on
this
alternative.
6.
Reduced
Certification
Data
Submittal
and
Testing
Requirements
Current
regulations
allow
significant
flexibility
for
certification
by
manufacturers
projecting
sales
below
10,000
units
of
combined
Class
I,
II,
and
III
motorcycles.
For
example,
a
qualifying
manufacturer
must
submit
an
application
for
certification
with
a
statement
that
their
vehicles
have
been
tested
and,
on
the
basis
of
the
tests,
conform
to
the
applicable
emission
standards.
The
manufacturer
retains
adequate
emission
test
data,
for
example,
but
need
not
submit
it.
Qualifying
manufacturers
also
need
not
complete
the
detailed
durability
testing
required
in
the
regulations.
We
are
proposing
no
changes
to
these
existing
provisions.
7.
Nonconformance
Penalties
Clean
Air
Act
section
206(
g)
(42
U.
S.
C.
7525(
g)),
allows
EPA
to
issue
a
certificate
of
conformity
for
heavyduty
engines
or
for
highway
motorcycles
that
exceed
an
applicable
section
202(
a)
emissions
standard,
but
do
not
exceed
an
upper
limit
associated
with
that
standard,
if
the
manufacturer
pays
a
nonconformance
penalty
established
by
rulemaking.
Congress
adopted
section
206(
g)
in
the
Clean
Air
Act
Amendments
of
1977
as
a
response
to
perceived
problems
with
technologyforcing
heavy
duty
engine
emissions
standards.
If
strict
standards
were
maintained,
then
some
manufacturers,
``
technological
laggards,
''
might
be
unable
to
comply
initially
and
would
be
forced
out
of
the
marketplace.
Nonconformance
penalties
were
intended
to
remedy
this
potential
problem.
The
laggards
would
have
a
temporary
alternative
that
would
permit
them
to
sell
their
engines
or
vehicles
by
payment
of
a
penalty.
There
are
three
criteria
for
determining
the
eligibility
of
emission
standards
for
nonconformance
penalties
in
any
given
model
year.
First,
the
emission
standard
in
question
must
become
more
difficult
to
meet,
either
by
becoming
more
stringent
itself
or
by
its
interaction
with
another
emission
standard
that
has
become
more
stringent.
Second,
substantial
work
must
be
required
to
meet
the
emission
standard.
We
consider
``
substantial
work''
to
mean
the
application
of
technology
not
previously
used
in
that
vehicle
or
engine
class/
subclass,
or
a
significant
modification
of
existing
technology,
to
bring
that
vehicle/
engine
into
compliance.
We
do
not
consider
minor
modifications
or
calibration
changes
to
be
classified
as
substantial
work.
Third,
it
must
be
likely
that
a
company
will
become
a
technological
laggard.
A
technological
laggard
is
defined
as
a
manufacturer
who
cannot
meet
a
particular
emission
standard
due
to
technological
(not
economic)
difficulties
and
who,
in
the
absence
of
nonconformance
penalties,
might
be
forced
from
the
marketplace.
Nonconformance
penalties
have
been
offered
on
occasion
as
a
compliance
option
for
several
heavy
duty
engine
emission
standards,
but
they
have
never
been
offered
for
highway
motorcycles.
However,
as
noted
above,
the
Clean
Air
Act
provides
us
with
the
authority
to
provide
nonconformance
penalties
for
highway
motorcycles
if
they
can
be
justified.
While
we
do
not
currently
believe
that
the
three
criteria
established
by
rulemaking
could
be
satisfied
with
respect
to
the
Tier
1
standard
(the
``
substantial
work''
criterion
may
not
be
applicable),
there
is
a
greater
possibility
that
the
criteria
could
be
satisfied
with
respect
to
the
Tier
2
standard.
We
request
comment
on
whether
the
three
criteria
noted
above
could
apply
to
the
Tier
1
or
Tier
2
standard,
and
if
so,
whether
nonconformance
penalties
should
be
considered
as
an
option.
Typically,
however,
it
is
impossible
at
the
time
of
a
rulemaking
to
make
the
finding
that
a
technological
laggard
has
emerged
with
respect
to
a
standard
taking
effect
well
into
the
future.
For
example,
the
proposed
program
would
provide
eight
years
of
lead
time
to
meet
the
Tier
2
standard,
and
making
a
judgment
in
this
rulemaking
regarding
the
existence
of
a
technological
laggard
is
impossible.
It
would
be
likely,
for
example,
that
we
revisit
this
issue
in
the
context
of
California
ARB's
2006
progress
review,
or
even
later.
However,
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2002
/
Proposed
Rules
42
The
manufacturer
taht
had
certified
this
twostroke
for
highway
use
has
typically
certified
4Ð
5
other
Class
I
or
II
engine
families;
therefore,
a
basic
averaging
program
could
enable
them
to
continue
to
market
their
two
stroke
dual
sport.
However,
other
manufacturers
may
not
have
adequate
additional
engine
families
in
these
classes,
making
a
basic
average
standard
less
useful
to
them.
43
Aprilia
webstie,
http://
www.
apriliausa.
com/
ridezone/
ing/
models/
scarabeo50dt/
moto.
htm.
Available
in
the
public
docket
for
review.
44
Improving
Urban
Air
Quality
in
South
Asia
by
Reducing
Emissions
from
Two
Stroke
Engine
Vehicles.
Masami
Kojima,
Carter
Brandon,
and
Jitendra
Shah.
December
2000.
Prepared
for
the
World
Bank.
Available
in
the
public
docket
for
review
(Docket
AÐ
2000Ð
01;
document
IIÐ
DÐ
191),
or
on
the
internet
at:
http://
www.
worldbank.
org/
html/
fpd/
esmpa/
publication/
airquality.
html.
we
request
comment
nevertheless
on
whether
nonconformance
penalties
would
be
a
desirable
option,
should
conditions
develop
that
warrant
them.
We
also
request
comment
on,
given
the
availability
of
the
hardship
provisions
described
above,
whether
nonconformance
penalties
would
potentially
be
needed.
E.
Technological
Feasibility
of
the
Standards
1.
Class
I
and
Class
II
Motorcycles
Between
50
and
180cc
As
noted
above,
we
are
proposing
to
adopt
the
current
California
standards
for
Class
I
and
Class
II
motorcycles.
These
standards
have
been
in
place
in
California
since
1982.
The
question
of
whether
or
not
these
standards
are
technically
feasible
has
been
answered
in
the
affirmative,
since
21
of
the
22
EPA
certified
2001
model
year
motorcycle
engine
families
in
these
classes
are
already
certified
to
these
standards,
and
all
24
of
the
2002
model
year
engine
families
meet
these
standards.
These
24
engine
families
are
all
powered
by
four
stroke
engines,
with
a
variety
of
emission
controls
applied,
including
basic
engine
modifications
on
almost
all
engine
families,
secondary
air
injection
on
three
engine
families,
and
a
two
way
oxidation
catalyst
on
one
engine
family.
In
past
model
years,
but
not
in
the
2002
model
year,
an
engine
family
that
does
not
meet
the
California
standards
had
certified
to
the
existing
federal
standards
and
not
sold
in
California.
It
was
a
100cc
dual
sport
motorcycle
powered
by
a
two
stroke
engine,
with
an
HC
certification
level
of
3.9
g/
km.
This
motorcycle
no
longer
appears
to
be
available
as
of
the
2002
model
year.
Adopting
the
California
standards
for
these
motorcycle
classes
could
preclude
this
motorcycle
or
others
like
it
from
being
certified
and
sold
federally,
unless
the
federal
program
includes
additional
flexibility
relative
to
the
California
program.
As
discussed
above,
we
are
proposing
that
the
HC
standard
for
Class
I
and
Class
II
motorcycles
be
an
averaging
standard,
in
a
departure
from
California's
treatment
of
these
motorcycle
classes.
This
in
itself
could
be
of
limited
use
given
the
low
number
of
Class
I
and
Class
II
engine
families,
but,
as
discussed
in
Section
V.
C.
2
above,
we
are
also
proposing
to
allow
credits
accumulated
by
certifying
Class
III
engine
families
to
a
level
lower
than
the
standard
to
be
used
to
offset
Class
I
or
Class
II
engine
families
certified
to
levels
above
the
fleet
average
standard.
42
2.
Class
I
Motorcycles
Under
50cc
As
we
have
described
earlier
we
are
proposing
to
apply
the
current
California
standard
for
Class
I
motorcycles
to
motorcycles
with
displacements
of
less
than
50cc
(e.
g.,
most
motor
scooters).
These
motorcycles
are
currently
not
subject
to
regulation
by
the
U.
S.
EPA
or
by
the
State
of
California.
They
are,
however,
subject
to
emission
standards
in
Europe
and
much
of
the
rest
of
the
world.
Historically
these
motorcycles
have
been
powered
by
2
stroke
engines,
but
a
trend
appears
to
be
developing
that
would
result
in
most
of
these
being
replaced
by
4
stroke
engines
or
possibly
by
advanced
technology
2
stroke
engines,
in
some
cases
with
catalysts.
The
4
stroke
engine
is
capable
of
meeting
our
proposed
standards.
Class
I
motorcycles
above
50cc
are
already
meeting
it,
most
of
them
employing
nothing
more
than
a
4
stroke
engine.
For
example,
the
existing
Class
I
scooters
certify
at
levels
ranging
from
0.4
to
0.8
grams
per
kilometer
HC.
All
of
these
achieve
the
standards
with
4
stroke
engine
designs,
and
only
one
incorporates
additional
technology
(a
catalyst).
These
engines
range
from
80
to
151cc
in
displacement,
indicating
that
a
smaller
engine
should
encounter
few
problems
meeting
the
proposed
standards.
In
order
to
meet
more
stringent
standards
being
implemented
worldwide,
manufacturers
are
developing
and
implementing
a
variety
of
options.
Honda,
perhaps
the
largest
seller
of
scooters
in
the
U.
S.,
has
entirely
eliminated
2
stroke
engines
from
their
scooter
product
lines
as
of
the
2002
model
year.
They
continue
to
offer
a
50cc
model,
but
with
a
4
stroke
engine.
Both
of
Aprilia's
49cc
scooters
available
in
the
U.
S.
have
incorporated
electronic
direct
injection
technology,
which,
in
the
case
of
one
model,
enables
it
to
meet
the
``
Euro
2''
standards
of
1.2
grams
per
kilometer
HC
and
0.3
grams
per
kilometer
NOX,
without
use
of
a
catalytic
converter.
43
Piaggio,
while
currently
selling
a
49cc
basic
2
stroke
scooter
in
the
U.
S.,
expects
to
begin
production
of
a
direct
injection
version
in
2002,
and
a
4
stroke
50cc
scooter
is
also
in
development.
Numerous
49cc
models
marketed
by
Piaggio
in
Europe
are
available
either
as
a
4
stroke
or
a
2
stroke
with
a
catalyst.
Piaggio,
also
an
engine
manufacturer
and
seller,
is
already
offering
a
50cc
4
stroke
engine
to
its
customers
for
incorporation
into
scooters.
The
U.
S.
represents
a
very
small
portion
of
the
market
for
small
motorcycles
and
scooters.
There
are
few,
if
any,
manufacturers
that
develop
a
small
displacement
motorcycle
exclusively
for
the
U.
S.
market;
the
domestic
sales
volumes
do
not
appear
large
enough
at
this
time
to
support
an
industry
of
this
kind.
The
Italian
company
Piaggio
(maker
of
the
Vespa
scooters),
for
example,
sold
about
as
many
scooters
worldwide
in
2000
(about
480,000)
as
the
entire
volume
of
highway
motorcycles
of
all
sizes
sold
in
the
U.
S.
in
that
year.
U.
S.
sales
of
Vespas
in
2000
amounted
to
about
4800.
The
largest
scooter
markets
today
are
in
South
Asia
and
Europe,
where
millions
are
sold
annually.
In
Taiwan
alone
almost
800,000
motorcycles
were
sold
domestically.
More
than
one
third
of
these
were
powered
by
2
stroke
engines.
Two
and
three
wheelers
constitute
a
large
portion
of
the
transportation
sector
in
Asia,
and
in
some
urban
areas
these
vehiclesÑ
many
of
them
powered
by
2
stroke
enginesÑ
can
approach
75
percent
of
the
vehicle
population.
According
to
a
World
Bank
report,
twostroke
gasoline
engine
vehicles
are
estimated
to
account
for
about
60
percent
of
the
total
vehicle
fleet
in
South
Asia.
44
Many
nations
are
now
realizing
that
the
popularity
of
these
vehicles
and
the
high
density
of
these
vehicles
in
urban
areas
are
contributing
to
severe
air
quality
problems.
As
a
consequence,
some
of
the
larger
small
motorcycle
markets
in
Asia
and
India
are
now
placing
these
vehicles
under
fairly
strict
regulation.
It
is
clear
that
actions
in
these
nations
will
move
the
emission
control
technology
on
small
motorcycles,
including
those
under
50cc,
in
a
positive
direction.
For
example,
according
to
the
World
Bank
report,
as
of
2000
catalytic
converters
are
installed
in
all
new
two
stroke
engine
motorcycles
in
India,
and
2003
standards
in
Taiwan
will
effectively
ban
new
two
strokes
with
emission
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Vol.
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157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
standards
so
stringent
that
only
a
fourstroke
engine
is
capable
of
meeting
them.
Given
the
emerging
international
picture
regarding
emission
standards
for
scooters,
we
believe
that
scooter
manufacturers
will
be
producing
scooters
of
less
than
50cc
displacement
that
meet
our
proposed
standards
well
in
advance
of
the
2006
model
year,
the
first
year
we
propose
to
subject
this
category
of
motorcycle
to
U.
S.
emission
standards.
We
would
expect
that
small
entities
that
import
scooters
into
the
U.
S.
from
the
larger
scooter
markets
would
be
able
to
import
complying
vehicles.
We
request
comment
on
this
assessment.
There
are
other
numerous
factors
in
the
international
arena
that
may
affect
the
product
offerings
in
the
less
than
50cc
market
segment.
For
example,
the
European
Union
recently
changed
the
requirements
regarding
insurance
and
helmet
use
for
under
50cc
scooters
and
mopeds.
Previously,
the
insurance
discounts
and
lack
of
helmet
requirements
in
Europe
provided
two
relatively
strong
incentives
to
purchasers
to
consider
a
49cc
scooter.
Recently,
however,
the
provisions
were
changed
such
that
helmets
are
now
required
and
the
insurance
costs
are
comparable
to
larger
motorcycles.
The
result
was
a
drop
of
about
30%
in
European
sales
of
49cc
scooters
in
2001
due
to
customers
perceiving
little
benefit
from
a
49cc
scooter
relative
to
a
larger
displacement
engine.
3.
Class
III
motorcycles
a.
Tier
1
standards.
In
the
short
term,
the
proposed
Tier
1
HC+
NOX
standard
of
1.4
g/
km
HC+
NOX
reflects
the
goal
of
achieving
emission
reductions
that
could
be
met
with
reasonably
available
control
technologies,
primarily
involving
engine
modifications
rather
than
catalytic
converters.
As
noted
earlier,
we
are
proposing
that
this
standard
be
effective
for
the
2006
model
year.
Based
on
current
certification
data,
a
number
of
existing
engine
families
already
comply
with
this
standard
or
would
need
relatively
simple
modifications
to
comply.
In
other
cases,
the
manufacturers
will
need
to
use
control
technologies
that
are
available
but
are
not
yet
used
on
their
particular
vehicles
(e.
g.,
electronic
fuel
injection
to
replace
carburetors,
changes
to
cam
lobes/
timing,
etc.).
For
the
most
part,
manufacturers
will
not
need
to
use
advanced
technologies
such
as
closecoupled
closed
loop
three
way
catalysts.
While
manufacturers
will
use
various
means
to
meet
the
Tier
1
standard,
there
are
four
basic
types
of
existing,
non
catalyst
based,
emission
control
systems
available
to
manufacturers.
The
most
important
of
these
is
the
use
of
secondary
pulse
air
injection.
Other
engine
modifications
and
systems
include
more
precise
fuel
control,
better
fuel
atomization
and
delivery,
and
reduced
engine
out
emission
levels
from
engine
changes.
The
combinations
of
low
emission
technologies
ultimately
chosen
by
motorcycle
manufacturers
are
dependent
on
the
engine
out
emission
levels
of
the
vehicle,
the
effectiveness
of
the
prior
emission
control
system,
and
individual
manufacturer
preferences.
Secondary
pulse
air
injection,
as
demonstrated
on
current
motorcycles,
is
applied
using
a
passive
system
(i.
e.,
no
air
pump
involved)
that
takes
advantage
of
the
flow
of
gases
(``
pulse'')
in
the
exhaust
pipes
to
draw
in
fresh
air
that
further
combusts
unburned
hydrocarbons
in
the
exhaust.
Engine
modifications
include
a
variety
of
techniques
designed
to
improve
fuel
delivery
or
atomization;
promote
``
swirl''
(horizontal
currents)
and
``
tumble''
(vertical
currents);
maintain
tight
control
on
air
to
fuel
(A/
F)
ratios;
stabilize
combustion
(especially
in
lean
A/
F
mixtures);
optimize
valve
timing;
and
retard
ignition
timing.
Secondary
pulse
air
injection
involves
the
introduction
of
fresh
air
into
the
exhaust
pipe
immediately
after
the
gases
exist
the
engine.
The
extra
air
causes
further
combustion
to
occur,
thereby
controlling
more
of
the
hydrocarbons
that
escape
the
combustion
chamber.
This
type
of
system
is
relatively
inexpensive
and
uncomplicated
because
it
does
not
require
an
air
pump;
air
is
drawn
into
the
exhaust
through
a
oneway
reed
valve
due
to
the
pulses
of
negative
pressure
inside
the
exhaust
pipe.
Secondary
pulse
air
injection
is
one
of
the
most
effective
non
catalytic
emission
control
technologies;
compared
to
engines
without
the
system,
reductions
of
10
to
40
percent
for
HC
are
possible
with
pulse
air
injection.
Sixty
five
of
the
151
2001
model
year
Class
III
engine
families
certified
for
sale
in
the
U.
S
employ
secondary
pulse
air
injection
to
help
meet
the
current
California
standards.
We
anticipate
that
most
of
the
remaining
engine
families
will
use
this
technique
to
help
meet
the
Tier
1
and
Tier
2
standards.
Improving
fuel
delivery
and
atomization
primarily
involves
the
replacement
of
carburetors,
currently
used
on
most
motorcycles,
with
more
precise
fuel
injection
systems.
There
are
several
types
of
fuel
injection
systems
and
components
manufacturers
can
choose.
The
most
likely
type
of
fuel
injection
manufacturers
will
choose
to
help
meet
the
Tier
1
standard
is
sequential
multi
point
fuel
injection
(SFI).
Unlike
conventional
multi
point
fuel
injection
systems
that
deliver
fuel
continuously
or
to
paired
injectors
at
the
same
time,
sequential
fuel
injection
can
deliver
fuel
precisely
when
needed
by
each
cylinder.
With
less
than
optimum
fuel
injection
timing,
fuel
puddling
and
intake
manifold
wall
wetting
can
occur,
both
of
which
hinder
complete
combustion.
Use
of
sequentialfuel
injection
systems
help
especially
in
reducing
cold
start
emissions
when
fuel
puddling
and
wall
wetting
are
more
likely
to
occur
and
emissions
are
highest.
Motorcycle
manufacturers
are
already
beginning
to
use
sequential
fuel
injection
(SFI).
Of
the
152
Class
III
motorcycle
engine
families
certified
for
sale
this
year,
36
employ
SFI
systems.
We
anticipate
increased
applications
of
this
or
similar
fuel
injection
systems
to
achieve
the
more
precise
fuel
delivery
needed
to
help
meet
the
Tier
1
and
Tier
2
standards.
In
addition
to
the
techniques
mentioned
above,
various
engine
modifications
can
be
made
to
improve
emission
levels.
Emission
performance
can
be
improved,
for
example,
by
reducing
crevice
volumes
in
the
combustion
chamber.
Unburned
fuel
can
be
trapped
momentarily
in
crevice
volumes
before
being
subsequently
released.
Since
trapped
and
re
released
fuel
can
increase
engine
out
emissions,
the
elimination
of
crevice
volumes
would
be
beneficial
to
emission
performance.
To
reduce
crevice
volumes,
manufacturers
can
evaluate
the
feasibility
of
designing
engines
with
pistons
that
have
reduced,
top
``
land
heights''
(the
distance
between
the
top
of
the
piston
and
the
first
ring).
Lubrication
oil
which
leaks
into
the
combustion
chamber
also
has
a
detrimental
effect
on
emission
performance
since
the
heavier
hydrocarbons
in
oil
do
not
oxidize
as
readily
as
those
in
gasoline
and
some
components
in
lubricating
oil
may
tend
to
foul
the
catalyst
and
reduce
its
effectiveness.
Also,
oil
in
the
combustion
chamber
may
trap
HC
and
later
release
the
HC
unburned.
To
reduce
oil
consumption,
manufacturers
can
tighten
the
tolerances
and
improve
the
surface
finish
on
cylinders
and
pistons,
piston
ring
design
and
materials,
and
exhaust
valve
stem
seals
to
prevent
excessive
leakage
of
lubricating
oil
into
the
combustion
chamber.
Increasing
valve
overlap
is
another
engine
modification
that
can
help
reduce
emissions.
This
technique
helps
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Vol.
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157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
reduce
NOX
generation
in
the
combustion
chamber
by
essentially
providing
passive
exhaust
gas
recirculation
(EGR).
When
the
engine
is
undergoing
its
pumping
cycle,
small
amounts
of
combusted
gases
flow
past
the
intake
valve
at
the
start
of
the
intake
cycle.
This
creates
what
is
essentially
a
passive
EGR
flow,
which
is
then
either
drawn
back
into
the
cylinder
or
into
another
cylinder
through
the
intake
manifold
during
the
intake
stroke.
These
combusted
gases,
when
combined
with
the
fresh
air/
fuel
mixture
in
the
cylinder,
help
reduce
peak
combustion
temperatures
and
NOX
levels.
This
technique
can
be
effected
by
making
changes
to
cam
timing
and
intake
manifold
design
to
optimize
NOX
reduction
while
minimizing
impacts
to
HC
emissions.
Secondary
pulse
air
injection
and
engine
modifications
already
play
important
parts
in
reducing
emission
levels;
we
expect
increased
uses
of
these
techniques
to
help
meet
the
Tier
1
standard.
Direct
evidence
of
the
extent
these
technologies
can
help
manufacturers
meet
the
Tier
1
standard
can
be
found
in
EPA's
highway
motorcycle
certification
database.
This
database
is
comprised
of
publiclyavailable
certification
emission
levels
as
well
as
some
confidential
data
reported
by
the
manufacturers
pursuant
to
existing
motorcycle
emission
certification
requirements.
We
do
not
expect
any
of
these
possible
changes
to
adversely
affect
performance.
Indeed,
the
transition
to
some
of
these
technologies
(e.
g.,
advanced
fuel
injection)
would
be
expected
to
improve
performance,
fuel
economy,
and
reliability.
A
direct
comparison
of
several
motorcycle
models
in
the
EPA
certification
database
between
the
``
California''
model
(where
one
is
offered;
it
is
the
exception
rather
than
the
rule
that
a
manufacturer
offers
a
separate
engine
system
for
California)
and
the
model
sold
in
the
rest
of
the
U.
S.
reveals
no
change
in
the
performance
characteristics
in
the
database
(e.
g.,
rated
horsepower,
torque).
We
request
comment
on
the
impact
these
anticipated
changes
might
have
on
performance
related
factors.
b.
Tier
2
standards.
In
the
long
term,
the
proposed
Tier
2
HC+
NOX
standard
of
0.8
g/
km
would
ensure
that
manufacturers
will
continue
to
develop
and
improve
emission
control
technologies.
We
are
proposing
the
Tier
2
standard
to
be
effective
by
the
2010
model
year.
We
believe
this
standard
is
technologically
feasible,
though
it
will
present
some
challenges
for
manufacturers.
Several
manufacturers
are,
however,
already
using
some
of
the
technologies
that
will
be
needed
to
meet
this
standard.
In
addition,
our
proposed
implementation
time
frame
gives
manufacturers
two
years
of
experience
in
meeting
this
standard
in
California
before
having
to
meet
it
on
a
nationwide
basis.
At
least
one
manufacturer
already
uses
closed
loop,
three
way
catalysts
on
several
of
its
product
lines.
One
manufacturer
has
already
certified
a
large
touring
motorcycle
to
the
Tier
2
standards
for
sale
in
California.
Depending
on
assumptions
regarding
NOX
levels,
other
manufacturers
have
products
currently
in
the
market
with
emission
levels
close
to
the
Tier
2
standards
using
two
way
catalysts,
fuel
injection,
secondary
pulse
air
injection,
and
other
engine
modifications.
The
current
average
HC
certification
level
for
Class
III
motorcycles
is
just
under
1.0
g/
km,
with
a
number
of
motorcycles
from
a
variety
of
manufacturers
at
levels
of
0.5
g/
km
or
lower.
We
expect
that
the
proposed
eight
years
of
lead
time
prior
to
meeting
these
standards
on
a
nationwide
basis
would
allow
manufacturers
to
optimize
these
and
other
technologies
to
meet
the
Tier
2
standard.
To
meet
the
proposed
Tier
2
standard
for
HC+
NOX,
manufacturers
would
likely
use
more
advanced
engine
modifications
and
secondary
air
injection.
Specifically,
we
believe
manufacturers
would
use
computercontrolled
secondary
pulse
air
injection
(i.
e.,
the
injection
valve
would
be
connected
to
a
computer
controlled
solenoid).
In
addition
to
these
systems,
manufacturers
would
probably
need
to
use
catalytic
converters
on
some
motorcycles
to
meet
the
proposed
Tier
2
standards.
There
are
two
types
of
catalytic
converters
currently
in
use:
two
way
catalysts
(which
control
only
HC
and
CO)
and
three
way
catalysts
(which
control
HC,
CO,
and
NOX).
Under
the
proposed
Tier
2
standard,
manufacturers
would
need
to
minimize
levels
of
both
HC
and
NOX.
Therefore,
to
the
extent
catalysts
are
used,
manufacturers
would
likely
use
a
threeway
catalyst
in
addition
to
engine
modifications
and
computer
controlled,
secondary
pulse
air
injection.
As
discussed
previously,
improving
fuel
control
and
delivery
provides
emission
benefits
by
helping
to
reduce
engine
out
emissions
and
minimizing
the
exhaust
variability
which
the
catalytic
converter
experiences.
One
method
for
improving
fuel
control
is
to
provide
enhanced
feedback
to
the
computer
controlled
fuel
injection
system
through
the
use
of
heated
oxygen
sensors.
Heated
oxygen
sensors
(HO2S)
are
located
in
the
exhaust
manifold
to
monitor
the
amount
of
oxygen
in
the
exhaust
stream
and
provide
feedback
to
the
electronic
control
module
(ECM).
These
sensors
allow
the
fuel
control
system
to
maintain
a
tighter
band
around
the
stoichiometric
A/
F
ratio
than
conventional
oxygen
sensors
(O2S).
In
this
way,
HO2S
assist
vehicles
in
achieving
precise
control
of
the
A/
F
ratio
and
thereby
enhance
the
overall
emissions
performance
of
the
engine.
At
least
one
manufacturer
is
currently
using
this
technology
on
several
2001
engine
families.
In
order
to
further
improve
fuel
control,
some
motorcycles
with
electronic
controls
may
utilize
software
algorithms
to
perform
individual
cylinder
fuel
control.
While
dual
oxygen
sensor
systems
are
capable
of
maintaining
A/
F
ratios
within
a
narrow
range,
some
manufacturers
may
desire
even
more
precise
control
to
meet
their
performance
needs.
On
typical
applications,
fuel
control
is
modified
whenever
the
O2S
determines
that
the
combined
A/
F
of
all
cylinders
in
the
engine
or
engine
bank
is
``
too
far''
from
stoichiometric.
The
needed
fuel
modifications
(i.
e.,
inject
more
or
less
fuel)
are
then
applied
to
all
cylinders
simultaneously.
Although
this
fuel
control
method
will
maintain
the
``
bulk''
A/
F
for
the
entire
engine
or
engine
bank
around
stoichiometric,
it
would
not
be
capable
of
correcting
for
individual
cylinder
A/
F
deviations
that
can
result
from
differences
in
manufacturing
tolerances,
wear
of
injectors,
or
other
factors.
With
individual
cylinder
fuel
control,
A/
F
variation
among
cylinders
will
be
diminished,
thereby
further
improving
the
effectiveness
of
the
emission
controls.
By
modeling
the
behavior
of
the
exhaust
gases
in
the
exhaust
manifold
and
using
software
algorithms
to
predict
individual
cylinder
A/
F,
a
feedback
fuel
control
system
for
individual
cylinders
can
be
developed.
Except
for
the
replacement
of
the
conventional
front
O2S
with
an
HO2S
sensor
and
a
more
powerful
engine
control
computer,
no
additional
hardware
is
needed
in
order
to
achieve
individual
cylinder
fuel
control.
Software
changes
and
the
use
of
mathematical
models
of
exhaust
gas
mixing
behavior
are
required
to
perform
this
operation.
In
order
to
maintain
good
driveability,
responsive
performance,
and
optimum
emission
control,
fluctuations
of
the
A/
F
must
remain
small
under
all
driving
conditions
including
transient
operation.
Virtually
all
current
fuel
systems
in
automobiles
incorporate
an
adaptive
fuel
control
system
that
automatically
adjusts
the
system
for
component
wear,
varying
environmental
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/
Wednesday,
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14,
2002
/
Proposed
Rules
conditions,
varying
fuel
composition,
etc.,
to
more
closely
maintain
proper
fuel
control
under
various
operating
conditions.
For
some
current
fuel
control
systems,
this
adaptation
process
affects
only
steady
state
operating
conditions
(i.
e.,
constant
or
slowly
changing
throttle
conditions).
However,
most
vehicles
are
now
being
introduced
with
adaptation
during
``
transient''
conditions
(e.
g.,
rapidly
changing
throttle,
purging
of
the
evaporative
system).
Accurate
fuel
control
during
transient
driving
conditions
has
traditionally
been
difficult
because
of
the
inaccuracies
in
predicting
the
air
and
fuel
flow
under
rapidly
changing
throttle
conditions.
Because
of
air
and
fuel
dynamics
(fuel
evaporation
in
the
intake
manifold
and
air
flow
behavior)
and
the
time
delay
between
the
air
flow
measurement
and
the
injection
of
the
calculated
fuel
mass,
temporarily
lean
A/
F
ratios
can
occur
during
transient
driving
conditions
that
can
cause
engine
hesitation,
poor
driveability
and
primarily
an
increase
in
NOX
emissions.
However,
by
utilizing
fuel
and
air
mass
modeling,
vehicles
with
adaptive
transient
fuel
control
are
more
capable
of
maintaining
accurate,
precise
fuel
control
under
all
operating
conditions.
Virtually
all
cars
will
incorporate
adaptive
transient
fuel
control
software;
motorcycles
with
computer
controlled
fuel
injection
can
also
benefit
from
this
technique
at
a
relatively
low
cost.
Three
way
catalytic
converters
traditionally
utilize
rhodium
and
platinum
as
the
catalytic
material
to
control
the
emissions
of
all
three
major
pollutants
(hydrocarbons
(HC),
CO,
NOX).
Although
this
type
of
catalyst
is
very
effective
at
converting
exhaust
pollutants,
rhodium,
which
is
primarily
used
to
convert
NOX,
tends
to
thermally
deteriorate
at
temperatures
significantly
lower
than
platinum.
Recent
advances
in
palladium
and
tri
metal
(i.
e.,
palladium
platinum
rhodium)
catalyst
technology,
however,
have
improved
both
the
light
off
performance
(light
off
is
defined
as
the
catalyst
bed
temperature
where
pollutant
conversion
reaches
50
percent
efficiency)
and
high
temperature
durability
over
previous
catalysts.
In
addition,
other
refinements
to
catalyst
technology,
such
as
higher
cell
density
substrates
and
adding
a
second
layer
of
catalyst
washcoat
to
the
substrate
(dual
layered
washcoats),
have
further
improved
catalyst
performance
from
just
a
few
years
ago.
Typical
cell
densities
for
conventional
catalysts
used
in
motorcycles
are
less
than
300
cells
per
square
inch
(cpsi).
To
meet
the
Tier
2
standard,
we
expect
manufacturers
to
use
catalysts
with
cell
densities
of
300
to
400
cpsi.
If
catalyst
volume
is
maintained
at
the
same
level
(we
assume
volumes
of
up
to
60
percent
of
engine
displacement),
using
a
higher
density
catalyst
effectively
increases
the
amount
of
surface
area
available
for
reacting
with
pollutants.
Catalyst
manufacturers
have
been
able
to
increase
cell
density
by
using
thinner
walls
between
each
cell
without
increasing
thermal
mass
(and
detrimentally
affecting
catalyst
light
off)
or
sacrificing
durability
and
performance.
In
addition
to
increasing
catalyst
volume
and
cell
density,
we
believe
that
increased
catalyst
loading
and
improved
catalyst
washcoats
will
help
manufacturers
meet
the
Tier
2
standard.
In
general,
increased
precious
metal
loading
(up
to
a
certain
point)
will
reduce
exhaust
emissions
because
it
increases
the
opportunities
for
pollutants
to
be
converted
to
harmless
constituents.
The
extent
to
which
precious
metal
loading
is
increased
will
be
dependent
on
the
precious
metals
used
and
other
catalyst
design
parameters.
We
believe
recent
developments
in
palladium/
rhodium
catalysts
are
very
promising
since
rhodium
is
very
efficient
at
converting
NOX,
and
catalyst
suppliers
have
been
investigating
methods
to
increase
the
amount
of
rhodium
in
catalysts
for
improved
NOX
conversion.
Double
layer
technologies
allow
optimization
of
each
individual
precious
metal
used
in
the
washcoat.
This
technology
can
provide
reduction
of
undesired
metal
metal
or
metal
base
oxide
interactions
while
allowing
desirable
interactions.
Industry
studies
have
shown
that
durability
and
pollutant
conversion
efficiencies
are
enhanced
with
double
layer
washcoats.
These
recent
improvements
in
catalysts
can
help
manufacturers
meet
the
Tier
2
standard
at
reduced
cost
relative
to
older
three
way
catalysts.
New
washcoat
formulations
are
now
thermally
stable
up
to
1050
°
C.
This
is
a
significant
improvement
from
conventional
washcoats,
which
are
stable
only
up
to
about
900
°
C.
With
the
improvements
in
light
off
capability,
catalysts
may
not
need
to
be
placed
as
close
to
the
engine
as
previously
thought.
However,
if
placement
closer
to
the
engine
is
required
for
better
emission
performance,
improved
catalysts
based
on
the
enhancements
described
above
would
be
more
capable
of
surviving
the
higher
temperature
environment
without
deteriorating.
The
improved
resistance
to
thermal
degradation
will
allow
closer
placement
to
the
engines
where
feasible,
thereby
providing
more
heat
to
the
catalyst
and
allowing
them
to
become
effective
quickly.
It
is
well
established
that
a
warmedup
catalyst
is
very
effective
at
converting
exhaust
pollutants.
Recent
tests
on
advanced
catalyst
systems
in
automobiles
have
shown
that
over
90
percent
of
emissions
during
the
Federal
Test
Procedure
(FTP)
are
now
emitted
during
the
first
two
minutes
of
testing
after
engine
start
up.
Similarly,
the
highest
emissions
from
a
motorcycle
occur
shortly
after
start
up.
Although
improvements
in
catalyst
technology
have
helped
reduce
catalyst
light
off
times,
there
are
several
methods
to
provide
additional
heat
to
the
catalyst.
Retarding
the
ignition
spark
timing
and
computer
controlled,
secondary
air
injection
have
been
shown
to
increase
the
heat
provided
to
the
catalyst,
thereby
improving
its
cold
start
effectiveness.
In
addition
to
using
computercontrolled
secondary
air
injection
and
retarded
spark
timing
to
increase
the
heat
provided
to
the
catalyst,
some
vehicles
may
employ
warm
up,
precatalysts
to
reduce
the
size
of
their
main
catalytic
converters.
Palladium
only
warm
up
catalysts
(also
known
as
``
pipe
catalysts''
or
``
Hot
Tubes'')
using
ceramic
or
metallic
substrates
may
be
added
to
further
decrease
warm
up
times
and
improve
emission
performance.
Although
metallic
substrates
are
usually
more
expensive
than
ceramic
substrates,
some
manufacturers
and
suppliers
believe
metallic
substrates
may
require
less
precious
metal
loading
than
ceramic
substrates
due
to
the
reduced
light
off
times
they
provide.
Improving
insulation
of
the
exhaust
system
is
another
method
of
furnishing
heat
to
the
catalyst.
Similar
to
closecoupled
catalysts,
the
principle
behind
insulating
the
exhaust
system
is
to
conserve
the
heat
generated
in
the
engine
for
aiding
catalyst
warm
up.
Through
the
use
of
laminated
thin
wall
exhaust
pipes,
less
heat
will
be
lost
in
the
exhaust
system,
enabling
quicker
catalyst
light
off.
As
an
added
benefit,
the
use
of
insulated
exhaust
pipes
will
also
reduce
exhaust
noise.
Increasing
numbers
of
manufacturers
are
expected
to
utilize
air
gap
exhaust
manifolds
(i.
e.,
manifolds
with
metal
inner
and
outer
walls
and
an
insulating
layer
of
air
sandwiched
between
them)
for
further
heat
conservation.
Besides
the
hardware
modifications
described
above,
motorcycle
manufacturers
may
borrow
from
other
current
automobile
techniques.
These
include
using
engine
calibration
changes
such
as
a
brief
period
of
substantial
ignition
retard,
increased
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Vol.
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No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
45
See
written
testimony
of
the
Manufacturers
of
Emission
Controls
Association
on
the
Proposed
Rulemaking
on
Control
of
Emissions
from
Nonroad
Large
Spark
Ignited
Engines
and
Recreational
Engines.
Available
in
the
public
docket
for
review
(Docket
AÐ
2000Ð
01;
document
IVÐ
DÐ
213).
cold
idling
speed,
and
leaner
air
fuel
mixtures
to
quickly
provide
heat
to
a
catalyst
after
cold
starts.
Only
software
modifications
are
required
for
an
engine
which
already
uses
a
computer
to
control
the
fuel
delivery
and
other
engine
systems.
For
these
engines,
calibration
modifications
provide
manufacturers
with
an
inexpensive
method
to
quickly
achieve
light
off
of
catalytic
converters.
When
combined
with
pre
catalysts,
computer
controlled
secondary
air
injection,
and
the
other
heat
conservation
techniques
described
above,
engine
calibration
techniques
may
be
very
effective
at
providing
the
required
heat
to
the
catalyst
for
achieving
the
Tier
2
standard.
These
techniques
are
currently
in
use
on
most
low
emission
vehicle
(LEV)
automobiles
and
may
have
applications
in
on
road
motorcycles.
The
nature
of
motorcycling
makes
riders
particularly
aware
of
the
many
safety
issues
that
confront
them.
Many
riders
that
submitted
comments
to
us
following
the
publication
of
the
ANPRM
in
December
of
2000
questioned
whether
catalytic
converters
could
be
implemented
on
motorcycles
without
increasing
the
risk
of
harm
to
the
rider
and/
or
passenger.
The
primary
concern
is
regarding
the
close
proximity
of
the
riders
to
hot
exhaust
pipes
and
the
catalytic
converter.
Protecting
the
rider
from
the
excessive
heat
is
a
concern
for
both
riders
and
manufacturers.
The
current
use
of
catalytic
converters
on
a
number
of
motorcycles
(accounting
for
tens
of
thousands
of
motorcycles
in
the
current
U.
S.
fleet
and
over
15
million
worldwide)
already
indicates
that
these
issues
are
not
insurmountable
on
a
variety
of
motorcycle
styles
and
engine
sizes.
Countries
that
have
successfully
implemented
catalyst
based
emission
control
programs
for
motorcycles
(some
of
which
have
many
years
of
experience)
do
not
report
any
safety
issues
associated
with
the
use
of
catalytic
converters
on
motorcycles
under
real
world
conditions.
45
A
number
of
approaches
to
shielding
the
rider
from
the
heat
of
the
catalytic
converter
are
possible,
such
as
exterior
pipe
covers,
shielded
foot
rests,
and
similar
components.
Some
manufacturers
have
found
that
placing
the
converter
on
the
underside
of
the
engine
can
keep
it
adequately
distant
from
the
rider.
Others
may
use
doublepipe
systems
that
reduce
overall
heat
loss
while
remaining
cooler
on
the
exterior.
Based
on
the
significant
lead
time
proposed
that
would
be
allowed
for
meeting
these
standards,
as
well
as
on
the
two
years
of
prior
experience
in
California
before
meeting
the
requirements
federally,
we
believe
that
these
issues
can
be
satisfactorily
resolved
for
the
proportion
of
motorcycles
for
which
catalytic
converters
would
likely
be
used
to
meet
the
proposed
standards.
We
do
not
expect
any
of
these
possible
changes
to
adversely
affect
performance.
Indeed,
the
transition
to
some
of
these
technologies
(e.
g.,
advanced
fuel
injection)
would
be
expected
to
improve
performance,
fuel
economy,
and
reliability.
A
direct
comparison
of
several
motorcycle
models
in
the
EPA
certification
database
between
the
``
California''
model
(where
one
is
offered;
it
is
the
exception
rather
than
the
rule
that
a
manufacturer
offers
a
separate
engine
system
for
California)
and
the
model
sold
in
the
rest
of
the
U.
S.
reveals
no
change
in
the
performance
characteristics
in
the
database
(e.
g.,
rated
horsepower,
torque).
We
request
comment
on
the
impact
these
anticipated
changes
might
have
on
performance
related
factors.
VI.
Projected
Impacts
This
section
summarizes
the
projected
impacts
of
the
proposed
emission
standards.
The
anticipated
environmental
benefits
are
compared
with
the
projected
cost
of
the
program
for
an
assessment
of
the
cost
per
ton
of
reducing
emissions
for
this
proposal.
A.
Environmental
Impact
Diurnal
evaporative
emission
factors
from
marine
vessels
were
developed
using
established
equations
for
determining
evaporative
emission
factors
as
a
function
of
ambient
conditions
and
fuel
tank
size.
Permeation
emissions
were
developed
based
on
known
material
permeation
rates
as
a
function
of
surface
area
and
temperature.
Other
inputs
for
these
calculations
were
taken
from
the
latest
version
of
our
NONROAD
model.
Emission
estimates
for
highway
motorcycles
were
developed
using
information
on
the
emission
levels
of
current
motorcycles
and
updated
information
on
motorcycle
use
provided
by
the
motorcycle
industry.
A
more
detailed
description
of
the
methodology
used
for
projecting
inventories
and
projections
for
additional
years
can
be
found
in
the
Chapter
6
of
the
Draft
Regulatory
Support
Document.
We
request
comment
on
all
aspects
of
the
emission
inventory
analysis,
including
the
usage
rates
and
other
inputs
used
in
the
analysis.
Tables
V.
AÐ
1
and
V.
AÐ
2
contain
the
projected
emission
inventories
for
the
years
2010
and
2020,
respectively,
from
the
engines
and
vehicles
subject
to
this
proposal.
The
inventories
are
presented
for
the
base
case
which
assumes
no
change
from
current
conditions
(i.
e.,
without
the
proposed
standards
taking
effect)
and
assuming
the
proposed
standards
take
effect.
The
inventories
for
2010
and
2020
include
the
effect
of
growth.
The
percent
reductions
based
on
a
comparison
of
estimated
emission
inventories
with
and
without
the
proposed
emission
standards
are
also
presented.
TABLE
VI.
A–
1.—
2010
PROJECTED
EMISSIONS
INVENTORIES
[Thousand
short
tons]
Category
NOX
HC*
Base
case
With
proposed
standards
Percent
reduction
Base
case
With
proposed
standards
Percent
reduction
Marine
SI
Evap
................................................................
0
0
0
106
91
14
Highway
motorcycles
.......................................................
11
10
9
46
41
11
Total
......................................................................
11
10
9
152
132
13
*Evaporative
HC
for
marine
SI;
exhaust
HC
for
highway
motorcycles.
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Proposed
Rules
46
For
further
information
on
learning
curves,
see
previous
final
rules
for
Tier
2
highway
vehicles
(65
FR
6698,
February
10,
2000),
marine
diesel
engines
(64
FR
73300,
December
29,
1999),
nonroad
diesel
engines
(63
FR
56968,
October
23,
1998),
and
highway
diesel
engines
(62
FR
54694,
October
21,
1997).
TABLE
VI.
A–
2.—
2020
PROJECTED
EMISSIONS
INVENTORIES
[Thousand
short
tons]
Category
NOX
HC*
Base
case
With
proposed
standards
Percent
reductions
Base
case
With
proposed
standards
Percent
reduction
Marine
SI
Evap
................................................................
0
0
0
114
50
56
Highway
motorcycles
.......................................................
14
7
50
58
29
50
Total
......................................................................
14
7
50
172
79
53
*Evaporative
HC
for
marine
SI;
exhaust
HC
for
highway
motorcycles.
As
described
in
Section
II,
there
will
also
be
environmental
benefits
associated
with
reduced
haze
in
many
sensitive
areas.
Finally,
anticipated
reductions
in
hydrocarbon
emissions
will
correspond
with
reduced
emissions
of
the
toxic
air
emissions
referenced
in
Section
II.
In
2020,
the
projected
reduction
in
hydrocarbon
emissions
should
result
in
an
equivalent
percent
reduction
in
air
toxic
emissions.
B.
Economic
Impact
In
assessing
the
economic
impact
of
setting
emission
standards,
we
have
made
a
best
estimate
of
the
technologies
and
their
associated
costs
to
meet
the
proposed
standards.
In
making
our
estimates
we
have
relied
on
our
own
technology
assessment,
which
includes
information
supplied
by
individual
manufacturers
and
our
own
in
house
testing.
Estimated
costs
include
variable
costs
(for
hardware
and
assembly
time)
and
fixed
costs
(for
research
and
development,
retooling,
and
certification).
We
projected
that
manufacturers
will
recover
the
fixed
costs
over
the
first
five
years
of
production
and
used
an
amortization
rate
of
7
percent
in
our
analysis.
The
analysis
also
considers
total
operating
costs,
including
maintenance
and
fuel
consumption.
Cost
estimates
based
on
the
projected
technologies
represent
an
expected
change
in
the
cost
of
engines
as
they
begin
to
comply
with
new
emission
standards.
All
costs
are
presented
in
2001
dollars.
Full
details
of
our
cost
analysis
can
be
found
in
Chapter
5
of
the
Draft
Regulatory
Support
Document.
We
request
comment
on
this
cost
information.
Cost
estimates
based
on
the
current
projected
costs
for
our
estimated
technology
packages
represent
an
expected
incremental
cost
of
vehicles
in
the
near
term.
For
the
longer
term,
we
have
identified
factors
that
would
cause
cost
impacts
to
decrease
over
time.
First,
as
noted
above,
we
project
that
manufacturers
will
spread
their
fixed
costs
over
the
first
five
years
of
production.
After
the
fifth
year
of
production,
we
project
that
the
fixed
costs
would
be
retired
and
the
per
unit
costs
would
be
reduced
as
a
result.
For
highway
motorcycles
above
50cc,
the
analysis
also
incorporates
the
expectation
that
manufacturers
and
suppliers
will
apply
ongoing
research
and
manufacturing
innovation
to
making
emission
controls
more
effective
and
less
costly
over
time.
Research
in
the
costs
of
manufacturing
has
consistently
shown
that
as
manufacturers
gain
experience
in
production
and
use,
they
are
able
to
apply
innovations
to
simplify
machining
and
assembly
operations,
use
lower
cost
materials,
and
reduce
the
number
or
complexity
of
component
parts.
46
(see
the
Draft
Regulatory
Support
Document
for
additional
information).
The
cost
analysis
generally
incorporates
this
learning
effect
by
decreasing
estimated
variable
costs
by
20
percent
starting
in
the
third
year
of
production
and
an
additional
20
percent
starting
in
the
sixth
year
of
production.
Long
term
impacts
on
costs
are
expected
to
decrease
as
manufacturers
fully
amortize
their
fixed
costs
and
learn
to
optimize
their
designs
and
production
processes
to
meet
the
standards
more
efficiently.
The
learning
curve
has
not
been
applied
to
the
marine
evaporative
controls
or
the
motorcycles
under
50cc
because
we
expect
manufacturers
to
use
technologies
that
will
be
well
established
prior
to
the
start
of
the
program.
We
request
comment
on
the
methodology
used
to
incorporate
the
learning
curve
into
the
analysis.
Evaporative
emission
controls
for
boats
with
marine
SI
engines
have
an
average
projected
cost
of
about
$36
per
boat.
While
manufacturers
may
choose
from
a
wide
variety
of
technologies
to
meet
emission
standards,
we
base
these
cost
estimates
on
all
boats
using
limited
flow
orifices
for
diurnal
emission
control,
fluorination
for
fuel
tank
permeation
control
and
low
permeability
barrier
for
fuel
hose
permeation
control.
Under
the
proposed
emission
credit
program,
manufacturers
would
have
the
option
of
offering
different
technologies
to
meet
emission
standards.
Where
there
is
a
current
demand
for
more
sophisticated
fuel
tank
technology,
we
would
expect
a
greater
cost
impact
than
from
the
lower
cost,
high
production
models.
Emissions
are
reduced
by
preventing
evaporation
of
fuel,
so
these
controls
translate
directly
into
a
fuel
savings,
which
we
have
estimated
to
be
about
$27
per
boat
(net
present
value
at
the
point
of
sale).
Therefore,
we
get
an
average
cost
of
$9
per
boat
when
the
fuel
savings
are
considered.
We
project
average
costs
of
$26
per
Class
III
highway
motorcycle
to
meet
the
Tier
1
standard
and
$35
to
meet
the
Tier
2
standards.
We
anticipate
the
manufacturers
will
meet
the
proposed
emission
standards
with
several
technology
changes,
including
electronic
fuel
injection,
catalysts,
pulse
air
systems,
and
other
general
improvements
to
engines.
For
motorcycles
with
engines
of
less
than
50cc,
we
project
average
costs
of
$44
per
motorcycle
to
meet
the
proposed
standards.
We
anticipate
the
manufacturers
of
these
small
motorcycles
(mostly
scooters)
will
meet
the
proposed
emission
standards
by
transitioning
any
remaining
two
stroke
engines
to
four
strokes.
The
costs
are
based
on
the
conversion
to
4
stroke
because
we
believe
this
to
be
the
most
likely
technology
path
for
the
majority
of
scooters.
Manufacturers
could
also
choose
to
employ
advanced
technology
two
stroke
(e.
g.,
direct
injection
and/
or
catalysts)
designs.
The
process
of
developing
clean
technologies
is
very
much
underway
already
as
a
result
of
regulatory
actions
in
Europe
and
the
rest
of
world
where
the
primary
markets
for
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Proposed
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small
motorcycles
exist.
Chapter
4
of
the
Draft
Regulatory
Support
Document
describes
these
technologies
further.
Because
several
models
are
already
available
with
the
anticipated
long
term
emission
control
technologies,
we
believe
that
manufacturers
and
consumers
will
be
able
to
bear
the
added
cost
associated
with
the
new
emission
standards.
The
above
analysis
presents
unit
cost
estimates
for
each
engine
type.
These
costs
represent
the
total
set
of
costs
the
engine
manufacturers
will
bear
to
comply
with
emission
standards.
With
current
and
projected
estimates
of
engine
and
equipment
sales,
we
translate
these
costs
into
projected
direct
costs
to
the
nation
for
the
new
emission
standards
in
any
year.
A
summary
of
the
annualized
costs
to
manufacturers
by
equipment
type
is
presented
in
Table
VI.
BÐ
1.
(The
annualized
costs
are
determined
over
the
first
twenty
years
that
the
proposed
standards
would
be
effective.)
The
annual
cost
savings
for
marine
vessels
and
highway
motorcycles
(<
50cc
only)
are
due
to
reduced
fuel
costs.
The
total
fleetwide
fuel
savings
start
slowly,
then
increase
as
greater
numbers
of
compliant
vessels
or
motorcycles
(<
50cc
only)
enter
the
fleet.
Table
VI.
BÐ
1
presents
a
summary
of
the
annualized
reduced
operating
costs
as
well.
TABLE
VI.
B–
1.—
ESTIMATED
ANNUAL
COST
TO
MANUFACTURERS
AND
ANNUAL
FUEL
SAVINGS
DUE
TO
THE
PROPOSED
STANDARDS
[Millions/
year]
Category
Annualized
cost
to
manufacturers
Annual
fuel
savings
Marine
SI
Evap
.......
$27.5
$15.6
Highway
Motorcycles
..................
18.8
0.2
Aggregate*
..............
42.0
13.3
*
Because
of
the
different
proposed
implementation
dates
for
the
two
classes,
the
aggregate
is
based
on
a
22
year
(rather
than
20
year)
annualized
cost.
Therefore,
the
aggregate
is
not
equal
to
the
sum
of
the
costs
for
the
two
engine
types.
C.
Cost
per
Ton
of
Emissions
Reduced
We
calculated
the
cost
per
ton
of
emission
reductions
for
the
proposed
standards.
For
these
calculations,
we
attributed
the
entire
cost
of
the
proposed
program
to
the
control
of
ozone
precursor
emissions
(HC
or
NOX
or
both).
Table
VI.
CÐ
1
presents
the
discounted
cost
per
ton
estimates
for
this
proposal.
Reduced
operating
costs
offsets
a
portion
of
the
increased
cost
of
producing
the
cleaner
marine
vessels
and
highway
motorcycles
(<
50cc
only).
TABLE
VI.
C–
1.—
ESTIMATED
COST
PER
TON
OF
THE
PROPOSED
EMISSION
STANDARDS
Category
Effective
date
Discounted
reductions
per
engine
(short
tons)
Pollutants
Discounted
cost
per
ton
Without
fuel
savings
With
fuel
savings
Marine
SI:
Diurnal
..........................................................................
2008
0.01
Evaporative
HC
..................
$745
$382
Tank
permeation
..........................................................
0.02
523
160
Hose
permeation
.........................................................
0.04
367
4
Aggregate
....................................................................
0.07
478
115
Highway
motorcycles
>50cc
...............................................
2006
0.03
Exhaust
HC+
NOX
...............
970
970
Highway
motorcycles
>50cc
...............................................
2010
0.03
Exhaust
HC+
NOX
...............
1,230
1,230
Highway
motorcycles
>50cc
...............................................
2006
0.02
Exhaust
HC
........................
2,130
1,750
Because
the
primary
purpose
of
costeffectiveness
is
to
compare
our
program
to
alternative
programs,
we
made
a
comparison
between
the
cost
per
ton
values
presented
in
this
chapter
and
the
cost
effectiveness
of
other
programs.
Table
VI.
CÐ
2
summarizes
the
cost
effectiveness
of
several
recent
EPA
actions
for
controlled
emissions
from
mobile
sources.
Additional
discussion
of
these
comparisons
is
contained
in
the
Regulatory
Impact
Analysis.
TABLE
VI.
C–
2—
COST
EFFECTIVENESS
OF
PREVIOUSLY
IMPLEMENTED
MOBILE
SOURCE
PROGRAMS
[Costs
adjusted
to
2001
dollars]
Program
$/
ton
Tier
2
vehicle/
gasoline
sulfur
1,437–
2,423
2007
Highway
HD
diesel
......
1,563–
2,002
2004
Highway
HD
diesel
......
227–
444
Off
highway
diesel
engine
....
456–
724
TABLE
VI.
C–
2—
COST
EFFECTIVENESS
OF
PREVIOUSLY
IMPLEMENTED
MOBILE
SOURCE
PROGRAMS—
Continued
[Costs
adjusted
to
2001
dollars]
Program
$/
ton
Tier
1
vehicle
........................
2,202–
2,993
NLEV
....................................
2,069
Marine
SI
engines
................
1,255–
1,979
On
board
diagnostics
...........
2,480
Marine
CI
engines
................
26–
189
D.
Additional
Benefits
For
the
marine
evaporative
emission
standards,
we
expect
there
will
be
a
fuel
savings
as
manufacturers
redesign
their
vessels
to
comply
with
the
proposed
standards.
This
savings
is
the
result
of
preventing
fuel
from
evaporating
into
the
atmosphere.
Overall,
the
fuel
savings
associated
with
the
anticipated
changes
in
technology
are
estimated
to
be
about
31
million
gallons
per
year
once
the
program
is
fully
phased
in.
For
the
motorcycle
emission
standards,
we
expect
there
will
be
a
fuel
savings
as
manufacturers
redesign
their
engines
to
comply
with
the
proposed
standards.
This
savings
is
the
result
of
converting
motorcycles
<50cc
from
2
stroke
designs
to
more
fuel
efficient
4
stroke
designs.
Overall,
the
fuel
savings
associated
with
the
anticipated
changes
in
technology
are
estimated
to
be
about
0.3
million
gallons
per
year
once
the
program
is
fully
phased
in.
The
controls
in
this
rule
are
a
highly
cost
effective
means
of
obtaining
reductions
in
HC
and
NOX
emissions.
A
related
subject
concerns
the
value
of
the
health
and
welfare
benefits
these
reductions
might
produce.
While
we
have
not
conducted
a
formal
benefitcost
analysis
for
this
rule,
we
believe
the
benefits
of
this
rule
clearly
will
greatly
outweigh
any
cost.
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Vol.
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157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
Ozone
causes
a
range
of
health
problems
related
to
breathing,
including
chest
pain,
coughing,
and
shortness
of
breath
Exposure
to
PM
(including
secondary
PM
formed
in
the
atmosphere
from
NOX
and
NMHC
emissions)
is
associated
with
premature
death,
increased
emergency
room
visits,
and
increased
respiratory
symptoms
and
disease
Children,
the
elderly,
and
individuals
with
pre
existing
respiratory
conditions
are
most
at
risk
regarding
both
ozone
and
PM.
In
addition,
ozone,
NOX,
and
PM
adversely
affect
the
environment
in
various
ways,
including
crop
damage,
acid
rain,
and
visibility
impairment.
In
two
recent
mobile
source
control
rules,
for
light
duty
vehicles
(the
Tier
2/
Gasoline
Sulfur
rule)
and
for
highway
heavy
duty
engines
and
diesel
fuel,
we
conducted
a
full
analysis
of
the
expected
benefits
once
the
rules
were
fully
implemented.
These
rules,
which
primarily
reduced
NOX
and
NMHC
emissions,
were
seen
to
yield
health
and
welfare
benefits
far
exceeding
the
costs.
Besides
reducing
premature
mortality,
there
were
large
projected
reductions
in
chronic
bronchitis
cases,
hospital
admissions
for
respiratory
and
cardiovascular
causes,
asthma
attacks
and
other
respiratory
symptoms,
and
a
variety
of
other
effects.
Given
the
similarities
in
pollutants
being
controlled,
we
would
expect
this
rule
to
produce
substantial
benefits
compared
to
its
cost.
VII.
Public
Participation
This
rule
was
proposed
under
the
authority
of
section
307(
d)
of
the
Clean
Air
Act.
We
request
comment
on
all
aspects
of
this
proposal.
This
section
describes
how
you
can
participate
in
this
process.
A.
How
Do
I
Submit
Comments?
We
are
opening
a
formal
comment
period
by
publishing
this
document.
We
will
accept
comments
for
the
period
indicated
under
DATES
above.
If
you
have
an
interest
in
the
program
described
in
this
document,
we
encourage
you
to
comment
on
any
aspect
of
this
rulemaking.
We
request
comment
on
various
topics
throughout
this
proposal.
We
attempted
to
incorporate
all
the
comments
received
in
response
to
the
Advance
Notice
of
Proposed
Rulemaking,
though
not
all
comments
are
addressed
directly
in
this
document.
Anyone
who
has
submitted
comments
on
the
Advance
Notice,
or
any
previous
publications
related
to
this
proposal,
and
feels
that
those
comments
have
not
been
adequately
addressed
is
encouraged
to
resubmit
comments
as
appropriate.
Your
comments
will
be
most
useful
if
you
include
appropriate
and
detailed
supporting
rationale,
data,
and
analysis.
If
you
disagree
with
parts
of
the
proposed
program,
we
encourage
you
to
suggest
and
analyze
alternate
approaches
to
meeting
the
air
quality
goals
described
in
this
proposal.
You
should
send
all
comments,
except
those
containing
proprietary
information,
to
our
Air
Docket
(see
ADDRESSES)
before
the
end
of
the
comment
period.
If
you
submit
proprietary
information
for
our
consideration,
you
should
clearly
separate
it
from
other
comments
by
labeling
it
``
Confidential
Business
Information.
''
You
should
also
send
it
directly
to
the
contact
person
listed
under
FOR
FURTHER
INFORMATION
CONTACT
instead
of
the
public
docket.
This
will
help
ensure
that
no
one
inadvertently
places
proprietary
information
in
the
docket.
If
you
want
us
to
use
your
confidential
information
as
part
of
the
basis
for
the
final
rule,
you
should
send
a
nonconfidential
version
of
the
document
summarizing
the
key
data
or
information.
We
will
disclose
information
covered
by
a
claim
of
confidentiality
only
through
the
application
of
procedures
described
in
40
CFR
part
2.
If
you
don't
identify
information
as
confidential
when
we
receive
it,
we
may
make
it
available
to
the
public
without
notifying
you.
B.
Will
There
Be
a
Public
Hearing?
We
will
hold
a
public
hearing
for
issues
related
to
highway
motorcycles
on
July
16
in
Dulles,
VA.
We
will
hold
a
public
hearing
for
issues
related
to
marine
vessels
on
July
18
in
Ann
Arbor,
MI.
The
hearings
will
start
at
9:
30
a.
m.
and
continue
until
testimony
is
complete.
See
ADDRESSES
above
for
location
and
phone
information.
If
you
would
like
to
present
testimony
at
a
public
hearing,
we
ask
that
you
notify
the
contact
person
listed
above
at
least
ten
days
before
the
hearing.
You
should
estimate
the
time
you
need
for
your
presentation
and
identify
any
needed
audio/
visual
equipment.
We
suggest
that
you
bring
copies
of
your
statement
or
other
material
for
the
EPA
panel
and
the
audience.
It
would
also
be
helpful
if
you
send
us
a
copy
of
your
statement
or
other
materials
before
the
hearing.
We
will
make
a
tentative
schedule
for
the
order
of
testimony
based
on
the
notification
we
receive.
This
schedule
will
be
available
on
the
morning
of
each
hearing.
In
addition,
we
will
reserve
a
block
of
time
for
anyone
else
in
the
audience
who
wants
to
give
testimony.
We
will
conduct
the
hearing
informally,
and
technical
rules
of
evidence
won't
apply.
We
will
arrange
for
a
written
transcript
of
the
hearing
and
keep
the
official
record
of
the
hearing
open
for
30
days
to
allow
you
to
submit
supplementary
information.
You
may
make
arrangements
for
copies
of
the
transcript
directly
with
the
court
reporter.
VII.
Administrative
Requirements
A.
Administrative
Designation
and
Regulatory
Analysis
(Executive
Order
12866)
Under
Executive
Order
12866
(58
FR
51735,
October
4,
1993),
the
Agency
must
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
Office
of
Management
and
Budget
(OMB)
and
the
requirements
of
this
Executive
Order.
The
Executive
Order
defines
a
``
significant
regulatory
action''
as
any
regulatory
action
that
is
likely
to
result
in
a
rule
that
may:
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;
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligations
of
recipients
thereof;
or
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
A
Draft
Regulatory
Support
Document
has
been
prepared
and
is
available
in
the
docket
for
this
rulemaking
and
at
the
internet
address
listed
under
ADDRESSES
above.
Pursuant
to
the
terms
of
Executive
Order
12866,
OMB
has
notified
EPA
that
it
considers
this
a
``
significant
regulatory
action''
within
the
meaning
of
the
Executive
Order.
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.
B.
Regulatory
Flexibility
Act
1.
Overview
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
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Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
47
``
Nonroad
Engine
and
Vehicle
Emission
StudyÑ
Report
and
Appendices,
''
EPAÐ
21AÐ
201,
November
1991
(available
in
Air
docket
AÐ
91Ð
24).
It
is
also
available
through
the
National
Technical
Information
Service,
referenced
as
document
PB
92Ð
126960.
48
59
FR
31306
(July
17,
1994).
49
See
Final
Finding,
``
Control
of
Emissions
from
New
Nonroad
Spark
Ignition
Engines
Rated
above
19
Kilowatts
and
New
Land
Based
Recreational
Spark
Ignition
Engines''
for
EPA's
finding
for
Large
SI
engines
and
recreational
vehicles
(65
FR
76790,
December
7,
2000).
EPA's
findings
for
marine
engines
are
contained
in
61
FR
52088
(October
4,
1996)
for
gasoline
engines
and
64
FR
73299
(December
29,
1999)
for
diesel
engines.
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
this
action
on
small
entities,
small
entity
is
defined
as:
(1)
A
small
business
that
meet
the
definition
for
business
based
on
SBA
size
standards;
(2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(3)
a
small
organization
that
is
any
not
forprofit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
The
following
table
provides
an
overview
of
the
primary
SBA
small
business
categories
potentially
affected
by
this
regulation.
TABLE
VIII.
B–
1.—
PRIMARY
SBA
SMALL
BUSINESS
CATEGORIES
POTENTIALLY
AFFECTED
BY
THIS
PROPOSED
REGULATION
Industry
NAICS
1
codes
Defined
by
SBA
as
a
small
business
If:
2
Motorcycles
and
motorcycle
parts
manufacturers
..............................................................................
336991
<500
employees.
Independent
Commercial
Importers
of
Vehicles
and
parts
................................................................
421110
<100
employees.
Boat
Building
and
Repairing
...............................................................................................................
336612
<
500
employees.
Fuel
Tank
Manufacturers
....................................................................................................................
336211
<1000
employees.
1
North
American
Industry
Classification
System.
2
According
to
SBA's
regulations
(13
CFR
part
121),
businesses
with
no
more
than
the
listed
number
of
employees
or
dollars
in
annual
receipts
are
considered
``
small
entities''
for
purposes
of
a
regulatory
flexibility
analysis.
2.
Background
In
accordance
with
Section
603
of
the
RFA,
EPA
prepared
an
initial
regulatory
flexibility
analysis
(IRFA)
that
examines
the
impact
of
the
proposed
rule
on
small
entities
along
with
regulatory
alternatives
that
could
reduce
that
impact.
In
preparing
this
IRFA,
we
looked
at
both
the
effect
of
this
proposal
and
the
October
5,
2001
proposal
for
other
nonroad
categories
(66
FR
51098).
The
IRFA
is
available
for
review
in
the
docket
and
is
summarized
below.
The
process
of
establishing
standards
for
nonroad
engines
began
in
1991
with
a
study
to
determine
whether
emissions
of
carbon
monoxide
(CO),
oxides
of
nitrogen
(NOX),
and
volatile
organic
compounds
(VOCs)
from
new
and
existing
nonroad
engines,
equipment,
and
vehicles
are
significant
contributors
to
ozone
and
CO
concentrations
in
more
than
one
area
that
has
failed
to
attain
the
national
ambient
air
quality
standards
for
ozone
and
CO.
47
In
1994,
EPA
finalized
its
finding
that
nonroad
engines
as
a
whole
``
are
significant
contributors
to
ozone
or
carbon
monoxide
concentrations''
in
more
than
one
ozone
or
carbon
monoxide
nonattainment
area.
48
Upon
this
finding,
the
Clean
Air
Act
(CAA
or
the
Act)
requires
EPA
to
establish
standards
for
all
classes
or
categories
of
new
nonroad
engines
that
cause
or
contribute
to
air
quality
nonattainment
in
more
than
one
ozone
or
carbon
monoxide
(CO)
nonattainment
area.
Since
the
finding
in
1994,
EPA
has
been
engaged
in
the
process
of
establishing
programs
to
control
emissions
from
nonroad
engines
used
in
many
different
applications.
Nonroad
categories
already
regulated
include:
Land
based
compression
ignition
(CI)
engines
(e.
g.,
farm
and
construction
equipment),
Small
land
based
spark
ignition
(SI)
engines
(e.
g.,
lawn
and
garden
equipment,
string
trimmers),
Marine
engines
(outboards,
personal
watercraft,
CI
commercial,
CI
engines
<37kW),
and
Locomotive
engines.
On
December
7,
2000,
EPA
issued
an
Advance
Notice
of
Proposed
Rulemaking
(ANPRM)
for
the
control
of
emissions
from
nonroad
large
SI
engines,
recreational
vehicles
(marine
and
land
based),
and
highway
motorcycles.
As
discussed
in
the
ANPRM,
the
proposal
under
development
will
be
a
continuation
of
the
process
of
establishing
standards
for
nonroad
engines
and
vehicles,
as
required
by
CAA
section
213(
a)(
3).
If,
as
expected,
standards
for
these
engines
and
vehicles
are
established,
essentially
all
new
nonroad
engines
will
be
required
to
meet
emissions
control
requirements.
This
proposal
is
the
second
part
of
an
effort
to
control
emissions
from
nonroad
engines
that
are
currently
unregulated
and
for
updating
Federal
emissions
standards
for
highway
motorcycles.
The
first
part
of
this
effort
was
a
proposal
published
on
October
5,
2001
for
emission
control
from
large
sparkignition
engines
such
as
those
used
in
forklifts
and
airport
tugs;
recreational
vehicles
using
spark
ignition
engines
such
as
off
highway
motorcycles,
allterrain
vehicles,
and
snowmobiles;
and
recreational
marine
diesel
engines.
EPA
found
that
the
nonroad
engines
described
above
cause
or
contribute
to
air
quality
nonattainment
in
more
than
one
ozone
or
carbon
monoxide
(CO)
nonattainment
area.
49
CAA
section
213
(a)(
3)
requires
EPA
to
establish
standards
that
achieve
the
greatest
degree
of
emissions
reductions
achievable
taking
cost
and
other
factors
into
account.
EPA
plans
to
propose
emissions
standards
and
related
programs
consistent
with
the
requirements
of
the
Act.
In
addition
to
proposing
standards
for
the
nonroad
vehicles
and
engines
noted
above,
this
proposal
reviews
EPA
requirements
for
highway
motorcycles.
The
emissions
standards
for
highway
motorcycles
were
established
twentythree
years
ago.
These
standards
allow
motorcycles
to
emit
about
100
times
as
much
per
mile
as
new
cars
and
light
trucks.
California
recently
adopted
new
emissions
standards
for
highway
motorcycles,
and
new
standards
and
testing
cycles
are
being
considered
internationally.
There
may
be
opportunities
to
reduce
emissions
in
a
cost
effective
way.
The
program
under
consideration
will
cover
engines
and
vehicles
that
vary
in
design
and
use,
and
many
readers
may
only
be
interested
in
one
or
two
of
the
applications.
There
are
various
ways
EPA
could
group
the
engines
and
present
information.
For
purposes
of
the
proposed
rule
EPA
has
chosen
to
group
engines
by
common
applications
(e.
g,
recreational
land
based
engines,
marine
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/
Wednesday,
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14,
2002
/
Proposed
Rules
engines,
large
spark
ignition
engines
used
in
commercial
applications).
3.
Summary
of
Regulated
Small
Entities
The
small
entities
directly
regulated
by
this
proposed
rule
are
the
following:
a.
Highway
Motorcycles.
Of
the
numerous
manufacturers
supplying
the
U.
S.
market
for
highway
motorcycles,
Honda,
Harley
Davidson,
Yamaha,
Kawasaki,
Suzuki,
and
BMW
are
the
largest,
accounting
for
95
percent
or
more
of
the
total
U.
S.
sales.
All
of
these
companies
except
Harley
Davidson
and
BMW
also
manufacture
off
road
motorcycles
and
ATVs
for
the
U.
S.
market.
Harley
Davidson
is
the
only
company
manufacturing
highway
motorcycles
exclusively
in
the
U.
S.
for
the
U.
S.
market.
Since
highway
motorcycles
have
had
to
meet
emission
standards
for
the
last
twenty
years,
EPA
has
good
information
on
the
number
of
companies
that
manufacture
or
market
highway
motorcycles
for
the
U.
S.
market
in
each
model
year.
In
addition
to
the
big
six
manufacturers
noted
above,
EPA
finds
as
many
as
several
dozen
more
companies
that
have
operated
in
the
U.
S.
market
in
the
last
couple
of
model
years.
Most
of
these
are
U.
S.
companies
that
are
either
manufacturing
or
importing
motorcycles,
although
a
few
are
U.
S.
affiliates
of
larger
companies
in
Europe
or
Asia.
Some
of
the
U.
S.
manufacturers
employ
only
a
few
people
and
produce
only
a
handful
of
custom
motorcycles
per
year,
while
others
may
employ
several
hundred
and
produce
up
to
several
thousand
motorcycles
per
year.
The
proposed
emission
standards
impose
no
new
development
or
certification
costs
for
any
company
producing
compliant
engines
in
California.
If
fact,
implementing
the
California
standards
with
a
two
year
delay
also
allows
manufacturers
to
streamline
their
production
to
further
reduce
the
cost
of
compliance.
The
estimated
hardware
costs
are
less
than
one
percent
of
the
cost
of
producing
a
highway
motorcycle,
so
none
of
these
companies
should
have
a
compliance
burden
greater
than
one
percent
of
revenues.
We
expect
that
a
small
number
of
companies
affected
by
EPA
emission
standards
will
not
already
be
certifying
products
in
California.
For
these
companies,
the
modest
effort
associated
with
applying
established
technology
will
add
compliance
costs
representing
between
1
and
3
percent
of
revenues.
The
flexible
approach
we
are
proposing
to
limit
testing,
reporting,
and
recordkeeping
burden
prevent
excessive
costs
for
all
these
companies.
b.
Marine
Vessels.
Marine
vessels
include
the
boat,
engine,
and
fuel
system.
The
evaporative
emission
controls
discussed
above
may
affect
the
boat
builders
and/
or
the
fuel
tank
manufacturers.
Exhaust
emission
controls
including
NTE
requirements,
as
addressed
in
the
August
29,
1999
SBAR
Panel
Report,
would
affect
the
engine
manufacturers
and
may
affect
boat
builders.
EPA
has
less
precise
information
about
recreational
boat
builders
than
is
available
about
engine
manufacturers.
EPA
has
utilized
several
sources,
including
trade
associations
and
Internet
sites
when
identifying
entities
that
build
and/
or
sell
recreational
boats.
EPA
has
also
worked
with
an
independent
contractor
to
assist
in
the
characterization
of
this
segment
of
the
industry.
Finally,
EPA
has
obtained
a
list
of
nearly
1,700
boat
builders
known
to
the
U.
S.
Coast
Guard
to
produce
boats
using
engines
for
propulsion.
At
least
1,200
of
these
companies
install
engines
that
use
gasoline
fueled
engines
and
would
therefore
be
subject
to
the
evaporative
emission
control
program
discussed
above.
More
than
90%
of
the
companies
identified
so
far
would
be
considered
small
businesses
as
defined
by
SBA.
EPA
continues
to
develop
a
more
complete
picture
of
this
segment
of
the
industry
and
will
provide
additional
information
as
it
becomes
available.
Based
on
information
supplied
by
a
variety
of
recreational
boat
builders,
fuel
tanks
for
boats
using
SI
marine
engines
are
usually
purchased
from
fuel
tank
manufacturers.
However,
some
boat
builders
construct
their
own
fuel
tanks.
The
boat
builder
provides
the
specifications
to
the
fuel
tank
manufacturer
who
helps
match
the
fuel
tank
for
a
particular
application.
It
is
the
boat
builder's
responsibility
to
install
the
fuel
tank
and
connections
into
their
vessel
design.
For
vessels
designed
to
be
used
with
small
outboard
engines,
the
boat
builder
may
not
install
a
fuel
tank;
therefore,
the
end
user
would
use
a
portable
fuel
tank
with
a
connection
to
the
engine.
EPA
has
determined
that
total
sales
of
tanks
for
gasoline
marine
applications
is
approximately
550,000
units
per
year.
The
market
is
broken
into
manufacturers
that
produce
plastic
tanks
and
manufacturers
that
produce
aluminum
tanks.
EPA
has
determined
that
there
are
at
least
seven
companies
that
make
plastic
fuel
tanks
with
total
sales
of
approximately
440,000
units
per
year.
EPA
has
determined
that
there
at
least
four
companies
that
make
aluminum
fuel
tanks
with
total
sales
of
approximately
110,000
units
per
year.
All
but
one
of
these
plastic
and
aluminum
fuel
tank
manufacturers
is
a
small
business
as
defined
under
SBA.
EPA
has
determined
that
there
are
at
least
16
companies
that
manufacture
CI
diesel
engines
for
recreational
vessels.
Nearly
75
percent
of
diesel
engines
sales
for
recreational
vessels
in
2000
can
be
attributed
to
three
large
companies.
Six
of
the
16
identified
companies
are
considered
small
businesses
as
defined
by
SBA.
Based
on
sales
estimates
for
2000,
these
six
companies
represent
approximately
4
percent
of
recreational
marine
diesel
engine
sales.
The
remaining
companies
each
comprise
between
two
and
seven
percent
of
sales
for
2000.
EPA
has
determined
that
there
are
at
least
24
companies
that
manufacture
SD/
I
gasoline
engines
(including
airboats
and
jet
boats)
for
recreational
vessels.
Seventeen
of
the
identified
companies
are
considered
small
businesses
as
defined
by
SBA.
These
17
companies
represent
approximately
6
percent
of
recreational
gasoline
marine
engines
sales
for
2000.
Approximately
70Ð
80
percent
of
gasoline
SD/
I
engines
manufactured
in
2000
can
be
attributed
to
one
company.
The
next
largest
company
is
responsible
for
about
10Ð
20
percent
of
2000
sales.
For
any
boat
builders
that
would
certify
to
the
proposed
requirements,
the
costs
of
compliance
would
be
much
less
than
one
percent
of
their
revenues.
Incremental
costs
of
fuel
tanks
are
dwarfed
by
the
capital
and
variable
costs
associated
with
manufacturing
power
boats.
Of
the
six
known
small
businesses
producing
plastic
fuel
tanks
for
gasoline
powered
marine
vessels,
these
companies
would
have
costs
approaching
10
percent
of
revenues.
While
this
is
a
large
percentage,
it
comes
predominantly
from
increasing
variable
costs
to
upgrade
the
fuel
tanks.
Capital
expenses
to
upgrade
to
compliant
products
are
relatively
small.
Also,
to
the
extent
that
tank
manufacturers
certify
their
products,
they
will
be
increasing
the
value
of
their
product
for
their
customers,
who
would
otherwise
need
to
assume
certification
responsibilities.
As
a
result,
we
believe
that
these
companies
will
be
able
to
largely
recover
their
compliance
costs
over
time.
The
net
cost
absorbed
by
tank
manufacturers
will
be
much
less
than
one
percent.
For
this
proposal
as
a
whole,
there
are
hundreds
of
small
businesses
that
will
have
total
compliance
costs
less
than
1
percent
of
their
annual
revenues.
We
estimate
that
three
companies
will
have
compliance
costs
between
1
and
3
percent
of
revenues
and
six
companies
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/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
will
have
compliance
costs
exceeding
3
percent
of
revenues.
4.
Potential
Reporting,
Recordkeeping,
and
Compliance
For
any
emission
control
program,
EPA
must
have
assurances
that
the
regulated
engines
will
meet
the
standards.
Historically,
EPA
programs
have
included
provisions
placing
manufacturers
responsible
for
providing
these
assurances.
The
program
that
EPA
is
considering
for
manufacturers
subject
to
this
proposal
may
include
testing,
reporting,
and
record
keeping
requirements.
Testing
requirements
for
some
manufacturers
may
include
certification
(including
deterioration
testing),
and
production
line
testing.
Reporting
requirements
would
likely
include
test
data
and
technical
data
on
the
engines
including
defect
reporting.
Manufacturers
would
likely
have
to
keep
records
of
this
information.
5.
Related
Federal
Rules
The
Panel
is
aware
of
several
other
current
Federal
rules
that
relate
to
the
proposed
rule
under
development.
During
the
Panel's
outreach
meeting,
SERs
specifically
pointed
to
Consumer
Product
Safety
Commission
(CPSC)
regulations
covering
ATVs,
and
noted
that
they
may
be
relevant
to
crafting
an
appropriate
definition
for
a
competition
exclusion
in
this
category.
The
Panel
recommends
that
EPA
continue
to
consult
with
the
CPSC
in
developing
a
proposed
and
final
rule
in
order
to
better
understand
the
scope
of
the
Commission's
regulations
as
they
may
relate
to
the
competition
exclusion.
Other
SERs,
representing
manufacturers
of
marine
engines,
noted
that
the
U.
S.
Coast
Guard
regulates
vessel
tanks,
most
notably
tank
pressure
and
anti
siphoning
requirements
for
carburetted
engines.
Tank
manufacturers
would
have
to
take
these
requirements
into
account
in
designing
evaporative
control
systems.
The
Panel
recommends
that
EPA
continue
to
work
with
the
Coast
Guard
to
evaluate
the
safety
implications
of
any
proposed
evaporative
emissions
standards
and
to
avoid
interference
with
Coast
Guard
safety
regulations.
The
Panel
is
also
aware
of
other
Federal
rules
that
relate
to
the
categories
that
EPA
would
address
with
the
proposed
rule,
but
are
not
likely
to
affect
policy
considerations
in
the
rule
development
process.
For
example,
there
are
now
EPA
noise
standards
covering
off
road
motorcycles;
however,
EPA
expects
that
most
emission
control
devices
are
likely
to
reduce,
rather
than
increase,
noise,
and
that
therefore
the
noise
standards
are
not
likely
to
be
important
in
developing
a
proposed
rule.
OTAQ
is
currently
developing
a
proposal
that
would
revise
the
rule
assigning
fees
to
be
paid
by
parties
required
to
certify
engines
in
return
for
continuing
Government
oversight
and
testing.
Among
other
options,
EPA
could
propose
to
extend
the
fee
structure
to
several
classes
of
non
road
engines
for
which
requirements
are
being
established
for
the
first
time
under
the
Recreation
Rule.
The
Panel
understands
that
EPA
will
carefully
examine
the
potential
impacts
of
the
Fees
Rule
on
small
businesses.
The
Panel
also
notes
that
EPA's
Office
of
Air
Quality,
Planning,
and
Standards
(OAQPS)
is
preparing
a
Maximum
Achievable
Control
Technology
(MACT)
standard
for
Engine
Testing
Facilities,
which
is
a
related
matter.
6.
Significant
Panel
Findings
The
Panel
considered
a
wide
range
of
options
and
regulatory
alternatives
for
providing
small
businesses
with
flexibility
in
complying
with
the
proposed
emissions
standards
and
related
requirements.
As
part
of
the
process,
the
Panel
requested
and
received
comment
on
several
ideas
for
flexibility
that
were
suggested
by
SERs
and
Panel
members.
The
major
options
recommended
by
the
Panel
are
summarized
below.
The
complete
set
of
recommendations
can
be
found
in
Section
9
of
the
Panel's
full
Report.
The
panel
recommendations
for
motorcycles
described
below
were
developed
for
the
exhaust
emission
standards.
Potential
controls
for
permeation
emissions
from
motorcycles
were
not
part
of
the
panel
process,
because
review
of
the
need
for
such
controls
resulted
from
comments
received
on
the
related
recreational
vehicles
proposal
and
further
investigation
by
EPA
following
the
end
of
the
panel
process.
However,
EPA
believes
that
the
potential
permeation
emission
controls
on
motorcycles
would
not,
if
promulgated,
have
a
significant
effect
on
the
burdens
of
this
rule
on
regulated
entities,
or
on
small
entities
in
particular,
due
to
the
relatively
low
cost
and
the
availability
of
materials
and
treatment
support
by
outside
vendors.
Low
permeation
fuel
hoses
are
available
from
vendors
today,
and
we
would
expect
that
surface
treatment
for
tanks
would
be
applied
through
an
outside
company.
We
request
comment
on
the
need
for
flexibilities
for
the
potential
permeation
standards,
if
they
are
adopted.
If
the
comments
or
other
information
the
Agency
receives
indicate
that
flexibilities
similar
to
(or
the
same
as)
those
for
the
motorcycle
exhaust
standards
are
appropriate
for
the
motorcycle
permeation
standards,
then
we
will
adopt
such
flexibilities
as
part
of
our
final
rule
if
we
adopt
such
permeation
standards.
Many
of
the
flexible
approaches
recommended
by
the
Panel
can
be
applied
to
either
marine
vessels
or
highway
motorcycles.
These
approaches
are
listed
below:
1.
Additional
lead
time
for
compliance.
2.
Hardship
provisions.
3.
Certification
flexibility.
4.
Broadly
defined
product
certification
families.
5.
Averaging,
banking,
and
trading.
Based
on
consultations
with
SERs,
the
Panel
believes
that
the
first
two
provisions
listed
above
are
likely
to
provide
the
greatest
flexibility
for
many
small
entities.
These
provisions
are
likely
to
be
most
valuable
because
they
either
provide
more
time
for
compliance
(e.
g.,
additional
lead
time
and
hardship
provisions).
The
remaining
three
approaches
have
the
potential
to
reduce
near
term
and
even
long
term
costs
once
a
small
entity
has
a
product
it
is
preparing
to
certify.
These
are
important
in
that
the
reducing
costs
of
testing
several
emission
families
and/
or
developing
deterioration
factors.
Small
businesses
could
also
meet
an
emission
standard
on
average
or
generate
credits
for
producing
engines
which
emit
at
levels
below
the
standard;
these
credits
could
then
be
sold
to
other
manufacturers
for
compliance
or
banked
for
use
in
future
model
years.
During
the
consultation
process,
it
became
evident
that,
in
a
few
situations,
it
could
be
helpful
to
small
entities
if
unique
provisions
were
available.
Two
such
provisions
are
described
below.
a.
Marine
Vessel
Tanks.
Most
of
this
sector
involves
small
fuel
tank
manufacturers
and
small
boat
builders.
The
Panel
recommends
that
the
program
be
structured
with
longer
lead
times
and
an
early
credit
generation
program
to
enable
the
fuel
tank
manufacturers
to
implement
controls
on
tanks
on
a
schedule
consistent
with
their
normal
turnover
of
fuel
tank
molds.
Also,
the
panel
recommends
that
the
program
allow
small
businesses
have
the
option
of
certifying
to
the
evaporative
emission
performance
standards
based
on
fuel
tank
design
characteristics
designed
to
reduce
emissions.
b.
Highway
Motorcycles.
The
California
Air
Resources
Board
(CARB)
has
found
that
California's
Tier
2
standard
is
potentially
infeasible
for
small
manufacturers.
Therefore,
the
Panel
recommends
that
EPA
delay
making
decisions
on
the
applicability
to
small
businesses
of
Tier
2
or
other
such
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Federal
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/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
revisions
to
the
federal
regulations
until
California's
2006
review
is
complete.
7.
Summary
of
SBREFA
Process
and
Panel
Outreach
As
required
by
section
609(
b)
of
the
RFA,
as
amended
by
SBREFA,
EPA
also
conducted
outreach
to
small
entities
and
convened
a
Small
Business
Advocacy
Review
Panel
to
obtain
advice
and
recommendations
of
representatives
of
the
small
entities
that
potentially
would
be
subject
to
the
rule's
requirements.
On
May
3,
2001,
EPA's
Small
Business
Advocacy
Chairperson
convened
this
Panel
under
Section
609(
b)
of
the
Regulatory
Flexibility
Act
(RFA)
as
amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(SBREFA).
In
addition
to
the
Chair,
the
Panel
consisted
of
the
Director
of
the
Assessment
and
Standards
Division
(ASD)
within
EPA's
Office
of
Transportation
and
Air
Quality,
the
Chief
Counsel
for
Advocacy
of
the
Small
Business
Administration,
and
the
Deputy
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs
within
the
Office
of
Management
and
Budget.
As
part
of
the
SBAR
process,
the
Panel
met
with
small
entity
representatives
(SERs)
to
discuss
the
potential
emission
standards
and,
in
addition
to
the
oral
comments
from
SERs,
the
Panel
solicited
written
input.
In
the
months
preceding
the
Panel
process,
EPA
conducted
outreach
with
small
entities
from
each
of
the
five
sectors
as
described
above.
On
May
18,
2001,
the
Panel
distributed
an
outreach
package
to
the
SERs.
On
May
30
and
31,
2001,
the
Panel
met
with
SERs
to
hear
their
comments
on
preliminary
alternatives
for
regulatory
flexibility
and
related
information.
The
Panel
also
received
written
comments
from
the
SERs
in
response
to
the
discussions
at
this
meeting
and
the
outreach
materials.
The
Panel
asked
SERs
to
evaluate
how
they
would
be
affected
under
a
variety
of
regulatory
approaches,
and
to
provide
advice
and
recommendations
regarding
early
ideas
for
alternatives
that
would
provide
flexibility
to
address
their
compliance
burden.
SERs
representing
companies
in
each
of
the
sectors
addressed
by
the
Panel
raised
concerns
about
the
potential
costs
of
complying
with
the
rules
under
development.
For
the
most
part,
their
concerns
were
focused
on
two
issues:
(1)
The
difficulty
(and
added
cost)
that
they
would
face
in
complying
with
certification
requirements
associated
with
the
standards
EPA
is
developing,
and
(2)
the
cost
of
meeting
the
standards
themselves.
SERs
observed
that
these
costs
would
include
the
opportunity
cost
of
deploying
resources
for
research
and
development,
expenditures
for
tooling/
retooling,
and
the
added
cost
of
new
engine
designs
or
other
parts
that
would
need
to
be
added
to
equipment
in
order
to
meet
EPA
emission
standards.
In
addition,
in
each
category,
the
SERs
noted
that
small
manufacturers
(and
in
the
case
of
one
category,
small
importers)
have
fewer
resources
and
are
therefore
less
well
equipped
to
undertake
these
new
activities
and
expenditures.
Furthermore,
because
their
product
lines
tend
to
be
smaller,
any
additional
fixed
costs
must
be
recovered
over
a
smaller
number
of
units.
Thus,
absent
any
provisions
to
address
these
issues,
new
emission
standards
are
likely
to
impose
much
more
significant
adverse
effects
on
small
entities
than
on
their
larger
competitors.
The
Panel
discussed
each
of
the
issues
raised
in
the
outreach
meetings
and
in
written
comments
by
the
SERs.
The
Panel
agreed
that
EPA
should
consider
the
issues
raised
by
the
SERs
and
that
it
would
be
appropriate
for
EPA
to
propose
and/
or
request
comment
on
various
alternative
approaches
to
address
these
concerns.
The
Panel's
key
discussions
centered
around
the
need
for
and
most
appropriate
types
of
regulatory
compliance
alternatives
for
small
businesses.
The
Panel
considered
a
variety
of
provisions
to
reduce
the
burden
of
complying
with
new
emission
standards
and
related
requirements.
Some
of
these
provisions
would
apply
to
all
companies
(e.
g.,
averaging,
banking,
and
trading),
while
others
would
be
targeted
at
the
unique
circumstances
faced
by
small
businesses.
A
complete
discussion
of
the
regulatory
alternatives
recommended
by
the
Panel
can
be
found
in
the
Final
Panel
Report.
Copies
of
the
Final
Report
can
be
found
in
the
docket
for
this
rulemaking
or
at
http://
www.
epa.
gov/
sbrefa.
Summaries
of
the
Panel's
recommended
alternatives
for
each
of
the
sectors
subject
to
this
action
can
be
found
in
the
respective
sections
of
the
preamble.
As
required
by
section
609(
b)
of
the
RFA,
as
amended
by
SBREFA,
EPA
also
conducted
outreach
to
small
entities
and
convened
a
Small
Business
Advocacy
Review
Panel
to
obtain
advice
and
recommendations
of
representatives
of
the
small
entities
that
potentially
would
be
subject
to
the
rule's
requirements.
EPA's
Small
Business
Advocacy
Chairperson
convened
this
on
May
3,
2001.
In
addition
to
the
Chair,
the
Panel
consisted
of
the
Director
of
the
Assessment
and
Standards
Division
(ASD)
within
EPA's
Office
of
Transportation
and
Air
Quality,
the
Chief
Counsel
for
Advocacy
of
the
Small
Business
Administration,
and
the
Deputy
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs
within
the
Office
of
Management
and
Budget.
The
proposal
being
developed
includes
marine
sterndrive
and
inboard
(SD/
I)
engines
and
boats
powered
by
SI
marine
engines.
In
addition,
EPA
also
intends
to
update
EPA
requirements
for
highway
motorcycles.
Finally,
the
proposal
being
developed
included
evaporative
emission
control
requirements
for
gasoline
fuel
tanks
and
systems
used
on
marine
vessels.
The
Panel
met
with
Small
Entity
Representatives
(SERs)
to
discuss
the
potential
emissions
standards
and,
in
addition
to
the
oral
comments
from
SERs,
the
Panel
solicited
written
input.
In
the
months
preceding
the
Panel
process,
EPA
conducted
outreach
with
small
entities
from
each
of
the
five
sectors
as
described
above.
On
May
18,
2001,
the
Panel
distributed
an
outreach
package
to
the
SERs.
On
May
30
and
31,
2001,
the
Panel
met
with
SERs
to
hear
their
comments
on
preliminary
options
for
regulatory
flexibility
and
related
information.
The
Panel
also
received
written
comments
from
the
SERs
in
response
to
the
discussions
at
this
meeting
and
the
outreach
materials.
The
Panel
asked
SERs
to
evaluate
how
they
would
be
affected
under
a
variety
of
regulatory
approaches,
and
to
provide
advice
and
recommendations
regarding
early
ideas
to
provide
flexibility.
See
Section
8
of
the
Panel
Report
for
a
complete
discussion
of
SER
comments,
and
Appendices
A
and
B
for
summaries
of
SER
oral
comments
and
SER
written
comments.
Consistent
with
the
RFA/
SBREFA
requirements,
the
Panel
evaluated
the
assembled
materials
and
small
entity
comments
on
issues
related
to
the
elements
of
the
IRFA.
A
copy
of
the
Panel
report
is
included
in
the
docket
for
this
proposed
rule.
The
following
are
Panel
recommendations
adopted
by
the
Agency.
Please
note
all
Panel
recommendations
were
adopted
for
this
proposal.
a.
Related
Federal
Rules.
The
Panel
recommends
that
EPA
continue
to
consult
with
the
CPSC
in
developing
a
proposed
and
final
rule
in
order
to
better
understand
the
scope
of
the
Commission's
regulations
as
they
may
relate
to
the
competition
exclusion.
In
addition,
the
Panel
recommends
that
EPA
continue
to
work
with
the
Coast
Guard
to
evaluate
the
safety
implications
of
any
proposed
evaporative
emissions
standards
and
to
avoid
interference
with
Coast
Guard
safety
regulations.
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2002
/
Proposed
Rules
b.
Regulatory
Flexibility
Alternatives.
The
Panel
recommends
that
EPA
consider
and
seek
comments
on
a
wide
range
of
alternatives,
including
the
flexibility
options
described
below.
(i)
Marine
Vessels.
(A)
Smooth
Transition
to
Proposed
Standards.
The
Panel
recommends
that
EPA
propose
an
approach
that
would
implement
any
evaporative
standards
five
years
after
a
regulation
for
marine
engines
takes
effect.
The
Panel
also
recommends
that
EPA
seek
comment
on
this
five
year
period
and
on
whether
there
are
small
entities
whose
product
line
is
dominated
by
tanks
that
turn
over
at
a
time
rate
slower
time
than
five
years.
(B)
Design
Based
Certification.
The
Panel
recommends
that
EPA
propose
to
grant
small
businesses
the
option
of
certifying
to
the
evaporative
emission
performance
requirements
based
on
fuel
tank
design
characteristics
that
reduce
emissions.
The
Panel
also
recommends
that
EPA
seek
comment
on
and
consider
proposing
an
approach
that
would
allow
manufacturers
to
use
this
averaging
approach
with
designs
other
than
those
listed
in
the
final
rule.
(C)
ABT
of
Emission
Credits
with
Design
Based
Certification.
The
Panel
recommends
that
EPA
allow
manufacturers
using
design
based
certification
to
generate
credits.
The
Panel
also
recommends
that
EPA
provide
adequately
detailed
design
specifications
and
associated
emission
levels
for
several
technology
options
that
could
be
used
to
certify.
(D)
Broadly
Defined
Product
Certification
Families.
The
Panel
recommends
that
EPA
take
comment
on
the
need
for
broadly
defined
emission
families
and
how
these
families
should
be
defined.
(E)
Hardship
Provisions.
The
Panel
recommends
that
EPA
propose
two
types
of
hardship
programs
for
marine
engine
manufacturers,
boat
builders
and
fuel
tank
manufacturers:
(1)
Allow
small
businesses
to
petition
EPA
for
additional
lead
time
to
comply
with
the
standards;
and
(2)
allow
small
businesses
to
apply
for
hardship
relief
if
circumstances
outside
their
control
cause
the
failure
to
comply
(i.
e.
supply
contract
broken
by
parts
supplier)
and
if
the
failure
to
sell
the
subject
fuel
tanks
or
boats
would
have
a
major
impact
on
the
company's
solvency.
The
Panel
also
recommends
that
EPA
work
with
small
manufacturers
to
develop
these
criteria
and
how
they
would
be
used.
(ii)
Highway
Motorcycles.
The
Panel
recommends
that
EPA
include
the
flexibilities
described
below
for
small
entities
with
highway
motorcycle
annual
sales
of
less
than
3,000
units
per
model
year
(combined
Class
I,
II,
and
III
motorcycles)
and
fewer
than
500
employees.
(A)
Delay
of
Proposed
Standards.
The
Panel
recommends
that
EPA
propose
to
delay
compliance
with
the
Tier
1
standard
of
1.4
g/
km
HC+
NOX
until
the
2008
model
year
for
small
volume
manufacturers.
The
Panel
also
recommends
that
EPA
seek
comment
on
whether
additional
time
is
needed
for
small
businesses
to
comply
with
the
Federal
program.
The
Panel
recommends
that
EPA
participate
with
CARB
in
the
2006
progress
review
as
these
provisions
are
revisited,
and
delay
making
decisions
on
the
applicability
to
small
businesses
of
Tier
2
or
other
revisions
to
the
federal
regulations
that
are
appropriate
following
the
review.
The
Panel
also
recommends
that
any
potential
Tier
2
requirements
for
small
manufacturer
motorcycles
consider
potential
test
procedure
changes
arising
from
the
ongoing
World
Motorcycle
Test
Cycle
work
described
in
the
Panel
Report.
(B)
Broader
Engine
Families.
The
Panel
recommends
that
EPA
keep
the
current
existing
regulations
for
small
volume
highway
motorcycle
manufacturers.
(C)
Exemption
from
Production
Line
Testing.
The
Panel
recommends
that
EPA
keep
the
current
provisions
for
no
mandatory
production
line
testing
requirement
for
highway
motorcycles
and
allow
the
EPA
to
request
production
vehicles
from
any
certifying
manufacturer
for
testing.
(D)
Averaging,
Banking,
and
Trading
(ABT).
The
Panel
recommends
that
EPA
propose
an
ABT
program
for
highway
motorcycles.
(E)
Hardship
Provisions.
The
Panel
recommends
that
EPA
propose
two
types
of
hardship
programs
for
highway
motorcycles:
(1)
Allow
small
businesses
to
petition
EPA
for
additional
lead
time
to
comply
with
the
standards;
and
(2)
allow
small
businesses
to
apply
for
hardship
relief
if
circumstances
outside
their
control
cause
the
failure
to
comply
(i.
e.
supply
contract
broken
by
parts
supplier)
and
if
failure
to
sell
the
subject
engines
or
vehicles
would
have
a
major
impact
on
the
company's
solvency.
The
Panel
also
recommends
that
EPA
request
comment
on
the
California
requirements,
which
do
not
include
hardship
provisions.
(F)
Reduced
Certification
Data
Submittal
and
Testing
Requirements.
The
Panel
recommends
that
EPA
keep
current
EPA
regulations
allow
significant
flexibility
for
certification
by
manufacturers
who
project
fewer
than
10,000
unit
sales
of
combined
Class
I,
II,
and
III
motorcycles.
We
invite
comments
on
all
aspects
of
the
proposal
and
its
impacts
on
small
entities.
C.
Paperwork
Reduction
Act
The
information
collection
requirements
in
this
proposed
rule
have
been
submitted
for
approval
to
the
Office
of
Management
and
Budget
(OMB)
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
Information
Collection
Requests
(ICR
No.
1897.03
for
marine
vessels
and
0783.43
for
highway
motorcycles)
have
been
prepared
by
EPA,
and
a
copy
may
be
obtained
from
Susan
Auby,
Collection
Strategies
Division;
U.
S.
Environmental
Protection
Agency
(2822);
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460,
by
e
mail
at
auby.
susan@
epamail.
epa.
gov,
or
by
calling
(202)
566Ð
1672.
A
copy
may
also
be
downloaded
off
the
internet
at
http:/
/www.
epa.
gov.
icr.
The
information
being
collected
is
to
be
used
by
EPA
to
ensure
that
new
marine
vessels
and
fuel
systems
and
new
highway
motorcycles
comply
with
applicable
emissions
standards
through
certification
requirements
and
various
subsequent
compliance
provisions.
For
marine
vessels,
the
annual
public
reporting
and
recordkeeping
burden
for
this
collection
of
information
is
estimated
to
average
6
hours
per
response,
with
collection
required
annually.
The
estimated
number
of
respondents
is
810.
The
total
annual
cost
for
the
first
3
years
of
the
program
is
estimated
to
be
$230,438
year
and
includes
no
annualized
capital
costs,
$14,000
in
operating
and
maintenance
costs,
at
a
total
of
4,838
hours
per
year.
For
highway
motorcycles,
the
annual
public
reporting
and
recordkeeping
burden
for
this
collection
of
information
is
estimated
to
average
228
hours
per
response,
with
collection
required
annually.
The
estimated
number
of
respondents
is
73.
The
total
annual
cost
for
the
first
3
years
of
the
program
is
estimated
to
be
$3,430,908
per
year
and
includes
no
annualized
capital
costs,
$2,728,000
in
operating
and
maintenance
costs,
at
a
total
of
16,647
hours
per
year.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
disclose,
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjusting
the
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/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
displayed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Comments
are
requested
on
the
Agency's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
Send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division;
U.
S.
Environmental
Protection
Agency
(2822);
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460;
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
St.,
NW.,
Washington,
DC
20503,
marked
``
Attention:
Desk
Officer
for
EPA.
''
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
August
14,
2002,
a
comment
to
OMB
is
best
ensured
of
having
its
full
effect
if
OMB
receives
it
by
September
13,
2002.
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
this
proposal.
D.
Intergovernmental
Relations
1.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(UMRA),
Pub.
L.
104Ð
4,
establishes
requirements
for
federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
state,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
federal
mandates''
that
may
result
in
expenditures
to
state,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$100
million
or
more
in
any
one
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
of
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
This
rule
contains
no
Federal
mandates
for
state,
local,
or
tribal
governments
as
defined
by
the
provisions
of
Title
II
of
the
UMRA.
The
rule
imposes
no
enforceable
duties
on
any
of
these
governmental
entities.
Nothing
in
the
rule
would
significantly
or
uniquely
affect
small
governments.
EPA
has
determined
that
this
rule
contains
federal
mandates
that
may
result
in
expenditures
of
less
than
$100
million
to
the
private
sector
in
any
single
year.
EPA
believes
that
the
proposal
represents
the
least
costly,
most
cost
effective
approach
to
achieve
the
air
quality
goals
of
the
rule.
The
costs
and
benefits
associated
with
the
proposal
are
discussed
in
Section
VI
and
in
the
Draft
Regulatory
Support
Document.
2.
Executive
Order
13175
(Consultation
and
Coordination
With
Indian
Tribal
Governments)
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.
''
``
Policies
that
have
tribal
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
the
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes.
''
This
proposed
rule
does
not
have
tribal
implications.
It
will
not
have
substantial
direct
effects
on
tribal
governments,
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
This
rule
contains
no
federal
mandates
for
tribal
governments.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.
However,
in
the
spirit
of
Executive
Order
13175,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
tribal
governments,
we
specifically
solicit
additional
comment
on
this
proposed
rule
from
tribal
officials.
E.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(``
NTTAA''),
Public
Law
104Ð
113,
§
12(
d)
(15
U.
S.
C.
272
note)
directs
EPA
to
use
voluntary
consensus
standards
in
its
regulatory
activities
unless
doing
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
and
business
practices)
that
are
developed
or
adopted
by
voluntary
consensus
standards
bodies.
NTTAA
directs
EPA
to
provide
Congress,
through
OMB,
explanations
when
the
Agency
decides
not
to
use
available
and
applicable
voluntary
consensus
standards.
This
proposed
rule
involves
technical
standards.
The
following
paragraphs
describe
how
we
specify
testing
procedures
for
engines
subject
to
this
proposal.
We
are
proposing
to
test
highway
motorcycles
with
the
Federal
Test
Procedure,
a
chassis
based
transient
test.
There
is
no
voluntary
consensus
standard
that
would
adequately
address
engine
or
vehicle
operation
for
suitable
emission
measurement.
For
marine
vessels,
we
are
proposing
to
use
an
evaporative
emission
test
procedure
based
on
the
highway
Federal
Test
Procedure.
There
is
no
voluntary
consensus
standard
for
testing
evaporative
emission
from
marine
vessels.
In
addition,
we
are
proposing
the
option
of
using
design
based
certification.
F.
Protection
of
Children
(Executive
Order
13045)
Executive
Order
13045,
``
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks''
(62
FR
19885,
April
23,
1997)
applies
to
any
rule
that
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157
/
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August
14,
2002
/
Proposed
Rules
(1)
is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
Section
5Ð
501
of
the
Order
directs
the
Agency
to
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.
This
proposed
rule
is
not
subject
to
the
Executive
Order
because
it
does
not
involve
decisions
on
environmental
health
or
safety
risks
that
may
disproportionately
affect
children.
The
effects
of
ozone
and
PM
on
children's
health
were
addressed
in
detail
in
EPA's
rulemaking
to
establish
the
NAAQS
for
these
pollutants,
and
EPA
is
not
revisiting
those
issues
here.
EPA
believes,
however,
that
the
emission
reductions
from
the
strategies
proposed
in
this
rulemaking
will
further
reduce
air
toxics
and
the
related
adverse
impacts
on
children's
health.
G.
Federalism
(Executive
Order
13132)
Executive
Order
13132,
entitled
``
Federalism''
(64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.
''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.
''
Under
Section
6
of
Executive
Order
13132,
EPA
may
not
issue
a
regulation
that
has
federalism
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,
unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
State
and
local
governments,
or
EPA
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
EPA
also
may
not
issue
a
regulation
that
has
federalism
implications
and
that
preempts
State
law,
unless
the
Agency
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
Section
4
of
the
Executive
Order
contains
additional
requirements
for
rules
that
preempt
State
or
local
law,
even
if
those
rules
do
not
have
federalism
implications
(i.
e.,
the
rules
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
states,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government).
Those
requirements
include
providing
all
affected
State
and
local
officials
notice
and
an
opportunity
for
appropriate
participation
in
the
development
of
the
regulation.
If
the
preemption
is
not
based
on
express
or
implied
statutory
authority,
EPA
also
must
consult,
to
the
extent
practicable,
with
appropriate
State
and
local
officials
regarding
the
conflict
between
State
law
and
Federally
protected
interests
within
the
agency's
area
of
regulatory
responsibility.
This
proposed
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
Although
Section
6
of
Executive
Order
13132
does
not
apply
to
this
rule,
EPA
did
consult
with
representatives
of
various
State
and
local
governments
in
developing
this
rule.
EPA
has
also
consulted
representatives
from
STAPPA/
ALAPCO,
which
represents
state
and
local
air
pollution
officials.
In
the
spirit
of
Executive
Order
13132,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
State
and
local
governments,
EPA
specifically
solicits
comment
on
this
proposed
rule
from
State
and
local
officials.
H.
Energy
Effects
(Executive
Order
13211)
This
rule
is
not
a
``
significant
energy
action''
as
defined
in
Executive
Order
13211,
``
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(66
FR
28355
(May
22,
2001))
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution
or
use
of
energy.
The
proposed
standards
have
for
their
aim
the
reduction
of
emission
from
certain
nonroad
engines,
and
have
no
effect
on
fuel
formulation,
distribution,
or
use.
Generally,
the
proposed
program
leads
to
reduced
fuel
usage
due
to
the
reduction
of
wasted
fuel
through
evaporation.
I.
Plain
Language
This
document
follows
the
guidelines
of
the
June
1,
1998
Executive
Memorandum
on
Plain
Language
in
Government
Writing.
To
read
the
text
of
the
regulations,
it
is
also
important
to
understand
the
organization
of
the
Code
of
Federal
Regulations
(CFR).
The
CFR
uses
the
following
organizational
names
and
conventions.
Title
40Ñ
Protection
of
the
Environment
Chapter
IÑ
Environmental
Protection
Agency
Subchapter
CÑ
Air
Programs.
This
contains
parts
50
to
99,
where
the
Office
of
Air
and
Radiation
has
usually
placed
emission
standards
for
motor
vehicle
and
nonroad
engines.
Subchapter
UÑ
Air
Programs
Supplement.
This
contains
parts
1000
to
1299,
where
we
intend
to
place
regulations
for
air
programs
in
future
rulemakings.
Part
1045Ñ
Control
of
Emissions
from
Marine
Spark
ignition
Engines
and
Vessels
Part
1068Ñ
General
Compliance
Provisions
for
Engine
Programs.
Provisions
of
this
part
apply
to
everyone.
Each
part
in
the
CFR
has
several
subparts,
sections,
and
paragraphs.
The
following
illustration
shows
how
these
fit
together.
Part
1045
Subpart
A
Section
1045.1
(a)
(b)
(1)
(2)
(i)
(ii)
(A)
(B)
A
cross
reference
to
§
1045.1(
b)
in
this
illustration
would
refer
to
the
parent
paragraph
(b)
and
all
its
subordinate
paragraphs.
A
reference
to
``§
1045.1(
b)
introductory
text''
would
refer
only
to
the
single,
parent
paragraph
(b).
List
of
Subjects
40
CFR
Part
86
Environmental
protection,
Administrative
practice
and
procedure,
Confidential
business
information,
Labeling,
Motor
vehicle
pollution,
Reporting
and
recordkeeping
requirements
40
CFR
Part
90
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Confidential
business
information,
Imports,
Labeling,
Reporting
and
recordkeeping
requirements,
Research,
Warranties
40
CFR
Part
1045
Environmental
protection,
Administrative
practice
and
procedure,
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Federal
Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
Air
pollution
control,
Confidential
business
information,
Imports,
Labeling,
Penalties,
Reporting
and
recordkeeping
requirements,
Research,
Warranties
40
CFR
Part
1051
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Confidential
business
information,
Imports,
Labeling,
Penalties,
Reporting
and
recordkeeping
requirements,
Warranties.
40
CFR
Part
1068
Environmental
protection,
Administrative
practice
and
procedure,
Confidential
business
information,
Imports,
Motor
vehicle
pollution,
Reporting
and
recordkeeping
requirements,
Warranties.
Dated:
July
25,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
set
out
in
the
preamble,
title
40,
chapter
I
of
the
Code
of
Federal
Regulations
is
proposed
to
be
amended
as
set
forth
below:
PART
86—
CONTROL
OF
EMISSIONS
FROM
NEW
AND
IN
USE
HIGHWAY
VEHICLES
AND
ENGINES
1.
The
authority
citation
for
part
86
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401Ð
7521(
l)
and
7521(
m)Ð
7671q.
Subpart
E—[
Amended]
2.
A
new
§
86.401Ð
2006
is
added
to
subpart
E
to
read
as
follows:
§
86.401–
2006
General
applicability.
This
subpart
applies
to
1978
and
later
model
year,
new,
gasoline
fueled
motorcycles
built
after
December
31,
1977,
and
to
1990
and
later
model
year,
new
methanol
fueled
motorcycles
built
after
December
31,
1989,
and
to
1997
and
later
model
year,
new
natural
gasfueled
and
liquefied
petroleum
gasfueled
motorcycles
built
after
December
31,
1996,
and
to
2006
and
later
model
year
new
motorcycles,
regardless
of
fuel.
3.
Section
86.402Ð
78(
a)
is
amended
by
adding
a
definition
for
``
Motor
vehicle''
in
alphabetical
order
to
read
as
follows:
§
86.402–
78
Definitions.
(a)
*
*
*
Motor
vehicle
has
the
meaning
we
give
in
40
CFR
85.1703.
*
*
*
*
*
4.
A
new
§
86.410Ð
2006
is
added
to
subpart
E
to
read
as
follows:
§
86.410–
2006
Emission
standards
for
2006
and
later
model
year
motorcycles.
(a)(
1)
Exhaust
emissions
from
Class
I
and
Class
II
motorcycles
shall
not
exceed
the
standards
listed
in
the
following
table:
TABLE
E.—
2006.1
CLASS
I
AND
II
MOTORCYCLE
EMISSION
STANDARDS
Model
year
Emission
standards
(g/
km)
HC
CO
2006
and
later
..........
1.0
12.0
(2)
Exhaust
emissions
from
Class
III
motorcycles
shall
not
exceed
the
standards
listed
in
the
following
table:
TABLE
E.—
2006.2
CLASS
III
MOTORCYCLE
EMISSION
STANDARDS
Tier
Model
year
Emission
standards
(g/
km)
HC+
NOX
CO
1
.......
2006–
2009
1.4
12.0
2
.......
2010
and
later.
0.8
12.0
(b)
The
standards
set
forth
in
paragraphs
(a)
(1)
and
(2)
of
this
section
refer
to
the
exhaust
emitted
over
the
driving
schedule
as
set
forth
in
subpart
F
and
measured
and
calculated
in
accordance
with
those
procedures.
(c)
Compliance
with
the
HC+
NOX
standards
set
forth
in
paragraph
(a)(
2)
of
this
section
may
be
demonstrated
using
the
averaging
provisions
of
§
86.449.
(d)
No
crankcase
emissions
shall
be
discharged
into
the
ambient
atmosphere
from
any
new
motorcycle
subject
to
this
subpart.
(e)
Manufacturers
with
fewer
than
500
employees
and
producing
fewer
than
3000
motorcycles
per
year
are
considered
small
volume
manufacturers
for
the
purposes
of
this
section.
The
following
provisions
apply
for
these
small
volume
manufacturers:
(1)
Small
volume
manufacturers
are
not
required
to
comply
with
the
Tier
1
standards
until
model
year
2008.
(2)
Small
volume
manufacturers
are
not
required
to
comply
with
the
Tier
2
standards.
5.
A
new
§
86.419Ð
2006
is
added
to
subpart
E
to
read
as
follows:
§
86.419–
2006
Engine
displacement,
motorcycle
classes.
(a)(
1)
Engine
displacement
shall
be
calculated
using
nominal
engine
values
and
rounded
to
the
nearest
whole
cubic
centimeter,
in
accordance
with
ASTM
E
29Ð
67
(incorporated
by
reference
in
§
86.1).
(2)
For
rotary
engines,
displacement
means
the
maximum
volume
of
a
combustion
chamber
between
two
rotor
tip
seals,
minus
the
minimum
volume
of
the
combustion
chamber
between
those
two
rotor
tip
seals,
times
three
times
the
number
of
rotors,
according
to
the
following
formula:
cc
=
(max.
chamber
volume
¥
min.
chamber
volume)
×
3
×
no.
of
rotors
(b)
Motorcycles
will
be
divided
into
classes
based
on
engine
displacement.
(1)
Class
IÑ
0
to
169
cc
(0
to
10.4
cu.
in.).
(2)
Class
IIÑ
170
to
279
cc
(10.4
to
17.1
cu.
in.).
(3)
Class
IIIÑ
280
cc
and
over
(17.1
cu.
in.
and
over).
(c)
At
the
manufacturer's
option,
a
vehicle
described
in
an
application
for
certification
may
be
placed
in
a
higher
class
(larger
displacement).
All
procedures
for
the
higher
class
must
then
be
complied
with,
compliance
withemission
standards
will
be
determined
on
the
basis
of
engine
displacement.
6.
A
new
§
86.445Ð
2006
is
added
to
subpart
E
to
read
as
follows:
§
86.445–
2006
What
temporary
provisions
address
hardship
due
to
unusual
circumstances?
(a)
After
considering
the
circumstances,
we
may
permit
you
to
introduce
into
commerce
highway
motorcycles
that
do
not
comply
with
emission
standards
if
all
the
following
conditions
and
requirements
apply:
(1)
Unusual
circumstances
that
are
clearly
outside
your
control
and
that
could
not
have
been
avoided
with
reasonable
discretion
prevent
you
from
meeting
requirements
from
this
chapter.
(2)
You
exercised
prudent
planning
and
were
not
able
to
avoid
the
violation;
you
have
taken
all
reasonable
steps
to
minimize
the
extent
of
the
nonconformity.
(3)
Not
having
the
exemption
will
jeopardize
the
solvency
of
your
company.
(4)
No
other
allowances
are
available
under
the
regulations
to
avoid
the
impending
violation.
(b)
To
apply
for
an
exemption,
you
must
send
the
Designated
Officer
a
written
request
as
soon
as
possible
before
you
are
in
violation.
In
your
request,
show
that
you
meet
all
the
conditions
and
requirements
in
paragraph
(a)
of
this
section.
(c)
Include
in
your
request
a
plan
showing
how
you
will
meet
all
the
applicable
requirements
as
quickly
as
possible.
(d)
You
must
give
us
other
relevant
information
if
we
ask
for
it.
(e)
We
may
include
reasonable
additional
conditions
on
an
approval
granted
under
this
section,
including
provisions
to
recover
or
otherwise
address
the
lost
environmental
benefit
or
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Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
paying
fees
to
offset
any
economic
gain
resulting
from
the
exemption.
For
example,
we
may
require
that
you
meet
standards
less
stringent
than
those
that
currently
apply.
7.
A
new
§
86.446Ð
2006
is
added
to
subpart
E
to
read
as
follows:
§
86.446–
2006
What
are
the
provisions
for
extending
compliance
deadlines
for
smallvolume
manufacturers
under
hardship?
(a)
After
considering
the
circumstances,
we
may
extend
the
compliance
deadline
for
you
to
meet
new
or
revised
emission
standards,
as
long
as
you
meet
all
the
conditions
and
requirements
in
this
section.
(b)
To
be
eligible
for
this
exemption,
you
must
qualify
as
a
small
volume
manufacturer
under
§
86.410Ð
2006(
e).
(c)
To
apply
for
an
extension,
you
must
send
the
Designated
Officer
a
written
request.
In
your
request,
show
that
all
the
following
conditionsand
requirements
apply:
(1)
You
have
taken
all
possible
business,
technical,
and
economic
steps
to
comply.
(i)
In
the
case
of
importers,
show
that
you
are
unable
to
find
a
manufacturer
capable
of
supplying
complying
products.
(ii)
For
all
other
manufacturers,
show
that
the
burden
of
compliance
costs
prevents
you
from
meeting
the
requirements
of
this
chapter.
(2)
Not
having
the
exemption
will
jeopardize
the
solvency
of
your
company.
(3)
No
other
allowances
are
available
under
the
regulations
to
avoidthe
impending
violation.
(d)
In
describing
the
steps
you
have
taken
to
comply
under
paragraph
(c)(
1)
of
this
section,
include
at
least
the
following
information:
(1)
Describe
your
business
plan,
showing
the
range
of
projects
active
or
under
consideration.
(2)
Describe
your
current
and
projected
financial
standing,
with
and
without
the
burden
of
complying
with
regulations.
(3)
Describe
your
efforts
to
raise
capital
to
comply
with
regulations.
(4)
Identify
the
engineering
and
technical
steps
you
have
taken
or
planto
take
to
comply
with
regulations.
(5)
Identify
the
level
of
compliance
you
can
achieve.
For
example,
you
may
be
able
to
produce
engines
that
meet
a
somewhat
less
stringent
emission
standard
than
the
regulations
require.
(e)
Include
in
your
request
a
plan
showing
how
you
will
meet
all
the
applicable
requirements
as
quickly
as
possible.
(f)
You
must
give
us
other
relevant
information
if
we
ask
for
it.
(g)
An
authorized
representative
of
your
company
must
sign
the
request
andinclude
the
statement:
``
All
the
information
in
this
request
is
true
andaccurate,
to
the
best
of
my
knowledge.
''
(h)
Send
your
request
for
this
extension
at
least
nine
months
before
new
standards
apply.
Do
not
send
your
request
before
the
regulations
in
question
apply
to
other
manufacturers.
(i)
We
may
include
reasonable
requirements
on
an
approval
granted
underthis
section,
including
provisions
to
recover
or
otherwise
address
the
lostenvironmental
benefit.
For
example,
we
may
require
that
you
meet
a
less
stringent
emission
standard
or
buy
and
use
available
emission
credits.
(j)
We
will
approve
extensions
of
up
to
one
year.
We
may
review
and
revisean
extension
as
reasonable
under
the
circumstances.
8.
A
new
§
86.447Ð
2006
is
added
to
subpart
E
to
read
as
follows:
§
86.447–
2006
What
are
the
provisions
for
exempting
motorcycles
under
50
cc
from
the
requirements
of
this
part
if
they
use
engines
you
certify
under
other
programs?
(a)
This
section
applies
to
you
if
you
manufacture
engines
under
50
cc
for
installation
in
a
highway
motorcycle.
See
§
86.448Ð
2006
if
you
are
not
the
engine
manufacturer.
(b)
The
only
requirements
or
prohibitions
from
this
part
that
apply
to
a
motorcycle
that
is
exempt
under
this
section
are
in
this
section
and
§
86.448Ð
2006.
(c)
If
you
meet
all
the
following
criteria
regarding
your
new
engine,
itis
exempt
under
this
section:
(1)
You
must
produce
it
under
a
valid
certificate
of
conformity
for
one
of
the
following
types
of
engines
or
vehicles:
(i)
Class
II
engines
under
40
CFR
part
90.
(ii)
Recreational
vehicles
under
40
CFR
part
1051.
(2)
You
must
not
make
any
changes
to
the
certified
engine
that
we
could
reasonably
expect
to
increase
its
exhaust
emissions.
For
example,
if
you
make
any
of
the
following
changes
to
one
of
these
engines,
you
do
not
qualify
for
this
exemption:
(i)
Change
any
fuel
system
parameters
from
the
certified
configuration.
(ii)
Change
any
other
emission
related
components.
(iii)
Modify
or
design
the
engine
cooling
system
so
that
temperatures
or
heat
rejection
rates
are
outside
the
original
engine's
specified
ranges.
(3)
You
must
make
sure
the
engine
has
the
emission
label
we
require
under
40
CFR
part
90
or
part
1051.
(4)
You
must
make
sure
that
fewer
than
50
percent
of
the
engine
model'stotal
sales,
from
all
companies,
are
used
in
highway
motorcycles.
(d)
If
you
produce
only
the
engine,
give
motorcycle
manufacturers
anynecessary
instructions
regarding
what
they
may
or
may
not
change
under
paragraph
(c)(
2)
of
this
section.
(e)
If
you
produce
both
the
engine
and
motorcycle
under
this
exemption,
you
must
do
all
of
the
following
to
keep
the
exemption
valid:
(1)
Make
sure
the
original
emission
label
is
intact.
(2)
Add
a
permanent
supplemental
label
to
the
engine
in
a
position
where
it
will
remain
clearly
visible
after
installation
in
the
vehicle.
In
your
engine's
emission
label,
do
the
following:
(i)
Include
the
heading:
``
Highway
Motorcycle
Emission
ControlInformation''.
(ii)
Include
your
full
corporate
name
and
trademark.
(iii)
State:
``
THIS
ENGINE
WAS
ADAPTED
FOR
HIGHWAY
USE
WITHOUT
AFFECTING
ITS
EMISSION
CONTROLS.
''.
(iv)
State
the
date
you
finished
installation
(month
and
year).
(3)
Send
the
Designated
Officer
a
signed
letter
by
the
end
of
each
calendar
year
(or
less
often
if
we
tell
you)
with
all
the
following
information:
(i)
Identify
your
full
corporate
name,
address,
and
telephone
number.
(ii)
List
the
models
you
expect
to
produce
under
this
exemption
in
the
coming
year.
(iii)
State:
``
We
produce
each
listed
model
as
a
highway
motorcycle
without
making
any
changes
that
could
increase
its
certified
emission
levels,
as
described
in
40
CFR
86.447.''.
(f)
If
your
vehicles
do
not
meet
the
criteria
listed
in
paragraph
(c)
of
this
section,
they
will
be
subject
to
the
standards
and
prohibitions
of
this
part.
Producing
these
vehicles
without
a
valid
exemption
or
certificate
of
conformity
would
violate
the
prohibitions
in
Clean
Air
Act
section
203
(42
U.
S.
C.
7522).
(g)
If
we
request
it,
you
must
send
us
emission
test
data
on
the
duty
cycle
for
Class
I
motorcycles.
You
may
include
the
data
in
your
application
for
certification
or
in
your
letter
requesting
the
exemption.
(h)
Vehicles
exempted
under
this
section
are
subject
to
all
the
requirements
affecting
engines
and
vehicles
under
40
CFR
part
90
or
part
1051,
as
applicable.
The
requirements
and
restrictions
of
40
CFR
part
90
or
1051
apply
to
anyone
manufacturing
these
engines,
anyone
manufacturing
vehicles
that
use
these
engines,
and
all
other
persons
in
the
same
manner
as
if
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Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
these
engines
were
used
in
a
nonroad
application.
9.
A
new
§
86.448Ð
2006
is
added
to
subpart
E
to
read
as
follows:
§
86.448–
2006
What
are
the
provisions
for
producing
motorcycles
under
50
cc
with
engines
already
certified
under
other
programs?
(a)
You
may
produce
a
highway
motorcycle
under
50
cc
using
a
nonroad
engine
if
you
meet
three
criteria:
(1)
The
engine
or
vehicle
is
certified
to
40
CFR
part
90
or
part
1051.
(2)
The
engine
is
not
adjusted
outside
the
manufacturer's
specifications,
as
described
in
§
86.447Ð
2006(
c)(
2)
and
(d).
(3)
The
engine
or
vehicle
is
not
modified
in
any
way
that
may
affect
its
emission
control.
(b)
This
section
does
not
apply
if
you
manufacture
the
engine
yourself;
see
§
86.447Ð
2006.
10.
A
new
§
86.449
is
added
to
subpart
E
to
read
as
follows:
§
86.449
Averaging
provisions.
(a)
Compliance
with
the
HC+
NOX
standards
set
forth
in
§
86.410Ð
2006(
a)(
2)
may
be
demonstrated
using
the
averaging
provisions
of
this
section.
To
do
this
you
must
show
that
your
average
emission
levels
are
at
or
below
the
applicable
standards
in
§
86.410Ð
2006.
Family
emission
limits
(FELs)
may
not
exceed
5.0
g/
km.
(b)
Do
not
include
any
exported
vehicles
in
the
certification
averaging
program.
Include
only
motorcycles
certified
under
this
subpart.
(c)
To
use
the
averaging
program,
do
the
following
things:
(1)
Certify
each
vehicle
to
a
family
emission
limit.
(2)
Calculate
a
preliminary
average
emission
level
according
to
paragraph
(d)
of
this
section
using
projected
production
volumes
for
your
application
for
certification.
(3)
After
the
end
of
your
model
year,
calculate
a
final
average
emission
level
according
to
paragraph
(d)
of
this
section
for
each
type
of
recreational
vehicle
or
engine
you
manufacture
or
import.
Use
actual
production
volumes.
(d)
Calculate
your
average
emission
level
for
each
type
of
recreational
vehicle
or
engine
for
each
model
year
according
to
the
following
equation
and
round
it
to
the
nearest
tenth
of
a
g/
km.
Use
consistent
units
throughout
the
calculation.
(1)
Calculate
the
average
emission
level
as:
Emission
level
=
FEL
Production
UL
i
i
i
(
)
×
(
)
×
(
)
(
)
×
(
)
UL
oduction
i
i
i
i
Pr
Where:
FELi
=
The
FEL
to
which
the
engine
family
is
certified.
ULi
=
The
useful
life
of
the
engine
family.
Productioni
=
The
number
of
vehicles
in
the
engine
family.
(2)
Use
production
projections
for
initial
certification,
and
actual
production
volumes
to
determine
compliance
at
the
end
of
the
model
year.
(e)(
1)
Maintain
and
keep
five
types
of
properly
organized
and
indexed
records
for
each
group
and
for
each
emission
family:
(i)
Model
year
and
EPA
emission
family.
(ii)
FEL.
(iii)
Useful
life.
(iv)
Projected
production
volume
for
the
model
year.
(v)
Actual
production
volume
for
the
model
year.
(2)
Keep
paper
records
of
this
information
for
three
years
from
the
due
date
for
the
end
of
year
report.
You
may
use
any
additional
storage
formats
or
media
if
you
like.
(3)
Follow
paragraphs
(f)
through
(i)
of
this
section
to
send
us
the
information
you
must
keep.
(4)
We
may
ask
you
to
keep
or
send
other
information
necessary
to
implement
this
subpart.
(f)
Include
the
following
information
in
your
applications
for
certification:
(1)
A
statement
that,
to
the
best
of
your
belief,
you
will
not
have
a
negative
credit
balance
for
any
type
of
recreational
vehicle
or
engine
when
all
credits
are
calculated.
This
means
that
if
you
believe
that
your
average
emission
level
will
be
above
the
standard
(i.
e.,
that
you
will
have
a
deficit
for
the
model
year),
you
must
have
banked
credits
pursuant
to
paragraph
(j)
of
this
section
to
offset
the
deficit.
(2)
Detailed
calculations
of
projected
emission
credits
(zero,
positive,
or
negative)
based
on
production
projections.
If
you
project
a
credit
deficit,
state
the
source
of
credits
needed
to
offset
the
credit
deficit.
(g)
At
the
end
of
each
model
year,
send
an
end
of
year
report.
(1)
Make
sure
your
report
includes
three
things:
(i)
Calculate
in
detail
your
average
emission
level
and
any
emission
credits
based
on
actual
production
volumes.
(ii)
If
your
average
emission
level
is
above
the
allowable
average
standard,
state
the
source
of
credits
needed
to
offset
the
credit
deficit.
(2)
Base
your
production
volumes
on
the
point
of
first
retail
sale.
This
point
is
called
the
final
product
purchase
location.
(3)
Send
end
of
year
reports
to
the
Designated
Officer
within
120
days
of
the
end
of
the
model
year.
If
you
send
reports
later,
you
are
violating
the
Clean
Air
Act.
(4)
If
you
generate
credits
for
banking
pursuant
to
paragraph
(j)
of
this
section
and
you
do
not
send
your
end
of
year
reports
within
120
days
after
the
end
of
the
model
year,
you
may
not
use
or
trade
the
credits
until
we
receive
and
review
your
reports.
You
may
not
use
projected
credits
pending
our
review.
(5)
You
may
correct
errors
discovered
in
your
end
of
year
report,
including
errors
in
calculating
credits
according
to
the
following
table:
If.
.
.
And
if.
.
.
Then
we
.
.
.
(i)
Our
review
discovers
an
error
in
your
end
of
year
report
that
increases
your
credit
bal
ance.
the
discovery
occurs
within
180
days
of
re
ceipt.
restore
the
credits
for
your
use.
(ii)
You
discover
an
error
in
your
report
that
increases
your
credit
balance.
the
discovery
occurs
within
180
days
of
re
ceipt.
restore
the
credits
for
your
use.
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/
Proposed
Rules
If.
.
.
And
if.
.
.
Then
we
.
.
.
(iii)
We
or
you
discover
an
error
in
your
report
that
increases
your
credit
balance.
the
discovery
occurs
more
than
180
days
after
receipt.
do
not
restore
the
credits
for
your
use.
(iv)
We
discover
an
error
in
your
report
that
reduces
your
credit
balance.
at
any
time
after
receipt
.................................
reduce
your
credit
balance.
(h)
Include
in
each
report
a
statement
certifying
the
accuracy
and
authenticity
of
its
contents.
(i)
We
may
void
a
certificate
of
conformity
for
any
emission
family
if
you
do
not
keep
the
records
this
section
requires
or
give
us
the
information
when
we
ask
for
it.
(j)
You
may
include
motorcycles
that
you
certify
with
HC+
NOX
emissions
below
0.8
g/
km
in
the
following
optional
early
banking
program:
(1)
To
include
a
motorcycle
in
the
early
banking
program,
assign
it
an
emission
rate
of
0.8
g/
km
when
calculating
your
average
emission
level
for
compliance
with
the
Tier
1
standards.
(2)(
i)
Calculate
bankable
credits
from
the
following
equation:
Bonus
credit
=
Y
x
[
(0.8
g/
kmÑ
Certfied
emission
level)
]x
[(
Production
volume
of
engine
family)
x
(Useful
life)
]
(ii)
The
value
of
Y
is
defined
by
the
model
year
and
emission
level,
as
shown
in
the
following
table:
Model
year
Multiplier
(Y)
for
use
in
MY
2010
or
later
corporate
averaging
If
your
certified
emission
level
is
less
than
0.8
g/
km,
but
greater
than
0.4
g/
km,
then
Y
=
.
.
.
If
your
certified
emission
level
is
less
than
0.4
g/
km,
then
Y
=
.
.
.
2003
through
2006
................................................................................................................
1.5
3.0
2007
.......................................................................................................................................
1.375
2.5
2008
.......................................................................................................................................
1.250
2.0
2009
.......................................................................................................................................
1.125
1.5
(3)
Credits
banked
under
this
paragraph
(j)
may
be
used
for
compliance
with
any
2010
or
later
model
year
standards
as
follows:
(i)
If
your
average
emission
level
is
above
the
average
standard,
calculate
your
credit
deficit
according
to
the
following
equation,
rounding
to
the
nearest
tenth
of
a
gram:
Deficit
=
(Emission
Level
¥
Average
Standard)
x
(Total
Annual
Production)
(ii)
Credits
deficits
may
be
offset
using
banked
credits.
Subpart
F—[
Amended]
11.
A
new
§
86.513Ð
2004
is
added
to
subpart
F
to
read
as
follows:
§
86.513–
2004
Fuel
and
engine
lubricant
specifications.
Section
86.513Ð
2004
includes
text
that
specifies
requirements
that
differ
from
§
86.513Ð
94.
Where
a
paragraph
in
§
86.513Ð
94
is
identical
and
applicable
to
§
86.513Ð
2004,
this
may
be
indicated
by
specifying
the
corresponding
paragraph
and
the
statement
``[
Reserved].
For
guidance
see
§
86.513Ð
94.''
Where
a
corresponding
paragraph
of
§
86.513Ð
94
is
not
applicable,
this
is
indicated
by
the
statement
``[
Reserved].
''
(a)
Gasoline.
(1)
Gasoline
having
the
following
specifications
will
be
used
by
the
Administrator
in
exhaust
emission
testing
of
gasoline
fueled
motorcycles.
Gasoline
having
the
following
specifications
or
substantially
equivalent
specifications
approved
by
the
Administrator,
shall
be
used
by
the
manufacturer
for
emission
testing
except
that
the
octane
specifications
do
not
apply.
TABLE
1
OF
§
86.513–
2004.—
GASOLINE
TEST
FUEL
SPECIFICATIONS
Item
Procedure
Value
Distillation
Range:
1.
Initial
boiling
point,
°
C
.................................................................................
ASTM
D
86–
97
...........................
23.9—
35.0.
1
2.
10%
point,
°
C
..............................................................................................
ASTM
D
86–
97
...........................
48.9—
57.2
3.
50%
point,
°
C
..............................................................................................
ASTM
D
86–
97
...........................
93.3—
110.0.
4.
90%
point,
°
C
..............................................................................................
ASTM
D
86–
97
...........................
148.9—
162.8.
5.
End
point,
°
C
...............................................................................................
ASTM
D
86–
97
...........................
212.8.
Hydrocarbon
composition:
1.
Olefins,
volume
%
.......................................................................................
ASTM
D
1319–
98
.......................
10
maximum.
2.
Aromatics,
volume
%
..................................................................................
ASTM
D
1319–
98
.......................
35
minimum.
3.
Saturates
.....................................................................................................
ASTM
D
1319–
98
.......................
Remainder.
Lead
(organic),
g/
liter
.............................................................................................
ASTM
D
3237
.............................
0.013
maximum.
Phosphorous,
g/
liter
................................................................................................
ASTM
D
3231
.............................
0.005
maximum.
Sulfur,
weight
%
.....................................................................................................
ASTM
D
1266
.............................
0.08
maximum.
Volatility
(Reid
Vapor
Pressure),
kPa
.....................................................................
ASTM
D
3231
.............................
55.2
to
63.4.
1
1
For
testing
at
altitudes
above
1
219
m,
the
specified
volatility
range
is
52
to
55
kPa
and
the
specified
initial
boiling
point
range
is
23.9
to
40.6
C.
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157
/
Wednesday,
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14,
2002
/
Proposed
Rules
(2)
Unleaded
gasoline
and
engine
lubricants
representative
of
commercial
fuels
and
engine
lubricants
which
will
be
generally
available
though
retail
outlets
shall
be
used
in
service
accumulation.
(3)
The
octane
rating
of
the
gasoline
used
shall
be
no
higher
than
4.0.
Research
octane
numbers
above
the
minimum
recommended
by
the
manufacturer.
(4)
The
Reid
Vapor
Pressure
of
the
gasoline
used
shall
be
characteristic
of
commercial
gasoline
fuel
during
the
season
in
which
the
service
accumulation
takes
place.
(b)
through
(d)
[Reserved].
For
guidance
see
§
86.513Ð
94.
12.
Section
86.544Ð
90
is
amended
by
revising
the
text
preceding
the
formula
to
read
as
follows:
§
86.544–
90
Calculations;
exhaust
emissions.
The
final
reported
text
results,
with
oxides
of
nitrogen
being
optional
for
model
years
prior
to
2006
and
required
for
2006
and
later
model
years,
shall
be
computed
by
use
of
the
following
formula
(The
results
of
all
emission
tests
shall
be
rounded,
in
accordance
with
ASTM
E29Ð
90
(incorporated
by
reference
in
§
86.1),
to
the
number
of
places
to
the
right
of
the
decimal
point
indicated
by
expressing
the
applicable
standard
to
three
significant
figures.):
*
*
*
*
*
Subpart
I
[Amended]
13.
Section
86.884Ð
14
is
amended
by
revising
the
equation
in
paragraph
(a)
to
read
as
follows:
§
86.884–
14
Calculations.
(a)
*
*
*
*
*
*
*
*
N
N/
s
m
=
×
(
)
(
)
100
1
1
100
L
L
s
m
/
PART
90—
CONTROL
OF
EMISSIONS
FROM
NONROAD
SPARK
IGNITION
ENGINES
14.
The
authority
for
part
90
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7521,
7522,
7523,
7524,
7525,
7541,
7542,
7543,
7547,
7549,
7550,
and
7601(
a).
Subpart
A—[
Amended]
15.
Section
90.1
as
proposed
at
66
FR
51181
is
amended
by
adding
a
new
paragraph
(f)
to
read
as
follows:
§
90.1
Applicability.
*
*
*
*
*
(f)
This
part
also
applies
to
engines
under
50
cc
used
in
highway
motorcycles
if
the
manufacturer
uses
the
provisions
of
40
CFR
86.447Ð
2006
to
meet
the
emission
standards
in
this
part
instead
of
the
requirements
of
40
CFR
part
86.
Compliance
with
the
provisions
of
this
part
is
a
required
condition
of
that
exemption.
Subchapter
U—
Air
Pollution
Controls
16.
Part
1045
is
added
to
subchapter
U
as
proposed
at
66
FR
51189
to
read
as
follows:
PART
1045—
CONTROL
OF
EMISSIONS
FROM
SPARK
IGNITION
MARINE
VESSELS
Subpart
A—
Determining
How
to
Follow
This
Part
Sec.
1045.1
Does
this
part
apply
to
me?
1045.5
Are
any
of
my
vessels
excluded
from
the
requirements
of
this
part?
1045.10
What
main
steps
must
I
take
to
comply
with
this
part?
1045.15
Do
any
other
regulation
parts
affect
me?
1045.20
Can
I
certify
just
the
fuel
system
instead
of
the
entire
vessel?
Subpart
B—
Emission
Standards
and
Related
Requirements
1045.105
What
evaporative
emission
standards
must
my
vessels
meet?
1045.115
What
other
requirements
must
my
vessels
meet?
1045.120
What
warranty
requirements
apply
to
me?
1045.125
What
maintenance
instructions
must
I
give
to
buyers?
1045.130
What
installation
instructions
must
I
give
to
vessel
manufacturers?
1045.135
How
must
I
label
and
identify
the
vessels
and
fuel
systems
I
produce?
1045.140
What
interim
provisions
apply
only
for
a
limited
time?
1045.145
What
provisions
apply
to
noncertifying
manufacturers?
Subpart
C—
Certifying
Emission
Families
1045.201
What
are
the
general
requirements
for
submitting
a
certification
application?
1045.205
How
must
I
prepare
my
application?
1045.215
What
happens
after
I
complete
my
application?
1045.225
How
do
I
amend
my
application
to
include
a
new
or
modified
product?
1045.230
How
do
I
select
emission
families?
1045.235
How
does
testing
fit
with
my
application
for
a
certificate
of
conformity?
1045.240
How
do
I
determine
if
my
emission
family
complies
with
emission
standards?
1045.245
What
records
must
I
keep
and
make
available
to
EPA?
1045.250
When
may
EPA
deny,
revoke,
or
void
my
certificate
of
conformity?
Subpart
D—[
Reserved]
Subpart
E—
Testing
In
use
Engines
1045.401
What
provisions
apply
for
in
use
testing
of
vessels?
Subpart
F—
Test
Procedures
1045.501
What
equipment
and
general
procedures
must
I
use
to
test
my
vessels?
1045.505
How
do
I
test
for
diurnal
evaporative
emissions?
1045.506
How
do
I
test
my
fuel
tank
for
permeation
emissions?
Subpart
G—
Compliance
Provisions
1045.601
What
compliance
provisions
apply
to
these
vessels?
Subpart
H—
Averaging,
Banking,
and
Trading
for
Certification
1045.701
General
provisions.
1045.705
How
do
I
average
emission
levels?
1045.710
How
do
I
generate
and
bank
emission
credits?
1045.715
How
do
I
trade
or
transfer
emission
credits?
1045.720
How
do
I
calculate
my
average
emission
level
or
emission
credits?
1045.725
What
information
must
I
keep?
1045.730
What
information
must
I
report?
Subpart
I—
Definitions
and
Other
Reference
Information
1045.801
What
definitions
apply
to
this
part?
1045.805
What
symbols,
acronyms,
and
abbreviations
does
this
part
use?
1045.810
What
materials
does
this
part
reference?
1045.815
How
should
I
request
EPA
to
keep
my
information
confidential?
1045.820
How
do
I
request
a
public
hearing?
Authority:
42
U.
S.
C.
7401Ð
7671(
q).
Subpart
A—
Determining
How
To
Follow
This
Part
§
1045.1
Does
this
part
apply
to
me?
(a)
This
part
applies
to
you
if
you
manufacture
or
import
new
sparkignition
marine
vessels
(defined
in
§
1045.801)
or
part
of
a
fuel
system
for
such
vessels
(defined
in
§
1045.801),
unless
we
exclude
the
vessels
under
§
1045.5.
You
should
read
§
1045.145
to
determine
whether
we
require
all
manufacturers
to
meet
a
specific
requirement.
(b)
See
40
CFR
part
90
to
meet
exhaust
emission
requirements
for
spark
ignition
marine
engines.
Note
that
40
CFR
part
90
does
not
apply
to
all
spark
ignition
marine
engines.
(c)
Note
in
subpart
G
of
this
part
that
40
CFR
part
1068
applies
to
everyone,
including
anyone
who
manufactures,
owns,
operates,
or
repairs
any
of
the
vessels
this
part
covers.
(d)
You
need
not
follow
this
part
for
vessels
produced
before
the
2008
model
year,
unless
you
certify
voluntarily.
See
§
1045.105,
§
1045.145,
and
the
definition
of
model
year
in
§
1045.801
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Federal
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/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
for
more
information
about
the
timing
of
new
requirements.
(e)
See
§§
1045.801
and
1045.805
for
definitions
and
acronyms
that
apply
to
this
part.
(f)
For
now,
ignore
references
to
engines,
which
will
apply
when
we
establish
exhaust
emission
standards
in
this
part
for
spark
ignition
marine
engines.
§
1045.5
Are
any
of
my
vessels
excluded
from
the
requirements
of
this
part?
(a)
The
requirements
of
this
part
do
not
apply
to
either
of
two
types
of
marine
vessels:
(1)
Hobby
vessels.
(2)
Vessels
fueled
with
diesel
fuel,
LPG,
natural
gas,
or
other
fuel
that
is
not
a
volatile
liquid
fuel.
(b)
See
part
1068,
subpart
C,
of
this
chapter
for
exemptions
of
specific
vessels.
(c)
We
may
require
you
to
label
a
vessel
if
this
section
excludes
it
and
other
requirements
in
this
chapter
do
not
apply
(for
example,
hobby
vessels).
(d)
Send
the
Designated
Officer
a
written
request
with
supporting
documentation
if
you
want
us
to
determine
whether
this
part
covers
or
excludes
certain
vessels.
Excluding
engines
from
this
part's
requirements
does
not
affect
other
requirements
that
may
apply
to
them.
§
1045.10
What
main
steps
must
I
take
to
comply
with
this
part?
(a)
Every
new
vessel
subject
to
the
standards
in
this
part
must
be
covered
by
a
certificate
of
conformity
before
it
is
sold,
offered
for
sale,
introduced
into
commerce,
distributed
or
delivered
for
introduction
into
commerce,
or
imported
into
the
United
States.
For
evaporative
emissions,
either
the
vessel
manufacturer
or
the
fuel
system
manufacturer
must
apply
for
a
certificate
of
conformity
for
each
new
model
year.
(b)
To
get
a
certificate
of
conformity
and
comply
with
its
terms,
you
must
do
three
things:
(1)
Show
that
each
vessel
will
meet
one
of
the
individual
emission
standards
and
other
requirements
in
subpart
B
of
this
part.
You
may
also
need
to
meet
a
corporate
average
emission
standard
(see
§
1045.105).
(2)
Apply
for
certification
(see
subpart
C
of
this
part).
(3)
Follow
our
instructions
throughout
this
part.
(c)
Subpart
F
of
this
part
and
40
CFR
part
86
describe
the
procedures
you
must
follow
to
test
your
vessels.
Subpart
F
of
this
part
and
§
1045.20
describe
cases
for
which
you
may
test
the
fuel
system
alone
instead
of
testing
the
entire
vessel.
(d)
Subpart
G
of
this
part
and
40
CFR
part
1068
of
this
chapter
describe
requirements
and
prohibitions
that
apply
to
manufacturers,
owners,
operators,
repairers,
and
all
others
associated
with
spark
ignition
marine
vessels.
§
1045.15
Do
any
other
regulation
parts
affect
me?
(a)
Part
86
of
this
chapter
describes
how
to
measure
evaporative
emissions.
Subpart
F
of
this
part
describes
how
to
apply
part
86
of
this
chapter
to
show
you
meet
this
part's
emission
standards.
(b)
Part
1068
of
this
chapter
describes
general
provisions,
including
these
seven
areas:
(1)
Prohibited
acts
and
penalties
for
manufacturers
and
others.
(2)
Rebuilding
and
other
aftermarket
changes.
(3)
Exemptions
for
certain
vessels.
(4)
Importing
vessels.
(5)
Selective
enforcement
audits
of
your
production.
(6)
Defect
reporting
and
recall.
(7)
Procedures
for
public
hearing.
(c)
Other
parts
of
this
chapter
affect
you
if
referenced
in
this
part.
§
1045.20
Can
I
certify
just
the
fuel
system
instead
of
the
entire
vessel?
(a)
You
may
certify
only
the
fuel
system
if
you
manufacture
part
or
all
of
the
system
for
a
vessel.
Vessels
using
certified
fuel
systems
do
not
need
to
be
certified
separately.
(b)
If
you
certify
a
fuel
system,
you
must
do
two
things:
(1)
Use
good
engineering
judgment
to
ensure
the
engine
will
comply
with
emission
standards
after
it
is
installed
in
a
vessel.
(2)
Comply
with
§
1045.130.
(c)
Do
not
use
the
provisions
of
this
section
to
circumvent
emission
standards
or
other
requirements
of
this
part.
Subpart
B—
Emission
Standards
and
Related
Requirements
§
1045.105
What
evaporative
emission
standards
must
my
vessels
meet?
Beginning
January
1,
2008,
each
new
vessel
and
new
portable
fuel
tank
must
be
certified
to
the
emission
standards
of
paragraphs
(a)
and
(b)
of
this
section
(except
as
allowed
by
paragraph
(c)
of
this
section).
Vessel
manufacturers
may
certify
vessels
directly
or
use
fuel
systems
certified
by
fuel
system
manufacturers.
(a)
Diurnal
Emissions.
Diurnal
emissions
from
your
vessel
may
not
exceed
1.1
grams
per
gallon
per
day
as
measured
according
to
the
diurnal
evaporative
test
procedures
in
subpart
F
of
this
part.
You
may
use
the
averaging
provisions
in
Subpart
H
of
this
part
to
show
you
meet
the
standards
of
this
paragraph
(a).
Emission
standards
described
in
this
paragraph
apply
to
marine
vessels
with
installed
fuel
tanks;
they
do
not
apply
to
portable
fuel
tanks,
which
are
addressed
in
paragraph
(c)
of
this
section.
(b)
Permeation
emissions.
Permeation
emissions
may
not
exceed
the
following
standards:
(1)
Permeation
emissions
from
your
vessel's
fuel
tank(
s)
may
not
exceed
0.08
grams
per
gallon
per
day
as
measured
according
to
the
tank
permeation
test
procedures
in
subpart
F
of
this
part.
(2)
Permeation
emissions
from
your
vessel's
fuel
lines
may
not
exceed
5
grams
per
square
meter
per
day
as
measured
according
to
the
fuel
line
permeation
test
procedures
in
subpart
F
of
this
part.
Use
the
inside
diameter
of
the
hose
to
determine
the
surface
area
of
the
hose.
(c)
You
may
certify
portable
fuel
tanks
to
the
diurnal
emission
standards
in
paragraph
(a)
of
this
section
by
meeting
the
following
design
criteria:
(1)
The
tank
may
include
no
more
than
two
vents,
which
must
be
readily
sealable
for
pressures
up
3
psig.
(2)
All
vents
and
the
fuel
line
connection
to
the
engine
must
seal
automatically
when
disconnected.
(d)
You
may
certify
vessels
and
fuel
systems
using
the
control
technologies
shown
in
the
following
tables
``
by
design.
''
This
means
the
design
of
these
technologies
certifies
them
to
the
standards
specified
in
paragraph
(a)
of
this
section:
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2002
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Proposed
Rules
TABLE
1
OF
§
1045.105.—
DIURNAL
LEVELS
FOR
DESIGN
CERTIFICATION
If
the
diurnal
control
technology
is
.
.
.
Then
you
may
design
certify
with
a
diurnal
emission
level
of
.
.
.
1.
Open
vented
fuel
tank
................................................................................................................................................
1.5
g/
gal/
test.
2.
A
sealed
fuel
tank
with
a
pressure
relief
valve
that
would
open
at
a
pressure
of
0.5
psi
........................................
1.3
g/
gal/
test.
3.
A
sealed
insulated
fuel
tank
(R
value
of
15
or
better)
with
a
limited
flow
orifice
with
a
maximum
cross
sectional
area
defined
by
the
following
equation:
Area
in
mm
2
=
0.04
×
fuel
tank
capacity
in
gallons
(Example:
A
20
gallon
tank
with
an
orifice
no
more
than
1.0
mm
in
diameter.)
1.3
g/
gal/
test.
4.
A
sealed
fuel
tank
with
a
pressure
relief
valve
that
would
open
at
a
pressure
of
1.0
psi
........................................
1.1
g/
gal/
test.
5.
A
sealed
fuel
tank
with
a
pressure
relief
valve
that
would
open
at
a
pressure
of
1.5
psi
........................................
0.9
g/
gal/
test.
6.
A
sealed
fuel
tank
with
a
pressure
relief
valve
that
would
open
at
a
pressure
of
2.0
psi
........................................
0.7
g/
gal/
test.
7.
A
sealed
fuel
tank
with
a
pressure
relief
valve
that
would
open
at
a
pressure
of
0.5
psi,
and
with
a
volume
compensating
bag
made
from
a
low
permeability
material
1
with
a
bag
volume
equal
to
at
least
25
percent
of
the
volume
of
the
fuel
tank.
0.5
g/
gal/
test.
8.
A
sealed
bladder
fuel
tank
made
from
a
low
permeability
........................................................................................
0.1
g/
gal/
test.
1
Permeability
of
5
g/
m
2
/day
or
less.
TABLE
2
OF
§
1045.105.—
TANK
PERMEATION
LEVELS
FOR
DESIGN
CERTIFICATION
If
the
tank
permeability
control
technology
is
.
.
.
Then
you
may
design
certify
with
a
tank
emission
level
of
.
.
.
1.
A
metal
fuel
tank
with
no
non
metal
gaskets
or
with
gaskets
made
from
a
low
permeability
material
1
..................
0.08
g/
gal/
test
day.
2.
A
metal
fuel
tank
with
non
metal
gaskets
with
an
exposed
surface
area
of
1000
mm
2
or
less
...............................
0.08
g/
gal/
test
day.
1
Permeability
of
10
g/
m
2
/day
or
less.
TABLE
3
OF
§
1045.105.—
FUEL
AND
VENT
LINE
PERMEATION
LEVELS
FOR
DESIGN
CERTIFICATION
If
the
fuel
line
and
vent
line
permeability
control
technology
is
.
.
.
Then
you
may
design
certify
with
a
fuel
line
permeation
emission
level
of
.
.
.
Hose
meeting
SAE
2260
Category
1
permeation
level
1
...............................................................................................
5
g/
m
2
/test
day.
1
Hose
must
also
meet
U.
S.
Coast
Guard
Regulations.
(e)
We
may
establish
additional
design
certification
options
based
on
test
data.
§
1045.115
What
other
requirements
must
my
vessels
meet?
(a)
through
(d)
[Reserved]
(e)
Prohibited
controls.
You
may
not
do
either
of
the
following
things:
(1)
You
may
not
design
engines
or
vessels
with
an
emission
control
system
that
emits
any
noxious
or
toxic
substance
that
the
engine
would
not
emit
during
operation
in
the
absence
of
such
a
system,
except
as
specifically
permitted
by
regulation.
(2)
You
may
not
design
engines
or
vessels
with
an
emission
control
system
that
is
unsafe.
For
example,
emission
controls
must
comply
with
all
applicable
U.
S.
Coast
Guard
regulations.
(f)
Defeat
devices.
You
may
not
equip
your
vessels
with
a
defeat
device.
A
defeat
device
is
an
auxiliary
emission
control
device
or
other
control
feature
that
degrades
emission
controls
under
conditions
you
may
reasonably
expect
the
vessel
to
encounter
during
normal
operation
and
use.
(g)
Evaporative
technology.
Make
sure
(by
testing
or
engineering
analysis)
that
technologies
used
to
meet
evaporative
emission
standards
keep
working
for
at
least
30
days
while
the
boat
or
engine
is
not
used.
Design
them
to
last
for
the
full
useful
life.
The
useful
life
for
evaporative
controls
is
ten
years.
(h)
Fuel
tank
location.
The
test
procedures
in
subpart
F
of
this
part
do
not
represent
the
experience
of
a
vessel
with
the
fuel
tank
exposed
to
direct
sunlight
(sun
exposure
can
cause
much
greater
fuel
temperature
swings,
which
would
increase
evaporative
emissions).
If
you
design
your
vessel
this
way,
you
must
show
that
you
meet
emission
standards
by
measuring
emissions
with
a
test
that
incorporates
the
effect
of
the
sun's
radiant
heat.
Note:
This
requirement
does
not
apply
to
portable
fuel
tanks.
§
1045.120
What
warranty
requirements
apply
to
me?
(a)
You
must
warrant
to
the
ultimate
buyer
that
the
new
vessel
meets
two
conditions:
(1)
You
have
designed,
built,
and
equipped
it
to
meet
the
requirements
of
this
part.
(2)
It
is
free
from
defects
in
materials
and
workmanship
that
may
keep
it
from
meeting
these
requirements.
(b)
Your
emission
related
warranty
for
evaporative
controls
must
be
valid
for
at
least
50
percent
of
the
useful
life
in
years.
You
may
offer
a
warranty
more
generous
than
we
require.
This
warranty
may
not
be
shorter
than
any
published
or
negotiated
warranty
you
offer
for
the
vessel
or
any
of
its
components.
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Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
§
1045.125
What
maintenance
instructions
must
I
give
to
buyers?
Give
the
ultimate
buyer
of
each
new
vessel
written
instructions
for
properly
maintaining
and
using
the
vessel,
including
the
emission
control
system.
§
1045.130
What
installation
instructions
must
I
give
to
vessel
manufacturers?
(a)
If
you
sell
a
certified
fuel
system
for
someone
else
to
install
in
a
sparkignition
marine
vessel,
give
the
buyer
of
the
fuel
system
written
instructions
for
installing
it
consistent
with
the
requirements
of
this
part.
Make
sure
these
instructions
have
the
following
information:
(1)
Include
the
heading:
``
Emissionrelated
installation
instructions.
''
(2)
State:
``
Failing
to
follow
these
instructions
when
installing
a
certified
fuel
system
in
a
spark
ignition
marine
vessel
violates
federal
law
(40
CFR
1068.105(
b)),
subject
to
fines
or
other
penalties
as
described
in
the
Clean
Air
Act.
''.
(3)
Describe
any
other
instructions
to
make
sure
the
installed
fuel
system
will
operate
according
to
design
specifications
in
your
application
for
certification.
(4)
State:
``
If
you
obscure
the
fuel
system's
emission
label,
you
must
attach
a
duplicate
label
to
your
vessel,
as
described
in
40
CFR
1068.105.''.
(b)
You
do
not
need
installation
instructions
for
fuel
systems
you
install
in
your
own
vessel.
§
1045.135
How
must
I
label
and
identify
the
vessels
and
fuel
systems
I
produce?
(a)
[Reserved]
(b)
At
the
time
of
manufacture,
add
a
permanent
label
identifying
each
tank.
To
meet
labeling
requirements,
do
three
things:
(1)
Attach
the
label
in
one
piece
so
it
is
not
removable
without
being
destroyed
or
defaced.
(2)
Design
and
produce
it
to
be
durable
and
readable
for
the
vessel's
entire
life.
(3)
Write
it
in
block
letters
in
English.
(c)
On
your
fuel
tank
label,
do
ten
things:
(1)
Include
the
heading
``
EMISSION
CONTROL
INFORMATION.
''
(2)
Include
your
full
corporate
name
and
trademark.
(3)
State:
``
THIS
VESSEL
IS
CERTIFIED
TO
OPERATE
ON
[specify
operating
fuel
or
fuels].
''.
(4)
State
the
date
of
manufacture
[DAY
(optional),
MONTH,
and
YEAR].
(5)
State:
``
THIS
VESSEL
MEETS
U.
S.
ENVIRONMENTAL
PROTECTION
AGENCY
REGULATIONS
FOR
[MODEL
YEAR]
VESSELS].
''.
(6)
Include
EPA's
standardized
designation
for
the
emission
family.
(7)
Include
the
model
number
(or
part
number)
of
the
fuel
tank.
(8)
Include
the
part
number(
s)
of
the
fuel
lines.
(9)
Include
the
fuel
tank
capacity
in
U.
S.
gallons.
(10)
Describe
other
information
on
proper
maintenance
and
use.
(11)
Identify
any
other
emission
standards
to
which
you
have
certified
the
vessel.
(d)
You
may
combine
the
EPA
emission
control
label
with
the
label
required
by
the
U.
S.
Coast
Guard.
If
you
are
unable
to
meet
the
exact
labeling
requirements
described
in
paragraph
(c)
of
this
section
for
your
combined
label,
you
may
ask
us
to
modify
the
requirements
consistent
with
the
intent
of
this
section.
(e)
Some
vessels
may
not
have
enough
space
for
a
label
with
all
the
required
information.
In
this
case,
we
may
allow
you
to
omit
some
of
the
information
required
if
you
print
it
in
the
owner's
manual
instead.
(f)
If
you
are
unable
to
meet
these
labeling
requirements,
you
may
ask
us
to
modify
them
consistent
with
the
intent
of
this
section.
(g)
If
you
obscure
the
fuel
tank
label
while
installing
the
tank
in
the
vessel,
you
must
place
a
duplicate
label
on
the
vessel.
If
someone
else
installs
the
fuel
tank
in
a
vessel,
give
them
duplicate
labels
if
they
ask
for
them
(see
40
CFR
1068.105).
(h)
Non
metallic
fuel
lines
must
be
labeled
with
the
name
of
the
fuel
line
manufacturer
and
with
a
permeability
classification.
§
1045.140
What
interim
provisions
apply
only
for
a
limited
time?
From
2004
to
2007,
if
you
certify
to
an
FEL
below
the
average
standard
in
§
1045.105(
a),
you
may
generate
early
credits.
Calculate
credits
according
to
§
1045.720(
b)
by
replacing
``
Average
Standard''
with
1.1
g/
gallon
and
``
Emission
Level''
with
the
FEL
to
which
the
emission
family
is
certified.
§
1045.145
What
provisions
apply
to
noncertifying
manufacturers?
(a)
General
requirements.
The
following
general
requirements
apply
to
non
certifying
manufacturers:
(1)
Every
manufacturer
is
responsible
for
compliance
with
the
requirements
of
this
part
that
apply
to
manufacturers.
However,
if
one
manufacturer
complies
with
a
requirement,
then
we
will
consider
all
manufacturers
to
have
complied
with
that
specific
requirement.
(2)
Where
more
than
one
entity
meets
the
definition
of
manufacturer
for
a
particular
vessel
and
any
one
of
the
manufacturers
obtains
a
certificate
of
conformity
covering
the
whole
vessel,
the
requirements
of
subparts
C
and
H
of
this
part
and
subparts
E
and
F
of
part
1068
of
this
chapter
apply
to
the
manufacturer
that
holds
the
certificate
of
conformity.
Other
manufacturers
must
meet
the
requirements
of
subparts
C
and
H
of
this
part
and
subparts
E
and
F
of
part
1068
of
this
chapter
only
if
we
say
so.
In
this
case,
we
will
allow
a
reasonable
time
to
meet
the
requirements
that
apply.
(b)
Requirements
for
permeability
treatment.
If
you
treat
fuel
tanks
or
fuel
lines
to
reduce
permeability
but
do
not
hold
the
certificate,
you
must
keep
records
of
the
treatment
process
for
three
years
after
the
treatment
occurs.
You
must
make
these
records
available
to
us
if
we
request
them.
(c)
Requirements
for
fuel
system
or
emission
control
components.
If
you
manufacture
a
fuel
system
component
or
an
emission
control
component
or
fuel
lines
used
to
reduce
permeability
but
do
not
hold
the
certificate,
we
may
require
you
to
keep
records
of
your
manufacturing
process
for
three
years
after
the
component
is
manufactured.
You
must
make
these
records
available
to
us
if
we
request
them.
(d)
Requirements
for
emission
test
data.
If
a
certifying
manufacturer
uses
your
emission
test
data
to
certify,
we
may
require
you
to
give
us
a
signed
statement
verifying
that
your
tests
were
conducted
using
the
test
procedures
in
this
part.
Subpart
C—
Certifying
Emission
Families
§
1045.201
What
are
the
general
requirements
for
submitting
a
certification
application?
(a)
Send
us
an
application
for
a
certificate
of
conformity
for
each
emission
family.
Each
application
is
valid
for
only
one
model
year.
(b)
The
application
must
not
include
false
or
incomplete
statements
or
information
(see
§
1045.250).
We
may
choose
to
ask
you
to
send
us
less
information
than
we
specify
in
this
subpart,
but
this
would
not
change
your
recordkeeping
requirements.
(c)
Use
good
engineering
judgment
for
all
decisions
related
to
your
application
(see
§
1068.005
of
this
chapter).
(d)
An
authorized
representative
of
your
company
must
approve
and
sign
the
application.
§
1045.205
How
must
I
prepare
my
application?
In
your
application,
you
must
do
all
the
following
things:
(a)
Describe
the
emission
family's
specifications
and
other
basic
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Proposed
Rules
parameters
of
the
design.
List
the
types
of
fuel
you
intend
to
use
to
certify
the
emission
family
(for
example,
gasoline
or
methanol).
(b)
Explain
how
the
emission
control
system
operates.
Describe
in
detail
all
the
system's
components,
auxiliary
emission
control
devices,
and
all
fuelsystem
components
you
will
install
on
any
production
or
test
system.
Explain
how
you
determined
that
the
emissioncontrol
system
comply
with
the
requirements
of
§
1045.115,
including
why
any
auxiliary
emission
control
devices
are
not
defeat
devices
(see
§
1045.115(
f)).
Do
not
include
detailed
calibrations
for
components
unless
we
ask
for
them.
(c)
Describe
the
vessels,
engines,
tanks,
and/
or
hoses
you
selected
for
testing
and
the
reasons
for
selecting
them.
(d)
Describe
any
special
or
alternate
test
procedures
you
used
(see
§
1045.501).
(e)
[Reserved]
(f)
List
the
specifications
of
the
test
fuel
to
show
that
it
falls
within
the
required
ranges
we
specify
in
40
CFR
part
1065,
subpart
C.
(g)
Identify
the
emission
family's
useful
life.
(h)
Propose
maintenance
and
use
instructions
for
the
ultimate
buyer
(see
§
1045.125).
(i)
Propose
emission
related
installation
instructions
if
you
sell
fuel
systems
for
someone
else
to
install
in
a
vessel
(see
§
1045.130).
(j)
Propose
an
emission
control
label.
(k)
Present
emission
data
for
HC
to
show
you
meet
the
emission
standards
we
specify
in
§
1045.105.
(l)
Report
all
test
results,
including
those
from
invalid
tests
or
from
any
nonstandard
tests.
(m)
[Reserved]
(n)
Describe
all
adjustable
operating
parameters.
(o)
If
you
conducted
testing,
state
that
you
conducted
your
emission
tests
according
to
the
specified
procedures
and
test
parameters
using
the
fuels
described
in
the
application
to
show
you
meet
the
requirements
of
this
part.
(p)
If
you
did
not
conduct
testing,
state
how
your
emission
family
meets
the
requirements
for
design
certification.
(q)
State
unconditionally
that
all
the
vessels
in
the
emission
family
comply
with
the
requirements
of
this
part,
other
referenced
parts,
and
the
Clean
Air
Act
(42
U.
S.
C.
7401
et
seq.).
(r)
Include
estimates
of
vessel
(or
fuel
system)
production.
(s)
Add
other
information
to
help
us
evaluate
your
application
if
we
ask
for
it.
§
1045.215
What
happens
after
I
complete
my
application?
(a)
If
any
of
the
information
in
your
application
changes
after
you
submit
it,
amend
it
as
described
in
§
1045.225.
(b)
We
may
decide
that
we
cannot
approve
your
application
unless
you
revise
it.
(1)
If
you
inappropriately
use
the
provisions
of
§
1045.230(
c)
or
(d)
to
define
a
broader
or
narrower
emission
family,
we
will
require
you
to
redefine
your
emission
family.
(2)
If
your
proposed
label
is
inconsistent
with
§
1045.135,
we
will
require
you
to
change
it
(and
tell
you
how,
if
possible).
(3)
If
you
require
or
recommend
maintenance
and
use
instructions
inconsistent
with
§
1045.125,
we
will
require
you
to
change
them.
(4)
If
we
find
any
other
problem
with
your
application,
we
will
tell
you
how
to
correct
it.
(c)
If
we
determine
your
application
is
complete
and
shows
you
meet
all
the
requirements,
we
will
issue
a
certificate
of
conformity
for
your
emission
family
for
that
model
year.
If
we
deny
the
application,
we
will
explain
why
in
writing.
You
may
then
ask
us
to
hold
a
hearing
to
reconsider
our
decision
(see
§
1045.820).
§
1045.225
How
do
I
amend
my
application
to
include
a
new
or
modified
product?
(a)
You
must
amend
your
application
for
certification
before
you
take
either
of
the
following
actions:
(1)
Add
a
vessel,
engine,
or
fuel
system
to
a
certificate
of
conformity.
(2)
Make
a
design
change
for
a
certified
emission
family
that
may
affect
emissions
or
an
emission
related
part
over
the
lifetime
of
the
vessel,
engine,
or
fuel
system.
(b)
Send
the
Designated
Officer
a
request
to
amend
the
application
for
certification
for
an
emission
family.
In
your
request,
do
all
of
the
following:
(1)
Describe
the
model
or
configuration
you
are
adding
or
changing.
(2)
Include
engineering
evaluations
or
reasons
why
the
original
testing
is
or
is
not
still
appropriate.
(3)
If
the
original
testing
for
the
emission
family
is
not
appropriate
to
show
compliance
for
the
new
or
modified
vessel,
include
new
test
data
showing
that
the
new
or
modified
product
meets
the
requirements
of
this
part.
(c)
You
may
start
producing
the
new
or
modified
product
anytime
after
you
send
us
your
request.
(d)
You
must
give
us
test
data
within
30
days
if
we
ask
for
more
testing,
or
stop
production
if
you
are
not
able
do
this.
(e)
If
we
determine
that
the
certificate
of
conformity
would
not
cover
your
new
or
modified
product,
we
will
send
you
a
written
explanation
of
our
decision.
In
this
case,
you
may
no
longer
produce
these
vessels,
engines,
or
fuel
systems,
though
you
may
ask
for
a
hearing
for
us
to
reconsider
our
decision
(see
§
1045.820).
§
1045.230
How
do
I
select
emission
families?
(a)
Divide
your
product
line
into
groups
of
vessels
(or
fuel
systems)
that
you
expect
to
have
similar
emission
characteristics.
These
groups
are
call
emission
families.
(b)
You
need
a
separate
emission
family
for
each
model
year.
§
1045.235
How
does
testing
fit
with
my
application
for
a
certificate
of
conformity?
This
section
describes
how
to
do
testing
in
your
effort
to
apply
for
a
certificate
of
conformity.
(a)
Test
your
vessels
using
the
procedures
and
equipment
specified
in
subpart
F
of
this
part.
(1)
For
evaporative
testing,
you
may
test
the
fuel
system
without
the
vessel.
(2)
For
exhaust
testing,
test
the
engine
without
the
vessel.
(b)
Select
from
each
emission
family
a
test
vessel
for
each
fuel
type
with
a
configuration
you
believe
is
most
likely
to
exceed
an
applicable
standard
(e.
g.,
the
diurnal
evaporative
standard).
Using
good
engineering
judgment,
consider
the
emission
levels
of
all
regulated
constituents
over
the
full
useful
life
of
the
vessel.
(c)
You
may
submit
emission
data
for
equivalent
emission
families
from
previous
years
instead
of
doing
new
tests,
but
only
if
the
data
shows
that
the
test
vessel
would
meet
all
the
requirements
for
the
latest
models.
We
may
require
you
to
do
new
emission
testing
if
we
believe
the
latest
models
could
be
substantially
different
from
the
previously
tested
vessel.
(d)
We
may
choose
to
measure
emissions
from
any
of
your
test
vessels.
(1)
If
we
do
this,
you
must
provide
the
test
vessel
at
the
location
we
select.
We
may
decide
to
do
the
testing
at
your
plant
or
any
other
facility.
If
we
choose
to
do
the
testing
at
your
plant,
you
must
schedule
it
as
soon
as
possible
and
make
available
the
instruments
and
equipment
we
need.
This
provision
does
not
apply
for
evaporative
emission
testing
for
manufacturers
that
use
the
design
certification
provisions
for
all
of
the
products
under
§
1045.105(
d).
(2)
If
we
measure
emissions
on
one
of
your
test
vessels,
the
results
of
that
testing
become
the
official
data
for
the
vessel.
Unless
we
later
invalidate
this
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14,
2002
/
Proposed
Rules
data,
we
may
decide
not
to
consider
your
data
in
determining
if
your
emission
family
meets
the
emission
standards.
(e)
We
may
allow
you
to
certify
vessels
using
existing
data
from
vessels
with
similarly
designed
fuel
systems
that
you
did
not
manufacture.
In
those
cases,
you
are
not
required
to
emissiontest
your
vessels
or
fuel
systems.
(f)
For
fuel
tanks
that
are
designcertified
based
on
permeability
treatments
for
plastic
fuel
tanks,
you
do
not
need
to
test
each
emission
family.
However,
you
must
use
good
engineering
judgment
to
determine
permeation
rates
for
the
tanks.
Good
engineering
judgment
requires
that
at
least
one
fuel
tank
be
tested
for
each
set
of
treatment
conditions.
For
example,
if
you
treat
tanks
made
from
the
same
material
using
the
identical
tretament
process,
but
that
are
in
different
emission
families,
then
you
would
only
need
to
test
one
tank.
§
1045.240
How
do
I
determine
if
my
emission
family
complies
with
emission
standards?
(a)
Your
emission
family
complies
with
the
applicable
numerical
emission
standards
in
§
1045.105
if
all
emissiondata
vessels
representing
that
family
have
test
results
showing
emission
levels
at
or
below
all
applicable
standards,
provided
you
also
comply
with
the
average
emission
standard
for
your
total
production.
(b)
Your
emission
family
does
not
comply
if
any
emission
data
vessel
representing
that
family
has
test
results
showing
emission
levels
above
the
applicable
standards
from
§
1045.105.
(c)
If
your
average
emission
level
is
above
an
applicable
standard,
then
all
of
emission
families
with
emission
levels
above
the
average
standard
are
noncompliant.
§
1045.245
What
records
must
I
keep
and
make
available
to
EPA?
(a)
Organize
and
maintain
the
following
records
to
keep
them
readily
available;
we
may
review
these
records
at
any
time:
(1)
A
copy
of
all
applications
and
any
summary
information
you
sent
us.
(2)
Any
of
the
information
we
specify
in
§
1045.205
that
you
did
not
include
in
your
application.
(3)
A
detailed
history
of
each
emission
data
vessel.
In
each
history,
describe
the
test
vessel's
construction,
including
its
origin
and
buildup,
steps
you
took
to
ensure
that
it
represents
production
vessels,
any
components
you
built
specially
for
it,
and
all
emission
related
components.
(b)
Keep
data
from
routine
emission
tests
for
one
year
after
we
issue
the
associated
certificate
of
conformity.
Keep
all
other
information
specified
in
paragraph
(a)
of
this
section
for
eight
years
after
we
issue
your
certificate.
(c)
Store
these
records
in
any
format
and
on
any
media,
as
long
as
you
can
promptly
send
us
organized,
written
records
in
English
if
we
ask
for
them.
(d)
Send
us
copies
of
any
vessel
maintenance
instructions
or
explanations
if
we
ask
for
them.
§
1045.250
When
may
EPA
deny,
revoke,
or
void
my
certificate
of
conformity?
(a)
We
may
deny
your
application
for
certification
if
your
emission
data
vessels
fail
to
comply
with
emission
standards
or
other
requirements.
Our
decision
may
be
based
on
any
information
available
to
us.
If
we
deny
your
application,
we
will
explain
why
in
writing.
(b)
In
addition,
we
may
deny
your
application
or
revoke
your
certificate
if
you
do
any
of
the
following:
(1)
Refuse
to
comply
with
any
testing
or
reporting
requirements.
(2)
Submit
false
or
incomplete
information
(paragraph
(d)
of
this
section
applies
if
this
is
fraudulent).
(3)
Render
inaccurate
any
test
data.
(4)
Deny
us
from
completing
authorized
activities
despite
our
presenting
a
warrant
or
court
order
(see
§
1068.020
of
this
chapter).
(5)
Produce
vessels
for
importation
into
the
United
States
at
a
location
where
local
law
prohibits
us
from
carrying
out
authorized
activities.
(c)
We
may
void
your
certificate
if
you
do
not
keep
the
records
we
require
or
do
not
give
us
information
when
we
ask
for
it.
(d)
We
may
void
your
certificate
if
we
find
that
you
committed
fraud
to
get
it.
This
means
intentionally
submitting
false
or
incomplete
information.
(e)
If
we
deny
your
application
or
revoke
or
void
your
certificate,
you
may
ask
for
a
hearing
(see
§
1045.820).
Any
such
hearing
will
be
limited
to
substantial
and
factual
issues.
Subpart
D—[
Reserved]
Subpart
E—
Testing
In
use
Engines
§
1045.401
What
provisions
apply
for
inuse
testing
of
vessels?
We
may
conduct
in
use
testing
of
any
vessel
(or
part
of
a
vessel)
subject
to
the
standards
of
this
part.
If
we
determine
that
a
substantial
number
of
vessels
do
not
comply
with
the
regulations
of
this
part,
we
may
order
the
manufacturer
to
conduct
a
recall
as
specified
in
40
CFR
part
1068.
Subpart
F—
Test
Procedures
§
1045.501
What
equipment
and
general
procedures
must
I
use
to
test
my
vessels?
(a)
Diurnal
testing.
Use
the
equipment
specified
in
40
CFR
part
86
subpart
B
(i.
e.,
the
procedures
used
to
measure
diurnal
evaporative
emissions
for
gasoline
fueled
highway
vehicles).
Use
the
procedures
specified
in
§
1045.505
to
measure
diurnal
emissions.
(1)
These
provisions
require
placing
your
vessel
or
fuel
system
within
a
sealed,
temperature
controlled
enclosure
called
a
SHED
(Sealed
Housing
for
Evaporative
Determination).
(2)
You
must
include
a
fan
to
maintain
a
minimum
wind
speed
of
5
miles
per
hour
across
the
tank.
(b)
Permeation
testing.
Use
the
following
equipment
and
procedures
for
measuring
permeation
emissions:
(1)
For
fuel
tank
permeation,
see
§
1045.506.
(2)
For
fuel
line
permeation,
see
SAE
J1527
(incorporated
by
reference
in
§
1045.810).
Alternatively,
you
may
use
the
equipment
and
procedures
specified
in
SAE
J1737
(incorporated
by
reference
in
§
1045.810),
except
that
all
tests
must
be
conducted
at
23
C
±
2
C.
(c)
Special
or
alternate
procedures.
You
may
use
special
or
alternate
procedures,
as
described
in
§
1065.010
of
this
chapter.
§
1045.505
How
do
I
test
for
diurnal
evaporative
emissions?
Measure
evaporative
emissions
by
placing
the
preconditioned
vessel
or
fuel
system
within
a
sealed,
temperature
controlled
SHED
and
recording
the
concentration
of
fuel
vapors
within
the
SHED
as
the
temperature
cycles
between
22.2
C
and
35.6
C.
(a)
Preconditioning
and
test
preparation.
To
prepare
your
vessel
or
fuel
system,
follow
these
seven
steps:
(1)
To
precondition
the
tank,
fill
it
to
its
nominal
capacity
and
allow
it
to
soak
at
30
C
±
5
C
for
one
month.
Note:
You
may
omit
this
step;
however,
if
you
omit
this
step,
you
may
not
correct
measured
emissions
for
permeation
that
occurs
during
the
test.
(2)
Determine
the
tank's
fuel
capacity
in
gallons
as
configured
in
the
vessel
(using
at
least
three
significant
figures).
(3)
Fill
the
fuel
tank
with
the
test
fuel
to
its
capacity.
If
you
fill
the
tank
within
the
SHED,
do
not
spill
any
fuel.
(4)
Allow
the
tank
and
its
contents
to
equilibrate
to
22.2
C
±
1
C
within
the
SHED.
(5)
Connect
a
fuel
siphon
to
the
tank
outlet
and
drain
60
percent
of
the
fuel.
You
may
vent
the
tank
before
draining
it.
Do
not
spill
any
fuel.
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Vol.
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No.
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/
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August
14,
2002
/
Proposed
Rules
(6)
Close
the
SHED
and
set
the
temperature
control
to
22.2
F.
Allow
the
SHED
to
equilibrate
for
two
hours.
(7)
If
the
fuel
tank
vent
will
have
an
attached
vent
hose
when
installed
in
the
vessel,
attach
a
vent
hose
representative
of
the
shortest
length
of
vent
hose
that
will
be
used
when
the
tank
is
installed
in
the
vessel.
You
may
attach
the
hose
at
any
time
before
you
start
the
test
run
(§
1045.505(
b)).
(b)
Test
run.
To
measure
emissions
from
your
vessel
or
fuel
system,
follow
these
six
steps:
(1)
Ensure
that
the
measured
temperature
within
the
SHED
is
22.2
±
0.2
C.
(2)
Ventilate
the
SHED.
(3)
Seal
the
SHED
and
record
the
hydrocarbon
concentration
within
the
SHED.
This
is
the
zero
hour
value.
(4)
Begin
the
temperature
cycle
in
Table
1
of
§
1045.505.
Run
the
temperature
cycle
three
times.
(5)
Record
the
hydrocarbon
concentration
at
the
end
of
each
temperature
cycle.
(6)
Use
the
calculation
procedures
of
40
CFR
86.143Ð
96
to
calculate
the
mass
emissions
for
each
of
the
three
24
hour
temperature
cycles.
The
highest
of
the
these
three
is
the
official
test
result.
If
you
precondition
the
tank
as
specified
in
§
1045.505(
a)(
1),
you
may
correct
these
results
by
subtracting
the
permeation
emissions
from
the
total,
consistent
with
good
engineering
judgment.
TABLE
1
OF
§
1045.505—
24
HOUR
TEMPERATURE
CYCLE
FOR
EMISSION
TESTING
Time
(hours)
Temperature
(
C)
0
....................................................
22.2
1
....................................................
22.5
2
....................................................
23.6
3
....................................................
26.6
4
....................................................
29.5
5
....................................................
31.8
6
....................................................
34.0
7
....................................................
34.8
8
....................................................
35.5
9
....................................................
35.6
10
..................................................
35.3
11
..................................................
34.4
12
..................................................
33.5
13
..................................................
31.8
14
..................................................
30.0
15
..................................................
28.6
16
..................................................
27.1
17
..................................................
26.1
18
..................................................
25.0
19
..................................................
24.3
20
..................................................
23.7
21
..................................................
23.3
22
..................................................
22.8
23
..................................................
22.5
24
..................................................
22.2
§
1045.506
How
do
I
test
my
fuel
tank
for
permeation
emissions?
Measure
permeation
emissions
by
weighing
a
sealed
fuel
tank
before
and
after
a
temperature
controlled
soak.
(a)
Preconditioning.
To
precondition
your
fuel
tank,
follow
these
six
steps:
(1)
Fill
the
tank
and
allow
it
to
soak
at
30
C
±
10
C
for
60
days.
(2)
Determine
the
tank's
fuel
capacity
as
configured
in
the
vessel
to
the
nearest
tenth
of
a
gallon.
(3)
Fill
the
fuel
tank
with
the
test
fuel
to
its
capacity.
If
you
fill
the
tank
within
the
SHED,
do
not
spill
any
fuel.
(4)
Allow
the
tank
and
its
contents
to
equilibrate
to
40
C
±
2
C.
(5)
Seal
the
fuel
tank
using
nonpermeable
fittings,
such
as
metal
or
Teflon
TM
.
(b)
Test
run.
To
measure
emissions
from
your
fuel
tank,
follow
these
nine
steps:
(1)
Weigh
the
sealed
fuel
tank,
and
record
the
weight
to
the
nearest
0.1
grams.
(You
may
use
less
precise
weights,
provided
that
the
difference
in
mass
from
the
start
of
the
test
to
the
end
of
the
test
has
at
least
three
significant
figures.)
(2)
Carefully
place
the
tank
within
the
temperature
controlled
container
or
SHED.
Do
not
spill
any
fuel.
(3)
Close
the
container
or
SHED
and
record
the
time.
(4)
Ensure
that
the
measured
temperature
within
the
container
or
SHED
is
40
C
±
2
C.
(5)
Leave
the
tank
in
the
container
or
SHED
for
10
to
30
days,
consistent
with
good
engineering
judgment
(based
on
the
expected
permeation
rate).
(6)
Hold
the
temperature
of
the
container
or
SHED
to
40
C
±
2
C
and
record
at
least
daily.
(7)
At
the
end
of
the
soak
period,
weigh
the
sealed
fuel
tank
and
record
the
weight
to
the
nearest
0.1
grams.
(You
may
use
less
precise
weights,
provided
that
the
difference
in
mass
from
the
start
of
the
test
to
the
end
of
the
test
has
at
least
three
significant
figures.)
(8)
Subtract
the
weight
of
the
tank
at
the
end
of
the
test
from
the
weight
of
the
tank
at
the
beginning
of
the
test,
and
divide
the
difference
by
the
capacity
of
the
fuel
tank.
Divide
this
gram/
gallon
value
by
the
number
of
test
days
to
calculate
the
gram/
gallon/
test
day
emission
rate.
Example:
If
a
20.4
gallon
tank
weighed
31782.3
grams
at
the
beginning
of
the
test,
weighed
31760.2
grams
after
soaking
for
25.03
days,
then
the
gram/
gallon/
test
day
emission
rate
would
be:
(31882.3
gÑ
31760.2
g)
/
20.4
gal
/
25.03
test
days
=
0.239
g/
gal/
test
day
(9)
Round
your
result
to
the
same
number
of
decimal
places
as
the
standard.
Subpart
G—
Compliance
Provisions
§
1045.601
What
compliance
provisions
apply
to
these
vessels?
Vessel
manufacturers,
as
well
as
owners,
operators,
and
rebuilders
of
these
vessels,
and
all
other
persons,
must
observe
the
requirements
and
prohibitions
in
part
1068
of
this
chapter.
Subpart
H—
Averaging,
Banking,
and
Trading
for
Certification
§
1045.701
General
provisions.
(a)
You
may
average,
bank,
and
trade
emission
credits
for
certification
as
described
in
this
subpart
to
meet
the
average
standards
of
this
part.
You
must
comply
with
the
averaging
requirements
if
you
certify
with
an
emission
level
higher
than
the
applicable
average
standard.
Participation
in
banking
and
trading
is
voluntary.
Note:
Some
standards,
such
as
the
tank
permeation
standard,
do
not
allow
you
to
comply
on
average.
(b)
The
definitions
of
Subpart
I
of
this
part
apply
to
this
subpart.
The
following
definitions
also
apply:
(1)
Average
standard
means
the
standard
that
applies
on
average
to
all
your
vessels,
engines,
or
fuel
systems
that
are
subject
to
this
part
(except
portable
fuel
tanks).
(2)
Broker
means
any
entity
that
facilitates
a
trade
between
a
buyer
and
seller.
(3)
Buyer
means
the
entity
that
receives
credits
as
a
result
of
trade
or
transfer.
(4)
FEL
means
the
familiy
emission
limit
to
which
an
emission
family
is
certified
(5)
Group
means
a
group
of
vessels
having
the
same
evaporative
control
technology,
model
year,
and
fuel
tank
capacity.
(6)
Reserved
credits
means
credits
generated
but
not
yet
verified
by
EPA
in
the
end
of
year
report
review.
(7)
Seller
means
the
entity
that
provides
credits
during
a
trade
or
transfer.
(8)
Transfer
means
to
convey
control
of
credits
an
individual
tank
generatesÑ
(i)
From
a
certifying
tank
manufacturer
to
a
vessel
manufacturer
that
buys
the
tank;
or
(ii)
To
a
certifying
tank
manufacturer
from
a
vessel
manufacturer
that
buys
the
tank.
(c)
Do
not
include
any
exported
vessel,
engine,
or
tank
in
the
certification
averaging,
banking,
and
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Federal
Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
trading
program.
Include
only
vessels,
engines,
or
fuel
tanks
certified
under
this
part.
§
1045.705
How
do
I
average
emission
levels?
(a)
As
specified
in
subpart
B
of
this
part,
certify
each
emission
family
that
you
are
including
the
averaging
program
to
an
FEL.
(b)
Calculate
a
preliminary
average
emission
level
according
to
§
1045.720
using
projected
production
volumes
for
your
application
for
certification.
(c)
After
the
end
of
your
model
year,
calculate
a
final
average
emission
level
according
to
§
1045.720
using
actual
production
volumes.
(d)
If
your
preliminary
average
emission
level
is
below
the
allowable
average
standard,
see
§
1045.710
for
information
about
generating
and
banking
emission
credits.
These
credits
will
be
considered
reserved
until
verified
by
EPA
during
the
end
of
year
report
review.
§
1045.710
How
do
I
generate
and
bank
emission
credits?
(a)
If
your
average
emission
level
is
below
the
average
standard,
you
may
calculate
credits
according
to
§
1045.720.
(b)
You
may
generate
credits
if
you
are
a
certifying
manufacturer.
You
may
hold
them
if
you
are
a
fuel
tank
or
vessel
manufacturer
(c)
You
may
bank
unused
emission
credits,
but
only
after
the
end
of
the
calendar
year
and
after
we
have
reviewed
your
end
of
year
reports.
(d)
During
the
calendar
year
and
before
you
send
in
your
end
of
year
report,
you
may
consider
reserved
any
credits
you
originally
designate
for
banking
during
certification.
You
may
redesignate
these
credits
for
trading
or
transfer
in
your
end
of
year
report,
but
they
are
not
valid
to
demonstrate
compliance
until
verified.
(e)
You
may
use
for
averaging
or
trading
any
credits
you
declared
for
banking
from
the
previous
calendar
year
that
we
have
not
reviewed.
But,
we
may
revoke
these
credits
laterÑ
following
our
review
of
your
end
of
year
report
or
audit
actions.
For
example,
this
could
occur
if
we
find
that
credits
are
based
on
erroneous
calculations;
or
that
emission
levels
are
misrepresented,
unsubstantiated,
or
derived
incorrectly
in
the
certification
process.
§
1045.715
How
do
I
trade
or
transfer
emission
credits?
(a)
You
may
trade
only
banked
credits,
not
reserved
credits.
(b)
Whether
or
not
you
hold
a
certificate,
you
may
transfer
unbanked
credits
to
a
manufacturer
that
is
supplying
a
fuel
tank
to
you
or
a
vessel
manufacturer
that
is
buying
a
fuel
tank
from
you.
(c)
How
you
handle
unused
transferred
credits
at
the
end
of
a
model
year
depends
on
whether
or
not
you
hold
a
certificate.
(1)
If
you
hold
a
certificate,
you
may
bank
these
credits.
(2)
If
you
do
not
hold
a
certificate,
you
may
not
bank
these
credits;
you
may
only
transfer
them
to
a
certificate
holder.
(d)
If
a
negative
credit
balance
results
from
a
credit
trade
or
transfer,
both
buyers
and
sellers
are
liable,
except
in
cases
involving
fraud.
We
may
void
the
certificates
of
all
emission
families
participating
in
a
negative
trade.
(1)
If
you
buy
credits
but
have
not
caused
the
negative
credit
balance,
you
must
only
supply
more
credits
equivalent
to
the
amount
of
invalid
credits
you
used.
(2)
If
you
caused
the
credit
shortfall,
you
may
be
subject
to
the
requirements
of
§
1045.730(
b)(
6).
§
1045.720
How
do
I
calculate
my
average
emission
level
or
emission
credits?
(a)
Calculate
your
average
emission
level
for
each
model
year
according
to
the
following
equation
and
round
it
to
the
nearest
tenth
of
a
gram
per
gallon.
Use
consistent
units
throughout
the
calculation.
(1)
Calculate
the
average
emission
level
as:
Emission
level
=
FEL
Capacity
Production
Production
Capacity
i
i
i
i
(
)
×
(
)
×
(
)
(
)
×
(
)
i
i
i
Where:
FELi
=
The
FEL
to
which
the
engine
family
is
certified.
Capacityi
=
The
capacity
of
the
fuel
tanks.
Productioni
=
The
number
of
fuel
tanks
produced
in
that
model
year
with
a
capacity
of
Capacityi.
(2)
Sum
the
emissions
for
each
unique
combination
of
emission
family
and
fuel
tank
capacity.
(3)
Use
production
projections
for
initial
certification,
and
actual
production
volumes
to
determine
compliance
at
the
end
of
the
model
year.
(b)
If
your
average
emission
level
is
below
the
average
standard,
calculate
credits
available
for
banking
according
to
the
following
equation
and
round
them
to
the
nearest
tenth
of
a
gram:
Credit
Average
standard
Emission
level
Production
Capacity
i
i
=
(
)
[
]
×
(
)
×
(
)
i
(c)
If
your
average
emission
level
is
above
the
average
standard,
calculate
your
preliminary
credit
deficit
according
to
the
following
equation,
rounding
to
the
nearest
tenth
of
a
gram:
Deficit
Emission
level
Average
standard
Production
Capacity
i
i
=
(
)
[
]
×
(
)
×
(
)
i
§
1045.725
What
information
must
I
keep?
(a)
Maintain
and
keep
five
types
of
properly
organized
and
indexed
records
for
each
group
and
for
each
emission
family:
(1)
Model
year
and
EPA
emission
family.
(2)
Bin
standard.
(3)
Fuel
tank
capacity.
(4)
Projected
production
volume
for
the
model
year.
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53112
Federal
Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
(5)
Actual
production
volume
for
the
model
year.
(b)
Keep
paper
records
of
this
information
for
three
years
from
the
due
date
for
the
end
of
year
report.
You
may
use
any
additional
storage
formats
or
media
if
you
like.
(c)
Follow
§
1045.730
to
send
us
the
information
you
must
keep.
(d)
We
may
ask
you
to
keep
or
send
other
information
necessary
to
implement
this
subpart.
§
1045.730
What
information
must
I
report?
(a)
Include
the
following
information
in
your
applications
for
certification:
(1)
A
statement
that,
to
the
best
of
your
belief,
you
will
not
have
a
negative
credit
balance
when
all
credits
are
calculated.
This
means
that
if
you
believe
that
your
average
emission
level
will
be
above
the
standard
(i.
e.,
that
you
will
have
a
deficit
for
the
model
year),
you
must
have
banked
credits
(or
project
to
have
traded
credits)
to
offset
the
deficit.
(2)
Detailed
calculations
of
projected
emission
credits
(zero,
positive,
or
negative)
based
on
production
projections.
(i)
If
you
project
a
credit
deficit,
state
the
source
of
credits
needed
to
offset
the
credit
deficit.
(ii)
If
you
project
credits,
state
whether
you
will
reserve
them
for
banking
or
transfer
them.
(b)
At
the
end
of
each
model
year,
send
an
end
of
year
report.
(1)
Make
sure
your
report
includes
three
things:
(i)
Calculate
in
detail
your
average
emission
level
and
any
emission
credits
(zero,
positive,
or
negative)
based
on
actual
production
volumes.
(ii)
If
your
average
emission
level
is
above
the
allowable
average
standard,
state
the
source
of
credits
needed
to
offset
the
credit
deficit.
(iii)
If
your
average
emission
level
is
below
the
allowable
average
standard,
state
whether
you
will
reserve
the
credits
for
banking
or
transfer
them.
(2)
Base
your
production
volumes
on
the
point
of
first
retail
sale.
This
point
is
called
the
final
product
purchase
location.
(3)
Send
end
of
year
reports
to
the
Designated
Officer
within
120
days
of
the
end
of
the
model
year.
If
you
send
reports
later,
you
are
violating
the
Clean
Air
Act.
(4)
If
you
generate
credits
for
banking
and
you
do
not
send
your
end
of
year
reports
within
120
days
after
the
end
of
the
model
year,
you
may
not
use
or
trade
the
credits
until
we
receive
and
review
your
reports.
You
may
not
use
projected
credits
pending
our
review.
(5)
You
may
correct
errors
discovered
in
your
end
of
year
report,
including
errors
in
calculating
credits
according
to
the
following
table:
If.
.
.
And
if.
.
.
Then
we.
.
.
(i)
Our
review
discovers
an
error
in
your
endof
year
report
that
increases
your
credit
balance
the
discovery
occurs
within
180
days
of
receipt
restore
the
credits
for
your
use.
(ii)
You
discover
an
error
in
your
report
that
increases
your
credit
balance.
the
discovery
occurs
within
180
days
of
receipt
restore
the
credits
for
your
use.
(iii)
We
or
you
discover
an
error
in
your
report
that
increases
your
credit
balance.
the
discovery
occurs
more
than
180
days
after
receipt.
do
not
restore
the
credits
for
your
use.
(iv)
We
discover
an
error
in
your
report
that
reduces
your
credit
balance.
at
any
time
after
receipt
....................................
reduce
your
credit
balance.
(6)
If
our
review
of
your
end
of
yearreport
shows
a
negative
balance,
you
may
buy
credits
to
bring
your
credit
balance
to
zero.
But
you
must
buy
1.1
credits
for
each
1.0
credit
needed.
If
enough
credits
are
not
available
to
bring
your
credit
balance
to
zero,
we
may
void
the
certificates
for
all
families
certified
to
standards
above
the
allowable
average.
(c)
Within
90
days
of
any
credit
trade
or
transfer,
you
must
send
the
Designated
Officer
a
report
of
the
trade
or
transfer
that
includes
three
types
of
information:
(1)
The
corporate
names
of
the
buyer,
seller,
and
any
brokers.
(2)
Information
about
the
credits
that
depends
on
whether
you
trade
or
transfer
them.
(i)
For
trades,
describe
the
banked
credits
being
traded.
(ii)
For
transfers,
calculate
the
credits
in
detail
and
identify
the
source
or
use
of
the
credits.
(3)
Copies
of
contracts
related
to
credit
trading
or
transfer
from
the
buyer,
seller,
and
broker,
as
applicable.
(d)
Include
in
each
report
a
statement
certifying
the
accuracy
and
authenticity
of
its
contents.
(e)
We
may
void
a
certificate
of
conformity
for
any
emission
family
if
you
do
not
keep
the
records
this
section
requires
or
give
us
the
information
when
we
ask
for
it.
Subpart
I—
Definitions
and
Other
Reference
Information
§
1045.801
What
definitions
apply
to
this
part?
The
definitions
in
this
section
apply
to
this
part.
The
definitions
apply
to
all
subparts
unless
we
note
otherwise.
All
undefined
terms
have
the
meaning
the
Act
gives
to
them.
The
definitions
follow:
Act
means
the
Clean
Air
Act,
as
amended,
42
U.
S.
C.
7401
et
seq.
Adjustable
parameter
means
any
device,
system,
or
element
of
design
that
someone
can
adjust
(including
those
which
are
difficult
to
access)
and
that,
if
adjusted,
may
affect
emissions
or
vessel
performance
during
emission
testing
or
normal
in
use
operation.
Aftertreatment
means
relating
to
any
system,
component,
or
technology
mounted
downstream
of
the
exhaust
valve
or
exhaust
port
whose
design
function
is
to
reduce
exhaust
emissions.
Auxiliary
emission
control
device
means
any
element
of
design
that
senses
temperature,
engine
rpm,
boat
speed,
transmission
gear,
atmospheric
pressure,
manifold
pressure
or
vacuum,
or
any
other
parameter
to
activate,
modulate,
delay,
or
deactivate
the
operation
of
any
part
of
the
emissioncontrol
system.
This
also
includes
any
other
feature
that
causes
in
use
emissions
to
be
higher
than
those
measured
under
test
conditions,
except
as
we
allow
under
this
part.
Broker
means
any
entity
that
facilitates
a
trade
of
emission
credits
between
a
buyer
and
seller.
Calibration
means
the
set
of
specifications
and
tolerances
specific
to
a
particular
design,
version,
or
application
of
a
component
or
assembly
capable
of
functionally
describing
its
operation
over
its
working
range.
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/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
Capacity
means
the
maximum
volume
of
liquid
fuel
that
a
fuel
tank
can
hold
when
installed
in
a
vessel.
Certification
means
obtaining
a
certificate
of
conformity
for
an
emission
family
that
complies
with
the
emission
standards
and
requirements
in
this
part.
Compression
ignition
means
relating
to
a
type
of
reciprocating,
internalcombustion
vessel
that
is
not
a
sparkignition
vessel.
Crankcase
emissions
means
airborne
substances
emitted
to
the
atmosphere
from
any
part
of
the
vessel
crankcase's
ventilation
or
lubrication
systems.
The
crankcase
is
the
housing
for
the
crankshaft
and
other
related
internal
parts.
Designated
Officer
means
the
Manager,
Engine
Compliance
Programs
Group
(6403Ð
J),
U.
S.
Environmental
Protection
Agency,
1200
Pennsylvania
Ave.,
Washington,
DC
20460.
Emission
control
system
means
any
device,
system,
or
element
of
design
that
controls
or
reduces
the
regulated
emissions
from
an
vessel.
Emission
data
vessel
means
a
vessel,
engine,
or
fuel
system
that
is
tested
for
certification.
Emission
family
means
a
group
of
vessels,
engines
or
fuel
systems
with
similar
emission
characteristics,
as
specified
in
§
1045.230.
Emission
related
maintenance
means
maintenance
that
substantially
affects
emissions
or
is
likely
to
substantially
affect
emissions
deterioration.
Fuel
system
means
any
or
all
of
the
components
involved
in
transporting,
metering,
and
mixing
the
fuel
from
the
fuel
tank
to
the
combustion
chamber(
s),
including
the
fuel
tank,
fuel
tank
cap,
fuel
pump,
fuel
filters,
fuel
lines,
carburetor
or
fuel
injection
components,
and
all
fuel
system
vents.
Good
engineering
judgment
has
the
meaning
we
give
it
in
§
1068.005
of
this
chapter.
Hobby
vessel
means
a
recreational
vessel
that
is
a
reduced
scale
model
vessel
that
is
not
capable
of
transporting
a
person.
Hydrocarbon
(HC)
means
the
hydrocarbon
group
on
which
the
emission
standards
are
based
for
each
fuel
type.
For
gasoline
and
LPG
fueled
vessels,
HC
means
total
hydrocarbon
(THC).
For
natural
gas
fueled
vessels,
HC
means
nonmethane
hydrocarbon
(NMHC).
For
alcohol
fueled
vessels,
HC
means
total
hydrocarbon
equivalent
(THCE).
Identification
number
means
a
unique
specification
(for
example,
model
number/
serial
number
combination)
that
allows
someone
to
distinguish
a
particular
vessel
from
other
similar
vessels.
Manufacturer
has
the
meaning
given
in
section
216(
1)
of
the
Act.
In
general,
this
term
includes
any
person
who
manufactures
a
vessel,
engine,
or
fuel
system
component
for
sale
in
the
United
States
or
otherwise
introduces
a
new
vessel,
engine,
or
fuel
system
component
into
commerce
in
the
United
States.
This
includes
importers
and
entities
that
treat
fuel
system
components
to
reduce
permeability.
Maximum
test
power
means
the
power
output
observed
with
the
maximum
fueling
rate
possible
at
the
maximum
test
speed.
Maximum
test
speed
means
the
speed
specified
by
40
CFR
1065.515.
Model
year
means
one
of
the
following
things:
(1)
For
freshly
manufactured
vessels
(see
definition
of
``
new
vessel,
''
paragraph
(1),
of
this
section),
model
year
means
one
of
the
following:
(i)
Calendar
year.
(ii)
Your
annual
new
model
production
period
if
it
is
different
than
the
calendar
year.
This
must
include
January
1
of
the
calendar
year
for
which
the
model
year
is
named.
It
may
not
begin
before
January
2
of
the
previous
calendar
year
and
it
must
end
by
December
31
of
the
named
calendar
year.
(2)
For
a
vessel
modified
by
an
importer
(not
the
original
vessel
manufacturer)
who
has
a
certificate
of
conformity
for
the
imported
vessel
(see
definition
of
``
new
vessel,
''
paragraph
(2),
of
this
section),
model
year
means
one
of
the
following:
(i)
The
calendar
year
in
which
the
importer
finishes
modifying
and
labeling
the
vessel.
(ii)
Your
annual
production
period
for
producing
vessels
if
it
is
different
than
the
calendar
year;
follow
the
guidelines
in
paragraph
(1)(
ii)
of
this
definition.
(3)
For
a
vessel
you
import
that
does
not
meet
the
criteria
in
paragraphs
(1)
or
(2)
of
the
definition
of
``
new
vessel''
in
this
section,
model
year
means
the
calendar
year
in
which
the
manufacturer
completed
the
original
assembly
of
the
vessel.
In
general,
this
applies
to
used
vessels
that
you
import
without
conversion
or
major
modification.
New
vessel
means
any
of
the
following
things:
(1)
A
freshly
manufactured
vessel
for
which
the
ultimate
buyer
has
never
received
the
equitable
or
legal
title.
The
vessel
is
no
longer
new
when
the
ultimate
buyer
receives
this
title
or
the
product
is
placed
into
service,
whichever
comes
first.
(2)
An
imported
vessel
covered
by
a
certificate
of
conformity
issued
under
this
part,
where
someone
other
than
the
original
manufacturer
modifies
the
vessel
after
its
initial
assembly
and
holds
the
certificate.
The
vessel
is
no
longer
new
when
it
is
placed
into
service.
(3)
An
imported
nonroad
vessel
that
is
not
covered
by
a
certificate
of
conformity
issued
under
this
part
at
the
time
of
importation.
Noncompliant
vessel
means
a
vessel,
engine,
or
fuel
system
that
was
originally
covered
by
a
certificate
of
conformity,
but
is
not
in
the
certified
configuration
or
otherwise
does
not
comply
with
the
conditions
of
the
certificate.
Nonconforming
vessel
means
a
vessel,
engine,
or
fuel
system
not
covered
by
a
certificate
of
conformity
that
would
otherwise
be
subject
to
emission
standards.
Nonroad
means
relating
to
nonroad
engines
or
nonroad
vehicles.
Nonroad
engine
has
the
meaning
given
in
§
1068.025
of
this
chapter.
Oxides
of
nitrogen
means
nitric
oxide
(NO)
and
nitrogen
dioxide
(NO2).
Oxides
of
nitrogen
are
expressed
quantitatively
as
if
the
NO
were
in
the
form
of
NO2
(assume
a
molecular
weight
for
oxides
of
nitrogen
equivalent
to
that
of
NO2).
Physically
adjustable
range
means
the
entire
range
over
which
a
vessel
parameter
can
be
adjusted,
except
as
modified
by
§
1045.115(
c).
Placed
into
service
means
used
for
its
intended
purpose.
Portable
fuel
tank
means
a
fuel
tank
that
has
a
permanently
affixed
handle,
has
a
fuel
capacity
no
greater
than
12
gallons,
and
is
not
permanently
mounted
to
a
marine
vessel.
Propulsion
marine
engine
means
a
marine
engine
that
moves
a
vessel
through
the
water
or
directs
the
vessel's
movement.
Revoke
means
to
discontinue
the
certificate
for
an
emission
family.
If
we
revoke
a
certificate,
you
must
apply
for
a
new
certificate
before
continuing
to
produce
the
affected
vessels.
This
does
not
apply
to
vessels
you
no
longer
possess.
Round
means
to
round
numbers
according
to
ASTM
E29Ð
93a,
which
is
incorporated
by
reference
(see
§
1045.810),
unless
otherwise
specified.
Scheduled
maintenance
means
adjusting,
repairing,
removing,
disassembling,
cleaning,
or
replacing
components
or
systems
that
is
periodically
needed
to
keep
a
part
from
failing
or
malfunctioning.
It
also
may
mean
actions
you
expect
are
necessary
to
correct
an
overt
indication
of
failure
or
malfunction
for
which
periodic
maintenance
is
not
appropriate.
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Federal
Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
Spark
ignition
means
relating
to
a
type
of
engine
with
a
spark
plug
(or
other
sparking
device)
and
with
operating
characteristics
significantly
similar
to
the
theoretical
Otto
combustion
cycle.
Spark
ignition
engines
usually
use
a
throttle
to
regulate
intake
air
flow
to
control
power
during
normal
operation.
Spark
ignition
marine
vessel
means
marine
vessel
that
is
powered
by
a
spark
ignition
engine.
Stoichiometry
means
the
proportion
of
a
mixture
of
air
and
fuel
such
that
the
fuel
is
fully
oxidized
with
no
remaining
oxygen.
For
example,
stoichiometric
combustion
in
gasoline
vessels
typically
occurs
at
an
air
fuel
mass
ratio
of
about
14.7.
Suspend
means
to
temporarily
discontinue
the
certificate
for
an
emission
family.
If
we
suspend
a
certificate,
you
may
not
sell
vessels
from
that
emission
family
unless
we
reinstate
the
certificate
or
approve
a
new
one.
Test
sample
means
the
collection
of
vessels
selected
from
the
population
of
an
emission
family
for
emission
testing.
Test
vessel
means
a
vessel,
engine,
or
fuel
system
in
a
test
sample.
Total
Hydrocarbon
Equivalent
means
the
sum
of
the
carbon
mass
contributions
of
non
oxygenated
hydrocarbons,
alcohols
and
aldehydes,
or
other
organic
compounds
that
are
measured
separately
as
contained
in
a
gas
sample,
expressed
as
petroleumfueled
vessel
hydrocarbons.
The
hydrogen
to
carbon
ratio
of
the
equivalent
hydrocarbon
is
1.85:
1.
Ultimate
buyer
means
ultimate
purchaser.
Ultimate
purchaser
means,
with
respect
to
any
new
nonroad
equipment
or
new
nonroad
vessel,
the
first
person
who
in
good
faith
purchases
such
new
nonroad
equipment
or
new
nonroad
vessel
for
purposes
other
than
resale.
United
States
means
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.
U.
S.
directed
production
volume
means
the
number
of
vessel
units,
subject
to
the
requirements
of
this
part,
produced
by
a
manufacturer
for
which
the
manufacturer
has
a
reasonable
assurance
that
sale
was
or
will
be
made
to
ultimate
buyers
in
the
Unites
States.
Useful
life
means
the
period
during
which
the
vessel
or
engine
is
designed
to
properly
function
in
terms
of
reliability
and
fuel
consumption,
without
being
remanufactured,
specified
as
a
number
of
hours
of
operation
or
calendar
years.
It
is
the
period
during
which
a
new
vessel
or
new
engine
is
required
to
comply
with
all
applicable
emission
standards.
Vessel
means
marine
vessel
as
defined
in
the
General
Provisions
of
the
United
States
Code,
1
U.
S.
C.
3.
Void
means
to
invalidate
a
certificate
or
an
exemption.
If
we
void
a
certificate,
all
the
vessels
produced
under
that
emission
family
for
that
model
year
are
considered
noncompliant,
and
you
are
liable
for
each
vessel
produced
under
the
certificate
and
may
face
civil
or
criminal
penalties
or
both.
If
we
void
an
exemption,
all
the
vessels
produced
under
that
exemption
are
considered
uncertified
(or
nonconforming),
and
you
are
liable
for
each
vessel
produced
under
the
exemption
and
may
face
civil
or
criminal
penalties
or
both.
You
may
not
produce
any
additional
vessels
using
the
voided
exemption.
Volatile
liquid
fuel
means
any
fuel
other
than
diesel
or
biodiesel
that
is
a
liquid
at
atmospheric
pressure.
§
1045.805
What
symbols,
acronyms,
and
abbreviations
does
this
part
use?
The
following
symbols,
acronyms,
and
abbreviations
apply
to
this
part:
°
C
degrees
Celsius.
ASTM
American
Society
for
Testing
and
Materials.
ATV
all
terrain
vessel.
cc
cubic
centimeters.
CO
carbon
monoxide.
CO2
carbon
dioxide.
EPA
Environmental
Protection
Agency.
FEL
Family
emission
limit.
g/
kW
hr
grams
per
kilowatt
hour.
LPG
liquefied
petroleum
gas.
m
meters.
mm
Hg
millimeters
of
mercury.
NMHC
nonmethane
hydrocarbon.
NMHCE
nonmethane
hydrocarbon
equivalent.
NOX
oxides
of
nitrogen
(NO
and
NO2).
psig
pounds
per
square
inch
of
gauge
pressure.
rpm
revolutions
per
minute.
SAE
Society
of
Automotive
Engineers
SHED
Sealed
Housing
for
Evaporative
Determination.
SI
spark
ignition.
THC
total
hydrocarbon.
THCE
total
hydrocarbon
equivalent
U.
S.
United
States
U.
S.
C.
United
States
Code.
§
1045.810
What
materials
does
this
part
reference?
We
have
incorporated
by
reference
the
documents
listed
in
this
section.
The
Director
of
the
Federal
Register
approved
the
incorporation
by
reference
as
prescribed
in
5
U.
S.
C.
552(
a)
and
1
CFR
part
51.
Anyone
may
inspect
copies
at
U.
S.
EPA,
OAR,
Air
and
Radiation
Docket
and
Information
Center,
401
M
Street,
SW.,
Washington,
DC
20460;
or
Office
of
the
Federal
Register,
800
N.
Capitol
St.,
NW.,
7th
Floor,
Suite
700,
Washington,
DC.
(a)
ASTM
material.
Table
1
of
§
1045.810
lists
material
from
the
American
Society
for
Testing
and
Materials
that
we
have
incorporated
by
reference.
The
first
column
lists
the
number
and
name
of
the
material.
The
second
column
lists
the
sections
of
this
part
where
we
reference
it.
The
second
column
is
for
information
only
and
may
not
include
all
locations.
Anyone
may
receive
copies
of
these
materials
from
American
Society
for
Testing
and
Materials,
1916
Race
St.,
Philadelphia,
PA
19103.
Table
1
follows:
TABLE
1
OF
§
1045.810.—
ASTM
MATERIALS
Document
number
and
name
Part
1045
reference
ASTM
E29–
93a,
Standard
Practice
for
Using
Significant
Digits
in
Test
Data
to
Determine
Conformance
with
Specifications.
1045.240,
1045.315,
1045.345,
1045.410,
1045.415.
(b)
ISO
material.
[Reserved]
(c)
SAE
material.
[Reserved]
§
1045.815
How
should
I
request
EPA
to
keep
my
information
confidential?
(a)
Clearly
show
what
you
consider
confidential
by
marking,
circling,
bracketing,
stamping,
or
some
other
method.
We
will
store
your
confidential
information
as
described
in
40
CFR
part
2.
Also,
we
will
disclose
it
only
as
specified
in
40
CFR
part
2.
(b)
If
you
send
us
a
second
copy
without
the
confidential
information,
we
will
assume
it
contains
nothing
confidential
whenever
we
need
to
release
information
from
it.
(c)
If
you
send
us
information
without
claiming
it
is
confidential,
we
may
make
it
available
to
the
public
without
further
notice
to
you,
as
described
in
40
CFR
2.204.
§
1045.820
How
do
I
request
a
public
hearing?
(a)
File
a
request
for
a
hearing
with
the
Designated
Officer
within
15
days
of
a
decision
to
deny,
suspend,
revoke,
or
void
your
certificate.
If
you
ask
later,
we
may
give
you
a
hearing
for
good
cause,
but
we
do
not
have
to.
(b)
Include
the
following
in
your
request
for
a
public
hearing:
(1)
State
which
emission
family
is
involved.
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Federal
Register
/
Vol.
67,
No.
157
/
Wednesday,
August
14,
2002
/
Proposed
Rules
(2)
State
the
issues
you
intend
to
raise.
We
may
limit
these
issues,
as
described
elsewhere
in
this
part.
(3)
Summarize
the
evidence
supporting
your
position
and
state
why
you
believe
this
evidence
justifies
granting
or
reinstating
the
certificate.
(c)
We
will
hold
the
hearing
as
described
in
40
CFR
part
1068,
subpart
F.
PART
1051—
CONTROL
OF
EMISSIONS
FROM
RECREATIONAL
ENGINES
AND
VEHICLES
17.
The
authority
citation
for
part
1051
as
proposed
at
66
FR
51219
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401Ð
7671(
q).
Subpart
A—[
Amended]
18.
Section
1051.1
as
proposed
at
66
FR
51220
is
amended
by
adding
a
new
paragraph
(e)
to
read
as
follows:
§
1051.1
Does
this
part
apply
to
me?
*
*
*
*
*
(e)
This
part
also
applies
to
engines
under
50
cc
used
in
highway
motorcycles
if
the
manufacturer
uses
the
provisions
of
40
CFR
86.447Ð
2006
to
meet
the
emission
standards
in
this
part
instead
of
the
requirements
of
40
CFR
part
86.
Compliance
with
the
provisions
of
this
part
is
a
required
condition
of
that
exemption.
PART
1068—
GENERAL
COMPLIANCE
PROVISIONS
FOR
NONROAD
PROGRAMS
19.
The
authority
citation
for
part
1068
as
proposed
at
66
FR
51252
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401Ð
7671(
q).
Subpart
A—[
Amended]
20.
Section
1068.1
as
proposed
at
66
FR
51253
is
amended
by
revising
paragraph
(a)
to
read
as
follows:
§
1068.1
Does
this
part
apply
to
me?
(a)
The
provisions
of
this
part
apply
to
everyone
with
respect
to
the
following
engines
or
to
equipment
using
the
following
engines:
(1)
Marine
vessels
powered
by
sparkignition
engines
we
regulate
under
40
CFR
1045.
(2)
Large
nonroad
spark
ignition
engines
we
regulate
under
40
CFR
part
1048.
(3)
Snowmobiles,
all
terrain
vehicles,
and
off
highway
motorcycles
we
regulate
under
40
CFR
part
1051.
*
*
*
*
*
[FR
Doc.
02Ð
19437
Filed
8Ð
13Ð
02;
8:
45
am]
BILLING
CODE
6560–
50–
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| epa | 2024-06-07T20:31:39.927344 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0024-0001/content.txt"
} |
EPA-HQ-OAR-2002-0036-0001 | Notice | "2002-11-22T05:00:00" | National Emission Standards for Hazardous Air
Pollutants: Revision of Area Source Category List Under
Section 112(c)(3) and 112(k)(3)(B)(ii) of the Clean Air
Act | 70427
Federal
Register
/
Vol.
67,
No.
226
/
Friday,
November
22,
2002
/
Notices
timely
manner
and
can
not
suspend
processing
the
application
(
including
extending
the
REA
comment
deadline
date)
until
February
2003,
in
hopes
that
the
collaborative
team
will
reach
a
settlement.
The
Commission's
goal
is
to
issue
a
draft
and
final
EA
during
the
spring
and
summer
of
2003,
respectively,
and
be
ready
for
a
Commission
decision
on
the
application
by
September
2003,
prior
to
the
October
31,
2003,
license
expiration
date.
The
requests
to
file
the
SA
and
ES
by
February
14,
2003,
could
delay
taking
final
action
on
the
license
application
beyond
the
license
expiration
date.
Therefore,
a
limited
extension
of
time
is
granted
to
file
the
SA,
ES,
and
comments,
recommendations,
terms
and
conditions,
and
prescriptions.
k.
Deadline
for
filing
comments,
recommendations,
terms
and
conditions,
and
prescriptions:
December
27,
2002.
All
documents
(
original
and
eight
copies)
should
be
filed
with:
Magalie
R.
Salas,
Secretary,
Federal
Energy
Regulatory
Commission,
888
First
Street,
NE.,
Washington,
DC
20426.
The
Commission's
rules
of
practice
require
all
intervenors
filing
documents
with
the
Commission
to
serve
a
copy
of
that
document
on
each
person
on
the
official
service
list
for
the
project.
Further,
if
an
intervenor
files
comments
or
documents
with
the
Commission
relating
to
the
merits
of
an
issue
that
may
affect
the
responsibilities
of
a
particular
resource
agency,
they
must
also
serve
a
copy
of
the
document
on
that
resource
agency.
Comments,
recommendations,
terms
and
conditions,
and
prescriptions
may
be
filed
electronically
via
the
Internet
in
lieu
of
paper.
The
Commission
strongly
encourages
electronic
filings.
See
18
CFR
385.2001(
a)(
1)(
iii)
and
the
instructions
on
the
Commission's
web
sitehttp://
www.
ferc.
govunder
the
``
e
Filing''
link.
l.
A
copy
of
the
application
is
available
for
review
at
the
Commission
in
the
Public
Reference
Room
or
may
be
viewed
on
the
Commission's
website
at
http://
www.
ferc.
gov
using
the
``
FERRIS''
link.
Enter
the
docket
number
excluding
the
last
three
digits
in
the
docket
number
field
to
access
the
document.
For
assistance,
please
contact
FERC
Online
Support
at
FERCOnlineSupport@
ferc.
gov
or
tollfree
at
(
866)
208
3676,
or
for
TTY,
(
202)
502
8659.
A
copy
is
also
available
for
inspection
and
reproduction
at
the
address
in
item
h
above.
m.
All
filings
must
(
1)
bear
in
all
capital
letters
the
title
``
COMMENTS'',
``
REPLY
COMMENTS'',
``
RECOMMENDATIONS,''
``
TERMS
AND
CONDITIONS,''
or
``
PRESCRIPTIONS;''
(
2)
set
forth
in
the
heading
the
name
of
the
applicant
and
the
project
number
of
the
application
to
which
the
filing
responds;
(
3)
furnish
the
name,
address,
and
telephone
number
of
the
person
submitting
the
filing;
and
(
4)
otherwise
comply
with
the
requirements
of
18
CFR
385.2001
through
385.2005.
All
comments,
recommendations,
terms
and
conditions
or
prescriptions
must
set
forth
their
evidentiary
basis
and
otherwise
comply
with
the
requirements
of
18
CFR
4.34(
b).
Agencies
may
obtain
copies
of
the
application
directly
from
the
applicant.
Each
filing
must
be
accompanied
by
proof
of
service
on
all
persons
listed
on
the
service
list
prepared
by
the
Commission
in
this
proceeding,
in
accordance
with
18
CFR
4.34(
b),
and
385.2010.
Linwood
A.
Watson,
Jr.,
Deputy
Secretary.
[
FR
Doc.
02
29748
Filed
11
21
02;
8:
45
am]
BILLING
CODE
6717
01
P
ENVIRONMENTAL
PROTECTION
AGENCY
[
Docket
ID
No.
OAR
2002
0036;
AD
FRL
7412
5]
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Revision
of
Area
Source
Category
List
Under
Section
112(
c)(
3)
and
112(
k)(
3)(
B)(
ii)
of
the
Clean
Air
Act
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Notice
of
revisions
to
the
area
source
category
list
under
the
Integrated
Urban
Air
Toxics
Strategy.
SUMMARY:
This
notice
adds
23
area
source
categories
of
hazardous
air
pollutants
(
HAP)
to
the
previous
lists
developed
under
the
Integrated
Urban
Air
Toxics
Strategy
(
Strategy).
With
the
addition
of
these
categories,
the
requirement
to
identify
and
list
area
source
categories
representing
at
least
90
percent
of
the
emissions
of
the
30
``
listed''
(
or
area
source)
HAP
under
section
112(
c)(
3)
and
112(
k)(
3)(
B)(
ii)
of
the
Clean
Air
Act
(
CAA)
is
fulfilled.
The
Strategy's
area
source
category
list
constitutes
an
important
part
of
EPA's
agenda
for
regulating
stationary
sources
of
air
topics
emissions.
These
revisions
to
the
list
of
area
sources
have
not
been
reflected
in
any
previous
notices
and
are
being
made
without
public
comment
on
the
Administrator's
own
motion.
Such
revisions
are
deemed
by
EPA
to
be
without
need
for
public
comment
based
on
the
nature
of
the
actions.
EFFECTIVE
DATE:
November
22,
2002.
ADDRESSES:
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
EPA
Docket
Center,
(
EPA/
DC)
EPA
West,
Room
B102,
1301
Constitution
Ave.,
NW.,
Washington,
DC.
FOR
FURTHER
INFORMATION
CONTACT:
Ms.
Barbara
B.
Driscoll,
Policy,
Planning
and
Standards
Group,
Emission
Standards
Division
(
C439
04),
EPA,
Research
Triangle,
Park,
North
Carolina
27711,
facsimile
number
(
919)
541
0942
telephone
number
(
919)
541
1051,
electronic
mail
(
e
mail):
driscoll.
barbara@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Docket.
The
EPA
has
established
an
official
public
docket
for
this
action
under
the
Docket
ID
No.
OAR
2002
0036.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
received
and
other
information
related
to
this
action.
Although
a
part
of
the
official
docket,
the
public
docket
does
not
include
Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
1744,
and
the
telephone
number
for
the
Docket
is
(
202)
566
1742.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.
Electronic
Access.
You
may
access
this
Federal
Register
document
electronically
through
the
EPA
Internet
under
the
``
Federal
Register''
listings
at
http://
www.
epa.
gov/
fedrgstr/.
An
electronic
version
of
the
public
docket
is
available
through
EPA's
electronic
public
docket
and
comment
system,
EPA
Dockets.
You
may
use
EPA
Dockets
at
http://
www.
epa.
gov/
edocket/
to
view
public
comments,
access
the
index
listing
of
the
contents
of
the
official
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Although
not
all
docket
materials
may
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
identified
in
this
document.
Once
in
the
system,
select
``
search,''
then
key
in
the
appropriate
docket
identification.
Worldwide
Web
(
WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
today's
notice
will
also
be
available
on
the
WWW
through
the
Technology
Transfer
Network
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Register
/
Vol.
67,
No.
226
/
Friday,
November
22,
2002
/
Notices
(
TTN).
Following
signature,
a
copy
of
the
notice
will
be
posted
on
the
TTN's
policy
and
guidance
page,
http://
www.
epg.
gov/
ttn/
oarpg.
The
TNN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TNN
is
needed,
call
the
TNN
HELP
line
at
(
919)
541
5384.
I.
What
Is
the
History
of
the
Integrated
Urban
Air
Toxics
Strategy
Area
Source
Category
List?
The
CAA
includes
two
provisions,
section
112(
c)(
3)
and
112(
k)(
3)(
B)(
ii),
that
instruct
EPA
to
identify
and
list
area
source
categories
accounting
for
at
least
90
percent
of
the
emissions
of
the
30
``
listed''
(
or
area
source)
HAP
(
64
FR
38706,
July
19,
1999),
and
that
are,
or
will
be,
subject
to
standards
under
section
112(
d)
of
the
CAA.
For
this
effort,
we
have
used
urban
area
source
information
from
the
section
112(
k)
inventory,
which
represents
a
baseline
year
of
1990.
In
the
July
1999
Strategy,
we
identified
16
area
source
categories
that
had
already
been
listed
for
regulation
under
the
CAA,
and
13
area
source
categories
that
were
being
listed
under
section
112(
c)(
3)
for
the
first
time.
These
29
area
source
categories
are:
Cyclic
Crude
and
Intermediate
Production
Flexible
Polyurethane
Foam
Fabrication
Operations
Hospital
Sterilizers
Industrial
Inorganic
Chemical
Manufacturing
Industrial
Organic
Chemical
Manufacturing
Mercury
Cell
Chlor
Alkali
Plants
Gasoline
Distribution
Stage
1
Municipal
Landfills
Oil
and
Natural
Gas
Production
Paint
Stripping
Operations
Plastic
Materials
and
Resins
Manufacturing
Publicly
Owned
Treatment
Works
Synthetic
Rubber
Manufacturing
Chromic
Acid
Anodizing
Commercial
Sterilization
Facilities
Other
Solid
Waste
Incinerators
(
Human/
Animal
Cremation)
Decorative
Chromium
Electroplating
Dry
Cleaning
Facilities
Halogenated
Solvent
Cleaners
Hard
Chromium
Electroplating
Hazardous
Waste
Combustors
Industrial
Boilers
Institutional/
Commercial
Boilers
Medical
Waste
Incinerators
Municipal
Waste
Combustors
Open
Burning
Scrap
Tires
Portland
Cement
Secondary
Lead
Smelting
Stationary
Internal
Combustion
Engines.
Each
of
the
first
13
area
source
categories
above,
which
were
listed
for
the
first
time
in
June
1999,
contributed
at
least
15
percent
of
the
total
area
source
urban
emissions
for
at
least
one
of
the
30
area
source
HAP.
We
also
took
credit
for
the
percentage
of
emission
contribution
from
the
last
16
area
source
categories
on
the
list
above.
Since
then,
we
added
Secondary
Aluminum
Production
to
our
list
of
major
and
area
source
categories
(
66
FR
8220,
January
30,
2001).
On
June
26,
2002,
we
listed
an
additional
18
area
source
categories:
Acrylic
Fibers/
Modacrylic
Fibers
Production
Plating
and
Polishing
Agricultural
Chemicals
&
Pesticides
Manufacturing
Autobody
Refinishing
Paint
Shops
Cadmium
Refining
&
Cadmium
Oxide
Production
Flexible
Polyurethane
Foam
Production
Iron
Foundries
Lead
Acid
Battery
Manufacturing
Miscellaneous
Organic
Chemical
Manufacturing
(
MON)
Pharmaceutical
Production
Polyvinyl
Chloride
&
Copolymers
Production
Pressed
and
Blown
Glass
&
Glassware
Manufacturing
Secondary
Copper
Smelting
Secondary
Nonferrous
Metals
Sewage
Sludge
Incineration
Stainless
and
Nonstainless
Steel
Manufacturing
Electric
Arc
Furnaces
(
EAF)
Steel
Foundries
Wood
Preserving.
The
listing
of
all
these
categories,
however,
did
not
meet
the
requirement
to
list
area
sources
representing
90
percent
of
the
area
source
emissions
of
the
30
area
source
HAP.
In
the
Strategy,
we
indicated
that
we
would
be
adding
additional
area
source
categories
as
necessary
to
meet
the
90
percent
requirement
and
would
complete
our
listing
by
2003.
II.
Why
Is
EPA
Issuing
This
Notice?
Under
the
provisions
of
section
112(
c)(
3)
and
112(
k)(
3)(
B)(
ii),
this
notice
announces
the
addition
of
23
area
source
categories
to
the
list
initially
published
on
July
19,
1999
(
64
FR
38721),
amended
on
January
30,
2001
(
66
FR
8220),
and
on
June
26,
2002
(
67
FR
43112).
While
this
listing
is
again
based
on
the
section
112(
k)
inventory
which
represents
urban
area
information
for
1990,
current
information
will
be
used
for
any
type
of
regulatory
development.
Each
of
the
source
categories
contributes
a
percentage
of
the
total
area
source
emissions
for
at
least
one
of
the
30
area
source
HAP
and
completes
our
requirement
to
address
90
percent
of
the
emissions
of
each
of
the
30
area
source
HAP.
The
additional
area
source
categories
being
listed
pursuant
to
section
112(
c)(
3)
and
112(
k)(
3)(
B)(
ii)
are:
Asphalt
Processing
and
Asphalt
Roofing
Manufacturing
Brick
and
Structural
Clay
Products
Manufacturing
Carbon
Black
Production
Chemical
Manufacturing:
Chromium
Compounds
Chemical
Preparations
Clay
Ceramics
Manufacturing
Industrial
Machinery
and
Equipment:
Finishing
Operations
Copper
Foundries
Electrical
and
Electronics
Equipment:
Finishing
Operations
Ferroalloys
Production:
Ferromanganese
and
Silicomanganese
Fabricated
Metal
Products
Manufacturing,
not
elsewhere
classified
(
nec)
Fabricated
Plate
Work
(
Boiler
Shops)
Fabricated
Structural
Metal
Manufacturing
Heating
Equipment
Manufacturing,
Except
Electric
Inorganic
Pigments
Manufacturing
Iron
and
Steel
Forging
Nonferrous
Foundries,
nec
Paints
and
Allied
Products
Manufacturing
Plastic
Parts
and
Products
(
Surface
Coating)
Prepared
Feeds
Manufacturing
Primary
Copper
Smelters
Primary
Metals
Products
Manufacturing
Valves
and
Pipe
Fittings
Manufacturing
In
addition
to
adding
these
area
source
categories,
EPA
is
also
revising
the
name
of
the
area
source
category
Cadmium
Refining
and
Cadmium
Oxide
Production
to
Primary
Nonferrous
Metals
Zinc,
Cadmium
and
Beryllium.
This
category
is
also
being
expanded
to
include
these
other
operations:
Primary
Smelting
and
Refining
of
Zinc,
and
Primary
Nonferrous
Metals.
Expanding
this
source
category
to
include
these
additional
operations
is
needed
to
meet
the
90
percent
requirement
for
several
HAP.
The
name
of
the
area
source
category
Lead
and
Acid
Battery
Manufacturing
is
also
changed
to
Lead
Acid
Battery
Manufacturing.
In
a
recent
notice,
addressed
in
a
separate
Federal
Register
notice),
the
area
source
category
Open
Burning
of
Scrap
Tires
was
removed
from
source
categories
included
in
the
inventory
analysis
for
section
112(
c)(
6)
and
112(
k).
Consequently,
that
source
category
will
no
longer
be
a
candidate
for
regulation
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Federal
Register
/
Vol.
67,
No.
226
/
Friday,
November
22,
2002
/
Notices
under
either
section
112(
c)(
6)
or
112(
k).
As
a
result,
two
area
source
categories:
Asphalt
Processing
and
Asphalt
Roof
Manufacturing,
and
Carbon
Black
Production
were
added
to
the
section
112(
k)
list
above
to
ensure
that
90
percent
of
the
emissions
of
the
HAP,
polycyclic
organic
matter,
are
addressed.
III.
Administrative
Requirements
Today's
notice
is
not
a
rule;
it
is
essentially
an
information
sharing
activity
which
does
not
impose
regulatory
requirements
or
costs.
Therefore,
the
requirements
of
Executive
Order
13045
(
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks),
Executive
Order
13175
(
Consultation
and
Coordination
with
Indian
Tribal
Governments),
Executive
Order
13132
(
Federalism),
Executive
Order
13211
(
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use),
the
Regulatory
Flexibility
Act,
the
National
Technology
Transfer
and
Advancement
Act,
and
the
Unfunded
Mandates
Reform
Act
do
not
apply
to
today's
notice.
Also,
this
notice
does
not
contain
any
information
collection
requirements
and,
therefore,
is
not
subject
to
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
a
regulatory
action
determined
to
be
``
significant''
is
subject
to
the
Office
of
Management
and
Budget
(
OMB)
review
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant''
regulatory
action
as
one
that
is
likely
to
lead
to
a
rule
that
may
either:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more,
or
adversely
affect
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
take
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
(
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.
The
OMB
has
determined
that
this
action
is
not
significant
under
the
terms
of
Executive
Order
12866.
Dated:
November
13,
2002.
Robert
Brenner,
Acting
Assistant
Administrator
for
Air
and
Radiation.
[
FR
Doc.
02
29774
Filed
11
21
02;
8:
45
am]
BILLING
CODE
6560
50
M
ENVIRONMENTAL
PROTECTION
AGENCY
[
ER
FRL
6635
2]
Environmental
Impact
Statements;
Notice
of
Availability
Responsible
Agency:
Office
of
Federal
Activities,
General
Information
(
202)
564
7167
or
http://
www.
epa.
gov/
compliance/
nepa.
Weekly
receipt
of
Environmental
Impact
Statements
Filed
November
11,
2002,
through
November
15,
2002,
Pursuant
to
40
CFR
1506.9.
EIS
No.
020466,
Draft
Supplement,
FHW,
MI,
US
31
Freeway
Connection
from
Napier
Road
to
I
94
Project,
transportation
improvement,
updated
information,
Berrien
County,
MI,
comment
period
ends:
January
3,
2003,
contact:
James
Kirschensteiner
(
517)
702
1835.
EIS
No.
020472,
Draft
Supplement,
COE,
FL,
Upper
ST.
Johns
River
Basin
and
Related
Areas,
Central
and
Southern
Florida
Flood
Control
Project,
proposed
modifications
to
project
features
north
of
the
Fellsmere
Grade,
to
preserve
and
enhance
floodplain
and
aquatic
habitats,
Brevard
County,
FL,
comment
period
ends:
January
3,
2003,
contact:
Esteban
Jimerez
(
904)
232
2115.
EIS
No.
020473,
Draft
EIS,
BLM,
NV,
Ivanpah
Energy
Center
Project,
proposes
to
construct
and
operate
a
500
Megawatt
(
MW)
gas
fired
electric
power
generating
station
in
southern
Clark
County,
NV,
comment
period
ends:
January
3,
2003,
contact:
Jerrold
E.
Crockford
(
505)
599
6333.
EIS
No.
020474,
Draft
EIS,
FHW,
AK,
South
Extension
of
the
Coastal
Trail
Project,
to
extend
the
existing
Tony
Knowles
Coastal
Trail
from
Kincaid
Park
through
the
project
area
to
the
Potter
Weigh
Station,
COE
section
10
and
404
permit,
municipality
of
Anchorage,
Anchorage,
Alaska,
comment
period
ends:
January
8,
2003,
contact:
Tim
A.
Haugh
(
907)
586
7418.
This
document
is
available
on
the
Internet
at:
http://
home.
gci.
net/
southtrail.
EIS
No.
020475,
Draft
EIS,
USN,
CA,
China
Lake
Naval
Air
Weapons
Station,
proposed
military
operational
increases
and
implementation
of
associated
comprehensive
land
use
and
integrated
natural
resources
management
plans,
located
in
the
North
and
South
Range,
Inyo,
Kern
and
San
Bernardino
Counties,
CA,
comment
period
ends:
February
18,
2003,
contact:
John
O'Gara
(
076)
093
9321.
EIS
No.
020476,
Final
EIS,
COE,
FL,
Miami
River
Dredged
Material
Management
Plan,
river
sediments
dredging
and
disposal
maintenance
dredging,
Biscayne
Bay,
city
of
Miami,
Miami
Dade
County,
FL,
wait
period
ends:
December
23,
2002,
contact:
Daniel
Small
(
404)
562
5224.
Amended
Notices
EIS
No.
020405,
Draft
EIS,
FHW,
NH,
Interstate
93
Improvements,
from
Salem
to
Manchester,
IM
IR
93
1(
174)
0,
10418
C,
funding,
NPDES
and
COE
section
404
permits,
Hillsborough
and
Rockingham
Counties,
NH,
comment
period
ends:
December
16,
2002,
contact:
William
F.
O'Donnell
(
603)
228
3057.
Revision
of
Federal
Register
notice
published
on
10/
4/
2002:
CEQ
comment
period
ending
11/
18/
2002
has
been
extended
to
12/
16/
2002.
EIS
No.
020445,
Draft
EIS,
COE,
Lake
Sidney
Lanier
Project,
to
continue
the
ongoing
operation
and
maintenance
activities
necessary
of
flood
control,
hydropower
generation,
water
supply,
recreation,
natural
resources
management,
and
shoreline
management,
section
10
and
404
permits,
Dawson,
Forsyth,
Lumpkin,
Hill
and
Gwinnett
Counties,
GA,
comment
period
ends:
December
23,
2002,
contact:
Glen
Coffee
(
251)
690
2727.
Revision
of
Federal
Register
notice
published
on
11/
8/
2002:
correction
to
contact
name
and
telephone
number.
Also
Draft
EIS
is
available
on
Internet
at:
http://
www.
usacelakelaniereis.
net/.
Dated:
November
19,
2002.
B.
Katherine
Biggs,
Associate
Director,
NEPA
Compliance,
Office
of
Federal
Activities.
[
FR
Doc.
02
29781
Filed
11
21
02;
8:
45
am]
BILLING
CODE
6560
50
P
ENVIRONMENTAL
PROTECTION
AGENCY
[
ER
FRL
6635
3]
Environmental
Impact
Statements
and
Regulations;
Availability
of
EPA
Comments
Availability
of
EPA
comments
prepared
pursuant
to
the
Environmental
Review
Process
(
ERP),
under
section
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| epa | 2024-06-07T20:31:40.004639 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0036-0001/content.txt"
} |
EPA-HQ-OAR-2002-0038-0001 | Proposed Rule | "2002-12-09T05:00:00" | National Emission Standards for Hazardous Air Pollutants for Source Categories: General Provisions; and Requirements for Control Technology eterminations for Major Sources in Accordance with Clean Air Act Sections, Sections 112(g) and 112(j) | 72875
Federal
Register
/
Vol.
67,
No.
236
/
Monday,
December
9,
2002
/
Proposed
Rules
II.
Where
can
I
find
more
information
about
this
proposal
and
corresponding
direct
final
rule?
I.
What
Action
Is
EPA
Taking
Today?
The
EPA
is
proposing
to
approve
as
a
revision
to
the
Indiana
particulate
matter
SIP
emission
control
regulations
that
pertain
to
Knauf
Fiber
Glass
(
Knauf)
which
is
located
in
Shelbyville,
Indiana,
as
requested
by
the
State
of
Indiana
on
October
17,
2002.
This
SIP
submission
makes
changes
to
federally
enforceable
Indiana
air
pollution
control
rules.
Indiana
made
these
changes
at
the
request
of
Knauf,
and
they
apply
to
the
operation
of
the
Knauf
fiberglass
plant
in
Shelbyville,
Indiana.
The
rule
revisions
modify
the
PM
emissions
limits
adopted
by
the
State
in
the
1980s
which
EPA
approved
as
part
of
the
current
Indiana
SIP.
The
revised
rules
delete
references
to
equipment
no
longer
in
use
by
Knauf
and
update
names
of
equipment
which
remains
in
use.
Because
the
revised
rules
reduce
both
allowable
emissions
and
the
allowable
emissions
rate
and
reflect
current
operations
at
the
Knauf
facility,
EPA
approval
of
these
revisions
should
not
result
in
an
adverse
impact
on
air
quality.
II.
Where
Can
I
Find
More
Information
About
This
Proposal
and
Corresponding
Direct
Final
Rule?
For
additional
information
see
the
direct
final
rule
published
in
the
rules
and
regulations
section
of
this
Federal
Register.
Authority:
42
U.
S.
C.
4201
et
seq.
Dated:
November
7,
2002.
Bharat
Mathur,
Acting
Regional
Administrator,
Region
5.
[
FR
Doc.
02
30938
Filed
12
6
02;
8:
45
am]
BILLING
CODE
6560
50
P
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[
FRL
7419
6]
RIN
2060
AK52
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Source
Categories:
General
Provisions;
and
Requirements
for
Control
Technology
Determinations
for
Major
Sources
in
Accordance
with
Clean
Air
Act
Sections,
Sections
112(
g)
and
112(
j)
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Proposed
rule;
amendments.
SUMMARY:
In
this
action,
we
are
proposing
specific
amendments
to
the
General
Provisions
for
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP),
and
to
the
rule
establishing
requirements
for
case
by
case
determinations
under
Clean
Air
Act
(
CAA)
section
112(
j).
We
are
proposing
to
establish
a
new
timetable
for
the
submission
of
section
112(
j)
Part
2
applications
which
is
derived
from
our
agreed
timetable
for
promulgation
of
the
remaining
NESHAP.
This
new
timetable
for
Part
2
applications
is
intended
both
to
avoid
the
expenditure
of
unnecessary
resources
by
affected
sources
and
permitting
authorities,
and
to
create
new
incentives
for
prompt
completion
of
the
remaining
standards.
We
are
also
proposing
to
make
several
changes
in
the
section
of
the
General
Provisions
rule
that
establishes
general
procedures
for
preparation,
maintenance,
and
periodic
revision
of
startup,
shutdown,
and
malfunction
(
SSM)
plans.
These
amendments
are
being
proposed
pursuant
to
a
settlement
agreement
concerning
a
petition
for
judicial
review
of
the
prior
amendments
to
these
rules
published
on
April
5,
2002.
We
are
also
proposing
to
revise
a
recordkeeping
provision
which
we
adopted
in
response
to
comments
we
received
on
the
prior
amendments
because
we
have
concluded
that
the
recordkeeping
provision
should
be
more
narrow
in
applicability.
DATES:
Comments.
Submit
comments
on
or
before
January
20,
2003.
Public
Hearing.
If
anyone
contacts
us
requesting
to
speak
at
a
public
hearing
by
December
16,
2002,
a
public
hearing
will
be
held
on
December
19,
2002.
ADDRESSES:
Comments.
Written
comments
may
be
submitted
to:
Air
and
Radiation
Docket
and
Information
Center,
Attention
Docket
Number
OAR
2002
0038,
Part
63
General
Provisions
(
Subpart
A)
and
Section
112(
j)
Regulations
(
Subpart
B)
Litigation
Settlement
Amendments
II,
Mailcode
6102T,
1200
Pennsylvania
Avenue,
NW,
Washington,
DC
20460.
Public
Hearing.
If
a
public
hearing
is
held,
it
will
be
held
at
10
a.
m.
on
December
19,
2002
in
our
EPA
facility
complex,
109
T.
W.
Alexander
Drive,
Research
Triangle
Park,
North
Carolina,
or
at
an
alternate
site
nearby.
FOR
FURTHER
INFORMATION
CONTACT:
Mr.
Rick
Colyer,
Emission
Standards
Division
(
C504
05),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711,
telephone
(
919)
541
5262,
e
mail
colyer.
rick@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Regulated
Entities
Categories
and
entities
potentially
regulated
by
this
action
include
all
section
112
source
categories
listed
under
section
112(
c)
of
the
CAA.
Industry
Group:
Source
Category
Fuel
Combustion:
Coal
and
Oil
fired
Electric
Utility
Steam
Generating
Units
Combustion
Turbines
Engine
Test
Facilities
Industrial
Boilers
Institutional/
Commercial
Boilers
Process
Heaters
Reciprocating
Internal
Combustion
Engines
Rocket
Testing
Facilities
Non
Ferrous
Metals
Processing:
Primary
Aluminum
Production
Primary
Copper
Smelting
Primary
Lead
Smelting
Primary
Magnesium
Refining
Secondary
Aluminum
Production
Secondary
Lead
Smelting
Ferrous
Metals
Processing:
Coke
Ovens:
Charging,
Top
Side,
and
Door
Leaks
Coke
Ovens:
Pushing,
Quenching,
Battery
Stacks
Ferroalloys
Production:
Silicomanganese
and
Ferromanganese
Integrated
Iron
and
Steel
Manufacturing
Iron
Foundries
Steel
Foundries
Steel
Pickling
HCl
Process
Facilities
and
Hydrochloric
Acid
Regeneration
Mineral
Products
Processing:
Asphalt
Processing
Asphalt
Roofing
Manufacturing
Asphalt/
Coal
Tar
Application
Metal
Pipes
Brick
and
Clay
Products
Manufacturing
Ceramics
Manufacturing
Lime
Manufacturing
Mineral
Wool
Production
Portland
Cement
Manufacturing
Refractories
Manufacturing
Taconite
Iron
Ore
Processing
Wool
Fiberglass
Manufacturing
Petroleum
and
Natural
Gas
Production
and
Refining:
Oil
and
Natural
Gas
Production
Natural
Gas
Transmission
and
Storage
Petroleum
Refineries
Catalytic
Cracking
Units,
Catalytic
Reforming
Units,
and
Sulfur
Plant
Units
Petroleum
Refineries
Other
Sources
Not
Distinctly
Listed
Liquids
Distribution:
Gasoline
Distribution
(
Stage
1)
Marine
Vessel
Loading
Operations
Organic
Liquids
Distribution
(
Non
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Register
/
Vol.
67,
No.
236
/
Monday,
December
9,
2002
/
Proposed
Rules
Gasoline)
Surface
Coating
Processes:
Aerospace
Industries
Auto
and
Light
Duty
Truck
(
Surface
Coating)
Large
Appliance
(
Surface
Coating)
Magnetic
Tapes
(
Surface
Coating)
Manufacture
of
Paints,
Coatings,
and
Adhesives
Metal
Can
(
Surface
Coating)
Metal
Coil
(
Surface
Coating)
Metal
Furniture
(
Surface
Coating)
Miscellaneous
Metal
Parts
and
Products
(
Surface
Coating)
Paper
and
Other
Webs
(
Surface
Coating)
Plastic
Parts
and
Products
(
Surface
Coating)
Printing,
Coating,
and
Dyeing
of
Fabrics
Printing/
Publishing
(
Surface
Coating)
Shipbuilding
and
Ship
Repair
(
Surface
Coating)
Wood
Building
Products
(
Surface
Coating)
Wood
Furniture
(
Surface
Coating)
Waste
Treatment
and
Disposal:
Hazardous
Waste
Incineration
Municipal
Solid
Waste
Landfills
Off
Site
Waste
and
Recovery
Operations
Publicly
Owned
Treatment
Works
(
POTW)
Site
Remediation
Agricultural
Chemicals
Production:
Pesticide
Active
Ingredient
Production
Fibers
Production
Processes:
Acrylic
Fibers/
Modacrylic
Fibers
Production
Spandex
Production
Food
and
Agriculture
Processes:
Manufacturing
of
Nutritional
Yeast
Solvent
Extraction
for
Vegetable
Oil
Production
Pharmaceutical
Production
Processes:
Pharmaceuticals
Production
Polymers
and
Resins
Production:
Acetal
Resins
Production
Acrylonitrile
Butadiene
Styrene
Production
Alkyd
Resins
Production
Amino
Resins
Production
Boat
Manufacturing
Butyl
Rubber
Production
Cellulose
Ethers
Production
Epichlorohydrin
Elastomers
Production
Epoxy
Resins
Production
Ethylene
Propylene
Rubber
Production
Flexible
Polyurethane
Foam
Production
Hypalon
(
tm)
Production
Maleic
Anhydride
Copolymers
Production
Methyl
Methacrylate
Acrylonitrile
Butadiene
Styrene
Production
Methyl
Methacrylate
Butadiene
Styrene
Terpolymers
Production
Neoprene
Production
Nitrile
Butadiene
Rubber
Production
Nitrile
Resins
Production
Non
Nylon
Polyamides
Production
Phenolic
Resins
Production
Polybutadiene
Rubber
Production
Polycarbonates
Production
Polyester
Resins
Production
Polyether
Polyols
Production
Polyethylene
Terephthalate
Production
Polymerized
Vinylidene
Chloride
Production
Polymethyl
Methacrylate
Resins
Production
Polystyrene
Production
Polysulfide
Rubber
Production
Polyvinyl
Acetate
Emulsions
Production
Polyvinyl
Alcohol
Production
Polyvinyl
Butyral
Production
Polyvinyl
Chloride
and
Copolymers
Production
Reinforced
Plastic
Composites
Production
Styrene
Acrylonitrile
Production
Styrene
Butadiene
Rubber
and
Latex
Production
Production
of
Inorganic
Chemicals:
Ammonium
Sulfate
Production
Caprolactam
By
Product
Plants
Carbon
Black
Production
Chlorine
Production
Cyanide
Chemicals
Manufacturing
Fumed
Silica
Production
Hydrochloric
Acid
Production
Hydrogen
Fluoride
Production
Phosphate
Fertilizers
Production
Phosphoric
Acid
Manufacturing
Production
of
Organic
Chemicals:
Ethylene
Processes
Quaternary
Ammonium
Compounds
Production
Synthetic
Organic
Chemical
Manufacturing
Miscellaneous
Processes:
Benzyltrimethylammonium
Chloride
Production
Carbonyl
Sulfide
Production
Chelating
Agents
Production
Chlorinated
Paraffins
Production
Chromic
Acid
Anodizing
Commercial
Dry
Cleaning
(
Perchloroethylene)
Transfer
Machines
Commercial
Sterilization
Facilities
Decorative
Chromium
Electroplating
Ethylidene
Norbornene
Production
Explosives
Production
Flexible
Polyurethane
Foam
Fabrication
Operations
Friction
Materials
Manufacturing
Halogenated
Solvent
Cleaners
Hard
Chromium
Electroplating
Hydrazine
Production
Industrial
Dry
Cleaning
(
Perchloroethylene)
Dry
to
dry
Machines
Industrial
Dry
Cleaning
(
Perchloroethylene)
Transfer
Machines
Industrial
Process
Cooling
Towers
Leather
Finishing
Operations
Miscellaneous
Vicose
Processes
OBPA/
1,3
Diisocyanate
Production
Paint
Stripping
Operations
Photographic
Chemicals
Production
Phthalate
Plasticizers
Production
Plywood
and
Composite
Wood
Products
Pulp
and
Paper
Production
Rubber
Chemicals
Manufacturing
Rubber
Tire
Manufacturing
Semiconductor
Manufacturing
Symmetrical
Tetrachloropyridine
Production
Wet
formed
Fiberglass
Mat
Production
Categories
of
Area
Sources:
Chromic
Acid
Anodizing
Commercial
Dry
Cleaning
(
Perchloroethylene)
Dry
to
Dry
Machines
Commercial
Dry
Cleaning
(
Perchloroethylene)
Transfer
Machines
Commercial
Sterilization
Facilities
Decorative
Chromium
Electroplating
Halogenated
Solvent
Cleaners
Hard
Chromium
Electroplating
Hazardous
Waste
Incinerators
Portland
Cement
Production
Secondary
Aluminum
Production
Secondary
Lead
Smelting
This
list
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
you
are
regulated
by
this
action,
you
should
examine
your
source
category
specific
section
112
regulation.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Docket
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
OAR
2002
0038.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
received,
and
other
information
related
to
this
action.
Although
a
part
of
the
official
docket,
the
public
docket
does
not
include
Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
Part
63
General
Provisions
(
Subpart
A)
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Federal
Register
/
Vol.
67,
No.
236
/
Monday,
December
9,
2002
/
Proposed
Rules
and
Section
112(
j)
Regulations
(
Subpart
B)
Litigation
Settlement
Amendments
II
Docket
in
the
EPA
Docket
Center,
(
EPA/
DC)
EPA
West,
Room
B102,
1301
Constitution
Ave.,
NW,
Washington,
DC.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
1744,
and
the
telephone
number
for
the
Part
63
General
Provisions
(
Subpart
A)
and
Section
112(
j)
Regulations
(
Subpart
B)
Litigation
Settlement
Amendments
II
Docket
is
(
202)
566
1742).
A
reasonable
fee
may
be
charged
for
copying
docket
materials.
You
may
access
this
Federal
Register
document
electronically
through
the
EPA
Internet
under
the
``
Federal
Register''
listings
at
http://
www.
epa.
gov/
fedrgstr/.
An
electronic
version
of
the
public
docket
is
available
through
EPA's
electronic
public
docket
and
comment
system,
EPA
Dockets.
You
may
use
EPA
Dockets
at
http://
www.
epa.
gov/
edocket/
to
submit
or
view
public
comments,
access
the
index
listing
of
the
contents
of
the
official
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,''
then
key
in
the
appropriate
docket
identification
number.
Certain
types
of
information
will
not
be
placed
in
the
EPA
Dockets.
Information
claimed
as
CBI
and
other
information
whose
disclosure
is
restricted
by
statute,
which
is
not
included
in
the
official
public
docket,
will
not
be
available
for
public
viewing
in
EPA's
electronic
public
docket.
EPA's
policy
is
that
copyrighted
material
will
not
be
placed
in
EPA's
electronic
public
docket
but
will
be
available
only
in
printed,
paper
form
in
the
official
public
docket.
To
the
extent
feasible,
publicly
available
docket
materials
will
be
made
available
in
EPA's
electronic
public
docket.
When
a
document
is
selected
from
the
index
list
in
EPA
Dockets,
the
system
will
identify
whether
the
document
is
available
for
viewing
in
EPA's
electronic
public
docket.
Although
not
all
docket
materials
may
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
previously
identified.
For
public
commenters,
it
is
important
to
note
that
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
in
paper,
will
be
made
available
for
public
viewing
in
EPA's
electronic
public
docket
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
EPA's
electronic
public
docket.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Public
comments
submitted
on
computer
disks
that
are
mailed
or
delivered
to
the
docket
will
be
transferred
to
EPA's
electronic
public
docket.
Public
comments
that
are
mailed
or
delivered
to
the
Docket
will
be
scanned
and
placed
in
EPA's
electronic
public
docket.
Where
practical,
physical
objects
will
be
photographed,
and
the
photograph
will
be
placed
in
EPA's
electronic
public
docket
along
with
a
brief
description
written
by
the
docket
staff.
You
may
submit
comments
electronically,
by
mail,
by
facsimile,
or
through
hand
delivery/
courier.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
comment.
Please
ensure
that
your
comments
are
submitted
within
the
specified
comment
period.
Comments
received
after
the
close
of
the
comment
period
will
be
marked
``
late.''
EPA
is
not
required
to
consider
these
late
comments.
If
you
wish
to
submit
CBI
or
information
that
is
otherwise
protected
by
statute,
please
follow
the
instructions
below.
Do
not
use
EPA
Dockets
or
e
mail
to
submit
CBI
or
information
protected
by
statute.
If
you
submit
an
electronic
comment
as
prescribed
below,
EPA
recommends
that
you
include
your
name,
mailing
address,
and
an
e
mail
address
or
other
contact
information
in
the
body
of
your
comment.
Also
include
this
contact
information
on
the
outside
of
any
disk
or
CD
ROM
you
submit
and
in
any
cover
letter
accompanying
the
disk
or
CD
ROM.
This
ensures
that
you
can
be
identified
as
the
submitter
of
the
comment
and
allows
EPA
to
contact
you
in
case
EPA
cannot
read
your
comment
due
to
technical
difficulties
or
needs
further
information
on
the
substance
of
your
comment.
EPA's
policy
is
that
EPA
will
not
edit
your
comment,
and
any
identifying
or
contact
information
provided
in
the
body
of
a
comment
will
be
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket
and
made
available
in
EPA's
electronic
public
docket.
If
EPA
cannot
read
your
comment
due
to
technical
difficulties
and
cannot
contact
you
for
clarification,
EPA
may
not
be
able
to
consider
your
comment.
Your
use
of
EPA's
electronic
public
docket
to
submit
comments
to
EPA
electronically
is
EPA's
preferred
method
for
receiving
comments.
Go
directly
to
EPA
Dockets
at
http://
www.
epa.
gov/
edocket
and
follow
the
online
instructions
for
submitting
comments.
To
access
EPA's
electronic
public
docket
from
the
EPA
Internet
Home
Page,
select
``
Information
Sources,''
``
Dockets,''
and
``
EPA
Dockets.''
Once
in
the
system,
select
``
search,''
and
then
key
in
Docket
ID
No.
OAR
2002
0038.
The
system
is
an
``
anonymous
access''
system,
which
means
EPA
will
not
know
your
identity,
e
mail
address,
or
other
contact
information
unless
you
provide
it
in
the
body
of
your
comment.
Comments
may
be
sent
by
electronic
mail
(
e
mail)
to
a
and
r
Docket@
epa.
gov,
Attention
Docket
ID
No.
OAR
2002
0038.
In
contrast
to
EPA's
electronic
public
docket,
EPA's
email
system
is
not
an
``
anonymous
access''
system.
If
you
send
an
e
mail
comment
directly
to
the
Docket
without
going
through
EPA's
electronic
public
docket,
EPA's
e
mail
system
automatically
captures
your
e
mail
address.
E
mail
addresses
that
are
automatically
captured
by
EPA's
e
mail
system
are
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket
and
made
available
in
EPA's
electronic
public
docket.
You
may
submit
comments
on
a
disk
or
CD
ROM.
These
electronic
submissions
will
be
accepted
in
WordPerfect
or
ASCII
file
format.
Avoid
the
use
of
special
characters
and
any
form
of
encryption.
Send
your
comments
to:
Part
63
General
Provisions
(
Subpart
A)
and
Section
112(
j)
Regulations
(
Subpart
B)
Litigation
Settlement
Amendments
II,
U.
S.
EPA,
Mailcode:
6102T,
1200
Pennsylvania
Ave.,
NW,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
2002
0038.
Deliver
your
comments
to:
Public
Reading
Room,
Room
B102,
EPA
West,
1301
Constitution
Avenue,
NW,
Washington,
DC,
Attention
Docket
ID
No.
OAR
2002
0038.
Such
deliveries
are
only
accepted
during
the
Docket's
normal
hours
of
operation.
Fax
your
comments
to
202
566
1741,
Attention
Docket
ID.
No.
OAR
2002
0038.
Do
not
submit
information
that
you
consider
to
be
CBI
electronically
through
EPA's
electronic
public
docket
or
by
e
mail.
Send
or
deliver
information
identified
as
CBI
only
to
the
following
address:
Attention:
Mr.
Rick
Colyer,
c/
o
OAQPS
Document
Control
Officer,
Mailcode
C404
02,
U.
S.
EPA,
Research
Triangle
Park,
NC
27711,
Attention
Docket
ID
No.
OAR
2002
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236
/
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December
9,
2002
/
Proposed
Rules
0038.
You
may
claim
information
that
you
submit
to
EPA
as
CBI
by
marking
any
part
or
all
of
that
information
as
CBI
(
if
you
submit
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
as
CBI
and
then
identify
electronically
within
the
disk
or
CD
ROM
the
specific
information
that
is
CBI).
Information
so
marked
will
not
be
disclosed
except
in
accordance
with
procedures
set
forth
in
40
CFR
part
2.
In
addition
to
one
complete
version
of
the
comments
that
includes
any
information
claimed
as
CBI,
a
copy
of
the
comments
that
does
not
contain
the
information
claimed
as
CBI
must
be
submitted
for
inclusion
in
the
public
docket
and
EPA's
electronic
public
docket.
If
you
submit
the
copy
that
does
not
contain
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
clearly
that
it
does
not
contain
CBI.
Information
not
marked
as
CBI
will
be
included
in
the
public
docket
and
EPA's
electronic
public
docket
without
prior
notice.
If
you
have
any
questions
about
CBI
or
the
procedures
for
claiming
CBI,
please
consult
the
person
identified
in
the
FOR
FURTHER
INFORMATION
CONTACT
section.
Public
Hearing
Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Ms.
Janet
Eck,
U.
S.
EPA,
Mailcode
C539
03,
Research
Triangle
Park,
NC
27711,
telephone
(
919)
541
7946,
no
later
than
December
17,
2002.
Persons
interested
in
attending
the
public
hearing
must
also
contact
Ms.
Eck
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
these
proposed
amendments.
Worldwide
Web
(
WWW)
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
today's
proposed
rule
amendments
will
also
be
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature,
a
copy
of
the
rule
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(
919)
541
5384.
Applicable
Law
This
rulemaking
is
being
undertaken
pursuant
to
the
procedures
established
by
CAA
section
307(
d).
The
special
procedures
for
rulemakings
governed
by
section
307(
d)
were
utilized
when
EPA
originally
promulgated,
and
when
EPA
subsequently
amended,
each
of
the
rules
to
which
this
proposal
applies.
The
Administrator
has
specifically
determined
that
it
is
appropriate
to
utilize
the
procedures
in
section
307(
d)
for
this
rulemaking.
Outline
The
information
presented
in
this
preamble
is
organized
as
follows:
I.
Background
A.
General
Provisions
B.
CAA
Section
112(
j)
Provisions
C.
The
Sierra
Club
Litigation
D.
Review
of
Proposed
Settlement
Under
CAA
Section
113(
g)
II.
Proposed
Amendments
to
the
General
Provisions
III.
Proposed
Amendments
to
the
Section
112(
j)
Provisions
A.
New
Schedule
for
Part
2
Applications
B.
Requests
for
Applicability
Determination
C.
Prior
Section
112(
g)
Determinations
D.
Content
of
Part
2
Applications
IV.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Executive
Order
13132,
Federalism
C.
Executive
Order
13175,
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution
or
Use
F.
Unfunded
Mandates
Reform
Act
of
1995
G.
Regulatory
Flexibility
Act
(
RFA)
as
Amended
by
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
H.
Paperwork
Reduction
Act
I.
National
Technology
Transfer
and
Advancement
Act
of
1995
I.
Background
A.
General
Provisions
Section
112
of
the
CAA
requires
us
to
list
categories
and
subcategories
of
major
sources
and
area
sources
of
Hazardous
Air
Pollutants
(
HAP)
and
to
establish
NESHAP
for
the
listed
source
categories
and
subcategories.
Major
sources
of
HAP
are
those
that
have
the
potential
to
emit
equal
to
or
greater
than
10
tons/
yr
of
any
one
HAP
or
25
tons/
yr
of
any
combination
of
HAP.
Area
sources
of
HAP
are
those
sources
that
do
not
have
potential
to
emit
equal
to
or
greater
than
10
tons/
yr
of
any
one
HAP
and
25
tons/
yr
of
any
combination
of
HAP.
The
General
Provisions
in
40
CFR
part
63
establish
the
framework
for
emission
standards
and
other
requirements
developed
pursuant
to
section
112
of
the
CAA.
The
General
Provisions
eliminate
the
repetition
of
general
information
and
requirements
in
individual
NESHAP
by
consolidating
all
generally
applicable
information
in
one
location.
They
include
sections
on
applicability,
definitions,
compliance
dates
and
requirements,
monitoring,
recordkeeping
and
reporting,
among
others.
In
addition,
they
include
administrative
sections
concerning
actions
that
the
EPA
(
or
delegated
authorities)
must
take,
such
as
making
determinations
of
applicability,
reviewing
applications
for
approval
of
new
construction,
responding
to
requests
for
extensions
or
waivers
of
applicable
requirements,
and
generally
enforcing
national
air
toxics
standards.
The
General
Provisions
become
applicable
to
a
CAA
section
112(
d)
source
category
rule
when
the
source
category
rule
is
promulgated
and
becomes
effective.
The
NESHAP
General
Provisions
were
first
promulgated
on
March
16,
1994
(
59
FR
12408).
We
subsequently
proposed
a
variety
of
amendments
to
that
initial
rule,
based
in
part
on
settlement
negotiations
with
industrial
trade
organizations
which
had
sought
judicial
review
of
the
rule
and
in
part
on
our
practical
experience
in
developing
and
implementing
maximum
achievable
control
technology
(
MACT)
standards
under
the
General
Provisions
(
66
FR
16318,
March
23,
2001).
We
then
promulgated
final
amendments
to
the
General
Provisions
pursuant
to
that
proposal
(
67
FR
16582,
April
5,
2002).
B.
CAA
Section
112(
j)
Provisions
The
1990
Amendments
to
section
112
of
the
CAA
include
a
new
section
112(
j),
which
is
entitled
``
Equivalent
Emission
Limitation
by
Permit.''
Section
112(
j)(
2)
provides
that
the
provisions
of
section
112(
j)
apply
if
the
EPA
misses
a
deadline
for
promulgation
of
a
standard
under
section
112(
d)
established
in
the
source
category
schedule
for
standards.
After
the
effective
date
of
a
title
V
permit
program
in
a
State,
section
112(
j)(
3)
requires
the
owner
or
operator
of
a
major
source
in
a
source
category,
for
which
the
EPA
failed
to
promulgate
a
section
112(
d)
standard,
to
submit
a
permit
application
18
months
after
the
missed
promulgation
deadline.
We
first
promulgated
a
rule
to
implement
section
112(
j)
on
May
20,
1994
(
59
FR
26429).
We
subsequently
proposed
a
variety
of
amendments
to
that
initial
rule,
based
in
part
on
settlement
negotiations
with
industrial
trade
organizations
which
had
sought
judicial
review
of
the
rule
and
in
part
on
our
own
further
evaluation
of
the
existing
procedures
(
66
FR
16318,
March
23,
2001).
We
then
promulgated
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236
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December
9,
2002
/
Proposed
Rules
final
amendments
to
the
section
112(
j)
rule,
along
with
our
final
amendments
to
the
General
Provisions
(
67
FR
16582,
April
5,
2002).
C.
The
Sierra
Club
Litigation
We
promulgated
the
final
rule
amending
the
MACT
General
Provisions
and
the
requirements
for
case
by
case
determinations
under
Clean
Air
Act
section
112(
j)
on
April
5,
2002
(
67
FR
16582).
The
Sierra
Club
filed
a
petition
seeking
judicial
review
of
that
final
rule
on
April
25,
2002,
Sierra
Club
v.
U.
S.
Environmental
Protection
Agency,
No.
02
1135
(
D.
C.
Circuit).
Sierra
Club
also
filed
a
petition
seeking
administrative
reconsideration
of
certain
provisions
in
the
final
rule,
pursuant
to
CAA
section
307(
d)(
7)(
B).
Shortly
after
the
filing
of
the
petition,
EPA
commenced
discussions
with
Sierra
Club
concerning
a
settlement
agreement.
We
reached
initial
agreement
with
Sierra
Club
on
the
terms
of
a
settlement
and
lodged
the
tentative
agreement
with
the
court
on
August
15,
2002.
Under
the
proposed
settlement,
we
agreed
to
propose
a
rule
to
make
specified
amendments
to
the
General
Provisions
and
section
112(
j)
rules
no
later
than
2
months
after
signature
and
to
take
final
action
on
the
proposed
amendments
within
7
months
after
signature.
D.
Review
of
Proposed
Settlement
Under
CAA
Section
113(
g)
As
required
by
section
113(
g)
of
the
CAA,
EPA
published
a
notice
in
the
Federal
Register
affording
interested
persons
an
opportunity
to
comment
on
the
terms
of
the
proposed
settlement
in
Sierra
Club
v.
U.
S.
Environmental
Protection
Agency,
No.
02
1135
(
D.
C.
Circuit)
(
67
FR
54804,
August
26,
2002).
In
response
to
that
notice,
we
received
110
timely
comments,
the
vast
majority
of
which
opposed
one
or
more
provisions
of
the
proposed
settlement.
While
we
do
not
believe
we
are
legally
required
to
discuss
or
summarize
our
review
of
the
comments
on
the
proposed
settlement
we
received
as
part
of
the
process
required
by
section
113(
g),
we
think
it
is
appropriate
in
this
instance
to
describe
our
assessment
of
and
response
to
certain
of
these
comments.
Virtually
all
of
the
commenters
expressed
concern
about
the
practical
consequences
of
the
proposal
to
reduce
the
time
between
the
section
112(
j)
Part
1
and
Part
2
applications
from
24
months
to
12
months.
We
agree
with
the
commenters
that
this
approach
would
have
resulted
in
wasteful
expenditures
by
the
applicants
and
the
permitting
agencies
to
prepare
and
to
process
permit
applications
which
in
all
likelihood
would
never
have
been
acted
upon.
Given
the
strong
opposition
to
this
approach
reflected
in
the
comments
both
by
industry
sources
and
organizations
and
by
State
and
local
permitting
authorities,
we
were
pleased
when
Sierra
Club
agreed
to
discuss
modifying
the
proposed
settlement
to
establish
an
alternative
timetable
for
submission
of
Part
2
section
112(
j)
applications.
Organizations
representing
the
State
and
local
permitting
authorities
played
a
very
helpful
role
in
the
discussions
concerning
a
revised
settlement.
These
organizations
noted
that
EPA
had
already
reached
an
agreement
with
Sierra
Club
on
a
schedule
for
promulgation
of
all
remaining
MACT
standards
that
were
included
on
the
original
schedule
established
pursuant
to
CAA
section
112(
e)(
1)
and
(
3).
We
anticipate
that
this
agreed
upon
schedule
for
promulgation
of
the
remaining
MACT
standards
will
be
incorporated
in
a
forthcoming
consent
decree
in
Sierra
Club
v.
Whitman,
01
1337
(
D.
D.
C.).
The
State
and
local
governmental
organizations
suggested
that
a
timetable
which
would
require
submission
of
section
112(
j)
Part
2
applications
only
if
the
agreed
upon
schedule
is
not
met
would
both
eliminate
the
expenditure
of
significant
resources
on
an
ultimately
futile
process
and
create
new
incentives
for
EPA
and
the
other
stakeholders
to
cooperate
in
meeting
the
promulgation
schedule.
After
Sierra
Club
agreed
to
consider
the
alternative
approach
suggested
by
the
State
and
local
governmental
organizations,
EPA
and
Sierra
Club
then
negotiated
a
revised
settlement
based
on
that
approach.
Under
the
timetable
we
are
proposing
pursuant
to
the
revised
settlement,
section
112(
j)
Part
2
applications
for
affected
sources
in
those
categories
for
which
MACT
standards
are
scheduled
to
be
promulgated
while
this
rulemaking
is
pending
will
be
due
on
May
15,
2003,
and
section
112(
j)
Part
2
applications
for
affected
sources
in
categories
for
which
the
MACT
standards
are
scheduled
to
be
promulgated
thereafter
will
be
due
60
days
after
the
corresponding
scheduled
promulgation
dates.
In
the
revised
settlement,
we
have
also
agreed
to
propose
the
same
amendments
to
the
General
Provisions
concerning
startup,
shutdown,
and
malfunction
(
SSM)
plans
which
were
set
forth
in
the
original
settlement.
Although
we
received
numerous
comments
opposing
these
amendments
as
well,
we
believe
that
many
of
these
comments
materially
misconstrued
both
the
intent
and
the
effect
of
these
proposed
amendments.
In
any
case,
we
note
that
there
will
be
a
full
opportunity
for
those
who
have
concerns
regarding
either
the
need
for
or
the
effect
of
these
amendments
to
comment
during
this
rulemaking.
We
also
believe
these
comments
are
likely
to
be
more
constructive
and
appropriately
focused
when
the
commenters
have
had
an
opportunity
to
review
our
explanation
of
the
basis
for
these
proposed
amendments
set
forth
below.
The
EPA
and
Sierra
Club
executed
a
final
settlement
agreement
in
Sierra
Club
v.
U.
S.
Environmental
Protection
Agency,
No.
02
1135
(
DC
Circuit),
and
filed
it
with
the
Court
on
November
26,
2002.
This
rulemaking
is
being
conducted
in
accordance
with
the
provisions
of
that
final
agreement.
II.
Proposed
Amendments
to
the
General
Provisions
In
today's
action,
we
are
proposing
to
make
several
changes
in
the
section
of
the
General
Provisions
rule
that
establishes
general
procedures
for
preparation,
maintenance,
and
periodic
revision
of
SSM
plans.
We
consider
these
proposed
revisions
to
be
modest
in
character,
and
we
believe
they
are
generally
consistent
with
the
policies
articulated
in
the
preamble
when
we
proposed
the
last
set
of
amendments
concerning
SSM
plans.
We
are
also
proposing
to
revise
a
new
recordkeeping
provision
which
we
adopted
in
the
prior
rulemaking
in
response
to
a
comment
we
received,
because
we
have
concluded
that
the
new
recordkeeping
provision
is
too
broad
in
its
effect.
We
are
proposing
some
minor
changes
in
the
language
in
40
CFR
63.6(
e)(
1)(
i)
to
correct
a
potential
problem
in
interpreting
the
relationship
between
the
general
duty
to
minimize
emissions
established
by
that
section
and
a
facility's
compliance
with
its
SSM
plan.
That
section
was
modified
in
the
last
rulemaking
because
it
appeared
at
that
time
to
impose
on
a
source
a
general
duty
to
further
reduce
emissions,
even
when
the
source
is
already
in
full
compliance
with
the
applicable
MACT
standards.
We
deemed
this
result
to
be
unreasonable
and
made
corresponding
changes
in
the
language
of
the
rule.
We
emphasize
that
nothing
in
today's
proposal
is
intended
to
alter
our
determination
that
the
general
duty
to
minimize
emissions
is
satisfied
when
emission
levels
required
by
the
MACT
standard
have
been
achieved.
However,
as
part
of
these
changes,
we
adopted
some
language
which
could
be
construed
as
contrary
to
the
policies
regarding
the
relationship
between
the
general
duty
to
minimize
emissions
and
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2002
/
Proposed
Rules
SSM
plans
which
we
stated
in
the
preamble
of
the
proposal
of
the
original
amendments.
We
note
at
the
outset
that
SSM
plans
must
be
drafted
in
a
manner
which
satisfies
the
general
duty
to
minimize
emissions
(
40
CFR
63.6(
e)(
3)(
i)(
A)).
Thus,
compliance
with
a
properly
drafted
SSM
plan
during
a
period
of
startup,
shutdown,
or
malfunction
will
necessarily
also
constitute
compliance
with
the
duty
to
minimize
emissions,
even
though
compliance
with
the
MACT
standards
themselves
during
a
period
of
startup,
shutdown,
or
malfunction
may
not
be
practicable.
However,
in
the
proposal
preamble
to
the
original
amendments,
we
stated
explicitly
that
``
compliance
with
an
inadequate
or
improperly
developed
SSM
plan
is
no
defense
for
failing
to
minimize
emissions''
(
66
FR
16327,
March
23,
2001).
We
note
that
this
understanding
of
the
effect
of
the
amendments
was
explicitly
restated
in
comments
by
the
organizations
that
represent
the
agencies
that
generally
enforce
these
requirements,
the
State
and
Territorial
Air
Pollution
Program
Administrators
(
STAPPA)
and
the
Association
of
Local
Air
Pollution
Control
Officials
(
ALAPCO).
See
Docket
A
2001
02.
Sierra
Club
subsequently
pointed
out
to
us
that
the
actual
language
of
the
section
as
promulgated
could
be
construed
to
indicate
that
a
facility
that
complies
with
its
SSM
plan
regardless
of
whether
the
plan
is
inadequate
or
improperly
developed
thereby
satisfies
its
general
duty
to
minimize
emissions.
We
did
not
intend
this
result.
We
believe
such
a
construction
could
encourage
potential
abuse,
particularly
because
SSM
plans
do
not
have
to
be
reviewed
or
approved
by
the
permitting
authority
before
they
take
effect,
and
because
such
plans
may
also
be
revised
by
the
facility
without
prior
notice
to
the
permitting
authority.
The
revisions
to
40
CFR
63.6(
e)(
1)(
i)
which
we
are
proposing
today
are
intended
to
assure
that
this
section
is
not
construed
in
this
manner.
Nothing
in
these
revisions
is
intended
either
to
change
the
general
principle
that
compliance
with
a
MACT
standard
is
not
mandatory
during
periods
of
startup,
shutdown,
or
malfunction,
or
to
require
a
source
to
further
minimize
emissions
during
periods
of
startup,
shutdown,
or
malfunction
once
it
has
achieved
levels
which
would
constitute
compliance
with
the
MACT
standard
at
other
times.
We
are
also
proposing
some
changes
to
40
CFR
63.6(
e)(
3)(
v),
the
section
that
governs
submission
of
SSM
plans
to
the
EPA
Administrator,
and
to
the
State
or
local
permitting
authorities
which
operate
as
the
Administator's
authorized
representatives.
The
present
rule
provides
that
the
current
SSM
plan
must
be
made
available
upon
request
to
the
Administrator
for
``
inspection
and
copying.''
The
``
Administrator''
is
defined
to
include
a
State
which
has
received
delegation
and
is
therefore
the
Administrator's
``
authorized
representative''
(
40
CFR
63.2).
We
stated
in
the
preamble
of
the
proposal
for
the
previous
amendments
that
the
permit
writer
or
the
Administrator
may
also
require
submission
of
the
SSM
plan
(
66
FR
16326,
March
23,
2001).
This
is
sensible
because
the
SSM
plan
is
an
integral
part
of
the
permit
file,
regardless
of
whether
the
plan
is
physically
available
at
the
EPA
Regional
Office
or
the
permitting
authority
that
has
received
delegation
or
is
maintained
only
at
the
affected
source.
However,
we
note
that
the
present
rule
does
not
expressly
require
that
SSM
plans
be
submitted
to
the
Administrator
or
to
the
permitting
authority
upon
request.
This
potential
omission
was
also
noted
in
previous
comments
by
STAPPA/
ALAPCO.
See
Docket
A
2001
02.
SSM
plans
are
developed
in
connection
with
individual
MACT
standards
promulgated
under
CAA
section
112
and
are
therefore
covered
by
CAA
section
114(
a).
Under
CAA
section
114(
c)
and
40
CFR
70.4(
b)(
3)(
viii),
information
in
SSM
plans
must
be
made
available
to
the
public,
unless
the
submitter
makes
a
satisfactory
showing
that
disclosure
would
divulge
methods
or
processes
that
are
entitled
to
protection
under
the
Trade
Secrets
Act,
18
U.
S.
C.
1905.
SSM
plans
are
considered
to
be
submitted
to
the
Administrator
under
CAA
Section
114
even
if
they
are
submitted
to
a
State
or
local
agency
acting
on
the
Administrator's
behalf
(
40
CFR
2.301(
b)(
2)).
Sierra
Club
has
expressed
concern
about
the
adequacy
of
the
provisions
in
the
present
rule
to
assure
the
degree
of
public
access
to
SSM
plans
required
by
law.
In
particular,
Sierra
Club
is
concerned
that
some
permitting
authorities
might
not
construe
the
rule
to
require
that
an
SSM
plan
be
obtained
from
the
affected
source
when
it
is
requested
by
a
member
of
the
public,
and
that
the
rule
does
not
expressly
require
submission
of
an
SSM
plan
when
the
permitting
authority
or
Administrator
requests
it.
Although
the
rule
clearly
requires
that
such
plans
must
be
made
available
for
inspection
and
copying
by
EPA
or
the
permitting
authority,
Sierra
Club
believes
that
interested
members
of
the
public
may
encounter
protracted
delays
in
obtaining
access
to
the
non
confidential
portions
of
an
SSM
plan.
We
understand
these
concerns
about
the
practicality
of
public
access
under
the
present
system,
and
we
have
agreed
to
propose
some
revisions
to
the
rule
to
facilitate
better
public
access.
The
new
language
requires
sources
to
submit
a
copy
of
the
SSM
plan
to
the
permitting
authority
at
the
time
it
is
first
adopted
and
when
it
is
subsequently
revised.
In
most
instances,
revised
versions
of
the
SSM
plan
may
be
submitted
with
the
semiannual
report
required
by
40
CFR
63.10(
d)(
5).
Under
our
proposal,
the
source
may
elect
to
submit
the
SSM
plan
in
an
electronic
format.
If
the
submitter
claims
that
any
portion
of
an
SSM
plan,
or
any
revision
of
an
SSM
plan,
is
CBI
entitled
to
protection
under
section
114(
c)
of
the
CAA
or
40
CFR
2.301,
the
material
which
is
claimed
as
confidential
must
be
clearly
designated
in
the
submission.
While
the
applicable
law
generally
requires
that
we
provide
public
access
to
those
portions
of
SSM
plans
which
are
not
entitled
to
confidentiality
under
the
Trade
Secrets
Act,
we
note
that
it
is
hypothetically
possible
that
some
information
in
a
particular
SSM
plan
would
be
deemed
to
be
sensitive
from
a
Homeland
Security
perspective.
In
most
instances,
we
think
that
such
sensitive
information
would
also
be
entitled
to
confidential
treatment
under
CAA
section
114(
c).
However,
we
note
that
the
entire
Federal
government
is
presently
reviewing
public
access
requirements
to
assure
that
they
are
compatible
with
Homeland
Security,
and
it
is
possible
that
we
may
in
the
future
propose
other
changes
in
public
access
to
SSM
plans
as
part
of
this
important
effort.
We
note
that
many
sources
have
already
adopted
SSM
plans,
and
that
the
language
we
are
proposing
does
not
establish
a
specific
transitional
process
for
submission
of
those
existing
plans
to
permitting
authorities.
If
we
adopt
the
proposed
changes,
we
want
to
minimize
the
burden
and
disruption
associated
with
this
transition,
and
we
are
requesting
comment
on
how
this
may
best
be
accomplished.
One
option
would
be
to
provide
a
specific
time
period
within
which
the
existing
plans
must
be
submitted.
Another
option
would
be
to
require
that
the
plans
be
submitted
as
part
of
the
next
semiannual
compliance
report.
We
are
also
proposing
a
change
to
40
CFR
63.6(
e)(
3)(
vii).
The
current
rule
provides
that
EPA
or
the
permitting
authority
``
may''
require
that
an
SSM
plan
be
revised
if
certain
specified
deficiencies
are
found.
However,
we
cannot
envision
any
circumstance
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236
/
Monday,
December
9,
2002
/
Proposed
Rules
where
revision
of
an
SSM
plan
should
not
be
mandatory
if
it
is
specifically
found
to
be
deficient
by
EPA
or
the
permitting
authority
according
to
one
of
the
criteria
set
forth
in
this
section.
Therefore,
we
have
agreed
to
propose
to
change
the
language
to
make
such
revisions
mandatory
rather
than
discretionary.
We
are
required
to
propose
all
of
the
foregoing
amendments
to
the
SSM
plan
provisions
in
the
MACT
General
Provisions
rule
by
the
final
settlement
agreement
that
we
executed
with
Sierra
Club.
We
solicit
comments
on
all
these
proposals.
In
addition
to
the
proposals
required
under
our
final
settlement
agreement
with
Sierra
Club,
we
are
also
proposing
to
revise
a
provision
concerning
reporting
of
SSM
events
which
we
adopted
in
the
previous
rulemaking
in
response
to
comments
we
received.
We
have
concluded
that
the
new
language
we
adopted
was
unnecessarily
broad
in
its
scope
and
we
are
proposing
to
substantially
narrow
its
applicability.
During
the
previous
rulemaking
concerning
revisions
to
the
General
Provisions
and
section
112(
j)
rules,
we
received
comments
from
STAPPA/
ALAPCO
indicating
that
it
would
assist
permitting
agencies
in
performing
their
oversight
function
if
facilities
were
required
to
include
the
number
and
a
description
of
all
malfunctions
that
occurred
during
the
prior
reporting
period
in
the
required
semiannual
report.
See
Docket
A
2001
02.
In
response
to
that
comment,
we
added
a
new
reporting
obligation
to
the
language
governing
periodic
SSM
reporting
in
40
CFR
63.10(
d)(
5)(
i).
However,
the
language
we
added
was
not
limited
to
malfunctions
and
required
that
the
facility
report
``
the
number,
duration,
and
a
brief
description
of
each
startup,
shutdown,
and
malfunction.''
We
have
concluded
that
the
inclusion
of
startups
and
shutdowns
in
this
reporting
requirement
is
unnecessary
and
burdensome.
With
respect
to
malfunctions,
the
rule
expressly
requires
that
the
SSM
plan
must
be
revised
by
the
facility
if
there
is
an
event
meeting
the
characteristics
of
a
malfunction
which
is
not
addressed
by
the
plan
(
40
CFR
63.6(
e)(
3)(
vii).
Although
the
facility
is
required
by
40
CFR
63.6(
e)(
3)(
iv)
to
immediately
report
those
instances
where
the
actions
it
takes
are
not
in
conformity
with
the
SSM
plan
and
the
standard
is
exceeded,
this
provision
may
not
be
sufficient
to
give
the
permitting
authority
all
the
information
it
needs
to
assure
that
SSM
plans
properly
address
all
types
of
malfunctions.
Thus,
we
think
that
the
requirement
that
the
owner
or
operator
report
the
number,
duration,
and
type
of
malfunctions
which
occurred
during
the
prior
reporting
period
may
provide
useful
information
to
the
permitting
authority.
We
recognize
that
some
sources
are
concerned
that
the
requirement
to
periodically
report
malfunctions
may
be
interpreted
to
require
reporting
of
minor
problems
that
have
no
impact
on
emissions.
However,
we
do
not
construe
the
provision
in
this
manner.
Under
our
regulations,
``
malfunction''
is
defined
as
``
any
sudden,
infrequent,
and
not
reasonably
preventable
failure
of
air
pollution
control
and
monitoring
equipment,
process
equipment,
or
a
process
to
operate
in
a
normal
or
usual
manner.''
See
40
CFR
63.2.
Only
those
events
that
meet
this
definition
would
be
subject
to
the
reporting
requirement.
During
an
event
that
meets
this
definition,
the
facility
is
not
required
to
comply
with
otherwise
applicable
emission
limits,
and
the
SSM
plan
must
specify
alternative
procedures
which
satisfy
the
general
duty
to
minimize
emissions.
Minor
or
routine
events
that
have
no
appreciable
impact
on
the
ability
of
a
source
to
meet
the
standard
need
not
be
classified
by
the
source
as
a
malfunction,
addressed
in
the
SSM
plan,
or
included
in
periodic
reports.
Thus,
if
a
source
experiences
a
minor
problem
that
does
not
affect
its
ability
to
meet
the
applicable
emission
standard,
the
problem
need
not
be
addressed
by
the
SSM
plan
and
would
not
be
a
reportable
``
malfunction''
under
our
regulations.
Unlike
malfunctions,
we
think
that
the
extension
of
this
requirement
to
startups
and
shutdowns
was
unwarranted.
In
some
industries,
startup
and
shutdown
events
are
numerous
and
routine.
So
long
as
the
provisions
of
the
SSM
plan
are
followed,
there
does
not
appear
to
be
any
real
utility
in
requiring
that
each
individual
startup
and
shutdown
be
reported
or
described.
In
those
instances
where
a
startup
and
shutdown
includes
actions
which
do
not
conform
to
the
SSM
plan
and
the
standard
is
exceeded,
the
facility
is
otherwise
required
to
promptly
report
these
deviations
from
the
plan.
We
encourage
all
interested
parties
to
comment
both
on
our
proposal
to
delete
startups
and
shutdowns
from
this
reporting
provision,
and
on
our
rationale
for
the
retention
of
the
periodic
reporting
of
malfunctions.
In
addition
to
seeking
comment
on
the
revisions
to
the
provisions
governing
SSM
plans
described
above,
we
are
also
requesting
comment
concerning
two
other
changes
to
the
General
Provisions
which
we
made
during
the
prior
rulemaking
in
response
to
industry
comments.
During
the
prior
rulemaking,
the
Colorado
Association
of
Commerce
and
Industry
suggested
that
we
revise
the
definition
of
``
monitoring''
in
40
CFR
63.2
to
include
the
phrase
``
or
to
verify
a
work
practice
standard.''
See
Docket
item
No.
IV
D
03.
There
are
times
when
we
must
adopt
a
work
practice
standard
under
CAA
section
112(
h)
rather
than
an
emission
standard
under
CAA
section
112(
d),
and
compliance
with
such
a
work
practice
standard
is
sometimes
verified
by
activities
which
may
not
require
``*
*
*
collection
and
use
of
measurement
data
or
other
information
to
control
the
operation
of
a
process
or
pollution
control
device
*
*
*''
Therefore,
we
thought
that
the
suggested
revision
was
a
sensible
one.
However,
because
the
additional
language
was
not
originally
proposed
by
EPA,
and
it
has
been
subsequently
suggested
that
this
revision
might
have
unintended
consequences,
we
have
decided
to
take
additional
comment
concerning
the
value
of
this
language
and
the
effects
it
might
have
when
read
in
conjunction
with
other
regulatory
requirements,
including
other
provisions
of
the
General
Provisions.
In
the
prior
rulemaking,
we
also
made
a
small
change
in
the
language
of
40
CFR
63.9(
h)(
2)(
ii)
by
adding
the
phrase
``(
or
activities
that
have
the
same
compliance
date)''
in
response
to
a
comment
submitted
by
Dow
Chemical
Company.
See
Docket
item
No.
IV
D
19.
Although
separate
notices
are
appropriate
for
compliance
obligations
with
different
compliance
dates
(
e.
g.,
equipment
leaks
versus
process
vents),
Dow
was
concerned
that
separate
compliance
reports
might
be
required
for
compliance
obligations
that
have
the
same
date
and
requested
the
option
of
filing
a
single
compliance
status
report
covering
multiple
compliance
obligations.
Because
the
new
language
in
question
was
not
originally
proposed
by
EPA,
and
some
have
questioned
whether
it
clearly
achieves
the
intended
purpose,
we
have
decided
to
request
additional
comment
concerning
the
need
for
this
change
and
potential
alternatives.
III.
Proposed
Amendments
to
the
Section
112(
j)
Provisions
A.
New
Schedule
for
Part
2
Applications
The
final
settlement
agreement
which
we
have
executed
with
Sierra
Club
requires
us
to
propose
to
replace
the
existing
schedule
for
submission
of
section
112(
j)
Part
2
applications,
under
which
most
Part
2
applications
would
have
been
due
on
May
15,
2004,
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67,
No.
236
/
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December
9,
2002
/
Proposed
Rules
a
schedule
which
will
establish
a
specific
deadline
for
submission
of
Part
2
applications
for
all
affected
sources
in
a
given
category
or
subcategory.
With
respect
to
those
listed
categories
or
subcategories
for
which
MACT
standards
are
scheduled
to
be
promulgated
by
November
30,
2002
or
by
February
28,
2003,
we
are
proposing
a
Part
2
application
deadline
of
May
15,
2003.
Establishing
an
earlier
deadline
for
these
sources
would
not
be
practicable
because
we
do
not
anticipate
completing
this
rulemaking
until
April
2003.
With
respect
to
those
categories
or
subcategories
for
which
MACT
standards
are
scheduled
to
be
promulgated
at
a
later
time,
we
are
proposing
Part
2
application
deadlines
which
are
60
days
after
each
respective
scheduled
promulgation
date.
The
deadlines
for
Part
2
applications
which
we
are
proposing
for
each
category
or
subcategory
are
set
forth
below
in
Tables
1
and
2
of
this
preamble.
TABLE
1.
SECTION
112(
j)
PART
2
APPLICATION
DUE
DATES
Due
date
MACT
standard
5/
15/
03
..................................................
Municipal
Solid
Waste
Landfills
Flexible
Polyurethane
Foam
Fabrication
Operations
Coke
Ovens:
Pushing,
Quenching,
and
Battery
Stacks
Reinforced
Plastic
Composites
Production
Semiconductor
Manufacturing
Refractories
Manufacturing
1
Brick
and
Structural
Clay
Products
Manufacturing,
and
Clay
Ceramics
Manufacturing
2
Asphalt
Roofing
Manufacturing
and
Asphalt
Processing
3
Integrated
Iron
and
Steel
Manufacturing
Hydrochloric
Acid
Production
and
Fumed
Silica
4
Engine
Test
Facilities
and
Rocket
Testing
Facilities
3
Metal
Furniture
(
Surface
Coating)
Printing,
Coating,
and
Dyeing
of
Fabrics
Wood
Building
Products
(
Surface
Coating)
10/
30/
03
................................................
Combustion
Turbines
Lime
Manufacturing
Site
Remediation
Iron
and
Steel
Foundries
Taconite
Iron
Ore
Processing
Miscellaneous
Organic
Chemical
Manufacturing
(
MON)
5
Organic
Liquids
Distribution
Primary
Magnesium
Refining
Metal
Can
(
Surface
Coating)
Plastic
Parts
and
Products
(
Surface
Coating)
Chlorine
Production
Miscellaneous
Metal
Parts
and
Products
(
Surface
Coating)
(
and
Asphalt/
Coal
Tar
Application
Metal
Pipes)
3
4/
28/
04
..................................................
Industrial
Boilers,
Institutional/
Commercial
Boilers
and
Process
Heaters
6
Plywood
and
Composite
Wood
Products
Reciprocating
Internal
Combustion
Engines
Auto
and
Light
Duty
Truck
(
Surface
Coating)
8/
13/
05
..................................................
Industrial
Boilers,
Institutional/
Commercial
Boilers,
and
Process
Heaters
7
Hydrochloric
Acid
Production
8
1
Includes
Chromium
Refractories
Production.
2
Two
subcategories
of
Clay
Products
Manufacturing.
3
Two
source
categories.
4
Includes
all
sources
within
the
category
Hydrochloric
Acid
Production
that
burn
no
hazardous
waste,
and
all
sources
in
the
category
Fumed
Silica.
5
Covers
23
source
categories,
see
Table
2
of
this
preamble.
6
Includes
all
sources
in
the
three
categories,
Industrial
Boilers,
Institutional/
Commercial
Boilers,
and
Process
Heaters
that
burn
no
hazardous
waste.
7
Includes
all
sources
in
the
three
categories,
Industrial
Boilers,
Institutional/
Commercial
Boilers,
and
Process
Heaters
that
burn
hazardous
waste.
8
Includes
furnaces
that
produce
acid
from
hazardous
waste
at
sources
in
the
category
Hydrochloric
Acid
Production.
TABLE
2.
MON
SOURCE
CATEGORIES
Manufacture
of
Paints,
Coatings,
and
Adhesives
Alkyd
Resins
Production
Maleic
Anhydride
Copolymers
Production
Polyester
Resins
Production
Polymerized
Vinylidene
Chloride
Production
Polymethyl
Methacrylate
Resins
Production
Polyvinyl
Acetate
Emulsions
Production
Polyvinly
Alcohol
Production
Polyvinyl
Butyral
Production
Ammonium
Sulfate
Production
Caprolactam
By
Product
Plants
TABLE
2.
MON
SOURCE
CATEGORIES
Continued
Quaternary
Ammonium
Compounds
Production
Benzyltrimethylammonium
Chloride
Production
Carbonyl
Sulfide
Production
Chelating
Agents
Production
Chlorinated
Paraffins
Production
Ethylidene
Norbornene
Production
Explosives
Production
Hydrazine
Production
OBPA/
1,3
Diisocyanate
Production
TABLE
2.
MON
SOURCE
CATEGORIES
Continued
Photographic
Chemicals
Production
Phthalate
Plasticizers
Production
Rubber
Chemicals
Manufacturing
Symmetrical
Tetrachloropyridine
Production
We
have
always
been
reluctant
to
establish
any
timetable
which
would
require
submission
of
a
large
number
of
Part
2
applications
which
would
in
all
likelihood
never
be
acted
upon
by
the
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236
/
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December
9,
2002
/
Proposed
Rules
permitting
authorities.
Submission
of
Part
2
applications
would
generally
be
a
futile
exercise
in
those
instances
where
a
final
Federal
MACT
standard
governing
the
facilities
in
question
is
scheduled
for
promulgation
prior
to
the
18
month
deadline
for
action
on
the
applications
by
the
respective
permitting
authorities.
It
has
been
our
consistent
view
that
requiring
submission
of
such
applications
would
represent
an
unwarranted
expenditure
of
private
and
public
resources.
Thus,
we
are
pleased
that
the
proposed
schedule
under
the
final
settlement
will
permit
us
to
avoid
such
a
wasteful
exercise
unless
there
are
further
delays
in
promulgation
of
the
remaining
MACT
standards.
We
note
also
that
the
prompt
and
significant
consequences
if
a
promulgation
deadline
is
missed
will
create
new
incentives
for
EPA
and
the
other
stakeholders
to
assure
that
the
agreed
upon
promulgation
deadlines
are
met.
We
recognize
that
the
proposed
schedule
for
submission
of
section
112(
j)
Part
2
applications
leaves
relatively
little
time
for
sources
to
prepare
and
submit
such
applications
if
a
particular
promulgation
deadline
is
missed.
In
recognition
of
the
tight
time
frames,
we
will
try
to
provide
prompt
advance
notice
to
affected
sources
and
to
permitting
authorities
if
we
have
reason
to
believe
that
we
will
not
be
able
to
meet
an
impending
promulgation
deadline
for
a
particular
MACT
standard.
We
note
that
the
MACT
standards
for
which
we
are
proposing
a
Part
2
application
deadline
of
May
15,
2003
are
actually
scheduled
to
be
promulgated
while
this
rulemaking
is
in
progress.
There
will
be
no
need
to
adopt
a
Part
2
application
deadline
for
affected
sources
in
any
category
for
which
a
final
MACT
standard
has
been
promulgated
under
CAA
section
112(
d)
and/
or
(
h)
prior
to
the
completion
of
this
rulemaking.
We
are
proposing
to
state
explicitly
in
the
amendments
to
the
section
112(
j)
rule
that
no
further
process
to
develop
a
case
by
case
MACT
determination
under
section
112(
j)
is
required
for
any
source
once
a
generally
applicable
Federal
MACT
standard
governing
that
source
has
been
promulgated.
The
revised
timetable
for
submission
of
Part
2
applications
we
are
proposing
requires
significant
changes
in
the
structure
of
the
existing
section
112(
j)
rule.
In
contrast
to
the
current
general
timetable
for
Part
2
applications,
which
applies
to
all
of
the
remaining
MACT
standards
which
were
included
in
the
schedule
adopted
under
CAA
section
112(
e)(
1)
and
(
3),
we
are
proposing
a
phased
timetable
for
Part
2
applications
with
different
dates
for
sources
in
different
categories
based
on
the
scheduled
promulgation
date.
We
are
also
proposing
to
make
the
new
schedule
as
uniform
as
practicable
for
all
affected
sources
in
each
category
or
subcategory,
regardless
of
whether
the
source
in
question
has
previously
requested
an
applicability
determination
under
40
CFR
63.52(
e)(
2)(
i)
or
has
previously
obtained
a
case
by
case
determination
under
CAA
section
112(
g).
These
proposed
changes
will
require
that
the
existing
section
112(
j)
rule
be
substantially
rewritten.
In
order
to
allow
the
rulemaking
process
required
by
the
final
settlement
agreement
to
proceed
expeditiously
and
to
encourage
commenters
to
focus
on
the
broad
issues
presented
by
the
new
approach,
we
are
not
proposing
specific
regulatory
text.
Rather,
we
are
providing
a
detailed
discussion
in
this
preamble
of
the
changes
we
are
proposing
to
make.
While
we
do
not
want
to
discourage
those
commenters
who
want
to
propose
specific
regulatory
text
for
our
consideration,
we
believe
that
comments
will
be
most
constructive
if
they
focus
on
the
larger
question
of
how
the
existing
rule
should
be
restructured
to
achieve
our
proposed
objectives.
When
we
first
proposed
the
creation
of
a
two
part
process
for
section
112(
j)
applications,
we
specified
a
6
month
period
between
the
submission
of
the
general
initial
notification
in
the
Part
1
application
and
the
submission
of
more
detailed
supporting
information
in
the
Part
2
application.
That
initial
proposal
was
based
on
the
premise
that
every
applicant
would
automatically
be
given
the
maximum
extension
of
time
to
supplement
an
incomplete
application
that
is
authorized
by
CAA
section
112(
j)(
4).
In
the
final
rule,
we
observed
that
there
is
another
provision
in
the
statute
which
may
be
reasonably
construed
to
provide
authority
for
us
to
establish
an
incremental
process
for
the
submission
of
section
112(
j)
applications.
The
hammer
provision
in
section
112(
j)(
2)
itself
establishes
the
requirement
to
submit
permit
applications
``
beginning
18
months
after''
the
statutory
date
for
promulgation
of
a
standard.
Reading
this
provision
in
context,
we
believe
that
the
statute
can
be
reasonably
construed
as
authorizing
us
to
provide
a
period
of
time
after
the
hammer
date
in
which
the
information
necessary
for
a
fully
informative
section
112(
j)
application
can
be
compiled.
We
have
not
changed
our
view
that
this
is
a
reasonable
construction
of
the
statutory
provision
in
question,
and
we
are
reiterating
this
construction
of
the
statute
as
part
of
our
rationale
for
these
proposed
rule
amendments.
B.
Requests
for
Applicability
Determination
As
we
explained
above,
we
are
proposing
to
establish
a
single
uniform
Part
2
application
deadline
for
all
sources
in
a
given
category
or
subcategory,
which
is
based
in
turn
on
the
agreed
upon
promulgation
date
for
the
MACT
standard
for
that
category
or
subcategory.
However,
to
achieve
this
objective
it
will
be
necessary
to
establish
new
procedures
for
those
affected
sources
which
have
previously
submitted
a
request
for
applicability
determination
under
40
CFR
63.52(
e)(
2)(
i).
That
provision
establishes
a
process
by
which
major
sources
can
request
that
the
permitting
authority
determine
whether
or
not
specific
sources
at
their
facility
belong
in
any
category
or
subcategory
requiring
a
case
by
case
determination
under
section
112(
j).
All
requests
for
applicability
determinations
were
due
at
the
same
time
as
the
section
112(
j)
Part
1
applications,
on
May
15,
2002.
Under
the
procedures
in
the
current
rule,
a
negative
determination
by
the
permitting
authority
concerning
such
a
request
means
that
no
further
action
is
required,
while
a
positive
determination
means
that
the
applicant
must
then
submit
a
Part
2
application
within
24
months.
In
order
to
adopt
the
single
uniform
deadline
for
Part
2
applications
for
each
affected
source
in
a
category
or
subcategory
which
we
are
required
to
propose
by
the
final
settlement,
it
is
necessary
to
amend
the
provisions
governing
requests
for
applicability
determinations.
We
lack
precise
information
concerning
how
many
such
requests
for
applicability
determination
were
submitted
to
permitting
authorities
on
or
before
May
15,
2002,
but
we
believe
that
hundreds
of
such
requests
are
pending.
We
know
that
some
of
these
requests
reflect
genuine
uncertainty
concerning
the
scope
of
the
activities
or
equipment
governed
by
a
particular
category
or
subcategory.
For
some
of
these
requests,
the
subsequent
issuance
of
a
proposed
MACT
standard
or
other
subsequent
events
may
have
resolved
such
uncertainty.
However,
we
also
believe
that
many
of
these
requests
were
filed
merely
because
the
filing
of
such
a
request
operated
to
defer
the
deadline
for
submission
of
a
Part
2
application.
Under
the
proposal
required
by
the
final
settlement,
such
an
indefinite
deferral
of
the
Part
2
application
deadline
will
no
longer
be
allowed.
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Proposed
Rules
We
do
not
seek
to
limit
the
right
of
those
affected
sources
who
may
have
genuine
uncertainty
regarding
the
scope
of
a
particular
category
or
subcategory
to
obtain
a
decision
on
applicability
issues
by
the
permitting
authority,
but
we
also
do
not
want
to
burden
the
permitting
authorities
with
a
process
that
requires
them
to
take
final
action
on
those
pending
requests
which
do
not
present
genuine
applicability
issues.
Accordingly,
we
are
proposing
to
require
that
each
affected
source
which
still
wishes
to
pursue
a
previously
filed
request
for
applicability
determination
under
40
CFR
63.52(
e)(
2)(
i)
which
is
still
pending
must
resubmit
and
supplement
that
request
within
60
days
after
EPA
publishes
final
action
in
this
rulemaking
or
within
60
days
after
EPA
publishes
a
proposed
MACT
standard
for
the
category
or
subcategory
in
question,
whichever
is
later.
Our
experience
tells
us
that
most
uncertainties
regarding
applicability
can
be
resolved
by
applying
the
specific
applicability
language
in
the
proposed
MACT
standard.
That
is
why
we
are
proposing
to
delay
any
requirement
to
resubmit
and
supplement
a
request
for
applicability
determination
until
after
a
proposed
MACT
standard
is
available.
We
are
proposing
to
require
that
each
resubmitted
request
for
an
applicability
determination
be
supplemented
to
specifically
discuss
the
relation
between
the
source(
s)
in
question
and
the
applicability
provision
in
the
proposed
MACT
standard
for
the
category
or
subcategory
in
question,
and
to
explain
why
there
may
still
be
uncertainties
that
require
a
determination
of
applicability.
We
are
also
proposing
to
require
that
the
permitting
authority
act
upon
each
resubmitted
and
supplemented
request
for
an
applicability
determination
within
an
additional
60
days
after
the
applicable
deadline
for
the
resubmitted
request.
We
believe
this
approach
will
preserve
the
rights
of
those
affected
sources
which
still
have
legitimate
applicability
concerns
even
after
issuance
of
a
proposed
MACT
standard.
We
also
expect
there
will
be
a
significant
reduction
in
the
number
of
pending
requests,
since
the
current
procedural
incentives
for
submission
of
such
requests
will
have
been
eliminated.
With
respect
to
those
requests
that
are
resubmitted,
the
proposed
mandatory
supplementation
should
delineate
the
issues
more
clearly
and
improve
the
record
for
a
decision
concerning
the
request
by
the
permitting
authority.
While
we
anticipate
that
the
issuance
of
a
proposed
MACT
standard
will
generally
operate
to
resolve
existing
applicability
issues
rather
than
raising
new
ones,
it
is
hypothetically
possible
that
a
facility
will
have
new
questions
based
on
the
applicability
provision
in
a
proposed
MACT
standard.
There
is
at
present
no
formal
process
for
addressing
such
issues,
but
we
encourage
all
major
sources
that
have
questions
concerning
the
applicability
of
a
proposed
MACT
standard
to
their
operations
or
equipment
to
seek
guidance
from
responsible
personnel
at
the
permitting
authority
and
the
EPA
Regional
Office.
We
note
that
there
are
special
timing
issues
with
respect
to
any
requests
for
applicability
determination
which
have
been
submitted
concerning
sources
that
may
be
in
a
category
or
subcategory
for
which
the
MACT
standard
in
question
is
scheduled
to
be
promulgated
by
November
30,
2002
or
by
February
28,
2003.
There
will
be
no
need
to
address
these
concerns
if
the
standards
are
promulgated
on
schedule.
However,
if
any
one
of
these
standards
is
delayed,
and
if
the
delayed
standard
still
has
not
been
promulgated
by
the
time
we
take
final
action
concerning
this
proposal,
special
procedures
will
be
required.
Those
facilities
which
have
sources
which
may
be
in
such
a
category
or
subcategory,
and
who
previously
submitted
a
request
for
applicability
determination
which
is
still
pending,
cannot
be
required
to
submit
their
Part
2
application
on
May
15,
2003.
In
such
an
instance,
we
propose
that
any
Part
2
application
will
be
required
120
days
after
EPA
publishes
final
action
in
this
rulemaking
if
the
request
for
applicability
determination
is
not
resubmitted
within
60
days
after
publication,
or
within
180
days
after
EPA
publishes
final
action
in
this
rulemaking
if
the
request
is
resubmitted
and
a
determination
concerning
the
request
by
the
permitting
authority
is
required.
We
consider
it
improbable
that
we
will
need
to
adopt
such
procedures,
but
we
are
proposing
them
now
in
the
unlikely
event
they
are
required.
We
note
also
that
those
major
sources
which
elect
to
resubmit
requests
for
applicability
determination
with
respect
to
sources
that
may
be
governed
by
one
of
the
MACT
standards
which
are
scheduled
to
be
promulgated
by
August
31,
2003,
may
not
be
entitled
to
receive
a
determination
by
the
permitting
authority
on
the
resubmitted
request
until
shortly
after
the
scheduled
promulgation
date.
If
such
a
standard
is
delayed,
and
there
is
no
negative
determination
by
the
permitting
authority
on
the
resubmitted
request,
the
Part
2
application
for
sources
within
the
category
in
question
will
be
due
on
October
30,
2003.
This
tight
time
frame
underscores
the
importance
of
careful
coordination
between
such
sources
and
the
permitting
authority
if
it
appears
that
a
MACT
standard
will
be
delayed.
As
discussed
above,
EPA
will
endeavor
to
provide
timely
information
to
affected
sources
and
permitting
authorities
if
it
becomes
apparent
that
the
Agency
will
not
meet
the
promulgation
schedule
for
any
of
the
remaining
MACT
standards.
C.
Prior
Section
112(
g)
Determinations
Our
proposal
to
establish
a
single
uniform
Part
2
application
deadline
for
all
sources
in
a
given
category
or
subcategory
also
requires
that
we
make
some
changes
to
the
current
procedures
governing
CAA
section
112(
j)
applications
for
those
sources
which
have
previously
received
a
case
by
case
determination
pursuant
to
CAA
section
112(
g).
In
evaluating
this
question,
it
is
important
to
understand
the
substantive
relationship
between
these
separate
statutory
requirements.
In
general,
we
anticipate
that
emission
control
requirements
established
as
part
of
a
previous
caseby
case
determination
under
section
112(
g)
will
subsequently
be
adopted
by
the
permitting
authority
to
satisfy
any
applicable
section
112(
j)
requirements
as
well.
This
is
because
the
determination
required
for
any
sources
subject
to
CAA
section
112(
g)
is
supposed
to
be
based
on
new
source
MACT,
and
the
subsequent
application
of
section
112(
j)
requirements
to
those
same
sources
will
be
based
on
existing
source
MACT.
Moreover,
to
assure
that
inconsequential
differences
in
emission
control
do
not
result
in
unduly
burdensome
sequential
case
by
case
determinations,
the
current
section
112(
j)
rule
requires
the
permitting
authority
to
adopt
any
prior
case
bycase
determination
under
section
112(
g)
as
its
determination
for
the
same
sources
under
section
112(
j)
if
it
``
determines
that
the
emission
limitations
in
the
prior
case
by
case
determination
are
substantially
as
effective
as
the
emission
limitations
which
the
permitting
authority
would
otherwise
adopt
under
section
112(
j).''
See
40
CFR
63.52(
a)(
3),
(
b)(
2),
and
(
e)(
2)(
ii).
Under
the
applicable
provisions
of
the
present
rule,
sources
which
have
previously
obtained
a
case
by
case
determination
under
CAA
section
112(
g)
are
generally
required
to
submit
a
request
for
an
``
equivalency
determination''
to
decide
if
the
applicable
section
112(
g)
requirements
are
``
substantially
as
effective''
as
the
requirements
which
would
otherwise
apply
under
section
112(
j).
As
explained
above,
we
believe
that
this
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2002
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Proposed
Rules
determination
will
generally
be
positive.
However,
40
CFR
63.52(
e)(
2)(
ii)
provides
that,
if
such
a
determination
is
negative,
the
source
must
then
submit
a
Part
2
application
within
24
months.
As
in
the
case
of
requests
for
applicability
determination,
changes
to
the
existing
rule
will
be
required
to
place
all
sources
in
a
given
category
or
subcategory
on
the
same
schedule
for
submission
of
Part
2
applications.
However,
in
this
instance,
we
believe
that
the
solution
is
considerably
simpler.
We
are
proposing
to
adopt
the
proposed
Part
2
application
deadline
for
a
given
category
or
subcategory
as
the
final
deadline
for
submission
of
a
request
for
an
``
equivalency
determination''
by
any
affected
source
that
previously
obtained
a
case
by
case
determination
under
CAA
section
112(
g).
Under
this
proposal,
those
sources
which
submitted
such
requests
earlier
under
the
provisions
of
the
existing
rule
need
not
resubmit
them.
However,
we
are
also
proposing
that
all
requests
for
an
equivalency
determination,
regardless
of
when
they
were
submitted,
will
be
construed
in
the
alternative
as
a
section
112(
j)
Part
2
application
as
well.
The
effect
of
this
proposal
will
be
to
require
that
the
permitting
authority
first
make
an
equivalency
determination.
In
the
event
of
a
negative
determination,
the
permitting
authority
will
then
proceed
to
adopt
a
separate
set
of
requirements
pursuant
to
section
112(
j).
Under
this
proposal,
this
process
will
be
completed
in
the
same
18
month
period
that
applies
to
the
processing
of
all
other
Part
2
applications.
This
proposal
will
assure
that
the
deadline
for
submission
of
Part
2
applications
will
be
the
same
for
all
affected
sources
within
a
category
or
subcategory,
regardless
of
whether
a
source
previously
obtained
a
case
bycase
determination
under
section
112(
g).
We
do
not
think
this
proposal
imposes
any
new
burden
on
sources
or
permitting
authorities,
because
the
permitting
authority
should
already
have
all
of
the
information
required
for
a
Part
2
application
in
any
instance
where
it
is
already
administering
section
112(
g)
requirements
applicable
to
the
same
source.
D.
Content
of
Part
2
Applications
We
are
hopeful
that
no
source
will
be
required
to
submit
a
section
112(
j)
Part
2
application
under
the
schedule
we
are
proposing
in
this
rulemaking.
We
also
note
that
the
Part
2
application
requirements
in
the
current
section
112(
j)
rule
are
significantly
narrower
than
the
application
requirements
in
the
original
section
112(
j)
rule.
However,
in
the
event
that
some
Part
2
applications
must
ultimately
be
submitted,
we
think
it
is
appropriate
to
give
some
additional
guidance
concerning
the
information
they
must
contain
and
to
request
comment
on
a
few
related
issues.
We
believe
that
an
affected
source
submitting
a
Part
2
application
may
elect
to
rely
directly
on
the
content
of
the
applicable
proposed
MACT
standard
in
identifying
affected
emission
points.
We
also
think
that
applicants
may
reasonably
limit
the
information
they
submit
concerning
HAP
emissions
to
those
specific
HAP
or
groups
of
HAP
which
would
be
subject
to
actual
control
in
the
applicable
proposed
MACT
standard.
We
encourage
all
section
112(
j)
Part
2
applicants
to
utilize
the
regulatory
approach
in
the
applicable
proposed
MACT
standard
as
a
practical
template
in
compiling
Part
2
applications.
We
also
encourage
applicants
who
have
previously
submitted
to
the
permitting
authority
some
of
the
information
required
in
the
Part
2
application
to
meet
the
requirements
in
question
by
crossreferencing
such
prior
submissions.
Moreover,
although
the
submission
by
an
affected
source
of
a
proposed
caseby
case
MACT
determination
as
part
of
its
Part
2
application
is
entirely
discretionary,
we
note
that
some
industry
representatives
have
stated
that
they
would
generally
elect
to
include
such
information
as
a
precautionary
matter.
While
we
do
not
seek
to
discourage
this
practice,
we
believe
that
the
burden
associated
with
inclusion
of
such
information
will
not
be
significant
in
instances
where
a
Federal
MACT
standard
has
already
been
proposed,
the
applicable
proposed
standard
has
already
been
evaluated
by
the
facility,
and
the
facility
has
already
had
an
opportunity
to
comment
on
the
applicable
proposed
standard.
We
also
want
to
do
whatever
we
can
to
minimize
any
unnecessary
burdens
associated
with
submission
of
a
Part
2
application.
We
do
not
want
to
require
the
submission
of
any
information
which
is
not
truly
necessary
to
prepare
for
potential
issuance
of
case
by
case
MACT
determinations.
To
that
end,
we
are
requesting
comment
on
the
approach
outlined
above
and
whether
there
may
be
other
ways
to
minimize
any
unnecessary
burden.
We
also
request
comments
on
the
following
specific
questions.
Does
the
applicant
need
to
provide
``
estimated
total
uncontrolled
and
controlled
emission
rates''
to
enable
the
permitting
authority
to
prepare
for
a
potential
case
by
case
determination?
If
the
applicant
does
not
have
the
information
required
to
provide
meaningful
estimates
of
emission
rates,
should
new
emission
testing
be
required?
Is
it
appropriate
to
require
individual
applicants
to
submit
``
information
relevant
to
establishing
the
MACT
floor''
in
their
Part
2
applications?
Are
there
any
Part
2
application
requirements
which
can
be
met
simply
by
referring
to
the
applicable
proposed
MACT
standard?
IV.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866,
(
58
FR
51735,
October
4,
1993)
the
Agency
must
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
Office
of
Management
and
Budget
(
OMB)
review
and
the
requirements
of
the
Executive
Order.
The
Order
defines
``
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
(
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.
We
have
determined
that
neither
the
proposed
amendments
to
the
General
Provisions
nor
the
proposed
amendments
to
the
section
112(
j)
rule
are
a
``
significant
regulatory
action''
under
the
terms
of
Executive
Order
12866,
and
this
proposal
was
therefore
not
submitted
to
OMB
for
review.
B.
Executive
Order
13132,
Federalism
Executive
Order
13132,
entitled,
``
Federalism
(
64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
Federalism
implications.''
``
Policies
that
have
Federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
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236
/
Monday,
December
9,
2002
/
Proposed
Rules
These
proposed
amendments
do
not
have
Federalism
implications
under
the
terms
of
this
Executive
Order.
We
do
not
believe
that
the
proposed
changes
in
the
General
Provisions
rule
have
any
significant
federalism
implications.
With
respect
to
the
alteration
in
the
schedule
for
submission
of
section
112(
j)
Part
2
applications,
we
note
that
the
CAA
itself
requires
that
State
and
local
permitting
authorities
receive
and
process
applications
for
case
by
case
MACT
determinations
pursuant
to
section
112(
j).
This
is
one
of
the
responsibilities
that
State
and
local
permitting
authorities
have
agreed
to
assume.
We
have
tried
to
construe
the
statutory
provisions
in
question
in
a
manner
that
minimizes
the
burden
on
these
agencies
associated
with
this
responsibility.
We
have
determined
that
the
proposed
change
in
the
schedule
for
submission
of
such
applications
does
not
itself
have
a
substantial
direct
effect
on
the
States,
on
the
relationship
between
the
national
government
and
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.
Nevertheless,
in
the
spirit
of
Executive
Order
13132
and
consistent
with
EPA
policy
to
promote
communications
between
EPA,
State,
and
local
governments,
EPA
specifically
solicits
comment
on
these
proposed
amendments
from
State
and
local
officials.
C.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175
(
65
FR
67249,
November
6,
2000)
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
``
Policies
that
have
tribal
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes.''
These
proposed
amendments
to
the
General
Provisions
and
the
section
112(
j)
rule
would
not
have
tribal
implications.
They
would
not
have
substantial
direct
effects
on
tribal
governments,
or
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
There
are
currently
no
tribal
governments
that
have
approved
title
V
permit
programs
to
which
sources
would
submit
case
by
case
permit
applications
under
section
112(
j).
Accordingly,
Executive
Order
13175
would
not
apply
to
this
action.
D.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
EPA
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
that
EPA
considered.
The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
501
of
the
Executive
Order
has
the
potential
to
influence
the
regulation.
These
amendments
are
not
subject
to
Executive
Order
13045
because
they
are
amending
information
collection
requirements
and
do
not
affect
health
or
safety
risks.
Furthermore,
this
rule
has
been
determined
not
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866.
E.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution
or
Use
These
proposed
amendments
are
not
subject
to
Executive
Order
13211,
``
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(
66
FR
28355,
May
22,
2001)
because
they
are
not
a
significant
regulatory
action
under
Executive
Order
12866.
F.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
on
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
costbenefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
by
State,
local,
and
tribal
governments,
in
aggregate,
or
by
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
leastcostly
most
cost
effective,
or
leastburdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA's
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
The
EPA
has
determined
that
these
proposed
amendments
do
not
contain
a
Federal
mandate
that
may
result
in
expenditures
of
$
100
million
or
more
for
State,
local,
and
tribal
governments,
in
the
aggregate,
in
any
1
year.
We
do
not
expect
annual
expenditures
by
State,
local
and
tribal
governments
in
connection
with
implementation
of
these
amendments
to
exceed
$
100
million.
In
any
case,
any
obligation
of
State
or
local
permitting
authorities
to
take
particular
actions
under
these
proposed
amendments
is
not
directly
enforceable
by
a
court
of
law,
and
any
failure
by
a
State
or
local
permitting
authority
to
meet
such
an
obligation
would
at
most
result
in
a
determination
that
the
permitting
authority
is
not
adequately
administering
its
permit
program
under
CAA
section
502(
i).
Thus,
it
can
be
argued
that
such
obligations
are
not
enforceable
duties
within
the
meaning
of
section
421(
5)(
A)(
i)
of
UMRA,
2
U.
S.
C.
658(
5)(
A)(
i).
Moreover,
even
if
such
obligations
were
deemed
to
be
enforceable
duties,
such
duties
might
be
viewed
as
falling
within
the
exception
for
a
condition
of
Federal
assistance
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Vol.
67,
No.
236
/
Monday,
December
9,
2002
/
Proposed
Rules
under
section
421(
5)(
A)(
i)(
I),
2
U.
S.
C.
658(
5)(
A)(
i)(
I).
We
have
also
determined
that
the
proposed
amendments
will
not
result
in
expenditures
by
the
private
sector
of
$
100
million
in
any
1
year.
We
fully
expect
to
promulgate
the
remaining
MACT
standards
on
or
near
schedule,
eliminating
the
need
for
sources
to
prepare
and
submit
section
112(
j)
Part
2
applications.
We
recognize
that
some
sources
may
choose
to
begin
preparing
the
Part
2
application,
but
cannot
estimate
the
total
expenditures
this
would
entail,
although
we
believe
it
to
be
only
a
small
fraction
of
the
$
100
million
criterion.
We
also
expect
relatively
few
resubmissions
of
applicability
determination
requests.
In
any
case,
all
such
resubmissions
will
be
done
at
the
source's
discretion,
and
we
expect
the
aggregate
expenditure
on
them
to
be
small.
Based
on
these
determinations,
today's
proposed
amendments
are
not
subject
to
the
requirements
of
sections
202,
203,
and
205
of
the
UMRA.
G.
Regulatory
Flexibility
Act
(
RFA)
as
Amended
by
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
proposed
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
amendments
on
small
entities,
small
entity
is
defined
as:
(
1)
A
small
business
as
defined
in
each
applicable
subpart,
as
defined
by
the
Small
Business
Administration;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
forprofit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities.
We
have
determined
that
the
proposed
amendments
to
the
General
Provisions
would
not
themselves
cause
any
economic
impacts
on
small
entities.
Rather,
any
economic
impacts
on
small
entities
would
be
associated
with
the
incorporation
of
specific
elements
of
the
General
Provisions
in
the
individual
MACT
standards
which
are
promulgated
for
particular
source
categories.
We
believe
that
adoption
of
the
proposed
amendments
will
not
lead
to
a
substantial
impact
on
small
entities
through
the
incorporation
of
the
General
Provisions
in
individual
MACT
standards.
For
most
MACT
standards,
we
anticipate
that
any
affected
facilities
will
not
be
small
entities.
For
those
MACT
standards
where
small
entities
would
be
affected,
we
believe
any
economic
impact
will
be
minimal
since
the
only
specific
action
which
may
be
required
is
the
submission
to
the
permitting
authority
of
an
existing
document
which
has
already
been
prepared
and
is
on
file
at
the
source.
We
also
have
not
prepared
any
regulatory
flexibility
analysis
for
the
proposed
amendments
to
the
section
112(
j)
rule.
At
this
time,
we
do
not
expect
that
any
Part
2
applications
will
have
to
be
submitted
or
case
by
case
determinations
will
have
to
be
made
under
section
112(
j)
and
thus
no
small
businesses
would
be
affected
by
such
determinations.
We
continue
to
be
interested
in
the
potential
impacts
of
the
proposed
rule
on
small
entities
and
welcome
comments
on
issues
related
to
such
impacts.
H.
Paperwork
Reduction
Act
As
required
by
the
Paperwork
Reduction
Act
(
PRA),
44
U.
S.
C.
3501
et
seq.,
the
OMB
must
clear
any
reporting
and
recordkeeping
requirements
that
qualify
as
an
information
collection
request
(
ICR)
under
the
PRA.
Approval
of
an
ICR
is
not
required
in
connection
with
the
proposed
amendments
to
the
General
Provisions
rule.
This
is
because
the
General
Provisions
do
not
themselves
require
any
reporting
and
recordkeeping
activities,
and
no
ICR
was
submitted
in
connection
with
their
original
promulgation
or
their
subsequent
amendment.
Any
recordkeeping
and
reporting
requirements
are
imposed
only
through
the
incorporation
of
specific
elements
of
the
General
Provisions
in
the
individual
MACT
standards
which
are
promulgated
for
particular
source
categories.
In
any
case,
we
believe
that
adoption
of
the
proposed
amendments
will
not
materially
alter
the
burden
imposed
on
affected
sources
through
the
incorporation
of
the
General
Provisions
in
individual
MACT
standards.
We
anticipate
that
any
incremental
changes
in
the
recordkeeping
and
reporting
burden
estimate
for
individual
MACT
standards
will
be
addressed
in
the
context
of
the
periodic
renewal
process
required
by
the
PRA.
Approval
is
also
not
required
for
the
proposed
amendments
to
the
section
112(
j)
rule.
We
expect
to
promulgate
all
remaining
MACT
standards
before
the
Part
2
application
due
dates
associated
with
those
standards
(
see
Table
1
of
this
preamble),
which
would
eliminate
the
need
for
sources
to
submit
the
Part
2
application.
Approval
is
also
not
necessary
for
resubmission
of
applicability
determination
requests.
We
expect
there
to
be
few
resubmissions,
and
all
of
these
will
be
entirely
at
the
sources'
discretion;
the
rule
does
not
require
submission
or
resubmission
of
such
requests.
Thus
we
do
not
project
any
recordkeeping
or
reporting
burden
to
be
incurred
by
sources
as
a
result
of
these
amendments.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
I.
National
Technology
Transfer
and
Advancement
Act
of
1995
Under
section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
(
NTTAA)
of
1995
(
Public
Law
No.
104
113),
all
Federal
agencies
are
required
to
use
voluntary
consensus
standards
(
VCS)
in
their
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
requires
Federal
agencies
to
provide
Congress,
through
annual
reports
to
OMB,
with
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Federal
Register
/
Vol.
67,
No.
236
/
Monday,
December
9,
2002
/
Proposed
Rules
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.
These
proposed
amendments
do
not
involve
technical
standards.
Therefore,
EPA
is
not
considering
the
use
of
any
VCS.
List
of
Subjects
in
40
CFR
Part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Hazardous
substances,
Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.
Dated:
December
3,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
cited
in
the
preamble,
title
40,
chapter
I
of
the
Code
of
Federal
Regulations
is
proposed
to
be
amended
as
follows:
PART
63
[
AMENDED]
1.
The
authority
citation
for
part
63
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401,
et
seq.
Subpart
A
[
Amended]
2.
Section
63.6
is
amended
by:
a.
Revising
paragraph
(
e)(
1)(
i);
b.
Adding
6
sentences
to
the
beginning
of
paragraph
(
e)(
3)(
v);
and
c.
Revising
the
introductory
text
to
paragraph
(
e)(
3)(
vii).
The
revisions
and
additions
read
as
follows:
§
63.6
Compliance
with
standards
and
maintenance
requirements.
*
*
*
*
*
(
e)
*
*
*
(
1)(
i)
At
all
times,
including
periods
of
startup,
shutdown,
and
malfunction,
owners
or
operators
must
operate
and
maintain
any
affected
source,
including
associated
air
pollution
control
equipment
and
monitoring
equipment,
in
a
manner
consistent
with
safety
and
good
air
pollution
control
practices
for
minimizing
emissions
to
the
levels
required
by
the
relevant
standards.
Determination
of
whether
acceptable
operation
and
maintenance
procedures
are
being
used
will
be
based
on
information
available
to
the
Administrator
which
may
include,
but
is
not
limited
to,
monitoring
results,
review
of
operation
and
maintenance
procedures
(
including
the
startup,
shutdown,
and
malfunction
plan
required
in
paragraph
(
e)(
3)
of
this
section),
review
of
operation
and
maintenance
records,
and
inspection
of
the
source.
*
*
*
*
*
(
3)
*
*
*
(
v)
The
owner
or
operator
must
submit
to
the
Administrator
a
copy
of
the
startup,
shutdown,
and
malfunction
plan
at
the
time
it
is
first
adopted.
The
owner
or
operator
must
also
submit
to
the
Administrator
a
copy
of
any
subsequent
revisions
of
the
startup,
shutdown,
and
malfunction
plan.
Such
revisions
must
be
submitted
at
the
time
they
are
adopted
if
the
revisions
are
required
in
order
to
adequately
address
an
event
involving
a
type
of
malfunction
not
included
in
the
plan,
or
the
revisions
alter
the
scope
of
the
activities
at
the
source
which
are
deemed
to
be
a
startup,
shutdown,
or
malfunction,
or
otherwise
modify
the
applicability
of
any
emission
limit,
work
practice
requirement,
or
other
requirement
in
a
standard
established
under
this
part.
All
other
revisions
to
the
startup,
shutdown,
and
malfunction
plan
may
be
submitted
with
the
semiannual
report
required
by
§
63.10(
d)(
5).
The
owner
or
operator
may
elect
to
submit
the
required
copy
of
the
initial
startup,
shutdown,
and
malfunction
plan,
and
of
all
subsequent
revisions
to
the
plan,
in
an
electronic
format.
If
the
owner
or
operator
claims
that
any
portion
of
a
startup,
shutdown,
and
malfunction
plan,
or
any
revision
of
the
plan,
submitted
to
the
Administrator
is
confidential
business
information
entitled
to
protection
under
section
114(
c)
of
the
CAA
or
40
CFR
2.301,
the
material
which
is
claimed
as
confidential
must
be
clearly
designated
in
the
submission.
*
*
*
*
*
*
*
*
(
vii)
Based
on
the
results
of
a
determination
made
under
paragraph
(
e)(
1)(
i)
of
this
section,
the
Administrator
may
require
that
an
owner
or
operator
of
an
affected
source
make
changes
to
the
startup,
shutdown,
and
malfunction
plan
for
that
source.
The
Administrator
must
require
appropriate
revisions
to
a
startup,
shutdown,
and
malfunction
plan,
if
the
Administrator
finds
that
the
plan:
*
*
*
*
*
3.
Section
63.10
is
amended
by
revising
the
second
sentence
of
paragraph
(
d)(
5)(
i)
to
read
as
follows:
§
63.10
Recordkeeping
and
reporting
requirements.
*
*
*
*
*
(
d)
*
*
*
(
5)(
i)
*
*
*
Reports
shall
only
be
required
if
a
startup,
shutdown,
or
malfunction
occurred
during
the
reporting
period,
and
they
must
include
the
number,
duration,
and
a
brief
description
of
each
malfunction.
*
*
*
*
*
*
*
*
[
FR
Doc.
02
31012
Filed
12
6
02;
8:
45
am]
BILLING
CODE
6560
50
P
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
300
[
FRL
7393
3]
National
Oil
and
Hazardous
Substances
Pollution
Contingency
Plan;
National
Priorities
List
AGENCY:
Environmental
Protection
Agency.
ACTION:
Notice
of
intent
to
delete
the
Industrial
Latex
Corp.
Superfund
Site
from
the
National
Priorities
List.
SUMMARY:
The
Environmental
Protection
Agency
(
EPA)
Region
II
Office
announces
its
intent
to
delete
the
Industrial
Latex
Corp.
Superfund
Site
from
the
National
Priorities
List
(
NPL)
and
requests
public
comment
on
this
action.
The
Industrial
Latex
site
is
located
in
the
Borough
of
Wallington,
Bergen
County,
New
Jersey.
The
NPL
constitutes
appendix
B
to
the
National
Oil
and
Hazardous
Substances
Pollution
Contingency
Plan
(
NCP),
40
CFR
part
300,
which
EPA
promulgated
pursuant
to
section
105
of
the
Comprehensive
Environmental
Response,
Compensation,
and
Liability
Act
of
1980
(
CERCLA),
as
amended.
EPA
and
the
State
of
New
Jersey,
through
the
Department
of
Environmental
Protection,
have
determined
that
all
appropriate
remedial
actions
have
been
completed
at
the
Industrial
Latex
site
and
no
further
fund
financed
remedial
action
is
appropriate
under
CERCLA.
In
addition,
EPA
and
the
State
of
New
Jersey
have
determined
that
the
remedial
actions
taken
at
the
Industrial
Latex
site
protect
public
health
and
the
environment
without
any
further
monitoring
or
restriction.
DATES:
The
EPA
will
accept
comments
concerning
its
intent
to
delete
on
or
before
January
8,
2003.
ADDRESSES:
Comments
should
be
mailed
to:
Stephanie
Vaughn,
Remedial
Project
Manager,
New
Jersey
Remediation
Branch,
Emergency
and
Remedial
Response
Division,
U.
S.
Environmental
Protection
Agency,
Region
II,
290
Broadway,
19th
Floor
New
York,
New
York
10007
1866.
Comprehensive
information
on
the
Industrial
Latex
site
is
contained
in
the
Administrative
Record
and
is
available
for
viewing,
by
appointment
only,
at:
U.
S.
EPA
Records
Center,
290
Broadway
18th
Floor,
New
York,
New
York
10007
1866.
Hours:
9
a.
m.
to
5
p.
m.
Monday
through
Friday.
Contact
the
Records
Center
at
(
212)
637
4308.
Information
on
the
Site
is
also
available
for
viewing
at
the
Information
VerDate
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31>
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15:
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2002
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| epa | 2024-06-07T20:31:40.016521 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0038-0001/content.txt"
} |
EPA-HQ-OAR-2002-0039-0001 | Proposed Rule | "2002-02-18T05:00:00" | National Emission Standards for Hazardous Air
Pollutants for Taconite Iron Ore Processing. | Wednesday,
December
18,
2002
Part
II
Environmental
Protection
Agency
40
CFR
Part
63
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Taconite
Iron
Ore
Processing;
Proposed
Rule
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19:
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Federal
Register
/
Vol.
67,
No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[
Docket
ID
No.
OAR
2002
0039;
FRL
7417
1]
RIN
2060
AJ02
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Taconite
Iron
Ore
Processing
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Proposed
rule.
SUMMARY:
This
action
proposes
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
taconite
iron
ore
processing
plants.
The
EPA
has
identified
taconite
iron
ore
processing
plants
as
a
major
source
of
hazardous
air
pollutant
(
HAP)
emissions.
These
proposed
standards
will
implement
section
112(
d)
of
the
Clean
Air
Act
(
CAA)
by
requiring
all
major
sources
to
meet
HAP
emission
standards
reflecting
application
of
the
maximum
achievable
control
technology
(
MACT).
The
HAP
emitted
by
plants
in
the
taconite
iron
ore
processing
source
category
include
metal
compounds
(
primarily
manganese,
arsenic,
lead,
nickel,
and
chromium),
products
of
incomplete
combustion
(
primarily
formaldehyde),
and
acid
gases
(
hydrochloric
acid
and
hydrofluoric
acid).
Exposure
of
these
substances
has
been
demonstrated
to
cause
adverse
health
effects,
including
chronic
and
acute
disorders
of
the
blood,
heart,
kidneys,
liver,
reproductive
system,
respiratory
system,
and
central
nervous
system.
Some
of
these
pollutants
are
considered
to
be
carcinogens.
DATES:
Comments.
Submit
comments
on
or
before
February
18,
2003.
Public
Hearing.
If
anyone
contacts
the
EPA
requesting
to
speak
at
a
public
hearing
by
January
7,
2003,
a
public
hearing
will
be
held
on
January
17,
2003.
ADDRESSES:
Comments.
Comments
may
be
submitted
electronically,
by
mail,
by
facsimile,
or
through
hand
delivery/
courier.
Send
comments
(
in
duplicate,
if
possible)
to:
Taconite
Iron
Ore
Processing
NESHAP
Docket,
EPA
Docket
Center
(
Air
Docket),
U.
S.
EPA
West,
Mail
Code
6102T,
Room
B108,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
2002
0039.
Follow
the
detailed
instructions
as
provided
in
the
SUPPLEMENTARY
INFORMATION
section.
Public
Hearing.
If
a
public
hearing
is
held,
it
will
be
held
at
the
new
EPA
facility
complex
in
Research
Triangle
Park,
NC
beginning
at
10
a.
m.
FOR
FURTHER
INFORMATION
CONTACT:
Conrad
Chin,
Metals
Group,
Emission
Standards
Division
(
C439
02),
Research
Triangle
Park,
NC
27711,
telephone
number
(
919)
541
1512,
electronic
mail
address:
chin.
conrad@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Regulated
Entities
Category
NAICS*
Example
of
regulated
entities
Taconite
Iron
Ore
Processing
Facilities
......
21221
Taconite
Iron
Ore
Processing
Facilities
[
taconite
ore
crushing
and
handling
operations,
indurating
furnaces,
finished
pellet
handling
operations,
and
ore
dryers].
*
North
American
Information
Classification
System.
This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
your
plant
is
regulated
by
this
action,
you
should
examine
the
applicability
criteria
in
§
63.9581
of
the
proposed
rule.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Docket
The
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
OAR
2002
0039.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
in
the
Taconite
Iron
Ore
Processing
NESHAP
Docket
at
the
EPA
Docket
Center
(
Air
Docket),
EPA
West,
Room
B108,
1301
Constitution
Avenue,
NW.,
Washington,
DC
20460.
The
Docket
Center
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Air
Docket
is
(
202)
566
1742.
Electronic
Access
An
electronic
version
of
the
public
docket
is
available
through
EPA's
electronic
public
docket
and
comment
system,
EPA
Dockets.
You
may
use
EPA
Dockets
at
http://
www.
epa.
gov/
edocket/
to
submit
or
review
public
comments,
access
the
index
of
the
contents
of
the
official
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,''
then
key
in
the
appropriate
docket
identification
number.
Certain
types
of
information
will
not
be
placed
in
the
EPA
dockets.
Information
claimed
as
confidential
business
information
(
CBI)
and
other
information
whose
disclosure
is
restricted
by
statue,
which
is
not
included
in
the
official
public
docket,
will
not
be
available
for
public
viewing
in
EPA's
electronic
public
docket.
EPA's
policy
is
that
copyrighted
material
will
not
be
placed
in
EPA's
electronic
public
docket
but
will
be
available
only
in
printed,
paper
form
in
the
official
public
docket.
Although
not
all
docket
materials
may
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
identified
in
this
document.
For
public
commenters,
it
is
important
to
note
that
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
in
paper,
will
be
made
available
for
public
viewing
in
EPA's
electronic
public
docket
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
disclosure
is
restricted
by
statue.
When
EPA
identifies
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comment
containing
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material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
EPA's
electronic
public
docket.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Public
comments
submitted
on
computer
disks
that
are
mailed
or
delivered
to
the
docket
will
be
transferred
to
EPA's
electronic
public
docket.
Public
comments
that
are
mailed
or
delivered
to
the
docket
will
be
scanned
and
placed
in
EPA's
electronic
public
docket.
Where
practical,
physical
objects
will
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photographed,
and
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photograph
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docket
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Comments
You
may
submit
comments
electronically,
by
mail,
by
facsimile,
or
through
hand
delivery/
courier.
To
ensure
proper
receipt
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identify
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identification
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Register
/
Vol.
67,
No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
number
in
the
subject
line
on
the
first
page
of
your
comment.
Please
ensure
that
your
comments
are
submitted
within
the
specified
comment
period.
Comments
submitted
after
the
close
of
the
comment
period
will
be
marked
``
late.''
EPA
is
not
required
to
consider
these
late
comments.
Electronically
If
you
submit
an
electronic
comment
as
prescribed
below,
EPA
recommends
that
you
include
your
name,
mailing
address,
and
an
e
mail
address
or
other
contact
information
in
the
body
of
your
comment.
Also
include
this
contact
information
on
the
outside
of
any
disk
or
CD
ROM
you
submit
and
in
any
cover
letter
accompanying
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disk
or
CD
ROM.
This
ensures
that
you
can
be
identified
as
the
submitter
of
the
comment
and
allows
EPA
to
contact
you
in
case
EPA
cannot
read
your
comment
due
to
technical
difficulties
or
needs
further
information
on
the
substance
of
your
comment.
EPA's
policy
is
that
EPA
will
not
edit
your
comment,
and
any
identifying
or
contact
information
provided
in
the
body
of
a
comment
will
be
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket
and
made
available
in
EPA's
electronic
public
docket.
If
EPA
cannot
read
your
comment
due
to
technical
difficulties
and
cannot
contact
you
for
clarification,
EPA
may
not
be
able
to
consider
your
comment.
Your
use
of
EPA's
electronic
public
docket
to
submit
comments
to
EPA
electronically
is
EPA's
preferred
method
for
receiving
comments.
Go
directly
to
EPA
Dockets
at
http://
www.
epa.
gov/
edocket
and
follow
the
online
instructions
for
submitting
comments.
Once
in
the
system,
select
``
search''
and
then
key
in
Docket
ID
No.
OAR
2002
0039.
The
system
is
an
``
anonymous
access''
system,
which
means
EPA
will
not
know
your
identity,
e
mail
address,
or
other
contact
information
unless
you
provide
it
in
the
body
of
your
comment.
Comments
may
be
sent
by
electronic
mail
(
e
mail)
to
air
and
rdocket
epa.
gov,
Attention
Docket
ID
No.
OAR
2002
0039.
In
contrast
to
EPA's
electronic
public
docket,
EPA's
email
system
is
not
an
``
anonymous
access''
system.
If
you
send
an
e
mail
comment
directly
to
the
Docket
without
going
through
EPA's
electronic
public
docket,
EPA's
e
mail
system
automatically
captures
your
e
mail
address.
E
mail
addresses
that
are
automatically
captured
by
EPA's
e
mail
system
are
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket
and
made
available
in
EPA's
electronic
public
docket.
You
may
submit
comments
on
a
disk
or
CD
ROM
that
you
mail
to
the
mailing
address
identified
in
this
document.
These
electronic
submissions
will
be
accepted
in
Wordperfect
or
ASCII
file
format.
Avoid
the
use
of
special
characters
and
any
form
of
encryption.
By
Mail
Send
your
comments
(
in
duplicate,
if
possible)
to:
Taconite
Iron
Ore
Processing
NESHAP
Docket,
EPA
Docket
Center
(
Air
Docket),
U.
S.
EPA
West,
Mail
Code
6102T,
Room
B108,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
2002
0039.
By
Hand
Delivery
or
Courier
Deliver
your
comments
(
in
duplicate,
if
possible)
to:
EPA
Docket
Center,
U.
S.
EPA
West,
Mail
Code
6102T,
Room
B108,
1301
Constitution
Avenue,
NW.,
Washington,
DC
20004,
Attention
Docket
ID
No.
OAR
2002
0039.
Such
deliveries
are
only
accepted
during
the
Docket
Center's
normal
hours
of
operation
as
identified
in
this
document.
By
Facsimile
Fax
your
comments
to:
(
202)
566
1741,
Attention
Taconite
Iron
Ore
Processing
NESHAP
Docket,
Docket
ID
No.
OAR
2002
0039.
CBI
Do
not
submit
information
that
you
consider
to
be
CBI
through
EPA's
electronic
public
docket
or
by
e
mail.
Send
or
deliver
information
identified
as
CBI
only
to
the
following
address:
Roberto
Morales,
OAQPS
Document
Control
Officer
(
C404
02),
U.
S.
EPA,
109
TW
Alexander
Drive,
Research
Triangle
Park,
NC
27709,
Attention
Docket
ID
No.
OAR
2002
0039.
You
may
claim
information
that
you
submit
to
EPA
as
CBI
by
marking
any
part
or
all
of
that
information
as
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(
if
you
submit
CBI
on
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or
CD
ROM,
mark
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outside
of
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or
CD
ROM
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and
then
identify
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within
the
disk
or
CD
ROM
the
specific
information
that
is
CBI).
Information
so
marked
will
not
be
disclosed
except
in
accordance
with
procedures
set
forth
in
40
CFR
part
2.
Public
Hearing
Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Ms.
Cassie
Posey,
Metals
Group,
Emission
Standards
Division
(
C439
02),
Research
Triangle
Park,
NC
27711,
telephone
number
(
919)
541
0069,
in
advance
of
the
public
hearing.
Persons
interested
in
attending
the
public
hearing
must
also
call
Ms.
Cassie
Posey
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
these
proposed
emission
standards.
Worldwide
Web
(
WWW)
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
today's
proposal
will
also
be
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature,
a
copy
of
this
action
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(
919)
541
5384.
Outline
The
information
presented
in
this
preamble
is
organized
as
follows:
I.
Background
A.
What
Is
the
Source
of
Authority
for
Development
of
NESHAP?
B.
What
Criteria
Are
Used
in
the
Development
of
NESHAP?
C.
What
Source
Category
Is
Affected
by
This
Proposed
Rule?
D.
What
Processes
Are
Used
at
Taconite
Iron
Ore
Processing
Plants?
E.
What
HAP
Are
Emitted
and
How
Are
They
Controlled?
F.
What
Are
the
Health
Effects
Associated
With
Emissions
From
Taconite
Iron
Ore
Processing
Plants?
II.
Summary
of
the
Proposed
Rule
A.
What
Are
the
Affected
Sources
and
Emission
Points?
B.
What
Are
the
Emission
Limitations
and
Work
Practice
Standards?
C.
What
Are
the
Operation
and
Maintenance
Requirements?
D.
What
Are
the
Initial
Compliance
Requirements?
E.
What
Are
the
Continuous
Compliance
Requirements?
F.
What
Are
the
Notification,
Recordkeeping,
and
Reporting
Requirements?
G.
What
Are
the
Compliance
Deadlines?
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
Did
We
Select
the
Affected
Sources?
B.
How
Did
We
Select
the
Pollutants?
C.
How
Did
We
Determine
the
Bases
and
Levels
of
the
Proposed
Standards?
D.
How
Did
We
Select
the
Initial
Compliance
Requirements?
E.
How
Did
We
Select
the
Continuous
Compliance
Requirements?
F.
How
Did
We
Select
the
Notification,
Recordkeeping,
and
Reporting
Requirements?
IV.
Summary
of
Environmental,
Energy,
and
Economic
Impacts
A.
What
Are
the
Air
Emission
Impacts?
B.
What
Are
the
Cost
Impacts?
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No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
C.
What
Are
the
Economic
Impacts?
D.
What
Are
the
Non
Air
Health,
Environmental
and
Energy
Impacts?
V.
Solicitation
of
Comments
and
Public
Participation
VI.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Executive
Order
13132,
Federalism
C.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
D.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
E.
Unfunded
Mandates
Reform
Act
of
1995
F.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
et
seq.
G.
Paperwork
Reduction
Act
H.
National
Technology
Transfer
and
Advancement
Act
I.
Executive
Order
13211,
Energy
Effects
I.
Background
A.
What
Is
the
Source
of
Authority
for
Development
of
NESHAP?
Section
112
of
the
CAA
requires
us
to
list
categories
and
subcategories
of
major
sources
and
area
sources
of
HAP
and
to
establish
NESHAP
for
the
listed
source
categories
and
subcategories.
The
category
of
major
sources
covered
by
today's
proposed
NESHAP,
Taconite
Iron
Ore
Processing,
was
listed
on
July
16,
1992
(
57
FR
31576).
Major
sources
of
HAP
are
those
that
have
the
potential
to
emit
greater
than
10
tons/
yr
of
any
one
HAP
or
25
tons/
yr
of
any
combination
of
HAP.
B.
What
Criteria
Are
Used
in
the
Development
of
NESHAP?
Section
112
of
the
CAA
requires
that
we
establish
NESHAP
for
the
control
of
HAP
from
both
new
and
existing
major
sources.
The
CAA
requires
the
NESHAP
to
reflect
the
maximum
degree
of
reduction
in
emissions
of
HAP
that
is
achievable.
This
level
of
control
is
commonly
referred
to
as
MACT.
The
MACT
floor
is
the
minimum
control
level
allowed
for
NESHAP
and
is
defined
under
section
112(
d)(
3)
of
the
CAA.
In
essence,
the
MACT
floor
ensures
that
the
standard
is
set
at
a
level
that
assures
that
all
major
sources
achieve
the
level
of
control
at
least
as
stringent
as
that
already
achieved
by
the
better
controlled
and
lower
emitting
sources
in
each
source
category
or
subcategory.
For
new
sources,
the
MACT
floor
cannot
be
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
bestcontrolled
similar
source.
The
MACT
standards
for
existing
sources
can
be
less
stringent
than
standards
for
new
sources,
but
they
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
bestperforming
12
percent
of
existing
sources
in
the
category
or
subcategory
(
or
the
best
performing
5
sources
for
categories
or
subcategories
with
fewer
than
30
sources).
In
developing
MACT,
we
also
consider
control
options
that
are
more
stringent
than
the
floor.
We
may
establish
standards
more
stringent
than
the
floor
based
on
the
consideration
of
cost
of
achieving
the
emissions
reductions,
any
health
and
environmental
impacts,
and
energy
requirements.
C.
What
Source
Category
Is
Affected
by
This
Proposed
Rule?
Section
112(
c)
of
the
CAA
requires
us
to
list
all
categories
of
major
and
area
sources
of
HAP
for
which
we
will
develop
national
emission
standards.
We
published
the
initial
list
of
source
categories
on
July
16,
1992
(
57
FR
31576).
``
Taconite
Iron
Ore
Processing''
is
one
of
the
source
categories
on
the
initial
list.
The
listing
was
based
on
our
determination
that
taconite
iron
ore
processing
plants
may
reasonably
be
anticipated
to
emit
a
variety
of
HAP
listed
in
section
112(
b)
in
quantities
sufficient
to
be
major
sources.
A
taconite
iron
ore
processing
plant
separates
and
concentrates
iron
ore
from
taconite,
a
low
grade
iron
ore,
and
produces
taconite
pellets,
which
are
approximately
60
percent
iron.
The
taconite
iron
ore
processing
source
category
includes,
but
is
not
limited
to,
ore
crushing
and
handling
units,
ore
dryers,
indurating
furnaces,
and
finished
pellet
handling
units.
At
present,
taconite
iron
ore
pellets
are
produced
at
eight
plant
sites
in
the
U.
S.;
six
plants
are
in
Minnesota
and
two
plants
are
in
Michigan.
D.
What
Processes
Are
Used
at
Taconite
Iron
Ore
Processing
Plants?
Taconite
iron
ore
processing
includes
crushing
and
handling
of
the
crude
ore;
concentrating
(
milling,
magnetic
separation,
chemical
flotation,
etc.);
agglomerating
(
dewatering,
drying,
and
balling);
indurating;
and
finished
pellet
handling.
The
main
processes
of
interest
because
of
their
potential
to
generate
HAP
emissions
include
ore
crushing
and
handling,
ore
drying,
indurating,
and
finished
pellet
handling.
Taconite
ore
is
obtained
from
the
ground
using
a
strip
mining
process.
First,
millions
of
tons
of
surface
material
and
rock
are
removed
to
expose
the
taconite
ore
bearing
rock
layers.
Next,
the
taconite
ore
is
blasted,
scooped
up
with
large
cranes
with
shovels,
and
loaded
into
transport
vehicles
such
as
240
ton
haulage
trucks
or
railcars.
The
transport
vehicles
move
the
ore
from
the
mine
to
the
primary
crushers.
At
most
plants
the
mine
is
located
adjacent
to
the
ore
processing
plant.
However,
at
a
few
plants
the
mine
and
the
ore
processing
plant
are
miles
apart.
In
these
cases,
the
taconite
ore
is
loaded
onto
railcars
and
transported
by
train
to
the
processing
plant.
The
ore
crushing
process
begins
where
the
taconite
ore
from
the
mine
is
dumped
from
trucks
or
railcars
into
the
primary
crusher
or
into
feed
stockpiles
for
the
primary
crusher.
The
ore
is
drycrushed
in
one
to
four
stages
depending
on
the
hardness
of
the
ore.
Gyratory
cone
crushers
are
generally
used
for
all
stages
of
crushing.
Primary
crushing
reduces
the
crude
ore
from
run
of
mine
size
to
a
size
about
six
inches
in
diameter,
while
fine
crushing
further
reduces
the
material
to
a
size
about
3
4
of
an
inch
in
diameter.
Intermediate
vibratory
screens
remove
the
undersized
material
from
the
feed
before
it
enters
the
next
crusher.
Dry
ore
crushing
and
handling
also
includes
a
number
of
conveying
and
transfer
points
as
the
ore
is
moved
from
one
crushing
stage
to
the
next.
After
it
is
adequately
crushed,
the
ore
is
conveyed
to
large
ore
storage
bins
at
the
concentrator
building.
In
the
concentrator
building,
water
is
typically
added
to
the
ore
as
it
is
conveyed
into
rod
and
ball
mills
which
further
grind
the
taconite
ore
to
the
consistency
of
coarse
beach
sand.
A
rod/
ball
mill
is
a
large
horizontal
cylinder
that
rotates
on
its
horizontal
axis
and
is
charged
with
heavy
steel
rods
or
balls
and
the
taconite
ore/
water
slurry.
As
the
rods/
balls
tumble
inside
the
mill,
they
grind
the
ore
into
finer
particles.
In
a
subsequent
process
step,
taconite
ore
is
separated
from
the
waste
rock
material
using
a
magnetic
separation
process.
During
magnetic
separation,
a
series
of
magnetized
cylinders
rotate
while
submerged
in
the
taconite
iron
ore
slurry.
The
iron
bearing
taconite
particles
adhere
to
the
magnetized
cylinder
surface
and
are
collected
as
a
iron
rich
slurry.
The
iron
content
of
the
slurry
is
further
increased
using
a
combination
of
hydraulic
concentration
(
gravity
settling)
and
chemical
flotation.
Since
the
concentrating
processes
are
completely
wet
operations,
any
potential
particulate
or
HAP
metal
emissions
are
suppressed.
However,
there
are
exceptions,
such
as
one
plant
that
conducts
dry
cobbing
(
a
dry
magnetic
separation
process)
instead
of
a
wet
magnetic
separation
process.
The
concentrated
taconite
slurry
then
enters
the
agglomerating
process.
Water
is
typically
removed
from
the
taconite
slurry
using
vacuum
disk
filters
or
similar
equipment.
One
plant,
which
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Proposed
Rules
processes
a
finer
grained
ore,
uses
rotary
dryers
after
the
disc
filters
to
dry
the
ore
further.
These
dryers
are
rotary
dryers,
which
repeatedly
tumble
the
wet
ore
concentrate
through
a
heated
air
stream
to
reduce
the
amount
of
entrained
moisture
in
the
ore.
Next,
the
taconite
is
mixed
with
various
binding
agents
such
as
bentonite
or
dolomite
in
a
balling
drum
which
tumbles
and
rolls
the
taconite
into
unfired
pellets.
When
the
unfired
pellets
exit
the
balling
drum,
they
are
transferred
to
a
metal
grate
that
conveys
them
to
the
furnace.
Once
the
pellets
exit
the
balling
drum
they
are
relatively
dry
and,
therefore,
have
the
potential
to
emit
particulate
HAP.
During
the
indurating
process,
the
unfired
taconite
pellets
are
hardened
and
oxidized
in
the
indurating
furnace
at
a
fusion
temperature
between
2,290
to
2,550
°
F.
Two
types
of
indurating
furnaces
are
currently
used
within
this
source
category:
straight
grate
furnaces
and
grate
kiln
furnaces.
The
indurating
furnace
process
begins
at
the
point
where
the
grate
feed
conveyor
discharges
the
unfired
pellets
onto
the
furnace
traveling
grate
and
ends
where
the
hardened
pellets
exit
the
indurating
furnace
cooler.
In
straight
grate
indurating
furnaces,
a
continuous
bed
of
unfired
pellets
is
carried
on
a
metal
grate
through
different
furnace
temperature
zones.
Each
zone
will
have
either
a
heated
upward
draft
or
downward
draft
blown
through
the
pellets.
A
layer
of
fired
pellets
is
placed
on
the
metal
grate
prior
to
the
addition
of
unfired
pellets.
This
hearth
layer
allows
for
even
airflow
through
the
pellet
bed
and
acts
as
a
buffer
between
the
metal
grate
and
the
exothermic
heat
generated
from
the
oxidation
of
taconite
pellets
in
the
indurating
stage.
Before
the
pellets
can
be
oxidized,
all
remaining
moisture
is
driven
off
in
the
first
two
stages
of
the
furnace,
the
updraft
and
downdraft
drying
zones.
Unfired
pellets
must
be
heated
gradually;
otherwise,
moisture
in
the
unfired
pellets
expands
too
quickly
and
causes
the
pellets
to
explode.
After
they
are
dried,
the
pellets
enter
a
preheat
zone
of
the
furnace
where
the
temperature
is
gradually
increased
for
the
indurating
stage.
The
next
zone
is
the
actual
firing
zone
for
induration,
where
the
pellets
are
exposed
to
the
highest
temperature.
The
fired
pellets
then
enter
the
post
firing
zone,
where
the
oxidation
process
is
completed.
Finally,
the
pellets
are
cooled
by
the
intake
of
ambient
air
typically
in
two
stages
of
cooling.
A
unique
characteristic
of
straight
grate
furnaces
is
that
approximately
30
percent
of
the
fired
pellets
are
recycled
to
the
feed
end
of
the
furnace
for
use
as
the
hearth
layer.
The
remaining
pellets
are
transported
by
conveyor
belts
to
storage
areas.
Waste
gases
from
the
straight
grate
furnace
are
discharged
primarily
through
two
ducts:
the
hood
exhaust,
which
handles
the
cooling
and
drying
gases;
and
the
windbox
exhaust,
which
handles
the
preheat,
firing,
and
afterfiring
gases.
For
a
typical
straight
grate
furnace,
the
two
discharge
ducts
are
combined
into
one
common
header
before
the
flow
is
divided
into
several
ducts
to
be
exhausted
to
the
atmosphere
after
control.
The
grate
kiln
indurating
furnace
system
consists
of
a
traveling
grate,
a
rotary
kiln,
and
an
annular
cooler.
The
grate
kiln
system
represents
a
newer
generation
of
indurating
furnaces
and
is
widely
used
by
the
taconite
plants.
As
with
the
straight
grate
furnace
system,
the
grate
kiln
system
is
also
a
counterflow
heat
exchanger,
with
the
unfired
pellets
and
indurated
pellets
moving
in
a
direction
opposite
to
that
of
the
process
gas
flow.
A
six
inch
bed
of
unfired
pellets
is
laid
on
a
continuously
moving,
horizontal
grate.
The
traveling
grate
carries
the
unfired
pellets
into
a
dryer/
preheater
that
resembles
a
large
rectangular
oven.
In
the
first
half
of
the
traveling
grate,
unfired
pellets
are
gradually
dried
by
hot
air
at
a
temperature
of
700
°
F.
The
second
half
of
the
traveling
grate
is
called
the
preheater,
where
the
unfired
pellets
are
heated
to
a
temperature
of
2,000
°
F
prior
to
dropping
into
the
rotary
kiln
furnace.
Pellets
are
discharged
from
the
traveling
grate
and
into
the
rotary
kiln.
Final
indurating
of
the
pellets
occurs
in
the
kiln
as
the
pellets
tumble
down
the
rotating
kiln.
The
rotary
kiln
typically
operates
at
a
temperature
of
2,300
to
2,400
°
F
to
ensure
that
the
kiln
oxidizes
the
iron
pellets
from
a
magnetite
structure
into
a
hematite
structure.
The
hardened
pellets
are
then
discharged
to
a
large
annular
shaped
cooler,
which
is
an
integral
part
of
an
elaborate
energy
recuperation
system.
The
fired
pellets
discharged
from
the
kiln
first
enter
the
primary
cooling
zone
of
the
annular
cooler,
where
ambient
air
is
brought
in
to
cool
the
pellets
in
a
counter
current
flow.
After
the
pellets
heat
the
ambient
air
to
approximately
2,000
°
F,
it
is
then
used
as
preheated
combustion
air
in
the
rotary
kiln.
As
the
cooled
pellets
enter
a
final
cooling
zone,
additional
ambient
air
is
used
to
cool
the
pellets
further.
Air
exiting
the
final
cooling
zone
is
heated
to
approximately
1,000
°
F
and
is
used
to
maintain
the
temperature
in
the
dryer
section
of
the
traveling
grate.
Pellets
exiting
the
final
cooling
zone
are
cooled
to
an
average
temperature
of
175
to
225
°
F.
Combustion
air
from
the
rotary
kiln,
which
is
approximately
2,000
°
F,
is
used
to
maintain
the
temperature
in
the
preheat
section
of
the
traveling
grate.
Pellet
cooler
vent
stacks
are
atmospheric
vents
in
the
cooler
section
of
a
grate
kiln
indurating
furnace.
Pellet
cooler
vent
stacks
exhaust
cooling
air
that
is
not
returned
for
heat
recuperation.
Straight
grate
furnaces
do
not
have
pellet
cooler
vent
stacks.
The
pellet
cooler
vent
stack
should
not
be
confused
with
the
cooler
discharge
stack,
which
is
in
the
pellet
loadout
or
dumping
area.
New
grate
kiln
furnace
designs
eliminate
the
cooler
vent
stack
by
recirculating
the
air
through
the
furnace.
The
finished
pellet
handling
process
begins
where
the
fired
taconite
pellets
exit
the
indurating
furnace
cooler
(
i.
e.,
pellet
loadout)
and
ends
at
the
finished
pellet
stockpile.
Operations
include
finished
pellet
screening,
transfer,
and
storage.
E.
What
HAP
Are
Emitted
and
How
Are
They
Controlled?
Ore
crushing
and
handling,
ore
drying,
and
finished
pellet
handling
are
all
potentially
significant
points
of
particulate
matter
(
PM)
emissions.
In
addition,
because
taconite
ore
inherently
contains
trace
metals,
such
as
manganese,
chromium,
cobalt,
arsenic,
and
lead,
they
are
also
emitters
of
HAP
metal
compounds.
Manganese
compounds
are
the
predominate
metal
HAP
emitted
from
ore
crushing
and
handling,
ore
drying,
and
finished
pellet
handling,
accounting
for
10
tons/
year.
All
other
metal
HAP
compounds
are
emitted
from
ore
crushing
and
handling,
ore
drying,
and
finished
pellet
handling
at
rates
of
less
than
0.1
tons
per
year.
Approximately
70
percent
of
the
ore
crushing
and
handling
and
finished
pellet
handling
units
control
PM
emissions
with
wet
scrubbers,
such
as
venturi
scrubbers,
marble
bed
scrubbers,
or
impingement
scrubbers.
The
remaining
units
control
PM
emissions
with
baghouses,
low
energy
scrubbers
(
i.
e.,
rotoclones),
multiclones,
and
electrostatic
precipitators
(
ESP).
The
two
ore
dryers
are
controlled
by
cyclones
and
impingement
scrubbers
in
series.
The
indurating
furnaces
are
the
most
significant
sources
of
HAP
emissions,
accounting
for
about
99
percent
of
the
total
HAP
emissions
from
the
taconite
iron
ore
processing
source
category.
Three
types
of
HAP
are
emitted
from
the
waste
gas
stacks
of
indurating
furnaces.
The
first
type
of
HAP
is
metallic
HAP
existing
as
a
portion
of
particulate
emissions
from
the
taconite
ore
or
fuel
(
such
as
coal)
fed
into
the
furnaces.
Manganese
and
arsenic
compounds
are
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Vol.
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No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
the
predominate
metal
HAP
emitted
by
indurating
furnaces
(
approximately
5.8
and
6.5
tons/
year,
respectively,
for
the
industry);
chromium,
lead,
and
nickel
compounds
are
emitted
in
smaller
amounts
(
each
approximately
between
2
to
5
tons/
year
for
the
industry);
and
antimony,
beryllium,
cadmium,
cobalt,
mercury,
and
selenium
compounds
are
emitted
in
yet
smaller
amounts
(
each
approximately
less
than
1
ton/
year
for
the
industry).
The
second
type
of
HAP
is
organic
HAP
resulting
as
products
of
incomplete
combustion,
primarily
formaldehyde.
Emissions
test
data
from
indurating
furnaces
confirm
the
presence
of
formaldehyde.
The
third
type
of
HAP
is
acidic
gases,
such
as
hydrochloric
acid
and
hydrofluoric
acid.
Fluorine
and
chlorine
compounds
in
the
raw
materials
are
liberated
during
the
indurating
process
and
combine
with
moisture
in
the
exhaust
to
form
hydrochloric
acid
and
hydrofluoric
acid.
Both
formaldehyde
and
the
acid
gases
are
present
in
exhaust
gas
from
the
indurating
furnace
stacks
at
concentrations
around
a
few
parts
per
million
(
ppm).
Formaldehyde
emissions
from
the
entire
industry
are
estimated
to
be
181
tons/
year.
Total
emissions
of
hydrogen
chloride
and
hydrogen
fluoride
are
approximately
349
and
308
tons/
year,
respectively.
Emissions
from
the
indurating
furnace
stacks
are
typically
controlled
with
either
a
venturi
wet
scrubber
or
an
ESP.
One
indurating
furnace
controls
emissions
with
a
multiclone
and
another
furnace
controls
emissions
with
a
gravity
collector.
F.
What
Are
the
Health
Effects
Associated
With
Emissions
From
Taconite
Iron
Ore
Processing
Plants?
As
previously
mentioned
in
this
preamble,
there
are
a
variety
of
metal
HAP
contained
in
the
PM
emitted
from
taconite
iron
ore
processing.
These
include
primarily
manganese
and
arsenic
compounds,
with
smaller
quantities
of
lead,
nickel
and
chromium
compounds.
Antimony,
beryllium,
cadmium,
cobalt,
mercury,
and
selenium
compounds
are
emitted
in
yet
smaller
amounts.
Other
HAP,
such
as
formaldehyde,
hydrochloric
acid,
and
hydrofluoric
acid,
are
present
in
the
waste
gas
stream
from
the
indurating
furnace
pelletizing
stacks
on
the
order
of
ppm.
Manganese
and
arsenic
compounds
comprise
the
majority
of
the
metal
HAP
emissions.
Adverse
health
effects
in
humans
have
been
associated
with
manganese
dietary
deficiencies
and
excessive
exposure
to
manganese.
Chronic
exposure
to
low
levels
of
manganese
in
the
diet
is
considered
to
be
nutritionally
essential
in
humans,
with
a
recommended
daily
allowance
of
2
to
5
milligrams
per
day.
Chronic
exposure
to
high
levels
of
manganese
by
inhalation
in
humans
results
primarily
in
central
nervous
system
effects.
Visual
reaction
time,
hand
steadiness,
and
eyehand
coordination
were
affected
in
chronically
exposed
workers.
Manganism,
characterized
by
feelings
of
weakness
and
lethargy,
tremors,
a
masklike
face,
and
psychological
disturbances,
may
result
from
chronic
exposure
to
higher
levels.
Impotence
and
loss
of
libido
have
been
noted
in
male
workers
afflicted
with
manganism
attributed
to
inhalation
exposures.
We
have
classified
manganese
in
Group
D,
not
classifiable
as
to
carcinogenicity
in
humans.
Arsenic
can
be
toxic
in
humans.
Acute
inhalation
exposure
to
arsenic
causes
gastrointestinal
effects,
such
as
nausea,
diarrhea,
and
abdominal
pain,
hemolysis,
and
central
nervous
system
disorders.
Chronic
inhalation
exposure
to
inorganic
arsenic
is
associated
with
irritation
of
the
skin
and
mucous
membranes
and
is
strongly
associated
with
lung
cancer.
We
have
classified
inorganic
arsenic
as
a
Group
A,
a
known
human
carcinogen
of
high
carcinogenic
hazard.
Exposure
to
formaldehyde
can
result
in
irritation
of
the
skin
and
mucous
membranes.
We
have
classified
formaldehyde
as
a
Group
B1,
probable
human
carcinogen
of
medium
carcinogenic
hazard.
Acute
exposure
to
the
acid
gases
can
cause
severe
respiratory
damage
in
humans
including
severe
irritation
and
pulmonary
edema.
Chronic
exposure
to
hydrochloric
acid
has
been
reported
to
cause
gastritis,
chronic
bronchitis,
and
dermatitis
in
workers.
Chronic
exposure
to
low
levels
of
fluoride
has
a
beneficial
effect
of
dental
cavity
prevention
and
may
be
helpful
in
the
treatment
of
osteoporosis.
However,
exposure
to
higher
levels
of
hydrochloric
or
hydrofluoric
acid
may
cause
dental
discoloration
and
erosion.
In
addition
to
HAP,
the
proposed
rule
would
also
reduce
PM
emissions,
which
are
controlled
under
national
ambient
air
quality
standards.
Emissions
of
PM
have
been
associated
with
aggravation
of
existing
respiratory
and
cardiovascular
disease
and
increased
risk
of
premature
death.
We
recognize
that
the
degree
of
adverse
effects
to
health
experienced
by
exposed
individuals
can
range
from
mild
to
severe.
The
extent
and
degree
to
which
the
health
effects
may
be
experienced
depend
on:
Pollutant
specific
characteristics
(
e.
g.,
toxicity,
half
life
in
the
environment,
bioaccumulation,
and
persistence);
The
ambient
concentrations
observed
in
the
area
(
e.
g.,
as
influenced
by
emission
rates,
meteorological
conditions,
and
terrain);
The
frequency
and
duration
of
exposures;
and
Characteristics
of
exposed
individuals
(
e.
g.,
genetics,
age,
preexisting
health
conditions,
and
lifestyle),
which
vary
significantly
within
the
general
population.
II.
Summary
of
the
Proposed
Rule
A.
What
Are
the
Affected
Sources
and
Emission
Points?
The
proposed
rule
would
affect
eight
plants
engaged
in
the
processing
of
taconite
iron
ore
(
six
plants
in
Minnesota
and
two
plants
in
Michigan).
The
affected
sources
within
each
plant
include
ore
crushing
and
handling,
ore
dryers,
indurating
furnaces,
and
finished
pellet
handling.
The
ore
crushing
and
handling
affected
source
includes
the
collection
of
all
new
and
existing
ore
crushing
and
handling
emission
units
including
all
primary,
secondary,
and
tertiary
crushers;
associated
screens,
conveyors,
storage
bins
and
piles;
transfer
points;
and
grate
feed.
The
ore
dryer
affected
source
includes
each
new
or
existing
individual
ore
dryer.
The
indurating
furnace
affected
source
includes
each
new
or
existing
individual
indurating
furnace.
The
finished
pellet
handling
affected
source
includes
the
collection
of
all
new
and
existing
pellet
handling
emission
units
including
all
pellet
screens,
conveyors,
storage
bins,
piles,
and
transfer
points.
An
existing
affected
source
is
one
constructed
or
reconstructed
on
or
before
December
18,
2002.
A
new
affected
source
is
one
constructed
or
reconstructed
after
December
18,
2002.
B.
What
Are
the
Emission
Limitations
and
Work
Practice
Standards?
The
proposed
rule
includes
PM
emission
limits,
work
practice
standards,
and
operating
limits
for
control
devices.
Particulate
matter
serves
as
a
surrogate
measure
of
metallic
HAP
emissions.
The
proposed
PM
emissions
limits
for
ore
crushing
and
handling
and
finished
pellet
handling
operations
are
0.008
grains
per
dry
standard
cubic
foot
(
gr/
dscf)
for
existing
sources
and
0.005
gr/
dscf
for
new
sources.
Compliance
with
the
proposed
PM
emissions
limits
for
ore
crushing
and
handling
are
determined
based
on
the
flow
weighted
mean
concentration
of
emissions
for
all
ore
crushing
and
handling
units
at
the
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Proposed
Rules
plant.
Similarly,
compliance
with
the
proposed
PM
emissions
limits
for
finished
pellet
handling
are
determined
based
on
the
flow
weighted
mean
concentration
of
PM
emissions
for
all
pellet
handling
units
at
the
plant.
The
proposed
rule
would
establish
PM
emission
limits
that
must
be
achieved
by
each
individual
ore
dryer.
The
proposed
emission
limit
is
0.052
gr/
dscf
for
existing
dryers
and
0.025
gr/
dscf
for
new
dryers.
Ore
dryers
with
multiple
stacks
would
calculate
their
PM
emissions
as
a
flow
weighted
mean
concentration
of
PM
emissions
from
all
stacks.
The
proposed
rule
would
establish
PM
emission
limits
that
must
be
achieved
by
each
individual
indurating
furnace.
Indurating
furnaces
with
multiple
stacks
would
calculate
their
PM
emissions
as
a
flow
weighted
mean
concentration
of
PM
emissions
from
all
stacks.
For
each
straight
grate
indurating
furnace
processing
magnetite,
the
proposed
emissions
limit
is
0.010
gr/
dscf
for
existing
straight
grate
furnaces
and
0.006
gr/
dscf
for
new
straight
grate
furnaces.
For
each
grate
kiln
indurating
furnace
processing
magnetite,
the
proposed
emissions
limit
is
0.011
gr/
dscf
for
existing
grate
kiln
furnaces
and
0.006
gr/
dscf
for
new
grate
kiln
furnaces.
For
each
grate
kiln
indurating
furnace
processing
hematite,
the
proposed
emissions
limit
is
0.025
gr/
dscf
for
existing
grate
kiln
furnaces
and
0.018
gr/
dscf
for
new
grate
kiln
furnaces.
The
proposed
rule
also
includes
specific
requirements
for
continuous
parameter
monitoring
and
associated
operating
limits
for
baghouses,
wet
scrubbers,
and
dry
ESP.
Baghouses
are
to
be
equipped
with
a
bag
leak
detection
system
(
BLDS)
capable
of
monitoring
relative
changes
in
PM
loading
in
the
baghouse
exhaust,
which
is
to
alarm
whenever
a
predetermined
set
point
is
exceeded,
indicating
an
increase
in
emissions
above
that
allowed
at
the
set
point.
The
proposed
rule
would
limit
the
frequency
and
duration
of
alarms
to
no
more
than
5
percent
of
a
source's
total
operating
time
in
any
semiannual
reporting
period.
In
the
case
of
wet
scrubbers,
sources
would
be
required
to
continuously
monitor
scrubber
pressure
drop
and
water
flow
rate
and
operate
at
all
times
at
or
above
specified
hourly
average
values
established
during
initial
performance
testing.
For
dry
ESP,
sources
would
be
required
to
install
and
operate
continuous
opacity
monitoring
systems
(
COMS).
Each
source
must
report
as
a
deviation
any
6
minute
period
during
which
the
average
opacity
exceeds
the
opacity
value
corresponding
to
the
99
percent
upper
confidence
level
established
during
the
performance
test.
The
proposed
rule
would
require
sources
to
submit
information
on
alternative
monitoring
parameters
and
operating
limits
if
a
control
device
other
than
a
baghouse,
wet
scrubber,
or
dry
ESP
is
used.
All
plants
subject
to
the
proposed
rule
would
be
required
to
prepare
and
implement
a
written
fugitive
dust
emissions
control
plan.
The
plan
would
describe
in
detail
the
measures
that
will
be
put
in
place
to
control
fugitive
dust
emissions
from
the
following
sources
at
a
plant,
as
applicable:
stockpiles,
material
transfer
points,
plant
roadways,
tailings
basin,
pellet
loading
areas
and
yard
areas.
Existing
fugitive
dust
emission
control
plans
that
describe
current
measures
to
control
fugitive
dust
emission
sources
that
have
been
approved
as
part
of
a
State
implementation
plan
or
title
V
permit
would
be
acceptable,
provided
they
address
the
prior
listed
fugitive
dust
emission
sources.
C.
What
Are
the
Operation
and
Maintenance
Requirements?
All
plants
subject
to
the
proposed
rule
would
be
required
to
prepare
and
implement
a
written
startup,
shutdown,
and
malfunction
plan
according
to
the
requirements
in
40
CFR
63.6(
e)
of
the
NESHAP
General
Provisions.
In
addition,
a
written
operation
and
maintenance
plan
is
also
required
for
each
control
device
subject
to
an
operating
limit.
This
plan
must
describe
procedures
for
the
inspection
and
preventative
maintenance
of
control
devices,
as
well
as
corrective
action
requirements
specific
to
baghouses
equipped
with
bag
leak
detection
systems.
In
the
event
of
a
bag
leak
detection
system
alarm,
the
plan
must
include
specific
requirements
for
initiating
corrective
action
to
determine
the
cause
of
the
problem
within
1
hour,
initiating
corrective
action
to
fix
the
problem
within
24
hours,
and
completing
all
corrective
actions
needed
to
fix
the
problem
as
soon
as
practicable.
D.
What
Are
the
Initial
Compliance
Requirements?
To
demonstrate
initial
compliance
with
the
PM
emission
limit
for
the
ore
crushing
and
handling
affected
source,
the
flow
weighted
mean
concentration
of
PM
emissions
of
all
units
within
the
affected
source
must
not
exceed
the
applicable
PM
emission
limit.
Similarly,
for
the
finished
pellet
handling
affected
source,
the
flow
weighted
mean
concentration
of
PM
emissions
of
all
units
within
the
affected
source
must
not
exceed
the
applicable
PM
emission
limit.
In
all
cases,
initial
compliance
must
be
demonstrated
through
a
performance
test.
The
performance
test
must
be
conducted
using
EPA
Method
5
or
17
in
40
CFR
part
60,
appendix
A.
All
initial
compliance
tests
must
be
completed
no
later
than
2
years
following
the
compliance
date.
In
lieu
of
conducting
performance
tests
for
all
emission
units,
the
plant
may
elect
to
group
similar
emission
units
together
and
conduct
initial
performance
tests
on
a
representative
sample
of
units
within
each
group.
Each
plant
must
submit
a
testing
plan
to
the
permitting
authority
for
approval.
The
testing
plan
must
identify
the
emission
units
that
will
be
grouped
as
similar,
identify
the
representative
unit(
s)
that
will
be
tested
for
each
group,
and
the
proposed
schedule
for
testing.
To
demonstrate
initial
compliance
with
the
PM
emission
limit
for
each
indurating
furnace
and
each
ore
dryer,
the
flow
weighted
mean
concentration
of
PM
emissions
of
all
stacks
for
each
furnace
or
each
ore
dryer
must
not
exceed
the
applicable
PM
emission
limit.
Initial
compliance
must
be
demonstrated
through
an
initial
performance
test.
The
performance
test
must
be
conducted
using
EPA
Method
5
or
17
in
40
CFR
part
60,
appendix
A.
The
initial
compliance
test
for
each
indurating
furnace
and
each
ore
dryer
must
be
completed
no
later
than
180
calendar
days
after
the
compliance
date.
For
indurating
furnaces
and
ore
dryers
with
multiple
stacks,
all
stacks
for
the
indurating
furnace
or
ore
dryer
must
be
tested
simultaneously.
The
proposed
rule
would
also
require
that
certain
operating
limits
on
control
devices
be
established
during
the
initial
compliance
test
to
ensure
that
control
devices
operate
properly
on
a
continuing
basis.
All
operating
limits
must
be
established
during
a
performance
test
that
demonstrates
compliance
with
the
applicable
emission
limit.
During
the
initial
compliance
tests,
operating
limits
must
be
established
for
pressure
drop
and
scrubber
water
flow
rate
for
all
wet
scrubbers,
and
opacity
(
using
a
COMS)
for
dry
ESP.
To
demonstrate
initial
compliance
with
the
proposed
work
practice
standards,
plants
would
prepare,
submit,
and
implement
a
fugitive
dust
emission
control
plan
on
or
before
the
applicable
compliance
date
as
specified
in
§
63.9583
of
the
proposed
rule.
To
demonstrate
initial
compliance
with
the
proposed
operation
and
maintenance
requirements,
plants
would
certify
in
their
notification
of
compliance
status
that
they
have
prepared
the
written
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243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
plans
and
will
operate
control
devices
according
to
the
procedures
in
the
plan.
E.
What
Are
the
Continuous
Compliance
Requirements?
For
ore
crushing
and
handling,
ore
dryers
and
finished
pellet
handling
units,
the
proposed
rule
would
require
plants
to
conduct
subsequent
performance
tests
to
demonstrate
continued
compliance
with
the
PM
emission
limits
following
the
schedule
established
in
the
title
V
permit
for
each
plant.
If
a
title
V
permit
has
not
been
issued,
the
plant
must
submit
a
testing
plan
and
schedule
to
the
permitting
authority
for
approval.
For
each
indurating
furnace,
the
proposed
rule
would
require
subsequent
testing
of
all
stacks
based
on
the
schedule
established
in
each
plant's
title
V
operating
permit,
but
no
less
frequent
than
twice
per
5
year
permit
term.
If
a
title
V
permit
has
not
been
issued,
then
the
plant
must
submit
a
testing
plan
and
schedule
to
the
permitting
authority
for
approval.
The
testing
frequency
in
the
testing
plan
must
be
no
less
frequent
than
twice
per
5
year
period.
Plants
are
required
to
monitor
operating
parameters
for
control
devices
subject
to
operating
limits
and
carry
out
the
procedures
in
their
fugitive
dust
emissions
control
plan
and
their
operation
and
maintenance
plan.
To
demonstrate
continuous
compliance,
plants
must
keep
records
documenting
compliance
with
the
rule
requirements
for
monitoring,
the
fugitive
dust
emissions
control
plan,
the
operation
and
maintenance
plan,
and
installation,
operation,
and
maintenance
of
a
continuous
parameter
monitoring
system
(
CPMS).
For
baghouses,
plants
are
required
to
monitor
the
relative
change
in
PM
loading
using
a
bag
leak
detection
system
and
make
inspections
at
specified
intervals.
The
bag
leak
detection
system
must
be
installed
and
operated
according
to
the
EPA
guidance
document
``
Fabric
Filter
Bag
Leak
Detection
Guidance,''
EPA
454/
R
98
015,
September
1997.
The
document
is
available
on
the
TTN
at
http:
www.
epa.
gov/
ttnemc01/
cem/
tribo.
pdf.
If
the
system
does
not
work
based
on
the
triboelectric
effect,
it
must
be
installed
and
operated
in
a
manner
consistent
with
the
manufacturer's
written
specifications
and
recommendations.
The
basic
inspection
requirements
include
daily,
weekly,
monthly,
or
quarterly
inspections
of
specified
parameters
or
mechanisms
with
monitoring
of
bag
cleaning
cycles
by
an
appropriate
method.
To
demonstrate
continuous
compliance,
the
proposed
rule
would
require
records
of
bag
leak
detection
system
alarms
and
records
documenting
conformance
with
the
operation
and
maintenance
plan,
as
well
as
the
inspection
and
maintenance
procedures.
For
scrubbers,
plants
would
be
required
to
use
a
CPMS
to
measure
and
record
the
hourly
average
pressure
drop
and
scrubber
water
flow
rate.
To
demonstrate
continuous
compliance,
plants
would
keep
records
documenting
conformance
with
the
monitoring
requirements
and
the
installation,
operation,
and
maintenance
requirements
for
the
CPMS.
For
dry
ESP,
plants
are
required
to
use
a
COMS
to
measure
and
record
the
average
hourly
opacity
of
emissions
exiting
each
stack
of
the
control
device.
Plants
must
operate
and
maintain
the
COMS
according
to
the
requirements
in
40
CFR
63.8
of
the
NESHAP
General
Provisions
and
Performance
Specification
1
in
40
CFR
part
60,
appendix
B.
These
requirements
include
a
quality
control
program
that
consists
of
a
daily
calibration
drift
assessment,
quarterly
performance
audit,
and
annual
zero
alignment.
F.
What
are
the
Notification,
Recordkeeping,
and
Reporting
Requirements?
The
proposed
notification,
recordkeeping,
and
reporting
requirements
are
based
on
the
NESHAP
General
Provisions
in
40
CFR
part
63,
subpart
A.
Table
2
of
the
proposed
rule
lists
each
of
the
requirements
in
the
General
Provisions
(
§
§
63.2
through
63.15)
with
an
indication
of
whether
they
do
or
do
not
apply.
The
plant
owner
or
operator
is
required
to
submit
each
initial
notification
required
in
the
NESHAP
General
Provisions
that
applies
to
their
plant.
These
include
an
initial
notification
of
applicability
with
general
information
about
the
plant
and
notifications
of
performance
tests
and
compliance
status.
Plants
are
required
to
maintain
the
records
required
by
the
NESHAP
General
Provisions
that
are
necessary
to
document
compliance,
such
as
performance
test
results;
copies
of
startup,
shutdown,
and
malfunction
plans
and
associated
corrective
action
records;
monitoring
data;
and
inspection
records.
Except
for
the
operation
and
maintenance
plan
for
control
devices,
the
fugitive
dust
emissions
control
plan,
and
the
testing
plan,
all
records
must
be
kept
for
a
total
of
5
years,
with
the
records
from
the
most
recent
2
years
kept
onsite.
The
proposed
rule
would
require
that
the
operation
and
maintenance
plan
for
control
devices
subject
to
an
operating
limit,
the
fugitive
dust
emissions
control
plan,
and
the
testing
plan,
be
kept
onsite
and
available
for
inspection
upon
request
for
the
life
of
the
affected
source
or
until
the
affected
source
is
no
longer
subject
to
the
rule
requirements.
Semiannual
reports
are
required
for
any
deviation
from
an
emission
limitation,
including
an
operating
limit.
Each
report
is
due
no
later
than
30
days
after
the
end
of
the
reporting
period.
If
no
deviation
occurred,
only
a
summary
report
is
required.
If
a
deviation
did
occur,
more
detailed
information
is
required.
An
immediate
report
is
required
if
there
were
actions
taken
during
a
startup,
shutdown,
or
malfunction
that
were
not
consistent
with
the
startup,
shutdown,
and
malfunction
plan
and
the
source
exceeded
its
emission
limit.
Deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
not
violations
if
the
owner
or
operator
demonstrates
to
the
authority
with
delegation
for
enforcement
that
the
source
was
operating
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan.
Plants
must
also
submit
the
fugitive
dust
emissions
control
plan,
testing
plan,
and
all
operation
and
maintenance
plans
on
or
before
the
applicable
compliance
date
to
the
Administrator
or
delegated
authority.
G.
What
are
the
Compliance
Deadlines?
The
owner
or
operator
of
an
existing
affected
source
must
comply
within
[
DATE
3
YEARS
AFTER
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
New
or
reconstructed
sources
that
startup
on
or
before
the
effective
date
of
the
final
rule
must
comply
by
the
effective
date
of
the
final
rule.
New
or
reconstructed
sources
that
startup
after
the
effective
date
of
the
final
rule
must
comply
upon
initial
startup.
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
Did
We
Select
the
Affected
Sources?
An
affected
source
is
the
collection
of
equipment,
processes
and
activities
within
a
source
category
to
which
an
emission
limitation,
work
practice
standard,
or
other
regulatory
requirement
in
a
MACT
standard
will
apply.
Depending
on
circumstance,
we
have
adopted
broader
or
narrower
definitions
of
affected
source.
In
some
instances,
we
have
adopted
a
definition
as
broad
as
all
processes,
equipment
and
activities
at
a
source,
while
in
other
instances,
we
have
defined
affected
source
as
narrowly
as
a
single
piece
of
equipment.
The
selection
of
affected
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Proposed
Rules
source
is
guided
by
the
consideration
of
many
factors
including
similarities
and
dissimilarities
in
emission
units
in
terms
of
their
size,
type,
and
HAP
emissions
potential;
the
functional
relationship
of
an
emission
unit
or
grouping
of
units
within
a
plant
or
process;
and
the
effect
of
an
affected
source
definition
on
when
and
where
new
source
MACT
should
apply.
We
considered
three
different
approaches
for
designating
the
affected
source:
the
entire
taconite
iron
ore
processing
plant,
groups
of
emission
points,
and
individual
emission
points.
In
selecting
the
affected
sources
for
regulation,
we
identified
each
HAPemitting
operation,
the
HAP
emitted,
and
the
quantity
of
HAP
emissions
from
individual
or
groups
of
emissions
points.
We
determined
that
establishing
the
entire
plant
as
the
affected
source
does
not
take
into
account
differences
in
the
quantity
and
types
of
HAP
emitted
by
different
processing
operations.
We
also
determined
that
establishing
each
individual
emission
point
as
the
affected
source
does
not
take
advantage
of
similarities
among
certain
processing
operations.
We
concluded
that
the
most
appropriate
approach
is
to
designate
the
group
of
emission
points
associated
with
each
major
process
area
as
an
affected
source.
The
resulting
affected
sources
are
ore
crushing
and
handling
operations,
each
indurating
furnace,
finished
pellet
handling
operations,
and
each
ore
dryer.
As
previously
mentioned,
the
term
affected
source
is
used
primarily
as
a
means
of
specifying
what
equipment
or
activities
would
be
affected
by
the
proposed
standards.
In
addition,
the
term
affected
source
serves
to
define
where
new
source
MACT
applies.
Specifically,
the
General
Provisions
of
40
CFR
part
63
define
the
terms
``
construction''
and
``
reconstruction''
with
reference
to
the
term
affected
source
and
provide
that
new
source
MACT
applies
when
construction
and
reconstruction
occur.
When
establishing
the
affected
sources
for
these
proposed
standards,
we
recognized
that
selecting
a
narrow
definition
of
affected
source
(
e.
g.,
each
crusher,
conveyor,
and
bin)
would
cause
new
source
MACT
requirements
to
be
triggered
more
frequently
than
if
the
affected
source
were
defined
as
a
collection
of
equipment
(
e.
g.,
all
ore
crushing
and
handling
emission
units).
We
do
not
believe
that
the
replacement
of
an
individual
emission
unit
that
is
part
of
a
larger
integrated
process
should
trigger
new
source
MACT.
Therefore,
we
established
affected
sources
for
ore
crushing
and
handling
and
finished
pellet
handling
that
represent
collections
of
equipment,
rather
than
individual
units.
During
the
development
of
the
affected
source
definitions,
we
considered
combining
the
two
affected
sources
into
one
due
to
similarities
in
emission
characteristics
and
controls.
However,
we
decided
not
to
do
so
due
to
differences
in
the
physical
location
and
organization
of
the
units.
Specifically,
ore
crushing
handling
units
are
located
upstream
of
the
indurating
furnace,
and
the
finished
pellet
handling
units
are
located
downstream
of
the
indurating
furnace.
As
a
result,
the
grouping
of
units
that
comprised
the
affected
sources
are
typically
located
in
different
buildings
at
different
parts
of
the
plant.
In
addition,
ore
crushing
handling
units
are
organized
with
respect
to
the
crushing
lines,
whereas
finished
pellet
handling
units
are
organized
with
respect
to
the
indurating
furnace
lines.
The
ore
crushing
and
handling
affected
source
consists
of
the
collection
of
equipment
and
operations
needed
to
produce
crushed
ore
suitable
for
processing
into
green
pellets.
Emission
units
include
ore
crushers
(
primary,
secondary,
and
tertiary),
screens,
conveyors,
storage
bins,
and
transfer
points.
The
ore
crushing
and
handling
affected
source
begins
where
crude
taconite
iron
ore
is
dumped
into
the
primary
crusher
and
ends
where
the
unfired
(
green)
pellets
enter
the
indurating
furnace.
We
grouped
all
of
these
emission
units
into
the
one
affected
source
based
on
their
functional
relationship,
the
similarity
of
their
HAP
emission
characteristics,
and
the
considerations
for
new
source
MACT
stated
above.
The
only
HAP
emitted
from
these
units
are
metallic
HAP,
primarily
manganese.
We
compared
the
outlet
PM
concentrations
for
the
different
types
of
emission
units
(
i.
e.,
crushers,
conveyors,
bins,
screens,
and
transfer
points)
and
crushing
stage
(
primary,
secondary,
and
tertiary)
and
observed
no
discernable
difference
in
emissions.
In
addition,
grouping
all
the
ore
crushing
and
handling
emission
units
into
one
affected
source
will
allow
sources
more
flexibility
in
developing
control
strategies
for
achieving
compliance.
All
wet
process
operations,
including
wet
milling,
magnetic
separation,
hydraulic
separation,
chemical
flotation,
and
concentrate
thickening
in
the
concentrator
area,
and
vacuum
disk
filters
and
balling
drums
in
the
pelletizing
area,
are
excluded
from
the
rule
because
the
water
effectively
suppresses
all
emissions
from
these
operations.
Operations
associated
with
the
handling
of
limestone/
dolomite
and
bentonite
are
also
excluded
since
they
produce
no
HAP
emissions.
The
finished
pellet
handling
affected
source
consists
of
the
following
emission
units:
conveyors,
storage
bins,
screens,
and
transfer
points.
The
finished
pellet
handling
affected
source
begins
at
the
indurating
furnace
discharge
and
ends
where
the
finished
pellets
are
stockpiled.
We
grouped
all
of
these
emission
units
into
the
finished
pellet
handling
affected
source
based
on
the
similarity
of
their
HAP
emission
characteristics
and
process
equipment
type.
The
only
HAP
emitted
by
these
units
are
metallic
HAP,
primarily
manganese.
We
compared
the
outlet
PM
concentrations
for
the
different
types
of
emission
units
(
i.
e.,
conveyors,
bins,
screens,
and
transfer
points)
and
observed
no
discernable
difference
in
emissions.
Therefore,
we
do
not
believe
that
subcategorization
of
the
finished
pellet
handling
affected
source
is
warranted.
Unlike
the
ore
crushing
and
handling
and
finished
pellet
handling
affected
sources,
we
have
selected
a
narrower
definition
of
affected
source
for
indurating
furnaces
by
defining
the
affected
source
as
each
individual
furnace,
rather
than
the
collection
of
indurating
furnaces
at
a
particular
plant.
We
defined
each
indurating
furnace
as
a
separate
affected
source
because
furnaces
are
independent
emission
units.
As
independent
emission
units,
each
indurating
furnace
has
it
own
dedicated
emission
controls.
In
contrast,
emissions
from
several
ore
crushing
and
handling
and
finished
pellet
handling
process
units
are
often
combined
and
vented
to
a
shared
control
device.
In
addition,
since
the
indurating
furnaces
are
the
most
significant
source
of
HAP
emissions,
we
wanted
all
new
indurating
furnaces
to
be
subject
to
new
source
MACT.
The
indurating
furnace
affected
source
includes
any
furnace,
including
both
straight
grate
and
grate
kiln
designs,
in
which
green
pellets
are
hardened
by
firing
to
a
high
temperature
of
between
2,200
to
2,500
°
F.
The
indurating
furnace
begins
at
the
point
where
the
grate
feed
conveyor
discharges
green
pellets
onto
the
furnace
traveling
grate
and
ends
where
the
hardened
pellets
exit
the
finished
pellet
cooler.
Unlike
ore
crushing
and
handling
and
finished
pellet
handling
units,
indurating
furnaces
are
combustion
sources,
and
as
such,
emit
substantially
more
HAP.
In
addition
to
emitting
metallic
HAP,
indurating
furnaces
emit
acid
gases
(
HCl
and
HF)
and
products
of
incomplete
combustion
(
primarily
formaldehyde).
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Vol.
67,
No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
We
are
establishing
subcategories
within
the
indurating
furnace
affected
source
to
distinguish
between
the
two
types
of
furnace
designs
grate
kiln
and
straight
grate.
We
have
determined
that
grate
kiln
furnaces
are
higher
emitting
sources
than
straight
grate
furnaces
due
to
physical
and
operational
differences
that
affect
emissions
and
the
controllability
of
emissions.
First,
the
grate
kiln
furnaces
are
larger
than
straight
grate
units
with
annual
production
rates
approximately
30
percent
higher
than
that
of
the
straight
grate
furnaces.
Second,
the
grate
kiln
furnaces
are
composed
of
two
furnace
sections,
a
continuous
grate
followed
by
a
rotary
kiln,
while
the
straight
grate
furnaces
include
only
a
continuous
grate.
In
the
grate
kiln,
the
pellets
drop
off
a
conveyor
into
the
kiln
and
then
tumble
in
the
kiln
as
it
rotates.
As
a
result,
there
is
substantially
more
disturbance
of
the
pellets
in
the
grate
kiln
furnace
which
contributes
to
an
increase
in
pellet
breakage
and
in
the
entrainment
of
particles
in
the
air
stream
and
causing
higher
PM
loadings
and
HAP
emissions.
In
addition,
the
average
volume
of
air
flowing
through
a
grate
kiln
furnace
is
more
than
twice
the
average
volume
of
air
flowing
through
a
straight
grate
furnace.
The
greater
air
flow
in
grate
kilns
causes
more
entrainment
of
particles
in
the
air
stream,
causing
higher
exhaust
gas
PM
loadings
and
HAP
emissions.
Available
test
data
show
that,
when
processing
magnetite
ore,
PM
loadings
for
grate
kilns
are
twice
that
of
straight
grate
furnaces.
Because
grate
kiln
furnaces
and
straight
grate
furnaces
have
unique
physical
and
operational
differences
that
affect
emissions
and
the
controllability
of
emissions,
we
have
subcategorized
based
on
furnace
type.
We
have
also
concluded
that,
within
the
grate
kiln
furnace
subcategory,
higher
PM
emissions
are
observed
when
hematite
ore
is
processed
rather
than
magnetite
ore.
For
example,
PM
emissions
for
one
furnace
were
measured
at
0.004
gr/
dscf
when
the
furnace
was
processing
magnetite.
When
the
same
furnace
was
processing
hematite,
the
PM
emissions
were
measured
at
0.018
gr/
dscf.
Contributing
factors
to
the
higher
emissions
include
the
fact
that
the
hematite
ore
pellets
are
finer
grained
and
subject
to
a
higher
breakage
rate.
As
a
result
of
the
higher
inlet
PM
loading,
the
controlled
outlet
PM
emissions
are
higher
when
processing
hematite
than
when
processing
magnetite.
Therefore,
to
account
for
this
difference
in
emissions,
we
are
making
a
distinction
on
the
basis
of
ore
type
within
grate
kilns.
There
are
only
two
grate
kiln
furnaces
that
process
hematite.
Both
of
these
indurating
furnaces
are
located
at
the
same
plant
in
Michigan.
These
furnaces
process
hematite
approximately
eight
months
of
the
year
and
process
magnetite
the
remainder
of
the
year.
There
are
no
straight
grate
indurating
furnaces
processing
hematite.
Emissions
from
cooler
vent
stacks
are
excluded
from
the
indurating
furnace
affected
source
based
on
the
large
size
of
the
particles
and
the
relatively
low
concentration
of
particulate
emissions.
Test
data
indicate
that
PM
emissions
from
cooler
vent
stacks
are
primarily
coarse
PM
with
80
percent
of
the
PM
larger
than
50
microns
and
only
less
than
1
percent
smaller
than
10
microns.
Uncontrolled
PM
emissions
from
cooler
vent
stacks
are
typically
around
0.04
gr/
dscf.
Cooler
vent
stacks
are
currently
not
controlled
at
any
of
the
existing
taconite
plants.
In
Minnesota,
cooler
vent
stacks
are
subject
to
the
State's
requirements
that
limit
the
PM
concentrations
based
on
volumetric
flow
rate.
Based
on
typical
volumetric
flow
rates
in
cooler
vent
stacks,
the
Industrial
Process
Equipment
Rule
(
IPER)
limit
values
range
from
0.04
to
0.05
gr/
dscf.
In
Michigan,
cooler
vent
stacks
are
not
recognized
as
emission
points
and
are
not
addressed
in
operating
permits.
Similar
to
the
indurating
furnace
affected
source,
we
have
selected
a
narrow
definition
of
affected
source
for
ore
dryers
by
defining
the
affected
source
as
each
individual
ore
dryer,
rather
than
the
collection
of
ore
dryers
at
a
particular
plant.
We
defined
each
ore
dryer
as
a
separate
affected
source
because
ore
dryers
are
independent
emission
units
with
their
own
dedicated
emission
control
devices.
There
are
only
two
ore
dryers,
and
both
are
located
at
the
same
plant
in
Michigan.
The
concentrate
from
the
Michigan
plant
contains
a
higher
percentage
of
fine
particles
than
other
taconite
operations
and,
therefore,
requires
additional
drying.
The
ore
dryers
are
located
just
upstream
of
the
balling
drum.
Both
dryers
are
rotary
designs
that
tumble
the
wet
taconite
ore
concentrate
through
a
heated
air
stream
to
reduce
the
amount
of
entrained
moisture
in
the
taconite
ore
concentrate.
B.
How
Did
We
Select
the
Pollutants?
Pollutants
emitted
by
plants
in
the
taconite
iron
ore
processing
source
category
include
metallic
HAP
(
primarily
naturally
occurring
compounds
of
manganese,
arsenic,
lead,
nickel,
and
chromium,
and
lesser
quantities
of
mercury),
organic
HAP
resulting
from
incomplete
combustion
(
mainly
formaldehyde),
and
acid
gases
(
hydrochloric
acid
and
hydrofluoric
acid).
Metallic
HAP
are
emitted
from
ore
crushing
and
handling
units,
indurating
furnaces,
finished
pellet
handling
units,
and
ore
dryers.
We
determined
that
it
is
not
practical
to
establish
individual
standards
for
each
metallic
HAP
that
could
be
present
in
the
various
processes
(
e.
g.,
separate
standards
for
manganese
compound
emissions,
separate
standards
for
lead
compound
emissions,
and
so
forth
for
each
metal
compound
group
listed
as
HAP
and
which
potentially
could
be
present).
When
released,
each
of
the
metallic
HAP
compounds,
except
elemental
mercury,
behave
as
PM.
As
a
result,
strong
correlations
exist
between
PM
emissions
and
emissions
of
the
individual
metallic
HAP
compounds.
Control
technologies
used
for
the
reduction
of
PM
emissions
achieve
comparable
levels
of
reduction
of
metallic
HAP
emissions.
Standards
requiring
good
control
of
PM
emissions
will
also
achieve
a
similar
level
of
control
of
metallic
HAP
emissions.
Therefore,
we
are
establishing
standards
for
total
PM
as
a
surrogate
pollutant
for
the
individual
metallic
HAP.
Establishing
separate
standards
for
each
metallic
HAP
would
impose
costly
and
significantly
more
complex
compliance
and
monitoring
requirements.
In
addition,
establishing
separate
standards
for
each
metallic
HAP
would
achieve
little,
if
any,
HAP
emissions
reductions
beyond
what
would
be
achieved
using
the
total
PM
surrogate
pollutant
approach.
Products
of
incomplete
combustion,
such
as
formaldehyde,
are
released
from
indurating
furnaces
at
very
low
concentrations
as
a
result
of
the
burning
of
fuels,
such
as
natural
gas.
Formaldehyde
has
been
measured
through
stack
testing
at
concentrations
that
are
typically
less
than
1
ppm.
Formaldehyde
emissions
are
currently
uncontrolled.
Existing
PM
emission
controls
on
indurating
furnaces
include
ESP
and
wet
scrubbers,
neither
of
which
are
capable
of
controlling
formaldehyde.
In
addition,
since
formaldehyde
emissions
are
produced
as
a
byproduct
of
burning
fuels,
generally
natural
gas,
taconite
plants
cannot
lower
their
formaldehyde
emissions
by
switching
raw
materials
or
changing
fuels.
We
know
of
no
feasible
control
technology
for
reducing
formaldehyde
emissions
at
these
extremely
low
concentrations
and
at
the
exhaust
gas
temperatures
typically
encountered
at
indurating
furnaces.
The
only
known
technology
for
the
control
of
formaldehyde
emissions
at
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/
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18,
2002
/
Proposed
Rules
concentrations
of
less
than
1
ppm
is
thermal
catalytic
oxidation
in
which
formaldehyde
is
contacted
with
a
precious
metal
catalyst
in
the
presence
of
oxygen
and
high
temperature
(
650
to
1,350
°
F)
to
yield
carbon
dioxide
and
water.
Destruction
efficiencies
of
85
to
90
percent
have
been
demonstrated
on
formaldehyde
emissions
contained
in
the
exhaust
gas
from
stationary
combustion
turbines
at
concentrations
in
the
parts
per
billion
range
and
temperatures
of
1,000
°
F
or
higher.
Destruction
efficiencies,
however,
decrease
exponentially
at
reaction
temperatures
below
650
°
F,
down
to
eventually
less
than
10
percent
at
exhaust
gas
temperature
of
300
°
F
or
less,
which
is
typical
of
most
indurating
furnaces.
Accordingly,
the
burning
of
large
quantities
of
additional
fuel,
such
as
natural
gas,
would
be
needed
to
heat
the
exhaust
gases
to
the
desired
temperature,
which
would
generate
additional
quantities
of
carbon
dioxide
(
a
global
warming
gas)
and
nitrogen
oxides
(
an
ozone
precursor).
In
addition,
given
the
large
volume
of
exhaust
gas
to
be
treated,
on
the
order
of
several
hundred
thousand
cubic
feet
per
minute
per
furnace,
and
the
complexity
of
retrofitting
multiple
stacks
with
gas
burners
and
thermal
catalytic
oxidation
units,
the
capital
cost
and
operating
cost
for
control
would
be
enormous.
Since
formaldehyde
emissions
are
currently
uncontrolled,
we
conclude
that
the
MACT
floor
for
formaldehyde
is
no
emissions
reduction.
In
addition,
due
to
the
severe
technical
and
economic
constraints
of
controlling
formaldehyde
at
high
volumetric
flow
rates,
very
low
concentrations
and
relatively
low
temperatures,
we
conclude
that
no
beyond
the
floor
control
is
feasible.
Accordingly,
specific
emission
limitations
for
formaldehyde
are
not
included
in
the
proposed
rule.
Acid
gases
(
hydrochloric
acid
and
hydrofluoric
acid)
are
also
emitted
from
indurating
furnaces
at
very
low
concentrations,
typically
less
than
3
ppm.
Acid
gases
are
formed
in
the
indurating
furnace
due
to
the
presence
of
chlorides
and
fluorides
in
pellet
additives,
such
as
dolomite
and
limestone.
The
taconite
industry
has
not
installed
equipment
to
specifically
control
acid
gases.
The
MACT
floor
for
acid
gases
was
determined
to
be
no
emissions
reduction.
Unlike
formaldehyde,
some
air
pollution
control
devices
currently
used
by
the
industry
to
reduce
PM
emissions
can
achieve
incidental
control
of
acid
gases.
Due
to
the
strong
affinity
of
these
acid
gases
for
water,
control
equipment
that
use
water,
such
as
wet
wall
electrostatic
precipitators
and
wet
scrubbers,
have
the
capability
of
reducing
hydrochloric
acid
and
hydrofluoric
acid
emissions
substantially.
Therefore,
a
specific
emission
limitation
for
acid
gases
is
not
included
in
today's
proposal.
Indurating
furnaces
are
also
a
source
of
mercury
emissions.
Mercury
is
a
naturally
occurring
element
in
the
taconite
ore.
As
the
taconite
pellets
are
heated
in
the
furnace,
the
naturally
occurring
mercury
compounds
are
volatilized.
The
key
factor
affecting
emissions
is
the
mercury
content
of
the
ore.
Currently,
none
of
the
plants
in
this
industry
have
installed
controls
for
mercury
emissions.
We
also
have
not
been
able
to
identify
any
currently
employed
operating
practices
which
effectively
reduce
mercury
emissions.
Since
specific
controls
for
mercury
are
not
currently
present
in
the
industry
and
operating
practices
which
effectively
reduce
mercury
emissions
have
not
been
identified,
the
MACT
floor
for
mercury
was
determined
to
be
no
emissions
reduction.
In
evaluating
potential
above
the
floor
options,
we
were
unable
to
identify
any
viable
control
technologies
or
operating
practices
for
achieving
reductions
in
mercury
emissions
from
indurating
furnaces
at
taconite
iron
ore
plants.
As
a
result,
a
specific
emission
limitation
for
mercury
has
not
been
included
in
the
proposed
rule.
We
will
reevaluate
the
feasibility
of
controlling
mercury
emissions
from
taconite
iron
ore
plants
as
part
of
the
assessment
for
residual
risk
standards.
Due
to
the
nature
of
the
taconite
iron
ore
deposits
on
the
Mesabi
Range
in
Northeast
Minnesota,
there
is
some
potential
for
the
occurrence
of
contaminant
asbestos
in
some
taconite
ore
mining
areas.
Asbestos
is
the
name
applied
to
a
group
of
six
different
minerals
that
occur
naturally
in
the
environment.
These
minerals
are
made
up
of
long
thin
fibers
similar
to
fiberglass.
The
concern
is
mainly
limited
to
two
taconite
plants
located
at
the
eastern
end
of
the
Mesabi
Range
where
acicular
(
needle
like)
minerals
may
be
present
in
the
ore.
Asbestos
emissions
are
currently
regulated
under
NESHAP
promulgated
in
April
1984
(
40
CFR
part
61,
subpart
M)
that
regulate
the
milling
of
commercial
asbestos
and
the
manufacturing
and
fabricating
of
asbestos
products.
The
provisions
of
the
NESHAP
also
apply
to
the
demolition
and
renovation
of
buildings
where
asbestos
containing
material
is
present.
The
NESHAP
do
not
apply
to
ore
or
other
mineral
processing
operations
that
may
contain
asbestos
as
a
contaminant.
A
work
group
within
EPA
is
currently
studying
the
complex
issues
involved
with
asbestos
emissions
from
beneficiation
and
subsequent
processing
of
minerals
where
asbestos
may
be
present
as
a
contaminant.
That
study
was
initiated
in
response
to
the
events
surrounding
exposures
of
citizens
to
asbestos
which
occurred
as
a
contaminant
in
a
vermiculite
mine
in
Libby,
Montana.
The
work
group
has
developed
an
action
plan
which
identifies
steps
necessary
to
gather
the
information
that
EPA
needs
to
decide
whether
regulations
for
sources
of
contaminant
asbestos
are
warranted.
The
work
group
has
targeted
vermiculite
mining
and
processing
operations
as
the
first
priority
in
the
study.
The
work
group
also
plans
to
study
asbestos
that
occurs
as
a
contaminant
from
other
mining
and
processing
operations,
including
taconite
ore
mining
and
processing.
Decisions
on
whether
to
regulate
asbestos
that
occurs
as
a
contaminant
in
taconite
ore
mining
and
processing
and
other
potential
industries
will
be
based
on
information
gathered
in
the
study.
C.
How
Did
We
Determine
the
Bases
and
Levels
of
the
Proposed
Standards?
We
have
taken
alternative
approaches
to
establishing
the
MACT
floor,
depending
on
the
type,
quality,
and
applicability
of
available
data.
The
three
approaches
most
commonly
used
involve
reliance
on
the
following:
State
and
Federal
regulations
or
permit
limits,
source
test
data
that
characterize
actual
emissions,
and
use
of
a
technology
floor
with
an
accompanying
demonstrated
achievable
emission
level
that
accounts
for
process
and/
or
air
pollution
control
device
variability.
We
evaluated
each
of
these
MACT
floor
approaches
when
developing
the
MACT
floor
for
each
of
the
four
affected
sources:
Ore
crushing
and
handling,
indurating
furnaces,
finished
pellet
handling,
and
ore
dryers.
As
previously
discussed
in
this
preamble,
we
are
establishing
standards
for
total
PM
as
a
surrogate
pollutant
for
individual
metallic
HAP
compounds.
1.
Ore
Crushing
and
Handling
and
Finished
Pellet
Handling
Although
ore
crushing
handling
and
finished
pellet
handling
are
defined
as
separate
affected
sources,
we
combined
the
available
test
data
on
both
sources
for
the
MACT
floor
and
MACT
analyses.
This
is
consistent
with
our
usual
practice
in
developing
MACT
standards
in
organizing,
as
appropriate,
the
available
information
for
similar
HAPemitting
equipment
into
related
groups
for
the
purpose
of
determining
MACT
floors
and
MACT;
yet,
as
appropriate,
maintaining
separate
affected
source
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Vol.
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No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
definitions
for
the
purpose
of
defining
the
applicability
of
relevant
standards.
We
identified
264
emission
units
within
the
ore
crushing
and
handling
affected
source
and
82
emission
units
within
the
finished
pellet
handling
affected
source
at
the
eight
taconite
plants
(
346
emission
units
total).
Particulate
matter
emissions
from
both
operations
are
controlled
primarily
with
medium
energy
wet
scrubbers
(
i.
e.,
venturi
rod
scrubbers,
impingement
scrubbers,
and
marble
bed
scrubbers).
Baghouses,
low
energy
wet
scrubbers
(
i.
e.,
rotoclones),
multiclones,
and
ESP
are
also
used.
Relative
to
State
and
Federal
regulations
and
permit
conditions,
some
of
the
ore
crushing
and
handling
and
finished
pellet
handling
emission
units
in
Minnesota
are
subject
to
the
new
source
performance
standards
(
NSPS)
for
metallic
mineral
processing
plants
(
40
CFR
part
60,
subpart
LL).
The
NSPS
limit
PM
emissions
from
each
affected
emission
unit
to
0.022
gr/
dscf.
However,
most
of
the
ore
crushing
and
handling
and
finished
pellet
handling
emission
units
in
Minnesota
are
subject
to
the
IPER.
The
Minnesota
IPER
establishes
PM
concentration
emission
limits
as
a
function
of
volumetric
flow.
The
emission
limit
becomes
more
stringent
as
volumetric
flow
increases.
Particulate
matter
emission
limits
for
ore
crushing
and
handling
and
finished
pellet
handling
units
under
the
IPER
range
from
approximately
0.030
gr/
dscf
to
approximately
0.095
gr/
dscf.
Due
to
its
proximity
to
Lake
Superior,
one
of
the
Minnesota
plants
is
subject
to
the
following
more
stringent
limits:
0.002
gr/
dscf
for
tertiary
crushing
and
some
storage/
transfer
points,
0.010
gr/
dscf
for
cobbing
and
some
storage/
transfer
points,
and
0.030
gr/
dscf
for
the
rest
of
the
emission
points.
The
two
taconite
plants
in
Michigan
are
subject
to
a
State
PM
emission
limit
of
0.1
pounds
of
PM
per
1,000
pounds
of
exhaust
gas,
which
equates
to
0.052
gr/
dscf.
The
PM
emissions
tests
data
used
in
the
MACT
analysis
covers
60
emission
units,
which
accounts
for
17
percent
of
the
combined
346
ore
crushing
and
handling
and
finished
pellet
handling
emission
units
in
the
source
category.
Included
are
representative
data
on
all
crushing
stages,
screening
operations,
conveyor
transfer
points,
and
storage
bins,
as
well
as
finished
pellet
screening
operations
and
conveyor
transfer
points.
These
tests
also
cover
the
full
range
of
control
devices
applied
to
both
emission
units.
Each
test
is
composed
of
three,
1
hour
test
runs
expressed
in
PM
concentration
units
of
gr/
dscf.
We
compared
these
60
data
points
on
actual
emissions
to
the
State
and
Federal
emissions
limitations
to
determine
whether
the
limitations
provided
a
reasonably
realistic
representation
of
actual
emissions
and
performance.
Based
on
this
comparison,
it
is
clear
that
actual
PM
emissions
are
considerably
lower
than
the
levels
allowed
by
the
State
emission
limits
and
the
metallic
mineral
processing
NSPS,
and
that
the
State
and
Federal
PM
emission
limits
do
not
realistically
represent
performance
achieved
in
practice
by
the
best
performing
sources.
Test
results
in
the
data
pool
are
on
the
order
of
0.002
to
0.010
gr/
dscf,
which
is
substantially
below
that
generally
allowed
under
the
State
and
Federal
emissions
limitations
cited
above.
We
evaluated
the
test
data
by
process
stage
(
i.
e.,
primary
crushing,
secondary
crushing,
tertiary
crushing,
grate
feed,
and
finished
pellet
handling)
to
determine
whether
PM
emissions
varied
depending
on
process
stage.
We
found
no
discernable
differences
in
the
types
of
controls
or
the
level
of
controlled
PM
emissions
among
the
various
process
stages.
Consequently,
we
concluded
that
distinguishing
among
process
stages
was
unnecessary,
and
that
it
was
feasible
to
establish
one
PM
emission
limit
that
would
apply
to
all
ore
crushing
and
handling
and
finished
pellet
handling
emission
units.
An
underlying
presumption
when
setting
MACT
standards
is
that
all
emission
limitations
must
be
met
or
complied
with
at
all
times.
Consequently,
when
establishing
MACT
floors
and
ultimately
MACT
standards,
we
must
consider
the
long
term
variability
in
performance
expected
to
occur
under
reasonable
worst
case
conditions
or
circumstances.
We
must
assure
that
ensuing
standards
reflect
the
level
of
emissions
control
determined
to
be
MACT.
We
must
also
assure
that
the
standards
are
achievable
under
normal
and
recurring
worst
case
circumstances.
The
MACT
floor
and
the
MACT
level
of
control
were
determined
based
on
each
plant's
flow
weighted
mean
PM
concentration
for
all
emission
units
in
both
affected
sources.
By
averaging
higher
emitting
units
with
lower
emitting
units,
each
plant's
flowweighted
mean
PM
concentration
value
takes
into
account
much
of
the
variability
in
emissions
among
different
units
within
the
two
affected
sources
and
provides
what
we
believe
to
be
a
reasonably
accurate
representation
of
the
overall
level
of
control
that
is
being
achieved
by
those
affected
sources.
We
then
proceeded
to
establish
the
MACT
floor
based
on
the
pool
of
credible
data
available
to
us
for
each
plant.
Of
the
eight
existing
taconite
iron
ore
plants,
three
plants
were
excluded
from
the
floor
analysis
due
to
a
lack
of
sufficient
test
data.
One
of
the
plants
had
no
PM
emissions
test
data
whatsoever,
and
the
other
two
plants
had
only
two
tested
units
each.
Each
of
the
remaining
five
plants
had
emissions
test
data
for
6
to
21
units.
The
first
step
in
the
MACT
floor
analysis
was
to
calculate
a
flowweighted
mean
PM
concentration
value
(
in
gr/
dscf)
for
each
of
the
five
plants
using
the
available
PM
emissions
data
for
the
ore
crushing
and
handling
and
finished
pellet
handling
units
at
each
plant.
For
each
unit
with
a
PM
emissions
test,
the
total
grains
of
PM
emitted
during
the
test
was
calculated
by
multiplying
the
test
average
in
gr/
dscf
by
the
test
average
flow
rate
in
dscf.
Then,
for
each
plant,
the
grains
of
PM
emitted
by
all
the
tested
units
at
that
plant
were
totaled.
The
total
grains
emitted
were
then
divided
by
the
total
air
flow
for
the
tested
units
(
in
dscf)
to
obtain
the
flow
weighted
mean
PM
concentration
in
gr/
dscf.
The
flowweighted
mean
PM
concentration
values
(
in
gr/
dscf)
for
each
of
the
five
plants
were
0.0047,
0.0050,
0.0059,
0.0114
and
0.0116.
The
resulting
MACT
floor
for
the
ore
crushing
and
handling
and
finished
pellet
handling
affected
sources
as
determined
using
the
flow
weighted
mean
PM
concentration
for
the
five
plants
is
0.008
gr/
dscf.
We
then
examined
a
beyond
the
floor
alternative.
The
next
increment
of
control
beyond
the
floor
is
the
installation
of
impingement
scrubbers
capable
of
meeting
a
concentration
limit
of
0.005
gr/
dscf,
which
is
equivalent
to
the
level
of
control
we
anticipate
requiring
for
new
sources.
We
estimate
the
additional
capital
cost
of
replacing
existing
controls
with
new
impingement
scrubbers
performing
at
a
level
of
0.005
gr/
dscf
to
be
$
3.5
million
and
the
total
annual
cost
to
be
$
653,000
per
year.
We
estimate
the
corresponding
incremental
reduction
in
HAP
metals
achieved
by
reducing
the
PM
concentration
from
0.008
to
0.005
gr/
dscf
to
be
0.37
tons.
The
cost
per
ton
of
HAP
is
$
1.7
million.
The
energy
increase
would
be
expected
to
be
2,870
mega
watt
hours
per
year,
primarily
due
to
the
energy
requirements
of
new
scrubbers.
We
believe
that
the
high
cost,
coupled
with
the
small
reduction
in
HAP
emissions,
does
not
justify
this
beyond
the
floor
alternative
at
this
time.
We
could
not
identify
any
other
beyond
the
floor
alternatives.
Consequently,
we
chose
the
floor
level
of
control
of
0.008
gr/
dscf
as
MACT.
For
new
ore
crushing
and
handling
and
new
finished
pellet
handling
affected
sources,
we
are
selecting
a
PM
outlet
concentration
of
0.005
gr/
dscf
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Wednesday,
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2002
/
Proposed
Rules
new
source
MACT.
The
0.005
gr/
dscf
level
corresponds
to
the
best
performing
source
(
plant)
with
the
lowest
flowweighted
mean
PM
concentration.
2.
Indurating
Furnaces
Processing
Magnetite
There
are
21
indurating
furnaces
at
the
eight
operating
taconite
plants.
Fourteen
of
the
furnaces
are
grate
kiln
designs
and
seven
are
straight
grate
designs.
As
discussed
previously
in
this
preamble,
we
are
establishing
subcategories
within
the
indurating
furnace
affected
source
to
accommodate
differences
in
the
two
furnace
designs.
We
have
determined
that
these
furnace
design
types
have
unique
physical
and
operational
differences
which
warrant
their
separation
into
two
subcategories.
We
are
also
differentiating
the
grate
kiln
furnaces
based
on
type
of
ore
processed
(
i.
e.,
hematite
versus
magnetite
ore).
We
evaluated
the
existing
State
PM
emission
limitations
as
an
option
for
establishing
the
MACT
floor.
However,
a
comparison
of
the
State
limits
with
data
on
actual
PM
emissions
shows
that
the
State
limits
are
generally
much
more
lenient
than
the
actual
emissions
and,
as
such,
are
not
appropriate
for
establishing
the
MACT
floor.
Most
of
the
indurating
furnaces
in
Minnesota
are
subject
to
the
State's
IPER.
Particulate
matter
emission
limits
for
indurating
furnaces
under
the
IPER
range
from
0.025
to
0.05
gr/
dscf.
Due
to
its
proximity
to
Lake
Superior,
one
of
the
Minnesota
plants,
which
operates
straight
grate
furnaces,
is
subject
to
a
more
stringent
State
limit
of
0.01
gr/
dscf.
The
two
Michigan
plants,
both
of
which
operate
grate
kiln
furnaces,
are
subject
to
State
PM
emission
limits
also
based
on
air
flow
rates.
One
plant
which
operates
two
furnaces
has
a
PM
emission
limit
of
0.065
pounds
of
PM
per
1,000
pounds
of
exhaust
gas,
which
equates
to
0.04
gr/
dscf.
The
other
plant
which
operates
four
grate
kilns
has
a
PM
emission
limit
of
0.10
pounds
of
PM
per
1,000
pounds
of
exhaust
gas
for
two
larger
kilns,
and
0.15
pounds
of
PM
per
1,000
pounds
of
exhaust
gas
for
two
smaller
kilns.
The
two
emission
limits
equate
to
0.06
to
0.09
gr/
dscf,
respectively.
By
contrast,
the
available
information
on
actual
PM
emissions
for
19
of
21
furnaces
for
which
we
have
emissions
test
data
indicate
that
the
actual
emissions
are
considerably
lower
than
the
levels
allowed
under
the
State
limits.
The
average
concentration
of
actual
emissions
measured
from
all
19
furnaces
when
processing
magnetite
range
from
0.005
to
0.02
gr/
dscf,
which
is
about
5
times
lower
than
the
typical
State
limit.
Therefore,
we
concluded
that
the
State
PM
emission
limits
and
permit
conditions
do
not
realistically
represent
the
emission
levels
actually
achieved
in
practice
by
the
best
performing
sources.
We
next
examined
the
available
emissions
data
to
determine
if
the
MACT
floor
could
be
based
on
actual
emissions.
We
have
credible
PM
test
data
for
six
of
the
seven
straight
grate
furnaces
and
thirteen
of
the
fourteen
grate
kiln
furnaces.
The
test
data
for
each
furnace
consists
of
a
test
for
each
furnace
stack,
with
multiple
tests
for
furnaces
that
discharge
through
more
than
one
stack.
Each
test
consists
of
three
1
hour
test
runs
expressed
in
gr/
dscf.
For
the
furnaces
with
multiple
stacks,
the
PM
emissions
from
each
indurating
furnace
were
calculated
as
the
flow
weighted
mean
concentration
of
PM
emissions
from
all
stacks.
Given
the
amount
and
quality
of
available
PM
emissions
test
data,
we
conclude
that
the
available
information
on
actual
emissions
is
more
than
adequate
for
the
purpose
of
determining
the
requisite
MACT
floors
for
new
and
existing
sources.
As
a
first
step
in
our
MACT
floor
and
MACT
analysis
for
indurating
furnaces,
we
initially
explored
the
appropriateness
of
using
a
plantwide
average
approach
similar
to
that
used
for
ore
crushing
and
handling
and
finished
pellet
handling.
After
an
assessment
of
the
available
test
data,
we
determined
that
the
plantwide
average
approach
was
not
feasible
due
to
insufficient
data,
and
that
an
alternative
approach
that
focuses
on
individual
furnace
emissions
rather
than
plantwide
emissions
is
more
suitable.
For
plants
using
grate
kiln
furnaces,
we
have
sufficient
test
data
to
calculate
a
plantwide
value
for
only
three
of
the
five
plants.
For
plants
using
straight
grate
furnaces,
we
have
sufficient
test
data
to
calculate
a
plantwide
value
for
only
two
of
the
three
plants.
Therefore,
due
to
a
lack
of
test
data
on
some
furnaces,
it
is
not
possible
to
use
a
plantwide
approach
to
determine
the
MACT
floor
for
indurating
furnaces.
As
an
alternative
approach,
we
treated
each
of
the
21
indurating
furnaces
as
separate
emission
units.
As
a
first
step,
we
looked
at
all
furnaces
(
straight
grate
and
grate
kiln)
with
multiple
PM
emissions
tests
to
account
for
the
variability
inherent
in
the
performance
tests.
There
are
12
grate
kiln
furnaces
and
three
straight
grate
furnaces
for
which
there
were
two
or
more
emissions
tests.
To
quantify
the
variability
between
tests
for
each
of
these
furnaces,
we
calculated
a
relative
standard
deviation
(
RSD)
for
each
furnace.
The
RSD
is
calculated
by
dividing
the
standard
deviation
of
the
data
by
the
mean
of
the
data
and
multiplying
the
result
by
100.
The
RSD
provides
a
measure
of
the
variability
of
the
PM
test
data
for
each
furnace
relative
to
the
mean
of
the
PM
test
data
for
each
furnace.
The
RSD
is
expressed
as
a
percentage
for
each
furnace,
and
these
percentages
were
then
compared
between
furnaces.
The
variability
between
tests
for
a
given
indurating
furnace
is
due
to
normal
variability
in
process
operation
and
control
device
performance,
as
well
as
measurement
error.
These
factors
affect
all
furnaces
similarly,
and
their
affect
on
emissions
is
largely
independent
of
furnace
type
and
ore
type.
Therefore,
we
looked
at
the
range
of
RSD
values
for
all
furnaces
together
(
grate
kilns
and
straight
grates)
when
determining
the
overall
variability.
The
RSD
for
the
15
furnaces
with
multiple
test
data
ranged
from
9
to
112
percent
and
averaged
37
percent.
This
indicates
that
on
average,
the
PM
emissions
tests
for
each
furnace
are
within
plus
or
minus
37
percent
of
the
mean
of
the
emissions
tests.
We
then
applied
the
average
RSD
of
37
percent
to
each
emission
test
to
include
a
measure
of
variability
to
each
test.
Next,
we
assigned
a
level
of
performance
to
each
of
the
19
furnaces
for
which
we
have
actual
emissions
data.
For
furnaces
for
which
we
have
two
or
more
tests,
we
chose
the
higher
of
the
test
results
as
the
representative
value
of
performance
for
that
furnace.
We
believe
that
selecting
the
higher
of
the
test
results
provides
more
assurance
that
the
inherent
operational
variability
is
fully
accounted
for
in
the
selection
of
the
representative
value.
For
furnaces
for
which
we
have
only
one
test,
we
used
that
single
test
result
as
the
assigned
value
of
performance.
Since
there
are
fewer
than
30
sources
in
the
straight
grate
and
grate
kiln
indurating
furnace
subcategories,
the
MACT
floors
were
determined
using
the
best
five
performing
sources.
Each
indurating
furnace
was
then
ranked
within
its
subcategory
according
to
its
flow
weighted
mean
concentration
of
PM
emissions
after
application
of
the
RSD
adjustment
for
variability.
The
five
furnaces
in
each
subcategory
with
the
lowest
adjusted
PM
concentration
were
identified
as
the
best
performing
sources.
The
MACT
floor
was
then
determined
as
the
mean
PM
concentration
value
for
the
five
best
performing
sources.
The
adjusted
PM
concentration
values
for
the
five
best
performing
straight
grate
furnaces
were
0.0083,
0.0090,
0.0093,
0.0105,
and
0.0126.
The
mean
of
the
five
best
performing
straight
grate
furnaces
was
determined
to
be
0.010
gr/
dscf.
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Federal
Register
/
Vol.
67,
No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
adjusted
PM
concentration
values
for
the
five
best
performing
grate
kiln
furnaces
were
0.0085,
0.0090,
0.0111,
0.0123,
and
0.0123.
The
mean
of
the
five
best
performing
grate
kiln
furnaces
was
determined
to
be
0.011
gr/
dscf.
We
then
examined
a
beyond
the
floor
option.
The
next
increment
of
control
beyond
the
floor
is
the
installation
of
venturi
scrubbers
or
dry
ESP
capable
of
meeting
a
concentration
limit
of
0.006
gr/
dscf,
which
is
equivalent
to
the
level
of
control
required
for
new
straight
grate
furnaces
and
new
grate
kiln
furnaces.
For
straight
grate
furnaces,
we
estimate
the
additional
capital
cost
of
going
from
a
level
of
0.010
gr/
dscf
to
a
level
of
0.006
gr/
dscf
to
be
$
71.2
million
and
the
total
annual
cost
to
be
$
11.4
million
per
year.
We
estimate
the
corresponding
additional
reduction
in
HAP
achieved
from
straight
grate
furnaces
to
be
30
tons.
The
cost
per
ton
of
HAP
for
straight
grate
furnaces
is
$
379,000/
ton.
The
energy
increase
would
be
expected
to
be
17,139
mega
watt
hours
per
year,
primarily
due
to
the
energy
requirements
of
new
wet
scrubbers
and
dry
ESP.
For
grate
kiln
furnaces,
we
estimate
the
additional
capital
cost
of
going
from
a
level
of
0.011
gr/
dscf
to
a
level
of
0.006
gr/
dscf
to
be
$
28.5
million
and
the
total
annual
cost
to
be
$
5.3
million
per
year.
We
estimate
the
corresponding
additional
reduction
in
HAP
achieved
from
grate
kilns
to
be
12.8
tons.
The
cost
per
ton
of
HAP
for
grate
kiln
furnaces
is
$
414,000/
ton.
The
energy
increase
would
be
expected
to
be
36,297
mega
watt
hours
per
year,
primarily
due
to
the
energy
requirements
of
new
wet
scrubbers
and
dry
ESP.
We
believe
that
the
high
cost,
coupled
with
the
small
reduction
in
HAP
emissions,
does
not
justify
this
beyond
the
floor
alternative
for
either
furnace
subcategory.
We
could
not
identify
any
other
beyond
the
floor
alternatives.
Consequently,
we
chose
the
MACT
floor
levels
of
control
of
0.010
gr/
dscf
for
straight
grate
furnaces
and
0.011
gr/
dscf
for
grate
kiln
furnaces
as
MACT
for
existing
indurating
furnace.
For
the
new
source
MACT
analysis,
we
did
not
adjust
the
PM
emissions
test
results
for
variability.
We
believe
that
a
variability
adjustment
is
not
necessary
because
new
emission
controls
can
be
engineered
to
account
for
variability
in
process
operation
and
control
device
performance,
as
well
as
measurement
error.
We
ranked
the
representative
PM
concentrations
for
each
straight
grate
furnace
and
for
each
grate
kiln
furnace
from
the
lowest
to
the
highest
values.
We
selected
the
furnace
with
the
lowest
PM
outlet
concentration
of
0.006
gr/
dscf
as
new
source
MACT
for
new
straight
grate
indurating
furnaces.
We
believe
that
this
furnace,
which
is
controlled
by
a
venturi
scrubber,
represents
the
best
controlled
similar
source
among
the
seven
operating
straight
grate
furnaces.
We
selected
the
furnace
with
the
lowest
PM
outlet
concentration
of
0.006
gr/
dscf
as
the
new
source
MACT
for
new
grate
kiln
indurating
furnaces
processing
magnetite.
We
believe
that
this
furnace,
which
is
controlled
by
a
dry
ESP,
represents
the
best
controlled
similar
source
among
the
14
operating
grate
kiln
furnaces.
3.
Indurating
Furnaces
Processing
Hematite
There
are
two
indurating
furnaces
that
process
hematite
ore.
Both
furnaces
are
grate
kiln
designs
and
are
located
at
the
same
plant
in
Michigan.
Hematite
is
processed
approximately
8
months
of
the
year
and
magnetite
is
processed
the
remainder
of
the
year.
Both
furnaces
are
similar
in
design,
size,
operating
conditions
and
air
pollution
control.
Each
furnace
is
of
the
grate
kiln
design,
which
consists
of
a
continuous
traveling
grate
followed
by
a
rotary
kiln.
The
two
kilns
are
both
25
feet
in
diameter
and
160
feet
long
and
have
similar
production
rates.
Exhaust
gases
from
each
furnace
are
controlled
by
three
ESP,
three
dry
units
on
one
furnace
and
one
wet
and
two
dry
units
on
the
other
furnace.
All
corresponding
ESP
for
each
furnace
have
similar
configurations,
including
number
of
chambers
and
fields,
and
collection
area;
and
similar
operating
conditions,
including
volumetric
air
flow,
gas
inlet
temperature,
primary
and
secondary
currents,
and
primary
and
secondary
voltages.
We
evaluated
the
existing
State
PM
emission
limitations
as
an
option
for
establishing
the
MACT
floor.
However,
a
comparison
of
the
State
limit
with
data
on
actual
PM
emissions
shows
that
the
State
limit
is
much
more
lenient
than
the
actual
emissions
and,
as
such,
is
not
appropriate
for
establishing
the
MACT
floor.
Both
furnaces
are
subject
to
Michigan's
PM
emission
limit
of
0.065
pounds
of
particulate
per
1,000
pounds
of
exhaust
gas,
which
equates
to
approximately
0.04
gr/
dscf.
In
comparison,
available
information
on
actual
PM
emissions
for
the
two
furnaces
indicate
that
the
actual
emissions
are
considerably
lower
than
the
levels
allowed
under
the
State
limit.
The
average
concentration
of
actual
emissions
measured
from
the
two
furnaces
when
processing
hematite
range
from
0.017
to
0.018
gr/
dscf,
which
is
about
half
the
State
limit.
Therefore,
we
concluded
that
the
State
PM
emission
limit
does
not
realistically
represent
the
emission
levels
actually
achieved
in
practice
by
the
two
furnaces
when
processing
hematite.
We
next
examined
the
available
emissions
data
to
determine
if
the
MACT
floor
could
be
based
on
actual
emissions.
We
have
credible
PM
test
data
for
both
furnaces
while
processing
hematite.
The
test
data
for
each
furnace
consists
of
a
PM
test
of
each
furnace
stack
(
three
tests
per
furnace).
Each
test
consists
of
three
1
hour
test
runs.
The
PM
emissions
from
each
furnace
were
calculated
as
the
flow
weighted
mean
concentration
of
PM
emissions
in
gr/
dscf
from
all
stacks.
We
believe
that
this
available
information
on
actual
emissions
is
adequate
for
the
purpose
of
determining
the
requisite
MACT
floors
for
new
and
existing
sources.
A
variability
analysis
for
furnaces
processing
hematite
could
not
be
conducted
because
multiple
valid
PM
emissions
tests
are
not
available
for
these
furnaces.
As
a
result,
we
relied
on
the
RSD
adjustment
used
when
processing
magnetite
to
account
for
process,
control
device,
and
measurement
variability.
As
noted
previously,
these
factors
affect
all
furnaces
similarly,
and
their
affect
on
emissions
is
largely
independent
of
furnace
type
and
ore
type.
Therefore,
we
believe
it
is
appropriate
to
apply
the
RSD
calculated
for
furnaces
processing
magnetite
to
furnaces
processing
hematite.
Since
there
are
only
two
indurating
furnaces
processing
hematite,
and
these
furnaces
are
ostensibly
identical
in
design,
size,
operation
and
emissions
control,
we
selected
the
MACT
floor
based
on
the
higher
of
the
two
PM
concentration
values
(
0.023
and
0.025
gr/
dscf)
after
application
of
the
RSD
adjustment
for
variability.
The
resulting
MACT
floor
for
existing
grate
kiln
indurating
furnaces
processing
hematite
is
0.025
gr/
dscf.
We
then
examined
a
beyond
the
floor
alternative.
The
next
increment
of
control
beyond
the
floor
is
the
installation
of
a
dry
ESP
capable
of
consistently
meeting
a
concentration
limit
of
0.018
gr/
dscf,
which
is
equivalent
to
the
level
of
control
required
for
new
grate
kiln
furnaces
processing
hematite.
We
estimate
the
additional
capital
cost
of
going
from
a
level
of
0.025
gr/
dscf
to
a
level
of
0.018
gr/
dscf
to
be
$
25.9
million
and
the
total
annual
cost
to
be
$
4.9
million
per
year.
We
estimate
the
corresponding
additional
reduction
in
HAP
achieved
from
grate
kiln
furnaces
processing
hematite
to
be
0.3
tons.
The
cost
per
ton
of
HAP
for
grate
kiln
furnaces
processing
hematite
is
$
19.6
million/
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ton.
The
energy
increase
would
be
expected
to
be
34,898
mega
watt
hours
per
year,
primarily
due
to
the
energy
requirements
of
new
dry
ESP.
We
believe
that
the
high
cost,
coupled
with
the
small
reduction
in
HAP
emissions,
does
not
justify
this
beyond
the
floor
alternative
at
this
time.
We
could
not
identify
any
other
beyond
the
floor
alternatives.
Consequently,
we
chose
the
MACT
floor
level
of
control
of
0.025
gr/
dscf
as
MACT
for
existing
grate
kiln
furnaces
processing
hematite.
For
the
new
source
MACT
analysis,
we
relied
on
the
same
emission
source
test
data
used
above
in
the
existing
source
MACT
determination.
However,
we
did
not
adjust
the
values
from
the
emissions
tests
with
a
RSD
adjustment
for
the
new
source
MACT
analysis.
We
believe
that
a
variability
adjustment
is
not
necessary
because
new
emission
controls
can
be
engineered
to
account
for
variability
in
process
operation
and
control
device
performance.
As
noted
previously,
both
furnaces
are
ostensibly
identical
in
design,
operation
and
control,
with
measured
PM
emissions
based
on
one
performance
test
per
furnace
of
0.017
and
0.018
gr/
dscf.
Given
the
similarities
between
the
two
furnaces
and
their
demonstrated
performance,
we
selected
a
PM
concentration
of
0.018
gr/
dscf
as
the
new
source
MACT
for
new
grate
kiln
indurating
furnaces
when
processing
hematite.
4.
Ore
Dryers
There
are
only
two
ore
dryers
in
the
source
category.
Both
are
rotary
designs
and
are
located
at
the
same
plant
in
Michigan.
The
first
dryer
measures
10
feet
in
diameter
and
80
feet
in
length
and
has
a
rated
capacity
of
400
tons
per
hour.
It
is
equipped
with
two
cyclones
and
an
impingement
scrubber
in
series
for
PM
control.
The
second
dryer
is
somewhat
larger
measuring
12.5
feet
in
diameter
and
100
feet
in
length
with
a
rated
capacity
of
650
tons
per
hour.
The
exhaust
gas
from
the
second
dryer
is
split
into
two
streams,
with
each
exhaust
stream
controlled
by
two
cyclones
and
an
impingement
scrubber
in
series
and
discharging
through
a
separate
stack.
Both
ore
dryers
are
subject
to
Michigan's
PM
emission
limit
of
0.1
pound
of
particulate
per
1,000
pounds
of
exhaust
gas,
which
equates
to
approximately
0.052
gr/
dscf.
We
have
one
PM
emission
test
for
each
dryer.
Both
dryers
were
tested
in
May
2002
while
processing
hematite.
Tests
were
conducted
at
each
of
the
three
dryer
stacks
and
included
three
1
hour
test
runs
per
stack.
In
the
case
of
the
two
stack
dryer,
the
test
results
were
calculated
on
a
flow
weighted
basis.
The
results,
expressed
in
units
of
PM
concentration,
are
0.017
and
0.040
gr/
dscf
for
the
smaller
and
larger
dryer,
respectively.
We
examined
the
test
conditions
under
which
each
dryer
was
tested
and
have
determined
that
the
smaller
dryer
was
tested
under
conditions
not
representative
of
normal
long
term
operations.
Specifically,
the
dryer
had
been
idle
prior
to
testing
and
brought
back
on
line
solely
for
the
purpose
of
testing
only
2
hours
ahead
of
commencing
the
performance
test,
which
was
3
hours
in
duration.
We
do
not
believe
that
a
warm
up
period
of
only
a
few
hours
is
adequate
to
produce
conditions
representative
of
the
worstcase
circumstance
reasonably
expected
to
occur
under
normal
long
term
operations.
We
have,
therefore,
excluded
these
data
from
further
consideration
in
our
MACT
assessment.
We
evaluated
the
existing
State
PM
emission
limit
as
an
option
for
establishing
the
MACT
floor.
A
comparison
of
the
State
limit
of
0.052
gr/
dscf
with
the
only
credible
data
on
actual
PM
emissions
of
0.040
gr/
dscf
indicates
that
the
State
limit
is
a
reasonable
proxy
of
actual
performance
and,
as
such,
is
appropriate
for
establishing
the
MACT
floor
level.
Consequently,
the
MACT
floor
for
ore
dryers
is
determined
to
be
the
level
of
control
indicated
by
the
existing
State
limit
of
0.052
gr/
dscf.
We
then
examined
a
beyond
the
floor
alternative.
The
next
increment
of
control
beyond
the
floor
is
the
installation
of
venturi
scrubbers
capable
of
meeting
a
concentration
limit
of
0.025
gr/
dscf,
which
is
equivalent
to
the
level
of
control
required
for
new
ore
dryers.
We
estimate
the
additional
capital
cost
of
going
from
a
level
of
0.052
gr/
dscf
to
a
level
of
0.025
gr/
dscf
to
be
$
98,000
and
the
total
annual
cost
to
be
$
256,000
per
year.
We
estimate
the
corresponding
additional
reductions
in
HAP
achieved
from
ore
dryers
to
be
0.32
tons.
The
cost
per
ton
of
HAP
for
ore
dryers
is
$
790,000/
ton.
The
energy
increase
would
be
expected
to
be
3,520
megawatt
hours
per
year,
primarily
due
to
the
energy
requirements
of
new
wet
scrubbers.
We
believe
that
the
high
cost,
coupled
with
the
small
reduction
in
HAP
emissions,
does
not
justify
this
beyond
the
floor
alternative
at
this
time.
We
could
not
identify
any
other
beyond
the
floor
alternatives.
Consequently,
we
chose
the
MACT
floor
level
of
control
of
0.052
gr/
dscf
as
MACT
for
existing
ore
dryers.
For
new
ore
dryers,
we
are
selecting
a
PM
outlet
concentration
of
0.025
gr/
dscf
as
new
source
MACT.
The
0.025
gr/
dscf
level
corresponds
to
the
standard
for
dryers
in
the
NSPS
for
calciners
and
dryers
in
mineral
industries
(
40
CFR
part
60,
subpart
UUU).
The
dryers
used
to
develop
the
NSPS
limit
are
very
similar
to
the
dryers
that
are
used
by
the
taconite
industry.
Specifically,
many
of
the
dryers
studied
in
the
NSPS
were
of
the
rotary
design,
were
controlled
by
wet
scrubbers,
and
processed
material
with
a
particle
size
distribution
similar
to
that
of
taconite
ore.
Therefore,
due
to
these
similarities,
we
believe
that
the
level
of
0.025
gr/
dscf
from
the
NSPS
for
calciners
and
dryers
in
mineral
industries
is
a
reasonable
proxy
of
the
performance
that
can
be
achieved
by
new
ore
dryers
in
the
taconite
industry.
D.
How
Did
We
Select
the
Initial
Compliance
Requirements?
To
demonstrate
initial
compliance
with
the
PM
emission
limit
for
the
ore
crushing
and
handling
affected
source,
the
flow
weighted
mean
concentration
of
PM
emissions
of
all
units
within
the
affected
source
must
not
exceed
the
applicable
PM
emission
limit.
Similarly,
for
the
finished
pellet
handling
affected
source,
the
flow
weighted
mean
concentration
of
PM
emissions
of
all
units
within
the
affected
source
must
not
exceed
the
applicable
PM
emission
limit.
For
both
affected
sources,
emission
units
must
demonstrate
their
performance
through
initial
testing.
The
performance
test
is
to
be
conducted
using
EPA
Method
5
or
17
in
40
CFR
part
60,
appendix
A.
Factors
that
can
affect
the
compatibility
of
the
Method
5
and
Method
17
results
are
stack
temperature,
moisture
and
the
type
and
quantity
of
condensible
material.
Stack
emissions
from
ore
crushing
and
handling
and
finished
pellet
handling
emission
units
are
typically
at
ambient
temperature,
and
are
low
in
moisture
and
condensible
material.
Therefore,
under
the
conditions
encountered
at
taconite
plants
for
both
units,
we
consider
the
results
from
Method
5
and
Method
17
to
be
equivalent.
There
are
a
total
of
346
ore
crushing
and
handling
and
finished
pellet
handling
emission
units
in
the
industry.
Combined,
these
units
account
for
only
1
percent
of
the
total
HAP
emitted
from
the
entire
source
category.
Requiring
an
initial
EPA
Method
5
or
17
PM
test
for
all
346
units
would
cost
approximately
$
1.73
million
($
5,000
per
test).
The
ore
crushing
and
handling
and
finished
pellet
handling
operations
at
most
taconite
iron
ore
processing
plants
consist
of
parallel
lines
of
crushers,
screens,
bins,
and
conveyors.
In
most
cases,
the
parallel
lines
consist
of
nearly
identical
process
units
and
emission
control
equipment.
Therefore,
to
reduce
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the
burden
of
initial
testing,
we
are
allowing
plants
to
group
similar
emission
units
with
similar
control
equipment
together
and
then
conduct
an
initial
performance
test
on
one
or
more
representative
emission
units
within
each
group,
depending
on
the
number
of
similar
units
within
the
group.
To
ensure
consistency
in
the
grouping
of
similar
emission
units,
the
rule
includes
the
following
criteria:
emission
units
must
be
the
same
type
of
process
unit
(
e.
g.,
primary
crushers
are
separate
from
secondary
crushers);
emissions
from
the
units
must
be
controlled
by
the
same
type
of
emission
control
device
(
e.
g.,
impingement
scrubbers
are
separate
from
venturi
scrubbers);
the
difference
in
the
volumetric
flow
rate
among
similar
emission
units
in
dscf
cannot
vary
by
more
than
10
percent;
and
the
difference
in
the
actual
process
throughput
rate
among
similar
emission
units
in
long
tons
per
hour
cannot
vary
by
more
than
10
percent.
Each
plant
must
submit
a
testing
plan
to
the
permitting
authority
for
approval.
The
testing
plan
must
identify
the
emission
units
that
will
be
grouped
as
similar
and
identify
the
representative
unit
that
will
be
tested
for
each
group.
By
allowing
similar
emission
units
to
be
grouped
together,
we
estimate
that
the
total
number
of
emission
units
subjected
to
initial
compliance
testing
would
be
reduced
from
346
to
176
units.
This
would
reduce
the
initial
compliance
burden
by
approximately
half
to
$
880,000.
Even
after
grouping
similar
emission
units,
most
plants
would
still
have
to
test
between
20
and
39
units
(
ore
crushing
and
handling
and
finished
pellet
handling
combined).
We
believe
that
180
days
does
not
allow
sufficient
time
to
schedule
and
test
this
number
of
emission
units.
In
addition,
plants
will
be
conducting
initial
compliance
tests
for
their
indurating
furnaces
at
the
same
time.
Therefore,
to
further
reduce
the
burden
of
initial
compliance
testing
for
both
emission
units,
we
are
allowing
plants
2
years
following
the
compliance
date
to
conduct
all
initial
compliance
tests
for
both
emission
units.
We
believe
that
by
grouping
similar
units
and
allowing
initial
testing
to
be
conducted
within
2
years,
the
initial
compliance
burden
will
be
minimized
while
still
providing
adequate
assurance
of
initial
compliance
with
the
emission
limits.
To
demonstrate
initial
compliance
with
the
PM
emission
limit
for
indurating
furnaces,
the
flow
weighted
mean
concentration
of
PM
emissions
of
all
furnace
stacks
for
each
furnace
must
not
exceed
the
applicable
PM
emission
limit.
Indurating
furnaces
must
demonstrate
their
performance
through
initial
testing.
The
performance
test
is
to
be
conducted
using
EPA
Method
5
or
17
in
40
CFR
part
60,
appendix
A.
As
mentioned
above,
factors
that
can
affect
the
compatibility
of
the
Method
5
and
Method
17
results
are
stack
temperature,
moisture
and
the
type
and
quantity
of
condensible
material.
Stack
emissions
from
indurating
furnaces
typically
range
from
200
to
315
°
F,
with
an
8
to
14
percent
moisture
content,
and
low
concentrations
of
condensible
material.
Under
these
conditions
we
consider
the
results
from
Method
5
and
Method
17
to
be
equivalent.
However,
if
the
stack
temperature
is
above
320
°
F
and
the
furnace
is
burning
a
fuel
other
than
natural
gas,
Method
5
must
be
used
for
the
performance
test.
The
initial
compliance
test
for
each
indurating
furnace
must
be
performed
within
180
calendar
days
of
the
compliance
date.
For
indurating
furnaces
with
multiple
stacks,
all
stacks
for
the
indurating
furnace
must
be
tested
simultaneously.
The
180
day
requirement
is
consistent
with
the
requirements
in
subpart
A
of
40
CFR
part
63.
The
number
of
indurating
furnaces
per
plant
ranges
from
one
to
five,
as
well
as
the
number
of
stacks
per
furnace.
Based
on
the
relatively
small
number
of
indurating
furnaces,
we
believe
that
180
days
allows
sufficient
time
for
plants
to
complete
initial
testing
of
all
indurating
furnaces.
To
demonstrate
initial
compliance
with
the
PM
emission
limit
for
ore
dryers,
the
flow
weighted
mean
concentration
of
PM
emissions
of
all
stacks
for
each
dryer
must
not
exceed
the
applicable
PM
emission
limit.
Ore
dryers
must
demonstrate
their
performance
through
initial
testing.
The
performance
test
is
to
be
conducted
using
EPA
Method
5
or
17
in
40
CFR
part
60,
appendix
A.
The
initial
compliance
test
for
each
ore
dryer
must
be
performed
within
180
calendar
days
of
the
compliance
date.
For
ore
dryers
with
multiple
stacks,
all
stacks
for
the
ore
dryer
must
be
tested
simultaneously.
The
180
day
requirement
is
consistent
with
the
requirements
in
subpart
A
of
40
CFR
part
63.
There
are
only
two
existing
ore
dryers
in
the
source
category.
As
such,
we
conclude
that
180
days
allows
sufficient
time
to
complete
initial
testing.
The
proposed
rule
would
also
require
that
certain
operating
limits
on
control
devices
be
established
during
the
initial
compliance
test
to
ensure
that
control
devices
operate
properly
on
a
continuing
basis.
All
operating
limits
must
be
established
during
a
performance
test
that
demonstrates
compliance
with
the
applicable
emission
limit.
During
the
initial
compliance
tests,
operating
limits
must
be
established
for
pressure
drop
and
scrubber
water
flow
rate
for
all
wet
scrubbers,
and
opacity
(
using
a
COMS)
for
dry
ESP.
E.
How
Did
We
Select
the
Continuous
Compliance
Requirements?
For
continuous
compliance,
we
chose
periodic
performance
testing
for
PM,
which
is
consistent
with
current
permit
requirements.
We
consulted
with
the
two
States
in
which
taconite
ore
processing
plants
are
located
to
determine
how
they
were
implementing
title
V
permitting
requirements
for
performance
tests.
The
requirements
for
the
frequency
and
number
of
performance
tests
for
ore
crushing
and
handling,
and
finished
pellet
handling
and
ore
drying
units
were
determined
to
be
variable
and
highly
site
specific.
Consequently,
for
ore
crushing
and
handling,
and
finished
pellet
handling
and
ore
drying
units,
we
decided
that
the
schedule
for
conducting
subsequent
performance
tests
should
be
based
on
schedules
established
in
each
plant's
title
V
operating
permit.
If
a
title
V
permit
has
not
been
issued,
then
the
plant
must
submit
a
testing
plan
and
schedule
to
the
permitting
authority
for
approval.
For
each
indurating
furnace,
the
proposed
rule
would
require
subsequent
testing
of
all
stacks
based
on
the
schedule
in
each
plant's
title
V
operating
permit,
but
no
less
frequent
than
twice
per
5
year
permit
term.
If
a
title
V
permit
has
not
been
issued,
then
the
plant
must
submit
a
testing
plan
and
schedule
to
the
permitting
authority
for
approval.
The
testing
frequency
in
the
testing
plan
can
be
no
less
frequent
than
twice
per
5
year
period.
Since
the
majority
of
the
HAP
emissions
from
this
source
category
result
from
the
operation
of
indurating
furnaces,
we
believe
that
testing
twice
per
permit
term
is
appropriate.
We
also
developed
procedures
to
ensure
that
control
equipment
are
operating
properly
on
a
continuous
basis.
Baghouses
must
be
equipped
with
a
bag
leak
detection
system.
Wet
scrubbers
must
be
monitored
for
pressure
drop
and
scrubber
water
flow
rate,
and
they
must
not
fall
below
the
parametric
monitoring
limits
established
during
the
performance
test.
Dry
electrostatic
precipitators
must
be
monitored
for
opacity
using
COMS.
The
opacity
must
not
exceed
the
operating
limit
established
during
the
performance
test.
If
a
plant
uses
equipment
other
than
a
baghouse,
scrubber,
or
dry
ESP
to
control
emissions
from
an
affected
source,
the
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/
Vol.
67,
No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
owner
or
operator
is
required
to
send
us
a
monitoring
plan
containing
information
on
the
type
of
device,
performance
test
results,
appropriate
operating
parameters
to
be
monitored,
operating
limits,
and
operation
and
maintenance.
F.
How
Did
We
Select
the
Notification,
Recordkeeping,
and
Reporting
Requirements?
We
selected
the
notification,
recordkeeping,
and
reporting
requirements
that
are
consistent
with
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A).
One
time
notifications
are
required
by
the
EPA
to
identify
which
plants
are
subject
to
the
standards,
if
a
plant
has
complied
with
the
rule
requirements,
and
when
certain
events
such
as
performance
tests
and
performance
evaluations
are
scheduled.
Semiannual
compliance
reports
containing
information
on
any
deviation
from
rule
requirements
are
also
required.
These
reports
would
include
information
on
any
deviation
that
occurred
during
the
reporting
period;
if
no
deviation
occurred,
only
summary
information
(
such
as
a
statement
of
compliance)
is
required.
Consistent
with
the
General
Provisions,
we
also
require
an
immediate
report
of
any
startup,
shutdown,
or
malfunction
where
the
actions
taken
in
response
were
not
consistent
with
the
startup,
shutdown,
and
malfunction
plan.
This
information
is
necessary
to
determine
if
changes
to
the
plan
are
required.
Recordkeeping
requirements
are
limited
to
those
records
that
are
required
to
document
compliance
with
the
proposed
rule.
Recordkeeping
requirements
include:
a
copy
of
each
notification
and
report
submitted
and
all
supporting
documentation;
records
of
startup,
shutdown,
and
malfunction;
records
of
performance
tests,
performance
evaluations,
and
opacity
observations;
and
records
related
to
control
device
performance.
These
notifications,
reports,
and
records
are
the
minimum
required
to
ensure
initial
and
continuous
compliance
with
the
proposed
rule.
IV.
Summary
of
Environmental,
Energy,
and
Economic
Impacts
The
environmental,
energy,
and
economic
impacts
of
the
proposed
rule
are
based
on
the
replacement
of
poor
performing
controls
at
existing
sources
with
new
controls
capable
of
meeting
the
emission
limits
established
in
the
proposed
rule.
We
estimated
no
impacts
for
new
sources
since
we
do
not
project
any
new
or
reconstructed
affected
sources
becoming
subject
to
the
new
source
MACT
requirements
in
the
foreseeable
future.
Specifically,
we
anticipate
that
four
plants
will
install
new
impingement
scrubbers
on
a
total
of
54
out
of
the
264
ore
crushing
and
handling
emission
units
to
meet
the
PM
emission
limit.
We
expect
that
four
plants
will
install
new
venturi
rod
wet
scrubbers
or
will
upgrade
existing
wet
scrubbers
on
at
least
one
of
their
indurating
furnaces.
In
total,
we
estimate
that
the
existing
controls
will
be
replaced
with
new
venturi
rod
wet
scrubbers
on
7
of
the
47
indurating
furnace
stacks.
We
estimate
that
the
existing
controls
will
be
upgraded
with
new
components
on
4
of
the
47
indurating
furnace
stacks.
We
anticipate
that
three
plants
will
install
new
impingement
scrubbers
on
a
total
of
11
out
of
the
82
finished
pellet
handling
units
to
meet
the
finished
pellet
handling
PM
emission
limit.
A.
What
are
the
Air
Emission
Impacts?
The
installation
of
new
controls
and
upgrades
discussed
in
the
preceding
paragraph
will
result
in
reductions
in
emissions
of
metal
HAP,
acid
gases,
and
PM.
Overall,
the
proposed
standards
are
expected
to
reduce
HAP
emissions
by
a
total
of
370
tons/
year,
a
reduction
of
about
40
percent.
Metallic
HAP
emissions
will
be
reduced
by
14
tons/
year
(
a
40
percent
reduction)
and
acid
gas
emissions
(
HCl
and
HF)
will
be
reduced
by
356
tons/
year
(
a
54
percent
reduction).
In
addition,
the
proposed
standards
are
expected
to
reduce
PM
emissions
by
9,438
tons/
year,
a
reduction
of
about
65
percent.
B.
What
Are
the
Cost
Impacts?
The
total
installed
capital
costs
to
the
industry
for
the
installation
of
control
equipment
are
estimated
to
be
$
47.3
million.
Total
annualized
costs
are
estimated
at
$
7.0
million/
yr,
which
includes
$
4.1
million/
yr
in
capital
recovery
costs,
$
2.8
million/
yr
in
emission
control
device
operation
and
maintenance
costs,
and
$
0.1
million/
yr
for
monitoring,
recordkeeping
and
reporting.
These
costs
are
based
on
the
installation
of
new
wet
scrubbers
on
54
ore
crushing
and
handling
units,
seven
indurating
furnace
stacks,
and
11
finished
pellet
handling
units.
The
costs
are
also
based
on
upgrading
four
wet
scrubbers
for
one
indurating
furnace.
In
addition,
the
estimate
includes
the
cost
of
bag
leak
detection
systems
for
baghouses,
continuous
parameter
monitoring
systems
for
scrubbers,
and
continuous
opacity
monitors
for
ESP.
C.
What
Are
the
Economic
Impacts?
We
prepared
an
economic
analysis
to
evaluate
the
impact
this
proposed
rule
would
have
on
the
producers
and
consumers
of
taconite
and
society
as
a
whole.
The
taconite
industry
consists
of
eight
companies
owning
eight
mining
operations,
concentration
plants,
and
pelletizing
plants.
The
total
annualized
social
cost
of
the
proposed
rule
is
$
7
million
(
in
2000
dollars).
This
cost
is
distributed
among
consumers
(
mainly
steel
mills)
who
may
buy
less
and/
or
spend
more
on
taconite
iron
ore
as
a
result
of
the
proposed
NESHAP,
including
merchant
taconite
producers
that
sell
their
output
on
the
market,
integrated
iron
and
steel
plants
that
produce
and
consume
the
taconite
captively
within
the
company,
steel
producers
that
use
electric
arc
furnace
(
EAF)
technology
to
produce
steel
from
scrap,
and
foreign
producers.
Consumers
incur
$
3.4
million
of
the
total
social
costs,
merchant
producers
incur
$
0.7
million
in
costs,
and
integrated
iron
and
steel
producers
incur
$
5
million
in
costs.
The
EAF
producers
and
foreign
producers
enjoy
a
net
gain
in
revenues
of
$
1.2
million
and
$
0.7
million,
respectively.
Our
analysis
indicates
that
the
taconite
iron
ore
market
will
experience
minimal
changes
in
the
price
and
quantity
of
produced,
and
in
the
prices
and
quantities
of
steel
mill
products
(
some
of
which
are
produced
using
taconite).
Prices
in
the
taconite
iron
ore
market
are
estimated
to
increase
by
2/
100th
of
a
percent
while
production
may
decrease
by
less
than
1/
100th
of
1
percent.
The
price
of
steel
mill
products
is
projected
to
increase
by
less
than
1/
100th
of
1
percent
and
the
quantity
produced
is
projected
to
change
by
less
than
1/
100th
of
1
percent.
The
EAF
steel
producers
who
make
steel
from
scrap
rather
than
iron
ore
are
projected
to
increase
their
output
by
approximately
2/
100th
of
1
percent
in
response
to
the
slight
increase
in
the
price
of
steel
mill
products.
While
the
market
overall
shows
minimal
impacts
associated
with
this
proposed
rule,
the
financial
stability
of
the
firms
operating
in
this
market
is
very
uncertain.
The
past
few
years
have
been
a
period
of
tremendous
change
in
the
iron
and
steel
industry,
during
which
more
than
27
companies
in
the
industry
have
declared
bankruptcy,
several
plants
have
closed,
and
EAF
technology
has
secured
a
growing
share
of
the
market.
These
changes
have
occurred
due
to
evolving
economic
conditions,
both
domestically
and
abroad,
and
technological
developments
within
the
industry.
Conditions
continue
to
be
challenging
for
iron
and
steel
producers.
In
an
assessment
of
the
impacts
on
the
companies
owning
taconite
plants,
we
find
the
estimated
costs
of
the
proposed
rule
are
uniformly
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Vol.
67,
No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
less
than
1
percent
of
baseline
sales
revenues,
and
typically
less
than
3
percent
of
baseline
profits.
However,
four
of
the
companies
had
negative
operating
income
in
2000,
a
period
of
time
during
in
which
the
entire
nation
experienced
a
drop
in
economic
activity.
Three
of
the
companies
owning
taconite
plants
have
filed
for
protection
under
Chapter
11
of
the
bankruptcy
code
since
September
2001.
Thus,
there
is
reason
to
be
concerned
about
the
financial
condition
of
companies
owning
taconite
plants.
The
incremental
effect
of
the
proposed
rule
on
firm
financial
stability,
however,
is
projected
to
be
very
small.
We
also
prepared
a
sensitivity
analysis
that
examined
the
regional
impacts
of
the
proposed
rule.
All
the
taconite
production
plants
are
located
within
four
counties
in
Minnesota
and
one
in
Michigan.
Thus,
the
impacts
of
the
proposed
rule
are
expected
to
be
concentrated
geographically.
We
modeled
the
supply
and
demand
linkages
of
the
various
industries
and
households
within
each
county
to
estimate
changes
that
may
occur
in
the
region
as
the
taconite
industry
complies
with
the
proposed
NESHAP.
We
estimate
that
as
industries
that
interact
with
the
taconite
industry
(
such
as
construction
and
earth
moving
equipment
industries)
react
to
the
changes
in
the
taconite
market,
and
as
household
incomes
are
reduced
as
a
result
of
changes
in
all
the
various
industries
in
the
region,
the
impact
of
the
proposed
rule
will
add
approximately
$
4
million
in
economic
cost
to
the
region.
This
represents
approximately
2/
10ths
of
1
percent
of
total
sales
in
those
counties.
Thus,
even
though
the
impacts
are
concentrated
in
only
five
counties,
we
believe
that
the
impacts
on
those
county
economies
will
not
be
very
large.
D.
What
Are
the
Non
Air
Health,
Environmental,
and
Energy
Impacts?
We
project
that
the
implementation
of
the
rule
as
proposed
would
increase
water
usage
by
8.4
billion
gallons
per
year
industrywide.
This
increased
water
usage
would
result
from
the
installation
of
new
wet
scrubbers
needed
for
compliance.
Much
of
this
water
will
be
discharged
as
scrubber
blowdown
to
the
tailings
basin(
s)
located
at
each
plant.
At
two
or
more
of
the
affected
facilities,
there
is
the
potential
that
this
increased
wastewater
burden
will
result
in
new
or
aggravated
violations
of
permitted
wastewater
discharge
limits
from
the
tailings
basins
unless
significant
measures
are
taken
to
install
new
or
upgrade
existing
wastewater
treatment
systems.
The
energy
increase
would
be
expected
to
be
15,298
megawatt
hours
per
year,
primarily
due
to
the
energy
requirements
of
new
wet
scrubbers.
V.
Solicitation
of
Comments
and
Public
Participation
We
seek
full
public
participation
in
arriving
at
final
decisions
and
encourage
comments
on
all
aspects
of
this
proposal
from
all
interested
parties.
You
need
to
submit
full
supporting
data
and
detailed
analysis
with
your
comments
to
allow
use
to
make
the
best
use
of
them.
Be
sure
to
direct
your
comments
to
the
EPA
Docket
Center
(
Air
Docket),
Docket
ID
No.
OAR
2002
0039
(
see
ADDRESSES).
VI.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
the
EPA
must
determine
whether
the
regulatory
action
is
``
significant''
and,
therefore,
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
a
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
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
entitlement,
grants,
user
fees,
or
loan
programs
or
the
rights
and
obligations
of
recipients
thereof;
or
(
4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
it
has
been
determined
that
this
regulatory
action
is
not
a
``
significant
regulatory
action''
because
none
of
the
listed
criteria
apply
to
this
action.
Consequently,
this
action
was
not
submitted
to
OMB
for
review
under
Executive
Order
12866.
B.
Executive
Order
13132,
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
the
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
rules
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
This
proposed
rule
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
This
proposed
rule
is
mandated
by
statute
and,
does
not
impose
requirements
on
States,
however,
States
will
be
required
to
implement
the
rule
by
incorporating
the
rule
into
permits
and
enforcing
the
rule
upon
delegation.
States
will
collect
permit
fees
that
will
be
used
to
offset
the
resource
burden
of
implementing
the
rule.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
this
rule.
Although
section
6
of
Executive
Order
13132
does
not
apply
to
this
rule,
the
EPA
did
consult
with
State
and
local
officials
in
developing
this
rule.
C.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
6,
2000),
requires
the
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
This
proposed
rule
does
not
have
tribal
implications.
No
tribal
governments
own
or
operate
taconite
iron
ore
processing
plants.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.
D.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant,''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
the
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
the
EPA
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children
and
explain
why
the
planned
rule
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.
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2002
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Proposed
Rules
The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
501
of
the
Executive
Order
has
the
potential
to
influence
the
rule.
This
proposed
rule
is
not
subject
to
Executive
Order
13045
because
it
is
technology
based
and
not
based
on
health
or
safety
risks.
No
children's
risk
analysis
was
performed
because
no
alternative
technologies
exist
that
would
provide
greater
stringency
at
a
reasonable
cost.
Further,
this
proposed
rule
has
been
determined
not
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866.
E.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
Tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
the
EPA
generally
must
prepare
a
written
statement,
including
a
costbenefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
by
State,
local,
and
Tribal
governments,
in
aggregate,
or
by
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
the
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
the
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
as
to
why
that
alternative
was
not
adopted.
Before
the
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
Tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
The
EPA
has
determined
that
this
proposed
rule
does
not
contain
a
Federal
mandate
that
may
result
in
expenditures
of
$
100
million
or
more
for
State,
local,
and
Tribal
governments,
in
the
aggregate,
or
to
the
private
sector
in
any
1
year.
The
maximum
total
annual
cost
of
this
rule
for
any
year
has
been
estimated
to
be
$
8.9
million.
Thus,
today's
proposed
rule
is
not
subject
to
the
requirements
of
sections
202
and
205
of
the
UMRA.
In
addition,
the
EPA
has
determined
that
this
proposed
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments
because
it
contains
no
requirements
that
apply
to
such
governments
or
impose
obligations
upon
them.
Therefore,
today's
proposed
rule
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.
F.
Regulatory
Flexibility
Act
(
RFA),
As
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
SBREFA),
5
U.
S.
C.
et
seq.
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
proposed
rule
on
small
entities,
``
small
entity''
is
defined
as:
(
1)
A
small
business
whose
parent
company
has
fewer
than
500
employees
(
the
size
standard
set
by
the
Small
Business
Administration
for
small
businesses
in
NAICS
21221,
Taconite
Iron
Ore
Processing
Facilities);
(
2)
a
small
governmental
jurisdiction
that
is
a
government
or
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
forprofit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
Since
there
are
no
small
entities
within
the
taconite
industry,
this
proposed
rule
is
not
expected
to
impose
regulatory
costs
on
any
small
entities.
Therefore,
EPA
certifies
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
G.
Paperwork
Reduction
Act
The
information
collection
requirements
in
this
proposed
rule
have
been
submitted
for
approval
to
OMB
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
The
EPA
has
prepared
an
Information
Collection
Request
(
ICR)
document
(
ICR
No.
2050.01),
and
you
may
obtain
a
copy
from
Susan
Auby
by
mail
at
U.
S.
EPA,
Office
of
Environmental
Information,
Collection
Strategies
Division,
U.
S.
EPA
(
2822T),
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460,
by
e
mail
at
auby.
susan@
epa.
gov,
or
by
calling
(
202)
566
1672.
You
may
also
download
a
copy
off
the
Internet
at
http://
www.
epa.
gov/
icr.
The
information
requirements
are
not
effective
until
OMB
approves
them.
The
information
requirements
are
based
on
notification,
recordkeeping,
and
reporting
requirements
in
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A),
which
are
mandatory
for
all
operators
subject
to
NESHAP.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(
42
U.
S.
C.
7414).
All
information
submitted
to
the
EPA
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
EPA's
policies
set
forth
in
40
CFR
part
2,
subpart
B.
The
proposed
rule
would
require
applicable
one
time
notifications
required
by
the
General
Provisions
for
each
affected
source.
As
required
by
the
NESHAP
General
Provisions,
all
plants
would
be
required
to
prepare
and
operate
by
a
startup,
shutdown,
and
malfunction
plan.
Plants
also
would
be
required
to
prepare
an
operation
and
maintenance
plan
for
control
devices
subject
to
operating
limits,
a
fugitive
emissions
control
plan,
and
a
performance
testing
plan.
Records
would
be
required
to
demonstrate
continuous
compliance
with
the
monitoring,
operation,
and
maintenance
requirements
for
control
devices
and
monitoring
systems.
Semiannual
compliance
reports
also
are
required.
These
reports
would
describe
any
deviation
from
the
standards,
any
period
a
continuous
monitoring
system
was
``
out
of
control,''
or
any
startup,
shutdown,
or
malfunction
event
where
actions
taken
to
respond
were
inconsistent
with
startup,
shutdown,
and
malfunction
plan.
If
no
deviation
or
other
event
occurred,
only
a
summary
report
would
be
required.
Consistent
with
the
General
Provisions,
if
actions
taken
in
response
to
a
startup,
shutdown,
or
malfunction
event
are
not
consistent
with
the
plan,
an
immediate
report
must
be
submitted
within
2
days
of
the
event
with
a
letter
report
7
days
later.
Since
the
rule
provides
a
3
year
compliance
period,
periodic
reporting,
initial
performance
testing,
and
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18,
2002
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Proposed
Rules
subsequent
performance
testing
activities
would
be
conducted
beyond
the
3
year
period
covered
by
the
ICR.
Therefore,
the
burden
for
these
items
is
not
included
in
the
burden
estimate.
The
annual
public
reporting
and
recordkeeping
burden
for
this
collection
of
information
(
averaged
over
the
first
3
years
after
the
effective
date
of
the
final
rule)
is
estimated
to
total
518
labor
hours
per
year
at
a
total
annual
cost
of
$
29,052,
including
labor,
capital,
and
operation
and
maintenance.
This
burden
estimate
includes
the
preparation
of
a
startup,
shutdown,
and
malfunction
plan,
an
operating
and
maintenance
plan,
a
fugitive
dust
emission
control
plan,
and
a
performance
testing
plan.
The
total
capital/
startup
costs
associated
with
the
monitoring
requirements
over
the
3
year
period
of
the
ICR
are
estimated
at
$
3.2
million
(
annualized
capital/
startup
costs
are
$
271,089/
year)
with
operating
and
maintenance
equipment
costs
of
$
101,455
per
year.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purpose
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
existing
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
Agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
rules
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Comments
are
requested
on
the
EPA's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
By
U.
S.
Postal
Service,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
EPA
(
2822T),
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460;
or
by
courier,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
EPA
(
2822T),
1301
Constitution
Avenue,
NW.,
Room
6143,
Washington
DC
20460
(
202
566
1700);
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
Street,
NW.,
Washington,
DC
20503,
marked
``
Attention:
Desk
Officer
for
EPA.''
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
December
18,
2002,
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
January
17,
2003.
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
this
proposal.
H.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
(
NTTAA)
of
1995
(
Pub.
L.
104
113;
15
U.
S.
C.
272
note)
directs
the
EPA
to
use
voluntary
consensus
standards
in
their
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
annual
reports
to
OMB,
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.
This
proposed
rule
involves
technical
standards.
The
EPA
cites
the
following
standards
in
this
proposed
rule:
EPA
Methods
1,
2,
2F,
2G,
3,
3A,
3B,
4,
5,
and
17.
Consistent
with
the
NTTAA,
EPA
conducted
searches
to
identify
voluntary
consensus
standards
in
addition
to
these
EPA
methods.
No
applicable
voluntary
consensus
standards
were
identified
for
EPA
Methods
2F
and
2G.
The
search
and
review
results
have
been
documented
and
are
placed
in
the
docket
(
Docket
Number
A
2001
14)
for
this
proposed
rule.
The
voluntary
consensus
standard
ASME
PTC
19
10
1981
Part
10,
``
Flue
and
Exhaust
Gas
Analyses,''
is
cited
in
this
rule
for
its
manual
method
for
measuring
the
oxygen,
carbon
dioxide,
and
carbon
monoxide
content
of
exhaust
gas.
This
part
of
ASME
PTC
19
10
1981
Part
10
is
an
acceptable
alternative
to
Method
3B.
This
search
for
emissions
measurement
procedures
identified
14
voluntary
consensus
standards.
The
EPA
determined
that
12
of
these
14
standards
identified
for
measuring
emissions
of
the
HAP
or
surrogates
subject
to
emission
standards
in
this
proposed
rule
were
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
this
proposed
rule.
Therefore,
EPA
does
not
intend
to
adopt
these
standards
for
this
purpose.
The
reasons
for
this
determination
for
the
12
methods
are
available
in
the
docket.
Two
of
the
14
voluntary
consensus
standards
identified
in
this
search
were
not
available
at
the
time
the
review
was
conducted
for
the
purposes
of
this
proposed
rule
because
they
are
under
development
by
a
voluntary
consensus
body:
ASME/
BSR
MFC
13M,
``
Flow
Measurement
by
Velocity
Traverse,''
for
EPA
Method
2
(
and
possibly
1);
and
ASME/
BSR
MFC
12M,
``
Flow
in
Closed
Conduits
Using
Multiport
Averaging
Pitot
Primary
Flowmeters,''
for
EPA
Method
2.
Sections
63.9621
and
63.9622
to
40
CFR
part
63,
subpart
RRRRR,
list
the
EPA
testing
methods
included
in
the
proposed
rule.
Under
§
§
63.7(
f)
and
63.8(
f)
of
subpart
A
of
the
General
Provisions,
a
source
may
apply
to
EPA
for
permission
to
use
alternative
test
methods
or
alternative
monitoring
requirements
in
place
of
any
of
the
EPA
testing
methods,
performance
specifications,
or
procedures.
I.
Executive
Order
13211,
Energy
Effects
This
rule
is
not
subject
to
Executive
Order
13211,
Actions
Concerning
Rules
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(
66
FR
28355,
May
22,
2001)
because
it
is
not
a
significant
regulatory
action
under
Executive
Order
12866.
List
of
Subjects
in
40
CFR
Part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Hazardous
substances,
Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.
Dated:
November
26,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
stated
in
the
preamble,
title
40,
chapter
I,
part
63
of
the
Code
of
Federal
Regulations
is
proposed
to
be
amended
as
follows:
PART
63
[
AMENDED]
1.
The
authority
citation
for
part
63
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401,
et
seq.
2.
Part
63
is
proposed
to
be
amended
by
adding
subpart
RRRRR
to
read
as
follows:
Subpart
RRRRR
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Taconite
Iron
Ore
Processing
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243
/
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December
18,
2002
/
Proposed
Rules
What
This
Subpart
Covers
Sec.
63.9580
What
is
the
purpose
of
this
subpart?
63.9581
Am
I
subject
to
this
subpart?
63.9582
What
parts
of
my
plant
does
this
subpart
cover?
63.9583
When
do
I
have
to
comply
with
this
subpart?
Emission
Limitations
and
Work
Practice
Standards
63.9590
What
emission
limitations
must
I
meet?
63.9591
What
work
practice
standards
must
I
meet?
Operation
and
Maintenance
Requirements
63.9600
What
are
my
operation
and
maintenance
requirements?
General
Compliance
Requirements
63.9610
What
are
my
general
requirements
for
complying
with
this
subpart?
Initial
Compliance
Requirements
63.9620
On
which
units
and
by
what
date
must
I
conduct
performance
tests
or
other
initial
compliance
demonstrations?
63.9621
What
test
methods
and
other
procedures
must
I
use
to
demonstrate
initial
and
continuous
compliance
with
the
emission
limits
for
particulate
matter?
63.9622
What
test
methods
and
other
procedures
must
I
use
to
establish
and
demonstrate
initial
compliance
with
the
operating
limits?
63.9623
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations
that
apply
to
me?
63.9624
How
do
I
demonstrate
initial
compliance
with
the
work
practice
standards
that
apply
to
me?
63.9625
How
do
I
demonstrate
initial
compliance
with
the
operation
and
maintenance
requirements
that
apply
to
me?
Continuous
Compliance
Requirements
63.9630
When
must
I
conduct
subsequent
performance
tests?
63.9631
What
are
my
monitoring
requirements?
63.9632
What
are
the
installation,
operation,
and
maintenance
requirements
for
my
monitoring
equipment?
63.9633
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
63.9634
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations
that
apply
to
me?
63.9635
How
do
I
demonstrate
continuous
compliance
with
the
work
practice
standards
that
apply
to
me?
63.9636
How
do
I
demonstrate
continuous
compliance
with
the
operation
and
maintenance
requirements
that
apply
to
me?
63.9637
What
other
requirements
must
I
meet
to
demonstrate
continuous
compliance?
Notifications,
Reports,
and
Records
63.9640
What
notifications
must
I
submit
and
when?
63.9641
What
reports
must
I
submit
and
when?
63.9642
What
records
must
I
keep?
63.9643
In
what
form
and
how
long
must
I
keep
my
records?
Other
Requirements
and
Information
63.9650
What
parts
of
the
General
Provisions
apply
to
me?
63.9651
Who
implements
and
enforces
this
subpart?
63.9652
What
definitions
apply
to
this
subpart?
Tables
to
Subpart
RRRRR
of
Part
63
Table
1
to
Subpart
RRRRR
of
Part
63
Emission
Limits
Table
2
to
Subpart
RRRRR
of
Part
63
Applicability
of
General
Provisions
to
Subpart
RRRRR
of
Part
63
Subpart
RRRRR
National
Emission
Standards
for
Hazardous
Pollutants
for
Taconite
Iron
Ore
Processing
What
This
Subpart
Covers
§
63.9580
What
is
the
purpose
of
this
subpart?
This
subpart
establishes
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
taconite
iron
ore
processing.
This
subpart
also
establishes
requirements
to
demonstrate
initial
and
continuous
compliance
with
all
applicable
emission
limitations
(
emission
limits
and
operating
limits),
work
practice
standards,
and
operation
and
maintenance
requirements
in
this
subpart.
§
63.9581
Am
I
subject
to
this
subpart?
You
are
subject
to
this
subpart
if
you
own
or
operate
a
taconite
iron
ore
processing
plant
that
is
(
or
is
part
of)
a
major
source
of
hazardous
air
pollutant
(
HAP)
emissions
on
the
first
compliance
date
that
applies
to
you.
Your
taconite
iron
ore
processing
plant
is
a
major
source
of
HAP
if
it
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
10
tons
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
25
tons
or
more
per
year.
§
63.9582
What
parts
of
my
plant
does
this
subpart
cover?
(
a)
This
subpart
applies
to
each
new
and
existing
affected
source
at
your
taconite
iron
ore
processing
plant.
(
b)
The
affected
sources
are
each
new
or
existing
ore
crushing
and
handling
operation,
ore
dryer,
indurating
furnace,
and
finished
pellet
handling
operation
at
your
taconite
iron
ore
processing
plant,
as
defined
in
§
63.9652.
(
c)
This
subpart
covers
emissions
from
ore
crushing
and
handling
emission
units;
ore
dryer
stacks;
indurating
furnace
stacks;
finished
pellet
handling
emission
units;
and
fugitive
dust
emissions.
(
d)
An
ore
crushing
and
handling
operation,
ore
dryer,
indurating
furnace,
or
finished
pellet
handling
operation
at
your
taconite
iron
ore
processing
plant
is
existing
if
you
commenced
construction
or
reconstruction
of
the
affected
source
before
December
18,
2002.
(
e)
An
ore
crushing
and
handling
operation,
ore
dryer,
indurating
furnace,
or
finished
pellet
handling
operation
at
your
taconite
iron
ore
processing
plant
is
new
if
you
commence
construction
or
reconstruction
of
the
affected
source
on
or
after
December
18,
2002.
An
affected
source
is
reconstructed
if
it
meets
the
definition
of
reconstruction
in
§
63.2.
§
63.9583
When
do
I
have
to
comply
with
this
subpart?
(
a)
If
you
have
an
existing
affected
source,
you
must
comply
with
each
emission
limitation,
work
practice
standard,
and
operation
and
maintenance
requirement
in
this
subpart
that
applies
to
you
no
later
than
[
DATE
3
YEARS
AFTER
THE
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
(
b)
If
you
have
a
new
affected
source
and
its
initial
startup
date
is
on
or
before
[
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
you
must
comply
with
each
emission
limitation,
work
practice
standard,
and
operation
and
maintenance
requirement
in
this
subpart
that
applies
to
you
by
[
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
(
c)
If
you
have
a
new
affected
source
and
its
initial
startup
date
is
after
[
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
you
must
comply
with
each
emission
limitation,
work
practice
standard,
and
operation
and
maintenance
requirement
in
this
subpart
that
applies
to
you
upon
initial
startup.
(
d)
If
your
taconite
iron
ore
processing
plant
is
an
area
source
that
becomes
a
major
source
of
HAP,
the
compliance
dates
in
paragraphs
(
d)
(
1)
and
(
2)
of
this
section
apply
to
you.
(
1)
Any
portion
of
the
taconite
iron
ore
processing
plant
that
is
a
new
affected
source
or
a
new
reconstructed
source
must
be
in
compliance
with
this
subpart
upon
startup.
(
2)
All
other
parts
of
the
taconite
iron
ore
processing
plant
must
be
in
compliance
with
this
subpart
no
later
than
3
years
after
it
becomes
a
major
source.
(
e)
You
must
meet
the
notification
and
schedule
requirements
in
§
63.9640.
Several
of
these
notifications
must
be
submitted
before
the
compliance
date
for
your
affected
source.
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Vol.
67,
No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
Emission
Limitations
and
Work
Practice
Standards
§
63.9590
What
emission
limitations
must
I
meet?
(
a)
You
must
meet
each
emission
limit
in
Table
1
of
this
subpart
that
applies
to
you.
(
b)
You
must
meet
each
operating
limit
for
control
devices
in
paragraphs
(
b)
(
1)
through
(
4)
of
this
section
that
applies
to
you.
(
1)
For
each
negative
pressure
baghouse
or
positive
pressure
baghouse
equipped
with
a
stack
applied
to
meet
any
particulate
matter
emission
limit
in
Table
1
of
this
subpart,
you
must
operate
the
baghouse
such
that
the
bag
leak
detection
system
does
not
alarm
for
more
than
5
percent
of
the
total
operating
time
in
any
semiannual
reporting
period.
(
2)
For
each
scrubber
applied
to
meet
any
particulate
matter
emission
limit
in
Table
1
of
this
subpart,
you
must
maintain
the
average
pressure
drop
and
scrubber
water
flow
rate
at
or
above
the
minimum
levels
established
during
the
initial
performance
test.
(
3)
For
each
dry
electrostatic
precipitator
applied
to
meet
any
particulate
matter
emission
limit
in
Table
1
of
this
subpart,
you
must
maintain
the
6
minute
average
opacity
of
emissions
exiting
the
control
device
stack
at
or
below
the
level
established
during
the
initial
performance
test.
(
4)
An
owner
or
operator
who
uses
an
air
pollution
control
device
other
than
a
baghouse,
scrubber,
or
dry
electrostatic
precipitator
must
submit
a
site
specific
monitoring
plan
as
described
in
§
63.9631(
d).
§
63.9591
What
work
practice
standards
must
I
meet?
(
a)
You
must
prepare,
and
at
all
times
operate
according
to,
a
fugitive
dust
emissions
control
plan
that
describes
in
detail
the
measures
that
will
be
put
in
place
to
control
fugitive
dust
emissions
from
the
locations
listed
in
paragraphs
(
a)
(
1)
through
(
6)
of
this
section.
(
1)
Stockpiles
(
includes,
but
is
not
limited
to,
stockpiles
of
uncrushed
ore,
crushed
ore,
or
finished
pellets);
(
2)
Material
transfer
points;
(
3)
Plant
roadways;
(
4)
Tailings
basin;
(
5)
Pellet
loading
areas;
and
(
6)
Yard
areas.
(
b)
A
copy
of
your
fugitive
dust
emissions
control
plan
must
be
submitted
for
approval
to
the
Administrator
or
delegated
authority
on
or
before
the
applicable
compliance
date
for
the
affected
source
as
specified
in
§
63.9583.
The
requirement
for
the
plant
to
operate
according
to
the
fugitive
dust
emissions
control
plan
must
be
incorporated
by
reference
in
the
operating
permit
for
the
plant
that
is
issued
by
the
designated
permitting
authority
under
part
70
or
71
of
this
chapter.
(
c)
You
can
use
an
existing
fugitive
dust
emissions
control
plan
provided
it
meets
the
requirements
in
paragraphs
(
c)
(
1)
through
(
3)
of
this
section.
(
1)
The
plan
satisfies
the
requirements
of
paragraph
(
a)
of
this
section.
(
2)
The
plan
describes
the
current
measures
to
control
fugitive
dust
emission
sources.
(
3)
The
plan
has
been
approved
as
part
of
a
State
Implementation
Plan
or
title
V
permit.
(
d)
You
must
maintain
a
current
copy
of
the
fugitive
dust
emissions
control
plan
onsite
and
available
for
inspection
upon
request.
You
must
keep
the
plan
for
the
life
of
the
affected
source
or
until
the
affected
source
is
no
longer
subject
to
the
requirements
of
this
subpart.
Operation
and
Maintenance
Requirements
§
63.9600
What
are
my
operation
and
maintenance
requirements?
(
a)
As
required
by
§
63.6(
e)(
1)(
i),
you
must
always
operate
and
maintain
your
affected
source,
including
air
pollution
control
and
monitoring
equipment,
in
a
manner
consistent
with
good
air
pollution
control
practices
for
minimizing
emissions
at
least
to
the
levels
required
by
this
subpart.
(
b)
You
must
prepare
and
operate
at
all
times
according
to
a
written
operation
and
maintenance
plan
for
each
control
device
subject
to
an
operating
limit
in
§
63.9590(
b).
Each
plan
must
be
submitted
to
the
Administrator
or
delegated
authority
on
or
before
the
compliance
date
that
is
specified
in
§
63.9583
and
must
address
the
elements
in
paragraphs
(
b)
(
1)
and
(
2)
of
this
section.
You
must
maintain
a
current
copy
of
the
operation
and
maintenance
plan
onsite
and
available
for
inspection
upon
request.
You
must
keep
the
plan
for
the
life
of
the
affected
source
or
until
the
affected
source
is
no
longer
subject
to
the
requirements
of
this
subpart.
(
1)
Preventative
maintenance
for
each
control
device,
including
a
preventative
maintenance
schedule
that
is
consistent
with
the
manufacturer's
instructions
for
routine
and
long
term
maintenance.
(
2)
In
the
event
a
bag
leak
detection
system
alarm
is
triggered
for
a
baghouse,
you
must
initiate
corrective
action
to
determine
the
cause
of
the
alarm
within
1
hour
of
the
alarm,
initiate
corrective
action
to
correct
the
cause
of
the
problem
within
24
hours
of
the
alarm,
and
complete
the
corrective
action
as
soon
as
practicable.
Actions
may
include,
but
are
not
limited
to,
the
actions
listed
in
paragraphs
(
b)(
2)
(
i)
through
(
vi)
of
this
section.
(
i)
Inspecting
the
baghouse
for
air
leaks,
torn
or
broken
bags
or
filter
media,
or
any
other
condition
that
may
cause
an
increase
in
emissions.
(
ii)
Sealing
off
defective
bags
or
filter
media.
(
iii)
Replacing
defective
bags
or
filter
media
or
otherwise
repairing
the
control
device.
(
iv)
Sealing
off
a
defective
baghouse
compartment.
(
v)
Cleaning
the
bag
leak
detection
system
probe,
or
otherwise
repairing
the
bag
leak
detection
system.
(
vi)
Shutting
down
the
process
producing
the
particulate
emissions.
General
Compliance
Requirements
§
63.9610
What
are
my
general
requirements
for
complying
with
this
subpart?
(
a)
You
must
be
in
compliance
with
the
emission
limitations,
work
practice
standards,
and
operation
and
maintenance
requirements
in
this
subpart
at
all
times,
except
during
periods
of
startup,
shutdown,
and
malfunction.
The
terms
startup,
shutdown,
and
malfunction
are
defined
in
§
63.2.
(
b)
During
the
period
between
the
compliance
date
specified
for
your
affected
source
in
§
63.9583
and
the
date
upon
which
continuous
monitoring
systems
have
been
installed
and
certified
and
any
applicable
operating
limits
have
been
set,
you
must
maintain
a
log
detailing
the
operation
and
maintenance
of
the
process
and
emissions
control
equipment.
(
c)
You
must
develop
and
implement
a
written
startup,
shutdown,
and
malfunction
plan
according
to
the
provisions
in
§
63.6(
e)(
3).
Initial
Compliance
Requirements
§
63.9620
On
which
units
and
by
what
date
must
I
conduct
performance
tests
or
other
initial
compliance
demonstrations?
(
a)
To
demonstrate
initial
compliance
with
the
emission
limits
in
Table
1
of
this
subpart
for
ore
crushing
and
handling,
you
must
conduct
an
initial
performance
test
for
particulate
matter
as
specified
in
paragraphs
(
a)
(
1)
and
(
2)
of
this
section.
(
1)
Except
as
provided
in
paragraph
(
e)
of
this
section,
an
initial
performance
test
must
be
performed
on
all
stacks
associated
with
ore
crushing
and
handling.
(
2)
The
initial
performance
tests
must
be
conducted
within
2
years
of
the
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/
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18,
2002
/
Proposed
Rules
compliance
date
that
is
specified
in
§
63.9583.
(
b)
To
demonstrate
initial
compliance
with
the
emission
limits
in
Table
1
of
this
subpart
for
each
indurating
furnace,
you
must
conduct
an
initial
performance
test
for
all
stacks
associated
with
an
indurating
furnace
within
180
calendar
days
of
the
compliance
date
that
is
specified
in
§
63.9583.
For
indurating
furnaces
with
multiple
stacks,
all
stacks
for
the
indurating
furnace
must
be
tested
simultaneously.
(
c)
To
demonstrate
initial
compliance
with
the
emission
limits
in
Table
1
of
this
subpart
for
finished
pellet
handling,
you
must
conduct
an
initial
performance
test
for
particulate
matter
as
specified
in
paragraphs
(
c)
(
1)
and
(
2)
of
this
section.
(
1)
Except
as
provided
in
paragraph
(
e)
of
this
section,
an
initial
performance
test
must
be
performed
on
all
stacks
associated
with
finished
pellet
handling.
(
2)
The
initial
performance
tests
must
be
conducted
within
2
years
of
the
compliance
date
that
is
specified
in
§
63.9583.
(
d)
To
demonstrate
initial
compliance
with
the
emission
limits
in
Table
1
of
this
subpart
for
each
ore
dryer,
you
must
conduct
an
initial
performance
test
for
all
stacks
associated
with
an
ore
dryer
within
180
calendar
days
of
the
compliance
date
that
is
specified
in
§
63.9583.
For
ore
dryers
with
multiple
stacks,
all
stacks
for
the
ore
dryer
must
be
tested
simultaneously.
(
e)
For
ore
crushing
and
handling
and
finished
pellet
handling,
in
lieu
of
conducting
initial
performance
tests
for
particulate
matter
on
all
stacks,
you
may
elect
to
group
similar
emission
units
together
and
conduct
an
initial
compliance
test
on
a
representative
sample
of
emission
units
within
each
group
of
similar
emission
units.
The
determination
of
whether
emission
units
are
similar
must
meet
the
criteria
in
paragraph
(
f)
of
this
section.
The
number
of
units
that
must
be
tested
within
each
group
of
similar
units
must
be
determined
using
the
criteria
in
paragraph
(
g)
of
this
section.
If
you
decide
to
test
representative
emission
units,
you
must
prepare
and
submit
a
testing
plan
as
described
in
paragraph
(
h)
of
this
section.
(
f)
If
you
elect
to
test
representative
emission
units
as
provided
in
paragraph
(
e)
of
this
section,
the
units
that
are
grouped
together
as
similar
units
must
meet
the
criteria
in
paragraphs
(
f)
(
1)
through
(
4)
of
this
section.
(
1)
The
emission
units
must
be
of
the
same
type,
which
may
include,
but
is
not
limited
to,
primary
crushers,
secondary
crushers,
tertiary
crushers,
fine
crushers,
ore
conveyors,
ore
bins,
ore
screens,
grate
feed,
pellet
loadout,
hearth
layer,
cooling
stacks,
pellet
conveyor,
and
pellet
screens.
(
2)
The
emission
units
must
have
the
same
type
of
air
pollution
control
device,
which
may
include,
but
is
not
limited
to,
venturi
scrubbers,
impingement
scrubbers,
rotoclones,
multiclones,
wet
and
dry
electrostatic
precipitators,
and
baghouses.
(
3)
The
volumetric
air
flow
rates
discharged
from
the
air
pollution
control
devices,
in
dry
standard
cubic
feet
(
dscf),
must
be
within
plus
or
minus
10
percent
of
the
representative
unit.
(
4)
The
actual
process
throughput
rate,
in
long
tons
per
hour,
must
be
within
plus
or
minus
10
percent
of
the
representative
unit.
(
g)
If
you
elect
to
test
representative
emission
units
as
provided
in
paragraph
(
e)
of
this
section,
the
number
of
emission
units
tested
within
each
group
of
similar
units
must
be
based
on
the
criteria
in
paragraphs
(
g)
(
1)
through
(
3)
of
this
section.
(
1)
For
each
group
of
similar
units
with
six
or
less
units,
you
must
test
at
least
one
unit.
(
2)
For
each
group
of
similar
units
with
greater
than
six,
but
equal
to
or
less
than
12
units,
you
must
test
at
least
two
units.
(
3)
For
each
group
of
similar
units
with
greater
than
12
units,
you
must
test
at
least
four
units.
(
h)
If
you
are
conducting
initial
testing
on
representative
emission
units
within
the
ore
crushing
and
handling
or
finished
pellet
handling,
you
must
submit
a
testing
plan
for
initial
performance
tests
as
required
under
paragraph
(
e)
of
this
section.
This
testing
plan
must
be
submitted
to
the
Administrator
or
delegated
authority
on
or
before
the
compliance
date
that
is
specified
in
§
63.9583.
The
testing
plan
must
contain
the
information
specified
in
paragraphs
(
h)
(
1)
through
(
3)
of
this
section.
(
1)
A
list
of
all
emission
units.
This
list
must
clearly
identify
all
emission
units
that
have
been
grouped
together
as
similar
emission
units.
Within
each
group
of
emission
units,
you
must
identify
the
emission
unit(
s)
that
will
be
the
representative
unit(
s)
for
that
group,
and
subject
to
initial
performance
testing.
(
2)
The
process
type,
type
of
emission
control,
the
air
flow
rate
in
dscf,
and
the
actual
process
throughput
rate
in
long
tons
per
hour
for
each
emission
unit.
(
3)
A
schedule
indicating
when
you
will
conduct
initial
performance
tests
for
particulate
matter
for
each
of
the
representative
units.
(
i)
For
each
work
practice
standard
and
operation
and
maintenance
requirement
that
applies
to
you
where
initial
compliance
is
not
demonstrated
using
a
performance
test,
you
must
demonstrate
initial
compliance
within
30
calendar
days
after
the
compliance
date
that
is
specified
for
your
affected
source
in
§
63.9583.
(
j)
If
you
commenced
construction
or
reconstruction
between
December
18,
2002,
and
[
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
you
must
demonstrate
initial
compliance
with
either
the
proposed
emission
limit
or
the
promulgated
emission
limit
no
later
than
[
DATE
180
CALENDAR
DAYS
AFTER
THE
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER]
or
no
later
than
180
calendar
days
after
startup
of
the
source,
whichever
is
later,
according
to
§
63.7(
a)(
2)(
ix).
(
k)
If
you
commenced
construction
or
reconstruction
between
December
18,
2002,
and
[
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
and
you
chose
to
comply
with
the
proposed
emission
limit
when
demonstrating
initial
compliance,
you
must
conduct
a
second
performance
test
to
demonstrate
compliance
with
the
promulgated
emission
limit
by
[
DATE
3
YEARS
AND
180
CALENDAR
DAYS
AFTER
THE
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
or
after
startup
of
the
source,
whichever
is
later,
according
to
§
63.7(
a)(
2)(
ix).
§
63.9621
What
test
methods
and
other
procedures
must
I
use
to
demonstrate
initial
and
continuous
compliance
with
the
emission
limits
for
particulate
matter?
(
a)
You
must
conduct
each
performance
test
that
applies
to
your
affected
source
according
to
the
requirements
in
§
63.7(
e)(
1)
and
the
conditions
detailed
in
paragraphs
(
b)
and
(
c)
of
this
section.
(
b)
To
determine
compliance
with
the
applicable
emission
limit
for
particulate
matter
in
Table
1
of
this
subpart
for
ore
crushing
and
handling,
and
for
finished
pellet
handling,
you
must
follow
the
test
methods
and
procedures
in
paragraphs
(
b)
(
1)
through
(
3)
of
this
section.
(
1)
Determine
the
concentration
of
particulate
matter
in
the
stack
gas
and
the
stack
gas
volumetric
flow
rate
for
each
emission
unit
according
to
the
test
methods
in
appendix
A
to
part
60
of
this
chapter.
The
applicable
test
methods
are
listed
in
paragraphs
(
b)(
1)
(
i)
through
(
v)
of
this
section.
(
i)
Method
1
or
1A
to
select
sampling
port
locations
and
the
number
of
traverse
points.
Sampling
ports
must
be
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18,
2002
/
Proposed
Rules
located
at
the
outlet
of
the
control
device
and
prior
to
any
releases
to
the
atmosphere.
(
ii)
Method
2,
2A,
2C,
2D,
2F,
or
2G,
as
applicable,
to
determine
the
volumetric
flow
rate
of
the
stack
gas.
(
iii)
Method
3,
3A,
or
3B
to
determine
the
dry
molecular
weight
of
the
stack
gas.
(
iv)
Method
4
to
determine
the
moisture
content
of
the
stack
gas.
(
v)
Method
5,
5D
or
17
to
determine
the
concentration
of
particulate
matter.
(
2)
Collect
a
minimum
sample
volume
of
60
dry
standard
cubic
feet
of
gas
during
each
particulate
matter
test
run.
Three
valid
test
runs
are
needed
to
comprise
a
performance
test.
(
3)
For
each
ore
crushing
and
handling
affected
source,
and
for
each
finished
pellet
handling
affected
source
you
must
determine
the
flow
weighted
mean
concentration
of
particulate
matter
emissions
using
the
procedure
in
paragraph
(
b)(
3)
(
i)
or
(
ii)
of
this
section.
(
i)
Compute
the
flow
weighted
mean
concentration
of
particulate
matter
emissions
using
Equation
1
of
this
section.
C
C
Eq
w
i
i
n
=
=
Q
Q
1)
i
i
i=
1
n
1
(
.
Where:
Cw
=
Flow
weighted
mean
concentration
of
particulate
matter
for
all
emission
units
within
the
affected
source,
grains
per
dry
standard
cubic
foot
(
gr/
dscf);
Ci
=
Three
run
average
particulate
matter
concentration
from
emission
unit
``
i'',
gr/
dscf;
Qi
=
Three
run
average
volumetric
flow
rate
of
stack
gas
from
emission
unit
``
i'',
dscf/
hr;
and
n
=
The
number
of
emission
units
in
the
affected
source.
(
ii)
If
you
are
grouping
similar
units
as
allowed
under
§
63.9620(
d),
you
must
meet
the
requirements
in
paragraphs
(
b)(
3)(
ii)
(
A)
and
(
B)
of
this
section.
(
A)
All
emission
units
within
each
group
of
similar
units
must
be
assigned
the
flow
weighted
mean
concentration
of
particulate
matter
emissions
for
the
representative
unit.
(
B)
All
emission
units
within
each
group
of
similar
units
must
be
assigned
the
actual
average
operating
volumetric
flow
rate
of
exhaust
gas
measured
for
each
emission
unit
within
each
group
of
similar
units.
You
cannot
assign
the
average
volumetric
flow
rate
of
exhaust
gas
measured
for
a
representative
unit
to
all
emission
units
within
each
group
of
similar
units.
(
c)
To
determine
compliance
with
the
applicable
emission
limit
for
particular
matter
in
Table
1
of
this
subpart
for
each
ore
dryer
and
for
each
indurating
furnace,
you
must
follow
the
test
methods
and
procedures
in
paragraphs
(
c)
(
1)
through
(
5)
of
this
section.
(
1)
Determine
the
concentration
of
particulate
matter
for
each
stack
according
to
the
test
methods
in
appendix
A
to
part
60
of
this
chapter.
The
applicable
test
methods
are
listed
in
paragraphs
(
c)(
1)
(
i)
through
(
v)
of
this
section.
(
i)
Method
1
or
1A
to
select
sampling
port
locations
and
the
number
of
traverse
points.
Sampling
ports
must
be
located
at
the
outlet
of
the
control
device
and
prior
to
any
releases
to
the
atmosphere.
(
ii)
Method
2,
2A,
2C,
2D,
2F,
or
2G,
as
applicable,
to
determine
the
volumetric
flow
rate
of
the
stack
gas.
(
iii)
Method
3,
3A,
or
3B
to
determine
the
dry
molecular
weight
of
the
stack
gas.
(
iv)
Method
4
to
determine
the
moisture
content
of
the
stack
gas.
(
v)
Method
5,
5D
or
17
to
determine
the
concentration
of
particulate
matter.
(
2)
Collect
a
minimum
sample
volume
of
60
dry
standard
cubic
feet
of
gas
during
each
particulate
matter
test
run.
Three
valid
test
runs
are
needed
to
comprise
a
performance
test.
(
3)
For
ore
dryers
and
indurating
furnaces
with
multiple
stacks,
all
stacks
must
be
tested
simultaneously.
(
4)
For
each
ore
dryer
and
each
indurating
furnace,
compute
the
flowweighted
mean
concentration
of
particulate
matter
for
each
test
run
using
Equation
2
of
this
section.
C
C
Eq
a
i
i
n
=
=
Q
Q
2)
i
i
i=
1
n
1
(
.
Where:
Ca
=
Flow
weighted
mean
concentration
of
particulate
matter
for
run
``
a'',
gr/
dscf;
Ci
=
Concentration
of
particulate
matter
from
stack
``
i''
for
run
``
a'',
gr/
dscf;
Qi
=
Volumetric
flow
rate
of
stack
gas
from
stack
``
i''
for
run
``
a'',
dscf/
hr;
n
=
Number
of
stacks;
and
a
=
Run
number:
1,
2,
or
3.
(
5)
For
each
ore
dryer
and
each
indurating
furnace,
compute
the
flowweighted
mean
particulate
matter
concentration
for
the
three
test
runs
using
Equation
3
of
this
section.
C
C
C
C
Eq
=
+
+
1
2
3
3
(
.
3)
Where:
C
=
Flow
weighted
mean
particulate
matter
concentration,
gr/
dscf;
C1
=
Flow
weighted
particulate
matter
concentration
for
run
1,
gr/
dscf;
C2
=
Flow
weighted
particulate
matter
concentration
for
run
2,
gr/
dscf;
and
C3
=
Flow
weighted
particulate
matter
concentration
for
run
3,
gr/
dscf.
§
63.9622
What
test
methods
and
other
procedures
must
I
use
to
establish
and
demonstrate
initial
compliance
with
the
operating
limits?
(
a)
For
a
wet
scrubber
subject
to
operating
limits
for
pressure
drop
and
scrubber
water
flow
rate
in
§
63.9590(
b)(
2),
you
must
establish
sitespecific
operating
limits
according
to
the
procedures
in
paragraphs
(
a)
(
1)
and
(
2)
of
this
section.
(
1)
Using
the
continuous
parameter
monitoring
system
(
CPMS)
required
in
§
63.9631(
b),
measure
and
record
the
pressure
drop
and
scrubber
water
flow
rate
every
15
minutes
during
each
run
of
the
particulate
matter
performance
test.
(
2)
Compute
and
record
the
average
pressure
drop
and
scrubber
water
flow
rate
for
each
individual
test
run.
Your
operating
limits
are
the
lowest
average
pressure
drop
and
scrubber
water
flow
rate
value
in
any
of
the
three
runs
that
meet
the
applicable
emission
limit.
(
b)
For
a
dry
electrostatic
precipitator
subject
to
the
operating
limit
in
§
63.9590(
b)(
3)
for
opacity,
you
must
establish
a
site
specific
operating
limit
according
to
the
procedures
in
paragraphs
(
b)
(
1)
and
(
4)
of
this
section.
(
1)
Using
the
continuous
opacity
monitoring
system
(
COMS)
required
in
§
63.9631(
c),
measure
and
record
the
opacity
of
emissions
from
each
control
device
stack
during
the
particulate
matter
performance
test.
(
2)
Compute
and
record
the
6
minute
opacity
averages
from
24
or
more
data
points
equally
spaced
over
each
6
minute
period
(
e.
g.,
at
15
second
intervals)
during
the
test
runs.
(
3)
Using
the
opacity
measurements
from
a
performance
test
that
meets
the
emission
limit,
determine
the
opacity
value
corresponding
to
the
99
percent
upper
confidence
level
of
a
normal
distribution
of
the
6
minute
opacity
averages.
(
4)
In
your
semiannual
compliance
report
required
by
63.9641(
b),
report
as
a
deviation
any
6
minute
period
during
which
the
average
opacity,
as
measured
by
the
COMS,
exceeds
the
opacity
value
corresponding
to
the
99
percent
upper
confidence
level
determined
under
paragraph
(
b)(
3)
of
this
section.
(
c)
You
may
change
the
operating
limits
for
a
wet
scrubber,
or
dry
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Federal
Register
/
Vol.
67,
No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
electrostatic
precipitator
if
you
meet
the
requirements
in
paragraphs
(
c)
(
1)
through
(
3)
of
this
section.
(
1)
Submit
a
written
notification
to
the
Administrator
of
your
request
to
conduct
a
new
performance
test
to
revise
the
operating
limit.
(
2)
Conduct
a
performance
test
to
demonstrate
compliance
with
the
applicable
emission
limitation
in
Table
1
of
this
subpart.
(
3)
Establish
revised
operating
limits
according
to
the
applicable
procedures
n
paragraphs
(
a)
and
(
b)
of
this
section.
§
63.9623
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations
that
apply
to
me?
(
a)
For
each
affected
source
subject
to
an
emission
limit
in
Table
1
of
this
subpart,
you
must
demonstrate
initial
compliance
by
meeting
the
requirements
in
paragraphs
(
a)
(
1)
through
(
6)
of
this
section.
(
1)
For
ore
crushing
and
handling,
the
flow
weighted
mean
concentration
of
particulate
matter,
determined
according
to
the
procedures
in
§
63.9620(
a)
and
§
63.9621(
b),
must
not
exceed
the
emission
limits
in
Table
1
of
this
subpart.
(
2)
For
indurating
furnaces,
the
flowweighted
mean
concentration
of
particulate
matter,
determined
according
to
the
procedures
in
§
63.9620(
b)
and
§
63.9621(
c),
must
not
exceed
the
emission
limits
in
Table
1
of
this
subpart.
(
3)
For
finished
pellet
handling,
the
flow
weighted
mean
concentration
of
particulate
matter,
determined
according
to
the
procedures
in
§
63.9620(
c)
and
§
63.9621(
b),
must
not
exceed
the
emission
limits
in
Table
1
of
this
subpart.
(
4)
For
ore
dryers,
the
flow
weighted
mean
concentration
of
particulate
matter,
determined
according
to
the
procedures
in
§
63.9620(
d)
and
§
63.9621(
c),
must
not
exceed
the
emission
limits
in
Table
1
of
this
subpart.
(
5)
For
each
wet
scrubber
subject
to
the
operating
limits
for
pressure
drop
and
scrubber
water
flow
rate
in
§
63.9590(
b)(
2),
you
must
meet
the
requirements
in
paragraphs
(
a)(
5)
(
i)
and
(
ii)
of
this
section.
(
i)
Measure
and
record
the
pressure
drop
and
scrubber
water
flow
rate
during
the
performance
test
in
accordance
with
§
63.9622(
a).
(
ii)
Establish
appropriate
site
specific
operating
limits.
(
6)
For
each
dry
electrostatic
precipitator
subject
to
the
opacity
operating
limit
in
§
63.9590(
b)(
3),
you
must
meet
the
requirements
in
paragraphs
(
a)(
6)(
i)
and
(
ii)
of
this
section.
(
i)
Measure
and
record
the
opacity
during
the
performance
test
in
accordance
with
§
63.9622(
b).
(
ii)
Establish
an
appropriate
sitespecific
operating
limit.
(
b)
For
each
emission
limitation
that
applies
to
you,
you
must
submit
a
notification
of
compliance
status
according
to
§
63.9640(
e).
§
63.9624
How
do
I
demonstrate
initial
compliance
with
the
work
practice
standards
that
apply
to
me?
(
a)
You
must
demonstrate
initial
compliance
with
the
work
practice
standards
by
meeting
the
requirements
in
paragraphs
(
a)(
1)
through
(
3)
of
this
section.
(
1)
You
must
prepare
a
fugitive
dust
emissions
control
plan
in
accordance
with
the
requirements
in
§
63.9591.
(
2)
You
must
submit
to
the
Administrator
or
delegated
authority
the
fugitive
dust
emissions
control
plan
in
accordance
with
the
requirements
in
§
63.9591.
(
3)
You
must
implement
each
control
practice
according
to
the
procedures
specified
in
your
fugitive
dust
emissions
control
plan.
(
b)
[
Reserved]
§
63.9625
How
do
I
demonstrate
initial
compliance
with
the
operation
and
maintenance
requirements
that
apply
to
me?
You
must
demonstrate
initial
compliance
by
certifying
in
your
notification
of
compliance
status
that
you
have
met
the
requirements
in
paragraphs
(
a)
through
(
c)
of
this
section.
(
a)
You
have
prepared
the
operation
and
maintenance
plan
according
to
the
requirements
in
§
63.9600(
b).
(
b)
You
operate
each
control
device
according
to
the
procedures
in
the
operation
and
maintenance
plan.
(
c)
You
submit
a
notification
of
compliance
status
according
to
the
requirements
in
§
63.9640(
e).
Continuous
Compliance
Requirements
§
63.9630
When
must
I
conduct
subsequent
performance
tests?
(
a)
You
must
conduct
subsequent
performance
tests
to
demonstrate
continued
compliance
with
the
ore
crushing
and
handling
emission
limit
in
Table
1
of
this
subpart
according
to
the
schedule
developed
by
your
permitting
authority
and
shown
in
your
title
V
permit.
If
a
title
V
permit
has
not
been
issued,
you
must
submit
a
testing
plan
and
schedule,
containing
the
information
specified
in
paragraph
(
e)
of
this
section,
to
the
permitting
authority
for
approval.
(
b)
You
must
conduct
subsequent
performance
tests
on
all
stacks
from
indurating
furnaces
to
demonstrate
continued
compliance
with
the
indurating
furnace
limits
in
Table
1
of
this
subpart
according
to
the
schedule
developed
by
your
permitting
authority
and
shown
in
your
title
V
permit,
but
no
less
frequent
than
twice
per
5
year
permit
term.
If
a
title
V
permit
has
not
been
issued,
you
must
submit
a
testing
plan
and
schedule,
containing
the
information
specified
in
paragraph
(
e)
of
this
section,
to
the
permitting
authority
for
approval.
For
indurating
furnaces
with
multiple
stacks,
all
stacks
for
the
indurating
furnace
must
be
tested
simultaneously.
(
c)
You
must
conduct
subsequent
performance
tests
to
demonstrate
compliance
with
the
finished
pellet
handling
emission
limit
in
Table
1
of
this
subpart
according
to
the
schedule
developed
by
your
permitting
authority
and
shown
in
your
title
V
permit.
If
a
title
V
permit
has
not
been
issued,
you
must
submit
a
testing
plan
and
schedule,
containing
the
information
specified
in
paragraph
(
e)
of
this
section,
to
the
permitting
authority
for
approval.
(
d)
You
must
conduct
subsequent
performance
tests
on
all
stacks
from
ore
dryers
to
demonstrate
continued
compliance
with
the
ore
dryer
limits
in
Table
1
of
this
subpart
according
to
the
schedule
developed
by
your
permitting
authority
and
shown
in
your
title
V
permit.
If
a
title
V
permit
has
not
been
issued,
you
must
submit
a
testing
plan
and
schedule,
containing
the
information
specified
in
paragraph
(
e)
of
this
section,
to
the
permitting
authority
for
approval.
For
ore
dryers
with
multiple
stacks,
all
stacks
for
the
ore
dryer
must
be
tested
simultaneously.
(
e)
If
your
plant
does
not
have
a
title
V
permit,
you
must
submit
a
testing
plan
for
subsequent
performance
tests
as
required
in
paragraphs
(
a)
through
(
d)
of
this
section.
This
testing
plan
must
be
submitted
to
the
Administrator
or
delegated
authority
on
or
before
the
compliance
date
that
is
specified
in
§
63.9583.
The
testing
plan
must
contain
the
information
specified
in
paragraphs
(
e)
(
1)
and
(
2)
of
this
section.
You
must
maintain
a
current
copy
of
the
testing
plan
onsite
and
available
for
inspection
upon
request.
You
must
keep
the
plan
for
the
life
of
the
affected
source
or
until
the
affected
source
is
no
longer
subject
to
the
requirements
of
this
subpart.
(
1)
A
list
of
all
emission
units.
(
2)
A
schedule
indicating
when
you
will
conduct
subsequent
performance
tests
for
particulate
matter
for
each
of
the
emission
units.
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Federal
Register
/
Vol.
67,
No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
§
63.9631
What
are
my
monitoring
requirements?
(
a)
For
each
baghouse
subject
to
the
operating
limit
in
§
63.9590(
b)(
1)
for
the
bag
leak
detection
system
alarm,
you
must
at
all
times
monitor
the
relative
change
in
particulate
matter
loadings
using
a
bag
leak
detection
system
according
to
the
requirements
in
§
63.9632(
a)
and
conduct
inspections
at
their
specified
frequencies
according
to
the
requirements
in
paragraphs
(
a)
(
1)
through
(
8)
of
this
section.
(
1)
Monitor
the
pressure
drop
across
each
baghouse
cell
each
day
to
ensure
pressure
drop
is
within
the
normal
operating
range
identified
in
the
manual.
(
2)
Confirm
that
dust
is
being
removed
from
hoppers
through
weekly
visual
inspections
or
other
means
of
ensuring
the
proper
functioning
of
removal
mechanisms.
(
3)
Check
the
compressed
air
supply
for
pulse
jet
baghouses
each
day.
(
4)
Monitor
cleaning
cycles
to
ensure
proper
operation
using
an
appropriate
methodology.
(
5)
Check
bag
cleaning
mechanisms
for
proper
functioning
through
monthly
visual
inspection
or
equivalent
means.
(
6)
Make
monthly
visual
checks
of
bag
tension
on
reverse
air
and
shaker
type
baghouses
to
ensure
that
bags
are
not
kinked
(
kneed
or
bent)
or
laying
on
their
sides.
You
do
not
have
to
make
this
check
for
shaker
type
baghouses
using
self
tensioning
(
spring
loaded)
devices.
(
7)
Confirm
the
physical
integrity
of
the
baghouse
through
quarterly
visual
inspections
of
the
baghouse
interior
for
air
leaks.
(
8)
Inspect
fans
for
wear,
material
buildup,
and
corrosion
through
quarterly
visual
inspections,
vibration
detectors,
or
equivalent
means.
(
b)
For
each
wet
scrubber
subject
to
the
operating
limits
for
pressure
drop
and
scrubber
water
flow
rate
in
§
63.9590(
b)(
2),
you
must
at
all
times
monitor
the
average
pressure
drop
and
water
flow
rate
using
a
CPMS
according
to
the
requirements
in
§
63.9632(
b)
and
(
c).
(
c)
For
each
dry
electrostatic
precipitator
subject
to
the
opacity
operating
limit
in
§
63.9590(
b)(
3),
you
must
at
all
times
monitor
the
6
minute
average
opacity
of
emissions
exiting
each
control
device
stack
using
a
COMS
according
to
the
requirements
in
§
63.9632(
d).
(
d)
An
owner
or
operator
who
uses
an
air
pollution
control
device
other
than
a
baghouse,
scrubber,
or
dry
electrostatic
precipitator
must
submit
a
site
specific
monitoring
plan
that
includes
the
information
in
paragraphs
(
d)
(
1)
through
(
4)
of
this
section.
The
monitoring
plan
is
subject
to
approval
by
the
Administrator.
You
must
maintain
a
current
copy
of
the
monitoring
plan
onsite
and
available
for
inspection
upon
request.
You
must
keep
the
plan
for
the
life
of
the
affected
source
or
until
the
affected
source
is
no
longer
subject
to
the
requirements
of
this
subpart.
(
1)
A
description
of
the
device;
(
2)
Test
results
collected
in
accordance
with
§
63.9621
verifying
the
performance
of
the
device
for
reducing
emissions
of
particulate
matter
to
the
atmosphere
to
the
levels
required
by
this
subpart;
(
3)
A
copy
of
the
operation
and
maintenance
plan
required
in
§
63.9600(
b);
and
(
4)
Appropriate
operating
parameters
that
will
be
monitored
to
maintain
continuous
compliance
with
the
applicable
emission
limitation(
s).
§
63.9632
What
are
the
installation,
operation,
and
maintenance
requirements
for
my
monitoring
equipment?
(
a)
For
each
baghouse
subject
to
the
operating
limit
in
§
63.9590(
b)(
1)
for
the
bag
leak
detection
system
alarm,
you
must
install,
operate,
and
maintain
each
bag
leak
detection
system
according
to
the
requirements
in
paragraphs
(
a)
(
1)
through
(
7)
of
this
section.
(
1)
The
system
must
be
certified
by
the
manufacturer
to
be
capable
of
detecting
emissions
of
particulate
matter
at
concentrations
of
10
milligrams
per
actual
cubic
meter
(
0.0044
grains
per
actual
cubic
foot)
or
less.
(
2)
The
system
must
provide
output
of
relative
changes
in
particulate
matter
loadings.
(
3)
The
system
must
be
equipped
with
an
alarm
that
will
sound
when
an
increase
in
relative
particulate
loadings
is
detected
over
a
preset
level.
The
alarm
must
be
located
such
that
it
can
be
heard
by
the
appropriate
plant
personnel.
(
4)
Each
system
that
works
based
on
the
triboelectric
effect
must
be
installed,
operated,
and
maintained
in
a
manner
consistent
with
the
guidance
document,
``
Fabric
Filter
Bag
Leak
Detection
Guidance,''
EPA
454/
R
98
015,
September
1997.
This
document
is
available
on
the
EPA's
Technology
Transfer
Network
at
http://
www.
epa.
gov/
ttn/
emc/
cem/
tribo.
pdf
(
Adobe
Acrobat
version)
or
http://
www.
epa.
gov/
ttn/
emc/
cem/
tribo.
wpd
(
WordPerfect
version).
You
may
install,
operate,
and
maintain
other
types
of
bag
leak
detection
systems
in
a
manner
consistent
with
the
manufacturer's
written
specifications
and
recommendations.
(
5)
To
make
the
initial
adjustment
of
the
system,
establish
the
baseline
output
by
adjusting
the
sensitivity
(
range)
and
the
averaging
period
of
the
device.
Then,
establish
the
alarm
set
points
and
the
alarm
delay
time.
(
6)
Following
the
initial
adjustment,
do
not
adjust
the
sensitivity
or
range,
averaging
period,
alarm
set
points,
or
alarm
delay
time,
except
as
detailed
in
your
operation
and
maintenance
plan.
Do
not
increase
the
sensitivity
by
more
than
100
percent
or
decrease
the
sensitivity
by
more
than
50
percent
over
a
365
day
period
unless
a
responsible
official
certifies,
in
writing,
that
the
baghouse
has
been
inspected
and
found
to
be
in
good
operating
condition.
(
7)
Where
multiple
detectors
are
required,
the
system's
instrumentation
and
alarm
may
be
shared
among
detectors.
(
b)
For
each
wet
scrubber
subject
to
the
operating
limits
in
§
63.9590(
b)(
2)
for
pressure
drop
and
scrubber
water
flow
rate,
you
must
install,
operate,
and
maintain
each
CPMS
according
to
the
requirements
in
paragraphs
(
b)(
1)
and
(
2)
of
this
section.
(
1)
For
the
pressure
drop
CPMS,
you
must
follow
the
procedures
in
paragraphs
(
b)(
1)(
i)
through
(
vi)
of
this
section.
(
i)
Locate
the
pressure
sensor(
s)
in
or
as
close
to
a
position
that
provides
a
representative
measurement
of
the
pressure
and
that
minimizes
or
eliminates
pulsating
pressure,
vibration,
and
internal
and
external
corrosion.
(
ii)
Use
a
gauge
with
a
minimum
measurement
sensitivity
of
0.5
inch
of
water
or
a
transducer
with
a
minimum
measurement
sensitivity
of
5
percent
of
the
pressure
range.
(
iii)
Check
the
pressure
tap
for
pluggage
daily.
(
iv)
Using
a
manometer,
check
gauge
calibration
quarterly
and
transducer
calibration
monthly.
(
v)
Conduct
calibration
checks
any
time
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
pressure
range,
or
install
a
new
pressure
sensor.
(
vi)
At
least
monthly,
inspect
all
components
for
integrity,
all
electrical
connections
for
continuity,
and
all
mechanical
connections
for
leakage.
(
2)
For
the
scrubber
water
flow
rate
CPMS,
you
must
follow
the
procedures
in
paragraphs
(
b)(
2)
(
i)
through
(
iv)
of
this
section.
(
i)
Locate
the
flow
sensor
and
other
necessary
equipment
in
a
position
that
provides
a
representative
flow
and
that
reduces
swirling
flow
or
abnormal
velocity
distributions
due
to
upstream
and
downstream
disturbances.
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18,
2002
/
Proposed
Rules
(
ii)
Use
a
flow
sensor
with
a
minimum
measurement
sensitivity
of
5
percent
of
the
flow
rate.
(
iii)
Conduct
a
flow
sensor
calibration
check
at
least
semiannually
according
to
the
manufacturer's
instructions.
(
iv)
At
least
monthly,
inspect
all
components
for
integrity,
all
electrical
connections
for
continuity,
and
all
mechanical
connections
for
leakage.
(
c)
You
must
install,
operate,
and
maintain
each
CPMS
for
a
wet
scrubber
according
to
the
requirements
in
paragraphs
(
c)
(
1)
through
(
3)
of
this
section.
(
1)
Each
CPMS
must
complete
a
minimum
of
one
cycle
of
operation
for
each
successive
5
minute
period.
(
2)
Each
CPMS
must
have
valid
data
for
at
least
95
percent
of
every
averaging
period.
(
3)
Each
CPMS
must
determine
and
record
the
average
of
all
recorded
readings.
(
d)
For
each
dry
electrostatic
precipitator
subject
to
the
opacity
operating
limit
in
§
63.9590(
b)(
3),
you
must
install,
operate,
and
maintain
each
COMS
according
to
the
requirements
in
paragraphs
(
d)
(
1)
through
(
4)
of
this
section.
(
1)
You
must
install
each
COMS
and
conduct
a
performance
evaluation
of
each
COMS
according
to
§
63.8
and
Performance
Specification
1
in
appendix
B
to
40
CFR
part
60.
(
2)
You
must
develop
and
implement
a
quality
control
program
for
operating
and
maintaining
each
COMS
according
to
§
63.8.
At
a
minimum,
the
quality
control
program
must
include
a
daily
calibration
drift
assessment,
quarterly
performance
audit,
and
annual
zero
alignment
of
each
COMS.
(
3)
You
must
operate
and
maintain
each
COMS
according
to
§
63.8(
e)
and
your
quality
control
program.
Identify
periods
the
COMS
is
out
of
control,
including
any
periods
that
the
COMS
fails
to
pass
a
daily
calibration
drift
assessment,
quarterly
performance
audit,
or
annual
zero
alignment
audit.
(
4)
You
must
determine
and
record
the
6
minute
average
opacity
collected
for
periods
during
which
the
COMS
is
not
out
of
control.
§
63.9633
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
(
a)
Except
for
monitoring
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
(
including
as
applicable,
calibration
checks
and
required
zero
and
span
adjustments),
you
must
monitor
continuously
(
or
collect
data
at
all
required
intervals)
at
all
times
an
affected
source
is
operating.
(
b)
You
may
not
use
data
recorded
during
monitoring
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
in
data
averages
and
calculations
used
to
report
emission
or
operating
levels,
or
to
fulfill
a
minimum
data
availability
requirement.
You
must
use
all
the
data
collected
during
all
other
periods
in
assessing
compliance.
(
c)
A
monitoring
malfunction
is
any
sudden,
infrequent,
not
reasonably
preventable
failure
of
the
monitoring
to
provide
valid
data.
Monitoring
failures
that
are
caused
in
part
by
poor
maintenance
or
careless
operation
are
not
considered
malfunctions.
§
63.9634
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations
that
apply
to
me?
(
a)
For
each
affected
source
subject
to
an
emission
limit
in
Table
1
of
this
subpart,
you
must
demonstrate
continuous
compliance
by
meeting
the
requirements
in
paragraphs
(
b)
through
(
f)
of
this
section.
(
b)
For
ore
crushing
and
handling
and
for
finished
pellet
handling,
you
must
demonstrate
continuous
compliance
by
meeting
the
requirements
in
paragraphs
(
b)(
1)
and
(
2)
of
this
section.
(
1)
The
flow
weighted
mean
concentration
of
particulate
matter
for
all
ore
crushing
and
handling
emission
units
and
for
all
finished
pellet
handling
emission
units
must
be
maintained
at
or
below
the
emission
limits
in
Table
1
of
this
subpart.
(
2)
You
must
conduct
subsequent
performance
tests
for
emission
units
in
the
ore
crushing
and
handling
and
finished
pellet
handling
affected
sources
following
the
schedule
in
your
title
V
permit.
If
a
title
V
permit
has
not
been
issued,
you
must
conduct
subsequent
performance
tests
according
to
a
testing
plan
approved
by
the
Administrator
or
delegated
authority.
(
c)
For
ore
dryers
and
indurating
furnaces,
you
must
demonstrate
continuous
compliance
by
meeting
the
requirements
in
paragraphs
(
c)
(
1)
and
(
2)
of
this
section.
(
1)
The
flow
weighted
mean
concentration
of
particulate
matter
for
all
stacks
from
the
ore
dryer
or
indurating
furnace
must
be
maintained
at
or
below
the
emission
limits
in
Table
1
of
this
subpart.
(
2)
For
ore
dryers,
you
must
conduct
subsequent
performance
tests
following
the
schedule
in
your
title
V
permit.
For
indurating
furnaces,
you
must
conduct
subsequent
performance
tests
following
the
schedule
in
your
title
V
permit,
but
no
less
frequent
than
twice
per
5
year
permit
term.
If
a
title
V
permit
has
not
been
issued,
you
must
conduct
subsequent
performance
tests
according
to
a
testing
plan
approved
by
the
Administrator
or
delegated
authority.
(
d)
For
each
baghouse
subject
to
the
operating
limit
for
the
bag
leak
detection
system
alarm
in
§
63.9590(
b)(
1),
you
must
demonstrate
continuous
compliance
by
completing
the
requirements
in
paragraphs
(
d)
(
1)
through
(
3)
of
this
section.
(
1)
Maintaining
each
baghouse
such
that
the
bag
leak
detection
system
alarm
does
not
sound
for
more
than
5
percent
of
the
operating
time
during
any
semiannual
reporting
period.
To
determine
the
percent
of
time
the
alarm
sounded
you
must
follow
the
procedure
in
paragraphs
(
d)(
1)
(
i)
through
(
v)
of
this
section.
(
i)
Alarms
that
occur
due
solely
to
a
malfunction
of
the
bag
leak
detection
system
are
not
included
in
the
calculation.
(
ii)
Alarms
that
occur
during
startup,
shutdown,
or
malfunction
are
not
included
in
the
calculation
if
the
condition
is
described
in
the
startup,
shutdown,
and
malfunction
plan
and
all
the
actions
you
took
during
the
startup,
shutdown,
or
malfunction
were
consistent
with
the
procedures
in
the
startup,
shutdown,
and
malfunction
plan.
(
iii)
Count
1
hour
of
alarm
time
for
each
alarm
when
you
initiated
procedures
to
determine
the
cause
of
the
alarm
within
1
hour.
(
iv)
Count
the
actual
amount
of
time
you
took
to
initiate
procedures
to
determine
the
cause
of
the
alarm
if
you
did
not
initiate
procedures
to
determine
the
cause
of
the
alarm
within
1
hour
of
the
alarm.
(
v)
Calculate
the
percentage
of
time
the
alarm
on
the
bag
leak
detection
system
sounds
as
the
ratio
of
the
sum
of
alarm
times
to
the
total
operating
time
multiplied
by
100.
(
2)
Maintaining
records
of
the
times
the
bag
leak
detection
system
alarm
sounded,
and
for
each
valid
alarm,
the
time
you
initiated
corrective
action,
the
corrective
action(
s)
taken,
and
the
date
on
which
corrective
action
was
completed.
(
3)
Inspecting
and
maintaining
each
baghouse
according
to
the
requirements
in
§
63.9631(
a)
(
1)
through
(
8)
and
recording
all
information
needed
to
document
conformance
with
these
requirements.
If
you
increase
or
decrease
the
sensitivity
of
the
bag
leak
detection
system
beyond
the
limits
specified
in
§
63.9632(
a)(
6),
you
must
include
a
copy
of
the
required
written
certification
by
a
responsible
official
in
the
next
semiannual
compliance
report.
(
e)
For
each
wet
scrubber
subject
to
the
operating
limits
for
pressure
drop
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18DEP2.
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Federal
Register
/
Vol.
67,
No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
and
scrubber
water
flow
rate
in
§
63.9590(
b)(
2),
you
must
demonstrate
continuous
compliance
by
completing
the
requirements
of
paragraphs
(
e)(
1)
through
(
3)
of
this
section.
(
1)
Maintaining
the
average
pressure
drop
and
scrubber
water
flow
rate
at
levels
no
lower
than
those
established
during
the
initial
or
subsequent
performance
test.
(
2)
Inspecting
and
maintaining
each
scrubber
CPMS
according
to
§
63.9632(
b)
and
recording
all
information
needed
to
document
conformance
with
these
requirements.
(
3)
Collecting
and
reducing
monitoring
data
for
pressure
drop
and
scrubber
water
flow
rate
according
to
§
63.9632(
c)
and
recording
all
information
needed
to
document
conformance
with
these
requirements.
(
f)
For
each
dry
electrostatic
precipitator
subject
to
the
site
specific
opacity
operating
limit
in
§
63.9590(
b)(
3),
you
must
demonstrate
continuous
compliance
by
completing
the
requirements
of
paragraphs
(
f)(
1)
and
(
2)
of
this
section.
(
1)
Maintaining
the
6
minute
average
opacity
of
emissions
no
higher
than
the
site
specific
limit
established
during
the
initial
or
subsequent
performance
test.
(
2)
Operating
and
maintaining
each
COMS
and
reducing
the
COMS
data
according
to
§
63.9632(
d).
§
63.9635
How
do
I
demonstrate
continuous
compliance
with
the
work
practice
standards
that
apply
to
me?
(
a)
You
must
demonstrate
continuous
compliance
with
the
work
practice
standard
requirements
in
§
63.9591
by
operating
in
accordance
with
your
fugitive
dust
emissions
control
plan
at
all
times.
(
b)
You
must
maintain
a
current
copy
of
the
fugitive
dust
emissions
control
plan
required
in
§
63.9591
onsite
and
available
for
inspection
upon
request.
You
must
keep
the
plan
for
the
life
of
the
affected
source
or
until
the
affected
source
is
no
longer
subject
to
the
requirements
of
this
subpart.
§
63.9636
How
do
I
demonstrate
continuous
compliance
with
the
operation
and
maintenance
requirements
that
apply
to
me?
(
a)
For
each
control
device
subject
to
an
operating
limit
in
§
63.9590(
b),
you
must
demonstrate
continuous
compliance
with
the
operation
and
maintenance
requirements
in
§
63.9600(
b)
by
completing
the
requirements
of
paragraphs
(
a)(
1)
and
(
2)
of
this
section.
(
1)
Performing
preventative
maintenance
for
each
control
device
according
to
§
63.9600(
b)(
1)
and
recording
all
information
needed
to
document
conformance
with
these
requirements;
and
(
2)
Initiating
and
completing
corrective
action
for
a
bag
leak
detection
system
alarm
according
to
§
63.9600(
b)(
2)
and
recording
all
information
needed
to
document
conformance
with
these
requirements.
(
b)
You
must
maintain
a
current
copy
of
the
operation
and
maintenance
plan
required
in
§
63.9600(
b)
onsite
and
available
for
inspection
upon
request.
You
must
keep
the
plan
for
the
life
of
the
affected
source
or
until
the
affected
source
is
no
longer
subject
to
the
requirements
of
this
subpart.
§
63.9637
What
other
requirements
must
I
meet
to
demonstrate
continuous
compliance?
(
a)
Deviations.
You
must
report
each
instance
in
which
you
did
not
meet
each
emission
limitation
in
Table
1
of
this
subpart
that
applies
to
you.
This
includes
periods
of
startup,
shutdown,
and
malfunction.
You
also
must
report
each
instance
in
which
you
did
not
meet
the
work
practice
standards
in
§
63.9591
and
each
instance
in
which
you
did
not
meet
each
operation
and
maintenance
requirement
in
§
63.9600
that
applies
to
you.
These
instances
are
deviations
from
the
emission
limitations,
work
practice
standards,
and
operation
and
maintenance
requirements
in
this
subpart.
These
deviations
must
be
reported
according
to
the
requirements
in
§
63.9641.
(
b)
Startups,
shutdowns,
and
malfunctions.
During
periods
of
startup,
shutdown,
and
malfunction,
you
must
operate
in
accordance
with
your
startup,
shutdown,
and
malfunction
plan.
(
1)
Consistent
with
§
§
63.6(
e)
and
63.7(
e)(
1),
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
not
violations
if
you
demonstrate
to
the
Administrator's
satisfaction
that
you
were
operating
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan.
(
2)
The
Administrator
will
determine
whether
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
violations,
according
to
the
provisions
in
§
63.6(
e).
Notifications,
Reports,
and
Records
§
63.9640
What
notifications
must
I
submit
and
when?
(
a)
You
must
submit
all
of
the
notifications
in
§
§
63.7(
b)
and
(
c),
63.8(
f)(
4),
and
63.9(
b)
through
(
h)
that
apply
to
you
by
the
specified
dates.
(
b)
As
specified
in
§
63.9(
b)(
2),
if
you
start
up
your
affected
source
before
[
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
Federal
Register],
you
must
submit
your
initial
notification
no
later
than
[
DATE
120
CALENDAR
DAYS
AFTER
THE
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
Federal
Register].
(
c)
As
specified
in
§
63.9(
b)(
3),
if
you
start
up
your
new
affected
source
on
or
after
[
DATE
OF
PUBLICATION
OF
THE
FINAL
RULE
IN
THE
Federal
Register],
you
must
submit
your
initial
notification
no
later
than
120
calendar
days
after
you
become
subject
to
this
subpart.
(
d)
If
you
are
required
to
conduct
a
performance
test,
you
must
submit
a
notification
of
intent
to
conduct
a
performance
test
at
least
60
calendar
days
before
the
performance
test
is
scheduled
to
begin
as
required
in
§
63.7(
b)(
1).
(
e)
If
you
are
required
to
conduct
a
performance
test
or
other
initial
compliance
demonstration,
you
must
submit
a
notification
of
compliance
status
according
to
§
63.9(
h)(
2)(
ii).
The
initial
notification
of
compliance
status
must
be
submitted
by
the
dates
specified
in
paragraphs
(
e)(
1)
and
(
2)
of
this
section.
(
1)
For
each
initial
compliance
demonstration
that
does
not
include
a
performance
test,
you
must
submit
the
notification
of
compliance
status
before
the
close
of
business
on
the
30th
calendar
day
following
completion
of
the
initial
compliance
demonstration.
(
2)
For
each
initial
compliance
demonstration
that
does
include
a
performance
test,
you
must
submit
the
notification
of
compliance
status,
including
the
performance
test
results,
before
the
close
of
business
on
the
60th
calendar
day
following
the
completion
of
the
performance
test
according
to
§
63.10(
d)(
2).
§
63.9641
What
reports
must
I
submit
and
when?
(
a)
Compliance
report
due
dates.
Unless
the
Administrator
has
approved
a
different
schedule,
you
must
submit
a
semiannual
compliance
report
to
your
permitting
authority
according
to
the
requirements
in
paragraphs
(
a)(
1)
through
(
5)
of
this
section.
(
1)
The
first
compliance
report
must
cover
the
period
beginning
on
the
compliance
date
that
is
specified
for
your
affected
source
in
§
63.9583
and
ending
on
June
30
or
December
31,
whichever
date
comes
first
after
the
compliance
date
that
is
specified
for
your
source
in
§
63.9583.
(
2)
The
first
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
comes
first
after
your
first
compliance
report
is
due.
(
3)
Each
subsequent
compliance
report
must
cover
the
semiannual
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reporting
period
from
January
1
through
June
30
or
the
semiannual
reporting
period
from
July
1
through
December
31.
(
4)
Each
subsequent
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
comes
first
after
the
end
of
the
semiannual
reporting
period.
(
5)
For
each
affected
source
that
is
subject
to
permitting
regulations
pursuant
to
40
CFR
part
70
or
71,
and
if
the
permitting
authority
has
established
dates
for
submitting
semiannual
reports
pursuant
to
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
you
may
submit
the
first
and
subsequent
compliance
reports
according
to
the
dates
the
permitting
authority
has
established
instead
of
according
to
the
dates
in
paragraphs
(
a)(
1)
through
(
4)
of
this
section.
(
b)
Compliance
report
contents.
Each
compliance
report
must
include
the
information
in
paragraphs
(
b)(
1)
through
(
3)
of
this
section
and,
as
applicable,
in
paragraphs
(
b)(
4)
through
(
8)
of
this
section.
(
1)
Company
name
and
address.
(
2)
Statement
by
a
responsible
official,
with
the
official's
name,
title,
and
signature,
certifying
the
truth,
accuracy,
and
completeness
of
the
content
of
the
report.
(
3)
Date
of
report
and
beginning
and
ending
dates
of
the
reporting
period.
(
4)
If
you
had
a
startup,
shutdown,
or
malfunction
during
the
reporting
period
and
you
took
actions
consistent
with
your
startup,
shutdown,
and
malfunction
plan,
the
compliance
report
must
include
the
information
in
§
63.10(
d)(
5)(
i).
(
5)
If
there
were
no
deviations
from
the
continuous
compliance
requirements
in
§
§
63.9634
through
63.9636
that
apply
to
you,
then
provide
a
statement
that
there
were
no
deviations
from
the
emission
limitations,
work
practice
standards,
or
operation
and
maintenance
requirements
during
the
reporting
period.
(
6)
If
there
were
no
periods
during
which
a
continuous
monitoring
system
(
including
a
CPMS
or
COMS)
was
outof
control
as
specified
in
§
63.8(
c)(
7),
then
provide
a
statement
that
there
were
no
periods
during
which
the
CPMS
was
out
of
control
during
the
reporting
period.
(
7)
For
each
deviation
from
an
emission
limitation
in
Table
1
of
this
subpart
that
occurs
at
an
affected
source
where
you
are
not
using
a
continuous
monitoring
system
(
including
a
CPMS
or
COMS)
to
comply
with
an
emission
limitation
in
this
subpart,
the
compliance
report
must
contain
the
information
in
paragraphs
(
b)(
1)
through
(
4)
of
this
section
and
the
information
in
paragraphs
(
b)(
7)(
i)
and
(
ii)
of
this
section.
This
includes
periods
of
startup,
shutdown,
and
malfunction.
(
i)
The
total
operating
time
of
each
affected
source
during
the
reporting
period.
(
ii)
Information
on
the
number,
duration,
and
cause
of
deviations
(
including
unknown
cause,
if
applicable)
as
applicable
and
the
corrective
action
taken.
(
8)
For
each
deviation
from
an
emission
limitation
occurring
at
an
affected
source
where
you
are
using
a
continuous
monitoring
system
(
including
a
CPMS
or
COMS)
to
comply
with
the
emission
limitation
in
this
subpart,
you
must
include
the
information
in
paragraphs
(
b)(
1)
through
(
4)
of
this
section
and
the
information
in
paragraphs
(
b)(
8)(
i)
through
(
xi)
of
this
section.
This
includes
periods
of
startup,
shutdown,
and
malfunction.
(
i)
The
date
and
time
that
each
malfunction
started
and
stopped.
(
ii)
The
date
and
time
that
each
continuous
monitoring
was
inoperative,
except
for
zero
(
low
level)
and
highlevel
checks.
(
iii)
The
date,
time,
and
duration
that
each
continuous
monitoring
system
was
out
of
control,
including
the
information
in
§
63.8(
c)(
8).
(
iv)
The
date
and
time
that
each
deviation
started
and
stopped,
and
whether
each
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction
or
during
another
period.
(
v)
A
summary
of
the
total
duration
of
the
deviation
during
the
reporting
period
and
the
total
duration
as
a
percent
of
the
total
source
operating
time
during
that
reporting
period.
(
vi)
A
breakdown
of
the
total
duration
of
the
deviations
during
the
reporting
period
including
those
that
are
due
to
startup,
shutdown,
control
equipment
problems,
process
problems,
other
known
causes,
and
other
unknown
causes.
(
vii)
A
summary
of
the
total
duration
of
continuous
monitoring
system
downtime
during
the
reporting
period
and
the
total
duration
of
continuous
monitoring
system
downtime
as
a
percent
of
the
total
source
operating
time
during
the
reporting
period.
(
viii)
A
brief
description
of
the
process
units.
(
ix)
A
brief
description
of
the
continuous
monitoring
system.
(
x)
The
date
of
the
latest
continuous
monitoring
system
certification
or
audit.
(
xi)
A
description
of
any
changes
in
continuous
monitoring
systems,
processes,
or
controls
since
the
last
reporting
period.
(
c)
Immediate
startup,
shutdown,
and
malfunction
report.
If
you
had
a
startup,
shutdown,
or
malfunction
during
the
semiannual
reporting
period
that
was
not
consistent
with
your
startup,
shutdown,
and
malfunction
plan,
you
must
submit
an
immediate
startup,
shutdown,
and
malfunction
report
according
to
the
requirements
in
§
63.10(
d)(
5)(
ii).
(
d)
Part
70
monitoring
report.
If
you
have
obtained
a
title
V
operating
permit
for
an
affected
source
pursuant
to
40
CFR
part
70
or
71,
you
must
report
all
deviations
as
defined
in
this
subpart
in
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A).
If
you
submit
a
compliance
report
for
an
affected
source
along
with,
or
as
part
of,
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
and
the
compliance
report
includes
all
the
required
information
concerning
deviations
from
any
emission
limitation
or
operation
and
maintenance
requirement
in
this
subpart,
submission
of
the
compliance
report
satisfies
any
obligation
to
report
the
same
deviations
in
the
semiannual
monitoring
report.
However,
submission
of
a
compliance
report
does
not
otherwise
affect
any
obligation
you
may
have
to
report
deviations
from
permit
requirements
for
an
affected
source
to
your
permitting
authority.
§
63.9642
What
records
must
I
keep?
(
a)
You
must
keep
the
records
listed
in
paragraphs
(
a)(
1)
through
(
3)
of
this
section.
(
1)
A
copy
of
each
notification
and
report
that
you
submitted
to
comply
with
this
subpart,
including
all
documentation
supporting
any
initial
notification
or
notification
of
compliance
status
that
you
submitted,
according
to
the
requirements
in
§
63.10(
b)(
2)(
xiv).
(
2)
The
records
in
§
63.6(
e)(
3)(
iii)
through
(
v)
related
to
startup,
shutdown,
and
malfunction.
(
3)
Records
of
performance
tests,
performance
evaluations
as
required
in
§
63.10(
b)(
2)(
viii).
(
b)
For
each
COMS,
you
must
keep
the
records
specified
in
paragraphs
(
b)(
1)
through
(
4)
of
this
section.
(
1)
Records
described
in
§
63.10(
b)(
2)(
vi)
through
(
xi).
(
2)
Monitoring
data
for
COMS
during
a
performance
evaluation
as
required
in
§
63.6(
h)(
7)(
i)
and
(
ii).
(
3)
Previous
(
that
is,
superceded)
versions
of
the
performance
evaluation
plan
as
required
in
§
63.8(
d)(
3).
(
4)
Records
of
the
date
and
time
that
each
deviation
started
and
stopped,
and
whether
the
deviation
occurred
during
a
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period
of
startup,
shutdown,
or
malfunction
or
during
another
period.
(
c)
You
must
keep
the
records
required
in
§
§
63.9634
through
63.9636
to
show
continuous
compliance
with
each
emission
limitation,
work
practice
standard,
and
operation
and
maintenance
requirement
that
applies
to
you.
§
63.9643
In
what
form
and
how
long
must
I
keep
my
records?
(
a)
Your
records
must
be
in
a
form
suitable
and
readily
available
for
expeditious
review,
according
to
§
63.10(
b)(
1).
(
b)
As
specified
in
§
63.10(
b)(
1),
you
must
keep
each
record
for
5
years
following
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record.
(
c)
You
must
keep
each
record
on
site
for
at
least
2
years
after
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record
according
to
§
63.10(
b)(
1).
You
can
keep
the
records
offsite
for
the
remaining
3
years.
Other
Requirements
and
Information
§
63.9650
What
parts
of
the
General
Provisions
apply
to
me?
Table
1
to
this
subpart
shows
which
parts
of
the
General
Provisions
in
§
§
63.1
through
63.15
apply
to
you.
§
63.9651
Who
implements
and
enforces
this
subpart?
(
a)
This
subpart
can
be
implemented
and
enforced
by
us,
the
United
States
Environmental
Protection
Agency
(
U.
S.
EPA),
or
a
delegated
authority
such
as
your
State,
local,
or
tribal
agency.
If
the
U.
S.
EPA
Administrator
has
delegated
authority
to
your
State,
local,
or
tribal
agency,
then
that
agency
has
the
authority
to
implement
and
enforce
this
subpart.
You
should
contact
your
U.
S.
EPA
Regional
Office
to
find
out
if
this
subpart
is
delegated
to
your
State,
local,
or
tribal
agency.
(
b)
In
delegating
implementation
and
enforcement
authority
of
this
subpart
to
a
State,
local,
or
tribal
agency
under
subpart
E
of
this
part,
the
authorities
contained
in
paragraph
(
c)
of
this
section
are
retained
by
the
Administrator
of
the
U.
S.
EPA
and
are
not
transferred
to
the
State,
local,
or
tribal
agency.
(
c)
The
authorities
that
will
not
be
delegated
to
State,
local,
or
tribal
agencies
are
specified
in
paragraphs
(
c)(
1)
through
(
3)
of
this
section.
(
1)
Approval
of
major
alternatives
to
test
methods
under
§
63.7(
e)(
2)(
ii)
and
(
f)
and
as
defined
in
§
63.90.
(
2)
Approval
of
major
alternatives
to
monitoring
under
§
63.8(
f)
and
as
defined
in
§
63.90.
(
3)
Approval
of
major
alternatives
to
recordkeeping
and
reporting
under
§
63.10(
f)
and
as
defined
in
§
63.90.
§
63.9652
What
definitions
apply
to
this
subpart?
Terms
used
in
this
subpart
are
defined
in
the
Clean
Air
Act,
in
§
63.2,
and
in
this
section
as
follows.
Affected
source
means
each
new
or
existing
ore
crushing
and
handling
operation,
ore
dryer,
indurating
furnace,
or
finished
pellet
handling
operation,
at
your
taconite
iron
ore
processing
plant.
Bag
leak
detection
system
means
a
system
that
is
capable
of
continuously
monitoring
relative
particulate
matter
(
dust)
loadings
in
the
exhaust
of
a
baghouse
to
detect
bag
leaks
and
other
upset
conditions.
A
bag
leak
detection
system
includes,
but
is
not
limited
to,
an
instrument
that
operates
on
tribroelectric,
light
scattering,
light
transmittance,
or
other
effect
to
continuously
monitor
relative
particulate
matter
loadings.
Conveyor
belt
transfer
point
means
a
point
in
the
conveying
operation
where
the
taconite
ore
or
taconite
pellets
are
transferred
to
or
from
a
conveyor
belt,
except
where
the
taconite
ore
or
taconite
pellets
are
being
transferred
to
a
bin
or
stockpile.
Crusher
means
a
machine
used
to
crush
taconite
ore
and
includes
feeders
or
conveyors
located
immediately
below
the
crushing
surfaces.
Crushers
include,
but
are
not
limited
to,
gyratory
crushers
and
cone
crushers.
Deviation
means
any
instance
in
which
an
affected
source
subject
to
this
subpart,
or
an
owner
or
operator
of
such
a
source:
(
1)
Fails
to
meet
any
requirement
or
obligation
established
by
this
subpart,
including
but
not
limited
to
any
emission
limitation
(
including
operating
limits)
or
operation
and
maintenance
requirement;
(
2)
Fails
to
meet
any
term
or
condition
that
is
adopted
to
implement
an
applicable
requirement
in
this
subpart
and
that
is
included
in
the
operating
permit
for
any
affected
source
required
to
obtain
such
a
permit;
or
(
3)
Fails
to
meet
any
emission
limitation
in
this
subpart
during
startup,
shutdown,
or
malfunction,
regardless
of
whether
or
not
such
failure
is
permitted
by
this
subpart.
Emission
limitation
means
any
emission
limit,
opacity
limit,
or
operating
limit.
Finished
pellet
handling
means
the
transfer
of
fired
taconite
pellets
from
the
indurating
furnace
to
the
finished
pellet
stockpiles
at
the
plant.
Finished
pellet
handling
includes,
but
is
not
limited
to,
furnace
discharge
or
grate
discharge,
and
finished
pellet
screening,
transfer,
and
storage.
Fugitive
dust
emission
source
means
a
stationary
source
from
which
particles
are
discharged
to
the
atmosphere
due
to
wind
or
mechanical
inducement
such
as
vehicle
traffic.
Fugitive
dust
sources
include,
but
are
not
limited
to:
(
1)
Stockpiles
(
includes,
but
is
not
limited
to,
stockpiles
of
uncrushed
ore,
crushed
ore,
or
finished
pellets);
(
2)
Material
transfer
points;
(
3)
Plant
roadways;
(
4)
Tailings
basins;
(
5)
Pellet
loading
areas;
and
(
6)
Yard
areas.
Grate
feed
means
the
transfer
of
unfired
taconite
pellets
from
the
pelletizer
into
the
indurating
furnace.
Grate
kiln
indurating
furnace
means
a
furnace
system
that
consists
of
a
traveling
grate,
a
rotary
kiln,
and
an
annular
cooler.
The
grate
kiln
indurating
furnace
begins
at
the
point
where
the
grate
feed
conveyor
discharges
the
green
balls
onto
the
furnace
traveling
grate
and
ends
where
the
hardened
pellets
exit
the
cooler.
The
atmospheric
pellet
cooler
vent
stack
is
not
included
as
part
of
the
grate
kiln
indurating
furnace.
Indurating
means
the
process
whereby
unfired
taconite
pellets,
called
green
balls,
are
hardened
at
high
temperature
in
an
indurating
furnace.
Types
of
indurating
furnaces
include
straight
grate
indurating
furnaces
and
grate
kiln
indurating
furnaces.
Ore
crushing
and
handling
means
the
process
whereby
dry
taconite
ore
is
crushed
and
screened.
Ore
crushing
and
handling
includes,
but
is
not
limited
to,
all
dry
crushing
operations
(
e.
g.,
primary,
secondary,
and
tertiary
crushing),
dry
ore
conveyance
and
transfer
points,
dry
ore
classification
and
screening,
dry
ore
storage
and
stockpiling,
dry
milling,
dry
cobbing
(
i.
e.,
dry
magnetic
separation),
and
the
grate
feed.
Ore
crushing
and
handling
specifically
excludes
any
operations
where
the
dry
crushed
ore
is
saturated
with
water,
such
as,
wet
milling
and
wet
magnetic
separation.
Ore
dryer
means
a
rotary
dryer
that
repeatedly
tumbles
wet
taconite
ore
concentrate
through
a
heated
air
stream
to
reduce
the
amount
of
entrained
moisture
in
the
taconite
ore
concentrate.
Pellet
cooler
vent
stacks
means
atmospheric
vents
in
the
cooler
section
of
the
grate
kiln
indurating
furnace
that
exhaust
cooling
air
that
is
not
returned
for
recuperation.
Pellet
cooler
vent
stacks
are
not
to
be
confused
with
the
cooler
discharge
stack,
which
is
in
the
pellet
loadout
or
dumping
area.
Pellet
loading
area
means
that
portion
of
a
taconite
iron
ore
processing
plant
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December
18,
2002
/
Proposed
Rules
where
taconite
pellets
are
loaded
into
trucks
or
railcars.
Responsible
official
means
responsible
official
as
defined
in
§
63.2.
Screen
means
a
device
for
separating
material
according
to
size
by
passing
undersize
material
through
one
or
more
mesh
surfaces
(
screens)
in
series
and
retaining
oversize
material
on
the
mesh
surfaces
(
screens).
Storage
bin
means
a
facility
for
storage
(
including
surge
bins
and
hoppers)
of
taconite
ore
or
taconite
pellets
prior
to
further
processing
or
loading.
Straight
grate
indurating
furnace
means
a
furnace
system
that
consists
of
a
traveling
grate
that
carries
the
taconite
pellets
through
different
furnace
temperature
zones.
In
the
straight
grate
indurating
furnace
a
layer
of
fired
pellets,
called
the
hearth
layer,
is
placed
on
the
traveling
grate
prior
to
the
addition
of
unfired
pellets.
The
straight
grate
indurating
furnace
begins
at
the
point
where
the
grate
feed
conveyor
discharges
the
green
balls
onto
the
furnace
traveling
grate
and
ends
where
the
hardened
pellets
drop
off
of
the
traveling
grate.
Taconite
iron
ore
processing
means
the
separation
and
concentration
of
iron
ore
from
taconite,
a
low
grade
iron
ore,
to
produce
taconite
pellets.
Taconite
ore
means
a
low
grade
iron
ore
suitable
for
concentration
of
magnetite
or
hematite
by
fine
grinding
and
magnetic
or
flotation
treatment,
from
which
pellets
containing
iron
can
be
produced.
Tailings
basin
means
a
natural
or
artificial
impoundment
in
which
gangue
or
other
refuse
material
resulting
from
the
washing,
concentration
or
treatment
of
ground
taconite
iron
ore
is
confined.
Wet
grinding
and
milling
means
the
process
where
wet
taconite
ore
is
finely
ground
using
rod
and/
or
ball
mills.
Tables
to
Subpart
RRRRR
of
Part
63
As
required
in
§
63.9590(
a),
you
must
comply
with
each
applicable
emission
limit
in
the
following
table:
TABLE
1
TO
SUBPART
RRRRR
OF
PART
63.
EMISSION
LIMITS
For
.
.
.
You
must
comply
with
each
of
the
following
.
.
.
1.
Existing
ore
crushing
and
handling
emission
units.
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
ore
crushing
and
handling
emission
units,
as
determined
using
the
procedures
in
§
63.9621(
b),
must
not
exceed
0.008
grains
per
dry
standard
cubic
foot
(
gr/
dscf).
2.
New
ore
crushing
and
handling
emission
units.
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
ore
crushing
and
handling
emission
units,
as
determined
using
the
procedures
in
§
63.9621(
b),
must
not
exceed
0.005
gr/
dscf.
3.
Each
existing
straight
grate
indurating
furnace
processing
magnetite.
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
stacks,
as
determined
using
the
procedures
in
§
63.9621(
c),
must
not
exceed
0.010
gr/
dscf.
4.
Each
new
straight
grate
indurating
furnace
processing
magnetite.
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
stacks,
as
determined
using
the
procedures
in
§
63.9621(
c),
must
not
exceed
0.006
gr/
dscf.
5.
Each
existing
grate
kiln
indurating
furnace
processing
magnetite.
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
stacks,
as
determined
using
the
procedures
in
§
63.9621(
c),
must
not
exceed
0.011
gr/
dscf.
6.
Each
new
grate
kiln
indurating
furnace
processing
magnetite.
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
stacks,
as
determined
using
the
procedures
in
§
63.9621(
c),
must
not
exceed
0.006
gr/
dscf.
7.
Each
existing
grate
kiln
indurating
furnace
processing
hematite.
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
stacks,
as
determined
using
the
procedures
in
§
63.9621(
c),
must
not
exceed
0.025
gr/
dscf.
8.
Each
new
grate
kiln
indurating
furnace
processing
hematite.
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
stacks,
as
determined
using
the
procedures
in
§
63.9621(
c),
must
not
exceed
0.018
gr/
dscf.
9.
Existing
finished
pellet
handling
emission
units.
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
finished
pellet
handling
emission
units,
as
determined
using
the
procedures
in
§
63.9621(
b),
must
not
exceed
0.008
gr/
dscf.
10.
New
finished
pellet
handling
emission
units
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
finished
pellet
handling
emission
units,
as
determined
using
the
procedures
in
§
63.9621(
b),
must
not
exceed
0.005
gr/
dscf.
11.
Each
existing
ore
dryer
................................
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
stacks,
as
determined
using
the
procedures
in
§
63.9621(
c),
must
not
exceed
0.052
gr/
dscf.
12.
Each
new
ore
dryer
......................................
The
flow
weighted
mean
concentration
of
particulate
matter
discharged
to
the
atmosphere
from
all
stacks,
as
determined
using
the
procedures
in
§
63.9621(
c),
must
not
exceed
0.025
gr/
dscf.
As
required
in
§
63.9650,
you
must
comply
with
the
requirements
of
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A)
shown
in
the
following
table:
TABLE
2
TO
SUBPART
RRRRR
OF
PART
63.
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
RRRRR
OF
PART
63
Citation
Subject
Applies
to
Subpart
RRRRR
Explanation
§
63.1
.....................................................
Applicability
..........................................
Yes.
§
63.2
.....................................................
Definitions
............................................
Yes.
§
63.3
.....................................................
Units
and
Abbreviations
.......................
Yes.
§
63.4
.....................................................
Prohibited
Activities
.............................
Yes.
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Vol.
67,
No.
243
/
Wednesday,
December
18,
2002
/
Proposed
Rules
TABLE
2
TO
SUBPART
RRRRR
OF
PART
63.
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
RRRRR
OF
PART
63
Continued
Citation
Subject
Applies
to
Subpart
RRRRR
Explanation
§
63.5
.....................................................
Construction/
Reconstruction
................
Yes.
§
63.6(
a)
(
g)
..........................................
Compliance
with
Standards
and
Maintenance
Requirements.
Yes.
§
63.6(
h)
................................................
Compliance
with
Opacity
and
Visible
Emission
(
VE)
Standards.
No
............................
Subpart
RRRRR
does
not
contain
opacity
and
VE
standards.
§
63.6(
i),(
j)
.............................................
Extension
of
Compliance
and
Presidential
Compliance
Extension.
Yes.
§
63.7(
a)(
1)
(
2)
.....................................
Applicability
and
Performance
Test
Dates.
No
............................
Subpart
RRRRR
specifies
performance
test
applicability
and
dates.
§
63.7(
a)(
3),
(
b)
(
h)
...............................
Performance
Testing
Requirements
....
Yes.
§
63.8(
a)(
1)
(
a)(
3),
(
b),
(
c)(
1)
(
3),
(
c)(
5)
(
8),
(
d),(
e),
(
f)(
1)
(
5),
(
g)(
1)
(
4).
Monitoring
Requirements
.....................
Yes
..........................
Continuous
monitoring
system
(
CMS)
requirements
in
§
63.8(
c)(
5)
and
(
6)
apply
only
to
COMS
for
dry
electrostatic
precipitators.
§
63.8(
a)(
4)
............................................
Additional
Monitoring
Requirements
for
Control
Devices
in
§
63.11.
No
............................
Subpart
RRRRR
does
not
require
flares.
§
63.8(
c)(
4)
............................................
Continuous
Monitoring
System
Requirements
No
............................
Subpart
RRRRR
specifies
requirements
for
operation
of
CMS.
§
63.8(
f)(
6)
.............................................
Relative
Accuracy
Test
Alternative
(
RATA).
No
............................
Subpart
RRRRR
does
not
require
continuous
emission
monitoring
systems
§
63.8(
g)(
5)
............................................
Data
Reduction
....................................
No
............................
Subpart
RRRRR
specifies
data
reduction
requirements.
§
63.9
.....................................................
Notification
Requirements
....................
Yes
..........................
Additional
notifications
for
CMS
in
§
63.9(
g)
apply
to
COMS
for
dry
electrostatic
precipitators.
§
63.10(
a),
(
b)(
1)
(
2)(
xii),
(
b)(
2)(
xiv),
(
b)(
3),(
c)(
1)
(
6)
(
c)(
9)
(
15),
(
d)(
1)
(
2),
(
d)(
4)
(
5),
(
e),
(
f).
Recordkeeping
and
Reporting
Requirements
Yes
..........................
Additional
records
for
CMS
§
63.10(
c)
(
1)
(
6),(
9)
(
15),
and
reports
in
§
63.10(
d)(
1)
(
2)
apply
only
to
COMS
for
dry
electrostatic
precipitators.
§
63.10(
b)(
2)(
xiii)
...................................
CMS
Records
for
RATA
Alternative
....
No
............................
Subpart
RRRRR
doesn't
require
continuous
emission
monitoring
systems
§
63.10(
c)(
7)
(
8)
....................................
Records
of
Excess
Emissions
and
Parameter
Monitoring
Exceedances
for
CMS.
No
............................
Subpart
RRRRR
specifies
record
requirements
§
63.10(
d)(
3)
..........................................
Reporting
opacity
or
VE
observations
No
............................
Subpart
RRRRR
does
not
have
opacity
and
VE
standards
§
63.11
...................................................
Control
Device
Requirements
..............
No
............................
Subpart
RRRRR
does
not
require
flares.
§
63.12
...................................................
State
Authority
and
Delegations
..........
Yes
§
63.13
§
63.15
....................................
Addresses,
Incorporation
by
Reference
Availability
of
Information.
Yes
[
FR
Doc.
02
31231
Filed
12
17
02;
8:
45
am]
BILLING
CODE
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| epa | 2024-06-07T20:31:40.034759 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0039-0001/content.txt"
} |
EPA-HQ-OAR-2002-0048-0001 | Proposed Rule | "2002-04-24T04:00:00" | National Emission Standards for Hazardous Air
Pollutants: Surface Coating of Metal Furniture; Proposed
Rule | Wednesday,
April
24,
2002
Part
II
Environmental
Protection
Agency
40
CFR
Part
63
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Surface
Coating
of
Metal
Furniture;
Proposed
Rule
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[FRL–
7163–
6]
RIN
2060–
AG55
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Surface
Coating
of
Metal
Furniture
AGENCY:
Environmental
Protection
Agency
(EPA).
ACTION:
Proposed
rule.
SUMMARY:
This
action
proposes
national
emission
standards
for
hazardous
air
pollutants
(NESHAP)
for
metal
furniture
surface
coating
operations
located
at
major
sources
of
hazardous
air
pollutant
(HAP)
emissions.
These
proposed
standards
would
implement
section
112(
d)
of
the
Clean
Air
Act
(CAA)
by
requiring
these
operations
to
meet
HAP
emission
standards
reflecting
the
application
of
the
maximum
achievable
control
technology
(MACT).
The
primary
HAP
emitted
by
these
operations
are
xylene,
toluene,
glycol
ethers,
2
butoxy
ethanol,
ethylbenzene,
and
methyl
ethyl
ketone.
Each
of
the
HAP
can
cause
toxic
effects
such
as
eye,
nose,
throat,
and
skin
irritation,
and
blood
cell,
heart,
liver,
and
kidney
damage.
Implementation
of
the
proposed
standards
would
reduce
nationwide
HAP
emissions
from
major
sources
by
about
70
percent.
DATES:
Comments.
Submit
comments
on
or
before
June
24,
2002.
Public
Hearing.
If
anyone
wishes
to
contact
EPA
to
request
to
speak
at
a
public
hearing,
they
should
do
so
by
May
14,
2002.
If
requested,
a
public
hearing
will
be
held
within
approximately
30
days
following
publication
of
this
notice
in
the
Federal
Register.
ADDRESSES:
Comments.
By
U.
S.
Postal
Service,
send
comments
(in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(6102),
Attention
Docket
Number
A–
97–
40,
U.
S.
Environmental
Protection
Agency,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460.
In
person
or
by
courier,
deliver
comments
(in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(6102),
Attention
Docket
Number
A–
97–
40,
U.
S.
Environmental
Protection
Agency,
401
M
Street,
SW.,
Room
M–
1500,
Washington,
DC
20460.
The
EPA
requests
a
separate
copy
also
be
sent
to
the
contact
person
listed
in
FOR
FURTHER
INFORMATION
CONTACT.
Public
Hearing.
If
a
public
hearing
is
held,
it
will
be
held
at
our
Office
of
Administration
Auditorium
in
Research
Triangle
Park,
North
Carolina.
You
should
contact
Ms.
Janet
Eck,
Coatings
and
Consumer
Products
Group,
Emission
Standards
Division
(C539–
03),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
North
Carolina
27711,
telephone
number
(919)
541–
7946,
to
request
to
speak
at
a
public
hearing
or
to
find
out
if
a
hearing
will
be
held.
Docket.
Docket
No.
A–
97–
40
contains
supporting
information
used
in
developing
the
proposed
standards.
The
docket
is
located
at
the
U.
S.
Environmental
Protection
Agency,
401
M
Street,
SW.,
Washington,
DC
20460
in
Room
M–
1500,
Waterside
Mall
(ground
floor),
and
may
be
inspected
from
8:
30
a.
m.
to
5:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
FOR
FURTHER
INFORMATION
CONTACT:
Dr.
Mohamed
Serageldin,
Coatings
and
Consumer
Products
Group,
Emission
Standards
Division
(C539–
03),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC
27711;
telephone
number
(919)
541–
2379;
facsimile
number
(919)
541–
5689;
electronic
mail
(e
mail)
address:
serageldin.
mohamed@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Comments.
Comments
and
data
may
be
submitted
by
e
mail
to:
a
and
rdocket
epa.
gov.
Electronic
comments
must
be
submitted
as
an
ASCII
file
to
avoid
the
use
of
special
characters
and
encryption
problems
and
will
also
be
accepted
on
disks
in
WordPerfect
file
format.
All
comments
and
data
submitted
in
electronic
form
must
note
the
docket
number:
A–
97–
40.
No
confidential
business
information
(CBI)
should
be
submitted
by
e
mail.
Electronic
comments
may
be
filed
online
at
many
Federal
Depository
Libraries.
Commenters
wishing
to
submit
proprietary
information
for
consideration
must
clearly
distinguish
such
information
from
other
comments
and
clearly
label
it
as
CBI.
Send
submissions
containing
such
proprietary
information
directly
to
the
following
address,
and
not
to
the
public
docket,
to
ensure
that
proprietary
information
is
not
inadvertently
placed
in
the
docket:
Dr.
Mohamed
Serageldin,
c/
o
OAQPS
Document
Control
Officer
(C404–
02),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC
27711.
The
EPA
will
disclose
information
identified
as
CBI
only
to
the
extent
allowed
by
the
procedures
set
forth
in
40
CFR
part
2.
If
no
claim
of
confidentiality
accompanies
a
submission
when
it
is
received
by
EPA,
the
information
may
be
made
available
to
the
public
without
further
notice
to
the
commenter.
Public
Hearing.
Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Ms.
Janet
Eck,
Coatings
and
Consumer
Products
Group,
Emission
Standards
Division
(C539–
03),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
North
Carolina
27711;
telephone
number
(919)
541–
7946
at
least
2
days
in
advance
of
the
public
hearing.
Persons
interested
in
attending
the
public
hearing
should
also
contact
Ms.
Eck
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
these
proposed
emission
standards.
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
because
material
is
added
throughout
the
rulemaking
process.
The
docketing
system
is
intended
to
allow
members
of
the
public
and
industries
involved
to
readily
identify
and
locate
documents
so
that
they
can
effectively
participate
in
the
rulemaking
process.
Along
with
the
proposed
and
promulgated
standards
and
their
preambles,
the
contents
of
the
docket
will
serve
as
the
record
in
the
case
of
judicial
review.
(See
section
307(
d)(
7)(
A)
of
the
CAA.)
The
regulatory
text
and
other
materials
related
to
this
rulemaking
are
available
for
review
in
the
docket
or
copies
may
be
obtained
by
mail
from
the
Air
and
Radiation
Docket
and
Information
Center
by
calling
(202)
260–
7548.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.
World
Wide
Web
(WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
this
proposed
rule
is
also
available
on
the
WWW
through
the
Technology
Transfer
Network
(TTN).
Following
signature
by
the
EPA
Administrator,
a
copy
of
the
proposed
rule
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(919)
541–
5384.
Regulated
Entities.
The
proposed
source
category
definition
includes
facilities
that
apply
coatings
to
metal
furniture
or
components
of
metal
furniture.
Metal
furniture
means
furniture
or
components
of
furniture
that
are
constructed
either
entirely
or
partially
from
metal.
Metal
furniture
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Federal
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/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
includes,
but
is
not
limited
to,
components
of
the
following
types
of
products
as
well
as
the
products
themselves:
household,
office,
institutional,
laboratory,
hospital,
public
building,
restaurant,
barber
and
beauty
shop,
and
dental
furniture;
office
and
store
fixtures;
partitions;
shelving;
lockers;
lamps
and
lighting
fixtures;
and
wastebaskets.
In
general,
facilities
that
coat
metal
furniture
are
covered
under
the
Standard
Industrial
Classification
(SIC)
and
North
American
Industrial
Classification
System
(NAICS)
codes
listed
in
table
1.
However,
facilities
classified
under
other
SIC
or
NAICS
codes
may
be
subject
to
the
proposed
regulation
if
they
meet
the
applicability
criteria.
Not
all
facilities
classified
under
the
SIC
and
NAICS
codes
in
table
1
will
be
subject
to
the
proposed
standard
because
some
of
the
classifications
cover
products
outside
the
scope
of
the
proposed
NESHAP
for
metal
furniture.
TABLE
1.—
METAL
FURNITURE
PRODUCT
DESCRIPTIONS
AND
CORRESPONDING
SIC
AND
NAICS
CODES
Product
description
1987
SIC
Code
Equivalent
1997
NAICS
Code(
s)
Equivalent
1997
NAICS
Product
Description
Metal
Household
Furniture
...................................................................
2514
337124
Metal
Household
Furniture
Manufacturing
Office
Furniture,
Except
Wood
.............................................................
2522
337214
Nonwood
Office
Furniture
Manufacturing.
Public
Building
and
Related
Furniture
.................................................
2531
337127
Institutional
Furniture
Manufacturing.
Office
and
Store
Fixtures,
Partitions,
Shelving,
and
Lockers,
Except
Wood.
2542
337215
Showcase,
Partition,
Shelving,
and
Locker
Manufacturing.
Furniture
and
Fixtures,
Not
Classified
Elsewhere
...............................
2599
337127
Institutional
Furniture
Manufacturing.
Hardware,
Not
Classified
Elsewhere
...................................................
3429
332951
Hardware
Manufacturing.
Metal
Stampings,
Not
Classified
Elsewhere
(Except
Kitchen
Utensils,
Pots
and
Pans
for
Cooking,
and
Coins).
3469
332116
Metal
Stamping.
Wire
Springs
.........................................................................................
3495
332612
Wire
Spring
Manufacturing.
Fabricated
Metal
Products,
Not
Classified
Elsewhere
.........................
3499
337215
Showcase,
Partition,
Shelving,
and
Locker
Manufacturing.
Residential
Electric
Lighting
Fixtures
...................................................
3645
335121
Residential
Electric
Lighting
Fixture
Manufacturing
Commercial,
Industrial,
and
Institutional
Electric
Lighting
Fixtures
.....
3646
335122
Commercial,
Industrial,
and
Institutional
Electric
Lighting
Fixture
Manufacturing.
Laboratory
Apparatus
and
Furniture
....................................................
3821
339111
Laboratory
Furniture
Manufacturing.
Dental
Equipment
and
Supplies
...........................................................
3843
339114
Dental
Equipment
Manufacturing.
Manufacturing
Industries,
Not
Classified
Elsewhere
...........................
3999
337127
Institutional
Furniture
Manufacturing.
Reupholster
and
Furniture
Repair
........................................................
7641
81142
Reupholstery
and
Furniture
Repair.
State/
Federal
Governmental
Agencies
................................................
......................
......................
State
correctional
institutions
and
military
installations
that
apply
coatings
to
metal
furniture.
This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
your
coating
operation
would
be
regulated
by
this
proposed
action,
you
should
examine
the
applicability
criteria
in
§
63.4881
of
the
proposed
rule.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:
I.
Background
A.
What
is
the
source
of
authority
for
development
of
NESHAP?
B.
What
criteria
are
used
in
the
development
of
NESHAP?
C.
What
are
the
health
effects
associated
with
HAP
emissions
from
the
surface
coating
of
metal
furniture?
II.
Summary
of
the
Proposed
Rule
A.
What
source
categories
would
be
affected
by
this
proposed
rule?
B.
What
is
the
relationship
to
other
rules?
C.
What
are
the
primary
sources
of
emissions
and
what
are
the
emissions?
D.
What
is
the
affected
source?
E.
What
are
the
proposed
emission
limits,
operating
limits,
and
other
standards?
F.
What
are
the
proposed
testing
and
initial
compliance
requirements?
G.
What
are
the
proposed
continuous
compliance
provisions?
H.
What
are
the
proposed
notification,
recordkeeping,
and
reporting
requirements?
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
did
we
select
the
source
category?
B.
How
did
we
select
the
regulated
pollutants?
C.
How
did
we
select
the
affected
source?
D.
How
did
we
determine
the
basis
and
level
of
the
proposed
standards
for
exisiting
and
new
sources?
E.
How
did
we
select
the
format
of
the
standards?
F.
How
did
we
select
the
testing
and
initial
compliance
requirements?
G.
How
did
we
select
the
continuous
compliance
requirements?
H.
How
did
we
select
the
notification,
recordkeeping,
and
reporting
requirements?
I.
How
did
we
select
the
compliance
date?
IV.
Summary
of
Environmental,
Energy,
and
Economic
Impacts
A.
What
are
the
air
impacts?
B.
What
are
the
cost
impacts?
C.
What
are
the
economic
impacts?
D.
What
are
the
nonair
health,
environmental,
and
energy
impacts?
V.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Executive
Order
13132,
Federalism
C.
Executive
Order
13175,
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Executive
Order
13211,
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
F.
Unfunded
Mandates
Reform
Act
of
1995
G.
Regulatory
Flexibility
Act,
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(SBREFA),
5
U.
S.
C.
601,
et
seq.
H.
Paperwork
Reduction
Act
I.
National
Technology
Transfer
and
Advancement
Act
I.
Background
A.
What
Is
the
Source
of
Authority
for
Development
of
NESHAP?
Section
112
of
the
CAA
requires
us
to
list
categories
and
subcategories
of
major
sources
and
certain
area
sources
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Vol.
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79
/
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April
24,
2002
/
Proposed
Rules
of
HAP
and
to
establish
NESHAP
for
the
listed
source
categories
and
subcategories.
The
Surface
Coating
of
Metal
Furniture
category
of
major
sources
was
listed
on
July
16,
1992
(57
FR
31576)
under
the
Surface
Coating
Processes
industry
group.
Major
sources
of
HAP
are
those
that,
considering
controls,
emit
or
have
the
potential
to
emit
equal
to,
or
greater
than,
10
tons
per
year
(tpy)
of
any
one
HAP
or
25
tpy
of
any
combination
of
HAP.
B.
What
Criteria
Are
Used
in
the
Development
of
NESHAP?
Section
112
of
the
CAA
requires
that
we
establish
NESHAP
for
the
control
of
HAP
from
both
new
and
existing
major
sources.
The
CAA
requires
the
NESHAP
to
reflect
the
maximum
degree
of
reduction
in
emissions
of
HAP
that
is
achievable.
This
level
of
control
is
commonly
referred
to
as
the
MACT.
The
MACT
floor
is
the
minimum
control
level
allowed
for
NESHAP
and
is
defined
under
section
112(
d)(
3)
of
the
CAA.
In
essence,
the
MACT
floor
ensures
that
the
standard
is
set
at
a
level
that
assures
that
all
major
sources
achieve
a
level
of
control
at
least
as
stringent
as
that
already
achieved
by
the
better
controlled
and
lower
emitting
sources
in
each
source
category
or
subcategory.
For
new
sources,
the
MACT
floor
cannot
be
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
bestcontrolled
similar
source.
The
MACT
standards
for
existing
sources
can
be
less
stringent
than
standards
for
new
sources,
but
they
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
bestperforming
12
percent
of
existing
sources
in
the
category
or
subcategory
(or
the
best
performing
five
sources
for
categories
or
subcategories
with
fewer
than
30
sources).
In
developing
MACT,
we
also
consider
control
options
that
are
more
stringent
than
the
floor.
We
may
establish
standards
more
stringent
than
the
floor
based
on
the
consideration
of
the
cost
of
achieving
the
emission
reductions,
any
nonair
quality
health
and
environmental
impacts,
and
energy
requirements.
C.
What
Are
the
Health
Effects
Associated
with
HAP
Emissions
From
the
Surface
Coating
of
Metal
Furniture?
The
major
HAP
emitted
from
the
surface
coating
of
metal
furniture
include
xylene,
toluene,
glycol
ethers,
2
butoxy
ethanol,
ethylbenzene,
and
methyl
ethyl
ketone.
These
compounds
account
for
about
90
percent
of
the
nationwide
HAP
emissions
from
this
source
category.
Other
HAP
identified
in
emissions
include
methyl
isobutyl
ketone,
hexane,
and
methylene
chloride.
These
pollutants
can
cause
reversible
or
irreversible
toxic
effects
following
sufficient
exposure.
The
potential
toxic
effects
include
eye,
nose,
throat,
and
skin
irritation;
nausea,
vomiting,
headache,
and
dizziness,
and
liver
and
kidney
damage.
The
degree
of
adverse
effects
to
human
health
from
exposure
to
HAP
can
range
from
mild
to
severe.
The
extent
and
degree
to
which
the
human
health
effects
may
be
experienced
are
dependent
upon
(1)
the
ambient
concentration
observed
in
the
area
(as
influenced
by
emission
rates,
meteorological
conditions,
and
terrain);
(2)
the
frequency
and
duration
of
exposures;
(3)
characteristics
of
exposed
individuals
(genetics,
age,
preexisting
health
conditions,
and
lifestyle),
which
vary
significantly
with
the
population;
and
(4)
pollutant
specific
characteristics
(toxicity,
half
life
in
the
environment,
bioaccumulation,
and
persistence).
II.
Summary
of
the
Proposed
Rule
A.
What
Source
Categories
Would
Be
Affected
by
This
Proposed
Rule?
The
proposed
rule
would
apply
to
you
if
you
own
or
operate
a
metal
furniture
surface
coating
facility
that
is
a
major
source,
or
is
located
at
a
major
source,
or
is
part
of
a
major
source
of
HAP
emissions.
We
have
defined
a
metal
furniture
surface
coating
facility
as
one
that
applies
coatings
to
metal
furniture
or
components
of
metal
furniture.
Metal
furniture
means
furniture
or
components
that
are
constructed
either
entirely
or
partially
from
metal.
You
would
not
be
subject
to
the
proposed
rule
if
your
metal
furniture
surface
coating
facility
is
located
at
an
area
source.
An
area
source
of
HAP
is
any
facility
that
has
the
potential
to
emit
HAP
but
is
not
a
major
source.
You
may
establish
area
source
status
by
limiting
the
source's
potential
to
emit
HAP
through
appropriate
mechanisms
available
through
the
permitting
authority.
You
would
not
be
subject
to
the
proposed
rule
if
you
use
only
coatings,
thinners,
and
cleaning
materials
that
contain
no
organic
HAP.
The
source
category
does
not
include
research
or
laboratory
facilities
or
janitorial,
building,
and
facility
maintenance
operations;
or
coating
application
using
handheld
nonrefillable
aerosol
containers.
B.
What
Is
the
Relationship
to
Other
Rules?
Affected
sources
subject
to
the
proposed
rule
may
also
be
subject
to
other
rules.
The
relationship
between
this
proposed
rule
and
other
rules
is
discussed
below.
We
specifically
request
comments
on
how
monitoring,
recordkeeping,
and
reporting
requirements
can
be
consolidated
for
sources
that
are
subject
to
more
than
one
rule.
We
also
request
comments
regarding
instances
where
a
facility
could
be
subject
to
multiple
surface
coating
NESHAP
or
where
the
applicability
of
one
NESHAP
versus
another
is
unclear.
Commenters
should
provide
specific
examples
of
these
instances
and
discuss
any
associated
adverse
effects
that
would
result.
New
Source
Performance
Standards—
40
CFR
Part
60,
Subpart
EE.
The
metal
furniture
new
source
performance
standards
(NSPS)
apply
to
facilities
that
apply
organic
coatings
to
metal
furniture
and
that
began
construction,
reconstruction,
or
modification
after
November
28,
1980.
The
pollutants
regulated
are
volatile
organic
compounds
(VOC).
Emissions
of
VOC
are
limited
to
0.09
kilogram
(kg)
per
liter
of
coating
solids
applied,
and
the
affected
source
is
each
individual
coating
operation.
The
proposed
rule
differs
from
the
NSPS
in
three
ways.
First,
the
affected
source
for
the
proposed
rule
is
defined
broadly
as
the
collection
of
all
coating
operations
and
related
activities
and
equipment
at
the
facility,
whereas
the
affected
facility
for
the
NSPS
is
defined
narrowly
as
each
individual
coating
operation.
This
broader
definition
of
affected
source
allows
a
facility's
emissions
to
be
combined
for
compliance
purposes.
Second,
the
proposed
rule
would
regulate
organic
HAP.
While
most
organic
HAP
emitted
from
metal
furniture
surface
coating
operations
are
VOC,
some
VOC
are
not
listed
as
HAP
and,
therefore,
the
NSPS
regulates
a
broader
range
of
pollutants
than
would
the
proposed
NESHAP.
Third,
the
emission
limitations
in
the
proposed
rule
would
be
based
on
the
amount
of
solids
used
at
the
affected
source.
The
NSPS
limitations
are
based
on
the
amount
of
solids
actually
applied
to
the
metal
furniture
which
necessitates
estimates
of
transfer
efficiency
in
the
compliance
calculations.
Because
of
the
differences
between
the
two
rules,
compliance
with
either
rule
cannot
be
deemed
compliance
with
the
other.
A
metal
furniture
surface
coating
facility
that
meets
the
applicability
requirements
of
both
rules
must
comply
with
both.
Overlapping
reporting,
recordkeeping,
and
monitoring
requirements
may
be
resolved
through
the
title
V
permit
process.
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
National
Emission
Standards
for
Wood
Furniture
Manufacturing
Operations—
40
CFR
Part
63,
Subpart
JJ.
There
may
be
situations
where
a
manufacturer
of
wood
furniture
also
coats
metal
components
of
that
wood
furniture.
The
coating
of
these
metal
components
would
be
subject
to
subpart
JJ,
the
rule
for
wood
furniture
manufacturing.
As
such,
the
proposed
rule
would
not
apply
to
these
facilities.
The
applicability
section
of
the
proposed
rule
clarifies
this
difference
in
applicability.
Future
national
emission
standards
for
the
surface
coating
of
miscellaneous
metal
parts.
Metal
furniture
often
contains
components,
such
as
metal
knobs,
hinges,
and
screws,
that
have
a
wider
use
beyond
metal
furniture.
The
coating
of
such
parts
would
not
be
subject
to
the
proposed
rule
provided
the
coating
takes
place
at
a
facility
that
does
not
apply
coatings
to
other
metal
furniture.
Such
metal
coating
operations
would
be
subject
to
the
future
NESHAP
for
the
surface
coating
of
miscellaneous
metal
parts.
Future
national
emission
standards
for
the
surface
coating
of
plastic
parts
and
products.
Plastic
parts
and
products
may
be
components
(e.
g.,
plastic
handles)
of
metal
furniture.
The
coating
of
such
plastic
parts
would
be
subject
to
the
proposed
rule
if
the
coating
takes
place
at
a
metal
furniture
surface
coating
facility;
otherwise,
the
coating
operation
would
be
subject
to
the
future
NESHAP
for
the
surface
coating
of
plastic
parts
and
products.
C.
What
Are
the
Primary
Sources
of
Emissions
and
What
Are
the
Emissions?
HAP
Emission
Sources.
Emissions
from
coating
application
account
for
more
than
60
percent
of
HAP
emissions
from
the
metal
furniture
surface
coating
process.
Remaining
emissions
are
primarily
from
cleaning.
In
most
cases,
HAP
emissions
from
mixing
and
storage
are
relatively
small.
The
organic
HAP
emissions
associated
with
coatings
(the
term
``
coatings''
includes
protective
and
functional
coatings,
as
well
as
adhesives)
occur
at
several
points.
A
coating
is
most
often
applied
by
using
a
spray
gun
in
a
spray
booth
or
by
dipping
the
substrate
in
a
tank
containing
the
coating.
In
a
spray
booth,
volatile
components
evaporate
from
the
coating
applied
to
the
part,
as
well
as
from
the
overspray.
The
coated
part
then
passes
through
an
open
(flash
off)
area
where
additional
volatiles
evaporate
from
the
coating.
The
coated
part
then
passes
through
a
drying/
curing
oven,
or
is
allowed
to
air
dry,
where
the
remaining
volatiles
are
evaporated.
Organic
HAP
emissions
also
occur
from
the
activities
undertaken
during
cleaning,
where
solvent
is
applied
to
remove
coating
residue
or
other
unwanted
materials.
Cleaning
in
this
industry
includes
cleaning
of
spray
guns
and
transfer
lines
(e.
g.,
tubing
or
piping),
tanks,
and
the
interior
of
spray
booths.
Cleaning
also
includes
applying
solvents
to
manufactured
parts
prior
to
coating
application
and
to
equipment
(e.
g.,
cleaning
rollers,
pumps,
conveyors,
etc.).
Mixing
and
Storage.
Organic
HAP
emissions
can
also
occur
from
displacement
of
organic
vapor
laden
air
in
containers
used
to
store
HAP
solvents
or
to
mix
coatings
containing
HAP
solvents.
The
displacement
of
organic
HAP
vapor
laden
air
can
occur
due
to
filling
of
containers,
temperature
or
barometric
pressure
changes,
or
due
to
agitation
during
mixing.
Organic
HAP.
Available
emission
data
collected
during
the
development
of
the
proposed
NESHAP
show
that
the
primary
organic
HAP
emitted
from
the
surface
coating
of
metal
furniture
include
xylene,
toluene,
glycol
ethers,
2
butoxy
ethanol,
ethylbenzene,
and
methyl
ethyl
ketone.
These
compounds
account
for
over
90
percent
of
this
category's
nationwide
organic
HAP
emissions.
Other
significant
organic
HAP
identified
include
methyl
isobutyl
ketone,
hexane,
and
methylene
chloride.
Inorganic
HAP.
Based
on
information
reported
in
survey
responses
during
the
development
of
the
proposed
NESHAP,
inorganic
HAP,
including
chromium,
lead,
and
manganese
compounds
are
contained
in
two
kinds
of
coatings
used
by
this
source
category.
No
inorganic
HAP
were
reported
in
cleaning
materials.
Nationwide
inorganic
HAP
emissions
are
estimated
to
be
less
than
5
megagrams
per
year
(Mg/
yr).
D.
What
Is
the
Affected
Source?
We
define
an
affected
source
as
a
stationary
source,
group
of
stationary
sources,
or
part
of
a
stationary
source
to
which
a
specific
emission
standard
applies.
This
proposed
rule
defines
the
affected
source
as
the
collection
of
all
operations
associated
with
the
surface
coating
of
metal
furniture
or
components
of
metal
furniture
that
are
performed
at
a
contiguous
area
under
common
control.
These
operations
include
preparation
of
a
coating
for
application
(e.
g.,
mixing
with
thinners);
surface
preparation
of
the
metal
furniture
or
component;
coating
application
and
flash
off;
drying
and/
or
curing
of
applied
coatings;
cleaning
of
equipment
used
in
surface
coating;
storage
of
coatings,
thinners,
and
cleaning
materials;
and
handling
and
conveyance
of
waste
materials
from
the
surface
coating
operations.
Coatings
include
such
materials
as
adhesives
and
protective
or
decorative
coatings.
E.
What
Are
the
Proposed
Emission
Limits,
Operating
Limits,
and
Other
Standards?
We
are
proposing
standards
that,
if
promulgated,
would
limit
HAP
emissions
from
the
surface
coating
of
metal
furniture.
The
proposed
standards
include
emission
limits
and
operating
limits.
Emission
Limits.
We
are
proposing
to
limit
organic
HAP
emissions
from
each
new
and
reconstructed
affected
source
to
no
more
than
0.094
kilogram
HAP
per
liter
of
coating
solids
used
(kg/
liter)
(0.78
pound
per
gallon
(lb/
gal))
each
calendar
month.
The
proposed
limit
for
each
existing
affected
source
is
0.12
kg
HAP/
liter
used
(1.0
lb/
gal).
You
would
choose
from
several
compliance
options
in
the
proposed
rule
to
achieve
the
emission
limit(
s).
You
could
comply
by
applying
materials
(coatings,
thinners,
and
cleaning
materials)
that
meet
the
emission
limit,
either
individually
or
collectively,
during
each
monthly
compliance
period.
You
could
also
use
a
capture
system
and
add
on
control
device
to
meet
the
emission
limit,
or
a
combination
of
both
approaches.
Operating
Limits.
If
you
reduce
emissions
by
using
a
capture
system
and
add
on
control
device
(other
than
a
solvent
recovery
system
for
which
you
conduct
a
monthly
liquid
liquid
material
balance),
the
proposed
operating
limits
would
apply
to
you.
These
limits
are
site
specific
parameter
limits
you
determine
during
the
initial
performance
test
of
the
system.
For
capture
systems,
you
would
establish
average
volumetric
flow
rate
limits
for
each
capture
device
(or
enclosure)
in
each
capture
system.
You
would
also
establish
limits
on
average
pressure
drop
across
openings
in
the
capture
system.
For
thermal
and
catalytic
oxidizers,
you
would
monitor
temperature.
For
solvent
recovery
systems
for
which
you
do
not
conduct
a
monthly
liquid
liquid
material
balance,
you
would
monitor
the
carbon
bed
temperature
and
the
amount
of
steam
or
nitrogen
used
to
desorb
the
bed.
For
condensers,
you
would
monitor
the
temperature
of
the
outlet
gas
temperature
from
the
condenser.
All
operating
limits
must
reflect
operation
of
the
capture
system
and
control
devices
during
a
performance
test
that
demonstrates
achievement
of
the
emission
limit
during
representative
operating
conditions.
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Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
General
Provisions.
The
General
Provisions
(40
CFR
part
63,
subpart
A)
also
would
apply
to
you
as
outlined
in
the
proposed
rule.
The
General
Provisions
codify
certain
procedures
and
criteria
for
all
40
CFR
part
63
NESHAP.
The
General
Provisions
contain
administrative
procedures,
preconstruction
review
procedures
for
new
sources,
and
procedures
for
conducting
compliance
related
activities
such
as
notifications,
reporting,
and
recordkeeping,
performance
testing,
and
monitoring.
The
proposed
rule
refers
to
individual
sections
of
the
General
Provisions
to
emphasize
key
sections
that
you
should
be
aware
of.
However,
unless
specifically
overridden
in
the
proposed
rule,
all
of
the
applicable
General
Provisions
requirements
would
apply
to
you.
F.
What
Are
the
Proposed
Testing
and
Initial
Compliance
Requirements?
Compliance
Dates.
Existing
affected
sources
would
have
to
be
in
compliance
with
the
final
standards
no
later
than
3
years
after
the
effective
date
of
the
subpart.
The
effective
date
is
the
date
on
which
the
final
rule
is
published
in
the
Federal
Register.
New
and
reconstructed
sources
would
have
to
be
in
compliance
upon
startup
of
the
affected
source
or
no
later
than
the
effective
date,
whichever
is
later.
The
proposed
initial
compliance
period
is
1
month
and
begins
on
the
compliance
date
and
ends
on
the
last
day
of
the
first
full
calendar
month
following
the
compliance
date;
except
that
for
new
and
reconstructed
sources
required
to
conduct
performance
tests,
it
ends
on
the
last
day
of
the
first
full
calendar
month
following
the
performance
test.
Being
``
in
compliance''
means
that
the
owner
or
operator
of
the
affected
source
meets
all
the
requirements
of
the
rule
to
achieve
the
proposed
emission
limit(
s)
and
operating
limits
by
the
end
of
the
initial
compliance
period.
At
the
end
of
the
initial
compliance
period,
the
owner
or
operator
would
use
the
data
and
records
generated
to
determine
whether
or
not
the
affected
source
is
in
compliance
for
that
period.
If
it
does
not
meet
the
applicable
limit(
s),
then
it
is
out
of
compliance
for
the
entire
initial
compliance
period.
Emission
Limit(
s).
There
are
several
proposed
options
for
complying
with
the
proposed
emission
limit(
s),
and
the
testing
and
initial
compliance
requirements
vary
accordingly.
If
you
demonstrate
compliance
based
on
the
materials
used
in
the
affected
source,
you
would
determine
the
mass
of
organic
HAP
and
the
volume
of
solids
in
all
materials
used
during
the
initial
compliance
period.
To
determine
the
mass
of
organic
HAP
in
coatings,
thinners,
and
cleaning
materials
and
the
volume
coating
solids,
you
could
either
rely
on
manufacturer's
data
or
on
results
from
the
test
methods
listed
below.
Under
§
63.4941
of
the
proposed
rule,
you
would
be
required
to
determine
the
mass
of
organic
HAP
in
coatings,
thinners,
and
cleaning
materials.
To
do
this,
you
would
count
HAP
that
are
present
at
1
percent
by
mass
or
more
if
they
are
not
carcinogens
identified
by
the
Occupational
Safety
and
Health
Administration
(OSHA)
at
29
CFR
1910.1200(
d)(
4),
and
count
HAP
that
are
present
at
0.1
percent
by
mass
or
more
if
they
are
OSHA
identified
carcinogens.
Coating
and
solvent
manufacturers
are
accustomed
to
providing
a
breakdown
of
material
components
according
to
this
distinction
and
routinely
report
the
values
on
Material
Safety
Data
Sheets
for
the
materials,
as
required
by
OSHA.
We
could
have
selected
some
other
way
to
count
HAP
components
of
materials
but
concluded
that
allowing
this
longstanding
approach
to
be
used
for
compliance
with
the
proposed
NESHAP
would
provide
the
information
needed
for
compliance
assurance
and
would
not
impose
any
additional
burden
on
the
industry.
We
request
comment
on
the
appropriateness
of
this
provision
of
the
proposed
rule.
You
may
use
alternative
test
methods
provided
you
get
EPA
approval
in
accordance
with
the
NESHAP
General
Provisions,
§
63.7(
f).
If
there
is
any
inconsistency
between
the
test
method
results
(either
EPA's
or
an
approved
alternative)
and
manufacturer's
data,
the
test
method
results
would
prevail
for
compliance
and
enforcement
purposes.
For
organic
HAP
content,
use
Method
311
of
40
CFR
part
63,
appendix
A;
The
proposed
rule
allows
you
to
use
nonaqueous
volatile
matter
as
a
surrogate
for
organic
HAP,
which
would
include
all
organic
HAP
plus
all
other
organic
compounds.
If
you
choose
this
option,
then
use
Method
24
of
40
CFR
part
60,
appendix
A;
and
For
volume
coating
solids,
use
either
manufacturer's
data
or
ASTM
Method
D2697–
86
(1998)
or
ASTM
Method
D6093–
97.
To
demonstrate
initial
compliance
based
on
the
materials
used,
you
would
be
required
to
either
ensure
that
the
organic
HAP
content
of
each
coating
meets
the
emission
limit
and
that
you
use
no
organic
HAP
containing
thinners
or
cleaning
materials;
or
ensure
that
the
total
mass
of
organic
HAP
in
all
coatings,
thinners,
and
cleaning
materials
divided
by
the
total
volume
of
coating
solids
meets
the
emission
limit.
For
the
latter
option,
you
would
be
required
to:
For
the
initial
compliance
period,
determine
the
quantity
of
each
coating,
thinner,
and
cleaning
material
used
in
the
affected
source.
Determine
the
mass
of
organic
HAP
in
each
coating,
thinner,
and
cleaning
material.
Determine
the
volume
fraction
solids
for
each
coating.
Calculate
the
total
mass
of
organic
HAP
for
materials
and
total
volume
of
coating
solids
used
in
the
affected
source
for
the
compliance
period.
You
may
subtract
from
the
total
mass
of
organic
HAP
the
amount
contained
in
waste
materials
you
send
to
a
hazardous
waste
treatment,
storage,
and
disposal
facility
(TSDF)
regulated
under
40
CFR
part
262,
264,
265,
or
266.
The
proposed
calculation
equation
(Equation
1
in
§
63.4951)
adds
together
all
the
organic
HAP
in
the
coatings,
thinners,
and
cleaning
materials
and
allows
you
to
subtract
organic
HAP
in
waste
materials
as
indicated
above.
The
calculated
mass
of
organic
HAP
is,
therefore,
not
based
on
actual
measurement
of
emissions
to
the
atmosphere
but
rather
assumes
that
all
organic
HAP
used
(less
those
in
waste
materials
as
appropriate)
are
emitted.
This
means
of
determining
organic
HAP
emissions
for
compliance
is
consistent
with
the
means
by
which
we
calculated
emission
rates
from
industry
data
on
which
the
proposed
emission
limits
are
based.
We
believe
that
Equation
1
is
a
simple
mass
balance
relationship
which
adequately
quantifies
the
organic
HAP
emissions
without
imposing
an
excessive
burden
on
respondents.
We
request
comment
on
our
approach
for
determining
emissions
and
on
any
alternatives.
Calculate
the
ratio
of
the
total
mass
of
organic
HAP
for
the
materials
used
to
the
total
volume
of
coating
solids
used.
Record
the
calculations
and
results
and
include
them
in
your
notification
of
compliance
status
(see
section
II.
H
of
this
preamble).
If
you
use
a
capture
system
and
control
device,
other
than
a
solvent
recovery
system
for
which
you
conduct
a
monthly
liquid
liquid
material
balance,
you
would:
Conduct
an
initial
performance
test
to
determine
the
capture
and
control
efficiencies
of
the
equipment
(described
below)
and
to
establish
operating
limits
to
be
achieved
on
a
continuous
basis
(also
described
below).
The
performance
test
would
have
to
be
completed
no
later
than
the
compliance
date
for
existing
sources
and
180
days
after
the
compliance
date
for
new
and
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Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
reconstructed
sources.
You
would
also
need
to
schedule
it
in
time
to
obtain
the
results
for
use
in
completing
your
compliance
determination
for
the
initial
compliance
period.
Determine
the
mass
of
organic
HAP
in
each
material
and
the
volume
fraction
coating
solids
for
each
coating
used
during
the
initial
compliance
period.
Calculate
the
organic
HAP
emissions
from
all
the
controlled
coating
operations
using
the
capture
and
control
efficiencies
determined
during
the
performance
test
and
the
total
mass
of
organic
HAP
in
materials
used
in
controlled
coating
operations.
Calculate
the
total
mass
of
organic
HAP
emissions
from
uncontrolled
coating
operations.
Calculate
the
ratio
of
the
total
mass
of
HAP
emissions
from
both
controlled
and
uncontrolled
coating
operations
to
the
total
volume
of
coating
solids
used
during
the
initial
compliance
period.
Record
the
calculations
and
results
and
include
them
in
your
Notification
of
Compliance
Status.
The
capture
and
control
efficiency
for
a
capture
and
control
system,
other
than
a
solvent
recovery
system
for
which
you
conduct
monthly
liquid
liquid
material
balances,
would
be
demonstrated
based
on
emission
capture
and
reduction
efficiency.
To
determine
the
capture
efficiency,
you
would
either
verify
the
presence
of
a
permanent
total
enclosure
using
EPA
Method
204
of
40
CFR
part
51,
appendix
M
(and
all
materials
must
be
applied
and
dried
within
the
enclosure),
or
use
one
of
three
protocols
in
§
63.4965
to
measure
capture
efficiency.
If
you
have
a
permanent
total
enclosure
and
all
materials
are
applied
and
dried
within
the
enclosure
and
you
route
all
exhaust
gases
from
the
enclosure
to
a
control
device,
then
you
would
assume
100
percent
capture.
To
determine
the
emission
reduction
efficiency
of
the
control
device,
you
would
conduct
measurements
of
the
inlet
and
outlet
gas
streams.
The
test
would
consist
of
three
runs,
each
run
lasting
1
hour,
using
the
following
EPA
Methods
in
40
CFR
part
60,
appendix
A:
Method
1
or
1A
for
selection
of
the
sampling
sites.
Method
2,
2A,
2C,
2D,
2F,
or
2G
to
determine
the
gas
volumetric
flow
rate.
Method
3,
3A,
or
3B
for
gas
analysis
to
determine
dry
molecular
weight.
Method
4
to
determine
stack
moisture.
Method
25
or
25A
to
determine
organic
volatile
matter
concentration.
In
lieu
of
Method
25
or
25A,
you
may
use
Method
18
if
you
know
the
HAP
constituents
in
the
inlet
and
outlet
gas
streams
and
you
quantify
at
least
90
percent
of
the
organic
compounds
in
the
gas
stream.
Alternatively,
any
other
test
method
or
data
that
have
been
validated
according
to
the
applicable
procedures
in
Method
301
of
40
CFR
part
63,
appendix
A,
and
approved
by
the
Administrator,
could
be
used.
If
you
use
a
solvent
recovery
system,
you
could
determine
the
overall
control
efficiency
using
a
liquid
liquid
material
balance
instead
of
conducting
an
initial
performance
test.
If
you
use
the
material
balance
alternative,
you
would
be
required
to
measure
the
amount
of
all
materials
used
in
the
affected
source
during
the
initial
compliance
period
and
determine
the
total
volatile
matter
contained
in
these
materials.
You
would
also
measure
the
amount
of
volatile
matter
recovered
by
the
solvent
recovery
system
during
the
compliance
period.
Then
you
would
compare
the
amount
recovered
to
the
amount
used
to
determine
the
overall
control
efficiency,
and
apply
this
efficiency
to
the
organic
HAP
to
solids
ratio
for
the
materials
used.
You
would
record
the
calculations
and
results
and
include
them
in
your
Notification
of
Compliance
Status.
Operating
Limits.
In
accordance
with
section
114(
a)
of
the
CAA,
the
proposed
operating
limits
would
require
the
use
of
continuous
parameter
monitoring
systems
(CPMS)
to
ensure
that
sources
are
in
compliance.
The
monitoring
must
be
capable
of
detecting
deviations
with
sufficient
representativeness,
accuracy,
precision,
reliability,
frequency,
and
timeliness
to
determine
if
compliance
is
continuous
during
a
reporting
period.
As
mentioned
above,
you
would
establish
operating
limits
as
part
of
the
initial
performance
test
of
a
capture
system
and
control
device,
other
than
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances.
The
operating
limits
are
the
minimum
or
maximum
(as
applicable)
values
achieved
for
capture
systems
and
control
devices
during
the
most
recent
performance
test
that
demonstrated
compliance
with
the
emission
limit.
If
you
operate
your
capture
system
and
control
device
at
different
sets
of
representative
operating
conditions,
you
must
establish
operating
limits
for
the
parameters
for
each
different
operating
condition.
The
proposed
rule
specifies
the
parameters
to
monitor
for
the
types
of
emission
control
systems
commonly
used
in
the
industry.
You
would
be
required
to
install,
calibrate,
maintain,
and
continuously
operate
all
monitoring
equipment
according
to
manufacturer's
specifications
and
ensure
that
the
CPMS
meet
the
requirements
in
§
63.4968
of
the
proposed
rule.
If
you
use
control
devices
other
than
those
identified
in
the
proposed
rule,
you
would
submit
the
operating
parameters
to
be
monitored
to
the
Administrator
for
approval.
The
authority
to
approve
the
parameters
to
be
monitored
is
retained
by
the
EPA
and
is
not
delegated
to
States.
We
request
comment
on
whether
there
are
alternative
means
of
monitoring
performance
for
add
on
controls
which
would
be
appropriate.
Commenters
should
address
the
relative
effectiveness
and
cost
of
alternatives.
If
you
use
a
thermal
or
catalytic
oxidizer,
you
would
continuously
monitor
temperature
and
record
it
at
least
every
15
minutes.
For
thermal
oxidizers,
the
temperature
monitor
is
placed
in
the
firebox
or
in
the
duct
immediately
downstream
of
the
firebox
before
any
substantial
heat
exchange
occurs.
The
operating
limit
would
be
the
average
temperature
measured
during
the
performance
test,
and
during
each
3
hour
period
the
average
temperature
would
have
to
be
at
or
above
this
limit.
For
catalytic
oxidizers,
temperature
monitors
are
placed
immediately
before
and
after
the
catalyst
bed.
The
operating
limits
would
be
the
average
combustion
temperature
just
before
the
catalyst
bed
and
the
average
temperature
difference
across
the
catalyst
bed
during
the
performance
test,
and
for
each
3
hour
period
the
average
combustion
temperature
and
the
average
temperature
difference
would
have
to
be
at
or
above
these
limits.
If
you
use
a
solvent
recovery
system,
and
do
not
conduct
liquid
liquid
material
balances
to
demonstrate
compliance,
then
you
would
monitor
the
carbon
bed
temperature
after
each
regeneration
and
the
total
amount
of
steam
or
nitrogen
used
to
desorb
the
bed
for
each
regeneration.
The
operating
limits
would
be
the
carbon
bed
temperature
(not
to
be
exceeded)
and
the
amount
of
steam
or
nitrogen
used
for
desorption
(to
be
met
as
a
minimum).
If
you
use
a
condenser,
you
would
monitor
the
outlet
gas
temperature
to
ensure
that
the
air
stream
is
being
cooled
to
a
low
enough
temperature.
The
operating
limit
would
be
the
average
condenser
outlet
gas
temperature
measured
during
the
performance
test,
and
for
each
3
hour
period
the
average
temperature
would
have
to
be
at
or
below
this
limit.
For
each
capture
system,
you
would
establish
operating
limits
for
gas
volumetric
flow
rate
and
pressure
drop
across
an
opening
in
each
enclosure
or
capture
device.
The
operating
limit
would
be
the
average
volumetric
flow
rate
and
average
pressure
drop
across
the
opening
during
the
performance
test,
to
be
met
as
a
minimum.
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
We
request
comment
on
the
proposed
testing
and
initial
compliance
requirements
discussed
above.
G.
What
Are
the
Proposed
Continuous
Compliance
Provisions?
Emission
Limit(
s)
If
you
demonstrate
compliance
with
the
proposed
emission
limit(
s)
based
on
the
materials
used
in
the
affected
source,
you
would
ensure,
for
each
monthly
compliance
period,
that
the
ratio
of
organic
HAP
to
coating
solids
meets
the
emission
limit.
You
would
follow
the
same
procedures
as
you
would
for
the
initial
compliance
period,
as
described
in
section
II.
F
of
this
preamble.
For
each
coating
operation
on
which
you
use
a
capture
system
and
control
device,
other
than
solvent
recovery
for
which
you
conduct
a
monthly
liquidliquid
material
balance,
you
would
use
the
continuous
parameter
monitoring
results
for
the
month
in
determining
the
mass
of
organic
HAP
emissions.
If
the
monitoring
results
indicate
no
deviations
from
the
operating
limits
and
there
were
no
bypasses
of
the
control
device,
then
you
would
assume
the
capture
system
and
control
device
is
achieving
the
same
percent
emission
reduction
efficiency
as
it
did
during
the
performance
test.
You
would
then
apply
this
percent
reduction
to
the
total
mass
of
organic
HAP
in
materials
used
in
controlled
coating
operations
to
determine
the
monthly
emission
rate
from
those
operations.
If
there
were
any
deviations
from
the
operating
limits
during
the
month
or
any
bypasses
of
the
control
device,
you
would
account
for
them
in
the
calculation
of
the
monthly
emission
rate
by
assuming
the
capture
system
and
control
device
were
achieving
zero
emission
reduction
during
the
periods
of
deviation.
For
each
coating
operation
on
which
you
use
a
solvent
recovery
system
and
conduct
a
liquid
liquid
material
balance
each
month,
you
would
use
the
liquidliquid
material
balance
to
determine
control
efficiency.
To
determine
the
overall
control
efficiency,
you
must
measure
the
amount
of
all
materials
applied
during
each
month
and
determine
the
volatile
matter
content
of
these
materials.
You
must
also
measure
the
amount
of
volatile
matter
recovered
by
the
solvent
recovery
system
during
the
month,
calculate
the
overall
control
efficiency,
and
apply
it
to
the
total
mass
of
organic
HAP
in
the
materials
used
to
determine
total
organic
HAP
emissions.
The
monthly
emission
rate
for
your
affected
source
would
be
the
total
mass
of
organic
HAP
emissions
from
all
controlled
and
uncontrolled
coating
operations
divided
by
the
total
volume
of
coating
solids
used
during
the
compliance
period.
Operating
Limits.
If
you
use
a
capture
system
and
control
device,
the
proposed
rule
would
require
you
to
achieve
on
a
continuous
basis
the
operating
limits
you
establish
during
the
performance
test
described
in
section
II.
F
of
this
preamble.
If
the
continuous
monitoring
shows
that
the
capture
system
and
control
device
is
operating
outside
the
range
of
values
established
during
the
performance
test,
then
you
have
deviated
from
the
established
operating
limits.
If
you
operate
a
capture
system
and
control
device
that
allows
emissions
to
bypass
the
control
device,
you
would
have
to
demonstrate
that
HAP
emissions
from
each
emission
point
within
the
affected
source
are
being
routed
to
the
control
device
by
monitoring
for
potential
bypass
of
the
control
device.
You
may
choose
from
the
following
four
monitoring
procedures:
(1)
Flow
control
position
indicator
to
provide
a
record
of
whether
the
exhaust
stream
is
directed
to
the
control
device;
(2)
Car
seal
or
lock
and
key
valve
closures
to
secure
the
bypass
line
valve
in
the
closed
position
when
the
control
device
is
operating;
(3)
Valve
closure
continuous
monitoring
to
ensure
any
bypass
line
valve
or
damper
is
closed
when
the
control
device
is
operating;
or
(4)
Automatic
shutdown
system
to
stop
the
coating
operation
when
flow
is
diverted
from
the
control
device.
If
the
bypass
monitoring
procedures
indicate
that
emissions
are
not
routed
to
the
control
device,
then
you
have
deviated
from
the
emission
limit.
Operations
During
Startup,
Shutdown,
and
Malfunction.
If
you
use
a
capture
system
and
control
device
for
compliance,
you
would
be
required
to
develop
and
operate
according
to
a
startup,
shutdown,
and
malfunction
plan
during
periods
of
startup,
shutdown,
and
malfunction
of
the
capture
system
and
control
device.
Emissions
Reductions
Plan
for
Mixing,
Storage,
and
Waste
Handling.
If
you
use
a
capture
system
and
control
device
for
compliance,
you
would
be
required
to
develop
and
operate
according
to
a
plan
for
reducing
emissions
from
mixing
operations,
storage
tanks
or
other
containers,
and
waste
handling
operations.
This
plan
would
include
a
description
of
all
steps
taken
to
minimize
emissions
from
these
sources
(e.
g.,
using
closed
storage
containers,
practices
to
minimize
emissions
during
filling
and
transfer
of
contents
from
containers,
using
spill
minimization
techniques,
placing
solvent
laden
cloth
in
closed
containers
immediately
after
use,
etc.).
If
you
do
not
develop
a
plan
or
you
do
not
implement
the
plan,
this
would
be
a
deviation
from
the
work
practice
standard.
We
request
comment
on
the
proposed
continuous
compliance
requirements
discussed
above.
H.
What
Are
the
Proposed
Notification,
Recordkeeping,
and
Reporting
Requirements?
You
would
be
required
to
comply
with
the
applicable
requirements
in
the
NESHAP
General
Provisions,
subpart
A
of
40
CFR
part
63,
as
described
in
the
proposed
rule.
The
General
Provisions
notification
requirements
include:
(1)
Initial
notifications,
(2)
notification
of
performance
test
if
you
are
complying
using
a
capture
system
and
control
device,
(3)
notification
of
compliance
status,
and
(4)
additional
notifications
required
for
affected
sources
with
continuous
monitoring
systems.
The
General
Provisions
also
require
certain
records
and
periodic
reports.
Initial
Notifications.
If
the
proposed
standards
apply
to
you,
you
would
be
required
to
send
a
notification
to
the
EPA
Regional
Office
in
the
region
where
your
facility
is
located
and
to
your
State
agency
at
least
1
year
before
the
compliance
date
for
existing
sources
and
within
120
days
after
the
date
of
initial
startup
for
new
and
reconstructed
sources,
or
120
days
after
publication
of
the
final
rule,
whichever
is
later.
This
report
notifies
us
and
your
State
agency
that
you
have
an
existing
facility
that
is
subject
to
the
proposed
standard
or
that
you
have
constructed
a
new
facility.
Thus,
it
allows
you
and
the
permitting
authority
to
plan
for
compliance
activities.
You
would
also
need
to
send
a
notification
of
planned
construction
or
reconstruction
of
a
source
that
would
be
subject
to
the
rule
and
apply
for
approval
to
construct
or
reconstruct.
Notification
of
Performance
Test.
If
you
demonstrate
compliance
by
using
a
capture
system
and
control
device
for
which
you
do
not
conduct
a
monthly
liquid
liquid
material
balance,
you
would
be
required
to
conduct
a
performance
test,
as
described
in
section
II.
F
of
this
preamble,
no
later
than
the
compliance
date
for
your
affected
source.
You
would
be
required
to
notify
your
EPA
Regional
Office
(or
the
delegated
State
or
local
agency)
at
least
60
calendar
days
before
the
performance
test
is
scheduled
to
begin,
as
indicated
in
the
General
Provisions
for
the
NESHAP.
Notification
of
Compliance
Status.
Your
compliance
procedures
would
depend
on
which
compliance
option
you
choose.
For
each
compliance
option,
you
would
send
us
a
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
Notification
of
Compliance
Status
within
30
days
after
the
end
of
the
initial
compliance
period
described
in
section
II.
F
of
this
preamble.
In
the
notification,
you
would
certify
whether
the
affected
source
has
complied
with
the
standards,
identify
the
option
you
used
to
demonstrate
initial
compliance,
summarize
the
data
and
calculations
supporting
the
compliance
demonstration,
and
describe
how
you
will
determine
continuous
compliance.
If
you
elect
to
comply
by
using
a
capture
system
and
control
device
for
which
you
conduct
performance
tests,
you
must
provide
the
results
of
the
tests.
Your
notification
would
also
include
the
measured
range
of
each
monitored
parameter
and
the
operating
limits
established
during
the
performance
test,
and
information
showing
whether
the
source
has
achieved
its
operating
limits
during
the
initial
compliance
period.
Recordkeeping
Requirements.
You
would
be
required
to
keep
records
of
reported
information
and
all
other
information
necessary
to
document
compliance
with
the
proposed
rule
for
5
years.
As
required
under
the
General
Provisions,
records
for
the
2
most
recent
years
would
be
required
to
be
kept
onsite
the
other
3
years'
records
could
be
kept
off
site.
Records
pertaining
to
the
design
and
operation
of
the
control
and
monitoring
equipment
would
have
to
be
kept
for
the
life
of
the
equipment.
Depending
on
the
compliance
option
that
you
choose,
you
could
need
to
keep
records
of
the
following:
Organic
HAP
content,
volatile
matter
content,
solids
content,
and
quantity
of
the
coatings,
thinners,
and
cleaning
materials
used
during
each
compliance
period;
All
documentation
supporting
initial
notifications
and
notifications
of
compliance
status.
If
you
demonstrate
compliance
by
using
a
capture
system
and
control
device,
you
would
also
need
to
keep
records
of
the
following:
The
occurrence
and
duration
of
each
startup,
shutdown,
or
malfunction
of
the
emission
capture
system
and
control
device;
All
maintenance
performed
on
the
capture
system
and
control
device;
Actions
taken
during
startup,
shutdown,
and
malfunction
that
are
different
from
the
procedures
specified
in
the
affected
source's
startup,
shutdown,
and
malfunction
plan;
All
information
necessary
to
demonstrate
conformance
with
the
affected
source's
startup,
shutdown,
and
malfunction
plan
when
the
plan
procedures
are
followed;
All
information
necessary
to
demonstrate
conformance
with
the
affected
source's
plan
for
minimizing
emissions
from
mixing,
storage,
and
waste
handling
operations;
Each
period
during
which
a
CPMS
is
malfunctioning
or
inoperative
(including
out
of
control
periods);
All
required
measurements
needed
to
demonstrate
compliance
with
the
standards;
and
All
results
of
performance
tests.
The
proposed
rule
would
require
you
to
collect
and
keep
records
according
to
certain
minimum
data
requirements
for
the
CPMS.
Failure
to
collect
and
keep
the
specified
minimum
data
would
be
a
deviation
that
is
separate
from
any
emission
limit,
operating
limit,
or
work
practice
standard.
Deviations,
as
determined
from
these
records,
would
need
to
be
recorded
and
also
reported,
as
described
in
section
II.
H
of
this
preamble.
A
deviation
is
any
instance
when
any
requirement
or
obligation
established
by
the
proposed
rule
including,
but
not
limited
to,
the
emission
limit(
s),
operating
limits,
and
work
practice
standards,
is
not
met.
If
you
use
a
capture
system
and
control
device
to
reduce
HAP
emissions,
you
would
have
to
make
your
startup,
shutdown,
and
malfunction
plan
available
for
inspection
if
the
Administrator
requests
to
see
it.
It
would
stay
in
your
records
for
the
life
of
the
affected
source
or
until
the
source
is
no
longer
subject
to
the
standards.
If
you
revise
the
plan,
you
would
need
to
keep
the
previous
superceded
versions
on
record
for
5
years
following
the
revision.
Periodic
Reports.
Each
reporting
year
is
divided
into
two
semiannual
reporting
periods.
If
no
deviations
occur
during
a
semiannual
reporting
period,
you
would
submit
a
semiannual
report
stating
that
the
affected
source
has
been
in
continuous
compliance.
If
deviations
occur,
you
would
need
to
document
them
in
the
report
as
follows:
Report
each
deviation
from
the
monthly
emission
limit.
If
you
are
complying
by
using
a
thermal
oxidizer,
report
all
times
when
a
3
hour
average
temperature
is
below
the
operating
limit.
If
you
are
complying
by
using
a
catalytic
oxidizer,
report
all
times
when
a
3
hour
average
temperature
difference
across
the
catalyst
bed
is
below
the
operating
limit,
and
when
a
3
hour
average
combustion
temperature
before
the
catalyst
bed
is
below
the
operating
limit.
If
you
are
complying
by
using
oxidizers,
or
solvent
recovery
systems
where
liquid
liquid
material
balances
are
not
conducted,
report
all
times
when
the
value
of
the
site
specific
operating
parameter
used
to
monitor
the
capture
system
performance
was
less
than
the
operating
limit
established
for
the
capture
system.
If
you
are
complying
by
using
a
carbon
adsorber
for
which
you
do
not
conduct
liquid
liquid
material
balances,
report
all
times
when
the
steam
or
nitrogen
flow
is
less
than,
and/
or
the
carbon
bed
temperature
is
more
than,
the
operating
limits.
If
you
are
complying
by
using
a
condenser,
report
all
times
when
a
3
hour
average
outlet
temperature
is
higher
than
the
operating
limit.
If
your
capture
system
contains
bypass
lines
that
could
divert
emissions
from
the
control
device
to
the
atmosphere,
report
all
times
when
emissions
were
not
routed
to
the
control
device.
Report
other
specific
information
on
the
periods
of
time
the
deviations
occurred.
You
would
also
have
to
include
an
explanation
in
each
semiannual
report
if
a
change
occurs
that
might
affect
the
compliance
status
of
the
affected
source
or
you
change
to
another
option
for
meeting
the
emission
limit.
Other
Reports.
You
would
be
required
to
submit
reports
for
periods
of
startup,
shutdown,
and
malfunction
of
the
capture
system
and
control
device.
If
the
procedures
you
follow
during
any
startup,
shutdown,
or
malfunction
are
inconsistent
with
your
plan,
you
would
report
those
procedures
with
your
semiannual
reports
in
addition
to
the
immediate
reports
required
by
§
63.10(
d)(
5)(
ii).
We
request
comment
on
the
proposed
notification,
recordkeeping,
and
reporting
requirements
discussed
above.
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
Did
We
Select
the
Source
Category?
The
surface
coating
of
metal
furniture
is
a
source
category
that
is
on
the
list
of
source
categories
to
be
regulated
because
it
contains
major
sources
which
emit
or
have
the
potential
to
emit,
considering
controls,
at
least
10
tons
of
any
one
HAP
or
at
least
25
tons
of
any
combination
of
HAP
annually.
The
proposed
rule
would
control
HAP
emissions
from
both
new
and
existing
major
sources.
Area
sources
are
not
being
regulated
under
this
proposed
rule.
The
surface
coating
of
metal
furniture
as
described
in
the
listing
includes
any
facility
engaged
in
the
surface
coating
and
manufacture
or
repair
of
metal
furniture
parts
or
products
(including,
but
not
limited
to,
chairs,
tables,
cabinets,
and
bookcases).
We
use
the
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pfrm09
PsN:
24APP2
20214
Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
metal
furniture
product
lists
contained
in
the
SIC
and
NAICS
code
descriptions
to
describe
the
vast
array
of
metal
furniture
parts
and
products.
We
intend
the
source
category
to
include
facilities
for
which
the
surface
coating
of
metal
furniture
is
either
their
principal
activity
or
is
an
integral
part
of
a
production
process
which
is
the
principal
activity.
Most
coating
operations
are
located
at
plant
sites
that
are
dedicated
to
these
activities.
However,
some
may
be
located
at
sites
for
which
some
other
activity
is
principal.
Collocated
surface
coating
operations
comparable
to
the
types
and
sizes
of
the
dedicated
facilities,
in
terms
of
the
coating
process
and
applicable
emission
control
techniques,
are
included
in
the
source
category.
The
source
category
does
not
include
research
or
laboratory
facilities
or
janitorial,
building,
and
facility
maintenance
operations.
The
statute
gives
us
discretion
to
determine
if
and
how
to
subcategorize.
Once
the
floor
has
been
determined
for
new
or
reconstructed
and
existing
affected
sources
for
a
source
category
or
subcategory,
we
must
set
MACT
standards
that
are
no
less
stringent
than
the
MACT
floor.
Such
standards
must
then
be
met
by
all
sources
within
the
source
category
or
subcategory.
A
subcategory
is
a
group
of
similar
sources
within
a
given
source
category.
As
part
of
the
regulatory
development
process,
we
evaluate
the
similarities
and
differences
between
industry
segments
or
groups
of
facilities
comprising
a
source
category.
In
establishing
subcategories,
we
consider
factors
such
as
process
operations
(type
of
operation,
raw
materials,
chemistry/
formulation
data,
associated
equipment,
and
final
products);
emission
characteristics
(amount
and
type
of
HAP);
control
device
applicability;
and
opportunities
for
pollution
prevention.
We
may
also
consider
existing
regulations
or
guidance
from
States
and
other
regulatory
agencies
in
determining
subcategories.
The
data
available
to
us
indicate
that
there
are
not
significant
differences
across
the
source
category
in
the
substrates
coated,
the
coating
technologies
used,
the
range
of
HAP
content
in
the
coatings
and
materials
used,
or
the
applicability
of
control
measures
used.
Based
on
this
information,
we
believe
that
subcategories
are
not
warranted
for
the
metal
furniture
surface
coating
source
category.
We
specifically
request
comment
on
this
view
and
ask
that
commenters
provide
data,
information,
and
rationale
to
support
their
position.
B.
How
Did
We
Select
the
Regulated
Pollutants?
Organic
HAP.
Available
emission
data
collected
during
the
development
of
the
proposed
NESHAP
show
that
the
primary
organic
HAP
emitted
from
the
surface
coating
of
metal
furniture
include
xylene,
toluene,
glycol
ethers,
2
butoxy
ethanol,
ethylbenzene,
and
methyl
ethyl
ketone.
These
compounds
account
for
about
90
percent
of
this
category's
nationwide
organic
HAP
emissions.
However,
many
other
organic
HAP
are
used,
or
can
be
used,
in
metal
furniture
coatings,
thinners,
and
cleaning
materials.
Therefore,
the
proposed
rule
would
regulate
emissions
of
all
organic
HAP.
Inorganic
HAP.
Based
on
information
reported
in
response
to
surveys
during
the
development
of
the
proposed
NESHAP,
most
of
the
coatings
used
in
this
source
category
do
not
contain
inorganic
HAP.
Approximately
680
coatings
were
reported
in
the
survey
responses
from
the
metal
furniture
industry,
and
only
2
coatings
are
reported
as
containing
inorganic
HAP
such
as
chromium,
lead,
or
manganese
compounds.
These
2
coatings
represent
less
than
0.5
percent
of
the
total
volume
of
coatings
reported
in
the
survey
responses.
The
facilities
in
this
source
category
using
coatings
with
inorganic
HAP
employ
either
a
waterwash
system
or
dry
particulate
filters
that
reduce
inorganic
HAP
emissions
from
the
spray
booth
exhaust.
At
this
time,
it
does
not
appear
that
emissions
of
inorganic
HAP
from
this
source
category
warrant
Federal
regulation.
C.
How
Did
We
Select
the
Affected
Source?
In
selecting
the
affected
source(
s)
for
emission
standards,
our
primary
goal
is
to
ensure
that
MACT
is
applied
to
HAPemitting
operations
or
activities
within
the
source
category
being
regulated.
The
affected
source
also
serves
to
distinguish
where
new
source
MACT
applies
under
a
particular
standard.
Specifically,
the
General
Provisions
in
subpart
A
of
40
CFR
part
63
define
the
terms
``
construction''
and
``
reconstruction''
with
reference
to
the
term
``
affected
source''
(40
CFR
60.2)
and
provide
that
new
source
MACT
applies
when
construction
or
reconstruction
of
an
affected
source
occurs
(40
CFR
60.5).
The
collection
of
equipment
and
activities
evaluated
in
determining
MACT
(including
the
MACT
floor)
is
used
in
defining
the
affected
source.
When
an
emission
standard
is
based
on
a
collection
of
emissions
sources,
or
total
facility
emissions,
we
select
an
affected
source
based
on
that
same
collection
of
emission
sources,
or
the
total
facility,
as
well.
This
approach
for
defining
the
affected
source
broadly
is
particularly
appropriate
for
industries
where
a
plantwide
emission
standard
provides
the
opportunity
and
incentive
for
owners
and
operators
to
utilize
control
strategies
that
are
more
cost
effective
than
if
separate
standards
were
established
for
each
emission
point
within
a
facility.
Selection
of
the
Affected
Source.
The
affected
source
for
these
proposed
standards
is
broadly
defined
to
include
all
operations
associated
with
the
coating
and
cleaning
of
metal
furniture
and
cleaning
of
equipment.
These
operations
include
storage
and
mixing
of
coatings
and
other
materials;
surface
preparation
of
the
metal
furniture
prior
to
coating
application;
coating
application
and
flash
off,
drying
and
curing
of
applied
coatings;
cleaning
operations;
and
waste
handling
operations.
In
selecting
the
affected
source,
we
considered,
for
each
operation,
the
extent
to
which
HAP
containing
materials
are
used
and
the
level
of
HAP
that
are
emitted.
Cleaning
and
coating
application,
flash
off,
and
curing/
drying
operations
account
for
the
majority
of
HAP
emissions
at
metal
furniture
surface
coating
operations,
and
most
of
the
industry's
emission
reduction
efforts
have
been
focused
on
these
areas.
Thus,
we
included
these
operations
in
the
affected
source.
We
were
not
able
to
obtain
data
to
adequately
quantify
HAP
emissions
from
storage,
mixing,
and
waste
handling.
However,
solvents
that
are
added
to
coatings
as
thinners,
and
other
HAP
containing
additives
to
coatings,
may
be
emitted
during
mixing
and
storage.
The
level
of
emissions
would
depend
on
the
type
of
mixing
equipment,
the
type
of
storage
container,
and
the
work
practices
adopted
at
the
facility.
Emissions
from
waste
handling
operations
depend
on
the
type
of
system
used
to
collect
and
transport
organic
HAP
containing
waste
coatings,
thinners,
and
cleaning
materials
in
the
facility.
For
example,
solvent
laden
rags
that
are
used
to
clean
spray
booths
or
tanks
could
be
a
source
of
HAP
emissions.
The
method
used
to
isolate
and
store
such
rags
would
affect
the
level
of
emissions
to
ambient
air.
Mixing,
storage,
and
waste
handling
operations
are
included
in
the
affected
source.
A
broad
definition
of
the
affected
source
was
selected
to
provide
maximum
flexibility
in
complying
with
the
proposed
emission
limits
for
organic
HAP.
In
planning
its
total
usage
of
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24APP2.
SGM
pfrm09
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24APP2
20215
Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
containing
materials,
each
facility
can
select
among
available
coatings,
thinners,
and
cleaning
materials
to
comply
with
the
proposed
limits.
Additional
information
on
the
metal
furniture
surface
coating
operations
selected
for
regulation,
and
other
operations,
are
included
in
the
docket
for
the
proposed
standards.
D.
How
Did
We
Determine
the
Basis
and
Level
of
the
Proposed
Standards
for
Existing
and
New
Sources?
The
sections
below
present
the
rationale
for
determining
the
MACT
floor,
regulatory
alternatives
beyond
the
floor,
and
selection
of
the
proposed
standards
for
existing
and
new
affected
sources.
How
did
we
determine
the
MACT
floor
technology?
After
we
identify
the
specific
source
categories
or
subcategories
of
sources
to
regulate
under
section
112,
we
must
develop
emission
standards
for
each
category
or
subcategory.
Section
112
establishes
a
minimum
baseline
or
``
floor''
for
standards.
For
new
sources
in
a
category
or
subcategory,
the
standards
cannot
be
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
bestcontrolled
similar
source
(section
112(
d)(
3)).
The
standards
for
existing
sources
can
be
less
stringent
than
standards
for
new
sources,
but
they
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
existing
sources
(or
the
best
performing
5
sources
for
categories
or
subcategories
with
fewer
than
30
sources).
Within
the
metal
furniture
industry,
organic
HAP
emission
control
for
cleaning
and
surface
coating
operations
is
accomplished
primarily
through
the
use
of
lower
HAP
coatings,
thinners,
and
cleaning
materials.
Add
on
capture
and
control
systems
for
organic
HAP
are
rarely
used
by
the
industry.
While
lower
organic
HAP
materials
are
broadly
used
throughout
the
industry,
each
particular
coating
technology
is
not
used
at
every
facility.
Rather,
facilities
use
various
combinations
of
low
HAP
coatings,
thinners,
and
cleaning
materials.
Thus,
the
most
reasonable
approach
to
establishing
a
MACT
floor
appeared
to
be
evaluation
of
a
facility's
organic
HAP
emissions
from
all
coating
related
operations.
To
account
for
differences
in
production
levels
from
one
facility
to
another,
we
normalized
the
organic
HAP
emissions
by
the
volume
of
coating
solids
used.
We
believe
coating
solids
usage
is
an
appropriate
indicator
of
overall
production
level.
We
used
information
obtained
from
industry
survey
responses
to
estimate
the
sourcewide
organic
HAP
emissions.
We
calculated
total
organic
HAP
emissions
by
assuming
that
100
percent
of
the
volatile
components
in
all
coatings
(including
adhesives),
thinners,
and
cleaning
materials
(including
surface
preparation
materials)
are
emitted.
The
survey
response
information
was
also
used
to
determine
the
total
volume
of
coating
solids
used.
We
included
protective
and
functional
coatings,
as
well
as
adhesives,
in
this
total.
Using
the
sourcewide
organic
HAP
emissions
and
the
total
volume
of
coating
solids
used.
We
calculated
the
normalized
organic
HAP
emission
rate
in
units
of
kilograms
organic
HAP
per
liter
of
coating
solids
used.
The
facilities
were
then
ranked
from
the
lowest
emission
rate
to
the
highest.
We
based
this
analysis
on
a
total
of
49
facilities
reporting
over
9
million
liters
usage
of
approximately
680
coatings
and
adhesives,
as
well
as
730,000
liters
of
cleaning
materials.
A
detailed
description
of
the
determination
of
the
MACT
floor
is
provided
in
a
memo
(the
MACT
floor
memo)
in
the
docket
for
the
proposed
rule.
The
description
includes
all
the
assumptions
and
it
documents
the
methodology
that
was
used.
(See
ADDRESSES
section
of
this
preamble
for
information
on
the
docket).
We
specifically
request
comment
on
the
methodology
used
to
determine
the
MACT
floor,
as
summarized
below.
The
MACT
floor
for
existing
sources
was
determined
by
the
arithmetic
mean
of
the
HAP
emission
rates
of
the
top
12
percent
of
49
facilities,
which
were
the
top
6
facilities.
This
mean
value
was
0.12
kg
organic
HAP/
liter
of
coating
solids
used
(1.0
lb/
gal)
and
represents
the
existing
source
MACT
floor
for
organic
HAP.
The
survey
data
showed
no
appreciable
differences
between
the
floor
facilities
and
the
remaining
facilities
in
the
database
in
the
substrates
coated,
the
coating
technologies
used,
or
the
applicability
of
control
measures
across
the
various
operations.
Using
the
list
of
facilities
ranked
by
emission
rates,
we
observed
that
the
best
controlled
source
emitted
0.094
kg
organic
HAP/
liter
of
coating
solids
used
(0.78
lb/
gal).
Before
establishing
this
level
of
emissions
as
the
new
source
MACT
floor,
we
evaluated
the
metal
furniture
surface
coating
operations
at
this
source
to
determine
if
the
coating
technology
(in
terms
of
the
coating
type
and
application
method)
used
was
transferable
throughout
the
industry.
We
also
determined
whether
the
product
type
produced
at
this
source
affected
the
emissions
such
that
the
source
may
not
be
similar
to
all
other
sources
in
the
category.
For
example,
a
source
that
coats
only
interior
parts
could
have
significantly
different
requirements
and
coating
choices
than
a
source
that
had
the
visual
and
quality
requirements
associated
with
coating
parts
for
the
exterior
of
the
product.
We
also
determined
that
the
emission
limit
represented
by
the
lowest
emitting
source
could
be
achieved
through
the
use
of
add
on
control
devices
for
those
facilities
electing
to
use
higher
organic
HAP
coatings,
thinners,
and
cleaning
materials.
The
best
controlled
source
produces
products
(metal
storage
cabinets,
lockers,
and
racks)
that
are
not
unusual
for
the
industry.
The
source
spray
applies
solvent
based
coatings,
and
all
cleaning
materials
used
for
surface
preparation
prior
to
coating
are
free
of
organic
HAP.
Coating
application
equipment
is
cleaned
with
solvents
containing
organic
HAP.
Thus,
the
source
is
employing
technologies
that
are
already
in
widespread
use
throughout
the
metal
furniture
coating
industry.
We
believe
that
this
source
is
similar
to
other
sources
in
the
category
and
represents
the
best
controlled
source
in
our
database.
We
recognize
that
some
sources
may
have
limited
choices
in
the
coatings
available
for
their
particular
application.
As
a
result,
lower
HAP
coatings
may
not
be
available
to
meet
the
needs
of
every
source.
However,
if
the
source
is
also
using
cleaning
materials
that
contain
organic
HAP,
then
it
may
be
able
to
meet
the
emission
limit
by
reformulating
these
cleaning
materials.
A
source
also
would
have
the
option
of
using
capture
systems
and
control
devices
to
reduce
emissions
although
we
believe
choice
of
this
option
is
not
likely
for
most
sources.
How
did
we
consider
beyond
the
floor
technology?
After
the
floors
have
been
determined
for
new
and
existing
sources
in
a
source
category
or
subcategory,
we
must
set
emission
standards
that
are
no
less
stringent
than
the
floors.
Such
standards
must
then
be
met
by
all
sources
within
the
category
or
subcategory.
We
identify
and
consider
any
reasonable
regulatory
alternatives
that
are
``
beyond
the
floor,
''
taking
into
account
emission
reduction,
cost,
nonair
quality
health
and
environmental
impacts,
and
energy
requirements.
These
alternatives
may
be
different
for
new
and
existing
sources
because
of
different
MACT
floors,
and
separate
standards
may
be
established
for
new
and
existing
sources.
We
identified
three
regulatory
alternatives
more
stringent
than
the
MACT
floor
level
of
control
for
organic
HAP.
These
alternatives
were
(1)
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Federal
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/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
conversion
to
powder
coatings;
(2)
conversion
to
liquid
coatings
that
have
a
very
low,
or
no,
organic
HAP
content;
and
(3)
use
of
add
on
capture
systems
and
control
devices.
Information
indicates
that
several
metal
furniture
surface
coating
facilities
have
converted
to
using
only
powder
coatings.
Such
facilities
typically
produce
a
single
type
of
product
(such
as
warehouse
shelving
units),
do
not
require
unusual
finishes,
and
use
a
small
number
of
colors.
Many
metal
furniture
surface
coating
facilities,
however,
manufacture
more
than
one
product
and
often
use
a
wide
array
of
colors.
Many
also
achieve
finish
types
that
cannot
be
duplicated
with
powder
coatings.
Powder
coating
may
not
produce
the
varied
surface
finishes
and
colors
available
from
liquid
coatings.
Although
powder
coatings
may
be
somewhat
more
durable
than
conventional
liquid
coatings,
specialty
finishes
such
as
antique
and
crackle,
as
well
as
the
palette
of
designer
colors
offered
by
some
manufacturers,
may
not
be
adequately
duplicated
by
powder
coatings.
Consequently,
while
powder
coating
is
a
proven
technology
that
can
be
used
in
many
situations,
we
do
not
believe
it
is
appropriate
to
require
the
use
of
powder
coatings
for
all
segments
of
the
metal
furniture
industry
and
have
not
included
them
in
our
proposal
as
a
beyond
the
floor
option.
Lower
organic
HAP
liquid
coatings
fall
into
two
primary
categories.
The
most
common
are
coatings
formulated
with
solvents
that
are
not
organic
HAP
(but
may
be
VOC).
The
second
category
are
those
coatings
that
result
from
alternate
technologies
such
as
Ultraviolet
(UV)
curable
coatings
and
autophoretic
coatings.
The
UV
curable
coatings
may
or
may
not
include
organic
solvents,
which
may
contain
HAP
or
VOC,
to
keep
the
pigment
and
other
components
of
the
coating
in
solution
until
curing.
Autophoretic
coatings
use
no
organic
HAP
and
only
small
amounts
of
VOC,
but
they
may
contain
inorganic
HAP.
These
coatings
are
applied
using
a
dip
application
method
where
a
chemical
reaction
deposits
the
coating
on
the
surface
of
the
part.
These
lower
organic
HAP
coatings
are
currently
in
production
use
but
their
applicability
is
limited
for
this
industry.
The
selection
of
lower
organic
HAP
coatings
is
limited
and
is
not
extensive
enough
to
broadly
meet
the
needs
of
all
segments
of
the
metal
furniture
industry.
Given
the
limited
applicability
of
UV
curable
and
autophoretic
coating
technologies,
we
do
not
believe
it
is
feasible
to
require
the
use
of
these
coating
technologies
and
have
not
included
them
in
our
proposal
as
a
beyond
the
floor
option
for
organic
HAP.
It
is
technically
feasible
to
achieve
organic
HAP
emission
rates
lower
than
the
MACT
floor
levels
through
the
use
of
emission
capture
systems
and
control
devices.
For
example,
the
use
of
a
permanent
total
enclosure
and
an
oxidizer
could
further
reduce
organic
HAP
emissions
from
typical
sources
by
about
4.2
Mg
(4.6
tons)
to
31
Mg
(34
tons)
per
year.
However,
the
cost
of
such
a
system
could
be
approximately
$1
million.
We
believe
that
the
additional
emission
reduction
would
not
justify
the
additional
cost.
Therefore,
we
have
not
included
the
use
of
emission
capture
and
control
systems
in
our
proposal
as
a
beyond
the
floor
option.
How
did
we
select
the
standards?
For
existing
sources,
we
based
the
standards
on
the
existing
source
MACT
floor.
As
described
earlier,
we
believe
that
beyond
the
floor
options
are
not
technically
or
economically
feasible
for
all
existing
sources.
For
the
same
reasons,
we
are
basing
the
proposed
standards
for
new
sources
on
the
new
source
MACT
floor.
Without
having
information
on
the
benefits
that
would
be
achieved
by
further
reducing
emissions
beyond
the
floor,
we
believe
that
the
additional
emission
reductions
that
could
be
achieved
do
not
warrant
the
costs
that
each
source
could
incur.
Therefore,
we
would
not
require
beyond
the
floor
levels
of
emission
reductions
in
this
proposed
rule.
After
implementation
of
a
final
MACT
rule
for
this
category,
we
will
evaluate
the
health
and
environmental
risks
that
may
be
posed
as
a
result
of
exposure
to
emissions
from
the
metal
furniture
surface
coating
source
category,
as
required
by
section
112(
f)
of
the
CAA.
At
that
time,
we
will
evaluate
whether
additional
controls
are
warranted
in
light
of
the
available
risk
information.
We
specifically
request
comment
on
our
proposal
not
to
base
the
CAA
section
112(
d)
standards
on
a
beyond
the
floor
option.
A
beyond
thefloor
option
could
apply
to
all
segments
of
the
metal
furniture
surface
coating
source
category
or
to
only
certain
segments.
Comments
supporting
our
proposed
decision
not
to
go
beyond
the
floor
as
well
as
comments
opposing
the
decision
should
include
data,
information,
and
rationale
supporting
the
position
of
the
commenter.
We
note
here
that
our
assumption,
in
the
development
of
the
MACT
floors,
that
100
percent
of
the
organic
HAP
in
the
materials
used
are
emitted
by
the
affected
source
would
not
apply
when
the
source
sends
waste
organic
HAPcontaining
materials
to
a
facility
for
treatment
or
disposal.
We
made
this
assumption
because
the
industry
survey
responses
provided
little
information
as
to
the
amount
of
organic
HAP
recovered
and
recycled
or
treated
and
disposed.
We,
therefore,
believe
that
this
practice
is
not
common
within
the
metal
furniture
industry.
We
recognize,
however,
that
some
metal
furniture
facilities
may
conduct
such
activities
and
should
be
allowed
to
account
for
such
activities
in
determining
their
emissions.
Thus,
the
proposed
regulation
would
allow
you
to
reduce
the
affected
sourcewide
organic
HAP
emissions
by
the
amount
of
any
organic
HAP
contained
in
waste
treated
or
disposed
at
a
hazardous
waste
treatment,
storage,
and
disposal
facility
that
is
regulated
under
40
CFR
part
262,
264,
265,
or
266.
E.
How
Did
We
Select
the
Format
of
the
Standards?
Numerical
emission
standards
are
required
by
section
112
of
the
CAA
unless
we
determine
that
it
is
not
feasible
to
prescribe
or
enforce
an
emission
standard,
in
which
case
a
design,
equipment,
work
practice,
or
operational
standard
can
be
set
(section
112(
h)
of
the
CAA).
The
formats
considered
for
the
proposed
standards
and
the
considerations
in
selection
of
the
format
are
discussed
below.
We
selected
as
the
format
of
the
proposed
standards
for
organic
HAP,
mass
of
organic
HAP
per
volume
of
coating
solids
used.
The
performancebased
nature
of
this
proposed
format
would
allow
metal
furniture
coating
operation
owners
and
operators
flexibility
in
choosing
any
combination
of
means
(including
coating
reformulation,
use
of
lower
HAP
or
nonHAP
materials,
solvent
elimination,
work
practices,
and
add
on
control
devices)
to
comply
with
the
emission
limit
that
is
workable
for
their
particular
situations.
We
selected
volume
of
coating
solids
as
a
component
of
the
proposed
standards
to
normalize
the
rate
of
organic
HAP
emissions
across
all
sizes
and
types
of
facilities.
We
could
not
normalize
by
surface
area
due
to
lack
of
information.
We
selected
the
volume
of
coating
solids
used
because
it
is
directly
related
to
the
surface
area
coated
(i.
e.,
the
average
dry
film
thickness
of
coatings
on
most
metal
furniture
products
is
generally
consistent)
and,
therefore,
provides
an
equitable
basis
for
all
coatings,
regardless
of
differences
in
coating
densities.
A
format
based
on
the
mass
or
weight
of
coating
solids
(instead
of
volume)
could
result
in
inequitable
standards
for
higher
density
pigmented
coatings,
such
as
basecoats
or
enamels,
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Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
compared
to
coatings
with
lower
densities
per
unit
volume.
Other
choices
for
the
format
of
the
standards
that
we
considered,
but
rejected,
included
a
usage
limit
(mass
per
unit
time)
and
a
never
to
beexceeded
limit
on
the
organic
HAP
content
of
coatings
and
cleaning
materials.
As
it
is
not
our
intent
to
limit
a
facility's
production
under
these
proposed
standards,
we
have
not
proposed
a
usage
limit.
We
also
chose
not
to
propose
a
never
to
be
exceeded
limit
because
the
availability
of
all
the
different
kinds
of
coatings
required
by
the
metal
furniture
industry
at
or
below
such
a
limit
does
not
appear
to
be
sufficient
to
meet
the
needs
of
all
segments
of
the
industry.
F.
How
Did
We
Select
the
Testing
and
Initial
Compliance
Requirements?
The
proposed
standards
would
allow
you
to
choose
among
several
methods
to
demonstrate
compliance
with
the
proposed
standards
for
organic
HAP:
(1)
Coatings
with
low
or
no
organic
HAP;
(2)
an
overall
organic
HAP
emission
rate
from
all
coatings,
thinners,
and
cleaning
materials
that
is
less
than
the
applicable
emission
limit;
or
(3)
capture
systems
and
control
devices.
Coatings
with
Low
or
No
Organic
HAP.
You
would
be
required
to
document
the
organic
HAP
content
of
all
coatings
and
show
that
each
is
less
than
the
applicable
emission
limit.
You
would
also
have
to
show
that
each
thinner
and
each
cleaning
material
used
contains
no
organic
HAP.
Method
311
is
the
method
developed
by
EPA
for
determining
the
mass
fraction
of
organic
HAP
in
coatings
and
has
been
used
in
previous
surface
coating
NESHAP.
We
have
not
identified
any
other
methods
that
provide
advantages
over
Method
311
for
use
in
the
proposed
standards.
Method
24
is
the
method
developed
by
EPA
for
determining
the
mass
fraction
of
volatile
matter
for
coatings
and
can
be
used
if
you
choose
to
determine
the
nonaqueous
volatile
matter
content
as
a
surrogate
for
organic
HAP.
In
past
standards,
VOC
emission
control
measures
have
been
implemented
in
the
coatings
industry,
with
Method
24
as
the
compliance
method.
We
have
not
identified
any
other
methods
that
provide
advantages
over
Method
24
for
use
in
the
proposed
standards.
The
proposed
requirements
for
determining
volume
coating
solids
would
allow
you
to
choose
between
using
manufacturer's
data
or
measuring
the
volume
with
either
ASTM
Method
D2697–
86
(1998)
or
ASTM
Method
D6093–
97.
Overall
Organic
HAP
Emission
Rate.
To
demonstrate
compliance
using
this
option,
you
would
calculate
the
organic
HAP
emission
rate
for
your
affected
source,
based
on
the
mass
of
organic
HAP
in
all
coatings,
thinners,
and
cleaners
and
the
volume
of
coating
solids
used
during
the
compliance
period,
and
demonstrate
that
it
does
not
exceed
the
applicable
emission
limit.
You
would
document
these
values
using
the
methods
discussed
previously.
Capture
Systems
and
Control
Devices.
If
you
use
a
capture
system
and
control
device,
other
than
a
solvent
recovery
device
for
which
you
conduct
a
monthly
liquid
liquid
material
balance,
you
would
be
required
to
conduct
an
initial
performance
test
of
the
system
to
determine
its
overall
control
efficiency.
For
a
solvent
recovery
system
for
which
you
conduct
a
liquid
liquid
material
balance,
you
would
determine
the
quantity
of
volatile
matter
applied
in
the
affected
source
and
the
quantity
recovered
during
the
initial
compliance
period
to
determine
its
overall
control
efficiency.
For
both
cases,
the
overall
control
efficiency
would
be
combined
with
the
monthly
mass
of
organic
HAP
in
the
coatings
and
other
materials
used
in
the
affected
source
to
derive
the
monthly
HAP
emission
rate
in
kg
HAP/
liter
of
coating
solids
used.
If
you
conduct
a
performance
test,
you
would
also
determine
parameter
operating
limits
during
the
test.
The
test
methods
that
the
proposed
standards
would
require
for
the
performance
test
(described
in
section
II.
F
of
this
preamble)
have
been
required
under
many
standards
of
performance
for
industrial
surface
coating
sources
under
40
CFR
part
60
and
NESHAP
under
40
CFR
part
63.
We
have
not
identified
any
other
methods
that
provide
advantages
over
these
methods.
G.
How
Did
We
Select
the
Continuous
Compliance
Requirements?
To
ensure
continuous
compliance
with
the
proposed
organic
HAP
emission
limit(
s)
and/
or
operating
limits,
the
proposed
standards
would
require
continuous
parameter
monitoring
of
capture
systems
and
control
devices
and
recordkeeping.
We
selected
the
following
requirements
based
on
reasonable
cost,
ease
of
execution,
and
usefulness
of
the
resulting
data
to
both
the
owners
or
operators
and
EPA
for
ensuring
continuous
compliance
with
the
emission
limit(
s)
and/
or
operating
limits.
We
are
proposing
that
certain
parameters
be
continuously
monitored
for
the
types
of
capture
systems
and
control
devices
commonly
used
in
the
industry.
These
monitoring
parameters
have
been
used
in
other
standards
for
similar
industries.
The
values
of
these
parameters
that
correspond
to
compliance
with
the
proposed
emission
limit(
s)
are
established
during
the
initial
or
most
recent
performance
test
that
demonstrates
compliance.
These
values
are
your
operating
limits
for
the
capture
system
and
control
device.
You
would
be
required
to
determine
consecutive
3
hour
average
values
for
most
monitored
parameters
for
the
affected
source.
We
selected
this
averaging
period
to
ensure
the
control
system
is
continuously
operating
at
conditions
that
are
the
same
or
better
than
those
recorded
during
a
performance
test
demonstrating
compliance
with
the
emission
limit(
s).
To
demonstrate
continuous
compliance
with
the
monthly
emission
limit(
s),
you
would
also
need
records
of
the
quantity
of
coatings
and
other
materials
used
and
the
data
and
calculations
supporting
your
determination
of
their
HAP
content.
If
you
conduct
monthly
liquid
liquid
material
balances,
you
would
need
records
of
the
quantity
of
volatile
matter
used
in
the
affected
source
and
the
quantity
recovered
by
the
solvent
recovery
system
each
month.
H.
How
Did
We
Select
the
Notification,
Recordkeeping,
and
Reporting
Requirements?
You
would
be
required
to
comply
with
the
applicable
requirements
in
the
NESHAP
General
Provisions,
subpart
A
of
40
CFR
part
63,
as
described
in
Table
2
of
the
proposed
subpart
RRRR.
We
evaluated
the
General
Provisions
requirements
and
included
those
we
determined
to
be
the
minimum
notification,
recordkeeping,
and
reporting
necessary
to
ensure
compliance
with,
and
effective
enforcement
of,
the
proposed
standards.
I.
How
Did
We
Select
the
Compliance
Date?
You
would
be
allowed
3
years
to
comply
with
the
final
standards
for
existing
affected
sources.
This
is
the
maximum
period
allowed
by
the
CAA.
We
believe
that
3
years
for
compliance
is
necessary
to
allow
adequate
time
to
accommodate
the
variety
of
compliance
methods
that
existing
sources
may
use.
Most
sources
in
this
category
would
need
this
3
year
maximum
amount
of
time
to
develop
and
test
reformulated
coatings,
particularly
those
who
may
opt
to
comply
using
a
different
loweremitting
coating
technology.
We
want
to
encourage
the
use
of
these
pollution
prevention
technologies.
In
addition,
time
would
be
needed
to
establish
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
records
management
systems
required
for
enforcement
purposes.
Sources
that
choose
to
use
emission
capture
and
control
systems
may
need
this
time
to
purchase
and
install
them
and
to
obtain
a
permit
for
the
use
of
add
on
controls.
The
CAA
requires
that
new
or
reconstructed
affected
sources
comply
with
standards
immediately
upon
startup
or
the
effective
date
of
the
final
rule,
whichever
is
later.
IV.
Summary
of
Environmental,
Energy,
and
Economic
Impacts
Model
plants
were
developed
to
aid
in
the
estimation
of
the
impacts
the
MACT
floor
level
of
control
would
have
on
the
metal
furniture
industry.
Three
model
plants
distinguished
by
size,
as
measured
by
the
total
volume
of
coating
solids
used,
were
developed.
Impacts
were
then
developed
for
each
model
plant,
and
these
individual
impacts
were
scaled
to
nationwide
levels
based
on
the
number
of
facilities
corresponding
to
each
model
plant
size.
We
used
the
model
plant
approach
because
we
did
not
have
adequate
data
to
determine
impacts
for
each
actual
facility.
A
variety
of
compliance
methods
are
available
to
the
industry
to
meet
the
proposed
emission
limit(
s).
We
analyzed
the
information
obtained
from
the
industry
survey
responses,
industry
site
visits,
trade
groups,
and
industry
representatives
to
determine
which
compliance
methods
would
most
likely
be
used
by
existing
and
new
sources.
We
expect
that
the
most
widely
used
method
would
be
low
HAP
content
liquid
coatings
(coatings
with
HAP
contents
at
or
below
the
emission
limits)
and
lower
HAP
cleaning
materials.
Powder
coatings
and
add
on
capture
and
control
systems
would
likely
be
used
to
a
lesser
extent.
Various
combinations
of
these
methods
may
be
used.
For
the
purpose
of
assessing
impacts,
we
assumed
that
all
existing
sources
would
convert
to
lower
HAP
content
liquid
coatings,
thinners,
and
cleaning
materials.
We
assumed
that
new
sources
would
also
use
lower
HAP
materials.
We
first
estimated
the
impacts
of
the
proposed
emission
limits
on
the
three
model
plants.
To
scale
up
the
model
plant
impacts
to
nationwide
levels,
we
multiplied
the
individual
model
plant
impacts
by
the
estimated
number
of
major
sources
in
the
United
States
corresponding
to
each
model
plant
size.
We
used
United
States
Census
Bureau
data
as
the
basis
for
this
estimate,
which
was
a
total
of
655
facilities.
For
more
information
on
how
impacts
were
estimated,
see
Chapters
7
and
8
of
the
background
information
document,
EPA–
453/
R–
01–
010.
A.
What
Are
the
Air
Impacts?
For
existing
major
sources,
we
estimated
that
compliance
with
the
proposed
emission
limits
would
result
in
a
reduction
of
nationwide
organic
HAP
emissions
of
13,900
Mg/
yr
(15,274
tpy).
This
represents
a
reduction
of
approximately
70
percent
from
the
baseline
organic
HAP
emissions
of
20,300
Mg/
yr
(22,308
tpy).
The
estimated
baseline
organic
HAP
emissions
for
new
sources
(20
over
the
first
5
years
after
promulgation
of
the
final
rule)
would
be
approximately
635
Mg
(698
tons)
in
the
fifth
year.
Emissions
from
new
sources
would
be
reduced
by
approximately
465
Mg
(511
tons)
in
the
fifth
year
as
a
result
of
the
proposed
standards
(73
percent
reduction).
B.
What
Are
the
Cost
Impacts?
An
affected
source
may
incur
three
types
of
costs
to
comply
with
the
proposed
standards:
capital,
direct,
and
indirect.
Capital
costs
represent
the
onetime
purchase
of
equipment.
We
have
included
coatings,
thinners,
and
cleaning
materials
as
direct
costs
incurred
on
a
continuing
basis
for
materials
consumed
in
the
manufacturing
process.
The
cost
of
utilities,
where
applicable,
is
also
included
in
the
direct
costs.
Indirect
costs
typically
include
overhead,
taxes,
insurance,
and
administrative
costs,
as
well
as
capital
recovery
costs.
Existing
sources.
To
comply
with
the
proposed
emission
limits,
we
estimated
that
existing
facilities
would
likely
use
reformulated
coatings,
thinners,
and
cleaning
materials.
No
capital
costs
have
been
attributed
to
these
compliance
methods.
We
estimated
full
costs
for
517
facilities.
Approximately
60
facilities
would
have
only
recordkeeping
and
reporting
costs
because
these
facilities
would
already
be
in
compliance
with
the
proposed
standards
(based
on
survey
responses).
Facilities
that
would
achieve
area
source
status
before
the
compliance
date
of
the
final
standards
will
only
incur
costs
of
reading
the
rule.
In
addition
to
the
direct
costs,
all
affected
sources
would
incur
some
recordkeeping
and
reporting
costs.
We
estimated
no
incremental
costs
associated
with
the
use
of
lower
HAP
coatings
and
thinners.
Only
the
incremental
cost
of
organic
HAP
free
cleaning
materials
over
organic
HAP
cleaning
materials
was
counted.
The
average
annual
cost
for
each
facility
incurring
full
costs
is
approximately
$26,574.
This
value
includes
monitoring,
recordkeeping,
and
reporting
costs.
We
estimated
total
nationwide
annual
costs
in
the
fifth
year
to
comply
with
the
proposed
emission
limits
to
be
$14.8
million
for
existing
sources.
These
costs
include
$4.66
million
direct
costs
associated
with
material
usage
and
$10.1
million
for
recordkeeping
and
reporting.
New
Sources.
We
estimated
the
number
of
new
major
sources
based
on
information
from
industry
trade
groups.
Starting
with
the
anticipated
annual
sales
growth
for
the
industry,
excluding
price
increases
and
inflation,
we
determined
the
amount
of
coating
capacity
that
would
be
needed
to
meet
the
predicted
increase
in
demand.
Based
on
information
provided
by
industry
representatives,
we
assumed
that
75
percent
of
this
coating
capacity
could
be
absorbed
by
excess
capacity
at
existing
facilities.
The
remaining
25
percent
increase
in
capacity
was
estimated
to
be
met
by
the
construction
of
four
new
facilities
per
year
for
the
first
5
years
after
promulgation
of
the
final
standards.
Based
on
available
information,
we
determined
which
compliance
methods
will
most
likely
be
used
by
new
sources
and,
therefore,
which
compliance
methods
to
use
to
estimate
the
cost
impacts.
We
determined
that
new
sources
would
choose
reformulated
lower
organic
HAP
content
materials
to
meet
the
new
source
emission
limit.
For
the
20
new
facilities
anticipated
over
the
5
year
period
after
promulgation
of
the
final
standards,
annual
costs
in
the
fifth
year
are
estimated
to
be
$0.6
million.
We
estimated
no
incremental
costs
associated
with
use
of
lower
HAP
coatings
and
thinners.
Only
the
incremental
cost
of
organic
HAP
free
cleaning
materials
over
organic
HAP
cleaning
materials
was
counted.
There
are
no
anticipated
capital
costs.
C.
What
Are
the
Economic
Impacts?
We
performed
an
economic
impact
analysis
(EIA)
to
provide
an
estimate
of
the
facility
and
market
impacts
of
the
proposed
standards
as
well
as
its
social
costs.
In
general,
we
expect
the
economic
impacts
of
the
proposed
standards
to
be
minimal,
with
price
increases
and
production
decreases
of
less
than
0.1
percent.
Given
the
negligible
market
impacts
of
this
proposed
rule,
the
social
costs
are
expected
to
be
roughly
the
same
as
the
estimated
engineering
compliance
costs
of
$14.8
million
for
existing
sources.
For
affected
facilities,
the
distribution
of
costs
is
slanted
toward
the
lower
impact
levels
with
many
facilities
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
incurring
only
those
related
to
recordkeeping
and
reporting.
The
EIA
indicates
that
these
regulatory
costs
are
expected
to
represent
only
0.1
percent
of
the
value
of
product
shipments,
which
should
not
cause
producers
to
cease
or
alter
their
current
operations.
Hence,
no
firms
or
facilities
are
expected
to
become
at
risk
of
closure
because
of
the
proposed
standards.
International
trade
impacts
would
only
occur
for
the
metal
household
furniture
segment
of
the
industry,
but
the
small
price
increase
(i.
e.,
0.04
percent)
on
this
segment
indicates
negligible
impacts,
if
any.
Based
on
the
projected
characteristics
and
costs
for
new
sources,
EPA
does
not
expect
any
differential
impacts
on
these
sources.
For
more
information,
refer
to
the
``
Economic
Impact
Analysis
of
the
Proposed
NESHAP:
Surface
Coating
of
Metal
Furniture''
(Docket
No.
A–
97–
40).
D.
What
are
the
Nonair
Health,
Environmental,
and
Energy
Impacts?
Based
on
information
from
the
industry
survey
responses,
there
was
no
indication
that
the
use
of
low
organic
HAP
content
coatings,
thinners,
and
cleaning
materials
would
result
in
any
increase
or
decrease
in
nonair
health,
environmental,
and
energy
impacts.
There
would
be
no
change
in
the
utility
requirements
associated
with
the
use
of
these
materials,
so
there
would
be
no
change
in
the
amount
of
energy
consumed
as
a
result
of
the
material
conversion.
Also,
we
estimate
that
there
would
be
no
significant
change
in
the
amount
of
materials
used
or
the
amount
of
waste
produced
and
there
would
be
no
additional
energy
requirements
for
affected
sources.
V.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(58
FR
51735,
October
4,
1993),
the
EPA
must
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
Office
of
Management
and
Budget
(OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(1)
Have
an
annual
effect
on
the
economy
of
$100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(2)
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(3)
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligation
of
recipients
thereof;
or
(4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
OMB
has
notified
EPA
that
it
considers
this
a
``
significant
regulatory
action''
within
the
meaning
of
the
Executive
Order.
The
EPA
has
submitted
the
action
to
OMB
for
review.
Changes
made
in
response
to
OMB
suggestions
or
recommendations
will
be
documented
in
the
docket
(see
ADDRESSES
section
of
this
preamble).
B.
Executive
Order
13132,
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.
''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.
''
Under
Section
6
of
Executive
Order
13132,
EPA
may
not
issue
a
regulation
that
has
federalism
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,
unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
State
and
local
governments,
or
EPA
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
The
EPA
also
may
not
issue
a
regulation
that
has
federalism
implications
and
that
preempts
State
law,
unless
the
Agency
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
This
proposed
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
Pursuant
to
the
terms
of
Executive
Order
13132,
it
has
been
determined
that
this
rule
does
not
have
``
federalism
implications,
''
because
it
does
not
meet
the
necessary
criteria.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
this
proposed
rule.
C.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.
''
``
Policies
that
have
tribal
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
the
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes.
''
This
proposed
rule
does
not
have
tribal
implications.
It
will
not
have
substantial
direct
effects
on
tribal
governments,
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
No
tribal
governments
own
or
operate
metal
furniture
surface
coating
facilities.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(1)
is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
the
EPA
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.
The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5–
501
of
the
Executive
Order
has
the
potential
to
influence
the
regulation.
This
proposed
rule
is
not
subject
to
Executive
Order
13045
because
it
is
based
on
technology
performance
and
not
on
health
or
safety
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
risks.
No
children's
risk
analysis
was
performed
because
no
alternative
technologies
exist
that
would
provide
greater
stringency
at
a
reasonable
cost.
Furthermore,
this
rule
has
been
determined
not
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866.
E.
Executive
Order
13211,
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
rule
is
not
a
``
significant
energy
action''
as
defined
in
Executive
Order
13211,
``
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(66
FR
28355,
May
22,
2001)
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.
Further,
we
have
concluded
that
this
proposed
rule
is
not
likely
to
have
any
adverse
energy
effects.
Affected
sources
are
expected
to
comply
with
the
proposed
rule
through
pollution
prevention
rather
than
end
of
pipe
controls,
and
therefore,
there
would
be
no
increase
in
energy
usage.
F.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(UMRA),
Public
Law
104–
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
the
EPA
generally
must
prepare
a
written
statement,
including
a
costbenefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
by
State,
local,
and
tribal
governments,
in
the
aggregate,
or
by
the
private
sector,
of
$100
million
or
more
in
any
1
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
the
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
the
EPA
to
adopt
an
alternative
other
than
the
leastcostly
most
cost
effective,
or
leastburdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
the
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
The
EPA
has
determined
that
this
proposed
rule
does
not
contain
a
Federal
mandate
that
may
result
in
expenditures
of
$100
million
or
more
for
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
The
maximum
total
annual
cost
of
this
rule
for
any
year
has
been
estimated
to
be
less
than
$15.4
million.
Thus,
today's
proposed
rule
is
not
subject
to
the
requirements
of
sections
202
and
205
of
the
UMRA.
In
addition,
the
EPA
has
determined
that
this
proposed
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments.
This
rule
contains
requirements
that
may
apply
to
State
governments'
correctional
institutions
that
manufacture
or
repair
metal
furniture.
However,
these
requirements
do
not
uniquely
or
significantly
affect
those
institutions.
Therefore,
today's
proposed
rule
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.
G.
Regulatory
Flexibility
Act
(RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(SBREFA),
5
U.
S.
C.
601,
et
seq.
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedures
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
the
purposes
of
assessing
the
impacts
of
today's
proposed
standards
on
small
entities,
small
entity
is
defined
as:
(1)
A
small
business
ranging
from
100–
1,000
employees
or
less
than
$5
million
in
annual
sales
(see
Table
2);
(2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district,
or
special
district
with
a
population
of
less
than
50,000;
and
(3)
a
small
organization
that
is
any
not
forprofit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
TABLE
2.—
SMALL
BUSINESS
ADMINISTRATION
(SBA)
SMALL
BUSINESS
SIZE
STANDARDS
FOR
COMPANIES
OWNING
FACILITIES
IN
THE
METAL
FURNITURE
SOURCE
CATEGORY
BY
NAICS
CODES
a,
b
1997
NAICS
code
Product
description
SBA
size
standard
(employees)
421610
.................................
Electrical
Apparatus
and
Equipment,
Wiring
Supplies,
and
Construction
Material
Wholesalers.
100
337124
.................................
Metal
Household
Furniture
Manufacturing
...................................................................
500
337214
.................................
Nonwood
Office
Furniture
Manufacturing
....................................................................
500
336360
.................................
Motor
Vehicle
Fabric
Accessories
and
Seat
Manufacturing
........................................
500
337127
.................................
Institutional
Furniture
Manufacturing
............................................................................
500
337215
.................................
Showcase,
Partition,
Shelving,
and
Locker
Manufacturing
.........................................
500
332951
.................................
Hardware
Manufacturing
..............................................................................................
500
332116
.................................
Metal
Stamping
............................................................................................................
500
332612
.................................
Wire
Spring
Manufacturing
..........................................................................................
500
337215
.................................
Showcase,
Partition,
Shelving,
and
Locker
Manufacturing
.........................................
500
335121
.................................
Residential
Electric
Lighting
Fixture
Manufacturing
.....................................................
500
335122
.................................
Commercial,
Industrial,
and
Institutional
Electric
Lighting
Fixture
Manufacturing
.......
500
339111
.................................
Laboratory
Apparatus
and
Furniture
Manufacturing
....................................................
500
339114
.................................
Dental
Equipment
and
Supplies
Manufacturing
..........................................................
500
337211
.................................
Wood
Office
Furniture
Manufacturing
..........................................................................
500
337212
.................................
Custom
Architectural
Woodwork
and
Millwork
Manufacturing
....................................
500
332312
.................................
Fabricated
Structural
Metal
Manufacturing
(pt)
...........................................................
500
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Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
TABLE
2.—
SMALL
BUSINESS
ADMINISTRATION
(SBA)
SMALL
BUSINESS
SIZE
STANDARDS
FOR
COMPANIES
OWNING
FACILITIES
IN
THE
METAL
FURNITURE
SOURCE
CATEGORY
BY
NAICS
CODES
a,
b
—Continued
1997
NAICS
code
Product
description
SBA
size
standard
(employees)
336391
.................................
Motor
Vehicle
Air
Conditioning
Manufacturing
............................................................
750
811420
.................................
Reupholstery
and
Furniture
Repair
..............................................................................
$5
million
(sales)
a
The
Agency
assumed
a
small
business
size
definition
of
1,000
employees
for
those
companies
included
in
the
SBREFA
analysis
without
available
information
on
SIC
or
NAICS
code.
b
Code
of
Federal
Regulations
(CFR).
Small
Business
Size
Standards
Part
121.
13
CFR–
121.
January
2001.
As
obtained
from
<http://
www.
sba.
gov/
regulations/
part121.
pdf>.
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
In
accordance
with
the
RFA
and
SBREFA,
the
EPA
conducted
an
assessment
of
the
proposed
standards
on
small
businesses
within
the
metal
furniture
coating
industry.
Based
on
Small
Business
Administration
size
definitions
and
reported
sales
and
employment
data,
EPA's
survey
identified
10
of
the
24
companies
owning
metal
furniture
facilities
as
small
businesses.
Although
small
businesses
represent
almost
42
percent
of
the
companies
within
the
source
category,
they
are
expected
to
incur
12
percent
of
the
total
industry
compliance
costs.
Under
the
proposed
standards,
the
average
annual
compliance
cost
share
of
sales
for
small
businesses
is
0.18
percent,
with
two
of
the
ten
small
businesses
not
expected
to
incur
any
additional
costs
because
they
are
permitted
as
synthetic
minor
HAP
emission
sources.
In
addition,
small
businesses
in
this
industry
typically
have
5
percent
profit
margins.
For
more
information,
consult
the
docket
for
this
project.
Although
this
proposed
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities,
EPA
has
nonetheless
worked
aggressively
to
minimize
the
impact
of
this
proposed
rule
on
small
entities,
consistent
with
our
obligations
under
the
CAA.
We
solicited
input
from
small
entities
during
the
data
gathering
phase
of
the
proposed
rulemaking.
We
are
proposing
compliance
options
which
give
small
entities
flexibility
in
choosing
the
most
cost
effective
and
least
burdensome
alternative
for
their
operation.
For
example,
a
facility
could
purchase
and
use
low
HAP
coatings
(i.
e.,
pollution
prevention)
that
meet
the
proposed
standards
instead
of
using
add
on
capture
and
control
systems.
This
method
of
compliance
can
be
demonstrated
with
minimum
burden
by
using
purchase
and
usage
records.
No
testing
of
materials
would
be
required,
as
the
facility
owner
could
show
that
their
coatings
meet
the
emission
limits
by
providing
formulation
data
supplied
by
the
manufacturer.
We
continue
to
be
interested
in
the
potential
impacts
of
the
proposed
rule
on
small
entities
and
welcome
comments
on
issues
related
to
such
impacts.
H.
Paperwork
Reduction
Act
The
information
collection
requirements
in
the
proposed
standards
have
been
submitted
for
approval
to
the
OMB
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501,
et
seq.
An
Information
Collection
Request
(ICR)
document
has
been
prepared
by
EPA
(ICR
No.
1952.01)
and
a
copy
may
be
obtained
from
Sandy
Farmer
by
mail
at
the
Collection
Strategies
Division
(2822),
U.
S.
Environmental
Protection
Agency,
1200
Pennsylvania
Avenue,
NW,
Washington,
DC
20460,
by
email
at
farmer.
sandy@
epa.
gov,
or
by
calling
(202)
260–
2740.
A
copy
may
also
be
downloaded
off
the
internet
at
http://
www.
epa.
gov/
icr.
The
information
requirements
are
not
effective
until
OMB
approves
them.
The
information
requirements
are
based
on
notification,
recordkeeping,
and
reporting
requirements
in
the
NESHAP
General
Provisions
(40
CFR
part
63,
subpart
A),
which
are
mandatory
for
all
owners
and
operators
subject
to
national
emission
standards.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(42
U.
S.
C.
7414).
All
information
submitted
to
the
EPA
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
Agency
policies
set
forth
in
40
CFR
part
2,
subpart
B.
The
proposed
standards
would
require
maintaining
records
of
all
coatings,
thinners,
and
cleaning
materials
data
and
calculations
used
to
determine
compliance.
This
information
includes
the
volume
used
during
each
monthly
compliance
period,
mass
fraction
organic
HAP,
density,
and,
for
coatings
only,
volume
fraction
solids.
If
an
add
on
control
device
is
used,
records
must
be
kept
of
the
capture
efficiency
of
the
capture
system,
destruction
or
removal
efficiency
of
the
add
on
control
device,
and
the
monitored
operating
parameters.
In
addition,
records
must
be
kept
of
each
calculation
of
the
affected
sourcewide
emissions
for
each
monthly
compliance
period
and
all
data,
calculations,
test
results,
and
other
supporting
information
used
to
determine
this
value.
The
monitoring,
recordkeeping,
and
reporting
burden
in
the
fifth
year
after
the
effective
date
of
the
promulgated
rule
is
estimated
to
be
approximately
165,000
labor
hours
at
a
cost
of
approximately
$11
million
for
new
and
existing
sources.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501,
et
seq.,
the
EPA
must
consider
the
paperwork
burden
imposed
by
any
information
collection
request
in
a
proposed
or
final
rule.
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
Comments
are
requested
on
the
Agency's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
By
U.
S.
Postal
Service,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division;
U.
S.
Environmental
Protection
Agency
(2822);
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460;
or
by
courier,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division;
U.
S.
Environmental
Protection
Agency
(2822);
401
M
Street,
SW.,
Room
925H,
West
Tower;
Washington,
DC;
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
Street,
NW.,
Washington,
DC
20503,
marked
``
Attention:
Desk
Officer
for
EPA.
''
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
April
24,
2002,
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
May
24,
2002.
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
this
proposal.
I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(NTTAA),
Public
Law
104–
113,
section
12(
d)
(15
U.
S.
C.
272
note),
directs
all
Federal
agencies
to
use
voluntary
consensus
standards
(VCS)
in
their
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
The
VCS
are
technical
standards
(e.
g.,
material
specifications,
test
methods,
sampling
procedures,
business
practices,
etc.)
that
are
developed
or
adopted
by
one
or
more
VCS
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
annual
reports
to
OMB,
with
explanations
when
EPA
does
not
use
available
and
applicable
VCS.
Consistent
with
the
NTTAA,
EPA
conducted
searches
to
identify
VCS
for
use
in
emissions
monitoring.
The
search
for
emissions
monitoring
procedures
identified
20
VCS
that
appeared
to
have
possible
use
in
lieu
of
EPA
standard
reference
methods.
However,
after
reviewing
the
available
standards,
EPA
determined
that
ten
of
the
candidate
consensus
standards
(ASTM
D3154–
00,
ASTM
D3271–
87,
ASTM
D3464–
96,
ASTM
D3796–
90,
ASTM
D3960–
98,
ASTM
D6053–
96,
ASTM
E337–
84,
ISO
9096:
1992,
PTC
19–
10–
1981,
and
EN
1093–
4:
1996)
identified
for
measuring
emissions
of
the
HAP
or
surrogates
subject
to
the
proposed
emission
standards
would
not
be
practical
due
to
lack
of
equivalency,
documentation,
and
validation
data
(Docket
A–
97–
47).
Seven
of
the
remaining
candidate
consensus
standards
(BSR/
ASME
MFC
13m,
ASTM
Z6871Z,
ISO/
DIS
14164,
ISO
PWI
17895,
ISO/
DIS
11890–
1,
ISO/
DIS
11890–
2,
and
PREN
12619)
are
under
development.
The
EPA
plans
to
follow,
review,
and
consider
adopting
these
standards
after
their
development
is
completed.
The
ASTM
2369–
98
is
practical
for
EPA
use
as
an
acceptable
alternative
in
measuring
the
volatile
matter
content
of
surface
coatings.
This
VCS
uses
the
same
techniques,
equipment,
and
procedures
as
Method
24.
The
EPA
will
incorporate
by
reference
ASTM
D2369–
98
into
40
CFR
63.14
in
the
near
future.
The
ASTM
D2697–
86
(1998)
and
ASTM
D6093–
97
are
acceptable
procedures
for
use
in
determining
the
volume
fraction
of
solids
for
a
variety
of
coatings.
The
EPA
will
incorporate
by
reference
ASTM
D2697–
86
(1998)
and
ASTM
D6093–
97
into
40
CFR
63.14
in
the
near
future.
Six
consensus
standards:
ASTM
D1475–
98,
ASTM
D2369–
98,
ASTM
D3792–
99,
ASTM
D4017–
96a,
ASTM
D4457–
85(
Reapproved
91),
and
ASTM
D5403–
93
are
already
incorporated
by
reference
in
EPA
Method
24;
and
five
consensus
standards:
ASTM
D1979–
97,
ASTM
D3432–
89,
ASTM
D4747–
87,
ASTM
D4827–
93,
and
ASTM
PS
9–
94
are
incorporated
by
reference
in
EPA
Method
311.
The
EPA
takes
comment
on
proposed
compliance
demonstration
requirements
in
the
proposed
standards
and
specifically
invites
the
public
to
identify
potentially
applicable
VCS.
Commentors
should
also
explain
why
the
proposed
standards
should
adopt
these
VCS
in
lieu
of
EPA's
methods.
Emission
test
methods
and
performance
specifications
submitted
for
evaluation
should
be
accompanied
with
a
basis
for
the
recommendation,
including
method
validation
data
and
the
procedure
used
to
validate
the
candidate
method
(if
method
other
than
Method
301,
40
CFR
part
63,
appendix
A,
was
used).
Sections
63.4964
through
63.4966
of
the
proposed
standards
list
EPA
testing
methods
and
performance
standards
included.
Most
of
the
standards
have
been
used
by
States
and
industry
for
more
than
10
years.
Nevertheless,
any
State
or
source
may
apply
to
EPA
for
permission
to
use
alternative
methods
in
place
of
any
of
the
EPA
testing
methods
or
performance
standards
listed.
List
of
Subjects
in
40
CFR
Part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Hazardous
substances,
Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.
Dated:
March
19,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
stated
in
the
preamble,
title
40,
chapter
I,
part
63
of
the
Code
of
Federal
Regulations
is
proposed
to
be
amended
as
follows:
PART
63—[
AMENDED]
1.
The
authority
citation
for
part
63
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401,
et
seq.
2.
Part
63
is
amended
by
adding
subpart
RRRR
to
read
as
follows:
Subpart
RRRR—
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Surface
Coating
of
Metal
Furniture
Sec.
What
This
Subpart
Covers
63.4880
What
is
the
purpose
of
this
subpart?
63.4881
Am
I
subject
to
this
subpart?
63.4882
What
parts
of
my
plant
does
this
subpart
cover?
63.4883
When
do
I
have
to
comply
with
this
subpart?
Emission
Limitations
63.4890
What
emission
limits
must
I
meet?
63.4891
What
are
my
options
for
meeting
the
emission
limits?
63.4892
What
operating
limits
must
I
meet?
63.4893
What
work
practice
standards
must
I
meet?
General
Compliance
Requirements
63.4900
What
are
my
general
requirements
for
complying
with
this
subpart?
63.4901
What
parts
of
the
General
Provisions
apply
to
me?
Notifications,
Reports,
and
Records
63.4910
What
notifications
must
I
submit?
63.4920
What
reports
must
I
submit?
63.4930
What
records
must
I
keep?
63.4931
In
what
form
and
for
how
long
must
I
keep
my
records?
Compliance
Requirements
for
the
Compliant
Material
Option
63.4940
By
what
date
must
I
conduct
the
initial
compliance
demonstration?
63.4941
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations?
63.4942
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
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/
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24,
2002
/
Proposed
Rules
Compliance
Requirements
for
the
Emission
Rate
Without
Add
On
Controls
Option
63.4950
By
what
date
must
I
conduct
the
initial
compliance
demonstration?
63.4951
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations?
63.4952
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
Compliance
Requirements
for
the
Emission
Rate
With
Add
On
Controls
Option
63.4960
By
what
date
must
I
conduct
performance
tests
and
other
initial
compliance
demonstrations?
63.4961
How
do
I
demonstrate
initial
compliance?
63.4962
How
do
I
determine
the
organic
HAP
emission
rate
for
a
controlled
coating
operation
not
using
a
liquidliquid
material
balance
if
I
operate
it
under
different
sets
of
representative
operating
conditions?
63.4963
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
63.4964
What
are
the
general
requirements
for
performance
tests?
63.4965
How
do
I
determine
the
emission
capture
system
efficiency?
63.4966
How
do
I
determine
the
add
on
control
device
emission
destruction
or
removal
efficiency?
63.4967
How
do
I
establish
the
emission
capture
system
and
add
on
control
device
operating
limits
during
the
performance
test?
63.4968
What
are
the
requirements
for
continuous
parameter
monitoring
system
(CPMS)
installation,
operation,
and
maintenance?
Other
Requirements
and
Information
63.4980
Who
implements
and
enforces
this
subpart?
63.4981
What
definitions
apply
to
this
subpart?
Tables
to
Subpart
RRRR
of
Part
63
Table
1
to
Subpart
RRRR
of
Part
63.
Operating
Limits
if
Using
the
Emission
Rate
with
Add
on
Controls
Option
Table
2
to
Subpart
RRRR
of
Part
63.
Applicability
of
General
Provisions
to
Subpart
RRRR
Table
3
to
Subpart
RRRR
of
Part
63.
Default
Organic
HAP
Mass
Fraction
for
Solvents
and
Solvent
Blends
Table
4
to
Subpart
RRRR
of
Part
63.
Default
Organic
HAP
Mass
Fraction
for
Petroleum
Solvent
Groups
What
This
Subpart
Covers
§
63.4880
What
is
the
purpose
of
this
subpart?
This
subpart
establishes
national
emission
standards
for
hazardous
air
pollutants
(NESHAP)
for
metal
furniture
surface
coating
facilities.
This
subpart
also
establishes
requirements
to
demonstrate
initial
and
continuous
compliance
with
the
emission
limitations.
§
63.4881
Am
I
subject
to
this
subpart?
(a)
Except
as
provided
in
paragraph
(c)
of
this
section,
the
source
category
to
which
this
subpart
applies
is
surface
coating
of
metal
furniture.
(1)
Surface
coating
is
the
application
of
coatings
to
a
substrate
using,
for
example,
spray
guns
or
dip
tanks.
(2)
Metal
furniture
means
furniture
or
components
of
furniture
constructed
either
entirely
or
partially
from
metal.
Metal
furniture
includes,
but
is
not
limited
to,
components
of
the
following
types
of
products
as
well
as
the
products
themselves:
household,
office,
institutional,
laboratory,
hospital,
public
building,
restaurant,
barber
and
beauty
shop,
and
dental
furniture;
office
and
store
fixtures;
partitions;
shelving;
lockers;
lamps
and
lighting
fixtures;
and
wastebaskets.
(b)
You
are
subject
to
this
subpart
if
you
own
or
operate
a
new,
reconstructed,
or
existing
affected
source,
as
defined
in
§
63.4882,
in
the
source
category
defined
in
paragraph
(a)
of
this
section
and
that
is
a
major
source,
is
located
at
a
major
source,
or
is
part
of
a
major
source
of
emissions
of
hazardous
air
pollutants
(HAP).
A
major
source
of
HAP
emissions
is
any
stationary
source
or
group
of
stationary
sources
located
within
a
contiguous
area
and
under
common
control
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
9.07
megagrams
(Mg)
(10
tons)
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
22.68
Mg
(25
tons)
or
more
per
year.
(c)
This
subpart
does
not
apply
to
surface
coating
that
meets
any
of
the
criteria
of
paragraphs
(c)(
1)
through
(5)
of
this
section.
(1)
Surface
coating
conducted
at
a
source
that
uses
only
coatings,
thinners,
and
cleaning
materials
that
contain
no
organic
HAP.
(2)
Surface
coating
of
metal
components
of
wood
furniture
conducted
in
an
operation
that
is
subject
to
the
wood
furniture
manufacturing
NESHAP
in
subpart
JJ
of
this
part.
(3)
Surface
coating
that
occurs
at
research
or
laboratory
facilities
or
that
is
part
of
janitorial,
building,
and
facility
maintenance
operations.
(4)
Surface
coating
of
only
small
items
such
as
knobs,
hinges,
or
screws
that
have
a
wider
use
beyond
metal
furniture
are
not
subject
to
this
subpart
unless
the
surface
coating
occurs
at
a
metal
furniture
source.
(5)
Surface
coating
of
metal
furniture
conducted
for
the
purpose
of
repairing
or
maintaining
metal
furniture
used
by
a
facility
and
not
for
commerce
is
not
subject
to
this
subpart,
unless
organic
HAP
emissions
from
the
surface
coating
itself
are
as
high
as
the
rates
specified
in
paragraph
(b)
of
this
section.
§
63.4882
What
parts
of
my
plant
does
this
subpart
cover?
(a)
This
subpart
applies
to
each
new,
reconstructed,
and
existing
affected
source.
(b)
The
affected
source
is
the
collection
of
all
of
the
items
listed
in
paragraphs
(b)(
1)
through
(4)
of
this
section
that
are
used
for
surface
coating
of
metal
furniture:
(1)
All
coating
operations
as
defined
in
§
63.4981;
(2)
All
storage
containers
and
mixing
vessels
in
which
coatings,
thinners,
and
cleaning
materials
are
stored
or
mixed;
(3)
All
manual
and
automated
equipment
and
containers
used
for
conveying
coatings,
thinners,
and
cleaning
materials;
and
(4)
All
storage
containers
and
all
manual
and
automated
equipment
and
containers
used
for
conveying
waste
materials
generated
by
a
coating
operation.
(c)
An
affected
source
is
a
new
affected
source
if
you
commenced
its
construction
after
April
24,
2002,
and
the
construction
is
of
a
completely
new
metal
furniture
surface
coating
facility
where
previously
no
metal
furniture
surface
coating
facility
had
existed.
(d)
An
affected
source
is
reconstructed
if
you
meet
the
criteria
as
defined
in
§
63.2.
(e)
An
affected
source
is
existing
if
it
is
not
new
or
reconstructed.
§
63.4883
When
do
I
have
to
comply
with
this
subpart?
The
date
by
which
you
must
comply
with
this
subpart
is
called
the
compliance
date.
The
compliance
date
for
each
type
of
affected
source
is
specified
in
paragraphs
(a)
through
(c)
of
this
section.
The
compliance
date
begins
the
initial
compliance
period
during
which
you
conduct
the
initial
compliance
demonstration
described
in
§§
63.4940,
63.4950,
and
63.4960.
(a)
For
a
new
or
reconstructed
affected
source,
the
compliance
date
is
the
applicable
date
in
paragraph
(a)(
1)
or
(2)
of
this
section:
(1)
If
the
initial
startup
of
your
new
or
reconstructed
affected
source
is
before
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
the
compliance
date
is
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
(2)
If
the
initial
startup
of
your
new
or
reconstructed
affected
source
occurs
after
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
the
compliance
date
is
the
date
of
initial
startup
of
your
affected
source.
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Vol.
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79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
(b)
For
an
existing
affected
source,
the
compliance
date
is
the
date
3
years
after
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
(c)
For
an
area
source
that
increases
its
emissions
or
its
potential
to
emit
such
that
it
becomes
a
major
source
of
HAP
emissions,
the
compliance
date
is
specified
in
paragraphs
(c)(
1)
and
(2)
of
this
section.
(1)
For
any
portion
of
the
source
that
becomes
a
new
or
reconstructed
affected
source
subject
to
this
subpart,
the
compliance
date
is
the
date
of
initial
startup
or
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
whichever
is
later.
(2)
For
any
portion
of
the
source
that
becomes
an
existing
affected
source
subject
to
this
subpart,
the
compliance
date
is
the
date
1
year
after
the
area
source
becomes
a
major
source
or
3
years
after
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
whichever
is
later.
(d)
You
must
meet
the
notification
requirements
in
§
63.4910
according
to
the
dates
specified
in
that
section
and
in
subpart
A
of
this
part.
Some
of
the
notifications
must
be
submitted
before
the
compliance
dates
described
in
paragraphs
(a)
through
(c)
of
this
section.
Emission
Limitations
§
63.4890
What
emission
limits
must
I
meet?
(a)
For
a
new
or
reconstructed
affected
source,
you
must
limit
organic
HAP
emissions
to
the
atmosphere
to
no
more
than
0.094
kilogram
(kg)
organic
HAP
per
liter
(0.78
pound
per
gallon
(lb/
gal))
of
coating
solids
used
during
each
compliance
period,
determined
according
to
the
procedures
in
§
63.4941,
§
63.4951,
or
§
63.4961.
(b)
For
an
existing
affected
source,
you
must
limit
organic
HAP
emissions
to
the
atmosphere
to
no
more
than
0.12
kg
organic
HAP
per
liter
(1.0
lb/
gal)
of
coating
solids
used
during
each
compliance
period,
determined
according
to
the
procedures
in
§
63.4941,
§
63.4951,
or
§
63.4961.
§
63.4891
What
are
my
options
for
meeting
the
emission
limits?
You
must
include
all
coatings,
thinners,
and
cleaning
materials
used
in
the
affected
source
when
determining
whether
the
organic
HAP
emission
rate
is
equal
to
or
less
than
the
applicable
emission
limit
in
§
63.4890.
To
make
this
determination,
you
must
use
at
least
one
of
the
three
compliance
options
listed
in
paragraphs
(a)
through
(c)
of
this
section.
You
may
apply
any
of
the
compliance
options
to
an
individual
coating
operation
or
to
multiple
coating
operations
as
a
group
or
to
the
entire
affected
source.
You
may
use
different
compliance
options
for
different
coating
operations
or
at
different
times
on
the
same
coating
operation.
However,
you
may
not
use
different
compliance
options
at
the
same
time
on
the
same
coating
operation.
If
you
switch
between
compliance
options
for
any
coating
operation
or
group
of
coating
operations,
you
must
document
this
switch
as
required
by
§
63.4930(
c),
and
you
must
report
it
in
the
next
semiannual
compliance
report
required
in
§
63.4920.
(a)
Compliant
material
option.
Demonstrate
that
the
organic
HAP
content
of
each
coating
used
in
the
coating
operation(
s)
is
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4890
and
that
each
thinner
and
each
cleaning
material
used
contains
no
organic
HAP.
You
must
meet
all
the
requirements
of
§§
63.4940,
63.4941,
and
63.4942
to
demonstrate
compliance
with
the
emission
limit
using
this
option.
(b)
Emission
rate
without
add
on
controls
option.
Demonstrate
that,
based
on
the
coatings,
thinners,
and
cleaning
materials
used
in
the
coating
operation(
s),
the
organic
HAP
emission
rate
for
the
coating
operation(
s)
is
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4890,
calculated
as
a
monthly
emission
rate.
You
must
meet
all
the
requirements
of
§§
63.4950,
63.4951,
and
63.4952
to
demonstrate
compliance
with
the
emission
limit
using
this
option.
(c)
Emission
rate
with
add
on
controls
option.
Demonstrate
that,
based
on
the
coatings,
thinners,
and
cleaning
materials
used
in
the
coating
operation(
s),
and
the
emission
capture
and
add
on
control
efficiencies
achieved,
the
organic
HAP
emission
rate
for
the
coating
operation(
s)
is
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4890,
calculated
as
a
monthly
emission
rate.
If
you
use
this
compliance
option,
you
must
also
demonstrate
that
all
capture
systems
and
add
on
control
devices
for
the
coating
operation(
s)
meet
the
operating
limits
required
in
§
63.4892,
except
for
solvent
recovery
systems
for
which
you
conduct
liquid
liquid
material
balances
according
to
§
63.4961(
j);
and
that
you
meet
the
work
practice
standards
required
in
§
63.4893.
You
must
meet
all
the
requirements
of
§§
63.4960
through
63.4968
to
demonstrate
compliance
with
the
emission
limits,
operating
limits,
and
work
practice
standards
using
this
option.
§
63.4892
What
operating
limits
must
I
meet?
(a)
For
any
coating
operation(
s)
on
which
you
use
the
compliant
material
option
or
the
emission
rate
without
addon
controls
option,
you
are
not
required
to
meet
any
operating
limits.
(b)
For
any
controlled
coating
operation(
s)
on
which
you
use
the
emission
rate
with
add
on
controls
option,
except
those
for
which
you
use
a
solvent
recovery
system
and
conduct
a
liquid
liquid
material
balance
according
to
§
63.4961(
j),
you
must
meet
the
operating
limits
specified
in
Table
1
of
this
subpart.
These
operating
limits
apply
to
the
emission
capture
and
control
systems
on
the
coating
operation(
s)
for
which
you
use
this
option,
and
you
must
establish
the
operating
limits
during
the
performance
test
according
to
the
procedures
in
§
63.4967.
You
must
meet
the
operating
limits
at
all
times
after
you
establish
them.
(c)
If
you
use
an
add
on
control
device
other
than
those
listed
in
Table
1
of
this
subpart,
or
wish
to
monitor
an
alternative
parameter
and
comply
with
a
different
operating
limit,
you
must
apply
to
the
Administrator
for
approval
of
alternative
monitoring
under
§
63.8(
f).
§
63.4893
What
work
practice
standards
must
I
meet?
(a)
For
any
coating
operation(
s)
on
which
you
use
the
compliant
material
option
or
the
emission
rate
without
addon
controls
option,
you
are
not
required
to
meet
any
work
practice
standards.
(b)
If
you
use
the
emission
rate
with
add
on
controls
option,
you
must
develop
and
implement
a
work
practice
plan
to
minimize
organic
HAP
emissions
from
the
storage,
mixing,
and
conveying
of
coatings,
thinners,
and
cleaning
materials
used
in,
and
waste
materials
generated
by,
the
controlled
coating
operation(
s)
for
which
you
use
this
option;
or
you
must
meet
an
alternative
standard
as
provided
in
paragraph
(c)
of
this
section.
The
plan
must
specify
practices
and
procedures
to
ensure
that,
at
a
minimum,
the
elements
specified
in
paragraphs
(b)(
1)
through
(5)
of
this
section
are
implemented.
(1)
All
organic
HAP
containing
coatings,
thinners,
cleaning
materials,
and
waste
materials
must
be
stored
in
closed
containers.
(2)
Spills
of
organic
HAP
containing
coatings,
thinners,
cleaning
materials,
and
waste
materials
must
be
minimized.
(3)
Organic
HAP
containing
coatings,
thinners,
cleaning
materials,
and
waste
materials
must
be
conveyed
from
one
location
to
another
in
closed
containers
or
pipes.
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Vol.
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No.
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/
Wednesday,
April
24,
2002
/
Proposed
Rules
(4)
Mixing
vessels
which
contain
organic
HAP
containing
coatings
and
other
materials
must
be
closed
except
when
adding
to,
removing,
or
mixing
the
contents.
(5)
Emissions
of
organic
HAP
must
be
minimized
during
cleaning
of
storage,
mixing,
and
conveying
equipment.
(c)
As
provided
in
§
63.6(
g),
we,
the
U.
S.
Environmental
Protection
Agency
(EPA),
may
choose
to
grant
you
permission
to
use
an
alternative
to
the
work
practice
standards
in
this
section.
General
Compliance
Requirements
§
63.4900
What
are
my
general
requirements
for
complying
with
this
subpart?
(a)
You
must
be
in
compliance
with
the
emission
limitations
in
this
subpart
as
specified
in
paragraphs
(a)(
1)
and
(2)
of
this
section.
(1)
Any
coating
operation(
s)
for
which
you
use
the
compliant
material
option
or
the
emission
rate
without
add
on
controls
option,
as
specified
in
§
63.4891(
a)
and
(b),
must
be
in
compliance
with
the
applicable
emission
limit
in
§
63.4890
at
all
times.
(2)
Any
coating
operation(
s)
for
which
you
use
the
emission
rate
with
add
on
controls
option,
as
specified
in
§
63.4891(
c),
must
be
in
compliance
with
the
applicable
emission
limit
in
§
63.4890
at
all
times
except
during
periods
of
startup,
shutdown,
and
malfunction.
Each
controlled
coating
operation
must
be
in
compliance
with
the
operating
limits
for
emission
capture
systems
and
add
on
control
devices
required
by
§
63.4892
at
all
times,
except
during
periods
of
startup,
shutdown,
and
malfunction,
and
except
for
solvent
recovery
systems
for
which
you
conduct
liquid
liquid
material
balances
according
to
§
63.4961(
j).
Each
controlled
coating
operation
must
be
in
compliance
with
the
work
practice
standards
in
§
63.4893
at
all
times.
(b)
You
must
always
operate
and
maintain
your
affected
source,
including
all
air
pollution
control
and
monitoring
equipment
you
use
for
purposes
of
complying
with
this
subpart,
according
to
the
provisions
in
§
63.6(
e)(
1)(
i).
(c)
If
your
affected
source
uses
an
emission
capture
system
and
add
on
control
device,
you
must
maintain
a
log
detailing
the
operation
and
maintenance
of
the
emission
capture
system,
add
on
control
device,
and
continuous
parameter
monitors
during
the
period
between
the
compliance
date
specified
for
your
affected
source
in
§
63.4883
and
the
date
when
the
initial
emission
capture
system
and
add
on
control
device
performance
tests
have
been
completed,
as
specified
in
§
63.4960.
This
requirement
does
not
apply
to
a
solvent
recovery
system
for
which
you
conduct
a
liquid
liquid
material
balance
according
to
§
63.4961(
j).
(d)
If
your
affected
source
uses
an
emission
capture
system
and
add
on
control
device,
you
must
develop
and
implement
a
written
startup,
shutdown,
and
malfunction
plan
according
to
the
provisions
in
§
63.6(
e)(
3).
The
plan
must
address
startup,
shutdown,
and
corrective
actions
in
the
event
of
a
malfunction
of
the
emission
capture
system
or
the
add
on
control
device.
The
plan
must
also
address
any
coating
operation
equipment
that
may
cause
increased
emissions
or
that
would
affect
capture
efficiency
if
the
process
equipment
malfunctions,
such
as
conveyors
that
move
parts
among
enclosures.
§
63.4901
What
parts
of
the
General
Provisions
apply
to
me?
Table
2
of
this
subpart
shows
which
parts
of
the
General
Provisions
in
§§
63.1
through
63.15
apply
to
you.
Notifications,
Reports,
and
Records
§
63.4910
What
notifications
must
I
submit?
(a)
General.
You
must
submit
the
notifications
in
§§
63.7(
b)
and
(c),
63.8(
f)(
4),
and
63.9(
b)
through
(e)
and
(h)
that
apply
to
you
by
the
dates
specified
in
those
sections,
except
as
provided
in
paragraphs
(b)
and
(c)
of
this
section.
(b)
Initial
Notification.
You
must
submit
the
Initial
Notification
required
by
§
63.9(
b)
for
a
new
or
reconstructed
affected
source
no
later
than
120
days
after
initial
startup
or
120
days
after
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
whichever
is
later.
For
an
existing
affected
source,
you
must
submit
the
Initial
Notification
no
later
than
1
year
after
[DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
(c)
Notification
of
Compliance
Status.
You
must
submit
the
Notification
of
Compliance
Status
required
by
§
63.9(
h)
no
later
than
30
calendar
days
following
the
end
of
the
initial
compliance
period
described
in
§§
63.4940,
63.4950,
or
63.4960
that
applies
to
your
affected
source.
The
Notification
of
Compliance
Status
must
contain
the
information
specified
in
paragraphs
(c)(
1)
through
(9)
of
this
section
and
in
§
63.9(
h).
(1)
Company
name
and
address.
(2)
Statement
by
a
responsible
official
with
that
official's
name,
title,
and
signature,
certifying
the
truth,
accuracy,
and
completeness
of
the
content
of
the
report.
(3)
Date
of
the
report
and
beginning
and
ending
dates
of
the
reporting
period.
The
reporting
period
is
the
initial
compliance
period
described
in
§§
63.4940,
63.4950,
or
63.4960
that
applies
to
your
affected
source.
(4)
Identification
of
the
compliance
option
or
options
specified
in
§
63.4891
that
you
used
on
each
coating
operation
in
the
affected
source
during
the
initial
compliance
period.
(5)
Statement
of
whether
or
not
the
affected
source
achieved
the
emission
limitations
for
the
initial
compliance
period.
(6)
If
you
had
a
deviation,
include
the
information
in
paragraphs
(c)(
6)(
i)
and
(ii)
of
this
section.
(i)
A
description
of
and
statement
of
the
cause
of
the
deviation.
(ii)
If
you
failed
to
meet
the
applicable
emission
limit
in
§
63.4890,
include
all
the
calculations
you
used
to
determine
the
kg
organic
HAP
emitted
per
liter
of
coating
solids
used.
You
do
not
need
to
submit
information
provided
by
the
materials
suppliers
or
manufacturers
or
test
reports.
(7)
For
each
of
the
data
items
listed
in
paragraphs
(c)(
7)(
i)
through
(iv)
of
this
section
that
is
required
by
the
compliance
option(
s)
you
used
to
demonstrate
compliance
with
the
emission
limit,
include
an
example
of
how
you
determined
the
value,
including
calculations
and
supporting
data.
Supporting
data
can
include
a
copy
of
the
information
provided
by
the
supplier
or
manufacturer
of
the
example
coating
or
material
or
a
summary
of
the
results
of
testing
conducted
according
to
§
63.4941(
a),
(b),
or
(c).
You
do
not
need
to
submit
copies
of
any
test
reports.
(i)
Mass
fraction
of
organic
HAP
for
one
coating,
for
one
thinner,
and
for
one
cleaning
material.
(ii)
Volume
fraction
of
coating
solids
for
one
coating.
(iii)
Density
for
one
coating,
one
thinner,
and
one
cleaning
material,
except
that
if
you
use
the
compliant
material
option,
only
the
example
coating
density
is
required.
(iv)
The
amount
of
waste
materials
and
the
mass
of
organic
HAP
contained
in
the
waste
materials
for
which
you
are
claiming
an
allowance
in
Equation
1
of
§
63.4951.
(8)
The
calculation
of
kg
organic
HAP
emitted
per
liter
coating
solids
used
for
the
compliance
option(
s)
you
used,
as
specified
in
paragraphs
(c)(
8)(
i)
through
(iii)
of
this
section.
(i)
For
the
compliant
material
option,
provide
an
example
calculation
of
the
organic
HAP
content
(Hc)
for
one
coating,
using
Equation
1
of
§
63.4941.
(ii)
For
the
emission
rate
without
addon
controls
option,
provide
the
calculation
of
the
total
mass
of
organic
HAP
emissions
during
the
initial
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Federal
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/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
compliance
period
(He);
the
calculation
of
the
total
volume
of
coating
solids
used
during
the
initial
compliance
period
(Vst);
and
the
calculation
of
the
organic
HAP
emission
rate
for
the
initial
compliance
period
(Havg),
using
Equations
1,
2,
and
3,
respectively,
of
§
63.4951.
(iii)
For
the
emission
rate
with
add
on
controls
option,
provide
the
calculation
of
the
total
mass
of
organic
HAP
emissions
for
the
coatings,
thinners,
and
cleaning
materials
used
during
the
initial
compliance
period
(He),
using
Equations
1
and
1A
through
1C
of
§
63.4951;
the
calculation
of
the
total
volume
of
coating
solids
used
during
the
initial
compliance
period
(Vst),
using
Equation
2
of
§
63.4951;
the
calculation
of
the
mass
of
organic
HAP
emission
reduction
during
the
initial
compliance
period
by
emission
capture
systems
and
add
on
control
devices,
using
Equations
1
and
1A
through
1D
of
§
63.4961
for
HC,
and
Equations
2
and
3
of
§
63.4961
for
HCSR,
as
applicable;
and
the
calculation
of
the
organic
HAP
emission
rate
(HHAP)
for
the
initial
compliance
period,
using
either
Equation
4
of
§
63.4961
or
Equation
1
of
§
63.4962,
as
applicable.
(9)
For
the
emission
rate
with
add
on
controls
option,
you
must
include
the
information
specified
in
paragraphs
(c)(
9)(
i)
through
(iv)
of
this
section.
The
requirements
in
paragraphs
(c)(
9)(
i)
through
(iii)
of
this
section
do
not
apply
to
solvent
recovery
systems
for
which
you
conduct
liquid
liquid
material
balances
according
to
§
63.4961(
j).
(i)
For
each
emission
capture
system,
a
summary
of
the
data
and
copies
of
the
calculations
supporting
the
determination
that
the
emission
capture
system
is
a
permanent
total
enclosure
(PTE)
or
a
measurement
of
the
emission
capture
system
efficiency.
Include
a
description
of
the
protocol
followed
for
measuring
capture
efficiency,
summaries
of
any
capture
efficiency
tests
conducted,
and
any
calculations
supporting
the
capture
efficiency
determination.
If
you
use
the
data
quality
objective
(DQO)
or
lower
confidence
limit
(LCL)
approach,
you
must
also
include
the
statistical
calculations
to
show
you
meet
the
DQO
or
LCL
criteria
in
appendix
A
to
subpart
KK
of
this
part.
You
do
not
need
to
submit
complete
test
reports.
(ii)
A
summary
of
the
results
of
each
add
on
control
device
performance
test.
You
do
not
need
to
submit
complete
test
reports.
(iii)
A
list
of
each
emission
capture
system's
and
add
on
control
device's
operating
limits
and
a
summary
of
the
data
used
to
calculate
those
limits.
(iv)
A
statement
of
whether
or
not
you
developed
and
implemented
the
work
practice
plan
required
by
§
63.4893.
§
63.4920
What
reports
must
I
submit?
(a)
Semiannual
compliance
reports.
You
must
submit
semiannual
compliance
reports
for
each
affected
source
according
to
the
requirements
of
paragraphs
(a)(
1)
through
(7)
of
this
section.
The
semiannual
compliance
reporting
requirements
may
be
satisfied
by
reports
required
under
other
parts
of
the
Clean
Air
Act
(CAA),
as
specified
in
paragraph
(a)(
2)
of
this
section.
(1)
Dates.
Unless
the
Administrator
has
approved
a
different
schedule
for
submission
of
reports
under
§
63.10(
a),
you
must
prepare
and
submit
each
semiannual
compliance
report
according
to
the
dates
specified
in
paragraphs
(a)(
1)(
i)
through
(iv)
of
this
section.
(i)
The
first
semiannual
compliance
report
must
cover
the
first
semiannual
reporting
period
which
begins
the
day
after
the
end
of
the
initial
compliance
period
described
in
§§
63.4940,
63.4950,
or
63.4960
that
applies
to
your
affected
source
and
ends
on
June
30
or
December
31,
whichever
occurs
first
following
the
end
of
the
initial
compliance
period.
(ii)
Each
subsequent
semiannual
compliance
report
must
cover
the
subsequent
semiannual
reporting
period
from
January
1
through
June
30
or
the
semiannual
reporting
period
from
July
1
through
December
31.
(iii)
Each
semiannual
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
is
the
first
date
following
the
end
of
the
semiannual
reporting
period.
(iv)
For
each
affected
source
that
is
subject
to
permitting
regulations
pursuant
to
40
CFR
part
70
or
71,
and
if
the
permitting
authority
has
established
dates
for
submitting
semiannual
reports
pursuant
to
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
you
may
submit
the
first
and
subsequent
compliance
reports
according
to
the
dates
the
permitting
authority
has
established
instead
of
according
to
the
date
specified
in
paragraph
(a)(
1)(
iii)
of
this
section.
(2)
Inclusion
with
Title
V
report.
Each
affected
source
that
has
obtained
a
title
V
operating
permit
pursuant
to
40
CFR
part
70
or
71
must
report
all
deviations
as
defined
in
this
subpart
in
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A).
If
an
affected
source
submits
a
semiannual
compliance
report
pursuant
to
this
section
along
with,
or
as
part
of,
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
and
the
semiannual
compliance
report
includes
all
required
information
concerning
deviations
from
any
emission
limitation
in
this
subpart,
its
submission
shall
be
deemed
to
satisfy
any
obligation
to
report
the
same
deviations
in
the
semiannual
monitoring
report.
However,
submission
of
a
semiannual
compliance
report
shall
not
otherwise
affect
any
obligation
the
affected
source
may
have
to
report
deviations
from
permit
requirements
to
the
permitting
authority.
(3)
General
requirements.
The
semiannual
compliance
report
must
contain
the
information
specified
in
paragraphs
(a)(
3)(
i)
through
(v)
of
this
section,
and
the
information
specified
in
paragraphs
(a)(
4)
through
(7)
and
(c)(
1)
of
this
section
that
is
applicable
to
your
affected
source.
(i)
Company
name
and
address.
(ii)
Statement
by
a
responsible
official
with
that
official's
name,
title,
and
signature,
certifying
the
truth,
accuracy,
and
completeness
of
the
content
of
the
report.
(iii)
Date
of
report
and
beginning
and
ending
dates
of
the
reporting
period.
The
reporting
period
is
the
6
month
period
ending
on
June
30
or
December
31.
(iv)
Identification
of
the
compliance
option
or
options
specified
in
§
63.4891
that
you
used
on
each
coating
operation
during
the
reporting
period.
If
you
switched
between
compliance
options
during
the
reporting
period,
you
must
report
the
beginning
and
ending
dates
you
used
each
option.
(v)
If
you
used
the
emission
rate
without
add
on
controls
or
the
emission
rate
with
add
on
controls
compliance
option
(§
63.4891(
b)
or
(c)),
the
calculation
results
for
each
monthly
organic
HAP
emission
rate
during
the
6
month
reporting
period.
(4)
No
deviations.
If
there
were
no
deviations
from
the
emission
limitations
in
§§
63.4890,
63.4892,
and
63.4893
that
apply
to
you,
the
semiannual
compliance
report
must
include
a
statement
that
there
were
no
deviations
from
the
emission
limitations
during
the
reporting
period.
If
you
used
the
emission
rate
with
add
on
controls
option
and
there
were
no
periods
during
which
the
continuous
parameter
monitoring
systems
(CPMS)
were
out
ofcontrol
as
specified
in
§
63.8(
c)(
7),
the
semiannual
compliance
report
must
include
a
statement
that
there
were
no
periods
during
which
the
CPMS
were
out
of
control
during
the
reporting
period.
(5)
Deviations:
compliant
material
option.
If
you
used
the
compliant
material
option,
and
there
was
a
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Proposed
Rules
deviation
from
the
applicable
emission
limit
in
§
63.4890,
the
semiannual
compliance
report
must
contain
the
information
in
paragraphs
(a)(
5)(
i)
through
(iv)
of
this
section.
(i)
Identification
of
each
coating
used
that
deviated
from
the
emission
limit,
and
of
each
thinner
and
cleaning
material
used
that
contained
organic
HAP,
and
the
dates
and
time
periods
each
was
used.
(ii)
The
calculation
of
the
organic
HAP
content
(HC,
using
Equation
1
of
§
63.4941)
for
each
coating
identified
in
paragraph
(a)(
5)(
i)
of
this
section.
You
do
not
need
to
submit
background
data
supporting
this
calculation,
for
example,
information
provided
by
coating
suppliers
or
manufacturers,
or
test
reports.
(iii)
The
determination
of
mass
fraction
of
organic
HAP
for
each
coating,
thinner,
and
cleaning
material
identified
in
paragraph
(a)(
5)(
i)
of
this
section.
You
do
not
need
to
submit
background
data
supporting
this
calculation,
for
example,
information
provided
by
material
suppliers
or
manufacturers,
or
test
reports.
(iv)
A
statement
of
the
cause
of
each
deviation.
(6)
Deviations:
emission
rate
without
add
on
controls
option.
If
you
used
the
emission
rate
without
add
on
controls
option,
and
there
was
a
deviation
from
the
applicable
emission
limit
in
§
63.4890,
the
semiannual
compliance
report
must
contain
the
information
in
paragraphs
(a)(
6)(
i)
through
(iii)
of
this
section.
(i)
The
beginning
and
ending
dates
of
each
compliance
period
during
which
the
organic
HAP
emission
rate
exceeded
the
applicable
emission
limit
in
§
63.4890.
(ii)
The
calculations
used
to
determine
the
organic
HAP
emission
rate
for
the
compliance
period
in
which
the
deviation
occurred.
You
must
submit
the
calculations
for
Equations
1,
1A
through
1C,
2,
and
3
in
§
63.4951;
and
if
applicable,
the
calculation
used
to
determine
Rw
according
to
§
63.4951(
e)(
4).
You
do
not
need
to
submit
background
data
supporting
these
calculations,
for
example,
information
provided
by
materials
suppliers
or
manufacturers,
or
test
reports.
(iii)
A
statement
of
the
cause
of
each
deviation.
(7)
Deviations:
emission
rate
with
add
on
controls
option.
If
you
used
the
emission
rate
with
add
on
controls
option,
and
there
was
a
deviation
from
an
emission
limitation
(including
any
periods
when
emissions
bypassed
the
add
on
control
device
and
were
diverted
to
the
atmosphere),
the
semiannual
compliance
report
must
contain
the
information
in
paragraphs
(a)(
7)(
i)
through
(xiv)
of
this
section.
This
includes
periods
of
startup,
shutdown,
and
malfunction
during
which
deviations
occurred.
(i)
The
beginning
and
ending
dates
of
each
compliance
period
during
which
the
organic
HAP
emission
rate
exceeded
the
applicable
emission
limit
in
§
63.4890.
(ii)
The
calculations
used
to
determine
the
organic
HAP
emission
rate
for
each
compliance
period
in
which
a
deviation
occurred.
You
must
provide
the
calculation
of
the
total
mass
of
organic
HAP
emissions
for
the
coatings,
thinners,
and
cleaning
materials
used
during
the
compliance
period
(He),
using
Equations
1
and
1A
through
1C
of
§
63.4951
and,
if
applicable,
the
calculation
used
to
determine
Rw
according
to
§
63.4951(
e)(
4);
the
calculation
of
the
total
volume
of
coating
solids
used
during
the
compliance
period
(Vst),
using
Equation
2
of
§
63.4951;
the
calculation
of
the
mass
of
organic
HAP
emission
reduction
during
the
compliance
period
by
emission
capture
systems
and
add
on
control
devices,
using
Equations
1
and
1A
through
1D
of
§
63.4961
for
HC,
and
Equations
2
and
3
of
§
63.4961
for
HCSR,
as
applicable;
and
the
calculation
of
the
organic
HAP
emission
rate
for
the
compliance
period
(HHAP),
using
either
Equation
4
of
§
63.4961
or
Equation
1
of
§
63.4962,
as
applicable.
You
do
not
need
to
submit
the
background
data
supporting
these
calculations,
for
example
information
provided
by
materials
suppliers
or
manufacturers,
or
test
reports.
(iii)
The
date
and
time
that
each
malfunction
started
and
stopped.
(iv)
A
brief
description
of
the
CPMS.
(v)
The
date
of
the
latest
CPMS
certification
or
audit.
(vi)
The
date
and
time
that
each
CPMS
was
inoperative,
except
for
zero
(low
level)
and
high
level
checks.
(vii)
The
date,
time,
and
duration
that
each
CPMS
was
out
of
control,
including
the
information
in
§
63.8(
c)(
8).
(viii)
The
date
and
time
period
of
each
deviation
from
an
operating
limit
in
Table
1
of
this
subpart;
date
and
time
period
of
any
bypass
of
the
add
on
control
device;
and
whether
each
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction
or
during
another
period.
(ix)
A
summary
of
the
total
duration
of
each
deviation
from
an
operating
limit
in
Table
1
of
this
subpart
and
each
bypass
of
the
add
on
control
device
during
the
semiannual
reporting
period
and
the
total
duration
as
a
percent
of
the
total
source
operating
time
during
that
semiannual
reporting
period.
(x)
A
breakdown
of
the
total
duration
of
the
deviations
from
the
operating
limits
in
Table
1
of
this
subpart
and
bypasses
of
the
add
on
control
device
during
the
semiannual
reporting
period
into
those
that
were
due
to
startup,
shutdown,
control
equipment
problems,
process
problems,
other
known
causes,
and
other
unknown
causes.
(xi)
A
summary
of
the
total
duration
of
CPMS
downtime
during
the
semiannual
reporting
period
and
the
total
duration
of
CPMS
downtime
as
a
percent
of
the
total
source
operating
time
during
that
semiannual
reporting
period.
(xii)
A
description
of
any
changes
in
the
CPMS,
coating
operation,
emission
capture
system,
or
add
on
control
device
since
the
last
semiannual
reporting
period.
(xiii)
For
each
deviation
from
the
work
practice
standards,
a
description
of
the
deviation;
the
date
and
time
period
of
the
deviation;
and
the
actions
you
took
to
correct
the
deviation.
(xiv)
A
statement
of
the
cause
of
each
deviation.
(b)
Performance
test
reports.
If
you
use
the
emission
rate
with
add
on
controls
option,
you
must
submit
reports
of
performance
test
results
for
emission
capture
systems
and
add
on
control
devices
no
later
than
60
days
after
completing
the
tests
as
specified
in
§
63.10(
d)(
2).
(c)
Startup,
shutdown,
malfunction
reports.
If
you
used
the
emission
rate
with
add
on
controls
option
and
you
had
a
startup,
shutdown,
or
malfunction
during
the
semiannual
reporting
period,
you
must
submit
the
reports
specified
in
paragraphs
(c)(
1)
and
(2)
of
this
section.
(1)
If
your
actions
were
consistent
with
your
startup,
shutdown,
and
malfunction
plan,
you
must
include
the
information
specified
in
§
63.10(
d)
in
the
semiannual
compliance
report
required
by
paragraph
(a)
of
this
section.
(2)
If
your
actions
were
not
consistent
with
your
startup,
shutdown,
and
malfunction
plan,
you
must
submit
an
immediate
startup,
shutdown,
and
malfunction
report
as
described
in
paragraph
(c)(
2)(
i)
and
(ii)
of
this
section.
(i)
You
must
describe
the
actions
taken
during
the
event
in
a
report
delivered
by
facsimile,
telephone,
or
other
means
to
the
Administrator
within
2
working
days
after
starting
actions
that
are
inconsistent
with
the
plan.
(ii)
You
must
submit
a
letter
to
the
Administrator
within
7
working
days
after
the
end
of
the
event,
unless
you
have
made
alternative
arrangements
with
the
Administrator
as
specified
in
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Vol.
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No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
§
63.10(
d)(
5)(
ii).
The
letter
must
contain
the
information
specified
in
§
63.10(
d)(
5)(
ii).
§
63.4930
What
records
must
I
keep?
You
must
collect
and
keep
records
of
the
data
and
information
specified
in
this
section.
Failure
to
collect
and
keep
these
records
is
a
deviation
from
the
applicable
standard.
(a)
A
copy
of
each
notification
and
report
that
you
submitted
to
comply
with
this
subpart,
and
the
documentation
supporting
each
notification
and
report.
(b)
A
current
copy
of
information
provided
by
materials
suppliers
or
manufacturers,
such
as
manufacturer's
formulation
data,
or
test
data
used
to
determine
the
mass
fraction
of
organic
HAP
and
density
for
each
coating,
thinner,
and
cleaning
material
and
the
volume
fraction
of
coating
solids
for
each
coating.
If
you
conducted
testing
to
determine
mass
fraction
of
organic
HAP,
density,
or
volume
fraction
of
coating
solids,
you
must
keep
a
copy
of
the
complete
test
report.
If
you
use
information
provided
to
you
by
the
manufacturer
or
supplier
of
the
material
that
was
based
on
testing,
you
must
keep
the
summary
sheet
of
results
provided
to
you
by
the
manufacturer
or
supplier.
You
are
not
required
to
obtain
the
test
report
or
other
supporting
documentation
from
the
manufacturer
or
supplier.
(c)
For
each
compliance
period,
the
records
specified
in
paragraphs
(c)(
1)
through
(4)
of
this
section.
(1)
A
record
of
the
coating
operations
at
which
you
used
each
compliance
option
and
the
time
periods
(beginning
and
ending
dates
and
times)
you
used
each
option.
(2)
For
the
compliant
material
option,
a
record
of
the
calculation
of
the
organic
HAP
content
for
each
coating
(H
c),
using
Equation
1
of
§
63.4941.
(3)
For
the
emission
rate
without
addon
controls
option,
a
record
of
the
calculation
of
the
total
mass
of
organic
HAP
emissions
for
the
coatings,
thinners,
and
cleaning
materials
used
during
each
compliance
period
(He),
using
Equations
1,
1A
through
1C,
and
2
of
§
63.4951
and,
if
applicable,
the
calculation
used
to
determine
Rw
according
to
§
63.4951(
e)(
4);
the
calculation
of
the
total
volume
of
coating
solids
used
during
each
compliance
period
(Vst),
using
Equation
2
of
§
63.4951;
and
the
calculation
of
the
organic
HAP
emission
rate
for
each
compliance
period
(Havg),
using
Equation
3
of
§
63.4951.
(4)
For
the
emission
rate
with
add
on
controls
option,
records
of
the
calculations
specified
in
paragraphs
(c)(
4)(
i)
through
(v)
of
this
section.
(i)
The
calculation
of
the
total
mass
of
organic
HAP
emissions
for
the
coatings,
thinners,
and
cleaning
materials
used
during
each
compliance
period
(He),
using
Equations
1
and
1A
through
1C
of
§
63.4951
and,
if
applicable,
the
calculation
used
to
determine
Rw
according
to
§
63.4951(
e)(
4);
(ii)
The
calculation
of
the
total
volume
of
coating
solids
used
during
each
compliance
period
(Vst),
using
Equation
2
of
§
63.4951;
(iii)
The
calculation
of
the
mass
of
organic
HAP
emission
reduction
by
emission
capture
systems
and
add
on
control
devices,
using
Equations
1
and
1A
through
1D
of
§
63.4961
for
HC,
and
Equations
2
and
3
of
§
63.4961
for
HCSR,
as
applicable;
(iv)
The
calculation
of
the
organic
HAP
emission
rate
for
each
compliance
period
(HHAP),
using
either
Equation
4
of
§
63.4961
or
Equation
1
of
§
63.4962,
as
applicable.
(d)
A
record
of
the
name
and
volume
of
each
coating,
thinner,
and
cleaning
material
used
during
each
compliance
period.
(e)
A
record
of
the
mass
fraction
of
organic
HAP
for
each
coating,
thinner,
and
cleaning
material
used
during
each
compliance
period.
(f)
A
record
of
the
volume
fraction
of
coating
solids
for
each
coating
used
during
each
compliance
period.
(g)
A
record
of
the
density
for
each
coating
used
during
each
compliance
period;
and,
if
you
use
either
the
emission
rate
without
add
on
controls
or
the
emission
rate
with
add
on
controls
compliance
option,
the
density
for
each
thinner
and
cleaning
material
used
during
each
compliance
period.
(h)
If
you
use
an
allowance
in
Equation
1
of
§
63.4951
for
organic
HAP
contained
in
waste
materials
sent
to
or
designated
for
shipment
to
a
treatment,
storage,
and
disposal
facility
(TSDF)
according
to
§
63.4951(
e)(
4),
you
must
keep
records
of
the
information
specified
in
paragraphs
(h)(
1)
through
(3)
of
this
section.
(1)
The
name
and
address
of
each
TSDF
to
which
you
sent
waste
materials
for
which
you
use
an
allowance
in
Equation
1
of
§
63.4951,
a
statement
of
which
subparts
under
40
CFR
parts
262,
264,
265,
and
266
apply
to
the
facility,
and
the
date
of
each
shipment.
(2)
Identification
of
the
coating
operations
producing
waste
materials
included
in
each
shipment
and
the
month
or
months
in
which
you
used
the
allowance
for
these
materials
in
Equation
1
of
§
63.4951.
(3)
The
methodology
used
in
accordance
with
§
63.4951(
e)(
4)
to
determine
the
total
amount
of
waste
materials
sent
to
or
the
amount
collected,
stored,
and
designated
for
transport
to
a
TSDF
each
month;
and
the
methodology
to
determine
the
mass
of
organic
HAP
contained
in
these
waste
materials.
This
must
include
the
sources
for
all
data
used
in
the
determination,
methods
used
to
generate
the
data,
frequency
of
testing
or
monitoring,
and
supporting
calculations
and
documentation,
including
the
waste
manifest
for
each
shipment.
(i)
[Reserved]
(j)
You
must
keep
records
of
the
date,
time,
and
duration
of
each
deviation.
(k)
If
you
use
the
emission
rate
with
add
on
controls
option,
you
must
keep
the
records
specified
in
paragraphs
(k)(
1)
through
(9)
of
this
section.
(1)
For
each
deviation,
a
record
of
whether
the
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction.
(2)
The
records
in
§
63.6(
e)(
3)(
iii)
through
(v)
related
to
startup,
shutdown,
and
malfunction.
(3)
The
records
required
to
show
continuous
compliance
with
each
operating
limit
specified
in
Table
1
of
this
subpart
that
applies
to
you.
(4)
If
you
operate
under
multiple
operating
conditions
that
affect
emission
capture
system
efficiency
or
add
on
control
device
organic
HAP
destruction
or
removal
efficiency,
and
you
are
using
different
emission
capture
system
efficiency
or
add
on
control
device
organic
HAP
destruction
or
removal
efficiency
factors
for
each
condition,
then
you
must
keep
records
of
the
data
you
used
to
calculate
the
organic
HAP
emission
rate
for
each
compliance
period,
as
described
by
Equation
1
in
§
63.4962.
(5)
For
each
capture
system
that
is
a
PTE,
the
data
and
documentation
you
used
to
support
a
determination
that
the
capture
system
meets
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
a
PTE
and
has
a
capture
efficiency
of
100
percent,
as
specified
in
§
63.4965(
a).
(6)
For
each
capture
system
that
is
not
a
PTE,
the
data
and
documentation
you
used
to
determine
capture
efficiency
according
to
the
requirements
specified
in
§§
63.4964
and
63.4965(
b)
through
(e),
including
the
records
specified
in
paragraphs
(k)(
6)(
i)
through
(iii)
of
this
section
that
apply
to
you.
(i)
Records
for
a
liquid
to
uncapturedgas
protocol
using
a
temporary
total
enclosure
or
building
enclosure.
Records
of
the
mass
of
total
volatile
hydrocarbon
(TVH)
as
measured
by
Method
204A
or
F
of
appendix
M
to
40
CFR
part
51
for
each
material
used
in
the
coating
operation,
and
the
total
TVH
for
all
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/
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April
24,
2002
/
Proposed
Rules
materials
used,
during
each
capture
efficiency
test
run,
including
a
copy
of
the
test
report.
Records
of
the
mass
of
TVH
emissions
not
captured
by
the
capture
system
that
exited
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run,
as
measured
by
Method
204D
or
E
of
appendix
M
to
40
CFR
part
51,
including
a
copy
of
the
test
report.
Records
documenting
that
the
enclosure
used
for
the
capture
efficiency
test
met
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
either
a
temporary
total
enclosure
or
a
building
enclosure.
(ii)
Records
for
a
gas
to
gas
protocol
using
a
temporary
total
enclosure
or
a
building
enclosure.
Records
of
the
mass
of
TVH
emissions
captured
by
the
emission
capture
system
as
measured
by
Method
204B
or
C
of
appendix
M
to
40
CFR
part
51
at
the
inlet
to
the
add
on
control
device,
including
a
copy
of
the
test
report.
Records
of
the
mass
of
TVH
emissions
not
captured
by
the
capture
system
that
exited
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run,
as
measured
by
Method
204D
or
E
of
appendix
M
to
40
CFR
part
51,
including
a
copy
of
the
test
report.
Records
documenting
that
the
enclosure
used
for
the
capture
efficiency
test
met
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
either
a
temporary
total
enclosure
or
a
building
enclosure.
(iii)
Records
for
an
alternative
protocol.
Records
needed
to
document
a
capture
efficiency
determination
using
an
alternative
method
or
protocol
as
specified
in
§
63.4965(
e),
if
applicable.
(7)
The
records
specified
in
paragraphs
(k)(
7)(
i)
and
(ii)
of
this
section
for
each
add
on
control
device
organic
HAP
destruction
or
removal
efficiency
determination
as
specified
in
§
63.4966.
(i)
Records
of
each
add
on
control
device
performance
test
conducted
according
to
§§
63.4964
and
63.4966.
(ii)
Records
of
the
coating
operation
conditions
during
the
add
on
control
device
performance
test
showing
that
the
performance
test
was
conducted
under
representative
operating
conditions.
(8)
Records
of
the
data
and
calculations
you
used
to
establish
the
emission
capture
and
add
on
control
device
operating
limits
as
specified
in
§
63.4967
and
to
document
compliance
with
the
operating
limits
as
specified
in
Table
1
of
this
subpart.
(9)
A
record
of
the
work
practice
plan
required
by
§
63.4893
and
documentation
that
you
are
implementing
the
plan
on
a
continuous
basis.
§
63.4931
In
what
form
and
for
how
long
must
I
keep
my
records?
(a)
Your
records
must
be
in
a
form
suitable
and
readily
available
for
expeditious
review,
according
to
§
63.10(
b)(
1).
Where
appropriate,
the
records
may
be
maintained
as
electronic
spreadsheets
or
as
a
database.
(b)
As
specified
in
§
63.10(
b)(
1),
you
must
keep
each
record
for
5
years
following
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record.
(c)
You
must
keep
each
record
on
site
for
at
least
2
years
after
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record,
according
to
§
63.10(
b)(
1).
You
may
keep
the
records
off
site
for
the
remaining
3
years.
Compliance
Requirements
for
the
Compliant
Material
Option
§
63.4940
By
what
date
must
I
conduct
the
initial
compliance
demonstration?
You
must
complete
the
initial
compliance
demonstration
for
the
initial
compliance
period
according
to
the
requirements
in
§
63.4941.
The
initial
compliance
period
begins
on
the
applicable
compliance
date
specified
in
§
63.4883
and
ends
on
the
last
day
of
the
first
full
month
following
the
compliance
date.
The
initial
compliance
demonstration
includes
the
calculations
according
to
§
63.4941
and
supporting
documentation
showing
that,
during
the
initial
compliance
period,
you
used
no
coating
with
an
organic
HAP
content
that
exceeded
the
applicable
emission
limit
in
§
63.4890
and
you
used
no
thinners
or
cleaning
materials
that
contained
organic
HAP.
§
63.4941
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations?
You
may
use
the
compliant
material
option
for
any
individual
coating
operation,
for
any
group
of
coating
operations
in
the
affected
source,
or
for
all
the
coating
operations
in
the
affected
source.
You
must
use
either
the
emission
rate
without
add
on
controls
option
or
the
emission
rate
with
add
on
controls
option
for
any
coating
operation
in
the
affected
source
for
which
you
do
not
use
this
option.
To
demonstrate
initial
compliance
using
the
compliant
material
option,
the
coating
operation
or
group
of
coating
operations
must
use
no
coating
with
an
organic
HAP
content
that
exceeds
the
applicable
emission
limit
in
§
63.4890
and
must
use
no
thinner
or
cleaning
material
that
contains
organic
HAP
as
determined
according
to
this
section.
Any
coating
operation
for
which
you
use
the
compliant
material
option
is
not
required
to
meet
the
operating
limits
or
work
practice
standards
required
in
§§
63.4892
and
63.4893,
respectively.
To
demonstrate
initial
compliance
with
the
emission
limitations
using
the
compliant
material
option,
you
must
meet
all
the
requirements
of
this
section
for
the
coating
operation
or
group
of
coating
operations
using
this
option.
Use
the
procedures
in
this
section
on
each
coating,
thinner,
and
cleaning
material
in
the
condition
it
is
in
when
it
is
received
from
its
manufacturer
or
supplier
and
prior
to
any
alteration.
You
do
not
need
to
redetermine
the
HAP
content
of
cleaning
materials
that
are
reclaimed
and
reused
onsite
provided
these
materials
in
their
condition
as
received
were
demonstrated
to
comply
with
the
compliant
material
option.
(a)
Determine
the
mass
fraction
of
organic
HAP
for
each
material
used.
You
must
determine
the
mass
fraction
of
organic
HAP
for
each
coating,
thinner,
and
cleaning
material
used
during
the
compliance
period
by
using
one
of
the
options
in
paragraphs
(a)(
1)
through
(5)
of
this
section.
(1)
Method
311
(appendix
A
to
40
CFR
part
63).
You
may
use
Method
311
for
determining
the
mass
fraction
of
organic
HAP.
Use
the
procedures
specified
in
paragraphs
(a)(
1)(
i)
and
(ii)
of
this
section
when
performing
a
Method
311
test.
(i)
Count
each
organic
HAP
that
is
measured
to
be
present
at
0.1
percent
by
mass
or
more
for
Occupational
Safety
and
Health
Administration
(OSHA)
defined
carcinogens
as
specified
in
29
CFR
1910.1200(
d)(
4)
and
at
1.0
percent
by
mass
or
more
for
other
compounds.
For
example,
if
toluene
(not
an
OSHA
carcinogen)
is
measured
to
be
0.5
percent
of
the
material
by
mass,
you
do
not
have
to
count
it.
Express
the
mass
fraction
of
each
organic
HAP
you
count
as
a
value
truncated
to
four
places
after
the
decimal
point
(for
example,
0.3791).
(ii)
Calculate
the
total
mass
fraction
of
organic
HAP
in
the
test
material
by
adding
up
the
individual
organic
HAP
mass
fractions
and
truncating
the
result
to
three
places
after
the
decimal
point
(for
example,
0.763).
(2)
Method
24
(appendix
A
to
40
CFR
part
60).
For
coatings,
you
may
use
Method
24
to
determine
the
mass
fraction
of
non
aqueous
volatile
matter
and
use
that
value
as
a
substitute
for
mass
fraction
of
organic
HAP.
(3)
Alternative
method.
You
may
use
an
alternative
test
method
for
determining
the
mass
fraction
of
organic
HAP
once
the
Administrator
has
approved
it.
You
must
follow
the
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Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
procedure
in
§
63.7(
f)
to
submit
an
alternative
test
method
for
approval.
(4)
Information
from
the
supplier
or
manufacturer
of
the
material.
You
may
rely
on
information
other
than
that
generated
by
the
test
methods
specified
in
paragraphs
(a)(
1)
through
(3)
of
this
section,
such
as
manufacturer's
formulation
data,
if
it
represents
each
organic
HAP
that
is
present
at
0.1
percent
by
mass
or
more
for
OSHAdefined
carcinogens
as
specified
in
29
CFR
1910.1200(
d)(
4)
and
at
1.0
percent
by
mass
or
more
for
other
compounds.
For
example,
if
toluene
(not
an
OSHA
carcinogen)
is
0.5
percent
of
the
material
by
mass,
you
do
not
have
to
count
it.
If
there
is
a
disagreement
between
such
information
and
results
of
a
test
conducted
according
to
paragraphs
(a)(
1)
through
(3)
of
this
section,
then
the
test
method
results
will
take
precedence.
(5)
Solvent
blends.
Solvent
blends
may
be
listed
as
single
components
for
some
materials
in
data
provided
by
manufacturers
or
suppliers.
Solvent
blends
may
contain
organic
HAP
which
must
be
counted
toward
the
total
organic
HAP
mass
fraction
of
the
materials.
When
test
data
and
manufacturer's
data
for
solvent
blends
are
not
available,
you
may
use
the
default
values
for
the
mass
fraction
of
organic
HAP
in
these
solvent
blends
listed
in
Table
3
or
4
of
this
subpart.
If
you
use
the
tables,
you
must
use
the
values
in
Table
3
for
all
solvent
blends
that
match
Table
3
entries,
and
you
may
only
use
Table
4
if
the
solvent
blends
in
the
materials
you
use
do
not
match
any
of
the
solvent
blends
in
Table
3
and
you
only
know
whether
the
blend
is
aliphatic
or
aromatic.
However,
if
the
results
of
a
Method
311
test
indicate
higher
values
than
those
listed
on
Table
3
or
4
of
this
subpart,
the
Method
311
results
will
take
precedence.
(b)
Determine
the
volume
fraction
of
coating
solids
for
each
coating.
You
must
determine
the
volume
fraction
of
coating
solids
(liters
of
coating
solids
per
liter
of
coating)
for
each
coating
used
during
the
compliance
period
by
a
test
or
by
information
provided
by
the
supplier
or
the
manufacturer
of
the
material,
as
specified
in
paragraphs
(b)(
1)
and
(2)
of
this
section.
If
test
results
obtained
according
to
paragraph
(b)(
1)
of
this
section
do
not
agree
with
the
information
obtained
under
paragraph
(b)(
2)
of
this
section,
the
test
results
will
take
precedence.
(1)
ASTM
Method
D2697–
86(
1998)
or
D6093–
97.
You
may
use
ASTM
Method
D2697–
86(
1998)
or
D6093–
97
to
determine
the
volume
fraction
of
coating
solids
for
each
coating.
Divide
the
nonvolatile
volume
percent
obtained
with
the
methods
by
100
to
calculate
volume
fraction
of
coating
solids.
(2)
Information
from
the
supplier
or
manufacturer
of
the
material.
You
may
obtain
the
volume
fraction
of
coating
solids
for
each
coating
from
the
supplier
or
manufacturer.
(c)
Determine
the
density
of
each
coating.
Determine
the
density
of
each
coating
used
during
the
compliance
period
from
test
results
using
ASTM
Method
D1475–
98
or
information
from
the
supplier
or
manufacturer
of
the
material.
If
there
is
disagreement
between
ASTM
Method
D1475–
98
test
results
and
the
supplier's
or
manufacturer's
information,
the
test
results
will
take
precedence.
(d)
Calculate
the
organic
HAP
content
of
each
coating.
Calculate
HC,
the
organic
HAP
content,
kg
organic
HAP
per
liter
coating
solids,
of
each
coating
used
during
the
compliance
period,
using
Equation
1
of
this
section:
H
D
W
V
c
c
c
s
=
(
)
(
)
(
)
Eq.
1
Where:
HC
=
organic
HAP
content
of
the
coating,
kg
organic
HAP
per
liter
coating
solids.
DC
=
density
of
coating,
kg
coating
per
liter
coating,
determined
according
to
paragraph
(c)
of
this
section.
WC
=
mass
fraction
of
organic
HAP
in
the
coating,
kg
organic
HAP
per
kg
coating,
determined
according
to
paragraph
(a)
of
this
section.
VS
=
volume
fraction
of
coating
solids,
liter
coating
solids
per
liter
coating,
determined
according
to
paragraph
(b)
of
this
section.
(e)
Compliance
demonstration.
The
calculated
organic
HAP
content,
HC,
for
each
coating
used
during
the
initial
compliance
period
must
be
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4890;
and
each
thinner
and
cleaning
material
used
during
the
initial
compliance
period
must
contain
no
organic
HAP,
determined
according
to
paragraph
(a)
of
this
section.
You
must
keep
all
records
required
by
§§
63.4930
and
63.4931.
As
part
of
the
Notification
of
Compliance
Status
required
in
§
63.4910,
you
must
identify
the
coating
operation(
s)
for
which
you
used
the
compliant
material
option
and
submit
a
statement
that
the
coating
operation(
s)
was
(were)
in
compliance
with
the
emission
limitations
during
the
initial
compliance
period
because
you
used
no
coatings
for
which
the
organic
HAP
content
exceeded
the
applicable
emission
limit
in
§
63.4890,
and
you
used
no
thinners
or
cleaning
materials
that
contained
organic
HAP.
§
63.4942
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
(a)
For
each
compliance
period,
to
demonstrate
continuous
compliance,
you
must
use
no
coating
for
which
the
organic
HAP
content,
HC,
determined
using
Equation
1
of
§
63.4941,
exceeds
the
applicable
emission
limit
in
§
63.4890,
and
use
no
thinner
or
cleaning
material
that
contains
organic
HAP,
determined
according
to
§
63.4941(
a).
Each
month
following
the
initial
compliance
period
described
in
§
63.4940
is
a
compliance
period.
(b)
If
you
choose
to
comply
with
the
emission
limitations
by
using
the
compliant
material
option,
the
use
of
any
coating,
thinner,
or
cleaning
material
that
does
not
meet
the
criteria
specified
in
paragraph
(a)
of
this
section
is
a
deviation
from
the
emission
limitations
that
must
be
reported
as
specified
in
§§
63.4910(
c)(
6)
and
63.4920(
a)(
5).
(c)
As
part
of
each
semiannual
compliance
report
required
by
§
63.4920,
you
must
identify
the
coating
operation(
s)
for
which
you
used
the
compliant
material
option.
If
there
were
no
deviations
from
the
emission
limitations
in
§
63.4890,
submit
a
statement
that
the
coating
operation(
s)
was
(were)
in
compliance
with
the
emission
limitations
during
the
reporting
period
because
you
used
no
coating
for
which
the
organic
HAP
content
exceeded
the
applicable
emission
limit
in
§
63.4890
and
you
used
no
thinner
or
cleaning
material
that
contained
organic
HAP.
(d)
You
must
maintain
records
as
specified
in
§§
63.4930
and
63.4931.
Compliance
Requirements
for
the
Emission
Rate
Without
Add
On
Controls
Option
§
63.4950
By
what
date
must
I
conduct
the
initial
compliance
demonstration?
You
must
complete
the
initial
compliance
demonstration
for
the
initial
compliance
period
according
to
the
requirements
of
§
63.4951.
The
initial
compliance
period
begins
on
the
applicable
compliance
date
specified
in
§
63.4883
and
ends
on
the
last
day
of
the
first
full
month
following
the
compliance
date.
The
initial
compliance
demonstration
includes
the
calculations
showing
that
the
organic
HAP
emission
rate
for
the
initial
compliance
period
was
equal
to
or
less
than
the
applicable
emission
limit
in
§
63.4890.
§
63.4951
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations?
You
may
use
the
emission
rate
without
add
on
controls
option
for
any
individual
coating
operation,
for
any
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/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
group
of
coating
operations
in
the
affected
source,
or
for
all
the
coating
operations
in
the
affected
source.
You
must
use
either
the
compliant
material
option
or
the
emission
rate
with
add
on
controls
option
for
any
coating
operation
in
the
affected
source
for
which
you
do
not
use
this
option.
To
demonstrate
initial
compliance
using
the
emission
rate
without
add
on
controls
option,
the
coating
operation
or
group
of
coating
operations
must
meet
the
applicable
emission
limit
in
§
63.4890,
but
is
not
required
to
meet
the
operating
limits
or
work
practice
standards
in
§§
63.4892
and
63.4893,
respectively.
You
must
meet
all
the
requirements
of
this
section
to
demonstrate
initial
compliance
with
the
applicable
emission
limit
in
§
63.4890
for
the
coating
operation(
s).
When
calculating
the
organic
HAP
emission
rate
according
to
this
section,
do
not
include
any
coatings,
thinners,
or
cleaning
materials
used
on
coating
operations
for
which
you
use
the
compliant
material
option
or
the
emission
rate
with
add
on
controls
option.
You
do
not
need
to
include
organic
HAP
in
coatings,
thinners,
or
cleaning
materials
that
are
reclaimed
and
reused
in
the
coating
operation
for
which
you
use
the
emission
rate
without
add
on
controls
option.
(a)
Determine
the
mass
fraction
of
organic
HAP
for
each
material.
Determine
the
mass
fraction
of
organic
HAP
for
each
coating,
thinner,
and
cleaning
material
used
during
the
compliance
period
according
to
the
requirements
in
§
63.4941(
a).
(b)
Determine
the
volume
fraction
of
coating
solids
for
each
coating.
Determine
the
volume
fraction
of
coating
solids
for
each
coating
used
during
the
compliance
period
according
to
the
requirements
in
§
63.4941(
b).
(c)
Determine
the
density
of
each
material.
Determine
the
density
of
each
coating,
thinner,
and
cleaning
material
used
during
the
compliance
period
according
to
the
requirements
in
§
63.4941(
c)
from
test
results
using
ASTM
Method
D1475–
98,
information
from
the
supplier
or
manufacturer
of
the
material,
or
reference
sources
providing
density
or
specific
gravity
data
for
pure
materials.
If
there
is
disagreement
between
ASTM
Method
D1475–
98
test
results
and
such
other
information
sources,
the
test
results
will
take
precedence.
(d)
Determine
the
volume
of
each
material
used.
Determine
the
volume
(liters)
of
each
coating,
thinner,
and
cleaning
material
used
during
the
compliance
period
by
measurement
or
usage
records.
(e)
Calculate
the
mass
of
organic
HAP
emissions.
The
mass
of
organic
HAP
emissions,
He,
is
the
combined
mass
of
organic
HAP
contained
in
all
coatings,
thinners,
and
cleaning
materials
used
during
the
compliance
period
minus
the
organic
HAP
in
certain
waste
materials.
Calculate
He
using
Equation
1
of
this
section:
H
A
B
C
R
Eq.
e
w
=
+
+
(
)
1
Where:
He
=
total
mass
of
organic
HAP
emissions
during
the
compliance
period,
kg.
A
=
total
mass
of
organic
HAP
in
the
coatings
used
during
the
compliance
period,
kg,
as
calculated
in
Equation
1A
of
this
section.
B
=
total
mass
of
organic
HAP
in
the
thinners
used
during
the
compliance
period,
kg,
as
calculated
in
Equation
1B
of
this
section.
C
=
total
mass
of
organic
HAP
in
the
cleaning
materials
used
during
the
compliance
period,
kg,
as
calculated
in
Equation
1C
of
this
section.
Rw
=
total
mass
of
organic
HAP
in
waste
materials
sent
or
designated
for
shipment
to
a
hazardous
waste
TSDF
for
treatment
or
disposal
during
the
compliance
period,
kg,
determined
according
to
paragraph
(e)(
4)
of
this
section.
(You
may
assign
a
value
of
zero
to
Rw
if
you
do
not
wish
to
use
this
allowance.)
(1)
Calculate
A,
the
kg
organic
HAP
in
the
coatings
used
during
the
compliance
period
using
Equation
1A
of
this
section:
A
Vol
D
W
c
i
c
i
c
i
m
=
(
)
(
)
(
)
(
)
i=
,,,
Eq.
1A
1
Where:
A
=
total
mass
of
organic
HAP
in
the
coatings
used
during
the
compliance
period,
kg.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
compliance
period,
liters.
Dc,
i
=
density
of
coating,
i,
kg
coating
per
liter
coating.
Wc,
i
=
mass
fraction
of
organic
HAP
in
coating,
i,
kg
organic
HAP
per
kg
coating.
m
=
number
of
different
coatings
used
during
the
compliance
period.
(2)
Calculate
B,
the
kg
of
organic
HAP
in
the
thinners
used
during
the
compliance
period
using
Equation
1B
of
this
section:
B
Vol
D
W
t
j
t
j
t
j
m
=
(
)
(
)
(
)
(
)
j=
,,,
Eq.
1B
1
Where:
B
=
total
mass
of
organic
HAP
in
the
thinners
used
during
the
compliance
period,
kg.
Volt,
j
=
total
volume
of
thinner,
j,
used
during
the
compliance
period,
liters.
Dt,
j
=
density
of
thinner,
j,
kg
per
liter.
Wt,
j
=
mass
fraction
of
organic
HAP
in
thinner,
j,
kg
organic
HAP
per
kg
thinner.
n
=
number
of
different
thinners
used
during
the
compliance
period.
(3)
Calculate
C,
the
kg
organic
HAP
in
the
cleaning
materials
used
during
the
compliance
period
using
Equation
1C
of
this
section:
C
Vol
D
W
s
k
s
k
s
k
p
=
(
)
(
)
(
)
(
)
k=
,,,
Eq.
1C
1
Where:
C
=
total
mass
of
organic
HAP
in
the
cleaning
materials
used
during
the
compliance
period,
kg.
Vols,
k
=
total
volume
of
cleaning
material,
k,
used
during
the
compliance
period,
liters.
Ds,
k
=
density
of
cleaning
material,
k,
kg
per
liter.
Ws,
k
=
mass
fraction
of
organic
HAP
in
cleaning
material,
k,
kg
organic
HAP
per
kg
material.
p
=
number
of
different
cleaning
materials
used
during
the
compliance
period.
(4)
If
you
choose
to
account
for
the
mass
of
organic
HAP
contained
in
waste
materials
sent
or
designated
for
shipment
to
a
hazardous
waste
TSDF
(Rw)
in
the
calculation
of
He
(Equation
1
of
this
section),
then
you
must
determine
Rw
according
to
paragraphs
(e)(
4)(
i)
through
(iv)
of
this
section.
(i)
You
may
include
in
the
determination
of
Rw
only
waste
materials
that
are
generated
by
coating
operations
for
which
you
use
Equation
1
of
this
section
and
that
will
be
treated
or
disposed
of
by
a
facility
regulated
as
a
TSDF
under
40
CFR
part
262,
264,
265,
or
266.
The
TSDF
may
be
either
off
site
or
on
site.
You
may
not
include
in
Rw
the
organic
HAP
contained
in
wastewater.
(ii)
You
must
determine
either
the
amount
of
the
waste
materials
sent
to
a
TSDF
during
the
compliance
period
or
the
amount
collected
and
stored
during
the
compliance
period
and
designated
for
future
transport
to
a
TSDF.
Do
not
include
in
your
determination
of
Rw
any
waste
materials
sent
to
a
TSDF
during
a
compliance
period
if
you
have
already
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
included
them
in
the
amount
collected
and
stored
during
that
or
a
previous
compliance
period.
(iii)
Determine
the
total
mass
of
organic
HAP
contained
in
the
waste
materials
specified
in
paragraph
(e)(
4)(
ii)
of
this
section.
(iv)
You
may
use
any
reasonable
methodology
to
determine
the
amount
of
waste
materials
and
the
total
mass
of
organic
HAP
they
contain,
and
you
must
document
your
methodology
as
required
in
§
63.4930(
h).
To
the
extent
that
waste
manifests
include
this
information,
they
may
be
used
as
part
of
the
documentation
of
the
amount
of
waste
materials
and
mass
of
organic
HAP
contained
in
them.
(f)
Calculate
the
total
volume
of
coating
solids
used.
Determine
Vst,
the
total
volume
of
coating
solids
used,
liters,
which
is
the
combined
volume
of
coating
solids
for
all
the
coatings
used
during
the
compliance
period,
using
Equation
2
of
this
section:
V
Vol
V
st
i
s
i
m
=
(
)
(
)
(
)
i=
c,,
Eq.
2
1
Where:
Vst
=
total
volume
of
coating
solids
used
during
the
compliance
period,
liters.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
compliance
period,
liters.
Vs,
i
=
volume
fraction
of
coating
solids
for
coating,
i,
liter
solids
per
liter
coating,
determined
according
to
§
63.4941(
b).
m
=
number
of
coatings
used
during
the
compliance
period.
(g)
Calculate
the
organic
HAP
emission
rate.
Calculate
Havg,
the
organic
HAP
emission
rate
for
the
compliance
period,
kg
organic
HAP
per
liter
coating
solids
used,
using
Equation
3
of
this
section:
H
H
V
avg
e
st
=
(
)
Eq.
3
Where:
Havg
=
organic
HAP
emission
rate
for
the
compliance
period,
kg
organic
HAP
per
liter
coating
solids.
He
=
total
mass
of
organic
HAP
emissions
from
all
materials
used
during
the
compliance
period,
kg,
as
calculated
by
Equation
1
of
this
section.
Vst
=
total
volume
of
coating
solids
used
during
the
compliance
period,
liters,
as
calculated
by
Equation
2
of
this
section.
(h)
Compliance
demonstration.
The
organic
HAP
emission
rate
for
the
initial
compliance
period,
Havg,
must
be
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4890.
You
must
keep
all
records
as
required
by
§§
63.4930
and
63.4931.
As
part
of
the
Notification
of
Compliance
Status
required
by
§
63.4910,
you
must
identify
the
coating
operation(
s)
for
which
you
used
the
emission
rate
without
add
on
controls
option
and
submit
a
statement
that
the
coating
operation(
s)
was
(were)
in
compliance
with
the
emission
limitations
during
the
initial
compliance
period
because
the
organic
HAP
emission
rate
was
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4890,
determined
according
to
this
section.
§
63.4952
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
(a)
To
demonstrate
continuous
compliance,
the
organic
HAP
emission
rate
for
each
compliance
period,
determined
according
to
§
63.4951(
a)
through
(g),
must
be
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4890.
Each
month
following
the
initial
compliance
period
described
in
§
63.4950
is
a
compliance
period.
(b)
If
the
organic
HAP
emission
rate
for
any
compliance
period
exceeded
the
applicable
emission
limit
in
§
63.4890,
this
is
a
deviation
from
the
emission
limitations
for
that
compliance
period
and
must
be
reported
as
specified
in
§§
63.4910(
c)(
6)
and
63.4920(
a)(
6).
(c)
As
part
of
each
semiannual
compliance
report
required
by
§
63.4920,
you
must
identify
the
coating
operation(
s)
for
which
you
used
the
emission
rate
without
add
on
controls
option.
If
there
were
no
deviations
from
the
emission
limitations,
you
must
submit
a
statement
that
the
coating
operation(
s)
was
(were)
in
compliance
with
the
emission
limitations
during
the
reporting
period
because
the
organic
HAP
emission
rate
for
each
compliance
period
was
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4890.
(d)
You
must
maintain
records
as
specified
in
§§
63.4930
and
63.4931.
Compliance
Requirements
for
the
Emission
Rate
With
Add
On
Controls
Option
§
63.4960
By
what
date
must
I
conduct
performance
tests
and
other
initial
compliance
demonstrations?
(a)
New
and
reconstructed
affected
sources.
For
a
new
or
reconstructed
affected
source,
you
must
meet
the
requirements
of
paragraphs
(a)(
1)
through
(4)
of
this
section.
(1)
All
emission
capture
systems,
on
control
devices,
and
CPMS
must
be
installed
and
operating
no
later
than
the
applicable
compliance
date
specified
in
§
63.4883.
Except
for
solvent
recovery
systems
for
which
you
conduct
liquid
liquid
material
balances
according
to
§
63.4961(
j),
you
must
conduct
a
performance
test
of
each
capture
system
and
add
on
control
device
according
to
§§
63.4964,
63.4965,
and
63.4966,
and
establish
the
operating
limits
required
by
§
63.4892,
no
later
than
180
days
after
the
applicable
compliance
date
specified
in
§
63.4883.
For
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances
according
to
§
63.4961(
j),
you
must
initiate
the
first
material
balance
no
later
than
180
days
after
the
applicable
compliance
date
specified
in
§
63.4883.
(2)
You
must
develop
and
begin
implementing
the
work
practice
plan
required
by
§
63.4893
no
later
than
the
compliance
date
specified
in
§
63.4883.
(3)
You
must
complete
the
initial
compliance
demonstration
for
the
initial
compliance
period
according
to
the
requirements
of
§
63.4961.
The
initial
compliance
period
begins
on
the
applicable
compliance
date
specified
in
§
63.4883
and
ends
on
the
last
day
of
the
first
full
month
following
the
compliance
date.
The
initial
compliance
demonstration
includes
the
results
of
emission
capture
system
and
add
on
control
device
performance
tests
conducted
according
to
§§
63.4964,
63.4965,
and
63.4966;
results
of
liquid
liquid
material
balances
conducted
according
to
§
63.4961(
j);
calculations
showing
whether
the
organic
HAP
emission
rate
for
the
initial
compliance
period
was
equal
to
or
less
than
the
emission
limit
in
§
63.4890(
a);
the
operating
limits
established
during
the
performance
tests
and
the
results
of
the
continuous
parameter
monitoring
required
by
§
63.4968;
and
documentation
of
whether
you
developed
and
implemented
the
work
practice
plan
required
by
§
63.4893.
(4)
You
do
not
need
to
comply
with
the
operating
limits
for
the
emission
capture
system
and
add
on
control
device
required
by
§
63.4892
until
after
you
have
completed
the
performance
tests
specified
in
paragraph
(a)(
1)
of
this
section.
Instead,
you
must
maintain
a
log
detailing
the
operation
and
maintenance
of
the
emission
capture
system,
add
on
control
device,
and
continuous
parameter
monitors
during
the
period
between
the
compliance
date
and
the
performance
test.
You
must
begin
complying
with
the
operating
limits
for
your
affected
source
on
the
date
you
complete
the
performance
tests
addspecified
in
paragraph
(a)(
1)
of
this
section.
The
requirements
in
this
paragraph
do
not
apply
to
solvent
recovery
systems
for
which
you
conduct
liquid
liquid
material
balances.
(b)
Existing
affected
sources.
For
an
existing
affected
source,
you
must
meet
the
requirements
of
paragraphs
(b)(
1)
through
(3)
of
this
section.
(1)
All
emission
capture
systems,
add
on
control
devices,
and
CPMS
must
be
installed
and
operating
no
later
than
the
applicable
compliance
date
specified
in
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/
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24,
2002
/
Proposed
Rules
§
63.4883.
Except
for
solvent
recovery
systems
for
which
you
conduct
liquidliquid
material
balances
according
to
§
63.4961(
j),
you
must
conduct
a
performance
test
of
each
capture
system
and
add
on
control
device
according
to
the
procedures
in
§§
63.4964,
63.4965,
and
63.4966,
and
establish
the
operating
limits
required
by
§
63.4892,
no
later
than
the
compliance
date
specified
in
§
63.4883.
For
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances
according
to
§
63.4961(
j),
you
must
initiate
the
first
material
balance
no
later
than
the
compliance
date
specified
in
§
63.4883.
(2)
You
must
develop
and
begin
implementing
the
work
practice
plan
required
by
§
63.4893
no
later
than
the
compliance
date
specified
in
§
63.4883.
(3)
You
must
complete
the
initial
compliance
demonstration
for
the
initial
compliance
period
according
to
the
requirements
of
§
63.4961.
The
initial
compliance
period
begins
on
the
applicable
compliance
date
specified
in
§
63.4883
and
ends
on
the
last
day
of
the
first
full
month
following
the
compliance
date.
The
initial
compliance
demonstration
includes
the
results
of
emission
capture
system
and
add
on
control
device
performance
tests
conducted
according
to
§§
63.4964,
63.4965,
and
63.4966;
results
of
liquidliquid
material
balances
conducted
according
to
§
63.4961(
j);
calculations
showing
whether
the
organic
HAP
emission
rate
for
the
initial
compliance
period
was
equal
to
or
less
than
the
emission
limit
in
§
63.4890(
b);
the
operating
limits
established
during
the
performance
tests
and
the
results
of
the
continuous
parameter
monitoring
required
by
§
63.4968;
and
documentation
of
whether
you
developed
and
implemented
the
work
practice
plan
required
by
§
63.4893.
§
63.4961
How
do
I
demonstrate
initial
compliance?
(a)
When
add
on
controls
are
used.
You
may
use
the
emission
rate
with
add
on
controls
option
for
any
coating
operation,
for
any
group
of
coating
operations
in
the
affected
source,
or
for
all
of
the
coating
operations
in
the
affected
source.
You
may
include
both
controlled
and
uncontrolled
coating
operations
in
a
group
for
which
you
use
this
option.
You
must
use
either
the
compliant
material
option
or
the
emission
rate
without
add
on
controls
option
for
any
coating
operation
in
the
affected
source
for
which
you
do
not
use
the
emission
rate
with
add
on
controls
option.
To
demonstrate
initial
compliance,
the
coating
operation(
s)
for
which
you
use
the
emission
rate
with
add
on
controls
option
must
meet
the
applicable
emission
limit
in
§
63.4890,
and
each
controlled
coating
operation
must
meet
the
operating
limits
and
work
practice
standards
required
in
§§
63.4892
and
63.4893,
respectively.
You
must
meet
all
the
requirements
of
this
section
to
demonstrate
initial
compliance
with
the
emission
limitations.
When
calculating
the
organic
HAP
emission
rate
according
to
this
section,
do
not
include
any
coatings,
thinners,
or
cleaning
materials
used
on
coating
operations
for
which
you
use
the
compliant
material
option
or
the
emission
rate
without
add
on
controls
option.
(b)
Compliance
with
operating
limits.
Except
as
provided
in
§
63.4960(
a)(
4),
you
must
establish
and
demonstrate
continuous
compliance
during
the
initial
compliance
period
with
the
operating
limits
required
by
§
63.4892,
using
the
procedures
specified
in
§§
63.4967
and
63.4968.
(c)
Compliance
with
work
practice
requirements.
You
must
develop,
implement,
and
document
your
implementation
of
the
work
practice
plan
required
by
§
63.4893
during
the
initial
compliance
period,
as
specified
in
§
63.4930.
(d)
Compliance
with
emission
limits.
You
must
follow
the
procedures
in
paragraphs
(e)
through
(n)
of
this
section
to
demonstrate
compliance
with
the
applicable
emission
limit
in
§
63.4890.
(e)
Determine
the
mass
fraction
of
organic
HAP,
density,
volume
used,
and
volume
fraction
of
coating
solids.
Follow
the
procedures
specified
in
§
63.4951(
a)
through
(d)
to
determine
the
mass
fraction
of
organic
HAP,
density,
and
volume
of
each
coating,
thinner,
and
cleaning
material
used
during
the
compliance
period;
and
the
volume
fraction
of
coating
solids
for
each
coating
used
during
the
compliance
period.
(f)
Calculate
the
total
mass
of
organic
HAP
emissions
before
add
on
controls.
Using
Equation
1
of
§
63.4951,
calculate
the
total
mass
of
organic
HAP
emissions
before
add
on
controls
from
all
coatings,
thinners,
and
cleaning
materials
used
during
the
compliance
period,
He.
(g)
Calculate
the
organic
HAP
emission
reduction
for
each
controlled
coating
operation.
Determine
the
mass
of
organic
HAP
emissions
reduced
for
each
controlled
coating
operation
during
the
compliance
period.
The
emission
reduction
determination
quantifies
the
total
organic
HAP
emissions
that
pass
through
the
emission
capture
system
and
are
destroyed
or
removed
by
the
add
on
control
device.
Use
the
procedures
in
paragraph
(h)
of
this
section
to
calculate
the
mass
of
organic
HAP
emission
reduction
for
each
controlled
coating
operation
using
an
emission
capture
system
and
add
on
control
device
other
than
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances.
For
each
controlled
coating
operation
using
a
solvent
recovery
system
for
which
you
conduct
a
liquid
liquid
material
balance,
use
the
procedures
in
paragraph
(j)
of
this
section
to
calculate
the
organic
HAP
emission
reduction.
(h)
Calculate
the
organic
HAP
emission
reduction
for
controlled
coating
operations
not
using
liquidliquid
material
balance,
HC.
For
each
controlled
coating
operation
using
an
emission
capture
system
and
add
on
control
device
other
than
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances,
calculate
HC,
using
Equation
1
of
this
section.
The
calculation
of
HC
applies
the
emission
capture
system
efficiency
and
add
on
control
device
efficiency
to
the
mass
of
organic
HAP
contained
in
the
coatings,
thinners,
and
cleaning
materials
that
are
used
in
the
coating
operation
served
by
the
emission
capture
system
and
add
on
control
device
during
the
compliance
period.
For
any
period
of
time
a
deviation
specified
in
§
63.4963(
c)
or
(d)
occurs
in
the
controlled
coating
operation,
including
a
deviation
during
a
period
of
startup,
shutdown,
or
malfunction,
you
must
assume
zero
efficiency
for
the
emission
capture
system
and
add
on
control
device.
Equation
1
of
this
section
treats
the
materials
used
during
such
a
deviation
as
if
they
were
used
on
an
uncontrolled
coating
operation
for
the
time
period
of
the
deviation:
H
ABC
CE
DRE
H
Eq
c
I
I
I
unc
=
+
+
(
)
×
+
(
)
100
100
.
1
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Vol.
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No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
Where:
HC
=
mass
of
organic
HAP
emission
reduction
for
the
controlled
coating
operation
during
the
compliance
period,
kg.
AI
=
total
mass
of
organic
HAP
in
the
coatings
used
in
the
controlled
coating
operation
during
the
compliance
period,
excluding
coatings
used
during
deviations,
kg,
as
calculated
in
Equation
1A
of
this
section.
BI
=
total
mass
of
organic
HAP
in
the
thinners
used
in
the
controlled
coating
operation
during
the
compliance
period,
excluding
thinners
used
during
deviations,
kg,
as
calculated
in
Equation
1B
of
this
section.
CI
=
total
mass
of
organic
HAP
in
the
cleaning
materials
used
in
the
controlled
coating
operation
during
the
compliance
period,
excluding
cleaning
materials
used
during
deviations,
kg,
as
calculated
in
Equation
1C
of
this
section.
CE
=
capture
efficiency
of
the
emission
capture
system
vented
to
the
add
on
control
device,
percent.
Use
the
test
methods
and
procedures
specified
in
§§
63.4964
and
63.4965
to
measure
and
record
capture
efficiency.
DRE
=
organic
HAP
destruction
or
removal
efficiency
of
the
add
on
control
device,
percent.
Use
the
test
methods
and
procedures
in
§§
63.4964
and
63.4966
to
measure
and
record
the
organic
HAP
destruction
or
removal
efficiency.
Hunc
=
total
mass
of
organic
HAP
in
the
coatings,
thinners,
and
cleaning
materials
used
during
all
deviations
specified
in
§
63.4963(
c)
and
(d)
that
occurred
during
the
compliance
period
in
the
controlled
coating
operation,
kg,
as
calculated
in
Equation
1D
of
this
section.
(1)
Calculate
AI,
the
mass
of
organic
HAP
in
the
coatings
used
in
the
controlled
coating
operation,
kg,
using
Equation
1A
of
this
section.
Do
not
include
in
the
calculation
of
AI
the
coatings
used
during
any
deviation
specified
in
§
63.4963(
c)
or
(d)
that
occurred
during
the
month.
Include
such
coatings
in
the
calculation
of
Hunc
in
Equation
1D
of
this
section.
A
Vol
D
W
I
cicici
m
=
(
)
(
)
(
)
(
)
i=
,,,
Eq.
1A
1
Where:
AI
=
total
mass
of
organic
HAP
in
the
coatings
used
in
the
controlled
coating
operation
during
the
compliance
period,
excluding
coatings
used
during
deviations,
kg.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
compliance
period
except
during
deviations,
liters.
Dc,
i
=
density
of
coating,
i,
kg
per
liter.
Wc,
i
=
mass
fraction
of
organic
HAP
in
coating,
i,
kg
per
kg.
m
=
number
of
different
coatings
used.
(2)
Calculate
BI,
the
mass
of
organic
HAP
in
the
thinners
used
in
the
controlled
coating
operation,
kg,
using
Equation
1B
of
this
section.
Do
not
include
in
the
calculation
of
BI
the
thinners
used
during
any
deviation
specified
in
§
63.4963(
c)
or
(d)
that
occurred
during
the
month.
Include
such
coatings
in
the
calculation
of
Hunc
in
Equation
1D
of
this
section.
B
Vol
D
W
I
tjtjtj
n
=
(
)
(
)
(
)
(
)
j=
,,,
Eq.
1B
1
Where:
BI
=
total
mass
of
organic
HAP
in
the
thinners
used
in
the
controlled
coating
operation
during
the
compliance
period,
excluding
thinners
used
during
deviations,
kg.
Volt,
j
=
total
volume
of
thinner,
j,
used
during
the
compliance
period
except
during
deviations,
liters.
Dt,
j
=
density
of
thinner,
j,
kg
per
liter.
Wt,
j
=
mass
fraction
of
organic
HAP
in
thinner,
j,
kg
per
kg.
n
=
number
of
different
thinners
used.
(3)
Calculate
CI,
the
mass
of
organic
HAP
in
the
cleaning
materials
used
in
the
controlled
coating
operation,
kg,
using
Equation
1C
of
this
section.
Do
not
include
in
the
calculation
of
CI
the
cleaning
materials
used
during
any
deviation
specified
in
§
63.4963(
c)
or
(d)
that
occurred
during
the
compliance
period.
Include
such
cleaning
materials
in
the
calculation
of
Hunc
in
Equation
1D
of
this
section.
C
Vol
D
W
I
sksksk
p
=
(
)
(
)
(
)
(
)
k=
,,,
Eq.
1C
1
Where:
CI
=
total
mass
of
organic
HAP
in
the
cleaning
materials
used
in
the
controlled
coating
operation
during
the
compliance
period,
excluding
cleaning
materials
used
during
deviations,
kg.
Vols,
k
=
total
volume
of
cleaning
material,
k,
used
during
the
compliance
period
except
during
deviations,
liters.
Ds,
k
=
density
of
cleaning
material,
k,
kg
per
liter.
Ws,
k
=
mass
fraction
of
organic
HAP
in
cleaning
material,
k,
kg
per
kg.
p
=
number
of
different
cleaning
materials
used.
(4)
Calculate
Hunc,
the
mass
of
organic
HAP
in
the
coatings,
thinners,
and
cleaning
materials
used
in
the
controlled
coating
operation
during
deviations
specified
in
§
63.4963(
c)
and
(d),
using
Equation
1D
of
this
section:
H
Vol
D
W
unc
h
h
h
q
=
(
)
(
)
(
)
(
)
h=
Eq.
1D
1
Where:
Hunc
=
total
mass
of
organic
HAP
in
the
coatings,
thinners,
and
cleaning
materials
used
during
all
deviations
specified
in
§
63.4963(
c)
and
(d)
that
occurred
during
the
compliance
period
in
the
controlled
coating
operation,
kg.
Volh
=
total
volume
of
coating,
thinner,
or
cleaning
material,
h,
used
in
the
controlled
coating
operation
during
deviations,
liters.
Dh
=
density
of
coating,
thinner,
or
cleaning
material,
h,
kg
per
liter.
Wh
=
mass
fraction
of
organic
HAP
in
coating,
thinner,
or
cleaning
material,
h,
kg
organic
HAP
per
kg
coating.
q
=
number
of
different
coatings,
thinning
solvents,
or
cleaning
materials.
(i)
[Reserved]
(j)
Calculate
the
organic
HAP
emission
reduction
for
controlled
coating
operations
using
liquid
liquid
material
balance,
HCSR.
For
each
controlled
coating
operation
using
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances,
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Vol.
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No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
calculate
HCSR
by
applying
the
volatile
organic
matter
collection
and
recovery
efficiency
to
the
mass
of
organic
HAP
contained
in
the
coatings,
thinners,
and
cleaning
materials
that
are
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period.
Perform
a
liquidliquid
material
balance
for
each
compliance
period
as
specified
in
paragraphs
(j)(
1)
through
(6)
of
this
section.
Calculate
the
mass
of
organic
HAP
emission
reduction
by
the
solvent
recovery
system
as
specified
in
paragraph
(j)(
7)
of
this
section.
(1)
For
each
solvent
recovery
system,
install,
calibrate,
maintain,
and
operate
according
to
the
manufacturer's
specifications,
a
device
that
indicates
the
cumulative
amount
of
volatile
organic
matter
recovered
by
the
solvent
recovery
system
each
compliance
period.
The
device
must
be
initially
certified
by
the
manufacturer
to
be
accurate
to
within
±
2.0
percent
of
the
mass
of
volatile
organic
matter
recovered.
(2)
For
each
solvent
recovery
system,
determine
the
mass,
M
VR,
of
volatile
organic
matter
recovered
for
the
compliance
period,
kg,
based
on
measurement
with
the
device
required
in
paragraph
(j)(
1)
of
this
section.
(3)
Determine
the
mass
fraction,
CV,
of
volatile
organic
matter
for
each
coating,
thinner,
and
cleaning
material
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period,
kg
volatile
organic
matter
per
kg
coating.
You
may
determine
the
volatile
organic
matter
mass
fraction
using
Method
24
of
40
CFR
part
60,
appendix
A,
or
an
EPA
approved
alternative
method,
or
you
may
use
information
provided
by
the
manufacturer
or
supplier
of
the
coating.
In
the
event
of
any
inconsistency
between
information
provided
by
the
manufacturer
or
supplier
and
the
results
of
Method
24
of
40
CFR
part
60,
appendix
A,
or
an
approved
alternative
method,
the
test
method
results
will
govern.
(4)
Determine
the
density
of
each
coating,
thinner,
and
cleaning
material
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period,
kg
per
liter,
according
to
§
63.4951(
c).
(5)
Measure
the
volume
of
each
coating,
thinner,
and
cleaning
material
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period,
liters.
(6)
Calculate
the
solvent
recovery
system's
volatile
organic
matter
collection
and
recovery
efficiency,
RV,
using
Equation
2
of
this
section:
R
M
Vol
D
WV
Vol
D
WV
Vol
D
WV
v
VR
i
i
ci
jj
tj
kk
sk
p
n
m
=
+
+
(
)
k=
j=
i=
100
1
1
1
,,,
Eq.
2
Where:
RV
=
volatile
organic
matter
collection
and
recovery
efficiency
of
the
solvent
recovery
system
during
the
compliance
period,
percent.
MVR
=
mass
of
volatile
organic
matter
recovered
by
the
solvent
recovery
system
during
the
compliance
period,
kg.
Voli
=
volume
of
coating,
i,
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period,
liters.
Di
=
density
of
coating,
i,
kg
per
liter.
WVc,
i
=
mass
fraction
of
volatile
organic
matter
for
coating,
i,
kg
volatile
organic
matter
per
kg
coating.
Volj
=
volume
of
thinner,
j,
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period,
liters.
Dj
=
density
of
thinner,
j,
kg
per
liter.
WVt,
j
=
mass
fraction
of
volatile
organic
matter
for
thinner,
j,
kg
volatile
organic
matter
per
kg
thinner.
Volk
=
volume
of
cleaning
material,
k,
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period,
liters.
Dk
=
density
of
cleaning
material,
k,
kg
per
liter.
WVs,
k
=
mass
fraction
of
volatile
organic
matter
for
cleaning
material,
k,
kg
volatile
organic
matter
per
kg
cleaning
material.
m
=
number
of
different
coatings
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period.
n
=
number
of
different
thinners
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period.
p
=
number
of
different
cleaning
materials
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period.
(7)
Calculate
the
mass
of
organic
HAP
emission
reduction
for
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period,
HCSR,
using
Equation
3
of
this
section:
H
ABC
R
CSR
I
I
I
V
=
+
+
(
)
(
)
100
Eq.
3
Where:
HCSR
=
mass
of
organic
HAP
emission
reduction
for
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
compliance
period,
kg.
AI
=
total
mass
of
organic
HAP
in
the
coatings
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
kg,
calculated
using
Equation
1A
of
this
section.
BI
=
total
mass
of
organic
HAP
in
the
thinners
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
kg,
calculated
using
Equation
1B
of
this
section.
CI
=
total
mass
of
organic
HAP
in
the
cleaning
materials
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
kg,
calculated
using
Equation
1C
of
this
section.
RV
=
volatile
organic
matter
collection
and
recovery
efficiency
of
the
solvent
recovery
system,
percent,
from
Equation
2
of
this
section.
(k)
Calculate
the
total
volume
of
coating
solids
used.
Determine
Vst,
the
total
volume
of
coating
solids
used,
liters,
which
is
the
combined
volume
of
coating
solids
for
all
the
coatings
used
during
the
compliance
period,
using
Equation
2
of
§
63.4951.
(l)
Calculate
the
organic
HAP
emissions
rate.
Determine
HHAP,
the
organic
HAP
emission
rate
to
the
atmosphere,
kg
organic
HAP
per
liter
coating
solids
used
during
the
compliance
period,
using
either
Equation
4
of
this
section
or
Equation
1
of
§
63.4962.
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
H
H
HH
V
HAP
e
Ci
q
CSR
j
r
st
=
(
)
(
)
(
)
i=
j=
,,
1
1
Eq.
4
Where:
HHAP
=
organic
HAP
emission
rate
for
the
compliance
period,
kg.
He
=
total
mass
of
organic
HAP
emissions
before
add
on
controls
from
all
the
coatings,
thinners,
and
cleaning
materials
used
during
the
compliance
period,
kg,
determined
according
to
paragraph
(f)
of
this
section.
HC,
i
=
total
mass
of
organic
HAP
emission
reduction
for
controlled
coating
operation,
i,
not
using
liquid
liquid
material
balances,
during
the
compliance
kg,
from
Equation
1
of
this
section.
HCSR,
j
=
total
mass
of
organic
HAP
emission
reduction
for
controlled
coating
operation,
j,
using
a
liquid
liquid
material
balance,
during
the
compliance
period,
kg,
from
Equation
3
of
this
section.
Vst
=
total
volume
of
coating
solids
used
during
the
compliance
period,
liters,
from
Equation
2
of
§
63.4951.
q
=
number
of
controlled
coating
operations
except
those
controlled
with
a
solvent
recovery
system.
r
=
number
of
coating
operations
controlled
with
a
solvent
recovery
system.
(m)
Compliance
demonstration.
To
demonstrate
initial
compliance
with
the
emission
limit,
HHAP,
calculated
using
either
Equation
4
of
this
section
or
Equation
1
of
§
63.4962,
must
be
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4890.
You
must
keep
all
records
as
required
by
§§
63.4930
and
63.4931.
As
part
of
the
Notification
of
Compliance
Status
required
by
§
63.4910,
you
must
identify
the
coating
operation(
s)
for
which
you
used
the
emission
rate
with
add
on
controls
option
and
submit
a
statement
that
the
coating
operation(
s)
was
(were)
in
compliance
with
the
emission
limitations
during
the
initial
compliance
period
because
the
organic
HAP
emission
rate
was
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4890,
and
you
achieved
the
operating
limits
required
by
§
63.4892
and
the
work
practice
standards
required
by
§
63.4893.
§
63.4962
How
do
I
determine
the
organic
HAP
emission
rate
for
a
controlled
coating
operation
not
using
a
liquid
liquid
material
balance
if
I
operate
it
under
different
sets
of
representative
operating
conditions?
(a)
This
section
applies
only
to
controlled
coating
operations
for
which
you
do
not
conduct
liquid
liquid
material
balances
to
demonstrate
compliance.
If
you
operate
such
a
controlled
coating
operation,
its
emission
capture
system,
or
its
add
on
control
device
at
multiple
sets
of
representative
operating
conditions
that
result
in
different
capture
system
or
add
on
control
device
efficiencies
during
a
compliance
period,
you
must
determine
the
organic
HAP
emission
rate
according
to
either
paragraph
(b)
or
(c)
of
this
section.
The
cases
described
in
paragraphs
(a)(
1)
and
(2)
of
this
section
are
examples
of
such
operating
conditions.
(1)
You
use
a
single
add
on
control
device
to
reduce
emissions
from
two
or
more
coating
operations
and
the
number
of
coating
operations
vented
to
the
add
on
control
device
is
variable
during
the
compliance
period.
This
case
also
includes
situations
where
you
have
more
than
one
capture
device
on
the
same
coating
operation
and
the
number
of
capture
devices
vented
to
the
add
on
control
device
is
changed
during
the
compliance
period.
(2)
The
coatings
or
cleaning
materials
you
apply
or
the
products
to
which
you
apply
them
differ
during
the
compliance
period,
and
the
differences
in
resulting
emissions
are
such
that
the
emission
capture
efficiency
or
add
on
control
device
efficiency
changes.
This
case
includes
a
change
in
the
shape
or
size
of
the
product
coated
such
that
there
is
a
change
in
capture
efficiency
of
the
capture
system.
This
case
also
includes
a
change
in
the
materials
that
results
in
an
inlet
concentration
to
the
add
on
control
device
that
is
sufficiently
lower
such
that
the
percent
reduction
the
addperiod
on
control
device
can
achieve
changes,
or
a
change
in
the
volatility
of
the
organic
HAP
in
the
materials
used
such
that
a
lower
proportion
of
the
HAP
is
captured
by
the
capture
system
and
a
higher
amount
is
not
captured
by
the
capture
system.
(b)
If
you
conduct
performance
tests
under
the
representative
operating
conditions
that
are
expected
to
result
in
the
lowest
emission
capture
system
and
add
on
control
device
efficiencies,
as
allowed
under
§
63.4964(
b)(
2),
then
determine
the
organic
HAP
emission
rate
according
to
the
procedures
and
equations
in
§
63.4961.
You
do
not
need
to
follow
paragraph
(c)
of
this
section.
(c)
If
you
conduct
performance
tests
under
multiple
sets
of
representative
operating
conditions
to
establish
different
emission
capture
system
and
add
on
control
device
efficiencies
for
each
set
of
operating
conditions,
as
allowed
under
§
63.4964(
b)(
1),
then
determine
the
organic
HAP
emission
rate
according
to
paragraphs
(c)(
1)
and
(2)
of
this
section.
(1)
You
must
use
Equation
1
of
this
section
for
determining
HHAP,
the
organic
HAP
emission
rate,
kg
organic
HAP
emitted
per
liter
coating
solids
used:
H
H
HHH
H
V
HAP
e
q
c
i
c
i
C
r
CSR
st
n
j
=
+
+
(
)
(
)
(
)
i=
j=
1
1
1
2
,,
,i
...
Eq.
1
Where:
HHAP
=
organic
HAP
emission
rate
for
the
compliance
period,
kg
organic
HAP
per
liter
coating
solids.
He
=
total
mass
of
organic
HAP
emissions
before
add
on
controls
from
all
coatings,
thinners,
and
cleaning
materials
used
during
the
compliance
period,
kg,
determined
according
to
§
63.4961(
f).
HC,
i1,
HC,
i2,HC,
in
=
total
mass
of
organic
HAP
emission
reduction,
kg,
for
controlled
coating
operation,
i,
while
operating
under
each
operating
condition,
n,
during
the
compliance
period,
from
Equation
1
of
§
63.4961.
HCSR,
j
=
total
mass
of
organic
HAP
emission
reduction,
kg,
for
controlled
coating
operation,
j,
using
a
liquid
liquid
material
balance
during
the
compliance
period,
from
Equation
3
of
§
63.4961.
Vst
=
total
volume
of
coating
solids
used
during
the
compliance
period,
liters,
from
Equation
2
of
§
63.4951.
n
=
number
of
different
operating
conditions
that
affect
emission
capture
system
efficiency
or
add
on
control
device
organic
HAP
destruction
or
removal
efficiency
under
which
the
coating
operation
operated
during
the
compliance
period.
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q
=
number
of
controlled
coating
operations
not
controlled
by
a
solvent
recovery
system.
r
=
number
of
coating
operations
controlled
by
a
solvent
recovery
system.
(2)
To
determine
the
HC,
in
in
Equation
1
of
this
section,
follow
the
steps
in
paragraphs
(c)(
2)(
i)
through
(iii)
of
this
section.
(i)
Use
Equation
1
of
§
63.4961
to
calculate
the
HC
for
each
operating
condition,
n,
of
each
controlled
coating
operation,
i.
(ii)
For
the
factors
AI,
BI,
and
CI
in
Equation
1
of
§
63.4961,
use
the
mass
of
organic
HAP
contained
in
the
coatings,
thinners,
and
cleaning
materials
used
in
each
controlled
coating
operation,
i,
while
operating
under
each
operating
condition,
n.
(iii)
In
Equation
1
of
§
63.4961,
use
the
emission
capture
system
efficiency
and
addon
control
device
organic
HAP
destruction
or
removal
efficiency
that
apply
under
each
operating
condition,
n.
These
efficiencies
for
each
operating
condition
are
determined
from
the
performance
test
required
by
§
63.4960
and
as
specified
in
§
63.4964(
b).
§
63.4963
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
(a)
To
demonstrate
continuous
compliance
with
the
applicable
emission
limit
in
§
63.4890,
the
organic
HAP
emission
rate
for
each
compliance
period,
determined
according
to
the
procedures
in
§
63.4961
(and
in
§
63.4962,
if
applicable),
must
be
equal
to
or
less
than
the
applicable
emission
limit
in
§
63.4890.
Each
month
following
the
initial
compliance
period
described
in
§
63.4960
is
a
compliance
period.
(b)
If
the
organic
HAP
emission
rate
for
any
compliance
period
exceeded
the
applicable
emission
limit
in
§
63.4890,
this
is
a
deviation
from
the
emission
limitation
for
that
compliance
period
and
must
be
reported
as
specified
in
§§
63.4910(
c)(
6)
and
63.4920(
a)(
7).
(c)
You
must
demonstrate
continuous
compliance
with
each
operating
limit
required
by
§
63.4892
that
applies
to
you,
as
specified
in
Table
1
of
this
subpart.
(1)
If
an
operating
parameter
is
out
of
the
allowed
range
specified
in
Table
1
of
this
subpart,
this
is
a
deviation
from
the
operating
limit
that
must
be
reported
as
specified
in
§§
63.4910(
b)(
6)
and
63.4920(
a)(
7).
(2)
If
an
operating
parameter
deviates
from
the
operating
limit
specified
in
Table
1
of
this
subpart,
then
you
must
assume
that
the
emission
capture
system
and
add
on
control
device
were
achieving
zero
efficiency
during
the
time
period
of
the
deviation.
For
the
purposes
of
completing
the
compliance
calculations
specified
in
§§
63.4961
and
63.4962,
you
must
treat
the
materials
used
during
a
deviation
on
a
controlled
coating
operation
as
if
they
were
used
on
an
uncontrolled
coating
operation
for
the
time
period
of
the
deviation,
as
indicated
in
Equation
1
of
§
63.4961.
(d)
You
must
meet
the
requirements
for
bypass
lines
in
§
63.4968(
b)
for
controlled
coating
operations
for
which
you
do
not
conduct
liquid
liquid
material
balances.
If
any
bypass
line
is
opened
and
emissions
are
diverted
to
the
atmosphere
when
the
coating
operation
is
running,
this
is
a
deviation
that
must
be
reported
as
specified
in
§§
63.4910(
c)(
6)
and
63.4920(
a)(
7).
For
the
purposes
of
completing
the
compliance
calculations
in
§§
63.4961
and
63.4962,
you
must
treat
the
materials
used
during
a
deviation
on
a
controlled
coating
operation
as
if
they
were
used
on
an
uncontrolled
coating
operation
for
the
time
period
of
the
deviation,
as
indicated
in
Equation
1
of
§
63.4961.
(e)
You
must
demonstrate
continuous
compliance
with
the
work
practice
standards
in
§
63.4893.
If
you
did
not
develop
a
work
practice
plan,
or
you
did
not
implement
the
plan,
or
you
did
not
keep
the
records
required
by
§
63.4930(
k)(
9),
this
is
a
deviation
from
the
work
practice
standards
that
must
be
reported
as
specified
in
§§
63.4910(
c)(
6)
and
63.4920(
a)(
7).
(f)
As
part
of
each
semiannual
compliance
report
required
in
§
63.4920,
you
must
identify
the
coating
operation(
s)
for
which
you
used
the
emission
rate
with
add
on
controls
option.
If
there
were
no
deviations
from
the
emission
limitations,
submit
a
statement
that
you
were
in
compliance
with
the
emission
limitations
during
the
reporting
period
because
the
organic
HAP
emission
rate
for
each
compliance
period
was
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4890,
and
you
achieved
the
operating
limits
required
by
§
63.4892
and
the
work
practice
standards
required
by
§
63.4893
during
each
compliance
period.
(g)
During
periods
of
startup,
shutdown,
or
malfunction
of
the
emission
capture
system,
add
on
control
device,
or
coating
operation
that
may
affect
emission
capture
or
control
device
efficiency,
you
must
operate
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan
required
by
§
63.4900(
d).
(h)
Consistent
with
§§
63.6(
e)
and
63.7(
e)(
1),
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
of
the
emission
capture
system,
add
on
control
device,
or
coating
operation
that
may
affect
emission
capture
or
control
device
efficiency
are
not
violations
if
you
demonstrate
to
the
Administrator's
satisfaction
that
you
were
operating
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan.
The
Administrator
will
determine
whether
deviations
that
occur
during
a
period
you
identify
as
a
startup,
shutdown,
or
malfunction
are
violations,
according
to
the
provisions
in
§
63.6(
e).
(i)
[Reserved]
(j)
You
must
maintain
records
as
specified
in
§§
63.4930
and
63.4931.
§
63.4964
What
are
the
general
requirements
for
performance
tests?
(a)
You
must
conduct
each
performance
test
required
by
§
63.4960
according
to
the
requirements
in
§
63.7(
e)(
1)
and
under
the
conditions
in
this
section
unless
you
obtain
a
waiver
of
the
performance
test
according
to
the
provisions
in
§
63.7(
h).
(1)
Representative
coating
operation
operating
conditions.
You
must
conduct
the
performance
test
under
representative
operating
conditions
for
the
coating
operation.
Operations
during
periods
of
startup,
shutdown,
or
malfunction,
and
periods
of
nonoperation
do
not
constitute
representative
conditions.
You
must
record
the
process
information
that
is
necessary
to
document
operating
conditions
during
the
test
and
explain
why
the
conditions
represent
normal
operation.
(2)
Representative
emission
capture
system
and
add
on
control
device
operating
conditions.
You
must
conduct
the
performance
test
when
the
emission
capture
system
and
add
on
control
device
are
operating
at
a
representative
flow
rate,
and
the
add
on
control
device
is
operating
at
a
representative
inlet
concentration.
You
must
record
information
that
is
necessary
to
document
emission
capture
system
and
add
on
control
device
operating
conditions
during
the
test
and
explain
why
the
conditions
represent
normal
operation.
(b)
If
the
coating
operation,
emission
capture
system,
or
add
on
control
device
will
be
operated
at
different
sets
of
representative
operating
conditions,
you
must
conduct
the
performance
test
according
to
either
paragraph
(b)(
1)
or
(2)
of
this
section:
(1)
Test
at
each
of
the
representative
operating
conditions
and
establish
emission
capture
system
and
add
on
control
device
efficiencies
and
operating
limits
for
each
operating
condition.
To
demonstrate
continuous
compliance
following
the
performance
test,
record
the
conditions
under
which
the
process,
emission
capture
system,
and
add
on
control
device
are
operating
during
each
time
period
of
operation,
and
calculate
the
organic
HAP
emission
rate
as
described
in
§
63.4962.
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2002
/
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Rules
(2)
Test
at
the
representative
operating
conditions
that
are
expected
to
result
in
the
lowest
emission
capture
system
and
add
on
control
device
efficiencies
and
establish
efficiencies
and
operating
limits
based
on
this
test.
Use
these
efficiencies
in
the
emission
calculations
in
§
63.4961.
(c)
You
must
conduct
each
performance
test
of
an
emission
capture
system
according
to
the
requirements
in
§
63.4965.
You
must
conduct
each
performance
test
of
an
add
on
control
device
according
to
the
requirements
in
§
63.4966.
(d)
The
performance
test
to
determine
add
on
control
device
organic
HAP
destruction
or
removal
efficiency
must
consist
of
three
runs
as
specified
in
§
63.7(
e)(
3)
and
each
run
must
last
at
least
1
hour.
§
63.4965
How
do
I
determine
the
emission
capture
system
efficiency?
You
must
use
the
procedures
and
test
methods
in
this
section
to
determine
capture
efficiency
as
part
of
the
performance
test
required
by
§
63.4960.
(a)
Assuming
100
percent
capture
efficiency.
You
may
assume
the
capture
system
efficiency
is
100
percent
if
both
of
the
conditions
in
paragraphs
(a)(
1)
and
(2)
of
this
section
are
met:
(1)
The
capture
system
meets
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
a
PTE
and
directs
all
the
exhaust
gases
from
the
enclosure
to
an
add
on
control
device.
(2)
All
coatings,
thinners,
and
cleaning
materials
used
in
the
coating
operation
are
applied
within
the
capture
system;
coating
solvent
flash
off
and
coating,
curing,
and
drying
occurs
within
the
capture
system;
and
the
removal
of
or
evaporation
of
cleaning
materials
from
the
surfaces
they
are
applied
to
occurs
within
the
capture
system.
For
example,
this
criterion
is
not
met
if
parts
enter
the
open
shop
environment
when
being
moved
between
a
spray
booth
and
a
curing
oven.
(b)
Measuring
capture
efficiency.
If
the
capture
system
does
not
meet
both
of
the
criteria
in
paragraphs
(a)(
1)
and
(2)
of
this
section,
then
you
must
use
one
of
the
three
protocols
described
in
paragraphs
(c),
(d),
and
(e)
of
this
section
to
measure
capture
efficiency.
The
capture
efficiency
measurements
use
TVH
capture
efficiency
as
a
surrogate
for
organic
HAP
capture
efficiency.
For
the
protocols
in
paragraphs
(c)
and
(d)
of
this
section,
the
capture
efficiency
measurement
must
consist
of
three
test
runs.
Each
test
run
must
be
at
least
3
hours
duration
or
the
length
of
a
production
run,
whichever
is
longer,
up
to
8
hours.
For
the
purposes
of
this
test,
a
production
run
means
the
time
required
for
a
single
part
to
go
from
the
beginning
to
the
end
of
production,
which
includes
surface
preparation
activities
and
drying
or
curing
time.
(c)
Liquid
to
uncaptured
gas
protocol
using
a
temporary
total
enclosure
or
building
enclosure.
The
liquid
touncaptured
gas
protocol
compares
the
mass
of
liquid
TVH
in
materials
used
in
the
coating
operation,
referred
to
as
TVHused,
to
the
mass
of
TVH
emissions
not
captured
by
the
emission
capture
system,
referred
to
as
TVHuncaptured.
Use
a
temporary
total
enclosure
or
a
building
enclosure
and
the
procedures
in
paragraphs
(c)(
1)
through
(6)
of
this
section
to
measure
emission
capture
system
efficiency
using
the
liquid
touncaptured
gas
protocol.
(1)
Either
use
a
building
enclosure
or
construct
an
enclosure
around
the
coating
operation
where
coatings,
thinners,
and
cleaning
materials
are
applied,
and
all
areas
where
emissions
from
these
applied
coatings
and
materials
subsequently
occur,
such
as
flash
off,
curing,
and
drying
areas.
The
areas
of
the
coating
operation
where
capture
devices
collect
emissions
for
routing
to
an
add
on
control
device,
such
as
the
entrance
and
exit
areas
of
an
oven
or
spray
booth,
must
also
be
inside
the
enclosure.
The
enclosure
must
meet
the
applicable
definition
of
a
temporary
total
enclosure
or
building
enclosure
in
Method
204
of
appendix
M
to
40
CFR
part
51.
(2)
Use
Method
204A
or
204F
of
appendix
M
to
40
CFR
part
51
to
determine
the
mass
fraction,
kg
TVH
per
kg
material,
of
TVH
liquid
input
from
each
coating,
thinner,
and
cleaning
material
used
in
the
coating
operation
during
each
capture
efficiency
test
run.
To
make
the
determination,
substitute
TVH
for
each
occurrence
of
the
term
volatile
organic
compounds
(VOC)
in
the
methods.
(3)
Use
Equation
1
of
this
section
to
calculate
TVHused,
the
total
mass
of
TVH
liquid
input
from
all
the
coatings,
thinners,
and
cleaning
materials
used
in
the
coating
operation
during
each
capture
efficiency
test
run:
TVH
TVH
Vol
D
used
i
i
i
n
=
(
)
(
)
(
)
(
)
i=
Eq.
1
1
Where:
TVHi
=
mass
fraction
of
TVH
in
coating,
thinner,
or
cleaning
material,
i,
that
is
used
in
the
coating
operation
during
the
capture
efficiency
test
run,
kg
TVH
per
kg
material.
Voli
=
total
volume
of
coating,
thinner,
or
cleaning
material,
i,
used
in
the
coating
operation
during
the
capture
efficiency
test
run,
liters.
Di
=
density
of
coating,
thinner,
or
cleaning
material,
i,
kg
material
per
liter
material.
n
=
number
of
different
coatings,
thinners,
and
cleaning
materials
used
in
the
coating
operation
during
the
capture
efficiency
test
run.
(4)
Use
Method
204D
or
E
of
appendix
M
to
40
CFR
part
51
to
measure
TVHuncaptured,
the
total
mass,
kg,
of
TVH
emissions
that
are
not
captured
by
the
emission
capture
system;
they
are
measured
as
they
exit
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run.
To
make
the
measurement,
substitute
TVH
for
each
occurrence
of
the
term
VOC
in
the
methods.
(i)
Use
Method
204D
if
the
enclosure
is
a
temporary
total
enclosure.
(ii)
Use
Method
204E
if
the
enclosure
is
a
building
enclosure.
During
the
capture
efficiency
measurement,
all
organic
compound
emitting
operations
inside
the
building
enclosure,
other
than
the
coating
operation
for
which
capture
efficiency
is
being
determined,
must
be
shut
down,
but
all
fans
and
blowers
must
be
operating
normally.
(5)
For
each
capture
efficiency
test
run,
determine
the
percent
capture
efficiency,
CE,
of
the
emission
capture
system
using
Equation
2
of
this
section:
CE
TVH
TVH
TVH
used
uncaptured
used
=
(
)
×
(
)
100
Eq.
2
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/
Proposed
Rules
Where:
CE
=
capture
efficiency
of
the
emission
capture
system
vented
to
the
add
on
control
device,
percent.
TVHused
=
total
mass
of
TVH
liquid
input
used
in
the
coating
operation
during
the
capture
efficiency
test
run,
kg.
TVHuncaptured
=
total
mass
of
TVH
that
is
not
captured
by
the
emission
capture
system
and
that
exits
from
the
temporary
total
enclosure
or
building
enclosure
during
the
capture
efficiency
test
run,
kg.
(6)
Determine
the
capture
efficiency
of
the
emission
capture
system
as
the
average
of
the
capture
efficiencies
measured
in
the
three
test
runs.
(d)
Gas
to
gas
protocol
using
a
temporary
total
enclosure
or
a
building
enclosure.
The
gas
to
gas
protocol
compares
the
mass
of
TVH
emissions
captured
by
the
emission
capture
system,
referred
to
as
TVHcaptured,
to
the
mass
of
TVH
emissions
not
captured,
referred
to
as
TVHuncaptured.
Use
a
temporary
total
enclosure
or
a
building
enclosure
and
the
procedures
in
paragraphs
(d)(
1)
through
(5)
of
this
section
to
measure
emission
capture
system
efficiency
using
the
gas
to
gas
protocol.
(1)
Either
use
a
building
enclosure
or
construct
an
enclosure
around
the
coating
operation
where
coatings,
thinners,
and
cleaning
materials
are
applied,
and
all
areas
where
emissions
from
these
applied
coatings
and
materials
subsequently
occur,
such
as
flash
off,
curing,
and
drying
areas.
The
areas
of
the
coating
operation
where
capture
devices
collect
emissions
generated
by
the
coating
operation
for
routing
to
an
add
on
control
device,
such
as
the
entrance
and
exit
areas
of
an
oven
or
a
spray
booth,
must
also
be
inside
the
enclosure.
The
enclosure
must
meet
the
applicable
definition
of
a
temporary
total
enclosure
or
building
enclosure
in
Method
204
of
appendix
M
to
40
CFR
part
51.
(2)
Use
Method
204B
or
204C
of
appendix
M
to
40
CFR
part
51
to
measure
TVHcaptured,
the
total
mass,
kg,
of
TVH
emissions
captured
by
the
emission
capture
system
during
each
capture
efficiency
test
run
as
measured
at
the
inlet
to
the
add
on
control
device.
To
make
the
measurement,
substitute
TVH
for
each
occurrence
of
the
term
VOC
in
the
methods.
(i)
The
sampling
points
for
the
Method
204B
or
204C
measurement
must
be
upstream
from
the
add
on
control
device
and
must
represent
total
emissions
routed
from
the
capture
system
and
entering
the
add
on
control
device.
(ii)
If
multiple
emission
streams
from
the
capture
system
enter
the
add
on
control
device
without
a
single
common
duct,
then
the
emissions
entering
the
add
on
control
device
must
be
simultaneously
measured
in
each
duct
and
the
total
emissions
entering
the
add
on
control
device
must
be
determined.
(3)
Use
Method
204D
or
204E
of
appendix
M
to
40
CFR
part
51
to
measure
TVHuncaptured,
the
total
mass,
kg,
of
TVH
emissions
that
are
not
captured
by
the
emission
capture
system;
they
are
measured
as
they
exit
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run.
To
make
the
measurement,
substitute
TVH
for
each
occurrence
of
the
term
VOC
in
the
methods.
(i)
Use
Method
204D
if
the
enclosure
is
a
temporary
total
enclosure.
(ii)
Use
Method
204E
if
the
enclosure
is
a
building
enclosure.
During
the
capture
efficiency
measurement,
all
organic
compound
emitting
operations
inside
the
building
enclosure,
other
than
the
coating
operation
for
which
capture
efficiency
is
being
determined,
must
be
shut
down,
but
all
fans
and
blowers
must
be
operating
normally.
(4)
For
each
capture
efficiency
test
run,
determine
the
percent
capture
efficiency,
CE,
of
the
emission
capture
system
using
Equation
3
of
this
section:
CE
TVH
TVH
TVH
captured
captured
uncaptured
=
+
(
)
×
(
)
100
Eq.
3
Where:
CE
=
capture
efficiency
of
the
emission
capture
system
vented
to
the
add
on
control
device,
percent.
TVHcaptuted
=
total
mass
of
TVH
captured
by
the
emission
capture
system
as
measured
at
the
inlet
to
the
add
on
control
device
during
the
emission
capture
efficiency
test
run,
kg.
TVHuncaptured
=
total
mass
of
TVH
that
is
not
captured
by
the
emission
capture
system
and
that
exits
from
the
temporary
total
enclosure
or
building
enclosure
during
the
capture
efficiency
test
run,
kg.
(5)
Determine
the
capture
efficiency
of
the
emission
capture
system
as
the
average
of
the
capture
efficiencies
measured
in
the
three
test
runs.
(e)
Alternative
capture
efficiency
protocol.
As
an
alternative
to
the
procedures
specified
in
paragraphs
(c)
and
(d)
of
this
section,
you
may
determine
capture
efficiency
using
any
other
capture
efficiency
protocol
and
test
methods
that
satisfy
the
criteria
of
either
the
DQO
or
LCL
approach
as
described
in
appendix
A
to
subpart
KK
of
this
part.
§
63.4966
How
do
I
determine
the
add
on
control
device
emission
destruction
or
removal
efficiency?
You
must
use
the
procedures
and
test
methods
in
this
section
to
determine
the
add
on
control
device
emission
destruction
or
removal
efficiency
as
part
of
the
performance
test
required
by
§
63.4960.
You
must
conduct
three
test
runs
as
specified
in
§
63.7(
e)(
3),
and
each
test
run
must
last
at
least
1
hour.
(a)
For
all
types
of
add
on
control
devices,
use
the
test
methods
specified
in
paragraphs
(a)(
1)
through
(5)
of
this
section.
(1)
Use
Method
1
or
1A
of
appendix
A
to
40
CFR
part
60,
as
appropriate,
to
select
sampling
sites
and
velocity
traverse
points.
(2)
Use
Method
2,
2A,
2C,
2D,
2F,
or
2G
of
appendix
A
to
40
CFR
part
60,
as
appropriate,
to
measure
gas
volumetric
flow
rate.
(3)
Use
Method
3,
3A,
or
3B
of
appendix
A
to
40
CFR
part
60,
as
appropriate,
for
gas
analysis
to
determine
dry
molecular
weight.
(4)
Use
Method
4
of
appendix
A
to
40
CFR
part
60,
to
determine
stack
gas
moisture.
(5)
Methods
for
determining
gas
volumetric
flow
rate,
dry
molecular
weight,
and
stack
gas
moisture
must
be
performed,
as
applicable,
during
each
test
run.
(b)
Measure
total
gaseous
organic
mass
emissions
as
carbon
at
the
inlet
and
outlet
of
the
add
on
control
device
simultaneously,
using
either
Method
25
or
25A
of
appendix
A
to
40
CFR
part
60,
as
specified
in
paragraphs
(b)(
1)
through
(3)
of
this
section.
You
must
use
the
same
method
for
both
the
inlet
and
outlet
measurements.
(1)
Use
Method
25
if
the
add
on
control
device
is
an
oxidizer
and
you
expect
the
total
gaseous
organic
concentration
as
carbon
to
be
more
than
50
parts
per
million
(ppm)
at
the
control
device
outlet.
(2)
Use
Method
25A
if
the
add
on
control
device
is
an
oxidizer
and
you
expect
the
total
gaseous
organic
concentration
as
carbon
to
be
50
ppm
or
less
at
the
control
device
outlet.
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/
Vol.
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No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
(3)
Use
Method
25A
if
the
add
control
device
is
not
an
oxidizer.
(c)
If
two
or
more
add
on
control
devices
are
used
for
the
same
emission
stream,
then
you
must
measure
emissions
at
the
outlet
of
each
device.
For
example,
if
one
add
on
control
device
is
a
concentrator
with
an
outlet
for
the
high
volume,
dilute
stream
that
has
been
treated
by
the
concentrator,
and
a
second
add
on
control
device
is
an
oxidizer
with
an
outlet
for
the
lowvolume
concentrated
stream
that
is
treated
with
the
oxidizer,
you
must
measure
emissions
at
the
outlet
of
the
oxidizer
and
the
high
volume
dilute
stream
outlet
of
the
concentrator.
(d)
For
each
test
run,
determine
the
total
gaseous
organic
emissions
mass
flow
rates
for
the
inlet
and
the
outlet
of
the
add
on
control
device,
using
Equation
1
of
this
section.
If
there
is
more
than
one
inlet
or
outlet
to
the
addon
control
device,
you
must
calculate
the
total
gaseous
organic
mass
flow
rate
using
Equation
1
of
this
section
for
each
inlet
and
each
outlet
and
then
total
all
of
the
inlet
emissions
and
total
all
of
the
outlet
emissions.
M
QC
Eq
f
sdc
=
(
)
(
)
(
)
(
)
12
0
0416
10
6
..
1
Where:
Mf
=
total
gaseous
organic
emissions
mass
flow
rate,
kg/
per
hour
(h).
Cc
=
concentration
of
organic
compounds
as
carbon
in
the
vent
gas,
as
determined
by
Method
25
or
Method
25A,
parts
per
million
by
volume
(ppmv),
dry
basis.
Qsd
=
volumetric
flow
rate
of
gases
entering
or
exiting
the
add
on
control
device,
as
determined
by
Method
2,
2A,
2C,
2D,
2F,
or
2G,
dry
standard
cubic
meters/
hour
(dscm/
h).
0.0416
=
conversion
factor
for
molar
volume,
kg
moles
per
cubic
meter
(mol/
m
3
)
(@
293
Kelvin
(K)
and
760
millimeters
of
mercury
(mmHg)).
(e)
For
each
test
run,
determine
the
add
on
control
device
organic
emissions
destruction
or
removal
efficiency,
DRE,
using
Equation
2
of
this
section:
DRE
M
M
M
Eq
fi
fo
fi
=
(
)
.
2
Where:
DRE
=
organic
emissions
destruction
or
removal
efficiency
of
the
add
on
control
device,
percent.
Mfi
=
total
gaseous
organic
emissions
mass
flow
rate
at
the
inlet(
s)
to
the
add
on
control
device,
using
Equation
1
of
this
section,
kg/
h.
Mfo
=
total
gaseous
organic
emissions
mass
flow
rate
at
the
outlet(
s)
of
the
add
on
control
device,
using
Equation
1
of
this
section,
kg/
h.
(f)
Determine
the
emission
destruction
or
removal
efficiency
of
the
add
on
control
device
as
the
average
of
the
efficiencies
determined
in
the
three
test
runs
and
calculated
in
Equation
2
of
this
section.
§
63.4967
How
do
I
establish
the
emission
capture
system
and
add
on
control
device
operating
limits
during
the
performance
test?
During
the
performance
test
required
by
§
63.4960
and
described
in
§§
63.4964,
63.4965,
and
63.4966,
you
must
establish
the
operating
limits
required
by
§
63.4892
according
to
this
section,
unless
you
have
received
approval
for
alternative
monitoring
and
operating
limits
under
§
63.8(
f)
as
specified
in
§
63.4892.
(a)
Thermal
oxidizers.
If
your
add
on
control
device
is
a
thermal
oxidizer,
establish
the
operating
limits
according
to
paragraphs
(a)(
1)
and
(2)
of
this
section.
(1)
During
the
performance
test,
you
must
monitor
and
record
the
combustion
temperature
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
You
must
monitor
the
temperature
in
the
firebox
of
the
thermal
oxidizer
or
immediately
downstream
of
the
firebox
before
any
substantial
heat
exchange
occurs.
(2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
combustion
temperature
maintained
during
the
performance
test.
This
average
combustion
temperature
is
the
minimum
operating
limit
for
your
thermal
oxidizer,
unless
you
are
determining
operating
limits
for
multiple
operating
conditions
as
specified
in
§
63.4964(
b)(
1)
and
paragraph
(f)
of
this
section.
(b)
Catalytic
oxidizers.
If
your
add
on
control
device
is
a
catalytic
oxidizer,
establish
the
operating
limits
according
to
either
paragraphs
(b)(
1)
and
(2)
or
paragraphs
(b)(
3)
and
(4)
of
this
section.
(1)
During
the
performance
test,
you
must
monitor
and
record
the
temperature
just
before
the
catalyst
bed
and
the
temperature
difference
across
the
catalyst
bed
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
(2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
temperature
just
before
the
catalyst
bed
and
the
average
temperature
difference
across
the
catalyst
bed
maintained
during
the
performance
test.
These
are
the
minimum
operating
limits
for
your
catalytic
oxidizer,
unless
you
are
determining
operating
limits
for
multiple
operating
conditions
as
specified
in
§
63.4964(
b)(
1)
and
paragraph
(f)
of
this
section.
(3)
As
an
alternative
to
monitoring
the
temperature
difference
across
the
catalyst
bed,
you
may
monitor
the
temperature
at
the
inlet
to
the
catalyst
bed
and
implement
a
site
specific
inspection
and
maintenance
plan
for
your
catalytic
oxidizer
as
specified
in
paragraph
(b)(
4)
of
this
section.
During
the
performance
test,
you
must
monitor
and
record
the
temperature
just
before
the
catalyst
bed
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
temperature
just
before
the
catalyst
bed
during
the
performance
test.
This
is
the
minimum
operating
limit
for
your
catalytic
oxidizer,
unless
you
are
determining
operating
limits
for
multiple
operating
conditions
as
specified
in
§
63.4964(
b)(
1)
and
paragraph
(f)
of
this
section.
(4)
You
must
develop
and
implement
an
inspection
and
maintenance
plan
for
your
catalytic
oxidizer(
s)
for
which
you
elect
to
monitor
according
to
paragraph
(b)(
3)
of
this
section.
The
plan
must
address,
at
a
minimum,
the
elements
specified
in
paragraphs
(b)(
4)(
i)
through
(iii)
of
this
section.
(i)
Annual
sampling
and
analysis
of
the
catalyst
activity
(i.
e.,
conversion
efficiency)
following
the
manufacturer's
or
catalyst
supplier's
recommended
procedures.
(ii)
Monthly
inspection
of
the
oxidizer
system,
including
the
burner
assembly
and
fuel
supply
lines
for
problems
and,
as
necessary,
adjust
the
equipment
to
assure
proper
air
to
fuel
mixtures.
(iii)
Annual
internal
and
monthly
external
visual
inspection
of
the
catalyst
bed
to
check
for
channeling,
abrasion,
and
settling.
If
problems
are
found,
you
must
replace
the
catalyst
bed
and
conduct
a
new
performance
test
to
determine
destruction
efficiency
according
to
§
63.4966.
(c)
Carbon
adsorbers.
If
your
add
on
control
device
is
a
carbon
adsorber,
establish
the
operating
limits
according
to
paragraphs
(c)(
1)
and
(2)
of
this
section.
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79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
(1)
You
must
monitor
and
record
the
total
regeneration
desorbing
gas
(e.
g.,
steam
or
nitrogen)
mass
flow
for
each
regeneration
cycle,
and
the
carbon
bed
temperature
after
each
carbon
bed
regeneration
and
cooling
cycle,
for
the
regeneration
cycle
either
immediately
preceding
or
immediately
following
the
performance
test.
(2)
The
operating
limits
for
your
carbon
adsorber
are
the
minimum
total
desorbing
gas
mass
flow
recorded
during
the
regeneration
cycle,
and
the
maximum
carbon
bed
temperature
recorded
after
the
cooling
cycle,
unless
you
are
determining
operating
limits
for
multiple
operating
conditions
as
specified
in
§
63.4964(
b)(
1)
and
paragraph
(f)
of
this
section.
(d)
Condensers.
If
your
add
on
control
device
is
a
condenser,
establish
the
operating
limits
according
to
paragraphs
(d)(
1)
and
(2)
of
this
section.
(1)
During
the
performance
test,
you
must
monitor
and
record
the
condenser
outlet
(product
side)
gas
temperature
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
(2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
condenser
outlet
(product
side)
gas
temperature
maintained
during
the
performance
test.
This
average
condenser
outlet
gas
temperature
is
the
maximum
operating
limit
for
your
condenser,
unless
you
are
determining
operating
limits
for
multiple
operating
conditions
as
specified
in
§
63.4964(
b)(
1)
and
paragraph
(f)
of
this
section.
(e)
Emission
capture
system.
For
each
capture
device
that
is
not
part
of
a
PTE
that
meets
the
criteria
of
§
63.4965(
a),
establish
an
operating
limit
for
either
the
gas
volumetric
flow
rate
or
duct
static
pressure,
as
specified
in
paragraphs
(e)(
1)
and
(2)
of
this
section.
The
operating
limit
for
a
PTE
is
specified
in
Table
1
of
this
subpart.
(1)
During
the
capture
efficiency
determination
required
by
§
63.4960
and
described
in
§§
63.4964
and
63.4965,
you
must
monitor
and
record
either
the
gas
volumetric
flow
rate
or
the
duct
static
pressure
for
each
separate
capture
device
in
your
emission
capture
system
at
least
once
every
15
minutes
during
each
of
the
three
test
runs
at
a
point
in
the
duct
between
the
capture
device
and
the
add
on
control
device
inlet.
(2)
Calculate
and
record
the
average
gas
volumetric
flow
rate
or
duct
static
pressure
for
the
three
test
runs
for
each
capture
device.
This
average
gas
volumetric
flow
rate
or
duct
static
pressure
is
the
minimum
operating
limit
for
that
specific
capture
device,
unless
you
are
determining
operating
limits
for
multiple
operating
conditions
as
specified
in
§
63.4964(
b)(
1)
and
paragraph
(f)
of
this
section.
(f)
Multiple
operating
conditions.
If
you
are
determining
operating
limits
for
multiple
operating
conditions
for
the
emission
capture
system
or
add
on
control
device
as
specified
in
§
63.4964(
b)(
1),
you
must
conduct
a
performance
test
under
each
operating
condition
and
establish
the
operating
limits
for
the
parameters
under
each
operating
condition
according
to
paragraphs
(f)(
1)
and
(2)
of
this
section.
(1)
You
must
monitor
and
record
the
value
of
the
parameter
that
corresponds
to
the
applicable
operating
limit
during
the
performance
test
under
each
operating
condition.
(2)
The
average
parameter
value
recorded
during
the
performance
test
under
each
condition
is
the
operating
limit
for
that
parameter
when
the
coating
operation
is
operating
under
that
condition.
(g)
Concentrators.
If
your
add
on
control
device
includes
a
concentrator,
you
must
establish
operating
limits
for
the
concentrator
according
to
paragraphs
(g)(
1)
and
(2)
of
this
section.
(1)
During
the
performance
test,
you
must
monitor
and
record
the
desorption
concentrate
stream
gas
temperature
at
least
once
every
15
minutes
during
each
of
the
three
runs
of
the
performance
test.
(2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
temperature.
This
is
the
minimum
operating
limit
for
the
desorption
concentrate
gas
stream
temperature.
(3)
During
the
performance
test,
you
must
monitor
and
record
the
pressure
drop
of
the
dilute
stream
across
the
concentrator
at
least
once
every
15
minutes
during
each
of
the
three
runs
of
the
performance
test.
(4)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
pressure
drop.
This
is
the
maximum
operating
limit
for
the
dilute
stream
across
the
concentrator.
§
63.4968
What
are
the
requirements
for
continuous
parameter
monitoring
system
(CPMS)
installation,
operation,
and
maintenance?
(a)
General.
You
must
install,
operate,
and
maintain
each
CPMS
specified
in
paragraphs
(c),
(e),
and
(f)
of
this
section
according
to
paragraphs
(a)(
1)
through
(6)
of
this
section.
You
must
install,
operate,
and
maintain
each
CPMS
specified
in
paragraphs
(b)
and
(d)
of
this
section
according
to
paragraphs
(a)(
3)
through
(5)
of
this
section.
(1)
The
CPMS
must
complete
a
minimum
of
one
cycle
of
operation
for
each
successive
15
minute
period.
You
must
have
a
minimum
of
four
equally
spaced
successive
cycles
of
CPMS
operation
in
1
hour.
(2)
You
must
determine
the
average
of
all
recorded
readings
for
each
successive
3
hour
period
of
the
emission
capture
system
and
add
on
control
device
operation.
(3)
You
must
record
the
results
of
each
inspection,
calibration,
and
validation
check
of
the
CPMS.
(4)
You
must
maintain
the
CPMS
at
all
times
and
have
available
necessary
parts
for
routine
repairs
of
the
monitoring
equipment.
(5)
You
must
operate
the
CPMS
and
collect
emission
capture
system
and
add
on
control
device
parameter
data
at
all
times
that
a
controlled
coating
operation
is
operating,
except
during
monitoring
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
(including,
if
applicable,
calibration
checks
and
required
zero
and
span
adjustments).
(6)
You
must
not
use
emission
capture
system
or
add
on
control
device
parameter
data
recorded
during
monitoring
malfunctions,
associated
repairs,
out
of
control
periods,
or
required
quality
assurance
or
control
activities
when
calculating
data
averages.
You
must
use
all
the
data
collected
during
all
other
periods
in
calculating
the
data
averages
for
determining
compliance
with
the
emission
capture
system
and
add
on
control
device
operating
limits.
(7)
A
monitoring
malfunction
is
any
sudden,
infrequent,
not
reasonably
preventable
failure
of
the
CPMS
to
provide
valid
data.
Monitoring
failures
that
are
caused
in
part
by
poor
maintenance
or
careless
operation
are
not
malfunctions.
Any
period
for
which
the
monitoring
system
is
out
of
control
and
data
are
not
available
for
required
calculations
is
a
deviation
from
the
monitoring
requirements.
(b)
Capture
system
bypass
line.
You
must
meet
the
requirements
of
paragraphs
(b)(
1)
and
(2)
of
this
section
for
each
emission
capture
system
that
contains
bypass
lines
that
could
divert
emissions
away
from
the
add
on
control
device
to
the
atmosphere.
(1)
You
must
monitor
or
secure
the
valve
or
closure
mechanism
controlling
the
bypass
line
in
a
nondiverting
position
in
such
a
way
that
the
valve
or
closure
mechanism
cannot
be
opened
without
creating
a
record
that
the
valve
was
opened.
The
method
used
to
monitor
or
secure
the
valve
or
closure
mechanism
must
meet
one
of
the
requirements
specified
in
paragraphs
(b)(
1)(
i)
through
(iv)
of
this
section.
(i)
Flow
control
position
indicator.
Install,
calibrate,
maintain,
and
operate
according
to
the
manufacturer's
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/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
specifications
a
flow
control
position
indicator
that
takes
a
reading
at
least
once
every
15
minutes
and
provides
a
record
indicating
whether
the
emissions
are
directed
to
the
add
on
control
device
or
diverted
from
the
add
on
control
device.
The
time
of
occurrence
and
flow
control
position
must
be
recorded,
as
well
as
every
time
the
flow
direction
is
changed.
The
flow
control
position
indicator
must
be
installed
at
the
entrance
to
any
bypass
line
that
could
divert
the
emissions
away
from
the
addon
control
device
to
the
atmosphere.
(ii)
Car
seal
or
lock
and
key
valve
closures.
Secure
any
bypass
line
valve
in
the
closed
position
with
a
car
seal
or
a
lock
and
key
type
configuration.
You
must
visually
inspect
the
seal
or
closure
mechanism
at
least
once
every
month
to
ensure
that
the
valve
is
maintained
in
the
closed
position,
and
the
emissions
are
not
diverted
away
from
the
add
on
control
device
to
the
atmosphere.
(iii)
Valve
closure
monitoring.
Ensure
that
any
bypass
line
valve
is
in
the
closed
(non
diverting)
position
through
monitoring
of
valve
position
at
least
once
every
15
minutes.
You
must
inspect
the
monitoring
system
at
least
once
every
month
to
verify
that
the
monitor
will
indicate
valve
position.
(iv)
Automatic
shutdown
system.
Use
an
automatic
shutdown
system
in
which
the
coating
operation
is
stopped
when
flow
is
diverted
by
the
bypass
line
away
from
the
add
on
control
device
to
the
atmosphere
when
the
coating
operation
is
running.
You
must
inspect
the
automatic
shutdown
system
at
least
once
every
month
to
verify
that
it
will
detect
diversions
of
flow
and
shut
down
the
coating
operation.
(2)
If
any
bypass
line
is
opened,
you
must
include
a
description
of
why
the
bypass
line
was
opened
and
the
length
of
time
it
remained
open
in
the
semiannual
compliance
reports
required
in
§
63.4920.
(c)
Thermal
oxidizers
and
catalytic
oxidizers.
If
you
are
using
a
thermal
oxidizer
or
catalytic
oxidizer
as
an
addon
control
device
(including
those
used
with
concentrators
or
with
carbon
adsorbers
to
treat
desorbed
concentrate
streams),
you
must
comply
with
the
requirements
in
paragraphs
(c)(
1)
through
(3)
of
this
section:
(1)
For
a
thermal
oxidizer,
install
a
gas
temperature
monitor
in
the
firebox
of
the
thermal
oxidizer
or
in
the
duct
immediately
downstream
of
the
firebox
before
any
substantial
heat
exchange
occurs.
(2)
For
a
catalytic
oxidizer,
install
gas
temperature
monitors
both
upstream
and
downstream
of
the
catalyst
bed.
The
temperature
monitors
must
be
in
the
gas
stream
immediately
before
and
after
the
catalyst
bed
to
measure
the
temperature
difference
across
the
bed.
(3)
For
all
thermal
oxidizers
and
catalytic
oxidizers,
you
must
meet
the
requirements
in
paragraphs
(a)
and
(c)(
3)(
i)
through
(vii)
of
this
section
for
each
gas
temperature
monitoring
device.
(i)
Locate
the
temperature
sensor
in
a
position
that
provides
a
representative
temperature.
(ii)
Use
a
temperature
sensor
with
a
measurement
sensitivity
of
4
degrees
Fahrenheit
or
0.75
percent
of
the
temperature
value,
whichever
is
larger.
(iii)
Shield
the
temperature
sensor
system
from
electromagnetic
interference
and
chemical
contaminants.
(iv)
If
a
gas
temperature
chart
recorder
is
used,
it
must
have
a
measurement
sensitivity
in
the
minor
division
of
at
least
20
degrees
Fahrenheit.
(v)
Perform
an
electronic
calibration
at
least
semiannually
according
to
the
procedures
in
the
manufacturer's
owners
manual.
Following
the
electronic
calibration,
you
must
conduct
a
temperature
sensor
validation
check
in
which
a
second
or
redundant
temperature
sensor
placed
nearby
the
process
temperature
sensor
must
yield
a
reading
within
30
degrees
Fahrenheit
of
the
process
temperature
sensor's
reading.
(vi)
Conduct
calibration
and
validation
checks
any
time
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
temperature
range
or
install
a
new
temperature
sensor.
(vii)
At
least
monthly,
inspect
components
for
integrity
and
electrical
connections
for
continuity,
oxidation,
and
galvanic
corrosion.
(d)
Carbon
adsorbers.
If
you
are
using
a
carbon
adsorber
as
an
add
on
control
device,
you
must
monitor
the
total
regeneration
desorbing
gas
(e.
g.,
steam
or
nitrogen)
mass
flow
for
each
regeneration
cycle,
the
carbon
bed
temperature
after
each
regeneration
and
cooling
cycle,
and
comply
with
paragraphs
(a)(
3)
through
(5)
and
(d)(
1)
and
(2)
of
this
section.
(1)
The
regeneration
desorbing
gas
mass
flow
monitor
must
be
an
integrating
device
having
a
measurement
sensitivity
of
plus
or
minus
10
percent,
capable
of
recording
the
total
regeneration
desorbing
gas
mass
flow
for
each
regeneration
cycle.
(2)
The
carbon
bed
temperature
monitor
must
have
a
measurement
sensitivity
of
1
percent
of
the
temperature
recorded
or
1
degree
Fahrenheit,
whichever
is
greater,
and
must
be
capable
of
recording
the
temperature
within
15
minutes
of
completing
any
carbon
bed
cooling
cycle.
(e)
Condensers.
If
you
are
using
a
condenser,
you
must
monitor
the
condenser
outlet
(product
side)
gas
temperature
and
comply
with
paragraphs
(a)
and
(e)(
1)
and
(2)
of
this
section.
(1)
The
gas
temperature
monitor
must
have
a
measurement
sensitivity
of
1
percent
of
the
temperature
recorded
or
1
degree
Fahrenheit,
whichever
is
greater.
(2)
The
temperature
monitor
must
provide
a
gas
temperature
record
at
least
once
every
15
minutes.
(f)
Emission
capture
systems.
The
capture
system
monitoring
system
must
comply
with
the
applicable
requirements
in
paragraphs
(f)(
1)
and
(2)
of
this
section.
(1)
For
each
flow
measurement
device,
you
must
meet
the
requirements
in
paragraphs
(a)
and
(f)(
1)(
i)
through
(iv)
of
this
section.
(i)
Locate
a
flow
sensor
in
a
position
that
provides
a
representative
flow
measurement
in
the
duct
from
each
capture
device
in
the
emission
capture
system
to
the
add
on
control
device.
(ii)
Reduce
swirling
flow
or
abnormal
velocity
distributions
due
to
upstream
and
downstream
disturbances.
(iii)
Conduct
a
flow
sensor
calibration
check
at
least
semiannually.
(iv)
At
least
monthly,
inspect
all
components
for
integrity,
all
electrical
connections
for
continuity,
and
all
mechanical
connections
for
leakage.
(2)
For
each
pressure
drop
measurement
device,
you
must
comply
with
the
requirements
in
paragraphs
(a)
and
(f)(
2)(
i)
through
(vi)
of
this
section.
(i)
Locate
the
pressure
sensor(
s)
in
or
as
close
to
a
position
that
provides
a
representative
measurement
of
the
pressure
drop
across
each
opening
you
are
monitoring.
(ii)
Minimize
or
eliminate
pulsating
pressure,
vibration,
and
internal
and
external
corrosion.
(iii)
Check
pressure
tap
pluggage
daily.
(iv)
Using
an
inclined
manometer
with
a
measurement
sensitivity
of
0.0002
inch
water,
check
gauge
calibration
quarterly
and
transducer
calibration
monthly.
(v)
Conduct
calibration
checks
any
time
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
pressure
range
or
install
a
new
pressure
sensor.
(vi)
At
least
monthly,
inspect
all
components
for
integrity,
all
electrical
connections
for
continuity,
and
all
mechanical
connections
for
leakage.
(g)
Concentrators.
If
you
are
using
a
concentrator,
such
as
a
zeolite
wheel
or
rotary
carbon
bed
concentrator,
you
must
comply
with
the
requirements
in
paragraphs
(g)(
1)
and
(2)
of
this
section.
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No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
(1)
You
must
install
a
temperature
monitor
in
the
desorption
gas
stream.
The
temperature
monitor
must
meet
the
requirements
in
paragraphs
(a)
and
(c)(
3)
of
this
section.
(2)
You
must
install
a
device
to
monitor
pressure
drop
across
the
zeolite
wheel
or
rotary
carbon
bed.
The
pressure
monitoring
device
must
meet
the
requirements
in
paragraphs
(a)
and
(g)(
2)(
i)
through
(vii)
of
this
section.
(i)
Locate
the
pressure
sensor(
s)
in
or
as
close
to
a
position
that
provides
a
representative
measurement
of
the
pressure.
(ii)
Minimize
or
eliminate
pulsating
pressure,
vibration,
and
internal
and
external
corrosion.
(iii)
Use
a
gauge
with
a
minimum
tolerance
of
0.5
inch
of
water
or
a
transducer
with
a
minimum
tolerance
of
1
percent
of
the
pressure
range.
(iv)
Check
the
pressure
tap
daily.
(v)
Using
a
manometer,
check
gauge
calibration
quarterly
and
transducer
calibration
monthly.
(vi)
Conduct
calibration
checks
any
time
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
pressure
range
or
install
a
new
pressure
sensor.
(vii)
At
least
monthly,
inspect
all
components
for
integrity,
all
electrical
connections
for
continuity,
and
all
mechanical
connections
for
leakage.
Other
Requirements
and
Information
§
63.4980
Who
implements
and
enforces
this
subpart?
(a)
This
subpart
can
be
implemented
and
enforced
by
us,
the
EPA,
or
a
delegated
authority
such
as
your
State,
local,
or
tribal
agency.
If
the
EPA
Administrator
has
delegated
authority
to
your
State,
local,
or
tribal
agency,
then
that
agency
(as
well
as
EPA)
has
the
authority
to
implement
and
enforce
this
subpart.
You
should
contact
your
EPA
Regional
Office
to
find
out
if
implementation
and
enforcement
of
this
subpart
is
delegated
to
your
State,
local,
or
tribal
agency.
(b)
In
delegating
implementation
and
enforcement
authority
of
this
subpart
to
a
State,
local,
or
tribal
agency
under
subpart
E
of
this
part,
the
authorities
contained
in
paragraph
(c)
of
this
section
are
retained
by
the
Administrator
and
are
not
transferred
to
the
State,
local,
or
tribal
agency.
(c)
The
authorities
that
will
not
be
delegated
to
State,
local,
or
tribal
agencies
are
as
follows:
(1)
Approval
of
alternatives
to
the
work
practice
standards
in
§
63.4893
under
§
63.6(
g).
(2)
Approval
of
major
alternatives
to
test
methods
under
§
63.7(
e)(
2)(
ii)
and
(f),
and
as
defined
in
§
63.90.
(3)
Approval
of
major
alternatives
to
monitoring
under
§
63.8(
f)
and
as
defined
in
§
63.90.
(4)
Approval
of
major
alternatives
to
recordkeeping
and
reporting
under
§
63.10(
f)
and
as
defined
in
§
63.90.
§
63.4981
What
definitions
apply
to
this
subpart?
Terms
used
in
this
subpart
are
defined
in
the
CAA,
in
40
CFR
63.2,
the
General
Provisions
of
this
part,
and
in
this
section
as
follows:
Add
on
control
means
an
air
pollution
control
device,
such
as
a
thermal
oxidizer
or
carbon
adsorber,
that
reduces
pollution
in
an
air
stream
by
destruction
or
removal
before
discharge
to
the
atmosphere.
Adhesive
means
any
chemical
substance
that
is
applied
for
the
purpose
of
bonding
two
surfaces
together.
Capture
device
means
a
hood,
enclosure,
room,
floor
sweep,
or
other
means
of
containing
or
collecting
emissions
and
directing
those
emissions
into
an
add
on
air
pollution
control
device.
Capture
efficiency
or
capture
system
efficiency
means
the
portion
(expressed
as
a
percentage)
of
the
pollutants
from
an
emission
source
that
is
delivered
to
an
add
on
control
device.
Capture
system
means
one
or
more
capture
devices
intended
to
collect
emissions
generated
by
a
coating
operation
in
the
use
of
coatings
or
cleaning
materials,
both
at
the
point
of
application
and
at
subsequent
points
where
emissions
from
the
coatings
or
cleaning
materials
occur,
such
as
flashoff,
drying,
or
curing.
As
used
in
this
subpart,
multiple
capture
devices
that
collect
emissions
generated
by
a
coating
operation
are
considered
a
single
capture
system.
Cleaning
material
means
a
solvent
used
to
remove
contaminants
and
other
materials,
such
as
dirt,
grease,
oil,
and
dried
or
wet
coating
(e.
g.,
depainting),
from
a
substrate
before
or
after
coating
application
or
from
equipment
associated
with
a
coating
operation,
such
as
spray
booths,
spray
guns,
racks,
tanks,
and
hangers.
Thus,
it
includes
any
cleaning
material
used
on
substrates
or
equipment
or
both.
Coating
means
a
material
applied
to
a
substrate
for
decorative,
protective,
or
functional
purposes.
Such
materials
include,
but
are
not
limited
to,
paints,
sealants,
caulks,
inks,
adhesives,
and
maskants.
Decorative,
protective,
or
functional
materials
that
consist
only
of
protective
oils
for
metal,
acids,
bases,
or
any
combination
of
these
substances
are
not
considered
coatings
for
the
purposes
of
this
subpart.
Coating
operation
means
equipment
used
to
apply
cleaning
materials
to
a
substrate
to
prepare
it
for
coating
application
or
to
remove
dried
coating
(surface
preparation);
to
apply
coating
to
a
substrate
(coating
application)
and
to
dry
or
cure
the
coating
after
application;
or
to
clean
coating
operation
equipment
(equipment
cleaning).
A
single
coating
operation
may
include
any
combination
of
these
types
of
equipment,
but
always
includes
at
least
the
point
at
which
a
coating
or
cleaning
material
is
applied
and
all
subsequent
points
in
the
affected
source
where
organic
HAP
emissions
from
that
coating
or
cleaning
material
occur.
There
may
be
multiple
coating
operations
in
an
affected
source.
Coating
application
with
hand
held
nonrefillable
aerosol
containers,
touchup
markers,
or
marking
pens
is
not
a
coating
operation
for
the
purposes
of
this
subpart.
Coating
solids
means
the
nonvolatile
portion
of
the
coating
that
makes
up
the
dry
film.
Continuous
parameter
monitoring
system
(CPMS)
means
the
total
equipment
that
may
be
required
to
meet
the
data
acquisition
and
availability
requirements
of
this
subpart,
used
to
sample,
condition
(if
applicable),
analyze,
and
provide
a
record
of
coating
operation,
or
capture
system,
or
add
on
control
device
parameters.
Controlled
coating
operation
means
a
coating
operation
from
which
some
or
all
of
the
organic
HAP
emissions
are
routed
through
an
emission
capture
system
and
add
on
control
device.
Deviation
means
any
instance
in
which
an
affected
source
subject
to
this
subpart,
or
an
owner
or
operator
of
such
a
source:
(1)
Fails
to
meet
any
requirement
or
obligation
established
by
this
subpart,
including
but
not
limited
to
any
emission
limit,
or
operating
limit,
or
work
practice
standard;
(2)
Fails
to
meet
any
term
or
condition
that
is
adopted
to
implement
an
applicable
requirement
in
this
subpart
and
that
is
included
in
the
operating
permit
for
any
affected
source
required
to
obtain
such
a
permit;
or
(3)
Fails
to
meet
any
emission
limit,
or
operating
limit,
or
work
practice
standard
in
this
subpart
during
startup,
shutdown,
or
malfunction,
regardless
of
whether
or
not
such
failure
is
permitted
by
this
subpart.
Emission
limitation
means
an
emission
limit,
operating
limit,
or
work
practice
standard.
Enclosure
means
a
structure
that
surrounds
a
source
of
emissions
and
captures
and
directs
the
emissions
to
an
add
on
control
device.
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/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
Exempt
compound
means
a
specific
compound
that
is
not
considered
a
VOC
due
to
negligible
photochemical
reactivity.
The
exempt
compounds
are
listed
in
40
CFR
51.100(
s).
Manufacturer's
formulation
data
means
data
on
a
material
(such
as
a
coating)
that
are
supplied
by
the
material
manufacturer
based
on
knowledge
of
the
ingredients
used
to
manufacture
that
material,
rather
than
based
on
testing
of
the
material
with
the
test
methods
specified
in
§
63.4941(
a)(
1)
through
(3).
Manufacturer's
formulation
data
may
include,
but
are
not
limited
to,
information
on
density,
organic
HAP
content,
volatile
organic
matter
content,
and
coating
solids
content.
Mass
fraction
of
organic
HAP
means
the
ratio
of
the
mass
of
organic
HAP
to
the
mass
of
a
material
in
which
it
is
contained;
kg
of
organic
HAP
per
kg
of
material.
Month
means
a
calendar
month
or
a
pre
specified
period
of
28
days
to
35
days
to
allow
for
flexibility
in
recordkeeping
when
data
are
based
on
a
business
accounting
period.
Organic
HAP
content
means
the
mass
of
organic
HAP
per
volume
of
coating
solids
for
a
coating,
calculated
using
Equation
1
of
§
63.4941.
The
organic
HAP
content
is
determined
for
the
coating
in
the
condition
it
is
in
when
received
from
its
manufacturer
or
supplier
and
does
not
account
for
any
alteration
after
receipt.
Permanent
total
enclosure
(PTE)
means
a
permanently
installed
enclosure
that
meets
the
criteria
of
Method
204
of
appendix
M,
40
CFR
part
51,
for
a
PTE
and
that
directs
all
the
exhaust
gases
from
the
enclosure
to
an
add
on
control
device.
Protective
oil
means
an
organic
material
that
is
applied
to
metal
for
the
purpose
of
providing
lubrication
or
protection
from
corrosion
without
forming
a
solid
film.
This
definition
of
protective
oil
includes,
but
is
not
limited
to,
lubricating
oils,
evaporative
oils
(including
those
that
evaporate
completely),
and
extrusion
oils.
Research
or
laboratory
facility
means
a
facility
whose
primary
purpose
is
for
research
and
development
of
new
processes
and
products,
that
is
conducted
under
the
close
supervision
of
technically
trained
personnel,
and
is
not
engaged
in
the
manufacture
of
final
or
intermediate
products
for
commercial
purposes,
except
in
a
de
minimis
manner.
Responsible
official
means
responsible
official
as
defined
in
40
CFR
70.2.
Startup,
initial
means
the
first
time
equipment
is
brought
online
in
a
facility.
Surface
preparation
means
use
of
a
cleaning
material
on
a
portion
of
or
all
of
a
substrate.
This
includes
use
of
a
cleaning
material
to
remove
dried
coating,
which
is
sometimes
called
``
depainting.
''
Temporary
total
enclosure
means
an
enclosure
constructed
for
the
purpose
of
measuring
the
capture
efficiency
of
pollutants
emitted
from
a
given
source
as
defined
in
Method
204
of
appendix
M,
40
CFR
part
51.
Thinner
means
an
organic
solvent
that
is
added
to
a
coating
after
the
coating
is
received
from
the
supplier.
Total
volatile
hydrocarbon
(TVH)
means
the
total
amount
of
nonaqueous
volatile
organic
matter
determined
according
to
Methods
204
and
204A
through
204F
of
appendix
M
to
40
CFR
part
51
and
substituting
the
term
TVH
each
place
in
the
methods
where
the
term
VOC
is
used.
The
TVH
includes
both
VOC
and
non
VOC.
Uncontrolled
coating
operation
means
a
coating
operation
from
which
none
of
the
organic
HAP
emissions
are
routed
through
an
emission
capture
system
and
add
on
control
device.
Volatile
organic
compound
(VOC)
means
any
compound
defined
as
VOC
in
40
CFR
51.100(
s).
Volume
fraction
of
coating
solids
means
the
ratio
of
the
volume
of
coating
solids
(also
known
as
volume
of
nonvolatiles)
to
the
volume
of
coating;
liters
of
coating
solids
per
liter
of
coating.
Wastewater
means
water
that
is
generated
in
a
coating
operation
and
is
collected,
stored,
or
treated
prior
to
being
discarded
or
discharged.
Tables
to
Subpart
RRRR
of
Part
63
If
you
are
required
to
comply
with
operating
limits
by
§
63.4892,
you
must
comply
with
the
applicable
operating
limits
in
the
following
table:
TABLE
1
TO
SUBPART
RRRR
OF
PART
63.—
OPERATING
LIMITS
IF
USING
THE
EMISSION
RATE
WITH
ADD
ON
CONTROLS
OPTION
For
the
following
device
*
*
*
You
must
meet
the
following
operating
limit
*
*
*
And
you
must
demonstrate
continuous
compliance
with
the
operating
limit
by
*
*
*
1.
thermal
oxidizer
............................
the
average
combustion
temperature
in
any
3
hour
period
must
not
fall
below
the
combustion
temperature
limit
established
according
to
§
63.4967(
a).
i.
collecting
the
combustion
temperature
data
according
to
§
63.4968(
c);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
combustion
at
or
above
the
temperature
limit.
2.
catalytic
oxidizer
...........................
a.
the
average
temperature
measured
just
before
the
catalyst
bed
in
any
3
hour
period
must
not
fall
below
the
limit
established
according
to
§
63.4967(
b).
i.
collecting
the
temperature
data
according
to
§
63.4968(
c);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
temperature
before
the
catalyst
bed
at
or
above
the
temperature
limit.
b.
either
ensure
that
the
average
temperature
difference
catalyst
bed
in
any
3
hour
period
does
not
fall
below
the
temperature
difference
limit
established
according
to
§
63.4967(
b)
or
develop
and
implement
an
inspection
and
maintenance
plan
according
to
§
63.4967(
b)(
3)
and
(4).
i.
either
collecting
the
temperature
data
according
to
across
the
§
63.4968(
c),
reducing
the
data
to
3
hour
block
averages,
and
maintaining
the
3
hour
average
temperature
difference
at
or
above
the
temperature
difference
limit;
or
ii.
complying
with
the
inspection
and
maintenance
plan
developed
according
to
§
63.4967(
b)(
3)
and
(4).
3.
carbon
adsorber
...........................
a.
the
total
regeneration
desorbing
gas
(e.
g.,
steam
or
nitrogen)
mass
flow
for
each
carbon
bed
regeneration
cycle
must
not
fall
below
the
total
regeneration
desorbing
gas
mass
flow
limit
established
according
to
§
63.4967(
c).
i.
measuring
the
total
regeneration
desorbing
gas
(e.
g.,
steam
or
nitrogen)
mass
flow
for
each
regeneration
cycle
according
to
§
63.4968(
d);
and
ii.
maintaining
the
total
regeneration
desorbing
gas
mass
flow
at
or
above
the
mass
flow
limit.
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/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
TABLE
1
TO
SUBPART
RRRR
OF
PART
63.—
OPERATING
LIMITS
IF
USING
THE
EMISSION
RATE
WITH
ADD
ON
CONTROLS
OPTION—
Continued
For
the
following
device
*
*
*
You
must
meet
the
following
operating
limit
*
*
*
And
you
must
demonstrate
continuous
compliance
with
the
operating
limit
by
*
*
*
b.
the
temperature
of
the
carbon
bed,
after
completing
each
regeneration
and
any
cooling
cycle,
must
not
exceed
the
carbon
bed
temperature
limit
established
according
to
§
63.4967(
c).
i.
measuring
the
temperature
of
the
carbon
bed,
after
completing
each
regeneration
and
any
cooling
cycle,
according
to
§
63.4968(
d);
and
ii.
operating
the
carbon
beds
such
that
each
carbon
bed
is
not
returned
to
service
until
completing
each
regeneration
and
any
cooling
cycle
until
the
recorded
temperature
of
the
carbon
bed
is
at
or
below
the
temperature
limit.
4.
condenser
.....................................
the
average
condenser
outlet
(product
side)
gas
temperature
in
any
3
hour
period
must
not
exceed
the
temperature
limit
established
according
to
§
63.4967(
d).
i.
collecting
the
condenser
outlet
(product
side)
gas
temperature
according
to
§
63.4968(
e);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
gas
temperature
at
the
outlet
at
or
below
the
temperature
limit.
5.
emission
capture
system
that
is
a
PTE
according
to
§
63.4965(
a).
the
direction
of
the
air
flow
at
all
times
must
be
into
the
enclosure;
and
either
the
average
facial
velocity
of
air
through
all
natural
draft
openings
in
the
enclosure
must
be
at
least
200
feet
per
minute;
or
the
pressure
drop
across
the
enclosure
must
be
at
least
0.007
inch
H2O,
as
established
in
Method
204
of
appendix
M
to
40
CFR
part
51.
i.
collecting
the
direction
of
air
flow,
and
either
the
facial
velocity
of
air
through
all
natural
draft
openings
according
to
§
63.4968(
f)(
1)
or
the
pressure
drop
across
the
enclosure
according
to
§
63.4968(
f)(
2);
and
ii.
maintaining
the
facial
velocity
of
air
flow
through
all
natural
draft
openings
or
the
pressure
drop
at
or
above
the
facial
velocity
limit
or
pressure
drop
limit,
and
maintaining
the
direction
of
air
flow
into
the
enclosure
at
all
times.
6.
emission
capture
system
that
is
a
PTE
according
to
§
63.4965(
a).
the
average
gas
volumetric
flow
rate
or
duct
static
pressure
in
each
duct
between
a
capture
device
and
add
on
control
device
inlet
in
any
3
hour
period
must
not
fall
below
the
average
volumetric
flow
rate
or
duct
static
pressure
limit
established
for
that
capture
device
according
to
§
63.4967(
e).
i.
collecting
the
gas
volumetric
flow
rate
or
duct
static
pressure
for
each
not
capture
device
according
to
§
63.4968(
f);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
gas
volumetric
flow
rate
or
duct
static
pressure
for
each
capture
device
at
or
above
the
gas
volumetric
flow
rate
or
duct
static
pressure
limit.
7.
concentrators,
including
zeolite
wheels
and
rotary
carbon
adsorbers.
a.
the
average
gas
temperature
of
the
desorption
concentrate
stream
in
any
3
hour
period
must
not
fall
below
the
limit
established
according
to
§
63.4967(
g).
i.
collecting
the
temperature
data
according
to
63.4968(
g);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
temperature
at
or
above
the
temperature
limit.
b.
the
average
pressure
drop
of
the
dilute
stream
across
the
concentrator
in
any
3
hour
period
must
not
fall
below
the
limit
established
according
to
§
63.4967(
g).
i.
collecting
the
pressure
drop
data
according
to
§
63.4968(
g);
ii.
reducing
the
pressure
drop
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
pressure
drop
at
or
above
the
pressure
drop
limit.
You
must
comply
with
the
applicable
General
Provisions
requirements
according
to
the
following
table:
TABLE
2
TO
SUBPART
RRRR
OF
PART
63.—
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
RRRR
Citation
Subject
Applicable
to
subpart
RRRR
Explanation
§
63.1(
a)(
1)–(
14)
..........
General
Applicability
.......................................
Yes.
§
63.1(
b)(
1)–(
3)
............
Initial
Applicability
Determination
....................
Yes
.............................
Applicability
to
subpart
RRRR
is
also
specified
in
§
63.4881.
§
63.1(
c)(
1)
..................
Applicability
After
Standard
Established
.........
Yes.
§
63.1(
c)(
2)–(
3)
............
Applicability
of
Permit
Program
for
Area
Sources.
No
...............................
Area
sources
are
not
subject
to
subpart
RRRR.
§
63.1(
c)(
4)–(
5)
............
Extensions
and
Notifications
...........................
Yes.
§
63.1(
e)
.......................
Applicability
of
Permit
Program
Before
Relevant
Standard
is
Set.
Yes.
§
63.2
...........................
Definitions
.......................................................
Yes
.............................
Additional
definitions
are
specified
in
§
63.4981.
§
63.3(
a)–(
c)
................
Units
and
Abbreviations
..................................
Yes.
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
TABLE
2
TO
SUBPART
RRRR
OF
PART
63.—
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
RRRR—
Continued
Citation
Subject
Applicable
to
subpart
RRRR
Explanation
§
63.4(
a)(
1)–(
5)
............
Prohibited
Activities
.........................................
Yes.
§
63.4(
b)–(
c)
................
Circumvention/
Severability
..............................
Yes.
§
63.5(
a)
.......................
Construction/
Reconstruction
...........................
Yes.
§
63.5(
b)(
1)–(
6)
............
Requirements
for
Existing,
Newly
Constructed
and
Reconstructed
Sources.
Yes.
§
63.5(
d)
.......................
Application
for
Approval
of
Construction/
Reconstruction
Yes.
§
63.5(
e)
.......................
Approval
of
Construction/
Reconstruction
.......
Yes.
§
63.5(
f)
........................
Approval
of
Construction/
Reconstruction
Based
on
Prior
State
Review.
Yes.
§
63.6(
a)
.......................
Compliance
With
Standards
and
Maintenance
Requirements—
Applicability.
Yes.
§
63.6(
b)(
1)–(
7)
............
Compliance
Dates
for
New
and
Reconstructed
Sources.
Yes
.............................
Section
63.4883
specifies
the
compliance
dates.
§
63.6(
c)(
1)–(
5)
............
Compliance
Dates
for
Existing
Sources
.........
Yes
.............................
Section
63.4883
specifies
the
compliance
dates.
§
63.6(
e)(
1)–(
2)
............
Operation
and
Maintenance
...........................
Yes.
§
63.6(
e)(
3)
..................
Startup,
Shutdown,
and
Malfunction
Plan
......
Yes
.............................
Only
sources
using
an
add
on
control
device
to
comply
with
the
standard
must
complete
startup,
shutdown,
and
malfunction
plans.
§
63.6(
f)(
1)
...................
Compliance
Except
During
Startup,
Shutdown
Malfunction.
Yes
.............................
Applies
only
to
sources
using
an
add
on
and
control
device
to
comply
with
the
standard.
§
63.6(
f)(
2)–(
3)
.............
Methods
for
Determining
Compliance
............
Yes.
§
63.6(
g)(
1)–(
3)
............
Use
of
an
Alternative
Standard
......................
Yes.
§
63.6(
h)
.......................
Compliance
With
Opacity/
Visible
Emission
Standards.
No
...............................
Subpart
RRRR
does
not
establish
opacity
standards
and
does
not
require
continuous
opacity
monitoring
systems
(COMS).
§
63.6(
i)(
1)–(
16)
...........
Extension
of
Compliance
................................
Yes.
§
63.6(
j)
........................
Presidential
Compliance
Exemption
...............
Yes.
§
63.7(
a)(
1)
..................
Performance
Test
Requirements—
Applicability
Yes
.............................
Applies
to
all
affected
sources.
Additional
requirements
for
performance
testing
are
specified
in
§§
63.4964,
63.4965,
and
63.4966.
§
63.7(
a)(
2)
..................
Performance
Test
Requirements—
Dates
.......
Yes
.............................
Applies
only
to
performance
tests
for
capture
system
and
control
device
efficiency
at
sources
using
these
to
comply
with
the
standard.
Section
63.4960
specifies
the
schedule
for
performance
test
requirements
that
are
earlier
than
those
specified
in
63.7(
a)(
2).
§
63.7(
a)(
3)
..................
Performance
Tests
Required
by
the
Administrator
Yes.
§
63.7(
b)–(
e)
................
Performance
Test
Requirements—
Notification
Quality
Assurance,
Facilities
Necessary
for
Safe
Testing,
Conditions
During
Test.
Yes
.............................
Applies
only
to
performance
tests
for
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standard.
§
63.7(
f)
........................
Performance
Test
Requirements—
Use
of
Alternative
Test
Method.
Yes
.............................
Applies
to
all
test
methods
except
those
used
to
determine
capture
system
efficiency.
§
63.7(
g)–(
h)
................
Performance
TestRequirements—
Data
Analysis
Recordkeeping,
Reporting,
Waiver
of
Test.
Yes
.............................
Applies
only
to
performance
tests
for
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standard.
§
63.8(
a)(
1)–(
3)
............
Monitoring
Requirements—
Applicability
.........
Yes
.............................
Applies
only
to
monitoring
of
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standard.
Additional
requirements
for
monitoring
are
specified
in
§
63.4968.
§
63.8(
a)(
4)
..................
Additional
Monitoring
Requirements
...............
No
...............................
Subpart
RRRR
does
not
have
monitoring
requirements
for
flares.
§
63.8(
b)
.......................
Conduct
of
Monitoring
.....................................
Yes.
§
63.8(
c)(
1)–(
3)
............
Continuous
Monitoring
System
(CMS)
Operation
and
Maintenance.
Yes
.............................
Applies
only
to
monitoring
of
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standard.
Additional
requirements
for
CMS
operations
and
maintenance
are
specified
in
§
63.4968.
§
63.8(
c)(
4)
..................
CMSs
..............................................................
No
...............................
Section
63.4968
specifies
the
requirements
for
the
operation
of
CMS
for
capture
systems
and
add
on
control
devices
at
sources
using
these
to
comply.
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
TABLE
2
TO
SUBPART
RRRR
OF
PART
63.—
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
RRRR—
Continued
Citation
Subject
Applicable
to
subpart
RRRR
Explanation
§
63.8(
c)(
5)
..................
COMS
.............................................................
No
...............................
Subpart
RRRR
does
not
have
opacity
or
visible
emission
standards.
§
63.8(
c)(
6)
..................
CMS
Requirements
.........................................
No
...............................
Section
63.4968
specifies
the
requirements
for
monitoring
systems
for
capture
systems
and
add
on
control
devices
at
sources
using
these
to
comply.
§
63.8(
c)(
7)
..................
CMS
Out
of
Control
Periods
...........................
Yes.
§
63.8(
c)(
8)
..................
CMS
Out
of
Control
Periods
reporting
...........
No
...............................
Section
63.4920
requires
reporting
of
CMS
out
of
control
periods.
§
63.8(
d)–(
e)
................
Quality
Control
Program
and
CMS
Performance
Evaluation.
No
...............................
Subpart
RRRR
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.8(
f)(
1)–(
5)
.............
Use
of
an
Alternative
Monitoring
Method
.......
Yes.
§
63.8(
f)(
6)
...................
Alternative
to
Relative
Accuracy
Test
.............
No
...............................
Subpart
RRRR
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.8(
g)(
1)–(
5)
............
Data
Reduction
...............................................
No
...............................
Sections
63.4967
and
63.4968
specify
monitoring
data
reduction.
§
63.9(
a)–(
d)
................
Notification
Requirements
...............................
Yes.
§
63.9(
e)
.......................
Notification
of
Performance
Test
....................
Yes
.............................
Applies
only
to
capture
system
and
add
on
control
device
performance
tests
at
sources
using
these
to
comply
with
the
standard.
§
63.9(
f)
........................
Notification
of
Visible
Emissions/
Opacity
Test
No
...............................
Subpart
RRRR
does
not
have
opacity
or
visible
emission
standards.
§
63.9(
g)(
1)–(
3)
............
Additional
Notifications
When
Using
CMS
.....
No
...............................
Subpart
RRRR
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.9(
h)
.......................
Notification
of
Compliance
Status
...................
Yes
.............................
Section
63.4910
specifies
the
dates
for
submitting
the
notification
of
compliance
status
§
63.9(
i)
........................
Adjustment
of
Submittal
Deadlines
.................
Yes.
§
63.9(
j)
........................
Change
in
Previous
Information
.....................
Yes.
§
63.10(
a)
.....................
Recordkeeping/
Reporting—
Applicability
and
General
Information.
Yes.
§
63.10(
b)(
1)
................
General
Recordkeeping
Requirements
..........
Yes
.............................
Additional
requirements
are
specified
in
§§
63.4930
and
63.4931.
§
63.10(
b)(
2)(
i)–(
v)
.......
Recordkeeping
Relevant
Startup,
to
Shutdown
and
Malfunction
Periods
and
CMS.
Yes
.............................
Requirements
for
Startup,
Startup,
Shutdown,
and
Malfunction
records
only
apply
to
addon
control
devices
used
to
comply
with
the
standard.
§
63.10(
b)(
2)(
vi)–(
xi)
....
.........................................................................
Yes.
§
63.10(
b)(
2)(
xii)
..........
Records
...........................................................
Yes.
§
63.10(
b)(
2)(
xiii)
..........
.........................................................................
No
...............................
Subpart
RRRR
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.10(
b)(
2)(
xiv)
.........
.........................................................................
Yes.
§
63.10(
b)(
3)
................
Recordkeeping
Requirements
for
Applicability
Determinations.
Yes.
§
63.10(
c)(
1)–(
6)
..........
Additional
Recordkeeping
Requirements
for
Sources
with
CMS.
Yes.
§
63.10(
c)(
7)–(
8)
..........
.........................................................................
No
...............................
The
same
records
are
required
in
§
63.4920(
a)(
7)
§
63.10(
c)(
9)–(
15)
........
.........................................................................
Yes.
§
63.10(
d)(
1)
................
General
Reporting
Requirements
...................
Yes
.............................
Additional
requirements
are
specified
in
§
63.4920.
§
63.10(
d)(
2)
................
Report
of
Performance
Test
Results
..............
Yes
.............................
Additional
requirements
are
specified
in
§
63.4920(
b).
§
63.10(
d)(
3)
................
Reporting
Opacity
or
Visible
Emissions
Observations
No
...............................
Subpart
RRRR
does
not
require
opacity
or
visible
emissions
observations.
§
63.10(
d)(
4)
................
Progress
Reports
for
Sources
With
Compliance
Extensions.
Yes.
§
63.10(
d)(
5)
................
Startup,
Shutdown,
and
Malfunction
Reports
Yes
.............................
Applies
only
to
add
on
control
devices
at
sources
using
these
to
comply
with
the
standard.
§
63.10(
e)(
1)–(
2)
..........
Additional
CMS
Reports
.................................
No
...............................
Subpart
RRRR
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.10(
e)(
3)
................
Excess
Emissions/
CMS
Performance
Reports
No
...............................
Section
63.4920(
b)
specifies
the
contents
of
periodic
compliance
reports.
§
63.10(
e)(
4)
................
COMS
Data
Reports
.......................................
No
...............................
Subpart
RRRR
does
not
specify
requirements
for
opacity
or
COMS.
§
63.10(
f)
......................
Recordkeeping/
Reporting
Waiver
...................
Yes.
§
63.11
.........................
Control
Device
Requirements/
Flares
..............
No
...............................
Subpart
RRRR
does
not
specify
use
of
flares
for
compliance.
§
63.12
.........................
State
Authority
and
Delegations
.....................
Yes.
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Federal
Register
/
Vol.
67,
No.
79
/
Wednesday,
April
24,
2002
/
Proposed
Rules
TABLE
2
TO
SUBPART
RRRR
OF
PART
63.—
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
RRRR—
Continued
Citation
Subject
Applicable
to
subpart
RRRR
Explanation
§
63.13
.........................
Addresses
.......................................................
Yes.
§
63.14
.........................
Incorporation
by
Reference
............................
Yes.
§
63.15
.........................
Availability
of
Information/
Confidentiality
........
Yes.
You
may
use
the
mass
fraction
values
in
the
following
table
for
solvent
blends
for
which
you
do
not
have
test
data
or
manufacturer's
formulation
data:
TABLE
3
TO
SUBPART
RRRR
OF
PART
63.—
DEFAULT
ORGANIC
HAP
MASS
FRACTION
FOR
SOLVENTS
AND
SOLVENT
BLENDS
Solvent/
Solvent
blend
CAS.
No.
Average
organic
HAP
mass
fraction
Typical
organic
HAP,
percent
by
mass
1.
Toluene
........................................................................
108–
88–
3
1.
0
Toluene.
2.
Xylene(
s)
......................................................................
1330–
20–
7
1.
0
Xylenes,
ethylbenzene.
3.
Hexane
.........................................................................
110–
54–
3
0.
5
n
hexane.
4.
n
Hexane
......................................................................
110–
54–
3
1.
0
n
hexane.
5.
Ethylbenzene
...............................................................
100–
41–
4
1.
0
Ethylbenzene.
6.
Aliphatic
140
................................................................
....................
0
None.
7.
Aromatic
100
................................................................
....................
0.02
1%
xylene,
1%
cumene.
8.
Aromatic
150
................................................................
....................
0.09
Naphthalene.
9.
Aromatic
naphtha
.........................................................
64742–
95–
6
0.
02
1%
xylene,
1%
cumene.
10.
Aromatic
solvent
........................................................
64742–
94–
5
0.
1
Naphthalene.
11.
Exempt
mineral
spirits
...............................................
8032–
32–
4
0
None.
12.
Ligroines
(VM
&
P)
....................................................
8032–
32–
4
0
None.
13.
Lactol
spirits
...............................................................
64742–
89–
6
0.
15
Toluene.
14.
Low
aromatic
white
spirit
...........................................
64742–
82–
1
0
None.
15.
Mineral
spirits
.............................................................
64742–
88–
7
0.
01
Xylenes.
16.
Hydrotreated
naphtha
................................................
64742–
48–
9
0
None.
17.
Hydrotreated
light
distillate
........................................
64742–
47–
8
0.
001
Toluene.
18.
Stoddard
solvent
........................................................
8052–
41–
3
0.
01
Xylenes.
19.
Super
high
flash
naphtha
...........................................
64742–
95–
6
0.
05
Xylenes.
20.
Varsol
solvent
.........................................................
8052–
49–
3
0.
01
0.5%
xylenes,
0.5%
ethyl
benzene.
21.
VM
&
P
naphtha
........................................................
64742–
89–
8
0.
06
3%
toluene,
3%
xylene.
22.
Petroleum
distillate
mixture
........................................
68477–
31–
6
0.
08
4%
naphthalene,
4%
biphenyl.
You
may
use
the
mass
fraction
values
in
the
following
table
for
solvent
blends
for
which
you
do
not
have
test
data
or
manufacturer's
formulation
data:
TABLE
4
TO
SUBPART
RRRR
OF
PART
63.—
DEFAULT
ORGANIC
HAP
MASS
FRACTION
FOR
PETROLEUM
SOLVENT
GROUPS
a
Solvent
type
Average
organic
HAP
mass
fraction
Typical
organic
HAP,
percent
by
mass
Aliphatic
b
....................................................
0.03
1%
Xylene,
1%
Toluene,
and
1%
Ethylbenzene.
Aromatic
c
...................................................
0.06
4%
Xylene,
1%
Toluene,
and
1%
Ethylbenzene.
a
Use
this
table
only
if
the
solvent
blend
does
not
match
any
of
the
solvent
blends
in
Table
3
to
this
subpart
and
you
only
know
whether
the
blend
is
aliphatic
or
aromatic.
b
e.
g.,
Mineral
Spirits
135,
Mineral
Spirits
150
EC,
Naphtha,
Mixed
Hydrocarbon,
Aliphatic
Hydrocarbon,
Aliphatic
Naphtha,
Naphthol
Spirits,
Petroleum
Spirits,
Petroleum
Oil,
Petroleum
Naphtha,
Solvent
Naphtha,
Solvent
Blend.
c
e.
g.,
Medium
flash
Naphtha,
High
flash
Naphtha,
Aromatic
Naphtha,
Light
Aromatic
Naphtha,
Light
Aromatic
Hydrocarbons,
Aromatic
Hydrocarbons
Light
Aromatic
Solvent.
[FR
Doc.
02–
7224
Filed
4–
23–
02;
8:
45
am]
BILLING
CODE
6560–
50–
P
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| epa | 2024-06-07T20:31:40.077119 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0048-0001/content.txt"
} |
EPA-HQ-OAR-2002-0049-0001 | Proposed Rule | "2002-10-16T04:00:00" | Standards of Performance for Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974, and On or Before August 17, 1983; and Standards of Performance for Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 17, 1983 | Wednesday,
October
16,
2002
Part
IV
Environmental
Protection
Agency
40
CFR
Part
60
Standards
of
Performance
for
Steel
Plants:
Electric
Arc
Furnaces
Constructed
After
October
21,
1974,
and
On
or
Before
August
17,
1983;
and
Standards
of
Performance
for
Steel
Plants:
Electric
Arc
Furnaces
and
Argon
Oxygen
Decarburization
Vessels
Constructed
After
August
17,
1983;
Proposed
Rule
VerDate
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Federal
Register
/
Vol.
67,
No.
200
/
Wednesday,
October
16,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
60
[AD–
FRL–
7394–
3]
RIN
2060–
AJ68
Standards
of
Performance
for
Steel
Plants:
Electric
Arc
Furnaces
Constructed
After
October
21,
1974,
and
On
or
Before
August
17,
1983;
and
Standards
of
Performance
for
Steel
Plants:
Electric
Arc
Furnaces
and
Argon
Oxygen
Decarburization
Vessels
Constructed
After
August
17,
1983
AGENCY:
Environmental
Protection
Agency
(EPA).
ACTION:
Proposed
rule;
amendments.
SUMMARY:
The
EPA
is
proposing
to
amend
certain
provisions
in
the
new
source
performance
standards
(NSPS)
for
electric
arc
furnaces
(EAF)
constructed
after
October
21,
1974,
and
on
or
before
August
17,
1983,
and
the
NSPS
for
EAF
constructed
after
August
17,
1983.
The
proposed
changes
add
alternative
requirements
for
monitoring
emissions
from
EAF
exhausts.
In
addition,
minor
editorial
corrections
are
being
made.
DATES:
Comments.
Comments
must
be
received
on
or
before
December
16,
2002.
Public
Hearing.
If
anyone
contacts
the
EPA
requesting
to
speak
at
a
public
hearing
by
November
5,
2002,
a
public
hearing
will
be
held
on
November
15,
2002.
ADDRESSES:
Comments.
By
U.
S.
Postal
Service,
send
comments
(in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(6102),
Attention
Docket
Number
A–
79–
33,
U.
S.
EPA,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460.
In
person
or
by
courier,
deliver
comments
(in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(6102),
Attention
Docket
Number
A–
79–
33,
U.
S.
EPA,
Room
Number
M1500,
401
M
Street,
SW.,
Washington,
DC
20460.
Effective
August
27,
2002,
send
comments
(in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(6102T),
Attention
Docket
Number
A–
79–
33,
U.
S.
EPA,
1301
Constitution
Avenue,
NW.,
Room
Number
B108,
Washington,
DC
20460.
We
request
that
a
separate
copy
of
each
public
comment
be
sent
to
the
contact
person
listed
below
(see
FOR
FURTHER
INFORMATION
CONTACT).
Public
Hearing.
If
a
public
hearing
is
held,
it
will
be
held
at
the
new
EPA
facility
complex
in
Research
Triangle
Park,
NC.
Docket.
Docket
No.
A–
79–
33
contains
supporting
information
used
in
developing
the
standards.
The
docket
is
located
at
the
U.
S.
EPA,
401
M
Street,
SW.,
Washington,
DC
20460
in
Room
M–
1500,
Waterside
Mall
(ground
floor),
and
may
be
inspected
from
8:
30
a.
m.
to
5:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
Effective
August
27,
2002,
the
docket
will
be
located
at:
U.
S.
EPA,
1301
Constitution
Avenue,
NW.,
Room
Number
B108,
Washington,
DC
20460.
FOR
FURTHER
INFORMATION
CONTACT:
Mr.
Kevin
Cavender,
Metals
Group,
Emission
Standards
Division
(C439–
02),
U.
S.
EPA,
Research
Triangle
Park,
NC
27711,
telephone
number:
(919)
541–
2364,
electronic
mail
address:
cavender.
kevin@
epa.
gov.
To
request
a
public
hearing,
to
request
to
speak
at
a
public
hearing,
or
to
find
out
if
a
public
hearing
will
be
held,
contact
Ms.
Cassie
Posey,
Metals
Group,
Emission
Standards
Division
(C439–
02),
U.
S.
EPA,
Research
Triangle
Park,
NC
27711,
telephone
number
(919)
541–
0069,
electronic
mail
address:
posey.
cassie@
epa.
gov.
For
information
concerning
applicability
and
rule
determinations,
contact
your
State
or
local
permitting
authority
or
the
appropriate
EPA
regional
office
representatives.
SUPPLEMENTARY
INFORMATION:
Comments.
Comments
and
data
may
be
submitted
by
electronic
mail
(e
mail)
to:
a
and
r
docket@
epa.
gov.
Electronic
comments
must
be
submitted
as
an
ASCII
file
to
avoid
the
use
of
special
characters
and
encryption
problems
and
will
also
be
accepted
on
disks
in
WordPerfect
format.
All
comments
and
data
submitted
in
electronic
form
must
note
the
docket
number:
Docket
No.
A–
79–
33.
No
confidential
business
information
(CBI)
should
be
submitted
by
e
mail.
Electronic
comments
may
be
filed
online
at
many
Federal
Depository
Libraries.
Commenters
wishing
to
submit
proprietary
information
for
consideration
must
clearly
distinguish
such
information
from
other
comments
and
clearly
label
it
as
CBI.
Send
submissions
containing
such
proprietary
information
directly
to
the
following
address,
and
not
to
the
public
docket,
to
ensure
that
proprietary
information
is
not
inadvertently
placed
in
the
docket:
OAQPS
Document
Control
Office
(C404–
02),
Attention:
Mr.
Kevin
Cavender,
Emission
Standards
Division,
U.
S.
EPA,
Research
Triangle
Park,
NC
27711.
The
EPA
will
disclose
information
identified
as
CBI
only
to
the
extent
allowed
by
the
procedures
set
forth
in
40
CFR
part
2.
If
no
claim
of
confidentiality
accompanies
a
submission
when
it
is
received
by
the
EPA,
the
information
may
be
made
available
to
the
public
without
further
notice
to
the
commenter.
Public
Hearing.
Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Ms.
Cassie
Posey,
telephone
number:
(919)
541–
0069.
Persons
interested
in
attending
the
public
hearing
must
also
contact
Cassie
Posey
to
verify
the
time,
date,
and
location
of
the
hearing.
The
address,
telephone
number,
and
e
mail
address
for
Ms.
Posey
are
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
A
public
hearing,
if
held,
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
the
proposed
emission
standards.
Docket.
The
docket
is
an
organized
and
complete
file
of
all
the
information
considered
by
the
EPA
in
rule
development.
The
docket
is
a
dynamic
file
because
material
is
added
throughout
the
rulemaking
process.
The
docketing
system
is
intended
to
allow
members
of
the
public
and
industries
involved
to
readily
identify
and
locate
documents
so
that
they
can
effectively
participate
in
the
rulemaking
process.
Along
with
the
proposed
and
promulgated
standards
and
their
preambles,
the
contents
of
the
docket
will
serve
as
the
record
in
the
case
of
judicial
review.
(See
section
307(
d)(
7)(
A)
of
the
Clean
Air
Act
(CAA).)
The
regulatory
text
and
other
materials
related
to
the
rulemaking
are
available
for
review
in
the
docket
or
copies
may
be
mailed
on
request
from
the
Air
Docket
by
calling
(202)
260–
7548.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.
World
Wide
Web
(WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
today's
proposed
rule
will
also
be
available
on
the
WWW
through
the
Technology
Transfer
Network
(TTN).
Following
signature,
a
copy
of
the
proposed
rule
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(919)
541–
5384.
Regulated
Entities.
Entities
potentially
regulated
by
this
action
include
steel
manufacturing
facilities
who
operate
electric
arc
furnaces.
Affected
categories
and
entities
include
certain
sources
in
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Federal
Register
/
Vol.
67,
No.
200
/
Wednesday,
October
16,
2002
/
Proposed
Rules
the
North
American
Information
Classification
System
code
331111.
This
description
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
your
facility
is
regulated
by
this
action,
you
should
examine
the
applicability
criteria
in
the
rule.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:
I.
Background
A.
What
is
an
EAF?
B.
What
are
the
current
NSPS
requirements
for
an
EAF?
C.
Why
are
the
current
NSPS
requirements
being
amended?
D.
What
is
a
bag
leak
detection
system,
and
how
is
it
used
to
monitor
baghouse
performance?
II.
Summary
of
Proposed
Amendment
A.
What
is
the
alternative
monitoring
option
being
proposed?
B.
What
are
the
editorial
corrections
being
made?
III.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Executive
Order
13132,
Federalism
C.
Executive
Order
13175,
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Unfunded
Mandates
Reform
Act
of
1995
F.
Regulatory
Flexibility
Act
(RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(SBREFA),
5
U.
S.
C.
601
et
seq.
G.
Paperwork
Reduction
Act
H.
National
Technology
Transfer
and
Advancement
Act
of
1995
I.
Executive
Order
13211,
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution
or
Use
I.
Background
A.
What
Is
an
EAF?
An
EAF
is
a
metallurgical
furnace
used
to
produce
carbon
and
alloy
steels.
The
input
material
to
an
EAF
is
typically
100
percent
scrap
steel.
Cylindrical,
refractory
lined
EAF
are
equipped
with
carbon
electrodes
to
be
raised
or
lowered
through
the
furnace
roof.
With
electrodes
retracted,
the
furnace
roof
can
be
rotated
to
permit
the
charge
of
scrap
steel
by
overhead
crane.
Alloying
agents
and
fluxing
materials
usually
are
added
through
doors
on
the
side
of
the
furnace.
Electric
current
is
passed
between
the
electrodes
and
through
the
scrap,
generating
arcing
and
the
generation
of
enough
heat
to
melt
the
scrap
steel
charge.
After
the
melting
and
refining
periods,
impurities
(in
the
form
of
a
slag)
and
the
refined
steel
are
poured
from
the
furnace.
The
production
of
steel
in
an
EAF
is
a
batch
process.
Cycles,
or
heats,
range
from
about
1
1
Ú2
to
5
hours
to
produce
carbon
steel
and
from
5
to
10
hours
to
produce
alloy
steel.
Scrap
steel
is
charged
to
begin
a
cycle,
and
alloying
agents
and
slag
forming
materials
are
added
for
refining.
Stages
of
each
cycle
normally
are
charging,
melting,
refining
(which
usually
includes
oxygen
blowing),
and
tapping.
All
of
those
operations
generate
particulate
matter
(PM)
emissions.
Emission
control
techniques
involve
an
emission
capture
system
and
a
gas
cleaning
system.
Emission
capture
systems
used
in
the
industry
include
direct
shell
(fourth
hole)
evacuation,
side
draft
hoods,
combination
hoods,
canopy
hoods,
scavenger
ducts,
and
furnace
enclosures.
Direct
shell
evacuation
(DEC)
consists
of
ductwork
attached
to
a
separate
opening,
or
``
fourth
hole'',
in
the
furnace
roof
which
draws
emissions
to
a
gas
cleaner.
The
direct
shell
evacuation
system
works
only
when
the
furnace
is
up
right
and
the
roof
is
in
place.
The
side
draft
hoods
collect
furnace
offgases
from
around
the
electrode
holes
and
the
work
doors
after
the
gases
leave
the
furnace.
The
combination
hood
incorporates
elements
from
the
side
draft
and
direct
shell
evacuation
systems.
Canopy
hoods
and
scavenger
ducts
are
used
to
address
charging
and
tapping
emissions.
Baghouses
are
typically
used
as
the
gas
cleaning
system.
B.
What
Are
the
Current
NSPS
Requirements
for
an
EAF?
The
NSPS
for
EAF
constructed
after
October
21,
1974,
and
on
or
before
August
17,
1983
(40
CFR
part
60,
subpart
AA)
were
first
promulgated
in
the
Federal
Register
on
September
23,
1975
(40
FR
43850).
The
NSPS
for
EAF
constructed
after
August
17,
1983
(40
CFR
part
60,
subpart
AAa)
were
first
promulgated
in
the
Federal
Register
on
October
31,
1984
(49
FR
43845).
Both
subparts
limit
the
allowable
PM
concentration
in
the
exhaust
of
an
EAF
emission
control
device
to
12
milligrams
per
dry
standard
cubic
meter
(mg/
dscm).
In
addition
to
the
PM
emission
limit,
both
subparts
limit
visible
emissions
from
the
EAF
control
device
to
less
than
3
percent
opacity,
as
determined
by
EPA
Method
9
of
40
CFR
part
60,
appendix
A.
In
both
subparts,
if
the
control
device
is
equipped
with
a
single
stack,
the
owner
or
operator
is
required
to
install,
calibrate,
maintain,
and
operate
a
continuous
opacity
monitoring
system
(COMS).
The
owner
and
operator
must
report
each
6
minute
average
COM
reading
of
3
percent
or
greater
as
an
excess
emission.
A
COMS
is
not
required
on
any
modular
or
multiplestack
fabric
filter
if
opacity
readings
are
taken
at
least
once
per
day
during
a
melting
and
refining
period,
in
accordance
with
EPA
Method
9.
The
subparts
also
contain
requirements
for
the
EAF
capture
systems.
However,
those
requirements
are
not
being
amended
by
today's
action.
As
such,
we
do
not
discuss
the
capture
system
requirements
here.
C.
Why
Are
the
Current
NSPS
Requirements
Being
Amended?
Today's
action
is
being
taken
in
response
to
a
petition
to
reopen
the
NSPS
that
we
received
from
the
American
Iron
and
Steel
Institute
(AISI),
the
Specialty
Steel
Industry
of
North
America
(SSINA),
and
the
Steel
Manufacturers
Association
(SMA),
who
jointly
will
be
referred
to
as
``
the
Petitioner.
''
In
their
request
to
reopen
the
EAF
NSPS,
the
Petitioner
argues
that
COMS
are
not
capable
of
accurately
monitoring
opacity
emissions
from
an
EAF
shop
at
the
3
percent
excess
emissions
threshold
level
and
that
the
EAF
NSPS
should
be
amended
to
address
the
technological
shortcomings
associated
with
COMS.
In
making
their
argument,
the
Petitioner
points
to
our
recent
revision
to
the
performance
specification
for
COMS
(PSÐ
1,
65
FR
48914)
in
which
we
acknowledge
that
there
is
potential
for
measurement
error
associated
with
COM
readings.
A
conservative
approach
to
estimating
the
upper
range
of
the
potential
measurement
error
resulted
in
an
estimate
of
approximately
4
percent
opacity.
The
Petitioner
also
points
out
that
the
American
Society
for
Testing
and
Materials
(ASTM)
Standard
for
COMS
(ASTM
D
6216Ð
98),
which
is
incorporated
in
PSÐ
1,
expressly
limits
the
scope
of
the
ASTM
Standard
to
COMS
used
to
monitor
opacity
subject
to
an
opacity
limit
of
10
percent
or
greater
due
to
the
potential
error
associated
with
opacity
measurements.
The
Petitioner
argues
that
COMS
generate
inaccurate
data
which
can
trigger
Federal
and
State
reporting
requirements
and
expose
a
facility
to
potential
liability
even
when
the
facility
is
meeting
the
opacity
standard.
As
pointed
out
above,
owners
and
operators
are
required
by
the
NSPS
to
report
all
6
minute
average
COMS
readings
above
3
percent
as
periods
of
excess
emissions.
Since
the
potential
COMS
measurement
error
is
high
in
comparison
to
the
3
percent
opacity
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Proposed
Rules
standard,
the
Petitioner
believes
that
the
COMS
can
and
do
produce
readings
above
the
3
percent
excess
emissions
threshold
when
the
actual
opacity
is
below
3
percent.
The
Petitioner
points
out
that
the
credible
evidence
revisions
(62
FR
8313,
February
24,
1997)
clarify
our
intent
to
use
COMS
data
as
evidence
of
a
potential
emissions
violation.
Therefore,
the
Petitioner
argues,
COMS
data
falsely
indicating
emissions
above
3
percent
opacity
could
be
used
as
evidence
of
violations
of
the
opacity
standard.
Even
if
the
erroneous
COMS
data
are
eventually
determined
not
to
be
credible,
the
Petitioner
argues,
companies
must
bear
the
burden
and
cost
of
defending
against
such
allegations.
The
revisions
to
PSÐ
1
explained
that
we
did
not
believe
it
was
appropriate
to
limit
the
applicability
of
PSÐ
1
based
on
the
level
of
the
emission
limit
that
would
be
monitored.
Instead
of
limiting
the
applicability
of
PSÐ
1,
we
determined
that
PSÐ
1
should
acknowledge
the
measurement
uncertainty
associated
with
COMS
measurements
below
10
percent
opacity,
and
allow
for
a
consideration
of
the
potential
error
(through
statistical
procedures
or
otherwise)
when
evaluating
compliance
with
opacity
standards
below
10
percent.
We
agree
that
it
is
appropriate
to
provide
an
alternative
monitoring
option
for
EAF
owners
and
operators
who
are
concerned
with
the
accuracy
of
COMS
measurements
at
levels
below
10
percent
opacity.
In
addition,
we
believe
that
bag
leak
detection
systems,
the
alternative
monitoring
option
being
proposed,
are
a
viable
alternative
to
COMS
for
the
purpose
of
monitoring
the
performance
of
baghouses.
D.
What
Is
a
Bag
Leak
Detection
System,
and
How
Is
It
Used
To
Monitor
Baghouse
Performance?
A
bag
leak
detection
system
is
a
device
that
is
used
to
measure
relative
particulate
loadings
in
the
exhaust
of
a
baghouse
on
a
continuous
basis
in
order
to
detect
bag
leaks
and
other
conditions
that
result
in
increases
in
particulate
loadings.
Bag
leak
detection
systems
have
been
developed
based
on
a
number
of
principles
including
triboelectric
effect,
electrodynamic
effect,
and
light
scattering.
A
bag
leak
detection
system
does
not
need
to
provide
an
output
in
terms
of
particulate
concentration,
but
must
provide
an
output
that
is
proportionate
to
the
particulate
concentration
such
that
if
particulate
concentrations
increase
the
output
from
the
bag
leak
detection
system
increases.
A
bag
leak
detection
system
identifies
leaks
by
the
resulting
increase
in
particulate
loadings.
A
properly
designed
baghouse
will
control
particulate
emissions
to
very
low
levels
when
in
good
operating
condition.
However,
if
the
baghouse
develops
a
leak,
due
to
a
torn
bag
or
seal,
there
will
be
a
measurable
increase
in
particulate
emissions.
A
bag
leak
detection
system
is
capable
of
quickly
(within
a
few
seconds)
determining
that
an
abnormal
increase
in
particulate
concentrations
has
occurred
and
can
then
trigger
an
alarm
to
alert
the
operator
so
that
the
leak
can
be
stopped
as
soon
as
possible.
Bag
leak
detection
systems
are
capable
of
detecting
small
leaks
while
particulate
emissions
are
well
below
the
levels
that
would
result
in
observable
opacity.
For
that
reason,
we
believe
that
bag
leak
detection
systems
are
well
suited
for
monitoring
the
performance
of
a
baghouse.
II.
Summary
of
Proposed
Amendment
A.
What
Is
the
Alternative
Monitoring
Option
Being
Proposed?
We
are
proposing
bag
leak
detection
coupled
with
a
once
per
day
opacity
observation
as
an
alternative
monitoring
option
to
COMS.
Under
the
proposed
alternative,
a
facility
could
elect
to
install,
calibrate,
maintain,
and
operate
a
bag
leak
detection
system.
Owners
or
operators
would
be
required
to
develop
a
site
specific
monitoring
plan
describing
how
the
system
would
be
selected,
installed,
and
operated,
including
how
the
alarm
levels
would
be
established.
Within
30
minutes
of
an
alarm,
the
owner
or
operator
would
be
required
to
initiate
procedures
to
determine
the
cause
of
the
alarm
and
alleviate
the
cause
of
the
alarm
within
3
hours.
In
addition,
the
owner
or
operator
would
be
required
to
maintain
and
operate
their
baghouse
such
that
the
alarm
on
the
bag
leak
detector
does
not
alarm
for
more
than
3
percent
of
the
operating
hours
in
any
6
month
reporting
period.
The
owner
or
operator
would
also
be
required
to
conduct
an
opacity
observation
at
least
once
per
day
when
the
furnace
is
in
the
melting
or
refining
operation
day,
in
accordance
with
EPA
Method
9.
All
opacity
observations
greater
than
3
percent
opacity
would
be
reported
as
a
violation
of
the
opacity
standard.
In
addition,
if
the
alarm
on
the
bag
leak
detection
system
was
not
alarming
during
the
time
the
opacity
was
observed
to
be
greater
than
3
percent,
the
alarm
on
the
bag
leak
detection
system
would
have
to
be
lowered
to
a
point
that
an
alarm
would
have
occurred
during
the
observation.
B.
What
Are
the
Editorial
Corrections
Being
Made?
Two
typographical
errors
are
being
corrected
in
the
amendment.
In
40
CFR
60.274(
c)
and
in
40
CFR
60.274a(
c),
the
references
to
paragraphs
(b)(
1)
and
(2)
are
being
corrected
to
refer
to
paragraph
(b).
The
paragraphs
(b)(
1)
and
(2)
of
40
CFR
60.274(
c)
and
40
CFR
60.274a(
c)
were
incorporated
into
paragraph
(b)
during
the
last
revision
to
the
NSPS
(64
FR
10105,
March
2,
1999).
In
40
CFR
60.274a(
b),
the
reference
to
paragraph
(d)
is
being
corrected
to
refer
to
paragraph
(e).
In
addition,
40
CFR
60.274a(
d)
and
40
CFR
60.274a(
e)
are
being
revised
to
clarify
that
owners
and
operators
may
petition
the
Administrator
to
approve
alternatives
to
the
monitoring
requirements
specified
in
40
CFR
60.274a(
b),
as
well
as
alternatives
to
the
monthly
operational
status
inspections
specified
in
40
CFR
60.274a(
d).
This
revision
does
not
change
the
rule
requirements
because
owners
and
operators
are
currently
allowed
to
petition
for
alternative
monitoring
requirements
under
40
CFR
60.13(
i)
of
the
General
Provisions.
III.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(58
FR
51735,
October
4,
1993),
we
must
determine
whether
the
regulatory
action
is
``
significant''
and,
therefore,
subject
to
review
by
the
Office
of
Management
and
Budget
(OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(1)
Have
an
annual
effect
on
the
economy
of
$100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(2)
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(3)
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligation
of
recipients
thereof;
or
(4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
it
has
been
determined
that
the
proposed
rule
amendments
are
not
a
``
significant
regulatory
action''
because
none
of
the
listed
criteria
apply
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16,
2002
/
Proposed
Rules
to
the
action.
Consequently,
the
action
was
not
submitted
to
OMB
for
review
under
Executive
Order
12866.
B.
Executive
Order
13132,
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(64
FR
43255,
August
10,
1999),
requires
us
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.
''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.
''
The
proposed
rule
amendments
do
not
have
federalism
implications.
They
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
None
of
the
affected
facilities
are
owned
or
operated
by
State
governments,
and
the
requirements
of
the
proposed
rule
amendments
will
not
supercede
State
regulations
that
are
more
stringent.
Thus,
Executive
Order
13132
does
not
apply
to
the
proposed
rule
amendments.
In
the
spirit
of
Executive
Order
13132
and
consistent
with
our
policy
to
promote
communications
between
us
and
State
and
local
governments,
we
specifically
solicit
comments
on
the
proposed
rule
amendments
from
State
and
local
officials.
C.
Executive
Order
13175,
Consultation
and
Coordination
with
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(65
FR
67249,
November
6,
2000),
requires
us
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.
''
``
Policies
that
have
tribal
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
the
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
federal
government
and
Indian
tribes.
''
The
proposed
rule
amendments
do
not
have
tribal
implications.
They
will
not
have
substantial
direct
effects
on
tribal
governments,
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
No
tribal
governments
own
or
operate
an
affected
source.
Thus,
Executive
Order
13175
does
not
apply
to
the
proposed
rule
amendments.
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(1)
Is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(2)
concerns
an
environmental
health
or
safety
risk
that
we
have
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
we
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
rule
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
that
we
considered.
We
interpret
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5Ð
501
of
the
Executive
Order
has
the
potential
to
influence
the
rule.
The
proposed
rule
amendments
are
not
subject
to
Executive
Order
13045
because
they
are
based
on
technology
performance
and
not
on
health
or
safety
risks.
No
children's
risk
analysis
was
performed
because
the
action
only
provides
affected
EAF
owners
and
operators
with
alternative
monitoring
options.
Furthermore,
the
proposed
rule
amendments
have
been
determined
not
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866.
E.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(UMRA),
Public
Law
104Ð
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
we
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
by
State,
local,
and
tribal
governments,
in
the
aggregate,
or
by
the
private
sector,
of
$100
million
or
more
in
any
1
year.
Before
promulgating
a
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
us
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
us
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
we
establish
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
we
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
our
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
We
have
determined
that
the
proposed
rule
amendments
do
not
contain
a
Federal
mandate
that
may
result
in
estimated
costs
of
$100
million
or
more
for
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
The
maximum
total
annual
cost
of
the
proposed
rule
amendments
for
any
year
has
been
estimated
to
be
less
than
$62,000.
Thus,
today's
proposed
rule
amendments
are
not
subject
to
the
requirements
of
sections
202
and
205
of
the
UMRA.
In
addition,
we
have
determined
that
the
proposed
rule
amendments
contain
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments
because
they
contain
no
requirements
that
apply
to
such
governments
or
impose
obligations
upon
them.
Therefore,
today's
proposed
rule
amendments
are
not
subject
to
the
requirements
of
section
203
of
the
UMRA.
F.
Regulatory
Flexibility
Act
(RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1966
(SBREFA),
5
U.
S.
C.
601
et
seq.
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
for
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
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/
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67,
No.
200
/
Wednesday,
October
16,
2002
/
Proposed
Rules
small
organizations,
and
small
governmental
jurisdictions.
The
proposed
amendments
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities
because
the
amendments
only
provide
alternative
compliance
options
designed
to
provide
facilities
with
increased
flexibility.
Therefore,
I
certify
that
the
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
G.
Paperwork
Reduction
Act
The
information
collection
requirements
in
the
proposed
rule
amendments
have
been
submitted
for
approval
to
OMB
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
We
have
prepared
an
Information
Collection
Request
(ICR)
document
(ICR
No.
1060.11),
and
you
may
obtain
a
copy
from
Susan
Auby
by
mail
at
the
Office
of
Environmental
Information,
Collection
Strategies
Division,
U.
S.
EPA
(2822),
1200
Pennsylvania
Avenue
NW.,
Washington,
DC
20460;
by
e
mail
at
auby.
susan@
epa.
gov;
or
by
calling
(202)
566Ð
1672.
You
may
also
download
a
copy
off
the
Internet
at
http://
www.
epa.
gov/
icr.
The
information
requirements
are
not
effective
until
OMB
approves
them.
The
information
requirements
are
based
on
notification,
recordkeeping,
and
reporting
requirements
in
the
NSPS
General
Provisions
(40
CFR
part
60,
subpart
A),
which
are
mandatory
for
all
operators
subject
to
NSPS.
The
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(42
U.
S.
C.
7414).
All
information
submitted
to
us
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
our
policies
set
forth
in
40
CFR
part
2,
subpart
B.
The
annual
increase
to
monitoring,
recordkeeping,
and
reporting
burden
for
the
proposed
rule
amendments
are
estimated
at
1750
labor
hours
at
a
total
cost
of
$61,267
nationwide,
and
the
annual
average
increase
in
burden
is
175
labor
hours
and
$6,127
per
source.
We
estimate
that
there
will
be
no
increase
in
the
annualized
capital
costs
due
to
the
proposed
rule
amendments.
We
estimate
that
the
annualized
costs
associated
with
purchasing
and
installing
a
bag
leak
detection
system
are
equal
to
the
offsetting
annualized
cost
savings
associated
with
the
discontinued
use
and
periodic
replacement
of
a
COMS.
In
making
the
estimates,
it
was
assumed
that
ten
existing
facilities
currently
required
to
install
and
operate
COMS
would
elect
to
use
the
proposed
alternative
monitoring
option.
The
cost
estimates
reflect
increased
costs
associated
with
the
installation
and
operation
of
a
bag
leak
detection
system
and
with
daily
opacity
observations
partially
offset
by
the
cost
savings
from
no
longer
having
to
operate
and
maintain
a
COMS.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to:
Review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
existing
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
Agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
our
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Comments
are
requested
on
our
need
for
the
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
Send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
EPA
(2822),
1200
Pennsylvania
Avenue
NW.,
Washington,
DC
20460;
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
Street
NW.,
Washington,
DC
20503;
marked
``
Attention:
Desk
Officer
for
EPA.
''
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
October
16,
2002,
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
November
15,
2002.
The
final
action
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
this
proposal.
H.
National
Technology
Transfer
and
Advancement
Act
of
1995
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(NTTAA)
Public
Law
104Ð
113
(15
U.
S.
C.
272
note)
directs
us
to
use
voluntary
consensus
standards
in
our
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
directs
us
to
provide
Congress,
through
annual
reports
to
OMB,
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.
The
proposed
rulemaking
does
not
involve
a
technical
standard.
I.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution
or
Use
The
proposed
rule
amendments
are
not
subject
to
Executive
Order
13211
(66
FR
28355,
May
22,
2001)
because
it
is
not
a
significant
regulatory
action
under
Executive
Order
12866.
List
of
Subjects
in
40
CFR
Part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.
Dated:
October
9,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
set
out
in
the
preamble,
title
40,
chapter
I,
part
63
of
the
Code
of
Federal
Regulations
is
amended
as
follows:
PART
60—[
AMENDED]
1.
The
authority
citation
for
part
60
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401,
et
seq.
2.
Section
60.271
is
amended
by
adding
new
paragraphs
(o)
and
(p)
to
read
as
follows:
§
60.271
Definitions.
*
*
*
*
*
(o)
Bag
Leak
detection
system
means
a
system
that
is
capable
of
continuously
monitoring
relative
particulate
matter
(dust)
loadings
in
the
exhaust
of
a
baghouse
to
detect
bag
leaks
and
other
conditions
that
result
in
increases
in
particulate
loadings.
A
bag
leak
detection
system
includes,
but
is
not
limited
to,
an
instrument
that
operates
on
triboelectric,
electrodynamic,
light
scattering,
light
transmittance,
or
other
effect
to
continuously
monitor
relative
particulate
matter
loadings.
(p)
Operating
time
means
the
period
of
time
in
hours
that
an
affected
source
is
in
operation
beginning
at
a
startup
and
ending
at
the
next
shutdown.
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/
Vol.
67,
No.
200
/
Wednesday,
October
16,
2002
/
Proposed
Rules
3.
Section
60.273
is
amended
by
revising
paragraph
(c)
and
adding
new
paragraphs
(e),
(f),
(g),
and
(h)
to
read
as
follows:
§
60.273
Emission
monitoring.
*
*
*
*
*
(c)
A
continuous
monitoring
system
for
the
measurement
of
the
opacity
of
emissions
discharged
into
the
atmosphere
from
the
control
device(
s)
is
not
required
on
any
modular,
multistack
negative
pressure
or
positivepressure
fabric
filter
if
observations
of
the
opacity
of
the
visible
emissions
from
the
control
device
are
performed
by
a
certified
visible
emission
observer;
or
on
any
single
stack
fabric
filter
if
visible
emissions
from
the
control
device
are
performed
by
a
certified
visible
emission
observer
and
the
owner
installs
and
continuously
operates
a
bag
leak
detection
system
according
to
paragraph
(e)
of
this
section.
Visible
emission
observations
shall
be
conducted
at
least
once
per
day
for
at
least
three
6
minute
periods
when
the
furnace
is
operating
in
the
melting
and
refining
period.
All
visible
emissions
observations
shall
be
conducted
in
accordance
with
Method
9
of
appendix
A
to
this
part.
If
visible
emissions
occur
from
more
than
one
point,
the
opacity
shall
be
recorded
for
any
points
where
visible
emissions
are
observed.
Where
it
is
possible
to
determine
that
a
number
of
visible
emission
sites
relate
to
only
one
incident
of
the
visible
emission,
only
one
set
of
three
6
minute
observations
will
be
required.
In
that
case,
the
Method
9
observations
must
be
made
for
the
site
of
highest
opacity
that
directly
relates
to
the
cause
(or
location)
of
visible
emissions
observed
during
a
single
incident.
Records
shall
be
maintained
of
any
6
minute
average
that
is
in
excess
of
the
emission
limit
specified
in
§
60.272(
a).
*
*
*
*
*
(e)
A
bag
leak
detection
system
must
be
installed
and
continuously
operated
on
all
single
stack
fabric
filters
if
the
owner
or
operator
elects
not
to
install
and
operate
a
continuous
opacity
monitoring
system
as
provided
for
under
paragraph
(c)
of
this
section.
In
addition,
the
owner
or
operator
shall
meet
the
visible
emissions
observation
requirements
in
paragraph
(c)
of
this
section.
The
bag
leak
detection
system
must
meet
the
specifications
and
requirements
of
paragraphs
(e)(
1)
through
(8)
of
this
section.
(1)
The
bag
leak
detection
system
must
be
certified
by
the
manufacturer
to
be
capable
of
detecting
particulate
matter
emissions
at
concentrations
of
10
milligrams
per
actual
cubic
meter
(0.0044
grains
per
actual
cubic
foot)
or
less.
(2)
The
bag
leak
detection
system
sensor
must
provide
output
of
relative
particulate
matter
loadings
and
the
owner
or
operator
shall
continuously
record
the
output
from
the
bag
leak
detection
system
using
electronic
or
other
means
(e.
g.,
using
a
strip
chart
recorder
or
a
data
logger.)
(3)
The
bag
leak
detection
system
must
be
equipped
with
an
alarm
system
that
will
sound
when
an
increase
in
relative
particulate
loading
is
detected
over
the
alarm
set
point
established
according
to
paragraph
(e)(
4)
of
this
section,
and
the
alarm
must
be
located
such
that
it
can
be
heard
by
the
appropriate
plant
personnel.
(4)
For
each
bag
leak
detection
system
required
by
paragraph
(e)
of
this
section,
the
owner
or
operator
shall
develop
and
submit,
to
the
Administrator
or
delegated
authority,
for
approval,
a
sitespecific
monitoring
plan
that
addresses
the
items
identified
in
paragraphs
(e)(
4)(
i)
through
(v)
of
this
section.
For
each
bag
leak
detection
system
that
operates
based
on
the
triboelectric
effect,
the
monitoring
plan
shall
be
consistent
with
the
recommendations
contained
in
the
U.
S.
Environmental
Protection
Agency
guidance
document
``
Fabric
Filter
Bag
Leak
Detection
Guidance''
(EPAÐ
454/
RÐ
98Ð
015).
The
owner
or
operator
shall
operate
and
maintain
the
bag
leak
detection
system
according
to
the
site
specific
monitoring
plan
at
all
times.
The
plan
shall
describe:
(i)
Installation
of
the
bag
leak
detector
system;
(ii)
Initial
and
periodic
adjustment
of
the
bag
leak
detector
system
including
how
the
alarm
set
point
will
be
established;
(iii)
Operation
of
the
bag
leak
detection
system
including
quality
assurance
procedures;
(iv)
How
the
bag
leak
detection
system
will
be
maintained
including
a
routine
maintenance
schedule
and
spare
parts
inventory
list;
and
(v)
How
the
bag
leak
detection
system
output
shall
be
recorded
and
stored.
(5)
The
initial
adjustment
of
the
system
shall,
at
a
minimum,
consist
of
establishing
the
baseline
output
by
adjusting
the
sensitivity
(range)
and
the
averaging
period
of
the
device,
and
establishing
the
alarm
set
points
and
the
alarm
delay
time
(if
applicable).
(6)
Following
initial
adjustment,
the
owner
or
operator
shall
not
adjust
the
averaging
period,
alarm
set
point,
or
alarm
delay
time
without
approval
from
the
Administrator
or
delegated
authority
except
as
provided
for
in
paragraphs
(e)(
6)(
i)
and
(ii)
of
this
section.
(i)
Once
per
quarter,
the
owner
or
operator
may
adjust
the
sensitivity
of
the
bag
leak
detection
system
to
account
for
seasonal
effects
including
temperature
and
humidity
according
to
the
procedures
identified
in
the
sitespecific
monitoring
plan
required
under
paragraph
(e)(
4)
of
this
section.
(ii)
If
opacities
greater
than
zero
percent
are
observed
over
four
consecutive
15
second
observations
during
the
daily
opacity
observations
required
under
paragraph
(c)
of
this
section
and
the
alarm
on
the
bag
leak
detection
system
does
not
sound,
the
owner
or
operator
shall
lower
the
alarm
set
point
on
the
bag
leak
detection
system
to
a
point
where
the
alarm
would
have
sounded
during
the
period
when
the
opacity
observations
were
made.
(7)
For
negative
pressure,
induced
air
baghouses,
and
positive
pressure
baghouses
that
are
discharged
to
the
atmosphere
through
a
stack,
the
bag
leak
detector
sensor
must
be
installed
downstream
of
the
baghouse
and
upstream
of
any
wet
scrubber.
(8)
Where
multiple
detectors
are
required,
the
system's
instrumentation
and
alarm
may
be
shared
among
detectors.
(f)
For
each
bag
leak
detection
system
installed
according
to
paragraph
(e)
of
this
section,
the
owner
or
operator
shall
initiate
procedures
to
determine
the
cause
of
all
alarms
within
30
minutes
of
an
alarm.
The
cause
of
the
alarm
must
be
alleviated
within
3
hours
of
the
time
the
alarm
occurred
by
taking
whatever
corrective
action(
s)
are
necessary.
If
additional
time
is
required
to
alleviate
the
cause
of
the
alarm,
the
owner
or
operator
shall
notify
the
Administrator
or
delegated
authority.
Corrective
actions
may
include,
but
are
not
limited
to
the
following:
(1)
Inspecting
the
baghouse
for
air
leaks,
torn
or
broken
bags
or
filter
media,
or
any
other
condition
that
may
cause
an
increase
in
particulate
emissions;
(2)
Sealing
off
defective
bags
or
filter
media;
(3)
Replacing
defective
bags
or
filter
media,
or
otherwise
repairing
the
control
device;
(4)
Sealing
off
a
defective
baghouse
compartment;
(5)
Cleaning
the
bag
leak
detection
system
probe,
or
otherwise
repairing
the
bag
leak
detection
system;
or
(6)
Shutting
down
the
process
producing
the
particulate
emissions.
(g)
The
owner
or
operator
shall
maintain
each
baghouse
monitored
by
a
bag
leak
detection
system
such
that
the
alarm
on
the
bag
leak
detection
system
does
not
sound
for
more
than
3
percent
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67,
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200
/
Wednesday,
October
16,
2002
/
Proposed
Rules
of
the
total
operating
time
in
a
6
month
reporting
period.
(h)
The
percentage
of
time
the
alarm
on
a
bag
leak
detection
system
sounds
shall
be
determined
according
to
paragraphs
(h)(
1)
through
(5)
of
this
section.
(1)
An
alarm
that
occurs
due
solely
to
a
malfunction
of
the
bag
leak
detection
system
shall
not
be
included
in
the
calculation.
(2)
An
alarm
that
occurs
during
startup,
shutdown,
or
malfunction
shall
not
be
included
in
the
calculation
if
the
owner
or
operator
follows
all
requirements
contained
in
§
60.11(
d).
(3)
For
each
alarm
where
the
owner
or
operator
initiates
procedures
to
determine
the
cause
of
an
alarm
within
1
hour
of
the
alarm,
1
hour
of
alarm
time
shall
be
counted.
(4)
For
each
alarm
where
the
owner
or
operator
does
not
initiate
procedures
to
determine
the
cause
of
the
alarm
within
1
hour
of
the
alarm,
alarm
time
will
be
counted
as
the
actual
amount
of
time
taken
by
the
owner
or
operator
to
initiate
procedures
to
determine
the
cause
of
the
alarm.
(5)
The
percentage
of
time
the
alarm
on
the
bag
leak
detection
system
sounds
shall
be
calculated
as
the
ratio
of
the
sum
of
alarm
times
to
the
total
operating
time
multiplied
by
100.
4.
Section
60.274
is
amended
by
revising
the
first
sentence
of
paragraph
(c)
to
read
as
follows:
§
60.274
Monitoring
of
operations.
*
*
*
*
*
(c)
When
the
owner
or
operator
of
an
affected
facility
is
required
to
demonstrate
compliance
with
the
standards
under
§
60.272(
a)(
3)
and
at
any
other
time
the
Administrator
may
require
that
(under
section
114
of
the
CAA,
as
amended)
either:
the
control
system
fan
motor
amperes
and
all
damper
positions;
the
volumetric
flow
rate
through
each
separately
ducted
hood;
or
the
volumetric
flow
rate
at
the
control
device
inlet
and
all
damper
positions
shall
be
determined
during
all
periods
in
which
a
hood
is
operated
for
the
purpose
of
capturing
emissions
from
the
affected
facility
subject
to
paragraph
(b)
of
this
section.
*
*
*
*
*
*
*
*
5.
Section
60.275
is
amended
by
revising
paragraph
(i)
to
read
as
follows:
§
60.275
Test
methods
and
procedures.
*
*
*
*
*
(i)
If
visible
emissions
observations
are
made
in
lieu
of
using
a
continuous
opacity
monitoring
system,
as
allowed
for
by
§
60.273(
c),
visible
emission
observations
shall
be
conducted
at
least
once
per
day
for
at
least
three
6
minute
periods
when
the
furnace
is
operating
in
the
melting
and
refining
period.
All
visible
emissions
observations
shall
be
conducted
in
accordance
with
Method
9.
If
visible
emissions
occur
from
more
than
one
point,
the
opacity
shall
be
recorded
for
any
points
where
visible
emissions
are
observed.
Where
it
is
possible
to
determine
that
a
number
of
visible
emission
sites
relate
to
only
one
incident
of
the
visible
emission,
only
one
set
of
three
6
minute
observations
will
be
required.
In
that
case,
the
Method
9
observations
must
be
made
for
the
site
of
highest
opacity
that
directly
relates
to
the
cause
(or
location)
of
visible
emissions
observed
during
a
single
incident.
Records
shall
be
maintained
of
any
6
minute
average
that
is
in
excess
of
the
emission
limit
specified
in
§
60.272(
a).
*
*
*
*
*
6.
Section
60.276
is
amended
by
adding
new
paragraphs
(e)
and
(f)
to
read
as
follows:
§
60.276
Recordkeeping
and
reporting
requirements.
*
*
*
*
*
(e)
The
owner
or
operator
shall
maintain
the
following
records
for
each
bag
leak
detection
system
required
under
§
60.273(
e):
(1)
Records
of
the
bag
leak
detection
system
output;
(2)
Records
of
bag
leak
detection
system
adjustments,
including
the
date
and
time
of
the
adjustment,
the
initial
bag
leak
detector
settings,
and
the
final
bag
leak
detector
settings;
(3)
An
identification
of
the
date
and
time
of
all
bag
leak
detection
system
alarms,
the
time
that
procedures
to
determine
the
cause
of
the
alarm
were
initiated,
if
procedures
were
initiated
within
30
minutes
of
the
alarm,
the
cause
of
the
alarm,
an
explanation
of
the
actions
taken,
the
date
and
time
the
cause
of
the
alarm
was
alleviated,
and
if
the
alarm
was
alleviated
within
3
hours
of
the
alarm;
and
(4)
The
calculation
of
the
percent
of
time
the
alarm
on
the
bag
leak
detection
system
sounded
during
each
6
month
reporting
period.
(f)
In
addition
to
the
information
required
by
§
60.7(
c),
the
percent
of
time
the
alarm
on
the
bag
leak
detection
system
sounded
during
each
6
month
reporting
period
shall
be
reported
to
the
Administrator
semi
annually.
7.
Section
60.271(
a)
is
amended
by
adding,
in
alphabetical
order,
definitions
for
``
Bag
leak
detection
system''
and
``
Operating
time''
as
follows:
§
60.271a
Definitions.
Bag
leak
detection
system
means
a
system
that
is
capable
of
continuously
monitoring
relative
particulate
matter
(dust)
loadings
in
the
exhaust
of
a
baghouse
to
detect
bag
leaks
and
other
conditions
that
result
in
increases
in
particulate
loadings.
A
bag
leak
detection
system
includes,
but
is
not
limited
to,
an
instrument
that
operates
on
triboelectric,
electrodynamic,
light
scattering,
light
transmittance,
or
other
effect
to
continuously
monitor
relative
particulate
matter
loadings.
*
*
*
*
*
Operating
time
means
the
period
of
time
in
hours
that
an
affected
source
is
in
operation
beginning
at
a
startup
and
ending
at
the
next
shutdown.
*
*
*
*
*
8.
Section
60.273a
is
amended
by
revising
paragraph
(c)
and
adding
new
paragraphs
(e),
(f),
(g),
and
(h)
to
read
as
follows:
§
60.273a
Emission
monitoring.
*
*
*
*
*
(c)
A
continuous
monitoring
system
for
the
measurement
of
the
opacity
of
emissions
discharged
into
the
atmosphere
from
the
control
device(
s)
is
not
required
on
any
modular,
multistack
negative
pressure
or
positivepressure
fabric
filter
if
observations
of
the
opacity
of
the
visible
emissions
from
the
control
device
are
performed
by
a
certified
visible
emission
observer;
or
on
any
single
stack
fabric
filter
if
visible
emissions
from
the
control
device
are
performed
by
a
certified
visible
emission
observer
and
the
owner
installs
and
continuously
operates
a
bag
leak
detection
system
according
to
paragraph
(e)
of
this
section.
Visible
emission
observations
shall
be
conducted
at
least
once
per
day
for
at
least
three
6
minute
periods
when
the
furnace
is
operating
in
the
melting
and
refining
period.
All
visible
emissions
observations
shall
be
conducted
in
accordance
with
Method
9.
If
visible
emissions
occur
from
more
than
one
point,
the
opacity
shall
be
recorded
for
any
points
where
visible
emissions
are
observed.
Where
it
is
possible
to
determine
that
a
number
of
visible
emission
sites
relate
to
only
one
incident
of
the
visible
emission,
only
one
set
of
three
6
minute
observations
will
be
required.
In
that
case,
the
Method
9
observations
must
be
made
for
the
site
of
highest
opacity
that
directly
relates
to
the
cause
(or
location)
of
visible
emissions
observed
during
a
single
incident.
Records
shall
be
maintained
of
any
6
minute
average
that
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Federal
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/
Vol.
67,
No.
200
/
Wednesday,
October
16,
2002
/
Proposed
Rules
is
in
excess
of
the
emission
limit
specified
in
§
60.272a(
a).
*
*
*
*
*
(e)
A
bag
leak
detection
system
must
be
installed
and
continuously
operated
on
all
single
stack
fabric
filters
if
the
owner
or
operator
elects
not
to
install
and
operate
a
continuous
opacity
monitoring
system
as
provided
for
under
paragraph
(c)
of
this
section.
In
addition,
the
owner
or
operator
shall
meet
the
visible
emissions
observation
requirements
in
paragraph
(c)
of
this
section.
The
bag
leak
detection
system
must
meet
the
specifications
and
requirements
of
paragraphs
(e)(
1)
through
(8)
of
this
section.
(1)
The
bag
leak
detection
system
must
be
certified
by
the
manufacturer
to
be
capable
of
detecting
particulate
matter
emissions
at
concentrations
of
10
milligrams
per
actual
cubic
meter
(0.0044
grains
per
actual
cubic
foot)
or
less.
(2)
The
bag
leak
detection
system
sensor
must
provide
output
of
relative
particulate
matter
loadings
and
the
owner
or
operator
shall
continuously
record
the
output
from
the
bag
leak
detection
system
using
electronic
or
other
means
(e.
g.,
using
a
strip
chart
recorder
or
a
data
logger.)
(3)
The
bag
leak
detection
system
must
be
equipped
with
an
alarm
system
that
will
sound
when
an
increase
in
relative
particulate
loading
is
detected
over
the
alarm
set
point
established
according
to
paragraph
(e)(
4)
of
this
section,
and
the
alarm
must
be
located
such
that
it
can
be
heard
by
the
appropriate
plant
personnel.
(4)
For
each
bag
leak
detection
system
required
by
paragraph
(e)
of
this
section,
the
owner
or
operator
shall
develop
and
submit,
to
the
Administrator
or
delegated
authority,
for
approval,
a
sitespecific
monitoring
plan
that
addresses
the
items
identified
in
paragraphs
(e)(
4)(
i)
through
(v)
of
this
section.
For
each
bag
leak
detection
system
that
operates
based
on
the
triboelectric
effect,
the
monitoring
plan
shall
be
consistent
with
the
recommendations
contained
in
the
U.
S.
Environmental
Protection
Agency
guidance
document
``
Fabric
Filter
Bag
Leak
Detection
Guidance''
(EPAÐ
454/
RÐ
98Ð
015).
The
owner
or
operator
shall
operate
and
maintain
the
bag
leak
detection
system
according
to
the
site
specific
monitoring
plan
at
all
times.
The
plan
shall
describe
the
following:
(i)
Installation
of
the
bag
leak
detector
system;
(ii)
Initial
and
periodic
adjustment
of
the
bag
leak
detector
system
including
how
the
alarm
set
point
will
be
established;
(iii)
Operation
of
the
bag
leak
detection
system
including
quality
assurance
procedures;
(iv)
How
the
bag
leak
detection
system
will
be
maintained
including
a
routine
maintenance
schedule
and
spare
parts
inventory
list;
and
(v)
How
the
bag
leak
detection
system
output
shall
be
recorded
and
stored.
(5)
The
initial
adjustment
of
the
system
shall,
at
a
minimum,
consist
of
establishing
the
baseline
output
by
adjusting
the
sensitivity
(range)
and
the
averaging
period
of
the
device,
and
establishing
the
alarm
set
points
and
the
alarm
delay
time
(if
applicable).
(6)
Following
initial
adjustment,
the
owner
or
operator
shall
not
adjust
the
averaging
period,
alarm
set
point,
or
alarm
delay
time
without
approval
from
the
Administrator
or
delegated
authority
except
as
provided
for
in
paragraphs
(e)(
6)(
i)
and
(ii)
of
this
section.
(i)
Once
per
quarter,
the
owner
or
operator
may
adjust
the
sensitivity
of
the
bag
leak
detection
system
to
account
for
seasonal
effects
including
temperature
and
humidity
according
to
the
procedures
identified
in
the
sitespecific
monitoring
plan
required
under
paragraph
(e)(
4)
of
this
section.
(ii)
If
opacities
greater
than
zero
percent
are
observed
over
four
consecutive
15
second
observations
during
the
daily
opacity
observations
required
under
paragraph
(c)
of
this
section
and
the
alarm
on
the
bag
leak
detection
system
does
not
sound,
the
owner
or
operator
shall
lower
the
alarm
set
point
on
the
bag
leak
detection
system
to
a
point
where
the
alarm
would
have
sounded
during
the
period
when
the
opacity
observations
were
made.
(7)
For
negative
pressure,
induced
air
baghouses,
and
positive
pressure
baghouses
that
are
discharged
to
the
atmosphere
through
a
stack,
the
bag
leak
detector
sensor
must
be
installed
downstream
of
the
baghouse
and
upstream
of
any
wet
scrubber.
(8)
Where
multiple
detectors
are
required,
the
system's
instrumentation
and
alarm
may
be
shared
among
detectors.
(f)
For
each
bag
leak
detection
system
installed
according
to
paragraph
(e)
of
this
section,
the
owner
or
operator
shall
initiate
procedures
to
determine
the
cause
of
all
alarms
within
30
minutes
of
an
alarm.
The
cause
of
the
alarm
must
be
alleviated
within
3
hours
of
the
time
the
alarm
occurred
by
taking
whatever
corrective
action(
s)
are
necessary.
If
additional
time
is
required
to
alleviate
the
cause
of
the
alarm,
the
owner
or
operator
shall
notify
the
Administrator
or
delegated
authority.
Corrective
actions
may
include,
but
are
not
limited
to,
the
following:
(1)
Inspecting
the
baghouse
for
air
leaks,
torn
or
broken
bags
or
filter
media,
or
any
other
condition
that
may
cause
an
increase
in
particulate
emissions;
(2)
Sealing
off
defective
bags
or
filter
media.
(3)
Replacing
defective
bags
or
filter
media,
or
otherwise
repairing
the
control
device;
(4)
Sealing
off
a
defective
baghouse
compartment.
(5)
Cleaning
the
bag
leak
detection
system
probe,
or
otherwise
repairing
the
bag
leak
detection
system;
and
(6)
Shutting
down
the
process
producing
the
particulate
emissions.
(g)
The
owner
or
operator
shall
maintain
each
baghouse
monitored
by
a
bag
leak
detection
system
such
that
the
alarm
on
the
bag
leak
detection
system
does
not
sound
for
more
than
3
percent
of
the
total
operating
time
in
a
6
month
reporting
period.
(h)
The
percentage
of
time
the
alarm
on
a
bag
leak
detection
system
sounds
shall
be
determined
according
to
paragraphs
(h)(
1)
through
(5)
of
this
section.
(1)
An
alarm
that
occurs
due
solely
to
a
malfunction
of
the
bag
leak
detection
system
shall
not
be
included
in
the
calculation.
(2)
An
alarm
that
occurs
during
startup,
shutdown,
or
malfunction
shall
not
be
included
in
the
calculation
if
the
owner
or
operator
follows
all
requirements
contained
in
§
60.11(
d).
(3)
For
each
alarm
where
the
owner
or
operator
initiates
procedures
to
determine
the
cause
of
an
alarm
within
1
hour
of
the
alarm,
1
hour
of
alarm
time
shall
be
counted.
(4)
For
each
alarm
where
the
owner
or
operator
does
not
initiate
procedures
to
determine
the
cause
of
the
alarm
within
1
hour
of
the
alarm,
alarm
time
will
be
counted
as
the
actual
amount
of
time
taken
by
the
owner
or
operator
to
initiate
procedures
to
determine
the
cause
of
the
alarm.
(5)
The
percentage
of
time
the
alarm
on
the
bag
leak
detection
system
sounds
shall
be
calculated
as
the
ratio
of
the
sum
of
alarm
times
to
the
total
operating
time
multiplied
by
100.
9.
Section
60.274a
is
amended
by
revising
the
first
sentence
of
paragraph
(b),
revising
the
first
sentence
of
paragraph
(c),
revising
the
first
sentence
of
paragraph
(d),
and
revising
paragraph
(e)
to
read
as
follows:
§
60.274a
Monitoring
of
operations.
*
*
*
*
*
(b)
Except
as
provided
under
paragraph
(e)
of
this
section,
the
owner
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Federal
Register
/
Vol.
67,
No.
200
/
Wednesday,
October
16,
2002
/
Proposed
Rules
or
operator
subject
to
the
provisions
of
this
subpart
shall
check
and
record
on
a
once
per
shift
basis
the
furnace
static
pressure
(if
DEC
system
is
in
use,
and
a
furnace
static
pressure
gauge
is
installed
according
to
paragraph
(f)
of
this
section)
and
either:
check
and
record
the
control
system
fan
motor
amperes
and
damper
position
on
a
onceper
shift
basis;
install
calibrate,
and
maintain
a
monitoring
device
that
continuously
records
the
volumetric
flow
rate
through
each
separately
ducted
hood;
or
install,
calibrate,
and
maintain
a
monitoring
device
that
continuously
records
the
volumetric
flow
rate
at
the
control
device
inlet
and
check
and
record
damper
positions
on
a
once
per
shift
basis.
*
*
*
(c)
When
the
owner
or
operator
of
an
affected
facility
is
required
to
demonstrate
compliance
with
the
standards
under
§
60.272a(
a)(
3)
and
at
any
other
time
the
Administrator
may
require
that
(under
section
114
of
the
CAA,
as
amended)
either:
the
control
system
fan
motor
amperes
and
all
damper
positions;
the
volumetric
flow
rate
through
each
separately
ducted
hood;
or
the
volumetric
flow
rate
at
the
control
device
inlet
and
all
damper
positions
shall
be
determined
during
all
periods
in
which
a
hood
is
operated
for
the
purpose
of
capturing
emissions
from
the
affected
facility
subject
to
paragraph
(b)
of
this
section.
*
*
*
(d)
Except
as
provided
under
paragraph
(e)
of
this
section,
the
owner
or
operator
shall
perform
monthly
operational
status
inspections
of
the
equipment
that
is
important
to
the
performance
of
the
total
capture
system
(i.
e.,
pressure
sensors,
dampers,
and
damper
switches).
*
*
*
(e)
The
owner
or
operator
may
petition
the
Administrator
to
approve
any
alternative
to
either
the
monitoring
requirements
specified
in
paragraph
(b)
of
this
section
or
the
monthly
operational
status
inspections
specified
in
paragraph
(d)
of
this
section
if
the
alternative
will
provide
a
continuous
record
of
operation
of
each
emission
capture
system.
*
*
*
*
*
10.
Section
60.276a
is
amended
by
adding
new
paragraphs
(h)
and
(i)
to
read
as
follows:
§
60.276a
Recordkeeping
and
reporting
requirements.
*
*
*
*
*
(h)
The
owner
or
operator
shall
maintain
the
following
records
for
each
bag
leak
detection
system
required
under
§
60.273a(
e):
(1)
Records
of
the
bag
leak
detection
system
output;
(2)
Records
of
bag
leak
detection
system
adjustments,
including
the
date
and
time
of
the
adjustment,
the
initial
bag
leak
detector
settings,
and
the
final
bag
leak
detector
settings;
(3)
An
identification
of
the
date
and
time
of
all
bag
leak
detection
system
alarms,
the
time
that
procedures
to
determine
the
cause
of
the
alarm
were
initiated,
if
procedures
were
initiated
within
30
minutes
of
the
alarm,
the
cause
of
the
alarm,
an
explanation
of
the
actions
taken,
the
date
and
time
the
cause
of
the
alarm
was
alleviated,
and
if
the
alarm
was
alleviated
within
3
hours
of
the
alarm;
and
(4)
The
calculation
of
the
percent
of
time
the
alarm
on
the
bag
leak
detection
system
sounded
during
each
6
month
reporting
period.
(i)
In
addition
to
the
information
required
by
§
60.7(
c),
the
percent
of
time
the
alarm
on
the
bag
leak
detection
system
sounded
during
each
6
month
reporting
period
shall
be
reported
to
the
Administrator
semi
annually.
[FR
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am]
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| epa | 2024-06-07T20:31:40.112321 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0049-0001/content.txt"
} |
EPA-HQ-OAR-2002-0052-0528 | Proposed Rule | "2002-12-20T05:00:00" | National Emission Standards for Hazardous Air Pollutants for Lime Manufacturing Plants; Proposed Rule | Friday,
December
20,
2002
Part
II
Environmental
Protection
Agency
40
CFR
Part
63
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Lime
Manufacturing
Plants;
Proposed
Rule
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Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[
Docket
ID
No.
OAR
2002
0052;
FRL
7418
1]
RIN
2060
AG72
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Lime
Manufacturing
Plants
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Proposed
rule.
SUMMARY:
This
action
proposes
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
the
lime
manufacturing
source
category.
The
lime
manufacturing
emission
units
regulated
would
include
lime
kilns,
lime
coolers,
and
various
types
of
materials
processing
operations
(
MPO).
The
EPA
has
identified
the
lime
manufacturing
industry
as
a
major
source
of
hazardous
air
pollutant
(
HAP)
emissions
including,
but
not
limited
to,
hydrogen
chloride
(
HCl),
antimony,
arsenic,
beryllium,
cadmium,
chromium,
lead,
manganese,
mercury,
nickel,
and
selenium.
Exposure
to
these
substances
has
been
demonstrated
to
cause
adverse
health
effects
such
as
cancer;
irritation
of
the
lung,
skin,
and
mucus
membranes;
effects
on
the
central
nervous
system;
and
kidney
damage.
The
proposed
standards
would
require
all
major
sources
subject
to
the
rule
to
meet
HAP
emission
standards
reflecting
the
application
of
maximum
achievable
control
technology
(
MACT).
Implementation
of
the
standards
as
proposed
would
reduce
non
volatile
metal
HAP
emissions
from
the
lime
manufacturing
industry
source
category
by
approximately
21
megagrams
per
year
(
Mg/
yr)
(
23
tons
per
year
(
tons/
yr))
and
would
reduce
emissions
of
particulate
matter
(
PM)
by
14,000
Mg/
yr
(
16,000
tons/
yr).
DATES:
Comments.
Submit
comments
on
or
before
February
18,
2003.
Public
Hearing.
If
anyone
contacts
the
EPA
requesting
to
speak
at
a
public
hearing
by
January
9,
2003,
a
public
hearing
will
be
held
on
January
21,
2003.
ADDRESSES:
Comments.
Comments
may
be
submitted
electronically,
by
mail,
by
facsimile,
or
through
hand
delivery/
courier.
Follow
the
detailed
instructions
as
provided
in
the
SUPPLEMENTARY
INFORMATION
section.
Public
Hearing.
If
a
public
hearing
is
held,
it
will
be
held
at
the
new
EPA
facility
complex
in
Research
Triangle
Park,
NC.
FOR
FURTHER
INFORMATION
CONTACT:
General
and
technical
information.
Joseph
P.
Wood,
P.
E.,
Minerals
and
Inorganic
Chemicals
Group,
Emissions
Standards
Division
(
C504
05),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711,
telephone
number
(
919)
541
5446,
electronic
mail
(
e
mail)
address
wood.
joe@
epa.
gov.
Methods,
sampling,
and
monitoring
information.
Michael
Toney,
Source
Measurement
Technology
Group,
Emission
Monitoring
and
Analysis
Division
(
D205
02),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711,
telephone
number
(
919)
541
5247,
e
mail
address
toney.
mike@
epa.
gov.
Economic
impacts
analysis.
Eric
Crump,
Innovative
Strategies
and
Economics
Group,
Air
Quality
Strategies
and
Standards
Division
(
C339
01),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711,
telephone
number
(
919)
541
4719,
e
mail
address
crump.
eric@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Regulated
Entities.
Categories
and
entities
potentially
regulated
by
this
action
include:
Category
NAICS
Examples
of
regulated
entities
32741
.......
Commercial
lime
manufacturing
plants.
33111
.......
Captive
lime
manufacturing
plants
at
iron
and
steel
mills.
3314
.........
Captive
lime
manufacturing
plants
at
nonferrous
metal
production
facilities.
327125
.....
Producers
of
dead
burned
dolomite
(
Non
clay
refractory
manufacturing).
This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
your
facility
is
regulated
by
this
action,
you
should
examine
the
applicability
criteria
in
§
63.7081
of
the
proposed
rule.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
technical
contact
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Docket.
The
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
OAR
2002
0052.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
Air
and
Radiation
Docket
and
Information
Center
(
Air
Docket)
in
the
EPA
Docket
Center,
(
EPA/
DC)
EPA
West,
Room
B102,
1301
Constitution
Ave.,
NW.,
Washington,
DC.
The
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
1744,
and
the
telephone
number
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Docket
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202)
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epa.
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edocket/
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publicly
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For
public
commenters,
it
is
important
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note
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EPA's
policy
is
that
public
comments,
whether
submitted
electronically
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in
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public
viewing
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electronic
public
docket
as
EPA
receives
them
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20,
2002
/
Proposed
Rules
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
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will
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The
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comments
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disks
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docket
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comments
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Where
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photograph
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public
docket
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Comments.
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facsimile,
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hand
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courier.
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late.''
EPA
is
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comments.
Comments
Submitted
Electronically.
If
you
submit
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EPA
recommends
that
you
include
your
name,
mailing
address,
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e
mail
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ROM
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submitter
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case
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cannot
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due
to
technical
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further
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will
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edit
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is
placed
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made
available
in
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electronic
public
docket.
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cannot
read
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contact
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clarification,
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may
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Your
use
of
EPA's
electronic
public
docket
to
submit
comments
to
EPA
electronically
is
EPA's
preferred
method
for
receiving
comments.
Go
directly
to
EPA
Dockets
at
http://
www.
epa.
gov/
edocket
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follow
the
online
instructions
for
submitting
comments.
Once
in
the
system,
select
``
search''
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then
key
in
Docket
ID
No.
OAR
2002
0052.
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system
is
an
``
anonymous
access''
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which
means
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will
not
know
your
identity,
e
mail
address,
or
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provide
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body
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your
comment.
Comments
may
be
sent
by
electronic
mail
(
e
mail)
to
a
and
r
docket@
epa.
gov,
Attention
Docket
ID
No.
OAR
2002
0052.
In
contrast
to
EPA's
electronic
public
docket,
EPA's
e
mail
system
is
not
an
``
anonymous
access''
system.
If
you
send
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e
mail
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e
mail
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automatically
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mail
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mail
addresses
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e
mail
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comment
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is
placed
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official
public
docket
and
made
available
in
EPA's
electronic
public
docket.
You
may
submit
comments
on
a
disk
or
CD
ROM
that
you
mail
to
the
mailing
address
identified
in
this
document.
These
electronic
submissions
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accepted
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Wordperfect
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Avoid
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use
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form
of
encryption.
Comments
Submitted
By
Mail.
Send
your
comments
(
in
duplicate,
if
possible)
to:
Lime
Manufacturing
NESHAP
Docket,
EPA
Docket
Center
(
Air
Docket),
U.
S.
EPA
West,
Mail
Code
6102T,
Room
B108,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
2002
0052.
Comments
Submitted
By
Hand
Delivery
or
Courier.
Deliver
your
comments
(
in
duplicate,
if
possible)
to:
EPA
Docket
Center,
U.
S.
EPA
West,
Mail
Code
6102T,
Room
B108,
1301
Constitution
Avenue,
NW.,
Washington,
DC
20004,
Attention
Docket
ID
No.
OAR
2002
0052.
Such
deliveries
are
only
accepted
during
the
Docket
Center's
normal
hours
of
operation
as
identified
in
this
document.
Comments
Submitted
By
Facsimile.
Fax
your
comments
to:
(
202)
566
1741,
Attention
Lime
Manufacturing
NESHAP
Docket,
Docket
ID
No.
OAR
2002
0052.
CBI.
Do
not
submit
information
that
you
consider
to
be
CBI
through
EPA's
electronic
public
docket
or
by
e
mail.
Send
or
deliver
information
identified
as
CBI
only
to
the
following
address:
OAQPS
Document
Control
Officer
(
C404
02),
U.
S.
EPA,
109
TW
Alexander
Drive,
Research
Triangle
Park,
NC
27709,
Attention
Joseph
Wood,
Docket
ID
No.
OAR
2002
0052.
You
may
claim
information
that
you
submit
to
EPA
as
CBI
by
marking
any
part
or
all
of
that
information
as
CBI
(
if
you
submit
CBI
on
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or
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ROM,
mark
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outside
of
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or
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ROM
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then
identify
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within
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disk
or
CD
ROM
the
specific
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that
is
CBI).
Information
so
marked
will
not
be
disclosed
except
in
accordance
with
procedures
set
forth
in
40
CFR
part
2.
Public
Hearing.
Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Mr.
Joseph
Wood,
Minerals
and
Inorganic
Chemicals
Group,
Emission
Standards
Division
(
C504
05),
Research
Triangle
Park,
NC
27711,
telephone
number
(
919)
541
5446,
at
least
2
days
in
advance
of
the
public
hearing.
Persons
interested
in
attending
the
public
hearing
must
also
call
Mr.
Joseph
Wood
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
these
proposed
emission
standards.
Worldwide
Web
(
WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
today's
proposal
will
also
be
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature,
a
copy
of
this
action
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(
919)
541
5384.
Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:
I.
Introduction
A.
What
Is
the
Purpose
of
the
Proposed
Rule?
B.
What
Is
the
Source
of
Authority
for
Development
of
NESHAP?
C.
What
Criteria
Are
Used
in
the
Development
of
NESHAP?
D.
How
Was
the
Proposed
Rule
Developed?
E.
What
Are
the
Health
Effects
of
the
HAP
Emitted
From
the
Lime
Manufacturing
Industry?
F.
What
Are
Some
Lime
Manufacturing
Industry
Characteristics?
G.
What
Are
the
Processes
and
Their
Emissions
at
a
Lime
Manufacturing
Plant?
II.
Summary
of
Proposed
Rule
A.
What
Lime
Manufacturing
Plants
Are
Subject
to
the
Proposed
Rule?
B.
What
Emission
Units
at
a
Lime
Manufacturing
Plant
Are
Included
Under
the
Definition
of
Affected
Source?
C.
What
Pollutants
Are
Regulated
By
the
Proposed
Rule?
D.
What
Are
the
Emission
Limits
and
Operating
Limits?
E.
When
Must
I
Comply
With
the
Proposed
Rule?
F.
How
Do
I
Demonstrate
Initial
Compliance
With
the
Proposed
Rule?
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2002
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Proposed
Rules
G.
How
Do
I
Continuously
or
Periodically
Demonstrate
Compliance
with
the
Proposed
Rule?
H.
How
Do
I
Determine
if
My
Lime
Manufacturing
Plant
Is
a
Major
Source
and
Thus
Subject
to
the
Proposed
Rule?
III.
Rationale
for
Proposed
Rule
A.
How
Did
We
Determine
the
Source
Category
to
Regulate?
B.
How
Did
We
Determine
the
Affected
Source?
C.
How
Did
We
Determine
Which
Pollutants
to
Regulate?
D.
How
Did
We
Determine
the
MACT
Floor
for
Emission
Units
at
Existing
Lime
Manufacturing
Plants?
E.
How
Did
We
Determine
the
MACT
Floor
For
Emission
Units
at
New
Lime
Manufacturing
Plants?
F.
What
Control
Options
Beyond
the
MACT
Floor
Did
We
Consider?
G.
How
Did
We
Select
the
Format
of
the
Proposed
Rule?
H.
How
Did
We
Select
the
Test
Methods
and
Monitoring
Requirements
for
Determining
Compliance
With
This
Proposed
Rule?
IV.
Summary
of
Environmental,
Energy
and
Economic
Impacts
A.
How
Many
Facilities
Are
Subject
To
the
Proposed
Rule?
B.
What
Are
the
Air
Quality
Impacts?
C.
What
Are
the
Water
Impacts?
D.
What
Are
the
Solid
Waste
Impacts?
E.
What
Are
the
Energy
Impacts?
F.
What
Are
the
Cost
Impacts?
G.
What
Are
the
Economic
Impacts?
V.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Executive
Order
13132,
Federalism
C.
Executive
Order
13084,
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Unfunded
Mandates
Reform
Act
of
1995
F.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
(
SBREFA)
of
1996,
5
U.
S.
C.
601
et
seq.
G.
Paperwork
Reduction
Act
H.
National
Technology
Transfer
and
Advancement
Act
of
1995
I.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution
or
Use
I.
Introduction
A.
What
Is
the
Purpose
of
the
Proposed
Rule?
The
purpose
of
the
proposed
rule
is
to
protect
the
public
health
by
reducing
emissions
of
HAP
from
lime
manufacturing
plants.
B.
What
Is
the
Source
of
Authority
for
Development
of
NESHAP?
Section
112
of
the
CAA
requires
us
to
list
categories
and
subcategories
of
major
sources
and
area
sources
of
HAP
and
to
establish
NESHAP
for
the
listed
source
categories
and
subcategories.
The
Lime
Manufacturing
category
of
major
sources
covered
by
today's
proposed
NESHAP
was
listed
on
July
16,
1992
(
57
FR
31576).
Major
sources
of
HAP
are
those
that
have
the
potential
to
emit
greater
than
10
tons/
yr
of
any
one
HAP
or
25
tons/
yr
of
any
combination
of
HAP.
C.
What
Criteria
Are
Used
in
the
Development
of
NESHAP?
Section
112
of
the
CAA
requires
that
we
establish
NESHAP
for
the
control
of
HAP
from
both
new
and
existing
major
sources.
The
CAA
requires
the
NESHAP
to
reflect
the
maximum
degree
of
reduction
in
emissions
of
HAP
that
is
achievable.
This
level
of
control
is
commonly
referred
to
as
the
maximum
achievable
control
technology
(
MACT).
The
MACT
floor
is
the
minimum
control
level
allowed
for
NESHAP
and
is
defined
under
section
112(
d)(
3)
of
the
CAA.
In
essence,
the
MACT
floor
ensures
that
the
standard
is
set
at
a
level
that
assures
that
all
major
sources
achieve
the
level
of
control
at
least
as
stringent
as
that
already
achieved
by
the
better
controlled
and
lower
emitting
sources
in
each
source
category
or
subcategory.
For
new
sources,
the
MACT
floor
cannot
be
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
bestcontrolled
similar
source.
The
MACT
standards
for
existing
sources
can
be
less
stringent
than
standards
for
new
sources,
but
they
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
bestperforming
12
percent
of
existing
sources
in
the
category
or
subcategory
(
or
the
best
performing
5
sources
for
categories
or
subcategories
with
fewer
than
30
sources).
In
developing
MACT,
we
also
consider
control
options
that
are
more
stringent
than
the
floor.
We
may
establish
standards
more
stringent
than
the
floor
based
on
the
consideration
of
cost
of
achieving
the
emissions
reductions,
any
health
and
environmental
impacts,
and
energy
requirements.
D.
How
Was
the
Proposed
Rule
Developed?
We
used
several
resources
to
develop
the
proposed
rule,
including
questionnaire
responses
from
industry,
emissions
test
data,
site
surveys
of
lime
manufacturing
facilities,
operating
and
new
source
review
permits,
and
permit
applications.
We
researched
the
relevant
technical
literature
and
existing
State
and
Federal
regulations
and
consulted
and
met
with
representatives
of
the
lime
manufacturing
industry,
State
and
local
representatives
of
air
pollution
agencies,
Federal
agency
representatives
(
e.
g.,
United
States
Geological
Survey)
and
emission
control
and
emissions
measurement
device
vendors
in
developing
the
proposed
rule.
We
also
conducted
an
extensive
emissions
test
program.
Industry
representatives
provided
emissions
test
data,
arranged
site
surveys
of
lime
manufacturing
plants,
participated
in
the
emissions
test
program,
reviewed
draft
questionnaires,
provided
information
about
their
manufacturing
processes
and
air
pollution
control
technologies,
and
identified
technical
and
regulatory
issues.
State
representatives
provided
existing
emissions
test
data,
copies
of
permits
and
other
information.
E.
What
Are
the
Health
Effects
of
the
HAP
Emitted
From
the
Lime
Manufacturing
Industry?
The
HAP
emitted
by
lime
manufacturing
facilities
include,
but
are
not
limited
to,
HCl,
antimony,
arsenic,
beryllium,
cadmium,
chromium,
lead,
manganese,
mercury,
nickel,
and
selenium.
Exposure
to
these
compounds
has
been
demonstrated
to
cause
adverse
health
effects
when
present
in
concentrations
higher
than
those
typically
found
in
ambient
air.
We
do
not
have
the
type
of
current
detailed
data
on
each
of
the
facilities
that
would
be
covered
by
the
proposed
NESHAP,
and
the
people
living
around
the
facilities,
that
would
be
necessary
to
conduct
an
analysis
to
determine
the
actual
population
exposures
to
the
HAP
emitted
from
these
facilities
and
the
potential
for
resultant
health
effects.
Therefore,
we
do
not
know
the
extent
to
which
the
adverse
health
effects
described
below
occur
in
the
populations
surrounding
these
facilities.
However,
to
the
extent
the
adverse
effects
do
occur,
the
proposed
rule
would
reduce
emissions
and
subsequent
exposures.
We
also
note
one
exception
to
this
statement,
namely
that
human
exposures
to
ambient
levels
of
HCl
resulting
from
lime
manufacturing
facilities'
emissions
were
estimated
by
industry
as
part
of
the
risk
assessment
they
conducted
for
purposes
of
demonstrating,
pursuant
to
section
112(
d)(
4)
of
the
CAA,
that
HCl
emissions
from
lime
kilns
are
below
the
threshold
level
of
adverse
effects,
with
an
ample
margin
of
safety.
The
HAP
that
would
be
controlled
with
the
proposed
rule
are
associated
with
a
variety
of
adverse
health
effects,
including
chronic
health
disorders
(
e.
g.,
irritation
of
the
lung,
skin,
and
mucus
membranes;
effects
on
the
central
nervous
system;
cancer;
and
damage
to
the
kidneys),
and
acute
health
disorders
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Proposed
Rules
(
e.
g.,
lung
irritation
and
congestion,
alimentary
effects
such
as
nausea
and
vomiting,
and
effects
on
the
kidney
and
central
nervous
system).
We
have
classified
three
of
the
HAP
arsenic,
chromium,
and
nickel
as
human
carcinogens
and
three
others
beryllium,
cadmium,
and
lead
as
probable
human
carcinogens.
F.
What
Are
Some
Lime
Manufacturing
Industry
Characteristics?
There
are
approximately
70
commercial
and
40
captive
lime
manufacturing
plants
in
the
U.
S.,
not
including
captive
lime
manufacturing
operations
at
pulp
and
paper
production
facilities.
About
30
of
the
captive
plants
in
the
U.
S.
produce
lime
that
is
used
in
the
beet
sugar
manufacturing
process,
but
captive
lime
manufacturing
plants
are
also
found
at
steel,
other
metals,
and
magnesia
production
facilities.
Lime
is
produced
in
about
35
States
and
Puerto
Rico
by
about
47
companies,
which
include
commercial
and
captive
producers
(
except
for
lime
manufacturing
plants
at
pulp
and
paper
production
facilities),
and
those
plants
which
produce
lime
hydrate
only.
G.
What
Are
the
Processes
and
Their
Emissions
at
a
Lime
Manufacturing
Plant?
There
are
many
synonyms
for
lime,
the
main
ones
being
quicklime
and
its
chemical
name,
calcium
oxide.
High
calcium
lime
consists
primarily
of
calcium
oxide,
and
dolomitic
lime
consists
of
both
calcium
and
magnesium
oxides.
Lime
is
produced
via
the
calcination
of
high
calcium
limestone
(
calcium
carbonate)
or
other
highly
calcareous
materials
such
as
aragonite,
chalk,
coral,
marble,
and
shell;
or
the
calcination
of
dolomitic
limestone.
Calcination
occurs
in
a
high
temperature
furnace
called
a
kiln,
where
lime
is
produced
by
heating
the
limestone
to
about
2000
°
F,
driving
off
carbon
dioxide
in
the
process.
Deadburned
dolomite
is
a
type
of
dolomitic
lime
produced
to
obtain
refractory
characteristics
in
the
lime.
The
kiln
is
the
heart
of
the
lime
manufacturing
plant,
where
various
fossil
fuels
(
such
as
coal,
petroleum
coke,
natural
gas,
and
fuel
oil)
are
combusted
to
produce
the
heat
needed
for
calcination.
There
are
five
different
types
of
kilns:
rotary,
vertical,
doubleshaft
vertical,
rotary
hearth,
and
fluidized
bed.
The
most
popular
is
the
rotary
kiln,
but
the
double
shaft
vertical
kiln
is
an
emerging
new
kiln
technology
gaining
in
acceptance
because
of
its
energy
efficiency.
Rotary
kilns
may
also
have
preheaters
associated
with
them
to
improve
energy
efficiency.
As
discussed
further
in
this
preamble,
additional
energy
efficiency
is
obtained
by
routing
exhaust
from
the
lime
cooler
to
the
kiln,
a
common
practice.
Emissions
from
lime
kilns
include,
but
are
not
limited
to,
metallic
HAP,
HCl,
PM,
sulfur
dioxide,
nitrogen
oxides,
and
carbon
dioxide.
These
emissions
predominately
originate
from
compounds
in
the
limestone
feed
material
and
fuels
(
e.
g.,
metals,
sulfur,
chlorine)
and
are
formed
from
the
combustion
of
fuels
and
the
heating
of
feed
material
in
the
kiln.
All
types
of
kilns
use
external
equipment
to
cool
the
lime
product,
except
vertical
(
including
double
shaft)
kilns,
where
the
cooling
zone
is
part
of
the
kiln.
Ambient
air
is
most
often
used
to
cool
the
lime
(
although
a
few
use
water
as
the
heat
transfer
medium),
and
typically
all
of
the
heated
air
stream
exiting
the
cooler
goes
to
the
kiln
to
be
used
as
combustion
air
for
the
kiln.
The
exception
to
this
is
the
grate
cooler,
where
more
airflow
is
generated
than
is
needed
for
kiln
combustion,
and
consequently
a
portion
(
about
40
percent)
of
the
grate
cooler
exhaust
is
vented
to
the
atmosphere.
We
estimate
that
there
are
about
five
to
ten
kilns
in
the
U.
S.
that
use
grate
coolers.
The
emissions
from
grate
coolers
include
the
lime
dust
(
PM)
and
the
trace
metallic
HAP
found
in
the
lime
dust.
Lime
manufacturing
plants
may
also
produce
hydrated
lime
(
also
called
calcium
hydroxide)
from
some
of
the
calcium
oxide
(
or
dolomitic
lime)
produced.
Hydrated
lime
is
produced
in
a
hydrator
via
the
chemical
reaction
of
calcium
oxide
(
or
magnesium
oxide)
and
water.
The
hydration
process
is
exothermic,
and
part
of
the
water
in
the
reaction
chamber
is
converted
to
steam.
A
wet
scrubber
is
integrated
with
the
hydrator
to
capture
the
lime
(
calcium
oxide
and
calcium
hydroxide)
particles
carried
in
the
gas
steam,
with
the
scrubber
water
recycled
back
to
the
hydration
chamber.
The
emissions
from
the
hydrator
are
the
PM
comprised
of
lime
and
hydrated
lime.
Operations
that
prepare
the
feed
materials
and
fuels
for
the
kiln
and
process
the
lime
product
for
shipment
or
further
on
site
use
are
found
throughout
a
lime
manufacturing
plant.
The
equipment
includes
grinding
mills,
crushers,
storage
bins,
conveying
systems
(
such
as
bucket
elevator,
belt
conveyors),
bagging
systems,
bulk
loading
or
unloading
systems,
and
screening
operations.
The
emissions
from
these
operations
include
limestone
and
lime
dust
(
PM)
and
the
trace
metallic
HAP
found
in
the
dust.
II.
Summary
of
Proposed
Rule
A.
What
Lime
Manufacturing
Plants
Are
Subject
to
the
Proposed
Rule?
The
proposed
rule
would
regulate
HAP
emissions
from
all
new
and
existing
lime
manufacturing
plants
that
are
major
sources,
co
located
with
major
sources,
or
are
part
of
major
sources.
However,
lime
manufacturing
plants
located
at
pulp
and
paper
mills
or
at
beet
sugar
factories
would
not
be
subject
to
the
proposed
rule.
Other
captive
lime
manufacturing
plants,
such
as
(
but
not
limited
to)
those
at
steel
mills
and
magnesia
production
facilities,
would
be
subject
to
the
proposed
rule.
We
define
a
lime
manufacturing
plant
as
any
plant
which
uses
a
lime
kiln
to
produce
lime
product
from
limestone
or
other
calcareous
material
by
calcination.
Lime
product
means
the
product
of
the
lime
kiln
calcination
process
including
calcitic
lime,
dolomitic
lime,
and
deadburned
dolomite.
B.
What
Emission
Units
at
a
Lime
Manufacturing
Plant
Are
Included
Under
the
Definition
of
Affected
Source?
The
proposed
rule
would
include
the
following
emission
units
under
the
definition
of
affected
source:
Lime
kilns
and
coolers,
and
MPO
associated
with
limestone
feed
preparation
(
beginning
with
the
raw
material
storage
bin).
The
individual
types
of
MPO
that
would
be
included
under
the
definition
of
affected
source
are
grinding
mills,
raw
material
storage
bins,
conveying
system
transfer
points,
bulk
loading
or
unloading
systems,
screening
operations,
bucket
elevators,
and
belt
conveyors
if
they
follow
the
raw
material
storage
bin
in
the
sequence
of
MPO.
The
MPO
associated
with
lime
products
(
such
as
quicklime
and
hydrated
lime),
lime
kiln
dust
handling,
quarry
or
mining
operations,
and
fuels
would
not
be
subject
to
today's
proposed
rule.
The
MPO
are
further
distinguished
in
the
proposed
rule
as
follows:
(
1)
Whether
their
emissions
are
vented
through
a
stack,
(
2)
whether
their
emissions
are
fugitive
emissions,
(
3)
whether
their
emissions
are
vented
through
a
stack
with
some
fugitive
emissions
from
the
partial
enclosure,
and/
or
(
4)
whether
the
source
is
enclosed
in
a
building.
Finally,
lime
hydrators
would
not
be
included
under
the
definition
of
affected
source
under
the
proposed
NESHAP.
C.
What
Pollutants
Are
Regulated
by
the
Proposed
Rule?
The
proposed
rule
would
establish
PM
emission
limits
for
lime
kilns,
coolers,
and
MPO
with
stacks.
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20,
2002
/
Proposed
Rules
Particulate
matter
would
be
measured
solely
as
a
surrogate
for
the
non
volatile
and
semi
volatile
metal
HAP.
(
Particulate
matter
of
course
is
not
itself
a
HAP,
but
is
a
typical
and
permissible
surrogate
for
HAP
metals.
See
National
Lime
Ass'n
v.
EPA,
233
F.
3d
625,
637
40
(
D.
C.
Cir.,
2000).)
The
proposed
rule
also
would
regulate
opacity
or
visible
emissions
from
most
of
the
MPO,
with
opacity
also
serving
as
a
surrogate
for
non
volatile
and
semi
volatile
HAP
metals.
D.
What
Are
the
Emission
Limits
and
Operating
Limits?
1.
Emission
Limits
The
PM
emission
limit
for
all
of
the
kilns
and
coolers
at
an
existing
lime
manufacturing
plant
would
be
0.12
pounds
(
lb)
PM
per
ton
(
0.06
kilogram
(
kg)
per
Mg)
of
stone
feed.
The
PM
emission
limit
for
all
of
the
kilns
and
lime
coolers
at
a
new
lime
manufacturing
plant
would
be
0.10
lb/
ton
of
stone
feed.
These
emission
limits
would
apply
to
the
combined
emissions
of
all
the
kilns
and
coolers
(
assuming
the
cooler(
s)
has
a
separate
exhaust
vent
to
the
atmosphere)
at
the
lime
manufacturing
plant.
In
other
words,
the
sum
of
the
PM
emission
rates
from
all
of
the
kilns
and
coolers
at
the
existing
lime
manufacturing
plant,
divided
by
the
sum
of
the
production
rates
of
the
kilns
at
the
existing
lime
manufacturing
plant,
would
be
used
to
determine
compliance
with
the
emission
limit
for
kilns
and
coolers
at
an
existing
lime
manufacturing
plant.
Similarly,
the
sum
of
the
PM
emission
rates
from
all
of
the
kilns
and
coolers,
divided
by
the
sum
of
the
production
of
the
kilns
at
a
new
plant,
would
be
used
to
determine
compliance
with
the
emission
limit
for
kilns
and
coolers
at
a
new
lime
manufacturing
plant.
Emissions
from
MPO
that
are
vented
through
a
stack
would
be
subject
to
a
standard
of
0.05
grams
PM
per
dry
standard
cubic
meter
(
g/
dscm)
and
7
percent
opacity.
Stack
emissions
from
MPO
that
are
controlled
by
wet
scrubbers
would
be
subject
to
the
0.05
grams
PM
per
dry
standard
cubic
meter
PM
limit
but
not
subject
to
the
opacity
limit.
Fugitive
emissions
from
MPO
would
be
subject
to
a
10
percent
opacity
limit.
We
are
proposing
that
for
each
building
enclosing
any
materials
processing
operation,
each
of
the
affected
MPO
in
the
building
would
have
to
comply
individually
with
the
applicable
PM
and
opacity
emission
limitations
discussed
above.
Otherwise,
we
propose
that
there
must
be
no
visible
emissions
from
the
building,
except
from
a
vent,
and
the
building's
vent
emissions
must
not
exceed
0.05
grams
PM
per
dry
standard
cubic
meter
and
7
percent
opacity.
We
are
proposing
that
for
each
fabric
filter
(
FF)
that
controls
emissions
from
only
an
individual,
enclosed
storage
bin,
the
opacity
emissions
must
not
exceed
7
percent.
For
each
set
of
multiple
storage
bins
with
combined
stack
emissions,
emissions
must
not
exceed
0.05
grams
PM
per
dry
standard
cubic
meter
and
7
percent
opacity.
2.
Operating
Limits
For
lime
kilns
that
use
a
wet
scrubber
PM
control
device,
you
would
be
required
to
maintain
the
3
hour
rolling
average
gas
stream
pressure
drop
across
the
scrubber
and
the
3
hour
rolling
average
scrubber
liquid
flow
rate
equal
to
or
above
the
levels
for
the
parameters
that
were
established
during
the
PM
performance
test.
For
lime
kilns
that
use
a
FF
PM
control
device,
you
would
be
required
to
maintain
and
operate
the
FF
such
that
the
bag
leak
detection
system
(
BLDS)
alarm
is
not
activated
and
alarm
condition
does
not
exist
for
more
than
5
percent
of
the
operating
time
in
each
6
month
period.
The
BLDS
must
be
certified
by
the
manufacturer
to
be
capable
of
detecting
PM
emissions
at
concentrations
of
10
milligrams
per
actual
cubic
meter
(
0.0044
grains
per
actual
cubic
foot)
or
less.
For
lime
kilns
that
use
an
electrostatic
precipitator
(
ESP)
PM
control
device,
you
would
be
required
to
maintain
the
3
hour
rolling
average
current
and
voltage
input
to
each
electrical
field
of
the
ESP
equal
to
or
above
the
operating
limits
for
these
parameters
that
were
established
during
the
PM
performance
test.
In
lieu
of
complying
with
these
ESP
operating
parameters,
we
are
giving
sources
the
option
of
monitoring
PM
levels
with
a
PM
detector
in
a
manner
similar
to
the
procedures
for
monitoring
PM
from
a
FF
using
a
BLDS.
You
would
need
to
maintain
and
operate
the
ESP
such
that
the
PM
detector
alarm
is
not
activated,
and
alarm
condition
does
not
exist
for
more
than
5
percent
of
the
operating
time
in
each
6
month
period.
In
lieu
of
using
a
bag
leak
detector,
PM
detector,
or
monitoring
ESP
operating
parameters
for
lime
kilns
with
a
FF
or
ESP
control
device,
we
are
providing
the
option
of
monitoring
opacity
(
as
an
operating
limit)
with
a
continuous
opacity
monitoring
system
(
COMS).
Sources
that
choose
to
use
a
COMS
would
be
required
to
install
and
operate
the
COMS
in
accordance
with
Performance
Specification
1
(
PS
1),
40
CFR
part
60,
Appendix
B,
and
maintain
the
opacity
level
of
the
lime
kiln
exhaust
at
or
below
15
percent
for
each
6
minute
block
period.
For
MPO
subject
to
a
PM
emission
limit
and
controlled
by
a
wet
scrubber,
you
would
be
required
to
collect
and
record
the
exhaust
gas
stream
pressure
drop
across
the
scrubber
and
the
scrubber
liquid
flow
rate
during
the
PM
performance
test.
You
would
be
required
to
maintain
the
3
hour
rolling
average
gas
stream
pressure
drop
across
the
scrubber
and
the
3
hour
rolling
average
scrubber
liquid
flow
rate
equal
to
or
above
the
levels
for
the
parameters
that
were
established
during
the
PM
performance
test.
You
would
be
required
to
prepare
a
written
operations,
maintenance,
and
monitoring
plan
to
cover
all
affected
emission
units.
The
plan
would
include
procedures
for
proper
operation
and
maintenance
of
each
emission
unit
and
its
air
pollution
control
device(
s);
procedures
for
monitoring
and
proper
operation
of
monitoring
systems
in
order
to
meet
the
emission
limits
and
operating
limits;
and
standard
procedures
for
the
use
of
a
BLDS
and
PM
detector,
and
any
corrective
actions
to
be
taken
when
operating
limits
are
deviated
from,
or
when
required
in
using
a
PM
detector
or
BLDS.
E.
When
Must
I
Comply
With
the
Proposed
Rule?
The
compliance
date
for
existing
lime
manufacturing
plants
would
be
[
Date
3
years
from
the
date
a
final
rule
is
published
in
the
Federal
Register].
(
Three
years
may
be
needed
to
install
new,
or
retrofit
existing,
air
pollution
control
equipment.)
The
date
the
final
rule
is
published
in
the
Federal
Register
is
called
the
effective
date
of
the
rule.
We
are
proposing
that
emission
units
at
a
new
lime
manufacturing
plant
(
i.
e.,
emission
units
for
which
construction
or
reconstruction
commences
after
today's
date)
must
be
in
compliance
upon
initial
startup
or
the
effective
date
of
the
rule,
whichever
is
later.
F.
How
Do
I
Demonstrate
Initial
Compliance
With
the
Proposed
Rule?
1.
Kiln
and
Coolers
For
the
kiln
and
cooler
PM
emission
limit,
we
are
proposing
that
you
must
conduct
a
PM
emissions
test
on
the
exhaust
of
each
kiln
at
the
lime
manufacturing
plant
and
measure
the
stone
feed
rate
to
each
kiln
during
the
test.
The
sum
of
the
emissions
from
all
the
kilns
at
the
existing
lime
manufacturing
plant,
divided
by
the
sum
of
the
average
stone
feed
rates
to
each
kiln
at
the
existing
lime
manufacturing
plant,
must
not
exceed
the
emission
limit
of
0.12
lb
PM/
ton
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2002
/
Proposed
Rules
stone
feed;
similarly,
the
sum
of
the
emissions
from
all
the
kilns
at
a
new
lime
manufacturing
plant,
divided
by
the
sum
of
the
average
stone
feed
rates
to
each
kiln
at
the
new
lime
manufacturing
plant,
must
not
exceed
the
emission
limit
of
0.10
lb
PM/
ton
stone
feed.
If
you
have
a
lime
cooler(
s)
that
has
a
separate
exhaust
to
the
atmosphere,
you
would
be
required
to
conduct
a
PM
test
on
the
cooler's
exhaust
concurrently
with
the
kiln
PM
test.
Then
the
sum
of
the
emissions
from
all
the
kilns
and
coolers
at
the
existing
lime
manufacturing
plant,
divided
by
the
sum
of
the
average
stone
feed
rates
to
each
kiln
at
the
existing
plant,
must
not
exceed
the
emission
limit
of
0.12
lb
PM/
ton
stone
feed
(
or
0.10
lb/
ton
of
stone
feed
for
kilns/
coolers
at
new
lime
manufacturing
plants).
For
kilns
with
an
ESP
or
wet
scrubber,
you
would
be
required
to
collect
and
record
the
applicable
operating
parameters
during
the
PM
performance
test
and
then
establish
the
operating
limits
based
on
those
data.
2.
Materials
Processing
Operations
For
the
MPO
with
stacks
and
subject
to
PM
emission
limits,
you
would
be
required
to
conduct
a
PM
emissions
test
on
each
stack
exhaust,
and
the
stack
emissions
must
not
exceed
the
emission
limit
of
0.05
g/
dscm.
For
the
MPO
with
stack
opacity
limits,
you
would
be
required
to
conduct
a
3
hour
Method
9
test
on
the
exhaust,
and
each
of
the
30
consecutive,
6
minute
opacity
averages
must
not
exceed
7
percent.
The
MPO
that
are
controlled
by
wet
scrubbers
would
not
have
an
opacity
limit,
but
you
would
be
required
to
collect
and
record
the
wet
scrubber
operating
parameters
during
the
PM
performance
test
and
then
establish
the
applicable
operating
limits
based
on
those
data.
For
MPO
with
fugitive
emissions,
you
would
be
required
to
conduct
a
Method
9
test,
and
each
of
the
consecutive
6
minute
opacity
averages
must
not
exceed
the
applicable
opacity
limit.
These
Method
9
tests
are
for
3
hours,
but
the
test
duration
may
be
reduced
to
1
hour
if
certain
criteria
are
met.
Lastly,
Method
9
tests
or
visible
emissions
checks
may
be
performed
on
MPO
inside
of
buildings,
but
additional
lighting,
improved
access
to
equipment,
and
temporary
installation
of
contrasting
backgrounds
may
be
needed.
For
additional
guidance,
see
page
116
from
the
``
Regulatory
and
Inspection
Manual
for
Nonmetallic
Minerals
Processing
Plants,''
EPA
report
305
B
97
008,
November
1997.
G.
How
Do
I
Continuously
or
Periodically
Demonstrate
Compliance
With
the
Proposed
Rule?
1.
General
You
would
be
required
to
install,
operate,
and
maintain
each
required
continuous
parameter
monitoring
system
(
CPMS)
such
that
the
CPMS
completes
a
minimum
of
one
cycle
of
operation
for
each
successive
15
minute
period.
The
CPMS
would
be
required
to
have
valid
data
from
at
least
three
of
four
equally
spaced
data
values
for
that
hour
from
a
CPMS
that
is
not
out
of
control
according
to
your
operation,
maintenance,
and
monitoring
plan.
To
calculate
the
average
for
each
3
hour
averaging
period,
you
must
have
at
least
two
of
three
of
the
hourly
averages
for
that
period
using
only
hourly
average
values
that
are
based
on
valid
data
(
i.
e.,
not
from
out
of
control
periods).
The
3
hour
rolling
average
value
for
each
operating
parameter
would
be
calculated
as
the
average
of
each
set
of
three
successive
1
hour
average
values.
The
3
hour
rolling
average
would
be
updated
each
hour.
Thus
the
3
hour
average
rolls
at
1
hour
increments,
i.
e.,
once
a
1
hour
average
has
been
determined
based
on
at
least
four
successive
available
15
minute
averages,
a
new
1
hour
average
would
be
determined
based
on
the
next
four
successive
available
15
minute
averages.
You
would
be
required
to
develop
and
implement
a
written
startup,
shutdown,
and
malfunction
plan
(
SSMP)
according
to
the
general
provisions
in
40
CFR
63.6(
e)(
3).
2.
Kilns
and
Coolers
For
kilns
controlled
by
a
wet
scrubber,
you
would
be
required
to
maintain
the
3
hour
rolling
average
of
the
exhaust
gas
stream
pressure
drop
across
the
wet
scrubber
greater
than
or
equal
to
the
pressure
drop
operating
limit
established
during
the
most
recent
PM
performance
test.
You
would
be
required
to
also
maintain
the
3
hour
rolling
average
of
the
scrubbing
liquid
flow
rate
greater
than
or
equal
to
the
flow
rate
operating
limit
established
during
the
most
recent
performance
test.
For
kilns
controlled
by
an
ESP,
if
you
choose
to
monitor
ESP
operating
parameters
rather
than
use
a
PM
detector
or
a
COMS,
you
would
be
required
to
maintain
the
3
hour
rolling
average
current
and
voltage
input
to
each
electrical
field
of
the
ESP
greater
than
or
equal
to
the
average
current
and
voltage
input
to
each
field
of
the
ESP
established
during
the
most
recent
performance
test.
Sources
opting
to
monitor
PM
emissions
from
an
ESP
with
a
PM
detector
in
lieu
of
monitoring
ESP
parameters
or
opacity
would
be
required
to
maintain
and
operate
the
ESP
such
that
the
PM
detector
alarm
is
not
activated,
and
alarm
condition
does
not
exist
for
more
than
5
percent
of
the
operating
time
in
a
6
month
period.
Each
time
the
alarm
sounds
and
the
owner
or
operator
initiates
corrective
actions
(
per
the
operations
and
maintenance
plan)
within
1
hour
of
the
alarm,
1
hour
of
alarm
time
will
be
counted.
If
inspection
of
the
ESP
demonstrates
that
no
corrective
actions
are
necessary,
no
alarm
time
will
be
counted.
The
sensor
on
the
PM
detection
system
would
provide
an
output
of
relative
PM
emissions.
The
PM
detection
system
would
have
an
alarm
that
would
sound
automatically
when
it
detects
an
increase
in
relative
PM
emissions
greater
than
a
preset
level.
The
PM
detection
systems
would
be
required
to
be
installed,
operated,
adjusted,
and
maintained
so
that
they
follow
the
manufacturer's
written
specifications
and
recommendations.
For
kilns
and
lime
coolers
(
if
the
cooler
has
a
separate
exhaust
to
the
atmosphere)
controlled
by
a
FF
and
monitored
with
a
BLDS,
you
would
be
required
to
maintain
and
operate
the
FF
such
that
the
BLDS
alarm
is
not
activated,
and
alarm
condition
does
not
exist
for
more
than
5
percent
of
the
operating
time
in
a
6
month
period.
Each
time
the
alarm
sounds
and
the
owner
or
operator
initiates
corrective
actions
(
per
the
operations,
maintenance,
and
monitoring
plan)
within
1
hour
of
the
alarm,
1
hour
of
alarm
time
will
be
counted.
If
inspection
of
the
FF
demonstrates
that
no
corrective
actions
are
necessary,
no
alarm
time
will
be
counted.
The
sensor
on
the
BLDS
would
be
required
to
provide
an
output
of
relative
PM
emissions.
The
BLDS
would
be
required
to
have
an
alarm
that
will
sound
automatically
when
it
detects
an
increase
in
relative
PM
emissions
greater
than
a
preset
level.
The
BLDS
would
be
required
to
be
installed,
operated,
adjusted,
and
maintained
so
that
they
follow
the
manufacturer's
written
specifications
and
recommendations.
Standard
operating
procedures
for
the
BLDS
and
PM
detection
systems
would
need
to
be
incorporated
into
the
operations,
maintenance,
and
monitoring
plan.
We
recommend
that
for
electrodynamic
(
or
other
similar
technology)
BLDS,
the
standard
operating
procedures
include
concepts
from
EPA's
``
Fabric
Filter
Bag
Leak
Detection
Guidance''
(
EPA
454/
R
98
015,
September
1997).
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/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
document
may
be
found
on
the
world
wide
web
at
www.
epa.
gov/
ttn/
emc.
For
kilns
and
lime
coolers
monitored
with
a
COMS,
you
would
be
required
to
maintain
each
6
minute
block
average
opacity
level
at
or
below
15
percent
opacity.
The
COMS
must
be
installed
and
operated
in
accordance
with
Performance
Specification
1
(
PS
1),
40
CFR
part
60,
Appendix
B.
3.
Materials
Processing
Operations
For
stack
emissions
from
MPO
which
are
controlled
by
a
wet
scrubber,
you
would
be
required
to
maintain
the
3
hour
rolling
average
exhaust
gas
stream
pressure
drop
across
the
wet
scrubber
greater
than
or
equal
to
the
pressure
drop
operating
limit
established
during
the
most
recent
PM
performance
test.
You
would
be
required
to
also
maintain
the
3
hour
rolling
average
scrubbing
liquid
flow
rate
greater
than
or
equal
to
the
flow
rate
operating
limit
established
during
the
most
recent
performance
test.
For
MPO
subject
to
opacity
limitations
and
which
do
not
use
a
wet
scrubber
control
device,
you
would
be
required
to
periodically
demonstrate
compliance
as
follows.
You
would
be
required
to
conduct
a
monthly
1
minute
visible
emissions
check
of
each
emissions
unit
under
the
affected
source
definition.
If
no
visible
emissions
are
observed
in
six
consecutive
monthly
tests
for
any
emission
unit,
you
may
decrease
the
frequency
of
testing
from
monthly
to
semiannually
for
that
emissions
unit.
If
visible
emissions
are
observed
during
any
semiannual
test,
you
would
be
required
to
resume
testing
of
that
emissions
unit
on
a
monthly
basis
and
maintain
that
schedule
until
no
visible
emissions
are
observed
in
six
consecutive
monthly
tests.
If
no
visible
emissions
are
observed
during
the
semiannual
test
for
any
emissions
unit,
you
may
decrease
the
frequency
of
testing
from
semiannually
to
annually
for
that
emissions
unit.
If
visible
emissions
are
observed
during
any
annual
test,
you
would
be
required
to
resume
visible
emissions
testing
of
that
emissions
unit
on
a
monthly
basis
and
maintain
that
schedule
until
no
visible
emissions
are
observed
in
six
consecutive
monthly
tests.
If
visible
emissions
are
observed
during
any
visible
emissions
check,
you
would
be
required
to
conduct
a
6
minute
test
of
opacity
in
accordance
with
Method
9
of
appendix
A
to
part
60
of
this
chapter.
The
Method
9
test
would
be
required
to
begin
within
1
hour
of
any
observation
of
visible
emissions,
and
the
6
minute
opacity
reading
would
be
required
to
not
exceed
the
applicable
opacity
limit.
We
request
comment
on
using
more
frequent
visible
emissions
checks
for
MPO,
such
as
going
from
monthly
to
quarterly,
and
then
continuing
with
semiannual
checks.
H.
How
Do
I
Determine
if
My
Lime
Manufacturing
Plant
Is
a
Major
Source
and
Thus
Subject
to
the
Proposed
Rule?
The
proposed
rule
would
apply
to
lime
manufacturing
plants
that
are
major
sources,
co
located
with
major
sources,
or
are
part
of
major
sources.
Each
lime
facility
owner/
operator
would
need
to
determine
whether
its
plant
is
a
major
or
area
source,
since
this
determines
whether
the
lime
manufacturing
plant
would
be
an
affected
source
under
the
proposed
rule.
Section
112
of
the
CAA
defines
a
major
source
as
a
``
stationary
source
or
group
of
stationary
sources
located
within
a
contiguous
area
and
under
common
control
that
emits
or
has
the
potential
to
emit
considering
controls,
in
the
aggregate,
10
tons/
yr
or
more
of
any
HAP
or
25
tons/
yr
or
more
of
any
combination
of
HAP.''
This
definition
may
be
interpreted
to
imply
that
the
CAA
requires
an
estimate
of
the
facility's
potential
to
emit
all
HAP
from
all
emission
sources
in
making
a
determination
of
whether
the
source
is
major
or
area.
However,
based
on
our
data
analysis,
HCl
is
most
likely
the
HAP
that
would
account
for
the
largest
quantity
of
HAP
emissions
from
a
lime
manufacturing
plant.
Although
lime
manufacturing
plants
emit
HAP
metals
from
most
of
the
emission
units
at
the
plant
site
and
organic
HAP
from
the
kiln,
our
analysis
indicates
that
most
likely
the
metal
and
organic
HAP
emissions
would
each
be
below
the
10/
25
tons/
yr
criteria.
One
potential
approach
to
estimating
HAP
metals
emissions
from
a
lime
manufacturing
plant
is
to
require
measurement
of
the
PM
emissions
from
all
of
the
emission
units
at
the
plant
and
then
allow
the
use
of
a
ratio
(
which
we
would
specify
in
the
final
rule)
of
HAP
metals
to
PM
to
calculate
the
metals
emissions.
We
request
comment
on
this
approach
to
estimating
HAP
metals
emissions.
And
although
we
are
not
proposing
to
require
sources
to
test
for
all
HAP
to
make
a
determination
of
whether
the
lime
manufacturing
plant
is
a
major
or
area
source,
we
do
request
comment
on
whether
emissions
testing
of
metal
and/
or
organic
HAP
should
be
required
for
an
owner
or
operator
to
claim
that
its
lime
manufacturing
plant
is
an
area
source.
We
are
proposing,
however,
to
require
that
a
source
measure
HCl
emissions
from
the
kiln(
s)
in
order
for
it
to
claim
it
is
an
area
source
(
provided
HCl
is
emitted
at
less
than
10
tons/
yr).
Due
to
the
known
problems
with
EPA
Method
26
(
which
may
have
positive
biases
attributable
to
chloride
salts
rather
than
to
HCl,
and
negative
biases
due
to
condensation
and
removal
of
HCl
on
the
filter
and/
or
in
the
sampling
probe),
we
have
decided
that
Methods
26
and
26A
may
not
be
used
to
measure
HCl
in
the
determination
whether
the
source
is
an
area
source.
We,
in
fact,
adopted
this
same
approach
in
the
final
NESHAP
for
the
portland
cement
industry.
See
40
CFR
part
63,
subpart
LLL,
and
64
FR
31907
and
31920
(
June
14,
1998).
In
addition,
we
worked
with
the
American
Society
of
Testing
and
Materials
(
ASTM),
in
conjunction
with
the
National
Lime
Association
(
NLA),
to
develop
an
impinger
based
method
for
the
measurement
of
HCl
based
on
Method
26
but
which
includes
changes
to
the
method
to
overcome
the
aforementioned
biases.
This
ASTM
HCl
impinger
based
method
has
been
demonstrated
on
lime
kilns
and
has
been
designated
as
ASTM
Test
Method
D
6735
01.
We
approve
of
this
method,
and
we
propose
to
allow
owners/
operators
to
use
it
to
measure
HCl
from
lime
kilns
to
determine
whether
their
lime
manufacturing
plant
is
a
major
or
area
source.
But
because
it
is
very
important
to
obtain
an
accurate
measurement
of
HCl
emissions,
we
are
proposing
to
require
the
paired
train
option
under
section
11.2.6
of
the
method,
and
we
are
also
proposing
to
require
the
post
test
analyte
spike
option
under
section
11.2.7
of
the
method.
Although
we
believe
these
additional
quality
assurance
procedures
are
critical
to
obtain
an
accurate
measurement
of
HCl,
we
seek
comment
on
the
appropriateness
of
requiring
them.
We
attempted
to
utilize
proposed
EPA
Method
322
(
based
on
gas
filter
correlation
infrared
spectroscopy)
to
gather
HCl
data
from
lime
kilns
and
encountered
technical
problems.
These
problems
included
inadequate
data
availability,
spike
recovery,
and
response
time,
which
led
to
our
decision
in
the
promulgation
of
the
NESHAP
for
the
portland
cement
industry
to
not
finalize
EPA
Method
322.
Today,
we
are
affirming
that
decision
and
propose
that
Method
322
may
not
be
used
to
measure
HCl
in
the
determination
whether
a
lime
manufacturing
plant
is
an
area
source.
Based
on
the
aforementioned
difficulties
with
Method
26
and
proposed
Method
322,
we
propose
that
the
test
methods
based
on
fourier
transform
infrared
(
FTIR)
spectroscopy,
EPA
Methods
320
and
321,
will
be
acceptable
for
measuring
HCl
from
lime
kilns
if
the
owner/
operator
wishes
to
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/
Friday,
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20,
2002
/
Proposed
Rules
claim
its
lime
manufacturing
facility
is
not
a
major
source.
These
FTIR
methods
were
finalized
along
with
the
portland
cement
industry
NESHAP,
and
this
requirement
would
be
consistent
with
those
NESHAP.
(
As
mentioned
above,
we
are
also
proposing
to
allow
sources
to
use
ASTM
Test
Method
D
6735
01
for
the
measurement
of
HCl
to
determine
whether
their
lime
manufacturing
plant
is
a
major
or
area
source.)
However,
we
acknowledge
the
NLA's
concerns
about
the
use
of
FTIR
during
the
lime
kiln
test
program.
In
letters
the
NLA
sent
to
us,
they
suggested
that
in
light
of
the
alleged
problems
experienced
by
our
test
contractors
in
using
FTIR,
we
should
allow
the
use
of
Method
26
for
measurement
of
HCl
emissions
from
lime
kilns.
However,
we
do
not
completely
agree
with
their
assessment
of
the
asserted
difficulties
we
experienced
with
FTIR.
Our
response
to
NLA's
concerns
about
FTIR
may
be
found
in
the
docket
to
the
proposed
rule.
And
despite
any
alleged
problems
with
FTIR,
we
do
not
consider
them
to
justify
the
use
of
Method
26
until
the
aforementioned
problems
with
Method
26
can
be
resolved.
III.
Rationale
for
Proposed
Rule
A.
How
Did
We
Determine
the
Source
Category
To
Regulate?
Section
112(
c)
of
the
CAA
directs
the
Agency
to
list
each
category
of
major
sources
that
emits
one
or
more
of
the
HAP
listed
in
section
112(
b)
of
the
CAA.
We
published
an
initial
list
of
source
categories
on
July
16,
1992
(
57
FR
31576).
``
Lime
Manufacturing''
is
one
of
the
174
categories
of
major
sources
on
the
initial
list.
As
defined
in
our
report,
``
Documentation
for
Developing
the
Initial
Source
Category
List''
(
EPA
450/
3
91
030,
July
1992),
the
lime
manufacturing
source
category
includes
any
facility
engaged
in
the
production
of
high
calcium
lime,
dolomitic
lime,
and
dead
burned
dolomite.
These
are
the
same
applicable
lime
products
as
defined
in
the
new
source
performance
standard
(
NSPS)
for
lime
manufacturing
plants
(
40
CFR
part
60,
subpart
HH)
and
in
the
proposed
rule.
According
to
the
background
document
for
the
initial
source
category
listing,
the
listing
of
lime
manufacturing
as
a
major
source
category
was
based
on
the
Administrator's
determination
that
some
lime
manufacturing
plants
would
be
major
sources
of
chlorine
and
metal
HAP
including,
but
not
limited
to,
compounds
of
arsenic,
cadmium,
chromium,
lead,
manganese,
mercury,
nickel,
and
selenium.
In
addition,
the
results
of
emissions
testing
we
conducted
in
the
development
of
the
proposed
rule
indicate
that
many
lime
manufacturing
plants
may
be
major
sources
of
HCl.
Hydrogen
chloride
emissions
from
these
lime
kiln
tests
using
EPA
Method
320
ranged
from
0.007
to
2.0
lbs
HCl
per
ton
of
lime
produced.
Assuming
an
average
HCl
emission
factor
of
0.4
lb/
ton,
a
lime
manufacturing
plant
would
only
have
to
produce
50,000
tons
of
lime
per
year
(
which
is
a
small
lime
manufacturing
plant)
for
it
to
be
a
major
source
(
for
this
reason
alone).
The
proposed
rule
would
regulate
HAP
emissions
from
all
new
and
existing
lime
manufacturing
plants
that
are
major
sources,
co
located
with
major
sources,
or
are
part
of
major
sources
(
e.
g.,
steel
production
facilities).
One
exception
to
this
is
that
lime
manufacturing
operations
located
at
pulp
and
paper
mills
would
not
be
subject
to
the
proposed
rule.
Lime
manufacturing
operations
at
pulp
and
paper
mills
would
be
subject
to
the
NESHAP
for
combustion
sources
at
kraft,
soda,
and
sulfite
pulp
and
paper
mills.
See
66
FR
3180,
January
12,
2001.
Lime
manufacturing
operations
at
beet
sugar
processing
plants
would
also
not
be
subject
to
the
NESHAP.
Both
the
lime
product
and
carbon
dioxide
in
the
beet
sugar
lime
kiln
exhaust
are
used
in
the
beet
sugar
manufacturing
process.
Beet
sugar
lime
kiln
exhaust
is
typically
routed
through
a
series
of
gas
washers
to
clean
the
exhaust
gas
prior
to
process
use.
The
clean,
cooled
gas
is
then
added
to
one
or
more
carbonation
units
(
which
contain
a
mixture
of
beet
juice,
lime,
and
water)
to
provide
the
carbon
dioxide
necessary
for
carbonation
and
precipitation
of
lime,
which
purifies
the
beet
sugar
juice.
Although
the
carbonation
units
are
part
of
the
sugar
manufacturing
process,
they
would
provide
additional
cleaning
of
the
lime
kiln
exhaust.
Beet
sugar
plants
typically
operate
only
seasonally,
and
our
analysis
indicates
that
beet
sugar
plants
are
not
major
sources
of
HAP.
B.
How
Did
We
Determine
the
Affected
Source?
The
proposed
rule
would
define
the
affected
source
as
the
lime
manufacturing
plant,
and
would
include
all
of
the
limestone
MPO
at
a
lime
manufacturing
plant,
beginning
with
the
raw
material
storage
bin,
and
all
of
the
lime
kilns
and
coolers
at
the
lime
manufacturing
plant.
This
definition
of
affected
source
conforms
with
the
General
Provisions
40
CFR
63.2
definition,
which
essentially
states
that
all
emission
units
at
a
plant
are
to
be
considered
as
one
affected
source.
A
new
lime
manufacturing
plant
is
defined
as
the
collection
of
any
limestone
MPO,
beginning
with
the
raw
material
storage
bin,
and
any
lime
kiln
or
cooler
for
which
construction
or
reconstruction
begins
after
December
20,
2002.
Thus,
it
is
possible
for
an
existing
lime
manufacturing
plant
and
a
new
lime
manufacturing
plant
to
be
located
at
the
same
site.
This
definition
of
new
affected
source
includes
the
same
emission
units
as
the
existing
affected
source,
except
that
the
new
affected
source
only
includes
those
emission
units
for
which
construction
or
reconstruction
begins
after
December
20,
2002.
The
definitions
are
different
because
the
MACT
PM
emission
limit
for
kilns
and
coolers
at
a
new
lime
manufacturing
plant
is
more
stringent
than
for
those
at
an
existing
lime
manufacturing
plant.
In
general,
the
emission
units
which
are
included
in
the
definition
of
new
or
existing
affected
source
were
selected
based
on
regulatory
history
(
e.
g.,
the
applicability
of
NSPS
and
the
information
included
in
the
initial
source
category
listing)
and
to
be
consistent
with
other
MACT
standards
(
e.
g.,
the
MACT
standards
for
the
portland
cement
industry).
Although
lime
coolers
were
not
among
the
list
of
emission
units
in
the
background
document
for
the
initial
source
category
listing
for
lime
manufacturing,
lime
coolers
would
be
an
emission
unit
under
the
definition
of
affected
source
in
the
proposed
rule.
All
lime
coolers
are
integrated
with
their
associated
kiln
such
that
most
coolers
vent
all
of
their
exhaust
(
if
there
is
an
exhaust
stream)
to
the
kiln,
although
a
few
lime
coolers
(
e.
g.,
grate
coolers)
also
vent
a
portion
of
their
exhaust
separately
to
the
atmosphere.
The
specific
MPO
which
are
included
in
the
affected
source
definition
include
the
following
emission
units:
all
of
the
grinding
mills,
raw
material
storage
bins,
conveying
system
transfer
points,
bulk
loading
or
unloading
systems,
screening
operations,
bucket
elevators,
and
belt
conveyors,
beginning
with
the
raw
material
storage
bin
and
up
to
the
kiln.
We
define
MPO
to
include
these
emission
units
under
the
proposed
subpart
because
these
units
are
also
subject
to
the
NSPS
for
Nonmetallic
Minerals
Processing
Plants
(
referred
to
in
this
preamble
as
the
NSPS
subpart
OOO).
We
specifically
solicit
comment
on
whether
raw
material
storage
piles
should
be
included
in
the
affected
source
definition.
In
today's
proposed
rule,
the
first
emission
unit
in
the
sequence
of
MPO
which
is
included
in
the
definition
of
affected
source
would
be
the
raw
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2002
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Proposed
Rules
material
storage
bin.
Furthermore,
the
first
conveyor
transfer
point
included
under
the
affected
source
definition
would
be
the
transfer
point
associated
with
the
conveyor
transferring
material
from
the
raw
material
storage
bin.
This
demarcation
in
the
sequence
of
MPO
which
defines
the
first
emission
unit
under
the
affected
source
definition
is
consistent
with
the
applicability
requirements
under
the
NESHAP
for
the
portland
cement
industry,
40
CFR
part
63,
subpart
LLL.
The
MPO
emission
units
that
would
be
excluded
from
the
affected
source
definition
are
described
as
follows.
Any
MPO
which
precedes
the
raw
material
storage
bin,
such
as
those
in
quarry
or
mine
operations,
is
not
included
in
the
definition
of
affected
source.
Any
operations
that
process
only
lime
product,
lime
kiln
dust,
or
fuel
would
be
excluded
from
the
definition.
Truck
dumping
into
any
screening
operation,
feed
hopper,
or
crusher
would
not
be
included
among
the
emission
units
considered
under
the
affected
source
definition.
(
These
exclusions
are
consistent
with
the
NSPS
subpart
OOO).
Finally,
lime
hydrators
would
not
be
included
as
an
emission
unit
under
the
affected
source
definition
since
all
hydrators
are
controlled
by
integrated
wet
scrubbers,
which
capture
the
lime
PM
(
and
associated
trace
metallic
HAP)
and
recycle
the
scrubber
water.
Additionally,
this
is
consistent
with
the
NSPS
subpart
HH,
which
does
not
apply
to
lime
hydrators.
C.
How
Did
We
Determine
Which
Pollutants
To
Regulate?
The
proposed
rule
would
reduce
emissions
of
non
volatile
and
semivolatile
metal
HAP
by
limiting
emissions
of
PM
from
the
kiln
and
cooler,
and
certain
MPO
emission
units.
Particulate
matter
is
a
surrogate
for
the
non
volatile
and
semi
volatile
metal
HAP
that
are
always
a
subset
of
PM.
Controlling
PM
emissions
will
control
the
non
volatile
and
semi
volatile
metal
HAP,
since
these
compounds
are
associated
with
the
PM,
i.
e.,
they
are
by
definition
in
the
particulate
phase
(
as
opposed
to
the
gaseous
form).
The
available
air
pollution
controls
for
the
particulate
HAP
metals
at
lime
manufacturing
plants
are
the
PM
controls
used
at
lime
manufacturing
plants,
i.
e.,
FF,
ESP,
and
wet
scrubbers.
These
at
the
stack
controls
capture
nonvolatile
and
semi
volatile
HAP
metals
non
preferentially
along
with
other
PM,
thus
showing
why
PM
is
a
permissible
indicator
for
these
HAP
metals.
See
National
Lime
Ass'n
v.
EPA,
233
F.
3d
at
639.
Also,
using
PM
as
a
surrogate
for
the
HAP
metals
would
reduce
the
cost
of
emissions
testing
and
monitoring
that
would
be
required
to
demonstrate
compliance
with
the
otherwise
numerous
standards
that
would
apply
to
individual
HAP
metals.
In
addition,
several
other
NESHAP
have
been
promulgated
which
use
PM
as
a
surrogate
for
non
volatile
and
semivolatile
HAP
metals
for
the
same
reason
it
is
a
technically
sound
surrogate
since
HAP
metals
are
necessarily
contained
in
PM,
are
controlled
by
PM
control
devices
to
roughly
the
same
efficiency,
and
there
are
significant
associated
cost
savings
due
to
monitoring
for
one
parameter
instead
of
many.
The
proposed
rule
would
limit
opacity
or
visible
emissions
from
certain
MPO
emission
units.
Opacity
serves
as
a
surrogate
for
the
non
volatile
and
semi
volatile
HAP
metals.
Opacity
is
indicative
of
PM
emission
levels
and,
thus,
for
the
same
reasons
that
PM
is
a
surrogate
for
the
particulate
HAP
metals,
opacity
would
also
be
a
surrogate
for
the
PM
HAP
metals.
Further,
opacity
levels
are
reduced
by
reducing
PM
emissions,
which
would
also
reduce
the
metal
HAP
in
the
particulate
phase,
i.
e.,
the
non
volatile
and
semi
volatile
HAP.
We
are
proposing
not
to
regulate
HCl
emissions
from
lime
kilns.
Under
the
authority
of
section
112(
d)(
4)
of
the
CAA,
we
have
determined
that
no
further
control
is
necessary
because
HCl
is
a
``
health
threshold
pollutant,''
and
HCl
levels
emitted
from
lime
kilns
are
below
the
threshold
value
within
an
ample
margin
of
safety.
The
following
explains
the
statutory
basis
for
considering
health
thresholds
when
establishing
standards,
and
the
basis
for
today's
proposed
decision,
including
a
discussion
of
the
risk
assessment
conducted
to
support
the
ample
margin
of
safety
decision.
Section
112
of
the
CAA
includes
exceptions
to
the
general
statutory
requirement
to
establish
emission
standards
based
on
MACT.
Of
relevance
here,
section
112(
d)(
4)
allows
us
to
develop
risk
based
standards
for
HAP
``
for
which
a
health
threshold
has
been
established''
provided
that
the
standards
achieve
an
``
ample
margin
of
safety.''
Therefore,
we
believe
we
have
the
discretion
under
section
112(
d)(
4)
to
develop
standards
which
may
be
less
stringent
than
the
corresponding
floorbased
MACT
standards
for
some
categories
emitting
threshold
pollutants.
In
deciding
standards
for
this
source
category,
we
seek
to
assure
that
emissions
from
every
source
in
the
category
result
in
exposures
less
than
the
threshold
level
even
for
an
individual
exposed
at
the
upper
end
of
the
exposure
distribution.
The
upper
end
of
the
exposure
distribution
is
calculated
using
the
``
high
end
exposure
estimate,''
defined
as
a
plausible
estimate
of
individual
exposure
for
those
persons
at
the
upper
end
of
the
exposure
distribution,
conceptually
above
the
90th
percentile,
but
not
higher
than
the
individual
in
the
population
who
has
the
highest
exposure.
We
believe
that
assuring
protection
to
persons
at
the
upper
end
of
the
exposure
distribution
is
consistent
with
the
``
ample
margin
of
safety''
requirement
in
section
112(
d)(
4).
We
emphasize
that
the
use
of
section
112(
d)(
4)
authority
is
wholly
discretionary.
As
the
legislative
history
indicates,
cases
may
arise
in
which
other
considerations
dictate
that
we
should
not
invoke
this
authority
to
establish
less
stringent
standards,
despite
the
existence
of
a
health
effects
threshold
that
is
not
jeopardized.
For
instance,
we
do
not
anticipate
that
we
would
set
less
stringent
standards
where
evidence
indicates
a
threat
of
significant
or
widespread
environmental
effects
taking
into
consideration
cost,
energy
safety
and
other
relevant
factors,
although
it
may
be
shown
that
emissions
from
a
particular
source
category
do
not
approach
or
exceed
a
level
requisite
to
protect
public
health
with
an
ample
margin
of
safety.
We
may
also
elect
not
to
set
less
stringent
standards
where
the
estimated
health
threshold
for
a
contaminant
is
subject
to
large
uncertainty.
Thus,
in
considering
appropriate
uses
of
our
discretionary
authority
under
section
112(
d)(
4),
we
consider
other
factors
in
addition
to
health
thresholds,
including
uncertainty
and
potential
``
adverse
environmental
effects,''
as
that
phrase
is
defined
in
section
112(
a)(
7)
of
the
CAA.
We
are
proposing
in
today's
notice
not
to
develop
standards
for
HCl
from
lime
kilns.
This
decision
is
based
on
the
following.
First,
we
consider
HCl
to
be
a
threshold
pollutant.
Second,
we
have
defined
threshold
values
in
the
form
of
an
Inhalation
Reference
Concentration
(
RfC)
and
acute
exposure
guideline
level
(
AEGL).
Third,
HCl
is
emitted
from
lime
kilns
in
quantities
that
result
in
human
exposure
in
the
ambient
air
at
levels
well
below
the
threshold
values
with
an
ample
margin
of
safety.
Finally,
there
are
no
adverse
environmental
effects
associated
with
HCl.
The
bases
and
supporting
rationale
for
these
conclusions
are
as
follows.
For
the
purposes
of
section
112(
d)(
4),
several
factors
are
considered
in
our
decision
on
whether
a
pollutant
should
be
categorized
as
a
health
threshold
pollutant.
These
factors
include
evidence
and
classification
of
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245
/
Friday,
December
20,
2002
/
Proposed
Rules
carcinogenic
risk
and
evidence
of
noncarcinogenic
effects.
For
a
detailed
discussion
of
factors
that
we
consider
in
deciding
whether
a
pollutant
should
be
categorized
as
a
health
threshold
pollutant,
please
see
the
April
15,
1998
Federal
Register
document
(
63
FR
18766).
In
the
April
15,
1998
action
cited
above,
we
determined
that
HCl,
a
Group
D
pollutant,
is
a
health
threshold
pollutant
for
the
purpose
of
section
112(
d)(
4)
of
the
CAA
(
63
FR
18753).
The
NLA
conducted
a
risk
assessment
to
determine
whether
the
emissions
of
HCl
from
lime
kilns
at
the
current
baseline
levels
resulted
in
exposures
below
the
threshold
values
for
HCl.
We
reviewed
the
risk
assessment
report
prepared
by
the
NLA
and
believe
that
it
uses
a
reasonable
and
conservative
methodology,
is
consistent
with
EPA
methodology
and
practice,
and
reaches
a
reasonable
conclusion
that
current
levels
of
HCl
emissions
from
lime
kilns
would
be
well
under
the
threshold
level
of
concern
for
human
receptors.
The
summary
of
the
NLA's
assessment
is
organized
as
follows:
(
1)
Hazard
identification
and
dose
response
assessment,
(
2)
emissions
and
release
information,
and
(
3)
exposure
assessment.
It
is
important
to
note
that
the
risk
assessment
methodology
applied
here
by
NLA
should
not
be
interpreted
as
a
standardized
approach
that
sets
a
precedent
for
how
EPA
will
analyze
application
of
section
112(
d)(
4)
in
other
cases.
The
approach
presented
here,
including
assumptions
and
models,
was
selected
to
meet
the
unique
needs
of
this
particular
case,
to
provide
the
appropriate
level
of
detail
and
margin
of
safety
given
the
data
availability,
chemicals,
and
emissions
particular
to
this
category.
The
RfC
is
a
``
long
term''
threshold,
defined
as
an
estimate
of
a
daily
inhalation
exposure
that,
over
a
lifetime,
would
not
likely
result
in
the
occurrence
of
significant
noncancer
health
effects
in
humans.
We
have
determined
that
the
RfC
for
HCl
of
20
micrograms
per
cubic
meter
(
µ
g/
m3)
is
an
appropriate
threshold
value
for
assessing
risk
to
humans
associated
with
exposure
to
HCl
through
inhalation
(
63
FR
18766,
April
15,
1998).
Therefore,
the
NLA
used
this
RfC
as
the
threshold
value
in
their
exposure
assessment
for
HCl
emitted
from
lime
kilns.
In
addition
to
the
effects
of
long
term
inhalation
of
HCl,
the
NLA,
at
our
request,
also
considered
thresholds
for
short
term
exposure
to
HCl
in
this
assessment.
The
AEGL
toxicity
values
are
estimates
of
adverse
health
effects
due
to
a
single
exposure
lasting
8
hours
or
less.
The
confidence
in
the
AEGL
(
a
qualitative
rating
or
either
low,
medium,
or
high)
is
based
on
the
number
of
studies
available
and
the
quality
of
the
data.
Consensus
toxicity
values
for
effects
of
acute
exposures
have
been
developed
by
several
different
organizations,
and
we
are
beginning
to
develop
such
values.
A
national
advisory
committee
organized
by
the
EPA
has
developed
AEGL
for
priority
chemicals
for
30
minute,
1
hour,
4
hour,
and
8
hour
airborne
exposures.
They
have
also
determined
the
levels
of
these
chemicals
at
each
exposure
duration
that
will
protect
against
discomfort
(
AEGL1),
serious
effects
(
AEGL2),
and
life
threatening
effects
or
death
(
AEGL3).
The
NLA
used
the
AEGL1
value
as
the
threshold
value
for
assessing
the
inhalation
health
effects
of
short
term
exposures
to
HCl.
The
NLA
conducted
dispersion
modeling
for
71
lime
plants
and
nearly
200
lime
kilns,
representing
all
operating
captive
and
commercial
lime
plants
in
the
U.
S.
that
would
potentially
be
subject
to
the
proposed
rule.
The
analyses
performed
assumed
worst
case
operating
scenarios,
such
as
maximum
production
rate
and
24
hours
per
day,
365
days
per
year
operation.
Hydrogen
chloride
emission
rates
were
based
on
either
measured
data
or
default
HCl
stack
concentrations.
For
plants
having
HCl
measurement
data,
only
HCl
data
collected
using
FTIR
were
used.
For
plants
where
no
emissions
data
were
available,
the
following
HCl
emission
levels
were
assumed
for
the
analyses:
10
parts
per
million
by
volume
(
ppmv)
for
kilns
with
either
scrubbers
or
preheaters,
18
ppmv
for
kilns
at
Riverton
Corporation,
26
ppmv
for
gasfired
kilns,
and
85
ppmv
for
all
other
kilns.
(
The
Riverton
emission
level
was
derived
by
multiplying
its
stack
test
results
obtained
using
EPA
Method
26
by
a
sampling
method
bias
factor
of
25.
Method
26
may
understate
actual
HCl
emissions
by
a
factor
of
between
2
and
25.)
The
HCl
emission
levels
were
converted
to
stack
emission
rates
using
the
stack
gas
volumetric
flow
rate.
The
release
characteristics
used
for
the
dispersion
model
included
stack
height,
stack
diameter,
exit
temperature,
and
exit
velocity.
Using
its
own
questionnaire,
the
NLA
collected
the
necessary
release
information
from
all
71
plants.
The
exposure
assessment
was
conducted
for
HCl
emissions
from
all
lime
plants
in
the
source
category.
As
discussed
above,
the
emissions
data
and
release
characteristics
were
used
as
inputs
to
the
assessment.
The
approach
taken
by
NLA
was
found
to
be
consistent
with
the
EPA's
tiered
methodology.
(
See
the
U.
S.
EPA
report
``
Screening
Procedures
for
Estimating
the
Air
Quality
Impact
of
Stationary
Sources
(
revised)'',
report
number
EPA
454/
R
92
019
(
1992).)
The
approach
for
each
of
the
facilities
involved
four
steps:
Step
1
was
the
modeling
of
HCl
concentrations
at
the
point
of
maximum
concentration,
whether
occurring
onsite
or
off
site,
using
SCREEN3,
a
screening
level
air
dispersion
model.
Step
2
was
the
same
as
Step
1,
but
modeling
was
performed
at
or
beyond
the
fence
line.
Step
3
was
the
same
as
Step
1,
but
modeling
was
performed
at
the
nearest
off
site
residence
or
business
location.
Step
4
was
the
modeling
of
HCl
concentrations
at
the
nearest
residence
or
business
location
using
the
ISC
PRIME
model.
(
ISC
PRIME
is
a
steady
state
Gaussian
plume
model
based
on
the
ISC3
dispersion
model,
with
the
Plume
RIse
Model
Enhancements
(
PRIME)
algorithm
added
for
improved
treatment
of
building
downwash.
The
model
can
account
for
settling
and
dry
deposition;
building
downwash;
area,
line,
and
volume
sources;
plume
rise
as
a
function
of
downwind
distance;
building
dimensions
and
stack
placement
relative
to
a
building;
separation
of
point
sources;
and
limited
terrain
adjustment.)
Note
that
each
succeeding
step
involves
more
refined
site
specific
data
and
less
conservative
assumptions.
The
analyses
performed
under
each
of
the
above
steps
assumed
worst
case
operating
scenarios,
such
as
maximum
production
rate,
and
in
Steps
1
through
3
worst
case
meteorology.
Local
terrain
and
building
downwash
effects
were
also
considered,
and
meteorological
data
were
taken
from
the
nearest
National
Weather
Service
meteorological
station.
Maximum
one
hour
averages
were
converted
to
annual
averages
using
a
conversion
factor
of
0.08,
consistent
with
EPA
recommendations.
The
NLA
generated
estimates
of
both
chronic
(
annual
average)
and
acute
(
onehour
concentrations
for
comparison
to
the
relevant
health
reference
values
or
threshold
levels.
Acute
and
chronic
exposures
were
compared
to
the
AEGL1
of
2,700
µ
g/
m3
for
one
hour
exposures
and
the
RfC
of
20
µ
g/
m3
for
long
term
continuous
exposure,
respectively.
Noncancer
risk
assessments
typically
use
a
metric
called
the
Hazard
Quotient
(
HQ)
to
assess
risks
of
exposures
to
noncarcinogens.
The
HQ
is
the
ratio
of
exposure
(
or
modeled
concentration)
to
the
health
reference
value
or
threshold
level
(
i.
e.,
RfC
or
AEGL).
HQ
values
less
than
``
1''
indicate
that
exposures
are
below
the
health
reference
value
or
threshold
level
and
are
likely
to
be
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245
/
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December
20,
2002
/
Proposed
Rules
without
appreciable
risk
of
adverse
effects
in
the
exposed
population.
HQ
values
above
``
1''
do
not
necessarily
imply
that
adverse
effects
will
occur,
but
that
the
potential
for
risk
of
such
effects
increases
as
HQ
values
exceed
``
1.''
In
addition,
when
information
on
background
levels
of
pollutants
is
not
available,
EPA
has
in
some
cases
considered
a
HQ
of
0.2
or
below
to
be
acceptable.
For
the
NLA
assessment,
if
the
HQ
was
found
to
be
less
than
0.5
for
any
of
the
first
three
steps
using
conservative
defaults
and
modeling
assumptions,
the
analysis
concluded
with
that
step.
On
the
other
hand,
if
the
HQ
exceeded
0.5,
work
proceeded
to
subsequent
steps.
There
were
no
facilities
where
Step
4
(
i.
e.,
the
most
refined
step)
yielded
an
HQ
above
0.5.
(
Steps
1,
2,
and
3
are
considered
``
Tier
2''
analyses
under
EPA's
tiered
modeling
approach,
whereas
Step
4
is
considered
a
``
Tier
3''
analysis.)
To
help
confirm
that
NLA's
approach
was
reasonable,
we
decided
to
reproduce
several
of
NLA's
modeling
analyses
by
performing
our
own
analyses
for
selected
facilities
having
the
highest
potential
for
health
risk
to
the
surrounding
community.
Generally,
these
were
facilities
having
the
highest
emission
rates
or
facilities
where
Tier
3
modeling
was
performed
for
actual
offsite
receptor
locations.
Fourteen
kilns
with
emission
rates
greater
than
5.0
grams/
second
were
evaluated
using
the
SCREEN3
air
dispersion
model.
For
the
analyses,
plant
specific
parameters
were
used
for
source
type,
emission
rate,
stack
height,
stack
inner
diameter
exit
velocity,
gas
exit
temperature,
and
location
(
urban
versus
rural).
Assumptions
about
flat
terrain,
meteorology,
and
building
dimensions
were
made,
as
appropriate.
For
plants
with
multiple
stacks,
emissions
were
considered
to
emanate
from
one
colocated
emission
point.
Then,
in
order
to
maintain
a
conservative
approach,
the
lowest
effective
stack
height
parameters
were
utilized
for
all
emissions.
The
model
was
run,
and
maximum
concentrations
for
distances
ranging
from
100
to
5,000
meters
were
obtained.
To
evaluate
acute
exposure,
the
HQ
was
determined
by
comparing
the
maximum
concentrations
to
the
HCl
acute
threshold
level
of
2,700
µ
g/
m3.
Maximum
concentrations
were
then
converted
into
annual
concentrations,
and
the
HQ
was
determined
by
comparing
these
concentrations
to
the
HCl
chronic
health
reference
value
of
20
µ
g/
m3.
We
then
used
the
Human
Exposure
Model
(
HEM)
to
examine
seven
of
the
kilns
that
were
modeled
by
the
NLA
using
ISC
PRIME.
Concentrations
were
predicted
at
geographically
weighted
centers
of
census
blocks.
Emissions
were
assumed
to
originate
from
a
single
stack
using
the
lowest
effective
stack
height
reported
at
each
facility.
Six
of
the
kilns
modeled
showed
values
well
below
the
RfC,
the
highest
having
an
HQ
=
0.11.
The
seventh
indicated
an
HQ
of
0.96.
The
seventh
kiln
was
re
simulated
using
site
specific
emissions
and
stack
data,
resulting
in
an
HQ
=
0.21.
Overall,
we
believe
that
the
NLA
has
taken
a
reasonably
conservative
approach
in
estimating
risk
due
to
HCl
exposure.
This
approach
is
consistent
with
the
methodology
and
assumptions
EPA
would
have
used
if
the
study
had
been
done
in
house,
and
in
several
instances
NLA's
approach
is
even
more
conservative.
Furthermore,
EPA
conducted
a
parallel
confirmatory
analysis
and
found
results
consistent
with
those
of
the
NLA
assessment.
At
this
point,
it
should
be
noted
that
the
potential
for
effects
depends
on
an
individual's
total
exposure
to
that
chemical.
As
a
result,
exposure
from
all
sources,
not
just
the
one
in
question,
must
be
evaluated.
Where
possible,
other
exposures
must
be
accounted
for,
either
explicitly
through
monitoring
or
modeling,
or
by
apportioning
a
portion
of
the
health
threshold
level
available
to
any
individual
source.
To
estimate
the
potential
exposure
from
other
sources,
the
NLA
reviewed
the
ambient
HCl
concentration
estimates
derived
by
the
air
component
of
EPA's
Cumulative
Exposure
Project
(
CEP).
They
found
that
the
mean
national
HCl
concentration
corresponded
to
an
HQ
of
0.06
and
the
95th
percentile
national
HCl
concentration
corresponded
to
an
HQ
of
0.2,
and
they
concluded
that
background
HCl
exposures
were
unlikely
to
exceed
an
HQ
of
0.2.
(
These
HQ
helped
confirm
that
the
total
HQ
for
a
facility,
including
contributions
from
other
sources
(``
background''),
would
not
be
expected
to
exceed
``
1.''
However,
these
background
HQ
were
not
actually
added
into
a
facility's
final
HQ
estimate.
Thus,
we
are
comfortable
with
NLA's
calculations
and
feel
confident
that
exposures
to
HCl
emissions
from
the
facilities
in
question
are
unlikely
to
ever
exceed
an
HQ
of
0.2.
Therefore,
we
believe
that
the
predicted
exposures
from
these
facilities
should
provide
an
ample
margin
of
safety
to
ensure
that
total
exposures
for
nearby
residents
should
not
exceed
the
short
term
or
long
term
health
based
threshold
levels
or
health
reference
values,
even
when
considering
the
possible
contributions
of
other
sources
of
HCl
or
similar
respiratory
irritants.
The
standards
for
emissions
must
also
protect
against
significant
and
widespread
adverse
environmental
effects
to
wildlife,
aquatic
life,
and
other
natural
resources.
The
NLA
did
not
conduct
a
formal
ecological
risk
assessment.
However,
we
have
reviewed
publications
in
the
literature
to
determine
if
there
would
be
reasonable
expectation
for
serious
or
widespread
adverse
effects
to
natural
resources.
We
consider
the
following
aspects
of
pollutant
exposure
and
effects:
Toxicity
effects
from
acute
and
chronic
exposures
to
expected
concentrations
around
the
source
(
as
measured
or
modeled),
persistence
in
the
environment,
local
and
long
range
transport,
and
tendency
for
biomagnification
with
toxic
effects
manifest
at
higher
trophic
levels.
No
research
has
been
identified
for
effects
on
terrestrial
animal
species
beyond
that
cited
in
the
development
of
the
HCl
RfC.
Modeling
calculations
indicate
that
there
is
little
likelihood
of
chronic
or
widespread
exposure
to
HCl
at
concentrations
above
the
threshold
around
lime
manufacturing
plants.
Based
on
these
considerations,
we
believe
that
the
RfC
can
reasonably
be
expected
to
protect
against
widespread
adverse
effects
in
other
animal
species
as
well.
Plants
also
respond
to
airborne
HCl
levels.
Chronic
exposure
to
about
600
µ
g/
m3
can
be
expected
to
result
in
discernible
effects,
depending
on
the
plant
species.
Plants
respond
differently
to
HCl
as
an
anhydrous
gas
than
to
HCl
aerosols.
Relative
humidity
is
important
in
plant
response;
there
appears
to
be
a
threshold
of
relative
humidity
above
which
plants
will
incur
twice
as
much
damage
at
a
given
dose.
Effects
include
leaf
injury
and
decrease
in
chlorophyll
levels
in
various
species
given
acute,
20
minute
exposures
of
6,500
to
27,000
µ
g/
m3.
A
field
study
reports
different
sensitivity
to
damage
of
foliage
in
50
species
growing
in
the
vicinity
of
an
anhydrous
aluminum
chloride
manufacturer.
American
elm,
bur
oak,
eastern
white
pine,
basswood,
red
ash
and
several
bean
species
were
observed
to
be
most
sensitive.
Concentrations
of
HCl
in
the
air
were
not
reported.
Chloride
ion
in
whole
leaves
was
0.2
to
0.5
percent
of
dry
weight;
sensitive
species
showed
damage
at
the
lower
value,
but
tolerant
species
displayed
no
injury
at
the
higher
value.
Injury
declined
with
distance
from
the
source
with
no
effects
observed
beyond
300
meters.
Maximum
modeled
long
term
HCl
concentrations
(
less
than
10
µ
g/
m3)
are
well
below
the
600
µ
g/
m3
chronic
threshold,
and
the
maximum
short
term
HCl
concentration
(
540
µ
g/
m3)
is
far
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below
the
6,500
µ
g/
m3
acute
exposure
threshold.
Therefore,
no
adverse
exposure
effects
are
anticipated.
Prevailing
meteorology
strongly
determines
the
fate
of
HCl
in
the
atmosphere.
However,
HCl
is
not
considered
a
strongly
persistent
pollutant,
or
one
where
long
range
transport
is
important
in
predicting
its
ecological
effects.
In
the
atmosphere,
HCl
can
be
expected
to
be
absorbed
into
aqueous
aerosols,
due
to
its
great
affinity
for
water,
and
removed
from
the
troposphere
by
rainfall.
In
addition,
HCl
will
react
with
hydroxy
ions
to
yield
water
plus
chloride
ions.
However,
the
concentration
of
hydroxy
ions
in
the
troposphere
is
low,
so
HCl
may
have
a
relatively
long
residence
time
in
areas
of
low
humidity.
No
studies
are
reported
of
HCl
levels
in
ponds
or
other
small
water
bodies
or
soils
near
major
sources
of
HCl
emissions.
Toxic
effects
of
HCl
to
aquatic
organisms
would
likely
be
due
to
the
hydronium
ion,
or
acidity.
Aquatic
organisms
in
their
natural
environments
often
exhibit
a
broad
range
of
pH
tolerance.
Effects
of
HCl
deposition
to
small
water
bodies
and
to
soils
will
primarily
depend
on
the
extent
of
neutralizing
by
carbonates
or
other
buffering
compounds.
Chloride
ions
are
essentially
ubiquitous
in
natural
waters
and
soils
so
minor
increases
due
to
deposition
of
dissolved
HCl
will
have
much
less
effect
than
the
deposited
hydronium
ions.
Deleterious
effects
of
HCl
on
ponds
and
soils,
where
such
effects
might
be
found
near
a
major
source
emitting
to
the
atmosphere,
likely
will
be
local
rather
than
widespread,
as
observed
in
plant
foliage.
Effects
of
HCl
on
tissues
are
generally
restricted
to
those
immediately
affected
and
are
essentially
acidic
effects.
The
rapid
solubility
of
HCl
in
aqueous
media
releases
hydronium
ions,
which
can
be
corrosive
to
tissue
when
above
a
threshold
concentration.
The
chloride
ions
may
be
concentrated
in
some
plant
tissues,
but
may
be
distributed
throughout
the
organism,
as
most
organisms
have
chloride
ions
in
their
fluids.
Leaves
or
other
tissues
exposed
to
HCl
may
show
some
concentration
above
that
of
their
immediate
environment;
that
is,
some
degree
of
bioconcentration
can
occur.
However,
long
term
storage
in
specific
organs
and
biomagnification
of
concentrations
of
HCl
in
trophic
levels
of
a
food
chain
would
not
be
expected.
Thus,
the
chemical
nature
of
HCl
results
in
deleterious
effects,
that
when
present,
are
local
rather
than
widespread.
In
conclusion,
acute
and
chronic
exposures
to
expected
HCl
concentrations
around
the
source
are
not
expected
to
result
in
adverse
toxicity
effects.
Hydrogen
chloride
is
not
persistent
in
the
environment.
Effects
of
HCl
on
ponds
and
soils
are
likely
to
be
local
rather
than
widespread.
Finally,
HCl
is
not
believed
to
result
in
biomagnification
or
bioaccumulation
in
the
environment.
Therefore,
we
do
not
anticipate
any
adverse
ecological
effects
from
HCl.
The
results
of
the
exposure
assessment
showed
that
exposure
levels
to
baseline
HCl
emissions
from
lime
production
facilities
are
well
below
the
health
threshold
value.
Additionally,
the
threshold
values,
for
which
the
RfC
and
AEGL
values
were
determined
to
be
appropriate
values,
were
not
exceeded
when
considering
conservative
estimates
of
exposure
resulting
from
lime
kiln
emissions
as
well
as
considering
background
exposures
to
HCl
and
therefore,
represent
an
ample
margin
of
safety.
Furthermore,
no
significant
or
widespread
adverse
environmental
effects
from
HCl
is
anticipated.
Therefore,
under
authority
of
section
112(
d)(
4),
we
have
determined
that
further
control
of
HCl
emissions
from
lime
manufacturing
plants
is
not
necessary.
We
considered
establishing
a
limit
for
mercury
emissions
from
lime
kilns,
but
there
is
no
MACT
floor
for
mercury
that
is,
we
know
of
no
way
to
establish
an
achievable
floor
standard
for
mercury
beyond
selecting
an
arbitrarily
high
emission
limit
that
any
source
could
achieve
under
any
circumstance
since
no
source
controls
mercury
emissions
using
a
means
of
control
that
can
be
duplicated
by
other
sources.
We
also
have
initially
determined
that
an
emission
limit
for
mercury
based
on
a
beyond
the
MACT
floor
option
is
not
considered
cost
effective
at
this
time;
nor
is
a
beyond
the
floor
standard
justified
for
mercury
after
otherwise
taking
into
account
cost,
non
air
quality
environmental
and
health
impacts,
and
energy
considerations.
D.
How
Did
We
Determine
the
MACT
Floor
for
Emission
Units
at
Existing
Lime
Manufacturing
Plants?
1.
PM
From
the
Kiln
and
Cooler
In
establishing
the
MACT
floor,
section
112(
d)(
3)(
A)
of
the
CAA
directs
us
to
set
standards
for
existing
sources
that
are
no
less
stringent
than
the
average
emission
limitation
achieved
in
practice
by
the
best
performing
12
percent
of
existing
sources
(
for
which
there
are
emissions
data)
where
there
are
more
than
30
sources
in
the
category
or
subcategory.
Among
the
possible
meanings
for
the
word
``
average''
as
the
term
is
used
in
the
CAA,
we
considered
two
of
the
most
common.
First,
``
average''
could
be
interpreted
as
the
arithmetic
mean.
The
arithmetic
mean
of
a
set
of
measurements
is
the
sum
of
the
measurements
divided
by
the
number
of
measurements
in
the
set.
The
word
``
average''
could
also
be
interpreted
as
the
median
of
the
emission
limitation
values.
The
median
is
the
value
in
a
set
of
measurements
below
and
above
which
there
are
an
equal
number
of
values
(
when
the
measurements
are
arranged
in
order
of
magnitude).
This
approach
identifies
the
emission
limitation
achieved
by
those
sources
within
the
top
12
percent,
arranges
those
emissions
limitations
achieved
in
order
of
magnitude,
and
the
control
level
achieved
by,
and
achievable
by,
the
median
source
is
selected.
Either
of
these
two
approaches
could
be
used
in
developing
MACT
standards
for
different
source
categories.
We
obtained
PM
data
for
47
lime
kilns
over
the
course
of
developing
the
proposed
rule.
The
most
comprehensive
body
of
data,
and
we
believe
the
one
that
most
accurately
approximates
the
performance
achieved
by,
and
achievable
by,
the
average
of
the
best
12
percent
of
existing
sources
for
which
the
Agency
has
emission
data,
are
PM
limitations
contained
in
State
and
local
agency
permits
for
these
sources.
We
used
the
permit
limitations
for
the
kilns
(
along
with
the
supporting
PM
emissions
data)
in
our
MACT
floor
analysis
because
the
permit
limitations
were
indicative
of
the
variability
in
the
long
term
performance
of
the
emission
controls.
We
examined
multiple
sets
of
PM
emissions
data
obtained
from
the
individual
kilns
during
compliance
testing
to
assure
that
the
permit
limitations
do
not
underestimate
the
pollution
control
capabilities
of
these
sources
(
i.
e.,
that
actual
performance
is
not
superior
to
the
permit
limits,
in
which
case
the
MACT
floor
would
need
to
be
based
on
that
superior
performance;
see
Sierra
Club
v.
EPA,
167
F.
3d
658,
661
62
(
D.
C.
Cir.
1999)).
Simply
taking
the
average
or
mean
of
the
lowest
12
percent
of
the
emissions
data
(
without
considering
permit
limitations,
i.
e.,
achievability
of
the
technology
over
the
long
term)
would
not
account
for
the
inherent
variability
of
performance
of
well
designed
and
operated
emission
controls,
since
individual
emissions
tests
are
based
on
short
durations
of
sampling,
typically
3
hour
tests
(
because
of
the
absence
of
PM
continuous
emissions
monitors)
and,
thus,
we
would
be
required
to
extrapolate
these
``
snapshot''
data
to
ascertain
long
term
achievable
performance.
Additionally,
we
obtained
multiple
compliance
test
data
for
the
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top
performing
kilns
(
where
available);
some
of
the
kilns'
data
vary
over
two
orders
of
magnitude
and
vary
up
to
their
permit
limit.
Further,
these
multiple
data
sets
indicate
that
some
of
these
top
performing
kilns
would
not
be
able
to
meet
an
emission
limit
based
on
a
strictly
arithmetic
average
of
the
top
performing
kilns'
emissions
data
(
the
result
being
a
standard
not
achieved
by
the
average
of
the
best
performing
sources,
and
hence
impermissible).
We
arrayed
the
data
by
permit
limitation,
from
lowest
to
highest,
in
units
of
lbs
PM/
ton
of
limestone
feed,
along
with
the
associated
PM
emissions
test
data.
The
best
performing
12
percent
of
the
47
kilns
are
the
best
performing
six
kilns,
with
the
third
and
fourth
best
performing
kilns
being
the
median.
The
six
best
performing
kilns'
permit
limits
for
PM
are
0.10,
0.12,
0.12,
0.12,
0.21,
and
0.21
lb/
ton
limestone
feed
and
are
equipped
with
either
a
FF
or
ESP.
The
emission
test
data
associated
with
these
kilns
indicate
that
these
kilns
have
indeed
achieved
the
limits
in
their
State
permits.
The
test
data
for
the
kilns
permitted
at
or
below
0.12
lb
PM/
ton
limestone
vary
from
0.0091
to
0.0925
lb
PM/
ton
limestone.
We
do
not
believe
that
these
kilns
could
consistently
achieve
standards
which
are
lower
than
the
permit
limitation
of
0.12
lb
PM/
ton
limestone
level,
due
to
the
probable
long
term
variability.
Therefore,
we
are
proposing
a
MACT
floor
PM
emission
limit
of
0.12
lb
PM/
ton
limestone
for
lime
kilns
at
existing
lime
plants,
using
the
median
approach
of
the
permit
limits,
which
the
associated
emissions
data
show
to
be
achievable
and
show
as
well
to
be
a
reasonable
approximation
of
the
achievable
performance
of
the
average
of
the
best
performing
12
percent
of
kilns
for
which
we
have
emissions
data,
taking
into
consideration
long
term
variability
in
performance.
Most
lime
coolers
(
approximately
96
percent)
in
the
lime
manufacturing
industry
use
ambient
air
for
cooling
and
are
integrated
with
the
kiln
such
that
all
the
cooler
exhaust
goes
directly
to
the
kiln
for
use
as
combustion
air,
or
else
the
cooling
of
the
lime
takes
place
within
the
kiln
itself
(
e.
g.,
in
vertical
kilns).
Thus,
for
96
percent
of
the
lime
kilns,
their
emissions
are
actually
the
kiln
and
cooler
emissions
combined.
The
kiln
PM
emission
limit
of
0.12
lb/
ton
limestone
is
based
on
kiln
permit
limits
and
associated
emissions
data
where
the
kiln
and
cooler
emissions
are
combined.
That
is,
based
on
our
review
of
the
questionnaire
responses,
discussions
with
plant
personnel,
and
State
permit
information,
none
of
the
best
performing
kilns
has
a
lime
cooler
with
a
separate
exhaust
to
the
atmosphere.
Thus,
the
kiln
PM
emission
limit
applies
to
the
emissions
from
both
the
kiln
and
cooler.
For
the
96
percent
of
the
kilns
with
no
separate
cooler
exhaust,
this
would
have
no
effect;
that
is,
the
coolers'
emissions
are
already
combined
with
the
kiln
prior
to
venting
to
the
atmosphere.
For
the
few
kilns
with
grate
coolers
that
separately
vent
a
portion
of
the
cooler
exhaust
to
the
atmosphere,
the
sum
of
the
emissions
from
the
kiln(
s)
and
the
grate
cooler
exhaust(
s)
at
the
existing
lime
manufacturing
plant
would
be
subject
to
the
kiln
and
cooler
emission
limit
of
0.12
lb
PM/
ton
limestone
feed.
With
this
approach,
the
emissions
from
the
kiln
and
cooler
are
subject
to
one
emission
limit,
regardless
of
whether
the
kiln
and
cooler
emissions
are
combined
prior
to
release
to
the
atmosphere.
This
reflects
the
performance
achieved
by,
and
achievable
by
(
taking
operating
variability
into
account),
the
median
of
the
12
percent
best
performing
kilns
for
which
the
Agency
has
emissions
data.
Further,
since
we
have
defined
the
affected
source
to
include
all
kilns
and
coolers
at
a
lime
manufacturing
plant,
the
kiln
and
cooler
PM
emission
limit
applies
to
the
combined
emissions
of
PM
from
all
of
the
kilns
and
coolers
at
the
existing
lime
manufacturing
plant.
During
the
review
of
a
draft
of
this
proposal
by
the
Small
Business
Advocacy
Review
(
SBAR)
Panel,
an
issue
was
raised
about
the
potential
for
increases
in
sulfur
dioxide
(
SO2)
and
HCl
emissions
that
may
occur
if
sources
opt
to
remove
existing
PM
wet
scrubbers
and
replace
them
with
dry
PM
control
devices
(
such
as
FF
or
ESP)
in
order
to
meet
the
proposed
kiln
PM
standard.
About
20
percent
of
the
lime
produced
in
the
U.
S.
is
from
kilns
equipped
with
wet
scrubbers,
and
about
90
percent
of
the
wet
scrubbers
on
lime
kilns
at
major
source
lime
plants
would
not
meet
the
proposed
PM
limit.
And
although
the
proposed
rule
would
not
dictate
how
the
lime
kiln
PM
standard
would
have
to
be
met,
and
our
limited
information
indicates
that
one
or
two
lime
kilns
with
wet
scrubbers
may
already
meet
the
proposed
PM
standard
(
this
may
be
because
they
burn
natural
gas
as
their
primary
fuel
source),
some
sources
may
elect
to
upgrade
their
existing
wet
scrubber
with
a
new
venturi
wet
scrubber
to
meet
the
PM
standard,
while
other
existing
sources
that
would
not
meet
the
proposed
PM
emission
limit
with
a
wet
scrubber
may
opt
to
replace
the
wet
scrubber
with
a
FF.
But
because
wet
scrubbers
are
more
effective
than
a
FF
or
ESP
at
removing
SO2
(
and
HCl),
the
SBAR
Panel
was
concerned
that
the
latter
approach
would
result
in
increases
in
SO2
emissions
from
these
kilns.
Therefore,
we
request
comment
on
establishing
a
subcategory
because
of
the
potential
increase
in
SO2
and
HCl
emissions
and
other
negative
environmental
impacts
(
discussed
further
below)
that
may
result
in
complying
with
the
proposed
PM
standard.
We
note,
however,
that
the
risk
analysis
showed
that
HCl
levels
emitted
from
lime
kilns
(
including
the
increased
HCl
levels
from
kilns
with
wet
scrubbers
that
are
replaced
with
FF)
are
below
the
threshold
value
within
an
ample
margin
of
safety.
Although
subcategorization
normally
is
based
on
differences
in
manufacturing
process,
emission
characteristics,
or
technical
feasibility,
and
is
not
justified
by
the
sole
fact
that
a
different
type
of
air
pollution
control
equipment
is
utilized,
EPA
solicits
comment
on
the
possibility
of
establishing
a
subcategory
for
existing
lime
kilns
using
wet
scrubbers
in
order
to
avoid
potentially
environmentally
counterproductive
effects
due
to
increased
emissions
of
acid
gases
and
increased
water
and
energy
use.
(
Such
a
subcategory
would
also
significantly
reduce
the
cost
impact
on
industry.)
In
addition,
we
request
comment
on
what
the
MACT
floor
PM
limit
would
be
for
this
possible
subcategory.
If
we
based
the
MACT
floor
for
this
possible
subcategory
on
an
inspection
of
the
permit
limit
information
available
to
us,
we
would
initially
conclude
that
a
PM
emission
limit
of
0.6
lb
PM/
ton
limestone
feed
may
be
appropriate.
We
note,
however,
that
in
order
to
use
permit
limits
as
a
basis
for
a
MACT
floor
determination,
those
permit
limits
must
accurately
reflect
the
actual
performance
of
the
sources
used
as
the
basis
for
the
MACT
floor
determination
(
considering
both
emission
levels
and
operating
variability
when
designed
and
operated
properly).
We,
therefore,
solicit
information
both
on
PM
permit
limits
for
wet
scrubber
equipped
kilns
and
on
the
actual
emissions
from
those
kilns.
Lastly,
at
the
recommendation
of
the
SBAR
Panel,
we
specifically
request
comment
on
any
operational,
process,
product,
or
other
technical
and/
or
spatial
constraints
that
would
preclude
installation
of
a
FF
or
ESP
at
an
existing
lime
manufacturing
plant.
We
note,
however,
that
following
the
SBAR
panel,
the
NLA
brought
to
our
attention
the
fact
that
if
sources
replace
their
wet
scrubbers
with
FF
to
comply
with
the
kiln
PM
standard,
they
would
most
likely
also
need
to
take
steps
to
cool
the
exhaust
gas
stream
entering
the
FF,
since
the
operating
temperature
of
a
FF
may
be
400
°
less
than
a
wet
scrubber.
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Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
Cooling
the
gas
stream
as
such
may
be
done
using
various
techniques,
all
with
varying
environmental
and
cost
impacts.
In
light
of
this
new
information
presented
by
NLA,
we
analyzed
the
costs
of
three
PM
control
options
available
to
sources
with
wet
scrubbers
that
do
not
currently
meet
the
proposed
PM
limit.
Sources
could
elect
to
replace
the
existing
wet
scrubber
with
a
new
FF
and
cool
the
entering
exhaust
gas
stream
using
either
a
water
spray
system
or
alternatively
a
kiln
preheater.
Or
sources
may
elect
to
replace
the
existing
wet
scrubber
with
a
new
venturi
wet
scrubber
and
thereby
avoid
the
need
for
gas
stream
cooling.
Based
on
our
review
of
the
technical
performance
of
venturi
scrubbers,
we
believe
that
a
new,
high
efficiency
venturi
wet
scrubber
with
a
gas
stream
pressure
drop
of
35
inches
water
guage
or
more
could
meet
the
proposed
lime
kiln
PM
emission
limit.
After
reviewing
the
cost
impacts
of
these
control
options,
we
chose
the
venturi
wet
scrubber
as
the
basis
for
estimating
the
proposed
rule's
impacts
(
for
kilns
with
wet
scrubbers
not
meeting
the
proposed
PM
limit)
because,
in
general,
this
option
was
the
least
expensive
in
terms
of
capital
cost
and,
in
some
cases,
annual
cost
as
well.
We
request
comment
on
our
cost
analyses
of
these
control
options
(
the
details
of
which
may
be
found
in
the
docket)
and
on
our
determination
to
base
the
impacts
estimates
of
the
proposed
rule
on
this
venturi
scrubber
control
option.
We
also
acknowledge
that
the
NLA's
cost
estimates
lead
them
to
conclude
that
it
may
be
less
expensive
for
sources
to
install
a
FF
with
gas
stream
cooling
rather
than
install
new
venturi
wet
scrubbers.
In
addition,
there
would
be
different
emission
and
environmental
impacts
depending
on
the
control
option
selected
by
sources
with
existing
wet
scrubbers
not
meeting
the
proposed
PM
limit.
For
the
control
option
of
a
wet
scrubber
being
replaced
with
a
new
FF,
we
estimate
that
national
HCl
emissions
would
increase
by
about
1,000
tons/
yr,
and
national
SO2
emissions
would
increase
by
about
15,000
tons/
yr.
The
NLA
commented
during
the
SBAR
Panel
that
the
resulting
SO2
increases
under
this
option
could
cause
a
lime
plant
to
become
subject
to
new
source
review
(
NSR)
rule
requirements,
and
the
source
would,
thus,
incur
additional
costs
associated
with
this
review.
Sources
utilizing
this
control
option
may
or
may
not
be
excluded
from
NSR
if
it
is
a
pollution
control
project.
Under
the
current
NSR
rules
and
guidance,
a
net
emissions
increase
of
40
tons/
yr
SO2
would
trigger
NSR
even
if
this
increase
was
due
to
a
pollution
control
project,
unless
the
control
project
qualified
for
a
Pollution
Control
Project
Exclusion.
The
EPA
is
currently
revising
the
NSR
rules.
Finally,
no
change
in
SO2
or
HCl
emissions
would
be
expected
for
sources
that
replace
existing
wet
scrubbers
with
new
venturi
wet
scrubbers.
With
no
resultant
SO2
emissions
increases,
it
would
be
unlikely
that
sources
would
seek
an
NSR
exclusion.
We
also
acknowledge
there
would
be
additional
negative
environmental
impacts
if
all
kilns
with
wet
scrubbers
not
meeting
the
proposed
PM
limit
are
replaced
with
new
venturi
wet
scrubbers.
These
impacts
would
include
an
increase
in
national
water
consumption
by
about
4.2
billion
gallons
per
year
from
current
levels,
and
an
increase
in
electricity
consumption
by
about
7.2
million
kilowatt
hours/
yr.
(
Industry
estimates
that
along
with
this
additional
electricity
consumption,
an
additional
8,000
tons/
yr
of
carbon
dioxide
would
be
emitted
from
fossil
fuel
fired
electrical
power
generating
stations.)
These
increases
result
from
the
new
venturi
wet
scrubbers
requiring
a
higher
water
flow
rate
and
larger
fans
to
handle
the
increased
gas
pressure
drop.
We
note,
however,
that
with
a
higher
PM
limit
for
a
possible
wet
scrubber
subcategory,
national
PM
emissions
from
lime
kilns
would
be
approximately
1,000
tons/
yr
greater
than
if
there
were
no
subcategory.
2.
Mercury
From
the
Kiln
Mercury
emitted
from
lime
kilns
originates
from
the
raw
materials
and
fuels
fed
to
the
kiln.
In
considering
a
potential
floor
for
mercury
from
these
emission
units,
we
considered
both
atthe
stack
controls
and
substitution
of
feed
and
fuels
as
a
potential
basis
for
a
standard.
Since
no
sources
are
controlling
the
mercury
emissions
from
their
lime
kilns
using
at
the
stack
controls,
such
control
cannot
be
the
basis
for
a
floor
standard.
Switching
of
raw
material
feed
or
fuel
is
also
not
a
basis
for
establishing
a
floor
standard
because
these
means
of
control
are
not
available,
leading
to
unachievable
standards.
Nor
is
there
any
indication
that
feed
or
fuel
substitution
would
control
mercury
emissions
from
these
sources.
The
reasons
for
these
conclusions
are
set
out
below.
Substitution
of
raw
materials,
i.
e.,
feedstock
substitution,
is
not
an
available
means
of
control.
First,
raw
materials
are
proprietary.
No
kiln
can
use
another's
raw
materials.
Thus,
a
standard
based
on
feed
control
is
not
achievable
because
it
is
not
even
available.
No
second
kiln
could
duplicate
a
``
low
mercury''
source's
performance,
even
assuming
there
was
a
low
mercury
source
of
feed
material.
In
addition,
we
are
aware
of
no
data
or
information
indicating
that
a
certain
type
of
limestone
or
source
of
limestone
has
a
lower
concentration
of
mercury,
and
although
such
deposits
may
exist,
we
do
not
believe
such
deposits
of
limestone
exist
sufficiently
throughout
the
U.
S.
to
supply
the
industry.
Further,
assuming
there
was
a
widespread
source
of
limestone
with
a
lower
level
of
mercury
(
which
is
highly
unlikely),
it
is
unclear
that
this
would
lead
to
lower
mercury
emissions
(
or
what
the
reductions
of
mercury
emissions
would
be),
since
mercury
emissions
from
lime
kilns
also
originate
from
the
fuel.
A
floor
standard
based
on
substitution
of
so
called
clean
mercury
fossil
fuels
is
likewise
not
achievable
due
to
unavailability
of
this
means
of
control.
The
floor
for
existing
sources
would
have
to
be
based
on
either
coal
or
natural
gas
substitution
since
there
are
enough
sources
using
coal
or
natural
gas
to
constitute
a
MACT
floor
for
existing
kilns.
However,
there
are
simply
inadequate
amounts
of
``
low
mercury''
coal
and
natural
gas
available
to
power
this
industry.
Thus,
we
see
no
feasible
way
for
the
lime
industry
to
function
if
it
can
only
use
the
6
percent
``
cleanest''
fuels
to
make
its
product.
See
H.
R.
Rep.
No.
101
490,
101st
Cong.
2d
sess.
328
(``
MACT
is
not
intended
*
*
*
to
drive
sources
to
the
brink
of
shutdown'').
Nor
do
we
see
any
evidence
that
``
low
mercury''
coal
exists.
Our
analysis
shows
that
the
average
mercury
levels
for
the
various
coal
types
bituminous,
subbituminous,
and
lignite
coals
are
nearly
the
same
at
around
0.1
part
per
million
by
weight.
These
data
show
that
there
is
not
a
certain
type
of
coal
that
has
a
lower
mercury
level.
Also,
based
on
the
data
in
the
EPA
Utility
Study
and
Report
to
Congress,
emissions
of
other
HAP
metals
would
or
could
increase
if
coal
or
oil
were
to
be
substituted
to
try
and
achieve
lower
mercury
emissions.
These
data
indicate
that
levels
of
HAP
metals
in
coal
are
so
variable
that
decreases
in
emissions
of
one
HAP
metal
are
offset
by
increases
in
others
when
different
coals
are
used
as
fuel.
These
data
also
show
that
if
fuel
oil
is
substituted
for
coal,
nickel
emissions
will
increase
because
fuel
oil
typically
contains
more
nickel
than
coal.
Thus,
based
on
these
data,
we
believe
that
fuel
switching
among
coal
and
oil
is
not
an
effective
means
of
controlling
HAP
metal
emissions
(
including
mercury),
even
if
this
were
an
available
means
of
control.
For
new
as
well
as
existing
kilns,
we
considered
basing
the
floor
for
mercury
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Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
on
the
use
of
natural
gas,
although
the
few
mercury
emissions
data
we
have
cannot
allow
us
to
definitively
state
what
effect
fuel
type
has
on
emissions.
However,
we
do
not
regard
natural
gas
fuel
substitution
as
an
available
technology
for
new
sources.
Natural
gas
is
not
readily
available
throughout
the
U.
S.,
i.
e.,
the
infrastructure
for
its
delivery
(
pipelines,
pumping
stations,
etc.)
is
not
available
for
all
locations
where
lime
manufacturing
plants
exist
and
is
not
expected
to
be
economically
available
to
build
such
infrastructure
throughout
the
U.
S.
Although
U.
S.
natural
gas
reserves
may
be
considered
plentiful,
the
gas
still
needs
to
be
extracted
through
drilling
and
the
construction
of
wells.
Thus,
for
plants
located
far
from
a
natural
gas
pipeline,
natural
gas
is
not
a
reasonable
alternative.
Additionally,
although
the
infrastructure
(
pipelines,
wells,
storage
facilities)
can
be
built,
the
delivery
capacity
will
likely
not
be
available
to
accommodate
a
fuel
switch
to
natural
gas
within
the
time
frame
by
which
new
kilns
would
have
to
comply.
We
note
further
that
the
amounts
of
mercury
emitted
by
these
kilns
is
small,
roughly
one
pound
per
plant
per
year.
Although
the
floor
provisions
of
the
CAA
do
not
provide
a
de
minimis
exception
to
establishing
floors,
see
National
Lime
v.
EPA,
233
F.
3d
at
640,
the
small
amounts
of
mercury
emitted
reinforce
the
Agency's
technical
determinations
that
control
via
substitutions
of
feed
or
fuel
are
neither
feasible
nor
likely
to
be
effective
since
random
variability
in
these
feed
and
fuels
will
likely
result
in
equal
amounts
of
mercury
being
emitted
in
any
case.
Indeed,
it
is
the
Agency's
view
that
not
even
a
single
source
could
reliably
duplicate
its
own
performance
for
mercury
due
to
the
small
amounts
emitted
and
the
random
variability
of
fuels
and
feed.
3.
PM
and
Opacity
From
MPO
There
are
numerous
types
of
MPO
such
as
grinding
mills,
storage
bins,
conveying
systems
(
such
as
bucket
elevators
and
belt
conveyors),
transfer
points,
and
screening
operations
at
each
lime
manufacturing
plant.
We
investigated
whether
there
were
any
MPO
subject
to
standards
more
stringent
than
the
NSPS
subpart
OOO,
or
otherwise
performing
with
consistently
lower
emissions
than
required
by
the
NSPS
(
i.
e.,
performing
at
a
lower
level
without
being
subject
to
a
regulatory
limit),
that
would
serve
as
a
basis
for
a
MACT
floor.
To
this
end,
we
reviewed
the
applicable
requirements
for
lime
manufacturing
plants
located
in
nonattainment
areas
for
PM10
(
particulate
matter
with
an
aerodynamic
diameter
less
than
or
equal
to
10
microns),
since
presumably
these
areas
of
the
U.
S.
would
be
the
most
likely
to
have
more
stringent
PM
emission
limitations.
We
found
seven
lime
manufacturing
plants
located
in
PM10
nonattainment
areas.
The
information
available
to
us
on
these
plants
indicated
that
no
MPO
were
subject
to
standards
more
stringent
than
the
NSPS
subpart
OOO
or
otherwise
performing
better.
We
believe
that
the
NSPS
subpart
OOO
standards
reasonably
reflect
the
level
of
performance
achieved
by,
and
achievable
by,
the
average
of
the
best
performing
12
percent
of
sources.
The
basis
for
the
MACT
floor
for
these
emission
units
is
the
NSPS
subpart
OOO
as
it
has
been
applied
to
lime
manufacturing
plants,
which
serves
as
a
reasonable
measure
of
the
performance
of
the
average
of
the
best
performing
sources.
The
NSPS
subpart
OOO
sets
PM,
opacity,
and
visible
emission
limits
for
limestone
MPO
that
were
constructed,
reconstructed,
or
modified
after
August
31,
1983.
We
investigated
whether
enough
of
these
MPO
are
located
at
lime
manufacturing
plants
subject
to
the
NSPS
subpart
OOO
to
make
a
MACT
floor
determination.
Using
the
median
approach
to
determining
MACT
floors,
at
least
6
percent
would
need
to
be
subject
to
the
NSPS
subpart
OOO.
In
one
approach
to
estimating
the
number
of
MPO
at
lime
manufacturing
plants
that
are
subject
to
the
NSPS
subpart
OOO,
we
estimate
that
there
are
104
lime
manufacturing
plants
in
the
U.
S.,
and
that
at
least
seven
of
these
were
built
after
August
31,
1983.
All
of
the
MPO
associated
with
these
new,
greenfield
lime
manufacturing
plants
that
were
built
after
August
31,
1983,
would
be
subject
to
the
NSPS
subpart
OOO.
Therefore,
at
least
6.7
percent
(
7/
104)
of
the
MPO
are
subject
to
the
NSPS
subpart
OOO,
enough
for
the
NSPS
subpart
OOO
to
serve
as
a
basis
for
the
MACT
floor.
In
another
approach
to
estimating
the
percentage
of
lime
manufacturing
plant
MPO
that
are
subject
to
the
NSPS
subpart
OOO,
our
information
shows
that
at
least
31
lime
kilns
were
constructed
after
August
31,
1983,
out
of
a
total
of
about
257
lime
kilns
in
the
U.
S.
Assuming
that
the
MPO
associated
with
these
new
lime
kilns
are
also
new,
we
estimate
that
12.1
percent
(
31/
257)
of
the
MPO
are
subject
to
the
NSPS
subpart
OOO.
Thus,
with
either
approach
to
estimating
the
number
of
MPO
at
lime
manufacturing
plants
that
are
subject
to
the
NSPS
subpart
OOO,
there
are
enough
to
support
a
MACT
floor
determination.
Therefore,
the
MACT
floor
for
MPO
is
equivalent
to
the
NSPS
subpart
OOO.
E.
How
Did
We
Determine
the
MACT
Floor
for
Emission
Units
at
New
Lime
Manufacturing
Plants?
The
CAA
requires
the
MACT
floor
for
new
sources
to
be
based
on
the
degree
of
emissions
reductions
achieved
in
practice
by
the
best
controlled
similar
source.
For
HAP
metals
emissions
from
MPO
at
new
lime
manufacturing
plants,
the
floor
is
the
NSPS
subpart
OOO
(
the
same
as
for
MPO
at
existing
lime
manufacturing
plants).
As
discussed
previously,
we
investigated
whether
there
were
any
MPO
subject
to
standards
more
stringent
than
the
NSPS
subpart
OOO,
or
were
emitting
at
lower
rates
without
being
subject
to
some
type
of
regulatory
standards,
that
would
serve
as
a
basis
for
MACT
for
new
sources.
The
information
available
to
us
indicates
that
no
MPO
are
subject
to
standards
more
stringent
than
the
NSPS
subpart
OOO
or
otherwise
performing
better.
Therefore,
the
floor
is
the
NSPS
subpart
OOO.
For
HAP
metals
emissions
from
kilns
and
coolers,
the
floor
for
those
at
new
lime
manufacturing
plants
is
defined
by
the
permit
limits
and
emissions
data
for
PM,
where
PM
is
a
surrogate
for
nonmercury
HAP
metals.
As
previously
described
in
this
preamble,
the
MACT
floor
PM
emission
limit
for
lime
kilns
and
coolers
at
existing
lime
manufacturing
plants
would
be
0.12
lb
PM/
ton
limestone.
This
determination
was
based
on
the
median
approach,
i.
e.,
on
the
third
best
kiln
permit
limit
of
0.12
lb
PM/
ton
limestone.
For
kilns
at
new
lime
manufacturing
plants,
MACT
is
based
on
the
best
controlled
similar
source,
which
is
the
kiln
permitted
at
the
lowest
emission
limit
(
i.
e.,
0.10
lb
PM/
ton
limestone).
Test
data
for
this
kiln
indicated
that
the
emission
level
was
0.0925
lb
PM/
ton,
demonstrating
that
this
permit
limit
is
indeed
achievable,
and
that
the
permit
level
reasonably
approximates
the
level
of
performance
that
is
consistently
achievable
by
this
kiln
(
so
that
a
lower
floor
level
would
not
be
technically
justified).
Therefore,
the
emission
limit
for
kilns
and
coolers
at
a
new
lime
manufacturing
plant
is
0.10
lb/
ton
stone
feed.
As
with
the
existing
sources,
this
emission
limit
applies
to
the
combined
emissions
from
all
of
the
kilns
and
coolers
at
a
new
lime
manufacturing
plant.
As
previously
described
and
for
the
same
reasons
that
there
is
no
MACT
floor
for
mercury
for
kilns
at
existing
lime
manufacturing
plants,
and
the
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78061
Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
beyond
the
MACT
floor
options
considered
for
kilns
at
existing
lime
manufacturing
plants
are
not
justified,
there
is
no
MACT
for
mercury
for
kilns
at
new
sources.
F.
What
Control
Options
Beyond
the
MACT
Floor
Did
We
Consider?
Raw
material
feed
or
fuel
switching
may
be
considered
potential
beyondthe
floor
options
for
mercury,
but
as
previously
stated,
no
data
or
information
is
available
indicating
that
a
certain
type
of
limestone
or
source
of
limestone
has
a
lower
concentration
of
mercury
or
is
generally
available
throughout
the
country.
In
addition,
even
if
deposits
of
limestone
with
low
levels
of
mercury
were
to
be
found,
it
is
unlikely
that
the
limestone
would
be
in
close
proximity
to
the
majority
of
lime
manufacturing
plants
in
the
U.
S.
and,
thus,
the
cost
of
transporting
the
limestone
to
lime
manufacturing
plants
would
be
prohibitively
expensive.
(
There
would
also
be
increased
energy
use
associated
with
this
option
in
the
form
of
increased
fuel
use
to
transport
raw
materials.)
Most,
if
not
all,
lime
manufacturing
plants
are
sited
and
located
adjacent
to
or
in
close
proximity
to
their
source
of
limestone
(
usually
a
quarry
or
mine)
to
avoid
the
high
cost
of
transporting
the
material.
Regarding
fuel
switching
as
a
possible
mercury
MACT
floor
or
beyond
the
MACT
floor
option
for
existing
or
new
kilns,
using
a
fuel
with
a
lower
level
of
mercury,
such
as
natural
gas
(
instead
of
coal),
may
result
in
lower
lime
kiln
mercury
emissions.
However,
there
are
no
data
available
to
quantify
what
the
emissions
reductions
would
be
since
our
analysis
indicates
that
most
mercury
emissions
originate
from
the
limestone
feed
material
(
compared
with
coal),
and
so
the
emissions
reductions
that
would
be
achieved
via
switching
from
coal
to
natural
gas
are
uncertain.
Further,
as
explained
above,
natural
gas
is
not
readily
available
throughout
the
U.
S.
(
i.
e.,
the
infrastructure
for
its
delivery
(
pipelines,
pumping
stations,
etc.)),
is
not
available
for
all
locations
where
lime
manufacturing
plants
exist,
and
is
not
expected
to
be
economically
available
to
build
such
infrastructure
throughout
the
U.
S.
We
considered
another
beyond
the
MACT
floor
option
based
on
activated
carbon
injection
a
mercury
control
technology
currently
used
on
various
types
of
waste
combustors.
However,
based
on
the
already
relatively
low
levels
of
mercury
emissions
from
lime
kilns,
we
expect
that
relatively
low
emissions
reductions
would
be
achieved
from
this
technology.
(
Use
of
activated
carbon
injection
also
generates
a
mercury
bearing
waste
stream
to
be
disposed
of.)
The
few
mercury
emissions
data
available
(
four
data
points)
range
from
0.7
to
2.5
micrograms/
dry
standard
cubic
meter
(
referenced
to
7
percent
oxygen).
These
uncontrolled
levels
are
10
to
100
times
lower
than
the
mercury
emission
standards
established
for
various
types
of
waste
combustors
and
translate
to
an
average
annual
emission
rate
of
approximately
1
lb/
year
per
lime
kiln.
Thus,
this
beyond
the
floor
control
option
would
not
be
cost
effective
because
of
the
low
emissions
reductions
expected
and
the
high
cost
of
control.
Further,
use
of
activated
carbon
generates
an
additional
waste
to
be
disposed
of,
and
there
are
increases
in
energy
use
associated
with
the
technology.
After
considering
cost,
energy,
and
non
air
human
health
and
environmental
impacts,
our
initial
conclusion
is
that
basing
beyond
thefloor
standards
for
mercury
on
use
of
activated
carbon
is
not
warranted.
For
HAP
metal
(
PM)
emissions
from
the
kiln
and
MPO,
no
technologies
were
identified
that
would
perform
better
than
the
technologies
representative
of
the
MACT
floors
that
were
determined.
Raw
material
feed
or
fuel
switching
is
not
a
beyond
the
MACT
floor
option
for
PM
control
from
lime
kilns,
for
reasons
similar
as
to
why
it
is
not
an
option
for
mercury
control.
Regarding
feed
material
switching,
no
data
or
information
is
available
indicating
that
using
a
certain
type
or
source
of
limestone
would
have
a
lower
HAP
metals
content
or
would
lead
to
reduced
PM
emissions.
We
do
not
believe
that
such
deposits
of
limestone
exist
or
that
use
of
a
certain
type
of
limestone
would
consistently
result
in
lower
PM
or
metals
emissions.
Further,
assuming
there
was
a
widespread
source
of
limestone
with
a
lower
HAP
metals
content
(
which
is
highly
unlikely),
it
is
unclear
that
this
would
lead
to
lower
HAP
metals
emissions
(
or
what
the
reductions
of
the
HAP
metals
emissions
would
be)
since
HAP
metals
emissions
from
lime
kilns
would
also
originate
from
the
fuel.
In
addition,
even
if
deposits
of
limestone
with
low
levels
of
HAP
metals
or
a
lower
PM
producing
limestone
were
to
be
found,
the
cost
of
transporting
the
limestone
to
lime
manufacturing
plants
would
be
prohibitively
expensive.
In
addition,
as
noted
earlier,
there
would
be
increased
energy
usage
associated
with
the
transport
of
large
amounts
of
raw
materials.
Regarding
fuel
switching
as
a
possible
beyond
the
MACT
floor
option
for
HAP
metals,
using
a
fuel
with
a
lower
level
of
metals,
such
a
natural
gas
(
compared
to
coal),
may
result
in
lower
lime
kiln
metals
emissions.
However,
there
are
insufficient
data
available
to
quantify
what
the
emissions
reductions
would
be,
since
as
we
described
above,
lime
kiln
metals
emissions
also
originate
from
the
limestone
feed
material.
Further,
natural
gas
is
not
readily
available
throughout
the
U.
S.
(
i.
e.,
the
infrastructure
for
its
delivery
(
pipelines,
pumping
stations,
etc.))
and
may
not
be
available
for
all
locations
where
lime
manufacturing
plants
exist.
Further,
the
cost
of
using
natural
gas
may
be
prohibitively
expensive
as
the
cost
of
natural
gas
continues
to
rise
as
the
growing
demand
for
it
rises
as
well.
We
do
not
regard
this
as
an
available
means
of
control
for
this
source
category.
See
also
the
discussion
above
as
to
why
the
use
of
natural
gas
is
not
a
viable
control
option
for
mercury;
this
rationale
also
applies
to
the
use
of
natural
gas
as
a
beyond
the
floor
option
for
PM
and
non
mercury
HAP
metals.
Consequently,
we
are
not
proposing
any
beyond
the
floor
standard
for
HAP
metal
control
based
on
requiring
the
use
of
natural
gas
rather
than
other
fossil
fuels.
Therefore,
the
Agency
is
proposing
that
the
floor
standard
for
mercury
reflect
no
existing
reduction
and
after
considering
the
factors
set
out
in
CAA
section
112
(
d)(
2),
that
no
beyond
thefloor
alternatives
are
achievable.
G.
How
Did
We
Select
the
Format
of
the
Proposed
Rule?
The
formats
selected
for
the
proposed
emission
limits
vary
according
to
the
emission
source,
pollutant,
and
the
MACT
basis
for
the
limits.
The
formats
selected
include
a
production
based
emission
limit,
pollutant
concentration
limits,
and
opacity
limits.
For
the
kiln
PM
standard,
the
``
lb
PM/
ton
limestone''
format
was
selected
to
be
consistent
with
the
NSPS
for
lime
manufacturing
plants,
40
CFR
60,
subpart
HH.
This
format
also
encourages
kiln
energy
efficiency.
A
more
energy
efficient
kiln
emits
less
exhaust
gas
per
ton
of
limestone
processed,
which
results
in
a
higher
gas
concentration
of
PM
compared
to
a
less
energy
efficient
kiln
for
the
same
amount
of
lime
produced
and
PM
emitted.
A
concentration
format
(
e.
g.,
grains
PM/
dry
standard
cubic
foot)
would
penalize
more
energy
efficient
kilns.
For
the
PM
and
opacity
standards
for
MPO,
a
concentration
format
for
PM
and
the
opacity
limit
requirements
were
selected
to
be
consistent
with
the
NSPS
for
nonmetallic
minerals
processing,
40
CFR
part
60,
subpart
OOO.
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/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
H.
How
Did
We
Select
the
Test
Methods
and
Monitoring
Requirements
for
Determining
Compliance
With
the
Proposed
Rule?
1.
PM
From
the
Kiln
and
Cooler
Today's
proposed
rule
would
require
you
to
conduct
a
PM
performance
test
and
concurrently
measure
the
stone
feed
rate
to
the
kiln
during
the
test.
If
you
operate
a
lime
cooler
associated
with
the
kiln
being
tested
that
has
a
separate
exhaust
to
the
atmosphere,
you
would
be
required
to
conduct
a
Method
5
(
40
CFR
part
60,
appendix
A
3)
test
on
the
cooler's
exhaust
concurrently
with
the
kiln
Method
5
test.
Method
5
is
the
long
standing
EPA
method
for
measuring
PM
emissions
from
stationary
sources.
For
each
kiln
with
an
ESP,
if
you
choose
to
monitor
ESP
operating
parameters
in
lieu
of
using
a
PM
detector
or
a
COMS,
you
would
be
required
to
collect
and
record
the
input
voltage
and
current
to
each
electrical
field
of
the
ESP
during
the
PM
performance
test,
and
then
determine
the
3
hour
operating
limit
for
each
parameter
for
each
electrical
field
based
on
these
data.
We
expect
that
most
lime
manufacturing
plants
with
ESP
already
monitor
the
electrical
current
and
voltage,
which
provides
an
indication
of
the
ESP
performance
and
consequently
PM
emissions
as
well.
For
continuous
compliance
demonstrations,
you
would
be
required
to
maintain
the
3
hour
rolling
average
current
and
voltage
input
to
each
electrical
field
of
the
ESP
greater
than
or
equal
to
the
average
current
and
voltage
input
to
each
field
of
the
ESP
as
established
during
the
performance
test.
You
would
be
required
to
collect
and
reduce
the
data
as
previously
described.
A
3
hour
rolling
average
was
selected
to
be
consistent
with
the
usual
3
hour
time
required
for
the
PM
test
(
three
test
runs
of
at
least
1
hour).
You
would
also
have
the
option
of
monitoring
PM
emissions
from
an
ESP
with
a
PM
detector,
in
lieu
of
monitoring
ESP
parameters.
Sources
may
determine
that
this
would
allow
them
greater
operational
flexibility.
These
devices
would
be
similar
to
the
BLDS
for
FF,
which
are
discussed
below,
but
they
are
based
on
light
scattering
technology
(
and
not
the
triboelectric
technology).
For
each
kiln
with
a
wet
scrubber,
you
would
be
required
to
collect
and
record
the
exhaust
gas
stream
pressure
drop
across
the
scrubber
and
the
scrubber
liquid
flow
rate
during
the
PM
performance
test,
and
then
establish
the
3
hour
operating
limit
for
each
of
these
parameters
based
on
the
data.
Pressure
drop
and
flow
rate
are
the
scrubber
operating
parameters
most
often
monitored
and
provide
an
indication
of
the
scrubber's
performance
and
consequently
PM
emissions
as
well.
For
continuous
compliance
demonstrations,
you
would
be
required
to
maintain
the
3
hour
rolling
average
pressure
drop
and
flow
rate
greater
than
or
equal
to
the
operating
limit
established
for
these
parameters
during
the
performance
test.
You
would
be
required
to
collect
and
reduce
the
data
as
previously
described.
For
kilns
and
lime
coolers
(
if
the
cooler
has
a
separate
exhaust
to
the
atmosphere)
controlled
by
a
FF,
if
you
choose
not
to
use
a
COMS,
you
would
be
required
to
install
a
BLDS.
These
systems
are
usually
based
on
either
triboelectric,
electrodynamic,
or
light
scattering
technology
and
provide
an
indication
of
relative
changes
in
particle
mass
loading.
Leaks
in
filter
bags
or
similar
failures
can
be
detected
early
enough
to
warn
if
additional
inspection
and
preventative
maintenance
are
needed
to
avoid
major
FF
failures
and
excessive
emissions.
When
the
system
detects
an
increase
in
relative
PM
emissions
greater
than
a
preset
level,
an
alarm
sounds
automatically.
The
FF
would
be
required
to
then
be
inspected
to
determine
if
corrective
action
is
necessary.
We
believe
that
the
monitoring
of
PM
via
BLDS
is
more
appropriate,
i.
e.,
a
better
technique,
than
monitoring
FF
operating
parameters
such
as
pressure
drop.
Some
other
MACT
standards
require
the
use
of
these
types
of
monitors.
It
should
be
noted
that
BLDS
would
also
be
required
on
positive
pressure
FF,
which
typically
have
multiple
stacks.
We
specifically
seek
comment
on
the
feasibility,
practicality,
and
cost
of
using
BLDS
for
these
types
of
FF;
and
on
alternative
monitoring
options
for
positive
pressure
FF
that
will
provide
a
continuous
indication
of
a
kiln
or
cooler's
compliance
status
with
regard
to
PM.
We
also
seek
comment
on
whether
EPA
Method
9,
40
CFR
part
60,
appendix
A
4
(
manual
observation
of
opacity)
should
be
allowed
in
lieu
of
BLDS
for
positive
pressure
FF.
We
are
soliciting
comment
on
requiring
the
application
of
PM
continuous
emission
monitoring
systems
(
CEMS)
as
a
method
to
assure
continuous
compliance
with
the
proposed
PM
emission
limits
for
lime
kilns
and
coolers.
Specifically,
we
are
soliciting
comment
on
the
cost
of
PM
CEMS,
and
the
relation
of
a
PM
CEMS
requirement
to
the
PM
emission
limits
that
are
proposed
today.
This
includes
the
level
and
averaging
time
of
a
CEMSbased
PM
emission
limit,
the
methodology
for
deriving
the
limit
from
the
available
data
for
lime
kilns,
and
any
additional
emissions
reductions
that
could
be
expected
as
a
result
of
using
a
PM
CEMS.
We
have
continued
to
learn
about
the
capabilities
and
performance
of
PM
CEMS
through
performing
and
witnessing
field
evaluations
and
through
discussions
with
our
European
counterparts.
We
believe
there
is
sound
evidence
that
PM
CEMS
should
work
on
lime
kilns.
See
the
revisions
we
made
to
the
performance
specification
for
PM
CEMS
(
Performance
Specification
11
(
PS
11),
40
CFR
part
60,
appendix
B,
and
Procedure
2,
40
CFR
part
60,
appendix
F)
at
66
FR
64176,
December
12,
2001.
During
the
review
of
a
draft
of
the
proposed
rule
by
the
SBAR
Panel,
small
entity
representatives
and
some
Panel
members
requested
that
we
consider
allowing
COMS
in
lieu
of
requiring
BLDS
and
other
monitoring
requirements
for
PM.
The
proposed
rule
would
allow
the
use
of
COMS
as
an
alternative
to
BLDS,
PM
detectors,
or
the
monitoring
of
ESP
operating
parameters.
However,
we
request
summary
data
on
lime
kiln
opacity
levels
measured
with
a
COMS,
and
we
request
information
on
the
applicability,
advantages,
and
disadvantages
of
using
COMS
and
BLDS
(
such
as
each
method's
sensitivity
or
lack
of
sensitivity,
availability
and
quality
of
promulgated
or
approved
specifications
and
procedures
to
verify
initial
performance,
potential
interferences
or
other
quality
assurance
problems,
inapplicability
to
certain
APCD
designs
or
configurations,
cost,
and
precision
and
accuracy
relative
to
the
operating
system
to
be
monitored
and
the
standards
to
be
proposed).
The
proposed
rule
would
allow
sources
with
FF
or
ESP
to
comply
with
a
15
percent
opacity
operating
limit,
as
an
alternative
to
using
a
BLDS,
a
PM
detector,
or
the
use
of
ESP
operating
parameters.
We
request
comment
on
using
a
COMS
to
monitor
opacity
as
an
emission
limit
(
which
would
act
as
a
surrogate
for
HAP
metals
emissions),
rather
than
as
an
operating
limit,
and
what
an
appropriate
MACT
floor
opacity
limit
would
be.
The
range
of
opacity
levels
under
consideration
as
the
MACT
floor
opacity
limit
for
lime
kilns
would
be
between
10
and
15
percent.
Sensitivity
for
COMS
is
dependent
on
the
path
length
that
the
light
beam
measures;
the
longer
the
path
length,
the
more
sensitive
the
measurement.
Performance
Specification
1
(
PS
1),
40
CFR
part
60,
Appendix
B,
gives
the
performance
criteria
for
COMS
used
to
measure
opacity
for
opacity
limitation
standards
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Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
but
we
recognize
that
there
are
potential
measurement
errors
associated
with
monitoring
opacity
in
stacks,
especially
for
emission
units
subject
to
opacity
limits
less
than
10
percent.
The
uncertainties
in
measurement
accuracy
result
from
the
following:
(
1)
The
unavailability
of
calibration
attenuators
for
opacity
levels
below
6
percent;
(
2)
the
error
associated
with
the
calibration
error
allowances,
the
zero
and
upscale
drift
specifications,
the
mandatory
drift
adjustment
levels,
and
the
imprecision
associated
with
the
allowed
compensation
for
dirt
accumulation;
and
(
3)
the
minimum
full
scale
range
of
80
percent
required
of
COMS
in
PS
1.
Because
of
these
aforementioned
limitations,
COMS
are
generally
considered
good
``
catastrophic''
control
equipment
indicators
using
opacity
generally
above
levels
greater
than
10
percent
opacity.
A
15
percent
opacity
level
is
the
opacity
limit
under
the
NSPS
for
lime
kilns
(
40
CFR
part
60,
subpart
HH)
and
based
on
a
preliminary
analysis,
may
also
be
the
median
opacity
permit
limit
for
the
six
top
performing
lime
kilns.
In
addition,
the
NLA
provided
information
indicating
that
the
opacity
level
of
one
of
the
top
performing
lime
kilns
(
in
terms
of
PM
emissions
and
permit
limit)
often
varies
between
10
and
15
percent.
Finally,
we
acknowledge
that
other
MACT
standards,
such
as
the
Petroleum
Refinery
MACT
(
67
FR
17761)
and
the
Secondary
Aluminum
MACT
(
65
FR
15690),
have
allowed
the
use
of
COMS.
In
the
Petroleum
Refinery
MACT,
the
rule
allows
sources
the
option
to
comply
with
the
NSPS
(
40
CFR
part
60,
subpart
J)
emission
limitations
(
which
includes
various
opacity
limits
for
certain
emission
units)
in
order
to
comply
with
the
MACT
standard.
Another
approach
to
using
a
COMS
that
was
raised
by
some
SBAR
Panel
members
was
to
use
it
in
a
way
similar
to
how
a
BLDS
would
be
used
to
indicate
the
need
for
inspection
and
maintenance
of
the
PM
control
device.
Under
this
approach,
we
would
specify
a
time
period
over
which
a
significant
increase
in
opacity
level
would
trigger
inspection
of
the
PM
control
device
for
leaks
or
other
malfunctions
and
maintenance
(
if
needed).
We
recognize
that
the
COMS
currently
being
used
in
the
lime
manufacturing
industry
have
a
potential
for
error
at
opacities
below
10
percent,
and
that
the
relevant
range
of
opacities
for
the
aforementioned
application
would
be
below
10
percent.
If
COMS
were
allowed
under
the
final
rule,
we
would
prefer
to
set
an
opacity
limit
because
of
the
COMS'
ability
to
directly
measure
opacity,
instead
of
using
the
COMS
in
the
aforementioned
way
(
i.
e.,
similar
to
how
a
BLDS
would
be
used).
However,
we
solicit
comment
on
this
option,
specifically
including
comments
regarding
the
opacity
levels
expected
from
a
kiln
in
compliance
with
the
proposed
PM
limit
and
the
sensitivity
of
COMS
at
those
levels.
In
accordance
with
the
SBAR
Panel's
recommendations,
we
request
comment
on
whether
the
proposed
rule
should
specify
separate,
longer
averaging
time
periods
(
or
greater
frequencies
of
occurrence)
for
demonstrating
compliance
with
operating
parameter
limits,
or
other
alternative
approaches
for
demonstrating
compliance
with
operating
parameter
limits.
For
example,
the
Panel
recommended
that
we
request
comment
on
an
approach
for
demonstrating
compliance
involving
two
tiers
of
standards
for
monitoring
operating
parameters
whereby,
if
the
conditions
of
the
first
monitoring
tier
are
exceeded,
the
facility
operator
would
be
required
to
implement
corrective
actions
specified
in
an
established
plan
to
bring
the
operating
parameter
levels
back
to
established
levels
and,
if
the
conditions
of
the
second
tier
are
exceeded,
the
exceedance
would
constitute
a
violation
of
the
standard
in
question.
The
SBAR
Panel
recommended
that
we
take
comment
about
the
suitability
of
other
PM
control
device
operating
parameters
that
could
be
monitored
to
demonstrate
compliance
with
the
PM
emission
limits
in
lieu
of
or
in
addition
to
the
parameters
proposed
in
today's
rule.
For
example,
small
entity
representatives
suggested
that
for
scrubber
equipped
kilns,
we
should
consider
allowing
the
monitoring
of
parameters
such
as
wet
scrubber
water
pump
amperage
and
wet
scrubber
exhaust
gas
outlet
temperature
in
lieu
of
scrubber
liquid
flow
rate.
In
addition,
sources
may
request
approval
of
alternative
monitoring
methods
according
to
section
40
CFR
63.8(
f).
2.
PM
From
MPO
Since
the
MACT
basis
for
these
emission
units
is
the
NSPS
subpart
OOO,
the
performance
test
requirements
for
PM,
opacity,
and
visible
emissions
are
based
in
part
on
those
in
the
NSPS
subpart
OOO,
with
additional
requirements
as
well.
Further,
as
is
required
under
the
NSPS
subpart
OOO,
the
proposed
rule
would
require
the
performance
test
measurement
of
opacity
from
certain
MPO,
including
fugitive
emission
units,
using
EPA
Method
9,
40
CFR
part
60,
appendix
A.
We
request
comment
on
the
suitability
of
using
Method
9
for
fugitive
emission
units,
and
whether
other
visual
opacity
measurement
methods
or
techniques
may
be
more
suitable,
such
as
provisions
from
proposed
EPA
Methods
203A,
203B,
and/
or
203C,
58
FR
61640,
January
6,
1994.
For
MPO
subject
to
a
PM
emission
limit
and
controlled
by
a
wet
scrubber,
you
would
be
required
to
collect
and
record
the
exhaust
gas
stream
pressure
drop
across
the
scrubber
and
the
scrubber
liquid
flow
rate
during
the
PM
performance
test
and
then
establish
the
3
hour
operating
limit
for
each
of
these
parameters
based
on
the
data.
Pressure
drop
and
flow
rate
provide
an
indication
of
the
scrubber's
performance
and
consequently
PM
emissions
as
well.
For
MPO
subject
to
opacity
limitations
which
do
not
use
a
wet
scrubber
control
device,
you
would
be
required
to
conduct
a
1
minute
visible
emissions
check
of
each
emission
unit
similar
to
the
requirements
under
Method
22,
40
CFR
part
60,
appendix
A7.
The
frequency
of
these
checks
is
monthly
but
diminishes
for
the
emission
unit
if
no
visible
emissions
are
observed.
If
visible
emissions
are
observed
during
any
visible
emissions
check,
you
would
be
required
to
conduct
a
6
minute
test
of
opacity
in
accordance
with
Method
9
of
appendix
A
to
part
60
of
this
chapter.
The
Method
9
test
would
be
required
to
begin
within
1
hour
of
any
observation
of
visible
emissions
and
the
6
minute
opacity
reading
would
be
required
to
not
exceed
the
applicable
opacity
limit.
Due
to
the
many
MPO
at
each
lime
manufacturing
plant,
this
type
of
periodic
monitoring
for
opacity
was
selected.
This
periodic
approach
to
monitoring
rewards
sources
that
have
no
visible
emissions
by
allowing
the
frequency
of
testing
to
be
reduced.
Finally,
this
monitoring
approach
(
visual
observations
of
opacity
instead
of
continuous
opacity
monitoring
systems)
is
similar
to
the
monitoring
regime
used
in
the
NSPS
subpart
OOO,
which
is
the
basis
for
MACT.
Although
we
are
not
compelled
to
use
identical
monitoring
regimes,
we
believe
it
is
appropriate
to
do
so
here
because
it
will
``
reasonably
ensure
compliance
with
the
standard.''
See
National
Lime,
233
F.
3d
at
635.
3.
Other
General
Requirements
The
operations,
maintenance,
and
monitoring
plan
would
be
required
to
ensure
effective
performance
of
the
air
pollution
control
devices,
monitoring
equipment
(
including
bag
leak
and
PM
detection
equipment),
and
to
minimize
malfunctions.
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/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
IV.
Summary
of
Environmental,
Energy
and
Economic
Impacts
A.
How
Many
Facilities
Are
Subject
to
the
Proposed
Rule?
There
are
approximately
110
lime
manufacturing
plants
in
the
U.
S.,
not
including
lime
production
facilities
at
pulp
and
paper
mills.
About
30
of
these
110
plants
are
located
at
beet
sugar
manufacturing
facilities
which
would
not
be
subject
to
the
proposed
rule.
We
estimate
that
70
percent
of
the
remaining
80
lime
manufacturing
plants
would
be
major
sources,
co
located
with
major
sources,
or
part
of
major
sources,
and,
thus,
56
lime
manufacturing
plants
would
be
subject
to
this
proposed
rule.
B.
What
Are
the
Air
Quality
Impacts?
We
estimate
that
all
sources
(
not
including
lime
manufacturing
plants
at
beet
sugar
factories)
in
the
lime
manufacturing
source
category
collectively
emit
approximately
9,700
Mg/
yr
(
10,700
tons/
yr)
of
HAP.
These
HAP
estimates
include
emissions
of
HCl
and
HAP
metals
from
existing
sources
and
projected
new
sources
over
the
next
5
years.
We
estimate
that
the
proposed
standards
would
reduce
HAP
metals
emissions
from
the
lime
manufacturing
source
category
by
about
21
Mg/
yr
(
23
tons/
yr),
and
would
reduce
HCl
emissions
by
about
213
Mg/
yr
(
235
tons/
yr).
In
addition,
we
estimate
that
the
proposed
standards
would
reduce
PM
emissions
by
about
14,000
Mg/
yr
(
16,000
tons/
yr)
from
a
baseline
level
of
29,000
Mg/
yr
(
32,000
tons/
yr),
and
the
proposed
standards
would
reduce
SO2
emissions
by
about
3,400
Mg/
yr
(
3,700
tons/
yr)
from
a
baseline
of
128,000
Mg/
yr
(
141,000
tons/
yr).
The
roughly
2
percent
decrease
in
HCl
and
SO2
emissions
is
the
projected
result
of
uncontrolled
sources
installing
baghouses
to
comply
with
the
proposed
PM
standards.
Tables
1
and
2
summarize
the
baseline
emissions
and
emissions
reductions
(
or
increases,
in
parentheses)
estimates,
in
English
and
Metric
units,
respectively.
TABLE
1.
TOTAL
NATIONAL
BASELINE
EMISSIONS
AND
EMISSIONS
REDUCTIONS
FOR
BOTH
NEW
AND
EXISTING
LIME
MANUFACTURING
PLANTS
[
English
Units]
Emissions
PM
(
tons/
yr)
HAP
metals
(
tons/
yr)
HCl
(
tons/
yr)
SO2
(
tons/
yr)
Baseline
emissions
existing
sources
..........................................................................
24,352
31.5
8,541
112,198
Baseline
emissions
new
sources
................................................................................
7,508
10.1
2,161
28,779
Total
baseline
emissions
...............................................................................................
31,861
41.6
10,702
140,977
Emissions
reductions
existing
sources
......................................................................
12,407
17.7
235
3,700
Emissions
reductions
new
sources
.............................................................................
3,154
5.4
0
0
Total
emissions
reductions
............................................................................................
15,561
23
235
3,700
TABLE
2.
TOTAL
NATIONAL
BASELINE
EMISSIONS
AND
EMISSIONS
REDUCTIONS
FOR
BOTH
NEW
AND
EXISTING
LIME
MANUFACTURING
PLANTS
[
Metric
Units]
Emissions
PM
(
Mg/
yr)
HAP
metals
(
Mg/
yr)
HCl
(
Mg/
yr)
SO2
(
Mg/
yr)
Baseline
emissions
existing
sources
..........................................................................
22,093
28.6
7,748
101,787
Baseline
emissions
new
sources
................................................................................
6,811
9.2
1,961
26,108
Total
baseline
emissions
...............................................................................................
28,904
38
9,709
127,895
Emissions
reductions
existing
sources
.......................................................................
11,256
16
213
3,356
Emissions
reductions
new
sources
.............................................................................
2,861
4.9
0
0
Total
emissions
reductions
............................................................................................
14,117
21
213
3,356
C.
What
Are
the
Water
Impacts?
We
expect
overall
water
consumption
for
existing
sources
to
increase
by
about
4,200
million
gallons
per
year
from
current
levels
as
a
result
of
the
proposed
rule.
This
estimate
is
based
on
the
assumption
that
sources
will
replace
existing
wet
scrubbers
with
new,
more
efficient
venturi
wet
scrubbers
(
that
require
more
water
flow
rate)
to
comply
with
the
PM
standards.
For
new
sources,
we
expect
no
additional
water
consumption
as
we
do
not
expect
new
sources
to
install
wet
scrubbers
for
PM
control.
D.
What
Are
the
Solid
Waste
Impacts?
As
a
result
of
the
proposed
rule,
solid
waste
would
be
generated
as
additional
PM
is
collected
in
complying
with
the
PM
standards.
We
estimate
that
about
16,000
tons/
yr
of
additional
solid
waste
would
be
generated
as
a
result
of
today's
proposed
rule.
This
estimate
does
not
include
consideration
that
some
of
this
would
most
likely
be
recycled
directly
to
the
lime
kiln
as
feedstock
or
sold
as
byproduct
material
(
agricultural
lime).
E.
What
Are
the
Energy
Impacts?
We
expect
electricity
demand
from
existing
sources
to
increase
by
about
7.2
million
kilowatt
hours/
yr
(
kWh/
yr)
as
a
result
of
the
proposed
rule.
This
estimate
is
based
on
the
assumption
that
sources
will
replace
existing
wet
scrubbers
with
new,
more
efficient
venturi
wet
scrubbers
(
that
require
more
electricity).
For
new
sources,
we
expect
an
increase
in
electricity
usage
of
about
0.1
million
kWh/
yr
as
a
result
of
the
proposed
rule.
This
electricity
demand
is
associated
with
complying
with
the
PM
standards
for
new
sources.
F.
What
Are
the
Cost
Impacts?
The
estimated
total
national
capital
cost
of
today's
proposed
rule
is
$
24.2
million
(
for
large
businesses)
plus
$
11.9
million
for
small
businesses
for
a
total
of
$
36.1
million.
This
capital
cost
applies
to
projected
new
and
existing
sources
and
includes
the
cost
to
purchase
and
install
emissions
control
equipment
(
e.
g.,
existing
PM
control
equipment
upgrades),
monitoring
equipment
(
the
cost
of
the
rule
is
estimated
assuming
bag
leak
and
PM
detectors
would
be
installed
on
all
lime
kilns
located
at
major
sources,
although
other
monitoring
options
are
available,
such
as
COMS),
the
costs
of
initial
performance
tests,
and
emissions
tests
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245
/
Friday,
December
20,
2002
/
Proposed
Rules
to
measure
HCl
to
determine
whether
a
source
is
a
major
source
and
hence
subject
to
the
standards.
The
estimated
annualized
costs
of
the
proposed
standards
are
$
22.4
million.
The
annualized
costs
account
for
the
annualized
capital
costs
of
the
control
and
monitoring
equipment,
operation
and
maintenance
costs,
periodic
monitoring
of
materials
handling
operations,
and
annualized
costs
of
the
initial
emissions
testing.
G.
What
Are
the
Economic
Impacts?
The
results
of
our
economic
impact
analysis
indicate
the
average
price
per
ton
for
lime
would
increase
by
2.1
percent
(
or
$
1.17
per
metric
ton)
as
a
result
of
the
proposed
standard
for
lime
manufacturers.
Overall
lime
production
is
projected
to
decrease
by
1.8
percent
as
a
result
of
the
proposed
standard.
Because
of
the
uncertainty
of
control
cost
information
for
large
firms,
we
accounted
for
these
firms
as
a
single
aggregate
firm
in
the
economic
model,
so
it
is
not
plausible
to
estimate
closures
for
large
firms.
However,
among
the
19
small
firms
in
this
industry,
we
project
that
two
firms
are
at
risk
for
closure.
Based
on
the
market
analysis,
we
project
the
annual
social
costs
of
the
proposed
rule
to
be
$
20.2
million.
As
a
result
of
higher
prices
and
lower
consumption
levels,
we
project
the
consumers
of
lime
(
both
domestic
and
foreign)
would
lose
$
19.7
million
annually,
while
domestic
producer
surplus
would
decline
by
$
0.8
million.
Foreign
producers
would
gain
as
a
result
of
the
proposed
regulation
with
profit
increasing
by
$
0.2
million.
For
more
information
regarding
the
economic
impacts,
consult
the
economic
impact
analysis
in
the
docket
for
this
rule.
V.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
we
would
be
required
to
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(
2)
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(
3)
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligation
of
recipients
thereof;
or
(
4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
OMB
has
notified
EPA
that
it
considers
this
a
``
significant
regulatory
action''
within
the
meaning
of
the
Executive
Order.
The
EPA
has
submitted
the
action
to
OMB
for
review.
Changes
made
in
response
to
OMB
suggestions
or
recommendations
will
be
documented
in
the
docket
(
see
ADDRESSEES
section
of
this
preamble).
B.
Executive
Order
13132,
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
us
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
Under
Section
6
of
Executive
Order
13132,
we
may
not
issue
a
regulation
that
has
federalism
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,
unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
State
and
local
governments,
or
we
consult
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
We
also
may
not
issue
a
regulation
that
has
federalism
implications
and
that
preempts
State
law
unless
the
Agency
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
If
we
comply
by
consulting,
Executive
Order
13132
requires
us
to
provide
to
OMB,
in
a
separately
identified
section
of
the
preamble
to
the
rule,
a
federalism
summary
impact
statement
(
FSIS).
The
FSIS
would
be
required
to
include
a
description
of
the
extent
of
our
prior
consultation
with
State
and
local
officials,
a
summary
of
the
nature
of
their
concerns
and
the
agency's
position
supporting
the
need
to
issue
the
regulation,
and
a
statement
of
the
extent
to
which
the
concerns
of
State
and
local
officials
have
been
met.
Also,
when
we
transmit
a
draft
final
rule
with
federalism
implications
to
OMB
for
review
pursuant
to
Executive
Order
12866,
we
would
be
required
to
include
a
certification
from
the
Agency's
Federalism
Official
stating
that
we
have
met
the
requirements
of
Executive
Order
13132
in
a
meaningful
and
timely
manner.
The
proposed
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
The
proposed
rule
would
not
impose
directly
enforceable
requirements
on
States,
nor
would
it
preempt
them
from
adopting
their
own
more
stringent
programs
to
control
emissions
from
lime
manufacturing
facilities.
Moreover,
States
are
not
required
under
the
CAA
to
take
delegation
of
federal
NESHAP
and
bear
their
implementation
costs,
although
States
are
encouraged
and
often
choose
to
do
so.
Thus,
Executive
Order
13132
does
not
apply
to
the
proposed
rule.
Although
it
does
not
apply
to
the
proposed
rule,
we
have
coordinated
with
State
and
local
officials
in
the
development
of
the
proposed
rule
and
we
are
providing
them
an
opportunity
for
comment.
A
summary
of
the
concerns
raised
during
the
notice
and
comment
process
and
our
response
to
those
concerns
will
be
provided
in
the
final
rulemaking
notice.
In
the
spirit
of
Executive
Order
13132,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
State
and
local
governments,
EPA
specifically
solicits
comment
on
the
proposed
rule
from
State
and
local
officials.
C.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
9,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
This
proposed
rule
does
not
have
tribal
implications,
as
specified
in
Executive
Order
13175.
There
are
no
lime
manufacturing
plants
located
on
tribal
land.
Thus
Executive
Order
13175
does
not
apply
to
the
proposed
rule.
The
EPA
specifically
solicits
additional
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Federal
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/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
comment
on
the
proposed
rule
from
tribal
officials.
D.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
we
have
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
we
would
be
required
to
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
us.
We
interpret
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
501
of
the
Executive
Order
has
the
potential
to
influence
the
regulation.
The
proposed
rule
is
not
subject
to
Executive
Order
13045
because
it
is
based
on
technology
performance
and
not
on
health
or
safety
risks.
Additionally,
the
proposed
rule
is
not
economically
significant
as
defined
by
Executive
Order
12866.
E.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
we
generally
would
be
required
to
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
by
State,
local,
and
tribal
governments,
in
aggregate,
or
by
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
us
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
us
to
adopt
an
alternative
other
than
the
leastcostly
most
cost
effective,
or
leastburdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
we
establish
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
we
would
be
required
to
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
would
be
required
to
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
our
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
We
have
determined
that
the
proposed
rule
does
not
contain
a
Federal
mandate
that
may
result
in
expenditures
of
$
100
million
or
more
by
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
The
total
cost
to
the
private
sector
is
approximately
$
22.4
million
per
year.
The
proposed
rule
contains
no
mandates
affecting
State,
local,
or
tribal
governments.
Thus,
today's
proposed
rule
is
not
subject
to
the
requirements
of
sections
202
and
205
of
the
UMRA.
We
have
determined
that
the
proposed
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments
because
it
contains
no
requirements
that
apply
to
such
governments
or
impose
obligations
upon
them.
F.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
(
SBREFA)
of
1996,
5
U.
S.
C.
601
et
seq.
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
proposed
rule
on
small
entities,
a
small
entity
is
defined
as
(
1)
A
small
business
as
a
lime
manufacturing
company
with
less
than
500
employees;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
for
profit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Despite
the
determination
that
the
proposed
rule
would
have
no
significant
impact
on
a
substantial
number
of
small
entities,
EPA
prepared
a
Small
Business
Flexibility
Analysis
that
has
all
the
components
of
an
initial
regulatory
flexibility
analysis
(
IRFA).
An
IRFA
examines
the
impact
of
the
proposed
rule
on
small
entities
along
with
regulatory
alternatives
that
could
reduce
that
impact.
The
Small
Business
Flexibility
Analysis
(
which
is
included
in
the
economic
impact
analysis)
is
available
for
review
in
the
docket,
and
is
summarized
below.
Based
on
SBA's
size
definitions
for
the
affected
industries
and
reported
sales
and
employment
data,
EPA
identified
19
of
the
45
companies
owning
potentially
affected
facilities
as
small
businesses.
Eight
of
these
45
companies
manufacture
beet
sugar
(
which
would
not
be
subject
to
this
proposed
rule),
three
of
which
are
small
firms.
Further,
an
additional
3
of
the
19
small
companies
would
not
be
subject
to
the
proposed
rule
because
they
do
not
manufacture
lime
in
a
kiln
(
e.
g.,
they
are
only
depot
or
hydration
facilities),
and/
or
we
do
not
expect
them
to
be
major
sources.
It
is
therefore
expected
that
13
small
businesses
would
be
subject
to
this
proposed
rule.
Although
small
businesses
represent
40
percent
of
the
companies
within
the
source
category,
they
are
expected
to
incur
30
percent
of
the
total
industry
annual
compliance
costs
of
$
22.4
million.
The
economic
impact
analysis
we
prepared
for
this
proposed
rule
includes
an
estimate
of
the
changes
in
product
price
and
production
quantities
for
the
firms
that
this
proposed
rule
would
affect.
The
analysis
shows
that
of
the
facilities
owned
by
potentially
affected
small
firms,
two
may
shut
down
rather
than
incur
the
cost
of
compliance
with
the
proposed
rule.
Because
of
the
nature
of
their
production
processes
and
existing
controls,
we
expect
these
two
firms
will
incur
significantly
higher
compliance
costs
than
the
other
small
firms.
Although
any
facility
closure
is
cause
for
concern,
it
should
be
noted
that
in
general,
the
burden
on
most
small
firms
is
low
when
compared
to
that
of
large
firms.
The
average
annual
compliance
costs
for
all
small
firms
is
$
358,000,
compared
to
$
592,000
per
year
for
large
firms.
If
the
two
small
firms
expected
to
incur
significantly
higher
control
costs
are
excluded,
the
average
annual
compliance
cost
for
the
remaining
firms
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Proposed
Rules
would
be
$
205,000,
which
is
much
less
than
the
average
control
costs
for
large
firms.
The
EPA's
efforts
to
minimize
small
business
impacts
have
materially
improved
today's
proposal.
Economic
analysis
of
provisions
under
earlier
consideration
for
inclusion
in
this
proposed
rule
indicated
greater
impacts
on
small
businesses
than
those
proposed
today.
For
the
small
companies
expected
to
incur
compliance
costs,
the
average
total
annual
compliance
cost
would
have
been
roughly
$
567,000
per
small
company
(
compared
with
$
358,000
in
today's
proposal).
About
85
percent
(
11
firms)
of
those
small
businesses
expected
to
incur
compliance
costs
would
have
experienced
an
impact
greater
than
1
percent
of
sales
(
compared
with
69
percent
of
those
small
businesses
in
today's
proposal).
And
77
percent
(
10
firms)
of
those
small
businesses
expected
to
incur
compliance
costs
would
have
experienced
impacts
greater
than
3
percent
of
sales
(
compared
with
31
percent
of
those
small
businesses
in
today's
proposal).
Before
concluding
that
the
Agency
could
properly
certify
today's
rule
under
the
terms
of
the
RFA,
EPA
conducted
outreach
to
small
entities
and
convened
a
Panel
as
required
by
section
609(
b)
of
the
RFA
to
obtain
the
advice
and
recommendations
from
representatives
of
the
small
entities
that
potentially
would
be
subject
to
the
proposed
rule
requirements.
The
Panel
convened
on
January
22,
2002,
and
was
comprised
of
representatives
from
OMB,
the
SBA
Office
of
Advocacy,
the
EPA
Small
Business
Advocacy
Chair,
and
the
Emission
Standards
Division
of
the
Office
of
Air
Quality
Planning
and
Standards
of
EPA.
The
Panel
solicited
advice
from
eight
small
entity
representatives
(
SER),
including
the
NLA
and
member
companies
and
nonmember
companies
of
the
NLA.
On
January
30,
2002,
the
Panel
distributed
a
package
of
descriptive
and
technical
materials
explaining
the
rule
in
progress
to
the
SER.
On
February
19,
2002,
the
Panel
met
with
the
SER
to
hear
their
comments
on
preliminary
options
for
regulatory
flexibility
and
related
information.
The
Panel
also
received
written
comments
from
the
SER
in
response
to
both
the
outreach
materials
and
the
discussions
at
the
meeting.
Consistent
with
RFA/
SBREFA
requirements,
the
Panel
evaluated
the
assembled
materials
and
small
entity
comments
on
issues
related
to
the
elements
of
the
initial
RFA.
A
copy
of
the
Panel
report
is
included
in
the
docket
for
the
proposed
rule.
The
Panel
considered
numerous
regulatory
flexibility
options
in
response
to
concerns
raised
by
the
SER.
The
major
concerns
included
the
affordability
and
technical
feasibility
of
add
on
controls.
These
are
the
Panel
recommendations
and
EPA's
responses:
Recommend
that
the
proposed
rule
should
not
include
the
HCl
work
practice
standard,
invoking
section
112(
d)(
4)
of
CAA.
Response:
The
proposal
does
not
include
an
emission
standard
for
HCl.
Recommend
that
in
the
proposed
rule,
the
MPO
in
the
quarry
should
not
be
considered
as
emission
units
under
the
definition
of
affected
source.
Response:
The
MPO
in
the
quarry
are
excluded
from
the
definition
of
affected
source.
Recommend
that
the
proposed
rule
allow
for
the
``
bubbling''
of
PM
emissions
from
all
of
the
lime
kilns
and
coolers
at
a
lime
plant,
such
that
the
sum
of
all
kilns'
and
coolers'
PM
emissions
at
a
lime
plant
would
be
subject
to
the
PM
emission
limit,
rather
than
each
individual
kiln
and
cooler.
Response:
The
proposed
rule
defines
the
affected
source
as
including
all
kilns
and
coolers
(
among
other
listed
emission
units)
at
the
lime
manufacturing
plant.
This
would
allow
the
source
to
average
emissions
from
the
kilns
and
coolers
for
compliance
determination.
Recommend
that
we
request
comment
on
establishing
a
subcategory
because
of
the
potential
increase
in
SO2
and
HCl
emissions
that
may
result
in
complying
with
the
PM
standard.
Response:
We
are
requesting
comment
on
this
issue.
Recommend
that
we
undertake
an
analysis
of
the
costs
and
emissions
impacts
of
replacing
scrubbers
with
dry
APCD
and
present
the
results
of
that
analysis
in
the
preamble;
and
that
we
request
comment
on
any
operational,
process,
product,
or
other
technical
and/
or
spatial
constraints
that
would
preclude
installation
of
a
dry
APCD.
Response:
We
are
requesting
comment
on
these
issues
and
have
presented
said
analysis.
Recommend
that
the
proposed
rule
allow
a
source
to
use
the
ASTM
HCl
manual
method
for
the
measurement
of
HCl
for
area
source
determinations.
Response:
Today's
proposal
includes
this
provision.
Recommend
that
we
clarify
in
the
preamble
to
the
proposed
rule
that
we
are
not
specifically
requiring
sources
to
test
for
all
HAP
to
make
a
determination
of
whether
the
lime
plant
is
a
major
or
area
source,
and
that
we
solicit
public
comment
on
related
issues.
Response:
Today's
preamble
includes
this
language.
Recommend
that
we
solicit
comment
on
providing
the
option
of
using
COMS
in
place
of
BLDS;
recommend
that
we
solicit
comment
on
various
approaches
to
using
COMS;
and
recommend
soliciting
comment
on
what
an
appropriate
opacity
limit
would
be.
Response:
The
preamble
solicits
comment
on
these
issues.
Recommend
that
EPA
take
comment
on
other
monitoring
options
or
approaches,
including
the
following:
using
longer
averaging
time
periods
(
or
greater
frequencies
of
occurrence)
for
demonstrating
compliance
with
parameter
limits;
demonstrating
compliance
with
operating
parameter
limits
using
a
two
tier
approach;
and
the
suitability
of
other
PM
control
device
operating
parameters
that
can
be
monitored
to
demonstrate
compliance
with
the
PM
emission
limits,
in
lieu
of
or
in
addition
to
the
parameters
currently
required
in
the
draft
rule.
Response:
Today's
preamble
solicits
comment
on
these
issues.
Recommend
that
the
incorporation
by
reference
of
Chapters
3
and
5
of
the
American
Conference
of
Governmental
Industrial
Hygienists
(
ACGIH)
Industrial
Ventilation
manual
be
removed
from
the
proposed
rule.
Response:
Today's
proposed
rule
does
not
include
this
requirement.
Recommend
that
EPA
reevaluate
the
assumptions
used
in
modeling
the
economic
impacts
of
the
standards
and
conduct
a
sensitivity
analysis
using
different
price
and
supply
elasticities
reflective
of
the
industry's
claims
that
there
is
little
ability
to
pass
on
control
costs
to
their
customers,
and
there
is
considerable
opportunity
for
product
substitution
in
a
number
of
the
lime
industry's
markets.
Response:
The
EIA
does
include
the
aforementioned
considerations
and
analyses.
In
summary,
to
better
understand
the
implications
of
the
proposed
rule
from
the
industries'
perspective,
we
engaged
with
the
lime
manufacturing
companies
in
an
exchange
of
information,
including
small
entities,
during
the
overall
rule
development.
Prior
to
convening
the
Panel,
we
had
worked
aggressively
to
minimize
the
impact
of
the
proposed
rule
on
small
entities,
consistent
with
our
obligations
under
the
CAA,
and
these
pre
Panel
efforts
have
been
discussed
previously
in
this
preamble.
These
are
summarized
below.
1.
Lime
manufacturing
operations
at
beet
sugar
plants,
of
which
three
are
small
businesses,
would
not
be
affected
sources.
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/
Proposed
Rules
2.
Lime
manufacturing
plants
that
produce
hydrated
lime
only
would
not
be
affected
sources
as
well.
3.
We
are
proposing
PM
emission
limits
which
allow
the
affected
source,
including
small
entities,
flexibility
in
choosing
how
they
will
meet
the
emission
limit.
And
in
general,
the
emission
limitations
selected
are
all
based
on
the
MACT
floor,
as
opposed
to
more
costly
beyond
the
MACT
floor
options
that
we
considered.
An
emission
limit
for
mercury
was
rejected
since
it
would
have
been
based
on
a
beyond
the
MACT
floor
control
option.
4.
We
are
proposing
that
compliance
demonstrations
for
MPO
be
conducted
monthly
rather
than
on
a
daily
basis.
We
believe
this
will
reduce
the
amount
of
records
needed
to
demonstrate
compliance
with
the
rule
when
implemented.
5.
Furthermore,
we
are
proposing
the
minimum
performance
testing
frequency
(
every
5
years),
monitoring,
recordkeeping,
and
reporting
requirements
specified
in
the
general
provisions
(
40
CFR
part
63,
subpart
A).
6.
Finally,
many
lime
manufacturing
plants
owned
by
small
businesses
would
not
be
subject
to
the
proposed
standards
because
they
are
area
sources.
We
continue
to
be
interested
in
the
potential
impacts
of
the
proposed
rule
on
small
entities
and
welcome
comments
on
issues
related
to
such
impacts.
G.
Paperwork
Reduction
Act
The
information
collection
requirements
in
the
proposed
rule
have
been
submitted
for
approval
to
the
Office
of
Management
and
Budget
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
We
have
prepared
an
Information
Collection
Request
(
ICR)
document
(
2072.01),
and
a
copy
may
be
obtained
from
Susan
Auby
by
mail
at
U.
S.
EPA,
Office
of
Environmental
Information,
Collection
Strategies
Division
(
2822T),
1200
Pennsylvania
Avenue,
NW.,
Washington
DC
20460,
by
email
at
auby.
susan@
epa.
gov,
or
by
calling
(
202)
566
1672.
You
may
also
download
a
copy
off
the
Internet
at
http://
www.
epa.
gov/
icr.
The
information
requirements
are
not
effective
until
OMB
approves
them.
The
information
requirements
are
based
on
notification,
recordkeeping,
and
reporting
requirements
in
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A),
which
are
mandatory
for
all
operators
subject
to
national
emission
standards.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(
42
U.
S.
C.
7414).
All
information
submitted
to
the
EPA
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
Agency
policies
set
forth
in
40
CFR
part
2,
subpart
B.
The
proposed
rule
would
require
development
and
implementation
of
an
operations,
maintenance,
and
monitoring
plan,
which
would
include
inspections
of
the
control
devices
but
would
not
require
any
notifications
or
reports
beyond
those
required
by
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A).
The
recordkeeping
requirements
require
only
the
specific
information
needed
to
determine
compliance.
The
annual
monitoring,
reporting,
and
recordkeeping
burden
for
this
collection
(
averaged
over
the
first
3
years
after
the
effective
date
of
the
rule)
is
estimated
to
be
7,766
labor
hours
per
year,
at
a
total
annual
cost
of
$
621,673.
This
estimate
includes
notifications
that
facilities
are
subject
to
the
rule;
notifications
of
performance
tests;
notifications
of
compliance
status,
including
the
results
of
performance
tests
and
other
initial
compliance
demonstrations
that
do
not
include
performance
tests;
startup,
shutdown,
and
malfunction
reports;
semiannual
compliance
reports;
and
recordkeeping.
Total
capital/
startup
costs
associated
with
the
testing,
monitoring,
reporting,
and
recordkeeping
requirements
over
the
3
year
period
of
the
ICR
are
estimated
to
be
$
1,000,000,
with
annualized
costs
of
$
377,933.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to:
(
1)
Review
instructions;
(
2)
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
(
3)
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
(
4)
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
(
5)
search
data
sources;
(
6)
complete
and
review
the
collection
of
information;
and
(
7)
transmit
or
otherwise
disclose
the
information.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
our
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501,
et
seq.,
the
EPA
must
consider
the
paperwork
burden
imposed
by
any
information
collection
request
in
a
proposed
or
final
rule.
Comments
are
requested
on
the
Agency's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
By
U.
S.
Postal
Service,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
EPA
(
2822T),
1200
Pennsylvania
Avenue,
NW.,
Washington
DC
20460;
or
by
courier,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
EPA
(
2822T),
1301
Constitution
Avenue,
NW.,
Room
6143,
Washington
DC
20460
((
202)
566
1700);
and
to
the
Office
of
Information
and
Regulatory
Affairs,
OMB,
725
17th
Street,
NW.,
Washington,
DC
20503,
marked
``
Attention:
Desk
Officer
for
EPA.''
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
December
20,
2002,
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
January
21,
2003.
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
the
proposal.
H.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
(
NTTAA)
of
1995
(
Public
Law
No.
104
113;
15
U.
S.
C.
272
note)
directs
the
EPA
to
use
voluntary
consensus
standards
in
their
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
annual
reports
to
the
OMB,
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.
The
proposed
rule
involves
technical
standards.
The
EPA
cites
the
following
standards
in
the
proposed
rule:
EPA
Methods
1,
1A,
2,
2A,
2C,
2D,
2F,
2G,
3,
3A,
3B,
4,
5,
5D,
9,
17,
18,
22,
320,
321.
Consistent
with
the
NTTAA,
EPA
conducted
searches
to
identify
voluntary
consensus
standards
in
addition
to
these
EPA
methods.
No
applicable
voluntary
consensus
standards
were
identified
for
EPA
Methods
1A,
2A,
2D,
2F,
2G,
5D,
9,
22,
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2002
/
Proposed
Rules
and
321.
The
search
and
review
results
have
been
documented
and
are
placed
in
the
docket
(
A
95
41)
for
the
proposed
rule.
The
three
voluntary
consensus
standards
described
below
were
identified
as
acceptable
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rule.
The
voluntary
consensus
standard
ASME
PTC
19
10
1981
Part
10,
``
Flue
and
Exhaust
Gas
Analyses,''
is
cited
in
the
proposed
rule
for
its
manual
method
for
measuring
the
oxygen,
carbon
dioxide,
and
carbon
monoxide
content
of
exhaust
gas.
This
part
of
ASME
PTC
19
10
1981
Part
10
is
an
acceptable
alternative
to
Method
3B.
The
voluntary
consensus
standard
ASTM
D6420
99,
``
Standard
Test
Method
for
Determination
of
Gaseous
Organic
Compounds
by
Direct
Interface
Gas
Chromatography
Mass
Spectrometry
(
GC/
MS),''
is
appropriate
in
the
cases
described
below
for
inclusion
in
the
proposed
rule
in
addition
to
EPA
Method
18
codified
at
40
CFR
part
60,
appendix
A,
for
the
measurement
of
organic
HAP
from
lime
kilns.
The
standard
ASTM
D6420
99
will
be
incorporated
by
reference
in
§
63.14.
Similar
to
EPA's
performance
based
Method
18,
ASTM
D6420
99
is
also
a
performance
based
method
for
measurement
of
gaseous
organic
compounds.
However,
ASTM
D6420
99
was
written
to
support
the
specific
use
of
highly
portable
and
automated
GC/
MS.
While
offering
advantages
over
the
traditional
Method
18,
the
ASTM
method
does
allow
some
less
stringent
criteria
for
accepting
GC/
MS
results
than
required
by
Method
18.
Therefore,
ASTM
D6420
99
is
a
suitable
alternative
to
Method
18
only
where
the
target
compound(
s)
are
those
listed
in
Section
1.1
of
ASTM
D6420
99,
and
the
target
concentration
is
between
150
parts
per
billion
by
volume
(
ppbv)
and
100
ppmv.
For
target
compound(
s)
not
listed
in
Section
1.1
of
ASTM
D6420
99,
but
potentially
detected
by
mass
spectrometry,
the
proposed
rule
specifies
that
the
additional
system
continuing
calibration
check
after
each
run,
as
detailed
in
Section
10.5.3
of
the
ASTM
method,
must
be
followed,
met,
documented,
and
submitted
with
the
data
report
even
if
there
is
no
moisture
condenser
used
or
the
compound
is
not
considered
water
soluble.
For
target
compound(
s)
not
listed
in
Section
1.1
of
ASTM
D6420
99,
and
not
amenable
to
detection
by
mass
spectrometry,
ASTM
D6420
99
does
not
apply.
As
a
result,
EPA
will
cite
ASTM
D6420
99
in
the
proposed
rule.
The
EPA
will
also
cite
Method
18
as
a
GC
option
in
addition
to
ASTM
D6420
99.
This
will
allow
the
continued
use
of
GC
configurations
other
than
GC/
MS.
The
voluntary
consensus
standard
ASTM
D6735
01,
``
Standard
Test
Method
for
Measurement
of
Gaseous
Chlorides
and
Fluorides
from
Mineral
Calcining
Exhaust
Sources
Impinger
Method,''
is
an
acceptable
alternative
to
EPA
Method
320
for
the
purposes
of
the
proposed
rule
provided
that
the
additional
requirements
described
in
Section
63.7142
of
the
proposed
rule
are
also
addressed
in
the
methodology.
In
addition
to
the
voluntary
consensus
standards
EPA
uses
in
the
proposed
rule,
the
search
for
emissions
measurement
procedures
identified
15
other
voluntary
consensus
standards.
The
EPA
determined
that
12
of
these
15
standards
identified
for
measuring
emissions
of
the
HAP
or
surrogates
subject
to
emission
standards
in
the
proposed
rule
were
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
this
rule.
Therefore,
EPA
does
not
intend
to
adopt
these
standards
for
this
purpose.
The
reasons
for
this
determination
can
be
found
in
the
docket
for
the
proposed
rule.
Three
of
the
15
voluntary
consensus
standards
identified
in
this
search
were
not
available
at
the
time
the
review
was
conducted
for
the
purposes
of
the
proposed
rule
because
they
are
under
development
by
a
voluntary
consensus
body:
ASME/
BSR
MFC
13M,
``
Flow
Measurement
by
Velocity
Traverse,''
for
EPA
Method
2
(
and
possibly
1);
ASME/
BSR
MFC
12M,
``
Flow
in
Closed
Conduits
Using
Multiport
Averaging
Pitot
Primary
Flowmeters,''
for
EPA
Method
2;
and
ASTM
D6348
98,
``
Determination
of
Gaseous
Compounds
by
Extractive
Direct
Interface
Fourier
Transform
(
FTIR)
Spectroscopy,''
for
EPA
Method
320.
The
standard
ASTM
D6348
98,
``
Determination
of
Gaseous
Compounds
by
Extractive
Direct
Interface
Fourier
Transform
(
FTIR)
Spectroscopy''
has
been
reviewed
by
the
EPA
and
comments
were
sent
to
ASTM.
Currently,
the
ASTM
Subcommittee
D22
03
is
now
undertaking
a
revision
of
ASTM
D6348
98.
Upon
successful
ASTM
balloting
and
demonstration
of
technical
equivalency
with
the
EPA
FTIR
methods,
the
revised
ASTM
standard
could
be
incorporated
by
reference
for
EPA
regulatory
applicability.
Section
63.7112
and
Table
4
to
proposed
subpart
AAAAA
list
the
EPA
testing
methods
included
in
the
proposed
rule.
Under
§
§
63.7(
f)
and
63.8(
f)
of
subpart
A
of
the
General
Provisions,
a
source
may
apply
to
EPA
for
permission
to
use
alternative
test
methods
or
alternative
monitoring
requirements
in
place
of
any
of
the
EPA
testing
methods,
performance
specifications,
or
procedures.
I.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution
or
Use
The
proposed
rule
is
not
a
``
significant
energy
action''
as
defined
in
Executive
Order
13211,
``
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(
66
FR
28355,
May
22,
2001)
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.
Although
compliance
with
the
proposed
rule
could
possibly
lead
to
increased
electricity
consumption
as
sources
may
replace
existing
wet
scrubbers
with
venturi
wet
scrubbers
that
require
more
electricity,
the
proposed
rule
would
not
require
that
venturi
scrubbers
be
installed,
and
in
fact,
there
are
some
alternatives
that
may
decrease
electrical
demand.
Further,
the
proposed
rule
would
have
no
effect
on
the
supply
or
distribution
of
energy.
Although
we
considered
certain
fuels
as
potential
bases
for
MACT,
none
of
our
proposed
MACT
determinations
are
based
on
fuels.
Finally,
we
acknowledge
that
an
interpretation
limiting
fuel
use
to
the
top
6
percent
of
``
clean
HAP''
fuels
(
if
they
existed)
could
potentially
have
adverse
implications
on
energy
supply.
List
of
Subjects
in
40
CFR
Part
63
Administrative
practice
and
procedure,
Air
pollution
control,
Environmental
protection,
Hazardous
substances,
Incorporation
by
reference,
Intergovernmental
relations,
Lime
manufacturing,
Reporting
and
recordkeeping
requirements.
Dated:
November
26,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
stated
in
the
preamble,
title
40,
chapter
I,
part
63
of
the
Code
of
the
Federal
Regulations
is
proposed
to
be
amended
as
follows:
PART
63
[
AMENDED]
1.
The
authority
citation
for
part
63
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401,
et
seq.
Subpart
A
[
Amended]
2.
Section
63.14
is
amended
by
adding
paragraphs
(
b)(
27)
and
(
b)(
28)
to
read
as
follows:
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20,
2002
/
Proposed
Rules
§
63.14
Incorporation
by
reference.
*
*
*
*
*
(
b)
*
*
*
(
27)
ASTM
D6420
99,
Standard
Test
Method
for
Determination
of
Gaseous
Organic
Compounds
by
Direct
Interface
Gas
Chromatography
Mass
Spectrometry
(
GC/
MS),
IBR
approved
[
date
of
publication
of
the
final
rule
in
the
Federal
Register]
for
§
63.7142.
(
28)
ASTM
D6735
01,
Standard
Test
Method
for
Measurement
of
Gaseous
Chlorides
and
Fluorides
from
Mineral
Calcining
Exhaust
Sources
Impinger
Method,
IBR
approved
[
date
of
publication
of
the
final
rule
in
the
Federal
Register]
for
§
63.7142.
*
*
*
*
*
3.
Part
63
is
amended
by
adding
subpart
AAAAA
to
read
as
follows:
Subpart
AAAAA
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Lime
Manufacturing
Plants
What
This
Subpart
Covers
Sec.
63.7080
What
is
the
purpose
of
this
subpart?
63.7081
Am
I
subject
to
this
subpart?
63.7082
What
parts
of
my
plant
does
this
subpart
cover?
63.7083
When
do
I
have
to
comply
with
this
subpart?
Emission
Limitations
63.7090
What
emission
limitations
must
I
meet?
General
Compliance
Requirements
63.7100
What
are
my
general
requirements
for
complying
with
this
subpart?
Testing
and
Initial
Compliance
Requirements
63.7110
By
what
date
must
I
conduct
performance
tests
and
other
initial
compliance
demonstrations?
63.7111
When
must
I
conduct
subsequent
performance
tests?
63.7112
What
performance
tests,
design
evaluations,
and
other
procedures
must
I
use?
63.7113
What
are
my
monitoring
installation,
operation,
and
maintenance
requirements?
63.7114
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations
standard?
Continuous
Compliance
Requirements
63.7120
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
63.7121
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations
standard?
Notifications,
Reports,
and
Records
63.7130
What
notifications
must
I
submit
and
when?
63.7131
What
reports
must
I
submit
and
when?
63.7132
What
records
must
I
keep?
63.7133
In
what
form
and
how
long
must
I
keep
my
records?
Other
Requirements
and
Information
63.7140
What
parts
of
the
General
Provisions
apply
to
me?
63.7141
Who
implements
and
enforces
this
subpart?
63.7142
What
are
the
requirements
for
claiming
area
source
status?
63.7143
What
definitions
apply
to
this
subpart?
Tables
to
Subpart
AAAAA
of
Part
63
Table
1
to
Subpart
AAAAA
of
Part
63
Emission
Limits
Table
2
to
Subpart
AAAAA
of
Part
63
Operating
Limits
Table
3
to
Subpart
AAAAA
of
Part
63
Initial
Compliance
with
Emission
Limitations
Table
4
to
Subpart
AAAAA
of
Part
63
Requirements
for
Performance
Tests
Table
5
to
Subpart
AAAAA
of
Part
63
Continuous
Compliance
with
Operating
Limits
Table
6
to
Subpart
AAAAA
of
Part
63
Periodic
Monitoring
for
Compliance
with
Opacity
and
Visible
Emissions
Limits
Table
7
to
Subpart
AAAAA
of
Part
63
Requirements
for
Reports
Table
8
to
Subpart
AAAAA
of
Part
63
Applicability
of
General
Provisions
to
Subpart
AAAAA
What
This
Subpart
Covers
§
63.7080
What
is
the
purpose
of
this
subpart?
This
subpart
establishes
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
lime
manufacturing
plants.
This
subpart
also
establishes
requirements
to
demonstrate
initial
and
continuous
compliance
with
the
emission
limitations.
§
63.7081
Am
I
subject
to
this
subpart?
(
a)
You
are
subject
to
this
subpart
if
you
own
or
operate
a
lime
manufacturing
plant
(
LMP)
that
is
a
major
source,
or
that
is
located
at,
or
is
part
of,
a
major
source
of
hazardous
air
pollutant
(
HAP)
emissions,
unless
the
LMP
is
located
at
a
kraft
pulp
mill,
soda
pulp
mill
or
beet
sugar
manufacturing
plant.
(
1)
An
LMP
is
an
establishment
engaged
in
the
manufacture
of
lime
product
(
calcium
oxide,
calcium
oxide
with
magnesium
oxide,
or
dead
burned
dolomite)
by
calcination
of
limestone,
dolomite,
shells
or
other
calcareous
substances.
(
2)
A
major
source
of
HAP
is
a
plant
site
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
9.07
megagrams
(
10
tons)
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
22.68
megagrams
(
25
tons)
or
more
per
year
from
all
emission
sources
at
the
plant
site.
(
b)
[
Reserved]
§
63.7082
What
parts
of
my
plant
does
this
subpart
cover?
(
a)
This
subpart
applies
to
each
existing,
reconstructed,
or
new
LMP
that
is
located
at
a
major
source.
(
b)
The
affected
source
is
the
collection
of
all
of
the
emission
units
listed
in
paragraph
(
c)
of
this
section.
(
c)
Emission
units
are
lime
kilns,
lime
coolers
and
materials
processing
operations
(
MPO)
as
defined
in
paragraph
(
d)
of
this
section.
(
d)
Materials
processing
operations
are
raw
material
grinding
mills,
raw
material
storage
bins,
conveying
system
transfer
points,
bulk
loading
or
unloading
systems,
screening
operations,
bucket
elevators
and
belt
conveyors,
except
as
provided
by
paragraphs
(
e)
through
(
g)
of
this
section.
(
e)
Materials
processing
operations
that
process
only
lime
product
or
fuel
are
not
subject
to
this
subpart.
(
f)
Truck
dumping
into
any
screening
operation,
feed
hopper
or
crusher
is
not
subject
to
this
subpart.
(
g)
The
first
emission
unit
in
the
sequence
of
MPO
that
is
subject
to
this
subpart
is
the
raw
material
storage
bin.
Any
MPO
which
precedes
the
raw
material
storage
bin
is
not
subject
to
this
subpart.
Furthermore,
the
first
conveyor
transfer
point
subject
to
this
subpart
is
the
transfer
point
associated
with
the
conveyor
transferring
material
from
the
raw
material
storage
bin
to
the
next
emission
unit.
(
h)
Lime
hydrators
are
not
subject
to
this
subpart.
(
i)
[
Reserved]
(
j)
A
new
affected
source
is
the
collection
of
all
emission
units
listed
in
paragraph
(
c)
of
this
section
for
which
construction
begins
after
December
20,
2002,
if
you
met
the
applicability
criteria
in
§
63.7081
at
the
time
you
commenced
construction.
(
k)
An
affected
source
is
reconstructed
if
it
meets
the
criteria
for
reconstruction
defined
in
§
63.2.
(
l)
[
Reserved]
(
m)
An
affected
source
is
existing
if
it
is
not
new
or
reconstructed.
§
63.7083
When
do
I
have
to
comply
with
this
subpart?
(
a)
If
you
have
a
new
or
reconstructed
affected
source,
you
must
comply
with
this
subpart
according
to
paragraphs
(
a)(
1)
and
(
2)
of
this
section.
(
1)
If
you
start
up
your
affected
source
before
the
[
date
of
publication
of
the
final
rule
in
the
Federal
Register],
you
must
comply
with
the
emission
limitations
no
later
than
[
date
of
publication
of
the
final
rule
in
the
Federal
Register].
(
2)
If
you
start
up
your
affected
source
after
[
date
of
publication
of
the
final
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2002
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rule
in
the
Federal
Register],
then
you
must
comply
with
the
emission
limitations
for
new
and
reconstructed
affected
sources
upon
startup
of
your
affected
source.
(
b)
If
you
have
an
existing
LMP,
you
must
comply
with
the
applicable
emission
limitations
for
the
existing
affected
source,
and
you
must
have
completed
all
applicable
performance
tests
no
later
than
[
3
years
from
the
date
of
publication
of
the
final
rule
in
the
Federal
Register].
The
compliance
date
is
site
specific
for
existing
LMP
and
is
the
day
following
completion
of
all
the
performance
tests
required
under
§
63.7110(
a).
(
c)
If
you
have
an
area
source
that
increases
its
emissions
or
its
potential
to
emit
such
that
it
becomes
a
major
source
of
HAP,
the
deadlines
specified
in
paragraphs
(
c)(
1)
and
(
2)
of
this
section
apply.
(
1)
Any
portion
of
the
LMP
that
is
a
new
affected
source
or
a
reconstructed
affected
source
must
be
in
compliance
with
this
subpart
upon
startup.
(
2)
The
emission
units
of
the
existing
LMP
subject
to
emission
limitations
under
this
subpart
must
be
in
compliance
with
this
subpart
within
3
years
after
the
source
becomes
a
major
source
of
HAP.
(
d)
You
must
meet
the
notification
requirements
in
§
63.7130
according
to
the
schedule
in
§
63.7130
and
in
subpart
A
of
this
part.
Some
of
the
notifications
must
be
submitted
before
you
are
required
to
comply
with
the
emission
limitations
in
this
subpart.
Emission
Limitations
§
63.7090
What
emission
limitations
must
I
meet?
(
a)
You
must
meet
each
emission
limitation
in
Table
1
to
this
subpart
that
applies
to
you.
(
b)
You
must
meet
each
operating
limit
in
Table
2
to
this
subpart
that
applies
to
you.
General
Compliance
Requirements
§
63.7100
What
are
my
general
requirements
for
complying
with
this
subpart?
(
a)
You
must
be
in
compliance
with
the
emission
limitations
(
including
operating
limits)
in
this
subpart
at
all
times,
except
during
periods
of
startup,
shutdown,
and
malfunction.
(
b)
You
must
be
in
compliance
with
the
opacity
and
visible
emission
limits
in
this
subpart
during
the
times
specified
in
§
63.6(
h)(
1).
(
c)
You
must
always
operate
and
maintain
your
affected
source,
including
air
pollution
control
and
monitoring
equipment,
according
to
the
provisions
in
§
63.6(
e)(
1)(
i).
(
d)
You
must
prepare
and
implement
for
each
LMP,
a
written
operations,
maintenance,
and
monitoring
(
OM&
M)
plan.
You
must
submit
the
plan
to
the
applicable
permitting
authority
for
review
and
approval
as
part
of
the
application
for
a
40
CFR
part
70
or
40
CFR
part
71
permit.
Any
subsequent
changes
to
the
plan
must
be
submitted
to
the
applicable
permitting
authority
for
review
and
approval.
Pending
approval
by
the
applicable
permitting
authority
of
an
initial
or
amended
plan,
you
must
comply
with
the
provisions
of
the
submitted
plan.
Each
plan
must
contain
the
following
information:
(
1)
Process
and
control
device
parameters
to
be
monitored
to
determine
compliance,
along
with
established
operating
limits
or
ranges,
as
applicable,
for
each
emission
unit.
(
2)
A
monitoring
schedule
for
each
emission
unit.
(
3)
Procedures
for
the
proper
operation
and
maintenance
of
each
emission
unit
and
each
air
pollution
control
device
used
to
meet
the
applicable
emission
limitations
and
operating
limits
in
Tables
1
and
2
to
this
subpart,
respectively.
(
4)
Procedures
for
the
proper
installation,
operation,
and
maintenance
of
monitoring
devices
or
systems
used
to
determine
compliance,
including:
(
i)
Calibration
and
certification
of
accuracy
of
each
monitoring
device;
(
ii)
Performance
and
equipment
specifications
for
the
sample
interface,
parametric
signal
analyzer,
and
the
data
collection
and
reduction
systems;
(
iii)
Ongoing
operation
and
maintenance
procedures
in
accordance
with
the
general
requirements
of
§
63.8(
c)(
1),
(
3),
and
(
4)(
ii);
and
(
iv)
Ongoing
data
quality
assurance
procedures
in
accordance
with
the
general
requirements
of
§
63.8(
d).
(
5)
Procedures
for
monitoring
process
and
control
device
parameters.
(
6)
Corrective
actions
to
be
taken
when
process
or
operating
parameters
or
add
on
control
device
parameters
deviate
from
the
operating
limits
specified
in
Table
2
to
this
subpart,
including:
(
i)
Procedures
to
determine
and
record
the
cause
of
a
deviation
or
excursion,
and
the
time
the
deviation
or
excursion
began
and
ended;
and
(
ii)
Procedures
for
recording
the
corrective
action
taken,
the
time
corrective
action
was
initiated,
and
the
time
and
date
the
corrective
action
was
completed.
(
7)
A
maintenance
schedule
for
each
emission
unit
and
control
device
that
is
consistent
with
the
manufacturer's
instructions
and
recommendations
for
routine
and
long
term
maintenance.
(
e)
You
must
develop
and
implement
a
written
startup,
shutdown,
and
malfunction
plan
(
SSMP)
according
to
the
provisions
in
§
63.6(
e)(
3).
Testing
and
Initial
Compliance
Requirements
§
63.7110
By
what
date
must
I
conduct
performance
tests
and
other
initial
compliance
demonstrations?
(
a)
If
you
have
an
existing
affected
source,
you
must
complete
all
applicable
performance
tests
within
3
years
after
[
date
of
publication
of
the
final
rule
in
the
Federal
Register],
according
to
the
provisions
in
§
§
63.7(
a)(
2)
and
63.7114.
(
b)
If
you
commenced
construction
or
reconstruction
of
an
LMP
between
December
20,
2002
and
[
date
of
publication
of
the
final
rule
in
the
Federal
Register],
you
must
demonstrate
initial
compliance
with
either
the
proposed
emission
limitation
or
the
promulgated
emission
limitation
no
later
than
180
calendar
days
after
[
date
of
publication
of
the
final
rule
in
the
Federal
Register]
or
within
180
calendar
days
after
startup
of
the
source,
whichever
is
later,
according
to
§
§
63.7(
a)(
2)(
ix)
and
63.7114.
(
c)
If
you
commenced
construction
or
reconstruction
between
December
20,
2002
and
[
date
of
publication
of
the
final
rule
in
the
Federal
Register],
and
you
chose
to
comply
with
the
proposed
emission
limitation
when
demonstrating
initial
compliance,
you
must
conduct
a
demonstration
of
compliance
with
the
promulgated
emission
limitation
within
3
years
after
[
date
of
publication
of
the
final
rule
in
the
Federal
Register]
or
after
startup
of
the
source,
whichever
is
later,
according
to
§
§
63.7(
a)(
2)(
ix)
and
63.7114.
(
d)
For
each
emission
limitation
in
Table
3
to
this
subpart
that
applies
to
you
where
the
monitoring
averaging
period
is
3
hours,
the
3
hour
period
for
demonstrating
continuous
compliance
for
emission
units
within
existing
affected
sources
at
LMP
begins
at
12:
01
a.
m.
on
the
compliance
date
for
existing
affected
sources,
that
is,
the
day
following
completion
of
the
initial
performance
test(
s),
and
ends
at
3:
01
a.
m.
on
the
same
day.
(
e)
For
each
emission
limitation
in
Table
3
to
this
subpart
that
applies
to
you
where
the
monitoring
averaging
period
is
3
hours,
the
3
hour
period
for
demonstrating
continuous
compliance
for
emission
units
within
new
or
reconstructed
affected
sources
at
LMP
begins
at
12:
01
a.
m.
on
the
day
following
completion
of
the
initial
compliance
demonstration
tests,
as
required
in
paragraphs
(
b)
and
(
c)
of
this
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20,
2002
/
Proposed
Rules
section,
and
ends
at
3:
01
a.
m.
on
the
same
day.
§
63.7111
When
must
I
conduct
subsequent
performance
tests?
You
must
conduct
a
performance
test
within
5
years
following
the
initial
performance
test
and
within
5
years
following
each
subsequent
performance
test
thereafter.
§
63.7112
What
performance
tests,
design
evaluations,
and
other
procedures
must
I
use?
(
a)
You
must
conduct
each
performance
test
in
Table
4
to
this
subpart
that
applies
to
you.
(
b)
Each
performance
test
must
be
conducted
according
to
the
requirements
in
§
63.7(
e)(
1)
and
under
the
specific
conditions
specified
in
Table
4
to
this
subpart.
(
c)
You
may
not
conduct
performance
tests
during
periods
of
startup,
shutdown,
or
malfunction,
as
specified
in
§
63.7(
e)(
1).
(
d)
Except
for
opacity
and
visible
emission
observations,
you
must
conduct
three
separate
test
runs
for
each
performance
test
required
in
this
section,
as
specified
in
§
63.7(
e)(
3).
Each
test
run
must
last
at
least
1
hour.
(
e)
The
emission
rate
of
particulate
matter
(
PM)
from
the
lime
kiln
(
and
the
lime
cooler
if
there
is
a
separate
exhaust
to
the
atmosphere
from
the
lime
cooler)
must
be
computed
for
each
run
using
Equation
1
of
this
section:
E
CQ
CQ
PK
Eq
k
k
c
c
=
+
(
)/
(
.
1)
Where:
E
=
Emission
rate
of
PM,
kg/
Mg
(
lb/
ton)
of
stone
feed.
Ck
=
Concentration
of
PM
in
the
kiln
effluent,
g/
dscm
(
grain/
dscf).
Qk
=
Volumetric
flow
rate
of
kiln
effluent
gas,
dscm/
hr
(
dscf/
hr).
Cc
=
Concentration
of
PM
in
the
cooler
effluent,
g/
dscm
(
grain/
dscf).
This
value
is
zero
if
there
is
not
a
separate
cooler
exhaust
to
the
atmosphere.
Qc
=
Volumetric
flow
rate
of
cooler
effluent
gas,
dscm/
hr
(
dscf/
hr).
This
value
is
zero
if
there
is
not
a
separate
cooler
exhaust
to
the
atmosphere.
P
=
Stone
feed
rate,
Mg/
hr
(
ton/
hr).
K
=
Conversion
factor,
1000
g/
kg
(
7000
grains/
lb).
(
f)
The
combined
particulate
emission
rate
from
all
kilns
and
coolers
within
an
existing
affected
source
at
an
LMP
must
be
calculated
using
Equation
2
of
this
section:
E
EP
P
Eq
T
ii
i
i
n
i
n
=
=
=
/
(
.
1
1
2)
Where:
ET
=
Emission
rate
of
PM
from
all
kilns
and
coolers
at
an
existing
LMP,
kg/
Mg
(
lb/
ton)
of
stone
feed.
Ei
=
Emission
rate
of
PM
from
kiln
i,
or
from
kiln/
cooler
combination
i,
kg/
Mg
(
lb/
ton)
of
stone
feed.
Pi
=
Stone
feed
rate
to
kiln
i,
Mg/
hr
(
ton/
hr).
n
=
Number
of
existing
kilns
at
the
existing
affected
source.
(
g)
The
combined
particulate
emission
rate
from
all
new
or
reconstructed
kilns
and
coolers
must
be
calculated
using
Equation
3
of
this
section:
E
EP
P
Eq
TN
j
j
j
j
m
j
m
=
=
=
/
(
.
3)
1
1
Where:
ETN
=
Emission
rate
of
PM
from
all
kilns
and
coolers
at
a
new
or
reconstructed
LMP,
kg/
Mg
(
lb/
ton)
of
stone
feed.
Ej
=
Emission
rate
of
PM
from
kiln
j,
or
from
kiln/
cooler
combination
j,
kg/
Mg
(
lb/
ton)
of
stone
feed.
Pj
=
Stone
feed
rate
to
kiln
j,
Mg/
hr
(
ton/
hr).
m
=
Number
of
kilns
and
kiln/
cooler
combinations
within
the
new
or
reconstructed
affected
source.
(
h)
Performance
test
results
must
be
documented
in
complete
test
reports
that
contain
the
information
required
by
paragraphs
(
h)(
1)
through
(
10)
of
this
section,
as
well
as
all
other
relevant
information.
The
plan
to
be
followed
during
testing
must
be
made
available
to
the
Administrator
at
least
60
days
prior
to
testing,
if
requested.
(
1)
A
brief
description
of
the
process
and
the
air
pollution
control
system;
(
2)
Sampling
location
description(
s);
(
3)
A
description
of
sampling
and
analytical
procedures
and
any
modifications
to
standard
procedures;
(
4)
Test
results,
including
opacity;
(
5)
Quality
assurance
procedures
and
results;
(
6)
Records
of
operating
conditions
during
the
test,
preparation
of
standards,
and
calibration
procedures;
(
7)
Raw
data
sheets
for
field
sampling
and
field
and
laboratory
analyses;
(
8)
Documentation
of
calculations;
(
9)
All
data
recorded
and
used
to
establish
operating
limits;
and
(
10)
Any
other
information
required
by
the
test
method.
(
i)
[
Reserved]
(
j)
You
must
establish
any
applicable
3
hour
rolling
average
operating
limit
indicated
in
Table
2
to
this
subpart
according
to
the
applicable
requirements
in
Table
3
to
this
subpart
and
paragraphs
(
j)(
1)
through
(
4)
of
this
section.
(
1)
Continuously
record
the
parameter
during
the
PM
performance
test
and
include
the
parameter
record(
s)
in
the
performance
test
report.
(
2)
Determine
the
average
parameter
value
for
each
15
minute
period
of
each
test
run.
(
3)
Calculate
the
test
run
average
for
the
parameter
by
taking
the
average
of
all
the
15
minute
parameter
values
for
the
run.
(
4)
Calculate
the
3
hour
operating
limit
by
taking
the
average
of
the
three
test
run
averages.
(
k)
For
each
building
enclosing
any
MPO
that
is
subject
to
a
visible
emission
(
VE)
limit,
you
must
conduct
a
VE
check
according
to
item
18
in
Table
4
to
this
subpart,
and
in
accordance
with
paragraphs
(
k)(
1)
through
(
3)
of
this
section.
(
1)
Conduct
visual
inspections
that
consist
of
a
visual
survey
of
the
building
over
the
test
period
to
identify
if
there
are
VE,
other
than
condensed
water
vapor.
(
2)
Select
a
position
at
least
15
but
not
more
than
1,320
feet
from
each
side
of
the
building
with
the
sun
or
other
light
source
generally
at
your
back.
(
3)
The
observer
conducting
the
VE
checks
need
not
be
certified
to
conduct
Method
9
in
appendix
A
to
part
60
of
this
chapter,
but
must
meet
the
training
requirements
as
described
in
Method
22
in
appendix
A
to
part
60
of
this
chapter.
§
63.7113
What
are
my
monitoring
installation,
operation,
and
maintenance
requirements?
(
a)
You
must
install,
operate,
and
maintain
each
continuous
parameter
monitoring
system
(
CPMS)
according
to
your
OM&
M
plan
required
by
§
63.7100(
d)
and
paragraphs
(
a)(
1)
through
(
5)
of
this
section,
and
you
must
install,
operate,
and
maintain
each
continuous
opacity
monitoring
system
(
COMS)
as
required
by
40
CFR
part
63,
subpart
A,
General
Provisions
and
according
to
PS
1
of
appendix
B
to
part
60
of
this
chapter.
(
1)
The
CPMS
must
complete
a
minimum
of
one
cycle
of
operation
for
each
successive
15
minute
period.
(
2)
To
calculate
a
valid
hourly
value,
you
must
have
at
least
three
of
four
equally
spaced
data
values
for
that
hour
from
a
CPMS
that
is
not
out
of
control
according
to
your
OM&
M
plan.
(
3)
To
calculate
the
average
for
each
3
hour
averaging
period,
you
must
have
at
least
two
of
three
of
the
hourly
averages
for
that
period
using
only
hourly
average
values
that
are
based
on
valid
data
(
i.
e.,
not
from
out
of
control
periods).
The
3
hour
rolling
average
is
updated
each
hour.
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78073
Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
(
4)
You
must
conduct
a
performance
evaluation
of
each
CPMS
in
accordance
with
your
OM&
M
plan.
(
5)
You
must
operate
and
maintain
the
CPMS
in
continuous
operation
according
to
the
OM&
M
plan.
(
b)
For
each
flow
measurement
device,
you
must
meet
the
requirements
in
paragraphs
(
a)(
1)
through
(
5)
and
(
b)(
1)
through
(
4)
of
this
section.
(
1)
Use
a
flow
sensor
with
a
minimum
tolerance
of
2
percent
of
the
flow
rate.
(
2)
Reduce
swirling
flow
or
abnormal
velocity
distributions
due
to
upstream
and
downstream
disturbances.
(
3)
Conduct
a
flow
sensor
calibration
check
at
least
semiannually.
(
4)
At
least
monthly,
inspect
all
components
for
integrity,
all
electrical
connections
for
continuity,
and
all
mechanical
connections
for
leakage.
(
c)
For
each
pressure
measurement
device,
you
must
meet
the
requirements
in
paragraphs
(
a)(
1)
through
(
5)
and
(
c)(
1)
through
(
7)
of
this
section.
(
1)
Locate
the
pressure
sensor(
s)
in
or
as
close
to
a
position
that
provides
a
representative
measurement
of
the
pressure.
(
2)
Minimize
or
eliminate
pulsating
pressure,
vibration,
and
internal
and
external
corrosion.
(
3)
Use
a
gauge
with
a
minimum
tolerance
of
0.5
inch
of
water
or
a
transducer
with
a
minimum
tolerance
of
1
percent
of
the
pressure
range.
(
4)
Check
pressure
tap
pluggage
daily.
(
5)
Using
a
manometer,
check
gauge
calibration
quarterly
and
transducer
calibration
monthly.
(
6)
Conduct
calibration
checks
any
time
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
pressure
range
or
install
a
new
pressure
sensor.
(
7)
At
least
monthly,
inspect
all
components
for
integrity,
all
electrical
connections
for
continuity,
and
all
mechanical
connections
for
leakage.
(
d)
For
each
bag
leak
detection
system,
you
must
meet
any
applicable
requirements
in
paragraphs
(
a)(
1)
through
(
5)
and
(
d)(
1)
through
(
8)
of
this
section.
(
1)
The
bag
leak
detection
system
must
be
certified
by
the
manufacturer
to
be
capable
of
detecting
PM
emissions
at
concentrations
of
10
milligrams
per
actual
cubic
meter
(
0.0044
grains
per
actual
cubic
foot)
or
less.
(
2)
The
sensor
on
the
bag
leak
detection
system
must
provide
output
of
relative
PM
emissions.
(
3)
The
bag
leak
detection
system
must
have
an
alarm
that
will
sound
automatically
when
it
detects
an
increase
in
relative
PM
emissions
greater
than
a
preset
level.
(
4)
The
alarm
must
be
located
in
an
area
where
appropriate
plant
personnel
will
be
able
to
hear
it.
(
5)
For
a
positive
pressure
fabric
filter,
each
compartment
or
cell
must
have
a
bag
leak
detector.
For
a
negativepressure
or
induced
air
fabric
filter,
the
bag
leak
detector
must
be
installed
downstream
of
the
fabric
filter.
If
multiple
bag
leak
detectors
are
required
(
for
either
type
of
fabric
filter),
detectors
may
share
the
system
instrumentation
and
alarm.
(
6)
Bag
leak
detection
systems
must
be
installed,
operated,
adjusted,
and
maintained
so
that
they
follow
the
manufacturer's
written
specifications
and
recommendations.
Standard
operating
procedures
must
be
incorporated
into
the
OM&
M
plan.
(
7)
At
a
minimum,
initial
adjustment
of
the
system
must
consist
of
establishing
the
baseline
output
in
both
of
the
following
ways:
(
i)
Adjust
the
range
and
the
averaging
period
of
the
device.
(
ii)
Establish
the
alarm
set
points
and
the
alarm
delay
time.
(
8)
After
initial
adjustment,
the
range,
averaging
period,
alarm
set
points,
or
alarm
delay
time
may
not
be
adjusted
except
as
specified
in
the
OM&
M
plan
required
by
§
63.7100(
d).
In
no
event
may
the
range
be
increased
by
more
than
100
percent
or
decreased
by
more
than
50
percent
over
a
365
day
period
unless
a
responsible
official,
as
defined
in
§
63.2,
certifies
in
writing
to
the
Administrator
that
the
fabric
filter
has
been
inspected
and
found
to
be
in
good
operating
condition.
(
e)
For
each
PM
detector,
you
must
meet
any
applicable
requirements
in
paragraphs
(
a)(
1)
through
(
5)
and
(
e)(
1)
through
(
8)
of
this
section.
(
1)
The
PM
detector
must
be
certified
by
the
manufacturer
to
be
capable
of
detecting
PM
emissions
at
concentrations
of
10
milligrams
per
actual
cubic
meter
(
0.0044
grains
per
actual
cubic
foot)
or
less.
(
2)
The
sensor
on
the
PM
detector
must
provide
output
of
relative
PM
emissions.
(
3)
The
PM
detector
must
have
an
alarm
that
will
sound
automatically
when
it
detects
an
increase
in
relative
PM
emissions
greater
than
a
preset
level.
(
4)
The
alarm
must
be
located
in
an
area
where
appropriate
plant
personnel
will
be
able
to
hear
it.
(
5)
For
a
positive
pressure
electrostatic
precipitator
(
ESP),
each
compartment
must
have
a
PM
detector.
For
a
negative
pressure
or
induced
air
ESP,
the
PM
detector
must
be
installed
downstream
of
the
ESP.
If
multiple
PM
detectors
are
required
(
for
either
type
of
ESP),
detectors
may
share
the
system
instrumentation
and
alarm.
(
6)
Particulate
matter
detectors
must
be
installed,
operated,
adjusted,
and
maintained
so
that
they
follow
the
manufacturer's
written
specifications
and
recommendations.
Standard
operating
procedures
must
be
incorporated
into
the
OM&
M
plan.
(
7)
At
a
minimum,
initial
adjustment
of
the
system
must
consist
of
establishing
the
baseline
output
in
both
of
the
following
ways:
(
i)
Adjust
the
range
and
the
averaging
period
of
the
device.
(
ii)
Establish
the
alarm
set
points
and
the
alarm
delay
time.
(
8)
After
initial
adjustment,
the
range,
averaging
period,
alarm
set
points,
or
alarm
delay
time
may
not
be
adjusted
except
as
specified
in
the
OM&
M
plan
required
by
§
63.7100(
d).
In
no
event
may
the
range
be
increased
by
more
than
100
percent
or
decreased
by
more
than
50
percent
over
a
365
day
period
unless
a
responsible
official
as
defined
in
§
63.2
certifies
in
writing
to
the
Administrator
that
the
ESP
has
been
inspected
and
found
to
be
in
good
operating
condition.
(
f)
For
each
emission
unit
equipped
with
an
add
on
air
pollution
control
device,
you
must
inspect
each
capture/
collection
and
closed
vent
system
at
least
once
each
calendar
year
to
ensure
that
each
system
is
operating
in
accordance
with
the
operating
requirements
in
item
6
of
Table
2
to
this
subpart
and
record
the
results
of
each
inspection.
(
g)
For
each
COMS
used
to
monitor
an
add
on
air
pollution
control
device,
you
must
meet
the
requirements
in
paragraphs
(
g)(
1)
and
(
2)
of
this
section.
(
1)
Install
the
COMS
at
the
outlet
of
the
control
device.
(
2)
Install,
maintain,
calibrate,
and
operate
the
COMS
as
required
by
40
CFR
part
63,
subpart
A,
General
Provisions
and
according
to
PS
1
of
appendix
B
to
part
60
of
this
chapter.
§
63.7114
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations
standard?
(
a)
You
must
demonstrate
initial
compliance
with
each
emission
limitation
in
Table
1
to
this
subpart
that
applies
to
you,
according
to
Table
3
to
this
subpart.
(
b)
You
must
establish
each
sitespecific
operating
limit
in
Table
2
to
this
subpart
that
applies
to
you
according
to
the
requirements
in
§
63.7112(
j)
and
Table
4
to
this
subpart.
(
c)
You
must
submit
the
Notification
of
Compliance
Status
containing
the
results
of
the
initial
compliance
demonstration
according
to
the
requirements
in
§
63.7130(
e).
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Continuous
Compliance
Requirements
§
63.7120
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
(
a)
You
must
monitor
and
collect
data
according
to
this
section.
(
b)
Except
for
monitor
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
(
including,
as
applicable,
calibration
checks
and
required
zero
adjustments),
you
must
monitor
continuously
(
or
collect
data
at
all
required
intervals)
at
all
times
that
the
emission
unit
is
operating.
(
c)
You
may
not
use
data
recorded
during
monitoring
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
in
data
averages
and
calculations
used
to
report
emission
or
operating
levels,
nor
may
such
data
be
used
in
fulfilling
a
minimum
data
availability
requirement,
if
applicable.
You
must
use
all
the
data
collected
during
all
other
periods
in
assessing
the
operation
of
the
control
device
and
associated
control
system.
§
63.7121
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations
standard?
(
a)
You
must
demonstrate
continuous
compliance
with
each
emission
limitation
in
Tables
1
and
2
to
this
subpart
that
applies
to
you
according
to
the
methods
specified
in
Tables
5
and
6
to
this
subpart.
(
b)
You
must
report
each
instance
in
which
you
did
not
meet
each
operating
limit,
opacity
limit,
and
VE
limit
in
Tables
2
and
6
to
this
subpart
that
applies
to
you.
This
includes
periods
of
startup,
shutdown,
and
malfunction.
These
instances
are
deviations
from
the
emission
limitations
in
this
subpart.
These
deviations
must
be
reported
according
to
the
requirements
in
§
63.7131.
(
c)
During
periods
of
startup,
shutdown,
and
malfunction,
you
must
operate
in
accordance
with
the
SSMP.
(
d)
Consistent
with
§
§
63.6(
e)
and
63.7(
e)(
1),
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
not
violations
if
you
demonstrate
to
the
Administrator's
satisfaction
that
you
were
operating
in
accordance
with
the
SSMP.
The
Administrator
will
determine
whether
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
violations,
according
to
the
provisions
in
§
63.6(
e).
(
e)
For
each
MPO
subject
to
an
opacity
limitation
as
specified
in
Table
1
to
this
subpart,
and
any
vents
from
buildings
subject
to
an
opacity
limitation,
you
must
conduct
a
VE
check
according
to
item
1
in
Table
6
to
this
subpart,
and
as
follows:
(
1)
Conduct
visual
inspections
that
consist
of
a
visual
survey
of
each
stack
or
process
emission
point
over
the
test
period
to
identify
if
there
are
visible
emissions,
other
than
condensed
water
vapor.
(
2)
Select
a
position
at
least
15
but
not
more
1,320
feet
from
the
affected
emission
point
with
the
sun
or
other
light
source
generally
at
your
back.
(
3)
The
observer
conducting
the
VE
checks
need
not
be
certified
to
conduct
Method
9
in
appendix
A
to
part
60
of
this
chapter,
but
must
meet
the
training
requirements
as
described
in
Method
22
of
appendix
A
to
part
60
of
this
chapter.
Notification,
Reports,
and
Records
§
63.7130
What
notifications
must
I
submit
and
when?
(
a)
You
must
submit
all
of
the
notifications
in
§
§
63.6(
h)(
4)
and
(
5),
63.7(
b)
and
(
c),
63.8(
e),
(
f)(
4)
and
(
6),
and
63.9
(
a)
through
(
j)
that
apply
to
you
by
the
dates
specified.
(
b)
As
specified
in
§
63.9(
b)(
2),
if
you
start
up
your
affected
source
before
[
date
of
publication
of
the
final
rule
in
the
Federal
Register],
you
must
submit
an
Initial
Notification
not
later
than
120
calendar
days
after
[
date
of
publication
of
the
final
rule
in
the
Federal
Register].
(
c)
As
specified
in
§
63.9(
b)(
3),
if
you
startup
your
new
or
reconstructed
affected
source
on
or
after
[
date
of
publication
of
the
final
rule
in
the
Federal
Register],
you
must
submit
an
Initial
Notification
not
later
than
120
calendar
days
after
you
startup
your
affected
source.
(
d)
If
you
are
required
to
conduct
a
performance
test,
you
must
submit
a
notification
of
intent
to
conduct
a
performance
test
at
least
60
calendar
days
before
the
performance
test
is
scheduled
to
begin
as
required
in
§
63.7(
b)(
1).
(
e)
If
you
are
required
to
conduct
a
performance
test,
design
evaluation,
opacity
observation,
VE
observation,
or
other
initial
compliance
demonstration
as
specified
in
Table
3
or
4
to
this
subpart,
you
must
submit
a
Notification
of
Compliance
Status
according
to
§
63.9(
h)(
2)(
ii).
(
1)
For
each
initial
compliance
demonstration
required
in
Table
3
to
this
subpart
that
does
not
include
a
performance
test,
you
must
submit
the
Notification
of
Compliance
Status
before
the
close
of
business
on
the
30th
calendar
day
following
the
completion
of
the
initial
compliance
demonstration.
(
2)
For
each
compliance
demonstration
required
in
Table
5
to
this
subpart
that
includes
a
performance
test
conducted
according
to
the
requirements
in
Table
4
to
this
subpart,
you
must
submit
the
Notification
of
Compliance
Status,
including
the
performance
test
results,
before
the
close
of
business
on
the
60th
calendar
day
following
the
completion
of
the
performance
test
according
to
§
63.10(
d)(
2).
§
63.7131
What
reports
must
I
submit
and
when?
(
a)
You
must
submit
each
report
in
Table
7
to
this
subpart
that
applies
to
you.
(
b)
Unless
the
Administrator
has
approved
a
different
schedule
for
submission
of
reports
under
§
63.10(
a),
you
must
submit
each
report
by
the
date
in
Table
7
to
this
subpart
and
according
to
the
requirements
in
paragraphs
(
b)(
1)
through
(
5)
of
this
section:
(
1)
The
first
compliance
report
must
cover
the
period
beginning
on
the
compliance
date
that
is
specified
for
your
affected
source
in
§
63.7083
and
ending
on
June
30
or
December
31,
whichever
date
is
the
first
date
following
the
end
of
the
first
half
calendar
year
after
the
compliance
date
that
is
specified
for
your
source
in
§
63.7083.
(
2)
The
first
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
follows
the
end
of
the
first
half
calendar
year
after
the
compliance
date
that
is
specified
for
your
affected
source
in
§
63.7083.
(
3)
Each
subsequent
compliance
report
must
cover
the
semiannual
reporting
period
from
January
1
through
June
30
or
the
semiannual
reporting
period
from
July
1
through
December
31.
(
4)
Each
subsequent
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
is
the
first
date
following
the
end
of
the
semiannual
reporting
period.
(
5)
For
each
affected
source
that
is
subject
to
permitting
regulations
pursuant
to
part
70
or
part
71
of
this
chapter,
if
the
permitting
authority
has
established
dates
for
submitting
semiannual
reports
pursuant
to
§
70.6(
a)(
3)(
iii)(
A)
or
§
71.6(
a)(
3)(
iii)(
A)
of
this
chapter,
you
may
submit
the
first
and
subsequent
compliance
reports
according
to
the
dates
the
permitting
authority
has
established
instead
of
according
to
the
dates
in
paragraphs
(
b)(
1)
through
(
4)
of
this
section.
(
c)
The
compliance
report
must
contain
the
information
specified
in
paragraphs
(
c)(
1)
through
(
6)
of
this
section.
(
1)
Company
name
and
address.
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(
2)
Statement
by
a
responsible
official
with
that
official's
name,
title,
and
signature,
certifying
the
truth,
accuracy,
and
completeness
of
the
content
of
the
report.
(
3)
Date
of
report
and
beginning
and
ending
dates
of
the
reporting
period.
(
4)
If
you
had
a
startup,
shutdown
or
malfunction
during
the
reporting
period
and
you
took
actions
consistent
with
your
SSMP,
the
compliance
report
must
include
the
information
in
§
63.10(
d)(
5)(
i).
(
5)
If
there
are
no
deviations
from
any
emission
limitations
(
emission
limit,
operating
limit,
opacity
limit,
and
VE
limit)
that
apply
to
you,
a
statement
that
there
were
no
deviations
from
the
emission
limitations
during
the
reporting
period.
(
6)
If
there
were
no
periods
during
which
the
operating
parameter
monitoring
systems
was
out
of
control
as
specified
in
§
63.8(
c)(
7),
a
statement
that
there
were
no
periods
during
the
which
the
continuous
monitoring
system
(
CMS)
was
out
of
control
during
the
reporting
period.
(
d)
For
each
deviation
from
an
emission
limitation
(
emission
limit,
operating
limit,
opacity
limit,
and
VE
limit)
that
occurs
at
an
affected
source
where
you
are
not
using
a
CMS
to
comply
with
the
emission
limitations
in
this
subpart,
the
compliance
report
must
contain
the
information
specified
in
paragraphs
(
c)(
1)
through
(
4)
and
(
d)(
1)
and
(
2)
of
this
section.
This
includes
periods
of
startup,
shutdown,
and
malfunction.
(
1)
The
total
operating
time
of
each
emission
unit
during
the
reporting
period.
(
2)
Information
on
the
number,
duration,
and
cause
of
deviations
(
including
unknown
cause,
if
applicable),
as
applicable,
and
the
corrective
action
taken.
(
e)
For
each
deviation
from
an
emission
limitation
(
emission
limit,
operating
limit,
opacity
limit,
and
VE
limit)
occurring
at
an
affected
source
where
you
are
using
a
CMS
to
comply
with
the
emission
limitation
in
this
subpart,
you
must
include
the
information
specified
in
paragraphs
(
c)(
1)
through
(
4)
and
(
e)(
1)
through
(
12)
of
this
section.
This
includes
periods
of
startup,
shutdown,
and
malfunction.
(
1)
The
date
and
time
that
each
malfunction
started
and
stopped.
(
2)
The
date
and
time
that
each
CMS
was
inoperative,
except
for
zero
(
lowlevel
and
high
level
checks.
(
3)
The
date,
time
and
duration
that
each
CMS
was
out
of
control,
including
the
information
in
§
63.8(
c)(
8).
(
4)
The
date
and
time
that
each
deviation
started
and
stopped,
and
whether
each
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction
or
during
another
period.
(
5)
A
summary
of
the
total
duration
of
the
deviation
during
the
reporting
period
and
the
total
duration
as
a
percent
of
the
total
source
operating
time
during
that
reporting
period.
(
6)
A
breakdown
of
the
total
duration
of
the
deviations
during
the
reporting
period
into
those
that
are
due
to
startup,
shutdown,
control
equipment
problems,
process
problems,
other
known
causes,
and
other
unknown
causes.
(
7)
A
summary
of
the
total
duration
of
CMS
downtime
during
the
reporting
period
and
the
total
duration
of
CMS
downtime
as
a
percent
of
the
total
emission
unit
operating
time
during
that
reporting
period.
(
8)
An
identification
of
each
HAP
that
was
monitored
at
the
affected
source.
(
9)
A
brief
description
of
the
process
units.
(
10)
A
brief
description
of
the
CMS.
(
11)
The
date
of
the
latest
CMS
certification
or
audit.
(
12)
A
description
of
any
changes
in
CMS,
processes,
or
controls
since
the
last
reporting
period.
(
f)
Each
facility
that
has
obtained
a
title
V
operating
permit
pursuant
to
part
70
or
part
71
of
this
chapter
must
report
all
deviations
as
defined
in
this
subpart
in
the
semiannual
monitoring
report
required
by
§
70.6(
a)(
3)(
iii)(
A)
or
§
71.6(
a)(
3)(
iii)(
A)
of
this
chapter.
If
you
submit
a
compliance
report
specified
in
Table
7
to
this
subpart
along
with,
or
as
part
of,
the
semiannual
monitoring
report
required
by
§
70.6(
a)(
3)(
iii)(
A)
or
§
71.6(
a)(
3)(
iii)(
A)
of
this
chapter,
and
the
compliance
report
includes
all
required
information
concerning
deviations
from
any
emission
limitation
(
including
any
operating
limit),
submission
of
the
compliance
report
shall
be
deemed
to
satisfy
any
obligation
to
report
the
same
deviations
in
the
semiannual
monitoring
report.
However,
submission
of
a
compliance
report
shall
not
otherwise
affect
any
obligation
you
may
have
to
report
deviations
from
permit
requirements
to
the
permit
authority.
§
63.7132
What
records
must
I
keep?
(
a)
You
must
keep
the
records
specified
in
paragraphs
(
a)(
1)
through
(
3)
of
this
section.
(
1)
A
copy
of
each
notification
and
report
that
you
submitted
to
comply
with
this
subpart,
including
all
documentation
supporting
any
Initial
Notification
or
Notification
of
Compliance
Status
that
you
submitted,
according
to
the
requirements
in
§
63.10(
b)(
2)(
xiv).
(
2)
The
records
in
§
63.6(
e)(
3)(
iii)
through
(
v)
related
to
startup,
shutdown,
and
malfunction.
(
3)
Records
of
performance
tests,
performance
evaluations,
and
opacity
and
VE
observations
as
required
in
§
63.10(
b)(
2)(
viii).
(
b)
You
must
keep
the
records
in
§
63.6(
h)(
6)
for
VE
observations.
(
c)
You
must
keep
the
records
required
by
Tables
5
and
6
to
this
subpart
to
show
continuous
compliance
with
each
emission
limitation
that
applies
to
you.
(
d)
You
must
keep
the
records
which
document
the
basis
for
the
initial
applicability
determination
as
required
under
§
63.7081.
§
63.7133
In
what
form
and
how
long
must
I
keep
my
records?
(
a)
Your
records
must
be
in
a
form
suitable
and
readily
available
for
expeditious
review,
according
to
§
63.10(
b)(
1).
(
b)
As
specified
in
§
63.10(
b)(
1),
you
must
keep
each
record
for
5
years
following
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record.
(
c)
You
must
keep
each
record
on
site
for
at
least
2
years
after
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record,
according
to
§
63.10(
b)(
1).
You
may
keep
the
records
offsite
for
the
remaining
3
years.
Other
Requirements
and
Information
§
63.7140
What
parts
of
the
General
Provisions
apply
to
me?
(
a)
Table
8
to
this
subpart
shows
which
parts
of
the
General
Provisions
in
§
§
63.1
through
63.15
apply
to
you.
When
there
is
overlap
between
subpart
A
and
subpart
AAAAA,
as
indicated
in
the
``
Explanations''
column
in
Table
8,
subpart
AAAAA
takes
precedence.
(
b)
[
Reserved]
§
63.7141
Who
implements
and
enforces
this
subpart?
(
a)
This
subpart
can
be
implemented
and
enforced
by
us,
the
U.
S.
EPA,
or
by
a
delegated
authority
such
as
your
State,
local,
or
tribal
agency.
If
the
U.
S.
EPA
Administrator
has
delegated
authority
to
your
State,
local,
or
tribal
agency,
then
that
agency
(
as
well
as
the
U.
S.
EPA)
has
the
authority
to
implement
and
enforce
this
subpart.
You
should
contact
your
U.
S.
EPA
Regional
Office
to
find
out
if
this
subpart
is
delegated
to
your
State,
local,
or
tribal
agency.
(
b)
In
delegating
implementation
and
enforcement
authority
of
this
subpart
to
a
State,
local,
or
tribal
agency
under
subpart
E
of
this
part,
the
authorities
contained
in
paragraph
(
c)
of
this
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/
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67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
section
are
retained
by
the
Administrator
of
U.
S.
EPA
and
are
not
transferred
to
the
State,
local,
or
tribal
agency.
(
c)
The
authorities
that
will
not
be
delegated
to
State,
local,
or
tribal
agencies
are
as
specified
in
paragraphs
(
c)(
1)
through
(
6)
of
this
section.
(
1)
Approval
of
alternatives
to
the
non
opacity
emission
limitations
in
§
63.7090(
a).
(
2)
Approval
of
alternative
opacity
emission
limitations
in
§
63.7090(
a).
(
3)
Approval
of
alternatives
to
the
operating
limits
in
§
63.7090(
b).
(
4)
Approval
of
major
alternatives
to
test
methods
under
§
63.7(
e)(
2)(
ii)
and
(
f)
and
as
defined
in
§
63.90.
(
5)
Approval
of
major
alternatives
to
monitoring
under
§
63.8(
f)
and
as
defined
in
§
63.90.
(
6)
Approval
of
major
alternatives
to
recordkeeping
and
reporting
under
§
63.10(
f)
and
as
defined
in
§
63.90.
§
63.7142
What
are
the
requirements
for
claiming
area
source
status?
(
a)
If
you
wish
to
claim
that
your
LMP
is
an
area
source,
you
must
measure
the
emissions
of
hydrogen
chloride
from
all
lime
kilns
at
your
plant
using
either:
(
1)
EPA
Method
320
of
appendix
A
to
this
part,
(
2)
EPA
Method
321
of
appendix
A
to
this
part,
or
(
3)
ASTM
Method
D6735
01,
Standard
Test
Method
for
Measurement
of
Gaseous
Chlorides
and
Fluorides
from
Mineral
Calcining
Exhaust
Sources
Impinger
Method
(
incorporated
by
reference
see
§
63.14),
provided
that
the
provisions
in
paragraphs
(
a)(
3)(
i)
through
(
vi)
of
this
section
are
followed.
(
i)
A
test
must
include
three
or
more
runs
in
which
a
pair
of
samples
is
obtained
simultaneously
for
each
run
according
to
section
11.2.6
of
ASTM
Method
D6735
01
(
incorporated
by
reference
see
§
63.14).
(
ii)
You
must
calculate
the
test
run
standard
deviation
of
each
set
of
paired
samples
to
quantify
data
precision,
according
to
Equation
1
of
this
section:
RSD
C
C
C
Eq
a
a
a
a
=
+
(
)
(
.
100
2
1
2
Absolute
Value
C1
1)
a
Where:
RSDa
=
The
test
run
relative
standard
deviation
of
sample
pair
a,
percent.
C1a
and
C2a
=
The
HCl
concentrations,
mg/
dscm,
from
the
paired
samples.
(
iii)
You
must
calculate
the
test
average
relative
standard
deviation
according
to
Equation
2
of
this
section:
RSD
RSD
p
Eq
TA
a
a
p
=
=
1
(
.
2)
Where:
RSDTA
=
The
test
average
relative
standard
deviation,
percent.
RSDa
=
The
test
run
relative
standard
deviation
for
sample
pair
a.
p
=
The
number
of
test
runs,
3.
(
iv)
If
RSDTA
is
greater
than
20
percent,
the
data
are
invalid
and
the
test
must
be
repeated.
(
v)
The
post
test
analyte
spike
procedure
of
section
11.2.7
of
ASTM
Method
D6735
01
(
incorporated
by
reference
see
§
63.14)
is
conducted,
and
the
percent
recovery
is
calculated
according
to
section
12.6
of
ASTM
Method
D6735
01
(
incorporated
by
reference
see
§
63.14).
(
vi)
If
the
percent
recovery
is
between
70
percent
and
130
percent,
inclusive,
the
test
is
valid.
If
the
percent
recovery
is
outside
of
this
range,
the
data
are
considered
invalid,
and
the
test
must
be
repeated.
(
b)
If
you
conduct
tests
to
determine
the
rates
of
emission
of
specific
organic
HAP
from
lime
kilns
at
LMP
for
use
in
applicability
determinations
under
§
63.7081,
you
may
use
either:
(
1)
Method
320
of
appendix
A
to
this
part,
or
(
2)
Method
18
of
appendix
A
to
part
60
of
this
chapter,
or
(
3)
ASTM
D6420
99,
Standard
Test
Method
for
Determination
of
Gaseous
Organic
Compounds
by
Direct
Interface
Gas
Chromatography
Mass
Spectrometry
(
GC/
MS),
(
incorporated
by
reference
see
§
63.14),
provided
that
the
provisions
of
paragraphs
(
b)(
3)(
i)
through
(
iv)
of
this
section
are
followed:
(
i)
The
target
compound(
s)
are
those
listed
in
section
1.1
of
ASTM
D6420
99
(
incorporated
by
reference
see
§
63.14);
(
ii)
The
target
concentration
is
between
150
parts
per
billion
by
volume
and
100
ppmv;
(
iii)
For
target
compound(
s)
not
listed
in
Table
1.1
of
ASTM
D6420
99
(
incorporated
by
reference
see
§
63.14),
but
potentially
detected
by
mass
spectrometry,
the
additional
system
continuing
calibration
check
after
each
run,
as
detailed
in
section
10.5.3
of
ASTM
D6420
99
(
incorporated
by
reference
see
§
63.14),
is
conducted,
met,
documented,
and
submitted
with
the
data
report,
even
if
there
is
no
moisture
condenser
used
or
the
compound
is
not
considered
water
soluble;
and
(
iv)
For
target
compound(
s)
not
listed
in
Table
1.1
of
ASTM
D6420
99
(
incorporated
by
reference
see
§
63.14),
and
not
amenable
to
detection
by
mass
spectrometry,
ASTM
D6420
99
(
incorporated
by
reference
see
§
63.14)
may
not
be
used.
§
63.7143
What
definitions
apply
to
this
subpart?
Terms
used
in
this
subpart
are
defined
in
the
Clean
Air
Act,
in
§
63.2,
and
in
this
section
as
follows:
Bag
leak
detector
means
the
monitoring
device
and
system
for
a
fabric
filter
that
identifies
an
increase
in
PM
emissions
resulting
from
a
broken
filter
bag
or
other
malfunction
and
sounds
an
alarm.
Belt
conveyor
means
a
conveying
device
that
transports
material
from
one
location
to
another
by
means
of
an
endless
belt
that
is
carried
on
a
series
of
idlers
and
routed
around
a
pulley
at
each
end.
Bucket
elevator
means
a
material
conveying
device
consisting
of
a
head
and
foot
assembly
which
supports
and
drives
an
endless
single
or
double
strand
chain
or
belt
to
which
buckets
are
attached.
Building
means
any
frame
structure
with
a
roof.
Capture
system
means
the
equipment
(
including
enclosures,
hoods,
ducts,
fans,
dampers,
etc.)
used
to
capture
and
transport
PM
generated
by
one
or
more
process
operations
to
a
control
device.
Control
device
means
the
air
pollution
control
equipment
used
to
reduce
PM
emissions
released
to
the
atmosphere
from
one
or
more
process
operations
at
an
LMP.
Conveying
system
means
a
device
for
transporting
material
from
one
piece
of
equipment
or
location
to
another
location
within
a
plant.
Conveying
systems
include
but
are
not
limited
to
feeders,
belt
conveyors,
bucket
elevators
and
pneumatic
systems.
Deviation
means
any
instance
in
which
an
affected
source,
subject
to
this
subpart,
or
an
owner
or
operator
of
such
a
source:
(
1)
Fails
to
meet
any
requirement
or
obligation
established
by
this
subpart,
including
but
not
limited
to
any
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78077
Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
emission
limitation
(
including
any
operating
limit);
(
2)
Fails
to
meet
any
term
or
condition
that
is
adopted
to
implement
an
applicable
requirement
in
this
subpart
and
that
is
included
in
the
operating
permit
for
any
affected
source
required
to
obtain
such
a
permit;
or
(
3)
Fails
to
meet
any
emission
limitation
(
including
any
operating
limit)
in
this
subpart
during
startup,
shutdown,
or
malfunction,
regardless
of
whether
or
not
such
failure
is
permitted
by
this
subpart.
Emission
limitation
means
any
emission
limit,
opacity
limit,
operating
limit,
or
VE
limit.
Emission
unit
means
a
lime
kiln,
lime
cooler,
raw
material
grinding
mill,
raw
material
storage
bin,
conveying
system
transfer
point,
bulk
loading
or
unloading
operation,
bucket
elevator
or
belt
conveyor
at
an
LMP.
Fugitive
emission
means
PM
that
is
not
collected
by
a
capture
system.
Grinding
mill
means
a
machine
used
for
the
wet
or
dry
fine
crushing
of
any
feed
material.
Grinding
mills
include,
but
are
not
limited
to,
the
hammer,
roller,
rod,
pebble
and
ball,
and
fluid
energy.
The
grinding
mill
includes
the
air
conveying
system,
air
separator,
or
air
classifier,
where
such
systems
are
used.
Hydrator
means
the
device
used
to
produce
hydrated
lime
or
calcium
hydroxide
via
the
chemical
reaction
of
the
lime
product
and
water.
Lime
cooler
means
the
device
external
to
the
lime
kiln
(
or
part
of
the
lime
kiln
itself)
used
to
reduce
the
temperature
of
the
lime
produced
by
the
kiln.
Lime
kiln
means
the
device,
including
any
associated
preheater,
used
to
produce
a
lime
product
from
stone
feed
by
calcination.
Kiln
types
include,
but
are
not
limited
to,
rotary
kiln,
vertical
kiln,
rotary
hearth
kiln,
double
shaft
vertical
kiln,
and
fluidized
bed
kiln.
Lime
manufacturing
plant
(
LMP)
means
any
plant
which
uses
a
lime
kiln
to
produce
lime
product
from
limestone
or
other
calcareous
material
by
calcination.
Lime
product
means
the
product
of
the
lime
kiln
calcination
process
including,
calcitic
lime,
dolomitic
lime,
and
dead
burned
dolomite.
Limestone
means
the
material
comprised
primarily
of
calcium
carbonate
(
referred
to
sometimes
as
calcitic
or
high
calcium
limestone),
magnesium
carbonate,
and/
or
the
double
carbonate
of
both
calcium
and
magnesium
(
referred
to
sometimes
as
dolomitic
limestone
or
dolomite).
Material
means
the
raw
limestone
or
stone
feed
used
at
an
LMP.
Materials
processing
operation
(
MPO)
means
the
equipment
and
transfer
points
between
the
equipment
used
to
prepare,
process,
or
transport
limestone,
or
stone
feed,
and
includes
grinding
mills,
raw
material
storage
bins,
conveying
system
transfer
points,
bulk
loading
or
unloading
systems,
screening
operations,
bucket
elevators,
and
belt
conveyors.
Particulate
matter
(
PM)
detector
means
the
monitoring
device
and
system
for
an
ESP
that
identifies
relative
levels
in
PM
emissions
and
sounds
an
alarm
at
a
preset
level.
Positive
pressure
fabric
filter
or
ESP
means
a
fabric
filter
or
ESP
with
the
fan(
s)
on
the
upstream
side
of
the
control
device.
Screening
operation
means
a
device
for
separating
material
according
to
size
by
passing
undersize
material
through
one
or
more
mesh
surfaces
(
screens)
in
series
and
retaining
oversize
material
on
the
mesh
surfaces
(
screens).
Stack
emission
means
the
PM
that
is
released
to
the
atmosphere
from
a
capture
system.
Stone
feed
means
the
limestone
feedstock
and
mill
scale
or
other
iron
oxide
additives
that
are
fed
to
the
lime
kiln.
Stone
feed
does
not
include
the
fuels
used
in
the
lime
kiln
to
produce
the
heat
needed
to
calcine
the
limestone
into
the
lime
product.
Storage
bin
means
a
facility
for
storage
(
including
surge
bins)
of
material
prior
to
further
processing
or
loading.
Transfer
point
means
a
point
in
a
conveying
operation
where
the
material
is
transferred
to
or
from
a
belt
conveyor
(
except
where
the
material
is
being
transferred
to
a
stockpile).
Truck
dumping
means
the
unloading
of
material
from
movable
vehicles
designed
to
transport
material
from
one
location
to
another.
Movable
vehicles
include
but
are
not
limited
to
trucks,
front
end
loaders,
skip
hoists,
and
railcars.
Vent
means
an
opening
through
which
there
is
mechanically
induced
air
flow
for
the
purpose
of
exhausting
from
a
building
air
carrying
PM
emissions
from
one
or
more
emission
units.
Tables
to
Subpart
AAAAA
of
Part
63
TABLE
1
TO
SUBPART
AAAAA
OF
PART
63.
EMISSION
LIMITS
[
You
must
meet
each
emission
limit
in
the
following
table
that
applies
to
you,
as
required
in
§
63.7090(
a)]
For
.
.
.
You
must
meet
the
following
emission
limitation
.
.
.
1.
All
lime
kilns
and
their
associated
lime
coolers
at
an
existing
LMP
....
The
sum
of
the
PM
emissions
from
all
of
the
kilns
and
associated
lime
coolers
must
not
exceed
0.06
kilograms
per
megagram
(
kg/
Mg)
(
0.12
pounds
per
ton)
of
stone
feed.
2.
All
lime
kilns
and
their
associated
lime
coolers
at
a
new
or
reconstructed
LMP.
The
sum
of
the
PM
emissions
from
all
of
the
kilns
and
associated
lime
coolers
must
not
exceed
0.05
kg/
Mg
(
0.10
pounds
per
ton)
of
stone
feed.
3.
Stack
emissions
from
all
MPO
at
a
new,
reconstructed
or
existing
affected
source.
PM
emissions
must
not
exceed
0.05
grams
per
dry
standard
cubic
meter
(
g/
dscm).
4.
Stack
emissions
from
all
MPO
at
a
new,
reconstructed
or
existing
affected
source,
unless
the
stack
emissions
are
discharged
through
a
wet
scrubber
control
device.
Emissions
must
not
exceed
7
percent
opacity.
5.
Fugitive
emissions
from
all
MPO
at
a
new,
reconstructed
or
existing
affected
source,
except
as
provided
by
item
6
of
this
Table
1.
Emissions
must
not
exceed
10
percent
opacity.
6.
All
MPO
at
a
new,
reconstructed
or
existing
affected
source
enclosed
in
a
building.
All
of
the
individually
affected
MPO
must
comply
with
the
applicable
PM
and
opacity
emission
limitations
in
items
3
through
5
of
this
Table
1,
or
the
building
must
comply
with
the
following:
there
must
be
no
visible
emissions
from
the
building,
except
from
a
vent;
and
vent
emissions
must
not
exceed
the
stack
emissions
limitations
in
items
3
and
4
of
this
Table
1.
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20DEP2
78078
Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
TABLE
1
TO
SUBPART
AAAAA
OF
PART
63.
EMISSION
LIMITS
Continued
[
You
must
meet
each
emission
limit
in
the
following
table
that
applies
to
you,
as
required
in
§
63.7090(
a)]
For
.
.
.
You
must
meet
the
following
emission
limitation
.
.
.
7.
Each
fabric
filter
that
controls
emissions
from
only
an
individual,
enclosed
storage
bin.
Emissions
must
not
exceed
7
percent
opacity.
8.
Each
set
of
multiple
storage
bins
at
a
new,
reconstructed
or
existing
affected
source,
with
combined
stack
emissions.
You
must
comply
with
the
emission
limits
in
items
3
and
4
of
this
Table
1.
TABLE
2
TO
SUBPART
AAAAA
OF
PART
63.
OPERATING
LIMITS
[
You
must
meet
each
operating
limit
in
the
following
table
that
applies
to
you,
as
required
in
§
63.7090(
b)]
For
.
.
.
You
must
.
.
.
1.
Each
lime
kiln
and
each
lime
cooler
(
if
there
is
a
separate
exhaust
to
the
atmosphere
from
the
associated
lime
cooler)
equipped
with
a
fabric
filter.
Maintain
and
operate
the
fabric
filter
such
that
the
bag
leak
detector
alarm
is
not
activated
and
alarm
condition
does
not
exist
for
more
than
5
percent
of
the
total
operating
time
in
a
6
month
period;
and
comply
with
the
requirements
in
§
63.7113(
d)
and
(
f)
and
Table
5
to
this
subpart.
In
lieu
of
a
bag
leak
detector,
maintain
the
fabric
filter
such
that
the
6
minute
average
opacity
for
any
6
minute
block
period
does
not
exceed
15
percent;
and
comply
with
the
requirements
in
§
63.7113(
f)
and
(
g)
and
Table
5
to
this
subpart.
2.
Each
lime
kiln
equipped
with
a
wet
scrubber
......................................
Maintain
the
3
hour
rolling
average
exhaust
gas
stream
pressure
drop
across
the
wet
scrubber
greater
than
or
equal
to
the
pressure
drop
operating
limit
established
during
the
most
recent
PM
performance
test;
and
maintain
the
3
hour
rolling
average
scrubbing
liquid
flow
rate
greater
than
the
flow
rate
operating
limit
established
during
the
most
recent
performance
test.
3.
Each
lime
kiln
equipped
with
an
electrostatic
precipitator
...................
Maintain
the
3
hour
rolling
average
current
and
voltage
input
to
each
electrical
field
of
the
ESP
greater
than
or
equal
to
the
average
current
and
voltage
input
to
each
field
of
the
ESP
established
during
the
most
recent
performance
test;
or,
in
lieu
of
complying
with
these
ESP
parameter
operating
limits,
install
a
PM
detector
and
maintain
and
operate
the
ESP
such
that
the
PM
detector
alarm
is
not
activated
and
alarm
condition
does
not
exist
for
more
than
5
percent
of
the
total
operating
time
in
a
6
month
period,
and
comply
with
§
63.7113(
e);
or,
maintain
the
ESP
such
that
the
6
minute
average
opacity
for
any
6
minute
block
period
does
not
exceed
15
percent,
and
comply
with
the
requirements
in
§
63.7113(
g);
and
comply
with
the
requirements
in
§
63.7113(
f)
and
Table
5
to
this
subpart.
4.
Each
materials
processing
operation
subject
to
a
PM
limit
which
uses
a
wet
scrubber.
Maintain
the
3
hour
rolling
average
exhaust
gas
stream
pressure
drop
across
the
wet
scrubber
greater
than
or
equal
to
the
pressure
drop
operating
limit
established
during
the
PM
performance
test;
and
maintain
the
3
hour
rolling
average
scrubbing
liquid
flow
rate
greater
than
or
equal
to
the
flow
rate
operating
limit
established
during
the
performance
test.
5.
All
affected
sources
..............................................................................
Prepare
a
written
OM&
M
plan;
the
plan
must
include
the
items
listed
in
§
63.7100(
d)
and
the
corrective
actions
to
be
taken
when
required
in
Table
5
to
this
subpart.
6.
Each
emission
unit
equipped
with
an
add
on
air
pollution
control
device
(
1)
Vent
captured
emissions
through
a
closed
system,
except
that
dilution
air
may
be
added
to
emission
streams
for
the
purpose
of
controlling
temperature
at
the
inlet
to
a
fabric
filter.
(
2)
Operate
each
capture/
collection
system
according
to
the
procedures
and
requirements
in
the
OM&
M
plan.
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20DEP2.
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78079
Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
TABLE
3
TO
SUBPART
AAAAA
OF
PART
63.
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITS
[
You
must
demonstrate
initial
compliance
with
each
emission
limitation
that
applies
to
you,
according
to
the
following
table,
as
required
in
§
63.7114]
For
.
.
.
For
the
emission
limitation
.
.
.
You
have
demonstrated
initial
compliance,
if
after
following
the
requirements
in
§
63.7112
.
.
.
1.
All
lime
kilns
and
their
associated
lime
coolers
at
a
new
or
reconstructed
affected
source
and
all
lime
kilns
and
their
associated
lime
coolers
at
an
existing
affected
source.
If
the
lime
cooler
associated
with
the
kiln
has
no
separate
exhaust
to
the
atmosphere,
PM
emissions
from
all
kilns
and
coolers
at
an
existing
LMP
must
not
exceed
0.06
kg
PM
per
Mg
of
stone
feed
(
0.12
lb
PM
per
ton
of
stone
feed);
PM
emissions
from
all
kilns
and
coolers
at
a
new
or
reconstructed
LMP
must
not
exceed
0.05
kg
PM
per
Mg
of
stone
feed
(
0.10
lb
PM
per
ton
of
stone
feed);
if
a
lime
cooler
associated
with
a
kiln
has
a
separate
exhaust
to
the
atmosphere
the
sum
of
all
kiln
and
cooler
PM
emissions
must
not
exceed
0.06
kg/
Mg
(
0.12
pounds
per
ton)
of
stone
feed
for
existing
LMP
and
0.05
kg/
Mg
(
0.1
pounds
per
ton)
of
stone
feed
for
kilns
at
new
or
reconstructed
LMP.
The
kiln
outlet
PM
emissions
(
and
if
applicable,
summed
with
the
separate
cooler
PM
emissions),
based
on
the
PM
emissions
measured
using
Method
5
in
appendix
A
to
part
60
of
this
chapter
and
the
stone
feed
rate
measurement,
over
the
period
of
the
initial
performance
test,
do
not
exceed
the
emission
limit;
if
the
lime
kiln
is
controlled
with
an
ESP
(
and
you
are
not
opting
to
monitor
PM
emissions
from
the
ESP
with
a
PM
detector
or
COMS)
or
wet
scrubber,
you
have
a
record
of
the
applicable
operating
parameters
over
the
3
hour
performance
test
during
which
emissions
did
not
exceed
the
emissions
limitation;
if
the
lime
kiln
is
controlled
by
a
fabric
filter
or
ESP
and
you
are
opting
to
monitor
PM
emissions
from
the
ESP
with
a
PM
detector
or
you
are
opting
to
monitor
PM
emissions
from
the
fabric
filter
with
a
bag
leak
detector,
you
have
installed
and
are
operating
the
monitoring
device
according
to
the
requirements
in
§
63.7113(
d)
or
(
e),
respectively;
and
if
the
lime
kiln
is
controlled
by
a
fabric
filter
or
ESP
and
you
are
opting
to
monitor
PM
emissions
using
a
COMS,
you
have
installed
and
are
operating
the
monitoring
device
according
to
the
requirements
in
§
63.7113(
g).
2.
Stack
emissions
from
all
MPO
at
a
new,
reconstructed
or
existing
affected
source.
PM
emissions
must
not
exceed
0.05
g/
dscm
.................
The
outlet
PM
emissions,
based
on
Method
5
or
Method
17
in
appendix
A
to
part
60
of
this
chapter,
over
the
period
of
the
initial
performance
test
do
not
exceed
0.05
g/
dscm;
and
if
the
emission
unit
is
controlled
with
a
wet
scrubber,
you
have
a
record
of
the
scrubber's
pressure
drop
and
liquid
flow
rate
operating
parameters
over
the
3
hour
performance
test
during
which
emissions
did
not
exceed
the
emissions
limitation.
3.
Stack
emissions
from
all
MPO
at
a
new,
reconstructed
or
existing
affected
source,
unless
the
stack
emissions
are
discharged
through
a
wet
scrubber
control
device.
Emissions
must
not
exceed
7
percent
opacity
...............
Each
of
the
thirty
6
minute
opacity
averages
during
the
initial
compliance
period,
using
Method
9
in
appendix
A
to
part
60
of
this
chapter,
does
not
exceed
the
7
percent
opacity
limit.
4.
Fugitive
emissions
from
all
MPO
at
a
new,
reconstructed
or
existing
affected
source.
Emissions
must
not
exceed
10
percent
opacity
.............
Each
of
the
6
minute
opacity
averages
during
the
initial
compliance
period,
using
Method
9
in
appendix
A
to
part
60
of
this
chapter,
does
not
exceed
the
10
percent
opacity
limit.
5.
All
MPO
at
a
new,
reconstructed
or
existing
affected
source,
enclosed
in
a
building.
All
of
the
individually
affected
MPO
must
comply
with
the
applicable
PM
and
opacity
emission
limitations
for
items
2
through
4
of
this
Table
3,
or
the
building
must
comply
with
the
following:
there
must
be
no
visible
emissions
from
the
building,
except
from
a
vent,
and
vent
emissions
must
not
exceed
the
emission
limitations
in
items
2
and
3
of
this
Table
3.
All
the
MPO
enclosed
in
the
building
have
demonstrated
initial
compliance
according
to
the
applicable
requirements
for
items
2
through
4
of
this
Table
3;
or
if
you
are
complying
with
the
building
emission
limitations,
there
are
no
visible
emissions
from
the
building
according
to
item
18
of
Table
4
to
this
subpart
and
§
63.7112(
k),
and
you
demonstrate
initial
compliance
with
applicable
building
vent
emissions
limitations
according
to
the
requirements
in
items
2
and
3
of
this
Table
3.
6.
Each
fabric
filter
that
controls
emissions
from
only
an
individual
storage
bin.
Emissions
must
not
exceed
7
percent
opacity
...............
Each
of
the
ten
6
minute
averages
during
the
1
hour
initial
compliance
period,
using
Method
9
in
appendix
A
to
part
60
of
this
chapter,
does
not
exceed
the
7
percent
opacity
limit.
7.
Each
set
of
multiple
storage
bins
with
combined
stack
emissions.
You
must
comply
with
the
emission
limitations
in
items
2
and
3
of
this
Table
3.
You
demonstrate
initial
compliance
according
to
the
requirements
in
items
2
and
3
of
this
Table
3.
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Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
TABLE
4
TO
SUBPART
AAAAA
OF
PART
63.
REQUIREMENTS
FOR
PERFORMANCE
TESTS
[
You
must
conduct
each
performance
test
in
the
following
table
that
applies
to
you,
as
required
in
§
63.7112]
For
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.
1.
Each
lime
kiln
and
each
associated
lime
cooler,
if
there
is
a
separate
exhaust
to
the
atmosphere
from
the
associated
lime
cooler.
Select
the
location
of
the
sampling
port
and
the
number
of
traverse
ports.
Method
1
or
1A
of
appendix
A
to
part
60
of
this
chapter;
and
§
63.7(
d)(
1)(
i).
Sampling
sites
must
be
located
at
the
outlet
of
the
control
device
s)
and
prior
to
any
releases
to
the
atmosphere.
2.
Each
lime
kiln
and
each
associated
lime
cooler,
if
there
is
a
separate
exhaust
to
the
atmosphere
from
the
associated
lime
cooler.
Determine
velocity
and
volumetric
flow
rate.
Method
2,
2A,
2C,
2D,
2F,
or
2G
in
appendix
A
to
part
60
of
this
chapter.
Not
applicable.
3.
Each
lime
kiln
and
each
associated
lime
cooler,
if
there
is
a
separate
exhaust
to
the
atmosphere
from
the
associated
lime
cooler.
Conduct
gas
molecular
weight
analysis.
Method
3,
3A,
or
3B
in
appendix
A
to
part
60
of
this
chapter.
Not
applicable.
4.
Each
lime
kiln
and
each
associated
lime
cooler,
if
there
is
a
separate
exhaust
to
the
atmosphere
from
the
associated
limit
cooler.
Measure
moisture
content
of
the
stack
gas.
Method
4
in
appendix
A
to
part
60
of
this
chapter.
Not
applicable.
5.
Each
lime
kiln
and
each
associated
lime
cooler,
if
there
is
a
separate
exhaust
to
the
atmosphere
from
the
associated
lime
cooler,
and
which
uses
a
negative
pressure
PM
control
device.
Measure
PM
emissions
................
Method
5
in
appendix
A
to
part
60
of
this
chapter.
Conduct
the
test(
s)
at
the
highest
production
level
reasonably
expected
to
occur;
the
minimum
sampling
volume
must
be
0.85
dscm
(
30
dscf);
if
there
is
a
separate
lime
cooler
exhaust
to
the
atmosphere,
you
must
conduct
the
Method
5
test
of
the
cooler
exhaust
concurrently
with
the
kiln
exhaust
test.
6.
Each
lime
kiln
and
each
associated
lime
cooler,
if
there
is
a
separate
exhaust
to
the
atmosphere
from
the
associated
lime
cooler,
and
which
uses
a
positive
pressure
fabric
filter
or
ESP.
Measure
PM
emissions
................
Method
5D
in
appendix
A
to
part
60
of
this
chapter.
Conduct
the
test(
s)
at
the
highest
production
level
reasonably
expected
to
occur;
if
there
is
a
separate
lime
cooler
exhaust
to
the
atmosphere,
you
must
conduct
the
Method
5
test
of
the
separate
cooler
exhaust
concurrently
with
the
kiln
exhaust
test.
7.
Each
lime
kiln
............................
Determine
the
mass
rate
of
stone
feed
to
the
kiln
during
the
kiln
PM
emissions
test.
Any
suitable
device
......................
Calibrate
and
maintain
the
device
according
to
manufacturer's
instructions
the
measuring
device
used
must
be
accurate
to
within
±
5
percent
of
the
mass
rate
over
its
operating
range.
8.
Each
lime
kiln
equipped
with
a
wet
scrubber.
Establish
the
operating
limit
for
the
average
gas
stream
pressure
drop
across
the
wet
scrubber
Data
for
the
gas
stream
pressure
drop
measurement
device
during
the
kiln
PM
performance
test.
The
continuous
pressure
drop
measurement
device
must
be
accurate
within
plus
or
minus
1
percent;
you
must
collect
the
pressure
drop
data
during
the
period
of
the
performance
test
and
determine
the
operating
limit
according
to
63.7112(
j).
9.
Each
lime
kiln
equipped
with
a
wet
scrubber.
Establish
the
operating
limit
for
the
average
liquid
flow
rate
to
the
scrubber.
Data
from
the
liquid
flow
rate
measurement
device
during
the
kiln
PM
performance
test.
The
continuous
scrubbing
liquid
flow
rate
measuring
device
must
be
accurate
within
plus
or
minus
1
percent;
you
must
collect
the
flow
rate
data
during
the
period
of
the
performance
test
and
determine
the
operating
limit
according
to
63.7112(
j).
10.
Each
lime
kiln
equipped
with
an
ESP,
except
ESP
monitored
with
a
PM
detector
in
lieu
of
monitoring
ESP
parameters.
Establish
the
operating
limits
for
the
average
current
and
the
average
voltage
supplied
to
each
field
of
the
ESP.
The
ESP
operating
data
during
the
kiln
PM
performance
test.
You
must
collect
the
current
and
voltage
data
during
the
period
of
the
performance
test
and
determine
the
operating
limits
for
both
parameters
according
to
63.7112(
j).
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20DEP2.
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Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
TABLE
4
TO
SUBPART
AAAAA
OF
PART
63.
REQUIREMENTS
FOR
PERFORMANCE
TESTS
Continued
[
You
must
conduct
each
performance
test
in
the
following
table
that
applies
to
you,
as
required
in
§
63.7112]
For
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.
11.
(
a)
Each
lime
kiln
equipped
with
a
fabric
filter
or
ESP
that
is
monitored
with
a
PM
detector.
Have
installed
and
have
operating
the
bag
leak
detector
or
PM
detector
respectively
prior
to
the
performance
test.
Standard
operating
procedures
incorporated
into
the
OM&
M
plan.
According
to
the
requirements
in
§
63.7113(
d)
or
(
e),
respectively
11.
(
b)
Each
lime
kiln
equipped
with
a
fabric
filter
or
ESP
that
is
monitored
with
a
COMS.
Have
installed
and
have
operating
the
COMS
prior
to
the
performance
test.
Standard
operating
procedures
incorporated
into
the
OM&
M
plan
and
as
required
by
40
CFR
part
63,
subpart
A,
General
Provisions
and
according
to
PS
1
of
appendix
B
to
part
60
of
this
chapter.
According
to
the
requirements
in
§
63.7113(
g).
12.
Each
stack
emission
from
an
MPO,
vent
from
a
building
enclosing
an
MPO,
or
set
of
multiple
storage
bins
with
combined
stack
emissions,
which
is
subject
to
a
PM
emission
limit.
Measure
PM
emissions
................
Method
5
or
Method
17
in
appendix
A
to
part
60
of
this
chapter.
The
sample
volume
must
be
at
least
1.70
dscm
(
60
dscf);
for
Method
5,
if
the
gas
stream
being
sampled
is
at
ambient
temperature,
the
sampling
probe
and
filter
may
be
operated
without
heaters;
and
if
the
gas
stream
is
above
ambient
temperature,
the
sampling
probe
and
filter
may
be
operated
at
a
temperature
high
enough,
but
no
higher
than
121
°
C
(
250
°
F),
to
prevent
water
condensation
on
the
filter
(
Method
17
may
be
used
only
with
exhaust
gas
temperatures
of
not
more
than
250
°
F).
13.
Each
stack
emission
from
an
MPO,
vent
from
a
building
enclosing
an
MPO,
or
set
of
multiple
storage
bins
with
combined
stack
emissions,
which
is
subject
to
an
opacity
limit.
Conduct
opacity
observations
......
Method
9
in
appendix
A
to
part
60
of
this
chapter.
The
test
duration
must
be
for
at
least
3
hours
and
you
must
obtain
at
least
thirty,
6
minute
averages.
14.
Each
stack
emissions
source
from
an
MPO
subject
to
a
PM
or
opacity
limit,
which
uses
a
wet
scrubber.
Establish
the
average
gas
stream
pressure
drop
across
the
wet
scrubber.
Data
for
the
gas
stream
pressure
drop
measurement
device
during
the
MPO
stack
PM
performance
test.
The
pressure
drop
measurement
device
must
be
accurate
within
plus
or
minus
1
percent;
you
must
collect
the
pressure
drop
data
during
the
period
of
the
performance
test
and
determine
the
average
level.
15.
Each
stack
emissions
source
from
an
MPO
subject
to
a
PM
or
opacity
limit,
which
uses
a
wet
scrubber.
Establish
the
operating
limit
for
the
average
liquid
flow
rate
to
the
scrubber.
Data
from
the
liquid
flow
rate
measurement
device
during
the
MPO
stack
PM
performance
test.
The
continuous
scrubbing
liquid
flow
rate
measuring
device
must
be
accurate
within
plus
or
minus
1
percent;
you
must
collect
the
flow
rate
data
during
the
period
of
the
performance
test
and
determine
the
operating
limit
according
to
§
63.7112(
c).
16.
Each
fabric
filter
that
controls
emissions
from
only
an
individual
enclosed,
new
or
existing
storage
bin.
Conduct
opacity
observations
......
Method
9
in
appendix
A
to
part
60
of
this
chapter.
The
test
duration
must
be
for
at
least
1
hour
and
you
must
obtain
ten
6
minute
averages.
17.
Fugitive
emissions
from
any
MPO
subject
to
an
opacity
limit.
Conduct
opacity
observations
......
Method
9
in
appendix
A
to
part
60
of
this
chapter.
The
test
duration
must
be
for
at
least
3
hours,
but
the
3
hour
test
may
be
reduced
to
1
hour
if
there
are
no
individual
readings
greater
than
10
percent
opacity
and
there
are
no
more
than
three
readings
of
10
percent
during
the
first
1
hour
period.
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20DEP2.
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Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
TABLE
4
TO
SUBPART
AAAAA
OF
PART
63.
REQUIREMENTS
FOR
PERFORMANCE
TESTS
Continued
[
You
must
conduct
each
performance
test
in
the
following
table
that
applies
to
you,
as
required
in
§
63.7112]
For
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.
18.
Each
building
enclosing
any
MPO,
that
is
subject
to
a
VE
limit.
Conduct
VE
check
........................
The
specifications
in
§
63.7112(
k).
The
performance
test
must
be
conducted
while
all
affected
materials
processing
operations
within
the
building
are
operating
the
performance
test
for
each
affected
building
must
be
at
least
75
minutes,
with
each
side
of
the
building
and
roof
being
observed
for
at
least
15
minutes.
TABLE
5
TO
SUBPART
AAAAA
OF
PART
63
CONTINUOUS
COMPLIANCE
WITH
OPERATING
LIMITS
[
You
must
demonstrate
continuous
compliance
with
each
operating
limit
that
applies
to
you,
according
to
the
following
table,
as
required
in
§
63.7121]
For
.
.
.
For
the
following
operating
limit
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.
1.
Each
lime
kiln
controlled
by
a
wet
scrubber
..
Maintain
the
3
hour
rolling
average
exhaust
gas
stream
pressure
drop
across
the
wet
scrubber
greater
than
or
equal
to
the
pressure
drop
operating
limit
established
during
the
PM
performance
test;
and
maintain
the
3
hour
rolling
average
scrubbing
liquid
flow
rate
greater
than
or
equal
to
the
flow
rate
operating
limit
established
during
the
performance
test.
Collecting
the
wet
scrubber
operating
according
to
all
applicable
requirements
in
§
63.7113
and
reducing
the
data
according
to
§
63.7113(
a);
maintaining
the
3
hour
rolling
average
exhaust
gas
stream
pressure
drop
across
the
wet
scrubber
greater
than
or
equal
to
the
pressure
drop
operating
limit
established
during
the
PM
performance
test;
and
maintaining
the
3
hour
rolling
average
scrubbing
liquid
flow
rate
greater
than
or
equal
to
the
flow
rate
operating
limit
established
during
the
performance
test
(
the
continuous
scrubbing
liquid
flow
rate
measuring
device
must
be
accurate,
within
±
1%
and
the
continuous
pressure
drop
measurement
hour
rolling
device
must
be
accurate
within
±
1%).
2.
Each
lime
kiln
or
lime
cooler
equipped
with
a
fabric
filter
and
using
a
bag
leak
detector,
and
each
lime
kiln
equipped
with
an
ESP
using
a
PM
detector
in
lieu
of
ESP
parameter
monitoring.
a.
Maintain
and
operate
the
fabric
filter
or
ESP
such
that
the
bag
leak
or
PM
detector
alarm,
respectively,
is
not
activated
and
alarm
condition
does
not
exist
for
more
than
5
percent
of
the
total
operating
time
in
a
6
month
period.
(
i)
Operating
the
fabric
filter
or
ESP
so
that
the
alarm
on
the
bag
leak
or
PM
detection
system,
respectively,
is
not
activated
and
alarm
condition
does
not
exist
for
more
than
5
percent
of
the
total
operating
time
in
each
6
month
reporting
period;
and
continuously
recording
the
output
from
the
bag
leak
or
PM
detection
system.
(
ii)
Each
time
the
alarm
sounds
and
the
owner
or
operator
initiates
corrective
actions
within
1
hour
of
the
alarm,
1
hour
of
alarm
time
will
be
counted
(
if
the
owner
or
operator
takes
longer
than
1
hour
to
initiate
corrective
actions,
alarm
time
will
be
counted
as
the
actual
amount
of
time
taken
by
the
owner
or
operator
to
initiate
corrective
actions);
if
inspection
of
the
fabric
filter
or
ESP
system
demonstrates
that
no
corrective
actions
are
necessary,
no
alarm
time
will
be
counted.
3.
Each
lime
kiln
equipped
with
an
ESP,
except
an
ESP
monitoring
PM
with
a
PM
detector
or
COMS.
Maintain
the
3
hour
rolling
average
current
and
voltage
input
to
each
electrical
field
of
the
ESP
greater
than
or
equal
to
the
average
current
and
voltage
input
to
each
field
of
the
ESP
established
during
the
performance
test.
Collecting
the
ESP
operating
data
according
to
all
applicable
requirements
in
§
63.7113
and
reducing
the
data
according
to
§
63.7113(
a),
and
maintaining
the
3
hour
rolling
average
voltage
input
and
current
input
to
each
field
greater
than
or
equal
to
voltage
input
and
current
input
operating
limits
for
each
field
established
during
the
performance
test.
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20DEP2.
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20DEP2
78083
Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
TABLE
5
TO
SUBPART
AAAAA
OF
PART
63
CONTINUOUS
COMPLIANCE
WITH
OPERATING
LIMITS
Continued
[
You
must
demonstrate
continuous
compliance
with
each
operating
limit
that
applies
to
you,
according
to
the
following
table,
as
required
in
§
63.7121]
For
.
.
.
For
the
following
operating
limit
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.
4.
Each
stack
emissions
source
form
a
MPO
subject
to
an
opacity
limit,
which
is
controlled
by
a
wet
scrubber.
Maintain
the
3
hour
rolling
average
exhaust
gas
stream
pressure
drop
across
the
wet
scrubber
greater
than
or
equal
to
the
pressure
drop
operating
limit
established
during
the
PM
performance
test;
and
maintain
the
3
hour
rolling
average
scrubbing
liquid
flow
rate
greater
than
or
equal
to
the
flow
rate
operating
limit
established
during
the
performance
test.
Collecting
the
wet
scrubber
operating
data
according
to
all
applicable
requirements
in
§
63.7113
and
reducing
the
data
according
to
§
63.7113(
a);
maintaining
the
3
hour
rolling
average
exhaust
gas
stream
pressure
drop
across
the
wet
scrubber
greater
than
or
equal
to
the
pressure
drop
operating
limit
established
during
the
PM
performance
test;
and
maintaining
the
3
hour
rolling
average
scrubbing
liquid
flow
rate
greater
than
or
equal
to
the
flow
rate
operating
limit
established
during
the
performance
test
(
the
continuous
scrubbing
liquid
flow
rate
measuring
device
must
be
accurate
within
±
1%
and
the
continuous
pressure
drop
measurement
device
must
be
accurate
within
±
1%).
5.
For
each
lime
kiln
or
lime
cooler
equipped
with
a
fabric
filter
or
an
ESP
that
uses
a
COMS
as
the
monitoring
device.
a.
Maintain
and
operate
the
fabric
filter
or
ESP
such
that
the
average
opacity
for
any
6
minute
block
period
does
not
exceed
15
percent.
i.
Installing,
maintaining,
calibrating
and
operating
a
COMS
as
required
by
40
CFR
part
63,
subpart
A,
General
Provisions
and
according
to
PS
1
of
appendix
B
to
part
60
of
this
chapter.
ii.
Collecting
the
COMS
data
at
a
frequency
of
at
least
once
every
15
seconds,
determining
block
averages
for
each
6
minute
period
and
demonstrating
for
each
6
minute
block
period
the
average
opacity
does
not
exceed
15
percent.
TABLE
6
TO
SUBPART
AAAAA
OF
PART
63.
PERIODIC
MONITORING
FOR
COMPLIANCE
WITH
OPACITY
AND
VISIBLE
EMISSIONS
LIMITS
[
You
must
periodically
demonstrate
compliance
with
each
opacity
and
visible
emission
limit
that
applies
to
you,
according
to
the
following
table,
as
required
in
§
63.7121]
For
.
.
.
For
the
following
emission
limitation
.
.
.
You
must
demonstrate
ongoing
compliance
.
.
.
1.
Each
MPO
subject
to
an
opacity
limitation
as
required
in
Table
1
to
this
subpart,
or
any
vents
from
buildings
subject
to
an
opacity
limitation.
a.
7
15
percent
opacity,
depending
on
the
materials
processing
operation,
as
required
in
Table
1
to
this
subpart.
(
i)
Conducting
a
monthly
1
minute
VE
check
of
each
emission
unit
in
accordance
with
§
63.7121(
e);
the
check
must
be
conducted
while
the
affected
source
is
in
operation.
(
ii)
If
no
VE
are
observed
in
6
consecutive
monthly
checks
for
any
emission
unit,
you
may
decrease
the
frequency
of
VE
checking
from
monthly
to
semi
annually
for
that
emission
unit;
if
VE
are
observed
during
any
semiannual
check,
you
must
resume
VE
checking
of
that
emission
unit
on
a
monthly
basis
and
maintain
that
schedule
until
no
VE
are
observed
in
6
consecutive
monthly
checks.
(
iii)
If
no
VE
are
observed
during
the
semiannual
check
for
any
emission
unit,
you
may
decrease
the
frequency
of
VE
checking
from
semi
annually
to
annually
for
that
emission
unit;
if
VE
are
observed
during
any
annual
check,
you
must
resume
VE
checking
of
that
emission
unit
on
a
monthly
basis
and
maintain
that
schedule
until
no
VE
are
observed
in
6
consecutive
monthly
checks.
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20DEP2.
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20DEP2
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Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
TABLE
6
TO
SUBPART
AAAAA
OF
PART
63.
PERIODIC
MONITORING
FOR
COMPLIANCE
WITH
OPACITY
AND
VISIBLE
EMISSIONS
LIMITS
Continued
[
You
must
periodically
demonstrate
compliance
with
each
opacity
and
visible
emission
limit
that
applies
to
you,
according
to
the
following
table,
as
required
in
§
63.7121]
For
.
.
.
For
the
following
emission
limitation
.
.
.
You
must
demonstrate
ongoing
compliance
.
.
.
(
iv)
If
VE
are
observed
during
any
VE
check,
you
must
conduct
a
6
minute
test
of
opacity
in
accordance
with
Method
9
of
appendix
A
to
part
60
of
this
chapter;
you
must
begin
the
Method
9
test
within
1
hour
of
any
observation
of
VE
and
the
6
minute
opacity
reading
must
not
exceed
the
applicable
opacity
limit.
2.
Any
building
subject
to
a
VE
limit,
according
to
item
6
of
Table
1
to
this
subpart.
a.
No
VE
..........................................................
(
i)
Conducting
a
monthly
VE
check
of
the
building,
in
accordance
with
the
specifications
in
§
63.7112(
k);
the
check
must
be
conducted
while
all
the
enclosed
according
MPO
are
in
operation.
(
ii)
The
check
for
each
affected
building
must
be
at
least
5
minutes,
with
each
side
of
the
building
and
roof
being
observed
for
at
least
1
minute.
(
iii)
If
no
VE
are
observed
in
6
consecutive
monthly
checks
of
the
building,
you
may
decrease
the
frequency
of
checking
from
monthly
to
semi
annually
for
that
affected
source;
if
VE
are
observed
during
any
semi
annual
check,
you
must
resume
checking
on
a
monthly
basis
and
maintain
that
schedule
until
no
VE
are
observed
in
6
consecutive
monthly
checks.
(
iv)
If
no
VE
are
observed
during
the
semi
annual
check,
you
may
decrease
the
frequency
of
checking
from
semi
annually
to
annually
for
that
affected
source;
and
if
VE
are
observed
during
any
annual
check,
you
must
resume
checking
of
that
emission
unit
on
a
monthly
basis
and
maintain
that
schedule
until
no
VE
are
observed
in
6
consecutive
monthly
checks
(
the
source
is
in
compliance
if
no
VE
are
observed
during
any
of
these
checks).
TABLE
7
TO
SUBPART
AAAAA
OF
PART
63.
REQUIREMENTS
FOR
REPORTS
[
You
must
submit
each
report
in
this
table
that
applies
to
you,
as
required
in
§
63.7131]
You
must
submit
a
.
.
.
The
report
must
contain
.
.
.
You
must
submit
the
report
.
.
.
1.
Compliance
report
..........................................
a.
If
there
are
no
deviations
from
any
emission
limitations
(
emission
limit,
operating
limit,
opacity
limit,
and
VE
limit)
that
applies
to
you,
a
statement
that
there
were
no
deviations
from
the
emission
limitations
during
the
reporting
period.
Semiannually
according
to
the
requirements
in
§
63.7131(
b).
b.
If
there
were
no
periods
during
which
the
CMS,
including
the
operating
parameter
monitoring
systems,
was
out
of
control
as
specified
in
§
63.8(
c)(
7),
a
statement
that
there
were
no
periods
during
which
the
CMS
was
out
of
control
during
the
reporting
period.
c.
If
you
have
a
deviation
from
any
emission
limitation
(
emission
limit,
operating
limit,
opacity
limit,
and
VE)
during
the
reporting
period,
the
report
must
contain
the
information
in
§
63.7131(
c).
d.
If
there
were
periods
during
which
the
CMS,
including
the
operating
parameter
monitoring
systems,
was
out
of
control,
as
specified
in
§
63.8(
c)(
7),
the
report
must
contain
the
information
in
§
63.7131(
e).
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/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
TABLE
7
TO
SUBPART
AAAAA
OF
PART
63.
REQUIREMENTS
FOR
REPORTS
Continued
[
You
must
submit
each
report
in
this
table
that
applies
to
you,
as
required
in
§
63.7131]
You
must
submit
a
.
.
.
The
report
must
contain
.
.
.
You
must
submit
the
report
.
.
.
e.
If
you
had
a
startup,
shutdown
or
malfunction
during
the
reporting
period
and
you
took
actions
consistent
with
your
SSMP,
the
compliance
report
must
include
the
information
in
§
63.10(
d)(
5)(
i).
2.
An
immediate
startup,
shutdown,
and
malfunction
report
if
you
had
a
startup,
shutdown
or
malfunction
during
the
reporting
period
that
is
not
consistent
with
your
SSMP.
Actions
taken
for
the
event
..............................
By
fax
or
telephone
within
2
working
days
after
starting
actions
inconsistent
with
the
SSMP.
3.
An
immediate
startup,
shutdown,
and
malfunction
report
if
you
had
a
startup,
shutdown
or
malfunction
during
the
reporting
period
that
is
not
consistent
with
your
SSMP.
The
information
in
§
63.10(
d)(
5)(
ii)
..................
By
letter
within
7
working
days
after
the
end
of
the
event
unless
you
have
made
alternative
arrangements
with
the
permitting
authority
See
§
63.10(
d)(
5)(
ii).
TABLE
8
TO
SUBPART
AAAAA
OF
PART
63.
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
AAAAA
[
You
must
comply
with
the
applicable
General
Provisions
requirements
according
to
the
following
table]
Citation
Summary
of
requirement
Am
I
subject
to
this
requirement
Explanations
63.1(
a)(
1)
(
4)
.......................
Applicability
......................................................
Yes.
63.1(
a)(
5)
.............................
..........................................................................
No.
63.1(
a)(
6)
.............................
Applicability
......................................................
Yes.
63.1(
a)(
7)
(
a)(
9)
..................
..........................................................................
No.
63.1(
a)(
10)
(
a)(
14)
..............
Applicability
......................................................
Yes.
63.1(
b)(
1)
.............................
Initial
Applicability
Determination
.....................
Yes
...................
§
§
63.7081
and
63.7142
specify
additional
applicability
determination
requirements.
63.1(
b)(
2)
.............................
..........................................................................
No.
63.1(
b)(
3)
.............................
Initial
Applicability
Determination
.....................
Yes.
63.1(
c)(
1)
.............................
Applicability
After
Standard
Established
..........
Yes.
63.1(
c)(
2)
.............................
Permit
Requirements
.......................................
No
.....................
Area
sources
not
subject
to
subpart
AAAAA,
except
all
sources
must
make
initial
applicability
determination.
63.1(
c)(
3)
.............................
..........................................................................
No.
63.1(
c)(
4)
(
5)
.......................
Extensions,
Notifications
..................................
Yes.
63.1(
d)
.................................
..........................................................................
No.
63.1(
e)
.................................
Applicability
of
Permit
Program
.......................
Yes.
63.2
......................................
Definitions
........................................................
...........................
Additional
definition
in
§
63.7143.
63.3(
a)
(
c)
...........................
Units
and
Abbreviations
...................................
Yes.
63.4(
a)(
1)
(
a)(
2)
..................
Prohibited
Activities
..........................................
Yes.
63.4(
a)(
3)
(
a)(
5)
..................
..........................................................................
No.
63.4(
b)
(
c)
...........................
Circumvention,
Severability
.............................
Yes.
63.5(
a)(
1)
(
2)
.......................
Construction/
Reconstruction
............................
Yes.
63.5(
b)(
1)
.............................
Compliance
Dates
............................................
Yes.
63.5(
b)(
2)
.............................
..........................................................................
No.
63.5(
b)(
3)
(
4)
.......................
Construction
Approval,
Applicability
................
Yes.
63.5(
b)(
5)
.............................
..........................................................................
No.
63.5(
b)(
6)
.............................
Applicability
......................................................
Yes.
63.5(
c)
..................................
..........................................................................
No.
63.5(
d)(
1)
(
4)
.......................
Approval
of
Construction/
Reconstruction
........
Yes.
63.5(
e)
.................................
Approval
of
Construction/
Reconstruction
........
Yes.
63.5(
f)(
1)
(
2)
........................
Approval
of
Construction/
Reconstruction
........
Yes.
63.6(
a)
.................................
Compliance
for
Standards
and
Maintenance
..
Yes.
63.6(
b)(
1)
(
5)
.......................
Compliance
Dates
............................................
Yes.
63.6(
b)(
6)
.............................
..........................................................................
No.
63.6(
b)(
7)
.............................
Compliance
Dates
............................................
Yes.
63.6(
c)(
1)
(
2)
.......................
Compliance
Dates
............................................
Yes.
63.6(
c)(
3)
(
c)(
4)
...................
..........................................................................
No.
63.6(
c)(
5)
.............................
Compliance
Dates
............................................
Yes.
63.6(
d)
.................................
..........................................................................
No.
63.6(
e)(
1)
.............................
Operation
&
Maintenance
................................
Yes
...................
See
also
§
63.7100
for
OM&
M
requirements.
63.6(
e)(
2)
.............................
..........................................................................
No.
63.6(
e)(
3)
.............................
Startup,
Shutdown
Malfunction
Plan
...............
Yes.
63.6(
f)(
1)
(
3)
........................
Compliance
with
Emission
Standards
.............
Yes.
63.6(
g)(
1)
(
g)(
3)
..................
Alternative
Standard
........................................
Yes.
63.6(
h)(
1)
(
2)
.......................
Opacity/
VE
Standards
......................................
Yes..
63.6(
h)(
3)
.............................
..........................................................................
No.
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Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
TABLE
8
TO
SUBPART
AAAAA
OF
PART
63.
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
AAAAA
Continued
[
You
must
comply
with
the
applicable
General
Provisions
requirements
according
to
the
following
table]
Citation
Summary
of
requirement
Am
I
subject
to
this
requirement
Explanations
63.6(
h)(
4)
(
h)(
5)(
i)
...............
Opacity/
VE
Standards
......................................
Yes
...................
This
requirement
only
applies
to
opacity
and
VE
performance
checks
required
in
Table
4
to
subpart
AAAAA.
63.6(
h)(
5)(
ii)
(
iii)
..................
Opacity/
VE
Standards
......................................
No
.....................
Test
durations
are
specified
in
subpart
AAAAA;
subpart
AAAAA
takes
precedence.
63.6(
h)(
5)(
iv)
........................
Opacity/
VE
Standards
......................................
No.
63.6(
h)(
5)(
v)
.........................
Opacity/
VE
Standards
......................................
Yes.
63.6(
h)(
6)
.............................
Opacity/
VE
Standards
......................................
Yes.
63.6(
h)(
7)
.............................
COM
Use
.........................................................
No
.....................
No
COM
required
under
subpart
AAAAA.
63.6(
h)(
8)
.............................
Compliance
with
Opacity
and
VE
....................
Yes.
63.6(
h)(
9)
.............................
Adjustment
of
Opacity
Limit
.............................
Yes.
63.6(
i)(
1)
(
i)(
14)
...................
Extension
of
Compliance
.................................
Yes.
63.6(
i)(
15)
............................
..........................................................................
No.
63.6(
i)(
16)
............................
Extension
of
Compliance
.................................
Yes.
63.6(
j)
...................................
Exemption
from
Compliance
............................
Yes.
63.7(
a)(
1)
(
a)(
3)
..................
Performance
Testing
Requirements
................
Yes
...................
§
63.7110
specifies
deadlines;
§
63.7112
has
additional
specific
requirements.
63.7(
b)
.................................
Notification
.......................................................
Yes.
63.7(
c)
..................................
Quality
Assurance/
Test
Plan
...........................
Yes.
63.7(
d)
.................................
Testing
Facilities
..............................................
Yes.
63.7(
e)(
1)
(
4)
.......................
Conduct
of
Tests
..............................................
Yes.
63.7(
f)
..................................
Alternative
Test
Method
...................................
Yes.
63.7(
g)
.................................
Data
Analysis
...................................................
Yes.
63.7(
h)
.................................
Waiver
of
Tests
................................................
Yes.
63.8(
a)(
1)
.............................
Monitoring
Requirements
.................................
Yes
...................
See
also
§
63.7113.
63.8(
a)(
2)
.............................
Monitoring
........................................................
Yes.
63.8(
a)(
3)
.............................
..........................................................................
No.
63.8(
a)(
4)
.............................
Monitoring
........................................................
No
.....................
Flares
not
applicable.
63.8(
b)(
1)
(
3)
.......................
Conduct
of
Monitoring
......................................
Yes.
63.8(
c)(
1)
(
3)
.......................
CMS
Operation/
Maintenance
...........................
Yes.
63.8(
c)(
4)
.............................
CMS
Requirements
..........................................
No
.....................
See
§
63.7121.
63.8(
c)(
4)(
i)
(
ii)
....................
Cycle
Time
for
COM
and
CEMS
.....................
No
.....................
No
COM
or
CEMS
are
required
under
subpart
AAAAA;
see
§
63.7113
for
CPMS
requirements
63.8(
c)(
5)
.............................
Minimum
COM
procedures
..............................
No
COM
not
required.
63.8(
c)(
6)
.............................
CMS
Requirements
..........................................
No
See
§
63.7113.
63.8(
c)(
7)
(
8)
.......................
CMS
Requirements
..........................................
Yes.
63.8(
d)
.................................
Quality
Control
.................................................
No
.....................
See
§
63.7113.
63.8(
e)
.................................
Performance
Evaluation
for
CMS
....................
No.
63.8(
f)(
1)
(
f)(
5)
....................
Alternative
Monitoring
Method
.........................
Yes.
63.8(
f)(
6)
..............................
Alternative
to
Relative
Accuracy
test
...............
No.
63.8(
g)(
1)
(
g)(
5)
..................
Data
Reduction;
Data
That
Cannot
Be
Used
..
No
.....................
See
data
reduction
requirements
in
§
§
63.7120
and
63.7121.
63.9(
a)
.................................
Notification
Requirements
................................
Yes
...................
See
also
§
63.7130
63.9(
b)
.................................
Initial
Notifications
............................................
Yes.
63.9(
c)
..................................
Request
for
Compliance
Extension
.................
Yes.
63.9(
d)
.................................
New
Source
Notification
for
Special
Compliance
Requirements.
Yes.
63.9(
e)
.................................
Notification
of
Performance
Test
.....................
Yes.
63.9(
f)
..................................
Notification
of
VE/
Opacity
Test
........................
Yes
...................
This
requirement
only
applies
to
opacity
and
VE
performance
tests
required
in
Table
4
to
subpart
AAAAA.
Notification
not
required
for
VE/
opacity
test
under
Table
6
to
subpart
AAAAA.
63.9(
g)
.................................
Additional
CMS
Notifications
...........................
No
.....................
Not
required
for
operating
parameter
monitoring
63.9(
h)(
1)
(
h)(
3)
..................
Notification
of
Compliance
Status
....................
Yes.
63.9(
h)(
4)
.............................
..........................................................................
No..
63.9(
h)(
5)
(
h)(
6)
..................
Notification
of
Compliance
Status
....................
Yes.
63.9(
i)
...................................
Adjustment
of
Deadlines
..................................
Yes.
63.9(
j)
...................................
Change
in
Previous
Information
......................
Yes.
63.10(
a)
...............................
Recordkeeping/
Reporting
General
Requirements
Yes
...................
See
§
§
63.7131
through
63.7133.
63.10(
b)(
1)
(
b)(
2)(
xii)
..........
Records
............................................................
Yes.
63.10(
b)(
2)(
xiii)
....................
Records
for
Relative
Accuracy
Test
................
No.
63.10(
b)(
2)(
xiv)
....................
Records
for
Notification
...................................
Yes.
63.10(
b)(
3)
...........................
Applicability
Determinations
.............................
Yes.
63.10(
c)
................................
Additional
CMS
Recordkeeping
.......................
No
.....................
See
§
63.7132.
63.10(
d)(
1)
...........................
General
Reporting
Requirements
....................
Yes.
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E:\
FR\
FM\
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SGM
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78087
Federal
Register
/
Vol.
67,
No.
245
/
Friday,
December
20,
2002
/
Proposed
Rules
TABLE
8
TO
SUBPART
AAAAA
OF
PART
63.
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
AAAAA
Continued
[
You
must
comply
with
the
applicable
General
Provisions
requirements
according
to
the
following
table]
Citation
Summary
of
requirement
Am
I
subject
to
this
requirement
Explanations
63.10(
d)(
2)
...........................
Performance
Test
Results
...............................
Yes.
63.10(
d)(
3)
...........................
Opacity
or
VE
Observations
............................
Yes
...................
For
the
periodic
monitoring
requirements
in
Table
6
to
subpart
AAAAA,
report
according
to
§
63.10(
d)(
3)
only
if
VE
observed
and
subsequent
visual
opacity
test
is
required.
63.10(
d)(
4)
...........................
Progress
Reports
.............................................
Yes.
63.10(
d)(
5)
...........................
Startup,
Shutdown,
Malfunction
Reports
.........
Yes.
63.10(
e)
...............................
Additional
CMS
Reports
..................................
No
.....................
See
specific
requirements
in
subpart
AAAAA,
see
§
63.7131.
63.10(
f)
................................
Waiver
for
Recordkeeping/
Reporting
...............
Yes.
63.11(
a)
(
b)
.........................
Control
Device
Requirements
..........................
No
.....................
Flares
not
applicable.
63.12(
a)
(
c)
.........................
State
Authority
and
Delegations
......................
Yes.
63.13(
a)
(
c)
.........................
State/
Regional
Addresses
...............................
Yes.
63.14(
a)
(
b)
.........................
Incorporation
by
Reference
.............................
Yes.
ASTM
6420
99
and
6735
01
(
see
§
63.14).
63.15(
a)
(
b)
.........................
Availability
of
Information
.................................
Yes.
*
*
*
*
*
[
FR
Doc.
02
31233
Filed
12
19
02;
8:
45
am]
BILLING
CODE
6560
50
P
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| epa | 2024-06-07T20:31:40.136236 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0052-0528/content.txt"
} |
EPA-HQ-OAR-2002-0052-0567 | Supporting & Related Material | "2002-11-20T05:00:00" | null | ~
.
~
c
Docket
No.
O~~
2002
0052
*
Item
NO.
1143
127
I*
$
n
G
UNITED
STATES
ENVIRONMENTAL
PROTECTION
AGENCY
RESEARCH
TRIANGLE
PARK,
NC
2771
1
4*\""
D
%+..
ww
5
%
.4i
PRO&
8
OFFICE
OF
AIR
QUALNY
PLANNING
AND
STANDARDS
MEMORANDUM
SUBJECT:
Cost
Inputs
for
Econ
ime
Industry
NESHAP
'
+
James
Crowder,
Group
Leader
8
bA
Minerals
and
Inorganic
Chemic
s
Group
Ron
Evans,
Group
Leader
Innovative
Strategies
and
Economics
Group
This
memorandum
provides
the
costs
of
air
pollution
controls
(
that
may
be
needed
to
comply
with
emission
limits
being
considered)
and
testing
and
monitoring
requirements
being
considered
for
the
subject
regulation.
These
costs
are
for
the
control
of
HAP
w
and
existing
lime
kilns,
lime
coolers,
and
mat
1
costs
have
been
estimatedxor
kil
for
the
kiln,
cooler,
and
MHO
are
HAP
metals,
using
PM
flect
updated
thinking
on
rule
requirements
based
on
el's
recommendations
and
a
comment
received
fro
Two
EIAs
need
to
be
conducted,
for
the
two
regulatory
options
under
consider
assuming
that
PM
continuous
emission
monitoring
systems
(
CEMS)
will
be
required,
other
option
that
PM
CEMS
will
not
be
required.
Please
find
attached
the
following
items:
es
applicable
to
the
cost
and
economic
analysis.
grading
existing
kilns'
baghouses
(
replace
bags)
sts
for
each
PM
control
option
for
model
kilns
and
cooler:
I
I
I
Upgrading
existing
kilns'
ESP
(
new
ESP
field)
Upgrading
existing
kilns'
wet
scrubbers
(
replace
with
new
venturi
wet
scrubber)
Upgrading
existing
uncontrolled
kilns
with
a
new
baghouse
Ne&
baghouse
for
a
new
kiln
0
I
I
0
MHO
conti
oi
costs
Table
of
testing
and
monitoring
costs
for
kilns
Testing
and
monitoring
costs
for
materials
handling
sources
Table
matching
each
lime
plant's
kiln(
s)
to
model
kilns
RqcledlRecyclable
Prlnted
with
Vegetable
Oil
Based
Ink
on
100%
Recycled
Paper
(
40%
Postconsumer)
General
Notes
for
Cost
and
Economic
Analysis
0
Costs
are
in
1000'
s
of
first
quarter1
997
dollars.
TCI
=
total
capital
investment
DAC
=
direct
annual
cost
IAC
=
indirect
annual
cost
TAC
=
total
annual
cost
=
D
Cost
recovery
based
on
7
perc
Costs
for
kilns
are
provided
on
a
model
basis,
and
only
for
those
models
Since
the
draft
revised
rule
includes
a
provision
for
bubbling
of
PM
emissions
from
the
0
0
0
0
C
+
cost
recovery
0
0
corresponding
actual
kilns
i
kilns
and
coolers,
this
will
allow
some
plants
to
avoid
installation
of
new,
or
upgrading
of
existing,
PM
controls
that
may
have
been
required
without
the
bubbling
provision.
To
account
for
this
lesser
impact,
the
cost
of
cooler
PM
controls
(
which
%
without
the
bubbling
provision)
are
zero.
0
0
MHO
control
costs
are
lump
sum
for
the
whole
plant.
We
assume
70
percent
of
plants
are
major
sources,
but
we
do
not
know
which
plants
are
,
except
the
costs
to
measure
HC1
lete
list
of
all
plants
in
the
U.
S.
0
major.
A
random
assignment
of
major
vs.
area
status
based
on
this
70%
probability
is
recommended.
0
orne
by
every
plant.
0
Extrapolation
of
costs
and
*
In
addition,
if
ofthe
economic
impacts
to
the
entire
industry
needs
to
be
consi
plants
listed
in
Table
7
are
small
businesses,
please
use
the
costs
we
provide
you
(
in
a
separate
memo).
sugar
production;
this
is
reflected
in
the
list
of
plants.
example,
the
percentage
of
existing
kilns
with
a
certain
PM
control
device
needing
an
upgrade
(
i.
e.,
not
meeting
the
emission
limit
and
thus
having
to
incur
the
cost
of
upgrading
their
air
pollution
control)
is
indicated.
We
do
not
know
which
plants
are
meeting
the
emission
limits,
so
these
costs
should
be
assigned
randomly
based
on
the
percentages
indicated.
The
exception
to
this
is
the
small
businesses,
for
which
costs
have
already
been
assigned,
based
on
the
assumption
that
all
are
major
except
1
company.
However,
the
small
businesses
need
to
be
included
when
determining
how
many
kilns
incur
a
cost
based
on
the
aforementioned
percentages.
We
will
provide
you
the
costs
to
small
businesses
in
a
separate
memo.
(
1)
HCl
testing
for
area
source
status
determination
(
incurred
by
every
plant;
depends
on
#
of
kilns
see
Table
6)
;,
and
if
the
lime
plant
is
a
major
source,
the
following
costs
also
0
The
NESHAP
will
not
affect
lime
plants
associated
with
pulp/
paper
production
or
beet
Additional
notes
particular
to
a
control
option
are
also
provided
in
the
tables
below.
For
0
0
In
summary,
total
cost
to
a
lime
plant
equals
cost
of:
apply:
3
(
2)
kiln
PM
control
(
depends
on
control
device,
if
meeting
emission
limit
see
Tables
1
through
5)
(
3)
MHO
control
(
costs
are
per
plant
see
top
of
page
7)
(
4)
kiln
testing
and
monitoring
(
costs
are
per
kiln;
all
kilns
incur
costs
see
Table
6)
(
5)
MHO
testing
and
monitoring
(
per
plant
see
page
8)
Table
1
:
Upgrading;
Existing;
Kilns
FF
with
New
Bags
Notes:
29
%
of
kilns
with
baghouses
are
not
expected
to
meet
the
PM
emission
limit,
and
thus
would
incur
these
costs.
Reference:
11
B
66
*
*
I
4
Table
2.
New
FF
on
Existing
Uncontrolled
Kiln
These
costs
would
apply
also
to
kilns
with
just
cyclones
or
gravel
beds.
All
kilns
that
are
uncontrolled
(
or
with
cyclone
or
gravel
bed)
would
incur
these
costs.
Reference:
11
B
70
(
1
0
a
9
.
e
c
a
5
Table
3.
Upgrading
Wet
Scrubbers
on
Existing.
Kilns
with
New
Venturi
Scrubber
cost
DAC
IAC
.
TAC
recovery
28
75
11
113
32
88
11
13
1
57
220
16
293
73
312
19
403
33
102
12
146
55
207
15
278
75
326
19
42Q
39
129
13
180
19
36
9
64
6
Table
4.
Additional
Field
for
ESP
Notes:
e
33
%
of
kilns
with
ESPs
are
not
expected
to
meet
the
PM
emission
limi
and
thus
would
incur
these
costs.
e
Reference:
11
B
67
Table
5.
New
Baghouse
on
New
Kiln
Notes:
e
1
kiln
of
model
size
N
and
1
kiln
of
model
size
P
are
expected
to
be
built
after
the
first
5
2
kilns
of
model
size
Q
and
2
kilns
of
model
size
R
are
expected
to
be
built
after
the
first
For
models
N,
P,
and
Q,
the
costs
are
incremental
compared
to
the
costs
that
would
be
years
following
the
compliance
date.
5
years
following
the
compliance
date.
incurred
in
complying
with
the
NSPS
for
lime
kilns.
Model
R
represents
a
double
shaft
vertical
kiln
and
these
costs
are
whole,
since
the
NSPS
applies
only
to
vertical
kilns.
Negative
DAC
represents
a
savings
due
to
reduced
electricity
consumption
because
of
a
larger
baghouse
with
less
pressure
drop.
e
e
e
Reference:
11
B
6
L
%
I
1
1
i
?
.
a
.
t
E
4
7
Materials
Handling;
Operations
Control
Costs
A
lump
sum
of
$
78,400
capital
cost
and
$
68,600
total
annual
cost
per
major
source
plant.
Reference:
Memo
fiom
Mike
Laney,
RTI.
Estimated
Costs
of
Controlling
Materials
e
Handling
Operations
at
Lime
Manufacturing
Facilities
Table
6.
Kiln
Testing;
and
MonitorinP
Costs
PM
control
device5
OM
and
M
plans,
plus
costs
for
misc.
notifications
Notes:
testing
and
monitoring
costs
would
only
be
incurred
at
major
sources,
except
that
the
M.
Costs
above
are
per
kiln,
except
as
noted.
Costs
for
testing
additional
kilns
at
same
plant
320
tests
would
be
incurred
by
every
plant
are
noted
below.
Add
$
5000
(
one
time
cost)
and
$
1250
(
annualized
cost)
for
each
additional
kiln
tested
at
same
location.
Add
$
3
100
(
one
time
cost)
and
$
775
(
annualized
cost)
for
each
additional
kiln
tested
at
same
location.
One
time
costs
are
annualized
over
a
5
year
period,
7%
interest
rate.
The
rule
applies
only
to
kilns
with
baghouses,
and
BLD
are
an
option
for
ESPs,
but
for
the
purposes
of
costing,
assume
all
kilns
will
use
BLD
e
1.
2.
3.
4.
>
x
.
be
c
B
8
5.
Assume
55
percent
of
currently
existing
kilns
with
baghouses
or
scrubbers
will
have
a
multi
stack
(
assume
10
compartment)
contr
the
single
stack
BLD.
Assume
34
percent
of
existing
kilns
with
ESPs
will
have
multi
stack
configuration
and
wil
6.
For
the
start
up,
shutdown,
ction
plan,
and
the
operations,
maintenance,
and
monitoring
plan,
and
other
evice
and
will
incur
these
costs
in
lieu
of
costs
in
lieu
of
single
stack
BLD.
ments.
Costs
are
per
plant.
7.
Important
Notes
Reparding
PM
CEMS:
A
separate
EIA
will
need
to
be
conducted
to
model
the
impact
of
the
costs
of
PM
CEMS.
The
PM
CEMS
costs
will
be
u
required
in
the
regulation,
then
BLDs
will
not
be
required.
The
exception
to
this
is
that
kilns
with
multi
stack
PM
control
devices
will
not
be
required
to
use
PM
CEMS,
so
these
kilns
will
always
incur
the
co
Note
Total
Capital
cost
(
Beta
Gage
type)
PM
CEMS
=
$
170,000
Annual
Cost
(
Beta
Gage
type)
PM
CEMS
=
$
15,000
Capital
Cost
feed
rate
monitor
=
$
22,000
Annual
Cost
feed
rate
monitor
=
$
6,000
Materials
Handling
Operations
Testing,
and
Monitoring
which
is
$
3,750
annualized
over
5
years.
instead
of
the
BLD
costs,
i.
e.,
if
PM
CEMS
are
D
for
a
multi
stack
PM
control
device.
(
See
d
rate
monitoring
as
well,
i.
e.,
I
.
Assume
all
major
source
plants
incur
$
15,000
in
one
time
costs
for
PM
tests
on
MHOS,
Costs
are
based
on
two
PM
tests.
One
time
costs
are
thus
1
*
10,000
+
(
1
*
5000)
.
=
$
15,000;
annualized
costs
are
*
2500
+
(
1
*
1250)
=
$
3,750.
.
assume
95
percent
of
major
source
plants
i
$
5,600
in
monitoring
costs,
randomly
assigned.
.
Based
on
$
5,300
*
(
138.8/
131.3))
annual
monitoring
costs.
See
attached
Appendix
A
for
information
on
how
these
costs
were
derived.
(
The
factor
138.8/
13
1.3
is
used
to
convert
ts
from
1993
dollars
to
1997
dollars.)
assume
5
percent
of
major
source
plants
incur
$
12,600
in
annual
monitoring
costs
(
randomly
assigned,
except
assume
all
small
businesses
incur
these
costs).
| epa | 2024-06-07T20:31:40.181475 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0052-0567/content.txt"
} |
EPA-HQ-OAR-2002-0059-0001 | Proposed Rule | "2002-12-19T05:00:00" | National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines; Proposed Rule | Thursday,
December
19,
2002
Part
II
Environmental
Protection
Agency
40
CFR
Part
63
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Stationary
Reciprocating
Internal
Combustion
Engines;
Proposed
Rule
VerDate
0ct<
31>
2002
16:
32
Dec
18,
2002
Jkt
200001
PO
00000
Frm
00001
Fmt
4717
Sfmt
4717
E:\
FR\
FM\
19DEP2.
SGM
19DEP2
77830
Federal
Register
/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[
OAR
2002
0059;
FRL
7417
9]
RIN
2060
AG
63
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Stationary
Reciprocating
Internal
Combustion
Engines
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Proposed
rule.
SUMMARY:
This
action
proposes
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
stationary
reciprocating
internal
combustion
engines
(
RICE)
with
manufacturer's
nameplate
rating
above
500
brake
horsepower
located
at
major
sources
of
hazardous
air
pollutants
(
HAP).
We
have
identified
stationary
RICE
as
a
major
source
category
of
HAP
emissions
such
as
formaldehyde,
acrolein,
methanol,
and
acetaldehyde.
The
proposed
rule
would
implement
section
112(
d)
of
the
Clean
Air
Act
(
CAA)
by
requiring
all
major
sources
to
meet
HAP
emission
standards
reflecting
the
application
of
the
maximum
achievable
control
technology
(
MACT)
for
RICE.
We
estimate
that
40
percent
of
stationary
RICE
will
be
located
at
major
sources
and
thus
subject
to
the
proposed
rule.
As
a
result,
the
environmental,
energy,
and
economic
impacts
presented
in
this
preamble
reflect
these
estimates.
We
estimate
that
the
proposed
rule
would
reduce
nationwide
HAP
emissions
from
major
stationary
RICE
by
approximately
5,000
tons/
year
in
the
5th
year
after
the
standards
are
implemented.
The
emissions
reductions
achieved
by
these
standards
will
provide
protection
to
the
public
and
achieve
a
primary
goal
of
the
CAA.
DATES:
Comments.
Submit
comments
on
or
before
February
18,
2003,
or
by
February
20,
2003
if
a
public
hearing
is
held.
Public
Hearing.
If
anyone
contacts
us
requesting
to
speak
at
a
public
hearing
by
January
8,
2003,
a
public
hearing
will
be
held
on
January
21,
2003.
ADDRESSES:
Comments
may
be
submitted
by
mail
(
in
duplicate,
if
possible)
to
EPA
West
(
Air
Docket),
U.
S.
EPA
(
MD
6102T),
Room
B
108,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
2002
0059.
By
hand
delivery/
courier,
comments
may
be
submitted
(
in
duplicate,
if
possible)
to
EPA
Docket
Center
(
Air
Docket),
U.
S.
EPA,
(
MD
6102T),
Room
B
108,
1301
Constitution
Avenue,
NW.,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
2002
0059.
Also,
comments
may
be
submitted
electronically
according
to
the
detailed
instructions
as
provided
in
the
SUPPLEMENTARY
INFORMATION
section.
Public
Hearing.
If
a
public
hearing
is
held,
it
will
be
held
at
the
new
EPA
facility
complex
in
Research
Triangle
Park,
North
Carolina,
or
at
an
alternate
site
nearby.
Docket.
Docket
No.
OAR
2002
0059
contains
supporting
information
used
in
developing
the
standards.
The
docket
is
located
at
the
U.
S.
EPA,
1301
Constitution
Avenue,
NW.,
Washington,
DC
20460
in
room
B108,
and
may
be
inspected
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
FOR
FURTHER
INFORMATION
CONTACT:
Mr.
Sims
Roy,
Combustion
Group,
Emission
Standards
Division,
(
MD
C439
01),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711;
telephone
number
(
919)
541
5263;
facsimile
number
(
919)
541
5450;
electronic
mail
address:
roy.
sims@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Regulated
Entities.
Categories
and
entities
potentially
regulated
by
this
action
include:
Category
SIC
NAICS
Examples
of
regulated
entities
Any
industry
using
a
stationary
RICE
as
defined
in
the
proposed
rule.
4911
2211
Electric
power
generation,
transmission,
or
distribution.
4922
48621
Natural
gas
transmission.
1311
211111
Crude
petroleum
and
natural
gas
production.
1321
211112
Natural
gas
liquids
producers.
9711
92811
National
security.
This
table
is
not
intended
to
be
exhaustive,
but
rather
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
your
facility
is
regulated
by
this
action,
you
should
examine
the
applicability
criteria
in
§
63.6585
of
the
proposed
rule.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Docket.
The
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
OAR
2002
0059.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
received,
and
other
information
related
to
this
action.
Although
a
part
of
the
official
docket,
the
public
docket
does
not
include
Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
Air
and
Radiation
Docket
in
the
EPA
Docket
Center,
(
EPA/
DC)
EPA
West,
Room
B108,
1301
Constitution
Ave.,
NW.,
Washington,
DC.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
1744,
and
the
telephone
number
for
the
Air
and
Radiation
Docket
is
(
202)
566
1742.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.
Electronic
Access.
You
may
access
this
Federal
Register
document
electronically
through
the
EPA
Internet
under
the
``
Federal
Register''
listings
at
http://
www.
epa.
gov/
fedrgstr/.
An
electronic
version
of
the
public
docket
is
available
through
EPA's
electronic
public
docket
and
comment
system,
EPA
Dockets.
You
may
use
EPA
Dockets
at
http://
www.
epa.
gov/
edocket/
to
submit
or
view
public
comments,
access
the
index
listing
of
the
contents
of
the
official
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,''
then
key
in
the
appropriate
docket
identification
number.
Certain
types
of
information
will
not
be
placed
in
the
EPA
Dockets.
Information
claimed
as
CBI
and
other
information
whose
disclosure
is
restricted
by
statute,
which
is
not
included
in
the
official
public
docket,
will
not
be
available
for
public
viewing
in
EPA's
electronic
public
docket.
The
EPA's
policy
is
that
copyrighted
material
will
not
be
placed
in
EPA's
electronic
public
docket
but
will
be
available
only
in
printed
paper
form
in
the
official
public
docket.
To
the
extent
feasible,
publicly
available
docket
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19,
2002
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Proposed
Rules
materials
will
be
made
available
in
EPA's
electronic
public
docket.
When
a
document
is
selected
from
the
index
list
in
EPA
Dockets,
the
system
will
identify
whether
the
document
is
available
for
viewing
in
EPA's
electronic
public
docket.
Although
not
all
docket
materials
may
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
identified
above.
The
EPA
intends
to
work
towards
providing
electronic
access
to
all
of
the
publicly
available
docket
materials
through
EPA's
electronic
public
docket.
For
public
commenters,
it
is
important
to
note
that
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
on
paper,
will
be
made
available
for
public
viewing
in
EPA's
electronic
public
docket
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
EPA's
electronic
public
docket.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Public
comments
submitted
on
computer
disks
that
are
mailed
or
delivered
to
the
docket
will
be
transferred
to
EPA's
electronic
public
docket.
Public
comments
that
are
mailed
or
delivered
to
the
Docket
will
be
scanned
and
placed
in
EPA's
electronic
public
docket.
Where
practical,
physical
objects
will
be
photographed,
and
the
photograph
will
be
placed
in
EPA's
electronic
public
docket
along
with
a
brief
description
written
by
the
docket
staff.
For
additional
information
about
EPA's
electronic
public
docket
visit
EPA
Dockets
online
or
see
67
FR
38102,
May
31,
2002.
You
may
submit
comments
electronically,
by
mail,
or
through
hand
delivery/
courier.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
comment.
Please
ensure
that
your
comments
are
submitted
within
the
specified
comment
period.
Comments
received
after
the
close
of
the
comment
period
will
be
marked
``
late.''
The
EPA
is
not
required
to
consider
these
late
comments.
However,
late
comments
may
be
considered
if
time
permits.
Electronically.
If
you
submit
an
electronic
comment
as
prescribed
below,
EPA
recommends
that
you
include
your
name,
mailing
address,
and
an
e
mail
address
or
other
contact
information
in
the
body
of
your
comment.
Also
include
this
contact
information
on
the
outside
of
any
disk
or
CD
ROM
you
submit,
and
in
any
cover
letter
accompanying
the
disk
or
CD
ROM.
This
ensures
that
you
can
be
identified
as
the
submitter
of
the
comment
and
allows
EPA
to
contact
you
in
case
EPA
cannot
read
your
comment
due
to
technical
difficulties
or
needs
further
information
on
the
substance
of
your
comment.
The
EPA's
policy
is
that
EPA
will
not
edit
your
comment,
and
any
identifying
or
contact
information
provided
in
the
body
of
a
comment
will
be
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket
and
made
available
in
EPA's
electronic
public
docket.
If
EPA
cannot
read
your
comment
due
to
technical
difficulties
and
cannot
contact
you
for
clarification,
EPA
may
not
be
able
to
consider
your
comment.
Your
use
of
EPA's
electronic
public
docket
to
submit
comments
to
EPA
electronically
is
EPA's
preferred
method
for
receiving
comments.
Go
directly
to
EPA
Dockets
at
http://
www.
epa.
gov/
edocket,
and
follow
the
online
instructions
for
submitting
comments.
To
access
EPA's
electronic
public
docket
from
the
EPA
Internet
Home
Page,
select
``
Information
Sources,''
``
Dockets,''
and
``
EPA
Dockets.''
Once
in
the
system,
select
``
search,''
and
then
key
in
Docket
ID
No.
OAR
2002
0059.
The
system
is
an
``
anonymous
access''
system,
which
means
EPA
will
not
know
your
identity,
e
mail
address,
or
other
contact
information
unless
you
provide
it
in
the
body
of
your
comment.
Comments
may
be
sent
by
electronic
mail
(
e
mail)
to
a
and
r
docket@
epa.
gov,
Attention
Docket
ID
No.
OAR
2002
0059.
In
contrast
to
EPA's
electronic
public
docket,
EPA's
e
mail
system
is
not
an
``
anonymous
access''
system.
If
you
send
an
e
mail
comment
directly
to
the
Docket
without
going
through
EPA's
electronic
public
docket,
EPA's
e
mail
system
automatically
captures
your
email
address.
E
mail
addresses
that
are
automatically
captured
by
EPA's
e
mail
system
are
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket
and
made
available
in
EPA's
electronic
public
docket.
You
may
submit
comments
on
a
disk
or
CD
ROM
that
you
mail
to
the
mailing
address
identified
below.
These
electronic
submissions
will
be
accepted
in
WordPerfect
or
ASCII
file
format.
Avoid
the
use
of
special
characters
and
any
form
of
encryption.
By
Mail.
Send
your
comments
(
in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center,
U.
S.
EPA,
Mailcode:
6102T,
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
2002
0059.
The
EPA
requests
a
separate
copy
also
be
sent
to
the
contact
person
listed
above
(
see
FOR
FURTHER
INFORMATION
CONTACT).
By
Hand
Delivery
or
Courier.
Deliver
your
comments
to:
EPA
Docket
Center,
Room
B108,
1301
Constitution
Ave.,
NW.,
Washington,
DC
20460,
Attention
Docket
ID
No.
OAR
2002
0059.
Such
deliveries
are
only
accepted
during
the
Docket's
normal
hours
of
operation
as
identified
above.
Do
not
submit
information
that
you
consider
to
be
CBI
electronically
through
EPA's
electronic
public
docket
or
by
e
mail.
Send
or
deliver
information
identified
as
CBI
only
to
the
following
address:
Mr.
Sims
Roy,
c/
o
OAQPS
Document
Control
Officer
(
Room
C404
2),
U.
S.
EPA,
Research
Triangle
Park,
27711,
Attention
Docket
ID
No.
OAR
2002
0059.
You
may
claim
information
that
you
submit
to
EPA
as
CBI
by
marking
any
part
or
all
of
that
information
as
CBI
(
if
you
submit
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
as
CBI
and
then
identify
electronically
within
the
disk
or
CD
ROM
the
specific
information
that
is
CBI).
Information
so
marked
will
not
be
disclosed
except
in
accordance
with
procedures
set
forth
in
40
CFR
part
2.
In
addition
to
one
complete
version
of
the
comment
that
includes
any
information
claimed
as
CBI,
a
copy
of
the
comment
that
does
not
contain
the
information
claimed
as
CBI
must
be
submitted
for
inclusion
in
the
public
docket
and
EPA's
electronic
public
docket.
If
you
submit
the
copy
that
does
not
contain
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
clearly
that
it
does
not
contain
CBI.
Information
not
marked
as
CBI
will
be
included
in
the
public
docket
and
EPA's
electronic
public
docket
without
prior
notice.
If
you
have
any
questions
about
CBI
or
the
procedures
for
claiming
CBI,
please
consult
the
person
identified
in
the
FOR
FURTHER
INFORMATION
CONTACT
section.
You
may
find
the
following
suggestions
helpful
for
preparing
your
comments:
1.
Explain
your
views
as
clearly
as
possible.
2.
Describe
any
assumptions
that
you
used.
3.
Provide
any
technical
information
and/
or
data
you
used
that
support
your
views.
4.
If
you
estimate
potential
burden
or
costs,
explain
how
you
arrived
at
your
estimate.
5.
Provide
specific
examples
to
illustrate
your
concerns.
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2002
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Proposed
Rules
6.
Offer
alternatives.
7.
Make
sure
to
submit
your
comments
by
the
comment
period
deadline
identified.
8.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
response.
It
would
also
be
helpful
if
you
provided
the
name,
date,
and
Federal
Register
citation
related
to
your
comments.
Public
Hearing.
Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Mrs.
Kelly
Hayes,
Combustion
Group,
Emission
Standards
Division
(
MD
C439
01),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711,
(
919)
541
5578
at
least
2
days
in
advance
of
the
public
hearing.
Persons
interested
in
attending
the
public
hearing
must
also
call
Mrs.
Hayes
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
the
proposed
rule.
If
a
public
hearing
is
requested
and
held,
EPA
will
ask
clarifying
questions
during
the
oral
presentation
but
will
not
respond
to
the
presentations
or
comments.
Written
statements
and
supporting
information
will
be
considered
with
equivalent
weight
as
any
oral
statement
and
supporting
information
presented
at
a
public
hearing,
if
held.
Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:
I.
Background
A.
What
is
the
regulatory
development
background
of
this
source
category?
B.
What
is
the
source
of
authority
for
development
of
NESHAP?
C.
What
criteria
are
used
in
the
development
of
NESHAP?
D.
What
are
the
health
effects
associated
with
HAP
from
stationary
RICE?
II.
Summary
of
the
Proposed
Rule
A.
Am
I
subject
to
the
proposed
rule?
B.
What
source
categories
and
subcategories
are
affected
by
the
proposed
rule?
C.
What
are
the
primary
sources
of
HAP
emissions
and
what
are
the
emissions?
D.
What
are
the
emission
limitations
and
operating
limitations?
E.
What
are
the
initial
compliance
requirements?
F.
What
are
the
continuous
compliance
provisions?
G.
What
monitoring
and
testing
methods
are
available
to
measure
these
low
concentrations
of
CO
and
formaldehyde?
H.
What
are
the
notification,
recordkeeping
and
reporting
requirements?
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
did
we
select
the
source
category
and
any
subcategories?
B.
What
is
the
affected
source?
C.
How
did
we
determine
the
basis
and
level
of
the
proposed
emission
limitations
and
operating
limitations?
D.
Why
does
the
proposed
rule
not
apply
to
stationary
RICE
of
500
brake
horsepower
or
less?
E.
Why
does
the
proposed
rule
not
apply
to
stationary
RICE
located
at
area
sources?
F.
How
did
we
select
the
format
of
the
standard?
G.
How
did
we
select
the
initial
compliance
requirements?
H.
How
did
we
select
the
continuous
compliance
requirements?
I.
What
monitoring
and
testing
methods
are
available
to
measure
these
low
concentrations
of
CO
and
formaldehyde?
J.
How
did
we
select
the
notification,
recordkeeping
and
reporting
requirements?
IV.
Summary
of
Environmental,
Energy
and
Economic
Impacts
A.
What
are
the
air
quality
impacts?
B.
What
are
the
cost
impacts?
C.
What
are
the
economic
impacts?
D.
What
are
the
nonair
health,
environmental
and
energy
impacts?
V.
Solicitation
of
Comments
and
Public
Participation
VI.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Executive
Order
13132,
Federalism
C.
Executive
Order
13175,
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Executive
Order
13211,
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
F.
Unfunded
Mandates
Reform
Act
of
1995
G.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
H.
Paperwork
Reduction
Act
I.
National
Technology
Transfer
and
Advancement
Act
I.
Background
A.
What
Is
the
Regulatory
Development
Background
of
the
Source
Category?
In
September
1996,
we
chartered
the
Industrial
Combustion
Coordinated
Rulemaking
(
ICCR)
advisory
committee
under
the
Federal
Advisory
Committee
Act
(
FACA).
The
committee's
objective
was
to
develop
recommendations
for
regulations
for
several
combustion
source
categories
under
sections
112
and
129
of
the
CAA.
The
ICCR
advisory
committee,
also
known
as
the
Coordinating
Committee,
formed
Source
Work
Groups
for
the
various
combustor
types
covered
under
the
ICCR.
One
work
group,
the
RICE
Work
Group,
was
formed
to
research
issues
related
to
stationary
RICE
units.
The
RICE
Work
Group
submitted
recommendations,
information,
and
data
analyses
to
the
Coordinating
Committee,
which
in
turn
considered
them
and
submitted
recommendations
and
information
to
EPA.
The
Committee's
2
year
charter
expired
in
September
1998.
We
considered
the
Committee's
recommendations
in
developing
the
proposed
rule
for
stationary
RICE.
B.
What
Is
the
Source
of
Authority
for
Development
of
NESHAP?
Section
112
of
the
CAA
requires
us
to
list
categories
and
subcategories
of
major
sources
and
area
sources
of
HAP
and
to
establish
NESHAP
for
the
listed
source
categories
and
subcategories.
The
stationary
RICE
source
category
was
listed
on
July
16,
1992
(
57
FR
31576).
Major
sources
of
HAP
are
those
that
have
the
potential
to
emit
greater
than
10
ton/
yr
of
any
one
HAP
or
25
ton/
yr
of
any
combination
of
HAP.
Most
RICE
engines
or
groups
of
RICE
engines
are
not
major
HAP
emission
sources
by
themselves
but
are
major
because
they
are
co
located
at
major
HAP
sites.
C.
What
Criteria
Are
Used
in
the
Development
of
NESHAP?
Section
112
of
the
CAA
requires
that
we
establish
NESHAP
for
the
control
of
HAP
from
both
new
and
existing
sources
in
regulated
source
categories.
The
CAA
requires
the
NESHAP
to
reflect
the
maximum
degree
of
reduction
in
emissions
of
HAP
that
is
achievable.
This
level
of
control
is
commonly
referred
to
as
the
MACT.
The
MACT
floor
is
the
minimum
control
level
allowed
for
NESHAP
and
is
defined
under
section
112(
d)(
3)
of
the
CAA.
In
essence,
the
MACT
floor
ensures
that
the
standards
are
set
at
a
level
that
assures
that
all
major
sources
achieve
the
level
of
control
at
least
as
stringent
as
that
already
achieved
by
the
better
controlled
and
lower
emitting
sources
in
each
source
category
or
subcategory.
For
new
sources,
the
MACT
floor
cannot
be
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
best
controlled
similar
source.
The
MACT
standards
for
existing
sources
can
be
less
stringent
than
standards
for
new
sources,
but
they
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
existing
sources
in
the
category
or
subcategory
(
or
the
best
performing
5
sources
for
categories
or
subcategories
with
fewer
than
30
sources).
In
developing
MACT,
we
also
consider
control
options
that
are
more
stringent
than
the
floor.
We
may
establish
standards
more
stringent
than
the
floor
based
on
the
consideration
of
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cost
of
achieving
the
emissions
reductions,
any
nonair
quality
health
and
environmental
impacts,
and
energy
requirements.
D.
What
Are
the
Health
Effects
Associated
With
HAP
From
Stationary
RICE?
Emission
data
collected
during
development
of
the
proposed
NESHAP
show
that
several
HAP
are
emitted
from
stationary
RICE.
These
HAP
emissions
are
formed
during
combustion
or
result
from
HAP
compounds
contained
in
the
fuel
burned.
Hazardous
air
pollutants
which
have
been
measured
in
emission
tests
conducted
on
natural
gas
fired
and
distillate
oil
fired
RICE
include:
1,1,2,2
tetrachloroethane,
1,3
butadiene,
2,2,4
trimethylpentane,
acetaldehyde,
acrolein,
benzene,
chlorobenzene,
chloroethane,
ethylbenzene,
formaldehyde,
methanol,
methylene
chloride,
n
hexane,
naphthalene,
polycyclic
aromatic
hydrocarbons,
polycyclic
organic
matter,
styrene,
tetrachloroethane,
toluene,
and
xylene.
Metallic
HAP
from
distillate
oil
fired
stationary
RICE
that
have
been
measured
are:
Cadmium,
chromium,
lead,
manganese,
mercury,
nickel,
and
selenium.
Although
numerous
HAP
may
be
emitted
from
RICE,
only
a
few
account
for
essentially
all
of
the
mass
of
HAP
emissions
from
stationary
RICE.
These
HAP
are:
Formaldehyde,
acrolein,
methanol,
and
acetaldehyde.
The
hazardous
air
pollutant
emitted
in
the
largest
quantities
from
stationary
RICE
is
formaldehyde.
Formaldehyde
is
a
probable
human
carcinogen
and
can
cause
irritation
of
the
eyes
and
respiratory
tract,
coughing,
dry
throat,
tightening
of
the
chest,
headache,
and
heart
palpitations.
Acute
inhalation
has
caused
bronchitis,
pulmonary
edema,
pneumonitis,
pneumonia,
and
death
due
to
respiratory
failure.
Long
term
exposure
can
cause
dermatitis
and
sensitization
of
the
skin
and
respiratory
tract.
Acrolein
is
a
cytotoxic
agent,
a
powerful
lacrimating
agent,
and
a
severe
tissue
irritant.
Acute
exposure
to
acrolein
can
cause
severe
irritation
or
corrosion
of
the
eyes,
nose,
throat,
and
lungs,
with
tearing,
pain
in
the
chest,
and
delayed
onset
pulmonary
injury
with
depressed
pulmonary
function.
Chronic
exposure
to
acrolein
can
cause
skin
sensitization
and
contact
dermatitis.
Acrolein
is
not
considered
carcinogenic
to
humans.
Humans
are
very
sensitive
to
the
toxic
effects
of
methanol
including
formic
acidaemia,
metabolic
acidosis,
ocular
toxicity,
nervous
system
depression,
blindness,
coma,
and
death.
A
majority
of
the
available
information
on
methanol
toxicity
in
humans
is
based
on
acute
rather
than
long
term
exposure.
However,
recent
animal
studies
also
indicate
potential
reproductive
and
developmental
health
consequences
following
exposure
to
methanol
in
both
mice
and
primates.
Methanol
has
not
been
classified
with
respect
to
carcinogenicity.
The
health
effects
for
acetaldehyde
are
irritation
of
the
eye
mucous
membranes,
skin,
and
upper
respiratory
tract,
and
a
central
nervous
system
(
CNS)
depressant
in
humans.
Chronic
exposure
can
cause
conjunctivitis,
coughing,
difficult
breathing,
and
dermatitis.
Chronic
exposure
may
cause
heart
and
kidney
damage,
embryotoxicity,
and
teratogenic
effects.
Acetaldehyde
is
a
probable
carcinogen
in
humans.
We
recently
reviewed
health
effects
associated
with
emissions
of
particulates
from
diesel
engines
in
the
context
of
regulating
heavy
duty
motor
vehicles
and
engines
(
66
FR
5001,
January
18,
2001).
Diesel
particulate
matter
is
not
currently
listed
as
a
hazardous
air
pollutant
for
stationary
sources
under
section
112
of
the
CAA
and
was
not
specifically
reviewed
under
the
proposed
rule,
though
constituent
parts
of
diesel
particulate
matter
are
subject
to
the
proposed
rule.
We
are
continuing
to
review
this
issue
in
the
context
of
regulating
stationary
internal
combustion
engines.
II.
Summary
of
the
Proposed
Rule
A.
Am
I
Subject
to
the
Proposed
Rule?
The
proposed
rule
applies
to
you
if
you
own
or
operate
stationary
RICE
which
are
located
at
a
major
source
of
HAP
emissions,
except
if
your
stationary
RICE
are
all
rated
at
or
under
500
brake
horsepower.
A
major
source
of
HAP
emissions
is
a
plant
site
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
10
tons
(
9.07
megagrams)
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
25
tons
(
22.68
megagrams)
or
more
per
year.
Section
112(
n)(
4)
of
the
CAA
requires
that
the
aggregation
of
HAP
for
purposes
of
determining
whether
an
oil
and
gas
production
facility
is
major
or
nonmajor
be
done
only
with
respect
to
particular
sites
within
the
source
and
not
on
a
total
aggregated
site
basis.
We
incorporated
the
requirements
of
section
112(
n)(
4)
of
the
CAA
into
our
NESHAP
for
Oil
and
Natural
Gas
Production
Facilities
in
subpart
HH
of
40
CFR
part
63.
As
in
subpart
HH,
we
plan
to
aggregate
HAP
emissions
for
the
purposes
of
determining
a
major
HAP
source
for
RICE
only
with
respect
to
particular
sites
within
an
oil
and
gas
production
facility.
The
sites
are
called
surface
sites
and
may
include
a
combination
of
any
of
the
following
equipment:
glycol
dehydrators,
tanks
which
have
potential
for
flash
emissions,
RICE
and
combustion
turbines.
The
standards
proposed
in
the
rule
have
specific
requirements
for
all
new
or
reconstructed
stationary
RICE
and
for
existing
spark
ignition
4
stroke
rich
burn
(
4SRB)
stationary
RICE
located
at
a
major
source
of
HAP
emissions,
except
that
stationary
RICE
with
a
manufacturer's
nameplate
rating
of
500
brake
horsepower
or
less
are
not
addressed
in
the
proposed
rule.
Stationary
RICE
which
operate
exclusively
as
emergency
power/
limited
use
units
or
which
combust
landfill
gas
or
digester
gas
as
primary
fuel
are
subject
only
to
initial
notification
requirements.
An
emergency
power/
limited
use
unit
means
any
stationary
RICE
that
operates
as
a
mechanical
or
electrical
power
source
during
emergencies,
when
the
primary
power
source
for
a
facility
has
been
rendered
inoperable
by
an
emergency
situation.
One
example
is
when
electric
power
from
the
local
utility
is
interrupted.
Another
example
is
to
pump
water
in
the
case
of
fire
or
flood.
Emergency
power/
limited
use
units
include
units
that
operate
less
than
50
hours
per
year
in
nonemergency
situations,
including
certain
peaking
units
at
electric
facilities
or
stationary
RICE
at
industrial
facilities.
With
the
exception
of
existing
spark
ignition
4SRB
stationary
RICE,
other
types
of
existing
stationary
RICE
(
i.
e.,
spark
ignition
2
stroke
lean
burn
(
2SLB),
spark
ignition
4
stroke
lean
burn
(
4SLB),
and
compression
ignition
(
CI))
located
at
a
major
source
of
HAP
emissions
are
not
subject
to
any
specific
requirement
under
the
proposed
rule.
Finally,
the
proposed
rule
does
not
apply
to
stationary
RICE
test
cells/
stands
since
these
facilities
will
be
covered
by
another
NESHAP,
subpart
PPPPP
of
40
CFR
part
63.
B.
What
Source
Categories
and
Subcategories
Are
Affected
by
the
Proposed
Rule?
The
proposed
rule
covers
new
or
reconstructed
stationary
RICE
and
existing
spark
ignition
4SRB
stationary
RICE.
A
RICE
is
any
spark
ignition
or
compression
ignition
reciprocating
internal
combustion
engine.
A
stationary
RICE
is
any
RICE
which
is
not
mobile.
Stationary
RICE
differ
from
mobile
RICE
in
that
stationary
RICE
are
not
self
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propelled,
are
not
intended
to
be
propelled
while
performing
their
function,
or
are
not
portable
or
transportable
as
that
term
is
identified
in
the
definition
of
non
road
engine
at
40
CFR
89.2.
We
divided
the
stationary
RICE
source
category
into
four
subcategories:
(
1)
Emergency
power/
limited
use
units,
(
2)
stationary
RICE
that
combust
landfill
gas
or
digester
gas
as
their
primary
fuel,
(
3)
stationary
RICE
with
a
manufacturer's
nameplate
rating
of
500
brake
horsepower
or
less,
and
(
4)
other
stationary
RICE.
We
further
divided
the
last
subcategory
into
four
subcategories:
(
1)
2SLB
stationary
RICE,
(
2)
4SLB
stationary
RICE,
(
3)
4SRB
stationary
RICE,
and
(
4)
CI
stationary
RICE.
We
are
specifically
soliciting
comments
on
creating
a
subcategory
of
limited
use
engines
with
a
capacity
utilization
of
10
percent
or
less.
This
is
further
discussed
in
the
``
Solicitation
of
Comments
and
Public
Participation''
section
of
this
preamble.
The
proposed
rule
does
not
apply
to
stationary
RICE
test
cells/
stands
since
these
facilities
will
be
covered
by
another
NESHAP,
subpart
PPPPP
of
40
CFR
part
63.
The
proposed
rule
also
does
not
apply
to
existing,
new,
or
reconstructed
stationary
RICE
located
at
an
area
source
of
HAP
emissions.
An
area
source
of
HAP
emissions
is
a
plant
site
that
does
not
emit
any
single
HAP
at
a
rate
of
10
tons
(
9.07
megagrams)
or
greater
per
year
or
any
combination
of
HAP
at
a
rate
of
25
tons
(
22.68
megagrams)
or
greater
per
year.
In
addition,
the
proposed
rule
does
not
apply
to
stationary
RICE
with
a
manufacturer's
nameplate
rating
of
500
brake
horsepower
or
below.
These
engines
have
been
discussed
previously
in
this
preamble.
C.
What
Are
the
Primary
Sources
of
HAP
Emissions
and
What
Are
the
Emissions?
The
primary
sources
of
HAP
emissions
are
exhaust
gases
from
combustion
of
gaseous
fuels
and
liquid
fuels
in
stationary
RICE.
Formaldehyde,
acrolein,
methanol,
and
acetaldehyde
are
HAP
that
are
present
in
significant
quantities
from
stationary
RICE.
D.
What
Are
the
Emission
Limitations
and
Operating
Limitations?
As
the
owner
or
operator
of
an
affected
source,
you
must
do
one
of
the
following:
(
1)
Each
existing,
new,
or
reconstructed
4SRB
stationary
RICE
must
comply
with
each
emission
limitation
in
Table
1(
a)
of
proposed
subpart
ZZZZ,
40
CFR
part
63,
and
each
operating
limitation
in
Table
1(
b)
of
proposed
subpart
ZZZZ
that
apply,
or
(
2)
each
new
or
reconstructed
2SLB
or
4SLB
stationary
RICE
or
CI
stationary
RICE
must
comply
with
each
emission
limitation
in
Table
2(
a)
of
proposed
subpart
ZZZZ
and
operating
limitation
in
Table
2(
b)
of
proposed
subpart
ZZZZ
that
apply.
Existing
2SLB
or
4SLB
stationary
RICE
or
existing
CI
stationary
RICE,
stationary
RICE
that
operate
exclusively
as
emergency
power/
limited
use
units,
or
stationary
RICE
that
combust
digester
gas
or
landfill
gas
as
their
primary
fuel
have
an
emission
standard
of
no
emission
reduction,
and
will
not
be
tested
to
meet
any
specific
emission
limitation
or
operating
limitation.
In
addition,
any
stationary
RICE
located
at
an
area
source
of
HAP
emissions,
any
stationary
RICE
that
have
a
manufacturer's
nameplate
rating
of
500
brake
horsepower
or
less,
or
stationary
RICE
that
are
being
tested
at
stationary
RICE
test
cells/
stands
are
not
addressed
in
the
proposed
rule
and,
therefore,
do
not
need
to
comply
with
any
emission
limitation
or
operating
limitation.
E.
What
Are
the
Initial
Compliance
Requirements?
If
your
stationary
RICE
must
meet
specific
emission
limitations
and
operating
limitations,
then
you
must
meet
the
following
initial
compliance
requirements.
The
testing
and
initial
compliance
requirements
are
different,
depending
on
whether
you
demonstrate
compliance
with
the
carbon
monoxide
(
CO)
emission
reduction
requirement,
formaldehyde
emission
reduction
requirement,
or
the
requirement
to
limit
the
formaldehyde
concentration
in
the
stationary
RICE
exhaust.
1.
If
you
own
or
operate
a
2SLB
or
4SLB
stationary
RICE,
or
a
CI
stationary
RICE
with
a
manufacturer's
nameplate
rating
less
than
5000
brake
horsepower
complying
with
the
requirement
to
reduce
CO
emissions
using
a
oxidation
catalyst,
you
must
install
a
continuous
parameter
monitoring
system
(
CPMS)
to
continuously
monitor
the
pressure
drop
across
the
catalyst
and
the
catalyst
inlet
temperature.
You
must
conduct
an
initial
performance
test
to
demonstrate
that
you
are
achieving
the
required
CO
percent
reduction,
corrected
to
15
percent
oxygen,
dry
basis.
During
the
initial
performance
test,
you
must
record
the
initial
pressure
drop
across
the
catalyst
and
the
catalyst
inlet
temperature.
2.
If
you
own
or
operate
a
2SLB
or
4SLB
stationary
RICE,
or
a
CI
stationary
RICE
with
a
manufacturer's
nameplate
rating
greater
than
or
equal
to
5000
brake
horsepower
complying
with
the
requirement
to
reduce
CO
emissions
using
an
oxidation
catalyst,
you
must
install
a
continuous
emissions
monitoring
system
(
CEMS)
to
measure
CO
and
either
carbon
dioxide
or
oxygen
simultaneously
at
the
inlet
and
outlet
of
the
oxidation
catalyst.
To
demonstrate
initial
compliance,
you
must
conduct
an
initial
performance
evaluation
using
Performance
Specifications
(
PS)
3
and
4A
of
40
CFR
part
60,
appendix
B.
You
must
demonstrate
that
the
reduction
of
CO
emissions
meets
the
required
percent
reduction
using
the
first
4
hour
average
after
a
successful
performance
evaluation.
Your
measurements
at
the
inlet
and
the
outlet
of
the
oxidation
catalyst
must
be
on
a
dry
basis
and
corrected
to
15
percent
oxygen
or
equivalent
carbon
dioxide
content.
3.
If
you
own
or
operate
a
4SRB
stationary
RICE
complying
with
the
requirement
to
reduce
formaldehyde
emissions
using
non
selective
catalytic
reduction
(
NSCR),
you
must
install
a
CPMS
to
continuously
monitor
the
pressure
drop
across
the
catalyst,
the
catalyst
inlet
temperature,
and
the
temperature
rise
across
the
catalyst.
You
must
conduct
an
initial
performance
test
to
demonstrate
that
you
are
achieving
the
required
formaldehyde
percent
reduction,
corrected
to
15
percent
oxygen,
dry
basis.
During
the
initial
performance
test,
you
must
record
the
initial
values
of
the
pressure
drop
across
the
catalyst,
the
catalyst
inlet
temperature,
and
the
temperature
rise
across
the
catalyst.
4.
If
you
are
complying
with
the
requirement
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust,
you
must
conduct
an
initial
performance
test
using
Test
Method
320
or
323
of
40
CFR
part
63,
appendix
A,
California
Air
Resources
Board
(
CARB)
Method
430,
or
EPA
Solid
Waste
(
SW)
846
Method
0011
to
demonstrate
that
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
is
less
than
or
equal
to
the
emission
limit,
corrected
to
15
percent
oxygen,
dry
basis,
that
applies
to
you.
To
correct
to
15
percent
oxygen,
dry
basis,
you
must
measure
oxygen
using
Method
3A
or
3B
of
40
CFR
part
60,
appendix
A,
and
measure
moisture
using
Method
4
of
40
CFR
part
60,
appendix
A.
The
initial
performance
test
must
be
conducted
at
the
lowest
load
at
which
you
will
operate
your
stationary
RICE
and
at
the
typical
load
at
which
you
will
operate
your
stationary
RICE.
This
initial
performance
test
establishes
the
lowest
load
or
the
minimum
fuel
flow
rate
at
which
you
may
operate
your
stationary
RICE.
To
demonstrate
initial
compliance,
you
must
also
install
a
CPMS
to
continuously
monitor
stationary
RICE
load
or
fuel
flow
rate
and
other
(
if
any)
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244
/
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December
19,
2002
/
Proposed
Rules
operating
parameters
approved
by
the
Administrator.
If
you
choose
to
comply
with
the
emission
limitation
to
limit
the
concentration
of
formaldehyde,
you
must
also
petition
the
Administrator
for
approval
of
additional
operating
limitations
or
approval
of
no
additional
operating
limitations.
If
the
Administrator
approves
your
petition
for
additional
operating
limitations,
the
operating
limitations
must
also
be
established
during
the
initial
performance
test.
If
you
petition
the
Administrator
for
approval
of
additional
operating
limitations,
your
petition
must
include
the
following:
(
1)
Identification
of
the
specific
parameters
you
propose
to
use
as
additional
operating
limitations;
(
2)
a
discussion
of
the
relationship
between
the
parameters
and
HAP
emissions,
identifying
how
HAP
emissions
change
with
changes
in
the
parameters,
and
how
limitations
on
the
parameters
will
serve
to
limit
HAP
emissions;
(
3)
a
discussion
of
how
you
will
establish
the
upper
and/
or
lower
values
for
the
parameters
which
will
establish
the
limits
on
the
parameters
in
the
operating
limitations;
(
4)
a
discussion
identifying
the
methods
you
will
use
to
measure
and
the
instruments
you
will
use
to
monitor
the
parameters,
as
well
as
the
relative
accuracy
and
precision
of
the
methods
and
instruments;
and
(
5)
a
discussion
identifying
the
frequency
and
methods
for
recalibrating
the
instruments
you
will
use
for
monitoring
the
parameters.
If
you
petition
the
Administrator
for
approval
of
no
additional
operating
limitations,
your
petition
must
include
the
following:
(
1)
Identification
of
the
parameters
associated
with
operation
of
the
stationary
RICE
and
any
emission
control
device
which
could
change
intentionally
(
e.
g.,
operator
adjustment,
automatic
controller
adjustment,
etc.)
or
unintentionally
(
e.
g.,
wear
and
tear,
error,
etc.)
on
a
routine
basis
or
over
time;
(
2)
a
discussion
of
the
relationship,
if
any,
between
changes
in
the
parameters
and
changes
in
HAP
emissions;
(
3)
for
those
parameters
with
a
relationship
to
HAP
emissions,
a
discussion
of
whether
establishing
limitations
on
the
parameters
would
serve
to
limit
HAP
emissions;
(
4)
for
those
parameters
with
a
relationship
to
HAP
emissions,
a
discussion
of
how
you
could
establish
upper
and/
or
lower
values
for
the
parameters
which
would
establish
limits
on
these
parameters
in
operating
limitations;
(
5)
for
the
parameters
with
a
relationship
to
HAP
emissions,
a
discussion
identifying
the
methods
you
could
use
to
measure
the
parameters
and
the
instruments
you
could
use
to
monitor
them,
as
well
as
the
relative
accuracy
and
precision
of
the
methods
and
instruments;
(
6)
for
the
parameters,
a
discussion
identifying
the
frequency
and
methods
for
recalibrating
the
instruments
you
could
use
to
monitor
them;
and
(
7)
a
discussion
of
why,
from
your
point
of
view,
it
is
infeasible
or
unreasonable
to
adopt
the
parameters
as
operating
limitations.
F.
What
Are
the
Continuous
Compliance
Provisions?
Several
general
continuous
compliance
requirements
apply
to
all
stationary
RICE
meeting
various
specified
emission
and
operating
limitations.
If
your
stationary
RICE
is
required
to
meet
specific
emission
and
operating
limitations,
then
you
are
required
to
comply
with
the
emission
and
operating
limitations
at
all
times,
except
during
startup,
shutdown,
and
malfunction
of
your
stationary
RICE.
You
must
also
operate
and
maintain
your
stationary
RICE,
air
pollution
control
equipment,
and
monitoring
equipment
according
to
good
air
pollution
control
practices
at
all
times,
including
startup,
shutdown,
and
malfunction.
You
must
conduct
all
monitoring
at
all
times
that
the
stationary
RICE
is
operating,
except
during
periods
of
malfunction
of
the
monitoring
equipment
or
necessary
repairs
or
quality
assurance
or
control
activities,
such
as
calibration
checks.
1.
For
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
a
manufacturer's
nameplate
rating
less
than
5000
brake
horsepower,
complying
with
the
requirement
to
reduce
CO
emissions
using
an
oxidation
catalyst,
you
must
conduct
quarterly
performance
tests
for
CO
and
oxygen
using
a
portable
CO
monitor
to
demonstrate
that
the
required
CO
percent
reduction
is
achieved.
To
demonstrate
continuous
compliance
with
the
CO
percent
reduction
requirement,
you
must
continuously
monitor
and
record
the
pressure
drop
across
the
catalyst
and
the
catalyst
inlet
temperature.
The
4
hour
rolling
average
of
the
valid
data
must
be
within
the
operating
limitations.
If
you
change
your
oxidation
catalyst
(
i.
e.,
replace
catalyst
elements),
you
must
reestablish
your
pressure
drop
and
catalyst
inlet
temperature.
2.
For
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
a
manufacturer's
nameplate
rating
greater
than
or
equal
to
5000
brake
horsepower,
complying
with
the
CO
percent
reduction
emission
limitation
using
an
oxidation
catalyst,
you
must
calibrate
and
operate
your
CEMS
according
to
the
requirements
in
40
CFR
63.8.
You
must
continuously
monitor
and
record
the
CO
concentration
at
the
inlet
and
outlet
of
the
oxidation
catalyst
and
calculate
the
percent
reduction
of
CO
emissions
hourly.
The
reduction
of
CO
must
be
at
least
the
required
percent
reduction,
based
on
a
rolling
4
hour
average,
averaged
every
hour.
You
must
also
conduct
an
annual
relative
accuracy
test
audit
(
RATA)
of
your
CEMS
using
PS
3
and
4A
of
40
CFR
part
60,
appendix
B,
as
well
as
daily
and
periodic
data
quality
checks
in
accordance
with
40
CFR
part
60,
appendix
F,
procedure
1.
3.
For
existing,
new,
or
reconstructed
4SRB
stationary
RICE
complying
with
the
requirement
to
reduce
formaldehyde
emissions
using
NSCR,
you
must
demonstrate
continuous
compliance
by
continuously
monitoring
the
pressure
drop
across
the
catalyst,
the
catalyst
inlet
temperature
and
the
temperature
rise
across
the
catalyst.
The
4
hour
rolling
average
of
the
valid
data
must
be
above
and/
or
below
the
lower
bounds
and/
or
upper
bounds
of
the
operating
parameters
corresponding
to
compliance
with
the
requirement
to
reduce
formaldehyde
emissions.
If
you
change
your
NSCR
(
i.
e.,
replace
catalyst
elements),
you
must
reestablish
the
values
of
the
pressure
drop
across
the
catalyst,
the
catalyst
inlet
temperature
and
the
temperature
rise
across
the
catalyst.
The
4SRB
stationary
RICE
with
a
manufacturer's
nameplate
rating
greater
than
or
equal
to
5000
brake
horsepower
must
also
conduct
semiannual
performance
tests
to
demonstrate
that
the
percent
reduction
for
formaldehyde
emissions
is
achieved.
If
you
demonstrate
compliance
with
the
percent
reduction
requirement
for
two
successive
performance
tests,
you
may
reduce
the
frequency
of
performance
testing
to
annually.
However,
if
an
annual
performance
test
indicates
a
deviation
from
the
percent
reduction
requirement,
you
must
return
to
semiannual
performance
tests.
4.
If
you
are
complying
with
the
requirement
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust,
the
following
requirements
must
be
met:
a.
Proper
maintenance.
At
all
times,
the
owner
or
operator
shall
maintain
the
monitoring
equipment
including,
but
not
limited
to,
maintaining
necessary
parts
for
routine
repairs
of
the
monitoring
equipment.
b.
Continued
operation.
Except
for,
as
applicable,
monitoring
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
(
including,
as
applicable,
calibration
checks
and
required
zero
and
span
adjustments),
the
owner
or
operator
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/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
shall
conduct
all
monitoring
in
continuous
operation
at
all
times
that
the
unit
is
operating.
Data
recorded
during
monitoring
malfunctions,
associated
repairs,
out
of
control
periods,
and
required
quality
assurance
or
control
activities
shall
not
be
used
for
purposes
of
calculating
data
averages.
The
owner
or
operator
shall
use
all
the
data
collected
during
all
other
periods
in
assessing
compliance.
A
monitoring
malfunction
is
any
sudden,
infrequent,
not
reasonably
preventable
failure
of
the
monitoring
equipment
to
provide
valid
data.
Monitoring
failures
that
are
caused
in
part
by
poor
maintenance
or
careless
operation
are
not
malfunctions.
Any
period
for
which
the
monitoring
system
is
out
of
control
and
data
are
not
available
for
required
calculations
constitutes
a
deviation
from
the
monitoring
requirements.
To
demonstrate
continuous
compliance
with
the
operating
limitations,
you
must
continuously
monitor
and
record
the
operating
load
or
fuel
flow
rate
of
the
stationary
RICE,
and
the
values
of
any
other
parameters
which
have
been
approved
by
the
Administrator
as
operating
limitations.
The
4
hour
rolling
average
of
the
operating
load
or
fuel
flow
rate
must
be
no
lower
than
5
percent
below
the
operating
limitations
established
during
the
initial
performance
test.
After
completion
of
the
initial
performance
test,
you
must
demonstrate
that
formaldehyde
emissions
remain
at
or
below
the
formaldehyde
concentration
limit
by
performing
semiannual
performance
tests.
If
you
demonstrate
compliance
with
the
requirement
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
for
two
successive
performance
tests,
you
may
reduce
the
frequency
of
performance
testing
to
annually.
However,
if
an
annual
performance
test
indicates
a
deviation
of
formaldehyde
emissions
from
the
formaldehyde
concentration
limit,
you
must
return
to
semiannual
performance
tests.
Also,
if
your
stationary
RICE
will
be
operated
at
a
load
that
is
lower
than
the
load
at
which
you
operated
the
stationary
RICE
during
the
initial
performance
test,
you
must
conduct
a
performance
test
and
reestablish
the
minimum
values
for
the
stationary
RICE.
G.
What
Monitoring
and
Testing
Methods
Are
Available
To
Measure
These
Low
Concentrations
of
CO
and
Formaldehyde?
Continuous
emissions
monitoring
systems
are
available
which
can
accurately
measure
CO
emissions
at
the
low
concentrations
found
in
the
exhaust
of
a
stationary
RICE
following
an
oxidation
catalyst
emission
control
device.
Our
PS
4A
of
40
CFR
part
60,
appendix
B,
for
CO
CEMS,
however,
has
not
been
updated
recently
and
does
not
reflect
the
performance
capabilities
of
the
systems.
We
are
currently
undertaking
a
review
of
PS
4
and
4A
of
40
CFR
part
60,
appendix
B,
for
CO
CEMS,
and
in
conjunction
with
this
effort,
we
solicit
comments
on
the
performance
capabilities
of
CO
CEMS
to
accurately
measure
the
low
concentrations
of
CO
experienced
in
the
exhaust
of
a
stationary
RICE
following
an
oxidation
catalyst
emission
control
device.
Similarly,
our
Fourier
Transform
Infrared
(
FTIR)
test
method,
Method
320
of
40
CFR
part
63,
appendix
A,
CARB
Method
430,
as
well
as
EPA
SW
846
Method
0011
can
be
used
to
accurately
measure
formaldehyde
concentrations
in
the
exhaust
of
a
stationary
RICE
as
low
as
350
parts
per
billion
by
volume,
dry
basis
(
ppbvd).
Similar
to
our
current
performance
specifications
for
CO
CEMS,
as
both
of
these
test
methods
are
currently
written,
they
do
not
provide
for
this
level
of
accuracy.
The
methods
must
be
used
with
some
revisions
to
achieve
such
accuracy.
As
a
result,
we
are
currently
undertaking
a
review
of
our
FTIR
method,
Method
320
of
40
CFR
part
63,
appendix
A,
to
incorporate
revisions
to
ensure
it
can
be
used
to
accurately
measure
formaldehyde
concentrations
as
low
as
8
ppbvd
in
the
exhaust
from
a
stationary
RICE.
In
conjunction
with
this
effort,
we
solicit
comments
on
revisions
to
Method
320
of
40
CFR
part
63,
appendix
A,
to
ensure
accurate
measurement
of
such
low
concentrations
of
formaldehyde.
In
addition,
we
are
also
proposing
another
EPA
method
for
measuring
formaldehyde
from
natural
gas
fired
stationary
RICE.
This
impinger
based
method,
EPA
Method
323
of
40
CFR
part
63,
appendix
A,
Measurement
of
Formaldehyde
Emissions
From
Natural
Gas
fired
Stationary
Sources
Acetyl
Acetone
Derivitization
Method,
may
be
an
acceptable
method
for
measuring
low
concentrations
as
required
by
the
proposed
rule.
H.
What
Are
the
Notification,
Recordkeeping
and
Reporting
Requirements?
If
you
own
or
operate
a
stationary
RICE
which
is
located
at
a
major
source
of
HAP
emissions,
you
must
submit
all
of
the
applicable
notifications
as
listed
in
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A),
including
an
initial
notification,
notification
of
performance
test
or
evaluation,
and
a
notification
of
compliance
for
each
stationary
RICE
which
must
comply
with
the
specified
emission
and
operating
limitations.
In
addition,
you
must
submit
an
initial
notification
for
each
stationary
RICE
which
operates
exclusively
as
an
emergency
power/
limited
use
unit
or
a
stationary
RICE
which
combusts
digester
gas
or
landfill
gas
as
primary
fuel.
You
must
record
all
of
the
data
necessary
to
determine
if
you
are
in
compliance
with
the
emission
limitations
and
operating
limitations
(
if
applicable)
as
required
by
the
proposed
rule.
Your
records
must
be
in
a
form
suitable
and
readily
available
for
review.
You
must
also
keep
each
record
for
5
years
following
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record.
Records
must
remain
on
site
for
at
least
2
years
and
then
can
be
maintained
offsite
for
the
remaining
3
years.
You
must
submit
a
compliance
report
semiannually.
This
report
should
contain
information
including
company
name
and
address,
a
statement
by
a
responsible
official
that
the
report
is
accurate,
and
a
statement
of
compliance
or
documentation
of
any
deviation
from
the
requirements
of
the
proposed
rule
during
the
reporting
period.
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
Did
We
Select
the
Source
Category
and
Any
Subcategories?
Stationary
RICE
are
listed
as
a
major
source
category
for
regulatory
development
under
section
112
of
the
CAA.
The
CAA
allows
us
discretion
in
defining
the
appropriate
scope
of
the
category
and
subcategories.
We
considered
several
criteria
associated
with
stationary
RICE
which
could
lead
to
establishment
of
subcategories
including
differences
in
emission
characteristics,
fuel,
mode
of
operation,
size
of
source,
and
type
of
source.
We
identified
four
subcategories
of
stationary
RICE
located
at
major
sources:
(
1)
Emergency
power/
limited
use
units,
(
2)
stationary
RICE
which
combust
landfill
gas
or
digester
gas
as
their
primary
fuel,
(
3)
stationary
RICE
with
a
manufacturer's
rating
of
500
brake
horsepower
or
less,
and
(
4)
other
stationary
RICE.
We
identified
emergency
power/
limited
use
units
as
a
subcategory.
Emergency
power/
limited
use
units
operate
only
in
emergencies,
such
as
a
loss
of
power
provided
by
another
source.
These
types
of
stationary
RICE
operate
infrequently
and,
when
called
upon
to
operate,
must
respond
without
failure
and
without
lengthy
periods
of
startup.
These
conditions
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/
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19,
2002
/
Proposed
Rules
applicability
of
HAP
emission
control
technology
to
emergency
power/
limited
use
units.
Similarly,
stationary
RICE
which
combust
landfill
gas
or
digester
gas
as
their
primary
fuel
were
identified
as
a
subcategory.
Landfill
and
digester
gases
contain
a
family
of
chemicals
referred
to
as
siloxanes,
which
limits
the
application
of
HAP
emission
control
technology.
Stationary
RICE
with
a
manufacturer's
nameplate
rating
of
500
brake
horsepower
or
less
were
also
identified
as
a
subcategory.
We
know
very
little
about
these
stationary
RICE
and
without
further
knowledge
have
concerns
about
the
applicability
of
HAP
emission
control
technology
to
them.
As
discussed
above,
we
have
not
addressed
these
stationary
RICE
in
the
proposed
rule.
Finally,
in
considering
the
fourth
subcategory
(
i.
e.,
other
stationary
RICE
located
at
major
sources
of
HAP
emissions),
we
identified
four
additional
subcategories
of
stationary
RICE
within
this
fourth
subcategory:
(
1)
2SLB
stationary
RICE,
(
2)
4SLB
stationary
RICE,
(
3)
4SRB
stationary
RICE,
and
(
4)
CI
stationary
RICE.
The
further
subcategorization
is
necessary
because
engine
design
characteristics,
HAP
emissions,
and
the
application
of
HAP
emission
control
technology
differ
among
the
subcategories.
For
further
information
on
our
rationale
for
subcategorization,
see
the
memorandum
entitled
``
Subcategorization
of
Stationary
Reciprocating
Internal
Combustion
Engines
for
the
Purpose
of
NESHAP''
in
the
docket.
Stationary
RICE
being
tested
at
stationary
RICE
test
cells/
stands
are
not
covered
by
the
proposed
rule
since
they
will
be
covered
by
a
separate
NESHAP,
subpart
PPPPP
of
40
CFR
part
63.
B.
What
Is
the
Affected
Source?
The
affected
source
for
the
proposed
rule
is
any
stationary
RICE
located
at
a
major
source
of
HAP
emissions
with
a
manufacturer's
nameplate
rating
above
500
brake
horsepower
and
not
being
tested
at
a
stationary
RICE
test
cell/
stand.
C.
How
Did
We
Determine
the
Basis
and
Level
of
the
Proposed
Emission
Limitations
and
Operating
Limitations?
1.
Overview
As
established
in
section
112(
d)
of
the
CAA,
the
emission
standards
must
be
no
less
stringent
than
the
MACT
floor,
which
for
existing
sources
is
the
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
existing
sources.
The
MACT
floor
for
new
sources
must
be
no
less
stringent
than
the
level
of
emission
control
that
is
achieved
in
practice
by
the
best
controlled
similar
source.
As
outlined
below,
the
MACT
floors
and
MACT
for
existing
and
new
stationary
RICE
were
developed
primarily
through
analyses
of
the
population
database
and
the
emissions
database.
The
population
database
provides
population
information
on
operating
stationary
RICE
in
the
United
States
and
was
constructed
to
support
the
proposed
rule.
The
population
database
contains
information
from
available
databases,
such
as
the
Aerometric
Information
Retrieval
System,
the
Ozone
Transport
and
Assessment
Group,
and
State
and
local
agencies'
databases.
The
first
version
of
the
database
was
released
in
1997.
Subsequent
versions
have
been
released
reflecting
additional
or
updated
data.
The
most
recent
release
of
the
database
is
version
4,
released
in
November
1998.
The
population
database
contains
information
on
approximately
28,000
stationary
RICE.
We
believe
the
current
stationary
RICE
population
is
about
37,000,
including
those
under
500
horsepower
and
those
at
area
sources,
therefore,
we
believe
the
population
database
represents
about
75
percent
of
the
stationary
RICE
in
the
United
States.
As
a
result,
we
believe
the
information
in
the
population
database
is
representative
of
the
stationary
RICE
industry
subject
to
the
proposed
rule.
The
emissions
database
is
a
compilation
of
available
HAP
emission
test
reports
created
to
support
the
proposed
rule.
The
majority
of
HAP
emission
test
reports
were
conducted
in
the
State
of
California
as
part
of
the
Air
Toxics
``
Hot
Spots''
Information
Assessment
Act
of
1987
program.
Complete
copies
of
HAP
emission
test
reports
for
stationary
RICE
were
gathered
from
air
districts
in
California
and
taken
from
a
previous
EPA
effort
referred
to
as
the
Source
Test
Information
Retrieval
System.
Other
States
and
trade
associations
such
as
Western
States
Petroleum
Association
and
Gas
Research
Institute
(
GRI)
were
contacted
for
available
HAP
emission
test
reports.
Finally,
the
emissions
database
also
includes
preliminary
results
from
a
joint
EPA
industry
HAP
emission
testing
program
on
stationary
RICE
at
the
Engines
and
Energy
Conversion
Laboratory
at
Colorado
State
University
(
CSU).
2.
General
We
considered
several
approaches
to
identify
MACT
floors
for
stationary
RICE.
One
approach
was
to
review
State
regulations
and
permits
for
stationary
RICE.
We
found
no
State
regulations
or
State
permits
which
specifically
limit
HAP
emissions
from
stationary
RICE.
Another
approach
we
considered
to
identify
MACT
floors
for
stationary
RICE
was
that
of
good
combustion
practices.
We
tried
to
identify
specific
practices
which
might
be
considered
improved
maintenance
or
operation,
such
as
frequent
checks
or
tune
ups,
which
serve
to
maintain
a
stationary
RICE
in
good
operating
condition.
We
thought
the
use
of
such
practices
might
prevent
increases
in
HAP
emissions
which
could
arise
from
poor
operation
or
failure
of
a
stationary
RICE.
Toward
that
end,
we
contacted
State
and
local
permitting
authorities,
as
well
as
the
manufacturers
and
the
owners
and
operators
of
stationary
RICE.
A
more
detailed
discussion
is
presented
in
``
Pollution
Prevention
for
Reciprocating
Internal
Combustion
Engines''
in
the
docket.
We
were
unable
to
identify
any
specific
good
combustion
practices
from
these
efforts
which
we
could
relate
directly
to
reduced
HAP
emissions.
As
mentioned
above,
the
primary
approach
we
ultimately
used
to
identify
MACT
floors
and
MACT
was
to
review
information
in
the
population
and
emissions
databases.
We
reviewed
the
information
in
the
databases
to
identify
stationary
RICE
operating
with
emission
control
systems
and
then
to
identify
the
level
of
performance,
in
terms
of
HAP
emissions
reductions,
associated
with
the
use
of
the
emission
control
systems.
We
reviewed
MACT
floors
and
MACT
for
the
four
subcategories
separately.
The
MACT
for
emergency
power/
limited
use
units
and
landfill/
digester
gas
units
are
discussed
later
in
this
preamble.
As
discussed
above,
we
did
not
address
engines
with
manufacturer's
nameplate
ratings
at
or
below
500
brake
horsepower
in
the
proposed
rule
nor
do
we
address
stationary
RICE
that
are
tested
at
stationary
RICE
test
cells/
stands.
The
MACT
for
other
stationary
RICE
are
discussed
below.
We
found
several
stationary
RICE
operating
with
oxidation
catalyst
systems
and
several
operating
with
NSCR
systems.
Oxidation
catalyst
systems
have
been
installed
primarily
to
reduce
CO
emissions
and,
to
some
extent,
volatile
organic
compounds
(
VOC)
emissions,
from
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE.
Non
selective
catalytic
reduction
systems,
on
the
other
hand,
have
been
installed
primarily
to
reduce
nitrogen
oxides
(
NOX)
emissions
from
4SRB
stationary
RICE.
Examination
of
HAP
emission
data
from
the
emissions
database,
as
well
as
preliminary
emission
data
from
HAP
emission
testing
at
CSU
leads
us
to
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Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
conclude
that
oxidation
catalyst
systems
will
reduce
HAP
emissions
from
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE,
as
discussed
further
below.
Similarly,
examination
of
HAP
emission
data
leads
us
to
conclude
that
NSCR
will
reduce
HAP
emissions
from
4SRB
stationary
RICE.
3.
Existing
Source
MACT
Floor
for
Other
Stationary
RICE
Subcategory
As
mentioned
in
the
previous
section,
MACT
floors
for
existing
RICE
could
not
be
established
based
on
State
and
local
permit
information
because
there
are
no
State
or
local
regulations
for
RICE
regarding
HAP
and
the
use
of
good
operating
practices
because
no
operating
practices
could
be
specifically
linked
to
HAP
emissions
reductions.
Review
of
the
population
database
indicates
that
few
existing
2SLB
and
4SLB
stationary
RICE
or
CI
stationary
RICE
use
oxidation
catalyst
systems.
The
number
is
less
than
1
percent
for
2SLB
stationary
RICE,
about
3
percent
for
4SLB
stationary
RICE,
and
less
than
1
percent
for
CI
stationary
RICE.
In
addition,
less
than
1
percent
of
existing
CI
stationary
RICE
use
a
catalyzed
diesel
particulate
filter
(
C
DPF),
which
is
believed
to
reduce
HAP
emissions
to
some
extent.
However,
all
of
these
percentages
are
well
below
the
criteria
for
a
MACT
floor
that
would
require
emissions
reductions
for
existing
sources
(
average
emission
limitation
achieved
by
the
best
performing
12
percent
of
existing
sources).
We
have
interpreted
average
emission
limitation
of
the
best
performing
12
percent
to
refer
to
either
the
numerical
mean
or
the
numerical
median.
In
this
case,
EPA
has
used
the
median
value,
that
is,
the
level
of
control
at
the
6th
(
best
performing)
percentile
to
determine
the
average.
Thus,
we
conclude
the
MACT
floor
for
existing
2SLB,
4SLB,
and
CI
stationary
RICE
is
no
emissions
reductions.
Unlike
the
situation
outlined
above,
more
than
6
percent
of
existing
4SRB
stationary
RICE
use
NSCR
systems.
Therefore,
we
conclude
the
MACT
floor
for
4SRB
existing
stationary
RICE
is
the
level
of
HAP
emissions
reductions
achieved
by
the
use
of
NSCR
systems.
We
discuss
this
in
more
detail
below.
4.
Existing
Source
MACT
To
determine
MACT
for
the
subcategories
of
existing
2SLB
and
4SLB
stationary
RICE
and
existing
CI
stationary
RICE,
we
evaluated
two
regulatory
alternatives
more
stringent
than
the
MACT
floor.
Specifically,
we
considered
the
use
of
oxidation
catalyst
systems
as
a
beyond
the
floor
regulatory
alternative
and
fuel
switching.
With
one
exception
noted
below,
these
are
the
only
options
we
know
of
which
could
serve
as
the
basis
for
MACT
to
reduce
HAP
emissions
from
the
subcategories
of
stationary
RICE.
In
our
review
of
oxidation
catalyst
systems,
we
concluded
that
this
alternative
would
be
inappropriate
given
the
cost
per
ton
of
HAP
removed.
Non
air
quality
health,
environmental
impacts,
and
energy
effects
were
not
significant
factors.
The
second
option
considered
was
to
switch
fuels
in
existing
RICE
from
fuels
which
result
in
higher
HAP
emissions
to
fuels
that
result
in
lower
HAP
emissions.
When
we
compared
the
CAA
section
112
HAP
emissions
factors
of
the
various
fuels
from
RICE,
using
the
July
2000
revision
of
Chapter
3.2
(
Natural
Gas
Fired
Reciprocating
Internal
Combustion
Engines)
and
the
October
1996
revision
of
Chapter
3.3
(
Gasoline
and
Diesel
Industrial
Engines)
of
``
Compilation
of
Air
Pollutant
Emission
Factors
AP
42,
Fifth
Edition,
Volume
1:
Stationary
Point
and
Area
Sources,''
we
could
not
find
a
fuel
that
was
clearly
less
HAP
emitting.
The
summation
of
emission
factors
for
various
HAP
when
using
natural
gas
(
usually
considered
the
cleanest
fuel)
or
diesel
fuel
were
comparable
based
on
the
emission
factor
information
that
is
available.
Therefore,
we
could
find
no
basis
to
consider
fuel
switching
as
a
beyond
the
floor
HAP
emissions
reductions
option.
For
existing
compression
ignition
stationary
RICE,
we
also
considered
another
beyond
the
floor
regulatory
alternative,
the
use
of
C
DPF.
Some
believe
the
use
of
such
filters
will
reduce
HAP
emissions;
however,
there
are
no
data
available
to
quantify
what
the
level
of
the
reduction
might
be.
Most
speculate
that
it
is
less
than
that
achieved
through
the
use
of
oxidation
catalyst
systems.
The
cost
of
C
DPF,
however,
is
greater
than
that
of
oxidation
catalyst
systems
and,
for
that
reason,
we
consider
the
alternative
to
also
be
inappropriate
as
well.
Non
air
quality
health,
environmental
impacts,
and
energy
effects
were
not
significant
factors.
We
conclude,
therefore,
that
MACT
for
existing
2SLB
and
4SLB
stationary
RICE
and
existing
CI
stationary
RICE
is
the
MACT
floor
(
i.
e.,
no
emissions
reductions).
As
a
result,
we
propose
no
requirements
for
emissions
testing
for
existing
2SLB
and
4SLB
stationary
RICE
and
existing
CI
stationary
RICE.
For
further
information
on
the
determination
of
MACT,
refer
to
the
Regulatory
Impact
Analysis
for
the
proposed
rule
and
memoranda
entitled
``
Regulatory
Alternatives
and
MACT
for
Stationary
Reciprocating
Internal
Combustion
Engines''
and
``
National
Impacts
Associated
with
Reciprocating
Internal
Combustion
Engines''
in
the
docket.
For
4SRB
stationary
RICE,
we
know
of
no
other
HAP
emission
control
technology
other
than
the
use
of
NSCR
systems.
The
fuel
switching
analysis
presented
previously
also
applies
to
existing
4SRB
RICE.
Therefore,
we
are
unable
to
identify
any
beyond
the
floor
regulatory
alternative
for
this
subcategory
of
stationary
RICE.
Consequently,
we
conclude
that
MACT
for
existing
4SRB
stationary
RICE
is
also
equivalent
to
the
MACT
floor
(
i.
e.,
the
level
of
HAP
emission
control
achieved
through
the
use
of
NSCR
systems).
To
determine
the
level
of
performance
associated
with
the
use
of
NSCR
systems
on
4SRB
stationary
RICE,
we
examined
HAP
emission
data
from
the
emissions
database.
We
also
examined
a
recent
industry
sponsored
formaldehyde
emission
test
conducted
on
two
4SRB
stationary
RICE
equipped
with
NSCR.
Emission
testing
to
measure
HAP
emitted
from
stationary
RICE
is
very
expensive,
and
we
know
of
no
CEMS
which
could
be
used
to
continuously
monitor
all
HAP
emissions.
As
a
result,
we
first
examined
the
emission
data
mentioned
above
to
determine
if
a
single
pollutant
could
serve
as
a
surrogate
for
HAP
emissions.
We
focused
on
CO
emissions
initially
because
CO
is
easy
to
measure.
In
addition,
CEMS
for
CO
emissions
are
readily
available
and,
in
most
cases,
the
costs
associated
with
their
use
are
considered
reasonable.
Unfortunately,
there
is
not
a
good
relationship
between
CO
emission
concentration
or
CO
emissions
reductions
and
HAP
emissions
concentrations
or
HAP
emissions
reductions
from
4SRB
stationary
RICE
equipped
with
NSCR.
Thus,
CO
emission
concentration
and
CO
emission
reduction
cannot
serve
as
surrogates
for
HAP
emissions
for
4SRB
stationary
RICE.
Next,
we
considered
the
use
of
formaldehyde
concentration
as
a
surrogate
for
all
HAP
emissions.
Formaldehyde
is
the
hazardous
air
pollutant
present
in
the
highest
concentrations
in
emissions
from
4SRB
stationary
RICE
and,
more
importantly,
the
level
of
formaldehyde
emissions
are
related
to
the
level
of
other
HAP
emissions.
When
formaldehyde
emissions
are
reduced
through
the
use
of
NSCR
systems,
HAP
emissions
are
reduced
as
well.
Consequently,
we
conclude
that
reductions
in
formaldehyde
emissions
can
serve
as
a
surrogate
for
reductions
in
HAP
emissions
for
4SRB
stationary
RICE
operating
with
NSCR
systems.
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/
Thursday,
December
19,
2002
/
Proposed
Rules
The
emissions
database
contains
several
emission
test
reports
that
measured
formaldehyde
emissions
from
4SRB
stationary
RICE
equipped
with
NSCR,
but
no
tests
measure
the
emissions
both
before
and
after
the
control
device,
so
the
control
efficiency
of
NSCR
systems
could
not
be
determined
from
the
emissions
database.
Moreover,
the
test
reports
in
the
emissions
database
provide
single
snapshot
emission
readings
from
stationary
RICE,
which
does
not
account
for
variability
of
emissions
that
may
occur
as
engines
are
operated
in
actual
use.
The
data,
for
example,
provided
little
or
no
information
regarding
variable
parameters
such
as
timing
and
load.
As
a
result,
we
examined
data
from
an
industry
sponsored
formaldehyde
emission
test
conducted
on
two
4SRB
stationary
RICE
equipped
with
NSCR
to
determine
the
level
of
performance
of
NSCR
systems.
These
test
reports
were
reviewed,
and
we
concluded
that
the
engines
and
control
devices
were
operated
correctly
during
the
tests
and
the
tests
were
conducted
properly.
We
considered
several
factors,
such
as
load,
which
could
have
an
effect
on
the
efficiency
of
the
control
device,
but
could
find
no
reason
for
the
variability
of
the
test
results
between
the
two
engines.
We
selected
the
best
performing
engine
based
on
the
highest
average
formaldehyde
percent
reduction.
The
average
reduction
was
79
percent
for
that
engine;
however,
to
establish
variability,
we
looked
at
each
of
the
12
individual
test
runs
performed
on
that
engine.
The
percent
reduction
varied
from
75
percent
to
81
percent.
We
selected
75
percent
for
the
MACT
floor,
which
takes
into
account
the
variability
of
the
best
performing
engine.
The
HAP
emission
data
outlined
above
show
that
the
use
of
NSCR
systems
on
4SRB
stationary
RICE
will
reduce
formaldehyde
emissions
by
75
percent
or
more.
As
a
result,
we
propose
a
75
percent
or
more
reduction
in
formaldehyde
emissions
as
the
emission
limitation
for
existing
4SRB
stationary
RICE.
For
existing
4SRB
engines
that
choose
to
use
a
control
or
reduction
technology
that
is
not
an
NSCR
system,
an
alternative
standard
was
developed
based
on
a
formaldehyde
concentration
limit.
For
existing
4SRB
engines
the
alternative
emission
limitation
is
350
ppbvd
corrected
to
15
percent
oxygen.
The
alternative
formaldehyde
concentration
limit
standard
is
discussed
in
more
detail
below.
5.
New
Source
MACT
Floor
Several
existing
2SLB
and
4SLB
stationary
RICE
and
existing
CI
stationary
RICE
currently
operate
with
oxidation
catalyst
systems.
No
technology
achieving
greater
emissions
reductions
was
found.
Thus,
we
conclude
the
MACT
floor
for
new
2SLB
and
4SLB
stationary
RICE
and
new
CI
stationary
RICE
is
the
level
of
HAP
emission
control
achieved
through
the
use
of
oxidation
catalyst
systems.
The
level
of
HAP
reductions
achieved
through
oxidation
catalysts
differs
for
each
of
the
subcategories
as
discussed
in
more
detail
below.
Again,
for
new
compression
ignition
stationary
RICE,
we
considered
whether
the
use
of
C
DPF
might
be
the
basis
for
the
MACT
floor.
However,
since
oxidation
catalyst
systems
achieve
greater
HAP
emissions
reductions,
we
concluded
that
oxidation
catalyst
systems,
not
C
DPF,
are
the
basis
for
the
MACT
floor
for
new
compression
ignition
stationary
RICE.
As
mentioned
earlier,
a
number
of
existing
4SRB
stationary
RICE
use
NSCR
systems.
As
a
result,
the
use
of
NSCR
systems
is
the
best
performing
technology
identified
for
use
by
4SRB
stationary
RICE.
Consequently,
we
conclude
the
MACT
floor
for
new
4SRB
stationary
RICE
is
the
level
of
HAP
emissions
reductions
achieved
through
the
use
of
NSCR
systems.
6.
New
Source
MACT
For
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE,
we
know
of
no
other
HAP
emission
control
technology
than
the
use
of
oxidation
catalyst
systems
(
other
than
possibly
the
use
of
C
DPF
on
compression
ignition
stationary
RICE,
as
discussed
earlier).
The
fuel
switching
analysis
presented
previously
also
applies
to
new
2SLB,
4SLB,
and
CI
RICE.
Therefore,
we
were
unable
to
identify
any
beyond
the
floor
regulatory
alternative
for
these
subcategories
of
stationary
RICE.
Consequently,
we
conclude
that
MACT
for
new
2SLB
and
4SLB
stationary
RICE
and
new
CI
stationary
RICE
is
equivalent
to
the
MACT
floor
(
i.
e.,
the
level
of
HAP
emission
control
achieved
through
the
use
of
oxidation
catalyst
systems).
Although
the
basis
for
MACT
for
each
of
these
subcategories
of
stationary
RICE
is
the
same,
as
outlined
below,
HAP
emission
data
from
the
emissions
database
and
preliminary
emission
data
from
the
HAP
emission
testing
program
at
CSU
indicate
that
the
level
of
performance
achieved
by
oxidation
catalyst
systems
on
each
of
these
subcategories
of
stationary
RICE
differ.
As
a
result,
we
propose
different
emission
limitations
for
each
of
these
subcategories
of
new
stationary
RICE.
As
mentioned
above,
emission
testing
to
measure
HAP
emissions
is
expensive,
and
we
know
of
no
CEMS
which
could
be
used
to
continuously
monitor
all
HAP
emissions.
As
a
result,
we
first
examined
the
emission
data
to
determine
if
a
single
pollutant
could
serve
as
a
surrogate
for
HAP
emissions.
Again,
we
focused
on
CO
emission
concentration
and
CO
emissions
reductions
initially.
In
this
case,
we
found
that
there
is
a
good
relationship
between
CO
emissions
reductions
and
HAP
emissions
reductions
from
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
equipped
with
oxidation
catalyst
systems.
When
CO
emissions
are
reduced,
HAP
emissions
are
reduced
in
a
relatively
proportional
manner.
As
a
result,
CO
emissions
reductions
can
serve
as
a
surrogate
for
HAP
emissions
reductions
for
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
operating
with
oxidation
catalyst
systems.
A
joint
EPA
industry
HAP
emission
testing
program
at
CSU
provided
HAP
and
CO
emissions
data
which
form
the
basis
for
the
MACT
floor
and
MACT
for
2SLB,
4SLB,
and
CI
stationary
RICE.
A
single
engine
of
each
type
equipped
with
an
oxidation
catalyst
control
system
was
tested.
The
engines
were
all
overhauled
before
the
testing
and
were
expected
to
operate
as
well
as
new
engines.
The
oxidation
catalyst
control
systems
represented
the
best
HAP
emission
control
known
for
each
type
of
engine.
All
catalyst
systems
were
new
but
were
operated
for
a
number
of
hours
until
the
CO
percent
reduction
stabilized.
This
assured
that
the
performance
would
be
not
overestimated
by
the
use
of
a
new
catalyst.
Prior
to
the
testing,
EPA
and
industry
developed
a
list
of
engine
operating
parameters
that
were
known
to
vary
throughout
the
U.
S.
for
each
type
of
engine.
The
engines
and
control
devices
were
tested
at
typical
engine
conditions
in
which
these
operating
parameters
were
varied.
The
variations
in
the
emission
reduction
results
for
each
engine
type
are
due
to
the
variability
of
the
engine
and
control
system
and
include
a
representation
of
the
performance
of
the
best
controlled
source
for
new
engines.
The
fluctuations
in
HAP
emission
control
represent
the
variability
inherent
in
operating
the
engine
and
control
device
combination
under
various
conditions.
Some
parameters
such
as
the
exhaust
temperature
are
an
important
determinate
of
the
catalytic
activity
and
resulting
emissions
reductions
but
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Vol.
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No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
cannot
be
controlled
by
the
operator
because
they
are
a
result
of
factors
such
as
engine
design,
ambient
temperature,
and
designed
air
to
fuel
ratio.
These
result
in
a
significant
source
of
variability
that
cannot
be
controlled.
The
HAP
emission
data
mentioned
above
show
that
the
use
of
oxidation
catalyst
systems
on
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
will
reduce
uncontrolled
CO
emissions
by
60
percent
or
more,
93
percent
or
more,
and
70
percent
or
more,
respectively,
taking
into
account
the
variability
of
results
achieved
when
tested
under
various
operating
parameters.
As
a
result,
we
propose:
(
1)
A
60
percent
or
more
reduction
in
CO
uncontrolled
emissions
as
the
emission
limitation
for
new
2SLB
stationary
RICE,
(
2)
a
93
percent
or
more
reduction
in
CO
emissions
as
the
emission
limitation
for
new
4SLB
stationary
RICE,
and
(
3)
a
70
percent
or
more
reduction
in
CO
emissions
as
the
emission
limitation
for
new
CI
stationary
RICE.
The
variation
in
percent
reduction
of
CO
achieved
between
2SLB
stationary
RICE
and
4SLB
stationary
RICE
is
a
result
of
the
higher
exhaust
temperatures
for
4SLB
stationary
RICE.
The
2SLB
stationary
RICE
tested
at
CSU
had
an
average
exhaust
temperature
of
530
degrees
Fahrenheit,
while
the
4SLB
stationary
RICE
had
an
average
exhaust
temperature
of
691
degrees
Fahrenheit.
In
general,
higher
exhaust
temperatures
lead
to
better
catalyst
performance.
This
difference
in
temperatures
is
a
function
of
the
inherent
design
of
these
engine
types
and
cannot
be
controlled
by
the
operator.
For
4SRB
stationary
RICE,
we
know
of
no
other
HAP
emission
control
technology
than
the
use
of
NSCR
systems.
The
fuel
switching
analysis
presented
previously
also
applies
to
new
4SRB
RICE.
As
a
result,
we
were
unable
to
identify
any
beyond
the
floor
regulatory
alternative.
Consequently,
we
conclude
that
MACT
for
new
4SRB
stationary
RICE
is
equivalent
to
the
MACT
floor
(
i.
e.,
the
level
of
HAP
emission
control
achieved
through
the
use
of
NSCR
systems).
The
basis
for
MACT
for
new
4SRB
stationary
RICE,
therefore,
is
the
same
as
that
for
existing
4SRB
stationary
RICE.
We
believe
NSCR
systems
will
achieve
the
same
level
of
performance
on
existing
as
well
as
new
4SRB
stationary
RICE.
Consequently,
we
propose
the
same
emission
limitation
for
both
existing
and
new
4SRB
stationary
RICE
(
i.
e.,
75
percent
or
more
reduction
in
formaldehyde
emissions).
For
new
4SRB
engines
that
choose
to
use
a
control
or
reduction
technology
that
is
not
an
NSCR
system,
and
for
new
2SLB,
4SLB,
and
CI
engines
that
choose
a
control
or
reduction
technology
that
is
not
an
oxidation
catalyst
system,
an
alternative
standard
was
developed
based
on
formaldehyde
concentration
limits.
The
alternative
emission
limits
for
new
RICE
sources
are:
17
parts
per
million
by
volume
dry
basis
(
ppmvd)
formaldehyde
for
2SLB
engines,
14
ppmvd
formaldehyde
for
4SLB
engines,
350
ppbvd
formaldehyde
for
4SRB
engines,
and
580
ppbvd
formaldehyde
for
CI
engines,
all
corrected
to
15
percent
oxygen.
The
alternative
formaldehyde
concentration
limit
standard
is
discussed
in
more
detail
below.
7.
MACT
Floor
and
MACT
for
Other
Subcategories
Although
the
proposed
rule
applies
to
all
stationary
RICE
with
a
manufacturer's
nameplate
rating
above
500
brake
horsepower
located
at
major
sources
excluding
stationary
RICE
being
tested
at
stationary
RICE
test
cells/
stands,
there
are
two
subcategories
of
stationary
RICE
for
which
the
appropriate
emission
standard
is
no
emissions
reductions;
therefore,
they
would
not
be
required
to
comply
with
any
emissions
limitations
or
operating
limitations
under
the
proposed
rule.
These
subcategories
are
stationary
RICE
which
combust
digester
or
landfill
gas
as
the
primary
fuel
and
emergency
power/
limited
use
stationary
RICE.
a.
Stationary
RICE
Combusting
Digester
or
Landfill
Gas
Examination
of
the
population
database
shows
that
there
are
no
stationary
RICE
burning
digester
gas
or
landfill
gas
as
the
primary
fuel
operating
with
emission
control
technologies
which
reduce
HAP
emissions.
Therefore,
we
conclude
the
MACT
floor
for
the
subcategory
is
no
emissions
reductions
for
both
existing
as
well
as
new
stationary
RICE.
We
considered
the
applicability
of
HAP
emission
control
technology,
such
as
the
use
of
an
oxidation
catalyst
system
for
example,
to
this
subcategory
of
stationary
RICE
for
beyond
the
floor
controls.
However,
digester
gases
and
landfill
gases
contain
a
family
of
silicon
based
compounds
called
siloxanes.
Combustion
of
siloxanes
can
foul
post
combustion
catalysts,
rendering
them
inoperable
within
a
short
period
of
time.
We
considered
pretreatment
systems
to
remove
siloxanes
from
the
gases
prior
to
combustion;
however,
we
found
no
pretreatment
systems
in
use
and
the
long
term
effectiveness
is
unknown.
As
a
result,
we
know
of
no
emission
control
technology
which
could
be
applied
to
the
subcategory
of
stationary
RICE
to
reduce
HAP
emissions.
We
also
considered
fuel
switching
for
this
subcategory
of
RICE.
Switching
to
a
different
fuel
such
as
natural
gas
or
diesel
would
potentially
allow
the
RICE
to
apply
the
MACT
controls.
However,
fuel
switching
would
defeat
the
purpose
of
these
units,
which
are
intended
to
use
this
type
of
fuel.
Fuel
switching
would
also
cause
the
landfill/
digester
gas
either
to
escape
uncontrolled
or
to
be
burned
in
a
flare
with
no
energy
recovery.
We
believe
that
switching
landfill
or
digester
gas
to
another
fuel
is
inappropriate
and
is
an
environmentally
inferior
option.
For
that
reason,
we
were
unable
to
identify
a
beyond
the
floor
regulatory
alternative
for
either
existing
or
new
stationary
RICE
combusting
digester
gases
or
landfill
gases
as
the
primary
fuel.
Consequently,
we
conclude
that
MACT
for
the
subcategory
of
stationary
RICE
is
the
MACT
floor
(
i.
e.,
no
emissions
reductions).
Thus,
we
propose
no
requirements
for
emissions
testing
for
stationary
RICE
which
combust
landfill
gases
or
digester
gases
as
the
primary
fuels.
b.
Emergency
Power/
Limited
Use
Stationary
RICE
Emergency
power/
limited
use
stationary
RICE
operate
only
in
emergencies
when
the
normal
source
of
power
at
a
facility
fails.
Based
on
our
review
of
the
population
database,
there
are
no
emergency
power/
limited
use
stationary
RICE
which
operate
with
HAP
emission
control
technology.
Thus,
we
conclude
the
MACT
floor
for
the
subcategory
is
no
emissions
reductions
for
both
existing
as
well
as
new
stationary
RICE.
As
with
stationary
RICE
burning
digester
gases
or
landfill
gases,
we
also
have
a
number
of
concerns
regarding
the
applicability
of
HAP
emission
control
technology
to
emergency
power/
limited
use
stationary
RICE.
Emergency
power/
limited
use
stationary
RICE
operate
infrequently
but
when
called
upon
to
operate,
they
must
respond
immediately
without
fail
and
without
lengthy
startup
periods.
Under
such
conditions,
we
have
doubts
whether
HAP
emission
control
technology,
such
as
the
use
of
oxidation
catalyst
systems,
would
effectively
reduce
HAP
emissions.
Despite
the
concerns,
we
examined
the
cost
per
ton
of
HAP
removed
for
emergency
power/
limited
use
stationary
RICE
as
a
beyond
the
floor
regulatory
alternative.
Whether
our
concerns
are
warranted
or
not,
we
consider
the
cost
per
ton
of
HAP
removed
for
the
alternative
unreasonable,
primarily
because
of
the
very
small
reductions
in
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Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
HAP
emissions
which
might
be
achieved.
Non
air
quality
health,
environmental
impacts,
nor
energy
effects
were
significant
factors.
For
all
of
the
reasons
listed
above,
we
conclude
that
MACT
for
both
existing
as
well
as
new
emergency
power/
limited
use
stationary
RICE
is
the
MACT
floor
(
i.
e.,
no
emissions
reductions).
Consequently,
we
propose
no
requirements
for
emissions
testing
for
emergency
power/
limited
use
stationary
RICE.
D.
Why
Does
the
Proposed
Rule
Not
Apply
to
Stationary
RICE
of
500
Brake
Horsepower
or
Less?
In
reviewing
the
population
database
to
identify
stationary
RICE
with
a
manufacturer's
nameplate
rating
of
500
brake
horsepower
or
less,
we
found
extremely
little
information.
In
discussions
with
State
and
local
permitting
officials,
the
manufacturers,
and
some
of
the
owners
and
operators
of
stationary
RICE,
we
found
that
such
small
stationary
RICE
have
generally
not
been
regarded
as
significant
sources
of
air
pollutant
emissions.
As
a
result,
the
small
stationary
RICE
have
not
been
subjected
to
the
same
level
of
scrutiny,
examination,
or
review
as
larger
stationary
RICE.
Little
information
has
been
gathered
or
compiled
by
anyone
for
this
subcategory
of
stationary
RICE.
Thus,
at
this
point,
we
know
very
little
about
stationary
RICE
with
a
manufacturer's
nameplate
rating
of
500
brake
horsepower
or
less.
For
example,
we
do
not
know
how
many
of
the
small
stationary
RICE
exist.
In
addition,
we
know
little
about
the
operating
characteristics
and
emissions,
the
current
use
of,
as
well
as
the
applicability
of,
emission
control
technologies,
the
costs
of
emission
control
for
the
small
stationary
RICE,
or
the
economic
impacts
and
benefits
associated
with
regulation.
In
the
absence
of
such
information,
we
have
concerns
with
the
applicability
of
HAP
emission
control
technology
to
these
stationary
RICE.
As
a
result,
we
believe
it
is
appropriate
to
defer
a
decision
on
regulation
of
stationary
RICE
with
a
manufacturer's
nameplate
rating
of
500
brake
horsepower
or
less
until
further
information
on
the
engines
can
be
obtained
and
analyzed.
We
believe
this
subcategory
of
stationary
RICE
is
likely
to
be
more
similar
to
stationary
RICE
located
at
area
sources
than
to
stationary
RICE
located
at
major
sources.
Thus,
we
plan
to
include
this
subcategory
of
stationary
RICE
in
our
considerations
to
develop
regulations
for
stationary
RICE
located
at
area
sources.
E.
Why
Does
the
Proposed
Rule
Not
Apply
to
Stationary
RICE
Located
at
Area
Sources?
The
proposed
rule
does
not
apply
to
stationary
RICE
located
at
area
sources.
In
developing
our
Urban
Air
Toxics
Strategy
(
64
FR
38706,
July
19,
1999),
we
identified
stationary
RICE
at
area
sources
as
a
category
which
would
be
subject
to
standards
to
protect
the
environment
and
the
public
health
and
satisfy
the
statutory
requirements
in
section
112
of
the
CAA
pertaining
to
area
sources.
We
are
not
setting
standards
at
this
time,
because
of
insufficient
information
regarding
the
operating
characteristics
and
the
emissions,
the
current
use
of,
as
well
as
the
applicability
of,
emission
control
technologies
to
stationary
RICE
at
area
sources,
the
costs
of
emission
control
for
such
stationary
RICE,
and
the
economic
impacts
and
benefits
associated
with
regulation
of
the
stationary
RICE.
F.
How
Did
We
Select
the
Format
of
the
Standards?
1.
CO
Percent
Reduction
Standard
We
are
proposing
a
CO
percent
reduction
standard
if
you
use
an
oxidation
catalyst
to
reduce
HAP
emissions
from
new
or
reconstructed
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE.
A
control
efficiency
for
CO
was
chosen
because
CO
control
is
a
surrogate
for
HAP
control
for
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE,
and
because
it
is
easier
to
monitor
CO
than
several
HAP.
2.
Formaldehyde
Percent
Reduction
Standard
We
are
proposing
a
formaldehyde
percent
reduction
standard
if
you
use
NSCR
to
reduce
HAP
emissions
from
existing,
new,
and
reconstructed
4SRB
stationary
RICE.
A
control
efficiency
for
formaldehyde
was
chosen
because
formaldehyde
control
is
a
surrogate
for
HAP
control
for
4SRB
stationary
RICE,
and
because
a
good
relationship
was
not
found
between
CO
emissions
reductions
and
HAP
emissions
reductions
for
4SRB
stationary
RICE.
3.
Formaldehyde
Concentration
Limit
We
are
also
proposing
alternative
emission
limitations
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
for
new
2SLB,
4SLB,
and
CI
engines
not
using
oxidation
catalyst
control
systems
and
for
existing
and
new
4SRB
engines
not
using
NSCR
control
systems.
If
you
own
or
operate
a
2SLB
or
4SLB
stationary
RICE
or
a
CI
stationary
RICE
using
an
oxidation
catalyst,
you
must
comply
with
the
CO
percentage
emission
limitation.
If
you
use
some
means
other
than
an
oxidation
catalyst,
you
must
comply
with
the
alternative
emission
limitation
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust.
If
you
own
or
operate
a
4SRB
stationary
RICE
using
NSCR,
you
must
comply
with
the
formaldehyde
percentage
emission
limitation.
If
you
use
some
means
other
than
NSCR,
you
must
comply
with
the
alternative
emission
limitation
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust.
As
mentioned
earlier,
we
know
of
no
other
emission
control
technology
other
than
oxidation
catalyst
and
NSCR
systems
which
can
be
used
to
reduce
HAP
emissions
from
stationary
RICE.
However,
we
would
like
to
promote
the
development
and
eventual
use
of
alternative
emission
control
technologies
to
reduce
HAP
emissions,
and
we
believe
alternative
emission
limitations
written
as
formaldehyde
concentration
limits
will
serve
to
do
so.
For
the
alternative
emission
limitation,
we
propose
to
use
formaldehyde
concentration
as
a
surrogate
for
all
HAP.
Formaldehyde
is
the
hazardous
air
pollutant
emitted
in
the
highest
concentrations
from
stationary
RICE.
In
addition,
the
emission
data
show
that
formaldehyde
emission
levels
and
other
HAP
emission
levels
are
related,
in
the
sense
that
when
emissions
of
one
are
lowered,
emissions
of
the
other
are
lowered.
That
leads
us
to
conclude
that
emission
control
technologies
which
lead
to
reductions
in
formaldehyde
emissions
will
lead
to
reductions
in
other
HAP
emissions.
The
alternative
emission
limitation
is
in
units
of
parts
per
billion
by
volume
or
parts
per
million
by
volume,
and
all
measurements
are
corrected
to
15
percent
oxygen,
dry
basis,
to
provide
a
common
basis.
A
volume
concentration
was
chosen
for
these
emission
limitations
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
because
it
can
be
measured
directly.
We
utilized
the
same
data
used
to
establish
the
percent
reduction
requirements
to
determine
the
alternative
emission
limitation
for
each
subcategory.
As
with
the
control
efficiencies
discussed
previously,
the
concentrations
for
the
formaldehyde
emission
limitations
are
based
on
the
minimum
level
of
control
achieved
by
the
best
controlled
source
for
each
type
of
engine.
This
approach
takes
into
account
the
variability
of
the
best
performing
engine.
For
the
2SLB
engine
tested
at
CSU,
the
controlled
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Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
formaldehyde
emissions
ranged
from
7.5
parts
per
million
(
ppm)
to
17
ppm;
therefore,
we
selected
17
ppm
for
the
emission
limitation.
The
controlled
formaldehyde
emissions
for
the
4SLB
engine
tested
at
CSU
ranged
from
6.4
ppm
to
14
ppm.
We
chose
the
highest
controlled
level
of
14
ppm
for
the
alternative
standard
for
the
4SLB
subcategory.
Similarly,
for
the
CI
engine
tested
at
CSU,
the
controlled
formaldehyde
emissions
ranged
from
130
to
580
parts
per
billion
(
ppb),
and
we,
therefore,
set
an
emission
limitation
of
580
ppb
for
the
CI
subcategory.
For
4SRB
engines,
we
chose
the
best
performing
engine
from
the
industry
testing.
The
controlled
formaldehyde
emissions
for
this
engine
ranged
from
330
to
350
ppb.
In
summary,
the
alternative
emission
limitations
are:
17
ppmvd
for
2SLB
stationary
RICE;
14
ppmvd
for
4SLB
stationary
RICE;
350
ppbvd
for
4SRB
stationary
RICE;
and
580
ppbvd
for
CI
stationary
RICE,
all
corrected
to
15
percent
oxygen.
G.
How
Did
We
Select
the
Initial
Compliance
Requirements?
The
tests
which
formed
the
basis
of
the
proposed
emission
limitations
were
conducted
following
EPA
or
CARB
test
methods.
The
proposed
rule
requires
the
use
of
EPA
or
CARB
test
methods
to
determine
compliance.
This
ensures
that
the
same
analytical
methods
that
were
followed
to
collect
the
emission
data
upon
which
the
emission
limitations
are
based
will
be
followed
for
compliance
testing.
By
using
the
same
methods,
we
eliminate
the
possibility
of
measurement
bias
influencing
determinations
of
compliance.
In
an
effort
to
identify
the
most
feasible
testing
and
compliance
requirements
for
stationary
RICE,
we
considered
the
applicability
of
several
compliance
and
monitoring
options.
The
results
of
these
considerations
lead
us
to
propose
different
compliance
and
monitoring
requirements
for
stationary
RICE
with
manufacturer's
nameplate
ratings
less
than
5000
brake
horsepower,
and
stationary
RICE
with
manufacturer's
nameplate
ratings
greater
than
or
equal
to
5000
brake
horsepower.
We
selected
less
burdensome
compliance
requirements
for
smaller
size
stationary
RICE
considering
the
ratio
of
total
control
and
monitoring
costs
to
the
equipment
cost.
For
smaller
size
stationary
RICE,
we
considered
the
ratio
excessive.
For
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
manufacturer's
nameplate
ratings
less
than
5000
brake
horsepower
complying
with
the
requirement
to
reduce
CO
emissions
using
an
oxidation
catalyst,
we
decided
to
require
an
initial
performance
test
for
CO.
The
purpose
of
the
initial
performance
test
is
to
demonstrate
initial
compliance
with
the
CO
percent
reduction
emission
limitation;
to
establish
the
initial
pressure
drop
across
the
catalyst,
which
will
serve
as
the
reference
point
for
continuous
monitoring
of
the
pressure
drop
across
the
catalyst;
and
also
to
demonstrate
that
the
catalyst
inlet
temperature
is
within
the
specified
operating
limitations.
For
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
manufacturer's
nameplate
ratings
greater
than
or
equal
to
5000
brake
horsepower
complying
with
the
requirement
to
reduce
CO
emissions
using
an
oxidation
catalyst,
an
initial
performance
evaluation
is
required
to
validate
the
performance
of
the
CEMS
for
continuous
monitoring
of
CO
emissions.
Initial
compliance
with
the
CO
emission
limitation
must
then
be
demonstrated
by
using
CO
emission
measurements
from
the
first
4
hour
period
following
a
successful
performance
evaluation
of
the
CO
CEMS.
For
all
4SRB
stationary
RICE
complying
with
the
requirement
to
reduce
formaldehyde
emissions
by
75
percent
using
NSCR,
an
initial
performance
test
is
required.
The
purpose
of
the
initial
performance
test
is
to
demonstrate
compliance
with
the
formaldehyde
percent
reduction
emission
limitation
and
to
establish
the
initial
values
of
the
operating
parameters
that
will
be
continuously
monitored
(
i.
e.,
pressure
drop
across
the
catalyst,
the
catalyst
inlet
temperature
and
the
initial
temperature
rise
across
the
catalyst).
For
all
stationary
RICE
complying
with
the
requirement
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust,
an
initial
performance
test
is
required.
The
purpose
of
the
initial
performance
test
is
to
demonstrate
initial
compliance
with
the
formaldehyde
concentration
limit
and
also
to
establish
the
values
of
the
operating
limitations
(
i.
e.,
either
operating
load
or
fuel
flow
rate
and
any
other
parameters
which
are
approved
by
the
Administrator
as
operating
limitations),
which
will
be
continuously
monitored.
H.
How
Did
We
Select
the
Continuous
Compliance
Requirements?
Continuous
compliance
is
required
at
all
times
except
during
startup,
shutdown,
and
malfunction
of
your
stationary
RICE.
As
mentioned
above,
we
considered
the
applicability
of
several
compliance
and
monitoring
options
for
stationary
RICE.
The
results
of
these
considerations
lead
us
to
propose
different
compliance
and
monitoring
requirements
for
stationary
RICE
with
manufacturer's
nameplate
ratings
less
than
5000
brake
horsepower
and
stationary
RICE
with
manufacturer's
nameplate
ratings
greater
than
or
equal
to
5000
brake
horsepower.
For
2SLB
and
4SLB
stationary
RICE
and
CI
RICE
with
manufacturer's
nameplate
ratings
less
than
5000
brake
horsepower
complying
with
the
requirement
to
reduce
CO
emissions
using
an
oxidation
catalyst,
we
considered
several
options:
(
1)
A
CEMS
for
CO;
(
2)
semiannual
stack
testing
for
CO
using
Method
10A
of
40
CFR
part
60,
appendix
A,
and
continuous
parametric
monitoring
of
the
pressure
drop
across
the
catalyst
and
the
catalyst
inlet
temperature;
(
3)
quarterly
stack
testing
with
a
portable
CO
monitor
using
American
Society
for
Testing
and
Materials
(
ASTM)
D6522
00,
and
continuous
parametric
monitoring
of
the
pressure
drop
across
the
catalyst
and
the
catalyst
inlet
temperature;
and
(
4)
initial
stack
testing
for
CO
with
a
portable
CO
monitor
using
ASTM
D6522
00
and
continuous
parametric
monitoring
of
the
pressure
drop
across
the
catalyst
and
the
catalyst
inlet
temperature.
We
consider
the
control
and
monitoring
costs
for
the
first
two
options
excessive,
but
consider
the
control
and
monitoring
costs
associated
with
the
third
option
reasonable.
As
a
result,
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
a
manufacturer's
nameplate
ratings
less
than
5000
brake
horsepower
complying
with
the
CO
percent
reduction
emission
limitation
must
perform
quarterly
stack
testing
for
CO
using
a
portable
CO
monitor.
The
quarterly
testing
will
ensure,
on
an
ongoing
basis,
that
the
source
is
meeting
the
CO
percent
reduction
requirement.
In
addition
to
quarterly
stack
testing
for
CO,
the
stationary
RICE
are
required
to
continuously
monitor
pressure
drop
across
the
catalyst
and
catalyst
inlet
temperature.
The
parameters
serve
as
surrogates
of
the
oxidation
catalyst
performance.
The
pressure
drop
across
the
catalyst
can
indicate
if
the
oxidation
catalyst
is
damaged
or
fouled,
in
which
case,
catalyst
performance
would
decrease.
If
the
pressure
drop
across
the
catalyst
deviates
by
more
than
two
inches
of
water
from
the
pressure
drop
across
the
catalyst
measured
during
the
initial
performance
test,
the
oxidation
catalyst
might
be
damaged
or
fouled.
If
you
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19,
2002
/
Proposed
Rules
change
the
oxidation
catalyst
(
i.
e.,
replace
catalyst
elements),
you
must
reestablish
the
pressure
drop
across
the
catalyst.
The
catalyst
inlet
temperature
is
a
requirement
for
proper
performance
of
the
oxidation
catalyst.
In
general,
the
oxidation
catalyst
performance
will
decrease
as
the
catalyst
inlet
temperature
decreases.
In
addition,
if
the
catalyst
inlet
temperature
is
too
high
(
above
1,250
degrees
Fahrenheit),
it
might
be
an
indication
of
ignition
misfiring,
poisoning,
or
fouling,
which
would
decrease
oxidation
catalyst
performance.
In
addition,
the
oxidation
catalyst
requires
inlet
temperatures
to
be
greater
than
or
equal
to
500
degrees
Fahrenheit
for
the
reduction
of
HAP
emissions.
For
2SLB
and
4SLB
stationary
RICE
and
CI
RICE
with
a
manufacturer's
nameplate
rating
greater
than
or
equal
to
5000
brake
horsepower
complying
with
the
requirement
to
reduce
CO
emissions
using
an
oxidation
catalyst,
we
considered
the
same
four
monitoring
options.
For
these
larger
size
stationary
RICE,
however,
we
consider
the
control
and
monitoring
costs
for
a
CO
CEMS
reasonable.
We
consider
the
use
of
CEMS
to
be
the
best
means
of
ensuring
continuous
compliance
with
emission
limitations.
Consequently,
the
large
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
are
required
to
use
a
CO
CEMS.
An
annual
RATA
and
daily
and
periodic
data
quality
checks
in
accordance
with
40
CFR
part
60,
appendix
F,
procedure
1,
are
also
required
to
ensure
that
performance
of
the
CEMS
does
not
deteriorate
over
time.
There
are
no
operating
limitations
for
the
larger
size
stationary
RICE
in
the
subcategories
since
the
CEMS
continuously
measures
CO
and
will
indicate
any
deviation
from
the
emission
limitations.
For
4SRB
stationary
RICE
complying
with
the
requirement
to
reduce
formaldehyde
emissions
using
NSCR,
we
also
considered
three
monitoring
options:
(
1)
A
CEMS
for
formaldehyde;
(
2)
stack
testing
for
formaldehyde
using
Test
Method
320
or
323
of
40
CFR
part
60,
appendix
A,
CARB
Method
430,
or
EPA
SW
846
Method
0011
with
an
initial
frequency
of
semiannually
which,
following
two
consecutive
stack
tests
demonstrating
compliance,
could
decrease
to
annual
stack
testing
and
continuous
parametric
monitoring;
and
(
3)
initial
stack
testing
for
formaldehyde
using
Test
Method
320
or
323
of
40
CFR
part
60,
appendix
A,
CARB
Method
430,
or
EPA
SW
846
Method
0011
and
continuous
parametric
monitoring.
We
consider
the
control
and
monitoring
costs
associated
with
the
first
option
excessive
for
all
4SRB
stationary
RICE
complying
with
the
requirement
to
reduce
formaldehyde
emissions
using
NSCR.
For
4SRB
stationary
RICE
with
a
manufacturer's
nameplate
rating
of
more
than
5000
brake
horsepower,
we
consider
the
control
and
monitoring
costs
of
the
second
option
reasonable.
Consequently,
we
chose
that
option
for
the
larger
size
4SRB
stationary
RICE.
For
4SRB
stationary
RICE
with
a
manufacturer's
nameplate
ratings
less
than
5000
brake
horsepower,
we
also
consider
the
control
and
monitoring
costs
of
the
second
option
excessive.
We
consider
the
control
and
monitoring
costs
of
the
third
option
reasonable,
and
we
chose
that
option
for
the
smaller
4SRB
stationary
RICE.
For
all
4SRB
stationary
RICE
complying
with
the
requirement
to
reduce
formaldehyde
emissions
using
NSCR,
monitoring
the
pressure
drop
across
the
catalyst,
the
catalyst
inlet
temperature
and
the
temperature
rise
across
the
catalyst
with
a
CPMS
is
also
required.
The
operating
parameters
serve
as
surrogates
of
the
NSCR
system
performance.
As
with
oxidation
catalyst
systems
for
lean
burn
and
CI
stationary
RICE,
the
pressure
drop
across
an
NSCR
system
is
an
indication
of
catalyst
performance
on
4SRB
stationary
RICE.
The
operating
limitations
are
also
the
same
maintain
the
pressure
drop
across
the
catalyst
within
two
inches
of
water
from
the
pressure
drop
measured
during
the
initial
performance
test.
If
you
change
your
NSCR
(
i.
e.,
replace
catalyst
elements),
you
must
reestablish
your
pressure
drop
across
the
catalyst,
the
catalyst
inlet
temperature
and
the
temperature
rise
across
the
catalyst.
As
for
oxidation
catalyst
control
devices,
the
performance
of
NSCR
is
also
dependent
on
catalyst
inlet
temperature.
Catalyst
inlet
temperature
should
be
maintained
between
750
degrees
Fahrenheit
and
1250
degrees
Fahrenheit
for
proper
activation
of
the
catalyst.
Temperatures
lower
than
that
fail
to
activate
the
catalyst
to
its
full
potential,
while
temperatures
higher
than
that
can
sinter
and
damage
the
active
sites
of
the
catalyst.
In
addition,
the
temperature
rise
across
the
catalyst
is
also
an
indication
of
NSCR
performance.
If
the
temperature
rise
across
the
catalyst
is
more
than
5
percent
different
from
the
temperature
rise
across
the
catalyst
measured
during
the
initial
performance
test,
that
might
be
an
indication
that
the
NSCR
is
being
damaged
or
fouled.
In
that
case,
catalyst
performance
would
decrease,
lowering
HAP
reductions.
For
stationary
RICE
complying
with
the
requirement
to
limit
the
concentration
of
formaldehyde
in
the
exhaust
of
the
stationary
RICE,
we
also
considered
requiring
a
CEMS.
However,
we
consider
the
costs
of
a
formaldehyde
CEMS
to
be
excessive.
A
reasonable
alternative
to
a
formaldehyde
CEMS,
however,
is
a
CPMS
(
supplemented
by
periodic
compliance
tests).
Hazardous
air
pollutant
emissions
from
stationary
RICE
correlate
with
operating
load;
HAP
emissions
increase
as
load
decreases.
As
a
result,
if
a
stationary
RICE
operates
at
loads
greater
than
that
at
which
compliance
has
been
demonstrated
through
a
performance
test,
there
is
a
reasonable
assurance
that
the
stationary
RICE
remains
in
compliance.
An
alternative
to
monitoring
operating
load
is
monitoring
the
stationary
RICE's
fuel
flow
rate.
Fuel
flow
rate
is
an
indicator
of
operating
load.
As
a
result,
we
propose
that
stationary
RICE
which
comply
with
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
monitor
continuously
operating
load
or
fuel
flow
rate
as
operating
limitations.
The
intention
is
to
measure
formaldehyde
at
the
lowest
load
at
which
the
stationary
RICE
will
be
operated
to
establish
compliance
at
that
load
level.
By
monitoring
operating
load
or
fuel
flow
rate,
sources
can
ensure
that
they
do
not
operate
at
load
or
fuel
flow
rate
conditions
(
within
5
percent)
below
which
compliance
has
not
been
demonstrated.
In
addition,
sources
complying
with
the
requirement
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
are
required
to
conduct
semiannual
performance
tests.
Semiannual
performance
testing
will
ensure,
on
an
ongoing
basis,
that
the
source
is
meeting
the
formaldehyde
concentration
limit.
To
reduce
the
cost
burden
of
performance
testing,
sources
that
show
compliance
for
two
successive
performance
tests
may
reduce
performance
testing
frequency.
We
believe
that
a
reduction
to
one
performance
test
per
year
will
provide
sufficient
assurance
of
stationary
RICE
performance
while
reducing
the
performance
testing
costs
for
the
affected
source.
However,
if
a
subsequent
annual
performance
test
indicates
a
deviation
from
the
formaldehyde
concentration
limit,
the
source
must
resume
semiannual
performance
testing.
The
source
must
include
a
notification
to
the
Administrator
in
their
semiannual
compliance
report
stating
that
they
will
be
reducing
the
frequency
of
performance
testing.
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/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
I.
What
Monitoring
and
Testing
Methods
are
Available
to
Measure
These
Low
Concentrations
of
CO
and
Formaldehyde?
We
believe
CEMS
are
available
which
can
measure
CO
emissions
at
the
low
concentrations
found
in
the
exhaust
from
a
stationary
RICE
following
an
oxidation
catalyst
control
system.
Our
PS
4
and
4A
for
CO
CEMS
of
40
CFR
part
60,
appendix
B,
however,
have
not
been
updated
recently
and
do
not
reflect
the
performance
capabilities
of
such
systems
at
these
low
CO
concentration
levels.
As
a
result,
we
solicit
comments
on
the
performance
capabilities
of
state
ofthe
art
CO
CEMS
and
their
ability
to
accurately
measure
the
low
concentrations
of
CO
experienced
in
the
exhaust
of
a
stationary
RICE
following
an
oxidation
catalyst
control
system.
We
also
solicit
comments
with
specific
recommendations
on
the
changes
we
should
make
to
our
PS
4
and
4A
for
CO
CEMS
of
40
CFR
part
60,
appendix
B,
to
ensure
the
installation
and
use
of
CEMS
which
can
be
used
to
determine
compliance
with
the
proposed
emission
limitation
for
CO
emissions.
In
addition,
we
solicit
comments
on
the
availability
of
instruments
capable
of
meeting
the
changes
they
recommend
to
our
performance
specifications
for
CO
CEMS.
The
proposed
rule
specifies
the
use
of
Method
10
of
40
CFR
part
60,
appendix
A,
as
the
reference
method
to
certify
the
performance
of
the
CO
CEMS.
We
also
believe
Method
10
of
40
CFR
part
60,
appendix
A,
is
capable
of
measuring
CO
concentrations
as
low
as
those
experienced
in
the
exhaust
of
a
stationary
RICE
following
an
oxidation
catalyst
control
system.
However,
the
performance
criteria
in
addenda
A
of
Method
10
of
40
CFR
part
60,
appendix
A,
have
not
been
revised
recently
and
are
not
suitable
for
certifying
the
performance
of
a
CO
CEMS
at
the
low
CO
concentrations.
Specifically,
we
believe
the
range
and
minimum
detectable
sensitivity
should
be
changed
to
reflect
target
concentrations
as
low
as
5
ppm
CO
in
some
cases.
We
also
expect
that
dual
range
instruments
will
be
necessary
to
measure
CO
concentrations
at
the
inlet
and
at
the
outlet
of
an
oxidation
catalyst
emission
control
device.
As
a
result,
we
solicit
comments
with
specific
recommendations
on
the
changes
we
should
make
to
Method
10
of
40
CFR
part
60,
appendix
A,
and
the
performance
criteria
in
addenda
A.
We
also
solicit
comments
on
the
availability
of
instruments
capable
of
meeting
the
changes
they
recommend
to
Method
10
of
40
CFR
part
60,
appendix
A,
and
the
performance
criteria
in
addenda
A,
while
also
meeting
the
remaining
addenda
A
performance
criteria.
With
regard
to
formaldehyde,
we
believe
systems
meeting
the
requirements
of
Method
320
of
40
CFR
part
63,
appendix
A,
a
self
validating
FTIR
method,
can
be
used
to
attain
detection
limits
for
formaldehyde
concentrations
below
350
ppbvd.
Method
320
of
40
CFR
part
60,
appendix
A,
also
includes
formaldehyde
spike
recovery
criteria
which
require
spike
recoveries
of
70
to
130
percent.
While
we
believe
FTIR
systems
can
meet
Method
320
of
40
CFR
part
63,
appendix
A,
and
measure
formaldehyde
concentrations
at
the
low
levels,
we
have
limited
experience
with
their
use.
As
a
result,
we
solicit
comments
on
the
ability
and
use
of
FTIR
systems
to
meet
the
validation
and
quality
assurance
requirements
of
Method
320
of
40
CFR
part
63,
appendix
A,
for
the
purpose
of
determining
compliance
with
the
emission
limitation
for
formaldehyde
emissions.
We
also
believe
EPA
Method
323
of
40
CFR
part
63,
appendix
A
and
CARB
Method
430
are
capable
of
measuring
formaldehyde
concentrations
at
the
low
levels
from
4SRB
engines.
Accordingly,
we
solicit
comments
on
the
use
of
EPA
Method
323,
CARB
430,
and
EPA
SW
846
Method
0011
to
determine
compliance
with
the
emission
limitations
for
formaldehyde
for
4SRB
engines.
Based
on
the
comments
we
receive
on
CO
CEMS,
we
anticipate
revising
Method
10
of
40
CFR
part
60,
appendix
A,
and
our
PS
4
and
4A
of
40
CFR
part
60,
appendix
B,
for
CO
CEMS
to
ensure
the
installation
and
use
of
CEMS
suitable
for
determining
compliance
with
the
emission
limitation
for
CO
emissions.
Similarly,
based
on
the
comments
we
receive
on
FTIR
systems
and
Method
320
of
40
CFR
part
63,
appendix
A,
we
may
develop
additional
or
revised
criteria
for
the
use
of
FTIR
systems
and/
or
Method
320
of
40
CFR
part
63,
appendix
A,
to
determine
compliance
with
the
emission
limitation
for
formaldehyde.
On
the
other
hand,
if
the
comments
we
receive
lead
us
to
conclude
that
CO
CEMS
are
not
capable
of
being
used
to
determine
compliance
with
the
emission
limitation
for
CO
emissions,
there
are
several
alternatives
we
may
consider.
One
alternative
would
be
to
delete
the
proposed
percent
reduction
emission
limitation
for
CO
and
require
compliance
with
a
comparable
formaldehyde
percent
reduction
limitation.
That
alternative
would
require
periodic
stack
emission
testing
before
and
after
the
control
device
and
would
also
require
owners
and
operators
to
petition
the
Administrator
for
additional
operating
limitations
as
proposed
for
those
choosing
to
comply
with
the
emission
limitation
for
formaldehyde.
Another
alternative
would
be
to
delete
the
proposed
emission
limitation
for
CO
emissions
and
require
compliance
with
the
proposed
emission
limitation
for
formaldehyde.
That
alternative
could
also
require
more
frequent
emission
testing
and
could
also
require
owners
and
operators
to
petition
the
Administrator
for
additional
operating
limitations.
Another
alternative
would
be
to
require
the
use
of
Method
320
of
40
CFR
part
60,
appendix
A,
(
i.
e.,
FTIR
systems)
to
determine
compliance
with
the
emission
limitation
for
CO
emissions.
That
alternative
could
also
require
more
frequent
emission
testing
and
require
owners
and
operators
to
petition
the
Administrator
for
additional
operating
limitations,
as
proposed
for
those
choosing
to
comply
with
the
emission
limitation
for
formaldehyde.
Yet
another
alternative
would
be
to
delete
the
emission
limitations
for
both
CO
emissions
and
formaldehyde
emissions
and
adopt
an
emission
limitation
consisting
of
an
equipment
and
work
practice
requirement.
That
alternative
would
require
the
use
of
oxidation
catalyst
control
systems
for
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE,
and
NSCR
systems
for
4SRB
stationary
RICE
which
meet
specific
and
narrow
design
and
operating
criteria.
We
believe
the
emission
limitations
we
are
proposing
for
CO
emissions
and
formaldehyde
emissions
are
superior
to
these
alternatives
for
a
number
of
reasons.
However,
we
solicit
comments
on
the
alternatives
should
we
conclude
that
the
proposed
emission
limitations
for
CO
emissions
and
formaldehyde
emissions
are
inappropriate
because
of
difficulties
in
monitoring
or
measuring
CO
emissions
or
formaldehyde
emissions
to
determine
compliance.
We
also
solicit
suggestions
and
recommendations
for
other
alternatives
should
we
conclude
the
proposed
emission
limitations
are
inappropriate
because
of
monitoring
or
measurement
difficulties.
J.
How
Did
We
Select
the
Notification,
Recordkeeping
and
Reporting
Requirements?
The
proposed
notification,
recordkeeping,
and
reporting
requirements
are
based
on
the
NESHAP
General
Provisions
of
40
CFR
part
63.
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244
/
Thursday,
December
19,
2002
/
Proposed
Rules
IV.
Summary
of
Environmental,
Energy
and
Economic
Impacts
A.
What
Are
the
Air
Quality
Impacts?
The
proposed
rule
will
reduce
total
HAP
emissions
from
stationary
RICE
by
an
estimated
5,000
tons/
year
in
the
5th
year
after
the
standards
are
implemented.
We
believe
approximately
1,800
existing
4SRB
stationary
RICE
will
be
affected
by
the
proposed
rule.
In
addition,
we
believe
that
approximately
1,600
new
2SLB,
4SLB
and
4SRB
stationary
RICE,
and
CI
stationary
RICE
will
be
affected
by
the
proposed
rule
each
year
for
the
next
5
years.
At
the
end
of
the
5th
year,
it
is
estimated
that
8,100
new
stationary
RICE
will
be
subject
to
the
proposed
rule.
To
estimate
air
impacts,
HAP
emissions
from
stationary
RICE
were
estimated
using
average
emission
factors
from
the
emissions
database.
It
was
also
assumed
that
each
stationary
RICE
is
operated
for
6,500
hours
annually.
The
total
national
HAP
emissions
reductions
are
the
sum
of
formaldehyde,
acetaldehyde,
acrolein,
and
methanol
emissions
reductions.
In
addition
to
HAP
emissions
reductions,
the
proposed
rule
will
reduce
criteria
pollutant
emissions,
including
CO,
VOC,
NOX,
and
particulate
matter
(
PM).
The
application
of
NSCR
controls
to
4SRB
engines
(
the
technology
on
which
MACT
for
4SRB
engines
is
based)
will
also
reduce
NOX
emissions
by
90
percent.
It
is
possible
that
oxidation
catalyst
controls
could
be
used
to
meet
the
4SRB
emission
standards,
but
it
is
expected
that
the
costs
of
controls
will
be
similar
for
both
systems.
Assuming
that
60
percent
of
the
4SRB
(
new
and
existing)
engines
that
are
covered
by
the
emission
standards
will
use
NSCR,
the
cumulative
emissions
reductions
of
NOX
by
the
end
of
the
5th
year
after
promulgation
are
calculated
to
be
about
167,900
tons
per
year.
We
are
specifically
soliciting
comments
on
the
percentage
of
4SRB
engines
that
would
choose
to
install
NSCR
HAP
controls
rather
than
other
HAP
controls.
B.
What
Are
the
Cost
Impacts?
A
list
of
26
model
stationary
RICE
was
developed
to
represent
the
range
of
existing
stationary
RICE.
Information
was
obtained
from
catalyst
vendors
on
equipment
costs
for
oxidation
catalyst
and
NSCR.
This
information
was
then
used
to
estimate
the
costs
of
the
proposed
rule
for
each
model
stationary
RICE
following
methodologies
from
the
Office
of
Air
Quality
Planning
and
Standards
(
OAQPS)
Control
Cost
Manual.
These
cost
estimates
for
model
stationary
RICE
were
extrapolated
to
the
national
population
of
stationary
RICE
in
the
United
States,
and
national
impacts
were
determined.
The
total
national
capital
cost
for
the
proposed
rule
for
existing
stationary
RICE
is
estimated
to
be
approximately
$
68
million,
with
a
total
national
annual
cost
of
$
38
million
in
the
5th
year.
The
total
national
capital
cost
for
the
proposed
rule
for
new
stationary
RICE
by
the
5th
year
is
estimated
to
be
approximately
$
372
million,
with
a
total
national
annual
cost
of
$
216
million
in
the
5th
year.
C.
What
Are
the
Economic
Impacts?
We
prepared
an
economic
impact
analysis
to
evaluate
the
primary
and
secondary
impacts
the
proposed
rule
would
have
on
the
producers
and
consumers
of
RICE,
and
society
as
a
whole.
The
affected
engines
operate
in
over
30
different
manufacturing
markets,
but
a
large
portion
are
located
in
the
oil
and
gas
exploration
industry,
the
oil
and
gas
pipeline
(
transmission)
industry,
the
mining
and
quarrying
of
non
metallic
minerals
industry,
the
chemicals
and
allied
products
industry,
and
the
electricity
and
gas
services
industry.
Taken
together,
these
industries
can
have
an
influence
on
the
price
and
demand
for
fuels
used
in
the
energy
market
(
i.
e.,
petroleum,
natural
gas,
electricity,
and
coal).
Therefore,
our
analysis
evaluates
the
impacts
on
each
of
the
30
different
manufacturing
markets
affected
by
the
proposed
rule,
as
well
as
the
combined
effect
on
the
market
for
energy.
The
total
annualized
social
cost
(
in
1998
dollars)
of
the
proposed
rule
is
$
254
million
but
this
cost
is
spread
across
all
30
markets
and
the
fuel
markets.
Overall,
our
analysis
indicates
a
minimal
change
in
prices
and
quantity
produced
in
most
of
the
fuel
markets.
The
distribution
of
impacts
on
the
fuel
markets
and
the
specific
manufacturing
market
segments
evaluated
are
summarized
in
Table
1
of
this
preamble.
TABLE
1.
ECONOMIC
IMPACT
OF
PROPOSED
RICE
RULE
ON
AFFECTED
MARKET
SECTORS
Market
sector
Change
in
price
(%)
Change
in
market
output
(%)
Total
social
cost
(
millions
of
1998$)
Fuel
Markets:
a
Petroleum
.............................................................................................................................
0.005
¥
0.001
¥
6.0
Natural
Gas
..........................................................................................................................
0.101
¥
0.014
¥
35.2
Electricity
..............................................................................................................................
0.022
0.001
3.2
Coal
......................................................................................................................................
0.001
0.001
0.3
Subtotal
.........................................................................................................................
........................
........................
¥
38.3
Sectors
of
Energy
Consumption:
b
Commercial
Sector
...............................................................................................................
........................
........................
¥
68.4
Residential
Sector
................................................................................................................
........................
........................
¥
40.0
Transportation
Sector
...........................................................................................................
........................
........................
¥
16.2
Mining
and
Quarrying
..................................................................................................................
0.020
¥
0.006
¥
21.0
Food
Products
.............................................................................................................................
0.001
¥
0.001
¥
5.9
Paper
Products
............................................................................................................................
0.001
¥
0.001
¥
5.2
Chemical
Products
.......................................................................................................................
0.001
¥
0.002
¥
17.8
Primary
Metals
.............................................................................................................................
0.001
¥
0.001
¥
6.7
Fabricated
Metal
Products
...........................................................................................................
0.001
¥
0.000
¥
1.8
Nonmetallic
Mineral
Products
......................................................................................................
0.002
¥
0.002
¥
3.5
Construction
Sector
.....................................................................................................................
0.001
¥
0.001
¥
11.1
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Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
TABLE
1.
ECONOMIC
IMPACT
OF
PROPOSED
RICE
RULE
ON
AFFECTED
MARKET
SECTORS
Continued
Market
sector
Change
in
price
(%)
Change
in
market
output
(%)
Total
social
cost
(
millions
of
1998$)
Other
Manufacturing
Markets
......................................................................................................
0.000
0.0
0.001
¥
17.7
a
Only
changes
in
producer
surplus
(
i.
e.,
producer's
share
of
regulatory
costs)
are
reported
for
the
Fuel
Markets
which
represent
the
producers
of
energy.
Sectors
of
energy
consumption
commercial,
residential,
and
transportation
have
reported
changes
in
consumer
surplus
only,
and
thus
do
not
have
reported
changes
in
price
and
output.
A
combination
of
these
costs
will
represent
total
social
costs
for
the
energy
market
in
the
economy.
Because
the
engines
affected
by
the
proposed
rule
are
those
that
use
natural
gas
as
a
fuel
source,
it
is
not
surprising
to
see
the
natural
gas
fuel
market
with
the
largest
portion
of
the
social
costs.
Although
the
natural
gas
market
has
a
greater
share
of
the
regulatory
burden,
the
overall
impact
on
prices
is
about
one
tenth
of
1
percent,
which
is
considered
to
be
a
minor
economic
impact
on
this
industry.
The
change
in
the
price
of
natural
gas
is
not
expected
to
influence
the
purchase
decisions
for
new
engines.
Our
analysis
indicates
that
at
most,
less
than
5
fewer
engines
out
of
over
20,000
engines
will
be
purchased
as
a
result
of
economic
impacts
associated
with
the
proposed
rule.
The
electricity
and
coal
markets
may
experience
a
slight
gain
in
revenues
due
to
some
fuel
switching
from
natural
gas
to
coal
or
electricity.
The
total
social
welfare
loss
for
the
manufacturing
industries
affected
by
the
proposed
rule
is
estimated
to
be
approximately
$
39.9
million
for
consumers
and
$
44.7
million
for
producers
in
the
aggregate.
In
comparison
to
the
energy
expenditures
of
these
industries
(
estimated
to
be
$
101.2
billion),
the
cost
of
the
proposed
rule
to
producers
as
a
percentage
of
their
fuel
expenditures
is
0.04
percent.
For
consumers,
the
total
value
of
shipments
for
the
affected
industries
is
$
3.95
trillion
in
1998,
so
the
cost
to
consumers
as
a
percentage
of
spending
on
the
outputs
from
these
industries
is
nearly
zero,
or
0.001
percent.
The
cost
to
residential
consumers
at
$
40.0
million
is
larger
than
for
any
individual
manufacturing
market,
and
about
equivalent
to
the
aggregate
consumer
surplus
losses
in
the
manufacturing
industries.
In
comparison,
the
social
cost
burden
to
residential
consumers
of
fuel
is
0.03
percent
of
residential
energy
expenditures
($
40.0
million/$
131.06
billion).
The
commercial
sector
of
energy
users
also
experiences
a
moderate
portion
of
total
social
costs
at
an
estimated
$
29.3
million
and
represents
an
aggregate
across
all
commercial
North
American
Industrial
Classification
System
(
NAICS)
codes.
As
a
percentage
of
fuel
expenditures
by
this
sector
of
fuel
consumers,
the
regulatory
burden
is
0.03
percent
($
29.3
million/
$
96.86
billion).
The
cost
to
transportation
consumers
is
estimated
to
be
$
16.2
million.
This
cost
represents
0.008
percent
($
16.2
million/$
188.13
billion)
of
energy
expenditures
for
the
transportation
sector.
Therefore,
giving
consideration
to
the
minimal
changes
in
prices
and
output
in
nearly
all
markets,
and
the
fact
that
the
regulatory
costs
that
are
shared
by
commercial,
residential,
and
transportation
users
of
fuel
energy
are
a
small
fraction
of
typical
energy
expenditures
in
these
sectors
each
year,
we
conclude
that
the
economic
impacts
of
the
proposed
rule
will
not
be
significant
to
any
one
sector
of
the
economy.
D.
What
Are
the
Non
Air
Health,
Environmental
and
Energy
Impacts?
We
do
not
expect
any
significant
wastewater,
solid
waste,
or
energy
impacts
resulting
from
the
proposed
rule.
Energy
impacts
associated
with
the
proposed
rule
would
be
due
to
additional
energy
consumption
that
the
proposed
rule
would
require
by
installing
and
operating
control
equipment.
The
only
energy
requirement
for
the
operation
of
the
control
technologies
is
a
very
small
increase
in
fuel
consumption
resulting
from
back
pressure
caused
by
the
emission
control
system.
V.
Solicitation
of
Comments
and
Public
Participation
A.
General
We
are
requesting
comments
on
all
aspects
of
the
proposed
rule,
such
as
the
proposed
emission
limitations
and
operating
limitations,
recordkeeping
and
monitoring
requirements,
as
well
as
aspects
you
may
feel
have
not
been
addressed.
Specifically,
we
request
comments
on
the
performance
capabilities
of
state
ofthe
art
CO
CEMS
and
their
ability
to
measure
the
low
concentrations
of
CO
in
the
exhaust
of
a
stationary
RICE
following
an
oxidation
catalyst
control
system.
We
also
request
comments
with
recommendations
on
changes
we
should
make
to
our
PS
4
and
4A
for
CO
CEMS
of
40
CFR
part
60,
appendix
B,
and
to
Method
10
of
40
CFR
part
60,
appendix
A,
and
the
performance
criteria
in
addenda
A
to
Method
10.
In
addition,
we
request
comments
on
the
availability
of
instruments
capable
of
meeting
the
changes
they
recommend
to
our
performance
specifications
for
CO
CEMS,
Method
10
of
40
CFR
part
60,
appendix
A,
and
addenda
A
to
Method
10.
As
also
mentioned
earlier,
we
request
comments
on
the
ability
and
use
of
FTIR
systems
to
meet
the
validation
and
quality
assurance
requirements
of
Method
320
of
40
CFR
part
63,
appendix
A,
for
the
purpose
of
determining
compliance
with
the
emission
limitations
for
formaldehyde
emissions.
In
addition,
we
request
comments
on
the
use
of
CARB
430
to
determine
compliance
with
the
emission
limitations
for
formaldehyde.
In
addition,
we
request
any
HAP
emissions
test
data
available
from
stationary
RICE;
however,
if
you
submit
HAP
emissions
test
data,
please
submit
the
full
and
complete
emission
test
report
with
these
data.
Without
a
complete
emission
test
report,
which
includes
sections
describing
the
stationary
RICE
and
its
operation
during
the
test
as
well
as
identifying
the
stationary
RICE
for
purposes
of
verification,
discussion
of
the
test
methods
employed
and
the
quality
assurance/
quality
control
procedures
followed,
the
raw
data
sheets,
all
the
calculations,
etc.,
which
such
reports
contain,
submittal
of
HAP
emission
data
by
itself
is
of
little
use.
B.
Can
We
Achieve
the
Goals
of
the
Rule
in
a
Less
Costly
Manner?
We
have
made
every
effort
in
developing
the
proposal
to
minimize
the
cost
to
the
regulated
community
and
allow
maximum
flexibility
in
compliance
options
consistent
with
our
statutory
obligations.
We
recognize,
however,
that
the
proposal
may
still
require
some
facilities
to
take
costly
steps
to
further
control
emissions
even
though
those
emissions
may
not
result
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Vol.
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244
/
Thursday,
December
19,
2002
/
Proposed
Rules
1
See
63
FR
18765
66
(
April
15,
1998)
(
Pulp
and
Paper
Combustion
Sources
Proposed
NESHAP).
in
exposures
which
could
pose
an
excess
individual
lifetime
cancer
risk
greater
than
one
in
one
million
or
which
exceed
thresholds
determined
to
provide
an
ample
margin
of
safety
for
protecting
public
health
and
the
environment
from
the
effects
of
hazardous
air
pollutants.
We
are,
therefore,
specifically
soliciting
comment
on
whether
there
are
further
ways
to
structure
the
proposed
rule
to
focus
on
the
facilities
which
pose
significant
risks
and
avoid
the
imposition
of
high
costs
on
facilities
that
pose
little
risk
to
public
health
and
the
environment.
Representatives
of
the
plywood
and
composite
wood
products
industry
provided
EPA
with
descriptions
of
three
mechanisms
that
they
believed
could
be
used
to
implement
more
cost
effective
reductions
in
risk.
The
docket
for
the
proposed
rule
contains
white
papers
prepared
by
industry
that
outline
their
proposed
approaches
(
see
docket
number
OAR
2002
0059).
These
approaches
could
be
effective
in
focusing
regulatory
controls
on
facilities
that
pose
significant
risks
and
avoiding
the
imposition
of
high
costs
on
facilities
that
pose
little
risk
to
public
health
or
the
environment,
and
we
are
seeking
public
comment
on
the
utility
of
each
of
these
approaches
with
respect
to
the
proposed
rule.
One
of
the
approaches,
an
applicability
cutoff
for
threshold
pollutants,
would
be
implemented
under
the
authority
of
CAA
section
112(
d)(
4);
the
second
approach,
subcategorization
and
delisting,
would
be
implemented
under
the
authority
of
CAA
sections
112(
c)(
1)
and
112(
c)(
9);
and,
the
third
approach
would
involve
the
use
of
a
concentration
based
applicability
threshold.
We
are
seeking
comment
on
whether
these
approaches
are
legally
justified
and,
if
so,
we
ask
for
information
that
could
be
used
to
support
such
approaches.
The
MACT
program
outlined
in
CAA
section
112(
d)
is
intended
to
reduce
emissions
of
HAP
through
the
application
of
MACT
to
major
sources
of
toxic
air
pollutants.
Section
112(
c)(
9)
of
the
CAA
is
intended
to
allow
EPA
to
avoid
setting
MACT
standards
for
categories
or
subcategories
of
sources
that
pose
less
than
a
specified
level
of
risk
to
public
health
and
the
environment.
The
EPA
requests
comment
on
whether
the
proposals
described
here
appropriately
rely
on
these
provisions
of
CAA
section
112.
While
both
approaches
focus
on
assessing
the
inhalation
exposures
of
HAP
emitted
by
a
source,
EPA
specifically
requests
comment
on
the
appropriateness
and
necessity
of
extending
these
approaches
to
account
for
non
inhalation
exposures
or
to
account
for
adverse
environmental
impacts.
In
addition
to
the
specific
requests
for
comment
noted
in
this
section,
we
are
also
interested
in
any
information
or
comment
concerning
technical
limitations,
environmental
and
cost
impacts,
compliance
assurance,
legal
rationale,
and
implementation
relevant
to
the
identified
approaches.
We
also
request
comment
on
appropriate
practicable
and
verifiable
methods
to
ensure
that
sources'
emissions
remain
below
levels
that
protect
public
health
and
the
environment.
We
will
evaluate
all
comments
before
determining
whether
either
of
the
three
approaches
will
be
included
in
the
final
rule.
1.
Industry
Emissions
and
Potential
Health
Effects
For
the
RICE
source
category,
four
HAP
make
up
the
majority
of
the
total
HAP.
Those
four
HAP
are
methanol,
formaldehyde,
acetaldehyde,
and
acrolein.
In
accordance
with
section
112(
k)
of
the
CAA,
EPA
developed
a
list
of
33
HAP
which
represent
the
greatest
threat
to
public
health
in
the
largest
number
of
urban
areas.
Three
of
the
four
HAP,
acetaldehyde,
acrolein,
and
formaldehyde,
are
included
in
the
HAP
listed
for
the
EPA's
Urban
Air
Toxics
Program.
In
November
1998,
EPA
published
``
A
Multimedia
Strategy
for
Priority,
Persistent,
Bioaccumulative,
and
Toxic
(
PBT)
Pollutants''.
The
HAP
emitted
by
RICE
facilities
do
not
appear
on
the
published
list
of
PBT
compounds
referenced
in
the
EPA
strategy.
Two
of
the
HAP,
acetaldehyde
and
formaldehyde,
are
considered
to
be
nonthreshold
carcinogens,
and
cancer
potency
values
are
reported
for
them
in
Integrated
Risk
Information
System
(
IRIS).
Acrolein
and
methanol
are
not
carcinogens,
but
are
considered
to
be
threshold
pollutants,
and
inhalation
reference
concentrations
are
reported
for
them
in
IRIS
and
by
the
California
Environmental
Protection
Agency
(
CalEPA),
respectively.
To
estimate
the
potential
baseline
risks
posed
by
the
RICE
source
category,
EPA
performed
a
crude
risk
analysis
of
the
RICE
source
category
that
focused
only
on
cancer
risks.
The
results
of
the
analysis
are
based
on
approaches
for
estimating
cancer
incidence
that
carry
significant
assumptions,
uncertainties,
and
limitations.
Based
on
the
assessment,
if
the
proposed
rule
is
implemented
at
all
affected
RICE
facilities,
annual
cancer
incidence
is
estimated
to
be
reduced
on
the
order
of
ten
cases/
year.
Due
to
the
uncertainties
associated
with
the
analysis,
annual
cancer
incidence
could
be
higher
or
lower
than
these
estimates.
(
Details
of
this
assessment
are
available
in
the
docket.)
2.
Applicability
Cutoffs
for
Threshold
Pollutants
Under
Section
112(
d)(
4)
of
the
CAA
The
first
approach
is
an
applicability
cutoff
for
threshold
pollutants
that
is
based
on
EPA's
authority
under
CAA
section
112(
d)(
4)
to
establish
standards
for
HAP
which
are
threshold
pollutants.
A
``
threshold
pollutant''
is
one
for
which
there
is
a
concentration
or
dose
below
which
adverse
effects
are
not
expected
to
occur
over
a
lifetime
of
exposure.
For
such
pollutants,
CAA
section
112(
d)(
4)
allows
EPA
to
consider
the
threshold
level,
with
an
ample
margin
of
safety,
when
establishing
emission
standards.
Specifically,
CAA
section
112(
d)(
4)
allows
EPA
to
establish
emission
standards
that
are
not
based
upon
the
MACT
specified
under
CAA
section
112(
d)(
2)
for
pollutants
for
which
a
health
threshold
has
been
established.
Such
standards
may
be
less
stringent
than
MACT.
Historically,
EPA
has
interpreted
CAA
section
112(
d)(
4)
to
allow
categories
of
sources
that
emit
only
threshold
pollutants
to
avoid
further
regulation
if
those
emissions
result
in
ambient
levels
that
do
not
exceed
the
threshold,
with
an
ample
margin
of
safety.
1
A
different
interpretation
would
allow
us
to
exempt
individual
facilities
within
a
source
category
that
meet
the
CAA
section
112(
d)(
4)
requirements.
There
are
three
potential
scenarios
under
this
interpretation
of
the
CAA
section
112(
d)(
4)
provision.
One
scenario
would
allow
an
exemption
for
individual
facilities
that
emit
only
threshold
pollutants
and
can
demonstrate
that
their
emissions
of
threshold
pollutants
would
not
result
in
air
concentrations
above
the
threshold
levels,
with
an
ample
margin
of
safety,
even
if
the
category
is
otherwise
subject
to
MACT.
A
second
scenario
would
allow
the
CAA
section
112(
d)(
4)
provision
to
be
applied
to
both
threshold
and
non
threshold
pollutants,
using
the
one
in
a
million
cancer
risk
level
for
decision
making
for
nonthreshold
pollutants.
A
third
scenario
would
allow
a
CAA
section
112(
d)(
4)
exemption
at
a
facility
that
emits
both
threshold
and
nonthreshold
pollutants.
For
those
emission
points
where
only
threshold
pollutants
are
emitted
and
where
emissions
of
the
threshold
pollutants
would
not
result
in
air
concentrations
above
the
threshold
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19DEP2.
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Federal
Register
/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
2
``
Methods
for
Derivation
of
Inhalation
Reference
Concentrations
and
Applications
of
Inhalation
Dosimetry.''
EPA
600/
8
90
066F,
Office
of
Research
and
Development,
USEPA,
October
1994.
3
``
Supplementary
Guidance
for
Conducting
Health
Risk
Assessment
of
Chemical
Mixtures.
Risk
Assessment
Forum
Technical
Panel,''
EPA/
630/
R
00/
002.
USEPA,
August
2000.
http://
www.
epa.
gov/
nceaww1/
pdfs/
chem
mix/
chem
mix
08
2001.
pdf.
levels,
with
an
ample
margin
of
safety,
those
emission
points
could
be
exempt
from
the
MACT
standards.
The
MACT
standards
would
still
apply
to
nonthreshold
emissions
from
other
emission
points
at
the
source.
For
this
third
scenario,
emission
points
that
emit
a
combination
of
threshold
and
nonthreshold
pollutants
that
are
cocontrolled
by
MACT
would
still
be
subject
to
the
MACT
level
of
control.
However,
any
threshold
HAP
eligible
for
exemption
under
CAA
section
112(
d)(
4)
that
are
controlled
by
control
devices
different
from
those
controlling
nonthreshold
HAP
would
be
able
to
use
the
exemption,
and
the
facility
would
still
be
subject
to
the
parts
of
the
standards
that
control
nonthreshold
pollutants
or
that
control
both
threshold
and
non
threshold
pollutants.
a.
Estimation
of
Hazard
Quotients
and
Hazard
Indices
Under
the
CAA
section
112(
d)(
4)
approach,
EPA
would
have
to
determine
that
emissions
of
each
of
the
threshold
pollutants
emitted
by
RICE
sources
at
the
facility
do
not
result
in
exposures
which
exceed
the
threshold
levels,
with
an
ample
margin
of
safety.
The
common
approach
for
evaluating
the
potential
hazard
of
a
threshold
air
pollutant
is
to
calculate
a
hazard
quotient
by
dividing
the
pollutant's
inhalation
exposure
concentration
(
often
assumed
to
be
equivalent
to
its
estimated
concentration
in
air
at
a
location
where
people
could
be
exposed)
by
the
pollutant's
inhalation
Reference
Concentration
(
RfC).
An
RfC
is
defined
as
an
estimate
(
with
uncertainty
spanning
perhaps
an
order
of
magnitude)
of
a
continuous
inhalation
exposure
that,
over
a
lifetime,
likely
would
not
result
in
the
occurrence
of
adverse
health
effects
in
humans,
including
sensitive
individuals.
The
EPA
typically
establishes
an
RfC
by
applying
uncertainty
factors
to
the
critical
toxic
effect
derived
from
the
lowest
or
no
observed
adverse
effect
level
of
a
pollutant.
2
A
hazard
quotient
less
than
one
means
that
the
exposure
concentration
of
the
pollutant
is
less
than
the
RfC,
and,
therefore,
presumed
to
be
without
appreciable
risk
of
adverse
health
effects.
A
hazard
quotient
greater
than
one
means
that
the
exposure
concentration
of
the
pollutant
is
greater
than
the
RfC.
Further,
EPA
guidance
for
assessing
exposures
to
mixtures
of
threshold
pollutants
recommends
calculating
a
hazard
index
by
summing
the
individual
hazard
quotients
for
those
pollutants
in
the
mixture
that
affect
the
same
target
organ
or
system
by
the
same
mechanism.
3
Hazard
index
(
HI)
values
would
be
interpreted
similarly
to
hazard
quotients;
values
below
one
would
generally
be
considered
to
be
without
appreciable
risk
of
adverse
health
effects,
and
values
above
one
would
generally
be
cause
for
concern.
For
the
determinations
discussed
herein,
EPA
would
generally
plan
to
use
RfC
values
contained
in
EPA's
toxicology
database,
the
IRIS.
When
a
pollutant
does
not
have
an
approved
RfC
in
IRIS,
or
when
a
pollutant
is
a
carcinogen,
EPA
would
have
to
determine
whether
a
threshold
exists
based
upon
the
availability
of
specific
data
on
the
pollutant's
mode
or
mechanism
of
action,
potentially
using
a
health
threshold
value
from
an
alternative
source,
such
as
the
Agency
for
Toxic
Substances
and
Disease
Registry
(
ATSDR)
or
the
CalEPA.
Table
2
of
this
preamble
provides
the
RfC,
as
well
as
unit
risk
estimates,
for
the
HAP
emitted
by
facilities
in
the
RICE
source
category.
A
unit
risk
estimate
is
defined
as
the
upper
bound
excess
lifetime
cancer
risk
estimated
to
result
from
continuous
exposure
to
an
agent
at
a
concentration
of
1
micrograms
per
cubic
meter
(
µ
g/
m3)
in
air.
TABLE
2.
DOSE
RESPONSE
ASSESSMENT
VALUES
FOR
HAP
REPORTED
EMITTED
BY
THE
RICE
SOURCE
CATEGORY
Chemical
name
CAS
No.
Reference
concentration
a
(
mg/
m3)
Unit
risk
estimate
b
(
1/(
µ
g/
m3))
Acetaldehyde
..............................................
75
07
0
9.0E
03
(
IRIS)
...........................................
2.2E
06
(
IRIS)
Acrolein
......................................................
107
02
8
2.0E
05
(
IRIS)
...........................................
Formaldehyde
............................................
50
00
0
9.8E
03
(
ATSDR)
......................................
1.3E
05
(
IRIS)
Methanol
.....................................................
67
56
1
4.0E+
00
(
CAL)
...........................................
a
Reference
Concentration:
An
estimate
(
with
uncertainty
spanning
perhaps
an
order
of
magnitude)
of
a
continuous
inhalation
exposure
to
the
human
population
(
including
sensitive
subgroups
which
include
children,
asthmatics
and
the
elderly)
that
is
likely
to
be
without
an
appreciable
risk
of
deleterious
effects
during
a
lifetime.
It
can
be
derived
from
various
types
of
human
or
animal
data,
with
uncertainty
factors
generally
applied
to
reflect
limitations
of
the
data
used.
b
Unit
Risk
Estimate:
The
upper
bound
excess
lifetime
cancer
risk
estimated
to
result
from
continuous
exposure
to
an
agent
at
a
concentration
of
1
µ
g/
m3
in
air.
The
interpretation
of
the
Unit
Risk
Estimate
would
be
as
follows:
if
the
Unit
Risk
Estimate
=
1.5
x
10
¥
6
per
µ
g/
m3,
1.5
excess
tumors
are
expected
to
develop
per
1,000,000
people
if
exposed
daily
for
a
lifetime
to
1
microgram
(
µ
g)
of
the
chemical
in
1
cubic
meter
of
air.
Unit
Risk
Estimates
are
considered
upper
bound
estimates,
meaning
they
represent
a
plausible
upper
limit
to
the
true
value.
(
Note
that
this
is
usually
not
a
true
statistical
confidence
limit.)
The
true
risk
is
likely
to
be
less,
but
could
be
greater.
Sources:
IRIS
=
EPA
Integrated
Risk
Information
System
(
http://
www.
epa.
gov/
iris/
subst/
index.
html)
ATSDR
=
U.
S.
Agency
for
Toxic
Substances
and
Disease
Registry
(
http://
www.
atsdr.
cdc.
gov/
mrls.
html)
CAL
=
California
Office
of
Environmental
Health
Hazard
Assessment
(
http://
www.
oehha.
ca.
gov/
air/
hot_
spots/
index.
html)
HEAST
=
EPA
Health
Effects
Assessment
Summary
Tables
(#
PB
(=
97
921199),
July
1997)
To
establish
an
applicability
cutoff
under
CAA
section
112(
d)(
4),
EPA
would
need
to
define
ambient
air
exposure
concentration
limits
for
any
threshold
pollutants
involved.
There
are
several
factors
to
consider
when
establishing
such
concentrations.
First,
we
would
need
to
ensure
that
the
concentrations
that
would
be
established
would
protect
public
health
with
an
ample
margin
of
safety.
As
discussed
above,
the
approach
EPA
commonly
uses
when
evaluating
the
potential
hazard
of
a
threshold
air
pollutant
is
to
calculate
the
pollutant's
hazard
quotient,
which
is
the
exposure
concentration
divided
by
the
RfC.
The
EPA's
``
Supplementary
Guidance
for
Conducting
Health
Risk
Assessment
of
Chemical
Mixtures''
suggests
that
the
noncancer
health
effects
associated
with
a
mixture
of
pollutants
ideally
are
assessed
by
considering
the
pollutants'
common
mechanisms
of
toxicity
3.
The
guidance
also
suggests,
however,
that
when
exposures
to
mixtures
of
pollutants
are
being
evaluated,
the
risk
assessor
may
calculate
a
HI.
The
recommended
method
is
to
calculate
multiple
hazard
indices
for
each
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Federal
Register
/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
4
Senate
Debate
on
Conference
Report
(
October
27,
1990),
reprinted
in
``
A
Legislative
History
of
the
Clean
Air
Act
Amendments
of
1990,''
Comm.
Print
S.
Prt.
103
38
(
1993)
(``
Legis.
Hist.'')
at
868.
5
See
http://
www.
epa.
gov/
ttn/
atw/
nata.
6
See
http://
www.
atsdr.
cdc.
gov/
toxpro2.
html.
7
``
A
Tiered
Modeling
Approach
for
Assessing
the
Risks
due
to
Sources
of
Hazardous
Air
Pollutants.''
EPA
450/
4
92
001.
David
E.
Guinnup,
Office
of
Air
Quality
Planning
and
Standards,
USEPA,
March
1992.
exposure
route
of
interest,
and
for
a
single
specific
toxic
effect
or
toxicity
to
a
single
target
organ.
The
default
approach
recommended
by
the
guidance
is
to
sum
the
hazard
quotients
for
those
pollutants
that
induce
the
same
toxic
effect
or
affect
the
same
target
organ.
A
mixture
is
then
assessed
by
several
HI,
each
representing
one
toxic
effect
or
target
organ.
The
guidance
notes
that
the
pollutants
included
in
the
HI
calculation
are
any
pollutants
that
show
the
effect
being
assessed,
regardless
of
the
critical
effect
upon
which
the
RfC
is
based.
The
guidance
cautions
that
if
the
target
organ
or
toxic
effect
for
which
the
HI
is
calculated
is
different
from
the
RfC's
critical
effect,
then
the
RfC
for
that
chemical
will
be
an
overestimate,
that
is,
the
resultant
HI
potentially
may
be
overprotective.
Conversely,
since
the
calculation
of
an
HI
does
not
account
for
the
fact
that
the
potency
of
a
mixture
of
HAP
can
be
more
potent
than
the
sum
of
the
individual
HAP
potencies,
an
HI
may
potentially
be
underprotective.
b.
Options
for
Establishing
a
Hazard
Index
Limit
One
consideration
in
establishing
a
hazard
index
limit
is
whether
the
analysis
considers
the
total
ambient
air
concentrations
of
all
the
emitted
HAP
to
which
the
public
is
exposed
4.
There
are
at
least
several
options
for
establishing
a
hazard
index
limit
for
the
CAA
section
112(
d)(
4)
analysis
that
reflect,
to
varying
degrees,
public
exposure.
One
option
is
to
allow
the
HI
posed
by
all
threshold
HAP
emitted
from
RICE
sources
at
the
facility
to
be
no
greater
than
one.
This
approach
is
protective
if
no
additional
threshold
HAP
exposures
would
be
anticipated
from
other
sources
in
the
vicinity
of
the
facility
or
through
other
routes
of
exposure
(
e.
g.,
through
ingestion).
A
second
option
is
to
adopt
a
default
percentage
approach,
whereby
the
hazard
index
limit
of
the
HAP
emitted
by
the
facility
is
set
at
some
percentage
of
one
(
e.
g.,
20
percent
or
0.2).
This
approach
recognizes
the
fact
that
the
facility
in
question
is
only
one
of
many
sources
of
threshold
HAP
to
which
people
are
typically
exposed
every
day.
Because
noncancer
risk
assessment
is
predicated
on
total
exposure
or
dose,
and
because
risk
assessments
focus
only
on
an
individual
source,
establishing
a
hazard
index
limit
of
0.2
would
account
for
an
assumption
that
20
percent
of
an
individual's
total
exposure
is
from
that
individual
source.
For
the
purposes
of
this
discussion,
we
will
call
all
sources
of
HAP,
other
than
the
facility
in
question,
background
sources.
If
the
facility
is
allowed
to
emit
HAP
such
that
its
own
impacts
could
result
in
HI
values
of
one,
total
exposures
to
threshold
HAP
in
the
vicinity
of
the
facility
could
be
substantially
greater
than
one
due
to
background
sources,
and
this
would
not
be
protective
of
public
health,
since
only
HI
values
below
one
are
considered
to
be
without
appreciable
risk
of
adverse
health
effects.
Thus,
setting
the
hazard
index
limit
for
the
facility
at
some
default
percentage
of
one
will
provide
a
buffer
which
would
help
to
ensure
that
total
exposures
to
threshold
HAP
near
the
facility
(
i.
e.,
in
combination
with
exposures
due
to
background
sources)
will
generally
not
exceed
one,
and
can
generally
be
considered
to
be
without
appreciable
risk
of
adverse
health
effects.
The
EPA
requests
comment
on
using
the
default
percentage
approach
and
on
setting
the
default
hazard
index
limit
at
0.2.
The
EPA
is
also
requesting
comment
on
whether
an
alternative
HI
limit,
in
some
multiple
of
1
would
be
a
more
appropriate
applicability
cutoff.
A
third
option
is
to
use
available
data
(
from
scientific
literature
or
EPA
studies,
for
example)
to
determine
background
concentrations
of
HAP,
possibly
on
a
national
or
regional
basis.
These
data
would
be
used
to
estimate
the
exposures
to
HAP
from
non
RICE
sources
in
the
vicinity
of
an
individual
facility.
For
example,
the
EPA's
National
Scale
Air
Toxics
Assessment
(
NATA)
5
and
ATSDR's
Toxicological
Profiles
6
contain
information
about
background
concentrations
of
some
HAP
in
the
atmosphere
and
other
media.
The
combined
exposures
from
RICE
sources
and
from
other
sources
(
as
determined
from
the
literature
or
studies)
would
then
not
be
allowed
to
exceed
a
hazard
index
limit
of
1.
The
EPA
requests
comment
on
the
appropriateness
of
setting
the
hazard
index
limit
at
1
for
such
an
analysis.
A
fourth
option
is
to
allow
facilities
to
estimate
or
measure
their
own
facility
specific
background
HAP
concentrations
for
use
in
their
analysis.
With
regard
to
the
third
and
fourth
options,
the
EPA
requests
comment
on
how
these
analyses
could
be
structured.
Specifically,
EPA
requests
comment
on
how
the
analyses
should
take
into
account
background
exposure
levels
from
air,
water,
food
and
soil
encountered
by
the
individuals
exposed
to
RICE
emissions.
In
addition,
we
request
comment
on
how
such
analyses
should
account
for
potential
increases
in
exposures
due
to
the
use
of
a
new
or
the
increased
use
of
a
previously
emitted
HAP,
or
the
effect
of
other
nearby
sources
that
release
HAP.
The
EPA
requests
comment
on
the
feasibility
and
scientific
validity
of
each
of
these
or
other
approaches.
Finally,
EPA
requests
comment
on
how
we
should
implement
the
CAA
section
112(
d)(
4)
applicability
cutoffs,
including
appropriate
mechanisms
for
applying
cutoffs
to
individual
facilities.
For
example,
would
the
title
V
permit
process
provide
an
appropriate
mechanism?
c.
Tiered
Analytical
Approach
for
Predicting
Exposure
Establishing
that
a
facility
meets
the
cutoffs
established
under
CAA
section
112(
d)(
4)
will
necessarily
involve
combining
estimates
of
pollutant
emissions
with
air
dispersion
modeling
to
predict
exposures.
The
EPA
envisions
that
we
would
promote
a
tiered
analytical
approach
for
these
determinations.
A
tiered
analysis
involves
making
successive
refinements
in
modeling
methodologies
and
input
data
to
derive
successively
less
conservative,
more
realistic
estimates
of
pollutant
concentrations
in
air
and
estimates
of
risk.
As
a
first
tier
of
analysis,
EPA
could
develop
a
series
of
simple
look
up
tables
based
on
the
results
of
air
dispersion
modeling
conducted
using
conservative
input
assumptions.
By
specifying
a
limited
number
of
input
parameters,
such
as
stack
height,
distance
to
property
line,
and
emission
rate,
a
facility
could
use
these
look
up
tables
to
determine
easily
whether
the
emissions
from
their
sources
might
cause
a
hazard
index
limit
to
be
exceeded.
A
facility
that
does
not
pass
this
initial
conservative
screening
analysis
could
implement
increasingly
more
sitespecific
but
more
resource
intensive
tiers
of
analysis
using
EPA
approved
modeling
procedures,
in
an
attempt
to
demonstrate
that
exposure
to
emissions
from
the
facility
does
not
exceed
the
hazard
index
limit.
The
EPA's
guidance
could
provide
the
basis
for
conducting
such
a
tiered
analysis.
7
The
EPA
requests
comment
on
methods
for
constructing
and
implementing
a
tiered
analytical
approach
for
determining
applicability
of
the
CAA
section
112(
d)(
4)
criterion
to
specific
RICE
sources.
It
is
also
possible
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19DEP2.
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Federal
Register
/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
8``
Draft
Revised
Guidelines
for
Carcinogen
Risk
Assessment.''
NCEA
F
0644.
USEPA,
Risk
Assessment
Forum,
July
1999.
pp
3
9ff.
http://
www.
epa.
gov/
ncea/
raf/
pdfs/
cancer_
gls.
pdf.
that
ambient
monitoring
data
could
be
used
to
supplement
or
supplant
the
tiered
modeling
approach
described
above.
It
is
envisioned
that
the
appropriate
monitoring
to
support
such
a
determination
could
be
extensive.
The
EPA
requests
comment
on
the
appropriate
use
of
monitoring
in
the
determinations
described
above.
d.
Accounting
for
Dose
Response
Relationships
In
the
past,
EPA
routinely
treated
carcinogens
as
nonthreshold
pollutants.
The
EPA
recognizes
that
advances
in
risk
assessment
science
and
policy
may
affect
the
way
EPA
differentiates
between
threshold
and
nonthreshold
HAP.
The
EPA's
draft
Guidelines
for
Carcinogen
Risk
Assessment
8
suggest
that
carcinogens
be
assigned
non
linear
dose
response
relationships
where
data
warrant.
Moreover,
it
is
possible
that
dose
response
curves
for
some
pollutants
may
reach
zero
risk
at
a
dose
greater
than
zero,
creating
a
threshold
for
carcinogenic
effects.
It
is
possible
that
future
evaluations
of
the
carcinogens
emitted
by
this
source
category
would
determine
that
one
or
more
of
the
carcinogens
in
the
category
is
a
threshold
carcinogen
or
is
a
carcinogen
that
exhibits
a
non
linear
dose
response
relationship
but
does
not
have
a
threshold.
The
dose
response
assessments
for
formaldehyde
and
acetaldehyde
are
currently
undergoing
revision
by
the
EPA.
As
part
of
this
revision
effort,
EPA
is
evaluating
formaldehyde
and
acetaldehyde
as
potential
non
linear
carcinogens.
The
revised
dose
response
assessments
will
be
subject
to
review
by
the
EPA
Science
Advisory
Board,
followed
by
full
consensus
review,
before
adoption
into
the
EPA
Integrated
Risk
Information
System.
At
this
time,
EPA
estimates
that
the
consensus
review
will
be
completed
by
the
end
of
2003.
The
revision
of
the
dose
response
assessments
could
affect
the
potency
factors
of
these
HAP,
as
well
as
their
status
as
threshold
or
nonthreshold
pollutants.
At
this
time,
the
outcome
is
not
known.
In
addition
to
the
current
reassessment
by
EPA,
there
have
been
several
reassessments
of
the
toxicity
and
carcinogenicity
of
formaldehyde
in
recent
years,
including
work
by
the
World
Health
Organization
and
the
Canadian
Ministry
of
Health.
The
EPA
requests
comment
on
how
we
should
consider
the
state
of
the
science
as
it
relates
to
the
treatment
of
threshold
pollutants
when
making
determinations
under
section
112(
d)(
4).
In
addition,
EPA
requests
comment
on
whether
there
is
a
level
of
emissions
of
a
nonthreshold
carcinogenic
HAP
(
e.
g.,
benzene,
methylene
chloride)
at
which
it
would
be
appropriate
to
allow
a
facility
to
use
the
approaches
discussed
in
this
section.
If
the
CAA
section
112(
d)(
4)
approach
were
adopted,
the
proposed
rulemaking
would
likely
indicate
that
the
requirements
of
the
rule
do
not
apply
to
any
source
that
demonstrates,
based
on
a
tiered
approach
that
includes
EPAapproved
modeling
of
the
affected
source's
emissions,
that
the
anticipated
HAP
exposures
do
not
exceed
the
specified
hazard
index
limit.
3.
Subcategory
Delisting
Under
Section
112(
c)(
9)(
B)
of
the
CAA
The
EPA
is
authorized
to
establish
categories
and
subcategories
of
sources,
as
appropriate,
pursuant
to
CAA
section
112(
c)(
1),
in
order
to
facilitate
the
development
of
MACT
standards
consistent
with
section
112
of
the
CAA.
Further,
section
112(
c)(
9)(
B)
allows
EPA
to
delete
a
category
(
or
subcategory)
from
the
list
of
major
sources
for
which
MACT
standards
are
to
be
developed
when
the
following
can
be
demonstrated:
(
1)
In
the
case
of
carcinogenic
pollutants,
that
``
no
source
in
the
category
*
*
*
emits
(
carcinogenic)
air
pollutants
in
quantities
which
may
cause
a
lifetime
risk
of
cancer
greater
than
1
in
1
million
to
the
individual
in
the
population
who
is
most
exposed
to
emissions
of
such
pollutants
from
the
source'';
(
2)
in
the
case
of
pollutants
that
cause
adverse
noncancer
health
effects,
that
``
emissions
from
no
source
in
the
category
or
subcategory
*
*
*
exceed
a
level
which
is
adequate
to
protect
public
health
with
an
ample
margin
of
safety'';
and
(
3)
in
the
case
of
pollutants
that
cause
adverse
environmental
effects,
that
``
no
adverse
environmental
effect
will
result
from
emissions
from
any
source.''
Given
these
authorities
and
the
suggestions
from
the
white
paper
prepared
by
industry
representatives
(
see
docket
number
OAR
2002
0059),
EPA
is
considering
whether
it
would
be
possible
to
establish
a
subcategory
of
facilities
within
the
larger
RICE
category
that
would
meet
the
risk
based
criteria
for
delisting.
Such
criteria
would
likely
include
the
same
requirements
as
described
previously
for
the
second
scenario
under
the
section
112(
d)(
4)
approach,
whereby
a
facility
would
be
in
the
low
risk
subcategory
if
its
emissions
of
threshold
pollutants
do
not
result
in
exposures
which
exceed
the
HI
limits
and
if
its
emissions
of
nonthreshold
pollutants
do
not
result
in
exposures
which
exceed
a
cancer
risk
level
of
10
¥
6.
The
EPA
requests
comment
on
what
an
appropriate
HI
limit
would
be
for
a
determination
that
a
facility
be
included
in
the
low
risk
subcategory.
Since
each
facility
in
such
a
subcategory
would
be
a
low
risk
facility
(
i.
e.,
if
each
met
these
criteria),
the
subcategory
could
be
delisted
in
accordance
with
CAA
section
112(
c)(
9),
thereby
limiting
the
costs
and
impacts
of
the
proposed
rule
to
only
those
facilities
that
do
not
qualify
for
subcategorization
and
delisting.
The
EPA
estimates
that
the
maximum
potential
effect
of
this
approach
would
be
the
same
as
that
of
applying
the
CAA
section
112(
d)(
4)
approach
that
allows
exemption
of
facilities
emitting
threshold
and
non
threshold
pollutants
if
exemption
criteria
are
met.
Facilities
seeking
to
be
included
in
the
delisted
subcategory
would
be
responsible
for
providing
all
data
required
to
determine
whether
they
are
eligible
for
inclusion.
Facilities
that
could
not
demonstrate
that
they
are
eligible
to
be
included
in
the
low
risk
subcategory
would
be
subject
to
MACT
and
possible
future
residual
risk
standards.
The
EPA
solicits
comment
on
implementing
a
risk
based
approach
for
establishing
subcategories
of
RICE
facilities.
Establishing
that
a
facility
qualifies
for
the
low
risk
subcategory
under
CAA
section
112(
c)(
9)
will
necessarily
involve
combining
estimates
of
pollutant
emissions
with
air
dispersion
modeling
to
predict
exposures.
The
EPA
envisions
that
we
would
employ
the
same
tiered
analytical
approach
described
earlier
in
the
CAA
section
112(
d)(
4)
discussion
for
these
determinations.
One
concern
that
EPA
has
with
respect
to
the
CAA
section
112(
c)(
9)
approach
is
the
effect
that
it
could
have
on
the
MACT
floors.
If
many
of
the
facilities
in
the
low
risk
subcategory
are
well
controlled,
that
could
make
the
MACT
floor
less
stringent
for
the
remaining
facilities.
One
approach
that
has
been
suggested
to
mitigate
this
effect
would
be
to
establish
the
MACT
floor
now
based
on
controls
in
place
for
the
entire
category
and
to
allow
facilities
to
become
part
of
the
low
risk
subcategory
in
the
future,
after
the
MACT
standards
are
established.
This
would
allow
low
risk
facilities
to
use
the
CAA
section
112(
c)(
9)
exemption
without
affecting
the
MACT
floor
calculation.
The
EPA
requests
comment
on
this
suggested
approach.
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/
Thursday,
December
19,
2002
/
Proposed
Rules
Another
approach
under
CAA
section
112(
c)(
9)
would
be
to
define
a
subcategory
of
facilities
within
the
RICE
source
category
based
upon
technological
differences,
such
as
differences
in
production
rate,
emission
vent
flow
rates,
overall
facility
size,
emissions
characteristics,
processes,
or
air
pollution
control
device
viability.
The
EPA
requests
comment
on
how
we
might
establish
RICE
subcategories
based
on
these,
or
other,
source
characteristics.
If
it
could
then
be
determined
that
each
source
in
this
technologically
defined
subcategory
presents
a
low
risk
to
the
surrounding
community,
the
subcategory
could
then
be
delisted
in
accordance
with
CAA
section
112(
c)(
9).
The
EPA
requests
comment
on
the
concept
of
identifying
technologically
based
subcategories
that
may
include
only
low
risk
facilities
within
the
RICE
source
category.
If
the
CAA
section
112(
c)(
9)
approach
were
adopted,
the
proposed
rulemaking
would
likely
indicate
that
the
rule
does
not
apply
to
any
source
that
demonstrates
that
it
belongs
in
a
subcategory
which
has
been
delisted
under
CAA
section
112(
c)(
9).
C.
Limited
Use
Subcategory
We
are
soliciting
comments
on
creating
a
subcategory
of
limited
use
engines
with
capacity
utilization
of
10
percent
or
less
(
876
or
fewer
hours
of
annual
operation).
Units
in
this
subcategory
would
include
engines
used
for
electric
power
peak
shaving
that
are
called
upon
to
operate
fewer
than
876
hours
per
year.
These
units
operate
only
during
peak
energy
use
periods,
typically
in
the
summer
months.
We
believe
that
these
infrequently
operated
units
typically
operate
10
percent
of
the
year
or
less.
While
these
are
potential
sources
of
emissions,
and
it
is
appropriate
for
EPA
to
address
them
in
the
proposed
rule,
the
Agency
believes
that
their
use
and
operation
are
different
compared
to
typical
RICE.
We
believe
that
it
may
be
appropriate
for
such
limited
use
units
to
have
their
own
subcategory.
Therefore,
we
are
soliciting
comment
on
subcategorizing
RICE
having
a
capacity
utilization
of
less
than
10
percent.
We
have
performed
a
preliminary
MACT
floor
analysis
on
engines
with
under
10
percent
capacity
utilization
that
are
in
EPA's
RICE
database.
This
analysis
indicates
that
existing
units
would
have
a
floor
of
no
emissions
reductions
and
new
units
would
have
a
floor
equal
to
the
performance
of
an
oxidation
catalyst
system.
We
are
interested
in
comments
on
creating
a
subcategory
for
limited
use
peak
shaving
(
less
than
10
percent
capacity
utilization)
engines.
We
are
interested
in
comments
on
the
validity
and
appropriateness
under
the
CAA
for
a
subcategory
for
limited
use
peak
shaving
engines,
data
on
the
levels
of
control
currently
achieved
by
such
engines,
and
any
technical
limitations
that
might
make
it
impossible
to
achieve
control
of
emissions
from
limited
use
peak
shaving
engines.
VI.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
we
must
determine
whether
a
regulatory
action
is
``
significant''
and,
therefore,
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(
2)
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(
3)
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligations
of
recipients
thereof;
or
(
4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
we
have
determined
that
the
proposed
rule
is
a
``
significant
regulatory
action''
because
it
could
have
an
annual
effect
on
the
economy
of
over
$
100
million.
Consequently,
this
action
was
submitted
to
OMB
for
review
under
Executive
Order
12866.
Any
written
comments
from
OMB
and
written
EPA
responses
are
available
in
the
docket.
As
stipulated
in
Executive
Order
12866,
in
deciding
how
or
whether
to
regulate,
EPA
is
required
to
assess
all
costs
and
benefits
of
available
regulatory
alternatives,
including
the
alternative
of
not
regulating.
To
this
end,
EPA
prepared
a
detailed
benefit
cost
analysis
in
the
``
Regulatory
Impact
Analysis
of
the
Proposed
Reciprocating
Internal
Combustion
Engines
NESHAP,''
which
is
contained
in
the
docket.
The
following
is
a
summary
of
the
benefitcost
analysis.
It
is
estimated
that
5
years
after
implementation
of
the
proposed
rule,
HAP
will
be
reduced
by
5,000
tons
per
year
due
to
reductions
in
formaldehyde,
acetaldehyde,
acrolein,
methanol,
and
several
other
HAP
from
some
existing
and
all
new
internal
combustion
engines.
Formaldehyde
and
acetaldehyde
have
been
classified
as
``
probable
human
carcinogens''
based
on
scientific
studies
conducted
over
the
past
20
years.
These
studies
have
determined
a
relationship
between
exposure
to
these
HAP
and
the
onset
of
cancer;
however,
there
are
some
questions
remaining
on
how
cancers
that
may
result
from
exposure
to
these
HAP
can
be
quantified
in
terms
of
dollars.
Acrolein,
methanol
and
the
other
HAP
emitted
from
RICE
sources
are
not
considered
carcinogenic
but
have
been
reported
to
cause
several
noncarcinogenic
effects.
The
control
technology
to
reduce
the
level
of
HAP
emitted
from
RICE
are
also
expected
to
reduce
emissions
of
criteria
pollutants,
primarily
CO,
NOX,
and
PM,
however,
VOC
are
also
reduced
to
a
minor
extent.
It
is
estimated
that
CO
emissions
reductions
totals
approximately
234,400
tons/
year,
NOX
emissions
reductions
totals
approximately
167,900
tons/
year,
and
PM
emissions
reductions
totals
approximately
3,700
tons
per
year.
These
reductions
occur
from
new
and
existing
engines
in
operation
5
years
after
the
implementation
of
the
rule
as
proposed
and
are
expected
to
continue
throughout
the
life
of
the
engines
and
continue
to
grow
as
new
engines
(
that
otherwise
would
not
be
controlled)
are
purchased
for
operation.
Human
health
effects
associated
with
exposure
to
CO
include
cardiovascular
system
and
CNS
effects,
which
are
directly
related
to
reduced
oxygen
content
of
blood
and
which
can
result
in
modification
of
visual
perception,
hearing,
motor
and
sensorimotor
performance,
vigilance,
and
cognitive
ability.
Emissions
of
NOX
can
transform
into
PM
in
the
atmosphere,
which
produces
a
variety
of
health
and
welfare
effects.
Human
health
effects
associated
with
NOX
include
respiratory
problems,
such
as
chronic
bronchitis,
asthma,
or
even
death
from
complications.
Welfare
effects
from
direct
NOX
exposure
include
agricultural
and
forestry
damage
and
acidification
of
estuaries
through
rain
deposition
of
nitrogen;
while
fine
PM
particles
created
from
NOX
can
reduce
visibility
in
national
parks
and
other
natural
and
urban
areas.
At
the
present
time,
the
Agency
cannot
provide
a
monetary
estimate
for
the
benefits
associated
with
the
reductions
in
CO.
For
NOX
and
PM,
the
Agency
has
conducted
several
analyses
recently
that
estimate
the
monetized
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Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
benefits
of
these
pollutant
reductions,
including:
the
Regulatory
Impact
Analysis
(
RIA)
of
the
PM/
Ozone
National
Ambient
Air
Quality
Standards
(
1997),
the
NOX
State
Implementation
Plan
Call
(
1998),
the
section
126
RIA
(
1999),
a
study
conducted
for
section
812(
b)
of
the
Clean
Air
Act
Amendments
(
1990),
the
Tier
2/
Gasoline
Sulfur
Standards
(
1999),
and
the
Heavy
Duty
Engine/
Diesel
Fuel
Standards
(
2000).
On
September
26,
2002,
the
National
Academy
of
Sciences
(
NAS)
released
a
report
on
its
review
of
the
Agency's
methodology
for
analyzing
the
health
benefits
of
measures
taken
to
reduce
air
pollution.
The
report
focused
on
EPA's
approach
for
estimating
the
health
benefits
of
regulations
designed
to
reduce
concentrations
of
airborne
particulate
matter
(
PM).
In
its
report,
the
NAS
said
that
EPA
has
generally
used
a
reasonable
framework
for
analyzing
the
health
benefits
of
PM
control
measures.
It
recommended,
however,
that
the
Agency
take
a
number
of
steps
to
improve
its
benefits
analysis.
In
particular,
the
NAS
stated
that
the
Agency
should:
(
1)
Include
benefits
estimates
for
a
range
of
regulatory
options;
(
2)
Estimate
benefits
for
intervals,
such
as
every
5
years,
rather
than
a
single
year;
(
3)
Clearly
state
the
project
baseline
statistics
used
in
estimating
health
benefits,
including
those
for
air
emissions,
air
quality,
and
health
outcomes;
(
4)
Examine
whether
implementation
of
proposed
regulations
might
cause
unintended
impacts
on
human
health
or
the
environment;
(
5)
When
appropriate,
use
data
from
non
U.
S.
studies
to
broaden
age
ranges
to
which
current
estimates
apply
and
to
include
more
types
of
relevant
health
outcomes;
(
6)
Begin
to
move
the
assessment
of
uncertainties
from
its
ancillary
analyses
into
its
primary
analyses
by
conducting
probabilistic,
multiple
source
uncertainty
analyses.
This
assessment
should
be
based
on
available
data
and
expert
judgment.
Although
the
NAS
made
a
number
of
recommendations
for
improvement
in
EPA's
approach,
it
found
that
the
studies
selected
by
EPA
for
use
in
its
benefits
analysis
were
generally
reasonable
choices.
In
particular,
the
NAS
agreed
with
EPA's
decision
to
use
cohort
studies
to
derive
benefits
estimates.
It
also
concluded
that
the
Agency's
selection
of
the
American
Cancer
Society
(
ACS)
study
for
the
evaluation
of
PM
related
premature
mortality
was
reasonable,
although
it
noted
the
publication
of
new
cohort
studies
that
should
be
evaluated
by
the
Agency.
Several
of
the
NAS
recommendations
addressed
the
issue
of
uncertainty
and
how
the
Agency
can
better
analyze
and
communicate
the
uncertainties
associated
with
its
benefits
assessments.
In
particular,
the
Committee
expressed
concern
about
the
Agency's
reliance
on
a
single
value
from
its
analysis
and
suggested
that
EPA
develop
a
probabilistic
approach
for
analyzing
the
health
benefits
of
proposed
regulatory
actions.
The
Agency
agrees
with
this
suggestion
and
is
working
to
develop
such
an
approach
for
use
in
future
rulemakings.
In
the
RIA
for
the
proposed
rule,
the
Agency
has
used
an
interim
approach
that
shows
the
impact
of
several
important
alternative
assumptions
about
the
estimation
and
valuation
of
reductions
in
premature
mortality
and
chronic
bronchitis.
This
approach,
which
was
developed
in
the
context
of
the
Agency's
Clear
Skies
analysis,
provides
an
alternative
estimate
of
health
benefits
using
the
time
series
studies
in
place
of
cohort
studies,
as
well
as
alternative
valuation
methods
for
mortality
and
chronic
bronchitis
risk
reductions.
For
today's
action,
we
conducted
an
air
quality
assessment
to
determine
the
change
in
concentrations
of
PM
that
results
from
reductions
of
NOX
and
direct
emissions
of
PM
at
all
sources
of
RICE.
Because
we
are
unable
to
identify
the
location
of
all
affected
existing
and
new
sources
of
RICE,
our
analysis
is
conducted
in
two
phases.
In
the
first
phase,
we
conduct
air
quality
analysis
assuming
a
50
percent
reduction
of
1996
levels
of
NOX
emissions
and
a
100
percent
reduction
of
PM10
emissions
for
all
RICE
sources
throughout
the
country.
The
results
of
this
analysis
serve
as
a
reasonable
approximation
of
air
quality
changes
to
transfer
to
the
proposed
rule's
emissions
reductions
at
affected
sources.
The
results
of
the
air
quality
assessment
served
as
input
to
a
model
that
estimates
the
benefits
related
to
the
health
effects
listed
above.
In
the
second
phase
of
our
analysis,
the
value
of
the
benefits
per
ton
of
NOX
and
PM
reduced
(
e.
g.,
$
benefit/
ton
reduced)
associated
with
the
air
quality
scenarios
are
then
applied
to
the
tons
of
NOX
and
PM
emissions
expected
to
be
reduced
by
the
proposed
rule.
We
also
used
the
benefit
transfer
method
to
value
improvements
in
ozone
based
on
the
transfer
of
benefit
values
from
an
analysis
of
the
1998
NOX
SIP
call.
In
addition,
although
the
benefits
of
the
welfare
effects
of
NOX
are
monetized
in
other
Agency
analyses,
we
chose
not
to
do
an
analysis
of
the
improvements
in
welfare
effects
that
will
result
from
the
proposed
rule.
Alternatively,
we
could
transfer
the
estimates
of
welfare
benefits
from
these
other
studies
to
this
analysis,
but
chose
not
to
do
so
because
these
studies
with
estimated
welfare
benefits
differ
in
the
source
and
location
of
emissions
and
associated
impacted
populations.
Every
benefit
cost
analysis
examining
the
potential
effects
of
a
change
in
environmental
protection
requirements
is
limited
to
some
extent
by
data
gaps,
limitations
in
model
capabilities
(
such
as
geographic
coverage),
and
uncertainties
in
the
underlying
scientific
and
economic
studies
used
to
configure
the
benefit
and
cost
models.
Deficiencies
in
the
scientific
literature
often
result
in
the
inability
to
estimate
changes
in
health
and
environmental
effects,
such
as
potential
increases
in
premature
mortality
associated
with
increased
exposure
to
carbon
monoxide.
Deficiencies
in
the
economics
literature
often
result
in
the
inability
to
assign
economic
values
even
to
those
health
and
environmental
outcomes
which
can
be
quantified.
While
these
general
uncertainties
in
the
underlying
scientific
and
economics
literatures
are
discussed
in
detail
in
the
RIA
and
its
supporting
documents
and
references,
the
key
uncertainties
which
have
a
bearing
on
the
results
of
the
benefit
cost
analysis
of
today's
action
are
the
following:
(
1)
The
exclusion
of
potentially
significant
benefit
categories
(
e.
g.,
health
and
ecological
benefits
of
reduction
in
hazardous
air
pollutants
emissions);
(
2)
Errors
in
measurement
and
projection
for
variables
such
as
population
growth;
(
3)
Uncertainties
in
the
estimation
of
future
year
emissions
inventories
and
air
quality;
(
4)
Uncertainties
associated
with
the
extrapolation
of
air
quality
monitoring
data
to
some
unmonitored
areas
required
to
better
capture
the
effects
of
the
standards
on
the
affected
population;
(
5)
Variability
in
the
estimated
relationships
of
health
and
welfare
effects
to
changes
in
pollutant
concentrations;
and
(
6)
Uncertainties
associated
with
the
benefit
transfer
approach.
Despite
these
uncertainties,
we
believe
the
benefit
cost
analysis
provides
a
reasonable
indication
of
the
expected
economic
benefits
of
the
RICE
NESHAP
under
two
different
sets
of
assumptions.
We
have
used
two
approaches
(
Base
and
Alternative
Estimates)
to
provide
benefits
in
health
effects
and
in
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monetary
terms.
They
differ
in
the
method
used
to
estimate
and
value
reduced
incidences
of
mortality
and
chronic
bronchitis,
which
is
explained
in
detail
in
the
RIA.
While
there
is
a
substantial
difference
in
the
specific
estimates,
both
approaches
show
that
the
RICE
MACT
may
provide
benefits
to
public
health,
whether
expressed
as
health
improvements
or
as
economic
benefits.
These
include
prolonging
lives,
reducing
cases
of
chronic
bronchitis
and
hospital
admissions,
and
reducing
thousands
of
cases
in
other
indicators
of
adverse
health
effects,
such
as
work
loss
days,
restricted
activity
days,
and
days
with
asthma
attacks.
In
addition,
there
are
a
number
of
health
and
environmental
effects
which
we
were
unable
to
quantify
or
monetize.
These
effects,
denoted
by
``
B''
are
additive
to
both
the
Base
and
Alternative
estimates
of
benefits.
Results
also
reflect
the
use
of
two
different
discount
rates
for
the
valuation
of
reduced
incidences
of
mortality;
a
3
percent
rate
which
is
recommended
by
EPA's
Guidelines
for
Preparing
Economic
Analyses
(
U.
S.
EPA,
2000a),
and
7
percent
which
is
recommended
by
OMB
Circular
A
94
(
OMB,
1992).
More
specifically,
the
Base
Estimate
of
benefits
reflects
the
use
of
peerreviewed
methodologies
developed
for
earlier
risk
and
benefit
cost
assessments
related
to
the
Clean
Air
Act,
such
as
the
regulatory
assessments
of
the
Heavy
Duty
Diesel
and
Tier
II
rules
and
the
section
812
Report
to
Congress.
The
Alternative
Estimate
explores
important
aspects
of
the
key
elements
underlying
estimates
of
the
benefits
of
reducing
NOX
emissions,
specifically
focusing
on
estimation
and
valuation
of
mortality
risk
reduction
and
valuation
of
chronic
bronchitis.
The
Alternative
Estimate
of
mortality
reduction
relies
on
recent
scientific
studies
finding
an
association
between
increased
mortality
and
shortterm
exposure
to
particulate
matter
over
days
to
weeks,
while
the
Base
Estimate
relies
on
a
recent
reanalysis
of
earlier
studies
that
associate
long
term
exposure
to
fine
particles
with
increased
mortality.
The
Alternative
Estimate
differs
in
the
following
ways:
It
explicitly
omits
any
impact
of
long
term
exposure
on
premature
mortality,
it
uses
different
data
on
valuation
and
makes
adjustments
relating
to
the
health
status
and
potential
longevity
of
the
populations
most
likely
affected
by
PM,
it
also
uses
a
cost
of
illness
method
to
value
reductions
in
cases
of
chronic
bronchitis
while
the
Base
Estimate
is
based
on
individual's
willingness
to
pay
(
WTP)
to
avoid
a
case
of
chronic
bronchitis.
In
addition,
one
key
area
of
uncertainty
is
the
value
of
a
statistical
life
(
VSL)
for
risk
reductions
in
mortality,
which
is
also
the
category
of
benefits
that
accounts
for
a
large
portion
of
the
total
benefit
estimate.
The
adoption
of
a
value
for
the
projected
reduction
in
the
risk
of
premature
mortality
is
the
subject
of
continuing
discussion
within
the
economic
and
public
policy
analysis
community.
There
is
general
agreement
that
the
value
to
an
individual
of
a
reduction
in
mortality
risk
can
vary
based
on
several
factors,
including
the
age
of
the
individual,
the
type
of
risk,
the
level
of
control
the
individual
has
over
the
risk,
the
individual's
attitude
toward
risk,
and
the
health
status
of
the
individual.
The
Environmental
Economics
Advisory
Committee
(
EEAC)
of
the
EPA
Science
Advisory
Board
(
SAB)
recently
issued
an
advisory
report
which
states
that
``
the
theoretically
appropriate
method
is
to
calculate
WTP
for
individuals
whose
ages
correspond
to
those
of
the
affected
population,
and
that
it
is
preferable
to
base
these
calculations
on
empirical
estimates
of
WTP
by
age''
(
EPA
SAB
EEAC
00
013).
In
developing
our
Base
Estimate
of
the
benefits
of
premature
mortality
reductions,
we
have
appropriately
discounted
over
the
lag
period
between
exposure
and
premature
mortality.
However,
the
empirical
basis
for
adjusting
the
current
$
6
million
VSL
for
other
factors
does
not
yet
justify
including
these
in
our
Base
Estimate.
A
discussion
of
these
factors
is
contained
in
the
RIA
and
supporting
documents.
The
EPA
recognizes
the
need
for
additional
research
by
the
scientific
community
to
develop
additional
empirical
support
for
adjustments
to
VSL
for
the
factors
mentioned
above.
Furthermore,
EPA
prefers
not
to
draw
distinctions
in
the
monetary
value
assigned
to
the
lives
saved
even
if
they
differ
in
age,
health
status,
socioeconomic
status,
gender
or
other
characteristic
of
the
adult
population.
However,
adjustments
to
VSL
for
age
and
life
expectancy
are
explored
in
the
Alternative
Estimate.
Given
its
basis
in
methods
approved
by
the
SAB,
we
employed
the
approach
used
for
the
benefit
analysis
of
the
Heavy
Duty
Engine/
Diesel
Fuel
standards
conducted
in
2000
to
the
RICE
NESHAP
discussed
in
this
preamble.
A
full
discussion
of
considerations
made
in
our
presentation
of
benefits
is
summarized
in
the
preamble
of
the
Final
Heavy
Duty
Engine/
Diesel
Fuel
standards
issued
in
December
2000,
and
in
all
supporting
documentation
and
analyses
of
the
Heavy
Duty
Diesel
Program,
and
in
the
RIA
for
the
proposed
rule.
In
addition
to
the
presentation
of
quantified
health
benefits,
our
estimate
also
includes
a
``
B''
to
represent
those
additional
health
and
environmental
benefits
which
could
not
be
expressed
in
quantitative
incidence
and/
or
economic
value
terms.
A
full
appreciation
of
the
overall
economic
consequences
of
the
RICE
NESHAP
requires
consideration
of
all
benefits
and
costs
expected
to
result
from
the
new
standards,
not
just
those
benefits
and
costs
which
could
be
expressed
here
in
dollar
terms.
A
full
listing
of
the
benefit
categories
that
could
not
be
quantified
or
monetized
in
our
estimate
are
provided
in
Table
3
of
this
preamble.
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TABLE
3.
UNQUANTIFIED
BENEFIT
CATEGORIES
FROM
RICE
EMISSIONS
REDUCTIONS
Unquantified
benefit
categories
associated
with
HAP
Unquantified
benefit
categories
associated
with
ozone
Unquantified
benefit
categories
associated
with
PM
Health
Categories
..........................
Carcinogenicity
mortality.
Genotoxicity
mortality.
Non
Cancer
lethality.
Pulmonary
function
decrement.
Dermal
irritation.
Eye
irritation.
Neurotoxicity.
Immunotoxicity.
Pulmonary
function
decrement.
Liver
damage.
Gastrointestinal
toxicity.
Kidney
damage.
Cardiovascular
impairment.
Hematopoietic
(
Blood
disorders).
Reproductive/
Developmental
toxicity
Airway
responsiveness.
Pulmonary
inflammation.
Increased
susceptibility
to
respiratory
infection.
Acute
inflammation
and
respiratory
cell
damage.
Chronic
respiratory
damage/
Premature
aging
of
lungs.
Emergency
room
visits
for
asthma
Changes
in
pulmonary
function.
Morphological
changes.
Altered
host
defense
mechanisms
Cancer.
Other
chronic
respiratory
disease.
Emergency
room
visits
for
asthma
Lower
and
upper
respiratory
symptoms.
Acute
bronchitis.
Shortness
of
breath.
Welfare
Categories
........................
Corrosion/
deterioration.
Unpleasant
odors.
Transportation
safety
concerns.
Yield
reductions/
Foliar
injury.
Biomass
decrease.
Species
richness
decline.
Species
diversity
decline.
Community
size
decrease.
Organism
lifespan
decrease.
Trophic
web
shortening.
Ecosystem
and
vegetation
effects
in
Class
I
areas
(
e.
g.,
national
parks).
Damage
to
urban
ornamentals
(
e.
g.,
grass,
flowers,
shrubs,
and
trees
in
urban
areas).
Commercial
field
crops.
Fruit
and
vegetable
crops
Reduced
yields
of
tree
seedlings,
commercial
and
non
commercial
forests.
Damage
to
ecosystems.
Materials
damage.
Materials
damage.
Damage
to
ecosystems
(
e.
g.,
acid
sulfate
deposition).
Nitrates
in
drinking
water.
Our
Base
Estimate
of
benefits
totals
approximately
$
280
million
when
using
a
3
percent
interest
rate
(
or
approximately
$
265
million
when
using
a
7
percent
interest
rate).
The
Alternative
Estimate
totals
approximately
$
40
million
when
using
a
3
percent
interest
rate
(
or
approximately
$
45
million
when
using
a
7
percent
interest
rate).
Benefit
cost
comparison
(
or
net
benefits)
is
another
tool
used
to
evaluate
the
reallocation
of
society's
resources
needed
to
address
the
pollution
externality
created
by
the
operation
of
RICE
units.
The
additional
costs
of
internalizing
the
pollution
produced
at
major
sources
of
emissions
from
RICE
units
is
compared
to
the
improvement
in
society's
well
being
from
a
cleaner
and
healthier
environment.
Comparing
benefits
of
the
proposed
rule
to
the
costs
imposed
by
alternative
ways
to
control
emissions
optimally
identifies
a
strategy
that
results
in
the
highest
net
benefit
to
society.
In
the
case
of
the
proposed
RICE
NESHAP,
we
are
proposing
only
one
option,
the
minimal
level
of
control
mandated
by
the
Clean
Air
Act,
or
the
MACT
floor.
Table
4
of
this
preamble
presents
a
summary
of
the
costs,
emission
reductions,
and
quantifiable
benefits
by
engine
type.
Table
5
of
this
preamble
presents
a
summary
of
net
benefits.
Based
on
estimated
compliance
costs
associated
with
the
proposed
rule
and
the
predicted
change
in
prices
and
production
in
the
affected
industries,
the
estimated
social
costs
of
the
proposed
rule
are
$
254
million
(
1998$)
as
are
discussed
previously
in
this
preamble.
Unfortunately,
the
air
benefits
characterized
in
this
analysis
are
limited
by
the
data
available
on
the
numerous
health
and
welfare
categories
for
the
affected
pollutants
and
by
the
lack
of
approved
methods
for
quantifying
effects.
Using
the
Base
Estimate
of
benefits,
the
portion
of
total
benefits
associated
with
NOX
and
PM
reductions
exceed
the
estimated
total
costs
of
the
proposed
rule
by
$
25
million
+
B
when
using
a
3
percent
discount
rate
(
or
approximately
$
10
million
+
B
when
using
a
7
percent
discount
rate).
However,
using
the
more
conservative
Alternative
Estimate
of
benefits,
net
benefits
are
negative.
Under
the
Alternative
Estimate,
net
benefits
total
¥
$
215
million
+
B
under
a
3
percent
discount
rate
(
or
approximately
¥
$
210
million
+
B
when
using
a
7
percent
discount
rate).
Approximately
90
percent
of
the
total
benefits
($
255
million
under
the
Base
Estimate,
and
$
35
million
under
the
Alternative
Estimate)
are
associated
with
NOX
reductions
from
the
4SRB
subcategory
for
new
and
existing
engines.
Approximately
10
percent
of
the
total
benefits
($
25
million
under
the
Base
Estimate,
and
$
5
million
under
the
Alternative
Estimate)
are
associated
with
the
PM
reductions
from
the
compression
ignition
engine
subcategory
at
new
sources.
In
both
cases,
net
benefits
would
be
greater
if
all
the
benefits
of
the
HAP
and
other
pollutant
reductions
could
be
quantified.
Notable
omissions
to
the
net
benefits
include
all
benefits
of
HAP
and
CO
reductions,
including
reduced
cancer
incidences,
toxic
morbidity
effects,
and
cardiovascular
and
CNS
effects.
It
is
also
important
to
note
that
not
all
benefits
of
NOX
reductions
have
been
monetized.
Categories
which
have
contributed
significantly
to
monetized
benefits
in
past
analyses
(
see
the
RIA
for
the
Heavy
Duty
Engine/
Diesel
standards)
include
commercial
agriculture
and
forestry,
recreational
and
residential
visibility
improvements,
and
estuarine
improvements.
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TABLE
4.
SUMMARY
OF
COSTS,
EMISSION
REDUCTIONS,
AND
QUANTIFIABLE
BENEFITS
BY
ENGINE
TYPE
Type
of
engine
Total
annualized
cost
(
million
$/
yr
in
the
5th
year
after
promulgation
Emission
reductions
A
(
tons/
yr
in
the
5th
year
after
promulgation)
Quantifiable
annual
monetized
benefits
B,
C
(
million
$/
yr
in
the
2005)
HAP
CO
NOX
PM
Base
estimate
Alternative
estimate
2SLB
New
...........................................................
3
250
2,025
0
0
B1
B2
4SLB
New
...........................................................
66
4,035
36,240
0
0
B3
B4
4SRB
Existing
.....................................................
38
230
98,040
69,900
0
$
105
+
B
5
$
100
+
B
6
$
15
+
B
7
$
15
+
B
8
4SRB
New
...........................................................
48
215
91,820
98,000
0
$
150
+
B
9
$
140
+
B
10
$
20
+
B
11
$
25
+
B
12
CI
New
.................................................................
99
305
6,320
0
3,700
$
25
+
B
13
$
5
+
B
14
Total
.............................................................
254
5,035
234,445
167,900
3,700
$
280
+
B
$
265
+
B
$
40
+
B
$
45
+
B
A
For
the
calculation
of
PM
related
benefits,
total
NOX
reductions
are
multiplied
by
the
appropriate
benefit
per
ton
value
presented
in
Table
8
7
of
the
RIA.
For
the
calculation
of
ozone
related
benefits,
NOX
reductions
are
multiplied
by
5
12
to
account
for
ozone
season
months
and
0.74
to
account
for
Eastern
States
in
the
ozone
analysis.
The
resulting
ozone
related
NOX
reductions
are
multiplied
by
$
28
per
ton.
Ozone
related
benefits
are
summed
together
with
PM
related
benefits
to
derive
total
benefits
of
NOX
reductions.
All
benefits
values
are
rounded
to
the
nearest
$
5
million.
B
Benefits
of
HAP
and
CO
emissions
reductions
are
not
quantified
in
this
analysis
and,
therefore,
are
not
presented
in
this
table.
The
quantifiable
benefits
are
from
emissions
reductions
of
NOX
and
PM
only.
For
notational
purposes,
unquantified
benefits
are
indicated
with
a
``
B''
to
represent
monetary
benefits.
A
detailed
listing
of
unquantified
NOX,
PM,
and
HAP
related
health
effects
is
provided
in
Table
8
13
of
the
RIA.
C
Results
reflect
the
use
of
two
different
discount
rates;
a
3
percent
rate
which
is
recommended
by
EPA's
Guidelines
for
Preparing
Economic
Analyses
(
U.
S.
EPA,
2000a),
and
7
percent
which
is
recommended
by
OMB
Circular
A
94
(
OMB,
1992).
TABLE
5.
ANNUAL
NET
BENEFITS
OF
THE
RICE
NESHAP
IN
2005
Million
1998$
A
Social
Costs
B
.................................................................................................................................................................................
$
255
Social
Benefits
B,
C,
D:
HAP
related
benefits
................................................................................................................................................................
Not
monetized
CO
related
benefits
..................................................................................................................................................................
Not
monetized
Ozone
and
PM
related
welfare
benefits
.................................................................................................................................
Not
monetized
Ozone
and
PM
related
health
benefits:
Base
Estimate
Using
3%
Discount
Rate
.......................................................................................................................................
$
280
+
B
Using
7%
Discount
Rate
.......................................................................................................................................
$
265
+
B
Alternative
Estimate
Using
3%
Discount
Rate
.......................................................................................................................................
$
40
+
B
Using
7%
Discount
Rate
.......................................................................................................................................
$
45
+
B
Net
Benefits
(
Benefits
Costs)
C,
D:
Base
Estimate
Using
3%
Discount
Rate
.......................................................................................................................................
$
25
+
B
Using
7%
Discount
Rate
.......................................................................................................................................
$
10
+
B
Alternative
Estimate
Using
3%
Discount
Rate
.......................................................................................................................................
$
215
+
B
Using
7%
Discount
Rate
.......................................................................................................................................
$
210
+
B
A
All
costs
and
benefits
are
rounded
to
the
nearest
$
5
million.
Thus,
figures
presented
in
this
chapter
may
not
exactly
equal
benefit
and
cost
numbers
presented
in
earlier
sections
of
the
chapter.
B
Note
that
costs
are
the
total
costs
of
reducing
all
pollutants,
including
HAP
and
CO,
as
well
as
NOx
and
PM
10.
Benefits
in
this
table
are
associated
only
with
PM
and
NOx
reductions.
C
Not
all
possible
benefits
or
disbenefits
are
quantified
and
monetized
in
this
analysis.
Potential
benefit
categories
that
have
not
been
quantified
and
monetized
are
listed
in
Table
8
13.
B
is
the
sum
of
all
unquantified
benefits
and
disbenefits.
D
Monetized
benefits
are
presented
using
two
different
discount
rates.
Results
calculated
using
3
percent
discount
rate
are
recommended
by
EPA's
Guidelines
for
Preparing
Economic
Analyses
(
U.
S.
EPA,
2000a).
Results
calculated
using
7
percent
discount
rate
are
recommended
by
OMB
Circular
A
94
(
OMB,
1992).
B.
Executive
Order
13132,
Federalism
Executive
Order
13132
(
64
FR
43255,
August
10,
1999),
requires
us
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
The
proposed
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
We
are
required
by
section
112
of
the
CAA,
42
U.
S.
C.
7412,
to
establish
the
standards
in
the
proposed
rule.
The
proposed
rule
primarily
affects
private
industry
and
does
not
impose
significant
economic
costs
on
State
or
local
governments.
The
proposed
rule
does
not
include
an
express
provision
preempting
State
or
local
regulations.
Thus,
the
requirements
of
section
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Proposed
Rules
the
Executive
Order
do
not
apply
to
the
proposed
rule.
Although
section
6
of
Executive
Order
13132
does
not
apply
to
the
proposed
rule,
we
consulted
with
representatives
of
State
and
local
governments
to
enable
them
to
provide
meaningful
and
timely
input
into
the
development
of
the
proposed
rule.
This
consultation
took
place
during
the
ICCR
FACA
committee
meetings
where
members
representing
State
and
local
governments
participated
in
developing
recommendations
for
EPA's
combustion
related
rulemakings,
including
the
proposed
rule.
The
concerns
raised
by
representatives
of
State
and
local
governments
were
considered
during
the
development
of
the
proposed
rule.
In
the
spirit
of
Executive
Order
13132,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
State
and
local
governments,
we
specifically
solicit
comment
on
the
proposed
rule
from
State
and
local
officials.
C.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175
(
65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
``
Policies
that
have
tribal
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
the
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes.''
The
proposed
rule
does
not
have
tribal
implications.
It
will
not
have
substantial
direct
effects
on
tribal
governments,
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
No
known
stationary
RICE
are
located
within
the
jurisdiction
of
any
tribal
government.
Thus,
Executive
Order
13175
does
not
apply
to
the
proposed
rule.
D.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
we
have
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
we
must
evaluate
the
environmental
health
or
safety
effects
of
the
proposed
rule
on
children,
and
explain
why
the
proposed
rule
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered.
The
Agency
does
not
have
reason
to
believe
the
environmental
health
or
safety
risks
associated
with
the
emissions
addressed
by
the
proposed
rule
present
a
disproportionate
risk
to
children.
The
public
is
invited
to
submit
or
identify
peer
reviewed
studies
and
data,
of
which
the
Agency
may
not
be
aware,
that
assess
the
results
of
early
life
exposure
to
the
pollutants
addressed
by
the
proposed
rule
and
suggest
a
disproportionate
impact.
E.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
Executive
Order
13211,
(
66
FR
28355,
May
22,
2001),
requires
EPA
to
prepare
and
submit
to
the
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
a
Statement
of
Energy
Effects
for
certain
actions
identified
as
significant
energy
actions.
Section
4(
b)
of
Executive
Order
13211
defines
significant
energy
actions
as
any
action
by
an
agency
(
normally
published
in
the
Federal
Register)
that
promulgates
or
is
expected
to
lead
to
the
promulgation
of
a
final
rule
or
regulation,
including
notices
of
inquiry,
advance
notices
of
proposed
rulemaking,
and
notices
of
proposed
rulemaking:
(
1)(
i)
that
is
a
significant
regulatory
action
under
Executive
Order
12866
or
any
successor
order,
and
(
ii)
is
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy;
or
(
2)
that
is
designated
by
the
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs
as
a
significant
energy
action.
While
the
proposed
rule
is
a
significant
regulatory
action
under
Executive
Order
12866,
EPA
has
determined
that
the
proposed
rule
is
not
a
significant
energy
action
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy
based
on
the
Statement
of
Energy
Effects
for
this
action
provided
below.
The
RIA
estimates
changes
in
prices
and
production
levels
for
all
energy
markets
(
i.
e.,
petroleum,
natural
gas,
electricity,
and
coal).
We
also
estimate
how
changes
in
the
energy
markets
will
impact
other
users
of
energy,
such
as
manufacturing
markets
and
residential,
industrial
and
commercial
consumers
of
energy.
The
results
of
the
economic
impact
analysis
for
the
proposed
rule
are
shown
for
2005,
for
that
is
the
year
in
which
full
implementation
of
the
rule
is
expected
to
occur.
These
results
show
that
there
will
be
minimal
changes
in
price,
if
any,
for
most
energy
products
affected
by
implementation
of
the
proposed
rule.
Only
a
slight
price
increase
(
about
0.001
percent
to
0.02
percent)
may
occur
in
three
of
the
energy
sectors:
petroleum,
electricity,
and
coal
products
nationwide,
and
approximately
a
one
tenth
of
one
percent
(
i.
e.,
0.10
percent)
change
in
natural
gas
prices.
The
change
in
energy
costs
associated
with
the
proposed
rule,
however,
represents
only
0.03
percent
of
expected
annual
energy
expenditures
by
residential
consumers
in
2005,
a
0.008
percent
change
for
transportation
consumers
of
energy,
and
about
0.03
percent
of
energy
expenditures
in
the
commercial
sector.
In
addition,
no
discernable
impact
on
exports
or
imports
of
energy
products
is
expected.
Therefore,
the
impacts
on
energy
markets
and
users
will
be
relatively
small
nationwide
as
a
result
of
implementation
of
the
proposed
reciprocating
internal
combustion
engines
NESHAP.
F.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
we
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
a
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
us
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost
effective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
proposed
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
us
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
we
establish
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2002
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Proposed
Rules
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
we
must
develop
a
small
government
agency
plan
under
section
203
of
the
UMRA.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
We
have
determined
that
the
proposed
rule
contains
a
Federal
mandate
that
may
result
in
expenditures
of
$
100
million
or
more
for
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
Accordingly,
we
have
prepared
a
written
statement
under
section
202
of
the
UMRA
which
is
summarized
below.
The
written
statement
is
in
the
docket.
1.
Statutory
Authority
As
discussed
previously
in
this
preamble,
the
statutory
authority
for
the
proposed
rulemaking
is
section
112
of
the
CAA.
Section
112(
b)
lists
the
189
chemicals,
compounds,
or
groups
of
chemicals
deemed
by
Congress
to
be
HAP.
These
toxic
air
pollutants
are
to
be
regulated
by
NESHAP.
Section
112(
d)
of
the
CAA
directs
us
to
develop
NESHAP
based
on
MACT
which
require
existing
and
new
major
sources
to
control
emissions
of
HAP.
These
NESHAP
apply
to
all
stationary
RICE
located
at
major
sources
of
HAP
emissions,
however,
only
certain
existing
and
new
or
reconstructed
stationary
RICE
have
substantive
regulatory
requirements.
In
compliance
with
section
205(
a),
we
identified
and
considered
a
reasonable
number
of
regulatory
alternatives.
The
regulatory
alternative
upon
which
the
proposed
rule
is
based
represents
the
MACT
floor
for
stationary
RICE
and,
as
a
result,
it
is
the
least
costly
and
least
burdensome
alternative.
2.
Social
Costs
and
Benefits
The
RIA
prepared
for
the
proposed
rule,
including
the
Agency's
assessment
of
costs
and
benefits,
is
detailed
in
the
``
Regulatory
Impact
Analysis
for
the
Proposed
RICE
NESHAP''
in
the
docket.
Based
on
estimated
compliance
costs
on
all
sources
associated
with
the
proposed
rule
and
the
predicted
change
in
prices
and
production
in
the
affected
industries,
the
estimated
social
costs
of
the
proposed
rule
are
$
254
million
(
1998$).
It
is
estimated
that
5
years
after
implementation
of
the
proposed
rule,
HAP
will
be
reduced
by
5,000
tons
per
year
due
to
reductions
in
formaldehyde,
acetaldehyde,
acrolein,
methanol
and
other
HAP
from
existing
and
new
stationary
RICE.
Formaldehyde
and
acetaldehyde
have
been
classified
as
``
probable
human
carcinogens.''
Acrolein,
methanol
and
the
other
HAP
are
not
considered
carcinogenic,
but
produce
several
other
toxic
effects.
The
proposed
rule
will
also
achieve
reductions
in
234,400
tons
of
CO,
approximately
167,900
tons
of
NOX
per
year,
and
approximately
3,700
tons
of
PM
per
year.
Exposure
to
CO
can
effect
the
cardiovascular
system
and
the
central
nervous
system.
Emissions
of
NOX
can
transform
into
PM,
which
can
result
in
fatalities
and
many
respiratory
problems
(
such
as
asthma
or
bronchitis);
and
NOX
can
also
transform
into
ozone
causing
several
respiratory
problems
to
affected
populations.
At
the
present
time,
the
Agency
cannot
provide
a
monetary
estimate
for
the
benefits
associated
with
the
reductions
in
HAP
and
CO.
For
NOX
and
PM,
we
estimated
the
benefits
associated
with
health
effects
of
PM
but
were
unable
to
quantify
all
categories
of
benefits
of
NOX
(
particularly
those
associated
with
ecosystem
and
environmental
effects).
Unquantified
benefits
are
noted
with
``
B''
in
the
estimates
presented
below.
Total
monetized
benefits
are
approximately
$
280
million
+
B
(
1998$)
under
our
Base
Estimate
when
using
a
3
percent
discount
rate
(
or
approximately
$
265
million
+
B
when
using
a
7
percent
discount
rate).
Under
the
Alternative
Estimate,
total
benefits
are
approximately
$
40
million
+
B
when
using
a
3
percent
discount
rate
(
or
approximately
$
45
million
+
B
when
using
a
7
percent
discount
rate).
The
approach
to
value
benefits
is
discussed
in
more
detail
in
this
preamble
under
the
Executive
Order
12866.
These
monetized
benefits
should
be
considered
along
with
the
many
categories
of
benefits
that
we
are
unable
to
place
a
dollar
value
on
to
consider
the
total
benefits
of
the
proposed
rule.
3.
Future
and
Disproportionate
Costs
The
UMRA
requires
that
we
estimate,
where
accurate
estimation
is
reasonably
feasible,
future
compliance
costs
imposed
by
the
proposed
rule
and
any
disproportionate
budgetary
effects.
Our
estimates
of
the
future
compliance
costs
of
the
proposed
rule
are
discussed
previously
in
this
preamble.
We
do
not
believe
that
there
will
be
any
disproportionate
budgetary
effects
of
the
proposed
rule
on
any
particular
areas
of
the
country,
State
or
local
governments,
types
of
communities
(
e.
g.,
urban,
rural),
or
particular
industry
segments.
4.
Effects
on
the
National
Economy
The
UMRA
requires
that
we
estimate
the
effect
of
the
proposed
rule
on
the
national
economy.
To
the
extent
feasible,
we
must
estimate
the
effect
on
productivity,
economic
growth,
full
employment,
creation
of
productive
jobs,
and
international
competitiveness
of
the
U.
S.
goods
and
services
if
we
determine
that
accurate
estimates
are
reasonably
feasible
and
that
such
effect
is
relevant
and
material.
The
nationwide
economic
impact
of
the
proposed
rule
is
presented
in
the
``
Regulatory
Impact
Analysis
for
RICE
NESHAP''
in
the
docket.
This
analysis
provides
estimates
of
the
effect
of
the
proposed
rule
on
most
of
the
categories
mentioned
above.
The
results
of
the
economic
impact
analysis
are
summarized
previously
in
this
preamble.
5.
Consultation
With
Government
Officials
The
UMRA
requires
that
we
describe
the
extent
of
our
prior
consultation
with
affected
State,
local,
and
tribal
officials,
summarize
the
officials'
comments
or
concerns,
and
summarize
our
response
to
those
comments
or
concerns.
In
addition,
section
203
of
UMRA
requires
that
we
develop
a
plan
for
informing
and
advising
small
governments
that
may
be
significantly
or
uniquely
impacted
by
a
proposal.
Although
the
proposed
rule
does
not
affect
any
State,
local,
or
tribal
governments,
we
have
consulted
with
State
and
local
air
pollution
control
officials.
We
also
have
held
meetings
on
the
proposed
rule
with
many
of
the
stakeholders
from
numerous
individual
companies,
environmental
groups,
consultants
and
vendors,
labor
unions,
and
other
interested
parties.
We
have
added
materials
to
the
docket
to
document
these
meetings.
In
addition,
we
have
determined
that
the
proposed
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments.
Therefore,
today's
proposed
rule
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.
G.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1966
(
SBREFA),
5
U.
S.
C.
601
et
seq.
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
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/
Thursday,
December
19,
2002
/
Proposed
Rules
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
proposed
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
proposed
rule
on
small
entities,
``
small
entity''
is
defined
as:
(
1)
A
small
business
whose
parent
company
has
fewer
than
500
employees
(
for
most
affected
industries);
(
2)
a
small
governmental
jurisdiction
that
is
a
government
or
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
forprofit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
It
should
be
noted
that
the
proposed
rule
covers
more
than
25
different
industries.
For
each
industry,
we
applied
the
definition
of
a
small
business
provided
by
the
Small
Business
Administration
at
13
CFR
part
121,
and
classified
by
the
NAICS.
The
Small
Business
Administration
(
SBA)
defines
small
businesses
in
most
industries
affected
by
the
proposed
rule
as
those
with
fewer
than
500
employees.
However,
SBA
has
defined
``
small
business''
differently
for
a
limited
number
of
industries,
either
through
reference
to
another
employment
cap
or
through
the
substitution
of
total
yearly
revenues
in
place
of
an
employment
limit.
For
more
information
on
the
size
standards
for
particular
industries,
please
refer
to
the
regulatory
impact
analysis
in
the
docket.
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
In
support
of
this
certification,
EPA
examined
the
percentage
of
annual
revenues
that
compliance
costs
may
consume
if
small
entities
must
absorb
all
of
the
compliance
costs
associated
with
the
proposed
rule.
Since
many
firms
will
be
able
to
pass
along
some
or
all
compliance
costs
to
customers,
actual
impacts
will
frequently
be
lower
than
those
analyzed
here.
As
is
mentioned
in
previous
sections
of
this
preamble,
the
proposed
rule
will
set
standards
for
only
a
limited
set
of
existing
units,
specifically
4SRB
units.
For
all
other
types
of
engines,
the
proposed
rule
would
impose
requirements
only
on
new
engines.
The
EPA
identified
a
total
of
26,832
engines
located
at
commercial,
industrial,
and
government
facilities.
From
this
initial
population
of
26,832
engines,
10,118
engines
were
excluded
because
the
proposed
regulation
will
not
cover
engines
smaller
than
500
horsepower
or
engines
used
to
supply
emergency/
backup
power.
Of
the
16,714
units
remaining,
2,645
units
had
sufficient
information
to
assign
to
model
unit
numbers
developed
during
the
cost
analysis.
These
2,645
units
were
linked
to
834
existing
facilities,
owned
by
153
parent
companies.
A
total
of
47
companies
were
identified
as
small
entities,
and
only
13
of
them
own
4SRB
engines.
These
small
entities
own
a
total
of
39
4SRB
units
at
21
facilities.
Further,
assuming
only
40
percent
of
the
all
RICE
sources
are
located
at
major
sources
and,
thus,
affected
by
the
regulation,
about
16
of
the
39
4SRB
units
identified
at
facilities
owned
by
small
businesses
would
be
located
at
major
sources.
Under
this
scenario,
there
are
no
small
firms
that
have
compliance
costs
above
3
percent
of
firm
revenues
and
only
two
small
firms
owning
4SRB
engines
that
have
impacts
between
1
and
3
percent
of
revenues.
In
addition
to
12
small
firms
with
4SRB
engines,
there
is
one
small
government
in
the
Inventory
Database
affected
by
the
proposed
rule.
The
costs
to
this
city
are
approximately
$
3
per
capita
annually
assuming
their
engine
is
affected
by
the
proposed
rule,
less
than
0.01
percent
of
median
household
income.
Based
on
this
subset
of
the
existing
engines
population,
the
regulation
will
affect
no
small
entities
owning
RICE
at
a
cost
to
sales
ratio
(
CSR)
greater
than
3
percent,
while
approximately
4
percent
(
2/
47)
of
small
entities
owning
RICE
greater
than
500
horsepower
will
have
compliance
costs
between
1
and
3
percent
of
sales
under
an
upper
bound
cost
scenario.
In
comparison,
the
total
existing
population
of
engines
with
greater
than
500
horsepower
that
are
not
backup
units
is
estimated
to
be
22,018.
Assuming
the
same
breakdown
of
large
and
small
company
ownership
of
engines
in
the
total
population
of
existing
engines
as
in
the
subset
with
parent
company
information
identified,
the
Agency
expects
that
approximately
17
small
entities
in
the
existing
population
of
RICE
owners
would
have
CSR
between
1
and
3
percent
under
an
upper
bound
cost
scenario
where
we
assume
all
RICE
owned
by
small
entities
are
located
at
major
sources.
In
addition,
because
many
small
entities
owning
RICE
will
not
be
affected
because
of
the
exclusion
of
engines
with
less
than
500
horsepower,
the
percentage
of
all
small
companies
owning
RICE
that
are
affected
by
the
proposed
rule
is
even
smaller.
Based
on
the
proportion
of
engines
in
the
Inventory
Database
that
are
greater
than
500
horsepower
and
are
not
backup
units
(
16,714/
26,832,
or
62.3
percent)
and
assuming
that
small
companies
own
the
same
proportion
of
small
engines
(
less
than
500
horsepower)
as
they
do
of
engines
greater
than
500
horsepower,
the
Agency
estimates
that
628
small
companies
own
RICE.
Of
all
small
companies
owning
RICE,
2.7
percent
(
17/
628)
are
expected
to
have
CSR
between
1
and
3
percent
under
an
upper
bound
cost
scenario.
If
the
percentage
of
RICE
owned
by
small
companies
that
are
located
at
major
sources
is
the
same
as
the
engine
population
overall
(
40
percent),
only
about
1.1
percent
of
small
companies
owning
RICE
would
be
expected
to
have
CSR
greater
than
1
percent.
The
average
profit
margin
for
the
industries
in
our
analysis
is
approximately
5
percent.
Therefore,
based
on
this
median
profit
margin
data,
it
seems
reasonable
to
review
the
number
of
small
firms
with
CSR
above
3
percent
in
screening
for
significant
impacts.
In
addition,
based
on
the
low
number
of
affected
small
firms,
the
fact
that
no
small
firms
have
CSR
between
3
and
5
percent,
and
the
fact
that
industry
profit
margins
average
5
percent,
this
analysis
concludes
that
the
proposed
rule
will
not
have
a
significant
impact
on
a
substantial
number
of
existing
small
entities.
For
new
sources,
it
can
be
reasonably
assumed
that
the
investment
decision
to
purchase
a
new
engine
may
be
slightly
altered
as
a
result
of
the
proposed
rule.
In
fact,
for
the
entire
population
of
affected
engines
(
approximately
20,000
new
engines
over
a
5
year
period),
2
fewer
engines
(
0.01
percent)
may
be
purchased
due
to
changes
in
costs
of
the
engines
and
market
responses
to
the
proposed
rule.
It
is
not
possible,
however,
to
determine
future
investment
decisions
by
the
small
entities
in
the
affected
industries,
so
we
cannot
link
these
2
engines
to
any
one
firm
(
small
or
large).
Overall,
it
is
very
unlikely
that
a
substantial
number
of
small
firms
who
may
consider
purchasing
a
new
engine
will
be
significantly
impacted,
because
the
decision
to
purchase
new
engines
is
not
altered
to
a
large
extent.
In
addition
to
this
consideration
of
costs
on
some
firms
attributable
to
the
proposed
rule,
EPA
notes
the
proposed
rule
is
likely
to
increase
revenues
for
many
small
firms,
including
those
not
regulated
by
the
proposed
rule,
due
to
a
predictable
increase
in
prices
of
natural
gas
in
the
industry.
Although
the
proposed
rule
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities,
EPA
nonetheless
has
tried
to
reduce
the
impact
of
the
proposed
rule
on
small
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Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
entities.
In
the
proposed
rule,
we
are
applying
the
minimum
level
of
control
allowed
by
the
CAA
(
i.
e.,
the
MACT
floor),
and
the
minimum
level
of
monitoring,
recordkeeping,
and
reporting
by
affected
sources.
In
addition,
as
mentioned
earlier
in
the
preamble,
new
RICE
units
with
capacities
under
500
horsepower
and
those
that
operate
as
emergency/
limited
use
units
are
not
covered
by
the
proposed
rule,
provisions
that
should
greatly
reduce
the
level
of
small
entity
impacts.
We
continue
to
be
interested
in
reducing
any
remaining
impacts
of
the
proposed
rule
on
small
entities
and
welcome
comments
on
issues
related
to
such
impacts.
H.
Paperwork
Reduction
Act
The
information
collection
requirements
in
the
proposed
rule
will
be
submitted
for
approval
to
the
OMB
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
An
Information
Collection
Request
(
ICR)
document
has
been
prepared
(
ICR
No.
1975.01)
and
a
copy
may
be
obtained
from
Susan
Auby
by
mail
at
the
U.
S.
Environmental
Protection
Agency,
Collection
Strategies
Division
(
2822),
1200
Pennsylvania
Avenue
NW.,
Washington,
DC
200,
by
email
at
auby.
susan@
epa.
gov,
or
by
calling
(
202)
566
1672.
A
copy
may
also
be
downloaded
off
the
internet
at
http:/
/
www.
epa.
gov/
icr.
The
information
requirements
are
not
effective
until
OMB
approves
them.
The
information
requirements
are
based
on
notification,
recordkeeping,
and
reporting
requirements
in
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A),
which
are
mandatory
for
all
operators
subject
to
national
emission
standards.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(
42
U.
S.
C.
7414).
All
information
submitted
to
the
EPA
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
Agency
policies
set
forth
in
40
CFR
part
2,
subpart
B.
The
proposed
rule
would
require
maintenance
inspections
of
the
control
devices
but
would
not
require
any
notifications
or
reports
beyond
those
required
by
the
General
Provisions.
The
recordkeeping
requirements
require
only
the
specific
information
needed
to
determine
compliance.
The
annual
monitoring,
reporting,
and
recordkeeping
burden
for
this
collection
(
averaged
over
the
first
3
years
after
the
effective
date
of
the
standards)
is
estimated
to
be
142,436
labor
hours
per
year
at
a
total
annual
cost
of
$
15,998,347.
The
estimate
includes
a
one
time
performance
test
and
report
(
with
repeat
tests
where
needed);
onetime
purchase
and
installation
of
bag
leak
detection
systems;
one
time
submission
of
a
startup,
shutdown,
and
malfunction
plan
with
semiannual
reports
for
any
event
when
the
procedures
in
the
plan
were
not
followed;
semiannual
excess
emission
reports;
maintenance
inspections;
notifications;
and
recordkeeping.
Total
capital/
startup
costs
associated
with
the
monitoring
requirements
over
the
3
year
period
of
the
ICR
are
estimated
at
$
5,436,882,
with
operation
and
maintenance
costs
of
$
1,208,206/
yr.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
That
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
Agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
the
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Comments
are
requested
on
our
need
for
the
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
Send
comments
on
the
ICR
to
the
U.
S.
EPA,
Director,
Collection
Strategies
Division
(
2822),
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20500;
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
St.,
NW.,
Washington,
DC
20503,
marked
``
Attention:
Desk
Officer
for
EPA.''
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
December
19,
2002,
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
January
21,
2003.
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
the
proposed
rule.
I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
(
NTTAA)
of
1995
(
Pub.
L.
No.
104
113;
15
U.
S.
C.
272
note)
directs
EPA
to
use
voluntary
consensus
standards
in
their
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
directs
us
to
provide
Congress,
through
annual
reports
to
OMB,
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.
The
proposed
rulemaking
involves
technical
standards.
We
propose
in
the
rule
to
use
EPA
Methods
1,
1A,
3A,
3B,
4,
10
of
40
CFR
part
60,
appendix
A;
Method
320
of
40
CFR
part
63,
appendix
A;
PS
3,
PS
4A
of
40
CFR
part
60,
appendix
B;
EPA
SW
8
Method
0011,
and
ARB
Method
430,
California
Environmental
Protection
Agency,
Air
Resources
Board,
2020
L
Street,
Sacramento,
CA
95812.
Consistent
with
the
NTTAA,
we
conducted
searches
to
identify
voluntary
consensus
standards
in
addition
to
these
EPA
methods.
No
applicable
voluntary
consensus
standards
were
identified
for
EPA
Methods
1A,
3B,
PS
3,
PS
4
of
CFR
part
60,
and
ARB
Method
430,
California
Environmental
Protection
Agency,
Air
Resources
Board,
2020
L
Street,
Sacramento,
CA
95812.
The
search
and
review
results
have
been
documented
and
are
placed
in
the
docket
for
the
proposed
rule.
One
voluntary
consensus
standard
was
identified
as
applicable,
and
we
propose
to
use
that
standard
in
the
proposed
rule.
The
voluntary
consensus
standard,
ASTM
D6522
00
(
2000)
Standard
Test
Method
for
Determination
of
Nitrogen
Oxides,
Carbon
Monoxide,
and
Oxygen
Concentrations
in
Emissions
From
Natural
Gas
Fired
Reciprocating
Engines,
Combustion
Turbines,
Boilers,
and
Process
Heaters
Using
Portable
Analyzers,
is
an
acceptable
alternative
procedure
for
use
in
determining
carbon
monoxide
and
oxygen
concentrations
the
exhaust
gases
of
reciprocating
internal
combustion
engines.
In
addition
to
the
voluntary
consensus
standard
we
propose
to
use
in
the
rule,
this
search
for
emission
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/
Vol.
67,
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244
/
Thursday,
December
19,
2002
/
Proposed
Rules
measurement
procedures
identified
ten
other
voluntary
consensus
standards.
We
determined
that
six
of
these
ten
standards
were
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rulemaking.
Therefore,
we
do
not
propose
to
adopt
these
standards
today.
The
reasons
for
this
determination
for
the
six
methods
are
discussed
below.
Two
of
the
six
voluntary
consensus
standards
are
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rulemaking
because
they
are
too
general,
too
broad,
or
not
sufficiently
detailed
to
assure
compliance
with
EPA
regulatory
requirements:
ASTM
E337
84
(
Reapproved
1996),
``
Standard
Test
Method
for
Measuring
Humidity
with
a
Psychrometer
(
the
Measurement
of
Wet
and
Dry
Bulb
Temperatures),''
for
EPA
Method
4
of
40
CFR
part
60,
appendix
A;
and
CAN/
CSA
Z223.2
M86(
1986),
``
Method
for
the
Continuous
Measurement
of
Oxygen,
Carbon
Dioxide,
Carbon
Monoxide,
Sulphur
Dioxide,
and
Oxides
of
Nitrogen
in
Enclosed
Combustion
Flue
Gas
Streams,''
for
EPA
Method
3A
of
40
CFR
part
60,
appendix
A.
Four
of
the
six
voluntary
consensus
standards
are
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rulemaking
because
they
lacked
sufficient
quality
assurance
and
quality
control
requirements
necessary
for
EPA
compliance
assurance
requirements:
ASTM
D3154
91,
``
Standard
Method
for
Average
Velocity
in
a
Duct
(
Pitot
Tube
Method),''
for
EPA
Methods
1,
2,
2C,
3,
3B,
and
4
of
40
CFR
part
60,
appendix
A;
ASTM
D5835
95,
``
Standard
Practice
for
Sampling
Stationary
Source
Emissions
for
Automated
Determination
of
Gas
Concentration,''
for
EPA
Method
3A
of
40
CFR
part
60,
appendix
A;
ISO
10396:
1993,
``
Stationary
Source
Emissions:
Sampling
for
the
Automated
Determination
of
Gas
Concentrations,''
for
EPA
Method
3A
of
40
CFR
part
60,
appendix
A;
ISO
9096:
1992,
``
Determination
of
Concentration
and
Mass
Flow
Rate
of
Particulate
Matter
in
Gas
Carrying
Ducts
Manual
Gravimetric
Method,''
for
EPA
Method
5
of
40
CFR
part
60,
appendix
A.
The
following
four
of
the
ten
voluntary
consensus
standards
identified
in
this
search
were
not
available
at
the
time
the
review
was
conducted
for
the
purposes
of
the
proposed
rulemaking
because
they
are
under
development
by
a
voluntary
consensus
body:
ASME/
BSR
MFC
13M,
``
Flow
Measurement
by
Velocity
Traverse,''
for
EPA
Method
1
(
and
possibly
2)
of
40
CFR
part
60,
appendix
A;
ISO/
DIS
12039,
``
Stationary
Source
Emissions
Determination
of
Carbon
Monoxide,
Carbon
Dioxide,
and
Oxygen
Automated
Methods,''
for
EPA
Method
3A
of
40
CFR
part
60,
appendix
A;
ASTM
D6348
98,
``
Determination
of
Gaseous
Compounds
by
Extractive
Direct
Interface
Fourier
Transform
(
FTIR)
Spectroscopy,''
for
EPA
Method
320
of
40
CFR
part
63,
appendix
A;
and
Gas
Research
Institute,
``
Measurement
of
Formaldehyde
Emissions
Using
the
Acetylacetone
Colorimetric
Method''
for
EPA
Method
320
of
40
CFR
part
60,
appendix
A.
While
we
are
not
proposing
to
include
these
four
voluntary
consensus
standards
in
today's
proposal,
we
will
consider
the
standards
when
final.
The
consensus
standard,
GRI,
``
Measurement
of
Formaldehyde
Emissions
Using
the
Acetylacetone
Colorimetric
Method,''
is
currently
under
our
review
as
an
alternative
method
for
sampling
formaldehyde
emissions
in
the
exhaust
of
natural
gasfired
combustion
sources.
This
standard
is
based
on
the
``
Chilled
Impinger
Train
Method
for
Methanol,
Acetone,
Acetaldehyde,
Methyl
Ethyl
Ketone,
and
Formaldehyde''
and
is
described
by
the
National
Council
for
Air
and
Stream
Improvement
in
its
Technical
Bulletin
No.
684,
dated
December
1994.
After
EPA's
review,
if
this
GRI
standard
is
determined
to
be
technically
appropriate
for
identifying
formaldehyde
emissions,
it
could
be
incorporated
by
reference
for
our
regulatory
applicability
at
a
later
date.
For
the
voluntary
consensus
standard,
ASTM
D6348
98,
``
Determination
of
Gaseous
Compounds
by
Extractive
Direct
Interface
Fourier
Transform
(
FTIR)
Spectroscopy,''
we
have
submitted
comments
to
ASTM
regarding
EPA's
technical
evaluation
of
ASTM
D6348
98.
Currently,
the
ASTM
Subcommittee
D22
03
is
undertaking
a
revision
of
the
ASTM
standard
in
part
to
address
EPA's
comments.
Upon
successful
ASTM
balloting
and
demonstration
of
technical
equivalency
with
EPA's
FTIR
methods,
the
revised
ASTM
standard
could
be
incorporated
by
reference
for
EPA
regulatory
applicability.
We
are
taking
comment
on
the
compliance
demonstration
requirements
in
the
proposed
rulemaking
and
specifically
invite
the
public
to
identify
potentially
applicable
voluntary
consensus
standards.
Commentors
should
also
explain
why
the
proposed
regulation
should
adopt
these
voluntary
consensus
standards
in
lieu
of
or
in
addition
to
EPA's
standards.
Emission
test
methods
and
performance
specifications
submitted
for
evaluation
should
be
accompanied
with
a
basis
for
the
recommendation,
including
method
validation
data
and
the
procedure
used
to
validate
the
candidate
method
(
if
a
method
other
than
Method
301,
of
40
CFR
part
63,
appendix
A,
was
used).
Tables
4,
5,
and
6
of
proposed
subpart
ZZZZ
list
the
EPA
testing
methods
and
performance
standards
included
in
the
proposed
rule.
Under
40
CFR
63.8
of
subpart
A
of
the
General
Provisions,
a
source
may
apply
to
EPA
for
permission
to
use
alternative
monitoring
in
place
of
any
of
the
EPA
testing
methods.
List
of
Subjects
in
40
CFR
Part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Hazardous
substances,
Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.
Dated:
November
26,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
stated
in
the
preamble,
title
40,
chapter
I,
part
63
of
the
Code
of
the
Federal
Regulations
is
proposed
to
be
amended
as
follows:
PART
63
[
AMENDED]
1.
The
authority
citation
for
part
63
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401,
et
seq.
2.
Part
63
is
amended
by
adding
subpart
ZZZZ
to
read
as
follows:
Subpart
ZZZZ
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Stationary
Reciprocating
Internal
Combustion
Engines
Sec.
What
This
Subpart
Covers
63.6580
What
is
the
purpose
of
subpart
ZZZZ?
63.6585
Am
I
subject
to
this
subpart?
63.6590
What
parts
of
my
plant
does
this
subpart
cover?
63.6595
When
do
I
have
to
comply
with
this
subpart?
Emission
and
Operating
Limitations
63.6600
What
emission
limitations
and
operating
limitations
must
I
meet?
General
Compliance
Requirements
63.6605
What
are
my
general
requirements
for
complying
with
this
subpart?
Testing
and
Initial
Compliance
Requirements
63.6610
By
what
date
must
I
conduct
the
initial
performance
tests
or
other
initial
compliance
demonstrations?
63.6615
When
must
I
conduct
subsequent
performance
tests?
63.6620
What
performance
tests
and
other
procedures
must
I
use?
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Vol.
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244
/
Thursday,
December
19,
2002
/
Proposed
Rules
63.6625
What
are
my
monitor
installation,
operation,
and
maintenance
requirements?
63.6630
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations
and
operating
limitations?
Continuous
Compliance
Requirements
63.6635
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
63.6640
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations
and
operating
limitations?
Notification,
Reports,
and
Records
63.6645
What
notifications
must
I
submit
and
when?
63.6650
What
reports
must
I
submit
and
when?
63.6655
What
records
must
I
keep?
63.6660
In
what
form
and
how
long
must
I
keep
my
records?
Other
Requirements
and
Information
63.6665
What
parts
of
the
General
Provisions
apply
to
me?
63.6670
Who
implements
and
enforces
this
subpart?
63.6675
What
definitions
apply
to
this
subpart?
Tables
to
Subpart
ZZZZ
of
Part
63
Table
1a
to
Subpart
ZZZZ
of
Part
63,
Emission
Limitations
for
Existing,
New,
and
Reconstructed
Spark
Ignition,
4SRB
Stationary
RICE
Table
1b
to
Subpart
ZZZZ
of
Part
63,
Operating
Limitations
for
Existing,
New,
and
Reconstructed
Spark
Ignition,
4SRB
Stationary
RICE
Table
2a
to
Subpart
ZZZZ
of
Part
63,
Emission
Limitations
for
New
and
Reconstructed
Lean
Burn
and
Compression
Ignition
Stationary
RICE
Table
2b
to
Subpart
ZZZZ
of
Part
63,
Operating
Limitations
for
New
and
Reconstructed
Lean
Burn
and
Compression
Ignition
Stationary
RICE
Table
3
to
Subpart
ZZZZ
of
Part
63,
Subsequent
Performance
Tests
Table
4
to
Subpart
ZZZZ
of
Part
63,
Requirements
for
Performance
Tests
Table
5
to
Subpart
ZZZZ
of
Part
63,
Initial
Compliance
with
Emission
Limitations
and
Operating
Limitations
Table
6
to
Subpart
ZZZZ
of
Part
63,
Continuous
Compliance
with
Emission
Limitations
and
Operating
Limitations
Table
7
to
Subpart
ZZZZ
of
Part
63,
Requirements
for
Reports
Table
8
to
Subpart
ZZZZ
of
Part
63,
Applicability
of
General
Provisions
to
Subpart
ZZZZ
What
This
Subpart
Covers
§
63.6580
What
is
the
purpose
of
subpart
ZZZZ?
Subpart
ZZZZ
establishes
national
emission
limitations
and
operating
limitations
for
hazardous
air
pollutants
(
HAP)
emitted
from
stationary
reciprocating
internal
combustion
engines
(
RICE)
located
at
major
sources
of
HAP
emissions.
This
subpart
also
establishes
requirements
to
demonstrate
initial
and
continuous
compliance
with
the
emission
limitations
and
operating
limitations.
§
63.6585
Am
I
subject
to
this
subpart?
You
are
subject
to
this
subpart
if
you
own
or
operate
a
stationary
RICE
at
a
major
source
of
HAP
emissions,
except
if
the
stationary
RICE
is
being
tested
at
a
stationary
RICE
test
cell/
stand.
(
a)
A
stationary
RICE
is
any
internal
combustion
engine
which
uses
reciprocating
motion
to
convert
heat
energy
into
mechanical
work
and
which
is
not
mobile.
Stationary
RICE
differ
from
mobile
RICE
in
that
stationary
RICE
are
not
self
propelled,
are
not
intended
to
be
propelled
while
performing
their
function,
or
are
not
portable
or
transportable
as
that
term
is
identified
in
the
definition
of
non
road
engine
at
40
CFR
89.2.
(
b)
A
major
source
of
HAP
emissions
is
a
plant
site
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
10
tons
(
9.07
megagrams)
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
25
tons
(
22.68
megagrams)
or
more
per
year,
except
that
for
oil
and
gas
production
facilities,
a
major
source
of
HAP
emissions
is
determined
for
each
surface
site.
§
63.6590
What
parts
of
my
plant
does
this
subpart
cover?
This
subpart
applies
to
each
affected
source.
(
a)
Affected
source.
An
affected
source
is
any
existing,
new,
or
reconstructed
stationary
RICE
located
at
a
major
source
of
HAP
emissions,
excluding
stationary
RICE
being
tested
at
a
stationary
RICE
test
cell/
stand.
(
1)
Existing
stationary
RICE.
A
stationary
RICE
is
existing
if
you
commenced
construction
or
reconstruction
of
the
stationary
RICE
before
December
19,
2002.
A
change
in
ownership
of
an
existing
stationary
RICE
does
not
make
that
stationary
RICE
a
new
or
reconstructed
stationary
RICE.
(
2)
New
stationary
RICE.
A
stationary
RICE
is
new
if
you
commenced
construction
of
the
stationary
RICE
after
December
19,
2002.
(
3)
Reconstructed
stationary
RICE.
A
stationary
RICE
is
reconstructed
if
you
meet
the
definition
of
reconstruction
in
§
63.2
and
reconstruction
is
commenced
after
December
19,
2002.
(
b)
Exceptions.
(
1)
A
stationary
RICE
which
meets
either
of
the
criteria
in
paragraph
(
b)(
1)(
i)
or
(
ii)
of
this
section
does
not
have
to
meet
the
requirements
of
this
subpart
and
of
subpart
A
of
this
part
except
for
the
initial
notification
requirements
of
§
63.6645(
d).
(
i)
The
stationary
RICE
is
an
emergency
power/
limited
use
unit;
or
(
ii)
The
stationary
RICE
combusts
digester
gas
or
landfill
gas
as
the
primary
fuel.
(
2)
A
stationary
RICE
which
meets
any
of
the
criteria
in
paragraph
(
b)(
2)(
i)
or
(
ii)
of
this
section
does
not
have
to
meet
the
requirements
of
this
subpart
and
of
subpart
A
of
this
part.
(
i)
The
stationary
RICE
is
an
existing
spark
ignition
2
stroke
lean
burn
(
2SLB),
an
existing
spark
ignition
4
stroke
lean
burn
(
4SLB),
or
a
compression
ignition
(
CI)
stationary
RICE;
or
(
ii)
The
stationary
RICE
has
a
manufacturer's
nameplate
rating
of
less
than
or
equal
to
500
brake
horsepower.
§
63.6595
When
do
I
have
to
comply
with
this
subpart?
(
a)
Affected
sources.
(
1)
If
you
have
an
existing
stationary
RICE,
you
must
comply
with
the
applicable
emission
limitations
and
operating
limitations
no
later
than
[
3
years
after
the
date
of
publication
of
the
final
rule
in
the
Federal
Register].
(
2)
If
you
start
up
your
new
or
reconstructed
stationary
RICE
before
[
date
of
publication
of
the
final
rule
in
the
Federal
Register],
you
must
comply
with
the
applicable
emission
limitations
and
operating
limitations
in
this
subpart
no
later
than
[
date
of
publication
of
the
final
rule
in
the
Federal
Register].
(
3)
If
you
start
up
your
new
or
reconstructed
stationary
RICE
after
[
date
of
publication
of
the
final
rule
in
the
Federal
Register],
you
must
comply
with
the
applicable
emission
limitations
and
operating
limitations
in
this
subpart
upon
startup
of
your
affected
source.
(
b)
Area
sources
that
become
major
sources.
If
you
have
an
area
source
that
increases
its
emissions
or
its
potential
to
emit
such
that
it
becomes
a
major
source
of
HAP,
any
existing,
new,
or
reconstructed
stationary
RICE
must
be
in
compliance
with
this
subpart
when
the
area
source
becomes
a
major
source.
(
c)
If
you
own
or
operate
an
affected
RICE,
you
must
meet
the
applicable
notification
requirements
in
§
63.6645
and
in
40
CFR
part
63,
subpart
A.
Emission
and
Operating
Limitations
§
63.6600
What
emission
limitations
and
operating
limitations
must
I
meet?
(
a)
If
you
own
or
operate
an
existing,
new,
or
reconstructed
spark
ignition
4
stroke
rich
burn
(
4SRB)
stationary
RICE
located
at
a
major
source
of
HAP
emissions,
you
must
comply
with
the
emission
limitations
in
Table
1(
a)
of
this
subpart
and
the
operating
limitations
in
Table
1(
b)
of
this
subpart
which
apply
to
you.
(
b)
If
you
own
or
operate
a
new
or
reconstructed
2SLB
or
4SLB
stationary
RICE
or
a
new
or
reconstructed
CI
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/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
stationary
RICE
located
at
a
major
source
of
HAP
emissions,
you
must
comply
with
the
emission
limitations
in
Table
2(
a)
of
this
subpart
and
the
operating
limitations
in
Table
2(
b)
of
this
subpart
which
apply
to
you.
(
c)
If
you
own
or
operate:
an
existing
2SLB
stationary
RICE,
4SLB
stationary
RICE,
or
a
CI
stationary
RICE;
a
stationary
RICE
that
combusts
digester
gas
or
landfill
gas
as
the
primary
fuel;
an
emergency
power/
limited
use
stationary
RICE;
a
stationary
RICE
with
a
manufacturer's
nameplate
rating
of
500
brake
horsepower
or
less;
or
a
stationary
RICE
which
is
being
tested
at
a
stationary
RICE
test
cell/
stand,
you
do
not
need
to
comply
with
the
emission
limitations
in
Tables
1(
a)
and
2(
a)
of
this
subpart
or
operating
limitations
in
Tables
1(
b)
and
2(
b)
of
this
subpart.
General
Compliance
Requirements
§
63.6605
What
are
my
general
requirements
for
complying
with
this
subpart?
(
a)
You
must
be
in
compliance
with
the
emission
limitations
and
operating
limitations
in
this
subpart
that
apply
to
you
at
all
times,
except
during
periods
of
startup,
shutdown,
and
malfunction.
(
b)
If
you
must
comply
with
emission
limitations
and
operating
limitations,
you
must
operate
and
maintain
your
stationary
RICE,
including
air
pollution
control
and
monitoring
equipment,
in
a
manner
consistent
with
good
air
pollution
control
practices
for
minimizing
emissions
at
all
times,
including
during
startup,
shutdown,
and
malfunction.
Testing
and
Initial
Compliance
Requirements
§
63.6610
By
what
date
must
I
conduct
the
initial
performance
tests
or
other
initial
compliance
demonstrations?
You
must
conduct
the
initial
performance
test
or
other
initial
compliance
demonstrations
in
Table
4
of
this
subpart
that
apply
to
you
within
180
calendar
days
after
the
compliance
date
that
is
specified
for
your
stationary
RICE
in
§
63.6595
and
according
to
the
provisions
in
§
63.7(
a)(
2).
§
63.6615
When
must
I
conduct
subsequent
performance
tests?
If
you
must
comply
with
the
emission
limitations
and
operating
limitations,
you
must
conduct
subsequent
performance
tests
as
specified
in
Table
3
of
this
subpart.
§
63.6620
What
performance
tests
and
other
procedures
must
I
use?
(
a)
You
must
conduct
each
performance
test
in
Tables
3
and
4
of
this
subpart
that
applies
to
you.
(
b)
Each
performance
test
must
be
conducted
according
to
the
requirements
in
§
63.7(
e)(
1)
and
under
the
specific
conditions
that
this
subpart
specifies
in
Table
4.
(
c)
You
may
not
conduct
performance
tests
during
periods
of
startup,
shutdown,
or
malfunction,
as
specified
in
§
63.7(
e)(
1).
(
d)
You
must
conduct
three
separate
test
runs
for
each
performance
test
required
in
this
section,
as
specified
in
§
63.7(
e)(
3).
Each
test
run
must
last
at
least
1
hour.
(
e)(
1)
You
must
use
Equation
1
of
this
section
to
determine
compliance
with
the
percent
reduction
requirement:
C
C
C
i
o
i
×
100
=
R
(
Eq.
1)
Where:
Ci
=
concentration
of
CO
or
formaldehyde
at
the
control
device
inlet,
Co
=
concentration
of
CO
or
formaldehyde
at
the
control
device
outlet,
and
R
=
percent
reduction
of
CO
or
formaldehyde
emissions.
(
2)
You
must
normalize
the
carbon
monoxide
(
CO)
or
formaldehyde
concentrations
at
the
inlet
and
outlet
of
the
oxidation
catalyst
or
non
selective
catalytic
reduction
(
NSCR)
(
whichever
applies
to
you)
to
a
dry
basis
and
to
15
percent
oxygen,
or
an
equivalent
percent
carbon
dioxide
(
CO2)
if
you
are
using
a
continuous
emissions
monitoring
system
(
CEMS).
(
f)
If
you
comply
with
the
emission
limitation
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust,
you
must
petition
the
Administrator
for
additional
operating
limitations
to
be
established
during
the
initial
performance
test
and
continuously
monitored
thereafter;
or
for
approval
of
no
additional
operating
limitations.
You
must
not
conduct
the
initial
performance
test
until
after
the
petition
has
been
approved
by
the
Administrator.
(
g)
If
you
comply
with
the
emission
limitation
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
and
you
petition
the
Administrator
for
approval
of
additional
operating
limitations,
your
petition
must
include
the
information
described
in
paragraphs
(
g)(
1)
through
(
5)
of
this
section.
(
1)
Identification
of
the
specific
parameters
you
propose
to
use
as
additional
operating
limitations;
(
2)
A
discussion
of
the
relationship
between
these
parameters
and
HAP
emissions,
identifying
how
HAP
emissions
change
with
changes
in
these
parameters,
and
how
limitations
on
these
parameters
will
serve
to
limit
HAP
emissions;
(
3)
A
discussion
of
how
you
will
establish
the
upper
and/
or
lower
values
for
these
parameters
which
will
establish
the
limits
on
these
parameters
in
the
operating
limitations;
(
4)
A
discussion
identifying
the
methods
you
will
use
to
measure
and
the
instruments
you
will
use
to
monitor
these
parameters,
as
well
as
the
relative
accuracy
and
precision
of
these
methods
and
instruments;
and
(
5)
A
discussion
identifying
the
frequency
and
methods
for
recalibrating
the
instruments
you
will
use
for
monitoring
these
parameters.
(
h)
If
you
comply
with
the
emission
limitation
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
and
you
petition
the
Administrator
for
approval
of
no
additional
operating
limitations,
your
petition
must
include
the
information
described
in
paragraphs
(
h)(
1)
through
(
7)
of
this
section.
(
1)
Identification
of
the
parameters
associated
with
operation
of
the
stationary
RICE
and
any
emission
control
device
which
could
change
intentionally
(
e.
g.,
operator
adjustment,
automatic
controller
adjustment,
etc.)
or
unintentionally
(
e.
g.,
wear
and
tear,
error,
etc.)
on
a
routine
basis
or
over
time;
(
2)
A
discussion
of
the
relationship,
if
any,
between
changes
in
the
parameters
and
changes
in
HAP
emissions;
(
3)
For
the
parameters
which
could
change
in
such
a
way
as
to
increase
HAP
emissions,
a
discussion
of
whether
establishing
limitations
on
the
parameters
would
serve
to
limit
HAP
emissions;
(
4)
For
the
parameters
which
could
change
in
such
a
way
as
to
increase
HAP
emissions,
a
discussion
of
how
you
could
establish
upper
and/
or
lower
values
for
the
parameters
which
would
establish
limits
on
the
parameters
in
operating
limitations;
(
5)
For
the
parameters,
a
discussion
identifying
the
methods
you
could
use
to
measure
them
and
the
instruments
you
could
use
to
monitor
them,
as
well
as
the
relative
accuracy
and
precision
of
the
methods
and
instruments;
(
6)
For
the
parameters,
a
discussion
identifying
the
frequency
and
methods
for
recalibrating
the
instruments
you
could
use
to
monitor
them;
and
(
7)
A
discussion
of
why,
from
your
point
of
view,
it
is
infeasible
or
unreasonable
to
adopt
the
parameters
as
operating
limitations.
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77863
Federal
Register
/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
§
63.6625
What
are
my
monitoring
installation,
operation,
and
maintenance
requirements?
(
a)
If
you
are
required
to
install
a
CEMS
as
specified
in
Table
5
of
this
subpart,
you
must
install,
operate,
and
maintain
a
CEMS
to
monitor
CO
and
either
oxygen
or
CO2
at
both
the
inlet
and
the
outlet
of
the
oxidation
catalyst
according
to
the
requirements
in
paragraphs
(
a)(
1)
through
(
4)
of
this
section.
(
1)
Each
CEMS
must
be
installed,
operated,
and
maintained
according
to
the
applicable
performance
specifications
of
40
CFR
part
60,
appendix
B.
(
2)
You
must
conduct
an
initial
performance
evaluation
and
an
annual
relative
accuracy
test
audit
(
RATA)
of
each
CEMS
according
to
the
requirements
in
§
63.8
and
according
to
the
applicable
performance
specifications
of
40
CFR
part
60,
appendix
B
as
well
as
daily
and
periodic
data
quality
checks
in
accordance
with
40
CFR
part
60,
appendix
F,
procedure
1.
(
3)
As
specified
in
§
63.8(
c)(
4)(
ii),
each
CEMS
must
complete
a
minimum
of
one
cycle
of
operation
(
sampling,
analyzing,
and
data
recording)
for
each
successive
15
minute
period.
You
must
have
at
least
two
data
points,
with
each
representing
a
different
15
minute
period,
to
have
a
valid
hour
of
data.
(
4)
The
CEMS
data
must
be
reduced
as
specified
in
§
63.8(
g)(
2)
and
recorded
in
parts
per
million
or
parts
per
billion
(
as
appropriate
for
the
applicable
limitation)
at
15
percent
oxygen
or
the
equivalent
CO2
concentration.
(
b)
If
you
are
required
to
install
a
continuous
parameter
monitoring
system
(
CPMS)
as
specified
in
Table
5
of
this
subpart,
you
must
install,
operate,
and
maintain
each
CPMS
according
to
the
requirements
in
§
63.8.
§
63.6630
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations
and
operating
limitations?
(
a)
You
must
demonstrate
initial
compliance
with
each
emission
and
operating
limitation
that
applies
to
you
according
to
Table
5
of
this
subpart.
(
b)
During
the
initial
performance
test,
you
must
establish
each
operating
limitation
in
Tables
1(
b)
and
2(
b)
of
this
subpart
that
applies
to
you.
(
c)
You
must
submit
the
Notification
of
Compliance
Status
containing
the
results
of
the
initial
compliance
demonstration
according
to
the
requirements
in
§
63.6645.
Continuous
Compliance
Requirements
§
63.6635
How
do
I
monitor
and
collect
data
to
demonstrate
continuous
compliance?
(
a)
If
you
must
comply
with
emission
and
operating
limitations,
you
must
monitor
and
collect
data
according
to
this
section.
(
b)
Except
for
monitor
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
(
including,
as
applicable,
calibration
checks
and
required
zero
and
span
adjustments),
you
must
monitor
continuously
at
all
times
that
the
stationary
RICE
is
operating.
(
c)
You
may
not
use
data
recorded
during
monitoring
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
in
data
averages
and
calculations
used
to
report
emission
or
operating
levels,
nor
may
such
data
be
used
in
fulfilling
the
minimum
data
availability
requirement.
You
must,
however,
use
all
the
valid
data
collected
during
all
other
periods.
§
63.6640
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations
and
operating
limitations?
(
a)
You
must
demonstrate
continuous
compliance
with
each
emission
limitation
and
operating
limitation
in
Tables
1(
a)
and
1(
b)
and
Tables
2(
a)
and
2(
b)
of
this
subpart
that
apply
to
you
according
to
methods
specified
in
Table
6
of
this
subpart.
(
b)
You
must
report
each
instance
in
which
you
did
not
meet
each
emission
limitation
or
operating
limitation
in
Tables
1(
a)
and
1(
b)
and
Tables
2(
a)
and
2(
b)
of
this
subpart
that
apply
to
you.
These
instances
are
deviations
from
the
emission
and
operating
limitations
in
this
subpart.
These
deviations
must
be
reported
according
to
the
requirements
in
§
63.6650.
If
you
change
your
catalyst
(
i.
e.,
replace
catalyst
elements),
you
must
reestablish
the
values
of
the
operating
parameters
measured
during
the
initial
performance
test.
When
you
reestablish
the
values
of
your
operating
parameters,
you
must
also
conduct
a
performance
test
to
demonstrate
that
you
are
meeting
the
required
CO
or
formaldehyde
percent
reduction
applicable
to
your
stationary
RICE.
(
c)
During
periods
of
startup,
shutdown,
and
malfunction,
you
must
operate
in
accordance
with
your
startup,
shutdown,
and
malfunction
plan.
(
d)
Consistent
with
§
§
63.6(
e)
and
63.7(
e)(
1),
deviations
from
the
emission
or
operating
limitations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
are
not
violations.
(
e)
If
you
are
complying
with
the
requirement
to
limit
the
formaldehyde
concentration,
you
must
conduct
performance
tests
as
shown
in
Table
4
of
this
subpart.
Following
the
initial
performance
test,
subsequent
performance
tests
must
be
conducted
at
the
lowest
load.
You
must
also
conduct
a
performance
test
and
reestablish
the
minimum
load
or
minimum
fuel
flow
rate
if
you
want
to
operate
the
stationary
RICE
at
a
load
or
fuel
flow
rate
lower
than
that
established
during
the
initial
performance
test.
(
f)
You
must
also
report
each
instance
in
which
you
did
not
meet
the
requirements
in
Table
8
of
this
subpart
that
apply
to
you.
If
you
own
or
operate
an
existing
2SLB
stationary
RICE,
existing
4SLB
stationary
RICE,
or
a
CI
stationary
RICE,
or
a
stationary
RICE
with
a
manufacturer's
nameplate
rating
of
500
brake
horsepower
or
less,
you
do
not
need
to
comply
with
the
requirements
in
Table
8
of
this
subpart.
If
you
own
or
operate
a
stationary
RICE
that
combusts
digester
gas
or
landfill
gas
as
the
primary
fuel
or
an
emergency
power/
limited
use
stationary
RICE,
you
do
not
need
to
comply
with
the
requirements
in
Table
8
of
this
subpart,
except
for
the
initial
notification
requirements.
Notifications,
Reports,
and
Records
§
63.6645
What
notifications
must
I
submit
and
when?
(
a)
You
must
submit
all
of
the
notifications
in
§
§
63.7(
b)
and
(
c),
63.8(
e),
(
f)(
4)
and
(
f)(
6),
63.9(
b)
through
(
e),
and
(
g)
and
(
h)
that
apply
to
you
by
the
dates
specified.
(
b)
As
specified
in
§
63.9(
b)(
2),
if
you
must
comply
with
the
emission
and
operating
limitations,
and
you
start
up
your
stationary
RICE
before
[
the
effective
date
of
this
subpart],
you
must
submit
an
Initial
Notification
not
later
than
[
120
days
after
date
of
publication
of
the
final
rule
in
the
Federal
Register].
(
c)
As
specified
in
§
63.9(
b)(
3),
if
you
start
up
your
new
or
reconstructed
stationary
RICE
on
or
after
the
[
date
of
publication
of
the
final
rule
in
the
Federal
Register],
you
must
submit
an
Initial
Notification
not
later
than
120
days
after
you
become
subject
to
this
subpart.
(
d)
If
you
are
required
to
submit
an
Initial
Notification
but
are
otherwise
not
affected
by
the
requirements
of
this
subpart,
in
accordance
with
§
63.6590(
b),
your
notification
should
include
the
information
in
§
63.9(
b)(
2)(
i)
through
(
v),
and
a
statement
that
your
stationary
RICE
has
no
additional
requirements
and
explain
the
basis
of
the
exclusion
(
for
example,
that
it
operates
exclusively
as
an
emergency/
limited
use
stationary
RICE).
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/
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December
19,
2002
/
Proposed
Rules
(
e)
If
you
are
required
to
conduct
a
performance
test,
you
must
submit
a
Notification
of
Intent
to
conduct
a
performance
test
at
least
60
calendar
days
before
the
performance
test
is
scheduled
to
begin
as
required
in
§
63.7(
b)(
1).
(
f)
If
you
are
required
to
conduct
a
performance
test
or
other
initial
compliance
demonstration
as
specified
in
Tables
4
and
5
to
this
subpart,
you
must
submit
a
Notification
of
Compliance
Status
according
to
§
63.9(
h)(
2)(
ii).
(
1)
For
each
initial
compliance
demonstration
required
in
Table
5
of
this
subpart
that
does
not
include
a
performance
test,
you
must
submit
the
Notification
of
Compliance
Status
before
the
close
of
business
on
the
30th
calendar
day
following
the
completion
of
the
initial
compliance
demonstration.
(
2)
For
each
initial
compliance
demonstration
required
in
Table
5
of
this
subpart
that
includes
a
performance
test
conducted
according
to
the
requirements
in
Table
4
to
this
subpart,
you
must
submit
the
Notification
of
Compliance
Status,
including
the
performance
test
results,
before
the
close
of
business
on
the
60th
calendar
day
following
the
completion
of
the
performance
test
according
to
§
63.10(
d)(
2).
§
63.6650
What
reports
must
I
submit
and
when?
(
a)
You
must
submit
each
report
in
Table
7
of
this
subpart
that
applies
to
you.
(
b)
Unless
the
Administrator
has
approved
a
different
schedule
for
submission
of
reports
under
§
63.10(
a),
you
must
submit
each
report
by
the
date
in
Table
7
of
this
subpart
and
according
to
the
requirements
in
paragraphs
(
b)(
1)
through
(
5)
of
this
section.
(
1)
The
first
Compliance
report
must
cover
the
period
beginning
on
the
compliance
date
that
is
specified
for
your
affected
source
in
§
63.6595
and
ending
on
June
30
or
December
31,
whichever
date
is
the
first
date
following
the
end
of
the
first
calendar
half
after
the
compliance
date
that
is
specified
for
your
source
in
§
63.6595.
(
2)
The
first
Compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
follows
the
end
of
the
first
calendar
half
after
the
compliance
date
that
is
specified
for
your
affected
source
in
§
63.6595.
(
3)
Each
subsequent
Compliance
report
must
cover
the
semiannual
reporting
period
from
January
1
through
June
30
or
the
semiannual
reporting
period
from
July
1
through
December
31.
(
4)
Each
subsequent
Compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
is
the
first
date
following
the
end
of
the
semiannual
reporting
period.
(
5)
For
each
stationary
RICE
that
is
subject
to
permitting
regulations
pursuant
to
40
CFR
part
70
or
71,
and
if
the
permitting
authority
has
established
dates
for
submitting
semiannual
reports
pursuant
to
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
you
may
submit
the
first
and
subsequent
Compliance
reports
according
to
the
dates
the
permitting
authority
has
established
instead
of
according
to
the
dates
in
paragraphs
(
b)(
1)
through
(
4)
of
this
section.
(
c)
The
Compliance
report
must
contain
the
information
in
paragraphs
(
c)(
1)
through
(
6)
of
this
section.
(
1)
Company
name
and
address.
(
2)
Statement
by
a
responsible
official,
with
that
official's
name,
title,
and
signature,
certifying
the
accuracy
of
the
content
of
the
report.
(
3)
Date
of
report
and
beginning
and
ending
dates
of
the
reporting
period.
(
4)
If
you
had
a
startup,
shutdown,
or
malfunction
during
the
reporting
period,
the
compliance
report
must
include
the
information
in
§
63.10(
d)(
5)(
i).
(
5)
If
there
are
no
deviations
from
any
emission
or
operating
limitations
that
apply
to
you,
a
statement
that
there
were
no
deviations
from
the
emission
or
operating
limitations
during
the
reporting
period.
(
6)
If
there
were
no
periods
during
which
the
continuous
monitoring
system
(
CMS),
including
CEMS
and
CPMS,
was
out
of
control,
as
specified
in
§
63.8(
c)(
7),
a
statement
that
there
were
no
periods
during
which
the
CMS
was
out
of
control
during
the
reporting
period.
(
d)
For
each
deviation
from
an
emission
or
operating
limitation
that
occurs
for
a
stationary
RICE
where
you
are
not
using
a
CMS
to
comply
with
the
emission
or
operating
limitations
in
this
subpart,
the
Compliance
report
must
contain
the
information
in
paragraphs
(
c)(
1)
through
(
4)
of
this
section
and
the
information
in
paragraphs
(
d)(
1)
and
(
2)
of
this
section.
(
1)
The
total
operating
time
of
the
stationary
RICE
at
which
the
deviation
occurred
during
the
reporting
period.
(
2)
Information
on
the
number,
duration,
and
cause
of
deviations
(
including
unknown
cause,
if
applicable),
as
applicable,
and
the
corrective
action
taken.
(
e)
For
each
deviation
from
an
emission
or
operating
limitation
occurring
for
a
stationary
RICE
where
you
are
using
a
CMS
to
comply
with
the
emission
and
operating
limitations
in
this
subpart,
you
must
include
information
in
paragraphs
(
c)(
1)
through
(
4)
and
(
e)(
1)
through
(
12)
of
this
section.
(
1)
The
date
and
time
that
each
malfunction
started
and
stopped.
(
2)
The
date,
time,
and
duration
that
each
CMS
was
inoperative,
except
for
zero
(
low
level)
and
high
level
checks.
(
3)
The
date,
time,
and
duration
that
each
CMS
was
out
of
control,
including
the
information
in
§
63.8(
c)(
8).
(
4)
The
date
and
time
that
each
deviation
started
and
stopped,
and
whether
each
deviation
occurred
during
a
period
of
malfunction
or
during
another
period.
(
5)
A
summary
of
the
total
duration
of
the
deviation
during
the
reporting
period,
and
the
total
duration
as
a
percent
of
the
total
source
operating
time
during
that
reporting
period.
(
6)
A
breakdown
of
the
total
duration
of
the
deviations
during
the
reporting
period
into
those
that
are
due
to
control
equipment
problems,
process
problems,
other
known
causes,
and
other
unknown
causes.
(
7)
A
summary
of
the
total
duration
of
CMS
downtime
during
the
reporting
period,
and
the
total
duration
of
CMS
downtime
as
a
percent
of
the
total
operating
time
of
the
stationary
RICE
at
which
the
CMS
downtime
occurred
during
that
reporting
period.
(
8)
An
identification
of
each
parameter
and
pollutant
(
CO
or
formaldehyde)
that
was
monitored
at
the
stationary
RICE.
(
9)
A
brief
description
of
the
stationary
RICE.
(
10)
A
brief
description
of
the
CMS.
(
11)
The
date
of
the
latest
CMS
certification
or
audit.
(
12)
A
description
of
any
changes
in
CMS,
processes,
or
controls
since
the
last
reporting
period.
(
f)
Each
affected
source
that
has
obtained
a
title
V
operating
permit
pursuant
to
40
CFR
part
70
or
71
must
report
all
deviations
as
defined
in
this
subpart
in
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A).
If
an
affected
source
submits
a
Compliance
report
pursuant
to
Table
7
of
this
subpart
along
with,
or
as
part
of,
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
and
the
Compliance
report
includes
all
required
information
concerning
deviations
from
any
emission
or
operating
limitation
in
this
subpart,
submission
of
the
Compliance
report
shall
be
deemed
to
satisfy
any
obligation
to
report
the
same
deviations
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/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
in
the
semiannual
monitoring
report.
However,
submission
of
a
Compliance
report
shall
not
otherwise
affect
any
obligation
the
affected
source
may
have
to
report
deviations
from
permit
requirements
to
the
permit
authority.
§
63.6655
What
records
must
I
keep?
(
a)
If
you
must
comply
with
the
emission
and
operating
limitations,
you
must
keep
the
records
described
in
paragraphs
(
a)(
1)
through
(
a)(
3),
(
b)(
1)
through
(
b)(
3)
and
(
c)
of
this
section.
(
1)
A
copy
of
each
notification
and
report
that
you
submitted
to
comply
with
this
subpart,
including
all
documentation
supporting
any
Initial
Notification
or
Notification
of
Compliance
Status
that
you
submitted,
according
to
the
requirement
in
§
63.10(
b)(
2)(
xiv).
(
2)
The
records
in
§
63.6(
e)(
3)(
iii)
through
(
v)
related
to
startup,
shutdown,
and
malfunction.
(
3)
Records
of
performance
tests
and
performance
evaluations
as
required
in
§
63.10(
b)(
2)(
viii).
(
b)
For
each
CEMS
or
CPMS,
you
must
keep
the
records
listed
in
paragraphs
(
b)(
1)
through
(
3)
of
this
section.
(
1)
Records
described
in
§
63.10(
b)(
2)(
vi)
through
(
xi).
(
2)
Previous
(
i.
e.,
superseded)
versions
of
the
performance
evaluation
plan
as
required
in
§
63.8(
d)(
3).
(
3)
Requests
for
alternatives
to
the
relative
accuracy
test
for
CEMS
or
CPMS
as
required
in
§
63.8(
f)(
6)(
i),
if
applicable.
(
c)
You
must
keep
the
records
required
in
Table
6
of
this
subpart
to
show
continuous
compliance
with
each
emission
or
operating
limitation
that
applies
to
you.
§
63.6660
In
what
form
and
how
long
must
I
keep
my
records?
(
a)
Your
records
must
be
in
a
form
suitable
and
readily
available
for
expeditious
review
according
to
§
63.10(
b)(
1).
(
b)
As
specified
in
§
63.10(
b)(
1),
you
must
keep
each
record
for
5
years
following
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record.
(
c)
You
must
keep
each
record
on
site
for
at
least
2
years
after
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record,
according
to
§
63.10(
b)(
1).
You
can
keep
the
records
offsite
for
the
remaining
3
years.
Other
Requirements
and
Information
§
63.6665
What
parts
of
the
General
Provisions
apply
to
me?
Table
8
of
this
subpart
shows
which
parts
of
the
General
Provisions
in
§
§
63.1
through
63.15
apply
to
you.
If
you
own
or
operate
an
existing
2SLB,
an
existing
4SLB
stationary
RICE,
an
existing
CI
stationary
RICE,
or
a
stationary
RICE
with
a
manufacturer's
nameplate
rating
of
500
brake
horsepower
or
less,
you
do
not
need
to
comply
with
any
of
the
requirements
of
the
General
Provisions.
If
you
own
or
operate
a
stationary
RICE
that
combusts
digester
gas
or
landfill
gas
as
the
primary
fuel
or
is
an
emergency
power/
limited
use
stationary
RICE,
you
do
not
need
to
comply
with
the
requirements
in
the
General
Provisions
except
for
the
initial
notification
requirements.
§
63.6670
Who
implements
and
enforces
this
subpart?
(
a)
This
subpart
is
implemented
and
enforced
by
the
U.
S.
EPA,
or
a
delegated
authority
such
as
your
State,
local,
or
tribal
agency.
If
the
U.
S.
EPA
Administrator
has
delegated
authority
to
your
State,
local,
or
tribal
agency,
then
that
agency
(
as
well
as
the
U.
S.
EPA)
has
the
authority
to
implement
and
enforce
this
subpart.
You
should
contact
your
U.
S.
EPA
Regional
Office
to
find
out
whether
this
subpart
is
delegated
to
your
State,
local,
or
tribal
agency.
(
b)
In
delegating
implementation
and
enforcement
authority
of
this
subpart
to
a
State,
local,
or
tribal
agency
under
40
CFR
part
63,
subpart
E,
the
authorities
contained
in
paragraph
(
c)
of
this
section
are
retained
by
the
Administrator
of
the
U.
S.
EPA
and
are
not
transferred
to
the
State,
local,
or
tribal
agency.
(
c)
The
authorities
that
will
not
be
delegated
to
State,
local,
or
tribal
agencies
are:
(
1)
Approval
of
alternatives
to
the
non
opacity
emission
limitations
and
operating
limitations
in
§
63.6600
under
§
63.6(
g).
(
2)
Approval
of
major
alternatives
to
test
methods
under
§
63.7(
e)(
2)(
ii)
and
(
f)
and
as
defined
in
§
63.90.
(
3)
Approval
of
major
alternatives
to
monitoring
under
§
63.8(
f)
and
as
defined
in
§
63.90.
(
4)
Approval
of
major
alternatives
to
recordkeeping
and
reporting
under
§
63.10(
f)
and
as
defined
in
§
63.90.
§
63.6675
What
definitions
apply
to
this
subpart?
Terms
used
in
this
subpart
are
defined
in
the
Clean
Air
Act
(
CAA);
in
40
CFR
63.2,
the
General
Provisions
of
this
part;
and
in
this
section
as
follows:
Area
source
means
any
stationary
source
of
HAP
that
is
not
a
major
source
as
defined
in
part
63.
Associated
equipment
as
used
in
this
subpart
and
as
referred
to
in
section
112(
n)(
4)
of
the
CAA,
means
equipment
associated
with
an
oil
or
natural
gas
exploration
or
production
well,
and
includes
all
equipment
from
the
well
bore
to
the
point
of
custody
transfer,
except
glycol
dehydration
units,
storage
vessels
with
potential
for
flash
emissions,
combustion
turbines,
and
stationary
RICE.
CAA
means
the
Clean
Air
Act
(
42
U.
S.
C.
7401
et
seq.,
as
amended
by
Public
Law
101
549,
104
Stat.
2399).
Compression
ignition
engine
means
any
stationary
RICE
in
which
a
high
boiling
point
liquid
fuel
injected
into
the
combustion
chamber
ignites
when
the
air
charge
has
been
compressed
to
a
temperature
sufficiently
high
for
autoignition
including
diesel
engines
and
dual
fuel
engines.
Custody
transfer
means
the
transfer
of
hydrocarbon
liquids
or
natural
gas:
after
processing
and/
or
treatment
in
the
producing
operations,
or
from
storage
vessels
or
automatic
transfer
facilities
or
other
such
equipment,
including
product
loading
racks,
to
pipelines
or
any
other
forms
of
transportation.
For
the
purposes
of
this
subpart,
the
point
at
which
such
liquids
or
natural
gas
enters
a
natural
gas
processing
plant
is
a
point
of
custody
transfer.
Deviation
means
any
instance
in
which
an
affected
source
subject
to
this
subpart,
or
an
owner
or
operator
of
such
a
source:
(
1)
Fails
to
meet
any
requirement
or
obligation
established
by
this
subpart,
including
but
not
limited
to
any
emission
limitation
or
operating
limitation;
(
2)
Fails
to
meet
any
term
or
condition
that
is
adopted
to
implement
an
applicable
requirement
in
this
subpart
and
that
is
included
in
the
operating
permit
for
any
affected
source
required
to
obtain
such
a
permit;
or
(
3)
Fails
to
meet
any
emission
limitation
or
operating
limitation
in
this
subpart
during
malfunction,
regardless
or
whether
or
not
such
failure
is
permitted
by
this
subpart.
Diesel
engine
means
any
stationary
RICE
in
which
a
high
boiling
point
liquid
fuel
injected
into
the
combustion
chamber
ignites
when
the
air
charge
has
been
compressed
to
a
temperature
sufficiently
high
for
auto
ignition.
This
process
is
also
known
as
compression
ignition.
Diesel
fuel
means
any
liquid
obtained
from
the
distillation
of
petroleum
with
a
boiling
point
of
approximately
150
to
360
degrees
Celsius.
One
commonly
used
form
is
fuel
oil
number
2.
Digester
gas
means
any
gaseous
byproduct
of
wastewater
treatment
formed
through
the
anaerobic
decomposition
of
organic
waste
materials
and
composed
principally
of
methane
and
CO2.
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2002
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Proposed
Rules
Dual
fuel
engine
means
any
stationary
RICE
in
which
a
liquid
fuel
(
typically
diesel
fuel)
is
used
for
compression
ignition
and
gaseous
fuel
(
typically
natural
gas)
is
used
as
the
primary
fuel.
Emergency
power/
limited
use
stationary
RICE
means
any
stationary
RICE
that
operates
as
a
mechanical
or
electrical
power
source
when
the
primary
power
source
for
a
facility
has
been
rendered
inoperable
by
an
emergency
situation.
Examples
include
stationary
RICE
used
when
electric
power
from
the
local
utility
is
interrupted,
stationary
RICE
used
to
pump
water
in
the
case
of
fire
or
flood,
etc.
Emergency
power/
limited
use
units
also
include
units
that
operate
less
than
50
hours
per
year
in
non
emergency
situations,
including
certain
peaking
units
at
electric
facilities
and
stationary
RICE
at
industrial
facilities.
Four
stroke
engine
means
any
type
of
engine
which
completes
the
power
cycle
in
two
crankshaft
revolutions,
with
intake
and
compression
strokes
in
the
first
revolution
and
power
and
exhaust
strokes
in
the
second
revolution.
Gaseous
fuel
means
a
material
used
for
combustion
which
is
normally
a
gas
with
a
heating
value
at
standard
temperature
and
pressure.
Hazardous
air
pollutants
(
HAP)
means
any
air
pollutants
listed
in
or
pursuant
to
section
112(
b)
of
the
CAA.
ISO
standard
day
conditions
means
288
degrees
Kelvin
(
15
degrees
Celsius),
60
percent
relative
humidity
and
101.3
kilopascals
pressure.
Landfill
gas
means
a
gaseous
byproduct
of
the
land
application
of
municipal
refuse
formed
through
the
anaerobic
decomposition
of
waste
materials
and
composed
principally
of
methane
and
CO2.
Lean
burn
engine
means
any
twostroke
or
four
stroke
engine
where
the
manufacturer's
recommended
operating
air/
fuel
ratio
divided
by
the
stoichiometric
air/
fuel
ratio
is
greater
than
1.1.
Liquefied
petroleum
gas
means
any
liquefied
hydrocarbon
gas
obtained
as
a
by
product
in
petroleum
refining
of
natural
gas
production.
Liquid
fuel
means
any
fuel
in
liquid
form
at
standard
temperature
and
pressure,
including
but
not
limited
to
diesel,
residual/
crude
oil,
kerosene/
naphtha
(
jet
fuel),
and
gasoline.
Major
Source,
as
used
in
this
subpart,
shall
have
the
same
meaning
as
in
§
63.2,
except
that:
(
1)
Emissions
from
any
oil
or
gas
exploration
or
production
well
(
with
its
associated
equipment
(
as
defined
in
this
section))
and
emissions
from
any
pipeline
compressor
station
or
pump
station
shall
not
be
aggregated
with
emissions
from
other
similar
units,
to
determine
whether
such
emission
points
or
stations
are
major
sources,
even
when
emission
points
are
in
a
contiguous
area
or
under
common
control
except
when
they
are
on
the
same
surface
site;
(
2)
For
oil
and
gas
production
facilities,
emissions
from
processes,
operations,
or
equipment
that
are
not
part
of
the
same
oil
and
gas
production
facility,
as
defined
in
this
section,
shall
not
be
aggregated;
and
(
3)
For
production
field
facilities,
only
HAP
emissions
from
glycol
dehydration
units,
storage
tanks
with
flash
emissions
potential,
combustion
turbines
and
reciprocating
internal
combustion
engines
shall
be
aggregated
for
a
major
source
determination.
Malfunction
means
any
sudden,
infrequent,
and
not
reasonably
preventable
failure
of
air
pollution
control
equipment,
process
equipment,
or
a
process
to
operate
in
a
normal
or
usual
manner.
Failures
that
are
caused
in
part
by
poor
maintenance
or
careless
operation
are
not
malfunctions.
Natural
gas
means
a
naturally
occurring
mixture
of
hydrocarbon
and
non
hydrocarbon
gases
found
in
geologic
formations
beneath
the
Earth's
surface,
of
which
the
principal
constituent
is
methane.
May
be
field
or
pipeline
quality.
Non
selective
catalytic
reduction
(
NSCR)
means
an
add
on
catalytic
nitrogen
oxides
(
NOX)
control
device
for
rich
burn
engines
that,
in
a
two
step
reaction,
promotes
the
conversion
of
excess
oxygen,
NOX,
CO,
and
volatile
organic
compounds
(
VOC)
into
CO2,
nitrogen,
and
water.
Oil
and
gas
production
facility
as
used
in
this
subpart
means
any
grouping
of
equipment
where
hydrocarbon
liquids
are
processed,
upgraded
(
i.
e.,
remove
impurities
or
other
constituents
to
meet
contract
specifications),
or
stored
prior
to
the
point
of
custody
transfer;
or
where
natural
gas
is
processed,
upgraded,
or
stored
prior
to
entering
the
natural
gas
transmission
and
storage
source
category.
For
purposes
of
a
major
source
determination,
facility
(
including
a
building,
structure,
or
installation)
means
oil
and
natural
gas
production
and
processing
equipment
that
is
located
within
the
boundaries
of
an
individual
surface
site
as
defined
in
this
section.
Equipment
that
is
part
of
a
facility
will
typically
be
located
within
close
proximity
to
other
equipment
located
at
the
same
facility.
Pieces
of
production
equipment
or
groupings
of
equipment
located
on
different
oil
and
gas
leases,
mineral
fee
tracts,
lease
tracts,
subsurface
or
surface
unit
areas,
surface
fee
tracts,
surface
lease
tracts,
or
separate
surface
sites,
whether
or
not
connected
by
a
road,
waterway,
power
line
or
pipeline,
shall
not
be
considered
part
of
the
same
facility.
Examples
of
facilities
in
the
oil
and
natural
gas
production
source
category
include,
but
are
not
limited
to,
well
sites,
satellite
tank
batteries,
central
tank
batteries,
a
compressor
station
that
transports
natural
gas
to
a
natural
gas
processing
plant,
and
natural
gas
processing
plants.
Oxidation
catalyst
means
an
add
on
catalytic
control
device
for
lean
burn
engines
that
controls
CO
and
VOC
by
oxidation.
Peaking
unit
or
engine
means
any
standby
engine
intended
for
use
during
periods
of
high
demand
that
are
not
emergencies.
Potential
to
emit
means
the
maximum
capacity
of
a
stationary
source
to
emit
a
pollutant
under
its
physical
and
operational
design.
Any
physical
or
operational
limitation
on
the
capacity
of
the
stationary
source
to
emit
a
pollutant,
including
air
pollution
control
equipment
and
restrictions
on
hours
of
operation
or
on
the
type
or
amount
of
material
combusted,
stored,
or
processed,
shall
be
treated
as
part
of
its
design
if
the
limitation
or
the
effect
it
would
have
on
emissions
is
federally
enforceable.
Production
field
facility
means
those
oil
and
gas
production
facilities
located
prior
to
the
point
of
custody
transfer.
Propane
means
a
colorless
gas
derived
from
petroleum
and
natural
gas,
with
the
molecular
structure
C3H8,
suitable
for
use
in
spark
ignited
internal
combustion
engines.
Responsible
official
means
responsible
official
as
defined
in
40
CFR
70.2.
Rich
burn
engine
means
any
fourstroke
spark
ignited
engine
where
the
manufacturer's
recommended
operating
air/
fuel
ratio
divided
by
the
stoichiometric
air/
fuel
ratio
is
less
than
or
equal
to
1.1.
Spark
ignition
engine
means
a
type
of
engine
in
which
a
compressed
air/
fuel
mixture
is
ignited
by
a
timed
electric
spark
generated
by
a
spark
plug.
Stationary
reciprocating
internal
combustion
engine
(
RICE)
means
any
reciprocating
internal
combustion
engine
which
uses
reciprocating
motion
to
convert
heat
energy
into
mechanical
work
and
which
is
not
mobile.
Stationary
RICE
differ
from
mobile
RICE
in
that
stationary
RICE
are
not
self
propelled,
are
not
intended
to
be
propelled
while
performing
their
function,
or
are
not
portable
or
transportable
as
that
term
is
identified
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244
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Thursday,
December
19,
2002
/
Proposed
Rules
in
the
definition
of
non
road
engine
at
40
CFR
89.2.
Stationary
RICE
test
cell/
stand
means
an
engine
test
cell/
stand,
as
defined
in
subpart
PPPPP
of
this
part,
that
tests
stationary
RICE.
Stoichiometric
means
the
theoretical
air
to
fuel
ratio
required
for
complete
combustion.
Subpart
means
40
CFR
part
63,
subpart
ZZZZ.
Surface
site
means
any
combination
of
one
or
more
graded
pad
sites,
gravel
pad
sites,
foundations,
platforms,
or
the
immediate
physical
location
upon
which
equipment
is
physically
affixed.
Two
stroke
engine
means
a
type
of
engine
which
completes
the
power
cycle
in
single
crankshaft
revolution
by
combining
the
intake
and
compression
operations
into
one
stroke
and
the
power
and
exhaust
operations
into
a
second
stroke.
This
system
requires
auxiliary
scavenging
and
inherently
runs
lean
of
stoichiometric.
Tables
to
Subpart
ZZZZ
of
Part
63
TABLE
1A
TO
SUBPART
ZZZZ
OF
PART
63.
EMISSION
LIMITATIONS
FOR
EXISTING,
NEW,
AND
RECONSTRUCTED
SPARK
IGNITION,
4SRB
STATIONARY
RICE
[
As
stated
in
§
§
63.6600
and
63.6640,
you
must
comply
with
the
following
emission
limitations
for
existing,
new
and
reconstructed
4SRB
stationary
RICE]
For
each
.
.
.
You
must
meet
one
of
the
following
emission
limitations
.
.
.
1.
4SRB
stationary
RICE
..........................................................................
a.
Reduce
formaldehyde
emissions
by
75
percent
or
more,
if
you
use
NSCR;
or
b.
Limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
to
350
ppbvd
or
less
at
15
percent
O2,
if
you
use
means
other
than
NSCR
to
reduce
HAP
emissions.
TABLE
1B
TO
SUBPART
ZZZZ
OF
PART
63.
OPERATING
LIMITATIONS
FOR
EXISTING,
NEW,
AND
RECONSTRUCTED
SPARK
IGNITION,
4SRB
STATIONARY
RICE
[
As
stated
in
§
§
63.6600,
63.6630
and
63.6640,
you
must
comply
with
the
following
operating
emission
limitations
for
existing,
new
and
reconstructed
4SRB
stationary
RICE]
For
each
.
.
.
You
must
meet
the
following
operating
limitation
.
.
.
1.
4SRB
stationary
RICE
complying
with
the
requirement
to
reduce
formaldehyde
emissions
by
75
percent
or
more
using
NSCR.
a.
Maintain
your
catalyst
so
that
the
pressure
drop
across
the
catalyst
does
not
change
by
more
than
two
inches
of
water
from
the
pressure
drop
across
the
catalyst
measured
during
the
initial
performance
test;
and
b.
Maintain
your
catalyst
so
that
the
temperature
rise
across
the
catalyst
is
no
more
than
5
percent
different
from
the
temperature
rise
across
the
catalyst
measured
during
the
initial
performance
test;
and
c.
Maintain
the
temperature
of
your
stationary
RICE
exhaust
so
that
the
catalyst
inlet
temperature
is
greater
than
or
equal
to
750
°
F
and
less
than
or
equal
to
1250
°
F.
2.
4SRB
stationary
RICE
complying
with
the
requirement
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
to
350
ppbvd
or
less
at
15
percent
O2
using
means
other
than
NSCR
to
reduce
emissions.
a.
Maintain
an
operating
load
equal
to
or
greater
than
95
percent
of
the
operating
load
established
during
the
initial
performance
test;
or
b.
Maintain
a
fuel
flow
rate
equal
to
or
greater
than
95
percent
of
the
fuel
flow
rate
established
during
the
initial
performance
test;
and
c.
You
must
comply
with
any
additional
operating
limitations
approved
by
the
Administrator.
TABLE
2A
TO
SUBPART
ZZZZ
OF
PART
63.
EMISSION
LIMITATIONS
FOR
NEW
AND
RECONSTRUCTED
LEAN
BURN
AND
COMPRESSION
IGNITION
STATIONARY
RICE
[
As
stated
in
§
§
63.6600
and
63.6640,
you
must
comply
with
the
following
emission
limitations
for
new
and
reconstructed
lean
burn
and
compression
ignition
stationary
RICE]
For
each
.
.
.
You
must
meet
the
following
emission
limitation
.
.
.
1.
2SLB
stationary
RICE
..........................................................................
a.
Reduce
CO
emissions
by
60
percent
or
more,
if
you
use
an
oxidation
catalyst;
or
b.
Limit
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
to
17
ppmvd
or
less
at
15
percent
O2,
if
you
use
some
means
other
than
an
oxidation
catalyst
to
reduce
emissions.
2.
4SLB
stationary
RICE
..........................................................................
a.
Reduce
CO
emissions
by
93
percent
or
more,
if
you
use
an
oxidation
catalyst;
or
b.
Limit
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
to
14
ppmvd
or
less
at
15
percent
O2,
if
you
use
some
means
other
than
an
oxidation
catalyst
to
reduce
emissions.
3.
CI
stationary
RICE
...............................................................................
a.
Reduce
CO
emissions
by
70
percent
or
more,
if
you
use
an
oxidation
catalyst;
or
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Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
TABLE
2A
TO
SUBPART
ZZZZ
OF
PART
63.
EMISSION
LIMITATIONS
FOR
NEW
AND
RECONSTRUCTED
LEAN
BURN
AND
COMPRESSION
IGNITION
STATIONARY
RICE
Continued
[
As
stated
in
§
§
63.6600
and
63.6640,
you
must
comply
with
the
following
emission
limitations
for
new
and
reconstructed
lean
burn
and
compression
ignition
stationary
RICE]
For
each
.
.
.
You
must
meet
the
following
emission
limitation
.
.
.
b.
Limit
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust
to
580
ppbvd
or
less
at
15
percent
O2,
if
you
use
some
means
other
than
an
oxidation
catalyst
to
reduce
emissions.
TABLE
2B
TO
SUBPART
ZZZZ
OF
PART
63.
OPERATING
LIMITATIONS
FOR
NEW
AND
RECONSTRUCTED
LEAN
BURN
AND
COMPRESSION
IGNITION
STATIONARY
RICE
[
As
stated
in
§
§
63.6600,
63.6630,
and
63.6640,
you
must
comply
with
the
following
operating
limitations
for
new
and
reconstructed
lean
burn
and
compression
ignition
stationary
RICE]
For
each
.
.
.
You
must
meet
the
following
operating
limitation
.
.
.
1.
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
a
brake
horsepower
<
5000
complying
with
the
requirement
to
reduce
CO
emissions
using
an
oxidation
catalyst.
a.
Maintain
your
catalyst
so
that
the
pressure
drop
across
the
catalyst
does
not
change
by
more
than
two
inches
of
water
from
the
pressure
drop
across
the
catalyst
that
was
measured
during
the
initial
performance
test;
and
b.
Maintain
the
temperature
of
your
stationary
RICE
exhaust
so
that
the
catalyst
inlet
temperature
is
greater
than
or
equal
to
500
°
F
and
less
than
or
equal
to
1250
°
F.
2.
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
complying
with
the
requirement
to
limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust.
a.
Maintain
an
operating
load
equal
to
or
greater
than
95
percent
of
the
operating
load
established
during
the
initial
performance
test;
or
b.
Maintain
a
fuel
flow
rate
equal
to
or
greater
than
95
percent
of
the
fuel
flow
rate
established
during
the
initial
performance
test;
and
c.
You
must
comply
with
any
additional
operating
limitations
approved
by
the
Administrator.
TABLE
3
TO
SUBPART
ZZZZ
OF
PART
63.
SUBSEQUENT
PERFORMANCE
TESTS
[
As
stated
in
§
§
63.6615
and
63.6620,
you
must
comply
with
the
following
subsequent
performance
test
requirements]
For
each
.
.
.
Complying
with
the
requirement
to
.
.
.
You
must
.
.
.
1.
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
a
brake
horsepower
<
5000.
Reduce
CO
emissions
if
using
an
oxidation
catalyst.
Conduct
subsequent
performance
tests
quarterly
2.
4SRB
stationary
RICE
with
a
brake
horsepower
5000.
Reduce
formaldehyde
emissions
75
percent
or
more
using
NSCR.
Conduct
subsequent
performance
tests
semiannually
a.
3.
Stationary
RICE
(
all
stationary
RICE
subcategories
and
all
brake
horsepower
ratings).
Limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust,
if
using
means
other
than
an
oxidation
catalyst
or
NSCR.
Conduct
subsequent
performance
tests
semiannually
a.
a
After
you
have
demonstrated
compliance
for
two
consecutive
tests,
you
may
reduce
the
frequency
of
subsequent
performance
tests
to
annually
If
the
results
of
any
subsequent
annual
performance
test
indicate
the
stationary
RICE
is
not
in
compliance
with
the
formaldehyde
emission
limitation,
or
you
deviate
from
any
of
your
operating
limitations,
you
must
resume
semiannual
performance
tests.
TABLE
4
TO
SUBPART
ZZZZ
OF
PART
63.
REQUIREMENTS
FOR
PERFORMANCE
TESTS
[
As
stated
in
§
§
63.6610,
63.6620,
and
63.6640,
you
must
comply
with
the
following
requirements
for
performance
tests]
For
each
.
.
.
Complying
with
the
requirement
to
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.
1.
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
a
brake
horsepower
<
5000.
a.
Reduce
CO
emissions
if
using
an
oxidation
catalyst
i.
Measure
the
O2
at
the
inlet
and
outlet
of
the
oxidation
catalyst.
and
(
1)
Portable
CO
and
O2
analyzer.
(
a)
Using
ASTM
D6522
00
b.
Measurements
to
determine
O2
must
be
made
at
the
same
time
as
the
measurements
for
CO
concentration.
ii.
Measure
the
CO
at
the
inlet
and
the
outlet
of
the
oxidation
catalyst.
(
1)
Portable
CO
and
O2
analyzer.
(
a)
Using
ASTM
D6522
00
b.
The
CO
concentration
must
be
at
15
percent
O2,
dry
basis.
2.
4SRB
stationary
RICE
..
a.
Reduce
formaldehyde
emissions
by
75
percent
or
more
using
NSCR.
i.
Select
the
sampling
port
location
and
the
number
of
traverse
points.
and
(
1)
Method
1
or
1A
of
40
CFR
part
60,
appendix
A
§
63.7(
d)(
1)(
i).
(
a)
Sampling
sites
must
be
located
at
the
inlet
and
outlet
of
the
NSCR.
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/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
TABLE
4
TO
SUBPART
ZZZZ
OF
PART
63.
REQUIREMENTS
FOR
PERFORMANCE
TESTS
Continued
[
As
stated
in
§
§
63.6610,
63.6620,
and
63.6640,
you
must
comply
with
the
following
requirements
for
performance
tests]
For
each
.
.
.
Complying
with
the
requirement
to
.
.
.
You
must
.
.
.
Using
.
.
.
According
to
the
following
requirements
.
.
.
ii.
Measure
O2
at
the
inlet
and
outlet
of
the
control
device.
and
(
1)
Method
3A
and
3B
of
40
CFR
part
60,
appendix
A.
(
a)
Measurements
to
determine
O2
concentration
must
be
made
at
the
same
time
as
the
measurements
for
formaldehyde
concentration.
iii.
Measure
moisture
content
at
the
inlet
and
outlet
of
the
NSCR.
and
(
1)
Method
4
of
40
CFR
part
60,
appendix
A.
(
a)
Measurements
to
determine
moisture
content
must
be
made
at
the
same
time
and
location
as
the
measurements
for
formaldehyde
concentration
iv.
Measure
formaldehyde
at
the
inlet
and
the
outlet
of
the
NSCR.
(
1)
Method
320
or
323
of
40
CFR
part
63,
appendix
A,
EPA
SW
846
Method
0011
or
Method
CARB
430
a.
(
a)
Formaldehyde
concentration
must
be
at
15
percent
O2,
dry
basis.
Results
of
this
test
consist
of
the
average
of
the
three
1
hour
or
longer
runs.
3.
Stationary
RICE
............
a.
Limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust.
i.
Select
the
sampling
port
location
and
the
number
of
traverse
points.
and
(
1)
Method
1
or
1A
of
40
CFR
part
60,
appendix
A
§
63.7(
d)(
1)(
i).
(
a)
If
using
a
control
device
the
sampling
site
must
be
located
at
the
outlet
of
the
control
device
ii.
Determine
the
O2
concentration
of
the
stationary
RICE
exhaust
at
the
sampling
port
location
and
(
1)
Method
3A
or
3B
of
40
CFR
part
60,
appendix
A.
(
a)
Measurements
to
determine
O2
concentration
must
be
made
at
the
same
time
and
location
as
the
measurements
for
formaldehyde
concentration
iii.
Measure
moisture
content
of
the
stationary
RICE
exhaust
at
the
sampling
port
location.
and
(
1)
Method
4
of
40
CFR
part
60,
appendix
A.
(
a)
Measurements
to
determine
moisture
content
must
be
made
at
the
same
time
and
location
as
the
measurements
for
formaldehyde
concentration
iv.
Measure
formaldehyde
at
the
exhaust
of
the
stationary
RICE.
(
1)
Method
320
or
323
of
40
CFR
part
63,
appendix
A;
or
Method
CARB
430
a
(
spark
ignition
4SRB
stationary
RICE
only);
or
EPA
SW
846
Method
0011.
(
a)
The
stationary
RICE
must
be
operating
at
the
lowest
operating
load
at
which
you
will
operate
the
stationary
RICE;
and
Formaldehyde
concentration
must
be
at
15
percent
O2,
dry
basis.
Results
of
this
test
consist
of
the
average
of
the
three
1
hour
or
longer
runs.
a
You
may
obtain
a
copy
of
ARB
Method
430
from
the
California
Environmental
Protection
Agency,
Air
Resources
Board,
2020
L
Street,
Sacramento
CA
95812,
or
you
may
download
a
copy
of
ARB
Method
430
from
ARB's
web
site
(
http://
www.
arb.
ca.
gov/
testmeth/
vol3/
vol3.
htm).
b
You
may
also
use
Methods
3A
and
10
as
options
to
ASTM
D6522
00.
You
may
obtain
a
copy
of
ASTM
D6522
00
from
at
least
one
of
the
following
addresses:
American
Society
for
Testing
and
Materials,
100
Barr
Harbor
Drive,
West
Conshohochen,
PA
19428
2959,
or
University
Microfilms
International,
300
North
Zeeb
Road,
Ann
Arbor,
MI
48106.
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Federal
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/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
TABLE
5
TO
SUBPART
ZZZZ
OF
PART
63.
INITIAL
COMPLIANCE
WITH
EMISSION
LIMITATIONS
AND
OPERATING
LIMITATIONS
[
As
stated
in
§
§
63.6625
and
63.6630,
you
must
initially
comply
with
the
emission
and
operating
limitations
as
required
by
the
following]
For
each
.
.
.
Complying
with
the
requirement
to
.
.
.
You
have
demonstrated
initial
compliance
if
.
.
.
1.
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
a
brake
horsepower
<
5000.
a.
Reduce
CO
emissions
if
using
an
oxidation
catalyst.
i.
The
average
reduction
of
emissions
of
CO
determined
from
the
initial
performance
test
achieves
the
required
CO
percent
reduction;
and
ii.
You
have
installed
a
CPMS
to
continuously
monitor
catalyst
pressure
drop
and
catalyst
inlet
temperature
according
to
the
requirements
in
§
63.6625(
b);
and
iii.
You
have
recorded
the
catalyst
pressure
drop
and
catalyst
inlet
temperature
during
the
initial
performance
test.
2.
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
a
brake
horsepower
5000.
a.
Reduce
CO
emissions
if
using
an
oxidation
catalyst.
i.
You
have
installed
a
CEMS
to
continuously
monitor
CO
and
either
O2
or
CO2
at
both
the
inlet
and
outlet
of
the
oxidation
catalyst
according
to
the
requirements
in
§
63.6625(
a);
and
ii.
You
have
conducted
a
performance
evaluation
of
your
CEMS
using
PS
3
and
4A
of
40
CFR
part
60,
appendix
B;
and
iii.
The
average
reduction
of
CO
calculated
using
§
63.6620
equals
or
exceeds
the
required
percent
reduction.
The
initial
test
comprises
the
first
4
hour
period
after
successful
validation
of
the
CEMS.
Compliance
is
based
on
the
average
percent
reduction
achieved
during
the
4
hour
period.
3.
4SRB
stationary
RICE
........................
a.
Reduce
formaldehyde
emissions
if
using
NSCR.
i.
The
average
reduction
of
emissions
of
formaldehyde
determined
from
the
initial
performance
test
is
equal
to
or
greater
than
the
required
formaldehyde
percent
reduction
and
ii.
You
have
installed
a
CPMS
to
continuously
monitor
catalyst
pressure
drop
and
catalyst
temperature
rise
according
to
the
requirements
in
§
63.6625(
b);
and
iii.
You
have
recorded
the
catalyst
pressure
drop,
catalyst
inlet
temperature
and
catalyst
temperature
rise
during
the
initial
performance
test.
4.
Stationary
RICE
..................................
a.
Limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust.
i.
The
average
formaldehyde
concentration,
corrected
to
15
percent
O2,
dry
basis,
from
the
three
test
runs
is
less
than
or
equal
to
the
formaldehyde
emission
limitation;
and
ii.
You
have
installed
a
CPMS
to
continuously
monitor
stationary
RICE
operating
load
or
fuel
flow
rate
according
to
the
requirements
in
§
63.6625(
b);
and
iii.
You
have
recorded
the
average
stationary
RICE
operating
load
or
fuel
flow
rate
during
the
initial
performance
test.
TABLE
6
TO
SUBPART
ZZZZ
OF
PART
63.
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
AND
OPERATING
LIMITATIONS
[
As
stated
in
§
63.6640,
you
must
continuously
comply
with
the
emissions
and
operating
limitations
as
required
by
the
following]
For
each
.
.
.
Complying
with
the
requirement
to
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.
1.
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
a
brake
horsepower
<
5000.
a.
Reduce
CO
emissions
if
using
an
ozidation
catalyst.
i.
Conducting
quarterly
performance
tests
for
CO
to
demonstrate
that
the
required
CO
percent
reduction
is
achieved;
and
ii.
Collecting
the
catalyst
pressure
drop
and
catalyst
inlet
temperature
data
according
to
§
63.6625(
b);
and
iii.
Reducing
these
data
to
4
hour
rolling
averages;
and
iv.
Maintaining
the
4
hour
rolling
averages
within
the
operating
limitations
for
the
pressure
drop
across
the
catalyst
and
the
catalyst
inlet
temperature
established
during
the
initial
performance
test.
2.
2SLB
and
4SLB
stationary
RICE
and
CI
stationary
RICE
with
a
brake
horsepower
5000.
a.
Reduce
CO
emissions
if
using
an
oxidation
catalyst.
i.
Collecting
the
monitoring
data
according
to
§
63.6625(
a),
reducing
the
measurements
to
1
hour
averages,
calculating
the
percent
reduction
of
CO
emissions
according
to
§
63.6620;
and
ii.
Demonstrating
that
the
oxidation
catalyst
achieves
the
required
percent
reduction
of
CO
emissions
over
the
4
hour
averaging
period;
and
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Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
TABLE
6
TO
SUBPART
ZZZZ
OF
PART
63.
CONTINUOUS
COMPLIANCE
WITH
EMISSION
LIMITATIONS
AND
OPERATING
LIMITATIONS
Continued
[
As
stated
in
§
63.6640,
you
must
continuously
comply
with
the
emissions
and
operating
limitations
as
required
by
the
following]
For
each
.
.
.
Complying
with
the
requirement
to
.
.
.
You
must
demonstrate
continuous
compliance
by
.
.
.
iii.
Conducting
an
annual
RATA
of
your
CEMS
using
PS
3
and
4A
of
40
CFR
part
60,
appendix
B,
as
well
as
daily
and
periodic
data
quality
checks
in
accordance
with
40
CFR
part
60,
appendix
F,
procedure
1.
3.
Spark
ignition,
4SRB
stationary
RICE
a.
Reduce
formaldehyde
emissions
if
using
NSCR.
i.
Collecting
the
pressure
drop
across
the
catalyst,
the
catalyst
inlet
temperature
and
the
temperature
rise
across
the
catalyst
data
according
to
§
63.6625(
b);
and
ii.
Reducing
these
data
to
4
hour
rolling
averages;
and
iii.
Maintaining
the
4
hour
rolling
averages
within
the
operating
limitations
for
pressure
drop
across
the
catalyst,
the
catalyst
inlet
temperature
and
temperature
rise
across
the
catalyst
established
during
the
performance
test.
4.
4SRB
stationary
RICE
with
a
brake
horsepower
5000.
Reduce
formaldehyde
emissions
if
using
NSCR.
Conducting
semiannual
performance
tests
for
formaldehyde
to
demonstrate
that
the
required
formaldehyde
percent
reduction
horsepower
is
achieved
a
5.
Stationary
RICE
..................................
a.
Limit
the
concentration
of
formaldehyde
in
the
stationary
RICE
exhaust.
i.
Conducting
semiannual
performance
tests
for
formaldehyde
to
demonstrate
that
your
emissions
remain
at
or
below
the
formaldehyde
concentration
limit
a;
and
ii.
Collecting
the
operating
load
or
fuel
flow
data;
and
iii.
Reducing
operating
load
or
fuel
flow
data
to
4
hour
rolling
averages;
and
iv.
Maintaining
the
4
hour
rolling
averages
equal
to
or
greater
than
95
percent
of
the
operating
limitations
established
during
the
initial
performance
test.
a
After
you
have
demonstrated
compliance
for
two
consecutive
tests,
you
may
reduce
the
frequency
of
subsequent
performance
tests
to
annually
If
the
results
of
any
subsequent
annual
performance
test
indicate
the
stationary
RICE
is
not
in
compliance
with
the
formaldehyde
emission
limitation,
or
you
deviate
from
any
of
your
operating
limitations,
you
must
resume
semiannual
performance
tests.
TABLE
7
TO
SUBPART
ZZZZ
OF
PART
63.
REQUIREMENTS
FOR
REPORTS
[
As
stated
in
§
63.6650,
you
must
comply
with
the
following
requirements
for
reports]
You
must
submit
a
(
n)
The
report
must
contain
.
.
.
You
must
submit
the
report
.
.
.
1.
Compliance
report
..............................
a.
If
there
are
no
deviations
from
any
emission
limitations
or
operating
limitations
that
apply
to
you,
a
statement
that
there
were
no
deviations
from
the
emission
limitations
or
operating
limitations
during
the
reporting
period.
If
there
were
no
periods
during
which
the
CMS,
including
CEMS
and
CPMS,
was
out
of
control,
as
specified
in
§
63.8(
c)(
7),
a
statement
that
there
were
not
periods
during
which
the
CMS
was
out
of
control
during
the
reporting
period.
or
i.
Semiannually
according
to
the
requirements
in
§
63.6650(
b).
b.
If
you
had
a
deviation
from
any
emission
limitation
or
operating
limitation
during
the
reporting
period,
the
information
in
§
63.6650(
d).
If
there
were
periods
during
which
the
CMS,
including
CEMS
and
CPMS,
was
out
of
control,
as
specified
in
§
63.8(
c)(
7),
the
information
in
§
63.6650(
e).
or
i.
Semiannually
according
to
the
requirements
in
§
63.6650(
b).
c.
If
you
had
a
startup,
shutdown
or
malfunction
during
the
reporting
period,
the
information
in
§
63.10(
d)(
5)(
i).
i.
Semiannually
according
to
the
requirements
in
§
63.6650(
b).
2.
An
immediate
startup,
shutdown,
and
malfunction
report
if
you
had
a
startup
shutdown,
or
malfunction
during
the
reporting
period.
a.
Actions
taken
for
the
event
...............................................
and
i.
by
fax
or
telephone
within
2
working
days
after
starting
actions
inconsistent
with
the
plan.
b.
The
information
in
§
63.10(
d)(
5)(
ii)
....................................
i.
By
letter
within
7
working
days
after
the
end
of
the
event
unless
you
have
made
alternative
arrangements
with
the
permitting
authorities.
(
§
63.10(
d)(
5)(
ii)).
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/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
TABLE
8
TO
SUBPART
ZZZZ
OF
PART
63
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
ZZZZ
[
As
stated
in
§
63.6665,
you
must
comply
with
the
following
applicable
general
provisions:]
General
provisions
citation
Subject
of
citation
Applies
to
Subpart
Explanation
1.
§
63.1
.........................................
General
applicability
of
the
General
Provisions.
Yes.
2.
§
63.2
.........................................
Definitions
.....................................
Yes
................................................
Additional
terms
defined
in
§
63.6675.
3.
§
63.3
.........................................
Units
and
abbreviations
................
Yes.
4.
§
63.4
.........................................
Prohibited
activities
and
circumvention
Yes.
5.
§
63.5
.........................................
Construction
and
reconstruction
...
Yes.
6.
§
63.6(
a)
.....................................
Applicability
...................................
Yes.
7.
§
63.6(
b)(
1)
(
4)
..........................
Compliance
dates
for
new
and
reconstructed
sources.
Yes.
8.
§
63.6(
b)(
5)
................................
Notification
....................................
Yes.
9.
§
63.6(
b)(
6)
................................
[
Reserved]
....................................
Yes.
10.
§
63.6(
b)(
7)
..............................
Compliance
dates
for
new
and
reconstructed
area
sources
that
become
major
sources.
Yes.
11.
§
63.6(
c)(
1)
(
2)
........................
Compliance
dates
for
existing
sources.
Yes.
12.
§
63.6(
c)(
3)
(
4)
........................
[
Reserved]
....................................
Yes.
13.
§
63.6(
c)(
5)
...............................
Compliance
dates
for
existing
area
sources
that
become
major
sources.
Yes.
14.
§
63.6(
d)
...................................
[
Reserved]
....................................
Yes.
15.
§
63.6(
e)(
1)
(
2)
........................
Operation
and
maintenance
.........
Yes.
16.
§
63.6(
e)(
3)
..............................
Startup,
shutdown,
and
malfunction
plan.
No
.................................................
No
requirement
for
a
startup,
shutdown
and
malfunction
plan.
17.
§
63.6(
f)(
1)
...............................
Applicability
of
standards
except
during
startup
shutdown
malfunction
(
SSM).
Yes.
18.
§
63.6(
f)(
2)
...............................
Methods
for
determining
compliance
Yes.
19.
§
63.6(
f)(
3)
...............................
Finding
of
compliance
..................
Yes.
20.
§
63.6(
g)(
1)
(
3)
........................
Use
of
alternate
standard
.............
Yes.
21.
§
63.6(
h)
...................................
Opacity
and
visible
emission
standards.
No
.................................................
Subpart
ZZZZ,
40
CFR
part
63,
does
not
contain
opacity
or
visible
emission
standards.
22.
§
63.6(
i)
....................................
Compliance
extension
procedures
and
criteria.
Yes.
23.
§
63.6(
j)
....................................
Presidential
compliance
exemption
Yes.
24.
§
63.7(
a)(
1)
(
2)
........................
Performance
test
dates
................
Yes.
25.
§
63.7(
a)(
3)
..............................
Section
114
authority
....................
Yes.
26.
§
63.7(
b)(
1)
..............................
Notification
of
performance
test
...
Yes.
27.
§
63.7(
b)(
2)
..............................
Notification
of
rescheduling
..........
Yes.
28.
§
63.7(
c)
...................................
Quality
assurance/
test
plan
..........
Yes.
29.
§
63.7(
d)
...................................
Testing
facilities
............................
Yes.
30.
§
63.7(
e)(
1)
..............................
Conditions
for
conducting
performance
tests.
Yes
................................................
Except
that
testing
is
required
under
lowest
load
conditions
for
some
regulatory
alternatives.
31.
§
63.7(
e)(
2)
..............................
Conditions
for
conducting
performance
tests.
Yes.
32.
§
63.7(
e)(
3)
..............................
Test
run
duration
..........................
Yes.
33.
§
63.7(
e)(
4)
..............................
Administrator
may
require
other
testing
under
section
114
of
the
CAA.
Yes.
34.
§
63.7(
f)
....................................
Alternative
test
method
provisions
Yes.
35.
§
63.7(
g)
...................................
Performance
test
data
analysis,
recordkeeping,
and
reporting.
Yes.
36.
§
63.7(
h)
...................................
Waiver
of
tests
..............................
Yes.
37.
§
63.8(
a)(
1)
..............................
Applicability
of
monitoring
requirements
Yes
................................................
Subpart
ZZZZ,
40
CFR
part
63,
contains
specific
requirements
for
monitoring
at
§
63.6625.
38.
§
63.8(
a)(
2)
..............................
Performance
specifications
..........
Yes.
39.
§
63.8(
a)(
3)
..............................
[
Reserved].
40.
§
63.8(
a)(
4)
..............................
Monitoring
with
flares
...................
No.
41.
§
63.8(
b)(
1)
..............................
Monitoring
.....................................
Yes.
42.
§
63.8(
b)(
2)
(
3)
........................
Multiple
effluents
and
multiple
monitoring
systems.
Yes.
43.
§
63.8(
c)(
1)
...............................
Monitoring
system
operation
and
maintenance.
Yes.
44.
§
63.8(
c)(
1)(
i)
...........................
Routine
and
predictable
SSM
......
Yes.
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/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
TABLE
8
TO
SUBPART
ZZZZ
OF
PART
63
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
ZZZZ
Continued
[
As
stated
in
§
63.6665,
you
must
comply
with
the
following
applicable
general
provisions:]
General
provisions
citation
Subject
of
citation
Applies
to
Subpart
Explanation
45.
§
63.8(
c)(
1)(
ii)
...........................
SSM
not
in
Startup
Shutdown
Malfunction
Plan.
Yes.
46.
§
63.8(
c)(
1)(
iii)
..........................
Compliance
with
operation
and
maintenance
requirements.
Yes.
47.
§
63.8(
c)(
2)
(
3)
........................
Monitoring
system
installation
......
Yes.
48.
§
63.8(
c)(
4)
...............................
Continuous
monitoring
system
(
CMS)
requirements.
Yes
................................................
Except
that
Subpart
ZZZZ,
40
CFR
part
63,
does
not
require
Continuous
Opacity
Monitoring
System
(
COMS).
49.
§
63.8(
c)(
5)
...............................
COMS
minimum
procedures
........
No
.................................................
Subpart
ZZZZ,
40
CFR
part
63,
does
not
require
COMS.
50.
§
63.8(
c)(
6)
(
8)
........................
CMS
requirements
........................
Yes
................................................
Except
that
Subpart
ZZZZ,
40
CFR
part
63,
does
not
require
COMS.
51.
§
63.8(
d)
...................................
CMS
quality
control
......................
Yes.
52.
§
63.8(
e)
...................................
CMS
performance
evaluation
.......
Yes
................................................
Except
for
§
63.8(
e)(
5)(
ii),
which
applies
to
COMS.
53.
§
63.8(
f)(
1)
(
5)
.........................
Alternative
monitoring
method
......
Yes.
54.
§
63.8(
f)(
6)
...............................
Alternative
to
relative
accuracy
test.
Yes.
55.
§
63.8(
g)
...................................
Data
reduction
..............................
Yes
................................................
Except
that
provisions
for
COMS
are
not
applicable.
Averaging
periods
for
demonstrating
compliance
are
specified
at
§
§
63.6635
and
63.6640.
56.
§
63.9(
a)
...................................
Applicability
and
State
delegation
of
notification
requirements.
Yes.
57.
§
63.9(
b)(
1)
(
5)
........................
Initial
notifications
.........................
Yes.
58.
§
63.9(
c)
...................................
Request
for
compliance
extension
Yes.
59.
§
63.9(
d)
...................................
Notification
of
special
compliance
requirements
for
new
sources.
Yes.
60.
§
63.9(
e)
...................................
Notification
of
performance
test
...
Yes.
61.
§
63.9(
f)
....................................
Notification
of
visible
emission
(
VE)/
opacity
test.
No.
62.
§
63.9(
g)(
1)
..............................
Notification
of
performance
evaluation
Yes.
63.
§
63.9(
g)(
2)
..............................
Notification
of
use
of
COMS
data
No
.................................................
Subpart
ZZZZ,
40
CFR
part
63,
does
not
contain
opacity
or
VE
standards.
64.
§
63.9(
g)(
3)
..............................
Notification
that
criterion
for
alternative
to
RATA
is
exceeded.
Yes
................................................
If
alternative
is
in
use.
65.
§
63.9(
h)(
1)
(
6)
........................
Notification
of
compliance
status
..
Yes
................................................
Except
that
notifications
for
sources
using
a
CEMS
are
due
30
days
after
completion
of
performance
evaluations.
66.
§
63.9(
i)
....................................
Adjustment
of
submittal
deadlines
Yes.
67.
§
63.9(
j)
....................................
Change
in
previous
information
...
Yes.
68.
§
63.10(
a)
.................................
Administrative
provisions
for
record
keeping/
reporting.
Yes.
69.
§
63.10(
b)(
1)
............................
Record
retention
...........................
Yes.
70.
§
63.10(
b)(
2)(
i)
(
v)
...................
Records
related
to
SSM
...............
Yes.
71.
§
63.10(
b)(
2)(
vi)
(
xi)
................
Records
........................................
Yes.
72.
§
63.10(
b)(
2)(
xii)
.......................
Record
when
under
waiver
..........
Yes.
73.
§
63.10(
b)(
2)(
xiii)
......................
Records
when
using
alternative
to
RATA.
Yes
................................................
For
CO
standard
if
using
RATA
alternative.
74.
§
63.10(
b)(
2)(
xiv)
......................
Records
of
supporting
documentation
Yes.
75.
§
63.10(
b)(
3)
............................
Records
of
applicability
determination
Yes.
76.
§
63.10(
c)
.................................
Additional
records
for
sources
using
CEMS.
Yes.
77.
§
63.10(
d)(
1)
............................
General
reporting
requirements
...
Yes.
78.
§
63.10(
d)(
2)
............................
Report
of
performance
test
results
Yes.
79.
§
63.10(
d)(
3)
............................
Reporting
opacity
or
VE
observations
No
.................................................
Subpart
ZZZZ,
40
CFR
part
63,
does
not
contain
opacity
or
VE
standards.
80.
§
63.10(
d)(
4)
............................
Progress
reports
...........................
Yes.
81.
§
63.10(
d)(
5)
............................
Startup,
shutdown,
and
malfunction
reports.
Yes.
82.
§
63.10(
e)(
1)
and
(
2)(
i)
.............
Additional
CMS
reports
................
Yes.
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E:\
FR\
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19DEP2.
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77874
Federal
Register
/
Vol.
67,
No.
244
/
Thursday,
December
19,
2002
/
Proposed
Rules
TABLE
8
TO
SUBPART
ZZZZ
OF
PART
63
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
ZZZZ
Continued
[
As
stated
in
§
63.6665,
you
must
comply
with
the
following
applicable
general
provisions:]
General
provisions
citation
Subject
of
citation
Applies
to
Subpart
Explanation
83.
§
63.10(
e)(
2)(
ii)
........................
COMS
related
report
....................
No
.................................................
Subpart
ZZZZ,
40
CFR
part
63,
does
not
require
COMS.
84.
§
63.10(
e)(
3)
............................
Excess
emission
and
parameter
exceedances
reports.
Yes.
85.
§
63.10(
e)(
4)
............................
Reporting
COMS
data
..................
No
.................................................
Subpart
ZZZZ,
40
CFR
part
63,
does
not
require
COMS.
86.
§
63.10(
f)
..................................
Waiver
for
recordkeeping/
reporting
Yes.
87.
§
63.11
.....................................
Flares
............................................
No.
88.
§
63.12
.....................................
State
authority
and
delegations
....
Yes.
89.
§
63.13
.....................................
Addresses
.....................................
Yes.
90.
§
63.14
.....................................
Incorporation
by
reference
...........
Yes.
91.
§
63.15
.....................................
Availability
of
information
..............
Yes.
[
FR
Doc.
02
31232
Filed
12
18
02;
8:
45
am]
BILLING
CODE
6560
50
P
VerDate
0ct<
31>
2002
16:
32
Dec
18,
2002
Jkt
200001
PO
00000
Frm
00046
Fmt
4701
Sfmt
4702
E:\
FR\
FM\
19DEP2.
SGM
19DEP2
| epa | 2024-06-07T20:31:40.217787 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0059-0001/content.txt"
} |
EPA-HQ-OAR-2002-0060-0337 | Supporting & Related Material | "2002-11-29T05:00:00" | null |
.
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peci
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111
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y
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r
o
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Press
7
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?
7
,
7
Test
No.
Time
Ambient
Temp.
(
DB)
Specific
Hunnidiity
I
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Baro.
Press
k
I
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+=
I=
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Test
No.
Date
12
8
9
3
I
Time
a:
50
67:
30
F*.
Turbine
Cont.
Temp.=
TS
QF)
I
I
I
Ambient
Temp.
@
B)
I
I
I
SDecific
Humidity
I
I
I
Baro.
Press
t
p
h=
r
a
:
s
1
m
AT
iJ
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L.
~~.
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A,.
.
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<
,
,
Appendix
C.
2.
b
Load
Curves
GRI
1
E
125
15
1971
5/
R
120D755.
T
I_
___
I______
s__
_
TURBINES
INCORPORATED
..
I
DATE
RUN
:
8
NOV
9
3
c
?
"`
GINE
PERFOWANCE
DATA
REV.
2.3
RUN
BY:
DAN
JARRELL
EXHAUST
GAS
ANlD
EMISSION
DATA.
REV.
2.0
,
IB
ID
:
.:
XT
CHANGES
REV.
2.1
@
MARS
100s
MARS
T14000S
(
SOLONOX)
CS/
MD
59F
MATCH
GAS
TMD
2S
REV.
2
DATA
FOR
NOMINAL
PERFORMANCE
FUEL
TYPE
ELEVATION,
I?
EET
INLET
LOSS,
I
N
.
`
H20
EXHAUST
LOSS,
I
N
.
H
2
0
AMB
TEMP,
DEG.
F
REL
"
MI,
PCT
INLET
LOSS
HP
EXHAUST
LOSS
HP
ELEVATION
LOSS
HP
COMP
OR
PIJME'
RPM
OPTIMUM
RI?
M
PERCENT
G2lS
PROD,
SPEED
GAS
PRODUCER
RPM
NET
OUTPUT
POWER
(
HP)
SPECIFIED
PART
LOAD
FUEL
FLOW,,
MMBTU/
HR
HEAT
RATE
BTU/
HP
HR
S
D
NATURAL
GAS
35.0
60.0
43.
24
.
300.
6591.
6591.
87.
9365.
3430.
25.0%
54
.
47
15878
.
INmT
AIR
FLOW,
LB/
HR
204515.
ENGINE
EXH
FLOW,
LB/
HR
206442.
PCD
P.
S.
1C.
GI..
93.7
P.
T.
INLET
TEMP,
DEG.
F
1251.
COMPENSATED
PTIT
DEG,
F
1310.
ENGINE
EXH
TEMP,
DEG.
F
888
.
2185.
2.0
2.0
35.0
60.0
49.
26.
358.
6910.
6910.
88.
9455.
4116.
30.0%
59.03
14340.
13148.
12202.
214218.
222968.
230826.
216332.
225251.
233267.
103.1
112.4
121.2
1260.
1268.
1274
.
1319.
1327.
1333.
896,
902.
905.
35.0
60.0
55.
28.
418
.
7207
.
7207.
88.
9536.
4803.
35.0%
63
.
14
35.0
60.0
60.
30.
478
.
74`
61,
7461.
89
.
9601.
5489.
40.0%
66.97
35.0
601.0
66.
32.
.538.
7687.
7687.
90.
9658.
6175.
45.0%
70.59
11433.
238093.
240684.
129.7
1279
.
1339.
907
.
35.0
60.0
71.
33
..
597
.
7886.
7886.
90.
9723.
6861.
50.0%
74.11
10801.
244736.
247475,
137.7
1285,
1345.
909.
"%
R
TURBINES
INCORPORATED
DATE
RUN:
8
NOV
93
NE
PERFORMANCE
DATA
REV.
2.3
R
U
R
B
E
D
j
JJST
GAS
AND
EMISSION
DA
?
CHANGES
REV.
2.1
MARS
T14000S
(
SOLONOX)
CS/
MD
59F
MATCH
GAS
TMD
2S
REV.
2
DATA
FOR
NOMINAL
PERFORMANCE
:
VEL
T
Y
~
G
S
D
NATURAL
GAS
,
LEVATION,
FEET
2185.
7+
LNLET
LOSS,
I
N
.
H20
2.0
SXHAUST
LOSS,
I
N
.
H20
2.0
r
J
+
f
O
D
WMB
TEMP,
DEG.
F
40.0
40.0
40.0
40.0
$
EL
HUMI,
PCT
60.0
60.0
60.0
60.0
60.
30.
~
X
H
A
U
S
T
LOSS
H
P
24.
26.
28.
ELEVATION
LOSS
HP
297.
353
.
413.
472.
COMP
OR
PUMP
RPM
6585.
6899.
7191.
7450.
89.
PERCENT
GAS
PROD.
SPEED
87
.
88.
89
.
SAS
PRODUCER
R
P
M
9402.
9491.
9571.
9639.
NET
OUTPUT
POWER
(
HP)
3389.
4067.
14744.
5422.1
S
P
E
C
I
F
I
E
D
PART
LOAD
25.0%
30.0%
35.0%
40.0%
IZNLET
LOSS
HP
43.
48.
54
.
3PTIMUM
RPM
.
6585.
6899.
7191.
7450.
FUEL
FLOW,
MMBTU/
HR
54.09
58.61
62.64
HEAT
RATE
,
BTU/
HP
HR
15963.
14411.
13202.
INLET
AIR
FLOW,
LB/
HR
202242.
211747.
220297.
ENGINE
EXH
FLOW,
LB/
HR
204158.
213849.
222565.
P.
T.
INLET
TEMP.
DEG.
F
1257.
1266.
1273.
COMPENSATED
PTIT
DEG.
F
1316.
1325.
1332.
I
C
D
P.
S.
I.
G.
93.0
102.4
111.5
ENGINE
EXH
TEMP,
DEG.
F
897.
904.
909.
66.40
12247.
228067
.
230490.
120.3
1279
.
1338.
913.
40.0
60.0
65.
31.
531.
7674
.
7674.
90.
9695.
6100.
45.0%
69.99
11474
7M
f
.
C
I
"
40.0
60.0
71.
33
.
590.
..
7874.
7874
.
90.
9756.
50.0%
1
6778.
73.38
10827
.
235219.
241730,
237791.
244444.
128.6
136.7
1284.
1289.
1343.
1348.
914
.
915
.
.
.
.
.
7
,
:
L.
*
:
I
MARS
T14000S
(
SOLONOX)
CS/
MD
59F
MATCH
GAS
TMD
2S
REV.
2
DATA
FOR
NOMINAL
PERFORMANCE
FUEL
TYPE
S
D
NATURAL
GAS
ELEVATION,
FEET
2185.
'
INLET
LOSS,
:
IN.
H20
2.0
EXHAUST
LOSS,
I
N
.
H
2
0
2.0
'
AMB
TEMP,
DE(:.
F
40.0
40.0
40.0
40.0
40.0
40.0
REL
HTJMI,
P
c
r
60.0
60.0
60.0
60.0
60.0
60.0
INLET
LOSS
HIP
76.
81.
87.
92.
97
.
103
.
EXHAUST
LOSS
HP
35.
36.
38.
39.
41.
42
.
.
ELEVATION
LOSS
HP
648.
708.
766.
825.
884,
941.
.'
zOMP
OR
PUMP
RPM
8054
.
OPTIMUM
RPM
8054
.
GAS
PRODUCER
RPM
9820.
SPECIFIED
PART
LOAD
55.0%
FUEL
FLOW,
MUIBTU/
HR
76.67
OHEAT
RATE
,
I3TU/
HP
HR
10284
.
.
INLET
AIR
FLOW,
LB/
HR
247994.
ENGINE
EXH
FlLOW,
LB/
HR
250846.
ZPCD
P.
S.
I.
G<.
144.6
P.
T.
INLET
TEMP.
DEG.
F
1293,
COMPENSATED
]?
TIT
DEG.
F
1353.
,
ENGINE
EXH
TEMP,
DEG.
F
915.
NET
OUTPUT
POWER
(
HP)
7456J
7.
8226.
8226.
9883
.
8133
.
60.0%
79
.
84
9816.
254158.
257142.
152
.
5
1298.
1357.
915.
8379.
8379.
9995.
8811.
65.0%
83.09
9431.
260628.
263747.
160.0
1304.
1363.
914
.
8519.
8519
.
10117.
9489.
70.0%
86.24
9088.
266511.
269762.
.
167.4
1310.
1369.
913.
8648.
8648
.
10238.
10167
.
75.01%
89
.
16
87701.
271926.
275300.
174.7
1314
.
1373
.
912
.
8770.
8770.
10374
.
10845.
80.0%
91.92
8475
.
276721.
280212.
182.1
'
13
17.
1377.
910.
.
.
i
MARS
T14000S
(
SOLONOX)
CS/
MD
59F
MATCH
GAS
TMD
2S
REV.
2
DATA
FOR
NOMINAL
PERFORMANCE
3JEL
TYPE
ISLEVATION
,
FEET
ENLET
LOSS,
I
N
.
H20
'
ZXHAUST
LOSS,
IN
H20
iHB
TEMP,
DEG.
F
S
D
NATURAL
GAS
2185.
2.0
2.0
b33'
35.0
35.0
35.0
35.0
35.0
35.0
60.0
87.
93
.
98
.
103
.
656.
716.
776.
835.
895.
951.
60.0
60.0
60.0
60.0
60.0
*,
EL
HUMI,
PCT
INLET
LOSS
HP
77.
82.
2XHAUST
LOSS
H
P
ZSVATION
LOSS
HP
35.
36.
38,
40.
41.
43
.
ZOMP
OR
PUMP
RPM
8069.
8240.
8395.
8534.
8664.
8788.
IlPTIMUM
RPM
8069.
8240.
8395.
8534.
8664.
8788.
SAS
PRODUCER
RPM
9788.
9866.
9983.
10111.
10233.
10385.
7547.
8233.
8919.
9606.
110292.
10978
I
~
E
T
OUTPUT
POWER
(
HP)
'
SPECIFIED
PART
LOAD
55.0%
60.0%
65.0%
70.0%
75.0%
80.0
1
_
.
I
'
FUEL
FLOW,
MMBTU/
HR
77.44
80.73
84.07
87.27
90.24
93.00
BEAT
RATE
,
BTU/
HP
HR
10261.
9805.
9426.
9085.
8768.
8472.
INLET
AIR
FLOW,
LB/
HR
251135.
257572.
264240.
269988.
275537.
279984,
ENGINE
EXH
FLOW,
LB/
HR
254013.
260587.
267394.
273277.
278950.
283516.
PCD
P
.
S
.
I
.
G
.
145.8
153.6
161.2
168.7
176.2
183.5
B,
T.
INLET
TEMP,
DEG.
F
1290.
1296,
1302.
1309.
1313.
1317.
COMPENSATED
PTIT
DEG.
F
1349,
1355.
1362.
1368.
1372.
1376,
ENGINE
EXH
TEMP,
DEG.
F
909
.
909.
908.
909.
907.
906.
MARS
'
T14000S
(
SOLONOX)
CS/
MD
59F
MATCH
GAS
.
TMD
2S
REV.
2
DATA
FOR
NOMINAL
PERFORMANCE
FUEL
TYPE:
SD
NATURAL
ELEVATIONI,
FEET
EXHAUST
LOSS,
I
N
.
H20
INLET
LOSiS,
I
N
.
H
2
0
GAS
2185.
2.0
2
.
0
'
33'
AMB
TEMP,
DEG,
F
35.0
35.0
35.0
35.0
REL
HUMI,
PCT
6
0
.
0
60.0
60.0
60.0
INLET
LOSS
HP
109.
114.
119
.
125.
EXHAUST
LOSS
HP
44.
46.
47
.
49.
ELEVATION
LOSS
HP
1009.
1068,
1129.
1193.
COMP
OR
PUMP
RPM
8902.
9001.
9087.
9234.
OPTIMUM
RPM
8902.
9001.
9087.
9234.
GAS
PRODUCEIR
RPM
10536.
10695,
10848.
11051.
NET
OUTPUT
POWER
(
HP)
11664.
12350.
113036.
13722.1
SPECIFIED
PART
LOAD
85.0%
90.0%
95.0%
FULL
FUEL
FLOW,
IYIMBTU/
HR
95.49
97.71
99.73
104.01
HEAT
RATE
,
BTU/
HP
HR
8187.
7912.
7650.
7580.
INLET
AIR
FILOW,
LB/
HR
283905.
286668.
288893,
291168.
ENGINE
EXH
F
L
O
W
,
LB/
HR
287544.
290404.
292720.
295195.
PCD
P.
S.
1.
G.
190.9
198.2
205.5
211.1
PIT,
I
N
W
T
TEMP,
DEG.
F
1318.
1319.
1320.
1356.
COMPENSATED
PTIT
DEG,
F
1378.
1379,
1379.
1415.
ENGINE
EXlK
TEMP,
DEG.
F
904
.
901,
896,
918
,
,
...
_
~
LE~
WRE$
UES
INCORPORATED
DATE
RUN:
9
NOV
93
RUN
BY:
DAN
J
A
R
R
E
r
X
_
PE_
fzF_
pECE
DATA
REV.
2.3
UST
GAS
AND
EMISSION.
DATA
%
iEV.
2
.
o
.
REV.
2.1
MARS
T14000S
(
SOLONOX)
CS/
MD
59F
MATCH
GAS
TMD
2S
REv.
2
DATA
FOR
NOMINAL
PERFORMANCE
`
UEL
TYPE
LEVAT
TI
ON,
FEET
3LET
LOSS,
I
N
.
H20
:
XHAUST
LOSS,
I
N
.
H20
IMB
TEMP,.
DEG.
F
ZL
HUMI,
PCT
:
NLET
LOSS
HP
X AUST
LOSS
HP
XEVATION
LOSS
HP
:
OMP
OR
PUMP
RF'M
bPTIMUM
RPM
;
AS
PRODUCER
RPM
ET
OUTPUT
POWER
(
HP)
iPECIFIED
PART
LOAD
;
PEL
FLOW,
MMBTU/
HR
lEAT
RATE
,
BTU/
HP
HR
INLET
AIR
FLOW,
LB/
HR
ENGINE
EXH
FLOW,
LB/
HR
T
D
P.
S.
I.
G.
).
To
INLET
TEMP.
DEG.
F
SD
NATURAL
GAS
2185.
2.0
.
2.0
40.0
40.0
6
0
.
0
60.0
108.
113.
44
.
46.
997.
1055
8883.
8985.
8883.
8985.
10521.
10673
.
11522.
12200.
85.0%
90.0%
94.38
96.61
8191.
7919.
40.0
60.0
118
.
47
.
1114
9077
.
9077.
10834.
12878.
95.0%
98.66
7661.
40.0
6
0
.
0
124.
49.
1177.
9221.
9221
11034.
13556.
FULL
102.90
7591.
280792,
283842.
286574.
2a8872.
284388.
287535.
290357.
292853.
189.4
196.6
203.8
209.3
1319.
1320.
1
3
2
0
,
`
1356.
_
_
`
OMPENSATED
PTIT
DEG.
F
1378,
1379.
1379.
1415.
ZNGINE
EXH
TEMP,
DEG.
F
907.
904.
899.
921.
i
GlU
1
E
125
15
197
lSlRl20D755.
T
Appendix
C.
3
Carnot
CEMS
Data
Appendix
C.
3.
a
NO,,
N,
O,
SO,,
CO,
0,,
and
CO,
Summaries
GFUl
E
125
15
1971
YR120D755.
T
<.
'
Test
No.
l
CEM
6A
2
CEM
6A
3CEM
6A
Average
IDate
12/
7/
93
12/
7/
93
12t7193
.
Time
1019.1119
1144
1234
1254
1334
INominal
Load
(%)
IF&
Flow
(
scfh)
IDry
Bulb
Temp.
0
Wet
t3ulb
Temp.
0
IReference
Temp.
0
.
IBarornetric
Press.
(
in.
Hg)
lrlumidity
(#
H2O#
air)
4
.
..
IEPA
"
Fd
factor(
dscf/
l
OqBtu)'
lfPA
"
Fc'
factor(
dscf/
l
O"
6Bhr)"
liW
(
btulsd)
Stack
Flow
based
on
Fd
(
dsdm)
!
Stack
Flow
based
on
Fc
(
dxfm)
Stack
Flow
based
on
S
type
pitot
(
dxfm)
02.41;
(
202.
Y
IWx.
ppm
(
3.
ppm
IQO.
ppm
IUOX.
ppm
Q
15
%
0
2
IWx,
ppm
Q
15
%
0
2
IS0
IUOx.
Iblhr+
IUOx.
Ibihr++
IrlOX.
Iblhr+++
IJOX.
lWlCr68tW
lmx.
lb110*
6Blu++
CO.
pipm
Q
15
%
0
2
CO.
Itfir+
(=
o.
uJhr++
CO.
Itmr
co.
IVlO*
GBtu+
(
10.
ItdlO%
Bhr*
1520.
ppm
Q
15
%
02
1520,
Ibh+
1520,
lwhr++
1520.
Ib/
hr+++
1520.
IWl
C
r
6
m
1520.
Ibll
0%
H2S.
ppm
tQS.
lWhr
S02.
pprn
!;
02.
ppm
Q
15%
0
2
S02,
lblhr
,
r302.
IWlO"
GBtw
SO2,
rmi
0%
100
108.200
35
35
68
27.57
0.0043
8.609
1,017
1.013
57.463
54.007
89.428
15.18
3.44
25.1
5.8
1
.
o
25.9
27.9
10.3
9.7
16.1
0.094
0.089
6.0
1
5
1.4
2.3
0.01
3
0.013
1.0.
0.4
0.4
0.6
0.004
0.003
<
1.4
<
0.013
<
0.04
<
0.05
<
0.03
<
0.0002
<
0.0002
100
108.420
35
35
68
27.55
0.0043
8,609
1.017
1,013
59.237
55241
89.969
15.34
3.37
26.3
8.4
1.1
27.9
30.1
112
10.4
16.9
0.1
02
0.095
8.9
2
2
2.0
3.3
0.020
0.018
1
2
0.4
0.4
0.7
0.004
0.004
1.4
0.01
3
0.04
0.05
0.03
0.0002
O.
OOO2
100
108.660
36
36
68
27.54
0.0044
8.609
1.01
7
1.013
59.907
57231
90.055
15.39
3.26
25.9
5
2
1.1
27.7
29.9
11.1
10.6
,
16.7
0.101
0.096
5.6
1.4
.1.3
2.0
0.012
0.012
1
2
0.5
0.4
0.7
0.004
0.004
1.4
0.013
0.04
0.05
0.03
0.0002
0.0002
58.869
55.493
89.817
15.30
3.36
'
25.8
6.5
1
.
l
272
29.3
10.9
102
16.6
0.099
0.093
6.8
1.7
1.6
2.5
0.015
0.014
1.1
0.4
.
0.4
0.7
0.004
0.004
1.4
0.01
3
0.04
Q.
05
0.03
0.0002
0.0002
IS0
PRESS
(
Camot
method)
I:
S0
TEMP
I
S
0
HUMIDITY
150
F,
ACTOR
1.042
1.042
1.042
.
1.042
1.075
1.075
1
.
OR
1.074
0.963
0.963
0.965
0.963
1.078
1.079
1.078
1.078
EF'A
Fd
factor
02
based
*
EPA
Fc
factor
C02
based
4.
~
Mass
emissions
are
calc.
using
stack
flow
based
on
Fd
factor
(
02)
++
Mass
emissions
are
calc.
using
stack
flow
based
on
Fc
facior
(
C02)
+++
Mass
emissions
are
calc.
using
stack
flow
based
on
S
type
pitot
IS0
PISESS
=
(
29.92
in.
Hg
I
B.
P.
in.
Hg)"
l/
2
IS0
TEMP
=
(
288
K
I
Tambient
K)"
l
.53
IS0
HIUMIDITY
=
eA(
l
9
(
Humidity
0.0063))
180
FACTOR
=
IS0
PRESS
IS0
TEMP
IS0
HUMIDITY
Nominal
Load
(%)
F
I
J
~
Fliow
(
sdfi)
Dry
Bulb
Temp.
(
F)
*
ret
Bidb
Temp.
0
Reference
Temp.
(
F)
Rarometrk
Press.
on
Hg)
Humidity
(
0
HZOM
air)
EIPA
F
W
factor(
dscf/
lO%
Btu)'
EIPA
T
c
factor(
dscfll0"
BBtu)"
HMI
(
l1Wsd)
Stack
I3ow
based
on
Fd
(
dsdm)
Stack
Flow
based
on
Fc
(
dscfrn)
Sib&
Flow
based
on
S
type
pitot
(
dscfm)
02.
w
co2.
?
6
CO.
Prim
N20.
ppm
N&.
FlPm
NOx.
Flpm
@
15
%
0
2
N&.
FIpm
@
15
%
02
fso
NOx.
IldtU+
NOx.
Ilfir++
NOx.
UJ/
llr+++
NDX.
lldl
owBtu+
NOx.
ll3/
10"
68an+
CO.
prim
Q
15
%
02
CQ.
bhr+
co.
m++
CO.
bhr
CO.
IbtlOAGBtu+
CO.
lhfl
OA6Bhr++
N20.
ppm
@
15
%
0
2
N20.
Ibh+
NZO.
Iblhr++
N20.
Ihlhrcc+
N2O.
lhll
NBtu+
N2O.
lbllO%
8tuc+
H2S.
pprn
H2S.
llblhr
S02.
ppm
S02.
pprn
@
15%
02
s02.
lblhr
SOZ.
lbll
o%
Btu+
502.
IbllCP6Btu
75
94.860
36
36
68
27.54
0.0044
8,609
1,017
1.013
56,392
52204
65.965
15.79
3.12
20.8
15.1
1.3
24.0
25.9
8.4
7.8
9.8
0.087
0.081
17.4
3.7
3.4
4.3
0.039
0.036
1
.5
0.5
0
5
0.6
0.005
0.
C
1.4
C
0.012
C
0.04
<
0.05
<
0.02
<
O.
OOO2
<
o.
Oo02
75
94.700
37
37
68
27.56
0.0046
8.609
1.017
1,013
55.860
51
,950
67.025
15.75
3.13
21
.
o
15.0
1
.
o
24.1
26.0
8.4
7.8
10.1
0.088
0.082
172
3.6
3.4
4.4
0.038
0.035
1.1
0.4
0.3
0.4
0.004
0.004
1.4
0.01
2
0.04
0.05
0.02
0.0002
0.0002
56,126
52.077
66.495
15.77
3.13
20.9
15.0
1.1
24.0
25.9
8.4
7.8
10.0
0.088
0.081
17.3
3.7
3.4
4.4
0.038
0.036
1.3
'
0.4
0.4
0.5
0.005
0.004
1.4
0.012
0.04
0.05
0.02
0.0002
O.
OOO2
.'
,
.
ISb
PRESS
(
Camot
method)
IS0
TEMP
BO
H~
UMlOITY
SO
FACTOR
1.042
.
1
.
on
0.965
1.078
1.042
1.069
0.968
1.078
1.042,
1.070
0.966
1.078
..
_.
PIA
FdJactor
0
2
based
*'
EF'A
Fc
factor
CO2
based
"
*.
+
Misss
emissions
are
calc.
using
stack
flow
based
on
Fd
lador
(
02)
++
Nhss
emisuons
are
calc.
using
stack
R4w
based
on
Fc
facbr
(
CO2)
+++
Mass
emissions
are
calc.
using
stack
flow
based
on
S
type
pitd
I
S
0
PRESS
=
(
29.92
in.
Hg
I
B.
P.
in.
Hg)*
lQ
I
O
TEMP
=
(
288
K
I
Tambient
Kp1.53
BO
HUMlDlN
=
eA(
19
(
Humidity
0.0063))
IS0
FACTOR
=
IS0
PRESS
IS0
TEMP
*
IS0
HUMiOlTY
Test
No.
Date
Time
Average
Nominal
Load
(%
j
Fuel
Flow
(
SCRI)
Dry
Bulb
Temp.
(
F)
Wet
Bulb
Temp.
(
F)
Reference
Temp.
(
F)
Baromebic
Press.
(
in.
Hg)
Humidity
(
at
HZOl
air)
EPA
'
F6
factor(
dsdl1NBhr)'
EPA
'
Fc.
factor(
dSdl1
OW3tu)
HHV
WSCQ
StacK
Flow
based
on
Fd
(
dsdm)
Stack
Flow
based
on
Fc
(
dscfm)
Stack
Row
based
on
S
type
pitot
(
dsdm)
02,
%
c02.
%
NO*.
ppm
CO.
ppm
N20.
ppm
NO*.
ppm
@
15
'%
02
NOx,
pprn@
15%
02!
SO
NO*.
Ib/
hr+
NOx.
IMU*
NO*.
Ib/
ht++
NO*.
lbll
O%
Btu+
NOx.
IbflO%
Btw+
CO.
ppm
Q
15
%
02
CO.
IWr+
CO.
IMr*
CO.
IWr*
co.
Ibllo"
GBtu+
CO.
Ib/
lO%
Btu++
~
2
0
.
ppm
Q
15
%
02
N20.
Ibhr+
N20.
lblhr++
N20.
Lblhr*++
N20.
IbM
0"
6Btu+
N20.
lWlO%
Btuc*
S02.
pprn
S02,
pprn
Q
15%
02
s02.
fMu
502.
IbllD*
6Btui
s02.
IWl0"
6Btu++
<
<
50
sO.
520
43
41
68
27.44
O.
OO50
8.609
1.017
1.013
47.496
46.866
44.474
.
15.75
2.95
352
572
1.8
403
43.1
121)
11.8
112
0.147
0.145
65.6
11.9
11.7
11.1
0.145
0.143
2.1
0
6
0.6
0.6
0
007
0
007
1.4
0.01
0
0.04
0.05
0.02
0.0002
O.
OOO2
50
(
Lean
PreMi)
79,580
44
42
68
27.40
0.0051
8.609
1.017
1,013
48253
46.795
44.658
15.89
2.92
34.5
52.5
1
3
40.6
43.4
11.9
11.6
11.0
0.1
48
0.143
61.8
11.0
10.7
10.2
0.137
0.133
1.6
0.4
0.4
0.4
0.005
0.005
1.4
0.01
0
0.04
0.05
0.02
0.0002
0.0002
47.874
46.831
44.566
15.82
2.94
34.9
54.9
1.6
40:
s
43.3
11.9
11.7
11.1
0.1
47
ai+
63.7
11.4
1
1
2
0.141
0.138
1
8
0
5
0
5
O
S
0.006
0.006
1.4
0.01
0
0.04
0.05
0.02
O.
WO2
0.0002
10.7
IS0
PRESS
(
Carnot
method)
1.044
1.045
1.045
IS0
TEMP
1.049
1.046
1.048
0.976
0.977
0.977
1.069
1.
068
1.069
IS0
HUMIDITY
IS0
FACTOR
EPA
Fd
factor
0
2
based
..
EPA
Fc
fador
C02
based
+
Mass
emissions
are
calc.
using
stack
flow
based
on
Fd
factor
(
02)
++
Mass
emissions
are
calc.
using
stack
fiow
based
on
Fc
factor
(
C02)
+++
Mass
emissions
are
calc.
using
stack
flow
based
on
S
type
pitot
IS0
PRESS
=
(
29.92
in.
Hg
I
B.
P.
in.
Hg)
W2
IS0
TEMP
=
(
288
K
i
Tambient
QA1
53
IS0
HUMlDrrY
=
eA(
19
.
(
Humidity
ODO63))
IS0
FACTOR
=
IS0
DRESS
*
IS0
TEMP
IS0
HUMIDITY
7
Test
No.
Date
Time
Average
Nominal
Load
(%)
Fuel
fllow
(
scfh)
Dry
Bulb
Temp.
(
F)
Wet
Bulb
Temp.
0
Refwence
Temp.
(
FJ
Barometric
Press.
(
in.
Hg)
Humidity
(#
H2OnP
air)
EPA
'
Fb
factor(
dsdI1
OA6BtU)'
PA
'
Fc"
factor(
dsdI1
O%
BtU)
Stack
lRow
based
cn
Fd
(
dscfm)
Stack
lnow
based
on
Fc
(
dscfm)
Stack
lflow
based
on
S
type
pitot
(
dsmn)
02.
%
COZ.
'
R
NOx.
ppm
CO.
piJm
N
2
0
.
ppm
(
IWN
NlOx,
ppm
Q
15
%
02
NKk,
ppm
Q
15
%
02
IS0
NIOx.
Ilbhr+
NDx,
IiblhrM
NDx,
UMu+++
~
i
~
x
,
mwi
w
a
~
+
CD.
ppm
Q
15
%
0
2
NDx,
IIWl
(
yLGBtu++
GO.
Iblhr+
CO.
Iblhr++
CD.
lblhrm
CO,
IbllO%
Btu+
cx9.
Ibillo%
Bam
hQ0.
ppm
Q
15
%
0
2
N20,
Im+
hl2O.
llb/
hr*
hr20.
IlblhW
N2O,
Ilbllo%
8tu+
hno.
Ilbllo%
Btu++
H2S.
ppm
HZS.
llbh
S02.
lppm
S02.
lppm
Q
15%
02
502,
IIMU
bi02.
'
Wlo%
Btu+
$
02.
WlO%
Btu++
.
.
45
42
68
27.35
0.0048
8.609
1.017
1.013
44.210
45.793
45,515
16.96
2.15
9
1498.6
112.6
302
32
0
6.4
6.6
6.6
0.110
0.114
22442
288.9
2992
297.4
4.973
5.151
168.5
34.1
35.3
35.1
0587
0.608
c
1.4
<
0.007
SC
20.1
c
0.03
<
0.
B
<
0.01
<
O.
OOO2
<
0.
m1
35
(
Diision)
58,220
43
42
68
27.35
0.0052
8.609
1.01
7
1.013
44.888
45.233
44,?
78
16.96
221
20.1
1453.0
112.5
30.1
32.3
,
6.5
6
5
6.4
0.110
0.110
21
75.7
284.3
286.5
283.6
4.821
4.858
168.5
34.6
34.9
34.5
0.587
0.591
1.4
0.007
0.03
0.05
0.01
0.0002
OMMZ
44.549
45.513
45.147
16.96
2.1
8
20.1
1475.8
112.5
30.1
322
6.4
6.6
6
5
0.1
10
0.1
12
2209.9
2196.6
292.9
290.5
4.897
5.005
168.5
34.3
35.1
34.8
0.587
0.600
1.4
0.007
0.03
0.05
0.01
O.
OOO2
O.
OOO2
SO
PRESS
(
Carnot
method)
L30
TEMP
L30
"
JMIDITY
t
S
0
FACTOR
1.046
1.046
1.043
1.049
0.972
0.979
1
.
om
1.075
1.046
1.046
0.976
1.067
*
PA
Fd
fador
02
based
41
Mass
emissions
are
cak.
using
stack
iiow
based
on
Fd
factw
(
02)
++
Mass
emissions
are
calc.
using
stack
flow
based
on
Fc
factor
(
C02)
+
H.+
Mass
emissions
are
calc.
usingstackflow
based
on
S
lype
pitot
Is0
PRESS
=
(
29.92
in.
Hg
I
B.
P.
in.
Hg)
W2
IS0
TEMP
=
(
288
K
I
Tarnbient
Q'
1.53
SO
PlUMlMM
=
eA(
l
9
*
(
Humidity
0.0063))
IS0
FACTOR
=
IS0
PRESS
*
IS0
TEMP
IS0
HUMIDITY
**
PA
Fc
factw
C02
based
.
_.
.
.
.
1
.
7
Ted
No.
Date
rime
20
15
(
Diion)
34=
28.500
Nominal
Load
(%)
Fuel
Row
(
XR)
I
Dry
Bulb
Temp.
(
F)
Wet
Bulb
Temp.
(
F)
Reference
Temp.
(
F)
Barometric
Press.
(
in.
Hg)
Humidity
(#
H20W
air)
43
42
68
27.35
0.0052
43
42
68
27.35
0.0052
8.609
1,017
1,013
30.061
33.983
8.609
1.017
1.013
34.362
37.731
EPA
'
Fb
factor(
dsdl1
WBtu)'
EPA
'
Fc'
factor(
dsdl1
WBtu)"
HHV
(
btulsd)
Stack
Flow
based
on
Fd
(
dsdm)
Stack
Flow
based
on
Fc
(
dsdm)
02.
Dk
co2.
%
NOx.
P
P
~
CO.
ppm
N2O.
ppm
NOx.
ppm@
15%
02
NOx.
ppm
Q
15
%
0
2
IS0
NOx.
Iblhr+
NOx.
IbhM
NOx.
IbllO"
6Btuc
NOx.
Wl0"
6Btu++
17.85
1.57
10.6
2009.4
351.4
18.02
1.44
9.2
1923.0
382.8
18.8
20.3
2.0
2
2
0.078
0.
oSs
20.6
22.1
2.6
2.9
0.075
0.082
3939.4
252.0
284.9
8.730
9.868
CO.
ppm
@
15
%
0
2
CO.
Iblhr+
co.
Ihlhr++
co.
Wl
o"
GBtu+
co.
Ibllcr6BtVw
3887.1
'
301.0
330.6
8.614
9.458
679.7
82.7
90.8
2.367
2599
784.1.
78.8
89.1
2.730
3.087
N20.
ppm
@
15
%
0
2
N20.
Whr+
N20.
I
W
h
m
N20.
IbllO"
6Btu+
N20.
IbllO"
6Btrm
1.4
0.00
1.4
0.00
H2S.
ppm
H2S.
lblhr
C
C
0.02
0.05
0.01
o:
m1
0.
m1
0.02
0.05
0.01
.
o.
Ooo1
o.
oO01
SO2.
ppm
S02.
ppm
Q
15%
02
s02.
Iblhr
s02.
IblloLGBtu+
s02.
Ibllo"
GBtU++
IS0
PRESS
(
Carnot
method)
IS0
TEMP
IS0
HUMIDITY
IS0
FACTOR
1.046
1.049
0.979
1.075
1.046
1.049
0.979
1.075
I
.
.
EPA
Fd
factor
02
based
PA
Fc
factor
C02
based
'
+
Mass
emissions
are
calc.
using
stack
flow
based
on
Fd
factor
(
02)
++
Mass
emissions
are
calc.
using
stack
flow
based
on
Fc
factor
(
CO2)
IS0
PRESS
=
(
29.92
in.
Hg
I
B.
P.
in.
Hg)'
lR
IS0
TEMP
=
(
288
K
I
Tambient
K)*
l.
53
IS0
HUMIDITY
=
e*(
19
(
Humidity
0.0063))
IS0
FACTOR
=
IS0
PRESS
*
IS0
TEMP
IS0
HUMIDITY
.
.
..
......
.
I.
.
Appendix
C.
3.
b
Calibration
md
Drift
Corrc:::
zs
GRI
1E
I25
15
197
1
SIR
120D755.
T
t
CEM
System
Bi,
as
and
Linearity
Correction
Calculations
Test
No.
Acceptance
Run
1
CEM
6A
0
2
c02
co
NOx
N20
Criteria
Status
Linearity:
Analyzer
Range
1
Analyzer
Range
2
High
Cat
Mid
Cal
Analyzer
Reads
Analyzer
Cat.
Error,%
Low
Cal
Analyzer
Reads
Analyzer
Cal.
Error.%
.
System
Bias:
Pretest
Bias
zero
Span
ZWO
Span
Posttest
Bias
Span
V,
alue
Zero
IDrift,
%
Span
Drift.
%
Test
Ave.
Corrected
Ave.
25
20.90
11.17
11.31
0.6
7.99
8.16
0.7
0.1
5
8.30
0.1
5
8.03
7.99
0.00
1
08
15.39
15.18
.
25
22.48
15.20
15.59
1.6
NA
NA
0.0
0.00
22.03
0.00
22.64
22.48
0.00
2.44
3.42
3.44
500
100.
424.00
84.87
79.90
1
.
o
NA
NA
0.0
0.00
79.90
1.10
79.50.
84.87
1.10
0.40
4.96
5.83
250
100
227.20
139.30
139.40
0.0
89.72
90.30
0.2
100
80.00
40.10
40.60
0.5
NA
NA
0.0
0.00
1.20
87.50
40.25
0.30
1.15
86.00
40.70
89.72
40.1
0
0.12
0.05
0.60
0.45
i
2%
<
2%
<
5%
<
5%
<
5%
e
5%
c
3%
K
3%
PASS
PASS
PASS
PASS
PASS
FAIL
PASS
PASS
24.40
2.16
25.12
1.01
Calculations:
Analyzer
Cal.
Ernor,%
=
[
Low(
Analyzer
Reads)
Low(
Cal)]
/
Analyzer
Range
X
100,
%
Zero
Drift,
%
:=
[
Posttest
Biasgero)
Pretest
Bias(
Zero}]
/
Analyzer
Range
X
100,
%
Span
Drift,
%
=
[
Posttest
Bias(
Span)
Pretest
Bias(
Span)]
/
Analyzer
Range
X
100,
%
Corrected
Avt?.
=
(
Span
Value
/
(((
Posttest
Bias(
Span)
+
Pretest
Bias(
Span))
(
Posttest
Biasgera)
+
Pfietest
Bias
(
Zero)))
/
2))
X
(
Test
Ave.
(
Posttest
Biasgero)
+
Pretest
Bias(
2ero))
/
2)
Carnot
2/
21/
94
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptance
Run
2
CEM
6A
0
2
c
0
2
co
NOx
N20
Criteria
Status
Analyzer
Range
25
25
100
100
100
.
System
Bias:
Pretest
Bias
Zero
0.1
5
0.00
0.00
0.30
1.15
<
5%
PASS
Spain
8.03
22.64
85.90
86.00
40.70
<
5%
PASS
Posttest
Bias
Zero
0.1
5
0.00
0.00
0.30
1.15
<
5%
PASS
Spain
7.99
22.50
85.00
85.50
40.25
<
5
%
PASS
Span
'
Value
'
7.99
22.48
84.87
89.72
40.1
0
Zero
Drift,
%
0.00
0.00
0.00
0.00
0.00
~
3
%
PASS
Spain
Drift,
%
0.16
0.56
0.90
0.50
0.45
<
3%
PASS
Test
Ave.
15.25
3.38
8.48
25.39
2.23
Corrected
Ave.
15.34
3.37
8.42
26.34
1.10
Camot
3/
29/!
94
.
.
CEM
System
Bizs
and
Linearity
Correction
Calculations
Test
No.
Acceptance
Run
3
CEM
6A
02
c02
co
NOx
N20
Criteria
Status
4
Analyzer
Range
25
25
100
100
100
System
Bias:
Pretest
Bias
Zero
Span
Zero
Span
Posttest
Bias
Span
Value
0.00
22.50
0.00
85.00
0.30
85.50
1.15
<
5%
PASS
40.25
2
5%
PASS
0.15
7.99
0.00
85.60
84.87
0.30
89.72
85
90
1.15
c
5%
PASS
40.50
5%
PASS
40.1
0
0.15
.
7.98
7.99
0.00
22.50
22.48
0.00
0.40
0.00
<
3%
PASS
0.25
c
3%
PASS
Zero
Drift,
%
Span
Drift,
%
0.00
.
0.04
0.00
0.00
0.00
0.60
Test
Ave.
Corrected
Ave.
24.93
25.88
2.24
1.11
15.25
15.39
3.26
3.26
5.22
5.1
9
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptance
Run
4
CEM
6A
0
2
c02
co
NOx
N20
Criteria
Status
Analyzer
Range
System
Bias:.
Pretest
Bias
,
Zero
Span
Posttest
Bias
Zero
Span
Spain
Value
Zero
Drift,
%
Span
Drift,
%
Test.
Ave.
Corrected
Ave.
25
25
0.15
0.00
7.98
22.55
0.14
0.04
7.97
.
22.39
7.99
22.48
0.04
0.16
0.04
0.64
15.63
3.10
,
15.79
3.12
100
0.00
85.60
0.00
85.80
84.87
0.00
0.20
15.26
.
15.11
100
0.30
.
85.90
0.1
0
86.00
89.72
0.20
9.1
0
20.06
20.78
100
1.15
1
~
5
%
.
PASS
40.50
<
5%
PASS
1
95
<
5%
PASS
40.60
~
5
%
PASS
40.1
0
0.80
<
3%
PASS
0.1
0
c
3%'
PASS
2.82
1.31
...
.
7
Camot
2/
21
/
94
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptance
Run
Status
1
5
CEM
6A
0
2
e
0
2
co
NOx
N20
Criteria
Analyzer
Range
25
25
100
100
100
System
Bias:
Pretest
Bias
Zero
Span
Zero
Span
Posttest
Bias
.
Span
Value
0.00
85.80
0.10
86.00
1.95
40.60
~
5
%
PASS
<
5
%
PASS
0.14
7.97
0.04
22.39
0.30
85.80
84.87
0.10
85.30
89.72
2.00
41
00
40.1
0
~
5
%
PASS
~
5
%
PASS
0.1
5
8.01
7.99
0.04
22.55
22.48
0.05
0.40
~
3
%
PASS
~
3
%
.
PASS
Zero
Drift,
%
Span
Drift,
%
0.04
0.16
0.00
0.64
3.09
3.13
0.30
0.00
0.00
0.70
20.1
5
21.03
2.90
0.96
Test
Ave.
'
Corrected
Ave.
15.62
15.75
15.27
14.98
Carnot
2/
21/
94
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptance
Run
6
CEM
6A
02
c02
co
NOx
N20
Criteria
Status
Linearity:
Analyzer
Range
1
Analyzer
Range
2
High
Cal
Mid
Cal
Analyzer
Reads
Analyzer
Cal.
Enror,%
Low
Cal
Analyzer
Reads
Analyzer
Cal.
Enror,%
System
Bias:
Pretest
Bias
Zero
Sipan
Posttest
Bias
Zero
.
Spain
Value
SlPan
Zero
Drift.
%
Sipan
Drift,
%
Test
Ave.
Corrected
Ave.
25
20.90
11.17
11
46
1.2
7
99
8.1
8
0.8
0.10
8
09
0.12
7.99
7.99
0.08
0.40
15.75
15.75
.
25
22
48
15.20
15.59
1.6
NA
NA
0.0
0.05
22.58
0.00
22.38
22.48
0.20
0.80
2.93
2.95
500
100
424.00
84.87
82.30
0.5
NA
NA
0.0
0.00
82.50
0.90
82
40
84
87
0.90
0.1
0
55.74
57.23
250
100
227.20
139.30
138.30
0.4
89
72
89.50
0.1
100
80.00
40.10
40.60
0.5
c2%
PASS
NA
NA
0.0
c2%
PASS
0.00
0.60
~
5
%
PASS
78.40
5%
PASS
87.00
1.20
1
.
a0
c5%
PASS
89.50
77.40
<
5%
PASS
89.72
80.00
0.48
1.20
c3%
PASS
1
.
oo
1
.
oo
<
3%
PASS
34.98
2.95
35.1
9
1.83
.
Calculations:
,.
Analyzer
Cal.
Enor,%
=
[
Low(
Analyzer
Reads)
Low(
Cal)]
/
Analyzer
Range
X
100,
%
Zero
Drift,
%
=
[
Posttest
Biasvero)
Pretest
Biasgero)]
/
Analyzer
Range
X
100,
%
Span
Drift,
%
I
=
[
Posttest
Bias(
Span)
Pretest
Bias(
Span)]
/
Analyzer
Range
X
100,
%
Corrected
Ave.
=:
(
Span
Value
I
(((
Posttest
Bias(
Span)
+
Pretest
Bias(
Span))
(
Posttest
Bias(
Zero)
+
Pretest
Bias
(
Zero)))
/
2))
X
vest
Ave.
(
Posttest
Biasgero)
+
Pretest
BiasGero))
/
2)
Carnot
2/
21/
94
L
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptance
Run
7
CEM
6A
02
c02
co
NOx
N20
Criteria
Status
Analyzer
Range
25
25
.
500
100
100
System
Bias:
Pretest
Bias
Zero
0.12
0.00
0.90
1.20
1.80
<
5
%
PASS
Span
7.99
22.38
82.40
89
50
77.40
<
5%
PASS
Zero
0.12
0.05
0.90
1.00
1.30
<
5%
PASS
Span
7.91
22.17
82.30
89.1
0
78.00
~
5
%
PASS
Posttest
Bias
Span
Value
7.99
22.48
84.87
89.72
80.00
Zero
Drift,
%
0.00
0.20
0.00
0.20
0.50
<
3%
PASS
Span
Drift,
%
0.32
0.84
0.02
0.40
0.60
<
3%
PASS
Test
Ave.
15.70
2.87
51
30
35.03
2.82
Corrected
Ave.
.
15;
89
2.92
52.52
34.51
1.33
7
Camot
2/
21/
94
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptance
Run
8
CEM
6A
0
2
co2
co
NOx
N
2
0
Criteria
Status
Analyzer
Range
System
Bias:
Preteslt
Bias
Zero
Span
Zero
Span
Po.
sttest
Bias
Span
Value
ilero
Drift.
%
Span
Drift.
%
Test
Ave.
Corrected
Ave.
25
0.12
7.91
0.1
0
7.86
7.99
0.08
0.20
16.62
16.96
25
0.05
22.1
7
0.05
22.00
22.48
0.00
0.68
2.07
2.15
1000
0.90
82.30
1
.
oo
83.40
84.87
0.01
0.1
1
ND
0.98
100
1.00
89.1
0
1
.
oo
88.00
89.72
0.00
1.10
20.65
20.14
1000
1.30
<
5%
78.00
<
5%
2.00
<
5%
79.90
<
5%
80.00
0.07
<
3%
0.1
9
<
3%
1
10.40
112.55'
.
PASS
PASS
PASS
PASS
PASS
PASS
Carnot
U21l94
Y
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptanc
Run
8
CEM
6A
02
02
DIL
CO
CO(
Corr)
Criteria
Status
Analyzer
Range
25
25
1000
1000
System
Bias:
Pretest
Bias
Zero
Span
0.12
0.10
0.90
NA
~
5
%
PASS
7.91.
8.10
82.30
NA
~
5
%
PASS
Posttest
Bias
0.10
1.00
NA
~
5
%
PASS
Zero
0.10
Span
7.86
8.08
83.40
NA
~
5
%
PASS
7.99
7.99
84.87
NA
Span
Value
Zero
Drift,
%
0.08
0.00
0.01
Span
Drift,
%
0.20
0.08
0.1
1
~
3
%
PASS
~
3
%
PASS
Test
Ave.
16.62
19.13
690.50
1669.68
Corrected
Ave.
16.96
19.02
714.56
1498.64
Calculations:
CO(
C0r
r)
=
(
20.9
Stack
02,
%)/(
20.9
Dilution
02,
%)*
CO,
ppm
CEM
System1
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptance
Run
9
CEM
6A
02
c
o
2
co
NOx
N20
Criteria
Status
Analyzer
Range
25
25
1000
100
200
System
Bias:
Pretest
Bias
Zero
0.1
0
0.05
1.00
1
00
3.50
~
5
%
PASS
Span
8.1
5
22.00
425.80
88.00
80.1
o
~
5
%
PASS
Zero
0.1
0
0.04
1.80
0.50
4.50
~
5
%
?
ASS
Span
8.1
4
22.25
425.80
89.1
0
80.90
~
5
%
PASS
Pos;
ttes;
t
Bias
Spain
Value
7.99
22.48
424.00
89.72
80.00
Zero
Drift.
%
0.00
0.04
0.08
0.50
0.50
<
3%
PASS
Sipan
Drift,
%
.
0.04
1.00
.
0.00
1.10
0.40
~
3
%
PASS
Test
Ave.
17.19
~
2.1
3
ND
20.43
111.60
Corrected
Ave.
16.96
2.21
1.40
20.11
112.52
Camot
3/
29/
94
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptanc
Run
9
CEM
6A
02
02
DIL
CO
CO(
Corr)
Criteria
Status
..
Analyzer
Range
25
25
1
000
1000
System
Bias:
Pretest
Bias
Zero
0.10
0.10
1.00
NA
~
5
%
PASS
Span
8.15
8.03
425.80
NA
~
5
%
PASS
Zero
0.10
0.10
1.80
NA
~
5
%
PASS
Posttest
Bias
Span
8.14
8.00
425.80
NA
<
5%
PASS
Span
Value
7.99
7.99
424.00
NA
Zero
Drift,
%
0.00
0.00
0.08
Span
Drift,
YO
0.04
0.12
0.00
Test
Ave.
17.19
18.71
785.99
1331.52
Corrected
Ave.
16.96
10.78
783.85
1452.95
~
3
%
PASS
c
3%
PASS
\
\
Carnot
2/
21/
94
.
.
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptance
Run
1
O
CEM
GA
02
co2
co
NOx
N20
Criteria
Status
~
.
J
~~
Analyzer
Range
25
25
1000
100
1000
System
Bias:
_
Pretest
Bias
Zero
0.10
r'
0.05
1
00
1
.
oo
3
50
c5%
PASS
Span
8.1
5
22
00
425.80
88.00
80.10
5%
PASS
Zero
0.1
0
0.04
1.80
0.50
4.50
~
5
%
PASS
Span
8.14
22.25
425.80
89.10
80.90
c5%
PASS
Posttest
Bias
Span
Value
7.99
22.48
424.00
89.72
80.00
Zlero
Drift,
%
0.00
0.04
0.08
0.50
0.1
0
<
3%
PASS
Span
Drift.
%
0.04
1.00
0.00
1.10
0.08
~
3
%
PASS
Test
Ave.
18.08
1.50
ND
11.15
340.00
Corrected
Ave.
17.85
1.57
1.40
10.63
351.37
.
.
.
Camot
2/
21/
9,4
e
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptanc
Run
1
0
CEM
6A
02
02
DIL
CO
CO(
C0rr)
Criteria
Status
Analyzer
Range
25
25
1000
1000
System
Bias:
Pretest
Bias
Zero
.
0.10
0.10
1.00
NA
~
5
%
PASS
Span
8.1
5
8.03
425.80
NA
~
5
%
PASS
Zero
0.10
0.1
0
1.80
NA
<
5%
PASS
Span
8.14
8.00
425.80
NA
~
5
%
PASS
Posttest
Bias
Span
Value
7.99
7.99
424.00
NA
Zero
Drift,
YO
0.00
0.00
0.08
~
3
%
PASS
Span
Drift,
YO
0.04
0.12
0.00
~
3
%
PASS
Test
Ave.
18
08
19.88
622.60
1721.31
Corrected
Ave.
17.85
19.96
620.61
2009.44
Calculations:
CO(
Corr)
=
(
20.9
Stack
02,
%)/(
20.9
Dilution
02,
%)*
CO,
ppm
CEM
System
Bias
and
Linearity
Correction
Calculations
.
\
T)
Camot
2/
21/
94
.
.
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptance
Run
1
1
CEM
6A
02
c02
co
NOx
N20
Criteria
Status
Analyzer
Ramie
System
Bias:
.
Zero
Span
Zero
Span
Pretest
13ias
Posttest
Bias
Span
Value
Zero
Drift,
%
Span
IMt,
%
`
Test
Ave.
Corrected
Ave.
25
0.1
0
8.1
5
0.1
0
8.14
7.99
0.00
0.04
18.25
18.02
25
0.05
22
00
0.04
22.25
22.48
0.04
1
.
oo
1.38
1
44
1000
1.00
425.80
1.80
425.80
424.00
0.08
0.00
ND
1
40
100
1
.
oo
88.00
0.50
89.10
89.72
0.50
1
10
9
75
9.20
.
1000
3.50
'
5%
80.1
0
c
5%
4.50
5%
80.90
c
5%
80.00
0.10
<
3%
0.08
c
3%
PASS
PASS
PASS
PASS
PASS
PASS
370.00
382.75
Camot
2/
21/
94
...
CEM
System
Bias
and
Linearity
Correction
Calculations
Test
No.
Acceptanc
Run
11
CEM
6A
02
02DIL
CO
CO(
Corr)
Criteria
status
Analyzer
Range
25
25
1000
1000
System
Bias:
Pretest
Bias
Zero
Span
0.1
0
1
.
oo
NA
~
5
%
PASS
8.03
425.80
NA
<
5%.
PASS
0.10
8.15
Posttest
Bias
0.10
1.80
NA
~
5
%
PASS
8.00
425.80
NA
~
5
%
PASS
Zero
0.10
Span
8.14
7.99
7.99
424.00
NA
0.00
0.00
0.08
~
3
%
PASS
Span
Drift,
%
0.04
0.12
0.00
<
3%
PASS
Span
Value
Zero
Drift,
YO
Test
Ave.
18.25
19.98
563.30
1622.55
Corrected
Ave.
18.02
20.06
561.37
1922.95
Calculations:
CO(
C0r
r)
=
(
20.9
Stack
02,
%)/(
20.9
Dilution
02,
%)
r
CO,
ppm
,.
GRI
1E
125
15
197151R120D755.
T
Appendix
C.
3.
c
Raw
Data
GASEOUSMEASUREMENTS
'
CLIEh7ILOCATl3N:
CONDfTON:
t=;\
CORRECTED
TO
x
,
DRY
POINT/
DRY,
UNCORRECTED
I
I
I
SAMPLE
TIME
TEST
CO,
I
CO
I
NOx
I
NO
I
NO,
CO
1
NOx
SO,
;
0,
I
1
SFAN
GAS
CONCENTF;
r?
FlOh'
I
A
f
M
.
AS
FOUND
SPAN
I
i
l
i
,
,
CONDITION:
I
CLENTROCATION:
SEOUS
MEASUREMENTS
CONDITION:
7
u
,>
n.!
cA!
c;
r
I
OPEfikTOR:
GL"
if)
2.
DATE:
TEST
LOCATION:
#
'
TESTNUMEX
6
m%&
SEOUS
MEASUREMENTS
CLIENT/
LOCATICIN:
*
CONDITION:
55%
Cjfk/
Nw]
TEST
NUM3fFi:
9
a
4
4
TEST
LOCATION:
Appendix
C.
4
Formaldehyde
Data
GFU
1
E4251
5
19715/
R
120D755.
T
.
x
.,
.....
L
Appendix
C.
4.
a
Exhaust
Gas
.
...
.
w
a
_
.
_._
il
..
r
I
I
oc'
N
c
C
c
?
I
2
#
I
Y
I
rr)
2
VI
P
m
'
3
T
VI
p:
W
w
s
W
m
VI
2
N
0
0
2
m
rrl
e
e
2
VI
m
2
;
I
f!
<
Ri
0
i&
e
cn
J
i
>
1
d
..
H
0
e
0
0
9
r!
I
N
Y
m
N
9
N
v)
?
N
Q\
1
4
CI
v)
r
m
.
.
.
u
U
x
"
L
..
,
r
..
8
..
z
P
c
t
'
C
&
s
5
p?
.
s
N
.
0
N
0
d
N
OI
0
m
0
:
$
8
h
5
8
9
0
N
Y
OI
Y
x
n:
0
0.
c'!
N
m
VI
04
a
W
.
o:
cy
VI
2
N
0
I
?
2
.
m
a
:
o
*
9
2
0
LL
:!
Y
'
I
.
.
December
21
354
Nordhoff
St.,
Suite
11
3,
Chatsworth,
CA
9131
1
(
81
8)
71
8
6070
FAX
(
818)
71
8
9779
21,
1993
environmental
consultants
laboratory
servlcer
LTR/
468/
93
Rus=?
l1
Pence
CARNOT
1140
Pearl
S
t
r
e
e
t
,
S
t
e
216
Boulder,
CO
80302
re:
impingers
&
cartridge
samples
Dear
Russell:
P
l
e
a
s
e
f
i
n
d
enclosed
t
h
e
laboratory
analysis
reports
and
t
h
e
o
r
i
g
i
n
l
a
l
chain
of
custody
forms
for
f
i
f
t
y
DNPH
impinger
samples
received
on
December
8
&
9
,
1993.
The
sa~
mpltes
w
e
r
e
analyzed
for
formaldehyde
by
high
performance
liquid
chromatography.
Sincerely,
AtmAA,
Iric.
Dr.
Koc:
hy
Fung
Air
Programs
Director
Encl.
KF/
krp
k.
.,
rL
c
..
...
.~
,
.,.
..
.
~
~
~
_.*
F
Inc.
_
21
354
Nordhoff
St..
Suite
1
13,
Chatsworth,
CA
91
31
1
(
81
8)
71
8
6070
FAX
(
81
8)
71
8
9779
environmental
consultants
laboratory
services
LABORATORY
ANALYSIS
REPORT
DNPH
impinger
s
o
l
u
t
i
o
n
s
w
e
r
e
extracted
and
analyzed
for
formaldehyde
(
HCHO)
by
h
i
g
h
performance
liquid
chromatography.
Report
D
a
t
e
:
December
20,
1993
D
a
t
e
Received:
December
9,
1993
D
a
t
e
E
x
t
r
a
c
t
e
d
:
December
9,
1993
D
a
t
e
Analyzed:
December
17,
1993
P.
O.
No.:
1510
C
l
i
e
n
t
P
r
O
j
.
No.:
10515
19714
HCHO
ug/
sample
Sample.
AtmAA
Lab,
No.
Sample
I
D
ug/
sample
vol.,
m
l
_
93433
21
9
343
3
2
2
9
34
3
3
2
3
9
34
33
24
9
34
33
2
5
9
3
433
2
6
9
3433
21
9
34
33
29
93433
30
93433
31
9
3433
32
93433
33
93433
34
93433
35
93433
36
93433
37
93433
39
93433
40
93433
41
934
33
42
*
*
93433
43**
93433
44
93433
45**
93433
46**
93433
47
93433
49
93433
50
93433
28
93433
38
93433
48
1A
fom
6A
1.07
lB
fom
6A
1
blk
6A
2
~
f
o
r
m
6
~
2B
fom
6A
3
0.20
2
blk
6A
0.21
3B
fom
6A
1.
+
0
18
3A
fom
6A
1.04
3
blk
6A
4A
f
0m
6A
0
16
m
4B
fom
6A
sp
$
0.38
4
blk
6A
0.21
5A
f
om
6A
2
9
8
SB
fOm
BA
3\
5
t
0.36
5
blk
6A
I
O
.
1
9
6A
f
om
CA
43.20
6B
fom
6A
q*
Q
p
1
0
9
6
blk
6A
0.23
7A
fom
6A
45
35
7B
f
orm
6A
YrOdS?
A
1
1
0
0.22
7
blk
6A
8A
f
orm
6A
8B
f
om
6A
8
blk
6A
4
2
9
.
9A
f
om
6A
620
39
9
blk
6A
8.22
9B
fom
6A
\\!%'
2?
t
501
16
t
r
i
p
b
l
a
n
1.40
1.78
,
1.22
5.93
3.34
44
29
46.44
1281
.
7
3
1121
55
15
2
9.9
10
7
16.5
10.5
1
0
2
15.9
10.6
10.2
13.7
11.6
14.2
9.9
10.4
14.9
10.6
9.9
17.0
10.8
11.1
15.0
12.2
13.3
15
9
10.8
13.1
9.9
13.2
11.0
9.8
.
._
..:.:
.
I
S
.
.
../.
c
.
L
.
.
LABORATORY
ANALYSIS
REPORT
(
continued)
RCHO
ug/
sample
Sample
A
t
m
~
Lab.
N
o
.
ug
/
sample
Vol.,
ml
RE:
PEATS
:
93
433
2
1
1A
f
om
6A
0
.
9
8
9
3
433
3
1
0.35
4
B
f
o
m
6A
9
3
433
4
1
7
blk
6A
0.22
"
TRIX
SPIKES:
9
343
3
22
1B
f
om
6A
7.46
93433
37
6B
fom
6A
.
8
.
3
1
0
.
0
2
Field
spikes
are
at
5
ug/
sample.
*
HCHO
s
p
i
k
e
i
s
at
6
.
7
1
ug
per
sample.
**
Large
d
i
l
u
t
i
o
n
needed
or
these
samples.
Df.
Kochy
Fung
A
i
r
Programs
Director
2
:
.
:
.
..
.
.
COHC
NfiHE
0
.
0
2
3
8
HCHO
El.
11378
CHSCHEl
0.6864.
PF;
PNGL
e.
1
179
,
..
i
'
3
8.6251
8.
1748
I
tim
HCHO
A
C
ET
0
N
CARNOT
CLIENT:
CARB
METHOD
430
TEST
DATA
'
I
TEST
LOCATION:
0
AMBENT
TEMPERATURE:
OPERATOR:
c#
MPINGERS
LOADED
c4
Y
MPINGER
RECOVERED
CAt
SAMPLE
LINE
RECOVERED
,&
NOTES:
,.
I
I
c
.
.
."
CARNOT
CARB
METHOD
430
TEST
DATA
2
.
ST
BAROMETRIC
PRESS.:
7
DATE:
/
J/
7/$
2
TEST
LOCATION/:
Lfh
FUEL
A
I
&
~
AMBIENT'
TEMPERATURE:
RELATIVE
HUMIDIW.
IMPINGERS
LOADED
L
IMPJNGER
RECOVERED
cg
SAMPLE
LINE
RECOVERED
c#
NOTES:
'
INCLUDES
CA?.
PMF
037
CARNOT
CARB
METHOD
430
TEST
DATA
OPERATOR:
cff
UPINGERS
LOADED
MPINGER
RECOVERED
SAMPLE
LINE
RECOVEFIED
&
NOTES:
J
CARNOT
CARB
METHOD
430
TEST
DATA
.
TEST
NO.:
L/
P>&
I
((
A
BAROMETRIC
PRESS.:
77
5v
I&/
7A]
CLIENT:.
DATE:
TEST
LOCATION:
FUEL
I'f.&=
S
AMBIENT
TEMPERATURE:
RELATIVE
HUMIDIIY:
OPE
RAT0
R:
GYP
4
9
3b
06
36
IMPINGEFlS
LOADED
led
IMPfNGER
RECOVERED
C
"
d
SAMPLE
LINE
RECOVERED
c/
H
NOTES:
t
i
I
1
,
1
*
PMF437
CARNOT
AMBIENT
TEMPER
ANRE:
RELATIVE
HUMIDITY:
OPERATOR:
&#
d0
37
IMPINGERS
LOADED
SAMPLE
LINE
RECOVERED
IMPINGER
RECOVERED
I
NOTES:
Pt&
c37
I
_
..
.
.
5
CARNOT
L.
CARB
METHOD
430
TEST
DATA
c
.
.
DATE:
,
c?/
5/
9?,
BAROMETRIC
PRESS.:
274
TEST
LOCATION:
'
d4.?
FUEL:
td
:
O
M
S
r/
AM6
I
ENT
TE
Ivl
PE
RATU
RE:
RELATIVE
HUMIDIN:
OPEFATOR:
G/
IMPINGERS
LOADED
L
IMPINGER
RECOVERED
A
SAMPLE
LINE
RECOVERED
NOTES:
AMBIENT
TEMPERATURE:
RELATIVE
HUMIDITY:
n
//
OPE
%.
TOR:
cjy
ll
IMPINGERS
LOADED
IMPINGER
RECOVERED
11
II
SAMPLE
LINE
RECOVERED
I
NOTES:
.
CARNOT
CARB
METHOD
420
TEST
DATA
$..
8
/&%
6A
.
'
'
mm
TEST
NO.:
CLIENT:
TEST
LCCATION:
'
f
§
uf/
2
RIEL:
J
r
k
5
DATE:
@
mv
BAROMETRIC
PRESS.:
a5
L
.
.
r
.
.
IMPINGEAS
LOADED
IMPINGER
RECOVERED
L
SAMPLE
LINE
RECOVERED
C
tt
NOTES:
L
COMMENTS
AND
OBSERVATJONS:
CARNOT
CAR8
METHOD
430
TEST
DATA
7
/
s
Gp
TEST
NO.:
DATE:
2
/>/=/
e
BAROMETRIC
PRESS.:
21
35
CUENT:
'
@
of/&
FUEL:
NrGCLe)
E
S
T
LOCATION:
RELATIVE
HUMIDITY:
.
I
MPINGERS
LOADED
IMPlNGER
RECOVERED
....
.
I
.
.
...
,
GRI
1
E
125
lii
197
15/
R
120D755.
T
c
Appendix
C.
4.
b
Ambient
Air
3
z
B
f
!
<
0
L.
l
i.
1
d
d
z
z
F
.
.
i,
l
..
u
i
o
I
..
r
n
z
L
2
a
4
z
d
z
0
\
4
0
'
0
0
d
z
r
l
0
9
W
2
n
n
n
M
d
9
:
f
c
Z
d
f
a
n
d
d
z
0
8
0
E
2
N
3
E)
W
>
4
d
_
_
.
A.
.
i
.
.
I
.
..
i
...
I
z
M
n
I
w
i
w
>
rf
e
h
s
8
3
d
e
x
..
.
3
x
'
I
Y
21
354
Nordhoff
St..
Suite
1
13,
Chatsworth,
CA
91
31
1
(
81
8)
71
8
6070
FAX
(
81
8)
71
8
9ng
environmental
consultants
laboratory
services
LABORATORY
ANALYSIS
REPORT
I
m
P
R
cartridges
were
extracted
and
analyzed
for
formaldehyde
perf
onnance
liquid
chromatography.
I[
HCHO)
by
high
Report
Date
:
Date
Received:
Date
Analyzed
:
c
c
l
i
e
n
t
I?
ro
j.
NO.
:
.
..
I.
AtsrAlL
Lab.
No.
9
3
4
33
97
9
3
4
33
9
8
9
3
4
3
3
9
9
93433
100
93433
101
93433
102
93433
103
93
433
1
04
93433
105
9
3
34
3
3
1
06
..
REPEATS
:
93433
91
D
e
t
.
.
L
i
m
i
t
.
*'
December
10,
1993
December
9;
1993
December
9,
1993
10515
19714
Sample
I
D
147
138
13
5
151
116
179
137
130
16
1
1
Cr
rs]
147
0.21
0.03
Dr.
Kochy
Fung
Air
Programs
Director
1
t
l
E
t
l
O
R
I
Z
E
D
RRT
M
E
A
IlK
I
D
N
O
CONC
R
1
6.
lilE.
l
NAHE
HCHO
L
.
.
.
.
I
I
I
c
1.
i
I
i
i
I
!
I
'
I.!
I
.
.
..
L
.
A
4
'
1
.
'
.
.
.
.
N
1.
!
m
a
1
I
It
I
Q
ii
I
I
..
N
',
I
1
1
I
I
c
,
I
I
.
I
I
i
i
0
..
I
s
!
.
.
1
.
'
.
,
I
I
,
.
1.
f
i
f
.
I
/
I
1
1
I
1
.
m
=
c
c
i
i
j
:
N
a
i
c
I
t
*
I
I
m
a
1
I
i
I
I
I
I
11
\"
T
..
Y
0
!
I/
I
1
I
H
I
J
a"
X
I
'
4
W
(
3
u
P
I
I
c
4
>
0
Appendix
C.
5
Benzene,
Methane,
and
TGNMO
Data
1
.
.
.,,
e,:
I.
.
GR.
31
E125
15
19715/
R120D755.
T
.
Appendix
C.
5.
a
Exhaust
Gas
GRI
1
E
ITS
15
1
97
1S/
R120D7SS.
T
G
W
t
b
!
.
.
e
N
C
V
w
m
m
kl
N
5
5
m
044
v
v
v
w
m
m
m
m
CI;.
2
P
r
r
3
N
.
(
r,
N
?
=
"
w
b
w
m
m
m
B
?
"
i
5
w
c.
0
z
s
r
3
d
.
r
U
M
5
I
n
b
e
..
L
U
Q
b
9
9
Iff2
2
%
,
OQ
*
*
21
354
Nordhoff
St..
Suite
1
13.
Chatsworth,
CA
91
31
1
(
81
8)
71
8
6070
FAX
(
81
8)
71
8
9779
environmental
consultants
laboratory
services
December
22,
1993
Russell
Pence
CARNOT
1140
Pearl
Street
Ste
216
Bouldeic
CO
80302
re:
10515
19714
Dear
Russel
1
:
LTR/
4
6
9
/
9
3
Please
find
enclosed
the
laboratory
analysis
reports,
quality
assurance
summaries,
and
the
original
chain
of
custody
forms
for
ten
!
Sunma
canister
and
ten
Tedlar
bag
samples
received
on
December
9,
1993,
The
samples
were
analyzed
for
methane,
total
gaseous
non
methane
organics,
benzene,
toluene,
and
carbon
monoxide
per
the
chain
of
custody
,
Sincerely,
AtmAZi,
Inc.
Caboratory
Director
Encl.
MLP/
kzp
environmental
consultants
laboratory
services
LABORATORY
ANALYSIS
REPORT
Benzene,
Toluene,
Methane,
&
Total
Gaseous
Non
Methane
Organics
Analysis
in
Tedlar
Bag
Samples
Report
Date:
December
21,1993
Client:
CARNOT
P0.
No.:
1509
Project
No.:
10515
19714
Date
Received:
December
9,1993
Date
Analyzed:
December
10
&
11,1993
ANALYSIS
DESCRPTXON
Methane
and
totdgaseous
non
methane
organics
were
measured
ly
flame
ionizah`
on
detecfionltotal
combustion
analysis
FIDlTCA)
Benzene
and
toluene
were
measwed
by
GCIMS.
At&
Lab
NO.:
93433
11
93433
12
93433
13
93433
14
93433
15
93433
16
Sample
LD.:
l
Bexu
2
Benz
3
Benz
4
Benz
5
Ben2
6
Benz
I
I
1
I
I
I
6A
6A
6A
6A
6A
6A
1
Components
(
Concentration
in
ppmv)
Methane
4.49
(
1
cl
1.02
1.09
2.59
TGNMO
1.70
3.02
2.21
1.28
2.22
4.69
Benzene
0.62
0.36
0.34
0.34
0.32
0.76
Toluene
0.95
1.48
1.66
1.12
1.70
1.16
(
Concentration
m
ppbv)
TGNMO
is
total
gaseous
non
methane
organics
reported
as
ppm
methane.
.
I
LABORATORY
ANALYSIS
REPORT
]
Benzene,
Toluene,
CO,
Methane,
&
Total
Gaseous
Non
Methane
Organics
Analysis
in
Tedlar
Bag
Samples
&
port
Date:
December
21,1993
Client:
CARNOT
P.
0.
No.:
1503
Project
No.:
10515
19714
.
Date
Received:
December
9,1993
Date
P
d
y
z
e
d
December
10
&
11,1993
ANALYSIS
DESCRIPTION
Methane,,
total
gaseous
non
methane
organics,
and
c&
n
rnonm.
de
were
measured
by
flame
ionization
detectionliotal
combustion
analysis
FIDITCA).
Benzene
and
toluene
were
mectsured
by
GCIMS.
AbAA
:
Lab
NO.:
93433
17
93433
18
93433
19
93433
20
Sample
I.
D.:
?
Bern
8
Ben2
9
Benz
BIk
Bern
I
6A
I
6A
1
6A
I
6A
1
Components
(
Concentration
in
ppmv)
Methane.
8.95
1440
1360
<
1
TGNMO
6.48
185
202
<
1
1460
1370
<
1
Carbon
Monoxide
Benzene
0.83
7.33
7.19
0.21
(
Concentration
in
ppbv)
Toluene
2.68
3.94
4.05
1.04
TGNMO
is
total
gaseous
non
methane
organics
reported
as
ppm
methane.
h
Michael
L.
Porter
QUALITYASSURANCE
SUMMARY
mepeat
~
n
d
y
s
i
s
)
i
4
Sample
Repeat
AMI*
Mean
ID
Run#
1
1
Rm#
2
Cone.
%
M.
FromMean
Methane
8
Ben2
1440
1430
1440
0.35
TGNMO
8
Ben~
184
186
185
0.54
Carbon
8
Benz
1460
1460
1460
0.0
Monoxide
(
Concentration
in
ppbv)
Benzene
4
Ben2
0.29
0.39
0.34
15
9
Benz
7.31
7.08
7.19
1.6
Toluene
4
Benz
0.80
1.43
1.12
28
9
Benz
3.36
4.75
4.05
17
A
set
of
10
TedIar
bug
samples
laboratory
numbers,
93433(
11
20)
was
analyzed
for
methane,
TGNMO,
carbon
monoxide,
benzene,
and
toluene.
Agreement
between
repeat
andyses
is
a
measure
of
precision
and
is
shown
above
in
the
column
"
R
Diffemnce
fmm
Mean."
Repeaf
analyses
are
an
important
part
of
AtmAA's
quaiie
msurance
program
The
merage
5%
Diffetence
f
b
m
Mean
for
7
at
rneczsmments
fivm
the
sample
set
of
10
Tedlur
bag
samples
is
83%.
Project
No.:
Date
R
e
i
v
d
Date
Analyzed:
QUALITYASSURANCE
SUMMARY
(
Spike
Analysis)
1
1
10515
19714
December
9,1993
December
ll,
1993
Component
Amount
Recovery
Spike
I
Theoretical
lExperimentaIf
(
W
Components
Composition
(
Concenration
in
ppbv)
Benzene
(
8
ml
NBS
1811
99.5
134
135
+
12
ml93433
19)
Toluene
(
8
ml
NBS
1811
92.4
90.4
97.8
+
12
ml93433
19)
Spike
results
in
obtained
by
analyzing
an
exact
mlme
ofa
standard,
mixed
with
an
exact
volwne
of
a
prwiously
analyzed
sample.
The
theomfical
amount
is
obtained
by
adding
componeni!
amrtunts
contributed
by
the
known
standard
OOILune
and
b.
r
the
Known.
CpreV;
ously
analyzed)
sample
volume.
Eqxrimental
results
are
those
derived
fiom
anai'.
ng
the
spike
mixture.
CARNOT
0,
AND
CO,
INTEGRATED
BAG
SAMPLES
Analytical
Method
(
Orsat/
CEM):
&'
k
Unit:
6
4
Fuel:
6
~
~
7
Date:
121
'
3
'
3
I
I
1
1
I
3
Q
Appendix
C.
5.
b
Ambient
Air
GRI
1
E
ll251!
i
197
I
5IR120D755
.
T
21
354
Nordhoff
St.,
Suite
1
13,
Chatsworth,
CA
91
31
1
(
81
8)
71
8
6070
FAX
(
81
8)
71
8
9779
LABORATORY
ANALYSIS
REPORT
environmental
consultants
laboratory
services
Benzene,
Toluene,
Methane,
&
Total
Gaseous
Non
Methane
Organics
Analysis
in
Summa
Canister
Samples
I
Report
Date:
December
21,1993
'
Client:
CARNOT
P.
O.
No.:
1511
Project
No.:
10515
19714
.
Date
Ikeived:
December
9,1993
Date
ILnalyzed:
December
11
&
13,1993
ANALYSIS
DESCRIPTION
Methane
and
totalgaseorrs
nowmethane
organics
were
measlrred
by
flame
ionization
deiecfionlfottd
combustion
analysis
FIDITCA).
Benzene
and
toIuene
were
measwrd
by
GCIMS.
AtmAA
:
Lab
NO.:
93433
1
93433
2
934
33
3
93433
4
93433
5
9
M
6
Saniple
I.
D.:
l
Benz
2
Ben2
3
Benz
Blk
Benz
4
Benz
5i
Be;
nz
I
AMB
6A
1
AMB
6A
I
AMB
6A
I
AMB
6A
I
AMB
GA
1
AMB
GA
1
656
742
11.4
666
7301
801
805
780
803
803
1.84
1.61
1.65
c
1
1.64
1.72
inititd
p
m
s
s
m
653
finad
pressure..
797
Componeints
(
Concentration
in
ppmv)
Methane
TGNMO
Benzene
1.56
<
1
(
1
(
1
(
1
<
1
0
88
0.25
0.59
0.22
0.25
0.21
(
Concentration
in
ppbv)
0.34
0.17'
Toluene
1.61
1.06
0.92
0.020
TGNMO
is
total
gaseous
non
methane
organics
reporfed
as
ppm
methane.
inifialpnessure,
mm
Hg
final
pressure,
mm
Hg
4
LABORATORY
ANALYSIS
REPORT
Benzene,
Toluene,
Methane,
&
Total
Gaseous
Non
Methane
Organics
Report
Date:
Client:
P.
O.
No.:
Project
No.:
Date
Received:
Date
Analyzed:
Amlysis
in
Summa
Canister
Samples
December
21,1993
CARNOT
1511
1051519714
.
December
9,1993
December
11
&
13,1993
ANALYSIS
DESCRfPTION
Methane
and
total
gaseous
non
methane
organics
were
measured
by
thermal
conductivity
detectionfgas
chmmatography
VCDIGC).
Benzene
and
toluene
wem
measured
by
GCfMS.
At
Lab
NO.:
93433
7
93433
8
93433
9
93433
10
Sample
ID.:
6
Ben2
7
Bem
&
Ben2
9
Benz
initial
pmssm
645
715
644
650
final
pressure=
801
802
801
800
Components
(
Concentration
in
ppmv)
Methane
1.63
1.63
1.63
1.65
TGNMO
(
1
(
1
(
1
<
1
Benzene
0.33
0.47
0.27
0.30
Toluene
18.0
3.37
3.45
1.33
1
AMB
6A
I
AMB
6A
1
AMB
6A
1
AMB
6A
I
(
Concentration
in
ppbv)
TGNMO
is
totdgaseorrs
non
methane
orgmics
reported
as
ppm
methane.
initialpressrrre,
mm
Hg
final
presswe,
mm
Hg
Michael
L.
Porter
'
Laboratory
Director
.
...
Repeat
Analysis
Run#
1
1
Run#
2
Jty
Mean
%
DDiff.
Cone
FromMean
.
.
'
,
L
:_
.
__..
....
_
QUAUTYASSURANCE
SUMMARY
(
Repeaf
AnaIysis)
Client
Project
No.:
10515
19714
Date
R.
eceivd
December
9,1993
Date
Andyzd
December
11
&
13,1993
Sample
ID
Components
Methane
2
Benz
6
BenZ
TG".
Io
2
Bern
6
I3em
1.58
1.65
1.61
2.2
1.64
1.62
1.63
0.61
I
<
1
<
I
.
e1
<
1
(
Concentration
m
ppbv)
Benzene
Blk
Bm
026
0.17
0.22
21
6
BenZ
0.42
0%
0.33
27
Toluene
Blk
Bem
0.023
0.016
0.020
18
6
Bern
20.9
15.1
18.0
16
A
set
of10
Sunzna
canister
samples
laboratory
numbers,
93433(
1
10)
was
analyzed
for
methane,
TGNMO,
benzene,
and
toluene.
Agreement
between
repeat
analyses
is
a
measum
of
precision
and
is
shown
above
in
the
coIumn
'
8
Diffemnce
fhm
Mean.'
Repeat
analyses
are
an
impwtant
part
of
AtmAA's
quality
asswance
program.
The
uverage
%
Diffimnce
j%
m
Mean
for
6
repeal
measurements
frvm
the
sample
sef
of
10
Summa
canisier
sampIes
is
14%.
page3of
4
QUALITYASSUBANCE
SUMMARY
(
Spike
Andysis)
Project
No.:
10515
19714
Date
Received:
December
9,1993
Date
Analyzed:
December
13,1993
Comuonent
Amount
Recovery
Spike
I
Theorbtical
[
Experimentall
(%
I
I
Components
Composition
(
Comemation
in
ppbv)
Benzene
(
10
ml
NBS
1811
48.0
48.2
100.4
+
40
mI
93443
8)
Toluene
(
10
ml
NBS
1811
47.7
49.3
103
+
40
mI
93443
8)
Spike
msulfs
are
obtained
by
analya'ng
an
exact
volume
of
a
standard,
mixed
with
an
exact
volume
of
a
previously
andjmd
sample.
The
theoreiical
amount
is
obtained
by
adding
component
amounts
mntduted
by
the
known
standard
volume
and
by
the
known
(
previously
analyzed)
sample
volume.
E
x
p
e
r
i
r
n
d
msrlts
are
those
&
rived
h
r
n
anaiyzing
Me
spike
rnixfwv.
.
CARNOT
EVACUATED
FLASK
DATA
.
.
.
.
.
CARNOT
EVACUATED
FLASK
DATA
BY:
M
AL
Appendix
C.
6
Fuel
Analysis
Data
GRI
1
E
12515
19715/
Rl20D755.
T
GAS
FUEL
F
FACTOR
CALCS
Y_
.
.
.
12/
07/
93
.12/
08/
93
SPECIES
Mole(%)
c1
C2
C5
IS0
c4
N
C4
IS0
c5
NC5
C
~
C
co
~
C02
:
N2
102
94.307
2.486
0.298
0.027
0.034
0.008
0.006
0.003
O.
Oo0
0.501
0.
OOO
1.937
0.393
94.507
2.757
0.320
0
032
0.042
0.012
0.008
0.004
O.
Oo0
0.524
O
OOO
1.527
0.267
Average
94.407
2.622
0.309
0.030
0.038
0.010
0.007
0.004
0.000
0.513
0.000
1.732
0.330
GAS
MW
'
16.93
'
16.92
16.93
I3TU/
SCF=
1008.6825
1016.78
@
60F
13TLJAb.
=
22610.70
22804.51
Ib./
scf=
0.0446
0.0446
Fd"(
68)
=
Fdl'(
60)
=
8608.87
8610.53
(
02
Based)
8478.43
8480.07
FC
"(
68)
=
1017.34)
Fc'(
60)
=
1001.92)
1018.42
(
C02
Based)
1002.99
1012.73
22707.60
0.0445
8609.70
8479.25
1017.88
1002.46
.
.
1.:
15
PM
GAS
FUEL
F
FACTOR
CALCS
Date:
1247
93
De~~
ripdon:
5
F~
l
6A
SPECIES
Cl
'
c
2
c3
IS0
c
4
N
C4
IS0
c5
NC5
C6+
co
c02
H20
N2
02
MW
MOLE
%
16
30
44
58
58
72
72
86
28
44
18
28
32
94.307
2.486
0.298
0.027
0.034
0.008
0.006
0.003
O.
Oo0
0.501
0
OOO
1
937
0.393
Mw*%
HHV
BTU/
SCF
C
H
0
1511.46
74.69
13.13
1.57
1.97
0.58
0.43
0.26
0.00
22.05
0.00
54.26
12.58
1012.00
954.39
11.33
3.79
0.00
1773
00.
44
08
0.60
0.15
0.00
2524.00
7
52
0.11
0.02
0.00
3271.00
0.88
0.01
0.00
0.00
3271
00
1.11
0.02
0.00
0.00
3998.00
0.32
0.00
0.00
0.00
3998.00
0.24
0.00
0.00
0.00
4743.00
0.14
0.00
0.00
0.00
321.00
0.00
0.00
0.00
0.00
0.06
0.00
0.16
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.13
N
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.54
0.00
1
AVGJTOT.
100.00
16Z.
98
1008.68
12.13
3.97
0.29
0.54
wr.
x
100.00
71.66
23.45
1.69
3.21
GAS
Mw
16.93
BTU!
SCF=
1008.68
@
6OF
BTUnb.
=
22610.70
I
b
.
k
f
=
0.0446
Fd"(
68)=
8608.87
(
02
Based)
Fd"(
60)=
8478.43
F~'(
68)
=
1017.34
(
CO2
Based)
_
+
Fc'(
60)
=
1001.92
.
Calculations:
Fd"(
68)
10
6
*
[
3.64
*
(
HX)
+
1.53
*
(
C%)
+
0.14
*
(
N%)
0.46
*
(
02%)]
/
"
V,
B
d
l
b
Fd"(
60)
=
Fd"(
68)
*
520
R
/
528
R
Fc"(
68)
=
10
6
*
10.321
*
(
C$)]
/
HHV,
BmAb
Fc"(
60)
=
Fc'(
68)
*
520
R
/
528
R
I
.
r
.
.
.
.
Y
L
.
.
*
ZALCO
LABORATORIES,
INC.
Analytical
&
Consufting
Services
.
.
*
.
LL;
i
.
_
.
_.
_.
.
CAHNIDT
Z
'
u
s
t
l
n
,
,
CA
92680'/
388
15991
R
e
d
Hill
A
v
e
.
S
t
e
.
110
L
a
b
.
No.:
038144
001
Received:
D
e
c
9,
1993
Reported:
D
e
c
1
0
,
1993
A
t
t
e
m
t
l
.
o
n
:
R
u
s
s
Pence
*
CHROMATOGRAPHIC
ANALYSiS
[
Z
1635)
*
C
o
n
i
p
o
n
e
n
ts
.
Mole
?,
Wt
Y
Hydrogen
0.000
0.000
C
a
r
b
o
n
IYonoxlde
0.000
0.000
Hydrogen
Sulfide
0.000
0.000
Propane
,298
377
N
ButanE?
0
3
4
11s
N
P
e
n
tarre
.006
,
0
2
7
Hexanles+
.003
.015
C
a
r
b
o
n
Dioxide
.
so1
1..
301
O
x
y
g
e
n
*
393
.742
N1
tralgeln
1.937
3.202
Methane
94.307
89.285
E
t
h
a
n
e
2.486
4.411
I
soBu
tarie
.027
092
1
s
o
P
e
n
t
a
n
e
.
OD8
.032
CHONS
W
t
Y
CARBON
71.55)
.
HYUHOGEhl
23.51
OXYGEN
1.69
NLTHOGEN
3.20
SULFUR
0.00
T
o
t
a
l
s
9'
9.99
T
o
t
a
l
H/
C
3
3
100.000
100.000
'
l'ot,
a1s
=
!
3lJEClFIC
GKAVI'I'Y
1
A
i
r
=
11
5
8
6
0
22.36
SPECIFIC
VOiL'PlE,
cu.
ft./
lb
GROSS
CALORIFIC
VALUE,
B
*
r
u
/
c
u
.
f
t
.
**
1010.68
GROSS
C
A
L
O
R
I
F
I
C
VALUE,
BTU/
fb
X
X
22598.88
NF:'
l'
CALOR1
FIIC
VALUE,
B
T
U
/
c
u
.
ft.
X
X
910.85
!
JET
C
A
L
O
R
l
F
l
C
VALUE,
B
T
U
/
l
b
x*
20366.70
8.5784
C:
OMPHESSIBILl'TY
FACTOR
'
2'
160
F
,
l
ATMj
9980
E:
PA
'
F'
F
a
c
t
o
r
@
68
F:
8618.980
DSCF
/
MM
B
t
u
.
KCAPCD
'
F
'
Factor
I$
60
F:
8489.695
DSCF
/
HM
B
t
u
.
1
GROSS
CALORIFIC
VALUE,
wru/
cu.
t
t
.
x
993.50
DSCF
EXHAUST
PEW
SCF
FUEL
(
0%
Oxygen1
*
Water
S
a
t
u
r
a
t
e
d
**
Dry
G
a
s
@
60
F
,
14.73
p
s
i
a
.
.
.
,
~
i
Jlrn
k
L
___=_#
LE
__
T
S
a
l
y
s
r
LaboratGry
.
D
i
r
e
c
t
o
r
4309
Armour
Avenue
Bakersfield.
Californts
93308
FAX
1
8
0
5
1
395
3069
GAS
FUEL
F
FACTOR
CALCS
Date:
1248
93
Descripaon:
7
Fuei
6A
SPECIES
MW
MOLE%
MW*%
HHV
BTUlSCF
C
H
0
N
c1
c
2
c
3
IS0
c4
NC4
IS0
c5
NC5
C6+
co
c02
H20
.
N2
02
16
30
44
58
58
72
72
86
28
44
18
28
32
94.507
2.757
0.320
0.032
0.042
0.012
0.008
0.004
0.
OOO
0.524
0.
ooo
1.527
0.267
1514.66
82.84
14.10
1.86
2.44
0.87
0.58
0.34
0.00
23.06
0.00
42.78
8
54
1012.00
2524.00
3271.00
3271
00
3998.00
3998.00
4743.00
321.00
.
im:
m
956.41
11.35
48.88
0.66
8.08
0.12
1.05
0.02
1.37
0.02
0.48
0.01
0.32
.
0.00
0.19
0.00
0.00
0.00
.
0.06
0.00
0.00
0.00
3.80
0.17
0.03
0.00
0.00
.
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0
00
0.00
0.17
0.00
0.00
0.09
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.43
0.00
AVG./
TOT.
100.00
1692.07
1016.78
12.24
4.00
0.25
0.43
WT.
5%
100.00
72.35
23.63
'
1.50
'
2.53
GAS
MW
16.92
BTU/
SCF
=
1016.78
@
60F
BTUAb.
=
2304.51
Ib./
scf=
0.0446
Fd'(
68)
=
8610.53
(
02
Based)
Fd'(
60)
=
8480.07
FC
"
(
68)
=
1018.42
(
C02
Based)
F~"(
60)
=
1002.99
__._
I*
.
.
.
Calculations:
Fd'(
68)
=
10'
6
*
13.64
*
(
HX)
+
1.53
*
(
C%)
+
0.14
*
(
N%)
0.46
*
(
OZX)]
i'
HHV,
B
d
I
b
Fd"(
60)
=
Fd"(
68)
*
520
R
/
528
R
Fc"(
68)
=
10'
6
*
10.321
*
(
C
%)]
/
HHV,
B
d
l
b
Fc'(
60)
=
Fc"(
68)
*
520
R
/
528
R
I
c
7
L
C
O
LABORATORIES,
INC.
Analytical
G
Consulting
Services
1
CARNO'I'
Lab.
No.:
038144
002
1
5
Y
Y
l
!
Hled
Hill
Ave.
Ste.
110
Received:
U
e
c
9
,
1993
Tust3.
n,
CA
92680
7388
Reported:
D
e
c
10,
1993
I
Attention:
~
u
s
s
Pence
\
2/
3l%
Sample
Description:
7
Yuel
6A
.
12
7
93
Id
1030
*
CHROMATOGRAPHIC
ANALYSlS
(
2
1635)
*
Cornponen
t
s
Mole
%
Wt
Y
CHONS
Wt
%
.
Hydrogen
0.000
0
.
0
0
0
CAKBON
72.28
Carbon
]
Dioxide
.
5
2
4
1.361
HYDROGEN
23.69
Oxygen
2
6
7
.
SO4
OXYGEN
1.49
Nitrogen
1.527
2.525
*
NlTROGEN
2.53
Carbon
Honoxide
0.000
0
.
0
0
0
SU
L
FUR
0
.
0
0
Hydrogen
S
u
l
f
i
d
e
0
.
0
0
0
0
,
0
0
0
Me
thane
94.507
8Y.
521
Totals
99.99
E
t
ha
n
e
2.757
4.896
'
rota1
H/
C
.33
Prop
a
1'
1
e
,
3
2
0
.834
3.
so
Bu
IC
a
ne
032
.
ill
hl
BUtZIAe
0
4
2
142
1
sopen
tane
.012
.
os0
N
Pen
t
a
ne
.
0
0
8
.036
Hexanes+
.004
.019
T
o
t
a
l
s
=
100.000
1
0
0
.
0
0
0
SPECIFIC
GRAVITY
(
Air
=
1)
.
5
8
5
7
S:
PECIFIC
VOLUME,
cu.
ft./
lb
%
22.37
GROSS
CALORIFIC
VALUE,
BTU/
cu.
ft.
**
.
1018.84
GROSS
CALORIFIC
VALUE,
BTU/
lb
%*
22792.65
NET
CALORIFIC
VALUE,
BTU/
cu.
ft.
%
*
918.3U
NET
CALORIFIC
VALUE,
BTU/
lb
%
*
20543.34
DSCF
EXHAUST
PER
SCF
FUEL
(
0
%
Oxygen)
8.6429
COMPRESSlBLLlTY
FACTOR
'
2'
(
6
0
F,
1
ATM)
.9980
EPA
'
F'
Factor
@
68
F:
8620.641
DSCF
/
MM
Btu.
KCAPCD
'
F'
Factor
@
60
F:
8491.332
DSCF
/
M
M
Btu.
a
n
G:
Z.
OSS
CkLCiXlTIC
VALilE,
ETU/
cu.
fi.
*
AU31.52
I
*
Watler
Saturated
**
Dry
Gas
@
60
F,
14.73
p
s
l
a
4309
Armour
Avenue
Bakersfield.
California
93308
..
GAS
FUEL
ANALYSIS
SPECIES
CI
c2
c3
IS0
c4
NC4
IS0
c.
5
NC5
C6+
CO2
HZO
N2
02
co
Mole
(
X)
9
13
93
96.523
1.659
0.125
0.044
0.013
0.005
O.
Oo0
0.002
O.
Oo0
0.381
O.
Oo0
1.153
0.095
11
16
93
93.065
4.181
0.382
0.038
0.050
0.014
0.009
0.005
0.
OOO
0.621
O.
Oo0
1.385
0.25
1
11
18
93
84.202
3
4
3
0.3
17
0.032
0
043
0.010
0.010
0.004
O.
Oo0
0.541
O.
Oo0
8.901
2.536
12
07
93
94.307
2.486
0.298
0.027
0.034
0.008
0.006
0.003
0.
OOO
0.501
O.
Oo0
1.937
0.393
12
08
93
Avenge*
94.507
2.757
.
0.320
0.032
0.042
0.012
0.008
0.004
O.
Oo0
0.524
O.
Oo0
1.527
0.267
Notes:
*
Avaerage
for
H2s
includes
the
fuel
samples
collected
on
9
13
93
and
11
16
93
and
omits
the
sample
collected
on
11
18
93,
12
7
93
and
12
9
93
as
it
appears
the
11
18
93
sample
was
diluted
With
ambient
and
the
ocher
two
sampl
were
not
anal
by
th;
&
ntracred
labratoty.
The
sample
collected
on
9
13
93
w
a
~
~
01le~
red
at
w
t
A
and
the
sample
collected
on
11
16
93
was
collected
at
nit
C.
The
average
of
these
cwo
fuel
gas
sampies
presents
a
more
representarive
itel
sample
for
H2S
than
any
of
che
the
octten
collecd
during
the
system
wide
test
program.
_
2/
17/
94
1:
15
PM
!
ZALCO
LABORATORIES,
INC.
Anafytical
&.
Consuking
Services
*
1150
3umerz
Avenue,
Suire
C
Caacord,
CA
94520
Lab.
No.:
037261
001
Received:
Sep
IS,
1
~
9
3
Reported:
Sep
15,
1993
.
A
t
t
e
t
i
t
i
.
o
n
:
.
Russ
P
e
n
c
e
a
.
Sample
D
e
s
c
r
i
p
t
i
o
n
:
Project
'
S30152
9
13
93
*
CHROHATOaPHIC
ANALYSIS
(
2
1535)
*
Components
Mole
%
Wt
1
cxobis
Wf
'
5
Hydrogen
CarSon
Dioxide
N
i
trogen
Carbon
Honoxide
Hydrogen
S
u
l
f
i
d
e
fierhane
.
Ethane
Pro
pan
e
1
so9u
Larue
I
s
oP
en
tan
e
N
Pen
t:
a
ne
n
exa
n
E?
s+
Yg=*
N
BU
tiZne
0.000
.381
.
0
9
5
1.153
0.000.
0
.
0
0
0
96.523
1
.
65
9
..
I
25
I
0
4
4
013
,005
.
0
.
0
0
0
IO02
0
000
1.010
1
947
0.000
0.000
93.293
3
006
331
154
0
4
6
021
0
.
0
0
0
.
0
0
8
.
is4
T
o
t
a
l
s
100.000
100.000
SPECIFIC
GZUiVITY
(
A
i
r
1)
SPECIFIC
VOLUXE,
cu.
ft./
lb
L
GXOSS
CALORIFIC
VALUE,
E?
TU/
cu
.
f
t
.
x
G2OSS
CALORIFIC
VALUE,
BTU/
lb
X
X
NET
CALORIFIC
?
VALUE,
B!
I?
U/
cu.
f
t.
xx
NET
CALORIFIC
VALUE,
B
T
U
/
l
b
x
x
GFtOSS
CALORlFIC
VALUE,
BTU/
cu.
2
t
.
*
x
e
DSCF
EXHAUST
P
U
SCF
FUEL
I
O
1
Oxygen1
COMPRESSIBILITY
FACTOR
'
2'
160
F
,
1
ATHl
EPA
'
F'
F
a
c
t
o
r
@
58
F:
8618.222
DSCF
KCXE'CD
'
F'
Factor
@
60
F:
8488.949
DSCF
CkillJON
HYDROGEN
OXYGEN
NITROGZN
su
L
FUB
Totals
T
o
t
a
l
H/
C
72.90
2
4
.
1
4
9
2
1
9
5
0
.
0
0
99
.
I
99
33
.
.5
74
0.
22.83.
9
9
6
2
7
1013.50
23136.42
913.08
20844.04
.
8
5874
/
M
9tu.
/
rVI
Btu.
.9380.
**
Dry
Gas
@
60
F,
14.73
p
s
i
a
*
Water
S
a
t
u
r
a
t
e
d
Carno
t
1150
Burnett
Avenue,
Suite
C
Concord,
CA
94520
Attention:
Russ
Pence
.
.
Laboratory
No:
Oate
Received:
Date
Reported:
P
0
8:
1120
..
37261
9
15
93
9
16
93
Sample:
Gas
Sample
Description:
5,.
'*
;.
T
o
t
a
l
Sulfur
(
ASTM
0
3246)
As
BzS,
ppm
(
v
o
l
)
~
As
S
,
Grains/
100
SCF*
Sampled
on
9
13
93
a
t
*
Stzndard
cubic
feet
(
60
OF,
14
7
p
i
a
)
1200
hours
.
.
.
.
.
.
1
..
.
.
Lab
Operations
Manager
.
..
.
.
.
..
.
L
.
T..
L.
c
..
.
.
r
.
ZALLCO
IEORATOHIES,
INC.
Analyti
I
&
Consulting
Services
L
Carnoc
.
1140
Pearl
Street,
Suite
216
Bouldler,
CO
80302
Atcention:
Russell
Tence
*'.
:.
.'
:
*
.
.
.
*.
3,:
.
'
.
.:;>
Lab.
No.:
037960
001
Received:
Nov
18,
1
9
9
3
Reported:
Nov
22,
1993
Samp1.
e
Description:
Trojecr
#
SO100
11
16
93
I
*
CHROMATOG
PHIC
ANALYSIS
12
1635)
X
Comiponents
Hole
%
Wt
%
CHONS
Wt
%
_
I_
Hydrogen
0
.
0
0
0
0
.
0
0
0
CARBON
72.54
Carbon
,
Dioxide
621
1.592
HYDROGEN
23
57
Oxygen
.251
.467
OXYGEN
1
62
N
i
crogen
1.385
2.259
NITROGEN
2
.
2
6
Carbon
Honoxide
0.000
0
.
0
0
0
SULFUR
0
.
0
0
Hydrogen
Sulfide
0
.
0
0
0
0
,
0
0
0
Methane
93.065
8
6
.
9
6
2
T
o
t
a
l
s
9
9
.
9
9
Ethane
4.181
7
.
3
2
3
T
o
t
a
l
H/
C
32
Propane
382
.982
I
so
9
u
ta
ne
I038
.129
N
Sutantt
.
os0
.169
I
s
o
Pein
t
a
n
e
.014
.
O
S
8
N?
en
cane
.009
.037
.
H
exa
n
e
s
i
005
.023
*
rot:
ais
=
100.000
100.000
:
j
f
g
c
I
F
i
C
G
a
d
I
T
y
[
Air
I
r;
S
I
E
C
I
r
'
I
C
VOLUHE,
Cu.
ft./
lb
x
C;
20SS
CALORIFIC
VALUE,
BTU/
lb
x
x
NET
CALORIFIC
VALUE,
BTU/
lb
x
x
C;
EIOSS
CALORIFIC
VALUE,
BTU/
cu.
f
t.
X
(;
XlSS
CALORIFIC
VALUE,
BTU/
cu.
ft.
x
*
NET'
CALORIFIC
VALUE,
BTU/
cu.
ft.
x
a
DSCP
EXHAUST
PER
SCF
FUEL
(
0
%
Oxygen1
GOMPAESSl~
ILITY
FACTOR
'
2
'
1
6
0
F,
1
ATHj
ETA
'
F'
Factor
6
8
F:
8624.165
DSCF
KCAPCD
'
F'
f
a
c
t
o
r
li!
60
Fr
8494.803
DSCF
ca
e
22.07
1014.21
1031.75
22767
32
930.33
20529.20
LI
.7547
9
9
7
9
/
t
l
f
l
Btu.
1
,
HM
Btu,
*
a
WaCt??
S
a
t
u
r
a
t
e
d
*
x
Dry
Gas
@
60
F,
1
4
.
7
3
psia
ZALCO
LABORATORIES,
INC.
Analytical
(
SI
Consukhg
Services
Carno
t
1140
Pearl
Street,
Suite
216
Eoulder,
CO
80302
Attention:
Russell
Pence
Laboratory
No:
37960
Date
Received:
11
18
93
Date
Reported:
11
23
93
P
0
8
:
I466
Sample:
Gas
Fuel
Line,
Project
t5G100
.
6
Sample
Description:
Sampled
y
`
Russell
Pence.
on
11
16
93
``
it
1800
hours
Total
S
u
l
f
u
r
(
ASTM
D
3246)
As
H,
S,
ppm
(
v
o
l
.)
.
1.7
As
S
,
Grains/!
OO
SCF*
0*
10
_.
*
Standard
cubic
f
~
t
(
60
OF,
14.7
psia)
e,>
irn
Etherton
Is
_____
____
._
gl_
E_
I_
E_
r____
z_
g_
I
a
4309
Armour
Avenue
Bakersfield.
Celiforn'ia
93308
DI(
ZALCO
LABORATORIES,
INC.
Analytical
&
Consulting
Services
Carno
c
1140
Pearl
S
t
r
e
e
t
,
S
u
i
t
e
212
Boulder,
CO
80302
Lab.
No.:
037982
001
Received:
Nov
22,
1993
Reported:
Nov
2
2
,
1993
A
t
t
e
n
t
i
o
n
:
R
u
s
s
e
l
l
Pence
+.
.
i
.
*
4
Sampl'e
D
e
s
c
r
i
p
t
i
o
n
:
FS
SA
.
11
18
93
*
CHROMATOGRAPHIC
ANALYSIS
[
Z
1
6
3
5
1
*
C
o
m
p
o
n
e
n
t
s
Hole
%
W
t
%
CXONS
W
t
%
O
x
y
g
e
n
2
.
5
3
6
4
.
4
4
1
OXYGEN
5.39
H
y
d
r
o
g
e
n
o
*
o
o
o
0.000
CARBON
6
1
.
0
7
Ca
rborl
E
l
i
oxi
de
5
4
1
1
.
3
0
3
HYDROGEN
1
9
.
8
9
N
i
t
r
o
g
e
n
8
.
9
0
1
1
3
.
6
4
4
NITROGEN
1
3
.
6
4
C
a
r
b
o
n
Monoxide
0
.
0
0
0
0
000
SULFUR
0
.
0
0
H
y
d
r
o
g
e
n
S
u
l
f
i
d
e
M
e
t
ha
ne
E
t
h
a
n
e
3.403
5
.
s99
T
o
t
a
l
H/
C
33
P
ropa
nl
e
.317
.764
I
s
o
B
u
r
a
n
e
.032
.
I
O
3
u
0
.
0
0
0
0.000
8
4
.
2
0
2
7
3
.
9
1
3
T
o
t
a
l
s
99
*
99
N
Butane
013
.
1
3
8
I
s
o
P
e
n
t
a
n
e
010
0
3
9
N
P
e
n
t
a
n
e
.
0
1
0
*
039
H
e
x
a
n
e
s
+
.
0
0
4
.
0
1
7
T
o
t
g
a
l
s
1
0
0
.
0
0
0
1
0
0
.
0
0
0
SI;
E(:
it'IC
GXAiiiiTY
[
Air
=
i
j
SPECIFIC
VOLUME,
cu.
ft./
lb
GROSS
CALORIFIC
VALUE,
GROSS
CALORIFIC
VALUE,
BTU/
cu.
f
t
%*
x
x
BTU/
cu.
f
t
.
G.
ROSS
CALORIFIC
VALUE,
BTU/
lb
**
NET
CALORIFIC
VALUE,
B
T
U
/
c
u
.
f
t
.
%*
NET
CALORIFIC
VALUE,
BTiJ/
lb
**
D:
SCF
EXHAUST
PER
SCF
FUEL
[
O
x
Oxygen1
ERA
'
F'
F
a
c
t
o
r
@
6
8
F:
8
6
1
1
.
5
9
1
DSCF
KCAE'CD
'
F'
F
a
c
t
o
r
@
60
F:
8482.417
DSCF
COMPRESSIBILITY
FACTOR
'
Z'
I
6
0
F
J
l
ATHI
.
I_
0
.
O
~
L
Y
2
0
.
7
4
909.86
925.59
19192.1
8
8
3
4
.
5
0
1
7
3
0
3
.
3
3
7
.
9
5
4
4
.
9
9
8
2
/
MM
B
t
u
.
/
JIM
Btu.
x
Water
S
a
t
u
r
a
t
e
d
**
Dry
Gas
@
6
0
F,
1
4
7
3
psia
ZALCO;
LABORATORIES,
INC.
Analytical
&
Consulting
Services
\
Carnot
1140
Pearl
S
t
r
e
e
t
,
S
u
i
t
e
212
Boulder,
CO
8,0302.
Attention:
Russell
Sample:
Gas
Sample
Description:
Pence
F
S
J
n
w
e
r
l
Line
Project
Sampled
by
on
1
18
93
Laboratory
No:
37982
Date
Received:
11
22
93
Date
Reported:
11
23
93
P
0
51470
Total
Sulfur
(
ASTM
D
3246)
As
5,
Grains/
100
SCFi
<
0.06
*
Standard
cubic
f
e
e
t
(
60
O
F
,
14.7
psia)
iSir100
10033
.
Appendix
C.
7
Flow
Rate
Data
CARNOT
SAMPLE
TRAIN
TEST
SUMMARY
ClienVLocation
Date
Test
N
um
b
er
Data
By
Test
Method
Sample
Lcication
Fuel
Reference
Temp
(
F)
Control
Box
#
Unit
Pitot
Factor
Meter
Cal
Ifactor
Stack
Area
(
sqi
ft)
Sample
Time
(
Min)
Bar
Press
([
in
tig)
%
l
VELH204A
RJP
PA
14
STACK
GAS
68
ES
31
ICE
0.840
1.0292
52.56
30
.
27.57
72/
7/
93
2
VEL,
H20
6A
RJP
EPA
1
4
GAS
68
ES
31
ICE
0.840
1.0292
52.56
30
27.55
STACK
Meter
Vol
(
acfJ
Meter
Temp
(
F)
Sack
Press
(
ivvg)
Stack
Temp
(
F)
Vel
Head
(
liwg)
0
2
(%):
from
(
CEM
from
portable
C02
(%):
from
CEM
calculated
Liquid
Vol
i[
ml)
Meter
Press
(
ivvg)
Sta
rt/
Stop
'
Tim
le
21.960
37.3
0.47
926.6
0.8303
15.18
3.44
3.44
36.2
1.50
1045
1
11
5
15.18
20.529
38.5
0.47
926.6
15.34
.
15.34
3.37
3.37
30.1
1.50
0.8303
1
145
1
21
5
19.470
39.6
0.47
926.6
0.8303
15.39
15.39
3.26
3.26
28.0
1.50
131
5
1
345
20.653
38.5
0.47
926.6
0.8303
15.30
15.30
3.36
3.36
31.4
1.50
3
VE1,
H20
6A
Average
RJP
EPA
1
4
STACK
GAS
68
ES
31
ICE
0.840
1.0292
52.56
30
27.54
i
a
Std
Sample
Val1
(
SCF)
Metric
Sarriple
Vol
(
mA3)
Moisture
Fraction
Stack
Gas
Mol
Wt
Stack
Gas
Vel.
(
Wsec)
Stack
Flow
Rake
(
wacfm)
Stack
Flow
Rate
(
dscfm)
Stack
Flow
Rate
(
dscfh)
22.19
0.63
0.072
86.95
274.21
3
5.37E+
06
28
36
89,428
20.67
0.59
0.064
28.44
86.87
273.946
5.40E+
06
89,969
19.56
0.55
0.063
86.89
274,012
90.055
5.40E+
06
28
43
I
20.81,
0.59
0.07
28.41
274,057
89,817
86.90
5.39E+
06
.
VEL
6A.
XLS
3/
29/
94
1:
14
PM
I
CARNOT
SAMPLE
TRAIN
TEST
SUMMARY
ClientRocation
Date
Test
Number
Data
By
.
Test
Method
Sample
Location
Fuel
Reference
Temp
(
F)
Control
Box
#
Unit
Pitot
Factor
Meter
Cal
Factor
Stack
Area
(
sq
f
t
)
Sample
Time
(
Min)
Bar
Press
(
in
Hg)
4
VEL,
H20
6A
RJP
EPA
1
4
STACK
GAS
68
ES
31
ICE
0.840
1.0292
52.56
30
27.54
5
VEL.
H20s6A
RJP
EPA
1
4
STACK
GAS
68
ES
31
ICE
0.840
1.0292
52.56
40
27.56
Average
.
Meter
Vol
(
acf)
19.925
23.204
21.565
Stack
Press
(
iwg)
0.39
0.39
0.39
Vel
Head
(
iwg)
0.4373
0.4373
0.4373
02
(%):
from
CEM
15.79
15.75
15.77
from
portable
15.79
15.75
15.77
CO2
(%):
from
CEM
3.12
3.13
3.13
calculated
3.12
3.13
3.13
Meter
Press
(
i
g
)
1
S
O
1.50
1.50
Start/
Stop
Time
1420
1450
1530
1610
Meter
Temp
(
F)
39.7
39.6
39.7
.
Stack
Temp
(
F)
913.2
91
3.2
913.2
Liquid
Vol
(
ml)
26.2
20.6
23.4
Std
Sample
Vol
(
SCF)
Metric
Sample
Val
(
rnA3)
Moisture
Fraction
Stack
Gas
Mol
Wt
Stack
Gas
Vel.
(
ftfsec)
Stack
Flow
Rate
(
wacfm)
Stack
Flow
Rate
(
dscfm)
Stack
Flow
Rate
(
dscfh)
20.01
0.57
0.058
28.48
62
70
197,739
65,965
3.96E+*
23.33
0.66
0.040
28.69
mi46
196.969
67,025
4.02E+
06
21.67
0.61
0.05
28.58
62.58
197,354
66,495
3.99E+
06
.
VEL
6A.
XLS
.+
2/
21/
94
8:
08
AM
CARNOT
SAMPLE
TRAIN
TEST
SUMMARY
ClientlLocatiori
Date
Test
Number
Data
By
Test
Method
Sample
Location
Fuel
Reference
Temp
(
F)
Control
Box
#
Unit
Pitot
Factor
Meter
Cat
Factor
Stack
Area
(
sq
ft)
Sample
Time
(
Min)
Bar
Press
(
in
Hg)
1
2819
3
12/
8/
93
6
VEL,
H20
6A
RJP
EPA
1
4
STACK
GAS
68
ES
31
ICE
0.840
1.0292
52.56
27.44
30
.
7
VEL.
H20
6A
RJP
STACK
GAS
68
ICE
0.840
1.0292
52.56
40
27.40
EPA
I
'
ES
31
Average
Meter
Vol
(
acf)
Meter
Temp
(
F)
Stack
Press
(
i
i
g
)
Stack
Temp
(
F)
Vel
Head
(
hwg)
0
2
(%):
f
r
o
m
C:
EM
from
portable
C02
i%):
from
CEM
calculated
Liquid
Vol
(
iml)
Meter
Press,
(
ikg)
StaNStop
Time
21.077
.
43.5
.
a.
10
920.1
0.2012
15.75
15.75
2.95
2.95
28.3
1.50
1000
1
030
27.813
47.9
0.10
920.1
0.2012
15.89
15.89
2.92
2.92
33.3
1.50
1040
1
120
24.445
45.7
0.10
920.1
0.1341
15.82
15.82
2.94
2.94
,
30.8
1.50
Std
Sample
Vol
(
SCF)
Metric
Sample
Vol
(
m"
3)
Moisture
Fraction
Stack
Gas
Mol
Wt
Stack
Gas
Vel.
(
Wsec)
Stack
Flow
Rate
(
wacfm)
Stack
Flow
Rate
(
dscfm)
Stack
Flow
Rate
(
dscfh)
20.93
0.59
0.060
28.44
42.78
134,908
44,474
2.67E+
06
27.34
0.77
0.054
28.50
42.76
134,856
44,658
2.68E+
06
24.14
0.68
0.06
28.47
134,882
44.566
2.67E+
06
.
42.77
5
VEL
6A.
XLS
2/
21/
94
8:
12
AM
CARNOT
SAMPLE
TRAIN
TEST
SUMMARY
ClientLocation
Date
Test
Number
Data
By
Test
Method
Sample
Location
Fuel
Reference
Temp
(
F)
Control
Box
#
unit
Pitot
Factor
Meter
Cal
Factor
Stack
Area
(
sq
ft)
Sample
Time
(
Min)
Ear
Press
(
in
Hg)
12/
8/
93
RJP
EPA
1
4
STACK
GAS
68
ES
3
1
ICE
0.840
1.0292
52.56
30
27.35
8
VEL.
HZ0
6A
ILIUIYJ
9
VE/
H20
6A
RJP
EPA
1
4
STACK
GAS
68
ES
31
ICE
0.840
1
0292
52.56
35
27.35
Average
.
.
.
.
i
.
.
Meter
Vol
(
acr)
Meter
Temp
(
F)
.
Stack
Press
(
`
i
g
)
Stack
Temp
(
F)
Vel
Head
(
iwg)
0
2
(%):
from
CEM
from
portable
C02
(%):
from
CEM
calculated
Liquid
Vol
(
mi)
Meter
Press
(
iwg)
StaNStop
Time
18.824
48.8
4
10
731.5
0.1796
16.96
16.96
2.15
2.15
21.5
1.50
1235
1305
20.968
45.9
0.1
0
731.5
0.1
796
16.96
16.96
2.21
2.21
33.3
1
s
o
13351
41
0
19.896
47.4
0.10
731.5
0.1197
'
'
16.96
16.96
2.18
2.1
8
27.4
1.50
..
..
,
Std
Sample
Vol
(
SCF)
Metric
Sample
Vol
(
rn"
3)
Moisture
Fraction
Stack
Gas
Mol
Wt
Stack
Gas
Vel.
(
Wsec)
Stack
Flow
Rate
(
wacfm)
Stack
Flow
Rate
(
dscfm)
Stack
Flow
Rate
(
dscfh)
18.44
0.52
0.052
28.45
37.61
4551
5
2.73E+
06
i
18,603
20.66
0.59
0.071
28.25
37.74
119,012
44,778
269E+
06
19.55
0.55
0.06
28.35
37.67
45,147
1
i
8,
a07
2.71
E+
06
CARNOT
SAMF'LE
LOCATION:
*
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L
UNITNO.:
fk
TESTNO.:,
[,&
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(
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soi
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STATIC
PFIESS.
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STACK
(
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oty>
ps
I
DATA
TAKEN
BY:
TEST
DESCRIPTION:
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de\
c\
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s
h&
UNIT
NO.:
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TEST
NO.:
'
7
\
fELCi/>
A
BARO.
PRESS.
(
in.
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S
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STATIC
PRESS.
IN
STACK
(
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ps
DATA
TAKEN
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c
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PRESS.
(
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Hg):
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1
35
'
ABS.
STATIC
PRESS.
IN
STACK
(
in.
Hg)
0
1
ID
P,
.
.
b
I
~
DATA
TAKEN
BY:
&$?
&
cbLs
TEST
DESCRIPTION:
k
PITOT
TUBE
COEFFICIENT
0
*
v
Cp
.
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c
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,
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1
1
1
1
I
I
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1.1
1
f.
.
_.
.
..
A
i
.
.
1
5
Appendix
C.
8
Ambient
Wind
Speed
and
Directiori
Data
GRI
1
E
125
IS
1
971
5/
R
120D755.
T
..
~
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.
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c:.
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...
IC______=_
.
.
.
.
.
.
.
APPENDIX
D
CALCULATIONS
.
.
.
GFU
I
E
12.5
15
1!?
7
15/
R
120D755.
T
D
1
Appendix
D.
1
General
Emissions
Calculations
GIUl
E
125
115
19715/
R120D755.
T
Page
1
of
4
EMISSION
CALCULATIONS
1.
$
mule
Volume
and
Isokinetics
.
...
a.
Sample
gas
volume,
dscf
V,
=
0.03342
V,
Pb+
5
(
Y)
(
I
q
.
.
)
b.
Water
vapor
voIume,
scf
V,,
=
a
0.0472
V'
[
5
2
k
!
]
C
SI
Moisture
content,
nondimensional
d.
Stack
gas
molecular
weight,
Ibhb
mole
Mw,,
=
0.44
(
XCOJ
+
0.32
(%
OJ
+
028
(%
NJ
M
w
,
=
MW,,
(
1
BJ
+
18
(
I33
e.
Absolute
stack
pressure,
in
Hg
P,
=
Pb
+
%
13.6
f.
Stack
velocity,
ftJsec
~
.
"
g.
Actual
stack
flow
rate,
wach
Q
=
(
VJ(
AJ(
W
I
h.
Standard
stack
gas
flow
rate,
dscfin
Qd
=
Q
(
1
B
,
J
[
s
)
(
L
)
T,
29.92
1.
Percent
isokinetic
10020F136C219.
T
Page
2
of
4
2.
])
articulate
Emissions
a.
Grain
loading,
gddsd
C
=
0.01543
[
2)
ti.
Grain
loading
at
12%
COz,
gr/
dscf
C.
Mass
emissions,
I
b
h
3.
Gaseous
Emissions.
lbhr
where,
SY
=
Jpeciific
molar
volume
of
an
ideat
gar;:
SV
=
385.3
fr3/
lb
moIe
for
qd
=
528
"
R
SV
=
3795
fr3]
lb
mole
for
Trd
=
520
"
R
4.
Emissions
Rates.
lb/
106
Btu
a.
Fuel
factor
at
68
OF,
dscf/
106
BN
at
0%
O2
106[
3.64(%
H)
+
1.53(%
C)
+
0.14
(
X
R
)
+
057(%
S)
0.46(%
U2fLeo]
H
m
,
Bzuilb
Fa
=
b
.,
Fuel
factor
at
60
OF
520
"
R
F60
=
Fa
(
e)
C.
Gaseous
Emissions
factor
20.9
d
.
I
Particulate
emission
factor
Nomeincla
ture:
4
3,
=
12*
w2
stack
area,
ft'
flue
gas
moisture
content
particulate
grain
loading,
gr/
dscf
corrected
to
12%
CO,
particulate
grain
loading,
gddscf
pitot
calibration
factor,
dimensionless
nozzle
diameter,
in.
fuel
F
factor,
dscf/
106
Btu
at
0%
0,
orifice
pressure
differential,
iwg
%
isokinetics
mass
of
collected
particulate,
mg
mass
emissions
of
species
i,
lbhr
molecular
weight
of
flue
gas
molecular
weight
of
species
i:
NO,
:
46
so,
:
64
co
:
28
HC
:
16
sample
time,
min.
Page
3
of
4
average
velocity
heaL,
iwg
=
(
barometric
pressure,
in.
Hg
stack
absolute
pressure,
in.
Hg
stack
static
pressure,
iwg
p
Nommdature
(
Continued):
=
wet
stack
gas
flow
rate
at
actual
conditions,
wacfm
dry
stack
gas
flow
rate
at
standard
conditions,
dsch
specific
molar
volume
of
an
ideal
gas
at
standard
conditions,
ffAb
mole
meter
temperature,
OR
reference
temperature,
.
OR
stack
temperature,
"
R
stack
velocity,
ft/
sec
voIume
of
liquid
collected
in
impingers,
ml
dry
meter
volume
uncorrected,
dcf
dry
meter
volume
at
standard
conditions,
dscf
volume
of
water
vapor
at
standard
conditions,
scf
meter
calibration
coefficient
Page
4
of
4
Appendix
D.
2
Specific
Emissions
Calculations
.
.
d
z
..
.
.
.
SHEET
HO.
Q
f
,
COMPUTED
BY
,
DATE
1
0
/
5
C
H
t
H
E
C
K
E
D
BY
OAT
E
.
.
b
.
11
50
Burnerr,
Suite
C,
Concord,
CA
94596
APPENDIX
E
STRIP
CHARTS
.
.
.
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Inn
n
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1
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A
...
APPENDIX
F
CHAIN
OF
CUSTODY
II
GRl1
E
125
15
197CSIR120D755
.
T
F
1
*
CERTIFICATION
OF
SAMPLE
RECEIPT
1
F
R
o
x
c
T
*
JO
s
I
3
197
4
OUTSIDE
LAB
REWIRED
(
Y
f
l
)
SAM?
LEDATE
fZ
17
81
93
CUENTROCATlCN
PROJECTMANAGER
&
P
SAMPLE
LOCATION
SALV
METHOD($)
q%
TECHNICIAN
ch'
COMPLIANCE
TEST
(
YN)
d
DATE
DUE
/
2jZ3/
q3
RECIPIENT
k
6
CERTIFICATION
OF
SAMPLE
RECEIPT
PFICJECT'S
lOsI7
19
OUTSIDE
IAB
REOUIFIED
(
Y;"
J
,
SAMPLE
DATE
/
z
/
7
g/
q3
SAMPLE
LOCATION
Ah.&
g.
N
J
METHOO(
S)
6
p
A
TO
ll
TECHNICIAN
/
mz
CUENTICOCATION
PROJECT
MANAGER
kf
Gwnl
0Jh'PLc
DATE
DUE
COMPLIANCE
TEST
(
YM)
AI
,
RECIPIENT
COMPANY
3ATE
B/
4/
43
.
I
CERTIFICATION
OF
SAMPLE
RECEIPT
PROJECT
#
d
l
6
I
4
OUTSIDE
LAB
REQUIRED
(
Y
N
)
9
SAMPLE
DATE
lLPf
4
.,*
r.
4
*
.
.
I
CUENTROCATIO
N
PROJECTMANAGER
#
.
SAMPLE
LOCATlON
METHOD(
S)
@
flo
L
id/
TECHNlClAM
.
F
A
CHAIN
OF
CUSTODY
PRIOR
TO
SHIPMEW:
DATE
)
t/
r
193
t
CERTIFlCATlON
OF
SAMPLE
RECEiPT
CUENTROCAnON
PROJECT
MANAGER
...
.
d
CHAIN
OF
CUSTODY
PRIOR
TO
SHIPMENT:
.
.
CARNOT
TEDLAR
BAG
SAMPLE
DATA
.
.
.,+
!
I
I
_
UNIT
3:
DATE:
1
I
BAG
ID
I
BAGID
1
BAGID
I
I
I
I
i
I
I
I
i
I
STOP
TIME
SAL!
PLE
LOCATION
I
I
li
!
C3MPhNY
DATE
I
I
.
4
.
.
;.:
.
CHAIN
OF
CUSTODY
DATE
UNR
BY:
r
I
BAGID
I
BAGlD
TEST
NO.
1
I
BAG
ID
1
SdhAPE
?.
ATE
STAFlT
TIME
I
1
I
I
I
..
1
NOTES:
I
I
b'
I
CERTlFlCATiON
OF
SAMPLE
R
E
C
W
T
COMPUANlCE
'
TEST
(
Ym)
9
SAMPES
SHIP?
RECIPE..
.
CHAIN
OF
CUSTODY
| epa | 2024-06-07T20:31:40.280198 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0060-0337/content.txt"
} |
EPA-HQ-OAR-2002-0065-0001 | Rule | "2002-11-08T05:00:00" | Control of Emissions From Nonroad Large Spark-Ignition Engines, and Recreational Engines (Marine and Land-Based); Final Rule [A-2000-01-V-A-03] | Friday,
November
8,
2002
Part
II
Environmental
Protection
Agency
40
CFR
Parts
89
et
al.
Control
of
Emissions
From
Nonroad
Large
Spark
Ignition
Engines,
and
Recreational
Engines
(
Marine
and
Land
Based);
Final
Rule
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Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
89,
90,
91,
94,
1048,
1051,
1065,
and
1068
[
AMS
FRL
7380
2]
RIN
2060
AI11
Control
of
Emissions
From
Nonroad
Large
Spark
Ignition
Engines,
and
Recreational
Engines
(
Marine
and
Land
Based)
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Final
rule.
SUMMARY:
In
this
action,
we
are
adopting
emission
standards
for
several
groups
of
nonroad
engines
that
have
not
been
subject
to
EPA
emission
standards.
These
engines
are
large
spark
ignition
engines
such
as
those
used
in
forklifts
and
airport
ground
service
equipment;
recreational
vehicles
using
sparkignition
engines
such
as
off
highway
motorcycles,
all
terrain
vehicles,
and
snowmobiles;
and
recreational
marine
diesel
engines.
Nationwide,
these
engines
and
vehicles
cause
or
contribute
to
ozone,
carbon
monoxide,
and
particulate
matter
nonattainment,
as
well
as
other
types
of
pollution
impacting
human
health
and
welfare.
We
expect
that
manufacturers
will
be
able
to
maintain
or
even
improve
the
performance
of
their
products
when
producing
engines
and
equipment
meeting
the
new
standards.
Many
engines
will
substantially
reduce
their
fuel
consumption,
partially
or
completely
offsetting
any
costs
associated
with
the
emission
standards.
Overall,
the
gasoline
equivalent
fuel
savings
associated
with
the
anticipated
changes
in
technology
resulting
from
this
rule
are
estimated
to
be
about
800
million
gallons
per
year
once
the
program
is
fully
phased
in.
Health
and
environmental
benefits
from
the
controls
included
in
today's
rule
are
estimated
to
be
approximately
$
8
billion
per
year
once
the
controls
are
fully
phased
in.
There
are
also
several
provisions
to
address
the
unique
limitations
of
small
volume
manufacturers.
DATES:
This
final
rule
is
effective
January
7,
2003.
The
incorporation
by
reference
of
certain
publications
listed
in
this
regulation
is
approved
by
the
Director
of
the
Federal
Register
as
of
January
7,
2003.
ADDRESSES:
Materials
relevant
to
this
rulemaking
are
contained
in
Public
Docket
Numbers
A
98
01
and
A
2000
01
at
the
following
address:
EPA
Docket
Center
(
EPA/
DC),
Public
Reading
Room,
Room
B102,
EPA
West
Building,
1301
Constitution
Avenue,
NW.,
Washington
DC.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
except
on
government
holidays.
You
can
reach
the
Reading
Room
by
telephone
at
(
202)
566
1742,
and
by
facsimile
at
(
202)
566
1741.
The
telephone
number
for
the
Air
Docket
is
(
202)
566
1742.
You
may
be
charged
a
reasonable
fee
for
photocopying
docket
materials,
as
provided
in
40
CFR
part
2.
For
further
information
on
electronic
availability
of
this
action,
see
SUPPLEMENTARY
INFORMATION
below.
FOR
FURTHER
INFORMATION
CONTACT:
U.
S.
EPA,
Office
of
Transportation
and
Air
Quality,
Assessment
and
Standards
Division
hotline,
(
734)
214
4636,
asdinfo@
epa.
gov;
Alan
Staut,
(
734)
214
4805.
SUPPLEMENTARY
INFORMATION:
Regulated
Entities
This
action
will
affect
companies
that
manufacture
or
introduce
into
commerce
any
of
the
engines
or
vehicles
subject
to
emission
standards.
These
include:
spark
ignition
industrial
engines
such
as
those
used
in
forklifts
and
compressors;
recreational
vehicles
such
as
off
highway
motorcycles,
allterrain
vehicles,
and
snowmobiles;
and
recreational
marine
diesel
engines.
This
action
will
also
affect
companies
buying
engines
for
installation
in
nonroad
equipment.
There
are
also
requirements
that
apply
to
those
who
rebuild
any
of
the
affected
nonroad
engines.
Regulated
categories
and
entities
include:
Category
NAICS
Codes
a
SIC
Codes
b
Examples
of
potentially
regulated
entities
Industry
...................
333618
3519
Manufacturers
of
new
nonroad
spark
ignition
engines,
new
marine
engines.
Industry
...................
333111
3523
Manufacturers
of
farm
equipment.
Industry
...................
333112
3531
Manufacturers
of
construction
equipment,
recreational
marine
vessels.
Industry
...................
333924
3537
Manufacturers
of
industrial
trucks.
Industry
...................
811310
7699
Engine
repair
and
maintenance.
Industry
...................
336991
....................
Motorcycle
manufacturers.
Industry
...................
336999
....................
Snowmobiles
and
all
terrain
vehicle
manufacturers.
Industry
...................
421110
....................
Independent
Commercial
Importers
of
Vehicles
and
Parts.
a
North
American
Industry
Classification
System
(
NAICS)
b
Standard
Industrial
Classification
(
SIC)
system
code.
This
list
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
this
action
regulates
particular
activities,
you
should
carefully
examine
the
regulations.
You
may
direct
questions
regarding
the
applicability
of
this
action
to
the
person
listed
in
FOR
FURTHER
INFORMATION
CONTACT.
Obtaining
Electronic
Copies
of
the
Regulatory
Documents
The
preamble,
regulatory
language,
Final
Regulatory
Support
Document,
and
other
rule
documents
are
also
available
electronically
from
the
EPA
Internet
web
site.
This
service
is
free
of
charge,
except
for
any
cost
incurred
for
internet
connectivity.
The
electronic
version
of
this
final
rule
is
made
available
on
the
day
of
publication
on
the
primary
web
site
listed
below.
The
EPA
Office
of
Transportation
and
Air
Quality
also
publishes
Federal
Register
notices
and
related
documents
on
the
secondary
web
site
listed
below.
1.
http://
www.
epa.
gov/
docs/
fedrgstr/
EPA
AIR/
(
either
select
desired
date
or
use
Search
feature)
2.
http://
www.
epa.
gov/
otaq/
(
look
in
What's
New
or
under
the
specific
rulemaking
topic)
Please
note
that
due
to
differences
between
the
software
used
to
develop
the
documents
and
the
software
into
which
the
document
may
be
downloaded,
format
changes
may
occur.
Table
of
Contents
I.
Introduction
A.
Overview
B.
How
Is
This
Document
Organized?
C.
What
Categories
of
Vehicles
and
Engines
Are
Covered
in
This
Final
Rule?
D.
What
Requirements
Are
We
Adopting?
E.
Why
Is
EPA
Taking
This
Action?
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Friday,
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8,
2002
/
Rules
and
Regulations
1
Diesel
cycle
engines,
referred
to
simply
as
``
diesel
engines''
in
this
document,
may
also
be
referred
to
as
compression
ignition
(
or
CI)
engines.
These
engines
typically
operate
on
diesel
fuel,
but
other
fuels
may
also
be
used.
Otto
cycle
engines
(
referred
to
here
as
spark
ignition
or
SI
engines)
typically
operate
on
gasoline,
liquefied
petroleum
gas,
or
natural
gas.
2
This
rule
also
found
that
PM
emissions
from
marine
diesel
engines
contribute
to
PM
nonattainment.
II.
Nonroad:
General
Provisions
A.
Scope
of
Application
B.
Emission
Standards
and
Testing
C.
Demonstrating
Compliance
D.
Other
Concepts
III.
Recreational
Vehicles
and
Engines
A.
Overview
B.
Engines
Covered
by
This
Rule
C.
Emission
Standards
D.
Testing
Requirements
E.
Special
Compliance
Provisions
F.
Technological
Feasibility
of
the
Standards
IV.
Permeation
Emission
Control
A.
Overview
B.
Vehicles
Covered
by
This
Provision
C.
Permeation
Emission
Standards
D.
Testing
Requirements
E.
Special
Compliance
Provisions
F.
Technological
Feasibility
V.
Large
Spark
ignition
(
SI)
Engines
A.
Overview
B.
Large
SI
Engines
Covered
by
This
Rule
C.
Emission
Standards
D.
Testing
Requirements
and
Supplemental
Emission
Standards
E.
Special
Compliance
Provisions
F.
Technological
Feasibility
of
the
Standards
VI.
Recreational
Marine
Diesel
Engines
A.
Overview
B.
Engines
Covered
by
This
Rule
C.
Emission
Standards
for
Recreational
Marine
Diesel
Engines
D.
Testing
Equipment
and
Procedures
E.
Special
Compliance
Provisions
F.
Technical
Amendments
G.
Technological
Feasibility
VII.
General
Nonroad
Compliance
Provisions
A.
Miscellaneous
Provisions
(
Part
1068,
Subpart
A)
B.
Prohibited
Acts
and
Related
Requirements
(
Part
1068,
Subpart
B)
C.
Exemptions
(
Part
1068,
Subpart
C)
D.
Imports
(
Part
1068,
Subpart
D)
E.
Selective
Enforcement
Audit
(
Part
1068,
Subpart
E)
F.
Defect
Reporting
and
Recall
(
Part
1068,
Subpart
F)
G.
Hearings
(
Part
1068,
Subpart
G)
VIII.
General
Test
Procedures
A.
General
Provisions
B.
Laboratory
Testing
Equipment
C.
Laboratory
Testing
Procedures
D.
Other
Testing
Procedures
IX.
Projected
Impacts
A.
Environmental
Impact
B.
Cost
Estimates
C.
Cost
Per
Ton
of
Emissions
Reduced
D.
Economic
Impact
Analysis
E.
Do
the
Benefits
Outweigh
the
Costs
of
the
Standards?
X.
Public
Participation
XI.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
B.
Paperwork
Reduction
Act
C.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
D.
Unfunded
Mandates
Reform
Act
E.
Executive
Order
13132:
Federalism
F.
Executive
Order
13175:
Consultation
and
Coordination
With
Indian
Tribal
Governments
G.
Executive
Order
13045:
Protection
of
Children
From
Environmental
Health
and
Safety
Risks
H.
Executive
Order
13211:
Actions
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
I.
National
Technology
Transfer
and
Advancement
Act
J.
Congressional
Review
Act
K.
Plain
Language
I.
Introduction
A.
Overview
Emissions
from
the
engines
regulated
in
this
rule
contribute
to
serious
airpollution
problems,
and
will
continue
to
do
so
in
the
future
absent
regulation.
These
air
pollution
problems
include
exposure
to
carbon
monoxide
(
CO),
ground
level
ozone,
and
particulate
matter
(
PM),
which
can
cause
serious
health
problems,
including
premature
mortality
and
respiratory
problems.
Fine
PM
has
also
been
associated
with
cardiovascular
problems,
such
as
heart
rate
variability
and
changes
in
fibrinogen
(
a
blood
clotting
factor)
levels,
and
hospital
admissions
and
mortality
related
to
cardiovascular
diseases.
These
emissions
also
contribute
to
other
serious
environmental
problems,
including
visibility
impairment
and
ecosystem
damage.
In
addition,
many
of
the
hydrocarbon
(
HC)
pollutants
emitted
by
these
engines
are
air
toxics.
This
rule
addresses
these
air
pollution
concerns
by
adopting
national
emission
standards
for
several
types
of
nonroad
engines
and
vehicles
that
are
currently
unregulated.
These
include
large
sparkignition
engines
used
in
industrial
and
commercial
applications
such
as
those
used
in
forklifts
and
airport
equipment;
recreational
spark
ignition
vehicles
such
as
off
highway
motorcycles,
all
terrain
vehicles,
and
snowmobiles;
and
recreational
marine
diesel
engines.
1
These
new
standards
are
a
continuation
of
the
process
of
establishing
emission
standards
for
nonroad
engines
and
vehicles,
under
Clean
Air
Act
section
213(
a).
We
conducted
a
study
of
emissions
from
nonroad
engines,
vehicles,
and
equipment
in
1991,
as
directed
by
the
Clean
Air
Act,
section
213(
a)
(
42
U.
S.
C.
7547(
a)).
Based
on
the
results
of
that
study,
we
determined
that
emissions
of
oxides
of
nitrogen
(
NOX),
volatile
organic
compounds,
and
CO
from
nonroad
engines
and
equipment
contribute
significantly
to
ozone
and
CO
concentrations
in
more
than
one
nonattainment
area
(
59
FR
31306,
June
17,
1994).
Given
this
determination,
section
213(
a)(
3)
of
the
Act
requires
us
to
establish
(
and
from
time
to
time
revise)
emission
standards
for
those
classes
or
categories
of
new
nonroad
engines,
vehicles,
and
equipment
that
in
our
judgment
cause
or
contribute
to
such
air
pollution.
We
have
determined
that
the
engines
covered
by
this
final
rule
cause
or
contribute
to
such
air
pollution
(
see
the
final
finding
for
recreational
vehicles
and
nonroad
spark
ignition
engines
over
19
kW
published
on
December
7,
2000
(
65
FR
76790),
the
final
rule
for
marine
diesel
engines
published
on
December
29,
1999
(
64
FR
73301)
2,
Section
II
of
the
preamble
to
the
proposed
rule
(
66
FR
51098,
October
5,
2001),
this
preamble,
and
the
Final
Regulatory
Support
Document).
Where
we
determine
that
other
emissions
from
new
nonroad
engines,
vehicles,
or
equipment
significantly
contribute
to
air
pollution
that
may
reasonably
be
anticipated
to
endanger
public
health
or
welfare,
section
213(
a)(
4)
of
the
Act
authorizes
EPA
to
establish
(
and
from
time
to
time
revise)
emission
standards
from
those
classes
or
categories
of
new
nonroad
engines,
vehicles,
and
equipment
that
cause
or
contribute
to
such
air
pollution.
Pursuant
to
section
213(
a)(
4)
of
the
Act,
we
are
finalizing
a
finding
that
emissions
from
new
nonroad
engines,
including
construction
equipment,
farm
tractors,
boats,
locomotives,
marine
engines,
nonroad
spark
ignition
engines
over
19
kW,
recreational
vehicles
(
including
off
highway
motorcycles,
allterrain
vehicles,
and
snowmobiles),
significantly
contribute
to
regional
haze
and
visibility
impairment
in
federal
Class
I
areas
and
where
people
live,
work
and
recreate.
These
engines,
particularly
recreational
vehicles
such
as
snowmobiles,
are
significant
emitters
of
pollutants
that
are
known
to
impair
visibility
in
federal
Class
I
areas
(
see
Section
I.
E
of
this
preamble
and
the
Final
Regulatory
Support
Document).
We
have
also
determined
that
engines
covered
by
this
final
rule,
particularly
recreational
vehicles
including
snowmobiles,
contribute
to
such
pollution.
Thus,
we
are
finalizing
HC
standards
for
snowmobiles
to
reduce
PM
related
visibility
impairment.
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2002
/
Rules
and
Regulations
3
For
this
final
rule,
we
consider
the
United
States
to
include
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.
B.
How
Is
This
Document
Organized?
This
final
rule
covers
engines
and
vehicles
that
vary
in
design
and
use,
and
many
readers
may
be
interested
in
only
one
or
two
of
the
applications.
We
have
grouped
engines
by
common
application
(
for
example,
recreational
land
based
engines,
marine
diesel
recreational
engines,
large
sparkignition
engines
used
in
commercial
applications).
This
document
is
organized
in
a
way
that
allows
each
reader
to
focus
on
the
applications
of
particular
interest.
Section
II
describes
general
provisions
that
are
relevant
to
all
of
the
nonroad
engines
covered
by
this
rulemaking.
Section
III
through
VI
present
information
specific
to
each
of
the
affected
nonroad
applications,
including
standards,
effective
dates,
testing
information,
and
other
specific
requirements.
Sections
VII
and
VIII
describe
a
wide
range
of
compliance
and
testing
provisions
that
apply
generally
to
engines
and
vehicles
from
all
the
nonroad
engine
and
vehicle
categories
included
in
this
rulemaking.
Several
of
these
provisions
apply
not
only
to
manufacturers,
but
also
to
equipment
manufacturers
installing
certified
engines,
remanufacturing
facilities,
operators,
and
others.
Therefore,
all
affected
parties
should
read
the
information
contained
in
these
sections.
Section
IX
summarizes
the
projected
impacts
and
a
discussion
of
the
benefits
of
this
rule.
Finally,
Sections
X
and
XI
contain
information
about
public
participation
and
various
administrative
requirements.
The
remainder
of
this
section
summarizes
the
new
requirements
and
the
air
quality
need
for
the
rulemaking.
C.
What
Categories
of
Vehicles
and
Engines
Are
Covered
in
This
Final
Rule?
This
final
rule
establishes
regulatory
programs
for
new
nonroad
vehicles
and
engines
not
yet
subject
to
EPA
emission
standards,
including
the
following
engines:
Land
based
spark
ignition
recreational
engines,
including
those
used
in
snowmobiles,
off
highway
motorcycles,
and
all
terrain
vehicles.
For
the
purpose
of
this
rule,
we
are
calling
this
group
of
engines
``
recreational
vehicles,''
even
though
allterrain
vehicles
can
be
used
for
commercial
purposes.
Land
based
spark
ignition
engines
rated
over
19
kW,
including
engines
used
in
forklifts,
generators,
airport
baggage
tow
trucks,
and
various
farm,
construction,
and
industrial
equipment.
This
category
also
includes
auxiliary
marine
engines,
but
does
not
include
propulsion
marine
engines
or
engines
used
in
recreational
vehicles.
For
purposes
of
this
rule,
we
refer
to
this
category
as
``
Large
SI
engines.''
Recreational
marine
diesel
engines.
This
final
rule
covers
new
engines
that
are
used
in
the
United
States,
whether
they
are
made
domestically
or
imported.
3
A
more
detailed
discussion
of
the
meaning
of
the
terms
``
new''
and
``
imported''
that
help
define
the
scope
of
application
of
this
rule
is
in
Section
II
of
this
preamble.
D.
What
Requirements
Are
We
Adopting?
The
fundamental
requirement
for
nonroad
engines
and
vehicles
is
meeting
EPA's
emission
standards.
Section
213(
a)(
3)
of
the
Act
requires
that
standards
to
control
emissions
related
to
ozone
or
CO
achieve
the
greatest
degree
of
emission
reduction
achievable
through
the
application
of
technology
that
will
be
available,
giving
appropriate
consideration
to
cost,
noise,
energy,
and
safety
factors.
Section
213
(
a)(
4)
of
the
Act
requires
that
standards
for
emissions
related
to
other
air
pollution
problems
be
appropriate
and
take
into
account
costs,
noise,
safety,
and
energy
impacts
of
applying
technology
that
will
be
available.
Other
requirements
such
as
applying
for
certification,
labeling
engines,
and
meeting
warranty
requirements
define
a
process
for
implementing
the
program
in
an
effective
way.
With
regard
to
Large
SI
engines,
we
are
adopting
a
two
phase
program.
The
first
phase
of
the
standards
go
into
effect
in
2004
and
are
the
same
as
those
adopted
in
October
1998
by
the
California
Air
Resources
Board
for
2004.
These
standards
will
reduce
combined
HC
and
NOX
emissions
by
nearly
75
percent,
based
on
emission
measurements
during
steady
state
operation.
In
2007,
we
supplement
these
standards
by
setting
limits
that
will
require
optimizing
the
same
technologies
and
will
base
emission
measurements
on
a
transient
test
cycle.
New
requirements
for
evaporative
emissions
and
engine
diagnostics
also
start
in
2007.
For
recreational
vehicles,
we
are
adopting
separate
emission
standards
for
snowmobiles,
off
highway
motorcycles,
and
all
terrain
vehicles.
For
snowmobiles,
we
are
adopting
a
first
phase
of
standards
for
HC
and
CO
emissions
based
on
a
mixture
of
technologies
ranging
from
clean
carburetion
and
engine
modifications
to
direct
fuel
injection
two
stroke
technology
and
some
conversion
to
four
stroke
engines,
and
second
and
third
phases
of
emission
standards
for
snowmobiles
that
will
involve
significant
use
of
direct
fuel
injection
two
stroke
technology
and
conversion
to
four
stroke
engines.
For
off
highway
motorcycles
and
all
terrain
vehicles,
we
are
adopting
standards
based
mainly
on
moving
these
engines
from
two
stroke
to
four
stroke
technology
with
the
use
of
some
secondary
air
injection.
We
are
also
adopting
requirements
to
address
permeation
emissions
from
all
three
types
of
recreational
vehicles.
The
emission
standards
for
recreational
marine
diesel
engines
are
comparable
to
those
already
established
for
commercial
marine
diesel
engines.
Manufacturers
generally
have
additional
time
to
meet
emission
standards
for
the
recreational
models
and
several
specific
rulemaking
provisions
are
tailored
to
the
unique
characteristics
of
these
engines.
We
are
also
adopting
more
stringent
voluntary
Blue
Sky
Series
emission
standards
for
recreational
marine
diesel
engines
and
Large
SI
engines.
Blue
Sky
Series
emission
standards
are
more
stringent
than
the
mandatory
emission
standards
and
are
intended
to
encourage
the
introduction
and
more
widespread
use
of
low
emission
technologies.
Manufacturers
may
be
motivated
to
exceed
emission
requirements
either
to
gain
early
experience
with
certain
technologies
or
as
a
response
to
market
demand
or
local
government
programs.
For
recreational
vehicles,
we
are
not
adopting
voluntary
standards
but
rather
providing
consumers
with
consumer
labeling,
which
will
provide
information
and
opportunity
to
buy
lower
emissions
models.
We
have
also
conducted
extensive
analysis
on
the
costs
and
benefits
of
this
rulemaking
effort,
with
specific
details
found
in
Section
IX
below
and
in
the
Final
Regulatory
Support
Document.
In
summary,
we
estimate
that
annually,
the
cost
to
manufacturers
is
approximately
$
210
million,
the
social
gain
is
approximately
$
550
million,
and
the
quantified
benefits
are
approximately
$
8
billion.
Social
gain
is
defined
as
the
economic
cost
of
the
rule
minus
the
estimated
fuels
savings.
Quantified
benefits
reflect
the
health
benefits
primarily
associated
with
particulate
matter
controls.
E.
Why
Is
EPA
Taking
This
Action?
There
are
important
public
health
and
welfare
reasons
supporting
the
new
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Regulations
4
U.
S.
EPA
Review
of
the
National
Ambient
Air
Quality
Standards
for
Ozone:
Policy
Assessment
of
Scientific
and
Technical
Information
OAQPS
Staff
Paper.
EPA
452/
R
96
007.
June
1996.
A
copy
of
this
document
can
be
found
in
Docket
A
99
06,
Document
II
A
22.
5
U.
S.
EPA
Review
of
the
National
Ambient
Air
Quality
Standards
for
Particulate
Matter:
Policy
Assessment
of
Scientific
and
Technical
Information
OAQPS
Staff
Paper.
EPA
452/
R
96
013.
1996.
Docket
Number
A
99
06,
Documents
Nos.
II
A
18,
19,
20,
and
23.
The
particulate
matter
air
quality
criteria
documents
are
also
available
at
http://
www.
epa.
gov/
ncea/
partmatt.
htm.
emission
standards.
As
described
below
and
in
the
Final
Regulatory
Support
Document,
these
engines
contribute
to
air
pollution
that
causes
public
health
and
welfare
problems.
Nationwide,
these
engines
and
vehicles
are
a
significant
source
of
mobile
source
air
pollution.
As
described
below,
of
all
mobile
source
emissions
in
2000
they
accounted
for
about
9
percent
of
HC
emissions,
4
percent
of
CO
emissions,
3
percent
of
NOX
emissions,
and
2
percent
of
direct
PM
emissions.
The
emissions
from
Large
SI
engines
contributed
2
to
3
percent
of
the
HC,
NOX,
and
CO
emissions
from
mobile
sources
in
2000.
Recreational
vehicles
by
themselves
account
for
about
6
percent
of
national
mobile
source
HC
emissions
and
about
2
percent
of
national
mobile
source
CO
emissions.
By
reducing
these
emissions,
the
standards
will
aid
states
facing
ozone
and
CO
air
quality
problems,
which
can
cause
a
range
of
adverse
health
effects,
especially
in
terms
of
respiratory
disease
and
related
illnesses.
The
engine
categories
subject
to
this
rule
contribute
to
regional
haze
and
visibility
impairment
in
Class
I
areas
and
near
where
people
live,
work
and
recreate.
Within
national
parks,
emissions
from
snowmobiles
in
particular
contribute
to
ambient
concentrations
of
fine
PM,
a
leading
cause
of
visibility
impairment.
States
are
required
to
develop
plans
to
address
visibility
impairment
in
national
parks,
and
the
reductions
required
in
this
rule
would
assist
states
in
those
efforts.
The
standards
will
also
help
reduce
acute
exposure
to
CO
and
air
toxics
for
forklift
operators,
equipment
users
or
riders,
national
and
state
park
attendants,
and
other
people
who
may
be
at
particular
risk
because
they
operate
or
work
or
are
otherwise
in
close
proximity
to
this
equipment
due
to
their
occupation
or
as
riders.
Emissions
from
these
vehicles
and
equipment
can
be
very
high
on
a
perengine
basis.
In
addition,
the
equipment
using
these
engines
(
especially
forklifts)
is
often
operated
in
enclosed
areas.
Similarly,
exposure
to
CO
and
air
toxics
can
be
intensified
for
snowmobile
riders
who
follow
a
group
of
other
riders
along
a
trail,
since
those
riders
are
exposed
to
the
emissions
of
all
the
other
snowmobiles
riding
ahead.
When
the
emission
standards
are
fully
implemented
in
2030,
we
expect
a
75
percent
reduction
in
HC
emissions,
82
percent
reduction
in
NOX
emissions,
and
61
percent
reduction
in
CO
emissions,
and
a
60
percent
reduction
in
direct
PM
emissions
from
these
engines,
equipment,
and
vehicles
(
see
Section
IX
below).
These
emission
reductions
will
reduce
ambient
concentrations
of
CO,
ozone,
and
PM
fine;
fine
particles
are
a
public
health
concern
and
contributes
to
visibility
impairment.
The
standards
will
also
reduce
exposure
for
people
who
operate
or
who
work
with
or
are
otherwise
in
close
proximity
to
these
engines
and
vehicles.
We
believe
technology
can
be
applied
to
these
engines
that
will
reduce
emissions
of
these
harmful
pollutants.
Manufacturers
can
reduce
two
stroke
engine
emissions
by
improving
fuel
management
and
calibration.
This
can
be
achieved
by
making
improvements
to
carbureted
fuel
systems
and/
or
converting
to
electronic
and
direct
fuel
injection.
In
addition,
many
of
the
existing
two
stroke
engines
in
these
categories
can
be
converted
to
fourstroke
technology.
Finally,
there
are
modifications
that
can
be
made
to
fourstroke
engines,
often
short
of
requiring
catalysts,
that
can
reduce
emissions
even
further.
1.
Health
and
Welfare
Effects
Exposure
to
CO,
ground
level
ozone,
and
PM
can
cause
serious
respiratory
problems,
including
premature
mortality
and
respiratory
problems.
Fine
PM
has
also
been
associated
with
cardiovascular
problems,
such
as
heart
rate
variability
and
fibrinogen
(
a
blood
clotting
factor)
levels,
and
hospital
admissions
and
mortality
related
to
cardiovascular
diseases.
These
emissions
also
contribute
to
other
serious
environmental
problems,
including
visibility
impairment
and
ecosystem
damage.
In
addition,
some
of
the
HC
pollutants
emitted
by
these
engines
are
air
toxics.
(
The
health
and
welfare
effects
are
described
in
more
detail
in
the
Final
Regulatory
Support
Document.)
CO
enters
the
bloodstream
through
the
lungs
and
reduces
the
delivery
of
oxygen
to
the
body's
organs
and
tissues.
The
health
threat
from
CO
is
most
serious
for
those
who
suffer
from
cardiovascular
disease,
particularly
those
with
angina
or
peripheral
vascular
disease.
Healthy
individuals
also
are
affected,
but
only
at
higher
CO
levels.
Exposure
to
elevated
CO
levels
is
associated
with
impairment
of
visual
perception,
work
capacity,
manual
dexterity,
learning
ability
and
performance
of
complex
tasks.
Exposures
to
ozone
has
been
linked
to
increased
hospital
admissions
and
emergency
room
visits
for
respiratory
problems.
4
Repeated
exposure
to
ozone
can
increase
susceptibility
to
respiratory
infection
and
lung
inflammation.
It
can
aggravate
preexisting
respiratory
diseases,
such
as
asthma.
Prolonged
(
6
to
8
hours),
repeated
exposure
to
ozone
can
cause
inflammation
of
the
lung,
impairment
of
lung
defense
mechanisms,
and
possibly
irreversible
changes
in
lung
structure,
which
over
time
could
lead
to
premature
aging
of
the
lungs
and/
or
chronic
respiratory
illnesses
such
as
emphysema
and
chronic
bronchitis.
Children,
the
elderly,
asthmatics
and
outdoor
workers
are
most
at
risk
from
ozone
exposure.
Evidence
also
exists
of
a
possible
relationship
between
daily
increases
in
ozone
levels
and
increases
in
daily
mortality
levels.
In
addition
to
human
health
effects,
ozone
adversely
affects
crop
yield,
vegetation
and
forest
growth,
and
the
durability
of
materials.
PM,
like
ozone,
has
been
linked
to
a
range
of
serious
respiratory
health
problems.
5
The
key
health
effects
associated
with
ambient
particulate
matter
include
premature
mortality,
aggravation
of
respiratory
and
cardiovascular
disease
(
as
indicated
by
increased
hospital
admissions
and
emergency
room
visits,
school
absences,
work
loss
days,
and
restricted
activity
days),
aggravated
asthma,
acute
respiratory
symptoms,
including
aggravated
coughing
and
difficult
or
painful
breathing,
chronic
bronchitis,
and
decreased
lung
function
that
can
be
experienced
as
shortness
of
breath.
Observable
human
non
cancer
health
effects
associated
with
exposure
to
diesel
PM
include
some
of
the
same
health
effects
reported
for
ambient
PM
such
as
respiratory
symptoms
(
cough,
labored
breathing,
chest
tightness,
wheezing),
and
chronic
respiratory
disease
(
cough,
phlegm,
chronic
bronchitis
and
suggestive
evidence
for
decreases
in
pulmonary
function).
Symptoms
of
immunological
effects
such
as
wheezing
and
increased
allergenicity
are
also
seen.
PM
also
causes
adverse
impacts
to
the
environment.
Fine
PM
is
the
major
cause
of
reduced
visibility
in
parts
of
the
United
States,
including
many
of
our
national
parks
and
in
places
where
people
live
and
work.
Visibility
effects
are
manifest
in
two
principal
ways:
(
1)
as
local
impairment
(
for
example,
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localized
hazes
and
plumes)
and
(
2)
as
regional
haze.
The
emissions
from
engines
covered
by
this
rule
can
contribute
to
both
types
of
visibility
impairment.
The
engines
covered
by
this
rule
also
emit
air
toxics
that
are
known
or
suspected
human
or
animal
carcinogens,
or
have
serious
non
cancer
health
effects.
These
include
benzene,
1,3
butadiene,
formaldehyde,
acetaldehyde,
and
acrolein.
2.
What
Is
the
Inventory
Contribution
From
the
Nonroad
Engines
and
Vehicles
That
Would
Be
Subject
to
This
Rule?
The
contribution
of
emissions
from
the
nonroad
engines
and
vehicles
that
will
be
subject
to
this
final
rule
to
the
national
inventories
of
pollutants
is
considerable.
To
estimate
nonroad
engine
and
vehicle
emission
contributions,
we
used
the
latest
version
of
our
NONROAD
emissions
model,
updated
with
information
received
during
the
public
comment
period.
This
model
computes
nationwide,
state,
and
county
emission
levels
for
a
wide
variety
of
nonroad
engines,
and
uses
information
on
emission
rates,
operating
data,
and
population
to
determine
annual
emission
levels
of
various
pollutants.
A
more
detailed
description
of
the
model
and
our
estimation
methodology
can
be
found
in
the
Chapter
6
of
the
Final
Regulatory
Support
Document.
Baseline
emission
inventory
estimates
for
the
year
2000
for
the
categories
of
engines
and
vehicles
covered
by
this
rule
are
summarized
in
Table
I.
E
1.
This
table
shows
the
relative
contributions
of
the
different
mobile
source
categories
to
the
overall
national
mobile
source
inventory.
Of
the
total
emissions
from
mobile
sources,
the
categories
of
engines
and
vehicles
covered
by
this
rule
contribute
about
9
percent,
3
percent,
4
percent,
and
2
percent
of
HC,
NOX,
CO,
and
PM
emissions,
respectively,
in
the
year
2000.
The
results
for
Large
SI
engines
indicate
they
contribute
approximately
2
to
3
percent
to
HC,
NOX,
and
CO
emissions
from
mobile
sources.
The
results
for
land
based
recreational
engines
reflect
the
impact
of
the
significantly
different
emissions
characteristics
of
two
stroke
engines.
These
engines
are
estimated
to
contribute
about
6
percent
of
HC
emissions
and
2
percent
of
CO
from
mobile
sources.
Recreational
marine
diesel
engines
contribute
less
than
1
percent
to
NOX
mobile
source
inventories.
When
only
nonroad
emissions
are
considered,
the
engines
and
vehicles
that
will
be
subject
to
the
standards
account
for
a
larger
share.
Our
draft
emission
projections
for
2020
and
2030
for
the
nonroad
engines
and
vehicles
subject
to
this
rule
show
that
emissions
from
these
categories
are
expected
to
increase
over
time
if
left
uncontrolled.
The
projections
for
2020
and
2030
are
summarized
in
Tables
I.
E
2
and
I.
E
3,
respectively.
The
projections
for
2020
and
2030
indicate
that
the
categories
of
engines
and
vehicles
covered
by
this
rule
are
expected
to
contribute
approximately
25
percent,
10
percent,
5
percent,
and
5
percent
of
mobile
source
HC,
NOX,
CO,
and
PM
emissions,
respectively,
if
left
uncontrolled.
Engine
population
growth
and
the
effects
of
other
regulatory
control
programs
are
factored
into
these
projections.
The
relative
importance
of
uncontrolled
nonroad
engines
in
2020
and
2030
is
higher
than
the
projections
for
2000
because
there
are
already
emission
control
programs
in
place
for
the
other
categories
of
mobile
sources
which
are
expected
to
reduce
their
emission
levels.
The
effectiveness
of
all
control
programs
is
offset
by
the
anticipated
growth
in
engine
populations.
Regarding
PM
specifically,
this
information
and
information
in
Section
I.
3(
ii)
below
show
that
the
engines
being
regulated
in
this
rule,
snowmobiles
and
other
recreational
vehicles
in
particular,
contribute
to
PM
concentrations
that
may
reasonably
be
anticipated
to
endanger
public
health
and
welfare
both
because
of
the
health
effects
associated
with
PM
and
because
of
the
effects
on
visibility
discussed
below.
TABLE
I.
E
1.
MODELED
ANNUAL
EMISSION
LEVELS
FOR
MOBILE
SOURCE
CATEGORIES
IN
2000
[
Thousand
short
tons]
Category
NOX
HC
CO
PM
1000
tons
Percent
of
mobile
source
1000
tons
Percent
of
mobile
source
1000
tons
Percent
of
mobile
source
1000
tons
Percent
of
mobile
source
Total
for
engines
subject
to
this
final
rule
*
......
351
2.6
645
8.8
2,860
3.8
14.6
2.1
Highway
Motorcycles
.......................................
8
0.1
84
1.2
331
0.4
0.4
0.1
Nonroad
Industrial
SI
>
19
kW*
........................
308
2.3
226
3.1
1,734
2.3
1.6
0.2
Recreational
SI*
...............................................
5
0.0
418
5.7
1,120
1.5
12.0
1.7
Recreational
Marine
Diesel*
............................
38
0.3
1
0.0
6
0.0
1
0.1
Marine
SI
Evap
................................................
0
0.0
100
1.4
0
0.0
0
0.0
Marine
SI
Exhaust
...........................................
32
0.2
708
9.7
2,144
2.8
38
5.4
Nonroad
SI
<
19
kW
.........................................
106
0.8
1,460
20.0
18,359
24.3
50
7.1
Nonroad
diesel
.................................................
2,625
19.5
316
4.3
1,217
1.6
253
35.9
Commercial
Marine
Diesel
...............................
963
7.2
30
0.4
127
0.2
41
5.8
Locomotive
.......................................................
1,192
8.9
47
0.6
119
0.2
30
4.3
Total
Nonroad
..................................................
5,269
39
3,305
45
24,826
33
427
60
Total
Highway
..................................................
7,981
59
3,811
52
49,813
66
240
34
Aircraft
..............................................................
178
1
183
3
1,017
1
39
6
Total
Mobile
Sources
.......................................
13,428
100
7,300
100
75,656
100
706
100
Total
Man
Made
Sources
................................
24,532
................
18,246
................
97,735
................
3,102
................
Mobile
Source
percent
of
Total
Man
Made
Sources
........................................................
55
................
40
................
77
................
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2002
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Rules
and
Regulations
TABLE
I.
E
2.
MODELED
ANNUAL
BASELINE
EMISSION
LEVELS
FOR
MOBILE
SOURCE
CATEGORIES
IN
2020
[
thousand
short
tons]
Category
NOX
HC
CO
PM
1000
tons
Percent
of
mobile
source
1000
tons
Percent
of
mobile
source
1000
tons
Percent
of
mobile
source
1000
tons
Percent
of
mobile
source
Total
for
engines
subject
to
this
final
rule*
......
547
8.8
1,305
24.1
4,866
5.6
34.1
5.2
Highway
Motorcycles
.......................................
14
0.2
142
2.6
572
0.7
0.8
0.1
Nonroad
Industrial
SI
>
19
kW*
.......................
472
7.6
318
5.9
2,336
2.7
2.3
0.4
Recreational
SI*
...............................................
14
0.2
985
18.2
2,521
2.9
30.2
4.6
Recreational
Marine
Diesel*
............................
61
1.0
2
0.0
9
0.0
1.6
0.2
Marine
SI
Evap
................................................
0
0.0
114
2.1
0
0.0
0
0.0
Marine
SI
Exhaust
...........................................
58
0.9
284
5.2
1,985
2.3
28
4.3
Nonroad
SI
<
19
Kw
........................................
106
1.7
986
18.2
27,352
31.7
77
11.8
Nonroad
Diesel
................................................
1,791
28.8
142
2.6
1,462
1.7
261
40.0
Commercial
Marine
Diesel
...............................
819
13.2
35
0.6
160
0.2
46
7.0
Locomotive
.......................................................
611
9.8
35
0.6
119
0.1
21
3.2
Total
Nonroad
..................................................
3,932
63
2,901
54
35,944
42
467
71
Total
Highway
..................................................
2,050
33
2,276
42
48,906
56
145
22
Aircraft
..............................................................
232
4
238
4
1,387
2
43
7
Total
Mobile
Sources
.......................................
6,214
100
5,415
100
86,237
100
655
100
Total
Man
Made
Sources
................................
16,190
................
15,475
................
109,905
................
3,039
................
Mobile
Source
percent
of
Total
Man
Made
Sources
........................................................
38
................
35
................
79
................
22
................
TABLE
I.
E
3.
MODELED
ANNUAL
EMISSION
LEVELS
FOR
MOBILE
SOURCE
CATEGORIES
IN
2030
[
Thousand
short
tons]
Category
NOX
HC
CO
PM
1000
tons
Percent
of
mobile
source
1000
tons
Percent
of
mobile
source
1000
tons
Percent
of
mobile
source
1000
tons
Percent
of
mobile
source
Total
for
engines
subject
to
this
final
rule*
......
640
10.0
1,411
23.5
5,363
5.4
36.5
4.8
Highway
Motorcycles
.......................................
17
0.3
172
2.9
693
0.7
1.0
0.1
Nonroad
Industrial
SI
>
19
kW*
.......................
553
8.6
371
6.2
2,703
2.7
2.7
0.4
Recreational
SI*
...............................................
15
0.2
1,038
17.3
2,649
2.7
31.9
4.2
Recreational
Marine
Diesel*
............................
72
1.1
2
0.0
11
0.0
1.9
0.3
Marine
SI
Evap
................................................
0
0.0
122
2.0
0
0.0
0
0.0
Marine
SI
Exhaust
...........................................
64
1.0
269
4.5
2,083
2.1
29
3.8
Nonroad
SI
<
19
kW
........................................
126
2.0
1,200
20.0
32,310
32.4
93
12.3
Nonroad
Diesel
................................................
1,994
31.0
158
2.6
1,727
1.7
306
40.4
Commercial
Marine
Diesel
...............................
1,166
18.1
52
0.9
198
0.2
74
9.8
Locomotive
.......................................................
531
8.3
30
0.5
119
0.1
18
2.4
Total
Nonroad
..................................................
4,521
70
3,242
54
41,800
42
557
74
Total
Highway
..................................................
1,648
26
2,496
42
56,303
56
158
21
Aircraft
..............................................................
262
4
262
4
1,502
2
43
6
Total
Mobile
Sources
.......................................
6,431
100
6,000
100
99,605
100
758
100
Total
Man
Made
Sources
................................
16,639
17,020
123,983
3,319
Mobile
Source
percent
of
Total
Man
Made
Sources
........................................................
39
35
80
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Regulations
6
Likewise,
Large
SI
equipment
and
recreational
marine
diesel
engines
also
contribute
to
CO
in
nonattainment
areas.
7
There
are
important
reasons
to
focus
on
redesignation
status,
as
compared
to
just
current
air
quality.
Areas
with
a
few
years
of
attainment
data
can
and
often
do
have
exceedances
following
such
years
of
attainment
because
of
several
factors
including
different
climatic
events
during
the
later
years,
increases
in
inventories,
etc.
Control
of
emissions
from
nonroad
engines
can
help
to
avoid
potential
future
air
quality
problems.
8
Draft
Anchorage
Carbon
Monoxide
Emission
Inventory
and
Year
2000
Attainment
Projections,
Air
Quality
Program,
May
2001,
Docket
Number
A
2000
01,
Document
II
A
40;
Draft
Fairbanks
1995
2001
Carbon
Monoxide
Emissions
Inventory,
June
1,
2001,
Docket
Number
A
2000
01,
Document
II
A
39.
9
National
Research
Council.
The
Ongoing
Challenge
of
Managing
Carbon
Monoxide
Pollution
in
Fairbanks,
AK.
May
2002.
Docket
A
2000
01,
Document
No.
IV
A
115.
10
National
Research
Council.
The
Ongoing
Challenge
of
Managing
Carbon
Monoxide
Pollution
in
Fairbanks,
AK.
May
2002.
Docket
A
2000
01,
Document
IV
A
115.
3.
Why
are
Controls
to
Protect
against
CO
Nonattainment
and
to
Protect
Visibility
Needed
From
the
Nonroad
Engines
and
Vehicles
That
Would
Be
Subject
to
This
Rule?
i.
Why
are
We
Controlling
CO
Emissions
from
Nonroad
Engines
and
Vehicles
that
Would
be
Subject
to
this
Rule?
Engines
subject
to
this
rule
contributed
about
3.8
percent
of
CO
from
mobile
sources
in
2000.
Over
22.4
million
people
currently
live
in
the
13
nonattainment
areas
for
the
CO
National
Ambient
Air
Quality
Standard
(
NAAQS).
Industry
association
comments
questioned
the
need
for
CO
control
and
snowmobile
contribution,
in
particular.
First,
the
statute
envisions
that
categories
should
be
considered
in
determining
contribution
because
otherwise,
it
would
be
possible
to
continue
to
arbitrarily
divide
subcategories
until
the
contribution
from
any
subcategory
becomes
minimal
while
the
cumulative
effect
of
the
air
pollution
remains.
EPA
previously
determined
that
the
category
of
Large
SI
engines
and
recreational
vehicles
cause
or
contribute
to
ambient
CO
and
ozone
in
more
than
one
nonattainment
area
(
65
FR
76790,
December
7,
2000).
EPA
also
examined
recreational
vehicles
separately
and
found
that
recreational
vehicles
subject
to
this
rule
contribute
to
CO
nonattainment
in
areas
such
as
Los
Angeles,
Phoenix,
Anchorage,
and
Las
Vegas
(
see
RSD
chapter
2).
Thus,
if
considered
as
a
category,
recreational
vehicles
contribute
to
CO
nonattainment.
6
Moreover,
when
we
examined
snowmobiles
separately,
they
met
the
contribution
criteria.
The
International
Snowmobile
Manufacturers
Association
(
ISMA)
stated
in
its
public
comments
that
snowmobiles
in
particular
are
not
operated
in
many
of
the
CO
nonattainment
areas
because
of
lack
of
snow
(
although
they
may
be
stored
in
those
areas).
The
commenters
also
contended
that
northern
areas
have
experienced
improved
CO
air
quality.
Many
areas
are
making
progress
in
improving
their
air
quality.
However,
an
area
cannot
be
redesignated
to
attainment
until
it
can
show
EPA
that
it
has
had
air
quality
levels
within
the
level
required
for
attainment
and
that
it
has
a
plan
in
place
to
maintain
such
levels.
Until
areas
have
been
redesignated,
they
remain
nonattainment
areas.
7
Snowmobiles
contribute
to
CO
nonattainment
in
more
than
one
of
these
areas.
Snowmobiles
have
relatively
high
per
engine
CO
emissions,
and
they
can
be
a
significant
source
of
ambient
CO
levels
in
CO
nonattainment
areas.
Despite
the
fact
that
snowmobiles
are
largely
banned
in
CO
nonattainment
areas
by
the
state
of
Alaska,
the
state
estimated
(
and
a
National
Research
Council
study
confirmed)
that
snowmobiles
contributed
0.3
tons/
day
in
2001
to
Fairbanks'
CO
nonattainment
area
or
1.2
percent
of
a
total
inventory
of
23.3
tons
per
day
in
2001.8,9
While
Fairbanks
has
made
significant
progress
in
reducing
ambient
CO
concentrations,
existing
climate
conditions
make
achieving
and
maintaining
attainment
challenging.
Anchorage,
AK,
reports
a
similar
contribution
of
snowmobiles
to
their
emissions
inventories
(
0.34
tons
per
day
in
2000).
Furthermore,
a
recent
National
Academy
of
Sciences
report
concludes
that
``
Fairbanks
will
be
susceptible
to
violating
the
CO
health
standards
for
many
years
because
of
its
severe
meteorological
conditions.
That
point
is
underscored
by
a
December
2001
exceedance
of
the
standard
in
Anchorage
which
had
no
violations
over
the
last
3
years.''
10
ISMA
commented
that
it
agreed
with
EPA
that
there
is
a
snowmobile
trail
within
the
Spokane,
WA,
CO
nonattainment
area,
although
they
noted
that
snowmobile
operation
alone
would
not
result
in
CO
nonattainment.
However,
emissions
from
regulated
categories
need
only
contribute
to,
not
themselves
cause,
nonattainment.
Concentrations
of
NAAQS
related
pollutants
are
by
definition
a
result
of
multiple
sources
of
pollution.
Several
states
that
contain
CO
nonattainment
areas
also
have
large
populations
of
registered
snowmobiles
and
nearby
snowmobile
trails
in
adjoining
counties,
which
are
an
indication
of
where
they
are
operated
(
see
Table
I.
E
4).
EPA
requested
comment
on
the
volume
and
nature
of
snowmobile
use
in
these
and
other
CO
nonattainment
areas.
ISMA
commented
on
the
proximity
of
trails
to
northern
CO
nonattainment
areas,
assuming
that
snowmobiles
are
operated
only
on
trails.
A
search
of
the
available
literature
indicates
that
snowmobiles
are
ridden
in
areas
other
than
trails.
For
example,
a
1998
report
by
the
Michigan
Department
of
Natural
Resources
indicates
that
from
1993
to
1997,
of
the
146
snowmobile
fatalities
studied,
46
percent
occurred
on
a
state
or
county
roadway
(
another
2
percent
on
roadway
shoulders)
and
27
percent
occurred
on
private
lands.
Furthermore,
accident
reports
in
CO
nonattainment
area
Fairbanks,
AK,
demonstrate
that
snowmobiles
driven
on
streets
have
collided
with
motor
vehicles.
On
certain
days
there
may
be
concentrations
of
snowmobiles
operated
in
nonattainment
areas
due
to
public
events
such
as
snowmachine
races
(
such
as
the
Iron
Dog
Gold
Rush
Classic,
which
finishes
in
Fairbanks,
AK),
during
which
snowmobiles
will
be
present
and
operated.
TABLE
I.
E
4.
SNOWMOBILE
USE
IN
SELECTED
CO
NONATTAINMENT
AREAS
City
and
state
CO
nonattainment
classification
2001
State
snowmobile
populationa
Anchorage,
AK
Fairbanks,
AK
...........................................................................................
Serious
...................................................................
b
35576
Spokane,
WA
............................................................................................
Serious
...................................................................
31532
Fort
Collins,
CO
........................................................................................
Moderate
................................................................
32500
Medford,
OR
.............................................................................................
Moderate
................................................................
16809
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/
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67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
11
Technical
Memorandum
to
Docket
A
2000
01
from
Drew
Kodjak,
Attorney
Advisor,
Office
of
Transportation
and
Air
Quality,
``
Air
Quality
Information
for
Selected
CO
Nonattainment
Areas,''
July
27,
2001,
Docket
Number
A
2000
01,
Document
Number
II
B
18.
12
Air
Quality
Criteria
for
Carbon
Monoxide,
U.
S.
EPA,
EPA
600/
P
99/
001F,
June
2000,
at
3
38,
Figure
3
32
(
Federal
Bldg,
AIRS
Site
020900002).
Air
Docket
A
2000
01,
Document
Number
II
A
29.
This
document
is
also
available
at
http://
www.
epa.
gov/
ncea/
coabstract.
htm.
13
National
Research
Council,
1993.
Protecting
Visibility
in
National
Parks
and
Wilderness
Areas.
National
Academy
of
Sciences
Committee
on
Haze
in
National
Parks
and
Wilderness
Areas.
National
Academy
Press,
Washington,
DC.
This
document
is
available
on
the
internet
at
http://
www.
nap.
edu/
books/
0309048443/
html/.
See
also
U.
S.
EPA
Air
Quality
Criteria
Document
for
Particulate
Matter
(
1996)
and
Review
of
the
National
Ambient
Air
Quality
Standards
for
Particulate
Matter:
Policy
Assessment
of
Scientific
and
Technical
Information.
These
documents
can
be
found
in
Docket
A
99
06,
Documents
No.
II
A
23
and
IV
A
130
32.
14
Visual
range
can
be
defined
as
the
maximum
distance
at
which
one
can
identify
a
black
object
against
the
horizon
sky.
It
is
typically
described
in
miles
or
kilometers.
Light
extinction
is
the
sum
of
light
scattering
and
absorption
by
particles
and
gases
in
the
atmosphere.
It
is
typically
expressed
in
terms
of
inverse
megameters
(
Mm
1),
with
larger
values
representing
worse
visibility.
The
deciview
metric
describes
perceived
visual
changes
in
a
linear
fashion
over
its
entire
range,
analogous
to
the
decibel
scale
for
sound.
A
deciview
of
0
represents
pristine
conditions.
Under
many
scenic
conditions,
a
change
of
1
deciview
is
considered
perceptible
by
the
average
person.
TABLE
I.
E
4.
SNOWMOBILE
USE
IN
SELECTED
CO
NONATTAINMENT
AREAS
Continued
City
and
state
CO
nonattainment
classification
2001
State
snowmobile
populationa
Missoula,
MT
............................................................................................
Moderate
................................................................
23440
a
Source:
ISMA
U.
S.
Snowmobile
Registration
History,
May
15,
2001;
various
studies
prepared
for
state
snowmobile
associations
included
in
Docket
A
2000
01.
b
Point
of
sale
registration
was
not
mandatory
in
Alaska
prior
to
1998,
so
the
statewide
registered
population
is
likely
to
underestimate
the
total
population.
Exceedances
of
the
8
hour
CO
standard
were
recorded
in
three
of
seven
CO
nonattainment
areas
located
in
the
northern
portion
of
the
country
over
the
five
year
period
from
1994
to
1999:
Fairbanks,
AK;
Medford,
OR;
and
Spokane,
WA.
11
Given
the
variability
in
CO
ambient
concentrations
due
to
weather
patterns
such
as
inversions,
the
absence
of
recent
exceedances
for
some
of
these
nonattainment
areas
should
not
be
viewed
as
eliminating
the
need
for
further
reductions
to
consistently
attain
and
maintain
the
standard.
A
review
of
CO
monitor
data
in
Fairbanks
from
1986
to
1995
shows
that
while
median
concentrations
have
declined
steadily,
unusual
combinations
of
weather
and
emissions
have
resulted
in
elevated
ambient
CO
concentrations
well
above
the
8
hour
standard
of
9
ppm.
Specifically,
a
Fairbanks
monitor
recorded
average
8
hour
ambient
concentrations
at
16
ppm
in
1988,
around
9
ppm
from
1990
to
1992,
and
then
a
steady
increase
in
CO
ambient
concentrations
at
12,
14
and
16
ppm
during
some
extreme
cases
in
1993,
1994
and
1995,
respectively.
12
In
addition,
there
are
6
areas
that
have
not
been
classified
as
nonattainment
where
air
quality
monitoring
indicated
a
need
for
CO
control.
For
example,
CO
monitors
in
northern
locations
such
as
Des
Moines,
IA,
and
Weirton,
WV/
Steubenville,
OH,
registered
levels
above
the
level
of
the
CO
standards
in
1998.
ii.
Why
are
Controls
Needed
From
the
Nonroad
Engines
and
Vehicles
That
Would
Be
Subject
to
this
Rule
to
Protect
Visibility?
(
1)
Visibility
is
Impaired
by
Fine
PM
and
Precursor
Emissions
From
Nonroad
Engines
and
Vehicles
That
Would
Be
Subject
to
This
Rule.
Visibility
can
be
defined
as
the
degree
to
which
the
atmosphere
is
transparent
to
visible
light.
13
Visibility
degradation
is
an
easily
noticeable
effect
of
fine
PM
present
in
the
atmosphere,
and
fine
PM
is
the
major
cause
of
reduced
visibility
in
parts
of
the
United
States,
including
many
of
our
national
parks
and
in
places
across
the
country
where
people
live,
work,
and
recreate.
Fine
particles
with
significant
light
extinction
efficiencies
include
organic
matter,
sulfates,
nitrates,
elemental
carbon
(
soot),
and
soil.
Visibility
is
an
important
effect
because
it
has
direct
significance
to
people's
enjoyment
of
daily
activities
in
all
parts
of
the
country.
Individuals
value
good
visibility
for
the
well
being
it
provides
them
directly,
both
in
where
they
live
and
work,
and
in
places
where
they
enjoy
recreational
opportunities.
Visibility
is
highly
valued
in
significant
natural
areas
such
as
national
parks
and
wilderness
areas,
because
of
the
special
emphasis
given
to
protecting
these
lands
now
and
for
future
generations.
To
quantify
changes
in
visibility,
we
compute
a
light
extinction
coefficient,
which
shows
the
total
fraction
of
light
that
is
decreased
per
unit
distance.
Visibility
can
be
described
in
terms
of
PM
concentrations,
visual
range,
light
extinction
or
deciview.
14
In
addition
to
limiting
the
distance
that
one
can
see,
the
scattering
and
absorption
of
light
caused
by
air
pollution
can
also
degrade
the
color,
clarity,
and
contrast
of
scenes.
Visibility
effects
are
manifest
in
two
main
ways:
as
local
impairment
(
for
example,
localized
hazes
and
plumes)
and
as
regional
haze.
In
addition,
visibility
impairment
has
a
time
dimension
in
that
it
might
relate
to
a
short
term
excursion
or
to
longer
periods
(
for
example,
worst
20
percent
of
days
or
annual
average
levels).
Local
scale
visibility
degradation
is
commonly
seen
as
a
plume
resulting
from
the
emissions
of
a
specific
source
or
small
group
of
sources,
or
it
is
in
the
form
of
a
localized
haze
such
as
an
urban
``
brown
cloud.''
Plumes
are
comprised
of
smoke,
dust,
or
colored
gas
that
obscure
the
sky
or
horizon
relatively
near
sources.
Impairment
caused
by
a
specific
source
or
small
group
of
sources
has
been
generally
termed
as
``
reasonably
attributable.''
The
second
type
of
impairment,
regional
haze,
results
from
pollutant
emissions
from
a
multitude
of
sources
located
across
a
broad
geographic
region.
It
impairs
visibility
in
every
direction
over
a
large
area,
in
some
cases
over
multi
state
regions.
Regional
haze
masks
objects
on
the
horizon
and
reduces
the
contrast
of
nearby
objects.
The
formation,
extent,
and
intensity
of
regional
haze
is
a
function
of
meteorological
and
chemical
processes,
which
sometimes
cause
fine
particulate
loadings
to
remain
suspended
in
the
atmosphere
for
several
days
and
to
be
transported
hundreds
of
kilometers
from
their
sources.
On
an
annual
average
basis,
the
concentrations
of
non
anthropogenic
fine
PM
are
generally
small
when
compared
with
concentrations
of
fine
particles
from
anthropogenic
sources.
Anthropogenic
contributions
account
for
about
one
third
of
the
average
extinction
coefficient
in
the
rural
West
and
more
than
80
percent
in
the
rural
East.
Because
of
significant
differences
related
to
visibility
conditions
in
the
eastern
and
western
U.
S.,
we
present
information
about
visibility
by
region.
Furthermore,
it
is
important
to
note
that
even
in
those
areas
with
relatively
low
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/
Vol.
67,
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217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
15
Memorandum
to
Docket
A
99
06
from
Eric
O.
Ginsburg,
Senior
Program
Advisor,
``
Summary
of
1999
Ambient
Concentrations
of
Fine
Particulate
Matter,''
November
15,
2000.
Air
Docket
A
2000
01,
Document
No.
II
B
12.
16
These
populations
would
obviously
also
be
exposed
to
PM
concentrations
associated
with
the
adverse
health
impacts
related
to
PM2.5.
17
Additional
information
about
the
Regulatory
Model
System
for
Aerosols
and
Deposition
(
REMSAD)
and
our
modeling
protocols
can
be
found
in
our
Regulatory
Impact
Analysis:
Heavy
Duty
Engine
and
Vehicle
Standards
and
Highway
Diesel
Fuel
Sulfur
Control
Requirements,
document
EPA420
R
00
026,
December
2000.
Docket
No.
A
2000
01,
Document
No.
A
II
13.
This
document
is
also
available
at
http://
www.
epa.
gov/
otaq/
disel.
htm#
documents.
18
Technical
Memorandum,
EPA
Air
Docket
A
99
06,
Eric
O.
Ginsburg,
Senior
Program
Advisor,
Emissions
Monitoring
and
Analysis
Division,
OAQPS,
Summary
of
Absolute
Modeled
and
Model
Adjusted
Estimates
of
Fine
Particulate
Matter
for
Selected
Years,
December
6,
2000,
Table
P
2.
Docket
Number
2000
01,
Document
Number
II
B
14.
concentrations
of
anthropogenic
fine
particles,
such
as
the
Colorado
plateau,
small
increases
in
anthropogenic
fine
particle
concentrations
can
lead
to
significant
decreases
in
visual
range.
This
is
one
of
the
reasons
Class
I
areas
have
been
given
special
consideration
under
the
Clean
Air
Act.
Nonroad
engines
that
are
subject
to
this
final
rule
contribute
to
ambient
fine
PM
levels
in
two
ways.
First,
they
contribute
through
direct
emissions
of
fine
PM.
As
shown
in
Table
I.
E
1,
these
engines
emitted
14,600
tons
of
PM
(
over
2
percent
of
all
mobile
source
PM)
in
2000.
Second,
these
engines
contribute
to
indirect
formation
of
PM
through
their
emissions
of
gaseous
precursors
which
are
then
transformed
in
the
atmosphere
into
particles.
For
example,
these
engines
emitted
over
8
percent
of
the
HC
tons
from
mobile
sources.
Furthermore,
recreational
vehicles,
such
as
snowmobiles
and
all
terrain
vehicles
emit
high
levels
of
organic
carbon
(
as
HC)
on
a
per
engine
basis.
Some
organic
emissions
are
transformed
into
particles
in
the
atmosphere
and
other
volatile
organics
can
condense
if
emitted
in
cold
temperatures,
as
is
the
case
for
emissions
from
snowmobiles,
for
example.
Organic
carbon
accounts
for
between
27
and
36
percent
of
ambient
fine
particle
mass
depending
on
the
area
of
the
country.
(
A)
Visibility
Impairment
Where
People
Live,
Work
and
Recreate
The
secondary
PM
NAAQS
is
designed
to
protect
against
adverse
welfare
effects
such
as
visibility
impairment.
In
1997,
the
secondary
PM
NAAQS
was
set
as
equal
to
the
primary
(
health
based)
PM
NAAQS
(
62
Federal
Register
No.
138,
July
18,
1997).
EPA
concluded
that
PM
can
and
does
produce
adverse
effects
on
visibility
in
various
locations,
depending
on
PM
concentrations
and
factors
such
as
chemical
composition
and
average
relative
humidity.
In
1997,
EPA
demonstrated
that
visibility
impairment
is
an
important
effect
on
public
welfare
and
that
visibility
impairment
is
experienced
throughout
the
U.
S.,
in
multi
state
regions,
urban
areas,
and
remote
Federal
Class
I
areas.
In
many
cities
having
annual
mean
PM2.5
concentrations
exceeding
17
µ
g/
m3,
improvements
in
annual
average
visibility
resulting
from
the
attainment
of
the
annual
PM2.5
standard
are
expected
to
be
perceptible
to
the
general
population
(
e.
g.,
to
exceed
1
deciview).
Based
on
annual
mean
monitored
PM2.5
data,
many
cities
in
the
Northeast,
Midwest,
and
Southeast
as
well
as
Los
Angeles
would
be
expected
to
experience
perceptible
improvements
in
visibility
if
the
PM2.5
annual
standard
were
attained.
For
example,
in
Washington,
DC,
where
the
IMPROVE
monitoring
network
shows
annual
mean
PM2.5
concentrations
at
about
19
µ
g/
m3
during
the
period
of
1992
to
1995,
approximate
annual
average
visibility
would
be
expected
to
improve
from
21
km
(
29
deciview)
to
27
km
(
27
deciview),
a
change
of
2
deciviews.
The
PM2.5
annual
average
in
Washington,
DC,
was
18.9
µ
g/
m3
in
2000.
The
updated
monitored
data
and
air
quality
modeling
presented
in
the
RSD
confirm
that
the
visibility
situation
identified
during
the
NAAQS
review
in
1997
is
still
likely
to
exist.
Thus,
the
determination
in
the
NAAQS
rulemaking
about
broad
visibility
impairment
and
related
benefits
from
NAAQS
compliance
are
still
relevant.
Levels
above
the
fine
PM
NAAQS
cause
adverse
welfare
impacts,
such
as
visibility
impairment
(
both
regional
and
localized
impairment).
Furthermore,
in
setting
the
PM
NAAQS,
EPA
acknowledged
that
levels
of
fine
particles
below
the
NAAQS
may
also
contribute
to
unacceptable
visibility
impairment
and
regional
haze
problems
in
some
areas,
and
Clean
Air
Act
Section
169
provides
additional
authorities
to
remedy
existing
impairment
and
prevent
future
impairment
in
the
156
national
parks,
forests
and
wilderness
areas
labeled
as
Class
I
areas.
In
making
determinations
about
the
level
of
protection
afforded
by
the
secondary
PM
NAAQS,
EPA
considered
how
the
Section
169
regional
haze
program
and
the
secondary
NAAQS
would
function
together.
Regional
strategies
are
expected
to
improve
visibility
in
many
urban
and
non
Class
I
areas
as
well.
The
following
recommendation
for
the
National
Research
Council,
Protecting
Visibility
in
National
Parks
and
Wilderness
Areas
(
1993),
addresses
this
point:
Efforts
to
improve
visibility
in
Class
I
areas
also
would
benefit
visibility
outside
these
areas.
Because
most
visibility
impairment
is
regional
in
scale,
the
same
haze
that
degrades
visibility
within
or
looking
out
from
a
national
park
also
degrade
visibility
outside
it.
The
1999
2000
PM2.5
monitored
values,
which
cover
about
a
third
of
the
nation's
counties,
indicate
that
at
least
82
million
people
live
in
areas
where
long
term
ambient
fine
particulate
matter
levels
are
at
or
above
15
µ
g/
m3.15
Thus,
these
populations
(
plus
those
who
travel
to
those
areas)
could
be
experiencing
visibility
impairment
that
is
unacceptable,
and
emissions
of
PM
and
its
precursors
from
engines
in
these
categories
contribute
to
this
unacceptable
impairment.
16
Because
the
chemical
composition
of
the
PM
affects
visibility
impairment,
we
used
EPA's
Regulatory
Model
System
for
Aerosols
and
Deposition
(
REMSAD)
17
model
to
project
visibility
conditions
in
2030
accounting
for
the
chemical
composition
of
the
particles
and
to
estimate
visibility
impairment
directly
as
changes
in
deciview.
Our
projections
included
anticipated
emissions
from
the
engines
subject
to
this
rule,
and
although
our
emission
predictions
reflected
our
best
estimates
of
emissions
projections
at
the
time
the
modeling
was
conducted,
we
now
have
new
estimates,
as
discussed
in
the
RSD
Chapter
1.
Based
on
public
comment
for
this
rule
and
new
information,
we
have
revised
our
emissions
estimates
in
some
categories
downwards
and
other
categories
upwards;
however,
on
net,
we
believe
the
modeling
underestimates
the
PM
air
quality
levels
that
would
have
been
predicted
if
new
inventories
were
used.
The
most
reliable
information
about
the
future
visibility
levels
would
be
in
areas
for
which
monitoring
data
are
available
to
evaluate
model
performance
for
a
base
year
(
e.
g.,
1996).
Accordingly,
we
predicted
that
in
2030,
49
percent
of
the
population
will
be
living
in
areas
where
fine
PM
levels
are
above
15
µ
g/
m3
and
monitors
are
available.
18
This
can
be
compared
with
the
1996
level
of
37
percent
of
the
population
living
in
areas
where
fine
PM
levels
are
above
15
µ
g/
m3
and
monitors
are
available.
Thus,
a
substantial
percent
of
the
population
would
experience
unacceptable
visibility
impairment
in
areas
where
they
live,
work
and
recreate.
As
shown
in
Table
I.
E
5,
in
2030,
we
expect
visibility
in
the
East
to
be
about
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19
Memo
to
file
from
Terence
Fitz
Simons,
OAQPS,
Scott
Mathias,
OAQPS,
Mike
Rizzo,
Region
5,
``
Analyses
of
1999
PM
Data
for
the
PM
NAAQS
Review,''
November
17,
2000,
with
attachment
B,
1999
PM2.5
Annual
Mean
and
98th
Percentile
24
Hour
Average
Concentrations.
Docket
No.
A
2000
01,
Document
No.
II
B
17.
20
This
information
also
shows
that
snowmobiles
contribute
to
concentrations
of
fine
PM
that
are
above
the
primary
health
related
NAAQS,
which
indicates
that
emissions
from
snowmobiles
also
contribute
to
primary
and
secondary
PM
pollution
that
may
reasonably
be
anticipated
to
endanger
public
health
and
welfare.
21
Review
of
the
National
Ambient
Air
Quality
Standards
for
Particulate
Matter:
Policy
Assessment
for
Scientific
and
Technical
Information,
OAQPS
Staff
Paper,
EPA
452\
R
96
013,
July,
1996,
at
IV
7.
This
document
is
available
from
Docket
A
99
06,
Document
II
A
23.
19
deciviews
(
or
visual
range
of
60
kilometers)
on
average,
with
poorer
visibility
in
urban
areas,
compared
to
the
visibility
conditions
without
manmade
pollution
of
9.5
deciviews
(
or
visual
range
of
150
kilometers).
Likewise,
we
expect
visibility
in
the
West
to
be
about
9.5
deciviews
(
or
visual
range
of
150
kilometers)
in
2030,
compared
to
the
visibility
conditions
without
man
made
pollution
of
5.3
deciviews
(
or
visual
range
of
230
kilometers).
Nonroad
engines
contribute
significantly
to
these
effects.
As
shown
in
Tables
I.
E
1
through
I.
E
3,
nonroad
engines
emissions
contribute
a
large
portion
of
the
total
PM
emissions
from
mobile
sources
and
anthropogenic
sources,
in
general.
These
emissions
occur
in
and
around
areas
with
PM
levels
above
the
annual
PM2.5
NAAQS.
The
engines
subject
to
the
final
rule
will
contribute
to
these
effects.
They
are
estimated
to
emit
36,500
tons
of
direct
PM
in
2030,
which
is
1.1
percent
of
the
total
anthropogenic
PM
emissions
in
2030.
Similarly,
for
PM
precursors,
the
engines
subject
to
this
rule
will
emit
640,000
tons
of
NOX
and
1,411,000
tons
HC
in
2030,
which
are
3.8
and
8.3
percent
of
the
total
anthropogenic
NOX
and
HC
emissions,
respectively,
in
2030.
Recreational
vehicles
in
particular
contribute
to
these
levels.
In
Table
I.
E
1
through
I.
E
3,
we
show
that
recreational
vehicles
emitted
about
1.7
percent
of
mobile
source
PM
emissions
in
2000.
Similarly,
recreational
vehicles
are
modeled
to
emit
over
4
percent
of
mobile
source
PM
in
2020
and
2030.
Thus,
the
emissions
from
these
sources
contribute
to
the
visibility
impairment
modeled
for
2030
summarized
in
the
table.
Furthermore,
for
20
counties
across
nine
states,
snowmobile
trails
are
found
within
or
near
counties
that
registered
ambient
PM2.5
concentrations
at
or
above
15
µ
g/
m3,
the
level
of
the
PM2.5
NAAQS.
19
Fine
particles
may
remain
suspended
for
days
or
weeks
and
travel
hundreds
to
thousands
of
kilometers,
and
thus
fine
particles
emitted
or
created
in
one
county
may
contribute
to
ambient
concentrations
in
a
neighboring
county.
20,
21
TABLE
I.
E
5
SUMMARY
OF
2030
NATIONAL
VISIBILITY
CONDITIONS
BASED
ON
REMSAD
MODELING
[
Deciviews]
Regions
a
Predicted
2030
visibility
b
(
annual
average
Natural
background
visibility
Eastern
U.
S.
.......
18.98
9.5
Urban
20.48
Rural
..
18.38
Western
U.
S.
.......
9.54
5.3
Urban
10.21
Rural
..
9.39
a
Eastern
and
Western
Regions
are
separated
by
100
degrees
north
longitude.
Background
visibility
conditions
differ
by
region.
b
The
results
incorporate
earlier
emissions
estimates
from
the
engines
subject
to
this
rule,
as
discussed
in
the
Final
Regulatory
Support
Document.
We
have
revised
our
estimates
both
upwards
for
some
categories
and
downwards
for
others
based
on
public
comment
and
updated
information;
however,
we
believe
that
the
net
results
would
underestimate
future
PM
emissions.
(
B)
Visibility
Impairment
in
Class
I
Areas
The
Clean
Air
Act
establishes
special
goals
for
improving
visibility
in
many
national
parks,
wilderness
areas,
and
international
parks.
In
the
1977
amendments
to
the
Clean
Air
Act,
Congress
set
as
a
national
goal
for
visibility
the
``
prevention
of
any
future,
and
the
remedying
of
any
existing,
impairment
of
visibility
in
mandatory
class
I
Federal
areas
which
impairment
results
from
manmade
air
pollution''
(
CAA
section
169A(
a)(
1)).
The
Amendments
called
for
EPA
to
issue
regulations
requiring
States
to
develop
implementation
plans
that
assure
``
reasonable
progress''
toward
meeting
the
national
goal
(
CAA
Section
169A(
a)(
4)).
EPA
issued
regulations
in
1980
to
address
visibility
problems
that
are
``
reasonably
attributable''
to
a
single
source
or
small
group
of
sources,
but
deferred
action
on
regulations
related
to
regional
haze,
a
type
of
visibility
impairment
that
is
caused
by
the
emission
of
air
pollutants
by
numerous
emission
sources
located
across
a
broad
geographic
region.
At
that
time,
EPA
acknowledged
that
the
regulations
were
only
the
first
phase
for
addressing
visibility
impairment.
Regulations
dealing
with
regional
haze
were
deferred
until
improved
techniques
were
developed
for
monitoring,
for
air
quality
modeling,
and
for
understanding
the
specific
pollutants
contributing
to
regional
haze.
In
the
1990
Clean
Air
Act
amendments,
Congress
provided
additional
emphasis
on
regional
haze
issues
(
see
CAA
section
169B).
In
1999
EPA
finalized
a
rule
that
calls
for
States
to
establish
goals
and
emission
reduction
strategies
for
improving
visibility
in
all
156
mandatory
Class
I
national
parks
and
wilderness
areas.
In
this
rule,
EPA
established
a
``
natural
visibility''
goal.
In
that
rule,
EPA
also
encouraged
the
States
to
work
together
in
developing
and
implementing
their
air
quality
plans.
The
regional
haze
program
is
focused
on
long
term
emissions
decreases
from
the
entire
regional
emissions
inventory
comprised
of
major
and
minor
stationary
sources,
area
sources
and
mobile
sources.
The
regional
haze
program
is
designed
to
improve
visibility
and
air
quality
in
our
most
treasured
natural
areas
from
these
broad
sources.
At
the
same
time,
control
strategies
designed
to
improve
visibility
in
the
national
parks
and
wilderness
areas
will
improve
visibility
over
broad
geographic
areas.
In
the
1997
PM
NAAQS
rulemaking,
EPA
also
anticipated
the
need
in
addition
to
the
NAAQS
and
Section
169
regional
haze
program
to
continue
to
address
localized
impairment
that
may
relate
to
unique
circumstances
in
some
Western
areas.
For
mobile
sources,
there
is
a
need
for
a
Federal
role
in
reduction
of
those
emissions,
particularly
because
mobile
source
vehicles
are
regulated
primarily
at
the
federal
level.
Visibility
impairment
is
caused
by
pollutants
(
mostly
fine
particles
and
precursor
gases)
directly
emitted
to
the
atmosphere
by
several
activities
(
such
as
electric
power
generation,
various
industry
and
manufacturing
processes,
truck
and
auto
emissions,
construction
activities,
etc.).
These
gases
and
particles
scatter
and
absorb
light,
removing
it
from
the
sight
path
and
creating
a
hazy
condition.
Visibility
impairment
is
caused
by
both
regional
haze
and
localized
impairment.
As
described
above,
regional
haze
is
caused
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22
U.
S.
EPA
Review
of
the
National
Ambient
Air
Quality
Standards
for
Particulate
Matter:
Policy
Assessment
of
Scientific
and
Technical
Information
OAQPS
Staff
Paper.
EPA
452/
R
96
013.
1996.
Docket
Number
A
99
06,
Documents
Nos.
II
A
18,
19,
20,
and
23.
The
particulate
matter
air
quality
criteria
documents
are
also
available
at
http://
www.
epa.
gov/
ncea/
partmatt.
htm.
23
In
a
recent
case,
American
Corn
Growers
Association
v.
EPA,
291
F.
3d
1
(
D.
C.
Cir
2002),
the
court
vacated
the
BART
provisions
of
the
Regional
Haze
rule,
but
the
court
denied
industry's
challenge
to
EPA's
requirement
that
state's
SIPs
provide
for
reasonable
progress
towards
achieving
natural
visibility
conditions
in
national
parks
and
wilderness
areas
and
the
``
no
degradation''
requirement.
Industry
did
not
challenge
requirements
to
improve
visibility
on
the
haziest
20
percent
of
days.
A
copy
of
this
decision
can
be
found
in
Docket
A
2000
01,
Document
IV
A
113.
24
The
results
incorporate
earlier
emissions
estimates
from
the
engines
subject
to
this
rule,
as
discussed
in
the
Final
Regulatory
Support
Document.
We
have
revised
our
estimates
both
upwards
for
some
categories
and
downwards
for
others
based
on
public
comment
and
updated
information;
however,
we
believe
that
the
net
results
would
underestimate
future
PM
emissions.
25
No
data
were
available
at
five
additional
parks
where
snowmobiles
are
also
commonly
used:
Black
Canyon
of
the
Gunnison,
CO,
Grand
Teton,
WY,
Northern
Cascades,
WA,
Theodore
Roosevelt,
ND,
and
Zion,
UT.
26
Letter
from
Debra
C.
Miller,
Data
Analyst,
National
Park
Service,
to
Drew
Kodjak,
August
22,
2001.
Docket
No.
A
2000
01,
Document
Number
II
B
28.
by
the
emission
from
numerous
sources
located
over
a
wide
geographic
area.
22
Because
of
evidence
that
fine
particles
are
frequently
transported
hundreds
of
miles,
all
50
states,
including
those
that
do
not
have
Class
I
areas,
participate
in
planning,
analysis,
and,
in
many
cases,
emission
control
programs
under
the
regional
haze
regulations.
Even
though
a
given
State
may
not
have
any
Class
I
areas,
pollution
that
occurs
in
that
State
may
contribute
to
impairment
in
Class
I
areas
elsewhere.
The
rule
encourages
states
to
work
together
to
determine
whether
or
how
much
emissions
from
sources
in
a
given
state
affect
visibility
in
a
downwind
Class
I
area.
The
regional
haze
program
calls
for
states
to
establish
goals
for
improving
visibility
in
national
parks
and
wilderness
areas
to
improve
visibility
on
the
haziest
20
percent
of
days
and
to
ensure
that
no
degradation
occurs
on
the
clearest
20
percent
of
days
(
64
FR
35722.
July
1,
1999).
The
rule
requires
states
to
develop
long
term
strategies
including
enforceable
measures
designed
to
meet
reasonable
progress
goals
toward
natural
visibility
conditions.
Under
the
regional
haze
program,
States
can
take
credit
for
improvements
in
air
quality
achieved
as
a
result
of
other
Clean
Air
Act
programs,
including
national
mobile
source
programs.
23
In
the
PM
air
quality
modeling
described
above,
we
also
modeled
visibility
conditions
in
the
Class
I
areas,
and
we
summarize
the
results
by
region
in
Table
I.
E
6.
TABLE
I.
E
6
SUMMARY
OF
2030
VISIBILITY
CONDITIONS
IN
CLASS
I
AREAS
BASED
ON
REMSAD
MODELING
[
Annual
Average
Deciview]
Region
a
Predicted
2030
visibility
b
Natural
background
visibility
Eastern
........................
9.5
Southeast
.................................................................................................................................................................
25.02
........................
Northeast/
Midwest
...................................................................................................................................................
21.00
........................
Western
........................
5.3
Southwest
................................................................................................................................................................
8.69
........................
California
..................................................................................................................................................................
11.61
........................
Rocky
Mountain
.......................................................................................................................................................
12.30
........................
Northwest
.................................................................................................................................................................
15.44
........................
National
Class
I
Area
Average
.........................................................................................................................
14.04
........................
a
Regions
are
depicted
in
Figure
VI
5
in
the
Regulatory
Support
Document
for
the
highway
Heavy
Duty
Engine/
Diesel
Fuel
RIA
(
EPA
420
R
00
026,
December
2000.)
Background
visibility
conditions
differ
by
region:
Eastern
natural
background
is
9.5
deciviews
(
or
visual
range
of
150
kilometers)
and
in
the
West
natural
background
is
5.3
deciviews
(
or
visual
range
of
230
kilometers).
b
The
results
incorporate
earlier
emissions
estimates
from
the
engines
subject
to
this
rule,
as
discussed
in
the
Final
Regulatory
Support
Document
We
have
revised
our
estimates
both
upwards
for
some
categories
and
downwards
for
others
based
on
public
comment
and
updated
information
however,
we
believe
that
the
net
results
underestimate
future
PM
emissions.
Nonroad
engines
represent
a
sizeable
portion
of
the
total
inventory
of
anthropogenic
emissions
related
to
PM2.5,
as
shown
in
the
tables
above.
Numerous
types
of
nonroad
engines
may
operate
near
Class
I
areas
(
e.
g.,
mining
equipment,
recreational
vehicles,
and
agricultural
equipment).
We
have
reviewed
contributions
from
snowmobile
in
particular.
Emissions
from
nonroad
engines,
in
particular
snowmobiles,
contribute
significantly
to
visibility
impairment
in
Class
I
areas.
24
Visibility
and
PM
monitoring
data
are
available
for
eight
Class
I
areas
where
snowmobiles
are
commonly
used.
These
are:
Acadia,
Boundary
Waters,
Denali,
Mount
Rainier,
Rocky
Mountain,
Sequoia
and
Kings
Canyon,
Voyageurs,
and
Yellowstone.
25
Fine
particle
monitoring
data
for
these
parks
are
set
out
in
Table
I.
E
7.
This
table
shows
the
number
of
monitored
days
in
the
winter
that
fell
within
the
20
percent
worst
visibility
days
for
each
of
these
eight
parks.
Monitors
collect
data
2
days
a
week
for
a
total
of
about
104
days
of
monitored
values.
Thus,
for
a
particular
site,
a
maximum
of
21
worst
possible
days
of
these
104
days
with
monitored
values
constitute
the
set
of
20
percent
worst
visibility
days
during
a
year
which
are
tracked
as
the
primary
focus
of
regulatory
efforts.
26
With
the
exception
of
Denali
in
Alaska,
we
defined
the
snowmobile
season
as
January
1
through
March
15
and
December
15
through
December
31
of
the
same
calendar
year,
consistent
with
the
methodology
used
in
the
Regional
Haze
Rule,
which
is
calendar
year
based.
For
Denali
in
Alaska,
the
snowmobile
season
is
October
1
to
April
30.
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27
Letter
from
Debra
C.
Miller,
Data
Analyst,
National
Park
Service,
to
Drew
Kodjak,
August
22,
2001.
Docket
No.
A
2000
01,
Document
Number
II
B
28.
28
See
Chapter
1
in
the
RSD
for
a
discussion
or
U.
S.
EPA
Technical
Support
Document
for
Heavyduty
Engine
and
Vehicle
Standards
and
Highway
Diesel
Fuel
Sulfur
Control
Requirements
Air
Quality
Modeling
Analyses
December
2000.
Docket
No.
A
2000
01,
Docket
Number
IV
A
218.
This
document
is
also
avaiable
at
www.
epa.
gov/
otaq/
hdmodels.
htm.
TABLE
I.
E
7
WINTER
DAYS
THAT
FALL
WITHIN
THE
20
PERCENT
WORST
VISIBILITY
DAYS
AT
NATIONAL
PARKS
USED
BY
SNOWMOBILES
NPS
unit
States
Number
of
sampled
wintertime
days
within
20
percent
worst
visibility
days
(
maximum
of
21
out
of
104
monitored
days)
1996
1997
1998
1999
Acadia
NP
..................................................................................
ME
...........................................
4
4
2
1
Denali
NP
and
Preserve
............................................................
AK
............................................
10
10
12
9
Mount
Rainier
NP
......................................................................
WA
...........................................
1
3
1
1
Rocky
Mountain
NP
...................................................................
CO
...........................................
2
1
2
1
Sequoia
and
Kings
Canyon
NP
.................................................
CA
............................................
4
9
1
8
Voyageurs
NP
(
1989
1992)
......................................................
MN
...........................................
1989
1990
1991
1992
3
4
6
8
Boundary
Waters
USFS
Wilderness
Area
(
close
to
Voyaguers
with
recent
data).
MN
...........................................
2
5
1
5
Yellowstone
NP
.........................................................................
ID,
MT,
WY
..............................
0
2
0
0
Source:
Letter
from
Debra
C.
Miller,
Data
Analyst,
National
Park
Service,
to
Drew
Kodjak,
August
22,
2001.
Docket
No.
A
2000
01,
Document
Number
II
B
28.
According
to
the
National
Park
Service,
``[
s]
ignificant
differences
in
haziness
occur
at
all
eight
sites
between
the
averages
of
the
clearest
and
haziest
days.
Differences
in
mean
standard
visual
range
on
the
clearest
and
haziest
days
fall
in
the
approximate
range
of
115
170
km.''
27
We
examined
future
air
quality
predictions
to
whether
the
emissions
from
recreational
vehicles,
such
as
snowmobiles,
contribute
to
regional
visibility
impairment
in
Class
I
areas.
We
present
results
from
the
future
air
quality
modeling
described
above
for
these
Class
I
areas
in
addition
to
inventory
and
air
quality
measurements.
Specifically,
in
Table
I.
E
8,
we
summarize
the
expected
future
visibility
conditions
in
these
areas
without
these
regulations.
TABLE
I.
E
8
ESTIMATED
2030
VISIBILITY
IN
SELECTED
CLASS
I
AREAS
a,
b
Class
I
area
County
State
Predicted
2030
visibility
(
annual
average
deciview)
Natural
background
visibility
(
annual
average
deciview)
Eastern
areas
..........................................
..........................................
........................
9.5
Acadia
.........................................................................
Hancock
Co
.....................
ME
....................................
23.42
........................
Boundary
Waters
........................................................
St.
Louis
Co
.....................
MN
...................................
22.07
........................
Voyageurs
...................................................................
St.
Louis
Co
.....................
MN
...................................
22.07
........................
Western
areas
..........................................
..........................................
........................
5.3
Grand
Teton
NP
.........................................................
Teton
Co
..........................
WY
...................................
11.97
........................
Kings
Canyon
.............................................................
Fresno
Co
........................
CA
....................................
10.39
........................
Mount
Rainier
.............................................................
Lewis
Co
..........................
WA
...................................
16.19
........................
Rocky
Mountain
..........................................................
Larimer
Co
.......................
CO
....................................
8.11
........................
Sequoia
Kings
.............................................................
Tulare
Co
.........................
CA
....................................
9.36
........................
Yellowstone
.................................................................
Teton
Co
..........................
WY
...................................
11.97
........................
a
Natural
background
visibility
conditions
differ
by
region
because
of
differences
in
factors
such
as
relative
humidity:
Eastern
natural
background
is
9.5
deciviews
(
or
visual
range
of
150
kilometers)
and
in
the
West
natural
background
is
5.3
deciviews
(
or
visual
range
of
230
kilometers
b
The
results
incorporate
earlier
emissions
estimates
from
the
engines
subject
to
this
rule.
We
have
revised
our
estimates
both
upwards
for
some
categories
and
downwards
for
others
based
on
public
comment
and
updated
information;
however,
on
net,
we
believe
that
HD07
analyses
would
underestimate
future
PM
emissions
from
these
categories.
The
information
presented
in
Table
I.
E
7
shows
that
visibility
data
support
a
conclusion
that
there
are
at
least
8
Class
I
Areas
(
7
national
parks
and
one
wilderness
area)
frequented
by
snowmobiles
with
one
or
more
wintertime
days
within
the
20
percent
worst
visibility
days
of
the
year,
and
in
many
cases
several
days.
For
example,
Rocky
Mountain
National
Park
in
Colorado
was
frequented
by
about
27,000
snowmobiles
during
the
1998
1999
winter.
Of
the
monitored
days
characterized
as
within
the
20
percent
worst
visibility
monitored
days,
2
of
those
days
occurred
during
the
wintertime
when
snowmobile
emissions
such
as
hydrocarbons
contributed
to
visibility
impairment.
The
information
in
Table
I.
E
8
shows
that
these
areas
also
are
predicted
to
have
high
annual
average
deciview
levels
in
the
future.
Emissions
from
snowmobiles
and
other
recreational
vehicles,
as
well
as
other
nonroad
engines
contributed
to
these
levels.
28
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/
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No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
29
Letter
from
Debra
C.
Miller,
Data
Analyst,
National
Park
Service,
to
Drew
Kodjak,
August
22,
2001.
Docket
No.
A
2000
01,
Document
Number
II
B
28.
30
Emissions
of
NOX
from
snowmobiles
contribute
to
the
total
amount
of
particulate
nitrate,
although
the
total
NOX
emissions
from
snowmobiles
are
considerably
less
than
HC
or
direct
PM
emissions
from
these
engines.
31
Technical
Memorandum,
Aaron
Worstell,
Environmental
Engineer,
National
Park
Service,
Air
Resources
Division,
Denver,
Colorado,
particularly
Table
1.
Docket
No.
A
2000
01,
Document
Number
II
G
178.
32
Memo
to
Docket,
Mike
Samulski.
``
Hydrocarbon
Measurements
as
an
Indicator
for
Particulate
Matter
Emissions
in
Snowmobiles,''
with
attachments.
September
6,
2002,
Docket
A
2000
01;
Document
No.
IV
B
42.
Ambient
concentrations
of
fine
particles
are
the
primary
pollutant
responsible
for
visibility
impairment.
The
classes
of
fine
particles
principally
responsible
for
visibility
impairment
are
sulfates,
nitrates,
organic
carbon
particles,
elemental
carbon,
and
crustal
material.
Hydrocarbon
emissions
from
automobiles,
trucks,
snowmobiles,
and
other
industrial
processes
are
common
sources
of
organic
carbon.
The
organic
carbon
fraction
of
fine
particles
ranges
from
47
percent
in
Western
areas
such
as
Denali
National
Park,
to
28
percent
in
Rocky
Mountain
National
Park,
to
13
percent
in
Acadia
National
Park.
29
In
the
winter
months,
HC
emissions
from
snowmobiles
can
be
significant,
and
these
HC
emissions
can
be
more
than
half
of
the
organic
carbon
fraction
of
fine
particles
which
are
largely
responsible
for
visibility
impairment.
In
Yellowstone,
a
park
with
high
snowmobile
usage
during
the
winter
months,
snowmobile
HC
emissions
can
exceed
500
tons
per
year,
as
much
as
several
large
stationary
sources.
30
Other
parks
with
less
snowmobile
traffic
are
also
impacted
although
to
a
lesser
extent
by
these
HC
emissions.
31
Table
I.
E
9
shows
estimated
tons
of
four
pollutants
during
the
winter
season
in
five
Class
I
national
parks
for
which
we
have
estimates
of
snowmobile
use.
The
national
park
areas
outside
of
Denali
in
Alaska
are
open
to
snowmobile
operation
in
accordance
with
special
regulations
(
36
CFR
part
7).
Denali
National
Park
permits
snowmobile
operation
by
local
rural
residents
engaged
in
subsistence
uses
(
36
CFR
part
13).
TABLE
I.
E
9.
WINTER
SEASON
SNOWMOBILE
EMISSIONS
[
tons;
1999
Winter
Season]
NPS
unit
HC
CO
NOX
PM
Denali
NP
&
Preserve
.............................................................................................................................
>
9.8
>
26.1
>
0.08
>
0.24
Grand
Teton
NP
......................................................................................................................................
13.7
36.6
0.1
0.3
Rocky
Mountain
NP
.................................................................................................................................
106.7
284.7
0.8
2.6
Voyageurs
NP
..........................................................................................................................................
138.5
369.4
1.1
3.4
Yellowstone
NP
.......................................................................................................................................
492
1311.9
3.8
12
Source:
Letter
from
Aaron
J.
Worstell,
Environmental
Engineer,
National
Park
Service,
Air
Resources
Division,
to
Drew
Kodjak,
August
21,
2001,
particularly
Table
1.
Docket
No.
A
2000
01,
Document
No.
II
G
178.
Inventory
analysis
performed
by
the
National
Park
Service
for
Yellowstone
National
Park
suggests
that
snowmobile
emissions
are
a
significant
source
of
total
annual
mobile
source
emissions
for
the
park
year
round.
The
proportion
of
snowmobile
emissions
to
emissions
from
other
sources
affecting
air
quality
in
these
parks
is
likely
to
be
similar
to
that
in
Yellowstone.
Furthermore,
public
comments
from
an
industry
initiated
study
contained
modeling
showing
a
4
to
8
percent
contribution
to
perceptible
impairment
from
snowmobile
exhaust
in
Yellowstone
National
Park.
Although
we
believe
the
modeling
technique
may
not
be
fully
appropriate,
the
study
still
indicates
a
significant
contribution
from
snowmobiles.
EPA
conducted
independent
modeling
using
a
more
appropriate
visibility
model,
and
we
confirmed
that
snowmobiles
would
be
creating
perceptible
plumes
at
all
park
entrances,
impairing
visibility.
This
evidence
shows
that
snowmobiles
contribute
significantly
to
visibility
impairment
in
several
Class
I
areas.
(
C)
Regulation
of
HC
Is
a
Good
Proxy
for
Regulation
of
Fine
PM
Emissions
From
Current
Snowmobile
Engines
We
believe
the
best
way
to
regulate
the
contribution
to
ambient
concentrations
of
fine
PM
from
current
snowmobile
engines
is
to
set
standards
to
control
HC
emissions.
The
current
fleet
of
snowmobiles
consists
almost
exclusively
of
two
stroke
engines.
Twostroke
engines
inject
lubricating
oil
into
the
air
intake
system
where
it
is
combusted
with
the
air
and
fuel
mixture
in
the
combustion
chamber.
This
is
done
to
provide
lubrication
to
the
piston
and
crankshaft,
since
the
crankcase
is
used
as
part
of
the
fuel
delivery
system
and
cannot
be
used
as
a
sump
for
oil
storage
as
in
four
stroke
engines.
As
a
result,
in
addition
to
products
of
incomplete
combustion,
two
stroke
engines
also
emit
a
mixture
of
uncombusted
fuel
and
lubricant
oil.
HCrelated
emissions
from
snowmobiles
increase
PM
concentrations
in
two
ways.
Snowmobile
engines
emit
HC
directly
as
particles
(
such
as
droplets
of
lubricant
oil).
Snowmobile
engines
also
emit
HC
gases,
as
well
as
raw
unburned
HC
from
the
fuel
which
either
condenses
in
cold
temperatures
to
particles
or
reacts
chemically
to
transform
into
particles
as
it
moves
in
the
atmosphere.
As
discussed
above,
fine
particles
can
cause
a
variety
of
adverse
health
and
welfare
effects,
including
visibility
impairment.
We
believe
measurements
of
HC
emissions
will
serve
as
a
reasonable
surrogate
for
measurement
of
fine
particles
for
snowmobiles
for
several
reasons.
First,
emissions
of
PM
and
HC
from
these
engines
are
related.
Test
data
show
that
over
70
percent
of
the
average
volatile
organic
fraction
of
PM
from
a
typical
two
stroke
snowmobile
engine
is
organic
hydrocarbons,
largely
from
lubricating
oil
components.
32
The
HC
measurements
(
which
use
a
191
°
C
heated
flame
ionization
detector
(
FID))
would
capture
the
volatile
component,
which
in
ambient
temperatures
would
be
particles
(
as
droplets).
Second,
many
of
the
technologies
that
will
be
employed
to
reduce
HC
emissions
are
expected
to
reduce
PM
(
four
stroke
engines,
pulse
air,
and
direct
fuel
injection
techniques
for
example).
The
organic
emissions
are
a
mixture
of
fuel
and
oil,
and
reductions
in
the
organic
emissions
will
likely
yield
both
HC
and
PM
reductions.
HC
measurements
would
capture
the
reduction
from
both
the
gas
and
particle
(
at
ambient
temperature)
phases.
For
example,
the
HC
emission
factor
for
a
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33
For
recreational
vehicles,
we
are
adopting
vehicle
based
standards.
For
these
applications,
the
term
``
engine''
in
this
document
applies
equally
to
the
vehicles.
34
The
term
``
manufacturer''
includes
any
individual
or
company
that
manufactures
any
new
engine
for
sale
or
otherwise
introduces
a
new
engine
into
commerce
in
the
United
States.
It
also
includes
importers
for
resale.
typical
two
stroke
snowmobile
is
111
g/
hp
hr.
The
HC
emission
factor
for
a
direct
fuel
injection
engine
is
21.8,
and
for
a
four
stroke
is
7.8
g/
hp
hr,
representing
a
80
percent
and
99
percent
reduction,
respectively.
Similarly,
the
PM
emission
factor
for
a
typical
two
stroke
snowmobile
is
2.7
g/
hp
hr.
The
corresponding
PM
emission
factor
for
a
direct
fuel
injection
engine
is
0.57,
and
for
a
four
stroke
is
0.15
g/
hp
hr,
representing
a
75
percent
and
93
percent
reduction,
respectively.
Thus,
manufacturers
will
generally
reduce
PM
emissions
as
a
result
of
reducing
HC
emissions,
making
separate
PM
standards
less
necessary.
Moreover,
PM
standards
would
cover
only
the
PM
directly
emitted
at
the
tailpipe.
It
would
not
measure
the
gaseous
or
semi
volatile
organic
emissions
which
would
condense
or
be
converted
into
PM
in
the
atmosphere.
The
HC
measurements
would
also
include
the
gaseous
HC
which
would
condense
or
be
converted
into
PM
in
the
atmosphere.
Consequently,
the
HC
measurement
would
be
a
more
comprehensive
measurement.
Also,
HC
standards
actually
will
reduce
secondary
PM
emissions
that
would
not
necessarily
be
reduced
by
PM
standards.
Finally,
from
an
implementation
point
of
view,
PM
is
not
routinely
measured
in
snowmobiles.
There
is
no
currently
established
protocol
for
measuring
PM
and
substantial
technical
issues
would
need
to
be
overcome
to
create
a
new
method.
Establishing
additional
PM
test
procedures
would
also
entail
additional
costs
for
manufacturers.
HC
measurements
are
more
routinely
performed
on
these
types
of
engines,
and
these
measurements
currently
serve
as
a
more
reliable
basis
for
setting
a
numeric
standard.
Thus,
we
believe
that
regulation
of
HC
is
the
best
way
to
reduce
PM
emissions
and
PM
contributions
from
current
snowmobile
engines.
We
included
a
NOX
standard
for
snowmobiles.
This
standard
will
essentially
cap
NOX
emissions
from
these
engines
to
prevent
backsliding.
We
are
not
promulgating
standards
that
would
require
substantial
reductions
in
NOX
because
we
believe
that
standards
which
force
substantial
NOX
reductions
would
likely
not
lead
to
reductions
in
PM
and
may
in
fact
increase
PM
levels.
NOX
emissions
from
snowmobiles
are
very
small,
particularly
compared
to
levels
of
HC.
In
fact,
technologies
that
reduce
HC
and
CO
are
likely
to
increase
levels
of
NOX
and
vice
versa,
because
technologies
to
reduce
HC
and
CO
emissions
would
result
in
leaner
operation.
A
lean
air
and
fuel
mixture
causes
NOX
emissions
to
increase.
These
increases
are
minor,
however,
compared
to
the
reductions
of
HC
(
and
therefore
PM)
that
result
from
these
techniques.
On
the
other
hand,
substantial
control
of
NOX
emissions
may
have
the
countereffect
of
increasing
HC
emissions
and
the
greater
PM
emissions
associated
with
those
HC
emissions.
The
only
way
to
reduce
NOX
emissions
from
fourstroke
engines
(
at
the
same
time
as
reducing
HC
and
CO
levels)
would
be
to
use
a
three
way
catalytic
converter.
We
do
not
have
enough
information
at
this
time
on
the
durability
or
safety
implications
of
using
a
three
way
catalyst
with
a
four
stroke
engine
in
snowmobile
applications.
Three
way
catalyst
technology
is
well
beyond
the
technology
reviewed
for
this
rule
and
would
need
substantial
additional
review
before
being
contemplated
for
snowmobiles.
Thus,
given
the
overwhelming
level
of
HC
compared
to
NOX,
and
the
secondary
PM
expected
to
result
from
these
levels,
it
would
be
premature
and
possibly
counterproductive
to
promulgate
NOX
standards
that
require
significant
NOX
reductions
from
snowmobiles
at
this
time.
We
have
therefore
decided
to
structure
our
long
term
HC+
NOX
standard
for
2012
and
later
model
year
snowmobiles
to
require
only
a
cap
on
NOX
emissions
from
the
advanced
technology
engines
which
will
be
the
dominant
technology
in
the
new
snowmobiles
certified
at
that
time.
II.
Nonroad:
General
Provisions
This
section
describes
general
provisions
concerning
the
emission
standards
adopted
in
this
final
rule
and
the
ways
in
which
a
manufacturer
shows
compliance
with
these
standards.
Clean
Air
Act
section
213(
a)(
3)
requires
us
to
set
standards
that
achieve
the
greatest
degree
of
emission
reduction
achievable
through
the
application
of
technology
that
will
be
available,
giving
appropriate
consideration
to
cost,
noise,
energy,
and
safety
factors.
Section
202(
a)(
4)
provides
further
authority
to
adopt
standards
for
pollution
beyond
that
regulated
under
section
202(
a)(
3).
In
addition
to
emission
standards,
this
document
describes
a
variety
of
other
provisions
necessary
for
implementing
the
proposed
emission
control
program
in
an
effective
way,
such
as
applying
for
certification,
labeling
engines,
and
meeting
warranty
requirements.
The
discussions
in
this
section
are
general
and
are
meant
to
cover
all
the
nonroad
engines
and
vehicles
subject
to
the
new
standards.
In
this
Section
II,
the
term
engine
is
sometimes
used
to
include
both
nonroad
engines
and
nonroad
vehicles.
Refer
to
the
discussions
of
specific
programs,
contained
in
Sections
III
through
VI,
to
determine
whether
the
regulations
are
being
applied
to
the
entire
vehicle
or
just
the
engine,
as
well
as
for
more
information
about
specific
requirements
for
different
categories
of
nonroad
engines
and
vehicles.
This
section
describes
general
nonroad
provisions
related
to
certification
prior
to
sale
or
introduction
into
commerce.
Section
VII
describes
several
compliance
provisions
that
apply
generally
to
nonroad
engines,
and
Section
VIII
similarly
describes
general
testing
provisions.
A.
Scope
of
Application
This
final
rule
covers
recreational
marine
diesel
engines,
nonroad
sparkignition
engines
rated
over
19
kW,
and
recreational
spark
ignition
vehicles
introduced
into
commerce
in
the
United
States.
The
following
sections
describe
generally
when
emission
standards
apply
to
these
products.
These
provisions
are
generally
consistent
with
prior
nonroad
and
motor
vehicle
rulemakings.
Refer
to
the
specific
program
discussion
below
for
more
information
about
the
scope
of
application
and
timing
of
new
standards.
1.
What
Engines
and
Vehicles
Are
Subject
to
the
Standards?
The
scope
of
this
rule
is
broadly
set
by
Clean
Air
Act
section
213(
a),
which
instructs
us
to
set
emission
standards
for
new
nonroad
engines
and
new
nonroad
vehicles.
Generally
speaking,
this
rule
is
intended
to
cover
all
new
engines
and
vehicles
in
the
categories
listed
above
(
including
any
associated
equipment
or
vessels)
for
their
entire
useful
lives,
as
defined
in
the
regulations.
33
Once
the
emission
standards
apply
to
a
group
of
engines
or
vehicles,
manufacturers
of
a
new
engine
must
have
an
approved
certificate
of
conformity
from
us
before
selling
them
in
the
United
States.
34
This
also
applies
to
importation
by
any
person
and
any
other
means
of
introducing
new
engines
and
vehicles
into
commerce.
We
also
require
equipment
manufacturers
that
install
engines
from
other
companies
to
install
only
certified
engines
into
new
equipment
once
emission
standards
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35
The
definition
in
Clean
Air
Act
section
216
applies
specifically
to
``
new
motor
vehicles,''
but
we
have
interpreted
``
new
nonroad
engine''
consistently
with
the
definition
in
section
216.
apply.
The
information
we
require
of
manufacturers
applying
for
certification
(
with
the
corresponding
engine
labels)
provides
assurance
that
manufacturers
have
met
their
obligation
to
make
engines
that
meet
emission
standards
over
the
useful
life
we
specify
in
the
regulations.
2.
How
Do
I
Know
if
My
Engine
or
Equipment
Is
New?
We
are
defining
``
new''
consistent
with
previous
rulemakings.
We
will
consider
a
nonroad
engine
(
or
nonroad
equipment)
to
be
new
until
its
title
has
been
transferred
to
the
ultimate
purchaser
or
the
engine
has
been
placed
into
service.
This
definition
applies
to
both
engines
and
equipment,
so
the
nonroad
equipment
using
these
engines,
including
all
terrain
vehicles,
snowmobiles,
off
highway
motorcycles,
and
other
land
based
nonroad
equipment
will
be
considered
new
until
their
title
has
been
transferred
to
an
ultimate
buyer.
In
Section
II.
B.
1
we
describe
how
to
determine
the
model
year
of
individual
engines
and
vehicles.
To
further
clarify
the
definition
of
new
nonroad
engine,
we
specify
that
a
nonroad
engine,
vehicle,
or
equipment
is
placed
into
service
when
it
is
used
for
its
intended
purpose.
An
engine
subject
to
emission
standards
is
used
for
its
functional
purpose
when
it
is
installed
in
an
all
terrain
vehicle,
snowmobile,
off
highway
motorcycle,
marine
vessel,
or
other
piece
of
nonroad
equipment.
We
need
to
make
this
clarification
because
some
engines
are
made
by
modifying
a
highway
or
land
based
nonroad
engine
that
has
already
been
installed
on
a
vehicle
or
other
piece
of
equipment.
For
example,
someone
can
install
an
engine
in
a
recreational
marine
vessel
after
it
has
been
used
for
its
functional
purpose
as
a
land
based
highway
or
nonroad
engine.
We
believe
our
approach
is
reasonable
because
the
practice
of
adapting
used
highway
or
land
based
nonroad
engines
may
become
more
common
if
these
engines
are
not
subject
to
emission
standards.
In
summary,
an
engine
may
be
subject
to
emission
standards
if
it
is:
Freshly
manufactured,
whether
domestic
or
imported;
this
may
include
engines
produced
from
engine
block
cores
Installed
for
the
first
time
in
nonroad
equipment
after
having
powered
an
automobile
or
a
category
of
nonroad
equipment
subject
to
different
emission
standards
Installed
in
new
nonroad
equipment,
regardless
of
the
age
of
the
engine
Imported
(
freshly
manufactured
or
used)
and
was
originally
manufactured
after
the
effective
date
of
our
standards
3.
When
Do
Imported
Engines
Need
To
Meet
Emission
Standards?
The
emission
standards
apply
to
all
new
engines
sold
in
the
United
States.
Consistent
with
Clean
Air
Act
section
216,
engines
that
are
imported
by
any
person,
whether
freshly
manufactured
or
used
are
considered
``
new''
engines.
35
Thus,
we
include
engines
that
are
imported
for
use
in
the
United
States,
whether
they
are
imported
as
loose
engines
or
if
they
are
already
installed
on
a
marine
vessel,
recreational
vehicle,
or
other
piece
of
nonroad
equipment,
built
elsewhere.
All
imported
engines
manufactured
after
our
standards
begin
to
apply
need
an
EPA
issued
certificate
of
conformity
to
clear
customs,
with
limited
exemptions
(
as
described
below).
An
engine
or
marine
vessel,
recreational
vehicle,
or
other
piece
of
nonroad
equipment
that
was
built
after
emission
standards
take
effect
cannot
be
imported
without
a
currently
valid
certificate
of
conformity.
We
would
consider
it
to
be
a
new
engine,
vehicle,
or
vessel,
which
would
trigger
a
requirement
to
comply
with
the
applicable
emission
standards.
Thus,
for
example,
a
marine
vessel
manufactured
in
a
foreign
country
in
2007,
then
imported
into
the
United
States
in
2010,
would
be
considered
``
new.''
The
engines
on
that
vessel
would
have
to
comply
with
the
requirements
for
the
2007
model
year,
assuming
no
other
exemptions
apply.
This
provision
is
important
to
prevent
manufacturers
from
avoiding
emission
standards
by
building
vessels
or
vehicles
abroad,
transferring
their
title,
and
then
importing
them
as
used
vessels
or
vehicles.
Imported
engines
are
generally
subject
to
emission
standards.
However,
we
are
not
adopting
a
definition
of
``
import''
in
this
regulation.
We
will
defer
to
the
U.
S.
Customs
Service
for
determinations
of
when
an
engine
or
vehicle
is
imported
into
the
U.
S.
4.
Do
the
Standards
Apply
to
Exported
Engines
or
Vehicles?
Engines
or
vehicles
intended
for
export
are
generally
not
required
to
meet
the
emission
standards
or
other
requirements
adopted
in
this
rule.
However,
engines
that
will
be
exported
and
subsequently
re
imported
into
the
United
States
must
be
covered
by
a
certificate
of
conformity.
For
example,
this
would
occur
when
a
foreign
company
purchases
engines
manufactured
in
the
United
States
for
installation
on
a
marine
vessel,
recreational
vehicle,
or
other
nonroad
equipment
for
export
back
to
the
United
States.
Those
engines
would
be
subject
to
the
emission
standards
that
apply
on
the
date
the
engine
was
originally
manufactured.
If
the
engine
is
later
modified
and
certified
(
or
recertified),
the
engine
is
subject
to
emission
standards
that
apply
on
the
date
the
modification
is
complete.
So,
for
example,
foreign
boat
builders
buying
U.
S.
made
engines
without
recertifying
the
engines
will
need
to
make
sure
they
purchase
complying
engines
for
the
products
they
sell
in
the
U.
S.
We
also
do
not
exempt
engines
exported
to
countries
that
share
our
emission
standards.
5.
Are
Any
New
Engines
or
Vehicles
in
the
Applicable
Categories
Not
Subject
to
Emission
Standards
of
This
Rule?
We
are
extending
our
basic
nonroad
exemptions
to
the
engines
and
vehicles
covered
by
this
rulemaking.
These
include
the
testing
exemption,
the
manufacturer
owned
exemption,
the
display
exemption,
and
the
nationalsecurity
exemption.
These
exemptions
are
described
in
more
detail
in
Section
VII.
C.
In
addition,
the
Clean
Air
Act
does
not
consider
stationary
engines
or
engines
used
solely
for
competition
to
be
nonroad
engines,
so
the
emission
standards
do
not
apply
to
them.
Refer
to
the
program
discussions
below
for
a
description
of
how
these
exclusions
or
exemptions
apply
for
different
categories
of
engines.
B.
Emission
Standards
and
Testing
1.
Which
Pollutants
Are
Covered
by
Emission
Standards?
Engines
subject
to
the
exhaust
emission
standards
must
meet
standards
based
on
measured
levels
of
specified
pollutants,
such
as
NOX,
HC,
or
CO,
though
not
all
engines
have
standards
for
each
pollutant.
Diesel
engines
generally
must
also
meet
a
PM
emission
standard.
In
addition,
there
may
be
standards
or
other
requirements
for
crankcase,
evaporative,
or
permeation
emissions,
as
described
below.
The
emission
standards
are
effective
on
a
model
year
basis.
We
define
model
year
much
like
we
do
for
passenger
cars.
It
generally
means
either
the
calendar
year
or
some
other
annual
production
period
based
on
the
manufacturer's
production
practices.
A
model
year
may
include
January
1
from
only
one
year.
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For
example,
manufacturers
could
start
selling
2006
model
year
engines
as
early
as
January
2,
2005,
as
long
as
the
production
period
extends
until
at
least
January
1,
2006.
All
of
a
manufacturer's
engines
from
a
given
model
year
must
meet
emission
standards
for
that
model
year.
For
example,
manufacturers
producing
new
engines
in
the
2006
model
year
need
to
comply
with
the
2006
standards.
The
model
year
of
a
particular
engine
is
determined
based
on
the
date
that
the
engine
is
fully
assembled.
In
the
case
of
recreational
vehicles,
this
generally
applies
to
the
final
assembly
of
the
whole
vehicle,
since
the
emission
standards
apply
to
the
vehicle.
Refer
to
the
individual
program
discussions
below
or
the
regulations
for
additional
information
about
model
year
periods,
including
how
to
define
what
model
year
means
in
less
common
scenarios,
such
as
installing
used
engines
in
new
equipment.
2.
What
Standards
Apply
to
Crankcase,
Evaporative,
Permeation,
and
Other
Emissions?
Blow
by
of
combustion
gases
and
the
reciprocating
action
of
the
piston
can
cause
exhaust
emissions
to
accumulate
in
the
crankcase
of
four
stroke
engines.
Uncontrolled
engine
designs
route
these
vapors
directly
to
the
atmosphere,
where
they
contribute
to
ambient
levels
of
hydrocarbons.
We
have
long
required
that
automotive
engines
prevent
emissions
from
their
crankcases.
Manufacturers
typically
do
this
by
routing
crankcase
vapors
through
a
valve
into
the
engine's
air
intake
system.
We
generally
require
in
this
rulemaking
that
engines
control
crankcase
emissions.
Vehicles
with
spark
ignition
engines
use
fuel
that
is
volatile
and
the
unburned
fuel
can
be
released
into
the
ambient
air.
We
are
adopting
standards
to
limit
evaporative
emissions
from
the
fuel.
Evaporative
emissions
result
from
heating
gasoline
or
other
volatile
fuels
in
a
tank
that
is
vented
to
the
atmosphere
or
from
permeation
through
plastic
fuel
tanks
and
rubber
hoses.
Section
IV
describes
the
permeation
standards
for
recreational
vehicles.
Section
V
provides
additional
information
on
the
evaporative
emission
standards
for
Large
SI
engines.
We
are
also
adopting
a
general
requirement
that
all
engines
subject
to
this
final
rule
may
not
cause
or
contribute
to
an
unreasonable
risk
to
public
health,
welfare,
or
safety,
especially
with
respect
to
noxious
or
toxic
emissions
that
may
increase
as
a
result
of
emission
control
technologies.
The
regulatory
language
has
been
modified
consistent
with
the
alternate
language
suggested
in
the
proposal.
This
alternate
language
implements
sections
202(
a)(
4)
and
206(
a)(
3)
of
the
Act
and
clarifies
that
the
purpose
of
this
requirement
is
to
prevent
control
technologies
that
would
cause
unreasonable
risks,
rather
than
to
prevent
trace
emissions
of
any
noxious
compounds.
For
example,
this
requirement
would
prevent
the
use
of
emission
control
technologies
that
produce
high
levels
of
pollutants
for
which
we
have
not
set
emission
standards,
but
nevertheless
pose
a
risk
to
the
public.
However,
it
should
be
noted
that
this
would
generally
not
apply
to
exhaust
gas
recirculation
systems
on
gasoline
or
diesel
fueled
engines.
3.
What
Duty
Cycles
Is
EPA
Adopting
for
Emission
Testing?
Testing
an
engine
for
exhaust
emissions
typically
consists
of
exercising
it
over
a
prescribed
duty
cycle
of
speeds
and
loads,
typically
using
an
engine
or
chassis
dynamometer.
The
duty
cycle
used
to
measure
emissions
for
certification,
which
is
generally
derived
from
typical
operation
from
the
field,
is
critical
in
evaluating
the
likely
emissions
performance
of
engines
designed
to
emission
standards.
Testing
for
recreational
marine
diesel
engines
and
Large
SI
engines
may
also
include
additional
operation
not
included
in
the
specific
duty
cycles.
Steady
state
testing
consists
of
engine
operation
for
an
extended
period
at
several
speed
load
combinations.
Associated
with
these
test
points
are
weighting
factors
that
allow
calculation
of
a
single
weighted
average
steady
state
emission
level
in
g/
kW.
Transient
testing
involves
a
continuous
trace
of
specified
engine
or
vehicle
operation;
emissions
are
collected
over
the
whole
testing
period
for
a
single
mass
measurement.
See
Section
VIII.
C
for
a
discussion
of
how
we
define
maximum
test
speed
and
intermediate
speed
for
engine
testing.
Refer
to
the
program
discussions
below
for
more
information
about
the
type
of
duty
cycle
required
for
testing
the
various
engines
and
vehicles.
Those
sections
also
include
information
regarding
testing
provisions
that
do
not
rely
on
specific
operating
cycles
(
i.
e.,
field
testing,
not
to
exceed
testing,
and
evaporative
testing).
4.
How
Do
Adjustable
Engine
Parameters
Affect
Emission
Testing?
Many
engines
are
designed
with
components
that
can
be
adjusted
for
optimum
performance
under
changing
conditions,
such
as
varying
fuel
quality,
high
altitude,
or
engine
wear.
Examples
of
adjustable
parameters
include
spark
timing,
idle
speed
setting,
and
fuelinjection
timing.
While
we
recognize
the
need
for
this
practice,
we
are
also
concerned
that
engines
maintain
an
appropriate
level
of
emission
control
for
the
whole
range
of
adjustability.
Manufacturers
must
therefore
show
that
their
engines
meet
emission
standards
over
the
full
adjustment
range.
Manufacturers
must
also
provide
a
physical
stop
to
prevent
adjustment
outside
the
established
range.
Operators
are
then
prohibited
by
the
antitampering
provisions
from
adjusting
engines
outside
this
range.
5.
What
Are
Voluntary
Low
Emission
Engines
and
Blue
Sky
Standards?
Several
state
and
environmental
groups
and
manufacturers
of
emission
controls
have
supported
our
efforts
to
develop
incentive
programs
to
encourage
engine
technologies
that
go
beyond
federal
emission
standards.
Some
companies
have
already
significantly
developed
these
technologies.
In
the
final
rule
for
landbased
nonroad
diesel
engines,
we
included
a
program
of
voluntary
standards
for
low
emitting
engines,
referring
to
these
as
``
Blue
Sky
Series''
engines
(
63
FR
56967,
October
23,
1998).
We
included
similar
programs
for
commercial
marine
diesel
engines.
The
general
purposes
of
such
programs
are
to
provide
incentives
to
manufacturers
to
produce
clean
products,
as
well
as
to
create
market
choices
and
opportunities
for
environmental
information
for
consumers
regarding
such
products.
We
are
adopting
voluntary
Blue
Sky
Series
standards
for
some
of
the
engines
subject
to
this
final
rule.
Creating
a
program
of
voluntary
standards
for
lowemitting
engines,
including
testing
and
durability
provisions
to
help
ensure
adequate
in
use
performance,
will
be
a
step
forward
in
advancing
emissioncontrol
technologies.
While
these
are
voluntary
standards,
they
become
binding
once
a
manufacturer
chooses
to
participate.
EPA
certification
will
therefore
provide
protection
against
false
claims
of
environmentally
beneficial
products.
C.
Demonstrating
Compliance
We
are
adopting
a
compliance
program
to
accompany
the
final
emission
standards.
This
consists
first
of
a
process
for
demonstrating
that
new
engine
models
comply
with
the
emission
standards.
In
addition
to
newengine
testing,
several
provisions
ensure
that
emission
control
systems
will
continue
to
function
over
long
term
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Rules
and
Regulations
operation
in
the
field.
Most
of
these
certification
provisions
are
consistent
with
previous
rulemakings
for
other
nonroad
engines.
Refer
to
the
discussion
of
the
specific
programs
below
for
additional
information
about
these
requirements
for
each
engine
category.
1.
How
Do
I
Certify
My
Engines?
We
are
adopting
a
certification
process
similar
to
that
already
established
for
other
nonroad
engines.
Manufacturers
generally
test
representative
prototype
engines
and
submit
the
emission
data
along
with
other
information
to
EPA
in
an
application
for
a
Certificate
of
Conformity.
If
we
approve
the
application,
EPA
issues
a
Certificate
of
Conformity
which
allows
the
manufacturer
to
produce
and
sell
the
engines
described
in
the
application
in
the
U.
S.
Manufacturers
certify
their
engine
models
by
grouping
them
into
engine
families
that
have
similar
emission
characteristics.
The
engine
family
definition
is
fundamental
to
the
certification
process
and
to
a
large
degree
determines
the
amount
of
testing
required
for
certification.
The
regulations
include
specific
engine
characteristics
for
grouping
engine
families
for
each
category
of
engines.
To
address
a
manufacturer's
unique
product
mix,
we
may
approve
using
broader
or
narrower
engine
families.
Engine
manufacturers
are
responsible
to
build
engines
that
meet
the
emission
standards
over
each
engine's
useful
life.
The
useful
life
we
adopt
by
regulation
is
intended
to
reflect
the
period
during
which
engines
are
designed
to
properly
function
without
being
remanufactured
or
the
average
service
life.
Useful
life
values,
which
are
expressed
in
terms
of
years
or
amount
of
operation
(
in
hours
or
kilometers),
vary
by
engine
category,
as
described
in
the
following
sections.
Consistent
with
other
recent
EPA
programs,
we
generally
consider
this
useful
life
value
in
amount
of
operation
to
be
a
minimum
value,
requiring
manufacturers
to
comply
for
a
longer
period
in
those
cases
where
their
engines
operate
longer
than
the
minimum
useful
life.
The
emission
data
engine
is
the
engine
from
an
engine
family
that
will
be
used
for
certification
testing.
To
ensure
that
all
engines
in
the
family
meet
the
standards,
manufacturers
must
select
the
engine
most
likely
to
exceed
emission
standards
in
a
family
for
certification
testing.
In
selecting
this
``
worst
case''
engine,
the
manufacturer
uses
good
engineering
judgment.
Manufacturers
consider,
for
example,
all
engine
configurations
and
power
ratings
within
the
engine
family
and
the
range
of
installed
options
allowed.
Requiring
the
worst
case
engine
to
be
tested
helps
the
manufacturer
be
sure
that
all
engines
within
the
engine
family
are
complying
with
emission
standards.
Manufacturers
estimate
the
rate
of
deterioration
for
each
engine
family
over
its
useful
life
and
show
that
engines
continue
to
meet
standards
after
incorporating
the
estimated
deterioration.
We
may
also
test
the
engines
ourselves.
Manufacturers
must
include
in
their
application
for
certification
the
results
of
emission
tests
showing
that
the
engine
family
meets
emission
standards.
In
addition,
we
may
ask
the
manufacturer
to
include
any
additional
data
from
their
emission
data
engines,
including
any
diagnostic
type
measurements
(
such
as
ppm
testing)
and
invalidated
tests.
This
complete
set
of
test
data
ensures
that
the
valid
tests
forming
the
basis
of
the
manufacturer's
application
are
a
robust
indicator
of
emission
control
performance,
rather
than
a
spurious
or
incidental
test
result.
We
are
adopting
test
fuel
specifications
intended
to
represent
inuse
fuels.
Engines
must
be
able
to
meet
the
standards
on
fuels
with
properties
anywhere
in
the
specified
ranges.
The
test
fuel
is
generally
to
be
used
for
all
testing
associated
with
the
regulations,
including
certification,
production
line
testing,
and
in
use
testing.
Refer
to
the
program
discussions
below
related
to
test
fuel
specifications.
We
require
engine
manufacturers
to
give
engine
buyers
instructions
for
properly
maintaining
their
engines.
We
are
including
limitations
on
the
frequency
of
scheduled
maintenance
that
a
manufacturer
may
specify
for
emission
related
components
to
help
ensure
that
emission
control
systems
don't
depend
on
an
unreasonable
expectation
of
maintenance
in
the
field.
These
maintenance
limits
also
apply
during
any
service
accumulation
that
a
manufacturer
may
do
to
establish
deterioration
factors.
This
approach
is
common
to
all
our
engine
programs.
It
is
important
to
note,
however,
that
these
provisions
don't
limit
the
maintenance
an
operator
may
perform;
it
merely
limits
the
maintenance
that
operators
can
be
expected
to
perform
on
a
regularly
scheduled
basis.
Refer
to
the
discussion
of
the
specific
programs
below
for
additional
information
about
the
allowable
maintenance
intervals
for
each
category
of
engines.
Once
an
engine
family
is
certified,
we
require
every
engine
a
manufacturer
produces
from
the
engine
family
to
have
a
label
with
basic
identifying
information.
The
design
and
content
of
engine
labels
is
specified
in
the
regulations.
2.
What
Warranty
Requirements
Apply
to
Certified
Engines?
Consistent
with
our
current
emissioncontrol
programs,
manufacturers
must
provide
a
design
and
defect
warranty
covering
emission
related
components
for
a
minimum
period
specified
in
the
regulations.
This
minimum
period
is
generally
half
of
the
useful
life
period.
The
regulations
also
provide
that
the
manufacturer's
emission
warranty
period
could
be
adjusted
to
a
value
higher
than
the
minimum
period
for
those
cases
where
the
manufacturer
provides
a
longer
mechanical
warranty
for
the
engine
or
any
of
its
components;
this
includes
extended
warranties
that
are
available
for
an
extra
price.
Any
such
adjustment
would
be
dependent
on
the
average
service
life
of
the
vehicle
as
well.
The
manufacturer
generally
does
not
need
to
include
scheduled
maintenance
or
other
routine
maintenance
under
the
emission
warranty.
See
the
regulation
language
for
a
detailed
description
of
the
components
that
are
considered
to
be
emission
related.
If
an
operator
makes
a
valid
warranty
claim
for
an
emission
related
component
during
the
warranty
period,
the
engine
manufacturer
is
generally
obligated
to
replace
the
component
at
no
charge
to
the
operator.
The
engine
manufacturer
may
deny
warranty
claims,
however,
if
the
operator
caused
the
component
failure
by
misusing
the
engine
or
failing
to
do
necessary
maintenance.
We
are
also
adopting
a
defect
reporting
requirement
that
applies
separate
from
the
emission
related
warranty
(
see
Section
VII.
F).
In
general,
defect
reporting
applies
when
a
manufacturer
discovers
a
pattern
of
component
failures,
whether
that
information
comes
from
warranty
claims,
voluntary
investigation
of
product
quality,
or
other
sources.
3.
Can
I
Use
Emission
Averaging
To
Show
That
I
Meet
Emission
Standards?
Many
of
our
mobile
source
emissioncontrol
programs
include
voluntary
use
of
emission
credits
to
facilitate
implementation
of
emission
controls.
An
emission
credit
program
is
an
important
factor
we
take
into
consideration
in
setting
emission
standards
that
are
appropriate
under
Clean
Air
Act
section
213.
An
emissioncredit
program
can
improve
the
technological
feasibility
and
reduce
the
cost
of
achieving
standards,
allowing
us
to
consider
a
more
stringent
emission
standard
than
might
otherwise
be
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Rules
and
Regulations
36
We
consider
an
engine
to
be
randomly
selected
if
it
undergoes
normal
assembly
and
manufacturing
procedures.
An
engine
is
not
randomly
selected
if
it
has
been
built
with
any
kind
of
special
components
or
procedures.
appropriate,
including
a
compliance
date
for
the
standards
earlier
than
would
otherwise
be
appropriate.
Manufacturers
gain
flexibility
in
product
planning
and
introduction
of
product
lines
meeting
a
new
standard.
Emission
credit
programs
also
create
an
incentive
for
the
early
introduction
of
new
technology,
which
allows
certain
engine
families
to
act
as
trailblazers
for
new
technology.
This
can
help
provide
valuable
information
to
manufacturers
on
the
technology
before
they
apply
the
technology
throughout
their
product
line.
This
early
introduction
of
clean
technology
improves
the
feasibility
of
achieving
the
standards
and
can
provide
valuable
information
for
use
in
other
regulatory
programs
that
may
benefit
from
similar
technologies.
Emission
credit
programs
may
involve
averaging,
banking,
or
trading.
Averaging
allows
a
manufacturer
to
certify
one
or
more
engine
families
at
emission
levels
above
the
applicable
emission
standards,
as
long
as
the
increased
emissions
from
that
engine
family
are
offset
by
one
or
more
engine
families
certified
below
the
applicable
standards.
The
over
complying
engine
families
generate
credits
that
are
used
by
the
under
complying
engine
families.
Compliance
is
determined
taking
into
account
differences
in
production
volume,
power
and
useful
life
among
engine
families.
The
average
of
all
the
engine
families
for
a
particular
manufacturer's
production
must
be
at
or
below
the
level
of
the
applicable
emission
standards.
This
calculation
generally
factors
in
sales
weighted
average
power,
production
volume,
and
useful
life.
Banking
allows
a
manufacturer
to
generate
emission
credits
and
bank
them
for
future
use
in
its
own
averaging
program
in
later
years.
Trading
allows
transfer
of
credits
to
another
company.
In
general,
a
manufacturer
choosing
to
participate
in
an
emission
credit
program
certifies
each
participating
engine
family
to
a
Family
Emission
Limit.
In
its
certification
application,
a
manufacturer
determines
a
separate
Family
Emission
Limit
for
each
pollutant
included
in
the
emissioncredit
program.
The
Family
Emission
Limit
selected
by
the
manufacturer
becomes
the
emission
standard
for
each
engine
in
that
engine
family.
Emission
credits
are
based
on
the
difference
between
the
emission
standard
that
applies
to
the
family
and
the
Family
Emission
Limit.
Manufacturers
must
meet
the
Family
Emission
Limit
for
all
emission
testing
of
any
engine
in
that
family.
At
the
end
of
the
model
year,
manufacturers
must
show
that
the
net
effect
of
all
their
engine
families
participating
in
the
emission
credit
program
is
a
zero
balance
or
a
net
positive
balance
of
credits.
A
manufacturer
may
generally
choose
to
include
only
a
single
pollutant
from
an
engine
family
in
the
emission
credit
program
or,
alternatively,
to
establish
a
Family
Emission
Limit
for
each
of
the
regulated
pollutants.
Refer
to
the
program
discussions
below
for
more
information
about
emission
credit
provisions
for
individual
engine
categories.
4.
What
Are
the
Production
Line
Testing
Requirements?
We
are
adopting
production
line
testing
requirements
for
recreational
marine
diesel
engines,
recreational
vehicles,
and
Large
SI
engines.
Manufacturers
must
routinely
test
production
line
engines
to
help
ensure
that
newly
assembled
engines
control
emissions
at
least
as
well
as
the
emission
data
engines
tested
for
certification.
Production
line
testing
serves
as
a
quality
control
step,
providing
information
to
allow
early
detection
of
any
problems
with
the
design
or
assembly
of
freshly
manufactured
engines.
This
is
different
than
selective
enforcement
auditing,
in
which
we
would
give
a
test
order
for
more
rigorous
testing
for
a
small
subset
of
production
line
engines
in
a
particular
engine
family
(
see
Section
VII.
E).
Production
line
testing
requirements
are
already
common
to
several
categories
of
nonroad
engines
as
part
of
their
emission
control
program.
If
an
engine
fails
to
meet
an
emission
standard,
the
manufacturer
must
modify
it
to
bring
that
specific
engine
into
compliance.
Manufacturers
may
adjust
the
engine
family's
Family
Emission
Limit
to
take
into
account
the
results
from
production
line
testing
(
if
applicable).
If
too
many
engines
exceed
emission
standards,
this
indicates
it
is
more
of
a
family
wide
problem
and
the
manufacturer
must
correct
the
problem
for
all
affected
engines.
The
remedy
may
involve
changes
to
assembly
procedures
or
engine
design,
but
the
manufacturer
must,
in
any
case,
do
sufficient
testing
to
show
that
the
engine
family
complies
with
emission
standards
before
producing
more
engines.
The
remedy
may
also
need
to
address
engines
already
produced
since
the
last
showing
that
production
line
engines
met
emission
standards.
The
production
line
testing
programs
for
Large
SI
engines
and
for
recreational
vehicles
depend
on
the
Cumulative
Sum
(
CumSum)
statistical
process
for
determining
the
number
of
engines
a
manufacturer
needs
to
test
(
see
the
regulations
for
the
specific
calculation
methodology).
Each
manufacturer
generally
selects
engines
randomly
at
the
beginning
of
each
new
quarter.
36
If
engines
must
be
tested
at
a
facility
where
final
assembly
is
not
yet
completed,
manufacturers
must
randomly
select
engine
components
and
assemble
the
test
engine
according
to
their
established
assembly
instructions.
The
Cumulative
Sum
program
uses
the
emission
results
to
calculate
the
number
of
tests
required
for
the
remainder
of
the
year
to
reach
a
pass
or
fail
determination
for
production
line
testing.
If
tested
engines
have
emissions
close
to
the
standard,
the
statistical
sampling
method
calls
for
an
increased
number
of
tests
to
show
whether
to
make
a
pass
or
fail
determination
for
the
engine
family.
The
remaining
number
of
tests
is
recalculated
after
the
manufacturer
tests
each
engine.
Engines
selected
should
cover
the
broadest
range
of
production
configurations
possible.
Tests
should
also
be
distributed
evenly
throughout
the
sampling
period
to
the
extent
possible.
If
an
engine
family
fails
the
production
line
testing
criteria,
we
may
suspend
the
Certificate
of
Conformity.
Under
the
CumSum
approach,
individual
engines
can
exceed
the
emission
standards
without
causing
the
whole
engine
family
to
exceed
the
production
line
testing
criteria.
The
production
line
testing
criteria
are
designed
to
determine
if
there
is
a
problem
that
applies
broadly
across
the
engine
family.
Whether
or
not
the
production
line
testing
criteria
are
met,
manufacturers
must
adjust
or
repair
every
failing
engine
and
retest
it
to
show
that
it
meets
the
emission
standards.
Note
also
that
all
production
line
emission
measurements
must
be
included
in
the
periodic
reports
to
us.
This
includes
any
type
of
screening
or
surveillance
tests
(
including
ppm
measurements),
all
data
points
for
evaluating
whether
an
engine
controls
emissions
``
off
cycle,''
and
any
engine
tests
that
exceed
the
minimum
required
level
of
testing.
The
regulations
allow
us
to
reduce
testing
requirements
for
engine
families
that
consistently
pass
the
productionline
testing
criteria.
For
engine
families
that
pass
all
of
the
production
line
test
requirements
for
two
consecutive
years,
the
manufacturer
may
request
a
reduced
testing
rate.
The
minimum
testing
rate
is
one
test
per
engine
family
for
one
year.
Our
approval
for
a
reduced
testing
rate
may
be
limited
to
a
single
model
year,
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Rules
and
Regulations
37
Almost
all
recreational
vehicles
are
equipped
with
spark
ignition
engines.
Any
diesel
engines
used
in
these
applications
must
meet
our
emission
standards
for
nonroad
diesel
engines.
but
manufacturers
may
continue
to
request
reduced
testing
rates.
As
we
have
concluded
in
other
engine
programs,
some
manufacturers
may
have
unique
circumstances
that
call
for
different
methods
to
show
that
production
engines
comply
with
emission
standards.
A
manufacturer
may
therefore
suggest
an
alternate
plan
for
testing
production
line
engines,
as
long
as
the
alternate
program
is
as
effective
at
ensuring
that
the
engines
will
comply.
A
manufacturer's
petition
to
use
an
alternate
plan
should
address
the
need
for
the
alternative
and
should
justify
any
changes
from
the
regular
testing
program.
The
petition
must
also
describe
in
detail
the
equivalent
thresholds
and
failure
rates
for
the
alternate
plan.
If
we
approve
the
plan,
we
will
use
these
criteria
to
determine
when
an
engine
family
passes
or
fails
the
production
line
testing
criteria.
It
is
important
to
note
that
this
allowance
is
intended
only
as
a
flexibility,
and
is
not
intended
to
affect
the
stringency
of
the
standards
or
the
production
line
testing
program.
Refer
to
the
specific
program
discussions
below
for
additional
information
about
production
line
testing
for
different
types
of
engines.
D.
Other
Concepts
1.
What
Are
Emission
Related
Installation
Instructions?
Manufacturers
selling
loose
engines
to
equipment
manufacturers
must
develop
a
set
of
emission
related
installation
instructions.
These
instructions
include
anything
the
installer
needs
to
know
to
ensure
that
the
engine
operates
within
its
certified
design
configuration.
For
example,
the
installation
instructions
could
specify
a
total
capacity
needed
from
the
engine
cooling
system,
placement
of
catalysts
after
final
assembly,
or
specification
of
parts
needed
to
control
evaporative
or
permeation
emissions.
We
approve
emission
related
installation
instructions
as
part
of
the
certification
process.
If
equipment
manufacturers
fail
to
follow
the
established
emissionrelated
installation
instructions,
we
will
consider
this
tampering,
which
may
subject
them
to
significant
civil
penalties.
Refer
to
the
program
discussions
below
for
more
information
about
specific
provisions
related
to
installation
instructions.
2.
Are
There
Special
Provisions
for
Small
Manufacturers
of
These
Engines
and
Vehicles?
The
scope
of
this
rule
includes
many
engine
and
vehicle
manufacturers
that
have
previously
not
been
subject
to
our
mobile
source
regulations
or
certification
process.
Some
of
these
manufacturers
are
small
businesses,
with
unique
concerns
relating
to
the
compliance
burden
from
the
general
regulating
program.
The
sections
describing
the
emission
control
program
include
discussion
of
special
compliance
provisions
designed
to
address
this
for
the
different
engine
categories.
III.
Recreational
Vehicles
and
Engines
A.
Overview
We
are
adopting
new
exhaust
emission
standards
for
snowmobiles,
off
highway
motorcycles,
and
all
terrain
vehicles
(
ATVs).
The
engines
used
in
these
vehicles
are
a
subset
of
nonroad
SI
engines.
37
In
our
program
to
set
exhaust
emission
standards
for
nonroad
sparkignition
engines
below
19
kW
(
Small
SI),
we
excluded
recreational
vehicles
because
they
have
different
design
characteristics
and
usage
patterns
than
certain
other
engines
in
the
Small
SI
category.
For
example,
engines
typically
found
in
the
Small
SI
category
are
used
in
lawn
mowers,
chainsaws,
trimmers,
and
other
lawn
and
garden
applications.
These
engines
tend
to
have
low
power
outputs
and
operate
at
constant
loads
and
speeds,
whereas
recreational
vehicles
can
have
high
power
outputs
with
highly
variable
engine
loads
and
speeds.
This
suggests
that
these
engines
should
be
regulated
differently
than
Small
SI
engines.
In
the
same
way,
we
treat
snowmobiles,
off
highway
motorcycles,
and
ATVs
separately
from
our
Large
SI
engine
program,
which
is
described
in
Section
V.
Recreational
vehicles
that
are
not
snowmobiles,
offhighway
motorcycles,
or
ATVs,
will
be
subject
to
the
standards
that
otherwise
apply
to
small
nonroad
spark
ignition
engines
(
see
Section
III.
B.
2).
We
are
adopting
exhaust
emission
standards
for
HC
and
CO
from
all
recreational
vehicles.
We
are
adopting
an
additional
requirement
to
control
NOX
from
off
highway
motorcycles
and
ATVs.
We
believe
that
vehicle
and
engine
manufacturers
will
be
able
to
use
technology
already
established
for
other
types
of
engines,
such
as
highway
motorcycles,
small
spark
ignition
engines,
and
marine
engines,
to
meet
these
standards.
We
recognize
that
some
small
businesses
manufacture
recreational
vehicles;
we
are
therefore
adopting
several
special
compliance
provisions
to
reduce
the
burden
of
emission
regulations
on
small
businesses.
1.
What
Are
Recreational
Vehicles
and
Who
Makes
Them?
We
are
adopting
new
exhaust
emission
standards
for
off
highway
motorcycles,
ATVs,
and
snowmobiles.
Eight
large
manufacturers
dominate
the
sales
of
these
recreational
vehicles.
Of
these
eight
manufacturers,
seven
of
them
manufacture
two
or
more
of
the
three
main
types
of
recreational
vehicles.
For
example,
there
are
four
companies
that
manufacture
both
offhighway
motorcycles
and
ATVs.
There
are
three
companies
that
manufacture
ATVs
and
snowmobiles;
one
company
manufactures
all
three.
These
eight
companies
represent
approximately
95
percent
of
all
domestic
sales
of
recreational
vehicles.
a.
Off
highway
motorcycles.
Motorcycles
are
two
wheeled,
selfpowered
vehicles
that
come
in
a
variety
of
configurations
and
styles.
Offhighway
motorcycles
are
similar
in
appearance
to
highway
motorcycles,
but
there
are
several
important
distinctions
between
the
two
types
of
machines.
Offhighway
motorcycles
are
not
street
legal
and
are
primarily
operated
on
public
and
private
lands
over
trails
and
open
areas.
A
significant
number
are
used
in
competition
events.
Off
highway
motorcycles
tend
to
be
much
smaller,
lighter
and
more
maneuverable
than
their
larger
highway
counterparts.
They
are
equipped
with
relatively
smalldisplacement
single
cylinder
two
or
four
stroke
engines
ranging
from
48
to
650
cubic
centimeters
(
cc)
in
size.
The
exhaust
systems
for
off
highway
motorcycles
are
distinctively
routed
high
on
the
frame
to
prevent
damage
from
brush,
rocks,
and
water.
Offhighway
motorcycles
are
designed
to
be
operated
over
varying
surfaces,
such
as
dirt,
sand,
or
mud,
and
are
equipped
with
knobby
tires
to
give
better
traction
in
off
road
conditions.
Unlike
highway
motorcycles,
off
highway
motorcycles
have
fenders
mounted
far
from
the
wheels
and
closer
to
the
rider
to
keep
dirt
and
mud
from
spraying
the
rider
and
clogging
between
the
fender
and
tire.
Off
highway
motorcycles
are
also
equipped
with
more
advanced
suspension
systems
than
those
for
highway
motorcycles.
This
allows
the
operator
to
ride
over
obstacles
and
make
jumps
safely.
Five
companies
dominate
sales
of
offhighway
motorcycles.
They
are
longestablished
large
corporations
that
manufacture
several
different
products
including
highway
and
off
highway
motorcycles.
These
five
companies
account
for
90
to
95
percent
of
all
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Vol.
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217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
38
Notice
to
Off
Highway
Recreational
Vehicle
Manufacturers
and
All
Other
Interested
Parties
Regarding
Alternate
Emission
Standards
for
All
Terrain
Vehicles,
Mail
Out
#
95
16,
April
28,
1995,
California
ARB
(
Docket
A
2000
01,
document
II
D
06).
domestic
sales
of
off
highway
motorcycles.
There
are
also
several
relatively
small
companies
that
manufacture
off
highway
motorcycles,
many
of
which
specialize
in
competition
machines.
b.
All
terrain
vehicles.
The
earliest
ATVs
were
three
wheeled
off
highway
models
with
large
balloon
tires
that
existed
in
the
early
1970'
s.
Due
to
safety
concerns,
the
three
wheeled
ATVs
were
phased
out
in
the
mid
1980s
and
replaced
by
the
current
and
more
popular
four
wheeled
vehicle
known
as
``
quad
runners''
or
simply
``
quads.''
Quads
resemble
the
earlier
threewheeled
ATVs
except
that
the
single
front
wheel
was
replaced
with
two
wheels.
The
ATV
steering
system
uses
motorcycle
handlebars,
rather
than
a
steering
wheel.
The
operator
sits
on
and
rides
the
quad
much
like
a
motorcycle.
The
engines
used
in
quads
tend
to
be
very
similar
to
those
used
in
offhighway
motorcycles
relatively
small,
single
cylinder
two
or
four
stroke
engines.
Quads
are
typically
divided
into
utility
and
sport
models.
The
utility
quads
are
designed
for
multi
function
use
and
have
the
ability
to
perform
many
utility
functions,
such
as
plowing
snow,
tilling
gardens,
and
mowing
lawns
in
addition
to
use
for
recreational
riding.
They
are
typically
heavier
and
equipped
with
relatively
large
fourstroke
engines
and
automatic
transmissions
with
a
reverse
gear.
Sport
quads
are
smaller
and
lighter
and
designed
primarily
for
recreational
purposes.
They
are
equipped
with
two
or
four
stroke
engines
and
manual
transmissions.
Presently
utility
ATVs
comprise
about
75
percent
of
the
market
and
sport
models
about
25
percent.
Of
all
of
the
types
of
recreational
vehicles,
ATVs
have
the
largest
number
of
major
manufacturers.
All
but
one
of
the
companies
noted
above
for
offhighway
motorcycles
and
below
for
snowmobiles
are
significant
ATV
producers.
These
seven
companies
represent
over
95
percent
of
total
domestic
ATV
sales.
The
remaining
5
percent
of
sales
come
from
importers,
which
tend
to
import
less
expensive,
youth
oriented
ATVs.
As
discussed
below,
we
are
requiring
utility
vehicles
capable
of
speeds
above
25
mph
to
comply
the
regulations
for
ATVs.
c.
Snowmobiles.
Snowmobiles,
also
referred
to
as
``
sleds,''
are
tracked
vehicles
designed
to
operate
over
snow.
Snowmobiles
have
some
similarities
to
off
highway
motorcycles
and
ATVs.
A
snowmobile
rider
sits
on
and
rides
a
snowmobile
similar
to
an
ATV.
Snowmobiles
use
high
powered
two
and
three
cylinder
two
stroke
engines
that
look
similar
to
off
highway
motorcycle
engines.
Rather
than
wheels,
snowmobiles
are
propelled
by
a
track
system
similar
to
what
is
used
on
a
bulldozer.
The
snowmobile
is
steered
by
two
skis
at
the
front
of
the
sled.
Snowmobiles
use
handlebars
similar
to
off
highway
motorcycles
and
ATVs.
The
typical
snowmobile
seats
two
riders
comfortably.
Over
the
years,
snowmobile
performance
has
steadily
increased
to
the
point
that
many
snowmobiles
currently
have
engines
over
100
horsepower
and
are
capable
of
exceeding
100
miles
per
hour.
The
definition
for
snowmobiles
includes
a
limit
of
1.5
meter
width
to
differentiate
conventional
snowmobiles
from
icegrooming
machines
and
snow
coaches,
which
use
very
different
engines.
There
are
four
major
snowmobile
manufacturers,
accounting
for
more
than
99
percent
of
all
domestic
sales.
The
remaining
sales
come
from
very
small
manufacturers
who
tend
to
specialize
in
high
performance
designs.
d.
Other
recreational
vehicles.
Currently,
our
Small
SI
nonroad
engine
regulations
cover
all
recreational
engines
that
are
under
19
kW
(
25
hp)
and
have
either
an
installed
speed
governor
or
a
maximum
engine
speed
less
than
5,000
revolutions
per
minute
(
rpm).
Recreational
vehicles
currently
covered
by
the
Small
SI
standards
include
go
carts,
golf
carts,
and
small
mini
bikes.
Although
some
off
highway
motorcycles,
ATVs
and
snowmobiles
have
engines
with
rated
horsepower
less
than
19
kW,
they
all
have
maximum
engine
speeds
greater
than
5,000
rpm.
Thus
they
have
not
been
included
in
the
Small
SI
regulations.
The
only
other
types
of
small
recreational
engines
not
covered
by
the
Small
SI
rule
are
those
engines
under
19
kW
that
aren't
governed
and
have
maximum
engine
speed
of
at
least
5,000
rpm.
There
are
relatively
few
such
vehicles
with
recreational
engines
not
covered
by
the
Small
SI
regulations.
The
best
example
of
vehicles
that
fit
in
this
category
are
stand
on
scooters
and
skateboards
that
have
been
equipped
with
very
small
gasoline
spark
ignition
engines.
The
engines
used
on
these
vehicles
are
typically
the
same
as
those
used
in
string
trimmers
or
other
lawn
and
garden
equipment,
which
are
covered
under
the
Small
SI
regulations.
Because
these
engines
are
generally
already
covered
by
the
Small
SI
regulations
and
are
the
same
as,
or
very
similar
to,
engines
as
those
used
in
lawn
and
garden
applications,
we
are
revising
the
Small
SI
rules
to
cover
these
engines
under
the
Small
SI
regulations.
To
avoid
any
problems
in
transitioning
to
meet
emission
standards,
we
are
applying
these
standards
beginning
in
2006.
We
did
not
receive
any
comments
on
this
approach.
2.
What
Is
the
Regulatory
History
for
Recreational
Vehicles?
The
California
Air
Resources
Board
(
California
ARB)
established
standards
for
off
highway
motorcycles
and
ATVs,
which
took
effect
in
January
1997
(
1999
for
vehicles
with
engines
of
90
cc
or
less).
California
has
not
adopted
standards
for
snowmobiles.
The
standards,
shown
in
Table
III.
A
1,
are
based
on
the
highway
motorcycle
chassis
test
procedures.
Manufacturers
may
certify
ATVs
to
optional
standards,
also
shown
in
Table
III.
A
1,
which
are
based
on
the
utility
engine
test
procedure.
38
This
is
the
test
procedure
over
which
Small
SI
engines
are
tested.
The
stringency
level
of
the
standards
was
based
on
the
emission
performance
of
small
four
stroke
engines
and
advanced
two
stroke
engines
with
a
catalytic
converter.
California
ARB
anticipated
that
the
standards
would
be
met
initially
by
using
high
performance
four
stroke
engines.
III.
A
1
CALIFORNIA
OFF
HIGHWAY
MOTORCYCLE
AND
ATV
STANDARDS
FOR
MODEL
YEAR
1997
AND
LATER
[
1999
and
later
for
engines
at
or
below
90
cc]
HC
NOX
CO
PM
Off
highway
motorcycle
and
ATV
standards
(
g/
km)
........................................
a
1.2
........................
15
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8,
2002
/
Rules
and
Regulations
39
Initial
Statement
of
Reasons,
Public
Hearing
to
Consider
Amendments
to
the
California
Regulations
for
New
1997
and
Later
Off
highway
Recreational
Vehicles
and
Engines,
California
ARB,
October
23,
1998
(
Docket
A
2000
01,
document
II
D
08).
40
Otto
cycle
is
another
name
for
a
reciprocating,
internal
combustion
engine
that
uses
a
spark
to
ignite
a
homogeneous
air
and
fuel
mixture,
in
which
air
fuel
mixing
may
occur
inside
or
outside
the
combustion
chamber.
41
Snowmobiles
use
continuously
variable
transmissions,
which
tend
to
operate
like
torque
converters.
HC
+
NOX
CO
PM
Optional
standards
for
ATV
engines
below
225
cc
(
g/
bhp
hr)
...................................................
a12.0
300
........................
Optional
standards
for
ATV
engines
at
or
above
225
cc
(
g/
bhp
hr)
..........................................
a10.0
300
........................
a
Corporate
average
standard.
California
revisited
the
program
because
a
lack
of
certified
off
highway
motorcycles
from
manufacturers
was
reportedly
creating
economic
hardship
for
dealerships.
The
number
of
certified
off
highway
motorcycle
models
was
particularly
inadequate.
39
In
1998,
California
revised
the
program,
allowing
the
uncertified
products
in
off
highway
vehicle
recreation
areas
with
regional/
seasonal
use
restrictions.
Currently,
noncomplying
vehicles
may
be
sold
in
California
and
used
in
attainment
areas
year
round
and
in
nonattainment
areas
during
months
when
exceedances
of
the
state
ozone
standard
are
not
expected.
For
enforcement
purposes,
certified
and
uncertified
products
are
identified
with
green
and
red
stickers,
respectively.
Only
about
one
third
of
off
highway
motorcycles
selling
in
California
are
certified.
All
certified
products
have
four
stroke
engines.
B.
Engines
Covered
by
This
Rule
We
are
adopting
new
emission
standards
for
new
off
highway
motorcycles,
ATVs,
and
snowmobiles.
(
We
are
also
applying
existing
Small
SI
emission
standards
to
other
recreational
equipment,
as
described
above.)
The
engines
used
in
recreational
vehicles
tend
to
be
small,
air
or
liquid
cooled,
reciprocating
Otto
cycle
engines
that
operate
on
gasoline.
40
Engines
used
in
vehicle
applications
experience
engine
performance
that
is
characterized
by
highly
transient
operation,
with
a
wide
range
of
engine
speed
and
load
capability.
Maximum
engine
speed
are
typically
well
above
5,000
rpm.
Also,
with
the
exception
of
snowmobiles,
the
vehicles
are
typically
equipped
with
transmissions
rather
than
torque
converters
to
ensure
performance
under
a
variety
of
operating
conditions.
41
1.
Two
Stroke
vs.
Four
Stroke
Engines
The
engines
used
by
recreational
vehicles
can
be
separated
into
two
distinct
designs:
two
stroke
and
fourstroke
The
distinction
between
twostroke
and
four
stroke
engines
is
important
for
emissions
because
twostroke
engines
tend
to
emit
much
greater
amounts
of
unburned
HC
and
PM
than
four
stroke
engines
of
similar
size
and
power.
Two
stroke
engines
have
lower
NOX
emissions
than
do
four
stroke
engines
because
they
experience
a
significant
amount
of
internal
exhaust
gas
recirculation
resulting
from
exhaust
gases
being
drawn
back
into
the
combustion
chamber
on
the
piston's
downward
stroke
while
the
exhaust
port
is
uncovered.
Exhaust
gas
is
inert
and
displaces
fresh
fuel
and
air
that
could
otherwise
be
combusted,
which
creates
lower
in
cylinder
temperatures
and
thus
less
NOX.
Two
stroke
engines
also
have
greater
fuel
consumption
than
fourstroke
engines,
but
they
also
tend
to
have
higher
power
output
per
unit
displacement,
lighter
weight,
and
better
cold
starting
performance.
These,
and
other
characteristics,
tend
to
make
twostroke
engines
popular
as
a
power
unit
for
recreational
vehicles.
With
the
exception
of
a
few
youth
and
touring
models,
almost
all
snowmobiles
use
two
stroke
engines.
Currently,
about
63
percent
of
all
off
highway
motorcycles
(
predominantly
in
high
performance,
youth,
and
entry
level
bikes)
and
20
percent
of
all
ATVs
sold
in
the
United
States
use
two
stroke
engines.
The
basis
for
the
differences
in
engine
performance
and
exhaust
emissions
between
two
stroke
and
four
stroke
engines
can
be
found
in
the
fundamental
differences
in
how
twostroke
and
four
stroke
engines
operate.
Four
stroke
operation
takes
place
in
four
distinct
steps:
intake,
compression,
power,
and
exhaust.
Each
step
corresponds
to
one
up
or
down
stroke
of
the
piston
or
180
°
of
crankshaft
rotation.
The
first
step
of
the
cycle
is
for
an
intake
valve
in
the
combustion
chamber
to
open
during
the
intake
stroke,
allowing
a
mixture
of
air
and
fuel
to
be
drawn
into
the
cylinder
while
the
piston
moves
down
the
cylinder.
The
intake
valve
then
closes
and
the
momentum
of
the
crankshaft
causes
the
piston
to
move
back
up
the
cylinder,
compressing
the
air
and
fuel
mixture.
At
the
very
end
of
the
compression
stroke,
the
air
and
fuel
mixture
is
ignited
by
a
spark
from
a
spark
plug
and
begins
to
burn.
As
the
air
and
fuel
mixture
burns,
increasing
temperature
and
pressure
cause
the
piston
to
move
back
down
the
cylinder.
This
is
referred
to
as
the
``
power''
stroke.
At
the
bottom
of
the
power
stroke,
an
exhaust
valve
opens
in
the
combustion
chamber
and
as
the
piston
moves
back
up
the
cylinder,
the
burnt
gases
are
pushed
out
through
the
exhaust
valve
to
the
exhaust
manifold,
and
the
cycle
is
complete.
In
a
four
stroke
engine,
combustion
and
the
resulting
power
stroke
occur
only
once
every
two
revolutions
of
the
crankshaft.
In
a
two
stroke
engine,
combustion
occurs
every
revolution
of
the
crankshaft.
Two
stroke
engines
eliminate
the
intake
and
exhaust
strokes,
leaving
only
compression
and
power
strokes.
This
is
due
to
the
fact
that
two
stroke
engines
do
not
use
intake
and
exhaust
valves.
Instead,
they
have
intake
and
exhaust
ports
in
the
sides
of
the
cylinder
walls.
With
a
twostroke
engine,
as
the
piston
approaches
the
bottom
of
the
power
stroke,
it
uncovers
exhaust
ports
in
the
wall
of
the
cylinder.
The
high
pressure
combustion
gases
blow
into
the
exhaust
manifold.
As
the
piston
gets
closer
to
the
bottom
of
the
power
stroke,
the
intake
ports
are
uncovered,
and
fresh
mixture
of
air
and
fuel
are
forced
into
the
cylinder
while
the
exhaust
ports
are
still
open.
Exhaust
gas
is
``
scavenged''
or
forced
into
the
exhaust
by
the
pressure
of
the
incoming
charge
of
fresh
air
and
fuel.
In
the
process,
however,
some
mixing
between
the
exhaust
gas
and
the
fresh
charge
of
air
and
fuel
takes
place,
so
that
some
of
the
fresh
charge
is
also
emitted
in
the
exhaust.
Losing
part
of
the
fuel
out
of
the
exhaust
during
scavenging
causes
very
high
hydrocarbon
emission
characteristics
of
two
stroke
engines.
The
other
major
reason
for
high
HC
emissions
from
twostroke
engines
is
their
tendency
to
misfire
under
low
load
conditions
due
to
greater
combustion
instability.
2.
Applicability
of
Small
SI
Regulations
In
our
regulations
for
Small
SI
engines,
we
established
criteria,
such
as
rated
engine
speed
at
or
above
5,000
rpm
and
the
use
of
a
speed
governor,
that
excluded
engines
used
in
certain
types
of
recreational
vehicles
(
see
40
CFR
90.1(
b)(
5)).
Engines
used
in
some
other
types
of
recreational
vehicles
may
be
covered
by
the
Small
SI
standards,
depending
on
the
characteristics
of
the
engines.
For
example,
lawnmower
type
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217
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Friday,
November
8,
2002
/
Rules
and
Regulations
engines
used
in
go
carts
are
typically
covered
by
the
Small
SI
standards
because
they
don't
operate
above
5000
rpm.
Similarly,
engines
used
in
golf
carts
are
included
in
the
Small
SI
program.
As
discussed
above,
we
are
revising
the
Small
SI
regulations
to
include
all
recreational
engines
except
those
in
off
highway
motorcycles,
ATVs,
snowmobiles,
and
hobby
engines.
Golf
cart
and
go
cart
engines
will
remain
in
the
Small
SI
program
because
the
vehicles
are
not
designed
for
operation
over
rough
terrain
and
do
not
meet
the
definition
of
ATV.
We
are
accordingly
removing
the
5,000
rpm
and
speed
governor
criteria
from
the
applicability
provisions
of
the
Small
SI
regulations.
3.
Utility
Vehicles
We
proposed
to
define
ATV
as
a
``
nonroad
vehicle
with
three
or
more
wheels
and
a
seat
designed
for
operation
over
rough
terrain
and
intended
primarily
for
transportation'',
and
that
it
would
include
``
both
land
based
and
amphibious
vehicles''.
We
requested
comment
on
the
proposed
definition
and
based
on
comments,
we
are
modifying
the
definition
to
clearly
exclude
utility
vehicles
not
capable
of
reaching
25
mph.
Utility
vehicles
differ
from
ATVs
in
several
ways.
As
stated
earlier,
an
ATV
is
operated
and
ridden
very
similar
to
a
motorcycle,
with
the
rider
straddling
the
seat
and
using
handlebars
to
steer
the
vehicle.
The
throttle
and
brakes
are
located
on
the
handle
bars,
similar
to
a
motorcycle
and
snowmobile.
Utility
vehicles
look
and
operate
very
similarly
to
golf
carts.
The
operator
sits
on
a
bench
seat
with
a
back
support
that
holds
two
or
more
passengers.
Rather
than
handlebars,
utility
vehicles
use
a
steering
wheel
and
have
throttle
and
brake
pedals
on
the
floor,
similar
to
an
automobile.
Utility
vehicles
also
typically
have
a
cargo
box
or
bed
(
similar
to
that
found
on
a
pickup
truck)
used
for
hauling
cargo.
We
define
an
off
highway
utility
vehicle
as
a
``
nonroad
vehicle
that
has
four
or
more
wheels,
seating
for
two
or
more
persons,
is
designed
for
operation
over
rough
terrain,
and
has
either
a
rear
payload
of
350
pounds
or
more
or
seating
for
six
or
more
passengers.''
We
are
requiring
utility
vehicles
capable
of
high
speed
operation
(
speeds
greater
than
25
mph)
to
meet
ATV
standards.
For
utility
vehicles
that
are
permanently
governed
and
not
capable
of
reaching
25
mph,
manufacturers
must
either
continue
to
certify
them
to
the
Small
SI
standards
(
or
Large
SI
standards,
if
applicable)
or
optionally
certify
them
to
the
new
ATV
standards.
We
received
comments
from
the
Outdoor
Power
Equipment
Institute
(
OPEI)
that
the
definition
should
be
clarified
to
exclude
utility
vehicles.
Most
utility
vehicles
are
equipped
with
engines
that
are
currently
required
to
meet
EPA
Small
SI
standards.
OPEI
commented
that
utility
vehicles
are
designed
specifically
for
work
related
tasks
and
are
equipped
with
seating
for
passengers,
a
bed
for
cargo,
and
ridingmower
style
controls.
The
industry
differentiates
between
utility
vehicles
based
on
vehicle
speed.
The
vast
majority
of
utility
vehicles
are
considered
``
low
speed
utility
vehicles''
(
LUVs)
and
are
vehicle
speed
governed
with
maximum
speed
of
less
than
25
mph.
The
engines
used
in
such
vehicles
are
generally
below
25
hp
and
are
typically
used
in
other
lawn
and
garden
or
utility
applications
such
as
generators
or
lawn
tractors.
The
engines
differ
significantly
from
those
used
in
recreational
products
which
are
designed
for
higher
rpm
operation
with
an
emphasis
on
higher
performance.
OPEI
also
provided
comment
on
a
newer
type
of
utility
vehicle,
which
uses
a
more
powerful
(
over
19kW)
ATVbased
engine
and
is
capable
of
speeds
of
up
to
40
mph.
We
are
finalizing
the
approach
described.
The
engines
used
in
lowspeed
utility
vehicles
are
more
similar
in
design
and
use
to
utility
engines
than
ATVs.
The
engines
used
to
power
these
vehicles
are
often
used
in
other
utility
applications,
such
as
lawn
and
garden
tractors
and
generators
and
are
typically
produced
by
companies
that
specialize
in
utility
and
lawn
equipment
rather
than
power
sport
vehicles.
These
products
are
already
certified
to
the
Small
SI
standards.
However,
we
have
some
concerns
with
continuing
to
use
the
Small
SI
program
test
cycle
for
engines
used
in
applications
that
operate
at
broad
engine
speeds.
The
cycle
was
developed
primarily
for
push
lawnmowers
and
other
equipment
that
operates
in
a
narrow
band
of
engine
speeds.
The
Small
SI
test
cycle
measures
emissions
only
at
a
single
high
engine
speed.
We
are
concerned
that
the
Small
SI
test
cycle
may
not
achieve
the
same
emission
reductions
for
off
highway
utility
vehicles
in
use
as
it
would
for
lawnmowers,
especially
as
more
stringent
standards
go
into
effect.
The
concern
also
applies
to
other
large
rideon
equipment
in
the
Small
SI
program,
such
as
riding
lawn
mowers,
where
engine
speed
is
inherently
variable.
While
the
ATV
program
may
not
be
appropriate
for
these
low
speed
utility
applications
due
to
operating
and
design
differences,
the
Small
SI
program
as
it
is
currently
designed
may
not
be
completely
appropriate
either.
Since
we
did
not
propose
changes
for
the
Small
SI
program
which
currently
applies
to
utility
vehicles
and
need
to
further
study
the
issues,
we
are
not
finalizing
such
changes
to
the
Small
SI
program
in
this
Final
Rule.
We
plan
to
continue
to
study
the
issue
and,
if
necessary,
address
it
through
a
future
rulemaking
for
the
Small
SI
program.
In
addition
to
test
cycle,
there
are
other
reasons
we
plan
to
continue
to
examine
the
appropriateness
of
the
Small
SI
program
for
large
ride
on
equipment.
With
respect
to
useful
life,
we
are
concerned
that
off
highway
utility
vehicles
may
be
designed
to
last
significantly
longer
than
the
typical
lawnmower.
40
CFR
90.105
specifies
useful
life
values
that
vary
by
application
with
the
longest
useful
life
being
1000
hours.
It
is
not
clear
that
this
maximum
value
is
high
enough
to
address
the
expected
life
of
in
use
offhighway
utility
vehicles,
especially
those
that
are
used
commercially.
Finally,
with
respect
to
the
level
of
the
standards,
we
are
concerned
about
the
relative
stringency
of
the
Small
SI
standards
relative
to
the
long
term
standards
for
ATVs
and
other
nonroad
vehicles.
Nevertheless,
given
the
lowspeed
operation
of
these
vehicles,
and
other
differences,
we
do
not
believe
that
they
should
be
treated
the
same
as
higher
speed
ATVs.
We
did
not
propose
changes
for
the
Small
SI
program
to
address
the
above
issues
and
need
to
study
them
further.
However,
these
vehicles
are
unique
in
many
ways,
and
should
be
addressed
in
a
future
rulemaking.
Given
the
utility
nature
of
the
lowspeed
vehicles,
we
believe
that
at
least
for
now,
it
is
appropriate
to
continue
to
certify
them
under
40
CFR
part
90.
For
vehicles
capable
of
higher
speeds
(
e.
g.,
greater
than
25
mph),
the
engine
designs
and
vehicle
in
use
operation
is
likely
to
be
more
like
ATVs.
The
test
procedures
and
standards
for
ATVs
will
better
fit
these
high
speed
vehicles
than
those
in
the
Small
SI
program.
For
regulatory
purposes,
we
are
defining
an
offhighway
utility
vehicle
as
a
nonroad
vehicle
that
has
four
or
more
wheels,
seating
for
two
or
more
persons,
is
designed
for
operation
over
rough
terrain,
and
has
either
a
rear
payload
capacity
of
350
pounds
or
more
or
total
seating
for
six
or
more
passengers.
4.
Hobby
Engines
The
Small
SI
rule
categorized
sparkignition
engines
used
in
model
cars,
boats,
and
airplanes
as
recreational
engines
and
exempted
them
from
the
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8,
2002
/
Rules
and
Regulations
42
80
FR
24292,
April
25,
2000.
43
Comments
submitted
by
Hobbico
on
behalf
of
Great
Plains
Model
Distributors
and
Radio
Control
Hobby
Trade
Association,
February
5,
2001,
Docket
A
2000
01,
document
II
D
58.
44
Hobby
engines
with
glow
plugs
are
considered
compression
ignition
(
diesel)
engines
because
they
lack
a
spark
ignition
system
and
a
throttle
(
see
the
definition
of
compression
ignition,
40
CFR
89.2).
The
nonroad
diesel
engine
regulations
40
CFR
part
89
generally
do
not
apply
to
hobby
engines,
so
these
engines
are
unregulated.
45
Comments
submitted
by
Hobbico
on
behalf
of
Great
Plains
Model
Distributors
and
Radio
Control
Hobby
Trade
Association,
February
5,
2001,
Docket
A
2000
01,
document
II
D
58.
46
E
mail
from
Carl
Maroney
of
the
Academy
of
Model
Aeronautics
to
Christopher
Lieske,
of
EPA,
June
4,
2001,
Docket
A
2000
01,
document
II
G
144.
47
Comments
submitted
by
Hobbico
on
Behalf
of
Great
Plains
Model
Distributors
and
Radio
Control
Hobby
Trade
Association,
February
5,
2001,
Docket
A
2000
01,
document
II
D
58.
48
For
further
information
on
the
feasibility,
emission
inventories,
and
costs,
see
``
Analysis
of
Spark
Ignition
Hobby
Engines'',
Memorandum
from
Chris
Lieske
to
Docket
A
2000
01,
document
II
G
144.
49
A
motocross
bike
is
typically
a
highperformance
off
highway
motorcycle
that
is
designed
to
be
operated
in
motocross
competition.
Motocross
competition
is
defined
as
a
circuit
race
around
an
off
highway
closed
course.
The
course
contains
numerous
jumps,
hills,
flat
sections,
and
bermed
or
banked
turns.
The
course
surface
usually
consists
of
dirt,
gravel,
sand,
and
mud.
Motocross
bikes
are
designed
to
be
very
light
for
quick
handling
and
easy
maneuverability.
They
also
come
with
large
knobby
tires
for
traction,
high
fenders
to
protect
the
rider
from
flying
dirt
and
rocks,
aggressive
suspension
systems
that
allow
the
bike
to
absorb
large
amounts
of
shock,
and
are
powered
by
high
performance
engines.
They
are
not
equipped
with
lights.
50
An
enduro
bike
is
very
similar
in
design
and
appearance
to
a
motocross
bike.
The
primary
difference
is
that
enduros
are
equipped
with
lights
and
have
slightly
different
engine
performance
that
is
more
geared
towards
a
broader
variety
of
operation
than
a
motocross
bike.
An
enduro
bike
Small
SI
program.
42
We
are
continuing
to
exclude
hobby
engines
from
the
Small
SI
program
because
of
significant
engine
design
and
use
differences.
We
also
believe
that
hobby
engines
are
substantially
different
than
engines
used
in
recreational
vehicles
and,
as
proposed,
we
are
not
including
sparkignition
hobby
engines
in
this
final
rule.
We
received
no
comment
on
our
proposed
treatment
of
hobby
engines
or
any
additional
information
on
their
design
or
use.
There
are
about
8,000
spark
ignition
engines
sold
per
year
for
use
in
scalemodel
aircraft,
cars,
and
boats.
43
This
is
a
very
small
subsection
of
the
overall
model
engine
market,
most
of
which
are
glow
plug
engines
that
run
on
a
mix
of
castor
oil,
methyl
alcohol,
and
nitro
methane.
44
A
typical
spark
ignition
hobby
engine
is
approximately
25
cc
with
a
horsepower
rating
of
about
1
3
hp,
though
larger
engines
are
available.
These
spark
ignition
engines
are
specialty
products
sold
in
very
low
volumes,
usually
not
more
than
a
few
hundred
units
per
engine
line
annually.
Many
of
the
engines
are
used
in
model
airplanes,
but
they
are
also
used
in
other
types
of
models
such
as
cars
and
boats.
These
engines,
especially
the
larger
displacement
models,
are
frequently
used
in
competitive
events
by
experienced
operators.
The
racing
engines
sometimes
run
on
methanol
instead
of
gasoline.
In
addition,
the
engines
are
usually
installed
and
adjusted
by
the
hobbyist
who
selects
an
engine
that
best
fits
the
particular
model
being
constructed.
The
average
annual
hours
of
operation
has
been
estimated
to
be
about
12.2
hours
per
year.
45
The
usage
rate
is
very
low
compared
to
other
recreational
or
utility
engine
applications
due
to
the
nature
of
their
use.
Much
of
the
hobby
revolves
around
building
the
model
and
preparing
the
model
for
operation.
The
engine
and
model
must
be
adjusted,
maintained,
and
repaired
between
uses.
Spark
ignition
model
engines
are
highly
specialized
and
differ
significantly
in
design
compared
to
engines
used
in
other
recreational
or
utility
engine
applications.
While
some
of
the
basic
components
such
as
pistons
may
be
similar,
the
materials,
airflow,
cooling,
and
fuel
delivery
systems
are
considerably
different.
46
47
Some
sparkignition
model
engines
are
scale
replicas
of
multi
cylinder
aircraft
or
automobile
engines
and
are
fundamentally
different
than
spark
ignition
engines
used
in
other
applications.
Model
engine
manufacturers
often
select
lighterweight
materials
and
simplified
designs
to
keep
engine
weight
down,
often
at
the
expense
of
engine
longevity.
Hobby
engines
use
special
ignition
systems
designed
specifically
for
the
application
to
be
lighter
than
those
used
in
other
applications.
To
save
weight,
hobby
engines
typically
lack
pull
starters
that
are
found
on
other
engines.
Hobby
engines
must
be
started
by
spinning
the
propeller.
In
addition,
the
models
themselves
vary
significantly
in
their
design,
introducing
packaging
issues
for
engine
manufacturers.
We
are
not
including
spark
ignition
hobby
engines
in
the
recreational
vehicles
program.
The
engines
differ
significantly
from
other
recreational
engines
in
their
design
and
use,
as
noted
above.
Emission
control
strategies
envisioned
for
other
recreational
vehicles
may
not
be
well
suited
for
hobby
engines
because
of
their
design,
weight
constraints,
and
packaging
limitations.
Approaches
such
as
using
a
four
stroke
engine,
a
catalyst,
or
fuel
injection
all
would
involve
increases
in
weight,
which
would
be
particularly
problematic
for
model
airplanes.
The
feasibility
of
these
approaches
for
these
engines
is
questionable.
Reducing
emissions,
even
if
feasible,
would
likely
involve
fundamental
engine
redesign
and
substantial
R&
D
efforts.
The
costs
of
achieving
emission
reductions
are
likely
to
be
much
higher
per
engine
than
for
other
recreational
applications
because
the
R&
D
costs
would
be
spread
over
very
low
sales
volumes.
The
cost
of
fundamentally
redesigning
the
engines
could
double
the
cost
of
some
engines.
By
contrast,
because
of
their
very
low
sales
volumes,
annual
usage
rates,
and
relatively
short
engine
life
cycle,
sparkignition
hobby
engine
emission
contributions
are
extremely
small
compared
to
recreational
vehicles.
The
emission
reductions
possible
from
regulating
such
engines
would
be
minuscule
(
we
estimate
that
sparkignition
hobby
engines
as
a
whole
account
for
less
than
30
tons
of
HC
nationally
per
year,
much
less
than
0.01
percent
of
mobile
source
HC
emissions).
48
In
addition,
hobby
engines
differ
significantly
in
their
in
use
operating
characteristics
compared
to
small
utility
engines
and
other
recreational
vehicle
engines.
It
is
unclear
if
the
test
procedures
developed
and
used
for
other
types
of
spark
ignition
engine
applications
would
be
sufficiently
representative
or
even
technically
practical
for
hobby
engines.
We
are
not
aware
of
any
efforts
to
develop
an
emission
test
cycle
or
conduct
any
emission
testing
of
these
engines.
Also,
because
installing,
optimizing,
maintaining,
and
repairing
the
engines
are
as
much
a
part
of
the
hobby
as
operating
the
engine,
emission
standards
could
fundamentally
alter
the
hobby
itself.
Engines
with
emissioncontrol
systems
would
be
more
complex
and
the
operator
would
need
to
be
careful
not
to
make
changes
that
would
cause
the
engine
to
exceed
emission
standards.
EPA
will
continue
to
review
these
issues,
as
necessary,
in
the
future
and
reconsider
adoption
of
regulations
if
appropriate.
5.
Competition
Exemptions
a.
Off
Highway
motorcycles.
Currently,
a
large
portion
of
off
highway
motorcycles
are
designed
as
competition/
racing
motorcycles.
These
models
often
represent
a
manufacturer's
high
performance
offerings
in
the
offhighway
market.
Most
such
motorcycles
are
of
the
motocross
variety,
although
some
high
performance
enduro
models
are
marketed
for
competition
use.
49
50
These
high
performance
motorcycles
are
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Rules
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needs
to
be
able
to
cruise
at
high
speeds
as
well
as
operate
through
tight
woods
or
deep
mud.
51
A
spark
arrester
is
a
device
located
in
the
end
of
the
tailpipe
that
catches
carbon
sparks
coming
from
the
engine
before
they
get
out
of
the
exhaust
system.
This
is
important
when
a
bike
is
used
offhighway
where
hot
carbon
sparks
falling
in
grassy
or
wooded
areas
could
result
in
fires.
52
Most
manufacturers
of
motocross
racing
motorcycles
do
not
offer
a
warranty.
Some
manufacturers
do,
however,
offer
very
limited
(
1
to
3
months)
warranties
under
special
conditions.
53
``
Characterization
of
Off
Road
Motorcycle
Use,''
ICF
Consulting,
September
2001,
A
2000
1
document
II
A
81.
largely
powered
by
two
stroke
engines,
though
some
four
stroke
models
have
been
introduced
in
recent
years.
Competition
events
for
motocross
motorcycles
mostly
involve
closedcourse
or
track
racing.
Other
types
of
off
highway
motorcycles,
such
as
enduros
and
trials
bikes,
are
usually
marketed
for
trail
or
open
area
use.
When
used
for
competition,
these
models
are
likely
to
be
involved
in
point
to
point
competition
events
over
trails
or
stretches
of
open
land.
There
are
also
specialized
off
highway
motorcycles
that
are
designed
for
competitions
such
as
ice
racing,
drag
racing,
and
observed
trials
competition.
A
few
races
involve
professional
manufacturer
sponsored
racing
teams.
Amateur
competition
events
for
offhighway
motorcycles
are
also
held
frequently
in
many
areas
of
the
U.
S.
Clean
Air
Act
subsections
216
(
10)
and
(
11)
exclude
engines
and
vehicles
``
used
solely
for
competition''
from
nonroad
engine
and
nonroad
vehicle
regulations.
In
the
proposal
we
stated
that
in
previous
nonroad
engine
emission
control
programs,
we
have
generally
defined
the
term
as
follows:
Used
solely
for
competition
means
exhibiting
features
that
are
not
easily
removed
and
that
would
render
its
use
other
than
in
competition
unsafe,
impractical,
or
highly
unlikely.
Most
motorcycles
marketed
for
competition
do
not
appear
to
have
obvious
physical
characteristics
that
constrain
their
use
solely
to
competition.
In
fact,
they
are
usually
sold
by
dealers
from
the
showroom
floor.
Upon
closer
inspection,
however,
there
are
several
features
and
characteristics
for
many
competition
motorcycles
that
make
recreational
use
unlikely.
For
example,
motocross
bikes
are
not
equipped
with
lights
or
a
spark
arrester,
which
prohibits
them
from
legally
operating
on
public
lands
(
such
as
roads,
parks,
state
land,
and
federal
land).
51
Vehicle
performance
of
modern
motocross
bikes
is
so
advanced
(
for
example,
with
extremely
high
power
toweight
ratios
and
advanced
suspension
systems)
that
it
is
highly
unlikely
that
these
machines
will
be
used
for
recreational
purposes.
In
addition,
motocross
and
other
competition
offhighway
motorcycles
typically
do
not
come
with
a
warranty,
which
further
deters
purchasing
and
using
competition
bikes
for
recreational
operation.
52
We
believe
these
features
are
sufficient
in
distinguishing
competition
motorcycles
from
recreational
motorcycles.
Therefore,
we
are
specifically
adopting
the
following
features
as
indicative
of
motorcycles
used
solely
for
competition:
absence
of
a
headlight
or
other
lights;
the
absence
of
a
spark
arrester;
suspension
travel
greater
than
10
inches;
an
engine
displacement
greater
than
50
cc;
absence
of
a
manufacturer
warranty;
and
the
absence
of
a
functional
seat.
Manufacturers
must
specifically
request
and
receive
an
exemption
from
EPA
to
sell
off
highway
motorcycles
without
a
certificate
under
the
competition
exemption.
Vehicles
not
meeting
the
applicable
criteria
listed
above
will
be
exempted
only
in
cases
where
the
manufacturer
has
clear
and
convincing
evidence
that
the
vehicles
for
which
the
exemption
is
being
sought
will
be
used
solely
for
competition.
Examples
of
this
type
of
evidence
may
be
technical
rationale
explaining
the
differences
between
a
competition
and
non
competition
motorcycle,
marketing
and
sales
information
indicating
the
intent
of
the
motorcycle
for
competition
purposes,
and
survey
data
from
users
indicating
the
competitive
nature
of
the
motorcycle.
Although
there
are
several
features
that
generally
distinguish
competition
motorcycles
from
recreational
motorcycles,
several
parties
have
commented
that
they
believe
motorcycles
designed
for
competition
use
are
also
used
for
recreational
purposes,
rather
than
solely
for
competition.
This
is
of
particular
concern
because
competition
motorcycles
represent
about
29
percent
of
total
off
highway
motorcycle
sales
or
approximately
43,000
units
per
year.
However,
a
study
on
the
characterization
of
off
highway
motorcycle
usage
found
that
there
are
numerous
and
increasingly
popular
amateur
off
highway
motorcycle
competitions
across
the
country,
especially
motocross.
53
The
estimated
number
of
off
highway
motorcycle
competitors
is
as
high
as
80,000.
Since
it
is
very
common
for
competitive
riders
to
replace
their
machines
every
one
to
two
years,
the
sale
of
43,000
offhighway
competition
motorcycles
appears
to
be
a
reasonable
number,
considering
the
number
of
competitive
participants.
We
are
therefore
confident
that,
although
we
are
excluding
a
high
percentage
of
off
highway
motorcycles
as
being
competition
machines,
the
criteria
laid
out
above
are
indicative
of
motorcycles
used
solely
for
competition.
However,
we
do
recognize
that
it
is
possible
that
some
competition
motorcycles
will
be
used
for
recreational
purposes.
We
are
therefore
adopting
a
provision
within
the
regulations
that
allows
the
Agency
to
deny
a
manufacturer's
claim
for
exemption
from
the
standards
for
any
models,
including
models
that
meet
the
six
specified
criteria,
where
other
information
is
available
that
indicates
these
off
highway
motorcycle
models
are
not
used
solely
for
competition.
This
same
provision
allows
the
Agency
to
deny
claims
for
exemptions
in
later
years
even
if
they
had
been
granted
previously.
Examples
of
this
type
of
information
can
be
state
registration
data
that
indicate
a
significant
number
of
competition
exempt
models
being
registered
to
operate
on
public
lands.
Off
highway
competition
motorcycles
designed
for
motocross
competition
are
not
typically
required
to
be
registered
with
states,
since
most
motocross
competitions
occur
on
closed
circuit
courses
on
private,
not
public
land,
and
motocross
machines
lack
spark
arresters
which
are
required
to
operate
on
public
land.
We
believe
the
possibility
of
losing
an
exemption
for
competition
motorcycles
will
encourage
manufacturers
to
take
proper
actions
in
promoting,
marketing,
and
guaranteeing
that
competition
machines
are
sold
to
those
individuals
who
will
use
them
solely
for
competition.
b.
Snowmobiles
and
ATVs.
Snowmobiles
and
ATVs
are
also
used
in
competition
events;
however,
the
percentage
of
snowmobiles
or
ATVs
used
solely
for
competition
is
not
nearly
as
large
as
that
for
off
highway
motorcycles.
Since
snowmobile
and
ATV
competition
have
typically
not
been
as
popular
as
off
highway
motorcycle
competitions,
there
has
not
been
the
demand
for
competition
machines
that
exists
with
off
highway
motorcycles.
As
a
result,
manufacturers
have
not
manufactured
and
sold
directly
from
their
dealers
competition
snowmobiles
and
ATVs
like
they
have
off
highway
motorcycles.
Most
snowmobiles
and
ATVs
used
in
competition
events
are
modified
recreational
vehicles,
rather
than
stock
racing
machines
bought
directly
from
the
dealer,
as
is
the
case
with
offhighway
motorcycles.
As
a
result,
there
isn't
the
same
concern
over
potential
misuse
of
competition
snowmobiles
and
ATVs
for
recreational
purposes.
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8,
2002
/
Rules
and
Regulations
Competition
snowmobiles
and
ATVs
aren't
currently
sold
directly
at
the
dealership.
Therefore,
manufacturers
can
receive
a
competition
exemption
from
EPA
for
snowmobiles
and
ATVs
meeting
all
of
the
following
criteria:
the
vehicle
or
engine
may
not
be
displayed
for
sale
in
any
public
dealership;
sale
of
the
vehicle
must
be
limited
to
professional
racers
or
other
qualified
racers;
and
the
vehicle
must
have
performance
characteristics
that
are
substantially
superior
to
noncompetitive
models.
As
with
off
highway
motorcycles,
snowmobiles
and
ATVs
not
meeting
the
applicable
criteria
listed
above
will
be
exempted
only
in
cases
where
the
manufacturer
has
clear
and
convincing
evidence
that
the
vehicles
for
which
the
exemption
is
being
sought
will
be
used
solely
for
competition.
We
are
also
adopting
the
same
provision
as
for
offhighway
motorcycles
within
the
regulations
that
allows
the
Agency
to
deny
a
manufacturer's
claim
for
exemption
from
the
standards
for
any
models
where
other
information
is
available
that
indicates
these
snowmobiles
and
ATVs
models
are
not
used
solely
for
competition.
As
with
offhighway
motorcycles,
this
same
provision
allows
the
Agency
to
deny
claims
for
exemptions
in
later
years
even
if
they
had
been
granted
previously.
C.
Emission
Standards
1.
What
Are
the
Emission
Standards
and
Compliance
Dates?
a.
Off
highway
motorcycles.
We
are
adopting
HC
plus
NOX
and
CO
standards
for
off
highway
motorcycles.
We
expect
the
largest
benefit
to
come
from
reducing
HC
emissions
from
twostroke
engines.
Two
stroke
engines
have
very
high
HC
emission
levels.
Baseline
NOX
levels
are
relatively
low
for
engines
used
in
these
applications
and
therefore
including
NOX
in
the
standard
serves
only
to
cap
NOX
emissions
for
these
engines.
Comparable
CO
reductions
can
be
expected
from
both
two
stroke
and
four
stroke
engines,
as
CO
levels
are
similar
for
the
two
engine
types.
We
are
also
adopting
averaging,
banking
and
trading
provisions
for
off
highway
motorcycles,
as
discussed
below.
In
the
current
off
highway
motorcycle
market,
consumers
can
choose
between
two
stroke
and
four
stroke
models
in
most
sizes.
Each
engine
type
offers
unique
performance
characteristics.
Some
manufacturers
specialize
in
twostroke
or
four
stroke
models,
while
others
offer
a
mix
of
models.
The
HC
standard
is
likely
to
be
a
primary
determining
factor
for
what
technology
manufacturers
choose
to
employ
to
meet
emission
standards
overall.
HC
emissions
can
be
reduced
substantially
by
switching
from
two
stroke
to
fourstroke
engines.
Four
stroke
engines
are
very
common
in
off
highway
motorcycle
applications.
Approximately
55
percent
of
non
competition
off
highway
motorcycles
are
four
stroke.
Certification
results
from
California
ARB's
emission
control
program
for
offhighway
motorcycles,
combined
with
our
own
baseline
emission
testing,
provides
ample
data
on
the
emissioncontrol
capability
of
four
stroke
engines
in
off
highway
motorcycles.
Offhighway
motorcycles
certified
to
California
ARB
standards
for
the
2000
model
year
have
HC
certification
levels
ranging
from
0.4
to
1.0
g/
km.
These
motorcycles
have
engines
ranging
in
size
from
48
to
650
cc;
none
of
these
use
catalysts.
The
emission
standards
for
offhighway
motorcycles
take
effect
beginning
in
the
2006
model
year.
We
will
allow
a
phase
in
of
50
percent
implementation
in
the
2006
model
year
with
full
implementation
in
2007.
These
standards
apply
to
testing
with
the
highway
motorcycle
Federal
Test
Procedure
(
FTP)
test
cycle.
For
HC+
NOX
emissions,
the
standard
is
2.0
g/
km
(
3.2
g/
mi).
For
CO
emissions,
the
standard
is
25.0
g/
km
(
40.5
g/
mi).
Both
of
these
standards
are
based
on
averaging
with
a
cap
on
the
Family
Emission
Limit
(
FEL)
of
20
g/
km
for
HC+
NOX
and
50
g/
km
for
CO.
Banking
and
trading
provisions
are
also
included
in
the
program,
as
described
in
Section
III.
C.
2.
These
emission
standards
allow
us
to
set
nearterm
requirements
to
introduce
the
lowemission
technologies
for
substantial
emission
reductions
with
minimal
lead
time.
We
expect
manufacturers
to
meet
these
standards
using
four
stroke
engines
with
some
low
level
modifications
to
fuel
system
calibrations.
These
systems
are
similar
to
those
used
for
many
years
in
highway
motorcycle
applications,
but
with
less
overall
sophistication
for
off
highway
applications.
We
received
comments
from
several
states
and
environmental
groups
encouraging
us
to
harmonize
our
offhighway
motorcycle
standards
with
California.
The
comments
focused
on
the
perceived
difference
in
stringency
between
the
two
programs.
For
California,
the
standard
is
an
HC
only
standard
of
1.2
g/
km.
Our
standard
is
a
HC+
NOX
standard
of
2.0
g/
km.
We
believe
it
is
prudent
to
set
a
HC+
NOX
standard
in
lieu
of
a
HC
only
standard
since
the
main
emission
control
strategy
is
expected
to
be
the
use
of
four
stroke
engines
in
lieu
of
two
stroke
engines.
Two
stroke
engines
emit
extremely
low
levels
of
NOX.
Four
stroke
engines,
on
the
other
hand,
have
higher
NOX
emission
levels,
in
the
range
of
0.3
g/
km
on
average.
This
is
part
of
the
reason
why
we
proposed
a
somewhat
higher
numeric
standard
compared
to
California.
The
California
standards,
which
were
adopted
in
1994,
were
stringent
enough
that
manufacturers
were
unable
to
certify
several
models
of
off
highway
motorcycles,
even
some
with
four
stroke
engine
technology.
The
result
was
a
substantial
shortage
of
products
for
dealers
to
sell
in
California.
The
shortage
led
California
to
change
their
program
to
allow
manufacturers
to
sell
noncompliant
off
highway
motorcycles
under
some
circumstances.
As
a
result,
approximately
a
third
of
the
off
highway
motorcycles
sold
in
California
are
compliant
with
the
standards.
The
uncertified
models
being
sold
in
California
include
both
two
stroke
and
four
stroke
machines.
EPA
received
comments
from
dealers
and
consumers
concerned
that
a
similar
shortage
could
arise
nationwide
if
EPA
adopted
the
California
standards.
EPA
shared
this
concern
and
proposed
standards
that
were
somewhat
less
stringent
than
that
of
California,
based
on
test
data
from
high
performance
fourstroke
machines.
We
are
finalizing
this
approach
to
ensure
the
four
stroke
technology
can
be
implemented
broadly
across
the
product
line
in
the
2006
timeframe
Although
the
approach
we
are
finalizing
contains
somewhat
less
stringent
standards
than
the
California
program,
we
believe
it
will
achieve
reductions
beyond
that
of
the
California
program
because
more
products
will
be
certified
(
even
when
the
competition
exemption
is
taken
into
account).
The
vast
majority
of
the
HC
reductions
achieved
by
the
program
come
from
shifting
away
from
conventional
twostroke
engines
which
have
HC
emissions
levels
in
the
range
of
35
g/
km.
The
2.0
g/
km
standard
represents
about
a
95
percent
reduction
in
emissions
for
these
vehicles.
If
we
were
to
go
beyond
this
level
of
reduction,
manufacturers
would
need
to
employ
on
a
widespread
basis
additional
technology
that
presents
significant
technical
issues
concerning
their
application
to
off
highway
motorcycles
given
their
extreme
usage
patterns
and
issues
such
as
safety,
packaging,
and
weight.
For
example,
technologies
such
as
electronic
fuel
injection
and
secondary
air
injection
raise
concerns
about
their
durability
and
reliability
in
the
harsh
operating
environments
to
which
off
highway
motorcycles
are
sometimes
exposed.
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217
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Friday,
November
8,
2002
/
Rules
and
Regulations
The
use
of
catalytic
converters
poses
concerns
over
packaging,
durability
and
safety.
Off
highway
motorcycles
are
very
light
and
narrow.
These
attributes
are
necessary
for
operating
through
tight
forest
trails
and
other
harsh
conditions.
This
leaves
little
room
for
packaging
a
catalyst
so
that
it
won't
be
damaged
from
engine
vibration,
shock
resulting
from
jumps
and
hopping
logs,
and
falling
over
and
hitting
objects,
such
as
trees
and
rocks.
These
technologies
may
become
compatible
for
off
highway
motorcycles
in
the
future,
but
we
do
not
believe
that
it
is
appropriate
to
promulgate
emission
standards
based
on
these
technologies
at
this
time,
given
the
technical
problems
currently
associated
with
their
use.
Four
stroke
engine
technology
has
advanced
considerably
since
the
California
regulations
went
into
effect.
Manufacturers
are
now
capable
of
offering
four
stroke
engines
that
provide
excellent
performance.
This
performance
can
be
achieved
only
as
long
as
manufacturers
are
allowed
to
operate
four
stroke
engines
with
a
slightly
rich
air
and
fuel
mixture,
which
can
result
in
somewhat
higher
HC
and
CO
emissions.
Although
the
standards
we
are
setting
are
higher
than
those
in
California,
we
believe
they
will
require
four
stroke
engines
that
are
well
calibrated
for
emissions
control
without
significantly
sacrificing
performance.
For
these
reasons,
we
believe
the
standards
we
are
establishing
are
appropriate.
As
discussed
above
in
Section
III.
B.
5,
the
Clean
Air
Act
requires
us
to
exempt
from
emission
standards
off
highway
motorcycles
used
for
competition.
We
expect
several
competition
two
stroke
off
highway
motorcycle
models
to
continue
to
be
available.
We
are
concerned
that
setting
standards
as
stringent
as
California's
would
result
in
a
performance
penalty
for
some
fourstroke
engines
that
would
be
unacceptable
to
the
consumers.
This
could
encourage
consumers
who
want
performance
oriented
off
highway
motorcycles
to
purchase
competition
vehicles
(
and
use
them
recreationally)
in
lieu
of
purchasing
compliant
machines
that
don't
provide
the
desired
performance.
We
believe
that
our
emission
standards
will
allow
the
continued
advancement
of
four
stroke
technology
and
properly
considers
available
emission
control
technology
while
taking
vehicle
performance
into
consideration
and
avoiding
significant
adverse
impacts
on
performance.
As
proposed,
we
are
also
finalizing
an
option
allowing
off
highway
motorcycles
with
an
engine
displacement
of
50
cc
or
less
to
be
certified
using
the
Small
SI
emission
standards
for
non
handheld
Class
I
engines.
These
youth
oriented
models
may
not
be
able
to
operate
over
the
FTP
due
to
the
higher
speeds
of
the
test
cycle.
We
did
not
receive
comment
on
this
provision.
Optional
Standards
During
the
comment
period,
we
received
several
comments
expressing
concern
that
our
proposed
standard
of
2.0
g/
km
HC+
NOX
for
off
highway
motorcycles
would
effectively
prohibit
the
use
of
two
stroke
engines
in
noncompetition
applications.
These
engines
currently
have
typical
HC+
NOX
levels
of
about
35
g/
km.
The
commenters
argued
that
two
stroke
engines
possess
several
unique
attributes,
such
as
high
power
and
light
weight,
that
make
two
stroke
powered
off
highway
motorcycles
more
desirable
to
some
operators,
especially
smaller,
lighter
riders,
than
heavier
fourstroke
powered
off
highway
motorcycles.
We
also
received
comments
from
several
states
and
environmental
organizations
expressing
strong
concern
over
the
number
of
competition
offhighway
motorcycles
that
would
be
exempt
from
our
regulations
as
a
result
of
our
competition
exemption.
They
felt
that
people
purchasing
exempt
competition
motorcycles
would
use
them
for
recreational
purposes
instead
of
solely
for
competition.
One
manufacturer
indicated
that
they
were
planning
on
building
highperformance
off
highway
motorcycles
equipped
with
direct
fuel
injection
twostroke
engines
that
would
potentially
be
capable
of
meeting
a
HC+
NOX
standard
of
4.0
g/
km.
To
enable
use
of
this
technology,
they
suggested
that
we
should
adopt
a
standard
of
4.0
g/
km
instead
of
the
proposed
standard
of
2.0
g/
km.
The
commenter
believes
that
direct
injection
could
be
used
to
make
clean
competition
machines
and
also
argued
that
the
technology
is
robust
and
not
as
susceptible
to
user
modifications
as
other
technologies
such
as
catalysts.
The
commenter
wanted
an
opportunity
to
develop
and
certify
their
product
because
it
perceives
a
benefit
to
the
purchaser
not
only
in
performance
but
also
in
the
ability
for
the
owner
to
resell
the
competition
vehicle
into
the
secondary
market
without
concerns
about
potential
misuse.
In
addition,
the
owner
would
be
able
to
use
the
vehicle
both
for
competition
and
recreation.
It
is
clear
that
if
manufacturers
were
able
to
certify
and
bring
to
market
clean
competition
machines
as
described
by
the
commenter,
significant
reductions
in
emissions
would
be
gained
over
conventional
two
stroke
technology.
Some
competition
models
we
tested
had
baseline
HC
and
CO
emissions
in
excess
of
50
g/
km
and
40
g/
km,
respectively.
We
believe
it
is
appropriate
to
provide
an
avenue
for
the
development
and
voluntary
certification
of
clean
competition
motorcycles.
Therefore,
we
are
finalizing
an
optional
set
of
standards
for
off
highway
motorcycles
of
4.0
g/
km
HC+
NOX
and
35.0
g/
km
CO.
For
manufacturers
to
utilize
this
option,
however,
they
must
certify
all
of
their
models,
including
their
competition
models,
to
the
optional
standards.
To
qualify
for
this
option,
a
manufacturer
must
show
that
ten
percent
or
more
of
their
sales
would
otherwise
meet
the
competition
definition.
The
optional
standard
was
derived
from
the
fact
that
non
competition
fourstroke
engines
can
meet
a
2.0
g/
km
level
and
competition
two
stroke
machines
with
advanced
direct
fuel
injection
technology
could
meet
a
8.0
g/
km
level.
Since
approximately
one
third
of
the
total
off
highway
motorcycle
fleet
are
competition
machines
and
the
other
two
thirds
would
be
non
competition
four
stroke
recreational
machines,
the
weighting
of
the
2.0
g/
km
level
by
twothirds
and
the
8.0
g/
km
level
by
onethird
results
in
a
weighted
standard
of
4.0
g/
km.
This
presumes
that
emissions
from
four
stroke
engines
will
not
increase
under
this
option
and
that
noncompetition
engines
will
be
almost
exclusively
four
stroke
engines.
These
assumptions
are
discussed
below.
The
significant
reductions
in
otherwise
unregulated
competition
engines
means
that
this
option
should
produce
even
greater
overall
reductions
than
the
base
2.0
g/
km
standard.
We
recognize
that
for
some
manufacturers
this
program
will
increase
opportunities
to
make
a
limited
number
of
non
competition
recreational
two
stroke
machines;
however,
we
believe
that
the
number
of
two
stroke
non
competition
engines
developed
under
this
program
will
be
limited
by
the
fact
that
the
required
technology
(
direct
fuel
injection)
would
be
too
expensive
and
complex
for
the
recreational
motorcycle
market.
The
majority
of
non
competition
recreational
off
highway
motorcycles
that
use
twostroke
engines
are
entry
level
and
youth
motorcycles,
where
cost
and
simplicity
are
important
factors.
There
is
also
the
fact
that
for
every
two
stroke
noncompetition
engine
manufactured
under
this
program,
a
manufacturer
must
make
one
less
competition
engine
or
must
make
more
four
stroke
engines.
Further,
we
believe
that
any
increase
in
the
number
of
non
competition
two
stroke
engines
is
justified
given
the
fact
that
this
program
will
overall
bring
levels
from
off
highway
engines
down
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considerably
and
the
fact
that
the
technology
needed
to
reduce
emissions
from
competition
machines
will
only
be
made
available
and
used
if,
under
this
optional
approach,
manufacturers
have
an
incentive
to
use
the
technologies.
One
major
incentive
in
using
this
approach
is
the
fact
that
once
these
machines
are
certified,
a
consumer
will
be
able
to
use
these
machines
legally
for
non
competition
uses,
which
increases
the
value
of
the
competition
machines.
This
approach
thus
will
also
reduce
the
incentive
for
manufacturers
to
manufacturer
all
of
their
two
stroke
machines
as
competition
machines
to
avoid
regulation,
and
thus
reduce
the
incentive
for
users
to
circumvent
the
regulations.
This
may
mean
that
any
increase
in
two
stroke
non
competition
engines
under
this
approach
would
not
lead
to
an
increase
in
total
two
stroke
sales,
because
manufacturers
will
not
have
an
incentive
to
increase
the
number
of
two
stroke
competition
vehicles
to
avoid
regulation.
We
believe
this
approach
is
responsive
to
all
of
the
above
comments.
It
directly
addresses
the
concerns
of
the
manufacturer
developing
the
new
competition
motorcycle
and
also
helps
address
the
concerns
of
users,
states,
and
environmental
groups.
The
successful
development
and
certification
of
clean
competition
models
increases
the
choices
for
consumers
in
the
marketplace.
Offered
the
option
of
a
certified
highperformance
two
stroke
off
highway
motorcycle
that
can
be
used
both
for
competition
and
recreation,
consumers
may
not
feel
the
need
to
purchase
exempt
competition
motorcycles.
This
option
has
the
potential
to
significantly
decrease
the
number
of
conventional
two
stroke
competition
machines
sold
under
the
competition
exemption
and
is
likely
to
decrease
the
potential
for
misuse
of
competition
machines.
Conventional
competition
two
stroke
motorcycles
generate
extremely
high
levels
of
HC
emissions,
as
noted
above.
For
every
conventional
two
stroke
competition
machine
replaced
by
a
certified
competition
machine,
HC
emissions
would
be
reduced
by
80
percent,
or
more.
While
the
4.0
g/
km
standard
is
higher
than
the
2.0
g/
km
standard
contained
in
the
base
program,
we
do
not
expect
any
loss
in
emissions
reductions
from
fourstroke
models.
We
continue
to
believe
most
off
highway
motorcycles
will
continue
to
be
powered
by
four
stroke
engines.
Most
non
competition
offhighway
motorcycles
are
already
fourstroke
motorcycles,
and
the
trend
towards
four
stroke
is
continuing
even
in
the
absence
of
these
regulations.
We
are
convinced
that
there
will
be
no
backsliding
of
emissions
control
for
motorcycles
using
four
stroke
engines,
because
the
dirtiest
of
the
four
stroke
models
tend
to
be
competition
machines,
and
our
emissions
testing
indicates
that
competition
four
stroke
off
highway
motorcycles
have
HC+
NOX
emission
levels
below
2.0
g/
km.
Since
these
motorcycles
are
optimized
for
power
and
racing
conditions,
there
is
no
incentive
for
manufacturers
to
increase
HC+
NOX
emissions
from
their
current
levels.
In
fact,
increasing
the
emission
levels
would
mean
increasing
the
air
tofuel
mixture,
which
would
tend
to
reduce
the
engines
performance.
As
with
the
primary
program,
these
optional
standards
would
take
effect
in
2006
with
50
percent
implementation
and
full
implementation
in
2007
and
manufacturers
could
switch
between
the
options
from
model
year
to
model
year.
The
HC+
NOX
standard
can
be
met
through
averaging
with
some
families
certified
above
the
standards
and
some
below.
If
averaging
is
used,
the
FEL
cap
would
be
8.0
g/
km.
We
are
retaining
the
averaging
approach
for
this
option
because
it
may
be
a
critical
flexibility
for
manufacturers
pursuing
clean
competition
products.
The
commenter
based
its
recommendation
for
a
4.0
g/
km
standard
on
their
projections
for
a
single
prototype
model
equipped
with
a
medium
sized
engine.
This
engine
is
in
the
early
stages
of
development
and
there
is
some
uncertainty
as
to
what
emissions
level
the
final
product
can
achieve.
Also,
manufacturers
may
want
to
apply
their
approach
to
other
engines
that
may
not
be
able
to
achieve
this
same
level
of
control.
Manufacturers
could
find
that
they
can
produce
competition
products
that
are
very
clean
relative
to
the
baseline
but
with
higher
emissions
than
4.0
g/
km.
For
example,
larger
engine
sizes
could
have
emissions
levels
somewhat
higher
than
the
4.0
g/
km
suggested
by
the
commenter.
We
are
not
satisfied
at
this
time
that
two
stroke
off
highway
motorcycles,
particularly
those
used
in
competition
could
meet
the
4.0
g/
km
standard,
especially
considering
the
special
performance
needs
of
competition
motorcycles.
Therefore,
rather
than
keeping
a
2.0
g/
km
standard
for
four
stroke
engines
and
having
a
standard
higher
than
4.0
g/
km
for
two
stroke
engines
(
a
standard
as
high
as
8.0
g/
km
might
be
appropriate),
we
are
using
a
4.0
g/
km
standard
that
permits
averaging.
Averaging
provides
flexibility
for
manufacturers
to
bring
cleaner
two
stroke,
particularly
cleaner
competition
two
stroke,
engines
to
market
without
creating
a
disincentive
to
building
four
stroke
engines.
One
way
of
taking
advantage
of
the
averaging
program
in
this
way
would
be
for
a
manufacturer
to
maximize
its
sales
of
four
stroke
models
as
part
of
its
sales
mix,
and
average
the
emissions
from
these
engines
against
the
higher
emissions
of
the
two
stroke
competition
engines
which
still
would
need
to
be
much
cleaner
than
if
they
were
unregulated.
This
approach
therefore
requires
the
substantial
use
of
cleaner
four
stroke
technologies
while
at
the
same
time
encouraging
manufacturers
to
substantially
reduce
emissions
from
motorcycles
that
would
otherwise
be
unregulated
competition
motorcycles.
We
have
capped
the
emissions
levels
at
8.0
g/
km
HC+
NOX
because
we
want
to
ensure
that
products
certified
under
this
option
provide
large
emissions
reductions
compared
to
baseline
levels
and
that
the
option
provides
environmental
benefits
in
all
cases.
Competition
motorcycles
certified
to
the
8.0
g/
km
level
would
continue
to
provide
over
a
75
percent
reduction
in
HC
emissions
over
baseline
levels.
One
of
the
challenges
facing
manufacturers
selecting
this
option
is
the
potentially
high
CO
emissions
from
competition
machines.
We
tested
competition
models
and
found
CO
emissions
to
be
in
the
range
25
to
50
g/
km.
Although
this
option
contains
a
somewhat
higher
CO
standard
(
35
g/
km
compared
to
25
g/
km)
than
the
base
program,
manufacturers
are
still
expected
to
need
to
control
CO
emissions
through
tight
engine
calibrations.
We
are
not
including
averaging
for
the
less
stringent
CO
standard.
As
noted
by
the
manufacturer
supporting
the
4.0
g/
km
option,
direct
injection
technology
is
likely
to
reduce
CO
from
two
stroke
engines.
We
believe
that
through
proper
calibration,
the
35
g/
km
standard
will
be
achievable
and
will
not
significantly
impede
manufacturers
in
selecting
this
option.
b.
ATVs.
We
are
adopting
HC
plus
NOX
and
CO
standards
for
ATVs.
We
expect
the
largest
benefit
to
come
from
reducing
HC
emissions
from
two
stroke
engines.
Two
stroke
engines
have
very
high
HC
emission
levels.
Baseline
NOX
levels
are
relatively
low
for
engines
used
in
these
applications
and
therefore
including
NOX
in
these
standards
serves
only
to
cap
NOX
emissions
for
these
engines.
Comparable
CO
reductions
can
be
expected
from
both
two
stroke
and
four
stroke
engines,
as
CO
levels
are
similar
for
the
two
engine
types.
We
are
also
adopting
averaging,
banking
and
trading
provisions
for
ATVs,
as
discussed
below.
In
the
current
ATV
market,
consumers
can
choose
between
two
stroke
and
four
stroke
models,
although
the
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2002
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Regulations
54
We
respond
to
these
comments
in
Section
II
of
the
Summary
and
Analysis
of
Comments.
55
Utility
type
ATVs,
it
should
be
noted,
are
not
the
same
as
utility
vehicles.
Utility
vehicles
are
not
Continued
majority,
approximately
eighty
percent
of
sales,
are
four
stroke.
Each
engine
type
offers
unique
performance
characteristics.
Some
manufacturers
specialize
in
two
stroke
or
four
stroke
models,
but
most
manufacturers
offer
a
mix
of
models.
The
HC
standard
is
likely
to
be
a
primary
determining
factor
for
which
technology
manufacturers
choose
to
employ
to
meet
emission
standards
overall.
HC
emissions
can
be
reduced
substantially
by
switching
from
two
stroke
to
four
stroke
engines.
Certification
results
from
California
ARB's
emission
control
program
for
ATVs,
combined
with
our
own
baseline
emission
testing,
provides
ample
data
on
the
emission
control
capability
of
four
stroke
engines
in
ATVs.
In
the
proposal
we
included
two
phases
of
ATV
standards.
The
first
phase
of
standards,
2.0
g/
km
HC+
NOX
and
25
g/
km
CO,
was
proposed
to
be
phased
in
at
50
percent
of
production
in
2006
with
the
remainder
phased
in
for
2007.
We
proposed
a
second
set
of
standards
that
included
a
more
stringent
1.0
g/
km
HC+
NOX
standard
with
no
change
to
the
CO
standards.
It
was
to
be
met
in
2009/
2010
using
the
same
50
percent
and
100
percent
phase
in
scheme
as
Phase
1.
We
proposed
that
both
phases
of
HC+
NOX
standards
could
be
met
through
averaging.
We
received
comments
from
several
environmental
groups
stating
that
we
should
harmonize
our
Phase
1
standards
with
the
California
FTP
based
standards.
Manufacturers
did
not
comment
on
the
level
of
our
proposed
Phase
1
HC+
NOX
standards.
However,
in
a
letter
sent
to
the
Agency
in
August
6,
2001,
just
before
we
published
the
proposal,
the
Motorcycle
Industry
Council
stated
that
the
most
costeffective
approach
to
setting
standards
for
ATVs
would
be
to
adopt
the
California
HC
standards
of
1.2
g/
km.
They
did
comment
on
the
fact
that
almost
all
of
the
CO
nonattainment
areas
identified
in
the
Draft
Regulatory
Support
Document
are
now
in
compliance
and
that
ATV
activity
is
typically
so
far
removed
from
congested
urban
areas,
that
we
should
delete
the
proposed
CO
standard.
54
Manufacturers
stated
generally
that
CO
standards
will
make
it
more
difficult
to
meet
the
HC+
NOX
standards
but
did
not
provide
additional
specific
comments
on
the
feasibility
or
costs
of
the
CO
level
proposed.
In
subsequent
meetings
with
manufacturers,
they
suggested
that
if
we
were
not
going
to
delete
the
CO
standard,
it
should
be
set
sufficiently
high
so
that
it
would
not
be
an
impediment
to
meeting
the
HC+
NOX
standard.
They
suggested
a
level
of
50.0
g/
km.
We
have
decided
to
finalize
only
one
set
of
HC+
NOX
emission
standards
for
the
2006
model
year
that
are
essentially
equivalent
to
the
California
standard.
The
emission
standards
for
ATVs
take
effect
beginning
in
the
2006
model
year.
We
will
allow
a
phase
in
of
50
percent
implementation
in
the
2006
model
year
with
full
implementation
in
2007.
These
standards
apply
to
testing
with
the
highway
motorcycle
Class
I
FTP
test
cycle.
For
HC+
NOX
emissions,
the
standard
is
1.5
g/
km
(
2.4
g/
mi).
The
California
program
has
a
HC
only
standard
of
1.2
g/
km.
We
have
made
the
standard
1.5
g/
km
to
account
for
NOX
emissions.
For
CO
emissions,
we
agree
with
manufacturers
that
CO
standards
can
make
it
more
difficult
to
meet
the
HC+
NOX
standard.
Based
on
our
emission
test
data,
we
feel
that
a
standard
of
35.0
g/
km
(
56.4
g/
mi)
is
more
appropriate
than
the
25.0
g/
km
standard
we
proposed
or
the
50.0
g/
km
standard
suggested
by
the
manufacturers.
A
standard
of
35.0
g/
km
will
still
result
in
an
overall
reduction
in
CO
emissions
from
high
emitting
ATVs,
but
will
also
allow
manufacturers
to
balance
CO
control
with
the
need
to
meet
stringent
NOX
levels.
The
HC+
NOX
standard
may
be
met
through
averaging.
Banking
and
trading
provisions
for
HC+
NOX
are
also
being
included
in
the
program,
as
discussed
in
C.
2.,
below.
Our
decision
to
finalize
a
1.5
g/
km
value
rather
than
the
2.0
g/
km
value
is
consistent
with
the
manufacturers
technical
capability
in
the
2006/
2007
time
frame.
The
1.5
g/
km
HC+
NOX
and
35
g/
km
CO
standards
require
the
use
of
engine
technology
changes
and
add
on
devices
such
as
secondary
air
systems,
which
are
clearly
available
for
ATV
application
in
this
time
frame.
We
proposed
a
1.0
g/
km
HC+
NOX
standard
for
a
2009/
2010
phase
in
which
could
require
use
of
catalytic
converter
technology
in
many
models
of
ATVs.
As
discussed
below,
we
are
not
finalizing
that
proposal
now,
and
thus
find
it
appropriate
to
finalize
more
stringent
Phase
1
standards
which
are
technologically
feasible
and
otherwise
consistent
with
statutory
criteria
related
to
cost,
safety,
noise,
and
energy
considerations.
Aligning
our
emission
standards
with
those
currently
in
place
in
California
allows
us
to
set
requirements
to
introduce
the
low
emission
technologies
for
substantial
emission
reductions
with
reasonable
lead
time
and
will
for
the
most
part
allow
manufacturers
to
sell
one
model
in
all
fifty
states.
This
``
harmonization''
between
federal
and
California
requirements
is
valued
by
industry
because
it
allows
the
development
and
production
of
one
emission
control
technology
per
model/
family.
However,
in
a
few
cases,
we
expect
emissions
reductions
under
the
EPA
program
that
go
beyond
that
of
the
California
program
because
California
allows
the
sale
of
uncertified
ATVs,
including
two
stroke
models,
under
their
red
sticker
provisions.
With
the
exception
of
competition
exempt
ATVs,
all
ATV
models
subject
to
the
EPA
program
will
need
to
be
certified.
We
expect
manufacturers
to
meet
these
standards
using
four
stroke
engines
with
some
modifications
to
fuel
system
calibrations
and
some
limited
use
of
secondary
air
systems.
These
systems
are
similar
to
those
used
for
many
years
in
highway
applications,
but
will
likely
require
lesser
sophistication
than
used
in
highway
motorcycle
applications.
In
addition
to
being
consistent
with
the
California
standards,
we
feel
the
1.5
g/
km
HC+
NOX
standard
is
more
appropriate
than
the
proposed
2.0
g/
km
standard
because
our
testing
has
shown
that
emission
levels
from
four
stroke
ATVs
can
vary
considerably.
We
stated
in
the
proposed
rule
that
a
standard
of
2.0
g/
km
HC+
NOX
would
be
a
fourstroke
enforcing
standard,
which
would
most
likely
result
in
the
elimination
of
any
two
stroke
engines,
but
not
necessarily
require
any
additional
control
from
the
four
stroke
engines.
As
stated
above,
a
standard
of
1.5
g/
km
HC+
NOX
will
require
the
use
of
engine
technology
changes
and
add
on
devices
such
as
secondary
air
systems,
which
are
clearly
available
for
ATV
application
in
this
time
frame.
At
this
point,
we
do
not
believe
it
is
appropriate
to
promulgate
Phase
2
standards.
In
the
proposal,
we
projected
significant
use
of
secondary
air
systems
and
catalysts
for
meeting
the
Phase
2
standards.
Since
that
time,
we
have
been
conducting
testing
on
ATVs
with
the
type
of
catalysts
and
secondary
air
systems
we
envisioned
for
the
Phase
2
standards
to
demonstrate
feasibility.
However,
the
testing
we
have
done
to
date
has
not
been
sufficient
to
reach
an
affirmative
conclusion
on
the
feasibility
of
the
Phase
2
standards.
Testing
with
secondary
air
systems
and
catalysts
have
not
shown
consistent
results
and
we
have
had
only
partial
success
in
demonstrating
the
feasibility
of
the
proposed
Phase
2
standards
using
these
technologies.
In
testing
on
a
utility
type
ATV,
these
technologies
have
provided
only
small
emissions
reductions.
55
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and
Regulations
considered
ATVs
due
to
fundamental
differences
in
the
vehicle
characteristics.
Most
utility
vehicles
are
currently
regulated
by
the
Small
SI
program,
with
a
small
subset
of
utility
vehicles
required
by
the
Final
Rule
to
meet
ATV
standards.
See
section
III.
B.
3.
above,
for
a
complete
discussion
of
utility
vehicles.
When
we
say
utility
type
ATV,
we
are
referring
to
ATVs
that
have
features
that
are
work
related
such
as
cargo
racks.
These
ATVs
are
often
somewhat
larger
and
bulkier
than
sport
models
and
may
have
transmissions
geared
more
for
work
related
tasks
rather
than
for
high
performance.
However,
they
have
ATV
features
such
as
four
low
pressure
tires,
a
seat
designed
to
be
straddled
by
the
operator,
handlebars
for
steering
controls,
and
are
intended
for
use
by
a
single
operator.
These
vehicle
must
meet
ATV
requirements.
56
Comments
of
the
Motorcycle
Industry
Council,
Inc.,
and
the
Specialty
Vehicle
Institute
of
America
on
the
Notice
of
Proposed
Rulemaking
to
Establish
Mandatory
Emission
Standards
for
Nonroad
Large
Spark
Ignition
Engines
and
Recreational
Engines
(
Marine
and
Land
Based),
Air
Docket
A
2000
01,
IV
D
214.
results
of
our
preliminary
testing
are
discussed
further
in
Section
III.
F
and
in
the
Final
Regulatory
Support
Document.
It
is
unclear
if
the
level
of
technology
we
projected
in
the
proposal
would
be
sufficient
to
meet
the
Phase
2
standards.
We
have
not
done
enough
research
or
testing
on
other
potential
technologies,
such
as
electronic
or
direct
fuel
injection,
to
finalize
a
decision
based
on
these
technologies.
We
plan
to
continue
to
evaluate
the
technologies
that
would
be
needed
to
meet
the
Phase
2
levels
and
determine
if
those
levels
can
be
met
with
the
level
of
technology
we
projected
in
the
proposal
or
with
other
technology.
We
also
received
comments
that
we
underestimated
costs
for
Phase
2
and
we
will
continue
to
evaluate
costs
as
well.
In
addition,
we
received
comments
that
the
emissions
inventories
we
projected
for
ATVs
were
too
large,
and
that
if
we
adjusted
them
appropriately,
we
would
see
that
Phase
2
was
not
needed.
This
is
provided
in
detail
in
the
public
docket.
56
We
have
studied
and
evaluated
in
depth
the
new
and
additional
information
provided
by
the
commenters
after
we
published
the
proposal.
As
is
shown
in
our
revised
analysis,
the
emissions
inventory
projections
for
ATVs
have
been
reduced
by
more
than
75
percent
in
response
to
the
significant
new
information
we
received
after
publishing
the
proposal.
Our
analysis
of
the
appropriate
standards
for
2006/
2007
described
above
was
made
using
this
new
information,
and
future
analysis
of
Phase
2
standards
would
also
use
these
revised
inventory
numbers.
However,
it
is
important
to
note
that
the
revised
inventories
still
show
that
these
vehicles
contribute
to
nonattainment.
Engine
based
Standards
California
allows
ATVs
to
be
optionally
tested
using
the
California
ARB
utility
engine
test
cycle
(
SAE
J1088)
and
procedures.
In
California,
manufacturers
using
the
J1088
engine
test
cycle
option
must
meet
the
California
Small
Off
Road
Engine
emission
standards.
Some
manufacturers
do
not
have
chassis
testing
facilities
and
at
the
time
California
finalized
its
program
were
concerned
about
the
cost
of
doing
FTP
testing
for
California
only
requirements.
To
use
this
option,
manufacturers
were
required
by
California
to
submit
some
emission
data
from
the
various
modes
of
the
J1088
test
cycles
to
show
that
emissions
from
these
modes
were
comparable
to
FTP
emissions.
Although
a
good
correlation
was
not
found
between
the
two
test
cycles,
California
allowed
this
option
because
the
goal
of
their
program
was
to
encourage
fourstroke
engine
technology
in
ATVs.
As
described
above,
we
are
finalizing
standards
based
on
vehicle
testing
over
the
FTP
that
are
essentially
harmonized
with
the
California
FTP
standards.
We
did
not
propose
a
permanent
option
of
engine
testing
using
J1088
due
to
strong
concerns
that
the
test
cycle
misses
substantial
portions
of
ATV
operation
because
it
contains
test
points
at
only
one
engine
speed.
We
understand
that
vehicle
testing
would
be
a
significant
change
for
manufacturers
who
currently
conduct
emissions
testing
on
the
engine
rather
than
the
vehicle
for
California.
Due
to
the
costs
and
lead
time
requirements
associated
with
switching
to
vehicle
based
testing,
we
proposed
a
transitional
program
to
allow
the
J1088
option
for
models
years
2006
through
2008.
To
facilitate
the
phase
in
of
ATV
standards,
we
proposed
to
allow
manufacturers
to
optionally
certify
ATVs
using
the
California
utility
cycle
and
standards,
shown
in
Table
III.
C
1,
instead
of
the
FTP
standards.
TABLE
III.
C
1.
CALIFORNIA
UTILITY
ENGINE
EMISSION
STANDARDS
Engine
displacement
HC+
NOX
CO
Less
than
225
cc
.................................................................................
12.0
g/
hp
hr
...................................................................
(
16.1
g/
kW
hr)
...............................................................
300
g/
hp
hr
(
400
g/
kW
hr)
Greater
than
225
cc
............................................................................
10.0
g/
hp
hr
...................................................................
(
13.4
g/
kW
hr)
...............................................................
300
g/
hp
hr
(
400
g/
kW
hr)
We
are
finalizing
this
approach,
but
will
eliminate
the
J1088
option
(
including
both
the
test
cycle
and
the
utility
engine
emission
standards)
for
certification
in
model
year
2009.
The
last
model
year
to
use
the
J1088
cycle
and
emission
standards
is
2008.
We
received
comments
that
the
FTP
is
also
not
representative
of
ATV
operation
and
that
the
J1088
option
should
remain
available
until
a
new
test
cycle
and
accompanying
standards
can
be
developed
and
made
available
to
manufacturers.
Although
it
may
not
be
completely
representative
of
ATV
operation,
we
believe
the
FTP
to
be
greatly
superior
to
the
J1088
test
cycle
because
the
cycle
is
transient,
emissions
are
measured
at
a
variety
of
speeds
and
it
is
more
likely
to
result
in
robust
emission
control
designs
that
reduce
emissions
in
use.
We
continue
to
be
very
concerned
that
the
vast
majority
of
ATV
operation
is
missed
with
the
J1088
test
because
the
engine
is
tested
at
only
one
engine
speed.
ATV
operation
is
inherently
transient
in
nature
because
the
user
controls
the
throttle
position
to
vary
vehicle
speed.
We
believe
the
J1088
test
is
not
sufficient
to
ensure
robust
emissions
control
development
and
use
for
ATVs.
Given
the
choice
of
available
test
procedures
for
the
longterm
we
could
not
justify
retaining
the
J1088
option.
For
small
displacement
ATVs
of
70
cc
or
less,
we
proposed
that
they
would
have
the
permanent
option
to
certify
to
the
proposed
FTP
based
ATV
standards
discussed
above
or
meet
the
Phase
1
Small
SI
emission
standards
for
nonhandheld
Class
1
engines.
These
standards
are
16.1
g/
kW
hr
HC+
NOX
and
610
g/
kW
hr
CO.
Manufacturers
argued
that
ATVs
with
engine
displacements
between
70
cc
and
99
cc
also
should
be
allowed
to
certify
to
the
Small
SI
standards,
since
the
differences
between
a
70
cc
and
99
cc
engine
is
very
small
and
the
ATVs
equipped
with
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2002
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and
Regulations
57
See
item
IV
G
114,
docket
A
2000
01.
cc
engines
face
the
same
obstacles
with
the
FTP
test
cycle
as
the
70
cc
and
below
ATVs.
They
also
argued
that
the
Phase
1
Small
SI
standards
are
too
stringent
for
these
engines
and
recommended
that
EPA
adopt
the
Phase
2
standards
for
Class
1B
engines
of
40
g/
kW
hr
for
HC+
NOX
and
610
g/
kW
hr
for
CO.
We
recognize
that
the
vast
majority
of
engine
families,
including
4
stroke
engines,
below
100
cc
are
not
certified
to
the
California
standards,
which
is
an
indication
to
us
that
the
standards
proposed
may
not
be
feasible
for
most
engines
in
this
size
range
given
the
lead
time
provided.
However,
manufacturers
did
not
provide
supporting
data
and
we
do
not
have
data
to
confirm
that
the
level
recommended
by
the
manufacturers
would
result
in
an
appropriate
level
of
control.
We
examined
the
2002
model
year
certification
data
for
non
handheld
Small
SI
engines
certified
to
the
Phase
2
Class
I
A
and
I
B
engine
standards
(
engines
below
100
cc).
We
found
that
the
five
engine
families
certified
to
these
standards
had
average
emissions
for
HC+
NOX
of
about
25
g/
kW
hr.
All
of
these
engine
families
had
CO
emissions
below
500
g/
kW
hr
and
well
below
the
610
g/
kW
hr
level
recommended
by
manufacturers.
We
believe
these
levels
are
more
representative
of
the
levels
that
can
be
achieved
with
the
lead
time
provided
through
the
use
of
4
stroke
engines
than
the
standards
recommended
by
the
manufacturers.
Therefore,
we
are
finalizing
a
25.0
g/
kW
hr
HC+
NOX
standard
and
a
500
g/
kW
hr
CO
standard
for
ATVs
with
engine
displacements
of
99
cc
or
less.
These
standards
will
be
optional
to
the
FTP
based
standards
and,
unlike
the
J
1088
standards
option
for
larger
displacement
engines,
the
option
will
not
expire.
We
are
retaining
averaging
for
the
HC+
NOX
standard
but
do
not
believe
averaging
would
be
appropriate
for
the
CO
standard.
This
is
consistent
with
the
approach
outlined
above
for
J
1088
standards
for
engines
above
100
cc.
The
ATV
standards
are
phased
in
at
50%
of
a
manufacturer's
production
in
2006
and
100%
in
2007.
This
phase
in
applies
to
a
manufacturer's
overall
ATV
production
regardless
engine
size
or
which
option
a
manufacturer
chooses
for
standards
for
particular
models.
New
Test
Procedure
for
ATVs
We
are
comfortable
with
retaining
the
FTP
as
the
basis
of
the
long
term
ATV
program.
However,
EPA
understands
the
manufacturers'
concerns
regarding
the
additional
facility
costs
associated
with
FTP
testing
for
ATVs.
We
also
recognize
that
this
approach
is
a
significant
deviation
from
their
current
practice
in
the
California
program.
Throughout
the
development
of
the
final
rule,
we
have
met
with
manufacturers
and
the
State
of
California
and
have
discussed
the
possibility
of
developing
a
new
test
cycle
for
ATVs.
We
intend
to
work
further
with
all
interested
parties
to
determine
whether
a
new
test
cycle
and
accompanying
standards
is
appropriate.
The
standards,
if
developed
for
the
new
test
cycle,
would
be
of
equivalent
stringency
to
the
FTP
standards
discussed
above.
If
we
do
propose
a
new
test
cycle
and
accompanying
standards
for
ATVs,
it
is
likely
that
we
would
do
so
in
concert
with
a
decision
on
whether
a
second
phase
of
standards
is
appropriate
for
ATVs.
We
are
now
developing
a
Memorandum
of
Understanding
with
manufacturers
which
describes
in
detail
the
steps
that
will
be
taken
in
furtherance
of
this
task.
57
Other
interested
parties
including
the
state
of
California
will
also
be
invited
to
participate
in
this
process.
By
finalizing
the
temporary
availability
of
J1088,
we
are
providing
time
to
develop,
and
if
appropriate,
finalize
and
implement
an
alternative
to
the
FTP
that
meets
both
the
needs
of
the
Agency,
manufacturers
and
other
parties.
This
allows
for
our
program
to
remain
harmonized
with
California
during
the
transition
to
the
new
test
procedure.
However,
we
do
not
support
allowing
the
use
of
J1088
for
a
period
any
longer
than
necessary
to
make
this
transition.
We
expect
that
developing
a
new
test
cycle
will
be
relatively
straightforward
and
that
the
MOU
process
cited
above
will
provide
a
road
map
of
how
we
will
proceed.
We
expect
to
initiate
this
effort
next
year
and
conclude
the
work
on
the
new
test
cycle
in
enough
time
to
promulgate
it
through
rulemaking
and
to
provide
industry
adequate
lead
time
to
implement
it
in
an
orderly
manner
(
nominally
three
years
lead
time).
If
we
encounter
unforeseen
and
unavoidable
delays
or
complications
in
this
process,
we
will
consider
extending
the
J1088
temporarily
as
part
of
our
process
of
adopting
changes
to
the
ATV
test
cycle
through
rulemaking.
We
would
expect
such
an
extension
to
be
at
most
for
one
model
year.
c.
Snowmobiles.
We
are
adopting
CO
and
HC
emission
standards
for
snowmobiles,
effective
in
three
phases,
as
discussed
below.
As
discussed
below,
we
are
also
adopting
an
emissions
averaging
banking
and
trading
program
for
snowmobiles
which
includes
provisions
for
the
early
generation
of
credits
prior
to
the
effective
date
of
the
standards.
We
are
not
adopting
PM
standards
for
snowmobiles
at
this
time,
because
limits
on
HC
emissions
will
serve
to
simultaneously
reduce
PM
and
because
there
are
significant
complications
in
accurately
measuring
PM
that
make
requiring
PM
standards
difficult
in
this
time
frame.
Finally,
we
are
not
adopting
limits
for
NOX
for
the
first
two
phases
of
standards,
but
manufacturers
are
required
to
measure
NOX
emissions
and
report
them
in
the
application
for
certification.
However,
we
have
included
NOX
in
the
Phase
3
standards
to
effectively
cap
NOX
emissions
from
snowmobiles.
The
three
phases
of
standards
we
are
adopting
will
require
progressively
broader
application
of
advanced
technologies
such
as
direct
injection
two
stroke
technology,
and
four
stroke
engines.
Only
about
two
percent
of
current
snowmobile
production
utilizes
these
advanced
technologies.
We
expect
that
about
seven
percent
of
new
snowmobiles
will
have
them
by
2005.
With
the
Phase
1
standards
we
expect
that
ten
percent
of
snowmobiles
will
require
advanced
technologies
(
in
addition
to
less
advanced
emissions
controls
on
most
other
snowmobiles).
We
project
that
the
Phase
2
and
Phase
3
standards
will
require
the
application
of
advanced
technology
on
50
and
70
percent
of
new
snowmobiles,
respectively.
Phase
1
Standards
We
are
adopting
Phase
1
standards
largely
as
proposed
for
snowmobiles
to
take
effect
for
all
models
starting
in
the
2006
model
year.
However,
given
that
the
manufacturers
will
effectively
have
only
three
years
to
design
and
certify
snowmobiles
prior
to
the
2006
model
year,
as
well
as
the
fact
that
snowmobiles
are
currently
unregulated,
we
believe
that
requiring
100
percent
of
models
to
certify
in
2006
is
not
reasonable.
Thus,
we
are
including
a
phase
in
of
the
Phase
1
standards
with
50
percent
of
sales
required
to
comply
with
the
30
percent
reduction
standards
in
2006
and
100
percent
compliance
required
in
2007.
The
standards
of
275
g/
kW
hr
(
205
g/
hp
hr)
for
CO
and
100
g/
kW
hr
(
75
g/
hp
hr)
for
HC
are
to
be
met
on
average
by
each
manufacturer.
As
described
in
the
proposal,
these
standards
represent
a
30
percent
reduction
from
the
baseline
CO
and
HC
emission
rates
for
uncontrolled
snowmobiles.
We
expect
manufacturers
to
meet
these
standards
using
a
variety
of
technologies
and
strategies
across
their
product
lines.
For
the
reasons
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58
http://
www.
arcticcat.
com,
http://
www.
polarisindustries.
com,
http://
www.
skidoo.
com,
and
http://
www.
yamahamotor
com.
59
See
the
snowmobile
feasibility
discussion
in
the
Final
Regulatory
Support
Document.
described
below,
we
believe
these
are
the
most
stringent
standards
feasible
beginning
in
the
2006
model
year.
Snowmobiles
pose
some
unique
challenges
for
implementing
emissioncontrol
technologies
and
strategies.
Snowmobiles
are
very
sensitive
to
weight,
power,
and
packaging
constraints.
Current
snowmobile
designs
have
very
high
power
to
weight
ratios,
to
address
performance
considerations.
The
desire
for
low
weight
has
been
stated
to
be
a
concern,
since
weight
(
and
weight
distribution)
affects
handling
and
operators
occasionally
have
to
drag
their
sleds
out
of
deep
snow.
This
has
especially
been
mentioned
as
a
concern
in
the
context
of
four
stroke
engines
given
that
they
are
heavier
than
their
two
stroke
counterparts
of
similar
power.
However,
four
stroke
engines
have
significantly
better
fuel
economy
than
two
stroke
engines,
and
for
identical
fuel
tank
sizes,
would
have
significantly
greater
range.
This
of
course
would
be
a
positive
attribute.
The
size
of
a
fuel
tank
on
a
four
stroke
powered
snowmobile
could
be
reduced
to
provide
similar
range
to
that
of
a
similarly
powered
twostroke
snowmobile,
resulting
in
offsetting
weight
savings
from
both
the
smaller
fuel
tank
and
less
fuel
on
board.
However,
this
could
still
represent
a
change
in
the
distribution
of
weight
compared
to
current
sleds.
The
approach
used
to
control
emissions
in
compliance
with
the
Phase
1
standards
will
vary
according
to
a
given
manufacturers
product
line,
technological
capability,
long
term
plans,
and
other
factors.
However,
we
expect
all
manufacturers
to
pursue
a
mix
of
technologies.
Some
manufacturers
may
focus
more
on
clean
carburetion
and
associated
engine
modifications
and
apply
those
widely
across
their
entire
product
line
with
more
limited
implementation
of
advanced
technology
such
as
four
stroke
and
semi
direct
injection
engines.
Others
may
choose
to
be
more
aggressive
in
applying
advanced
technologies
in
their
more
expensive,
high
performance
sleds
and
be
less
aggressive
in
pursuing
emission
reductions
from
their
lower
priced
offerings
to
optimize
the
fit
of
different
technologies
(
and
their
associated
costs)
to
the
various
product
offerings
in
the
near
term.
As
can
be
seen
on
their
websites58,
all
large
manufacturers
now
have
limited
product
offerings
of
advanced
emissions
technology
snowmobiles.
Snowmobiles
must,
on
average
and
according
to
the
phase
in
schedule,
meet
the
first
phase
of
emission
standards
beginning
with
the
2006
model
year.
Given
the
relative
inexperience
this
industry
has
with
designing
effective
snowmobile
engines
with
advanced
emissions
controls
and
in
certifying
to
EPA
requirements,
it
is
unlikely
that
any
manufacturer
could
market
enough
of
these
advanced
snowmobiles
for
model
year
2006
to
enable
it
to
meet
significantly
more
stringent
standards.
Due
to
the
unique
performance
requirements
for
snowmobiles
and
the
relatively
short
lead
time
to
modify
current
engines
or
design
new
products,
we
believe
our
2006/
2007
standards
will
be
technologically
challenging
for
manufacturers
and
will
result
in
cleaner
snowmobiles.
Phase
2
and
Phase
3
Standards
We
believe
the
two
most
viable
advanced
technologies
for
use
in
snowmobiles
are
two
stroke
direct
(
or
semi
direct)
injection
technology
and
four
stroke
engines.
All
four
major
snowmobile
manufacturers
either
currently
offer
or
are
planning
to
offer
in
the
next
year
or
two
one
or
more
of
these
technologies
on
a
limited
number
of
snowmobile
models.
With
sufficient
resources
and
lead
time
for
manufacturers,
we
believe
it
would
be
technologically
possible
to
eventually
apply
such
advanced
technology
broadly
across
most
or
all
of
the
snowmobile
fleet.
Manufacturers
have
indicated
that
with
enough
investment
and
sufficient
time
to
design
and
implement
direct
injection
technology
for
snowmobile
use,
two
stroke
engines
equipped
with
direct
fuel
injection
systems
can
reduce
HC
emissions
by
70
to
75
percent
and
reduce
CO
emissions
by
50
to
70
percent.
These
projections
are
based
largely
on
laboratory
prototypes
and
generally
do
not
account
for
in
use
deterioration
or
the
need
for
production
compliance
margins
in
the
ultimate
certification
levels.
Certification
results
for
2002
model
year
outboard
engines
and
personal
water
craft
support
these
projections.
59
In
addition
to
the
direct
injection
twostroke
a
few
four
stroke
models
are
currently
available,
and
more
are
expected
to
be
introduced
in
the
next
few
years.
Based
on
testing
of
prototypes
and
other
low
hour
engines
it
appears
that
advanced
four
stroke
snowmobiles
are
capable
of
HC
reductions
ranging
from
70
to
95
percent
relative
to
current
technology
two
stroke
snowmobile
engines.
However,
CO
reductions
from
four
stroke
engines
vary
quite
a
bit.
For
fourstroke
engines
used
in
low
power
applications,
CO
reductions
of
50
to
80
percent
from
baseline
levels
have
been
reported.
However,
the
majority
of
the
snowmobile
market
is
for
higherpowered
performance
machines,
and
CO
reductions
from
higher
powered
four
stroke
engines
are
lower
than
those
from
low
powered
four
strokes,
with
expected
reductions
of
20
to
50
percent
from
baseline
levels.
As
discussed
further
in
the
RSD
and
Summary
and
Analysis
of
Comments
document,
we
expect
that
many
of
the
four
stroke
snowmobile
models
offered
in
the
future
will
not
be
current
two
stroke
models
which
have
been
modified
to
utilize
a
four
stroke
engine,
but
rather
new
models
designed
specifically
to
take
advantage
of
the
unique
characteristics
of
four
stroke
engines.
Thus,
we
expect
that
the
lead
time
associated
with
the
conversion
to
fourstroke
engines
and
optimized
sleds
is
even
longer
than
that
needed
for
conversion
to
direct
injection
two
stroke
technology.
It
is
not
obvious
to
us
that
either
of
these
advanced
technologies
is
better
than
the
other
or
more
suited
to
broad
application
in
the
snowmobile
market.
Each
has
its
strong
points
regarding
emissions
performance,
power,
noise,
cost,
etc.
For
example,
two
stroke
engines
equipped
with
direct
fuel
injection
have
the
potential
to
have
greater
CO
emission
reductions
than
a
comparably
powered
four
stroke
engine,
although
they
would
have
less
HC
reductions.
For
those
applications
where
a
light,
powerful,
compact
engine
is
desired,
a
direct
injection
two
stroke
engine
may
be
preferred.
However,
for
applications
where
pure
power
and
speed
is
desired,
a
high
performance
four
stroke
engine
may
be
preferred.
Given
the
broad
range
of
snowmobile
model
designs
and
applications
it
is
apparent
that
one
of
these
technologies
could
be
preferable
to
the
other
in
some
situations.
Further,
given
the
broad
range
of
snowmobile
types
offered,
a
mix
of
advanced
technologies
would
provide
the
best
opportunity
for
substantial
average
emission
reductions
while
still
maintaining
customer
satisfaction
across
the
entire
range
of
snowmobile
types.
Thus,
we
believe
it
is
most
appropriate
to
set
emission
standards
for
snowmobiles
that
are
not
based
entirely
on
the
use
of
either
direct
injection
two
stroke
technology
or
fourstroke
engines,
but
rather
a
mix
of
the
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two,
along
with
some
other
technologies
in
certain
applications.
It
is
our
belief
that
with
sufficient
resources
and
lead
time,
manufacturers
can
successfully
implement
technologies
such
as
two
stroke
direct
injection
and
four
stroke
engines
in
many
models
in
their
respective
snowmobile
fleets.
The
question
at
hand
is
how
broadly
this
technology
can
be
practically
applied
across
the
snowmobile
fleet
in
the
near
term,
taking
into
account
factors
such
as
the
number
of
engine
and
snowmobile
models
currently
available,
and
the
capacity
of
the
industry
to
perform
the
research
and
development
efforts
required
to
optimally
apply
advanced
technology
to
each
of
these
models.
Currently
there
are
only
four
major
snowmobile
manufacturers,
and
each
has
different
technological
capabilities.
Of
these
four,
only
two
currently
manufacturer
all
of
their
own
engines,
one
has
limited
in
house
engine
manufacturing
operations,
the
other
has
none.
Beyond
this,
there
are
only
two
advanced
technologies
(
direct
injection
two
stroke,
and
four
stroke)
that
at
this
time
appear
to
be
feasible
to
provide
significant
reductions
in
snowmobile
emissions.
Further,
given
the
small
volume
of
snowmobile
sales
compared
to
other
vehicles
and
equipment
which
use
similar
sized
engines,
these
manufacturers
may
have
difficulty
in
working
with
their
engine
suppliers
to
develop
and
optimize
four
stroke
or
direct
injection
two
stroke
technology
quickly.
Clearly,
the
nature
of
the
relationship
between
these
snowmobile
manufacturers
and
their
suppliers
would
result
in
a
less
efficient
use
of
available
lead
time
as
compared
to
the
manufacturers
that
have
both
technology
and
engine
manufacturing
available
in
house.
Thus,
there
is
varying
capability
within
the
snowmobile
industry
to
develop
and
implement
advanced
technology
in
the
next
five
to
ten
years.
The
amount
of
engine
redesign
or
development
work
is
another
factor.
While
one
snowmobile
manufacturer
currently
offers
four
different
engine
models,
the
other
three,
including
the
two
that
do
not
manufacture
their
own
engines,
currently
offer
eight
to
twelve
engine
models
each.
Additionally,
each
of
these
engine
models
typically
goes
into
more
than
one
type
of
snowmobile.
There
are
a
variety
of
basic
snowmobile
types
specifically
designed
for
a
variety
of
riding
styles
and
terrains
including
high
performance
trail
riding,
highperformance
off
trail
riding
(
including
designs
specifically
for
deep
snow),
mountain
riding,
touring
(
two
person
snowmobiles
designed
for
use
on
groomed
trails),
and
entry
level
snowmobiles
(
lower
powered
and
lower
priced
snowmobiles
which
utilize
simpler
technology
and
are
specifically
designed
to
appeal
to
first
time
buyers).
Some
snowmobile
manufacturers
also
offer
snowmobile
models
specifically
for
youth,
and
utility
models
for
work
in
cold
climates
or
to
facilitate
winter
sports
such
as
hauling
winter
camping
gear,
or
hunting
and
fishing
equipment.
It
is
not
surprising
that
some
of
these
snowmobile
models
are
much
more
popular
than
others.
Thus,
there
can
be
quite
a
difference
in
the
production
volumes
of
the
different
snowmobile
types,
with
performance
models
typically
having
large
sales
volumes,
and
more
unique
models
such
as
utility
and
youth
models
selling
far
fewer
units.
Considering
the
number
of
snowmobile
types,
and
the
fact
that
each
engine
model
is
typically
used
in
several
different
snowmobile
models,
each
manufacturer
has
potentially
dozens
of
different
engine/
snowmobile
combinations
that
it
offers.
An
analysis
of
the
manufacturers
current
product
offerings
shows
that
while
one
manufacturer
has
only
about
twelve
unique
engine/
snowmobile
model
combinations,
the
other
three
offer
significantly
more
from
around
30
to
over
50.
Each
of
these
different
snowmobile
models
is
designed
with
specific
power
needs
in
mind,
with
the
engine
and
clutching
specifically
suited
for
the
application
style
for
which
the
snowmobile
was
intended.
This
means
that
a
given
engine
model
may
require
slightly
different
calibrations
for
each
different
snowmobile
model
in
which
it
is
used.
While
the
advanced
technologies
are
known,
they
are
not
``
one
size
fits
all''
technologies.
These
technologies
need
to
be
optimized
not
only
for
the
specific
engine
model,
but
in
some
cases
for
the
snowmobile
the
engine
will
be
used
in
as
well,
as
just
described.
For
all
of
the
reasons
just
discussed,
we
believe
that
it
is
necessary
to
allow
two
additional
years
of
lead
time
for
compliance
with
the
proposed
Phase
2
standards,
and
are
therefore
adopting
the
ultimate
phase
of
snowmobile
standards
effective
for
the
2012
model
year
rather
than
the
2010
model
year
as
proposed.
However,
we
expect
that
between
the
2006
and
2012
model
years
there
can
and
will
be
substantial
development
and
application
of
advanced
technologies
on
snowmobiles
beyond
that
required
in
compliance
with
the
Phase
1
standards.
We
believe
that
it
is
important
to
capture
the
emission
benefits
that
these
advances
present,
and
are
therefore
adopting
a
new
set
of
Phase
2
standards,
effective
with
the
2010
model
year,
which
will
require
50
percent
HC
reductions
and
30
percent
CO
reductions
from
average
baseline
levels.
The
Phase
2
standards
are
275
g/
kW
hr
(
205
g/
hp
hr)
for
CO
and
75
g/
kW
hr
(
56
g/
hp
hr)
for
HC.
These
Phase
2
standards
will
be
followed
by
Phase
3
standards
in
2012
which
will
effectively
require
the
equivalent
of
50
percent
reductions
in
both
HC
and
CO
as
compared
to
average
baseline
levels.
We
believe
that
the
2010
and
2012
model
years
are
appropriate
for
the
second
and
third
phases
of
snowmobile
standards
because
they
allow
an
additional
four
to
six
years
beyond
the
Phase
1
standards
for
the
further
development
and
application
of
advanced
emissions
control
technology.
We
expect
that
the
manufacturers
will
utilize
some
level
of
advanced
technology
in
compliance
with
the
Phase
1
standards,
and
this
will
give
the
manufacturers
some
time
to
evaluate
how
the
advanced
technology
they
have
already
applied
works
in
the
field
as
well
as
give
them
several
years
to
work
with
the
certification
and
compliance
programs
before
more
stringent
Phase
2
standards
take
effect
in
2010.
We
believe
that
by
the
2010/
2012
time
frame
manufacturers
could,
at
least
in
theory,
apply
advanced
technology
across
essentially
their
entire
product
lines.
However,
the
manufacturers
are
resource
constrained,
and
they
will
need
to
focus
their
efforts
on
compliance
with
the
Phase
1
and
Phase
2
standards
prior
to
the
2010
model
year.
There
is
a
need
for
significant
technology
development
and
manufacturing
learning
to
occur,
and
there
is
concern
that
in
this
time
frame
such
technology
could
not
be
performance,
emissions,
and
safety
optimized
for
each
application
given
the
number
of
engine
and
snowmobile
model
combinations
that
would
require
optimization.
This
would
be
especially
challenging
for
those
manufacturers
who
rely
on
outside
suppliers
for
their
engines.
Rather,
we
expect
that
by
the
2012
model
year
the
manufacturers
could
both
apply
and
optimize
advanced
technology
to
their
larger
volume
families
while
applying
clean
carburetion
and
electronic
fuel
injection
technology
to
the
rest
of
their
production.
Under
this
scenario
we
expect
that
the
manufacturers
could
apply
optimized
advanced
technology
on
around
50
percent
of
their
production
by
the
2010
model
year,
and
an
additional
20
percent
of
their
production
by
the
2012
model
year.
We
do
not
believe
that
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only
two
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years
lead
time
between
the
Phase
2
and
Phase
3
standards
presents
any
problems
because
compliance
with
the
Phase
3
standards
will
be
achieved
through
the
broader
application
of
technologies
which
will
already
be
applied
in
compliance
with
the
Phase
2
standards,
rather
than
through
the
introduction
of
new
technologies
altogether.
As
was
previously
discussed,
fourstroke
technology
has
the
potential
to
significantly
reduce
HC
emissions,
even
below
levels
expected
from
direct
injection
two
stroke
technology.
However,
higher
powered
four
stroke
engines
are
not
currently
capable
of
CO
reductions
on
the
order
of
those
expected
from
direct
injection
twostroke
technology.
This
is
significant
given
that
a
very
large
segment
of
the
snowmobile
market
is
in
higher
powered
performance
sleds.
We
are
concerned
that
a
straight
50
percent
reduction
in
CO
in
the
Phase
3
standards
may
deter
technology
development
and
constrain
the
use
of
four
stroke
technology
in
this
key
portion
of
the
snowmobile
market.
As
the
emissions
standards
become
more
stringent
we
believe
that
it
is
important
to
provide
additional
flexibility
to
assure
compliance
in
a
manner
which
minimizes
costs
and
is
consistent
with
the
availability
of
technology
and
the
realities
of
the
snowmobile
marketplace.
Thus,
to
allow
snowmobile
manufacturers
the
flexibility
to
base
their
future
product
lines
on
higher
percentages
of
four
stroke
models,
we
are
adopting
a
flexible
Phase
3
standards
scheme
that
will
allow
manufacturers
to
certify
their
production
to
levels
which
nominally
represent
50
percent
reductions
in
HC
and
CO.
This
overall
reduction
could
be
met
by
other
combinations
summing
to
100
percent
such
as
70
percent
reductions
in
HC
and
30
percent
reductions
in
CO,
or
any
level
between
these
two
points
(
for
example,
60
percent
reductions
in
HC
and
40
percent
reductions
in
CO).
However,
in
no
case
may
a
manufacturer's
corporate
average
for
the
individual
pollutants
for
Phase
3
be
less
than
50
percent
on
HC
and
30
percent
on
CO
(
the
Phase
2
standards).
Some
manufacturers
have
raised
safety
concerns
regarding
the
use
of
advanced
technologies
on
snowmobiles,
particularly
four
stroke
engines
used
in
high
performance
and
mountain
sleds.
In
particular,
they
raised
issues
regarding
weight
and
the
ability
to
start
the
snowmobile
in
cold
weather.
However,
we
believe
these
issues
can
be
overcome
with
sufficient
time
and
technology.
For
example,
as
noted
above,
smaller
fuel
tanks
can
significantly
reduce
the
weight
of
fourstroke
snowmobiles.
The
use
of
new
light
weight
materials
can
also
reduce
weight
for
four
stroke
designs.
Manufacturers
have
raised
concerns
over
cold
starting
for
four
stroke
engines
because
the
typical
four
stroke
design
uses
an
oil
distribution
system
where
the
pump
and
oil
are
located
in
the
crankcase
(
referred
to
as
a
``
wet''
sump).
During
extremely
cold
temperatures,
the
oil
becomes
thick
and
provides
an
additional
load
the
engine
must
overcome
when
starting.
However,
by
using
a
``
dry''
sump,
where
the
oil
and
pump
are
located
in
a
separate
tank
(
not
in
the
crankcase),
the
concern
over
cold
temperature
starting
loads
due
to
thickened
oil
in
the
crankcase
are
gone.
The
new
Yamaha
RX
1
four
stroke
snowmobile
uses
a
smaller
fuel
tank
and
lighter
materials
to
reduce
weight
and
a
dry
sump
to
help
cold
starting,
so
clearly
these
issues
can
be
addressed.
We
believe
that,
given
enough
resources
and
lead
time,
it
is
ultimately
feasible
at
some
point
beyond
the
2012
model
year
to
apply
advanced
technology
successfully
to
all
snowmobiles
and
perhaps
to
even
resolve
current
design
and
operating
issues
with
regard
to
the
use
of
aftertreatment
devices
such
as
catalytic
converters.
However,
it
is
difficult
to
predict
at
this
point
when
this
would
be
feasible,
especially
given
the
number
of
smaller
volume
snowmobile
models
that
would
need
development
effort
once
the
larger
volume
models
were
optimized
in
compliance
with
the
Phase
3
standards
in
2012.
We
did
consider
standards
based
on
the
full
application
of
optimized
advanced
technology
to
all
snowmobiles,
for
example
by
setting
the
Phase
3
standards
at
a
level
that
would
require
the
full
application
of
advanced
technology
to
all
snowmobiles.
However,
we
believe
that
such
standards
are
not
feasible
by
2012
and,
we
are
not
confident
that
we
could
choose
the
appropriate
model
year
beyond
2012
for
such
standards
given
how
far
in
the
future
such
a
requirement
would
be.
Such
an
approach
would
also
serve
to
eliminate
the
benefits
associated
with
the
Phase
3
standards
in
2012.
There
are
diverse
capabilities
and
limiting
factors
within
the
industry,
and
time
is
needed
for
an
orderly
development
and
prove
out
of
this
advanced
technology
across
the
various
models
and
applications
before
standards
are
set
which
require
its
use
in
all
models.
Additionally,
as
these
engines
have
never
previously
been
regulated
or
used
advanced
emission
control
technologies
in
large
numbers,
we
believe
it
is
appropriate
to
monitor
the
development
and
use
of
such
technologies
on
snowmobiles
before
requiring
these
technologies
for
the
entire
fleet.
Thus,
we
chose
not
to
set
standards
at
this
time
based
on
the
optimized
application
of
advanced
technology
to
all
snowmobiles.
Nevertheless,
we
will
monitor
the
development
and
application
of
the
advanced
technology
as
manufacturers
work
to
comply
with
the
Phase
3
standards
in
2012
and
will
consider
a
fourth
phase
of
snowmobile
standards
to
take
effect
sometime
after
the
2012
model
year.
We
have
not
included
a
NOX
standard
for
the
first
two
phases
of
the
snowmobile
regulations
because
NOX
emissions
from
snowmobiles,
particularly
two
stroke
engines,
are
very
small
compared
to
levels
of
HC,
CO
and
PM
and
we
believe
that
stringent
NOX
standards
may
require
the
use
of
technologies
that
will
lead
to
increases
in
HC,
PM
and
CO
levels.
Technologies
that
reduce
NOX
are
likely
to
increase
levels
of
HC,
PM
and
CO
and
vice
versa,
because
technologies
to
reduce
HC,
PM
and
CO
emissions
would
result
in
leaner
operation.
A
lean
air
and
fuel
mixture
causes
NOX
emissions
to
increase.
These
increases
are
minor,
however,
compared
to
the
reductions
of
HC,
CO
and
PM
that
result
from
these
techniques.
On
the
other
hand,
any
attempt
to
control
the
NOX
emissions
may
have
the
counter
effect
of
increasing
HC,
CO,
and
PM
emissions,
as
well
as
causing
the
greater
secondary
PM
concentrations
associated
with
increased
HC
emissions.
This
is
especially
critical
for
HC
and
PM,
because
NOX
would
be
regulated
primarily
for
its
effect
on
secondary
PM
levels.
We
are
promulgating
a
NOX
standard
(
actually
an
HC
plus
NOX
standard)
as
part
of
the
third
phase
of
the
snowmobile
standards.
This
standard
will
essentially
cap
NOX
emissions
from
these
engines.
The
reason
we
are
including
such
standards
in
the
final
phase
of
the
rule
as
that
the
third
phase
of
the
rule
will
result
in
increases
in
the
use
of
four
stroke
engines.
While
fourstroke
engines
greatly
reduce
HC
and
direct
PM
levels,
they
increase
levels
of
NOX.
While
NOX
levels
remain
substantially
lower
than
HC
and
CO
levels,
they
are
higher
than
levels
for
two
stroke
engines.
Thus,
it
is
appropriate
to
place
a
cap
on
such
levels
to
ensure
that
levels
do
not
become
so
high
as
to
become
a
substantial
concern.
While
we
are
promulgating
an
effective
cap
on
such
emissions,
the
standard
will
not
mandate
substantial
reductions
in
NOX.
This
is
because
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emissions
effect
on
reducing
NOX
from
four
stroke
engines
is
the
same
as
for
two
stroke
engines;
that
is,
technologies
that
substantially
reduce
NOX
will
increase
levels
of
other
pollutants
of
concern.
The
only
way
to
reduce
NOX
emissions
from
four
stroke
engines
(
at
the
same
time
as
reducing
HC
and
CO
levels)
would
be
to
use
a
three
way
catalytic
converter.
We
don't
have
enough
information
at
this
time
on
the
durability
or
safety
implications
of
using
a
three
way
catalyst
with
a
fourstroke
engine
in
snowmobile
applications.
Three
way
catalyst
technology
is
well
beyond
the
technology
reviewed
for
this
rule
and
would
need
substantial
additional
review
before
being
contemplated
for
snowmobiles.
Thus,
given
the
overwhelming
level
of
HC
and
CO
compared
to
NOX,
and
the
secondary
PM
expected
to
result
from
these
levels,
it
would
be
premature
and
possibly
counterproductive
to
require
substantial
NOX
reductions
from
snowmobiles
at
this
time.
2.
Are
There
Opportunities
for
Averaging,
Emission
Credits,
or
Other
Flexibilities?
a.
Averaging,
banking
and
trading.
Historically,
voluntary
emission
credit
programs
have
allowed
a
manufacturer
to
certify
one
or
more
engine
families
at
emission
levels
above
the
applicable
emission
standards,
provided
that
the
increased
emissions
are
offset
by
one
or
more
engine
families
certified
below
the
applicable
standards.
With
averaging
alone,
the
average
of
all
engine
families
for
a
particular
manufacturer's
production
must
be
at
or
below
that
level
of
the
applicable
emission
standards.
We
are
adopting
separate
emission
credit
programs
for
snowmobiles,
off
highway
motorcycles,
and
ATVs.
We
are
adopting
an
emission
credit
program
for
the
optional
ATV
engine
based
standards
as
well
as
the
chassis
based
standards.
In
addition
to
the
averaging
program
just
described,
the
emission
credit
program
contains
banking
and
trading
provisions,
which
allow
manufacturers
to
generate
emission
credits
and
bank
them
for
future
use
in
their
own
averaging
program
or
sell
them
to
another
entity.
We
are
not
adopting
a
credit
life
limit
or
credit
discounting
for
these
credits.
Unlimited
credit
life
and
no
discounting
increases
the
incentive
to
introduce
the
clean
technologies
needed
to
gain
credits.
To
generate
credits,
the
engine
family's
emissions
level
must
be
below
the
standard,
so
any
credits
will
result
from
reducing
emissions
more
than
necessary
to
meet
the
standards.
ATVs
and
Off
highway
Motorcycles
Emission
credits
from
off
highway
motorcycle
and
ATVs
will
be
averaged
separately
because
there
are
differing
degrees
of
stringency
in
the
standards
for
ATVs
and
off
highway
motorcycles
long
term
and
we
do
not
want
offhighway
motorcycle
credits
to
dilute
the
effectiveness
of
the
ATV
standards.
This
also
avoids
providing
an
advantage
in
the
market
to
companies
that
offer
both
types
of
products
over
those
that
produce
only
one
type.
Also,
ATVs
certified
to
the
chassis
based
standards
or
engine
based
standards
are
considered
separate
averaging
groups
with
no
credit
exchanges
between
the
two.
We
are
not
allowing
credit
exchanges
between
engine
and
chassisbased
testing
because
there
is
little,
if
any,
correlation
between
the
two
test
cycles.
Without
a
strong
correlation,
it
is
not
possible
to
establish
an
exchange
rate
between
the
two
programs.
For
the
engine
based
(
J
1088)
ATV
standards,
the
standards
vary
by
engine
size
(
less
than
100
cc,
100
cc
up
to
225
cc,
and
225
cc
and
greater).
We
are
allowing
averaging,
banking,
and
trading
for
each
of
the
separate
engine
based
HC+
NOX
standards
with
no
credit
exchanges
or
averaging
between
the
engine
size
categories.
We
did
not
propose
an
averaging,
banking,
and
trading
program
for
CO
for
ATVs
and
off
highway
motorcycles
because
it
was
not
clear
if
such
provisions
would
be
needed
to
implement
the
expected
technologies
or
if
the
need
would
warrant
the
additional
complexity
of
an
averaging
program.
We
received
comments
that
the
25
g/
km
CO
standard
could
be
technologically
limiting
in
some
instances.
Manufacturers
recommended
that
EPA
drop
CO
the
standard
from
the
program
and
provided
no
comments
regarding
CO
averaging.
In
addition,
our
recent
testing
indicates
that
the
level
of
the
standards
may
represent
a
significant
technological
challenge
to
the
manufacturers
in
some
cases.
We
are
retaining
CO
standards
in
the
final
program,
and
are
establishing
different
CO
standards
for
off
highway
motorcycles
and
ATVs,
as
discussed
in
Section
III.
C.
1.
For
ATVs,
we
are
addressing
the
feasibility
issues
by
finalizing
a
standard
of
35
g/
km.
We
are
not
including
averaging
or
a
credits
program
at
this
level.
We
are
also
adopting
the
35
g/
km
CO
standard
for
the
optional
off
highway
motorcycle
program
with
no
averaging
or
credits
program.
At
the
35
g/
km
level,
we
believe
averaging
is
unnecessary
and
would
greatly
reduce
the
need
to
control
CO,
especially
for
larger
manufacturers
who
have
several
engine
families
with
which
to
average.
The
engine
based
(
J
1088)
standards
for
CO
also
do
not
represent
levels
of
stringency
where
we
believe
averaging
would
be
appropriate
or
necessary.
California
certification
test
data
shows
that
the
engine
based
(
J
1088)
CO
standards
can
be
achieved
with
reasonable
compliance
margins.
For
the
primary
off
highway
motorcycle
program,
we
are
retaining
the
proposed
25
g/
km
CO
standard.
We
are
providing
the
option
of
averaging
for
the
25
g/
km
CO
standard,
to
help
manufacturers
balance
the
need
to
control
CO
while
meeting
stringent
NOX
requirements.
We
believe
that
the
final
program
with
averaging
for
CO
will
enable
manufacturers
to
develop
a
unified
emission
control
strategy
to
control
HC,
NOX,
and
CO,
rather
than
requiring
them
to
develop
unique
control
strategies
driven
by
the
need
to
meet
the
CO
standards.
We
are
adopting
FEL
caps
where
we
are
allowing
averaging
standards.
For
ATVs
certified
to
the
1.5
g/
km
FTP
standard,
there
will
be
an
FEL
cap
of
20
g/
km
HC+
NOX.
This
cap
will
also
apply
to
off
highway
motorcycles
certified
to
the
2.0
g/
km
NOX+
HC
standard.
For
offhighway
motorcycles
certified
to
the
25
g/
km
CO
standard,
the
CO
cap
will
be
50
g/
km.
For
off
highway
motorcycles,
we
are
also
finalizing
an
option
that
allows
manufacturers
to
certify
to
an
average
HC+
NOX
standard
of
4.0
g/
km,
if
the
manufacturer
certifies
all
offhighway
motorcycles
including
competition
machines.
Under
this
option,
we
are
limiting
FELs
to
8.0
g/
km.
The
goal
of
the
option
is
to
encourage
the
development
and
certification
of
clean
competition
products.
Without
a
reasonable
FEL
limit,
manufacturers
could
certify
twostroke
machines
at,
or
close
to,
baseline
levels.
This
is
a
concern
because
the
majority
of
manufacturers'
product
offerings
are
likely
to
be
certified
below
the
4.0
g/
km
level
and
significant
credits
could
be
available.
We
believe
the
8.0
g/
km
limit
ensures
significantly
cleaner
products
compared
to
baseline
levels
for
competition
machines,
while
providing
manufacturers
with
the
incentive
and
flexibility
to
pursue
innovative
technologies
for
their
competition
products.
As
noted
above,
we
have
also
included
engine
based
J
1088
standards
for
ATVs.
The
HC+
NOX
portion
of
the
J
1088
standards
can
be
met
through
averaging
and
we
have
included
reasonable
emissions
caps
for
these
standards
as
well.
For
engines
certified
to
the
permanent
optional
J
1088
standards
for
ATV
engines
below
100
cc,
the
emissions
cap
is
40.0
g/
kW
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The
NOX+
HC
emissions
cap
is
32.2
g/
kW
hr
for
engine
certified
to
the
temporary
J
1088
standards
which
are
available
for
all
engine
sizes.
Snowmobiles
For
snowmobiles,
we
are
adopting
an
emissions
averaging
and
credit
program
for
all
three
phases
of
standards.
Averaging
is
available
for
each
phase
of
standards.
Once
the
program
begins
in
2006,
manufacturers
will
make
a
demonstration
of
compliance
with
the
applicable
corporate
average
standards
at
the
end
of
the
model
year.
If
a
manufacturer
has
achieved
a
corporate
average
level
below
the
corporate
average
standards,
then
the
manufacturer
may
bank
credits.
Manufacturers
may
bank
credits
for
use
in
a
current
phase
of
standards
based
on
the
difference
between
their
corporate
average
and
the
standards.
In
order
to
bank
credits
for
future
use
under
a
subsequent
phase
of
standards,
manufacturers
may
pull
engines
from
their
corporate
average
for
the
current
phase
of
standards
and
certify
them
early
to
a
future
phase
of
standards.
The
credits
must
be
generated
based
on
the
difference
between
the
FEL
for
those
engines
and
the
phase
of
standards
for
which
they
are
intended
to
be
used.
The
credits
may
not
be
carried
forward
for
use
to
meet
a
subsequent
phase
of
standards.
For
example,
manufacturers
may
bank
Phase
2
credits
in
2007
by
removing
engines
from
their
2007
corporate
average
for
one
or
both
pollutants
and
certifying
the
engines
to
the
Phase
2
standards
early.
These
Phase
2
credits
may
then
be
saved
for
Phase
2,
but
may
not
be
used
for
Phase
3.
Manufacturers
may
also
remove
only
part
of
an
engine
family
for
purposes
of
banking
credits.
Manufacturers
may
bank
credits
after
the
end
of
the
model
year
when
they
have
completed
their
demonstration
of
compliance
for
that
year.
The
Final
Rule
includes
provisions
for
banking
credits
for
a
single
pollutant,
with
the
other
pollutant
remaining
in
the
averaging
program
for
the
current
model
year.
For
Phase
3,
if
a
manufacturer
chooses
to
bank
credits
for
only
one
pollutant,
the
manufacturer
must
use
an
assigned
value
for
the
other
pollutant
in
the
Phase
3
standards
formula.
We
are
specifying
a
value
of
90
g/
kW
hr
for
HC+
NOX
and
275
g/
kW
hr
for
CO.
These
levels
ensure
no
windfall
credits
using
the
Phase
3
formula
for
the
creditgenerating
engines.
Starting
with
Phase
3,
Family
Emission
Limits
may
be
set
up
to
the
current
average
baseline
emission
levels
of
400
g/
kW
hr
(
300
g/
hp
hr)
CO
and
150
g/
kW
hr
(
110
g/
hp
hr)
HC.
These
caps
ensure
a
minimum
level
of
control
for
each
snowmobile
certified
under
the
long
term
program.
We
believe
this
is
appropriate
due
to
the
potential
for
personal
exposure
to
very
high
levels
of
emissions
as
well
as
the
potential
for
high
levels
of
emissions
in
areas
where
several
snowmobiles
are
operated
in
a
group.
We
proposed
that
these
limits
would
be
effective
beginning
in
2006.
We
received
comments
from
manufacturers
recommending
that
we
drop
the
FEL
limits
because
they
would
create
a
tremendous
near
term
workload
burden.
They
commented
that
manufacturers
would
need
to
modify
all
product
lines
for
2006
just
to
meet
the
FEL
limit.
EPA
recognizes
that
this
could
be
a
significant
issue
in
the
early
years
of
the
program
and
could
detract
from
manufacturers'
efforts
to
develop
much
cleaner
technologies.
Thus,
we
are
finalizing
the
FEL
limits
only
for
Phase
3
and
later,
beginning
in
2012.
We
believe
this
helps
resolve
the
leadtime
and
workload
issues
while
maintaining
the
integrity
of
the
longterm
program.
b.
Early
credits.
We
believe
that
allowing
manufacturers
to
generate
credits
prior
to
2006
has
some
merit
in
that
it
encourages
them
to
produce
cleaner
snowmobiles
earlier
than
they
otherwise
might
and
provides
early
environmental
benefits.
It
would
also
allow
for
a
smoother
transition
to
new
emission
standards
in
a
previously
unregulated
industry.
However,
in
the
proposal
we
expressed
concern
that
an
early
credit
program
could
result
in
the
generation
of
windfall
credits,
especially
if
the
credits
were
generated
relative
to
the
average
baseline
emissions
rates.
A
manufacturer
could
choose
those
engine
families
that
already
emit
below
the
average
baseline
levels
and
certify
those
families
for
credit
generation
purposes
without
doing
anything
to
actually
reduce
their
emissions.
Clearly
this
would
undermine
any
environmental
advantages
of
an
early
credit
program.
However,
we
believe
that
it
is
possible
to
design
an
early
credit
program
which
provides
incentive
for
the
early
introduction
of
cleaner
snowmobiles
and
also
helps
ease
the
transition
into
the
first
ever
phase
of
snowmobile
standards
while
preventing
the
generation
of
windfall
credits.
The
early
credit
program
described
in
the
following
paragraphs
will
be
available
beginning
with
the
2003
model
year.
As
with
the
standard
snowmobile
emissions
averaging,
banking
and
trading
program,
credits
generated
under
the
early
credit
program
will
be
calculated
on
a
power
weighted
basis.
A
manufacturer
can
choose
to
certify
one
or
more
engine
families
early
for
purposes
of
credit
generation.
An
engine
family
must
at
least
meet
the
Phase
1
standards
for
both
HC
and
CO
to
qualify
for
early
credits,
and
the
credits
will
be
calculated
based
on
the
difference
between
the
certification
FEL
and
the
Phase
1
standards.
Credits
generated
under
this
option
can
be
used
only
in
compliance
with
the
Phase
1
standards.
Thus,
such
early
credits
will
expire
at
the
end
of
the
2009
model
year.
The
above
discussion
of
early
credits
primarily
addresses
those
snowmobiles
that
will
meet
the
Phase
1
standards
early.
However,
we
also
expect
that
there
will
be
some
engine
families
introduced
prior
to
the
2006
model
year
which
could
meet
Phase
2
standards.
For
such
engines,
a
manufacturer
may
elect
to
split
credits
between
Phase
1
and
Phase
2.
A
manufacturer
may
save
credits
generated
between
the
certification
FELs
and
the
actual
Phase
2
standards
for
use
in
Phase
2.
Credits
generated
between
the
Phase
1
and
Phase
2
standards
could
be
used
for
Phase
1
only.
Credits
generated
prior
to
the
start
of
the
program
in
2006
may
not
be
used
for
Phase
3.
EPA
did
not
receive
comments
on
such
programs
for
off
highway
motorcycle
or
ATVs
and
we
are
not
finalizing
any
additional
provisions.
The
majority
of
products
currently
offered
for
sale
are
equipped
with
fourstroke
engines
which
raises
concerns
over
the
potential
for
windfall
credits.
Due
to
this
issue
and
the
lack
of
suggestions
or
input
on
the
part
of
commenters,
we
are
not
finalizing
early
credits
or
other
types
of
flexibilities
for
these
programs.
c.
Nonconformance
penalties
for
recreational
vehicles.
Section
206(
g)
of
the
Act,
42
U.
S.
C.
7525(
g),
authorizes
EPA
to
establish
nonconformance
penalties
(
NCPs)
for
motorcycles
and
heavy
duty
engines
which
exceed
the
applicable
emission
standard,
provided
that
their
emissions
do
not
exceed
an
appropriate
upper
limit.
NCPs
allow
manufacturers
that
are
technological
laggards
to
temporarily
sell
their
vehicles
by
payment
of
a
penalty,
rather
than
being
forced
out
of
the
marketplace.
One
manufacturer
suggested
that
we
consider
establishing
NCPs
for
recreational
vehicles.
Section
213(
d)
of
the
Act
makes
nonroad
standards
subject
to
the
provisions
of
section
206,
and
directs
EPA
to
enforce
nonroad
standards
in
the
same
manner
as
highway
vehicles.
We
therefore
believe
that
the
Act
authorizes
us
to
establish
NCPs
in
appropriate
circumstances
for
nonroad
engines
and
vehicles.
Recreational
vehicles
are
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60
The
snowmobile
industry
(
see
docket
item
II
G
221)
and
a
group
of
public
health
and
environmental
organizations
(
see
docket
item
II
G
139)
have
both
expressed
their
general
support
for
labeling
programs
that
can
provide
information
on
the
environmental
performance
of
various
products
to
consumers.
similar
technologically
to
highway
motorcycles,
and
NCPs
might
be
appropriate
for
recreational
vehicles
under
certain
circumstances.
We
will
consider
the
need
for
NCPs
two
or
three
years
before
compliance
with
these
standards
is
required.
Manufacturers
that
determine
in
that
time
frame
that
they
are
likely
to
be
unable
to
comply
with
the
standards
should
notify
us.
If
we
determine
that
NCPs
are
appropriate
for
recreational
vehicles,
we
would
establish
regulations
that
would
specify
how
to
calculate
the
penalties.
While
we
have
not
determined
the
content
of
such
regulations,
it
is
likely
that
they
would
be
similar
to
our
existing
NCP
regulations
for
heavy
duty
engines,
which
are
set
forth
in
40
CFR
part
86,
subpart
L.
3.
Are
There
Voluntary
Low
Emission
Standards
for
These
Engines?
In
the
proposal
we
included
a
Voluntary
Low
Emission
Standards
program
for
recreational
vehicles.
We
did
this
for
two
reasons:
to
encourage
new
emission
control
technology
and
to
aid
the
consumer
in
choosing
clean
technologies.
We
received
numerous
comments
on
this
proposed
program.
The
environmental
community
was
supportive
of
voluntary
standards
and
encouraged
us
to
adopt
permanent
labels
which
identify
the
emission
performance
of
the
vehicle
in
a
simplistic
manner
that
would
be
easily
understood
by
the
initial
purchaser
and
any
purchases
of
used
recreational
vehicles.
Manufacturers
of
recreational
vehicles
ATVs,
off
highway
motorcycles,
and
snowmobiles),
on
the
other
hand,
did
not
support
voluntary
standards.
They
were
supportive
of
providing
initial
purchasers
with
emission
performance
information
via
temporary
consumer
labeling,
but
were
opposed
to
voluntary
standards.
Their
concern
was
that
voluntary
standards
or
permanent
labels
could
be
used
by
federal,
state,
local
or
any
other
jurisdictions
to
limit
the
use
of
recreational
vehicles
from
public
lands
by
allowing
access
only
to
recreational
vehicles
that
meet
certain
emission
criteria.
Manufacturers
further
argued
that
our
proposed
mandatory
emission
standards
were
stringent
enough
that
they
would
encourage
and
result
in
the
use
of
advanced
emission
control
technology
and
that
the
voluntary
standards
would
provide
no
additional
incentives.
As
stated
above,
the
general
purpose
of
the
Voluntary
Low
Emission
Standards
program
is
to
provide
incentives
to
manufacturers
to
produce
clean
products
and
thus
create
market
choices
for
consumers
to
purchase
these
products.
60
For
all
three
recreational
vehicle
categories,
but
especially
for
snowmobiles,
we
are
expecting
a
variety
of
emission
control
technologies
to
be
used
to
meet
the
standards.
In
all
three
categories
we
expect
consumers
to
have
a
choice
of
which
technologies
to
purchase
and
that
they
will
base
that
purchase
on
an
understanding
of
key
attributes
such
as
cost,
performance,
noise
levels,
safety,
and
emissions.
Thus,
an
important
factor
for
informing
consumer
decision
is
to
provide
them
information
on
the
relative
emissions
attributes
of
a
given
model.
We
believe
this
can
be
achieved
through
a
temporary
consumer
labeling
program
without
voluntary
standards.
Therefore,
we
are
not
finalizing
a
voluntary
standard
program
for
recreational
vehicles
at
this
time.
We
will
consider
this
issue
again
in
the
future,
once
experience
is
gained
under
this
program.
In
addition,
given
the
manufacturer's
opposition,
it
is
not
clear
that
voluntary
standards
by
themselves
would
be
an
effective
incentive
for
manufacturers.
Instead,
we
will
be
adopting
a
consumer
labeling
program.
A
label
must
be
fixed
securely
to
the
product
prior
to
arriving
at
the
dealership
but
does
not
have
to
be
permanent
and
may
be
removed
by
the
consumer
when
placed
into
use.
The
label
can
be
in
the
form
of
a
removable
sticker
or
decal,
or
a
hang
tag
affixed
to
the
handlebars
or
fuel
cap.
If
a
hang
tag
is
used,
it
must
be
attached
by
a
cable
tie
that
cannot
be
easily
removed,
except
by
the
ultimate
retail
consumer.
The
label,
at
a
minimum,
must
include
the
following
information:
U.
S.
EPA;
Clean
Air
Index
(
appropriate
pollutant,
e.
g.,
HC+
NOX,
etc.);
manufacturer
name;
vehicle
model
with
engine
description
(
e.
g.,
500
cc
two
stroke
with
direct
fuel
injection);
emission
performance
rating
scale;
explanation
of
scale;
and
notice
stating
that
label
must
be
on
vehicle
prior
to
sale
and
can
be
removed
only
by
the
ultimate
retail
consumer.
In
section
1051.135(
g)
of
the
regulations,
titled
``
How
must
I
label
and
identify
the
vehicles
I
produce?,''
we
have
developed
several
equations
that
determine
what
the
emission
performance
rating
scale
will
be
for
each
category.
The
scale
is
based
on
a
rating
system
of
1.0
through
10.0.
A
value
of
1.0
would
be
assigned
for
the
cleanest
vehicle,
while
the
dirtiest
vehicle
would
get
a
rating
of
10.0.
4.
What
Durability
Provisions
Apply?
We
are
adopting
several
additional
provisions
to
ensure
that
emission
controls
will
be
effective
throughout
the
life
of
the
vehicle.
This
section
discusses
these
provisions
for
recreational
vehicles.
More
general
certification
and
compliance
provisions,
which
apply
across
different
vehicle
categories,
are
discussed
in
Sections
II
and
VII,
respectively.
a.
How
long
do
my
engines
have
to
comply.
Manufacturers
must
produce
off
highway
motorcycle
and
ATV
engines
that
comply
over
a
useful
life
of
5
years
or
until
the
vehicle
accumulates
10,000
kilometers,
or
for
ATVs
1,000
hours,
whichever
occurs
first.
We
consider
the
10,000
kilometer
and
1,000
hour
values
to
be
minimum
values
for
useful
life,
with
the
requirement
that
manufacturers
must
comply
for
a
longer
period
if
the
average
life
of
their
vehicles
is
longer
than
this
minimum
value.
The
values
being
finalized
will
harmonize
EPA's
useful
life
intervals
with
those
contained
in
the
California
program.
We
proposed
a
significantly
longer
useful
life
intervals
of
30,000
kilometers
based
on
our
understanding
of
usage
rates
for
the
vehicles
at
the
time
of
the
proposal.
We
received
comments
from
manufacturers
that
we
overestimated
vehicle
usage
and
commenters
recommended
that
we
harmonize
the
useful
life
intervals
with
California's.
We
have
lowered
our
estimate
of
usage
rates
based
on
available
data,
including
new
data
provided
during
the
comment
period.
Based
on
our
current
estimates
of
usage,
we
concur
with
manufacturers
that
harmonization
with
California
is
the
best
approach
for
establishing
minimum
useful
life
intervals.
Generally,
this
will
allow
the
same
emission
test
data
to
be
used
for
certification
under
both
programs.
However,
this
remains
the
minimum
useful
life
and
longer
useful
life
intervals
could
be
required
in
cases
where
the
basic
mechanical
warranty
of
the
engine
or
the
advertised
operating
life
is
longer
than
the
minimum
interval.
Average
service
life
information
will
help
in
making
such
a
determination.
The
manufacturer
can
alternatively
base
the
longer
useful
life
on
the
average
service
life
of
the
vehicles
where
necessary
data
are
available.
For
snowmobiles,
the
minimum
useful
life
is
5
years,
8,000
km,
or
400
hours
of
operation,
whichever
occurs
first.
We
based
these
values
on
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61
EPA
memorandum,
``
Emission
Modeling
for
Recreational
Vehicles,''
from
Linc
Wehrly
to
Docket
A
2000
01,
November
13,
2000
(
document
II
B
19).
62
While
it
is
possible
that
the
user
could
make
modifications
to
their
competition
off
highway
motorcycle
that
alter
the
emissions
characteristics
of
the
vehicle,
we
do
not
expect
tampering
to
be
a
problem
for
those
competition
vehicles
certifying
to
our
voluntary
standard
of
4.0
g/
km
HC+
NOX
because
the
technologies
required
to
meet
this
standard,
four
stroke
engines
and
direct
fuel
injection
two
stroke
engines,
are
inherent
to
the
engine
and
will
be
optimized
for
maximum
engine
performance
as
well
as
emissions
performance.
Thus,
any
modifications
would
actually
reduce
rather
than
improve
engine
performance.
63
``
Closed
Crankcase
Exhaust
Emissions
from
Four
Stoke
Competition
Off
highway
Motorcycle,''
EPA
memo
from
L.
Wehrly
to
Docket
A
2000
01,
September
10,
2001
(
document
II
B
25).
discussions
with
manufacturers
regarding
typical
snowmobile
life,
and
on
emission
modeling
data
regarding
typical
snowmobile
usage
rates.
61
As
with
ATVs
and
off
highway
motorcycles,
longer
useful
life
intervals
are
required
where
the
basic
mechanical
warranty
of
the
engine
or
the
advertised
operating
life
is
longer
than
the
minimum
interval
and
the
manufacturer
may
alternatively
base
the
longer
useful
life
on
the
average
service
life
of
the
vehicles
where
necessary
data
are
available.
b.
What
are
the
minimum
warranty
periods
for
emission
controls.
For
offhighway
motorcycle,
ATVs,
and
snowmobiles,
manufacturers
must
provide
an
emission
related
warranty
for
at
least
half
of
the
minimum
useful
life
period.
These
periods
could
be
longer
if
the
manufacturer
offers
a
longer
mechanical
warranty
for
the
engine
or
any
of
its
components;
this
includes
extended
warranties
that
are
available
for
an
extra
price.
See
§
1051.120
for
a
description
of
which
components
are
emission
related.
We
have
included
in
our
final
rule
an
optional
set
of
standards
for
off
highway
motorcycles
that
would
require
the
certification
of
competition
motorcycles.
However,
for
those
individual
vehicles
actually
used
in
organized
competition
events,
it
may
be
appropriate
to
exclude
competition
motorcycles
from
warranty
coverage.
Machines
used
in
competition,
even
part
of
the
time,
may
be
subject
to
usage
that
can
cause
premature
degradation
of
the
engine
and
related
components.
Competition
riders
may
place
a
premium
on
winning
at
the
expense
of
engine
durability
or
could
otherwise
damage
the
vehicle
during
the
competition
events.
In
fact,
most
manufacturers
do
not
offer
any
mechanical
warranty
on
vehicles
used
in
competition.
In
addition,
motorcycles
used
only
for
competition
may
be
modified
by
the
user
in
ways
that
alter
the
emissions
characteristics
of
the
vehicle.
62
We
do
not
believe
it
is
reasonable
to
hold
manufacturers
responsible
for
the
emission
warranty
for
such
vehicles.
c.
How
do
I
demonstrate
emission
durability
during
certification.
Durability
demonstration
for
offhighway
motorcycles,
ATVs,
and
snowmobiles
includes
a
requirement
to
run
the
engines
long
enough
to
develop
and
justify
the
full
life
deterioration
factor.
This
allows
manufacturers
to
generate
a
deterioration
factor
that
helps
ensure
that
the
engines
will
continue
to
control
emissions
over
a
lifetime
of
operation.
Snowmobiles
also
must
run
out
to
the
end
of
the
useful
life
for
purposes
of
durability
demonstration
and
generating
deterioration
factors.
d.
What
maintenance
is
allowed
during
service
accumulation.
For
vehicles
certified
to
the
minimum
useful
life,
emission
related
maintenance
is
generally
not
allowed
during
service
accumulation.
The
only
maintenance
that
may
be
done
must
be
(
1)
regularly
scheduled,
(
2)
unrelated
to
emissions,
and
(
3)
technologically
necessary.
This
typically
includes
changing
engine
oil,
oil
filter,
fuel
filter,
and
air
filter.
5.
Do
These
Standards
Apply
to
Alternative
Fueled
Engines?
These
standards
apply
to
all
sparkignited
recreational
vehicles,
without
regard
to
the
type
of
fuel
used.
However,
because
we
are
not
aware
of
any
alternative
fueled
recreational
vehicles
sold
into
the
U.
S.
market,
we
are
not
adopting
extensive
special
provisions
to
address
them
at
this
time.
6.
Is
EPA
Controlling
Crankcase
Emissions?
We
are
requiring
that
new
offhighway
motorcycles
and
ATVs
not
emit
crankcase
vapors
directly
to
the
atmosphere.
This
requirement
will
phase
in
beginning
in
2006
and
be
fully
phased
in
by
2007.
California's
regulations
for
off
highway
motorcycles
and
ATVs,
which
has
been
in
effect
since
1997,
also
prohibits
the
venting
of
crankcase
vapors
into
the
atmosphere.
The
major
ATV
manufacturers
sell
many
of
their
California
certified
ATV
models
federally
as
50
state
applications.
Thus,
many
ATVs
sold
federally
already
control
crankcase
emissions.
The
only
exceptions
could
be
some
of
the
small
youth
ATV
models
that
are
imported
from
Asia.
The
typical
control
strategy
used
to
control
crankcase
emissions
is
to
route
the
crankcase
vapors
back
to
the
engine
intake.
This
is
consistent
with
our
previous
regulation
of
crankcase
emissions
from
such
diverse
sources
as
highway
motorcycles,
outboard
and
personal
water
craft
marine
engines,
locomotives,
and
passenger
cars.
We
have
data
from
California
ARB
showing
that
a
performance
based
four
stroke
offhighway
motorcycle
experienced
considerably
higher
tailpipe
emission
results
when
crankcase
emissions
were
routed
back
into
the
intake
of
the
engine,
illustrating
the
potentially
high
levels
of
crankcase
emissions
that
exist.
63
New
snowmobiles
must
also
have
closed
crankcases,
beginning
in
2006.
This
requirement
is
relevant
only
for
four
stroke
snowmobiles,
however,
since
two
stroke
engines,
by
virtue
of
their
operation,
have
closed
crankcases.
Information
on
the
costs
and
benefits
of
this
action
can
be
found
in
the
Final
Regulatory
Support
Document.
D.
Testing
Requirements
1.
What
Duty
Cycles
Are
Used
To
Measure
Emissions?
Testing
a
vehicle
or
engine
for
emissions
typically
consists
of
exercising
it
over
a
prescribed
duty
cycle
of
speeds
and
loads,
typically
using
a
chassis
or
engine
dynamometer.
The
nature
of
the
duty
cycle
used
for
determining
compliance
with
emission
standards
during
the
certification
process
is
critical
in
evaluating
the
likely
emission
performance
of
engines
designed
to
those
standards.
Duty
cycles
must
be
relatively
comparable
to
the
way
equipment
is
actually
used
because
if
they
are
not,
then
compliance
with
emission
standards
would
not
assure
that
emissions
from
the
equipment
are
actually
being
reduced
in
use
as
intended.
a.
Off
highway
Motorcycles
and
ATVs.
For
testing
off
highway
motorcycles
and
ATVs,
we
specify
the
current
highway
motorcycle
test
procedure
be
used
for
measuring
emissions.
The
highway
motorcycle
test
procedure
is
very
similar
to
the
test
procedure
as
used
for
light
duty
vehicles
(
i.
e.,
passenger
cars
and
trucks)
and
is
referred
to
as
the
Federal
Test
Procedure
(
FTP).
The
FTP
for
a
particular
class
of
engine
or
equipment
is
actually
the
aggregate
of
all
of
the
emission
tests
that
the
engine
or
equipment
must
meet
to
be
certified.
However,
the
term
FTP
has
also
been
used
traditionally
to
refer
to
the
exhaust
emission
test
based
on
the
Urban
Dynamometer
Driving
Schedule
(
UDDS),
also
referred
to
as
the
LA
4
(
Los
Angeles
Driving
Cycle
#
4).
The
UDDS
is
a
chassis
dynamometer
driving
cycle
that
consists
of
numerous
``
hills''
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2002
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Rules
and
Regulations
64
``
Development
and
Validation
of
a
Snowmobile
Engine
Emission
Test
Procedure,''
Jeff
J.
White,
Southwest
Research
Institute
and
Christopher
W.
Wright,
Arctic
Cat,
Inc.,
Society
of
Automotive
Engineers
paper
982017,
September,
1998.
(
Docket
A
2000
1;
document
II
D
05).
which
represent
a
driving
event.
Each
hill
includes
accelerations,
steady
state
operation,
and
decelerations.
There
is
an
idle
between
each
hill.
The
FTP
consists
of
a
cold
start
UDDS,
a
10
minute
soak,
and
a
hot
start.
The
emissions
from
these
three
separate
events
are
collected
into
three
unique
bags.
Each
bag
represents
one
of
the
events.
Bag
1
represents
cold
transient
operation,
Bag
2
represents
cold
stabilized
operation,
and
Bag
3
represents
hot
transient
operation.
For
highway
motorcycles,
we
have
three
classes
based
on
engine
displacement,
with
Class
I
(
50
to
169
cc)
being
the
smallest
and
Class
III
(
280
cc
and
over)
being
the
largest.
The
highway
motorcycle
regulations
allow
Class
I
motorcycles
to
be
tested
on
a
less
severe
UDDS
cycle
than
the
Class
II
and
III
motorcycles.
This
is
accomplished
by
reducing
the
acceleration
and
deceleration
rates
on
some
the
more
aggressive
``
hills.''
We
proposed
to
use
this
same
class/
cycle
distinction
for
offhighway
motorcycles
and
ATVs.
In
other
words,
we
proposed
that
offhighway
motorcycles
and
ATVs
with
an
engine
displacement
at
or
below
169
cc
would
be
tested
over
the
FTP
test
cycle
for
Class
I
highway
motorcycles.
We
proposed
that
off
highway
motorcycles
and
ATVs
with
engine
displacements
greater
than
169
cc
would
be
tested
over
the
FTP
test
cycle
for
Class
II
and
Class
III
highway
motorcycles.
We
requested
comment
on
the
appropriateness
of
allowing
the
use
of
the
Class
I
test
cycle
for
all
ATVs.
Manufacturers
have
expressed
concerns
over
the
appropriateness
of
testing
ATVs
using
the
FTP
and
the
ability
of
some
ATVs
to
be
run
on
the
test
cycle.
Manufacturers
recommended
for
FTP
testing,
that
all
ATVs
be
tested
over
the
Class
I
cycle.
Manufacturers
stated
that
the
Class
I
cycle
top
speed
of
36
mph
would
be
``
much
more
representative''
of
ATV
operation
than
the
57
mph
top
speed
of
the
Class
III
cycle.
Manufacturers
also
noted
that
California
FTP
testing
is
based
on
the
use
of
the
Class
I
cycle
for
all
ATVs
and
that
the
EPA
program
would
need
to
be
changed
allow
for
harmonization.
Manufacturers
did
not
raise
these
same
concern
for
off
highway
motorcycles
which
are
tested
in
accordance
with
the
highway
motorcycle
classifications
for
California.
After
considering
this
issue
further,
we
concur
with
the
manufacturer's
comments
and
are
finalizing
the
Class
I
cycle
for
all
ATVs.
One
of
the
objectives
of
the
final
program
is
to
allow
harmonization
with
California
and
this
change
is
fundamental
in
the
manufacturers'
ability
to
use
the
same
FTP
test
data
for
both
programs.
Also,
the
average
speeds
of
in
use
ATVs
appear
to
be
significantly
lower
than
we
estimated
in
the
analysis
for
the
proposal
(
8
13
mph
compared
to
20
mph).
The
new
data
on
ATV
usage
alleviates
concerns
that
the
lower
speeds
of
the
Class
I
test
cycle
might
miss
significant
high
speed
ATV
operation.
The
change
in
the
test
procedure
is
directionally
consistent
with
this
new
data.
In
addition,
the
change
in
test
procedure
will
enable
ATVs
in
general
to
be
tested
over
the
FTP
with
fewer
issues
concerning
the
ability
of
the
vehicles
to
operate
over
the
driving
cycle.
We
are
finalizing
the
test
procedure
requirements
as
proposed
for
off
highway
motorcycles.
We
believe
that
the
manufacturer's
concerns
regarding
the
FTP
are
also
addressed
by
the
option
to
test
the
smallest
ATVs
(
up
to
100
cc)
to
J
1088
standards
permanently.
These
vehicles
are
typically
governed
to
top
speeds
below
the
36
mph
contained
in
the
Class
I
FTP
cycle.
Also,
the
small
displacement
ATVs
may
be
most
strenuously
tested
(
i.
e.,
more
operation
at
high
loads)
on
the
FTP
due
to
their
lower
horsepower
output.
We
acknowledge
that
chassis
dynamometers
for
ATVs
could
be
costly
to
purchase
and
difficult
to
put
in
place
in
the
near
term,
especially
for
smaller
manufacturers.
As
discussed
in
Section
III.
C.
1.
b,
we
are
allowing
the
use
of
the
J1088
engine
test
cycle
as
a
transitional
option
through
model
year
2008.
The
J1088
option
expires
after
2008
and
the
FTP
becomes
the
required
test
cycle
in
2009.
As
noted
above,
EPA
is
currently
in
discussions
with
ATV
manufacturers
to
determine
whether
a
new
test
cycle
is
appropriate.
The
J1088
may
be
discontinued
earlier
than
2009
if
another
test
procedure
is
implemented.
b.
Snowmobiles.
We
are
adopting
the
snowmobile
duty
cycle
developed
by
Southwest
Research
Institute
(
SwRI)
in
cooperation
with
the
International
Snowmobile
Manufacturers
Association
(
ISMA)
for
all
snowmobile
emission
testing.
64
The
test
procedure
consists
of
two
main
parts;
the
duty
cycle
that
the
snowmobile
engine
operates
over
during
testing
and
other
testing
protocols
surrounding
the
measurement
of
emissions
(
sampling
and
analytical
equipment,
specification
of
test
fuel,
atmospheric
conditions
for
testing,
etc.).
While
the
duty
cycle
was
developed
specifically
to
roughly
approximate
snowmobile
operation,
many
of
the
testing
protocols
are
well
established
in
other
EPA
emission
control
programs
and
have
been
simply
adapted
where
appropriate
for
snowmobiles.
The
snowmobile
duty
cycle
was
developed
by
instrumenting
several
snowmobiles
and
operating
them
in
the
field
in
a
variety
of
typical
riding
styles,
including
aggressive
(
trail),
moderate
(
trail),
double
(
trail
with
operator
and
one
passenger),
freestyle
(
off
trail),
and
lake
driving.
A
statistical
analysis
of
the
collected
data
produced
the
five
mode
steady
state
test
cycle
is
shown
in
Table
III.
D
1.
This
duty
cycle
is
the
one
that
was
used
to
generate
the
baseline
emissions
levels
for
snowmobiles,
and
we
believe
it
is
the
most
appropriate
for
demonstrating
compliance
with
the
snowmobile
emission
standards
at
this
time.
TABLE
III.
D
1.
SNOWMOBILE
ENGINE
TEST
CYCLE
Engine
parameter
Mode
1
2
3
4
5
Normalized
Speed
.........................................................................
1.00
0.85
0.75
0.65
Idle
Normalized
Torque
........................................................................
1.00
0.51
0.33
0.19
0.00
Relative
Weighting
(
in
percent)
.....................................................
12
27
25
31
5
The
rest
of
the
testing
protocol
is
largely
derived
from
our
regulations
for
marine
outboard
and
personal
water
craft
engines,
as
recommended
in
the
SwRI/
ISMA
test
cycle
development
work
(
61
FR
52088,
October
4,
1996).
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Rules
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Regulations
65
For
example,
importers
may
have
access
to
large
supplies
of
vehicles
from
major
overseas
manufacturers
and
potentially
could
substantially
increase
their
market
share
by
selling
less
expensive
noncomplying
products.
The
testing
equipment
and
procedures
from
that
regulation
are
generally
appropriate
for
snowmobiles,
including
the
provisions
for
raw
exhaust
gas
sampling
which
are
being
adopted
here
for
snowmobiles.
Unlike
marine
engines,
however,
snowmobiles
tend
to
operate
in
cold
ambient
temperatures.
Thus,
some
provision
needs
to
be
made
in
the
snowmobile
test
procedure
to
account
for
the
colder
ambient
temperatures
typical
of
snowmobile
operation.
Since
snowmobile
carburetors
are
jetted
for
specific
ambient
temperatures
and
pressures,
appropriate
accounting
for
typical
operating
temperatures
is
important
to
assure
that
anticipated
emissions
reductions
actually
occur
in
use.
We
proposed
that
snowmobile
engine
inlet
air
temperature
be
between
¥
15
°
C
and
¥
5
°
C
(
5
°
F
and
23
°
F),
but
that
the
ambient
temperature
in
the
test
cell
not
be
required
to
be
refrigerated.
We
received
comments
stating
that
this
approach
would
be
expensive
due
to
the
need
for
refrigeration
equipment,
pointing
out
that
the
snowmobile
manufacturers
do
not
currently
have
the
capacity
for
cold
testing.
Further,
we
received
comments
that
accurate
emissions
results
can
be
obtained
using
appropriate
jetting
determined
by
extrapolating
from
the
manufacturer's
jet
chart
(
if
necessary).
We
agree
that
emissions
can
be
accurately
measured
at
higher
ambient
temperatures
provided
that
the
proper
compensation
be
made
in
the
fueling
system.
For
carbureted
engines
this
means
jetting
the
engine
appropriately
for
the
test
temperature.
For
electronically
controlled
engines
this
doesn't
tend
to
be
an
issue
because
such
technology
generally
includes
temperature
compensation
in
its
control
algorithms.
However,
one
manufacturer
stated
that
for
snowmobiles
that
have
electronically
controlled
engines,
it
would
be
preferable
and
environmentally
appropriate
to
test
with
colder
inlet
temperatures.
Thus,
we
are
adopting
the
option
to
allow
snowmobile
testing
using
either
cold
engine
inlet
air
temperatures
between
¥
15
°
C
and
¥
5
°
C
(
5
°
F
and
23
°
F)
or
warm
engine
inlet
air
temperatures
between
20
°
C
and
30
°
C
(
68
°
F
and
86
°
F).
However,
depending
on
the
location
of
the
air
box
where
inlet
air
enters
the
engine
intake
system,
the
inlet
temperature
could
be
considerably
warmer
than
ambient
conditions.
For
a
snowmobile
that
does
not
have
temperature
compensating
capabilities,
it
could
be
possible
to
get
a
moderate
emission
reduction
due
to
the
increase
in
air
density
that
results
at
colder
temperatures
from
the
artificially
induced
test
inlet
air.
These
emission
reductions
would
not
occur
in
real
operation
since
actual
inlet
air
would
be
warmer.
Therefore,
to
use
the
colder
inlet
temperature
option,
a
manufacturer
must
demonstrate
that
for
the
given
engine
family,
the
temperature
of
the
inlet
air
within
the
air
box
is
consistent
with
the
inlet
air
temperature
test
conditions.
2.
What
Fuels
Will
Be
Used
During
Exhaust
Emission
Testing?
We
are
adopting
fuel
specifications
as
proposed
for
all
recreational
vehicles
that
we
have
specified
for
2004
and
later
light
duty
vehicles.
3.
Are
There
Production
Line
Testing
Provisions
for
These
Engines?
Recreational
vehicle
or
engine
manufacturers
must
perform
emission
tests
on
a
small
percentage
of
their
production
as
it
leaves
the
assembly
line
to
ensure
that
production
vehicles
operate
at
certified
emission
levels.
The
broad
outline
of
this
program
is
discussed
in
Section
II.
C.
4
above.
Production
line
testing
must
be
performed
using
the
same
test
procedures
as
for
certification
testing.
E.
Special
Compliance
Provisions
As
described
in
Section
XI.
B,
the
report
of
the
inter
agency
Small
Business
Advocacy
Review
Panel
addresses
the
concerns
of
small
volume
manufacturers
of
recreational
vehicles.
We
proposed
to
adopt
the
provisions
recommended
by
the
panel
and
received
comments
on
the
proposals.
We
are
finalizing
the
provisions
below
as
proposed,
with
the
modifications
as
noted.
Off
Highway
Motorcycles
and
ATVs
To
identify
representatives
of
small
businesses
for
this
process,
we
used
the
definitions
provided
by
the
Small
Business
Administration
for
motorcycles,
ATVs,
and
snowmobiles
(
fewer
than
500
employees).
Eleven
small
businesses
agreed
to
serve
as
small
entity
representatives.
These
companies
represented
a
cross
section
of
off
highway
motorcycle,
ATV,
and
snowmobile
manufacturers,
as
well
as
importers
of
off
highway
motorcycles
and
ATVs.
As
discussed
above,
our
emission
standards
for
off
highway
motorcycles
and
ATVs
will
likely
necessitate
the
widespread
use
of
four
stroke
engines.
Most
small
volume
off
highway
motorcycle
and
ATV
importers
and
to
a
lesser
degree,
small
volume
manufacturers
currently
use
twostroke
engines.
While
four
stroke
engines
are
common
in
motorcycles
and
ATVs
in
general,
their
adoption
by
any
manufacturer
is
still
a
significant
business
challenge.
Small
manufacturers
of
these
engines
may
face
additional
challenges
in
certifying
engines
to
emission
standards,
because
the
cost
of
certification
would
be
spread
over
the
relatively
few
engines
they
produce.
These
higher
per
unit
costs
may
place
small
manufacturers
at
a
competitive
disadvantage
without
specific
provisions
to
address
this
burden.
We
are
applying
the
flexibilities
described
below
to
engines
produced
or
imported
by
small
entities
with
combined
off
highway
motorcycle
and
ATV
annual
sales
of
fewer
than
5,000
units.
The
inter
agency
panel
recommended
these
provisions
to
address
the
potentially
significant
adverse
effects
on
small
entities
of
an
emission
standard
that
may
require
conversion
to
four
stroke
engines.
The
5,000
unit
threshold
is
intended
to
focus
these
flexibilities
on
those
segments
of
the
market
where
the
need
is
likely
to
be
greatest
and
to
ensure
that
the
flexibilities
do
not
result
in
significant
adverse
environmental
effects
during
the
period
of
additional
lead
time
recommended
below.
65
In
addition,
we
are
limiting
some
or
all
of
these
flexibilities
to
companies
that
are
in
existence
or
have
product
sales
at
the
time
we
proposed
emission
standards
to
avoid
creating
arbitrary
opportunities
in
the
import
sector,
and
to
guard
against
the
possibility
of
corporate
reorganization,
entry
into
the
market,
or
other
action
for
the
sole
purpose
of
circumventing
emission
standards.
Snowmobiles
There
are
only
a
few
small
snowmobile
manufacturers
and
they
sell
only
a
few
hundred
sleds
a
year,
which
represents
less
than
0.5
percent
of
total
annual
production.
Therefore,
the
perunit
cost
of
regulation
may
be
significantly
higher
for
these
small
entities
because
they
produce
very
low
volumes.
Additionally,
these
companies
do
not
have
the
design
and
engineering
resources
to
tackle
compliance
with
emission
standard
requirements
at
the
same
time
as
large
manufacturers
and
tend
to
have
limited
ability
to
invest
the
capital
necessary
to
conduct
emission
testing
related
to
research,
development,
and
certification.
Finally,
the
requirements
of
the
snowmobile
program
may
be
infeasible
or
highly
impractical
because
some
small
volume
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Rules
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manufacturers
may
have
typically
produced
engines
with
unique
designs
or
calibrations
to
serve
niche
markets
(
such
as
mountain
riding).
The
new
snowmobile
emission
standards
may
impose
significant
economic
hardship
on
these
few
manufacturers
whose
market
presence
is
small.
We
therefore
believe
significant
flexibility
is
necessary
and
appropriate
for
this
category
of
small
entities,
as
described
below.
Flexibilities
1.
Additional
lead
time.
We
are
adopting
a
delay
of
two
years
beyond
the
date
larger
businesses
must
comply
to
ease
the
burden
for
small
businesses.
This
will
provide
extra
time
to
develop
technology
and,
in
the
case
of
importers,
extra
time
to
resolve
supplier
issues
that
may
arise.
The
two
year
delay
also
applies
to
the
timing
of
the
Phase
2
standards
for
snowmobiles.
In
addition,
for
small
snowmobile
manufacturers,
the
emission
standards
phase
in
over
an
additional
two
years
at
a
rate
of
50
percent,
then
100
percent.
Phase
1
phases
in
at
50/
50/
100
percent
in
2008/
2009/
2010
and
Phase
2
phases
in
at
50/
50/
100
percent
in
2012/
2013/
2014.
2.
Design
based
certification.
The
process
of
certification
is
a
business
cost
and
lead
time
issue
that
may
place
a
disproportionate
burden
on
small
entities,
particularly
importers.
Certification
is
a
fixed
cost
of
doing
business,
which
is
potentially
more
burdensome
on
a
unit
cost
basis
for
small
entities.
It
is
potentially
an
even
greater
challenge,
since
some
small
entities
will
either
contract
emission
testing
to
other
parties
or,
in
the
case
of
importers,
perhaps
rely
on
off
shore
manufacturers
to
develop
and
certify
imported
engines.
Small
volume
manufacturers
may
use
design
based
certification,
which
allows
us
to
issue
a
certificate
to
a
small
business
for
the
emission
performance
standard
based
on
a
demonstration
that
engines
or
vehicles
of
a
similar
design
criteria
meet
the
standards
of
the
individual
engine
family.
The
small
vehicle
manufacturer
must
demonstrate
that
their
engine
uses
a
design
similar
to
or
superior
to
one
that
is
being
used
by
other
manufacturers
that
has
been
shown
through
prior
emission
testing
to
meet
the
standards.
The
demonstration
must
be
based
in
part
on
emission
test
data
from
engines
of
a
similar
design.
Under
a
design
based
certification
program,
a
manufacturer
provides
evidence
in
the
application
for
certification
that
an
engine
or
vehicle
meets
the
applicable
standards
for
its
useful
life
based
on
comparing
its
design
(
for
example,
the
use
a
fourstroke
engine,
advanced
fuel
injection,
or
any
other
particular
technology
or
calibration)
to
that
of
a
previously
tested
engine.
The
design
criteria
might
include
specifications
for
engine
type,
calibrations
(
spark
timing,
air
/
fuel
ratio,
etc.),
and
other
emission
critical
features,
including,
if
appropriate,
catalysts
(
size,
efficiency,
precious
metal
loading).
Manufacturers
submit
adequate
engineering
and
other
information
about
their
individual
designs
showing
that
they
will
meet
emission
standards
for
the
useful
life.
3.
Broaden
engine
families.
Small
businesses
may
define
their
engine
families
more
broadly,
putting
all
their
models
into
one
engine
family
(
or
more)
for
certification
purposes.
Manufacturers
may
then
certify
their
engines
using
the
``
worst
case''
configuration
within
the
family.
A
small
manufacturer
might
need
to
conduct
certification
emission
testing
rather
than
pursuing
design
based
certification.
Such
a
manufacturer
would
likely
find
broadened
engine
families
useful.
4.
Production
line
testing
waiver.
As
discussed
above,
manufacturers
must
test
a
small
sampling
of
production
engines
to
ensure
that
production
engines
meet
emission
standards.
We
are
waiving
production
line
testing
requirements
for
small
manufacturers.
This
will
eliminate
or
substantially
reduce
production
line
testing
requirements
for
small
businesses.
5.
Use
of
assigned
deterioration
factors
for
certification.
Small
manufacturers
may
use
deterioration
factors
assigned
by
EPA.
Rather
than
performing
a
durability
demonstration
for
each
family
for
certification,
manufacturers
may
elect
to
use
deterioration
factors
determined
by
us
to
demonstrate
emission
levels
at
the
end
of
the
useful
life,
thus
reducing
the
development
and
testing
burden.
This
might
be
a
very
useful
and
costbeneficial
option
for
a
small
manufacturer
opting
to
perform
certification
emission
testing
instead
of
design
based
certification.
6.
Using
emission
standards
and
certification
from
other
EPA
programs.
A
wide
array
of
engines
certified
to
other
EPA
programs
may
be
used
in
recreational
vehicles.
For
example,
there
is
a
large
variety
of
engines
certified
to
EPA
lawn
and
garden
standards
(
Small
SI).
Manufacturers
of
recreational
vehicles
may
use
engines
certified
to
any
other
EPA
standards
for
five
years.
Under
this
approach,
engines
certified
to
the
Small
SI
standards
may
be
used
in
recreational
vehicles.
These
engines
would
then
meet
the
Small
SI
standards
and
related
provisions
rather
than
those
adopted
in
this
document
for
recreational
vehicles.
Small
businesses
using
these
engines
will
not
have
to
recertify
them,
as
long
as
they
do
not
alter
the
engines
in
a
way
that
might
cause
it
to
exceed
the
emission
standards
it
was
originally
certified
to
meet.
Also,
the
recreational
vehicle
application
may
not
be
the
primary
intended
application
for
the
engine.
Additionally,
a
certified
snowmobile
engine
produced
by
a
large
snowmobile
manufacturer
may
be
used
by
a
small
snowmobile
manufacturer,
as
long
as
the
small
manufacturer
did
not
change
the
engine
in
a
way
that
might
cause
it
to
exceed
the
snowmobile
emission
standards.
This
provides
a
reasonable
degree
of
emission
control.
For
example,
if
a
manufacturer
changed
a
certified
engine
only
by
replacing
the
stock
exhaust
pipes
with
pipes
of
similar
configuration
or
the
stock
muffler
and
air
intake
box
with
a
muffler
and
air
box
of
similar
air
flow,
the
engine
would
still
be
eligible
for
this
flexibility
option,
subject
to
our
review.
The
manufacturer
may
also
change
the
carburetor
to
have
a
leaner
air
fuel
ratio
without
losing
eligibility.
The
manufacturer
in
such
cases
could
establish
a
reasonable
basis
for
knowing
that
emissions
performance
is
not
negatively
affected
by
the
changes.
However,
if
the
manufacturer
changed
the
bore
or
stroke
of
the
engine,
it
would
no
longer
qualify,
as
emissions
might
increase
beyond
the
level
of
the
standard.
7.
Averaging,
banking,
and
trading.
For
the
overall
program,
we
are
adopting
corporate
average
emission
standards
with
opportunities
for
banking
and
trading
of
emission
credits.
We
expect
the
averaging
provisions
to
be
most
helpful
to
manufacturers
with
broad
product
lines.
Small
manufacturers
and
small
importers
with
only
a
few
models
might
not
have
as
much
opportunity
to
take
advantage
of
these
flexibilities.
However,
we
received
comment
from
one
small
manufacturer
supporting
these
types
of
provisions
as
a
critical
component
of
the
program.
Therefore,
we
are
adopting
corporateaverage
emission
standards
with
opportunities
for
banking
and
trading
of
emission
credits
for
small
manufacturers.
8.
Hardship
provisions.
We
are
adopting
provisions
to
address
hardship
circumstances,
as
described
in
Section
VII.
C.
9.
Unique
snowmobile
engines.
Even
with
the
broad
flexibilities
described
above,
there
may
be
a
situation
where
a
small
snowmobile
manufacturer
cannot
comply.
Therefore,
we
are
adopting
an
additional
provision
to
allow
a
small
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Rules
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66
The
engines
are
small
relative
to
automotive
engines.
For
example,
automotive
engines
typically
range
from
one
liter
to
well
over
five
liters
in
displacement,
whereas
off
highway
motorcycles
range
from
0.05
liters
to
0.65
liters.
snowmobile
manufacturer
to
petition
us
for
relaxed
standards
for
one
or
more
engine
families.
The
manufacturer
must
justify
that
the
engine
has
unique
design,
calibration,
or
operating
characteristics
that
make
it
atypical
and
infeasible
or
highly
impractical
to
meet
the
emission
reduction
requirements,
considering
technology,
cost,
and
other
factors.
At
our
discretion,
we
may
then
set
an
alternative
standard
at
a
level
between
the
prescribed
standard
and
the
baseline
level,
which
would
likely
apply
until
the
engine
family
is
retired
or
modified
in
a
way
that
might
alter
emissions.
These
engines
will
be
excluded
from
averaging
calculations.
We
proposed
that
this
provision
be
limited
to
300
snowmobiles
per
year.
However,
we
received
comment
that
this
limit
is
too
restrictive
to
be
of
much
assistance
to
small
businesses.
Based
on
this
comment
we
are
adopting
a
limit
for
this
provision
of
600
snowmobiles
per
year.
F.
Technological
Feasibility
of
the
Standards
1.
Off
highway
Motorcycles
and
ATVs
We
believe
the
new
emission
standards
are
technologically
feasible
given
the
availability
of
emissioncontrol
technologies,
as
described
below.
a.
What
are
the
baseline
technologies
and
emission
levels?
As
discussed
earlier,
off
highway
motorcycles
and
ATVs
are
equipped
with
relatively
small
(
48
to
650
cc)
high
performance
two
or
four
stroke
single
cylinder
engines
that
are
either
air
or
liquid
cooled.
66
Since
these
vehicles
are
unregulated
outside
of
the
state
of
California,
the
main
emphasis
of
engine
design
is
on
performance,
durability,
and
cost
and
thus
they
generally
have
no
emission
controls.
The
fuel
systems
used
on
these
engines
are
almost
exclusively
carburetted.
Two
stroke
engines
lubricate
the
piston
and
crankshaft
by
mixing
oil
with
the
air
and
fuel
mixture.
This
is
accomplished
by
most
contemporary
two
stroke
engines
with
a
pump
that
sends
two
cycle
oil
from
a
separate
oil
reserve
to
the
carburetor
where
it
is
mixed
with
the
air
and
fuel
mixture.
Some
less
expensive
twostroke
engines
require
that
the
oil
be
mixed
with
the
gasoline
in
the
fuel
tank.
Four
stroke
engines
inject
oil
via
a
pump
throughout
the
engine
as
the
means
of
lubrication.
With
the
exception
of
those
vehicles
certified
in
California,
most
of
these
engines
are
unregulated
and
thus
have
no
emission
controls.
For
ATVs,
approximately
80
percent
use
four
stroke
engines
while
only
55
percent
of
off
highway
motorcycles
use
four
stroke
engines.
The
average
HC
emissions
for
twostroke
engines
are
about
35
g/
km,
while
the
average
for
four
stroke
engines
are
1.5
g/
km.
CO
emissions
levels
are
very
similar
between
the
types
of
engines
with
two
stroke
levels
of
approximately
34
g/
km
and
four
stroke
levels
of
30
g/
km.
For
performance
and
durability
reasons,
off
highway
motorcycle
and
ATV
engines
all
tend
to
operate
with
a
``
rich''
air
and
fuel
mixture.
That
is,
they
operate
with
excess
fuel,
which
enhances
performance
and
allows
engine
cooling
to
promote
longer
engine
life.
However,
rich
operation
results
in
high
levels
of
HC,
CO,
and
PM
emissions.
Also,
two
stroke
engines
tend
to
have
high
scavenging
losses,
where
up
to
a
third
of
the
unburned
air
and
fuel
mixture
goes
out
of
the
exhaust
resulting
in
high
levels
of
HC
emissions.
b.
What
technology
approaches
are
available
to
control
emissions?
Several
approaches
are
available
to
control
emissions
from
off
highway
motorcycles
and
ATVs.
The
simplest
approach
consists
of
modifications
to
the
base
engine,
fuel
system,
cooling
system,
and
recalibration
of
the
air
and
fuel
mixture.
These
changes
may
include
adjusting
valve
timing
for
four
stroke
engines,
changing
from
air
to
liquid
cooling,
and
using
advanced
carburetion
techniques
or
electronic
fuel
injection
instead
of
traditional
carburetion
systems.
Other
approaches
may
include
secondary
air
injected
into
the
exhaust,
an
oxidation
or
three
way
catalyst,
or
a
combination
of
secondary
air
and
a
catalyst.
The
engine
technology
that
may
have
the
most
potential
for
maximizing
emission
reductions
from
two
stroke
engines
is
direct
fuel
injection.
Direct
fuel
injection
is
able
to
reduce
or
even
eliminate
scavenging
losses
by
pumping
only
air
through
the
engine
and
then
injecting
fuel
into
the
combustion
chamber
after
the
intake
and
exhaust
ports
have
closed.
Using
oxidation
catalysts
with
direct
injection
may
reduce
emissions
even
further.
Finally,
converting
from
two
stroke
to
fourstroke
engine
technology
will
significantly
reduce
HC
emissions.
All
of
these
technologies
have
the
capability
to
reduce
HC
and
CO
emissions.
We
expect
none
of
these
technologies
to
negatively
affect
noise,
safety,
or
energy
factors.
Fuel
injection
can
improve
the
combustion
process
which
can
result
in
lower
engine
noise.
The
vast
majority
of
four
stroke
engines
used
in
off
highway
motorcycles
and
ATVs
are
considerably
quieter
than
their
twostroke
counterparts.
Fuel
injection
has
no
impact
on
safety
and
four
stroke
engines
often
have
a
more
``
forgiving''
power
band
which
means
the
typical
operator
may
find
the
performance
of
the
machine
to
be
more
reasonable
and
safe.
Fuel
injection,
the
enleanment
of
the
air
and
fuel
mixture
and
four
stroke
technology
all
can
result
in
significant
reductions
in
fuel
consumption.
c.
What
technologies
are
most
likely
to
be
used
to
meet
emission
standards?
Four
Stroke
Engines
Most
manufacturers
have
experience
with
four
stroke
engine
technology
and
currently
have
several
models
powered
by
four
stroke
engines.
This
is
especially
true
in
the
ATV
market
where
four
stroke
engines
account
for
80
percent
of
sales.
Because
four
stroke
engines
have
been
so
prevalent
over
the
last
10
years
in
the
off
highway
motorcycle
and
ATV
industry,
manufacturers
have
developed
a
high
level
of
confidence
in
four
stroke
technology
and
its
application.
Manufacturers
of
off
highway
motorcycles
and
ATVs
utilizing
fourstroke
engines
will
need
to
make
some
minor
calibration
changes
and
improvements
to
the
carburetor
to
meet
emission
standards
for
the
2006
model
year.
Some
of
these
modifications
may
have
already
been
incorporated
in
response
to
California
requirements.
The
calibration
changes
will
most
likely
consist
of
reducing
the
amount
of
fuel
in
the
air
fuel
mixture.
This
is
commonly
referred
to
as
leaning
out
the
air
fuel
ratio.
Although
four
stroke
engines
produce
considerably
lower
levels
of
HC
than
two
stroke
engines,
the
four
stroke
engines
used
in
offhighway
motorcycles
and
ATVs
all
tend
to
be
calibrated
to
operate
with
a
rich
air
fuel
ratio
for
performance
and
durability
benefits.
This
rich
operation
results
in
high
levels
of
CO,
since
CO
is
formed
in
the
engine
when
there
is
a
lack
of
oxygen
to
complete
combustion.
We
believe
that
many
of
these
engines
are
calibrated
to
operate
richer
than
needed,
because
they
have
either
never
had
to
consider
emissions
when
optimizing
air
fuel
ratio
or
those
that
are
certified
to
the
California
standards
can
operate
richer
because
the
California
ATV
CO
standards
are
fairly
lenient.
Carburetors
with
tighter
tolerances
ensure
more
precise
flow
of
fuel
and
air,
resulting
in
better
fuel
atomization
(
i.
e.,
smaller
fuel
droplets),
better
combustion,
and
lower
emissions.
In
addition
to
converting
to
fourstroke
technology
and
making
some
minor
calibration
and
carburetion
improvements
to
meet
the
2006
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Regulations
emission
standards,
manufacturers
may
need
to
use
secondary
air
injection
on
some
models.
Secondary
air
has
been
used
by
passenger
cars
and
highway
motorcycles
for
many
years
as
a
means
to
help
control
HC
and
CO.
The
hot
exhaust
gases
coming
from
the
combustion
chamber
contain
significant
levels
of
unburned
HC
and
CO.
If
sufficient
oxygen
is
present,
these
gases
will
continue
to
react
in
the
exhaust
system,
reducing
the
amount
of
pollution
emitted
into
the
atmosphere.
To
assure
that
sufficient
oxygen
is
present
in
the
exhaust,
air
is
injected
into
the
exhaust
system.
For
offhighway
motorcycles
and
ATVs,
the
additional
air
can
be
injected
into
the
exhaust
manifold
using
a
series
of
check
valves
which
use
the
normal
pressure
pulsations
in
the
exhaust
manifold
to
draw
air
from
outside,
commonly
referred
to
as
pulse
air
injection.
We
have
tested
several
four
stroke
ATVs
with
secondary
air
injected
into
the
exhaust
manifold
and
found
that
the
HC
and
CO
emission
levels
were
below
the
standards
(
further
details
of
our
secondary
air
testing
are
described
in
the
Final
Regulatory
Support
Document).
A
small
number
of
models
in
California
have
been
equipped
with
secondary
air
technology.
It
is
likely
that
some
manufacturers
will
opt
to
use
secondary
air
systems
to
reduce
emissions
in
addition
to
enleanment
strategies
to
meet
EPA
standards.
We
believe
this
may
be
especially
true
for
ATVs
meeting
the
1.5
g/
km
HC+
NOX
standard.
Using
these
systems
would
also
provide
manufacturers
with
more
flexibility
within
the
averaging
scheme
and
would
allow
them
to
avoid
any
negative
affects
on
performance
that
could
accompany
excessive
enleanment.
Also,
several
models
are
not
certified
to
California
standards,
including
some
four
stroke
models.
Manufacturers
may
use
secondary
air
on
a
more
widespread
basis
to
bring
all
models
into
compliance.
Since
the
emission
standards
address
HC
+
NOX,
as
well
as
CO,
manufacturers
will
have
to
use
an
emission
control
strategy
or
technology
that
doesn't
cause
NOX
emissions
to
increase
disproportionately.
However,
since
all
of
these
vehicles
operate
with
rich
airfuel
ratios,
as
discussed
above,
NOX
levels
from
these
engines
are
generally
low
and
strategies
designed
to
focus
on
HC
reduction
allow
manufacturers
to
meet
emission
standards
with
no
significant
increase
in
NOX
levels.
Two
Stroke
Engines
Off
highway
motorcycles
and
ATVs
using
two
stroke
engines
will
present
a
greater
challenge
for
compliance
with
emission
standards.
Since
baseline
HC
and
CO
emission
levels
are
so
high
for
two
stroke
engines,
it
would
be
very
difficult
for
any
two
stroke
engine
to
meet
our
standards
with
current
production
technologies.
Although
catalysts
have
been
used
for
two
stroke
powered
mopeds,
scooters,
and
small
displacement
highway
motorcycles
in
Europe
and
Asia,
the
standards
and
test
cycles
are
significantly
different
from
ours
and
there
is
no
way
to
make
reasonable
comparisons.
We
have
not
performed
any
testing,
nor
are
we
aware
of
any
emission
test
data
on
the
use
of
catalysts
on
ATV
and
off
highway
motorcycle
two
stroke
engines.
Therefore,
we
do
not
believe
that
catalysts
would
be
available
for
twostroke
engines
that
would
meet
our
standards
in
the
time
frame
necessary
to
comply
with
our
program.
Direct
fuel
injection
has
been
successfully
applied
to
two
stroke
engines
used
in
marine
personal
water
craft,
outboard
engines,
and
small
mopeds
and
scooters
and
is
just
now
being
looked
at
for
off
highway
motorcycle
applications.
However,
as
discussed
below,
even
this
advanced
technology
cannot
meet
our
standards
alone.
As
described
in
Section
III.
C.
1.
a,
we
are
including
an
optional
standard
for
off
highway
motorcycles
of
4.0
g/
km
HC
+
NOX,
for
manufacturers
willing
to
certify
competition
motorcycles
that
would
otherwise
be
exempt
from
emission
standards.
We
received
comment
from
REV!
Motorcycles
in
support
of
this
level.
Rev!
plans
to
manufacture
two
stroke
off
highway
motorcycles
equipped
with
direct
injection.
Based
on
an
early
analysis
of
the
technology,
REV!
requested
that
EPA
consider
establishing
a
4.0
g/
km
standard
to
allow
them
to
pursue
the
technology
and
have
a
realistic
opportunity
to
meet
emission
standards.
According
to
their
comments,
they
believe
that
their
engines
will
be
capable
of
meeting
the
4.0
g/
km
standard
without
the
use
of
a
catalyst.
Perhaps
most
importantly,
REV!
believes
that
this
is
a
viable
technology
approach
for
competition
models,
which
have
very
high
baseline
emissions.
REV!
shared
their
plans
and
emissions
projections
for
a
single
prototype
model
of
competition
motorcycle.
Production
units,
additional
models,
or
motorcycles
produced
by
other
manufacturers
using
similar
technologies
may
not
be
able
to
achieve
the
4.0
g/
km
level.
The
4.0
g/
km
level
represents
an
HC
reduction
of
90
percent
or
more
from
baseline
levels
for
some
competition
motorcycles,
which
is
likely
to
be
very
challenging.
This
is
one
reason
EPA
is
also
allowing
averaging,
banking,
and
trading
for
this
option.
Averaging
will
provide
flexibility
to
manufacturers
who
have
some
models
that,
while
very
clean
relative
to
baseline
levels,
are
above
the
4.0
g/
km
standard.
Manufacturers
will
be
able
to
use
credits,
for
example,
from
the
sale
of
four
stroke
machines
with
emissions
below
4.0
g/
km
to
achieve
the
4.0
g/
km
standard
on
average.
2.
Snowmobiles
a.
What
are
the
baseline
technologies
and
emission
levels?
As
discussed
earlier,
snowmobiles
are
equipped
with
relatively
small
high
performance
twostroke
two
and
three
cylinder
engines
that
are
either
air
or
liquid
cooled.
Since
these
vehicles
are
currently
unregulated,
the
main
emphasis
of
engine
design
is
on
performance,
durability,
and
cost
and
thus
they
have
no
emission
controls.
The
fuel
system
used
on
these
engines
are
almost
exclusively
carburetors,
although
some
have
electronic
fuel
injection.
Twostroke
engines
lubricate
the
piston
and
crankshaft
by
mixing
oil
with
the
air
and
fuel
mixture.
This
is
accomplished
by
most
contemporary
two
stroke
engines
with
a
pump
that
sends
twocycle
oil
from
a
separate
oil
reserve
to
the
carburetor
where
it
is
mixed
with
the
air
and
fuel
mixture.
Some
less
expensive
two
stroke
engines
require
that
the
oil
be
mixed
with
the
gasoline
in
the
fuel
tank.
Snowmobiles
currently
operate
with
a
``
rich''
air
and
fuel
mixture.
That
is,
they
operate
with
excess
fuel,
which
enhances
performance
and
allows
engine
cooling
which
promotes
longer
lasting
engine
life.
However,
rich
operation
results
in
high
levels
of
HC,
CO,
and
PM
emissions.
Also,
two
stroke
engines
tend
to
have
high
scavenging
losses,
where
up
to
a
third
of
the
unburned
air
and
fuel
mixture
goes
out
of
the
exhaust
resulting
in
high
levels
of
raw
HC.
Current
average
snowmobile
emission
rates
are
400
g/
kW
hr
(
296
g/
hp
hr)
CO
and
150
g/
kW
hr
(
111
g/
hp
hr)
HC.
There
are
however,
at
least
two
snowmobile
models
that
use
four
stroke
engines.
Two
companies
currently
have
a
moderate
powered
four
stroke
touring
model
that
has
very
low
emissions.
One
sled
uses
a
small
advanced
automotive
engine,
while
the
other
uses
a
modified
ATV
engine.
Both
engines
are
very
sophisticated,
using
electronic
fuel
injection
and
computer
based
closedloop
control.
The
other
snowmobile
manufacturers
are
planning
to
release
four
stroke
models
for
the
2003
model
year,
but
are
focusing
on
higher
performing
models
that,
according
to
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Regulations
the
manufacturers,
may
not
have
as
good
of
emissions
control
as
the
production
four
stroke
touring
models.
b.
What
technology
approaches
are
available
to
control
emissions?
We
believe
the
new
emission
standards
are
technologically
feasible.
A
variety
of
technologies
are
currently
available
or
in
stages
of
development
to
be
available
for
use
on
two
stroke
snowmobiles.
These
include
improvements
to
carburetion
(
improved
fuel
control
and
atomization,
as
well
as
improved
production
tolerances),
enleanment
strategies
for
both
carbureted
and
fuel
injected
engines,
and
semi
direct
and
direct
fuel
injection.
In
addition
to
these
two
stroke
technologies,
converting
to
four
stroke
engines
is
also
feasible.
Each
of
these
is
discussed
in
the
following
paragraphs.
There
are
several
ways
to
improve
carburetion
in
snowmobile
engines.
First,
strategies
to
improve
fuel
atomization
promote
more
complete
combustion
of
the
fuel/
air
mixture.
Additionally,
improved
production
tolerances
enable
more
consistent
fuel
metering.
Both
of
these
changes
allow
more
accurate
control
of
air
fuel
ratios.
Snowmobile
engines
are
currently
calibrated
with
rich
air
fuel
ratios
for
durability
reasons.
Leaner
calibrations
to
CO
and
HC
emissions
pose
a
challenge
for
maintaining
engine
durability,
but
many
engine
improvements
are
available
to
prevent
problems.
These
include
changes
to
the
cylinder
head,
pistons,
ports
and
pipes
to
reduce
knock.
In
addition
critical
engine
components
can
be
made
more
robust
to
improve
durability.
The
same
calibration
changes
to
the
air
fuel
ratio
just
discussed
for
carbureted
engines
can
also
be
employed,
possibly
with
more
accuracy,
by
using
fuel
injection.
At
least
one
major
snowmobile
manufacturer
currently
employs
electronic
fuel
injection
on
several
of
its
snowmobile
models.
In
addition
to
rich
air
fuel
ratios,
one
of
the
main
reasons
that
two
stroke
engines
have
such
high
HC
emission
levels
is
that
they
release
a
substantial
amount
of
unburned
fuel
into
the
atmosphere
as
a
result
from
scavenging
losses,
as
described
above.
One
way
to
reduce
or
eliminate
such
losses
is
to
inject
the
fuel
into
the
cylinder
after
the
exhaust
port
has
closed.
This
can
be
done
by
injecting
the
fuel
into
the
cylinder
through
the
transfer
port
(
semidirect
injection)
or
directly
into
the
cylinder
(
direct
injection).
Both
of
these
approaches
are
currently
being
used
successfully
in
two
stroke
personal
water
craft
engines.
We
believe
these
technologies
hold
promise
for
application
to
snowmobiles.
In
fact,
one
company
is
offering
a
snowmobile
with
a
semi
direct
injection
two
stroke
engine
for
the
2003
model
year.
Manufacturers
must
address
a
variety
of
technical
design
issues
for
adapting
the
technology
to
snowmobile
operation,
such
as
operating
in
colder
ambient
temperatures
and
at
variable
altitude.
The
averaging
approach
and
the
several
years
of
lead
time
give
manufacturers
time
to
incorporate
these
development
efforts
into
their
overall
research
plan
as
they
apply
these
technologies
to
snowmobiles.
In
addition
to
the
two
stroke
technologies
just
discussed,
using
fourstroke
engines
in
snowmobiles
is
another
feasible
approach
to
reduce
emissions.
Since
they
do
not
scavenge
the
exhaust
gases
with
the
incoming
airfuel
mixture,
four
stroke
engines
have
inherently
lower
HC
emissions
compared
to
two
stroke
engines.
Fourstroke
engines
have
a
lower
power
todisplacement
ratio
than
two
stroke
engines
and
are
heavier.
Thus,
initially
they
may
be
more
appropriate
for
snowmobile
models
where
extreme
power
and
acceleration
are
not
the
primary
selling
points.
Such
models
include
touring
and
sport
trail
sleds.
However,
one
company
has
developed
a
four
stroke
engine
based
off
one
of
their
sport
highway
motorcycle
engines
that
produces
150
horsepower
and
will
be
used
in
their
high
performance
snowmobiles
in
the
2003
model
year.
c.
What
technologies
are
most
likely
to
be
used
to
meet
emission
standards?
2006
Standards
We
expect
that,
in
the
context
of
an
emissions
averaging
program,
manufacturers
might
choose
to
take
different
paths
to
meet
the
2006
emission
standards.
We
expect
manufacturers
to
use
a
mix
of
technologies
that
will
include
improved
carburetion
and
enleanment
strategies,
combined
with
engine
modifications,
the
use
of
direct
injection,
and
the
use
of
four
stroke
engine
technology.
For
example,
depending
on
their
emission
rates,
one
scenario
for
meeting
our
standards
could
be
a
mixture
of
60
percent
using
improved
carburetion,
enleanment
strategies,
and
engine
modifications,
15
percent
using
direct
injection,
and
another
15
percent
using
four
stroke
engines.
Manufacturers
can
expect
moderate
emission
reductions
from
engine
modifications
and
enleanment
strategies.
Most
two
stroke
snowmobile
engines
are
designed
to
operate
with
a
rich
air
and
fuel
mixture,
which
result
in
high
levels
of
HC,
CO,
and
PM.
By
reducing
the
amount
of
fuel
in
the
air
and
fuel
mixture
(
i.
e.,
enleanment),
these
emissions
can
be
reduced.
Because
manufacturers
use
the
extra
fuel
in
the
air
and
fuel
mixture
to
help
cool
the
engine,
some
modifications
such
as
the
use
of
more
robust
materials,
may
be
necessary.
Manufacturers
have
indicated
to
us
that
direct
injection
strategies
can
result
in
emission
reductions
of
70
to
75
percent
for
HC
and
50
to
70
percent
for
CO.
Certification
results
from
2000
model
year
outboard
engines
and
personal
water
craft
(
PWC)
support
such
reductions.
We
believe
that
as
manufacturers
learn
to
apply
direct
injection
strategies
they
may
choose
to
implement
those
technologies
on
some
of
their
more
expensive
sleds
and
use
less
aggressive
technologies,
such
as
improved
carburetion
and
enleanment
on
their
lower
performance
models.
It
appears
that
the
use
of
four
stroke
engines
in
snowmobiles
will
be
more
prevalent
than
we
initially
anticipated.
For
the
2003
model
year,
all
four
of
the
major
snowmobile
manufacturers
will
offer
a
four
stroke
engine.
Two
manufacturers
have
already
sold
limited
quantities
of
their
four
stroke
snowmobiles
in
2002.
All
of
these
engines
will
be
appearing
in
at
least
two
different
models
and
in
some
cases
up
to
three
or
four
models.
The
size
and
design
of
these
engines
is
quite
varied.
All
of
the
engines
range
in
size
from
650
cc
to
1000
cc.
There
are
two
cylinder
and
four
cylinder
engines,
fuel
injected
and
carbureted,
moderate
horsepower
and
high
horsepower.
Manufacturers
have
indicated
that
depending
on
their
success,
four
stroke
engines
will
play
a
large
role
in
meeting
our
standards.
2010
Standards
As
with
the
2006
standards,
we
expect
that
manufacturers
will
use
a
mix
of
technologies
to
meet
our
2010
standards.
To
meet
the
2010
standards,
manufacturers
will
need
to
employ
the
use
of
advanced
technologies
such
as
direct
fuel
injection
and
four
stroke
engines
on
a
larger
portion
of
their
production.
As
noted
above,
manufacturers
are
beginning
to
introduce
these
technologies
and
will
be
gaining
experience
with
them
over
the
next
several
years.
Because
we
are
offering
manufacturers
the
option
to
choose
between
two
sets
of
standards
in
2010,
the
mixture
of
technologies
will
be
very
manufacturer
and
engine
family
specific.
For
example,
direct
injection
typically
reduces
CO
significantly
but
does
not
reduce
HC
to
the
same
extent
as
four
stroke
engines.
Engine
families
that
manufacturers
believe
will
be
most
compatible
with
direct
injection
technology
would
likely
meet
the
75
g/
kW
hr
HC
and
200
g/
kW
hr
CO
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Regulations
67
Estimated
reductions
in
permeation
are
95
percent
when
not
considering
competition
vehicles,
which
are
exempt
from
the
standard.
standards.
A
potential
scenario
for
meeting
these
standards
could
be
a
mixture
of
50
percent
direct
injection,
20
percent
four
stroke
engines,
and
30
percent
with
engine
modifications.
Engine
families
that
manufacturers
believe
will
be
more
compatible
with
four
stroke
technology,
which
typically
has
superior
HC
emissions
levels
but
do
not
necessarily
have
exceptionally
good
CO
performance,
will
likely
meet
the
45
g/
kW
hr
HC
and
275
g/
kw
hr
CO
standards.
Under
either
option,
it
is
possible
that
manufacturers
will
continue
to
sell
two
stroke
models
with
lesser
levels
of
technology.
Manufacturers
are
likely
to
reduce
emissions
where
possible
from
at
least
a
portion
of
the
remaining
two
stroke
engines
through
the
use
of
engine
modifications,
calibration
optimization,
and
secondary
air
systems.
In
some
cases
this
will
be
necessary
just
to
meet
the
FEL
cap.
A
potential
scenario
for
meeting
these
standards
could
be
a
mixture
of
70
percent
four
stroke
engines,
10
percent
direct
fuel
injection,
and
20
percent
with
engine
modifications.
IV.
Permeation
Emission
Control
A.
Overview
In
the
proposal
we
specified
only
exhaust
emission
controls
for
recreational
vehicles.
However,
several
commenters
raised
the
issue
of
control
of
evaporative
emissions
related
to
permeation
from
fuel
tanks
and
fuel
hoses.
The
commenters
stated
that
work
done
by
California
ARB
on
permeation
emissions
from
plastic
fuel
tanks
and
rubber
fuel
line
hoses
for
various
types
of
nonroad
equipment
as
well
as
portable
plastic
fuel
containers
raised
a
new
emissions
concern.
Our
own
investigation
into
the
hydrocarbon
emissions
related
to
permeation
of
fuel
tanks
and
fuel
hoses
from
recreational
land
based
and
marine
applications
supports
the
concerns
raised
by
the
commenters.
Therefore,
on
May
1,
2002,
we
reopened
the
comment
period
and
requested
comment
on
possible
approaches
to
regulating
permeation
emissions
from
recreational
vehicles.
As
a
result
of
our
investigations
and
the
comments
received,
we
have
determined
that
it
is
appropriate
to
promulgate
standards
regulating
permeation
emissions
from
these
vehicles.
This
section
describes
the
provisions
for
40
CFR
part
1051,
which
would
apply
only
to
recreational
vehicle
manufacturers.
This
section
also
discusses
test
equipment
and
procedures
(
for
anyone
who
tests
fuel
tanks
and
hoses
to
show
they
meet
emission
standards)
and
general
compliance
provisions.
We
are
adopting
performance
standards
intended
to
reduce
permeation
emissions
from
recreational
vehicles.
The
standards,
which
apply
to
new
vehicles
starting
in
2008,
are
nominally
based
on
manufacturers
reducing
these
permeation
emissions
from
new
vehicles
by
about
90
percent
overall.
67
We
also
recognize
that
there
are
many
small
businesses
that
manufacture
recreational
vehicles.
We
are
therefore
adopting
several
special
compliance
provisions
to
reduce
the
burden
of
permeation
emission
regulations
on
small
businesses.
These
special
provisions
are
the
same
as
for
the
exhaust
emission
standards,
as
applicable,
and
are
discussed
in
Section
III.
E.
B.
Vehicles
Covered
by
This
Provision
We
are
adopting
new
permeation
emission
standards
for
new
off
highway
motorcycles,
all
terrain
vehicles,
and
snowmobiles.
These
provisions
apply
even
if
the
recreational
vehicle
manufacturer
exercises
the
option
to
use
an
engine
certified
under
another
program
such
as
the
small
spark
ignition
requirements
in
40
CFR
part
90.
These
standards
would
require
these
vehicle
manufacturers
to
use
low
permeability
fuel
tanks
and
hoses.
We
include
vehicles
and
fuel
systems
that
are
used
in
the
United
States,
whether
they
are
made
domestically
or
imported.
Even
though
snowmobiles
do
not
usually
experience
year
around
use,
as
is
the
case
with
ATVs
and
off
highway
motorcycles,
we
are
including
snowmobiles
in
this
standard
because
it
is
common
practice
among
snowmobile
owners
to
store
their
snowmobiles
in
the
off
season
with
fuel
in
the
tank
(
typically
half
full
to
full
tank).
A
fuel
stabilizer
is
typically
added
to
the
fuel
to
prevent
gum,
varnish,
and
rust
from
occurring
in
the
engine
as
a
result
of
the
fuel
sitting
in
the
fuel
tank
and
fuel
system
for
an
extended
period
of
time;
however,
this
does
not
reduce
permeation.
Thus,
snowmobiles
experience
fuel
permeation
losses
just
like
off
highway
motorcycles
and
ATVs.
We
are
extending
our
basic
nonroad
exemptions
to
the
engines
and
vehicles
covered
by
this
rule.
These
include
the
testing
exemption,
the
manufacturerowned
exemption,
the
display
exemption,
and
the
national
security
exemption.
These
exemptions
are
described
in
more
detail
under
Section
VII.
C.
In
addition,
vehicles
used
solely
for
competition
are
not
considered
to
be
nonroad
vehicles,
so
they
are
exempt
from
meeting
the
emission
standards
(
but
see
discussion
in
Section
III.
C.
1.
a
regarding
the
voluntary
program
for
certification
of
all
off
highway
motorcycles).
C.
Permeation
Emission
Standards
1.
What
Are
the
Emission
Standards
and
Compliance
Dates?
We
are
finalizing
new
standards
that
will
require
an
85
percent
reduction
in
plastic
fuel
tank
permeation
and
a
95
percent
reduction
in
fuel
system
hose
permeation
from
new
recreational
vehicles
beginning
in
2008.
These
standards
and
their
implementation
dates
are
presented
in
Table
IV.
C
1.
Section
IV.
D
presents
the
test
procedures
associated
with
these
standards.
Test
temperatures
are
presented
in
Table
IV.
C
1
because
they
represent
an
important
parameter
in
defining
the
emission
levels.
We
will
base
the
permeation
standards
on
the
inside
surface
areas
of
the
hoses
and
fuel
tanks.
We
sought
comment
on
whether
the
potential
permeation
standards
for
fuel
tanks
should
be
expressed
as
grams
per
gallon
of
fuel
tank
capacity
per
day
or
as
grams
per
square
meter
of
inside
surface
area
per
day.
Although
volume
is
generally
used
to
characterize
fuel
tank
emission
rates,
we
base
the
standard
on
inside
surface
area
because
permeation
is
a
function
of
surface
area.
In
addition,
the
surface
to
volume
ratio
of
a
fuel
tank
changes
with
capacity
and
geometry
of
the
tank.
Two
similar
shaped
tanks
of
different
volumes
or
two
different
shaped
tanks
of
the
same
volume
could
have
different
g/
gallon/
day
permeation
rates
even
if
they
were
made
of
the
same
material
and
used
the
same
emissioncontrol
technology.
Therefore,
we
believe
that
using
a
g/
m2/
day
form
of
the
standard
more
accurately
represents
the
emissions
characteristics
of
a
fuel
tank
and
minimizes
complexity.
This
approach
was
supported
by
the
commenters.
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Rules
and
Regulations
TABLE
IV.
C
1.
PERMEATION
STANDARDS
FOR
RECREATIONAL
VEHICLES
Emission
component
Implementation
date
Standard
Test
temperature
Fuel
Tank
Permeation
...............................................................................
2008
1.5
g/
m2/
day
....................................
28
°
C
(
82
°
F)
Hose
Permeation
.......................................................................................
2008
15
g/
m2/
day
.....................................
23
°
C
(
73
°
F)
These
standards
are
revised
compared
to
the
values
we
sought
comment
on
in
the
notice.
In
the
reopening
of
the
comment
period,
we
identified
the
need
to
accommodate
variability
and
deterioration
in
setting
the
fuel
tank
permeation
standard.
Since
the
notice,
we
have
received
test
information
that
suggests
that
a
tank
permeation
standard
representing
an
85
rather
than
a
95
percent
reduction
would
fully
accommodate
these
factors.
Nonetheless,
we
continue
to
believe
that
manufacturers
will
target
control
technologies
and
strategies
focused
on
achieving
reductions
of
95
percent
in
production
tanks.
With
regard
to
the
permeation
standard
for
hoses,
we
have
adjusted
the
standard
slightly
to
give
the
manufacturers
more
freedom
in
selecting
their
hose
material
and
to
accommodate
the
fact
that
we
selected
a
certification
test
fuel
based
on
a
10
percent
ethanol
blend,
which
would
be
prone
to
greater
permeation
than
straight
gasoline.
Cost
effective
technologies
exist
to
significantly
reduce
permeation
emissions.
Because
essentially
all
of
these
vehicles
use
high
density
polyethylene
(
HDPE)
fuel
tanks,
manufacturers
would
be
able
to
choose
from
several
technologies
for
providing
a
permeation
barrier
in
HDPE
tanks.
The
use
of
metal
fuel
tanks
would
also
meet
the
standards,
because
metal
tanks
do
not
experience
any
permeation
losses.
The
hose
permeation
standard
can
be
met
using
barrier
hose
technology
or
through
using
low
permeation
automotive
type
tubing.
These
technologies
are
discussed
in
Section
IV.
F.
The
implementation
dates
give
manufacturers
three
to
four
years
to
comply.
This
will
allow
manufacturers
time
to
implement
controls
in
their
tanks
and
hoses
in
an
orderly
business
manner.
2.
Will
I
Be
Able
to
Average,
Bank,
or
Trade
Emissions
Credits?
Averaging,
banking,
and
trading
(
ABT)
refers
to
the
generation
and
use
of
emission
credits
based
on
certified
emission
levels
relative
to
the
standard.
The
general
ABT
concept
is
discussed
in
detail
in
Section
II.
C.
3.
In
many
cases,
an
ABT
program
can
improve
technological
feasibility,
provide
manufacturers
with
additional
product
planning
flexibility,
and
reduce
costs
which
allows
us
to
consider
emission
standards
with
the
most
appropriate
level
of
stringency
and
lead
time,
as
well
as
providing
an
incentive
for
the
early
introduction
of
new
technology.
We
are
finalizing
ABT
for
fuel
tanks
to
facilitate
the
implementation
of
the
standard
across
a
variety
of
tank
designs
which
include
differences
in
wall
thickness,
tank
geometry,
material
quality,
and
pigment
in
plastic
fuel
tanks.
To
meet
the
standard
on
average,
manufacturers
would
be
able
to
divide
their
fuel
tanks
into
different
emission
families
and
certify
each
of
their
emission
families
to
a
different
Family
Emissions
Level
(
FEL).
The
emission
families
would
include
fuel
tanks
with
similar
characteristics,
including
wall
thickness,
material
used
(
including
additives
such
as
pigments,
plasticizers,
and
UV
inhibitors),
and
the
emissioncontrol
strategy
applied.
The
FELs
would
then
be
weighted
by
sales
volume
and
fuel
tank
inside
surface
area
to
determine
the
average
level
across
a
manufacturer's
total
production.
An
additional
benefit
of
a
corporate
average
approach
is
that
it
provides
an
incentive
for
developing
new
technology
that
can
be
used
to
achieve
even
larger
emission
reductions
or
perhaps
to
achieve
the
same
reduction
at
lower
costs
or
to
achieve
some
reductions
early.
Any
manufacturer
could
choose
to
certify
each
of
its
evaporative
emission
control
families
at
levels
which
would
meet
the
standard.
Some
manufacturers
may
choose
this
approach
as
the
could
see
it
as
less
complicated
to
implement.
We
are
also
finalizing
a
voluntary
program
intended
to
give
an
opportunity
for
manufacturers
to
prove
out
technologies
earlier
than
2008.
Manufacturers
will
be
able
to
use
permeation
control
strategies
early,
and
even
if
they
do
not
meet
the
standard,
they
can
earn
credit
through
partial
emission
reduction
that
will
give
them
more
lead
time
to
meet
the
standard.
This
program
will
allow
a
manufacturer
to
certify
fuel
tanks
early
to
a
less
stringent
standard
and
thereby
delay
the
fuel
tank
permeation
standard.
Therefore,
a
manufacturer
can
earn
more
time
to
meet
the
1.5
g/
m2/
day
standard
if
they
have
an
alternative
approach
that
will
reduce
permeation
by
a
lesser
amount
earlier
than
2008.
Specifically,
if
a
manufacturer
certifies
fuel
tanks
early
to
a
standard
of
3.0
g/
m2/
day,
they
can
delay
the
1.5
g/
m2/
day
standard
for
these
fuel
tanks
by
1
tankyear
for
every
tank
year
of
early
certification.
As
an
alternative,
this
delay
could
be
applied
to
other
fuel
tanks
provided
that
these
tanks
have
an
equal
or
smaller
inside
surface
area
and
meet
a
level
of
3.0
g/
m2/
day.
As
an
example,
suppose
a
manufacturer
were
to
sell
50
vehicles
in
2006
and
75
vehicles
in
2007
with
fuel
tanks
that
meet
a
level
of
3.0
g/
m2/
day.
This
manufacturer
would
then
be
able
to
sell
125
vehicles
with
fuel
tanks
that
meet
a
level
of
3.0
g/
m2/
day
in
2008
and
later
years.
No
uncontrolled
tanks
could
be
sold
after
2007.
In
addition
to
providing
implementation
flexibility
to
manufacturers,
this
option,
if
used,
would
result
in
additional
and
earlier
emission
reductions.
For
hoses,
we
do
not
believe
that
ABT
provisions
would
result
in
a
significant
technological
benefit
to
manufacturers.
We
believe
that
all
fuel
hoses
can
meet
the
permeation
standards
using
straight
forward
technology
as
discussed
in
Section
IV.
F.
From
EPA's
perspective,
including
an
ABT
program
in
the
rule
creates
a
long
term
administrative
burden
that
is
not
worth
taking
on
since
it
does
not
provide
the
industry
with
useful
flexibility.
3.
How
Do
I
Certify
My
Products?
We
are
finalizing
a
certification
process
similar
to
our
existing
program
for
other
mobile
sources.
Manufacturers
test
representative
prototype
designs
and
submit
the
emission
data
along
with
other
information
to
EPA
in
an
application
for
a
Certificate
of
Conformity.
As
discussed
in
Section
IV.
D.
3,
we
will
allow
manufacturers
to
certify
based
on
either
design
(
for
which
there
is
already
data)
or
by
conducting
its
own
emissions
testing.
If
we
approve
the
application,
then
the
manufacturer's
Certificate
of
Conformity
allows
the
manufacturer
to
produce
and
sell
the
vehicles
described
in
the
application
in
the
U.
S.
Manufacturers
certify
their
fuel
systems
by
grouping
them
into
emission
families
that
have
similar
emission
characteristics.
The
emission
family
definition
is
fundamental
to
the
certification
process
and
to
a
large
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2002
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Rules
and
Regulations
68
Draft
SAE
Information
Report
J1769,
``
Test
Protocol
for
Evaluation
of
Long
Term
Permeation
Barrier
Durability
on
Non
Metallic
Fuel
Tanks,''
(
Docket
A
2000
01,
document
IV
A
24).
degree
determines
the
amount
of
testing
required
for
certification.
The
regulations
include
specific
characteristics
for
grouping
emission
families
for
each
category
of
tanks
and
hoses.
For
fuel
tanks,
key
parameters
include
wall
thickness,
material
used
(
including
additives
such
as
pigments,
plasticizers,
and
UV
inhibitors),
and
the
emission
control
strategy
applied.
For
hoses,
key
parameters
include
material,
wall
thickness,
and
emission
control
strategy
applied.
To
address
a
manufacturer's
unique
product
mix,
we
may
approve
using
broader
or
narrower
engine
families.
The
certification
process
for
vehicle
permeation
is
similar
as
for
the
process
for
certifying
engines
(
see
Section
II.
C.
1).
4.
What
Durability
Provisions
Apply?
We
are
adopting
several
additional
provisions
to
ensure
that
emission
controls
will
be
effective
throughout
the
life
of
the
vehicle.
This
section
discusses
these
provisions
for
permeation
from
recreational
vehicles.
More
general
certification
and
compliance
provisions,
which
apply
across
different
vehicle
categories,
are
discussed
in
Sections
II
and
VII,
respectively.
a.
How
long
do
my
vehicles
have
to
comply?
Manufacturers
would
be
required
to
build
fuel
systems
that
meet
the
emission
standards
over
each
vehicle's
useful
life.
For
the
permeation
standards,
we
use
the
same
useful
life
as
discussed
in
Section
III.
C.
4.
a
for
exhaust
emissions
from
recreational
vehicle
engines
based
on
the
belief
that
fuel
system
components
and
engines
are
intended
to
have
the
same
design
life.
Further,
we
are
applying
the
same
warranty
period
for
permeation
emission
related
components
of
the
fuel
system
as
for
exhaust
emission
related
components
of
the
vehicle
(
See
Section
III.
C.
4.
b).
b.
How
do
I
demonstrate
emission
durability?
We
are
adopting
several
additional
provisions
to
ensure
that
emission
controls
will
be
effective
throughout
the
life
of
the
vehicle.
Vehicle
manufacturers
must
demonstrate
that
the
permeation
emission
control
strategies
will
last
for
the
useful
life
of
the
vehicle.
Any
deterioration
in
performance
would
have
to
be
included
in
the
family
emissions
limit.
This
section
discusses
durability
provisions
for
fuel
tanks
and
hoses.
For
plastic
fuel
tanks,
we
are
specifying
a
preconditioning
and
four
durability
steps
that
must
be
performed
in
conjunction
with
the
permeation
testing
for
certification
to
the
standard.
These
steps,
which
include
fuel
soaking,
slosh,
pressure
vacuum
cycling,
temperature
cycling,
and
ultra
violet
light
exposure,
are
described
in
more
detail
in
Section
IV.
D.
1.
The
purpose
of
these
preconditioning
steps
is
to
help
demonstrate
the
durability
of
the
fuel
tank
permeation
control
under
conditions
that
may
occur
in
use.
For
fuel
hoses,
the
only
preconditioning
step
that
we
are
requiring
is
a
fuel
soak
to
ensure
that
the
permeation
rate
is
stabilized
prior
to
testing.
Data
from
before
and
after
the
durability
tests
would
be
used
to
determine
deterioration
factors
for
the
certified
fuel
tanks.
The
durability
factors
would
be
applied
to
permeation
test
results
to
determine
the
certification
emission
level
of
the
fuel
tank
at
full
useful
life.
The
manufacturer
would
still
be
responsible
for
ensuring
that
the
fuel
tank
and
hose
meet
the
permeation
standards
throughout
the
useful
life
of
the
vehicle.
We
recognize
that
vehicle
manufacturers
will
likely
depend
on
suppliers/
vendors
for
treated
tanks
and
fuel
hoses.
We
believe
that,
in
addition
to
normal
business
practices,
our
testing
requirements
will
help
assure
that
suppliers/
vendors
consistently
meet
the
performance
specifications
laid
out
in
the
certificate.
D.
Testing
Requirements
To
obtain
a
certificate
allowing
sale
of
products
meeting
EPA
emission
standards,
manufacturers
generally
must
show
compliance
with
such
standards
through
emission
testing.
The
test
procedures
for
determining
permeation
emissions
from
fuel
tanks
and
hoses
on
recreational
vehicles
are
described
below.
This
section
also
discusses
design
based
certification
as
an
alternative
to
performing
specific
testing.
1.
What
Are
the
Test
Procedures
for
Measuring
Permeation
Emissions
From
Fuel
Tanks?
Prior
to
testing
the
fuel
tanks
for
permeation
emissions,
the
fuel
tank
must
be
preconditioned
by
allowing
the
tank
to
sit
with
fuel
in
it
until
the
hydrocarbon
permeation
rate
has
stabilized.
Under
this
step,
the
fuel
tank
must
be
filled
with
a
10
percent
ethanol
blend
in
gasoline
(
E10),
sealed,
and
soaked
for
20
weeks
at
a
temperature
of
28
±
5
°
C.
Once
the
soak
period
has
ended,
the
fuel
tank
is
drained,
refilled
with
fresh
fuel,
and
sealed.
The
permeation
rate
from
fuel
tanks
is
measured
at
a
temperature
of
28
±
2
°
C
over
a
period
of
at
least
2
weeks.
Consistent
with
good
engineering
judgment,
a
longer
period
may
be
necessary
for
an
accurate
measurement
for
fuel
tanks
with
low
permeation
rates.
Permeation
loss
is
determined
by
measuring
the
weight
of
the
fuel
tank
before
and
after
testing
and
taking
the
difference.
Once
the
mass
change
is
determined
it
is
divided
by
the
manufacturer
provided
tank
surface
area
and
the
number
of
days
of
soak
to
get
the
emission
rate.
As
an
option,
permeation
may
be
measured
using
alternative
methods
that
will
provide
equivalent
or
better
accuracy.
Such
methods
include
enclosure
testing
as
described
in
40
CFR
part
86.
The
fuel
used
for
this
testing
will
be
a
blend
of
90
percent
gasoline
and
10
percent
ethanol.
This
fuel
is
consistent
with
the
test
fuel
used
for
highway
evaporative
emission
testing.
To
determine
permeation
emission
deterioration
factor,
we
are
specifying
three
durability
tests:
slosh
testing,
pressure
vacuum
cycling,
and
ultraviolet
exposure.
The
purpose
of
these
deterioration
tests
is
to
help
ensure
that
the
technology
is
durable
and
the
measured
emissions
are
representative
of
in
use
permeation
rates.
For
slosh
testing,
the
fuel
tank
is
filled
to
40
percent
capacity
with
E10
fuel
and
rocked
for
1
million
cycles.
The
pressure
vacuum
testing
contains
10,000
cycles
from
¥
0.5
to
2.0
psi.
These
two
durability
tests
are
based
on
draft
recommended
SAE
practice.
68
The
third
durability
test
is
intended
to
assess
potential
impacts
of
UV
sunlight
(
0.2
µ
m
0.4
µ
m)
on
the
durability
of
the
surface
treatment.
In
this
test,
the
tank
must
be
exposed
to
a
UV
light
of
at
least
0.40
W
hr/
m2
/
min
on
the
tank
surface
for
15
hours
per
day
for
30
days.
Alternatively,
it
can
be
exposed
to
direct
natural
sunlight
for
an
equivalent
period
of
time.
We
originally
sought
comment
on
applying
the
procedures
in
49
CFR
part
173,
appendix
B,
but
upon
further
evaluation
and
receipt
of
additional
information
found
these
inadequate
for
our
purposes.
The
49
CFR
part
173
test
procedure
is
designed
for
testing
plastic
receptacles
for
transporting
hazardous
chemicals.
This
test
focus
on
temperatures
and
durability
procedures
that
do
not
represent
recreational
vehicle
use.
2.
What
Are
the
Test
Procedures
for
Measuring
Permeation
Emissions
From
Fuel
System
Hoses?
The
permeation
rate
of
fuel
from
hoses
would
be
measured
at
a
temperature
of
23
±
2
°
C
using
SAE
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69
SAE
Recommended
Practice
J30,
``
Fuel
and
Oil
Hoses,''
June
1998,
(
Docket
A
2000
01,
document
IV
A
92).
70
SAE
Recommended
Practice
J1737,
``
Test
Procedure
to
Determine
the
Hydrocarbon
Losses
from
Fuel
Tubes,
Hoses,
Fittings,
and
Fuel
Line
Assemblies
by
Recirculation,''
1997,
(
Docket
A
2000
01,
document,
IV
A
34).
71
SAE
Recommended
Practice
J1527,
``
Marine
Fuel
Hoses,''
1993,
(
Docket
A
2000
01,
document
IV
A
19).
72
ASTM
Standard
Test
Method
D
814
95
(
Reapproved
2000),
``
Rubber
Property
Vapor
Transmission
of
Volatile
Liquids,''
(
Docket
A
2000
01,
document
IV
A
95).
73
SAE
Recommended
Practice
J2260,
``
Nonmetallic
Fuel
System
Tubing
with
One
or
More
Layers,''
1996,
(
Docket
A
2000
01,
document
IV
A
18).
method
J3069
with
E10.
The
hose
must
be
preconditioned
with
a
fuel
soak
to
ensure
that
the
permeation
rate
has
stabilized.
The
fuel
to
be
used
for
this
testing
would
be
a
blend
of
90
percent
gasoline
and
10
percent
ethanol.
This
fuel
is
consistent
with
the
test
fuel
used
for
highway
evaporative
emission
testing.
Alternatively,
for
purposes
of
submission
of
data
at
certification,
permeation
could
be
measured
using
alternative
equipment
and
procedures
that
provide
equivalent
results.
To
use
these
alternative
methods,
manufacturers
would
have
to
apply
to
us
and
demonstrate
equivalence.
Examples
of
alternative
approaches
that
we
anticipate
manufacturers
may
use
are
the
recirculation
technique
described
in
SAE
J1737,70
enclosuretype
testing
such
as
in
40
CFR
part
86,
or
weight
loss
testing
such
as
described
in
SAE
J1527.71
3.
Can
I
Certify
Based
on
Engineering
Design
Rather
Than
Through
Testing?
In
general,
test
data
would
be
required
to
certify
fuel
tanks
and
hoses
to
the
permeation
standards.
Test
data
could
be
carried
over
from
year
to
year
for
a
given
emission
control
design.
We
do
not
believe
the
cost
of
testing
tanks
and
hose
designs
for
permeation
would
be
burdensome
especially
given
that
the
data
could
be
carried
over
from
year
to
year,
and
that
there
is
a
good
possibility
that
the
broad
emission
family
concepts
would
lead
to
minimum
testing.
However,
there
are
some
specific
cases
where
we
would
allow
certification
based
on
design.
These
special
cases
are
discussed
below.
We
would
consider
a
metal
fuel
tank
to
meet
the
design
criteria
for
a
low
permeation
fuel
tank
because
fuel
does
not
permeate
through
metal.
However,
we
would
not
consider
this
design
to
be
any
more
effective
than
any
other
low
permeation
fuel
tank
for
the
purposes
of
any
sort
of
credit
program.
Although
metal
is
impermeable,
seals
and
gaskets
used
on
the
fuel
tank
may
not
be.
The
design
criteria
for
the
seals
and
gaskets
would
be
that
either
they
would
not
have
a
total
exposed
surface
area
exceeding
1000
mm2,
or
the
seals
and
gaskets
would
have
to
be
made
of
a
material
with
a
permeation
rate
of
10
g/
m2/
day
or
less
at
23
°
C
as
measured
under
ASTM
D814.72
A
metal
fuel
tank
with
seals
that
meet
this
design
criteria
would
readily
pass
the
standard.
Fuel
hoses
can
be
certified
by
design
as
being
manufactured
in
compliance
with
certain
accepted
SAE
specifications.
Specifically,
a
fuel
hose
meeting
the
SAE
J30
R11
A
or
R12
requirements
could
be
design
certified
to
the
standard.
In
addition,
fuel
line
meeting
the
SAE
J226073
Category
1
requirements
could
be
design
certified
to
the
standard.
These
fuel
hoses
and
fuel
line
specifications
are
based
on
15
percent
methanol
fuel
and
higher
temperatures.
We
believe
that
fuel
hoses
and
lines
that
are
tested
and
meet
these
requirements
would
also
meet
our
hose
permeation
standards
because
both
are
generally
acknowledged
as
representing
more
stringent
test
parameters.
In
the
future,
if
new
SAE
specifications
are
developed
which
are
consistent
with
our
hose
permeation
standards,
we
would
consider
including
hoses
meeting
the
new
SAE
requirements
as
being
able
to
certify
by
design.
At
certification,
manufacturers
will
have
to
submit
an
engineering
analysis
showing
that
the
tank
or
hose
designs
will
meet
the
standards
throughout
their
full
useful
life.
The
tanks
and
hoses
will
remain
subject
to
the
emission
standards
throughout
their
useful
lives.
The
design
criteria
relate
only
to
the
issuance
of
a
certificate.
E.
Special
Compliance
Provisions
We
believe
that
the
permeation
control
requirements
will
be
relatively
easy
for
small
businesses
to
meet,
given
the
relatively
low
cost
of
the
requirements
and
the
availability
of
materials
and
treatment
support
by
outside
vendors.
Low
permeation
fuel
hoses
are
available
from
vendors
today,
and
we
would
expect
that
surface
treatment
would
be
applied
through
an
outside
company.
However,
to
minimize
any
additional
burden
these
requirements
may
impose
on
small
manufacturers,
we
are
implementing,
where
they
are
applicable
to
permeation,
the
same
options
we
proposed
for
the
exhaust
emission
standards.
These
options
for
small
recreational
vehicle
manufacturers
are
described
in
detail
in
Section
III.
E.
F.
Technological
Feasibility
We
believe
there
are
several
strategies
that
manufacturers
can
use
to
meet
our
permeation
emission
standards.
This
section
gives
an
overview
of
this
technology.
See
Chapters
3
and
4
of
the
Final
Regulatory
Support
Document
for
more
detail
on
the
technology
discussed
here.
1.
Implementation
Schedule
The
permeation
emission
standards
for
fuel
tanks
become
effective
in
the
2008
model
year.
Several
technologies
are
available
that
could
be
used
to
meet
this
standard.
Surface
treatments
to
reduce
tank
permeation
are
widely
used
today
in
other
container
applications,
and
the
technology
and
production
facilities
needed
to
conduct
this
process
exist.
Selar
is
used
by
at
least
one
portable
fuel
tank
manufacturer
and
has
also
been
used
in
automotive
applications.
Plastic
tanks
with
coextruded
barriers
have
been
used
in
automotive
applications
for
years.
However,
fuel
tanks
used
in
recreational
vehicles
are
primarily
(
but
not
exclusively)
high
density
polyethylene
tanks
with
no
permeation
control.
We
received
comments
from
manufacturers
that
they
would
not
be
able
to
comply
with
permeation
standards
until
2008
or
2009.
They
stated
that,
especially
for
fuel
tanks,
they
would
need
this
extra
lead
time
to
ensure
that
the
useful
life
requirement
can
be
met
on
their
products.
At
the
same
time,
others
commented
that
the
technology
is
already
available
and
that
the
permeation
standards
should
apply
in
2004.
We
believe
it
is
appropriate
to
give
manufacturers
until
the
2008
model
year
for
the
fuel
tank
permeation
standards.
Manufacturers
will
need
lead
time
to
allow
for
durability
testing
and
other
development
work
associated
with
applying
this
technology
to
recreational
vehicles.
This
is
especially
true
for
manufacturers
or
vendors
who
choose
to
set
up
their
own
sulfonation
or
fluorination
facilities
in
house.
We
believe
that
the
low
permeation
hose
technology
can
also
be
applied
in
the
2008
time
frame.
A
lower
permeation
fuel
hose
exists
today
known
as
the
SAE
R9
hose
that
is
as
flexible
as
the
SAE
R7
hose
used
in
most
recreational
applications
today.
These
SAE
hose
specifications
are
contained
in
SAE
J30
cited
above.
This
hose
would
meet
our
permeation
standard
on
gasoline,
but
probably
not
on
a
10
percent
ethanol
blend.
As
noted
in
Chapter
4
of
the
Final
Regulatory
Support
Document,
barrier
materials
typically
used
in
R9
hose
today
may
have
permeation
rates
3
to
5
times
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higher
on
a
10
percent
ethanol
blend
than
on
straight
gasoline.
However,
there
are
several
lower
permeability
barrier
materials
that
can
be
used
in
rubber
hose
that
will
comply
with
the
hose
permeation
requirement
on
a
10
percent
ethanol
blend
and
still
be
flexible
enough
for
use
in
recreational
vehicles.
This
hose
is
available
for
automotive
applications
at
this
time,
but
some
lead
time
may
be
required
to
apply
these
hoses
to
recreational
vehicles
if
hose
connection
fitting
changes
were
required.
For
these
reasons,
we
are
implementing
the
hose
permeation
standard
on
the
same
schedule
as
the
tank
permeation
standards.
2.
Standard
Levels
We
have
identified
several
strategies
for
reducing
permeation
emissions
from
fuel
tanks
and
hoses.
We
recognize
that
some
of
these
technologies
may
be
more
desirable
than
others
for
some
manufacturers,
and
we
recognize
that
different
strategies
for
equal
emission
reductions
may
be
better
for
different
applications.
A
specific
example
of
technology
that
could
be
used
to
meet
the
fuel
tank
permeations
would
be
surface
barrier
treatments
such
as
sulfonation
or
fluorination.
With
these
surface
treatments,
more
than
a
95
percent
reduction
in
permeation
emissions
from
new
fuel
tanks
is
feasible.
However,
variation
in
material
tolerances
and
in
use
deterioration
can
reduce
this
effectiveness.
Given
the
lead
time
for
the
standards,
manufacturers
will
be
able
to
provide
fuel
tanks
with
consistent
material
quality,
and
the
surface
treatment
processes
can
be
optimized
for
a
wide
range
of
material
qualities
and
additives
such
as
pigments,
plasticizers,
and
UV
inhibitors.
We
do
not
expect
a
large
deterioration
in
use;
however,
data
on
slosh
testing
suggest
that
some
deterioration
may
occur.
To
accommodate
variability
and
deterioration,
we
are
finalizing
a
standard
that
represents
about
an
85
percent
reduction
in
permeation
emissions
from
plastic
fuel
tanks.
It
is
our
expectation
that
manufacturers
will
aim
for
a
surface
treatment
effectiveness
rate
as
near
to
100
percent
a
practical
for
new
tanks.
Therefore,
even
with
variability
and
deterioration
in
use,
control
rates
are
likely
to
exceed
85
percent.
Several
materials
are
available
today
that
could
be
used
as
a
low
permeation
barrier
in
rubber
hoses.
We
present
more
detail
on
these
and
other
technological
approaches
below.
3.
Technological
Approaches
a.
Fuel
tanks.
Blow
molding
is
widely
used
for
the
manufacture
of
small
fuel
tanks
of
recreational
vehicles.
Typically,
blow
molding
is
performed
by
creating
a
hollow
tube,
known
as
a
parison,
by
pushing
high
density
polyethylene
(
HDPE)
through
an
extruder
with
a
screw.
The
parison
is
then
pinched
in
a
mold
and
inflated
with
an
inert
gas.
In
highway
applications,
non
permeable
plastic
fuel
tanks
are
produced
by
blow
molding
a
layer
of
ethylene
vinyl
alcohol
(
EVOH)
or
nylon
between
two
layers
of
polyethylene.
This
process
is
called
coextrusion
and
requires
at
least
five
layers:
the
barrier
layer,
adhesive
layers
on
either
side
of
the
barrier
layer,
and
HDPE
as
the
outside
layers
which
make
up
most
of
the
thickness
of
the
fuel
tank
walls.
However,
multi
layer
construction
requires
two
additional
extruder
screws
which
significantly
increases
the
cost
of
the
blow
molding
process.
Multi
layer
fuel
tanks
can
also
be
formed
using
injection
molding.
In
this
method,
a
low
viscosity
polymer
is
forced
into
a
thin
mold
to
create
each
side
of
the
fuel
tank.
The
two
sides
are
then
welded
together.
To
add
a
barrier
layer,
a
thin
sheet
of
the
barrier
material
is
placed
inside
the
mold
prior
to
injection
of
the
poleythylene.
The
polyethylene,
which
generally
has
a
much
lower
melting
point
than
the
barrier
material,
bonds
with
the
barrier
material
to
create
a
shell
with
an
inner
liner.
A
less
expensive
alternative
to
coextrusion
is
to
blend
a
low
permeable
resin
in
with
the
HDPE
and
extrude
it
with
a
single
screw.
The
trade
name
typically
used
for
this
permeation
control
strategy
is
Selar.
The
low
permeability
resin,
typically
EVOH
or
nylon,
creates
non
continuous
platelets
in
the
HDPE
fuel
tank
which
reduce
permeation
by
creating
long,
tortuous
pathways
that
the
hydrocarbon
molecules
must
navigate
to
pass
through
the
fuel
tank
walls.
Although
the
barrier
is
not
continuous,
this
strategy
can
still
achieve
greater
than
a
90
percent
reduction
in
permeation
of
gasoline.
EVOH
has
much
higher
permeation
resistance
to
alcohol
than
nylon;
therefore,
it
would
be
the
preferred
material
to
use
for
meeting
our
standard
which
is
based
on
testing
with
a
10
percent
ethanol
fuel.
Another
type
of
low
permeation
technology
for
fuel
tanks
would
be
to
treat
the
surfaces
of
a
plastic
fuel
tanks
with
a
barrier
layer.
Two
ways
of
achieving
this
are
known
as
fluorination
and
sulfonation.
The
fluorination
process
causes
a
chemical
reaction
where
exposed
hydrogen
atoms
are
replaced
by
larger
fluorine
atoms
which
creates
a
barrier
on
the
surface
of
the
fuel
tank.
In
this
process,
a
batch
of
fuel
tanks
are
generally
processed
post
production
by
stacking
them
in
a
steel
container.
The
container
is
then
voided
of
air
and
flooded
with
fluorine
gas.
By
pulling
a
vacuum
in
the
container,
the
fluorine
gas
is
forced
into
every
crevice
in
the
fuel
tanks.
As
a
result
of
this
process,
both
the
inside
and
outside
surfaces
of
the
fuel
tank
would
be
treated.
As
an
alternative,
fuel
tanks
can
be
fluorinated
on
line
by
exposing
the
inside
surface
of
the
fuel
tank
to
fluorine
during
the
blow
molding
process.
However,
this
method
may
not
prove
as
effective
as
off
line
fluorination
which
treats
the
inside
and
outside
surfaces.
Sulfonation
is
another
surface
treatment
technology
where
sulfur
trioxide
is
used
to
create
the
barrier
by
reacting
with
the
exposed
polyethylene
to
form
sulfonic
acid
groups
on
the
surface.
Current
practices
for
sulfonation
are
to
place
fuel
tanks
on
a
small
assembly
line
and
expose
the
inner
surfaces
to
sulfur
trioxide,
then
rinse
with
a
neutralizing
agent.
However,
sulfonation
can
also
be
performed
using
a
batch
method.
Either
of
these
processes
can
be
used
to
reduce
gasoline
permeation
by
more
than
95
percent.
Over
the
first
month
or
so
of
use,
polyethylene
fuel
tanks
can
expand
by
as
much
as
three
percent
due
to
saturation
of
the
plastic
with
fuel.
Manufacturers
have
raised
the
concern
that
this
hydrocarbon
expansion
could
affect
the
effectiveness
of
surface
treatments
like
fluorination
or
sulfonation.
We
believe
this
will
not
have
a
significant
effect
on
the
effectiveness
of
these
surface
treatments.
California
ARB
has
performed
extensive
permeation
testing
on
portable
fuel
containers
with
and
without
these
surface
treatments.
Prior
to
the
permeation
testing,
the
tanks
were
prepared
by
first
performing
a
durability
procedure
where
the
fuel
container
is
cycled
a
minimum
of
1000
times
between
¥
1
psi
and
5
psi.
In
addition,
the
fuel
containers
are
soaked
with
fuel
for
a
minimum
of
four
weeks
prior
to
testing.
Their
test
data,
presented
in
Chapter
4
of
the
Final
Regulatory
Support
Document
show
that
fluorination
and
sulfonation
are
still
effective
after
this
durability
testing.
Manufacturers
have
also
commented
that
fuel
sloshing
in
the
fuel
tank,
under
normal
in
use
operation,
could
wear
off
the
surface
treatments.
However,
we
do
not
believe
that
this
is
likely.
These
surface
treatments
actually
result
in
an
atomic
change
in
the
structure
of
the
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/
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8,
2002
/
Rules
and
Regulations
74
ethylene
tetrafluoro
ethylene
(
ETFE),
tetrafluoro
ethylene,
hexa
fluoro
propylene,
and
vinyledene
fluoride
(
THV).
75
Gas
turbines
are
non
reciprocating
internal
combustion
engines.
outside
surface
of
the
fuel
tank.
To
wear
off
the
treatment,
the
plastic
would
need
to
be
worn
away
on
the
outside
surface.
In
addition,
testing
by
California
ARB
shows
that
the
fuel
tank
permeation
standard
can
be
met
by
fuel
tanks
that
have
been
sloshed
for
1.2
million
cycles.
Test
data
on
an
sulfonated
automotive
HDPE
fuel
tank
after
five
years
of
use
showed
no
deterioration
in
the
permeation
barrier.
This
data
are
presented
in
Chapter
4
of
the
Final
Regulatory
Support
Document.
Permeation
can
also
be
reduced
from
fuel
tanks
by
constructing
them
out
of
a
lower
permeation
material
than
HDPE.
For
instance,
metal
fuel
tanks
would
not
permeate.
In
addition,
there
are
grades
of
plastics
other
than
HDPE
that
could
be
molded
into
fuel
tanks.
One
commenter
suggested
nylon;
however,
although
nylon
has
excellent
permeation
resistance
on
gasoline,
it
has
poor
chemical
resistance
to
alcoholblended
fuels.
Other
materials,
which
have
excellent
permeation
even
with
alcohol
blended
fuels
are
acetal
copolymers
and
thermoplastic
polyesters.
At
this
time,
these
materials
are
generally
much
more
expensive
than
HDPE.
b.
Hoses.
Fuel
hoses
produced
for
use
in
recreational
vehicles
are
generally
extruded
nitrile
rubber
with
a
cover
for
abrasion
resistance.
Lower
permeability
fuel
hoses
produced
today
for
other
applications
are
generally
constructed
in
one
of
two
ways:
either
with
a
low
permeability
layer
or
by
using
a
low
permeability
rubber
blend.
By
using
hose
with
a
low
permeation
thermoplastic
layer,
permeation
emissions
can
be
reduced
by
more
than
95
percent.
Because
the
thermoplastic
layer
is
very
thin,
on
the
order
of
0.1
to
0.2
mm,
the
rubber
hose
retains
its
flexibility.
Two
thermoplastics
which
have
excellent
permeation
resistance,
even
with
an
alcohol
blend
fuel,
are
ETFE
and
THV.
74
In
automotive
applications,
multilayer
plastic
tubing,
made
of
fluoropolymers
is
generally
used.
An
added
benefit
of
these
low
permeability
lines
is
that
some
fluoropolymers
can
be
made
to
conduct
electricity
and
therefore
can
prevent
the
buildup
of
static
charges.
Although
this
technology
can
achieve
more
than
an
order
of
magnitude
lower
permeation
than
barrier
hoses,
it
is
relatively
inflexible
and
may
need
to
be
molded
in
specific
shapes
for
each
recreational
vehicle
design.
Manufacturers
have
commented
that
they
would
need
flexible
hose
to
fit
their
many
designs,
resist
vibration,
and
to
simplify
the
hose
connections
and
fittings.
An
alternative
approach
to
reducing
the
permeability
of
fuel
hoses
would
be
to
apply
a
surface
treatment
such
as
fluorination
or
sulfonation.
This
process
would
be
performed
in
a
manner
similar
to
discussed
above
for
fuel
tanks.
4.
Conclusions
The
standards
for
permeation
emissions
from
recreational
vehicles
reasonably
reflect
what
manufacturers
can
achieve
through
the
application
of
available
technology.
Manufacturers
will
have
several
years
of
lead
time
to
select,
design,
and
produce
permeation
emission
control
strategies
that
will
work
best
for
their
product
lines.
We
expect
that
meeting
these
requirements
will
pose
a
challenge,
but
one
that
is
feasible
taking
into
consideration
the
availability
and
cost
of
technology,
lead
time,
noise,
energy,
and
safety.
The
role
of
these
factors
is
presented
in
detail
in
Chapters
3
and
4
of
the
Final
Regulatory
Support
Document.
The
permeation
standards
are
based
on
the
effective
application
of
low
permeable
materials
or
surface
treatments.
This
is
a
step
change
in
technology;
therefore,
we
believe
that
even
if
we
set
a
less
stringent
permeation
standard,
these
technology
options
would
likely
still
be
used.
In
addition,
this
technology
is
relatively
inexpensive
and
can
achieve
meaningful
emission
reductions.
The
standards
are
expected
to
achieve
more
than
an
85
percent
reduction
in
permeation
emissions
from
fuel
tanks
and
more
than
95
percent
from
hoses.
We
believe
that
more
stringent
standards
could
result
in
significantly
more
expensive
materials
without
corresponding
additional
emission
reduction.
In
addition,
the
control
technology
would
generally
pay
for
itself
over
time
by
conserving
fuel
that
would
otherwise
evaporate.
The
projected
costs
and
fuel
savings
are
discussed
in
Chapter
5
of
the
Final
Regulatory
Support
Document.
V.
Large
Spark
Ignition
(
SI)
Engines
A.
Overview
This
section
applies
to
most
nonroad
spark
ignition
engines
rated
over
19
kW
(``
Large
SI
engines'').
The
emission
standards
will
lead
to
emission
reductions
of
about
90
percent
for
CO,
NOX,
and
HC.
Since
the
emission
standards
are
based
on
engine
testing
with
broadly
representative
duty
cycles,
these
estimated
reductions
apply
to
all
types
of
equipment
using
these
engines.
Reducing
Large
SI
engine
emissions
will
help
reduce
ozone
and
CO
concentrations
and
will
also
be
valuable
to
individuals
operating
these
engines
in
areas
with
limited
fresh
air
circulation.
The
cost
of
applying
the
anticipated
emission
control
technology
to
these
engines
is
offset
by
much
greater
cost
savings
from
reduced
fuel
consumption
over
the
engines'
operating
lifetime,
as
described
in
the
Final
Regulatory
Support
Document.
This
section
describes
the
requirements
that
apply
to
engine
manufacturers.
See
Section
II
for
a
description
of
our
general
approach
to
regulating
nonroad
engines
and
how
manufacturers
show
that
they
meet
emission
standards.
See
Section
VII
for
additional
requirements
for
engine
manufacturers,
equipment
manufacturers,
and
others.
See
Section
VIII
for
general
provisions
related
to
testing
equipment
and
procedures.
B.
Large
SI
Engines
Covered
by
This
Rule
Large
SI
engines
covered
in
this
section
power
nonroad
equipment
such
as
forklifts,
sweepers,
pumps,
and
generators.
This
includes
marine
auxiliary
engines,
but
does
not
include
marine
propulsion
engines
or
engines
used
in
recreational
vehicles
(
snowmobiles,
off
highway
motorcycles,
and
all
terrain
vehicles).
These
other
nonroad
applications
are
addressed
elsewhere
in
this
document.
This
final
rule
applies
only
to
sparkignition
engines.
Our
most
recent
rulemaking
for
nonroad
diesel
engines
adopted
a
definition
of
``
compressionignition
that
addressed
the
status
of
alternative
fuel
engines
(
63
FR
56968,
October
23,
1998).
We
are
adopting
updated
definitions
consistent
with
those
already
established
in
previous
rulemakings
to
clarify
that
all
reciprocating
internal
combustion
engines
are
either
spark
ignition
or
compression
ignition.
75
These
new
definitions
apply
to
40
CFR
parts
89
and
1048.
Spark
ignitions
include
gasolinefueled
engines
and
any
others
that
control
power
with
a
throttle
and
follow
the
theoretical
Otto
cycle.
Compressionignition
engines
are
any
reciprocating
internal
combustion
engines
that
are
not
spark
ignition
engines.
Under
these
definitions,
it
is
possible
for
a
dieselderived
engine
to
fall
under
the
sparkignition
program.
We
believe
the
requirements
adopted
in
this
rule
are
feasible
and
appropriate
for
these
engines.
However,
we
will
allow
such
engines
over
250
kW
to
instead
meet
the
requirements
that
apply
to
nonroad
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/
Rules
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Regulations
diesel
engines.
We
believe
this
is
appropriate
for
several
reasons.
First,
the
technology
requirements
are
comparable
between
programs.
The
nonroad
diesel
emission
standards,
which
apply
over
the
longer
useful
life
characteristic
of
diesel
engines,
are
slightly
more
stringent
for
CO
and
slightly
less
stringent
for
HC+
NOX.
The
calibration
changes
needed
to
adjust
these
emission
levels
are
not
fundamental
to
the
overall
design
of
the
emission
control
system.
Second,
the
diesel
engine
manufacturers
producing
these
engines
are
already
set
up
to
do
testing
based
on
test
procedures
that
apply
to
diesel
engines.
To
the
extent
that
they
would
incur
costs
to
be
able
to
run
test
procedures
specified
for
Large
SI
engines,
these
costs
would
likely
not
correspond
with
improving
emission
controls.
Third,
these
engines
share
important
technical
characteristics
with
diesel
engines
and
are
likely
to
experience
in
use
operation
that
is
more
like
that
of
nonroad
diesel
engines.
In
addition,
they
are
installed
in
applications
that
also
use
diesel
engines,
not
Large
SI
engines.
Several
types
of
engines
are
excluded
or
exempted
from
these
new
regulations.
The
following
sections
describe
the
types
of
special
provisions
that
apply
uniquely
to
nonrecreational
spark
ignition
engines
rated
over
19
kW.
Section
VII.
C
covers
several
additional
exemptions
that
apply
generally
across
programs.
1.
Stationary
Engine
Exclusion
Consistent
with
the
Clean
Air
Act,
stationary
source
engines
are
not
nonroad
engines,
so
the
emission
standards
don't
apply
to
engines
used
in
stationary
applications.
In
general,
an
engine
that
would
otherwise
be
considered
a
Large
SI
engine
is
not
considered
a
nonroad
engine
if
it
will
be
either
installed
in
a
fixed
position
or
if
it
will
be
a
portable
(
or
transportable)
engine
operating
for
at
least
one
year
periods
without
moving
throughout
its
lifetime.
We
are
adopting
the
same
definitions
for
these
engines
that
have
already
been
established
for
other
programs.
These
stationary
engines
(
that
would
otherwise
qualify
as
Large
SI
engines)
must
have
an
engine
label
identifying
their
excluded
status.
This
is
especially
valuable
for
importing
excluded
engines
without
complication
from
U.
S.
Customs
officials.
It
also
helps
us
ensure
that
such
engines
are
legitimately
excluded
from
emission
standards.
2.
Exclusion
for
Engines
Used
Solely
for
Competition
For
Large
SI
engines
we
proposed
the
existing
regulatory
definition
for
nonroad
engines,
with
excludes
engines
used
solely
for
competition.
As
described
in
the
proposed
rule,
we
are
not
aware
of
any
manufacturers
producing
new
engines
that
are
intended
only
for
competition.
As
a
result,
we
are
not
adopting
any
specific
provisions
addressing
a
competition
exclusion
for
manufacturers.
Part
1068
of
the
regulations
includes
provisions
addressing
the
practice
of
modifying
certified
engines
for
competition
(
see
Section
VII.
C).
3.
Motor
Vehicle
Engine
Exemption
In
some
cases
an
engine
manufacturer
may
want
to
modify
a
certified
automotive
engine
for
nonroad
use
to
sell
the
engine
without
recertifying
it
as
a
Large
SI
engine.
We
are
therefore
adopting
an
exemption
from
the
Large
SI
standards
in
40
CFR
part
1048
for
engines
that
are
already
certified
to
the
emission
standards
in
40
CFR
part
86
for
highway
applications.
To
qualify
for
this
exemption
from
separately
certifying
to
nonroad
standards,
the
manufacturer
must
makes
no
changes
to
the
engine
that
might
affect
its
exhaust
or
evaporative
emissions.
Companies
using
this
exemption
must
report
annually
to
us,
including
a
list
of
its
exempted
engine
models.
For
engines
included
under
this
provision,
manufacturers
of
the
vehicle
or
engine
must
generally
meet
all
the
requirements
from
40
CFR
part
86
that
would
apply
if
the
engine
were
used
in
a
motor
vehicle.
Section
1048.605
of
the
regulations
describes
the
qualifying
criteria
and
responsibilities
in
greater
detail.
We
generally
prohibit
equipment
or
vehicle
manufacturers
from
producing
new
nonroad
equipment
that
does
not
have
engines
certified
to
nonroad
emission
standards.
However,
in
some
cases
a
manufacturer
may
want
to
produce
vehicles
certified
to
highway
emission
standards
for
nonroad
use.
We
are
providing
an
exemption
for
these
manufacturers,
as
long
as
there
is
no
change
in
the
vehicle's
exhaust
or
evaporative
emission
control
systems.
For
example,
a
mining
company
may
want
to
use
a
pickup
truck
for
dedicated
work
at
a
mine
site,
but
special
order
the
trucks
from
the
manufacturer
with
modifications
that
cause
the
truck
to
no
longer
qualify
as
a
motor
vehicle.
Manufacturers
may
produce
such
a
modified
version
of
a
truck
that
has
been
certified
to
the
motor
vehicle
standards,
as
long
as
the
modifications
don't
affect
its
emissions.
4.
Lawn
and
Garden
Engine
Exemption
Most
Large
SI
engines,
rated
over
19
kW,
have
a
total
displacement
greater
than
one
liter.
The
design
and
application
of
the
few
Large
SI
engines
currently
being
produced
with
displacement
less
than
one
liter
are
very
similar
to
those
of
engines
rated
below
19
kW,
which
are
typically
used
for
lawn
and
garden
applications.
As
described
in
the
most
recent
rulemaking
for
these
smaller
engines,
manufacturers
may
certify
engines
between
19
and
30
kW
with
total
displacement
of
one
liter
or
less
to
the
requirements
we
have
already
adopted
in
40
CFR
part
90
for
engines
below
19
kW
(
see
65
FR
24268,
April
25,
2000).
We
are
not
changing
this
provision,
and
engines
so
certified
would
not
be
subject
to
the
requirements
that
apply
to
Large
SI
engines.
This
approach
allows
manufacturers
of
small
air
cooled
engines
to
certify
their
engines
rated
between
19
and
30
kW
with
the
program
adopted
for
the
comparable
engines
with
slightly
lower
power
ratings.
This
is
also
consistent
with
the
provisions
adopted
by
California
ARB,
except
for
the
addition
of
the
30
kW
cap
to
prevent
treating
high
power
engines
under
the
program
that
applies
to
lawn
and
garden
engines.
Technological,
economic,
and
environmental
issues
associated
with
the
few
engine
models
with
rated
power
over
19
kW,
but
with
displacement
at
or
below
1
liter,
were
previously
analyzed
in
the
rulemaking
for
nonroad
sparkignition
engines
below
19
kW.
This
rule
therefore
does
not
specifically
address
the
provisions
applying
to
them
or
repeat
the
estimated
impacts
of
adopting
emission
standards.
Conversely,
we
are
aware
that
some
engines
rated
below
19
kW
may
be
part
of
a
larger
family
of
engine
models
that
includes
engines
rated
above
19
kW.
This
may
include,
for
example,
three
and
four
cylinder
engine
models
that
are
otherwise
identical.
To
avoid
the
need
to
separate
these
engines
into
separate
engine
families
(
certified
under
completely
different
control
programs),
manufacturers
may
certify
any
engine
rated
under
19
kW
to
the
more
stringent
Large
SI
emission
standards.
Such
an
engine
is
then
exempt
from
the
requirements
of
40
CFR
part
90.
C.
Emission
Standards
In
October
1998,
California
ARB
adopted
emission
standards
for
Large
SI
engines.
We
are
extending
these
requirements
to
the
rest
of
the
U.
S.
in
the
near
term.
We
are
also
revising
the
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76
See
Section
V.
D
for
a
discussion
of
duty
cycles.
emission
standards
and
adding
various
provisions
in
the
long
term,
as
described
below.
The
near
term
and
the
long
term
emission
standards
are
based
on
threeway
catalytic
converters
with
electronic
fueling
systems
to
control
emissions,
and
differ
primarily
in
terms
of
how
well
the
controls
are
optimized.
In
addition
to
the
anticipated
emission
reductions,
we
project
that
these
technologies
will
provide
large
savings
to
operators
as
a
result
of
reduced
fuel
consumption
and
other
performance
improvements.
An
important
element
of
the
control
program
is
the
attempted
harmonization
with
the
requirements
adopted
by
California
ARB.
We
are
aware
that
inconsistent
or
conflicting
requirements
may
lead
to
additional
costs.
Cooperation
between
agencies
has
allowed
a
great
degree
of
harmonization.
In
addition
to
the
common
structure
of
the
programs,
the
specific
provisions
that
make
up
the
certification
requirements
and
compliance
programs
are
consistent
with
very
few
exceptions.
In
most
of
the
cases
where
individual
provisions
differ,
the
EPA
language
is
more
general
than
that
adopted
by
California,
rather
than
being
incompatible.
The
following
sections
describe
the
requirements
in
greater
detail.
1.
What
Are
the
Emission
Standards
and
Compliance
Dates?
a.
Exhaust
emissions.
We
are
adopting
standards
starting
in
the
2004
model
year
consistent
with
those
adopted
by
California
ARB.
These
standards,
which
apply
to
testing
only
with
the
applicable
steady
state
duty
cycles,
are
4.0
g/
kW
hr
(
3.0
g/
hp
hr)
for
HC+
NOX
emissions
and
50
g/
kW
hr
(
37
g/
hp
hr)
for
CO
emissions.
See
Section
V.
D
for
further
discussion
of
the
steady
state
duty
cycles.
We
expect
manufacturers
to
meet
these
standards
using
three
way
catalytic
converters
and
electronically
controlled
fuel
systems.
These
systems
are
similar
to
those
used
for
many
years
in
highway
applications,
but
not
necessarily
with
the
same
degree
of
sophistication.
Adopting
emission
standards
for
these
engines
starting
in
2004
allows
a
relatively
short
lead
time.
However,
manufacturers
will
be
able
to
achieve
this
by
expanding
their
production
of
the
same
engines
they
will
be
selling
in
California
at
that
time.
We
have
designed
our
2004
standards
to
require
no
additional
development,
design,
or
testing
beyond
what
California
ARB
already
requires.
Adopting
these
nearterm
emission
standards
allows
us
to
set
early
requirements
to
introduce
the
lowemission
technologies
for
substantial
emission
reductions
with
minimal
lead
time.
The
final
requirements
includes
two
principal
adjustments
to
align
with
the
California
ARB
standards.
First,
we
specify
that
manufacturers'
deterioration
factors
for
2004
through
2006
model
years
should
be
based
on
emission
measurements
over
3500
hours
of
engine
operation,
rather
than
the
full
useful
life
of
5000
hours.
Second,
for
those
same
model
years,
we
are
applying
an
emission
standard
of
5.4
g/
kW
hr
(
4.0
g/
hp
hr)
HC+
NOX
for
any
inuse
testing
to
account
for
the
potential
for
additional
deterioration
beyond
3500
hours.
This
allowance
for
higher
in
use
emissions
is
a
temporary
provision
to
ensure
the
feasibility
of
compliance
in
the
early
years
of
the
program.
Testing
has
shown
that
with
additional
design
time,
manufacturers
can
incorporate
emission
control
technologies
with
sufficient
durability
that
the
long
term
standards
do
not
require
a
separate
inuse
standard.
This
is
separate
from
the
field
testing
standards
described
below.
Testing
has
shown
that
additional
time
to
optimize
designs
to
better
control
emissions
will
allow
manufacturers
to
meet
significantly
more
stringent
emission
standards
that
are
based
on
more
robust
measurement
procedures.
We
are
therefore
adopting
a
second
tier
of
standards
to
require
additional
emission
reductions.
These
later
standards
require
manufacturers
to
control
emissions
under
both
steadystate
and
transient
engine
operation,
as
described
in
Section
V.
D
below).
Setting
the
emission
standards
to
require
additional
control
involves
separate
consideration
of
the
achievable
level
of
control
for
HC+
NOX
and
CO
emissions.
While
HC+
NOX
emissions
contribute
to
nonattainment
of
ozone
air
quality
standards,
CO
emissions
contribute
to
nonattainment
of
CO
air
quality
standards
and
potentially
harmful
exposures
of
individuals
where
engines
are
operating
in
areas
where
fresh
airflow
may
be
restricted.
Emissioncontrol
technology
is
able
to
simultaneously
control
these
three
pollutants,
but
a
tradeoff
between
NOX
and
CO
emissions
persists
for
any
given
system.
This
relationship
is
determined
by
an
engine's
precise
control
of
air
fuel
ratios
shifting
to
air
fuel
ratios
slightly
lean
of
stoichiometric
increases
NOX
emissions
but
decreases
CO
emissions
and
vice
versa.
Engines
using
different
fuels
face
this
same
situation,
though
gasoline
engines
operating
under
heavy
load
generally
need
to
shift
to
richer
airfuel
ratios
to
prevent
accelerated
engines
wear
from
very
high
combustion
temperatures.
Our
primary
focus
in
setting
the
level
of
the
emission
standards
is
reductions
in
emissions
that
contribute
to
ambient
air
pollution
problems.
At
the
same
time,
we
recognize
that
these
engines
are
used
in
many
applications
where
there
are
concerns
about
personal
exposure
to
the
engine
exhaust,
including
workplace
exposure,
focusing
primarily
on
CO
exposure.
It
is
appropriate
to
take
such
concerns
into
consideration
in
setting
the
level
of
the
standards.
In
this
case,
where
the
equipment
using
these
engines
can
vary
substantially
and
where
the
emissioncontrol
technology
means
there
is
a
trade
off
between
HC+
NOX
control
and
CO
control,
it
is
difficult
to
set
a
single,
optimal
standard
for
all
three
pollutants.
In
such
a
situation
it
is
reasonable
to
have
more
than
one
set
of
standards
to
allow
an
engine
to
use
technologies
focused
on
controlling
the
pollutants
of
most
concern
for
a
specific
application.
We
are
not
in
a
position,
however,
to
readily
identity
the
specific
levels
of
alternative
standards
that
are
appropriate
for
each
application
or
to
pick
specific
applications
that
should
go
with
different
standards.
We
also
want
to
ensure
that
engines
significantly
reduce
emissions
of
all
three
pollutants.
To
address
this,
we
are
setting
a
combination
of
standards
requiring
more
effective
emission
controls
starting
with
the
2007
model
year.
First,
we
are
setting
benchmark
emission
standards
of
2.7
g/
kW
hr
(
2.0
g/
hp
hr)
for
HC+
NOX
emissions
and
4.4
g/
kW
hr
(
3.3
g/
hp
hr)
for
CO
emissions.
The
emission
standards
apply
to
measurements
during
duty
cycle
testing
under
both
steady
state
and
transient
operation,
including
certification,
production
line
testing,
and
in
use
testing.
76
These
emission
levels
provide
for
substantial
control
of
HC+
NOX
emissions
(
in
fact,
these
standards
are
more
stringent
than
those
proposed),
but
also
contain
substantial
control
of
CO
emissions
to
protect
against
individual
exposure
as
well
as
CO
nonattainment.
We
are
also
including
an
option
for
manufacturers
to
certify
their
engines
to
different
emission
levels
to
allow
manufacturers
to
build
engines
whose
emission
controls
are
more
weighted
toward
controlling
NOX
emissions
to
reflect
the
inherent
tradeoff
of
NOX
and
CO
emissions.
Generally
this
involves
meeting
a
less
stringent
CO
standard
if
a
manufacturer
certifies
an
engine
with
lower
HC+
NOX
emissions.
Table
V.
C
1
shows
several
examples
of
possible
combinations
of
HC+
NOX
and
CO
emission
standards.
The
highest
allowable
CO
standard
is
20.6
g/
kW
hr
(
15.4
g/
hp
hr),
which
corresponds
with
HC+
NOX
emissions
below
0.8
g/
kW
hr
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77
While
the
emission
standards
in
this
final
rule
require
substantial
emission
reductions
of
CO
and
other
harmful
pollutants
from
nonroad
engines,
this
does
not
replace
the
need
for
ongoing
regulation
of
air
quality
to
protect
occupational
safety
and
health.
More
specifically,
in
accordance
with
the
limitations
provided
in
Section
310(
a)
of
the
Clean
Air
Act
(
42
U.
S.
C.
section
7610(
a)),
nothing
in
this
rule
affects
the
Occupational
Safety
and
Health
Administration's
authority
to
enforce
standards
and
other
requirements
under
the
Occupational
Safety
and
Health
Act
of
1970
(
29
U.
S.
C.
sections
651
et
seq.).
(
0.6
g/
hp
hr).
Manufacturers
certify
to
any
HC+
NOX
level
between
and
including
0.8
and
2.7
g/
kW
hr,
rounding
to
the
nearest
0.1
g/
kW
hr.
They
will
certify
also
to
the
corresponding
CO
level,
as
calculated
using
the
formula
below,
again
rounding
to
the
nearest
0.1
g/
kW
hr.
TABLE
V.
C
1.
SAMPLES
OF
POSSIBLE
ALTERNATIVE
DUTY
CYCLE
EMISSION
STANDARDS
FOR
LARGE
SI
ENGINES(
G/
KW
HR)*
HC+
NOX
CO
2.7
.................................................
4.4
2.2
.................................................
5.6
1.7
.................................................
7.9
1.3
.................................................
11.1
1.0
.................................................
15.5
0.8
.................................................
20.6
*
As
described
in
the
Final
Regulatory
Support
Document
and
the
regulations,
the
values
in
the
table
are
related
by
the
following
formula
(
HC+
NOX)
x
CO0.784
=
8.57.
These
values
follow
directly
from
the
logarithmic
relationship
presented
with
the
proposal
in
the
Draft
Regulatory
Support
Document.
We
believe
this
flexible
approach
to
setting
standards
is
the
most
appropriate
and
efficient
way
to
allocate
the
different
design
strategies
to
achieve
effective
reductions
of
HC+
NOX
emissions
while
providing
for
the
best
control
of
CO
emissions
where
it
is
most
needed.
Testing
has
shown
that
emission
controls
are
more
likely
to
experience
degradation
with
respect
to
controlling
CO
emissions
than
HC
or
NOX
emissions.
Manufacturers
therefore
have
a
natural
incentive
to
certify
engine
families
with
an
HC+
NOX
emission
level
as
low
as
possible
to
increase
the
compliance
margin
for
meeting
the
CO
standard.
In
addition,
many
of
these
engines
will
be
used
in
applications
where
ozone
is
of
more
concern.
As
a
result,
we
expect
manufacturers
to
design
most
of
their
engines
to
operate
substantially
below
the
2.7
g/
kW
hr
standard
for
HC+
NOX
emissions.
This
approach
also
encourages
manufacturers
to
continually
improve
their
control
of
HC+
NOX
emissions
over
time.
At
the
same
time,
to
the
extent
that
purchasers
want
engines
with
low
CO
emission
levels,
particularly
for
exposure
related
concerns,
manufacturers
will
be
able
to
produce
compliant
engines
that
will
provide
appropriate
protection.
Note
that
engines
operating
at
the
highest
allowable
CO
emission
levels
under
the
2007
standards
will
still
be
substantially
reducing
CO
emissions
compared
with
baseline
levels.
The
emission
standards
in
this
final
rule
will
achieve
substantial
reductions,
but
are
not
designed
to
guarantee
workplace
safety
or
to
set
a
safety
standard.
Rather,
we
intend
to
facilitate
the
use
of
engine
based
control
technologies
so
that
owners
and
operators
can
purchase
equipment
to
help
them
address
these
concerns.
We
are
not
adopting
any
controls
or
limits
to
restrict
the
sale
of
engines
meeting
certain
requirements
into
certain
applications.
We
believe
that
the
manufacturers
and
customers
for
these
products
will
together
make
educated
choices
regarding
the
appropriate
mix
of
emission
controls
for
each
application
and
that
market
forces
will
properly
balance
emission
controls
for
the
different
pollutants
in
specific
applications.
We
believe
that
customers
for
these
applications,
some
of
whom
are
subject
to
occupational
air
quality
standards
for
related
pollutant
concentrations,
will
be
well
placed
to
make
informed
choices
regarding
airpollution
control,
especially
given
their
ability
to
make
choices
based
on
the
specific
environmental
circumstances
of
each
particular
customer.
77
We
are
adopting
field
testing
standards
of
3.8
g/
kW
hr
(
2.8
g/
hp
hr)
for
HC+
NOX
and
6.5
g/
kW
hr
(
4.9
g/
hphr
for
CO.
As
described
above
for
dutycycle
testing,
field
testing
allows
for
the
same
pattern
of
optional
emission
standards
to
reflect
the
tradeoff
of
CO
and
NOX
emissions.
See
Section
V.
D.
5
for
more
information
about
field
testing.
As
described
in
Chapter
4
of
the
Final
Regulatory
Support
Document,
we
believe
manufacturers
can
achieve
these
emission
standards
by
optimizing
currently
available
three
way
catalysts
and
electronically
controlled
fuel
systems.
Two
additional
provisions
apply
to
specific
situations.
First,
some
engines
need
to
operate
with
rich
air
fuel
ratios
at
high
loads
to
protect
the
engine
from
overheating.
This
is
especially
true
for
gasoline
fueled
engines,
which
typically
experience
higher
combustion
temperatures.
When
operating
at
such
air
fuel
ratios,
the
engines
may
be
unable
to
meet
the
CO
emission
standard
during
steady
state
testing
because
the
steady
state
duty
cycle
involves
sustained
operation
under
high
load
conditions,
unlike
the
transient
duty
cycle.
If
a
manufacturer
shows
us
that
this
type
of
engine
operation
keeps
it
from
meeting
the
CO
emission
standard
shown
above
for
specific
models,
we
will
approve
a
separate
CO
emission
standard
of
31.0
g/
kW
hr
that
would
apply
only
to
steady
state
testing.
This
standard
reflects
the
adjustment
needed
at
highload
operation
and
would
apply
to
any
steady
state
tests
for
certification,
production
line
testing,
or
in
use
testing.
To
prevent
high
in
use
emission
levels,
we
are
adopting
several
additional
provisions
related
to
this
separate
CO
standard.
Manufacturers
must
show
that
enrichment
is
necessary
to
protect
the
engine
from
damage
and
that
enrichment
will
be
limited
to
operating
modes
that
require
additional
cooling
to
protect
the
engine
from
damage.
In
addition,
manufacturers
must
show
in
their
application
for
certification
that
enrichment
will
rarely
occur
in
the
equipment
in
which
your
engines
are
installed
(
for
example,
an
engine
that
is
expected
to
operate
5
percent
of
the
time
in
use
with
enrichment
would
clearly
not
qualify).
Finally,
manufacturers
must
include
in
the
emission
related
installation
instructions
any
steps
necessary
for
someone
installing
the
engines
to
prevent
enrichment
during
normal
operation.
This
option
does
not
apply
to
transient
or
field
testing,
so
these
engines
would
need
to
meet
the
same
formula
for
HC+
NOX
and
CO
standards
that
apply
to
other
engines
for
transient
testing
and
for
field
testing.
By
tying
the
CO
standard
for
these
engines
to
the
highest
allowable
CO
emission
level
for
field
testing,
we
are
effectively
requiring
that
manufacturers
ensure
that
in
use
engines
employ
engine
protection
strategies
no
more
frequently
than
is
reflected
in
the
steady
state
duty
cycles
for
certification.
Second,
equipment
manufacturers
have
made
it
clear
that
some
nonroad
applications
involve
operation
in
severe
environments
that
require
the
use
of
aircooled
engines.
These
engines
rely
on
air
movement
instead
of
an
automotivestyle
water
cooled
radiator
to
maintain
acceptable
engine
temperatures.
Since
air
cooling
is
less
effective,
these
engines
rely
substantially
on
enrichment
to
provide
additional
cooling
relative
to
water
cooled
engines.
At
these
richer
air
fuel
ratios,
catalysts
are
able
to
reduce
NOX
emissions
but
oxidation
of
CO
emissions
is
much
less
effective.
As
a
result,
we
are
adopting
emission
standards
for
these
``
severeduty
engines
of
2.7
g/
kW
hr
for
HC+
NOX
and
130
g/
kW
hr
for
CO.
These
standards
apply
to
duty
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Regulations
emission
testing
for
both
steady
state
and
transient
measurements
(
for
certification,
production
line,
and
inuse
testing).
The
corresponding
fieldtesting
standards
are
3.8
g/
kW
hr
for
HC+
NOX
and
200
g/
kW
hr
for
CO.
Severe
duty
applications
include
concrete
saws
and
concrete
pumps.
These
types
of
equipment
are
exposed
to
high
levels
of
concrete
dust,
which
tends
to
form
a
thick
insulating
coat
around
any
heat
exchanger
surfaces
and
exposes
engines
to
highly
abrasive
dust
particles.
Manufacturers
may
request
approval
in
identifying
additional
severe
duty
applications
subject
to
these
less
stringent
standards
if
they
can
provide
clear
evidence
that
the
majority
of
installations
need
air
cooled
engines
as
a
result
of
operation
in
a
severe
duty
environment.
This
arrangement
generally
prevents
these
higher
emitting
engines
from
gaining
a
competitive
advantage
in
markets
that
don't
already
use
air
cooled
engines.
We
believe
three
years
between
phases
of
emission
standards
allows
manufacturers
enough
lead
time
to
meet
the
more
stringent
emission
standards.
The
projected
emission
control
technologies
for
the
2004
emission
standards
should
be
capable
of
meeting
the
2007
emission
levels
with
additional
optimization
and
testing.
In
fact,
manufacturers
may
be
able
to
apply
their
optimization
efforts
before
2004,
leaving
only
the
additional
testing
demonstration
for
complying
with
the
2007
standards.
The
biggest
part
of
the
optimization
effort
may
be
related
to
gaining
assurance
that
engines
will
meet
field
testing
emission
standards
described
in
Section
V.
D.
5,
since
engines
will
not
be
following
a
prescribed
duty
cycle.
For
engines
fueled
by
gasoline
and
liquefied
petroleum
gas
(
LPG),
we
specify
emission
standards
based
on
total
hydrocarbon
measurements,
while
California
ARB
standards
are
based
on
nonmethane
hydrocarbons.
We
believe
that
switching
to
measurement
based
on
total
hydrocarbons
simplifies
testing,
especially
for
field
testing
of
in
use
engines
with
portable
devices
(
See
Section
V.
D.
5).
To
maintain
consistency
with
California
ARB
standards
in
the
near
term,
we
will
allow
manufacturers
to
base
their
certification
through
2006
on
either
nonmethane
or
total
hydrocarbons
(
see
40
CFR
1048.145).
Methane
emissions
from
controlled
engines
operating
on
gasoline
or
LPG
are
about
0.1
g/
kW
hr.
Operation
of
natural
gas
engines
is
very
similar
to
that
of
LPG
engines,
with
one
noteworthy
exception.
Since
natural
gas
consists
primarily
of
methane,
these
engines
have
a
much
higher
level
of
methane
in
the
exhaust.
Methane
generally
does
not
contribute
to
ozone
formation,
so
it
is
often
excluded
from
emission
measurements.
We
have
therefore
specified
nonmethane
hydrocarbon
emissions
for
comparison
with
the
standard
for
natural
gas
engines.
However,
the
emission
standards
based
on
measuring
emissions
in
the
field
depend
on
total
hydrocarbons.
We
are
therefore
adopting
a
NOX
only
field
testing
standard
for
natural
gas
engines
instead
of
a
HC+
NOX
standard.
Since
control
of
NOX
emissions
for
natural
gas
engines
poses
a
significantly
greater
challenge
than
controlling
nonmethane
hydrocarbons,
duty
cycle
testing
provides
adequate
assurance
that
these
engines
have
sufficiently
low
hydrocarbon
emission
levels.
Manufacturers
must
show
that
they
meet
these
duty
cycle
standards
for
certification
and
the
engines
remain
subject
to
the
nonmethane
hydrocarbon
standard
in
use
when
tested
over
the
same
duty
cycles.
b.
Evaporative
emissions.
We
are
adopting
requirements
related
to
evaporative
and
permeation
emissions
from
gasoline
fueled
Large
SI
engines.
For
controlling
diurnal
emissions,
we
are
adopting
an
emission
standard
of
0.2
grams
of
hydrocarbon
per
gallon
of
fuel
tank
capacity
during
a
24
hour
period.
In
addition,
we
specify
that
manufacturers
use
fuel
lines
meeting
an
industry
standard
for
permeationresistance
Finally,
we
require
that
manufacturers
take
steps
to
prevent
fuel
from
boiling.
We
expect
certification
of
manufacturers'
equipment
to
be
designbased
as
compared
with
conducting
a
full
emission
measurement
program
during
certification.
As
such,
meeting
these
evaporative
requirements
is
much
more
like
meeting
the
requirements
related
to
controlling
crankcase
emissions
and
is
therefore
discussed
in
detail
in
Section
V.
C.
4
below.
2.
May
I
Average,
Bank,
or
Trade
Emission
Credits?
We
are
not
including
an
averaging,
banking,
and
trading
program
for
certifying
engines.
As
described
in
Chapter
4
of
the
Final
Regulatory
Support
Document,
we
believe
that
manufacturers
will
generally
be
able
to
rely
on
a
relatively
uniform
application
of
emission
control
technology
to
meet
emission
standards.
The
standards
were
selected
based
on
the
capabilities
of
all
manufacturers
to
comply
with
all
their
models
without
an
emission
credit
program.
Moreover,
overlaying
an
emission
credit
program
on
the
flexible
standards
described
above
would
be
highly
impractical.
If
such
a
program
could
be
devised
it
would
need
to
be
very
complex
and
would
achieve
little,
if
any,
advantage
to
manufacturers
beyond
the
advantages
already
embodied
in
the
flexible
approach
we
are
adopting.
However,
as
an
alternative
to
a
program
of
calculating
emission
credits
for
averaging,
banking,
and
trading,
we
are
adopting
a
simpler
approach
of
``
family
banking''
to
help
manufacturers
transition
to
new
emission
standards
(
see
40
CFR
1048.145
of
the
regulations).
Manufacturers
may
certify
an
engine
family
early,
which
would
allow
them
to
delay
certification
of
smaller
engine
families.
This
would
be
based
on
the
actual
sales
of
each
engine
family;
this
requires
no
calculation
or
accounting
of
emission
credits.
The
manufacturer
would
have
actual
sales
figures
for
the
early
family
at
the
end
of
the
production
year,
which
would
yield
a
total
number
of
allowable
sales
for
the
engine
family
with
delayed
compliance.
Manufacturers
may
certify
engines
to
the
2004
standards
early,
but
this
would
provide
benefits
only
for
complying
with
the
2004
standards.
These
``
credits''
would
not
apply
to
engines
for
meeting
the
2007
standards.
3.
Is
EPA
Adopting
Voluntary
Blue
Sky
Standards
for
These
Engines?
We
are
adopting
voluntary
Blue
Sky
standards
for
Large
SI
engines.
We
are
setting
a
target
of
0.8
g/
kW
hr
(
0.6
g/
hphr
HC+
NOX
and
4.4
g/
kW
hr
(
3.3
g/
hphr
CO
as
a
qualifying
level
for
Blue
Sky
Series
engines.
The
corresponding
fieldtesting
standards
for
Blue
Sky
Series
engines
are
1.1
g/
kW
hr
(
0.8
g/
hp
hr)
HC+
NOX
and
6.6
g/
kW
hr
(
4.9
g/
hp
hr)
CO.
These
voluntary
standards
are
based
on
achieving
the
maximum
control
of
both
HC+
NOX
and
CO
emissions,
as
described
in
Section
V.
C.
1.
To
achieve
these
emission
levels,
manufacturers
will
need
to
apply
significantly
additional
technology
beyond
that
required
for
the
mandatory
standards.
Manufacturers
may
start
producing
engines
to
these
voluntary
standards
immediately
after
this
final
rule
becomes
effective.
In
addition,
we
are
adopting
interim
voluntary
standards
corresponding
with
the
introduction
of
new
emission
standards.
Since
manufacturers
will
not
be
complying
early
to
bank
emission
credits,
voluntary
emission
standards
are
an
appropriate
way
to
encourage
manufacturers
to
meet
emission
standards
before
the
regulatory
deadline.
If
manufacturers
certify
engines
to
these
voluntary
standards,
they
are
not
eligible
for
participation
in
the
family
banking
program
described
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78
Stoichiometry
is
the
proportion
of
a
mixture
of
air
and
fuel
such
that
the
fuel
is
fully
oxidized
with
no
remaining
oxygen.
For
example,
stoichiometric
combustion
in
gasoline
engines
typically
occurs
at
an
air
fuel
mass
ratio
of
about
14.7.
79
''
Measurement
of
Evaporative
Emissions
from
Off
Road
Equipment,''
by
James
N.
Carroll
and
Jeff
J.
White,
Southwest
Research
Institute
(
SwRI
08
Continued
above.
In
the
2003
model
year,
manufacturers
may
certify
their
engines
to
the
requirements
that
apply
starting
in
2004
to
qualify
for
the
Blue
Sky
designation.
Since
manufacturers
are
producing
engines
with
emissioncontrol
technologies
starting
in
2001,
these
engines
are
available
to
customers
outside
of
California
desiring
emission
reductions
or
fuel
economy
improvements.
Similarly,
for
2003
through
2006
model
years,
manufacturers
may
certify
their
engines
to
the
requirements
that
start
to
apply
in
2007.
4.
Are
There
Other
Requirements
for
Large
SI
Engines?
a.
Crankcase
emissions.
Due
to
blowby
of
combustion
gases
and
the
reciprocating
action
of
the
piston,
exhaust
emissions
(
mostly
hydrocarbons)
can
accumulate
in
the
crankcase.
These
crankcase
emissions
are
significant,
representing
about
33
percent
of
total
exhaust
hydrocarbon.
Uncontrolled
engines
route
these
vapors
directly
to
the
atmosphere.
We
have
long
required
that
automotive
engines
prevent
crankcase
emissions.
Manufacturers
typically
do
this
by
routing
crankcase
vapors
through
a
valve
into
the
engine's
air
intake
system
where
they
are
burned
in
the
combustion
process.
Manufacturers
may
choose
one
of
two
methods
for
controlling
crankcase
emissions.
First,
adding
positivecrankcase
ventilation
prevents
crankcase
emissions.
Since
automotive
engine
blocks
are
already
tooled
for
closed
crankcases,
the
cost
of
adding
a
valve
for
positive
crankcase
ventilation
for
most
engines
is
very
small.
An
alternative
method
addresses
specific
concerns
related
to
turbocharged
engines
or
engines
operating
in
severeduty
environments.
Where
closed
crankcases
are
impractical,
manufacturers
may
therefore
measure
crankcase
emissions
during
any
emission
testing
to
add
crankcase
emissions
to
measured
exhaust
emissions
for
comparing
with
the
standards.
b.
Diagnosing
malfunctions.
Manufacturers
must
design
their
Large
SI
engines
to
diagnose
malfunctioning
emission
control
systems
starting
with
the
2007
model
year
(
see
§
1048.110).
Three
way
catalyst
systems
with
closedloop
fueling
control
work
well
only
when
the
air
fuel
ratios
are
controlled
to
stay
within
a
narrow
range
around
stoichiometry.
78
Worn
or
broken
components
or
drifting
calibrations
over
time
can
prevent
an
engine
from
operating
within
the
specified
range.
This
increases
emissions
and
can
significantly
increase
fuel
consumption
and
engine
wear.
The
operator
may
or
may
not
notice
the
change
in
the
way
the
engine
operates.
We
are
not
requiring
similar
diagnostic
controls
for
recreational
vehicles
or
recreational
marine
diesel
engines,
because
the
anticipated
emission
control
technologies
for
these
other
applications
are
generally
less
susceptible
to
drift
and
gradual
deterioration.
This
diagnostic
requirement
focuses
solely
on
maintaining
stoichiometric
control
of
air
fuel
ratios.
This
kind
of
design
detects
problems
such
as
broken
oxygen
sensors,
leaking
exhaust
pipes,
fuel
deposits,
and
other
things
that
require
maintenance
to
keep
the
engine
at
the
proper
air
fuel
ratio.
Some
companies
are
already
producing
engines
with
diagnostic
systems
that
check
for
consistent
airfuel
ratios.
Their
initiative
supports
the
idea
that
diagnostic
monitoring
provides
a
mechanism
to
help
keep
engines
tuned
to
operate
properly,
with
benefits
for
both
controlling
emissions
and
maintaining
optimal
performance.
There
are
currently
no
inspection
and
maintenance
programs
for
nonroad
engines,
so
the
most
important
variable
in
making
the
emission
control
and
diagnostic
systems
effective
is
in
getting
operators
to
repair
the
engine
when
the
diagnostic
light
comes
on.
This
calls
for
a
relatively
simple
design
to
avoid
the
signaling
of
false
failures
as
much
as
possible.
The
diagnostic
requirements
in
this
rule
therefore
focus
on
detecting
inappropriate
air
fuel
ratios,
which
is
the
most
likely
failure
mode
for
threeway
catalyst
systems.
The
malfunctionindicator
light
must
go
on
when
an
engine
runs
for
a
full
minute
under
closed
loop
operation
without
reaching
a
stoichiometric
air
fuel
ratio.
Some
natural
gas
engines
may
meet
standards
with
lean
burn
designs
that
never
approach
stoichiometric
combustion.
While
manufacturers
may
design
these
engines
to
operate
at
specific
air
fuel
ratios,
catalyst
conversion
(
with
two
way
catalysts)
would
not
be
as
sensitive
to
air
fuel
ratio
as
with
stoichiometric
designs.
For
these
or
other
engines
that
rely
on
emission
control
technologies
incompatible
with
the
diagnostic
system
described
above,
manufacturers
must
devise
an
alternate
system
that
alerts
the
operator
to
engine
malfunctions
that
would
prevent
the
emission
control
system
from
functioning
properly.
The
automotive
industry
has
developed
a
standardized
protocol
for
diagnostic
systems,
including
hardware
specifications,
and
uniform
trouble
codes.
In
the
regulations
we
reference
standards
adopted
by
the
International
Organization
for
Standardization
(
ISO)
for
automotive
systems.
If
manufacturers
find
that
these
standards
are
not
applicable
to
the
simpler
diagnostic
design
specified
for
Large
SI
engines,
we
encourage
engine
manufacturers
to
cooperate
with
each
other
and
with
other
interested
companies
to
develop
new
standards
specific
to
nonroad
engines.
Manufacturers
may
request
approval
to
use
systems
that
don't
meet
the
automotive
specifications
if
those
specifications
are
not
practical
or
appropriate
for
their
engines.
c.
Evaporative
emissions.
Evaporative
emissions
occur
when
fuel
evaporates
and
is
vented
into
the
atmosphere.
They
can
occur
while
an
engine
or
vehicle
is
operating
and
even
while
it
is
not
being
operated.
Among
the
factors
that
affect
evaporative
emissions
are:
Fuel
metering
(
fuel
injectors
or
carburetor)
The
degree
to
which
fuel
permeates
fuel
lines
and
fuel
tanks
Proximity
of
the
fuel
tank
to
the
exhaust
system
or
other
heat
sources
Whether
the
fuel
system
is
sealed
and
the
pressure
at
which
fuel
vapors
are
ventilated.
In
addition,
some
gasoline
fuel
tanks
may
be
exposed
to
heat
from
the
engine
compartment
and
high
temperature
surfaces
such
as
the
exhaust
pipe.
In
extreme
cases,
fuel
can
start
boiling,
producing
very
large
amounts
of
gasoline
vapors
vented
directly
to
the
atmosphere.
Evaporative
emissions
from
Large
SI
engines
and
the
associated
equipment
represent
a
significant
part
of
their
overall
hydrocarbon
emissions.
The
magnitude
of
evaporative
emissions
varies
widely
depending
on
the
engine
design
and
application.
LPG
fueled
equipment
generally
has
very
low
evaporative
emissions
because
of
the
tightly
sealed
fuel
system.
At
the
other
extreme,
carbureted
gasoline
fueled
equipment
can
have
high
rates
of
evaporation.
In
1998,
Southwest
Research
Institute
measured
emissions
from
several
gasoline
fueled
Large
SI
engines
and
found
them
to
vary
from
about
12
g/
day
up
to
almost
100
g/
day.
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Rules
and
Regulations
1076),
November
1998,
Docket
A
2000
01,
document
II
A
10.
80
''
Industrial
Trucks,
Internal
Combustion
Engine
Powered,''
UL558,
ninth
edition,
June
28,
1996,
paragraphs
26.1
through
26.4,
Docket
A
2000
01,
document
II
A
28.
See
Section
XI.
I
for
our
consideration
of
incorporating
the
UL
requirements
into
our
regulations
by
reference.
81
''
New
Evaporative
Control
System
for
Gasoline
Tanks,''
EPA
Memorandum
from
Charles
Moulis
to
Glenn
Passavant,
March
1,
2001,
Docket
A
2000
01,
document
II
B
16.
82
SAE
J2260
``
Nonmetallic
Fuel
System
Tubing
with
One
or
More
Layers,''
November
1996
(
Docket
A
2000
01,
document
II
A
03).
83
UL558,
paragraph
19.1.1,
Docket
A
2000
01,
document
II
A
28.
This
study
did
not
take
into
account
the
possibility
of
unusually
high
fuel
temperatures
during
engine
operation,
as
described
further
below.
We
are
adopting
basic
measures
to
reduce
evaporative
emissions
from
gasoline
fueled
Large
SI
engines.
First,
we
are
adopting
an
evaporative
emission
standard
of
0.2
grams
per
gallon
of
fuel
tank
capacity
for
24
hour
day
when
temperatures
cycle
between
72
°
and
96
°
F.
For
purposes
of
certification,
manufacturers
may
choose,
however,
to
rely
on
a
specific
design
for
certification
instead
of
measuring
emissions.
We
have
identified
a
technology
that
adequately
prevents
evaporative
emissions
such
that
the
design
itself
would
be
enough
to
show
compliance
with
the
evaporative
emission
standard
for
purposes
of
certification.
Specifically,
pressurized
fuel
tanks
control
evaporative
emissions
by
suppressing
vapor
generation.
In
its
standards
for
industrial
trucks
operating
in
certain
environments,
Underwriters
Laboratories
requires
that
trucks
use
self
closing
fuel
caps
with
tanks
that
stay
sealed
to
prevent
evaporative
losses;
venting
is
allowed
for
positive
pressures
above
3.5
psi
or
for
vacuum
pressures
of
at
least
1.5
psi.
80
We
know
that
any
Large
SI
engines
or
vehicles
operating
with
these
pressures
would
meet
the
standard
because
test
data
confirm
the
basic
chemistry
principles
related
to
phase
change
pressure
relationships
showing
that
fuel
tanks
will
remain
sealed
at
all
times
during
the
prescribed
test
procedure.
Also,
similar
to
the
Underwriters
Laboratories'
requirement,
we
specify
that
manufacturers
must
use
self
closing
or
tethered
fuel
caps
to
ensure
that
fuel
tanks
designed
to
hold
pressure
are
not
inadvertently
left
exposed
to
the
atmosphere.
In
some
applications,
manufacturers
may
want
to
avoid
high
fuel
tank
pressures.
Manufacturers
may
be
able
to
meet
the
standard
using
an
air
bladder
inside
the
fuel
tank
that
changes
in
volume
to
keep
the
system
in
equilibrium
at
atmospheric
pressure.
81
We
have
data
showing
that
these
systems
also
would
remain
sealed
at
all
times
during
the
prescribed
test
procedure.
However,
the
permeation
levels
related
to
the
air
bladder
and
the
long
term
durability
of
this
type
of
system
are
still
unknown.
Once
these
parameters
are
established
with
test
data,
perhaps
with
some
additional
product
development,
this
technology
may
then
qualify
as
an
option
for
design
based
certification.
Similarly,
collapsible
bladder
tanks,
which
change
in
volume
to
prevent
generation
of
a
vapor
space
or
vapor
emissions,
may
eventually
be
available
as
a
technology
for
design
based
certification
once
permeation
data
are
available
to
confirm
that
systems
with
these
tanks
would
meet
the
standard.
Finally,
an
automotive
type
system
that
stores
fuel
tank
vapors
for
burning
in
the
engine
would
be
another
alternative
technology,
though
it
is
unlikely
that
such
a
system
can
be
simply
characterized
and
included
as
an
option
for
design
based
certification.
In
addition,
engine
manufacturers
must
use
(
or
specify
that
equipment
manufacturers
installing
their
engines
use)
fuel
lines
meeting
the
industry
performance
standard
for
permeationresistant
fuel
lines
developed
for
motor
vehicles.
82
While
metal
fuel
lines
do
not
have
problems
with
permeation,
manufacturers
should
use
discretion
in
selecting
materials
for
grommets
and
valves
connecting
metal
components
to
avoid
high
permeation
materials.
Evaporative
emission
standards
for
motor
vehicles
have
led
to
the
development
of
a
wide
variety
of
permeation
resistant
polymer
components.
These
permeation
requirements
are
based
on
manufacturers
using
a
more
effective
emission
controls
than
that
specified
for
recreational
vehicles.
This
is
appropriate
because
Large
SI
manufacturers
are
able
to
use
automotive
grade
materials
across
their
product
line,
while
recreational
vehicle
manufacturers
have
pointed
out
various
limitations
in
incorporating
automotivegrade
materials.
Conversely,
Large
SI
manufacturers
are
not
subject
to
permeation
requirements
related
to
fuel
tanks,
since
almost
all
of
these
tanks
are
made
of
metal.
Finally,
based
on
available
technologies,
manufacturers
must
take
steps
to
prevent
fuel
boiling.
The
Underwriters
Laboratories
specification
for
forklifts
attempts
to
address
this
concern
through
a
specified
maximum
fuel
temperature,
but
the
current
limit
does
not
prevent
fuel
boiling.
83
We
are
adopting
a
standard
that
prohibits
fuel
boiling
during
continuous
operation
at
30
°
C
(
86
°
F).
Engine
manufacturers
must
incorporate
designs
that
reduce
the
heat
load
to
the
fuel
tank
to
prevent
boiling.
For
companies
that
sell
loose
engines,
this
may
involve
instructions
to
equipment
manufacturers
to
help
ensure,
for
example,
that
fuel
tank
surfaces
are
exposed
to
ambient
air
rather
than
to
exhaust
pipes
or
direct
engine
heat.
Engine
manufacturers
may
specify
a
maximum
fuel
temperature
for
the
final
installation.
Such
a
temperature
limit
should
be
well
below
53
°
C
(
128
°
F),
the
temperature
at
which
summer
grade
gasoline
(
9
RVP)
typically
starts
boiling.
An
additional
source
of
evaporative
emissions
is
from
carburetors.
Carburetors
often
have
high
hot
soak
emissions
(
immediately
after
engine
shutdown).
We
expect
manufacturers
to
convert
carbureted
designs
to
fuel
injection
as
a
result
of
the
exhaust
emission
standards.
While
we
do
not
mandate
this
technology,
we
believe
the
need
to
reduce
exhaust
emissions
will
cause
engine
manufacturers
to
use
fuel
injection
on
all
gasoline
engines.
This
change
alone
will
eliminate
most
hot
soak
emissions.
Engine
manufacturers
using
designbased
certification
need
to
describe
in
the
application
for
certification
the
selected
design
measures
and
specifications
to
address
evaporative
losses
from
gasoline
fueled
engines.
For
loose
engine
sales,
this
includes
emission
related
installation
instructions
that
the
engine
manufacturer
gives
to
equipment
manufacturers.
While
equipment
manufacturers
must
follow
these
installation
instruction,
the
engine
manufacturer
has
the
responsibility
to
certify
a
system
that
meets
the
evaporative
related
requirements
described
in
this
section.
This
should
work
in
practice,
because
engine
manufacturers
already
provide
equipment
manufacturers
a
variety
of
specifications
and
other
instructions
to
ensure
that
engines
operate
properly
inuse
after
installation
in
the
equipment.
The
alternative
approach
of
requiring
equipment
manufacturers
to
certify
is
impractical
because
of
the
very
large
number
of
companies
involved.
5.
What
Durability
Provisions
Apply?
a.
Useful
life.
We
are
adopting
a
useful
life
period
of
seven
years
or
until
the
engine
accumulates
at
least
5,000
operating
hours,
whichever
comes
first.
This
figure
represents
a
minimum
value
and
may
increase
as
a
result
of
data
showing
that
an
engine
model
is
designed
to
last
longer.
This
figure,
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and
Regulations
which
California
ARB
has
already
adopted,
represents
an
operating
period
that
is
common
for
Large
SI
engines
before
they
undergo
rebuild.
This
also
reflects
a
comparable
degree
of
operation
relative
to
the
useful
life
values
of
100,000
to
150,000
miles
that
apply
to
automotive
engines
(
assuming
an
average
driving
speed
of
20
to
30
miles
per
hour).
Some
engines
are
designed
for
operation
in
severe
duty
applications
with
a
shorter
expected
lifetime.
Concrete
saws
in
particular
undergo
accelerated
wear
as
a
result
of
operating
in
an
environment
with
high
concentrations
of
highly
abrasive,
airborne
concrete
dust
particles.
We
are
allowing
manufacturers
to
request
a
shorter
useful
life
for
an
engine
family
based
on
information
showing
that
engines
in
the
family
rarely
operate
beyond
the
alternative
useful
life
period.
For
example,
if
engines
powering
concrete
saws
are
typically
scrapped
after
2000
hours
of
operation,
this
would
form
the
basis
for
establishing
a
shorter
useful
life
period
for
those
engines.
Manufacturers
relying
on
designbased
certification
to
meet
the
evaporative
requirements
must
use
good
engineering
judgment
to
show
that
emission
controls
will
work
for
at
least
seven
years.
This
may,
for
example,
be
based
on
warranty
or
productperformance
history
from
component
suppliers.
This
also
applies
for
systems
designed
to
address
crankcase
emissions.
b.
Warranty.
Manufacturers
must
provide
an
emission
related
warranty
for
at
least
the
first
half
of
an
engine's
useful
life
(
in
operating
hours)
or
three
years,
whichever
comes
first.
These
periods
must
be
longer
if
the
manufacturer
offers
a
longer
mechanical
warranty
for
the
engine
or
any
of
its
components;
this
includes
extended
warranties
that
are
available
for
an
extra
price.
The
emission
related
warranty
includes
components
related
to
controlling
evaporative
and
crankcase
emissions.
In
addition,
we
are
adopting
the
warranty
provisions
adopted
by
California
ARB
for
high
cost
parts.
For
emission
related
components
whose
replacement
cost
is
more
than
about
$
400,
we
specify
a
minimum
warranty
period
of
at
least
70
percent
of
the
engine's
useful
life
(
in
operating
hours)
or
5
years,
whichever
comes
first.
See
§
1048.120
for
a
description
of
which
components
are
emission
related.
c.
Maintenance
instructions.
We
are
specifying
minimum
maintenance
intervals
much
like
those
established
by
California
ARB
for
Large
SI
engines.
The
minimum
intervals
define
how
much
maintenance
a
manufacturer
may
specify
to
ensure
that
engines
are
properly
maintained
for
staying
within
emission
standards.
Manufacturers
may
schedule
maintenance
on
catalysts,
fuel
injectors,
electronic
control
units
and
turbochargers
after
5,000
hours.
For
oxygen
sensors
and
cleaning
of
fuelsystem
components,
the
minimum
maintenance
interval
is
2,500
hours.
This
fuel
system
cleaning
must
be
limited
to
steps
that
can
be
taken
without
disassembling
components.
We
have
relaxed
this
from
the
proposed
interval
of
4,500
hours
to
take
into
account
comments
emphasizing
that
these
maintenance
steps
will
be
necessary
more
frequently
than
the
proposed
interval;
this
shorter
interval
also
reflects
the
comparable
provisions
that
apply
to
automotive
systems.
We
are
also
proposing
a
diagnostic
requirement
to
ensure
that
prematurely
failing
oxygen
sensors
or
other
components
are
detected
and
replaced
on
an
as
needed
basis.
If
operators
fail
to
address
faulty
components
after
a
fault
signal,
we
would
not
consider
that
engine
to
be
properly
maintained.
This
could
the
engine
ineligible
for
manufacturer
in
use
testing.
d.
Deterioration
factors.
We
are
adopting
an
approach
that
gives
manufacturers
wide
discretion
in
how
to
establish
deterioration
factors
for
Large
SI
engines.
The
general
expectation
is
that
manufacturers
will
rely
on
emission
measurements
from
engines
that
have
operated
for
an
extended
period,
either
in
field
service
or
in
the
laboratory.
The
manufacturer
should
do
testing
as
needed
to
be
confident
that
their
engines
will
meet
emission
standards
under
the
in
use
testing
program.
In
deciding
to
certify
an
engine
family,
we
can
review
deterioration
factors
to
ensure
that
the
projected
deterioration
accurately
predicts
in
use
deterioration.
We
will
use
results
under
the
in
use
testing
program
to
verify
the
appropriateness
of
deterioration
factors.
In
the
first
two
or
three
years
of
certification,
manufacturers
will
not
yet
have
data
from
the
in
use
testing
program.
Moreover,
manufacturers
may
choose
to
rely
on
technologies
and
calibrations
for
meeting
the
long
term
standards
well
before
2007
to
simplify
their
product
development
efforts.
We
are
therefore
allowing
manufacturers
to
rely
on
an
assigned
deterioration
factor
to
meet
the
2004
standards,
while
continuing
to
require
manufacturers
to
meet
the
applicable
emission
standards
throughout
the
useful
life
for
these
engines.
The
assigned
deterioration
factor
may
be
derived
from
any
available
data
that
would
help
predict
the
way
these
systems
would
perform
in
the
field,
using
good
engineering
judgment.
Manufacturers
may
develop
deterioration
factors
for
crankcase
and
evaporative
controls.
However,
we
do
not
expect
these
control
technologies
to
experience
degradation
that
would
cause
a
deterioration
factor
to
be
appropriate.
e.
In
use
fuel
quality.
Gasoline
used
in
industrial
applications
is
generally
the
same
as
that
used
for
automotive
applications.
Improvements
that
have
been
made
to
highway
grade
gasoline
therefore
carry
over
directly
to
nonroad
markets.
This
helps
manufacturers
be
sure
that
fuel
quality
will
not
degrade
an
engine's
emission
control
performance
after
several
years
of
sustained
operation.
In
contrast,
there
are
no
enforceable
industry
or
government
standards
for
LPG
fuel
quality.
Testing
data
indicate
that
varying
fuel
quality
has
a
small
direct
effect
on
emissions
from
a
closedloop
engine
with
a
catalyst.
The
greater
concern
is
that
fuel
impurities
and
heavy
end
hydrocarbons
may
cause
an
accumulation
of
deposits
that
can
prevent
an
emission
control
system
from
functioning
properly.
While
an
engine's
feedback
controls
can
compensate
for
some
restriction
in
air
and
fuel
flow,
deposits
may
eventually
prevent
the
engine
from
accurately
controlling
air
fuel
ratios
at
stoichiometry.
As
described
in
the
Final
Regulatory
Support
Document,
test
data
show
that
emission
control
systems
can
tolerate
substantial
fuel
related
deposits
before
there
is
any
measurable
effect
on
emissions.
Moreover,
the
engine
diagnostic
systems
described
in
the
next
section
will
notify
the
operator
when
fuel
related
deposits
prevent
an
engine
from
operating
at
stoichiometry.
In
any
case,
a
routine
cleaning
step
should
remove
deposits
and
restore
the
engine
to
proper
functioning.
Data
from
in
use
testing
will
provide
additional
information
related
to
the
effects
of
varying
fuel
quality
on
emission
levels.
This
information
will
be
helpful
in
making
sure
that
the
deterioration
factors
for
certifying
engines
accurately
reflect
the
whole
range
of
in
use
operating
variables,
including
varying
fuel
quality.
Our
testing
shows
that
fuel
properties
of
conventional
commercial
LPG
fuel
allow
for
durable,
long
term
control
of
emissions.
However,
to
the
extent
that
engines
operating
in
specific
areas
have
inferior
fuel
quality
that
prevents
them
from
meeting
emission
standards,
we
will
be
pursuing
nationwide
requirements
to
set
minimum
quality
standards
for
in
use
LPG
fuel.
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8,
2002
/
Rules
and
Regulations
D.
Testing
Requirements
and
Supplemental
Emission
Standards
1.
What
Duty
Cycles
Are
Used
To
Measure
Emissions?
For
2004
through
2006
model
years,
we
specify
the
same
steady
state
duty
cycles
adopted
by
California
ARB.
For
variable
speed
engines,
this
involves
the
testing
based
on
the
ISO
C2
duty
cycle,
which
has
five
modes
at
various
intermediate
speed
points,
plus
one
mode
at
rated
speed
and
one
idle
mode.
The
combined
intermediate
speed
points
at
10,
25,
and
50
percent
account
for
over
70
percent
of
the
total
modal
weighting.
A
separate
duty
cycle
for
the
large
number
of
Large
SI
engine
providing
power
for
constant
speed
applications,
such
as
generators,
welders,
compressors,
pumps,
sweepers,
and
aerial
lifts.
Constant
speed
testing
is
based
on
the
ISO
D2
duty
cycle,
which
specifies
engine
operation
at
rated
speed
with
five
different
load
points.
This
same
steady
state
duty
cycle
applies
to
constant
speed,
nonroad
diesel
engines.
Emission
values
measured
on
the
D2
duty
cycle
are
treated
the
same
as
values
from
the
C2
duty
cycle;
the
same
numerical
standards
apply
to
both
cycles.
Manufacturers
must
generally
test
engines
on
both
the
C2
and
D2
duty
cycles.
Since
the
C2
cycle
includes
very
little
operation
at
rated
speed,
it
is
not
effective
in
ensuring
control
of
emissions
for
constant
speed
engines.
The
D2
cycle
is
even
less
capable
of
predicting
emission
performance
from
variable
speed
engines.
Manufacturers
may,
however,
choose
to
certify
their
engines
on
only
one
of
these
two
steadystate
duty
cycles.
In
this
case,
they
would
need
to
take
steps
to
make
sure
C2
certified
engines
are
installed
only
in
variable
speed
applications
and
D2
certified
engines
are
installed
only
in
constant
speed
applications.
Engine
manufacturers
would
do
this
by
labeling
their
engines
appropriately
and
providing
installation
instructions
to
make
sure
equipment
manufacturers
and
others
are
aware
of
the
restricted
certification.
Equipment
manufacturers
are
required
under
the
regulations
to
follow
the
engine
manufacturer's
emission
related
installation
instructions.
Starting
in
2007,
we
specify
an
expanded
set
of
duty
cycles,
again
with
separate
treatment
for
variable
speed
and
constant
speed
applications.
The
test
procedure
is
comprised
of
three
segments:
(
1)
A
warm
up
segment,
(
2)
a
transient
segment,
and
(
3)
a
steady
state
segment.
Each
of
these
segments,
described
briefly
in
this
section,
include
specifications
for
the
speed
and
load
of
the
engine
as
a
function
of
time.
Measured
emissions
during
the
transient
and
steady
state
segments
must
meet
the
same
emission
standards
that
apply
to
all
duty
cycles.
In
general,
the
duty
cycles
are
intended
to
represent
operation
from
the
wide
variety
of
in
use
applications.
This
includes
highly
transient
low
speed
forklift
operation,
constant
speed
operation
of
portable
equipment,
and
intermediate
speed
vehicle
operation.
Ambient
temperatures
in
the
laboratory
must
be
between
20
°
and
30
°
C
(
68
°
and
86
°
F)
during
duty
cycle
testing.
This
improves
the
repeatability
of
emission
measurements
when
the
engine
runs
through
its
prescribed
operation.
We
nevertheless
expect
manufacturers
to
design
for
controlling
emissions
under
broader
ambient
conditions,
as
described
in
Section
V.
D.
5.
The
warm
up
segment
begins
with
a
cold
start.
This
means
that
the
engine
should
be
near
room
temperature
before
the
test
cycle
begins.
(
Starting
with
an
engine
that
is
still
warm
from
previous
testing
is
allowed
if
good
engineering
judgment
indicates
that
this
will
not
affect
emissions.)
Once
the
engine
is
started,
it
operates
over
the
first
3
minutes
of
the
specified
transient
duty
cycle
without
emission
measurement.
The
engine
then
idles
for
30
seconds
before
starting
the
prescribed
transient
cycle.
The
purpose
of
the
warm
up
segment
is
to
bring
the
engine
up
to
normal
operating
temperature
in
a
standardized
way.
For
severe
duty
engines,
the
warm
up
period
is
extended
up
to
15
minutes
to
account
for
the
additional
time
needed
to
stabilize
operating
temperatures
from
air
cooled
engines.
The
warm
up
period
allows
enough
time
for
engine
out
emissions
to
stabilize,
for
the
catalyst
to
warm
up
enough
to
become
active,
and
for
the
engine
to
start
closed
loop
operation.
This
serves
as
a
defined
and
achievable
target
for
the
design
engineer
to
limit
cold
start
emissions
to
a
relatively
short
period.
In
addition,
we
require
manufacturers
to
activate
emission
control
systems
as
soon
as
possible
after
engine
starting
to
make
clear
that
it
is
not
acceptable
to
design
the
emission
control
system
to
start
working
only
after
the
defined
warm
up
period
is
complete.
In
addition,
we
may
measure
emissions
during
the
warm
up
period
to
evaluate
whether
manufacturers
are
employing
defeat
devices.
In
contrast,
transient
testing
of
heavy
duty
highway
engines
requires
separate
cold
start
and
hot
start
measurements,
with
an
86
percent
weighting
assigned
to
the
hot
start
portion
in
calculating
an
engine's
composite
emission
level.
We
believe
this
approach
for
nonroad
engines
serves
to
limit
cold
start
emissions
without
forcing
manufacturers
to
focus
design
and
testing
resources
on
this
portion
of
operation.
The
transient
segment
of
the
general
duty
cycle
is
a
composite
of
forklift
and
welder
operation.
This
duty
cycle
was
developed
by
selecting
segments
of
measured
engine
operation
from
two
forklifts
and
a
welder
as
they
performed
their
normal
functions.
This
transient
segment
captures
the
wide
variety
of
operation
from
a
large
majority
of
Large
SI
engines
as
fork
lifts
and
constantspeed
engines
represent
about
90
percent
of
the
Large
SI
market.
Emissions
measured
during
this
segment
are
averaged
over
the
entire
transient
segment
to
give
a
single
value
in
g/
kW.
Steady
state
testing
consists
of
engine
operation
for
an
extended
period
at
several
discrete
speed
load
combinations.
Associated
with
these
test
points
are
weighting
factors
that
allow
a
single
weighted
average
steadystate
emission
level
in
g/
kW.
While
any
steady
state
duty
cycle
is
limited
in
how
much
it
can
represent
operation
of
engines
that
undergo
transient
operation,
the
distribution
of
the
C2
modes
and
their
weighting
values
aligns
significantly
with
expected
and
measured
engine
operation
from
Large
SI
engines.
In
particular,
these
engines
are
generally
not
designed
to
operate
for
extended
periods
at
high
load,
rated
speed
conditions.
Field
measurement
of
engine
operation
shows,
however,
that
forklifts
operate
extensively
at
lower
speeds
than
those
included
in
the
C2
duty
cycle.
While
we
believe
the
test
points
of
the
C2
duty
cycle
are
representative
of
engine
operation
from
many
applications
of
Large
SI
engines,
supplementing
the
steady
state
testing
with
a
transient
duty
cycle
is
necessary
to
adequately
include
engine
operation
characteristic
of
what
occurs
in
the
field.
A
separate
transient
duty
cycle
applies
to
engines
that
are
certified
for
constant
speed
applications
only.
These
engines
maintain
a
constant
speed,
but
can
experience
widely
varying
loads.
The
transient
duty
cycle
for
these
engines
includes
20
minutes
of
engine
operation
based
on
the
way
engines
work
in
a
welder.
Note
that
manufacturers
selling
engines
for
both
constant
speed
and
variable
speed
applications
may
omit
the
constantspeed
transient
test,
since
that
type
of
operation
is
included
in
the
general
transient
test.
A
subset
of
constant
speed
engines
are
designed
to
operate
only
at
high
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2002
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Rules
and
Regulations
load.
To
address
the
operating
limitations
of
these
engines,
we
are
adopting
a
modified
steady
state
duty
cycle
if
the
manufacturer
provides
clear
evidence
showing
that
engines
rarely
operate
below
75
percent
of
full
load
at
rated
speed.
Since
most
Large
SI
engines
are
clearly
capable
of
operating
for
extended
periods
at
light
loads,
we
expect
these
provisions
to
apply
to
very
few
engines.
This
modified
duty
cycle
consists
of
two
equally
weighted
points,
75
percent
and
100
percent
of
full
load,
at
rated
speed.
Since
the
transient
cycle
described
above
involves
extensive
light
load
operation,
engines
qualifying
for
this
high
load
duty
cycle
would
not
need
to
measure
emissions
over
the
transient
cycle.
Note
that
the
fieldtesting
emission
standards
still
apply
to
engines
that
don't
certify
to
transient
duty
cycle
standards.
Some
diesel
derived
engines
operating
on
natural
gas
with
power
ratings
up
to
1,500
or
2,000
kW
may
be
covered
by
these
emission
standards.
Engine
dynamometers
with
transientcontrol
capabilities
are
generally
limited
to
testing
engines
up
to
500
or
600
kW.
At
this
time
emission
standards
and
testing
requirements
related
to
transient
duty
cycles
will
not
apply
for
engines
rated
above
560
kW.
We
will
likely
review
this
provision
for
Large
SI
engines
once
we
have
reached
a
conclusion
on
the
same
issue
for
nonroad
diesel
engines.
For
example,
if
we
propose
provisions
for
nonroad
diesel
engines
that
address
testing
issues
for
these
very
large
engines,
we
would
likely
propose
those
same
provisions
for
Large
SI
engines.
Test
procedures
related
to
evaporative
emissions
are
described
in
Section
V.
C.
4
above.
In
general,
this
involves
measuring
evaporative
losses
during
a
three
day
period
of
cycling
ambient
temperatures
between
72
°
and
96
°
F.
2.
What
Fuels
Are
Used
During
Emission
Testing?
For
gasoline
fueled
Large
SI
engines,
we
are
adopting
the
same
specifications
we
have
established
for
testing
gasolinefueled
highway
vehicles
and
engines.
This
includes
the
revised
specification
to
cap
sulfur
levels
at
80
ppm
(
65
FR
6698,
February
10,
2000).
These
fuel
specifications
apply
for
both
exhaust
and
evaporative
emissions.
For
LPG,
we
are
adopting
the
same
specifications
established
by
California
ARB.
We
understand
that
in
use
fuel
quality
for
LPG
varies
significantly
in
different
parts
of
the
country
and
at
different
times
of
the
year.
Not
all
in
use
fuels
outside
California
meet
California
ARB
specifications
for
certification
fuel,
but
fuels
meeting
the
California
specifications
are
nevertheless
widely
available.
Test
data
show
that
LPG
fuels
with
a
much
lower
propane
content
have
only
slightly
higher
NOX
and
CO
emissions
(
see
Chapter
4
of
the
Final
Regulatory
Support
Document
for
additional
information).
These
data
support
our
belief
that
engines
certified
using
the
specified
fuel
will
achieve
the
desired
emission
reduction
for
a
wide
range
of
in
use
fuels.
At
certification
manufacturers
provide
deterioration
factors
that
take
into
account
any
effects
related
to
the
varying
quality
of
commercially
available
fuels.
For
natural
gas,
we
are
adopting
specifications
similar
to
those
adopted
by
California
ARB.
As
described
in
the
Summary
and
Analysis
of
Comments,
we
have
adjusted
some
of
the
detailed
specifications
from
the
proposal
to
reflect
new
data
submitted
after
the
proposal
regarding
ranges
of
fuel
properties
reflecting
current
commercial
fuels.
Unlike
California
ARB,
we
apply
the
fuel
specifications
to
testing
only
for
emission
measurements,
not
to
service
accumulation.
Service
accumulation
between
emission
tests
may
involve
certification
fuel
or
any
commercially
available
fuel
of
the
appropriate
type.
We
similarly
allow
manufacturers
to
choose
between
certification
fuel
and
any
commercial
fuel
for
in
use
measurements
to
show
compliance
with
field
testing
emission
standards.
Since
publishing
the
proposal,
we
learned
about
issues
related
to
Large
SI
engines
that
operate
around
landfills
or
oil
wells,
where
engines
may
burn
naturally
occurring
gases
that
are
otherwise
emitted
to
the
atmosphere.
These
gases
generally
consist
of
methane,
but
a
wide
range
of
other
constituents
may
also
be
mixed
in.
As
a
result,
engines
may
require
adjustment
over
a
wide
range
of
settings
for
spark
timing
and
air
fuel
ratio
to
maintain
consistent
combustion.
We
generally
believe
that
engine
manufacturers
should
design
their
engines
to
operate
with
automatic
feedback
controls
as
much
as
possible
to
avoid
the
need
for
operators
to
manually
adjust
engines.
However,
in
cases
involving
these
noncommercial
fuels,
there
is
no
way
to
improve
the
quality
of
the
fuel
to
conform
to
any
standardized
specifications.
Also,
it
is
clearly
preferred
to
capture
and
burn
these
gases
than
to
emit
them
directly
to
the
atmosphere,
both
to
prevent
greenhouse
gas
emissions
and
to
avoid
wasting
this
source
of
fuel.
To
address
this
concern,
we
are
adopting
special
provisions
for
engines
burning
noncommercial
fuels
if
they
are
unable
to
meet
emission
standards
over
the
full
range
of
adjustability
needed
to
accommodate
the
varying
fuel
properties.
Manufacturers
would
show
that
these
engines
can
meet
emission
standards
using
normal
certification
fuels,
but
the
normal
provisions
related
to
adjustable
parameters
would
not
apply.
To
properly
constrain
this
provision,
we
are
including
four
requirements.
First,
manufacturers
would
need
to
add
information
on
an
engine
label
instructing
operators
how
to
make
adjustments
that
would
allow
for
maintained
emission
control
and
overall
engine
performance.
Second,
manufacturers
would
include
additional
label
language
to
warn
operators
that
the
engine
may
be
used
only
in
applications
involving
noncommercial
fuels.
Third,
manufacturers
must
separate
these
engines
into
a
distinct
engine
family.
Fourth,
manufacturers
must
keep
a
record
of
individual
sales
of
such
engines.
3.
Are
There
Production
Line
Testing
Provisions
for
Large
SI
Engines?
The
provisions
described
in
Section
II.
C.
4
apply
to
Large
SI
engines.
These
requirements
are
consistent
with
those
adopted
by
California
ARB.
One
new
issue
specific
to
Large
SI
engines
relates
to
the
duty
cycles
for
measuring
emissions
from
production
line
engines.
For
routine
production
line
testing,
we
require
emission
measurements
only
with
the
steady
state
duty
cycles
used
for
certification.
Due
to
the
cost
of
sampling
equipment
for
transient
engine
operation,
we
do
not
require
routine
transient
testing
of
production
line
engines.
Transient
testing
of
productionline
engines
would
add
a
substantial
burden,
since
many
manufacturers
have
limited
emission
sampling
capability
at
production
facilities;
also,
these
production
facilities
might
be
located
at
multiple
sites.
We
believe
that
steadystate
emission
measurements
will
give
a
good
indication
of
the
manufacturers'
ability
to
build
engines
consistent
with
the
prototypes
on
which
their
certification
data
are
based.
We
reserve
the
right,
however,
to
direct
a
manufacturer
to
measure
emissions
with
a
transient
duty
cycle
if
we
believe
it
is
appropriate.
One
indication
of
the
need
for
this
transient
testing
would
be
if
steady
state
emission
levels
from
production
line
engines
are
significantly
higher
than
the
emission
levels
reported
in
the
application
for
certification
for
that
engine
family.
For
manufacturers
with
the
capability
of
measuring
transient
emission
levels
at
the
production
line,
we
recommend
doing
transient
tests
to
better
ensure
that
inuse
tests
will
not
reveal
problems
in
controlling
emissions
during
transient
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8,
2002
/
Rules
and
Regulations
operation.
Manufacturers
need
not
make
any
measurements
to
show
that
production
line
engines
meet
fieldtesting
emission
standards.
We
expect
manufacturers
generally
to
certify
their
engines
to
the
evaporative
requirements
using
a
design
based
approach.
Accordingly,
the
technologies
we
expect
manufacturers
to
use
for
controlling
evaporative
emissions
are
not
subject
to
variation
as
a
result
of
production
procedures,
so
we
are
not
requiring
production
line
testing
related
to
the
evaporative
requirements.
4.
Are
There
In
Use
Testing
Provisions
for
Large
SI
Engines?
While
the
certification
and
production
line
compliance
requirements
are
important
to
ensure
that
engines
are
designed
and
produced
in
compliance
with
established
emission
limits,
there
is
also
a
need
to
confirm
that
manufacturers
build
engines
with
sufficient
durability
to
meet
emission
limits
as
they
age
in
service.
Consistent
with
the
California
ARB
program,
we
are
requiring
engine
manufacturers
to
conduct
emission
tests
on
a
small
number
of
field
aged
engines
to
show
they
meet
emission
standards.
We
may
generally
select
up
to
25
percent
of
a
manufacturer's
engine
families
in
a
given
year
to
be
subject
to
in
use
testing.
Most
companies
will
need
to
test
at
most
one
engine
family
per
year.
Manufacturers
may
conduct
in
use
testing
on
any
number
of
additional
engine
families
at
their
discretion.
Manufacturers
in
unusual
circumstances
may
develop
an
alternate
plan
to
fulfill
any
in
use
testing
obligations,
consistent
with
a
similar
program
we
have
adopted
for
outboard
and
personal
watercraft
marine
engines.
These
circumstances
include
total
sales
for
an
engine
family
below
200
per
year,
installation
only
in
applications
where
testing
is
not
possible
without
irreparable
damage
to
the
vehicle
or
engine,
or
any
other
unique
feature
that
prevents
full
emission
measurements.
While
the
regulations
allow
us
to
select
an
engine
family
every
year
from
an
engine
manufacturer,
there
are
several
reasons
why
small
volume
manufacturers
may
expect
a
less
demanding
approach.
These
manufacturers
may
have
only
one
or
two
engine
families.
If
a
manufacturer
shows
that
an
engine
family
meets
emission
standards
in
an
in
use
testing
exercise,
that
may
provide
adequate
data
to
show
compliance
for
that
engine
family
for
a
number
of
years,
provided
that
the
manufacturer
continues
to
produce
those
engines
without
significantly
redesigning
them
in
a
way
that
might
affect
their
in
use
emissions
performance
and
that
we
do
not
have
other
reason
to
suspect
noncompliance.
Also,
where
we
have
evidence
that
a
manufacturer's
engines
are
likely
in
good
in
use
compliance,
we
generally
take
the
approach
of
selecting
engine
families
based
on
some
degree
of
proportionality.
To
the
extent
that
manufacturers
produce
a
smaller
than
average
proportion
of
engines,
they
may
expect
us
to
select
their
engine
families
less
frequently,
especially
if
other
available
data
pointed
toward
in
use
compliance.
In
addition,
our
experience
in
implementing
a
comparable
testing
program
for
recreational
marine
engines
provides
a
history
of
how
we
implement
in
use
testing
requirements.
Engines
can
be
tested
one
of
two
ways.
First,
manufacturers
can
remove
engines
from
vehicles
or
equipment
and
test
the
engines
on
a
laboratory
dynamometer
using
certification
procedures.
For
2004
through
2006
model
year
engines,
this
is
the
same
steady
state
duty
cycle
used
for
certification;
manufacturers
may
optionally
test
engines
on
the
dynamometer
under
transient
operating
conditions.
For
2007
and
later
model
year
engines,
manufacturers
must
test
engines
using
both
steady
state
and
transient
duty
cycles,
as
in
certification.
As
an
alternative,
manufacturers
may
use
the
specified
equipment
and
procedures
for
testing
engines
without
removing
them
from
the
equipment
(
referred
to
in
this
document
as
field
testing).
See
Section
V.
D.
5
for
a
more
detailed
description
of
how
to
measure
emissions
from
engines
during
normal
operation
in
the
field.
Since
engines
operating
in
the
field
cannot
be
controlled
to
operate
on
a
specific
duty
cycle,
compliance
is
demonstrated
by
comparing
the
measured
emission
levels
to
the
field
testing
emission
standards,
which
have
higher
numerical
value
to
account
for
the
possible
effects
of
different
engine
operation.
Because
the
engine
operation
can
be
so
variable,
however,
engines
tested
to
show
compliance
only
with
the
field
testing
emission
standards
are
not
eligible
to
participate
in
the
in
use
averaging,
banking,
and
trading
program
(
described
below).
Clean
Air
Act
section
213
requires
engines
to
comply
with
emission
standards
throughout
their
regulatory
useful
lives,
and
section
207
requires
a
manufacturer
to
remedy
in
use
nonconformity
when
we
determine
that
a
substantial
number
of
properly
maintained
and
used
engines
fail
to
conform
with
the
applicable
emission
standards
(
42
U.
S.
C.
7541).
Along
with
the
in
use
testing
program,
we
would
allow
manufacturers
to
demonstrate
that
they
have
designed
their
engines
to
control
emissions
substantially
below
the
emission
standards
that
apply.
If
manufacturers
are
able
to
show
that
they
have
already
been
reducing
emissions
more
than
required
by
the
standards,
including
appropriate
consideration
for
deterioration
and
compliance
margins,
this
may
allow
us
to
conclude
that
these
accumulated
additional
emission
reductions
are
sufficient
to
offset
the
high
emissions
from
a
failing
engine
family.
In
concept,
this
approach
serves
much
like
a
banking
program
to
recognize
manufacturers'
efforts
to
go
beyond
the
minimum
required
emission
reductions.
This
approach
differs
from
the
specific
in
use
emission
credit
program
that
we
proposed.
This
more
general
approach
is
preferred
for
two
primary
reasons.
First,
while
we
proposed
to
limit
the
in
use
emission
credit
program
to
transient
testing
in
the
laboratory,
manufacturers
will
now
be
able
to
use
emission
data
generated
from
field
testing
to
characterize
an
engine
family's
average
emission
level.
This
becomes
necessarily
more
subjective,
but
allows
us
to
consider
a
wider
range
of
information
in
evaluating
the
degree
to
which
manufacturers
are
complying
with
emission
standards
across
their
product
line.
Second,
this
approach
makes
clearer
the
role
of
the
emission
credits
in
our
consideration
to
recall
failing
engines.
As
we
described
in
the
proposal,
we
plan
to
consider
average
emission
levels
from
multiple
engine
families
in
deciding
whether
to
recall
engines
from
a
failing
engine
family.
We
therefore
believe
it
is
not
appropriate
to
have
a
detailed
emission
credit
program
defining
precisely
how
and
when
to
calculate,
generate,
and
use
credits
that
do
not
necessarily
have
value
elsewhere.
The
regulations
do
not
specify
how
manufacturers
would
generate
emission
credits
to
offset
a
nonconforming
engine
family.
This
gives
us
the
ability
to
consider
any
appropriate
test
data
in
deciding
what
action
to
take.
In
generating
this
kind
of
information,
some
general
guidelines
would
apply.
For
example,
we
would
expect
manufacturers
to
share
test
data
from
all
engines
and
all
engine
families
tested
under
the
in
use
testing
program,
including
nonstandard
tests
that
might
be
used
to
screen
engines
for
later
measurement.
This
allows
us
to
understand
the
manufacturers'
overall
level
of
performance
in
controlling
emissions
to
meet
emission
standards.
Average
emission
levels
should
be
calculated
over
a
running
three
year
period
to
include
a
broad
range
of
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217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
testing
without
skewing
the
results
based
on
old
designs.
Emission
values
from
engines
certified
to
different
tiers
of
emission
standards
or
tested
using
different
measurement
procedures
should
not
be
combined
to
calculate
a
single
average
emission
level.
Average
emission
levels
should
be
calculated
according
to
the
following
equation,
rounding
the
results
to
0.1
g/
kW
hr:
Average
EL
(
STD
CL)
(
UL)
(
Sales)
Power
LF
(
UL)
(
Sales)
Power
LF
i
i
i
i
i
i
i
i
i
i
i
=
×
×
×
×
÷
×
×
×
Where:
Average
EL=
Average
emission
level
in
g/
kW
hr.
Salesi=
The
number
of
eligible
sales,
tracked
to
the
point
of
first
retail
sale
in
the
U.
S.,
for
the
given
engine
family
during
the
model
year.
i(
STD
CL)=
The
difference
between
the
emission
standard
and
the
average
emission
level
for
an
in
use
testing
family
in
g/
kW
hr.
ULi=
Useful
life
in
hours.
Poweri=
The
sales
weighted
average
rated
brake
power
for
an
engine
family
in
kW.
LFi=
Load
factor
or
fraction
of
rated
engine
power
utilized
in
use;
use
0.50
for
engine
families
used
only
in
constant
speed
applications
and
0.32
for
all
other
engine
families.
The
anticipated
crankcase
and
evaporative
emission
control
technologies
generally
are
best
evaluated
simply
by
checking
whether
or
not
they
continue
to
function
as
designed,
rather
than
implementing
a
program
to
measure
these
emissions
from
in
use
engines.
As
a
result,
we
may
inspect
in
use
engines
to
verify
that
these
systems
continue
to
function
properly
throughout
the
useful
life,
but
are
not
requiring
manufacturers
to
include
crankcase
or
evaporative
measurements
as
part
of
the
in
use
testing
program
described
in
this
section.
5.
What
Are
the
Field
Testing
Emission
Standards
and
Test
Procedures?
To
address
concerns
for
controlling
emissions
outside
of
the
certification
duty
cycles
and
to
enable
field
testing
of
Large
SI
engines,
we
are
adopting
procedures
and
standards
that
apply
to
a
wider
range
of
normal
engine
operation.
a.
What
is
the
field
testing
concept?
Measuring
emissions
from
engines
in
the
field
as
they
undergo
normal
operation
while
installed
in
nonroad
equipment
addresses
two
broad
concerns.
First,
testing
of
in
use
engines
has
shown
that
emissions
can
vary
dramatically
under
certain
modes
of
operation.
Second,
this
provides
a
low
cost
method
of
testing
in
use
engines,
which
facilitates
in
use
compliance
programs.
Field
testing
addresses
this
by
including
emission
measurements
over
the
broad
range
of
normal
engine
operation.
This
may
include
varying
engine
speeds
and
loads
according
to
real
operation
and
may
include
a
reasonable
range
of
ambient
conditions,
as
described
below.
No
engine
operating
in
the
field
can
follow
a
prescribed
duty
cycle
for
a
consistent
measure
of
emission
levels.
Similarly,
no
single
test
procedure
can
cover
all
real
world
applications,
operations,
or
conditions.
Specifying
parameters
for
testing
engines
in
the
field
and
adopting
an
associated
emission
standard
provides
a
framework
for
requiring
that
engines
control
emissions
under
the
whole
range
of
normal
operation
in
the
relevant
nonroad
equipment.
To
ensure
that
emissions
are
controlled
from
Large
SI
engines
over
the
full
range
of
speed
and
load
combinations
seen
in
the
field,
we
are
adopting
supplemental
emission
standards
that
apply
more
broadly
than
the
duty
cycle
standard,
as
detailed
below.
These
standards
apply
to
all
regulated
pollutants
(
NOX,
HC,
and
CO)
under
all
normal
operation
(
steady
state
or
transient).
We
exclude
abnormal
operation
(
such
as
very
low
average
power
and
extended
idling
time),
but
do
not
restrict
operation
to
any
specific
combination
of
speeds
and
loads.
In
addition,
the
field
testing
standards
apply
under
a
broad
range
of
in
use
ambient
conditions,
both
to
ensure
robust
emission
controls
and
to
avoid
overly
restricting
the
times
available
for
testing.
These
provisions
are
described
in
detail
below.
b.
How
do
the
field
testing
standards
apply?
Manufacturers
have
expressed
an
interest
in
using
field
testing
procedures
before
the
2007
model
year
to
show
that
they
can
meet
emission
standards
as
part
of
the
in
use
testing
program.
While
we
are
not
adopting
specific
fieldtesting
standards
for
2004
through
2006
model
year
engines,
we
will
allow
this
as
an
option.
In
this
case,
manufacturers
would
conduct
the
field
testing
as
described
here
to
show
that
their
engines
meet
the
5.4
g/
kW
hr
HC+
NOX
standard
and
the
50
g/
kW
hr
CO
standard.
This
may
give
manufacturers
the
opportunity
to
do
testing
at
significantly
lower
cost
compared
with
laboratory
testing.
Preliminary
certification
data
from
California
ARB
show
that
manufacturers
are
reaching
steady
state
emission
levels
well
below
emission
standards,
so
we
expect
any
additional
variability
in
field
testing
measurements
not
to
affect
manufacturers'
ability
to
meet
the
same
emission
standards.
The
2007
field
testing
standards
are
based
on
emission
data
measured
on
engines
with
the
same
emission
control
technology
used
to
establish
the
dutycycle
standards.
As
described
above
for
the
duty
cycle
standards,
we
are
adopting
a
flexible
approach
to
address
the
tradeoff
between
HC+
NOX
and
CO
emissions.
Table
V.
D
1
shows
the
range
of
values
that
define
the
standard
for
showing
compliance
for
field
testing
measurements.
The
higher
numerical
values
of
the
Tier
2
standards
for
field
testing
(
compared
with
duty
cycle
testing)
reflect
the
observed
variation
in
emissions
for
varying
engine
operation,
and
the
projected
effects
of
ambient
conditions
on
the
projected
technology.
Conceptually,
we
believe
that
fieldtesting
standards
should
primarily
require
manufacturers
to
adjust
engine
calibrations
to
effectively
manage
airfuel
ratios
under
varying
conditions.
The
estimated
cost
of
complying
with
emission
standards
includes
an
allowance
for
the
time
and
resources
needed
for
this
recalibration
effort
(
see
Section
IX.
B.
for
total
estimated
costs
per
engine).
TABLE
V.
D
1.
SAMPLES
OF
POSSIBLE
ALTERNATIVE
FIELD
TESTING
EMISSION
STANDARDS
FOR
LARGE
SI
ENGINES(
G/
KW
HR)
*
HC+
NOX
CO
3.8
...............................................
6.5
3.1
...............................................
8.5
2.4
...............................................
11.7
1.8
...............................................
16.8
1.4
...............................................
23.1
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Regulations
TABLE
V.
D
1.
SAMPLES
OF
POSSIBLE
ALTERNATIVE
FIELD
TESTING
EMISSION
STANDARDS
FOR
LARGE
SI
ENGINES(
G/
KW
HR)
*
Continued
HC+
NOX
CO
1.1
...............................................
31
*
As
described
in
the
Final
Regulatory
Support
Document
and
the
regulations,
the
values
in
the
table
are
related
by
the
following
formula
(
HC+
NOX)
×
CO0.791
=
16.78.
These
values
follow
directly
from
the
logarithmic
relationship
presented
with
the
proposal
in
the
Draft
Regulatory
Impact
Analysis.
We
generally
require
manufacturers
to
show
at
certification
that
they
are
capable
of
meeting
all
standards
that
apply
for
the
useful
life.
This
adds
a
measure
of
assurance
to
both
EPA
and
manufacturers
that
the
engine
design
is
sufficient
for
any
in
use
engines
to
pass
any
later
testing.
For
Large
SI
engines,
manufacturers
must
show
in
their
application
for
certification
that
they
are
able
to
meet
the
field
testing
standards.
Manufacturers
must
submit
a
statement
that
their
engines
will
comply
with
field
testing
emission
standards
under
all
conditions
that
may
reasonably
be
expected
to
occur
in
normal
vehicle
operation
and
use.
Manufacturer
will
provide
a
detailed
description
of
any
testing,
engineering
analysis,
and
other
information
that
forms
the
basis
for
the
statement.
This
will
likely
include
a
variety
of
steady
state
emission
measurements
not
included
in
the
prescribed
duty
cycle.
It
may
also
include
a
continuous
trace
showing
how
emissions
vary
during
the
transient
test
or
it
may
include
emission
measurements
during
other
segments
of
operation
manufacturers
believe
are
representative
of
the
way
their
engines
normally
operate
in
the
field.
Two
additional
provisions
are
necessary
to
allow
emission
testing
without
removing
engines
from
equipment
in
the
field.
Manufacturers
must
design
their
engines
to
broadcast
instantaneous
speed
and
torque
values
to
the
onboard
computer
and
ensure
that
emission
sampling
is
possible
after
engine
installation.
The
test
equipment
and
procedures
for
showing
compliance
with
fieldtesting
standards
also
hold
promise
to
reduce
the
cost
of
production
line
testing.
Companies
with
production
facilities
that
have
a
dynamometer
but
no
emission
measurement
capability
may
use
the
field
testing
equipment
and
procedures
to
get
a
low
cost,
valid
emission
measurement
at
the
production
line.
Manufacturers
may
also
choose
to
use
the
cost
advantage
of
the
simpler
measurement
to
sample
a
greater
number
of
production
line
engines.
This
would
provide
greater
assurance
of
consistent
emissions
performance,
but
would
also
provide
valuable
quality
control
data
for
overall
engine
performance.
See
the
discussion
of
alternate
approaches
to
productionline
testing
in
Section
II.
C.
4
for
more
information.
c.
What
limits
are
placed
on
field
testing?
The
field
testing
standards
apply
to
all
normal
operation.
This
may
include
steady
state
or
transient
engine
operation.
Given
a
set
of
field
testing
standards,
the
goal
for
the
design
engineer
is
to
ensure
that
engines
are
properly
calibrated
for
controlling
emissions
under
any
reasonably
expected
mode
of
engine
operation.
Engines
may
not
be
able
to
meet
the
emissions
limit
under
all
conditions,
however,
so
we
are
adopting
several
parameters
to
narrow
the
range
of
engine
operation
that
is
subject
to
the
field
testing
standards.
For
example,
emission
sampling
for
field
testing
does
not
include
engine
starting.
Engines
can
often
operate
at
extreme
environmental
and
geographic
conditions
(
temperature,
altitude,
etc.).
To
narrow
the
range
of
conditions
for
the
design
engineer,
we
are
limiting
emission
measurements
during
field
testing
to
ambient
temperatures
from
13
°
to
35
°
C
(
55
°
to
95
°
F),
and
to
ambient
pressures
from
600
to
775
millimeters
of
mercury
(
which
should
cover
almost
all
normal
pressures
from
sea
level
to
7,000
feet
above
sea
level).
This
allows
testing
under
a
wider
range
of
conditions
in
addition
to
helping
ensure
that
engines
are
able
to
control
emissions
under
the
whole
range
of
conditions
under
which
they
operate.
Some
additional
limits
to
define
``
normal''
operation
apply
to
field
testing.
These
restrictions
are
intended
to
provide
manufacturers
with
some
certainty
about
what
their
design
targets
are
and
to
ensure
that
compliance
with
the
field
testing
standards
is
feasible.
These
restrictions
apply
to
both
variable
speed
and
constant
speed
engine
applications.
First,
measurements
with
more
than
2
minutes
of
continuous
idle
are
excluded.
This
means
that
an
emission
measurement
from
a
forklift
while
it
idled
for
5
minutes
will
not
be
considered
valid.
On
the
other
hand,
an
emission
measurement
from
a
forklift
that
idled
for
multiple
1
minute
periods
and
otherwise
operated
at
40
percent
power
for
several
minutes
would
be
considered
a
valid
measurement.
Measurements
with
in
use
equipment
in
their
normal
service
show
that
idle
periods
for
Large
SI
engines
are
short,
but
relatively
frequent.
We
therefore
do
not
automatically
exclude
an
emission
sample
if
it
includes
an
idling
portion.
At
the
same
time,
controlling
emissions
during
extended
idling
poses
a
difficult
design
challenge,
especially
at
low
ambient
temperatures.
Exhaust
and
catalyst
temperatures
under
these
conditions
can
decrease
enough
that
catalyst
conversion
is
significantly
less
effective.
Since
extended
idling
is
not
an
appropriate
focus
of
extensive
development
efforts
at
this
stage,
we
believe
the
2
minute
threshold
for
continuous
idle
appropriately
balances
the
need
to
include
measurement
during
short
idling
periods
with
the
technical
challenges
of
controlling
emissions
under
difficult
conditions.
Second,
measured
power
during
the
sampling
period
must
be
above
5
percent
of
maximum
power
for
an
emission
measurement
to
be
considered
valid.
Brake
specific
emissions
(
g/
kWhr
can
be
very
high
at
low
power
because
they
are
calculated
by
dividing
the
g/
hr
emission
rate
by
a
very
small
power
level
(
kW).
By
ensuring
that
brake
specific
emissions
are
not
calculated
by
dividing
by
power
levels
less
than
5
percent
of
the
maximum,
we
can
avoid
this
problem.
The
data
presented
in
Chapter
4
of
the
Final
Regulator
Support
Document
show
that
engines
can
meet
the
emission
standards
when
operating
above
5
percent
of
rated
power.
Third,
some
engines
need
to
run
rich
of
stoichiometric
combustion
during
extended
high
load
operation
to
protect
against
engine
failure.
This
increases
HC
and
CO
emissions.
We
are
adopting
provisions
allowing
manufacturers
to
meet
separate
standards
for
these
engines
for
steady
state
operation.
For
engines
qualifying
for
these
different
steady
state
standards,
we
specify
that
a
valid
sample
for
field
testing
must
include
less
than
10
percent
of
operation
at
90
percent
or
more
of
maximum
power.
We
expect
it
to
be
uncommon
for
engine
installations
to
call
for
such
high
power
demand
due
to
the
shortened
engine
lifetime
at
very
high
load
operation.
A
larger
engine
can
generally
produce
the
desired
power
at
a
lower
relative
load,
without
compromising
engine
lifetime.
Alternatively,
applications
that
call
for
full
load
operation
typically
use
diesel
engines.
Manufacturers
may
request
a
different
threshold
to
allow
more
openloop
operation.
Before
we
approve
such
a
request,
the
engine
manufacturer
would
need
to
have
a
plan
for
ensuring
that
the
engines
in
their
final
installation
do
not
routinely
operate
at
loads
above
the
specified
threshold.
An
additional
parameter
to
consider
is
the
minimum
sampling
time
for
field
testing.
A
longer
period
allows
for
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Regulations
greater
accuracy,
due
mainly
to
the
smoothing
effect
of
measuring
over
several
transient
events.
On
the
other
hand,
an
overly
long
sampling
period
can
mask
areas
of
engine
operation
with
poor
emission
control
characteristics.
To
balance
these
concerns,
we
are
applying
a
minimum
sampling
period
of
2
minutes.
In
other
rules
for
diesel
engines,
we
have
allowed
sampling
periods
as
short
as
30
seconds.
Sparkignition
engines
generally
don't
have
turbochargers
and
they
control
emissions
by
maintaining
air
fuel
ratio
with
closed
loop
controls
through
changing
engine
operation.
Sparkignition
engines
are
therefore
much
less
prone
to
consistent
emission
spikes
from
off
cycle
or
unusual
engine
operation.
We
believe
the
2
minute
sampling
time
requirement
will
ensure
sufficient
measurement
accuracy
and
will
allow
for
more
meaningful
measurements
from
engines
that
may
be
operated
with
very
frequent
but
brief
times
at
idle.
We
do
not
specify
a
maximum
sampling
time.
We
expect
manufacturers
testing
in
use
engines
to
select
an
approximate
sampling
time
before
measuring
emissions;
however,
the
standards
apply
for
any
sampling
time
that
meets
the
minimum.
When
selecting
an
engine
family
for
the
in
use
testing
program,
we
will
develop
a
plan
with
direction
related
to
the
way
manufacturers
conduct
the
emissionsampling
effort,
such
as
sampling
time
or
specific
types
of
engine
operation,
to
ensure
that
testing
provides
relevant
data.
d.
How
do
I
test
engines
in
the
field?
To
test
engines
without
removing
them
from
equipment,
analyzers
are
connected
to
the
engine's
exhaust
to
detect
emission
concentrations
during
normal
operation.
Exhaust
volumetric
flow
rate
and
continuous
power
output
are
also
needed
to
convert
the
analyzer
responses
to
units
of
g/
kW
hr
for
comparing
to
emission
standards.
These
values
can
be
calculated
from
measurements
of
the
engine
intake
flow
rate,
the
exhaust
air
fuel
ratio
and
the
engine
speed,
and
from
torque
information.
Available
small
analyzers
and
other
equipment
may
be
adapted
for
measuring
emissions
from
field
equipment.
A
portable
flame
ionization
detector
can
measure
total
hydrocarbon
concentrations.
Methane
measurement
currently
requires
more
expensive
laboratory
equipment
that
is
impractical
for
field
measurements.
Field
testing
standards
are
therefore
be
based
on
total
hydrocarbon
emissions.
A
portable
analyzer
based
on
zirconia
technology
measures
NOX
emissions.
A
nondispersive
infrared
(
NDIR)
unit
can
measure
CO.
Emission
samples
can
best
be
drawn
from
the
exhaust
flow
directly
downstream
of
the
catalyst
material
to
avoid
diluting
effects
from
the
end
of
the
tailpipe.
Installing
a
sufficiently
long
tailpipe
extension
is
also
an
acceptable
way
to
avoid
dilution.
Mass
flow
rates
also
factor
into
the
torque
calculation;
this
may
either
be
measured
in
the
intake
manifold
or
downstream
of
the
catalyst.
Calculating
brake
specific
emissions
depends
on
determining
instantaneous
engine
speed
and
torque
levels.
Manufacturers
must
therefore
design
their
engines
to
continuously
monitor
engine
speed
and
torque.
The
tolerance
for
speed
measurements,
which
is
relatively
straightforward,
is
±
5
percent.
For
torque,
the
onboard
computer
needs
to
convert
measured
engine
parameters
into
useful
units.
Manufacturers
generally
will
need
to
monitor
a
surrogate
value
such
as
intake
manifold
pressure
or
throttle
position
(
or
both),
then
rely
on
a
look
up
table
programmed
into
the
onboard
computer
to
convert
these
torque
indicators
into
newton
meters.
Manufacturers
may
also
want
to
program
the
look
up
tables
for
torque
conversion
into
a
remote
scan
tool.
Because
of
the
greater
uncertainty
in
these
measurements
and
calculations,
manufacturers
must
produce
their
systems
to
report
torque
values
that
are
within
85
and
105
percent
of
the
true
value.
This
broader
range
allows
appropriately
for
the
uncertainty
in
the
measurement,
while
providing
an
incentive
for
manufacturers
to
make
the
torque
reading
as
accurate
as
possible.
Under
reporting
torque
values
would
over
predict
emissions.
These
tolerances
are
taken
into
account
in
the
selection
of
the
field
testing
standards,
as
described
in
Chapter
4
of
the
Final
Regulatory
Support
Document.
E.
Special
Compliance
Provisions
We
are
adopting
hardship
provisions
to
address
the
particular
concerns
of
small
volume
manufacturers,
which
generally
have
limited
capital
and
engineering
resources.
These
hardship
provisions
are
generally
described
in
Section
VII.
C.
For
Large
SI
engines,
we
are
adopting
a
longer
available
extension
of
the
deadline,
up
to
four
years,
for
meeting
emission
standards
for
companies
that
qualify
for
special
treatment
under
the
hardship
provisions.
We
will,
however,
not
extend
the
deadline
for
compliance
beyond
the
four
year
period.
This
approach
considers
the
fact
that,
unlike
most
other
engine
categories,
qualifying
small
businesses
are
more
likely
to
be
manufacturers
designing
their
own
products.
Other
types
of
engines
more
often
involve
importers,
which
are
limited
more
by
available
engine
suppliers
than
design
or
development
schedules.
We
are
not
finalizing
the
proposed
interim
emission
standards
proposed
for
small
volume
manufacturers.
We
believe
we
can
accomplish
the
same
objectives
with
more
flexibility,
and
potentially
with
greater
net
emission
reductions,
by
relying
on
the
hardship
provisions.
In
addition,
we
are
waiving
the
requirement
for
small
volume
manufacturers
to
broadcast
engine
speed
and
torque
values.
These
companies
may
choose
to
do
this
to
enable
field
testing
of
their
products,
but
may
be
constrained
in
developing
this
capability
to
the
extent
that
they
rely
on
component
suppliers
to
provide
systems
that
meet
EPA
requirements.
F.
Technological
Feasibility
of
the
Standards
We
are
adopting
emission
standards
that
depend
on
the
industrial
versions
of
established
automotive
technologies.
The
most
recent
advances
in
automotive
technology
have
made
possible
even
more
dramatic
emission
reductions.
However,
we
believe
that
transferring
some
of
these
most
advanced
technologies
is
not
appropriate
for
nonroad
engines
at
this
time,
especially
considering
the
much
smaller
sales
volumes
for
amortizing
fixed
costs
and
the
additional
costs
associated
with
the
first
time
regulation
of
these
engines.
To
comply
with
the
2004
model
year
standards,
manufacturers
should
not
need
to
do
any
development,
testing,
or
certification
work
that
is
not
already
necessary
to
meet
California
ARB
standards
in
2004.
As
shown
in
Chapter
4
of
the
Final
Regulatory
Support
Document,
manufacturers
can
meet
these
standards
with
three
way
catalysts
and
closed
loop
fuel
systems.
These
technologies
have
been
available
for
industrial
engine
applications
for
several
years.
Moreover,
several
manufacturers
have
already
completed
the
testing
effort
to
certify
with
California
ARB
that
their
engines
meet
these
standards.
Complying
with
emission
standards
nationwide
in
2004
will
therefore
generally
require
manufacturers
only
to
produce
greater
numbers
of
the
engines
complying
with
the
California
standards.
Chapter
4
of
the
Final
Regulatory
Support
Document
further
describes
data
and
rationale
showing
why
we
believe
that
the
2007
model
year
emission
standards
under
the
steadystate
and
transient
duty
cycles
and
field
testing
procedures
are
feasible.
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and
Regulations
summary,
testing
from
Southwest
Research
Institute
and
other
data
show
that
the
same
catalyst
and
fuel
system
technologies
needed
to
meet
the
2004
standards
can
be
optimized
to
meet
more
stringent
emission
standards.
Applying
further
development
allows
the
design
engineer
to
fine
tune
control
of
air
fuel
ratios
and
address
any
highemission
modes
of
operation
to
produce
engines
that
consistently
control
emissions
to
very
low
levels,
even
considering
the
wide
range
of
operation
experienced
by
these
engines.
The
numerical
emission
standards
are
based
on
measured
emission
levels
from
engines
that
have
operated
for
at
least
5,000
hours
with
a
functioning
emission
control
system.
These
engines
demonstrate
the
achievable
level
of
control
from
catalyst
based
systems
and
provide
a
significant
degree
of
basic
development
that
should
help
manufacturers
in
optimizing
their
own
engines.
We
believe
it
is
appropriate
to
initiate
the
second
stage
of
standards
in
2007,
because
we
believe
that
applying
these
emission
standards
earlier
does
not
allow
manufacturers
enough
stability
between
introduction
of
different
phases
of
emission
standards
to
prepare
for
complying
with
the
full
set
of
requirements
in
this
final
rule
and
to
amortize
their
fixed
costs.
Three
years
of
stable
emission
standards,
plus
the
remaining
lead
time
before
2004,
allows
manufacturers
enough
time
to
go
through
the
development
and
certification
effort
to
comply
with
the
new
standards
including
new
test
cycle
requirements.
The
provisions
to
allow
``
family
banking''
for
early
compliance
provide
an
additional
tool
for
companies
that
choose
to
spread
out
their
design
and
certification
efforts.
The
new
emission
standards
will
either
have
no
impact
or
a
positive
impact
with
respect
to
noise,
energy,
and
safety,
as
described
in
Chapter
4
of
the
Final
Regulatory
Support
Document.
In
particular,
the
anticipated
fuel
savings
associated
with
the
expected
emission
control
technologies
will
provide
a
very
big
energy
benefit
related
to
new
emission
standards.
The
projected
technologies
are
currently
available
and
are
consistent
with
those
anticipated
for
complying
with
the
emission
standards
adopted
by
California
ARB.
The
lead
time
for
the
near
term
and
long
term
emission
standards
allows
manufacturers
enough
time
to
optimize
these
designs
to
most
effectively
reduce
emissions
from
the
wide
range
of
Large
SI
equipment
applications.
VI.
Recreational
Marine
Diesel
Engines
This
section
describes
the
new
provisions
for
40
CFR
part
94,
which
apply
to
engine
manufacturers
and
importers.
We
are
applying
the
same
general
compliance
provisions
from
40
CFR
part
94
for
engine
manufacturers,
equipment
manufacturers,
operators,
rebuilders,
and
others.
See
Section
II
for
a
description
of
our
general
approach
to
regulating
nonroad
engines
and
how
manufacturers
show
that
they
meet
emission
standards.
A.
Overview
We
are
adopting
exhaust
and
crankcase
emission
standards
for
recreational
marine
diesel
engines
with
power
ratings
greater
than
or
equal
to
37
kW.
We
are
adopting
emission
standards
for
HC,
NOX,
CO,
and
PM
beginning
in
2006.
We
believe
manufacturers
will
be
able
to
use
technology
developed
for
land
based
nonroad
and
commercial
marine
diesel
engines.
To
encourage
the
introduction
of
low
emission
technology,
we
are
also
adopting
voluntary
``
Blue
Sky''
standards
which
are
40
percent
lower
than
the
mandatory
standards.
We
also
recognize
that
there
are
many
small
businesses
that
manufacture
recreational
marine
diesel
engines.
We
are
therefore
including
several
regulatory
options
for
small
businesses
that
will
help
minimize
any
unique
burdens
caused
by
emission
regulations.
Diesel
engines
are
primarily
available
in
inboard
marine
configurations,
but
may
also
be
available
in
sterndrive
and
outboard
marine
configurations.
Inboard
diesel
engines
are
the
primary
choice
for
many
larger
recreational
boats.
B.
Engines
Covered
by
This
Rule
The
standards
in
this
section
apply
to
recreational
marine
diesel
engines.
We
excluded
these
engines
from
the
requirements
applying
to
commercial
marine
diesel
engines
because
at
the
time
we
thought
their
operation
in
planing
mode
might
impose
design
requirements
on
recreational
boat
builders
and
to
allow
us
more
time
for
further
evaluation
prior
to
setting
standards
(
64
FR
73300,
December
29,
1999).
Commercial
marine
vessels
tend
to
be
displacement
hull
vessels,
designed
and
built
for
a
unique
commercial
application
(
such
as
towing,
fishing,
or
general
cargo).
Power
ratings
for
engines
used
on
these
vessels
are
analogous
to
land
based
applications,
and
these
engines
generally
have
warranties
for
2,000
to
5,000
hours
of
use.
Recreational
vessels,
on
the
other
hand,
tend
to
be
planing
vessels.
Engines
used
on
these
vessels
are
designed
to
achieve
higher
power
output
with
less
engine
weight.
This
increase
in
power
reduces
the
lifetime
of
the
engine,
so
recreational
marine
engines
have
shorter
warranties
than
their
commercial
counterparts.
In
our
previous
rulemaking,
recreational
engine
industry
representatives
raised
concerns
about
the
ability
of
these
engines
to
meet
the
commercial
standards
without
substantial
changes
in
the
size
and
weight
of
the
engine.
Such
changes
may
have
an
impact
on
vessel
builders,
who
might
have
to
redesign
vessel
hulls
to
accommodate
the
new
engines.
Because
most
recreational
vessel
hulls
are
made
with
fiberglass
molds,
this
may
be
a
significant
burden
for
recreational
vessel
builders.
Our
further
evaluation
of
these
issues
leads
us
to
conclude
that
recreational
marine
diesel
engines
can
achieve
those
same
emission
standards
without
significant
impacts
on
engine
size
and
weight,
and
therefore
without
significant
impacts
on
vessel
design.
Section
VI.
G
of
this
document,
Chapters
3
and
4
of
the
Final
Regulatory
Support
Document,
and
Section
II.
A
of
the
Summary
and
Analysis
of
Comments
describe
the
several
technological
changes
we
anticipate
manufacturers
will
use
to
comply
with
the
new
emission
standards.
None
of
these
technologies
has
an
inherent
negative
effect
on
the
performance
or
power
density
of
an
engine.
As
with
engines
in
land
based
applications,
we
expect
that
manufacturers
will
be
able
to
use
the
range
of
technologies
available
to
maintain
or
even
improve
the
performance
capabilities
of
their
engines.
We
are
establishing
a
separate
regulatory
program
for
recreational
marine
diesel
engines
in
this
rule,
with
most
aspects
the
same
as
for
commercial
marine
diesel
engines
but
with
certain
aspects
of
the
program
tailored
to
these
applications,
notably
the
not
to
exceed
emissions
requirements.
To
distinguish
between
commercial
and
recreational
marine
diesel
engines
for
the
purpose
of
emission
controls,
it
is
necessary
to
define
``
recreational
marine
diesel
engine.''
The
commercial
marine
diesel
engine
rule
defined
recreational
marine
engine
as
a
propulsion
marine
engine
that
is
intended
by
the
manufacturer
to
be
installed
on
a
recreational
vessel.
The
engine
must
be
labeled
to
distinguish
it
from
a
commercial
marine
diesel
engine.
The
label
must
read:
``
THIS
ENGINE
IS
CATEGORIZED
AS
A
RECREATIONAL
ENGINE
UNDER
40
CFR
PART
94.
INSTALLATION
OF
THIS
ENGINE
IN
ANY
NONRECREATIONAL
VESSEL
IS
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Regulations
VIOLATION
OF
FEDERAL
LAW
SUBJECT
TO
PENALTY.''
We
are
revising
this
definition
to
include
a
requirement
that
a
recreational
marine
engine
must
be
a
Category
1
marine
engine
(
have
a
displacement
of
less
than
5
liters
per
cylinder).
Category
2
marine
engines
are
generally
designed
with
characteristics
similar
to
commercial
marine
engines.
Vessels
using
engines
of
this
size
generally
require
engines
that
can
operate
longer
at
higher
power
than
typical
recreational
boats;
therefore,
these
engines
generally
have
a
lower
power
density
and
are
not
offered
in
a
``
recreational''
rating.
For
the
purpose
of
the
recreational
marine
diesel
engine
definition
included
in
the
proposal,
recreational
vessel
was
defined
as
``
a
vessel
that
is
intended
by
the
vessel
manufacturer
to
be
operated
primarily
for
pleasure
or
leased,
rented,
or
chartered
to
another
for
the
latter's
pleasure.''
Because
certain
vessels
that
are
used
for
pleasure
may
have
operating
characteristics
that
are
more
similar
to
commercial
marine
vessels
(
such
as
excursion
vessels
and
charter
craft),
we
drew
on
the
Coast
Guard's
definition
of
a
``
small
passenger
vessel''
(
46
U.
S.
C.
2101
(
35))
to
further
delineate
what
would
be
considered
to
be
a
recreational
vessel.
Specifically,
the
term
``
operated
primarily
for
pleasure
or
leased,
rented
or
chartered
to
another
for
the
latter's
pleasure''
does
not
include
the
following
vessels:
(
1)
Vessels
of
less
than
100
gross
tons
that
carry
more
than
6
passengers;
(
2)
vessels
of
100
gross
tons
or
more
that
carry
one
or
more
passengers;
or
(
3)
vessels
used
solely
for
competition.
For
the
purposes
of
this
definition,
a
passenger
is
defined
by
46
U.
S.
C
2101
(
21,
21a)
which
generally
means
an
individual
who
pays
to
be
on
the
vessel.
We
received
several
comments
in
this
rulemaking
on
these
definitions.
Engine
manufacturers
were
concerned
that
the
definitions
may
be
unworkable
for
engine
manufacturers,
because
they
cannot
know
whether
a
particular
recreational
vessel
might
carry
more
than
six
passengers
at
a
time.
All
they
can
know
is
whether
the
engine
they
manufacture
is
intended
by
them
for
installation
on
a
vessel
designed
for
pleasure
and
having
the
corresponding
characteristics
for
planing,
power
density,
and
performance
requirements.
We
are
not
revising
our
existing
definition
of
recreational
marine
vessel.
As
discussed
in
the
Summary
and
Analysis
of
Comments,
a
vessel
will
be
considered
recreational
if
the
boat
builder
intends
that
the
customer
will
operate
it
consistent
with
the
recreational
vessel
definition.
Relying
on
the
boat
builder's
intent
is
necessary
because
manufacturers
need
to
establish
a
vessel's
classification
before
it
is
sold,
whereas
the
Coast
Guard
definitions
apply
at
the
time
of
use.
The
definition
therefore
relies
on
the
intent
of
the
boat
builder
to
establish
that
the
vessel
will
be
used
consistent
with
the
above
criteria.
If
a
boat
builder
manufactures
a
vessel
for
a
customer
who
intends
to
use
the
vessel
for
recreational
purposes,
we
would
always
consider
that
a
recreational
vessel,
regardless
of
how
the
owner
(
or
a
subsequent
owner)
actually
uses
it.
The
engine
manufacturer
will
not
be
expected
to
ensure
that
their
engines
are
used
only
in
recreational
craft;
however,
they
would
be
required
to
label
their
recreational
engines
as
described
above.
The
vessel
builders
will
then
be
required
to
install
properly
certified
recreational
(
or
commercial)
marine
engines
in
recreational
vessels
and
certified
commercial
marine
engines
in
commercial
vessels.
C.
Emission
Standards
for
Recreational
Marine
Diesel
Engines
This
section
describes
the
new
emission
standards
and
implementation
dates,
with
an
outline
of
the
technology
that
can
be
used
to
achieve
these
levels.
The
technological
feasibility
discussion
below
(
Section
VI.
G)
describes
our
technical
rationale
in
more
detail.
1.
What
Are
the
Emission
Standards
and
Compliance
Dates?
The
emission
standards
for
recreational
marine
diesel
engines
are
the
same
as
the
Tier
2
standards
for
commercial
marine
diesel
engines
with
two
years
additional
lead
time.
We
are
setting
the
standards
at
the
same
level
because
recreational
marine
diesel
engines
can
use
all
the
technologies
projected
for
Tier
2
and
these
technologies
are
expected
to
lead
to
compliance.
As
with
commercial
marine
engines
this
technology
will
be
available
in
the
lead
time
provided
to
allow
compliance
with
the
emission
standards.
Many
of
these
engines
already
use
this
technology.
This
includes
electronic
fuel
management,
turbocharging,
and
separate
circuit
aftercooling.
In
fact,
because
recreational
engines
have
much
shorter
design
lives
than
commercial
engines,
it
is
easier
to
apply
raw
water
aftercooling
to
these
engines,
which
allows
manufacturers
to
enhance
performance
while
reducing
NOX
emissions.
Engine
manufacturers
will
generally
increase
the
fueling
rate
in
recreational
engines,
compared
to
commercial
engines,
to
gain
power
from
a
given
engine
size.
This
helps
bring
a
planing
vessel
onto
the
water
surface
and
increases
the
maximum
vessel
speed
without
increasing
the
weight
of
the
vessel.
This
difference
in
how
recreational
engines
are
designed
and
used
affects
emissions.
However,
the
technology
listed
above
can
be
used
to
meet
the
emission
standards
while
still
meeting
the
performance
requirements
of
a
recreational
engine.
We
are
adopting
the
commercial
marine
engine
standards
for
recreational
marine
diesel
engines,
allowing
two
years
beyond
the
dates
that
standards
apply
for
the
commercial
engines.
This
gives
engine
manufacturers
additional
lead
time
in
adapting
technology
to
their
recreational
marine
diesel
engines.
For
manufacturers
producing
only
recreational
marine
engines
the
implementation
dates
provide
three
to
six
years
of
lead
time
beyond
this
notice.
Based
on
our
evaluation
of
the
industry,
we
believe
that
manufacturers
who
produce
only
recreational
marine
engines
would
likely
be
small
businesses
and
would
have
the
option
of
additional
lead
time,
and
other
flexibility,
as
discussed
in
Section
VI.
E.
The
emission
standards
and
implementation
dates
for
recreational
marine
diesel
engines
are
presented
in
Table
VI.
C
1.
The
subcategories
refer
to
engine
displacement
in
liters
per
cylinder.
TABLE
VI.
C
1.
RECREATIONAL
MARINE
DIESEL
EMISSION
STANDARDS
AND
IMPLEMENTATION
DATES
Subcategory
HC+
NOX
g/
kW
hr
PM
g/
kW
hr
CO
g/
kW
hr
Implementation
date
power
37
kW
disp
<
0.9
...............................................................................
7.5
0.40
5.0
2007
0.9
disp
<
1.2
................................................................................................
7.2
0.30
5.0
2006
1.2
disp
<
2.5
................................................................................................
7.2
0.20
5.0
2006
disp
2.5
.........................................................................................................
7.2
0.20
5.0
2009
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2002
/
Rules
and
Regulations
Manufacturers
commented
that
engines
with
less
than
2.5
liters
per
cylinder,
but
more
than
560
kW
would
have
no
lead
time
beyond
the
landbased
nonroad
diesel
engine
standards
and
that
some
commercial
marine
engines
in
this
category
would
actually
have
to
certify
two
years
before
nonroad
engines.
In
this
case
this
is
caused
by
the
way
we
define
subclasses,
but
has
technology
and
cost
implications
for
the
engines
involved.
To
address
this,
we
are
providing
an
optional
implementation
date
of
2008
for
certain
commercial
and
recreational
marine
engines
(
see
the
Summary
and
Analysis
of
Comments
for
more
detail).
To
be
eligible
for
this
option,
the
engine
must
be
derived
from
a
land
based
nonroad
engine
with
a
rated
power
greater
than
560
kW
and
have
a
displacement
of
2.0
to
2.5
liters
per
cylinder.
To
use
this
option,
we
are
requiring
that
engines
certified
under
this
option
meet
an
HC+
NOX
standard
of
6.4
g/
kW
hr
through
model
year
2012.
We
believe
this
emission
level,
which
matches
the
Tier
2
level
for
land
based
nonroad
engines,
should
be
achievable
given
the
extra
lead
time
for
development.
Testing
would
still
be
performed
on
the
appropriate
marine
duty
cycles.
Based
on
our
analysis
in
the
Final
Regulatory
Impact
Analysis
for
commercial
marine
engines,
HC+
NOX
emissions
measured
over
the
marine
duty
cycles
should
be
similar
to
those
measured
over
the
landbased
nonroad
duty
cycle.
We
are
also
adopting
not
to
exceed
emission
standards
and
related
requirements
similar
to
those
finalized
for
commercial
marine
diesel
engines.
This
is
discussed
below
in
Section
VI.
C.
8.
2.
Will
I
Be
Able
To
Average,
Bank,
or
Trade
Emissions
Credits?
Manufacturers
may
use
emission
credits
from
recreational
marine
diesel
engines
to
show
that
they
meet
emission
standards.
Section
II.
C.
3
gives
an
overview
of
the
emission
credit
program,
which
is
consistent
with
what
we
have
adopted
for
Category
1
commercial
marine
diesel
engines.
The
emission
credit
program
covers
HC+
NOX
and
PM
emissions,
but
not
CO
emissions.
Consistent
with
our
land
based
nonroad
and
commercial
marine
diesel
engine
regulations,
manufacturers
may
not
simultaneously
generate
HC+
NOX
credits
while
using
PM
credits
on
the
same
engine
family,
and
vice
versa.
This
is
necessary
because
of
the
inherent
trade
off
between
NOX
and
PM
emissions
in
diesel
engines.
We
are
adopting
the
same
maximum
value
of
the
Family
Emission
Limit
(
FEL)
as
for
commercial
marine
diesel
engines.
For
engines
with
a
displacement
of
less
than
1.2
liters/
cylinder,
the
maximum
values
are
11.5
g/
kW
hr
HC+
NOX
and
1.2
g/
kW
hr
PM;
for
larger
engines,
the
maximum
values
are
10.5
g/
kW
hr
HC+
NOX
and
0.54
g/
kW
hr
PM.
These
maximum
FEL
values
were
based
on
the
comparable
landbased
emission
credit
program
and
will
ensure
that
the
emissions
from
any
given
family
certified
under
this
program
not
be
significantly
higher
than
the
applicable
emission
standards.
We
believe
these
maximum
values
will
prevent
backsliding
of
emissions
above
the
baseline
levels
for
any
given
engine
model.
Also,
we
are
concerned
that
the
higher
emitting
engines
may
cause
increased
emissions
in
areas
such
as
ports
that
may
have
a
need
for
PM
or
NOX
emission
reductions.
Nonetheless,
it
is
acknowledged
that
recreational
marine
diesel
engines
constitute
a
small
fraction
of
PM
and
HC
+
NOX
emissions
in
nonattainment
areas.
Emission
credits
generated
under
this
program
have
no
expiration,
with
no
discounting
applied.
This
is
consistent
with
the
commercial
marine
credit
program
and
gives
manufacturers
more
options
in
implementing
their
engine
designs.
However,
if
we
revisit
these
standards
later,
we
will
have
to
reevaluate
this
issue
in
the
context
of
whether
future
advances
in
technology
would
result
in
a
large
amount
of
accumulated
credits
that
would
adversely
impact
the
timely
implementation
of
any
new
requirements.
Consistent
with
the
land
based
nonroad
diesel
rule,
we
will
also
not
allow
manufacturers
to
use
credits
generated
on
land
based
engines
for
demonstrating
compliance
with
marine
diesel
engines.
In
addition,
credits
may
not
be
exchanged
between
recreational
and
commercial
marine
engines.
The
emission
standards
for
recreational
engines
are
based
on
the
baseline
levels
of
current
recreational
marine
engines
and
the
capability
of
technology
to
reduce
emissions
from
recreational
marine
engines.
The
standard
is,
therefore,
premised
on
the
capability
and
use
of
recreational
marine
technology
and
not
on
the
capability
and
use
of
technology
on
other
engines.
Emissions
from
land
based,
commercial,
and
recreational
marine
engines
are
measured
over
different
duty
cycles
and
have
different
useful
lives.
Correction
factors
would
be
difficult
to
generate
and
they
would
add
complexity
and
uncertainty
to
the
value
of
the
credits.
Furthermore,
we
are
concerned
that
allowing
cross
program
trading
could
create
an
inequity
between
manufacturers
with
diverse
product
lines
and
those
with
more
limited
offerings,
thereby
potentially
creating
a
competitive
advantage
for
diverse
companies
over
small
companies
selling
only
recreational
marine
engines.
If
a
manufacturer
were
to
do
this,
we
do
not
believe
it
is
likely
that
they
would
sell
emission
credits
at
a
price
that
would
be
economical
for
small
manufacturers.
We
will
allow
early
banking
of
emission
credits
relative
to
the
standard.
Early
banking
of
emission
credits
may
allow
for
a
smoother
implementation
of
the
recreational
marine
standards.
These
credits
are
generated
relative
to
the
new
emission
standards
and
are
undiscounted.
We
will
also
allow
manufacturers
to
generate
early
credits
relative
to
their
pre
control
emission
levels.
If
manufacturers
choose
this
option
they
will
have
to
develop
baseline
emission
levels
specific
to
each
participating
engine
family.
Credits
will
then
be
calculated
relative
to
the
manufacturergenerated
baseline
emission
rates,
rather
than
the
standards.
To
generate
the
baseline
emission
rates,
a
manufacturer
must
test
three
engines
from
the
family
for
which
the
baseline
is
being
generated.
The
baseline
will
be
the
average
emissions
of
the
three
engines.
Under
this
option,
engines
must
still
certify
to
the
standards
to
generate
credits,
but
the
credits
will
be
calculated
relative
to
the
generated
baseline
rather
than
the
standards.
Any
credits
generated
between
the
level
of
the
standards
and
the
generated
baseline
will
be
discounted
10
percent.
This
is
to
account
for
the
variability
of
testing
inuse
engines
to
establish
the
familyspecific
baseline
levels,
which
may
result
from
differences
in
hours
of
use
and
maintenance
practices
as
well
as
other
sources
of
potential
uncertainty
about
the
representativeness
if
the
baseline.
Manufacturers
commented
that
credits
should
not
be
generated
under
the
early
banking
program
for
the
portion
of
NOX
reductions
above
the
MARPOL
Annex
VI
standard.
We
believe
this
approach
is
reasonable
since
this
should
be
a
common
upper
limit
for
all
engines.
Therefore,
if
manufacturers
use
this
option,
any
baseline
NOX
levels
determined
to
be
above
the
MARPOL
Annex
VI
standard
must
be
adjusted
to
that
level
for
determining
early
credits.
3.
Is
EPA
Proposing
Voluntary
Standards
for
These
Engines?
a.
Blue
Sky.
We
are
adopting
voluntary
emission
standards
based
on
a
45
percent
reduction
beyond
the
mandatory
standards.
An
engine
family
meeting
the
voluntary
standards
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217
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November
8,
2002
/
Rules
and
Regulations
qualifies
for
designation
as
Blue
Sky
Series
engines.
These
voluntary
standards
are
the
same
as
those
adopted
for
commercial
marine
diesel
engines
(
see
Table
VI.
C
2).
While
the
Blue
Sky
Series
emission
standards
are
voluntary,
a
manufacturer
choosing
to
certify
an
engine
under
this
program
must
comply
with
all
the
requirements
that
apply
to
this
category
of
engines,
including
allowable
maintenance,
warranty,
useful
life,
rebuild,
and
deterioration
factor
provisions.
This
program
is
effective
immediately
when
we
publish
this
rule.
To
maximize
the
potential
for
other
groups
to
create
incentive
programs,
without
double
counting,
we
do
not
allow
manufacturers
to
earn
marketable
credits
for
their
Blue
Sky
Engines.
TABLE
VI.
C
2.
BLUE
SKY
VOLUNTARY
EMISSION
STANDARDS
FOR
RECREATIONAL
MARINE
DIESEL
ENGINES
[
g/
kW
hr]
Rated
brake
power
(
kW)
HC+
NOX
PM
power
37
kW
displ.<
0.9
...............
4.0
0.24
0.9
displ.<
1.2
...........
4.0
0.18
1.2
displ.<
2.5
...........
4.0
0.12
2.5
displ.
..................
5.0
0.12
b.
MARPOL
Annex
VI.
The
MARPOL
Annex
VI
standards
are
for
NOX
emissions
from
marine
diesel
engines
rated
above
130
kW.
We
encourage
engine
manufacturers
to
make
Annex
VI
compliant
engines
available
and
boat
builders
to
purchase
and
install
them
before
we
apply
the
EPA
Tier
2
standards.
If
the
treaty
enters
into
force,
the
standards
would
go
into
effect
retroactively
to
all
boats
built
January
1,
2000
or
later.
One
advantage
of
using
MARPOL
compliant
engines
is
that
if
this
happens,
users
will
be
in
compliance
with
the
standard
without
having
to
make
any
changes
to
their
engines.
4.
What
Durability
Provisions
Apply?
Several
provisions
help
ensure
that
engines
control
emissions
throughout
a
lifetime
of
operation.
Section
II.
C
gives
a
general
overview
of
durability
provisions
associated
with
emissions
certification.
This
section
discusses
these
provisions
specifically
for
recreational
marine
diesel
engines.
a.
How
long
do
my
engines
have
to
comply?
Manufacturers
must
produce
engines
that
comply
over
a
useful
life
of
ten
years
or
until
the
engine
accumulates
1,000
operating
hours,
whichever
occurs
first.
The
hours
requirement
is
a
minimum
value
for
useful
life,
and
manufacturers
must
comply
for
a
longer
period
in
those
cases
where
they
design
their
engines
to
be
operated
longer
than
1,000
hours.
In
making
the
determination
that
engines
are
designed
to
last
longer
than
the
1,000
hour
value,
we
will
consider
evidence
such
as
whether
the
engines
continue
to
reliably
deliver
the
necessary
power
output
without
an
increase
in
fuel
consumption
that
the
user
would
find
unacceptable
and
thus
might
trigger
a
maintenance
or
rebuild
action
by
the
user.
b.
How
do
I
demonstrate
emission
durability?
We
are
extending
the
durability
demonstration
requirements
for
commercial
marine
diesel
engines
to
also
cover
recreational
marine
diesel
engines.
This
means
that
recreational
marine
engine
manufacturers,
using
good
engineering
judgment,
will
generally
need
to
test
one
or
more
engines
for
emissions
before
and
after
accumulating
the
number
of
hours
consistent
with
the
engine
useful
life
(
usually
performed
by
continuous
engine
operation
in
a
laboratory).
The
results
of
these
tests
are
referred
to
as
``
durability
data,''
and
are
used
to
determine
the
rates
at
which
emissions
are
expected
to
increase
over
the
useful
life
of
the
engine
for
each
engine
family
The
rates
are
known
as
deterioration
factors.
However,
in
many
cases,
manufacturers
may
use
durability
data
from
a
different
engine
family,
or
for
the
same
engine
family
in
a
different
model
year.
Because
of
this
allowance
to
use
the
same
data
for
multiple
engine
families,
we
expect
durability
testing
to
be
very
limited.
We
also
specify
that
manufacturers
must
collect
durability
data
and
generate
deterioration
factors
using
the
same
methods
established
for
commercial
marine
diesel
engines.
These
requirements
are
in
40
CFR
94.211,
94.218,
94.219,
and
94.220.
These
sections
describe
when
durability
data
from
one
engine
family
can
be
used
for
another
family,
how
to
select
to
the
engine
configuration
that
is
to
be
tested,
how
to
conduct
the
service
accumulation,
and
what
maintenance
can
be
performed
on
the
engine
during
this
service
accumulation.
Under
40
CFR
94.220,
manufacturers
may
project
deterioration
rates
from
engines
with
an
accumulation
of
less
than
1,000
hours,
as
long
as
the
amount
of
service
accumulation
completed
and
projection
procedures
are
determined
using
good
engineering
judgment.
c.
What
maintenance
may
be
done
during
service
accumulation?
For
engines
certified
to
a
1,000
hour
useful
life,
the
only
maintenance
that
may
be
done
must
be:
(
1)
Regularly
scheduled,
(
2)
unrelated
to
emissions,
and
(
3)
technologically
necessary.
This
typically
includes
changing
engine
oil,
oil
filter,
fuel
filter,
and
air
filter.
For
recreational
marine
diesel
engines
certified
to
longer
lives,
these
engines
will
be
subject
to
the
same
minimum
allowable
maintenance
intervals
as
commercial
marine
engines.
These
intervals
and
the
allowable
maintenance
are
specified
in
40
CFR
94.211.
d.
Are
there
production
line
testing
provisions?
We
are
adopting
the
production
line
testing
requirements
from
commercial
marine
engines
for
recreational
marine
diesel
engines,
with
the
additional
provisions
described
in
II.
C.
4.
A
manufacturer
must
test
one
percent
of
its
total
projected
annual
sales
of
Category
1
engines
each
year
to
meet
production
line
testing
requirements.
We
are
not
adopting
a
minimum
number
of
tests,
so
a
manufacturer
who
produces
no
more
than
100
marine
diesel
engines
is
not
required
to
do
any
production
line
testing.
Similar
to
the
commercial
marine
requirements,
manufacturers
have
the
option
of
using
alternative
production
line
testing
programs
with
EPA
approval.
Manufacturers
commented
that
we
should
limit
the
number
of
engines
tested
for
a
given
engine
family
to
five,
arguing
that
five
engines
would
be
sufficient
to
demonstrate
compliance
with
the
standards.
Although
there
isn't
necessarily
an
engineering
rationale
for
capping
the
number
of
tests
for
each
engine
family
to
five,
we
believe
that
statistical
certainty
can
be
determined
using
the
Cumulative
Sum
method
described
for
recreational
vehicles
in
40
CFR
part
1051,
subpart
D.
Therefore,
we
are
providing
the
option
of
using
the
Cumulative
Sum
method
for
determining
sample
sizes
under
the
production
line
testing
program.
For
marine
engines,
PM
would
need
to
be
included
in
this
methodology.
Under
the
Cumulative
Sum
method,
a
statistical
analysis
is
applied
to
test
results
to
establish
the
number
of
tests
needed.
This
may
limit
the
number
of
engines
tested
to
less
than
1
percent
of
the
production
volume
in
cases
where
there
is
low
variability
in
the
test
data.
5.
Do
These
Standards
Apply
to
Alternative
Fueled
Engines?
These
new
standards
apply
to
all
recreational
marine
diesel
engines,
without
regard
to
the
type
of
fuel
used.
While
we
are
not
aware
of
any
alternative
fueled
recreational
marine
diesel
engines
currently
being
sold
into
the
U.
S.
market,
alternate
forms
of
the
hydrocarbon
standards
address
the
potential
for
natural
gas
fueled
and
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Rules
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Regulations
alcohol
fueled
engines.
In
our
regulation
of
highway
vehicles
and
engines,
we
determined
that
nonmethane
standards
should
be
used
in
place
of
total
hydrocarbon
standards
for
engines
fueled
with
natural
gas
(
which
is
comprised
primarily
of
methane)
(
59
FR
48472,
September
21,
1994).
These
alternate
forms
follow
the
precedent
set
in
previous
rulemakings
to
make
the
standards
similar
in
stringency
and
environmental
impact.
Similarly,
we
are
applying
HCequivalent
(
HCE)
standards
instead
of
total
hydrocarbon
standards
to
alcoholfueled
highway
engines
and
vehicles
(
54
FR
14426,
April
11,
1989).
HCequivalent
emissions
are
calculated
from
the
oxygenated
organic
components
and
non
oxygenated
organic
components
of
the
exhaust,
summed
together
based
on
the
amount
of
organic
carbon
present
in
the
exhaust.
Alcohol
fueled
recreational
marine
engines
must
therefore
comply
with
total
hydrocarbon
equivalent
(
THCE)
plus
NOX
standards
instead
of
THC
plus
NOX
standards.
6.
Is
EPA
Controlling
Crankcase
Emissions?
Manufacturers
must
prevent
crankcase
emissions
from
recreational
marine
diesel
engines,
with
one
exception.
Turbocharged
recreational
marine
diesel
engines
may
be
built
with
open
crankcases,
as
long
as
the
crankcase
ventilation
system
allows
for
measurement
of
crankcase
emissions.
For
these
engines
with
open
crankcases,
we
will
require
crankcase
emissions
to
be
either
routed
into
the
exhaust
stream
to
be
included
in
the
exhaust
measurement,
or
to
be
measured
separately
and
added
to
the
measured
exhaust
mass.
These
measurement
requirements
do
not
add
significantly
to
the
cost
of
testing,
especially
where
the
crankcase
vent
is
simply
routed
into
the
exhaust
stream
prior
to
the
point
of
exhaust
sampling.
These
provisions
are
consistent
with
our
previous
regulation
of
crankcase
emissions
from
such
diverse
sources
as
commercial
marine
engines,
locomotives,
and
passenger
cars.
7.
What
Are
the
Smoke
Requirements?
We
are
not
adopting
smoke
requirements
for
recreational
marine
diesel
engines.
Marine
diesel
engine
manufacturers
have
stated
that
many
of
their
engines,
though
currently
unregulated,
are
manufactured
with
smoke
limiting
controls
at
the
request
of
customers.
Users
seek
low
smoke
emissions
both
because
they
dislike
the
exhaust
residue
on
decks
and
because
they
can
be
subject
to
penalties
in
ports
with
smoke
emission
requirements.
In
many
cases,
marine
engine
exhaust
gases
are
mixed
with
water
prior
to
being
released.
This
practice
reduces
smoke
visibility.
Moreover,
we
believe
that
applying
PM
standards
will
have
the
effect
of
limiting
smoke
emissions
as
well.
8.
What
Are
the
Not
To
Exceed
Standards
and
Related
Requirements?
a.
Concept.
Our
goal
is
to
achieve
control
of
emissions
over
the
broad
range
of
in
use
speed
and
load
combinations
that
can
occur
on
a
recreational
marine
diesel
engine
so
that
real
world
emission
control
is
achieved,
rather
than
just
controlling
emissions
under
certain
laboratory
conditions.
An
important
tool
for
achieving
this
goal
is
an
in
use
program
with
an
objective
emission
standard
and
an
easily
implemented
test
procedure.
Prior
to
this
concept,
our
approach
has
been
to
set
a
numerical
standard
on
a
specified
test
procedure
and
rely
on
the
additional
prohibition
of
defeat
devices
to
ensure
in
use
control
over
a
broad
range
of
operation
not
included
in
the
test
procedure.
We
are
applying
the
defeat
device
provisions
established
for
commercial
marine
engines
to
recreational
marine
diesel
engines
in
addition
to
the
NTE
requirements
(
see
40
CFR
94.2).
A
design
in
which
an
engine
met
the
standard
at
the
steady
state
test
points
but
was
intentionally
designed
to
approach
the
NTE
limit
everywhere
else
would
be
considered
to
be
defeating
the
standard.
Electronic
controls
that
recognize
and
modulate
the
emissioncontrol
system
when
the
engine
is
not
being
tested
for
emissions
and
increases
the
emissions
from
the
engine
would
be
an
example
of
a
defeat
device,
regardless
of
the
emissions
performance
of
the
engine
with
regard
to
the
standards.
No
single
test
procedure
can
cover
all
real
world
applications,
operations,
or
conditions.
Yet
to
ensure
that
emission
standards
are
providing
the
intended
benefits
in
use,
we
must
have
a
reasonable
expectation
that
emissions
under
real
world
conditions
reflect
those
measured
on
the
test
procedure.
The
defeat
device
prohibition
is
designed
to
ensure
that
emission
controls
are
employed
during
real
world
operation,
not
just
under
laboratory
or
test
procedure
conditions.
However,
the
defeat
device
prohibition
is
not
a
quantified
standard
and
does
not
have
an
associated
test
rocedure,
so
it
does
not
have
the
clear
objectivity
and
ready
enforceability
of
a
numerical
standard
and
test
procedure.
As
a
result,
relying
on
just
a
using
a
standardized
test
procedure
and
the
defeat
device
prohibition
makes
it
harder
to
ensure
that
engines
will
operate
with
the
same
level
of
control
in
the
real
world
as
in
the
test
cell.
Because
the
ISO
E5
duty
cycle
uses
only
five
modes
on
an
average
propeller
curve
intended
to
characterize
typical
marine
engine
operation
for
this
industry,
we
are
concerned
that
an
engine
designed
to
the
duty
cycle
may
not
necessarily
perform
the
same
way
over
the
range
of
speed
and
load
combinations
normally
seen
on
a
boat
nor
will
it
always
follow
the
average
curve.
These
duty
cycles
are
based
on
an
average
propeller
curve,
but
a
propulsion
marine
engine
may
never
be
fitted
with
an
``
average
propeller.''
In
addition,
even
if
fitted
with
an
``
average
propeller,''
an
engine
fit
to
a
specific
boat
may
operate
differently
based
on
how
heavily
the
boat
is
loaded.
To
ensure
that
emissions
are
controlled
from
recreational
marine
engines
over
the
full
range
of
speed
and
load
combinations
normally
seen
on
boats,
we
are
establishing
a
zone
under
the
engine's
power
curve
where
the
engine
may
not
exceed
a
specified
emission
limit.
This
limit
applies
to
all
of
the
regulated
pollutants
under
steadystate
operation.
Testing
in
this
``
not
toexceed
(
NTE)
zone
may
include
the
whole
range
of
real
ambient
conditions.
The
NTE
zone,
limit,
and
ambient
conditions
are
described
below.
We
believe
there
are
significant
advantages
to
taking
this
approach.
The
test
procedure
is
flexible
enough
to
represent
the
majority
of
in
use
engine
operation
and
ambient
conditions.
Therefore,
the
NTE
approach
takes
all
of
the
benefits
of
a
numerical
standard
and
test
procedure
and
expands
it
to
cover
a
broad
range
of
conditions.
Also,
a
standard
that
requires
laboratory
testing
makes
it
harder
to
perform
in
use
testing
because
either
the
engines
must
be
removed
from
the
vessel
or
laboratorytype
conditions
must
be
achieved
on
the
vessel.
With
the
NTE
approach,
in
use
testing
becomes
much
easier
to
implement
since
emissions
may
be
sampled
during
normal
vessel
use.
Because
this
approach
is
objective,
it
makes
enforcement
easier
and
provides
more
certainty
to
the
industry
in
terms
of
what
control
is
expected
in
use
versus
over
a
fixed
laboratory
test
procedure.
Even
with
the
NTE
requirements,
we
believe
it
is
important
to
retain
standards
based
on
the
steady
state
duty
cycles.
This
is
the
standard
that
we
expect
the
certified
marine
engines
to
meet
on
average
in
use.
The
NTE
testing
is
more
focused
on
maximum
emissions
for
segments
of
operation.
We
believe
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basing
the
emission
standards
on
a
distinct
cycle
and
using
the
NTE
zone
to
better
ensure
in
use
control
creates
a
comprehensive
program.
In
addition,
the
steady
state
duty
cycles
give
a
basis
for
calculating
credits
for
averaging,
banking,
and
trading.
As
described
in
the
Summary
and
Analysis
of
Comments,
the
same
technology
that
can
be
used
to
meet
the
standards
over
the
E5
duty
cycle
can
be
used
to
meet
the
NTE
caps
in
the
NTE
zone.
We
therefore
do
not
expect
these
standards
to
cause
recreational
marine
diesel
engines
to
need
more
advanced
technology
that
is
used
by
the
nonroad
and
commercial
marine
engines
from
which
they
are
derived.
We
do
not
believe
the
NTE
concept
results
in
a
large
amount
of
additional
testing,
because
these
engines
should
be
designed
to
perform
as
well
in
use
as
they
do
over
the
steady
state
five
mode
certification
test.
However,
our
cost
analysis
in
Chapter
5
of
the
Final
Regulatory
Support
Document
accounts
for
some
additional
testing,
especially
in
the
early
years,
to
provide
manufacturers
with
assurance
that
their
engines
will
meet
the
NTE
requirements.
b.
Shape
of
the
NTE
zone.
Figure
VI.
C
1
illustrates
the
NTE
zone
for
recreational
marine
diesel
engines.
We
based
this
zone
on
the
range
of
conditions
that
these
engines
might
typically
see
in
use.
Also,
we
divide
the
zone
into
subzones
of
operation
which
have
different
limits
as
described
below.
Chapter
4
of
the
Final
Regulatory
Support
Document
describes
the
development
of
the
boundaries
and
conditions
associated
with
the
NTE
zone.
The
NTE
zone
for
recreational
marine
diesel
engines
is
the
same
for
commercial
marine
diesel
engines
operating
on
a
propeller
curve,
except
that
an
additional
subzone
is
added
at
speeds
over
95
percent
of
rated
to
address
the
typical
recreational
design
for
higher
rated
power.
BILLING
CODE
6560
50
P
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Regulations
BILLING
CODE
6560
50
C
EPA
may
approve
adjustments
to
the
size
and
shape
of
the
NTE
zone
for
certain
engines
if
the
manufacturer
demonstrates
that
the
engine
will
not
see
operation
outside
of
the
revised
NTE
zone
in
use.
This
way,
manufacturers
can
avoid
having
to
test
their
engines
under
operation
that
they
will
not
see
in
use.
However,
manufacturers
are
responsible
for
ensuring
that
their
specified
operation
represents
realworld
operation.
In
addition,
if
a
manufacturer
designs
an
engine
for
operation
at
speeds
and
loads
outside
of
the
NTE
zone
(
i.
e.,
variable
speed
engines
used
with
variable
pitch
propellers),
the
manufacturer
is
responsible
for
notifying
us,
so
the
NTE
zone
for
that
engine
family
can
be
modified
to
include
this
operation.
c.
Transient
operation.
NTE
testing
includes
only
steady
state
operation
with
a
minimum
sampling
time
of
30
seconds.
We
specify
the
ISO
E5
steadystate
duty
cycle
for
showing
compliance
with
average
emission
standards.
The
goal
of
adopting
NTE
standards
and
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Rules
and
Regulations
84
The
range
of
intake
air
temperature
is
13
to
30
°
C
for
engines
that
draw
air
from
outside
the
engine
room.
procedures
is
to
cover
the
operation
away
from
the
five
modes
that
are
on
the
assumed
propeller
curve.
Our
understanding
is
that
the
majority
of
marine
engine
operation
is
steady
state;
however,
we
recognize
that
recreational
marine
use
is
likely
more
transient
than
commercial
marine
use.
At
this
time
we
do
not
have
enough
data
on
marine
engine
operation
to
accurately
determine
the
amount
of
transient
operation
that
occurs
or
to
set
an
NTE
standard
for
transient
operation.
We
are
aware
that
the
high
load
transient
operation
seen
when
a
boat
comes
to
plane
is
not
included
in
the
NTE
zone
as
defined,
even
if
we
were
to
require
compliance
with
NTE
standards
during
transient
operation.
We
are
also
aware
that
these
speed
and
load
points
cannot
be
achieved
under
steady
state
operation
for
a
properly
loaded
boat
in
use.
If
we
find
that
excluding
transient
operation
from
the
compliance
requirements
results
in
a
significant
increase
in
emissions,
we
will
revisit
this
provision
in
the
future.
Also,
an
engine
designed,
with
multiple
injection
timing
maps
based
on
operation,
to
operate
at
higher
emissions
during
transient
operation
than
during
steadystate
testing
would
be
in
noncompliance
with
our
defeat
device
prohibition.
d.
Emission
standards.
We
are
requiring
emissions
caps
for
the
NTE
zones
that
represent
a
multiplier
times
the
weighted
test
result
used
for
certification
for
all
of
the
regulated
pollutants
(
HC+
NOX,
CO,
and
PM).
This
is
consistent
with
the
concept
of
a
weighted
modal
emission
test
such
as
the
steady
state
tests
included
in
this
rule.
The
standard
itself
is
intended
to
represent
the
average
emissions
under
steady
state
conditions.
Because
it
is
an
average,
some
points
can
be
higher,
some
lower,
and
the
manufacturer
will
design
to
maximize
performance
and
still
meet
the
engine
standard.
The
NTE
limit
is
on
top
of
this.
It
is
designed
to
make
sure
that
no
part
of
the
engine
operation
and
that
no
application
goes
too
far
from
the
average
level
of
control.
Consistent
with
the
requirements
for
commercial
marine
engines,
recreational
marine
diesel
engines
must
meet
a
cap
of
1.50
times
the
certified
level
for
HC+
NOX,
PM,
and
CO
for
the
speed
and
power
subzone
below
45
percent
of
rated
power
and
a
cap
of
1.20
times
the
certified
levels
at
or
above
45
percent
of
rated
power.
However,
we
are
applying
an
additional
subzone
at
speeds
greater
than
95
percent
of
rated,
with
a
corresponding
standard
of
1.50
times
the
certified
levels
for
this
subzone.
This
additional
subzone
addresses
the
typical
recreational
design
for
higher
rated
power.
We
understand
that
this
power
is
needed
to
ensure
that
the
engine
can
bring
the
boat
to
plane.
Chapter
4
of
the
Final
Regulatory
Support
Document
provides
more
detail
on
how
we
determined
the
standards.
We
are
aware
that
marine
diesel
engines
may
not
be
able
to
meet
the
emissions
limit
under
all
conditions.
Specifically,
there
are
times
when
emission
control
must
be
compromised
for
startability
or
safety.
Engine
starting
is
not
included
in
NTE
testing.
In
addition,
manufacturers
have
the
option
of
petitioning
the
Administrator
to
allow
emissions
to
increase
under
engine
protection
strategies,
such
as
when
an
engine
overheats.
This
is
also
consistent
with
the
requirements
for
commercial
marine
engines.
e.
Ambient
conditions.
Variations
in
ambient
conditions
can
affect
emissions.
Such
conditions
include
air
temperature,
humidity,
and
(
especially
for
aftercooled
engines)
water
temperature.
We
are
applying
the
commercial
marine
engine
ranges
for
these
variables.
Chapter
4
of
the
Final
Regulatory
Support
Document
provides
more
detail
on
how
we
determined
these
ranges.
Within
the
ranges,
there
is
no
calculation
to
correct
measured
emissions
to
standard
conditions.
Outside
of
the
ranges,
emissions
can
be
corrected
back
to
the
nearest
end
of
the
range.
The
ambient
variable
ranges
are
13
to
35
°
C
(
55
to
95
°
F)
for
intake
air
temperature,
7.1
to
10.7
g
water/
kg
dry
air
(
50
to
75
grains/
pound
dry
air)
for
intake
air
humidity,
and
5
to
27
°
C
(
41
to
80
°
F)
for
ambient
water
temperature.
84
f.
Certification.
At
the
time
of
certification,
manufacturers
must
submit
a
statement
that
its
engines
will
comply
with
these
requirements
under
all
conditions
that
may
reasonably
be
expected
to
occur
in
normal
vessel
operation
and
use.
The
manufacturer
also
provides
a
detailed
description
of
all
testing,
engineering
analysis,
and
other
information
that
forms
the
basis
for
the
statement.
This
statement
may
be
based
on
testing
other
research
that
validly
supports
such
a
statement,
consistent
with
good
engineering
judgment.
EPA
may
review
the
basis
of
this
statement
during
the
certification
process.
D.
Testing
Equipment
and
Procedures
The
regulations
detail
specifications
for
test
equipment
and
procedures
that
apply
generally
to
commercial
marine
engines
(
including
NTE
testing)
in
40
CFR
part
94.
We
have
based
the
recreational
marine
diesel
engine
test
procedures
on
this
part.
Section
VIII
gives
a
general
discussion
of
testing
requirements;
this
section
describes
procedures
that
are
specific
to
recreational
marine
such
as
the
duty
cycle
for
operating
engines
for
emission
measurements.
Chapter
4
of
the
Draft
Regulatory
Support
Document
describes
these
duty
cycles
in
greater
detail.
In
addition
to
the
information
provided
above,
the
following
section
discusses
issues
concerning
test
equipment
and
procedures.
1.
Which
Duty
Cycles
Are
Used
To
Measure
Emissions?
For
recreational
marine
diesel
engines,
we
specify
the
ISO
E5
duty
cycle.
This
is
a
5
mode
steady
state
cycle,
including
an
idle
mode
and
four
modes
lying
on
a
cubic
propeller
curve.
ISO
intends
for
this
cycle
to
be
used
for
all
engines
in
boats
less
than
24
meters
in
length.
We
apply
it
to
all
recreational
marine
diesel
engines
to
avoid
the
complexity
of
tying
emission
standards
to
boat
characteristics.
A
given
engine
may
be
used
in
boats
longer
and
shorter
than
24
meters;
engine
manufacturers
generally
will
not
know
the
size
of
the
boat
into
which
an
engine
will
be
installed.
Also,
we
expect
that
most
recreational
boats
will
be
under
24
meters
in
length.
Chapter
4
of
the
Final
Regulatory
Support
Document
provides
further
detail
on
the
ISO
E5
duty
cycle.
2.
What
Fuels
Will
Be
Used
During
Emission
Testing?
We
are
applying
the
same
specifications
for
recreational
marine
diesel
engines
that
we
established
for
commercial
marine
diesel
engines.
That
means
that
the
recreational
engines
will
use
the
same
test
fuel
that
is
required
for
testing
Category
1
commercial
marine
diesel
engines,
which
is
a
regular
nonroad
test
fuel
with
moderate
sulfur
content.
We
are
not
aware
of
any
difference
in
fuel
specifications
for
recreational
and
commercial
marine
engines
of
comparable
size.
3.
How
Does
In
Use
Testing
Work?
In
use
testing
on
marine
engines
may
be
used
to
ensure
compliance
in
use.
This
testing
may
include
taking
in
use
marine
engines
out
of
the
vessel
and
testing
them
in
a
laboratory,
as
well
as
field
testing
of
in
use
engines
on
the
boat,
in
a
marine
environment.
We
plan
to
use
field
testing
data
in
two
ways.
First,
we
may
use
it
as
a
screening
tool,
with
follow
up
laboratory
testing
over
the
ISO
E5
duty
cycle
or
NTE
zone
where
appropriate.
Second,
we
may
use
the
data
directly
as
a
basis
for
compliance
determinations,
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Rules
and
Regulations
as
long
as
field
testing
equipment
and
procedures
are
capable
of
providing
reliable
information
from
which
conclusions
can
be
drawn
regarding
what
emission
levels
would
be
with
laboratory
based
measurements.
Because
it
would
likely
be
difficult
to
match
the
E5
test
points
exactly
on
an
engine
in
use
on
a
vessel,
NTE
zone
testing
will
reduce
the
difficulty
of
inuse
compliance
determinations.
For
marine
engines
that
expel
exhaust
gases
underwater
or
mix
their
exhaust
with
water,
manufacturers
must
equip
engines
with
an
exhaust
sample
port
where
a
probe
can
be
inserted
for
in
use
exhaust
emission
testing.
It
is
important
that
the
location
of
this
port
allow
a
well
mixed
and
representative
sample
of
the
exhaust.
This
provision
is
intended
to
simplify
in
use
testing.
In
cases
where
the
engine
manufacturer
does
not
supply
enough
of
the
exhaust
system
to
add
a
sample
port,
the
engine
manufacturer
would
be
required
to
provide
installation
instructions
for
a
sample
port.
Vessel
manufacturers
would
be
required
to
follow
this
and
any
other
emission
related
installation
instructions.
One
of
the
advantages
of
the
not
toexceed
requirements
will
be
to
facilitate
in
use
testing.
This
will
allow
us
to
perform
compliance
testing
in
the
field.
As
long
as
the
engine
is
operating
under
steady
state
conditions
in
the
NTE
zone,
we
will
be
able
to
measure
emissions
and
compare
them
to
the
NTE
limits.
To
assist
in
this
testing,
engines
with
electronic
controls
will
be
required
to
broadcast
engine
torque
(
as
percent
of
maximum)
and
engine
speed
on
their
controller
area
networks.
4.
How
Is
the
Maximum
Test
Speed
Determined?
To
ensure
that
a
manufacturer's
declared
maximum
speed
is
representative
of
actual
engine
operating
characteristics
and
is
not
improperly
used
to
influence
the
parameters
under
which
their
engines
are
certified,
we
are
applying
the
definition
of
maximum
test
speed
used
for
commercial
marine
engines.
This
definition
of
maximum
test
speed
is
the
single
point
on
an
engine's
normalized
maximum
power
versus
speed
curve
that
lies
farthest
away
from
the
zero
power,
zero
speed
point.
In
establishing
this
definition
of
maximum
test
speed,
it
was
our
intent
to
specify
the
highest
speed
at
which
the
engine
is
likely
to
be
operated
in
use.
Under
normal
circumstances
this
maximum
test
speed
should
be
close
to
the
speed
at
which
peak
power
is
achieved.
However,
as
some
manufacturers
indicated
in
their
comments,
it
is
possible
under
this
definition
for
the
maximum
test
speed
to
be
very
different
than
the
speed
at
which
peak
power
is
achieved.
This
could
result
in
the
certification
test
cycle
and
the
NTE
zone
(
which
are
both
defined
in
part
by
the
maximum
test
speed)
being
unrepresentative
of
in
use
operation.
Since
we
were
aware
of
this
potential
during
the
development
of
the
commercial
marine
regulations,
we
included
two
provisions
to
address
issues
such
as
these.
First,
§
94.102
allows
EPA
to
modify
test
procedures
in
situations
where
the
specified
test
procedures
would
otherwise
be
unrepresentative
of
in
use
operation.
Thus,
in
cases
in
which
the
definition
of
maximum
test
speed
resulted
in
an
engine
speed
that
was
not
expected
to
occur
with
in
use
engines,
we
would
work
with
the
manufacturers
to
determine
the
maximum
speed
that
would
be
expected
to
occur
in
use.
Second,
§
94.106(
c)(
2)
allows
EPA
to
specify
during
certification
a
broader
NTE
zone
to
include
actual
in
use
operation.
In
those
cases
where
we
could
not
specify
a
single
maximum
test
speed
under
§
94.102
that
would
sufficiently
cover
the
range
of
in
use
engine
speeds,
we
would
specify
a
broader
NTE
zone.
For
example,
we
would
generally
expect
that
the
NTE
zone
would
include
the
peak
power
point.
If
the
maximum
test
speed
derived
under
§
§
94.102
and
94.107
resulted
in
an
NTE
zone
that
did
not
include
the
peak
power
point,
we
would
likely
specify
that
the
NTE
zone
be
broadened
to
include
that
point.
Similarly,
we
would
expect
that
a
manufacturer's
advertised
rated
power/
speed
point
should
be
within
the
NTE
zone,
and
could
broaden
the
NTE
zone
to
include
that
point
as
well.
E.
Special
Compliance
Provisions
The
provisions
discussed
here
are
designed
to
minimize
regulatory
burdens
on
manufacturers
needing
added
flexibility
to
comply
with
emission
standards.
These
manufacturers
include
engine
dressers,
small
volume
engine
marinizers,
and
small
volume
boat
builders.
Commenters
generally
supported
these
provisions
as
proposed.
1.
What
Are
the
Burden
Reduction
Approaches
for
Engine
Dressers?
Many
recreational
marine
diesel
engine
manufacturers
take
a
new,
landbased
engine
and
modify
it
for
installation
on
a
marine
vessel.
Some
of
the
companies
that
modify
an
engine
for
installation
on
a
boat
make
no
changes
that
might
affect
emissions.
Instead,
the
modifications
may
consist
of
adding
mounting
hardware
and
a
generator
or
reduction
gears
for
propulsion.
It
can
also
involve
installing
a
new
marine
cooling
system
that
meets
original
manufacturer
specifications
and
duplicates
the
cooling
characteristics
of
the
land
based
engine,
but
with
a
different
cooling
medium
(
such
as
sea
water).
In
many
ways,
these
manufacturers
are
similar
to
nonroad
equipment
manufacturers
that
purchase
certified
land
based
nonroad
engines
to
make
auxiliary
engines.
This
simplified
approach
of
producing
an
engine
can
more
accurately
be
described
as
dressing
an
engine
for
a
particular
application.
Because
the
modified
landbased
engines
are
subsequently
used
on
a
marine
vessel,
however,
these
modified
engines
will
be
considered
marine
diesel
engines,
which
then
fall
under
these
requirements.
To
clarify
the
responsibilities
of
engine
dressers
under
this
rule,
we
will
not
treat
them
as
a
manufacturer
of
a
recreational
marine
diesel
engine
and
therefore
they
would
not
be
required
to
obtain
a
certificate
of
conformity,
as
long
as
they
meet
the
following
seven
conditions.
(
1)
The
engine
being
dressed
(
the
``
base''
engine)
must
be
a
highway,
landbased
nonroad,
or
locomotive
engine,
certified
pursuant
to
40
CFR
part
86,
40
CFR
part
89,
or
40
CFR
part
92,
respectively,
or
a
marine
diesel
engine
certified
pursuant
to
this
part.
(
2)
The
base
engine's
emissions,
for
all
pollutants,
must
meet
the
otherwise
applicable
recreational
marine
emission
limits.
In
other
words,
starting
in
2005,
a
dressed
nonroad
Tier
1
engine
will
not
qualify
for
this
exemption,
because
the
more
stringent
standards
for
recreational
marine
diesel
engines
go
into
effect
at
that
time.
(
3)
The
dressing
process
must
not
involve
any
modifications
that
can
change
engine
emissions.
We
do
not
consider
changes
to
the
fuel
system
to
be
engine
dressing
because
this
equipment
is
integral
to
the
combustion
characteristics
of
an
engine.
(
4)
All
components
added
to
the
engine,
including
cooling
systems,
must
comply
with
the
specifications
provided
by
the
engine
manufacturer.
(
5)
The
original
emissions
related
label
must
remain
clearly
visible
on
the
engine.
(
6)
The
engine
dresser
must
notify
purchasers
that
the
marine
engine
is
a
dressed
highway,
nonroad,
or
locomotive
engine
and
is
exempt
from
the
requirements
of
40
CFR
part
94.
(
7)
The
engine
dresser
must
report
annually
to
us
the
models
that
are
exempt
pursuant
to
this
provision
and
such
other
information
as
we
deem
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2002
/
Rules
and
Regulations
necessary
to
ensure
appropriate
use
of
the
exemption.
Any
engine
dresser
not
meeting
all
these
conditions
will
be
considered
an
engine
manufacturer
and
will
accordingly
need
to
obtain
a
certificate
of
conformity
for
these
new
engines,
consistent
with
this
rule's
provisions,
and
label
the
engine
showing
that
it
is
available
for
use
as
a
marine
engine.
An
engine
dresser
violating
the
above
criteria
might
be
liable
under
antitampering
provisions
for
any
change
made
to
the
land
based
engine
that
affects
emissions.
The
dresser
might
also
be
subject
to
a
compliance
action
for
selling
new
marine
engines
that
are
not
certified
to
the
required
emission
standards.
For
an
engine
dresser
complying
with
the
above
provisions,
the
original
certificate
would
remain
in
effect
and
the
certifier
of
the
engine
would
remain
liable
for
the
emissions
performance
of
the
engine.
2.
What
Special
Provisions
Is
EPA
Adopting
for
Small
Entities?
In
addition
to
provisions
for
engine
dressers,
we
are
also
finalizing
special
provisions
designed
to
provide
flexibility
to
small
entities.
Prior
to
the
proposal,
we
conducted
an
inter
agency
Small
Business
Advocacy
Review
Panel
as
described
in
Section
XI.
C.
With
input
from
small
entity
representatives,
the
panel
drafted
a
report
with
findings
and
recommendations
on
how
to
reduce
the
potential
small
business
burden
resulting
from
this
rule.
The
interagency
panel's
recommendations
were
proposed
by
EPA
and
are
now
being
finalized
as
proposed.
The
following
sections
describe
these
provisions.
3.
What
Are
the
Burden
Reduction
Approaches
for
Small
Volume
Engine
Marinizers?
We
are
providing
additional
options
for
small
volume
engine
marinizers.
The
purpose
of
these
options
is
to
reduce
the
burden
on
companies
for
which
fixed
costs
cannot
be
distributed
over
a
large
number
of
engines.
For
this
reason,
we
are
defining
a
small
volume
engine
manufacturer
based
on
annual
U.
S.
sales
of
engines
and
are
providing
the
additional
options
on
this
basis
rather
than
on
business
size
in
terms
of
number
of
employees,
revenue,
or
other
such
measures.
The
production
count
we
are
using
includes
all
engines
(
automotive,
other
nonroad,
etc.)
and
not
just
recreational
marine
engines.
We
consider
recreational
marine
diesel
engine
manufacturers
to
be
small
volume
for
purposes
of
this
provision
if
they
produce
fewer
than
1,000
internal
combustion
engines
per
year.
Based
on
our
characterization
of
the
industry,
there
is
a
natural
break
in
production
volumes
above
500
engine
sales
where
the
next
smallest
manufacturers
make
tens
of
thousands
of
engines.
We
chose
1,000
engines
as
a
limit
because
it
groups
together
all
the
marinizers
most
needing
relief,
while
still
allowing
for
reasonable
sales
growth.
The
options
for
small
volume
marinizers
are
discussed
below.
a.
Broaden
engine
families.
We
have
established
engine
criteria
for
distinguishing
between
engine
families,
which
is
intended
to
divide
a
manufacturer's
product
line
into
multiple
engine
families.
We
are
allowing
small
volume
marinizers
to
put
all
of
their
models
into
one
engine
family
(
or
more
as
necessary)
for
certification
purposes.
Marinizers
would
then
certify
using
the
``
worstcase
configuration.
This
approach
is
consistent
with
the
option
offered
to
post
manufacture
marinizers
under
the
commercial
marine
regulations.
The
advantage
of
this
approach
is
that
it
minimizes
certification
testing
because
the
marinizer
can
use
a
single
engine
in
the
first
year
to
certify
their
whole
product
line.
As
for
large
companies,
the
small
volume
manufacturers
could
then
carry
over
data
from
year
to
year
until
changing
engine
designs
in
a
way
that
might
significantly
affect
emissions.
We
understand
that
this
option
alone
still
requires
a
certification
test
and
the
associated
burden
for
small
volume
manufactures.
We
consider
this
to
be
the
foremost
cost
concern
for
some
small
volume
manufacturers,
because
the
test
costs
are
spread
over
low
sales
volumes.
Also,
we
recognize
that
it
may
be
difficult
to
determine
the
worst
case
emitter
without
additional
testing.
We
are
requiring
testing
because
we
need
a
reliable,
test
based
technical
basis
to
issue
a
certificate
for
these
engines.
Manufacturers
will
be
able
to
use
carryover
to
spread
costs
over
multiple
years
of
production.
b.
Minimize
compliance
requirements.
Production
line
and
deterioration
testing
requirements
do
not
apply
to
small
volume
marinizers.
We
will
assign
a
deterioration
factor
for
use
in
calculating
end
of
life
emission
factors
for
certification.
The
advantages
of
this
approach
would
be
to
minimize
compliance
testing.
Production
line
and
deterioration
testing
would
be
more
extensive
than
a
single
certification
test.
c.
Expand
engine
dresser
flexibility.
We
are
expanding
the
engine
dresser
definition
for
small
volume
marinizers
to
include
water
cooled
turbochargers
where
the
goal
is
to
match
the
performance
of
the
non
water
cooled
turbocharger
on
the
original
certified
configuration.
We
believe
this
would
provide
more
opportunities
for
diesel
marinizers
to
be
excluded
from
certification
testing
if
they
operate
as
dressers.
d.
Streamlined
certification.
We
will
allow
small
volume
marinizers
to
certify
to
the
not
to
exceed
(
NTE)
requirements
with
a
streamlined
approach.
We
believe
small
volume
marinizers
can
make
a
satisfactory
showing
that
they
meet
NTE
standards
with
limited
test
data.
Similar
to
the
standard
NTE
program,
once
these
manufacturers
test
engines
over
the
five
mode
certification
duty
cycle
(
E5),
they
can
use
those
or
other
test
points
to
extrapolate
the
results
to
the
rest
of
the
NTE
zone.
For
example,
an
engineering
analysis
may
consider
engine
timing
and
fueling
rate
to
determine
how
much
the
engine's
emissions
may
change
at
points
not
included
in
the
E5
cycle.
For
this
streamlined
NTE
approach,
keeping
all
four
test
modes
of
the
E5
cycle
within
the
NTE
standards
will
be
enough
for
small
volume
marinizers
to
certify
compliance
with
NTE
requirements,
as
long
as
there
are
no
significant
changes
in
timing
or
fueling
rate
between
modes.
e.
Delay
standards
for
five
years.
Applying
a
five
year
delay,
the
standards
take
effect
from
2011
to
2014
for
small
volume
marinizers,
depending
on
engine
size.
Marinizers
may
apply
this
five
year
delay
to
all
or
just
a
portion
of
their
production.
They
may
therefore
still
sell
engines
that
meet
the
standards
when
possible
on
some
product
lines
while
delaying
introduction
of
emission
control
technology
on
other
product
lines.
This
option
provides
more
time
for
small
marinizers
to
redesign
their
products,
allowing
time
to
learn
from
the
technology
development
of
the
rest
of
the
industry.
Boat
builders
may
use
these
uncertified
engines
in
their
vessels.
While
we
are
concerned
about
the
loss
of
emission
control
from
part
of
the
fleet
during
this
time,
we
recognize
the
special
needs
of
small
volume
marinizers
and
believe
the
added
time
may
be
necessary
for
these
companies
to
comply
with
emission
standards.
This
additional
time
will
allow
small
volume
marinizers
to
obtain
and
implement
proven,
cost
effective
emission
control
technology.
f.
Hardship
provisions.
We
are
adopting
two
hardship
provisions
for
small
volume
marinizers.
Marinizers
may
apply
for
this
relief
on
an
annual
basis.
First,
small
marinizers
may
petition
us
for
additional
time
to
comply
with
the
standards.
The
marinizer
must
show
that
it
has
taken
all
possible
steps
to
comply
but
the
burden
of
compliance
costs
will
have
a
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major
impact
on
the
company's
solvency.
Also,
if
a
certified
base
engine
is
available,
the
marinizer
must
generally
use
this
engine.
We
believe
this
provision
will
protect
small
volume
marinizers
from
undue
hardship
due
to
certification
burden.
Also,
some
emission
reduction
can
be
gained
if
a
certified
base
engine
becomes
available.
Second,
small
volume
marinizers
may
also
apply
for
hardship
relief
if
circumstances
outside
their
control
caused
the
failure
to
comply
(
such
as
a
supply
contract
broken
by
parts
supplier)
and
if
failure
to
sell
the
subject
engines
will
have
a
major
impact
on
the
company's
solvency.
We
consider
this
relief
mechanism
to
be
an
option
of
last
resort.
We
believe
this
provision
will
protect
small
volume
marinizers
from
circumstances
outside
their
control.
We,
however,
intend
to
not
grant
hardship
relief
if
contract
problems
with
a
specific
company
prevent
compliance
for
a
second
time.
Although
the
inter
agency
panel
did
not
specify
a
time
limit
for
these
hardship
provisions,
and
we
are
not
finalizing
any
such
time
limits,
we
envision
these
hardship
provisions
as
transitional
in
nature.
We
would
expect
their
use
to
be
limited
to
the
early
years
of
the
program,
in
a
similar
time
frame
as
we
are
establishing
for
the
recreational
vehicle
hardship
provisions,
as
discussed
in
Section
VII.
C.
4.
What
Are
the
Burden
Reduction
Approaches
for
Small
Volume
Boat
Builders
Using
Recreational
Marine
Diesel
Engines?
The
inter
agency
panel
also
recommended
burden
reduction
approaches
for
small
volume
boat
builders.
The
recommendations
were
based
on
the
concerns
that,
although
boat
builders
are
not
subject
to
the
engine
based
emission
standards,
they
are
required
to
use
certified
engines
and
may
need
to
redesign
engine
compartments
on
some
boats
if
engine
designs
were
to
change
significantly.
EPA
proposed
the
flexibilities
recommended
by
the
panel
and
are
finalizing
them
as
proposed.
We
are
adopting
four
options
for
small
volume
vessel
manufacturers
using
recreational
marine
diesel
engines.
These
options
are
intended
to
reduce
the
burden
on
companies
for
which
fixed
costs
cannot
be
distributed
over
a
large
number
of
vessels.
As
proposed,
we
are
therefore
defining
a
small
volume
boat
builder
as
one
that
produces
fewer
than
100
boats
for
sale
in
the
U.
S.
in
one
year
and
has
fewer
than
500
employees.
The
production
count
includes
all
engine
powered
recreational
boats.
These
options
may
be
used
at
the
manufacturer's
discretion.
The
options
for
small
volume
boat
builders
are
discussed
below.
a.
Percent
of
production
delay.
Manufacturers
with
a
written
request
from
a
small
volume
boat
builder
and
prior
approval
from
us
may
produce
a
limited
number
of
uncertified
recreational
marine
diesel
engines.
From
2006
through
2010,
small
volume
boat
builders
may
purchase
uncertified
engines
to
sell
in
boats
for
an
amount
equal
to
80
percent
of
engine
sales
for
one
year.
For
example,
if
the
small
boat
builder
sells
100
engines
per
year,
a
total
of
80
uncertified
engines
may
be
sold
over
the
five
year
period.
This
will
give
small
boat
builders
an
option
to
delay
using
new
engine
designs
for
a
portion
of
business.
Engines
produced
under
this
flexibility
must
be
labeled
accordingly
so
that
customs
inspectors
know
which
uncertified
engines
can
be
imported.
We
continue
to
believe
this
approach
is
appropriate
and
are
finalizing
it
as
proposed.
b.
Small
volume
allowance.
This
allowance
is
similar
to
the
percent
ofproduction
allowance,
but
is
designed
for
boat
builders
with
very
small
production
volumes.
The
only
difference
with
the
above
allowance
is
that
the
80
percent
allowance
described
above
may
be
exceeded,
as
long
as
sales
do
not
exceed
either
10
engines
per
year
or
20
engines
over
five
years
(
2006
to
2010).
This
applies
only
to
engines
less
than
or
equal
to
2.5
liters
per
cylinder.
c.
Existing
inventory
and
replacement
engine
allowance.
Small
volume
boat
builders
may
sell
their
existing
inventory
after
the
implementation
date
of
the
new
standards.
However,
no
purposeful
stockpiling
of
uncertified
engines
is
permitted.
This
provision
is
intended
to
allow
small
boat
builders
the
ability
to
turn
over
engine
designs.
d.
Hardship
relief
provision.
Small
boat
builders
may
apply
for
hardship
relief
if
circumstances
outside
their
control
caused
the
problem
(
for
example,
if
a
supply
contract
were
broken
by
the
engine
supplier)
and
if
failure
to
sell
the
subject
vessels
will
have
a
major
impact
on
the
company's
solvency.
This
relief
allows
the
boat
builder
to
use
an
uncertified
engine
and
is
considered
a
mechanism
of
last
resort.
These
hardship
provisions
are
consistent
with
those
currently
in
place
for
post
manufacture
marinizers
of
commercial
marine
diesel
engines.
F.
Technical
Amendments
The
regulations
include
a
variety
of
amendments
to
the
programs
already
adopted
for
marine
spark
ignition
and
diesel
engines,
as
described
in
the
following
paragraphs.
1.
40
CFR
Part
91:
Outboards
and
Personal
Watercraft
We
have
identified
four
principal
amendments
to
the
requirements
for
outboard
and
personal
watercraft
engines.
First,
we
are
adding
a
definition
of
United
States
which
is
``
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.''
This
definition
is
consistent
with
that
included
in
40
CFR
part
94
for
marine
diesel
engines.
This
is
especially
helpful
in
clearing
up
questions
related
to
U.
S.
territories
in
the
Carribean
Sea
and
the
Pacific
Ocean.
Second,
we
have
found
two
typographical
errors
in
the
equations
needed
for
calculating
emission
levels
in
40
CFR
91.419.
Third,
we
are
adjusting
the
regulation
language
to
clarify
testing
rates
for
the
in
use
testing
program.
The
regulations
currently
specify
a
maximum
rate
of
25
percent
of
a
manufacturer's
engine
families
subject
to
in
use
testing.
The
revised
language
states
that
for
manufacturers
with
fewer
than
four
engine
families
subject
to
in
use
testing,
the
maximum
testing
rate
is
one
family
per
year
in
place
of
the
percentage
calculation.
Finally,
we
are
revising
the
regulatory
provision
prohibiting
emission
controls
that
lead
to
increases
of
noxious
or
toxic
compounds
that
would
pose
an
unreasonable
risk
to
the
public,
as
described
in
Section
II.
B.
2.
2.
40
CFR
Part
94:
Commercial
Marine
Diesel
Engines
We
are
adopting
several
regulatory
amendments
to
the
program
for
commercial
marine
diesel
engines.
Many
of
these
are
straightforward
edits
for
correct
grammar
and
cross
references.
We
are
also
changing
the
definition
of
United
States,
as
described
in
the
previous
section.
We
are
adding
a
definition
for
sparkignition
consistent
with
the
existing
definition
for
compression
ignition,
which
will
allow
us
to
define
compression
ignition
as
any
engine
that
is
not
spark
ignition.
This
will
help
ensure
that
marine
emission
standards
for
the
different
types
of
engines
fit
together
appropriately.
The
discussion
of
production
line
testing
in
Section
II.
C.
4
specifies
reduced
testing
rates
after
two
years
of
consistent
good
performance.
We
are
extending
this
provision
to
commercial
marine
diesel
engines
as
well.
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The
test
procedures
for
Category
2
marine
engines
give
a
cross
reference
to
40
CFR
part
92,
which
defines
the
procedures
for
testing
locomotives
and
locomotive
engines.
Part
92
specifies
a
wide
range
of
ambient
temperatures
for
testing,
to
allow
for
outdoor
measurements.
We
expect
all
testing
of
Category
2
marine
engines
to
occur
indoors
and
are
therefore
adopting
a
range
of
13
°
to
30
°
C
(
55
°
to
86
°
F)
for
emission
testing.
Finally,
we
are
revising
the
regulatory
provision
prohibiting
emission
controls
that
lead
to
increases
of
noxious
or
toxic
compounds
that
would
pose
an
unreasonable
risk
to
the
public,
as
described
in
Section
II.
B.
2.
G.
Technological
Feasibility
We
have
concluded
that
the
emissionreduction
strategies
expected
for
landbased
nonroad
diesel
engines
and
commercial
marine
diesel
engines
can
also
be
applied
to
recreational
marine
diesel
engines,
such
that
these
emission
reductions
strategies
will
provide
compliance
with
recreational
marine
diesel
emission
standards.
Marine
diesel
engines
are
generally
derivatives
of
land
based
nonroad
and
highway
diesel
engines.
Marine
engine
manufacturers
and
marinizers
make
modifications
to
the
engine
to
make
it
ready
for
use
in
a
vessel.
These
modifications
can
range
from
basic
engine
mounting
and
cooling
changes
to
a
restructuring
of
the
power
assembly
and
fuel
management
system.
Chapters
3
and
4
of
the
Final
Regulatory
Support
Document
discuss
this
process
in
more
detail.
Also,
we
have
collected
emission
data
demonstrating
the
feasibility
of
the
steady
state
average
standard
and
not
to
exceed
requirements.
These
data
are
presented
in
Chapter
4
of
the
Final
Regulatory
Support
Document.
1.
Implementation
Schedule
For
recreational
marine
diesel
engines,
the
implementation
schedule
allows
an
additional
two
years
of
delay
beyond
the
commercial
marine
diesel
standards.
This
represents
up
to
a
fiveyear
lead
time
relative
to
the
implementation
dates
of
the
land
based
nonroad
standards.
This
allows
time
for
the
carryover
of
technology
from
landbased
nonroad
and
commercial
marine
diesel
engines.
In
addition,
these
implementation
dates
represent
three
to
six
years
of
lead
time
beyond
publication
of
this
final
rule.
2.
Standard
Levels
Marine
diesel
engines
are
typically
derived
from
or
use
the
same
technology
as
land
based
nonroad
and
commercial
marine
diesel
engines
and
should
therefore
be
able
to
effectively
use
the
same
emission
control
strategies.
In
fact,
recreational
marine
engines
can
better
use
the
water
they
operate
in
as
a
cooling
medium
compared
with
commercial
marine,
because
they
are
able
to
use
raw
water
aftercooling.
This
can
help
them
reduce
charge
air
intake
temperatures
more
easily
than
the
commercial
models
and
much
more
easily
than
land
based
nonroad
diesel
engines.
Cooling
the
intake
charge
reduces
the
formation
of
NOX
emissions
and
thus
indirectly
enables
other
HC
and
PM
control
strategies.
As
a
result,
baseline
recreational
engines
generally
have
lower
NOX
emissions
than
uncontrolled
commercial
marine
engines.
Therefore,
we
believe
that
recreational
marine
engines
can
meet
the
same
standard
levels
as
are
in
place
for
commercial
marine
engines
without
sacrificing
power
or
increasing
weight
of
the
engine.
3.
Technological
Approaches
We
anticipate
that
manufacturers
will
meet
the
new
emission
standards
for
recreational
marine
diesel
engines
primarily
with
technology
that
will
be
applied
to
land
based
nonroad
and
commercial
marine
diesel
engines.
Much
of
this
technology
has
already
been
established
in
highway
applications
and
is
being
used
in
limited
land
based
nonroad
and
marine
applications.
Our
analysis
of
this
technology
is
described
in
detail
in
Chapters
3
and
4
of
the
Final
Regulatory
Support
Document
and
is
summarized
here.
By
adopting
standards
that
don't
go
into
place
until
2006,
we
are
providing
engine
manufacturers
with
substantial
lead
time
for
developing,
testing,
and
implementing
emission
control
technologies.
This
lead
time
and
the
coordination
of
standards
with
those
for
land
based
nonroad
engines
allows
time
for
a
comprehensive
program
to
integrate
the
most
effective
emissioncontrol
approaches
into
the
manufacturers'
overall
design
goals
related
to
durability,
reliability,
and
fuel
consumption.
Engine
manufacturers
have
already
produced
limited
numbers
of
low
NOX
marine
diesel
engines.
More
than
80
of
these
engines
have
been
placed
into
service
in
California
through
demonstration
programs.
Through
the
demonstration
programs,
we
were
able
to
gain
some
insight
into
what
technologies
can
be
used
to
meet
the
new
emission
standards.
Chapter
4
presents
data
on
25
of
these
engines
tested
over
the
E5
duty
cycle.
Although
only
one
of
these
engines
has
been
shown
to
meet
the
HC+
NOX
and
PM
standards,
many
of
these
engines
are
well
below
either
the
HC+
NOX
or
PM
standards
or
are
close
to
meeting
both.
With
further
optimization,
we
believe
these
engine
designs
can
be
used
to
meet
the
exhaust
emission
standards
for
recreational
marine
diesel
engines.
Highway
engines
have
been
the
leaders
in
developing
new
emissioncontrol
technology
for
diesel
engines.
Because
of
the
similar
engine
designs
in
land
based
nonroad
and
marine
diesel
engines,
it
is
clear
that
much
of
the
technological
development
that
has
led
to
lower
emitting
highway
engines
can
be
transferred
or
adapted
for
use
on
land
based
nonroad
and
marine
engines.
Much
of
the
improvement
in
emissions
from
these
engines
comes
from
``
internal''
engine
changes
such
as
variation
in
fuel
injection
variables
(
injection
timing,
injection
pressure,
spray
pattern,
rate
shaping),
modified
piston
bowl
geometry
for
better
air
fuel
mixing,
and
improvements
intended
to
reduce
oil
consumption.
Introduction
and
ongoing
improvement
of
electronic
controls
have
played
a
vital
role
in
facilitating
many
of
these
improvements.
Turbocharging
is
widely
used
now
in
marine
applications,
especially
in
larger
engines,
because
it
improves
power
and
efficiency
by
compressing
the
intake
air.
Turbocharging
may
also
be
used
to
decrease
particulate
emissions
in
the
exhaust.
Today,
marine
engine
manufacturers
generally
have
to
rematch
the
turbocharger
to
the
engine
characteristics
of
the
marine
version
of
a
nonroad
engine
and
often
will
add
water
jacketing
around
the
turbocharger
housing
to
keep
surface
temperatures
low.
Once
the
nonroad
Tier
2
engines
are
available
to
the
marine
industry,
matching
the
turbochargers
for
the
engines
will
be
an
important
step
in
achieving
low
emissions.
Aftercooling
is
a
well
established
technology
for
reducing
NOX
by
decreasing
the
temperature
of
the
charge
air
after
it
has
been
heated
during
compression.
Decreasing
the
charge
air
temperature
directly
reduces
the
peak
cylinder
temperature
during
combustion,
which
is
the
primary
cause
of
NOX
formation.
Air
to
water
and
water
to
water
aftercoolers
are
well
established
for
land
based
applications.
For
engines
in
marine
vessels,
there
are
two
different
types
of
aftercooling:
jacket
water
and
raw
water
aftercooling.
With
jacket
water
aftercooling,
the
fluid
that
extracts
heat
from
the
aftercooler
is
itself
cooled
by
ambient
water.
This
cooling
circuit
may
either
be
the
same
circuit
used
to
cool
the
engine
or
it
may
be
a
separate
circuit.
By
incorporating
a
separate
circuit,
marine
engine
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manufacturers
can
further
reduce
charge
air
temperatures.
This
separate
circuit
can
result
in
even
lower
temperatures
with
raw
water
as
the
coolant.
This
means
that
ambient
water
is
pumped
directly
to
the
aftercooler.
Raw
water
aftercooling
is
currently
widely
used
in
recreational
applications.
Because
of
the
access
that
marine
engines
have
to
a
large
ambient
water
cooling
medium,
we
anticipate
that
marine
diesel
engine
manufacturers
will
largely
reduce
NOX
emissions
with
aftercooling.
Electronic
controls
also
offer
great
potential
for
improved
control
of
engine
parameters
for
better
performance
and
lower
emissions.
Unit
pumps
or
injectors
allow
higher
pressure
fuel
injection
with
rate
shaping
to
carefully
time
the
delivery
of
the
whole
volume
of
injected
fuel
into
the
cylinder.
Marine
engine
manufacturers
can
take
advantage
of
modifications
to
the
routing
of
the
intake
air
and
the
shape
of
the
combustion
chamber
of
nonroad
engines
for
improved
mixing
of
the
fuelair
charge.
Separate
circuit
aftercooling
(
both
jacket
water
and
raw
water)
will
likely
gain
widespread
use
in
turbocharged
engines
to
increase
performance
and
lower
NOX.
Fuel
injection
changes
and
other
NOX
control
strategies
typically
reduce
engine
noise,
sometimes
dramatically.
One
important
source
of
noise
in
diesel
combustion
is
the
sound
associated
with
the
combustion
event
itself.
When
a
premixed
charge
of
fuel
and
air
ignites,
the
very
rapid
combustion
leads
to
a
sharp
increase
in
pressure,
which
is
easily
heard
and
recognized
as
the
characteristic
sound
of
a
diesel
engine.
The
conditions
that
lead
to
high
noise
levels
also
cause
high
levels
of
NOX
formation.
The
impact
of
the
new
emission
standards
on
energy
is
measured
by
the
effect
on
fuel
consumption
from
complying
engines.
Many
of
the
marine
engine
manufacturers
are
expected
to
retard
engine
timing
which
increases
fuel
consumption
somewhat.
Most
of
the
technology
changes
anticipated
in
response
to
the
new
standards,
however,
have
the
potential
to
reduce
fuel
consumption
as
well
as
emissions.
Redesigning
combustion
chambers,
incorporating
improved
fuel
injection
systems,
and
introducing
electronic
controls
provide
the
engine
designer
with
powerful
tools
for
improving
fuel
efficiency
while
simultaneously
controlling
emission
formation.
To
the
extent
that
manufacturers
add
aftercooling
to
non
aftercooled
engines
and
shift
from
jacket
water
aftercooling
to
raw
water
aftercooling,
there
will
be
a
marked
improvement
in
fuelefficiency
Manufacturers
of
highway
diesel
engines
have
been
able
to
steadily
improve
fuel
efficiency
even
as
new
emission
standards
required
significantly
reduced
emissions.
There
are
no
apparent
safety
issues
associated
with
the
new
emission
standards.
Marine
engine
manufacturers
will
likely
use
only
proven
technology
that
is
currently
used
in
other
engines
such
as
nonroad
land
based
diesel
applications,
locomotives,
and
diesel
trucks.
The
main
technological
approach
will
likely
be
optimization
and
calibration
of
their
fuel
injection
and
air
management
systems.
4.
Our
Conclusions
The
new
emission
standards
for
recreational
marine
diesel
engines
reasonably
reflect
what
manufacturers
can
achieve
through
the
application
of
available
technology
to
current
recreational
marine
diesel
engines.
Recreational
marine
engine
manufacturers
will
need
to
use
the
available
lead
time
to
develop
the
necessary
emission
control
strategies,
including
transfer
of
technology
from
land
based
nonroad
and
commercial
marine
diesel
engines.
This
development
effort
will
require
not
only
achieving
the
targeted
emission
levels,
but
also
ensuring
that
each
engine
will
meet
all
performance
and
emission
requirements
over
its
useful
life.
As
discussed
in
Section
IX,
the
new
standards
represent
significant
reductions
compared
with
baseline
emission
levels.
Based
on
information
currently
available,
we
conclude
it
is
feasible
for
recreational
marine
diesel
engine
manufacturers
to
meet
the
new
emission
standards
using
combinations
of
technological
approaches
discussed
above
and
in
Chapters
3
and
4
of
the
Final
Regulatory
Support
Document.
While
the
technologies
described
above
are
expected
to
yield
the
full
degree
of
emission
reduction
anticipated,
it
is
possible
that
manufacturers
may
also
rely
on
a
modest
degree
of
fuel
injection
timing
retard
as
a
strategy
for
complying
with
emission
standards.
This
is
due
to
variations
in
engine
designs
and
baseline
injection
timing.
For
instance,
an
engine
with
very
advanced
injection
timing
in
its
baseline
configuration
would
likely
need
to
employ
some
timing
retard
to
meet
the
standards.
The
transfer
of
technology
from
landbased
nonroad
and
commercial
marine
engines
is
an
important
factor
in
our
determination
that
the
recreational
marine
diesel
engine
standards
are
feasible.
Most
marine
diesel
engine
models
also
serve
in
land
based
applications.
Sales
of
land
based
versions
of
these
engines
are
usually
much
greater
than
those
of
the
marine
counterpart
versions,
so
manufacturers
typically
focus
their
primary
technology
development
efforts
on
their
land
based
products.
Manufacturers
then
modify
these
engines
for
use
in
marine
applications.
These
changes
can
be
extensive,
but
they
rarely
involve
basic
R&
D
for
new
technologies.
We
do
not
anticipate
the
use
of
advanced
technology
such
as
particulate
filters
and
NOX
adsorbers
on
trucks
until
the
2007
time
frame.
Therefore,
we
do
not
believe
that
it
would
be
appropriate
to
implement
standards,
at
this
time,
that
would
require
the
use
of
advanced
technology
that
has
yet
to
be
developed
for
the
higher
volume
land
based
diesel
engine
market.
We
would,
however,
consider
this
technology
in
the
future
for
setting
further
tiers
of
marine
engine
emission
standards.
In
addition,
we
have
incorporated
various
options
that
will
permit
marinizers
and
boat
builders
to
respond
to
engine
changes
in
an
orderly
way.
We
expect
that
meeting
these
requirements
will
pose
a
challenge,
but
one
that
is
feasible
taking
into
consideration
the
availability
and
cost
of
technology,
time,
noise,
energy,
and
safety.
VII.
General
Nonroad
Compliance
Provisions
This
section
describes
a
wide
range
of
compliance
provisions
that
apply
generally
to
all
the
spark
ignition
engines
and
vehicles
subject
to
the
new
emission
standards.
Several
of
these
provisions
apply
not
only
to
manufacturers
and
importers,
but
also
to
equipment
manufacturers
installing
certified
engines,
remanufacturing
facilities,
operators,
and
others.
The
regulatory
text
for
the
compliance
requirements
for
Large
SI
engines
and
recreational
vehicles
are
in
a
new
Part
1068
of
Title
40,
entitled
``
General
Compliance
Programs
for
Nonroad
Engines.''
The
compliance
provisions
for
recreational
marine
diesel
engines
are
generally
the
same
as
those
already
adopted
for
commercial
marine
diesel
engines
(
40
CFR
part
94).
The
following
discussion
of
the
general
nonroad
provisions
follows
the
regulatory
text.
For
ease
of
reference,
the
subpart
designations
for
40
CFR
part
1068
are
provided.
Where
different
provisions
apply
to
the
marine
engines,
we
note
those
differences
in
this
section.
A.
Miscellaneous
Provisions
(
Part
1068,
Subpart
A)
This
subpart
contains
general
provisions
to
define
terms
and
the
scope
of
application
for
all
of
40
CFR
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Rules
and
Regulations
85
EPA
acted
to
adjust
the
maximum
penalty
amount
in
1996
(
61
FR
69364,
December
31,
1996)
and
2002
(
67
FR
41343,
June
18,
2002).
See
also
40
CFR
part
19.
1068.
Other
provisions
concern
how
we
handle
confidential
information,
how
the
EPA
Administrator
delegates
decision
making
authority,
and
when
we
may
inspect
a
manufacturer's
facilities,
engines,
or
records.
The
process
of
testing
engines
and
preparing
an
application
for
certification
requires
the
manufacturer
to
make
a
variety
of
judgments.
This
includes,
for
example,
selecting
test
engines,
operating
engines
between
tests,
and
developing
deterioration
factors.
The
regulations
describe
the
methodology
we
use
to
evaluate
concerns
related
to
how
manufacturers
use
good
engineering
judgment
in
cases
where
the
manufacturer
has
such
discretion
(
see
40
CFR
1068.5
and
40
CFR
94.221).
If
we
find
a
problem
in
these
areas,
we
will
take
into
account
the
degree
to
which
any
error
in
judgment
was
deliberate
or
in
bad
faith.
This
subpart
is
consistent
with
provisions
already
adopted
for
lightduty
highway
vehicles
and
commercial
marine
diesel
engines.
B.
Prohibited
Acts
and
Related
Requirements
(
Part
1068,
Subpart
B)
The
provisions
in
this
subpart
establish
a
set
of
prohibitions
for
engine
manufacturers
(
including
importers),
equipment
manufacturers,
operators,
engine
rebuilders,
and
owners/
operators
to
ensure
that
engines
meet
the
emission
standards.
These
provisions
are
intended
to
help
ensure
that
each
new
engine
sold
or
otherwise
entered
into
commerce
in
the
United
States
is
certified
to
the
relevant
standards,
that
it
remains
in
its
certified
configuration
throughout
its
lifetime,
and
that
only
certified
engines
are
used
in
the
appropriate
nonroad
equipment.
1.
General
Prohibitions
(
§
1068.101)
This
regulation
contains
several
prohibitions
consistent
with
the
Clean
Air
Act.
No
one
may
sell
a
new
engine
subject
to
the
emission
standards
(
or
equipment
containing
such
an
engine)
in
the
United
States
without
a
valid
certificate
of
conformity
issued
by
EPA,
deny
us
access
to
relevant
records,
or
keep
us
from
entering
a
facility
to
test
or
inspect
engines.
In
addition,
no
one
may
remove
or
disable
a
device
or
design
element
that
may
affect
an
engine's
emission
levels,
or
manufacture
any
device
that
will
make
emission
controls
ineffective,
which
we
consider
tampering.
Other
prohibitions
reinforce
manufacturers'
obligations
to
meet
various
certification
requirements.
We
also
prohibit
selling
engine
parts
that
prevent
emission
control
systems
from
working
properly.
Finally,
for
engines
that
are
excluded
because
they
are
used
in
applications
not
covered
by
these
regulations
(
for
example,
stationary
or
solely
for
competition),
we
generally
prohibit
using
these
engines
in
regulated
applications.
These
prohibitions
are
the
same
as
those
that
apply
to
other
engines
we
have
regulated
in
previous
rulemakings.
Each
prohibited
act
has
a
corresponding
maximum
penalty
as
specified
in
Clean
Air
Act
section
205.
As
provided
for
in
the
Federal
Civil
Penalties
Inflation
Adjustment
Act
of
1990,
Pub.
L.
10
410,
these
maximum
penalties
are
periodically
adjusted
by
regulation
to
account
for
inflation.
The
current
penalty
amount
for
each
violation
is
$
31,500.85
2.
Equipment
Manufacturer
Provisions
(
§
1068.105)
Equipment
manufacturers
may
not
sell
new
equipment
with
uncertified
engines
once
the
emission
standards
begin
to
apply.
We
allow
a
grace
period
for
equipment
manufacturers
to
use
up
their
supply
of
uncertified
engines,
as
long
as
they
follow
their
normal
inventory
practices
for
buying
engines.
We
require
equipment
manufacturers
to
observe
the
engine
manufacturers'
emission
related
installation
specifications
to
ensure
that
the
engine
remains
in
its
certified
configuration.
This
may
include
such
things
as
radiator
specifications,
placement
of
catalytic
converters,
diagnostic
signals
and
interfaces,
and
steps
to
minimize
evaporative
emissions.
If
equipment
manufacturers
install
a
certified
engine
in
a
way
that
obscures
the
engine
label,
they
must
add
a
duplicate
label
on
the
equipment.
If
equipment
manufacturers
don't
fulfill
the
responsibilities
we
describe
in
this
section,
we
consider
them
to
be
violating
one
or
more
of
the
prohibited
acts
described
above.
3.
In
Service
Engines
(
§
1068.110)
The
regulations
prevent
manufacturers
from
requiring
owners
to
use
any
certain
brand
of
aftermarket
parts
and
give
the
manufacturer
responsibility
for
engine
servicing
related
to
emissions
warranty,
leaving
the
responsibility
for
all
other
maintenance
with
the
owner.
This
regulation
also
reserves
our
right
to
do
testing
(
or
require
testing)
to
determine
compliance
with
emission
standards
and
investigate
potential
defeat
devices,
as
authorized
by
the
Act.
4.
Engine
Rebuilding
(
§
1068.120)
We
are
establishing
rebuild
provisions
for
all
the
nonroad
engines
subject
to
the
emission
standards
in
this
final
rule.
This
approach
is
similar
to
what
applies
to
heavy
duty
highway
engines,
nonroad
diesel
engines,
and
commercial
marine
diesel
engines.
This
is
necessary
to
prevent
an
engine
rebuilder
from
rebuilding
engines
in
a
way
that
disables
the
engine's
emission
controls
or
compromises
the
effectiveness
of
the
emission
control
system.
For
businesses
involved
in
commercial
engine
rebuilding,
we
are
adopting
minimal
recordkeeping
requirements
so
rebuilders
can
show
that
they
comply
with
regulations.
In
general,
we
require
anyone
rebuilding
a
certified
engine
to
restore
it
to
its
original
(
or
a
lower
emitting)
configuration.
We
are
adding
unique
requirements
for
rebuilders
to
replace
some
critical
emission
control
components
such
as
fuel
injectors
and
oxygen
sensors
in
all
rebuilds
for
engines
that
use
those
technologies,
unless
there
is
reason
to
believe
that
those
components
are
still
working
properly.
We
also
require
that
rebuilders
replace
an
existing
catalyst
if
there
is
evidence
that
it
is
not
functional;
for
example,
if
a
catalyst
has
lost
its
physical
integrity
with
loose
pieces
rattling
inside,
it
would
need
to
be
replaced.
The
rebuilding
provisions
define
good
rebuilding
practices
to
avoid
violating
the
prohibition
on
``
removing
or
disabling''
emission
control
systems.
We
are
therefore
extending
these
provisions
to
individuals
who
rebuild
their
own
engines,
but
without
any
recordkeeping
requirements.
C.
Exemptions
(
Part
1068,
Subpart
C)
We
are
including
several
exemptions
for
certain
specific
situations.
Most
of
these
are
consistent
with
previous
rulemakings.
We
highlight
the
new
or
different
provisions
in
the
following
paragraphs.
In
general,
exempted
engines
must
comply
with
the
requirements
only
in
the
sections
related
to
the
exemption.
Note
that
additional
restrictions
may
apply
to
importing
exempted
engines
(
see
Section
VII.
D).
Also,
we
may
require
manufacturers
(
or
importers)
to
add
a
permanent
label
describing
that
the
engine
is
exempt
from
emission
standards
for
a
specific
purpose.
In
addition
to
helping
us
enforce
emission
standards,
this
helps
ensure
that
imported
engines
clear
Customs
without
difficulty.
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Rules
and
Regulations
1.
Testing
Anyone
may
request
an
exemption
for
engines
used
only
for
research
or
other
investigative
purposes.
2.
Manufacturer
Owned
Engines
Engines
that
are
used
by
engine
manufacturers
for
development
or
marketing
purposes
may
be
exempted
from
regulation
if
they
are
maintained
in
the
manufacturers'
possession
and
are
not
used
for
any
revenue
generating
service.
3.
Display
Engines
Anyone
may
request
an
exemption
for
engines
intended
for
only
for
display.
4.
National
Security
In
general,
engines
installed
in
combat
related
equipment
are
exempt
from
emission
standards.
In
addition,
engine
manufacturers
may
request
and
receive
an
exemption
for
other
engines
if
they
are
needed
by
an
agency
of
the
federal
government
responsible
for
national
defense.
The
request
for
exemptions
in
these
cases
must
include
the
endorsement
of
the
procuring
government
agency.
5.
Exported
Engines
Engines
that
will
be
exported
to
countries
that
don't
have
the
same
emission
standards
as
those
that
apply
in
the
United
States
are
exempted
without
a
request.
This
exemption
is
not
available
if
the
destination
country
has
the
same
emission
standards
as
those
in
the
United
States.
6.
Competition
Engines
New
engines
used
solely
for
competition
are
generally
excluded
or
exempted
from
regulations
that
apply
to
nonroad
engines.
For
purposes
of
our
certification
requirements,
manufacturers
receive
an
exemption
if
they
can
show
that
they
produce
an
engine
model
specifically
for
use
solely
in
competition.
In
addition,
engines
that
have
been
modified
for
use
in
competition
are
exempt
from
the
prohibition
against
tampering
described
above
(
without
need
for
request).
The
literal
meaning
of
the
term
``
used
solely
for
competition''
would
apply
for
these
modifications.
We
therefore
do
not
allow
anyone
to
use
the
engine
for
anything
other
than
competition
once
it
has
been
modified.
This
also
applies
to
someone
who
later
buys
the
engine,
so
we
require
the
person
modifying
the
engine
to
remove
or
deface
the
original
engine
label
and
inform
a
subsequent
buyer
in
writing
of
the
conditions
of
the
exemption.
7.
Replacement
Engines
An
exemption
is
available
to
engine
manufacturers
without
request
if
that
is
the
only
way
to
replace
an
engine
from
the
field
that
was
produced
before
the
current
emission
standards
took
effect.
If
less
stringent
standards
applied
to
the
old
engine
when
it
was
new,
the
replacement
engine
must
at
a
minimum
meet
those
standards.
8.
Hardship
Related
to
Economic
Burden
There
are
two
types
of
hardship
provisions.
The
first
type
of
hardship
program
allows
small
businesses
to
petition
EPA
for
up
to
three
years
of
additional
lead
time
to
comply
with
the
standards.
A
small
manufacturer
must
demonstrate
that
it
has
taken
all
possible
business,
technical,
and
economic
steps
to
comply
but
the
burden
of
compliance
costs
will
have
a
significant
impact
on
the
company's
solvency.
A
manufacturer
must
provide
a
compliance
plan
detailing
when
and
how
it
will
achieve
compliance
with
the
standards.
Hardship
relief
may
include
requirements
for
reducing
emission
on
an
interim
basis
and/
or
purchasing
and
using
emission
credits.
The
length
of
the
hardship
relief
decided
during
review
of
the
hardship
application
may
be
up
to
one
year,
with
the
potential
to
extend
the
relief
as
needed.
The
second
hardship
program
allows
companies
to
apply
for
hardship
relief
if
circumstances
outside
their
control
cause
the
failure
to
comply
(
such
as
a
supply
contract
broken
by
parts
supplier)
and
if
the
failure
to
sell
the
subject
engines
will
have
a
major
impact
on
the
company's
solvency.
We
would,
however,
not
grant
hardship
relief
if
contract
problems
with
a
specific
company
prevent
compliance
for
a
second
time.
9.
Hardship
for
Equipment
Manufacturers
Equipment
manufacturers
in
many
cases
depend
on
engine
manufacturers
to
supply
certified
engines
in
time
to
produce
complying
equipment
by
the
date
emission
standards
begin
to
apply.
This
is
especially
true
for
industrial
and
marine
applications.
In
other
programs,
equipment
manufacturers
have
raised
concerns
of
certified
engines
being
available
too
late
for
equipment
manufacturers
to
adequately
accommodate
changing
engine
size
or
performance
characteristics.
To
address
this
concern,
in
unusual
circumstances,
equipment
manufacturers
may
request
up
to
one
extra
year
before
using
certified
engines
if
they
are
not
at
fault
and
will
face
serious
economic
hardship
without
an
extension.
In
addition,
we
are
aware
that
some
manufacturers
of
nonroad
engines
are
dependent
on
another
engine
manufacturer
to
supply
base
engines
that
are
then
modified
for
the
final
application.
Much
like
equipment
manufacturers,
these
``
secondary
engine
manufacturers''
may
face
difficulty
in
producing
certified
engines
if
the
manufacturer
selling
the
base
engine
makes
an
engine
model
unavailable
with
short
notice.
These
secondary
manufacturers
generally
each
buy
a
relatively
small
number
of
engines
and
would
therefore
not
necessarily
be
able
to
influence
the
marketing
or
sales
practices
of
the
engine
selling
the
base
engines.
In
this
rulemaking,
this
is
of
particular
concern
for
Large
SI
engine
manufacturers
subject
to
new
standards
in
2004.
As
a
result,
we
are
allowing
secondary
engine
manufacturers
to
sell
uncertified
engines
or
engines
certified
at
emission
levels
above
the
standard
for
a
short
period
after
emission
standards
begin
to
apply.
However,
these
companies
control
the
final
design
of
the
engines,
so
we
would
not
approve
any
exemption
unless
the
manufacturer
committed
to
a
plan
to
make
up
for
any
calculated
loss
in
environmental
benefit.
For
example,
based
on
an
alternate
compliance
level
for
2004
model
year
engines,
we
could
calculate
the
number
of
2006
model
year
engines
that
would
need
to
be
certified
early
to
the
2007
emission
standards.
Provisions
similar
to
these
were
adopted
for
commercial
marine
diesel
engines
and
will
apply
equally
to
recreational
marine
diesel
engines.
See
the
regulatory
text
in
40
CFR
1068.255
and
40
CFR
94.209
for
additional
information.
D.
Imports
(
Part
1068,
Subpart
D)
In
general,
the
same
certification
requirements
apply
to
engines
and
equipment
whether
they
are
produced
in
the
U.
S.
or
are
imported.
This
regulation
also
includes
some
additional
provisions
that
apply
if
someone
wants
to
import
an
exempted
or
excluded
engine.
For
example,
the
importer
needs
appropriate
documentation
before
importing
nonconforming
engines;
this
is
true
even
if
an
exemption
for
the
same
reason
doesn't
require
approval
for
engines
produced
in
the
U.
S.
These
declaration
forms
are
available
on
the
Internet
at
http://
www.
epa.
gov/
OMS/
imports/
or
by
phone
at
202
564
9660.
All
the
exemptions
described
above
for
new
engines
also
apply
to
importation,
though
some
of
these
apply
only
on
a
temporary
basis.
If
we
approve
a
temporary
exemption,
it
is
available
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2002
/
Rules
and
Regulations
only
for
a
defined
period
and
could
require
the
importer
to
post
bond
while
the
engine
is
in
the
U.
S.
There
are
several
additional
exemptions
that
apply
only
to
imported
engines.
Identical
configuration:
This
is
a
permanent
exemption
to
allow
individuals
to
import
engines
that
were
designed
and
produced
to
meet
applicable
emission
standards.
These
engines
may
not
have
the
emission
label
only
because
they
were
not
intended
for
sale
in
the
United
States.
This
exemption
applies
to
all
the
engines
covered
by
40
CFR
part
1068.
`
`
Antique''
engines:
We
generally
treat
used
engines
as
new
if
they
are
imported
without
a
certificate
of
conformity.
However,
this
permanent
exemption
allows
for
importation
of
uncertified
engines
if
they
are
more
than
20
years
old
and
still
in
their
original
configuration.
Repairs
or
alterations:
This
is
a
temporary
exemption
to
allow
companies
to
repair
or
modify
engines.
This
exemption
does
not
allow
for
operating
the
engine,
except
as
needed
to
do
the
intended
work.
Diplomatic
or
military:
This
is
a
temporary
exemption
to
allow
diplomatic
or
military
personnel
to
use
uncertified
engines
during
their
term
of
service
in
the
U.
S.
Engines
subject
to
other
programs:
This
is
a
temporary
exemption
that
allows
someone
to
import
an
uncertified
engine
that
will
be
converted
for
use
in
a
different
application.
For
example,
someone
may
want
to
import
a
landbased
nonroad
engine
to
modify
it
and
eventually
sell
it
as
a
marine
engine.
This
exemption
expires
when
the
engine
modifications
are
complete,
since
one
of
the
following
scenarios
will
apply
(
1)
the
company
modifying
the
engine
will
modify
the
engine
to
meet
emission
standards
that
apply
to
the
modified
engine,
(
2)
the
company
will
have
a
valid
exemption
under
the
program
that
applies
to
the
modified
engine,
or
(
3)
the
modified
engine
will
not
be
subject
to
emission
standards,
in
which
case
an
exemption
is
no
longer
necessary.
E.
Selective
Enforcement
Audit
(
Part
1068,
Subpart
E)
Clean
Air
Act
section
206(
b)
gives
us
the
discretion
in
any
program
with
vehicle
or
engine
emission
standards
to
do
selective
enforcement
auditing
of
production
engines.
In
selective
enforcement
auditing,
we
choose
an
engine
family
and
give
the
manufacturer
a
test
order
detailing
a
testing
program
to
show
that
production
line
engines
meet
emission
standards.
The
regulation
text
describes
the
audit
procedures
in
greater
detail.
We
intend
generally
to
rely
on
manufacturers'
testing
of
productionline
engines
to
show
that
their
production
process
is
producing
engines
in
compliance
they
comply
with
emission
standards.
However,
we
reserve
our
right
to
do
selective
enforcement
auditing
if,
for
example,
we
have
reason
to
question
the
emission
testing
conducted
and
reported
by
the
manufacturer.
F.
Defect
Reporting
and
Recall
(
Part
1068,
Subpart
F)
In
Part
1068,
Subpart
F,
we
are
adopting
defect
reporting
requirements
that
obligate
manufacturers
to
tell
us
when
they
learn
that
emission
control
systems
are
defective
and
to
conduct
investigations
under
certain
circumstances
to
determine
if
an
emission
related
defect
is
present.
We
are
also
requiring
that
manufacturers
use
warranty
information,
parts
shipments,
and
any
other
information
which
may
be
available
to
trigger
these
investigations.
For
the
purpose
of
this
subpart,
we
are
considering
defective
any
part
or
system
that
does
not
function
as
originally
designed
for
the
regulatory
useful
life
of
the
engine
or
the
scheduled
replacement
interval
specified
in
the
manufacturer's
maintenance
instructions.
For
recreational
vehicles
and
nonroad
spark
ignition
engines
over
19
kW,
this
approach
to
defect
reporting
takes
into
account
the
varying
sales
volumes
of
the
different
products.
We
believe
the
investigation
requirement
in
this
rule
will
allow
both
EPA
and
the
engine
manufacturers
to
fully
understand
the
significance
of
any
unusually
high
rates
of
warranty
claims
and
parts
replacement
for
systems
or
parts
that
may
have
an
impact
on
emissions.
We
believe
that
any
prudent
and
responsible
engine
manufacturer
would,
and
should,
conduct
a
thorough
investigation
as
part
of
its
normal
product
quality
practices
when
in
possession
of
data
indicating
an
usually
high
number
of
recurring
parts
failures.
In
the
past,
defect
reports
were
submitted
based
on
a
very
low
threshold
with
the
same
threshold
applicable
to
all
size
engine
families
and
with
little
information
about
the
full
extent
of
the
problem.
The
new
approach
should
result
in
fewer
overall
defect
reports
being
submitted
by
manufacturers
than
would
otherwise
be
required
under
the
old
defect
reporting
requirements
because
the
number
of
defects
triggering
the
submission
requirement
rises
with
the
engine
family
size.
The
defect
reporting
requirements
under
other
vehicle
and
engine
regulations
do
not
explicitly
require
investigations
or
reporting
based
on
information
available
to
the
manufacturer
about
warranty
claims
or
parts
shipments.
Such
information
is
valuable
and
readily
available
to
most
manufacturers
and
should
be
considered
when
determining
whether
or
not
there
is
a
defect
of
an
emissionrelated
part.
We
are
aware
that
counting
warranty
claims
and
part
shipments
will
likely
include
many
claims
that
are
not
emission
related
or
that
do
not
represent
defects,
so
we
are
establishing
a
relatively
high
threshold
for
triggering
the
manufacturer's
responsibility
to
investigate
whether
there
is
in
fact
a
real
occurrence
of
an
emission
related
defect.
Manufacturers
are
not
required
to
count
towards
the
investigation
threshold
any
replacement
parts
they
require
to
be
replaced
during
the
useful
life,
as
specified
in
the
application
for
certification
and
maintenance
instructions
to
the
owner,
because
such
part
shipments
clearly
do
not
represent
defects.
Subpart
F
is
intended
to
require
manufacturers
to
use
information
we
would
expect
them
to
keep
in
the
normal
course
of
business.
We
believe
in
most
cases
manufacturers
will
not
be
required
to
institute
new
programs
or
activities
to
monitor
product
quality
or
performance.
A
manufacturer
that
does
not
keep
warranty
or
replacement
part
information
may
ask
for
our
approval
to
use
an
alternate
defect
reporting
methodology
that
is
at
least
as
effective
in
identifying
and
tracking
potential
emissions
related
defects
as
the
requirements
of
subpart
F.
However,
until
we
approve
such
a
request,
the
thresholds
and
procedures
of
subpart
F
continue
to
apply.
For
engines
with
rated
power
below
560
kW,
the
investigation
thresholds
in
40
CFR
1068.501
are
4
percent
of
total
production,
or
4,000
engines,
whichever
is
less,
for
any
single
engine
family
in
one
model
year.
The
thresholds
are
reduced
by
50
percent
for
defects
related
to
aftertreatment
devices,
because
these
components
typically
play
such
a
significant
role
in
controlling
engine
emissions.
For
example,
for
an
engine
family
with
a
sales
volume
of
20,000
units
in
a
given
model
year,
the
manufacturer
must
investigate
for
emission
related
defects
if
there
were
warranty
claims
for
replacing
electronic
control
units
in
800
or
more
engines
or
catalytic
converters
on
400
or
more
engines.
For
a
family
with
sales
volume
of
200,000
units
in
a
given
model
year,
the
manufacturer
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/
Rules
and
Regulations
must
investigate
for
emission
related
defects
if
there
were
warranty
claims
for
replacing
electronic
control
units
in
4,000
or
more
engines
or
catalytic
converters
on
2,000
or
more
engines.
For
engines
rated
above
560
kW,
each
engine
emits
much
greater
levels
of
emissions,
both
because
of
the
higher
power
rating
and
the
fact
that
these
engines
generally
operate
at
high
load
and
for
long
periods.
In
addition,
the
engine
family
for
such
engines
are
typically
of
smaller
volume
compared
to
the
lower
power
engines.
We
are
therefore
adopting
a
requirement
that
manufacturers
investigate
defects
for
these
engines
if
they
learn
of
5
or
more
defects
that
may
be
emission
related,
or
1
percent
of
total
production,
whichever
is
greater.
The
second
threshold
in
40
CFR
1068.501
specifies
when
a
manufacturer
must
report
that
there
is
an
emissionrelated
defect.
This
threshold
involves
a
smaller
number
of
engines
because
each
possible
occurrence
has
been
screened
to
confirm
that
it
is
an
emission
related
defect.
In
counting
engines
to
compare
with
the
defect
reporting
threshold,
the
manufacturer
must
consider
a
single
engine
family
and
model
year.
However,
when
a
defect
report
is
required,
the
manufacturer
must
report
all
occurrences
of
the
same
defect
in
all
engine
families
and
all
model
years.
For
engines
with
rated
power
below
560
kW,
the
threshold
for
reporting
a
defect
is
0.25
percent
of
total
production
for
any
single
engine
family,
or
250
defects,
whichever
is
less.
The
thresholds
are
reduced
50
percent
for
reporting
defects
related
to
aftertreatment
devices.
For
engines
with
rated
power
greater
than
560kW,
the
threshold
for
reporting
defects
is
0.5
percent
of
total
production,
or
2
engines,
whichever
is
greater.
If
the
number
of
engines
with
a
specific
defect
is
found
to
be
less
than
the
threshold
for
submitting
a
defect
report,
but
information,
such
as
warranty
or
parts
shipment
data,
later
indicates
that
there
may
be
additional
defective
engines,
all
the
information
must
be
considered
in
determining
whether
the
threshold
for
submitting
a
defect
report
has
been
met.
If
a
manufacturer
has
actual
knowledge
from
any
source
that
the
threshold
for
submitting
a
defect
report
has
been
met,
a
defect
report
must
be
submitted
even
if
the
trigger
for
investigating
has
not
yet
been
met.
For
example,
if
manufacturers
receive
from
their
dealers,
technical
staff
or
other
field
personnel
information
showing
conclusively
that
there
is
a
recurring
emission
related
defect,
they
must
submit
a
defect
report.
At
specified
times
the
manufacturer
must
also
report
the
open
investigations
as
well
as
recently
closed
investigations
that
did
not
require
a
defect
report.
One
manufacturer
indicated
that
investigations
of
potential
defects
can
sometimes
take
a
long
time.
We
agree
and,
therefore,
are
not
specifying
a
time
limit
for
manufacturers
to
complete
their
investigations.
The
periodic
reports
required
by
the
regulations,
however,
will
allow
us
to
monitor
these
investigations
and
determine
if
it
is
necessary
or
appropriate
for
us
to
take
further
action.
In
general,
we
believe
this
updated
approach
to
defect
reporting
will
decrease
the
number
of
defect
reports
submitted
by
manufacturers
overall
while
significantly
improving
their
quality
and
their
value
to
both
EPA
and
the
manufacturer.
We
are
adopting
the
defect
reporting
requirements
for
recreational
marine
diesel
engines
that
already
apply
to
Category
1
commercial
marine
diesel
engines
(
40
CFR
94.403).
In
general,
this
requires
the
manufacturer
to
report
to
us
if
they
learn
that
25
or
more
models
have
a
specific
defect,
without
considering
what
percentage
of
the
total
engines
that
represents.
This
applies
to
the
occurrence
of
the
same
defect
and
is
not
constrained
by
engine
family
or
model
year.
We
believe
it
would
not
be
appropriate
to
have
different
defectreporting
requirements
for
different
types
of
marine
diesel
engines,
so
we
are
not
adopting
the
defect
reporting
provisions
described
above
for
recreational
marine
diesel
engines
at
this
time.
In
the
future
we
may
consider
whether
the
defect
reporting
methodology
described
above
should
apply
to
recreational
and
commercial
marine
diesel
engines.
Under
Clean
Air
Act
section
207,
if
we
determine
that
a
substantial
number
of
engines
within
an
engine
family,
though
properly
used
and
maintained,
do
not
conform
to
the
appropriate
emission
standards,
the
manufacturer
will
be
required
to
conduct
a
recall
of
the
noncomplying
engine
family
to
remedy
the
problem.
However,
we
also
recognize
the
practical
difficulty
in
implementing
an
effective
recall
program
for
nonroad
engines.
It
may
be
difficult
to
properly
identify
all
the
affected
owners
absent
a
nationwide
registration
requirement
similar
to
that
for
cars
and
trucks.
The
response
rate
for
affected
owners
or
operators
to
an
emission
related
recall
notice
is
also
a
critical
issue
to
consider.
We
recognize
that
in
some
cases,
recalling
noncomplying
nonroad
engines
may
not
achieve
sufficient
environmental
protection,
so
our
intent
in
such
situations
is
generally
to
allow
manufacturers
to
nominate
alternative
remedial
measures
to
address
most
potential
noncompliance
situations.
We
expect
that
successful
implementation
of
appropriate
alternative
remediation
would
obviate
the
need
for
us
to
make
a
determination
of
substantial
nonconformity
under
section
207
of
the
Act.
Alternatives
nominated
by
a
manufacturer
will
be
evaluated
based
on
the
following
criteria.
The
alternatives
should
(
1)
Represent
a
new
initiative
that
the
manufacturer
was
not
otherwise
planning
to
perform
at
that
time,
with
a
clear
connection
to
the
emission
problem
demonstrated
by
the
engine
family
in
question;
(
2)
Cost
more
than
foregone
compliance
costs
and
consider
the
time
value
of
the
foregone
compliance
costs
and
the
foregone
environmental
benefit
of
the
engine
family;
(
3)
Offset
at
least
100
percent
of
the
emission
exceedance
relative
to
that
required
to
meet
emission
standards
(
or
Family
Emission
Limits);
and
(
4)
Be
possible
to
implement
effectively
and
expeditiously
and
to
complete
in
a
reasonable
time.
These
criteria,
and
any
other
appropriate
factors,
will
guide
us
in
evaluating
projects
to
determine
whether
their
nature
and
burden
is
appropriate
to
remedy
the
environmental
impact
of
the
nonconformity.
G.
Hearings
(
Part
1068,
subpart
G)
Manufacturers
have
the
opportunity
to
challenge
our
decisions
related
to
implementing
this
final
rule.
We
are
adopting
hearing
procedures
consistent
with
those
currently
in
place
for
highway
engines
and
vehicles.
VIII.
General
Test
Procedures
This
rule
establishes
new
engine
testing
regulations
in
40
CFR
part
1065.
These
regulations
will
apply
to
anyone
who
tests
engines
to
show
that
they
meet
the
emission
standards
for
snowmobiles,
ATV,
motorcycles,
or
Large
SI
engines.
This
includes
certification
testing,
as
well
as
all
production
line
and
in
use
testing.
See
the
program
descriptions
above
for
testing
provisions
that
are
unique
to
different
engine
categories.
The
regulatory
text
in
40
CFR
part
1065
is
written
recognizing
that
we
may
someday
apply
these
procedures
more
broadly
to
other
EPA
engine
testing
programs.
If
we
decide
to
apply
these
provisions
to
other
engines
in
future
rulemaking,
we
would
incorporate
necessary
additions
or
changes
at
that
time.
Recreational
marine
diesel
engines
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Rules
and
Regulations
86
See
the
final
rule
for
commercial
marine
diesel
engines
for
a
broader
discussion
of
maximum
test
speed
(
64
FR
73300,
December
29,
1999).
must
be
tested
using
the
procedures
already
adopted
in
40
CFR
part
94.
A.
General
Provisions
As
we
have
done
in
previous
programs,
we
are
adopting
specific
test
procedures
to
define
how
to
measure
emissions,
but
allow
alternate
procedures
if
they
are
shown
to
be
equivalent
to
our
specified
procedures.
The
test
procedures
in
40
CFR
part
1065
are
derived
from
our
test
procedures
in
40
CFR
part
86
for
highway
heavy
duty
gasoline
engines
and
light
duty
vehicles.
The
procedures
have
been
simplified
(
and
to
some
extent
generalized)
to
better
fit
nonroad
engines.
B.
Laboratory
Testing
Equipment
The
regulations
do
not
specify
the
type
of
engine
or
chassis
dynamometer
to
use
during
testing.
Rather,
they
include
performance
criteria
that
must
be
met
during
each
test.
These
criteria
are
intended
to
ensure
that
deviations
from
the
specified
speed
and
load
duty
cycle
are
small.
Measuring
emissions
during
transient
operation
calls
for
a
greater
degree
of
sophistication
than
steady
state
testing.
For
chassis
testing
of
recreational
vehicles,
we
are
adopting
the
specifications
established
in
40
CFR
part
86
for
highway
engines.
For
Large
SI
engines,
we
based
the
dynamometer
specifications
around
the
capabilities
of
current
dynamometers
with
enhanced
control
capabilities.
While
EPA
confirmatory
testing
with
transient
duty
cycles
must
meet
the
prescribed
specifications,
manufacturers
may
ask
for
approval
to
run
tests
with
relaxed
requirements
for
following
the
trace
of
the
transient
duty
cycle.
Manufacturers
would
have
an
incentive
to
accurately
reproduce
the
test
cycle
to
ensure
compliance
with
emission
standards,
but
would
be
able
to
use
otherwise
invalidated
tests
if
the
degree
of
variance
from
the
test
cycle
does
not
call
into
question
the
engine's
reported
emission
levels.
In
addition,
for
transient
testing
with
recreational
vehicles
and
any
testing
with
Large
SI
engines,
the
regulations
specify
that
emissions
must
be
measured
using
a
full
dilution
constantvolume
sampler
(
CVS)
like
those
used
to
measure
emissions
from
highway
engines.
This
means
that
during
a
test,
an
engine's
exhaust
is
routed
into
a
dilution
tunnel
where
it
is
mixed
with
air
and
then
sampled
using
a
bag
sampler
system.
After
the
test,
the
concentrations
of
HC,
CO,
and
NOX
in
the
bag
is
measured
using
conventional
laboratory
analyzers.
For
Large
SI
engines
and
snowmobiles,
the
steady
state
test
procedures
specify
measuring
emissions
with
dilute
sampling
equipment.
Some
manufacturers
have
expressed
a
preference
to
continue
with
their
established
practice
of
using
rawsampling
equipment
and
procedures.
While
we
believe
dilute
sampling
is
most
appropriate
for
these
engines,
the
provisions
for
alternate
testing
procedures
may
allow
for
raw
sampling
measurements
for
steady
state
testing.
As
specified
in
40
CFR
1065.10(
c)(
3)
of
the
regulations,
we
allow
manufacturers
to
use
alternate
procedures
shown
to
be
equivalent
to
the
specified
procedures.
We
are
also
including
an
interim
provision
for
snowmobiles
to
allow
manufacturers
to
use
the
raw
sampling
procedures
in
40
CFR
part
91
for
a
few
years
before
they
are
required
to
show
equivalence
with
the
dilute
sampling
procedures.
This
option
will
allow
manufacturers
to
focus
their
engineering
efforts
on
reducing
emissions
during
the
start
of
the
program.
C.
Laboratory
Testing
Procedures
The
specific
procedures
for
running
emission
tests
are
outlined
briefly
here,
with
a
more
detailed
description
of
the
most
significant
aspects.
Before
testing
the
engine,
it
is
necessary
to
operate
it
enough
to
stabilize
emission
levels
or
to
make
it
more
representative
of
in
use
engines.
This
is
called
service
accumulation
and
may
take
one
of
two
forms.
In
the
first
method,
a
new
engine
is
operated
for
up
to
50
hours
as
a
breakin
period.
This
is
done
for
most
or
all
emission
data
engines.
The
second
method
is
much
longer,
up
to
the
full
useful
life,
and
is
done
to
determine
deterioration
factors.
Once
an
engine
is
ready
for
testing,
it
is
connected
to
the
dynamometer
with
its
exhaust
flowing
into
the
dilution
tunnel.
The
dynamometer
is
controlled
to
make
the
engine
follow
the
specified
duty
cycle.
A
continuous
sample
is
collected
from
the
dilution
tunnel
for
each
test
segment
or
test
mode
using
sample
bags.
These
bags
are
then
analyzed
to
determine
the
concentrations
of
HC,
CO,
and
NOX.
1.
Test
Speeds
The
definition
of
maximum
test
speed,
where
speed
is
the
angular
velocity
of
an
engine's
crankshaft
(
usually
expressed
in
revolutions
per
minute,
or
rpm),
is
an
important
aspect
of
most
duty
cycles.
Until
recently,
we
relied
on
engine
manufacturers
to
declare
reasonable
rated
speeds
for
their
engines
and
then
used
the
rated
speed
as
the
maximum
test
speed.
However,
to
have
a
more
objective
measure
of
an
engine's
maximum
test
speed,
we
have
established
a
specific
procedure
for
measuring
this
engine
parameter.
86
We
define
the
maximum
test
speed
for
any
engine
to
be
the
single
point
on
an
engine's
maximum
power
versus
speed
curve
that
lies
farthest
away
from
the
zero
power,
zero
speed
point
on
a
normalized
maximum
power
versus
speed
plot.
In
other
words,
consider
straight
lines
drawn
between
the
origin
(
speed
=
0,
load
=
0)
and
each
point
on
an
engine's
normalized
maximumpower
versus
speed
curve.
Maximum
test
speed
is
defined
at
that
point
where
the
length
of
this
line
reaches
its
maximum
value.
For
constant
speed
engines,
maximum
test
speed
is
the
engine's
rated
speed.
Intermediate
speed
for
steady
state
duty
cycles
is
defined
as
the
speed
at
which
the
engine
generates
its
maximum
torque
value.
However,
in
cases
where
the
maximum
torque
occurs
at
a
speed
that
is
less
than
60
percent
or
greater
than
75
percent
of
the
rated
speed,
the
intermediate
speed
is
often
specified
as
either
60
or
75
percent
of
rated
speed,
whichever
is
closer
to
the
speed
of
maximum
torque.
The
maximum
test
speed
described
above
is
used
to
calculate
these
percentage
values
relative
to
rated
speed.
2.
Maintenance
As
described
in
Section
II.
C.
1,
we
are
limiting
the
amount
of
scheduled
maintenance
manufacturers
may
prescribe
for
their
customers
to
ensure
that
engines
continue
to
meet
emission
standards.
If
manufacturers
specify
unreasonably
frequent
maintenance,
there
would
be
little
assurance
that
inuse
engines
would
continue
to
operate
at
certified
emission
levels.
We
also
apply
these
minimum
maintenance
intervals
to
engines
the
manufacturer
operates
for
service
accumulation
before
testing
for
emissions.
For
example,
manufacturers
may
not
install
a
new
catalyst
on
a
Large
SI
engine
after
2,000
hours
of
operation,
then
select
that
engine
for
the
in
use
testing
program.
Similarly,
manufacturers
may
not
replace
fuel
system
components
on
a
recreational
vehicle
during
the
course
of
service
accumulation
for
establishing
deterioration
factors.
We
do
not
restrict
scheduling
of
routine
maintenance
items,
such
as
changing
engine
oil
and
replacing
oil,
fuel,
or
air
filters.
We
may
also
allow
changing
spark
plugs,
even
though
we
are
aware
that
spark
plugs
may
affect
emissions.
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Regulations
D.
Other
Testing
Procedures
As
noted
in
earlier
sections,
we
are
establishing
some
special
test
procedures
for
field
testing
situations.
These
special
procedures
are
designed
to
apply
to
specific
types
of
engines,
and
thus
do
not
apply
generally
to
all
engines
covered
by
this
rulemaking.
You
should
read
the
specific
applicable
section
to
determine
if
such
special
test
procedures
apply
to
any
specific
category
of
engines
or
vehicles.
IX.
Projected
Impacts
This
section
summarizes
the
projected
impacts
of
the
emission
standards.
The
anticipated
reduction
in
emissions
is
compared
with
the
projected
cost
of
the
program
for
an
assessment
of
the
cost
per
ton
of
reducing
emissions
for
this
rule.
The
section
includes
the
results
of
the
analysis
for
the
Final
Program.
We
have
also
analyzed
the
impacts
of
different
alternatives
for
each
of
the
program
areas.
This
analysis
of
alternatives,
for
the
most
part,
focused
on
more
or
less
stringent
alternative
standards.
For
recreational
marine
diesels,
the
alternatives
analyzed
were
applying
draft
European
standards
or
implementing
our
primary
program
two
years
earlier.
For
the
Large
SI
category,
the
alternative
focused
on
adopting
a
steady
state
only
2007
requirement.
For
off
highway
motorcycles,
we
analyzed
a
more
stringent
1.0
g/
km
standard
and
a
less
stringent
4.0
g/
km
standard
for
HC
+
NOX
control.
With
ATVs,
the
alternatives
presented
were
a
2.0
g/
km
and
a
1.0
g/
km
HC
+
NOX
standard.
For
snowmobiles,
we
analyzed
four
alternatives,
ranging
from
only
adopting
one
phase
of
standards
in
2006
to
a
standard
that
would
require,
on
average,
reductions
of
85%
HC
and
50%
CO
from
baseline
emissions.
Additional
detailed
discussion
on
these
alternatives
and
the
results
of
the
alternatives
analysis
are
presented
in
Chapter
11
of
the
RSD.
A.
Environmental
Impact
To
estimate
nonroad
engine
and
vehicle
emission
contributions,
we
used
the
latest
version
of
our
NONROAD
emissions
model.
This
model
computes
emission
levels
for
a
wide
variety
of
nonroad
engines,
and
uses
information
on
emission
rates,
operating
data,
and
population
to
determine
annual
emission
levels
of
various
pollutants.
A
more
detailed
description
of
the
methodology
used
for
projecting
inventories
and
projections
for
additional
years
can
be
found
in
the
Chapter
6
of
the
Final
Regulatory
Support
Document.
Tables
IX.
A
1
and
IX.
A
2
contain
the
projected
emission
inventories
for
calendar
year
2010
from
the
engines
and
vehicles
subject
to
this
rulemaking
under
the
base
case
(
i.
e.,
without
the
standards
taking
effect)
and
assuming
the
standards
take
effect.
Tables
IX.
A
3
and
IX.
A
4
contain
the
projected
emission
inventories
for
calendar
year
2020.
The
percent
reductions
based
on
a
comparison
of
estimated
emission
inventories
with
and
without
the
emission
standards
are
also
presented
in
each
of
the
tables.
TABLE
IX.
A
1.
2010
PROJECTED
HC
AND
NOX
EMISSIONS
INVENTORIES
[
Thousand
short
tons]
Category
HC*
NOX
Base
case
With
standards
Percent
reduction
Base
case
With
standards
Percent
reduction
Large
SI
.............................................................................................
268
88
67
389
118
70
Snowmobiles
......................................................................................
297
250
16
3
4
(
16)
ATVs
..................................................................................................
308
211
31
7
6
11
Off
highway
motorcycles
....................................................................
193
155
20
1.1
1.2
(
8)
Recreational
marine
diesel
................................................................
1.6
1.5
10
49
46
7
Total
........................................................................................
1,066
705
34
450
174
61
*
The
estimate
for
Large
SI
includes
both
exhaust
HC
and
evaporative
HC
emissions.
The
estimates
for
snowmobiles,
ATVs
and
Off
highway
motorcycles
includes
both
exhaust
HC
and
permeation
HC
emissions.
The
estimate
for
recreation
marine
diesel
includes
exhaust
HC
emissions.
TABLE
IX.
A
2.
2010
PROJECTED
CO
AND
PM
EMISSIONS
INVENTORIES
[
Thousand
short
tons]
Category
CO
PM
Base
case
With
standards
Percent
reduction
Base
case
With
standards
Percent
reduction
Large
SI
...................................................................................................
2,022
945
53
1.9
1.9
0
Snowmobiles
............................................................................................
775
670
14
7.0
6.7
4
ATVs
........................................................................................................
1,042
989
5
10.8
7.4
32
Recreational
marine
diesel
......................................................................
8
8
0
1.3
1.2
6
Off
highway
motorcycles
..........................................................................
266
239
10
7.3
5.8
20
Total
..............................................................................................
4,113
2,851
31
28.3
23.0
19
TABLE
IX.
A
3.
2020
HC
AND
NOX
PROJECTED
EMISSIONS
INVENTORIES
[
Thousand
short
tons]
Category
HC*
NOX
Base
case
With
standards
Percent
reduction
Base
case
With
standards
Percent
reduction
Large
SI
...............................................................................................
318
34
89
472
43
91
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87
For
further
information
on
learning
curves,
see
Chapter
5
of
the
Economic
Impact,
from
Regulatory
Impact
Analysis
Control
if
Air
Pollution
from
New
Motor
Vehicles:
Tier
2
Motor
Vehicle
Emission
Standards
and
Gasoline
Sulfur
Control
Requirements,
EPA420
R
99
023,
December
1999.
A
copy
of
this
document
is
included
in
Air
Docket
A
2000
01,
at
Document
No.
II
A
83.
The
interested
reader
should
also
refer
to
previous
final
rules
for
Tier
2
highway
vehicles
(
65
FR
6698,
February
10,
2000),
marine
diesel
engines
(
64
FR
73300,
December
29,
1999),
nonroad
diesel
engines
(
63
FR
56968,
October
23,
1998),
and
highway
diesel
engines
(
62
FR
54694,
October
21,
1997).
TABLE
IX.
A
3.
2020
HC
AND
NOX
PROJECTED
EMISSIONS
INVENTORIES
Continued
[
Thousand
short
tons]
Category
HC*
NOX
Base
case
With
standards
Percent
reduction
Base
case
With
standards
Percent
reduction
Snowmobiles
........................................................................................
358
149
58
5
10
(
101)
ATVs
....................................................................................................
374
53
86
8
6
25
Off
highway
motorcycles
......................................................................
232
117
50
1.3
1.5
(
19)
Recreational
marine
diesel
..................................................................
2.0
1.5
28
61
48
21
Total
..........................................................................................
1,284
355
72
547
109
80
*
The
estimate
for
Large
SI
includes
both
exhaust
HC
and
evaporative
HC
emissions.
The
estimates
for
snowmobiles,
ATVs
and
Off
highway
motorcycles
includes
both
exhaust
HC
and
permeation
HC
emissions.
The
estimate
for
recreation
marine
diesel
includes
exhaust
HC
emissions.
TABLE
IX.
A
4.
2020
PROJECTED
CO
AND
PM
EMISSIONS
INVENTORIES
[
Thousand
short
tons]
Category
CO
PM
Percent
reduction
Base
case
With
standards
Percent
reduction
Base
case
With
standards
Large
SI
...................................................................................................
2,336
277
88
2.3
2.3
0
Snowmobiles
............................................................................................
950
508
46
8.4
4.9
42
ATVs
........................................................................................................
1,250
1,085
13
13.1
1.9
86
Off
highway
motorcycles
..........................................................................
321
236
26
8.7
4.4
50
Recreational
Marine
diesel
......................................................................
9
9
0
1.6
1.3
18
Total
..............................................................................................
4,866
2,115
56
34.2
14.8
57
As
described
in
Section
I,
we
project
there
will
also
be
environmental
benefits
associated
with
reduced
haze
in
many
sensitive
areas.
Finally,
anticipated
reductions
in
hydrocarbon
emissions
correspond
with
reduced
emissions
of
the
toxic
air
emissions
referenced
in
Section
I.
B.
Cost
Estimates
In
assessing
the
economic
impact
of
setting
emission
standards,
we
have
made
a
best
estimate
of
the
necessary
technologies
and
their
associated
costs.
In
making
our
estimates
we
have
relied
on
our
own
technology
assessment,
which
includes
information
supplied
by
individual
manufacturers
and
our
own
in
house
testing.
Estimated
costs
include
variable
costs
(
for
hardware
and
assembly
time)
and
fixed
costs
(
for
research
and
development,
retooling,
and
certification).
The
analysis
also
considers
total
operating
costs,
including
maintenance
and
fuel
consumption.
Cost
estimates
based
on
the
projected
technologies
represent
an
expected
change
in
the
cost
of
engines
as
they
begin
to
comply
with
new
emission
standards.
All
costs
are
presented
in
2001
dollars.
Full
details
of
our
cost
analysis
can
be
found
in
Chapter
5
of
the
Final
Regulatory
Support
Document.
Cost
estimates
based
on
the
current
projected
costs
for
our
estimated
technology
packages
represent
an
expected
incremental
cost
of
vehicles
in
the
near
term.
For
the
longer
term,
we
have
identified
factors
that
will
cause
cost
impacts
to
decrease
over
time.
First,
we
project
that
manufacturers
will
generally
recover
their
fixed
costs
over
a
five
year
period,
so
these
costs
disappear
from
the
analysis
after
the
fifth
year
of
production.
Second,
the
analysis
incorporates
the
expectation
that
manufacturers
and
suppliers
will
apply
ongoing
research
and
manufacturing
innovation
to
making
emission
controls
more
effective
and
less
costly
over
time.
Research
in
the
costs
of
manufacturing
unrelated
to
emissions
control
technologies
has
consistently
shown
that
as
manufacturers
gain
experience
in
production
and
use,
they
are
able
to
apply
innovations
to
simplify
machining
and
assembly
operations,
use
lower
cost
materials,
and
reduce
the
number
or
complexity
of
component
parts
(
see
the
Final
Regulatory
Support
Document
for
additional
information).
87
The
cost
analysis
assumes
this
learning
effect
applies
equally
well
to
the
adoption
of
the
technologies
associated
with
this
rule
by
decreasing
estimated
variable
costs
by
20
percent
starting
in
the
third
year
of
production
and
an
additional
20
percent
starting
in
the
sixth
year
of
production.
Table
IX.
B
1
summarizes
the
projected
near
term
per
unit
average
costs
to
meet
the
new
emission
standards.
These
estimates
are
based
on
the
manufacturing
cost
rather
than
predicting
price
increase;
the
costs
nevertheless
take
into
account
anticipated
mark
ups
to
present
retailprice
equivalent
figures.
Long
term
impacts
on
engine
costs
are
expected
to
decrease
as
manufacturers
fully
amortize
their
fixed
costs
and
learn
to
optimize
their
designs
and
production
processes
to
meet
the
standards
more
efficiently.
The
tables
also
show
our
projections
of
reduced
operating
costs
for
some
engines
(
calculated
on
a
net
present
value
basis),
which
generally
results
from
substantial
reductions
in
fuel
consumption.
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Chapter
5
of
the
Final
Regulatory
Support
Document
describes
why
we
believe
market
forces
haven't
already
led
manufacturers
to
add
fuelsaving
technologies
to
their
products.
89
The
program
contains
an
optional
set
of
standards
for
off
highway
motorcycles
which
could
result
in
the
use
of
direct
injection
two
stroke
technology
in
some
high
performance
applications.
Chapter
11.3
provides
a
cost
analysis
for
this
option.
The
costs
are
projected
to
be
somewhat
higher
for
this
option
due
to
the
application
of
technology
to
high
performance
competition
models.
TABLE
IX.
B
1.
ESTIMATED
AVERAGE
COST
IMPACTS
OF
EMISSION
STANDARDS
Standards
Dates
Increased
production
cost
per
vehicle*
Lifetime
operating
costs
per
vehicle
(
NPV)
Large
SI
exhaust
.............................................................................................................................
2004
$
611
$
¥
3,981
Large
SI
exhaust
.............................................................................................................................
2007
55
0
Large
SI
evaporative
.......................................................................................................................
2007
13
¥
56
Snowmobile
exhaust
(
Phase
1)
.......................................................................................................
2006
73
¥
57
Snowmobile
exhaust
(
Phase
2)
.......................................................................................................
2010
131
¥
286
Snowmobile
exhaust
(
Phase
3)
.......................................................................................................
2012
89
¥
191
Snowmobile
permeation
..................................................................................................................
2008
7
¥
11
ATV
exhaust
....................................................................................................................................
2006
84
¥
24
ATV
permeation
...............................................................................................................................
2008
3
¥
6
Off
highway
motorcycle
exhaust
.....................................................................................................
2006
155
¥
48
Off
highway
motorcycle
peermeation
..............................................................................................
2008
3
¥
5
Recreational
.....................................................................................................................................
2006
346
0
*
These
estimates
are
for
near
term
costs.
The
estimated
long
term
costs
decrease
by
about
35
percent.
Costs
presented
for
the
Large
SI
and
snowmobile
second
phase
standards
are
incremental
to
the
first
phase
standards.
Costs
for
Phase
3
are
incremental
to
Phase
2.
These
costs
numbers
may
not
necessarily
reflect
actual
price
increases
as
manufacturer
production
costs,
perceived
product
enhancements,
and
other
market
impacts
will
affect
actual
prices
to
consumers.
We
estimate
that
the
anticipated
increase
in
the
near
term
cost
of
producing
new
Large
SI
engines
for
the
2004
standards
is
estimated
to
range
from
$
550
to
$
800,
depending
on
fuel
type,
with
a
composite
estimated
cost
of
$
605.
This
cost
is
attributed
to
upgrading
engines
to
operate
with
closed
loop
fuel
systems
and
three
way
catalysts.
These
technologies
also
improve
the
overall
performance
of
these
engines,
including
improvements
to
fuel
economy
that
result
in
reduced
operating
costs
that
fully
offset
the
additional
hardware
cost.
We
further
estimate
additional
costs
of
$
50
for
the
2007
standards,
which
primarily
involve
additional
development
time
to
optimize
engines
using
the
same
closedloop
systems
with
three
way
catalysts.
While
these
costs
are
a
small
percentage
of
the
cost
of
industrial
equipment,
we
are
aware
that
this
may
not
be
insignificant
in
this
very
competitive
market.
Given
the
compelling
advantages
of
improved
performance
and
reduced
operating
expenses,
however,
we
believe
manufacturers
will
generally
be
able
to
recover
their
costs
over
time.
88
Projected
average
near
term
costs
for
ATVs
and
off
highway
motorcycles
are
$
84
and
$
155
per
unit,
respectively.
Standards
are
based
on
the
emissioncontrol
capability
of
engines
four
stroke
engines.
89
Those
models
that
convert
from
two
stroke
to
four
stroke
technology
will
see
substantial
fuel
savings
in
addition
to
greatly
reduced
emissions.
With
an
averaging
program
that
allows
manufacturers
to
apply
varying
degrees
of
technology
to
different
models,
we
believe
they
will
be
able
to
tailor
emission
controls
in
a
way
that
reflects
the
performance
needs
for
their
products.
Fuel
savings
associated
with
replacing
two
stroke
engines
with
four
stroke
engines
partially
offsets
the
additional
cost
of
producing
these
vehicles.
We
expect
that
the
near
term
cost
of
the
2006
snowmobile
standards
will
average
$
73
per
snowmobile.
These
costs
are
based
on
a
mix
of
technologies
including
a
small
increase
in
the
use
of
four
stroke
and
direct
injection
technology.
For
other
engines
we
expect
manufacturers
to
lean
out
the
air
fuel
mixture,
improve
carburetion
for
better
fuel
control
and
less
production
variation,
and
modify
the
engine
to
withstand
higher
temperatures
and
potential
misfire
episodes
attributed
to
enleanment.
We
expect
that
the
2010
and
2012
standards
will
be
met
through
inceasing
the
application
of
direct
injection
two
stroke
technology
and
four
stroke
engines
on
a
significant
portion
of
the
fleet.
We
project
that
the
near
term
incremental
cost
of
the
Phase
2
standards
will
average
$
131
per
snowmobile
and
Phase
3
will
be
$
89,
although
we
believe
these
costs
will
be
fully
offset
by
fuel
savings.
Recreational
marine
diesel
engines
are
expected
to
see
increased
costs
averaging
under
$
400
per
engine
in
the
near
term.
We
expect
manufacturers
to
meet
emission
standards
by
improving
fuel
injection
systems
and
making
general
design
changes
to
the
geometries,
configurations,
and
calibrations
of
their
engines.
These
figures
are
somewhat
lower
than
we
have
projected
for
the
comparable
commercial
marine
engines,
since
the
recreational
models
generally
already
have
some
of
the
emission
control
technologies
needed
to
meet
the
emission
standards.
The
above
analysis
presents
unit
cost
estimates
for
each
type
of
engine
or
vehicle.
These
costs
represent
the
total
set
of
costs
the
engine
or
vehicle
manufacturers
will
bear
to
comply
with
emission
standards.
For
those
categories
with
engine
based
standards,
we
do
not
anticipate
significant
new
costs
for
equipment
manufacturers
installing
certified
engines.
Operating
costs
are
also
taken
into
account,
but
where
there
is
an
effect,
we
project
these
impacts
to
involve
only
cost
savings
for
operators.
With
current
and
projected
estimates
of
engine
and
equipment
sales,
we
translate
these
costs
into
projected
direct
costs
to
the
nation
for
the
new
emission
standards
in
any
year.
A
summary
of
the
annualized
costs
to
manufacturers
by
equipment
type
is
presented
in
Table
IX.
B
2.
(
The
annualized
costs
are
determined
over
the
first
twenty
years
that
the
standards
will
be
in
effect.
Because
the
standards
take
effect
in
different
years
for
the
various
categories
of
equipment
covered
by
this
rule,
the
aggregate
annualized
cost
is
calculated
over
a
slightly
longer
period
of
time
encompassing
the
first
twenty
years
of
each
of
the
standards.
For
this
reason,
the
aggregate
annualized
cost
is
not
the
sum
of
the
individual
annualized
costs.)
The
annual
cost
savings
due
to
reduced
operating
expenses
start
slowly,
then
increase
as
greater
numbers
of
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Regulations
compliant
engines
enter
the
fleet.
Table
IX.
B
2
also
presents
a
summary
of
the
annualized
reduction
in
operating
costs.
Overall,
based
on
currently
available
information,
we
project
an
annualized
net
savings
to
the
economy
of
approximately
$
200
million
per
year.
TABLE
IX.
B
2
ESTIMATED
ANNUAL
COST
TO
MANUFACTURERS
AND
ANNUAL
SAVINGS
FROM
REDUCED
OPERATING
COSTS
OF
EMISSION
STANDARDS
Engine
type
Annualized
cost
to
manufacturers
(
millions/
year)
Annualized
savings
from
reduced
operating
costs
(
millions/
year)
Large
SI
...............................................................................................................................................................
$
84
$
324
Snowmobiles
........................................................................................................................................................
36
47
ATVs
....................................................................................................................................................................
61
31
Off
highway
motorcycles
.....................................................................................................................................
25
14
Marine
Diesel
.......................................................................................................................................................
7
0
Aggregate
*
..........................................................................................................................................................
192
410
*
Because
the
standards
take
effect
in
different
years
for
the
various
categories
of
equipment,
the
aggregate
annualized
cost
is
calculated
over
a
slightly
longer
period
of
time.
For
this
reason,
the
aggregate
annualized
cost
is
not
the
sum
of
the
individual
annualized
costs.
C.
Cost
Per
Ton
of
Emissions
Reduced
We
calculated
the
cost
per
ton
of
emission
reductions
for
the
emission
standards.
For
snowmobiles,
this
calculation
is
on
the
basis
of
HC
and
CO
emissions.
For
all
other
engines,
we
attributed
the
entire
cost
of
the
program
to
the
control
of
ozone
precursor
emissions
(
HC
or
NOX
or
both).
Table
IX.
C
1
presents
the
near
term
discounted
cost
per
ton
estimates
for
the
various
engines
covered
by
the
rule.
(
The
aggregate
cost
per
ton
estimates
are
over
the
first
20
years
of
emission
standards.)
Reduced
operating
costs
more
than
offset
the
increased
cost
of
producing
the
cleaner
engines
for
Phase
1
Large
SI,
and
Phase
2
and
Phase
3
snowmobile
engines.
The
cost
to
society
and
the
associated
cost
per
ton
figures
for
these
engines,
and
the
aggregate
values
for
all
engines
covered
by
this
rule,
therefore
show
a
net
savings
resulting
from
the
emission
standards.
The
table
presents
these
as
$
0
per
ton,
rather
than
calculating
a
negative
value
that
has
no
clear
meaning.
TABLE
IX.
C
1.
ESTIMATED
COST
PER
TON
OF
EMISSION
STANDARDS
Standards
Dates
Discounted
reductions
per
vehicle
(
short
tons)
*
Discounted
cost
per
ton
of
HC+
NOX
Discounted
cost
per
ton
of
CO
Without
fuel
savings
With
fuel
savings
Without
fuel
savings
With
fuel
savings
Large
SI
exhaust
(
Composite
of
all
fuels)
..................................................
2004
3.07
$
240
$
0
Large
SI
exhaust
(
Composite
of
all
fuels)
..................................................
2007
0.80
80
80
Large
SI
evaporative
..................................................................................
2007
0.13
80
0
Snowmobile
exhaust
...................................................................................
2006
HC:
0.40
90
20
$
40
$
10
CO:
1.02
Snowmobile
exhaust
...................................................................................
2010
HC:
0.10
1,370
0
Snowmobile
exhaust
...................................................................................
2012
CO:
0.25
360
0
Snowmobile
permeation
.............................................................................
2008
0.03
210
0
ATV
exhaust
...............................................................................................
2006
0.21
400
290
ATV
permeation
..........................................................................................
2008
0.02
180
0
Off
highway
motorcycle
exhaust
................................................................
2006
0.38
410
280
Off
highway
motorcycle
permeation
...........................................................
2008
0.01
230
0
Recreational
marine
diesel
.........................................................................
2006
0.44
670
670
Aggregate
...................................................................................................
240
0
80
0
*
HC
reductions
for
evaporative
and
permeation,
and
HC+
NOX
reductions
for
exhaust
(
except
snowmobiles
where
CO
reductions
are
also
presented).
D.
Economic
Impact
Analysis
We
performed
an
analysis
to
estimate
the
economic
impacts
of
this
final
rule
on
producers
and
consumers
of
recreational
marine
diesel
vessels
(
specifically,
diesel
inboard
cruisers),
forklifts,
snowmobiles,
ATVs,
offhighway
motorcycles,
and
society
as
a
whole.
This
economic
impact
analysis
focuses
on
market
level
changes
in
price,
quantity,
and
economic
welfare
(
social
gains
or
costs)
associated
with
the
regulation.
A
description
of
the
methodology
used
can
be
found
in
Chapter
9
of
the
Final
Regulatory
Support
Document
prepared
for
this
rulemaking.
We
did
not
perform
an
economic
impact
analysis
for
categories
of
Large
SI
nonroad
engines
other
than
forklifts,
even
though
those
other
Large
SI
engines
are
also
subject
to
the
standards
contained
in
this
final
rule.
As
explained
in
more
detail
in
Chapter
9
of
the
Final
Regulatory
Support
Document,
this
was
due
to
the
large
number
of
different
types
of
equipment
that
use
Large
SI
engines
and
data
availability
constraints
for
those
market
segments.
For
the
sake
of
completeness,
the
following
analysis
reports
separate
estimates
for
Large
SI
engines
other
than
forklifts.
Engineering
costs
are
assumed
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Regulations
90
Consumer
and
producer
surplus
losses
are
measures
of
the
economic
welfare
loss
consumers
and
producers,
respectively
are
likely
to
experience
as
a
result
of
the
regulations.
Combined
these
losses
represent
an
estimate
of
the
economic
or
social
costs
of
the
rule.
Note
that
for
the
Large
SI
and
recreational
vehicle
rules,
fuel
efficiency
gains
must
be
netted
from
surplus
losses
to
estimate
the
social
costs
or
social
gains
(
in
cases
where
fuel
efficiency
gains
exceed
surplus
losses)
attributable
to
the
rules.
91
Regulatory
Impact
Analysis:
Heavy
Duty
Engine
and
Vehicle
Standards
and
Highway
Diesel
Fuel
Sulfur
Control
Requirements,
document
EPA420
R
00
026,
December
2000.
Docket
No.
A
2000
01,
Document
No.
II
A
13.
This
document
is
also
available
at
http://
www.
epa.
gov/
otaq/
diesel.
htm#
documents.
The
transfer
technique
is
described
in
a
memorandum,
Dr.
Bryan
Hubbell,
Senior
Economist,
Estimated
Nox,
Sox,
and
PM
Emissions
Health
Damages
for
Heavy
Duty
Vehicle
Emissions,
April
22,
2002.
A
copy
of
this
letter
can
be
found
in
Docket
A
2000
01,
Document
IV
A
146.
92
The
section
812
studies
include:
(
1)
U.
S.
EPA,
Report
to
Congress:
The
Benefits
and
Costs
of
the
Clean
Air
Act,
1970
to
1990,
October
1997
(
also
known
as
the
``
Section
812
Retrospective
Report'');
to
be
equal
to
economic
costs
for
those
engines.
This
approach
slightly
overestimates
the
social
costs
associated
with
the
relevant
standards.
Based
on
the
estimated
regulatory
costs
associated
with
this
rule
and
the
predicted
changes
in
prices
and
quantity
produced
in
the
affected
industries,
the
total
estimated
annual
social
gains
of
the
rule
in
the
year
2030
is
projected
to
be
$
553.5
million
(
in
2000
and
2001
dollars).
The
net
present
value
of
the
social
gains
for
the
2002
to
2030
time
frame
is
equal
to
$
4.9
billion,
using
a
3%
discount
rate.
This
value
would
be
$
2.4
billion
with
a
7%
discount
rate.
The
social
gains
are
equal
to
the
fuel
savings
minus
the
combined
loss
in
consumer
and
producer
surplus
(
see
Table
IX.
D
1),
taking
into
account
producers'
and
consumers'
changes
in
behavior
resulting
from
the
costs
associated
with
the
rule.
90
Social
gains
do
not
account
for
the
social
benefits
(
the
monetized
health
and
environmental
effects
of
the
rule).
TABLE
IX.
D
1.
SURPLUS
LOSSES,
FUEL
EFFICIENCY
GAINS,
AND
SOCIAL
GAINS/
COSTS
IN
2030
a
Vehicle
category
Surplus
losses
in
2030
($
millions)
Fuel
efficiency
gains
in
2030
($
millions)
Social
gains/
costs
in
2030
b
($
millions)
Recreational
marine
diesel
vessels
.........................................................................................
$
6.6
$
0
($
6.6)
Forklifts
....................................................................................................................................
47.8
420.1
372.3
Other
Large
SI
.........................................................................................................................
c
48.1
138.4
90.3
Snowmobiles
............................................................................................................................
41.9
135.0
93.1
ATVs
........................................................................................................................................
47.2
51.4
4.2
Off
highway
motorcycles
.........................................................................................................
25.0
25.2
0.2
All
vehicles
total
.......................................................................................................................
216.6
770.1
553.5
NPV
of
all
vehicles
total
d
........................................................................................................
3,231.4
8,130.3
4,898.9
NPV
of
all
vehicles
total
e
.........................................................................................................
1,889.5
4,282.3
2,392.8
a
Figures
are
in
2000
and
2001
dollars.
b
Figures
in
this
column
exclude
estimated
social
benefits.
Numbers
in
parentheses
denote
social
costs.
c
Figure
is
engineering
costs;
see
text
for
explanation.
d
Net
Present
Value
is
calculated
over
the
2002
to
2030
time
frame
using
a
3
percent
discount
rate.
e
Net
Present
Value
is
calculated
over
the
2002
to
2030
time
frame
using
a
7
percent
discount
rate.
For
most
of
the
engine
categories
contained
in
this
rule,
we
expect
there
will
be
a
fuel
savings
as
manufacturers
redesign
their
engines
to
comply
with
emission
standards.
For
ATVs
and
offhighway
motorcycles,
the
fuel
savings
will
be
realized
as
manufacturers
switch
from
two
stroke
to
four
stroke
technologies.
For
snowmobiles,
the
fuel
savings
will
be
realized
as
manufacturers
switch
some
of
their
engines
to
more
fuel
efficient
two
stroke
technologies
and
some
of
their
engines
to
four
stroke
technologies.
For
Large
SI
engines,
the
fuel
savings
will
be
realized
as
manufacturers
adopt
more
sophisticated
and
more
efficient
fuel
systems;
this
is
true
for
all
fuels
used
by
Large
SI
engines.
Overall,
we
project
the
fuel
savings
associated
with
the
anticipated
changes
in
technology
to
be
about
800
million
gallons
per
year
once
the
program
is
fully
phased
in.
These
savings
are
factored
into
the
calculated
costs
and
costs
per
ton
of
reduced
emissions,
as
described
above.
E.
Do
the
Benefits
Outweigh
the
Costs
of
the
Standards?
While
EPA
uses
relative
costeffectiveness
as
the
primary
manner
to
take
costs
into
consideration,
further
insight
regarding
the
standards
can
be
provided
by
benefit
cost
analysis.
The
purpose
of
this
section
is
to
summarize
the
methods
we
used
and
results
we
obtained
in
conducting
an
analysis
of
the
economic
benefits
of
the
changes
in
emissions
from
engines
covered
by
this
rule,
and
to
compare
these
economic
benefits
with
the
estimated
economic
costs
of
the
rule.
In
summary,
the
results
of
our
analysis
indicate
that
the
economic
benefits
of
the
final
standards
will
exceed
the
costs
of
meeting
the
standards.
The
annual
estimated
benefits
we
were
able
to
quantify
were
approximately
$
10
billion
in
2030.
1.
What
Was
Our
Overall
Approach
to
the
Benefit
Cost
Analysis?
The
basic
question
we
sought
to
answer
in
the
benefit
cost
analysis
was,
``
What
are
the
net
yearly
economic
benefits
to
society
of
the
reduction
in
mobile
source
emissions
likely
to
be
achieved
by
this
final
rulemaking?''
In
designing
an
analysis
to
address
this
question,
we
selected
a
future
year
for
analysis
(
2030)
that
is
representative
of
full
implementation
of
the
program
(
i.
e.,
when
the
Large
SI
and
recreational
vehicle
fleet
is
composed
of
virtually
only
compliant
vehicles).
To
quantify
benefits,
we
evaluated
PM
related
health
effects
(
including
directly
emitted
PM
and
NOX
contribution
to
particulate
nitrate)
using
a
benefits
transfer
technique.
Although
we
expect
economic
benefits
to
exist,
we
were
unable
to
quantify
or
to
value
specific
changes
in
visibility,
ozone,
CO
or
air
toxics
because
we
did
not
perform
additional
air
quality
modeling.
To
evaluate
the
PM
related
health
effects,
we
adopted
a
benefits
transfer
technique
that
relies
on
the
extensive
particulate
matter
air
quality
and
benefits
modeling
conducted
for
the
highway
Heavy
Duty
Engine/
Diesel
Fuel
final
rule.
91
That
RIA
used
an
analytical
structure
and
sequence
similar
to
that
used
in
the
``
section
812
studies''
to
estimate
the
total
benefits
and
costs
of
the
full
Clean
Air
Act.
92
In
the
HD
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8,
2002
/
Rules
and
Regulations
and
(
2)
the
first
in
the
ongoing
series
of
prospective
studies
estimating
the
total
costs
and
benefits
of
the
Clean
Air
Act
(
see
EPA
report
number:
EPA
410
R
99
001,
November
1999).
See
Docket
A
99
06,
Document
II
A
21.
93
In
the
original
HD
Engine/
Diesel
Fuel
analysis,
we
modeled
air
quality
and
benefits
in
2030.
There
are
sufficient
non
linearities
and
interactions
among
pollutants
in
the
atmospheric
chemistry
that
introduce
additional
uncertainties
in
the
quantitative
estimate
of
the
benefits
in
years
that
were
not
fully
modeled
in
the
original
analysis.
94
SAB
advised
that
the
EPA
``
continue
to
use
a
wage
risk
based
VSL
as
its
primary
estimate,
including
appropriate
sensitivity
analyses
to
reflect
the
uncertainty
of
these
estimates,''
and
that
``
the
only
risk
characteristic
for
which
adjustments
to
the
VSL
can
be
made
is
the
timing
of
the
risk''
(
EPASAB
EEAC
00
013;
a
copy
of
this
document
can
be
found
in
Docket
A
99
06,
Document
No.
IV
A
19).
In
developing
our
primary
estimate
of
the
benefits
of
premature
mortality
reductions,
we
have
appropriately
discounted
over
the
lag
period
between
exposure
and
premature
mortality.
However,
an
empirical
basis
that
meets
the
SAB's
standards
of
reliability
for
adjusting
the
current
$
6
million
VSL
for
many
of
these
factors
does
not
yet
exist.
A
discussion
of
these
factors
is
contained
in
the
RIA
and
supporting
documents.
EPA
recognizes
the
need
for
additional
research
by
the
scientific
community
to
develop
additional
empirical
support
for
adjustments
to
VSL
for
the
factors
mentioned
above.
Engine/
Diesel
Fuel
analysis,
we
used
many
of
the
same
models
and
assumptions
used
in
the
section
812
studies
as
well
as
other
Regulatory
Impact
Analyses
(
RIAs)
prepared
by
the
Office
of
Air
and
Radiation.
By
adopting
the
major
design
elements,
models,
and
assumptions
developed
for
the
section
812
studies
and
other
RIAs,
we
have
largely
relied
on
methods
which
have
already
received
extensive
review
by
the
independent
Science
Advisory
Board
(
SAB),
by
the
public,
and
by
other
federal
agencies.
Although
the
underlying
method
has
experienced
significant
review,
the
transfer
of
values
from
an
existing
primary
benefits
analysis
to
estimate
the
benefits
of
a
new
program
has
not
had
this
type
of
review
and
the
transfer
technique
introduces
additional
uncertainties.
2.
What
Are
the
Significant
Limitations
of
the
Benefit
Cost
Analysis?
Every
benefit
cost
analysis
examining
the
potential
effects
of
a
change
in
environmental
protection
requirements
is
limited
to
some
extent
by
data
gaps,
limitations
in
model
capabilities
(
such
as
geographic
coverage),
and
uncertainties
in
the
underlying
scientific
and
economic
studies
used
to
configure
the
benefit
and
cost
models.
Deficiencies
in
the
scientific
literature
often
result
in
the
inability
to
estimate
quantitative
changes
in
health
and
environmental
effects,
such
as
potential
increases
in
premature
mortality
associated
with
increased
exposure
to
carbon
monoxide.
Deficiencies
in
the
economics
literature
often
result
in
the
inability
to
assign
economic
values
even
to
those
health
and
environmental
outcomes
which
can
be
quantified.
While
these
general
uncertainties
in
the
underlying
scientific
and
economics
literatures,
which
can
cause
the
valuations
to
be
higher
or
lower,
are
discussed
in
detail
in
the
Final
Regulatory
Support
Document
and
its
supporting
documents
and
references,
the
key
uncertainties
which
have
a
bearing
on
the
results
of
the
benefit
cost
analysis
of
this
final
rule
include
the
following:
The
exclusion
of
potentially
significant
benefit
categories
(
such
as
health
and
ecological
benefits
of
reduction
in
hazardous
air
pollutants
emissions
and
ozone;
improvements
in
visibility);
Errors
in
measurement
and
projection
for
variables
such
as
population
growth;
Uncertainties
in
the
estimation
of
future
year
emissions
inventories
and
air
quality;
Uncertainties
associated
with
the
transfer
of
the
results
of
the
HD
Engine/
Diesel
Fuel
analysis
to
this
program,
especially
regarding
the
assumption
of
similarity
in
geographic
distribution
between
emissions
and
human
populations
and
years
of
analysis;
93
Variability
in
the
estimated
relationships
of
health
and
welfare
effects
to
changes
in
pollutant
concentrations;
Uncertainties
in
exposure
estimation;
Uncertainties
in
applying
willingness
to
pay
estimates
from
National
Park
and
Forest
visitors
to
U.
S.
recreational
participants
and
uncertainties
in
average
number
of
activity
days
per
year;
and
Uncertainties
associated
with
the
effect
of
potential
future
actions
to
limit
emissions.
Despite
these
uncertainties,
we
believe
the
benefit
cost
analysis
provides
a
reasonable
indication
of
the
expected
economic
benefits
of
the
final
rulemaking
in
future
years
under
a
set
of
assumptions.
One
key
area
of
uncertainty
is
the
value
of
a
statistical
life
(
VSL)
for
reductions
in
mortality
risk.
The
adoption
of
a
value
for
the
projected
reduction
in
the
risk
of
premature
mortality
is
the
subject
of
continuing
discussion
within
the
economic
and
public
policy
analysis
community.
In
accordance
with
the
independent
Science
Advisory
Board
advice,
94
we
use
the
value
of
a
statistical
life
(
VSL)
for
risk
reductions
in
mortality
in
our
primary
estimate.
Alternative
calculations
of
adjustment
for
age
and
other
factors
are
presented
in
the
RIA
for
the
HD
Engine/
Diesel
Fuel
rule
and
in
the
RSD
for
this
rule.
The
presentation
of
the
other
alternative
calculations
for
certain
endpoints
seeks
to
demonstrate
how
much
the
overall
benefit
estimate
might
vary
based
on
the
value
EPA
has
given
to
a
parameter
(
which
has
uncertainty
associated
with
it)
underlying
the
estimates
for
human
health
and
environmental
effect
incidence
and
the
economic
valuation
of
those
effects.
These
alternative
calculations
represent
conditions
that
might
occur;
however,
EPA
has
selected
the
best
values
supported
by
current
scientific
literature
for
use
in
the
primary
estimate.
The
primary
estimate
is
the
source
for
our
benefits
transfer
technique.
Even
with
our
efforts
to
fully
disclose
the
uncertainty
in
our
estimate,
our
uncertainty
presentation
method
does
not
provide
a
definitive
or
complete
picture
of
the
true
range
of
monetized
benefits
estimates.
The
set
of
alternative
calculations
is
only
representative
of
those
benefits
that
we
were
able
to
quantify
and
monetize.
3.
What
Are
the
benefits
In
the
Years
Leading
Up
to
2030?
The
final
rule
has
various
cost
and
emission
related
components,
as
described
earlier
in
this
section.
These
components
would
begin
at
various
times
and
in
some
cases
would
phase
in
over
time.
This
means
that
during
the
early
years
of
the
program
there
would
not
be
a
consistent
match
between
cost
and
benefits,
especially
where
the
full
vehicle
cost
would
be
incurred
at
the
time
of
vehicle
purchase,
while
the
fuel
savings
along
with
the
emission
reductions
and
benefits
resulting
from
all
these
costs
would
occur
throughout
the
lifetime
of
the
vehicle.
Because
of
this
inconsistency
and
our
desire
to
more
appropriately
match
the
costs
and
emission
reductions
of
our
program,
our
analysis
uses
a
future
year
(
2030)
when
the
fleet
is
nearly
fully
turned
over.
In
the
years
before
2030,
the
benefits
from
the
final
rule
will
be
less
than
those
estimated
here,
because
the
compliant
vehicle
fleet
will
not
be
fully
phased
in,
and
the
overall
U.
S.
population
would
be
smaller.
Annualized
costs,
on
the
other
hand,
reach
nearly
their
full
value
within
a
few
years
of
program
initiation
(
once
all
phase
ins
are
completed).
Thus,
a
benefit
cost
ratio
computed
for
the
earlier
years
of
the
program
would
be
expected
to
be
lower
than
a
ratio
based
on
our
2030
analysis
when
the
fleet
has
fully
turned
over.
The
stream
of
costs
and
the
limited
set
of
quantified
benefits
over
time
are
presented
in
the
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217
/
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November
8,
2002
/
Rules
and
Regulations
95
Based
upon
recent
preliminary
findings
by
the
Health
Effects
Institute,
the
concentration
response
functions
used
to
estimate
reductions
in
hospital
admissions
may
over
or
underestimate
the
true
concentration
response
relationship.
See
Letter
from
Dan
Greenberg,
President,
Health
Effects
Institute,
May
30,
2002,
attached
to
letter
from
Dr.
Hopke,
dated
August
8,
2002.
Docket
A
2000
01,
Document
IV
A
145.
96
Our
estimate
also
incorporates
significant
reductions
in
27,000
fewer
cases
of
lower
respiratory
symptoms,
and
26,600
fewer
cases
of
upper
respiratory
symptoms
in
asthmatic
children
each
year.
In
addition,
we
estimate
that
this
final
rule
will
reduce
23,400
incidents
of
asthma
attacks
each
year
in
asthmatics
of
all
ages
from
reduced
exposure
to
particles.
Additional
incidents
would
be
avoided
from
reduced
ozone
exposures.
Asthma
is
the
most
prevalent
chronic
disease
among
children
and
currently
affects
over
seven
percent
of
children
under
18
years
of
age.
Regulatory
Support
Document.
On
the
other
hand,
since
the
estimated
benefits
are
more
than
40
times
the
costs
(
excluding
fuel
savings)
in
2030,
the
emission
reduction
and
cost
trends
suggest
that
it
is
likely
that
annual
benefits
would
exceed
costs
from
a
time
early
in
the
life
of
the
program.
4.
What
Were
the
Results
of
the
Benefit
Cost
Analysis?
The
benefit
cost
analysis
for
the
final
rule
reflects
a
single
year
picture
of
the
yearly
benefits
and
costs
expected
to
be
realized
once
the
standards
have
been
fully
implemented
and
non
compliant
vehicles
have
all
been
retired.
Table
IX.
E
1
presents
EPA's
primary
estimate
of
the
benefits
of
the
rule,
both
the
estimated
reductions
in
incidences
and
the
estimated
economic
value
of
those
incidence
reductions.
In
interpreting
the
results,
it
is
important
to
keep
in
mind
the
limited
set
of
effects
we
are
able
to
monetize.
Specifically,
the
table
lists
the
avoided
PM
related
incidences
of
health
effects
and
the
estimated
economic
value
of
those
avoided
incidences.
95
We
present
estimates
for
the
reductions
for
the
Large
SI
category
only.
As
the
table
indicates,
we
estimate
that
the
final
rule
will
reduce
premature
mortality
associated
with
fine
PM
by
around
1,000
incidences
per
year,
produce
about
600
fewer
cases
of
chronic
bronchitis,
and
result
in
significant
reductions
in
minor
restricted
activity
days
(
with
an
estimated
1
million
fewer
cases).
96
TABLE
IX.
E
1.
EPA
PRIMARY
ESTIMATE
OF
THE
ANNUAL
QUANTIFIED
AND
MONETIZED
BENEFITS
ASSOCIATED
WITH
IMPROVED
PM
AIR
QUALITY
RESULTING
FROM
THE
LARGE
SI/
RECREATIONAL
VEHICLE
RULE
IN
2030
a
PM
related
endpoint
Avoided
incidence
a,
c
(
cases/
year)
Monetary
benefits
a,
d
(
millions
2002
$)
Premature
mortality
a,
b
(
adults,
ages
30
and
over)
........................................................................
1,000
..........................
$
7,510
Chronic
bronchitis
..........................................................................................................................
640
.............................
$
280
Hospital
Admissions
from
Respiratory
Causes
g
...........................................................................
300
.............................
<$
10
Hospital
Admissions
from
Cardiovascular
Causes
g
......................................................................
300
.............................
<$
10
Emergency
Room
Visits
for
Asthma
..............................................................................................
300
.............................
<$
1
Acute
bronchitis
(
children,
ages
8
12)
..........................................................................................
2,200
..........................
<$
1
Upper
respiratory
symptoms
(
asthmatic
children,
ages
9
11)
......................................................
20,600
........................
<$
1
Lower
respiratory
symptoms
(
children,
ages
7
14)
......................................................................
23,700
........................
<$
1
Asthma
attacks
(
asthmatics,
all
ages)
a
.........................................................................................
20,600
........................
<$
1
Work
loss
days
(
adults,
ages
18
65)
............................................................................................
181,300
......................
$
20
Minor
restricted
activity
days
(
adults,
ages
18
65)
(
adjusted
to
exclude
asthma
attacks)
a
........
944,400
......................
$
50
Other
health
effects
e
......................................................................................................................
U1+
U2+
U3+
U4
.............
B1+
B2+
B3+
B4
Monetized
Total
f
.....................................................................................................................
.....................................
$
7,880
+
B
a
Ozone
related
benefits
are
not
included,
thus
underestimating
national
benefits.
Relative
to
PM
related
benefits,
ozone
benefits
have
typically
accounted
for
only
a
small
portion
of
total
benefits.
However,
ozone
reductions
can
have
a
significant
impact
on
asthma
attacks
in
asthma
sufferers
as
well
as
contributing
to
reductions
in
the
overall
number
of
minor
restricted
activity
days.
b
The
value
we
are
transferring
assumes
that
some
of
the
incidences
of
premature
mortality
related
to
PM
exposures
occur
in
a
distributed
fashion
over
the
five
years
following
exposure,
and
it
embeds
an
annual
three
percent
discount
rate
to
the
value
of
premature
mortality
occurring
in
years
after
our
analysis
year.
c
Incidences
are
rounded
to
the
nearest
100.
d
Dollar
values
are
rounded
to
the
nearest
10
million.
Monetary
benefits
account
for
growth
in
real
GDP
per
capita
through
2030.
e
The
Ui
are
the
incidences
and
the
Bi
are
the
values
for
the
unquantified
category
i.
A
detailed
listing
of
unquantified
PM,
ozone,
CO,
and
HC
related
health
and
welfare
effects
is
provided
in
Table
IX
E.
2.
Many
of
the
HC
emitted
from
these
vehicles
are
also
hazardous
air
pollutants
listed
in
the
Clean
Air
Act.
f
B
is
equal
to
the
sum
of
all
unmonetized
categories,
i.
e.,
Ba+
B1+
B2+
*
*
*
+
Bn.
g
Based
upon
recent
preliminary
findings
by
the
Health
Effects
Institute,
the
concentration
response
functions
used
to
estimate
reductions
in
hospital
admissions
may
over
or
under
estimate
the
true
concentration
response
relationship.
Total
monetized
benefits
are
driven
primarily
by
the
reduction
in
premature
fatalities
each
year,
which
account
for
over
80
percent
of
total
benefits.
This
table
also
indicates
with
a
``
B''
those
additional
health
and
environmental
benefits
which
could
not
be
expressed
in
quantitative
incidence
and/
or
economic
value
terms.
A
full
listing
of
the
benefit
categories
that
could
not
be
quantified
or
monetized
in
our
estimate
are
provided
in
Table
IX.
E
2.
The
final
rule
may
also
provide
some
visibility
improvements
in
Class
I
areas
and
near
where
people
live,
work,
and
recreate.
A
full
appreciation
of
the
overall
economic
consequences
of
the
final
standards
requires
consideration
of
all
benefits
and
costs
expected
to
result
from
the
new
standards,
not
just
those
benefits
and
costs
which
could
be
expressed
here
in
dollar
terms.
TABLE
IX.
E
2.
ADDITIONAL,
NONMONETIZED
BENEFITS
OF
THE
LARGE
SI/
RECREATIONAL
VEHICLE
STANDARDS
Pollutant
Unquantified
effects
Ozone
Health
Premature
mortality.
a
Increased
airway
responsiveness
to
stimuli.
Inflammation
in
the
lung.
Chronic
respiratory
damage.
Premature
aging
of
the
lungs.
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Regulations
TABLE
IX.
E
2.
ADDITIONAL,
NONMONETIZED
BENEFITS
OF
THE
LARGE
SI/
RECREATIONAL
VEHICLE
STANDARDS
Continued
Pollutant
Unquantified
effects
Acute
inflammation
and
respiratory
cell
damage.
Increased
susceptibility
to
respiratory
infection.
Non
asthma
respiratory
emergency
room
visits.
Increased
school
absence
rates
Ozone
Welfare
Decreased
yields
for
commercial
forests
(
for
example
Western
US).
Decreased
yields
for
fruits
and
vegetables.
Decreased
yields
for
noncommercial
crops.
Damage
to
urban
ornamental
plants.
Impacts
on
recreational
demand
from
damaged
forest
aesthetics.
Damage
to
ecosystem
functions
PM
Health
......
Infant
mortality.
Low
birth
weight.
Changes
in
pulmonary
function
Chronic
respiratory
diseases
other
than
chronic
bronchitis
Cardiac
endpoints.
Morphological
changes.
Altered
host
defense
mechanisms
Cancer.
Non
asthma
respiratory
emergency
room
visits
PM
Welfare
....
Visibility
in
Class
I
areas.
Residential
and
recreational
visibility
in
non
Class
I
areas.
Soiling
and
materials
damage
Damage
to
ecosystem
functions
Nitrogen
and
Sulfate
Deposition
Welfare
Impacts
of
acidic
sulfate
and
nitrate
deposition
on
commercial
forests
Impacts
of
acidic
deposition
to
commercial
freshwater
fishing.
Impacts
of
acidic
deposition
to
recreation
in
terrestrial
ecosystems.
Reduced
existence
values
for
currently
healthy
ecosystems
Impacts
of
nitrogen
deposition
on
commercial
fishing,
agriculture,
and
forests.
TABLE
IX.
E
2.
ADDITIONAL,
NONMONETIZED
BENEFITS
OF
THE
LARGE
SI/
RECREATIONAL
VEHICLE
STANDARDS
Continued
Pollutant
Unquantified
effects
Impacts
of
nitrogen
deposition
on
recreation
in
estuarine
ecosystems.
Damage
to
ecosystem
functions
CO
Health
......
Premature
mortalitya.
Behavioral
effects.
Hospital
admissions
respiratory
cardiovascular,
and
other.
Other
cardiovascular
effects
Developmental
effects.
Decreased
time
to
onset
of
angina.
Non
asthma
respiratory
ER
visits
HC
Health
b
....
Cancer
(
benzene,
1,3
butadiene
formaldehyde,
acetaldehyde
Anemia
(
benzene).
Disruption
of
production
of
blood
components
(
benzene).
Reduction
in
the
number
of
blood
platelets
(
benzene).
Excessive
bone
marrow
formation
(
benzene).
Depression
of
lymphocyte
counts
(
benzene)
Reproductive
and
developmental
effects
(
1,3
butadiene
Irritation
of
eyes
and
mucus
membranes
(
formaldehyde).
Respiratory
irritation
(
formaldehyde).
Asthma
attacks
in
asthmatics
(
formaldehyde).
Asthma
like
symptoms
in
non
asthmatics
(
formaldehyde).
Irritation
of
the
eyes,
skin,
and
respiratory
tract
(
acetaldehyde).
Upper
respiratory
tract
irritation
and
congestion
(
acrolein)
TABLE
IX.
E
2.
ADDITIONAL,
NONMONETIZED
BENEFITS
OF
THE
LARGE
SI/
RECREATIONAL
VEHICLE
STANDARDS
Continued
Pollutant
Unquantified
effects
HC
Welfare
....
Direct
toxic
effects
to
animals
Bioaccumulation
in
the
food
chain.
Damage
to
ecosystem
function
a
Premature
mortality
associated
with
ozone
and
carbon
monoxide
is
not
separately
included
in
this
analysis.
In
this
analysis,
we
assume
that
the
ACS/
Krewski,
et
al.
C
R
function
for
premature
mortality
captures
both
PM
mortality
benefits
and
any
mortality
benefits
associated
with
other
air
pollutants.
A
copy
of
Krewski,
et
al.,
can
be
found
in
Docket
A
99
06,
Document
No.
IV
G
75.
b
Many
of
the
key
hydrocarbons
related
to
this
rule
are
also
hazardous
air
pollutants
listed
in
the
Clean
Air
Act.
In
summary,
EPA's
primary
estimate
of
the
benefits
of
the
final
rule
is
approximately
$
7.8
billion
in
2030.
This
estimate
accounts
for
growth
in
real
gross
domestic
product
(
GDP)
per
capita
between
the
present
and
2030.
The
estimated
social
cost
(
measured
as
changes
in
consumer
and
producer
surplus)
in
2030
to
implement
the
final
rule
from
Table
IX.
D
1
above
is
$
217
million
(
2001$).
The
net
social
gain,
considering
fuel
efficiency,
is
$
554
million.
The
monetized
benefits
are
approximately
$
7.8
billion,
and
EPA
believes
there
is
considerable
value
to
the
public
of
the
benefits
it
could
not
monetize.
The
net
benefit
that
can
be
monetized
is
$
8.4
billion.
Therefore,
implementation
of
the
final
rule
is
expected
to
provide
society
with
a
net
gain
in
social
welfare
based
on
economic
efficiency
criteria.
Table
IX.
E
3
summarizes
the
costs,
benefits,
and
net
benefits.
The
net
present
value
of
the
future
benefits
have
been
calculated
using
a
3%
discount
rate
over
the
2002
to
2030
time
frame.
The
net
present
value
of
the
social
gains
is
$
4,899
million
and
the
net
present
value
of
the
total
annual
benefits
is
$
77,177
million
+
B.
Consequently,
the
net
present
value
of
the
monetized
net
benefits
of
this
program
is
$
82,076
million.
If
a
discount
rate
of
7%
is
used,
the
values
above
change
to
$
2,393
million
for
social
gains
and
$
40,070
million
+
B
for
total
benefits,
giving
a
total
of
$
42,463
million.
TABLE
IX.
E
3.
2030
ANNUAL
MONETIZED
COSTS,
BENEFITS,
AND
NET
BENEFITS
FOR
THE
FINAL
RULE
Millions
of
2001
$
a
Social
Gains
f
.....................................................................................................................................................
$
550
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2002
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Rules
and
Regulations
TABLE
IX.
E
3.
2030
ANNUAL
MONETIZED
COSTS,
BENEFITS,
AND
NET
BENEFITS
FOR
THE
FINAL
RULE
Continued
Millions
of
2001
$
a
Monetized
PM
related
benefits
b,
c
......................................................................................................................
$
7,880
+
BPM
Monetized
Ozone
related
benefits
b,
d
.................................................................................................................
Not
monetized
(
BOzone)
HC
related
benefits
............................................................................................................................................
Not
monetized
(
BHC)
CO
related
benefits
............................................................................................................................................
Not
monetized
(
BCO)
Total
annual
benefits
..........................................................................................................................................
$
7,880
+
BPM
+
BOzone
+
BHC
+
BCO
Monetized
net
benefits
e
.....................................................................................................................................
$
8,430
+
B
a
For
this
section,
all
costs
and
benefits
are
rounded
to
the
nearest
10
million.
Thus,
figures
presented
in
this
chapter
may
not
exactly
equal
benefit
and
cost
numbers
presented
in
earlier
sections
of
the
chapter.
b
Not
all
possible
benefits
or
disbenefits
are
quantified
and
monetized
in
this
analysis.
Potential
benefit
categories
that
have
not
been
quantified
and
monetized
are
listed
in
Table
IX
E.
2.
Unmonetized
PM
and
ozone
related
benefits
are
indicated
by
BPM.
and
BOzone,
respectively.
c
Based
upon
recent
preliminary
findings
by
the
Health
Effects
Institute,
the
concentration
response
functions
used
to
estimate
reductions
in
hospital
admissions
may
over
or
under
estimate
the
true
concentration
response
relationship.
d
There
are
substantial
uncertainties
associated
with
the
benefit
estimates
presented
here,
as
compared
to
other
EPA
analyses
that
are
supported
by
specific
modeling.
This
analysis
used
a
benefits
transfer
technique
described
in
the
RSD.
e
B
is
equal
to
the
sum
of
all
unmonetized
benefits,
including
those
associated
with
PM,
ozone,
CO,
and
HC.
f
The
social
gains
are
equal
to
the
fuel
savings
minus
the
combined
loss
in
consumer
and
producer
surplus.
X.
Public
Participation
A
wide
variety
of
interested
parties
participated
in
the
rulemaking
process
that
culminates
with
this
final
rule.
This
process
provided
several
opportunities
for
public
comment
over
a
period
of
more
than
two
years.
An
Advance
Notice
of
Proposed
Rulemaking
(
65
FR
76797,
December
7,
2000)
announced
our
intent
to
address
emissions
from
these
engines.
Comments
received
during
this
period
were
considered
in
the
development
of
the
proposal
and
are
discussed
in
that
document.
These
comments
included
information
received
from
small
businesses
as
a
part
of
the
inter
agency
Small
Business
Advocacy
Review
Panel
process
which
was
completed
before
we
published
the
proposal
and
is
described
below
under
the
discussion
of
the
Regulatory
Flexibility
Act.
The
formal
comment
period
and
public
hearing
associated
with
the
proposal
provided
another
opportunity
for
public
input.
We
have
also
met
with
a
variety
of
stakeholders
at
various
points
in
the
process,
including
state
and
environmental
organizations,
engine
manufacturers,
and
equipment
manufacturers.
We
have
prepared
a
detailed
Summary
and
Analysis
of
Comments
document,
which
describes
the
comments
we
received
on
the
proposal
and
our
response
to
each
of
these
comments.
The
Summary
and
Analysis
of
Comments
is
available
in
the
docket
for
this
rule
and
on
the
Office
of
Transportation
and
Air
Quality
internet
home
page
at
http://
www.
epa.
gov/
otaq/
.
XI.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
the
Agency
must
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
this
Executive
Order.
The
Executive
Order
defines
a
``
significant
regulatory
action''
as
any
regulatory
action
that
is
likely
to
result
in
a
rule
that
may:
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;
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligations
of
recipients
thereof;
or
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
A
Final
Regulatory
Support
Document
has
been
prepared
and
is
available
in
the
docket
for
this
rulemaking
and
at
the
internet
address
listed
under
ADDRESSES
above.
This
action
was
submitted
to
the
Office
of
Management
and
Budget
for
review
under
Executive
Order
12866.
Annual
initial
costs
of
this
rulemaking
are
estimated
to
be
over
$
100
million
per
year
but
this
is
offset
by
operating
cost
savings
of
over
$
400
million
dollars
per
year.
Even
so,
this
rule
is
considered
economically
significant.
Written
comments
from
OMB
and
responses
from
EPA
to
OMB
comments
are
in
the
public
docket
for
this
rulemaking.
B.
Paperwork
Reduction
Act
The
information
collection
requirements
(
ICR)
in
this
rule
will
be
submitted
for
approval
to
the
Office
of
Management
and
Budget
(
OMB)
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
The
Agency
may
not
conduct
or
sponsor
an
information
collection,
and
a
person
is
not
required
to
respond
to
a
request
for
information,
unless
the
information
collection
request
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
The
reporting
requirements
in
this
final
rule
do
not
apply
until
the
Office
of
Management
has
approved
them.
We
will
publish
a
document
in
the
Federal
Register
announcing
that
the
information
collection
requirements
are
approved.
C.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
EPA
has
determined
that
it
is
not
necessary
to
prepare
a
regulatory
flexibility
analysis
in
connection
with
this
final
rule.
EPA
has
also
determined
that
this
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
For
purposes
of
assessing
the
impacts
of
this
final
rule
on
small
entities,
a
small
entity
is
defined
as:
(
1)
A
small
business
that
meet
the
definition
for
business
based
on
SBA
size
standards;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
for
profit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
This
rulemaking
will
affect
only
the
small
businesses.
In
accordance
with
section
609
of
the
RFA,
EPA
conducted
an
outreach
to
small
entities
and
convened
a
Small
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Regulations
97
59
FR
31306
(
July
17,
1994).
Business
Advocacy
Review
(
SBAR)
Panel
prior
to
proposing
this
rule,
to
obtain
advice
and
recommendations
of
representatives
of
the
small
entities
that
potentially
would
be
subject
to
the
rule's
requirements.
Through
the
Panel
process,
we
gathered
advice
and
recommendations
from
small
entity
representatives
who
would
be
affected
by
the
provisions
in
the
rule
relating
to
large
SI
engines
and
land
based
recreational
vehicles,
and
published
the
results
in
a
Final
Panel
Report,
dated
July
17,
2001.
EPA
had
previously
convened
a
separate
Panel
for
marine
engines
and
vessels.
This
panel
also
produced
a
report,
dated
August
25,
1999.
We
also
prepared
an
Initial
Regulatory
Flexibility
Analysis
(
IRFA)
in
accordance
with
section
603
of
the
Regulatory
Flexibility
Act.
The
IRFA
is
found
in
chapter
8
of
the
Draft
Regulatory
Support
Document.
Both
Panel
reports
and
the
IRFA
have
been
placed
in
the
docket
for
this
rulemaking
(
Public
Docket
A
2000
01,
items
II
A
85,
II
F
22,
and
III
B
01).
EPA
proposed
the
majority
of
the
Panel
recommendations,
and
took
comments
on
these
and
other
recommendations.
The
information
we
received
during
this
rulemaking
process
indicated
that
fewer
small
entities
would
be
significantly
impacted
by
the
rule
than
we
had
originally
estimated.
During
the
SBAR
Panel
process,
a
concern
was
raised
that
importers
would
have
limited
access
to
certified
models
for
import.
We
received
no
comments
regarding
this
concern
and
believe
that
the
supply
of
four
stroke
engines
for
ATVs
and
off
highway
motorcycles
will
continue
to
increase.
As
a
result,
we
believe
all
these
companies
should
be
able
to
find
manufacturers
that
are
able
to
supply
them
with
compliant
engines.
These
importers
incur
no
development
costs,
and
they
are
not
involved
in
adding
emission
control
hardware
or
other
variable
costs
to
provide
a
finished
product
to
market.
We
also
expect
that
the
vehicles
they
import
would
have
fuel
tanks
and
hoses
that
comply
with
the
permeation
standards.
However,
even
if
this
were
not
the
case,
the
additional
two
or
three
dollars
that
it
would
cost
to
make
them
compliant
with
the
permeation
standards
is
trifling
in
comparison
with
the
normal
selling
price
for
these
vehicles.
They
should
therefore
expect
to
buy
and
sell
their
products
with
the
normal
markup
to
cover
their
costs
and
profit.
As
noted
below,
we
expect
all
21
known
smallbusiness
importers
to
face
compliance
costs
of
less
than
one
percent
of
their
revenues.
Thus,
EPA
has
determined
that
this
final
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
We
also
made
some
changes
as
a
result
of
comments
received
on
the
proposal
that
we
believe
will
further
reduce
the
level
of
impact
to
small
entities
directly
regulated
by
the
rule.
These
can
be
found
below
in
Section
5,
``
Steps
Taken
to
Minimize
the
Impact
on
Small
Entities.''
Although
this
final
rule
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities,
EPA
has
prepared
a
Small
Business
Flexibility
Analysis
that
examines
the
impact
of
the
rule
on
small
entities,
along
with
regulatory
alternatives
that
could
reduce
that
impact.
This
analysis
would
meet
the
requirements
for
a
Final
Regulatory
Flexibility
Analysis
(
FRFA),
had
that
analysis
been
required.
The
Small
Business
Flexibility
Analysis
can
be
found
in
Chapter
8
of
the
Final
Regulatory
Support
Document,
which
is
available
for
review
in
the
docket
and
is
summarized
below.
The
key
elements
of
our
Small
Business
Flexibility
Analysis
include:
The
need
for,
and
objectives
of,
the
rule.
The
significant
issues
raised
by
public
comments,
a
summary
of
the
Agency's
assessment
of
those
issues,
and
a
statement
of
any
changes
made
to
the
proposed
rule
as
a
result
of
those
comments.
The
types
and
number
of
small
entities
to
which
the
rule
will
apply.
The
reporting,
record
keeping
and
other
compliance
requirement
of
the
rule.
The
steps
taken
to
minimize
the
impact
of
the
rule
on
small
entities,
consistent
with
the
stated
objectives
of
the
applicable
statute.
A
fuller
discussion
of
each
of
these
elements
can
be
found
in
the
Small
Business
Flexibility
Analysis
(
Chapter
8
of
the
Final
Regulatory
Support
Document).
1.
The
Need
for
and
Objectives
of
This
Rule
EPA
began
a
study
of
emissions
from
new
and
existing
nonroad
engines,
equipment,
and
vehicles
in
1991.
In
1994,
EPA
finalized
its
finding
that
nonroad
engines
as
a
whole
``
are
significant
contributors
to
ozone
or
carbon
monoxide
concentrations''
in
more
than
one
ozone
or
carbon
monoxide
nonattainment
area.
97
Clean
Air
Act
section
213
(
a)(
3)
then
requires
EPA
to
establish
standards
for
all
classes
and
categories
of
new
nonroad
engines
that
cause
or
contribute
to
ozone
or
CO
concentrations
in
more
than
one
ozone
or
CO
nonattainment
area
that
achieve
the
greatest
degree
of
emissions
reductions
achievable
taking
cost
and
other
factors
into
account.
Since
the
finding
in
1994,
EPA
has
been
engaged
in
the
process
of
establishing
programs
to
control
emissions
from
nonroad
engines
used
in
many
different
applications.
Nonroad
categories
already
regulated
include:
Land
based
compression
ignition
(
CI)
engines
(
such
as
farm
and
construction
equipment),
Small
land
based
spark
ignition
(
SI)
engines
(
such
as
lawn
and
garden
equipment
and
string
trimmers),
Marine
engines
(
outboards,
personal
watercraft,
commercial
marine
diesel,
marine
diesel
engines
under
37
kW),
Locomotive
engines.
EPA
issued
an
Advance
Notice
of
Proposed
Rulemaking
(
ANPRM)
on
December
7,
2000,
and
a
Notice
of
Proposed
Rulemaking
(
NPRM)
on
September
14,
2001,
which
continued
the
process
of
establishing
standards
for
nonroad
engines
and
vehicles,
with
proposed
new
emission
standards
for
recreational
marine
diesel
engines,
recreational
vehicles,
and
other
nonroad
spark
ignition
engines
over
19
kW.
This
final
rule
includes
emission
standards
and
related
requirements
for
these
vehicles
and
engines
that
are
consistent
with
the
requirements
of
the
Act.
2.
Summary
of
Significant
Issues
Raised
by
Public
Comments
We
received
comments
from
engine
and
equipment
manufacturers
and
consumers,
both
during
the
SBAR
Panel
process
and
during
the
comment
period
after
we
issued
the
proposal.
Smallvolume
engine
and
equipment
manufacturers
commented
on
the
financial
hardships
they
would
face
in
complying
with
the
proposed
regulations.
Most
requested
that
we
consider
hardship
provisions,
primarily
an
exemption
from
or
a
delay
in
the
implementation
of
the
proposed
standards,
or
certain
flexibilities
in
the
certification
process.
Due
to
the
wide
variety
of
engines,
vehicles,
and
equipment
covered
by
this
rulemaking,
we
decided
that
a
variety
of
provisions
were
needed
to
address
the
concerns
of
the
small
entities
involved.
Changes
to
the
proposal
as
a
result
of
comments
from
small
entity
representatives
or
others
are
noted
below
in
Section
5
for
each
of
the
sectors
affected
by
this
rule.
The
NPRM
proposed
only
exhaust
emission
controls
for
recreational
vehicles.
However,
several
commenters
raised
the
issue
of
control
of
evaporative
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emissions
related
to
permeation
from
fuel
tanks
and
fuel
hoses.
They
maintained
that
our
obligations
under
section
213
of
the
Clean
Air
Act
included
control
of
permeation
emissions,
and
pointed
to
work
done
by
the
California
ARB
on
emissions
from
plastic
fuel
tanks
and
rubber
fuel
line
hoses,
as
well
as
from
portable
plastic
fuel
containers.
Our
own
investigation
into
hydrocarbon
emissions
related
to
permeation
of
fuel
tanks
and
fuel
hoses
from
recreational
land
based
and
marine
applications
also
supported
the
concerns
raised
by
the
commenters.
Therefore,
on
May
1,
2002,
we
published
a
notice
in
the
Federal
Register
reopening
the
comment
period
and
requesting
comment
on
possible
approaches
to
regulating
permeation
emissions
from
recreational
vehicles.
The
notice
also
included
the
expected
costs
and
emission
reductions
resulting
from
these
approaches.
Commenters
were
given
thirty
days
from
May
1,
2002
to
provide
comments
on
the
notice.
We
received
comments
from
several
affected
businesses,
including
at
least
one
small
entity.
These
comments
have
been
addressed
in
this
final
rulemaking,
including
several
changes
made
to
the
provisions
as
a
result
of
the
comments.
c.
Numbers
and
Types
of
Small
Entities
Affected
The
following
table
provides
an
overview
of
the
primary
SBA
small
business
categories
potentially
affected
by
this
regulation.
TABLE
XI.
C
1:
PRIMARY
SBA
SMALL
BUSINESS
CATEGORIES
POTENTIALLY
AFFECTED
BY
THIS
REGULATION
Industry
NAICSa
Codes
Defined
by
SBA
as
a
small
business
if:
b
Motorcycles
and
motorcycle
parts
manufacturers
........................................................................................
336991
<
500
employees.
Snowmobile
and
ATV
manufacturers
...........................................................................................................
336999
<
500
employees.
Independent
Commercial
Importers
of
Vehicles
and
parts
..........................................................................
421110
<
100
employees.
Nonroad
SI
engines
......................................................................................................................................
333618
<
1,000
employees.
Internal
Combustion
Engines
.......................................................................................................................
333618
<
1,000
employees.
Boat
Building
and
Repairing
.........................................................................................................................
336612
<
500
employees.
Fuel
Tank
Manufacturers
..............................................................................................................................
336211
<
1,000
employees.
a
North
American
Industry
Classification
System
b
According
to
SBA's
regulations
(
13
CFR
part
121),
businesses
with
no
more
than
the
listed
number
of
employees
or
dollars
in
annual
receipts
are
considered
``
small
entities''
for
purposes
of
a
regulatory
flexibility
analysis.
The
small
entities
directly
regulated
by
this
rule
are
the
following:
a.
Recreational
Vehicles
(
ATVs,
snowmobiles,
and
off
highway
motorcycles).
The
ATV
sector
has
the
broadest
assortment
of
manufacturers.
There
are
seven
large
companies
representing
over
95
percent
of
total
domestic
ATV
sales.
The
remaining
5
percent
come
from
small
manufacturers
or
importers,
who
tend
to
import
inexpensive,
youth
oriented
ATVs
from
China
and
other
Asian
nations.
We
have
identified
21
small
companies
that
offer
off
highway
motorcycles,
ATVs,
or
both
products.
Annual
unit
sales
for
these
companies
can
range
from
a
few
hundred
to
several
thousand
units
per
year.
There
are
three
small
businesses
manufacturing
off
highway
motorcycles
in
the
U.
S.
Two
of
these
make
only
competition
models,
so
do
not
need
to
certify
their
products
under
this
regulation.
The
remaining
off
highway
motorcycle
manufacturer
already
offers
engines
that
should
be
meeting
the
new
emission
standards,
especially
under
our
provisions
allowing
design
based
certification.
There
is
one
small
business
manufacturing
two
separate
youth
ATV
models.
This
company
already
uses
four
stroke
engines.
Also,
the
standards
are
based
on
emissions
per
watt
hour,
which
are
less
costly
to
meet
for
models
with
smalldisplacement
engines.
As
a
result,
we
expect
both
of
these
manufacturers
to
face
compliance
costs
less
than
one
percent
of
their
revenues.
We
expect
all
21
small
business
importers
to
face
compliance
costs
less
than
one
percent
of
their
revenues.
These
companies
incur
no
development
costs
and
they
are
not
involved
in
adding
emission
control
hardware
or
other
variable
costs
to
provide
a
finished
product
to
market.
As
a
result,
they
should
expect
to
buy
and
sell
their
products
with
the
normal
mark
up
to
cover
their
costs
and
profit.
During
the
SBAR
Panel
process,
the
concern
was
raised
that
importers
might
have
limited
access
to
certified
models
for
import.
We
received
no
comments
confirming
this
concern
and
believe
that
the
supply
of
four
stroke
engines
for
ATVs
and
offhighway
motorcycles
will
continue
to
increase;
as
a
result
all
these
companies
should
be
able
to
find
manufacturers
that
are
able
to
supply
compliant
engines
into
the
U.
S.
market.
We
further
believe
that
compliance
with
the
permeation
standards
will
not
place
a
significant
burden
on
either
the
small
manufacturers
or
on
the
importers.
We
have
estimated
the
incremental
cost
of
compliance
for
ATVs
and
off
highway
motorcycles
at
roughly
three
dollars
per
vehicle.
This
estimate
includes
shipping,
and
is
based
on
buying
the
necessary
lowpermeability
hoses
and
surface
treatment
for
the
fuel
tanks
from
outside
suppliers.
Thus,
no
capital
outlays
are
required,
and
the
increase
in
vehicle
cost
is
insignificant,
so
that
it
can
easily
be
passed
along
to
the
ultimate
consumer.
However,
to
ensure
that
these
requirements
do
not
adversely
affect
small
manufacturers,
we
are
implementing,
where
they
are
applicable
to
permeation,
the
same
flexibility
options
we
proposed
for
the
exhaust
emission
standards.
Based
on
available
industry
information,
four
major
manufacturers
account
for
over
99
percent
of
all
domestic
snowmobile
sales.
The
remaining
one
percent
comes
from
very
small
manufacturers
who
tend
to
specialize
in
unique
and
highperformance
designs.
One
potential
manufacturer
is
not
a
small
business,
but
hopes
to
produce
snowmobiles
within
the
next
year.
Most
of
these
manufacturers
build
less
than
50
units
per
year.
We
have
identified
three
small
manufacturers
of
snowmobiles
who
are
still
in
business
(
of
five
originally
identified).
Two
of
these
companies
specialize
in
high
performance
versions
of
standard
recreational
snowmobile
types
(
i.
e.,
travel
and
mountain
sleds).
The
other
manufacturer
produces
a
unique
design,
which
is
a
small
scooterlike
snowmobile
designed
to
be
ridden
standing
up.
This
manufacturer
provided
no
response
to
repeated
outreach
efforts
to
determine
potential
economic
effects
of
the
final
rule,
but
could
be
expected
to
use
production
engines
certified
to
the
Small
SI
standards.
There
are
thus
three
small
businesses
currently
producing
snowmobiles
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the
U.
S.
market.
One
of
these
currently
makes
a
mix
of
two
stroke
and
fourstroke
models
and
will
likely
rely
on
the
provision
allowing
separate
standards
for
certain
manufacturers
to
produce
low
emitting
engines
with
a
streamlined
development
effort.
Estimated
compliance
costs
for
this
company
are
less
than
one
percent
of
revenues.
Costs
for
the
company
producing
the
standup
snowmobile
should
also
be
less
than
one
percent.
The
third
manufacturer
sells
a
single
snowmobile
model
in
addition
to
a
sizable
business
of
supplying
aftermarket
parts
for
snowmobiles
from
other
manufacturers.
We
don't
have
revenue
information
for
the
whole
company,
but
with
such
low
sales
volumes,
we
estimate
that
this
company's
compliance
costs
could
reach
4
10
percent
of
annual
snowmobile
revenues.
Control
of
permeation
emissions
was
not
part
of
the
SBAR
Panel
process.
We
received
comments
from
one
small
snowmobile
manufacturer
who
stated
that
it
would
experience
additional
hardship
due
to
the
permeation
standards,
because
they
do
not
have
the
sales
volume
to
install
the
barrier
treatment
for
fuel
tanks
in
house.
They
also
commented
that
if
shipping
and
processing
of
fuel
tanks
took
3
4
months,
it
would
be
difficult
for
a
small
business
to
tie
up
funds
for
so
long.
However,
we
believe
that
the
permeation
control
requirements
should
be
relatively
easy
for
small
businesses
to
meet,
given
the
relatively
low
costs
involved
($
5
to
$
7
per
sled,
based
on
outside
vendor
costs).
This
is
insignificant
in
comparison
to
the
cost
of
the
high
end
sleds
that
this
company
produces
and
should
not
materially
affect
the
company's
cash
flow.
We
also
believe
it
is
not
necessary,
or
costeffective
for
a
small
entity
to
make
the
capital
investments
for
in
house
treatment
facilities.
Low
permeation
fuel
hoses
are
available
from
vendors
today,
and
we
would
expect
that
surface
treatment
would
be
applied
through
an
outside
company,
rather
than
installing
a
treatment
facility
in
house.
In
any
event,
to
make
sure
that
these
requirements
do
not
adversely
affect
small
manufacturers,
we
are
implementing,
where
they
are
applicable
to
permeation,
the
same
flexibility
options
we
proposed
for
the
exhaust
emission
standards.
b.
Marine
Vessels.
Marine
vessels
include
the
boat,
engine,
and
fuel
system.
Exhaust
emission
controls
including
NTE
requirements,
as
addressed
in
the
August
29,
1999
and
July
17,
2001
SBAR
Panel
Reports,
may
affect
the
engine
manufacturers
and
may
affect
boat
builders.
We
have
determined
that
at
least
16
companies
manufacture
marine
diesel
engines
for
recreational
vessels.
Nearly
75
percent
of
diesel
engines
sales
for
recreational
vessels
in
2000
can
be
attributed
to
three
large
companies.
Six
of
the
16
identified
companies
are
considered
small
businesses
as
defined
by
SBA.
Based
on
sales
estimates
for
2000,
these
six
companies
represent
approximately
4
percent
of
recreational
marine
diesel
engine
sales.
The
remaining
companies
each
comprise
between
two
and
seven
percent
of
sales
for
2000.
We
are
thus
aware
of
six
small
businesses
producing
marine
diesel
engines
that
may
be
considered
recreational.
Three
of
these
companies
produce
both
commercial
and
recreational
models
without
significant
differences,
so
we
expect
them
to
meet
the
standards
in
this
final
rule
with
little
more
than
the
administrative
expenses
associated
with
including
recreational
models
in
their
commercial
engine
families.
High
performance
recreational
marine
diesel
engines
already
include
technologies
that
help
control
NOX
emissions,
so
our
cost
estimates
include
relatively
modest
development
costs
to
add
new
technologies.
Moreover,
the
smallbusiness
provisions
allowing
substantial
additional
lead
time
provide
an
opportunity
for
these
companies
to
spread
development
and
certification
costs
over
several
years.
As
a
result,
we
expect
one
small
business
to
have
compliance
costs
approaching
one
percent
and
one
to
have
compliance
costs
between
1
and
3
percent.
One
very
small
business
could
have
compliance
costs
of
about
four
percent
of
annual
revenues.
c.
Large
Spark
ignition
Engines.
We
are
aware
of
two
manufacturers
of
Large
SI
engines
qualifying
as
small
businesses.
One
of
these
companies
plans
to
produce
engines
that
meet
the
standards
adopted
by
California
ARB
in
2004,
with
the
possible
exception
of
one
engine
family.
The
other
company
is
attempting
to
restart
the
production
of
engines
from
another
failed
company.
This
company
did
not
exist
during
the
SBAR
Panel
process
associated
with
this
rule.
The
established
company
will
face
relatively
small
compliance
costs
as
a
result
of
this
rule,
since
Californiacompliant
engines
will
need
only
a
small
amount
of
additional
development
effort
to
meet
long
term
standards.
These
costs
should
be
less
than
one
percent
of
revenues.
The
start
up
company
faces
significant
development
costs,
though
much
of
this
effort
is
required
to
improve
the
engine
enough
to
sustain
a
market
presence
as
other
manufacturers
continue
to
make
improvements
to
competitive
engines.
Under
the
hardship
provisions,
we
expect
the
start
up
company
to
spread
compliance
costs
over
several
years
to
reduce
the
impact
of
emission
standards.
We
nevertheless
estimate
that
the
compliance
costs
associated
with
meeting
EPA
emission
standards
are
about
5
percent
of
revenues.
Since
this
manufacturer
is
operating
in
a
niche
market,
with
customers
providing
public
comments
citing
the
need
for
these
engines,
we
expect
that
most
of
the
increased
cost
of
production
will
be
recovered
by
increased
revenues.
d.
Result
for
all
Small
Entities.
For
this
regulation
as
a
whole,
we
expect
32
small
businesses
to
have
total
compliance
costs
less
than
1
percent
of
their
annual
revenues.
We
estimate
that
one
company
will
have
compliance
costs
between
1
and
3
percent
of
revenues.
Three
companies
will
likely
have
compliance
costs
exceeding
3
percent
of
revenues,
but
at
least
one
will
likely
be
able
to
benefit
from
the
relief
provisions
outlined
below.
These
estimates
include
the
costs
for
compliance
with
the
permeation
standards.
4.
Reporting,
Record
Keeping,
and
Compliance
Requirements
For
any
emission
control
program,
we
need
assurance
that
the
regulated
engines
will
meet
the
standards.
Historically,
EPA
programs
have
assigned
manufacturers
the
responsibility
to
provide
these
assurances.
This
final
rule
includes
testing,
reporting,
and
record
keeping
requirements.
Testing
requirements
for
some
manufacturers
include
certification
(
including
deterioration
testing)
and
production
line
testing.
Reporting
and
record
keeping
requirements
include
test
data
and
technical
data
on
the
engines,
including
defect
reporting.
5.
Steps
Taken
To
Minimize
the
Impact
on
Small
Entities
The
two
SBAR
Panels
considered
a
variety
of
provisions
to
reduce
the
burden
of
complying
with
new
emission
standards
and
related
requirements.
Some
of
these
provisions
(
such
as
emission
credit
programs)
would
apply
to
all
companies,
while
others
would
be
targeted
at
the
unique
circumstances
faced
by
small
businesses.
A
complete
discussion
of
the
regulatory
alternatives
recommended
by
the
Panels
can
be
found
in
the
Final
Panel
Reports.
Summaries
of
the
Panels'
recommended
alternatives
for
each
of
the
sectors
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Rules
and
Regulations
subject
to
this
action
can
also
be
found
in
their
respective
sections
of
the
preamble.
The
following
Panel
recommendations
are
being
finalized
by
the
Agency,
except
for
a
few
items
as
noted
below:
(
A)
Related
Federal
Rules
The
Panel
recommended
that
EPA
continue
to
consult
with
the
CPSC
in
developing
the
rule
to
better
understand
the
scope
of
the
Commission's
regulations
as
they
may
relate
to
the
competition
exemption.
(
B)
Regulatory
Flexibility
Alternatives
The
Panel
recommended
that
EPA
consider
and
seek
comments
on
a
wide
range
of
alternatives,
including
the
flexibility
options
described
below.
As
noted
above,
we
issued
a
subsequent
Federal
Register
notice
dated
May
1,
2002
(
67
FR
21613),
seeking
comment
on
applying
permeation
control
standards
for
fuel
tanks
and
fuel
hoses
used
on
recreational
vehicles.
The
flexibilities
listed
below
for
recreational
vehicles
would
generally
also
apply
to
those
controls,
which
would
effectively
extend
the
panel
recommendations
to
the
permeation
controls
as
well.
(
1)
Large
SI
Engines
The
Panel
recommended
that
EPA
propose
several
possible
provisions
to
address
concerns
that
the
new
EPA
standards
could
potentially
place
small
businesses
at
a
competitive
disadvantage
to
larger
entities
in
the
industry.
These
provisions
are
described
below.
(
a)
Using
Certification
and
Emission
Standards
From
Other
EPA
Programs.
The
Panel
made
several
recommendations
for
this
provision.
First,
the
Panel
recommended
that
EPA
temporarily
expand
this
arrangement
to
allow
small
numbers
of
constant
speed
engines
up
to
2.5
liters
(
up
to
30kW)
to
be
certified
to
the
Small
SI
standards.
Second,
the
Panel
further
recommended
that
EPA
seek
comment
on
the
appropriateness
of
limiting
the
sales
level
of
300.
Third,
the
Panel
recommended
that
EPA
request
comment
on
the
anticipated
cap
of
30
kW
on
the
special
treatment
provisions
outlined
above,
or
whether
a
higher
cap
on
power
rating
is
appropriate.
Finally,
the
Panel
recommended
that
EPA
propose
to
allow
small
volume
manufacturers
producing
engines
up
to
30kW
to
certify
to
the
Small
SI
standards
during
the
first
3
model
years
of
the
program.
Thereafter,
the
standards
and
test
procedures
which
could
apply
to
other
companies
at
the
start
of
the
program
would
apply
to
small
businesses.
We
are
not
adopting
this
provision
and
are
instead
relying
on
the
hardship
provisions
in
the
final
rule,
which
will
allow
us
to
accomplish
the
objective
of
the
proposed
provision
with
more
flexibility.
(
b)
Delay
of
Emission
Standards.
The
Panel
recommended
that
EPA
propose
to
delay
the
applicability
of
the
longterm
standards
to
small
volume
manufacturers
for
three
years
beyond
the
date
at
which
they
would
generally
apply
to
accommodate
the
possibility
that
small
companies
need
to
undertake
further
design
work
to
adequately
optimize
their
designs
and
to
allow
them
to
recover
the
costs
associated
with
the
near
term
emission
standards.
We
are
also
folding
this
provision
into
the
scope
of
the
hardship
provision,
but
have
decided
to
increase
the
delay
to
up
to
four
years,
depending
on
the
nature
of
the
hardship
involved.
(
c)
Production
Line
Testing.
The
Panel
made
several
recommendations
for
this
provision.
First,
the
Panel
recommended
that
EPA
adopt
provisions
allowing
more
flexibility
than
is
available
under
the
California
Large
SI
program
or
other
EPA
programs
in
general
to
address
the
concern
that
production
line
testing
is
another
area
where
small
volume
manufacturers
typically
face
a
difficult
testing
burden.
Second,
the
Panel
recommended
that
EPA
allow
small
volume
manufacturers
to
have
a
reduced
testing
rate
if
they
have
consistently
good
test
results
from
testing
production
line
engines.
Finally,
the
Panel
recommended
that
EPA
allow
small
volume
manufacturers
to
use
alternative
low
cost
testing
options
to
show
that
production
line
engines
meet
emission
standards.
(
d)
Deterioration
Factors.
The
Panel
recommended
that
EPA
allow
smallvolume
manufacturers
to
develop
deterioration
factors
based
on
available
emission
measurements
and
good
engineering
judgment.
(
e)
Hardship
Provision.
The
Panel
recommended
that
EPA
propose
two
types
of
hardship
provisions
for
Large
SI
engines.
First
the
Panel
recommended
that
EPA
allow
small
businesses
to
petition
EPA
for
up
to
three
years
of
additional
lead
time
to
comply
with
the
standards.
Second,
the
Panel
recommended
that
EPA
allow
small
businesses
to
apply
for
hardship
relief
if
circumstances
outside
their
control
cause
the
failure
to
comply
(
such
as
a
supply
contract
broken
by
a
parts
supplier)
and
if
the
failure
to
sell
the
subject
engines
would
have
a
major
impact
on
the
company's
solvency.
(
2)
Off
Highway
Motorcycles
and
ATVs
The
NPRM
for
this
rule
discussed
several
flexibility
options
for
small
businesses
manufacturing
recreational
vehicles,
based
on
the
SBAR
Panel
process.
When
we
reopened
the
comment
period
on
May
1,
2002
to
request
comment
on
possible
approaches
to
regulating
permeation
emissions
from
recreational
vehicles,
we
did
not
specifically
discuss
small
business
issues.
However,
it
is
our
intent
that
these
provisions
carry
over
to
permeation
controls
as
well.
The
Panel
made
the
following
recommendations
for
this
subcategory:
(
a)
General
Recommendations.
(
1)
The
Panel
recommended
that
EPA
propose
to
apply
the
flexibilities
described
below
to
engines
produced
or
imported
by
small
entities
with
combined
offhighway
motorcycle
and
ATV
annual
sales
of
less
than
5,000
units
per
model
year.
(
2)
The
Panel
recommended
that
EPA
request
comment
on
the
appropriateness
of
the
5,000
unit
per
model
year
threshold.
(
3)
The
Panel
recommended
that
EPA
request
comment
on
allowing
small
entities
with
sales
in
excess
of
5,000
units
to
certify
using
the
flexible
approaches
described
below
for
a
number
of
engines
equal
to
their
2000
or
2001
sales
level.
(
4)
The
Panel
recommended
that
EPA
describe
and
seek
comment
on
the
effect
of
the
standards
on
these
entities,
including
a
request
for
any
data
and/
or
related
studies
to
estimate
the
extent
to
which
sales
of
their
products
are
likely
to
be
reduced
as
a
result
of
changes
in
product
price
that
are
attributable
to
the
emission
standards.
(
5)
The
Panel
recommended
that,
in
the
final
rule,
EPA
assess
any
information
received
in
response
to
this
request
for
purposes
of
informing
the
final
rule
decision
making
process
on
whether
additional
flexibility
(
beyond
that
considered
in
this
report)
is
warranted.
(
b)
Additional
Lead
Time
To
Meet
Emission
Standards.
First,
the
Panel
recommended
that
EPA
propose
at
least
a
two
year
delay,
but
seek
comment
on
whether
a
larger
time
period
is
appropriate
given
the
costs
of
compliance
for
small
businesses
and
the
relationship
between
importers
and
their
suppliers.
Second,
the
Panel
recommended
that
EPA
provide
additional
time
for
small
volume
manufacturers
to
revise
their
manufacturing
process,
and
would
allow
importers
to
change
their
supply
chain
to
acquire
complying
products.
Third,
the
Panel
recommended
that
EPA
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Rules
and
Regulations
request
comment
on
the
appropriate
length
for
a
delay
(
lead
time).
(
c)
Design
Certification.
The
Panel
recommended
that
EPA
propose
to
permit
small
entities
to
use
designbased
certification.
The
Panel
also
recommended
that
EPA
work
with
the
small
entity
representatives
and
other
members
of
the
industry
to
develop
appropriate
criteria
for
such
designbased
certification.
(
d)
Broaden
Engine
Families.
The
Panel
recommended
that
EPA
request
comment
on
engine
family
flexibility
and
conducting
design
based
certification
emissions
testing.
(
e)
Production
Line
Testing
Waiver.
The
Panel
recommended
that
EPA
propose
to
provide
small
manufacturers
and
small
importers
a
waiver
from
manufacturer
production
line
testing.
The
Panel
also
recommended
that
EPA
request
comment
on
whether
limits
or
the
scope
of
this
waiver
are
appropriate.
(
f)
Use
of
Assigned
Deterioration
Factors
During
Certification.
The
Panel
recommended
that
EPA
propose
to
provide
small
business
with
the
option
to
use
assigned
deterioration
factors.
(
g)
Using
Certification
and
Emission
Standards
from
Other
EPA
Programs.
The
Panel
recommended
that
EPA
propose
to
provide
small
business
with
this
flexibility
through
the
fifth
year
of
the
program
and
request
comment
on
which
of
the
already
established
standards
and
programs
are
believed
to
be
a
useful
certification
option
for
the
small
businesses.
(
h)
Averaging,
Banking,
and
Trading.
The
Panel
recommended
that
EPA
propose
to
provide
small
business
with
the
same
averaging,
banking,
and
trading
program
flexibilities
that
would
apply
for
large
manufacturers
and
request
comment
on
how
the
provisions
could
be
enhanced
for
small
business
to
make
them
more
useful.
(
i)
Hardship
Provisions.
The
Panel
recommended
that
EPA
propose
two
types
of
hardship
program
for
offhighway
motorcycles
and
ATVs:
First,
EPA
should
allow
small
manufacturers
and
small
importers
to
petition
EPA
for
limited
additional
lead
time
to
comply
with
the
standards.
Second,
EPA
should
allow
small
manufacturers
and
small
importers
to
apply
for
hardship
relief
if
circumstances
outside
their
control
cause
the
failure
to
comply
(
such
as
a
supply
contract
broken
by
a
parts
supplier)
and
if
failure
to
sell
the
subject
engines
or
vehicles
would
have
a
major
impact
on
the
company's
solvency.
The
Panel
also
recommended
that
EPA
propose
both
aspects
of
the
hardship
provisions
for
small
offhighway
motorcycle
and
ATV
manufacturers
and
importers
and
seek
comment
on
the
implementation
provisions.
(
3)
Marine
Vessels
(
a)
Delay
Standards
for
Five
Years.
The
Panel
recommended
that
EPA
delay
the
standards
for
five
years
for
small
businesses.
(
b)
Design
Based
Certification.
The
Panel
recommended
that
EPA
allow
manufacturers
to
certify
by
design
and
to
be
able
use
this
to
generate
credits
under
this
approach.
The
Panel
also
recommended
that
EPA
provide
adequately
detailed
design
specifications
and
associated
emission
levels
for
several
technology
options
that
could
be
used
to
certify.
Although
we
proposed
this
approach,
we
were
unable
to
specify
any
technology
options
for
diesel
engines
that
could
be
used
for
design
based
certification.
We
requested
comment
on
such
designs
and
received
no
comment.
Therefore,
we
are
not
finalizing
a
design
based
certification
option.
However,
we
are
finalizing
the
engine
dresser
provisions
and
expanding
these
provisions
to
include
water
cooled
turbocharging.
This
will
allow
some
engines
to
be
exempt
from
the
standards
based
on
design.
(
c)
Broadly
Defined
Product
Certification
Families.
The
Panel
recommended
that
EPA
take
comment
on
the
need
for
broadly
defined
emission
families
and
how
these
families
should
be
defined.
(
d)
Hardship
Provisions.
The
Panel
recommended
that
EPA
propose
two
types
of
hardship
programs
for
marine
engine
manufacturers,
boat
builders
and
fuel
tank
manufacturers:
First,
that
we
should
allow
small
businesses
to
petition
us
for
additional
lead
time
to
comply
with
the
standards.
Second,
EPA
should
allow
small
businesses
to
apply
for
hardship
relief
if
circumstances
outside
their
control
cause
the
failure
to
comply
(
such
as
a
supply
contract
broken
by
a
parts
supplier)
and
if
the
failure
to
sell
the
subject
fuel
tanks
or
boats
would
have
a
major
impact
on
the
company's
solvency.
The
Panel
also
recommended
that
EPA
work
with
small
manufacturers
to
develop
these
criteria
and
how
they
would
be
used.
(
e)
Burden
Reduction
Approaches
Designed
for
Small
Marinizers
of
Marine
Engines
With
Respect
to
NTE
Provisions.
The
Panel
recommended
that
EPA
specifically
include
NTE
in
a
design
based
approach.
(
4)
Snowmobiles
As
noted
above,
permeation
standards
were
not
part
of
the
original
NPRM
for
this
rule,
which
incorporated
recommendations
from
the
SBAR
Panel
process.
When
we
reopened
the
comment
period
on
May
1,
2002
to
request
comment
on
possible
approaches
to
regulating
permeation
emissions
from
recreational
vehicles,
which
would
apply
to
snowmobiles
as
well
as
to
off
highway
motorcycles
and
ATVs,
we
did
not
specifically
discuss
small
business
issues.
However,
it
is
our
intent
that
the
proposed
flexibilities
for
exhaust
emissions
carry
over
to
permeation
controls
for
all
three
vehicle
categories,
to
the
extent
that
they
are
applicable.
(
a)
Delay
of
Emission
Standards.
The
Panel
recommended
that
EPA
propose
to
delay
the
standards
for
small
snowmobile
manufacturers
by
two
years
from
the
date
at
which
other
manufacturers
would
be
required
to
comply.
The
Panel
also
recommended
that
EPA
propose
that
the
emission
standards
for
small
snowmobile
manufacturers
be
phased
in
over
an
additional
two
year
(
four
years
to
fully
implement
the
standard).
Thus,
the
2006
Phase
1
standards
would
be
phased
in
at
50/
100
percent
in
2008/
2009,
the
Phase
2
standards
would
be
phased
in
at
50/
100
percent
in
2012/
2013,
and
the
Phase
3
standards
would
be
phased
in
at
50/
100
percent
in
2014/
2015.
(
b)
Design
Based
Certification.
The
Panel
recommended
that
EPA
take
comment
on
how
design
based
certification
could
be
applied
to
small
snowmobile
manufacturers,
and
that
EPA
work
with
the
small
entities
in
the
design
and
implementation
of
this
concept.
(
c)
Broader
Engine
Families.
The
Panel
recommended
that
EPA
propose
a
provision
for
small
snowmobile
manufactures
that
would
use
relaxed
criteria
for
what
constitutes
an
engine
or
vehicle
family.
(
d)
Elimination
of
Production
Line
Testing
Requirements.
The
Panel
recommended
that
EPA
propose
that
small
snowmobile
manufacturers
not
be
subject
to
production
line
testing
requirements.
(
e)
Use
of
Assigned
DF
During
Certification.
The
Panel
recommended
that
EPA
propose
to
allow
small
snowmobile
manufacturers
to
elect
to
use
deterioration
factors
determined
by
EPA
to
demonstrate
end
of
useful
life
emission
levels,
thus
reducing
development/
testing
burdens,
rather
than
performing
a
durability
demonstration
for
each
engine
family
as
part
of
the
certification
testing
requirement.
(
f)
Using
Certification
and
Emission
Standards
From
Other
EPA
Programs.
The
Panel
recommended
that
EPA
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Rules
and
Regulations
propose
to
provide
small
business
with
the
flexibility
to
use
an
engine
certified
to
another
EPA
program
without
recertifying
it
in
its
new
application
provided
that
the
manufacturer
does
not
alter
the
engine
in
such
a
way
as
to
cause
it
to
exceed
the
emission
standards
it
was
originally
certified
to
meet.
(
g)
Averaging,
Banking
and
Trading.
The
Panel
recommended
that
EPA
propose
an
averaging,
banking
and
trading
program
for
snowmobiles,
and
seek
comment
on
additional
flexibilities
related
to
emission
credits
that
should
be
considered
for
small
snowmobile
manufacturers.
(
h)
Hardship
Provisions.
The
Panel
recommended
that
EPA
propose
two
types
of
hardship
programs
for
small
snowmobile
manufacturers.
First,
EPA
should
allow
small
snowmobile
manufacturers
to
petition
EPA
for
additional
lead
time
to
comply
with
the
standards.
Second,
EPA
should
allow
small
snowmobile
manufacturers
to
apply
for
hardship
relief
if
circumstances
outside
their
control
cause
the
failure
to
comply
(
such
as
a
supply
contract
broken
by
a
parts
supplier)
and
if
failure
to
sell
the
subject
engines
or
vehicles
would
have
a
major
impact
on
the
company's
solvency.
(
i)
Unique
Snowmobile
Engines.
The
Panel
recommended
that
EPA
seek
comment
on
an
additional
provision,
which
would
allow
a
small
snowmobile
manufacturer
to
petition
EPA
for
relaxed
standards
for
one
or
more
engine
families.
The
Panel
also
recommended
that
EPA
allow
a
provision
for
EPA
to
set
an
alternative
standard
at
a
level
between
the
prescribed
standard
and
the
baseline
level
until
the
engine
family
is
retired
or
modified
in
such
a
way
as
to
increase
emission
and
for
the
provision
to
be
extended
for
up
to
300
engines
per
year
per
manufacturer
would
assure
it
is
sufficiently
available
for
those
manufacturers
for
whom
the
need
is
greatest.
However,
we
received
comment
that
the
limit
of
300
is
too
restrictive
to
be
of
much
assistance
to
small
businesses.
Based
on
this
comment
we
are
adopting
a
limit
for
this
provision
of
600
snowmobiles
per
year.
Finally,
the
Panel
recommended
that
EPA
seek
comment
on
initial
and
deadline
dates
for
the
submission
of
such
petitions.
We
received
no
comments
in
this
area,
but
for
clarity
have
decided
to
require
at
least
nine
months
lead
time
by
the
petitioner.
(
5)
Conclusion
In
summary,
considering
both
exhaust
emission
and
permeation
regulations,
we
have
found
that
only
three
small
entities
are
likely
to
be
impacted
by
more
than
3
percent
of
their
sales,
and
the
degree
of
impact
is
likely
to
be
further
reduced
by
the
flexibilities
that
are
being
finalized
in
this
rulemaking.
Therefore,
this
final
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
D.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
4,
establishes
requirements
for
federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
state,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
federal
mandates''
that
may
result
in
expenditures
to
state,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
one
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
of
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
This
rule
contains
no
federal
mandates
for
state,
local,
or
tribal
governments
as
defined
by
the
provisions
of
Title
II
of
the
UMRA.
The
rule
imposes
no
enforceable
duties
on
any
of
these
governmental
entities.
Nothing
in
the
rule
would
significantly
or
uniquely
affect
small
governments.
EPA
has
determined
that
this
rule
contains
federal
mandates
that
may
result
in
expenditures
of
more
than
$
100
million
to
the
private
sector
in
any
single
year.
EPA
believes
that
this
rule
represents
the
least
costly,
most
costeffective
approach
to
achieve
the
air
quality
goals
of
the
rule.
The
costs
and
benefits
associated
with
the
rule
are
discussed
in
Section
IX
and
in
the
Small
Business
Support
Document,
as
required
by
the
UMRA.
E.
Executive
Order
13132:
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
are
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
Under
Section
6
of
Executive
Order
13132,
EPA
may
not
issue
a
regulation
that
has
federalism
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,
unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
State
and
local
governments,
or
EPA
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
regulation.
EPA
also
may
not
issue
a
regulation
that
has
federalism
implications
and
that
preempts
State
law,
unless
the
Agency
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
regulation.
Section
4
of
the
Executive
Order
contains
additional
requirements
for
rules
that
preempt
State
or
local
law,
even
if
those
rules
do
not
have
federalism
implications
(
i.
e.,
the
rules
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
states,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government).
Those
requirements
include
providing
all
affected
State
and
local
officials
notice
and
an
opportunity
for
appropriate
participation
in
the
development
of
the
regulation.
If
the
preemption
is
not
based
on
express
or
implied
statutory
authority,
EPA
also
must
consult,
to
the
extent
practicable,
with
appropriate
State
and
local
officials
regarding
the
conflict
between
State
law
and
Federally
protected
interests
within
the
agency's
area
of
regulatory
responsibility.
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and
Regulations
This
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
Although
Section
6
of
Executive
Order
13132
does
not
apply
to
this
rule,
EPA
did
consult
with
representatives
of
various
State
and
local
governments
in
developing
this
rule.
EPA
has
also
consulted
representatives
from
STAPPA/
ALAPCO,
which
represents
state
and
local
air
pollution
officials.
F.
Executive
Order
13175:
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
``
Policies
that
have
tribal
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
the
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes.''
This
rule
does
not
have
tribal
implications.
It
will
not
have
substantial
direct
effects
on
tribal
governments,
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
The
emission
standards
and
other
related
requirements
for
private
businesses
in
this
rule
have
national
applicability
and
therefore
do
not
uniquely
affect
the
communities
of
Indian
Tribal
Governments.
Further,
no
circumstances
specific
to
such
communities
exist
that
would
cause
an
impact
on
these
communities
beyond
those
discussed
in
the
other
sections
of
this
rule.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.
G.
Executive
Order
13045:
Protection
of
Children
From
Environmental
Health
and
Safety
Risks
Executive
Order
13045,
``
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks''
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that
(
1)
is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
Section
5
501
of
the
Order
directs
the
Agency
to
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.
This
rule
is
not
subject
to
the
Executive
Order
because
it
does
not
involve
decisions
on
environmental
health
or
safety
risks
that
may
disproportionately
affect
children.
The
effects
of
ozone
and
PM
on
children's
health
were
addressed
in
detail
in
EPA's
rulemaking
to
establish
the
NAAQS
for
these
pollutants,
and
EPA
is
not
revisiting
those
issues
here.
EPA
believes,
however,
that
the
emission
reductions
from
the
strategies
in
this
rulemaking
will
further
reduce
air
toxics
and
the
related
adverse
impacts
on
children's
health.
H.
Executive
Order
13211:
Actions
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
rule
is
not
a
``
significant
energy
action''
as
defined
in
Executive
Order
13211,
``
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(
66
FR
28355
(
May
22,
2001))
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution
or
use
of
energy.
The
aim
to
reduce
emissions
from
certain
nonroad
engines
and
have
no
effect
on
fuel
formulation,
distribution,
or
use.
Generally,
the
final
rule
leads
to
reduced
fuel
usage
due
to
the
improvements
in
engine
based
emission
control
technologies.
I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(``
NTTAA''),
Public
Law
104
113,
section
12(
d)
(
15
U.
S.
C.
272
note)
directs
EPA
to
use
voluntary
consensus
standards
in
its
regulatory
activities
unless
doing
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
such
as
materials
specifications,
test
methods,
sampling
procedures,
and
business
practices)
that
are
developed
or
adopted
by
voluntary
consensus
standards
bodies.
NTTAA
directs
EPA
to
provide
Congress,
through
OMB,
explanations
when
the
Agency
decides
not
to
use
available
and
applicable
voluntary
consensus
standards.
This
rule
involves
technical
standards.
The
following
paragraphs
describe
how
we
specify
testing
procedures
for
engines
subject
to
this
rule.
The
International
Organization
for
Standardization
(
ISO)
has
a
voluntary
consensus
standard
that
can
be
used
to
test
Large
SI
engines.
However,
the
current
version
of
that
standard
(
ISO
8178)
is
applicable
only
for
steady
state
testing,
not
for
transient
testing.
As
described
in
the
Final
Regulatory
Support
Document,
transient
testing
is
an
important
part
of
the
emissioncontrol
program
for
these
engines.
We
are
therefore
not
adopting
the
ISO
procedures
in
this
rulemaking.
Underwriters
Laboratories
(
UL)
has
adopted
voluntary
consensus
standards
for
forklifts
that
are
relevant
to
the
new
requirements
for
Large
SI
engines.
UL
sets
a
maximum
temperature
specification
for
gasoline
and,
for
forklifts
used
in
certain
applications,
defines
requirements
to
avoid
venting
from
gasoline
fuel
tanks.
We
are
adopting
a
different
temperature
limit,
because
the
maximum
temperature
specified
by
UL
does
not
prevent
fuel
boiling.
We
are
adopting
separate
measures
to
address
venting
of
gasoline
vapors,
because
of
UL's
provisions
to
allow
venting
with
an
orifice
up
to
1.78
mm
(
0.070
inches).
We
believe
forklifts
with
such
a
vent
would
have
unnecessarily
high
evaporative
emissions.
If
the
UL
standard
is
revised
to
address
these
technical
concerns,
it
would
be
appropriate
to
reference
the
UL
standard
in
our
regulations.
An
additional
concern
relates
to
the
fact
that
the
UL
requirements
apply
only
to
forklifts
(
and
not
all
forklifts
in
the
case
of
the
restriction
on
vapor
venting).
EPA
regulations
would
therefore
need
to,
at
a
minimum,
extend
any
published
UL
standards
to
other
engines
and
equipment
to
which
the
UL
standards
would
otherwise
not
apply.
The
Gas
Processors
Association
has
adopted
standards
with
fuel
specifications
for
liquefied
petroleum
gas.
However,
there
is
no
existing
regulations
requiring
suppliers
to
meet
these
specifications.
Comments
received
on
the
rule
indicate
a
high
level
of
concern
that
in
use
fuel
quality
does
not
meet
the
published
voluntary
standards,
so
we
are
not
relying
on
these
fuel
specifications
to
define
fuels
for
certification
testing.
We
are
adopting
requirements
to
test
off
highway
motorcycles
and
all
terrain
vehicles
with
the
Federal
Test
Procedure,
a
chassis
based
transient
test.
There
is
no
voluntary
consensus
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Rules
and
Regulations
standard
that
would
adequately
address
engine
or
vehicle
operation
for
suitable
emission
measurement.
Furthermore,
we
are
interested
in
pursuing
an
enginebased
test
procedure
for
all
terrain
vehicles.
We
intend
to
develop
a
new
duty
cycle
for
this,
because
there
is
no
acceptable
engine
duty
cycle
today
that
would
adequately
represent
the
way
these
engines
operate.
For
snowmobiles,
we
are
adopting
test
procedures
based
on
work
that
has
been
published,
but
not
yet
adopted
as
a
voluntary
consensus
standard.
For
recreational
marine
diesel
engines,
we
are
adopting
the
same
test
procedures
that
we
have
established
for
commercial
marine
diesel
engines
(
with
a
new
duty
cycle
appropriate
for
recreational
applications).
We
are
again
adopting
these
procedures
in
place
of
the
ISO
8178
standard
that
would
apply
to
these
engines.
We
believe
that
ISO
8178
relies
too
heavily
on
reference
testing
conditions.
Because
our
test
procedures
need
to
represent
in
use
operation
typical
of
operation
in
the
field,
they
must
be
based
on
a
range
of
ambient
conditions.
We
determined
that
the
ISO
procedures
are
not
broadly
usable
in
their
current
form,
and
therefore
should
not
be
adopted
by
reference.
We
remain
hopeful
that
future
ISO
test
procedures
will
be
developed
that
are
usable
and
accurate
for
the
broad
range
of
testing
needed,
and
that
such
procedures
could
then
be
adopted.
We
expect
that
any
such
development
of
revised
test
procedures
will
be
done
in
accordance
with
ISO
procedures
and
in
a
balanced
and
transparent
manner
that
includes
the
involvement
of
all
interested
parties,
including
industry,
U.
S.
EPA,
foreign
government
organizations,
state
governments,
and
environmental
groups.
In
so
doing,
we
believe
that
the
resulting
procedures
would
be
``
global''
test
procedures
that
can
facilitate
the
free
flow
of
international
commerce
for
these
products.
J.
Congressional
Review
Act
The
Congressional
Review
Act,
5
U.
S.
C.
801
et
seq.,
as
added
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996,
generally
provides
that
before
a
rule
may
take
effect,
the
agency
promulgating
the
rule
must
submit
a
rule
report,
which
includes
a
copy
of
the
rule,
to
each
House
of
the
Congress
and
to
the
Comptroller
General
of
the
United
States.
EPA
will
submit
a
report
containing
this
rule
and
other
required
information
to
the
U.
S.
Senate,
the
U.
S.
House
of
Representatives,
and
the
Comptroller
General
of
the
United
States
prior
to
publication
of
the
rule
in
the
Federal
Register.
This
rule
is
a
``
major
rule''
as
defined
by
5
U.
S.
C.
804(
2).
K.
Plain
Language
This
document
follows
the
guidelines
of
the
June
1,
1998
Executive
Memorandum
on
Plain
Language
in
Government
Writing.
To
read
the
text
of
the
regulations,
it
is
also
important
to
understand
the
organization
of
the
Code
of
Federal
Regulations
(
CFR).
The
CFR
uses
the
following
organizational
names
and
conventions.
Title
40
Protection
of
the
Environment
Chapter
I
Environmental
Protection
Agency
Subchapter
C
Air
Programs.
This
contains
parts
50
to
99,
where
the
Office
of
Air
and
Radiation
has
usually
placed
emission
standards
for
motor
vehicle
and
nonroad
engines.
Subchapter
U
Air
Programs
Supplement.
This
contains
parts
1000
to
1299,
where
we
intend
to
place
regulations
for
air
programs
in
future
rulemakings.
Part
1048
Control
of
Emissions
from
New,
Large,
Nonrecreational,
Nonroad
Spark
ignition
Engines.
Most
of
the
provisions
in
this
part
apply
only
to
engine
manufacturers.
Part
1051
Control
of
Emissions
from
Recreational
Engines
and
Vehicles.
Most
of
the
provisions
in
this
part
apply
only
to
vehicle
manufacturers.
Part
1065
General
Test
Procedures
for
Engine
Testing.
Provisions
of
this
part
apply
to
anyone
who
tests
engines
to
show
that
they
meet
emission
standards.
Part
1068
General
Compliance
Provisions
for
Engine
Programs.
Provisions
of
this
part
apply
to
everyone.
Each
part
in
the
CFR
has
several
subparts,
sections,
and
paragraphs.
The
following
illustration
shows
how
these
fit
together.
Part
1048
Subpart
A
Section
1048.1
(
a)
(
b)
(
1)
(
2)
(
i)
(
ii)
A
cross
reference
to
§
1048.1(
b)
in
this
illustration
would
refer
to
the
parent
paragraph
(
b)
and
all
its
subordinate
paragraphs.
A
reference
to
§
1048.1(
b)
introductory
text''
would
refer
only
to
the
single,
parent
paragraph
(
b).
List
of
Subjects
40
CFR
Part
89
Environmental
protection,
Administrative
practice
and
procedure,
Confidential
business
information,
Imports,
Labeling,
Motor
vehicle
pollution,
Reporting
and
recordkeeping
requirements,
Research,
Vessels,
Warranties.
40
CFR
Part
90
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Confidential
business
information,
Imports,
Labeling,
Reporting
and
recordkeeping
requirements,
Research,
Warranties.
40
CFR
Part
91
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Confidential
business
information,
Imports,
Labeling,
Penalties,
Reporting
and
recordkeeping
requirements,
Warranties.
40
CFR
Part
94
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Confidential
business
information,
Imports,
Penalties,
Reporting
and
recordkeeping
requirements,
Vessels,
Warranties.
40
CFR
Part
1048
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Confidential
business
information,
Imports,
Incorporation
by
reference,
Labeling,
Penalties,
Reporting
and
recordkeeping
requirements,
Research,
Warranties.
40
CFR
Part
1051
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Confidential
business
information,
Imports,
Incorporation
by
reference,
Labeling,
Penalties,
Reporting
and
recordkeeping
requirements,
Warranties.
40
CFR
Part
1065
Environmental
protection,
Administrative
practice
and
procedure,
Incorporation
by
reference,
Reporting
and
recordkeeping
requirements,
Research.
40
CFR
Part
1068
Environmental
protection,
Administrative
practice
and
procedure,
Confidential
business
information,
Imports,
Motor
vehicle
pollution,
Penalties,
Reporting
and
recordkeeping
requirements,
Warranties.
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Vol.
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No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Dated:
September
13,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
set
out
in
the
preamble,
title
40,
chapter
I
of
the
Code
of
Federal
Regulations
is
amended
as
set
forth
below.
PART
89
CONTROL
OF
EMISSIONS
FROM
NEW
AND
IN
USE
NONROAD
COMPRESSION
IGNITION
ENGINES
1.
The
authority
for
part
89
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7521,
7522,
7523,
7524,
7525,
7541,
7542,
7543,
7545,
7547,
7549,
7550,
and
7601(
a).
Subpart
A
[
Amended]
2.
Section
89.2
is
amended
by
adding
definitions
for
``
Aircraft'',
``
Sparkignition
and
``
United
States''
in
alphabetic
order
and
revising
the
definition
of
``
Compression
ignition''
to
read
as
follows:
§
89.2
Definitions.
*
*
*
*
*
Aircraft
means
any
vehicle
capable
of
sustained
air
travel
above
treetop
heights.
*
*
*
*
*
Compression
ignition
means
relating
to
a
type
of
reciprocating,
internalcombustion
engine
that
is
not
a
sparkignition
engine.
*
*
*
*
*
Spark
ignition
means
relating
to
a
gasoline
fueled
engine
or
other
engines
with
a
spark
plug
(
or
other
sparking
device)
and
with
operating
characteristics
significantly
similar
to
the
theoretical
Otto
combustion
cycle.
Spark
ignition
engines
usually
use
a
throttle
to
regulate
intake
air
flow
to
control
power
during
normal
operation.
*
*
*
*
*
United
States
means
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.
*
*
*
*
*
Subpart
B
[
Amended]
3.
Section
89.106
is
amended
by
revising
paragraph
(
b)
read
as
follows:
§
89.106
Prohibited
controls.
*
*
*
*
*
(
b)
You
may
not
design
your
engines
with
emission
control
devices,
systems,
or
elements
of
design
that
cause
or
contribute
to
an
unreasonable
risk
to
public
health,
welfare,
or
safety
while
operating.
For
example,
this
would
apply
if
the
engine
emits
a
noxious
or
toxic
substance
it
would
otherwise
not
emit
that
contributes
to
such
an
unreasonable
risk.
PART
90
CONTROL
OF
EMISSIONS
FROM
NONROAD
SPARK
IGNITION
ENGINES
AT
OR
BELOW
19
KILOWATTS
4.
The
heading
to
part
90
is
revised
to
read
as
set
forth
above.
5.
The
authority
for
part
90
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7521,
7522,
7523,
7524,
7525,
7541,
7542,
7543,
7547,
7549,
7550,
and
7601(
a).
Subpart
A
[
Amended]
6.
Section
90.1
is
revised
to
read
as
follows:
§
90.1
Applicability.
(
a)
This
part
applies
to
new
nonroad
spark
ignition
engines
and
vehicles
with
gross
power
output
at
or
below
19
kilowatts
(
kW)
used
for
any
purpose,
unless
we
exclude
them
under
paragraph
(
d)
of
this
section.
(
b)
This
part
also
applies
to
engines
with
a
gross
power
output
above
19
kW
if
the
manufacturer
uses
the
provisions
of
40
CFR
1048.615
or
1051.145(
a)(
3)
to
exempt
them
from
the
requirements
of
40
CFR
part
1048
or
1051,
respectively.
Compliance
with
the
provisions
of
this
part
is
a
required
condition
of
those
exemptions.
(
c)
[
Reserved]
(
d)
The
following
nonroad
engines
and
vehicles
are
not
subject
to
the
provisions
of
this
part:
(
1)
Engines
certified
to
meet
the
requirements
of
40
CFR
part
1051
(
e.
g.,
engines
used
in
snowmobiles).
This
part
nevertheless
applies
to
engines
used
in
recreational
vehicles
if
the
manufacturer
uses
the
provisions
of
40
CFR
1051.145(
a)(
3)
to
exempt
them
from
the
requirements
of
40
CFR
part
1051.
Compliance
with
the
provisions
of
this
part
is
a
required
condition
of
that
exemption.
(
2)
Engines
used
in
highway
motorcycles.
See
40
CFR
part
86,
subpart
E.
(
3)
Propulsion
marine
engines.
See
40
CFR
part
91.
This
part
applies
with
respect
to
auxiliary
marine
engines.
(
4)
Engines
used
in
aircraft.
See
40
CFR
part
87.
(
5)
Engines
certified
to
meet
the
requirements
of
40
CFR
part
1048.
(
6)
Hobby
engines.
(
7)
Engines
that
are
used
exclusively
in
emergency
and
rescue
equipment
where
no
certified
engines
are
available
to
power
the
equipment
safely
and
practically,
but
not
including
generators,
alternators,
compressors
or
pumps
used
to
provide
remote
power
to
a
rescue
tool.
The
equipment
manufacturer
bears
the
responsibility
to
ascertain
on
an
annual
basis
and
maintain
documentation
available
to
the
Administrator
that
no
appropriate
certified
engine
is
available
from
any
source.
(
e)
Engines
subject
to
the
provisions
of
this
subpart
are
also
subject
to
the
provisions
found
in
subparts
B
through
N
of
this
part,
except
that
Subparts
C,
H,
M
and
N
of
this
part
apply
only
to
Phase
2
engines
as
defined
in
this
subpart.
(
f)
Certain
text
in
this
part
is
identified
as
pertaining
to
Phase
1
or
Phase
2
engines.
Such
text
pertains
only
to
engines
of
the
specified
Phase.
If
no
indication
of
Phase
is
given,
the
text
pertains
to
all
engines,
regardless
of
Phase.
7.
Section
90.2
is
amended
by
adding
a
new
paragraph
(
c)
to
read
as
follows:
§
90.2
Effective
dates.
*
*
*
*
*
(
c)
Notwithstanding
paragraphs
(
a)
and
(
b)
of
this
section,
engines
used
in
recreational
vehicles
with
engine
rated
speed
greater
than
or
equal
to
5,000
rpm
and
with
no
installed
speed
governor
are
not
subject
to
the
provisions
of
this
part
through
the
2005
model
year.
Starting
with
the
2006
model
year,
all
the
requirements
of
this
part
apply
to
engines
used
in
these
vehicles
if
they
are
not
included
in
the
scope
of
40
CFR
part
1051.
8.
Section
90.3
is
amended
by
adding
definitions
for
``
Aircraft'',
``
Hobby
engines'',
``
Marine
engine'',
``
Marine
vessel'',
``
Recreational'',
and
``
United
States''
in
alphabetical
order,
to
read
as
follows:
§
90.3
Definitions.
*
*
*
*
*
Aircraft
means
any
vehicle
capable
of
sustained
air
travel
above
treetop
heights.
*
*
*
*
*
Hobby
engines
means
engines
used
in
reduced
scale
models
of
vehicles
that
are
not
capable
of
transporting
a
person
(
for
example,
model
airplanes).
Marine
engine
means
an
engine
that
someone
installs
or
intends
to
install
on
a
marine
vessel.
There
are
two
kinds
of
marine
engines:
(
1)
Propulsion
marine
engine
means
a
marine
engine
that
moves
a
vessel
through
the
water
or
directs
the
vessel's
movement.
(
2)
Auxiliary
marine
engine
means
a
marine
engine
not
used
for
propulsion.
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Rules
and
Regulations
Marine
vessel
means
a
vehicle
that
is
capable
of
operation
in
water
but
is
not
capable
of
operation
out
of
water.
Amphibious
vehicles
are
not
marine
vessels.
*
*
*
*
*
Recreational
means,
for
purposes
of
this
part,
relating
to
a
vehicle
intended
by
the
vehicle
manufacturer
to
be
operated
primarily
for
pleasure.
*
*
*
*
*
United
States
means
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.
*
*
*
*
*
Subpart
B
[
Amended]
9.
Section
90.103
is
amended
by
redesignating
paragraph
(
a)(
2)(
v)
as
paragraph
(
a)(
2)(
vi)
and
adding
a
new
paragraph
(
a)(
2)(
v)
to
read
as
follows:
§
90.103
Exhaust
emission
standards.
(
a)*
*
*
(
2)*
*
*
(
v)
The
engine
must
be
used
in
a
recreational
application,
with
a
combined
total
vehicle
dry
weight
under
20
kilograms;
*
*
*
*
*
10.
Section
90.110
is
amended
by
revising
paragraph
(
b)
to
read
as
follows:
§
90.110
Requirement
of
certification
prohibited
controls.
*
*
*
*
*
(
b)
You
may
not
design
your
engines
with
emission
control
devices,
systems,
or
elements
of
design
that
cause
or
contribute
to
an
unreasonable
risk
to
public
health,
welfare,
or
safety
while
operating.
For
example,
this
would
apply
if
the
engine
emits
a
noxious
or
toxic
substance
it
would
otherwise
not
emit
that
contributes
to
such
an
unreasonable
risk.
PART
91
CONTROL
OF
EMISSIONS
FROM
MARINE
SPARK
IGNITION
ENGINES
11.
The
authority
for
part
91
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7521,
7522,
7523,
7524,
7525,
7541,
7542,
7543,
7547,
7549,
7550,
and
7601(
a).
Subpart
A
[
Amended]
12.
Section
91.3
is
amended
by
adding
the
definition
for
``
United
States''
in
alphabetical
order
to
read
as
follows:
§
91.3
Definitions.
*
*
*
*
*
United
States
means
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.
*
*
*
*
*
Subpart
B
[
Amended]
13.
Section
91.110
is
amended
by
revising
paragraph
(
b)
to
read
as
follows:
§
91.110
Requirement
of
certification
prohibited
controls.
*
*
*
*
*
(
b)
You
may
not
design
your
engines
with
emission
control
devices,
systems,
or
elements
of
design
that
cause
or
contribute
to
an
unreasonable
risk
to
public
health,
welfare,
or
safety
while
operating.
For
example,
this
would
apply
if
the
engine
emits
a
noxious
or
toxic
substance
it
would
otherwise
not
emit
that
contributes
to
such
an
unreasonable
risk.
Subpart
E
[
Amended]
14.
Section
91.419
is
amended
in
paragraph
(
b)
by
revising
the
equations
for
MHCexh
and
Mexh
to
read
as
follows:
§
91.419
Raw
emission
sampling
calculations.
*
*
*
*
*
(
b)
*
*
*
MHCexh
=
12.01
+
1.008
×
a
*
*
*
*
*
M
K)
28
(
1
exh
=
×
+
×
+
×
+
×
+
×
+
×
+
×
×
M
WHC
WCO
WCO
WNO
WH
WHC
WCO
WCO
WNO
WH
K
HC
x
x
exh
10
28
01
10
44
1
10
46
01
10
2
016
10
18
01
1
01
100
10
10
100
10
6
2
2
2
6
2
2
4
2
4
2
2
.
.
.
.
.
(
.
)
*
*
*
*
*
Subpart
G
[
Amended]
15.
Appendix
A
to
Subpart
G
of
part
91
is
amended
by
revising
Table
1
to
read
as
follows:
Appendix
A
to
Subpart
G
of
Part
91
Sampling
Plans
for
Selective
Enforcement
Auditing
of
Marine
Engines
TABLE
1.
SAMPLING
PLAN
CODE
LETTER
Annual
engine
family
sales
Code
letter
20
50
.....................................
AA1
TABLE
1.
SAMPLING
PLAN
CODE
LETTER
Continued
Annual
engine
family
sales
Code
letter
20
99
.....................................
A1
100
299
.................................
B
300
499
.................................
C
500
or
greater
........................
D
1
A
manufacturer
may
optionally
use
either
the
sampling
plan
for
code
letter
``
AA''
or
sampling
plan
for
code
letter
``
A''
for
Selective
Enforcement
Audits
of
engine
families
with
annual
sales
between
20
and
50
engines.
Additional
the
manufacturers
may
switch
between
these
plans
during
the
audit.
*
*
*
*
*
Subpart
I
[
Amended]
16.
Section
91.803
is
amended
by
revising
paragraph
(
a)
to
read
as
follows:
§
91.803
Manufacturer
in
use
testing
program.
(
a)
EPA
shall
annually
identify
engine
families
and
those
configurations
within
families
which
the
manufacturers
must
then
subject
to
in
use
testing.
For
each
model
year,
EPA
may
identify
the
following
number
of
engine
families
for
testing,
based
on
the
number
of
the
manufacturer's
engine
families
to
which
this
subpart
is
applicable
produced
in
that
model
year:
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Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
(
1)
For
manufactures
with
three
or
fewer
engine
families,
EPA
may
identify
a
single
engine
family.
(
2)
For
manufacturers
with
four
or
more
engine
families,
EPA
may
identify
a
number
of
engine
families
that
is
no
greater
than
twenty
five
percent
of
the
number
of
engine
families
to
which
this
subpart
is
applicable
that
are
produced
by
the
manufacturer
in
that
model
year.
*
*
*
*
*
PART
94
CONTROL
OF
EMISSIONS
FROM
MARINE
COMPRESSIONIGNITION
ENGINES
17.
The
heading
to
part
94
is
revised
to
read
as
set
forth
above.
18.
The
authority
citation
for
part
94
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7522,
7523,
7524,
7525,
7541,
7542,
7543,
7545,
7547,
7549,
7550
and
7601(
a).
Subpart
A
[
Amended]
19.
Section
94.1
is
revised
to
read
as
follows:
§
94.1
Applicability.
(
a)
Except
as
noted
in
paragraphs
(
b)
and
(
c)
of
this
section,
the
provisions
of
this
part
apply
to
manufacturers
(
including
post
manufacture
marinizers
and
dressers),
rebuilders,
owners
and
operators
of:
(
1)
Marine
engines
that
are
compression
ignition
engines
manufactured
(
or
that
otherwise
become
new)
on
or
after
January
1,
2004;
(
2)
Marine
vessels
manufactured
(
or
that
otherwise
become
new)
on
or
after
January
1,
2004
and
which
include
a
compression
ignition
marine
engine.
(
b)
Notwithstanding
the
provision
of
paragraph
(
c)
of
this
section,
the
requirements
and
prohibitions
of
this
part
do
not
apply
to
three
types
of
marine
engines:
(
1)
Category
3
marine
engines;
(
2)
Marine
engines
with
rated
power
below
37
kW;
or
(
3)
Marine
engines
on
foreign
vessels.
(
c)
The
provisions
of
Subpart
L
of
this
part
apply
to
everyone
with
respect
to
the
engines
identified
in
paragraph
(
a)
of
this
section.
20.
Section
94.2
is
amended
by
revising
paragraph
(
b)
introductory
text,
removing
the
definition
for
``
Commercial
marine
engine'',
revising
definitions
for
``
Compression
ignition'',
``
Designated
officer'',
``
Passenger'',
``
Recreational
marine
engine'',
``
Recreational
vessel'',
and
``
United
States'',
and
adding
new
definitions
for
``
Commercial'',
``
Small
volume
boat
builder'',
``
Small
volume
manufacturer'',
and
``
Spark
ignition''
in
alphabetical
order
to
read
as
follows:
§
94.2
Definitions.
*
*
*
*
*
(
b)
As
used
in
this
part,
all
terms
not
defined
in
this
section
shall
have
the
meaning
given
them
in
the
Act:
*
*
*
*
*
Commercial
means
relating
to
an
engine
or
vessel
that
is
not
a
recreational
marine
engine
or
a
recreational
vessel.
*
*
*
*
*
Compression
ignition
means
relating
to
an
engine
that
is
not
a
spark
ignition
engine.
*
*
*
*
*
Designated
Officer
means
the
Manager,
Engine
Programs
Group
(
6403
J),
U.
S.
Environmental
Protection
Agency,
1200
Pennsylvania
Ave.,
Washington,
DC
20460.
*
*
*
*
*
Passenger
has
the
meaning
given
by
46
U.
S.
C.
2101
(
21)
and
(
21a).
In
the
context
of
commercial
vessels,
this
generally
means
that
a
passenger
is
a
person
that
pays
to
be
on
the
vessel.
*
*
*
*
*
Recreational
marine
engine
means
a
Category
1
propulsion
marine
engine
that
is
intended
by
the
manufacturer
to
be
installed
on
a
recreational
vessel,
and
which
is
permanently
labeled
as
follows:
``
THIS
ENGINE
IS
CATEGORIZED
AS
A
RECREATIONAL
MARINE
ENGINE
UNDER
40
CFR
PART
94.
INSTALLATION
OF
THIS
ENGINE
IN
ANY
NONRECREATIONAL
VESSEL
IS
A
VIOLATION
OF
FEDERAL
LAW
SUBJECT
TO
CIVIL
PENALTY.''.
Recreational
vessel
has
the
meaning
given
in
46
U.
S.
C.
2101
(
25),
but
excludes
``
passenger
vessels''
and
``
small
passenger
vessels''
as
defined
by
46
U.
S.
C.
2101
(
22)
and
(
35)
and
excludes
vessels
used
solely
for
competition.
In
general,
for
this
part,
``
recreational
vessel''
means
a
vessel
that
is
intended
by
the
vessel
manufacturer
to
be
operated
primarily
for
pleasure
or
leased,
rented
or
chartered
to
another
for
the
latter's
pleasure,
excluding
the
following
vessels:
(
1)
Vessels
of
less
than
100
gross
tons
that
carry
more
than
6
passengers
(
as
defined
in
this
section).
(
2)
Vessels
of
100
gross
tons
or
more
that
carry
one
or
more
passengers
(
as
defined
in
this
section).
(
3)
Vessels
used
solely
for
competition.
*
*
*
*
*
Small
volume
boat
builder
means
a
boat
manufacturer
with
fewer
than
500
employees
and
with
annual
U.
S.
directed
production
of
fewer
than
100
boats.
For
manufacturers
owned
by
a
parent
company,
these
limits
apply
to
the
combined
production
and
number
of
employees
of
the
parent
company
and
all
its
subsidiaries.
Small
volume
manufacturer
means
a
manufacturer
with
annual
U.
S.
directed
production
of
fewer
than
1,000
internal
combustion
engines
(
marine
and
nonmarine).
For
manufacturers
owned
by
a
parent
company,
the
limit
applies
to
the
production
of
the
parent
company
and
all
its
subsidiaries.
Spark
ignition
means
relating
to
a
gasoline
fueled
engine
or
other
engines
with
a
spark
plug
(
or
other
sparking
device)
and
with
operating
characteristics
significantly
similar
to
the
theoretical
Otto
combustion
cycle.
Spark
ignition
engines
usually
use
a
throttle
to
regulate
intake
air
flow
to
control
power
during
normal
operation.
*
*
*
*
*
United
States
means
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.
*
*
*
*
*
21.
Section
94.7
is
amended
by
revising
paragraphs
(
c),
(
d),
and
(
e)
to
read
as
follows:
§
94.7
General
standards
and
requirements.
*
*
*
*
*
(
c)
You
may
not
design
your
engines
with
emission
control
devices,
systems,
or
elements
of
design
that
cause
or
contribute
to
an
unreasonable
risk
to
public
health,
welfare,
or
safety
while
operating.
For
example,
this
would
apply
if
the
engine
emits
a
noxious
or
toxic
substance
it
would
otherwise
not
emit
that
contributes
to
such
an
unreasonable
risk.
(
d)
All
engines
subject
to
the
emission
standards
of
this
part
shall
be
equipped
with
a
connection
in
the
engine
exhaust
system
that
is
located
downstream
of
the
engine
and
before
any
point
at
which
the
exhaust
contacts
water
(
or
any
other
cooling/
scrubbing
medium)
for
the
temporary
attachment
of
gaseous
and/
or
particulate
emission
sampling
equipment.
This
connection
shall
be
internally
threaded
with
standard
pipe
threads
of
a
size
not
larger
than
one
half
inch,
and
shall
be
closed
by
a
pipe
plug
when
not
in
use.
Equivalent
connections
are
allowed.
Engine
manufacturers
may
comply
with
this
requirement
by
providing
vessel
manufacturers
with
clear
instructions
explaining
how
to
meet
this
requirement,
and
noting
in
the
instructions
that
failure
to
comply
may
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217
/
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November
8,
2002
/
Rules
and
Regulations
invalidate
a
certificate
and
subject
the
vessel
manufacturer
to
federal
penalties.
(
e)
Electronically
controlled
engines
subject
to
the
emission
standards
of
this
part
shall
broadcast
on
engine's
controller
area
networks
engine
torque
(
as
percent
of
maximum
torque
at
that
speed)
and
engine
speed.
22.
Section
94.8
is
amended
by
revising
paragraphs
(
a),
(
e),
(
f)
introductory
text,
and
(
f)(
1)
to
read
as
follows:
§
94.8
Exhaust
emission
standards.
(
a)
Exhaust
emissions
from
marine
compression
ignition
engines
shall
not
exceed
the
applicable
exhaust
emission
standards
contained
in
Table
A
1
as
follows:
TABLE
A
1.
PRIMARY
TIER
2
EXHAUST
EMISSION
STANDARDS
(
G/
KW
HR)
Engine
size
liters/
cylinder,
rated
power
Category
Model
yeara
THC+
NOX
g/
kW
hr
CO
g/
kW
hr
PM
g/
kWhr
Disp.
<
0.9
and
..........................................................................
power
37
kW
..........................................................................
Category
1,
Commercial
.........
2005
7.5
5.0
0.40
Category
1,
Recreational
........
2007
7.5
5.0
0.40
0.9
disp.
<
1.2
........................................................................
All
power
levels
.........................................................................
Category
1,
Commercial
.........
2004
7.2
5.0
0.30
Category
1,
Recreational
........
2006
7.2
5.0
0.30
1.2
disp.
<
2.5
........................................................................
All
power
levels
.........................................................................
Category
1,
Commercial
.........
2004
7.2
5.0
0.20
Category
1,
Recreational
........
2006
7.2
5.0
0.20
2.5
disp.
<
5.0
........................................................................
All
power
levels
.........................................................................
Category
1,
Commercial
.........
2007
7.2
5.0
0.20
Category
1,
Recreational
........
2009
7.2
5.0
0.20
5.0
disp.
<
15.0
......................................................................
All
power
levels
.........................................................................
Category
2
..............................
2007
7.8
5.0
0.27
15.0
disp.
<
20.0
....................................................................
Power
<
3300
kW
......................................................................
Category
2
..............................
2007
8.7
5.0
0.50
15.0
disp.
<
20.0
....................................................................
Power
<
3300
kW
......................................................................
Category
2
..............................
2007
9.8
5.0
0.50
20.0
disp.
<
25.0
....................................................................
All
power
levels
.........................................................................
Category
2
..............................
2009
9.8
5.0
0.50
25.0
disp.
<
30.0
....................................................................
All
power
levels
.........................................................................
Category
2
..............................
2007
11.0
5.0
0.50
a
The
dates
listed
indicate
the
model
years
for
which
the
specified
standards
start.
*
*
*
*
*
(
e)
Exhaust
emissions
from
propulsion
engines
subject
to
the
standards
(
or
FELs)
in
paragraph
(
a),
(
c),
or
(
f)
of
this
section
shall
not
exceed:
(
1)
Commercial
marine
engines.
(
i)
1.20
times
the
applicable
standards
(
or
FELs)
when
tested
in
accordance
with
the
supplemental
test
procedures
specified
in
§
94.106
at
loads
greater
than
or
equal
to
45
percent
of
the
maximum
power
at
rated
speed
or
1.50
times
the
applicable
standards
(
or
FELs)
at
loads
less
than
45
percent
of
the
maximum
power
at
rated
speed.
(
ii)
As
an
option,
the
manufacturer
may
choose
to
comply
with
limits
of
1.25
times
the
applicable
standards
(
or
FELs)
when
tested
over
the
whole
power
range
in
accordance
with
the
supplemental
test
procedures
specified
in
§
94.106,
instead
of
the
limits
in
paragraph
(
e)(
1)(
i)
of
this
section.
(
2)
Recreational
marine
engines.
(
i)
1.20
times
the
applicable
standards
(
or
FELs)
when
tested
in
accordance
with
the
supplemental
test
procedures
specified
in
§
94.106
at
loads
greater
than
or
equal
to
45
percent
of
the
maximum
power
at
rated
speed
and
speeds
less
than
95
percent
of
maximum
test
speed,
or
1.50
times
the
applicable
standards
(
or
FELs)
at
loads
less
than
45
percent
of
the
maximum
power
at
rated
speed,
or
1.50
times
the
applicable
standards
(
or
FELs)
at
any
loads
for
speeds
greater
than
or
equal
to
95
percent
of
the
maximum
test
speed.
(
ii)
As
an
option,
the
manufacturer
may
choose
to
comply
with
limits
of
1.25
times
the
applicable
standards
(
or
FELs)
when
tested
over
the
whole
power
range
in
accordance
with
the
supplemental
test
procedures
specified
in
§
94.106,
instead
of
the
limits
in
paragraph
(
e)(
2)(
i)
of
this
section.
(
f)
The
following
defines
the
requirements
for
low
emitting
Blue
Sky
Series
engines:
(
1)
Voluntary
standards.
Engines
may
be
designated
``
Blue
Sky
Series''
engines
through
the
2012
model
year
by
meeting
the
voluntary
standards
listed
in
Table
A
2,
which
apply
to
all
certification
and
in
use
testing,
as
follows:
TABLE
A
2.
VOLUNTARY
EMISSION
STANDARDS
(
G/
KW
HR)
Rated
brake
power
(
kW)
THC+
NOX
PM
Power
37
kW,
and
displ.<
0.9
................................................................................................................................
4.0
0.24
0.9
displ.<
1.2
..........................................................................................................................................................
4.0
0.18
1.2
displ.<
2.5
..........................................................................................................................................................
4.0
0.12
2.5
displ.<
5
.............................................................................................................................................................
5.0
0.12
5
displ.<
15
..............................................................................................................................................................
5.0
0.16
15
disp.<
20,
and
power
<
3300
kW
.....................................................................................................................
5.2
0.30
15
disp.<
20,
and
power
3300
kW
.....................................................................................................................
5.9
0.30
20
disp.<
25
...........................................................................................................................................................
5.9
0.30
25
disp.<
30
...........................................................................................................................................................
6.6
0.30
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217
/
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November
8,
2002
/
Rules
and
Regulations
*
*
*
*
*
23.
Section
94.9
is
amended
by
revising
paragraphs
(
a)
introductory
text
and
(
a)(
1)
to
read
as
follows:
§
94.9
Compliance
with
emission
standards.
(
a)
The
general
standards
and
requirements
in
§
94.7
and
the
emission
standards
in
§
94.8
apply
to
each
new
engine
throughout
its
useful
life
period.
The
useful
life
is
specified
both
in
years
and
in
hours
of
operation,
and
ends
when
either
of
the
values
(
hours
of
operation
or
years)
is
exceeded.
(
1)
The
minimum
useful
life
is:
(
i)
10
years
or
1,000
hours
of
operation
for
recreational
Category
1
engines;
(
i)
10
years
or
10,000
hours
of
operation
for
commercial
Category
1
engines;
(
iii)
10
years
or
20,000
hours
of
operation
for
Category
2
engines.
*
*
*
*
*
24.
Section
94.12
is
amended
by
revising
the
introductory
text
and
paragraphs
(
a),
(
b)(
1),
and
(
e)
and
adding
new
paragraphs
(
f)
and
(
g)
to
read
as
follows:
§
94.12
Interim
provisions.
This
section
contains
provisions
that
apply
for
a
limited
number
of
calendar
years
or
model
years.
These
provisions
apply
instead
of
the
other
provisions
of
this
part.
(
a)
Compliance
date
of
standards.
Certain
companies
may
delay
compliance
with
emission
standards.
Companies
wishing
to
take
advantage
of
this
provision
must
inform
the
Designated
Officer
of
their
intent
to
do
so
in
writing
before
the
date
that
compliance
with
the
standards
would
otherwise
be
mandatory.
(
1)
Post
manufacture
marinizers
may
elect
to
delay
the
model
year
of
the
Tier
2
standards
for
commercial
engines
as
specified
in
§
94.8
by
one
year
for
each
engine
family.
(
2)
Small
volume
manufacturers
may
elect
to
delay
the
model
year
of
the
Tier
2
standards
for
recreational
engines
as
specified
in
§
94.8
by
five
years
for
each
engine
family.
(
b)
Early
banking
of
emission
credits.
(
1)
A
manufacturer
may
optionally
certify
engines
manufactured
before
the
date
the
Tier
2
standards
take
effect
to
earn
emission
credits
under
the
averaging,
banking,
and
trading
program.
Such
optionally
certified
engines
are
subject
to
all
provisions
relating
to
mandatory
certification
and
enforcement
described
in
this
part.
Manufacturers
may
begin
earning
credits
for
recreational
engines
on
December
9,
2002.
*
*
*
*
*
(
e)
Compliance
date
of
NTE
requirements
(
1)
Notwithstanding
the
other
provisions
of
this
part,
the
requirements
of
§
94.8(
e)
for
commercial
marine
engines
start
with
2010
model
year
engines
for
postmanufacture
marinizers
and
2007
model
year
engines
for
all
other
engine
manufacturers.
(
2)
Notwithstanding
the
other
provisions
of
this
part,
the
requirements
of
§
94.8(
e)
for
recreational
marine
engines
start
with
2012
model
year
engines
for
post
manufacture
marinizers
and
2009
model
year
engines
for
all
other
engine
manufacturers.
(
f)
Flexibility
for
small
volume
boat
builders.
Notwithstanding
the
other
provisions
of
this
part,
manufacturers
may
sell
uncertified
recreational
engines
to
small
volume
boat
builders
during
the
first
five
years
for
which
the
emission
standards
in
§
94.8
apply,
subject
to
the
following
provisions:
(
1)
The
U.
S.
directed
production
volume
of
boats
from
any
small
volume
boat
builder
using
uncertified
engines
during
the
total
five
year
period
may
not
exceed
80
percent
of
the
manufacturer's
average
annual
production
for
the
three
years
prior
to
the
general
applicability
of
the
recreational
engine
standards
in
§
94.8,
except
as
allowed
in
paragraph
(
f)(
2)
of
this
section.
(
2)
Small
volume
boat
builders
may
exceed
the
production
limits
in
paragraph
(
f)(
1)
of
this
section,
provided
they
do
not
exceed
20
boats
during
the
five
year
period
or
10
boats
in
any
single
calendar
year.
This
does
not
apply
to
boats
powered
by
engines
with
displacement
greater
than
2.5
liters
per
cylinder.
(
3)
Small
volume
boat
builders
must
keep
records
of
all
the
boats
and
engines
produced
under
this
paragraph
(
f),
including
boat
and
engine
model
numbers,
serial
numbers,
and
dates
of
manufacture.
Records
must
also
include
information
verifying
compliance
with
the
limits
in
paragraph
(
f)(
1)
or
(
f)(
2)
of
this
section.
Keep
these
records
until
at
least
two
full
years
after
you
no
longer
use
the
provisions
in
this
paragraph
(
f).
(
4)
Manufacturers
must
add
a
permanent,
legible
label,
written
in
block
letters
in
English,
to
a
readily
visible
part
of
each
engine
exempted
under
this
paragraph
(
f).
This
label
must
include
at
least
the
following
items:
(
i)
The
label
heading
``
EMISSION
CONTROL
INFORMATION''.
(
ii)
Your
corporate
name
and
trademark.
(
iii)
Engine
displacement
(
in
liters),
rated
power,
and
model
year
of
the
engine
or
whom
to
contact
for
further
information.
(
iv)
The
statement
``
THIS
ENGINE
IS
EXEMPT
UNDER
40
CFR
94.12(
f)
FROM
EMISSION
STANDARDS
AND
RELATED
REQUIREMENTS.''.
(
g)
Flexibility
for
engines
over
560kW.
Notwithstanding
the
other
provisions
of
this
part,
manufacturers
may
choose
to
delay
certification
of
marine
engines
with
less
than
2.5
liters
per
cylinder
and
rated
power
above
560
kW,
that
are
derived
from
a
land
based
nonroad
engine
with
a
rated
power
greater
than
560
kW,
if
they
do
all
of
the
following:
(
1)
Certify
all
of
their
applicable
marine
engines
with
less
than
2.5
liters
per
cylinder
and
rated
power
above
560
kW
to
a
NOX
standard
of
6.4
g/
kW
hr
for
model
years
2008
through
2012.
(
2)
Notify
EPA
in
writing
before
2004
of
their
intent
to
use
this
provision.
This
notification
must
include
a
signed
statement
certifying
that
the
manufacturer
will
comply
with
all
the
provisions
of
this
paragraph
(
g).
(
3)
Add
a
permanent,
legible
label,
written
in
block
letters
in
English,
to
a
readily
visible
part
of
each
engine
exempted
under
this
paragraph
(
f).
This
label
must
include
at
least
the
following
items:
(
i)
The
label
heading
``
EMISSION
CONTROL
INFORMATION''.
(
ii)
Your
corporate
name
and
trademark.
(
iii)
Engine
displacement
(
in
liters),
rated
power,
and
model
year
of
the
engine
or
whom
to
contact
for
further
information.
(
iv)
The
statement
``
THIS
ENGINE
IS
EXEMPT
UNDER
40
CFR
94.12(
g)
FROM
EMISSION
STANDARDS
AND
RELATED
REQUIREMENTS.''.
Subpart
B
[
Amended]
25.
Section
94.104
is
amended
by
redesignating
paragraph
(
c)
as
paragraph
(
d)
and
adding
a
new
paragraph
(
c)
to
read
as
follows:
§
94.104
Test
procedures
for
Category
2
marine
engines.
*
*
*
*
*
(
c)
Conduct
testing
at
ambient
temperatures
from
13
°
C
to
30
°
C.
*
*
*
*
*
26.
Section
94.105
is
amended
by
revising
paragraph
(
b)
text
preceding
Table
B
1,
revising
``#''
to
read
``
±
'
'
in
footnotes
1
and
2
in
the
tables
in
paragraphs
(
b),
(
c)(
1),
(
c)(
2),
and
(
d)(
1),
and
adding
a
new
paragraph
(
e)
to
read
as
follows:
§
94.105
Duty
cycles.
*
*
*
*
*
(
b)
General
cycle.
Propulsion
engines
that
are
used
with
(
or
intended
to
be
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217
/
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November
8,
2002
/
Rules
and
Regulations
used
with)
fixed
pitch
propellers,
and
any
other
engines
for
which
the
other
duty
cycles
of
this
section
do
not
apply,
shall
be
tested
using
the
duty
cycle
described
in
the
following
Table
B
1:
*
*
*
*
*
(
e)
Recreational.
For
the
purpose
of
determining
compliance
with
the
emission
standards
of
§
94.8,
recreational
engines
shall
be
tested
using
the
duty
cycle
described
in
Table
B
5,
which
follows:
TABLE
B
5.
RECREATIONAL
MARINE
DUTY
CYCLE
Mode
No.
Engine
speed(
1)
(
percent
of
maximum
test
speed)
Percent
of
maximum
test
power(
2)
Minimum
time
in
mode
(
minutes)
Weighting
factors
1
.......................................................................................................................
100
100
5.0
0.08
2
.......................................................................................................................
91
75
5.0
0.13
3
.......................................................................................................................
80
50
5.0
0.17
4
.......................................................................................................................
63
25
5.0
0.32
5
.......................................................................................................................
idle
0
5.0
0.30
1
Engine
speed:
±
2
percent
of
point.
2
Power:
±
2
percent
of
engine
maximum
value.
27.
Section
94.106
is
amended
by
revising
paragraphs
(
b)
introductory
text,
(
b)(
1)
introductory
text,
(
b)(
2)
introductory
text,
(
b)(
3)
introductory
text,
and
(
b)(
4)
and
adding
a
new
paragraph
(
b)(
5)
to
read
as
follows:
§
94.106
Supplemental
test
procedures.
*
*
*
*
*
(
b)
The
specified
Not
to
Exceed
Zones
for
marine
engines
are
defined
as
follows.
These
Not
to
Exceed
Zones
apply,
unless
a
modified
zone
is
established
under
paragraph
(
c)
of
this
section.
(
1)
For
commercial
Category
1
engines
certified
using
the
duty
cycle
specified
in
§
94.105(
b),
the
Not
to
Exceed
zones
are
defined
as
follows:
*
*
*
*
*
(
2)
For
Category
2
engines
certified
using
the
duty
cycle
specified
in
§
94.105(
b),
the
Not
to
Exceed
zones
are
defined
as
follows:
*
*
*
*
*
(
3)
For
engines
certified
using
the
duty
cycle
specified
in
§
94.105(
c)(
2),
the
Not
to
Exceed
zones
are
defined
as
follows:
*
*
*
*
*
(
4)
For
engines
certified
using
the
duty
cycle
specified
in
§
94.105(
c)(
1),
the
Not
to
Exceed
zone
is
defined
as
any
load
greater
than
or
equal
to
25
percent
of
maximum
power
at
rated
speed,
and
any
speed
at
which
the
engine
operates
in
use.
(
5)
For
recreational
marine
engines
certified
using
the
duty
cycle
specified
in
§
94.105(
e),
the
Not
to
Exceed
zones
are
defined
as
follows:
(
i)
The
Not
to
Exceed
zone
is
the
region
between
the
curves
power
=
1.15
×
SPD2
and
power
=
0.85
×
SPD4,
excluding
all
operation
below
25%
of
maximum
power
at
rated
speed
and
excluding
all
operation
below
63%
of
maximum
test
speed.
(
ii)
This
zone
is
divided
into
three
subzones,
one
below
45%
of
maximum
power
at
maximum
test
speed;
one
above
95%
of
maximum
test
speed;
and
a
third
area
including
all
of
the
remaining
area
of
the
NTE
zone.
(
iii)
SPD
in
paragraph
(
b)(
5)(
i)
of
this
section
refers
to
percent
of
maximum
test
speed.
(
iv)
See
Figure
B
4
for
an
illustration
of
this
Not
to
Exceed
zone
as
follows:
BILLING
CODE
6560
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Regulations
BILLING
CODE
6560
50
C
28.
Section
94.108
is
amended
in
paragraph
(
a)(
1)
by
revising
footnote
1
in
Table
B
5
to
read
as
follows:
§
94.108
Test
fuels.
(
a)
*
*
*
(
1)
*
*
*
TABLE
B
5.
FEDERAL
TEST
FUEL
SPECIFICATIONS
*
*
*
*
*
*
*
1
All
ASTM
procedures
in
this
table
have
been
incorporated
by
reference.
See
§
94.5.
*
*
*
*
*
*
*
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Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
*
*
*
*
*
Subpart
C
[
Amended]
29.
Section
94.203
is
amended
by
revising
paragraphs
(
d)(
14)
and
(
d)(
16)
to
read
as
follows:
§
94.203
Application
for
certification.
*
*
*
*
*
(
d)
*
*
*
(
14)
A
statement
that
all
the
engines
included
in
the
engine
family
comply
with
the
Not
To
Exceed
standards
specified
in
§
94.8(
e)
when
operated
under
all
conditions
which
may
reasonably
be
expected
to
be
encountered
in
normal
operation
and
use;
the
manufacturer
also
must
provide
a
detailed
description
of
all
testing,
engineering
analyses,
and
other
information
which
provides
the
basis
for
this
statement.
*
*
*
*
*
(
16)
A
statement
indicating
duty
cycle
and
application
of
the
engine
(
e.
g.,
used
to
propel
planing
vessels,
use
to
propel
vessels
with
variable
pitch
propellers,
constant
speed
auxiliary,
recreational,
etc.).
*
*
*
*
*
30.
Section
94.204
is
amended
by
removing
``
and''
at
the
end
of
paragraph
(
b)(
9),
adding
``;
and''
at
the
end
of
paragraph
(
b)(
10),
adding
a
new
paragraph
(
b)(
11),
and
revising
paragraph
(
e)
to
read
as
follows:
§
94.204
Designation
of
engine
families.
*
*
*
*
*
(
b)
*
*
*
(
11)
Class
(
commercial
or
recreational).
*
*
*
*
*
(
e)
Upon
request
by
the
manufacturer,
the
Administrator
may
allow
engines
that
would
be
required
to
be
grouped
into
separate
engine
families
based
on
the
criteria
in
paragraph
(
b)
or
(
c)
of
this
section
to
be
grouped
into
a
single
engine
family
if
the
manufacturer
demonstrates
that
the
engines
will
have
similar
emission
characteristics;
however,
recreational
and
commercial
engines
may
not
be
grouped
in
the
same
engine
family.
This
request
must
be
accompanied
by
emission
information
supporting
the
appropriateness
of
such
combined
engine
families.
31.
Section
94.209
is
revised
to
read
as
follows:
§
94.209
Special
provisions
for
postmanufacture
marinizers
and
small
volume
manufacturers.
(
a)
Broader
engine
families.
Instead
of
the
requirements
of
§
94.204,
an
engine
family
may
consist
of
any
engines
subject
to
the
same
emission
standards.
This
does
not
change
any
of
the
requirements
of
this
part
for
showing
that
an
engine
family
meets
emission
standards.
To
be
eligible
to
use
the
provisions
of
this
paragraph
(
a),
the
manufacturer
must
demonstrate
one
of
the
following:
(
1)
It
is
a
post
manufacture
marinizer
and
that
the
base
engines
used
for
modification
have
a
valid
certificate
of
conformity
issued
under
40
CFR
part
89
or
40
CFR
part
92
or
the
heavy
duty
engine
provisions
of
40
CFR
part
86.
(
2)
It
is
a
small
volume
manufacturer.
(
b)
Hardship
relief.
Post
manufacture
marinizers,
small
volume
manufacturers,
and
small
volume
boat
builders
may
take
any
of
the
otherwise
prohibited
actions
identified
in
§
94.1103(
a)(
1)
if
approved
in
advance
by
the
Administrator,
subject
to
the
following
requirements:
(
1)
Application
for
relief
must
be
submitted
to
the
Designated
Officer
in
writing
prior
to
the
earliest
date
in
which
the
applying
manufacturer
would
be
in
violation
of
§
94.1103.
The
manufacturer
must
submit
evidence
showing
that
the
requirements
for
approval
have
been
met.
(
2)
The
conditions
causing
the
impending
violation
must
not
be
substantially
the
fault
of
the
applying
manufacturer.
(
3)
The
conditions
causing
the
impending
violation
must
jeopardize
the
solvency
of
the
applying
manufacturer
if
relief
is
not
granted.
(
4)
The
applying
manufacturer
must
demonstrate
that
no
other
allowances
under
this
part
will
be
available
to
avoid
the
impending
violation.
(
5)
Any
relief
may
not
exceed
one
year
beyond
the
date
relief
is
granted.
(
6)
The
Administrator
may
impose
other
conditions
on
the
granting
of
relief
including
provisions
to
recover
the
lost
environmental
benefit.
(
7)
The
manufacturer
must
add
a
permanent,
legible
label,
written
in
block
letters
in
English,
to
a
readily
visible
part
of
each
engine
exempted
under
this
paragraph
(
b).
This
label
must
include
at
least
the
following
items:
(
i)
The
label
heading
``
EMISSION
CONTROL
INFORMATION''.
(
ii)
Your
corporate
name
and
trademark.
(
iii)
Engine
displacement
(
in
liters),
rated
power,
and
model
year
of
the
engine
or
whom
to
contact
for
further
information.
(
iv)
The
statement
``
THIS
ENGINE
IS
EXEMPT
UNDER
40
CFR
94.209(
b)
FROM
EMISSION
STANDARDS
AND
RELATED
REQUIREMENTS.''.
(
c)
Extension
of
deadlines.
Smallvolume
manufacturers
may
use
the
provisions
of
40
CFR
1068.250
to
ask
for
an
extension
of
a
deadline
to
meet
emission
standards.
We
may
require
that
you
use
available
base
engines
that
have
been
certified
to
emission
standards
for
land
based
engines
until
you
are
able
to
produce
engines
certified
to
the
requirements
of
this
part.
32.
Section
94.212
is
amended
by
revising
paragraph
(
b)(
10)
to
read
as
follows:
§
94.212
Labeling.
*
*
*
*
*
(
b)
Engine
labels.
*
*
*
(
10)
The
application
for
which
the
engine
family
is
certified.
(
For
example:
constant
speed
auxiliary,
variable
speed
propulsion
engines
used
with
fixedpitch
propellers,
recreational,
etc.)
*
*
*
*
*
33.
Section
94.218
is
amended
by
adding
a
new
paragraph
(
d)(
2)(
iv)
to
read
as
follows:
§
94.218
Deterioration
factor
determination.
*
*
*
*
*
(
d)
*
*
*
(
2)
*
*
*
(
iv)
Assigned
deterioration
factors.
Small
volume
manufacturers
may
use
deterioration
factors
established
by
EPA.
Subpart
D
[
Amended]
34.
Section
94.304
is
amended
by
revising
paragraph
(
k)
to
read
as
follows:
§
94.304
Compliance
requirements.
*
*
*
*
*
(
k)
The
following
provisions
limit
credit
exchanges
between
different
types
of
engines:
(
1)
Credits
generated
by
Category
1
engine
families
may
be
used
for
compliance
by
Category
1
or
Category
2
engine
families.
Credits
generated
from
Category
1
engine
families
for
use
by
Category
2
engine
families
must
be
discounted
by
25
percent.
(
2)
Credits
generated
by
Category
2
engine
families
may
be
used
for
compliance
only
by
Category
2
engine
families.
(
3)
Credits
may
not
be
exchanged
between
recreational
and
commercial
engines.
*
*
*
*
*
Subpart
F
[
Amended]
35.
Section
94.501
is
amended
by
revising
paragraph
(
a)
to
read
as
follows:
§
94.501
Applicability.
(
a)
The
requirements
of
this
subpart
are
applicable
to
manufacturers
of
engines
subject
to
the
provisions
of
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8,
2002
/
Rules
and
Regulations
Subpart
A
of
this
part,
excluding
smallvolume
manufacturers.
*
*
*
*
*
36.
Section
94.503
is
amended
by
adding
a
new
paragraph
(
d)
to
read
as
follows:
§
94.503
General
requirements.
*
*
*
*
*
(
d)
If
you
certify
an
engine
family
with
carryover
emission
data,
as
described
in
§
94.206(
c),
and
these
equivalent
engine
families
consistently
pass
the
production
line
testing
requirements
over
the
preceding
twoyear
period,
you
may
ask
for
a
reduced
testing
rate
for
further
production
line
testing
for
that
family.
The
minimum
testing
rate
is
one
engine
per
engine
family.
If
we
reduce
your
testing
rate,
we
may
limit
our
approval
to
any
number
of
model
years.
In
determining
whether
to
approve
your
request,
we
may
consider
the
number
of
engines
that
have
failed
the
emission
tests.
Subpart
J
[
Amended]
37.
Section
94.907
is
amended
by
revising
paragraphs
(
d)
and
(
g)
to
read
as
follows:
§
94.907
Engine
dressing
exemption.
*
*
*
*
*
(
d)
New
marine
engines
that
meet
all
the
following
criteria
are
exempt
under
this
section:
(
1)
You
must
produce
it
by
marinizing
an
engine
covered
by
a
valid
certificate
of
conformity
from
one
of
the
following
programs:
(
i)
Heavy
duty
highway
engines
(
40
CFR
part
86).
(
ii)
Land
based
nonroad
diesel
engines
(
40
CFR
part
89).
(
iii)
Locomotive
engines
(
40
CFR
part
92).
(
2)
The
engine
must
have
the
label
required
under
40
CFR
part
86,
89,
or
92.
(
3)
You
must
not
make
any
changes
to
the
certified
engine
that
could
reasonably
be
expected
to
increase
its
emissions.
For
example,
if
you
make
any
of
the
following
changes
to
one
of
these
engines,
you
do
not
qualify
for
the
engine
dressing
exemption:
(
i)
Changing
any
fuel
system
parameters
from
the
certified
configuration.
(
ii)
Replacing
an
original
turbocharger,
except
that
small
volume
manufacturers
of
recreational
engines
may
replace
an
original
turbocharger
with
one
that
matches
the
performance
of
the
original
turbocharger.
(
iii)
Modify
or
design
the
marine
engine
cooling
or
aftercooling
system
so
that
temperatures
or
heat
rejection
rates
are
outside
the
original
engine
manufacturer's
specified
ranges.
(
4)
You
must
make
sure
that
fewer
than
50
percent
of
the
engine
model's
total
sales,
from
all
companies,
are
used
in
marine
applications.
*
*
*
*
*
(
g)
If
your
engines
do
not
meet
the
criteria
listed
in
paragraphs
(
d)(
2)
through
(
d)(
4)
of
this
section,
they
will
be
subject
to
the
standards
and
prohibitions
of
this
part.
Marinization
without
a
valid
exemption
or
certificate
of
conformity
would
be
a
violation
of
§
94.1103(
a)(
1)
and/
or
the
tampering
prohibitions
of
the
applicable
landbased
regulations
(
40
CFR
part
86,
89,
or
92).
*
*
*
*
*
Subpart
L
[
Amended]
38.
Section
94.1103
is
amended
by
revising
paragraph
(
a)(
5)
to
read
as
follows:
§
94.1103
Prohibited
acts.
(
a)
*
*
*
(
5)
For
a
manufacturer
of
marine
vessels
to
distribute
in
commerce,
sell,
offer
for
sale,
or
deliver
for
introduction
into
commerce
a
new
vessel
containing
an
engine
not
covered
by
a
certificate
of
conformity
applicable
for
an
engine
model
year
the
same
as
or
later
than
the
calendar
year
in
which
the
manufacture
of
the
new
vessel
is
initiated.
This
prohibition
covers
improper
installation
in
a
manner
such
that
the
installed
engine
would
not
be
covered
by
the
engine
manufacturer's
certificate.
Improper
installation
would
include,
but
is
not
limited
to,
failure
to
follow
the
engine
manufacturer's
instructions
related
to
engine
cooling,
exhaust
aftertreatment,
emission
sampling
ports,
or
any
other
emission
related
component,
parameter,
or
setting.
In
general,
you
may
use
up
your
normal
inventory
of
engines
not
certified
to
new
emission
standards
if
they
were
built
before
the
date
of
the
new
standards.
However,
we
consider
stockpiling
of
these
engines
to
be
a
violation
of
paragraph
(
a)(
1)(
i)(
A)
of
this
section.
(
Note:
For
the
purpose
of
this
paragraph
(
a)(
5),
the
manufacture
of
a
vessel
is
initiated
when
the
keel
is
laid,
or
the
vessel
is
at
a
similar
stage
of
construction.)
*
*
*
*
*
39.
A
new
subchapter
U
is
added
to
chapter
I,
consisting
of
parts
1048,
1051,
1065,
and
1068,
to
read
as
follows:
SUBCHAPTER
U
AIR
POLLUTION
CONTROLS
PART
1048
CONTROL
OF
EMISSIONS
FROM
NEW,
LARGE
NONROAD
SPARK
IGNITION
ENGINES
Subpart
A
Determining
How
to
Follow
This
Part
Sec.
1048.1
Does
this
part
apply
to
me?
1048.5
Which
engines
are
excluded
or
exempted
from
this
part's
requirements?
1048.10
What
main
steps
must
I
take
to
comply
with
this
part?
1048.15
Do
any
other
regulation
parts
affect
me?
1048.20
What
requirements
from
this
part
apply
to
my
excluded
engines?
Subpart
B
Emission
Standards
and
Related
Requirements
1048.101
What
exhaust
emission
standards
must
my
engines
meet?
1048.105
What
evaporative
emissions
standards
and
requirements
apply?
1048.110
How
must
my
engines
diagnose
malfunctions?
1048.115
What
other
requirements
must
my
engines
meet?
1048.120
What
warranty
requirements
apply
to
me?
1048.125
What
maintenance
instructions
must
I
give
to
buyers?
1048.130
What
installation
instructions
must
I
give
to
equipment
manufacturers?
1048.135
How
must
I
label
and
identify
the
engines
I
produce?
1048.140
What
are
the
provisions
for
certifying
Blue
Sky
Series
engines?
1048.145
What
provisions
apply
only
for
a
limited
time?
Subpart
C
Certifying
Engine
Families
1048.201
What
are
the
general
requirements
for
submitting
a
certification
application?
1048.205
What
must
I
include
in
my
application?
1048.210
May
I
get
preliminary
approval
before
I
complete
my
application?
1048.215
What
happens
after
I
complete
my
application?
1048.220
How
do
I
amend
the
maintenance
instructions
in
my
application?
1048.225
How
do
I
amend
my
application
to
include
new
or
modified
engines?
1048.230
How
do
I
select
engine
families?
1048.235
What
emission
testing
must
I
perform
for
my
application
for
a
certificate
of
conformity?
1048.240
How
do
I
demonstrate
that
my
engine
family
complies
with
exhaust
emission
standards?
1048.245
How
do
I
demonstrate
that
my
engine
family
complies
with
evaporative
emission
standards?
1048.250
What
records
must
I
keep
and
make
available
to
EPA?
1048.255
When
may
EPA
deny,
revoke,
or
void
my
certificate
of
conformity?
Subpart
D
Testing
Production
line
Engines
1048.301
When
must
I
test
my
productionline
engines?
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Rules
and
Regulations
1048.305
How
must
I
prepare
and
test
my
production
line
engines?
1048.310
How
must
I
select
engines
for
production
line
testing?
1048.315
How
do
I
know
when
my
engine
family
fails
the
production
line
testing
requirements?
1048.320
What
happens
if
one
of
my
production
line
engines
fails
to
meet
emission
standards?
1048.325
What
happens
if
an
engine
family
fails
the
production
line
requirements?
1048.330
May
I
sell
engines
from
an
engine
family
with
a
suspended
certificate
of
conformity?
1048.335
How
do
I
ask
EPA
to
reinstate
my
suspended
certificate?
1048.340
When
may
EPA
revoke
my
certificate
under
this
subpart
and
how
may
I
sell
these
engines
again?
1048.345
What
production
line
testing
records
must
I
send
to
EPA?
1048.350
What
records
must
I
keep?
Subpart
E
Testing
In
use
Engines
1048.401
What
testing
requirements
apply
to
my
engines
that
have
gone
into
service?
1048.405
How
does
this
program
work?
1048.410
How
must
I
select,
prepare,
and
test
my
in
use
engines?
1048.415
What
happens
if
in
use
engines
do
not
meet
requirements?
1048.420
What
in
use
testing
information
must
I
report
to
EPA?
1048.425
What
records
must
I
keep?
Subpart
F
Test
Procedures
1048.501
What
procedures
must
I
use
to
test
my
engines?
1048.505
What
steady
state
duty
cycles
apply
for
laboratory
testing?
1048.510
What
transient
duty
cycles
apply
for
laboratory
testing?
1048.515
Field
testing
procedures.
Subpart
G
Compliance
Provisions
1048.601
What
compliance
provisions
apply
to
these
engines?
1048.605
What
are
the
provisions
for
exempting
engines
from
the
requirements
of
this
part
if
they
are
already
certified
under
the
motor
vehicle
program?
1048.610
What
are
the
provisions
for
producing
nonroad
equipment
with
engines
already
certified
under
the
motor
vehicle
program?
1048.615
What
are
the
provisions
for
exempting
engines
designed
for
lawn
and
garden
applications?
1048.620
What
are
the
provisions
for
exempting
large
engines
fueled
by
natural
gas?
1048.625
What
special
provisions
apply
to
engines
using
noncommercial
fuels?
Subpart
H
[
Reserved]
Subpart
I
Definitions
and
Other
Reference
Information
1048.801
What
definitions
apply
to
this
part?
1048.805
What
symbols,
acronyms,
and
abbreviations
does
this
part
use?
1048.810
What
materials
does
this
part
reference?
1048.815
How
should
I
request
EPA
to
keep
my
information
confidential?
1048.820
How
do
I
request
a
hearing?
Appendix
I
to
Part
1048
Large
Sparkignition
(
SI)
Transient
Cycle
for
Constant
Speed
Engines
Appendix
II
to
Part
1048
Large
Sparkignition
(
SI)
Composite
Transient
Cycle
Authority:
42
U.
S.
C.
7401
7671(
q).
Subpart
A
Determining
How
to
Follow
This
Part
§
1048.1
Does
this
part
apply
to
me?
(
a)
This
part
applies
to
you
if
you
manufacture
or
import
new,
sparkignition
nonroad
engines
(
defined
in
§
1048.801)
with
maximum
brake
power
above
19
kW,
unless
we
exclude
them
under
§
1048.5.
See
§
1048.20
for
the
requirements
that
apply
to
excluded
engines.
(
b)
If
you
manufacture
or
import
engines
with
maximum
brake
power
at
or
below
19
kW
that
would
otherwise
be
covered
by
40
CFR
part
90,
you
may
choose
to
meet
the
requirements
of
this
part
instead.
In
this
case,
all
the
provisions
of
this
part
apply
for
those
engines.
(
c)
As
noted
in
subpart
G
of
this
part,
40
CFR
part
1068
applies
to
everyone,
including
anyone
who
manufactures,
installs,
owns,
operates,
or
rebuilds
any
of
the
engines
this
part
covers
or
equipment
containing
these
engines.
(
d)
You
need
not
follow
this
part
for
engines
you
produce
before
January
1,
2004,
unless
you
certify
voluntarily.
See
§
§
1048.101
through
1048.115
and
§
1048.145
and
the
definition
of
model
year
in
§
1048.801
for
more
information
about
the
timing
of
new
requirements.
(
e)
See
§
§
1048.801
and
1048.805
for
definitions
and
acronyms
that
apply
to
this
part.
The
definition
section
contains
significant
regulatory
provisions
and
it
is
very
important
that
you
read
them.
§
1048.5
Which
engines
are
excluded
or
exempted
from
this
part's
requirements?
(
a)
This
part
does
not
apply
to
the
following
nonroad
engines:
(
1)
Engines
certified
to
meet
the
requirements
of
40
CFR
part
1051
(
for
example,
engines
used
in
snowmobiles
and
all
terrain
vehicles).
(
2)
Propulsion
marine
engines.
See
40
CFR
part
91.
This
part
applies
with
respect
to
auxiliary
marine
engines.
(
b)
See
subpart
G
of
this
part
and
40
CFR
part
1068,
subpart
C,
for
exemptions
of
specific
engines.
(
c)
Send
the
Designated
Officer
a
written
request
if
you
want
us
to
determine
whether
this
part
covers
or
excludes
certain
engines.
Excluding
engines
from
this
part's
requirements
does
not
affect
other
requirements
that
may
apply
to
them.
Note:
See
40
CFR
part
87
for
engines
used
in
aircraft.)
(
d)
As
defined
in
§
1048.801,
stationary
engines
are
not
required
to
comply
with
this
part
(
because
they
are
not
nonroad
engines),
except
that
you
must
meet
the
requirements
in
§
1048.20.
In
addition,
the
prohibitions
in
40
CFR
1068.101
restrict
the
use
of
stationary
engines
for
non
stationary
purposes.
§
1048.10
What
main
steps
must
I
take
to
comply
with
this
part?
(
a)
You
must
have
a
certificate
of
conformity
from
us
for
each
engine
family
before
you
do
any
of
the
following
with
a
new
nonroad
engine
covered
by
this
part:
sell,
offer
for
sale,
introduce
into
commerce,
distribute
or
deliver
for
introduction
into
commerce,
or
import
it
into
the
United
States.
``
New''
engines
may
include
some
already
placed
in
service
(
see
the
definition
of
``
new
nonroad
engine''
and
``
new
nonroad
equipment''
in
§
1048.801).
You
must
get
a
new
certificate
of
conformity
for
each
new
model
year.
(
b)
To
get
a
certificate
of
conformity
and
comply
with
its
terms,
you
must
do
six
things:
(
1)
Meet
the
emission
standards
and
other
requirements
in
subpart
B
of
this
part.
(
2)
Perform
preproduction
emission
tests.
(
3)
Apply
for
certification
(
see
subpart
C
of
this
part).
(
4)
Do
routine
emission
testing
on
production
engines
as
required
by
subpart
D
of
this
part.
(
5)
Do
emission
testing
on
in
use
engines,
as
we
direct
under
subpart
E
of
this
part.
(
6)
Follow
our
instructions
throughout
this
part.
(
c)
Subpart
F
of
this
part
describes
how
to
test
your
engines
(
including
references
to
other
parts).
(
d)
Subpart
G
of
this
part
and
40
CFR
part
1068
describe
requirements
and
prohibitions
that
apply
to
engine
manufacturers,
equipment
manufacturers,
owners,
operators,
rebuilders,
and
all
others.
§
1048.15
Do
any
other
regulation
parts
affect
me?
(
a)
Part
1065
of
this
chapter
describes
procedures
and
equipment
specifications
for
testing
engines.
Subpart
F
of
this
part
describes
how
to
apply
the
provisions
of
part
1065
of
this
chapter
to
show
you
meet
the
emission
standards
in
this
part.
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and
Regulations
(
b)
Part
1068
of
this
chapter
describes
general
provisions,
including
these
seven
areas:
(
1)
Prohibited
acts
and
penalties
for
engine
manufacturers,
equipment
manufacturers,
and
others.
(
2)
Rebuilding
and
other
aftermarket
changes.
(
3)
Exclusions
and
exemption
for
certain
engines.
(
4)
Importing
engines.
(
5)
Selective
enforcement
audits
of
your
production.
(
6)
Defect
reporting
and
recall.
(
7)
Procedures
for
hearings.
(
c)
Other
parts
of
this
chapter
affect
you
if
referenced
in
this
part.
§
1048.20
What
requirements
from
this
part
apply
to
my
excluded
engines?
(
a)
Engine
manufacturers
producing
an
engine
excluded
under
§
1048.5(
d)
must
add
a
permanent
label
or
tag
identifying
each
engine.
This
applies
equally
to
importers.
To
meet
labeling
requirements,
you
must
do
the
following
things:
(
1)
Attach
the
label
or
tag
in
one
piece
so
no
one
can
remove
it
without
destroying
or
defacing
it.
(
2)
Make
sure
it
is
durable
and
readable
for
the
engine's
entire
life.
(
3)
Secure
it
to
a
part
of
the
engine
needed
for
normal
operation
and
not
normally
requiring
replacement.
(
4)
Write
it
in
block
letters
in
English.
(
5)
Instruct
equipment
manufacturers
that
they
must
place
a
duplicate
label
as
described
in
40
CFR
1068.105
if
they
obscure
the
engine's
label.
(
b)
Engine
labels
or
tags
required
under
this
section
must
have
the
following
information:
(
1)
Include
the
heading
``
Emission
Control
Information''.
(
2)
Include
your
full
corporate
name
and
trademark.
(
3)
State
the
engine
displacement
(
in
liters)
and
maximum
brake
power.
(
4)
State:
``
THIS
ENGINE
IS
EXCLUDED
FROM
THE
REQUIREMENTS
OF
40
CFR
PART
1048
AS
A
``
STATIONARY
ENGINE.''
INSTALLING
OR
USING
THIS
ENGINE
IN
ANY
OTHER
APPLICATION
MAY
BE
A
VIOLATION
OF
FEDERAL
LAW
SUBJECT
TO
CIVIL
PENALTY.''.
Subpart
B
Emission
Standards
and
Related
Requirements
§
1048.101
What
exhaust
emission
standards
must
my
engines
meet?
Apply
the
exhaust
emission
standards
in
this
section
by
model
year.
You
may
choose
to
certify
engines
earlier
than
we
require.
The
Tier
1
standards
apply
only
to
steady
state
testing,
as
described
in
paragraph
(
b)
of
this
section.
The
Tier
2
standards
apply
to
steady
state,
transient,
and
field
testing,
as
described
in
paragraphs
(
a),
(
b),
and
(
c)
of
this
section.
(
a)
Standards
for
transient
testing.
Starting
in
the
2007
model
year,
Tier
2
exhaust
emission
standards
apply
for
transient
measurement
of
emissions
with
the
duty
cycle
test
procedures
in
subpart
F
of
this
part:
(
1)
The
Tier
2
HC+
NOX
standard
is
2.7
g/
kW
hr
and
the
Tier
2
CO
standard
is
4.4
g/
kW
hr.
For
severe
duty
engines,
the
Tier
2
HC+
NOX
standard
is
2.7
g/
kW
hr
and
the
Tier
2
CO
standard
is
130.0
g/
kW
hr.
The
standards
in
this
paragraph
(
a)
do
not
apply
for
transient
testing
of
high
load
engines.
(
2)
You
may
optionally
certify
your
engines
according
to
the
following
formula
instead
of
the
standards
in
paragraph
(
a)(
1)
of
this
section:
(
HC+
NOX)
×
CO0.784
8.57.
The
HC+
NOX
and
CO
emission
levels
you
select
to
satisfy
this
formula,
rounded
to
the
nearest
0.1
g/
kW
hr,
become
the
emission
standards
that
apply
for
those
engines.
You
may
not
select
an
HC+
NOX
emission
standard
higher
than
2.7
g/
kWhr
or
a
CO
emission
standard
higher
than
20.6
g/
kW
hr.
The
following
table
illustrates
a
range
of
possible
values
under
this
paragraph
(
a)(
2):
TABLE
1
OF
§
1048.101.
EXAMPLES
OF
POSSIBLE
TIER
2
DUTY
CYCLE
EMISSION
STANDARDS
HC+
NOX
(
g/
kW
hr)
CO
(
g/
kW
hr)
2.7
.............................................
4.4
2.2
.............................................
5.6
1.7
.............................................
7.9
1.3
.............................................
11.1
1.0
.............................................
15.5
0.8
.............................................
20.6
(
b)
Standards
for
steady
state
testing.
Except
as
we
allow
in
paragraph
(
d)
of
this
section,
the
following
exhaust
emission
standards
apply
for
steadystate
measurement
of
emissions
with
the
duty
cycle
test
procedures
in
subpart
F
of
this
part:
(
1)
The
following
table
shows
the
Tier
1
exhaust
emission
standards
that
apply
to
engines
from
2004
through
2006
model
years:
TABLE
2
OF
§
1048.101.
TIER
1
EMISSION
STANDARDS
(
G/
KW
HR)
Testing
General
emission
standards
Alternate
emission
standards
for
severe
duty
engines
HC+
NOX
CO
HC+
NOX
CO
Certification
and
production
line
testing
..........................................................................
4.0
50.0
4.0
130.0
In
use
testing
...................................................................................................................
5.4
50.0
5.4
130.0
(
2)
Starting
in
the
2007
model
year,
engines
must
meet
the
Tier
2
exhaust
emission
standards
in
paragraph
(
a)
of
this
section
for
both
steady
state
and
transient
testing.
See
paragraph
(
d)
of
this
section
for
alternate
standards
that
apply
for
certain
engines.
(
c)
Standards
for
field
testing.
Starting
in
2007,
the
following
Tier
2
exhaust
emission
standards
apply
for
emission
measurements
with
the
field
testing
procedures
in
subpart
F
of
this
part:
(
1)
The
HC+
NOX
standard
is
3.8
g/
kW
hr
and
the
CO
standard
is
6.5
g/
kWhr
For
severe
duty
engines,
the
HC+
NOX
standard
is
3.8
g/
kW
hr
and
the
CO
standard
is
200.0
g/
kW
hr.
For
natural
gas
fueled
engines,
you
are
not
required
to
measure
nonmethane
hydrocarbon
emissions
or
total
hydrocarbon
emissions
for
testing
to
show
that
the
engine
meets
the
emission
standards
of
this
paragraph
(
c);
that
is,
you
may
assume
HC
emissions
are
equal
to
zero.
(
2)
You
may
apply
the
following
formula
to
determine
alternate
emission
standards
that
apply
to
your
engines
instead
of
the
standards
in
paragraph
(
c)(
1)
of
this
section:
(
HC+
NOX)
×
CO0.791
16.78.
HC+
NOX
emission
levels
may
not
exceed
3.8
g/
kW
hr
and
CO
emission
levels
may
not
exceed
31.0
g/
kW
hr.
The
following
table
illustrates
a
range
of
possible
values
under
this
paragraph
(
c)(
2):
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2002
/
Rules
and
Regulations
TABLE
3
OF
§
1048.101.
EXAMPLES
OF
POSSIBLE
TIER
2
FIELD
TESTING
EMISSION
STANDARDS
HC+
NOX
(
g/
kW
hr)
CO
(
g/
kW
hr)
3.8
.............................................
6.5
3.1
.............................................
8.5
2.4
.............................................
11.7
1.8
.............................................
16.8
1.4
.............................................
23.1
1.1
.............................................
31.0
(
d)
Engine
protection.
For
engines
that
require
enrichment
at
high
loads
to
protect
the
engine,
you
may
ask
to
meet
alternate
Tier
2
standards
of
2.7
g/
kWhr
for
HC+
NOX
and
31.0
g/
kW
hr
for
CO
instead
of
the
emission
standards
described
in
paragraph
(
b)(
2)
of
this
section
for
steady
state
testing.
If
we
approve
your
request,
you
must
still
meet
the
transient
testing
standards
in
paragraph
(
a)
of
this
section
and
the
field
testing
standards
in
paragraph
(
c)
of
this
section.
To
qualify
for
this
allowance,
you
must
do
all
the
following
things:
(
1)
Show
that
enrichment
is
necessary
to
protect
the
engine
from
damage.
(
2)
Show
that
you
limit
enrichment
to
operating
modes
that
require
additional
cooling
to
protect
the
engine
from
damage.
(
3)
Show
in
your
application
for
certification
that
enrichment
will
rarely
occur
in
use
in
the
equipment
in
which
your
engines
are
installed.
For
example,
an
engine
that
is
expected
to
operate
5
percent
of
the
time
in
use
with
enrichment
would
clearly
not
qualify.
(
4)
Include
in
your
installation
instructions
any
steps
necessary
for
someone
installing
your
engines
to
prevent
enrichment
during
normal
operation
(
see
§
1048.130).
(
e)
Fuel
types.
Apply
the
exhaust
emission
standards
in
this
section
for
engines
using
each
type
of
fuel
specified
in
40
CFR
part
1065,
subpart
C,
for
which
they
are
designed
to
operate.
You
must
meet
the
numerical
emission
standards
for
hydrocarbons
in
this
section
based
on
the
following
types
of
hydrocarbon
emissions
for
engines
powered
by
the
following
fuels:
(
1)
Gasoline
and
LPG
fueled
engines:
THC
emissions.
(
2)
Natural
gas
fueled
engines:
NMHC
emissions.
(
3)
Alcohol
fueled
engines:
THCE
emissions.
(
f)
Small
engines.
Certain
engines
with
total
displacement
at
or
below
1000
cc
may
comply
with
the
requirements
of
40
CFR
part
90
instead
of
complying
with
the
requirements
of
this
part,
as
described
in
§
1048.615.
(
g)
Useful
life.
Your
engines
must
meet
the
exhaust
emission
standards
in
paragraphs
(
a)
through
(
c)
of
this
section
over
their
full
useful
life
(
§
1048.240
describes
how
to
use
deterioration
factors
to
show
this).
The
minimum
useful
life
is
5,000
hours
of
operation
or
seven
years,
whichever
comes
first.
(
1)
Specify
a
longer
useful
life
in
hours
for
an
engine
family
under
either
of
two
conditions:
(
i)
If
you
design,
advertise,
or
market
your
engine
to
operate
longer
than
the
minimum
useful
life
(
your
recommended
hours
until
rebuild
may
indicate
a
longer
design
life).
(
ii)
If
your
basic
mechanical
warranty
is
longer
than
the
minimum
useful
life.
(
2)
You
may
request
a
shorter
useful
life
for
an
engine
family
if
you
have
documentation
from
in
use
engines
showing
that
these
engines
will
rarely
operate
longer
than
the
alternate
useful
life.
The
useful
life
value
may
not
be
shorter
than
any
of
the
following:
(
i)
1,000
hours
of
operation.
(
ii)
Your
recommended
overhaul
interval.
(
iii)
Your
mechanical
warranty
for
the
engine.
(
h)
Applicability
for
testing.
The
standards
in
this
subpart
apply
to
all
testing,
including
production
line
and
in
use
testing,
as
described
in
subparts
D
and
E
of
this
part.
§
1048.105
What
evaporative
emissions
standards
and
requirements
apply?
(
a)
Starting
in
the
2007
model
year,
engines
that
run
on
a
volatile
liquid
fuel
(
such
as
gasoline),
must
meet
the
following
evaporative
emissions
standards
and
requirements:
(
1)
Evaporative
hydrocarbon
emissions
may
not
exceed
0.2
grams
per
gallon
of
fuel
tank
capacity
when
measured
with
the
test
procedures
for
evaporative
emissions
in
subpart
F
of
this
part.
(
2)
For
nonmetallic
fuel
lines,
you
must
specify
and
use
products
that
meet
the
Category
1
specifications
in
SAE
J2260
(
incorporated
by
reference
in
§
1048.810).
(
3)
Liquid
fuel
in
the
fuel
tank
may
not
reach
boiling
during
continuous
engine
operation
in
the
final
installation
at
an
ambient
temperature
of
30
°
C.
Note
that
gasoline
with
a
Reid
vapor
pressure
of
62
kPa
(
9
psi)
begins
to
boil
at
about
53
°
C.
(
b)
Note
that
§
1048.245
allows
you
to
use
design
based
certification
instead
of
generating
new
emission
data.
(
c)
If
other
companies
install
your
engines
in
their
equipment,
give
them
any
appropriate
instructions,
as
described
in
§
1048.130.
§
1048.110
How
must
my
engines
diagnose
malfunctions?
(
a)
Equip
your
engines
with
a
diagnostic
system.
Starting
in
the
2007
model
year,
equip
each
engine
with
a
diagnostic
system
that
will
detect
significant
malfunctions
in
its
emissioncontrol
system
using
one
of
the
following
protocols:
(
1)
If
your
emission
control
strategy
depends
on
maintaining
air
fuel
ratios
at
stoichiometry,
an
acceptable
diagnostic
design
would
identify
malfunction
whenever
the
air
fuel
ratio
does
not
cross
stoichiometry
for
one
minute
of
intended
closed
loop
operation.
You
may
use
other
diagnostic
strategies
if
we
approve
them
in
advance.
(
2)
If
the
protocol
described
in
paragraph
(
a)(
1)
of
this
section
does
not
apply
to
your
engine,
you
must
use
an
alternative
approach
that
we
approve
in
advance.
Your
alternative
approach
must
generally
detect
when
the
emission
control
system
is
not
functioning
properly.
(
b)
Use
a
malfunction
indicator
light
(
MIL).
The
MIL
must
be
readily
visible
to
the
operator;
it
may
be
any
color
except
red.
When
the
MIL
goes
on,
it
must
display
``
Check
Engine,''
``
Service
Engine
Soon,''
or
a
similar
message
that
we
approve.
You
may
use
sound
in
addition
to
the
light
signal.
The
MIL
must
go
on
under
each
of
these
circumstances:
(
1)
When
a
malfunction
occurs,
as
described
in
paragraph
(
a)
of
this
section.
(
2)
When
the
diagnostic
system
cannot
send
signals
to
meet
the
requirement
of
paragraph
(
b)(
1)
of
this
section.
(
3)
When
the
engine's
ignition
is
in
the
``
key
on''
position
before
starting
or
cranking.
The
MIL
should
go
out
after
engine
starting
if
the
system
detects
no
malfunction.
(
c)
Control
when
the
MIL
can
go
out.
If
the
MIL
goes
on
to
show
a
malfunction,
it
must
remain
on
during
all
later
engine
operation
until
servicing
corrects
the
malfunction.
If
the
engine
is
not
serviced,
but
the
malfunction
does
not
recur
for
three
consecutive
engine
starts
during
which
the
malfunctioning
system
is
evaluated
and
found
to
be
working
properly,
the
MIL
may
stay
off
during
later
engine
operation.
(
d)
Store
trouble
codes
in
computer
memory.
Record
and
store
in
computer
memory
any
diagnostic
trouble
codes
showing
a
malfunction
that
should
illuminate
the
MIL.
The
stored
codes
must
identify
the
malfunctioning
system
or
component
as
uniquely
as
possible.
Make
these
codes
available
through
the
data
link
connector
as
described
in
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Vol.
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217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
paragraph
(
g)
of
this
section.
You
may
store
codes
for
conditions
that
do
not
turn
on
the
MIL.
The
system
must
store
a
separate
code
to
show
when
the
diagnostic
system
is
disabled
(
from
malfunction
or
tampering).
(
e)
Make
data,
access
codes,
and
devices
accessible.
Make
all
required
data
accessible
to
us
without
any
access
codes
or
devices
that
only
you
can
supply.
Ensure
that
anyone
servicing
your
engine
can
read
and
understand
the
diagnostic
trouble
codes
stored
in
the
onboard
computer
with
generic
tools
and
information.
(
f)
Consider
exceptions
for
certain
conditions.
Your
diagnostic
systems
may
disregard
trouble
codes
for
the
first
three
minutes
after
engine
starting.
You
may
ask
us
to
approve
diagnosticsystem
designs
that
disregard
trouble
codes
under
other
conditions
that
would
produce
an
unreliable
reading,
damage
systems
or
components,
or
cause
other
safety
risks.
This
might
include
operation
at
altitudes
over
8,000
feet.
(
g)
Follow
standard
references
for
formats,
codes,
and
connections.
Follow
conventions
defined
in
the
following
documents
(
incorporated
by
reference
in
§
1048.810)
or
ask
us
to
approve
using
updated
versions
of
(
or
variations
from)
these
documents:
(
1)
ISO
9141
2
Road
vehicles
Diagnostic
systems
Part
2:
CARB
requirements
for
interchange
of
digital
information,
February
1994.
(
2)
ISO
14230
4
Road
vehicles
Diagnostic
systems
Keyword
Protocol
2000
Part
4:
Requirements
for
emission
related
systems,
June
2000.
§
1048.115
What
other
requirements
must
my
engines
meet?
Your
engines
must
meet
the
following
requirements:
(
a)
Closed
crankcase.
Your
engines
may
not
vent
crankcase
emissions
into
the
atmosphere
throughout
their
useful
life,
with
the
following
exception:
your
engines
may
vent
crankcase
emissions
if
you
measure
and
include
these
crankcase
emissions
with
all
measured
exhaust
emissions.
(
b)
Torque
broadcasting.
Electronically
controlled
engines
must
broadcast
their
speed
and
output
shaft
torque
(
in
newton
meters)
on
their
controller
area
networks.
Engines
may
alternatively
broadcast
a
surrogate
value
for
torque
that
can
be
read
with
a
remote
device.
This
information
is
necessary
for
testing
engines
in
the
field
(
see
40
CFR
1065.515).
This
requirement
applies
beginning
in
the
2007
model
year.
Small
volume
engine
manufacturers
may
omit
this
requirement.
(
c)
EPA
access
to
broadcast
information.
If
we
request
it,
you
must
provide
us
any
hardware
or
tools
we
would
need
to
readily
read,
interpret,
and
record
all
information
broadcast
by
an
engine's
on
board
computers
and
electronic
control
modules.
If
you
broadcast
a
surrogate
parameter
for
torque
values,
you
must
provide
us
what
we
need
to
convert
these
into
torque
units.
We
will
not
ask
for
hardware
or
tools
if
they
are
readily
available
commercially.
(
d)
Emission
sampling
capability.
Produce
all
your
engines
to
allow
sampling
of
exhaust
emissions
in
the
field
without
damaging
the
engine
or
equipment.
Show
in
your
application
for
certification
how
this
can
be
done
in
a
way
that
prevents
diluting
the
exhaust
sample
with
ambient
air.
To
do
this,
you
might
simply
allow
for
extending
the
exhaust
pipe
by
20
cm;
you
might
also
install
exhaust
ports
downstream
of
any
aftertreatment
devices.
(
e)
Adjustable
parameters.
Engines
that
have
adjustable
parameters
must
meet
all
the
requirements
of
this
part
for
any
adjustment
in
the
physically
adjustable
range.
(
1)
We
do
not
consider
an
operating
parameter
adjustable
if
you
permanently
seal
it
or
if
ordinary
tools
cannot
readily
access
it.
(
2)
We
may
require
that
you
set
adjustable
parameters
to
any
specification
within
the
adjustable
range
during
certification
testing,
productionline
testing,
selective
enforcement
auditing,
or
any
in
use
testing.
(
f)
Prohibited
controls.
You
may
not
design
your
engines
with
emissioncontrol
devices,
systems,
or
elements
of
design
that
cause
or
contribute
to
an
unreasonable
risk
to
public
health,
welfare,
or
safety
while
operating.
For
example,
this
would
apply
if
the
engine
emits
a
noxious
or
toxic
substance
it
would
otherwise
not
emit
that
contributes
to
such
an
unreasonable
risk.
(
g)
Defeat
devices.
You
may
not
equip
your
engines
with
a
defeat
device.
A
defeat
device
is
an
auxiliary
emissioncontrol
device
that
reduces
the
effectiveness
of
emission
controls
under
conditions
you
may
reasonably
expect
the
engine
to
encounter
during
normal
operation
and
use.
This
does
not
apply
to
auxiliary
emission
control
devices
you
identify
in
your
certification
application
if
any
of
the
following
is
true:
(
1)
The
conditions
of
concern
were
substantially
included
in
your
prescribed
duty
cycles.
(
2)
You
show
your
design
is
necessary
to
prevent
catastrophic
engine
(
or
equipment)
damage
or
accidents.
(
3)
The
reduced
effectiveness
applies
only
to
starting
the
engine.
§
1048.120
What
warranty
requirements
apply
to
me?
(
a)
General
requirements.
You
must
warrant
to
the
ultimate
buyer
that
the
new
nonroad
engine
meets
two
conditions:
(
1)
It
is
designed,
built,
and
equipped
it
to
conform
at
the
time
of
sale
with
the
requirements
of
this
part.
(
2)
It
is
free
from
defects
in
materials
and
workmanship
that
may
keep
it
from
meeting
these
requirements.
(
b)
Warranty
period.
Your
emissionrelated
warranty
must
be
valid
for
at
least
50
percent
of
the
engine's
useful
life
in
hours
of
operation
or
at
least
three
years,
whichever
comes
first.
In
the
case
of
a
high
cost
warranted
part,
the
warranty
must
be
valid
for
at
least
70
percent
of
the
engine's
useful
life
in
hours
of
operation
or
at
least
five
years,
whichever
comes
first.
You
may
offer
an
emission
related
warranty
more
generous
than
we
require.
This
warranty
may
not
be
shorter
than
any
published
or
negotiated
warranty
you
offer
for
the
engine
or
any
of
its
components.
If
an
engine
has
no
hour
meter,
we
base
the
warranty
periods
in
this
paragraph
(
b)
only
on
the
engine's
age
(
in
years).
(
c)
Components
covered.
The
emission
related
warranty
must
cover
components
whose
failure
would
increase
an
engine's
emissions,
including
electronic
controls,
fuel
injection
(
for
liquid
or
gaseous
fuels),
exhaust
gas
recirculation,
aftertreatment,
or
any
other
system
you
develop
to
control
emissions.
We
generally
consider
replacing
or
repairing
other
components
to
be
the
owner's
responsibility.
(
d)
Scheduled
maintenance.
You
may
schedule
emission
related
maintenance
for
a
component
named
in
paragraph
(
c)
of
this
section,
subject
to
the
restrictions
of
§
1048.125.
You
are
not
required
to
cover
this
scheduled
maintenance
under
your
warranty
if
the
component
meets
either
of
the
following
criteria:
(
1)
The
component
was
in
general
use
on
similar
engines,
and
was
subject
to
scheduled
maintenance,
before
January
1,
2000.
(
2)
Failure
of
the
component
would
clearly
degrade
the
engine's
performance
enough
that
the
operator
would
need
to
repair
or
replace
it.
(
e)
Limited
applicability.
You
may
deny
warranty
claims
under
this
section
if
the
operator
caused
the
problem,
as
described
in
40
CFR
1068.115.
(
f)
Aftermarket
parts.
As
noted
40
CFR
1068.101,
it
is
a
violation
of
the
Act
to
manufacture
an
engine
part
if
one
of
its
main
effects
is
to
reduce
the
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217
/
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November
8,
2002
/
Rules
and
Regulations
effectiveness
of
the
engine's
emission
controls.
If
you
make
an
aftermarket
part,
you
may
but
do
not
have
to
certify
that
using
the
part
will
still
allow
engines
to
meet
emission
standards,
as
described
in
40
CFR
85.2114.
§
1048.125
What
maintenance
instructions
must
I
give
to
buyers?
Give
the
ultimate
buyer
of
each
new
nonroad
engine
written
instructions
for
properly
maintaining
and
using
the
engine,
including
the
emission
control
system.
The
maintenance
instructions
also
apply
to
service
accumulation
on
your
test
engines,
as
described
in
40
CFR
part
1065,
subpart
E.
(
a)
Critical
emission
related
maintenance.
Critical
emission
related
maintenance
includes
any
adjustment,
cleaning,
repair,
or
replacement
of
airinduction
fuel
system,
or
ignition
components,
aftertreatment
devices,
exhaust
gas
recirculation
systems,
crankcase
ventilation
valves,
sensors,
or
electronic
control
units.
This
may
also
include
any
other
component
whose
only
purpose
is
to
reduce
emissions
or
whose
failure
will
increase
emissions
without
significantly
degrading
engine
performance.
You
may
schedule
critical
emission
related
maintenance
on
these
components
if
you
meet
the
following
conditions:
(
1)
You
may
ask
us
to
approve
critical
emission
related
maintenance
only
if
it
meets
two
criteria:
(
i)
Operators
are
reasonably
likely
to
do
the
maintenance
you
call
for.
(
ii)
Engines
need
the
maintenance
to
meet
emission
standards.
(
2)
We
will
accept
scheduled
maintenance
as
reasonably
likely
to
occur
in
use
if
you
satisfy
any
of
four
conditions:
(
i)
You
present
data
showing
that,
if
a
lack
of
maintenance
increases
emissions,
it
also
unacceptably
degrades
the
engine's
performance.
(
ii)
You
present
survey
data
showing
that
80
percent
of
engines
in
the
field
get
the
maintenance
you
specify
at
the
recommended
intervals.
(
iii)
You
provide
the
maintenance
free
of
charge
and
clearly
say
so
in
maintenance
instructions
for
the
customer.
(
iv)
You
otherwise
show
us
that
the
maintenance
is
reasonably
likely
to
be
done
at
the
recommended
intervals.
(
3)
You
may
not
schedule
critical
emission
related
maintenance
more
frequently
than
the
following
intervals,
except
as
specified
in
paragraph
(
a)(
4)
of
this
section:
(
i)
For
catalysts,
fuel
injectors,
electronic
control
units,
superchargers,
and
turbochargers:
the
useful
life
of
the
engine
family.
(
ii)
For
gaseous
fuel
system
components
(
cleaning
without
disassembly
only)
and
oxygen
sensors:
2,500
hours.
(
4)
If
your
engine
family
has
an
alternate
useful
life
shorter
than
the
period
specified
in
paragraph
(
a)(
3)(
ii)
of
this
section,
you
may
not
schedule
maintenance
on
those
components
more
frequently
than
the
alternate
useful
life
(
see
§
1048.101(
g)).
(
b)
Recommended
additional
maintenance.
You
may
recommend
any
additional
amount
of
maintenance
on
the
components
listed
in
paragraph
(
a)
of
this
section,
as
long
as
you
make
clear
that
these
maintenance
steps
are
not
necessary
to
keep
the
emission
related
warranty
valid.
If
operators
do
the
maintenance
specified
in
paragraph
(
a)
of
this
section,
but
not
the
recommended
additional
maintenance,
this
does
not
allow
you
to
disqualify
them
from
in
use
testing
or
deny
a
warranty
claim.
(
c)
Special
maintenance.
You
may
specify
more
frequent
maintenance
to
address
problems
related
to
special
situations
such
as
substandard
fuel
or
atypical
engine
operation.
For
example,
you
may
specify
more
frequent
cleaning
of
fuel
system
components
for
engines
you
have
reason
to
believe
will
be
using
fuel
that
causes
substantially
more
engine
performance
problems
than
commercial
fuels
of
the
same
type
that
are
generally
available
across
the
United
States.
(
d)
Noncritical
emission
related
maintenance.
For
engine
parts
not
listed
in
paragraph
(
a)
of
this
section,
you
may
schedule
any
amount
of
emissionrelated
inspection
or
maintenance.
But
you
must
state
clearly
that
these
steps
are
not
necessary
to
keep
the
emissionrelated
warranty
valid.
Also,
do
not
take
these
inspection
or
maintenance
steps
during
service
accumulation
on
your
test
engines.
(
e)
Maintenance
that
is
not
emissionrelated
For
maintenance
unrelated
to
emission
controls,
you
may
schedule
any
amount
of
inspection
or
maintenance.
You
may
also
take
these
inspection
or
maintenance
steps
during
service
accumulation
on
your
test
vehicles
or
engines.
This
might
include
adding
engine
oil
or
changing
air,
fuel,
or
oil
filters.
(
f)
Source
of
parts
and
repairs.
Print
clearly
on
the
first
page
of
your
written
maintenance
instructions
that
any
repair
shop
or
person
may
maintain,
replace,
or
repair
emission
control
devices
and
systems.
Your
instructions
may
not
require
components
or
service
identified
by
brand,
trade,
or
corporate
name.
Also,
do
not
directly
or
indirectly
condition
your
warranty
on
a
requirement
that
the
vehicle
be
serviced
by
your
franchised
dealers
or
any
other
service
establishments
with
which
you
have
a
commercial
relationship.
You
may
disregard
the
requirements
in
this
paragraph
(
f)
if
you
do
one
of
two
things:
(
1)
Provide
a
component
or
service
without
charge
under
the
purchase
agreement.
(
2)
Get
us
to
waive
this
prohibition
in
the
public's
interest
by
convincing
us
the
engine
will
work
properly
only
with
the
identified
component
or
service.
§
1048.130
What
installation
instructions
must
I
give
to
equipment
manufacturers?
(
a)
If
you
sell
an
engine
for
someone
else
to
install
in
a
piece
of
nonroad
equipment,
give
the
buyer
of
the
engine
written
instructions
for
installing
it
consistent
with
the
requirements
of
this
part.
Include
all
information
necessary
to
ensure
that
engines
installed
this
way
will
meet
emission
standards.
(
b)
Make
sure
these
instructions
have
the
following
information:
(
1)
Include
the
heading:
``
Emissionrelated
installation
instructions''.
(
2)
State:
``
Failing
to
follow
these
instructions
when
installing
a
certified
engine
in
a
piece
of
nonroad
equipment
violates
federal
law
(
40
CFR
1068.105(
b)),
subject
to
fines
or
other
penalties
as
described
in
the
Clean
Air
Act.''.
(
3)
Describe
any
other
instructions
needed
to
install
an
exhaust
aftertreatment
device
and
to
locate
exhaust
sampling
ports
consistent
with
your
application
for
certification.
(
4)
Describe
the
steps
needed
to
control
evaporative
emissions,
as
described
in
§
§
1048.105
and
1048.245.
(
5)
Describe
any
necessary
steps
for
installing
the
diagnostic
system
described
in
§
1048.110.
(
6)
Describe
any
limits
on
the
range
of
applications
needed
to
ensure
that
the
engine
operates
consistently
with
your
application
for
certification.
For
example,
if
your
engines
are
certified
only
for
constant
speed
operation,
tell
equipment
manufacturers
not
to
install
the
engines
in
variable
speed
applications.
Also,
if
you
need
to
avoid
sustained
high
load
operation
to
meet
the
field
testing
emission
standards
we
specify
in
§
1048.101(
c)
or
to
comply
with
the
provisions
of
§
1048.101(
d),
describe
how
the
equipment
manufacturer
must
properly
size
the
engines
for
a
given
application.
(
7)
Describe
any
other
instructions
to
make
sure
the
installed
engine
will
operate
according
to
design
specifications
in
your
application
for
certification.
(
8)
State:
``
If
you
install
the
engine
in
a
way
that
makes
the
engine's
emission
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/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
control
information
label
hard
to
read
during
normal
engine
maintenance,
you
must
place
a
duplicate
label
on
the
vehicle,
as
described
in
40
CFR
1068.105.''.
(
c)
You
do
not
need
installation
instructions
for
engines
you
install
in
your
own
equipment.
§
1048.135
How
must
I
label
and
identify
the
engines
I
produce?
(
a)
Assign
each
production
engine
a
unique
identification
number
and
permanently
and
legibly
affix,
engrave,
or
stamp
it
on
the
engine.
(
b)
At
the
time
of
manufacture,
add
a
permanent
emission
control
information
label
identifying
each
engine.
To
meet
labeling
requirements,
do
four
things:
(
1)
Attach
the
label
in
one
piece
so
it
is
not
removable
without
being
destroyed
or
defaced.
(
2)
Design
and
produce
it
to
be
durable
and
readable
for
the
engine's
entire
life.
(
3)
Secure
it
to
a
part
of
the
engine
needed
for
normal
operation
and
not
normally
requiring
replacement.
(
4)
Write
it
in
block
letters
in
English.
(
c)
On
your
engine's
emission
control
information
label,
do
13
things:
(
1)
Include
the
heading
``
EMISSION
CONTROL
INFORMATION''.
(
2)
Include
your
full
corporate
name
and
trademark.
(
3)
State:
``
THIS
ENGINE
IS
CERTIFIED
TO
OPERATE
ON
[
specify
operating
fuel
or
fuels].''.
(
4)
Identify
the
emission
control
system;
your
identifiers
must
use
names
and
abbreviations
consistent
with
SAE
J1930
(
incorporated
by
reference
in
§
1048.810).
(
5)
List
all
requirements
for
fuel
and
lubricants.
(
6)
State
the
date
of
manufacture
(
DAY
(
optional),
MONTH,
and
YEAR);
if
you
stamp
this
information
on
the
engine
and
print
it
in
the
owner's
manual,
you
may
omit
it
from
the
emission
control
information
label.
(
7)
State:
``
THIS
ENGINE
MEETS
U.
S.
ENVIRONMENTAL
PROTECTION
AGENCY
REGULATIONS
FOR
(
MODEL
YEAR)
LARGE
NONROAD
SI
ENGINES.''.
(
8)
Include
EPA's
standardized
designation
for
the
engine
family
(
and
subfamily,
where
applicable).
(
9)
State
the
engine's
displacement
(
in
liters)
and
maximum
brake
power.
(
10)
State
the
engine's
useful
life
(
see
§
1048.101(
g)).
(
11)
List
specifications
and
adjustments
for
engine
tuneups;
show
the
proper
position
for
the
transmission
during
tuneup
and
state
which
accessories
should
be
operating.
(
12)
Describe
other
information
on
proper
maintenance
and
use.
(
13)
Identify
the
emission
standards
to
which
you
have
certified
the
engine.
(
d)
Some
of
your
engines
may
need
more
information
on
the
emission
control
information
label.
(
1)
If
you
have
an
engine
family
that
has
been
certified
only
for
constantspeed
engines,
add
to
the
engine
label
``
CONSTANT
SPEED
ONLY''.
(
2)
If
you
have
an
engine
family
that
has
been
certified
only
for
variablespeed
engines,
add
to
the
engine
label
``
VARIABLE
SPEED
ONLY''.
(
3)
If
you
have
an
engine
family
that
has
been
certified
only
for
high
load
engines,
add
to
the
engine
label
``
THIS
ENGINE
IS
NOT
INTENDED
FOR
OPERATION
AT
LESS
THAN
75
PERCENT
OF
FULL
LOAD.''.
(
4)
If
you
certify
an
engine
to
the
voluntary
standards
in
§
1048.140,
add
to
the
engine
label
``
BLUE
SKY
SERIES''.
(
5)
If
you
produce
an
engine
we
exempt
from
the
requirements
of
this
part,
see
subpart
G
of
this
part
and
40
CFR
part
1068,
subparts
C
and
D,
for
more
label
information.
(
6)
If
you
certify
an
engine
family
under
§
1048.101(
d)
(
and
show
in
your
application
for
certification
that
in
use
engines
will
experience
infrequent
highload
operation),
add
to
the
engine
label
``
THIS
ENGINE
IS
NOT
INTENDED
FOR
OPERATION
AT
MORE
THAN
l
PERCENT
OF
FULL
LOAD.''.
Specify
the
appropriate
percentage
of
full
load
based
on
the
nature
of
the
engine
protection.
You
may
add
other
statements
to
discourage
operation
in
engine
protection
modes.
(
e)
Some
engines
may
not
have
enough
space
for
an
emission
control
information
label
with
all
the
required
information.
In
this
case,
you
may
omit
the
information
required
in
paragraphs
(
c)(
3),
(
c)(
4),
(
c)(
5),
and
(
c)(
12)
of
this
section
if
you
print
it
in
the
owner's
manual
instead.
(
f)
If
you
are
unable
to
meet
these
labeling
requirements,
you
may
ask
us
to
modify
them
consistent
with
the
intent
of
this
section.
§
1048.140
What
are
the
provisions
for
certifying
Blue
Sky
Series
engines?
This
section
defines
voluntary
standards
for
a
recognized
level
of
superior
emission
control
for
engines
designated
as
``
Blue
Sky
Series''
engines.
Blue
Sky
Series
engines
must
meet
one
of
the
following
standards:
(
a)
For
the
2003
model
year,
to
receive
a
certificate
of
conformity,
a
``
Blue
Sky
Series''
engine
family
must
meet
all
the
requirements
in
this
part
that
apply
to
2004
model
year
engines.
This
includes
all
testing
and
reporting
requirements.
(
b)
For
the
2003
through
2006
model
years,
to
receive
a
certificate
of
conformity,
a
``
Blue
Sky
Series''
engine
family
must
meet
all
the
requirements
in
this
part
that
apply
to
2007
model
year
engines.
This
includes
all
testing
and
reporting
requirements.
(
c)
For
any
model
year,
to
receive
a
certificate
of
conformity
as
a
``
Blue
Sky
Series''
engine
family
must
meet
all
the
requirements
in
this
part,
while
certifying
to
the
following
exhaust
emission
standards:
(
1)
0.8
g/
kW
hr
HC+
NOX
and
4.4
g/
kW
hr
CO
using
steady
state
and
transient
test
procedures,
as
described
in
subpart
F
of
this
part.
(
2)
1.1
g/
kW
hr
HC+
NOX
and
6.6
g/
kW
hr
CO
using
field
testing
procedures,
as
described
in
subpart
F
of
this
part.
(
d)
If
you
certify
an
engine
family
under
this
section,
it
is
subject
to
all
the
requirements
of
this
part
as
if
these
voluntary
standards
were
mandatory.
§
1048.145
What
provisions
apply
only
for
a
limited
time?
The
provisions
in
this
section
apply
instead
of
other
provisions
in
this
part.
This
section
describes
when
these
interim
provisions
expire.
(
a)
Family
banking.
You
may
certify
an
engine
family
to
comply
with
Tier
1
or
Tier
2
standards
earlier
than
necessary.
For
each
model
year
of
early
compliance
for
an
engine
family,
you
may
delay
compliance
with
the
same
standards
for
an
equal
number
of
engines
from
another
engine
family
(
or
families)
for
one
model
year.
If
you
certify
engines
under
the
voluntary
standards
of
§
1048.140,
you
may
not
use
them
in
your
calculation
under
this
paragraph
(
a).
Base
your
calculation
on
actual
power
weighted
nationwide
sales
for
each
family.
You
may
delay
compliance
for
up
to
three
model
years.
For
example,
if
you
sell
1,000
engines
with
an
average
power
rating
of
60
kW
certified
a
year
early,
you
may
delay
certification
to
that
tier
of
standards
for
up
to
60,000
kW
engine
years
in
any
of
the
following
ways:
(
1)
Delay
certification
of
another
engine
family
with
an
average
power
rating
of
100
kW
of
up
to
600
engines
for
one
model
year.
(
2)
Delay
certification
of
another
engine
family
with
an
average
power
rating
of
100
kW
of
up
to
200
engines
for
three
model
years.
(
3)
Delay
certification
of
one
engine
family
with
an
average
power
rating
of
100
kW
of
up
to
400
engines
for
one
model
year
and
a
second
engine
family
with
an
average
power
rating
of
200
kW
of
up
to
50
engines
for
two
model
years.
(
b)
Hydrocarbon
standards.
For
2004
through
2006
model
years,
engine
manufacturers
may
use
nonmethane
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hydrocarbon
measurements
to
demonstrate
compliance
with
applicable
emission
standards.
(
c)
Transient
emission
testing.
Engines
rated
over
560
kW
are
exempt
from
the
transient
emission
standards
in
§
1048.101(
a).
(
d)
Tier
1
deterioration
factors.
For
Tier
1
engines,
base
the
deterioration
factor
from
§
1048.240
on
3500
hours
of
operation.
We
may
assign
a
deterioration
factor
for
a
Tier
1
engine
family,
but
this
would
not
affect
your
need
to
meet
all
emission
standards
that
apply.
(
e)
[
Reserved]
(
f)
Optional
early
field
testing.
You
may
optionally
use
the
field
testing
procedures
in
subpart
F
of
this
part
for
any
in
use
testing
required
under
subpart
E
of
this
part
to
show
that
you
meet
Tier
1
standards.
In
this
case,
the
same
Tier
1
in
use
emission
standards
apply
to
both
steady
state
testing
in
the
laboratory
and
field
testing.
(
g)
Small
volume
provisions.
If
you
qualify
for
the
hardship
provisions
in
§
1068.250
of
this
chapter,
we
may
approve
extensions
of
up
to
four
years
total.
(
h)
2004
certification.
For
the
2004
model
year,
you
may
choose
to
have
the
emission
standards
and
other
requirements
that
apply
to
these
engines
in
California
serve
as
the
emission
standards
and
other
requirements
applicable
under
this
part,
instead
of
those
in
subpart
A
of
this
part.
To
ask
for
a
certificate
under
this
paragraph
(
h),
send
us
the
application
for
certification
that
you
prepare
for
the
California
Air
Resources
Board
instead
of
the
information
we
otherwise
require
in
§
1048.205.
(
i)
Recreational
vehicles.
Engines
or
vehicles
identified
in
the
scope
of
40
CFR
part
1051
that
are
not
yet
regulated
under
that
part
are
excluded
from
the
requirements
of
this
part.
For
example,
snowmobiles
produced
in
2004
are
not
subject
to
the
emission
standards
in
this
part.
Once
emission
standards
apply
to
these
engines
and
vehicles,
they
are
excluded
from
the
requirements
of
this
part
under
§
1048.5(
a)(
1).
Subpart
C
Certifying
Engine
Families
§
1048.201
What
are
the
general
requirements
for
submitting
a
certification
application?
(
a)
Send
us
an
application
for
a
certificate
of
conformity
for
each
engine
family.
Each
application
is
valid
for
only
one
model
year.
(
b)
The
application
must
not
include
false
or
incomplete
statements
or
information
(
see
§
1048.255).
(
c)
We
may
choose
to
ask
you
to
send
us
less
information
than
we
specify
in
this
subpart,
but
this
would
not
change
your
recordkeeping
requirements.
(
d)
Use
good
engineering
judgment
for
all
decisions
related
to
your
application
(
see
40
CFR
1068.5).
(
e)
An
authorized
representative
of
your
company
must
approve
and
sign
the
application.
§
1048.205
What
must
I
include
in
my
application?
In
your
application,
do
all
the
following
things
unless
we
ask
you
to
send
us
less
information:
(
a)
Describe
the
engine
family's
specifications
and
other
basic
parameters
of
the
engine's
design.
List
the
types
of
fuel
you
intend
to
use
to
certify
the
engine
family
(
for
example,
gasoline,
liquefied
petroleum
gas,
methanol,
or
natural
gas).
(
b)
Explain
how
the
emission
control
systems
operate.
(
1)
Describe
in
detail
all
the
system
components
for
controlling
exhaust
emissions,
including
auxiliary
emissioncontrol
devices
and
all
fuel
system
components
you
will
install
on
any
production
or
test
engine.
Explain
why
any
auxiliary
emission
control
devices
are
not
defeat
devices
(
see
§
1048.115(
g)).
Do
not
include
detailed
calibrations
for
components
unless
we
ask
for
them.
(
2)
Describe
the
evaporative
emission
controls.
(
c)
Explain
how
the
engine
diagnostic
system
works,
describing
especially
the
engine
conditions
(
with
the
corresponding
diagnostic
trouble
codes)
that
cause
the
malfunction
indicator
light
to
go
on.
Propose
what
you
consider
to
be
extreme
conditions
under
which
the
diagnostic
system
should
disregard
trouble
codes,
as
described
in
§
1048.110.
(
d)
Describe
the
engines
you
selected
for
testing
and
the
reasons
for
selecting
them.
(
e)
Describe
any
special
or
alternate
test
procedures
you
used
(
see
§
1048.501).
(
f)
Describe
how
you
operated
the
engine
or
vehicle
prior
to
testing,
including
the
duty
cycle
and
the
number
of
engine
operating
hours
used
to
stabilize
emission
levels.
Describe
any
scheduled
maintenance
you
did.
(
g)
List
the
specifications
of
the
test
fuel
to
show
that
it
falls
within
the
required
ranges
we
specify
in
40
CFR
part
1065,
subpart
C.
(
h)
Identify
the
engine
family's
useful
life.
(
i)
Propose
maintenance
and
use
instructions
for
the
ultimate
buyer
of
each
new
nonroad
engine
(
see
§
1048.125).
(
j)
Propose
emission
related
installation
instructions
if
you
sell
engines
for
someone
else
to
install
in
a
piece
of
nonroad
equipment
(
see
§
1048.130).
(
k)
Identify
each
high
cost
warranted
part
and
show
us
how
you
calculated
its
replacement
cost,
including
the
estimated
retail
cost
of
the
part,
labor
rates,
and
labor
hours
to
diagnose
and
replace
defective
parts.
(
l)
Propose
an
emission
control
information
label.
(
m)
Present
emission
data
to
show
that
you
meet
emission
standards.
(
1)
Present
exhaust
emission
data
for
HC,
NOX,
and
CO
on
a
test
engine
to
show
your
engines
meet
the
duty
cycle
emission
standards
we
specify
in
§
1048.101(
a)
and
(
b).
Show
these
figures
before
and
after
applying
deterioration
factors
for
each
engine.
Starting
in
the
2007
model
year,
identify
the
duty
cycle
emission
standards
to
which
you
are
certifying
engines
in
the
engine
family.
Include
test
data
for
each
type
of
fuel
from
40
CFR
part
1065,
subpart
C,
on
which
you
intend
for
engines
in
the
engine
family
to
operate
(
for
example,
gasoline,
liquefied
petroleum
gas,
methanol,
or
natural
gas).
If
we
specify
more
than
one
grade
of
any
fuel
type
(
for
example,
a
summer
grade
and
winter
grade
of
gasoline),
you
only
need
to
submit
test
data
for
one
grade,
unless
the
regulations
of
this
part
specify
otherwise
for
your
engine.
Note
that
§
1048.235
allows
you
to
submit
an
application
in
certain
cases
without
new
emission
data.
(
2)
If
your
engine
family
includes
a
volatile
liquid
fuel
(
and
you
do
not
use
design
based
certification
under
§
1048.245)
present
evaporative
test
data
to
show
your
vehicles
meet
the
evaporative
emission
standards
we
specify
in
subpart
B
of
this
part.
Show
these
figures
before
and
after
applying
deterioration
factors,
where
applicable.
(
n)
Report
all
test
results,
including
those
from
invalid
tests
or
from
any
nonstandard
tests
(
such
as
measurements
based
on
exhaust
concentrations
in
parts
per
million).
(
o)
Identify
the
engine
family's
deterioration
factors
and
describe
how
you
developed
them.
Present
any
emission
test
data
you
used
for
this.
(
p)
Describe
all
adjustable
operating
parameters
(
see
§
1048.115(
e)),
including
the
following:
(
1)
The
nominal
or
recommended
setting.
(
2)
The
intended
physically
adjustable
range,
including
production
tolerances
if
they
affect
the
range.
(
3)
The
limits
or
stops
used
to
establish
adjustable
ranges.
(
q)
Describe
everything
we
need
to
read
and
interpret
all
the
information
broadcast
by
an
engine's
onboard
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computers
and
electronic
control
modules
and
state
that
you
will
give
us
any
hardware
or
tools
we
would
need
to
do
this.
You
may
reference
any
appropriate
publicly
released
standards
that
define
conventions
for
these
messages
and
parameters.
Format
your
information
consistent
with
publicly
released
standards.
(
r)
State
whether
your
engine
will
operate
in
variable
speed
applications,
constant
speed
applications,
or
both.
If
your
certification
covers
only
constantspeed
or
only
variable
speed
applications,
describe
how
you
will
prevent
use
of
these
engines
in
the
applications
for
which
they
are
not
certified.
(
s)
Starting
in
the
2007
model
year,
state
that
all
the
engines
in
the
engine
family
comply
with
the
field
testing
emission
standards
we
specify
in
§
1048.101(
c)
for
all
normal
operation
and
use
(
see
§
1048.515).
Describe
in
detail
any
testing,
engineering
analysis,
or
other
information
on
which
you
base
this
statement.
(
t)
State
that
you
operated
your
test
engines
according
to
the
specified
procedures
and
test
parameters
using
the
fuels
described
in
the
application
to
show
you
meet
the
requirements
of
this
part.
(
u)
State
unconditionally
that
all
the
engines
in
the
engine
family
comply
with
the
requirements
of
this
part,
other
referenced
parts,
and
the
Clean
Air
Act.
(
v)
Include
estimates
of
U.
S.
directed
production
volumes.
(
w)
Show
us
how
to
modify
your
production
engines
to
measure
emissions
in
the
field
(
see
§
1048.115(
d)).
(
x)
Add
other
information
to
help
us
evaluate
your
application
if
we
ask
for
it.
§
1048.210
May
I
get
preliminary
approval
before
I
complete
my
application?
If
you
send
us
information
before
you
finish
the
application,
we
will
review
it
and
make
any
appropriate
determinations
listed
in
§
1048.215(
b)(
1)
through
(
7).
Decisions
made
under
this
section
are
considered
to
be
preliminary
approval.
We
will
generally
not
disapprove
applications
under
§
1048.215(
b)(
1)
through
(
5)
where
we
have
given
you
preliminary
approval,
unless
we
find
new
and
substantial
information
supporting
a
different
decision.
(
a)
If
you
request
preliminary
approval
related
to
the
upcoming
model
year
or
the
model
year
after
that,
we
will
make
a
``
best
efforts''
attempt
to
make
the
appropriate
determinations
as
soon
as
possible.
We
will
generally
not
provide
preliminary
approval
related
to
a
future
model
year
more
than
two
years
ahead
of
time.
(
b)
You
may
consider
full
compliance
with
published
guidance
to
be
preliminary
approval
only
if
the
guidance
includes
a
statement
that
we
intend
you
to
consider
it
as
such.
§
1048.215
What
happens
after
I
complete
my
application?
(
a)
If
any
of
the
information
in
your
application
changes
after
you
submit
it,
amend
it
as
described
in
§
1048.225.
(
b)
We
may
deny
your
application
(
that
is,
determine
that
we
cannot
approve
it
without
revision)
if
the
engine
family
does
not
meet
the
requirements
of
this
part
or
the
Act.
For
example:
(
1)
If
you
inappropriately
use
the
provisions
of
§
1048.230(
c)
or
(
d)
to
define
a
broader
or
narrower
engine
family,
we
will
require
you
to
redefine
your
engine
family.
(
2)
If
we
determine
you
did
not
appropriately
select
the
useful
life
under
§
1048.101(
g),
we
will
require
you
to
lengthen
it.
(
3)
If
we
determine
you
did
not
appropriately
select
deterioration
factors
under
§
1048.240(
c),
we
will
require
you
to
revise
them.
(
4)
If
your
diagnostic
system
is
inadequate
for
detecting
significant
malfunctions
in
emission
control
systems,
as
described
in
§
1048.110(
b),
we
will
require
you
to
make
the
system
more
effective.
(
5)
If
your
diagnostic
system
inappropriately
disregards
trouble
codes
under
certain
conditions,
as
described
in
§
1048.110(
f),
we
will
require
you
to
change
the
system
to
operate
under
broader
conditions.
(
6)
If
your
proposed
emission
control
information
label
is
inconsistent
with
§
1048.135,
we
will
require
you
to
change
it
(
and
tell
you
how,
if
possible).
(
7)
If
you
require
or
recommend
maintenance
and
use
instructions
inconsistent
with
§
1048.125,
we
will
require
you
to
change
them.
(
8)
If
we
find
any
other
problem
with
your
application,
we
will
tell
you
what
the
problem
is
and
what
needs
to
be
corrected.
(
c)
If
we
determine
your
application
is
complete
and
shows
that
the
engine
family
meets
all
the
requirements
of
this
part
and
the
Act,
we
will
issue
a
certificate
of
conformity
for
your
engine
family
for
that
model
year.
If
we
deny
the
application,
we
will
explain
why
in
writing.
You
may
then
ask
us
to
hold
a
hearing
to
reconsider
our
decision
(
see
§
1048.820).
§
1048.220
How
do
I
amend
the
maintenance
instructions
in
my
application?
Send
the
Designated
Officer
a
request
to
amend
your
application
for
certification
for
an
engine
family
if
you
want
to
change
the
emission
related
maintenance
instructions
in
a
way
that
could
affect
emissions.
In
your
request,
describe
the
proposed
changes
to
the
maintenance
instructions.
(
a)
If
you
are
decreasing
the
specified
level
of
maintenance,
you
may
distribute
the
new
maintenance
instructions
to
your
customers
30
days
after
we
receive
your
request,
unless
we
disapprove
your
request.
We
may
approve
a
shorter
time
or
waive
this
requirement.
(
b)
If
your
requested
change
would
not
decrease
the
specified
level
of
maintenance,
you
may
distribute
the
new
maintenance
instructions
anytime
after
you
send
your
request.
(
c)
If
you
are
correcting
or
clarifying
your
maintenance
instructions
or
if
you
are
changing
instructions
for
maintenance
unrelated
to
emission
controls,
the
requirements
of
this
section
do
not
apply.
§
1048.225
How
do
I
amend
my
application
to
include
new
or
modified
engines?
(
a)
You
must
amend
your
application
for
certification
before
you
take
either
of
the
following
actions:
(
1)
Add
an
engine
to
a
certificate
of
conformity
(
this
includes
any
changes
you
make
in
selecting
emission
standards
under
§
1048.205(
m)(
1)).
(
2)
Make
a
design
change
for
a
certified
engine
family
that
may
affect
emissions
or
an
emission
related
part
over
the
engine's
lifetime.
(
b)
Send
the
Designated
Officer
a
request
to
amend
the
application
for
certification
for
an
engine
family.
In
your
request,
do
all
of
the
following:
(
1)
Describe
the
engine
model
or
configuration
you
are
adding
or
changing.
(
2)
Include
engineering
evaluations
or
reasons
why
the
original
test
engine
is
or
is
not
still
appropriate.
(
3)
If
the
original
test
engine
for
the
engine
family
is
not
appropriate
to
show
compliance
for
the
new
or
modified
nonroad
engine,
include
new
test
data
showing
that
the
new
or
modified
nonroad
engine
meets
the
requirements
of
this
part.
(
c)
You
may
start
producing
the
new
or
modified
nonroad
engine
anytime
after
you
send
us
your
request.
If
we
determine
that
the
affected
engines
do
not
meet
applicable
requirements,
we
will
require
you
to
cease
production
of
the
engines
and
to
recall
and
correct
the
engines
at
no
expense
to
the
owner.
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/
Friday,
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8,
2002
/
Rules
and
Regulations
you
choose
to
produce
engines
under
this
paragraph
(
c),
we
will
consider
that
to
be
consent
to
recall
all
engines
that
we
determine
do
not
meet
applicable
standards
or
other
requirements
and
to
remedy
the
nonconformity
at
no
expense
to
the
owner.
(
d)
You
must
give
us
test
data
within
30
days
if
we
ask
for
more
testing,
or
stop
producing
the
engine
if
you
cannot
do
this.
You
may
give
us
an
engineering
evaluation
instead
of
test
data
if
we
agree
that
you
can
address
our
questions
without
test
data.
(
e)
If
we
determine
that
the
certificate
of
conformity
would
not
cover
your
new
or
modified
nonroad
engine,
we
will
send
you
a
written
explanation
of
our
decision.
In
this
case,
you
may
no
longer
produce
these
engines,
though
you
may
ask
for
a
hearing
for
us
to
reconsider
our
decision
(
see
§
1048.820).
§
1048.230
How
do
I
select
engine
families?
(
a)
Divide
your
product
line
into
families
of
engines
that
you
expect
to
have
similar
emission
characteristics.
Your
engine
family
is
limited
to
a
single
model
year.
(
b)
Group
engines
in
the
same
engine
family
if
they
are
the
same
in
all
of
the
following
aspects:
(
1)
The
combustion
cycle.
(
2)
The
cooling
system
(
water
cooled
vs.
air
cooled).
(
3)
Configuration
of
the
fuel
system
(
for
example,
fuel
injection
vs.
carburetion).
(
4)
Method
of
air
aspiration.
(
5)
The
number,
location,
volume,
and
composition
of
catalytic
converters.
(
6)
The
number,
arrangement,
and
approximate
bore
diameter
of
cylinders.
(
7)
Evaporative
emission
controls.
(
c)
In
some
cases
you
may
subdivide
a
group
of
engines
that
is
identical
under
paragraph
(
b)
of
this
section
into
different
engine
families.
To
do
so,
you
must
show
you
expect
emission
characteristics
to
be
different
during
the
useful
life
or
that
any
of
the
following
engine
characteristics
are
different:
(
1)
Method
of
actuating
intake
and
exhaust
timing
(
poppet
valve,
reed
valve,
rotary
valve,
etc.).
(
2)
Location
or
size
of
intake
and
exhaust
valves
or
ports.
(
3)
Configuration
of
the
combustion
chamber.
(
4)
Cylinder
stroke.
(
5)
Exhaust
system.
(
6)
Type
of
fuel.
(
d)
If
your
engines
are
not
identical
with
respect
to
the
things
listed
in
paragraph
(
b)
of
this
section,
but
you
show
that
their
emission
characteristics
during
the
useful
life
will
be
similar,
we
may
approve
grouping
them
in
the
same
engine
family.
(
e)
If
you
cannot
appropriately
define
engine
families
by
the
method
in
this
section,
we
will
define
them
based
on
features
related
to
emission
characteristics.
(
f)
You
may
ask
us
to
create
separate
families
for
exhaust
emissions
and
evaporative
emissions.
If
we
do
this,
list
both
families
on
the
emission
control
information
label.
(
g)
Where
necessary,
you
may
divide
an
engine
family
into
sub
families
to
meet
different
emission
standards,
as
specified
in
§
1048.101(
a)(
2).
For
issues
related
to
compliance
and
prohibited
actions,
we
will
generally
apply
decisions
to
the
whole
engine
family.
For
engine
labels
and
other
administrative
provisions,
we
may
approve
your
request
for
separate
treatment
of
sub
families.
§
1048.235
What
emission
testing
must
I
perform
for
my
application
for
a
certificate
of
conformity?
This
section
describes
the
emission
testing
you
must
perform
to
show
compliance
with
the
emission
standards
in
§
§
1048.101(
a)
and
(
b)
and
1048.105
during
certification.
See
§
1048.205(
s)
regarding
emission
testing
related
to
the
field
testing
emission
standards.
(
a)
Test
your
emission
data
engines
using
the
procedures
and
equipment
specified
in
subpart
F
of
this
part.
For
any
testing
related
to
evaporative
emissions,
use
good
engineering
judgment
to
include
a
complete
fuel
system
with
the
engine.
(
b)
Select
engine
families
according
to
the
following
criteria:
(
1)
For
exhaust
testing,
select
from
each
engine
family
a
test
engine
for
each
fuel
type
with
a
configuration
that
is
most
likely
to
exceed
the
exhaust
emission
standards,
using
good
engineering
judgment.
Consider
the
emission
levels
of
all
exhaust
constituents
over
the
full
useful
life
of
the
engine
when
operated
in
a
piece
of
equipment.
(
2)
For
evaporative
testing,
select
from
each
engine
family
a
test
fuel
system
for
each
fuel
type
with
a
configuration
that
is
most
likely
to
exceed
the
evaporative
emission
standards,
using
good
engineering
judgment.
(
c)
You
may
use
previously
generated
emission
data
in
either
of
the
following
cases:
(
1)
You
may
submit
emission
data
for
equivalent
engine
families
from
previous
years
instead
of
doing
new
tests,
but
only
if
the
data
show
that
the
test
engine
would
meet
all
the
requirements
for
the
latest
engine
models.
We
may
require
you
to
do
new
emission
testing
if
we
believe
the
latest
engine
models
could
be
substantially
different
from
the
previously
tested
engine.
(
2)
You
may
submit
emission
data
for
equivalent
engine
families
performed
to
show
compliance
with
other
standards
(
such
as
California
standards)
instead
of
doing
new
tests,
but
only
if
the
data
show
that
the
test
engine
would
meet
all
of
this
part's
requirements.
(
d)
We
may
choose
to
measure
emissions
from
any
of
your
test
engines
(
or
other
engines
from
the
engine
family).
(
1)
If
we
do
this,
you
must
provide
the
test
engine
at
the
location
we
select.
We
may
decide
to
do
the
testing
at
your
plant
or
any
other
facility.
If
we
choose
to
do
the
testing
at
your
plant,
you
must
schedule
it
as
soon
as
possible
and
make
available
the
instruments
and
equipment
we
need.
(
2)
If
we
measure
emissions
on
one
of
your
test
engines,
the
results
of
that
testing
become
the
official
data
for
the
engine.
Unless
we
later
invalidate
this
data,
we
may
decide
not
to
consider
your
data
in
determining
if
your
engine
family
meets
the
emission
standards.
(
3)
Before
we
test
one
of
your
engines,
we
may
set
its
adjustable
parameters
to
any
point
within
the
physically
adjustable
ranges
(
see
§
1048.115(
e)).
(
4)
Calibrate
the
test
engine
within
normal
production
tolerances
for
anything
we
do
not
consider
an
adjustable
parameter
(
see
§
1048.205(
p)).
§
1048.240
How
do
I
demonstrate
that
my
engine
family
complies
with
exhaust
emission
standards?
(
a)
For
certification,
your
engine
family
is
considered
in
compliance
with
the
numerical
emission
standards
in
§
1048.101
(
a)
and
(
b),
if
all
emissiondata
engines
representing
that
family
have
test
results
showing
emission
levels
at
or
below
these
standards.
(
b)
Your
engine
family
does
not
comply
if
any
emission
data
engine
representing
that
family
has
test
results
showing
emission
levels
above
the
standards
from
§
1048.101
(
a)
and
(
b)
for
any
pollutant.
(
c)
To
compare
emission
levels
from
the
test
engine
with
the
emission
standards,
apply
deterioration
factors
to
the
measured
emission
levels.
The
deterioration
factor
is
a
number
that
shows
the
relationship
between
exhaust
emissions
at
the
end
of
useful
life
and
at
the
low
hour
test
point.
Specify
the
deterioration
factors
based
on
emission
measurements
using
four
significant
figures,
consistent
with
good
engineering
judgment.
For
example,
deterioration
factors
must
be
consistent
with
emission
increases
observed
from
in
use
testing
with
similar
engines
(
see
subpart
E
of
this
part).
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Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
engine
manufacturers
may
use
assigned
deterioration
factors
that
we
establish.
Apply
the
deterioration
factors
as
follows:
(
1)
For
engines
that
use
aftertreatment
technology,
such
as
catalytic
converters,
the
deterioration
factor
is
the
ratio
of
exhaust
emissions
at
the
end
of
useful
life
to
exhaust
emissions
at
the
low
hour
test
point.
Adjust
the
official
emission
results
for
each
tested
engine
at
the
selected
test
point
by
multiplying
the
measured
emissions
by
the
deterioration
factor.
If
the
factor
is
less
than
one,
use
one.
(
2)
For
engines
that
do
not
use
aftertreatment
technology,
the
deterioration
factor
is
the
difference
between
exhaust
emissions
at
the
end
of
useful
life
and
exhaust
emissions
at
the
low
hour
test
point.
Adjust
the
official
emission
results
for
each
tested
engine
at
the
selected
test
point
by
adding
the
factor
to
the
measured
emissions.
If
the
factor
is
less
than
zero,
use
zero.
(
d)
After
adjusting
the
emission
levels
for
deterioration,
round
them
to
the
same
number
of
decimal
places
as
the
emission
standard.
Compare
the
rounded
emission
levels
to
the
emission
standard
for
each
test
engine.
§
1048.245
How
do
I
demonstrate
that
my
engine
family
complies
with
evaporative
emission
standards?
(
a)
For
certification,
your
engine
family
is
considered
in
compliance
with
the
evaporative
emission
standards
in
subpart
B
of
this
part
if
you
do
either
of
the
following:
(
1)
You
have
test
results
showing
that
evaporative
emissions
in
the
family
are
at
or
below
the
standards
throughout
the
useful
life.
(
2)
Where
applicable,
you
comply
with
the
design
specifications
in
paragraph
(
e)
of
this
section.
(
b)
Your
engine
family
does
not
comply
if
any
fuel
system
representing
that
family
has
test
results
showing
emission
levels
above
the
standards.
(
c)
Use
good
engineering
judgment
to
develop
a
test
plan
to
establish
deterioration
factors
to
show
how
much
emissions
increase
at
the
end
of
useful
life.
(
d)
If
you
adjust
the
emission
levels
for
deterioration,
round
them
to
the
same
number
of
decimal
places
as
the
emission
standard.
Compare
the
rounded
emission
levels
to
the
emission
standard
for
each
test
fuel
system.
(
e)
You
may
demonstrate
that
your
engine
family
complies
with
the
evaporative
emission
standards
by
demonstrating
that
you
use
the
following
control
technologies:
(
1)
For
certification
to
the
standards
specified
in
§
1048.105(
a)(
1),
with
the
following
technologies:
(
i)
Use
a
tethered
or
self
closing
gas
cap
on
a
fuel
tank
that
stays
sealed
up
to
a
positive
pressure
of
24.5
kPa
(
3.5
psig)
or
a
vacuum
pressure
of
10.5
kPa
(
1.5
psig).
(
ii)
[
Reserved]
(
2)
For
certification
to
the
standards
specified
in
§
1048.105(
a)(
3),
demonstrating
that
you
use
design
features
to
prevent
fuel
boiling
under
all
normal
operation.
You
may
do
this
using
fuel
temperature
data
measured
during
normal
operation.
(
3)
We
may
establish
additional
options
for
design
based
certification
where
we
find
that
new
test
data
demonstrate
that
a
technology
will
ensure
compliance
with
the
emission
standards
in
this
section.
§
1048.250
What
records
must
I
keep
and
make
available
to
EPA?
(
a)
Organize
and
maintain
the
following
records
to
keep
them
readily
available;
we
may
review
these
records
at
any
time:
(
1)
A
copy
of
all
applications
and
any
summary
information
you
sent
us.
(
2)
Any
of
the
information
we
specify
in
§
1048.205
that
you
did
not
include
in
your
application.
(
3)
A
detailed
history
of
each
emission
data
engine.
In
each
history,
describe
all
of
the
following:
(
i)
The
test
engine's
construction,
including
its
origin
and
buildup,
steps
you
took
to
ensure
that
it
represents
production
engines,
any
components
you
built
specially
for
it,
and
all
emission
related
components.
(
ii)
How
you
accumulated
engine
operating
hours,
including
the
dates
and
the
number
of
hours
accumulated.
(
iii)
All
maintenance
(
including
modifications,
parts
changes,
and
other
service)
and
the
dates
and
reasons
for
the
maintenance.
(
iv)
All
your
emission
tests,
including
documentation
on
routine
and
standard
tests,
as
specified
in
part
40
CFR
part
1065,
and
the
date
and
purpose
of
each
test.
(
v)
All
tests
to
diagnose
engine
or
emission
control
performance,
giving
the
date
and
time
of
each
and
the
reasons
for
the
test.
(
vi)
Any
other
significant
events.
(
b)
Keep
data
from
routine
emission
tests
(
such
as
test
cell
temperatures
and
relative
humidity
readings)
for
one
year
after
we
issue
the
associated
certificate
of
conformity.
Keep
all
other
information
specified
in
paragraph
(
a)
of
this
section
for
eight
years
after
we
issue
your
certificate.
(
c)
Store
these
records
in
any
format
and
on
any
media,
as
long
as
you
can
promptly
send
us
organized,
written
records
in
English
if
we
ask
for
them.
(
d)
Send
us
copies
of
any
engine
maintenance
instructions
or
explanations
if
we
ask
for
them.
§
1048.255
When
may
EPA
deny,
revoke,
or
void
my
certificate
of
conformity?
(
a)
We
may
deny
your
application
for
certification
if
your
engine
family
fails
to
comply
with
emission
standards
or
other
requirements
of
this
part
or
the
Act.
Our
decision
may
be
based
on
any
information
available
to
us
showing
you
do
not
meet
emission
standards
or
other
requirements,
including
any
testing
that
we
conduct
under
paragraph
(
f)
of
this
section.
If
we
deny
your
application,
we
will
explain
why
in
writing.
(
b)
In
addition,
we
may
deny
your
application
or
revoke
your
certificate
if
you
do
any
of
the
following:
(
1)
Refuse
to
comply
with
any
testing
or
reporting
requirements.
(
2)
Submit
false
or
incomplete
information
(
paragraph
(
d)
of
this
section
applies
if
this
is
fraudulent).
(
3)
Render
inaccurate
any
test
data.
(
4)
Deny
us
from
completing
authorized
activities
despite
our
presenting
a
warrant
or
court
order
(
see
40
CFR
1068.20).
(
5)
Produce
engines
for
importation
into
the
United
States
at
a
location
where
local
law
prohibits
us
from
carrying
out
authorized
activities.
(
c)
We
may
void
your
certificate
if
you
do
not
keep
the
records
we
require
or
do
not
give
us
information
when
we
ask
for
it.
(
d)
We
may
void
your
certificate
if
we
find
that
you
intentionally
submitted
false
or
incomplete
information.
(
e)
If
we
deny
your
application
or
revoke
or
void
your
certificate,
you
may
ask
for
a
hearing
(
see
§
1048.820).
Any
such
hearing
will
be
limited
to
substantial
and
factual
issues.
(
f)
We
may
conduct
confirmatory
testing
of
your
engines
as
part
of
certification.
We
may
deny
your
application
for
certification
or
revoke
your
certificate
if
your
engines
fail
to
comply
with
emission
standards
or
other
requirements
during
confirmatory
testing.
Subpart
D
Testing
Production
line
Engines
§
1048.301
When
must
I
test
my
production
line
engines?
(
a)
If
you
produce
engines
that
are
subject
the
requirements
of
this
part,
you
must
test
them
as
described
in
this
subpart.
(
b)
We
may
suspend
or
revoke
your
certificate
of
conformity
for
certain
engine
families
if
your
production
line
engines
do
not
meet
the
requirements
of
this
part
or
you
do
not
fulfill
your
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Rules
and
Regulations
obligations
under
this
subpart
(
see
§
§
1048.325
and
1048.340).
(
c)
Other
requirements
apply
to
engines
that
you
produce.
Other
regulatory
provisions
authorize
us
to
suspend,
revoke,
or
void
your
certificate
of
conformity,
or
order
recalls
for
engines
families
without
regard
to
whether
they
have
passed
these
production
line
testing
requirements.
The
requirements
of
this
part
do
not
affect
our
ability
to
do
selective
enforcement
audits,
as
described
in
part
1068
of
this
chapter.
Individual
engines
in
families
that
pass
these
productionline
testing
requirements
must
also
conform
to
all
applicable
regulations
of
this
part
and
part
1068
of
this
chapter.
(
d)
You
may
ask
to
use
an
alternate
program
for
testing
production
line
engines.
In
your
request,
you
must
show
us
that
the
alternate
program
gives
equal
assurance
that
your
production
line
engines
meet
the
requirements
of
this
part.
If
we
approve
your
alternate
program,
we
may
waive
some
or
all
of
this
subpart's
requirements.
(
e)
If
you
certify
an
engine
family
with
carryover
emission
data,
as
described
in
§
1048.235(
c),
and
these
equivalent
engine
families
consistently
pass
the
production
line
testing
requirements
over
the
preceding
two
year
period,
you
may
ask
for
a
reduced
testing
rate
for
further
production
line
testing
for
that
family.
The
minimum
testing
rate
is
one
engine
per
engine
family.
If
we
reduce
your
testing
rate,
we
may
limit
our
approval
to
any
number
of
model
years.
In
determining
whether
to
approve
your
request,
we
may
consider
the
number
of
engines
that
have
failed
the
emission
tests.
(
f)
We
may
ask
you
to
make
a
reasonable
number
of
production
line
engines
available
for
a
reasonable
time
so
we
can
test
or
inspect
them
for
compliance
with
the
requirements
of
this
part.
§
1048.305
How
must
I
prepare
and
test
my
production
line
engines?
(
a)
Test
procedures.
Test
your
production
line
engines
using
either
the
steady
state
or
transient
testing
procedures
in
subpart
F
of
this
part
to
show
you
meet
the
emission
standards
in
§
1048.101(
a)
or
(
b),
respectively.
We
may
require
you
to
test
engines
using
the
transient
testing
procedures
to
show
you
meet
the
emission
standards
in
§
1048.101(
a).
(
b)
Modifying
a
test
engine.
Once
an
engine
is
selected
for
testing
(
see
§
1048.310),
you
may
adjust,
repair,
prepare,
or
modify
it
or
check
its
emissions
only
if
one
of
the
following
is
true:
(
1)
You
document
the
need
for
doing
so
in
your
procedures
for
assembling
and
inspecting
all
your
production
engines
and
make
the
action
routine
for
all
the
engines
in
the
engine
family.
(
2)
This
subpart
otherwise
specifically
allows
your
action.
(
3)
We
approve
your
action
in
advance.
(
c)
Engine
malfunction.
If
an
engine
malfunction
prevents
further
emission
testing,
ask
us
to
approve
your
decision
to
either
repair
the
engine
or
delete
it
from
the
test
sequence.
(
d)
Setting
adjustable
parameters.
Before
any
test,
we
may
adjust
or
require
you
to
adjust
any
adjustable
parameter
to
any
setting
within
its
physically
adjustable
range.
(
1)
We
may
adjust
idle
speed
outside
the
physically
adjustable
range
as
needed
only
until
the
engine
has
stabilized
emission
levels
(
see
paragraph
(
e)
of
this
section).
We
may
ask
you
for
information
needed
to
establish
an
alternate
minimum
idle
speed.
(
2)
We
may
make
or
specify
adjustments
within
the
physically
adjustable
range
by
considering
their
effect
on
emission
levels,
as
well
as
how
likely
it
is
someone
will
make
such
an
adjustment
with
in
use
engines.
(
e)
Stabilizing
emission
levels.
Before
you
test
production
line
engines,
you
may
operate
the
engine
to
stabilize
the
emission
levels.
Using
good
engineering
judgment,
operate
your
engines
in
a
way
that
represents
the
way
production
engines
will
be
used.
You
may
operate
each
engine
for
no
more
than
the
greater
of
two
periods:
(
1)
50
hours.
(
2)
The
number
of
hours
you
operated
your
emission
data
engine
for
certifying
the
engine
family
(
see
40
CFR
part
1065,
subpart
E).
(
f)
Damage
during
shipment.
If
shipping
an
engine
to
a
remote
facility
for
production
line
testing
makes
necessary
an
adjustment
or
repair,
you
must
wait
until
after
the
after
the
initial
emission
test
to
do
this
work.
We
may
waive
this
requirement
if
the
test
would
be
impossible
or
unsafe,
or
if
it
would
permanently
damage
the
engine.
Report
to
us,
in
your
written
report
under
§
1048.345,
all
adjustments
or
repairs
you
make
on
test
engines
before
each
test.
(
g)
Retesting
after
invalid
tests.
You
may
retest
an
engine
if
you
determine
an
emission
test
is
invalid.
Explain
in
your
written
report
reasons
for
invalidating
any
test
and
the
emission
results
from
all
tests.
If
you
retest
an
engine
and,
within
ten
days
after
testing,
ask
to
substitute
results
of
the
new
tests
for
the
original
ones,
we
will
answer
within
ten
days
after
we
receive
your
information.
§
1048.310
How
must
I
select
engines
for
production
line
testing?
(
a)
Use
test
results
from
two
engines
for
each
engine
family
to
calculate
the
required
sample
size
for
the
model
year.
Update
this
calculation
with
each
test.
(
b)
Early
in
each
calendar
quarter,
randomly
select
and
test
two
engines
from
the
end
of
the
assembly
line
for
each
engine
family.
(
c)
Calculate
the
required
sample
size
for
each
engine
family.
Separately
calculate
this
figure
for
HC+
NOX
and
for
CO.
The
required
sample
size
is
the
greater
of
these
two
calculated
values.
Use
the
following
equation:
N
t
x
=
×
+
(
)
(
95
2
STD)
1
Where:
N
=
Required
sample
size
for
the
model
year.
t95
=
95%
confidence
coefficient,
which
depends
on
the
number
of
tests
completed,
n,
as
specified
in
the
table
in
paragraph
(
c)(
1)
of
this
section.
It
defines
95%
confidence
intervals
for
a
one
tail
distribution.
x
=
Mean
of
emission
test
results
of
the
sample.
STD
=
Emission
standard.
s
=
Test
sample
standard
deviation
(
see
paragraph
(
c)(
2)
of
this
section).
(
1)
Determine
the
95%
confidence
coefficient,
t95,
from
the
following
table:
n
t95
n
t95
n
t95
2
6.31
121.80
221.72
3
2.92
131.78
231.72
4
2.35
141.77
241.71
5
2.13
151.76
251.71
6
2.02
161.75
261.71
7
1.94
171.75
271.71
8
1.90
181.74
281.70
9
1.86
191.73
291.70
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/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
n
t95
n
t95
n
t95
10
1.83
201.73
30+
1.70
11
1.81
211.72
(
2)
Calculate
the
standard
deviation,
s,
for
the
test
sample
using
the
following
formula:
=
(
X
x)
n
i
2
1
Where:
Xi
=
Emission
test
result
for
an
individual
engine.
n
=
The
number
of
tests
completed
in
an
engine
family.
(
d)
Use
final
deteriorated
test
results
to
calculate
the
variables
in
the
equations
in
paragraph
(
c)
of
this
section
(
see
§
1048.315(
a)).
(
e)
After
each
new
test,
recalculate
the
required
sample
size
using
the
updated
mean
values,
standard
deviations,
and
the
appropriate
95
percent
confidence
coefficient.
(
f)
Distribute
the
remaining
engine
tests
evenly
throughout
the
rest
of
the
year.
You
may
need
to
adjust
your
schedule
for
selecting
engines
if
the
required
sample
size
changes.
Continue
to
randomly
select
engines
from
each
engine
family;
this
may
involve
testing
engines
that
operate
on
different
fuels.
(
g)
Continue
testing
any
engine
family
for
which
the
sample
mean,
x,
is
greater
than
the
emission
standard.
This
applies
if
the
sample
mean
for
either
HC+
NOX
or
for
CO
is
greater
than
the
emission
standard.
Continue
testing
until
one
of
the
following
things
happens:
(
1)
The
sample
size,
n,
for
an
engine
family
is
greater
than
the
required
sample
size,
N,
and
the
sample
mean,
x,
is
less
than
or
equal
to
the
emission
standard.
For
example,
if
N
=
3.1
after
the
third
test,
the
sample
size
calculation
does
not
allow
you
to
stop
testing.
(
2)
The
engine
family
does
not
comply
according
to
§
1048.325.
(
3)
You
test
30
engines
from
the
engine
family.
(
4)
You
test
one
percent
of
your
projected
annual
U.
S.
directed
production
volume
for
the
engine
family.
(
5)
You
choose
to
declare
that
the
engine
family
does
not
comply
with
the
requirements
of
this
subpart.
(
h)
If
the
sample
size
calculation
allows
you
to
stop
testing
for
a
pollutant,
you
must
continue
measuring
emission
levels
of
that
pollutant
for
any
additional
tests
required
under
this
section.
However,
you
need
not
continue
making
the
calculations
specified
in
this
section
for
that
pollutant.
This
paragraph
(
h)
does
not
affect
the
requirements
in
section
§
1048.320.
(
i)
You
may
elect
to
test
more
randomly
chosen
engines
than
we
require.
Include
these
engines
in
the
sample
size
calculations.
§
1048.315
How
do
I
know
when
my
engine
family
fails
the
production
line
testing
requirements?
This
section
describes
the
pass/
fail
criteria
for
the
production
line
testing
requirements.
We
apply
this
criteria
on
an
engine
family
basis.
See
§
1048.320
for
the
requirements
that
apply
to
individual
engines
that
fail
a
production
line
test.
(
a)
Calculate
your
test
results.
Round
them
to
the
number
of
decimal
places
in
the
emission
standard
expressed
to
one
more
decimal
place.
(
1)
Initial
and
final
test
results.
Calculate
and
round
the
test
results
for
each
engine.
If
you
do
several
tests
on
an
engine,
calculate
the
initial
test
results,
then
add
them
together
and
divide
by
the
number
of
tests
and
round
for
the
final
test
results
on
that
engine.
(
2)
Final
deteriorated
test
results.
Apply
the
deterioration
factor
for
the
engine
family
to
the
final
test
results
(
see
§
1048.240(
c)).
(
b)
Construct
the
following
CumSum
Equation
for
each
engine
family
(
for
HC+
NOX
and
for
CO
emissions):
C
X
(
STD
)
i
1
i
=
+
+
×
Ci
0
25
.
Where:
Ci
=
The
current
CumSum
statistic.
Ci
1
=
The
previous
CumSum
statistic.
For
the
first
test,
CumSum
statistic
is
0
(
i.
e.
C1
=
0).
Xi
=
The
current
emission
test
result
for
an
individual
engine.
STD
=
Emission
standard.
(
c)
Use
final
deteriorated
test
results
to
calculate
the
variables
in
the
equation
in
paragraph
(
b)
of
this
section
(
see
§
1048.315(
a)).
(
d)
After
each
new
test,
recalculate
the
CumSum
statistic.
(
e)
If
you
test
more
than
the
required
number
of
engines,
include
the
results
from
these
additional
tests
in
the
CumSum
Equation.
(
f)
After
each
test,
compare
the
current
CumSum
statistic,
Ci,
to
the
recalculated
Action
Limit,
H,
defined
as
H
=
5.0
×
s.
(
g)
If
the
CumSum
statistic
exceeds
the
Action
Limit
in
two
consecutive
tests,
the
engine
family
fails
the
production
line
testing
requirements
of
this
subpart.
Tell
us
within
ten
working
days
if
this
happens.
(
h)
If
you
amend
the
application
for
certification
for
an
engine
family
(
see
§
1048.225),
do
not
change
any
previous
calculations
of
sample
size
or
CumSum
statistics
for
the
model
year.
§
1048.320
What
happens
if
one
of
my
production
line
engines
fails
to
meet
emission
standards?
If
you
have
a
production
line
engine
with
final
deteriorated
test
results
exceeding
one
or
more
emission
standards
(
see
§
1048.315(
a)),
the
certificate
of
conformity
is
automatically
suspended
for
that
failing
engine.
You
must
take
the
following
actions
before
your
certificate
of
conformity
can
cover
that
engine:
(
a)
Correct
the
problem
and
retest
the
engine
to
show
it
complies
with
all
emission
standards.
(
b)
Include
in
your
written
report
a
description
of
the
test
results
and
the
remedy
for
each
engine
(
see
§
1048.345).
§
1048.325
What
happens
if
an
engine
family
fails
the
production
line
requirements?
(
a)
We
may
suspend
your
certificate
of
conformity
for
an
engine
family
if
it
fails
under
§
1048.315.
The
suspension
may
apply
to
all
facilities
producing
engines
from
an
engine
family,
even
if
you
find
noncompliant
engines
only
at
one
facility.
(
b)
We
will
tell
you
in
writing
if
we
suspend
your
certificate
in
whole
or
in
part.
We
will
not
suspend
a
certificate
until
at
least
15
days
after
the
engine
family
fails.
The
suspension
is
effective
when
you
receive
our
notice.
(
c)
Up
to
15
days
after
we
suspend
the
certificate
for
an
engine
family,
you
may
ask
for
a
hearing
(
see
§
1048.820).
If
we
agree
before
a
hearing
that
we
used
erroneous
information
in
deciding
to
suspend
the
certificate,
we
will
reinstate
the
certificate.
(
d)
Section
§
1048.335
specifies
steps
you
must
take
to
remedy
the
cause
of
the
production
line
failure.
All
the
engines
you
have
produced
since
the
end
of
the
last
test
period
are
presumed
noncompliant
and
should
be
addressed
in
your
proposed
remedy.
We
may
require
you
to
apply
the
remedy
to
engines
produced
earlier
if
we
determine
that
the
cause
of
the
failure
is
likely
to
have
affected
the
earlier
engines.
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68360
Federal
Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
§
1048.330
May
I
sell
engines
from
an
engine
family
with
a
suspended
certificate
of
conformity?
You
may
sell
engines
that
you
produce
after
we
suspend
the
engine
family's
certificate
of
conformity
under
§
1048.315
only
if
one
of
the
following
occurs:
(
a)
You
test
each
engine
you
produce
and
show
it
complies
with
emission
standards
that
apply.
(
b)
We
conditionally
reinstate
the
certificate
for
the
engine
family.
We
may
do
so
if
you
agree
to
recall
all
the
affected
engines
and
remedy
any
noncompliance
at
no
expense
to
the
owner
if
later
testing
shows
that
the
engine
family
still
does
not
comply.
§
1048.335
How
do
I
ask
EPA
to
reinstate
my
suspended
certificate?
(
a)
Send
us
a
written
report
asking
us
to
reinstate
your
suspended
certificate.
In
your
report,
identify
the
reason
for
noncompliance,
propose
a
remedy
for
the
engine
family,
and
commit
to
a
date
for
carrying
it
out.
In
your
proposed
remedy
include
any
quality
control
measures
you
propose
to
keep
the
problem
from
happening
again.
(
b)
Give
us
data
from
production
line
testing
that
shows
the
remedied
engine
family
complies
with
all
the
emission
standards
that
apply.
§
1048.340
When
may
EPA
revoke
my
certificate
under
this
subpart
and
how
may
I
sell
these
engines
again?
(
a)
We
may
revoke
your
certificate
for
an
engine
family
in
the
following
cases:
(
1)
You
do
not
meet
the
reporting
requirements.
(
2)
Your
engine
family
fails
to
comply
with
the
requirements
of
this
subpart
and
your
proposed
remedy
to
address
a
suspended
certificate
under
§
1048.325
is
inadequate
to
solve
the
problem
or
requires
you
to
change
the
engine's
design
or
emission
control
system.
(
b)
To
sell
engines
from
an
engine
family
with
a
revoked
certificate
of
conformity,
you
must
modify
the
engine
family
and
then
show
it
complies
with
the
requirements
of
this
part.
(
1)
If
we
determine
your
proposed
design
change
may
not
control
emissions
for
the
engine's
full
useful
life,
we
will
tell
you
within
five
working
days
after
receiving
your
report.
In
this
case
we
will
decide
whether
production
line
testing
will
be
enough
for
us
to
evaluate
the
change
or
whether
you
need
to
do
more
testing.
(
2)
Unless
we
require
more
testing,
you
may
show
compliance
by
testing
production
line
engines
as
described
in
this
subpart.
(
3)
We
will
issue
a
new
or
updated
certificate
of
conformity
when
you
have
met
these
requirements.
§
1048.345
What
production
line
testing
records
must
I
send
to
EPA?
Do
all
the
following
things
unless
we
ask
you
to
send
us
less
information:
(
a)
Within
30
calendar
days
of
the
end
of
each
calendar
quarter,
send
us
a
report
with
the
following
information:
(
1)
Describe
any
facility
used
to
test
production
line
engines
and
state
its
location.
(
2)
State
the
total
U.
S.
directed
production
volume
and
number
of
tests
for
each
engine
family.
(
3)
Describe
how
you
randomly
selected
engines.
(
4)
Describe
your
test
engines,
including
the
engine
family's
identification
and
the
engine's
model
year,
build
date,
model
number,
identification
number,
and
number
of
hours
of
operation
before
testing
for
each
test
engine.
(
5)
Identify
where
you
accumulated
hours
of
operation
on
the
engines
and
describe
the
procedure
and
schedule
you
used.
(
6)
Provide
the
test
number;
the
date,
time
and
duration
of
testing;
test
procedure;
initial
test
results
before
and
after
rounding;
final
test
results;
and
final
deteriorated
test
results
for
all
tests.
Provide
the
emission
results
for
all
measured
pollutants.
Include
information
for
both
valid
and
invalid
tests
and
the
reason
for
any
invalidation.
(
7)
Describe
completely
and
justify
any
nonroutine
adjustment,
modification,
repair,
preparation,
maintenance,
or
test
for
the
test
engine
if
you
did
not
report
it
separately
under
this
subpart.
Include
the
results
of
any
emission
measurements,
regardless
of
the
procedure
or
type
of
equipment.
(
8)
Provide
the
CumSum
analysis
required
in
§
1048.315
for
each
engine
family.
(
9)
Report
on
each
failed
engine
as
described
in
§
1048.320.
(
10)
State
the
date
the
calendar
quarter
ended
for
each
engine
family.
(
b)
We
may
ask
you
to
add
information
to
your
written
report,
so
we
can
determine
whether
your
new
nonroad
engines
conform
with
the
requirements
of
this
subpart.
(
c)
An
authorized
representative
of
your
company
must
sign
the
following
statement:
We
submit
this
report
under
Sections
208
and
213
of
the
Clean
Air
Act.
Our
production
line
testing
conformed
completely
with
the
requirements
of
40
CFR
part
1048.
We
have
not
changed
production
processes
or
quality
control
procedures
for
the
engine
family
in
a
way
that
might
affect
the
emission
control
from
production
engines.
All
the
information
in
this
report
is
true
and
accurate,
to
the
best
of
my
knowledge.
I
know
of
the
penalties
for
violating
the
Clean
Air
Act
and
the
regulations.
(
Authorized
Company
Representative)
(
d)
Send
electronic
reports
of
production
line
testing
to
the
Designated
Officer
using
an
approved
information
format.
If
you
want
to
use
a
different
format,
send
us
a
written
request
with
justification
for
a
waiver.
(
e)
We
will
send
copies
of
your
reports
to
anyone
from
the
public
who
asks
for
them.
See
§
1048.815
for
information
on
how
we
treat
information
you
consider
confidential.
§
1048.350
What
records
must
I
keep?
(
a)
Organize
and
maintain
your
records
as
described
in
this
section.
We
may
review
your
records
at
any
time,
so
it
is
important
to
keep
required
information
readily
available.
(
b)
Keep
paper
records
of
your
production
line
testing
for
one
full
year
after
you
complete
all
the
testing
required
for
an
engine
family
in
a
model
year.
You
may
use
any
additional
storage
formats
or
media
if
you
like.
(
c)
Keep
a
copy
of
the
written
reports
described
in
§
1048.345.
(
d)
Keep
the
following
additional
records:
(
1)
A
description
of
all
test
equipment
for
each
test
cell
that
you
can
use
to
test
production
line
engines.
(
2)
The
names
of
supervisors
involved
in
each
test.
(
3)
The
name
of
anyone
who
authorizes
adjusting,
repairing,
preparing,
or
modifying
a
test
engine
and
the
names
of
all
supervisors
who
oversee
this
work.
(
4)
If
you
shipped
the
engine
for
testing,
the
date
you
shipped
it,
the
associated
storage
or
port
facility,
and
the
date
the
engine
arrived
at
the
testing
facility.
(
5)
Any
records
related
to
your
production
line
tests
that
are
not
in
the
written
report.
(
6)
A
brief
description
of
any
significant
events
during
testing
not
otherwise
described
in
the
written
report
or
in
this
section.
(
7)
Any
information
specified
in
§
1048.345
that
you
do
not
include
in
your
written
reports.
(
e)
If
we
ask,
you
must
give
us
projected
or
actual
production
figures
for
an
engine
family.
We
may
ask
you
to
divide
your
production
figures
by
maximum
brake
power,
displacement,
fuel
type,
or
assembly
plant
(
if
you
produce
engines
at
more
than
one
plant).
(
f)
Keep
a
list
of
engine
identification
numbers
for
all
the
engines
you
produce
under
each
certificate
of
conformity.
Give
us
this
list
within
30
days
if
we
ask
for
it.
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08NOR2.
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68361
Federal
Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
(
g)
We
may
ask
you
to
keep
or
send
other
information
necessary
to
implement
this
subpart.
Subpart
E
Testing
In
use
Engines
§
1048.401
What
testing
requirements
apply
to
my
engines
that
have
gone
into
service?
(
a)
If
you
produce
engines
that
are
subject
to
the
requirements
of
this
part,
you
must
test
them
as
described
in
this
subpart.
This
generally
involves
testing
engines
in
the
field
or
removing
them
for
measurement
in
a
laboratory.
(
b)
We
may
approve
an
alternate
plan
for
showing
that
in
use
engines
comply
with
the
requirements
of
this
part
if
one
of
the
following
is
true:
(
1)
You
produce
200
or
fewer
engines
per
year
in
the
selected
engine
family.
(
2)
Removing
the
engine
from
most
of
the
applications
for
that
engine
family
causes
significant,
irreparable
damage
to
the
equipment.
(
3)
You
identify
a
unique
aspect
of
your
engine
applications
that
keeps
you
from
doing
the
required
in
use
testing.
(
c)
We
may
void
your
certificate
of
conformity
for
an
engine
family
if
you
do
not
meet
your
obligations
under
this
part.
(
d)
Independent
of
your
responsibility
to
test
in
use
engines,
we
may
choose
at
any
time
to
do
our
own
testing
of
your
in
use
engines.
(
e)
If
in
use
testing
shows
that
engines
fail
to
meet
emission
standards
or
other
requirements
of
this
part,
we
may
pursue
a
recall
or
other
remedy
as
allowed
by
the
Act
(
see
§
1048.415).
§
1048.405
How
does
this
program
work?
(
a)
You
must
test
in
use
engines,
for
exhaust
emissions,
from
the
families
we
select.
We
may
select
up
to
25
percent
of
your
engine
families
in
any
model
year
or
one
engine
family
if
you
have
three
or
fewer
families.
We
will
select
engine
families
for
testing
before
the
end
of
the
model
year.
When
we
select
an
engine
family
for
testing,
we
may
specify
that
you
preferentially
test
engines
based
on
fuel
type
or
equipment
type.
In
addition,
we
may
identify
specific
modes
of
operation
or
sampling
times.
You
may
choose
to
test
additional
engine
families
that
we
do
not
select.
(
b)
Send
us
an
in
use
testing
plan
within
12
calendar
months
after
we
direct
you
to
test
a
particular
engine
family.
Complete
the
testing
within
24
calendar
months
after
we
approve
your
plan.
(
c)
You
may
need
to
test
engines
from
more
than
one
model
year
at
a
given
time.
§
1048.410
How
must
I
select,
prepare,
and
test
my
in
use
engines?
(
a)
You
may
make
arrangements
to
select
representative
test
engines
from
your
own
fleet
or
from
other
independent
sources.
(
b)
For
the
selected
engine
families,
select
engines
that
you
or
your
customers
have
(
1)
Operated
for
at
least
50
percent
of
the
engine
family's
useful
life
(
see
§
1048.101(
d));
(
2)
Not
maintained
or
used
in
an
abnormal
way;
and
(
3)
Documented
in
terms
of
total
hours
of
operation,
maintenance,
operating
conditions,
and
storage.
(
c)
Use
the
following
methods
to
determine
the
number
of
engines
you
must
test
in
each
engine
family:
(
1)
Test
at
least
two
engines
if
you
produce
2,000
or
fewer
engines
in
the
model
year
from
all
engine
families,
or
if
you
produce
500
or
fewer
engines
from
the
selected
engine
family.
Otherwise,
test
at
least
four
engines.
(
2)
If
you
successfully
complete
an
inuse
test
program
on
an
engine
family
and
later
certify
an
equivalent
engine
family
with
carryover
emission
data,
as
described
in
§
1048.235(
c),
then
test
at
least
one
engine
instead
of
the
testing
rates
in
paragraph
(
c)(
1)
of
this
section.
(
3)
If
you
test
the
minimum
required
number
of
engines
and
all
comply
fully
with
emission
standards,
you
may
stop
testing.
(
4)
For
each
engine
that
fails
any
applicable
standard,
test
two
more.
Regardless
of
measured
emission
levels,
you
do
not
have
to
test
more
than
ten
engines
in
an
engine
family.
You
may
do
more
tests
than
we
require.
(
5)
You
may
concede
that
the
engine
family
does
not
comply
before
testing
a
total
of
ten
engines.
(
d)
You
may
do
minimal
maintenance
to
set
components
of
a
test
engine
to
specifications
for
anything
we
do
not
consider
an
adjustable
parameter
(
see
§
1048.205(
p)).
Limit
maintenance
to
what
is
in
the
owner's
instructions
for
engines
with
that
amount
of
service
and
age.
Document
all
maintenance
and
adjustments.
(
e)
Do
at
least
one
valid
exhaust
emission
test
for
each
test
engine.
(
f)
For
a
test
program
on
an
engine
family,
choose
one
of
the
following
methods
to
test
your
engines:
(
1)
Remove
the
selected
engines
for
testing
in
a
laboratory.
Use
the
applicable
steady
state
and
transient
procedures
in
subpart
F
of
this
part
to
show
compliance
with
the
duty
cycle
standards
in
§
1048.101(
a)
and
(
b).
We
may
direct
you
to
measure
emissions
on
the
dynamometer
using
the
supplemental
test
procedures
in
§
1048.515
to
show
compliance
with
the
field
testing
standards
in
§
1048.101(
c).
(
2)
Test
the
selected
engines
while
they
remain
installed
in
the
equipment.
Use
the
field
testing
procedures
in
subpart
F
of
this
part.
Measure
emissions
during
normal
operation
of
the
equipment
to
show
compliance
with
the
field
testing
standards
in
§
1048.101(
c).
We
may
direct
you
to
include
specific
areas
of
normal
operation.
(
g)
You
may
ask
us
to
waive
parts
of
the
prescribed
test
procedures
if
they
are
not
necessary
to
determine
in
use
compliance.
(
h)
Calculate
the
average
emission
levels
for
an
engine
family
from
the
results
for
the
set
of
tested
engines.
Round
them
to
the
number
of
decimal
places
in
the
emission
standards
expressed
to
one
more
decimal
place.
§
1048.415
What
happens
if
in
use
engines
do
not
meet
requirements?
(
a)
Determine
the
reason
each
in
use
engine
exceeds
the
emission
standards.
(
b)
If
the
average
emission
levels
calculated
in
§
1048.410(
h)
exceed
any
of
the
emission
standards
that
apply,
notify
us
within
fifteen
days
of
completing
testing
on
this
family.
Otherwise
follow
the
reporting
instructions
in
§
1048.420.
(
c)
We
will
consider
failure
rates,
average
emission
levels,
and
any
defects
among
other
things
to
decide
on
taking
remedial
action
under
this
subpart
(
see
40
CFR
1068.505).
We
may
consider
the
results
from
any
voluntary
additional
testing
you
conduct.
We
may
also
consider
information
related
to
testing
from
other
engine
families
showing
that
you
designed
them
to
exceed
the
minimum
requirements
for
controlling
emissions.
We
may
order
a
recall
before
or
after
you
complete
testing
of
an
engine
family
if
we
determine
a
substantial
number
of
engines
do
not
conform
to
section
213
of
the
Act
or
to
this
part.
(
d)
If
in
use
testing
reveals
a
design
or
manufacturing
defect
that
prevents
engines
from
meeting
the
requirements
of
this
part,
you
must
correct
the
defect
as
soon
as
possible
for
any
future
production
for
engines
in
every
family
affected
by
the
defect.
(
e)
You
may
voluntarily
recall
an
engine
family
for
emission
failures,
as
described
in
40
CFR
1068.535,
unless
we
have
ordered
a
recall
for
that
family
under
40
CFR
1068.505.
(
f)
You
have
the
right
to
a
hearing
before
we
order
you
to
recall
your
engines
or
implement
an
alternative
remedy
(
see
§
1048.820).
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Rules
and
Regulations
§
1048.420
What
in
use
testing
information
must
I
report
to
EPA?
(
a)
In
a
report
to
us
within
three
months
after
you
finish
testing
an
engine
family,
do
all
the
following:
(
1)
Identify
the
engine
family,
model,
serial
number,
and
date
of
manufacture.
(
2)
For
each
engine
inspected
or
considered
for
testing,
identify
whether
the
diagnostic
system
was
functioning.
(
3)
Describe
the
specific
reasons
for
disqualifying
any
engines
for
not
being
properly
maintained
or
used.
(
4)
For
each
engine
selected
for
testing,
include
the
following
information:
(
i)
Estimate
the
hours
each
engine
was
used
before
testing.
(
ii)
Describe
all
maintenance,
adjustments,
modifications,
and
repairs
to
each
test
engine.
(
5)
State
the
date
and
time
of
each
test
attempt.
(
6)
Include
the
results
of
all
emission
testing,
including
incomplete
or
invalidated
tests,
if
any.
(
b)
Send
electronic
reports
of
in
use
testing
to
the
Designated
Officer
using
an
approved
information
format.
If
you
want
to
use
a
different
format,
send
us
a
written
request
with
justification
for
a
waiver.
(
c)
We
will
send
copies
of
your
reports
to
anyone
from
the
public
who
asks
for
them.
See
§
1048.815
for
information
on
how
we
treat
information
you
consider
confidential.
(
d)
We
may
ask
for
more
information.
§
1048.425
What
records
must
I
keep?
(
a)
Organize
and
maintain
your
records
as
described
in
this
section.
We
may
review
your
records
at
any
time,
so
it
is
important
to
keep
required
information
readily
available.
(
b)
Keep
paper
records
of
your
in
use
testing
for
one
full
year
after
you
complete
all
the
testing
required
for
an
engine
family
in
a
model
year.
You
may
use
any
additional
storage
formats
or
media
if
you
like.
(
c)
Keep
a
copy
of
the
written
reports
described
in
§
1048.420.
(
d)
Keep
any
additional
records
related
to
the
procurement
process.
Subpart
F
Test
Procedures
§
1048.501
What
procedures
must
I
use
to
test
my
engines?
(
a)
Use
the
equipment
and
procedures
for
spark
ignition
engines
in
40
CFR
part
1065
to
show
your
engines
meet
the
duty
cycle
emission
standards
in
§
1048.101(
a)
and
(
b).
Measure
HC,
NOX,
CO,
and
CO2
emissions
using
the
fullflow
dilute
sampling
procedures
in
40
CFR
part
1065.
Use
the
applicable
duty
cycles
in
§
§
1048.505
and
1048.510.
(
b)
We
describe
in
§
1048.515
the
supplemental
procedures
for
showing
that
your
engines
meet
the
field
testing
emission
standards
in
§
1048.101(
c).
(
c)
Use
the
fuels
specified
in
40
CFR
part
1065,
subpart
C,
for
all
the
testing
we
require
in
this
part,
except
as
noted
in
§
1048.515.
Use
these
test
fuels
or
any
commercially
available
fuel
for
service
accumulation.
(
d)
To
test
engines
for
evaporative
emissions,
use
the
equipment
and
procedures
specified
for
testing
diurnal
emissions
in
40
CFR
86.107
96
and
86.133
96
with
fuel
meeting
the
specifications
in
40
CFR
part
1065,
subpart
C.
Measure
emissions
from
a
test
engine
with
a
complete
fuel
system.
Reported
emission
levels
must
be
based
on
the
highest
emissions
from
three
successive
24
hour
periods
of
cycling
temperatures.
Note
that
you
may
not
be
required
to
test
for
evaporative
emissions
during
certification
if
you
certify
by
design,
as
specified
in
§
1048.245.
(
e)
You
may
use
special
or
alternate
procedures,
as
described
in
40
CFR
1065.10.
(
f)
We
may
reject
data
you
generate
using
alternate
procedures
if
later
testing
with
the
procedures
in
40
CFR
part
1065
shows
contradictory
emission
data.
§
1048.505
What
steady
state
duty
cycles
apply
for
laboratory
testing?
(
a)
Measure
emissions
by
testing
the
engine
on
a
dynamometer
with
one
or
more
of
the
following
sets
of
steadystate
duty
cycles
to
show
that
the
engine
meets
the
steady
state
standards
in
§
1048.101(
b):
(
1)
Use
the
7
mode
duty
cycle
described
in
the
following
table
for
engines
from
an
engine
family
that
will
be
used
only
in
variable
speed
applications:
TABLE
1
OF
§
1048.505
7
MODE
DUTY
CYCLE
1
Mode
No.
Engine
speed
Observed
torque
2
Minimum
time
in
mode
(
minutes)
Weighting
factors
1
..................................................
Maximum
test
speed
......................................................................
25
3.0
0.06
2
..................................................
Intermediate
test
speed
..................................................................
100
3.0
0.02
3
..................................................
Intermediate
test
speed
..................................................................
75
3.0
0.05
4
..................................................
Intermediate
test
speed
..................................................................
50
3.0
0.32
5
..................................................
Intermediate
test
speed
..................................................................
25
3.0
0.30
6
..................................................
Intermediate
test
speed
..................................................................
10
3.0
0.10
7
..................................................
Idle
..................................................................................................
0
3.0
0.15
1
This
duty
cycle
is
analogous
to
the
C2
cycle
specified
in
ISO
8178
4.
2
The
percent
torque
is
relative
to
the
maximum
torque
at
the
given
engine
speed.
(
2)
Use
the
5
mode
duty
cycle
described
in
the
following
table
if
you
certify
an
engine
family
for
operation
only
at
a
single,
rated
speed:
TABLE
2
OF
§
1048.505
5
MODE
DUTY
CYCLE
FOR
CONSTANT
SPEED
ENGINES
1
Mode
No.
Engine
speed
Torque
2
Minimum
time
in
mode
(
minutes)
Weighting
factors
1
..................................................
Maximum
test
.................................................................................
100
3.0
0.05
2
..................................................
Maximum
test
.................................................................................
75
3.0
0.25
3
..................................................
Maximum
test
.................................................................................
50
3.0
0.30
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/
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8,
2002
/
Rules
and
Regulations
TABLE
2
OF
§
1048.505
5
MODE
DUTY
CYCLE
FOR
CONSTANT
SPEED
ENGINES
1
Mode
No.
Engine
speed
Torque
2
Minimum
time
in
mode
(
minutes)
Weighting
factors
4
..................................................
Maximum
test
.................................................................................
25
3.0
0.30
5
..................................................
Maximum
test
.................................................................................
10
3.0
0.10
1
This
duty
cycle
is
analogous
to
the
D2
cycle
specified
in
ISO
8178
4.
2
The
percent
torque
is
relative
to
the
maximum
torque
at
maximum
test
speed.
(
3)
Use
both
of
the
duty
cycles
described
in
paragraphs
(
a)(
1)
and
(
a)(
2)
of
this
section
if
you
will
not
restrict
an
engine
family
to
constant
speed
or
variable
speed
applications.
(
4)
Use
only
the
duty
cycle
specified
in
paragraph
(
a)(
2)
of
this
section
for
all
severe
duty
engines.
(
5)
Use
the
2
mode
duty
cycle
described
in
the
following
table
for
high
load
engines
instead
of
the
other
duty
cycles
in
this
paragraph
(
a):
TABLE
3
OF
§
1048.505
2
MODE
DUTY
CYCLE
FOR
HIGH
LOAD
ENGINES
1
Mode
No.
Engine
speed
Torque
2
Minimum
time
in
mode
(
minutes)
Weighting
factors
1
..................................................
Maximum
test
.................................................................................
100
3.0
0.50
2
..................................................
Maximum
test
.................................................................................
75
3.0
0.50
1
This
duty
cycle
is
derived
from
the
D1
cycle
specified
in
ISO
8178
4.
2
The
percent
torque
is
relative
to
the
maximum
torque
at
maximum
test
speed.
(
b)
If
we
test
an
engine
to
confirm
that
it
meets
the
duty
cycle
emission
standards,
we
will
use
the
steady
state
duty
cycles
that
apply
for
that
engine
family.
(
c)
During
idle
mode,
operate
the
engine
with
the
following
parameters:
(
1)
Hold
the
speed
within
your
specifications.
(
2)
Keep
the
throttle
at
the
idle
stop
position.
(
3)
Keep
engine
torque
under
5
percent
of
the
peak
torque
value
at
maximum
test
speed.
(
d)
For
the
full
load
operating
mode,
operate
the
engine
at
wide
open
throttle.
(
e)
See
40
CFR
part
1065
for
detailed
specifications
of
tolerances
and
calculations.
(
f)
In
the
normal
test
sequence
described
in
40
CFR
part
1065,
subpart
F,
steady
state
testing
generally
follows
the
transient
test.
For
those
cases
where
we
do
not
require
transient
testing,
perform
the
steady
state
test
after
an
appropriate
warm
up
period,
consistent
with
good
engineering
judgment.
§
1048.510
What
transient
duty
cycles
apply
for
laboratory
testing?
(
a)
Starting
with
the
2007
model
year,
measure
emissions
by
testing
the
engine
on
a
dynamometer
with
one
of
the
following
transient
duty
cycles
to
show
that
the
engine
meets
the
transient
emission
standards
in
§
1048.101(
a):
(
1)
If
you
certify
an
engine
family
for
constant
speed
operation
only,
use
the
transient
duty
cycle
described
in
Appendix
I
of
this
part.
(
2)
For
all
other
engines,
use
the
transient
duty
cycle
described
in
Appendix
II
of
this
part.
(
b)
If
we
test
an
engine
to
confirm
that
it
meets
the
duty
cycle
emission
standards,
we
will
use
the
transient
duty
cycle
that
applies
for
that
engine
family.
(
c)
Warm
up
the
test
engine
as
follows:
(
1)
Operate
the
engine
for
the
first
180
seconds
of
the
appropriate
duty
cycle,
then
allow
it
to
idle
without
load
for
30
seconds.
At
the
end
of
the
30
second
idling
period,
start
measuring
emissions
as
the
engine
operates
over
the
prescribed
duty
cycle.
For
severe
duty
engines,
this
engine
warm
up
procedure
may
include
up
to
15
minutes
of
operation
over
the
appropriate
duty
cycle.
(
2)
If
the
engine
was
already
operating
before
a
test,
use
good
engineering
judgment
to
let
the
engine
cool
down
enough
so
measured
emissions
during
the
next
test
will
accurately
represent
those
from
an
engine
starting
at
room
temperature.
For
example,
if
an
engine
starting
at
room
temperature
warms
up
enough
in
three
minutes
to
start
closedloop
operation
and
achieve
full
catalyst
activity,
then
minimal
engine
cooling
is
necessary
before
starting
the
next
test.
(
3)
You
are
not
required
to
measure
emissions
while
the
engine
is
warming
up.
However,
you
must
design
your
emission
control
system
to
start
working
as
soon
as
possible
after
engine
starting.
In
your
application
for
certification,
describe
how
your
engine
meets
this
objective
(
see
§
1048.205(
b)).
§
1048.515
Field
testing
procedures.
(
a)
This
section
describes
the
procedures
to
determine
whether
your
engines
meet
the
field
testing
emission
standards
in
§
1048.101(
c).
These
procedures
may
include
any
normal
engine
operation
and
ambient
conditions
that
the
engines
may
experience
in
use.
Paragraph
(
b)
of
this
section
defines
the
limits
of
what
we
will
consider
normal
engine
operation
and
ambient
conditions.
Use
the
test
procedures
we
specify
in
§
1048.501,
except
for
the
provisions
we
specify
in
this
section.
Measure
emissions
with
one
of
the
following
procedures:
(
1)
Remove
the
selected
engines
for
testing
in
a
laboratory.
You
can
use
an
engine
dynamometer
to
simulate
normal
operation,
as
described
in
this
section.
(
2)
Test
the
selected
engines
while
they
remain
installed
in
the
equipment.
In
40
CFR
part
1065,
subpart
J,
we
describe
the
equipment
and
sampling
methods
for
testing
engines
in
the
field.
Use
fuel
meeting
the
specifications
of
40
CFR
1065.210
or
a
fuel
typical
of
what
you
would
expect
the
engine
to
use
in
service.
(
b)
An
engine's
emissions
may
not
exceed
the
levels
we
specify
in
§
1048.101(
c)
for
any
continuous
sampling
period
of
at
least
120
seconds
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2002
/
Rules
and
Regulations
under
the
following
ranges
of
operation
and
operating
conditions:
(
1)
Engine
operation
during
the
emission
sampling
period
may
include
any
normal
operation,
subject
to
the
following
restrictions:
(
i)
Average
power
must
be
over
5
percent
of
maximum
brake
power.
(
ii)
Continuous
time
at
idle
must
not
be
greater
than
120
seconds.
(
iii)
The
sampling
period
may
not
begin
until
the
engine
has
reached
stable
operating
temperatures.
For
example,
this
would
exclude
engine
operation
after
starting
until
the
thermostat
starts
modulating
coolant
temperature.
(
iv)
The
sampling
period
may
not
include
engine
starting.
(
v)
For
engines
that
qualify
for
the
alternate
Tier
2
emission
standards
in
§
1048.101(
d),
operation
at
90
percent
or
more
of
maximum
power
must
be
less
than
10
percent
of
the
total
sampling
time.
You
may
request
our
approval
for
a
different
power
threshold.
(
2)
Engine
testing
may
occur
under
any
normal
conditions
without
correcting
measured
emission
levels,
subject
to
the
following
restrictions:
(
i)
Barometric
pressure
must
be
between
80.0
and
103.3
kPa
(
600
and
775
mm
Hg).
(
ii)
Ambient
air
temperature
must
be
between
13
°
and
35
°
C.
Subpart
G
Compliance
Provisions
§
1048.601
What
compliance
provisions
apply
to
these
engines?
Engine
and
equipment
manufacturers,
as
well
as
owners,
operators,
and
rebuilders
of
these
engines,
and
all
other
persons,
must
observe
the
requirements
and
prohibitions
in
40
CFR
part
1068
and
the
requirements
of
the
Act.
The
compliance
provisions
in
this
subpart
apply
only
to
the
engines
we
regulate
in
this
part.
§
1048.605
What
are
the
provisions
for
exempting
engines
from
the
requirements
of
this
part
if
they
are
already
certified
under
the
motor
vehicle
program?
(
a)
This
section
applies
to
you
if
you
are
an
engine
manufacturer.
See
§
1048.610
if
you
are
not
an
engine
manufacturer.
(
b)
The
only
requirements
or
prohibitions
from
this
part
that
apply
to
an
engine
that
is
exempt
under
this
section
are
in
this
section.
(
c)
If
you
meet
all
the
following
criteria
and
requirements
regarding
your
new
nonroad
engine,
it
is
exempt
under
this
section:
(
1)
You
must
produce
it
by
modifying
an
engine
covered
by
a
valid
certificate
of
conformity
under
40
CFR
part
86.
(
2)
Do
not
make
any
changes
to
the
certified
engine
that
we
could
reasonably
expect
to
increase
its
exhaust
or
evaporative
emissions.
For
example,
if
you
make
any
of
the
following
changes
to
one
of
these
engines,
you
do
not
qualify
for
this
exemption:
(
i)
Change
any
fuel
system
or
evaporative
system
parameters
from
the
certified
configuration
(
this
does
not
apply
to
refueling
emission
controls).
(
ii)
Change
any
other
emission
related
components.
(
iii)
Modify
or
design
the
engine
cooling
system
so
that
temperatures
or
heat
rejection
rates
are
outside
the
original
engine
manufacturer's
specified
ranges.
(
3)
Demonstrate
that
fewer
than
50
percent
of
the
engine
model's
total
sales,
from
all
companies,
are
used
in
nonroad
applications.
(
4)
The
engine
must
have
the
label
we
require
under
40
CFR
part
86.
(
5)
Add
a
permanent
supplemental
label
to
the
engine
in
a
position
where
it
will
remain
clearly
visible
after
installation
in
the
equipment.
In
your
engine's
emission
control
information
label,
do
the
following:
(
i)
Include
the
heading:
``
Nonroad
Engine
Emission
Control
Information''.
(
ii)
Include
your
full
corporate
name
and
trademark.
(
iii)
State:
``
THIS
ENGINE
WAS
ADAPTED
FOR
NONROAD
USE
WITHOUT
AFFECTING
ITS
EMISSION
CONTROLS.''.
(
iv)
State
the
date
you
finished
modifying
the
engine
(
month
and
year).
(
6)
The
original
and
supplemental
labels
must
be
readily
visible
after
the
engine
is
installed
in
the
equipment
or,
if
the
equipment
obscures
the
engine's
emission
control
information
label,
the
equipment
manufacturer
must
attach
duplicate
labels,
as
described
in
40
CFR
1068.105.
(
7)
Send
the
Designated
Officer
a
signed
letter
by
the
end
of
each
calendar
year
(
or
less
often
if
we
tell
you)
with
all
the
following
information:
(
i)
Identify
your
full
corporate
name,
address,
and
telephone
number.
(
ii)
List
the
engine
models
you
expect
to
produce
under
this
exemption
in
the
coming
year.
(
iii)
State:
``
We
produce
each
listed
engine
model
for
nonroad
application
without
making
any
changes
that
could
increase
its
certified
emission
levels,
as
described
in
40
CFR
1048.605.''.
(
d)
If
your
engines
do
not
meet
the
criteria
listed
in
paragraph
(
c)
of
this
section,
they
will
be
subject
to
the
standards
and
prohibitions
of
this
part.
Producing
these
engines
without
a
valid
exemption
or
certificate
of
conformity
would
violate
the
prohibitions
in
40
CFR
1068.101.
(
e)
If
you
are
the
original
engine
manufacturer
of
both
the
highway
and
nonroad
versions
of
an
exempted
engine,
you
must
send
us
emission
test
data
on
the
applicable
nonroad
duty
cycle(
s).
You
may
include
the
data
in
your
application
for
certification
or
in
your
letter
requesting
the
exemption.
(
f)
If
you
are
the
original
engine
manufacturer
of
an
exempted
engine
that
is
modified
by
another
company
under
this
exemption,
we
may
require
you
to
send
us
emission
test
data
on
the
applicable
nonroad
duty
cycle(
s).
If
we
ask
for
this
data,
we
will
allow
a
reasonable
amount
of
time
to
collect
it.
(
g)
The
engine
exempted
under
this
section
must
meet
all
applicable
requirements
from
40
CFR
part
86.
This
applies
to
engine
manufacturers,
equipment
manufacturers
who
use
these
engines,
and
all
other
persons
as
if
these
engines
were
used
in
a
motor
vehicle.
§
1048.610
What
are
the
provisions
for
producing
nonroad
equipment
with
engines
already
certified
under
the
motor
vehicle
program?
If
you
are
not
an
engine
manufacturer,
you
may
produce
nonroad
equipment
from
complete
or
incomplete
motor
vehicles
with
the
motor
vehicle
engine
if
you
meet
three
criteria:
(
a)
The
engine
or
vehicle
is
certified
to
40
CFR
part
86.
(
b)
The
engine
is
not
adjusted
outside
the
engine
manufacturer's
specifications
(
see
§
1048.605(
c)(
2)).
(
c)
The
engine
or
vehicle
is
not
modified
in
any
way
that
may
affect
its
emission
control.
This
applies
to
exhaust
and
evaporative
emission
controls,
but
not
refueling
emission
controls.
§
1048.615
What
are
the
provisions
for
exempting
engines
designed
for
lawn
and
garden
applications?
This
section
is
intended
for
engines
designed
for
lawn
and
garden
applications,
but
it
applies
to
any
engines
meeting
the
size
criteria
in
paragraph
(
a)
of
this
section.
(
a)
If
an
engine
meets
all
the
following
criteria,
it
is
exempt
from
the
requirements
of
this
part:
(
1)
The
engine
must
have
a
total
displacement
of
1,000
cc
or
less.
(
2)
The
engine
must
have
a
maximum
brake
power
of
30
kW
or
less.
(
3)
The
engine
must
be
in
an
engine
family
that
has
a
valid
certificate
of
conformity
showing
that
it
meets
emission
standards
for
Class
II
engines
under
40
CFR
part
90.
(
b)
The
only
requirements
or
prohibitions
from
this
part
that
apply
to
an
engine
that
meets
the
criteria
in
paragraph
(
a)
of
this
section
are
in
this
section.
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Rules
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(
c)
If
your
engines
do
not
meet
the
criteria
listed
in
paragraph
(
a)
of
this
section,
they
will
be
subject
to
the
provisions
of
this
part.
Producing
these
engines
without
a
valid
exemption
or
certificate
of
conformity
would
violate
the
prohibitions
in
40
CFR
1068.101.
(
d)
Engines
exempted
under
this
section
are
subject
to
all
the
requirements
affecting
engines
under
40
CFR
part
90.
The
requirements
and
restrictions
of
40
CFR
part
90
apply
to
anyone
manufacturing
these
engines,
anyone
manufacturing
equipment
that
uses
these
engines,
and
all
other
persons
in
the
same
manner
as
if
these
engines
had
a
total
maximum
brake
power
at
or
below
19
kW.
§
1048.620
What
are
the
provisions
for
exempting
large
engines
fueled
by
natural
gas?
(
a)
If
an
engine
meets
all
the
following
criteria,
it
is
exempt
from
the
requirements
of
this
part:
(
1)
The
engine
must
operate
solely
on
natural
gas.
(
2)
The
engine
must
have
maximum
brake
power
250
kW
or
higher.
(
3)
The
engine
must
be
in
an
engine
family
that
has
a
valid
certificate
of
conformity
showing
that
it
meets
emission
standards
for
engines
of
that
power
rating
under
40
CFR
part
89.
(
b)
The
only
requirements
or
prohibitions
from
this
part
that
apply
to
an
engine
that
is
exempt
under
this
section
are
in
this
section.
(
c)
If
your
engines
do
not
meet
the
criteria
listed
in
paragraph
(
a)
of
this
section,
they
will
be
subject
to
the
provisions
of
this
part.
Producing
these
engines
without
a
valid
exemption
or
certificate
of
conformity
would
violate
the
prohibitions
in
40
CFR
1068.101.
(
d)
Engines
exempted
under
this
section
are
subject
to
all
the
requirements
affecting
engines
under
40
CFR
part
89.
The
requirements
and
restrictions
of
40
CFR
part
89
apply
to
anyone
manufacturing
these
engines,
anyone
manufacturing
equipment
that
uses
these
engines,
and
all
other
persons
in
the
same
manner
as
if
these
were
nonroad
diesel
engines.
(
e)
You
may
request
an
exemption
under
this
section
by
submitting
an
application
for
certification
for
the
engines
under
40
CFR
part
89.
§
1048.625
What
special
provisions
apply
to
engines
using
noncommercial
fuels?
If
you
are
unable
to
meet
this
part's
requirements
with
engines
using
noncommercial
fuels
(
such
as
unrefined
natural
gas
released
by
oil
wells),
the
following
provisions
apply
for
those
engines:
(
a)
Create
a
separate
engine
family.
(
b)
Disregard
the
limits
on
adjustable
parameters
in
§
1048.115(
e),
but
make
sure
the
engines
meet
emission
standards
with
normal
settings
when
the
engine
is
using
fuel
meeting
the
specifications
of
40
CFR
part
1065,
subpart
C.
(
c)
Add
the
following
information
to
the
emission
control
information
label
specified
in
§
1048.135:
(
1)
Include
instructions
describing
how
to
adjust
the
engine
to
operate
in
a
way
that
maintains
the
effectiveness
of
the
emission
control
system.
(
2)
State:
``
THIS
ENGINE
IS
CERTIFIED
TO
OPERATE
IN
APPLICATIONS
USING
NONCOMMERCIAL
FUEL.
USING
IT
IN
AN
APPLICATION
INVOLVING
ONLY
COMMERCIAL
FUELS
MAY
BE
A
VIOLATION
OF
FEDERAL
LAW
SUBJECT
TO
CIVIL
PENALTY.''.
(
d)
Keep
records
to
document
the
destinations
and
quantities
of
engines
produced
under
this
section.
Subpart
H
[
Reserved]
Subpart
I
Definitions
and
Other
Reference
Information
§
1048.801
What
definitions
apply
to
this
part?
The
following
definitions
apply
to
this
part.
The
definitions
apply
to
all
subparts
unless
we
note
otherwise.
All
undefined
terms
have
the
meaning
the
Act
gives
to
them.
The
definitions
follow:
Act
means
the
Clean
Air
Act,
as
amended,
42
U.
S.
C.
7401
et
seq.
Adjustable
parameter
means
any
device,
system,
or
element
of
design
that
someone
can
adjust
(
including
those
which
are
difficult
to
access)
and
that,
if
adjusted,
may
affect
emissions
or
engine
performance
during
emission
testing
or
normal
in
use
operation.
You
may
ask
us
to
exclude
a
parameter
that
is
difficult
to
access
if
it
cannot
be
adjusted
to
affect
emissions
without
significantly
degrading
performance,
or
if
you
otherwise
show
us
that
it
will
not
be
adjusted
in
a
way
that
affects
emissions
during
in
use
operation.
Aftertreatment
means
relating
to
any
system,
component,
or
technology
mounted
downstream
of
the
exhaust
valve
or
exhaust
port
whose
design
function
is
to
reduce
exhaust
emissions.
Aircraft
means
any
vehicle
capable
of
sustained
air
travel
above
treetop
heights.
All
terrain
vehicle
has
the
meaning
we
give
in
40
CFR
1051.801.
Auxiliary
emission
control
device
means
any
element
of
design
that
senses
temperature,
engine
rpm,
motive
speed,
transmission
gear,
atmospheric
pressure,
manifold
pressure
or
vacuum,
or
any
other
parameter
to
activate,
modulate,
delay,
or
deactivate
the
operation
of
any
part
of
the
emissioncontrol
system.
This
also
includes
any
other
feature
that
causes
in
use
emissions
to
be
higher
than
those
measured
under
test
conditions,
except
as
we
allow
under
this
part.
Blue
Sky
Series
engine
means
an
engine
meeting
the
requirements
of
§
1048.140.
Brake
power
means
the
usable
power
output
of
the
engine,
not
including
power
required
to
operate
fuel
pumps,
oil
pumps,
or
coolant
pumps.
Broker
means
any
entity
that
facilitates
a
trade
of
emission
credits
between
a
buyer
and
seller.
Calibration
means
the
set
of
specifications
and
tolerances
specific
to
a
particular
design,
version,
or
application
of
a
component
or
assembly
capable
of
functionally
describing
its
operation
over
its
working
range.
Certification
means
obtaining
a
certificate
of
conformity
for
an
engine
family
that
complies
with
the
emission
standards
and
requirements
in
this
part.
Compression
ignition
means
relating
to
a
type
of
reciprocating,
internalcombustion
engine
that
is
not
a
sparkignition
engine.
Constant
speed
engine
means
an
engine
governed
to
operate
at
a
single
speed.
Crankcase
emissions
means
airborne
substances
emitted
to
the
atmosphere
from
any
part
of
the
engine
crankcase's
ventilation
or
lubrication
systems.
The
crankcase
is
the
housing
for
the
crankshaft
and
other
related
internal
parts.
Designated
Officer
means
the
Manager,
Engine
Programs
Group
(
6405
J),
U.
S.
Environmental
Protection
Agency,
1200
Pennsylvania
Ave.,
Washington,
DC
20460.
Emission
control
system
means
any
device,
system,
or
element
of
design
that
controls
or
reduces
the
regulated
emissions
from
an
engine.
Emission
data
engine
means
an
engine
that
is
tested
for
certification.
Emission
related
maintenance
means
maintenance
that
substantially
affects
emissions
or
is
likely
to
substantially
affect
emissions
deterioration.
Engine
family
means
a
group
of
engines
with
similar
emission
characteristics,
as
specified
in
§
1048.230.
Engine
manufacturer
means
the
manufacturer
of
the
engine.
See
the
definition
of
``
manufacturer''
in
this
section.
Fuel
system
means
all
components
involved
in
transporting,
metering,
and
mixing
the
fuel
from
the
fuel
tank
to
the
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Rules
and
Regulations
combustion
chamber(
s),
including
the
fuel
tank,
fuel
tank
cap,
fuel
pump,
fuel
filters,
fuel
lines,
carburetor
or
fuelinjection
components,
and
all
fuelsystem
vents.
Good
engineering
judgment
has
the
meaning
we
give
in
40
CFR
1068.5.
High
cost
warranted
part
means
a
component
covered
by
the
emissionrelated
warranty
with
a
replacement
cost
(
at
the
time
of
certification)
exceeding
$
400
(
in
1998
dollars).
Adjust
this
value
using
the
most
recent
annual
average
consumer
price
index
information
published
by
the
U.
S.
Bureau
of
Labor
Statistics.
For
this
definition,
replacement
cost
includes
the
retail
cost
of
the
part
plus
labor
and
standard
diagnosis.
High
load
engine
means
an
engine
for
which
the
engine
manufacturer
can
provide
clear
evidence
that
operation
below
75
percent
of
maximum
load
in
it's
final
application
will
be
rare.
Hydrocarbon
(
HC)
means
the
hydrocarbon
group
on
which
the
emission
standards
are
based
for
each
fuel
type.
For
gasoline
and
LPG
fueled
engines,
HC
means
total
hydrocarbon
(
THC).
For
natural
gas
fueled
engines,
HC
means
nonmethane
hydrocarbon
(
NMHC).
For
alcohol
fueled
engines,
HC
means
total
hydrocarbon
equivalent
(
THCE).
Identification
number
means
a
unique
specification
(
for
example,
model
number/
serial
number
combination)
that
allows
someone
to
distinguish
a
particular
engine
from
other
similar
engines.
Intermediate
test
speed
has
the
meaning
we
give
in
40
CFR
1065.515.
Manufacturer
has
the
meaning
given
in
section
216(
1)
of
the
Act.
In
general,
this
term
includes
any
person
who
manufactures
an
engine,
vehicle,
or
piece
of
equipment
for
sale
in
the
United
States
or
otherwise
introduces
a
new
nonroad
engine
into
commerce
in
the
United
States.
This
includes
importers
who
import
engines,
equipment,
or
vehicles
for
resale.
Marine
engine
means
an
engine
that
someone
installs
or
intends
to
install
on
a
marine
vessel.
There
are
two
kinds
of
marine
engines:
(
1)
Propulsion
marine
engine
means
a
marine
engine
that
moves
a
vessel
through
the
water
or
directs
the
vessel's
movement.
(
2)
Auxiliary
marine
engine
means
a
marine
engine
not
used
for
propulsion.
Marine
vessel
means
a
vehicle
that
is
capable
of
operation
in
water
but
is
not
capable
of
operation
out
of
water.
Amphibious
vehicles
are
not
marine
vessels.
Maximum
brake
power
means
the
maximum
brake
power
an
engine
produces
at
maximum
test
speed.
Maximum
test
speed
has
the
meaning
we
give
in
40
CFR
1065.515.
Maximum
test
torque
has
the
meaning
we
give
in
40
CFR
1065.1001.
Model
year
means
one
of
the
following
things:
(
1)
For
freshly
manufactured
engines
(
see
definition
of
``
new
nonroad
engine,''
paragraph
(
1)),
model
year
means
one
of
the
following:
(
i)
Calendar
year.
(
ii)
Your
annual
new
model
production
period
if
it
is
different
than
the
calendar
year.
This
must
include
January
1
of
the
calendar
year
for
which
the
model
year
is
named.
It
may
not
begin
before
January
2
of
the
previous
calendar
year
and
it
must
end
by
December
31
of
the
named
calendar
year.
(
2)
For
an
engine
that
is
converted
to
a
nonroad
engine
after
being
placed
into
service
in
a
motor
vehicle,
model
year
means
the
calendar
year
in
which
the
engine
was
originally
produced
(
see
definition
of
``
new
nonroad
engine,''
paragraph
(
2)).
(
3)
For
a
nonroad
engine
excluded
under
§
1048.5
that
is
later
converted
to
operate
in
an
application
that
is
not
excluded,
model
year
means
the
calendar
year
in
which
the
engine
was
originally
produced
(
see
definition
of
``
new
nonroad
engine,''
paragraph
(
3)).
(
4)
For
engines
that
are
not
freshly
manufactured
but
are
installed
in
new
nonroad
equipment,
model
year
means
the
calendar
year
in
which
the
engine
is
installed
in
the
new
nonroad
equipment.
This
installation
date
is
based
on
the
time
that
final
assembly
of
the
equipment
is
complete
(
see
definition
of
``
new
nonroad
engine,''
paragraph
(
4)).
(
5)
For
an
engine
modified
by
an
importer
(
not
the
original
engine
manufacturer)
who
has
a
certificate
of
conformity
for
the
imported
engine
(
see
definition
of
``
new
nonroad
engine,''
paragraph
(
5)),
model
year
means
one
of
the
following:
(
i)
The
calendar
year
in
which
the
importer
finishes
modifying
and
labeling
the
engine.
(
ii)
Your
annual
production
period
for
producing
engines
if
it
is
different
than
the
calendar
year;
follow
the
guidelines
in
paragraph
(
1)(
ii)
of
this
definition.
(
6)
For
an
engine
you
import
that
does
not
meet
the
criteria
in
paragraphs
(
1)
through
(
5)
of
the
definition
of
``
new
nonroad
engine,''
model
year
means
the
calendar
year
in
which
the
engine
manufacturer
completed
the
original
assembly
of
the
engine.
In
general,
this
applies
to
used
equipment
that
you
import
without
conversion
or
major
modification.
Motor
vehicle
has
the
meaning
we
give
in
40
CFR
85.1703(
a).
In
general,
motor
vehicle
means
a
self
propelled
vehicle
that
can
transport
one
or
more
people
or
any
material,
but
doesn't
include
any
of
the
following:
(
1)
Vehicles
having
a
maximum
ground
speed
over
level,
paved
surfaces
no
higher
than
40
km
per
hour
(
25
miles
per
hour).
(
2)
Vehicles
that
lack
features
usually
needed
for
safe,
practical
use
on
streets
or
highways
for
example,
safety
features
required
by
law,
a
reverse
gear
(
except
for
motorcycles),
or
a
differential.
(
3)
Vehicles
whose
operation
on
streets
or
highways
would
be
unsafe,
impractical,
or
highly
unlikely.
Examples
are
vehicles
with
tracks
instead
of
wheels,
very
large
size,
or
features
associated
with
military
vehicles,
such
as
armor
or
weaponry.
New
nonroad
engine
means
any
of
the
following
things:
(
1)
A
freshly
manufactured
nonroad
engine
for
which
the
ultimate
buyer
has
never
received
the
equitable
or
legal
title.
This
kind
of
vehicle
might
commonly
be
thought
of
as
``
brand
new.''
In
the
case
of
this
paragraph
(
1),
the
engine
is
no
longer
new
when
the
ultimate
buyer
receives
this
title
or
the
product
is
placed
into
service,
whichever
comes
first.
(
2)
An
engine
originally
manufactured
as
a
motor
vehicle
engine
that
is
later
intended
to
be
used
in
a
piece
of
nonroad
equipment.
In
this
case,
the
engine
is
no
longer
a
motor
vehicle
engine
and
becomes
a
``
new
nonroad
engine''.
The
engine
is
no
longer
new
when
it
is
placed
into
nonroad
service.
(
3)
A
nonroad
engine
that
has
been
previously
placed
into
service
in
an
application
we
exclude
under
§
1048.5,
where
that
engine
is
installed
in
a
piece
of
equipment
for
which
these
exclusions
do
not
apply.
The
engine
is
no
longer
new
when
it
is
placed
into
nonroad
service.
For
example,
this
would
apply
to
a
stationary
engine
that
is
no
longer
used
in
a
stationary
application.
(
4)
An
engine
not
covered
by
paragraphs
(
1)
through
(
3)
of
this
definition
that
is
intended
to
be
installed
in
new
nonroad
equipment.
The
engine
is
no
longer
new
when
the
ultimate
buyer
receives
a
title
for
the
equipment
or
the
product
is
placed
into
service,
whichever
comes
first.
This
generally
includes
installation
of
used
engines
in
new
equipment.
(
5)
An
imported
nonroad
engine
covered
by
a
certificate
of
conformity
issued
under
this
part,
where
someone
other
than
the
original
engine
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manufacturer
modifies
the
engine
after
its
initial
assembly
and
holds
the
certificate.
The
engine
is
no
longer
new
when
it
is
placed
into
nonroad
service.
(
6)
An
imported
nonroad
engine
that
is
not
covered
by
a
certificate
of
conformity
issued
under
this
part
at
the
time
of
importation.
This
addresses
uncertified
engines
and
vehicles
that
have
been
placed
into
service
in
other
countries
and
that
someone
seeks
to
import
into
the
United
States.
Importation
of
this
kind
of
new
nonroad
engine
(
or
vehicle
containing
such
an
engine)
is
generally
prohibited
by
40
CFR
part
1068.
New
nonroad
equipment
means
either
of
the
following
things:
(
1)
A
nonroad
vehicle
or
other
piece
of
equipment
for
which
the
ultimate
buyer
has
never
received
the
equitable
or
legal
title.
The
product
is
no
longer
new
when
the
ultimate
buyer
receives
this
title
or
the
product
is
placed
into
service,
whichever
comes
first.
(
2)
An
imported
nonroad
piece
of
equipment
with
an
engine
not
covered
by
a
certificate
of
conformity
issued
under
this
part
at
the
time
of
importation
and
manufactured
after
the
date
for
applying
the
requirements
of
this
part.
Noncommercial
fuel
means
a
fuel
that
is
not
marketed
or
sold
as
a
commercial
product.
For
example,
this
includes
methane
produced
and
released
from
landfills
or
oil
wells.
Noncompliant
engine
means
an
engine
that
was
originally
covered
by
a
certificate
of
conformity,
but
is
not
in
the
certified
configuration
or
otherwise
does
not
comply
with
the
conditions
of
the
certificate.
Nonconforming
engine
means
an
engine
not
covered
by
a
certificate
of
conformity
that
would
otherwise
be
subject
to
emission
standards.
Nonmethane
hydrocarbon
means
the
difference
between
the
emitted
mass
of
total
hydrocarbons
and
the
emitted
mass
of
methane.
Nonroad
means
relating
to
nonroad
engines
or
equipment
that
includes
nonroad
engines.
Nonroad
engine
has
the
meaning
given
in
40
CFR
1068.30.
In
general
this
means
all
internal
combustion
engines
except
motor
vehicle
engines,
stationary
engines,
or
engines
used
solely
for
competition.
This
part
does
not
apply
to
all
nonroad
engines
(
see
§
1048.5).
Off
highway
motorcycle
has
the
meaning
we
give
in
40
CFR
1051.801.
(
Note:
highway
motorcycles
are
regulated
under
40
CFR
part
86.)
Oxides
of
nitrogen
has
the
meaning
given
it
in
40
CFR
part
1065
Placed
into
service
means
used
for
its
intended
purpose.
Point
of
first
retail
sale
means
the
location
at
which
the
retail
sale
occurs.
This
generally
means
a
dealership.
Revoke
means
to
discontinue
the
certificate
for
an
engine
family.
If
we
revoke
a
certificate,
you
must
apply
for
a
new
certificate
before
continuing
to
produce
the
affected
vehicles
or
engines.
This
does
not
apply
to
vehicles
or
engines
you
no
longer
possess.
Round
means
to
round
numbers
according
to
ASTM
E29
02
(
incorporated
by
reference
in
§
1048.810),
unless
otherwise
specified.
Scheduled
maintenance
means
adjusting,
repairing,
removing,
disassembling,
cleaning,
or
replacing
components
or
systems
that
is
periodically
needed
to
keep
a
part
from
failing
or
malfunctioning.
It
also
may
mean
actions
you
expect
are
necessary
to
correct
an
overt
indication
of
failure
or
malfunction
for
which
periodic
maintenance
is
not
appropriate.
Severe
duty
application
includes
concrete
saws,
concrete
pumps,
and
any
other
application
where
an
engine
manufacturer
can
provide
clear
evidence
that
the
majority
of
installations
need
air
cooled
engines
as
a
result
of
operation
in
a
severe
duty
environment.
Severe
duty
engine
means
an
engine
from
an
engine
family
in
which
the
majority
of
engines
are
installed
in
severe
duty
applications.
Small
volume
engine
manufacturer
means
a
company
with
fewer
than
200
employees.
This
includes
any
employees
working
for
parent
or
subsidiary
companies.
Snowmobile
has
the
meaning
we
give
in
40
CFR
1051.801.
Spark
ignition
means
relating
to
a
gasoline
fueled
engine
or
any
other
type
of
engine
with
a
spark
plug
(
or
other
sparking
device)
and
with
operating
characteristics
significantly
similar
to
the
theoretical
Otto
combustion
cycle.
Spark
ignition
engines
usually
use
a
throttle
to
regulate
intake
air
flow
to
control
power
during
normal
operation.
Stationary
engine
means
an
internal
combustion
engine
that
is
neither
a
nonroad
engine,
nor
a
motor
vehicle
engine,
nor
an
engine
used
solely
for
competition
(
see
the
definition
of
nonroad
engine
in
40
CFR
1068.30).
In
general
this
includes
fixed
engines
and
all
portable
or
transportable
engines
that
stay
in
a
single
site
at
a
building,
structure,
facility,
or
installation
for
at
least
a
full
year;
this
does
not
include
an
engine
installed
in
equipment
that
has
the
ability
to
propel
itself.
For
yearround
sources,
a
full
year
is
12
consecutive
months.
For
seasonal
sources,
a
full
year
is
a
full
annual
operating
period
of
at
least
three
months.
A
seasonal
source
is
a
site
with
engines
operating
only
part
of
the
year
for
at
least
two
consecutive
years.
If
you
replace
an
engine
with
one
that
does
the
same
or
similar
work
in
the
same
place,
you
may
apply
the
previous
engine's
service
to
your
calculation
for
residence
time.
If
you
move
a
stationary
engine
anytime
in
its
life
after
it
has
been
in
place
for
at
least
a
full
year,
it
becomes
a
nonroad
engine
subject
to
emission
standards
unless
it
stays
at
the
new
location
for
a
full
year.
Stoichiometry
means
the
proportion
of
a
mixture
of
air
and
fuel
such
that
the
fuel
is
fully
oxidized
with
no
remaining
oxygen.
For
example,
stoichiometric
combustion
in
gasoline
engines
typically
occurs
at
an
air
fuel
mass
ratio
of
about
14.7.
Suspend
means
to
temporarily
discontinue
the
certificate
for
an
engine
family.
If
we
suspend
a
certificate,
you
may
not
sell
vehicles
or
engines
from
that
engine
family
unless
we
reinstate
the
certificate
or
approve
a
new
one.
Test
engine
means
an
engine
in
a
test
sample.
Test
sample
means
the
collection
of
engines
selected
from
the
population
of
an
engine
family
for
emission
testing.
Total
hydrocarbon
means
the
combined
mass
organic
compounds
measured
by
our
total
hydrocarbon
test
procedure,
expressed
as
a
hydrocarbon
with
a
hydrogen
to
carbon
mass
ratio
of
1.85:
1.
Total
hydrocarbon
equivalent
means
the
sum
of
the
carbon
mass
contributions
of
non
oxygenated
hydrocarbons,
alcohols
and
aldehydes,
or
other
organic
compounds
that
are
measured
separately
as
contained
in
a
gas
sample,
expressed
as
petroleumfueled
engine
hydrocarbons.
The
hydrogen
to
carbon
ratio
of
the
equivalent
hydrocarbon
is
1.85:
1.
Tier
1
means
relating
to
the
emission
standards
and
other
requirements
that
apply
beginning
with
the
2004
model
year.
Tier
2
means
relating
to
the
emission
standards
and
other
requirements
that
apply
beginning
with
the
2007
model
year.
Ultimate
buyer
means
ultimate
purchaser.
Ultimate
purchaser
means,
with
respect
to
any
new
nonroad
equipment
or
new
nonroad
engine,
the
first
person
who
in
good
faith
purchases
such
new
nonroad
equipment
or
new
nonroad
engine
for
purposes
other
than
resale.
United
States
means
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
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2002
/
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and
Regulations
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.
Upcoming
model
year
means
for
an
engine
family
the
model
year
after
the
one
currently
in
production.
U.
S.
directed
production
volume
means
the
number
of
engine
units,
subject
to
the
requirements
of
this
part,
produced
by
a
manufacturer
for
which
the
manufacturer
has
a
reasonable
assurance
that
sale
was
or
will
be
made
to
ultimate
buyers
in
the
United
States.
Useful
life
means
the
period
during
which
the
engine
is
designed
to
properly
function
in
terms
of
reliability
and
fuel
consumption,
without
being
remanufactured,
specified
as
a
number
of
hours
of
operation
or
calendar
years.
It
is
the
period
during
which
a
new
nonroad
engine
is
required
to
comply
with
all
applicable
emission
standards.
See
§
1048.101(
g).
Variable
speed
engine
means
an
engine
that
is
not
a
constant
speed
engine.
Void
means
to
invalidate
a
certificate
or
an
exemption.
If
we
void
a
certificate,
all
the
vehicles
produced
under
that
engine
family
for
that
model
year
are
considered
noncompliant,
and
you
are
liable
for
each
vehicle
produced
under
the
certificate
and
may
face
civil
or
criminal
penalties
or
both.
If
we
void
an
exemption,
all
the
vehicles
produced
under
that
exemption
are
considered
uncertified
(
or
nonconforming),
and
you
are
liable
for
each
vehicle
produced
under
the
exemption
and
may
face
civil
or
criminal
penalties
or
both.
You
may
not
produce
any
additional
vehicles
using
the
voided
exemption.
Volatile
liquid
fuel
means
any
fuel
other
than
diesel
or
biodiesel
that
is
a
liquid
at
atmospheric
pressure.
Wide
open
throttle
means
maximum
throttle
opening.
Unless
this
is
specified
at
a
given
speed,
it
refers
to
maximum
throttle
opening
at
maximum
speed.
For
electronically
controlled
or
other
engines
with
multiple
possible
fueling
rates,
wide
open
throttle
also
means
the
maximum
fueling
rate
at
maximum
throttle
opening
under
test
conditions.
§
1048.805
What
symbols,
acronyms,
and
abbreviations
does
this
part
use?
The
following
symbols,
acronyms,
and
abbreviations
apply
to
this
part:
°
C
degrees
Celsius.
ASTM
American
Society
for
Testing
and
Materials.
cc
cubic
centimeters.
CFR
Code
of
Federal
Regulations.
cm
centimeter.
CO
carbon
monoxide.
CO2
carbon
dioxide.
EPA
Environmental
Protection
Agency.
g/
kW
hr
grams
per
kilowatt
hour.
HC
hydrocarbon.
ISO
International
Organization
for
Standardization.
kPa
kilopascals.
kW
kilowatts.
LPG
liquefied
petroleum
gas.
m
meters.
MIL
malfunction
indicator
light.
mm
Hg
millimeters
of
mercury.
NMHC
nonmethane
hydrocarbons.
NOX
oxides
of
nitrogen
(
NO
and
NO2).
psi
pounds
per
square
inch
of
absolute
pressure.
psig
pounds
per
square
inch
of
gauge
pressure.
rpm
revolutions
per
minute.
SAE
Society
of
Automotive
Engineers.
SI
spark
ignition.
THC
total
hydrocarbon.
THCE
total
hydrocarbon
equivalent.
U.
S.
C.
United
States
Code.
§
1048.810
What
materials
does
this
part
reference?
We
have
incorporated
by
reference
the
documents
listed
in
this
section.
The
Director
of
the
Federal
Register
approved
the
incorporation
by
reference
as
prescribed
in
5
U.
S.
C.
552(
a)
and
1
CFR
part
51.
Anyone
may
inspect
copies
at
the
U.
S.
EPA,
Air
and
Radiation
Docket
and
Information
Center,
1301
Constitution
Ave.,
NW.,
Room
B102,
EPA
West
Building,
Washington,
DC
20460
or
the
Office
of
the
Federal
Register,
800
N.
Capitol
St.,
NW.,
7th
Floor,
Suite
700,
Washington,
DC.
(
a)
ASTM
material.
Table
1
of
§
1048.810
lists
material
from
the
American
Society
for
Testing
and
Materials
that
we
have
incorporated
by
reference.
The
first
column
lists
the
number
and
name
of
the
material.
The
second
column
lists
the
sections
of
this
part
where
we
reference
it.
Anyone
may
purchase
copies
of
these
materials
from
the
American
Society
for
Testing
and
Materials,
100
Barr
Harbor
Dr.,
West
Conshohocken,
PA
19428.
Table
1
follows:
TABLE
1
OF
§
1048.810.
ASTM
MATERIALS
Document
number
and
name
Part
1048
reference
ASTM
E29
02,
Standard
Practice
for
Using
Significant
Digits
in
Test
Data
to
Determine
Conformance
with
Specifications
..............
1048.801
(
b)
SAE
material.
Table
2
of
§
1048.810
lists
material
from
the
Society
of
Automotive
Engineering
that
we
have
incorporated
by
reference.
The
first
column
lists
the
number
and
name
of
the
material.
The
second
column
lists
the
sections
of
this
part
where
we
reference
it.
Anyone
may
purchase
copies
of
these
materials
from
the
Society
of
Automotive
Engineers,
400
Commonwealth
Drive,
Warrendale,
PA
15096.
Table
2
follows:
TABLE
2
OF
§
1048.810.
SAE
MATERIALS
Document
number
and
name
Part
1048
reference
SAE
J1930,
Electrical/
Electronic
Systems
Diagnostic
Terms,
Definitions,
Abbreviations,
and
Acronyms,
May
1998
..........................
1048.135
SAE
J2260,
Nonmetallic
Fuel
System
Tubing
with
One
or
More
Layers,
November
1996
...................................................................
1048.105
(
c)
ISO
material.
Table
3
of
§
1048.810
lists
material
from
the
International
Organization
for
Standardization
that
we
have
incorporated
by
reference.
The
first
column
lists
the
number
and
name
of
the
material.
The
second
column
lists
the
section
of
this
part
where
we
reference
it.
Anyone
may
purchase
copies
of
these
materials
from
the
International
Organization
for
Standardization,
Case
Postale
56,
CH
1211
Geneva
20,
Switzerland.
Table
3
follows:
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217
/
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8,
2002
/
Rules
and
Regulations
TABLE
3
OF
§
1048.810.
ISO
MATERIALS
Document
number
and
name
Part
1048
reference
ISO
9141
2
Road
vehicles
Diagnostic
systems
Part
2:
CARB
requirements
for
interchange
of
digital
information,
February
1994
.....................................................................................................................................................................................................
1048.110
ISO
14230
4
Road
vehicles
Diagnostic
systems
Keyword
Protocol
2000
Part
4:
Requirements
for
emission
related
systems,
June
2000
............................................................................................................................................................................................
1048.110
§
1048.815
How
should
I
request
EPA
to
keep
my
information
confidential?
(
a)
Clearly
show
what
you
consider
confidential
by
marking,
circling,
bracketing,
stamping,
or
some
other
method.
We
will
store
your
confidential
information
as
described
in
40
CFR
part
2.
Also,
we
will
disclose
it
only
as
specified
in
40
CFR
part
2.
(
b)
If
you
send
us
a
second
copy
without
the
confidential
information,
we
will
assume
it
contains
nothing
confidential
whenever
we
need
to
release
information
from
it.
(
c)
If
you
send
us
information
without
claiming
it
is
confidential,
we
may
make
it
available
to
the
public
without
further
notice
to
you,
as
described
in
40
CFR
2.204.
§
1048.820
How
do
I
request
a
hearing?
See
40
CFR
part
1068,
subpart
G,
for
information
related
to
hearings.
Appendix
I
to
Part
1048
Large
Sparkignition
(
SI)
Transient
Cycle
for
Constant
Speed
Engines
The
following
table
shows
the
transient
duty
cycle
for
constant
speed
engines,
as
described
in
§
1048.510:
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
1
....................
58
5
2
....................
58
5
3
....................
58
5
4
....................
58
5
5
....................
58
5
6
....................
58
5
7
....................
58
5
8
....................
58
5
9
....................
58
5
10
..................
58
5
11
..................
58
5
12
..................
65
8
13
..................
72
9
14
..................
79
12
15
..................
86
14
16
..................
93
16
17
..................
93
16
18
..................
93
16
19
..................
93
16
20
..................
93
16
21
..................
93
16
22
..................
93
16
23
..................
93
16
24
..................
93
31
25
..................
93
30
26
..................
93
27
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
27
..................
93
23
28
..................
93
24
29
..................
93
21
30
..................
93
20
31
..................
93
18
32
..................
93
16
33
..................
93
18
34
..................
93
16
35
..................
93
17
36
..................
93
20
37
..................
93
20
38
..................
93
22
39
..................
93
20
40
..................
93
17
41
..................
93
17
42
..................
93
17
43
..................
93
16
44
..................
93
18
45
..................
93
18
46
..................
93
21
47
..................
93
21
48
..................
93
18
49
..................
94
24
50
..................
93
28
51
..................
93
23
52
..................
93
19
53
..................
93
20
54
..................
93
20
55
..................
93
29
56
..................
93
23
57
..................
93
25
58
..................
93
23
59
..................
93
23
60
..................
93
23
61
..................
93
22
62
..................
93
21
63
..................
93
22
64
..................
93
30
65
..................
93
33
66
..................
93
25
67
..................
93
29
68
..................
93
27
69
..................
93
23
70
..................
93
21
71
..................
93
21
72
..................
93
19
73
..................
93
20
74
..................
93
24
75
..................
93
23
76
..................
93
21
77
..................
93
44
78
..................
93
34
79
..................
93
28
80
..................
93
37
81
..................
93
29
82
..................
93
27
83
..................
93
33
84
..................
93
28
85
..................
93
22
86
..................
96
30
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
87
..................
95
25
88
..................
95
17
89
..................
95
13
90
..................
95
10
91
..................
95
9
92
..................
95
8
93
..................
95
7
94
..................
95
7
95
..................
95
6
96
..................
95
6
97
..................
93
37
98
..................
93
35
99
..................
93
29
100
................
93
23
101
................
93
23
102
................
93
21
103
................
93
20
104
................
93
29
105
................
93
27
106
................
93
26
107
................
93
35
108
................
93
43
109
................
95
35
110
................
95
24
111
................
95
17
112
................
95
13
113
................
95
10
114
................
95
9
115
................
95
8
116
................
95
7
117
................
95
7
118
................
95
6
119
................
93
36
120
................
93
30
121
................
93
25
122
................
93
21
123
................
93
22
124
................
93
19
125
................
93
34
126
................
93
36
127
................
93
31
128
................
93
26
129
................
93
27
130
................
93
22
131
................
93
22
132
................
93
18
133
................
93
18
134
................
93
19
135
................
93
19
136
................
93
23
137
................
93
22
138
................
93
20
139
................
93
23
140
................
93
20
141
................
93
18
142
................
93
18
143
................
93
16
144
................
93
19
145
................
94
25
146
................
93
30
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217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
147
................
93
29
148
................
93
23
149
................
93
24
150
................
93
22
151
................
94
20
152
................
93
17
153
................
93
16
154
................
93
16
155
................
93
15
156
................
93
17
157
................
93
18
158
................
93
20
159
................
93
21
160
................
93
18
161
................
93
17
162
................
92
54
163
................
93
38
164
................
93
29
165
................
93
24
166
................
93
24
167
................
93
24
168
................
93
23
169
................
93
20
170
................
93
20
171
................
93
18
172
................
93
19
173
................
93
19
174
................
93
16
175
................
93
16
176
................
93
16
177
................
93
18
178
................
93
21
179
................
93
20
180
................
93
20
181
................
93
17
182
................
93
19
183
................
93
17
184
................
93
18
185
................
93
16
186
................
93
16
187
................
93
16
188
................
93
17
189
................
93
16
190
................
93
17
191
................
93
18
192
................
93
17
193
................
93
16
194
................
93
17
195
................
93
17
196
................
93
22
197
................
93
19
198
................
93
19
199
................
95
21
200
................
95
16
201
................
95
12
202
................
95
10
203
................
96
8
204
................
96
7
205
................
95
7
206
................
96
7
207
................
95
6
208
................
96
6
209
................
96
6
210
................
88
6
211
................
89
48
212
................
93
34
213
................
93
27
214
................
93
26
215
................
93
25
216
................
93
22
217
................
93
23
218
................
93
21
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
219
................
93
21
220
................
93
23
221
................
93
23
222
................
93
23
223
................
93
23
224
................
93
23
225
................
93
22
226
................
93
22
227
................
93
24
228
................
93
23
229
................
93
23
230
................
93
21
231
................
93
20
232
................
93
20
233
................
93
20
234
................
93
22
235
................
93
26
236
................
93
22
237
................
93
20
238
................
93
18
239
................
93
22
240
................
93
20
241
................
94
27
242
................
93
22
243
................
93
23
244
................
93
21
245
................
93
22
246
................
95
22
247
................
95
16
248
................
95
12
249
................
95
10
250
................
95
9
251
................
95
8
252
................
96
7
253
................
95
7
254
................
95
6
255
................
92
42
256
................
93
36
257
................
93
33
258
................
92
60
259
................
93
48
260
................
93
36
261
................
93
30
262
................
93
28
263
................
93
24
264
................
93
24
265
................
93
23
266
................
93
23
267
................
93
25
268
................
93
27
269
................
93
29
270
................
93
26
271
................
93
26
272
................
93
21
273
................
93
23
274
................
93
23
275
................
94
23
276
................
93
40
277
................
94
67
278
................
93
46
279
................
93
38
280
................
93
29
281
................
93
28
282
................
93
27
283
................
93
29
284
................
93
28
285
................
94
34
286
................
93
31
287
................
93
30
288
................
94
42
289
................
93
31
290
................
93
29
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
291
................
93
27
292
................
93
23
293
................
93
23
294
................
93
20
295
................
93
20
296
................
93
23
297
................
93
23
298
................
93
24
299
................
93
25
300
................
93
20
301
................
93
25
302
................
93
23
303
................
93
23
304
................
93
24
305
................
93
28
306
................
93
23
307
................
93
24
308
................
93
34
309
................
93
31
310
................
93
35
311
................
93
31
312
................
93
32
313
................
93
31
314
................
93
30
315
................
93
23
316
................
93
23
317
................
93
36
318
................
93
32
319
................
93
25
320
................
93
31
321
................
93
33
322
................
93
31
323
................
93
27
324
................
93
24
325
................
93
19
326
................
96
21
327
................
96
16
328
................
95
12
329
................
95
10
330
................
95
8
331
................
95
8
332
................
95
7
333
................
95
7
334
................
95
6
335
................
95
6
336
................
95
6
337
................
87
6
338
................
57
6
339
................
58
6
340
................
58
6
341
................
58
6
342
................
58
6
343
................
58
6
344
................
58
6
345
................
58
6
346
................
58
6
347
................
58
6
348
................
58
6
349
................
58
6
350
................
58
6
351
................
58
6
352
................
95
73
353
................
93
65
354
................
93
52
355
................
93
38
356
................
93
30
357
................
93
31
358
................
93
26
359
................
93
21
360
................
93
22
361
................
93
26
362
................
93
23
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FR\
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08NOR2.
SGM
08NOR2
68371
Federal
Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
363
................
93
19
364
................
93
27
365
................
93
42
366
................
93
29
367
................
94
25
368
................
94
26
369
................
94
29
370
................
93
28
371
................
93
23
372
................
93
21
373
................
93
26
374
................
93
23
375
................
93
20
376
................
94
23
377
................
93
18
378
................
93
19
379
................
93
23
380
................
93
19
381
................
93
16
382
................
93
25
383
................
93
22
384
................
93
20
385
................
93
25
386
................
94
28
387
................
93
23
388
................
93
23
389
................
93
25
390
................
93
23
391
................
93
20
392
................
93
19
393
................
93
24
394
................
93
20
395
................
93
18
396
................
93
21
397
................
95
22
398
................
96
16
399
................
96
12
400
................
95
10
401
................
96
9
402
................
95
8
403
................
96
7
404
................
96
7
405
................
96
6
406
................
96
6
407
................
95
6
408
................
91
6
409
................
58
6
410
................
58
6
411
................
58
6
412
................
58
6
413
................
58
6
414
................
58
6
415
................
58
6
416
................
58
6
417
................
58
6
418
................
58
6
419
................
58
6
420
................
58
6
421
................
58
6
422
................
58
6
423
................
58
6
424
................
58
6
425
................
58
6
426
................
58
6
427
................
58
6
428
................
58
6
429
................
58
6
430
................
58
6
431
................
58
6
432
................
58
6
433
................
58
6
434
................
58
6
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
435
................
58
6
436
................
58
6
437
................
58
6
438
................
58
6
439
................
58
6
440
................
58
6
441
................
58
6
442
................
58
6
443
................
93
66
444
................
93
48
445
................
93
40
446
................
93
34
447
................
93
28
448
................
93
23
449
................
93
28
450
................
93
27
451
................
93
23
452
................
93
19
453
................
93
25
454
................
93
24
455
................
93
22
456
................
93
31
457
................
93
36
458
................
93
28
459
................
93
25
460
................
93
35
461
................
93
34
462
................
93
29
463
................
93
37
464
................
93
36
465
................
93
38
466
................
93
31
467
................
93
29
468
................
93
34
469
................
93
36
470
................
93
34
471
................
93
31
472
................
93
26
473
................
93
21
474
................
94
16
475
................
96
19
476
................
96
15
477
................
95
11
478
................
96
10
479
................
95
8
480
................
95
7
481
................
95
7
482
................
96
7
483
................
96
6
484
................
96
6
485
................
95
6
486
................
85
6
487
................
56
74
488
................
93
52
489
................
93
42
490
................
93
36
491
................
93
35
492
................
93
33
493
................
93
38
494
................
93
40
495
................
93
29
496
................
93
23
497
................
93
23
498
................
93
24
499
................
93
24
500
................
93
20
501
................
93
19
502
................
93
16
503
................
93
21
504
................
93
23
505
................
93
24
506
................
93
22
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
507
................
93
18
508
................
93
21
509
................
95
18
510
................
95
20
511
................
95
15
512
................
96
11
513
................
95
10
514
................
96
8
515
................
95
7
516
................
95
7
517
................
95
7
518
................
95
6
519
................
96
6
520
................
96
6
521
................
83
6
522
................
56
6
523
................
58
6
524
................
72
54
525
................
94
51
526
................
93
42
527
................
93
42
528
................
93
31
529
................
93
25
530
................
93
21
531
................
93
17
532
................
93
15
533
................
93
15
534
................
93
16
535
................
93
15
536
................
93
14
537
................
93
15
538
................
93
16
539
................
94
15
540
................
93
45
541
................
93
45
542
................
93
41
543
................
93
33
544
................
93
26
545
................
93
21
546
................
93
20
547
................
93
17
548
................
93
16
549
................
93
17
550
................
93
16
551
................
93
14
552
................
93
16
553
................
93
15
554
................
93
14
555
................
93
16
556
................
93
15
557
................
93
14
558
................
93
13
559
................
93
14
560
................
93
14
561
................
93
15
562
................
93
17
563
................
93
17
564
................
93
22
565
................
93
22
566
................
93
19
567
................
93
19
568
................
93
20
569
................
93
18
570
................
93
20
571
................
93
20
572
................
93
42
573
................
93
32
574
................
93
25
575
................
93
26
576
................
93
23
577
................
93
21
578
................
93
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Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
579
................
93
19
580
................
93
21
581
................
93
20
582
................
93
20
583
................
93
20
584
................
93
18
585
................
93
18
586
................
93
21
587
................
93
19
588
................
93
21
589
................
93
19
590
................
93
19
591
................
93
18
592
................
93
18
593
................
93
17
594
................
93
16
595
................
93
16
596
................
93
15
597
................
93
16
598
................
93
19
599
................
93
52
600
................
93
45
601
................
95
39
602
................
95
39
603
................
95
39
604
................
95
39
605
................
94
30
606
................
95
30
607
................
95
29
608
................
95
24
609
................
94
30
610
................
95
28
611
................
94
25
612
................
94
29
613
................
95
32
614
................
95
33
615
................
95
44
616
................
99
37
617
................
98
27
618
................
98
19
619
................
98
13
620
................
98
11
621
................
98
9
622
................
98
7
623
................
98
7
624
................
98
6
625
................
98
6
626
................
98
6
627
................
98
5
628
................
69
6
629
................
49
5
630
................
51
5
631
................
51
5
632
................
51
5
633
................
51
6
634
................
51
6
635
................
51
6
636
................
51
6
637
................
51
5
638
................
51
5
639
................
51
5
640
................
51
5
641
................
51
6
642
................
51
6
643
................
51
6
644
................
51
6
645
................
51
5
646
................
51
6
647
................
51
5
648
................
51
6
649
................
51
5
650
................
96
35
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
651
................
95
29
652
................
95
26
653
................
95
31
654
................
95
34
655
................
95
29
656
................
95
29
657
................
95
30
658
................
95
24
659
................
95
19
660
................
95
23
661
................
95
21
662
................
95
22
663
................
95
19
664
................
95
18
665
................
95
20
666
................
94
60
667
................
95
48
668
................
95
39
669
................
95
36
670
................
95
27
671
................
95
22
672
................
95
19
673
................
95
22
674
................
95
19
675
................
94
17
676
................
95
27
677
................
95
24
678
................
98
19
679
................
98
19
680
................
98
14
681
................
98
11
682
................
98
9
683
................
98
8
684
................
98
7
685
................
98
6
686
................
98
6
687
................
98
6
688
................
98
6
689
................
98
5
690
................
81
5
691
................
49
5
692
................
78
48
693
................
95
37
694
................
95
31
695
................
94
32
696
................
94
34
697
................
95
29
698
................
95
25
699
................
94
26
700
................
95
28
701
................
95
27
702
................
94
28
703
................
95
30
704
................
95
27
705
................
95
26
706
................
95
27
707
................
95
25
708
................
95
26
709
................
95
25
710
................
95
23
711
................
95
20
712
................
95
23
713
................
95
20
714
................
95
18
715
................
94
22
716
................
95
19
717
................
95
23
718
................
95
27
719
................
95
26
720
................
95
23
721
................
95
20
722
................
99
23
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
723
................
98
20
724
................
98
14
725
................
98
11
726
................
98
9
727
................
98
8
728
................
98
7
729
................
98
6
730
................
98
6
731
................
98
6
732
................
98
5
733
................
98
5
734
................
73
6
735
................
49
5
736
................
50
77
737
................
95
39
738
................
95
30
739
................
95
28
740
................
94
31
741
................
95
36
742
................
95
36
743
................
95
30
744
................
95
26
745
................
95
27
746
................
95
22
747
................
95
18
748
................
95
19
749
................
95
25
750
................
94
25
751
................
95
21
752
................
95
22
753
................
95
27
754
................
95
27
755
................
95
27
756
................
95
24
757
................
94
20
758
................
94
23
759
................
94
26
760
................
95
25
761
................
95
25
762
................
95
21
763
................
95
28
764
................
94
39
765
................
95
32
766
................
95
24
767
................
95
19
768
................
98
20
769
................
98
17
770
................
98
12
771
................
98
10
772
................
98
8
773
................
98
7
774
................
98
6
775
................
98
6
776
................
95
61
777
................
94
51
778
................
95
40
779
................
94
35
780
................
94
36
781
................
94
32
782
................
95
24
783
................
94
19
784
................
94
19
785
................
95
19
786
................
95
19
787
................
94
18
788
................
94
20
789
................
94
23
790
................
94
22
791
................
95
23
792
................
94
20
793
................
94
18
794
................
95
16
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FR\
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08NOR2.
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Federal
Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
795
................
95
17
796
................
94
16
797
................
94
16
798
................
94
17
799
................
94
18
800
................
94
21
801
................
95
21
802
................
94
19
803
................
95
18
804
................
94
19
805
................
95
22
806
................
95
21
807
................
95
19
808
................
94
20
809
................
94
22
810
................
94
22
811
................
94
22
812
................
95
23
813
................
94
22
814
................
95
22
815
................
95
19
816
................
95
16
817
................
95
14
818
................
95
18
819
................
95
18
820
................
94
20
821
................
94
22
822
................
94
19
823
................
95
18
824
................
95
17
825
................
95
19
826
................
95
19
827
................
95
19
828
................
94
19
829
................
94
21
830
................
94
19
831
................
94
17
832
................
94
18
833
................
94
21
834
................
94
19
835
................
95
18
836
................
95
19
837
................
95
17
838
................
94
15
839
................
94
17
840
................
95
19
841
................
94
22
842
................
94
21
843
................
94
18
844
................
94
16
845
................
95
14
846
................
95
14
847
................
94
19
848
................
95
20
849
................
95
23
850
................
98
23
851
................
98
22
852
................
98
16
853
................
98
12
854
................
98
9
855
................
98
8
856
................
98
7
857
................
98
6
858
................
98
6
859
................
98
6
860
................
98
5
861
................
98
5
862
................
80
5
863
................
49
5
864
................
51
5
865
................
51
5
866
................
51
6
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
867
................
51
6
868
................
51
6
869
................
51
6
870
................
51
5
871
................
51
6
872
................
51
7
873
................
96
45
874
................
94
44
875
................
94
34
876
................
94
41
877
................
95
44
878
................
94
32
879
................
95
26
880
................
94
20
881
................
95
29
882
................
95
27
883
................
95
21
884
................
95
34
885
................
95
31
886
................
94
26
887
................
95
22
888
................
95
23
889
................
95
19
890
................
94
18
891
................
94
20
892
................
94
26
893
................
95
29
894
................
94
32
895
................
95
26
896
................
95
34
897
................
95
30
898
................
95
24
899
................
95
19
900
................
94
17
901
................
94
16
902
................
98
19
903
................
98
17
904
................
98
12
905
................
98
10
906
................
98
8
907
................
98
7
908
................
98
6
909
................
98
6
910
................
98
6
911
................
98
5
912
................
98
5
913
................
98
5
914
................
69
5
915
................
49
5
916
................
51
5
917
................
51
6
918
................
51
6
919
................
69
75
920
................
95
70
921
................
95
57
922
................
94
49
923
................
94
38
924
................
95
43
925
................
94
51
926
................
94
41
927
................
98
42
928
................
95
89
929
................
95
66
930
................
94
52
931
................
95
41
932
................
95
34
933
................
95
34
934
................
94
30
935
................
94
30
936
................
95
29
937
................
94
28
938
................
95
24
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
939
................
94
34
940
................
95
26
941
................
94
36
942
................
95
27
943
................
95
25
944
................
95
26
945
................
94
21
946
................
94
19
947
................
98
21
948
................
93
53
949
................
94
45
950
................
94
35
951
................
95
28
952
................
95
23
953
................
95
20
954
................
95
17
955
................
94
19
956
................
94
18
957
................
94
18
958
................
94
18
959
................
94
19
960
................
97
17
961
................
98
19
962
................
98
14
963
................
98
11
964
................
98
9
965
................
98
7
966
................
98
7
967
................
98
6
968
................
98
6
969
................
98
6
970
................
98
5
971
................
98
5
972
................
82
5
973
................
49
5
974
................
51
6
975
................
51
6
976
................
51
6
977
................
51
5
978
................
51
6
979
................
72
58
980
................
94
36
981
................
95
28
982
................
95
24
983
................
95
25
984
................
95
26
985
................
94
30
986
................
94
26
987
................
95
34
988
................
95
57
989
................
95
45
990
................
94
37
991
................
95
34
992
................
95
27
993
................
95
27
994
................
95
29
995
................
98
22
996
................
94
84
997
................
94
74
998
................
95
62
999
................
94
51
1000
..............
95
50
1001
..............
95
81
1002
..............
94
65
1003
..............
95
49
1004
..............
94
56
1005
..............
95
65
1006
..............
94
59
1007
..............
99
58
1008
..............
98
41
1009
..............
98
27
1010
..............
98
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E:\
FR\
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08NOR2.
SGM
08NOR2
68374
Federal
Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
1011
..............
98
13
1012
..............
98
11
1013
..............
98
9
1014
..............
98
8
1015
..............
98
7
1016
..............
98
6
1017
..............
98
6
1018
..............
98
6
1019
..............
71
6
1020
..............
49
5
1021
..............
51
6
1022
..............
51
6
1023
..............
51
6
1024
..............
51
6
1025
..............
51
6
1026
..............
51
6
1027
..............
51
6
1028
..............
51
6
1029
..............
51
6
1030
..............
51
6
1031
..............
51
5
1032
..............
51
6
1033
..............
51
5
1034
..............
51
6
1035
..............
51
6
1036
..............
51
6
1037
..............
51
5
1038
..............
51
5
1039
..............
51
6
1040
..............
51
6
1041
..............
69
59
1042
..............
94
48
1043
..............
95
34
1044
..............
95
29
1045
..............
95
26
1046
..............
94
27
1047
..............
95
31
1048
..............
95
26
1049
..............
95
34
1050
..............
95
29
1051
..............
95
31
1052
..............
95
29
1053
..............
95
35
1054
..............
95
38
1055
..............
94
41
1056
..............
95
28
1057
..............
95
36
1058
..............
94
30
1059
..............
94
26
1060
..............
94
33
1061
..............
95
34
1062
..............
95
27
1063
..............
98
26
1064
..............
98
19
1065
..............
98
13
1066
..............
98
11
1067
..............
98
9
1068
..............
98
7
1069
..............
98
7
1070
..............
98
6
1071
..............
98
6
1072
..............
98
6
1073
..............
98
5
1074
..............
89
6
1075
..............
49
5
1076
..............
51
6
1077
..............
51
6
1078
..............
51
6
1079
..............
51
6
1080
..............
51
6
1081
..............
51
6
1082
..............
51
6
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
1083
..............
50
6
1084
..............
51
6
1085
..............
51
6
1086
..............
51
6
1087
..............
51
6
1088
..............
51
6
1089
..............
51
6
1090
..............
51
6
1091
..............
56
74
1092
..............
95
56
1093
..............
94
49
1094
..............
95
47
1095
..............
94
43
1096
..............
94
33
1097
..............
95
50
1098
..............
94
40
1099
..............
95
33
1100
..............
95
24
1101
..............
94
22
1102
..............
94
22
1103
..............
94
25
1104
..............
95
27
1105
..............
95
32
1106
..............
94
29
1107
..............
94
26
1108
..............
94
26
1109
..............
94
24
1110
..............
98
52
1111
..............
94
41
1112
..............
99
35
1113
..............
95
58
1114
..............
95
58
1115
..............
98
57
1116
..............
98
38
1117
..............
98
26
1118
..............
93
63
1119
..............
94
59
1120
..............
98
100
1121
..............
94
73
1122
..............
98
53
1123
..............
94
76
1124
..............
95
61
1125
..............
94
49
1126
..............
94
37
1127
..............
97
50
1128
..............
98
36
1129
..............
98
25
1130
..............
98
18
1131
..............
98
12
1132
..............
98
10
1133
..............
98
8
1134
..............
98
7
1135
..............
98
7
1136
..............
98
6
1137
..............
98
6
1138
..............
98
6
1139
..............
80
6
1140
..............
49
6
1141
..............
78
61
1142
..............
95
50
1143
..............
94
43
1144
..............
94
42
1145
..............
94
31
1146
..............
95
30
1147
..............
95
34
1148
..............
95
28
1149
..............
95
27
1150
..............
94
27
1151
..............
95
31
1152
..............
95
42
1153
..............
94
41
1154
..............
95
37
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
1155
..............
95
43
1156
..............
95
34
1157
..............
95
31
1158
..............
95
27
1159
..............
95
23
1160
..............
95
27
1161
..............
96
38
1162
..............
95
40
1163
..............
95
39
1164
..............
95
26
1165
..............
95
33
1166
..............
94
28
1167
..............
94
34
1168
..............
98
73
1169
..............
95
49
1170
..............
95
51
1171
..............
94
55
1172
..............
95
48
1173
..............
95
35
1174
..............
95
39
1175
..............
95
39
1176
..............
94
41
1177
..............
95
30
1178
..............
95
23
1179
..............
94
19
1180
..............
95
25
1181
..............
94
29
1182
..............
98
27
1183
..............
95
89
1184
..............
95
74
1185
..............
94
60
1186
..............
94
48
1187
..............
94
41
1188
..............
94
29
1189
..............
94
24
1190
..............
95
19
1191
..............
94
21
1192
..............
95
29
1193
..............
95
28
1194
..............
95
27
1195
..............
94
23
1196
..............
95
25
1197
..............
95
26
1198
..............
94
22
1199
..............
95
19
1200
..............
94
17
Appendix
II
to
Part
1048
Large
Sparkignition
(
SI)
Composite
Transient
Cycle
The
following
table
shows
the
transient
duty
cycle
for
engines
that
are
not
constant
speed
engines,
as
described
in
§
1048.510:
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
0
....................
0
0
1
....................
0
0
2
....................
0
0
3
....................
0
0
4
....................
0
0
5
....................
0
0
6
....................
0
0
7
....................
0
0
8
....................
0
0
9
....................
1
8
10
..................
6
54
11
..................
8
61
12
..................
34
59
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FR\
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08NOR2
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Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
13
..................
22
46
14
..................
5
51
15
..................
18
51
16
..................
31
50
17
..................
30
56
18
..................
31
49
19
..................
25
66
20
..................
58
55
21
..................
43
31
22
..................
16
45
23
..................
24
38
24
..................
24
27
25
..................
30
33
26
..................
45
65
27
..................
50
49
28
..................
23
42
29
..................
13
42
30
..................
9
45
31
..................
23
30
32
..................
37
45
33
..................
44
50
34
..................
49
52
35
..................
55
49
36
..................
61
46
37
..................
66
38
38
..................
42
33
39
..................
17
41
40
..................
17
37
41
..................
7
50
42
..................
20
32
43
..................
5
55
44
..................
30
42
45
..................
44
53
46
..................
45
56
47
..................
41
52
48
..................
24
41
49
..................
15
40
50
..................
11
44
51
..................
32
31
52
..................
38
54
53
..................
38
47
54
..................
9
55
55
..................
10
50
56
..................
33
55
57
..................
48
56
58
..................
49
47
59
..................
33
44
60
..................
52
43
61
..................
55
43
62
..................
59
38
63
..................
44
28
64
..................
24
37
65
..................
12
44
66
..................
9
47
67
..................
12
52
68
..................
34
21
69
..................
29
44
70
..................
44
54
71
..................
54
62
72
..................
62
57
73
..................
72
56
74
..................
88
71
75
..................
100
69
76
..................
100
34
77
..................
100
42
78
..................
100
54
79
..................
100
58
80
..................
100
38
81
..................
83
17
82
..................
61
15
83
..................
43
22
84
..................
24
35
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
85
..................
16
39
86
..................
15
45
87
..................
32
34
88
..................
14
42
89
..................
8
48
90
..................
5
51
91
..................
10
41
92
..................
12
37
93
..................
4
47
94
..................
3
49
95
..................
3
50
96
..................
4
49
97
..................
4
48
98
..................
8
43
99
..................
2
51
100
................
5
46
101
................
8
41
102
................
4
47
103
................
3
49
104
................
6
45
105
................
3
48
106
................
10
42
107
................
18
27
108
................
3
50
109
................
11
41
110
................
34
29
111
................
51
57
112
................
67
63
113
................
61
32
114
................
44
31
115
................
48
54
116
................
69
65
117
................
85
65
118
................
81
29
119
................
74
21
120
................
62
23
121
................
76
58
122
................
96
75
123
................
100
77
124
................
100
27
125
................
100
79
126
................
100
79
127
................
100
81
128
................
100
57
129
................
99
52
130
................
81
35
131
................
69
29
132
................
47
22
133
................
34
28
134
................
27
37
135
................
83
60
136
................
100
74
137
................
100
7
138
................
100
2
139
................
70
18
140
................
23
39
141
................
5
54
142
................
11
40
143
................
11
34
144
................
11
41
145
................
19
25
146
................
16
32
147
................
20
31
148
................
21
38
149
................
21
42
150
................
9
51
151
................
4
49
152
................
2
51
153
................
1
58
154
................
21
57
155
................
29
47
156
................
33
45
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
157
................
16
49
158
................
38
45
159
................
37
43
160
................
35
42
161
................
39
43
162
................
51
49
163
................
59
55
164
................
65
54
165
................
76
62
166
................
84
59
167
................
83
29
168
................
67
35
169
................
84
54
170
................
90
58
171
................
93
43
172
................
90
29
173
................
66
19
174
................
52
16
175
................
49
17
176
................
56
38
177
................
73
71
178
................
86
80
179
................
96
75
180
................
89
27
181
................
66
17
182
................
50
18
183
................
36
25
184
................
36
24
185
................
38
40
186
................
40
50
187
................
27
48
188
................
19
48
189
................
23
50
190
................
19
45
191
................
6
51
192
................
24
48
193
................
49
67
194
................
47
49
195
................
22
44
196
................
25
40
197
................
38
54
198
................
43
55
199
................
40
52
200
................
14
49
201
................
11
45
202
................
7
48
203
................
26
41
204
................
41
59
205
................
53
60
206
................
44
54
207
................
22
40
208
................
24
41
209
................
32
53
210
................
44
74
211
................
57
25
212
................
22
49
213
................
29
45
214
................
19
37
215
................
14
43
216
................
36
40
217
................
43
63
218
................
42
49
219
................
15
50
220
................
19
44
221
................
47
59
222
................
67
80
223
................
76
74
224
................
87
66
225
................
98
61
226
................
100
38
227
................
97
27
228
................
100
53
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E:\
FR\
FM\
08NOR2.
SGM
08NOR2
68376
Federal
Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
229
................
100
72
230
................
100
49
231
................
100
4
232
................
100
13
233
................
87
15
234
................
53
26
235
................
33
27
236
................
39
19
237
................
51
33
238
................
67
54
239
................
83
60
240
................
95
52
241
................
100
50
242
................
100
36
243
................
100
25
244
................
85
16
245
................
62
16
246
................
40
26
247
................
56
39
248
................
81
75
249
................
98
86
250
................
100
76
251
................
100
51
252
................
100
78
253
................
100
83
254
................
100
100
255
................
100
66
256
................
100
85
257
................
100
72
258
................
100
45
259
................
98
58
260
................
60
30
261
................
43
32
262
................
71
36
263
................
44
32
264
................
24
38
265
................
42
17
266
................
22
51
267
................
13
53
268
................
23
45
269
................
29
50
270
................
28
42
271
................
21
55
272
................
34
57
273
................
44
47
274
................
19
46
275
................
13
44
276
................
25
36
277
................
43
51
278
................
55
73
279
................
68
72
280
................
76
63
281
................
80
45
282
................
83
40
283
................
78
26
284
................
60
20
285
................
47
19
286
................
52
25
287
................
36
30
288
................
40
26
289
................
45
34
290
................
47
35
291
................
42
28
292
................
46
38
293
................
48
44
294
................
68
61
295
................
70
47
296
................
48
28
297
................
42
22
298
................
31
29
299
................
22
35
300
................
28
28
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
301
................
46
46
302
................
62
69
303
................
76
81
304
................
88
85
305
................
98
81
306
................
100
74
307
................
100
13
308
................
100
11
309
................
100
17
310
................
99
3
311
................
80
7
312
................
62
11
313
................
63
11
314
................
64
16
315
................
69
43
316
................
81
67
317
................
93
74
318
................
100
72
319
................
94
27
320
................
73
15
321
................
40
33
322
................
40
52
323
................
50
50
324
................
11
53
325
................
12
45
326
................
5
50
327
................
1
55
328
................
7
55
329
................
62
60
330
................
80
28
331
................
23
37
332
................
39
58
333
................
47
24
334
................
59
51
335
................
58
68
336
................
36
52
337
................
18
42
338
................
36
52
339
................
59
73
340
................
72
85
341
................
85
92
342
................
99
90
343
................
100
72
344
................
100
18
345
................
100
76
346
................
100
64
347
................
100
87
348
................
100
97
349
................
100
84
350
................
100
100
351
................
100
91
352
................
100
83
353
................
100
93
354
................
100
100
355
................
94
43
356
................
72
10
357
................
77
3
358
................
48
2
359
................
29
5
360
................
59
19
361
................
63
5
362
................
35
2
363
................
24
3
364
................
28
2
365
................
36
16
366
................
54
23
367
................
60
10
368
................
33
1
369
................
23
0
370
................
16
0
371
................
11
0
372
................
20
0
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
373
................
25
2
374
................
40
3
375
................
33
4
376
................
34
5
377
................
46
7
378
................
57
10
379
................
66
11
380
................
75
14
381
................
79
11
382
................
80
16
383
................
92
21
384
................
99
16
385
................
83
2
386
................
71
2
387
................
69
4
388
................
67
4
389
................
74
16
390
................
86
25
391
................
97
28
392
................
100
15
393
................
83
2
394
................
62
4
395
................
40
6
396
................
49
10
397
................
36
5
398
................
27
4
399
................
29
3
400
................
22
2
401
................
13
3
402
................
37
36
403
................
90
26
404
................
41
2
405
................
25
2
406
................
29
2
407
................
38
7
408
................
50
13
409
................
55
10
410
................
29
3
411
................
24
7
412
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51
16
413
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62
15
414
................
72
35
415
................
91
74
416
................
100
73
417
................
100
8
418
................
98
11
419
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100
59
420
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100
98
421
................
100
99
422
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100
75
423
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100
95
424
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100
100
425
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100
97
426
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100
90
427
................
100
86
428
................
100
82
429
................
97
43
430
................
70
16
431
................
50
20
432
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42
33
433
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89
64
434
................
89
77
435
................
99
95
436
................
100
41
437
................
77
12
438
................
29
37
439
................
16
41
440
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16
38
441
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15
36
442
................
18
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443
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No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
445
................
26
35
446
................
15
45
447
................
21
39
448
................
29
52
449
................
26
46
450
................
27
50
451
................
13
43
452
................
25
36
453
................
37
57
454
................
29
46
455
................
17
39
456
................
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41
457
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38
458
................
28
35
459
................
8
51
460
................
14
36
461
................
17
47
462
................
34
39
463
................
34
57
464
................
11
70
465
................
13
51
466
................
13
68
467
................
38
44
468
................
53
67
469
................
29
69
470
................
19
65
471
................
52
45
472
................
61
79
473
................
29
70
474
................
15
53
475
................
15
60
476
................
52
40
477
................
50
61
478
................
13
74
479
................
46
51
480
................
60
73
481
................
33
84
482
................
31
63
483
................
41
42
484
................
26
69
485
................
23
65
486
................
48
49
487
................
28
57
488
................
16
67
489
................
39
48
490
................
47
73
491
................
35
87
492
................
26
73
493
................
30
61
494
................
34
49
495
................
35
66
496
................
56
47
497
................
49
64
498
................
59
64
499
................
42
69
500
................
6
77
501
................
5
59
502
................
17
59
503
................
45
53
504
................
21
62
505
................
31
60
506
................
53
68
507
................
48
79
508
................
45
61
509
................
51
47
510
................
41
48
511
................
26
58
512
................
21
62
513
................
50
52
514
................
39
65
515
................
23
65
516
................
42
62
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
517
................
57
80
518
................
66
81
519
................
64
62
520
................
45
42
521
................
33
42
522
................
27
57
523
................
31
59
524
................
41
53
525
................
45
72
526
................
48
73
527
................
46
90
528
................
56
76
529
................
64
76
530
................
69
64
531
................
72
59
532
................
73
58
533
................
71
56
534
................
66
48
535
................
61
50
536
................
55
56
537
................
52
52
538
................
54
49
539
................
61
50
540
................
64
54
541
................
67
54
542
................
68
52
543
................
60
53
544
................
52
50
545
................
45
49
546
................
38
45
547
................
32
45
548
................
26
53
549
................
23
56
550
................
30
49
551
................
33
55
552
................
35
59
553
................
33
65
554
................
30
67
555
................
28
59
556
................
25
58
557
................
23
56
558
................
22
57
559
................
19
63
560
................
14
63
561
................
31
61
562
................
35
62
563
................
21
80
564
................
28
65
565
................
7
74
566
................
23
54
567
................
38
54
568
................
14
78
569
................
38
58
570
................
52
75
571
................
59
81
572
................
66
69
573
................
54
44
574
................
48
34
575
................
44
33
576
................
40
40
577
................
28
58
578
................
27
63
579
................
35
45
580
................
20
66
581
................
15
60
582
................
10
52
583
................
22
56
584
................
30
62
585
................
21
67
586
................
29
53
587
................
41
56
588
................
15
67
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
589
................
24
56
590
................
42
69
591
................
39
83
592
................
40
73
593
................
35
67
594
................
32
61
595
................
30
65
596
................
30
72
597
................
48
51
598
................
66
58
599
................
62
71
600
................
36
63
601
................
17
59
602
................
16
50
603
................
16
62
604
................
34
48
605
................
51
66
606
................
35
74
607
................
15
56
608
................
19
54
609
................
43
65
610
................
52
80
611
................
52
83
612
................
49
57
613
................
48
46
614
................
37
36
615
................
25
44
616
................
14
53
617
................
13
64
618
................
23
56
619
................
21
63
620
................
18
67
621
................
20
54
622
................
16
67
623
................
26
56
624
................
41
65
625
................
28
62
626
................
19
60
627
................
33
56
628
................
37
70
629
................
24
79
630
................
28
57
631
................
40
57
632
................
40
58
633
................
28
44
634
................
25
41
635
................
29
53
636
................
31
55
637
................
26
64
638
................
20
50
639
................
16
53
640
................
11
54
641
................
13
53
642
................
23
50
643
................
32
59
644
................
36
63
645
................
33
59
646
................
24
52
647
................
20
52
648
................
22
55
649
................
30
53
650
................
37
59
651
................
41
58
652
................
36
54
653
................
29
49
654
................
24
53
655
................
14
57
656
................
10
54
657
................
9
55
658
................
10
57
659
................
13
55
660
................
15
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FR\
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08NOR2.
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08NOR2
68378
Federal
Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
661
................
31
57
662
................
19
69
663
................
14
59
664
................
33
57
665
................
41
65
666
................
39
64
667
................
39
59
668
................
39
51
669
................
28
41
670
................
19
49
671
................
27
54
672
................
37
63
673
................
32
74
674
................
16
70
675
................
12
67
676
................
13
60
677
................
17
56
678
................
15
62
679
................
25
47
680
................
27
64
681
................
14
71
682
................
5
65
683
................
6
57
684
................
6
57
685
................
15
52
686
................
22
61
687
................
14
77
688
................
12
67
689
................
12
62
690
................
14
59
691
................
15
58
692
................
18
55
693
................
22
53
694
................
19
69
695
................
14
67
696
................
9
63
697
................
8
56
698
................
17
49
699
................
25
55
700
................
14
70
701
................
12
60
702
................
22
57
703
................
27
67
704
................
29
68
705
................
34
62
706
................
35
61
707
................
28
78
708
................
11
71
709
................
4
58
710
................
5
58
711
................
10
56
712
................
20
63
713
................
13
76
714
................
11
65
715
................
9
60
716
................
7
55
717
................
8
53
718
................
10
60
719
................
28
53
720
................
12
73
721
................
4
64
722
................
4
61
723
................
4
61
724
................
10
56
725
................
8
61
726
................
20
56
727
................
32
62
728
................
33
66
729
................
34
73
730
................
31
61
731
................
33
55
732
................
33
60
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
733
................
31
59
734
................
29
58
735
................
31
53
736
................
33
51
737
................
33
48
738
................
27
44
739
................
21
52
740
................
13
57
741
................
12
56
742
................
10
64
743
................
22
47
744
................
15
74
745
................
8
66
746
................
34
47
747
................
18
71
748
................
9
57
749
................
11
55
750
................
12
57
751
................
10
61
752
................
16
53
753
................
12
75
754
................
6
70
755
................
12
55
756
................
24
50
757
................
28
60
758
................
28
64
759
................
23
60
760
................
20
56
761
................
26
50
762
................
28
55
763
................
18
56
764
................
15
52
765
................
11
59
766
................
16
59
767
................
34
54
768
................
16
82
769
................
15
64
770
................
36
53
771
................
45
64
772
................
41
59
773
................
34
50
774
................
27
45
775
................
22
52
776
................
18
55
777
................
26
54
778
................
39
62
779
................
37
71
780
................
32
58
781
................
24
48
782
................
14
59
783
................
7
59
784
................
7
55
785
................
18
49
786
................
40
62
787
................
44
73
788
................
41
68
789
................
35
48
790
................
29
54
791
................
22
69
792
................
46
53
793
................
59
71
794
................
69
68
795
................
75
47
796
................
62
32
797
................
48
35
798
................
27
59
799
................
13
58
800
................
14
54
801
................
21
53
802
................
23
56
803
................
23
57
804
................
23
65
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
805
................
13
65
806
................
9
64
807
................
27
56
808
................
26
78
809
................
40
61
810
................
35
76
811
................
28
66
812
................
23
57
813
................
16
50
814
................
11
53
815
................
9
57
816
................
9
62
817
................
27
57
818
................
42
69
819
................
47
75
820
................
53
67
821
................
61
62
822
................
63
53
823
................
60
54
824
................
56
44
825
................
49
39
826
................
39
35
827
................
30
34
828
................
33
46
829
................
44
56
830
................
50
56
831
................
44
52
832
................
38
46
833
................
33
44
834
................
29
45
835
................
24
46
836
................
18
52
837
................
9
55
838
................
10
54
839
................
20
53
840
................
27
58
841
................
29
59
842
................
30
62
843
................
30
65
844
................
27
66
845
................
32
58
846
................
40
56
847
................
41
57
848
................
18
73
849
................
15
55
850
................
18
50
851
................
17
52
852
................
20
49
853
................
16
62
854
................
4
67
855
................
2
64
856
................
7
54
857
................
10
50
858
................
9
57
859
................
5
62
860
................
12
51
861
................
14
65
862
................
9
64
863
................
31
50
864
................
30
78
865
................
21
65
866
................
14
51
867
................
10
55
868
................
6
59
869
................
7
59
870
................
19
54
871
................
23
61
872
................
24
62
873
................
34
61
874
................
51
67
875
................
60
66
876
................
58
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E:\
FR\
FM\
08NOR2.
SGM
08NOR2
68379
Federal
Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
877
................
60
52
878
................
64
55
879
................
68
51
880
................
63
54
881
................
64
50
882
................
68
58
883
................
73
47
884
................
63
40
885
................
50
38
886
................
29
61
887
................
14
61
888
................
14
53
889
................
42
6
890
................
58
6
891
................
58
6
892
................
77
39
893
................
93
56
894
................
93
44
895
................
93
37
896
................
93
31
897
................
93
25
898
................
93
26
899
................
93
27
900
................
93
25
901
................
93
21
902
................
93
22
903
................
93
24
904
................
93
23
905
................
93
27
906
................
93
34
907
................
93
32
908
................
93
26
909
................
93
31
910
................
93
34
911
................
93
31
912
................
93
33
913
................
93
36
914
................
93
37
915
................
93
34
916
................
93
30
917
................
93
32
918
................
93
35
919
................
93
35
920
................
93
32
921
................
93
28
922
................
93
23
923
................
94
18
924
................
95
18
925
................
96
17
926
................
95
13
927
................
96
10
928
................
95
9
929
................
95
7
930
................
95
7
931
................
96
7
932
................
96
6
933
................
96
6
934
................
95
6
935
................
90
6
936
................
69
43
937
................
76
62
938
................
93
47
939
................
93
39
940
................
93
35
941
................
93
34
942
................
93
36
943
................
93
39
944
................
93
34
945
................
93
26
946
................
93
23
947
................
93
24
948
................
93
24
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
949
................
93
22
950
................
93
19
951
................
93
17
952
................
93
19
953
................
93
22
954
................
93
24
955
................
93
23
956
................
93
20
957
................
93
20
958
................
94
19
959
................
95
19
960
................
95
17
961
................
96
13
962
................
95
10
963
................
96
9
964
................
95
7
965
................
95
7
966
................
95
7
967
................
95
6
968
................
96
6
969
................
96
6
970
................
89
6
971
................
68
6
972
................
57
6
973
................
66
32
974
................
84
52
975
................
93
46
976
................
93
42
977
................
93
36
978
................
93
28
979
................
93
23
980
................
93
19
981
................
93
16
982
................
93
15
983
................
93
16
984
................
93
15
985
................
93
14
986
................
93
15
987
................
93
16
988
................
94
15
989
................
93
32
990
................
93
45
991
................
93
43
992
................
93
37
993
................
93
29
994
................
93
23
995
................
93
20
996
................
93
18
997
................
93
16
998
................
93
17
999
................
93
16
1000
..............
93
15
1001
..............
93
15
1002
..............
93
15
1003
..............
93
14
1004
..............
93
15
1005
..............
93
15
1006
..............
93
14
1007
..............
93
13
1008
..............
93
14
1009
..............
93
14
1010
..............
93
15
1011
..............
93
16
1012
..............
93
17
1013
..............
93
20
1014
..............
93
22
1015
..............
93
20
1016
..............
93
19
1017
..............
93
20
1018
..............
93
19
1019
..............
93
19
1020
..............
93
20
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
1021
..............
93
32
1022
..............
93
37
1023
..............
93
28
1024
..............
93
26
1025
..............
93
24
1026
..............
93
22
1027
..............
93
22
1028
..............
93
21
1029
..............
93
20
1030
..............
93
20
1031
..............
93
20
1032
..............
93
20
1033
..............
93
19
1034
..............
93
18
1035
..............
93
20
1036
..............
93
20
1037
..............
93
20
1038
..............
93
20
1039
..............
93
19
1040
..............
93
18
1041
..............
93
18
1042
..............
93
17
1043
..............
93
16
1044
..............
93
16
1045
..............
93
15
1046
..............
93
16
1047
..............
93
18
1048
..............
93
37
1049
..............
93
48
1050
..............
93
38
1051
..............
93
31
1052
..............
93
26
1053
..............
93
21
1054
..............
93
18
1055
..............
93
16
1056
..............
93
17
1057
..............
93
18
1058
..............
93
19
1059
..............
93
21
1060
..............
93
20
1061
..............
93
18
1062
..............
93
17
1063
..............
93
17
1064
..............
93
18
1065
..............
93
18
1066
..............
93
18
1067
..............
93
19
1068
..............
93
18
1069
..............
93
18
1070
..............
93
20
1071
..............
93
23
1072
..............
93
25
1073
..............
93
25
1074
..............
93
24
1075
..............
93
24
1076
..............
93
22
1077
..............
93
22
1078
..............
93
22
1079
..............
93
19
1080
..............
93
16
1081
..............
95
17
1082
..............
95
37
1083
..............
93
43
1084
..............
93
32
1085
..............
93
27
1086
..............
93
26
1087
..............
93
24
1088
..............
93
22
1089
..............
93
22
1090
..............
93
22
1091
..............
93
23
1092
..............
93
22
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Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
1093
..............
93
22
1094
..............
93
23
1095
..............
93
23
1096
..............
93
23
1097
..............
93
22
1098
..............
93
23
1099
..............
93
23
1100
..............
93
23
1101
..............
93
25
1102
..............
93
27
1103
..............
93
26
1104
..............
93
25
1105
..............
93
27
1106
..............
93
27
1107
..............
93
27
1108
..............
93
24
1109
..............
93
20
1110
..............
93
18
1111
..............
93
17
1112
..............
93
17
1113
..............
93
18
1114
..............
93
18
1115
..............
93
18
1116
..............
93
19
1117
..............
93
22
1118
..............
93
22
1119
..............
93
19
1120
..............
93
17
1121
..............
93
17
1122
..............
93
18
1123
..............
93
18
1124
..............
93
19
1125
..............
93
19
1126
..............
93
20
1127
..............
93
19
1128
..............
93
20
1129
..............
93
25
1130
..............
93
30
1131
..............
93
31
1132
..............
93
26
1133
..............
93
21
1134
..............
93
18
1135
..............
93
20
1136
..............
93
25
1137
..............
93
24
1138
..............
93
21
1139
..............
93
21
1140
..............
93
22
1141
..............
93
22
1142
..............
93
28
1143
..............
93
29
1144
..............
93
23
1145
..............
93
21
1146
..............
93
18
1147
..............
93
16
1148
..............
93
16
1149
..............
93
16
1150
..............
93
17
1151
..............
93
17
1152
..............
93
17
1153
..............
93
17
1154
..............
93
23
1155
..............
93
26
1156
..............
93
22
1157
..............
93
18
1158
..............
93
16
1159
..............
93
16
1160
..............
93
17
1161
..............
93
19
1162
..............
93
18
1163
..............
93
16
1164
..............
93
19
Time(
s)
Normalized
speed
(
percent)
Normalized
torque
(
percent)
1165
..............
93
22
1166
..............
93
25
1167
..............
93
29
1168
..............
93
27
1169
..............
93
22
1170
..............
93
18
1171
..............
93
16
1172
..............
93
19
1173
..............
93
19
1174
..............
93
17
1175
..............
93
17
1176
..............
93
17
1177
..............
93
16
1178
..............
93
16
1179
..............
93
15
1180
..............
93
16
1181
..............
93
15
1182
..............
93
17
1183
..............
93
21
1184
..............
93
30
1185
..............
93
53
1186
..............
93
54
1187
..............
93
38
1188
..............
93
30
1189
..............
93
24
1190
..............
93
20
1191
..............
95
20
1192
..............
96
18
1193
..............
96
15
1194
..............
96
11
1195
..............
95
9
1196
..............
95
8
1197
..............
96
7
1198
..............
94
33
1199
..............
93
46
1200
..............
93
37
1201
..............
16
8
1202
..............
0
0
1203
..............
0
0
1204
..............
0
0
1205
..............
0
0
1206
..............
0
0
1207
..............
0
0
1208
..............
0
0
1209
..............
0
0
PART
1051
CONTROL
OF
EMISSIONS
FROM
RECREATIONAL
ENGINES
AND
VEHICLES
Subpart
A
Determining
How
To
Follow
This
Part
Sec.
1051.1
Does
this
part
apply
to
me?
1051.5
Which
engines
are
excluded
or
exempted
from
this
part's
requirements?
1051.10
What
main
steps
must
I
take
to
comply
with
this
part?
1051.15
Do
any
other
regulation
parts
affect
me?
1051.20
May
I
certify
a
recreational
engine
instead
of
the
vehicle?
1051.25
What
requirements
apply
when
installing
certified
engines
in
recreational
vehicles?
Subpart
B
Emission
Standards
and
Related
Requirements
1051.101
What
emission
standards
and
other
requirements
must
my
vehicles
meet?
1051.103
What
are
the
exhaust
emission
standards
for
snowmobiles?
1051.105
What
are
the
exhaust
emission
standards
for
off
highway
motorcycles?
1051.107
What
are
the
exhaust
emission
standards
for
all
terrain
vehicles
(
ATVs)
and
offroad
utility
vehicles?
1051.110
What
evaporative
emission
standards
must
my
vehicles
meet?
1051.115
What
other
requirements
must
my
vehicles
meet?
1051.120
What
warranty
requirements
apply
to
me?
1051.125
What
maintenance
instructions
must
I
give
to
buyers?
1051.130
What
installation
instructions
must
I
give
to
vehicle
manufacturers?
1051.135
How
must
I
label
and
identify
the
vehicles
I
produce?
1051.145
What
provisions
apply
only
for
a
limited
time?
Subpart
C
Certifying
Engine
Families
1051.201
What
are
the
general
requirements
for
submitting
a
certification
application?
1051.205
What
must
I
include
in
my
application?
1051.210
May
I
get
preliminary
approval
before
I
complete
my
application?
1051.215
What
happens
after
I
complete
my
application?
1051.220
How
do
I
amend
the
maintenance
instructions
in
my
application?
1051.225
How
do
I
amend
my
application
to
include
new
or
modified
vehicles
or
to
change
an
FEL?
1051.230
How
do
I
select
engine
families?
1051.235
What
emission
testing
must
I
perform
for
my
application
for
a
certificate
of
conformity?
1051.240
How
do
I
demonstrate
that
my
engine
family
complies
with
exhaust
emission
standards?
1051.245
How
do
I
demonstrate
that
my
engine
family
complies
with
evaporative
emission
standards?
1051.250
What
records
must
I
keep
and
make
available
to
EPA?
1051.255
When
may
EPA
deny,
revoke,
or
void
my
certificate
of
conformity?
Subpart
D
Testing
Production
Line
Engines
1051.301
When
must
I
test
my
productionline
vehicles
or
engines?
1051.305
How
must
I
prepare
and
test
my
production
line
vehicles
or
engines?
1051.310
How
must
I
select
vehicles
or
engines
for
production
line
testing?
1051.315
How
do
I
know
when
my
engine
family
fails
the
production
line
testing
requirements?
1051.320
What
happens
if
one
of
my
production
line
vehicles
or
engines
fails
to
meet
emission
standards?
1051.325
What
happens
if
an
engine
family
fails
the
production
line
requirements?
1051.330
May
I
sell
vehicles
from
an
engine
family
with
a
suspended
certificate
of
conformity?
1051.335
How
do
I
ask
EPA
to
reinstate
my
suspended
certificate?
1051.340
When
may
EPA
revoke
my
certificate
under
this
subpart
and
how
may
I
sell
these
vehicles
again?
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and
Regulations
1051.345
What
production
line
testing
records
must
I
send
to
EPA?
1051.350
What
records
must
I
keep?
Subpart
E
Testing
In
Use
Engines
[
Reserved]
Subpart
F
Test
Procedures
1051.501
What
procedures
must
I
use
to
test
my
vehicles
or
engines?
1051.505
What
special
provisions
apply
for
testing
snowmobiles?
1051.510
What
special
provisions
apply
for
testing
ATV
engines?
[
Reserved]
1051.515
How
do
I
test
my
fuel
tank
for
permeation
emissions?
1051.520
How
do
I
perform
exhaust
durability
testing?
Subpart
G
Compliance
Provisions
1051.601
What
compliance
provisions
apply
to
vehicles
and
engines
subject
to
this
part?
1051.605
What
are
the
provisions
for
exempting
vehicles
from
the
requirements
of
this
part
if
they
use
engines
you
have
certified
under
the
motor
vehicle
program
or
the
Large
Spark
ignition
program?
1051.610
What
are
the
provisions
for
producing
recreational
vehicles
with
engines
already
certified
under
the
motor
vehicle
program
or
the
Large
SI
program?
1051.615
What
are
the
special
provisions
for
certifying
small
recreational
engines?
1051.620
When
may
a
manufacturer
obtain
an
exemption
for
competition
recreational
vehicles?
1051.625
What
special
provisions
apply
to
unique
snowmobile
designs
for
smallvolume
manufacturers?
1051.630
What
special
provisions
apply
to
unique
snowmobile
designs
for
all
manufacturers?
1051.635
What
provisions
apply
to
new
manufacturers
that
are
small
businesses?
Subpart
H
Averaging,
Banking,
and
Trading
for
Certification
1051.701
General
provisions.
1051.705
How
do
I
average
emission
levels?
1051.710
How
do
I
generate
and
bank
emission
credits?
1051.715
How
do
I
trade
emission
credits?
1051.720
How
do
I
calculate
my
average
emission
level
or
emission
credits?
1051.725
What
information
must
I
keep?
1051.730
What
information
must
I
report?
1051.735
Are
there
special
averaging
provisions
for
snowmobiles?
Subpart
I
Definitions
and
Other
Reference
Information
1051.801
What
definitions
apply
to
this
part?
1051.805
What
symbols,
acronyms,
and
abbreviations
does
this
part
use?
1051.810
What
materials
does
this
part
reference?
1051.815
How
should
I
request
EPA
to
keep
my
information
confidential?
1051.820
How
do
I
request
a
hearing?
Authority:
42
U.
S.
C.
7401
7671(
q).
Subpart
A
Determining
How
to
Follow
This
Part
§
1051.1
Does
this
part
apply
to
me?
(
a)
This
part
applies
to
you
if
you
manufacture
or
import
any
of
the
following
recreational
vehicles
or
engines
used
in
them,
unless
we
exclude
them
under
§
1051.5:
(
1)
Snowmobiles.
(
2)
Off
highway
motorcycles.
(
3)
All
terrain
vehicles
(
ATVs).
(
4)
Offroad
utility
vehicles
with
engines
with
displacement
less
than
or
equal
to
1000
cc,
maximum
brake
power
less
than
or
equal
to
30
kW,
and
maximum
vehicle
speed
of
25
miles
per
hour
or
higher.
Offroad
utility
vehicles
that
are
subject
to
this
part
are
subject
to
the
same
requirements
as
ATVs.
This
means
that
any
requirement
that
applies
to
ATVs
also
applies
to
these
offroad
utility
vehicles,
without
regard
to
whether
the
regulatory
language
mentions
offroad
utility
vehicles.
(
b)
[
Reserved]
(
c)
As
noted
in
subpart
G
of
this
part,
40
CFR
part
1068
applies
to
everyone,
including
anyone
who
manufactures,
installs,
owns,
operates,
or
rebuilds
any
of
the
vehicles
or
engines
this
part
covers.
(
d)
You
need
not
follow
this
part
for
vehicles
you
produce
before
the
2006
model
year,
unless
you
certify
voluntarily.
See
§
§
1051.103
through
1051.110,
§
1051.145,
and
the
definition
of
``
model
year''
in
§
1051.801
for
more
information
about
the
timing
of
the
requirements.
(
e)
The
requirements
of
this
part
begin
to
apply
when
a
vehicle
is
new.
See
the
definition
of
``
new''
in
§
1051.801
for
more
information.
In
some
cases,
vehicles
or
engines
that
have
been
previously
used
may
be
considered
``
new''
for
the
purposes
of
this
part.
(
f)
See
§
§
1051.801
and
1051.805
for
definitions
and
acronyms
that
apply
to
this
part.
The
definition
section
contains
significant
regulatory
provisions
and
it
is
very
important
that
you
read
them.
§
1051.5
Which
engines
are
excluded
or
exempted
from
this
part's
requirements?
(
a)
You
may
exclude
vehicles
with
compression
ignition
engines.
See
40
CFR
part
89
for
regulations
that
cover
these
engines.
(
b)
See
subpart
G
of
this
part
and
40
CFR
part
1068,
subpart
C,
for
exemptions
of
specific
engines.
(
c)
We
may
require
you
to
label
an
engine
or
vehicle
(
or
both)
if
this
section
excludes
it
and
other
requirements
in
this
chapter
do
not
apply.
(
d)
Send
the
Designated
Officer
a
written
request
with
supporting
documentation
if
you
want
us
to
determine
whether
this
part
covers
or
excludes
certain
vehicles.
Excluding
engines
from
this
part's
requirements
does
not
affect
other
requirements
that
may
apply
to
them.
§
1051.10
What
main
steps
must
I
take
to
comply
with
this
part?
(
a)
You
must
get
a
certificate
of
conformity
from
us
for
each
engine
family
before
you
do
any
of
the
following
things
with
a
new
vehicle
or
new
engine
covered
by
this
part:
sell,
offer
for
sale,
introduce
into
commerce,
distribute
or
deliver
for
introduction
into
commerce,
or
import
it
into
the
United
States.
``
New''
vehicles
or
engines
may
include
some
already
placed
in
service
(
see
the
definition
of
``
new''
in
§
1051.801).
You
must
get
a
new
certificate
of
conformity
for
each
new
model
year.
(
b)
To
get
a
certificate
of
conformity
and
comply
with
its
terms,
you
must
do
five
things:
(
1)
Meet
the
emission
standards
and
other
requirements
in
subpart
B
of
this
part.
(
2)
Perform
preproduction
emission
tests.
(
3)
Apply
for
certification
(
see
subpart
C
of
this
part).
(
4)
Do
routine
emission
testing
on
production
vehicles
or
engines
as
required
by
subpart
D
of
this
part.
(
5)
Follow
our
instructions
throughout
this
part.
(
c)
Subpart
F
of
this
part
describes
how
to
test
your
engines
or
vehicles
(
including
references
to
other
parts)
and
when
you
may
test
the
engine
alone
instead
of
the
entire
vehicle.
(
d)
Subpart
G
of
this
part
and
40
CFR
part
1068
describe
requirements
and
prohibitions
that
apply
to
manufacturers,
owners,
operators,
rebuilders,
and
all
others.
They
also
describe
exemptions
available
for
special
circumstances.
§
1051.15
Do
any
other
regulation
parts
affect
me?
(
a)
Parts
86
and
1065
of
this
chapter
describe
procedures
and
equipment
specifications
for
testing
vehicles
and
engines.
Subpart
F
of
this
part
describes
how
to
apply
part
86
or
1065
of
this
chapter
to
show
you
meet
the
emission
standards
in
this
part.
(
b)
Part
1068
of
this
chapter
describes
general
provisions,
including
these
seven
areas:
(
1)
Prohibited
actions
and
penalties
for
manufacturers
and
others.
(
2)
Rebuilding
and
other
aftermarket
changes.
(
3)
Exemptions
and
exclusions
for
certain
vehicles
and
engines.
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217
/
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November
8,
2002
/
Rules
and
Regulations
(
4)
Importing
vehicles
and
engines.
(
5)
Selective
enforcement
audits
of
your
production.
(
6)
Defect
reporting
and
recall.
(
7)
Procedures
for
hearings.
(
c)
Other
parts
of
this
chapter
affect
you
if
referenced
in
this
part.
§
1051.20
May
I
certify
a
recreational
engine
instead
of
the
vehicle?
(
a)
You
may
certify
engines
sold
separately
from
vehicles
in
either
of
two
cases:
(
1)
If
you
manufacture
recreational
engines
but
not
recreational
vehicles,
you
may
ask
to
certify
the
engine
alone.
In
your
request,
explain
why
you
cannot
certify
the
entire
vehicle.
(
2)
If
you
manufacture
complete
recreational
vehicles
containing
engines
you
also
sell
separately,
you
may
ask
to
certify
all
these
engines
in
a
single
engine
family
or
in
separate
engine
families.
(
b)
If
you
certify
an
engine
under
this
section,
you
must
use
the
test
procedures
in
subpart
F
of
this
part.
If
the
test
procedures
require
vehicle
testing,
use
good
engineering
judgment
to
install
the
engine
in
an
appropriate
vehicle
for
measuring
emissions.
(
c)
If
we
allow
you
to
certify
recreational
engines,
the
vehicles
must
meet
the
applicable
emission
standards
(
including
evaporative
emission
standards)
with
the
engines
installed
in
the
appropriate
vehicles.
You
must
prepare
installation
instructions
as
described
in
§
1051.130
and
use
good
engineering
judgment
so
that
the
engines
will
meet
emission
standards
after
proper
installation
in
the
vehicle.
(
d)
Identify
and
label
engines
you
produce
under
this
section
consistent
with
the
requirements
of
§
1051.135.
On
the
emission
control
information
label,
identify
the
manufacturing
date
of
the
engine
rather
than
the
vehicle.
(
e)
You
may
not
use
the
provisions
of
this
section
to
circumvent
or
reduce
the
stringency
of
this
part's
standards
or
other
requirements.
(
f)
If
you
certify
under
paragraph
(
a)(
1)
of
this
section,
you
may
ask
us
to
allow
you
to
perform
production
line
testing
on
the
engine.
If
you
certify
under
paragraph
(
a)(
2)
of
this
section,
use
good
engineering
judgment
to
ensure
that
these
engines
are
produced
in
the
same
manner
as
the
engines
you
produce
for
your
vehicles,
so
that
your
production
line
testing
results
under
subpart
D
of
this
part
would
apply
to
them.
§
1051.25
What
requirements
apply
when
installing
certified
engines
in
recreational
vehicles?
(
a)
If
you
manufacture
recreational
vehicles
with
engines
certified
under
§
1051.20,
you
need
not
also
certify
the
vehicle
under
this
part.
The
vehicle
must
nevertheless
meet
emission
standards
with
the
engine
installed.
(
b)
You
must
follow
the
engine
manufacturer's
emission
related
installation
instructions,
as
described
in
§
1051.135
and
40
CFR
1068.105.
For
example,
you
must
use
a
fuel
system
that
meets
the
permeation
requirements
of
this
part,
consistent
with
the
engine
manufacturer's
instructions.
(
c)
If
you
install
the
engine
in
a
way
that
makes
the
engine's
emission
control
information
label
hard
to
read
during
normal
engine
maintenance,
you
must
place
a
duplicate
label
on
the
vehicle,
as
described
in
40
CFR
1068.105.
Subpart
B
Emission
Standards
and
Related
Requirements
§
1051.101
What
emission
standards
and
other
requirements
must
my
vehicles
meet?
(
a)
You
must
show
that
your
vehicles
meet
the
following:
(
1)
The
applicable
exhaust
emission
standards
in
§
1051.103,
§
1051.105,
or
§
1051.107.
(
i)
For
snowmobiles,
see
§
1051.103.
(
ii)
For
off
highway
motorcycles,
see
§
1051.105.
(
iii)
For
all
terrain
vehicles
and
offroad
utility
vehicles
subject
to
this
part,
see
§
1051.107.
(
2)
The
evaporative
emission
standards
in
§
1051.110.
(
3)
All
the
requirements
in
§
1051.115.
(
b)
The
certification
regulations
in
subpart
C
of
this
part
describe
how
you
make
this
showing.
(
c)
These
standards
and
requirements
apply
to
all
testing,
including
production
line
and
in
use
testing,
as
described
in
subparts
D
and
E
of
this
part.
(
d)
Other
sections
in
this
subpart
describe
other
requirements
for
manufacturers
such
as
labeling
or
warranty
requirements.
(
e)
It
is
important
that
you
read
§
1051.145
to
determine
if
there
are
other
interim
requirements
or
interim
compliance
options
that
apply
for
a
limited
time.
(
f)
As
is
described
in
§
1051.1(
a)(
4),
offroad
utility
vehicles
that
are
subject
to
this
part
are
subject
to
the
same
requirements
as
ATVs.
§
1051.103
What
are
the
exhaust
emission
standards
for
snowmobiles?
(
a)
Apply
the
exhaust
emission
standards
in
this
section
by
model
year.
Measure
emissions
with
the
snowmobile
test
procedures
in
subpart
F
of
this
part.
(
1)
Follow
Table
1
of
this
section
for
exhaust
emission
standards.
You
may
use
the
averaging,
banking,
and
trading
provisions
of
subpart
H
of
this
part
to
show
compliance
with
these
standards
(
an
engine
family
meets
emission
standards
even
if
its
family
emission
limit
is
higher
than
the
standard,
as
long
as
you
show
that
the
whole
averaging
set
of
applicable
engine
families
meet
the
applicable
emission
standards
using
emission
credits,
and
the
vehicles
within
the
family
meet
the
family
emission
limit).
Table
1
also
shows
the
maximum
value
you
may
specify
for
a
family
emission
limit,
as
follows:
TABLE
1
OF
§
1051.103.
EXHAUST
EMISSION
STANDARDS
FOR
SNOWMOBILES
(
G/
KW
HR)
Phase
Model
year
Phase
in
(
percent)
Emission
standards
Maximum
allowable
family
emission
limits
HC
HC+
NOX
CO
HC
HC+
NOX
CO
Phase
1
...............
2006
....................
50
100
....................
275
....................
....................
........................
Phase
1
...............
2007
2009
..........
100
100
....................
275
....................
....................
........................
Phase
2
...............
2010
and
2011
...
100
75
....................
275
....................
....................
........................
Phase
3
...............
2012
and
later
....
100
75
(
1)
(
1)
150
165
400
1
See
§
1051.103(
a)(
2).
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217
/
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November
8,
2002
/
Rules
and
Regulations
(
2)
For
Phase
3,
the
HC+
NOX
and
CO
standards
are
defined
by
a
functional
relationship.
Choose
your
corporate
average
HC+
NOX
and
CO
standards
for
each
model
year
according
to
the
following
criteria:
(
i)
Prior
to
production,
select
the
HC+
NOX
standard
and
CO
standard
(
specified
as
g/
kW
hr)
so
that
the
combined
percent
reduction
from
baseline
emission
levels
is
greater
than
or
equal
to
100
percent;
that
is,
that
the
standards
comply
with
the
following
equation:
1
15
150
100
1
100
100
×
+
×
(
)
HC+
NO
CO
400
x
STD
STD
(
ii)
Your
corporate
average
HC+
NOX
standard
may
not
be
higher
than
90
g/
kW
hr.
(
iii)
Your
corporate
average
CO
standard
may
not
be
higher
than
275
g/
kW
hr.
(
iv)
You
may
use
the
averaging
and
banking
provisions
of
subpart
H
of
this
part
to
show
compliance
with
these
HC+
NOX
and
CO
standards
in
this
paragraph
(
a)(
2).
You
may
modify
your
selection
of
the
HC+
NOX
and
CO
standards
at
the
end
of
the
model
year
under
paragraph
(
a)(
2)(
i)
of
this
section.
You
must
comply
with
these
final
corporate
average
emission
standards.
(
b)
Apply
the
exhaust
emission
standards
in
this
section
for
snowmobiles
using
each
type
of
fuel
specified
in
40
CFR
part
1065,
subpart
C,
for
which
they
are
designed
to
operate.
You
must
meet
the
numerical
emission
standards
for
hydrocarbons
in
this
section
based
on
the
following
types
of
hydrocarbon
emissions
for
snowmobiles
powered
by
the
following
fuels:
(
1)
Gasoline
and
LPG
fueled
snowmobiles:
THC
emissions.
(
2)
Natural
gas
fueled
snowmobiles:
NMHC
emissions.
(
3)
Alcohol
fueled
snowmobiles:
THCE
emissions.
(
c)
Your
snowmobiles
must
meet
emission
standards
over
their
full
useful
life
(
§
1051.240
describes
how
to
use
deterioration
factors
to
show
this).
The
minimum
useful
life
is
8,000
kilometers,
400
hours
of
engine
operation,
or
five
calendar
years,
whichever
comes
first.
You
must
specify
a
longer
useful
life
in
terms
of
kilometers
and
hours
for
the
engine
family
if
the
average
service
life
of
your
vehicles
is
longer
than
the
minimum
value,
as
follows:
(
1)
Except
as
allowed
by
paragraph
(
c)(
2)
of
this
section,
your
useful
life
(
in
kilometers
and
hours)
may
not
be
less
than
either
of
the
following:
(
i)
Your
projected
operating
life
from
advertisements
or
other
marketing
materials
for
any
vehicles
in
the
engine
family.
(
ii)
Your
basic
mechanical
warranty
for
any
engines
in
the
engine
family.
(
2)
Your
useful
life
may
be
based
on
the
average
service
life
of
vehicles
in
the
engine
family
if
you
show
that
the
average
service
life
is
less
than
the
useful
life
required
by
paragraph
(
c)(
1)
of
this
section,
but
more
than
the
minimum
useful
life
(
8,000
kilometers
or
400
hours
of
engine
operation).
In
determining
the
actual
average
service
life
of
vehicles
in
an
engine
family,
we
will
consider
all
available
information
and
analyses.
Survey
data
is
allowed
but
not
required
to
make
this
showing.
§
1051.105
What
are
the
exhaust
emission
standards
for
off
highway
motorcycles?
(
a)
Apply
the
exhaust
emission
standards
in
this
section
by
model
year.
Measure
emissions
with
the
off
highway
motorcycle
test
procedures
in
subpart
F
of
this
part.
(
1)
Follow
Table
1
of
this
section
for
exhaust
emission
standards.
You
may
use
the
averaging,
banking,
and
trading
provisions
of
subpart
H
of
this
part
to
show
compliance
with
the
HC+
NOX
and/
or
CO
standards
(
an
engine
family
meets
emission
standards
even
if
its
family
emission
limit
is
higher
than
the
standard,
as
long
as
you
show
that
the
whole
averaging
set
of
applicable
engine
families
meet
the
applicable
emission
standards
using
emission
credits,
and
the
vehicles
within
the
family
meet
the
family
emission
limit).
The
phase
in
values
specify
the
percentage
of
your
U.
S.
directed
production
that
must
comply
with
the
emission
standards
for
those
model
years.
Calculate
this
compliance
percentage
based
on
a
simple
count
of
production
units
within
the
engine
family.
Table
1
follows:
TABLE
1
OF
§
1051.105.
EXHAUST
EMISSION
STANDARDS
FOR
OFF
HIGHWAY
MOTORCYCLES
(
G/
KM)
Phase
Model
year
Phase
in
(
percent)
Emission
standards
Maximum
allowable
family
emission
limits
HC+
NOX
CO
HC+
NOX
CO
Phase
1
........................................
2006
..............................................
50
2.0
25
20.0
50
2007
and
later
..............................
100
2.0
25
20.0
50
(
2)
For
model
years
2007
and
later
you
may
choose
to
certify
all
of
your
offhighway
motorcycles
to
an
HC+
NOX
standard
of
4.0
g/
km
and
a
CO
standard
of
35
g/
km,
instead
of
the
standards
listed
in
paragraph
(
a)(
1)
of
this
section.
To
certify
to
the
standards
in
this
paragraph
(
a)(
2),
you
must
comply
with
the
following
provisions:
(
i)
You
may
not
request
an
exemption
for
any
off
highway
motorcycles
under
§
1051.620
(
ii)
At
least
ten
percent
of
your
offhighway
motorcycles
for
the
model
year
must
have
four
of
the
following
features:
(
A)
The
absence
of
a
headlight
or
other
lights.
(
B)
The
absence
of
a
spark
arrestor.
(
C)
The
absence
of
manufacturer
warranty.
(
D)
Suspension
travel
greater
than
10
inches.
(
E)
Engine
displacement
greater
than
50
cc.
(
F)
The
absence
of
a
functional
seat.
(
iii)
You
may
use
the
averaging
and
banking
provisions
of
subpart
H
of
this
part
to
show
compliance
with
this
HC+
NOX
standard,
but
not
this
CO
standard.
If
you
use
the
averaging
or
banking
provisions
to
show
compliance,
your
FEL
for
HC+
NOX
may
not
exceed
8.0
g/
km
for
any
engine
family.
You
may
not
use
the
trading
provisions
of
subpart
H
of
this
part.
(
3)
You
may
certify
off
highway
motorcycles
with
engines
that
have
total
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217
/
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November
8,
2002
/
Rules
and
Regulations
displacement
of
70
cc
or
less
to
the
exhaust
emission
exhaust
standards
in
§
1051.615
instead
of
certifying
them
to
the
exhaust
emission
standards
of
this
section.
(
b)
Apply
the
exhaust
emission
standards
in
this
section
for
off
highway
motorcycles
using
each
type
of
fuel
specified
in
40
CFR
part
1068,
subpart
C,
for
which
they
are
designed
to
operate.
You
must
meet
the
numerical
emission
standards
for
hydrocarbons
in
this
section
based
on
the
following
types
of
hydrocarbon
emissions
for
offhighway
motorcycles
powered
by
the
following
fuels:
(
1)
Gasoline
and
LPG
fueled
offhighway
motorcycles:
THC
emissions.
(
2)
Natural
gas
fueled
off
highway
motorcycles:
NMHC
emissions.
(
3)
Alcohol
fueled
off
highway
motorcycles:
THCE
emissions.
(
c)
Your
off
highway
motorcycles
must
meet
emission
standards
over
their
full
useful
life
(
§
1051.240
describes
how
to
use
deterioration
factors
to
show
this).
The
minimum
useful
life
is
10,000
kilometers
or
five
years,
whichever
comes
first.
You
must
specify
a
longer
useful
life
for
the
engine
family
in
terms
of
kilometers
if
the
average
service
life
of
your
vehicles
is
longer
than
the
minimum
value,
as
follows:
(
1)
Except
as
allowed
by
paragraph
(
c)(
2)
of
this
section,
your
useful
life
(
in
kilometers)
may
not
be
less
than
either
of
the
following:
(
i)
Your
projected
operating
life
from
advertisements
or
other
marketing
materials
for
any
vehicles
in
the
engine
family.
(
ii)
Your
basic
mechanical
warranty
for
any
engines
in
the
engine
family.
(
2)
Your
useful
life
may
be
based
on
the
average
service
life
of
vehicles
in
the
engine
family
if
you
show
that
the
average
service
life
is
less
than
the
useful
life
required
by
paragraph
(
c)(
1)
of
this
section,
but
more
than
the
minimum
useful
life
(
10,000
kilometers).
In
determining
the
actual
average
service
life
of
vehicles
in
an
engine
family,
we
will
consider
all
available
information
and
analyses.
Survey
data
is
allowed
but
not
required
to
make
this
showing.
§
1051.107
What
are
the
exhaust
emission
standards
for
all
terrain
vehicles
(
ATVs)
and
offroad
utility
vehicles?
This
section
specifies
the
exhaust
emission
standards
that
apply
to
ATVs.
As
is
described
in
§
1051.1(
a)(
4),
offroad
utility
vehicles
that
are
subject
to
this
part
are
subject
to
these
same
standards.
(
a)
Apply
the
exhaust
emission
standards
in
this
section
by
model
year.
Measure
emissions
with
the
ATV
test
procedures
in
subpart
F
of
this
part.
(
1)
Follow
Table
1
of
this
section
for
exhaust
emission
standards.
You
may
use
the
averaging,
banking,
and
trading
provisions
of
subpart
H
of
this
part
to
show
compliance
with
these
HC+
NOX
standards
(
an
engine
family
meets
emission
standards
even
if
its
family
emission
limit
is
higher
than
the
standard,
as
long
as
you
show
that
the
whole
averaging
set
of
applicable
engine
families
meet
the
applicable
emission
standards
using
emission
credits,
and
the
vehicles
within
the
family
meet
the
family
emission
limit).
Table
1
also
shows
the
maximum
value
you
may
specify
for
a
family
emission
limit.
The
phase
in
values
in
the
table
specify
the
percentage
of
your
total
U.
S.
directed
production
that
must
comply
with
the
emission
standards
for
those
model
years.
Calculate
this
compliance
percentage
based
on
a
simple
count
of
production
units
within
the
engine
family.
This
applies
to
your
total
production
of
ATVs
and
offroad
utility
vehicles
that
are
subject
to
the
standards
of
this
part;
including
both
ATVs
and
offroad
utility
vehicles
subject
to
the
standards
of
this
section
and
ATVs
and
offroad
utility
vehicles
certified
to
the
standards
of
other
sections
in
this
part
1051
(
such
as
§
1051.615,
but
not
including
vehicles
certified
under
other
parts
in
this
chapter
(
such
as
40
CFR
part
90).
Table
1
follows:
TABLE
1
OF
§
1051.107.
EXHAUST
EMISSION
STANDARDS
FOR
ATVS
(
G/
KM)
Phase
Model
year
Phase
in
(
percent)
Emission
standards
Maximum
allowable
family
emission
limits
HC+
NOX
CO
HC+
NOX
CO
Phase
1
........................................
2006
..............................................
50
1.5
35
20.0
50
2007
and
later
..............................
100
1.5
35
20.0
50
(
2)
You
may
certify
ATVs
with
engines
that
have
total
displacement
of
less
than
100
cc
to
the
exhaust
emission
exhaust
standards
in
§
1051.615
instead
of
certifying
them
to
the
exhaust
emission
standards
of
this
section.
(
b)
Apply
the
exhaust
emission
standards
in
this
section
for
ATVs
using
each
type
of
fuel
specified
in
40
CFR
1065,
subpart
C
for
which
they
are
designed
to
operate.
You
must
meet
the
numerical
emission
standards
for
hydrocarbons
in
this
section
based
on
the
following
types
of
hydrocarbon
emissions
for
ATVs
powered
by
the
following
fuels:
(
1)
Gasoline
and
LPG
fueled
ATVs:
THC
emissions.
(
2)
Natural
gas
fueled
ATVs:
NMHC
emissions.
(
3)
Alcohol
fueled
ATVs:
THCE
emissions.
(
c)
Your
ATVs
must
meet
emission
standards
over
their
full
useful
life
(
§
1051.240
describes
how
to
use
deterioration
factors
to
show
this).
The
minimum
useful
life
is
10,000
kilometers,
1000
hours
of
engine
operation,
or
five
years,
whichever
comes
first.
You
must
specify
a
longer
useful
life
for
the
engine
family
in
terms
of
kilometers
and
hours
if
the
average
service
life
of
your
vehicles
is
longer
than
the
minimum
value,
as
follows:
(
1)
Except
as
allowed
by
paragraph
(
c)(
2)
of
this
section,
your
useful
life
(
in
kilometers)
may
not
be
less
than
either
of
the
following:
(
i)
Your
projected
operating
life
from
advertisements
or
other
marketing
materials
for
any
vehicles
in
the
engine
family.
(
ii)
Your
basic
mechanical
warranty
for
any
engines
in
the
engine
family.
(
2)
Your
useful
life
may
be
based
on
the
average
service
life
of
vehicles
in
the
engine
family
if
you
show
that
the
average
service
life
is
less
than
the
useful
life
required
by
paragraph
(
c)(
1)
of
this
section,
but
more
than
the
minimum
useful
life
(
10,000
kilometers
or
1,000
hours
of
engine
operation).
In
determining
the
actual
average
service
life
of
vehicles
in
an
engine
family,
we
will
consider
all
available
information
and
analyses.
Survey
data
is
allowed
but
not
required
to
make
this
showing.
§
1051.110
What
evaporative
emission
standards
must
my
vehicles
meet?
All
of
your
new
vehicles
must
meet
the
emission
standards
of
this
section
over
their
full
useful
life,
as
specified
in
this
section.
Note
that
§
1051.245
allows
you
to
use
design
based
certification
instead
of
generating
new
emission
data.
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217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
(
a)
Beginning
with
the
2008
model
year,
permeation
emissions
from
your
vehicle's
fuel
tank(
s)
may
not
exceed
1.5
grams
per
square
meter
per
day
when
measured
with
the
test
procedures
for
tank
permeation
in
subpart
F
of
this
part.
You
may
use
the
averaging,
banking,
and
trading
provisions
of
subpart
H
of
this
part
to
show
compliance.
(
b)
Beginning
with
the
2008
model
year,
permeation
emissions
from
your
vehicle's
fuel
lines
may
not
exceed
15
grams
per
square
meter
per
day
when
measured
with
the
test
procedures
for
fuel
line
permeation
in
subpart
F
of
this
part.
Use
the
inside
diameter
of
the
hose
to
determine
the
surface
area
of
the
hose.
§
1051.115
What
other
requirements
must
my
vehicles
meet?
Your
vehicles
must
meet
the
following
requirements:
(
a)
Closed
crankcase.
Design
and
produce
your
vehicles
so
they
release
no
crankcase
emissions
into
the
atmosphere
throughout
their
useful
life.
(
b)
Emission
sampling
capability.
Produce
all
your
vehicles
to
allow
sampling
of
exhaust
emissions
in
the
field
without
damaging
the
vehicle.
Show
in
your
application
for
certification
how
this
can
be
done
in
a
way
that
prevents
diluting
the
exhaust
sample
with
ambient
air.
To
do
this,
you
might
simply
allow
for
extending
the
exhaust
pipe
by
20
cm;
you
might
also
install
sample
ports
in
the
exhaust
(
downstream
of
any
aftertreatment
devices).
(
c)
Adjustable
parameters.
If
your
vehicles
have
adjustable
parameters,
they
must
meet
all
the
requirements
of
this
part
for
any
adjustment
in
the
physically
adjustable
range.
Note
that
parameters
that
control
the
air
fuel
ratio
may
be
treated
separately
under
paragraph
(
d)
of
this
section.
(
1)
We
do
not
consider
an
operating
parameter
adjustable
if
you
permanently
seal
it
or
if
ordinary
tools
cannot
readily
access
it.
(
2)
We
may
require
you
to
adjust
the
engine
to
any
specification
within
the
adjustable
range
during
certification
testing,
production
line
testing,
selective
enforcement
auditing,
or
inuse
testing.
(
d)
Other
adjustments.
This
provision
applies
if
an
experienced
mechanic
can
change
your
engine's
air
fuel
ratio
in
less
than
one
hour
with
a
few
parts
whose
total
cost
is
under
$
50
(
in
2001
dollars).
Examples
include
carburetor
jets
and
needles.
In
the
case
of
carburetor
jets
and
needles,
your
vehicle
must
meet
all
the
requirements
of
this
part
for
any
air
fuel
ratio
within
the
adjustable
range
described
in
paragraph
(
d)(
1)
of
this
section.
(
1)
In
your
application
for
certification,
specify
the
adjustable
range
of
air
fuel
ratios
you
expect
to
occur
in
use.
You
may
specify
it
in
terms
of
engine
parts
(
such
as
the
carburetor
jet
size
and
needle
configuration
as
a
function
of
atmospheric
conditions).
(
2)
This
adjustable
range
(
specified
in
paragraph
(
d)(
1)
of
this
section)
must
include
all
air
fuel
ratios
between
the
lean
limit
and
the
rich
limit,
unless
you
can
show
that
some
air
fuel
ratios
will
not
occur
in
use.
(
i)
The
lean
limit
is
the
air
fuel
ratio
that
produces
the
highest
engine
power
output
(
averaged
over
the
test
cycle).
(
ii)
The
rich
limit
is
the
richest
of
the
following
air
fuel
ratios:
(
A)
The
air
fuel
ratio
that
would
result
from
operating
the
vehicle
as
you
produce
it
at
the
specified
test
conditions.
This
paragraph
(
d)(
2)(
ii)(
A)
does
not
apply
if
you
produce
the
vehicle
with
an
unjetted
carburetor
so
that
the
vehicle
must
be
jetted
by
the
dealer
or
operator.
(
B)
The
air
fuel
ratio
of
the
engine
when
you
do
durability
testing.
(
C)
The
richest
air
fuel
ratio
that
you
recommend
to
your
customers
for
the
applicable
ambient
conditions.
(
3)
If
the
air
fuel
ratio
of
your
vehicle
is
adjusted
primarily
by
changing
the
carburetor
jet
size
and/
or
needle
configuration,
you
may
submit
your
recommended
jetting
chart
instead
of
the
range
of
air
fuel
ratios
required
by
paragraph
(
d)(
1)
of
this
section
if
the
following
criteria
are
met:
(
i)
Good
engineering
judgment
indicates
that
vehicle
operators
would
not
have
an
incentive
to
operate
the
vehicle
with
richer
air
fuel
ratios
than
recommended.
(
ii)
The
chart
is
based
on
use
of
a
fuel
that
is
equivalent
to
the
specified
test
fuel(
s).
As
an
alternative
you
may
submit
a
chart
based
on
a
representative
in
use
fuel
if
you
also
provide
instructions
for
converting
the
chart
to
be
applicable
to
the
test
fuel(
s).
(
iii)
The
chart
is
specified
in
units
that
are
adequate
to
make
it
practical
for
an
operator
to
keep
the
vehicle
properly
jetted
during
typical
use.
For
example,
charts
that
specify
jet
sizes
based
on
increments
of
temperature
smaller
than
20
°
F
(
11.1
°
C)
or
increments
of
altitude
less
than
2000
feet
would
not
meet
this
criteria.
Temperature
ranges
must
overlap
by
at
least
5
°
F
(
2.8
°
C).
(
iv)
You
follow
the
jetting
chart
for
durability
testing.
(
v)
You
do
not
produce
your
vehicles
with
jetting
richer
than
the
jetting
chart
recommendation
for
the
intended
vehicle
use.
(
4)
We
may
require
you
to
adjust
the
engine
to
any
specification
within
the
adjustable
range
during
certification
testing,
production
line
testing,
selective
enforcement
auditing,
or
inuse
testing.
If
we
allow
you
to
submit
your
recommended
jetting
chart
instead
of
the
range
of
air
fuel
ratios
required
by
paragraph
(
d)(
1)
of
this
section,
adjust
the
engine
to
the
richest
specification
within
the
jetting
chart
for
the
test
conditions,
unless
we
specify
a
leaner
setting.
We
may
not
specify
a
setting
leaner
than
that
described
in
paragraph
(
d)(
2)(
i)
of
this
section.
(
e)
Prohibited
controls.
You
may
not
design
your
engines
with
emissioncontrol
devices,
systems,
or
elements
of
design
that
cause
or
contribute
to
an
unreasonable
risk
to
public
health,
welfare,
or
safety
while
operating.
For
example,
this
would
apply
if
the
engine
emits
a
noxious
or
toxic
substance
it
would
otherwise
not
emit
that
contributes
to
such
an
unreasonable
risk.
(
f)
Defeat
devices.
You
may
not
equip
your
vehicles
with
a
defeat
device.
A
defeat
device
is
an
auxiliary
emissioncontrol
device
or
other
control
feature
that
reduces
the
effectiveness
of
emission
controls
under
conditions
you
may
reasonably
expect
the
vehicle
to
encounter
during
normal
operation
and
use.
This
does
not
apply
to
auxiliary
emission
control
devices
you
identify
in
your
certification
application
if
any
of
the
following
is
true:
(
1)
The
conditions
of
concern
were
substantially
included
in
your
prescribed
duty
cycles.
(
2)
You
show
your
design
is
necessary
to
prevent
catastrophic
vehicle
damage
or
accidents.
(
3)
The
reduced
effectiveness
applies
only
to
starting
the
engine.
(
g)
Noise
standards.
There
are
no
noise
standards
specified
in
this
part
1051.
See
40
CFR
Chapter
I,
Subchapter
G,
to
determine
if
your
vehicle
must
meet
noise
emission
standards
under
another
part
our
regulations.
§
1051.120
What
warranty
requirements
apply
to
me?
(
a)
General
requirements.
You
must
warrant
to
the
ultimate
buyer
that
the
new
engine
meets
two
conditions:
(
1)
It
is
designed,
built,
and
equipped
to
conform
at
the
time
of
sale
with
the
requirements
of
this
part.
(
2)
It
is
free
from
defects
in
materials
and
workmanship
that
may
keep
it
from
meeting
these
requirements.
(
b)
Warranty
period.
Your
emissionrelated
warranty
must
be
valid
for
at
least
50
percent
of
the
vehicle's
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Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
minimum
useful
life
in
kilometers
or
at
least
30
months,
whichever
comes
first.
You
may
offer
an
emission
related
warranty
more
generous
than
we
require.
This
warranty
may
not
be
shorter
than
any
published
or
negotiated
warranty
you
offer
for
the
engine
or
any
of
its
components.
If
a
vehicle
has
no
odometer,
base
warranty
periods
in
this
paragraph
(
b)
only
on
the
vehicle's
age
(
in
years).
(
c)
Components
covered.
The
emission
related
warranty
must
cover
components
whose
failure
would
increase
an
engine's
emissions,
including
electronic
controls,
fuel
injection
(
for
liquid
or
gaseous
fuels),
exhaust
gas
recirculation,
aftertreatment,
or
any
other
system
you
develop
to
control
emissions.
We
generally
consider
replacing
or
repairing
other
components
to
be
the
owner's
responsibility.
(
d)
Scheduled
maintenance.
You
may
schedule
emission
related
maintenance
for
a
component
named
in
paragraph
(
c)
of
this
section,
subject
to
the
restrictions
of
§
1051.125.
You
are
not
required
to
cover
this
scheduled
maintenance
under
your
warranty
if
the
component
meets
either
of
the
following
criteria:
(
1)
The
component
was
in
general
use
on
similar
engines,
and
was
subject
to
scheduled
maintenance,
before
January
1,
2000.
(
2)
Failure
of
the
component
would
clearly
degrade
the
engine's
performance
enough
that
the
operator
would
need
to
repair
or
replace
it.
(
e)
Limited
applicability.
You
may
deny
warranty
claims
under
this
section
if
the
operator
caused
the
problem,
as
described
in
1068.115
of
this
chapter.
You
may
ask
us
to
allow
you
to
exclude
from
your
emission
related
warranty
certified
vehicles
that
have
been
used
significantly
for
competition,
especially
certified
motorcycles
that
meet
at
least
four
of
the
criteria
in
§
1051.620(
b)(
1).
(
f)
Aftermarket
parts.
As
noted
in
§
1068.101
of
this
chapter,
it
is
a
violation
of
the
Act
to
manufacture
a
vehicle
part
if
one
of
its
main
effects
is
to
reduce
the
effectiveness
of
the
vehicle's
emission
controls.
If
you
make
an
aftermarket
part,
you
may
but
do
not
have
to
certify
that
using
the
part
will
still
allow
engines
to
meet
emission
standards,
as
described
in
§
85.2114
of
this
chapter.
§
1051.125
What
maintenance
instructions
must
I
give
to
buyers?
Give
the
ultimate
buyer
of
each
new
vehicle
written
instructions
for
properly
maintaining
and
using
the
vehicle,
including
the
emission
control
system.
The
maintenance
instructions
also
apply
to
service
accumulation
on
your
test
vehicles
or
engines,
as
described
in
40
CFR
part
1065,
subpart
E.
(
a)
Critical
emission
related
maintenance.
Critical
emission
related
maintenance
includes
any
adjustment,
cleaning,
repair,
or
replacement
of
airinduction
fuel
system,
or
ignition
components,
aftertreatment
devices,
pulse
air
valves,
exhaust
gas
recirculation
systems,
crankcase
ventilation
valves,
sensors,
or
electronic
control
units.
This
may
also
include
any
other
component
whose
only
purpose
is
to
reduce
emissions
or
whose
failure
will
increase
emissions
without
significantly
degrading
engine
performance.
You
may
schedule
critical
emission
related
maintenance
on
these
components
if
you
meet
the
following
conditions:
(
1)
You
may
ask
us
to
approve
critical
emission
related
maintenance
only
if
it
meets
two
criteria:
(
i)
Operators
are
reasonably
likely
to
do
the
maintenance
you
call
for.
(
ii)
Vehicles
need
the
maintenance
to
meet
emission
standards.
(
2)
We
will
accept
scheduled
maintenance
as
reasonably
likely
to
occur
in
use
if
you
satisfy
any
of
four
conditions:
(
i)
You
present
data
showing
that,
if
a
lack
of
maintenance
increases
emissions,
it
also
unacceptably
degrades
the
vehicle's
performance.
(
ii)
You
present
survey
data
showing
that
80
percent
of
vehicles
in
the
field
get
the
maintenance
you
specify
at
the
recommended
intervals.
(
iii)
You
provide
the
maintenance
free
of
charge
and
clearly
say
so
in
maintenance
instructions
for
the
customer.
(
iv)
You
otherwise
show
us
that
the
maintenance
is
reasonably
likely
to
be
done
at
the
recommended
intervals.
(
3)
You
may
not
schedule
critical
emission
related
maintenance
within
the
minimum
useful
life
period
for
aftertreatment
devices,
pulse
air
valves,
fuel
injectors,
oxygen
sensors,
electronic
control
units,
superchargers,
or
turbochargers.
(
b)
Recommended
additional
maintenance.
You
may
recommend,
but
not
require,
any
additional
amount
of
maintenance
on
the
components
listed
in
paragraph
(
a)
of
this
section.
However,
you
must
make
it
clear
that
these
maintenance
steps
are
not
necessary
to
keep
the
emission
related
warranty
valid.
If
operators
do
the
maintenance
specified
in
paragraph
(
a)
of
this
section,
but
not
the
recommended
additional
maintenance,
this
does
not
allow
you
to
disqualify
them
from
in
use
testing
or
deny
a
warranty
claim.
(
c)
Special
maintenance.
You
may
specify
more
frequent
maintenance
to
address
problems
related
to
special
situations
such
as
substandard
fuel
or
atypical
engine
operation.
You
may
not
perform
this
special
maintenance
during
service
accumulation
or
durability
testing.
(
d)
Noncritical
emission
related
maintenance.
For
engine
parts
not
listed
in
paragraph
(
a)
of
this
section,
you
may
schedule
any
amount
of
emissionrelated
inspection
or
maintenance.
But
you
must
state
clearly
that
these
steps
are
not
necessary
to
keep
the
emissionrelated
warranty
valid.
Also,
do
not
take
these
inspection
or
maintenance
steps
during
service
accumulation
on
your
test
vehicles
or
engines.
(
e)
Maintenance
that
is
not
emissionrelated
For
maintenance
unrelated
to
emission
controls,
you
may
schedule
any
amount
of
inspection
or
maintenance.
You
may
also
take
these
inspection
or
maintenance
steps
during
service
accumulation
on
your
test
vehicles
or
engines.
This
might
include
adding
engine
oil
or
adjusting
chain
tension,
clutch
position,
or
tire
pressure.
(
f)
Source
of
parts
and
repairs.
Print
clearly
on
the
first
page
of
your
written
maintenance
instructions
that
any
repair
shop
or
person
may
maintain,
replace,
or
repair
emission
control
devices
and
systems.
Your
instructions
may
not
require
any
component
or
service
identified
by
brand,
trade,
or
corporate
name.
Also,
do
not
directly
or
indirectly
condition
your
warranty
on
a
requirement
that
the
vehicle
be
serviced
by
your
franchised
dealers
or
any
other
service
establishments
with
which
you
have
a
commercial
relationship.
You
may
disregard
the
requirements
in
this
paragraph
(
f)
if
you
do
one
of
two
things:
(
1)
Provide
a
component
or
service
without
charge
under
the
purchase
agreement.
(
2)
Get
us
to
waive
this
prohibition
in
the
public's
interest
by
convincing
us
the
vehicle
will
work
properly
only
with
the
identified
component
or
service.
§
1051.130
What
installation
instructions
must
I
give
to
vehicle
manufacturers?
(
a)
If
you
sell
an
engine
for
someone
else
to
install
in
a
recreational
vehicle,
give
the
engine
buyer
written
instructions
for
installing
it
consistent
with
the
requirements
of
this
part.
Include
all
information
necessary
to
ensure
that
engines
installed
this
way
will
meet
emission
standards.
(
b)
These
instructions
must
have
the
following
information:
(
1)
Include
the
heading:
``
Emissionrelated
installation
instructions''.
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8,
2002
/
Rules
and
Regulations
(
2)
State:
``
Failing
to
follow
these
instructions
when
installing
a
certified
engine
in
a
recreational
vehicle
may
violate
federal
law
(
40
CFR
1068.105(
b)),
and
subject
you
to
fines
or
other
penalties
as
described
in
the
Clean
Air
Act.''.
(
3)
Describe
any
other
instructions
needed
to
install
an
exhaust
aftertreatment
device
consistent
with
your
application
for
certification.
(
4)
Describe
the
steps
needed
to
comply
with
the
evaporative
emission
standards
in
§
1051.110.
(
5)
Describe
any
limits
on
the
range
of
applications
needed
to
ensure
that
the
engine
operates
consistently
with
your
application
for
certification.
For
example,
if
your
engines
are
certified
only
to
the
snowmobile
standards,
tell
vehicle
manufacturers
not
to
install
the
engines
in
other
vehicles.
(
6)
Describe
any
other
instructions
to
make
sure
the
installed
engine
will
operate
according
to
any
design
specifications
you
describe
in
your
application
for
certification.
(
7)
State:
``
If
you
install
the
engine
in
a
way
that
makes
the
engine's
emission
control
information
label
hard
to
read
during
normal
engine
maintenance,
you
must
place
a
duplicate
label
on
the
vehicle,
as
described
in
40
CFR
1068.105.''.
(
c)
You
do
not
need
installation
instructions
for
engines
you
install
in
your
own
vehicles.
§
1051.135
How
must
I
label
and
identify
the
vehicles
I
produce?
Each
of
your
vehicles
must
have
three
labels:
a
vehicle
identification
number
as
described
in
paragraph
(
a)
of
this
section,
an
emission
control
information
label
as
described
in
paragraphs
(
b)
through
(
e)
of
this
section,
and
a
consumer
information
label
as
described
in
paragraph
(
g)
of
this
section.
(
a)
Assign
each
production
vehicle
a
unique
identification
number
and
permanently
and
legibly
affix,
stamp,
or
engrave
it
on
the
vehicle.
(
b)
At
the
time
of
manufacture,
add
a
permanent
label
identifying
the
emission
controls
for
each
vehicle.
This
is
the
vehicle's
``
emission
control
information
label.''
To
meet
labeling
requirements,
do
the
following
things:
(
1)
Attach
the
label
in
one
piece
so
it
is
not
removable
without
being
destroyed
or
defaced.
(
2)
Design
and
produce
it
to
be
durable
and
readable
for
the
vehicle's
entire
life.
(
3)
Secure
it
to
a
part
of
the
vehicle
(
or
engine)
needed
for
normal
operation
and
not
normally
requiring
replacement.
(
4)
Write
it
in
block
letters
in
English.
(
5)
Attach
the
label
in
a
location
where
it
can
be
easily
read.
(
c)
On
your
label,
do
these
things:
(
1)
Include
the
heading
``
EMISSION
CONTROL
INFORMATION''.
(
2)
Include
your
full
corporate
name
and
trademark.
(
3)
State:
``
THIS
VEHICLE
IS
CERTIFIED
TO
OPERATE
ON
[
specify
operating
fuel
or
fuels].''.
(
4)
Identify
the
emission
control
system;
your
identifiers
must
use
names
and
abbreviations
consistent
with
SAE
J1930
(
incorporated
by
reference
in
§
1051.810).
(
5)
List
all
requirements
for
fuel
and
lubricants.
(
6)
State
the
date
of
manufacture
[
DAY
(
optional),
MONTH,
and
YEAR];
if
you
stamp
it
on
the
engine
and
print
it
in
the
owner's
manual,
you
may
omit
this
information
from
the
emission
control
information
label.
(
7)
State:
``
THIS
VEHICLE
MEETS
U.
S.
ENVIRONMENTAL
PROTECTION
AGENCY
REGULATIONS
FOR
[
MODEL
YEAR]
[
SNOWMOBILES
or
OFF
ROAD
MOTORCYCLES
or
ATVs].''.
(
8)
Include
EPA's
standardized
designation
for
the
engine
family.
(
9)
State
the
engine's
displacement
(
in
liters)
and
maximum
brake
power.
You
do
not
need
to
include
the
engine's
displacement
and
power
on
the
emission
control
information
label
if
the
vehicle
is
permanently
labeled
with
a
unique
model
name
that
corresponds
to
a
specific
displacement/
power
configuration.
(
10)
State
the
engine's
useful
life
if
it
is
different
than
the
minimum
value.
(
11)
List
specifications
and
adjustments
for
engine
tuneups;
show
the
proper
position
for
the
transmission
during
tuneup
and
state
which
accessories
should
be
operating.
(
12)
Identify
the
emission
standards
or
family
emission
limits
to
which
you
have
certified
the
engine.
(
d)
Some
of
your
engines
may
need
more
information
on
the
emission
control
information
label.
If
you
produce
an
engine
or
vehicle
that
we
exempt
from
the
requirements
of
this
part,
see
subpart
G
of
this
part
and
40
CFR
part
1068,
subparts
C
and
D,
for
more
label
information.
(
e)
Some
engines
may
not
have
enough
space
for
an
emission
control
information
label
with
all
the
required
information.
In
this
case,
you
may
omit
the
information
required
in
paragraphs
(
c)(
3),
(
c)(
4),
and
(
c)(
5)
of
this
section
if
you
print
it
in
the
owner's
manual
instead.
(
f)
If
you
are
unable
to
meet
these
labeling
requirements,
you
may
ask
us
to
modify
them
consistent
with
the
intent
of
this
section.
(
g)
Label
every
vehicle
certified
under
this
part
with
a
removable
hang
tag
showing
its
emission
characteristics
relative
to
other
models.
The
label
should
be
attached
securely
to
the
vehicle
before
it
is
offered
for
sale
in
such
a
manner
that
it
would
not
be
accidentally
removed
prior
to
sale.
Use
the
applicable
equations
of
this
paragraph
(
g)
to
determine
the
normalized
emission
rate
(
NER)
from
the
FEL
for
your
vehicle.
If
the
vehicle
is
certified
without
using
the
averaging
provisions
of
subpart
H,
use
the
final
deteriorated
emission
level.
Round
the
resulting
normalized
emission
rate
for
your
vehicle
to
the
nearest
whole
number.
We
may
specify
a
standardized
format
for
labels.
At
a
minimum,
the
tag
should
include:
The
manufacturer's
name,
vehicle
model
name,
engine
description
(
500
cc
two
stroke
with
DFI),
the
NER,
and
a
brief
explanation
of
the
scale
(
for
example,
note
that
0
is
the
cleanest
and
10
is
the
least
clean).
(
1)
For
snowmobiles,
use
the
following
equation:
NER
=
16.61
×
log(
2.667
×
HC
+
CO)
¥
38.22
Where:
HC
and
CO
are
the
cycle
weighted
FELs
(
or
emission
rates)
for
hydrocarbons
and
carbon
monoxide
in
g/
kW
hr.
(
2)(
i)
For
off
highway
motorcycles
with
HC+
NOX
emissions
less
than
or
equal
to
2.0
g/
km,
use
the
following
equation:
(
NER
=
2.500
×
(
HC
+
NOX)
Where:
HC
+
NOX
is
the
FEL
(
or
the
sum
of
the
cycle
weighted
emission
rates)
for
hydrocarbons
and
oxides
of
nitrogen
in
g/
km.
(
ii)
For
off
highway
motorcycles
with
HC+
NOX
emissions
greater
than
2.0
g/
km,
use
the
following
equation:
NER
=
5.000
×
log(
HC
+
NOX)
+
3.495
Where:
HC
+
NOX
is
the
FEL
(
or
the
sum
of
the
cycle
weighted
emission
rates)
for
hydrocarbons
and
oxides
of
nitrogen
in
g/
km.
(
3)(
i)
For
ATVs
with
HC+
NOX
emissions
less
than
or
equal
to
1.5
g/
km,
use
the
following
equation:
NER
=
3.333
×
(
HC
+
NOX)
Where:
HC
+
NOX
is
the
FEL
(
or
the
sum
of
the
cycle
weighted
emission
rates)
for
hydrocarbons
and
oxides
of
nitrogen
in
g/
km.
(
ii)
For
ATVs
with
HC+
NOX
emissions
greater
than
1.5
g/
km,
use
the
following
equation:
NER
=
4.444
×
log(
HC
+
NOX)
+
4.217
Where:
HC
+
NOX
is
the
FEL
(
or
the
sum
of
the
cycle
weighted
emission
rates)
for
hydrocarbons
and
oxides
of
nitrogen
in
g/
km.
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Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
§
1051.145
What
provisions
apply
only
for
a
limited
time?
Apply
the
following
provisions
instead
of
others
in
this
part
for
the
periods
and
circumstances
specified
in
this
section.
(
a)
Provisions
for
small
volume
manufacturers.
Special
provisions
apply
to
you
if
you
are
a
small
volume
manufacturer
subject
to
the
requirements
of
this
part.
Contact
us
before
2006
if
you
intend
to
use
these
provisions.
(
1)
You
may
delay
complying
with
otherwise
applicable
emission
standards
(
and
other
requirements)
for
two
model
years.
(
2)
If
you
are
a
small
volume
manufacturer
of
snowmobiles,
only
50
percent
of
the
models
you
produce
(
instead
of
all
of
the
models
you
produce)
must
meet
emission
standards
in
the
first
two
years
they
apply
to
you
as
a
small
volume
manufacturer,
as
described
in
paragraph
(
a)(
1)
of
this
section.
For
example,
this
alternate
phase
in
allowance
would
allow
smallvolume
snowmobile
manufacturers
to
comply
with
the
Phase
1
exhaust
standards
by
certifying
50
percent
of
their
snowmobiles
in
2008,
50
percent
of
their
snowmobiles
in
2009,
and
100
percent
in
2010.
(
3)
Your
vehicles
for
model
years
before
2011
may
be
exempt
from
the
exhaust
standards
of
this
part
if
you
meet
the
following
criteria:
(
i)
Produce
your
vehicles
by
installing
engines
covered
by
a
valid
certificate
of
conformity
under
40
CFR
part
90
that
shows
the
engines
meet
standards
for
Class
II
engines
for
each
engine's
model
year.
(
ii)
Do
not
change
the
engine
in
a
way
that
we
could
reasonably
expect
to
increase
its
exhaust
emissions.
(
iii)
The
engine
meets
all
applicable
requirements
from
40
CFR
part
90.
This
applies
to
engine
manufacturers,
vehicle
manufacturers
who
use
these
engines,
and
all
other
persons
as
if
these
engines
were
not
used
in
recreational
vehicles.
(
iv)
Demonstrate
that
fewer
than
50
percent
of
the
engine
model's
total
sales,
from
all
companies,
are
used
in
recreational
vehicles
regulated
under
this
part.
(
4)
All
vehicles
certified
or
exempted
under
this
paragraph
(
a)
must
be
labeled
according
to
our
specifications.
The
label
must
include
the
following:
(
i)
The
heading
``
EMISSION
CONTROL
INFORMATION''.
(
ii)
Your
full
corporate
name
and
trademark.
(
iii)
A
description
of
the
provisions
under
which
the
vehicle
is
either
exempted
or
certified.
(
iv)
Other
information
that
we
specify
to
you
in
writing.
(
b)
Optional
emission
standards
for
ATVs.
To
meet
ATV
standards
for
model
years
before
2009,
you
may
apply
the
exhaust
emission
standards
by
model
year
in
paragraph
(
b)(
1)
of
this
section
while
measuring
emissions
using
the
engine
based
test
procedures
in
40
CFR
part
1065
instead
of
the
chassis
based
test
procedures
in
40
CFR
part
86.
(
1)
Follow
Table
1
of
this
section
for
exhaust
emission
standards,
while
meeting
all
the
other
requirements
of
§
1051.107.
You
may
use
emission
credits
to
show
compliance
with
these
standards
(
see
subpart
H
of
this
part).
You
may
not
exchange
emission
credits
with
engine
families
meeting
the
standards
in
§
1051.107(
a).
You
may
also
not
exchange
credits
between
engine
families
certified
to
the
standards
for
engines
above
225
cc
and
engine
families
certified
to
the
standards
for
engines
below
225
cc.
The
phase
in
percentages
in
the
table
specify
the
percentage
of
your
U.
S.
directed
production
that
must
comply
with
the
emission
standards
for
those
model
years.
Table
1
follows:
TABLE
1
OF
§
1051.145.
OPTIONAL
EXHAUST
EMISSION
STANDARDS
FOR
ATVS
(
G/
KW
HR)
Engine
displacement
Model
year
Phase
in
(
percent)
Emission
standards
Maximum
allowable
family
emission
limits
HC+
NOX
CO
HC+
NOX
2006
..........................................................
50
16.1
400
32.2
<
225
cc
.....................................................
2007
and
2008
.........................................
100
16.1
400
32.2
2006
..........................................................
50
13.4
400
26.8
225
cc
.....................................................
2007
and
2008
.........................................
100
13.4
400
26.8
(
2)
Measure
emissions
by
testing
the
engine
on
a
dynamometer
with
the
steady
state
duty
cycle
described
in
Table
2
of
this
section.
(
i)
During
idle
mode,
hold
the
speed
within
your
specifications,
keep
the
throttle
fully
closed,
and
keep
engine
torque
under
5
percent
of
the
peak
torque
value
at
maximum
test
speed.
(
ii)
For
the
full
load
operating
mode,
operate
the
engine
at
its
maximum
fueling
rate.
(
iii)
See
part
1065
of
this
chapter
for
detailed
specifications
of
tolerances
and
calculations.
(
iv)
Table
2
follows:
TABLE
2
OF
§
1051.145.
6
MODE
DUTY
CYCLE
FOR
RECREATIONAL
ENGINES
Mode
No.
Engine
speed
(
percent
of
maximum
test
speed)
Torque
(
percent
of
maximum
test
torque
at
test
speed)
Minimum
time
in
mode
(
minutes)
Weighting
factors
1
.....................................................................................................................
85
100
5.0
0.09
2
.....................................................................................................................
85
75
5.0
0.20
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TABLE
2
OF
§
1051.145.
6
MODE
DUTY
CYCLE
FOR
RECREATIONAL
ENGINES
Continued
Mode
No.
Engine
speed
(
percent
of
maximum
test
speed)
Torque
(
percent
of
maximum
test
torque
at
test
speed)
Minimum
time
in
mode
(
minutes)
Weighting
factors
3
.....................................................................................................................
85
50
5.0
0.29
4
.....................................................................................................................
85
25
5.0
0.30
5
.....................................................................................................................
85
10
5.0
0.07
6
.....................................................................................................................
Idle
0
5.0
0.05
(
3)
For
ATVs
certified
to
the
standards
in
this
paragraph
(
b)
use
the
following
equation
to
determine
the
normalized
emission
rate
required
by
§
1051.135(
g):
NER
=
9.898
×
log(
HC
+
NOX
¥
4.898
Where:
HC
+
NOX
is
the
sum
of
the
cycle
weighted
emission
rates
for
hydrocarbons
and
oxides
of
nitrogen
in
g/
kW
hr.
(
c)
Production
line
testing.
Vehicles
certified
to
the
Phase
1
or
Phase
2
standards
in
§
1051.103,
or
the
Phase
1
standards
in
§
§
1051.105
or
1051.107
are
exempt
from
the
production
line
testing
requirements
of
subpart
D
of
this
part
if
they
are
certified
without
participating
in
the
emission
averaging,
banking
and
trading
program
described
in
Subpart
H
of
this
part.
(
d)
Phase
in
flexibility.
For
model
years
before
2014,
if
you
make
a
good
faith
effort
to
comply,
but
fail
to
meet
the
sales
requirements
of
this
part
during
a
phase
in
period
for
new
standards,
or
fail
to
meet
the
average
emission
standards,
we
may
approve
an
alternative
remedy
to
offset
the
emission
reduction
deficit
using
future
emission
credits
under
this
part.
To
apply
for
this,
you
must:
(
1)
Submit
a
plan
during
the
certification
process
for
the
first
model
year
of
the
phase
in
showing
how
you
project
to
meet
the
sales
requirement
of
the
phase
in.
(
2)
Notify
us
less
than
30
days
after
you
determine
that
you
are
likely
to
fail
to
comply
with
the
sales
requirement
of
the
phase
in.
(
3)
Propose
a
remedy
that
will
achieve
equivalent
or
greater
emission
reductions
compared
to
the
specified
phase
in
requirements,
and
that
will
offset
the
deficit
within
one
model
year.
(
e)
Snowmobile
testing.
You
may
use
the
raw
sampling
procedures
described
in
40
CFR
part
91,
subparts
D
and
E,
for
emission
testing
of
snowmobiles
for
model
years
prior
to
2010.
For
later
model
years,
you
may
use
these
procedures
if
you
show
that
they
produce
emission
measurements
equivalent
to
the
otherwise
specified
test
procedures.
(
f)
Early
credits.
Snowmobile
manufacturers
may
generate
early
emission
credits
in
one
of
the
following
ways,
by
certifying
some
or
all
of
their
snowmobiles
prior
to
2006.
Credit
generating
snowmobiles
must
meet
all
other
applicable
requirements
of
this
part.
No
early
credits
may
be
generated
by
off
highway
motorcycles
or
ATVs.
(
1)
You
may
certify
one
or
more
snowmobile
engine
families
to
FELs
(
HC
and
CO)
below
the
numerical
level
of
the
Phase
2
standards
prior
to
the
date
when
compliance
with
the
Phase
1
standard
is
otherwise
required.
Credits
are
calculated
relative
to
the
Phase
2
standards.
Credits
generated
under
this
paragraph
(
f)(
1)
may
be
used
at
any
time
before
2012.
(
2)
You
may
certify
a
snowmobile
engine
family
to
FELs
(
HC
and
CO)
below
the
numerical
level
of
the
Phase
1
standards
prior
to
the
date
when
compliance
with
the
Phase
1
standard
is
otherwise
required.
Credits
are
calculated
relative
to
the
Phase
1
standards.
Credits
generated
under
this
paragraph
(
f)(
2)
may
only
be
used
for
compliance
with
the
Phase
1
standards.
You
may
generate
credits
under
this
paragraph
(
f)(
2)
without
regard
to
whether
the
FELs
are
above
or
below
the
numerical
level
of
the
Phase
2
standards.
(
g)
Pull
ahead
option
for
permeation
emissions.
Manufacturers
choosing
to
comply
with
an
early
tank
permeation
standard
of
3.0
g/
m2/
day
prior
to
model
year
2008
may
be
allowed
to
delay
compliance
with
the
1.5
g/
m2/
day
standard,
for
an
equivalent
number
of
tanks,
subject
to
the
following
provisions:
(
1)
Pull
ahead
tanks
meeting
the
3.0
g/
m2/
day
standard
must
be
certified
and
must
meet
all
applicable
requirements
other
than
those
limited
to
compliance
with
the
exhaust
standards.
(
2)
Tanks
for
which
compliance
with
the
1.5
g/
m2/
day
standard
is
delayed
must
meet
the
3.0
g/
m2/
day
standard.
(
3)
You
may
delay
compliance
with
the
1.5
g/
m2/
day
standard
for
one
tank
for
one
year
for
each
tank
year
of
credit
generated
early.
(
4)
You
may
not
use
credits
for
a
tank
that
is
larger
than
the
tank
from
which
you
generated
the
credits.
Subpart
C
Certifying
Engine
Families
§
1051.201
What
are
the
general
requirements
for
submitting
a
certification
application?
(
a)
Send
us
an
application
for
a
certificate
of
conformity
for
each
engine
family.
Each
application
is
valid
for
only
one
model
year.
(
b)
The
application
must
not
include
false
or
incomplete
statements
or
information
(
see
§
1051.255).
(
c)
We
may
choose
to
ask
you
to
send
us
less
information
than
we
specify
in
this
subpart,
but
this
would
not
change
your
recordkeeping
requirements.
(
d)
Use
good
engineering
judgment
for
all
decisions
related
to
your
application
(
see
§
1068.5
of
this
chapter).
(
e)
An
authorized
representative
of
your
company
must
approve
and
sign
the
application.
§
1051.205
What
must
I
include
in
my
application?
In
your
application,
do
all
the
following
things
unless
we
ask
you
to
send
us
less
information:
(
a)
Describe
the
engine
family's
specifications
and
other
basic
parameters
of
the
vehicle
design.
List
the
types
of
fuel
you
intend
to
use
to
certify
the
engine
family
(
for
example,
gasoline,
liquefied
petroleum
gas,
methanol,
or
natural
gas).
List
vehicle
configurations
and
model
names
that
are
included
in
the
engine
family.
(
b)
Explain
how
the
emission
control
systems
operate.
(
1)
Describe
in
detail
all
the
system
components
for
controlling
exhaust
emissions,
including
auxiliary
emissioncontrol
devices
and
all
fuel
system
components
you
will
install
on
any
production
or
test
vehicle
or
engine.
Explain
why
any
auxiliary
emissioncontrol
devices
are
not
defeat
devices
(
see
§
1051.115(
f)).
Do
not
include
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and
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detailed
calibrations
for
components
unless
we
ask
for
them.
(
2)
Describe
the
evaporative
emission
controls.
(
c)
Describe
the
vehicles
or
engines
you
selected
for
testing
and
the
reasons
for
selecting
them.
(
d)
Describe
any
special
or
alternate
test
procedures
you
used
(
see
§
1051.501).
(
e)
Describe
how
you
operated
the
engine
or
vehicle
prior
to
testing,
including
the
duty
cycle
and
the
number
of
engine
operating
hours
used
to
stabilize
emission
levels,
and
any
scheduled
maintenance
you
performed.
(
f)
List
the
specifications
of
the
test
fuels
to
show
that
they
fall
within
the
required
ranges.
(
g)
Identify
the
engine
family's
useful
life.
(
h)
Propose
maintenance
and
use
instructions
for
the
ultimate
buyer
of
each
new
vehicle
(
see
§
1051.125).
(
i)
Propose
emission
related
installation
instructions
if
you
sell
engines
for
someone
else
to
install
in
a
vehicle
(
see
§
1051.130).
(
j)
Propose
an
emission
control
information
label.
(
k)
Present
emission
data
to
show
that
you
meet
emission
standards.
(
1)
Present
exhaust
emission
data
for
HC,
NOX
(
as
applicable),
and
CO
on
a
test
vehicle
or
engine
to
show
your
vehicles
meet
the
emission
standards
we
specify
in
subpart
B
of
this
part.
Show
these
figures
before
and
after
applying
deterioration
factors
for
each
vehicle
or
engine.
Include
test
data
for
each
type
of
fuel
from
part
1065,
subpart
C,
of
this
chapter
on
which
you
intend
for
vehicles
in
the
engine
family
to
operate
(
for
example,
gasoline,
liquefied
petroleum
gas,
methanol,
or
natural
gas).
If
we
specify
more
than
one
grade
of
any
fuel
type
(
for
example,
a
summer
grade
and
winter
grade
of
gasoline),
you
only
need
to
submit
test
data
for
one
grade,
unless
the
regulations
of
this
part
explicitly
specify
otherwise
for
your
vehicle.
(
2)
Present
evaporative
test
data
for
HC
to
show
your
vehicles
meet
the
evaporative
emission
standards
we
specify
in
subpart
B
of
this
part.
Show
these
figures
before
and
after
applying
deterioration
factors
for
each
vehicle
or
engine,
where
applicable.
If
you
did
not
perform
the
testing,
identify
the
source
of
the
test
data.
(
3)
Note
that
§
1051.235
and
1051.245
allows
you
to
submit
an
application
in
certain
cases
without
new
emission
data.
(
l)
Report
all
test
results,
including
those
from
invalid
tests
or
from
any
nonstandard
tests
(
such
as
measurements
based
on
exhaust
concentrations
in
parts
per
million).
(
m)
Identify
the
engine
family's
deterioration
factors
and
describe
how
you
developed
them.
Present
any
emission
test
data
you
used
for
this.
(
n)
Describe
all
adjustable
operating
parameters
and
other
adjustments
(
see
§
1051.115
(
c)
and
(
d)),
including
the
following:
(
1)
The
nominal
or
recommended
setting.
(
2)
The
intended
physically
adjustable
range,
including
production
tolerances
if
they
affect
the
range.
(
3)
The
limits
or
stops
used
to
establish
adjustable
ranges.
(
4)
The
air
fuel
ratios
or
jet
chart
specified
in
§
1051.115(
d).
(
o)
State
that
you
operated
your
test
vehicles
or
engines
according
to
the
specified
procedures
and
test
parameters
using
the
fuels
described
in
the
application
to
show
you
meet
the
requirements
of
this
part.
(
p)
State
unconditionally
that
all
the
vehicles
(
and/
or
engines)
in
the
engine
family
comply
with
the
requirements
of
this
part,
other
referenced
parts,
and
the
Clean
Air
Act.
(
q)
Include
estimates
of
U.
S.
directed
production
volumes.
(
r)
Show
us
how
to
modify
your
production
vehicles
to
measure
emissions
in
the
field
(
see
§
1051.115).
(
s)
Add
other
information
to
help
us
evaluate
your
application
if
we
ask
for
it.
§
1051.210
May
I
get
preliminary
approval
before
I
complete
my
application?
If
you
send
us
information
before
you
finish
the
application,
we
will
review
it
and
make
any
appropriate
determinations
listed
in
§
1051.215(
b)(
1)
through
(
5).
Decisions
made
under
this
section
are
considered
to
be
preliminary
approval.
We
will
generally
not
disapprove
applications
under
§
1051.215(
b)(
1)
through
(
5)
where
we
have
given
you
preliminary
approval,
unless
we
find
new
and
substantial
information
supporting
a
different
decision.
(
a)
If
you
request
preliminary
approval
related
to
the
upcoming
model
year
or
the
model
year
after
that,
we
will
make
a
``
best
efforts''
attempt
to
make
the
appropriate
determinations
as
soon
as
possible.
We
will
generally
not
provide
preliminary
approval
related
to
a
future
model
year
more
than
two
years
ahead
of
time.
(
b)
If
we
have
published
general
guidance
that
serves
as
our
determination
for
your
situation,
you
may
consider
that
to
be
preliminary
approval.
§
1051.215
What
happens
after
I
complete
my
application?
(
a)
If
any
of
the
information
in
your
application
changes
after
you
submit
it,
amend
it
as
described
in
§
1051.225.
(
b)
We
may
deny
your
application
(
that
is,
determine
that
we
cannot
approve
it
without
revision)
if
the
engine
family
does
not
meet
the
requirements
of
this
part
or
the
Act.
For
example:
(
1)
If
you
inappropriately
use
the
provisions
of
§
1051.230(
c)
or
(
d)
to
define
a
broader
or
narrower
engine
family,
we
will
require
you
to
redefine
your
engine
family.
(
2)
If
we
determine
you
did
not
appropriately
select
the
useful
life
as
specified
in
§
1051.103(
c),
§
1051.105(
c),
or
§
1051.107(
c),
we
will
require
you
to
lengthen
it.
(
3)
If
we
determine
you
did
not
appropriately
select
deterioration
factors
under
§
1051.240(
c),
we
will
require
you
to
revise
them.
(
4)
If
your
proposed
emission
control
information
label
is
inconsistent
with
§
1051.135,
we
will
require
you
to
change
it
(
and
tell
you
how,
if
possible).
(
5)
If
you
require
or
recommend
maintenance
and
use
instructions
inconsistent
with
§
1051.125,
we
will
require
you
to
change
them.
(
6)
If
we
find
any
other
problem
with
your
application,
we
will
tell
you
what
the
problem
is,
and
what
needs
to
be
corrected.
(
c)
If
we
determine
your
application
is
complete
and
shows
that
the
engine
family
meets
all
the
requirements
of
this
part
and
the
Act,
we
will
issue
a
certificate
of
conformity
for
your
engine
family
for
that
model
year.
If
we
deny
the
application,
we
will
explain
why
in
writing.
You
may
then
ask
us
to
hold
a
hearing
to
reconsider
our
decision
(
see
§
1051.820).
§
1051.220
How
do
I
amend
the
maintenance
instructions
in
my
application?
Send
the
Designated
Officer
a
request
to
amend
your
application
for
certification
for
an
engine
family
if
you
want
to
change
the
emission
related
maintenance
instructions
in
a
way
that
could
affect
emissions.
In
your
request,
describe
the
proposed
changes
to
the
maintenance
instructions.
(
a)
If
you
are
decreasing
the
specified
level
of
maintenance,
you
may
distribute
the
new
maintenance
instructions
to
your
customers
30
days
after
we
receive
your
request,
unless
we
disapprove
your
request.
We
may
approve
a
shorter
time
or
waive
this
requirement.
(
b)
If
your
requested
change
would
not
decrease
the
specified
level
of
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maintenance,
you
may
distribute
the
new
maintenance
instructions
anytime
after
you
send
your
request.
(
c)
If
you
are
correcting
or
clarifying
your
maintenance
instructions
or
if
you
are
changing
instructions
for
maintenance
unrelated
to
emission
controls,
the
requirements
of
this
section
do
not
apply.
§
1051.225
How
do
I
amend
my
application
to
include
new
or
modified
vehicles
or
to
change
an
FEL?
(
a)
You
must
amend
your
application
for
certification
before
you
take
either
of
the
following
actions:
(
1)
Add
a
vehicle
to
a
certificate
of
conformity.
(
2)
Make
a
design
change
for
a
certified
engine
family
that
may
affect
emissions
or
an
emission
related
part
over
the
vehicle's
lifetime.
(
3)
Modify
an
FEL
for
an
engine
family,
as
described
in
paragraph
(
f)
of
this
section.
(
b)
Send
the
Designated
Officer
a
request
to
amend
the
application
for
certification
for
an
engine
family.
In
your
request,
do
all
of
the
following:
(
1)
Describe
the
vehicle
model
or
configuration
you
are
adding
or
changing.
(
2)
Include
engineering
evaluations
or
reasons
why
the
original
test
vehicle
or
engine
is
or
is
not
still
appropriate.
(
3)
If
the
original
test
vehicle
or
engine
for
the
engine
family
is
not
appropriate
to
show
compliance
for
the
new
or
modified
vehicle,
include
new
test
data
showing
that
the
new
or
modified
vehicle
meets
the
requirements
of
this
part.
(
c)
You
may
start
producing
the
new
or
modified
vehicle
anytime
after
the
time
at
which
you
send
us
your
request
(
for
example,
the
day
you
mail
your
request).
If
we
determine
that
the
affected
vehicles
do
not
meet
applicable
requirements,
we
will
require
you
to
cease
production
of
the
vehicles
and
to
recall
and
correct
the
vehicles
at
no
expense
to
the
owner.
If
you
choose
to
produce
vehicles
under
this
paragraph,
we
will
consider
that
to
be
consent
to
recall
all
vehicles
that
we
determine
do
not
meet
applicable
standards
and
other
requirements
and
to
remedy
the
nonconformity
at
no
expense
to
the
owner.
(
d)
You
must
give
us
test
data
within
30
days
if
we
ask
for
more
testing,
or
stop
producing
the
vehicle
if
you
are
not
able
to
do
this.
You
may
give
us
an
engineering
evaluation
instead
of
test
data
if
we
agree
that
you
can
address
our
questions
without
test
data.
(
e)
If
we
determine
that
the
certificate
of
conformity
would
not
cover
your
new
or
modified
vehicle,
we
will
send
you
a
written
explanation
of
our
decision.
In
this
case,
you
may
no
longer
produce
these
vehicles,
though
you
may
ask
for
a
hearing
for
us
to
reconsider
our
decision
(
see
§
1051.820).
(
f)
You
may
ask
to
change
your
FEL
in
the
following
cases:
(
1)
You
may
ask
to
raise
your
FEL
for
your
engine
family
after
the
start
of
production.
You
must
use
the
higher
FEL
for
the
entire
family
to
calculate
your
average
emission
level
under
subpart
H
of
this
part.
In
your
request,
you
must
demonstrate
that
you
will
still
be
able
to
comply
with
the
applicable
average
emission
standards
as
specified
in
subparts
B
and
H
of
this
part.
(
2)
You
may
ask
to
lower
the
FEL
for
your
engine
family
after
the
start
of
production
only
when
you
have
test
data
from
production
vehicles
indicating
that
your
vehicles
comply
with
the
lower
FEL.
You
may
create
a
separate
subfamily
with
the
lower
FEL.
Otherwise,
you
must
use
the
higher
FEL
for
the
family
to
calculate
your
average
emission
level
under
subpart
H
of
this
part.
(
3)
If
you
change
the
FEL
during
production,
you
must
include
the
new
FEL
on
the
emission
control
information
label
for
all
vehicles
produced
after
the
change.
§
1051.230
How
do
I
select
engine
families?
(
a)
Divide
your
product
line
into
families
of
vehicles
that
you
expect
to
have
similar
emission
characteristics.
Your
engine
family
is
limited
to
a
single
model
year.
(
b)
Group
vehicles
in
the
same
engine
family
if
they
are
the
same
in
all
of
the
following
aspects:
(
1)
The
combustion
cycle.
(
2)
The
cooling
system
(
water
cooled
vs.
air
cooled).
(
3)
Configuration
of
the
fuel
system
(
for
example,
port
fuel
injection
vs.
carburetion).
(
4)
Method
of
air
aspiration.
(
5)
The
number,
location,
volume,
and
composition
of
catalytic
converters.
(
6)
Type
of
fuel.
(
7)
The
number,
arrangement,
and
approximate
bore
diameter
of
cylinders.
(
8)
Evaporative
emission
controls.
(
c)
In
some
cases
you
may
subdivide
a
group
of
vehicles
that
is
identical
under
paragraph
(
b)
of
this
section
into
different
engine
families.
To
do
this
under
normal
circumstances,
you
must
show
you
expect
emission
characteristics
to
be
different
during
the
useful
life
or
that
any
of
the
following
engine
characteristics
are
different:
(
1)
Method
of
actuating
intake
and
exhaust
timing
(
poppet
valve,
reed
valve,
rotary
valve,
etc.).
(
2)
Location
or
size
of
intake
and
exhaust
valves
or
ports.
(
3)
Configuration
of
the
combustion
chamber.
(
4)
Cylinder
stroke
or
actual
bore
diameter.
(
5)
Exhaust
system.
(
d)
In
some
cases,
you
may
include
different
engines
in
the
same
engine
family,
even
though
they
are
not
identical
with
respect
to
the
things
listed
in
paragraph
(
b)
of
this
section.
(
1)
If
different
engines
have
similar
emission
characteristics
during
the
useful
life,
we
may
approve
grouping
them
in
the
same
engine
family.
(
2)
If
you
are
a
small
volume
manufacturer,
you
may
group
engines
from
any
vehicles
subject
to
the
same
emission
standards
into
a
single
engine
family.
This
does
not
change
any
of
the
requirements
of
this
part
for
showing
that
an
engine
family
meets
emission
standards.
(
e)
If
you
cannot
appropriately
define
engine
families
by
the
method
in
this
section,
we
will
define
them
based
on
features
related
to
emission
characteristics.
(
f)
You
may
ask
us
to
create
separate
families
for
exhaust
emissions
and
evaporative
emissions.
If
we
do
this,
list
both
families
on
the
emission
control
information
label.
§
1051.235
What
emission
testing
must
I
perform
for
my
application
for
a
certificate
of
conformity?
This
section
describes
the
emission
testing
you
must
perform
to
show
compliance
with
the
emission
standards
in
subpart
B
of
this
part
during
certification.
(
a)
Test
your
emission
data
vehicles
using
the
procedures
and
equipment
specified
in
subpart
F
of
this
part.
Where
specifically
required
or
allowed,
test
the
engine
instead
of
the
vehicle.
For
evaporative
emissions,
test
the
fuel
system
components
separate
from
the
vehicle.
(
b)
Select
from
each
engine
family
a
test
vehicle
or
engine,
and
a
fuel
system
for
each
fuel
type
with
a
configuration
that
is
most
likely
to
exceed
the
emission
standards,
using
good
engineering
judgment,
consider
the
emission
levels
of
all
exhaust
constituents
over
the
full
useful
life
of
the
vehicle.
(
c)
You
may
use
previously
generated
emission
data
in
the
following
cases:
(
1)
You
may
submit
emission
data
for
equivalent
engine
families
from
previous
years
instead
of
doing
new
tests,
but
only
if
the
data
show
that
the
test
vehicle
or
engine
would
meet
all
the
requirements
for
the
latest
vehicle
or
engine
models.
We
may
require
you
to
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2002
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and
Regulations
do
new
emission
testing
if
we
believe
the
latest
vehicle
or
engine
models
could
be
substantially
different
from
the
previously
tested
vehicle
or
engine.
(
2)
You
may
submit
emission
data
for
equivalent
engine
families
performed
to
show
compliance
with
other
standards
(
such
as
California
standards)
instead
of
doing
new
tests,
but
only
if
the
data
show
that
the
test
vehicle
or
engine
would
meet
all
of
this
part's
requirements.
(
3)
You
may
submit
evaporative
emission
data
measured
by
a
fuel
system
supplier.
We
may
require
you
to
verify
that
the
testing
was
conducted
in
accordance
with
the
applicable
regulations.
(
d)
We
may
choose
to
measure
emissions
from
any
of
your
test
vehicles
or
engines
(
or
other
vehicles
or
engines
in
the
engine
family).
(
1)
If
we
do
this,
you
must
provide
the
test
vehicle
or
engine
at
the
location
we
select.
We
may
decide
to
do
the
testing
at
your
plant
or
any
other
facility.
If
we
choose
to
do
the
testing
at
your
plant,
you
must
schedule
it
as
soon
as
possible
and
make
available
the
instruments
and
equipment
we
need.
(
2)
If
we
measure
emissions
on
one
of
your
test
vehicles
or
engines,
the
results
of
that
testing
become
the
official
data
for
the
vehicle
or
engine.
Unless
we
later
invalidate
this
data,
we
may
decide
not
to
consider
your
data
in
determining
if
your
engine
family
meets
the
emission
standards.
(
3)
Before
we
test
one
of
your
vehicles
or
engines,
we
may
set
its
adjustable
parameters
to
any
point
within
the
physically
adjustable
ranges
(
see
§
1051.115(
c)).
We
may
also
adjust
the
air
fuel
ratio
within
the
adjustable
range
specified
in
§
1051.115(
d).
(
4)
Calibrate
the
test
vehicle
or
engine
within
normal
production
tolerances
for
anything
not
covered
by
§
1051.115(
c)
and
(
d)
of
this
section.
(
e)
If
you
are
a
small
volume
manufacturer,
you
may
certify
by
design
on
the
basis
of
preexisting
exhaust
emission
data
for
similar
technologies
and
other
relevant
information,
and
in
accordance
with
good
engineering
judgment.
In
those
cases,
you
are
not
required
to
test
your
vehicles.
This
is
called
``
design
certification''
or
``
certifying
by
design.''
To
certify
by
design,
you
must
show
that
the
technology
used
on
your
engines
is
sufficiently
similar
to
the
previously
tested
technology
that
a
person
reasonably
familiar
with
emissioncontrol
technology
would
believe
that
your
engines
will
comply
with
the
emission
standards.
(
f)
For
fuel
tanks
that
are
certified
based
on
permeability
treatments
for
plastic
fuel
tanks,
you
do
not
need
to
test
each
engine
family.
However,
you
must
use
good
engineering
judgment
to
determine
permeation
rates
for
the
tanks.
This
requires
that
more
than
one
fuel
tank
be
tested
for
each
set
of
treatment
conditions.
You
may
not
use
test
data
from
a
given
tank
for
any
other
tanks
that
have
thinner
walls.
You
may,
however,
use
test
data
from
a
given
tank
for
other
tanks
that
have
thicker
walls.
This
applies
to
both
low
hour
(
i.
e.,
baseline
testing)
and
durability
testing.
Note
that
§
1051.245
allows
you
to
use
design
based
certification
instead
of
generating
new
emission
data.
§
1051.240
How
do
I
demonstrate
that
my
engine
family
complies
with
exhaust
emission
standards?
(
a)
For
certification,
your
engine
family
is
considered
to
be
in
compliance
with
the
numerical
exhaust
emission
standards
in
subpart
B
of
this
part
if
all
emission
data
vehicles
representing
that
family
have
test
results
showing
emission
levels
at
or
below
the
standards.
(
b)
Your
engine
family
does
not
comply
if
any
emission
data
vehicle
representing
that
family
has
test
results
showing
emission
levels
above
the
standards
for
any
pollutant.
(
c)
To
compare
emission
levels
from
the
emission
data
vehicle
with
the
emission
standards,
apply
deterioration
factors
(
to
three
significant
figures)
to
the
measured
emission
levels.
The
deterioration
factor
is
a
number
that
shows
the
relationship
between
exhaust
emissions
at
the
end
of
useful
life
and
at
the
low
hour
test
point.
Section
1051.520
specifies
how
to
test
your
vehicle
to
develop
deterioration
factors
that
estimate
the
change
in
emissions
over
your
vehicle's
full
useful
life.
Small
volume
manufacturers
may
use
assigned
deterioration
factors
that
we
establish.
Apply
the
deterioration
factors
as
follows:
(
1)
For
vehicles
that
use
aftertreatment
technology,
such
as
catalytic
converters,
the
exhaust
deterioration
factor
is
the
ratio
of
exhaust
emissions
at
the
end
of
useful
life
to
exhaust
emissions
at
the
low
hour
test
point.
Adjust
the
official
emission
results
for
each
tested
vehicle
at
the
selected
test
point
by
multiplying
the
measured
emissions
by
the
deterioration
factor.
If
the
factor
is
less
than
one,
use
one.
(
2)
For
vehicles
that
do
not
use
aftertreatment
technology,
the
exhaust
deterioration
factor
is
the
difference
between
exhaust
emissions
at
the
end
of
useful
life
and
exhaust
emissions
at
the
low
hour
test
point.
Adjust
the
official
emission
results
for
each
tested
vehicle
at
the
selected
test
point
by
adding
the
factor
to
the
measured
emissions.
If
the
factor
is
less
than
zero,
use
zero.
(
d)
After
adjusting
the
emission
levels
for
deterioration,
round
them
to
the
same
number
of
decimal
places
as
the
emission
standard.
Compare
the
rounded
emission
levels
to
the
emission
standard
for
each
test
vehicle.
§
1051.245
How
do
I
demonstrate
that
my
engine
family
complies
with
evaporative
emission
standards?
(
a)
For
certification,
your
engine
family
is
considered
in
compliance
with
the
evaporative
emission
standards
in
subpart
B
of
this
part
if
you
do
either
of
the
following:
(
1)
You
have
test
results
showing
permeation
emission
levels
from
the
fuel
tanks
and
fuel
lines
in
the
family
are
at
or
below
the
standards
in
§
1051.110
throughout
the
useful
life.
(
2)
You
comply
with
the
design
specifications
in
paragraph
(
e)
of
this
section.
(
b)
Your
engine
family
does
not
comply
if
any
fuel
tank
or
fuel
line
representing
that
family
has
test
results
showing
emission
levels
above
the
standards.
(
c)
To
compare
emission
levels
with
the
emission
standards,
apply
deterioration
factors
(
to
three
significant
figures)
to
the
measured
emission
levels.
The
deterioration
factor
is
a
number
that
shows
the
relationship
between
emissions
at
the
end
of
useful
life
and
at
the
low
hour
test
point.
For
permeation
emissions,
the
deterioration
factor
is
the
difference
between
evaporative
emissions
at
the
end
of
useful
life
and
evaporative
emissions
at
the
low
hour
test
point.
Adjust
the
official
emission
results
for
each
tested
vehicle
at
the
selected
test
point
by
adding
the
factor
to
the
measured
emissions.
If
the
factor
is
less
than
zero,
use
zero.
(
1)
Section
1051.515
specifies
how
to
test
your
fuel
tanks
to
develop
deterioration
factors
that
estimate
the
change
in
emissions
over
your
vehicle's
full
useful
life.
Small
volume
manufacturers
may
use
assigned
deterioration
factors
that
we
establish.
Apply
the
deterioration
factors
as
follows:
(
i)
Calculate
the
deterioration
factor
from
emission
tests
performed
before
and
after
the
durability
tests
described
in
§
1051.515(
c)
and
using
good
engineering
judgment.
The
durability
tests
described
in
§
1051.515(
c)
represent
the
minimum
requirements
for
determining
a
deterioration
factor.
You
may
not
use
a
deterioration
factor
that
is
less
than
the
difference
between
evaporative
emissions
before
and
after
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Rules
and
Regulations
the
durability
tests
described
in
§
1051.515(
c).
(
ii)
Do
not
apply
the
deterioration
factor
to
test
results
for
tanks
that
have
already
undergone
these
durability
tests.
(
2)
Determine
the
deterioration
factor
for
fuel
lines
using
good
engineering
judgment.
(
d)
After
adjusting
the
emission
levels
for
deterioration,
round
them
to
the
same
number
of
decimal
places
as
the
emission
standard.
Compare
the
rounded
emission
levels
to
the
emission
standard
for
each
test
vehicle.
(
e)
You
may
demonstrate
for
certification
that
your
engine
family
complies
with
the
evaporative
emission
standards
by
demonstrating
that
you
use
the
following
control
technologies:
(
1)
For
certification
to
the
standards
specified
in
§
1051.110(
a)
with
the
control
technologies
shown
in
the
following
table:
TABLE
1
OF
§
1051.245.
DESIGN
CERTIFICATION
TECHNOLOGIES
FOR
CONTROLLING
TANK
PERMEATION
If
the
tank
permeability
control
technology
is
.
.
.
Then
you
may
design
certify
with
a
tank
emission
level
of
.
.
.
(
i)
A
metal
fuel
tank
with
no
non
metal
gaskets
or
with
gaskets
made
from
a
low
permeability
material
1.
1.5
g/
m
2/
day.
(
ii)
A
metal
fuel
tank
with
non
metal
gaskets
with
an
exposed
surface
area
of
1000
mm
2
or
less.
1.5
g/
m
2/
day.
1
Permeability
of
10
g/
m
2/
day
or
less
according
to
ASTM
D
814
95
(
incorporated
by
reference
in
§
1051.810).
(
2)
For
certification
to
the
standards
specified
in
§
1051.110(
b)
with
the
control
technologies
shown
in
the
following
table:
TABLE
2
OF
§
1051.245.
DESIGN
CERTIFICATION
TECHNOLOGIES
FOR
CONTROLLING
FUEL
LINE
PERMEATION
If
the
fuel
line
permeability
control
technology
is
.
.
.
jennifer
Then
you
may
design
certify
with
a
fuel
line
permeation
emission
level
of
.
.
.
(
i)
Hose
meeting
Category
1
permeation
specifications
in
SAE
J2260
(
incorporated
by
reference
in
§
1051.810).
15
g/
m2/
day.
(
ii)
Hose
meeting
the
R11
A
or
R12
permeation
specifications
in
SAE
J30
(
incorporated
by
reference
in
§
1051.810).
15
g/
m2/
day.
(
3)
We
may
establish
additional
design
certification
options
where
we
find
that
new
test
data
demonstrate
that
the
use
of
other
technology
designs
will
ensure
compliance
with
the
applicable
emission
standards.
§
1051.250
What
records
must
I
keep
and
make
available
to
EPA?
(
a)
Organize
and
maintain
the
following
records
to
keep
them
readily
available;
we
may
review
these
records
at
any
time:
(
1)
A
copy
of
all
applications
and
any
summary
information
you
sent
us.
(
2)
Any
of
the
information
we
specify
in
§
1051.205
that
you
did
not
include
in
your
application.
(
3)
A
detailed
history
of
each
emission
data
vehicle.
In
each
history,
describe
all
of
the
following:
(
i)
The
emission
data
vehicle's
construction,
including
its
origin
and
buildup,
steps
you
took
to
ensure
that
it
represents
production
vehicles,
any
components
you
built
specially
for
it,
and
all
emission
related
components.
(
ii)
How
you
accumulated
vehicle
or
engine
operating
hours,
including
the
dates
and
the
number
of
hours
accumulated.
(
iii)
All
maintenance
(
including
modifications,
parts
changes,
and
other
service)
and
the
dates
and
reasons
for
the
maintenance.
(
iv)
All
your
emission
tests,
including
documentation
on
routine
and
standard
tests,
as
specified
in
part
1065
of
this
chapter
or
other
applicable
test
procedures
regulations,
and
the
date
and
purpose
of
each
test.
(
v)
All
tests
to
diagnose
engine
or
emission
control
performance,
giving
the
date
and
time
of
each
and
the
reasons
for
the
test.
(
vi)
Any
other
significant
events.
(
b)
Keep
routine
data
from
emission
tests
(
such
as
test
cell
temperatures
and
relative
humidity
readings)
for
one
year
after
we
issue
the
associated
certificate
of
conformity.
Keep
all
other
information
specified
in
paragraph
(
a)
of
this
section
for
eight
years
after
we
issue
your
certificate.
(
c)
Store
these
records
in
any
format
and
on
any
media,
as
long
as
you
can
promptly
send
us
organized,
written
records
in
English
if
we
ask
for
them.
(
d)
Send
us
copies
of
any
maintenance
instructions
or
explanations
if
we
ask
for
them.
§
1051.255
When
may
EPA
deny,
revoke,
or
void
my
certificate
of
conformity?
(
a)
We
may
deny
your
application
for
certification
if
your
engine
family
fails
to
comply
with
emission
standards
or
other
requirements
of
the
regulation
or
the
Act.
Our
decision
may
be
based
on
any
information
available
to
us
showing
you
do
not
meet
emission
standards
or
other
requirements,
including
any
testing
that
we
conduct
under
paragraph
(
g)
of
this
section.
If
we
deny
your
application,
we
will
explain
why
in
writing.
(
b)
In
addition,
we
may
deny
your
application
or
revoke
your
certificate
if
you
do
any
of
the
following:
(
1)
Refuse
to
comply
with
any
testing
or
reporting
requirements.
(
2)
Submit
false
or
incomplete
information
(
paragraph
(
d)
of
this
section
applies
if
this
is
fraudulent).
(
3)
Render
inaccurate
any
test
data.
(
4)
Deny
us
from
completing
authorized
activities
despite
our
presenting
a
warrant
or
court
order
(
see
§
1068.20
of
this
chapter).
(
5)
Produce
vehicle
or
engines
for
importation
into
the
United
States
at
a
location
where
local
law
prohibits
us
from
carrying
out
authorized
activities.
(
c)
We
may
void
your
certificate
if
you
do
not
keep
the
records
we
require
or
do
not
give
us
information
when
we
ask
for
it.
(
d)
We
may
void
your
certificate
if
we
find
that
you
intentionally
submitted
false
or
incomplete
information.
(
e)
We
may
void
your
certificate
for
any
family
certified
to
an
FEL
above
the
allowable
average
if
you
fail
to
show
in
your
end
of
year
report
that
your
average
emission
levels
are
below
the
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/
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November
8,
2002
/
Rules
and
Regulations
applicable
standards
in
subpart
B
of
this
part,
or
that
you
have
sufficient
credits
to
offset
a
credit
deficit
for
the
model
year.
(
f)
If
we
deny
your
application
or
revoke
or
void
your
certificate,
you
may
ask
for
a
hearing
(
see
§
1051.820).
Any
such
hearing
will
be
limited
to
substantial
and
factual
issues.
(
g)
We
may
conduct
confirmatory
testing
of
your
vehicles
as
part
of
certification.
We
may
deny
your
application
for
certification
or
revoke
your
certificate
if
your
vehicles
fail
to
comply
with
emission
standards
or
other
requirements
during
confirmatory
testing.
Subpart
D
Testing
Production
line
Engines
§
1051.301
When
must
I
test
my
production
line
vehicles
or
engines?
(
a)
If
you
certify
vehicles
to
the
standards
of
this
part,
you
must
test
them
as
described
in
this
subpart.
If
your
vehicle
is
certified
to
g/
kW
hr
standards,
then
test
the
engine;
otherwise,
test
the
vehicle.
The
provisions
of
this
subpart
do
not
apply
to
small
volume
manufacturers.
(
b)
We
may
suspend
or
revoke
your
certificate
of
conformity
for
certain
engine
families
if
your
production
line
vehicles
or
engines
do
not
meet
the
requirements
of
this
part
or
you
do
not
fulfill
your
obligations
under
this
subpart
(
see
§
§
1051.325
and
1051.340).
(
c)
Other
requirements
apply
to
vehicles
and
engines
that
you
produce.
Other
regulatory
provisions
authorize
us
to
suspend,
revoke,
or
void
your
certificate
of
conformity,
or
order
recalls
for
engines
families
without
regard
to
whether
they
have
passed
these
production
line
testing
requirements.
The
requirements
of
this
subpart
do
not
affect
our
ability
to
do
selective
enforcement
audits,
as
described
in
part
1068
of
this
chapter.
Individual
vehicles
and
engines
in
families
that
pass
these
production
line
testing
requirements
must
also
conform
to
all
applicable
regulations
of
this
part
and
part
1068
of
this
chapter.
(
d)
You
may
ask
to
use
an
alternate
program
for
testing
production
line
vehicles
or
engines.
In
your
request,
you
must
show
us
that
the
alternate
program
gives
equal
assurance
that
your
products
meet
the
requirements
of
this
part.
If
we
approve
your
alternate
program,
we
may
waive
some
or
all
of
this
subpart's
requirements.
(
e)
If
you
certify
an
engine
family
with
carryover
emission
data,
as
described
in
§
1051.235(
c),
and
these
equivalent
engine
families
consistently
pass
the
production
line
testing
requirements
over
the
preceding
two
year
period,
you
may
ask
for
a
reduced
testing
rate
for
further
production
line
testing
for
that
family.
The
minimum
testing
rate
is
one
vehicle
or
engine
per
engine
family.
If
we
reduce
your
testing
rate,
we
may
limit
our
approval
to
a
any
number
of
model
years.
In
determining
whether
to
approve
your
request,
we
may
consider
the
number
of
vehicles
or
engines
that
have
failed
the
emission
tests.
(
f)
We
may
ask
you
to
make
a
reasonable
number
of
production
line
vehicles
or
engines
available
for
a
reasonable
time
so
we
can
test
or
inspect
them
for
compliance
with
the
requirements
of
this
part.
(
g)
The
requirements
of
this
subpart
do
not
apply
to
engine
families
certified
under
the
provisions
of
§
1051.630.
§
1051.305
How
must
I
prepare
and
test
my
production
line
vehicles
or
engines?
(
a)
Test
procedures.
Test
your
production
line
vehicles
or
engines
using
the
applicable
testing
procedures
in
subpart
F
of
this
part
to
show
you
meet
the
emission
standards
in
subpart
B
of
this
part.
(
b)
Modifying
a
test
vehicle
or
engine.
Once
a
vehicle
or
engine
is
selected
for
testing
(
see
§
1051.310),
you
may
adjust,
repair,
prepare,
or
modify
it
or
check
its
emissions
only
if
one
of
the
following
is
true:
(
1)
You
document
the
need
for
doing
so
in
your
procedures
for
assembling
and
inspecting
all
your
production
vehicles
or
engines
and
make
the
action
routine
for
all
the
vehicles
or
engines
in
the
engine
family.
(
2)
This
subpart
otherwise
specifically
allows
your
action.
(
3)
We
approve
your
action
in
advance.
(
c)
Malfunction.
If
a
vehicle
or
engine
malfunction
prevents
further
emission
testing,
ask
us
to
approve
your
decision
to
either
repair
it
or
delete
it
from
the
test
sequence.
(
d)
Setting
adjustable
parameters.
Before
any
test,
we
may
adjust
or
require
you
to
adjust
any
adjustable
parameter
to
any
setting
within
its
physically
adjustable
range.
(
1)
We
may
adjust
idle
speed
outside
the
physically
adjustable
range
as
needed
only
until
the
vehicle
or
engine
has
stabilized
emission
levels
(
see
paragraph
(
e)
of
this
section).
We
may
ask
you
for
information
needed
to
establish
an
alternate
minimum
idle
speed.
(
2)
We
may
make
or
specify
adjustments
within
the
physically
adjustable
range
by
considering
their
effect
on
emission
levels,
as
well
as
how
likely
it
is
someone
will
make
such
an
adjustment
with
in
use
vehicles.
(
3)
We
may
adjust
the
air
fuel
ratio
within
the
adjustable
range
specified
in
§
1051.115(
d).
(
e)
Stabilizing
emission
levels.
Before
you
test
production
line
vehicles
or
engines,
you
may
operate
the
vehicle
or
engine
to
stabilize
the
emission
levels.
Using
good
engineering
judgment,
operate
your
vehicles
or
engines
in
a
way
that
represents
the
way
they
will
be
used.
You
may
operate
each
vehicle
or
engine
for
no
more
than
the
greater
of
two
periods:
(
1)
50
hours.
(
2)
The
number
of
hours
you
operated
the
emission
data
vehicle
used
for
certifying
the
engine
family
(
see
40
CFR
part
1065,
subpart
E,
or
the
applicable
regulations
governing
how
you
should
prepare
your
test
vehicle
or
engine).
(
f)
Damage
during
shipment.
If
shipping
a
vehicle
or
engine
to
a
remote
facility
for
production
line
testing
makes
necessary
an
adjustment
or
repair,
you
must
wait
until
after
the
after
the
initial
emission
test
to
do
this
work.
We
may
waive
this
requirement
if
the
test
would
be
impossible
or
unsafe,
or
if
it
would
permanently
damage
the
vehicle
or
engine.
Report
to
us,
in
your
written
report
under
§
1051.345,
all
adjustments
or
repairs
you
make
on
test
vehicles
or
engines
before
each
test.
(
g)
Retesting
after
invalid
tests.
You
may
retest
a
vehicle
or
engine
if
you
determine
an
emission
test
is
invalid.
Explain
in
your
written
report
reasons
for
invalidating
any
test
and
the
emission
results
from
all
tests.
If
you
retest
a
vehicle
or
engine,
you
may
ask
us
to
substitute
results
of
the
new
tests
for
the
original
ones.
You
must
ask
us
within
ten
days
of
testing.
We
will
generally
answer
within
ten
days
after
we
receive
your
information.
§
1051.310
How
must
I
select
vehicles
or
engines
for
production
line
testing?
(
a)
Use
test
results
from
two
vehicles
or
engines
for
each
engine
family
to
calculate
the
required
sample
size
for
the
test
period.
Update
this
calculation
with
each
test.
(
1)
For
engine
families
with
projected
annual
sales
of
at
least
1600,
the
test
periods
are
consecutive
quarters
(
3
months).
If
your
annual
production
period
is
less
than
12
months
long,
define
your
test
periods
by
dividing
your
annual
production
period
into
approximately
equal
segments
of
70
to
125
calendar
days.
(
2)
For
engine
families
with
projected
annual
sales
below
1600,
the
test
period
is
the
whole
model
year.
(
b)
Early
in
each
test
period,
randomly
select
and
test
an
engine
from
the
end
of
the
assembly
line
for
each
engine
family.
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/
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8,
2002
/
Rules
and
Regulations
(
1)
In
the
first
test
period
for
newly
certified
engines,
randomly
select
and
test
one
more
engine.
Then,
calculate
the
required
sample
size
for
the
test
period
as
described
in
paragraph
(
c)
of
this
section.
(
2)
In
later
test
periods
or
for
engine
families
relying
on
previously
submitted
test
data,
combine
the
new
test
result
with
the
last
test
result
from
the
previous
test
period.
Then,
calculate
the
required
sample
size
for
the
new
test
period
as
described
in
paragraph
(
c)
of
this
section.
(
c)
Calculate
the
required
sample
size
for
each
engine
family.
Separately
calculate
this
figure
for
HC,
NOX
(
or
HC+
NOX),
and
CO
(
and
other
regulated
pollutants).
The
required
sample
size
is
the
greater
of
these
calculated
values.
Use
the
following
equation:
N
t
x
=
×
+
(
(
95
2
1
STD)
Where:
N
=
Required
sample
size
for
the
model
year.
t95
=
95%
confidence
coefficient,
which
depends
on
the
number
of
tests
completed,
n,
as
specified
in
the
table
in
paragraph
(
c)(
1)
of
this
section.
It
defines
95%
confidence
intervals
for
a
one
tail
distribution.
x
=
Mean
of
emission
test
results
of
the
sample.
STD
=
Emission
standard
(
or
family
emission
limit,
if
applicable).
s
=
Test
sample
standard
deviation
(
see
paragraph
(
c)(
2)
of
this
section).
(
1)
Determine
the
95%
confidence
coefficient,
t95,
from
the
following
table:
n
t95
n
t95
n
t95
2
6.31
12
1.80
22
1.72
3
2.92
13
1.78
23
1.72
4
2.35
14
1.77
24
1.71
5
2.13
15
1.76
25
1.71
6
2.02
16
1.75
26
1.71
7
1.94
17
1.75
27
1.71
8
1.90
18
1.74
28
1.70
9
1.86
19
1.73
29
1.70
10
1.83
20
1.73
30+
1.70
11
1.81
21
1.72
............................
...........................................
(
2)
Calculate
the
standard
deviation,
s,
for
the
test
sample
using
the
following
formula:
=
(
Xi
x)
n
2
1
Where:
Xi
=
Emission
test
result
for
an
individual
vehicle
or
engine.
n
=
The
number
of
tests
completed
in
an
engine
family.
(
d)
Use
final
deteriorated
test
results
to
calculate
the
variables
in
the
equations
in
paragraph
(
c)
of
this
section
(
see
§
1051.315(
a)).
(
e)
After
each
new
test,
recalculate
the
required
sample
size
using
the
updated
mean
values,
standard
deviations,
and
the
appropriate
95
percent
confidence
coefficient.
(
f)
Distribute
the
remaining
vehicle
or
engine
tests
evenly
throughout
the
rest
of
the
year.
You
may
need
to
adjust
your
schedule
for
selecting
vehicles
or
engines
if
the
required
sample
size
changes.
Continue
to
randomly
select
vehicles
or
engines
from
each
engine
family;
this
may
involve
testing
vehicles
or
engines
that
operate
on
different
fuels.
(
g)
Continue
testing
any
engine
family
for
which
the
sample
mean,
x,
is
greater
than
the
emission
standard.
This
applies
if
the
sample
mean
for
either
HC,
NOX
(
or
HC+
NOX),
or
CO
(
or
other
regulated
pollutants)
is
greater
than
the
emission
standard.
Continue
testing
until
one
of
the
following
things
happens:
(
1)
The
sample
size,
n,
for
an
engine
family
is
greater
than
the
required
sample
size,
N,
and
the
sample
mean,
x,
is
less
than
or
equal
to
the
emission
standard.
For
example,
if
N
=
3.1
after
the
third
test,
the
sample
size
calculation
does
not
allow
you
to
stop
testing.
(
2)
The
engine
family
does
not
comply
according
to
§
1051.325.
(
3)
You
test
30
vehicles
or
engines
from
the
engine
family.
(
4)
You
test
one
percent
of
your
projected
annual
U.
S.
directed
production
volume
for
the
engine
family.
(
5)
You
choose
to
declare
that
the
engine
family
fails
the
requirements
of
this
subpart.
(
h)
If
the
sample
size
calculation
allows
you
to
stop
testing
for
a
pollutant,
you
must
continue
measuring
emission
levels
of
that
pollutant
for
any
additional
tests
required
under
this
section.
However,
you
need
not
continue
making
the
calculations
specified
in
this
section
for
that
pollutant.
This
paragraph
does
not
affect
the
requirements
in
section
§
1051.320.
(
i)
You
may
elect
to
test
more
randomly
chosen
vehicles
or
engines
than
we
require.
Include
these
vehicles
or
engines
in
the
sample
size
calculations.
§
1051.315
How
do
I
know
when
my
engine
family
fails
the
production
line
testing
requirements?
This
section
describes
the
pass
fail
criteria
for
the
production
line
testing
requirements.
We
apply
this
criteria
on
an
engine
family
basis.
See
§
1051.320
for
the
requirements
that
apply
to
individual
vehicles
or
engines
that
fail
a
production
line
test.
(
a)
Calculate
your
test
results.
Round
them
to
the
number
of
decimal
places
in
the
emission
standard
expressed
to
one
more
decimal
place.
(
1)
Initial
and
final
test
results.
Calculate
and
round
the
test
results
for
each
vehicle
or
engine.
If
you
do
several
tests
on
a
vehicle
or
engine,
calculate
the
initial
test
results,
then
add
them
together
and
divide
by
the
number
of
tests
and
round
for
the
final
test
results
on
that
vehicle
or
engine.
(
2)
Final
deteriorated
test
results.
Apply
the
deterioration
factor
for
the
engine
family
to
the
final
test
results
(
see
§
1051.240(
c)).
(
b)
Construct
the
following
CumSum
Equation
for
each
engine
family
for
HC,
NOX
(
or
HC+
NOX),
and
CO
emissions
(
and
other
regulated
pollutants):
C
X
(
STD
i
1
i
=
+
+
×
Ci
0
25
.
)
Where:
Ci
=
The
current
CumSum
statistic.
Ci
1
=
The
previous
CumSum
statistic.
For
the
first
test,
the
CumSum
statistic
is
0
(
i.
e.
C1
=
0).
Xi
=
The
current
emission
test
result
for
an
individual
vehicle
or
engine.
STD
=
Emission
standard.
(
c)
Use
final
deteriorated
test
results
to
calculate
the
variables
in
the
equation
in
paragraph
(
b)
of
this
section
(
see
§
1051.315(
a)).
(
d)
After
each
new
test,
recalculate
the
CumSum
statistic.
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68396
Federal
Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
(
e)
If
you
test
more
than
the
required
number
of
vehicles
or
engines,
include
the
results
from
these
additional
tests
in
the
CumSum
Equation.
(
f)
After
each
test,
compare
the
current
CumSum
statistic,
Ci,
to
the
recalculated
Action
Limit,
H,
defined
as
H
=
5.0
×
s.
(
g)
If
the
CumSum
statistic
exceeds
the
Action
Limit
in
two
consecutive
tests,
the
engine
family
fails
the
production
line
testing
requirements
of
this
subpart.
Tell
us
within
ten
working
days
if
this
happens.
You
may
request
to
amend
the
application
for
certification
to
raise
the
FEL
of
the
engine
family
at
this
point
if
you
meet
the
requirements
of
§
1051.225(
f).
(
h)
If
you
amend
the
application
for
certification
for
an
engine
family
under
§
1051.225,
do
not
change
any
previous
calculations
of
sample
size
or
CumSum
statistics
for
the
model
year.
§
1051.320
What
happens
if
one
of
my
production
line
vehicles
or
engines
fails
to
meet
emission
standards?
(
a)
If
you
have
a
production
line
vehicle
or
engine
with
final
deteriorated
test
results
exceeding
one
or
more
emission
standards
(
see
§
1051.315(
a)),
the
certificate
of
conformity
is
automatically
suspended
for
that
failing
vehicle
or
engine.
You
must
take
the
following
actions
before
your
certificate
of
conformity
can
cover
that
vehicle
or
engine:
(
1)
Correct
the
problem
and
retest
the
vehicle
or
engine
to
show
it
complies
with
all
emission
standards.
(
2)
Include
in
your
written
report
a
description
of
the
test
results
and
the
remedy
for
each
vehicle
or
engine
(
see
§
1051.345).
(
b)
You
may
request
to
amend
the
application
for
certification
to
raise
the
FEL
of
the
entire
engine
family
at
this
point
(
see
§
1051.225).
§
1051.325
What
happens
if
an
engine
family
fails
the
production
line
requirements?
(
a)
We
may
suspend
your
certificate
of
conformity
for
an
engine
family
if
it
fails
under
§
1051.315.
The
suspension
may
apply
to
all
facilities
producing
vehicles
or
engines
from
an
engine
family,
even
if
you
find
noncompliant
vehicles
or
engines
only
at
one
facility.
(
b)
We
will
tell
you
in
writing
if
we
suspend
your
certificate
in
whole
or
in
part.
We
will
not
suspend
a
certificate
until
at
least
15
days
after
the
engine
family
fails.
The
suspension
is
effective
when
you
receive
our
notice.
(
c)
Up
to
15
days
after
we
suspend
the
certificate
for
an
engine
family,
you
may
ask
for
a
hearing
(
see
§
1051.820).
If
we
agree
before
a
hearing
that
we
used
erroneous
information
in
deciding
to
suspend
the
certificate,
we
will
reinstate
the
certificate.
(
d)
Section
1051.335
specifies
steps
you
must
take
to
remedy
the
cause
of
the
production
line
failure.
All
the
vehicles
you
have
produced
since
the
end
of
the
last
test
period
are
presumed
noncompliant
and
should
be
addressed
in
your
proposed
remedy.
We
may
require
you
to
apply
the
remedy
to
engines
produced
earlier
if
we
determine
that
the
cause
of
the
failure
is
likely
to
have
affected
the
earlier
engines.
(
e)
You
may
request
to
amend
the
application
for
certification
to
raise
the
FEL
of
the
engine
family
before
or
after
we
suspend
your
certificate
if
you
meet
the
requirements
of
§
1051.225(
f).
§
1051.330
May
I
sell
vehicles
from
an
engine
family
with
a
suspended
certificate
of
conformity?
You
may
sell
vehicles
that
you
produce
after
we
suspend
the
engine
family's
certificate
of
conformity
under
§
1051.315
only
if
one
of
the
following
occurs:
(
a)
You
test
each
vehicle
or
engine
you
produce
and
show
it
complies
with
emission
standards
that
apply.
(
b)
We
conditionally
reinstate
the
certificate
for
the
engine
family.
We
may
do
so
if
you
agree
to
recall
all
the
affected
vehicles
and
remedy
any
noncompliance
at
no
expense
to
the
owner
if
later
testing
shows
that
the
engine
family
still
does
not
comply.
§
1051.335
How
do
I
ask
EPA
to
reinstate
my
suspended
certificate?
(
a)
Send
us
a
written
report
asking
us
to
reinstate
your
suspended
certificate.
In
your
report,
identify
the
reason
for
noncompliance,
propose
a
remedy
for
the
engine
family,
and
commit
to
a
date
for
carrying
it
out.
In
your
proposed
remedy
include
any
quality
control
measures
you
propose
to
keep
the
problem
from
happening
again.
(
b)
Give
us
data
from
production
line
testing
that
shows
the
remedied
engine
family
complies
with
all
the
emission
standards
that
apply.
§
1051.340
When
may
EPA
revoke
my
certificate
under
this
subpart
and
how
may
I
sell
these
vehicles
again?
(
a)
We
may
revoke
your
certificate
for
an
engine
family
in
the
following
cases:
(
1)
You
do
not
meet
the
reporting
requirements.
(
2)
Your
engine
family
fails
to
comply
with
the
requirements
of
this
subpart
and
your
proposed
remedy
to
address
a
suspended
certificate
under
§
1051.325
is
inadequate
to
solve
the
problem
or
requires
you
to
change
the
vehicle's
design
or
emission
control
system.
(
b)
To
sell
vehicles
from
an
engine
family
with
a
revoked
certificate
of
conformity,
you
must
modify
the
engine
family
and
then
show
it
complies
with
the
requirements
of
this
part.
(
1)
If
we
determine
your
proposed
design
change
may
not
control
emissions
for
the
vehicle's
full
useful
life,
we
will
tell
you
within
five
working
days
after
receiving
your
report.
In
this
case
we
will
decide
whether
production
line
testing
will
be
enough
for
us
to
evaluate
the
change
or
whether
you
need
to
do
more
testing.
(
2)
Unless
we
require
more
testing,
you
may
show
compliance
by
testing
production
line
vehicles
or
engines
as
described
in
this
subpart.
(
3)
We
will
issue
a
new
or
updated
certificate
of
conformity
when
you
have
met
these
requirements.
§
1051.345
What
production
line
testing
records
must
I
send
to
EPA?
Do
all
the
following
things
unless
we
ask
you
to
send
us
less
information:
(
a)
Within
30
calendar
days
of
the
end
of
each
calendar
quarter,
send
us
a
report
with
the
following
information:
(
1)
Describe
any
facility
used
to
test
production
line
vehicles
or
engines
and
state
its
location.
(
2)
State
the
total
U.
S.
directed
production
volume
and
number
of
tests
for
each
engine
family.
(
3)
Describe
how
you
randomly
selected
vehicles
or
engines.
(
4)
Describe
your
test
vehicles
or
engines,
including
the
engine
family's
identification
and
the
vehicle's
model
year,
build
date,
model
number,
identification
number,
and
number
of
hours
of
operation
before
testing
for
each
test
vehicle
or
engine.
(
5)
Identify
where
you
accumulated
hours
of
operation
on
the
vehicles
or
engines
and
describe
the
procedure
and
schedule
you
used.
(
6)
Provide
the
test
number;
the
date,
time
and
duration
of
testing;
test
procedure;
initial
test
results
before
and
after
rounding;
final
test
results;
and
final
deteriorated
test
results
for
all
tests.
Provide
the
emission
results
for
all
measured
pollutants.
Include
information
for
both
valid
and
invalid
tests
and
the
reason
for
any
invalidation.
(
7)
Describe
completely
and
justify
any
nonroutine
adjustment,
modification,
repair,
preparation,
maintenance,
or
test
for
the
test
vehicle
or
engine
if
you
did
not
report
it
separately
under
this
subpart.
Include
the
results
of
any
emission
measurements,
regardless
of
the
procedure
or
type
of
vehicle.
(
8)
Provide
the
CumSum
analysis
required
in
§
1051.315
for
each
engine
family.
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November
8,
2002
/
Rules
and
Regulations
(
9)
Report
on
each
failed
vehicle
or
engine
as
described
in
§
1051.320.
(
10)
State
the
date
the
calendar
quarter
ended
for
each
engine
family.
(
b)
We
may
ask
you
to
add
information
to
your
written
report,
so
we
can
determine
whether
your
new
vehicles
conform
with
the
requirements
of
this
subpart.
(
c)
An
authorized
representative
of
your
company
must
sign
the
following
statement:
We
submit
this
report
under
Sections
208
and
213
of
the
Clean
Air
Act.
Our
production
line
testing
conformed
completely
with
the
requirements
of
40
CFR
part
1051.
We
have
not
changed
production
processes
or
quality
control
procedures
for
the
engine
family
in
a
way
that
might
affect
the
emission
control
from
production
vehicles
(
or
engines).
All
the
information
in
this
report
is
true
and
accurate,
to
the
best
of
my
knowledge.
I
know
of
the
penalties
for
violating
the
Clean
Air
Act
and
the
regulations.
(
Authorized
Company
Representative)
(
d)
Send
electronic
reports
of
production
line
testing
to
the
Designated
Officer
using
an
approved
information
format.
If
you
want
to
use
a
different
format,
send
us
a
written
request
with
justification
for
a
waiver.
(
e)
We
will
send
copies
of
your
reports
to
anyone
from
the
public
who
asks
for
them.
See
§
1051.815
for
information
on
how
we
treat
information
you
consider
confidential.
§
1051.350
What
records
must
I
keep?
(
a)
Organize
and
maintain
your
records
as
described
in
this
section.
We
may
review
your
records
at
any
time,
so
it
is
important
to
keep
required
information
readily
available.
(
b)
Keep
paper
records
of
your
production
line
testing
for
one
full
year
after
you
complete
all
the
testing
required
for
an
engine
family
in
a
model
year.
You
may
use
any
additional
storage
formats
or
media
if
you
like.
(
c)
Keep
a
copy
of
the
written
reports
described
in
§
1051.345.
(
d)
Keep
the
following
additional
records:
(
1)
A
description
of
all
test
equipment
for
each
test
cell
that
you
can
use
to
test
production
line
vehicles
or
engines.
(
2)
The
names
of
supervisors
involved
in
each
test.
(
3)
The
name
of
anyone
who
authorizes
adjusting,
repairing,
preparing,
or
modifying
a
test
vehicle
or
engine
and
the
names
of
all
supervisors
who
oversee
this
work.
(
4)
If
you
shipped
the
vehicle
or
engine
for
testing,
the
date
you
shipped
it,
the
associated
storage
or
port
facility,
and
the
date
the
vehicle
or
engine
arrived
at
the
testing
facility.
(
5)
Any
records
related
to
your
production
line
tests
that
are
not
in
the
written
report.
(
6)
A
brief
description
of
any
significant
events
during
testing
not
otherwise
described
in
the
written
report
or
in
this
section.
(
7)
Any
information
specified
in
§
1051.345
that
you
do
not
include
in
your
written
reports.
(
e)
If
we
ask,
you
must
give
us
projected
or
actual
production
figures
for
an
engine
family.
We
may
ask
you
to
divide
your
production
figures
by
rated
brake
power,
displacement,
fuel
type,
or
assembly
plant
(
if
you
produce
vehicles
or
engines
at
more
than
one
plant).
(
f)
Keep
a
list
of
vehicle
or
engine
identification
numbers
for
all
the
vehicles
or
engines
you
produce
under
each
certificate
of
conformity.
Give
us
this
list
within
30
days
if
we
ask
for
it.
(
g)
We
may
ask
you
to
keep
or
send
other
information
necessary
to
implement
this
subpart.
Subpart
E
Testing
In
use
Engines
[
Reserved]
Subpart
F
Test
Procedures
§
1051.501
What
procedures
must
I
use
to
test
my
vehicles
or
engines?
This
section
describes
test
procedures
that
you
use
to
show
compliance
with
the
requirements
of
this
part.
See
§
1051.235
to
determine
when
testing
is
required
for
certification.
See
subpart
D
of
this
part
for
the
production
line
testing
requirements.
(
a)
Snowmobiles.
For
snowmobiles,
use
the
equipment
and
procedures
for
spark
ignition
engines
in
part
1065
of
this
chapter
to
show
your
snowmobiles
meet
the
duty
cycle
emission
standards
in
§
1051.103.
Measure
HC,
NOX
(
as
applicable),
CO,
and
CO2
emissions
using
the
dilute
sampling
procedures
in
part
1065
of
this
chapter.
For
steadystate
testing,
you
may
use
raw
gas
sampling
methods
(
such
as
those
described
in
40
CFR
part
91),
provided
they
have
been
shown
to
produce
measurements
equivalent
to
the
dilute
sampling
methods
specified
in
part
1065
of
this
chapter.
Use
the
duty
cycle
in
§
1051.505.
(
b)
Motorcycles
and
ATVs.
For
motorcycles
and
ATVs,
use
the
equipment,
procedures,
and
duty
cycle
in
40
CFR
part
86,
subpart
F,
to
show
your
vehicles
meet
the
exhaust
emission
standards
in
§
1051.105
or
§
1051.107.
Measure
HC,
NOX,
CO,
and
CO2.
If
we
allow
you
to
certify
ATVs
based
on
engine
testing,
use
the
equipment,
procedures,
and
duty
cycle
described
or
referenced
in
that
section
that
allows
engine
testing.
For
motorcycles
with
engine
displacement
at
or
below
169
cc
and
all
ATVs,
use
the
driving
schedule
in
paragraph
(
c)
of
Appendix
I
to
40
CFR
part
86.
For
all
other
motorcycles
use
the
driving
schedule
in
paragraph
(
b)
of
Appendix
I
to
part
86.
With
respect
to
vehicle
speed
governors,
test
motorcycles
and
ATVs
in
their
ungoverned
configuration,
unless
we
approve
in
advance
testing
in
a
governed
configuration.
We
will
only
approve
testing
in
a
governed
configuration
if
you
can
show
that
the
governor
is
permanently
installed
on
all
production
vehicles
and
is
unlikely
to
be
removed
in
use.
With
respect
to
engine
speed
governors,
test
motorcycles
and
ATVs
in
their
governed
configuration.
(
c)
Permeation
testing.
(
1)
Use
the
equipment
and
procedures
specified
in
§
1051.515
to
measure
fuel
tank
permeation
emissions.
(
2)
Prior
to
permeation
testing
of
fuel
hose,
the
hose
must
be
preconditioned
by
filling
the
hose
with
the
fuel
specified
in
(
d)(
3)
of
this
section,
sealing
the
openings,
and
soaking
the
hose
for
4
weeks
at
23
°
C
±
5
°
C.
To
measure
fuelline
permeation
emissions,
use
the
equipment
and
procedures
specified
in
SAE
J30
(
incorporated
by
reference
in
§
1051.810).
The
measurements
must
be
performed
at
23
°
C
using
the
fuel
specified
in
paragraph
(
d)(
3)
of
this
section.
(
d)
Fuels.
Use
the
fuels
meeting
the
following
specifications:
(
1)
Exhaust.
Use
the
fuels
and
lubricants
specified
in
40
CFR
part
1065,
subpart
C,
for
all
the
testing
and
service
accumulation
we
require
in
this
part.
(
2)
Fuel
Tank
Permeation.
(
i)
For
the
preconditioning
soak
described
in
§
1051.515(
a)(
1)
and
fuel
slosh
durability
test
described
in
§
1051.515(
c)(
4),
use
the
fuel
specified
in
Table
1
of
§
1065.210
of
this
chapter
blended
with
10
percent
ethanol
by
volume.
As
an
alternative,
you
may
use
Fuel
CE10,
which
is
Fuel
C
as
specified
in
ASTM
D
471
98
(
incorporated
by
reference
in
§
1051.810)
blended
with
10
percent
ethanol
by
volume.
(
ii)
For
the
permeation
measurement
test
in
§
1051.515(
b),
use
the
fuel
specified
in
Table
1
of
§
1065.210
of
this
chapter.
As
an
alternative,
you
may
use
the
fuel
specified
in
paragraph
(
d)(
2)(
i)
of
this
section.
(
3)
Fuel
Hose
Permeation.
Use
the
fuel
specified
in
Table
1
of
§
1065.210
of
this
chapter
blended
with
10
percent
ethanol
by
volume
for
permeation
testing
of
fuel
lines
and
tanks.
As
an
alternative,
you
may
use
Fuel
CE10,
which
is
Fuel
C
as
specified
in
ASTM
D
471
98
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217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
(
incorporated
by
reference
in
§
1051.810)
blended
with
10
percent
ethanol
by
volume.
(
e)
Special
procedures
for
engine
testing.
(
1)
You
may
use
special
or
alternate
procedures,
as
described
in
§
1065.10
of
this
chapter.
(
2)
We
may
reject
data
you
generate
using
alternate
procedures
if
later
testing
with
the
procedures
in
part
1065
of
this
chapter
shows
contradictory
emission
data.
(
f)
Special
procedures
for
vehicle
testing.
(
1)
You
may
use
special
or
alternate
procedures,
as
described
in
paragraph
(
f)(
3)
of
this
section.
(
2)
We
may
reject
data
you
generate
using
alternate
procedures
if
later
testing
with
the
otherwise
specified
procedures
shows
contradictory
emission
data.
(
3)(
i)
The
test
procedures
specified
for
vehicle
testing
are
intended
to
produce
emission
measurements
equivalent
to
those
that
would
result
from
measuring
emissions
during
in
use
operation
using
the
same
vehicle
configuration.
If
good
engineering
judgment
indicates
that
use
of
the
procedures
in
this
part
for
a
vehicle
would
result
in
measurements
that
are
not
representative
of
in
use
operation
of
that
vehicle,
you
must
notify
us.
If
we
determine
that
using
these
procedures
would
result
in
measurements
that
are
significantly
unrepresentative
and
that
changes
to
the
procedures
will
result
in
more
representative
measurements
that
do
not
decrease
the
stringency
of
emission
standards
or
other
requirements,
we
will
specify
changes
to
the
procedures.
In
your
notification
to
us,
you
should
recommend
specific
changes
you
think
are
necessary.
(
ii)
You
may
ask
to
use
emission
data
collected
using
other
test
procedures,
such
as
those
of
the
California
Air
Resources
Board
or
the
International
Organization
for
Standardization.
We
will
allow
this
only
if
you
show
us
that
these
data
are
equivalent
to
data
collected
using
our
test
procedures.
(
iii)
You
may
ask
to
use
alternate
procedures
that
produce
measurements
equivalent
to
those
obtained
using
the
specified
procedures.
In
this
case,
send
us
a
written
request
showing
that
your
alternate
procedures
are
equivalent
to
the
test
procedures
of
this
part.
If
you
prove
to
us
that
the
procedures
are
equivalent,
we
will
allow
you
to
use
them.
You
may
not
use
alternate
procedures
until
we
approve
them.
(
iv)
You
may
ask
to
use
special
test
procedures
if
your
vehicle
cannot
be
tested
using
the
specified
test
procedures
(
for
example,
it
is
incapable
of
operating
on
the
specified
transient
cycle).
In
this
case,
send
us
a
written
request
showing
that
you
cannot
satisfactorily
test
your
engines
using
the
test
procedures
of
this
part.
We
will
allow
you
to
use
special
test
procedures
if
we
determine
that
they
would
produce
emission
measurements
that
are
representative
of
those
that
would
result
from
measuring
emissions
during
in
use
operation.
You
may
not
use
special
procedures
until
we
approve
them.
§
1051.505
What
special
provisions
apply
for
testing
snowmobiles?
Use
the
following
special
provisions
for
testing
snowmobiles:
(
a)
Measure
emissions
by
testing
the
engine
on
a
dynamometer
with
the
steady
state
duty
cycle
described
in
the
following
Table:
TABLE
1
OF
§
1051.505.
5
MODE
DUTY
CYCLE
FOR
SNOWMOBILES
Engine
speed
(
percent
of
maximum
test
speed)
Torque
(
percent
of
maximum
test
torque
at
maximum
test
speed)
Minimum
time
in
mode
(
minutes)
Weighting
factors
Mode
number:
1
................................................................................................................
100
100
3.0
0.12
2
................................................................................................................
85
51
3.0
0.27
3
................................................................................................................
75
33
3.0
0.25
4
................................................................................................................
65
19
3.0
0.31
5
................................................................................................................
Idle
0
3.0
0.05
(
b)
During
idle
mode,
operate
the
engine
with
the
following
parameters:
(
1)
Hold
the
speed
within
your
specifications.
(
2)
Keep
the
throttle
at
the
idle
stop
position.
(
3)
Keep
engine
torque
under
5
percent
of
the
peak
torque
value
at
maximum
test
speed.
(
c)
For
the
full
load
operating
mode,
operate
the
engine
at
wide
open
throttle.
(
d)
Ambient
temperatures
during
testing
must
be
between
20
°
C
and
30
°
C
(
68
°
F
and
86
°
F),
or
other
representative
test
temperatures,
as
specified
in
paragraph
(
g)
of
this
section.
(
e)
See
part
1065
of
this
chapter
for
detailed
specifications
of
tolerances
and
calculations.
(
f)
You
may
test
snowmobiles
at
ambient
temperatures
below
20
°
C
or
using
intake
air
temperatures
below
20
°
C
if
you
show
that
such
testing
complies
with
§
1065.10(
c)(
1)
of
this
chapter.
You
must
get
our
approval
before
you
begin
the
emission
testing.
For
example,
the
following
approach
would
be
appropriate
to
show
that
such
testing
complies
with
§
1065.10(
c)(
1)
of
this
chapter:
(
1)
Using
good
engineering
judgment,
instrument
a
representative
snowmobile
built
with
a
representative
engine
from
the
family
being
tested
with
an
appropriate
temperature
measuring
device
located
in
the
intake
air
plenum
where
fuel
spitback
is
not
likely
to
occur.
(
2)
Choose
a
time
and
location
with
the
following
weather
conditions:
windspeed
less
than
10
knots,
no
falling
precipitation,
air
temperature
between
¥
20
°
C
and
0
°
C
(
¥
4
°
F
and
32
°
F).
(
3)
Operate
the
snowmobile
until
its
engine
reaches
a
steady
operating
temperature.
(
4)
Operate
the
snowmobile
on
a
level
surface
free
of
other
vehicle
traffic.
Operate
the
snowmobile
at
each
specified
engine
speed
corresponding
to
each
mode
in
the
emissions
test
specific
to
the
engine
being
tested.
When
readings
are
stable,
record
the
temperature
in
the
intake
air
plenum
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2002
/
Rules
and
Regulations
and
the
ambient
temperature.
Calculate
the
temperature
difference
between
the
air
in
the
plenum
and
the
ambient
air
for
each
mode.
(
5)
Calculate
the
nominal
intake
air
test
temperature
for
each
test
mode
as
¥
10
°
C
(
14
°
F)
plus
the
temperature
difference
for
the
corresponding
mode
determined
in
(
g)(
4)
of
this
section.
(
6)
Before
the
emissions
test,
select
the
appropriate
carburetor
jetting
for
¥
10
°
C
(
14
°
F)
conditions
according
to
the
jet
chart.
For
each
mode,
maintain
the
inlet
air
temperature
within
5
°
C
of
the
corresponding
modal
temperature
calculated
in
(
g)(
5)
of
this
section.
(
7)
Adjust
other
operating
parameters
to
be
consistent
with
operation
at
¥
10
°
C
(
14
°
F).
For
example,
this
may
require
that
you
modify
the
engine
cooling
system
used
in
the
laboratory
to
make
its
performance
representative
of
cold
temperature
operation.
§
1051.510
What
special
provisions
apply
for
testing
ATV
engines?
[
Reserved]
§
1051.515
How
do
I
test
my
fuel
tank
for
permeation
emissions?
Measure
permeation
emissions
by
weighing
a
sealed
fuel
tank
before
and
after
a
temperature
controlled
soak.
(
a)
Preconditioning.
To
precondition
your
fuel
tank,
follow
these
five
steps:
(
1)
Fill
the
tank
with
the
fuel
specified
in
§
1051.501(
d)(
2)(
i),
seal
it,
and
allow
it
to
soak
at
28
±
5
°
C
for
20
weeks.
Alternatively,
the
tank
may
be
soaked
for
a
shorter
period
of
time
at
a
higher
temperature
if
you
can
show
that
the
hydrocarbon
permeation
rate
has
stabilized.
(
2)
Determine
the
fuel
tank's
internal
surface
area
in
square
meters
accurate
to
at
least
three
significant
figures.
You
may
use
less
accurate
estimates
of
the
surface
area
if
you
make
sure
not
to
overestimate
the
surface
area.
(
3)
Fill
the
fuel
tank
with
the
test
fuel
specified
in
§
1051.501(
d)(
2)(
ii)
to
its
nominal
capacity.
If
you
fill
the
tank
inside
the
temperature
controlled
room
or
enclosure,
do
not
spill
any
fuel.
(
4)
Allow
the
tank
and
its
contents
to
equilibrate
to
28
±
2
°
C.
(
5)
Seal
the
fuel
tank
using
nonpermeable
fittings,
such
as
metal
or
TeflonTM.
(
b)
Test
run.
To
run
the
test,
follow
these
nine
steps
for
a
tank
that
was
preconditioned
as
specified
in
paragraph
(
a)
of
this
section:
(
1)
Weigh
the
sealed
fuel
tank
and
record
the
weight
to
the
nearest
0.1
grams.
(
You
may
use
less
precise
weights
as
long
as
the
difference
in
mass
from
the
start
of
the
test
to
the
end
of
the
test
has
at
least
three
significant
figures.)
(
2)
Carefully
place
the
tank
within
a
ventilated
temperature
controlled
room
or
enclosure.
Do
not
spill
any
fuel.
(
3)
Close
the
room
or
enclosure
and
record
the
time.
(
4)
Ensure
that
the
measured
temperature
in
the
room
or
enclosure
is
28
±
2
°
C.
(
5)
Leave
the
tank
in
the
room
or
enclosure
for
2
to
4
weeks,
consistent
with
good
engineering
judgment
(
based
on
the
permeation
rate).
Do
not
stop
soaking
before
4
weeks
unless
you
know
that
you
can
measure
the
weight
loss
during
the
test
to
at
least
three
significant
figures
earlier.
(
6)
Hold
the
temperature
of
the
room
or
enclosure
to
28
±
2
°
C;
measure
and
record
the
temperature
at
least
daily.
(
7)
At
the
end
of
the
soak
period,
weigh
the
sealed
fuel
tank
and
record
the
weight
to
the
nearest
0.1
grams.
(
You
may
use
less
precise
weights
as
long
as
the
difference
in
mass
from
the
start
of
the
test
to
the
end
of
the
test
has
at
least
three
significant
figures.)
(
8)
Subtract
the
weight
of
the
tank
at
the
end
of
the
test
from
the
weight
of
the
tank
at
the
beginning
of
the
test;
divide
the
difference
by
the
internal
surface
area
of
the
fuel
tank.
Divide
this
g/
m
2
value
by
the
number
of
test
days
(
using
at
least
three
significant
figures)
to
calculate
the
g/
m
2/
day
emission
rate.
Example:
If
a
tank
with
an
internal
surface
area
of
1.51
m
2
weighed
31882.3
grams
at
the
beginning
of
the
test
and
weighed
31760.2
grams
after
soaking
for
25.03
days,
then
the
g/
m
2/
day
emission
rate
would
be:
(
31882.3
g
¥
31760.2
g)/
1.51
m
2/
25.03
days
=
3.23
g/
m
2/
day.
(
9)
Round
your
result
to
the
same
number
of
decimal
places
as
the
emission
standard.
(
c)
Durability
testing.
You
normally
need
to
perform
a
separate
durability
demonstration
for
each
substantially
different
combination
of
treatment
approaches
and
tank
materials.
Perform
these
demonstrations
before
an
emission
test
by
taking
the
following
steps,
unless
you
can
use
good
engineering
judgment
to
apply
the
results
of
previous
durability
testing
with
a
different
fuel
system.
You
can
determine
a
deterioration
factor
by
measuring
emissions
on
a
tank
after
these
durability
tests
if
you
previously
tested
the
same
tank
before
the
durability
tests
(
but
after
the
preconditioning
step
described
in
paragraph
(
a)
of
this
section).
For
the
purposes
of
deterioration
factor
determination,
the
permeation
tests
before
and
after
the
durability
testing
must
be
performed
on
the
fuel
specified
in
§
1051.501
(
d)(
2)(
i).
You
may
ask
to
exclude
any
of
the
following
durability
tests
if
you
can
clearly
demonstrate
that
it
does
not
affect
the
emissions
from
your
fuel
tank.
(
1)
Perform
a
pressure
test
by
sealing
the
tank
and
cycling
it
between
+
2.0
psig
and
¥
0.5
psig
and
back
to
+
2.0
psig
for
10,000
cycles
at
a
rate
60
seconds
per
cycle.
(
2)
Perform
a
sunlight
exposure
test
by
exposing
the
tank
to
an
ultraviolet
light
of
at
least
0.40
W
hr/
m
2/
min
on
the
tank
surface
for
15
hours
per
day
for
4
weeks.
Alternatively,
the
fuel
tank
may
be
exposed
to
direct
natural
sunlight
for
an
equivalent
period
of
time,
as
long
as
you
ensure
that
the
tank
is
exposed
to
at
least
450
daylight
hours.
(
3)
Perform
a
slosh
test
by
filling
the
tank
to
40
percent
of
its
capacity
with
the
fuel
specified
in
§
1051.501(
d)(
2)(
i)
and
rocking
it
at
a
rate
of
15
cycles
per
minute
until
you
reach
one
million
total
cycles.
Use
an
angle
deviation
of
+
15
°
to
¥
15
°
from
level.
This
test
must
be
performed
at
a
temperature
of
28
°
C
±
5
°
C.
(
4)
Following
the
durability
testing,
the
fuel
tank
must
be
soaked
(
as
described
in
paragraph
(
a)
of
this
section)
to
ensure
that
the
permeation
rate
is
stable.
The
period
of
slosh
testing
and
the
period
of
ultraviolet
testing
(
if
performed
with
fuel
in
the
tank
consistent
with
paragraph
(
a)(
1)
of
this
section)
may
be
considered
to
be
part
of
this
soak,
provided
that
the
soak
begins
immediately
after
the
slosh
testing.
To
determine
the
final
permeation
rate,
drain
and
refill
the
tank
with
fresh
fuel,
and
repeat
the
test
run
(
as
described
in
paragraph
(
b)
of
this
section)
immediately
after
this
soak
period.
(
d)
Flow
chart.
The
following
figure
presents
a
flow
chart
for
the
permeation
testing
described
in
this
section,
showing
full
test
procedure
with
durability
testing,
as
well
as
the
simplified
test
procedure
with
an
applied
deterioration
factor:
BILLING
CODE
6560
50
P
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/
Rules
and
Regulations
BILLING
CODE
6560
50
C
§
1051.520
How
do
I
perform
exhaust
durability
testing?
This
section
applies
for
durability
testing
to
determine
deterioration
factors
for
exhaust
emissions.
Smallvolume
manufacturers
may
omit
durability
testing
if
they
use
our
assigned
deterioration
factors
that
we
establish
based
on
our
projection
of
the
likely
deterioration
in
the
performance
of
specific
emission
controls.
(
a)
Calculate
your
deterioration
factor
by
testing
a
vehicle
or
engine
that
is
representative
of
your
engine
family
at
a
low
hour
test
point
and
the
end
of
its
useful
life.
You
may
also
test
at
intermediate
points.
(
b)
Operate
the
vehicle
or
engine
over
a
representative
duty
cycle
for
a
period
at
least
as
long
as
the
useful
life
(
in
hours
or
kilometers).
You
may
operate
the
vehicle
or
engine
continuously.
(
c)
You
may
perform
critical
emission
related
maintenance
during
durability
testing,
consistent
with
§
1051.125(
a).
You
may
not
perform
any
other
emission
related
maintenance
during
durability
testing.
(
d)
Use
a
linear
least
squares
fit
of
your
test
data
for
each
pollutant
to
calculate
your
deterioration
factor.
(
e)
You
may
ask
us
to
allow
you
to
use
other
testing
methods
to
determine
deterioration
factors,
consistent
with
good
engineering
judgment.
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No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Subpart
G
Compliance
Provisions
§
1051.601
What
compliance
provisions
apply
to
vehicles
and
engines
subject
to
this
part?
Engine
and
vehicle
manufacturers,
as
well
as
owners,
operators,
and
rebuilders
of
these
vehicles,
and
all
other
persons,
must
observe
the
requirements
and
prohibitions
in
part
1068
of
this
chapter
and
the
requirements
of
the
Act.
The
compliance
provisions
in
this
subpart
apply
only
to
the
vehicles
and
engines
we
regulate
in
this
part.
§
1051.605
What
are
the
provisions
for
exempting
vehicles
from
the
requirements
of
this
part
if
they
use
engines
you
have
certified
under
the
motor
vehicle
program
or
the
Large
Spark
ignition
program?
(
a)
You
may
ask
for
an
exemption
under
this
section
if
you
are
the
manufacturer
of
an
engine
certified
under
the
motor
vehicle
program
or
the
Large
Spark
ignition
program.
See
§
1051.610
if
you
are
not
the
engine
manufacturer.
(
b)(
1)
The
only
requirements
or
prohibitions
from
this
part
that
apply
to
a
vehicle
that
is
exempt
under
this
section
are
in
this
section
and
§
1051.610.
(
2)
If
the
vehicles
do
not
meet
the
criteria
listed
in
paragraph
(
c)
of
this
section,
they
will
be
subject
to
the
standards
and
prohibitions
of
this
part.
Producing
these
vehicles
without
a
valid
exemption
or
certificate
of
conformity
would
violate
the
prohibitions
in
§
1068.101
of
this
chapter.
(
3)
Vehicles
exempted
under
this
section
are
subject
to
all
the
requirements
affecting
engines
and
vehicles
under
40
CFR
part
86
or
part
1048,
as
applicable.
The
requirements
and
restrictions
of
40
CFR
part
86
or
1048
apply
to
anyone
manufacturing
these
engines,
anyone
manufacturing
vehicles
that
use
these
engines,
and
all
other
persons
in
the
same
manner
as
if
these
engines
were
used
in
a
motor
vehicle
or
other
nonrecreational
application.
(
c)
If
you
meet
all
the
following
criteria
regarding
your
engine,
the
vehicle
using
the
engine
is
exempt
under
this
section:
(
1)
The
vehicle
is
produced
using
an
engine
or
incomplete
vehicle
covered
by
a
valid
certificate
of
conformity
under
40
CFR
part
86
or
part
1048.
(
2)
No
changes
are
made
to
the
certified
engine
or
vehicle
that
we
could
reasonably
expect
to
increase
any
of
its
regulated
emissions.
For
example,
if
any
of
the
following
changes
are
made
to
the
engine,
it
does
not
qualify
for
this
exemption:
(
i)
Any
fuel
system
or
evaporative
system
parameters
are
changed
from
the
certified
configuration
(
this
does
not
apply
to
refueling
emission
controls).
(
ii)
Any
other
emission
related
components
are
changed.
(
iii)
The
engine
cooling
system
is
modified
or
assembled
so
that
temperatures
or
heat
rejection
rates
are
outside
the
original
engine's
specified
ranges.
(
3)
The
engine
must
have
the
emission
control
information
label
we
require
under
40
CFR
part
86
or
part
1048.
(
4)
You
must
demonstrate
that
fewer
than
50
percent
of
the
engine
model's
total
sales,
from
all
companies,
are
used
in
recreational
vehicles.
(
d)
If
you
manufacture
both
the
engine
and
vehicle
under
this
exemption,
you
must
do
all
of
the
following
to
keep
the
exemption
valid:
(
1)
Make
sure
the
original
emission
control
information
label
is
intact.
(
2)
Add
a
permanent
supplemental
label
to
the
engine
in
a
position
where
it
will
remain
clearly
visible
after
installation
in
the
vehicle.
In
your
engine's
emission
control
information
label,
do
the
following:
(
i)
Include
the
heading:
``
Recreational
Vehicle
Emission
Control
Information''.
(
ii)
Include
your
full
corporate
name
and
trademark.
(
iii)
State:
``
THIS
ENGINE
WAS
ADAPTED
FOR
RECREATIONAL
USE
WITHOUT
AFFECTING
ITS
EMISSION
CONTROLS.''.
(
iv)
State
the
date
you
finished
installation
(
month
and
year).
(
3)
Make
sure
the
original
and
supplemental
labels
are
readily
visible
after
the
engine
is
installed
in
the
vehicle
or,
if
the
vehicle
obscures
the
engine's
emission
control
information
label,
make
sure
the
vehicle
manufacturer
attaches
duplicate
labels,
as
described
in
§
1068.105
of
this
chapter.
(
4)
Send
the
Designated
Officer
a
signed
letter
by
the
end
of
each
calendar
year
(
or
less
often
if
we
tell
you)
with
all
the
following
information:
(
i)
Identify
your
full
corporate
name,
address,
and
telephone
number.
(
ii)
List
the
models
you
expect
to
produce
under
this
exemption
in
the
coming
year.
(
iii)
State:
``
We
produce
each
listed
model
for
recreational
application
without
making
any
changes
that
could
increase
its
certified
emission
levels,
as
described
in
40
CFR
1051.605.''.
(
e)
If
we
request
it,
you
must
send
us
emission
test
data
on
the
applicable
recreational
duty
cycle(
s).
You
may
include
the
data
in
your
application
for
certification
under
40
CFR
part
86
or
part
1048,
or
in
your
letter
requesting
the
exemption.
We
will
generally
not
ask
you
for
these
data
under
normal
circumstances,
especially
when
they
are
more
readily
available
from
another
source.
§
1051.610
What
are
the
provisions
for
producing
recreational
vehicles
with
engines
already
certified
under
the
motorvehicle
program
or
the
Large
SI
program?
(
a)
You
may
produce
a
recreational
vehicle
without
certifying
it
under
this
part
by
using
a
certified
motor
vehicle
engine,
or
Large
SI
engine.
This
section
does
not
apply
if
you
manufacture
the
engine
yourself;
see
§
1051.605.
In
order
to
produce
recreational
vehicles
under
this
section,
you
must
meet
all
of
the
following
criteria:
(
1)
The
engine
or
vehicle
is
certified
to
40
CFR
part
86
or
part
1048.
(
2)
The
engine
is
not
adjusted
outside
the
certifying
manufacturer's
specifications
(
see
§
1051.605(
c)(
2)).
(
3)
The
engine
or
vehicle
is
not
modified
in
any
way
that
may
affect
its
emission
control.
This
does
not
apply
to
refueling
emission
controls.
(
4)
The
vehicle
is
labeled
consistent
with
paragraph
(
c)
of
this
section.
(
b)(
1)
The
only
requirements
or
prohibitions
from
this
part
that
apply
to
a
vehicle
that
is
exempt
under
this
section
are
in
this
section
and
§
1051.605.
(
2)
If
the
vehicles
do
not
meet
the
criteria
listed
in
§
1051.605(
c)
and
paragraph
(
c)
of
this
section,
they
will
be
subject
to
the
standards
and
prohibitions
of
this
part.
Producing
these
vehicles
without
a
valid
exemption
or
certificate
of
conformity
would
violate
the
prohibitions
in
§
1068.101
of
this
chapter.
(
3)
Vehicles
exempted
under
this
section
are
subject
to
all
the
requirements
affecting
engines
and
vehicles
under
40
CFR
part
86
or
part
1048,
as
applicable.
The
requirements
and
restrictions
of
40
CFR
part
86
or
1048
apply
to
anyone
manufacturing
these
engines,
anyone
manufacturing
vehicles
that
use
these
engines,
and
all
other
persons
in
the
same
manner
as
if
these
engines
were
used
in
a
motor
vehicle
or
other
nonrecreational
application.
(
c)(
1)
Make
sure
the
original
emission
control
information
label
is
intact
after
assembly
in
the
vehicle.
(
2)
Add
a
permanent
supplemental
label
to
the
vehicle
in
a
position
where
it
will
be
clearly
visible.
In
this
emission
control
information
label,
do
the
following:
(
i)
Include
the
heading:
``
Recreational
Vehicle
Emission
Control
Information''.
(
ii)
Include
your
full
corporate
name
and
trademark.
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8,
2002
/
Rules
and
Regulations
(
iii)
State:
``
THIS
ENGINE
WAS
ADAPTED
FOR
RECREATIONAL
USE
WITHOUT
AFFECTING
ITS
EMISSION
CONTROLS.''.
(
iv)
State
the
date
you
finished
installation
(
month
and
year).
(
3)
Send
the
Designated
Officer
a
signed
letter
by
the
end
of
each
calendar
year
(
or
less
often
if
we
tell
you)
with
all
the
following
information:
(
i)
Identify
your
full
corporate
name,
address,
and
telephone
number.
(
ii)
List
the
models
you
expect
to
produce
under
this
exemption
in
the
coming
year.
(
iii)
State:
``
We
produce
each
listed
model
for
recreational
application
without
making
any
changes
that
could
increase
its
certified
emission
levels,
as
described
in
40
CFR
1051.605.''.
(
d)
If
you
build
recreational
vehicles
under
this
section,
we
may
require
(
as
a
condition
of
the
exemption)
that
you
comply
with
the
emission
related
warranty
and
recall
responsibilities
of
this
part.
(
e)
If
you
build
a
recreational
vehicle
using
a
motor
vehicle
engine
that
was
certified
as
part
of
a
vehicle
based
engine
family,
we
may
require
you
to
certify
under
this
part
instead
of
granting
you
an
exemption
under
this
part.
If
we
do
this,
we
may
allow
you
to
submit
an
abbreviated
application
for
certification
to
show
that
you
comply
with
the
requirements
of
this
part.
You
may
reference
the
information
in
the
original
motor
vehicle
application.
§
1051.615
What
are
the
special
provisions
for
certifying
small
recreational
engines?
(
a)
You
may
certify
ATVs
with
engines
that
have
total
displacement
of
less
than
100
cc
to
the
following
emission
exhaust
standards
instead
of
certifying
them
to
the
exhaust
emission
standards
of
subpart
B
of
this
part:
(
1)
25.0
g/
kW
hr
HC+
NOX,
with
an
FEL
cap
of
40.0
g/
kW
hr
HC+
NOX.
(
2)
500
g/
kW
hr
CO.
(
b)
You
may
certify
off
highway
motorcycles
with
engines
that
have
total
displacement
of
70
cc
or
less
to
the
following
emission
exhaust
standards
instead
of
certifying
them
to
the
exhaust
emission
standards
of
subpart
B
of
this
part:
(
1)
16.1
g/
kW
hr
HC+
NOX,
with
an
FEL
cap
of
32.2
g/
kW
hr
HC+
NOX.
(
2)
519
g/
kW
hr
CO.
(
c)
You
may
use
the
averaging,
banking,
and
trading
provisions
of
subpart
H
of
this
part
to
show
compliance
with
this
HC+
NOX
standards
(
an
engine
family
meets
emission
standards
even
if
its
family
emission
limit
is
higher
than
the
standard,
as
long
as
you
show
that
the
whole
averaging
set
of
applicable
engine
families
meet
the
applicable
emission
standards
using
emission
credits,
and
the
vehicles
within
the
family
meet
the
family
emission
limit).
You
may
not
use
averaging
to
meet
the
CO
standards
of
this
section.
(
d)
Measure
emissions
by
testing
the
engine
on
a
dynamometer
with
the
steady
state
duty
cycle
described
in
Table
1
of
this
section.
(
1)
During
idle
mode,
hold
the
speed
within
your
specifications,
keep
the
throttle
fully
closed,
and
keep
engine
torque
under
5
percent
of
the
peak
torque
value
at
maximum
test
speed.
(
2)
For
the
full
load
operating
mode,
operate
the
engine
at
wide
open
throttle.
(
3)
See
part
1065
of
this
chapter
for
detailed
specifications
of
tolerances
and
calculations.
(
4)
Table
1
follows:
TABLE
1
OF
§
1051.615.
6
MODE
DUTY
CYCLE
FOR
RECREATIONAL
ENGINES
Engine
speed
(
percent
of
maximum
test
speed)
Torque
(
percent
of
maximum
test
torque
at
test
speed)
Minimum
time
in
mode
(
minutes)
Weighting
factors
Mode
number:
1
................................................................................................................
85
100
5.0
0.09
2
................................................................................................................
85
75
5.0
0.20
3
................................................................................................................
85
50
5.0
0.29
4
................................................................................................................
85
25
5.0
0.30
5
................................................................................................................
85
10
5.0
0.07
6
................................................................................................................
Idle
0
5.0
0.05
(
e)
All
other
requirements
and
prohibitions
of
this
part
apply
to
these
engines
and
vehicles.
§
1051.620
When
may
a
manufacturer
obtain
an
exemption
for
competition
recreational
vehicles?
(
a)
We
may
grant
you
an
exemption
from
the
standards
and
requirements
of
this
part
for
a
new
recreational
vehicle
on
the
grounds
that
it
is
to
be
used
solely
for
competition.
The
provisions
of
this
part
other
than
those
in
this
section
do
not
apply
to
recreational
vehicles
that
we
exempt
for
use
solely
for
competition.
(
b)
We
will
exempt
vehicles
that
we
determine
will
be
used
solely
for
competition.
The
basis
of
our
determinations
are
described
in
paragraphs
(
b)(
1),
(
b)(
2),
and
(
c)
of
this
section.
Exemptions
granted
under
this
section
are
good
for
only
one
model
year
and
you
must
request
renewal
for
each
subsequent
model
year.
We
will
not
approve
your
renewal
request
if
we
determine
the
vehicles
will
not
be
used
solely
for
competition.
(
1)
Off
highway
motorcycles.
Motorcycles
that
are
marketed
and
labeled
as
only
for
competitive
use
and
that
meet
at
least
four
of
the
criteria
listed
in
paragraphs
(
b)(
1)(
i)
through
(
vi)
of
this
section
are
considered
to
be
used
solely
for
competition,
except
in
cases
where
other
information
is
available
that
indicates
that
they
are
not
used
solely
for
competition.
The
following
features
are
indicative
of
motorcycles
used
solely
for
competition:
(
i)
The
absence
of
a
headlight
or
other
lights.
(
ii)
The
absence
of
a
spark
arrestor.
(
iii)
The
absence
of
manufacturer
warranty.
(
iv)
Suspension
travel
greater
than
10
inches.
(
v)
Engine
displacement
greater
than
50
cc.
(
vi)
The
absence
of
a
functional
seat.
(
For
example,
a
seat
less
with
than
30
square
inches
of
seating
surface
would
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No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
generally
not
be
considered
a
functional
seat).
(
2)
Snowmobiles
and
ATVs.
Snowmobiles
and
ATVs
meeting
all
of
the
following
criteria
are
considered
to
be
used
solely
for
competition,
except
in
cases
where
other
information
is
available
that
indicates
that
they
are
not
used
solely
for
competition:
(
i)
The
vehicle
or
engine
may
not
be
displayed
for
sale
in
any
public
dealership.
(
ii)
Sale
of
the
vehicle
must
be
limited
to
professional
racers
or
other
qualified
racers.
(
iii)
The
vehicle
must
have
performance
characteristics
that
are
substantially
superior
to
noncompetitive
models.
(
c)
Vehicles
not
meeting
the
applicable
criteria
listed
in
paragraph
(
b)
of
this
section
will
be
exempted
only
in
cases
where
the
manufacturer
has
clear
and
convincing
evidence
that
the
vehicles
will
be
used
solely
for
competition.
(
d)
You
must
permanently
label
vehicles
exempted
under
this
section
to
clearly
indicate
that
they
are
to
be
used
only
for
competition.
Failure
to
properly
label
a
vehicle
will
void
the
exemption
for
that
vehicle.
(
e)
If
we
request
it,
you
must
provide
us
any
information
we
need
to
determine
whether
the
vehicles
are
used
solely
for
competition.
§
1051.625
What
special
provisions
apply
to
unique
snowmobile
designs
for
smallvolume
manufacturers?
(
a)
If
you
are
a
small
volume
manufacturer,
we
may
permit
you
to
produce
up
to
600
snowmobiles
per
year
that
are
certified
to
less
stringent
emission
standards
than
those
in
§
1051.103,
as
long
as
you
meet
all
the
conditions
and
requirements
in
this
section.
(
b)
To
apply
for
alternate
standards
under
this
section,
send
the
Designated
Officer
a
written
request.
In
your
request,
do
two
things:
(
1)
Show
that
the
snowmobile
has
unique
design,
calibration,
or
operating
characteristics
that
make
it
atypical
and
infeasible
or
highly
impractical
to
meet
the
emission
standards
in
§
1051.103,
considering
technology,
cost,
and
other
factors.
(
2)
Identify
the
level
of
compliance
you
can
achieve,
including
a
description
of
available
emission
control
technologies
and
any
constraints
that
may
prevent
more
effective
use
of
these
technologies.
(
c)
You
must
give
us
other
relevant
information
if
we
ask
for
it.
(
d)
An
authorized
representative
of
your
company
must
sign
the
request
and
include
the
statement:
``
All
the
information
in
this
request
is
true
and
accurate,
to
the
best
of
my
knowledge.''.
(
e)
Send
your
request
for
this
extension
at
least
nine
months
before
the
relevant
deadline.
If
different
deadlines
apply
to
companies
that
are
not
small
volume
manufacturers,
do
not
send
your
request
before
the
regulations
in
question
apply
to
the
other
manufacturers.
(
f)
If
we
approve
your
request,
we
will
set
alternate
standards
for
your
qualifying
snowmobiles.
These
standards
will
not
be
above
400
g/
kWhr
for
CO
or
150
g/
kW
hr
for
HC.
(
g)
You
may
produce
these
snowmobiles
to
meet
the
alternate
standards
we
establish
under
this
section
as
long
as
you
continue
to
produce
them
at
the
same
or
lower
emission
levels.
(
h)
You
may
not
include
snowmobiles
you
produce
under
this
section
in
any
averaging,
banking,
or
trading
calculations
under
Subpart
H
of
this
part.
(
i)
You
must
meet
all
the
requirements
of
this
part,
except
as
noted
in
this
section.
§
1051.630
What
special
provisions
apply
to
unique
snowmobile
designs
for
all
manufacturers?
(
a)
We
may
permit
you
to
produce
up
to
600
snowmobiles
per
year
that
are
certified
to
the
FELs
listed
in
this
section
without
new
test
data,
as
long
as
you
meet
all
the
conditions
and
requirements
in
this
section.
(
b)
You
may
certify
these
snowmobiles
with
FELs
of
560
g/
kW
hr
for
CO
and
270
g/
kW
hr
for
HC
(
using
the
normal
certification
procedures).
(
c)
The
emission
levels
described
in
this
section
are
intended
to
represent
worst
case
emission
levels.
You
may
not
certify
snowmobiles
under
this
section
if
good
engineering
judgment
indicates
that
they
have
emission
rates
higher
than
these
levels.
(
d)
Include
snowmobiles
you
produce
under
this
section
in
your
averaging
calculations
under
Subpart
H
of
this
part.
(
e)
You
must
meet
all
the
requirements
of
this
part,
unless
the
regulations
of
this
part
specify
otherwise.
§
1051.635
What
provisions
apply
to
new
manufacturers
that
are
small
businesses?
(
a)
If
you
are
a
small
business
(
as
defined
by
the
Small
Business
Administration)
that
manufactures
recreational
vehicles,
but
does
not
otherwise
qualify
for
the
small
volume
manufacturer
provisions
of
this
part,
you
may
ask
us
to
designate
you
to
be
a
small
volume
manufacturer.
You
may
do
this
whether
you
began
manufacturing
recreational
vehicles
before,
during,
or
after
2002.
(
b)
We
may
set
other
reasonable
conditions
that
are
consistent
with
the
intent
of
this
section
and
the
Act.
For
example,
we
may
place
sales
limits
on
companies
that
we
designate
to
be
small
volume
manufacturers
under
this
section.
Subpart
H
Averaging,
Banking,
and
Trading
for
Certification
§
1051.701
General
provisions.
(
a)
You
may
average,
bank,
and
trade
emission
credits
for
purposes
of
certification
as
described
in
this
subpart
to
show
compliance
with
the
standards
of
this
part.
To
do
this
you
must
show
that
your
average
emission
levels
are
below
the
applicable
standards
in
subpart
B
of
this
part,
or
that
you
have
sufficient
credits
to
offset
a
credit
deficit
for
the
model
year
(
as
calculated
in
§
1051.720).
If
you
cannot
show
in
your
end
of
year
report
that
your
average
emission
levels
are
below
the
applicable
standards
in
subpart
B
of
this
part,
or
that
you
have
sufficient
credits
to
offset
a
credit
deficit
for
the
model
year,
we
may
void
the
certificates
for
all
families
certified
to
FELs
above
the
allowable
average.
(
b)
The
following
averaging
set
restrictions
apply:
(
1)
You
may
not
average
together
engine
families
that
are
certified
to
different
standards.
You
may,
however,
use
banked
credits
that
were
generated
relative
to
different
standards,
except
as
prohibited
by
paragraphs
(
b)(
2)
and
(
3)
of
this
section,
paragraph
(
e)
of
this
section,
or
by
other
provisions
in
this
part.
For
example,
you
may
not
average
together
within
a
model
year
offhighway
motorcycles
that
are
certified
to
the
standards
in
§
1051.105(
a)(
1)
and
§
1051.105(
a)(
2);
but
you
may
use
banked
credits
generated
by
off
highway
motorcycles
that
are
certified
to
the
standards
in
§
1051.105(
a)(
1)
to
show
compliance
with
the
standards
in
§
1051.105(
a)(
2)
in
a
later
model
year,
and
vice
versa.
(
2)
There
are
separate
averaging,
banking,
and
trading
programs
for
snowmobiles,
ATVs,
and
off
highway
motorcycles.
You
may
not
average
or
exchange
banked
or
traded
credits
from
engine
families
of
one
type
of
vehicle
with
those
from
engine
families
of
another
type
of
vehicle.
(
3)
You
may
not
average
or
exchange
banked
or
traded
credits
with
other
engine
families
if
you
use
fundamentally
different
measurement
procedures
for
the
different
engine
families
(
for
example,
ATVs
certified
to
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chassis
based
vs.
engine
based
standards).
This
paragraph
(
b)(
3)
does
not
restrict
you
from
averaging
together
engine
families
that
use
test
procedures
that
we
determine
provide
equivalent
emission
results.
(
4)
You
may
not
average
or
exchange
banked
or
traded
exhaust
credits
with
evaporative
credits,
or
vice
versa.
(
c)
The
definitions
of
Subpart
I
of
this
part
apply
to
this
subpart.
The
following
definitions
also
apply:
(
1)
Average
standard
means
a
standard
that
allows
you
comply
by
averaging
all
your
vehicles
under
this
part.
See
subpart
B
of
this
part
to
determine
which
standards
are
average
standards.
(
2)
Broker
means
any
entity
that
facilitates
a
trade
between
a
buyer
and
seller.
(
3)
Buyer
means
the
entity
that
receives
credits
as
a
result
of
trade.
(
4)
Family
emission
limit
(
FEL)
has
the
meaning
given
in
it
in
§
1051.801.
(
5)
Reserved
credits
means
credits
you
have
generated
that
we
have
not
yet
verified
in
reviewing
the
end
of
year
report.
(
6)
Seller
means
the
entity
that
provides
credits
during
a
trade.
(
d)
Do
not
include
any
exported
vehicles
in
the
certification
averaging,
banking,
and
trading
program.
Include
only
vehicles
certified
under
this
part.
§
1051.705
How
do
I
average
emission
levels?
(
a)
As
specified
in
subpart
B
of
this
part,
certify
each
vehicle
to
a
family
emission
limit
(
FEL).
(
b)
Calculate
a
preliminary
average
emission
level
according
to
§
1051.720
using
projected
U.
S.
directed
production
volumes
for
your
application
for
certification.
(
c)
After
the
end
of
your
model
year,
calculate
a
final
average
emission
level
according
to
§
1051.720
for
each
type
of
recreational
vehicle
or
engine
you
manufacture
or
import.
Use
actual
U.
S.
directed
production
volumes.
(
d)
If
your
preliminary
average
emission
level
is
below
the
allowable
average
standard,
see
§
1051.710
for
information
about
generating
and
banking
emission
credits.
These
credits
will
be
considered
reserved
until
we
verify
them
in
reviewing
the
end
of
year
report.
§
1051.710
How
do
I
generate
and
bank
emission
credits?
(
a)
If
your
average
emission
level
is
below
the
average
standard,
you
may
calculate
credits
according
to
§
1051.720.
(
b)
You
may
generate
credits
if
you
are
a
certifying
manufacturer.
(
c)
You
may
bank
unused
emission
credits,
but
only
after
the
end
of
the
calendar
year
and
after
we
have
reviewed
your
end
of
year
reports.
Credits
you
generate
do
not
expire.
(
d)
During
the
calendar
year
and
before
you
send
in
your
end
of
year
report,
you
may
consider
reserved
any
credits
you
originally
designate
for
banking
during
certification.
You
may
redesignate
these
credits
for
trading
in
your
end
of
year
report,
but
they
are
not
valid
to
demonstrate
compliance
until
verified.
(
e)
You
may
use
for
averaging
or
trading
any
credits
you
declared
for
banking
from
the
previous
calendar
year
that
we
have
not
reviewed.
But,
we
may
revoke
these
credits
later
following
our
review
of
your
end
of
year
report
or
audit
actions.
For
example,
this
could
occur
if
we
find
that
credits
are
based
on
erroneous
calculations;
or
that
emission
levels
are
misrepresented,
unsubstantiated,
or
derived
incorrectly
in
the
certification
process.
§
1051.715
How
do
I
trade
emission
credits?
(
a)
You
may
trade
only
banked
emission
credits,
not
reserved
credits.
(
b)
You
may
trade
banked
credits
to
any
certifying
manufacturer.
(
c)
If
a
negative
credit
balance
results
from
a
credit
trade,
both
buyers
and
sellers
are
liable,
except
in
cases
involving
fraud.
We
may
void
the
certificates
of
all
emission
families
participating
in
a
negative
trade.
(
1)
If
you
buy
credits
but
have
not
caused
the
negative
credit
balance,
you
must
only
supply
more
credits
equivalent
to
the
amount
of
invalid
credits
you
used.
(
2)
If
you
caused
the
credit
shortfall,
you
may
be
subject
to
the
requirement
sof
§
1051.730(
b)(
6).
§
1051.720
How
do
I
calculate
my
average
emission
level
or
emission
credits?
(
a)
Calculate
your
average
emission
level
for
each
type
of
recreational
vehicle
or
engine
for
each
model
year
according
to
the
following
equation
and
round
it
to
the
nearest
tenth
of
a
g/
km
or
g/
kW
hr.
Use
consistent
units
throughout
the
calculation.
(
1)
For
exhaust
emissions:
(
i)
Calculate
the
average
emission
level
as:
Emission
level
=
(
FEL)
(
UL)
(
Production)
Production
(
UL)
i
i
i
i
i
×
×
×
(
)
i
i
Where:
FELi
=
The
FEL
to
which
the
engine
family
is
certified.
ULi
=
The
useful
life
of
the
engine
family.
Productioni
=
The
number
of
vehicles
in
the
engine
family.
(
ii)
Use
U.
S.
directed
production
projections
for
initial
certification,
and
actual
U.
S.
directed
production
volumes
to
determine
compliance
at
the
end
of
the
model
year.
(
2)
For
vehicles
that
have
standards
expressed
as
g/
kW
hr
and
a
useful
life
in
km,
convert
the
useful
life
to
kW
hr
based
on
the
maximum
power
output
observed
over
the
emission
test
and
an
assumed
vehicle
speed
of
30
km/
hr
as
follows:
UL
(
kW
hr)
=
UL
(
km)
×
Maximum
Test
Power
(
kW)
÷
30
km/
hr.
(
Note:
It
is
not
necessary
to
include
a
load
factor,
since
credit
exchange
is
not
allowed
between
vehicles
certified
to
g/
kW
hr
standards
and
vehicles
certified
to
g/
km
standards.)
(
3)
For
evaporative
permeation
standards
expressed
as
g/
m2/
day,
use
the
useful
life
value
in
years
multiplied
by
365.24,
and
calculate
the
average
emission
level
as:
Emission
level
=
(
FEL)
(
UL)
(
Production)
Production
(
UL)
i
i
i
i
i
×
×
×
(
)
i
i
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Where:
Productioni
=
The
number
of
vehicles
in
the
engine
family
times
the
average
internal
surface
area
of
the
vehicles'
fuel
tanks.
(
b)
If
your
average
emission
level
is
below
the
average
standard,
calculate
credits
available
for
banking
according
to
the
following
equation
and
round
them
to
the
nearest
tenth
of
a
gram:
Credit
=
(
Average
standard
Emission
level)
Production
(
UL)
i
[
]
×
×
(
)
i
i
(
c)
If
your
average
emission
level
is
above
the
average
standard,
calculate
your
preliminary
credit
deficit
according
to
the
following
equation,
rounding
to
the
nearest
tenth
of
a
gram:
Deficit
=
(
Emission
level
Average
standard)
(
Production)
(
UL)
i
i
i
[
]
×
×
§
1051.725
What
information
must
I
keep?
(
a)
Maintain
and
keep
five
types
of
properly
organized
and
indexed
records
for
each
engine
family:
(
1)
Model
year
and
EPA
engine
family.
(
2)
FEL.
(
3)
Useful
life.
(
4)
Projected
U.
S.
directed
production
volume
for
the
model
year.
(
5)
Actual
U.
S.
directed
production
volume
for
the
model
year.
(
b)
Keep
paper
records
of
this
information
for
three
years
from
the
due
date
for
the
end
of
year
report.
You
may
use
any
additional
storage
formats
or
media
if
you
like.
(
c)
Keep
a
copy
of
all
of
the
information
you
send
us
under
§
1051.730.
(
d)
We
may
ask
you
to
keep
or
send
other
information
necessary
to
implement
this
subpart.
§
1051.730
What
information
must
I
report?
(
a)
Include
the
following
information
in
each
of
your
applications
for
certification:
(
1)
A
statement
that,
to
the
best
of
your
belief,
you
will
not
have
a
negative
credit
balance
for
any
type
of
recreational
vehicle
or
engine
when
all
credits
are
calculated.
This
means
that
if
you
believe
that
your
average
emission
level
will
be
above
the
standard
(
i.
e.,
that
you
will
have
a
deficit
for
the
model
year),
you
must
have
banked
credits
(
or
project
to
have
received
traded
credits)
to
offset
the
deficit.
(
2)
Detailed
calculations
of
projected
emission
credits
(
zero,
positive,
or
negative)
based
on
U.
S.
directed
production
projections.
If
you
project
a
credit
deficit,
state
the
source
of
credits
needed
to
offset
the
credit
deficit.
(
b)
At
the
end
of
each
model
year,
send
an
end
of
year
report.
(
1)
Your
report
must
include
three
things:
(
i)
Calculate
in
detail
your
average
emission
level
and
any
emission
credits
(
positive,
or
negative)
based
on
actual
U.
S.
directed
production
volumes.
(
ii)
If
your
average
emission
level
is
above
the
allowable
average
standard,
demonstrate
that
you
have
the
credits
needed
to
offset
the
credit
deficit.
If
you
cannot
demonstrate
that
you
have
the
credits
at
the
time
you
submit
your
endof
year
report,
we
may
void
the
certificates
for
all
families
certified
to
FELs
above
the
allowable
average.
(
iii)
If
your
average
emission
level
is
below
the
allowable
average
standard,
state
whether
you
will
reserve
the
credits
for
banking.
(
2)
Base
your
U.
S.
directed
production
volumes
on
the
point
of
first
retail
sale.
You
may
consider
distributors
to
be
the
point
of
first
retail
sale
if
all
their
engines
are
sold
to
ultimate
buyers
in
the
United
States.
(
3)
Send
end
of
year
reports
to
the
Designated
Officer
within
120
days
of
the
end
of
the
model
year.
If
you
send
reports
later,
you
are
violating
the
Act.
(
4)
If
you
generate
credits
for
banking
and
you
do
not
send
your
end
of
year
reports
within
120
days
after
the
end
of
the
model
year,
you
may
not
use
or
trade
the
credits
until
we
receive
and
review
your
reports.
You
may
not
use
projected
credits
pending
our
review.
(
5)
You
may
correct
errors
discovered
in
your
end
of
year
report,
including
errors
in
calculating
credits
according
to
the
following
table:
If
And
if
Then
we
(
i)
Our
review
discovers
an
error
in
your
end
of
year
report
that
increases
your
credit
balance.
the
discovery
occurs
within
180
days
of
receipt
.............
restore
the
credits
for
your
use.
(
ii)
You
discover
an
error
in
your
report
that
increases
your
credit
balance.
the
discovery
occurs
within
180
days
of
receipt
.............
restore
the
credits
for
your
use.
(
iii)
We
or
you
discover
and
error
in
your
report
that
increases
your
credit
balance.
the
discovery
occurs
more
than
180
days
after
receipt
do
not
restore
the
credits
for
your
use.
(
iv)
We
discover
an
error
in
your
report
that
reduces
your
credit
balance.
at
any
time
after
receipt
..................................................
reduce
your
credit
balance
(
6)
If
our
review
of
a
your
end
of
yearreport
shows
a
negative
balance,
you
may
buy
credits
to
bring
your
credit
balance
to
zero.
But
you
must
buy
1.1
credits
for
each
1.0
credit
needed.
If
enough
credits
are
not
available
to
bring
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your
credit
balance
to
zero
within
90
days
of
when
we
notify
you,
we
may
void
the
certificates
for
all
families
certified
to
FELs
above
the
allowable
average.
(
c)
Within
90
days
of
any
credit
trade,
you
must
send
the
Designated
Officer
a
report
of
the
trade
that
includes
three
types
of
information:
(
1)
The
corporate
names
of
the
buyer,
seller,
and
any
brokers.
(
2)
Copies
of
contracts
related
to
credit
trading
from
the
buyer,
seller,
and
broker,
as
applicable.
(
d)
Include
in
each
report
a
statement
certifying
the
accuracy
and
authenticity
of
its
contents.
(
e)
We
may
void
a
certificate
of
conformity
for
any
emission
family
if
you
do
not
keep
the
records
this
section
requires
or
give
us
the
information
when
we
ask
for
it.
§
1051.735
Are
there
special
averaging
provisions
for
snowmobiles?
For
snowmobiles,
you
may
only
use
credits
for
the
same
phase
or
set
of
standards
against
which
they
were
generated,
except
as
allowed
by
this
section.
(
a)
Restrictions.
(
1)
You
may
not
use
any
Phase
1
or
Phase
2
credits
for
Phase
3
compliance.
(
2)
You
may
not
use
Phase
1
HC
credits
for
Phase
2
HC
compliance.
However,
because
the
Phase
1
and
Phase
2
CO
standards
are
the
same,
you
may
use
Phase
1
CO
credits
for
compliance
with
the
Phase
2
CO
standards.
(
b)
Special
credits
for
next
phase
of
standards.
You
may
choose
to
generate
credits
early
for
banking
for
purposes
of
compliance
with
later
phases
of
standards
as
follows:
(
1)
If
your
corporate
average
emission
level
at
the
end
of
the
model
year
exceeds
the
applicable
(
current)
phase
of
standards
(
without
the
use
of
traded
or
previously
banked
credits),
you
may
choose
to
redesignate
some
of
your
snowmobile
production
to
a
calculation
to
generate
credits
for
a
future
phase
of
standards.
To
generate
credits
the
snowmobiles
designated
must
have
an
FEL
below
the
emission
level
of
that
set
of
standards.
This
can
be
done
on
a
pollutant
specific
basis.
(
2)
Do
not
include
the
snowmobiles
that
you
redesignate
in
the
final
compliance
calculation
of
your
average
emission
level
for
the
otherwise
applicable
(
current)
phase
of
standards.
Your
average
emission
level
for
the
remaining
(
non
redesignated)
snowmobiles
must
comply
with
the
otherwise
applicable
(
current)
phase
of
standards.
(
3)
Include
the
snowmobiles
that
you
redesignate
in
a
separate
calculation
of
your
average
emission
level
for
redesignated
engines.
Calculate
credits
using
this
average
emission
level
relative
to
the
specific
pollutant
in
the
future
phase
of
standards.
These
credits
may
be
used
for
compliance
with
the
future
standards.
(
4)
For
generating
early
Phase
3
credits,
you
may
generate
credits
for
HC+
NOX
or
CO
separately
as
described:
(
i)
To
determine
if
you
qualify
to
generate
credits
in
accordance
with
paragraphs
(
b)(
1)
through
(
3)
of
this
section,
you
must
meet
the
credit
trigger
level.
For
HC+
NOX
this
value
is
62
g/
kW
hr
(
which
would
be
the
HC+
NOX
standard
that
would
result
from
inputting
the
highest
allowable
CO
standard
(
275
g/
kW
hr)
into
the
Phase
3
equation).
For
CO
the
value
is
200
g/
kW
hr
(
which
would
be
the
CO
standard
that
would
result
from
inputting
the
highest
allowable
HC+
NOX
standard
(
90
g/
kW
hr)
into
the
Phase
3
equation).
(
ii)
HC+
NOX
and
CO
credits
for
Phase
3
are
calculated
relative
to
the
62
g/
kWhr
and
200
g/
kW
hr
values,
respectively.
(
5)
Credits
can
also
be
calculated
for
Phase
3
using
both
sets
of
standards.
Without
regard
to
the
trigger
level
values,
if
your
net
emission
reduction
for
the
redesignated
averaging
set
exceeds
the
requirements
of
Phase
3
in
§
1051.103
(
using
both
HC+
NOX
and
CO
in
the
Phase
3
equation
in
§
1051.103),
then
your
credits
are
the
difference
between
the
Phase
3
reduction
requirement
of
that
section
and
your
calculated
value.
Subpart
I
Definitions
and
Other
Reference
Information
§
1051.801
What
definitions
apply
to
this
part?
The
following
definitions
apply
to
this
part.
The
definitions
apply
to
all
subparts
unless
we
note
otherwise.
All
undefined
terms
have
the
meaning
the
Act
gives
to
them.
The
definitions
follow:
Act
means
the
Clean
Air
Act,
as
amended,
42
U.
S.
C.
7401
et
seq.
Adjustable
parameter
means
any
device,
system,
or
element
of
design
that
someone
can
adjust
(
including
those
which
are
difficult
to
access)
and
that,
if
adjusted,
may
affect
emissions
or
engine
performance
during
emission
testing
or
normal
in
use
operation.
You
may
ask
us
to
exclude
a
parameter
that
is
difficult
to
access
if
it
cannot
be
adjusted
to
affect
emissions
without
significantly
degrading
performance,
or
if
you
otherwise
show
us
that
it
will
not
be
adjusted
in
use
in
a
way
that
affect
emissions
Aftertreatment
means
relating
to
any
system,
component,
or
technology
mounted
downstream
of
the
exhaust
valve
or
exhaust
port
whose
design
function
is
to
reduce
exhaust
emissions.
All
terrain
vehicle
means
a
land
based
or
amphibious
nonroad
vehicle
that
meets
the
criteria
listed
in
paragraph
(
1)
of
this
definition;
or,
alternatively,
the
criteria
of
paragraph
(
2)
of
this
definition
but
not
the
criteria
of
paragraph
(
3)
of
this
definition.
(
1)
Vehicles
designed
to
travel
on
four
low
pressure
tires,
having
a
seat
designed
to
be
straddled
by
the
operator
and
handlebars
for
steering
controls,
and
intended
for
use
by
a
single
operator
and
no
other
passengers
are
allterrain
vehicles.
(
2)
Other
all
terrain
vehicles
have
three
or
more
wheels
and
one
or
more
seats,
are
designed
for
operation
over
rough
terrain,
and
are
intended
primarily
for
transportation.
Golf
carts
generally
do
not
meet
these
criteria
since
they
are
generally
not
designed
for
operation
over
rough
terrain.
(
3)
Vehicles
that
meet
the
definition
of
``
offroad
utility
vehicle''
in
this
section
are
not
all
terrain
vehicles.
However,
§
1051.1(
a)
specifies
that
some
offroad
utility
vehicles
are
required
to
meet
the
same
requirements
as
allterrain
vehicles.
Auxiliary
emission
control
device
means
any
element
of
design
that
senses
temperature,
engine
rpm,
motive
speed,
transmission
gear,
atmospheric
pressure,
manifold
pressure
or
vacuum,
or
any
other
parameter
to
activate,
modulate,
delay,
or
deactivate
the
operation
of
any
part
of
the
emissioncontrol
system.
This
also
includes
any
other
feature
that
causes
in
use
emissions
to
be
higher
than
those
measured
under
test
conditions,
except
as
we
allow
under
this
part.
For
example,
an
accelerator
pump
would
be
considered
an
auxiliary
emissioncontrol
device.
Brake
power
means
the
usable
power
output
of
the
engine
not
including
power
required
to
operate
fuel
pumps,
oil
pumps,
or
coolant
pumps.
Broker
means
any
entity
that
facilitates
a
trade
of
emission
credits
between
a
buyer
and
seller.
Calibration
means
the
set
of
specifications
and
tolerances
specific
to
a
particular
design,
version,
or
application
of
a
component
or
assembly
capable
of
functionally
describing
its
operation
over
its
working
range.
Certification
means
obtaining
a
certificate
of
conformity
for
an
engine
family
that
complies
with
the
emission
standards
and
requirements
in
this
part.
Compression
ignition
means
relating
to
a
type
of
reciprocating,
internalcombustion
engine
that
is
not
a
sparkignition
engine.
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Crankcase
emissions
means
airborne
substances
emitted
to
the
atmosphere
from
any
part
of
the
engine
crankcase's
ventilation
or
lubrication
systems.
The
crankcase
is
the
housing
for
the
crankshaft
and
other
related
internal
parts.
Designated
Officer
means
the
Manager,
Engine
Programs
Group
(
6405
J),
U.
S.
Environmental
Protection
Agency,
1200
Pennsylvania
Ave.,
Washington,
DC
20460.
Emission
control
system
means
any
device,
system,
or
element
of
design
that
controls
or
reduces
the
regulated
emissions
from
a
vehicle.
Emission
data
vehicle
means
a
vehicle
or
engine
that
is
tested
for
certification.
Emission
related
maintenance
means
maintenance
that
substantially
affects
emissions
or
is
likely
to
substantially
affect
emissions
deterioration.
Engine
family
means
a
group
of
vehicles
with
similar
emission
characteristics,
as
specified
in
§
1051.230.
Evaporative
means
relating
to
fuel
emissions
that
result
from
permeation
of
fuel
through
the
fuel
system
materials
and
from
ventilation
of
the
fuel
system.
Family
emission
limit
(
FEL)
means
an
emission
level
declared
by
the
manufacturer
to
serve
in
place
of
an
emission
standard
for
certification
under
the
emission
credit
program
in
subpart
H
of
this
part.
The
family
emission
limit
must
be
expressed
to
the
same
number
of
decimal
places
as
the
emission
standard
it
replaces.
Fuel
system
means
all
components
involved
in
transporting,
metering,
and
mixing
the
fuel
from
the
fuel
tank
to
the
combustion
chamber(
s),
including
the
fuel
tank,
fuel
tank
cap,
fuel
pump,
fuel
filters,
fuel
lines,
carburetor
or
fuelinjection
components,
and
all
fuelsystem
vents.
Good
engineering
judgment
has
the
meaning
we
give
it
in
§
1068.5
of
this
chapter.
Hydrocarbon
(
HC)
means
the
hydrocarbon
group
on
which
the
emission
standards
are
based
for
each
fuel
type.
For
gasoline
and
LPG
fueled
engines,
HC
means
total
hydrocarbon
(
THC).
For
natural
gas
fueled
engines,
HC
means
nonmethane
hydrocarbon
(
NMHC).
For
alcohol
fueled
engines,
HC
means
total
hydrocarbon
equivalent
(
THCE).
Identification
number
means
a
unique
specification
(
for
example,
model
number/
serial
number
combination)
that
allows
someone
to
distinguish
a
particular
vehicle
or
engine
from
other
similar
vehicle
or
engines.
Manufacturer
has
the
meaning
given
in
section
216(
1)
of
the
Act.
In
general,
this
term
includes
any
person
who
manufactures
a
vehicle
or
engine
for
sale
in
the
United
States
or
otherwise
introduces
a
new
vehicle
or
engine
into
commerce
in
the
United
States.
This
includes
importers
that
import
for
resale.
Maximum
brake
power
means
the
maximum
brake
power
of
an
engine
at
test
conditions.
Maximum
test
power
means
the
maximum
brake
power
of
an
engine
at
maximum
test
speed.
Maximum
test
speed
has
the
meaning
we
give
in
§
1065.515
of
this
chapter
Maximum
test
torque
means
the
torque
output
observed
at
wide
open
throttle
at
a
given
speed.
Model
year
means
one
of
the
following
things:
(
1)
For
freshly
manufactured
vehicles
or
engines
(
see
definition
of
``
new,''
paragraph
(
1)),
model
year
means
one
of
the
following:
(
i)
Calendar
year.
(
ii)
Your
annual
new
model
production
period
if
it
is
different
than
the
calendar
year.
This
must
include
January
1
of
the
calendar
year
for
which
the
model
year
is
named.
It
may
not
begin
before
January
2
of
the
previous
calendar
year
and
it
must
end
by
December
31
of
the
named
calendar
year.
(
2)
For
a
vehicle
or
engine
that
is
converted
to
a
nonroad
vehicle
or
engine
after
being
placed
into
service
in
a
motor
vehicle,
model
year
means
the
calendar
year
in
which
the
vehicle
or
engine
was
originally
produced
(
see
definition
of
``
new,''
paragraph
(
2)).
(
3)
For
a
nonroad
vehicle
excluded
under
§
1051.5
that
is
later
converted
to
operate
in
an
application
that
is
not
excluded,
model
year
means
the
calendar
year
in
which
the
vehicle
was
originally
produced
(
see
definition
of
``
new,''
paragraph
(
3)).
(
4)
For
engines
that
are
not
freshly
manufactured
but
are
installed
in
new
nonroad
vehicles,
model
year
means
the
calendar
year
in
which
the
engine
is
installed
in
the
new
nonroad
vehicle.
This
installation
date
is
based
on
the
time
that
final
assembly
of
the
vehicle
is
complete
(
see
definition
of
``
new,''
paragraph
(
4)).
(
5)
For
a
vehicle
or
engine
modified
by
an
importer
(
not
the
original
manufacturer)
who
has
a
certificate
of
conformity
for
the
imported
vehicle
or
engine
(
see
definition
of
``
new,''
paragraph
(
5)),
model
year
means
one
of
the
following:
(
i)
The
calendar
year
in
which
the
importer
finishes
modifying
and
labeling
the
vehicle
or
engine.
(
ii)
Your
annual
production
period
for
producing
vehicles
or
engines
if
it
is
different
than
the
calendar
year;
follow
the
guidelines
in
paragraph
(
1)(
ii)
of
this
definition.
(
6)
For
a
vehicle
or
engine
you
import
that
does
not
meet
the
criteria
in
paragraphs
(
1)
through
(
5)
of
the
definition
of
``
new''
model
year
means
the
calendar
year
in
which
the
manufacturer
completed
the
original
assembly
of
the
vehicle
or
engine.
In
general,
this
applies
to
used
equipment
that
you
import
without
conversion
or
major
modification.
Motor
vehicle
has
the
meaning
we
give
in
§
85.1703(
a)
of
this
chapter.
In
general,
motor
vehicle
means
a
selfpropelled
vehicle
that
can
transport
one
or
more
people
or
any
material,
but
does
not
include
any
of
the
following:
(
1)
Vehicles
having
a
maximum
ground
speed
over
level,
paved
surfaces
no
higher
than
40
km
per
hour
(
25
miles
per
hour).
(
2)
Vehicles
that
lack
features
usually
needed
for
safe,
practical
use
on
streets
or
highways
for
example,
safety
features
required
by
law,
a
reverse
gear
(
except
for
motorcycles),
or
a
differential.
(
3)
Vehicles
whose
operation
on
streets
or
highways
would
be
unsafe,
impractical,
or
highly
unlikely.
Examples
are
vehicles
with
tracks
instead
of
wheels,
very
large
size,
or
features
associated
with
military
vehicles,
such
as
armor
or
weaponry.
New
means
relating
to
any
of
the
following
vehicles
or
engines:
(
1)
A
freshly
manufactured
engine
or
vehicle
for
which
the
ultimate
buyer
has
never
received
the
equitable
or
legal
title.
This
kind
of
vehicle
might
commonly
be
thought
of
as
``
brand
new.''
In
the
case
of
this
paragraph
(
1),
the
vehicle
or
engine
is
no
longer
new
when
the
ultimate
buyer
receives
this
title
or
the
product
is
placed
into
service,
whichever
comes
first.
(
2)
An
engine
originally
manufactured
as
a
motor
vehicle
engine
that
is
later
intended
to
be
used
in
a
piece
of
nonroad
equipment.
In
this
case,
the
engine
ceases
being
a
motor
vehicle
engine
and
becomes
a
``
new
nonroad
engine''.
The
engine
is
no
longer
new
when
it
is
placed
into
nonroad
service.
(
3)
A
nonroad
engine
that
has
been
previously
placed
into
service
in
an
application
we
exclude
under
§
1051.5
or
exempt
under
1051.620,
where
that
engine
is
installed
in
a
piece
of
equipment
for
which
these
exclusions
or
exemptions
do
not
apply.
The
engine
is
no
longer
new
when
it
is
placed
into
nonroad
service.
For
example,
this
would
apply
to
a
competition
vehicle
that
is
no
longer
used
solely
for
competition.
(
4)
An
engine
not
covered
by
paragraphs
(
1)
through
(
3)
of
this
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definition
that
is
intended
to
be
installed
in
new
nonroad
equipment.
The
engine
is
no
longer
new
when
the
ultimate
buyer
receives
a
title
for
the
equipment
or
the
product
is
placed
into
service,
whichever
comes
first.
This
generally
includes
installation
of
used
engines
in
new
vehicles.
(
5)
An
imported
nonroad
vehicle
or
engine
covered
by
a
certificate
of
conformity
issued
under
this
part,
where
someone
other
than
the
original
manufacturer
modifies
the
vehicle
or
engine
after
its
initial
assembly
and
holds
the
certificate.
The
vehicle
or
engine
is
no
longer
new
when
it
is
placed
into
nonroad
service.
(
6)
An
imported
nonroad
vehicle
or
engine
that
is
not
covered
by
a
certificate
of
conformity
issued
under
this
part
at
the
time
of
importation.
This
addresses
uncertified
engines
and
vehicles
that
have
been
placed
into
service
in
other
countries
and
that
someone
seeks
to
import
into
the
United
States.
Importation
of
this
kind
of
new
nonroad
engine
or
vehicle
is
generally
prohibited
by
part
1068
of
this
chapter.
Noncompliant
vehicle
or
engine
means
a
vehicle
or
engine
that
was
originally
covered
by
a
certificate
of
conformity,
but
is
not
in
the
certified
configuration
or
otherwise
does
not
comply
with
the
conditions
of
the
certificate.
Nonconforming
vehicle
or
engine
means
a
vehicle
or
engine
not
covered
by
a
certificate
of
conformity
that
would
otherwise
be
subject
to
emission
standards.
Nonmethane
hydrocarbon
means
the
difference
between
the
emitted
mass
of
total
hydrocarbons
and
the
emitted
mass
of
methane.
Nonroad
means
relating
to
nonroad
engines,
or
to
vehicles
or
equipment
that
include
nonroad
engines.
Nonroad
engine
has
the
meaning
given
in
§
1068.30
of
this
chapter.
In
general
this
means
all
internalcombustion
engines
except
motor
vehicle
engines,
stationary
engines,
or
engines
used
solely
for
competition.
This
part
only
applies
to
nonroad
engines
that
are
used
in
snowmobiles,
off
highway
motorcycles,
and
ATVs
(
see
§
1051.5).
Off
highway
motorcycle
means
a
twowheeled
vehicle
with
a
nonroad
engine
and
a
seat
(
excluding
marine
vessels
and
aircraft).
(
Note:
highway
motorcycles
are
regulated
under
40
CFR
part
86.)
Offroad
utility
vehicle
means
a
nonroad
vehicle
that
has
four
or
more
wheels,
seating
for
two
or
more
persons,
is
designed
for
operation
over
rough
terrain,
and
has
either
a
rear
payload
350
pounds
or
more
or
seating
for
six
or
more
passengers.
Vehicles
intended
primarily
for
recreational
purposes
that
are
not
capable
of
transporting
six
passengers
(
such
as
dune
buggies)
are
not
offroad
utility
vehicles.
(
Note:
§
1051.1(
a)
specifies
that
some
offroad
utility
vehicles
are
required
to
meet
the
requirements
that
apply
for
all
terrain
vehicles.)
Oxides
of
nitrogen
has
the
meaning
given
it
in
40
CFR
part
1065.
Phase
1
means
relating
to
Phase
1
standards
of
§
§
1051.103,
1051.105,
or
1051.107,
or
other
Phase
1
standards
specified
in
subpart
B
of
this
part.
Phase
2
means
relating
to
Phase
2
standards
of
§
1051.103,
or
other
Phase
2
standards
specified
in
subpart
B
of
this
part.
Phase
3
means
relating
to
Phase
3
standards
of
§
1051.103,
or
other
Phase
3
standards
specified
in
subpart
B
of
this
part.
Physically
adjustable
range
means
the
entire
range
over
which
an
engine
parameter
can
be
adjusted,
except
as
modified
by
§
1051.115(
c).
For
parts
described
in
§
1051.115(
d),
``
physically
adjustable
range''
means
the
adjustable
range
defined
in
that
paragraph.
Placed
into
service
means
used
for
its
intended
purpose.
Point
of
first
retail
sale
means
the
location
at
which
the
retail
sale
occurs.
This
generally
means
a
dealership.
Recreational
means,
for
purposes
of
this
part,
relating
to
snowmobiles,
allterrain
vehicles,
off
highway
motorcycles,
and
other
vehicles
that
we
regulate
under
this
part.
Note
that
40
CFR
part
90
applies
to
other
recreational
vehicles.
Revoke
means
to
discontinue
the
certificate
for
an
engine
family.
If
we
revoke
a
certificate,
you
must
apply
for
a
new
certificate
before
continuing
to
produce
the
affected
vehicles
or
engines.
This
does
not
apply
to
vehicles
or
engines
you
no
longer
possess.
Round
means
to
round
numbers
according
to
ASTM
E29
02
(
incorporated
by
reference
in
§
1051.810),
unless
otherwise
specified.
Scheduled
maintenance
means
adjusting,
repairing,
removing,
disassembling,
cleaning,
or
replacing
components
or
systems
that
is
periodically
needed
to
keep
a
part
from
failing
or
malfunctioning.
It
also
may
mean
actions
you
expect
are
necessary
to
correct
an
overt
indication
of
failure
or
malfunction
for
which
periodic
maintenance
is
not
appropriate.
Small
volume
manufacturer
means:
(
1)
For
motorcycles
and
ATVs,
a
manufacturer
that
sold
motorcycles
or
ATVs
before
2003
and
had
annual
U.
S.
directed
production
of
no
more
than
5,000
off
road
motorcycles
and
ATVs
(
combined
number)
in
2002
and
all
earlier
calendar
years.
For
manufacturers
owned
by
a
parent
company,
the
limit
applies
to
the
production
of
the
parent
company
and
all
of
its
subsidiaries.
(
2)
For
snowmobiles,
a
manufacturer
that
sold
snowmobiles
before
2003
and
had
annual
U.
S.
directed
production
of
no
more
than
300
snowmobiles
in
2002
and
all
earlier
model
years.
For
manufacturers
owned
by
a
parent
company,
the
limit
applies
to
the
production
of
the
parent
company
and
all
of
its
subsidiaries.
(
3)
A
manufacturer
that
we
designate
to
be
a
small
volume
manufacturer
under
§
1051.635.
Snowmobile
means
a
vehicle
designed
to
operate
outdoors
only
over
snowcovered
ground,
with
a
maximum
width
of
1.5
meters
or
less.
Spark
ignition
means
relating
to
a
gasoline
fueled
engine,
or
any
other
engine
with
a
spark
plug
(
or
other
sparking
device)
and
with
operating
characteristics
significantly
similar
to
the
theoretical
Otto
combustion
cycle.
Spark
ignition
engines
usually
use
a
throttle
to
regulate
intake
air
flow
to
control
power
during
normal
operation.
Suspend
means
to
temporarily
discontinue
the
certificate
for
an
engine
family.
If
we
suspend
a
certificate,
you
may
not
sell
vehicles
or
engines
from
that
engine
family
unless
we
reinstate
the
certificate
or
approve
a
new
one.
Test
sample
means
the
collection
of
vehicles
or
engines
selected
from
the
population
of
an
engine
family
for
emission
testing.
Test
vehicle
or
engine
means
a
vehicle
or
engine
in
a
test
sample.
Total
hydrocarbon
means
the
combined
mass
organic
compounds
measured
by
our
total
hydrocarbon
test
procedure,
expressed
as
a
hydrocarbon
with
a
hydrogen
to
carbon
mass
ratio
of
1.85:
1.
Total
hydrocarbon
equivalent
means
the
sum
of
the
carbon
mass
contributions
of
non
oxygenated
hydrocarbons,
alcohols
and
aldehydes,
or
other
organic
compounds
that
are
measured
separately
as
contained
in
a
gas
sample,
expressed
as
petroleumfueled
engine
hydrocarbons.
The
hydrogen
to
carbon
ratio
of
the
equivalent
hydrocarbon
is
1.85:
1.
Ultimate
buyer
means
ultimate
purchaser.
Ultimate
purchaser
means,
with
respect
to
any
new
vehicle
or
engine,
the
first
person
who
in
good
faith
purchases
such
vehicle
or
engine
for
purposes
other
than
resale.
United
States
means
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
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Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.
Upcoming
model
year
means
for
an
engine
family
the
model
year
after
the
one
currently
in
production.
U.
S.
directed
production
means
the
number
of
vehicle
units,
subject
to
the
requirements
of
this
part,
produced
by
a
manufacturer
(
and/
or
imported)
for
which
the
manufacturer
has
a
reasonable
assurance
that
sale
was
or
will
be
made
to
ultimate
buyers
in
the
United
States.
Useful
life
means
the
period
during
which
a
vehicle
is
required
to
comply
with
all
applicable
emission
standards,
specified
as
a
number
of
kilometers,
hours,
and/
or
calendar
years.
It
must
be
at
least
as
long
as
both
of
the
following:
(
1)
The
expected
average
service
life
before
the
vehicle
is
remanufactured
or
retired
from
service.
(
2)
The
minimum
useful
life
value.
Void
means
to
invalidate
a
certificate
or
an
exemption.
If
we
void
a
certificate,
all
the
vehicles
produced
under
that
engine
family
for
that
model
year
are
considered
noncompliant,
and
you
are
liable
for
each
vehicle
produced
under
the
certificate
and
may
face
civil
or
criminal
penalties
or
both.
If
we
void
an
exemption,
all
the
vehicles
produced
under
that
exemption
are
considered
uncertified
(
or
nonconforming),
and
you
are
liable
for
each
vehicle
produced
under
the
exemption
and
may
face
civil
or
criminal
penalties
or
both.
You
may
not
produce
any
additional
vehicles
using
the
voided
exemption.
Wide
open
throttle
means
maximum
throttle
opening.
Unless
this
is
specified
at
a
given
speed,
it
refers
to
maximum
throttle
opening
at
maximum
speed.
For
electronically
controlled
or
other
engines
with
multiple
possible
fueling
rates,
wide
open
throttle
also
means
the
maximum
fueling
rate
at
maximum
throttle
opening
under
test
conditions.
§
1051.805
What
symbols,
acronyms,
and
abbreviations
does
this
part
use?
The
following
symbols,
acronyms,
and
abbreviations
apply
to
this
part:
°
degrees.
ASTM
American
Society
for
Testing
and
Materials.
ATV
all
terrain
vehicle.
cc
cubic
centimeters.
cm
centimeter.
C
Celsius.
CO
carbon
monoxide.
CO2
carbon
dioxide.
EPA
Environmental
Protection
Agency.
F
Fahrenheit.
g
grams.
g/
gal/
day
grams
per
gallon
per
test
day.
g/
m2/
day
grams
per
meter
square
per
test
day.
Hg
mercury.
hr
hours.
km
kilometer.
kW
kilowatt.
LPG
liquefied
petroleum
gas.
m
meters.
mm
millimeters.
mW
milliwatts.
NMHC
nonmethane
hydrocarbons.
NOX
oxides
of
nitrogen
(
NO
and
NOX).
psig
pounds
per
square
inches
of
gauge
pressure.
rpm
revolutions
per
minute.
SAE
Society
of
Automotive
Engineers.
SI
spark
ignition.
THC
total
hydrocarbon.
THCE
total
hydrocarbon
equivalent.
U.
S.
C.
United
States
Code.
§
1051.810
What
materials
does
this
part
reference?
We
have
incorporated
by
reference
the
documents
listed
in
this
section.
The
Director
of
the
Federal
Register
approved
the
incorporation
by
reference
as
prescribed
in
5
U.
S.
C.
552(
a)
and
1
CFR
part
51.
Anyone
may
inspect
copies
at
the
U.
S.
EPA,
Air
and
Radiation
Docket
and
Information
Center,
1301
Constitution
Ave.,
NW.,
Room
B102,
EPA
West
Building,
Washington,
DC
20460
or
the
Office
of
the
Federal
Register,
800
N.
Capitol
St.,
NW.,
7th
Floor,
Suite
700,
Washington,
DC.
(
a)
ASTM
material.
Table
1
of
§
1051.810
lists
material
from
the
American
Society
for
Testing
and
Materials
that
we
have
incorporated
by
reference.
The
first
column
lists
the
number
and
name
of
the
material.
The
second
column
lists
the
sections
of
this
part
where
we
reference
it.
Anyone
may
purchase
copies
of
these
materials
from
the
American
Society
for
Testing
and
Materials,
100
Barr
Harbor
Dr.,
West
Conshohocken,
PA
19428.
Table
1
follows:
TABLE
1
OF
§
1051.810.
ASTM
MATERIALS
Document
number
and
name
Part
1051
reference
ASTM
D471
98,
Standard
Test
Method
for
Rubber
Property
Effect
of
Liquids.
.....................
1051.501
ASTM
D814
95
(
reapproved
2000),
Standard
Test
Method
for
Rubber
Property
Vapor
Transmission
of
Volatile
Liquids
.........................................
1051.245
ASTM
E29
02,
Standard
Practice
for
Using
Significant
Digits
in
Test
Data
to
Determine
Conformance
with
Specifications
........................................
1051.801
(
b)
SAE
material.
Table
2
of
§
1051.810
lists
material
from
the
Society
of
Automotive
Engineering
that
we
have
incorporated
by
reference.
The
first
column
lists
the
number
and
name
of
the
material.
The
second
column
lists
the
sections
of
this
part
where
we
reference
it.
Anyone
may
purchase
copies
of
these
materials
from
the
Society
of
Automotive
Engineers,
400
Commonwealth
Drive,
Warrendale,
PA
15096.
Table
2
follows:
TABLE
2
OF
§
1051.810.
SAE
MATERIALS
Document
number
and
name
Part
1051
reference
SAE
J30,
Fuel
and
Oil
Hoses,
June
1998.
..............................
1051.245,
1051.501
SAE
J1930,
Electrical/
Electronic
Systems
Diagnostic
Terms,
Definitions,
Abbreviations,
and
Acronyms,
May
1998.
.............
1051.135
SAE
J2260,
Nonmetallic
Fuel
System
Tubing
with
One
or
More
Layers,
November
1996.
1051.245
§
1051.815
How
should
I
request
EPA
to
keep
my
information
confidential?
(
a)
Clearly
show
what
you
consider
confidential
by
marking,
circling,
bracketing,
stamping,
or
some
other
method.
We
will
store
your
confidential
information
as
described
in
40
CFR
part
2.
Also,
we
will
disclose
it
only
as
specified
in
40
CFR
part
2.
(
b)
If
you
send
us
a
second
copy
without
the
confidential
information,
we
will
assume
it
contains
nothing
confidential
whenever
we
need
to
release
information
from
it.
(
c)
If
you
send
us
information
without
claiming
it
is
confidential,
we
may
make
it
available
to
the
public
without
further
notice
to
you,
as
described
in
§
2.204
of
this
chapter.
§
1051.820
How
do
I
request
a
hearing?
See
40
CFR
part
1068,
subpart
G,
for
information
related
to
hearings.
PART
1065
TEST
PROCEDURES
AND
EQUIPMENT
Subpart
A
Applicability
and
General
Provisions
Sec.
1065.1
Applicability.
1065.5
Overview
of
test
procedures.
1065.10
Other
test
procedures.
1065.15
Engine
testing.
1065.20
Limits
for
test
conditions.
Subpart
B
Equipment
and
Analyzers
1065.101
Overview.
1065.105
Dynamometer
and
engine
equipment
specifications.
1065.110
Exhaust
gas
sampling
system;
spark
ignition
(
SI)
engines.
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and
Regulations
1065.115
Exhaust
gas
sampling
system;
compression
ignition
engines.
[
Reserved]
1065.120
Raw
sampling.
[
Reserved]
1065.125
Analyzers
(
overview/
general
response
characteristics).
1065.130
Hydrocarbon
analyzers.
1065.135
NOX
analyzers.
1065.140
CO
and
CO2
analyzers.
1065.145
Smoke
meters.
[
Reserved]
1065.150
Flow
meters.
1065.155
Temperature
and
pressure
sensors.
Subpart
C
Test
Fuels
and
Analytical
Gases
1065.201
General
requirements
for
test
fuels.
1065.205
Test
fuel
specifications
for
distillate
diesel
fuel.
[
Reserved]
1065.210
Test
fuel
specifications
for
gasoline.
1065.215
Test
fuel
specifications
for
natural
gas.
1065.220
Test
fuel
specifications
for
liquefied
petroleum
gas.
1065.240
Lubricating
oils.
1065.250
Analytical
gases.
Subpart
D
Analyzer
and
Equipment
Calibrations
1065.301
Overview.
1065.305
International
calibration
standards.
1065.310
CVS
calibration.
[
Reserved]
1065.315
Torque
calibration.
Subpart
E
Engine
Selection,
Preparation,
and
Service
Accumulation
1065.401
Selecting
a
test
engine.
1065.405
Preparing
and
servicing
a
test
engine.
1065.410
Service
limits
for
stabilized
test
engines.
1065.415
Durability
demonstration.
Subpart
F
Running
an
Emission
Test
1065.501
Overview
of
the
engine
dynamometer
test
procedures.
1065.510
Engine
mapping
procedures.
1065.515
Test
cycle
generation.
1065.520
Engine
starting,
restarting,
and
shutdown.
1065.525
Engine
dynamometer
test
run.
1065.530
Test
cycle
validation
criteria.
Subpart
G
Data
Analysis
and
Calculations
1065.601
Overview.
1065.605
Required
records.
1065.610
Bag
sample
analysis.
1065.615
Bag
sample
calculations.
Subpart
H
Particulate
Measurements
[
Reserved]
Subpart
I
Testing
With
Oxygenated
Fuels
1065.801
Applicability.
1065.805
Sampling
system.
1065.810
Calculations.
Subpart
J
Field
Testing
1065.901
Applicability.
1065.905
General
provisions.
1065.910
Measurement
accuracy
and
precision.
1065.915
Equipment
specifications
for
SI
engines.
1065.920
Equipment
setup
and
test
run
for
SI
engines.
1065.925
Calculations.
1065.930
Specifications
for
mass
air
flow
sensors.
1065.935
Specifications
for
THC
analyzers.
1065.940
Specifications
for
NOX
and
air/
fuel
sensors.
1065.945
Specifications
for
CO
analyzers.
1065.950
Specifications
for
speed
and
torque
measurement.
Subpart
K
Definitions
and
Other
Reference
Information
1065.1001
Definitions.
1065.1005
Symbols,
acronyms,
and
abbreviations.
1065.1010
Reference
materials.
1065.1015
Confidential
information.
Authority:
42
U.
S.
C.
7401
7671(
q).
Subpart
A
Applicability
and
General
Provisions
§
1065.1
Applicability.
(
a)
This
part
describes
the
procedures
that
apply
to
testing
that
we
require
for
the
following
engines
or
for
equipment
using
the
following
engines:
(
1)
Large
nonroad
spark
ignition
engines
we
regulate
under
40
CFR
part
1048.
(
2)
Vehicles
that
we
regulate
under
40
CFR
part
1051
(
i.
e.,
recreational
SI
vehicles)
that
are
regulated
based
on
engine
testing.
See
40
CFR
part
1051
to
determine
which
vehicles
may
be
certified
based
on
engine
test
data.
(
b)
This
part
does
not
apply
to
any
of
the
following
engine
or
vehicle
categories:
(
1)
Light
duty
highway
vehicles
(
see
40
CFR
part
86).
(
2)
Heavy
duty
highway
Otto
cycle
engines
(
see
40
CFR
part
86).
(
3)
Heavy
duty
highway
diesel
engines
(
see
40
CFR
part
86).
(
4)
Aircraft
engines
(
see
40
CFR
part
87).
(
5)
Locomotive
engines
(
see
40
CFR
part
92).
(
6)
Land
based
nonroad
diesel
engines
(
see
40
CFR
part
89).
(
7)
General
marine
engines
(
see
40
CFR
parts
89
and
94).
(
8)
Marine
outboard
and
personal
watercraft
engines
(
see
40
CFR
part
91).
(
9)
Small
nonroad
spark
ignition
engines
(
see
40
CFR
part
90).
(
c)
This
part
is
addressed
to
you
as
a
manufacturer,
but
it
applies
equally
to
anyone
who
does
testing
for
you,
and
to
us
when
we
conduct
testing
to
determine
if
you
meet
emission
standards.
(
d)
Paragraph
(
a)
of
this
section
identifies
the
parts
of
the
CFR
that
define
emission
standards
and
other
requirements
for
particular
types
of
engines.
In
this
part
1065,
we
refer
to
each
of
these
other
parts
generically
as
the
``
standard
setting
part.''
For
example,
40
CFR
part
1051
is
always
the
standard
setting
part
for
snowmobiles.
Follow
the
standard
setting
part
if
it
differs
from
this
part.
(
e)
For
equipment
subject
to
this
part
and
regulated
under
equipment
based
or
vehicle
based
standards,
interpret
the
term
``
engine''
in
this
part
to
include
equipment
and
vehicles(
see
40
CFR
1068.30).
§
1065.5
Overview
of
test
procedures.
(
a)
Some
of
the
provisions
of
this
part
do
not
apply
to
all
types
of
engines.
For
example,
measurement
of
particulate
matter
is
generally
not
required
for
spark
ignition
engines.
See
the
standard
setting
part
to
determine
which
provisions
in
this
part
may
not
apply.
Before
using
this
part's
procedures,
read
the
standard
setting
part
to
answer
at
least
the
following
questions:
(
1)
How
should
I
warm
up
the
test
engine
before
measuring
emissions?
Do
I
need
to
measure
cold
start
emissions
during
this
warm
up
segment
of
the
duty
cycle?
(
2)
Do
I
measure
emissions
while
the
warmed
up
engine
operates
over
a
steady
state
schedule,
a
transient
schedule,
or
both?
(
3)
What
are
the
speed
and
load
points
of
the
test
cycle(
s)?
(
4)
Which
exhaust
constituents
do
I
need
to
measure?
(
5)
Does
testing
require
full
flow
dilute
sampling?
Is
raw
sampling
acceptable?
Is
partial
flow
dilute
sampling
acceptable?
(
6)
Do
any
unique
specifications
apply
for
test
fuels?
(
7)
What
maintenance
steps
may
I
do
before
or
between
tests
on
an
emissiondata
engine?
(
8)
Do
any
unique
requirements
apply
to
stabilizing
emission
levels
on
a
new
engine?
(
9)
Do
any
unique
requirements
apply
to
testing
conditions,
such
as
ambient
temperatures
or
pressures?
(
10)
Are
there
special
emission
standards
that
affect
engine
operation
and
ambient
conditions?
(
11)
Are
there
different
emission
standards
that
apply
to
field
testing
under
normal
operation?
(
b)
The
following
table
shows
how
this
part
divides
testing
specifications
into
subparts:
This
subpart...
Describes
these
specifications
or
procedures...
Subpart
A
.....
General
provisions
for
test
procedures.
Subpart
B
.....
Equipment
for
testing.
Subpart
C
.....
Fuels
and
analytical
gases
for
testing.
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8,
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/
Rules
and
Regulations
This
subpart...
Describes
these
specifications
or
procedures...
Subpart
D
.....
How
to
calibrate
test
equipment
Subpart
E
.....
How
to
prepare
engines
for
testing,
including
service
accumulation.
Subpart
F
.....
How
to
test
for
emissions.
Subpart
G
.....
How
to
calculate
emission
levels
from
measured
data.
Subpart
H
.....
[
Reserved].
Subpart
I
......
How
to
measure
emissions
from
engines
fueled
with
an
oxygenated
fuel
such
as
methanol
or
ethanol.
Subpart
J
......
How
to
do
field
testing
of
inuse
vehicles
and
equipment
Subpart
K
.....
Definitions,
abbreviations,
and
other
reference
information
that
apply
to
emission
testing
§
1065.10
Other
test
procedures.
(
a)
Your
testing.
These
test
procedures
apply
for
all
testing
that
you
do
to
show
compliance
with
emission
standards,
with
a
few
exceptions
listed
in
this
section.
(
b)
Our
testing.
These
test
procedures
generally
apply
for
testing
that
we
do
to
determine
if
your
engines
comply
with
applicable
emission
standards.
We
may
conduct
other
testing
as
allowed
by
the
Act.
(
c)
Exceptions.
You
may
be
allowed
or
required
to
use
test
procedures
other
than
those
specified
in
this
part
in
the
following
cases:
(
1)
The
test
procedures
in
this
part
are
intended
to
produce
emission
measurements
equivalent
to
those
that
would
result
from
measuring
emissions
during
in
use
operation
using
the
same
engine
configuration
installed
in
a
piece
of
equipment.
If
good
engineering
judgment
indicates
that
use
of
the
procedures
in
this
part
for
an
engine
would
result
in
measurements
that
are
not
representative
of
in
use
operation
of
that
engine,
you
must
notify
us.
If
we
determine
that
using
these
procedures
would
result
in
measurements
that
are
significantly
unrepresentative
and
that
changing
the
procedures
will
result
in
more
representative
measurements
and
not
decrease
the
stringency
of
emission
standards,
we
will
specify
changes
to
the
procedures.
In
your
notification
to
us,
you
should
recommend
specific
changes
you
think
are
necessary.
(
2)
You
may
ask
to
use
emission
data
collected
using
other
test
procedures,
such
as
those
of
the
California
Air
Resources
Board
or
the
International
Organization
for
Standardization.
We
will
allow
this
only
if
you
show
us
that
these
data
are
equivalent
to
data
collected
using
our
test
procedures.
(
3)
You
may
ask
to
use
alternate
procedures
that
produce
measurements
equivalent
to
those
from
the
specified
procedures.
If
you
send
us
a
written
request
showing
your
procedures
are
equivalent,
and
we
agree
that
they
are
equivalent,
we
will
allow
you
to
use
them.
You
may
not
use
an
alternate
procedure
until
we
approve
them,
either
by:
telling
you
directly
that
you
may
use
this
procedure;
or
issuing
guidance
to
all
manufacturers,
which
allows
you
to
use
the
alternate
procedure
without
additional
approval.
(
4)
You
may
ask
to
use
special
test
procedures
if
your
engine
cannot
be
tested
under
the
specified
procedures
(
for
example,
your
engine
cannot
operate
on
the
specified
transient
cycle).
In
this
case,
tell
us
in
writing
why
you
cannot
satisfactorily
test
your
engines
using
this
part's
procedures
and
ask
to
use
a
different
approach.
We
will
approve
your
special
test
procedures
if
we
determine
they
would
produce
emission
measurements
that
are
representative
of
those
that
would
result
from
measuring
emissions
during
in
use
operation.
You
may
not
use
special
procedures
until
we
approve
them.
(
5)
The
standard
setting
part
may
contain
other
specifications
for
test
procedures
that
apply
for
your
engines.
In
cases
where
it
is
not
possible
to
comply
with
both
the
test
procedures
in
those
parts
and
the
test
procedures
in
this
part,
you
must
comply
with
the
test
procedures
specified
in
the
standardsetting
part.
Those
other
parts
may
also
allow
you
to
deviate
from
the
test
procedures
of
this
part
for
other
reasons.
§
1065.15
Engine
testing.
(
a)
This
part
describes
the
procedures
for
performing
exhaust
emission
tests
on
engines
that
must
meet
emission
standards.
(
b)
Generally,
you
must
test
an
engine
while
operating
it
on
a
laboratory
dynamometer
over
a
prescribed
sequence.
(
Subpart
J
of
this
part
describes
in
use
testing
of
engines
installed
in
vehicles
or
equipment.)
You
need
to
sample
and
analyze
the
exhaust
gases
generated
during
engine
operation
to
determine
the
concentration
of
the
regulated
pollutants.
(
c)
Concentrations
are
converted
into
units
of
grams
of
pollutant
per
kilowatthour
(
g/
kW
hr)
or
similar
units
for
comparison
to
emission
standards.
If
the
applicable
emission
standards
are
expressed
as
g/
bhp
hr,
references
in
this
part
to
kW
should
generally
be
interpreted
to
mean
horsepower.
§
1065.20
Limits
for
test
conditions.
(
a)
Unless
specified
elsewhere
in
this
chapter,
you
may
conduct
tests
to
determine
compliance
with
duty
cycle
emission
standards
at
ambient
temperatures
of
20
30
°
C
(
68
86
°
F),
ambient
pressures
of
600
775
mm
Hg,
and
any
ambient
humidity
level.
(
b)
Follow
the
standard
setting
part
for
ambient
conditions
when
testing
to
determine
compliance
with
not
toexceed
or
other
off
cycle
emission
standards.
(
c)
For
engine
testing
in
a
laboratory,
you
may
heat,
cool,
and/
or
dehumidify
the
dilution
air
before
it
enters
the
CVS.
(
d)
For
engine
testing
in
a
laboratory,
if
the
barometric
pressure
observed
while
generating
the
maximum
torque
curve
changes
by
more
than
25
mm
Hg
from
the
value
measured
when
you
started
mapping,
you
must
remap
the
engine.
Also,
to
have
a
valid
test,
the
average
barometric
pressure
observed
during
the
exhaust
emission
test
must
be
within
25
mm
Hg
of
the
average
observed
during
the
maximum
torque
curve
generation
(
see
§
1065.510).
Subpart
B
Equipment
and
Analyzers
§
1065.101
Overview.
This
subpart
describes
equipment
and
analyzers
for
measuring
emissions.
Subpart
D
of
this
part
describes
how
to
calibrate
these
devices
and
subpart
C
of
this
part
defines
the
accuracy
and
purity
specifications
of
analytical
gases.
§
1065.105
Dynamometer
and
engine
equipment
specifications.
(
a)
The
engine
dynamometer
system
must
be
able
to
control
engine
torque
and
speed
simultaneously
over
the
applicable
test
cycles
within
the
accuracies
specified
in
§
1065.530.
If
your
dynamometer
cannot
meet
the
accuracy
requirements
in
§
1065.530,
you
must
get
our
approval
before
using
it.
For
transient
testing,
issue
command
set
points
for
engine
torque
and
speed
at
5
Hz
or
greater
(
10
Hz
recommended).
Record
feedback
engine
torque
and
speed
at
least
once
every
second
during
the
test.
In
addition
to
these
general
requirements,
make
sure
your
engine
or
dynamometer's
readout
signals
for
speed
and
torque
meet
the
following
accuracies
for
all
testing:
(
1)
Engine
speed
readout
must
be
accurate
to
within
±
2
percent
of
the
absolute
standard
value.
A
60
tooth
(
or
greater)
wheel
in
combination
with
a
common
mode
rejection
frequency
counter
is
considered
an
absolute
standard
for
engine
or
dynamometer
speed.
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Friday,
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8,
2002
/
Rules
and
Regulations
(
2)
Engine
flywheel
torque
readout
must
meet
one
of
the
two
following
standards
for
accuracy:
(
i)
Within
±
3
percent
of
the
NIST
true
value
torque
(
as
defined
in
§
1065.315).
(
ii)
The
following
accuracies:
If
the
full
scale
torque
value
is...
Engine
flywheel
torque
readout
must
be
within...
T
550
ft
lbs.
............
±
2.5
ft
lbs.
of
NIST
true
value.
550
<
T
1050
ft
lbs.
±
5.0
ft
lbs.
of
NIST
true
value.
T
>
1050
ft
lbs.
±
10.0
ft
lbs.
of
NIST
true
value.
(
3)
Option:
You
may
use
internal
dynamometer
signals
(
such
as
armature
current)
to
measure
torque
if
you
can
show
that
the
engine
flywheel
torque
during
the
test
cycle
conforms
to
paragraph
(
b)(
2)
of
this
section.
Your
measurements
must
compensate
for
increased
or
decreased
flywheel
torque
because
of
the
armature's
inertia
during
accelerations
and
decelerations
in
the
test
cycle.
(
b)
To
verify
that
the
test
engine
has
followed
the
test
cycle
correctly,
collect
the
dynamometer
or
engine
readout
signals
for
speed
and
torque
so
you
can
statistically
correlate
the
engine's
actual
performance
with
the
test
cycle
(
see
§
1065.530).
Normally,
to
do
this,
you
would
convert
analog
signals
from
the
dynamometer
or
engine
into
digital
values
for
computer
storage,
but
all
conversions
must
meet
two
criteria:
(
1)
Speed
values
used
to
evaluate
cycles
must
be
accurate
to
within
2
percent
of
the
readout
value
for
dynamometer
or
engine
speed.
(
2)
Engine
flywheel
torque
values
used
to
evaluate
cycles
must
be
accurate
to
within
2
percent
of
the
readout
value
for
dynamometer
or
engine
flywheel
torque.
(
c)
You
may
combine
the
tolerances
in
paragraphs
(
a)
and
(
b)
of
this
section
if
you
use
the
root
mean
square
(
RMS)
method
and
refer
accuracies
of
the
RMS
values
to
absolute
standard
or
NIST
true
values.
(
1)
Speed
values
used
to
evaluate
cycles
must
be
accurate
to
within
±
2.8
percent
of
the
absolute
standard
values,
as
defined
in
paragraph
(
a)(
1)
of
this
section.
(
2)
Engine
flywheel
torque
values
used
to
evaluate
cycles
must
be
accurate
to
within
±
3.6
percent
of
NIST
true
values,
as
determined
in
§
1065.315.
§
1065.110
Exhaust
gas
sampling
system;
spark
ignition
(
SI)
engines.
(
a)
General.
The
exhaust
gas
sampling
system
described
in
this
section
is
designed
to
measure
the
true
mass
of
gaseous
emissions
in
the
exhaust
of
SI
engines.
(
If
the
standard
setting
part
requires
determination
of
THCE
or
NMHCE
for
your
engine,
then
see
subpart
I
of
this
part
for
additional
requirements.)
Under
the
constantvolume
sampler
(
CVS)
concept,
you
must
measure
the
total
volume
of
the
mixture
of
exhaust
and
dilution
air
and
collect
a
continuously
proportioned
volume
of
sample
for
analysis.
You
must
control
flow
rates
so
that
the
ratio
of
sample
flow
to
CVS
flow
remains
constant.
You
then
determine
the
mass
emissions
from
the
sample
concentration
and
total
flow
over
the
test
period.
(
1)
Do
not
let
the
CVS
or
dilution
air
inlet
system
artificially
lower
exhaust
system
backpressure.
To
verify
proper
backpressures,
measure
pressure
in
the
raw
exhaust
immediately
upstream
of
the
inlet
to
the
CVS.
Continuously
measure
and
compare
the
static
pressure
of
the
raw
exhaust
observed
during
a
transient
cycle
with
and
without
the
CVS
operating.
Static
pressure
measured
with
the
CVS
system
operating
must
remain
within
±
5
inches
of
water
(
1.2
kPa)
of
the
static
pressure
measured
when
disconnected
from
the
CVS,
at
identical
moments
in
the
test
cycle.
(
Note:
We
will
use
sampling
systems
that
can
maintain
the
static
pressure
to
within
±
1
inch
of
water
(
0.25
kPa)
if
your
written
request
shows
that
this
closer
tolerance
is
necessary.)
This
requirement
serves
as
a
design
specification
for
the
CVS/
dilution
air
inlet
system,
and
should
be
performed
as
often
as
good
engineering
practice
dictates
(
for
example,
after
installing
an
uncharacterized
CVS,
adding
an
unknown
inlet
restriction
on
the
dilution
air,
or
otherwise
altering
the
system).
(
2)
The
system
for
measuring
temperature
(
sensors
and
readout)
must
have
an
accuracy
and
precision
of
±
3.4
°
F
(
±
1.9
°
C).
The
temperature
measuring
system
for
a
CVS
without
a
heat
exchanger
must
respond
within
1.50
seconds
to
62.5
percent
of
a
temperature
change
(
as
measured
in
hot
silicone
oil).
For
a
CVS
with
a
heat
exchanger,
there
is
no
specific
requirement
for
response
time.
(
3)
The
system
for
measuring
pressure
(
sensors
and
readout)
must
have
an
accuracy
and
precision
of
±
3
mm
Hg
(
0.4
kPa).
(
4)
The
flow
capacity
of
the
CVS
must
be
large
enough
to
keep
water
from
condensing
in
the
system.
You
may
dehumidify
the
dilution
air
before
it
enters
the
CVS.
You
also
may
heat
or
cool
the
air
if
three
conditions
exist:
(
i)
The
air
(
or
air
plus
exhaust
gas)
temperature
does
not
exceed
250
°
F
(
121
°
C).
(
ii)
You
calculate
the
CVS
flow
rate
necessary
to
prevent
water
condensation
based
on
the
lowest
temperature
in
the
CVS
before
sampling.
(
We
recommend
insulating
the
CVS
system
when
you
use
heated
dilution
air.)
(
iii)
The
dilution
ratio
is
high
enough
to
prevent
condensation
in
bag
samples
as
they
cool
to
room
temperature.
(
5)
Bags
for
collecting
dilution
air
and
exhaust
samples
must
be
big
enough
for
samples
to
flow
freely.
(
6)
The
general
CVS
sample
system
consists
of
a
dilution
air
filter
(
optional)
and
mixing
assembly,
cyclone
particulate
separator
(
optional),
a
sample
line
for
the
bag
sample
or
other
sample
lines
a
dilution
tunnel,
and
associated
valves
and
sensors
for
pressure
and
temperature.
Except
for
the
system
to
sample
hydrocarbons
from
two
stroke
engines,
the
temperature
of
the
sample
lines
must
be
more
than
3
°
C
above
the
mixture's
maximum
dew
point
and
less
than
121
°
C.
We
recommend
maintaining
them
at
113
±
8
°
C.
For
the
hydrocarbon
sampling
system
with
two
stroke
engines,
the
temperature
of
the
sample
lines
should
be
maintained
at
191
±
11
°
C.
A
general
schematic
of
the
SI
sampling
system
is
shown
in
Figure
1065.110
1,
which
follows:
BILLING
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BILLING
CODE
6460
50
C
(
b)
Steady
state
testing.
Constant
proportional
sampling
is
required
throughout
transient
testing,
but
is
not
required
throughout
steady
state
testing.
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/
Rules
and
Regulations
Steady
state
testing
requires
that
you
draw
a
proportional
sample
for
each
test
mode,
but
you
may
sample
in
different
proportions
for
different
test
modes,
as
long
as
you
know
the
ratio
of
the
sample
flow
to
total
flow
during
each
test
mode.
This
allowance
means
that
you
may
use
simpler
flow
control
systems
for
steadystate
testing
than
are
shown
in
Figure
1065.110
1
of
this
section.
(
c)
Configuration
variations.
Since
various
configurations
can
produce
equivalent
results,
you
need
not
conform
exactly
to
the
drawings
in
this
subpart.
You
may
use
other
components
such
as
instruments,
valves,
solenoids,
pumps
and
switches
to
provide
more
information
and
coordinate
the
components'
functions.
Based
on
good
engineering
judgment,
you
may
exclude
other
components
that
are
not
needed
to
maintain
accuracy
on
some
systems.
(
d)
CFV
CVS
component
description.
The
flow
characteristics
of
a
Critical
Flow
Venturi,
Constant
Volume
Sampler
(
CFV
CVS)
are
governed
by
the
principles
of
fluid
dynamics
associated
with
critical
flow.
The
CFV
system
is
commonly
called
a
constant
volume
system
(
CVS)
even
though
the
mass
flow
varies.
More
properly,
they
are
constantproportion
sampling
systems,
because
small
CFVs
in
each
of
the
sample
lines
maintains
proportional
sampling
while
temperatures
vary.
This
CFV
maintains
the
mixture's
flow
rate
at
choked
flow,
which
is
inversely
proportional
to
the
square
root
of
the
gas
temperature,
and
the
system
computes
the
actual
flow
rate
continuously.
Because
pressures
and
temperatures
are
the
same
at
all
venturi
inlets,
the
sample
volume
is
proportional
to
the
total
volume.
The
CFV
CVS
sample
system
uses
critical
flow
venturis
for
the
bag
sample
or
other
sample
lines
(
these
are
shown
in
the
figure
as
flow
control
valves)
and
a
critical
flow
venturi
for
the
dilution
tunnel.
All
venturis
must
be
maintained
at
the
same
temperature.
(
e)
EFC
CVS
component
description.
The
electronic
flow
control
CVS
(
EFC
CVS)
system
for
sampling
is
identical
to
the
CFV
system
described
in
paragraph
(
b)
of
this
section,
except
that
it
adds
electronic
flow
controllers
(
instead
of
sampling
venturis),
a
subsonic
venturi
and
an
electronic
flow
controller
for
the
CVS
(
instead
of
the
critical
flow
venturi),
metering
valves,
and
separate
flow
meters
(
optional)
to
totalize
sample
flow
volumes.
The
EFC
sample
system
must
conform
to
the
following
requirements:
(
1)
The
system
must
meet
all
the
requirements
in
paragraph
(
b)
of
this
section.
(
2)
The
ratio
of
sample
flow
to
CVS
flow
must
not
vary
by
more
than
±
5
percent
from
the
test's
setpoint.
(
3)
Sample
flow
totalizers
must
meet
the
accuracy
specifications
in
§
1065.150.
You
may
obtain
total
volumes
from
the
flow
controllers,
with
our
advance
approval,
if
you
can
show
they
meet
these
accuracies.
(
f)
Component
description,
PDP
CVS.
The
positive
displacement
pump
CVS
(
PDP
CVS)
system
for
sampling
is
identical
to
the
CFV
system
described
in
paragraph
(
b)
of
this
section,
except
for
the
following
changes:
(
1)
Include
a
heat
exchanger.
(
2)
Use
positive
displacement
pumps
for
the
CVS
flow
and
sampling
system
flow.
You
do
not
need
sampling
venturis
or
a
venturi
for
the
dilution
tunnel.
All
pumps
must
operate
at
a
constant
flow
rate.
(
3)
All
pumps
must
operate
at
a
nominally
constant
temperature.
Maintain
the
gas
mixture's
temperature
measured
at
a
point
just
ahead
of
the
positive
displacement
pump
(
and
after
the
heat
exchanger
for
the
main
CVS
pump)
within
±
10
°
F
(
±
5.6
°
C)
of
the
average
operating
temperature
observed
during
the
test.
(
You
may
estimate
the
average
operating
temperature
from
the
temperatures
observed
during
similar
tests.)
The
system
for
measuring
temperature
(
sensors
and
readout)
must
have
an
accuracy
and
precision
of
±
3.4
°
F
(
1.9
°
C),
and
response
time
consistent
with
good
engineering
judgment.
(
g)
Mixed
systems.
You
may
combine
elements
of
paragraphs
(
d),
(
e),
and
(
f)
consistent
with
good
engineering
judgment.
For
example,
you
may
control
the
CVS
flow
rate
using
a
CFV,
and
control
sample
flow
rates
using
electronic
flow
controllers.
§
1065.115
Exhaust
gas
sampling
system;
compression
ignition
engines.
[
Reserved]
§
1065.120
Raw
sampling.
[
Reserved]
§
1065.125
Analyzers
(
overview/
general
response
characteristics).
(
a)
General.
The
following
sections
and
subparts
describe
the
specifications
for
analyzers
and
analytical
equipment:
(
1)
The
analyzers
for
measuring
hydrocarbon,
NOX,
CO,
and
CO2
emission
concentrations
are
specified
in
§
1065.130
through
§
1065.140.
(
2)
The
analytical
equipment
for
measuring
particulate
emissions
is
specified
in
Subpart
H
of
this
part.
(
3)
The
analytical
equipment
for
measuring
emissions
of
oxygenated
compounds
(
for
example,
methanol)
is
specified
in
Subpart
I
of
this
part.
(
4)
The
analytical
equipment
for
measuring
in
use
emissions
is
specified
in
Subpart
J
of
this
part.
(
b)
Response
time.
Analyzers
must
have
the
following
response
characteristics:
(
1)
For
steady
state
testing
and
transient
testing
with
bag
sample
analysis,
the
analyzer
must
reach
at
least
90
percent
of
its
final
response
within
5.0
seconds
after
any
step
change
to
the
input
concentration
at
or
above
80
percent
of
full
scale.
(
2)
For
transient
testing
with
continuous
measurement,
the
analyzer
must
reach
at
least
90
percent
of
its
final
response
within
1.0
second
after
any
step
change
to
the
input
concentration
at
or
above
80
percent
of
full
scale.
(
c)
Precision
and
noise.
Analyzers
must
meet
the
following
characteristics
for
precision
and
noise:
(
1)
Precision
must
be
no
worse
than
±
1
percent
of
full
scale
concentration
for
each
range
used
above
155
ppm
(
or
ppmC),
or
±
2
percent
for
each
range
used
below
155
ppm
(
or
ppmC).
For
this
paragraph
(
c)(
1),
we
define
precision
as
2.5
times
the
standard
deviation
of
10
repetitive
responses
to
a
given
calibration
or
span
gas.
(
2)
Peak
to
peak
response
to
zero
and
calibration
or
span
gases
over
any
10
second
period
must
be
no
more
than
2
percent
of
full
scale
chart
deflection
on
all
ranges
used.
(
d)
Drift.
Analyzers
must
meet
specifications
for
zero
response
and
span
drift.
(
1)
The
zero
response
drift
during
one
hour
must
be
less
than
2
percent
of
fullscale
chart
deflection
on
the
lowest
range
used.
Zero
response
is
the
mean
response,
including
noise,
to
a
zero
gas
during
a
30
second
interval.
(
2)
The
span
drift
during
one
hour
must
be
less
than
2
percent
of
full
scale
chart
deflection
on
the
lowest
range
used.
Span
is
the
difference
between
the
span
response
and
the
zero
response.
Span
response
is
the
mean
response,
including
noise,
to
a
span
gas
during
a
30
second
interval.
(
e)
Calibration.
See
subpart
D
of
this
part
for
specifications
to
calibrate
analyzers.
§
1065.130
Hydrocarbon
analyzers.
This
section
describes
the
requirements
for
flame
ionization
detectors
(
FIDs)
used
to
measure
hydrocarbons.
(
a)
Fuel
the
FID
with
a
mixture
of
hydrogen
in
helium
and
calibrate
it
using
propane.
(
b)
If
you
use
a
heated
FID
(
required
only
for
diesels
and
two
stroke,
sparkignition
engines),
keep
the
temperature
191
±
11
°
C).
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/
Rules
and
Regulations
(
c)
Use
an
overflow
sampling
system
for
heated
continuous
FIDs.
(
In
an
overflow
system
excess
zero
gas
or
span
gas
spills
out
of
the
probe
when
you
are
doing
zero
or
span
checks.)
(
d)
Do
not
premix
the
FID
fuel
and
burner
air.
(
e)
Make
sure
the
FID
meets
accuracy
and
precision
specifications
in
ISO
8178
1
(
incorporated
by
reference
in
§
1065.1010).
§
1065.135
NOX
analyzers.
This
section
describes
the
requirements
for
chemiluminescent
detectors
(
CLD)
used
to
measure
NOX.
Good
engineering
practice
may
require
the
use
of
other
detectors.
(
a)
A
CLD
must
meet
the
following
requirements:
(
1)
Make
sure
your
CLD
meets
the
accuracy
and
precision
specifications
in
ISO
8178
1
(
incorporated
by
reference
in
§
1065.1010).
(
2)
The
NO
to
NO2
converter
must
have
an
efficiency
of
at
least
90
percent.
(
3)
Use
an
overflow
sampling
system
for
continuous
CLDs.
(
In
an
overflow
system
excess
zero
gas
or
span
gas
spills
out
of
the
probe
when
you
are
doing
zero
or
span
checks.)
(
4)
You
do
not
need
a
heated
CLD
to
test
spark
ignition
engines.
(
b)
Using
CLDs
is
generally
acceptable
even
though
they
measure
only
NO
and
NO2,
since
conventional
engines
do
not
emit
significant
amounts
of
other
NOX
species.
§
1065.140
CO
and
CO2
analyzers.
This
section
describes
the
requirements
for
non
dispersive
infrared
absorption
detectors
(
NDIR)
to
measure
CO
and
CO2.
(
a)
The
NDIR
must
meet
the
applicable
accuracy
and
precision
specifications
of
ISO
8178
1
(
incorporated
by
reference
in
§
1065.1010).
(
b)
The
NDIR
must
meet
the
applicable
quench
and
interference
requirements
of
ISO
8178
1
(
incorporated
by
reference
in
§
1065.1010).
§
1065.145
Smoke
meters.
[
Reserved]
§
1065.150
Flow
meters.
(
a)
Flow
meters
must
have
accuracy
and
precision
of
±
2
percent
of
point
or
better
and
be
traceable
to
NIST
standards.
(
b)
You
may
correct
flow
measurements
for
temperature
or
pressure,
if
your
temperature
and
pressure
measurements
have
accuracy
and
precision
of
±
2
percent
of
point
or
better
(
absolute).
§
1065.155
Temperature
and
pressure
sensors.
(
a)
Except
where
we
specify
otherwise
in
this
part,
must
meet
the
applicable
accuracy
and
precision
specifications
of
ISO
8178
1
(
incorporated
by
reference
in
§
1065.1010).
(
b)
Use
good
engineering
judgment
to
design
and
operate
your
temperature
and
pressure
measuring
systems
to
minimize
delays
in
response
time
and
avoid
hysteresis.
Subpart
C
Test
Fuels
and
Analytical
Gases
§
1065.201
General
requirements
for
test
fuels.
(
a)
For
all
emission
tests,
use
test
fuels
meeting
the
specifications
in
this
subpart,
unless
the
standard
setting
part
directs
otherwise.
For
any
service
accumulation
on
a
test
engine,
if
we
do
not
specify
a
fuel,
use
the
specified
test
fuel
or
a
fuel
typical
of
what
you
would
expect
the
engine
to
use
in
service.
(
b)
We
may
require
you
to
test
the
engine
with
each
type
of
fuel
it
can
use
(
for
example,
gasoline
and
natural
gas).
(
c)
If
you
will
produce
engines
that
can
run
on
a
type
of
fuel
(
or
mixture
of
fuels)
that
we
do
not
specify
in
this
subpart,
we
will
allow
you
to
test
with
fuel
representing
commercially
available
fuels
of
that
type.
However,
we
must
approve
your
fuel's
specifications
before
you
may
use
it
for
emission
testing.
(
d)
You
may
use
a
test
fuel
other
than
those
we
specify
in
this
subpart
if
you
do
all
of
the
following:
(
1)
Show
that
it
is
commercially
available.
(
2)
Show
that
your
engines
will
use
only
the
designated
fuel
in
service.
(
3)
Show
that
operating
the
engines
on
the
fuel
we
specify
would
increase
emissions
or
decrease
durability.
(
4)
Get
our
written
approval
before
you
start
testing.
(
e)
We
may
allow
you
to
use
other
test
fuels
(
for
example,
California
Phase
2
gasoline)
if
they
do
not
affect
the
demonstration
of
compliance.
§
1065.205
Test
fuel
specifications
for
distillate
diesel
fuel.
[
Reserved]
§
1065.210
Test
fuel
specifications
for
gasoline.
Gasoline
used
as
a
test
fuel
must
meet
the
following
specifications:
(
a)
Unless
the
standard
setting
part
requires
testing
with
fuel
appropriate
for
low
temperatures,
use
gasoline
test
fuels
meeting
the
specifications
in
the
following
table:
TABLE
1
OF
§
1065.210.
GENERAL
TEST
FUEL
SPECIFICATIONS
FOR
GASOLINE
Item
Procedure1
Value1
Distillation
Range:
1.
Initial
boiling
point,
°
C
..................................................................................................................
ASTM
D
86
01
23.9
35.02
2.
10%
point,
°
C
...............................................................................................................................
ASTM
D
86
01
48.9
57.2
3.50%
point,
°
C
................................................................................................................................
ASTM
D
86
01
93.3
110.0
4.
90%
point,
°
C
...............................................................................................................................
ASTM
D
86
01
148.9
162.8
5.
End
point,
°
C
(
maximum)
.............................................................................................................
ASTM
D
86
01
212.8.
Hydrocarbon
composition:
1.
Olefins,
volume
%
........................................................................................................................
ASTM
D
1319
02
10
maximum
2.
Aromatics,
volume
%
....................................................................................................................
ASTM
D
1319
02
35
maximum
3.
Saturates
......................................................................................................................................
ASTM
D
1319
02
Remainder
Lead
(
organic),
g/
liter
...............................................................................................................................
ASTM
D
3237
97
0.013
maximum
Phosphorous,
g/
liter
.................................................................................................................................
ASTM
D
3231
02
0.0013
maximum
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Rules
and
Regulations
TABLE
1
OF
§
1065.210.
GENERAL
TEST
FUEL
SPECIFICATIONS
FOR
GASOLINE
Continued
Item
Procedure1
Value1
Sulfur,
weight
%
.......................................................................................................................................
ASTM
D
1266
98
0.008
maximum
Volatility
(
Reid
Vapor
Pressure),
kPa
......................................................................................................
ASTM
D
323
99a
60.0
to
63.4.2,3
1All
ASTM
standards
are
incorporated
by
reference
in
§
1065.1010.
2For
testing
at
altitudes
above
1
219
m,
the
specified
volatility
range
is
52
to
55
kPa
(
7.5
to
8.0)
and
the
specified
initial
boiling
point
range
is
23.9
°
to
40.6
°
C.
3For
testing
unrelated
to
evaporative
emissions,
the
specified
range
is
55
to
63
kPa
(
8.0
to
9.1
psi).
(
b)
If
the
standard
setting
part
requires
testing
with
fuel
appropriate
for
low
temperatures,
use
gasoline
test
fuels
meeting
the
specifications
in
the
following
table:
TABLE
2
OF
§
1065.210.
LOW
TEMPERATURE
TEST
FUEL
SPECIFICATIONS
FOR
GASOLINE
Item
Procedure1
Value1
Distillation
Range:
1.
Initial
boiling
point,
°
C
..................................................................................................................
ASTM
D
86
01
24.4
35.6.
2.
10%
point,
°
C
...............................................................................................................................
ASTM
D
86
01
36.7
47.8.
3.
50%
point,
°
C
...............................................................................................................................
ASTM
D
86
01
81.7
101.1.
4.
90%
point,
°
C
...............................................................................................................................
ASTM
D
86
01
157.8
174.4.
5.
End
point,
°
C
(
maximum)
.............................................................................................................
ASTM
D
86
01
211.7.
Hydrocarbon
composition:
1.
Olefins,
volume
%
........................................................................................................................
ASTM
D
1319
02
17.5
maximum.
2.
Aromatics,
volume
%
....................................................................................................................
ASTM
D
1319
02
30.4
maximum.
3.
Saturates
......................................................................................................................................
ASTM
D
1319
02
Remainder.
Lead
(
organic),
g/
liter
...............................................................................................................................
ASTM
D
3237
97
0.013
maximum.
Phosphorous,
g/
liter
.................................................................................................................................
ASTM
D
3231
02
0.005
maximum.
Sulfur,
weight
%
.......................................................................................................................................
ASTM
D
1266
98
0.08
maximum.
Volatility
(
Reid
Vapor
Pressure),
kPa
......................................................................................................
ASTM
D
323
99a
11.2
11.8
psi.
1All
ASTM
standards
are
incorporated
by
reference
in
§
1065.1010.
(
c)
Use
gasoline
test
fuel
with
octane
values
that
represent
commercially
available
fuels
for
the
appropriate
application.
§
1065.215
Test
fuel
specifications
for
natural
gas.
(
a)
Natural
gas
used
as
a
test
fuel
must
meet
the
specifications
in
the
following
table:
TABLE
1
OF
§
1065.215.
TEST
FUEL
SPECIFICATIONS
FOR
NATURAL
GAS
Item
Procedure1
Value
(
mole
percent)
1.
Methane
...............................................................................................................................................
ASTM
D
1945
96
87.0
minimum.
2.
Ethane
..................................................................................................................................................
ASTM
D
1945
96
5.5
maximum.
3.
Propane
...............................................................................................................................................
ASTM
D
1945
96
1.2
maximum.
4.
Butane
..................................................................................................................................................
ASTM
D
1945
96
0.35
maximum.
5.
Pentane
................................................................................................................................................
ASTM
D
1945
96
0.13
maximum.
6.
C6
and
higher
......................................................................................................................................
ASTM
D
1945
96
0.1
maximum.
7.
Oxygen
.................................................................................................................................................
ASTM
D
1945
96
1.0
maximum.
8.
Inert
gases
(
sum
of
CO2
and
N2)
........................................................................................................
ASTM
D
1945
96
5.1
maximum.
1All
ASTM
standards
are
incorporated
by
reference
in
§
1065.1010.
(
b)
At
ambient
conditions,
the
fuel
must
have
a
distinctive
odor
detectable
down
to
a
concentration
in
air
of
not
more
than
one
fifth
of
the
lower
flammability
limit.
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217
/
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8,
2002
/
Rules
and
Regulations
§
1065.220
Test
fuel
specifications
for
liquefied
petroleum
gas.
(
a)
Liquefied
petroleum
gas
used
as
a
test
fuel
must
meet
the
specifications
in
the
following
table:
TABLE
1
OF
§
1065.220.
TEST
FUEL
SPECIFICATIONS
FOR
LIQUEFIED
PETROLEUM
GAS
Item
Procedure1
Value
1.
Propane
..........................................................................................................................
ASTM
D
2163
91
85.0
vol.
percent
minimum.
2.
Vapor
pressure
at
38
°
C
................................................................................................
ASTM
D
1267
02
or
2598
02
2
14
bar
maximum.
3.
Volatility
residue
(
evaporated
temp.,
35
°
C)
..................................................................
ASTM
D
1837
02
38
°
C
maximum.
4.
Butanes
..........................................................................................................................
ASTM
D
2163
91
5.0
vol.
percent
maximum.
5.
Butenes
..........................................................................................................................
ASTM
D
2163
91
2.0
vol.
percent
maximum.
6.
Pentenes
and
heavier
....................................................................................................
ASTM
D
2163
91
0.5
vol.
percent
maximum.
7.
Propene
..........................................................................................................................
ASTM
D
2163
91
10.0
vol.
percent
maximum.
8.
Residual
matter
(
residue
on
evap.
of
100
ml
oil
stain
observ.)
....................................
ASTM
D
2158
02
0.05
ml
maximum
pass.
3
9.
Corrosion,
copper
strip
...................................................................................................
ASTM
D
1838
91
No.
1
maximum.
10.
Sulfur
............................................................................................................................
ASTM
D
2784
98
80
ppm
maximum.
11.
Moisture
content
...........................................................................................................
ASTM
D
2713
91
pass.
1
All
ASTM
standards
are
incorporated
by
reference
in
§
1065.1010.
2
If
these
two
test
methods
yield
different
results,
use
the
results
from
ASTM
D
1267
02.
3
The
test
fuel
must
not
yield
a
persistent
oil
ring
when
you
add
0.3
ml
of
solvent
residue
mixture
to
a
filter
paper
in
0.1
ml
increments
and
examine
it
in
daylight
after
two
minutes
(
see
ASTM
D
2158
02).
(
b)
At
ambient
conditions,
the
fuel
must
have
a
distinctive
odor
detectable
down
to
a
concentration
in
air
of
not
over
one
fifth
of
the
lower
flammability
limit.
§
1065.240
Lubricating
oils.
Lubricating
oils
you
use
to
comply
with
this
part
must
be
commercially
available
and
represent
the
oil
that
will
be
used
with
your
in
use
engines.
§
1065.250
Analytical
gases.
Analytical
gases
that
you
use
to
comply
with
this
part
must
meet
the
accuracy
and
purity
specifications
of
this
section.
You
must
record
the
expiration
date
specified
by
the
gas
supplier
and
may
not
use
any
gas
after
the
expiration
date.
(
a)
Pure
gases.
Use
the
``
pure
gases''
shown
in
the
following
table:
TABLE
1
OF
§
1065.250.
CONCENTRATION
LIMITS
FOR
PURE
GASES
Gas
type
Maximum
contaminant
concentrations
Oxygen
content
Organic
carbon
Carbon
monoxide
Carbon
dioxide
Nitric
oxide
(
NO)
Purified
Nitrogen
..........
1
ppmC
.......................
1
ppm
..........................
400
ppm
......................
0.1
ppm
.......................
NA.
Purified
Oxygen
...........
NA
...............................
NA
...............................
NA
...............................
NA
...............................
99.5
100.0%.
Purified
Synthetic
Air,
or
Zero
Grade
Air.
1
ppmC
.......................
1
ppm
..........................
400
ppm
......................
0.1
ppm
.......................
18
21%.
(
b)
Fuel
for
flame
ionization
detectors.
Use
a
hydrogen
helium
mixture
as
the
fuel.
Make
sure
the
mixture
contains
40
±
2
percent
hydrogen
and
no
more
than
1
ppmC
of
organic
carbon
or
400
ppm
of
CO2.
(
c)
Calibration
and
span
gases.
Apply
the
following
provisions
to
calibration
and
span
gases:
(
1)
Use
the
following
gas
mixtures,
as
applicable,
for
calibrating
and
spanning
your
analytical
instruments:
(
i)
Propane
in
purified
synthetic
air.
You
may
ask
us
to
allow
you
to
use
propane
in
purified
nitrogen
for
high
concentrations
of
propane.
(
ii)
CO
in
purified
nitrogen.
(
iii)
NO
and
NO2
in
purified
nitrogen
(
the
amount
of
NO2
in
this
calibration
gas
must
not
exceed
5
percent
of
the
NO
content).
(
iv)
Oxygen
in
purified
nitrogen.
(
v)
CO2
in
purified
nitrogen.
(
vi)
Methane
in
purified
synthetic
air.
(
2)
The
calibration
gases
in
paragraph
(
c)(
1)
of
this
section
must
be
traceable
to
within
one
percent
of
NIST
gas
standards
or
other
gas
standards
we
have
approved.
Span
gases
in
paragraph
(
c)(
1)
of
this
section
must
be
accurate
to
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2002
/
Rules
and
Regulations
within
two
percent
of
true
concentration,
where
true
concentration
refers
to
NIST
gas
standards,
or
other
gas
standards
we
have
approved.
Record
concentrations
of
calibration
gas
as
volume
percent
or
volume
ppm.
(
3)
You
may
use
gases
for
species
other
than
those
in
paragraph
(
c)(
1)
of
this
section
(
such
as
methanol
in
air
gases
used
to
determine
response
factors),
as
long
as
they
meet
the
following
criteria:
(
i)
They
are
traceable
to
within
±
2
percent
of
NIST
gas
standards
or
other
standards
we
have
approved.
(
ii)
They
remain
within
±
2
percent
of
the
labeled
concentration.
Show
this
by
measuring
quarterly
with
a
precision
of
±
2
percent
(
two
standard
deviations)
or
by
using
another
method
we
approve.
You
may
take
multiple
measurements.
If
the
true
concentration
of
the
gas
changes
by
more
than
two
percent,
but
less
than
ten
percent,
you
may
relabel
the
gas
with
the
new
concentration.
(
4)
You
may
generate
calibration
and
span
gases
using
precision
blending
devices
(
gas
dividers)
to
dilute
gases
with
purified
nitrogen
or
with
purified
synthetic
air.
Make
sure
the
mixing
device
produces
a
concentration
of
blended
calibration
gases
that
is
accurate
to
within
±
1.5
percent.
To
do
so,
you
must
know
the
concentration
of
primary
gases
used
for
blending
to
an
accuracy
of
at
least
±
1
percent,
traceable
to
NIST
gas
standards
or
other
gas
standards
we
have
approved.
For
each
calibration
incorporating
a
blending
device,
verify
the
blending
accuracy
between
15
and
50
percent
of
full
scale.
You
may
optionally
check
the
blending
device
with
an
instrument
that
is
linear
by
nature
(
for
example,
using
NO
gas
with
a
CLD).
Adjust
the
instrument's
span
value
with
the
span
gas
connected
directly
to
it.
Check
the
blending
device
at
the
used
settings
to
ensure
that
the
difference
between
nominal
values
and
measured
concentrations
at
each
point
stays
within
±
0.5
percent
of
the
nominal
value.
(
d)
Oxygen
interference
gases.
Gases
to
check
oxygen
interference
are
mixtures
of
oxygen,
nitrogen,
and
propane.
The
oxygen
concentration
must
be
20
22
percent
and
the
propane
concentration
must
be
50
90
percent
of
the
maximum
value
in
the
most
typically
used
FID
range.
Independently
measure
the
concentration
of
total
hydrocarbons
plus
impurities
by
chromatographic
analysis
or
by
dynamic
blending.
Subpart
D
Analyzer
and
Equipment
Calibrations
§
1065.301
Overview.
Calibrate
all
analyzers
and
equipment
at
least
annually,
but
make
the
actual
frequency
consistent
with
good
engineering
judgment.
We
may
establish
other
guidelines
as
appropriate.
Calibrate
following
specifications
in
one
of
three
sources:
(
a)
Recommendations
from
the
manufacturer
of
the
analyzers
or
equipment.
(
b)
40
CFR
part
86,
subpart
F
or
subpart
N.
(
c)
40
CFR
part
90,
subparts
D
and
E,
as
applicable.
§
1065.305
International
calibration
standards.
(
a)
You
may
ask
to
use
international
standards
for
calibration.
(
b)
You
need
not
ask
for
approval
to
use
standards
that
have
been
shown
to
be
traceable
to
NIST
standards.
§
1065.310
CVS
calibration.
[
Reserved]
§
1065.315
Torque
calibration.
You
must
use
one
of
two
techniques
to
calibrate
torque:
the
lever
arm
deadweight
or
the
transfer
technique.
You
may
use
other
techniques
if
you
show
they
are
equally
accurate.
The
NIST
``
true
value''
torque
is
defined
as
the
torque
calculated
by
taking
the
product
of
an
NIST
traceable
weight
or
force
and
a
sufficiently
accurate
horizontal
distance
along
a
lever
arm,
corrected
for
the
lever
arm's
hanging
torque.
(
a)
The
lever
arm
dead
weight
technique
involves
placing
known
weights
at
a
known
horizontal
distance
from
the
torque
measuring
device's
center
of
rotation.
You
need
two
types
of
equipment:
(
1)
Calibration
weights.
This
technique
requires
at
least
six
calibration
weights
for
each
range
of
torque
measuring
device
used.
Equally
space
the
weights
and
make
sure
each
one
is
traceable
to
NIST
weights.
You
also
may
use
weights
certified
by
a
U.
S.
state
government's
bureau
of
weights
and
measures.
If
your
laboratory
is
outside
the
U.
S.,
see
§
1065.305
for
information
about
using
non
NIST
standards.
You
may
account
for
effects
of
changes
in
gravitational
constant
at
the
test
site.
(
2)
Lever
arm.
This
technique
also
requires
a
lever
arm
at
least
20
inches
long.
Make
sure
the
horizontal
distance
from
the
torque
measurement
device's
centerline
to
the
point
where
you
apply
the
weight
is
accurate
to
within
±
0.10
inches.
You
must
balance
the
arm
or
know
its
hanging
torque
to
within
±
0.1
ft
lbs.
(
b)
The
transfer
technique
involves
calibrating
a
master
load
cell
(
dynamometer
case
load
cell).
You
may
calibrate
the
master
load
cell
with
known
calibration
weights
at
known
horizontal
distances.
Or
you
may
use
a
hydraulically
actuated,
precalibrated,
master
load
cell
and
then
transfer
this
calibration
to
the
device
that
measures
the
flywheel
torque.
The
transfer
technique
involves
three
main
steps:
(
1)
Precalibrate
a
master
load
cell
or
calibrate
it
following
paragraph
(
a)(
1)
of
this
section.
Use
known
weights
traceable
to
NIST
with
the
lever
arms
specified
in
paragraph
(
b)(
2)
of
this
section.
Run
or
vibrate
the
dynamometer
during
this
calibration
to
reduce
static
hysteresis.
(
2)
Use
lever
arms
at
least
20
inches
long.
The
horizontal
distances
from
the
master
load
cell's
centerline
to
the
dynamometer's
centerline
and
to
the
point
where
you
apply
weight
or
force
must
be
accurate
to
within
±
0.10
inches.
Balance
the
arms
or
know
their
net
hanging
torque
to
within
±
0.1
ft
lbs.
(
3)
Transfer
calibration
from
the
case
or
master
load
cell
to
the
torquemeasuring
device
with
the
dynamometer
operating
at
a
constant
speed.
Calibrate
the
torquemeasurement
device's
readout
to
the
master
load
cell's
torque
readout
at
a
minimum
of
six
loads
spaced
about
equally
across
the
full
useful
ranges
of
both
measurement
devices.
(
Good
engineering
practice
requires
that
both
devices
have
about
the
same
useful
ranges
of
torque
measurement.)
Transfer
the
calibration
so
it
meets
the
accuracy
requirements
in
§
1065.105(
a)(
2)
for
readouts
from
the
torque
measurement
device.
Subpart
E
Engine
Selection,
Preparation,
and
Service
Accumulation
§
1065.401
Selecting
a
test
engine.
While
all
engine
configurations
within
a
certified
engine
family
must
comply
with
the
applicable
standards
in
the
standard
setting
part,
you
are
not
required
to
test
each
configuration
for
certification.
(
a)
Select
for
testing
according
to
the
following
guidance
the
engine
configuration
within
the
engine
family
that
is
most
likely
to
exceed
an
emission
standard:
(
1)
Test
the
engine
that
we
specify,
whether
we
do
this
through
general
guidance
or
give
you
specific
instructions.
(
2)
If
we
do
not
tell
you
which
engine
to
test,
follow
any
instructions
in
the
standard
setting
part.
(
3)
If
we
do
not
tell
you
which
engine
to
test
and
the
standard
setting
part
does
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/
Rules
and
Regulations
not
include
specifications
for
selecting
test
engines,
use
good
engineering
judgment
to
select
the
engine
configuration
within
the
engine
family
that
is
most
likely
to
exceed
an
emission
standard.
(
b)
In
the
absence
of
other
information,
the
following
characteristics
are
appropriate
to
consider
when
selecting
the
engine
to
test:
(
1)
Maximum
fueling
rates.
(
2)
Maximum
in
use
engine
speed
(
governed
or
ungoverned,
as
applicable).
(
3)
Highest
sales
volume.
(
c)
We
may
select
any
engine
configuration
within
the
engine
family
for
our
testing.
§
1065.405
Preparing
and
servicing
a
test
engine.
(
a)
If
you
are
testing
an
emission
data
engine
for
certification,
make
sure
you
have
built
it
to
represent
production
engines.
(
b)
Run
the
test
engine,
with
all
emission
control
systems
operating,
long
enough
to
stabilize
emission
levels.
If
you
accumulate
50
hours
of
operation,
you
may
consider
emission
levels
stable
without
measurement.
(
c)
Do
not
service
the
test
engine
before
you
stabilize
emission
levels,
unless
we
approve
other
maintenance
in
advance.
This
prohibition
does
not
apply
to
your
recommended
oil
and
filter
changes
for
newly
produced
engines,
or
to
idle
speed
adjustments.
(
d)
Select
engine
operation
for
accumulating
operating
hours
on
your
test
engines
to
represent
normal
in
use
operation
for
the
engine
family.
(
e)
If
you
need
more
than
50
hours
to
stabilize
emission
levels,
record
your
reasons
and
the
method
you
use
to
do
this.
Give
us
these
records
if
we
ask
for
them.
§
1065.410
Service
limits
for
stabilized
test
engines.
(
a)
After
you
stabilize
the
test
engine's
emission
levels,
you
may
do
scheduled
maintenance,
other
than
during
emission
testing,
as
the
standard
setting
part
specifies.
(
b)
You
may
not
do
any
unscheduled
maintenance
to
the
test
engine
or
its
emission
control
system
or
fuel
system
without
our
advance
approval.
Unscheduled
maintenance
includes
adjusting,
repairing,
removing,
disassembling,
cleaning,
or
replacing
the
test
engine.
We
may
approve
routine
maintenance
that
is
not
scheduled
such
as
maintaining
the
proper
oil
level.
(
1)
We
may
approve
other
unscheduled
maintenance
if
all
of
the
following
occur:
(
i)
You
determine
that
a
part
failure
or
system
malfunction
(
or
the
associated
repair)
does
not
make
the
engine
unrepresentative
of
production
engines
in
the
field
and
does
not
require
anyone
to
access
the
combustion
chamber.
(
ii)
Something
clearly
malfunctions
(
such
as
persistent
misfire,
engine
stall,
overheating,
fluid
leakage,
or
loss
of
oil
pressure)
and
needs
maintenance
or
repair.
(
iii)
You
give
us
a
chance
to
verify
the
extent
of
the
malfunction
before
you
do
the
maintenance.
(
2)
If
we
determine
that
a
part's
failure
or
a
system's
malfunction
(
or
the
associated
repair)
has
made
the
engine
unrepresentative
of
production
engines,
you
may
no
longer
use
it
as
a
test
engine.
(
3)
You
may
not
do
unscheduled
maintenance
based
on
emission
measurements
from
the
test
engine.
(
4)
Unless
we
approve
otherwise
in
advance,
you
may
not
use
equipment,
instruments,
or
tools
to
identify
bad
engine
components
unless
you
specify
they
should
be
used
for
scheduled
maintenance
on
production
engines.
In
this
case,
if
they
are
not
generally
available,
you
must
also
make
them
available
at
dealerships
and
other
service
outlets.
(
c)
If
you
do
maintenance
that
might
affect
emissions,
you
must
completely
test
the
engine
for
emissions
before
and
after
the
maintenance,
unless
we
waive
this
requirement.
(
d)
If
your
test
engine
has
a
major
mechanical
failure
that
requires
you
to
take
it
apart,
you
may
no
longer
use
it
as
a
test
engine.
§
1065.415
Durability
demonstration.
If
the
standard
setting
part
requires
durability
testing,
you
must
accumulate
service
in
a
way
that
represents
how
you
expect
the
engine
to
operate
in
use.
You
may
accumulate
service
hours
using
an
accelerated
schedule,
such
as
through
continuous
operation.
(
a)
Maintenance.
The
following
limits
apply
to
the
maintenance
that
we
allow
you
to
do
on
test
engine:
(
1)
You
may
perform
scheduled
maintenance
that
you
recommend
to
operators,
but
only
if
it
is
consistent
with
the
standard
setting
part's
restrictions.
(
2)
You
may
perform
additional
maintenance
only
if
we
approve
it
in
advance,
as
specified
in
§
1065.410(
b).
(
3)
If
your
test
engine
has
a
major
mechanical
failure
that
requires
you
to
take
it
apart,
you
may
no
longer
use
it
as
a
test
engine.
(
b)
Emission
measurements.
You
must
measure
emissions
following
two
main
requirements:
(
1)
Perform
emission
tests
to
determine
deterioration
factors
consistent
with
good
engineering
judgment.
Evenly
space
any
tests
between
the
first
and
last
test
points
throughout
the
durability
period.
(
2)
Perform
emission
tests
following
the
provisions
of
this
part
and
the
standard
setting
part.
Subpart
F
Running
an
Emission
Test
§
1065.501
Overview
of
the
engine
dynamometer
test
procedures.
(
a)
The
engine
dynamometer
test
procedure
measures
brake
specific
emissions
of
hydrocarbons
(
total
and
nonmethane,
as
applicable),
carbon
monoxide,
and
oxides
of
nitrogen.
To
perform
this
test
procedure,
you
first
dilute
exhaust
emissions
with
ambient
air
and
collect
a
continuous
proportional
sample
for
analysis,
then
analyze
the
composite
samples
(
either
in
bags
after
the
test
or
continuously
during
the
test).
The
general
test
procedure
consists
of
a
test
cycle
made
of
one
or
more
segments
(
check
the
standard
setting
part
for
specific
cycles):
(
1)
Either
a
cold
start
cycle
(
where
you
measure
emissions)
or
a
warm
up
cycle
(
where
you
do
not
measure
emissions).
(
2)
A
hot
start
transient
test
(
some
test
cycles
may
omit
engine
starting
from
the
``
hot
start''
cycle).
(
3)
A
steady
state
test.
(
b)
Measure
power
using
the
dynamometer's
feedback
signals
for
torque
and
speed.
The
power
measurement
produces
a
brake
kilowatthour
value
that
allows
you
to
calculate
brake
specific
emissions
(
see
Subpart
G
of
this
part).
(
c)
Prepare
engines
for
testing
consistent
with
§
1065.10(
c)(
1)
and
according
to
the
following
provisions:
(
1)
When
you
test
an
engine
or
operate
it
for
service
accumulation,
use
the
complete
engine
with
all
emissioncontrol
devices
installed
and
functioning.
(
2)
Install
the
fan
for
any
air
cooled
engine
(
if
applicable).
(
3)
You
may
install
accessories
such
as
an
oil
cooler,
alternators,
and
air
compressors
or
simulate
their
loading
if
they
are
typical
of
in
use
operation.
Apply
this
loading
during
all
testing
operations,
including
mapping.
(
4)
You
may
install
a
production
type
starter
on
the
engine.
(
5)
Cool
the
engine
in
a
way
that
will
maintain
its
operating
temperatures
including
the
intake
air,
oil,
water
temperatures
about
the
same
as
they
would
be
during
normal
operation.
You
may
use
auxiliary
fans
if
necessary.
You
may
use
rust
inhibitors
and
lubrication
additives,
up
to
the
levels
that
the
additive
manufacturer
recommends.
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Vol.
67,
No.
217
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Friday,
November
8,
2002
/
Rules
and
Regulations
You
may
also
use
antifreeze
mixtures
and
other
coolants
typical
of
those
approved
for
use
by
the
manufacturer.
(
6)
Use
representative
exhaust
and
airintake
systems.
Make
sure
the
exhaust
restriction
is
80
to
100
percent
of
the
recommended
maximum
specified
exhaust
restriction
and
the
air
inlet
restriction
is
between
that
of
a
clean
filter
and
the
maximum
restriction
specification.
As
the
manufacturer,
you
are
liable
for
emission
compliance
from
the
minimum
in
use
restrictions
to
the
maximum
restrictions
you
specify
for
that
particular
engine.
§
1065.510
Engine
mapping
procedures.
(
a)
Torque
map.
Map
your
engine's
torque
while
it
is
mounted
on
the
dynamometer.
Use
the
torque
curve
resulting
from
the
mapping
to
convert
the
normalized
torque
values
in
the
engine
cycle
to
actual
torque
values
for
the
test
cycle.
Make
sure
the
speed
ranges
at
least
from
the
warm
no
load
idle
speed
to
105
percent
of
the
maximum
test
speed.
Because
you
determine
the
maximum
test
speed
from
the
torque
map,
you
may
have
to
perform
a
preliminary
torque
map
to
determine
the
full
mapping
range.
You
may
perform
this
preliminary
torque
map
while
the
engine
warms
up.
To
map
the
engine,
do
the
following
things
in
sequence:
(
1)
Warm
up
the
engine
so
oil
and
water
temperatures
(
on
an
absolute
scale
such
as
the
Kelvin
scale)
vary
by
less
than
two
percent
for
two
minutes;
or
until
the
thermostat
opens
if
the
enginecoolant
system
includes
a
thermostat.
(
2)
Operate
the
engine
at
the
warm
noload
idle
speed.
(
3)
Fully
open
the
throttle.
(
4)
While
maintaining
wide
open
throttle
and
full
load,
keep
the
engine
at
minimum
speed
for
at
least
15
seconds.
Record
the
average
torque
during
the
last
5
seconds.
(
5)
In
increments
of
100
±
20
rpm,
determine
the
maximum
torque
curve
for
the
full
speed
range.
Hold
each
test
point
for
15
seconds
and
record
the
average
torque
over
the
last
5
seconds.
You
may
use
larger
increments
for
engines
with
maximum
test
speed
over
4000
rpm,
as
long
as
you
include
at
least
40
points
and
space
them
evenly.
(
6)
Fit
all
data
points
recorded
with
a
cubic
spline,
Akima,
or
other
technique
we
approve
in
advance.
The
resultant
curve
must
be
accurate
to
within
±
1.0
ftlbs
of
all
recorded
engine
torques.
(
b)
Torque
map
with
continual
engine
speed
sweep.
In
place
of
paragraphs
(
a)(
1)
through
(
a)(
4)
of
this
section,
you
may
do
a
continual
sweep
of
engine
speed.
While
operating
at
wide
open
throttle,
increase
the
engine
speed
at
an
average
rate
of
8
±
1
rpm/
sec
over
the
full
speed
range.
You
may
use
higher
sweeping
rates
for
naturally
aspirated
engines,
in
accordance
with
good
engineering
judgment.
Record
speed
and
torque
points
at
a
rate
of
at
least
one
point
per
second.
Connect
all
points
generated
under
this
approach
by
linear
interpolation.
(
c)
Alternate
mapping.
You
may
use
other
mapping
techniques
if
you
believe
those
in
paragraphs
(
a)
and
(
b)
of
this
section
are
unsafe
or
unrepresentative
for
any
engine
or
engine
family.
These
alternate
techniques
must
satisfy
the
intent
of
the
specified
mapping
procedures
to
determine
the
maximum
available
torque
at
all
engine
speeds
that
occur
during
the
test
cycles.
Report
deviations
from
this
section's
mapping
techniques
for
reasons
of
safety
or
representativeness.
In
no
case,
however,
may
you
use
descending
continual
sweeps
of
engine
speed
for
governed
or
turbocharged
engines.
(
d)
Replicate
tests.
You
need
not
map
an
engine
before
every
test,
but
you
do
need
to
remap
the
engine
in
any
of
the
following
situations:
(
1)
Good
engineering
judgment
determines
that
an
unreasonable
amount
of
time
has
passed
since
the
last
map.
(
2)
The
barometric
pressure
before
the
test
begins
has
changed
more
than
25
mm
Hg
from
the
average
barometric
pressure
observed
during
the
map.
(
3)
The
engine
has
undergone
physical
changes
or
recalibration
that
might
affect
its
performance.
(
e)
Power
map.
Where
applicable,
generate
a
power
map
using
the
procedures
this
section
specifies
for
torque
maps.
You
may
generate
the
power
map
directly
or
convert
the
torque
map
to
a
power
map
using
engine
speeds.
The
power
map
is
also
called
a
lug
curve.
(
f)
Cycles
based
only
on
torque/
power
at
maximum
test
speed.
If
the
applicable
test
cycle
for
your
engine
does
not
require
map
information
for
engine
speeds
other
than
the
maximum
test
speed,
you
may
make
the
following
simplifications:
(
1)
You
need
not
perform
the
entire
torque
or
power
map,
as
long
as
you
map
the
engines
for
speeds
between
75
and
105
percent
of
the
maximum
test
speed.
(
2)
You
need
not
remap
an
engine
according
to
paragraph
(
d)
of
this
section.
You
need
only
verify
the
maximum
torque
or
power
at
maximum
test
speed.
§
1065.515
Test
cycle
generation.
(
a)
Denormalizing
test
cycles.
The
standard
setting
parts
establish
the
applicable
test
cycles
consisting
of
second
by
second
specifications
for
normalized
torque
and
speed
for
transient
cycles,
or
modal
specifications
for
normalized
torque
and
speed
(
or
power
and
speed)
for
steady
state
cycles.
You
must
denormalize
these
values
to
get
actual
torque
and
speed
for
your
engine.
(
1)
Torque
is
normalized
to
a
maximum
torque
value.
Check
the
standard
setting
part
to
see
if
it
is
normalized
based
on
the
maximum
torque
at
the
given
speed
or
based
on
the
maximum
torque
for
all
speeds.
To
denormalize
the
torque
values
in
the
cycle,
use
the
engine's
maximum
torque
point
or
its
torque
map
(
§
1065.510
describes
how
to
generate
the
torque
map).
(
2)
Power
is
normalized
to
a
maximum
power
value.
Check
the
standard
setting
part
to
see
if
it
is
normalized
based
on
the
maximum
power
at
the
given
speed
or
based
on
the
maximum
power
for
all
speeds.
To
denormalize
the
power
values
in
the
cycle,
use
the
engine's
maximum
power
point
or
its
power
map
(
§
1065.510
describes
how
to
generate
the
power
map).
(
3)
To
denormalize
speed,
use
the
following
equation:
Actual
engine
speed
=
(
0.01)
×
(%
engine
speed)
×
(
Maximum
test
speed
warm
idle
speed)
+
warm
idle
speed
(
4)
Paragraph
(
d)
of
this
section
describes
how
to
calculate
maximum
test
speed.
(
b)
Example
of
denormalizing
a
test
points.
For
an
engine
with
maximum
test
speed
of
3800
rpm
and
warm
idle
speed
of
600
rpm,
denormalize
the
following
test
point:
percent
engine
speed
=
43,
percent
torque
=
82.
(
1)
Calculate
actual
engine
speed.
The
following
equation
applies
for
this
example:
Actual
engine
speed
=
(
0.01)
×
(
43)
×
(
3800
¥
600)
+
600
=
1976
rpm.
(
2)
Determine
actual
torque.
Determine
the
maximum
observed
torque
at
1976
rpm
from
the
maximum
torque
curve.
Then
multiply
this
value
(
for
example,
358
ft
lbs.)
by
0.82.
The
resulting
actual
torque
is
294
ft
lbs.
(
c)
Cold
start
enhancement
devices.
If
an
engine
has
a
properly
operating
automatic
enhancement
device
for
cold
starts,
let
it
override
the
zero
percent
speed
specified
in
the
test
cycles.
(
d)
Maximum
test
speed.
For
constant
speed
engines,
maximum
test
speed
is
the
same
as
the
engine's
maximum
operating
speed
in
use.
Maximum
test
speed
for
variable
speed
engines
occurs
on
the
lug
curve
at
the
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/
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67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
point
farthest
from
the
origin
on
a
plot
of
power
vs.
speed.
To
find
this
speed,
follow
three
main
steps:
(
1)
Generate
the
lug
curve.
Before
testing
an
engine
for
emissions,
generate
data
points
for
maximum
measured
brake
power
with
varying
engine
speed
(
see
§
1065.510).
These
data
points
form
the
lug
curve.
(
2)
Normalize
the
lug
curve.
To
normalize
the
lug
curve,
do
three
things:
(
i)
Identify
the
point
(
power
and
speed)
on
the
lug
curve
where
maximum
power
occurs.
(
ii)
Normalize
the
power
values
of
the
lug
curve
divide
them
by
the
maximum
power
and
multiply
the
resulting
values
by
100.
(
iii)
Normalize
the
engine
speed
values
of
the
lug
curve
divide
them
by
the
speed
at
which
maximum
power
occurs
and
multiply
the
resulting
values
by
100.
(
3)
Determine
maximum
test
speed.
Calculate
the
maximum
test
speed
from
the
following
speed
factor
analysis:
(
i)
For
a
given
power
speed
point,
the
speed
factor
is
the
normalized
distance
to
the
power
speed
point
from
the
zeropower
zero
speed
point.
Compute
the
speed
factor's
value:
Speed
factor
=
(
power)
(
speed)
2
2
+
(
ii)
Determine
the
maximum
value
of
speed
factors
for
all
the
power
speed
data
points
on
the
lug
curve.
Maximum
test
speed
is
the
speed
at
which
the
speed
factor's
maximum
value
occurs.
Note
that
this
maximum
test
speed
is
the
100
percent
speed
point
for
normalized
transient
duty
cycles.
(
e)
Intermediate
test
speed.
Determine
intermediate
test
speed
with
the
following
provisions:
(
1)
If
peak
torque
speed
is
60
to
75
percent
of
the
maximum
test
speed,
the
intermediate
speed
point
is
at
that
same
speed.
(
2)
If
peak
torque
speed
is
less
than
60
percent
of
the
maximum
test
speed,
the
intermediate
speed
point
is
at
60
percent
of
maximum
test
speed.
(
3)
If
peak
torque
speed
is
greater
than
75
percent
of
the
maximum
test
speed,
the
intermediate
speed
point
is
at
75
percent
of
maximum
test
speed.
§
1065.520
Engine
starting,
restarting,
and
shutdown.
Unless
the
standard
setting
part
specifies
otherwise,
follow
the
steps
in
this
section
to
start
and
shut
down
the
test
engine:
(
a)
Engine
starting.
Start
the
engine
according
to
the
manufacturer's
recommended
starting
procedure
in
the
owner's
manual,
using
either
a
production
starter
motor
or
the
dynamometer.
Use
the
dynamometer
to
crank
(
or
motor)
the
engine
at
the
typical
in
use
cranking
speed
with
a
fully
charged
battery
(
nominal
speed
±
10
percent),
accelerating
the
engine
to
cranking
speed
in
the
same
time
it
would
take
with
a
starter
motor
(
nominal
±
0.5
seconds).
Stop
motoring
by
the
dynamometer
within
one
second
of
starting
the
engine.
The
cycle's
freeidle
period
begins
when
you
determine
that
the
engine
has
started.
(
1)
If
the
engine
does
not
start
after
15
seconds
of
cranking,
stop
cranking
and
determine
the
reason
it
failed
to
start.
While
diagnosing
the
problem,
turn
off
the
device
that
measures
gas
flow
(
or
revolution
counter)
on
the
constantvolume
sampler
(
and
all
integrators
when
measuring
emissions
continuously).
Also,
turn
off
the
constant
volume
sampler
or
disconnect
the
exhaust
tube
from
the
tailpipe.
If
failure
to
start
is
an
operational
error,
reschedule
the
engine
for
testing
(
this
may
require
soaking
the
engine
if
the
test
requires
a
cold
start).
(
2)
If
longer
cranking
times
are
necessary,
you
may
use
them
instead
of
the
15
second
limit,
as
long
as
the
owner's
manual
and
the
service
repair
manual
describe
the
longer
cranking
times
as
normal.
(
3)
If
an
engine
malfunction
causes
a
failure
to
start,
you
may
correct
it
in
less
than
30
minutes
and
continue
the
test.
Reactivate
the
sampling
system
at
the
same
time
cranking
begins.
When
the
engine
starts,
begin
the
timing
sequence.
If
an
engine
malfunction
causes
a
failure
to
start,
and
you
cannot
restart
the
engine,
the
test
is
void.
(
b)
Engine
stalling.
Respond
to
engine
stalling
as
follows:
(
1)
If
the
engine
stalls
during
the
warm
up
period,
the
initial
idle
period
of
test,
or
the
steady
state
segment,
you
may
restart
the
engine
immediately
using
the
appropriate
starting
procedure
and
continue
the
test.
(
2)
If
the
engine
stalls
at
any
other
time,
the
test
is
void.
(
c)
Engine
shutdown.
Shut
the
engine
down
according
to
the
manufacturer's
specifications.
§
1065.525
Engine
dynamometer
test
run.
Take
the
following
steps
for
each
test:
(
a)
Prepare
the
engine,
dynamometer,
and
sampling
system.
Change
filters
or
other
replaceable
items
and
check
for
leaks
as
necessary.
(
b)
If
you
are
using
bag
samples,
connect
evacuated
sample
collection
bags
to
the
collection
system
for
the
dilute
exhaust
and
dilution
air
sample.
(
c)
Attach
the
CVS
to
the
engine's
exhaust
system
any
time
before
starting
the
CVS.
(
d)
Start
the
CVS
(
if
not
already
started),
the
sample
pumps,
the
engine
cooling
fans,
and
the
data
collection
system.
Before
the
test
begins,
preheat
the
CVS's
heat
exchanger
(
if
used)
and
the
heated
components
of
any
continuous
sampling
systems
to
designated
operating
temperatures.
(
e)
Adjust
the
sample
flow
rates
to
the
desired
levels
and
set
to
zero
the
devices
in
the
CVS
that
measure
gas
flow.
The
venturi
design
fixes
the
sample
flow
rate
in
a
CFV
CVS.
(
f)
Start
the
engine
if
engine
starting
is
not
part
of
the
test
cycle,
as
specified
in
the
standard
setting
part.
(
g)
Run
the
test
cycle
specified
in
the
standard
setting
part
and
collect
the
test
data.
(
h)
As
soon
as
practical
after
the
test
cycle
is
complete,
analyze
the
bag
samples.
§
1065.530
Test
cycle
validation
criteria.
(
a)
Steady
state
emission
testing.
Make
sure
your
engine's
speeds
and
loads
stay
within
±
2
percent
of
the
set
point
during
the
sampling
period.
(
b)
Transient
emission
testing
performed
by
EPA.
Emission
tests
must
meet
the
specifications
of
this
paragraph
(
b).
Otherwise,
they
do
not
comply
with
the
test
cycle
requirements
of
the
standard
setting
part,
unless
we
determine
the
cause
of
the
failure
to
meet
these
specifications
is
related
to
the
engine
rather
than
the
test
equipment.
(
1)
Shifting
feedback
signals.
The
time
lag
between
the
feedback
and
referencecycle
values
may
bias
results.
To
reduce
this
effect,
you
may
advance
or
delay
the
entire
sequence
of
engine
speed
and
torque
feedback
signals
with
respect
to
the
reference
sequence
for
speed
and
torque.
If
you
shift
the
feedback
signals,
you
must
shift
speed
and
torque
the
same
amount
in
the
same
direction.
(
2)
Calculating
brake
kilowatt
hour
emissions.
Calculate
brake
kilowatt
hour
emissions
for
each
pair
of
feedback
values
recorded
for
engine
speed
and
torque.
Also
calculate
the
reference
brake
kilowatt
hour
for
each
pair
of
reference
values
for
engine
speed
and
torque.
Calculate
to
five
significant
figures.
(
3)
Performing
regression
line
analysis.
Perform
regression
analysis
to
calculate
validation
statistics
as
follows:
(
i)
Perform
linear
regressions
of
feedback
value
on
reference
value
for
speed,
torque,
and
brake
power
on
1
Hz
data
after
the
feedback
shift
has
occurred
(
see
paragraph
(
b)(
1)
of
this
section).
Use
the
method
of
least
squares,
with
the
best
fit
equation
having
the
form:
y
=
mx
+
b
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MATH>
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Federal
Register
/
Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
Where:
y
=
The
feedback
(
actual)
value
of
speed
(
rpm),
torque
(
ft
lbs.),
or
brake
power.
m
=
Slope
of
the
regression
line.
x
=
The
reference
value
(
speed,
torque,
or
brake
power).
b
=
The
y
intercept
of
the
regression
line.
(
ii)
Calculate
the
standard
error
of
estimate
(
SE)
of
y
on
x
and
the
coefficient
of
determination
(
r2)
for
each
regression
line.
(
iii)
For
a
valid
test,
make
sure
the
feedback
cycle's
integrated
brake
kilowatt
hour
is
within
5
percent
of
the
reference
cycle's
integrated
brake
kilowatt
hour.
Also,
ensure
that
the
slope,
intercept,
standard
error,
and
coefficient
of
determination
meet
the
criteria
in
the
following
table
(
you
may
delete
individual
points
from
the
regression
analyses,
consistent
with
good
engineering
judgment):
TABLE
1
OF
§
1065.530.
STATISTICAL
CRITERIA
FOR
VALIDATING
TEST
CYCLES
Speed
Torque
Power
1.
Slope
of
the
regression
line
(
m)
0.980
to
1.020
..............................
0.880
to
1.030
..............................
0.880
to
1.030.
2.
Y
intercept
of
the
regression
line
(
b).
b
40
rpm
.................................
b
5.0
percent
of
maximum
torque
from
power
map.
b
3.0
percent
of
maximum
torque
from
power
map.
3.
Standard
error
of
the
estimate
of
Y
on
X
(
SE).
100
rpm
........................................
15
percent
of
maximum
torque
from
power
map.
10
percent
of
maximum
power
from
power
map.
4.
Coefficient
of
determination
(
r2)
r2
0.970
......................................
r2
0.900
......................................
r2
0.900.
(
c)
Transient
testing
performed
by
manufacturers.
Emission
tests
that
meet
the
specifications
of
paragraph
(
b)
of
this
section
satisfy
the
standard
setting
part's
requirements
for
test
cycles.
You
may
ask
to
use
a
dynamometer
that
cannot
meet
those
specifications,
consistent
with
good
engineering
practice.
We
will
approve
your
request
as
long
as
using
the
alternate
dynamometer
does
not
affect
your
ability
to
show
that
you
comply
with
all
applicable
emission
standards.
Subpart
G
Data
Analysis
and
Calculations
§
1065.601
Overview.
This
subpart
describes
how
to
use
the
responses
on
the
analyzers
and
other
meters
to
calculate
final
gram
per
kilowatt
hour
emission
rates.
Note:
Volume
and
density
values
used
in
these
calculations
are
generally
corrected
to
standard
conditions
of
20
°
C
and
101.3
kPa.)
§
1065.605
Required
records.
Retain
the
following
information
for
each
test:
(
a)
Test
number.
(
b)
System
or
device
tested
(
brief
description).
(
c)
Date
and
time
of
day
for
each
part
of
the
test
schedule.
(
d)
Test
results.
(
e)
Operator's
name.
(
f)
Engine:
ID
number,
manufacturer,
model
year,
emission
standards,
engine
family,
basic
engine
description,
fuel
system,
engine
code,
and
idle
speed,
as
applicable.
(
g)
Dynamometer:
Dynamometer
identification,
records
to
verify
compliance
with
the
duty
cycle
requirements
of
the
test.
(
h)
Gas
analyzers:
Analyzer
bench
identification,
analyzer
ranges,
recordings
of
analyzer
output
during
zero,
span,
and
sample
readings.
(
i)
Recorder
charts:
Test
number,
date,
identification,
operator's
name,
and
identification
of
the
measurements
recorded.
(
j)
Test
cell
barometric
pressure,
ambient
temperature,
and
humidity
as
required.
(
Some
test
systems
may
require
continuous
measurements;
others
may
require
a
single
measurement,
or
measurements
before
and
after
the
test.)
(
k)
Temperatures:
Records
to
verify
compliance
with
the
ambient
temperature
requirements
throughout
the
test
procedure.
(
l)
CFV
CVS:
Total
dilute
exhaust
volume
(
Vmix)
for
each
phase
of
the
exhaust
test.
(
m)
PDP
CVS:
Test
measurements
for
calculating
the
total
dilute
exhaust
volume
(
Vmix),
and
the
Vmix
for
each
phase
of
the
exhaust
test.
(
n)
The
humidity
of
the
dilution
air.
Note:
If
you
do
not
use
conditioning
columns,
this
measurement
is
not
necessary.
If
you
use
conditioning
columns
and
take
the
dilution
air
from
the
test
cell,
you
may
use
the
ambient
humidity
for
this
measurement.
§
1065.610
Bag
sample
analysis.
(
a)
Zero
the
analyzers
and
obtain
a
stable
zero
reading.
Recheck
after
tests.
(
b)
Introduce
span
gases
and
set
instrument
gains.
To
avoid
errors,
span
and
calibrate
at
the
same
flow
rates
used
to
analyze
the
test
sample.
Span
gases
should
have
concentrations
equal
to
75
to
100
percent
of
full
scale.
If
gain
has
shifted
significantly
on
the
analyzers,
check
the
calibrations.
Show
actual
concentrations
on
the
chart.
(
c)
Check
zeroes;
if
necessary,
repeat
the
procedure
in
paragraphs
(
a)
and
(
b)
of
this
section.
(
d)
Check
flow
rates
and
pressures.
(
e)
Measure
HC,
CO,
CO2,
and
NOX
concentrations
of
samples.
(
f)
Check
zero
and
span
points.
If
the
difference
is
greater
than
2
percent
of
full
scale,
repeat
the
procedure
in
paragraphs
(
a)
through
(
e)
of
this
section.
§
1065.615
Bag
sample
calculations.
(
a)
Calculate
the
dilution
factor.
The
dilution
factor
is
the
ratio
of
the
total
volume
of
the
raw
exhaust
to
the
total
volume
of
the
diluted
exhaust.
It
is
calculated
as
134,000
divided
by
the
sum
of
the
diluted
ppmC
concentrations
of
carbon
containing
compounds
in
the
exhaust,
as
follows:
DF
=
134,000/
(
CO2sample+
THCsample+
COsample),
Where:
CO2sample
and
COsample
are
expressed
as
ppm,
and
THCsample
is
expressed
as
ppmC.
(
b)
Calculate
mass
emission
rates
(
g/
test)
for
the
transient
segment
using
the
general
equation
in
paragraph
(
b)(
1)
of
this
section:
(
1)
The
general
equation
is:
Emission
rate
=
(
total
dilute
exhaust
flow
volume)(
ppm)(
density
factor)/
106
Mx
=
(
Vmix)(
Ci)(
fdi)/
106
Where:
Mx
=
Mass
emission
rate
in
g/
test
segment.
Vmix
=
Total
dilute
exhaust
flow
volume
flow
in
m3
per
test
segment
corrected
to
20
°
C
and
101.3
kPa.
Ci
=
The
concentration
of
species
i,
in
ppm
or
ppmC,
corrected
for
background
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Rules
and
Regulations
contribution
according
to
the
equation
in
paragraph
(
b)(
2)
of
this
section.
fdi
=
The
density
factor
for
species
i.
The
density
factors
are
576.8
g/
m3
for
THC,
1913
g/
m3
for
NOX,
and
1164
g/
m3
for
CO.
(
2)
The
equation
to
calculate
Ci
is:
Ci
=
Csample
Cbackground
[
1
(
1/
DF)]
Where:
Csample
=
Concentration
of
species
i
in
the
diluted
exhaust
sample,
in
ppm
or
ppmC.
Cbackground
=
Concentration
of
species
i
in
the
dilution
air
background
sample,
in
ppm
or
ppmC.
DF
=
Dilution
factor,
as
calculated
in
paragraph
(
a)
of
this
section.
(
c)
Calculate
total
brake
work
(
kW
hr)
done
during
the
emissions
sampling
period
of
each
segment
or
mode.
(
d)
Calculate
emissions
in
g/
kW
hr
by
dividing
the
mass
emission
rate
(
g/
test
segment)
by
the
total
brake
work
for
the
test
segment.
(
e)
Apply
deterioration
factors
or
other
adjustment
factors
to
the
brakespecific
emission
rate
in
paragraph
(
e)
as
specified
in
the
standard
setting
part.
Subpart
H
Particulate
Measurements
[
Reserved]
Subpart
I
Testing
With
Oxygenated
Fuels
§
1065.801
Applicability.
(
a)
This
subpart
applies
for
testing
with
oxygenated
fuels.
Except
where
specified
otherwise
in
the
standardsetting
part,
compliance
with
this
subpart
is
not
required
for
fuels
that
contain
less
than
25
percent
oxygenated
compounds
by
volume.
For
example,
you
generally
would
not
need
to
follow
the
requirements
of
this
subpart
for
tests
performed
using
a
fuel
that
was
10
percent
ethanol
and
90
percent
gasoline,
but
you
would
need
to
follow
these
requirements
for
tests
performed
using
a
fuel
that
was
85
percent
ethanol
and
15
percent
gasoline.
(
b)
This
subpart
specifies
sampling
procedures
and
calculations
that
are
different
than
those
used
for
nonoxygenated
fuels.
The
other
test
procedures
of
this
part
apply
for
testing
with
oxygenated
fuels.
§
1065.805
Sampling
system.
(
a)
Use
the
sampling
procedures
specified
in
40
CFR
part
86
for
methanol
and
formaldehyde
to
measure
alcohols
and
aldehydes
in
the
exhaust.
This
requires
the
following:
(
1)
Bubbling
a
sample
of
the
exhaust
through
water
to
collect
the
alcohols.
(
2)
Passing
a
sample
of
the
exhaust
through
cartridges
impregnated
with
2,4
dinitrophenylhydrazine
to
measure
aldehydes.
(
b)
Use
good
engineering
judgment
to
measure
other
oxygenated
compounds
in
the
exhaust.
§
1065.810
Calculations.
(
a)
THCE
emissions.
(
1)
Calculate
THCE
emissions
as
the
sum
of
the
mass
of
the
nonoxygenated
hydrocarbons
in
the
exhaust
and
the
carbon
equivalent
mass
of
each
measured
oxygenated
species
in
the
exhaust.
(
2)
Calculate
carbon
equivalent
mass
of
each
measured
oxygenated
species
from
the
following
equation:
Carbon
equivalent
=
13.8756
×
MOC/
MWPC
Where:
MOC
is
the
mass
of
the
oxygenated
compound
in
the
exhaust,
and
MWPC
is
the
molecular
weight
of
compound
per
carbon
atom
of
compound.
(
b)
NMHCE
emissions.
Calculate
NMHCE
emissions
as
either:
(
1)
The
sum
of
the
mass
of
the
nonoxygenated
nonmethane
hydrocarbons
in
the
exhaust
and
the
carbon
equivalent
mass
of
each
measured
oxygenated
species
in
the
exhaust.
(
2)
THCE
minus
the
mass
of
methane
in
the
exhaust.
(
c)
Sample
calculation.
(
1)
Assume
the
following
emissions
for
a
test:
40.00
grams
of
nonoxygenated
hydrocarbons,
100.00
grams
of
ethanol,
and
10.00
grams
of
acetaldehyde,
and
1.00
gram
of
formaldehyde.
(
2)
The
carbon
equivalent
of
the
masses
of
oxygenated
compounds
are:
(
i)
13.8756
×
100.00/(
46.068/
2)
=
60.24
grams
of
ethanol.
(
ii)
13.8756
×
10.00/(
44.052/
2)
=
6.30
grams
of
acetaldehyde.
(
iii)
13.8756
×
1.00/(
30.026)
=
0.46
grams
of
formaldehyde.
(
3)
THCE
=
40.00
+
60.24
+
6.30
+
0.46
=
107.00
grams
per
test.
Subpart
J
Field
Testing
§
1065.901
Applicability.
(
a)
The
test
procedures
in
this
subpart
measure
brake
specific
emissions
from
engines
while
they
remain
installed
in
vehicles
or
equipment
in
the
field.
(
b)
These
test
procedures
apply
to
your
engines
as
specified
in
the
standard
setting
part.
For
example,
part
1048
of
this
chapter
specifies
emission
standard
to
be
used
for
in
use
tests
conducted
in
accordance
with
the
provisions
of
this
part.
Unless
this
subpart
is
specifically
mentioned
in
the
standard
setting
part,
compliance
with
the
provisions
of
this
subpart
is
not
required.
§
1065.905
General
provisions.
(
a)
Unless
the
standard
setting
part
specifies
deviations
from
the
provisions
of
this
subpart,
testing
conducted
under
this
subpart
must
conform
to
all
of
the
provisions
of
this
subpart.
(
b)
Testing
conducted
under
this
subpart
may
include
any
normal
in
use
operation
of
the
engine.
§
1065.910
Measurement
accuracy
and
precision.
(
a)
Measurement
systems
used
for
inuse
testing
must
be
accurate
to
within
±
5
percent
compared
to
engine
dynamometer
testing
conducted
according
to
the
test
procedures
of
this
part
that
are
applicable
for
your
engine.
These
systems
must
also
have
a
precision
of
±
5
percent
or
better.
Determine
accuracy
and
precision
of
an
in
use
system
by
simultaneously
measuring
emissions
using
the
enginedynamometer
test
procedures
of
this
part
and
the
in
use
system.
To
have
a
statistically
valid
sample,
measure
emissions
during
at
least
3
tests
each
for
at
least
3
different
engines.
You
must
conduct
these
verification
tests
using
the
test
cycle
specified
in
the
standardsetting
part,
unless
we
approve
a
different
test
cycle.
(
1)
A
system
must
meet
the
following
conditions
to
be
considered
sufficiently
accurate:
(
i)
The
correlation
coefficient
(
r)
for
a
least
squares
linear
fit
that
includes
the
origin
must
be
0.95
or
higher.
(
ii)
The
average
ratio
(
for
all
tests)
of
the
emission
rate
from
the
in
use
system
divided
by
the
emission
rate
from
the
dynamometer
procedure
must
be
0.97
to
1.05.
(
2)
For
a
system
to
be
considered
sufficiently
precise,
the
average
coefficient
of
variance
for
all
engines
must
be
5
percent
or
less
for
each
pollutant.
Note:
Increasing
the
length
of
the
sampling
period
may
be
an
effective
way
to
improve
precision.
(
b)
Measurement
systems
that
conform
to
the
provisions
of
§
§
1065.915
through
1065.950
are
considered
to
be
in
compliance
with
the
accuracy
and
precision
requirements
of
paragraph
(
a)
of
this
section.
§
1065.915
Equipment
specifications
for
SI
engines.
This
section
describes
equipment
you
may
use
to
measure
in
use
emissions.
You
may
use
other
equipment
and
measurement
systems
that
conform
to
the
requirements
of
§
§
1065.905
and
1065.910.
(
a)
The
primary
components
of
the
inuse
measurement
system
are
a
mass
air
flow
sensor,
a
portable
FID,
a
zirconia
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8,
2002
/
Rules
and
Regulations
based
NOX
sensor,
a
zirconia
based
air/
fuel
ratio
sensor,
and
a
portable
NDIR
analyzer.
(
1)
The
mass
air
flow
sensor
must
meet
the
requirements
of
§
1065.930.
(
2)
The
portable
FID
must
meet
the
requirements
of
§
1065.935.
(
3)
The
NOX
and
air/
fuel
sensors
must
meet
the
requirements
of
§
1065.940
(
4)
The
NDIR
analyzer
must
meet
the
requirements
of
§
1065.945.
(
b)
You
must
measure
the
following
parameters
continuously
at
a
rate
of
3
Hz
or
higher
and
store
the
data
electronically:
(
1)
THC,
NOX,
CO
concentrations.
(
2)
Mass
air
fuel
ratio.
(
3)
Intake
air
flow
rate.
(
4)
Engine
speed.
(
5)
Parameters
used
to
calculate
torque.
(
c)
You
must
minimize
sample
line
length
for
any
analyzers
that
require
a
physical
sample
be
drawn
from
the
exhaust
to
the
analyzer
(
i.
e.,
THC
and
CO
analyzers).
You
must
draw
these
samples
at
a
constant
flow
rate.
In
no
case
may
you
use
any
combination
of
sample
line
length
and
sample
flow
rate
that
would
require
more
than
10
seconds
for
the
analyzer
to
reach
90
percent
of
its
final
response
after
a
step
change
to
the
input
concentration
at
the
opening
of
the
sample
probe.
For
residence
time
delays
between
1
and
10
seconds,
you
must
correct
the
measurements
to
be
consistent
with
the
data
for
engine
speed,
torque,
and
air
intake.
You
may
also
correct
other
measurements
with
less
than
delays
less
than
1
second.
(
d)
You
may
insert
the
sample
probes
and
sensors
into
the
exhaust
pipe,
or
mount
them
in
an
exhaust
extension
that
is
connected
to
the
exhaust
pipe
with
negligible
leaking.
Place
the
sample
probes
and
sensors
close
enough
to
the
center
line
of
the
exhaust
pipe
to
minimize
boundary
layer
effects
from
the
wall.
§
1065.920
Equipment
setup
and
test
run
for
SI
engines.
This
section
describes
how
to
set
up
the
equipment
specified
in
§
1065.915,
and
how
to
use
it
to
measure
in
use
emissions
from
SI
engines.
(
a)
Inspect
the
vehicle
or
equipment
to
determine
whether
it
meets
any
applicable
requirements
of
the
standardsetting
part.
This
may
include
requirements
related
to
model
year,
accumulated
hours
of
operation,
fuel
specifications,
maintenance
history,
engine
temperatures,
etc.
(
b)
Perform
calibrations
as
specified
in
this
subpart.
In
the
field,
this
generally
will
require
only
zeroing
and
spanning
the
instruments.
However,
each
instrument
must
have
been
fully
calibrated
according
to
the
instrument
manufacturer's
specifications.
Nonlinear
calibrations
generated
previously
from
the
full
calibration
may
be
used
after
zeroing
and
spanning
the
instruments.
Spanning
can
be
performed
using
a
single
gas
bottle,
consistent
with
good
engineering
practice,
and
provided
that
stability
of
the
span
mixture
has
been
demonstrated.
(
c)
Connect
the
data
recorder
(
with
any
necessary
signal
interpreters
or
converters)
to
the
engine's
electronic
control
module.
(
d)
Disconnect
the
air
intake
system,
as
necessary,
to
attach
the
mass
air
flow
sensor.
Reconnect
the
system
after
attaching
the
mass
air
flow
sensor.
(
e)
Attach
the
sample
extension
to
the
exhaust
outlet.
(
f)
Turn
on
instruments
and
allow
them
to
warm
up
as
necessary.
(
g)
Begin
sampling.
You
do
not
need
to
begin
recording
the
data
at
this
point.
(
h)
Begin
operating
the
vehicle
or
equipment
in
a
normal
manner.
Note:
We
may
require
you
to
operate
the
vehicle
or
equipment
in
a
specific
manner.
(
i)
Begin
recording
engine
speed,
engine
torque
(
or
surrogate),
intake
air
flow,
emissions
data
(
THC,
NOX,
CO,
air/
fuel
ratio),
and
time.
This
time
marks
the
beginning
of
the
sampling
period.
(
j)
Continue
recording
data
and
operating
the
vehicle
or
equipment
in
a
normal
manner
until
the
end
of
the
sampling
period.
The
length
of
the
sampling
period
is
based
on
good
engineering
practice,
the
precision
requirements
of
§
1065.910,
and
applicable
limits
in
the
standard
setting
part.
(
k)
You
may
measure
background
concentrations
and
correct
measured
emission
values
accordingly.
However,
if
any
background
corrections
are
equivalent
to
5
percent
or
more
of
the
maximum
emissions
allowed
by
the
applicable
standard,
the
test
shall
be
voided
and
repeated
in
an
environment
with
lower
background
concentrations.
§
1065.925
Calculations.
(
a)
[
Reserved]
(
b)
Convert
emission
analyzer
data
to
instantaneous
concentrations
in
ppm
(
ppmC
for
the
FID).
(
c)
Calculate
instantaneous
exhaust
volumetric
flow
rates
in
standard
m3/
hr
(
volume
and
density
values
used
in
these
calculations
are
corrected
to
standard
conditions
of
20
°
C
and
101.3
kPa.).
Calculate
exhaust
volumetric
flow
rate
from
the
following
equation:
Exhaust
volumetric
flow
rate
=
(
intake
air
mass
flow
rate)(
1+
mass
fuel/
air
ratio)/(
density
of
exhaust)
(
1)
If
you
do
not
know
the
instantaneous
density
of
the
exhaust,
use
the
minimum
density
of
the
exhaust
that
occurs
over
the
course
of
the
test,
corrected
to
standard
conditions.
(
2)
For
gasoline
fueled
engines
designed
to
be
operated
at
stoichiometric
fuel/
air
ratios,
you
may
assume
that
the
density
of
the
exhaust
is
1202
g/
m3
at
standard
conditions
of
20
°
C
and
101.3
kPa.
(
3)
For
LPG
fueled
engines
designed
to
be
operated
at
stoichiometric
fuel/
air
ratios,
you
may
assume
that
the
density
of
the
exhaust
is
1175
g/
m3
at
standard
conditions
of
20
°
C
and
101.3
kPa.
(
4)
For
CNG
fueled
engines
designed
to
be
operated
at
stoichiometric
fuel/
air
ratios,
you
may
assume
that
the
density
of
the
exhaust
is
1149
g/
m3
at
standard
conditions
of
20
°
C
and
101.3
kPa.
(
d)
Calculate
instantaneous
emission
rates
(
g/
hr)
using
the
following
general
equation:
Emission
rate
=
(
exhaust
volumetric
flow
rate)(
ppm)(
density
factor)/
106
Where:
Density
factors
are
576.8
g/
m3
for
THC,
1913
g/
m3
for
NOX,
1164
g/
m3
for
CO.
(
e)
Integrate
instantaneous
emission
rates
for
the
entire
specified
sample
period.
(
f)
Determine
instantaneous
brake
torque
and
speed.
(
g)
Calculate
instantaneous
brake
power.
(
h)
Integrate
instantaneous
brake
power
for
the
entire
specified
sample
period.
(
i)
Divide
the
integrated
emission
rates
by
the
integrated
brake
power.
These
are
your
final
brake
specific
emission
rates.
§
1065.930
Specifications
for
mass
air
flow
sensors.
(
a)
Measure
the
intake
air
flow
using
the
engine's
mass
air
flow
sensor.
If
the
engine
is
not
equipped
with
a
mass
air
flow
sensor,
you
need
to
install
one.
(
b)
The
sensor
design
must
have
an
accuracy
and
precision
of
±
5
percent
under
steady
state
laboratory
conditions.
(
c)
The
sensor
must
reach
at
least
90
percent
of
its
final
response
within
0.3
seconds
after
any
step
change
to
the
flow
rate
greater
than
or
equal
80
percent
of
full
scale.
(
d)
Calibrate
the
sensor
according
to
good
engineering
practice.
Verify
for
each
engine
before
testing
that
the
sensor
accurately
reads
the
idle
intake
air
flow
rate
based
on
measured
manifold
temperature
(
TM)
and
pressure
PM).
Use
the
following
equation:
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/
Friday,
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8,
2002
/
Rules
and
Regulations
Intake
air
flow
=
(
displacement)(
rpm)(
volumetric
efficiency)(
PM/
101.3
kPa)(
293.15
K/
TM)
§
1065.935
Specifications
for
THC
analyzers.
(
a)
Use
a
flame
ionization
detector
(
FID).
(
b)
The
analyzer
must
have
an
accuracy
and
precision
of
±
2
percent
of
point
or
better
under
steady
state
laboratory
conditions.
(
c)
The
analyzer
must
reach
at
least
90
percent
of
its
final
response
within
1.0
second
after
any
step
change
to
the
input
concentration
greater
than
or
equal
80
percent
of
full
scale.
(
d)
Zero
and
span
the
analyzer
daily
during
testing.
Calibrate
it
according
to
the
analyzer
manufacturer's
specifications.
§
1065.940
Specifications
for
NOX
and
air/
fuel
sensors.
(
a)
Use
stabilized
zirconia
based
sensors.
(
b)
The
sensors
must
have
an
accuracy
and
precision
of
±
2
percent
of
point
or
better
under
steady
state
laboratory
conditions.
(
c)
The
sensors
must
reach
at
least
90
percent
of
its
final
response
within
1.0
second
after
any
step
change
to
the
input
concentration
greater
than
or
equal
80
percent
of
full
scale.
(
d)
The
sensors
must
be
zeroed
and
spanned
daily
during
testing,
and
must
be
calibrated
according
to
the
sensor
manufacturer's
specifications.
§
1065.945
Specifications
for
CO
analyzers.
(
a)
Use
a
non
dispersive
infrared
(
NDIR)
detector
that
is
compensated
for
CO2
and
water
interference.
(
b)
The
analyzer
must
have
an
accuracy
and
precision
of
±
2
percent
of
point
or
better
under
steady
state
laboratory
conditions.
(
c)
The
analyzer
must
reach
at
least
90
percent
of
its
final
response
within
5.0
second
after
any
step
change
to
the
input
concentration
greater
than
or
equal
80
percent
of
full
scale.
(
d)
The
analyzer
must
be
zeroed
and
spanned
daily
during
testing,
and
must
be
calibrated
according
to
the
analyzer
manufacturer's
specifications.
§
1065.950
Specifications
for
speed
and
torque
measurement.
(
a)
Determine
torque
from
a
previously
determined
relationship
of
torque
and
engine
speed,
throttle
position,
and/
or
manifold
absolute
pressure.
Torque
estimates
must
be
between
85
percent
and
105
percent
of
the
true
value.
You
can
demonstrate
compliance
with
this
accuracy
requirement
using
steady
state
laboratory
data.
(
b)
Measure
speed
from
the
engine's
electronic
control
module.
Speed
estimates
must
be
within
±
5
rpm
of
the
true
value.
Subpart
K
Definitions
and
Other
Reference
Information
§
1065.1001
Definitions.
The
following
definitions
apply
to
this
part.
The
definitions
apply
to
all
subparts
unless
we
note
otherwise.
All
undefined
terms
have
the
meaning
the
Act
gives
to
them.
The
definitions
follow:
Accuracy
means
the
maximum
difference
between
a
measured
or
calculated
value
and
the
true
value,
where
the
true
value
is
determined
by
NIST.
Act
means
the
Clean
Air
Act,
as
amended,
42
U.
S.
C.
7401
et
seq.
Adjustable
parameter
means
any
device,
system,
or
element
of
design
that
someone
can
adjust
(
including
those
which
are
difficult
to
access)
and
that,
if
adjusted,
may
affect
emissions
or
engine
performance
during
emission
testing
or
normal
in
use
operation.
Aftertreatment
means
relating
to
any
system,
component,
or
technology
mounted
downstream
of
the
exhaust
valve
or
exhaust
port
whose
design
function
is
to
reduce
exhaust
emissions.
Auxiliary
emission
control
device
means
any
element
of
design
that
senses
temperature,
engine
speed,
motive
speed,
transmission
gear,
atmospheric
pressure,
manifold
pressure
or
vacuum,
or
any
other
parameter
to
activate,
modulate,
delay,
or
deactivate
the
operation
of
any
part
of
the
emissioncontrol
system.
This
also
includes
any
other
feature
that
causes
in
use
emissions
to
be
higher
than
those
measured
under
test
conditions,
except
as
we
allow
under
this
part.
Brake
power
has
the
meaning
given
in
the
standard
setting
part.
If
it
is
not
defined
in
the
standard
setting
part,
brake
power
means
the
usable
power
output
of
the
engine
not
including
power
required
to
operate
fuel
pumps,
oil
pumps,
or
coolant
pumps.
Calibration
means
the
set
of
specifications
and
tolerances
specific
to
a
particular
design,
version,
or
application
of
a
component
or
assembly
capable
of
functionally
describing
its
operation
over
its
working
range.
Certification
means
obtaining
a
certificate
of
conformity
for
an
engine
family
that
complies
with
the
emission
standards
and
requirements
in
this
part.
Compression
ignition
means
relating
to
a
type
of
reciprocating,
internalcombustion
engine
that
is
not
a
sparkignition
engine.
Constant
speed
engine
means
an
engine
governed
to
operate
only
at
its
rated
speed.
Designated
Officer
means
the
Manager,
Engine
Programs
Group
(
6405
J),
U.
S.
Environmental
Protection
Agency,
1200
Pennsylvania
Ave.,
Washington,
DC
20460.
Emission
control
system
means
any
device,
system,
or
element
of
design
that
controls
or
reduces
the
regulated
emissions
from
an
engine.
Emission
data
engine
means
an
engine
that
is
tested
for
certification.
Emission
related
maintenance
means
maintenance
that
substantially
affects
emissions
or
is
likely
to
substantially
affect
emissions
deterioration.
Engine
means
an
engine
to
which
this
part
applies.
Engine
based
means
having
emission
standards
related
to
measurements
using
an
engine
dynamometer,
in
units
of
grams
of
pollutant
per
kilowatt
hour.
Engine
family
means
a
group
of
engines
with
similar
emission
characteristics,
as
specified
in
the
standard
setting
part.
Equipment
based
or
vehicle
based
means
relating
to
programs
that
require
that
a
piece
of
equipment
of
vehicle
be
certified,
rather
than
only
the
engine.
Fuel
system
means
all
components
involved
in
transporting,
metering,
and
mixing
the
fuel
from
the
fuel
tank
to
the
combustion
chamber(
s),
including
the
fuel
tank,
fuel
tank
cap,
fuel
pump,
fuel
filters,
fuel
lines,
carburetor
or
fuelinjection
components,
and
all
fuelsystem
vents.
Fuel
type
means
a
general
category
of
fuels
such
as
gasoline
or
LPG.
There
can
be
multiple
grades
within
a
single
type
of
fuel,
such
as
summer
grade
gasoline
and
winter
grade
gasoline.
Good
engineering
judgment
has
the
meaning
we
give
it
in
§
1068.5
of
this
chapter.
Identification
number
means
a
unique
specification
(
for
example,
model
number/
serial
number
combination)
that
allows
someone
to
distinguish
a
particular
engine
from
other
similar
engines.
Idle
speed
means
the
lowest
engine
speed
with
zero
load.
Note:
Warm
idle
speed
is
the
idle
speed
of
a
warmed
up
engine.
Manufacturer
has
the
meaning
given
in
section
216(
1)
of
the
Act.
In
general,
this
term
includes
any
person
who
manufactures
an
engine
for
sale
in
the
United
States
or
otherwise
introduces
a
new
engine
into
commerce
in
the
United
States.
This
includes
importers
that
import
engines
for
resale.
Maximum
test
torque
means:
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Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
(
1)
For
throttled
engines,
the
torque
output
observed
at
wide
open
throttle
at
a
given
speed.
(
2)
For
non
throttled
engines,
the
torque
output
observed
with
the
maximum
fueling
rate
possible
at
a
given
speed.
Nonmethane
hydrocarbons
means
the
sum
of
all
hydrocarbon
species
measured
by
a
FID
except
methane,
expressed
with
an
assumed
mass
13.876
grams
per
mole
of
carbon
atoms.
Nonroad
means
relating
to
nonroad
engines.
Nonroad
engine
has
the
meaning
given
in
§
89.2
of
this
chapter.
In
general
this
means
all
internal
combustion
engines
except
motor
vehicle
engines,
stationary
engines,
or
engines
used
solely
for
competition.
Oxides
of
nitrogen
means
compounds
containing
only
nitrogen
and
oxygen.
Oxides
of
nitrogen
are
expressed
quantitatively
as
if
the
NO
is
in
the
form
of
NO2
(
assume
a
molecular
weight
for
all
oxides
of
nitrogen
equivalent
to
that
of
NO2).
This
correction
is
included
in
the
equations
specified
for
calculating
NOX
emissions.
Oxygenated
fuel
means
a
fuel
that
is
comprised
of
oxygen
containing
compound,
such
as
ethanol
or
methanol.
Generally,
testing
engines
that
use
oxygenated
fuels
requires
the
use
of
the
sampling
methods
in
subpart
I
of
this
part.
However,
you
should
read
the
standard
setting
part
and
subpart
I
of
this
part
to
determine
which
sampling
methods
to
use.
Precision
means
two
times
the
coefficient
of
variance
of
multiple
measurements,
except
where
specified
otherwise.
Revoking
a
certificate
of
conformity
means
discontinuing
the
certificate
for
an
engine
family.
If
we
revoke
a
certificate,
you
must
apply
for
a
new
certificate
before
continuing
to
introduce
into
commerce
the
affected
engines.
This
does
not
apply
to
engines
you
no
longer
possess.
Scheduled
maintenance
means
maintenance
(
i.
e.,
adjusting,
repairing,
removing,
disassembling,
cleaning,
or
replacing
components
or
systems)
that
is
periodically
needed
to
keep
a
part
from
failing
or
malfunctioning.
It
also
may
mean
actions
you
expect
are
necessary
to
correct
an
overt
indication
of
failure
or
malfunction
for
which
periodic
maintenance
is
not
appropriate.
Span
means
to
adjust
an
instrument
so
that
it
gives
a
proper
response
to
a
calibration
standard
that
represents
between
75
and
100
percent
of
the
maximum
value
in
the
instrument
range
(
e.
g.
a
span
gas).
Spark
ignition
means
relating
to
a
gasoline
fueled
engine
or
other
engines
with
a
spark
plug
(
or
other
sparking
device)
and
with
operating
characteristics
significantly
similar
to
the
theoretical
Otto
combustion
cycle.
Spark
ignition
engines
usually
use
a
throttle
to
regulate
intake
air
flow
to
control
power
during
normal
operation.
Standard
setting
part
means
the
part
in
the
Code
of
Federal
Regulations
that
defines
emission
standards
for
a
particular
engine
(
see
§
1065.1(
a)).
Stoichiometry
means
the
proportion
of
a
mixture
of
air
and
fuel
such
that
the
fuel
is
fully
oxidized
with
no
remaining
oxygen.
For
example,
stoichiometric
combustion
in
gasoline
engines
typically
occurs
at
an
air
fuel
mass
ratio
of
about
14.7.
Suspending
a
certificate
of
conformity
means
temporarily
discontinuing
the
certificate
for
an
engine
family.
If
we
suspend
a
certificate,
you
may
not
sell
engines
from
that
engine
family
unless
we
reinstate
the
certificate
or
approve
a
new
one.
Test
engine
means
an
engine
in
a
test
sample.
Test
sample
means
the
collection
of
engines
selected
from
the
population
of
an
engine
family
for
emission
testing.
Total
Hydrocarbon
(
THC)
means
the
sum
of
all
hydrocarbon
species
measured
by
an
FID,
expressed
with
an
assumed
mass
13.876
grams
per
mole
of
carbon
atoms.
Total
Hydrocarbon
Equivalent
means
the
sum
of
the
carbon
mass
contributions
of
non
oxygenated
hydrocarbons,
alcohols
and
aldehydes,
or
other
organic
compounds
that
are
measured
separately
as
contained
in
a
gas
sample,
expressed
as
petroleumfueled
engine
hydrocarbons.
The
hydrogen
to
carbon
ratio
of
the
equivalent
hydrocarbon
is
1.85:
1.
United
States
means
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.
Wide
open
throttle
means
maximum
throttle
opening
for
throttled
engines.
Unless
this
is
specified
at
a
given
speed,
it
refers
to
maximum
throttle
opening
at
maximum
speed.
For
electronically
controlled
or
other
engines
with
multiple
possible
fueling
rates,
wideopen
throttle
also
means
the
maximum
fueling
rate
at
maximum
throttle
opening
under
test
conditions.
Zero
means
to
adjust
an
instrument
so
that
it
gives
a
proper
response
to
a
blank
calibration
standard
(
e.
g.
zero
grade
air).
§
1065.1005
Symbols,
acronyms,
and
abbreviations.
The
following
symbols,
acronyms,
and
abbreviations
apply
to
this
part:
°
degrees.
inches.
ASTM
American
Society
for
Testing
and
Materials.
C
Celsius.
cc
cubic
centimeters.
CFR
Code
of
Federal
Regulations.
CFV
critical
flow
venturi.
CI
compression
ignition.
CLD
chemiluminescent
detector.
CO
carbon
monoxide.
CO2
carbon
dioxide.
CVS
constant
volume
sampler.
DF
deterioration
factor.
F
Fahrenheit.
EFC
electronic
flow
control.
EPA
Environmental
Protection
Agency.
ft
feet.
FID
flame
ionization
detector.
g/
kW
hr
grams
per
kilowatt
hour.
g/
liter
grams
per
liter.
g/
m3
grams
per
cubic
meter.
Hz
hertz.
IBP
initial
boiling
point.
ISO
International
Organization
for
Standardization.
kPa
kilopascal.
lbs.
pounds.
LPG
liquefied
petroleum
gas.
m
meters.
ml
milliliters.
mm
Hg
millimeters
of
mercury.
NDIR
nondispersive
infrared.
NIST
National
Institute
for
Standards
and
Testing.
NMHC
nonmethane
hydrocarbons.
NMHCE
nonmethane
hydrocarbon
equivalent.
NO
nitric
oxide.
NO2
nitrogen
dioxide.
NOX
oxides
of
nitrogen
(
NO
and
NO2).
O2
oxygen.
PDP
positive
displacement
pump.
ppm
parts
per
million.
ppmC
parts
per
million
carbon.
RMS
root
mean
square.
rpm
revolutions
per
minute.
sec
seconds.
SI
spark
ignition.
THC
total
hydrocarbon.
THCE
total
hydrocarbon
equivalent.
U.
S.
C.
United
States
Code.
§
1065.1010
Reference
materials.
We
have
incorporated
by
reference
the
documents
listed
in
this
section.
The
Director
of
the
Federal
Register
approved
the
incorporation
by
reference
as
prescribed
in
5
U.
S.
C.
552(
a)
and
1
CFR
part
51.
Anyone
may
inspect
copies
at
the
U.
S.
EPA,
Air
and
Radiation
Docket
and
Information
Center,
1301
Constitution
Ave.,
NW.,
Room
B102,
EPA
West
Building,
Washington,
DC
20460
or
the
Office
of
the
Federal
Register,
800
N.
Capitol
St.,
NW.,
7th
Floor,
Suite
700,
Washington,
DC.
(
a)
ASTM
material.
Table
1
of
§
1065.1010
lists
material
from
the
American
Society
for
Testing
and
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and
Regulations
Materials
that
we
have
incorporated
by
reference.
The
first
column
lists
the
number
and
name
of
the
material.
The
second
column
lists
the
sections
of
this
part
where
we
reference
it.
Anyone
may
purchase
copies
of
these
materials
from
the
American
Society
for
Testing
and
Materials,
100
Barr
Harbor
Dr.,
West
Conshohocken,
PA
19428.
Table
1
follows:
TABLE
1
OF
§
1065.1010.
ASTM
MATERIALS
Document
number
and
name
Part
1065
reference
ASTM
D
86
01,
Standard
Test
Method
for
Distillation
of
Petroleum
Products
at
Atmospheric
Pressure
.........................................
1065.210
ASTM
D
323
99a,
Standard
Test
Method
for
Vapor
Pressure
of
Petroleum
Products
(
Reid
Method)
.............................................
1065.210
ASTM
D
1266
98,
Standard
Test
Method
for
Sulfur
in
Petroleum
Products
(
Lamp
Method)
...........................................................
1065.210
ASTM
D
1319
02,
Standard
Test
Method
for
Hydrocarbon
Types
in
Liquid
Petroleum
Products
by
Fluorescent
Indicator
Adsorption
.............................................................................................................................................................................................
1065.210
ASTM
D
1267
02,
Standard
Test
Method
for
Gage
Vapor
Pressure
of
Liquefied
Petroleum
(
LP)
Gases
(
LP
Gas
Method)
..........
1065.220
ASTM
D
1837
02,
Standard
Test
Method
for
Volatility
of
Liquefied
Petroleum
(
LP)
Gases
.............................................................
1065.220
ASTM
D
1838
91
(
Reapproved
2001),
Standard
Test
Method
for
Copper
Strip
Corrosion
by
Liquefied
Petroleum
(
LP)
Gases
....
1065.220
ASTM
D
1945
96
(
Reapproved
2001),
Standard
Test
Method
for
Analysis
of
Natural
Gas
by
Gas
Chromatography
....................
1065.215
ASTM
D
2158
02,
Standard
Test
Method
for
Residues
in
Liquefied
Petroleum
(
LP)
Gases
...........................................................
1065.220
ASTM
D
2163
91
(
Reapproved
1996),
Standard
Test
Method
for
Analysis
of
Liquefied
Petroleum
(
LP)
Gases
and
Propene
Concentrates
by
Gas
Chromatography
...........................................................................................................................................
1065.220
ASTM
D
2598
02,
Standard
Practice
for
Calculation
of
Certain
Physical
Properties
of
Liquefied
Petroleum
(
LP)
Gases
from
Compositional
Analysis
....................................................................................................................................................................
1065.220
ASTM
D
2713
91
(
Reapproved
2001),
Standard
Test
Method
for
Dryness
of
Propane
(
Valve
Freeze
Method)
............................
1065.220
ASTM
D
2784
98,
Standard
Test
Method
for
Sulfur
in
Liquefied
Petroleum
Gases
(
Oxy
Hydrogen
Burner
or
Lamp)
...................
1065.220
ASTM
D
3231
02,
Standard
Test
Method
for
Phosphorus
in
Gasoline
.............................................................................................
1065.210
ASTM
D
3237
97,
Standard
Test
Method
for
Lead
in
Gasoline
By
Atomic
Absorption
Spectroscopy
.............................................
1065.210
(
b)
ISO
material.
Table
2
of
§
1065.1010
lists
material
from
the
International
Organization
for
Standardization
that
we
have
incorporated
by
reference.
The
first
column
lists
the
number
and
name
of
the
material.
The
second
column
lists
the
section
of
this
part
where
we
reference
it.
Anyone
may
purchase
copies
of
these
materials
from
the
International
Organization
for
Standardization,
Case
Postale
56,
CH
1211
Geneva
20,
Switzerland.
Table
2
follows:
TABLE
2
OF
§
1065.1010.
ISO
MATERIALS
Document
number
and
name
Part
1065
reference
ISO
8178
1,
Reciprocating
internal
combustion
engines
Exhaust
emission
measurement
Part
1:
Testbed
measurement
of
gaseous
and
particulate
exhaust
emissions,
1996.
1065.130,
1065.135,
1065.140,
1065.155.
§
1065.1015
Confidential
information.
(
a)
Clearly
show
what
you
consider
confidential
by
marking,
circling,
bracketing,
stamping,
or
some
other
method.
We
will
store
your
confidential
information
as
described
in
40
CFR
part
2.
Also,
we
will
disclose
it
only
as
specified
in
40
CFR
part
2.
(
b)
If
you
send
us
a
second
copy
without
the
confidential
information,
we
will
assume
it
contains
nothing
confidential
whenever
we
need
to
release
information
from
it.
(
c)
If
you
send
us
information
without
claiming
it
is
confidential,
we
may
make
it
available
to
the
public
without
further
notice
to
you,
as
described
in
§
2.204
of
this
chapter.
PART
1068
GENERAL
COMPLIANCE
PROVISIONS
FOR
NONROAD
PROGRAMS
Subpart
A
Applicability
and
Miscellaneous
Provisions
Sec.
1068.1
Does
this
part
apply
to
me?
1068.5
How
must
manufacturers
apply
good
engineering
judgment?
1068.10
How
do
I
request
EPA
to
keep
my
information
confidential
1068.15
Who
is
authorized
to
represent
the
Agency?
1068.20
May
EPA
enter
my
facilities
for
inspections?
1068.25
What
information
must
I
give
to
EPA?
1068.30
What
definitions
apply
to
this
part?
1068.35
What
symbols,
acronyms,
and
abbreviations
does
this
part
use?
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8,
2002
/
Rules
and
Regulations
Subpart
B
Prohibited
Actions
and
Related
Requirements
1068.101
What
general
actions
does
this
regulation
prohibit?
1068.105
What
other
provisions
apply
to
me
specifically
if
I
manufacture
equipment
needing
certified
engines?
1068.110
What
other
provisions
apply
to
engines
in
service?
1068.115
When
must
manufacturers
honor
emission
related
warranty
claims?
1068.120
What
requirements
must
I
follow
to
rebuild
engines?
1068.125
What
happens
if
I
violate
the
regulations?
Subpart
C
Exemptions
and
Exclusions
1068.201
Does
EPA
exempt
or
exclude
any
engines
from
the
prohibited
acts?
1068.210
What
are
the
provisions
for
exempting
test
engines?
1068.215
What
are
the
provisions
for
exempting
manufacturer
owned
engines?
1068.220
What
are
the
provisions
for
exempting
display
engines?
1068.225
What
are
the
provisions
for
exempting
engines
for
national
security?
1068.230
What
are
the
provisions
for
exempting
engines
for
export?
1068.235
What
are
the
provisions
for
exempting
engines
used
solely
for
competition?
1068.240
What
are
the
provisions
for
exempting
new
replacement
engines?
1068.245
What
temporary
provisions
address
hardship
due
to
unusual
circumstances?
1068.250
What
are
the
provisions
for
extending
compliance
deadlines
for
small
volume
manufacturers
under
hardship?
1068.255
What
are
the
provisions
for
exempting
engines
for
hardship
for
equipment
manufacturers
and
secondary
engine
manufacturers?
Subpart
D
Imports
1068.301
Does
this
subpart
apply
to
me?
1068.305
How
do
I
get
an
exemption
or
exclusion
for
imported
engines?
1068.310
What
are
the
exclusions
for
imported
engines?
1068.315
What
are
the
permanent
exemptions
for
imported
engines?
1068.320
How
must
I
label
an
imported
engine
with
a
permanent
exemption?
1068.325
What
are
the
temporary
exemptions
for
imported
engines?
1068.330
How
do
I
import
engines
to
modify
for
other
applications?
1068.335
What
are
the
penalties
for
violations?
Subpart
E
Selective
Enforcement
Auditing
11068.401
What
is
a
selective
enforcement
audit?
1068.405
What
is
in
a
test
order?
1068.410
How
must
I
select
and
prepare
my
engines?
1068.415
How
do
I
test
my
engines?
1068.420
How
do
I
know
when
my
engine
family
fails
an
SEA?
1068.425
What
happens
if
one
of
my
production
line
engines
exceeds
the
emission
standards?
1068.430
What
happens
if
an
engine
family
fails
an
SEA?
1068.435
May
I
sell
engines
from
an
engine
family
with
a
suspended
certificate
of
conformity?
1068.440
How
do
I
ask
EPA
to
reinstate
my
suspended
certificate?
1068.445
When
may
EPA
revoke
my
certificate
under
this
subpart
and
how
may
I
sell
these
engines
again?
1068.450
What
records
must
I
send
to
EPA?
1068.455
What
records
must
I
keep?
Appendix
A
to
Subpart
E
of
Part
1068
Plans
for
Selective
Enforcement
Auditing
Subpart
F
Reporting
Defects
and
Recalling
Engines
1068.501
How
do
I
report
engine
defects?
1068.505
How
does
the
recall
program
work?
1068.510
How
do
I
prepare
and
apply
my
remedial
plan?
1068.515
How
do
I
mark
or
label
repaired
engines?
1068.520
How
do
I
notify
affected
owners?
1068.525
What
records
must
I
send
to
EPA?
1068.530
What
records
must
I
keep?
1068.535
How
can
I
do
a
voluntary
recall
for
emission
related
problems?
1068.540
What
terms
do
I
need
to
know
for
this
subpart?
Subpart
G
Hearings
1068.601
What
are
the
procedures
for
hearings?
Appendix
I
to
Part
1068
Emission
Related
Components
Appendix
II
to
Part
1068
Emission
Related
Parameters
and
Specifications
Authority:
42
U.
S.
C.
7401
7671(
q).
Subpart
A
Applicability
and
Miscellaneous
Provisions
§
1068.1
Does
this
part
apply
to
me?
(
a)
The
provisions
of
this
part
apply
to
everyone
with
respect
to
the
following
engines
or
to
equipment
using
the
following
engines
(
including
owners,
operators,
parts
manufacturers,
and
persons
performing
maintenance):
(
1)
Large
nonroad
spark
ignition
engines
we
regulate
under
40
CFR
part
1048.
(
2)
Recreational
SI
engines
and
vehicles
that
we
regulate
under
40
CFR
part
1051
(
such
as
snowmobiles
and
offhighway
motorcycles).
(
b)
This
part
does
not
apply
to
any
of
the
following
engine
or
vehicle
categories:
(
1)
Light
duty
motor
vehicles
(
see
40
CFR
part
86).
(
2)
Heavy
duty
motor
vehicles
and
motor
vehicle
engines
(
see
40
CFR
part
86).
(
3)
Aircraft
engines
(
see
40
CFR
part
87).
(
4)
Locomotive
engines
(
see
40
CFR
part
92).
(
5)
Land
based
nonroad
diesel
engines
(
see
40
CFR
part
89).
(
6)
Marine
diesel
engines
(
see
40
CFR
parts
89
and
94)
(
7)
Marine
outboard
and
personal
watercraft
engines
(
see
40
CFR
part
91).
(
8)
Small
nonroad
spark
ignition
engines
(
see
40
CFR
part
90).
(
c)
For
equipment
subject
to
this
part
and
regulated
under
equipment
based
standards,
interpret
the
term
``
engine''
in
this
part
to
include
equipment
(
see
§
1068.30).
(
d)
Paragraph
(
a)(
1)
of
this
section
identifies
the
parts
of
the
CFR
that
define
emission
standards
and
other
requirements
for
particular
types
of
engines
and
vehicles.
This
part
1068
refers
to
each
these
other
parts
generically
as
the
``
standard
setting
part.''
For
example,
40
CFR
part
1051
is
always
the
standard
setting
part
for
snowmobiles.
Follow
the
provisions
of
the
standard
setting
part
if
they
are
different
than
any
of
the
provisions
in
this
part.
§
1068.5
How
must
manufacturers
apply
good
engineering
judgment?
(
a)
You
must
use
good
engineering
judgment
for
decisions
related
to
any
requirements
under
this
chapter.
This
includes
your
applications
for
certification,
any
testing
you
do
to
show
that
your
production
line
or
in
use
engines
comply
with
requirements
that
apply
to
them,
and
how
you
select,
categorize,
determine,
and
apply
these
requirements.
(
b)
If
we
send
you
a
written
request,
you
must
give
us
a
written
description
of
the
engineering
judgment
in
question.
Respond
within
15
working
days
of
receiving
our
request
unless
we
allow
more
time.
(
c)
We
may
reject
your
decision
if
it
is
not
based
on
good
engineering
judgment
or
is
otherwise
inconsistent
with
the
requirements
that
apply,
based
on
the
following
provisions:
(
1)
We
may
suspend,
revoke,
or
void
a
certificate
of
conformity
if
we
determine
you
deliberately
used
incorrect
information
or
overlooked
important
information,
that
you
did
not
decide
in
good
faith,
or
that
your
decision
was
not
rational.
(
2)
If
we
believe
a
different
decision
would
better
reflect
good
engineering
judgment,
but
none
of
the
provisions
of
paragraph
(
c)(
1)
of
this
section
apply,
we
will
tell
you
of
our
concern
(
and
its
basis).
You
will
have
30
days
to
respond
to
our
concerns,
or
more
time
if
we
agree
that
you
need
it
to
generate
more
information.
After
considering
your
information,
we
will
give
you
a
final
ruling.
If
we
conclude
that
you
did
not
use
good
engineering
judgment,
we
may
reject
your
decision
and
apply
the
new
ruling
to
similar
situations
as
soon
as
possible.
(
d)
We
will
tell
you
in
writing
of
the
conclusions
we
reach
under
paragraph
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8,
2002
/
Rules
and
Regulations
(
c)
of
this
section
and
explain
our
reasons
for
them.
(
e)
If
you
disagree
with
our
conclusions,
you
may
file
a
request
for
a
hearing
with
the
Designated
Officer
as
described
in
subpart
F
of
this
part.
In
your
request,
specify
your
objections,
include
data
or
supporting
analysis,
and
get
your
authorized
representative's
signature.
If
we
agree
that
your
request
raises
a
substantial
factual
issue,
we
will
hold
the
hearing
according
to
subpart
F
of
this
part.
§
1068.10
How
do
I
request
EPA
to
keep
my
information
confidential
(
a)
Clearly
identify
any
information
you
consider
confidential
by
marking,
circling,
bracketing,
stamping,
or
some
other
method.
We
will
store
your
confidential
information
as
described
in
40
CFR
part
2.
Also,
we
will
disclose
it
only
as
specified
in
40
CFR
part
2.
This
procedure
applies
equally
to
the
Environmental
Appeals
Board.
(
b)
If
you
send
us
a
second
copy
without
the
confidential
information,
we
will
assume
it
contains
nothing
confidential
whenever
we
need
to
release
information
from
it.
(
c)
If
you
send
us
information
without
claiming
it
is
confidential,
we
may
make
it
available
to
the
public
without
further
notice
to
you,
as
described
in
§
2.204
of
this
chapter.
§
1068.15
Who
is
authorized
to
represent
the
Agency?
(
a)
The
Administrator
of
the
Environmental
Protection
Agency
or
any
official
to
whom
the
Administrator
has
delegated
specific
authority
may
represent
the
Agency.
For
more
information,
ask
for
a
copy
of
the
relevant
sections
of
the
EPA
Delegation
Manual
from
the
Designated
Officer.
(
b)
The
regulations
in
this
part
and
in
the
standard
setting
part
have
specific
requirements
describing
how
to
get
EPA
approval
before
you
take
specific
actions.
These
regulations
also
allow
us
to
waive
some
specific
requirements.
For
provisions
or
flexibilities
that
we
address
frequently,
we
may
choose
to
provide
detailed
guidance
in
supplemental
compliance
instructions
for
manufacturers.
Such
instructions
will
generally
state
how
they
relate
to
the
need
for
pre
approval.
Unless
we
explicitly
state
so,
you
should
not
consider
full
compliance
with
the
instructions
to
be
equivalent
to
EPA
approval.
§
1068.20
May
EPA
enter
my
facilities
for
inspections?
(
a)
We
may
inspect
your
engines,
testing,
manufacturing
processes,
engine
storage
facilities
(
including
port
facilities
for
imported
engines
or
other
relevant
facilities),
or
records,
as
authorized
by
the
Act,
to
enforce
the
provisions
of
this
chapter.
Inspectors
will
have
authorizing
credentials
and
will
limit
inspections
to
reasonable
times
usually,
normal
operating
hours.
(
b)
If
we
come
to
inspect,
we
may
or
may
not
have
a
warrant
or
court
order.
(
1)
If
we
do
not
have
a
warrant
or
court
order,
you
may
deny
us
entry.
(
2)
If
we
have
a
warrant
or
court
order,
you
must
allow
us
to
enter
the
facility
and
carry
out
the
activities
it
describes.
(
c)
We
may
seek
a
warrant
or
court
order
authorizing
an
inspection
described
in
this
section,
whether
or
not
we
first
tried
to
get
your
permission
to
inspect.
(
d)
We
may
select
any
facility
to
do
any
of
the
following:
(
1)
Inspect
and
monitor
any
aspect
of
engine
manufacturing,
assembly,
storage,
or
other
procedures,
and
any
facilities
where
you
do
them.
(
2)
Inspect
and
monitor
any
aspect
of
engine
test
procedures
or
test
related
activities,
including
test
engine
selection,
preparation,
service
accumulation,
emission
duty
cycles,
and
maintenance
and
verification
of
your
test
equipment's
calibration.
(
3)
Inspect
and
copy
records
or
documents
related
to
assembling,
storing,
selecting,
and
testing
an
engine.
(
4)
Inspect
and
photograph
any
part
or
aspect
of
engines
and
components
you
use
for
assembly.
(
e)
You
must
give
us
reasonable
help
without
charge
during
an
inspection
authorized
by
the
Act.
For
example,
you
may
need
to
help
us
arrange
an
inspection
with
the
facility's
managers,
including
clerical
support,
copying,
and
translation.
You
may
also
need
to
show
us
how
the
facility
operates
and
answer
other
questions.
If
we
ask
in
writing
to
see
a
particular
employee
at
the
inspection,
you
must
ensure
that
he
or
she
is
present
(
legal
counsel
may
accompany
the
employee).
(
f)
If
you
have
facilities
in
other
countries,
we
expect
you
to
locate
them
in
places
where
local
law
does
not
keep
us
from
inspecting
as
described
in
this
section.
We
will
not
try
to
inspect
if
we
learn
that
local
law
prohibits
it,
but
we
may
suspend
your
certificate
if
we
are
not
allowed
to
inspect.
§
1068.25
What
information
must
I
give
to
EPA?
If
you
are
subject
to
the
requirements
of
this
part,
we
may
require
you
to
give
us
information
to
evaluate
your
compliance
with
any
regulations
that
apply,
as
authorized
by
the
Act.
This
includes
the
following
things:
(
a)
You
must
provide
the
information
we
require
in
this
chapter.
(
b)
You
must
establish
and
maintain
records,
perform
tests,
make
reports
and
provide
additional
information
that
we
may
reasonably
require
under
section
208
of
the
Act.
This
also
applies
to
engines
we
exempt
from
emission
standards.
§
1068.30
What
definitions
apply
to
this
part?
The
following
definitions
apply
to
this
part.
The
definitions
apply
to
all
subparts
unless
we
note
otherwise.
All
undefined
terms
have
the
meaning
the
Act
gives
to
them.
The
definitions
follow:
Act
means
the
Clean
Air
Act,
as
amended,
42
U.
S.
C.
7401
et
seq.
Aircraft
means
any
vehicle
capable
of
sustained
air
travel
above
treetop
heights.
Certificate
holder
means
a
manufacturer
(
including
importers)
with
a
valid
certificate
of
conformity
for
at
least
one
engine
family
in
a
given
calendar
year.
Designated
Officer
means
the
Manager
of
the
Engine
Programs
Group
(
6405
J),
U.
S.
Environmental
Protection
Agency,
1200
Pennsylvania
Ave.,
Washington,
DC
20460.
Emission
related
defect
means
a
defect
in
design,
materials
or
workmanship
(
in
an
emission
control
device
or
vehicle
component
or
system)
that
affects
an
emission
related
component,
parameter,
or
specification
that
is
identified
in
Appendix
I
or
Appendix
II
of
this
part.
Engine
means
an
engine
to
which
this
part
applies.
For
equipment
subject
to
this
part
and
regulated
under
equipment
based
standards,
the
term
engine
in
this
part
shall
be
interpreted
to
include
equipment.
Engine
based
means
having
emission
standards
related
to
measurements
using
an
engine
dynamometer,
in
units
of
grams
of
pollutant
per
kilowatt
hour.
Engine
manufacturer
means
the
manufacturer
that
is
subject
to
the
certification
requirements
of
the
standard
setting
part.
For
vehicles/
equipment
subject
to
this
part
and
regulated
under
vehicle/
equipmentbased
standards,
the
term
engine
manufacturer
in
this
part
includes
vehicles/
equipment
manufacturers.
Equipment
based
means
having
emission
standards
related
to
measurements
from
an
engine
installed
in
a
vehicle
using
a
chassis
dynamometer,
in
units
of
grams
of
pollutant
per
kilometer.
Equipment
manufacturer
means
any
company
producing
a
piece
of
equipment
(
such
as
a
vehicle)
for
sale
or
use
in
the
United
States.
Manufacturer
has
the
meaning
given
in
section
216(
1)
of
the
Act.
In
general,
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Rules
and
Regulations
this
term
includes
any
person
who
manufactures
an
engine
or
vehicle
for
sale
in
the
United
States
or
otherwise
introduces
a
new
engine
or
vehicle
into
commerce
in
the
United
States.
This
includes
importers
that
import
new
engines
or
new
equipment
into
the
United
States
for
resale.
It
also
includes
secondary
engine
manufacturers.
New
has
the
meaning
we
give
it
in
the
standard
setting
part.
Nonroad
engine
means:
(
1)
Except
as
discussed
in
paragraph
(
2)
of
this
definition,
a
nonroad
engine
is
any
internal
combustion
engine:
(
i)
In
or
on
a
piece
of
equipment
that
is
self
propelled
or
serves
a
dual
purpose
by
both
propelling
itself
and
performing
another
function
(
such
as
garden
tractors,
off
highway
mobile
cranes
and
bulldozers);
or
(
ii)
In
or
on
a
piece
of
equipment
that
is
intended
to
be
propelled
while
performing
its
function
(
such
as
lawnmowers
and
string
trimmers);
or
(
iii)
That,
by
itself
or
in
or
on
a
piece
of
equipment,
is
portable
or
transportable,
meaning
designed
to
be
and
capable
of
being
carried
or
moved
from
one
location
to
another.
Indicia
of
transportability
include,
but
are
not
limited
to,
wheels,
skids,
carrying
handles,
dolly,
trailer,
or
platform.
(
2)
An
internal
combustion
engine
is
not
a
nonroad
engine
if:
(
i)
The
engine
is
used
to
propel
a
motor
vehicle
or
a
vehicle
used
solely
for
competition,
or
is
subject
to
standards
promulgated
under
section
202
of
the
Act;
or
(
ii)
The
engine
is
regulated
by
a
federal
New
Source
Performance
Standard
promulgated
under
section
111
of
the
Act;
or
(
iii)
The
engine
otherwise
included
in
paragraph
(
1)(
iii)
of
this
definition
remains
or
will
remain
at
a
location
for
more
than
12
consecutive
months
or
a
shorter
period
of
time
for
an
engine
located
at
a
seasonal
source.
A
location
is
any
single
site
at
a
building,
structure,
facility,
or
installation.
Any
engine
(
or
engines)
that
replaces
an
engine
at
a
location
and
that
is
intended
to
perform
the
same
or
similar
function
as
the
engine
replaced
will
be
included
in
calculating
the
consecutive
time
period.
An
engine
located
at
a
seasonal
source
is
an
engine
that
remains
at
a
seasonal
source
during
the
full
annual
operating
period
of
the
seasonal
source.
A
seasonal
source
is
a
stationary
source
that
remains
in
a
single
location
on
a
permanent
basis
(
i.
e.,
at
least
two
years)
and
that
operates
at
that
single
location
approximately
three
months
(
or
more)
each
year.
This
paragraph
(
2)(
iii)
does
not
apply
to
an
engine
after
the
engine
is
removed
from
the
location.
Operating
hours
means:
(
1)
For
engine
storage
areas
or
facilities,
times
during
which
people
other
than
custodians
and
security
personnel
are
at
work
near,
and
can
access,
a
storage
area
or
facility.
(
2)
For
other
areas
or
facilities,
times
during
which
an
assembly
line
operates
or
any
of
the
following
activities
occurs:
(
i)
Testing,
maintenance,
or
service
accumulation.
(
ii)
Production
or
compilation
of
records.
(
iii)
Certification
testing.
(
iv)
Translation
of
designs
from
the
test
stage
to
the
production
stage.
(
v)
Engine
manufacture
or
assembly.
Piece
of
equipment
means
any
vehicle,
vessel,
locomotive,
aircraft,
or
other
type
of
equipment
using
engines
to
which
this
part
applies.
Placed
into
service
means
used
for
its
intended
purpose.
Reasonable
technical
basis
means
information
that
would
lead
a
person
familiar
with
engine
design
and
function
to
reasonably
believe
a
conclusion,
related
to
compliance
with
the
requirements
of
this
part.
For
example,
it
would
be
reasonable
to
believe
that
parts
performing
the
same
function
as
the
original
parts
(
and
to
the
same
degree)
would
control
emissions
to
the
same
degree
as
the
original
parts.
Standard
setting
part
means
the
part
in
the
Code
of
Federal
Regulations
that
defines
emission
standards
for
a
particular
engine
(
see
§
1068.1(
a)).
For
example,
the
standard
setting
part
for
non
recreational
spark
ignition
engines
over
19
kW
is
part
1048
of
this
chapter.
Ultimate
purchaser
means
the
first
person
who
in
good
faith
buys
a
new
engine
for
purposes
other
than
resale.
United
States
means
the
States,
the
District
of
Columbia,
the
Commonwealth
of
Puerto
Rico,
the
Commonwealth
of
the
Northern
Mariana
Islands,
Guam,
American
Samoa,
the
U.
S.
Virgin
Islands,
and
the
Trust
Territory
of
the
Pacific
Islands.
We
(
us,
our)
means
the
Administrator
of
the
Environmental
Protection
Agency
and
any
authorized
representatives.
§
1068.35
What
symbols,
acronyms,
and
abbreviations
does
this
part
use?
The
following
symbols,
acronyms,
and
abbreviations
apply
to
this
part:
$
U.
S.
dollars.
CFR
Code
of
Federal
Regulations.
EPA
Environmental
Protection
Agency.
U.
S.
United
States.
U.
S.
C.
United
States
Code.
Subpart
B
Prohibited
Actions
and
Related
Requirements
§
1068.101
What
general
actions
does
this
regulation
prohibit?
This
section
specifies
actions
that
are
prohibited
and
the
maximum
civil
penalties
that
we
can
assess
for
each
violation.
The
maximum
penalty
values
listed
in
paragraphs
(
a)
and
(
b)
of
this
section
are
shown
for
calendar
year
2002.
As
described
in
paragraph
(
e)
of
this
section,
maximum
penalty
limits
for
later
years
are
set
forth
in
40
CFR
part
19.
(
a)
The
following
prohibitions
and
requirements
apply
to
manufacturers
of
new
engines
and
manufacturers
of
equipment
containing
these
engines,
except
as
described
in
subparts
C
and
D
of
this
part:
(
1)
You
may
not
sell,
offer
for
sale,
or
introduce
or
deliver
into
commerce
in
the
United
States
or
import
into
the
United
States
any
new
engine
or
equipment
after
emission
standards
take
effect
for
that
engine
or
equipment,
unless
it
has
a
valid
certificate
of
conformity
for
its
model
year
and
the
required
label
or
tag.
You
also
may
not
take
any
of
the
actions
listed
in
the
previous
sentence
with
respect
to
any
equipment
containing
an
engine
subject
to
this
part's
provisions,
unless
the
engine
has
a
valid
certificate
of
conformity
for
its
model
year
and
the
required
engine
label
or
tag.
This
requirement
also
covers
new
engines
you
produce
to
replace
an
older
engine
in
a
piece
of
equipment,
unless
the
engine
qualifies
for
the
replacementengine
exemption
in
§
1068.240.
We
may
assess
a
civil
penalty
up
to
$
31,500
for
each
engine
in
violation.
(
2)
This
chapter
requires
you
to
record
certain
types
of
information
to
show
that
you
meet
our
standards.
You
must
comply
with
these
requirements
to
make
and
maintain
required
records
(
including
those
described
in
§
1068.501).
You
may
not
deny
us
access
to
or
copying
of
your
records
if
we
have
the
authority
to
see
or
copy
them.
Also,
you
must
give
us
the
required
reports
or
information
without
delay.
Failure
to
comply
with
the
requirements
of
this
paragraph
is
prohibited.
We
may
assess
a
civil
penalty
up
to
$
31,500
for
each
day
in
violation.
(
3)
You
may
not
keep
us
from
entering
your
facility
to
test
engines
or
inspect
if
we
are
authorized
to
do
so.
Also,
you
must
perform
the
tests
we
require
(
or
have
the
tests
done
for
you).
Failure
to
perform
this
testing
is
prohibited.
We
may
assess
a
civil
penalty
up
to
$
31,500
for
each
day
in
violation.
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Vol.
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217
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Friday,
November
8,
2002
/
Rules
and
Regulations
(
b)
The
following
prohibitions
apply
to
everyone
with
respect
to
the
engines
to
which
this
part
applies:
(
1)
You
may
not
remove
or
disable
a
device
or
element
of
design
that
may
affect
an
engine's
emission
levels.
This
restriction
applies
before
and
after
the
engine
is
placed
in
service.
Section
1068.120
describes
how
this
applies
to
rebuilding
engines.
For
a
manufacturer
or
dealer,
we
may
assess
a
civil
penalty
up
to
$
31,500
for
each
engine
in
violation.
For
anyone
else,
we
may
assess
a
civil
penalty
up
to
$
3,150
for
each
engine
in
violation.
This
does
not
apply
in
any
of
the
following
situations:
(
i)
You
need
to
repair
an
engine
and
you
restore
it
to
proper
functioning
when
the
repair
is
complete.
(
ii)
You
need
to
modify
an
engine
to
respond
to
a
temporary
emergency
and
you
restore
it
to
proper
functioning
as
soon
as
possible.
(
iii)
You
modify
a
new
engine
that
another
manufacturer
has
already
certified
to
meet
emission
standards,
intending
to
recertify
it
under
your
own
engine
family.
In
this
case
you
must
tell
the
original
manufacturer
not
to
include
the
modified
engines
in
the
original
engine
family.
(
2)
You
may
not
knowingly
manufacture,
sell,
offer
to
sell,
or
install,
an
engine
part
if
one
of
its
main
effects
is
to
bypass,
impair,
defeat,
or
disable
the
engine's
control
of
emissions.
We
may
assess
a
civil
penalty
up
to
$
3,150
for
each
part
in
violation.
(
3)
For
an
engine
that
is
excluded
from
any
requirements
of
this
chapter
because
it
is
a
stationary
engine,
you
may
not
move
it
or
install
it
in
any
mobile
equipment,
except
as
allowed
by
the
provisions
of
this
chapter.
You
may
not
circumvent
or
attempt
to
circumvent
the
residence
time
requirements
of
paragraph
(
2)(
iii)
of
the
nonroad
engine
definition
in
§
1068.30.
We
may
assess
a
civil
penalty
up
to
$
31,500
for
each
day
in
violation.
(
4)
For
an
uncertified
engine
or
piece
of
equipment
that
is
excluded
or
exempted
from
any
requirements
of
this
chapter
because
it
is
to
be
used
solely
for
competition,
you
may
not
use
it
in
a
manner
that
is
inconsistent
with
use
solely
for
competition.
We
may
assess
a
civil
penalty
up
to
$
31,500
for
each
day
in
violation.
(
5)
You
may
not
import
an
uncertified
engine
or
piece
of
equipment
if
it
is
defined
to
be
new
in
the
standardsetting
part,
and
it
would
have
been
subject
to
standards
had
it
been
built
in
the
United
States.
We
may
assess
a
civil
penalty
up
to
$
31,500
for
each
day
in
violation.
Note
the
following:
(
i)
The
definition
of
new
is
broad
for
imported
engines;
uncertified
engines
and
equipment
(
including
used
engines
and
equipment)
are
generally
considered
to
be
new
when
imported.
(
ii)
Engines
that
were
originally
manufactured
before
applicable
EPA
standards
were
in
effect
are
generally
not
subject
to
emission
standards.
(
c)
Exemptions
from
these
prohibitions
are
described
in
subparts
C
and
D
of
this
part.
(
d)
The
standard
setting
parts
describe
more
requirements
and
prohibitions
that
apply
to
manufacturers
(
including
importers)
and
others
under
this
chapter.
(
e)
The
maximum
penalty
values
listed
in
paragraphs
(
a)
and
(
b)
of
this
section
are
shown
for
calendar
year
2002.
Maximum
penalty
limits
for
later
years
may
be
adjusted
based
on
the
Consumer
Price
Index.
The
specific
regulatory
provisions
for
changing
the
maximum
penalties,
published
in
40
CFR
part
19,
reference
the
applicable
U.
S.
Code
citation
on
which
the
prohibited
action
is
based.
The
following
table
is
shown
here
for
informational
purposes:
TABLE
1
OF
§
1068.101.
LEGAL
CITATION
FOR
SPECIFIC
PROHIBITIONS
FOR
DETERMINING
MAXIMUM
PENALTY
AMOUNTS
Part
1068
regulatory
citation
of
prohibited
action
General
description
of
prohibition
U.
S.
Code
citation
for
Clean
Air
Act
authority
§
1068.101(
a)(
1)
................................................................
Introduction
into
commerce
of
an
uncertified
product
....
42
U.
S.
C.
7522(
a)(
1)
§
1068.101(
a)(
1)
................................................................
Failure
to
provide
information
.........................................
42
U.
S.
C.
7522(
a)(
2)
§
1068.101(
a)(
3)
................................................................
Denying
access
to
facilities
.............................................
42
U.
S.
C.
7522(
a)(
2)
§
1068.101(
b)(
1)
................................................................
Tampering
with
emission
controls
by
a
manufacturer
or
dealer.
42
U.
S.
C.
7522(
a)(
3)
Tampering
with
emission
controls
by
someone
other
than
a
manufacturer
or
dealer.
§
1068.101(
b)(
2)
................................................................
Sale
or
use
of
a
defeat
device
........................................
42
U.
S.
C.
7522(
a)(
3)
§
1068.101(
b)(
3)
................................................................
Mobile
use
of
a
stationary
engine
...................................
42
U.
S.
C.
7522(
a)(
1)
§
1068.101(
b)(
4)
................................................................
Noncompetitive
use
of
an
uncertified
engine
that
is
exempted
for
competition.
42
U.
S.
C.
7522(
a)(
1)
§
1068.101(
b)(
5)
................................................................
Importation
of
an
uncertified
product
..............................
42
U.
S.
C.
7522(
a)(
1)
§
1068.105
What
other
provisions
apply
to
me
specifically
if
I
manufacture
equipment
needing
certified
engines?
(
a)
Transitioning
to
new
standards.
You
may
use
up
your
normal
inventory
of
engines
not
certified
to
new
emission
standards
if
they
were
built
before
the
date
of
the
new
standards.
However,
stockpiling
these
engines
violates
§
1068.101(
a)(
1).
(
b)
Installing
engines.
You
must
follow
the
engine
manufacturer's
emission
related
installation
instructions.
For
example,
you
may
need
to
constrain
where
you
place
an
exhaust
aftertreatment
device
or
integrate
into
your
equipment
models
a
device
for
sending
visual
or
audible
signals
to
the
operator.
Not
meeting
the
manufacturer's
emission
related
installation
instructions
is
a
violation
of
§
1068.101(
b)(
1).
(
c)
Attaching
a
duplicate
label.
If
you
obscure
the
engine's
label,
you
must
do
three
things
to
avoid
violating
§
1068.101(
a)(
1):
(
1)
Permanently
attach
to
your
equipment
a
duplicate
label.
Secure
it
to
a
part
needed
for
normal
operation
and
not
normally
requiring
replacement.
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Rules
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Regulations
(
2)
Make
sure
your
label
is
identical
to
the
engine
label.
You
may
make
the
label
yourself
or
get
it
from
the
engine
manufacturer.
(
3)
Make
sure
an
average
person
can
easily
read
it.
(
d)
Producing
nonroad
equipment
certified
to
highway
emission
standards.
You
may
produce
nonroad
equipment
from
complete
or
incomplete
motor
vehicles
with
the
motor
vehicle
engine
if
you
meet
three
criteria:
(
1)
The
engine
or
vehicle
is
certified
to
40
CFR
part
86.
(
2)
The
engine
is
not
adjusted
outside
the
manufacturer's
specifications.
(
3)
The
engine
or
vehicle
is
not
modified
in
any
way
that
may
affect
its
emission
control.
This
applies
to
evaporative
emission
controls,
but
not
refueling
emission
controls.
§
1068.110
What
other
provisions
apply
to
engines
in
service?
(
a)
Aftermarket
parts
and
service.
As
the
engine
manufacturer,
you
may
not
require
anyone
to
use
your
parts
or
service
to
maintain
or
repair
an
engine,
unless
we
approve
this
in
your
application
for
certification.
It
is
a
violation
of
the
Act
for
anyone
to
manufacture
an
engine
or
vehicle
part
if
one
of
its
main
effects
is
to
reduce
the
effectiveness
of
the
emission
controls.
See
§
1068.101(
b)(
2).
(
b)
Certifying
aftermarket
parts.
As
the
manufacturer
or
rebuilder
of
an
aftermarket
engine
part,
you
may
but
are
not
required
to
certify
according
to
§
85.2114
of
this
chapter
that
using
the
part
will
not
cause
engines
to
fail
to
meet
emission
standards.
Whether
you
certify
or
not,
however,
you
must
keep
any
information
showing
how
your
parts
or
service
affect
emissions.
(
c)
Compliance
with
standards.
We
may
test
engines
or
equipment
to
investigate
compliance
with
emission
standards.
We
may
also
require
the
manufacturer
to
do
this
testing.
(
d)
Defeat
devices.
We
may
test
engines
or
equipment
to
investigate
potential
defeat
devices.
We
may
also
require
the
manufacturer
to
do
this
testing.
If
we
choose
to
investigate
one
of
your
designs,
we
may
require
you
to
show
us
that
it
does
not
have
a
defeat
device.
To
do
this,
you
may
have
to
share
with
us
information
regarding
test
programs,
engineering
evaluations,
design
specifications,
calibrations,
onboard
computer
algorithms,
and
design
strategies.
It
is
a
violation
of
the
Act
for
anyone
to
make,
install
or
use
defeat
devices.
See
§
1068.101(
b)(
2)
and
the
standard
setting
part.
(
e)
Warranty
and
maintenance.
Owners
may
make
warranty
claims
against
the
manufacturer
for
emissionrelated
parts,
as
described
in
§
1068.115.
This
generally
includes
any
emissionrelated
engine
parts
that
were
not
in
common
use
before
we
have
adopted
emission
standards.
In
general,
we
consider
replacement
or
repair
of
any
other
components
to
be
the
owner's
responsibility.
The
warranty
period
begins
when
the
engine
is
first
placed
into
service.
See
the
standard
setting
part
for
specific
requirements.
It
is
a
violation
of
the
Act
for
anyone
to
disable
emission
controls.
See
§
1068.101(
b)(
1)
and
the
standardsetting
part.
§
1068.115
When
must
manufacturers
honor
emission
related
warranty
claims?
Section
207(
a)
of
the
Clean
Air
Act
(
42
U.
S.
C.
7541(
a))
requires
certifying
manufacturers
to
warrant
to
purchasers
that
their
engines
are
designed,
built,
and
equipped
to
conform
at
the
time
of
sale
to
the
applicable
regulations
for
their
full
useful
life,
including
a
warranty
that
the
engines
are
free
from
defects
in
materials
and
workmanship
that
would
cause
an
engine
to
fail
to
conform
to
the
applicable
regulations
during
the
specified
warranty
period.
This
section
codifies
the
warranty
requirements
of
section
207(
a)
without
intending
to
limit
these
requirements.
(
a)
As
a
certifying
manufacturer,
you
may
deny
warranty
claims
for
failures
that
have
been
caused
by
the
owner's
or
operator's
improper
maintenance
or
use.
For
example,
you
would
not
need
to
honor
warranty
claims
for
failures
that
have
been
directly
caused
by
the
operator's
abuse
of
an
engine
or
the
operator's
use
of
the
engine
in
a
manner
for
which
it
was
not
designed,
and
are
not
attributable
to
you
in
any
way.
(
b)
As
a
certifying
manufacturer,
you
may
not
deny
emission
related
warranty
claims
based
on
any
of
the
following:
(
1)
Maintenance
or
other
service
you
or
your
authorized
facilities
performed.
(
2)
Engine
repair
work
that
an
operator
performed
to
correct
an
unsafe,
emergency
condition
attributable
to
you,
as
long
as
the
operator
tries
to
restore
the
engine
to
its
proper
configuration
as
soon
as
possible.
(
3)
Any
action
or
inaction
by
the
operator
unrelated
to
the
warranty
claim.
(
4)
Maintenance
that
was
performed
more
frequently
than
you
specify.
(
5)
Anything
that
is
your
fault
or
responsibility.
(
6)
The
use
of
any
fuel
that
is
commonly
available
where
the
engine
operates,
unless
your
written
maintenance
instructions
state
that
this
fuel
would
harm
the
engine's
emission
control
system
and
operators
can
readily
find
the
proper
fuel.
§
1068.120
What
requirements
must
I
follow
to
rebuild
engines?
(
a)
This
section
describes
the
steps
to
take
when
rebuilding
engines
to
avoid
violating
the
tampering
prohibition
in
§
1068.101(
b)(
1).
These
requirements
apply
to
anyone
rebuilding
an
engine
subject
to
this
part,
but
the
recordkeeping
requirements
in
paragraphs
(
j)
and
(
k)
of
this
section
apply
only
to
businesses.
(
b)
The
term
``
rebuilding''
refers
to
a
rebuild
of
an
engine
or
engine
system,
including
a
major
overhaul
in
which
you
replace
the
engine's
pistons
or
power
assemblies
or
make
other
changes
that
significantly
increase
the
service
life
of
the
engine.
It
also
includes
replacing
or
rebuilding
an
engine's
turbocharger
or
aftercooler
or
the
engine's
systems
for
fuel
metering
or
electronic
control
so
that
it
significantly
increases
the
service
life
of
the
engine.
For
these
provisions,
rebuilding
may
or
may
not
involve
removing
the
engine
from
the
equipment.
Rebuilding
does
not
normally
include
the
following:
(
1)
Scheduled
emission
related
maintenance
that
the
standard
setting
part
allows
during
the
useful
life
period
(
such
as
replacing
fuel
injectors).
(
2)
Unscheduled
maintenance
that
occurs
commonly
within
the
useful
life
period.
For
example,
replacing
a
water
pump
is
not
rebuilding.
(
c)
For
maintenance
or
service
that
is
not
rebuilding,
you
may
not
make
changes
that
might
increase
emissions,
but
you
do
not
need
to
keep
any
records.
(
d)
If
you
rebuild
an
engine
or
engine
system,
you
must
have
a
reasonable
technical
basis
for
knowing
that
the
rebuilt
engine
has
the
same
emissions
performance
as
the
engine
in
its
certified
configuration.
Identify
the
model
year
of
the
resulting
engine
configuration.
You
have
a
reasonable
basis
if
you
meet
two
main
conditions:
(
1)
Install
parts
new,
used,
or
rebuilt
so
a
person
familiar
with
engine
design
and
function
would
reasonably
believe
that
the
engine
with
those
parts
will
control
emissions
to
the
same
degree
as
with
the
original
parts.
For
example,
it
would
be
reasonable
to
believe
that
parts
performing
the
same
function
as
the
original
parts
(
and
to
the
same
degree)
would
control
emissions
to
the
same
degree
as
the
original
parts.
(
2)
Adjust
parameters
or
change
design
elements
only
according
to
the
original
engine
manufacturer's
instructions.
Or,
if
you
differ
from
these
instructions,
you
must
have
data
or
some
other
technical
basis
to
show
you
should
not
expect
in
use
emissions
to
increase.
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Rules
and
Regulations
(
e)
If
the
rebuilt
engine
remains
installed
or
is
reinstalled
in
the
same
piece
of
equipment,
you
must
rebuild
it
to
the
original
configuration
or
another
certified
configuration
of
the
same
or
later
model
year.
(
f)
If
the
rebuilt
engine
replaces
another
engine
in
a
piece
of
equipment,
you
must
rebuild
it
to
a
certified
configuration
that
equals
the
emissions
performance
of
the
engine
you
are
replacing.
(
g)
Do
not
erase
or
reset
emissionrelated
codes
or
signals
from
onboard
monitoring
systems
without
diagnosing
and
responding
appropriately
to
any
diagnostic
codes.
This
requirement
applies
regardless
of
the
manufacturer's
reason
for
installing
the
monitoring
system
and
regardless
of
its
form
or
interface.
Clear
any
codes
from
diagnostic
systems
when
you
return
the
rebuilt
engine
to
service.
Do
not
disable
a
diagnostic
signal
without
addressing
its
cause.
(
h)
When
you
rebuild
an
engine,
check,
clean,
adjust,
repair,
or
replace
all
emission
related
components
(
listed
in
Appendix
I
of
this
part)
as
needed
according
to
the
original
manufacturer's
recommended
practice.
In
particular,
replace
oxygen
sensors,
replace
the
catalyst
if
there
is
evidence
of
malfunction,
clean
gaseous
fuel
system
components,
and
replace
fuel
injectors
(
if
applicable),
unless
you
have
a
reasonable
technical
basis
for
believing
they
do
not
need
replacement.
(
i)
If
you
are
installing
an
engine
that
someone
else
has
rebuilt,
check
all
emission
related
components
listed
in
Appendix
I
of
this
part
as
needed
according
to
the
original
manufacturer's
recommended
practice.
(
j)
Keep
at
least
the
following
records:
(
1)
Identify
the
hours
of
operation
(
or
mileage,
as
appropriate)
at
time
of
rebuild.
(
2)
Identify
the
work
done
on
the
engine
or
any
emission
related
control
components,
including
a
listing
of
parts
and
components
you
used.
(
3)
Describe
any
engine
parameter
adjustments.
(
4)
Identify
any
emission
related
codes
or
signals
you
responded
to
and
reset.
(
k)
You
must
show
us
or
send
us
your
records
if
we
ask
for
them.
Keep
records
for
at
least
two
years
after
rebuilding
an
engine.
Keep
them
in
any
format
that
allows
us
to
readily
review
them.
(
1)
You
do
not
need
to
keep
information
that
is
not
reasonably
available
through
normal
business
practices.
We
do
not
expect
you
to
have
information
that
you
cannot
reasonably
access.
(
2)
You
do
not
need
to
keep
records
of
what
other
companies
do.
(
3)
You
may
keep
records
based
on
engine
families
rather
than
individual
engines
if
that
is
the
way
you
normally
do
business.
§
1068.125
What
happens
if
I
violate
the
regulations?
(
a)
Civil
penalties
and
injunctions.
We
may
bring
a
civil
action
to
assess
and
recover
civil
penalties
and/
or
enjoin
and
restrain
violations
in
the
United
States
District
Court
for
the
district
where
you
allegedly
violated
a
requirement,
or
the
district
where
you
live
or
have
your
main
place
of
business.
Actions
to
assess
civil
penalties
or
restrain
violations
of
§
1068.101
must
be
brought
by
and
in
the
name
of
the
United
States.
The
selected
court
has
jurisdiction
to
restrain
violations
and
assess
civil
penalties.
(
1)
To
determine
the
amount
of
a
civil
penalty
and
reach
a
just
conclusion,
the
court
considers
these
main
factors:
(
i)
The
seriousness
of
your
violation.
(
ii)
How
much
you
benefitted
or
saved
because
of
the
violation.
(
iii)
The
size
of
your
business.
(
iv)
Your
history
of
compliance
with
Title
II
of
the
Act.
(
v)
What
you
did
to
remedy
the
violation.
(
vi)
How
the
penalty
will
affect
your
ability
to
continue
in
business.
(
vii)
Such
other
matters
as
justice
may
require.
(
2)
Subpoenas
for
witnesses
who
must
attend
a
district
court
in
any
district
may
apply
to
any
other
district.
(
b)
Administrative
penalties.
Instead
of
bringing
a
civil
action,
we
may
assess
administrative
penalties
if
the
total
is
less
than
$
250,000
against
you
individually.
This
maximum
penalty
may
be
greater
if
the
Administrator
and
the
Attorney
General
jointly
determine
that
is
appropriate
for
administrative
penalty
assessment,
or
if
the
limit
is
adjusted
under
40
CFR
part
19.
No
court
may
review
such
a
determination.
Before
we
assess
an
administrative
penalty,
you
may
ask
for
a
hearing
(
subject
to
40
CFR
part
22).
The
Administrator
may
compromise
or
remit,
with
or
without
conditions,
any
administrative
penalty
that
may
be
imposed
under
this
section.
(
1)
To
determine
the
amount
of
an
administrative
penalty,
we
will
consider
the
factors
described
in
paragraph
(
a)(
1)
of
this
section.
(
2)
An
administrative
order
we
issue
under
this
paragraph
(
b)
becomes
final
30
days
after
we
issue
it,
unless
you
ask
for
judicial
review
by
that
time
(
see
paragraph
(
c)
of
this
section).
You
may
ask
for
review
by
any
of
the
district
courts
listed
in
paragraph
(
a)
of
this
section.
Send
the
Administrator
a
copy
of
the
filing
by
certified
mail.
(
3)
We
will
not
pursue
an
administrative
action
for
a
violation
if
either
of
the
following
two
conditions
is
true:
(
i)
We
are
separately
prosecuting
the
violation
under
this
part.
(
ii)
We
have
issued
a
final
order
for
a
violation,
no
longer
subject
to
judicial
review,
for
which
you
have
already
paid
a
penalty.
(
c)
Judicial
review.
If
you
ask
a
court
to
review
a
civil
or
administrative
penalty,
we
will
file
in
the
appropriate
court
within
30
days
of
your
request
a
certified
copy
or
certified
index
of
the
record
on
which
the
court
or
the
Administrator
issued
the
order.
(
1)
The
judge
may
set
aside
or
remand
any
order
issued
under
this
section
only
if
one
of
the
following
is
true:
(
i)
Substantial
evidence
does
not
exist
in
the
record,
taken
as
a
whole,
to
support
finding
a
violation.
(
ii)
The
Administrator's
assessment
of
the
penalty
is
an
abuse
of
discretion.
(
2)
The
judge
may
not
add
civil
penalties
unless
our
penalty
is
an
abuse
of
discretion
that
favors
you.
(
d)
Effect
of
enforcement
actions
on
other
requirements.
Our
pursuit
of
civil
or
administrative
penalties
does
not
affect
or
limit
our
authority
to
enforce
any
provisions
of
this
chapter.
(
e)
Penalties.
In
any
proceedings,
the
United
States
government
may
seek
to
collect
civil
penalties
assessed
under
this
section.
(
1)
Once
a
penalty
assessment
is
final,
if
you
do
not
pay
it,
the
Administrator
will
ask
the
Attorney
General
to
bring
a
civil
action
in
an
appropriate
district
court
to
recover
the
money.
We
may
collect
interest
from
the
date
of
the
final
order
or
final
judgment
at
rates
established
by
the
Internal
Revenue
Code
of
1986
(
26
U.
S.
C.
6621(
a)(
2)).
In
this
action
to
collect
overdue
penalties,
the
court
will
not
review
the
validity,
amount,
and
appropriateness
of
the
penalty.
(
2)
In
addition,
if
you
do
not
pay
the
full
amount
of
a
penalty
on
time,
you
must
then
pay
more
to
cover
interest,
enforcement
expenses
(
including
attorney's
fees
and
costs
for
collection),
and
a
quarterly
nonpayment
penalty
for
each
quarter
you
do
not
pay.
The
nonpayment
penalty
is
10
percent
of
your
total
penalties
plus
any
unpaid
nonpayment
penalties
from
previous
quarters.
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/
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8,
2002
/
Rules
and
Regulations
Subpart
C
Exemptions
and
Exclusions
§
1068.201
Does
EPA
exempt
or
exclude
any
engines
from
the
prohibited
acts?
We
may
exempt
new
engines
from
the
prohibited
acts
in
subpart
B
of
this
part
under
requirements
described
in
this
subpart.
We
may
exempt
an
engine
already
placed
in
service
in
the
United
States
from
the
prohibition
in
§
1068.101(
b)(
1)
if
the
exemption
for
engines
used
solely
for
competition
applies
(
see
§
1068.235).
In
addition,
see
§
1068.1
and
the
standard
setting
parts
to
determine
if
other
engines
are
excluded
from
some
or
all
of
the
regulations
in
this
chapter.
(
a)
This
subpart
identifies
which
engines
qualify
for
exemptions
and
what
information
we
need.
We
may
ask
for
more
information.
(
b)
If
you
violate
any
of
the
terms,
conditions,
instructions,
or
requirements
to
qualify
for
an
exemption,
we
may
void
the
exemption.
(
c)
If
you
use
an
exemption
under
this
subpart,
we
may
require
you
to
add
a
permanent
label
to
your
exempted
engines.
You
may
ask
us
to
approve
wording
on
the
emission
label
different
than
we
specify
in
this
subpart
if
it
is
more
appropriate
for
your
engine.
(
d)
If
you
produce
engines
we
exempt
under
this
subpart,
we
may
require
you
to
make
and
keep
records,
perform
tests,
make
reports
and
provide
information
as
needed
to
reasonably
evaluate
the
validity
of
the
exemption.
(
e)
If
you
own
or
operate
engines
we
exempt
under
this
subpart,
we
may
require
you
to
provide
information
as
needed
to
reasonably
evaluate
the
validity
of
the
exemption.
(
f)
Subpart
D
of
this
part
describes
how
we
apply
these
exemptions
to
engines
you
import
(
or
intend
to
import).
(
g)
If
you
want
to
ask
for
an
exemption
or
need
more
information,
write
to
the
Designated
Officer.
(
h)
You
may
ask
us
to
modify
the
administrative
requirements
for
the
exemptions
described
in
this
subpart.
We
may
approve
your
request
if
we
determine
that
such
approval
is
consistent
with
the
intent
of
this
part.
For
example,
waivable
administrative
requirements
might
include
some
reporting
requirements,
but
would
not
include
any
eligibility
requirements
or
use
restrictions.
(
i)
If
you
want
to
take
an
action
with
respect
to
an
exempted
or
excluded
engine
that
is
prohibited
by
the
exemption
or
exclusion,
such
as
selling
it,
you
need
to
certify
the
engine.
We
will
issue
a
certificate
of
conformity
if
you
send
us
an
application
for
certification
showing
that
you
meet
all
the
applicable
requirements
from
the
standard
setting
part.
Also,
in
some
cases,
it
may
be
sufficient
to
modify
the
engine
as
needed
to
make
it
identical
to
engines
already
covered
by
a
certificate.
Make
sure
these
engines
have
emission
control
information
labels
that
accurately
describe
their
status.
§
1068.210
What
are
the
provisions
for
exempting
test
engines?
(
a)
We
may
exempt
engines
that
are
not
exempted
under
other
sections
of
this
part
that
you
will
use
for
research,
investigations,
studies,
demonstrations,
or
training.
(
b)
Anyone
may
ask
for
a
testing
exemption.
(
c)
If
you
are
a
certificate
holder,
you
may
request
an
exemption
for
engines
you
intend
to
include
in
test
programs
over
a
two
year
period.
(
1)
In
your
request,
tell
us
the
maximum
number
of
engines
involved
and
describe
how
you
will
make
sure
exempted
engines
are
used
only
for
this
testing.
(
2)
Give
us
the
information
described
in
paragraph
(
d)
of
this
section
if
we
ask
for
it.
(
d)
If
you
are
not
a
certificate
holder
do
all
of
the
following:
(
1)
Show
that
the
proposed
test
program
has
a
valid
purpose
under
paragraph
(
a)
of
this
section.
(
2)
Show
you
need
an
exemption
to
achieve
the
purpose
of
the
test
program
(
time
constraints
may
be
a
basis
for
needing
an
exemption,
but
the
cost
of
certification
alone
is
not).
(
3)
Estimate
the
duration
of
the
proposed
test
program
and
the
number
of
engines
involved.
(
4)
Allow
us
to
monitor
the
testing.
(
5)
Describe
how
you
will
ensure
that
you
stay
within
this
exemption's
purposes.
Address
at
least
the
following
things:
(
i)
The
technical
nature
of
the
test.
(
ii)
The
test
site.
(
iii)
The
duration
and
accumulated
engine
operation
associated
with
the
test.
(
iv)
Ownership
of
the
engines
involved
in
the
test.
(
v)
The
intended
final
disposition
of
the
engines.
(
vi)
How
you
will
identify,
record,
and
make
available
the
engine
identification
numbers.
(
vii)
The
means
or
procedure
for
recording
test
results.
(
e)
If
we
approve
your
request
for
a
testing
exemption,
we
will
send
you
a
letter
or
a
memorandum
for
your
signature
describing
the
basis
and
scope
of
the
exemption.
The
exemption
does
not
take
effect
until
we
receive
the
signed
letter
or
memorandum
from
you.
It
will
also
include
any
necessary
terms
and
conditions,
which
normally
require
you
to
do
the
following:
(
1)
Stay
within
the
scope
of
the
exemption.
(
2)
Create
and
maintain
adequate
records
that
we
may
inspect.
(
3)
Add
a
permanent,
legible
label,
written
in
block
letters
in
English,
to
a
readily
visible
part
of
each
exempted
engine.
This
label
must
include
at
least
the
following
items:
(
i)
The
label
heading
``
EMISSION
CONTROL
INFORMATION''.
(
ii)
Your
corporate
name
and
trademark.
(
iii)
Engine
displacement,
engine
family
identification
(
as
applicable),
and
model
year
of
the
engine;
or
whom
to
contact
for
further
information.
(
iv)
The
statement
``
THIS
ENGINE
IS
EXEMPT
UNDER
40
CFR
1068.210
FROM
EMISSION
STANDARDS
AND
RELATED
REQUIREMENTS.''.
(
4)
Tell
us
when
the
test
program
is
finished.
(
5)
Tell
us
the
final
disposition
of
the
engines.
(
6)
Send
us
a
written
confirmation
that
you
meet
the
terms
and
conditions
of
this
exemption.
§
1068.215
What
are
the
provisions
for
exempting
manufacturer
owned
engines?
(
a)
You
are
eligible
for
the
exemption
for
manufacturer
owned
engines
only
if
you
are
a
certificate
holder.
(
b)
An
engine
may
be
exempt
without
a
request
if
it
is
a
nonconforming
engine
under
your
ownership
and
control
and
you
operate
it
to
develop
products,
assess
production
methods,
or
promote
your
engines
in
the
marketplace.
You
may
not
lease,
sell,
or
use
the
engine
to
generate
revenue,
either
by
itself
or
in
a
piece
of
equipment.
(
c)
To
use
this
exemption,
you
must
do
three
things:
(
1)
Establish,
maintain,
and
keep
adequately
organized
and
indexed
information
on
each
exempted
engine,
including
the
engine
identification
number,
the
use
of
the
engine
on
exempt
status,
and
the
final
disposition
of
any
engine
removed
from
exempt
status.
(
2)
Let
us
access
these
records,
as
described
in
§
1068.20.
(
3)
Add
a
permanent,
legible
label,
written
in
block
letters
in
English,
to
a
readily
visible
part
of
each
exempted
engine.
This
label
must
include
at
least
the
following
items:
(
i)
The
label
heading
``
EMISSION
CONTROL
INFORMATION''.
(
ii)
Your
corporate
name
and
trademark.
(
iii)
Engine
displacement,
engine
family
identification,
and
model
year
of
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Friday,
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2002
/
Rules
and
Regulations
the
engine
or
whom
to
contact
for
further
information.
(
iv)
The
statement
``
THIS
ENGINE
IS
EXEMPT
UNDER
40
CFR
1068.215
FROM
EMISSION
STANDARDS
AND
RELATED
REQUIREMENTS.''.
§
1068.220
What
are
the
provisions
for
exempting
display
engines?
(
a)
Anyone
may
request
an
exemption
for
display
engines.
(
b)
A
nonconforming
display
engine
will
be
exempted
if
it
is
used
only
for
displays
in
the
interest
of
a
business
or
the
general
public.
This
exemption
does
not
apply
to
engines
displayed
for
private
use
or
any
other
purpose
we
determine
is
inappropriate
for
a
display
exemption.
(
c)
You
may
operate
the
exempted
engine,
but
only
if
we
approve
specific
operation
that
is
part
of
the
display.
(
d)
You
may
sell
or
lease
the
exempted
engine
only
with
our
advance
approval;
you
may
not
use
it
to
generate
revenue.
(
e)
To
use
this
exemption,
you
must
add
a
permanent,
legible
label,
written
in
block
letters
in
English,
to
a
readily
visible
part
of
each
exempted
engine.
This
label
must
include
at
least
the
following
items:
(
1)
The
label
heading
``
EMISSION
CONTROL
INFORMATION''.
(
2)
Your
corporate
name
and
trademark.
(
3)
Engine
displacement,
engine
family
identification,
and
model
year
of
the
engine
or
whom
to
contact
for
further
information.
(
4)
The
statement
``
THIS
ENGINE
IS
EXEMPT
UNDER
40
CFR
1068.220
FROM
EMISSION
STANDARDS
AND
RELATED
REQUIREMENTS.''.
(
f)
We
may
set
other
conditions
for
approval
of
this
exemption.
§
1068.225
What
are
the
provisions
for
exempting
engines
for
national
security?
(
a)
You
are
eligible
for
the
exemption
for
national
security
only
if
you
are
a
manufacturer.
(
b)
Your
engine
is
exempt
without
a
request
if
you
produce
it
for
a
piece
of
equipment
owned
or
used
by
an
agency
of
the
federal
government
responsible
for
national
defense,
where
the
equipment
has
armor,
permanently
attached
weaponry,
or
other
substantial
features
typical
of
military
combat.
(
c)
You
may
request
a
national
security
exemption
for
engines
not
meeting
the
conditions
of
paragraph
(
b)
of
this
section,
as
long
as
your
request
is
endorsed
by
an
agency
of
the
federal
government
responsible
for
national
defense.
In
your
request,
explain
why
you
need
the
exemption.
§
1068.230
What
are
the
provisions
for
exempting
engines
for
export?
(
a)
If
you
export
a
new
engine
to
a
country
with
emission
standards
identical
to
ours,
we
will
not
exempt
it.
These
engines
must
comply
with
our
certification
requirements.
(
b)
If
you
export
an
engine
to
a
country
with
different
emission
standards
or
no
emission
standards,
it
is
exempt
from
the
prohibited
acts
in
this
part
without
a
request.
If
you
produce
an
exempt
engine
for
export
and
it
is
sold
or
offered
for
sale
to
someone
in
the
United
States
(
except
for
export),
we
will
void
the
exemption.
(
c)
Label
each
exempted
engine
and
shipping
container
with
a
label
or
tag
showing
the
engine
is
not
certified
for
sale
or
use
in
the
United
States.
The
label
must
include
at
least
the
statement
``
THIS
ENGINE
IS
SOLELY
FOR
EXPORT
AND
IS
THEREFORE
IS
EXEMPT
UNDER
40
CFR
1068.230
FROM
U.
S.
EMISSION
STANDARDS
AND
RELATED
REQUIREMENTS.''.
§
1068.235
What
are
the
provisions
for
exempting
engines
used
solely
for
competition?
(
a)
New
engines
you
produce
that
are
used
solely
for
competition
are
generally
excluded
from
emission
standards.
See
the
standard
setting
parts
for
specific
provisions
where
applicable.
(
b)
If
you
modify
an
engine
after
it
has
been
placed
into
service
in
the
United
States
so
it
will
be
used
solely
for
competition,
it
is
exempt
without
request.
This
exemption
applies
only
to
the
prohibition
in
§
1068.101(
b)(
1)
and
is
valid
only
as
long
as
the
engine
is
used
solely
for
competition.
(
c)
If
you
modify
an
engine
under
this
exemption,
you
must
destroy
the
original
emission
label.
If
you
sell
or
give
one
of
these
engines
to
someone
else,
you
must
tell
the
new
owner
in
writing
that
it
may
be
used
only
for
competition.
§
1068.240
What
are
the
provisions
for
exempting
new
replacement
engines?
(
a)
You
are
eligible
for
the
exemption
for
new
replacement
engines
only
if
you
are
a
certificate
holder.
(
b)
The
prohibitions
in
§
1068.101(
a)(
1)
do
not
apply
to
an
engine
if
all
the
following
conditions
apply:
(
1)
You
produce
a
new
engine
to
replace
an
engine
already
placed
in
service
in
a
piece
of
equipment.
(
2)
The
engine
being
replaced
was
manufactured
before
the
emission
standards
that
would
otherwise
apply
to
the
new
engine
took
effect.
(
3)
No
engine
certified
to
current
emission
requirements
is
available
with
the
appropriate
physical
or
performance
characteristics
for
the
piece
of
equipment.
(
4)
You
or
your
agent
takes
possession
of
the
old
engine.
(
5)
You
make
the
replacement
engine
in
a
configuration
identical
in
all
material
respects
to
the
engine
being
replaced
(
or
that
of
another
certified
engine
of
the
same
or
later
model
year).
This
requirement
applies
only
if
the
old
engine
was
certified
to
emission
standards
less
stringent
than
those
in
effect
when
you
produce
the
replacement
engine.
(
c)
If
the
old
engine
was
not
certified
to
any
emission
standards
under
this
chapter,
clearly
label
the
replacement
engine
with
the
following
language:
THIS
ENGINE
DOES
NOT
COMPLY
WITH
FEDERAL
NONROAD
OR
HIGHWAY
EMISSION
REQUIREMENTS.
SELLING
OR
INSTALLING
THIS
ENGINE
FOR
ANY
PURPOSE
OTHER
THAN
AS
A
REPLACEMENT
ENGINE
IN
A
VEHICLE
OR
PIECE
OF
EQUIPMENT
BUILT
BEFORE
JANUARY
1,
[
Insert
appropriate
year
reflecting
when
standards
began
to
apply
to
engines
of
that
size
and
type]
IS
A
VIOLATION
OF
FEDERAL
LAW
SUBJECT
TO
CIVIL
PENALTY.
(
d)
If
the
old
engine
was
certified
to
emission
standards
less
stringent
than
those
in
effect
when
you
produce
the
replacement
engine,
clearly
label
the
replacement
engine
with
the
following
language:
THIS
ENGINE
DOES
NOT
COMPLY
WITH
CURRENT
FEDERAL
NONROAD
OR
HIGHWAY
EMISSION
REQUIREMENTS.
SELLING
OR
INSTALLING
THIS
ENGINE
FOR
ANY
PURPOSE
OTHER
THAN
AS
A
REPLACEMENT
ENGINE
IN
A
VEHICLE
OR
PIECE
OF
EQUIPMENT
BUILT
BEFORE
JANUARY
1,
[
Insert
appropriate
year
reflecting
when
the
earlier
tier
of
emission
standards
began
to
apply
to
the
old
engine]
IS
A
VIOLATION
OF
FEDERAL
LAW
SUBJECT
TO
CIVIL
PENALTY.
§
1068.245
What
temporary
provisions
address
hardship
due
to
unusual
circumstances?
(
a)
After
considering
the
circumstances,
we
may
permit
you
to
introduce
into
commerce
engines
or
equipment
that
do
not
comply
with
emission
standards
if
all
the
following
conditions
apply:
(
1)
Unusual
circumstances
that
are
clearly
outside
your
control
and
that
could
not
have
been
avoided
with
reasonable
discretion
prevent
you
from
meeting
requirements
from
this
chapter.
(
2)
You
exercised
prudent
planning
and
were
not
able
to
avoid
the
violation;
you
have
taken
all
reasonable
steps
to
minimize
the
extent
of
the
nonconformity.
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Rules
and
Regulations
(
3)
Not
having
the
exemption
will
jeopardize
the
solvency
of
your
company.
(
4)
No
other
allowances
are
available
under
the
regulations
in
this
chapter
to
avoid
the
impending
violation.
(
b)
To
apply
for
an
exemption,
you
must
send
the
Designated
Officer
a
written
request
as
soon
as
possible
before
you
are
in
violation.
In
your
request,
show
that
you
meet
all
the
conditions
and
requirements
in
paragraph
(
a)
of
this
section.
(
c)
Include
in
your
request
a
plan
showing
how
you
will
meet
all
the
applicable
requirements
as
quickly
as
possible.
(
d)
You
must
give
us
other
relevant
information
if
we
ask
for
it.
(
e)
We
may
include
reasonable
additional
conditions
on
an
approval
granted
under
this
section,
including
provisions
to
recover
or
otherwise
address
the
lost
environmental
benefit
or
paying
fees
to
offset
any
economic
gain
resulting
from
the
exemption.
For
example,
in
the
case
of
multiple
tiers
of
emission
standards,
we
may
require
that
you
meet
the
less
stringent
standards.
(
f)
Add
a
permanent,
legible
label,
written
in
block
letters
in
English,
to
a
readily
visible
part
of
each
engine
exempted
under
this
section.
This
label
must
include
at
least
the
following
items:
(
1)
The
label
heading
``
EMISSION
CONTROL
INFORMATION''.
(
2)
Your
corporate
name
and
trademark.
(
3)
Engine
displacement
(
in
liters),
rated
power,
and
model
year
of
the
engine
or
whom
to
contact
for
further
information.
(
4)
The
statement
``
THIS
ENGINE
IS
EXEMPT
UNDER
40
CFR
1068.245
FROM
EMISSION
STANDARDS
AND
RELATED
REQUIREMENTS.''.
§
1068.250
What
are
the
provisions
for
extending
compliance
deadlines
for
smallvolume
manufacturers
under
hardship?
(
a)
After
considering
the
circumstances,
we
may
extend
the
compliance
deadline
for
you
to
meet
new
or
revised
emission
standards,
as
long
as
you
meet
all
the
conditions
and
requirements
in
this
section.
(
b)
To
be
eligible
for
this
exemption,
you
must
qualify
under
the
standardsetting
part
for
special
provisions
for
small
businesses
or
small
volume
manufacturers.
(
c)
To
apply
for
an
extension,
you
must
send
the
Designated
Officer
a
written
request.
In
your
request,
show
that
all
the
following
conditions
and
requirements
apply:
(
1)
You
have
taken
all
possible
business,
technical,
and
economic
steps
to
comply.
(
i)
In
the
case
of
importers
of
engines
produced
by
other
companies,
show
that
you
attempted
to
find
a
manufacturer
capable
of
supplying
complying
products
as
soon
as
you
became
aware
of
the
applicable
requirements,
but
were
unable
to
do
so.
(
ii)
For
all
other
manufacturers,
show
that
the
burden
of
compliance
costs
prevents
you
from
meeting
the
requirements
of
this
chapter.
(
2)
Not
having
the
exemption
will
jeopardize
the
solvency
of
your
company.
(
3)
No
other
allowances
are
available
under
the
regulations
in
this
chapter
to
avoid
the
impending
violation.
(
d)
In
describing
the
steps
you
have
taken
to
comply
under
paragraph
(
c)(
1)
of
this
section,
include
at
least
the
following
information:
(
1)
Describe
your
business
plan,
showing
the
range
of
projects
active
or
under
consideration.
(
2)
Describe
your
current
and
projected
financial
standing,
with
and
without
the
burden
of
complying
fully
with
the
applicable
regulations
in
this
chapter.
(
3)
Describe
your
efforts
to
raise
capital
to
comply
with
regulations
in
this
chapter
(
this
may
not
apply
for
importers).
(
4)
Identify
the
engineering
and
technical
steps
you
have
taken
or
plan
to
take
to
comply
with
regulations
in
this
chapter.
(
5)
Identify
the
level
of
compliance
you
can
achieve.
For
example,
you
may
be
able
to
produce
engines
that
meet
a
somewhat
less
stringent
emission
standard
than
the
regulations
in
this
chapter
require.
(
e)
Include
in
your
request
a
plan
showing
how
you
will
meet
all
the
applicable
requirements
as
quickly
as
possible.
(
f)
You
must
give
us
other
relevant
information
if
we
ask
for
it.
(
g)
An
authorized
representative
of
your
company
must
sign
the
request
and
include
the
statement:
``
All
the
information
in
this
request
is
true
and
accurate,
to
the
best
of
my
knowledge.''.
(
h)
Send
your
request
for
this
extension
at
least
nine
months
before
the
relevant
deadline.
If
different
deadlines
apply
to
companies
that
are
not
small
volume
manufacturers,
do
not
send
your
request
before
the
regulations
in
question
apply
to
the
other
manufacturers.
Otherwise,
do
not
send
your
request
more
than
three
years
before
the
relevant
deadline.
(
i)
We
may
include
reasonable
requirements
on
an
approval
granted
under
this
section,
including
provisions
to
recover
or
otherwise
address
the
lost
environmental
benefit.
For
example,
we
may
require
that
you
meet
a
less
stringent
emission
standard
or
buy
and
use
available
emission
credits.
(
j)
We
will
approve
extensions
of
up
to
one
year.
We
may
review
and
revise
an
extension
as
reasonable
under
the
circumstances.
(
k)
Add
a
permanent,
legible
label,
written
in
block
letters
in
English,
to
a
readily
visible
part
of
each
engine
exempted
under
this
section.
This
label
must
include
at
least
the
following
items:
(
1)
The
label
heading
``
EMISSION
CONTROL
INFORMATION''.
(
2)
Your
corporate
name
and
trademark.
(
3)
Engine
displacement
(
in
liters),
rated
power,
and
model
year
of
the
engine
or
whom
to
contact
for
further
information.
(
4)
The
statement
``
THIS
ENGINE
IS
EXEMPT
UNDER
40
CFR
1068.250
FROM
EMISSION
STANDARDS
AND
RELATED
REQUIREMENTS.''.
§
1068.255
What
are
the
provisions
for
exempting
engines
for
hardship
for
equipment
manufacturers
and
secondary
engine
manufacturers?
This
section
describes
how,
in
unusual
circumstances,
we
may
exempt
certain
engines
to
prevent
a
hardship
to
an
equipment
manufacturer
or
a
secondary
engine
manufacturer.
This
section
does
not
apply
to
products
that
are
subject
to
vehicle
based
emission
standards.
(
a)
Equipment
exemption.
As
an
equipment
manufacturer,
you
may
ask
for
approval
to
produce
exempted
equipment
for
up
to
12
months.
We
will
generally
limit
this
to
the
first
year
that
new
or
revised
emission
standards
apply.
Send
the
Designated
Officer
a
written
request
for
an
exemption
before
you
are
in
violation.
In
your
request,
you
must
show
you
are
not
at
fault
for
the
impending
violation
and
that
you
would
face
serious
economic
hardship
if
we
do
not
grant
the
exemption.
This
exemption
is
not
available
under
this
paragraph
(
a)
if
you
manufacture
the
engine
you
need
for
your
own
equipment
or
if
complying
engines
are
available
from
other
engine
manufacturers
that
could
be
used
in
your
equipment,
unless
we
allow
it
elsewhere
in
this
chapter.
We
may
impose
other
conditions,
including
provisions
to
recover
the
lost
environmental
benefit.
In
determining
whether
to
grant
the
exemptions,
we
will
consider
all
relevant
factors,
including
the
following:
(
1)
The
number
of
engines
to
be
exempted.
(
2)
The
size
of
your
company
and
your
ability
to
endure
the
hardship.
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Vol.
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No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
(
3)
The
amount
of
time
you
had
to
redesign
your
equipment
to
accommodate
a
complying
engine.
(
4)
Whether
there
was
any
breach
of
contract
by
an
engine
supplier.
(
5)
The
potential
for
market
disruption.
(
b)
Engine
exemption.
As
an
engine
manufacturer,
you
may
produce
nonconforming
engines
for
the
equipment
we
exempt
in
paragraph
(
a)
of
this
section.
You
do
not
have
to
request
this
exemption
for
your
engines,
but
you
must
have
written
assurance
from
equipment
manufacturers
that
they
need
a
certain
number
of
exempted
engines
under
this
section.
Add
a
permanent,
legible
label,
written
in
block
letters
in
English,
to
a
readily
visible
part
of
each
exempted
engine.
This
label
must
include
at
least
the
following
items:
(
1)
The
label
heading
``
EMISSION
CONTROL
INFORMATION''.
(
2)
Your
corporate
name
and
trademark.
(
3)
Engine
displacement
(
in
liters),
rated
power,
and
model
year
of
the
engine
or
whom
to
contact
for
further
information.
(
4)
The
statement
``
THIS
ENGINE
IS
EXEMPT
UNDER
40
CFR
1068.255
FROM
EMISSION
STANDARDS
AND
RELATED
REQUIREMENTS.''.
(
c)
Secondary
engine
manufacturers.
As
a
secondary
engine
manufacturer,
you
may
ask
for
approval
to
produce
exempted
engines
under
this
section
for
up
to
one
year.
We
may
require
you
to
certify
your
engines
to
compliance
levels
above
the
emission
standards
that
apply.
For
example,
if
you
need
an
exemption
from
a
second
tier
of
standards,
we
may
require
you
to
meet
the
standards
that
applied
to
earlier
model
years.
(
1)
For
the
purpose
of
this
section,
a
secondary
engine
manufacturer
is
a
manufacturer
that
produces
an
engine
by
modifying
an
engine
that
is
made
by
a
different
manufacturer
for
a
different
type
of
application.
This
includes,
for
example,
automotive
engines
converted
for
use
in
industrial
applications,
or
land
based
engines
converted
for
use
in
marine
applications.
This
applies
whether
the
secondary
engine
manufacturer
is
modifying
a
complete
or
partially
complete
engine
and
whether
the
engine
was
previously
certified
to
emission
standards
or
not.
To
be
a
secondary
engine
manufacturer,
you
must
not
be
controlled
by
the
manufacturer
of
the
base
engine
(
or
by
an
entity
that
also
controls
the
manufacturer
of
the
base
engine).
In
addition,
equipment
manufacturers
that
substantially
modify
engines
become
secondary
engine
manufacturers.
For
the
purpose
of
this
definition,
``
substantially
modify''
means
changing
an
engine
in
a
way
that
could
change
its
emission
characteristics.
(
2)
The
provisions
in
paragraph
(
a)
of
this
section
that
apply
to
equipment
manufacturers
requesting
an
exemption
apply
equally
to
you,
except
that
you
may
manufacture
the
engines.
Before
we
can
approve
the
exemption
under
this
section,
you
must
commit
to
a
plan
to
make
up
the
lost
environmental
benefit.
(
i)
If
you
produce
uncertified
engines
under
this
exemption,
we
will
calculate
the
lost
environmental
benefit
based
on
our
best
estimate
of
uncontrolled
emission
rates
for
your
engines.
(
ii)
If
you
produce
engines
under
this
exemption
that
are
certified
to
a
compliance
level
less
stringent
than
the
emission
standards
that
would
otherwise
apply,
we
will
calculate
the
lost
environmental
benefit
based
on
the
compliance
level
you
select
for
your
engines.
(
3)
The
labeling
requirements
in
paragraph
(
b)
of
this
section
apply
to
your
exempted
engines;
however,
if
you
certify
engines
to
specific
compliance
levels,
state
on
the
label
the
compliance
levels
that
apply
to
each
engine.
Subpart
D
Imports
§
1068.301
Does
this
subpart
apply
to
me?
(
a)
This
subpart
applies
to
you
if
you
import
into
the
United
States
engines
or
equipment
subject
to
our
emission
standards
or
equipment
containing
engines
subject
to
our
emission
standards.
(
b)
In
general,
engines
that
you
import
must
be
covered
by
a
certificate
of
conformity
unless
they
were
built
before
emission
standards
started
to
apply.
This
subpart
describes
the
limited
cases
where
we
allow
importation
of
exempt
or
excluded
engines.
(
c)
The
U.
S.
Customs
Service
may
prevent
you
from
importing
an
engine
if
you
do
not
meet
the
requirements
of
this
subpart.
In
addition,
U.
S.
Customs
Service
regulations
may
contain
other
requirements
for
engines
imported
into
the
United
States
(
see
19
CFR
Chapter
I).
§
1068.305
How
do
I
get
an
exemption
or
exclusion
for
imported
engines?
(
a)
Complete
the
appropriate
EPA
declaration
form
before
importing
any
nonconforming
engine.
These
forms
are
available
on
the
Internet
at
http://
www.
epa.
gov/
OMS/
imports/
or
by
phone
at
202
564
9660.
(
b)
If
we
ask
for
it,
prepare
a
written
request
in
which
you
do
the
following:
(
1)
Give
your
name,
address,
telephone
number,
and
taxpayer
identification
number.
(
2)
Give
the
engine
owner's
name,
address,
telephone
number,
and
taxpayer
identification
number.
(
3)
Identify
the
make,
model,
identification
number,
and
original
production
year
of
each
engine.
(
4)
Identify
which
exemption
or
exclusion
in
this
subpart
allows
you
to
import
a
nonconforming
engine
and
describe
how
your
engine
qualifies.
(
5)
Tell
us
where
you
will
keep
your
engines
if
you
might
need
to
store
them
until
we
approve
your
request.
(
6)
Authorize
us
to
inspect
or
test
your
engines
as
the
Act
allows.
(
c)
We
may
ask
for
more
information.
(
d)
You
may
import
the
nonconforming
engines
you
identify
in
your
request
if
you
get
prior
written
approval
from
us.
The
U.
S.
Customs
Service
may
require
you
to
show
them
the
approval
letter.
We
may
temporarily
or
permanently
approve
the
exemptions
or
exclusions,
as
described
in
this
subpart.
(
e)
Make
sure
the
engine
meets
any
labeling
requirements
that
apply.
§
1068.310
What
are
the
exclusions
for
imported
engines?
Emission
standards
do
not
apply
to
excluded
engines
that
you
import.
If
you
show
us
that
your
engines
qualify
under
one
of
the
paragraphs
of
this
section,
we
will
approve
your
request
to
import
excluded
engines.
You
must
have
our
approval
to
import
an
engine
under
paragraph
(
a)
of
this
section.
You
may,
but
are
not
required
to
request
our
approval
for
the
other
exclusions
in
this
section.
The
following
engines
are
excluded:
(
a)
Engines
used
solely
for
competition.
Engines
you
use
solely
for
competition
are
excluded.
The
standardsetting
part
may
set
special
provisions
for
the
manufacture,
sale,
or
import
of
engines
used
solely
for
competition.
Section
1068.101(
b)(
4)
prohibits
using
these
excluded
engines
for
other
purposes.
(
b)
Stationary
engines.
This
includes
engines
that
will
be
used
in
a
permanently
fixed
location
and
engines
meeting
the
criteria
for
the
exclusion
in
paragraph
(
2)(
iii)
of
the
nonroad
engine
definition
in
§
1068.30.
Section
1068.101(
b)(
3)
prohibits
using
these
engines
for
other
purposes.
(
c)
Other
engines.
The
standardsetting
parts
may
exclude
engines
used
in
certain
applications.
For
example,
engines
used
in
aircraft,
underground
mining,
and
hobby
vehicles
are
generally
excluded.
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2002
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Rules
and
Regulations
§
1068.315
What
are
the
permanent
exemptions
for
imported
engines?
We
may
approve
a
permanent
exemption
for
an
imported
engine
under
the
following
conditions:
(
a)
National
security
exemption.
You
may
import
engine
under
the
national
security
exemption
in
§
1068.225.
(
b)
Manufacturer
owned
engine
exemption.
You
may
import
a
manufacturer
owned
engine,
as
described
in
§
1068.215.
(
c)
Replacement
engine
exemption.
You
may
import
a
nonconforming
replacement
engine
as
described
in
§
1068.240.
To
use
this
exemption,
you
must
be
a
certificate
holder
for
an
engine
family
we
regulate
under
the
same
part
as
the
replacement
engine.
(
d)
Extraordinary
circumstances
exemption.
You
may
import
a
nonconforming
engine
if
we
grant
hardship
relief
as
described
in
§
1068.245.
(
e)
Hardship
exemption.
You
may
import
a
nonconforming
engine
if
we
grant
an
exemption
for
the
transition
to
new
or
revised
emission
standards,
as
described
in
§
1068.255.
(
f)
Identical
configuration
exemption.
You
may
import
a
nonconforming
engine
if
it
is
identical
to
certified
engines
produced
by
the
same
manufacturer,
subject
to
the
following
provisions:
(
1)
You
may
import
only
the
following
engines
under
this
exemption:
(
i)
Large
nonroad
spark
ignition
engines
(
see
part
1048
of
this
chapter).
(
ii)
Recreational
nonroad
sparkignition
engines
and
equipment
(
see
part
1051
of
this
chapter).
(
2)
You
must
meet
all
the
following
criteria:
(
i)
You
have
owned
the
engine
for
at
least
one
year.
(
ii)
You
agree
not
to
sell,
lease,
donate,
trade,
or
otherwise
transfer
ownership
of
the
engine
for
at
least
five
years,
or
until
the
engine
is
eligible
for
the
exemption
in
paragraph
(
g)
of
this
section.
During
this
period,
the
only
acceptable
way
to
dispose
of
the
engine
is
to
destroy
or
export
it.
(
iii)
You
use
data
or
evidence
sufficient
to
show
that
the
engine
is
in
a
configuration
that
is
the
same
as
an
engine
the
original
manufacturer
has
certified
to
meet
emission
standards
that
apply
at
the
time
the
manufacturer
finished
assembling
or
modifying
the
engine
in
question.
If
you
modify
the
engine
to
make
it
identical,
you
must
follow
the
original
manufacturer's
complete
written
instructions.
(
3)
We
will
tell
you
in
writing
if
we
find
the
information
insufficient
to
show
that
the
engine
is
eligible
for
this
exemption.
In
this
case,
we
will
not
consider
your
request
further
until
you
address
our
concerns.
(
g)
Ancient
engine
exemption.
If
you
are
not
the
original
engine
manufacturer,
you
may
import
a
nonconforming
engine
that
is
subject
to
a
standard
setting
part
and
was
first
manufactured
at
least
21
years
earlier,
as
long
as
it
is
still
in
its
original
configuration.
§
1068.320
How
must
I
label
an
imported
engine
with
a
permanent
exemption?
(
a)
For
engines
imported
under
§
1068.315
(
a),
(
b),
(
c),
(
d),
or
(
e),
you
must
place
a
permanent
label
or
tag
on
each
engine.
If
no
specific
label
requirements
from
subpart
C
of
this
part
apply,
you
must
meet
the
following
requirements:
(
1)
Attach
the
label
or
tag
in
one
piece
so
no
one
can
remove
it
without
destroying
or
defacing
it.
(
2)
Make
sure
it
is
durable
and
readable
for
the
engine's
entire
life.
(
3)
Secure
it
to
a
part
of
the
engine
needed
for
normal
operation
and
not
normally
requiring
replacement.
(
4)
Write
it
in
block
letters
in
English.
(
5)
Make
it
readily
visible
to
the
average
person
after
the
engine
is
installed
in
the
equipment.
(
b)
On
the
engine
label
or
tag,
do
the
following:
(
1)
Include
the
heading
``
Emission
Control
Information.''
(
2)
Include
your
full
corporate
name
and
trademark.
(
3)
State
the
engine
displacement
(
in
liters)
and
rated
power.
If
the
engine's
rated
power
is
not
established,
state
the
approximate
power
rating
accurately
enough
to
allow
a
detemination
of
which
stanadards
would
otherwise
apply.
(
4)
State:
``
THIS
ENGINE
IS
EXEMPT
FROM
THE
REQUIREMENTS
OF
[
identify
the
part
referenced
in
40
CFR
1068.1(
a)
that
would
otherwise
apply],
AS
PROVIDED
IN
[
identify
the
paragraph
authorizing
the
exemption
(
for
example,
``
40
CFR
1068.315(
a)'')].
INSTALLING
THIS
ENGINE
IN
ANY
DIFFERENT
APPLICATION
IS
A
VIOLATION
OF
FEDERAL
LAW
SUBJECT
TO
CIVIL
PENALTY.''.
(
c)
Get
us
to
approve
alternate
label
language
if
it
is
more
accurate
for
your
engine.
§
1068.325
What
are
the
temporary
exemptions
for
imported
engines?
If
we
approve
a
temporary
exemption
for
an
engine,
you
may
import
it
under
the
conditions
in
this
section.
We
may
ask
the
U.
S.
Customs
Service
to
require
a
specific
bond
amount
to
make
sure
you
comply
with
the
requirements
of
this
subpart.
You
may
not
sell
or
lease
one
of
these
engines
while
it
is
in
the
United
States.
You
must
eventually
export
the
engine
as
we
describe
in
this
section
unless
you
get
a
certificate
of
conformity
for
it
or
it
qualifies
for
one
of
the
permanent
exemptions
in
§
1068.315.
Section
1068.330
specifies
an
additional
temporary
exemption
allowing
you
to
import
certain
engines
you
intend
to
sell
or
lease.
(
a)
Exemption
for
repairs
or
alterations.
You
may
temporarily
import
a
nonconforming
engine
under
bond
solely
to
repair
or
alter
it.
You
may
operate
the
engine
in
the
United
States
only
to
repair
or
alter
it
or
to
ship
it
to
or
from
the
service
location.
Export
the
engine
directly
after
the
engine
servicing
is
complete.
(
b)
Testing
exemption.
You
may
temporarily
import
a
nonconforming
engine
under
bond
for
testing
if
you
follow
the
requirements
of
§
1068.210.
You
may
operate
the
engine
in
the
United
States
only
to
allow
testing.
This
exemption
expires
one
year
after
you
import
the
engine,
unless
we
approve
a
one
time
request
for
an
extension
of
up
to
one
more
year.
The
engine
must
be
exported
before
the
exemption
expires.
(
c)
Display
exemption.
You
may
temporarily
import
a
nonconforming
engine
under
bond
for
display,
as
described
in
§
1068.220.
This
exemption
expires
one
year
after
you
import
the
engine,
unless
we
approve
your
request
for
an
extension.
We
may
approve
an
extension
of
up
to
one
more
year
for
each
request,
but
no
more
than
three
years
in
total.
The
engine
must
be
exported
by
the
time
the
exemption
expires
or
directly
after
the
display
concludes,
whichever
comes
first.
(
d)
Export
exemption.
You
may
temporarily
import
a
nonconforming
engine
to
export
it,
as
described
in
§
1068.230.
You
may
operate
the
engine
in
the
United
States
only
as
needed
to
prepare
it
for
export.
Label
the
engine
as
described
in
§
1068.230.
(
e)
Diplomatic
or
military
exemption.
You
may
temporarily
import
nonconforming
engines
without
bond
if
you
represent
a
foreign
government
in
a
diplomatic
or
military
capacity.
In
your
request
to
the
Designated
Officer
(
see
§
1068.305),
include
either
written
confirmation
from
the
U.
S.
State
Department
that
you
qualify
for
this
exemption
or
a
copy
of
your
orders
for
military
duty
in
the
United
States.
We
will
rely
on
the
State
Department
or
your
military
orders
to
determine
when
your
diplomatic
or
military
status
expires,
at
which
time
you
must
export
your
exempt
engines.
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Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
§
1068.330
How
do
I
import
engines
to
modify
for
other
applications?
This
section
allows
you
to
import
engines
in
configurations
different
than
their
final
configuration.
This
exemption
is
temporary,
as
described
in
paragraph
(
d)
of
this
section.
(
a)
This
section
applies
in
the
following
cases:
(
1)
You
import
a
partially
complete
engine
with
the
intent
to
manufacture
complete
engines
for
which
you
have
either
a
certificate
of
conformity
or
an
exemption
that
allows
you
to
sell
completed
engines.
(
2)
You
import
an
uncertified
complete
engine
with
the
intent
to
modify
it
for
installation
in
an
application
different
than
its
otherwise
intended
application
(
for
example,
you
import
a
land
based
engine
to
modify
it
for
a
marine
application).
In
this
case,
to
qualify
for
an
exemption
under
this
section,
you
need
either
a
certificate
of
conformity
or
an
exemption
that
allows
you
to
sell
completed
engines.
(
3)
You
import
a
complete
or
partially
complete
engine
to
modify
for
an
application
for
which
emission
standards
do
not
apply.
(
b)
You
may
request
this
exemption
in
an
application
for
certification.
Otherwise,
send
your
request
to
the
Designated
Officer.
Your
request
must
include:
(
1)
The
name
of
the
supplier
of
the
partially
complete
engine,
or
the
original
manufacturer
of
the
complete
engine.
(
2)
A
description
of
the
certificate
or
exemption
that
will
apply
to
the
engines
in
the
final
configuration,
or
an
explanation
why
a
certificate
or
exemption
is
not
needed.
(
3)
A
brief
description
of
how
and
where
final
assembly
will
be
completed.
(
4)
An
unconditional
statement
that
the
engines
will
comply
with
all
applicable
regulations
in
their
final
configuration.
(
c)
If
we
approve
a
temporary
exemption
for
an
engine,
you
may
import
it
under
the
conditions
in
this
section.
We
may
ask
the
U.
S.
Customs
Service
to
require
a
specific
bond
amount
to
make
sure
you
comply
with
the
requirements
of
this
subpart.
(
d)
These
provisions
are
intended
only
to
allow
you
to
import
engines
in
the
specific
circumstances
identified
in
this
section,
so
any
exemption
under
this
section
expires
when
you
complete
the
assembly
of
the
engine
in
its
final
configuration.
If
the
engine
in
its
final
configuration
is
subject
to
emission
standards,
then
it
must
be
covered
by
a
certificate
or
a
different
exemption
before
you
introduce
it
into
commerce.
§
1068.335
What
are
the
penalties
for
violations?
(
a)
All
imported
engines.
Unless
you
comply
with
the
provisions
of
this
subpart,
importation
of
nonconforming
engines
is
violation
of
sections
203
and
213(
d)
of
the
Act.
You
may
then
have
to
export
the
engines,
or
pay
civil
penalties,
or
both.
The
U.
S.
Customs
Service
may
seize
unlawfully
imported
engines.
(
b)
Temporarily
imported
engines.
If
you
do
not
comply
with
the
provisions
of
this
subpart
for
a
temporary
exemption,
you
may
forfeit
the
total
amount
of
the
bond
in
addition
to
the
sanctions
we
identify
in
paragraph
(
a)
of
this
section.
We
will
consider
an
engine
to
be
exported
if
it
has
been
destroyed
or
delivered
to
the
U.
S.
Customs
Service
for
export
or
other
disposition
under
applicable
Customs
laws
and
regulations.
EPA
or
the
U.
S.
Customs
Service
may
offer
you
a
grace
period
to
allow
you
to
export
a
temporarily
exempted
engine
without
penalty
after
the
exemption
expires.
Subpart
E
Selective
Enforcement
Auditing
§
1068.401
What
is
a
selective
enforcement
audit?
(
a)
We
may
conduct
or
require
you
to
conduct
emission
tests
on
your
production
engines
in
a
selective
enforcement
audit.
This
requirement
is
independent
of
any
requirement
for
you
to
routinely
test
production
line
engines.
(
b)
If
we
send
you
a
signed
test
order,
you
must
follow
its
directions
and
the
provisions
of
this
subpart.
We
will
tell
you
where
to
test
the
engines.
This
may
be
where
you
produce
the
engines
or
any
other
emission
testing
facility.
(
c)
If
we
select
one
or
more
of
your
engine
families
for
a
selective
enforcement
audit,
we
will
send
the
test
order
to
the
person
who
signed
the
application
for
certification
or
we
will
deliver
it
in
person.
(
d)
Within
one
working
day
of
receiving
the
test
order,
notify
the
Designated
Officer
which
test
facility
you
have
selected
for
emission
testing.
(
e)
You
must
do
everything
we
require
in
the
audit
without
delay.
§
1068.405
What
is
in
a
test
order?
(
a)
In
the
test
order,
we
will
specify
the
following
things:
(
1)
The
engine
family
and
configuration
(
if
any)
we
have
identified
for
testing.
(
2)
The
engine
assembly
plant,
storage
facility,
or
(
if
you
import
the
engines)
port
facility
from
which
you
must
select
engines.
(
3)
The
procedure
for
selecting
engines
for
testing,
including
a
selection
rate.
(
4)
The
test
procedures,
duty
cycles,
and
test
points,
as
appropriate,
for
testing
the
engines
to
show
that
they
meet
emission
standards.
(
b)
We
may
state
that
we
will
select
the
test
engines.
(
c)
We
may
identify
alternate
engine
families
or
configurations
for
testing
in
case
we
determine
the
intended
engines
are
not
available
for
testing
or
if
you
do
not
produce
enough
engines
to
meet
the
minimum
rate
for
selecting
test
engines.
(
d)
We
may
include
other
directions
or
information
in
the
test
order.
(
e)
We
may
ask
you
to
show
us
that
you
meet
any
additional
requirements
that
apply
to
your
engines
(
closed
crankcases,
for
example).
(
f)
In
anticipation
of
a
potential
audit,
you
may
give
us
a
list
of
your
preferred
engine
families
and
the
corresponding
assembly
plants,
storage
facilities,
or
(
if
you
import
the
engines)
port
facilities
from
which
we
should
select
engines
for
testing.
The
information
would
apply
only
for
a
single
model
year,
so
it
would
be
best
to
include
this
information
in
your
application
for
certification.
If
you
give
us
this
list
before
we
issue
a
test
order,
we
will
consider
your
recommendations,
but
we
may
select
engines
differently.
(
g)
If
you
also
do
routine
productionline
testing
with
the
selected
engine
family
in
the
same
time
period,
the
test
order
will
tell
you
what
changes
you
might
need
to
make
in
your
productionline
testing
schedule.
§
1068.410
How
must
I
select
and
prepare
my
engines?
(
a)
Selecting
engines.
Select
engines
as
described
in
the
test
order.
If
you
are
unable
to
select
test
engines
this
way,
you
may
ask
us
to
approve
an
alternate
plan,
as
long
as
you
make
the
request
before
you
start
selecting
engines.
(
b)
Assembling
engines.
Produce
and
assemble
test
engines
using
your
normal
production
and
assembly
process
for
that
engine
family.
(
1)
Notify
us
directly
if
you
make
any
change
in
your
production,
assembly,
or
quality
control
processes
that
might
affect
emissions
between
the
time
you
receive
the
test
order
and
the
time
you
finish
selecting
test
engines.
(
2)
If
you
do
not
fully
assemble
engines
at
the
specified
location,
we
will
describe
in
the
test
order
how
to
select
components
to
finish
assembling
the
engines.
Assemble
these
components
onto
the
test
engines
using
your
documented
assembly
and
quality
control
procedures.
(
c)
Modifying
engines.
Once
an
engine
is
selected
for
testing,
you
may
adjust,
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Rules
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Regulations
repair,
prepare,
or
modify
it
or
check
its
emissions
only
if
one
of
the
following
is
true:
(
1)
You
document
the
need
for
doing
so
in
your
procedures
for
assembling
and
inspecting
all
your
production
engines
and
make
the
action
routine
for
all
the
engines
in
the
engine
family.
(
2)
This
subpart
otherwise
allows
your
action.
(
3)
We
approve
your
action
in
advance.
(
d)
Engine
malfunction.
If
an
engine
malfunction
prevents
further
emission
testing,
ask
us
to
approve
your
decision
to
either
repair
the
engine
or
delete
it
from
the
test
sequence.
(
e)
Setting
adjustable
parameters.
Before
any
test,
we
may
adjust
or
require
you
to
adjust
any
adjustable
parameter
to
any
setting
within
its
physically
adjustable
range.
(
1)
We
may
adjust
idle
speed
outside
the
physically
adjustable
range
as
needed
until
the
engine
has
stabilized
emission
levels
(
see
paragraph
(
e)
of
this
section).
We
may
ask
you
for
information
needed
to
establish
an
alternate
minimum
idle
speed.
(
2)
We
may
make
or
specify
adjustments
within
the
physically
adjustable
range
by
considering
their
effect
on
emission
levels,
as
well
as
how
likely
it
is
someone
will
make
such
an
adjustment
with
in
use
engines.
(
f)
Stabilizing
emission
levels.
Before
you
test
production
line
engines,
you
may
operate
the
engine
to
stabilize
the
emission
levels.
Using
good
engineering
judgment,
operate
your
engines
in
a
way
that
represents
the
way
production
engines
will
be
used.
You
may
operate
each
engine
for
no
more
than
the
greater
of
two
periods:
(
1)
50
hours.
(
2)
The
number
of
hours
you
operated
your
emission
data
engine
for
certifying
the
engine
family
(
see
40
CFR
part
1065,
subpart
E).
(
g)
Damage
during
shipment.
If
shipping
an
engine
to
a
remote
facility
for
production
line
testing
makes
necessary
an
adjustment
or
repair,
you
must
wait
until
after
the
initial
emission
test
to
do
this
work.
We
may
waive
this
requirement
if
the
test
would
be
impossible
or
unsafe,
or
if
it
would
permanently
damage
the
engine.
Report
to
us,
in
your
written
report
under
§
1068.450,
all
adjustments
or
repairs
you
make
on
test
engines
before
each
test.
(
h)
Shipping
engines.
If
you
need
to
ship
engines
to
another
facility
for
testing,
make
sure
the
test
engines
arrive
at
the
test
facility
within
24
hours
after
being
selected.
You
may
ask
that
we
allow
more
time
if
you
are
unable
to
do
this.
(
i)
Retesting
after
invalid
tests.
You
may
retest
an
engine
if
you
determine
an
emission
test
is
invalid.
Explain
in
your
written
report
reasons
for
invalidating
any
test
and
the
emission
results
from
all
tests.
If
you
retest
an
engine
and,
within
ten
days
after
testing,
ask
to
substitute
results
of
the
new
tests
for
the
original
ones,
we
will
answer
within
ten
days
after
we
receive
your
information.
§
1068.415
How
do
I
test
my
engines?
(
a)
Use
the
test
procedures
specified
in
the
standard
setting
part
for
showing
that
your
engines
meet
emission
standards.
The
test
order
will
give
further
testing
instructions.
(
b)
If
no
test
cells
are
available
at
a
given
facility,
you
may
make
alternate
testing
arrangements
with
our
approval.
(
c)
Test
at
least
two
engines
in
each
24
hour
period
(
including
void
tests).
However,
if
your
projected
U.
S.
nonroad
engine
sales
within
the
engine
family
are
less
than
7,500
for
the
year,
you
may
test
a
minimum
of
one
engine
per
24
hour
period.
If
you
request
and
justify
it,
we
may
approve
a
lower
testing
rate.
(
d)
Accumulate
service
on
test
engines
at
a
minimum
rate
of
6
hours
per
engine
during
each
24
hour
period.
The
first
24
hour
period
for
service
accumulation
begins
when
you
finish
preparing
an
engine
for
testing.
The
minimum
service
accumulation
rate
does
not
apply
on
weekends
or
holidays.
You
may
ask
us
to
approve
a
lower
service
accumulation
rate.
Plan
your
service
accumulation
to
allow
testing
at
the
rate
specified
in
§
1068.415.
Select
engine
operation
for
accumulating
operating
hours
on
your
test
engines
to
represent
normal
in
use
engine
operation
for
the
engine
family.
(
e)
Test
engines
is
the
same
order
you
select
them.
§
1068.420
How
do
I
know
when
my
engine
family
fails
an
SEA?
(
a)
A
failed
engine
is
one
whose
final
deteriorated
test
results
exceed
an
applicable
emission
standard
for
any
regulated
pollutant.
(
b)
Continue
testing
engines
until
you
reach
a
pass
decision
for
all
pollutants
or
a
fail
decision
for
one
pollutant.
(
c)
You
reach
a
pass
decision
for
the
SEA
requirements
when
the
number
of
failed
engines
is
less
than
or
equal
to
the
pass
decision
number
in
Appendix
A
to
this
subpart
for
the
total
number
of
engines
tested.
You
reach
a
fail
decision
for
the
SEA
requirements
when
the
number
of
failed
engines
is
greater
than
or
equal
to
the
fail
decision
number
in
Appendix
A
to
this
subpart
for
the
total
number
of
engines
you
test.
An
acceptable
quality
level
of
40
percent
is
the
basis
for
the
pass
or
fail
decision.
(
d)
Consider
test
results
in
the
same
order
as
the
engine
testing
sequence.
(
e)
If
you
reach
a
pass
decision
for
one
pollutant,
but
need
to
continue
testing
for
another
pollutant,
we
will
disregard
these
later
test
results
for
the
pollutant
with
the
pass
decision.
(
f)
Appendix
A
to
this
subpart
lists
multiple
sampling
plans.
Use
the
sampling
plan
for
the
projected
sales
volume
you
reported
in
your
application
for
the
audited
engine
family.
(
g)
We
may
choose
to
stop
testing
after
any
number
of
tests.
(
h)
If
we
test
some
of
your
engines
in
addition
to
your
own
testing,
we
may
decide
not
to
include
your
test
results
as
official
data
for
those
engines
if
there
is
substantial
disagreement
between
your
testing
and
our
testing.
We
will
reinstate
your
data
as
valid
if
you
show
us
that
we
made
an
error
and
your
data
are
correct.
(
i)
If
we
rely
on
our
test
data
instead
of
yours,
we
will
notify
you
in
writing
of
our
decision
and
the
reasons
we
believe
your
facility
is
not
appropriate
for
doing
the
tests
we
require
under
this
subpart.
You
may
request
in
writing
that
we
consider
your
test
results
from
the
same
facility
for
future
testing
if
you
show
us
that
you
have
made
changes
to
resolve
the
problem.
§
1068.425
What
happens
if
one
of
my
production
line
engines
exceeds
the
emission
standards?
(
a)
If
one
of
your
production
line
engines
fails
to
meet
one
or
more
emission
standards
(
see
§
1068.420),
the
certificate
of
conformity
is
automatically
suspended
for
that
engine.
You
must
take
the
following
actions
before
your
certificate
of
conformity
can
cover
that
engine:
(
1)
Correct
the
problem
and
retest
the
engine
to
show
it
complies
with
all
emission
standards.
(
2)
Include
in
your
written
report
a
description
of
the
test
results
and
the
remedy
for
each
engine
(
see
§
1068.450).
(
b)
You
may
at
any
time
ask
for
a
hearing
to
determine
whether
the
tests
and
sampling
methods
were
proper
(
see
subpart
G
of
this
part).
§
1068.430
What
happens
if
an
engine
family
fails
an
SEA?
(
a)
We
may
suspend
your
certificate
of
conformity
for
an
engine
family
if
it
fails
the
SEA
under
§
1068.420.
The
suspension
may
apply
to
all
facilities
producing
engines
from
an
engine
family,
even
if
you
find
noncompliant
engines
only
at
one
facility.
(
b)
We
will
tell
you
in
writing
if
we
suspend
your
certificate
in
whole
or
in
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part.
We
will
not
suspend
a
certificate
until
at
least
15
days
after
the
engine
family
fails
the
SEA.
The
suspension
is
effective
when
you
receive
our
notice.
(
c)
Up
to
15
days
after
we
suspend
the
certificate
for
an
engine
family,
you
may
ask
for
a
hearing
to
determine
whether
the
tests
and
sampling
methods
were
proper
(
see
subpart
G
of
this
part).
If
we
agree
before
a
hearing
that
we
used
erroneous
information
in
deciding
to
suspend
the
certificate,
we
will
reinstate
the
certificate.
§
1068.435
May
I
sell
engines
from
an
engine
family
with
a
suspended
certificate
of
conformity?
You
may
sell
engines
that
you
produce
after
we
suspend
the
engine
family's
certificate
of
conformity
only
if
one
of
the
following
occurs:
(
a)
You
test
each
engine
you
produce
and
show
it
complies
with
emission
standards
that
apply.
(
b)
We
conditionally
reinstate
the
certificate
for
the
engine
family.
We
may
do
so
if
you
agree
to
recall
all
the
affected
engines
and
remedy
any
noncompliance
at
no
expense
to
the
owner
if
later
testing
shows
that
engines
in
the
engine
family
still
do
not
comply.
§
1068.440
How
do
I
ask
EPA
to
reinstate
my
suspended
certificate?
(
a)
Send
us
a
written
report
asking
us
to
reinstate
your
suspended
certificate.
In
your
report,
identify
the
reason
for
the
SEA
failure,
propose
a
remedy,
and
commit
to
a
date
for
carrying
it
out.
In
your
proposed
remedy
include
any
quality
control
measures
you
propose
to
keep
the
problem
from
happening
again.
(
b)
Give
us
data
from
production
line
testing
showing
that
engines
in
the
remedied
engine
family
comply
with
all
the
emission
standards
that
apply.
§
1068.445
When
may
EPA
revoke
my
certificate
under
this
subpart
and
how
may
I
sell
these
engines
again?
(
a)
We
may
revoke
your
certificate
for
an
engine
family
in
the
following
cases:
(
1)
You
do
not
meet
the
reporting
requirements.
(
2)
Your
engine
family
fails
an
SEA
and
your
proposed
remedy
to
address
a
suspended
certificate
is
inadequate
to
solve
the
problem
or
requires
you
to
change
the
engine's
design
or
emissioncontrol
system.
(
b)
To
sell
engines
from
an
engine
family
with
a
revoked
certificate
of
conformity,
you
must
modify
the
engine
family
and
then
show
it
complies
with
the
applicable
requirements.
(
1)
If
we
determine
your
proposed
design
change
may
not
control
emissions
for
the
engine's
full
useful
life,
we
will
tell
you
within
five
working
days
after
receiving
your
report.
In
this
case
we
will
decide
whether
production
line
testing
will
be
enough
for
us
to
evaluate
the
change
or
whether
you
need
to
do
more
testing.
(
2)
Unless
we
require
more
testing,
you
may
show
compliance
by
testing
production
line
engines
as
described
in
this
subpart.
(
3)
We
will
issue
a
new
or
updated
certificate
of
conformity
when
you
have
met
these
requirements.
§
1068.450
What
records
must
I
send
to
EPA?
(
a)
Within
30
calendar
days
of
the
end
of
each
audit,
send
us
a
report
with
the
following
information:
(
1)
Describe
any
facility
used
to
test
production
line
engines
and
state
its
location.
(
2)
State
the
total
U.
S.
directed
production
volume
and
number
of
tests
for
each
engine
family.
(
3)
Describe
your
test
engines,
including
the
engine
family's
identification
and
the
engine's
model
year,
build
date,
model
number,
identification
number,
and
number
of
hours
of
operation
before
testing
for
each
test
engine.
(
4)
Identify
where
you
accumulated
hours
of
operation
on
the
engines
and
describe
the
procedure
and
schedule
you
used.
(
5)
Provide
the
test
number;
the
date,
time
and
duration
of
testing;
test
procedure;
initial
test
results
before
and
after
rounding;
final
test
results;
and
final
deteriorated
test
results
for
all
tests.
Provide
the
emission
figures
for
all
measured
pollutants.
Include
information
for
both
valid
and
invalid
tests
and
the
reason
for
any
invalidation.
(
6)
Describe
completely
and
justify
any
nonroutine
adjustment,
modification,
repair,
preparation,
maintenance,
or
test
for
the
test
engine
if
you
did
not
report
it
separately
under
this
subpart.
Include
the
results
of
any
emission
measurements,
regardless
of
the
procedure
or
type
of
equipment.
(
7)
Report
on
each
failed
engine
as
described
in
§
1068.425.
(
b)
We
may
ask
you
to
add
information
to
your
written
report,
so
we
can
determine
whether
your
new
engines
conform
with
the
requirements
of
this
subpart.
(
c)
An
authorized
representative
of
your
company
must
sign
the
following
statement:
We
submit
this
report
under
Sections
208
and
213
of
the
Clean
Air
Act.
Ourtesting
conformed
completely
with
the
requirements
of
40
CFR
part
1068.
We
have
not
changed
production
processes
or
quality
control
procedures
for
the
engine
family
in
a
way
that
might
affect
the
emission
control
from
production
engines.
All
the
information
in
this
report
is
true
and
accurate,
to
the
best
of
my
knowledge.
I
know
of
the
penalties
for
violating
the
Clean
Air
Act
and
the
regulations.
(
Authorized
Company
Representative)
(
d)
Send
reports
of
your
testing
to
the
Designated
Officer
using
an
approved
information
format.
If
you
want
to
use
a
different
format,
send
us
a
written
request
with
justification
for
a
waiver.
(
e)
We
will
send
copies
of
your
reports
to
anyone
from
the
public
who
asks
for
them.
We
will
release
information
about
your
sales
or
production
volumes,
which
is
all
we
will
consider
confidential.
§
1068.455
What
records
must
I
keep?
(
a)
We
may
review
your
records
at
any
time,
so
it
is
important
to
keep
required
information
readily
available.
Organize
and
maintain
your
records
as
described
in
this
section.
(
b)
Keep
paper
records
for
testing
under
this
subpart
for
one
full
year
after
you
complete
all
the
testing
required
for
the
selective
enforcement
audit.
For
additional
storage,
you
may
use
any
format
or
media.
(
c)
Keep
a
copy
of
the
written
reports
described
in
§
1068.450.
(
d)
Keep
the
following
additional
records:
(
1)
The
names
of
supervisors
involved
in
each
test.
(
2)
The
name
of
anyone
who
authorizes
adjusting,
repairing,
preparing,
or
modifying
a
test
engine
and
the
names
of
all
supervisors
who
oversee
this
work.
(
3)
If
you
shipped
the
engine
for
testing,
the
date
you
shipped
it,
the
associated
storage
or
port
facility,
and
the
date
the
engine
arrived
at
the
testing
facility.
(
4)
Any
records
related
to
your
audit
that
are
not
in
the
written
report.
(
5)
A
brief
description
of
any
significant
events
during
testing
not
otherwise
described
in
the
written
report
or
in
this
section.
(
e)
If
we
ask,
you
must
give
us
projected
or
actual
production
for
an
engine
family.
Include
each
assembly
plant
if
you
produce
engines
at
more
than
one
plant.
(
f)
We
may
ask
you
to
keep
or
send
other
information
necessary
to
implement
this
subpart.
Appendix
A
to
Subpart
E
of
Part
1068
Plans
for
Selective
Enforcement
Auditing
The
following
tables
describe
sampling
plans
for
selective
enforcement
audits,
as
described
in
§
1068.420:
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TABLE
A
1.
SAMPLING
PLAN
CODE
LETTER
Projected
engine
family
sales
Code
letter
1
Minimum
number
of
tests
Maximum
number
of
tests
To
pass
To
fail
20
50
.............................................................................................................................
AA
3
5
20
20
99
.............................................................................................................................
A
4
6
30
100
299
.........................................................................................................................
B
5
6
40
300
499
.........................................................................................................................
C
5
6
50
500
+
................................................................................................................................
D
5
6
60
1
A
manufacturer
may
optionally
use
either
the
sampling
plan
for
code
letter
``
AA''
or
sampling
plan
for
code
letter
``
A''
for
Selective
enforcement
Audits
of
engine
families
with
annual
sales
between
20
and
50
engines.
Additionally,
the
manufacturer
may
switch
between
these
plans
during
the
audit.
TABLE
A
2.
SAMPLING
PLANS
FOR
DIFFERENT
ENGINE
FAMILY
SALES
VOLUMES
Stage
a
AA
A
B
C
D
Pass
#
Fail
#
Pass
#
Fail
#
Pass
#
Fail
#
Pass
#
Fail
#
Pass
#
Fail
#
1.
2.
3
........................
0
4
........................
....................
0
5
........................
1
5
0
0
0
0
6
........................
1
6
1
6
1
6
0
6
0
6
7
........................
2
6
1
7
1
7
1
7
1
7
8
........................
2
7
2
7
2
7
2
7
2
8
9
........................
3
7
2
8
2
8
2
8
2
8
10
......................
3
8
3
8
3
8
3
9
3
9
11
......................
4
8
3
8
3
9
3
9
3
9
12
......................
4
9
4
9
4
9
4
10
4
10
13
......................
5
9
5
10
4
10
4
10
4
10
14
......................
5
10
5
10
5
10
5
11
5
11
15
......................
6
10
6
11
5
11
5
11
5
11
16
......................
6
10
6
11
6
12
6
12
6
12
17
......................
7
10
7
12
6
12
6
12
6
12
18
......................
8
10
7
12
7
13
7
13
7
13
19
......................
8
10
8
13
8
13
7
13
7
13
20
......................
9
10
8
13
8
14
8
14
8
14
21
......................
9
14
9
14
8
14
8
14
22
......................
10
14
9
15
9
15
9
15
23
......................
10
15
10
15
10
15
9
15
24
......................
11
15
10
16
10
16
10
16
25
......................
11
16
11
16
11
16
11
16
26
......................
12
16
11
17
11
17
11
17
27
......................
12
17
12
17
12
17
12
17
28
......................
13
17
12
18
12
18
12
18
29
......................
14
17
13
18
13
18
13
19
30
......................
16
17
13
19
13
19
13
19
31
......................
14
19
14
19
14
20
32
......................
14
20
14
20
14
20
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Regulations
TABLE
A
2.
SAMPLING
PLANS
FOR
DIFFERENT
ENGINE
FAMILY
SALES
VOLUMES
Continued
Stage
a
AA
A
B
C
D
Pass
#
Fail
#
Pass
#
Fail
#
Pass
#
Fail
#
Pass
#
Fail
#
Pass
#
Fail
#
33
......................
15
20
15
20
15
21
34
......................
16
21
15
21
15
21
35
......................
16
21
16
21
16
22
36
......................
17
22
16
22
16
22
37
......................
17
22
17
22
17
23
38
......................
18
22
18
23
17
23
39
......................
18
22
18
23
18
24
40
......................
21
22
19
24
18
24
41
......................
19
24
19
25
42
......................
20
25
19
26
43
......................
20
25
20
26
44
......................
21
26
21
27
45
......................
21
27
21
27
46
......................
22
27
22
28
47
......................
22
27
22
28
48
......................
23
27
23
29
49
......................
23
27
23
29
50
......................
26
27
24
30
51
......................
24
30
52
......................
25
31
53
......................
25
31
54
......................
26
32
55
......................
26
32
56
......................
27
33
57
......................
27
33
58
......................
28
33
59
......................
28
33
60
32
33
a
Stage
refers
to
the
cumulative
number
of
engines
tested.
Subpart
F
Reporting
Defects
and
Recalling
Engines
§
1068.501
How
do
I
report
engine
defects?
(
a)
General
provisions.
As
an
engine
manufacturer,
you
must
investigate
in
certain
circumstances
whether
emission
related
components
are
defective
and
send
us
reports
as
specified
by
this
section.
(
1)
The
term
emission
related
component
includes
those
components
listed
in
Appendix
I
of
this
part.
For
the
purposes
of
this
section,
complete
engines
shall
also
be
considered
an
emissions
related
component.
It
also
includes
factory
settings
of
emissionrelated
parameters
and
specifications
listed
in
Appendix
II
of
this
part.
(
2)
For
the
purposes
of
this
section,
defects
do
not
include
damage
to
emission
related
components
(
or
maladjustment
of
parameters)
caused
by
owners
improperly
maintaining
or
abusing
their
engine.
(
3)
You
must
track
the
information
specified
in
paragraph
(
b)(
1)
of
this
section.
You
are
not
required
to
collect
additional
information
other
than
that
specified
in
paragraph
(
b)(
1)
of
this
section
before
reaching
the
threshold
for
an
investigation
specified
in
paragraph
(
e)
of
this
section.
(
4)
You
may
ask
us
to
allow
you
to
use
alternate
methods
for
tracking,
investigating,
reporting,
and
correcting
emission
related
defects.
In
your
request,
explain
and
demonstrate
why
you
believe
your
alternate
system
will
be
at
least
as
effective
in
tracking,
identifying,
investigating,
evaluating,
reporting,
and
correcting
potential
and
actual
emissions
related
defects
as
the
requirements
in
this
section.
(
5)
If
we
determine
that
emissionrelated
defects
result
in
a
substantial
number
of
properly
maintained
and
used
engines
not
conforming
to
the
regulations
of
this
chapter
during
their
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useful
life,
we
may
order
you
to
conduct
a
recall
of
your
engines
(
see
§
1068.505).
(
6)
Send
the
defect
reports
and
status
reports
required
by
this
section
to
the
Designated
Officer.
(
b)
Investigation
of
possible
defects.
If
the
number
of
engines
that
possibly
have
a
defect,
as
defined
by
paragraph
(
b)(
1)
of
this
section,
exceed
the
thresholds
specified
in
paragraph
(
e)
of
this
section,
you
must
conduct
an
investigation
to
determine
if
an
emission
related
component
is
actually
defective.
(
1)
You
must
track
warranty
claims,
parts
shipments,
and
the
other
information
specified
in
paragraph
(
b)(
1)(
iii)
of
this
section.
You
must
classify
an
engine
as
possibly
having
a
defective
component
if
any
of
the
following
is
true:
(
i)
A
warranty
claim
is
submitted
for
the
component,
whether
this
is
under
your
emission
related
warranty
or
any
other
warranty.
(
ii)
You
ship
a
replacement
component
other
than
for
normally
scheduled
maintenance
during
the
useful
life
of
the
engine.
(
iii)
You
receive
any
other
information
indicating
the
component
may
be
defective,
such
as
information
from
dealers
or
hot
line
complaints.
(
2)
Your
investigation
must
be
prompt,
thorough,
consider
all
relevant
information,
follow
scientific
and
engineering
principles,
and
be
designed
to
obtain
all
the
information
specified
in
paragraph
(
d)
of
this
section.
(
3)
Your
investigation
only
needs
to
consider
defects
that
occur
within
the
useful
life
period,
or
within
five
years
after
the
end
of
the
model
year,
whichever
is
longer.
(
4)
You
must
continue
your
investigation
until
you
are
able
to
obtain
all
the
information
specified
for
a
defect
report
in
paragraph
(
d)
of
this
section.
Send
us
an
updated
defect
report
anytime
you
have
significant
additional
information.
(
5)
If
a
component
believed
to
be
defective
is
used
in
additional
engine
families
or
model
years,
you
must
investigate
whether
the
component
or
part
is
defective
when
used
in
these
additional
engine
families
or
model
years,
and
include
these
results
as
part
of
your
defect
report.
(
6)
If
your
initial
investigation
concludes
that
the
number
of
engines
with
a
defect
is
fewer
than
the
thresholds
specified
in
paragraph
(
f)
of
this
section,
but
other
information
becomes
available
that
may
show
that
the
number
of
engines
with
a
defect
exceeds
these
thresholds,
then
you
must
resume
your
investigation.
If
you
resume
an
investigation,
you
must
include
the
information
from
the
earlier
investigation
to
determine
whether
to
send
a
defect
report.
(
c)
Reporting
defects.
You
must
send
us
a
defect
report
in
either
of
the
following
cases:
(
1)
Your
investigation
shows
that
the
number
of
engines
with
a
defect
exceeds
the
thresholds
specified
in
paragraph
(
f)
of
this
section.
Send
the
defect
report
within
15
days
after
the
date
you
identify
this
number
of
defective
engines.
(
2)
You
know
a
defective
emissionrelated
component
exists
in
a
number
of
engines
that
exceeds
the
thresholds
specified
in
paragraph
(
f)
of
this
section,
regardless
of
how
you
obtain
this
information.
Send
the
defect
report
within
15
days
after
you
learn
that
the
number
of
defects
exceeds
one
of
these
thresholds.
(
d)
Contents
of
a
defect
report.
Include
the
following
information
in
a
defect
report:
(
1)
Your
corporate
name
and
a
person
to
contact
regarding
this
defect.
(
2)
A
description
of
the
defect,
including
a
summary
of
any
engineering
analyses
and
associated
data,
if
available.
(
3)
A
description
of
the
engines
that
may
have
the
defect,
including
engine
families,
models,
and
range
of
production
dates.
Note
that
you
must
address
all
model
years
for
the
engines,
not
just
the
model
year
for
which
you
triggered
the
reporting
requirement.
(
4)
An
estimate
of
the
number
and
percentage
of
each
class
or
category
of
affected
engines
that
have
or
may
have
the
defect,
and
an
explanation
of
how
you
determined
this
number.
(
5)
An
estimate
of
the
defect's
impact
on
emissions,
with
an
explanation
of
how
you
calculated
this
estimate
and
a
summary
of
any
emission
data
demonstrating
the
impact
of
the
defect,
if
available.
(
6)
A
description
of
your
plan
for
addressing
the
defect
or
an
explanation
of
your
reasons
for
not
believing
the
defects
must
be
remedied.
(
e)
Thresholds
for
conducting
a
defect
investigation.
Unless
the
standardsetting
part
specifies
otherwise,
you
must
begin
a
defect
investigation
based
on
the
following
threshold
values:
(
1)
For
engine
with
rated
power
under
560
kW:
(
i)
When
the
component
is
a
catalytic
converter
(
or
other
aftertreatment
device),
if
the
number
of
engines
in
an
engine
family
that
may
have
the
defect
exceeds
2
percent
of
the
total
number
of
engines
in
the
engine
family
or
2,000
engines,
whichever
is
less.
(
ii)
When
the
emission
related
component
is
anything
but
a
catalytic
converter
(
or
other
aftertreatment
device),
if
the
number
of
engines
in
an
engine
family
that
may
have
the
defect
exceeds
4
percent
of
the
total
number
of
engines
in
the
engine
family
or
4,000
engines,
whichever
is
less.
(
2)
For
engine
with
rated
power
greater
than
or
equal
to
560
kW,
if
the
number
of
engines
in
an
engine
family
that
may
have
the
defect
exceeds
1
percent
of
the
total
number
of
engines
in
the
engine
family
or
5
engines,
whichever
is
greater.
(
f)
Thresholds
for
filing
a
defect
report.
You
must
send
a
defect
report
based
on
the
following
threshold
values:
(
1)
For
engine
with
rated
power
under
560
kW:
(
i)
When
the
component
is
a
catalytic
converter
(
or
other
aftertreatment
device),
if
the
number
of
engines
in
an
engine
family
that
has
the
defect
exceeds
0.125
percent
of
the
total
number
of
engines
in
the
engine
family
or
125
engines,
whichever
is
less.
(
ii)
When
the
emission
related
component
is
anything
but
a
catalytic
converter
(
or
other
aftertreatment
device),
if
the
number
of
engines
in
an
engine
family
that
has
the
defect
exceeds
0.250
percent
of
the
total
number
of
engines
in
the
engine
family
or
250
engines,
whichever
is
less.
(
2)
For
engine
with
rated
power
greater
than
or
equal
to
560
kW,
if
the
number
of
engines
in
an
engine
family
that
has
the
defect
exceeds
0.5
percent
of
the
total
number
of
engines
in
the
engine
family
or
2
engines,
whichever
is
greater.
(
g)
How
to
count
defects.
In
most
cases,
you
may
track
defects
separately
for
each
model
year
and
engine
family.
For
families
with
annual
U.
S.
directed
production
volumes
under
5,000
engines,
you
may
apply
the
percentage
thresholds
in
paragraphs
(
e)
and
(
f)
of
this
section
on
the
basis
of
multiple
model
years,
for
engines
using
the
same
emission
related
components.
To
determine
whether
you
exceed
the
investigation
threshold
in
paragraph
(
e)
of
this
section,
count
defects
that
you
correct
before
they
reach
the
ultimate
purchaser.
Do
not
count
these
corrected
defects
to
determine
whether
you
exceed
the
reporting
threshold
in
paragraph
(
f)
of
this
section.
(
h)
Status
reports.
You
must
send
us
a
mid
year
or
end
of
year
status
report
if
you
concluded
an
investigation
during
the
previous
six
months
without
filing
a
defect
report
or
if
you
have
an
unresolved
investigation
at
the
end
of
the
six
month
period.
Include
the
information
specified
in
paragraph
(
c)
of
this
section,
or
explain
why
the
information
is
not
relevant.
Send
these
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/
Friday,
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8,
2002
/
Rules
and
Regulations
status
reports
no
later
than
June
30
and
December
31
of
each
year.
(
i)
Future
production.
If
you
identify
a
design
or
manufacturing
defect
that
prevents
engines
from
meeting
the
requirements
of
this
part,
you
must
correct
the
defect
as
soon
as
possible
for
any
future
production
for
engines
in
every
family
affected
by
the
defect.
This
applies
without
regard
to
whether
you
are
required
to
conduct
a
defect
investigation
or
submit
a
defect
report
under
this
section.
§
1068.505
How
does
the
recall
program
work?
(
a)
If
we
make
a
determination
that
a
substantial
number
of
properly
maintained
and
used
engines
do
not
conform
to
the
regulations
of
this
chapter
during
their
useful
life,
you
must
submit
a
plan
to
remedy
the
nonconformity
of
your
engines.
We
will
notify
you
of
our
determination
in
writing.
Our
notice
will
identify
the
class
or
category
of
engines
affected
and
describe
how
we
reached
our
conclusion.
If
this
happens,
you
must
meet
the
requirements
and
follow
the
instructions
in
this
subpart.
You
must
remedy
at
your
expense
noncompliant
engines
that
have
been
properly
maintained
and
used.
You
may
not
transfer
this
expense
to
a
dealer
or
equipment
manufacturer
through
a
franchise
or
other
agreement.
(
b)
You
may
ask
for
a
hearing
if
you
disagree
with
our
determination
(
see
subpart
G
of
this
part).
(
c)
Unless
we
withdraw
the
determination
of
noncompliance,
you
must
respond
to
it
by
sending
a
remedial
plan
to
the
Designated
Officer
by
the
later
of
these
two
deadlines:
(
1)
Within
60
days
after
we
notify
you.
(
2)
Within
60
days
after
a
hearing.
(
d)
Once
you
have
sold
an
engine
to
the
ultimate
purchaser,
we
may
inspect
or
test
the
engine
only
if
he
or
she
permits
it,
or
if
state
or
local
inspection
programs
separately
provide
for
it.
(
e)
You
may
ask
us
to
allow
you
to
conduct
your
recall
differently
than
specified
in
this
subpart,
consistent
with
section
207(
c)
of
the
Act.
§
1068.510
How
do
I
prepare
and
apply
my
remedial
plan?
(
a)
In
your
remedial
plan,
describe
all
of
the
following:
(
1)
The
class
or
category
of
engines
to
be
recalled,
including
the
number
of
engines
involved
and
the
model
year
or
other
information
needed
to
identify
the
engines.
(
2)
The
modifications,
alterations,
repairs,
corrections,
adjustments,
or
other
changes
you
will
make
to
correct
the
affected
engines.
(
3)
A
brief
description
of
the
studies,
tests,
and
data
that
support
the
effectiveness
of
the
remedy
you
propose
to
use.
(
4)
The
instructions
you
will
send
to
those
who
will
repair
the
engines
under
the
remedial
plan.
(
5)
How
you
will
determine
the
owners'
names
and
addresses.
(
6)
How
you
will
notify
owners;
include
copies
of
any
notification
letters.
(
7)
The
proper
maintenance
or
use
you
will
specify,
if
any,
as
a
condition
to
be
eligible
for
repair
under
the
remedial
plan.
Describe
how
owners
should
show
they
meet
your
conditions.
(
8)
The
steps
owners
must
take
for
you
to
do
the
repair.
You
may
set
a
date
or
a
range
of
dates,
specify
the
amount
of
time
you
need,
and
designate
certain
facilities
to
do
the
repairs.
(
9)
Which
company
(
or
group)
you
will
assign
to
do
or
manage
the
repairs.
(
10)
If
your
employees
or
authorized
warranty
agents
will
not
be
doing
the
work,
state
who
will
and
say
they
can
do
it.
(
11)
How
you
will
ensure
an
adequate
and
timely
supply
of
parts.
(
12)
The
effect
of
proposed
changes
on
fuel
consumption,
driveability,
and
safety
of
the
engines
you
will
recall;
include
a
brief
summary
of
the
information
supporting
these
conclusions.
(
13)
How
you
intend
to
label
the
engines
you
repair
and
where
you
will
place
the
label
on
the
engine
(
see
§
1068.515).
(
b)
We
may
require
you
to
add
information
to
your
remedial
plan.
(
c)
We
may
require
you
to
test
the
proposed
repair
to
show
it
will
remedy
the
noncompliance.
(
d)
Use
all
reasonable
means
to
locate
owners.
We
may
require
you
to
use
government
or
commercial
registration
lists
to
get
owners'
names
and
addresses,
so
your
notice
will
be
effective.
(
e)
The
maintenance
or
use
that
you
specify
as
a
condition
for
eligibility
under
the
remedial
plan
may
include
only
things
you
can
show
would
cause
noncompliance.
Do
not
require
use
of
a
component
or
service
identified
by
brand,
trade,
or
corporate
name,
unless
we
approved
this
approach
with
your
original
certificate
of
conformity.
Also,
do
not
place
conditions
on
who
maintained
the
engine.
(
f)
We
may
require
you
to
adjust
your
repair
plan
if
we
determine
owners
would
be
without
their
engines
or
equipment
for
an
unreasonably
long
time.
(
g)
We
will
tell
you
in
writing
within
15
days
of
receiving
your
remedial
plan
whether
we
have
approved
or
disapproved
it.
We
will
explain
our
reasons
for
any
disapproval.
(
h)
Begin
notifying
owners
within
15
days
after
we
approve
your
remedial
plan.
If
we
hold
a
hearing,
but
do
not
change
our
position
about
the
noncompliance,
you
must
begin
notifying
owners
within
60
days
after
we
complete
the
hearing,
unless
we
specify
otherwise.
§
1068.515
How
do
I
mark
or
label
repaired
engines?
(
a)
Attach
a
label
to
each
engine
you
repair
under
the
remedial
plan.
At
your
discretion,
you
may
label
or
mark
engines
you
inspect
but
do
not
repair.
(
b)
Make
the
label
from
a
durable
material
suitable
for
its
planned
location.
Make
sure
no
one
can
remove
the
label
without
destroying
or
defacing
it.
(
c)
On
the
label,
designate
the
specific
recall
campaign
and
state
where
you
repaired
or
inspected
the
engine.
(
d)
We
may
waive
or
modify
the
labeling
requirements
if
we
determine
they
are
overly
burdensome.
§
1068.520
How
do
I
notify
affected
owners?
(
a)
Notify
owners
by
first
class
mail,
unless
we
say
otherwise.
We
may
require
you
to
use
certified
mail.
Include
the
following
in
your
notice:
(
1)
State:
``
The
U.
S.
Environmental
Protection
Agency
has
determined
that
your
engine
may
be
emitting
pollutants
in
excess
of
the
Federal
emission
standards,
as
defined
in
Title
40
of
the
Code
of
Federal
Regulations.
These
emission
standards
were
established
to
protect
the
public
health
or
welfare
from
air
pollution''.
(
2)
State
that
you
(
or
someone
you
designate)
will
repair
these
engines
at
your
expense.
(
3)
If
we
approved
maintenance
and
use
conditions
in
your
remedial
plan,
state
that
you
will
make
these
repairs
only
if
owners
show
their
engines
meet
the
conditions
for
proper
maintenance
and
use.
Describe
these
conditions
and
how
owners
should
prove
their
engines
are
eligible
for
repair.
(
4)
Describe
the
components
your
repair
will
affect
and
say
generally
how
you
will
repair
the
engines.
(
5)
State
that
the
engine,
if
not
repaired,
may
fail
an
emission
inspection
test
if
state
or
local
law
requires
one.
(
6)
Describe
any
adverse
effects
on
its
performance
or
driveability
that
would
be
caused
by
not
repairing
the
engine.
(
7)
Describe
any
adverse
effects
on
the
functions
of
other
engine
components
that
would
be
caused
by
not
repairing
the
engine.
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Vol.
67,
No.
217
/
Friday,
November
8,
2002
/
Rules
and
Regulations
(
8)
Specify
the
date
you
will
start
the
repairs,
the
amount
of
time
you
will
need
to
do
them,
and
where
you
will
do
them.
Include
any
other
information
owners
may
need
to
know.
(
9)
Include
a
self
addressed
card
that
owners
can
mail
back
if
they
have
sold
the
engine
(
or
equipment
in
which
the
engine
is
installed);
include
a
space
for
owners
to
write
the
name
and
address
of
a
buyer.
(
10)
State
that
owners
should
call
you
at
a
phone
number
you
give
to
report
any
difficulty
in
obtaining
repairs.
(
11)
State:
``
To
ensure
your
full
protection
under
the
emission
warranty
on
your
engine
by
federal
law,
and
your
right
to
participate
in
future
recalls,
we
recommend
you
have
your
engine
serviced
as
soon
as
possible.
We
may
consider
your
not
servicing
it
to
be
improper
maintenance''.
(
b)
We
may
require
you
to
add
information
to
your
notice
or
to
send
more
notices.
(
c)
You
may
not
in
any
communication
with
owners
or
dealers
say
or
imply
that
your
noncompliance
does
not
exist
or
that
it
will
not
degrade
air
quality.
§
1068.525
What
records
must
I
send
to
EPA?
(
a)
Send
us
a
copy
of
all
communications
related
to
the
remedial
plan
you
sent
to
dealers
and
others
doing
the
repairs.
Mail
or
e
mail
us
the
information
at
the
same
time
you
send
it
to
others.
(
b)
From
the
time
you
begin
to
notify
owners,
send
us
a
report
within
25
days
of
the
end
of
each
calendar
quarter.
Send
reports
for
six
consecutive
quarters
or
until
all
the
engines
are
inspected,
whichever
comes
first.
In
these
reports,
identify
the
following:
(
1)
The
range
of
dates
you
needed
to
notify
owners.
(
2)
The
total
number
of
notices
sent.
(
3)
The
number
of
engines
you
estimate
fall
under
the
remedial
plan
(
explain
how
you
determined
this
number).
(
4)
The
cumulative
number
of
engines
you
inspected
under
the
remedial
plan.
(
5)
The
cumulative
number
of
these
engines
you
found
needed
the
specified
repair.
(
6)
The
cumulative
number
of
these
engines
you
have
repaired.
(
7)
The
cumulative
number
of
engines
you
determined
to
be
unavailable
due
to
exportation,
theft,
retirement,
or
other
reasons
(
specify).
(
8)
The
cumulative
number
of
engines
you
disqualified
for
not
being
properly
maintained
or
used.
(
c)
If
your
estimated
number
of
engines
falling
under
the
remedial
plan
changes,
change
the
estimate
in
your
next
report
and
add
an
explanation
for
the
change.
(
d)
We
may
ask
for
more
information.
(
e)
We
may
waive
reporting
requirements
or
adjust
the
reporting
schedule.
(
f)
If
anyone
asks
to
see
the
information
in
your
reports,
we
will
follow
the
provisions
of
§
1068.10
for
handling
confidential
information.
§
1068.530
What
records
must
I
keep?
We
may
review
your
records
at
any
time,
so
it
is
important
that
you
keep
required
information
readily
available.
Keep
records
associated
with
your
recall
campaign
for
three
years
after
you
complete
your
remedial
plan.
Organize
and
maintain
your
records
as
described
in
this
section.
(
a)
Keep
a
paper
copy
of
the
written
reports
described
in
§
1068.525.
(
b)
Keep
a
record
of
the
names
and
addresses
of
owners
you
notified.
For
each
engine,
state
whether
you
did
any
of
the
following:
(
1)
Inspected
the
engine.
(
2)
Disqualified
the
engine
for
not
being
properly
maintained
or
used.
(
3)
Completed
the
prescribed
repairs.
(
c)
You
may
keep
the
records
in
paragraph
(
b)
of
this
section
in
any
form
we
can
inspect,
including
computer
databases.
§
1068.535
How
can
I
do
a
voluntary
recall
for
emission
related
problems?
If
we
have
made
a
determination
that
a
substantial
number
of
properly
maintained
and
used
engines
do
not
conform
to
the
regulations
of
this
chapter
during
their
useful
life,
you
may
not
use
a
voluntary
recall
or
other
alternate
means
to
meet
your
obligation
to
remedy
the
noncompliance.
Thus,
this
section
only
applies
where
you
learn
that
your
engine
family
does
not
meet
the
requirements
of
this
chapter
and
we
have
not
made
such
a
determination.
(
a)
To
do
a
voluntary
recall
under
this
section,
first
send
the
Designated
Officer
a
plan,
following
the
guidelines
in
§
1068.510.
Within
15
days,
we
will
send
you
our
comments
on
your
plan.
(
b)
Once
we
approve
your
plan,
start
notifying
owners
and
carrying
out
the
specified
repairs.
(
c)
From
the
time
you
start
the
recall
campaign,
send
us
a
report
within
25
days
of
the
end
of
each
calendar
quarter,
following
the
guidelines
in
§
1068.525(
b).
Send
reports
for
six
consecutive
quarters
or
until
all
the
engines
are
inspected,
whichever
comes
first.
(
d)
Keep
your
reports
and
the
supporting
information
as
described
in
§
1068.530.
§
1068.540
What
terms
do
I
need
to
know
for
this
subpart?
The
following
terms
apply
to
this
subpart:
Days
means
calendar
days.
Owner
means
someone
who
owns
an
engine
affected
by
a
remedial
plan
or
someone
who
owns
a
piece
of
equipment
that
has
one
of
these
engines.
Subpart
G
Hearings
§
1068.601
What
are
the
procedures
for
hearings?
If
we
agree
to
hold
a
hearing
related
to
our
decision
to
order
a
recall
under
§
1068.505,
we
will
hold
the
hearing
according
to
the
provisions
of
40
CFR
85.1807.
For
any
other
issues,
you
may
request
an
informal
hearing,
as
described
in
40
CFR
86.1853
01.
Appendix
I
to
Part
1068
Emission
Related
Components
This
appendix
specifies
emission
related
components
that
we
refer
to
for
describing
such
things
as
emission
related
defects
or
requirements
related
to
rebuilding
engines.
I.
Emission
related
components
include
any
engine
parts
related
to
the
following
systems:
1.
Air
induction
system.
2.
Fuel
system.
3.
Ignition
system.
4.
Exhaust
gas
recirculation
systems.
II.
The
following
parts
are
also
considered
emission
related
components:
1.
Aftertreatment
devices.
2.
Crankcase
ventilation
valves.
3.
Sensors.
4.
Electronic
control
units.
III.
Emission
related
components
also
include
any
other
part
whose
only
purpose
is
to
reduce
emissions
or
whose
failure
will
increase
emissions
without
significantly
degrading
engine
performance.
IV.
We
also
consider
the
emission
control
information
label
to
be
an
emissionrelated
component.
Appendix
II
to
Part
1068
Emission
Related
Parameters
and
Specifications
This
appendix
specifies
emission
related
parameters
and
specifications
that
we
refer
to
for
describing
such
things
as
emission
related
defects
or
requirements
related
to
rebuilding
engines.
I.
Basic
Engine
Parameters
Reciprocating
Engines.
1.
Compression
ratio.
2.
Type
of
air
aspiration
(
natural,
Rootsblown
supercharged,
turbocharged).
3.
Valves
(
intake
and
exhaust).
a.
Head
diameter
dimension.
b.
Valve
lifter
or
actuator
type
and
valve
lash
dimension.
4.
Camshaft
timing.
a.
Valve
opening
intake
exhaust
(
degrees
from
top
dead
center
or
bottom
dead
center).
b.
Valve
closing
intake
exhaust
(
degrees
from
top
dead
center
or
bottom
dead
center).
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/
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8,
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/
Rules
and
Regulations
c.
Valve
overlap
(
degrees).
5.
Ports
two
stroke
engines
(
intake
and/
or
exhaust).
a.
Flow
area.
b.
Opening
timing
(
degrees
from
top
dead
center
or
bottom
dead
center).
c.
Closing
timing
(
degrees
from
top
dead
center
or
bottom
dead
center).
II.
Intake
Air
System.
1.
Roots
blower/
supercharger/
turbocharger
calibration.
2.
Charge
air
cooling.
a.
Type
(
air
to
air;
air
to
liquid).
b.
Type
of
liquid
cooling
(
engine
coolant,
dedicated
cooling
system).
c.
Performance.
3.
Temperature
control
system
calibration.
4.
Maximum
allowable
inlet
air
restriction.
III.
Fuel
System.
1.
General.
a.
Engine
idle
speed.
b.
Engine
idle
mixture.
2.
Carburetion.
a.
Air
fuel
flow
calibration.
b.
Idle
mixture.
c.
Transient
enrichment
system
calibration.
d.
Starting
enrichment
system
calibration.
e.
Altitude
compensation
system
calibration.
f.
Hot
idle
compensation
system
calibration.
3.
Fuel
injection
for
spark
ignition
engines.
a.
Control
parameters
and
calibrations.
b.
Idle
mixture.
c.
Fuel
shutoff
system
calibration.
d.
Starting
enrichment
system
calibration.
e.
Transient
enrichment
system
calibration.
f.
Air
fuel
flow
calibration.
g.
Altitude
compensation
system
calibration.
h.
Operating
pressure(
s).
i.
Injector
timing
calibration.
4.
Fuel
injection
for
compression
ignition
engines.
a.
Control
parameters
and
calibrations.
b.
Transient
enrichment
system
calibration.
c.
Air
fuel
flow
calibration.
d.
Altitude
compensation
system
calibration.
e.
Operating
pressure(
s).
f.
Injector
timing
calibration.
IV.
Ignition
System
for
Spark
ignition
Engines.
1.
Control
parameters
and
calibration.
2.
Initial
timing
setting.
3.
Dwell
setting.
4.
Altitude
compensation
system
calibration.
5.
Spark
plug
voltage.
V.
Engine
Cooling
System
thermostat
calibration.
VI.
Exhaust
System
maximum
allowable
back
pressure.
VII.
System
for
Controlling
Exhaust
Emissions.
1.
Air
injection
system.
a.
Control
parameters
and
calibrations.
b.
Pump
flow
rate.
2.
EGR
system.
a.
Control
parameters
and
calibrations.
b.
EGR
valve
flow
calibration.
3.
Catalytic
converter
system.
a.
Active
surface
area.
b.
Volume
of
catalyst.
c.
Conversion
efficiency.
4.
Backpressure.
VIII.
System
for
Controlling
Crankcase
Emissions.
1.
Control
parameters
and
calibrations.
2.
Valve
calibrations.
IX.
Auxiliary
Emission
Control
Devices
(
AECD).
1.
Control
parameters
and
calibrations.
2.
Component
calibration(
s).
X.
System
for
Controlling
Evaporative
Emissions.
1.
Control
parameters
and
calibrations.
2.
Fuel
tank.
a.
Volume.
b.
Pressure
and
vacuum
relief
settings.
XI.
Warning
Systems
Related
to
Emission
Controls.
1.
Control
parameters
and
calibrations.
2.
Component
calibrations.
[
FR
Doc.
02
23801
Filed
11
7
02;
8:
45
am]
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CODE
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"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0065-0001/content.txt"
} |
EPA-HQ-OAR-2002-0067-0001 | Proposed Rule | "2002-12-27T05:00:00" | Stay of Authority Under 40 CFR 50.9(b) Related to
Applicability of 1-Hour Ozone Standard; Proposed Rule | Friday,
December
27,
2002
Part
VI
Environmental
Protection
Agency
40
CFR
Part
50
Stay
of
Authority
Under
40
CFR
50.9(
b)
Related
to
Applicability
of
1
Hour
Ozone
Standard;
Proposed
Rule
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67,
No.
249
/
Friday,
December
27,
2002
/
Proposed
Rules
1
Part
D
of
title
I
of
the
Clean
Air
Act
(
CAA)
contains
a
number
of
subparts
concerning
implementation
of
the
NAAQS.
Subpart
1
applies
for
purposes
of
implementing
all
new
or
revised
NAAQS.
Subparts
2
5,
each
apply
to
one
or
more
specific
NAAQS.
At
the
time
EPA
promulgated
the
8
hour
ozone
NAAQS,
EPA
indicated
that
it
believed
subpart
1
was
the
only
subpart
that
would
apply
for
purposes
of
implementing
the
revised
8
hour
NAAQS
and
stated
that
subpart
2,
which
specifically
addresses
ozone,
applied
only
for
purposes
of
implementing
the
1
hour
ozone
standard.
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
50
[
FRL
7430
2]
Stay
of
Authority
Under
40
CFR
50.9(
b)
Related
to
Applicability
of
1
Hour
Ozone
Standard
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Notice
of
proposed
rulemaking
(
NPRM).
SUMMARY:
The
EPA
is
proposing
to
stay
its
authority
under
the
second
sentence
of
40
CFR
50.9(
b)
to
determine
that
an
area
has
attained
the
1
hour
standard
(``
Proposed
Stay'')
and
that
the
1
hour
standard
no
longer
applies.
The
EPA
proposes
that
the
stay
shall
be
effective
until
such
time
as
EPA
takes
final
action
in
a
subsequent
rulemaking
addressing
whether
the
second
sentence
of
40
CFR
50.9(
b)
should
be
modified
in
light
of
the
Supreme
Court's
decision
in
Whitman
v.
American
Trucking
Ass'ns,
Inc.,
531
U.
S.
457
(
2001),
remanding
EPA's
strategy
for
the
implementation
of
the
8
hour
ozone
NAAQS
to
EPA
for
further
consideration.
In
the
subsequent
rulemaking
reconsidering
the
second
sentence
of
40
CFR
50.9(
b),
EPA
will
consider
and
address
any
comments
concerning
(
a)
which,
if
any,
implementation
activities
for
an
8
hour
ozone
standard,
including
designations
and
classifications,
would
need
to
occur
before
EPA
would
determine
that
the
1
hour
ozone
standard
no
longer
applies
to
an
area,
and
(
b)
the
effect
of
revising
the
ozone
NAAQS
on
the
existing
1
hour
ozone
designations.
DATES:
To
be
considered,
comments
must
be
received
on
or
before
January
27,
2003.
ADDRESSES:
Comments
should
be
submitted
(
in
duplicate,
if
possible)
to
the
EPA
Docket
Center
(
6102T),
Attention:
Docket
Number
OAR
2002
0067,
U.
S.
Environmental
Protection
Agency,
EPA
West
(
Air
Docket),
1200
Pennsylvania
Avenue,
NW.,
Room:
B108,
Washington,
DC
20460,
telephone
(
202)
566
1742,
fax
(
202)
566
1741,
between
8:
30
a.
m.
and
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
To
mail
comments
through
Federal
Express,
UPS
or
other
courier
services,
the
mailing
address
is:
EPA
Docket
Center
(
Air
Docket,
U.
S.
Environmental
Protection
Agency,
1301
Constitution
Avenue,
NW.,
Room:
B108,
Mail
Code:
6102T,
Washington,
DC
20004.
A
reasonable
fee
may
be
charged
for
copying.
Comments
and
data
may
also
be
submitted
electronically
by
following
the
instructions
under
SUPPLEMENTARY
INFORMATION
of
this
document.
No
confidential
business
information
should
be
submitted
through
e
mail.
FOR
FURTHER
INFORMATION
CONTACT:
Questions
concerning
this
NPRM
should
be
addressed
to
Annie
Nikbakht,
Office
of
Air
Quality
Planning
and
Standards,
Air
Quality
Strategies
and
Standards
Division,
Ozone
Policy
and
Strategies
Group,
MD
C539
02,
Research
Triangle
Park,
NC
27711,
telephone
(
919)
541
5246.
SUPPLEMENTARY
INFORMATION:
Electronic
Availability
The
official
record
for
this
proposed
rule,
as
well
as
the
public
version,
has
been
established
under
Docket
Number
OAR
2002
0067.
Submit
comments
by
e
mail
to
address:
www.
epa.
gov/
rpas.
Table
of
Contents
I.
Background
II.
Summary
of
Today's
Action
III.
Statutory
and
Executive
Order
Reviews
I.
Background
A.
The
Revised
8
Hour
Ozone
NAAQS
On
July
18,
1997,
the
EPA
promulgated
a
revised
8
hour
National
Ambient
Air
Quality
Standard
(
NAAQS)
for
ozone.
The
rule
was
challenged
by
a
number
of
industry
groups
and
States
in
the
Court
of
Appeals
for
the
District
of
Columbia
Circuit
(
D.
C.
Circuit).
The
Court
granted
many
aspects
of
those
challenges
and
remanded
the
8
hour
ozone
NAAQS
to
EPA.
American
Trucking
Ass'ns,
Inc.
v.
EPA,
175
F.
3d
1027
(
D.
C.
Cir.
1999)
(``
ATA'').
With
respect
to
EPA's
authority
to
implement
the
revised
8
hour
ozone
standard,
the
Court
held
that
the
statute
was
clear
on
its
face
that
the
provisions
of
``
subpart
2''
applied
and
then
held
that
under
the
terms
of
the
statute,
the
8
hour
standard
``
cannot
be
enforced.''
1
Id.
at
1048
1050,
1057.
The
Court
also
remanded
the
standard
to
EPA
on
the
ground
that,
under
EPA's
interpretation
of
its
authority
to
promulgate
the
NAAQS,
the
CAA
provided
an
unconstitutional
delegation
of
authority
to
EPA.
Id.
at
1034
1040.
Finally,
the
Court
held
that
EPA
had
failed
to
consider
whether
ground
level
ozone
had
some
beneficial
effects,
in
particular,
whether
groundlevel
ozone
acted
as
a
shield
from
the
harmful
effects
of
ultraviolet
radiation.
Id.
at
1051
1053.
The
D.
C.
Circuit
largely
denied
EPA's
request
for
rehearing,
but
did
modify
its
decision
to
say
that
the
8
hour
NAAQS
could
be
enforced,
but
only
in
conformity
with
certain
ozone
specific
provisions
(
subpart
2)
enacted
in
1990.
ATA
II,
195
F.
3d
4
(
D.
C.
Cir.
1999).
The
EPA
requested
review
by
the
Supreme
Court
of
two
aspects
of
the
D.
C.
Circuit's
decision
the
delegation
and
implementation
issues.
The
Court
agreed
to
consider
the
case
and
on
February
27,
2000,
rejected
the
D.
C.
Circuit's
holding
that
EPA's
interpretation
of
the
CAA
resulted
in
an
unconstitutional
delegation
of
authority.
Whitman
v.
American
Trucking
Ass'ns,
Inc.,
531
U.
S.
457,
472
476
(
2001)
(
Whitman).
While
disagreeing
with
the
Court
of
Appeals
that
the
CAA
was
clear
on
its
face
that
subpart
2
applied
for
purposes
of
implementing
the
revised
ozone
standard,
the
Court
found
unreasonable
EPA's
assertion
that
subpart
2
was
inapplicable
for
implementation
of
the
8
hour
ozone
NAAQS.
The
Court
remanded
the
implementation
strategy
to
EPA
for
further
consideration.
Id.
at
481
486.
B.
EPA's
Revocation
Rules
Simultaneous
with
its
promulgation
of
the
8
hour
ozone
NAAQS
on
July
18,
1997,
EPA
promulgated
a
final
rule
governing
the
continued
applicability
of
the
existing
1
hour
ozone
NAAQS.
40
CFR
50.9(
b).
The
relevant
language
in
40
CFR
50.9(
b)
provides:
``
The
1
hour
standards
set
forth
in
this
section
will
no
longer
apply
to
an
area
once
EPA
determines
that
the
area
has
air
quality
meeting
the
1
hour
standard.
Area
designations
are
codified
in
40
CFR
part
81.''
In
part,
EPA
based
this
approach
on
its
interpretation
that
the
provisions
of
subpart
2
of
part
D
of
title
I
of
the
CAA
applied
as
a
matter
of
law
for
purposes
of
implementing
the
1
hour
ozone
NAAQS,
but
that
they
would
not
apply
for
purposes
of
implementing
the
revised
ozone
standard.
Thus,
EPA
believed
it
made
sense
to
delay
revocation
of
the
1
hour
standard
until
such
time
as
the
provisions
of
subpart
2
would
no
longer
apply
and,
at
that
time,
revoke
the
1
hour
standard.
Thus,
once
an
area
attained
the
1
hour
standard
and
EPA
determined
the
1
hour
standard
no
longer
applied
to
that
area,
the
provisions
of
subpart
2
would
also
no
longer
apply.
On
June
5,
1998,
EPA
issued
a
final
rule
determining
that
over
2,000
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/
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December
27,
2002
/
Proposed
Rules
2
In
addition
to
the
two
Revocation
Rules
that
were
challenged,
EPA
issued
a
third
Revocation
Rule
on
July
22,
1998
that
was
not
challenged,
(
63
FR
39432).
counties
had
attained
the
1
hour
ozone
standard
and
that,
therefore,
the
1
hour
standard
and
the
associated
designation
for
that
standard
no
longer
applied
to
those
areas.
See
``
Identification
of
Ozone
Areas
Attaining
the
1
Hour
Standard
to
Which
the
1
Hour
Standard
is
No
Longer
Applicable,''
(
63
FR
31014,
June
5,
1998)
(``
Revocation
Rule'').
Subsequently,
on
August
3,
1998,
Environmental
Defense
and
the
Natural
Resources
Defense
Council
(
collectively
``
Environmental
Defense'')
filed
a
petition
for
review
challenging
that
rule.
Environmental
Defense
v.
EPA
(
No.
98
1363,
D.
C.
Cir.).
On
June
9,
1999,
EPA
issued
a
final
rule
determining
that
the
1
hour
ozone
standard
no
longer
applied
in
an
additional
ten
areas.
Appalachian
Mountain
Club
filed
a
petition
for
review
challenging
that
action
August
9,
1999.
Appalachian
Mountain
Club
v.
EPA,
No.
99
1880
(
1st
Cir.).
Because
of
the
doubt
cast
on
the
8
hour
standard
and
EPA's
authority
to
enforce
it
by
the
D.
C.
Circuit
in
the
ATA
case,
on
July
20,
2000,
EPA
issued
a
final
rule
rescinding
the
Revocation
Rules,
(
65
FR
45182,
July
20,
2000)
(
Rescission
Rule).
2
Thus,
EPA
reinstated
the
1
hour
ozone
NAAQS
for
all
of
the
counties
for
which
EPA
previously
determined
that
the
1
hour
ozone
NAAQS
no
longer
applied.
As
part
of
the
Rescission
Rule,
EPA
modified
the
second
sentence
in
40
CFR
50.9(
b)
to
provide:
``
In
addition,
after
the
8
hour
standard
has
become
fully
enforceable
under
part
D
of
title
I
of
the
CAA
and
subject
to
no
further
legal
challenge,
the
1
hour
standards
set
forth
in
this
section
will
no
longer
apply
to
an
area
once
EPA
determines
that
the
area
has
air
quality
meeting
the
1
hour
standard.
Area
designations
and
classifications
with
respect
to
the
1
hour
standards
are
codified
in
40
CFR
part
81.''
C.
Revocation
Rule
Litigation
The
parties
in
both
the
Environmental
Defense
and
the
Appalachian
Mountain
Club
cases
determined
to
stay
the
litigation
based
on
EPA's
Rescission
Rule
and
the
continued
litigation
regarding
the
8
hour
ozone
NAAQS
and
EPA's
authority
to
implement
that
standard.
Following
the
Supreme
Court's
decision
in
the
Whitman
case,
the
parties
negotiated
a
Settlement
Agreement
that
provided
for
EPA
to
issue
this
proposal
to
stay
its
authority
under
40
CFR
50.9(
b)
while
EPA
considers
whether
to
modify
the
language
in
40
CFR
50.9(
b)
regarding
the
process
and
basis
for
revoking
the
1
hour
ozone
standard.
See
67
FR
48896
(
July
26,
2002).
Environmental
Defense
and
Appalachian
Mountain
Club
have
agreed
to
dismiss
their
cases
if
EPA
issues
a
final
rule
staying
the
revocation
provision
in
40
CFR
50.9(
b)
until
such
time
as
EPA
considers
in
a
subsequent
rulemaking
whether
that
provision
should
be
modified
and,
in
the
final
stay,
commits
to
consider
and
address
in
the
subsequent
rulemaking
any
comments
concerning
(
a)
which,
if
any,
implementation
activities
for
a
revised
ozone
standard
(
including
but
not
limited
to
designation
and
classification
of
areas)
would
need
to
occur
before
EPA
would
determine
that
the
1
hour
ozone
standard
no
longer
applied
to
an
area,
and
(
b)
the
effect
of
revising
the
ozone
NAAQS
on
existing
designations
for
the
pollutant
ozone.
II.
Summary
of
Today's
Action
The
EPA
is
proposing
to
stay
its
authority
under
the
second
sentence
of
40
CFR
50.9(
b)
to
determine
that
an
area
has
attained
the
1
hour
standard
and
that
the
1
hour
standard
no
longer
applies.
The
EPA
proposes
that
the
stay
shall
be
effective
until
such
time
as
EPA
takes
final
agency
action
in
a
subsequent
rulemaking
addressing
whether
the
second
sentence
of
40
CFR
50.9(
b)
should
be
modified
in
light
of
the
Supreme
Court's
decision
in
Whitman
regarding
implementation
of
the
8
hour
NAAQS.
In
developing
a
revised
8
hour
implementation
strategy
consistent
with
the
Supreme
Court's
decision,
EPA
will
consider
and
address
any
comments
concerning
(
a)
which,
if
any,
implementation
activities
for
an
8
hour
ozone
standard,
including
designations
and
classifications,
would
need
to
occur
before
EPA
would
determine
that
the
1
hour
ozone
standard
no
longer
applied
to
an
area,
and
(
b)
the
effect
of
revising
the
ozone
NAAQS
on
existing
designations
for
the
pollutant
ozone.
The
EPA
plans
to
consider
the
timeframe
and
basis
for
revoking
the
1
hour
standard
in
the
implementation
rulemaking
that
it
plans
to
issue
in
response
to
the
Supreme
Court's
remand.
The
EPA
believes
that
it
is
appropriate
to
reconsider
this
issue
because,
at
the
time
EPA
promulgated
§
50.9(
b),
EPA
anticipated
that
subpart
2
would
not
apply
for
purposes
of
implementing
the
revised
ozone
standard.
It
makes
sense,
in
light
of
the
many
issues
that
are
now
being
considered
regarding
implementation
of
the
8
hour
standard,
including
the
applicability
of
subpart
2
for
purposes
of
implementing
that
standard,
for
EPA
to
consider
simultaneously
the
most
effective
means
to
transition
from
implementation
of
the
1
hour
standard
to
implementation
of
the
revised
8
hour
ozone
NAAQS.
III.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
the
EPA
must
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
OMB
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
a
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
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
entitlement,
grants,
user
fees,
or
loan
programs
or
the
rights
and
obligations
of
recipients
thereof;
or
(
4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
it
has
been
determined
that
this
action
is
not
a
``
significant
regulatory
action''
and
was
not
submitted
to
OMB
for
review.
B.
Paperwork
Reduction
Act
This
proposed
rule
does
not
contain
any
information
collection
requirements
which
require
OMB
approval
under
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.).
C.
Regulatory
Flexibility
Act
(
RFA)
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
noticeand
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
proposed
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
A
small
business
as
defined
in
the
Small
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249
/
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December
27,
2002
/
Proposed
Rules
Business
Administration's
(
SBA)
regulations
at
13
CFR
12.201;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
forprofit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
This
action
will
not
impose
any
requirements
on
small
entities.
This
action
proposes
to
stay
EPA's
authority
under
the
second
sentence
of
40
CFR
50.9(
b)
to
determine
that
an
area
has
attained
the
1
hour
standard
and
that
the
1
hour
standard
no
longer
applies.
It
does
not
establish
requirements
applicable
to
small
entities.
D.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
Tribal
governments,
and
the
private
sector.
Under
section
202
of
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
by
State,
local,
and
Tribal
governments,
in
the
aggregate,
or
by
the
private
sector,
of
$
100
million
or
more
in
any
one
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost
effective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
laws.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
Tribal
governments,
it
must
have
developed
under
section
203
of
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
This
proposed
action
also
does
not
impose
any
additional
enforceable
duty,
contain
any
unfunded
mandate,
or
impose
any
significant
or
unique
impact
on
small
governments
as
described
in
UMRA.
Because
today's
action
does
not
create
any
additional
mandates,
no
further
UMRA
analysis
is
needed.
E.
Executive
Order
13132:
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
are
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
Under
section
6
of
Executive
Order
13132,
EPA
may
not
issue
a
regulation
that
has
federalism
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,
unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
State
and
local
governments,
or
EPA
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
The
EPA
also
may
not
issue
a
regulation
that
has
federalism
implications
and
that
preempts
State
law,
unless
the
Agency
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
This
proposed
action
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
This
action
stays
the
language
of
40
CFR
50.9(
b)
regarding
EPA's
authority
to
take
action
and
imposes
no
additional
burdens
on
States
or
local
entities;
it
does
not
change
the
existing
relationship
between
the
national
government
and
the
States
or
the
distribution
of
power
and
responsibilities
among
the
various
branches
of
government.
Thus,
the
requirements
of
section
6
of
this
Executive
Order
do
not
apply
to
this
proposed
rule.
F.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
9,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
Tribal
implications.''
This
proposed
rule
does
not
have
Tribal
implications,
as
specified
in
Executive
Order
13175,
because
it
will
not
have
a
substantial
direct
effect
on
one
or
more
Indian
Tribes,
on
the
relationship
between
the
Federal
Government
and
Indian
Tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
Government
and
Indian
Tribes.
Today's
action
does
not
significantly
or
uniquely
affect
the
communities
of
Indian
Tribal
governments,
and
does
not
impose
substantial
direct
compliance
costs
on
such
communities.
Thus,
Executive
Order
13175
does
not
apply
to
this
proposed
rule.
G.
Executive
Order
13045:
Protection
of
Children
From
Environmental
Health
and
Safety
Risks
The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
501
of
the
Order
has
the
potential
to
influence
the
regulation.
This
proposed
rule
is
not
subject
to
Executive
Order
13045,
because
this
action
is
not
``
economically
significant''
as
defined
under
Executive
Order
12866
and
there
are
no
environmental
health
risks
or
safety
risks
addressed
by
this
rule.
H.
Executive
Order
13211:
Actions
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
rule
is
not
subject
to
Executive
Order
13211,
``
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(
66
FR
28355,
May
22,
2001)
because
it
is
not
a
significant
regulatory
action
under
Executive
Order
12866.
I.
National
Technology
Transfer
Advancement
Act
Section
12
of
the
National
Technology
Transfer
Advancement
Act
(
NTTAA)
of
1995
requires
Federal
agencies
to
evaluate
existing
technical
standards
when
developing
new
regulations.
To
comply
with
NTTAA,
EPA
must
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Federal
Register
/
Vol.
67,
No.
249
/
Friday,
December
27,
2002
/
Proposed
Rules
consider
and
use
``
voluntary
consensus
standards''
(
VCS)
if
available
and
applicable
when
developing
programs
and
policies
unless
doing
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
The
EPA
believes
that
VCS
are
inapplicable
to
this
proposed
action.
Today's
proposed
action
does
not
require
the
public
to
perform
activities
conducive
to
the
use
of
VCS.
J.
Executive
Order
12898:
Federal
Actions
to
Address
Environmental
Justice
in
Minority
Populations
and
Low
Income
Populations
Under
Executive
Order
12898,
each
Federal
agency
must
make
achieving
environmental
justice
part
of
its
mission
by
identifying
and
addressing,
as
appropriate,
disproportionately
high
and
adverse
human
health
or
environmental
effects
of
its
programs,
policies,
and
activities
on
minorities
and
low
income
populations.
Today's
proposed
action
to
stay
EPA's
authority
under
40
CFR
50.9(
b)
related
to
applicability
of
the
1
hour
ozone
standard
does
not
have
a
disproportionate
adverse
effect
on
minorities
and
low
income
populations.
List
of
Subjects
in
40
CFR
Part
50
Environmental
protection,
Air
pollution
control,
Carbon
monoxide,
Lead,
Nitrogen
dioxide,
Ozone,
Particulate
matter,
Sulfur
oxides.
Dated:
December
19,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
set
forth
in
the
preamble,
part
50
of
chapter
I
of
title
40
of
the
Code
of
Federal
Regulations
is
proposed
to
be
amended
as
follows:
PART
50
AMENDED
1.
The
authority
citation
for
part
50
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7410,
et
seq.
2.
Section
50.9
is
proposed
to
be
amended
by
adding
paragraph
(
c)
to
read
as
follows:
§
50.9
National
1
hour
primary
and
secondary
ambient
air
quality
standards
for
ozone.
*
*
*
*
*
(
c)
EPA's
authority
under
paragraph
(
b)
of
this
section
to
determine
that
an
area
has
attained
the
1
hour
standard
and
that
the
1
hour
standard
no
longer
applies
is
stayed
until
such
time
as
EPA
issues
a
final
rule
revising
or
reinstating
such
authority.
[
FR
Doc.
02
32577
Filed
12
26
02;
8:
45
am]
BILLING
CODE
6560
50
P
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| epa | 2024-06-07T20:31:40.518172 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0067-0001/content.txt"
} |
EPA-HQ-OAR-2002-0068-0086 | Proposed Rule | "2002-12-31T05:00:00" | Prevention of Significant Deterioration (PSD) and Non-attainment New Source Review (NSR): Routine Maintenance, Repair and Replacement | 80290
Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
51
and
52
[
FRL
7414
6;
Docket
A
2002
4]
RIN
2060
AK28
Prevention
of
Significant
Deterioration
(
PSD)
and
Non
attainment
New
Source
Review
(
NSR):
Routine
Maintenance,
Repair
and
Replacement
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Proposed
rule.
SUMMARY:
The
EPA
is
proposing
revisions
to
the
regulations
governing
the
NSR
programs
mandated
by
parts
C
and
D
of
title
I
of
the
Clean
Air
Act
(
CAA).
These
proposed
changes
reflect
the
EPA's
consideration
of
the
President's
National
Energy
Policy
(
NEP),
EPA's
Report
to
the
President
on
the
impact
of
NSR
pursuant
to
the
NEP,
and
EPA's
recommended
changes
to
NSR
based
on
the
Report
findings
and
discussions
with
various
stakeholders
including
representatives
from
industry,
State
and
local
governments,
and
environmental
groups.
The
proposed
changes
provide
a
future
category
of
activities
that
would
be
considered
to
be
routine
maintenance,
repair
and
replacement
(
RMRR)
under
the
NSR
program.
The
changes
are
intended
to
provide
greater
regulatory
certainty
without
sacrificing
the
current
level
of
environmental
protection
and
benefit
derived
from
the
program.
We
believe
that
these
changes
will
facilitate
the
safe,
efficient,
and
reliable
operation
of
affected
facilities.
DATES:
Comments.
Comments
must
be
received
on
or
before
March
3,
2003.
Public
Hearing.
If
anyone
contacts
us
requesting
to
speak
at
a
public
hearing
by
January
21,
2003,
we
will
hold
a
public
hearing
approximately
30
days
after
publication
in
the
Federal
Register.
ADDRESSES:
Comments.
Comments
may
be
submitted
electronically,
by
mail,
by
facsimile,
or
through
hand
delivery/
courier.
Follow
the
detailed
instructions
as
provided
in
section
I.
C.
of
the
SUPPLEMENTARY
INFORMATION
section.
Public
Hearing.
The
public
hearing,
if
requested,
will
be
held
at
the
EPA's
facilities
at
109
TW
Alexander
Drive,
Research
Triangle
Park,
NC
27709
or
at
an
alternate
facility
nearby.
The
EPA
will
not
hold
a
hearing
if
one
is
not
requested.
Please
check
EPA's
web
page
at
http://
www.
epa.
gov/
ttn/
nsr/
whatsnew.
html
on
January
21,
2003
for
the
announcement
of
whether
the
hearing
will
be
held.
FOR
FURTHER
INFORMATION
CONTACT:
Mr.
Dave
Svendsgaard,
Information
Transfer
and
Program
Integration
Division
(
C339
03),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC
27711,
telephone
(
919)
541
2380,
or
electronic
mail
at
svendsgaard.
dave@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
I.
General
Information
A.
What
Are
the
Regulated
Entities?
Entities
potentially
affected
by
this
proposed
action
include
sources
in
all
industry
groups.
The
majority
of
sources
potentially
affected
are
expected
to
be
in
the
following
groups.
Industry
group
SECa
NAICSb
Electric
Services
.....................................................
491
221111,
221112,
221113,
221119,
221121,
221122
Petroleum
Refining
.................................................
291
32411
Chemical
Processes
...............................................
281
325181,
32512,
325131,
325182,
211112,
325998,
331311,
325188
Natural
Gas
Transport
............................................
492
48621,
22121
Pulp
and
Paper
Mills
..............................................
261
32211,
322121,
322122,
32213
Paper
Mills
..............................................................
262
322121,
322122
Automobile
Manufacturing
......................................
371
336111,
336112,
336712,
336211,
336992,
336322,
336312,
33633,
33634,
33635,
336399,
336212,
336213
Pharmaceuticals
.....................................................
283
325411,
325412,
325413,
325414
a
Standard
Industrial
Classification
b
North
American
Industry
Classification
System.
Entities
potentially
affected
by
this
proposed
action
also
would
include
State,
local,
and
tribal
governments
that
are
delegated
authority
to
implement
these
regulations.
B.
How
Can
I
Get
Copies
of
This
Document
and
Other
Related
Information?
1.
Docket.
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
A
2002
04.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
received,
and
other
information
related
to
this
action.
Although
a
part
of
the
official
docket,
the
public
docket
does
not
include
Confidential
Business
Information
(
CBI)
or
other
information
whose
disclosure
is
restricted
by
statute.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
EPA
Docket
Center,
(
Air
Docket),
U.
S.
Environmental
Protection
Agency,
1301
Constitution
Ave.,
NW.,
Room:
B108,
Mail
Code:
6102T,
Washington,
DC,
20004.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
1742.
A
reasonable
fee
may
be
charged
for
copying.
2.
Electronic
Access.
You
may
access
this
Federal
Register
document
electronically
through
the
EPA
Internet
under
the
``
Federal
Register''
listings
at
http://
www.
epa.
gov/
fedrgstr/.
An
electronic
version
of
the
public
docket
is
available
through
EPA's
electronic
public
docket
and
comment
system,
EPA
Dockets.
You
may
use
EPA
Dockets
at
http://
www.
epa.
gov/
edocket/
to
submit
or
view
public
comments,
access
the
index
listing
of
the
contents
of
the
official
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,''
then
key
in
the
appropriate
docket
identification
number.
Certain
types
of
information
will
not
be
placed
in
the
EPA
Dockets.
Information
claimed
as
CBI
and
other
information
whose
disclosure
is
restricted
by
statute,
which
is
not
included
in
the
official
public
docket,
will
not
be
available
for
public
viewing
in
EPA's
electronic
public
docket.
EPA's
policy
is
that
copyrighted
material
will
not
be
placed
in
EPA's
electronic
public
docket
but
will
be
available
only
in
printed,
paper
form
in
the
official
public
docket.
To
the
extent
feasible,
publicly
available
docket
materials
will
be
made
available
in
EPA's
electronic
public
docket.
When
a
document
is
selected
from
the
index
list
in
EPA
Dockets,
the
system
will
identify
whether
the
document
is
available
for
viewing
in
EPA's
electronic
public
docket.
Although
not
all
docket
materials
may
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Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
identified
in
section
I.
B.
1.
EPA
intends
to
work
towards
providing
electronic
access
to
all
of
the
publicly
available
docket
materials
through
EPA's
electronic
public
docket.
For
public
commenters,
it
is
important
to
note
that
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
in
paper,
will
be
made
available
for
public
viewing
in
EPA's
electronic
public
docket
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
EPA's
electronic
public
docket.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Public
comments
submitted
on
computer
disks
that
are
mailed
or
delivered
to
the
docket
will
be
transferred
to
EPA's
electronic
public
docket.
Public
comments
that
are
mailed
or
delivered
to
the
Docket
will
be
scanned
and
placed
in
EPA's
electronic
public
docket.
Where
practical,
physical
objects
will
be
photographed,
and
the
photograph
will
be
placed
in
EPA's
electronic
public
docket
along
with
a
brief
description
written
by
the
docket
staff.
For
additional
information
about
EPA's
electronic
public
docket
visit
EPA
Dockets
online
or
see
67
FR
38102,
May
31,
2002.
C.
How
and
to
Whom
Do
I
Submit
Comments?
You
may
submit
comments
electronically,
by
mail,
by
facsimile,
or
through
hand
delivery/
courier.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
comment.
Please
ensure
that
your
comments
are
submitted
within
the
specified
comment
period.
Comments
received
after
the
close
of
the
comment
period
will
be
marked
``
late.''
EPA
is
not
required
to
consider
these
late
comments.
If
you
wish
to
submit
CBI
or
information
that
is
otherwise
protected
by
statute,
please
follow
the
instructions
in
section
I.
D.
Do
not
use
EPA
Dockets
or
e
mail
to
submit
CBI
or
information
protected
by
statute.
1.
Electronically.
If
you
submit
an
electronic
comment
as
prescribed
below,
EPA
recommends
that
you
include
your
name,
mailing
address,
and
an
e
mail
address
or
other
contact
information
in
the
body
of
your
comment.
Also
include
this
contact
information
on
the
outside
of
any
disk
or
CD
ROM
you
submit,
and
in
any
cover
letter
accompanying
the
disk
or
CD
ROM.
This
ensures
that
you
can
be
identified
as
the
submitter
of
the
comment
and
allows
EPA
to
contact
you
in
case
EPA
cannot
read
your
comment
due
to
technical
difficulties
or
needs
further
information
on
the
substance
of
your
comment.
EPA's
policy
is
that
EPA
will
not
edit
your
comment,
and
any
identifying
or
contact
information
provided
in
the
body
of
a
comment
will
be
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket,
and
made
available
in
EPA's
electronic
public
docket.
If
EPA
cannot
read
your
comment
due
to
technical
difficulties
and
cannot
contact
you
for
clarification,
EPA
may
not
be
able
to
consider
your
comment.
a.
EPA
Dockets.
Your
use
of
EPA's
electronic
public
docket
to
submit
comments
to
EPA
electronically
is
EPA's
preferred
method
for
receiving
comments.
Go
directly
to
EPA
Dockets
at
http://
www.
epa.
gov/
edocket,
and
follow
the
online
instructions
for
submitting
comments.
To
access
EPA's
electronic
public
docket
from
the
EPA
Internet
Home
Page,
select
``
Information
Sources,''
``
Dockets,''
and
``
EPA
Dockets.''
Once
in
the
system,
select
``
search,''
and
then
key
in
Docket
ID
No.
A
2002
04.
The
system
is
an
``
anonymous
access''
system,
which
means
EPA
will
not
know
your
identity,
e
mail
address,
or
other
contact
information
unless
you
provide
it
in
the
body
of
your
comment.
b.
E
mail.
Comments
may
be
sent
by
electronic
mail
(
e
mail)
to
a
and
rdocket
epamail.
epa.
gov,
Attention
Docket
ID
No.
A
2002
04.
In
contrast
to
EPA's
electronic
public
docket,
EPA's
email
system
is
not
an
``
anonymous
access''
system.
If
you
send
an
e
mail
comment
directly
to
the
Docket
without
going
through
EPA's
electronic
public
docket,
EPA's
e
mail
system
automatically
captures
your
e
mail
address.
E
mail
addresses
that
are
automatically
captured
by
EPA's
e
mail
system
are
included
as
part
of
the
comment
that
is
placed
in
the
official
public
docket,
and
made
available
in
EPA's
electronic
public
docket.
c.
Disk
or
CD
ROM.
You
may
submit
comments
on
a
disk
or
CD
ROM
that
you
mail
to
the
mailing
address
identified
in
section
I.
C.
2.
These
electronic
submissions
will
be
accepted
in
WordPerfect
or
ASCII
file
format.
Avoid
the
use
of
special
characters
and
any
form
of
encryption.
2.
By
Mail.
Send
two
copies
of
your
comments
to:
U.
S.
Environmental
Protection
Agency,
EPA
West
(
Air
Docket),
1200
Pennsylvania
Ave.,
NW,
Room:
B108,
Mail
code:
6102T,
Washington,
DC,
20460,
Attention
Docket
ID
No.
A
2002
04.
3.
By
Hand
Delivery
or
Courier.
Deliver
your
comments
to:
EPA
Docket
Center,
(
Air
Docket),
U.
S.
Environmental
Protection
Agency,
1301
Constitution
Ave.,
NW.,
Room:
B108,
Mail
Code:
6102T,
Washington,
DC,
20004.,
Attention
Docket
ID
No.
A
2002
04.
Such
deliveries
are
only
accepted
during
the
Docket's
normal
hours
of
operation
as
identified
in
section
I.
B.
1.
4.
By
Facsimile.
Fax
your
comments
to
the
EPA
Docket
Center
at
(
202)
566
1741,
Attention
Docket
ID.
No.
A
2002
04.
D.
How
Should
I
Submit
CBI
to
the
Agency?
Do
not
submit
information
that
you
consider
to
be
CBI
electronically
through
EPA's
electronic
public
docket
or
by
e
mail.
Send
or
deliver
information
identified
as
CBI
only
to
the
following
address:
Mr.
David
Svendsgaard,
c/
o
OAQPS
Document
Control
Officer
(
C339
03),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC
27711,
Attention
Docket
ID
No.
A
2002
04.
You
may
claim
information
that
you
submit
to
EPA
as
CBI
by
marking
any
part
or
all
of
that
information
as
CBI.
(
If
you
submit
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
as
CBI
and
then
identify
electronically
within
the
disk
or
CD
ROM
the
specific
information
that
is
CBI).
Information
so
marked
will
not
be
disclosed
except
in
accordance
with
procedures
set
forth
in
40
CFR
Part
2.
In
addition
to
one
complete
version
of
the
comment
that
includes
any
information
claimed
as
CBI,
a
copy
of
the
comment
that
does
not
contain
the
information
claimed
as
CBI
must
be
submitted
for
inclusion
in
the
public
docket
and
EPA's
electronic
public
docket.
If
you
submit
the
copy
that
does
not
contain
CBI
on
disk
or
CD
ROM,
mark
the
outside
of
the
disk
or
CD
ROM
clearly
that
it
does
not
contain
CBI.
Information
not
marked
as
CBI
will
be
included
in
the
public
docket
and
EPA's
electronic
public
docket
without
prior
notice.
If
you
have
any
questions
about
CBI
or
the
procedures
for
claiming
CBI,
please
consult
the
person
identified
in
the
FOR
FURTHER
INFORMATION
CONTACT
section.
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67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
E.
What
Should
I
Consider
as
I
Prepare
my
Comments
for
EPA?
You
may
find
the
following
suggestions
helpful
for
preparing
your
comments.
Explain
your
views
as
clearly
as
possible.
Describe
any
assumptions
that
you
used.
Provide
any
technical
information
and/
or
data
you
used
that
support
your
views.
If
you
estimate
potential
burden
or
costs,
explain
how
you
arrived
at
your
estimate.
Provide
specific
examples
to
illustrate
your
concerns.
Offer
alternatives.
Make
sure
to
submit
your
comments
by
the
comment
period
deadline
identified.
To
ensure
proper
receipt
by
EPA,
identify
the
appropriate
docket
identification
number
in
the
subject
line
on
the
first
page
of
your
response.
It
would
also
be
helpful
if
you
provided
the
name,
date,
and
Federal
Register
citation
related
to
your
comments.
F.
How
Can
I
Find
Information
About
a
Possible
Public
Hearing?
Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Ms.
Pamela
J.
Smith,
Integrated
Implementation
Group,
Information
Transfer
and
Program
Integration
Division
(
C339
03),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC
27711,
telephone
number
(
919)
541
0641,
at
least
2
days
in
advance
of
the
public
hearing.
Persons
interested
in
attending
the
public
hearing
should
also
contact
Ms.
Smith
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
these
proposed
emission
standards.
G.
Where
Can
I
Obtain
Additional
Information?
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
this
proposed
rule
is
also
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature
by
the
EPA
Administrator,
a
copy
of
the
proposed
rule
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(
919)
541
5384.
H.
How
is
This
Preamble
Organized?
The
information
presented
in
this
preamble
is
organized
as
follows:
I.
General
Information
A.
What
are
the
regulated
entities?
B.
How
can
I
get
copies
of
this
document
and
other
related
information?
C.
How
and
to
whom
do
I
submit
comments?
D.
How
should
I
submit
CBI
to
the
Agency?
E.
What
should
I
consider
as
I
prepare
my
comments
for
EPA?
F.
How
can
I
find
information
about
a
possible
public
hearing?
G.
Where
can
I
obtain
additional
information?
H.
How
is
this
preamble
organized?
II.
Purpose
III.
Background
A.
How
does
the
process
of
using
the
RMRR
exclusion
currently
work?
B.
Why
is
the
specification
of
categories
of
RMRR
activities
appropriate?
C.
Process
Used
to
Develop
This
Rule
IV.
Overview
of
Recommended
Approaches
for
RMRR
A.
Annual
Maintenance,
Repair
and
Replacement
Allowance
B.
Equipment
Replacement
Provision
V.
Legal
Basis
for
Recommended
Approaches
VI.
Discussion
of
Issues
Under
Annual
Maintenance,
Repair
and
Replacement
Allowance
Approach
A.
Appropriate
Time
Period
for
a
Maintenance,
Repair
and
Replacement
Allowance
B.
Cost
Basis
C.
Basis
for
Annual
Allowance
Stationary
Source
vs
Process
Unit
D.
Basis
for
Annual
Maintenance,
Repair
and
Replacement
Allowance
Percentage
E.
How
to
Calculate
Costs
F.
Applicability
Safeguards
G.
Timing
of
Determination
VII.
Discussion
of
Issues
under
the
Equipment
Replacement
Approach
A.
Replacement
of
Existing
Equipment
with
Identical
or
Functionally
Equivalent
Equipment
B.
Defining
``
Process
Unit''
for
Evaluating
Equipment
Replacement
Cost
Percentage
C.
Miscellaneous
Issues
D.
Quantitative
Analysis
VIII.
Other
Options
Considered
A.
Capacity
Based
Option
B.
Age
Based
Option
IX.
Administrative
Requirements
for
this
Proposed
Rulemaking
A.
Executive
Order
12866
Regulatory
Planning
and
Review
B.
Executive
Order
13132
Federalism
C.
Executive
Order
13175
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Paperwork
Reduction
Act
F.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
G.
Unfunded
Mandates
Reform
Act
of
1995
H.
National
Technology
Transfer
and
Advancement
Act
of
1995
I.
Executive
Order
13211
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
X.
Statutory
Authority
II.
Purpose
We
are
proposing
a
change
to
the
NSR
program
to
provide
specific
categories
of
activities
that
EPA
will
consider
RMRR
in
the
future.
We
are
seeking
comment
on
all
aspects
of
our
proposed
approaches
to
specifying
categories
of
RMRR
activities
under
the
NSR
program,
and
on
other
options
considered.
These
approaches
would
be
voluntary,
in
that
owners
or
operators
could
opt
to
continue
using
the
current
procedures
for
determining
what
activities
constitute
RMRR
at
their
facilities.
This
proposal
seeks
public
comments
in
accordance
with
section
307(
d)
of
the
CAA
and
should
not
be
used
or
cited
in
any
litigation
as
the
final
position
of
the
Agency.
III.
Background
A.
How
Does
the
Process
of
Using
the
RMRR
Exclusion
Currently
Work?
Under
the
changes
promulgated
today
to
40
CFR
parts
51
and
52,
``
major
modification''
is
defined
as
any
physical
change
in
or
change
in
the
method
of
operation
of
a
major
stationary
source
that
would
result
in:
(
1)
A
significant
emissions
increase
of
a
regulated
NSR
pollutant;
and
(
2)
a
significant
net
emissions
increase
of
that
pollutant
from
the
major
stationary
source.
Owners/
operators
of
major
stationary
sources
are
required
to
obtain
a
major
NSR
permit
prior
to
beginning
actual
construction
of
a
modification
that
meets
this
definition.
The
regulations
exclude
certain
activities
from
the
definition
of
``
major
modification.''
One
such
exclusion
is
for
RMRR
activities.
The
regulations
do
not
define
this
term.
(
See
40
CFR
51.165(
a)(
1)(
v)(
C)(
1),
51.166(
b)(
2)(
iii)(
a),
52.21(
b)(
2)(
iii)(
a)
and
52.24(
f)(
5)(
iii)(
a).)
Under
our
current
approach,
the
RMRR
exclusion
is
applied
on
a
caseby
case
basis.
In
interpreting
this
exclusion,
we
have
followed
certain
criteria.
The
preamble
to
the
1992
``
WEPCO
Rule''
(
57
FR
32314)
and
applicability
determinations
made
to
date
describe
our
current
approach
to
assessing
what
activities
constitute
RMRR.
These
applicability
determinations
are
available
electronically
from
the
Region
7
NSR
Policy
and
Guidance
Database
(
http/://
www.
epa.
gov/
Region7/
programs/
artd/
air/
nsr/
nsrpg.
htm).
To
summarize
these
documents,
to
determine
whether
proposed
work
at
a
facility
is
routine,
EPA
makes
a
case
by
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67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
1
Reliable,
Affordable,
and
Environmentally
Sound
Energy
for
America's
Future,
Report
of
the
National
Energy
Policy
Development
Group,
May
17,
2001.
case
determination
by
weighing
the
nature,
extent,
purpose,
frequency,
and
the
cost
of
the
work
as
well
as
other
relevant
factors
to
arrive
at
a
common
sense
finding.
WEPCO
at
910.
None
of
these
factors,
in
and
of
itself,
is
conclusive.
Instead,
a
reviewing
authority
should
take
account
of
how
each
of
these
factors
might
apply
in
a
particular
circumstance
to
arrive
at
a
conclusion
considering
the
project
as
a
whole.
If
an
owner
or
operator
is
uncertain
whether
he
or
she
is
applying
the
NSR
regulations
correctly,
we
encourage
the
owner
or
operator
to
consult
the
appropriate
reviewing
authority
for
assistance.
B.
Why
Is
Specification
of
Categories
of
RMRR
Activities
Appropriate?
There
has
been
some
debate
over
the
years
as
to
the
case
by
case
approach
and
the
types
of
activities
that
qualify
as
RMRR
under
our
current
case
by
case
approach.
The
case
specific
approach
works
well
in
many
respects.
For
example,
it
is
a
flexible
tool
that
accommodates
the
broad
range
of
industries
and
the
diversity
of
activities
that
are
potentially
subject
to
the
NSR
program.
However,
the
case
by
case
approach
has
certain
drawbacks.
Unless
an
owner
or
operator
seeks
an
applicability
determination
from
his
or
her
reviewing
authority
or
from
EPA,
it
can
be
difficult
for
the
owner
or
operator
to
know
with
certainty
whether
a
particular
activity
constitutes
RMRR.
Applicability
determinations
can
be
costly
and
time
consuming
for
reviewing
authorities
and
industry
alike.
If
a
source
proceeds
without
a
determination
and
is
later
proven
to
have
made
an
incorrect
determination,
that
source
faces
potentially
serious
enforcement
consequences.
Moreover,
under
the
current
case
by
case
approach,
State
and
local
reviewing
authorities
must
devote
scarce
resources
to
making
complex
determinations
and
consult
with
other
agencies
to
ensure
that
any
determinations
are
consistent
with
determinations
made
for
similar
circumstances
in
other
jurisdictions
and/
or
that
EPA
or
other
reviewing
authorities
would
concur
with
the
conclusion.
On
the
other
hand,
if
a
source
foregoes
or
defers
activities
that
are
important
to
maintaining
its
plant
when
the
activities
in
question
are
in
fact
within
scope
of
the
exclusion,
that
can
have
adverse
consequences
for
the
source's
reliability,
efficiency,
and
safety.
Finally,
the
source
may
install
less
efficient
or
less
modern
equipment
in
order
to
be
more
certain
that
it
is
within
the
regulatory
bounds,
or
it
may
agree
to
limit
its
hours
of
operation
or
capacity.
Any
of
these
approaches
will
make
the
source
less
productive
than
it
would
be
otherwise.
In
fact,
we
concluded
in
our
recent
report
to
the
President
on
the
impacts
of
NSR
on
the
energy
sector
that
there
have
been
cases
in
which
uncertainty
about
the
exclusion
for
RMRR
resulted
in
delay
or
cancellation
of
activities
that
would
have
maintained
and
improved
the
reliability,
efficiency,
and
safety
of
existing
energy
capacity.
Such
discouragement
results
in
lost
capacity
and
lost
opportunities
to
improve
energy
efficiency
and
reduce
air
pollution.
We
believe
that
these
problems
would
be
significantly
reduced
by
adding
to
our
current
RMRR
provision
specific
categories
of
activities
that
will
be
considered
to
be
RMRR
in
the
future.
Such
categories
would
remove
disincentives
to
undertaking
RMRR
activities
and
provide
more
certainty
both
to
source
owners
and
operators
who
could
better
plan
activities
at
their
facilities,
and
to
reviewing
authorities
who
could
better
focus
resources
on
activities
outside
these
RMRR
categories.
Accordingly,
the
establishment
of
categories
of
activities
as
RMRR
is
consistent
with
the
central
purpose
of
the
CAA,
``
to
protect
and
enhance
the
quality
of
the
Nation's
air
resources
so
as
to
promote
the
public
health
and
welfare
and
the
productive
capacity
of
its
population.''
CAA
section
101.
It
should
be
noted
that
there
may
be
some
activities
which,
while
fitting
within
the
ambit
of
the
RMRR
exclusion
could,
if
implemented,
violate
other
applicable
CAA
requirements.
As
has
always
been
the
case,
compliance
with
NSR
requirements
is
not
a
license
to
violate
any
of
the
other
applicable
CAA
requirements
such
as
title
V
permitting
requirements.
C.
Process
Used
To
Develop
This
Rule
In
the
1992
``
WEPCO
Rule''
preamble,
we
indicated
that
we
planned
to
issue
guidance
on
the
subject
of
RMRR.
In
1994,
as
part
of
our
meetings
with
the
Clean
Air
Act
Advisory
Committee,
we
developed,
for
discussion
purposes
only,
a
document
on
how
RMRR
could
be
defined.
We
received
a
substantial
volume
of
comments
on
this
document.
We
subsequently
decided
not
to
include
a
definition
of
RMRR
in
our
1996
NSR
proposed
rulemaking.
In
2001,
the
President's
NEP
Report
1
directed
EPA
in
consultation
with
the
Department
of
Energy
(
DOE)
and
other
federal
agencies
to
review
the
impact
of
NSR
on
investment
in
new
utility
and
refinery
generation
capacity,
energy
efficiency
and
environmental
protection.
The
release
of
the
report
in
May
2001
triggered
a
review
of
the
impacts
of
NSR
rules.
EPA's
Report
to
the
President
underscored
the
desirability
of
specifying
certain
categories
of
activities
that
qualify
as
RMRR.
In
parallel
with
this
review,
we
renewed
our
exploration
of
recommendations
for
improving
the
NSR
program.
Recommended
improvements
suggested
during
this
time
represented
a
continuation
of
discussions
on
NSR
issues
that
had
taken
place
during
the
1990'
s,
as
well
as
new
ideas.
The
process
of
discussing
possible
improvements
to
the
NSR
program
included
significant
interagency
consultation,
including
meetings
with
representatives
from
the
DOE,
the
Department
of
the
Interior,
and
the
Office
of
Management
and
Budget.
Building
on
what
we
heard,
we
held
conference
calls
with
various
stakeholders
during
October
2001
(
including
representatives
from
industry,
State
and
local
governments,
and
environmental
groups)
to
discuss
new
ideas
that
were
raised.
During
many
of
these
meetings,
we
discussed
ideas
for
how
to
define
RMRR
in
order
to
create
more
certainty
for
the
industry
and
reviewing
authorities.
Today's
proposed
rule
is
an
outgrowth
of
ideas
discussed
in
those
meetings.
IV.
Overview
of
Recommended
Approaches
for
RMRR
Ever
since
EPA's
promulgation
of
its
original
Prevention
of
Significant
Deterioration
(
PSD)
regulations
in
1980,
EPA
has
defined
``
modification''
in
its
NSR
regulations
to
include
commonsense
exclusions
from
the
``
physical
or
operational
change''
component
of
the
definition,
including
an
exclusion
for
RMRR.
Today,
we
are
proposing
two
categories
of
activities
that
will
in
the
future
be
considered
RMRR
activities:
activities
within
an
annual
maintenance,
repair
and
replacement
allowance
and
replacements
that
meet
our
equipment
replacement
provision
criteria.
Under
the
proposal,
when
an
activity
falls
within
either
of
these
categories,
it
would
be
considered
RMRR
and
a
source's
owners
or
operators
would
know
that
the
activity
was
excluded
from
NSR
without
regard
to
other
considerations.
When
an
activity
did
not
fall
within
one
of
these
categories,
then
it
still
could
qualify
as
routine
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/
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December
31,
2002
/
Proposed
Rules
2
A
fiscal
year
period
would
have
to
be
12
consecutive
months.
maintenance,
repair,
and
replacement
under
the
case
by
case
test.
A.
Annual
Maintenance,
Repair
and
Replacement
Allowance
First,
we
are
proposing
to
add
new
language
to
the
RMRR
exclusion
at
40
CFR
51.165
(
a)(
1)(
v)(
C)(
1),
40
CFR
51.166
(
b)(
2)(
iii)(
a),
40
CFR
part
51,
Appendix
S
(
A)(
5)(
iii)(
a),
40
CFR
52.21(
b)(
2)(
iii)(
a),
and
40
CFR
52.24
(
f)(
5)(
iii)(
a).
This
proposal
would
allow
certain
activities
engaged
in
to
promote
the
safe,
reliable
and
efficient
operation
of
a
facility
that
is,
those
that
involve
relatively
small
capital
expenditures
compared
with
the
replacement
cost
of
the
facility
to
be
excluded
from
NSR
provided
that
total
costs
did
not
exceed
the
annual
maintenance,
repair
and
replacement
allowance.
The
annual
maintenance,
repair
and
replacement
allowance
and
the
rules
for
calculation
and
summation
of
activities
under
the
allowance
would
be
defined
in
new
provisions
at
40
CFR
51.165(
a)(
1)(
xxxxii),
40
CFR
51.166(
b)(
53),
40
CFR
52.21(
b)(
55),
and
40
CFR
52.24(
f)(
25).
Under
our
proposed
approach,
a
calendar
year
maintenance,
repair
and
replacement
allowance
would
be
established
for
each
stationary
source.
The
owner
or
operator
may
elect
to
use
a
fiscal
year
period
instead
of
a
calendar
year
if
financial
records
are
typically
kept
for
a
period
other
than
calendar
year
at
a
facility.
2
Although
the
proposal
contemplates
a
one
year
allowance,
in
recognition
of
the
fact
that
maintenance
cycles
in
many
industries
extend
for
more
than
1
year,
we
also
seek
comment
on
whether
a
stationary
source
should
have
the
option
of
a
multi
year
allowance,
such
as
over
5
years.
Under
our
1
year
allowance
proposal,
an
owner
or
operator
would
sum
the
costs
of
the
relevant
activities
performed
at
the
stationary
source
during
the
fiscal
or
calendar
year
(
from
the
least
expensive
to
the
most
expensive)
to
get
a
yearly
cost.
For
activities
taking
more
than
1
year
to
complete,
costs
associated
with
those
activities
would
be
included
in
the
cost
calculations
for
the
year
that
the
costs
were
incurred
(
using
an
accounting
method
consistent
with
that
used
for
other
purposes
by
the
stationary
source).
If
the
total
costs
for
all
activities
undertaken
for
these
purposes
came
within
the
annual
maintenance,
repair
and
replacement
allowance,
these
activities
would
all
be
considered
RMRR
activities.
Other
than
documentation
of
the
results
of
this
assessment,
the
owner
or
operator
would
not
have
to
do
anything
further
with
respect
to
those
activities
for
purposes
of
major
NSR.
Where
total
yearly
costs
for
all
activities
undertaken
for
these
purposes
at
a
source
exceed
the
annual
maintenance,
repair
and
replacement
allowance,
the
activities
would
be
reviewed
as
follows.
The
owner
or
operator
would
subtract
activities
from
the
total
yearly
cost,
starting
with
the
most
expensive
activity,
until
the
remainder
is
less
than
or
equal
to
the
annual
maintenance,
repair
and
replacement
allowance.
The
owner
or
operator
would
evaluate
on
a
case
by
case
basis
in
accordance
with
EPA's
case
by
case
test
any
activities
that
did
not
come
within
the
allowance
and
that
are
not
otherwise
excluded,
in
order
to
determine
whether
they
are
RMRR.
If
uncertain
about
a
particular
activity
the
owner
or
operator
could
seek
an
applicability
determination.
If
an
owner
or
operator
concluded
that
any
such
activity
was
not
RMRR,
he
or
she
would
then
have
to
determine
whether
it
constitutes
a
``
major
modification''
that
requires
an
NSR
permit.
The
annual
maintenance,
repair
and
replacement
allowance
would
be
equal
to
the
product
of
the
replacement
cost
of
the
source
and
a
specified
maintenance,
repair
and
replacement
percentage.
(
See
§
§
51.165(
a)(
1)(
xxxxii),
51.166(
b)(
53),
52.21(
b)(
55)
and
52.24(
f)(
25)
of
proposed
rules.)
EPA
intends
to
set
this
percentage
on
an
industry
specific
basis.
There
are
several
ways
in
which
the
percentage
could
be
established.
One
way
is
to
set
the
threshold
so
as
to
cover
the
RMRR
capital
and
non
capital
costs
that
an
owner
or
operator
incurs
to
maintain,
facilitate,
restore,
or
improve
the
safety,
reliability,
availability,
or
efficiency
of
the
source.
We
are
also
requesting
comment
on
other
approaches.
For
example,
we
could
apply
a
discount
factor
to
the
typical
costs
in
order
to
account
for
variability
within
an
industry.
We
also
ask
for
comment
on
how
to
determine
typical
costs
for
particular
industries.
We
are
considering
using
the
Internal
Revenue
Service
``
Annual
Asset
Guideline
Repair
Allowance
Percentages''
(
AAGRAP),
which
we
use
for
an
exclusion
under
the
New
Source
Performance
Standard
(
NSPS)
program
for
increases
in
production.
We
also
could
rely
on
industry
specific
data
for
choosing
an
appropriate
threshold,
such
as
the
North
American
Electric
Reliability
Council
Generating
Availability
Data
System
(
NERC/
GADS)
database
or
standard
industry
reference
manuals.
The
replacement
cost
used
in
the
calculation
described
above
would
be
an
estimate
of
the
total
capital
investment
necessary
to
replace
the
stationary
source.
The
accounting
procedures
used
to
document
eligibility
under
this
rule
should
conform
to
the
accounting
procedures
used
for
other
purposes
at
a
facility.
Where
several
accounting
procedures
are
used
at
a
facility
(
e.
g.,
methods
for
tax
accounting
and
for
setting
rates
often
are
different),
the
most
appropriate
procedures
should
be
used
for
the
purpose
of
determining
costs
pursuant
to
this
regulation.
EPA
also
seeks
to
standardize
practices
for
estimating
this
investment,
along
the
lines
described
in
the
EPA
Air
Pollution
Control
Cost
Manual,
excluding
the
costs
for
installing
and
maintaining
pollution
control
equipment.
See
section
V.
E.
of
this
document
for
further
information
on
our
recommended
approach
to
calculating
costs.
The
control
cost
manual
is
available
electronically
via
the
internet
at
http://
www.
epa.
gov/
ttn/
catc/
dir1/
c_
allchs.
pdf.
We
acknowledge
that
this
manual
is
geared
toward
cost
calculations
for
add
on
control
equipment
but
believe
the
basic
concepts
can
be
applied
to
process
equipment
as
well.
These
concepts
are
taken
from
work
done
by
the
American
Association
of
Cost
Engineers
to
define
the
components
of
cost
calculations
for
all
types
of
processes,
not
just
emission
control
equipment.
We
seek
comment
on
whether
this
manual
or
other
reference
documents
or
tools
provide
the
best
approach
for
standardizing
estimation
of
these
costs,
whether
different
methods
should
be
provided,
and
whether
provision
should
be
made
in
the
form
of
a
requirement
or
an
assurance
that
if
a
method
is
used,
we
will
accept
it.
Our
recommended
approach
will
contain
safeguards
to
help
ensure
that
activities
that
should
be
considered
a
physical
change
or
change
in
the
method
of
operation
under
the
regulations
are
ineligible
for
exclusion
from
NSR
under
the
annual
maintenance,
repair
and
replacement
allowance.
We
are
proposing
to
exclude
the
following
from
use
of
the
annual
allowance.
The
construction
of
a
new
``
process
unit,''
which
is
a
collection
of
structures
and/
or
equipment
that
uses
material
inputs
to
produce
or
store
a
completed
product.
See
discussion
below
at
section
VII
for
further
information
regarding
process
units.
The
replacement
of
an
entire
process
unit
Any
change
that
would
result
in
an
increase
in
the
source's
maximum
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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
3
Of
course,
as
noted
earlier,
the
traditional
caseby
case
approach
to
administering
the
RMRR
exclusion
will
continue
to
apply
to
activities
that
do
not
qualify
under
the
annual
maintenance,
repair
and
replacement
allowance
approach
described
above,
but
for
the
reasons
noted
earlier,
we
believe
that
approach
would
be
improved
on
by
the
identification
of
activities
that
may
be
found
to
Continued
achievable
hourly
emissions
rate
of
any
regulated
NSR
pollutant,
or
in
the
emission
of
any
regulated
NSR
pollutant
not
previously
emitted
by
the
stationary
source.
If
an
owner
or
operator
uses
the
annual
maintenance,
repair
and
replacement
allowance
to
determine
that
certain
activities
at
a
stationary
source
are
RMRR,
all
relevant
activities
performed
at
that
source
must
be
included
in
the
annual
cost
calculations
unless
the
owner
or
operator
elects
to
obtain
a
major
NSR
permit
for
the
activity.
In
other
words,
an
owner
or
operator
may
not
select
which
activities
to
review
case
by
case
and
which
to
include
in
the
cost
calculations
when
using
the
annual
maintenance,
repair
and
replacement
allowance
to
determine
RMRR
activities.
This
is
because,
assuming
the
threshold
is
set
to
approximate
the
total
amount
that
an
owner
or
operator
would
typically
be
expected
to
spend
on
RMRR
activities
(
or
a
discounted
portion
of
this
value
selected
to
account
for
variability
within
an
industry),
the
fact
that
a
given
activity's
cost
comes
within
the
allowance
can
only
reasonably
assure
that
it
is
RMRR
if
all
other
relevant
activities
also
are
included.
If
the
owner
or
operator
could
pick
and
choose
among
activities
that
he
or
she
wished
to
include
in
the
allowance,
such
an
approach
might
allow
the
owner
or
operator
to
include
large,
atypical
activities
that
do
not
constitute
RMRR
within
the
allowance,
while
applying
the
case
by
case
test
to
smaller
activities
that
quite
clearly
constitute
RMRR
under
that
test.
The
rule
that
all
relevant
activities
must
be
included
in
the
calculation
and
that
lowest
cost
activities
would
be
counted
first
should
provide
sufficient
protection
against
this
risk.
Owners
or
operators
electing
to
use
the
annual
maintenance,
repair
and
replacement
allowance
to
determine
RMRR
activities
will
be
required
to
submit
an
annual
report
to
the
appropriate
reviewing
authority
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
The
report
will
provide
a
summary
of
the
estimated
replacement
value
of
the
stationary
source,
the
annual
maintenance,
repair
and
replacement
allowance
for
the
stationary
source,
a
brief
description
of
all
maintenance,
repair
and
replacement
activities
undertaken
at
the
stationary
source,
and
the
costs
associated
with
those
activities.
If
the
costs
of
activities
in
question
exceed
the
annual
maintenance,
repair
and
replacement
allowance
for
a
stationary
source,
the
report
must
identify
the
activities
included
within
the
allowance
and
the
activities
that
fell
outside
the
allowance.
The
procedures
set
out
in
40
CFR
part
2
are
available
for
confidential
and
business
sensitive
information
submitted
as
part
of
this
report.
The
following
provides
an
example
of
how
the
process
would
work.
Assume
the
source's
annual
maintenance,
repair
and
replacement
allowance
equals
$
2,000,000.
During
a
given
year,
the
owner
or
operator
spends
$
1,000,000
on
running
maintenance
activities,
and
implements
five
other
discrete
maintenance
activities
at
the
source
with
costs
as
follows
in
Table
1
(
none
of
these
activities
involves
the
construction
of
a
new
process
unit,
replacement
of
an
existing
process
unit,
or
an
increase
in
the
maximum
achievable
hourly
emissions
rate
of
a
regulated
NSR
pollutant
or
in
the
emission
of
any
regulated
NSR
pollutant
not
previously
emitted
by
the
stationary
source).
TABLE
1.
EXAMPLE
SUMMARY
OF
ACTIVITIES
COMMENCED
DURING
YEAR
Change
Month
Cost
Activity
1
.................................................................................
January
...................................................................................
$
200,000
Activity
2
.................................................................................
March
......................................................................................
600,000
Activity
3
.................................................................................
April
........................................................................................
360,000
Activity
4
.................................................................................
July
.........................................................................................
150,000
Activity
5
.................................................................................
November
...............................................................................
250,000
The
sum
of
costs
incurred
during
the
year
is
$
2,560,000,
$
560,000
above
the
annual
maintenance,
repair
and
replacement
allowance.
The
most
expensive
activity
commencing
during
the
year
was
the
$
600,000
activity
commencing
in
March.
The
source
must
evaluate
on
a
case
by
case
basis
whether
this
activity
is
RMRR.
When
the
cost
of
Activity
2
is
subtracted
from
the
total
annual
cost,
the
remainder
is
$
1,960,000,
less
than
the
annual
maintenance,
repair
and
replacement
allowance.
The
remaining
activities
(
Activities
1,
3,
4,
and
5)
are
considered
to
be
RMRR.
We
note
that
this
example
is
framed
as
if
the
owner
or
operator
would
make
these
calculations
for
the
first
time
at
the
end
of
the
year.
In
reality,
however,
an
owner
or
operator
who
is
considering
relying
on
the
maintenance,
repair
and
replacement
allowance
as
the
basis
for
his
or
her
conclusion
that
a
particular
activity
is
RMRR
is
likely
to
make
these
calculations
before
beginning
construction
on
any
activity.
This
is
because
the
owner
or
operator
would
know
that
he
or
she
will
only
be
able
to
rely
on
the
allowance
if
the
costs
of
the
activity
in
question,
when
added
with
the
costs
of
other
activities
to
assure
the
safe,
efficient,
and
reliable
operation
of
the
plant
that
the
owner
or
operator
is
planning
for
the
year,
will
in
fact
be
within
the
allowance.
B.
Equipment
Replacement
Provision
In
addition
to
our
proposed
annual
maintenance,
repair
and
replacement
allowance,
today
we
are
also
soliciting
comment
on
an
additional
approach
to
be
used
in
the
future
for
those
replacement
activities
that
should
qualify
without
regard
to
other
considerations
as
RMRR.
Specifically,
we
are
soliciting
comment
on
whether
replacing
existing
equipment
with
equipment
that
serves
the
same
function
and
that
does
not
alter
the
basic
design
parameters
of
a
unit
should
also
qualify
without
regard
for
other
considerations
for
RMRR
treatment
provided
the
cost
of
the
replacement
equipment
does
not
exceed
a
certain
percentage
of
the
cost
of
the
process
unit
to
which
the
equipment
belongs.
While
we
believe
the
annual
maintenance,
repair
and
replacement
provisions
described
above
will
significantly
improve
implementation
of
the
RMRR
exclusion,
we
recognize
that
the
allowance
may
apply
only
to
a
subset
of
the
activities
that
appropriately
fall
within
the
exclusion
and
that
are
susceptible
of
being
identified
as
categorically
constituting
RMRR.
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Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
constitute
RMRR
without
requiring
case
by
case
consideration
of
this
type.
Accordingly,
today
we
are
soliciting
comment
on
an
additional
approach
to
be
used
in
the
future
for
determining
that
certain
replacement
activities
whose
costs
fall
below
a
specified
threshold
qualify
as
RMRR
without
regard
for
other
considerations.
Under
this
approach,
EPA
would
establish
a
percentage
of
the
replacement
value
of
a
process
unit
as
a
threshold
for
applying
the
equipment
replacement
provision.
If
the
replacement
component
is
functionally
equivalent
to
the
replaced
component,
does
not
change
the
basic
design
parameters
of
the
process
unit,
and
does
not
exceed
the
cost
threshold,
it
would
constitute
RMRR.
This
approach
should
enable
the
owner
or
operator
to
streamline
the
RMRR
analysis
and
make
this
determination
more
readily
and
should
further
alleviate
some
of
the
problems
noted
above.
We
are
soliciting
comment
on
whether
this
approach
would
serve
to
streamline
the
RMRR
determination
process
for
activities
that
involve
the
replacement
of
existing
equipment
with
identical
new
equipment
and
the
replacement
of
existing
equipment
with
functionally
equivalent
equipment.
We
are
also
soliciting
comment
on
whether
this
approach
should
be
adopted
along
with
the
annual
maintenance,
repair
and
replacement
allowance
described
above,
or
whether
this
approach
is
preferred
over
the
other
such
that
we
should
only
offer
the
equipment
replacement
provision
in
the
final
rule.
We
also
solicit
comment
on
what
provisions
might
be
needed
to
clarify
and
facilitate
implementation
of
a
combined
approach.
For
example,
should
the
costs
of
activities
that
qualify
as
an
excluded
equipment
replacement
count
toward
the
annual
maintenance,
repair
and
replacement
allowance?
And,
if
so,
how
should
they
be
counted?
We
are
also
soliciting
comment
on
whether
any
other
category
of
activity
undertaken
for
these
purposes
should
be
excludable
by
the
owner
or
operator
from
the
annual
maintenance,
repair
and
replacement
allowance.
For
example,
activities
undertaken
to
address
unanticipated
forced
outages
or
catastrophic
events
such
as
fires
or
explosions
may
be
the
kind
of
unforeseeable
expenditure
that
an
owner
or
operator
should
not
have
to
include
because
it
is
not
possible
to
plan
for
it.
Also,
the
absence
of
an
exclusion
for
such
activities
might
be
a
disincentive
for
maintaining
and
ensuring
safe
operation.
If
excluded
from
the
maintenance,
repair
and
replacement
allowance,
these
activities
could
still
qualify
for
RMRR
status
under
the
equipment
replacement
provision
of
this
rule
if
they
meet
the
criteria
for
that
allowance
or
under
the
case
by
case
analysis.
Finally,
we
are
soliciting
comment
on
other
approaches
that
might
be
effective
in
streamlining
the
RMRR
determination
process.
V.
Legal
Basis
for
Recommended
Approaches
The
modification
provisions
of
the
NSR
program
in
parts
C
and
D
of
title
I
of
the
CAA
are
based
on
the
broad
definition
of
modification
in
section
111(
a)(
4)
of
the
CAA.
The
term
``
modification''
means
``
any
physical
change
in,
or
change
in
the
method
of
operation
of,
a
stationary
source
which
increases
the
amount
of
any
air
pollutant
emitted
by
such
source
or
which
results
in
the
emission
of
any
air
pollutant
not
previously
emitted.''
That
definition
contemplates
that
you
will
first
determine
whether
a
physical
or
operational
change
will
occur.
If
so,
then
you
proceed
to
determine
whether
the
physical
or
operational
change
will
result
in
an
emissions
increase
over
baseline
levels.
The
expression
``
any
physical
change
*
*
*
or
change
in
the
method
of
operation''
in
section
111(
a)(
4)
of
the
CAA
is
not
defined.
We
have
recognized
that
Congress
did
not
intend
to
make
every
activity
at
a
source
subject
to
the
major
NSR
program.
As
a
result,
we
have
previously
adopted
nine
exclusions
from
what
may
constitute
a
``
physical
or
operational
change.''
One
of
these
is
an
exclusion
for
routine
maintenance,
repair,
and
replacement.
Today's
rulemaking
proposes
two
provisions
that
will
improve
and
help
carry
out
the
purposes
of
this
exclusion.
VI.
Discussion
of
Issues
Under
Annual
Maintenance,
Repair
and
Replacement
Allowance
Approach
The
following
provides
a
discussion
of
the
key
issues
we
considered
in
developing
our
preferred
approaches
to
addressing
RMRR
under
the
NSR
program.
We
are
requesting
comment
on
all
alternatives
considered
and
any
other
viable
alternatives.
We
are
also
interested
in
the
impact
the
use
of
a
cost
based
approach
such
as
the
annual
maintenance,
repair
and
replacement
allowance
will
have
on
reviewing
authorities,
such
as
the
need
for
staff
knowledgeable
in
cost
estimation,
and
are
requesting
comment
on
this
issue.
A.
Appropriate
Time
Period
for
a
Maintenance,
Repair
and
Replacement
Allowance
In
developing
a
maintenance,
repair
and
replacement
allowance,
we
considered
setting
an
allowance
based
on
either
a
calendar
or
fiscal
year
or
a
multi
year
limit.
We
believe
that
a
limit
applied
over
a
specified
period
of
time
is
more
appropriate
than
an
activitybased
limit.
We
are
proposing
an
annual
limit,
but
we
also
believe
that
a
multiyear
limit
is
worthy
of
serious
consideration
as
a
possible
option
that
could
be
chosen
by
owners
or
operators
with
multi
year
maintenance
cycles.
Under
NSR,
to
determine
applicability,
the
owner
or
operator
of
a
major
source
must
determine
whether
an
activity
performed
at
a
source
is
a
physical
change
or
change
in
the
method
of
operation
that
results
in
a
significant
emissions
increase
and
a
significant
net
emissions
increase.
NSR
may
apply
to
a
single
physical
change
or
operational
change
at
a
single
process
unit,
to
several
physical
or
operational
changes
at
a
single
process
unit,
or
to
multiple
changes
across
multiple
process
units,
each
of
which
changes
can
vary
widely
in
scope
and
cost.
Developing
a
maintenance,
repair
and
replacement
allowance
on
an
activity
basis
would
be
consistent
with
this
framework.
However,
the
variability
in
the
scope
of
such
activities
makes
it
difficult
to
establish
an
appropriate
cost
allowance
for
individual
activities
based
on
data
currently
available
to
us.
On
the
other
hand,
the
majority
of
information
that
is
currently
available
to
us
does
provide
a
reasonable
basis
for
developing
facility
wide,
annual
maintenance,
repair
and
replacement
cost
estimates.
In
addition
to
the
difficulty
in
establishing
an
activity
cost
limit,
maintenance
budgets
are
typically
set
on
an
annual
basis
rather
than
an
activity
basis,
making
an
annual
allowance
more
consistent
with
industry
financial
practices.
In
choosing
between
an
annual
versus
a
multi
year
limit,
there
are
considerations
pointing
in
both
directions.
The
most
important
argument
in
favor
of
a
multi
year
option
is
that
in
a
number
of
industries,
maintenance
cycles
extend
over
multiple
years.
For
example,
petroleum
refineries
conduct
regularly
scheduled
maintenance,
referred
to
as
a
``
turnaround,''
in
cycles
that
can
be
as
long
as
8
years
depending
on
the
type
of
units
and
equipment
involved
and
the
particulars
of
the
unit's
operations.
During
a
turnaround,
all
or
part
of
the
refinery
is
shut
down,
and
the
owner
or
operator
undertakes
numerous
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
maintenance,
repair
and/
or
replacement
activities
during
the
shutdown.
Similarly,
the
power
generation
sector
performs
regularly
scheduled
maintenance,
inspections,
and
repair
on
varying
cycles,
which,
depending
on
the
equipment
involved,
can
range
from
12
months
to
a
number
of
years.
Like
refineries,
power
generation
facilities
must
conduct
much
of
the
inspection,
maintenance,
repair
and
replacement
work
when
the
units
are
shut
down,
and
to
minimize
the
frequency
of
scheduled
outages,
the
owner
or
operator
will
undertake
numerous
activities
during
a
given
shutdown
to
minimize
maintenance
costs,
minimize
the
need
for
replacement
power,
and
maximize
the
availability
of
the
units.
As
a
result,
for
industries
of
this
type,
the
cost
of
maintenance
will
vary
significantly
from
year
to
year
and
may
be
distributed
across
several
years.
An
annual
allowance
for
industries
of
this
type
may
be
unworkable
if
the
allowance
is
set
at
the
average
of
their
maintenance
costs
during
their
maintenance
cycle.
But
setting
the
level
higher
than
the
average
runs
the
risk
of
sweeping
in
non
routine
activity.
In
addition,
an
annual
allowance
might
lead
owners
or
operators
in
such
industries
to
engage
in
more
outages
than
is
efficient
in
order
to
make
sure
that
they
were
not
losing
a
portion
of
their
allowance.
This
could
increase
energy
costs
and
reduce
energy
availability
to
consumers.
If
a
multi
year
allowance
were
used,
the
same
principles
of
summing
the
costs
of
activities
from
least
to
most
costly
and
excluding
the
most
costly
activities
from
the
allowance
and
instead
subjecting
them
to
case
by
case
scrutiny
would
continue
to
apply.
This
approach
also
may
have
its
difficulties.
For
example,
as
the
cycle
gets
longer,
it
is
harder
for
owners
or
operators
to
project
their
costs
for
safeguarding
the
safety,
reliability
and
efficiency
of
their
plants
farther
into
the
future.
This,
in
turn,
may
contribute
to
a
rule
that
is
more
difficult
to
implement
and
enforce.
If,
through
the
after
the
fact
case
by
case
review,
it
is
determined
that
certain
activities
should
have
been
subject
to
the
NSR
program,
all
parties
may
be
placed
in
the
difficult
situation
of
implementing
a
preconstruction
review
program
for
an
activity
that
was
begun
or
completed
significantly
prior
to
the
applicability
determination.
This
difficulty
may
arise
to
some
extent
even
with
a
1
year
allowance
period.
But
extending
the
period
beyond
1
year
increases
both
the
possibility
for
this
occurrence
and
the
potential
difficulties
of
an
after
the
fact
applicability
determination
for
older
activities.
Thus,
while
using
a
single
year
as
the
time
period
will
reduce
the
flexibility
for
some
owners
or
operators,
we
believe
it
will
help
to
reduce
the
likelihood
that
an
after
the
fact
NSR
review
will
be
required.
For
these
reasons,
we
are
proposing
the
annual
maintenance,
repair
and
replacement
allowance
approach,
but
will
also
be
giving
serious
consideration
to
the
multi
year
approach
of
up
to
5
years.
We
are
requesting
comments
on
the
approaches
discussed
above.
We
are
also
proposing
that
the
time
period
for
the
annual
maintenance,
repair
and
replacement
allowance
should
be
a
calendar
or
fiscal
year.
If
the
owner
or
operator
of
a
major
stationary
source
uses
a
fiscal
year
that
differs
from
a
calendar
year
for
accounting
purposes,
the
proposed
rule
would
allow
the
stationary
source
to
elect
to
use
that
fiscal
year
for
purposes
of
applying
the
annual
maintenance,
repair
and
replacement
allowance.
As
proposed,
once
the
choice
is
made,
the
choice
is
permanent.
(
See
§
51.165(
a)(
1)(
xxxxii)(
A)(
1),
§
51.166(
b)(
53)(
i)(
a),
§
52.21(
b)(
55)(
i)(
a),
and
§
52.24(
f)(
25)(
i)(
a)
of
proposed
rules.)
We
specifically
ask
for
comment
on
this
aspect
of
the
proposal.
B.
Cost
Basis
Under
our
proposal,
the
replacement
cost
of
a
source
would
be
multiplied
by
the
maintenance
percentage
established
by
rule
to
determine
the
annual
maintenance,
repair
and
replacement
allowance.
(
See
§
51.165(
a)(
1)(
xxxxii),
§
51.166(
b)(
53),
§
52.21(
b)(
55),
and
§
52.24(
f)(
25)
of
proposed
rules.)
In
developing
the
proposal,
we
also
considered
using
an
invested
cost
basis
adjusted
for
inflation.
There
can
be
advantages
to
using
invested
cost.
The
most
obvious
advantage
is
that
knowledge
of
cost
estimation
is
not
necessary,
because
actual
cost
data
would
be
used.
However,
complete
invested
cost
information
may
no
longer
exist
for
older
stationary
sources,
or
it
may
not
have
been
provided
to
the
buyer
when
a
source
was
purchased.
As
a
result,
we
would
still
need
to
provide
for
an
alternative
for
situations
where
invested
cost
data
were
not
available.
In
addition,
even
when
adjusted
for
inflation,
there
could
be
inequities
between
facilities
if
an
invested
cost
basis
was
used.
Adjustment
for
inflation
between
sources
will
not
likely
take
into
account
variations
in
site
specific
costs
such
as
land,
labor,
and
materials,
among
others.
Use
of
replacement
cost,
which
takes
into
account
site
specific
factors
to
a
greater
degree,
will
put
all
regulated
entities
on
a
more
equitable
footing.
Moreover,
most
decisions
regarding
maintenance,
repair
and
replacement
are
more
likely
to
take
into
consideration
the
cost
of
replacement
rather
than
the
original
invested
cost.
We
are
proposing
to
use
source
replacement
cost;
however,
we
are
requesting
comment
on
other
potentially
appropriate
bases
for
source
cost,
including
invested
cost,
invested
cost
adjusted
for
inflation
or
any
other
viable
methodology.
C.
Basis
for
Annual
Allowance
Stationary
Source
vs
Process
Unit
We
are
considering
two
approaches
for
administering
the
annual
maintenance,
repair
and
replacement
allowance
the
allowance
could
be
established
at
either
an
entire
stationary
source
(
source)
or
at
the
process
unit
level.
A
comprehensive
discussion
of
the
term
``
process
unit,''
along
with
a
proposed
definition,
is
set
forth
in
section
VII,
below.
If
we
opt
for
the
``
process
unit''
approach,
we
would
use
the
definition
and
concepts
proposed
in
section
VII.
We
are
proposing
the
stationary
source
approach
but
seeking
comment
on
both.
If
the
annual
maintenance,
repair
and
replacement
allowance
is
established
for
the
entire
stationary
source,
the
owner
or
operator
would
only
have
to
track
compliance
with
a
single
annual
maintenance,
repair
and
replacement
allowance
and
would
have
greater
flexibility
in
decision
making
with
respect
to
maintenance,
repair
and
replacement
activities.
It
is
our
understanding
that
accounting
of
maintenance
activities
is
most
often
performed
at
the
facility
level
and,
consequently,
managing
the
RMRR
annual
maintenance,
repair
and
replacement
allowance
from
a
facilitywide
standpoint
is
more
consistent
with
current
industry
practices.
In
large,
complex
manufacturing
facilities
such
as
refineries,
several
major
processes
are
constantly
being
maintained
but
larger
maintenance
activities
may
be
rotated
throughout
the
plant
during
different
years
to
accommodate
fiscal
and
operating
cycles.
Requiring
these
facilities
to
divide
their
plants
into
separate
process
units
for
maintenance
accounting
would
create
disincentives
to
the
source
in
administering
the
allowance.
A
source
wide
approach
also
may
be
more
sensible
to
account
for
situations
in
which
shared
services
(
e.
g.,
electrical
distribution,
wastewater
treatment)
cannot
be
attributed
to
a
single
process
at
a
facility.
On
the
other
hand,
setting
the
annual
maintenance,
repair
and
replacement
allowance
at
the
source
wide
level
presents
the
possibility
that
an
owner
or
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Proposed
Rules
operator
could
forego
maintenance
at
some
process
units
and
engage
in
activities
at
others
that
are
not
truly
RMRR
and
seek
to
use
the
maintenance,
repair
and
replacement
allowance
as
a
shield
for
these
activities.
Setting
the
annual
maintenance,
repair
and
replacement
allowance
at
the
process
unit
level
would
help
to
alleviate
this
concern.
On
balance,
however,
we
are
not
persuaded
that
this
concern
is
wellfounded
If
the
allowance
level
is
set
correctly,
the
only
way
an
owner
or
operator
could
attempt
the
kind
of
misuse
of
the
allowance
described
above
would
be
to
forego
maintenance,
repair
and
replacement
activities
at
other
process
units
activities
that
are
important
to
keep
those
other
process
units
in
good
working
order.
It
seems
unlikely
that
an
owner
or
operator
would
think
that
a
prudent
or
sensible
course.
Finally,
we
note
that
it
likely
is
more
difficult
to
develop
reliable
estimates
of
what
it
typically
costs
an
owner
or
operator
to
maintain
a
process
unit.
That
being
the
case,
the
most
likely
way
a
process
unit
based
allowance
would
be
developed
would
be
by
taking
the
numbers
that
would
underlie
a
sourcewide
allowance
and
allocating
them
to
process
units.
This
approach
could
present
its
own
opportunities
for
gaming
the
system.
We
are
proposing
to
set
the
annual
maintenance,
repair
and
replacement
allowance
at
the
source
wide
level.
(
See
§
51.165(
a)(
1)(
v)(
C)(
1),
§
51.166(
b)(
2)(
iii)(
a),
§
52.21(
b)(
2)(
iii)(
a),
and
§
52.24(
f)(
5)(
iii)(
a)
of
proposed
rules.)
We
believe
that
this
approach
is,
on
balance,
easier
to
implement
for
both
the
reviewing
authorities
and
the
industry
and
is
more
consistent
with
current
industry
maintenance
and
financial
practices.
We
specifically
request
comment
on
the
use
of
a
sourcewide
limit,
a
process
unit
limit,
or
any
other
means
of
applying
a
cost
threshold.
In
addition,
as
noted
in
section
VII,
we
request
comment
on
our
proposed
definition
of
process
unit.
D.
Basis
for
Annual
Maintenance,
Repair
and
Replacement
Allowance
Percentage
The
proposed
annual
maintenance,
repair
and
replacement
allowance
for
each
source
would
be
determined
by
multiplying
the
replacement
cost
of
the
source
by
an
annual
maintenance,
repair
and
replacement
allowance
percentage
specified
by
rule.
(
See
§
51.165(
a)(
1)(
xxxxii),
§
51.166(
b)(
53),
§
52.21(
b)(
55),
and
§
52.24(
f)(
25)
of
proposed
rules.)
As
stated
previously,
the
goal
of
this
portion
of
the
rule
is
to
provide
a
clear
exclusion
for
the
activities
whose
total
costs
fall
below
specified
thresholds.
We
intend
to
set
these
thresholds
on
an
industry
specific
basis,
and
believe
the
following
sources
of
information
should
be
useful
in
establishing
these
thresholds:
the
IRS
AAGRAP,
standard
engineering
reference
manuals,
and
actual
industry
data
available
to
the
EPA.
The
IRS
AAGRAP
is
the
value
used
in
an
exclusion
under
the
NSPS
for
increases
in
production.
The
IRS
AAGRAP
values
provide
repair
allowance
percentages
for
specific
industries
in
order
to
reflect
differing
maintenance
needs.
These
percentages
range
from
0.5
percent
to
20
percent
of
invested
cost.
For
instance,
the
aerospace
industry
has
an
AAGRAP
value
of
7.5
percent,
electric
utility
steam
generation
has
a
value
of
5
percent,
and
cement
plants
have
a
value
of
3
percent.
There
is
good
reason
to
think
that
the
industry
specific
basis
and
the
specific
percentages
are
appropriate
in
the
RMRR
context.
For
example,
the
AAGRAP
values
have
been
used
for
over
20
years
in
the
NSPS
program,
so
they
are
time
tested
and
appear
to
work
well
in
that
context.
Moreover,
because
the
values
were
developed
in
the
first
instance
to
differentiate
between
costs
that
should
be
capitalized
for
tax
accounting
purposes
and
costs
that
properly
should
be
expensed,
the
values
should
be
well
suited
to
distinguishing
maintenance,
repair
and
replacement
from
nonroutine
activities
in
the
NSR
context.
However,
the
AAGRAP
is
based
on
the
invested
cost
of
the
facility,
not
the
replacement
cost,
which
may
or
may
not
require
us
to
make
some
adjustments.
Also,
there
are
some
industries
for
which
an
AAGRAP
is
not
available.
The
policy
reasons
behind
the
use
of
AAGRAP
in
the
tax
context
also
may
not
be
the
same
as
those
we
need
to
consider
in
the
NSR
context,
notwithstanding
the
fact
that
the
AAGRAP
has
been
used
in
the
NSPS
context.
Finally,
the
IRS
has
moved
to
other
approaches.
We
solicit
comment
on
the
extent
to
which
the
AAGRAP,
or
some
derivative
of
the
AAGRAP,
may
appropriately
be
employed
if
we
determine
that
a
safe
harbor
based
on
replacement
cost
is
preferable.
There
are
also
standard
reference
manuals
that
provide
cost
estimation
information
that
is
considered
to
be
up
to
date.
Plant
Design
and
Economics
for
Chemical
Engineers,
by
Peters
and
Timmerhaus,
and
Perry's
Chemical
Engineer's
Handbook,
by
Perry
and
Green,
are
two
widely
used
resources.
They
provide
a
range
of
annual
maintenance
and
repair
costs
from
2
percent
to
10
percent
of
the
fixed
capital
investment
of
the
stationary
source.
These
two
resources,
however,
are
limited
to
the
chemical
process
industry
and
may
not
have
broader
applicability
to
other
industry
sectors
(
although
there
may
be
comparable
resources
for
other
industries).
Based
on
information
contained
in
the
resources
mentioned
above,
the
appropriate
annual
maintenance
percentages
would
be
in
the
range
of
0.5
percent
to
20
percent,
depending
on
the
industry.
To
the
extent
that
we
have
data,
we
intend
in
the
final
rule
to
set
different
percentages
for
specific
industry
categories.
In
selecting
appropriate
industry
specific
percentages,
it
would
be
helpful
if
further
information
is
made
available
to
us
during
the
public
comment
period
for
this
proposal;
therefore,
we
are
requesting
that
information
relating
to
types
of
maintenance,
repair
and
replacement
activities
undertaken
and
costs
associated
with
those
activities
be
provided
during
the
public
comment
period
on
this
proposed
rule.
For
example,
relevant
information
for
the
electric
utility
industry
might
be
available
from
the
NERC/
GADS
database,
the
Federal
Energy
Regulatory
Commission,
or
the
Integrated
Environmental
Control
Model
maintained
by
the
Energy
and
Environmental
Center
at
Carnegie
Mellon
University.
Commenters
should
provide
actual
source,
company
or
industry
information,
as
well
as
any
other
data
underlying
summaries.
Substantiated
claims
and
estimates
will
be
given
greater
consideration
than
information
not
supported
by
actual
data.
If
there
is
a
lack
of
information
with
which
to
set
industry
specific
percentages,
we
may
elect
to
set
a
default
value.
We
are
seeking
comment
on
the
appropriate
default
percentage
to
be
used,
and/
or
methods
available
to
determine
that
percentage.
E.
How
To
Calculate
Costs
In
order
for
a
cost
based
approach
to
be
equitable,
all
owners
or
operators
must
include
the
same
categories
of
expenses
in
both
the
replacement
cost
and
the
cost
sought
to
be
covered
by
the
allowance.
Therefore,
we
believe
it
may
be
appropriate
to
require
that
costs
be
calculated
using
an
approach
along
the
lines
set
out
as
the
elements
of
Total
Capital
Investment
as
defined
in
the
EPA
Air
Pollution
Control
Cost
Manual
(
http://
www.
epa.
gov/
ttn/
catc/
dir1/
c_
allchs.
pdf).
While
the
manual
contains
basic
concepts
that
could
be
used
to
estimate
total
capital
investment
at
a
process
unit,
it
is
geared
toward
cost
calculations
for
add
on
control
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31,
2002
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Proposed
Rules
equipment.
On
the
other
hand,
the
underlying
concepts
are
taken
from
work
done
by
the
American
Association
of
Cost
Engineers
to
define
the
components
of
cost
calculations
for
all
types
of
processes,
not
just
emission
control
equipment.
We
invite
comment
on
whether
we
should
use
the
manual
as
the
mechanism
for
standardizing
these
calculations,
whether
we
should
use
other
manuals,
or
whether
it
might
make
sense
to
give
sources
a
range
of
manuals
whose
approach
to
this
question
we
believe
may
be
appropriate
for
their
circumstances.
We
also
invite
comment
on
whether
EPA
should
require
use
of
the
manuals
identified
or
simply
provide
assurance
that
if
methods
in
an
identified
manual
are
used,
EPA
will
accept
them.
Under
the
EPA
Manual,
Total
Capital
Investment
includes
the
costs
required
to
purchase
equipment,
the
costs
of
labor
and
materials
for
installing
the
equipment
(
direct
installation
costs),
costs
for
site
preparation
and
buildings,
and
certain
other
indirect
installation
costs.
However,
any
costs
associated
with
the
installation
and
maintenance
of
pollution
control
equipment
would
be
excluded
from
the
cost
calculation.
For
the
purposes
of
this
maintenance,
repair
and
replacement
allowance,
we
believe
that
equipment
that
serves
a
dual
purpose
of
process
equipment
and
control
equipment
(
that
is,
combustion
equipment
used
to
produce
steam
and
to
control
Hazardous
Air
Pollutant
emissions,
exhaust
conditioning
in
the
semiconductor
industry,
etc.)
should
be
considered
process
equipment.
We
ask
for
comment
on
this
point.
Direct
installation
costs
include
costs
for
foundations
and
supports,
erecting
and
handling
the
equipment,
electrical
work,
piping,
insulation,
and
painting.
Indirect
installation
costs
include
such
costs
as
engineering
costs;
construction
and
field
expenses
(
that
is,
costs
for
construction
supervisory
personnel,
office
personnel,
rental
of
temporary
offices,
etc.);
contractor
fees
(
for
construction
and
engineering
firms
involved
in
the
activity);
startup
and
performance
test
costs;
and
contingencies.
We
are
also
considering
whether
or
not
to
exclude
costs
associated
with
the
unanticipated
shutdown
of
equipment,
due
to
component
failure
or
catastrophic
failures
such
as
explosions
or
fires,
from
the
costs
that
must
be
included
in
the
allowance.
If
costs
associated
with
unanticipated
outages
are
excluded,
these
activities
would
be
subjected
to
a
case
by
case
review
of
NSR
applicability.
We
request
comment
on
whether
or
not
repairs
and
replacements
resulting
from
the
unanticipated
shutdown
of
equipment,
or
of
an
entire
source,
should
be
included
in
the
annual
maintenance,
repair
and
replacement
allowance
calculations.
F.
Applicability
Safeguards
We
are
proposing
to
include
some
safeguards
in
our
rules.
There
are
some
relatively
inexpensive
activities
that
can
be
undertaken
at
a
facility
that
we
believe
should
not
be
included
within
the
maintenance,
repair
and
replacement
allowance
because,
due
to
their
very
nature,
they
may
significantly
alter
the
design
of
the
source
or
they
may
result
in
significantly
greater
emissions.
Ineligibility
for
the
allowance
does
not
mean
that
the
activities
will
necessarily
be
subject
to
NSR.
These
activities
will
still
be
eligible
for
treatment
as
RMRR
under
a
case
by
case
review,
may
qualify
for
other
exclusions,
may
not
require
a
major
NSR
permit
because
of
emissions
limitations
in
a
synthetic
minor
limitation,
or
may
be
netted
out
of
NSR
applicability.
We
are
proposing
to
include
three
such
safeguards.
(
See
§
51.165(
a)(
1)(
xxxxii)(
B),
§
51.166(
b)(
53)(
ii),
§
52.21(
b)(
55)(
ii),
and
§
52.24(
f)(
25)(
ii)
of
proposed
rules.)
The
first
of
the
safeguards
is
that
no
new
process
unit
may
be
added
under
the
annual
maintenance,
repair
and
replacement
allowance.
The
addition
of
a
new
process
unit
is
not
maintenance,
repair
or
replacement
of
existing
equipment
at
a
stationary
source
in
order
to
ensure
continued
safe
and
reliable
operation
and
hence
should
not
qualify
for
the
allowance.
The
second
safeguard
is
that
an
owner
or
operator
may
not
use
the
maintenance,
repair
and
replacement
allowance
to
replace
an
entire
process
unit.
We
do
not
believe
that
replacement
of
an
entire
process
unit
should
qualify
for
the
allowance.
Because
of
their
nature,
wholesale
exchanges
of
a
process
unit
should
be
subject
to
greater
scrutiny
in
determining
NSR
applicability
than
use
of
the
maintenance,
repair
and
replacement
allowance
would
entail.
The
third
safeguard
is
not
allowing
any
activity
that
results
in
an
increase
in
maximum
achievable
hourly
emissions
rate
of
a
regulated
NSR
pollutant
at
the
stationary
source
or
in
the
emission
of
any
regulated
NSR
pollutant
not
previously
emitted
to
be
excluded
under
the
annual
maintenance,
repair
and
replacement
allowance.
Such
activities
are
more
likely
to
result
in
possible
significant
emissions
increases
and,
therefore,
should
not
be
excluded
from
NSR
on
the
basis
that
they
fall
within
the
maintenance,
repair
and
replacement
allowance.
We
request
comment
on
the
appropriateness
and
adequacy
of
these
proposed
safeguards
or
any
additional
safeguards
that
may
be
appropriate.
G.
Timing
of
Determination
Under
the
annual
maintenance,
repair
and
replacement
allowance
as
proposed,
an
owner
or
operator
will
sum
the
costs
of
maintenance,
repair
and
replacement
activities
from
least
to
most
expensive
to
determine
which
activities
are
excluded
pursuant
to
the
allowance.
Actual
activity
costs
will
not
be
known
until
activities
are
underway
or
completed.
We
have
considered
two
options
for
the
timing
of
the
decision
regarding
qualification
of
activities
under
the
annual
maintenance,
repair
and
replacement
allowance
when
summing
activities
in
this
manner.
The
first
is
to
require
application
of
the
allowance
prior
to
construction
based
on
planned
activities
and
estimated
costs.
The
second
is
to
perform
an
endof
year
reconciliation
after
the
activity
costs
are
known.
If
an
end
of
year
reconciliation
is
used,
actual
costs
incurred
would
be
known.
However,
if
costs
exceed
the
annual
maintenance,
repair
and
replacement
allowance,
some
activities
that
have
already
been
started
or
completed
will
have
to
be
evaluated
on
a
case
by
case
basis
unless
already
excluded
from
major
NSR
on
some
other
basis.
If
it
is
determined
that
the
activity
is
not
RMRR
and
does
not
qualify
for
another
exclusion,
and
it
results
in
a
significant
emissions
increase
and
a
significant
net
emissions
increase,
and
it
is
consequently
subject
to
the
requirements
of
NSR,
the
owner
or
operator
would
be
in
violation
of
the
CAA
for
failure
to
obtain
the
necessary
permit
prior
to
commencing
construction.
In
addition,
if
in
a
nonattainment
area,
the
owner
or
operator
could
be
required
to
obtain
offsets,
which
may
not
be
readily
available
in
the
area.
The
owner
or
operator
may
also
be
faced
with
penalties
for
constructing
without
a
permit.
In
practice,
however,
we
do
not
believe
this
scenario
is
likely
to
occur.
We
expect
that
an
owner
or
operator
who
intended
to
rely
on
the
annual
maintenance,
repair
and
replacement
allowance
would
have
planned
the
year's
activities
accordingly
and
would
be
tracking
activities
throughout
the
year
in
order
to
avoid
this
situation.
We
believe
requiring
an
end
of
year
reconciliation
strikes
a
reasonable
balance,
since
it
will
lead
owners
or
operators
to
make
preconstruction
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
estimates
of
activities
and
costs
in
order
to
determine
qualification
for
the
exclusion
but
will
not
require
them
to
become
involved
in
permitting
type
actions
with
respect
to
excluded
activities.
Finally,
it
is
not
possible
for
an
owner
or
operator
to
plan
all
maintenance,
repair
and
replacement
needs,
so
there
will
be
inaccuracies
in
any
estimation
no
matter
how
diligent
an
owner
or
operator
may
be
in
seeking
to
plan
these
activities.
We
have
considered
two
other
possible
ways
to
address
this
situation.
The
first
is
to
allow
any
unplanned
activity
to
undergo
a
case
by
case
determination
of
RMRR.
However,
this
method
might
create
an
incentive
to
omit
smaller,
less
expensive
activities
from
the
preconstruction
estimation
in
order
to
avoid
a
case
by
case
review
on
larger
activities.
The
second
is
to
make
ineligible
for
the
use
of
the
maintenance,
repair
and
replacement
allowance
any
activity
that
was
not
included
in
the
preconstruction
estimation.
But
that
seems
unreasonable,
since
as
noted
above
actual
activity
costs
may
be
unintentionally
underestimated
or
omitted,
resulting
in
actual
activity
costs
exceeding
the
annual
maintenance,
repair
and
replacement
estimates.
After
considering
the
options,
we
believe
that
an
evaluation
based
on
actual
data
rather
than
estimates
is
preferable.
Careful
planning
by
an
owner
or
operator
should
reduce
the
likelihood
that
the
annual
allowance
is
exceeded
for
activities
that
the
owner
believes
will
come
within
the
allowance.
Moreover,
a
prudent
owner
or
operator
who
believes
his
RMRR
activities
will
be
close
to
exceeding
the
allowance
will
determine
whether
more
costly
activities
are
otherwise
excluded,
evaluate
them
under
the
case
by
case
test,
or
seek
an
applicability
determination
or
a
permit
to
assure
compliance
with
NSR
requirements.
Therefore,
we
are
proposing
to
determine
qualification
for
the
exclusion
through
an
end
of
year
reconciliation.
(
See
§
51.165(
a)(
1)(
xxxxii)(
A)(
5),
§
51.166(
b)(
53)(
i)(
e),
§
52.21(
b)(
55)(
i)(
e),
and
§
52.24(
f)(
25)(
i)(
e)
of
proposed
rules).
One
other
possible
approach
to
this
question
would
be
to
sum
costs
in
the
order
they
occur,
rather
than
from
least
expensive
to
most
expensive.
Under
that
approach,
an
owner
or
operator
would
maintain
a
running
total
of
maintenance,
repair
and
replacement
costs
and
could
determine
before
beginning
construction
on
a
subsequent
activity
if
there
was
room
under
the
annual
maintenance,
repair
and
replacement
allowance.
However,
this
process
might
encourage
an
owner
or
operator
to
delay
less
costly
activities
in
order
to
use
the
annual
maintenance,
repair
and
replacement
allowance
for
activities
that
are
both
larger
and
more
atypical
and,
therefore,
might
not
qualify
for
RMRR
treatment.
Maintaining
the
least
expensive
to
most
expensive
methodology
discussed
above,
we
could
address
the
issue
through
an
expedited
case
by
case
review
of
larger
activities.
An
owner
or
operator
would
be
responsible
for
obtaining
a
case
by
case
determination
from
the
reviewing
authority
for
larger
activities
to
ensure
that
an
activity
would
still
be
considered
RMRR
if
it
is
later
found
that
the
activity
could
not
be
accommodated
under
the
annual
maintenance,
repair
and
replacement
allowance.
This,
however,
is
inconsistent
with
our
intent
that
owners
or
operators
be
able
to
use
these
provisions
without
obtaining
an
advance
determination
from
the
reviewing
authority.
Finally,
rather
than
establishing
an
annual
cost
threshold
to
define
what
activities
fit
within
the
allowance,
we
could
establish
a
threshold
per
activity.
Activities
whose
costs
fell
below
the
threshold
could
proceed
as
RMRR.
Activities
with
costs
above
the
threshold
would
be
ineligible
to
use
the
allowance,
and
thus
could
only
constitute
RMRR
if
they
either
fell
within
the
portion
of
the
RMRR
exclusion
for
equipment
replacements
or
constitute
RMRR
upon
an
application
of
the
case
by
case
test.
We
are
proposing
a
similar
approach
for
replacement
of
equipment
with
functional
equivalents.
But
we
believe
that
any
broader
activity
based
approach
would
have
the
undesirable
consequence
of
forcing
industry
and
the
reviewing
authorities
to
address
potentially
complex
questions
about
how
to
define
whether
activities
are
truly
separate
and
hence
below
the
threshold
or
whether
they
are
part
of
some
larger
activity
that
exceeds
the
threshold.
To
summarize,
at
this
time
we
are
proposing
an
annual
maintenance,
repair
and
replacement
allowance;
to
sum
activities
from
least
expensive
to
most
expensive
to
determine
eligibility;
and
an
end
of
year
review
and
report.
We
request
comment
on
each
of
these
aspects
of
the
proposal
and
any
additional
approaches
that
commenters
wish
to
recommend.
VII.
Discussion
of
Issues
Under
the
Equipment
Replacement
Approach
We
recognize
that
there
are
numerous
occasions
when,
to
maintain,
facilitate,
restore,
or
improve
efficiency,
reliability,
availability,
or
safety
within
normal
facility
operations,
facilities
replace
existing
equipment
with
either
identical
equipment
or
equipment
that
serves
the
same
function.
Such
replacements
may
be
conducted
immediately
after
component
failure
or
they
may
be
conducted
preventively
to
assure
a
source's
continued
safe,
reliable
and
efficient
operation.
We
believe
that
many
such
replacements
typically
should
be
considered
RMRR
activities.
But,
allowing
replacement
of
equipment
with
``
functionally
equivalent''
or
``
identical''
equipment
to
qualify
as
RMRR,
if
unbounded,
could
theoretically
allow
replacement
of
an
entire
production
line
or
utility
boiler.
Thus,
there
must
also
be
some
reasonable
bound
to
equipment
replacements
that
qualify.
The
following
discussion
addresses
key
considerations
in
determining
the
appropriate
boundary
for
the
types
of
replacement
activities
that
should
be
excluded
under
the
equipment
replacement
provision
of
the
RMRR
exclusion.
A.
Replacement
of
Existing
Equipment
With
Identical
or
Functionally
Equivalent
Equipment
One
of
today's
proposals
deals
with
replacing
equipment
with
identical
or
functionally
equivalent
equipment.
This
proposal
is
based
on
our
view
that
most
replacements
of
existing
equipment
that
are
necessary
for
the
safe,
efficient,
and
reliable
operation
of
practically
all
industrial
operations
are
not
of
regulatory
concern
and
should
qualify
for
the
RMRR
exclusion.
Industrial
facilities
are
constructed
with
the
understanding
that
equipment
failures
are
common
and
ongoing
maintenance
programs
are
routine.
Delaying
or
foregoing
maintenance
could
lead
to
failure
of
the
production
unit
and
may
create
or
add
to
safety
concerns.
When
such
equipment
replacement
occurs
and
the
replacement
is
identical,
the
replacement
is
inherent
to
both
the
original
design
and
purposes
of
the
facility,
and
ordinarily
will
not
increase
emissions.
For
example,
if
a
pump
associated
with
a
distillation
column
fails
and
is
replaced
with
an
identical
new
pump,
we
believe
that
such
a
common
activity
is
and
should
be
considered
an
excluded
replacement.
We
believe
that
activities
like
such
pump
replacements
are
routine
and
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Federal
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
should
not
trigger
NSR
permitting
requirements.
We
also
recognize
that
this
principle
extends
beyond
the
replacement
of
equipment
with
identical
equipment.
When
equipment
is
wearing
out
or
breaks
down,
it
often
is
replaced
with
equipment
that
serves
the
same
purpose
or
function
but
is
different
in
some
respect
or
improved
in
some
way
in
comparison
to
the
equipment
that
is
removed.
For
example,
when
worn
out
pipes
are
replaced
in
a
chemical
process
plant,
the
replacement
pipes
sometimes
are
constructed
of
new
or
different
materials
to
help
reduce
corrosion,
erosion,
or
chemical
compatibility
problems.
Moreover,
the
technology
employed
in
certain
types
of
equipment
is
constantly
changing
and
evolving.
When
equipment
of
this
sort
needs
to
be
replaced,
it
often
is
simply
not
possible
to
find
the
old
style
technology.
Owners
or
operators
may
have
no
choice
but
to
purchase
and
install
equipment
reflecting
current
design
innovations.
Even
if
it
is
possible
to
find
old
style
equipment,
owners
or
operators
have
obvious
incentives
for
wanting
to
use
the
best
equipment
that
suits
the
given
need
when
replacements
must
be
installed.
A
good
example
was
presented
to
us
by
the
forest
products
industry
during
our
review
of
the
NSR
program's
impacts
on
the
energy
sector.
A
company
in
that
sector
needed
to
replace
outdated
analog
controllers
at
a
series
of
six
batch
digesters.
The
original
controllers
were
no
longer
manufactured.
The
new
digital
controllers,
costing
approximately
$
50,000,
are
capable
of
receiving
inputs
from
the
digester
vessel
temperature,
pressure,
and
chemical/
steam
flow.
The
new
controllers
would
have
more
precisely
filled
and
pressurized
digesters
with
chips,
chemicals,
and
steam,
thus
bringing
a
batch
digester
on
line
faster.
The
source
determined
that
this
activity
would
not
be
considered
routine
under
today's
NSR
rules
and
decided
not
to
proceed
with
the
project.
The
limiting
principle
here
is
that
the
replacement
equipment
must
be
identical
or
functionally
equivalent
and
must
not
change
the
basic
design
parameters
of
the
affected
process
unit
(
for
example,
for
electric
utility
steam
generating
units,
this
would
mean
maximum
heat
input
and
fuel
consumption
specifications).
Efficiency,
however,
should
not
be
considered
a
basic
design
parameter,
as
NSR
should
not
impede
industry
in
making
energy
and
process
efficiency
improvements
which,
on
balance,
will
be
beneficial
both
economically
and
environmentally.
This
should
address
the
concern
and
perception
that
the
NSR
program
serves
as
a
barrier
to
activities
undertaken
to
facilitate,
restore,
or
improve
efficiency,
reliability,
availability,
or
safety
of
a
facility.
We
also
note,
however,
that
taken
to
the
extreme,
even
without
a
change
in
basic
design
parameters,
an
identical
or
functionally
equivalent
replacement
activity
can
still
go
beyond
the
bounds
of
the
RMRR
exclusion.
For
example,
instead
of
replacing
a
pump,
what
if
a
chemical
manufacturing
facility
replaced
an
entire
production
unit?
Even
if
the
replacement
was
identical,
we
likely
would
not
consider
the
activity
to
be
an
excluded
replacement.
Such
an
activity
effectively
constitutes
construction
of
a
new
process
unit
in
much
the
same
way
the
construction
of
an
entirely
new
process
unit
at
an
existing
stationary
source
could
not
constitute
RMRR.
This
is
not
the
kind
of
activity
that
sources
typically
engage
in
to
maintain
their
plants,
and
it
is
the
kind
of
activity
that
would
likely
be
a
logical
point
for
owners
or
operators
to
install
state
of
the
art
controls.
We
recognize
that
it
may
sometimes
be
difficult
to
determine
where
to
draw
the
line
between
an
activity
that
should
be
treated
as
an
excluded
replacement
activity
and
one
that
should
be
viewed
as
a
physical
change
that
might
constitute
a
major
modification
when
the
replacement
of
equipment
with
identical
or
functionally
equivalent
equipment
involves
a
large
portion
of
an
existing
unit.
At
the
same
time,
we
believe
it
is
important
to
provide
some
clear
parameters
for
making
this
determination.
To
that
end,
we
are
soliciting
comment
on
an
equipment
replacement
cost
approach
based
on
the
NSPS
program
to
determine
whether
identical
or
functionally
equivalent
replacement
activities
constitute
RMRR
without
regard
to
other
considerations.
Under
the
NSPS
program,
a
project
at
an
existing
affected
source
triggers
any
applicable
NSPS
when
the
cost
of
the
project
exceeds
50
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
a
comparable
entirely
new
unit
that
is,
the
current
capital
replacement
value
of
the
existing
affected
source.
40
CFR
60.15(
b).
In
essence,
such
a
``
reconstruction''
is
tantamount
to
new
construction
and,
therefore,
triggers
any
applicable
NSPS
even
if
the
project
would
otherwise
be
excluded.
We
recognize
that,
in
some
respects,
an
equipment
replacement
cost
threshold
such
as
the
NSPS
reconstruction
test
may
be
viewed
as
the
proper
tool
to
be
used
in
the
future
for
distinguishing
between
routine
and
non
routine
identical
and
functionally
equivalent
replacements
under
the
NSR
program.
As
noted
above,
we
do
not
believe
it
is
reasonable
to
exclude
from
NSR
activities
that
involve
the
total
replacement
of
an
existing
entire
process
unit.
By
extension,
it
is
therefore
logical
and
consistent
to
conclude
that
activities
which,
based
on
their
cost,
effectively
constitute
replacement
of
the
process
unit
should
not
qualify
as
RMRR.
Thus,
we
believe
that
the
50
percent
capital
replacement
threshold
used
under
the
NSPS
might
constitute
an
appropriate
limitation
on
when
identical
or
functionally
equivalent
replacements
should
qualify
as
RMRR
under
the
equipment
replacement
provision
without
regard
to
other
considerations.
We
also
recognize,
however,
that
there
are
other
considerations
pointing
in
favor
of
a
threshold
lower
than
the
50
percent
reconstruction
threshold
that
may
be
appropriate
to
bound
the
equipment
replacement
provision.
For
example,
since
under
NSPS
half
of
the
capital
replacement
value
of
an
existing
affected
facility
effectively
constitutes
construction
of
a
new
unit,
it
could
be
argued
that
some
percentage
less
than
the
50
percent
reconstruction
threshold
might
be
a
suitable
line
of
demarcation
in
determining
whether
identical
replacements
constitute
a
modification
of
an
existing
unit.
We
are
soliciting
comment
on
whether
the
proposed
approach
is
workable,
whether
the
capital
replacement
percentage
should
be
50
percent
or
another
lesser
percentage,
and
whether
different
percentages
should
apply
to
different
industrial
groupings
or
different
types
of
industrial
processes.
For
example,
it
may
be
appropriate
to
set
a
higher
percentage
for
process
operations
that
involve
heat
and
corrosive
compounds.
Such
processes
may
require
more
expensive
replacements,
and
a
greater
degree
of
maintenance
activities
than
other
types
of
processes.
In
addition,
we
solicit
comment
on
whether
this
equipment
replacement
provision
should
be
implemented
on
a
component
bycomponent
basis,
or
some
other
reasoned
basis
such
as
applying
the
percentage
to
components
that
are
replaced
collectively
over
a
fixed
period
of
time.
We
recognize
that
there
are
widely
divergent
views
as
to
how
expansive
the
RMRR
exclusion
should
be.
From
our
perspective,
the
most
important
thing
we
can
do
to
improve
air
quality
in
the
United
States
with
respect
to
stationary
sources
is
to
make
substantial
reductions
in
NOX
and
SO2
emissions
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/
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2002
/
Proposed
Rules
from
facilities
in
the
utility
sector.
Our
current
view,
however,
is
that
if
the
rules
clearly
establish
a
narrow
RMRR
exclusion
and
set
out
to
require
permits
for
replacement
of
larger
components
or
the
replacement
of
components
with
more
efficient
ones,
owners
or
operators
will
comply
with
these
rules
but
will
find
ways
to
make
the
replacements
without
having
to
obtain
permits
and
install
state
of
the
art
controls.
As
a
result,
such
rules
will
not
achieve
significant
reductions
in
NOX
or
SO2
on
a
prospective
basis.
As
discussed
below,
these
owners
or
operators
will
likely
avoid
having
to
make
such
reductions
through
one
of
several
ways
plainly
permissible
under
NSR.
For
example,
when
a
power
plant
operator
plans
to
undertake
an
activity
that
the
operator
believes
may
not
qualify
as
RMRR
and
is
assessing
compliance
alternatives,
that
operator
is
faced
with
three
options:
(
1)
Proceed
with
the
activity
pursuant
to
an
NSR
permit,
which
could
require
more
than
$
100
million
to
be
spent
on
air
pollution
controls;
(
2)
forego
the
activity,
which
likely
would
result
in
a
permanent
reduction
in
capacity
or
utilization
of
the
facility
or
might
reduce
efficiency
and
increase
emissions
per
unit
of
product
manufactured
or
energy
produced;
or
(
3)
proceed
with
the
activity,
but
take
steps
to
limit
future
emissions
such
that
the
activity
would
not
result
in
a
significant
net
emissions
increase.
We
also
believe
that
few
owners
or
operators
would
choose
the
first
option.
This
option
would
make
economic
sense
only
in
circumstances
where
the
current
capacity
and
utilization
of
the
facility
are
so
low
that
the
major
investment
in
air
pollution
controls
would
provide
an
incrementally
better
payback
than
the
option
of
investing
the
same
money
in
other
assets
or
in
the
development
of
a
new
power
plant.
We
also
believe
that
few
owners
or
operators
would
elect
the
second
option.
It
makes
no
sense
in
most
cases
for
the
owners
or
operators
of
costly
power
plants
to
let
these
assets
significantly
deteriorate
over
time,
because
the
value
of
the
asset
will
eventually
be
lost.
We
believe
that
most
owners
or
operators
would
select
the
third
option.
We
note
that
industry
commenters
during
our
review
of
the
impact
of
NSR
on
the
energy
sector
argued
that
this
option
would,
over
time,
result
in
a
substantial
reduction
in
the
capacity
of
their
facilities.
For
example,
the
Tennessee
Valley
Authority
reported
that,
over
the
last
20
years,
it
would
have
lost
32
percent
of
its
coal
system's
energy
capability
if
it
had
capped
emissions
under
a
``
narrow''
routine
maintenance
exclusion.
In
similar
analyses,
Southern
Company
estimated
that
it
would
have
experienced
an
energy
shortfall
of
57.5
million
MW
hr,
and
First
Energy
estimated
that
it
would
have
lost
39
percent
of
its
coal
fired
generating
capacity
between
1981
and
2000.
West
Associates,
the
Western
System
Coordinating
Council,
and
the
National
Rural
Electric
Cooperative
Association
reported
similar
results.
Notwithstanding
these
assessments,
we
believe
that
most
owners
or
operators
would
proceed
with
activities
and
take
emissions
limitations.
To
the
extent
that
such
limitations
might
curtail
full
utilization
of
the
facility,
incremental
control
measures
of
modest
cost
would
likely
be
taken
to
recover
the
``
lost''
utilization.
For
example,
use
of
a
slightly
lower
sulfur
coal
could
produce
the
marginally
lower
SO2
emissions
that
would
be
needed
to
recapture
some
capacity.
Likewise,
various
types
of
relatively
low
cost
combustion
or
process
control
modifications
could
be
employed
to
reduce
NOX
emissions.
Thus,
it
is
not
probable
that
owners
or
operators
would
respond
to
a
narrow
exclusion
by
installing
state
of
the
art
controls
every
time
they
need
to
replace
a
major
component.
At
the
same
time,
a
narrow
RMRR
exclusion
of
this
type
would
not
allow
in
many
cases
the
replacement
of
equipment
with
equipment
that
improves
process
efficiency.
This
would
cause
owners
or
operators
to
forego
replacements
that
would
improve
air
quality
because
they
would
allow
greater
efficiency.
For
these
reasons,
a
narrow
RMRR
exclusion
that
is
clearly
established
is
not
expected
to
achieve
significant
reductions
in
historic
emissions
levels,
and
might
even
lead
to
area
wide
emissions
increases.
Most
facilities
would
take
lawful
steps
to
avoid
having
to
obtain
an
NSR
permit
that
would
impose
strict
limitations,
even
when
replacements
would
be
found
under
this
narrow
exclusion
to
be
non
routine.
B.
Defining
``
Process
Unit''
for
Evaluating
Equipment
Replacement
Cost
Percentage
In
this
section,
we
discuss
issues
related
to
what
collection
of
equipment
should
be
considered
in
applying
the
equipment
replacement
approach.
We
are
proposing
the
term
``
process
unit''
as
the
appropriate
collection.
A
definition
of
process
unit
currently
is
included
in
40
CFR
63.41.
We
have
built
upon
that
definition
to
accommodate
the
intended
coverage
of
activities
under
the
equipment
replacement
approach.
The
purpose
of
this
term
is,
as
best
as
possible,
to
align
implementation
of
the
provision
with
generally
accepted
and
practical
understandings
of
what
constitutes
a
discrete
production
process.
The
general
definition
would
read
as
follows:
Process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
facility
may
contain
more
than
one
process
unit.
Our
primary
goal
in
defining
this
term
is
to
encompass
integrated
manufacturing
operations
that
produce
a
completed
product
rather
than
smaller
pieces
of
such
operations.
To
help
illustrate
these
concepts,
we
developed
and
have
included
in
the
proposed
rules
some
industry
specific
examples
of
how
this
definition
might
be
applied.
The
examples
are
drawn
from
a
few
selected
industry
categories
electric
utilities,
refineries,
cement
manufacturers,
pulp
and
paper
producers,
and
incinerators.
Because
of
the
centrality
of
the
``
process
unit''
concept
to
the
usefulness
of
the
equipment
replacement
provision,
it
is
our
desire
to
include
a
version
of
these
examples
in
the
final
rule
to
make
sure
sources
have
a
benchmark
against
which
they
can
evaluate
with
greater
confidence
whether
a
particular
replacement
comes
within
the
equipment
replacement
provision
of
the
RMRR
exclusion.
We
also
request
comment
on
whether
associated
pollution
control
equipment
should
typically
not
be
considered
part
of
the
process
unit.
We
are
proposing
to
exclude
such
equipment
from
the
definition.
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
that
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boiler,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.
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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
We
solicit
comment
on
the
proposed
definition
of
``
process
unit''
and
whether
another
approach
might
be
more
effective.
We
also
solicit
comment
on
the
particular
process
units
identified
in
specific
industries,
whether
there
are
better
ways
of
identifying
those
process
units
in
those
industries,
and
whether
other
process
units
should
be
specifically
identified
as
part
of
the
rule.
Finally,
today's
proposed
approaches
for
replacement
of
existing
equipment
with
identical
or
functionally
equivalent
equipment
rely
on
the
concept
of
a
process
unit,
but
it
is
possible
that
it
is
not
appropriate
for
replacement
of
nonemitting
components
because
such
replacements
may
not
have
emissions
consequences
in
the
first
place
and
hence
would
not
warrant
scrutiny
under
NSR.
Similarly,
it
is
possible
that
maintenance,
repair
and
replacement
activities
performed
on
non
emitting
units
should
not
be
included
in
the
activities
that
would
have
to
be
accounted
for
under
the
annual
maintenance,
repair
and
replacement
allowance
provision
of
the
RMRR
exclusion.
We
solicit
comment
on
how
these
various
activities
should
be
handled
in
the
context
of
today's
proposal,
bearing
in
mind
that
forthcoming
proposed
NSR
rules
for
future
activities
involving
debottlenecking
will
specifically
address
changes
made
at
non
emitting
units
that
affect
emissions
at
other
process
units
at
a
stationary
source
among
other
issues.
However,
we
request
comment
on
limiting
today's
proposed
approaches
to
changes
made
at
emitting
units
or
modifying
them
so
as
to
differentiate
between
changes
made
at
emitting
versus
non
emitting
units.
C.
Miscellaneous
Issues
In
addition
to
the
issues
noted
above,
we
also
request
comment
on
the
following
matters.
First,
we
solicit
comments
on
the
topic
of
basic
design
parameters.
Our
proposal
states
that
maximum
heat
input
and
fuel
consumption
specifications
(
for
electric
utility
steam
generating
units)
and
maximum
material/
fuel
input
specifications
(
for
other
types
of
units)
are
basic
design
parameters.
We
solicit
comment
on
whether
that
provides
sufficient
definition
of
this
term,
whether
further
definition
is
appropriate,
or
whether
there
are
industry
specific
considerations
that
should
be
taken
into
account.
Second,
in
calculating
costs,
we
propose
that
owners
or
operators
should
use
the
same
principles
and
guidelines
as
discussed
above
with
respect
to
calculating
costs
for
the
maintenance,
repair
and
replacement
allowance.
We
request
comment
on
whether
these
same
principles
and
requirements
are
applicable
and
workable
for
the
equipment
replacement
provision.
Third,
in
addition
to
soliciting
comment
on
the
approaches
described
above,
we
are
also
soliciting
comment
on
whether
the
maintenance,
repair
and
replacement
allowance
and
this
equipment
replacement
provision
should
both
be
adopted
or
whether
just
the
equipment
replacement
provision
is
sufficient?
In
addition,
if
we
assume
that
both
approaches
are
adopted,
how
should
they
work
together?
Should
an
RMRR
activity
that
is
excluded
under
the
equipment
replacement
provision
also
count
against
your
annual
maintenance,
repair
and
replacement
allowance?
We
are
soliciting
comment
on
whether
to
adopt
any
or
all
of
these
approaches
and
how
they
might
fit
together.
Lastly,
EPA
strongly
supports
efforts
to
improve
energy
efficiency
at
existing
power
plants.
These
activities
reduce
the
amount
of
criteria
pollutants
(
SO2
and
NOX)
emitted
per
unit
of
electricity
generated
and
also
reduce
greenhouse
gas
emissions.
During
our
study
of
the
impact
of
NSR
on
the
energy
sector,
we
received
information
concerning
a
number
of
instances
where
activities
that
would
have
improved
energy
efficiency
were
not
implemented
because
they
would
have
resulted
in
significant
annual
emission
increases
that
would
have
triggered
NSR.
Some
have
commented
that
any
activity
that
produces
any
improvement
in
energy
efficiency
should
be
exempt
from
NSR.
However,
given
the
continuing
improvement
in
materials
and
design,
almost
any
component
replacement
can
be
expected
to
have
some
beneficial
impact
on
the
energy
efficiency
of
the
unit
and,
left
unbounded,
this
approach
could
result
in
the
replacement
of
an
entire
boiler
with
a
new,
more
efficient
boiler
without
state
of
the
art
pollution
controls.
As
mentioned
above,
however,
we
do
not
think
replacement
of
an
entire
boiler
is
properly
viewed
as
routine.
We
also
do
not
believe
that
the
need
to
install
state
of
the
art
controls
on
new
boilers
will
deter
sources
from
installing
new
boilers
if
they
are
otherwise
prepared
to
do
so.
These
issues
prompt
EPA
to
solicit
comment
in
several
areas.
To
the
extent
that
an
activity
is
the
replacement
of
existing
equipment
that
serves
the
same
function
as
the
equipment
replaced,
does
not
alter
the
basic
design
parameters
of
the
process
unit,
and
otherwise
meets
the
provisions
of
our
proposed
equipment
replacement
approach,
described
above,
it
would
be
excluded
from
NSR
under
the
proposal.
There
may,
however,
be
rare
instances
where
activities
do
not
involve
replacing
existing
equipment,
are
not
otherwise
excluded
from
NSR,
and
nevertheless
promote
efficiency.
Is
there
a
need
for
a
separate
``
stand
alone''
exclusion
for
such
activities?
If
so,
should
there
be
other
limitations
on
the
scope
of
such
activities?
Are
there
activities
that
result
in
a
minor
improvement
in
efficiency
but
a
very
large
increase
in
annual
emissions?
If
so,
what
are
the
characteristics
of
such
activities
and
how
should
EPA
treat
them?
Today,
we
solicit
comment
broadly
on
the
impact
of
the
NSR
program
on
decisions
to
proceed
with
activities
that
produce
net
benefits
to
human
health
and
the
environment,
including,
but
not
limited,
to
energy
efficiency
activities.
We
also
solicit
comments
on
the
extent
to
which
our
proposals
can
promote
energy
efficiency
while
preserving
the
benefits
of
the
NSR
program.
D.
Quantitative
Analysis
We
have
attempted
to
analyze
quantitatively
the
possible
emissions
consequences
of
the
range
of
different
approaches
to
the
RMRR
exclusion
described
above
to
evaluate
if
our
policy
conclusions
are
correct.
Our
analysis
was
conducted
using
the
Integrated
Planning
Model
(
IPM).
This
analysis
was
done
for
electric
utilities
because
we
have
a
powerful
model
to
perform
such
an
analysis
that
we
do
not
have
for
other
industries.
We
think
the
results
for
the
electric
utilities
accurately
reflects
the
trends
we
would
see
in
other
industries.
This
model
and
technical
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/
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31,
2002
/
Proposed
Rules
information
describing
it
can
be
found
in
the
docket.
The
analysis
included
several
relevant
scenarios.
In
the
first
scenario,
we
assumed
that
efficiency
and
capacity
of
relevant
units
modestly
decrease
over
time.
This
scenario
was
intended
to
reflect
the
consequences
of
a
new
rule
with
a
relatively
``
narrow''
RMRR
exclusion,
under
which
we
would
assume
that
there
would
be
slow
and
steady
deterioration
of
relevant
generating
assets.
As
explained
above,
we
do
not
actually
believe
that
such
a
trend
would
occur
under
such
a
new
RMRR
exclusion,
because
plants
would
take
steps
to
limit
emissions
and
perhaps
implement
incremental
controls
to
recapture
lost
capacity.
Nevertheless,
we
believe
that
this
scenario
offers
a
bounding
analysis
for
seeing
whether
a
narrow
RMRR
exclusion
can
have
significant
emissions
benefits
because
our
model
assumes
well
controlled
and
highly
efficient
new
generating
assets
rather
than
recaptured
capacity
from
incrementally
better
controlled
existing
units.
In
the
other
scenarios,
we
assumed
that
utilization,
efficiency,
or
capacity
of
relevant
units
modestly
increases
over
time.
These
scenarios
were
intended
to
reflect
the
consequences
of
a
new
rule
with
a
``
broader''
RMRR
exclusion,
which
would
allow
facility
availability
and/
or
output
over
time
without
triggering
major
NSR.
These
scenarios
present
various
combinations
of
assumptions
on
possible
incremental
changes
to
relevant
operational
parameters
and
are
intended
to
encompass
the
range
of
possible
operational
outcomes
that
might
be
associated
with
the
proposed
RMRR
exclusion.
The
IPM
analyses
of
these
scenarios
proves
the
point
made
above,
that
the
breadth
of
the
RMRR
exclusion
would
have
no
practical
impact
on,
let
alone
being
the
controlling
factor
in
determining,
the
emissions
reductions
that
will
be
achieved
in
the
future
under
the
major
NSR
program.
The
analyses
show
that
emissions
of
SO2
are
essentially
the
same
under
all
scenarios.
This
stands
to
reason
because
nationwide
emissions
of
SO2
from
the
power
sector
are
capped
by
the
title
IV
Acid
Rain
Program.
For
NOX,
these
analyses
show
modest
relative
decreases
in
some
cases
and
modest
relative
increases
in
other
cases.
These
predicted
changes
represent
only
a
modest
fraction
of
nationwide
NOX
emissions
from
the
power
sector,
which
hover
around
4.3
million
tons
per
year
(
tpy).
At
this
time,
we
do
not
have
adequate
information
to
predict
with
confidence
which
modeled
scenario
is
most
likely
to
occur
if
the
options
under
consideration
are
adopted.
What
these
analyses
indicate,
however,
is
that
regardless
of
which
scenario
is
closest
to
what
comes
to
pass,
none
of
the
proposed
provisions
related
to
the
RMRR
exclusion
will
have
a
significant
impact
on
emissions
from
the
power
sector.
The
DOE
also
attempted
to
analyze
quantitatively
the
possible
emissions
consequences
of
the
range
of
different
approaches
to
the
RMRR
exclusion
described
above.
Using
the
National
Energy
Modeling
System
(
NEMS),
a
variety
of
changes
in
energy
efficiency
and
availability
were
evaluated,
as
well
as
the
effect
on
emissions
resulting
from
these
changes.
This
analysis
concluded
that
efficiency
improvements
resulting
from
increased
maintenance
are
expected
to
decrease
emissions,
whereas
availability
improvements
are
expected
to
increase
emissions.
In
the
cases
represented
in
this
analysis,
the
impacts
of
the
assumed
reductions
in
heat
rates
tend
to
dominate
the
corresponding
effects
of
the
assumed
availability
increases.
Data
regarding
the
emissions
reductions
that
are
achieved
under
other
CAA
programs
further
illustrate
the
relative
limits
of
the
major
NSR
program
as
a
tool
for
achieving
significant
emissions
reductions.
For
example,
the
title
IV
Acid
Rain
Program
has
reduced
SO2
emissions
from
the
electric
utility
industry
by
more
than
7
million
tpy
and
will
ultimately
result
in
reductions
of
approximately
10
million
tpy.
The
Tier
2
motor
vehicle
emissions
standards
and
gasoline
sulfur
control
requirements
will
ultimately
achieve
NOX
reductions
of
2.8
million
tpy.
Standards
for
highway
heavy
duty
vehicles
and
engines
will
reduce
NOX
emissions
by
2.6
million
tpy.
Standards
for
non
road
diesel
engines
are
anticipated
to
reduce
NOX
emissions
by
about
1.5
million
tpy.
The
NOX
``
SIP
call''
will
reduce
NOX
emissions
by
over
1
million
tpy.
Altogether,
these
and
other
similar
programs
achieve
emissions
reductions
that
far
exceed
those
attributable
to
the
major
NSR
program
and
dwarf
any
possible
emissions
consequences
attributable
to
future
promulgation
of
a
rule
based
on
today's
proposal.
A
copy
of
our
IPM
analysis
and
the
DOE
NEMS
analysis
are
included
in
the
docket
for
this
rulemaking.
We
ask
for
comment
on
all
aspects
of
these
analyses
and
on
the
policy
discussion
provided
above.
VIII.
Other
Options
Considered
In
addition
to
the
cost
based
approaches
discussed
above,
we
are
considering
two
additional
options
for
addressing
RMRR.
These
options
are
discussed
below,
and
we
are
requesting
comment
on
these
options.
We
are
also
interested
in
other
possible
alternatives.
A.
Capacity
Based
Option
We
are
considering
the
alternative
option
of
developing
an
RMRR
provision
based
on
the
capacity
of
a
process
unit.
Under
such
an
approach,
an
owner
or
operator
could
undertake
any
activity
that
did
not
increase
the
capacity
of
the
process
unit.
Such
an
approach
would
require
safeguards
similar
to
those
in
the
proposed
costbased
approaches
in
order
to
ensure
that
activities
that
should
be
subject
to
the
NSR
program
are
not
inappropriately
excluded.
These
safeguards
would
exclude
the
construction
of
a
new
process
unit,
the
replacement
of
an
entire
process
unit,
and
activities
that
result
in
an
increase
in
maximum
achievable
hourly
emissions
rate
of
a
regulated
NSR
pollutant
from
use
of
the
exclusion
or
the
emission
of
any
regulated
NSR
pollutant
not
previously
emitted
by
the
stationary
source.
Basing
RMRR
on
capacity
is
appealing
for
several
reasons.
The
primary
objective
of
RMRR
is
to
keep
a
unit
operating
at
capacity
and/
or
availability.
In
addition,
the
linkage
between
capacity
and
environmental
impact
is
more
apparent
than
cost
and
environmental
impact.
Finally,
this
type
of
approach
might,
in
principle,
be
easier
to
use
before
beginning
actual
construction
than
the
cost
based
approaches.
The
difficulty
with
using
a
capacitybased
approach
is
defining
the
capacity
of
a
process
unit.
Capacity
may
be
defined
based
on
input
or
output.
Nameplate
capacity
of
a
process
unit
may
vary
greatly
from
the
capacity
at
which
the
process
unit
may
be
able
to
operate.
It
may
be
more
appropriate
in
some
industries
to
measure
capacity
based
on
input
while
in
others
on
output.
As
an
example,
in
a
review
of
promulgated
and
proposed
Maximum
Achievable
Control
Technology
standards,
six
of
eleven
standards
measured
capacity
based
on
unit
output
while
five
based
capacity
on
input.
In
fact,
the
NSPS
exclusion
for
increases
in
production
rate
at
40
CFR
60.14(
e)
originally
was
dependent
upon
the
``
operating
design
capacity''
of
an
affected
unit.
In
proposed
revisions
to
the
NSPS
program
published
on
October
15,
1974,
we
state
(
39
FR
36948):
The
exemption
of
increases
in
production
rate
is
no
longer
dependent
upon
the
``
operating
design
capacity.''
This
term
is
not
easily
defined,
and
for
certain
industries
the
``
design
capacity''
bears
little
relationship
to
the
actual
operating
capacity
of
the
facility.
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251
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December
31,
2002
/
Proposed
Rules
We
are
requesting
comment
on
this
capacity
based
option,
as
well
as
comments
on
possible
methods
to
address
any
of
the
issues
relating
to
implementation
of
such
an
option.
B.
Age
Based
Option
Under
an
age
based
approach,
any
process
unit
under
a
specified
age
could
undergo
any
activity
that
does
not
increase
the
capacity
of
a
process
unit
on
a
maximum
hourly
basis
without
triggering
the
requirements
of
the
major
NSR
program.
However,
the
activities
could
not
constitute
reconstruction
of
the
process
unit;
that
is,
their
cost
could
not
exceed
50
percent
of
the
cost
of
a
replacement
process
unit.
The
age
of
the
process
unit
would
likely
be
in
the
range
of
25
50
years.
An
owner
or
operator
would
have
to
become
a
Clean
Unit
as
defined
at
40
CFR
51.165(
c)(
3),
51.166(
t)(
3),
and
52.21(
x)(
3),
once
the
age
of
a
process
unit
exceeds
the
age
threshold.
Such
an
approach
would
provide
an
owner
or
operator
a
clear
understanding
of
RMRR
for
an
extended
period
of
time.
It
also
may
provide
the
owner
or
operator
greater
flexibility
than
under
the
current
system
for
a
limited
period
of
time.
Like
the
capacity
based
approach,
this
approach
would,
in
principle,
allow
for
a
fairly
simple
preconstruction
determination
of
applicability.
We
see
several
difficulties
in
developing
this
type
of
approach.
The
first
is
defining
capacity.
The
second
is
establishing
the
age
cut
off
for
the
exclusion.
The
useful
life
of
equipment
is
difficult
to
establish
and
may
vary
greatly.
The
third
is
that
some
of
the
activities
that
would
be
allowed
at
newer
sources
do
not
fit
within
any
ordinary
meaning
of
RMRR
and
some
of
the
activities
that
would
be
forbidden
at
older
facilities
would
come
within
that
meaning.
Fourth,
some
sources
may
consciously,
and
appropriately,
engage
in
aggressive
RMRR
as
a
method
of
maximizing
the
life
span
of
its
process
units,
and
an
age
based
approach
would
discriminate
against
them.
We
are
requesting
comment
on
this
age
based
option,
as
well
as
comments
on
possible
methods
to
address
the
issues
raised
above
with
respect
to
this
option.
IX.
Administrative
Requirements
for
This
Proposed
Rulemaking
A.
Executive
Order
12866
Regulatory
Planning
and
Review
Under
Executive
Order
12866
[
58
FR
51,735
(
October
4,
1993)],
we
must
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(
2)
Create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(
3)
Materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligations
of
recipients
thereof;
or
(
4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
OMB
has
notified
us
that
it
considers
this
an
``
economically
significant
regulatory
action''
within
the
meaning
of
the
Executive
Order.
We
have
submitted
this
action
to
OMB
for
review.
Changes
made
in
response
to
OMB
suggestions
or
recommendations
will
be
documented
in
the
public
record.
All
written
comments
from
OMB
to
EPA
and
any
written
EPA
response
to
any
of
those
comments
are
included
in
the
docket
listed
at
the
beginning
of
this
notice
under
ADDRESSES.
In
addition,
consistent
with
Executive
Order
12866,
EPA
consulted
extensively
with
the
State,
local
and
tribal
agencies
that
will
be
affected
by
this
rule.
We
have
also
sought
involvement
from
industry
and
public
interest
groups.
B.
Executive
Order
13132
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
us
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
are
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
This
proposed
rule
does
not
have
federalism
implications.
Nevertheless,
in
developing
this
rule,
we
consulted
with
affected
parties
and
interested
stakeholders,
including
State
and
local
authorities,
to
enable
them
to
provide
timely
input
in
the
development
of
this
rule.
A
summary
of
stakeholder
involvement
appears
above
in
section
III.
C.
of
today's
proposed
rule.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
State
and
local
programs,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
While
this
proposed
rule
will
result
in
some
expenditures
by
the
States,
we
expect
those
expenditures
to
be
limited
to
$
580,160
for
the
estimated
112
affected
reviewing
authorities.
This
figure
includes
the
small
increase
in
burden
imposed
upon
reviewing
authorities
in
order
for
them
to
revise
the
State's
State
Implementation
Plan
(
SIP).
However,
this
revision
provides
sources
permitted
by
the
States
greater
certainty
in
application
of
the
program,
which
should
in
turn
reduce
the
overall
burden
of
the
program
on
State
and
local
authorities.
Thus,
the
requirements
of
Executive
Order
13132
do
not
apply
to
this
rule.
C.
Executive
Order
13175
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
EPA
believes
that
this
proposed
rule
does
not
have
tribal
implications
as
specified
in
Executive
Order
13175.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.
The
purpose
of
today's
proposed
rule
is
to
add
greater
flexibility
to
the
existing
major
NSR
regulations.
These
changes
will
benefit
reviewing
authorities
and
the
regulated
community,
including
any
major
source
owned
by
a
tribal
government
or
located
in
or
near
tribal
land,
by
providing
increased
certainty
as
to
when
the
requirements
of
the
NSR
program
apply.
Taken
as
a
whole,
today's
proposed
rule
should
result
in
no
added
burden
or
compliance
costs
and
should
not
substantially
change
the
level
of
environmental
performance
achieved
under
the
previous
rules.
The
EPA
anticipates
that
initially
these
changes
will
result
in
a
small
increase
in
the
burden
imposed
upon
reviewing
authorities
in
order
for
them
to
be
included
in
the
State's
SIP.
Nevertheless,
these
options
and
revisions
will
ultimately
provide
greater
operational
flexibility
to
sources
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67,
No.
251
/
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December
31,
2002
/
Proposed
Rules
permitted
by
the
States,
which
will
in
turn
reduce
the
overall
burden
on
the
program
on
State
and
local
authorities
by
reducing
the
number
of
required
permit
modifications.
In
comparison,
no
tribal
government
currently
has
an
approved
Tribal
Implementation
Plan
(
TIP)
under
the
CAA
to
implement
the
NSR
program.
The
Federal
government
is
currently
the
NSR
reviewing
authority
in
Indian
country.
Thus,
tribal
governments
should
not
experience
added
burden,
nor
should
their
laws
be
affected
with
respect
to
implementation
of
this
rule.
Additionally,
although
major
stationary
sources
affected
by
today's
proposed
rule
could
be
located
in
or
near
Indian
country
and/
or
be
owned
or
operated
by
tribal
governments,
such
affected
sources
would
not
incur
additional
costs
or
compliance
burdens
as
a
result
of
this
rule.
Instead,
the
only
effect
on
such
sources
should
be
the
benefit
of
the
added
certainty
and
flexibility
provided
by
the
rule.
The
EPA
recognizes
the
importance
of
including
tribal
consultation
as
part
of
the
rulemaking
process.
Nonetheless,
to
this
point
we
have
not
specifically
consulted
with
tribal
officials
on
this
proposed
rule.
We
are
committed
to
work
with
any
tribal
government
to
resolve
any
issues
that
we
may
have
overlooked
in
today's
proposed
rules
and
that
may
have
an
adverse
impact
in
Indian
country.
As
a
result,
today
we
are
announcing
our
intention
to
develop
and
implement
a
consultation
process
with
tribal
governments
to
ensure
that
the
concerns
of
tribal
officials
are
considered
before
finalizing
this
proposed
rule.
EPA
specifically
solicits
additional
comment
on
this
proposed
rule
from
tribal
officials.
D.
Executive
Order
13045
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045,
``
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks''
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that
(
1)
is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
we
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonable
alternatives
that
we
considered.
This
proposed
rule
is
not
subject
to
Executive
Order
13045,
because
we
do
not
have
reason
to
believe
the
environmental
health
or
safety
risks
addressed
by
this
action
present
a
disproportionate
risk
to
children.
We
believe
that
this
package
as
a
whole
will
result
in
equal
or
better
environmental
protection
than
currently
provided
by
the
existing
regulations,
and
do
so
in
a
more
streamlined
and
effective
manner.
E.
Paperwork
Reduction
Act
The
EPA
prepared
an
Information
Collection
Request
(
ICR)
document
(
ICR
No.
1713.04).
You
may
obtain
a
copy
from
Sandy
Farmer
by
mail
at
the
U.
S.
Environmental
Protection
Agency,
Office
of
Environmental
Information,
Collection
Strategies
Division
(
2822),
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460
0001,
by
e
mail
at
farmer.
sandy@
epa.
gov,
or
by
calling
(
202)
260
2740.
A
copy
may
also
be
downloaded
from
the
internet
at
http://
www.
epa.
gov/
icr.
The
information
that
ICR
No.
1713.04
covers
is
required
for
EPA
to
carry
out
its
required
oversight
function
of
reviewing
preconstruction
permits
and
assuring
adequate
implementation
of
the
program.
In
order
to
carry
out
its
oversight
function,
EPA
must
have
available
to
it
information
on
proposed
construction
and
modifications.
This
information
collection
is
necessary
for
the
proper
performance
of
EPA's
functions,
has
practical
utility,
and
is
not
unnecessarily
duplicative
of
information
we
otherwise
can
reasonably
access.
We
have
reduced,
to
the
extent
practicable
and
appropriate,
the
burden
on
persons
providing
the
information
to
or
for
EPA.
The
collection
of
information
is
authorized
under
42
U.
S.
C.
7401
et
seq.
According
to
ICR
No.
1713.04,
the
first
3
years
of
this
proposed
rulemaking
will
potentially
incur
a
burden
of
17,400
hours
and
1,305,000
dollars
to
affected
sources,
and
2,906
hours
and
107,522
dollars
for
the
Federal
government,
and
15,680
hours
and
580,160
hours
for
reviewing
authorities.
These
costs
are
based
upon
an
estimated
number
of
1,450
affected
sources.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purpose
of
responding
to
the
information
collection;
adjust
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
respond
to
a
collection
of
information;
search
existing
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
We
will
continue
to
present
OMB
control
numbers
in
a
consolidated
table
format
to
be
codified
in
40
CFR
part
9
of
the
Agency's
regulations,
and
in
each
CFR
volume
containing
EPA
regulations.
The
table
lists
the
section
numbers
with
reporting
and
record
keeping
requirements,
and
the
current
OMB
control
numbers.
This
listing
of
the
OMB
control
numbers
and
their
subsequent
codification
in
the
CFR
satisfy
the
requirements
of
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.)
and
OMB's
implementing
regulations
at
5
CFR
part
1320.
F.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
Any
small
business
employing
fewer
than
500
employees;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
for
profit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
In
determining
whether
a
rule
has
a
significant
economic
impact
on
a
substantial
number
of
small
entities,
the
impact
of
concern
is
any
significant
adverse
economic
impact
on
small
entities,
since
the
primary
purpose
of
the
regulatory
flexibility
analyses
is
to
identify
and
address
regulatory
alternatives
``
which
minimize
any
significant
economic
impact
of
the
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Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
proposed
rule
on
small
entities.''
5
U.
S.
C.
603
and
604.
Thus,
an
agency
may
certify
that
a
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities
if
the
rule
relieves
regulatory
burden,
or
otherwise
has
a
positive
economic
effect
on
all
of
the
small
entities
subject
to
the
rule.
Today's
proposed
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities
because
it
will
decrease
the
regulatory
burden
of
the
existing
regulations
and
have
a
positive
effect
on
all
small
entities
subject
to
the
rule.
This
rule
improves
operational
flexibility
for
owners
and
operators
of
major
stationary
sources
and
clarifies
applicable
requirements
for
determining
if
a
change
qualifies
as
a
major
modification.
We
have
therefore
concluded
that
today's
proposed
rule
will
relieve
regulatory
burden
for
all
small
entities.
We
continue
to
be
interested
in
the
potential
impacts
of
the
proposed
rule
on
small
entities
and
welcome
comments
on
issues
related
to
such
impacts.
G.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
UMRA,
we
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector
of
$
100
million
or
more
in
any
one
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
us
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
us
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
we
establish
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
we
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
our
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
We
believe
the
proposed
rule
changes
will
actually
reduce
the
regulatory
burden
associated
with
the
major
NSR
program
by
improving
the
operational
flexibility
of
owners
and
operators
and
clarifying
the
requirements.
Because
the
program
changes
provided
in
the
proposed
rule
are
not
expected
to
result
in
any
increases
in
the
expenditure
by
State,
local,
and
tribal
governments,
or
the
private
sector,
we
have
not
prepared
a
budgetary
impact
statement
or
specifically
addressed
the
selection
of
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative.
Because
small
governments
will
not
be
significantly
or
uniquely
affected
by
this
rule,
we
are
not
required
to
develop
a
plan
with
regard
to
small
governments.
Therefore,
this
proposed
rule
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.
H.
National
Technology
Transfer
and
Advancement
Act
of
1995
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(
NTTAA),
Public
Law
No.
104
113,
section
12(
d)
(
15
U.
S.
C.
272
note)
directs
us
to
use
voluntary
consensus
standards
(
VCS)
in
our
regulatory
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
VCS
are
technical
standards
(
for
example,
materials
specifications,
test
methods,
sampling
procedures,
and
business
practices)
that
are
developed
or
adopted
by
voluntary
consensus
standards
bodies.
The
NTTAA
directs
us
to
provide
Congress,
through
OMB,
explanations
when
the
Agency
decides
not
to
use
available
and
applicable
VCS.
Although
this
rule
does
involve
the
use
of
technical
standards,
it
does
not
preclude
the
State,
local,
and
tribal
reviewing
agencies
from
using
VCS.
Today's
proposed
rulemaking
is
an
improvement
of
the
existing
NSR
permitting
program.
As
such,
it
only
ensures
that
promulgated
technical
standards
are
considered
and
appropriate
controls
are
installed,
prior
to
the
construction
of
major
sources
of
air
emissions.
Therefore,
we
are
not
considering
the
use
of
any
VCS
in
today's
rulemaking.
I.
Executive
Order
13211
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
proposed
rule
is
not
a
``
significant
energy
action''
as
defined
in
Executive
Order
13211,
``
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(
66
FR
28355
(
May
22,
2001))
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution
or
use
of
energy.
Today's
proposed
rule
improves
the
ability
of
sources
to
maintain
the
reliability
of
production
facilities,
and
effectively
utilize
and
improve
existing
capacity.
X.
Statutory
Authority
The
statutory
authority
for
this
action
is
provided
by
sections
101,
111,
114,
116,
and
301
of
the
CAA
as
amended
(
42
U.
S.
C.
7401,
7411,
7414,
7416,
and
7601).
This
rulemaking
is
also
subject
to
section
307(
d)
of
the
CAA
(
42
U.
S.
C.
7407(
d)).
List
of
Subjects
in
40
CFR
Parts
51
and
52
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.
Dated:
November
22,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
set
out
in
the
preamble,
title
40,
chapter
I
of
the
Code
of
Federal
Regulations
is
proposed
to
be
amended
as
follows:
PART
51
[
AMENDED]
1.
The
authority
citation
for
part
51
continues
to
read
as
follows:
Authority:
23
U.
S.
C.
101;
42
U.
S.
C.
7401
7671q.
Subpart
I
[
Amended]
2.
Section
51.165
is
amended:
a.
By
revising
paragraph
(
a)(
1)(
v)(
C)(
1).
b.
By
adding
paragraphs
(
a)(
1)(
xliii)
through
(
xlvii).
The
revision
and
additions
read
as
follows:
§
51.165
Permit
requirements.
(
a)
*
*
*
(
1)
*
*
*
(
v)
*
*
*
(
C)
*
*
*
(
1)
Routine
maintenance,
repair
and
replacement,
which
shall
include
but
not
be
limited
to
the
activities
set
out
in
paragraphs
(
a)(
1)(
v)(
C)(
1)(
i)
and
(
ii)
of
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
1
EPA
has
not
determined
this
value.
this
section.
Without
regard
to
other
considerations,
the
activities
specified
in
paragraphs
(
a)(
1)(
v)(
C)(
1)(
i)
and
(
ii)
shall
constitute
routine
maintenance,
repair
and
replacement:
(
i)
Activities
performed
at
a
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
whose
total
cost,
when
added
together
with
the
total
costs
of
all
previous
activities
performed
at
the
same
stationary
source
in
the
same
year
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
does
not
exceed
that
stationary
source's
annual
maintenance,
repair
and
replacement
allowance.
``
Annual
maintenance,
repair
and
replacement
allowance''
is
defined
in
paragraph
(
a)(
1)(
xliii)
of
this
section.
Rules
for
calculation
and
summation
of
costs
are
provided
in
paragraph
(
a)(
1)(
xliii)(
A)
of
this
section.
A
stationary
source
may
elect
to
calculate
an
annual
maintenance,
repair
and
replacement
allowance
for
either
all
or
none,
but
not
some,
of
the
maintenance,
repair,
and
replacement
activities
performed
at
the
stationary
source.
(
ii)
The
replacement
of
components
of
a
process
unit
with
identical
or
functionally
equivalent
components,
provided
that:
The
fixed
capital
cost
of
the
components
does
not
exceed
[
x]
1
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
an
entirely
new
process
unit;
and
the
replacement
does
not
change
the
basic
design
parameters
of
the
process
unit.
The
basic
design
parameters
for
electric
utility
steam
generating
units
are
maximum
heat
input
and
fuel
consumption
specifications.
For
nonutilities
basic
design
parameters
are
the
maximum
fuel
or
material
input
specifications
to
the
process
unit.
An
improvement
in
efficiency
does
not
change
a
process
unit's
basic
design
parameters.
``
Functionally
equivalent
components''
and
``
fixed
capital
cost''
are
defined
in
paragraphs
(
a)(
1)(
xlv)
and
(
a)(
1)(
xlvi)
of
this
section,
respectively.
*
*
*
*
*
(
xliii)
Annual
maintenance,
repair
and
replacement
allowance
means
a
dollar
amount
calculated
according
to
the
following
equation:
(
Industry
sector
percentage)
×
(
replacement
cost
of
the
stationary
source)
where
``
industry
sector
percentage''
is
drawn
from
Table
1
of
this
section.
TABLE
1
OF
§
51.165(
A)(
1)(
XLIII).
INDUSTRY
SECTOR
PERCENTAGES
Industry
sector
Industry
sector
percentage
Electric
Services
Petroleum
Refining
Chemical
Processes
Natural
Gas
Transport
Pulp
and
Paper
Mills
Paper
Mills
Automobile
Manufacturing
Pharmaceuticals
Other
(
A)
A
stationary
source's
annual
maintenance
costs
shall
be
calculated
and
summed
according
to
the
following
rules:
(
1)
The
owner
or
operator
may
choose
to
sum
costs
over
either
a
calendar
year
or
initially
specified
fiscal
year.
The
initially
specified
fiscal
year
must
remain
in
use
unless
other
accounting
procedures
at
the
stationary
source
subsequently
change
to
a
different
fiscal
year.
(
2)
Costs
incurred
for
all
activities
performed
at
the
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source
that
are
not
excluded
under
paragraph
(
a)(
1)(
xliii)(
B)
of
this
section,
or
that
have
not
been
issued
a
preconstruction
permit,
shall
be
tracked
chronologically
and
summed
at
the
end
of
the
year.
(
i)
At
the
end
of
the
year,
these
costs
shall
be
listed
and
summed
in
order
from
least
cost
to
highest
cost.
(
ii)
All
activities
prior
to
the
point
on
the
cost
ordered
list
at
which
the
sum
of
activity
costs
exceeds
the
annual
maintenance,
repair
and
replacement
allowance
shall
automatically
qualify
as
routine
maintenance,
repair,
or
replacement.
(
3)
Costs
associated
with
maintaining
or
installing
pollution
control
equipment
shall
not
be
included
in
the
calculation
and
summation
of
costs
for
routine
maintenance,
repair,
and
replacement.
Costs
shall
remain
included
if
they
are
associated
with
maintaining
or
installing
equipment
that
serves
a
dual
function
as
both
process
and
control
equipment.
(
4)
The
owner
or
operator
shall
provide
an
annual
report
to
the
reviewing
authority
containing
complete
information
on
all
maintenance,
repair
and
replacement
costs
and
process
unit
replacement
cost
estimates
at
the
stationary
source.
The
report
shall
be
provided
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
(
B)
An
activity
otherwise
eligible
for
inclusion
in
the
annual
maintenance,
repair
and
replacement
allowance
shall
not
be
eligible
to
be
included
in
the
allowance
if
it:
(
1)
Results
in
an
increase
in
the
maximum
achievable
hourly
emissions
rate
of
the
stationary
source
of
a
regulated
NSR
pollutant,
or
results
in
emissions
of
a
regulated
NSR
pollutant
not
previously
emitted;
(
2)
Constitutes
construction
of
a
new
process
unit;
or
(
3)
Removes
an
entire
existing
process
unit
and
installs
a
different
process
unit
in
its
place.
(
xliv)(
A)
In
general,
process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
stationary
source
may
contain
more
than
one
process
unit.
(
B)
The
following
list
identifies
the
process
units
at
specific
kinds
of
stationary
sources.
(
1)
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
which
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boiler,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
(
2)
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.
(
3)
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
(
4)
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
1
EPA
has
not
determined
this
value.
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
(
5)
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
(
xlv)
Functionally
equivalent
component
means
a
component
that
serves
the
same
purpose
as
the
replaced
component.
(
xlvi)
Fixed
capital
cost
means
the
capital
needed
to
provide
all
the
depreciable
components.
``
Depreciable
components''
refers
to
all
components
of
fixed
capital
cost
and
is
calculated
by
subtracting
land
and
working
capital
from
the
total
capital
investment,
as
defined
in
paragraph
(
a)(
1)(
xlvii)
of
this
section.
(
xlvii)
Total
capital
investment
means
the
sum
of
the
following:
all
costs
required
to
purchase
needed
process
equipment
(
purchased
equipment
costs);
the
costs
of
labor
and
materials
for
installing
that
equipment
(
direct
installation
costs);
the
costs
of
site
preparation
and
buildings;
other
costs
such
as
engineering,
construction
and
field
expenses,
fees
to
contractors,
startup
and
performance
tests,
and
contingencies
(
indirect
installation
costs);
land
for
the
process
equipment;
and
working
capital
for
the
process
equipment.
*
*
*
*
*
3.
Section
51.166
is
amended:
a.
By
revising
paragraph
(
b)(
2)(
iii)(
a).
b.
By
adding
paragraphs
(
b)(
53)
through
(
57).
The
revision
and
additions
read
as
follows:
§
51.166
Prevention
of
significant
deterioration
of
air
quality.
*
*
*
*
*
(
b)
*
*
*
(
2)
*
*
*
(
iii)
*
*
*
(
a)
Routine
maintenance,
repair
and
replacement,
which
shall
include
but
not
be
limited
to
the
activities
set
out
in
paragraphs
(
b)(
2)(
iii)(
a)(
1)
and
(
2)
of
this
section.
Without
regard
to
other
considerations,
the
activities
specified
in
paragraphs
(
b)(
2)(
iii)(
a)(
1)
and
(
2)
shall
constitute
routine
maintenance,
repair
and
replacement:
(
1)
Activities
performed
at
a
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
whose
total
cost,
when
added
together
with
the
total
costs
of
all
previous
activities
performed
at
the
same
stationary
source
in
the
same
year
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
does
not
exceed
that
stationary
source's
annual
maintenance,
repair
and
replacement
allowance.
``
Annual
maintenance,
repair
and
replacement
allowance''
is
defined
in
paragraph
(
b)(
53)
of
this
section.
Rules
for
calculation
and
summation
of
costs
are
provided
in
paragraph
(
b)(
53)(
i)
of
this
section.
A
stationary
source
may
elect
to
calculate
an
annual
maintenance,
repair
and
replacement
allowance
for
either
all
or
none,
but
not
some,
of
the
maintenance,
repair,
and
replacement
activities
performed
at
the
stationary
source.
(
2)
The
replacement
of
components
of
a
process
unit
with
identical
or
functionally
equivalent
components,
provided
that:
(
i)
The
fixed
capital
cost
of
the
components
does
not
exceed
[
x]
1
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
an
entirely
new
process
unit;
and
(
ii)
The
replacement
does
not
change
the
basic
design
parameters
of
the
process
unit.
The
basic
design
parameters
for
electric
utility
steam
generating
units
are
maximum
heat
input
and
fuel
consumption
specifications.
For
non
utilities,
basic
design
parameters
are
the
maximum
fuel
or
material
input
specifications
to
the
process
unit.
An
improvement
in
efficiency
does
not
change
a
process
unit's
basic
design
parameters.
``
Functionally
equivalent
components''
and
``
fixed
capital
cost''
are
defined
in
paragraphs
(
b)(
55)
and
(
b)(
56)
of
this
section.
*
*
*
*
*
(
53)
Annual
maintenance,
repair
and
replacement
allowance
means
a
dollar
amount
calculated
according
to
the
following
equation:
(
Industry
sector
percentage)
×
(
replacement
cost
of
the
stationary
source)
where
``
industry
sector
percentage''
is
drawn
from
Table
1
of
this
section.
TABLE
1
OF
§
51.166(
B)(
53).
INDUSTRY
SECTOR
PERCENTAGES
Industry
sector
Industry
sector
percentage
Electric
Services
Petroleum
Refining
Chemical
Processes
Natural
Gas
Transport
Pulp
and
Paper
Mills
Paper
Mills
Automobile
Manufacturing
Pharmaceuticals
Other
(
i)
A
stationary
source's
annual
maintenance
costs
shall
be
calculated
and
summed
according
to
the
following
rules:
(
a)
The
owner
or
operator
may
choose
to
sum
costs
over
either
a
calendar
year
or
initially
specified
fiscal
year.
The
initially
specified
fiscal
year
must
remain
in
use
unless
other
accounting
procedures
at
the
stationary
source
subsequently
change
to
a
different
fiscal
year.
(
b)
Costs
incurred
for
all
activities
performed
at
the
stationary
source
in
order
to
maintain,
facilitate,
restore,
or
improve
the
efficiency,
reliability,
availability,
or
safety
of
that
stationary
source
that
are
not
excluded
under
paragraph
(
b)(
53)(
ii)
of
this
section,
or
that
have
not
been
issued
a
preconstruction
permit,
shall
be
tracked
chronologically
and
summed
at
the
end
of
the
year.
(
1)
At
the
end
of
the
year,
these
costs
shall
be
listed
and
summed
in
order
from
least
cost
to
highest
cost.
(
2)
All
activities
prior
to
the
point
on
the
cost
ordered
list
at
which
the
sum
of
activity
costs
exceeds
the
annual
maintenance,
repair
and
replacement
allowance
shall
automatically
qualify
as
routine
maintenance,
repair,
or
replacement.
(
c)
Costs
associated
with
maintaining
or
installing
pollution
control
equipment
shall
not
be
included
in
the
calculation
and
summation
of
costs
for
routine
maintenance,
repair,
and
replacement.
Costs
shall
remain
included
if
they
are
associated
with
maintaining
or
installing
equipment
that
serves
a
dual
function
as
both
process
and
control
equipment.
(
d)
The
owner
or
operator
shall
provide
an
annual
report
to
the
reviewing
authority
containing
complete
information
on
all
maintenance,
repair
and
replacement
costs
and
process
unit
replacement
cost
estimates
at
the
stationary
source.
The
report
shall
be
provided
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
(
ii)
An
activity
otherwise
eligible
for
inclusion
in
the
annual
maintenance,
repair
and
replacement
allowance
shall
not
be
eligible
to
be
included
in
the
allowance
if
it:
(
a)
Results
in
an
increase
in
the
maximum
achievable
hourly
emissions
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/
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No.
251
/
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December
31,
2002
/
Proposed
Rules
1
EPA
has
not
determined
this
value.
rate
of
the
stationary
source
of
a
regulated
NSR
pollutant,
or
results
in
emissions
of
a
regulated
NSR
pollutant
not
previously
emitted;
(
b)
Constitutes
construction
of
a
new
process
unit;
or
(
c)
Removes
an
entire
existing
process
unit
and
installs
a
different
process
unit
in
its
place.
(
54)(
i)
In
general,
process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
stationary
source
may
contain
more
than
one
process
unit.
(
ii)
The
following
list
identifies
the
process
units
at
specific
kinds
of
stationary
sources.
(
a)
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
which
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boiler,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
(
b)
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.
(
c)
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
(
d)
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
(
e)
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
(
55)
Functionally
equivalent
component
means
a
component
that
serves
the
same
purpose
as
the
replaced
component.
(
56)
Fixed
capital
cost
means
the
capital
needed
to
provide
all
the
depreciable
components.
``
Depreciable
components''
refers
to
all
components
of
fixed
capital
cost
and
is
calculated
by
subtracting
land
and
working
capital
from
the
total
capital
investment,
as
defined
in
paragraph
(
b)(
57)
of
this
section.
(
57)
Total
capital
investment
means
the
sum
of
the
following:
all
costs
required
to
purchase
needed
process
equipment
(
purchased
equipment
costs);
the
costs
of
labor
and
materials
for
installing
that
equipment
(
direct
installation
costs);
the
costs
of
site
preparation
and
buildings;
other
costs
such
as
engineering,
construction
and
field
expenses,
fees
to
contractors,
startup
and
performance
tests,
and
contingencies
(
indirect
installation
costs);
land
for
the
process
equipment;
and
working
capital
for
the
process
equipment.
*
*
*
*
*
Appendix
S
[
Amended]
4.
In
Appendix
S
to
Part
51
Section
II
is
amended:
a.
By
revising
paragraph
A.
5(
iii)
(
a).
b.
By
adding
paragraphs
A.
21
through
25.
The
revision
and
additions
read
as
follows:
Appendix
S
to
part
51
Emission
Offset
Interpretative
Ruling
*
*
*
*
*
II.
Initial
Screening
Analyses
and
Determination
of
Applicable
Requirements
A.
*
*
*
5.
*
*
*
(
iii)
*
*
*
(
a)
Routine
maintenance,
repair
and
replacement,
which
shall
include
but
not
be
limited
to
the
activities
set
out
in
paragraphs
A.
5
(
iii)(
a)(
1)
and
(
2)
of
this
section.
Without
regard
to
other
considerations,
the
activities
specified
in
paragraphs
A.
5
(
iii)(
a)(
1)
and
(
2)
shall
constitute
routine
maintenance,
repair
and
replacement:
(
1)
Activities
performed
at
a
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
whose
total
cost,
when
added
together
with
the
total
costs
of
all
previous
activities
performed
at
the
same
stationary
source
in
the
same
year
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
does
not
exceed
that
stationary
source's
annual
maintenance,
repair
and
replacement
allowance.
``
Annual
maintenance,
repair
and
replacement
allowance''
is
defined
in
paragraph
A.
21
of
this
section.
Rules
for
calculation
and
summation
of
costs
are
provided
in
paragraph
A.
21
(
i)
of
this
section.
A
stationary
source
may
elect
to
calculate
an
annual
maintenance,
repair
and
replacement
allowance
for
either
all
or
none,
but
not
some,
of
the
maintenance,
repair,
and
replacement
activities
performed
at
the
stationary
source.
(
2)
The
replacement
of
components
of
a
process
unit
with
identical
or
functionally
equivalent
components,
provided
that:
(
i)
The
fixed
capital
cost
of
the
components
does
not
exceed
[
x]
1
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
an
entirely
new
process
unit;
and
(
ii)
The
replacement
does
not
change
the
basic
design
parameters
of
the
process
unit.
The
basic
design
parameters
for
electric
utility
steam
generating
units
are
maximum
heat
input
and
fuel
consumption
specifications.
For
non
utilities,
basic
design
parameters
are
the
maximum
fuel
or
material
input
specifications
to
the
process
unit.
An
improvement
in
efficiency
does
not
change
a
process
unit's
basic
design
parameters.
``
Functionally
equivalent
components''
and
``
fixed
capital
cost''
are
defined
in
paragraphs
A.
23
and
A.
24
of
this
section,
respectively.
*
*
*
*
*
21.
Annual
maintenance,
repair
and
replacement
allowance
means
a
dollar
amount
calculated
according
to
the
following
equation:
(
Industry
sector
percentage)
×
(
replacement
cost
of
the
stationary
source)
where
``
industry
sector
percentage''
is
drawn
from
Table
1
of
this
section.
TABLE
1.
OF
SECTION
II.
A.
21.
INDUSTRY
SECTOR
PERCENTAGES
Industry
sector
Industry
sector
percentage
Electric
Services
Petroleum
Refining
Chemical
Processes
Natural
Gas
Transport
Pulp
and
Paper
Mills
Paper
Mills
Automobile
Manufacturing
Pharmaceuticals
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
TABLE
1.
OF
SECTION
II.
A.
21.
INDUSTRY
SECTOR
PERCENTAGES
Continued
Industry
sector
Industry
sector
percentage
Other
(
i)
A
stationary
source's
annual
maintenance
costs
shall
be
calculated
and
summed
according
to
the
following
rules:
(
a)
The
owner
or
operator
may
choose
to
sum
costs
over
either
a
calendar
year
or
initially
specified
fiscal
year.
The
initially
specified
fiscal
year
must
remain
in
use
unless
other
accounting
procedures
at
the
stationary
source
subsequently
change
to
a
different
fiscal
year.
(
b)
Costs
incurred
for
all
activities
not
performed
at
the
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source
that
are
not
excluded
under
A.
21
(
ii)
of
this
section,
or
that
have
not
been
issued
a
preconstruction
permit,
shall
be
tracked
chronologically
and
summed
at
the
end
of
the
year.
(
1)
At
the
end
of
the
year,
these
costs
shall
be
listed
and
summed
in
order
from
least
cost
to
highest
cost.
(
2)
All
activities
prior
to
the
point
on
the
cost
ordered
list
at
which
the
sum
of
activity
costs
exceeds
the
annual
maintenance,
repair
and
replacement
allowance
shall
automatically
qualify
as
routine
maintenance,
repair,
or
replacement.
(
c)
Costs
associated
with
maintaining
or
installing
pollution
control
equipment
shall
not
be
included
in
the
calculation
and
summation
of
costs
for
routine
maintenance,
repair,
and
replacement.
Costs
shall
remain
included
if
they
are
associated
with
maintaining
or
installing
equipment
that
serves
a
dual
function
as
both
process
and
control
equipment.
(
d)
The
owner
or
operator
shall
provide
an
annual
report
to
the
reviewing
authority
containing
complete
information
on
all
maintenance,
repair
and
replacement
costs
and
process
unit
replacement
cost
estimates
at
the
stationary
source.
The
report
shall
be
provided
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
(
ii)
An
activity
otherwise
eligible
for
inclusion
in
the
annual
maintenance,
repair
and
replacement
allowance
shall
not
be
eligible
to
be
included
in
the
allowance
if
it:
(
a)
Results
in
an
increase
in
the
maximum
achievable
hourly
emissions
rate
of
the
stationary
source
of
a
regulated
NSR
pollutant,
or
results
in
emissions
of
a
regulated
NSR
pollutant
not
previously
emitted;
(
b)
Constitutes
construction
of
a
new
process
unit;
or
(
c)
Removes
an
entire
existing
process
unit
and
installs
a
different
process
unit
in
its
place.
22.
(
i)
In
general,
process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
stationary
source
may
contain
more
than
one
process
unit.
(
ii)
The
following
list
identifies
the
process
units
at
specific
kinds
of
stationary
sources.
(
a)
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
which
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boilers,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
(
b)
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.
(
c)
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
(
d)
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
(
e)
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
23.
Functionally
equivalent
component
means
a
component
that
serves
the
same
purpose
as
the
replaced
component.
24.
Fixed
capital
cost
means
the
capital
needed
to
provide
all
the
depreciable
components.
``
Depreciable
components''
refers
to
all
components
of
fixed
capital
cost
and
is
calculated
by
subtracting
land
and
working
capital
from
the
total
capital
investment,
as
defined
in
paragraph
A.
25
of
this
section.
25.
Total
capital
investment
means
the
sum
of
the
following:
all
costs
required
to
purchase
needed
process
equipment
(
purchased
equipment
costs);
the
costs
of
labor
and
materials
for
installing
that
equipment
(
direct
installation
costs);
the
costs
of
site
preparation
and
buildings;
other
costs
such
as
engineering,
construction
and
field
expenses,
fees
to
contractors,
startup
and
performance
tests,
and
contingencies
(
indirect
installation
costs);
land
for
the
process
equipment;
and
working
capital
for
the
process
equipment.
*
*
*
*
*
PART
52
[
AMENDED]
1.
The
authority
citation
for
part
52
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401,
et
seq.
Subpart
A
[
Amended]
2.
Section
52.21
is
amended:
a.
By
revising
paragraph
(
b)(
2)(
iii)(
a).
b.
By
adding
paragraphs
(
b)(
55)
through
(
59).
The
revision
and
additions
are
revised
to
read
as
follows:
§
52.21
Prevention
of
significant
deterioration
of
air
quality.
*
*
*
*
*
(
b)
*
*
*
(
2)
*
*
*
(
iii)
*
*
*
(
a)
Routine
maintenance,
repair
and
replacement,
which
shall
include
but
not
be
limited
to
the
activities
set
out
in
paragraphs
(
b)(
2)(
iii)(
a)(
1)
and
(
2)
of
this
section.
Without
regard
to
other
considerations,
the
activities
specified
in
paragraphs
(
b)(
2)(
iii)(
a)(
1)
and
(
2)
shall
constitute
routine
maintenance,
repair
and
replacement:
(
1)
Activities
performed
at
a
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
whose
total
cost,
when
added
together
with
the
total
costs
of
all
previous
activities
performed
at
the
same
stationary
source
in
the
same
year
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
does
not
exceed
that
stationary
source's
annual
maintenance,
repair
and
replacement
allowance.
``
Annual
maintenance,
repair
and
replacement
allowance''
is
defined
in
paragraph
(
b)(
55)
of
this
section.
Rules
for
calculation
and
summation
of
costs
are
provided
in
paragraph
(
b)(
55)(
i)
of
this
section.
A
stationary
source
may
elect
to
calculate
an
annual
maintenance,
repair
and
replacement
allowance
for
either
all
or
none,
but
not
some,
of
the
maintenance,
repair,
and
replacement
activities
performed
at
the
stationary
source.
(
2)
The
replacement
of
components
of
a
process
unit
with
identical
or
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/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
1
EPA
has
not
determined
this
value.
functionally
equivalent
components,
provided
that:
(
i)
The
fixed
capital
cost
of
the
components
does
not
exceed
[
x]
1
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
an
entirely
new
process
unit;
and
(
ii)
The
replacement
does
not
change
the
basic
design
parameters
of
the
process
unit.
The
basic
design
parameters
for
electric
utility
steam
generating
units
are
maximum
heat
input
and
fuel
consumption
specifications.
For
non
utilities,
basic
design
parameters
are
the
maximum
fuel
or
material
input
specifications
to
the
process
unit.
An
improvement
in
efficiency
does
not
change
a
process
unit's
basic
design
parameters.
``
Functionally
equivalent
components''
and
``
fixed
capital
cost''
are
defined
in
paragraphs
(
b)(
57)
and
(
b)(
58)
of
this
section.
*
*
*
*
*
(
55)
Annual
maintenance,
repair
and
replacement
allowance
means
a
dollar
amount
calculated
according
to
the
following
equation:
(
Industry
sector
percentage)
x
(
replacement
cost
of
the
stationary
source)
where
``
industry
sector
percentage''
is
drawn
from
Table
1
of
this
section.
TABLE
1
OF
§
52.21(
B)(
55).
INDUSTRY
SECTOR
PERCENTAGES
Industry
sector
Industry
sector
percentage
Electric
Services
Petroleum
Refining
Chemical
Processes
Natural
Gas
Transport
Pulp
and
Paper
Mills
Paper
Mills
Automobile
Manufacturing
Pharmaceuticals
Other
(
i)
A
stationary
source's
annual
maintenance
costs
shall
be
calculated
and
summed
according
to
the
following
rules:
(
a)
The
owner
or
operator
may
choose
to
sum
costs
over
either
a
calendar
year
or
initially
specified
fiscal
year.
The
initially
specified
fiscal
year
must
remain
in
use
unless
other
accounting
procedures
at
the
stationary
source
subsequently
change
to
a
different
fiscal
year.
(
b)
Costs
incurred
for
all
activities
not
performed
at
the
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source
that
are
not
excluded
under
paragraph
(
b)(
55)(
ii)
of
this
section,
or
that
have
not
been
issued
a
preconstruction
permit,
shall
be
tracked
chronologically
and
summed
at
the
end
of
the
year.
(
1)
At
the
end
of
the
year,
these
costs
shall
be
listed
and
summed
in
order
from
least
cost
to
highest
cost.
(
2)
All
activities
prior
to
the
point
on
the
cost
ordered
list
at
which
the
sum
of
activity
costs
exceeds
the
annual
maintenance,
repair
and
replacement
allowance
shall
automatically
qualify
as
routine
maintenance,
repair,
or
replacement.
(
c)
Costs
associated
with
maintaining
or
installing
pollution
control
equipment
shall
not
be
included
in
the
calculation
and
summation
of
costs
for
routine
maintenance,
repair,
and
replacement.
Costs
shall
remain
included
if
they
are
associated
with
maintaining
or
installing
equipment
that
serves
a
dual
function
as
both
process
and
control
equipment.
(
d)
The
owner
or
operator
shall
provide
an
annual
report
to
the
reviewing
authority
containing
complete
information
on
all
maintenance,
repair
and
replacement
costs
and
process
unit
replacement
cost
estimates
at
the
stationary
source.
The
report
shall
be
provided
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
(
ii)
An
activity
otherwise
eligible
for
inclusion
in
the
annual
maintenance,
repair
and
replacement
allowance
shall
not
be
eligible
to
be
included
in
the
allowance
if
it:
(
a)
Results
in
an
increase
in
the
maximum
achievable
hourly
emissions
rate
of
the
stationary
source
of
a
regulated
NSR
pollutant,
or
results
in
emissions
of
a
regulated
NSR
pollutant
not
previously
emitted;
(
b)
Constitutes
construction
of
a
new
process
unit;
or
(
c)
Removes
an
entire
existing
process
unit
and
installs
a
different
process
unit
in
its
place.
(
56)
(
i)
In
general,
process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
stationary
source
may
contain
more
than
one
process
unit.
(
ii)
The
following
list
identifies
the
process
units
at
specific
kinds
of
stationary
sources.
(
a)
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
which
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boiler,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
(
b)
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.
(
c)
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
(
d)
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
(
e)
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
(
57)
Functionally
equivalent
component
means
a
component
that
serves
the
same
purpose
as
the
replaced
component.
(
58)
Fixed
capital
cost
means
the
capital
needed
to
provide
all
the
depreciable
components.
``
Depreciable
components''
refers
to
all
components
of
fixed
capital
cost
and
is
calculated
by
subtracting
land
and
working
capital
from
the
total
capital
investment,
as
defined
in
paragraph
(
b)(
59)
of
this
section.
(
59)
Total
capital
investment
means
the
sum
of
the
following:
all
costs
required
to
purchase
needed
process
equipment
(
purchased
equipment
costs);
the
costs
of
labor
and
materials
for
installing
that
equipment
(
direct
installation
costs);
the
costs
of
site
preparation
and
buildings;
other
costs
such
as
engineering,
construction
and
field
expenses,
fees
to
contractors,
startup
and
performance
tests,
and
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Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
1
EPA
has
not
determined
this
value.
contingencies
(
indirect
installation
costs);
land
for
the
process
equipment;
and
working
capital
for
the
process
equipment.
*
*
*
*
*
3.
Section
52.24
is
amended:
a.
By
revising
paragraph
(
f)(
5)(
iii)(
a).
b.
By
adding
paragraphs
(
f)(
25)
through
(
29).
The
revision
and
additions
read
as
follows:
§
52.24
Statutory
restriction
on
new
sources.
*
*
*
*
*
(
f)
*
*
*
(
5)
*
*
*
(
iii)
*
*
*
(
a)
Routine
maintenance,
repair
and
replacement,
which
shall
include
but
not
be
limited
to
the
activities
set
out
in
paragraphs
(
f)(
5)(
iii)(
a)(
1)
and
(
2)
of
this
section.
Without
regard
to
other
considerations,
the
activities
specified
in
paragraphs
(
f)(
5)(
iii)(
a)(
1)
and
(
2)
shall
constitute
routine
maintenance,
repair
and
replacement:
(
1)
Activities
performed
at
a
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
whose
total
cost,
when
added
together
with
the
total
costs
of
all
previous
activities
performed
at
the
same
stationary
source
in
the
same
year
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source,
does
not
exceed
that
stationary
source's
annual
maintenance,
repair
and
replacement
allowance.
``
Annual
maintenance,
repair
and
replacement
allowance''
is
defined
in
paragraph
(
f)(
25)
of
this
section.
Rules
for
calculation
and
summation
of
costs
are
provided
in
paragraph
(
f)(
25)(
i)
of
this
section.
A
stationary
source
may
elect
to
calculate
an
annual
maintenance,
repair
and
replacement
allowance
for
either
all
or
none,
but
not
some,
of
the
maintenance,
repair,
and
replacement
activities
performed
at
the
stationary
source.
(
2)
The
replacement
of
components
of
a
process
unit
with
identical
or
functionally
equivalent
components,
provided
that:
(
i)
The
fixed
capital
cost
of
the
components
does
not
exceed
[
x]
1
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
an
entirely
new
process
unit;
and
(
ii)
The
replacement
does
not
change
the
basic
design
parameters
of
the
process
unit.
The
basic
design
parameters
for
electric
utility
steam
generating
units
are
maximum
heat
input
and
fuel
consumption
specifications.
For
non
utilities,
basic
design
parameters
are
the
maximum
fuel
or
material
input
specifications
to
the
process
unit.
An
improvement
in
efficiency
does
not
change
a
process
unit's
basic
design
parameters.
``
Functionally
equivalent
components''
and
``
fixed
capital
cost''
are
defined
in
paragraphs
(
f)(
27)
and
(
f)(
28)
of
this
section,
respectively.
*
*
*
*
*
(
25)
Annual
maintenance,
repair
and
replacement
allowance
means
a
dollar
amount
calculated
according
to
the
following
equation:
(
Industry
sector
percentage)
x
(
replacement
cost
of
the
stationary
source)
where
``
industry
sector
percentage''
is
drawn
from
Table
1
of
this
section.
TABLE
1
OF
§
52.24(
F)(
25).
INDUSTRY
SECTOR
PERCENTAGES
Industry
sector
Industry
sector
percentage
Electric
Services
Petroleum
Refining
Chemical
Processes
Natural
Gas
Transport
Pulp
and
Paper
Mills
Paper
Mills
Automobile
Manufacturing
Pharmaceuticals
Other
(
i)
A
stationary
source's
annual
maintenance
costs
shall
be
calculated
and
summed
according
to
the
following
rules:
(
a)
The
owner
or
operator
may
choose
to
sum
costs
over
either
a
calendar
year
or
initially
specified
fiscal
year.
The
initially
specified
fiscal
year
must
remain
in
use
unless
other
accounting
procedures
at
the
stationary
source
subsequently
change
to
a
different
fiscal
year.
(
b)
Costs
incurred
for
all
activities
not
performed
at
the
stationary
source
in
order
to
maintain,
facilitate,
restore
or
improve
the
efficiency,
reliability,
availability
or
safety
of
that
stationary
source
that
are
not
excluded
under
paragraph
(
f)(
25)(
ii)
of
this
section,
or
that
have
not
been
issued
a
preconstruction
permit,
shall
be
tracked
chronologically
and
summed
at
the
end
of
the
year.
(
1)
At
the
end
of
the
year,
these
costs
shall
be
listed
and
summed
in
order
from
least
cost
to
highest
cost.
(
2)
All
activities
prior
to
the
point
on
the
cost
ordered
list
at
which
the
sum
of
activity
costs
exceeds
the
annual
maintenance,
repair
and
replacement
allowance
shall
automatically
qualify
as
routine
maintenance,
repair,
or
replacement.
(
c)
Costs
associated
with
maintaining
or
installing
pollution
control
equipment
shall
not
be
included
in
the
calculation
and
summation
of
costs
for
routine
maintenance,
repair,
and
replacement.
Costs
shall
remain
included
if
they
are
associated
with
maintaining
or
installing
equipment
that
serves
a
dual
function
as
both
process
and
control
equipment.
(
d)
The
owner
or
operator
shall
provide
an
annual
report
to
the
reviewing
authority
containing
complete
information
on
all
maintenance,
repair
and
replacement
costs
and
process
unit
replacement
cost
estimates
at
the
stationary
source.
The
report
shall
be
provided
within
60
days
after
the
end
of
the
year
over
which
activity
costs
have
been
summed.
(
ii)
An
activity
otherwise
eligible
for
inclusion
in
the
annual
maintenance,
repair
and
replacement
allowance
shall
not
be
eligible
to
be
included
in
the
allowance
if
it:
(
a)
Results
in
an
increase
in
the
maximum
achievable
hourly
emissions
rate
of
the
stationary
source
of
a
regulated
NSR
pollutant,
or
results
in
emissions
of
a
regulated
NSR
pollutant
not
previously
emitted;
(
b)
Constitutes
construction
of
a
new
process
unit;
or
(
c)
Removes
an
entire
existing
process
unit
and
installs
a
different
process
unit
in
its
place.
(
26)
(
i)
In
general,
process
unit
means
any
collection
of
structures
and/
or
equipment
that
processes,
assembles,
applies,
blends,
or
otherwise
uses
material
inputs
to
produce
or
store
a
completed
product.
A
single
stationary
source
may
contain
more
than
one
process
unit.
(
ii)
The
following
list
identifies
the
process
units
at
specific
kinds
of
stationary
sources.
(
a)
For
a
steam
electric
generating
facility,
the
process
unit
would
consist
of
those
portions
of
the
plant
which
contribute
directly
to
the
production
of
electricity.
For
example,
at
a
pulverized
coal
fired
facility,
the
process
unit
would
generally
be
the
combination
of
those
systems
from
the
coal
receiving
equipment
through
the
emission
stack,
including
the
coal
handling
equipment,
pulverizers
or
coal
crushers,
feedwater
heaters,
boiler,
burners,
turbinegenerator
set,
air
preheaters,
and
operating
control
systems.
Each
separate
generating
unit
would
be
considered
a
separate
process
unit.
Components
shared
between
two
or
more
process
units
would
be
proportionately
allocated
based
on
capacity.
(
b)
For
a
petroleum
refinery,
there
are
several
categories
of
process
units:
those
that
separate
and
distill
petroleum
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Register
/
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67,
No.
251
/
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December
31,
2002
/
Proposed
Rules
feedstocks;
those
that
change
molecular
structures;
petroleum
treating
processes;
auxiliary
facilities,
such
as
boilers
and
hydrogen
production;
and
those
that
load,
unload,
blend
or
store
products.
(
c)
For
a
cement
plant,
the
process
unit
would
generally
consist
of
the
kiln
and
equipment
that
supports
it,
including
all
components
that
process
or
store
raw
materials,
preheaters,
and
components
that
process
or
store
products
from
the
kilns,
and
associated
emission
stacks.
(
d)
For
a
pulp
and
paper
mill,
there
are
several
types
of
process
units.
One
is
the
system
that
processes
wood
products,
another
is
the
digester
and
its
associated
heat
exchanger,
blow
tank,
pulp
filter,
accumulator,
oxidation
tower,
and
evaporators.
A
third
is
the
chemical
recovery
system,
which
includes
the
recovery
furnace,
lime
kiln,
storage
vessels,
and
associated
oxidation
processes
feeding
regenerated
chemicals
to
the
digester.
(
e)
For
an
incinerator,
the
process
unit
would
consist
of
components
from
the
feed
pit
or
refuse
pit
to
the
stack,
including
conveyors,
combustion
devices,
heat
exchangers
and
steam
generators,
quench
tanks,
and
fans.
(
27)
Functionally
equivalent
component
means
a
component
that
serves
the
same
purpose
as
the
replaced
component.
(
28)
Fixed
capital
cost
means
the
capital
needed
to
provide
all
the
depreciable
components.
``
Depreciable
components''
refers
to
all
components
of
fixed
capital
cost
and
is
calculated
by
subtracting
land
and
working
capital
from
the
total
capital
investment,
as
defined
in
paragraph
(
f)(
29)
of
this
section.
(
29)
Total
capital
investment
means
the
sum
of
the
following:
all
costs
required
to
purchase
needed
process
equipment
(
purchased
equipment
costs);
the
costs
of
labor
and
materials
for
installing
that
equipment
(
direct
installation
costs);
the
costs
of
site
preparation
and
buildings;
other
costs
such
as
engineering,
construction
and
field
expenses,
fees
to
contractors,
startup
and
performance
tests,
and
contingencies
(
indirect
installation
costs);
land
for
the
process
equipment;
and
working
capital
for
the
process
equipment.
*
*
*
*
*
[
FR
Doc.
02
31900
Filed
12
30
02;
8:
45
am]
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| epa | 2024-06-07T20:31:40.537586 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0068-0086/content.txt"
} |
EPA-HQ-OAR-2002-0069-0001 | Proposed Rule | "2002-11-25T05:00:00" | Federal Plan Requirements for Commercial and Industrial Solid Waste Incinerators Constructed on or Before November 30, 1999; Proposed Rule | Monday,
November
25,
2002
Part
II
Environmental
Protection
Agency
40
CFR
Part
62
Federal
Plan
Requirements
for
Commercial
and
Industrial
Solid
Waste
Incinerators
Constructed
on
or
Before
November
30,
1999;
Proposed
Rule
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No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
62
[
AD
FRL
7408
1]
RIN
2060
AJ28
Federal
Plan
Requirements
for
Commercial
and
Industrial
Solid
Waste
Incinerators
Constructed
on
or
Before
November
30,
1999
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Proposed
rule.
SUMMARY:
On
December
1,
2000,
EPA
adopted
emission
guidelines
for
existing
commercial
and
industrial
solid
waste
incineration
(
CISWI)
units.
Sections
111
and
129
of
the
Clean
Air
Act
(
CAA)
require
States
with
existing
CISWI
units
subject
to
the
emission
guidelines
to
submit
plans
to
EPA
that
implement
and
enforce
the
emission
guidelines.
Indian
Tribes
may
submit,
but
are
not
required
to
submit,
Tribal
plans
to
implement
and
enforce
the
emission
guidelines
in
Indian
country.
State
plans
are
due
from
States
with
CISWI
units
subject
to
the
emission
guidelines
on
December
1,
2001.
If
a
State
or
Tribe
with
existing
CISWI
units
does
not
submit
an
approvable
plan,
sections
111(
d)
and
129
of
the
CAA
require
EPA
to
develop,
implement,
and
enforce
a
Federal
plan
for
CISWI
units
located
in
that
State
or
Tribal
area
within
2
years
after
promulgation
of
the
emission
guidelines
(
December
1,
2002).
This
action
proposes
a
Federal
plan
to
implement
emission
guidelines
for
CISWI
units
located
in
States
and
Indian
country
without
effective
State
or
Tribal
plans.
On
the
effective
date
of
an
approved
State
or
Tribal
plan,
the
Federal
plan
would
no
longer
apply
to
CISWI
units
covered
by
the
State
or
Tribal
plan.
DATES:
Comments.
Comments
on
the
proposed
CISWI
Federal
plan
must
be
received
on
or
before
January
24,
2003.
Public
hearing.
The
EPA
will
hold
a
public
hearing
if
requests
to
speak
are
received
by
December
10,
2002.
For
additional
information
on
the
public
hearing
and
requesting
to
speak,
see
the
Supplementary
Information
section
of
this
preamble.
If
requested,
the
hearing
would
take
place
on
December
30,
2002
and
would
begin
at
10
a.
m.
ADDRESSES:
Comments.
Submit
written
comments
(
in
duplicate,
if
possible)
to
the
following
address:
Air
and
Radiation
Docket
and
Information
Center
(
MC
6102T)
,
U.
S.
Environmental
Protection
Agency,
1200
Pennsylvania
Avenue,
NW,
Washington,
D.
C.
20460,
Attention
Docket
No.
A
2000
52.
The
EPA
requests
that
a
separate
copy
also
be
sent
to
the
contact
person
listed
below.
For
additional
information
on
the
docket
and
electronic
availability,
see
Supplementary
Information.
Public
hearing.
If
timely
requests
to
speak
at
a
public
hearing
are
received,
a
public
hearing
will
be
held
at
EPA's
New
RTP
Campus
located
at
109
T.
W.
Alexander
Drive
in
Research
Triangle
Park,
NC.
Were
one
to
be
held,
a
hearing
would
be
held
in
the
auditorium
of
the
main
facility.
FOR
FURTHER
INFORMATION
CONTACT:
For
information
concerning
specific
aspects
of
this
proposal,
contact
Mr.
David
Painter
at
(
919)
541
5515,
Program
Implementation
and
Review
Group,
Information
Transfer
and
Program
Integration
Division
(
E143
02),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
North
Carolina
27711,
email:
painter.
david@
epa.
gov.
For
technical
information,
contact
Mr.
Fred
Porter
at
(
919)
541
5251,
Combustion
Group,
Emission
Standards
Division
(
C439
01),
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
N.
C.
27711,
email:
porter.
fred@
epa.
gov.
For
information
regarding
implementation
of
this
proposed
rule,
contact
the
appropriate
Regional
Office
(
table
1)
as
shown
in
Supplementary
Information.
SUPPLEMENTARY
INFORMATION:
Comment
Information.
Comments
may
be
submitted
electronically
via
electronic
mail
(
e
mail)
or
on
disk.
Electronic
comments
on
this
proposed
rule
may
be
filed
via
e
mail
at
most
Federal
Depository
Libraries.
E
mail
submittals
should
be
sent
to:
``
A
and
RDocket
epa.
gov''.
Electronic
comments
must
be
submitted
as
an
American
Standard
Code
for
Information
Interchange
(
ASCII)
file
avoiding
the
use
of
special
characters
or
encryption.
Comments
and
data
will
also
be
accepted
on
disks
or
as
an
e
mail
attachment
in
WordPerfect
or
Corel
``
wpd''
file
format,
Microsoft
Word
format,
or
ASCII
file
format.
All
comments
and
data
for
this
proposed
rule,
whether
in
paper
form
or
electronic
forms
such
as
through
e
mail
or
on
diskette,
must
be
identified
by
docket
number
A
2000
52.
Persons
wishing
to
submit
proprietary
information
for
consideration
must
clearly
distinguish
such
information
from
other
comments
by
clearly
labeling
it
``
Confidential
Business
Information''
(
CBI).
To
ensure
that
proprietary
information
is
not
inadvertently
placed
in
the
docket,
submit
CBI
directly
to
the
following
address,
and
not
the
public
docket:
Mr.
Roberto
Morales,
OAQPS
Document
Control
Officer,
411
W.
Chapel
Hill
Street,
Room
740B,
Durham,
North
Carolina
27701.
Information
covered
by
such
a
claim
of
confidentiality
will
be
disclosed
by
the
EPA
only
to
the
extent
allowed
and
by
the
procedures
set
forth
in
40
CFR
part
2.
If
no
claim
of
confidentiality
is
made
with
the
submission,
the
submission
may
be
made
available
to
the
public
without
further
notice.
No
confidential
business
information
should
be
submitted
through
e
mail.
Public
hearing
information.
Persons
wishing
to
speak
at
a
public
hearing
should
notify
Ms.
Christine
Adams
at
(
919)
541
5590.
If
a
public
hearing
is
requested
and
held,
EPA
will
ask
clarifying
questions
during
the
oral
presentation
but
will
not
respond
to
the
presentations
or
comments.
Written
statements
and
supporting
information
will
be
considered
with
equivalent
weight
as
any
oral
statement
and
supporting
information
subsequently
presented
at
a
public
hearing,
if
held.
Related
information.
Electronic
versions
of
this
notice,
the
proposed
regulatory
text,
and
other
background
information
are
available
at
the
World
Wide
Web
site
that
EPA
has
established
for
CISWI
units.
The
address
is
http://
www.
epa.
gov/
ttn/
atw/
129/
ciwi/
ciwipg.
html.
The
CISWI
website
references
other
websites
for
closely
related
rules,
such
as
large
and
small
municipal
waste
combustors
(
MWC),
hazardous
waste,
and
hospital/
medical/
infectious
waste
incinerators
(
HMIWI).
The
large
MWC
and
HMIWI
sites
contain
the
respective
State
plan
guidance
documents.
Docket.
Docket
numbers
A
2000
52
and
A
94
63
contain
the
supporting
information
for
this
proposed
rule
and
the
supporting
information
for
EPA's
promulgation
of
emission
guidelines
for
existing
CISWI
units,
respectively.
Docket
A
2000
52
incorporates
all
of
the
information
in
Docket
A
94
63.
The
dockets
are
organized
and
complete
files
of
all
the
information
submitted
to
or
otherwise
considered
by
EPA
in
the
development
of
this
proposed
rulemaking.
The
dockets
are
available
for
public
inspection
and
copying
between
8:
30
a.
m.
and
4:
30
p.
m.,
Monday
through
Friday,
at
the
OAR
Docket
in
the
EPA
Docket
Center
(
EPA/
DC),
1301
Constitution
Avenue,
NW.,
Washington,
DC
20460,
or
by
calling
(
202)
566
1744.
The
docket
is
located
in
Room
B102,
(
basement
of
EPA
West
Building).
The
fax
number
for
the
Center
is
(
202)
566
1749
and
the
E
mail
address
is
http://
www.
epa.
gov/
edocket.
A
reasonable
fee
may
be
charged
for
copying.
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/
Vol.
67,
No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
Regulated
entities.
The
proposed
Federal
plan
would
affect
the
following
North
American
Industrial
Classification
System
(
NAICS)
and
Standard
Industrial
Classification
(
SIC)
codes:
Category
NAICS
Code
SIC
Code
Examples
of
potentially
regulated
entities
Any
industry
using
a
solid
waste
incinerator
as
defined
in
the
regulations.
325
28
Manufacturers
of
chemicals
and
allied
products.
325
34
Manufacturers
of
electronic
equipment.
421
36
Manufacturers
of
wholesale
trade,
durable
goods.
321,
337
24,
25
Manufacturers
of
lumber
and
wood
furniture.
This
list
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
EPA
expects
to
be
regulated
by
this
proposed
rule.
This
table
lists
examples
of
the
types
of
entities
that
could
be
affected
by
this
proposed
rule.
Other
types
of
entities
not
listed
could
also
be
affected.
To
determine
whether
your
facility,
company,
business
organization,
etc.,
is
regulated
by
this
action,
carefully
examine
the
applicability
criteria
in
40
CFR
62.14510
through
62.14530
of
subpart
III.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
your
solid
waste
incineration
unit,
refer
to
the
FOR
FURTHER
INFORMATION
CONTACT
section.
EPA
Regional
Office
Contacts.
Table
1
lists
EPA
Regional
Offices
that
can
answer
questions
regarding
implementation
of
this
proposed
rule.
TABLE
1.
EPA
REGIONAL
CONTACTS
FOR
CISWI
Region
Contact
Phone/
Fax
States
and
Protectorates
I
...........
EPA
New
England
Director,
Air
Compliance
Program,
1
Congress
Street,
Suite
1100
(
SEA),
Boston,
MA
02114
2023.
617
918
1650,
617
918
1505
(
fax).
CT,
ME,
MA,
NH,
RI,
VT
II
..........
U.
S.
EPA
Region
2,
Air
Compliance
Branch,
290
Broadway,
New
York,
New
York
10007.
212
637
4080,
212
637
3998
(
fax).
NJ,
NY,
Puerto
Rico,
Virgin
Islands
III
.........
U.
S.
EPA
Region
3,
Chief,
Air
Enforcement
Branch
(
3AP12),
1650
Arch
Street,
Philadelphia,
PA
19103
2029.
215
814
3438,
215
814
2134
(
fax).
DE,
DC,
MD,
PA,
VA,
WV
IV
.........
U.
S.
EPA
Region
4,
Air
and
Radiation,
Technology
Branch,
Atlanta
Federal
Center,
61
Forsyth
Street,
Atlanta,
Georgia
30303
3104.
404
562
9105,
404
562
9095
(
fax).
AL,
FL,
GA,
KY,
MS,
NC,
SC,
TN
V
..........
U.
S.
EPA
Region
5,
Air
Enforcement
and
Compliance
Assurance
Branch,
(
AR
18J),
77
West
Jackson
Boulevard,
Chicago
IL
60604
3590.
312
353
2211,
312
886
8289
(
fax).
IL,
IN,
MN,
OH,
WI
VI
.........
U.
S.
EPA
Region
6,
Chief,
Toxics
Enforcement,
Section
(
6EN
AT),
1445
Ross
Avenue,
Dallas,
TX
75202
2733.
214
665
7224,
214
665
7446
(
fax).
AR,
LA,
NM,
OK,
TX
VII
........
U.
S.
EPA
Region
7,
901
N.
5th
Street,
Kansas
City,
KS
66101
913
551
7020,
913
551
7844
(
fax).
IA,
KS,
MO,
NE
VIII
.......
U.
S.
EPA
Region
8,
Air
Program
Technical
Unit,
(
Mail
Code
8P
AR),
999
18th
Street
Suite
500,
Denver,
CO
80202.
303
312
6007,
303
312
6064
(
fax).
CO,
MT,
ND,
SD,
UT,
WY
IX
.........
U.
S.
EPA
Region
9,
Air
Division,
75
Hawthorne
Street,
San
Francisco,
CA
94105.
415
744
1219,
415
744
1076
(
fax).
AZ,
CA,
HI,
NV,
American
Samoa,
Guam
X
..........
U.
S.
EPA
Region
10,
Office
of
Air
Quality,
1200
Sixth
Avenue,
Seattle,
WA
98101.
(
206)
553
4273,
(
206)
553
0110
(
fax).
Organization
of
this
document.
The
following
outline
is
provided
to
aid
in
locating
information
in
this
preamble.
I.
Background
Information
A.
What
is
the
Regulatory
Development
Background
for
this
Proposed
Rule?
B.
What
Impact
Does
the
U.
S.
Appeals
Court
Remand
and
EPA's
Granting
of
a
Request
for
Reconsideration
Have
on
this
Federal
Plan?
II.
Affected
Facilities
A.
What
Is
a
CISWI
Unit?
B.
Does
The
Federal
Plan
Apply
to
Me?
C.
How
Do
I
Determine
If
My
CISWI
Unit
Is
Covered
by
an
Approved
and
Effective
State
or
Tribal
Plan?
III.
Elements
of
the
CISWI
Federal
Plan
A.
Legal
Authority
and
Enforcement
Mechanism
B.
Inventory
of
Affected
CISWI
Units
C.
Inventory
of
Emissions
D.
Emission
Limitations
E.
Compliance
Schedules
F.
Waste
Management
Plan
Requirements
G.
Testing,
Monitoring,
Recordkeeping,
and
Reporting
H.
Operator
Training
and
Qualification
Requirements
I.
Record
of
Public
Hearings
J.
Progress
Reports
IV.
Summary
of
CISWI
Federal
Plan
A.
What
Emission
Limitations
Must
I
Meet?
B.
What
Operating
Limits
Must
I
Meet?
C.
What
are
the
Requirements
for
Air
Curtain
Incinerators?
D.
What
are
the
Testing,
Monitoring,
Inspection,
Recordkeeping,
and
Reporting
Requirements?
E.
What
is
the
Compliance
Schedule?
F.
How
Did
EPA
Determine
the
Compliance
Schedule?
V.
CISWI
That
Have
or
Will
Shut
Down
A.
Units
That
Plan
to
Close
Rather
Than
Comply
B.
Inoperable
Units
C.
CISWI
Units
That
Have
Shut
Down
VI.
Implementation
of
the
Federal
Plan
and
Delegation
A.
Background
of
Authority
B.
Delegation
of
the
Federal
Plan
and
Retained
Authorities
C.
Mechanisms
for
Transferring
Authority
D.
Implementing
Authority
E.
CISWI
Federal
Plan
and
Indian
County
VII.
Title
V
Operating
Permits
VIII.
Administrative
Requirements
A.
Docket
B.
Public
Hearing
C.
Executive
Order
12866:
Regulatory
Planning
and
Review
D.
Executive
Order
13132:
Federalism
E.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
F.
Executive
Order
13045:
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
G.
Executive
Order
13211:
Energy
Effects
H.
Unfunded
Mandates
Reform
Act
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/
Monday,
November
25,
2002
/
Proposed
Rules
1
Similarly,
the
obligations
of
States
and
sources
are
unaffected
by
the
reconsideration
petition
and
the
remand.
I.
Regulatory
Flexibility
Act/
Small
Business
Regulatory
Enforcement
Fairness
Act
(
SBREFA)
J.
Paperwork
Reduction
Act
K.
National
Technology
Transfer
and
Advancement
Act
I.
Background
Information
A.
What
Is
the
Regulatory
Development
Background
for
This
Proposed
Rule?
Section
129
of
the
CAA
requires
EPA
to
develop
emission
guidelines
for
existing
``
solid
waste
incineration
units
combusting
commercial
or
industrial
waste.''
The
EPA
refers
to
these
units
as
``
commercial
and
industrial
solid
waste
incineration''
(
CISWI)
units.
The
EPA
proposed
emission
guidelines
for
CISWI
units
on
November
30,
1999
and
promulgated
them
on
December
1,
2000
(
65
FR
75338)
(
to
be
codified
at
40
CFR
part
60,
subpart
DDDD).
In
writing
Section
129
of
the
Clean
Air
Act,
Congress
looked
first
to
the
States
as
the
preferred
implementers
of
emission
guidelines
for
existing
CISWI
units.
To
make
these
emission
guidelines
enforceable,
States
with
existing
CISWI
units
must
have
submitted
to
EPA
within
one
year
following
promulgation
of
the
emission
guidelines
(
by
December
1,
2001)
State
plans
that
implement
and
enforce
the
emission
guidelines.
For
States
or
Tribes
that
do
not
have
an
EPA
approved
and
effective
plan,
EPA
must
develop
and
implement
a
Federal
plan
within
two
years
following
promulgation
of
the
emission
guidelines
(
by
December
1,
2002).
The
EPA
sees
the
Federal
plan
as
an
interim
measure
to
ensure
that
Congressionally
mandated
emission
standards
are
implemented
until
States
assume
their
role
as
the
preferred
implementers
of
the
emissions
guidelines.
Thus,
the
EPA
encourages
States
to
either
use
the
Federal
plan
as
a
template
to
reduce
the
effort
needed
to
develop
their
own
plans
or
to
simply
take
delegation
to
directly
implement
and
enforce
the
guidelines.
States
without
any
existing
CISWI
units
are
required
to
submit
to
the
Administrator
a
letter
of
negative
declaration
certifying
that
there
are
no
CISWI
units
in
the
State.
No
plan
is
required
for
States
that
do
not
have
any
CISWI
units.
As
discussed
in
section
VI.
E
of
this
preamble,
Indian
Tribes
may,
but
are
not
required
to,
submit
Tribal
plans
to
cover
CISWI
units
in
Indian
country.
A
Tribe
may
submit
to
the
Administrator
a
letter
of
negative
declaration
certifying
that
no
CISWI
units
are
located
in
the
Tribal
area.
No
plan
is
required
for
Tribes
that
do
not
have
any
CISWI
units.
CISWI
units
located
in
States
or
Tribal
areas
that
mistakenly
submit
a
letter
of
negative
declaration
would
be
subject
to
the
Federal
plan
until
a
State
or
Tribal
plan
has
been
approved
and
becomes
effective
covering
those
CISWI
units.
Today's
action
proposes
a
Federal
plan
for
CISWI
units
that
are
not
covered
by
an
approved
State
or
Tribal
plan
as
of
December
1,
2002.
Sections
111
and
129
of
the
CAA
and
40
CFR
60.27(
c)
and
(
d)
require
EPA
to
develop,
implement,
and
enforce
a
Federal
plan
to
cover
existing
CISWI
units
located
in
States
that
do
not
have
an
approved
plan
within
two
years
after
promulgation
of
the
emission
guidelines
(
by
December
1,
2002
for
CISWI
units).
The
EPA
is
proposing
this
Federal
plan
now
so
that
a
promulgated
Federal
plan
will
be
in
place
at
the
earliest
possible
date,
thus
ensuring
timely
implementation
and
enforcement
of
the
CISWI
emission
guidelines.
In
addition,
EPA's
timing
allows
a
State
or
Tribe
the
opportunity
to
take
delegation
of
the
Federal
plan
in
lieu
of
writing
a
State
plan.
B.
What
Impact
Does
the
U.
S.
Appeals
Court
Remand
and
EPA's
Granting
of
a
Request
for
Reconsideration
Have
on
This
Federal
Plan?
Subsequent
to
EPA's
promulgation
of
the
final
rule
establishing
the
NSPS
and
EG
for
CISWI
units,
two
events
occurred
that
potentially
could
result
in
substantive
changes
to
these
standards.
First,
in
August
2001
EPA
granted
a
request
for
reconsideration,
pursuant
to
section
307(
d)(
7)(
B)
of
the
CAA,
submitted
on
behalf
of
the
National
Wildlife
Federation
and
the
Louisiana
Environmental
Action
Network,
related
to
the
definition
of
``
commercial
and
industrial
solid
waste
incineration
unit''
in
EPA's
CISWI
rulemaking.
In
granting
this
petition
for
reconsideration,
EPA
agreed
to
undertake
further
notice
and
comment
proceedings
related
to
this
definition.
Second,
on
January
30,
2001,
the
Sierra
Club
filed
a
petition
for
review
in
the
U.
S.
Court
of
Appeals
for
the
D.
C.
Circuit
challenging
EPA's
final
CISWI
rule.
On
Sept.
6,
2001,
the
Court
entered
an
order
granting
EPA's
motion
for
a
voluntary
remand
of
the
CISWI
rule
without
vacature.
EPA's
request
for
a
voluntary
remand
of
the
final
CISWI
rule
was
intended
to
allow
the
Agency
to
address
concerns
related
to
the
Agency's
procedures
for
establishing
MACT
floors
for
CISWI
units
in
light
of
the
D.
C.
Circuit
Court's
decision
in
Cement
Kiln
Recycling
Coalition
v.
EPA,
255
F.
3d
855
(
D.
C.
Cir.
2001).
Neither
EPA's
granting
of
the
petition
for
reconsideration,
nor
the
Court's
order
granting
a
voluntary
remand,
stay,
vacate
or
otherwise
influence
the
effectiveness
of
the
currently
existing
CISWI
regulations.
Specifically,
section
307(
d)(
7)(
B)
of
the
Act
provides
that
``
reconsideration
shall
not
postpone
the
effectiveness
of
the
rule,''
except
that
``[
t]
he
effectiveness
of
the
rule
may
be
stayed
during
such
reconsideration
*
*
*
by
the
Administrator
or
the
court
for
a
period
not
to
exceed
three
months.''
In
this
case,
neither
EPA
nor
the
court
stayed
the
effectiveness
of
the
final
CISWI
regulations
in
connection
with
the
reconsideration
petition.
Likewise,
the
D.
C.
Circuit
granted
EPA's
motion
for
a
remand
without
vacature,
therefore,
the
Court's
remand
order
had
no
impact
on
the
effectiveness
of
the
current
CISWI
regulations.
Because
the
existing
CISWI
regulations
remain
in
full
effect,
EPA's
obligation
under
section
129(
b)(
3)
of
the
Act
to
promulgate
a
Federal
Plan
(
to
implement
those
regulations
for
existing
units
that
are
not
covered
by
an
approved
and
effective
State
plan)
remains
unchanged.
1
Therefore,
EPA
is
complying
with
its
statutory
obligations
by
issuing
today's
proposed
Federal
Plan
for
CISWI
units.
To
the
extent
that
EPA
might
take
action
in
the
future
that
results
in
changes
in
the
underlying
CISWI
rule
in
response
to
the
petition
for
reconsideration
or
in
response
to
the
voluntary
remand
EPA
will
simultaneously
amend
this
Federal
Plan
to
reflect
any
such
changes.
If
such
changes
become
necessary,
interested
parties,
including
States
and
sources,
will
have
the
opportunity
to
provide
comments,
and
EPA
will
reasonably
accommodate
the
concerns
of
commenters
as
appropriate.
II.
Affected
Facilities
A.
What
Is
a
CISWI
Unit?
A
CISWI
unit
means
any
combustion
device
that
combusts
commercial
and
industrial
waste,
as
defined
in
proposed
40
CFR
part
62,
subpart
III.
Commercial
and
industrial
waste,
as
defined
in
proposed
subpart
III,
is
solid
waste
combusted
in
an
enclosed
device
using
controlled
flame
combustion
without
energy
recovery
that
is
a
distinct
operating
unit
of
any
commercial
or
industrial
facility
(
including
fielderected
modular,
and
custom
built
incineration
units
operating
with
starved
or
excess
air),
or
solid
waste
combusted
in
an
air
curtain
incinerator
without
energy
recovery
that
is
a
distinct
operating
unit
of
any
commercial
or
industrial
facility.
Fifteen
types
of
combustion
units,
which
are
listed
in
§
62.14525
of
subpart
III
are
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Vol.
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227
/
Monday,
November
25,
2002
/
Proposed
Rules
conditionally
exempt
from
the
Federal
plan.
B.
Does
the
Federal
Plan
Apply
to
Me?
The
proposed
Federal
plan
will
apply
to
you
if
you
are
the
owner
or
operator
of
a
combustion
device
that
combusts
commercial
and
industrial
waste
(
as
defined
in
subpart
III)
and
the
device
is
not
covered
by
an
approved
and
effective
State
or
Tribal
plan
as
of
December
1,
2002.
The
proposed
Federal
plan
covers
your
CISWI
unit
until
EPA
approves
a
State
or
Tribal
plan
that
covers
your
CISWI
unit
and
that
plan
becomes
effective.
If
you
began
the
construction
of
your
CISWI
unit
on
or
before
November
30,
1999,
it
is
considered
an
existing
CISWI
unit
and
could
be
subject
to
the
Federal
plan.
If
you
began
the
construction
of
your
CISWI
unit
after
November
30,
1999,
it
is
considered
a
new
CISWI
unit
and
is
subject
to
the
NSPS.
If
you
began
reconstruction
or
modification
of
your
CISWI
unit
prior
to
June
1,
2001,
it
is
considered
an
existing
CISWI
unit
and
could
be
subject
to
the
Federal
plan.
Likewise,
if
you
began
reconstruction
or
modification
of
your
CISWI
unit
on
or
after
June
1,
2001,
it
is
considered
a
new
CISWI
unit
and
is
subject
to
the
NSPS.
Your
CISWI
unit
would
be
subject
to
this
Federal
plan
if
on
the
effective
date
of
the
Federal
plan,
EPA
has
not
approved
a
State
or
Tribal
Plan
that
covers
your
unit,
or
the
EPA
approved
State
or
Tribal
plan
has
not
become
effective.
The
specific
applicability
of
this
plan
is
described
in
§
§
62.14510
through
62.14530
of
subpart
III.
Once
an
approved
State
or
Tribal
plan
is
in
effect,
the
Federal
plan
will
no
longer
apply
to
a
CISWI
unit
covered
by
such
plan.
An
approved
State
or
Tribal
plan
is
a
plan
developed
by
a
State
or
Tribe
that
EPA
has
reviewed
and
approved
based
on
the
requirements
in
40
CFR
part
60,
subpart
B
to
implement
and
enforce
40
CFR
part
60,
subpart
DDDD.
The
State
or
Tribal
plan
is
effective
on
the
date
specified
in
the
notice
published
in
the
Federal
Register
announcing
EPA's
approval
of
the
plan.
The
EPA's
promulgation
of
a
CISWI
Federal
plan
will
not
preclude
States
or
Tribes
from
submitting
a
plan.
If
a
State
or
Tribe
submits
a
plan
after
promulgation
of
the
CISWI
Federal
plan
final
rule,
EPA
will
review
and
approve
or
disapprove
the
State
or
Tribal
plan.
If
EPA
approves
a
plan,
then
the
Federal
plan
would
no
longer
apply
to
CISWI
units
covered
by
the
State
or
Tribal
plan
as
of
the
effective
date
of
the
State
or
Tribal
plan.
(
See
the
discussion
in
``
State
or
Tribe
Submits
A
Plan
After
CISWI
Units
Located
in
the
Area
Are
Subject
to
the
Federal
Plan''
in
section
VI.
C
of
this
preamble.)
If
a
CISWI
unit
were
overlooked
by
a
State
or
Tribe
and
the
State
or
Tribe
submitted
a
negative
declaration
letter,
or
if
an
individual
CISWI
unit
were
not
covered
by
an
approved
and
effective
State
or
Tribal
plan,
the
CISWI
unit
would
be
subject
to
this
Federal
plan.
C.
How
Do
I
Determine
If
My
CISWI
Unit
Is
Covered
by
an
Approved
and
Effective
State
or
Tribal
Plan?
Part
62
of
Title
40
of
the
Code
of
Federal
Regulations
identifies
the
approval
and
promulgation
of
section
111(
d)
and
section
129
State
or
Tribal
plans
for
designated
facilities
in
each
State
or
area
of
Indian
Country.
However,
part
62
is
updated
only
once
per
year.
Thus,
if
part
62
does
not
indicate
that
your
State
or
Tribal
area
has
an
approved
and
effective
plan,
you
should
contact
your
State
environmental
agency's
air
director
or
your
EPA
Regional
Office
(
Table
1)
to
determine
if
approval
occurred
since
publication
of
the
most
recent
version
of
part
62.
III.
Elements
of
the
CISWI
Federal
Plan
Because
EPA
is
proposing
a
Federal
plan
to
cover
CISWI
units
located
in
States
and
areas
of
Indian
Country
where
plans
are
not
in
effect,
EPA
has
elected
to
include
in
this
proposal
the
same
elements
as
are
required
for
State
plans:
(
1)
Identification
of
legal
authority
and
mechanisms
for
implementation,
(
2)
inventory
of
CISWI
units,
(
3)
emissions
inventory,
(
4)
emission
limitations,
(
5)
compliance
schedules,
(
6)
waste
management
plan,
(
7)
testing,
monitoring,
inspection,
reporting,
and
recordkeeping,
(
8)
operator
training
and
qualification,
(
9)
public
hearing,
and
(
10)
progress
reporting.
See
40
CFR
part
60
subparts
B
and
C
and
sections
111
and
129
of
the
CAA.
Each
plan
element
is
described
below
as
it
relates
to
this
proposed
CISWI
Federal
plan.
Table
2
lists
each
element
and
identifies
where
it
is
located
or
codified.
TABLE
2.
ELEMENTS
OF
THE
CISWI
FEDERAL
PLAN
Element
of
the
CISWI
Federal
plan
Location
Legal
authority
and
enforcement
mechanism
Sections
129(
b)(
3)
111(
d),
301(
a),
and
301(
d)(
4)
of
the
CAA
Inventory
of
Affected
MWC
Units.
Docket
A
2000
52
Inventory
of
Emissions.
Docket
A
2000
52
TABLE
2.
ELEMENTS
OF
THE
CISWI
FEDERAL
PLAN
Continued
Element
of
the
CISWI
Federal
plan
Location
Emission
Limits
40
CFR
62.14630
62.14645
Compliance
Schedules.
40
CFR
62.14535
62.14575
Operator
Training
and
Qualification.
40
CFR
62.14595
62.14625
Waste
Management
Plan.
40
CFR
62.14580
62.14590
Record
of
Public
Hearings.
Docket
A
2000
52
Testing,
Monitoring
Recordkeeping
and
Reporting
40
CFR
62.14670
62.14760
Progress
Reports
Section
III.
J
of
this
preamble
A.
Legal
Authority
and
Enforcement
Mechanism
1.
EPA's
Legal
Authority
in
States
Section
301(
a)
of
the
CAA
provides
EPA
with
broad
authority
to
write
regulations
that
carry
out
the
functions
of
the
CAA.
Sections
111(
d)
and
129(
b)(
3)
of
the
CAA
direct
EPA
to
develop
a
Federal
plan
for
States
that
do
not
submit
approvable
State
plans.
Sections
111
and
129
of
the
CAA
provide
EPA
with
the
authority
to
implement
and
enforce
the
Federal
plan
in
cases
where
the
State
fails
to
submit
a
satisfactory
State
plan.
Section
129(
b)(
3)
requires
EPA
to
develop,
implement,
and
enforce
a
Federal
plan
within
2
years
after
the
date
the
relevant
emission
guidelines
are
promulgated
(
by
December
1,
2002
for
CISWI
units).
Compliance
with
the
emission
guidelines
cannot
be
later
than
5
years
after
the
relevant
emission
guidelines
are
promulgated
(
by
December
1,
2005
for
CISWI
units).
2.
EPA's
Legal
Authority
in
Indian
Country
Section
301
provides
EPA
with
the
authority
to
administer
Federal
programs
in
Indian
country.
See
sections
301
(
a)
and
(
d).
Section
301(
d)(
4)
of
the
CAA
authorizes
the
Administrator
to
directly
administer
provisions
of
the
CAA
where
Tribal
implementation
of
those
provisions
is
not
appropriate
or
administratively
not
feasible.
See
section
VI.
E
of
this
preamble
for
a
more
detailed
discussion
of
EPA's
authority
to
administer
the
CISWI
Federal
plan
in
Indian
country.
The
EPA
is
proposing
this
Federal
regulation
under
the
legal
authority
of
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the
CAA
to
implement
the
emission
guidelines
in
those
States
and
areas
of
Indian
country
not
covered
by
an
approved
plan.
As
discussed
in
section
VI
of
this
document,
implementation
and
enforcement
of
the
Federal
plan
may
be
delegated
to
eligible
Tribal,
State,
or
local
agencies
when
requested
by
a
State,
eligible
Tribal,
or
local
agency,
and
when
EPA
determines
that
such
delegation
is
appropriate.
B.
Inventory
of
Affected
CISWI
Units
The
proposed
Federal
plan
includes
an
inventory
of
CISWI
units
affected
by
the
emission
guidelines.
(
See
40
CFR
60.25(
a).)
Docket
number
A
2000
52
contains
an
inventory
of
the
CISWI
units
that
may
potentially
be
covered
by
this
proposed
Federal
plan
in
the
absence
of
State
or
Tribal
plans.
This
inventory
contains
99
CISWI
units
in
30
States
and
one
protectorate.
It
is
based
on
information
collected
from
State
and
Federal
databases,
information
collection
request
survey
responses,
and
stakeholder
meetings
during
the
development
of
the
CISWI
emission
guidelines.
The
EPA
recognizes
that
this
list
may
not
be
complete.
Therefore,
sources
potentially
subject
to
this
Federal
plan
may
include,
but
are
not
limited
to,
the
CISWI
units
listed
in
the
inventory
memorandum
in
docket
number
A
2000
52.
Any
CISWI
unit
that
meets
the
applicability
criteria
in
the
Federal
plan
rule
is
subject
to
the
Federal
plan,
regardless
of
whether
it
is
listed
in
the
inventory.
States,
Tribes,
or
individuals
are
invited
to
identify
additional
sources
for
inclusion
to
the
list
during
the
comment
period
for
this
proposal.
C.
Inventory
of
Emissions
The
proposed
Federal
plan
includes
an
emissions
estimate
for
CISWI
units
subject
to
the
emission
guidelines.
(
See
40
CFR
60.25(
a).)
The
pollutants
to
be
inventoried
are
dioxins/
furans,
cadmium
(
Cd),
lead
(
Pb),
mercury
(
Hg),
particulate
matter
(
PM),
hydrogen
chloride
(
HCl),
oxides
of
nitrogen
(
NOX),
carbon
monoxide
(
CO),
and
sulfur
dioxide
(
SO2).
For
this
proposal,
EPA
has
estimated
the
emissions
from
each
known
CISWI
unit
that
potentially
may
be
covered
by
the
Federal
plan
for
the
nine
pollutants
regulated
by
the
Federal
plan.
The
emissions
inventory
is
based
on
available
information
about
the
CISWI
units,
emission
factors,
and
typical
emission
rates
developed
for
calculating
nationwide
air
impacts
of
the
CISWI
emission
guidelines
and
the
Federal
plan.
Refer
to
the
inventory
memorandum
in
docket
number
A
2000
52
for
the
complete
emissions
inventory
and
details
on
the
emissions
calculations.
D.
Emission
Limitations
The
proposed
Federal
plan
includes
emission
limitations.
(
See
40
CFR
60.24(
a).)
Section
129(
b)(
2)
of
the
CAA
requires
these
emission
limitations
to
be
``
at
least
as
protective
as''
those
in
the
emission
guidelines.
The
emission
limitations
in
this
proposed
CISWI
Federal
plan
are
the
same
as
those
contained
in
the
emission
guidelines.
(
See
table
2
of
subpart
III.)
Section
IV
of
this
preamble
discusses
the
emission
limitations
and
operating
limits.
Table
3
of
subpart
III
contains
operating
limits
for
wet
scrubbers.
E.
Compliance
Schedules
Increments
of
progress
are
required
for
CISWI
units
that
need
more
than
1
year
from
State
plan
approval
to
comply,
or
in
the
case
of
the
Federal
plan,
more
than
1
year
after
promulgation
of
the
final
Federal
plan.
(
See
40
CFR
60.24(
e)(
1).)
Increments
of
progress
are
included
to
ensure
that
each
CISWI
unit
needing
more
time
to
comply
is
making
progress
toward
meeting
the
emission
limits.
For
CISWI
units
that
need
more
than
1
year
to
comply,
the
proposed
CISWI
Federal
plan
includes
in
its
compliance
schedule
two
increments
of
progress
from
40
CFR
60.21(
h),
as
allowed
by
40
CFR
60.24(
e)(
1)
and
required
by
40
CFR
part
60,
subpart
DDDD
(
§
60.2575).
The
Federal
plan
includes
defined
and
enforceable
dates
for
completion
of
each
increment.
These
increments
of
progress
are
(
1)
submit
final
control
plan,
and
(
2)
achieve
final
compliance.
The
proposed
increments
of
progress
are
described
in
section
IV.
E
of
this
preamble.
F.
Waste
Management
Plan
Requirements
A
waste
management
plan
is
a
written
plan
that
identifies
both
the
feasibility
and
the
methods
used
to
reduce
or
separate
certain
components
of
solid
waste
from
the
waste
stream
to
reduce
or
eliminate
toxic
emissions
from
incinerated
waste.
The
waste
management
plan
must
be
submitted
no
later
than
the
date
six
months
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
Sections
62.14580
through
62.14590
of
subpart
III
contain
the
waste
management
plan
requirements.
G.
Testing,
Monitoring,
Recordkeeping,
and
Reporting
The
proposed
Federal
plan
includes
testing,
monitoring,
recordkeeping,
and
reporting
requirements.
(
See
40
CFR
60.25.)
Testing,
monitoring,
recordkeeping,
and
reporting
requirements
are
consistent
with
subpart
DDDD,
and
assure
initial
and
ongoing
compliance.
H.
Operator
Training
and
Qualification
Requirements
The
owner
or
operator
must
qualify
operators
or
their
supervisors
(
at
least
one
per
facility)
by
ensuring
that
they
complete
an
operator
training
course
and
annual
review
or
refresher
course.
Sections
62.14595
through
62.14625
of
the
proposed
subpart
III
contain
the
operator
training
and
qualification
requirements.
I.
Record
of
Public
Hearings
The
proposed
Federal
plan
provides
opportunity
for
public
participation
in
adopting
the
plan.
(
See
40
CFR
60.23(
c).)
If
requested
to
do
so,
EPA
will
hold
a
public
hearing
in
Research
Triangle
Park,
NC.
A
record
of
the
public
hearing,
if
any,
will
appear
in
Docket
A
2000
52.
If
a
public
hearing
is
requested
and
held,
EPA
will
ask
clarifying
questions
during
the
oral
presentation
but
will
not
respond
to
the
presentations
or
comments.
Written
statements
and
supporting
information
submitted
during
the
public
comment
period
will
be
considered
with
equivalent
weight
as
any
oral
statement
and
supporting
information
subsequently
presented
at
a
public
hearing,
if
held.
J.
Progress
Reports
Under
the
Federal
plan,
the
EPA
Regional
Offices
will
prepare
annual
progress
reports
to
show
progress
of
CISWI
units
in
the
Region
toward
implementation
of
the
emission
guidelines.
(
See
40
CFR
60.25(
e).)
States
or
Tribes
that
have
been
delegated
the
authority
to
implement
and
enforce
this
Federal
plan
would
also
be
required
to
submit
annual
progress
reports
to
the
appropriate
EPA
Regional
Office.
Appendix
D
of
40
CFR
part
60
requires
reporting
of
emissions
data
to
the
Aerometric
Emissions
Information
Retrieval
System
(
AIRS)/
AIRS
Facility
Subsystem(
AFS).
These
reports
can
be
combined
with
the
State
implementation
plan
report
required
by
40
CFR
51.321
in
order
to
avoid
double
reporting.
Under
the
proposed
Federal
plan,
EPA
Regional
Offices
would
report
AIRS
emissions
data.
If
a
State
or
Tribe
has
been
delegated
the
authority
to
implement
and
enforce
the
Federal
plan,
the
State
or
Tribe
would
report
emissions
data
to
AIRS.
Each
progress
report
must
include
the
following
items:
(
1)
Status
of
enforcement
actions;
(
2)
status
of
increments
of
progress;
(
3)
identification
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67,
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227
/
Monday,
November
25,
2002
/
Proposed
Rules
of
sources
that
have
shut
down
or
started
operation;
(
4)
emission
inventory
data
for
sources
that
were
not
in
operation
at
the
time
of
plan
development,
but
that
began
operation
during
the
reporting
period;
(
5)
additional
data
as
necessary
to
update
previously
submitted
source
and
emission
information;
and
(
6)
copies
of
technical
reports
on
any
performance
testing
and
monitoring.
IV.
Summary
of
CISWI
Federal
Plan
A.
What
Emission
Limitations
Must
I
Meet?
As
the
owner
or
operator
of
an
existing
CISWI
unit,
you
will
be
required
to
meet
the
emission
limitations
specified
in
Table
1.
See
section
IV.
E
of
this
preamble
for
a
discussion
of
the
compliance
schedule.
TABLE
1.
EMISSION
LIMITATIONS
FOR
EXISTING
CISWI
UNITS
For
these
pollutants
You
must
meet
these
emission
limitations
a
And
determine
compliance
using
these
methods
b
Cadmium
..............................
0.004
mg/
dscm
................................................................
EPA
Method
29
Carbon
Monoxide
.................
157
ppm
..........................................................................
EPA
Methods
10,
10A,
or
10B
Dioxins/
Furans,
toxic
equivalent
(
TEQ)
basis.
0.41
ng/
dscm
...................................................................
EPA
Method
23
Hydrogen
Chloride
...............
62
ppm
by
dry
volume
....................................................
EPA
Method
26A
Lead
.....................................
0.04
mg/
dscm
..................................................................
EPA
Method
29
Mercury
................................
0.47
mg/
dscm
..................................................................
EPA
Method
29
Opacity
.................................
10
percent
.......................................................................
EPA
Method
9
Oxides
of
Nitrogen
...............
388
ppm
by
dry
volume
..................................................
EPA
Method
7,
7A,
7C,
7D,
or
7E
Particulate
Matter
.................
70
mg/
dscm
.....................................................................
EPA
Method
5
or
29
Sulfur
Dioxide
.......................
20
ppm
by
dry
volume
....................................................
EPA
Method
6
or
6c
a
All
emission
limitations
(
except
opacity)
are
measured
at
7
percent
oxygen,
dry
basis
at
standard
conditions.
b
These
methods
are
in
40
CFR
part
60,
appendix
A.
B.
What
Operating
Limits
Must
I
Meet?
If
you
are
using
a
wet
scrubber
to
comply
with
the
emission
limitations,
you
will
be
required
to
establish
the
maximum
and
minimum
site
specific
operating
limits
indicated
in
Table
2.
You
will
be
required
to
operate
the
CISWI
unit
and
wet
scrubber
so
that
the
operating
parameters
do
not
deviate
from
the
established
operating
limits.
TABLE
2.
OPERATING
LIMITS
FOR
EXISTING
CISWI
UNITS
USING
WET
SCRUBBERS
For
these
operating
parameters
You
must
establish
these
operating
limits
And
monitor
continuously
using
these
recording
times
Charge
rate
..........................
Maximum
charge
rate
.....................................................
Every
hour
Pressure
drop
across
the
wet
scrubber,
or
amperage
to
the
wet
scrubber.
Minimum
pressure
drop
or
amperage
............................
Every
15
minutes
Scrubber
liquor
flow
rate
......
Minimum
flow
rate
...........................................................
Every
15
minutes
For
these
operating
parameters
You
must
establish
these
operating
limits.
.....................
And
monitor
continuously
using
these
recording
times
Scrubber
liquor
pH
...............
Minimum
pH
....................................................................
Every
15
minutes
NOTE:
Compliance
is
determined
on
a
3
hour
rolling
average
basis,
except
charge
rate
for
batch
incinerators,
which
is
determined
on
a
daily
basis.
If
you
are
using
an
air
pollution
control
device
other
than
a
wet
scrubber
to
comply
with
the
emission
limitations,
you
will
be
required
to
petition
the
Administrator
for
other
site
specific
operating
limits
to
be
established
during
the
initial
performance
test
and
continuously
monitored
thereafter.
The
required
components
of
the
petition
are
described
in
§
62.14640
of
subpart
III.
If
you
are
using
a
fabric
filter
to
comply
with
the
emission
limitations,
in
addition
to
other
operating
limits
as
approved
by
the
Administrator,
you
must
operate
the
fabric
filter
system
such
that
the
bag
leak
detection
system
alarm
does
not
sound
more
than
5
percent
of
the
operating
time
during
any
6
month
period.
C.
What
Are
the
Requirements
for
Air
Curtain
Incinerators?
The
Federal
plan
will
establish
opacity
limitations
for
air
curtain
CISWI
units
burning
100
percent
wood
wastes
and/
or
clean
lumber.
This
opacity
limitation
will
be
10
percent,
except
35
percent
opacity
will
be
allowed
during
start
up
periods
that
are
within
the
first
30
minutes
of
operation.
D.
What
Are
the
Testing,
Monitoring,
Inspection,
Recordkeeping,
and
Reporting
Requirements?
The
owner
or
operator
of
a
CISWI
unit
subject
to
the
CISWI
Federal
plan
will
be
required
to
conduct
initial
performance
tests
for
cadmium,
dioxins/
furans,
hydrogen
chloride,
lead,
mercury,
opacity,
particulate
matter,
and
sulfur
dioxide
and
establish
operating
limits
(
i.
e.,
maximum
or
minimum
values
for
operating
parameters).
The
initial
performance
test
must
be
conducted
within
180
days
after
the
date
the
facility
is
required
to
achieve
final
compliance.
The
owner
or
operator
will
be
required
to
conduct
annual
performance
tests
for
particulate
matter,
hydrogen
chloride,
and
opacity.
(
An
owner
or
operator
may
conduct
less
frequent
testing
if
the
facility
demonstrates
that
it
is
in
compliance
with
the
emission
limitations
for
3
consecutive
years.)
To
assure
ongoing
achievement
of
the
Federal
plan's
provisions,
an
owner
or
operator
using
a
wet
scrubber
to
comply
with
the
emission
limitations
will
continuously
monitor
the
following
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/
Vol.
67,
No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
operating
parameters:
charge
rate,
pressure
drop
across
the
wet
scrubber
(
or
amperage),
and
scrubber
liquid
flow
rate
and
pH.
If
something
other
than
a
wet
scrubber
is
used
to
comply
with
the
emission
limitations,
the
owner
or
operator
will
be
required
to
monitor
other
operating
parameters,
as
approved
by
the
Administrator.
If
the
owner
or
operator
is
using
a
fabric
filter
to
comply
with
the
emission
limitations,
in
addition
to
other
operating
limits
as
approved
by
the
Administrator,
the
owner
or
operator
must
install
and
continuously
operate
a
bag
leak
detection
system.
The
owner
or
operator
must
keep
records
of
periods
when
the
alarm
sounds
and
calculate
whether
these
periods
are
more
than
5
percent
of
the
operating
time
for
each
6
month
period.
The
owner
or
operator
will
be
required
to
submit
information
documenting
compliance
with
these
requirements
as
part
of
an
annual
report;
and
report
deviations
semiannually
In
addition,
the
Federal
plan
will
require
CISWI
unit
owners
and
operators
to
maintain
for
5
years
records
of
the
initial
performance
tests
and
all
subsequent
performance
tests,
operating
parameters,
any
maintenance,
and
operator
training
and
qualification.
The
owner
or
operator
will
submit
the
results
of
the
initial
performance
tests
and
all
subsequent
performance
tests
and
values
for
the
operating
parameters
in
annual
reports.
E.
What
Is
the
Compliance
Schedule?
Each
CISWI
unit
will
be
required
to
either:
(
1)
Reach
final
compliance
by
the
date
1
year
after
publication
of
the
final
rule
in
the
Federal
Register,
or
(
2)
meet
increments
of
progress
and
reach
final
compliance
by
the
date
2
years
after
publication
of
the
final
rule
in
the
Federal
Register.
In
addition,
the
owner
or
operator
must
comply
with
the
operator
training
and
qualification
requirements
and
inspection
requirements
by
the
date
1
year
after
publication
of
the
final
rule
in
the
Federal
Register,
regardless
of
when
the
CISWI
unit
reaches
final
compliance.
Each
owner
or
operator
that
takes
more
than
1
year
to
reach
final
compliance
must
submit
a
final
control
plan
(
increment
1)
by
the
date
6
months
after
publication
of
the
final
rule
for
this
Federal
plan
in
the
Federal
Register
and
reach
final
compliance
(
increment
2)
by
the
date
2
years
after
publication
of
the
final
rule
in
the
Federal
Register.
To
ensure
timely
progress
towards
implementation
of
the
Federal
plan,
the
proposed
rules
include
a
requirement
for
owners
or
operators
of
CISWI
units
seeking
to
take
an
additional
year
to
reach
final
compliance
to
submit
a
request
to
the
Administrator
that
documents
the
need
for
an
extension.
To
meet
the
increment
1
requirement,
the
owner
or
operator
of
each
CISWI
unit
must
submit
a
final
control
plan
that
includes
five
items:
(
1)
A
description
of
the
air
pollution
control
devices
and/
or
process
changes
that
will
be
employed
so
that
each
CISWI
unit
complies
with
the
emission
limits
and
other
requirements,
(
2)
a
list
of
the
types
of
waste
burned,
(
3)
the
maximum
design
waste
burning
capacity,
(
4)
the
anticipated
maximum
charge
rate,
and,
(
5)
if
applicable,
the
petition
for
sitespecific
operating
limits.
A
final
control
plan
is
not
required
for
units
that
will
be
shut
down,
but
those
units
must
close
by
1
year
after
the
final
rule
is
published
or
must
submit
a
closure
agreement
by
6
months
after
the
final
rule
is
published,
close
no
later
than
2
years
after
the
rule
is
published,
and
meet
other
requirements
as
described
in
section
V.
A.
of
this
preamble.
To
meet
the
second
increment
of
progress,
the
owner
or
operator
of
each
CISWI
unit
must
incorporate
all
process
changes
or
complete
retrofit
construction
in
accordance
with
the
final
control
plan.
The
owner
or
operator
must
connect
the
air
pollution
control
equipment
or
process
changes
such
that
when
the
CISWI
unit
is
brought
on
line
all
necessary
process
changes
or
air
pollution
control
equipment
will
operate
as
designed.
F.
How
Did
EPA
Determine
the
Compliance
Schedule?
The
EPA
determined
the
compliance
schedule
based
on
the
requirements
of
40
CFR
part
60,
subpart
B
and
the
feasibility
of
owners
or
operators
to
retrofit
combustion
units
with
air
pollution
control
devices.
CISWI
units
must
comply
within
1
year
after
publication
of
the
final
Federal
plan
or
meet
increments
of
progress.
The
requirement
to
reach
final
compliance
within
1
year
is
consistent
with
40
CFR
60.24(
c)
of
subpart
B.
Subpart
B
requires
final
compliance
to
be
``
as
expeditiously
as
practicable*
*
*''
and
requires
increments
of
progress
if
the
compliance
schedule
is
longer
than
1
year.
The
EPA
believes
that
many
CISWI
units
can
reach
final
compliance
within
1
year
after
promulgation
of
the
Federal
plan
based
on
their
similarity
to
HMIWI
units.
In
addition
to
the
1
year
after
promulgation
of
the
Federal
plan,
units
could
use
the
time
between
this
proposed
rule
and
promulgation
of
the
final
Federal
plan
to
plan
and
begin
retrofits.
The
proposed
compliance
schedule
for
CISWI
units
is
similar
to
the
compliance
schedule
for
HMIWI
units.
Most
CISWI
units
are
similar
in
size
to
HMIWI
units.
In
addition,
CISWI
units
would
require
similar
controls
to
meet
the
CISWI
Federal
plan
emission
limits
as
HMIWI
units
would
need
to
meet
the
HMIWI
Federal
plan
emission
limits.
To
determine
the
compliance
schedule
for
HMIWI
units,
EPA
conducted
case
studies
of
eight
HMIWI
units
that
completed
retrofits
of
the
types
of
controls
needed
to
meet
the
HMIWI
Federal
plan
(
64
FR
36430,
July
6,
1999).
Based
on
these
case
studies
(
Docket
No.
A
98
24,
II
A
1),
EPA
found
that
many
HMIWI
units
can
meet
the
requirements
of
the
Federal
plan
within
1
year.
Similarly,
many
CISWI
units
could
meet
a
1
year
schedule.
We
expect
that
some
CISWI
units
could
need
more
than
1
year
to
comply,
as
did
some
HMIWI
units,
due
to
sitespecific
circumstances.
For
units
that
cannot
comply
within
1
year,
the
proposed
Federal
plan
establishes
increments
of
progress,
as
required
by
subpart
B.
The
proposed
date
for
the
first
increment
of
progress,
submittal
of
a
final
control
plan,
is
6
months
after
publication
of
the
final
Federal
plan
in
the
Federal
Register.
The
proposed
date
for
the
second
increment
of
progress,
final
compliance,
is
2
years
after
publication
of
the
final
Federal
plan
in
the
Federal
Register.
These
increments
are
derived
from
the
findings
of
the
case
studies
performed
to
characterize
the
retrofit
of
control
systems
for
hospital
medical
and
infectious
waste
(
HMIWI)
incinerators
(
Docket
A
98
24,
Item
II
A
1).
The
size
and
design
of
CISWI
are
similar
to
the
smaller
HMIWI
that
were
the
subjects
of
the
case
studies.
In
particular,
most
units
are
small
and
controls
will
be
ordered
``
off
the
shelf''
as
assembled
packages.
Thus,
the
Agency
did
not
see
a
need
for
increments
to
address
details
of
on
site
construction
and
installation
of
control
systems.
Also,
CISWI
sites
are
not
thought
to
have
the
problems
with
space
and
access
that
were
concerns
for
HMIWI
retrofits.
In
addition,
CISWI
units
have
the
time
between
publication
of
this
proposed
rule
and
publication
of
the
final
rule
in
the
Federal
Register
to
begin
developing
the
final
control
plan
and
to
initiate
retrofit
activities.
The
proposed
rules
do
not
include
increments
of
progress
for
air
curtain
incinerators
(
ACI).
Air
curtain
incinerators
must
comply
with
the
requirements
of
the
Federal
plan
one
year
after
the
date
of
promulgation
of
the
final
rule.
Delaying
implementation
for
ACI
would
not
be
appropriate
because
there
will
be
little
or
no
need
for
the
installation
of
control
equipment
on
these
units(
Primarily
because
control
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/
Vol.
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No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
equipment
is
typically
infeasible
for
ACI).
Compliance
with
the
opacity
limits
applicable
to
this
class
of
units
would
primarily
be
achieved
by
good
operation
and
maintenance
practices.
This
approach
is
consistent
with
the
proposed
requirement
for
completion
of
CISWI
operator
training
by
the
date
one
year
after
promulgation
of
the
final
rule.
V.
CISWI
That
Have
or
Will
Shut
Down
A.
Units
That
Plan
To
Close
Rather
Than
Comply
If
you
plan
to
permanently
close
your
currently
operating
CISWI
unit,
you
must
do
one
of
the
following:
(
a)
close
by
the
date
1
year
after
publication
of
the
final
rule
for
this
Federal
plan
in
the
Federal
Register,
or
(
b)
submit
a
legally
binding
closure
agreement,
including
the
date
of
closure,
to
the
Administrator
by
the
date
6
months
after
publication
of
the
final
rule
in
the
Federal
Register.
The
closure
agreement
must
specify
the
date
by
which
operation
will
cease.
The
closure
date
cannot
be
later
than
the
final
compliance
date
of
the
CISWI
Federal
plan
(
2
years
after
publication
of
the
final
rule
in
the
Federal
Register).
If
you
close
your
CISWI
unit
after
the
date
1
year
after
publication
of
the
final
rule
in
the
Federal
Register,
but
before
the
date
2
years
after
publication
of
the
final
rule
in
the
Federal
Register,
then
you
must
comply
with
the
operator
training
and
qualification
requirements
by
the
date
1
year
after
publication
of
the
final
rule
in
the
Federal
Register.
In
addition,
while
still
in
operation,
you
are
subject
to
the
same
requirements
for
title
V
operating
permits
that
apply
to
units
that
will
not
shut
down.
B.
Inoperable
Units
In
cases
where
a
CISWI
unit
has
already
shut
down,
has
been
rendered
inoperable,
and
does
not
intend
to
restart,
the
CISWI
unit
may
be
left
off
the
source
inventory
in
a
State,
Tribal,
or
this
Federal
plan.
A
CISWI
unit
that
has
been
rendered
inoperable
would
not
be
covered
by
the
Federal
plan.
The
CISWI
owner
or
operator
may
do
the
following
to
render
a
CISWI
unit
inoperable:
(
1)
Weld
the
waste
charge
door
shut,
(
2)
remove
stack
(
and
by
pass
stack,
if
applicable),
(
3)
remove
combustion
air
blowers,
or
(
4)
remove
burners
or
fuel
supply
appurtenances.
C.
CISWI
Units
That
Have
Shut
Down
CISWI
units
that
are
known
to
have
already
shut
down
(
but
are
not
known
to
be
inoperable)
will
be
included
in
the
source
inventory
and
identified
in
any
State
or
Tribal
plan
submitted
to
EPA.
1.
Restarting
Before
The
Final
Compliance
Date
If
the
owner
or
operator
of
an
inactive
CISWI
unit
plans
to
restart
before
the
final
compliance
date,
the
owner
or
operator
must
submit
a
control
plan
for
the
CISWI
unit
and
meet
the
applicable
compliance
schedule.
Final
compliance
is
required
for
all
pollutants
and
all
CISWI
units
no
later
than
the
final
compliance
date.
(
See
section
IV.
E
for
the
discussion
on
compliance
schedules
and
increments
of
progress.)
2.
Restarting
After
The
Final
Compliance
Date
Under
this
proposed
Federal
plan,
a
control
plan
would
not
be
needed
for
inactive
CISWI
units
that
restart
after
the
final
compliance
date.
However,
before
restarting,
such
CISWI
units
would
have
to
complete
the
operator
training
and
qualification
requirements
and
inspection
requirements
(
if
applicable)
and
complete
retrofit
or
process
modifications.
Performance
testing
to
demonstrate
compliance
would
be
required
within
180
days
after
restarting.
There
would
be
no
need
to
show
that
the
increments
of
progress
have
been
met
since
these
steps
would
have
occurred
before
restart
while
the
CISWI
unit
was
shut
down
and
not
generating
emissions.
A
CISWI
unit
that
operates
out
of
compliance
after
the
final
compliance
date
would
be
in
violation
of
the
Federal
plan
and
subject
to
enforcement
action.
VI.
Implementation
of
the
Federal
Plan
and
Delegation
A.
Background
of
Authority
Under
sections
111(
d)
and
129(
b)
of
the
CAA,
EPA
is
required
to
adopt
emission
guidelines
that
are
applicable
to
existing
solid
waste
incineration
sources.
These
emission
guidelines
are
not
enforceable
until
EPA
approves
a
State
or
Tribal
plan
or
adopts
a
Federal
plan
that
implements
and
enforces
them,
and
the
State,
Tribal,
or
Federal
plan
has
become
effective.
As
discussed
above,
the
Federal
plan
regulates
CISWI
units
in
a
State
or
Tribal
area
that
does
not
have
an
EPA
approved
plan
currently
in
effect.
Congress
has
determined
that
the
primary
responsibility
for
air
pollution
prevention
and
control
rests
with
State
and
local
agencies.
See
section
101(
a)(
3)
of
the
CAA.
Consistent
with
that
overall
determination,
Congress
established
sections
111
and
129
of
the
CAA
with
the
intent
that
the
States
and
local
agencies
take
the
primary
responsibility
for
ensuring
that
the
emission
limitations
and
other
requirements
in
the
emission
guidelines
are
achieved.
Also,
in
section
111(
d)
of
the
CAA,
Congress
explicitly
required
that
EPA
establish
procedures
that
are
similar
to
those
under
section
110(
c)
for
State
Implementation
Plans.
Although
Congress
required
EPA
to
propose
and
promulgate
a
Federal
plan
for
States
that
fail
to
submit
approvable
State
plans
on
time,
States
and
Tribes
may
submit
approvable
plans
after
promulgation
of
the
CISWI
Federal
plan.
The
EPA
strongly
encourages
States
that
are
unable
to
submit
approvable
plans
to
request
delegation
of
the
Federal
plan
so
that
they
can
have
primary
responsibility
for
implementing
the
emission
guidelines,
consistent
with
Congress'
intent.
Approved
and
effective
State
plans
or
delegation
of
the
Federal
plan
is
EPA's
preferred
outcome
since
EPA
believes
that
State
and
local
agencies
not
only
have
the
responsibility
to
carry
out
the
emission
guidelines,
but
also
have
the
practical
knowledge
and
enforcement
resources
critical
to
achieving
the
highest
rate
of
compliance.
For
these
reasons,
EPA
will
do
all
that
it
can
to
expedite
delegation
of
the
Federal
plan
to
State
and
local
agencies,
whenever
possible.
The
EPA
also
believes
that
Indian
Tribes
should
be
the
primary
parties
responsible
for
regulating
air
quality
within
Indian
country,
if
they
desire
to
do
so.
See
EPA's
Indian
Policy
(``
Policy
for
Administration
of
Environmental
Programs
on
Indian
Reservations,''
signed
by
William
D.
Ruckelshaus,
Administrator
of
EPA,
dated
November
4,
1984),
reaffirmed
in
a
2001
memorandum
(``
EPA
Indian
Policy,''
signed
by
Christine
Todd
Whitman,
Administrator
of
EPA,
dated
July
11,2001).
B.
Delegation
of
the
Federal
Plan
and
Retained
Authorities
If
a
State
or
Indian
Tribe
intends
to
take
delegation
of
the
Federal
plan,
the
State
or
Indian
Tribe
must
submit
to
the
appropriate
EPA
Regional
Office
a
written
request
for
delegation
of
authority.
The
State
or
Indian
Tribe
must
explain
how
it
meets
the
criteria
for
delegation.
See
generally
``
Good
Practices
Manual
for
Delegation
of
NSPS
and
NESHAP''
(
EPA,
February
1983).
In
order
to
obtain
delegation,
an
Indian
Tribe
must
also
establish
its
eligibility
to
be
treated
in
the
same
manner
as
a
State
(
see
section
IV.
E.
1
of
this
preamble).
The
letter
requesting
delegation
of
authority
to
implement
the
Federal
plan
must
demonstrate
that
the
State
or
Tribe
has
adequate
resources,
as
well
as
the
legal
and
enforcement
authority
to
administer
and
enforce
the
program.
A
memorandum
of
agreement
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/
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227
/
Monday,
November
25,
2002
/
Proposed
Rules
between
the
State
or
Tribe
and
EPA
would
set
forth
the
terms
and
conditions
of
the
delegation,
the
effective
date
of
the
agreement,
and
would
also
serve
as
the
mechanism
to
transfer
authority.
Upon
signature
of
the
agreement,
the
appropriate
EPA
Regional
Office
would
publish
an
approval
notice
in
the
Federal
Register,
thereby
incorporating
the
delegation
authority
into
the
appropriate
subpart
of
40
CFR
part
62.
If
authority
is
not
delegated
to
a
State
or
Indian
Tribe,
EPA
will
implement
the
Federal
plan.
Also,
if
a
State
or
Tribe
fails
to
properly
implement
a
delegated
portion
of
the
Federal
plan,
EPA
will
assume
direct
implementation
and
enforcement
of
that
portion.
The
EPA
will
continue
to
hold
enforcement
authority
along
with
the
State
or
Tribe
even
when
a
State
or
Tribe
has
received
delegation
of
the
Federal
plan.
In
all
cases
where
the
Federal
plan
is
delegated,
EPA
will
retain
and
will
not
transfer
authority
to
a
State
or
Tribe
to
approve
the
following
items:
(
1)
Alternative
site
specific
operating
parameters
established
by
facilities
using
CISWI
controls
other
than
a
wet
scrubber
(
§
62.14640
of
subpart
III),
(
2)
Alternative
methods
of
demonstrating
compliance,
(
3)
Alternative
requirements
that
could
change
the
stringency
of
the
underlying
standard,
which
are
likely
to
be
nationally
significant,
or
which
may
require
a
national
rulemaking
and
subsequent
Federal
Register
notice.
The
following
authorities
may
not
be
delegated
to
the
State,
Tribal
or
local
agencies:
Approval
of
alternative
nonopacity
emission
standards,
approval
of
alternative
opacity
standard,
approval
of
major
alternatives
to
test
methods,
approval
of
major
alternatives
to
monitoring,
and
waiver
of
recordkeeping
and
reporting;
and
(
4)
Petitions
to
the
Administrator
to
add
a
chemical
recovery
unit
to
§
62.14525(
n)
of
subpart
III.
CISWI
owners
or
operators
who
wish
to
establish
alternative
operating
parameters
or
alternative
methods
of
demonstrating
compliance
should
submit
a
request
to
the
Regional
Office
Administrator
with
a
copy
to
the
appropriate
State
or
Tribe.
C.
Mechanisms
for
Transferring
Authority
There
are
two
mechanisms
for
transferring
implementation
authority
to
State
or
Tribal
agencies:
(
1)
EPA
approval
of
a
State
or
Tribal
plan
after
the
Federal
plan
is
in
effect;
and
(
2)
if
a
State
or
Tribe
does
not
submit
or
obtain
approval
of
its
own
plan,
EPA
delegation
to
a
State
or
Tribe
of
the
authority
to
implement
certain
portions
of
this
Federal
plan
to
the
extent
appropriate
and
if
allowed
by
State
or
Tribal
law.
Both
of
these
options
are
described
in
more
detail
below.
1.
Federal
Plan
Becomes
Effective
Prior
to
Approval
of
a
State
or
Tribal
Plan
After
CISWI
units
in
a
State
or
Tribal
area
become
subject
to
the
Federal
plan,
the
State
or
Tribal
agency
may
still
adopt
and
submit
a
plan
to
EPA.
If
EPA
determines
that
the
State
or
Tribal
plan
is
as
protective
as
the
emission
guidelines,
EPA
will
approve
the
State
or
Tribal
plan.
If
EPA
determines
that
the
plan
is
not
as
protective
as
the
emission
guidelines,
EPA
will
disapprove
the
plan
and
the
CISWI
units
covered
in
the
State
or
Tribal
plan
would
remain
subject
to
the
Federal
plan
until
a
State
or
Tribal
plan
covering
those
CISWI
units
is
approved
and
effective.
Upon
the
effective
date
of
an
approved
State
or
Tribal
plan,
the
Federal
plan
would
no
longer
apply
to
CISWI
units
covered
by
such
a
plan,
and
the
State
or
Tribal
agency
would
implement
and
enforce
the
State
or
Tribal
plan
in
lieu
of
the
Federal
plan.
When
an
EPA
Regional
Office
approves
a
State
or
Tribal
plan,
it
will
amend
the
appropriate
subpart
of
40
CFR
part
62
to
indicate
such
approval.
2.
State
or
Tribe
Takes
Delegation
of
the
Federal
Plan
The
EPA,
in
its
discretion,
may
delegate
to
State
or
eligible
Tribal
agencies
the
authority
to
implement
this
Federal
plan.
As
discussed
above,
EPA
believes
that
it
is
advantageous
and
the
best
use
of
resources
for
State
or
Tribal
agencies
to
agree
to
undertake,
on
EPA's
behalf,
the
administrative
and
substantive
roles
in
implementing
the
Federal
plan
to
the
extent
appropriate
and
where
authorized
by
State
or
Tribal
law.
If
a
State
requests
delegation,
EPA
will
generally
delegate
the
entire
Federal
plan
to
the
State
agency.
These
functions
include
administration
and
oversight
of
compliance
reporting
and
recordkeeping
requirements,
CISWI
inspections,
and
preparation
of
draft
notices
of
violation.
The
EPA
also
believes
that
it
is
the
best
use
of
resources
for
Tribal
agencies
to
undertake
a
role
in
the
implementation
of
the
Federal
plan.
The
Tribal
Authority
Rule
issued
on
February
12,
1998
(
63
FR
7254)
provides
Tribes
the
opportunity
to
develop
and
implement
Clean
Air
Act
programs.
However,
due
to
resource
constraints
and
other
factors
unique
to
Tribal
governments,
it
leaves
to
the
discretion
of
the
Tribe
whether
to
develop
these
programs
and
which
elements
of
the
program
they
will
adopt.
Consistent
with
the
approach
of
the
Tribal
Authority
Rule,
EPA
may
choose
to
delegate
a
partial
Federal
plan
(
i.
e.,
to
delegate
authority
for
some
functions
needed
to
carry
out
the
plan)
in
appropriate
circumstances
and
where
consistent
with
Tribal
law.
Both
States
and
Tribal
agencies,
that
have
taken
delegation,
as
well
as
EPA,
will
have
responsibility
for
bringing
enforcement
actions
against
sources
violating
Federal
plan
provisions.
However,
EPA
recognizes
that
Tribes
have
limited
criminal
enforcement
authority,
and
EPA
will
address
in
the
delegation
agreement
with
the
Tribe
how
criminal
enforcement
issues
are
referred
to
EPA.
D.
Implementing
Authority
The
EPA
will
delegate
authority
within
the
Agency
to
the
EPA
Regional
Administrators
to
implement
the
CISWI
Federal
plan.
All
reports
required
by
this
Federal
plan
should
be
submitted
to
the
appropriate
Regional
Office
Administrator.
Table
1
under
Supplementary
Information
lists
the
names
and
addresses
of
the
EPA
Regional
Office
contacts
and
the
States
that
they
cover.
E.
CISWI
Federal
Plan
and
Indian
Country
The
term
``
Indian
country,''
as
used
in
this
preamble,
means
(
1)
all
land
within
the
limits
of
any
Indian
reservation
under
the
jurisdiction
of
the
United
States
government,
notwithstanding
the
issuance
of
any
patent,
and
including
rights
of
way
running
through
the
reservation;
(
2)
all
dependent
Indian
communities
within
the
borders
of
the
United
States
whether
within
the
original
or
subsequently
acquired
territory
thereof,
and
whether
within
or
without
the
limits
of
a
State;
and
(
3)
all
Indian
allotments,
the
Indian
titles
to
which
have
not
been
extinguished,
including
rights
of
way
running
through
the
same.
The
CISWI
Federal
plan
would
apply
throughout
Indian
country
to
ensure
that
there
is
not
a
regulatory
gap
for
existing
CISWI
units
in
Indian
country.
However,
eligible
Indian
tribes
now
have
the
authority
under
the
CAA
to
develop
Tribal
plans
in
the
same
manner
that
States
develop
State
plans.
On
February
12,
1998,
EPA
promulgated
regulations
that
outline
provisions
of
the
CAA
for
which
it
is
appropriate
to
treat
Tribes
in
the
same
manner
as
States.
See
63
FR
7254
(
Final
Rule
for
Indian
Tribes:
Air
Quality
Planning
and
Management,
(
Tribal
Authority
Rule))
(
codified
at
40
CFR
part
49).
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Vol.
67,
No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
2
A
title
V
application
should
be
submitted
early
enough
for
the
permitting
authority
to
find
the
application
either
complete
or
incomplete
before
the
title
V
application
deadline.
In
the
event
the
application
is
found
incomplete
by
the
permitting
authority,
the
source
must
submit
the
information
needed
to
make
the
application
complete
by
the
application
deadline
in
order
to
obtain
the
application
shield.
See
40
CFR
62.14835(
b)
and
40
CFR
70.5(
a)(
2)
and
71.5(
a)(
2).
3
For
example,
in
the
absence
of
such
an
interpretation,
if
a
final
Federal
plan
were
to
become
effective
more
than
24
months
after
the
promulgation
of
emission
guidelines
promulgated
under
sections
111
and
129,
a
source,
if
subject
to
the
Federal
plan,
would
have
less
than
12
months
to
prepare
and
submit
a
complete
title
V
permit
application
and
to
have
the
permit
issued.
EPA's
interpretation
allows
section
129(
e)
to
be
read
consistently
with
section
503(
d)
of
the
Act
and
40
CFR
70.7(
b)
and
71.7(
b).
EPA's
interpretation
is
also
consistent
with
section
503(
c)
of
the
Act
which
requires
sources
to
submit
title
V
applications
not
later
than
12
months
after
becoming
subject
to
a
title
V
permits
programs.
If
a
permit
as
opposed
to
a
title
V
application
were
required
by
the
later
of
the
two
deadlines
specified
in
section
129(
e),
some
section
129
sources
would
be
required
to
have
been
issued
final
title
V
permits
in
potentially
much
less
time
than
allotted
for
non
section
129
sources
to
submit
their
title
V
applications.
4
If
a
source
is
subject
to
title
V
for
more
than
one
reason,
the
12
month
time
frame
for
submitting
a
title
V
application
is
triggered
by
the
requirement
which
first
causes
the
source
to
become
subject
to
title
V.
As
provided
in
section
503(
c)
of
the
CAA,
permitting
authorities
may
establish
permit
application
deadlines
earlier
than
the
12
month
deadline.
March
16,
1998,
the
effective
date
of
the
Tribal
Authority
Rule,
EPA
has
had
authority
under
the
CAA
to
approve
Tribal
programs
such
as
Tribal
plans
to
implement
and
enforce
the
CISWI
emission
guidelines.
1.
Tribal
Implementation
Section
301(
d)
of
the
CAA
authorizes
the
Administrator
to
treat
an
Indian
tribe
as
a
State
under
certain
circumstances.
The
Tribal
Authority
Rule,
which
implements
section
301(
d)
of
the
CAA,
identifies
provisions
of
the
CAA
for
which
it
is
appropriate
to
treat
a
Tribe
as
a
State.
(
See
40
CFR
49.3
and
49.4.)
Under
the
Tribal
Authority
Rule,
a
Tribe
may
be
treated
as
a
State
for
purposes
of
this
Federal
plan.
If
a
Tribe
meets
the
criteria
below,
EPA
can
delegate
to
an
Indian
tribe
authority
to
implement
the
Federal
plan
in
the
same
way
it
can
delegate
authority
to
a
State:
(
1)
The
applicant
is
an
Indian
tribe
recognized
by
the
Secretary
of
the
Interior;
(
2)
The
Indian
tribe
has
a
governing
body
carrying
out
substantial
governmental
duties
and
functions;
(
3)
The
functions
to
be
exercised
by
the
Indian
tribe
pertain
to
the
management
and
protection
of
air
resources
within
the
exterior
boundaries
of
the
reservation
or
other
areas
within
the
tribe's
jurisdiction;
and
(
4)
The
Indian
tribe
is
reasonably
expected
to
be
capable,
in
the
EPA
Regional
Administrator's
judgment,
of
carrying
out
the
functions
to
be
exercised
in
a
manner
consistent
with
the
terms
and
purposes
of
the
CAA
and
all
applicable
regulations.
(
See
40
CFR
49.6.)
2.
EPA
Implementation
The
CAA
also
provides
EPA
with
the
authority
to
administer
Federal
programs
in
Indian
country.
This
authority
is
based
in
part
on
the
general
purpose
of
the
CAA,
which
is
national
in
scope.
Section
301(
a)
of
the
CAA
provides
EPA
broad
authority
to
issue
regulations
that
are
necessary
to
carry
out
the
functions
of
the
CAA.
Congress
intended
for
EPA
to
have
the
authority
to
operate
a
Federal
program
when
Tribes
choose
not
to
develop
a
program,
do
not
adopt
an
approvable
program,
or
fail
to
adequately
implement
an
air
program
authorized
under
section
301(
d)
of
the
CAA.
Section
301(
d)(
4)
of
the
CAA
authorizes
the
Administrator
to
directly
administer
provisions
of
the
CAA
to
achieve
the
appropriate
purpose
where
Tribal
implementation
is
not
appropriate
or
administratively
not
feasible.
The
EPA's
interpretation
of
its
authority
to
directly
implement
Clean
Air
Act
programs
in
Indian
country
is
discussed
in
more
detail
in
the
Tribal
Authority
Rule.
See
63
FR
at
7262
7263.
As
mentioned
previously,
Tribes
may,
but
are
not
required
to,
submit
a
CISWI
plan
under
section
111(
d)
of
the
CAA.
3.
Applicability
in
Indian
Country
The
Federal
plan
would
apply
throughout
Indian
country
except
where
an
EPA
approved
plan
already
covers
an
area
of
Indian
country.
This
approach
is
consistent
with
EPA's
implementation
of
the
Federal
Operating
Permits
program
in
Indian
country
(
see
64
FR
8247
(
February
19,
1999)).
VII.
Title
V
Operating
Permits
Except
for
the
sources
specified
in
section
62.14830
of
this
proposed
rule,
sources
subject
to
this
CISWI
Federal
plan
must
obtain
title
V
operating
permits.
These
title
V
operating
permits
must
assure
compliance
with
all
applicable
requirements
for
these
sources,
including
all
applicable
requirements
of
this
Federal
plan.
See
40
CFR
70.6(
a)(
1),
70.2,
71.6(
a)(
1)
and
71.2.
Owners
or
operators
of
section
129
sources
(
including
CISWI
units)
subject
to
standards
or
regulations
under
sections
111
and
129
must
operate
pursuant
to
a
title
V
permit
not
later
than
36
months
after
promulgation
of
emission
guidelines
under
sections
111
and
129
or
by
the
effective
date
of
the
State,
Tribal,
or
Federal
title
V
operating
permits
program
that
covers
the
area
in
which
the
unit
is
located,
whichever
is
later.
The
EPA
has
interpreted
section
129(
e)
to
be
consistent
with
section
503(
d)
of
the
CAA
and
40
CFR
70.7(
b)
and
71.7(
b).
(
See,
e.
g.,
the
final
Federal
Plan
for
Hospital/
Medical/
Infectious
Waste
Incinerators,
August
15,
2000
(
65
FR
49868,
49878)).
Section
503(
d)
of
the
CAA
and
40
CFR
70.7(
b)
and
71.7(
b)
allow
a
source
to
operate
without
being
in
violation
of
title
V
once
the
source
has
submitted
a
timely
and
complete
permit
application,
even
if
the
source
has
not
yet
received
a
final
title
V
operating
permit
from
the
permitting
authority.
2
As
a
result,
EPA
interprets
the
dates
in
section
129(
e)
to
be
the
dates
by
which
complete
title
V
applications
need
to
be
submitted.
In
the
absence
of
such
an
interpretation,
a
section
129
source
may
be
required
to
prepare
and
submit
a
complete
title
V
application
and
the
permitting
authority
would
have
to
issue
a
permit
to
this
source
in
a
very
short
period
of
time.
3
As
a
result
of
EPA's
interpretation,
existing
CISWI
units
must
submit
complete
title
V
applications
by
the
later
of
the
following
dates:
Not
later
than
36
months
after
the
promulgation
of
40
CFR
part
60,
subpart
DDDD
or
by
the
effective
date
of
the
State,
Tribal,
or
Federal
title
V
operating
permits
program
that
covers
the
area
in
which
the
unit
is
located.
As
of
today's
proposal,
all
areas
of
the
country
are
covered
by
effective
title
V
programs.
As
a
result,
the
relevant
section
129(
e)
date
for
existing
CISWI
units
is
36
months
following
promulgation
of
40
CFR
part
60,
subpart
DDDD,
i.
e.,
December
1,
2003.
Therefore,
December
1,
2003
is
the
latest
possible
date
by
which
complete
applications
for
existing
CISWI
units
can
be
submitted
and
still
be
considered
timely.
This
date
applies
regardless
of
when
the
CISWI
Federal
plan
becomes
effective
or
when
an
EPA
approved
section
111(
d)/
129
plan
for
existing
CISWI
units
becomes
effective.
If,
however,
an
earlier
application
deadline
applies
to
an
existing
CISWI
unit,
then
this
deadline
must
be
met
in
order
for
the
unit
to
be
in
compliance
with
section
502(
a)
of
the
CAA.
To
determine
when
an
application
is
due
for
an
existing
CISWI
unit,
section
129(
e)
of
the
CAA
must
be
read
in
conjunction
with
section
503(
c)
of
the
CAA.
As
stated
in
section
503(
c),
a
source
has
up
to
12
months
to
apply
for
a
title
V
permit
once
it
becomes
subject
to
a
title
V
permitting
program.
4
For
example,
if
an
existing
CISWI
unit
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25,
2002
/
Proposed
Rules
5
See
CAA
section
502(
b)(
9);
40
CFR
70.7(
f)(
1)(
i)
and
71.7(
f)(
1)(
i).
Owners
or
operators
of
CISWI
units,
which
have
been
permitted
and
are
subject
to
this
Federal
plan,
may
wish
to
consult
their
operating
permits
program
regulations
or
permitting
authorities
to
determine
whether
their
permits
must
be
reopened
to
incorporate
the
requirements
of
this
Federal
plan.
becomes
subject
to
a
title
V
permitting
program
for
the
first
time
on
the
effective
date
of
this
Federal
plan,
then
the
source
must
apply
for
a
title
V
permit
within
12
months
of
the
effective
date
of
this
Federal
plan
in
order
to
operate
after
this
date
in
compliance
with
Federal
law.
An
application
deadline
earlier
than
either
of
the
two
dates
noted
above,
i.
e.,
December
1,
2003
or
not
later
than
12
months
after
the
effective
date
of
this
Federal
plan,
may
apply
to
an
existing
CISWI
unit
if
it
is
subject
to
title
V
for
more
than
one
reason.
For
example,
an
existing
CISWI
unit
may
already
be
subject
to
title
V
as
a
result
of
being
a
major
source
under
one
or
more
of
three
major
source
definitions
in
title
V
section
112,
section
302,
or
part
D
of
title
I
of
the
CAA.
See
40
CFR
70.3(
a)(
1)
and
71.3(
a)(
1)
(
subjecting
major
sources
to
title
V
permitting)
and
40
CFR
70.2
and
71.2
(
defining
major
source
for
purposes
of
title
V).
See
also
40
CFR
70.3(
a)
and
(
b)
and
71.3(
a)
and
(
b)
for
a
list
of
the
applicability
criteria
which
trigger
the
requirement
to
apply
for
a
title
V
permit.
If
an
owner
or
operator
is
already
subject
to
title
V
by
virtue
of
some
requirement
other
than
this
Federal
plan
and
has
submitted
a
timely
and
complete
permit
application,
but
the
draft
title
V
permit
has
not
yet
been
released
by
the
permitting
authority,
then
the
owner
or
operator
must
supplement
his
title
V
application
by
including
the
applicable
requirements
of
this
Federal
plan
in
accordance
with
40
CFR
70.5(
b)
or
71.5(
b).
If
an
existing
CISWI
unit
is
a
major
source
or
is
part
of
a
major
source,
is
subject
to
this
Federal
plan,
and
is
already
covered
by
a
title
V
permit
with
a
remaining
permit
term
of
3
or
more
years
on
the
effective
date
of
this
Federal
plan,
then
the
owner
or
operator
will
receive
from
his
permitting
authority
a
notice
of
intent
to
reopen
his
source's
title
V
permit
to
include
the
requirements
of
this
Federal
plan.
Reopenings
required
for
such
CISWI
units
must
be
completed
not
later
than
18
months
after
the
effective
date
of
this
Federal
plan
in
accordance
with
the
procedures
established
in
40
CFR
70.7(
f)(
1)(
i)
or
71.7(
f)(
1)(
i).
If
an
existing
CISWI
unit
subject
to
this
Federal
plan
does
not
meet
the
above
criteria,
e.
g.,
the
unit
is
part
of
a
nonmajor
source
or
is
covered
by
a
permit
which
has
a
remaining
term
of
less
than
3
years
on
the
effective
date
of
this
Federal
plan,
then
the
permitting
authority
does
not
need
to
reopen
the
source's
permit,
as
a
matter
of
Federal
law,
to
include
the
requirements
of
this
Federal
plan.
5
However,
the
owner
or
operator
of
a
source
subject
to
a
section
111/
129
Federal
plan
remains
subject
to,
and
must
act
in
compliance
with,
section
111/
129
requirements
and
all
other
applicable
requirements
to
which
the
source
is
subject
regardless
of
whether
these
requirements
are
included
in
a
title
V
permit.
See
40
CFR
70.6(
a)(
1),
70.2,
71.6(
a)(
1)
and
71.2.
The
EPA
has
recently
become
aware
that
there
has
been
some
confusion
regarding
the
Title
V
obligations
of
section
129
sources
that
are
subject
to
standards
or
regulations
under
sections
111
and
129.
We
are
therefore
including
the
following
chart
to
help
clarify
when
CISWI
units
(
even
those
not
subject
to
this
Federal
plan)
must
apply
for
a
title
V
permit.
While
the
following
chart
provides
specific
information
relative
to
CISWI
units,
the
same
title
V
obligations
apply
to
all
section
129
sources
subject
to
standards
or
regulations
under
sections
111
and
129.
Of
course,
specific
deadlines
will
vary
for
other
section
129
sources
depending
on
when
the
relevant
NSPS
is
promulgated,
when
the
relevant
State
or
Tribal
section
111(
d)/
129
plan
is
approved
by
EPA
and
becomes
effective,
etc.
Lastly,
the
following
table
takes
into
account
that
as
of
the
promulgation
date,
i.
e.,
December
1,
2000,
for
the
NSPS
(
subpart
CCCC
of
part
60)
and
emission
guidelines
(
subpart
DDDD
of
part
60)
for
CISWI
units,
every
area
of
the
country
was
covered
by
a
title
V
permits
program
under
40
CFR
part
70
or
part
71.
This
point
is
relevant
because
a
section
111/
129
standard
cannot
trigger
the
requirement
for
a
source
to
apply
for
a
title
V
permit
unless
a
title
V
permits
program
is
in
effect
in
the
area
in
which
the
source
is
located.
Title
V
Permit
Application
Deadlines
If
a
CISWI
unit
is
a
major
source
or
is
part
of
a
major
source,
and
had
commenced
operation
as
of
the
effective
date
of
the
relevant
title
V
permits
program,
Then
a
complete
title
V
application
which
covers
the
entire
source
6
is
due
not
later
than
12
months
(
or
earlier
if
required
by
the
title
V
permitting
authority)
after
the
effective
date
of
the
relevant
title
V
permits
program.
See
CAA
section
503(
c)
and
40
CFR
70.4(
b)(
11)(
i),
71.4(
i)(
1),
70.5(
a)(
1)(
i)
and
71.5(
a)(
1)(
i).
If
a
CISWI
unit
is
a
major
source
or
is
part
of
a
major
source,
but
did
not
commence
operation
until
after
the
relevant
title
V
permits
program
became
effective,
Then
a
complete
title
V
application
which
covers
the
entire
source
is
due
not
later
than
12
months
(
or
earlier
if
required
by
the
title
V
permitting
authority)
after
the
date
the
source
commences
operation.
See
CAA
section
503(
c)
and
40
CFR
70.5(
a)(
1)(
i)
and
71.5(
a)(
1)(
i).
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No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
If
a
CISWI
unit
is
a
nonmajor
source
or
is
part
of
a
nonmajor
source,
is
subject
to
the
CISWI
NSPS
(
subpart
CCCC
of
40
CFR
part
60),
and
had
commenced
operation
as
of
December
1,
2000,
Then
a
complete
title
V
application
7
is
due
not
later
than
12
months
after
subpart
CCCC
was
promulgated,
i.
e.,
December
1,
2001
(
or
earlier
if
required
by
the
title
V
permitting
authority).
See
CAA
section
503(
c)
and
40
CFR
70.5(
a)(
1)(
i)
and
71.5(
a)(
1)(
i).
If
a
CISWI
unit
is
a
nonmajor
source
or
is
part
of
a
nonmajor
source,
is
subject
to
the
CISWI
NSPS
(
subpart
CCCC
of
40
CFR
part
60),
but
did
not
commence
operation
until
after
December
1,
2000,
Then
a
complete
title
V
application
7
is
due
not
later
than
12
months
(
or
earlier
if
required
by
the
title
V
permitting
authority)
after
the
date
the
source
commences
operation.
See
CAA
section
503(
c)
and
40
CFR
70.5(
a)(
1)(
i)
and
71.5(
a)(
1)(
i).
If
a
CISWI
unit
is
a
nonmajor
source
or
is
part
of
a
nonmajor
source,
and
is
subject
to
an
EPA
approved
and
effective
State
or
Tribal
section
111(
d)/
129
plan,
Then
a
complete
title
V
application
is
due
not
later
than
12
months
(
or
earlier
if
required
by
the
title
V
permitting
authority)
after
the
effective
date
of
the
EPA
approved
State
or
Tribal
section
11(
d)/
129
plan.
8
See
CAA
section
503(
c)
and
40
CFR
70.5(
a)(
1)(
i)
and
71.5(
a)(
1)(
i).
In
no
event,
however,
can
such
an
existing
CISWI
unit
submit
a
complete
title
V
application
after
December
1,
2003
and
have
it
be
considered
timely.
See
CAA
section
129(
e)
and
40
CFR
62.14835
of
subpart
III.
If
a
CISWI
unit
is
a
nonmajor
source
or
is
part
of
a
nonmajor
source,
and
is
subject
to
the
CISWI
Federal
plan
(
subpart
III
of
40
CFR
part
62),
Then
a
complete
title
V
application
is
due
not
later
than
12
months
(
or
earlier
if
required
by
the
title
V
permitting
authority)
after
the
effective
date
of
40
CFR
part
62,
subpart
III.
See
CAA
section
503(
c)
and
40
CFR
70.5(
a)(
1)(
i)
and
71.5(
a)(
1)(
i).
In
no
event,
however,
can
such
an
existing
CISWI
unit
submit
a
complete
title
V
application
after
December
1,
2003
and
have
it
be
considered
timely.
See
CAA
section
129(
e)
and
40
CFR
62.14835
of
subpart
III.
If
a
CISWI
unit
is
required
to
obtain
a
title
V
permit
due
to
triggering
more
than
one
of
the
applicability
criteria
listed
above
or
in
40
CFR
70.3(
a)
or
71.3(
a),
Then
a
complete
title
V
application
is
due
not
later
than
12
months
(
or
earlier
if
required
by
the
title
V
permitting
authority)
after
the
unit
triggers
the
criterion
which
first
caused
the
unit
to
be
subject
to
title
V.
See
CAA
section
503(
c)
and
40
CFR
70.3(
a)
and
(
b),
70.5(
a)(
1),
71.3(
a)
and
(
b)
and
71.5(
a)(
1).
In
no
event,
however,
can
an
existing
CISWI
unit
submit
a
complete
title
V
application
after
December
1,
2003
and
have
it
be
considered
timely.
See
CAA
section
129(
e)
and
40
CFR
62.14835
of
subpart
III.
Reopening
Title
V
Permits
If
a
CISWI
unit
is
a
major
source
or
is
part
of
a
major
source,
is
subject
to
the
CISWI
NSPS
(
subpart
CCCC
of
40
CFR
part
60),
and
is
covered
by
a
title
V
permit
with
a
remaining
permit
term
of
3
or
more
years
on
December
1,
2000,
Then
the
title
V
permitting
authority
must
complete
a
reopening
of
the
source's
title
V
permit
to
incorporate
the
requirements
of
40
CFR
part
60,
subpart
CCCC
not
later
than
June
1,
2002.
See
CAA
section
502(
b)(
9);
40
CFR
70.7(
f)(
1)(
i)
and
71.7(
f)(
1)(
i).
If
a
CISWI
unit
is
a
major
source
or
is
part
of
a
major
source,
is
subject
to
an
EPA
approved
and
effective
State
or
Tribal
section
111(
d)/
129
plan
for
CISWI
units,
and
is
covered
by
a
title
V
permit
with
a
remaining
term
of
3
or
more
years
on
the
effective
date
of
the
EPA
approved
section
111(
d)/
129
plan,
Then
the
title
V
permitting
authority
must
complete
a
reopening
of
the
source's
title
V
permit
to
incorporate
the
requirements
of
this
EPA
approved
and
effective
section
111(
d)/
129
plan
not
later
than
18
months
after
the
effective
date
of
this
plan.
See
CAA
section
502(
b)(
9);
40
CFR
70.7(
f)(
1)(
i)
and
71.7(
f)(
1)(
i).
If
a
CISWI
unit
is
a
major
source
or
is
part
of
a
major
source,
is
subject
to
the
CISWI
Federal
plan
(
supbart
III
of
40
CFR
part
62),
and
is
covered
by
a
title
V
permit
with
a
remaining
permit
term
of
3
or
more
years
on
the
effective
date
of
this
Federal
plan,
Then
the
title
V
permitting
authority
must
complete
a
reopening
of
the
source's
title
V
permit
to
incorporate
the
requirements
of
subpart
III
of
40
CFR
part
62
not
later
than
18
months
after
the
effective
date
of
the
CISWI
Federal
plan.
See
CAA
section
502(
b)(
9);
40
CFR
70.7(
f)(
1)(
i)
and
71.7(
f)(
1)(
i).
Updating
Existing
Title
V
Permit
Applications
If
a
CISWI
unit
is
subject
to
the
CISWI
NSPS
(
subpart
CCCC
of
40
CFR
part
60),
but
first
became
subject
to
title
V
permitting
prior
to
the
promulgation
of
this
NSPS,
and
the
owner
or
operator
of
the
unit
has
submitted
a
timely
and
complete
title
V
permit
application,
but
the
draft
title
V
permit
has
not
yet
been
released
by
the
permitting
authority,
Then
the
owner
or
operator
must
supplement
the
title
V
application
by
including
the
applicable
requirements
of
40
CFR
part
60,
subpart
CCCC
in
accordance
with
40
CFR
70.5(
b)
or
71.5(
b).
If
a
CISWI
unit
is
subject
to
an
EPA
approved
and
effective
State
or
Tribal
section
111(
d)/
129
plan
for
CISWI
units,
but
first
became
subject
to
title
V
permitting
prior
to
the
effective
date
of
the
section
111(
d)/
129
plan,
and
the
owner
or
operator
of
the
unit
has
submitted
a
timely
and
complete
title
V
permit
application,
but
the
draft
title
V
permit
has
not
yet
been
released
by
the
permitting
authority,
Then
the
owner
or
operator
must
supplement
the
title
V
application
by
including
the
applicable
requirements
of
the
approved
and
effective
section
111(
d)/
129
plan
in
accordance
with
40
CFR
70.5(
b)
or
71.5(
b).
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Register
/
Vol.
67,
No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
9
An
owner
or
operator
of
a
source
subject
to
a
section
111/
129
Federal
plan
remains
subject
to,
and
must
act
in
compliance
with,
section
111/
129
requirements
and
all
other
applicable
requirements
to
which
the
source
is
subject
regardless
of
whether
these
requirements
are
included
in
a
title
V
permit.
See
40
CFR
70.6(
a)(
1),
70.2,
71.6(
a)(
1)
and
71.2.
10
Under
40
CFR
70.4(
b)(
3)(
iv),
permitting
authorities
are
allowed
to
issue
permits
for
solid
waste
incineration
units
combusting
municipal
waste
subject
to
standards
under
section
129(
e)
of
the
Act
for
a
period
not
to
exceed
12
years,
provided
that
the
permits
are
reviewed
at
least
every
5
years.
Permits
with
acid
rain
provisions
must
be
issued
for
a
fixed
term
of
five
years;
shorter
terms
for
such
permits
are
not
allowed.
11
If
the
Administrator
chooses
to
retain
certain
authorities
under
a
standard,
those
authorities
cannot
be
delegated,
e.
g.,
alternative
methods
of
demonstrating
compliance.
12
The
EPA
interprets
the
phrase
``
assure
compliance''
in
section
502(
b)(
5)(
A)
to
mean
that
permitting
authorities
will
implement
and
enforce
If
a
CISWI
unit
is
subject
to
the
CISWI
Federal
plan
(
subpart
III
of
40
CFR
part
62),
but
first
became
subject
to
title
V
permitting
prior
to
the
effective
date
of
this
Federal
plan,
and
the
owner
or
operator
of
the
unit
has
submitted
a
timely
and
complete
title
V
permit
application,
but
the
draft
title
V
permit
has
not
yet
been
released
by
the
permitting
authority,
Then
the
owner
or
operator
must
supplement
the
title
V
application
by
including
the
applicable
requirements
of
40
CFR
part
62,
subpart
III
in
accordance
with
40
CFR
70.5(
b)
or
71.5(
b).
6
A
title
V
application
from
a
major
source
must
address
all
emissions
units
at
the
title
V
source,
not
just
the
section
129
emissions
unit.
See
40
CFR
70.3(
c)(
1)
and
71.3(
c)(
1).
(
For
information
on
aggregating
emissions
units
to
determine
what
is
a
source
under
title
V,
see
the
definition
of
major
source
in
40
CFR
70.2,
71.2,
and
63.2.)
7
Consistent
with
40
CFR
70.3(
c)(
2)
and
71.3(
c)(
2),
a
permit
application
from
a
nonmajor
title
V
source
is
only
required
to
address
the
emissions
units
which
caused
the
source
to
be
subject
to
title
V.
The
requirements
which
trigger
the
need
for
the
owner
or
operator
of
a
nonmajor
source
to
apply
for
a
title
V
permit
are
found
in
40
CFR
70.3(
a)
and
(
b)
and
71.3(
a)
and
(
b).
Permits
issued
to
these
nonmajor
sources
must
include
all
of
the
applicable
requirements
that
apply
to
the
triggering
units,
e.
g.,
State
Implementation
Plan
requirements,
not
just
the
requirements
which
caused
the
source
to
be
subject
to
title
V.
See
footnote
#
2
in
Change
to
Definition
of
Major
Source
rule,
November
27,
2001
(
66
FR
59161,
59163).
8
If
a
CISWI
unit
becomes
subject
to
an
approved
and
effective
State
or
Tribal
section
111(
d)/
129
plan
after
being
subject
to
an
effective
Federal
plan,
the
CISWI
unit
is
still
required
to
file
a
complete
title
V
application
consistent
with
the
application
deadlines
for
units
subject
to
the
CISWI
Federal
plan.
Title
V
and
Delegation
of
a
Federal
Plan
During
the
development
of
the
Federal
plan
for
Hospital/
Medical/
Infectious
Waste
Incinerators
(
HMIWI),
a
State
agency
raised
the
question
of
whether
a
title
V
operating
permits
program
could
be
used
as
a
mechanism
for
transferring
the
authority
to
implement
and
enforce
section
111/
129
requirements
from
EPA
to
State
and
local
agencies.
See
``
Transfer
of
Authority''
section
of
final
Federal
plan
for
HMIWI,
August
15,
2000
(
65
FR
49868,
49873).
The
State
agency
noted
that
the
proposal
for
that
rulemaking
described
two
mechanisms
for
transferring
authority
to
State
and
local
agencies
following
promulgation
of
the
Federal
plan.
Those
two
mechanisms
were:
(
1)
The
approval
of
a
State
or
Tribal
plan
after
the
Federal
plan
is
in
effect;
and
(
2)
if
a
State
or
Tribe
does
not
submit
or
obtain
approval
of
its
own
plan,
EPA
delegation
to
a
State
or
Tribe
of
the
authority
to
implement
and
enforce
the
HMIWI
Federal
plan.
The
State
asked
EPA
to
recognize
the
Title
V
operating
permits
program
as
a
third
mechanism
for
transferring
authority
to
State
and
local
agencies.
The
commenter
said
that
State
and
local
agencies
implement
Title
V
programs
and
that
Title
V
permits
must
include
the
requirements
of
the
Federal
plan.
The
commenter
concluded
that
Title
V
permitting
authorities
already
have
implementation
responsibility
for
the
Federal
plan
through
their
Title
V
permits
programs,
regardless
of
whether
the
authority
to
implement
the
Federal
plan
is
delegated
to
the
State
or
local
agency.
In
its
response
to
the
State,
the
EPA
explained
why
the
issuance
of
a
Title
V
permit
is
not
equivalent
to
the
approval
of
a
State
plan
or
delegation
of
a
Federal
plan
by
focusing
on
situations
in
which
a
Title
V
permitting
authority
without
delegation
of
a
Federal
plan
could
not
implement
and
enforce
section
111/
129
requirements.
This
situation
would
arise
any
time
a
Title
V
permit
was
not
in
effect
for
a
source
subject
to
the
section
111/
129
Federal
plan
or
where
the
permit
did
not
contain
the
applicable
section
111/
129
requirements.
For
example,
a
title
V
source
may
be
allowed
to
operate
without
a
title
V
permit
for
a
number
of
years
in
some
cases
between
the
time
the
source
first
triggers
the
requirement
to
apply
for
a
permit
and
the
issuance
of
the
permit.
The
preamble
to
the
final
HMIWI
Federal
plan
also
noted
that
a
source
with
a
Title
V
permit
with
a
permit
term
less
than
3
years
is
not
required
by
part
70
to
have
its
permit
reopened
by
a
State
or
Tribe
to
include
new
applicable
requirements
such
as
the
HMIWI
standard.
9
See
40
CFR
70.7(
f)(
1)(
i).
In
addition
to
the
explanation
provided
in
the
preamble
to
the
final
HMIWI
Federal
plan,
there
are
additional
State
implementation
and
enforcement
gaps
which
would
not
be
addressed
by
implementing
and
enforcing
the
section
111/
129
standard
through
a
Title
V
permit.
The
following
is
an
example
of
such
a
gap:
Title
V
permits
are
not
permanent.
With
two
exceptions,
all
permits
must
be
renewed
at
least
every
5
years
10.
Although
40
CFR
70.4(
b)(
10)
requires
States
to
provide
that
a
permit
or
the
terms
and
conditions
of
a
permit
may
not
expire
until
the
permit
is
renewed,
this
requirement
only
applies
if
a
timely
and
complete
application
for
a
renewal
permit
has
been
submitted
by
the
source,
creating
a
potential
gap.
In
contrast
to
the
example,
the
two
mechanisms
that
EPA
has
identified
for
transferring
authority
ensure
that
a
State
or
Tribe
can
implement
and
enforce
the
section
111/
129
standards
at
all
times.
Legally,
delegation
of
a
standard
or
requirement
results
in
a
delegated
State
or
Tribe
standing
in
for
EPA
as
a
matter
of
Federal
law.
This
means
that
obligations
a
source
may
have
to
the
EPA
under
a
federally
promulgated
standard
become
obligations
to
a
State
(
except
for
functions
that
the
EPA
retains
for
itself)
upon
delegation.
11
Although
a
State
or
Tribe
may
have
the
authority
to
incorporate
section
111/
129
requirements
into
its
title
V
permits,
and
implement
and
enforce
these
requirements
in
these
permits
without
first
taking
delegation
of
the
section
111/
129
Federal
plan,
the
State
or
Tribe
is
not
standing
in
for
EPA
as
a
matter
of
Federal
law
in
this
situation.
Where
a
State
or
Tribe
does
not
take
delegation
of
a
section
111/
129
Federal
plan,
obligations
that
a
source
has
to
EPA
under
the
Federal
plan
continue
after
a
title
V
permit
is
issued
to
the
source.
As
a
result,
the
EPA
continues
to
maintain
that
an
approved
part
70
operating
permits
program
cannot
be
used
as
a
mechanism
to
transfer
the
authority
to
implement
and
enforce
the
Federal
plan
from
the
EPA
to
a
State
or
Tribe.
As
mentioned
above,
a
State
or
Tribe
may
have
the
authority
under
State
or
Tribal
law
to
incorporate
section
111/
129
requirements
into
its
title
V
permits,
and
implement
and
enforce
these
requirements
in
that
context
without
first
taking
delegation
of
the
section
111/
129
Federal
plan.
12
Some
States
or
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/
Vol.
67,
No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
each
applicable
standard,
regulation,
or
requirement
which
must
be
included
in
the
title
V
permits
the
permitting
authorities
issue.
See
definition
of
``
applicable
requirement''
in
40
CFR
70.2.
See
also
40
CFR
70.4(
b)(
3)(
i)
and
70.6(
a)(
1).
13
It
is
important
to
note
that
an
AG's
opinion
submitted
at
the
time
of
initial
title
V
program
approval
is
sufficient
if
it
demonstrates
that
a
State
or
Tribe
has
adequate
authority
to
incorporate
section
111/
129
requirements
into
its
title
V
permits,
and
to
implement
and
enforce
these
requirements
through
its
title
V
permits
without
delegation.
Tribes,
however,
may
not
be
able
to
implement
and
enforce
a
section
111/
129
standard
in
a
title
V
permit
until
the
section
111/
129
standard
has
been
delegated.
In
these
situations,
a
State
or
Tribe
should
not
issue
a
part
70
permit
to
a
source
subject
to
a
Federal
plan
before
taking
delegation
of
the
section
111/
129
Federal
plan.
If
a
State
or
Tribe
can
provide
an
Attorney
General's
(
AG's)
opinion
delineating
its
authority
to
incorporate
section
111/
129
requirements
into
its
Title
V
permits,
and
then
implement
and
enforce
these
requirements
through
its
Title
V
permits
without
first
taking
delegation
of
the
requirements,
then
a
State
or
Tribe
does
not
need
to
take
delegation
of
the
section
111/
129
requirements
for
purposes
of
title
V
permitting.
13
In
practical
terms,
without
approval
of
a
State
or
Tribal
plan,
delegation
of
a
Federal
plan,
or
an
adequate
AG's
opinion,
States
and
Tribes
with
approved
part
70
permitting
programs
open
themselves
up
to
potential
questions
regarding
their
authority
to
issue
permits
containing
section
111/
129
requirements,
and
to
assure
compliance
with
these
requirements.
Such
questions
could
lead
to
the
issuance
of
a
notice
of
deficiency
for
a
State's
or
Tribe's
part
70
program.
As
a
result,
prior
to
a
State
or
Tribal
permitting
authority
drafting
a
part
70
permit
for
a
source
subject
to
a
section
111/
129
Federal
plan,
the
State
or
Tribe,
EPA
Regional
Office,
and
source
in
question
are
advised
to
ensure
that
delegation
of
the
relevant
Federal
plan
has
taken
place
or
that
the
permitting
authority
has
provided
to
the
EPA
Regional
Office
an
adequate
AG's
opinion.
In
addition,
if
a
permitting
authority
chooses
to
rely
on
an
AG's
opinion
and
not
take
delegation
of
a
Federal
plan,
a
section
111/
129
source
subject
to
the
Federal
plan
in
that
State
must
simultaneously
submit
to
both
EPA
and
the
State
or
Tribe
all
reports
required
by
the
standard
to
be
submitted
to
the
EPA.
Given
that
these
reports
are
necessary
to
implement
and
enforce
the
section
111/
129
requirements
when
they
have
been
included
in
title
V
permits,
the
permitting
authority
needs
to
receive
these
reports
at
the
same
time
as
the
EPA.
In
the
situation
where
a
permitting
authority
chooses
to
rely
on
an
AG's
opinion
and
not
take
delegation
of
a
Federal
plan,
EPA
Regional
Offices
will
be
responsible
for
implementing
and
enforcing
section
111/
129
requirements
outside
of
any
title
V
permits.
Moreover,
in
this
situation,
EPA
Regional
Offices
will
continue
to
be
responsible
for
developing
progress
reports,
entering
emissions
data
into
the
Aerometric
Information
Retrieval
System
(
AIRS)/
AIRS
Facility
Subsystem
(
AFS),
and
conducting
any
other
administrative
functions
required
under
this
Federal
plan
or
any
other
section
111/
129
Federal
plan.
See
Section
III.
J.
of
this
preamble
titled
``
Progress
Reports';
section
II.
J.
of
the
proposed
Federal
plan
for
HMIWI,
July
6,
1999
(
64
FR
36426,
36431);
40
CFR
60.25(
e),
and
Appendix
D
of
40
CFR
part
60.
It
is
important
to
note
that
the
EPA
is
not
using
its
authority
under
40
CFR
70.4(
i)(
3)
to
request
that
all
States
and
Tribes
which
do
not
take
delegation
of
this
Federal
plan
submit
supplemental
AG's
opinions
at
this
time.
However,
the
EPA
Regional
Offices
shall
request,
and
permitting
authorities
shall
provide,
such
opinions
when
the
EPA
questions
a
State's
or
Tribe's
authority
to
incorporate
section
111/
129
requirements
into
a
title
V
permit,
and
implement
and
enforce
these
requirements
in
that
context
without
delegation.
Lastly,
the
EPA
would
like
to
correct
and
clarify
the
following
sentences
from
the
``
Transfer
of
Authority''
section
of
the
preamble
to
the
final
HMIWI
Federal
plan
(
65
FR
49868,
49873):
``
Prior
to
delegation,
only
the
EPA
will
have
enforcement
authority.
In
neither
instance
does
the
title
V
permit
status
of
a
source
affect
the
enforcement
responsibility
of
EPA
and
the
State
or
Tribal
permitting
authorities.''
In
situations
where
a
State
or
Tribe
is
subject
to
a
section
111/
129
Federal
plan
and
does
not
take
delegation
of
the
Federal
plan,
the
following
applies:
Prior
to
delegation,
only
EPA
can
implement
and
enforce
section
111/
129
requirements
outside
of
a
title
V
permit.
Whenever
there
is
a
title
V
permit
in
effect
which
includes
section
111/
129
requirements,
however,
EPA
and
the
State
or
Tribe
have
dual
authority
to
implement
and
enforce
the
section
111/
129
requirements
in
the
title
V
permit.
When
a
State
or
Tribe
has
not
taken
delegation
of
a
section
111/
129
Federal
plan,
the
previous
sentence
is
relevant
only
in
situations
where
a
State
or
Tribe
has
the
authority
to
incorporate
section
111/
129
requirements
into
title
V
permits,
and
to
implement
and
enforce
these
requirements
in
title
V
permits
without
delegation.
VIII.
Administrative
Requirements
This
section
addresses
the
following
administrative
requirements:
Docket,
Public
Hearing,
Executive
Orders
12866,
13132,
13175,
13045,
and
13211,
Unfunded
Mandates
Reform
Act,
Regulatory
Flexibility
Act,
Regulatory
Flexibility
Act/
Small
Business
Regulatory
Enforcement
Fairness
Act,
Paperwork
Reduction
Act,
and
the
National
Technology
Transfer
and
Advancement
Act.
Since
today's
rule
simply
proposes
to
implement
the
CISWI
emission
guidelines
(
40
CFR
part
60,
subpart
DDDD)
as
promulgated
on
December
1,
2000,
and
does
not
impose
any
new
requirements,
much
of
the
following
discussion
of
administrative
requirements
refers
to
the
documentation
of
applicable
administrative
requirements
as
discussed
in
the
preamble
to
the
rule
promulgating
the
emission
guidelines
(
65
FR
75338,
December
1,
2000).
A.
Docket
The
docket
is
intended
to
be
an
organized
and
complete
file
of
the
administrative
records
compiled
by
EPA.
The
docket
is
a
dynamic
file
because
material
is
added
throughout
the
rulemaking
process.
The
docketing
system
is
intended
to
allow
members
of
the
public
and
industries
involved
to
readily
identify
and
locate
documents
so
they
can
effectively
participate
in
the
rulemaking
process.
Along
with
proposed
and
promulgated
standards
and
their
preambles,
the
contents
of
the
docket
(
with
limited
exceptions)
will
serve
as
the
record
in
the
case
of
judicial
review.
See
section
307(
d)(
7)(
A)
of
the
CAA.
As
discussed
above,
a
docket
has
been
prepared
for
this
action
pursuant
to
the
procedural
requirements
of
section
307(
d)
of
the
CAA,
42
U.
S.
C.
7607(
d).
Supporting
information
is
included
in
Docket
A
2000
52.
Docket
number
A
94
63
contains
the
technical
support
for
the
final
emission
guidelines,
40
CFR
part
60,
subpart
DDDD.
Docket
A
2000
52
incorporates
all
of
the
information
in
Docket
A
94
63.
B.
Public
Hearing
A
public
hearing
will
be
held,
if
requested,
to
discuss
the
proposed
standards
in
accordance
with
section
307(
d)(
5)
of
the
CAA.
Persons
wishing
to
make
oral
presentations
on
the
proposed
standards
should
contact
EPA
(
see
ADDRESSES).
If
a
public
hearing
is
requested
and
held,
EPA
will
ask
clarifying
questions
during
the
oral
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presentation
but
will
not
respond
to
the
presentations
or
comments.
To
provide
an
opportunity
for
all
who
may
wish
to
speak,
oral
presentations
will
be
limited
to
15
minutes
each.
Any
member
of
the
public
may
file
a
written
statement
on
or
before
January
24,
2003.
Written
statements
should
be
addressed
to
the
Air
and
Radiation
Docket
and
Information
Center
(
see
ADDRESSES),
and
refer
to
Docket
No.
A
2000
52.
Written
statements
and
supporting
information
will
be
considered
with
equivalent
weight
as
any
oral
statement
and
supporting
information
subsequently
presented
at
a
public
hearing,
if
held.
A
verbatim
transcript
of
the
hearing
and
written
statements
will
be
placed
in
the
docket
and
be
available
for
public
inspection
and
copying,
or
mailed
upon
request,
at
the
Air
and
Radiation
Docket
and
Information
Center
(
see
ADDRESSES).
C.
Executive
Order
12866:
Regulatory
Planning
and
Review
Under
Executive
Order
12866,
58
FR
51735
(
October
4,
1993),
EPA
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
impacts
of
entitlements,
grants,
user
fees,
or
loan
programs
or
the
rights
and
obligations
of
recipients
thereof;
or
(
4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
The
EPA
considered
the
2000
emission
guidelines
to
be
significant
and
the
rules
were
reviewed
by
OMB
in
2000.
See
65
FR
75338,
December
1,
2000.
The
Federal
plan
promulgated
today
would
simply
implement
the
2000
emission
guidelines
and
does
not
result
in
any
additional
control
requirements
or
impose
any
additional
costs
above
those
previously
considered
during
promulgation
of
the
2000
emission
guidelines.
Therefore,
this
regulatory
action
is
considered
``
not
significant''
under
Executive
Order
12866.
D.
Executive
Order
13132:
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
us
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
are
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
This
proposed
rule
does
not
have
Federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
This
rule
establishes
emission
limits
and
other
requirements
for
solid
waste
incineration
units
that
are
not
covered
by
an
EPA
approved
and
effective
State
or
Tribal
plan.
The
EPA
is
required
by
section
129
of
the
CAA,
42
U.
S.
C.
7429,
to
establish
the
standards
for
such
units.
This
regulation
primarily
affects
private
industry
and
does
not
impose
significant
economic
costs
on
State
or
local
governments.
The
standards
established
by
this
rule
apply
to
facilities
that
operate
commercial
or
industrial
solid
waste
incineration
units
located
in
States
that
do
not
have
EPAapproved
plans
covering
such
units
by
the
effective
date
of
the
promulgated
Federal
plan
(
and
the
owners
or
operators
of
such
facilities).
The
regulation
does
not
include
an
express
provision
preempting
State
or
local
regulations.
However,
once
this
Federal
plan
is
in
effect,
covered
facilities
would
be
subject
to
the
standards
established
by
this
rule,
regardless
of
any
less
protective
State
or
local
regulations
that
contain
emission
limitations
for
the
pollutants
addressed
by
this
rule.
To
the
extent
that
this
might
preempt
State
or
local
regulations,
it
does
not
significantly
affect
the
relationship
between
the
national
government
and
the
States,
or
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
this
rule;
and
EPA
has
complied
with
the
requirements
of
section
4(
e),
to
the
extent
that
they
may
be
applicable
to
the
regulations,
by
providing
notice
to
potentially
affected
State
and
local
officials
through
publication
of
this
rule.
Although
section
6
of
Executive
Order
13132
does
not
apply
to
this
rule,
EPA
consulted
with
representatives
of
State
and
local
governments
to
enable
them
to
provide
meaningful
and
timely
input
into
the
development
of
the
CISWI
emission
guidelines.
This
consultation
took
place
during
the
Industrial
Combustion
Coordinated
Rulemaking
Federal
Advisory
Committee
Act
committee
meetings,
where
members
representing
State
and
local
governments
participated
in
developing
recommendations
for
our
combustionrelated
rulemakings,
including
the
CISWI
emission
guidelines.
Additionally,
EPA
sponsored
the
Small
Communities
Outreach
Project,
which
involved
meetings
with
elected
officials
and
other
government
representative
to
provide
them
with
information
about
the
CISWI
emission
guidelines
and
to
solicit
their
comments.
The
concerns
raised
by
representative
of
State
and
local
governments
were
considered
during
the
development
of
the
CISWI
emission
guidelines.
In
the
spirit
of
Executive
Order
13132,
and
consistent
with
EPA
policy
to
promote
communications
between
EPA
and
State
and
local
governments,
EPA
specifically
solicits
comment
on
this
proposed
rule
from
State
and
local
officials.
E.
Executive
Order
13175:
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
``
Policies
that
have
tribal
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
the
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes.''
This
proposed
rule
does
not
have
tribal
implications.
It
will
not
have
substantial
direct
effects
on
tribal
governments,
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
The
EPA
knows
of
no
CISWI
units
presently
owned
by
Indian
tribal
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governments.
However,
if
any
exist
now
or
in
the
future,
the
rule
would
not
have
tribal
implications
on
these
tribal
governments
as
defined
by
the
Executive
Order.
This
Federal
plan
simply
implements
the
2000
emission
guidelines.
It
does
not
result
in
any
additional
control
requirements
nor
imposes
any
additional
costs
above
those
previously
considered
during
promulgation
of
the
2000
emission
guidelines.
Thus,
the
requirements
of
Executive
Order
13175
do
not
apply.
F.
Executive
Order
13045:
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
disproportionately
affect
children.
If
the
regulatory
action
meets
these
criteria,
EPA
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
EPA
considered.
The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
501
of
the
Order
has
the
potential
to
influence
the
regulation.
This
proposed
rule
is
not
subject
to
Executive
Order
13045
because
it
is
based
on
technology
performance
and
not
on
health
or
safety
risks.
Additionally,
this
proposed
rule
is
not
economically
significant
as
defined
by
Executive
Order
12866.
G.
Executive
Order
13211:
Energy
Effects
This
rule
is
not
subject
to
Executive
Order
13211,
``
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(
66
F.
R.
28355
(
May
22,
2001))
because
it
is
not
a
significant
regulatory
action
under
Executive
Order
12866.
H.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
a
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
us
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
us
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
of
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
EPA
must
develop
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
thereby
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
the
regulatory
proposal
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
The
EPA
has
determined
that
this
rule
does
not
contain
a
Federal
mandate
that
may
result
in
expenditures
of
$
100
million
or
more
for
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
The
environmental
impact
analysis
for
the
emission
guidelines
estimates
the
total
national
annualized
cost
impact
of
this
regulatory
action
at
$
11.6
million
per
year
(
Docket
A
94
63).
This
proposed
Federal
plan
will
apply
to
only
a
subset
of
the
units
considered
in
the
environmental
impacts
analysis
for
the
emission
guidelines.
Thus,
this
rule
is
not
subject
to
the
requirements
of
sections
202
and
205
of
the
UMRA.
Additionally,
EPA
has
determined
that
this
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments,
because
commercial
and
industrial
units
are
not
likely
to
be
owned
by
small
governments.
I.
Regulatory
Flexibility
Act/
Small
Business
Regulatory
Enforcement
Fairness
Act
(
SBREFA)
The
Regulatory
Flexibility
Act
(
RFA)
of
1980,
as
amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
(
SBREFA),
5
U.
S.
C.
601
et
seq.,
generally
requires
Federal
agencies
to
conduct
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements,
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
businesses,
small
not
for
profit
enterprises,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
A
small
business
that
has
less
than
500
employees;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
for
profit
enterprise
that
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
The
SBA
guidelines
define
a
small
business
based
on
number
of
employees
or
annual
revenues
and
the
size
standards
vary
from
industry
to
industry.
Generally,
businesses
covered
by
the
North
American
Industrial
Classification
System
(
NAICS)
codes
affected
by
this
rule
are
considered
small
if
they
have
less
than
500
employees
or
less
than
$
5
million
in
annual
sales.
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
During
the
2000
CISWI
emission
guidelines
rulemaking,
EPA
determined
that
based
on
the
low
number
of
affected
small
entities
in
each
individual
market,
the
alternative
method
of
waste
disposal
available,
and
the
relatively
low
control
cost,
the
CISWI
emission
guidelines
should
not
generate
a
significant
small
business
impact
on
a
substantial
number
of
small
entities
in
the
commercial
and
industrial
sectors.
The
EPA
determined
that
it
was
not
necessary
to
prepare
a
regulatory
flexibility
analysis
in
connection
with
the
final
emission
guidelines.
The
EPA
has
also
determined
that
the
final
emission
guidelines
would
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities
(
65
FR
75348).
This
Federal
plan
would
not
establish
any
new
requirements.
Therefore,
pursuant
to
the
provisions
of
5
U.
S.
C.
605(
b),
EPA
has
determined
that
this
proposed
Federal
plan
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities,
and
thus
a
regulatory
flexibility
analysis
is
not
required.
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/
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25,
2002
/
Proposed
Rules
J.
Paperwork
Reduction
Act
The
information
collection
requirements
have
been
submitted
for
approval
to
OMB
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
An
information
collection
request
(
ICR)
document
has
been
prepared
for
the
emission
guidelines
(
ICR
No.
1927.02
for
subpart
DDDD)
and
copies
may
be
obtained
from
Susan
Auby
by
mail
at
U.
S.
Environmental
Protection
Agency,
Office
of
Environmental
Information;
Collection
Strategies
Division
(
2822T);
1200
Pennsylvania
Avenue,
NW.;
Washington,
DC
20460,
by
e
mail
at
auby.
susan@
epa.
gov,
or
by
calling
(
202)
566
1672.
Copies
may
also
be
downloaded
from
the
internet
at
http:/
/
www.
epa.
gov/
icr.
This
ICR
reflects
the
burden
estimate
for
the
emission
guidelines
which
were
promulgated
in
the
Federal
Register
on
December
1,
2000.
The
burden
estimate
includes
the
burden
associated
with
State
or
Tribal
plans
as
well
as
the
burden
associated
with
the
proposed
Federal
plan.
Consequently,
the
burden
estimates
described
below
overstate
the
information
collection
burden
associated
with
the
Federal
plan.
However,
upon
approval
by
EPA,
a
State
or
Tribal
plan
becomes
Federally
enforceable.
Therefore,
it
is
important
to
estimate
the
full
burden
associated
with
the
State
or
Tribal
plans
and
the
Federal
plan.
As
State
or
Tribal
plans
are
approved,
the
Federal
plan
burden
will
decrease,
but
the
overall
burden
of
the
State
or
Tribal
plans
and
the
Federal
plan
will
remain
the
same.
The
Federal
plan
contains
monitoring,
reporting,
and
recordkeeping
requirements.
The
information
will
be
used
to
ensure
that
the
Federal
plan
requirements
are
met
on
a
continuous
basis.
Records
and
reports
will
be
necessary
to
enable
us
to
identify
waste
incineration
units
that
may
not
be
in
compliance
with
the
Federal
plan
requirements.
Based
on
reported
information,
EPA
would
decide
which
units
and
what
records
or
processes
should
be
inspected.
The
records
that
owners
and
operators
of
existing
CISWI
units
maintain
will
indicate
to
EPA
whether
personnel
are
operating
and
maintaining
control
equipment
property.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(
42
U.
S.
C.
7414).
All
information
submitted
to
us
for
which
a
claim
of
confidentiality
is
made
will
be
safeguarded
according
to
our
policies
in
40
CFR
part
2,
subpart
B,
Confidentiality
of
Business
Information.
The
estimated
average
annual
burden
for
the
first
3
years
after
promulgation
of
the
emission
guidelines
for
industry
and
the
implementing
agency
is
outlined
below.
Affected
entity
Total
hours
Labor
costs
Capital
costs
O&
M
costs
Total
costs
Industry
...............................
9,145
$
407,067
0
0
$
407,067
Implementing
agency
.........
1,817
$
48,386
0
0
$
48,386
The
EPA
expects
the
Federal
plan
to
affect
a
maximum
of
116
units
over
the
first
3
years.
(
Note:
This
assumes
that
no
State
plans
are
in
effect.)
The
EPA
assumes
that
6
existing
units
will
be
replaced
by
6
new
units
each
year.
There
are
no
capital,
start
up,
or
operation
and
maintenance
costs
for
existing
units
during
the
first
3
years.
The
implementing
agency
would
not
incur
any
capital
or
start
up
costs.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
disclose,
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
number
for
this
proposed
rule
and
for
the
emissions
guidelines
which
it
implements
is
2060
0451.
The
OMB
control
numbers
for
our
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
K.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
(
NTTAA)
of
1995
(
Pub.
L.
104
113;
15
U.
S.
C.
272)
directs
EPA
to
use
voluntary
consensus
standards
in
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
annual
reports
to
the
Office
of
Management
and
Budget
(
OMB),
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.
This
proposed
Federal
plan
involves
technical
standards.
The
EPA
proposes
in
this
plan
to
use
EPA
Methods
1,
3A,
3B,
5,
6,
6C,
7,
7A,
7C,
7D,
7E,
9,
10,
10A,
10B,
23,
26A,
and
29.
Consistent
with
the
NTTAA,
EPA
conducted
searches
to
identify
voluntary
consensus
standards
in
addition
to
these
EPA
methods.
No
applicable
voluntary
consensus
standards
were
identified
for
EPA
Methods
7A,
7D,
9,
and
10B.
The
search
and
review
results
have
been
documented
and
are
placed
in
the
Docket
No.
A
2000
52
for
this
proposed
plan.
This
search
for
emission
measurement
procedures
identified
24
voluntary
consensus
standards.
The
EPA
determined
that
20
of
these
24
standards
were
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
this
proposed
Federal
plan.
Therefore,
EPA
does
not
propose
to
adopt
these
standards
today.
The
reasons
for
this
determination
for
the
20
methods
are
discussed
below.
The
standard,
ASTM
D3162
(
1994)
``
Standard
Test
Method
for
Carbon
Monoxide
in
the
Atmosphere
(
Continuous
Measurement
by
Nondispersive
Infrared
Spectrometry),''
is
impractical
as
an
alternative
to
EPA
Method
10
in
this
proposed
Federal
plan
because
this
ASTM
standard,
which
is
stated
to
be
applicable
in
the
range
of
0.5
100
ppm
CO,
does
not
cover
the
potential
range
in
the
plan
(
up
to
157
ppm).
Whereas
EPA
Method
10
has
a
range
from
20
1000
ppm
CO.
Also,
ASTM
D3162
does
not
provide
a
procedure
to
remove
carbon
dioxide
interference.
Therefore,
this
ASTM
standard
is
not
appropriate
for
combustion
source
conditions.
In
terms
of
NDIR
instrument
performance
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25,
2002
/
Proposed
Rules
specifications,
ASTM
D3162
has
much
higher
maximum
allowable
rise
and
fall
times
(
5
minutes)
than
EPA
Method
10
(
which
has
30
seconds).
However,
it
should
be
noted
that
ASTM
D3162
has
more
quality
control
requirements
than
EPA
Method
10
in
terms
of
instrument
calibration
procedures,
span
gas
cylinder
validation
procedures,
and
operational
checks.
The
standard
ASTM
E1979
98
(
1998),
``
Standard
Practice
for
Ultrasonic
Extraction
of
Paint,
Dust,
Soil,
and
Air
Samples
for
Subsequent
Determination
of
Lead,''
is
impractical
as
an
alternative
to
EPA
Method
29
in
this
proposed
Federal
plan.
This
ASTM
standard
does
not
require
the
use
of
hydrogen
fluoride
(
HF)
as
in
EPA
Method
29
and,
therefore,
it
cannot
be
used
for
the
preparation,
digestion,
and
analysis
of
Method
29
samples.
Additionally,
Method
29
requires
the
use
of
a
glass
fiber
filter,
whereas
this
ASTM
standard
requires
cellulose
filters
and
other
probable
nonglass
fiber
media
which
cannot
be
considered
equivalent
to
EPA
Method
29.
The
European
standard
EN
1911
1,2,3
(
1998),
``
Stationary
Source
Emissions
Manual
Method
of
Determination
of
HCl
Part
1:
Sampling
of
Gases
Ratified
European
Text
Part
2:
Gaseous
Compounds
Absorption
Ratified
European
Text
Part
3:
Adsorption
Solutions
Analysis
and
Calculation
Ratified
European
Text,''
is
impractical
as
an
alternative
to
EPA
Method
26A.
Part
3
of
this
standard
cannot
be
considered
equivalent
to
EPA
Method
26A
because
the
sample
absorbing
solution
(
water)
would
be
expected
to
capture
both
HCl
and
chlorine
gas,
if
present,
without
the
ability
to
distinguish
between
the
two.
The
EPA
Method
26A
uses
an
acidified
absorbing
solution
to
first
separate
HCl
and
chlorine
gas
so
that
they
can
be
selectively
absorbed,
analyzed,
and
reported
separately.
In
addition,
in
EN
1911
the
absorption
efficiency
for
chlorine
gas
would
be
expected
to
vary
as
the
pH
of
the
water
changed
during
sampling.
The
following
ten
methods
are
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
this
plan
because
they
are
too
general,
too
broad,
or
not
sufficiently
detailed
to
assure
compliance
with
EPA
regulatory
requirements:
ASTM
D3154
91
(
1995),
``
Standard
Method
for
Average
Velocity
in
a
Duct
(
Pitot
Tube
Method),''
for
EPA
Methods
1
and
3B;
ASTM
D5835
95,
``
Standard
Practice
for
Sampling
Stationary
Source
Emissions,
for
Automated
Determination
of
Gas
Concentration,''
for
EPA
Method
3A;
ISO
10396:
1993,
``
Stationary
Source
Emissions:
Sampling
for
the
Automated
Determination
of
Gas
Concentrations,''
for
EPA
Method
3A;
CAN/
CSA
Z223.2
M86(
1986),
``
Method
for
the
Continuous
Measurement
of
Oxygen,
Carbon
Dioxide,
Carbon
Monoxide,
Sulphur
Dioxide,
and
Oxides
of
Nitrogen
in
Enclosed
Combustion
Flue
Gas
Streams,''
for
EPA
Method
3A;
ASME
C00031
or
PTC
19
10
1981
Part
10,
``
Flue
and
Exhaust
Gas
Analyses,''
for
EPA
Methods
6
and
7;
ASTM
D1608
98,
``
Test
Method
for
Oxides
of
Nitrogen
in
Gaseous
Combustion
Products
(
Pheno
Disulfonic
Acid
Procedures),''
for
EPA
Method
7;
ISO
7934:
1998,
``
Stationary
Source
Emissions
Determination
of
the
Mass
Concentration
of
Sulfur
Dioxide
Hydrogen
Peroxide/
Barium
Perchlorate/
Thorin
Method,''
for
EPA
Method
6;
ISO
11564:
1998,
``
Stationary
Source
Emissions
Determination
of
the
Mass
Concentration
of
Nitrogen
Oxides
NEDA
(
naphthylethylenediamine)/
Photometric
Method,''
for
EPA
Methods
7
and
7C;
CAN/
CSA
Z223.21
M1978,
``
Method
for
the
Measurement
of
Carbon
Monoxide:
3
Method
of
Analysis
by
Non
Dispersive
Infrared
Spectrometry,''
for
EPA
Methods
10
and
10A;
and
European
Committee
for
Standardization
(
CEN)
EN
1948
3
(
1997),
``
Determination
of
the
Mass
Concentration
of
PCDD'S/
PCDF'S
Part
3:
Identification
and
Quantification,''
for
EPA
Method
23.
The
following
seven
methods
are
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
this
Federal
plan
because
they
lacked
sufficient
quality
assurance
and
quality
control
requirements
necessary
for
EPA
compliance
assurance
requirements:
ASME
PTC
38
80
R85
or
C00049,
``
Determination
of
the
Concentration
of
Particulate
Matter
in
Gas
Streams,''
for
EPA
Method
5;
ASTM
D3685/
D3685M
98,
``
Test
Methods
for
Sampling
and
Determination
of
Particulate
Matter
in
Stack
Gases,''
for
EPA
Method
5;
ISO
9096:
1992,
``
Determination
of
Concentration
and
Mass
Flow
Rate
of
Particulate
Matter
in
Gas
Carrying
Ducts
Manual
Gravimetric
Method,''
for
EPA
Method
5;
CAN/
CSA
Z223.1
M1977,
``
Method
for
the
Determination
of
Particulate
Mass
Flows
in
Enclosed
Gas
Streams,''
for
EPA
Method
5;
ISO
11632:
1998,
``
Stationary
Source
Emissions
Determination
of
the
Mass
Concentration
of
Sulfur
Dioxide
Ion
Chromatography,''
for
EPA
Method
6;
CAN/
CSA
Z223.24
M1983,
``
Method
for
the
Measurement
of
Nitric
Oxide
and
Nitrogen
Dioxide
in
Air,''
for
EPA
Method
7;
and
CAN/
CSA
Z223.26
M1987,
``
Measurement
of
Total
Mercury
in
Air
Cold
Vapour
Atomic
Absorption
Spectrophotometeric
Method,''
for
EPA
Method
29.
The
following
four
of
the
24
voluntary
consensus
standards
identified
in
this
search
were
not
available
at
the
time
the
review
was
conducted
for
the
purposes
of
this
proposed
plan
because
they
are
under
development
by
a
voluntary
consensus
body:
ISO/
DIS
12039,
``
Stationary
Source
Emissions
Determination
of
Carbon
Monoxide,
Carbon
Dioxide,
and
Oxygen
Automated
Methods,''
for
EPA
Method
3A;
ASTM
Z6449Z,
``
Standard
Method
for
the
Determination
of
Sulfur
Dioxide
in
Stationary
Sources,''
for
EPA
Method
6;
ASTM
Z6590Z,
``
Manual
Method
for
Both
Speciated
and
Elemental
Mercury,''
for
EPA
Method
29
(
portion
for
mercury
only);
prEN
13211
(
1998),
``
Air
Quality
Stationary
Source
Emissions
Determination
of
the
Concentration
of
Total
Mercury,''
for
EPA
Method
29
(
portion
for
mercury
only).
While
EPA
is
not
proposing
to
include
these
four
voluntary
consensus
standards
in
today's
proposed
plan,
the
EPA
will
consider
the
standards
when
final.
The
EPA
takes
comment
on
the
compliance
demonstration
requirements
proposed
in
this
Federal
plan
and
specifically
invites
the
public
to
identify
potentially
applicable
voluntary
consensus
standards.
Commenters
should
also
explain
why
this
plan
should
adopt
these
voluntary
consensus
standards
in
lieu
of
or
in
addition
to
EPA's
standards.
Emission
test
methods
submitted
for
evaluation
should
be
accompanied
with
a
basis
for
the
recommendation,
including
method
validation
data
and
the
procedure
used
to
validate
the
candidate
method
(
if
a
method
other
than
Method
301,
40
CFR
part
63,
Appendix
A
was
used).
Table
1
of
proposed
Subpart
III
lists
the
EPA
testing
methods
included
in
the
emission
Federal
Plan
Requirements
for
Commercial
and
Industrial
Solid
Waste
Incinerators.
Under
40
CFR
63.8(
f)
of
subpart
A
of
the
General
Provisions,
a
source
may
apply
to
EPA
for
permission
to
use
alternative
monitoring
in
place
of
any
of
the
EPA
testing
methods.
List
of
Subjects
in
40
CFR
Part
62
Environmental
protection,
Air
pollution
control,
Carbon
monoxide,
Metals,
Nitrogen
dioxide,
Particulate
matter,
Sulfur
oxides,
Waste
treatment
and
disposal.
Dated:
November
6,
2002.
Christine
Todd
Whitman,
Administrator.
40
CFR
part
62
is
proposed
to
be
amended
as
follows:
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/
Vol.
67,
No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
PART
62
[
AMENDED]
1.
The
authority
citation
for
part
62
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401
7671q.
2.
Amend
§
62.13
by
adding
paragraph
(
d)
to
read
as
follows:
§
62.13
Federal
plans.
*
*
*
*
*
(
d)
The
substantive
requirements
of
the
Commercial
and
industrial
solid
waste
incineration
units
Federal
plan
are
contained
in
subpart
III
of
this
part.
These
requirements
include
emission
limits,
compliance
schedules,
testing,
monitoring,
and
reporting
and
recordkeeping
requirements.
3.
Amend
part
62
by
adding
subpart
III
to
read
as
follows:
Subpart
III
Federal
Plan
Requirements
for
Commercial
and
Industrial
Solid
Waste
Incineration
Units
That
Commenced
Construction
on
or
Before
November
30,
1999
Introduction
Sec.
62.14500
What
is
the
purpose
of
this
subpart?
62.14505
What
are
the
principal
components
of
this
subpart?
Applicability
62.14510
Am
I
subject
to
this
subpart?
62.14515
Can
my
CISWI
unit
be
covered
by
both
a
State
plan
and
this
subpart?
62.14520
How
do
I
determine
if
my
CISWI
unit
is
covered
by
an
approved
and
effective
State
or
Tribal
plan?
62.14521
If
my
CISWI
unit
is
not
listed
in
the
Federal
plan
inventory,
am
I
exempt
from
this
subpart?
62.14525
Can
my
combustion
unit
be
exempt
from
this
subpart?
62.14530
What
if
I
have
a
chemical
recovery
unit
that
is
not
listed
in
§
62.14525(
n)?
62.14531
When
must
I
submit
any
records
required
pursuant
to
an
exemption
allowed
under
§
62.14525?
Compliance
Schedule
and
Increments
of
Progress
62.14535
When
must
I
comply
with
this
subpart
if
I
plan
to
continue
operation
of
my
CISWI
unit?
62.14536
What
steps
are
required
to
request
an
extension
of
the
initial
compliance
date
if
I
plan
to
continue
operation
of
my
CISWI
unit?
62.14540
When
must
I
complete
each
increment
of
progress?
62.14545
What
must
I
include
in
each
notification
of
achievement
of
an
increment
of
progress?
62.14550
When
must
I
submit
a
notification
of
achievement
of
the
first
increment
of
progress?
62.14555
What
if
I
do
not
meet
an
increment
of
progress?
62.14560
How
do
I
comply
with
the
increment
of
progress
for
submittal
of
a
control
plan?
62.14565
How
do
I
comply
with
the
increment
of
progress
for
achieving
final
compliance?
§
62.14570
What
must
I
do
if
I
plan
to
permanently
close
my
CISWI
unit?
§
62.14575
What
must
I
do
if
I
close
my
CISWI
unit
and
then
restart
it?
Waste
Management
Plan
62.14580
What
is
a
waste
management
plan?
62.14585
When
must
I
submit
my
waste
management
plan?
62.14590
What
should
I
include
in
my
waste
management
plan?
Operator
Training
and
Qualification
62.14595
What
are
the
operator
training
and
qualification
requirements?
62.14600
When
must
the
operator
training
course
be
completed?
62.14605
How
do
I
obtain
my
operator
qualification?
62.14610
How
do
I
maintain
my
operator
qualification?
62.14615
How
do
I
renew
my
lapsed
operator
qualification?
62.14620
What
site
specific
documentation
is
required?
62.14625
What
if
all
the
qualified
operators
are
temporarily
not
accessible?
Emission
Limitations
and
Operating
Limits
62.14630
What
emission
limitations
must
I
meet
and
by
when?
62.14635
What
operating
limits
must
I
meet
and
by
when?
62.14536
What
steps
are
required
to
request
an
extension
of
the
initial
compliance
date
if
I
plan
to
continue
operation
of
my
CISWI
unit?
62.14640
What
if
I
do
not
use
a
wet
scrubber
to
comply
with
the
emission
limitations?
62.14645
What
happens
during
periods
of
startup,
shutdown,
and
malfunction?
Performance
Testing
62.14650
How
do
I
conduct
the
initial
and
annual
performance
test?
62.14655
How
are
the
performance
test
data
used?
Initial
Compliance
Requirements
62.14660
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations
and
establish
the
operating
limits?
62.14665
By
what
date
must
I
conduct
the
initial
performance
test?
Continuous
Compliance
Requirements
62.14670
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations
and
the
operating
limits?
62.14675
By
what
date
must
I
conduct
the
annual
performance
test?
62.14680
May
I
conduct
performance
testing
less
often?
62.14685
May
I
conduct
a
repeat
performance
test
to
establish
new
operating
limits?
Monitoring
62.14690
What
monitoring
equipment
must
I
install
and
what
parameters
must
I
monitor?
62.14695
Is
there
a
minimum
amount
of
monitoring
data
I
must
obtain?
Recordkeeping
and
Reporting
62.14700
What
records
must
I
keep?
62.14705
Where
and
in
what
format
must
I
keep
my
records?
62.14710
What
reports
must
I
submit?
62.14715
When
must
I
submit
my
waste
management
plan?
62.14720
What
information
must
I
submit
following
my
initial
performance
test?
62.14725
When
must
I
submit
my
annual
report?
62.14730
What
information
must
I
include
in
my
annual
report?
62.14735
What
else
must
I
report
if
I
have
a
deviation
from
the
operating
limits
or
the
emission
limitations?
62.14740
What
must
I
include
in
the
deviation
report?
62.14745
What
else
must
I
report
if
I
have
a
deviation
from
the
requirement
to
have
a
qualified
operator
accessible?
62.14750
Are
there
any
other
notifications
or
reports
that
I
must
submit?
62.14755
In
what
form
can
I
submit
my
reports?
62.14760
Can
reporting
dates
be
changed?
Air
Curtain
Incinerators
that
Burn
100
Percent
Wood
Wastes
and
Clean
Lumber
62.14765
What
is
an
air
curtain
incinerator?
62.14770
When
must
I
achieve
final
compliance?
62.14795
How
do
I
achieve
final
compliance?
62.14805
What
must
I
do
if
I
close
my
air
curtain
incinerator
and
then
restart
it?
62.14810
What
must
I
do
if
I
plan
to
permanently
close
my
air
curtain
incinerator
and
not
restart
it?
62.14815
What
are
the
emission
limitations
for
air
curtain
incinerators
that
burn
100
percent
wood
wastes
and
clean
lumber?
62.14820
How
must
I
monitor
opacity
for
air
curtain
incinerators
that
burn
100
percent
wood
wastes
and
clean
lumber?
62.14825
What
are
the
recordkeeping
and
reporting
requirements
for
air
curtain
incinerators
that
burn
100
percent
wood
wastes
and
clean
lumber?
Title
V
Requirements
62.14830
Does
this
subpart
require
me
to
obtain
an
operating
permit
under
title
V
of
the
Clean
Air
Act?
62.14835
When
must
I
submit
a
title
V
permit
application
for
my
existing
CISWI
unit?
Definitions
62.14840
What
definitions
must
I
know?
Tables
Table
1
of
Subpart
III
of
Part
62
Emission
Limitations
Table
2
of
Subpart
III
of
Part
62
Operating
Limits
for
Wet
Scrubbers
Table
3
of
Subpart
III
of
Part
62
Toxic
Equivalency
Factors
Table
4
of
Subpart
III
of
Part
62
Summary
of
Reporting
Requirements
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Vol.
67,
No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
Introduction
§
62.14500
What
is
the
purpose
of
this
subpart?
(
a)
This
subpart
establishes
emission
requirements
and
compliance
schedules
for
the
control
of
emissions
from
commercial
and
industrial
solid
waste
incineration
(
CISWI)
units
that
are
not
covered
by
an
EPA
approved
and
currently
effective
State
or
Tribal
plan.
The
pollutants
addressed
by
these
emission
requirements
are
listed
in
Table
1
of
this
subpart.
These
emission
requirements
are
developed
in
accordance
with
sections
111(
d)
and
129
of
the
Clean
Air
Act
and
subpart
B
of
40
CFR
part
60.
(
b)
In
this
subpart,
you
means
the
owner
or
operator
of
a
CISWI
unit.
§
62.14505
What
are
the
principal
components
of
this
subpart?
This
subpart
contains
the
eleven
major
components
listed
in
paragraphs
(
a)
through
(
k)
of
this
section.
(
a)
Increments
of
progress
toward
compliance.
(
b)
Waste
management
plan.
(
c)
Operator
training
and
qualification.
(
d)
Emission
limitations
and
operating
limits.
(
e)
Performance
testing.
(
f)
Initial
compliance
requirements.
(
g)
Continuous
compliance
requirements.
(
h)
Monitoring.
(
i)
Recordkeeping
and
reporting.
(
j)
Definitions.
(
k)
Tables.
Applicability
§
62.14510
Am
I
subject
to
this
subpart?
(
a)
You
are
subject
to
this
subpart
if
you
own
or
operate
a
commercial
and
industrial
solid
waste
incinerator
(
CISWI)
unit
as
defined
in
§
62.14840
and
the
CISWI
unit
meets
the
criteria
described
in
paragraphs
(
a)(
1)
through
(
a)(
3)
of
this
section.
(
1)
Construction
of
your
CISWI
unit
commenced
on
or
before
November
30,
1999.
(
2)
Your
CISWI
unit
is
not
exempt
under
§
62.14525.
(
3)
Your
CISWI
unit
is
not
regulated
by
an
EPA
approved
and
currently
effective
State
or
Tribal
plan,
or
your
CISWI
unit
is
located
in
any
State
whose
approved
State
or
Tribal
plan
is
subsequently
vacated
in
whole
or
in
part.
(
b)
If
you
made
changes
after
June
1,
2001
that
meet
the
definition
of
modification
or
reconstruction
after
promulgation
of
the
final
40
CFR
part
60,
subpart
CCCC
(
New
Source
Performance
Standards
for
Commercial
and
Industrial
Solid
Waste
Incineration
Units),
your
CISWI
unit
is
subject
to
subpart
CCCC
of
40
CFR
part
60
and
this
subpart
no
longer
applies
to
that
unit.
(
c)
If
you
make
physical
or
operational
changes
to
your
existing
CISWI
unit
primarily
to
comply
with
this
subpart,
then
such
changes
do
not
qualify
as
modifications
or
reconstructions
under
subpart
CCCC
of
40
CFR
part
60.
§
62.14515
Can
my
CISWI
unit
be
covered
by
both
a
State
plan
and
this
subpart?
(
a)
If
your
CISWI
unit
is
located
in
a
State
that
does
not
have
an
EPAapproved
State
plan
or
your
State's
plan
has
not
become
effective,
this
subpart
applies
to
your
CISWI
unit
until
EPA
approves
a
State
plan
that
covers
your
CISWI
unit
and
that
State
plan
becomes
effective.
However,
a
State
may
enforce
the
requirements
of
a
State
regulation
while
your
CISWI
unit
is
still
subject
to
this
subpart.
(
b)
After
the
EPA
approves
a
State
plan
covering
your
CISWI
unit,
and
after
that
State
plan
becomes
effective,
you
will
no
longer
be
subject
to
this
subpart
and
will
only
be
subject
to
the
approved
and
effective
State
plan.
§
62.14520
How
do
I
determine
if
my
CISWI
unit
is
covered
by
an
approved
and
effective
State
or
Tribal
plan?
This
part
(
40
CFR
part
62)
contains
a
list
of
State
and
Tribal
areas
with
approved
Clean
Air
Act
section
111(
d)
and
section
129
plans
along
with
the
effective
dates
for
such
plans.
The
list
is
published
annually.
If
this
part
does
not
indicate
that
your
State
or
Tribal
area
has
an
approved
and
effective
plan,
you
should
contact
your
State
environmental
agency's
air
director
or
your
EPA
Regional
Office
to
determine
if
EPA
has
approved
a
State
plan
covering
your
unit
since
publication
of
the
most
recent
version
of
this
subpart.
§
62.14521
If
my
CISWI
unit
is
not
listed
in
the
Federal
plan
inventory,
am
I
exempt
from
this
subpart?
Not
necessarily.
Sources
subject
to
this
subpart
are
not
limited
to
the
inventory
of
sources
listed
in
Docket
A
2000
52
for
the
Federal
plan.
If
your
CISWI
units
meets
the
applicability
criteria
in
§
62.14510,
this
subpart
applies
to
you
whether
or
not
your
unit
is
listed
in
the
Federal
plan
inventory
in
the
docket.
§
62.14525
Can
my
combustion
unit
be
exempt
from
this
subpart?
This
subpart
exempts
fifteen
types
of
units
described
in
paragraphs
(
a)
through
(
o)
of
this
section
except
for
the
requirements
specified
in
this
section
and
in
§
62.14531.
(
a)
Pathological
waste
incineration
units.
Incineration
units
burning
90
percent
or
more
by
weight
(
on
a
calendar
quarter
basis
and
excluding
the
weight
of
auxiliary
fuel
and
combustion
air)
of
pathological
waste,
low
level
radioactive
waste,
and/
or
chemotherapeutic
waste
as
defined
in
§
62.14840
are
not
subject
to
this
subpart
if
you
meet
the
two
requirements
specified
in
paragraphs
(
a)(
1)
and
(
2)
of
this
section.
(
1)
Notify
the
Administrator
that
the
unit
meets
these
criteria.
(
2)
Keep
records
on
a
calendar
quarter
basis
of
the
weight
of
pathological
waste,
low
level
radioactive
waste,
and/
or
chemotherapeutic
waste
burned,
and
the
weight
of
all
other
fuels
and
wastes
burned
in
the
unit.
(
b)
Agricultural
waste
incineration
units.
Incineration
units
burning
90
percent
or
more
by
weight
(
on
a
calendar
quarter
basis
and
excluding
the
weight
of
auxiliary
fuel
and
combustion
air)
of
agricultural
wastes
as
defined
in
§
62.14840
are
not
subject
to
this
subpart
if
you
meet
the
two
requirements
specified
in
paragraphs
(
b)(
1)
and
(
2)
of
this
section.
(
1)
Notify
the
Administrator
that
the
unit
meets
these
criteria.
(
2)
Keep
records
on
a
calendar
quarter
basis
of
the
weight
of
agricultural
waste
burned,
and
the
weight
of
all
other
fuels
and
wastes
burned
in
the
unit.
(
c)
Municipal
waste
combustion
units.
Incineration
units
that
meet
either
of
the
two
criteria
specified
in
paragraphs
(
c)(
1)
or
(
2)
of
this
section.
(
1)
Units
that
are
regulated
under
subpart
Ea
of
40
CFR
part
60
(
Standards
of
Performance
for
Municipal
Waste
Combustors);
subpart
Eb
of
40
CFR
part
60
(
Standards
of
Performance
for
Municipal
Waste
Combustors
for
Which
Construction
is
Commenced
After
September
20,
1994);
subpart
Cb
of
40
CFR
part
60
(
Emission
Guidelines
and
Compliance
Times
for
Large
Municipal
Waste
Combustors
Constructed
on
or
Before
September
20,
1994);
subpart
AAAA
of
40
CFR
part
60
(
Standards
of
Performance
for
New
Stationary
Sources:
Small
Municipal
Waste
Combustion
Units);
or
subpart
BBBB
of
40
CFR
part
60
(
Emission
Guidelines
for
Existing
Stationary
Sources:
Small
Municipal
Waste
Combustion
Units).
(
2)
Units
that
burn
greater
than
30
percent
municipal
solid
waste
or
refusederived
fuel,
as
defined
in
40
CFR
part
60
subpart
Ea,
subpart
Eb,
subpart
AAAA,
and
subpart
BBBB,
and
that
have
the
capacity
to
burn
less
than
35
tons
(
32
megagrams)
per
day
of
municipal
solid
waste
or
refuse
derived
fuel,
if
you
meet
the
two
requirements
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/
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25,
2002
/
Proposed
Rules
in
paragraphs
(
c)(
2)(
i)
and
(
ii)
of
this
section.
(
i)
Notify
the
Administrator
that
the
unit
meets
these
criteria.
(
ii)
Keep
records
on
a
calendar
quarter
basis
of
the
weight
of
municipal
solid
waste
burned,
and
the
weight
of
all
other
fuels
and
wastes
burned
in
the
unit.
(
d)
Medical
waste
incineration
units.
Incineration
units
regulated
under
subpart
Ec
of
40
CFR
part
60
(
Standards
of
Performance
for
Hospital/
Medical/
Infectious
Waste
Incinerators
for
Which
Construction
is
Commenced
After
June
20,
1996);
40
CFR
part
60
subpart
Ce
(
Emission
Guidelines
and
Compliance
Times
for
Hospital/
Medical/
Infectious
Waste
Incinerators);
and
40
CFR
part
62
subpart
HHH
(
Federal
Plan
Requirements
for
Hospital/
Medical/
Infectious
Waste
Incinerators
Constructed
on
or
before
June
20,
1996).
(
e)
Small
power
production
facilities.
Units
that
meet
the
three
requirements
specified
in
paragraphs
(
e)(
1)
through
(
3)
of
this
section.
(
1)
The
unit
qualifies
as
a
small
power
production
facility
under
section
3(
17)(
C)
of
the
Federal
Power
Act
(
16
U.
S.
C.
796(
17)(
C)).
(
2)
The
unit
burns
homogeneous
waste
(
not
including
refuse
derived
fuel)
to
produce
electricity.
(
3)
You
notify
the
Administrator
that
the
unit
meets
all
of
these
criteria.
(
f)
Cogeneration
facilities.
Units
that
meet
the
three
requirements
specified
in
paragraphs
(
f)(
1)
through
(
3)
of
this
section.
(
1)
The
unit
qualifies
as
a
cogeneration
facility
under
section
3(
18)(
B)
of
the
Federal
Power
Act
(
16
U.
S.
C.
796(
18)(
B)).
(
2)
The
unit
burns
homogeneous
waste
(
not
including
refuse
derived
fuel)
to
produce
electricity
and
steam
or
other
forms
of
energy
used
for
industrial,
commercial,
heating,
or
cooling
purposes.
(
3)
You
notify
the
Administrator
that
the
unit
meets
all
of
these
criteria.
(
g)
Hazardous
waste
combustion
units.
Units
regulated
under
subpart
EEE
of
part
63
(
National
Emission
Standards
for
Hazardous
Air
Pollutants
from
Hazardous
Waste
Combustors).
(
h)
Materials
recovery
units.
Units
that
combust
waste
for
the
primary
purpose
of
recovering
metals,
such
as
primary
and
secondary
smelters.
(
i)
Air
curtain
incinerators.
Air
curtain
incinerators
that
burn
100
percent
wood
waste
and
clean
lumber
are
only
required
to
meet
the
requirements
under
``
Air
Curtain
Incinerators
That
Burn
100
Percent
Wood
Wastes
and
Clean
Lumber''
(
§
§
62.14765
through
62.14825)
and
the
title
V
operating
permit
requirements
(
§
§
62.14830
and
62.14835).
(
j)
Cyclonic
barrel
burners.
(
k)
Rack,
part,
and
drum
reclamation
units.
(
l)
Cement
kilns.
(
m)
Sewage
sludge
incinerators.
Incineration
units
regulated
under
subpart
O
of
40
CFR
part
60
(
Standards
of
Performance
for
Sewage
Treatment
Plants).
(
n)
Chemical
recovery
units.
Combustion
units
burning
materials
to
recover
chemical
constituents
or
to
produce
chemical
compounds
where
there
is
an
existing
commercial
market
for
such
recovered
chemical
constituents
or
compounds.
The
seven
types
of
units
described
in
paragraphs
(
n)(
1)
through
(
7)
of
this
section
are
considered
chemical
recovery
units.
(
1)
Units
burning
only
pulping
liquors
(
i.
e.,
black
liquor)
that
are
reclaimed
in
a
pulping
liquor
recovery
process
and
reused
in
the
pulping
process.
(
2)
Units
burning
only
spent
sulfuric
acid
used
to
produce
virgin
sulfuric
acid.
(
3)
Units
burning
only
wood
or
coal
feedstock
for
the
production
of
charcoal.
(
4)
Units
burning
only
manufacturing
byproduct
streams/
residues
containing
catalyst
metals
which
are
reclaimed
and
reused
as
catalysts
or
used
to
produce
commercial
grade
catalysts.
(
5)
Units
burning
only
coke
to
produce
purified
carbon
monoxide
that
is
used
as
an
intermediate
in
the
production
of
other
chemical
compounds.
(
6)
Units
burning
only
hydrocarbon
liquids
or
solids
to
produce
hydrogen,
carbon
monoxide,
synthesis
gas,
or
other
gases
for
use
in
other
manufacturing
processes.
(
7)
Units
burning
only
photographic
film
to
recover
silver.
(
o)
Laboratory
units.
Units
that
burn
samples
of
materials
for
the
purpose
of
chemical
or
physical
analysis.
§
62.14530
What
if
I
have
a
chemical
recovery
unit
that
is
not
listed
in
§
62.14525(
n)?
(
a)
If
you
have
a
recovery
unit
that
is
not
listed
in
§
62.14525(
n),
you
can
petition
the
Administrator
to
add
the
unit
to
the
list.
The
petition
must
contain
the
six
items
in
paragraphs
(
a)(
1)
through
(
6)
of
this
section.
(
1)
A
description
of
the
source
of
the
materials
being
burned.
(
2)
A
description
of
the
composition
of
the
materials
being
burned,
highlighting
the
chemical
constituents
in
these
materials
that
are
recovered.
(
3)
A
description
(
including
a
process
flow
diagram)
of
the
process
in
which
the
materials
are
burned,
highlighting
the
type,
design,
and
operation
of
the
equipment
used
in
this
process.
(
4)
A
description
(
including
a
process
flow
diagram)
of
the
chemical
constituent
recovery
process,
highlighting
the
type,
design,
and
operation
of
the
equipment
used
in
this
process.
(
5)
A
description
of
the
commercial
markets
for
the
recovered
chemical
constituents
and
their
use.
(
6)
The
composition
of
the
recovered
chemical
constituents
and
the
composition
of
these
chemical
constituents
as
they
are
bought
and
sold
in
commercial
markets.
(
b)
Until
the
Administrator
approves
the
petition,
the
incineration
unit
is
covered
by
this
subpart.
(
c)
If
a
petition
is
approved,
the
Administrator
will
amend
§
62.14525(
n)
to
add
the
unit
to
the
list
of
chemical
recovery
units.
§
62.14531
When
must
I
submit
any
records
required
pursuant
to
an
exemption
allowed
under
§
62.14525?
Owners
or
operators
of
sources
that
qualify
for
the
exemptions
in
§
62.14525(
a)
through
(
o)
must
submit
any
records
required
to
support
their
claims
of
exemption
to
the
EPA
Administrator
(
or
delegated
enforcement
authority)
upon
request.
Upon
request
by
any
person
under
the
regulation
at
part
2
of
this
chapter
(
or
a
comparable
law
or
regulation
governing
a
delegated
enforcement
authority),
the
EPA
Administrator
(
or
delegated
enforcement
authority)
must
request
the
records
in
§
62.14525(
a)
through
(
o)
from
an
owner
or
operator
and
make
such
records
available
to
the
requestor
to
the
extent
required
by
part
2
of
this
chapter
(
or
a
comparable
law
governing
a
delegated
enforcement
authority).
Any
records
required
under
§
62.14525(
a)
through
(
o)
must
be
maintained
by
the
source
for
a
period
of
at
least
5
years.
Notifications
of
exemption
claims
required
under
§
62.14525(
a)
through
(
o)
of
this
section
must
be
maintained
by
the
EPA
or
delegated
enforcement
authority
for
a
period
of
at
least
5
years.
Any
information
obtained
from
an
owner
or
operator
of
a
source
accompanied
by
a
claim
of
confidentiality
will
be
treated
in
accordance
with
the
regulations
in
part
2
of
this
chapter
(
or
a
comparable
law
governing
a
delegated
enforcement
authority).
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Vol.
67,
No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
Compliance
Schedule
and
Increments
of
Progress
§
62.14535
When
must
I
comply
with
this
subpart
if
I
plan
to
continue
operation
of
my
CISWI
unit?
If
you
plan
to
continue
operation
of
your
CISWI
unit,
then
you
must
follow
the
requirements
in
paragraph
(
a)
or
(
b)
of
this
section
depending
on
when
you
plan
to
come
into
compliance
with
the
requirements
of
this
subpart.
(
a)
If
you
plan
to
continue
operation
and
come
into
compliance
with
the
requirements
of
this
subpart
by
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register,
then
you
must
complete
the
requirements
of
paragraphs
(
a)(
1)
through
(
a)(
5)
of
this
section.
(
1)
You
must
comply
with
the
operator
training
and
qualification
requirements
and
inspection
requirements
(
if
applicable)
of
this
subpart
by
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
2)
You
must
submit
a
waste
management
plan
no
later
than
the
date
six
months
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
3)
You
must
achieve
final
compliance
by
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
To
achieve
final
compliance,
you
must
incorporate
all
process
changes
and
complete
retrofit
construction
of
control
devices,
as
specified
in
the
final
control
plan,
so
that,
if
the
affected
CISWI
unit
is
brought
online,
all
necessary
process
changes
and
air
pollution
control
devices
would
operate
as
designed.
(
4)
You
must
conduct
the
initial
performance
test
within
90
days
after
the
date
when
you
are
required
to
achieve
final
compliance
under
paragraph
(
a)(
3)
of
this
section.
(
5)
You
must
submit
an
initial
report
including
the
results
of
the
initial
performance
test
no
later
than
60
days
following
the
initial
performance
test
(
see
§
§
62.14700
through
62.14760
for
complete
reporting
and
recordkeeping
requirements).
(
b)
If
you
plan
to
continue
operation
and
come
into
compliance
with
the
requirements
of
this
subpart
after
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register,
but
before
the
date
two
years
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register,
you
must
petition
for
and
be
granted
an
extension
of
the
final
compliance
date
specified
§
62.14535(
a)(
3)
by
meeting
the
requirements
of
§
62.14536
and
you
must
meet
the
requirements
for
increments
of
progress
specified
in
§
62.14540
through
§
62.14565.
To
achieve
the
final
compliance
increment
of
progress,
you
must
complete
the
requirements
of
paragraphs
(
b)(
1)
through
(
b)(
5)
of
this
section.
(
1)
You
must
comply
with
the
operator
training
and
qualification
requirements
and
inspection
requirements
(
if
applicable)
of
this
subpart
by
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
2)
You
must
submit
a
waste
management
plan
no
later
than
the
date
six
months
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
3)
You
must
achieve
final
compliance
by
the
date
two
years
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
For
the
final
compliance
increment
of
progress,
you
must
incorporate
all
process
changes
and
complete
retrofit
construction
of
control
devices,
as
specified
in
the
final
control
plan,
so
that,
when
the
affected
CISWI
unit
is
brought
online,
all
necessary
process
changes
and
air
pollution
control
devices
operate
as
designed.
(
4)
You
must
conduct
the
initial
performance
test
within
90
days
after
the
date
when
you
are
required
to
achieve
final
compliance
under
paragraph
(
b)(
3)
of
this
section.
(
5)
You
must
submit
an
initial
report
including
the
result
of
the
initial
performance
no
later
than
60
days
following
the
initial
performance
test
(
see
§
§
62.14700
through
62.14760
for
complete
reporting
and
recordkeeping
requirements).
§
62.14536
What
steps
are
required
to
request
an
extension
of
the
initial
compliance
date
if
I
plan
to
continue
operation
of
my
CISWI
unit?
If
you
plan
to
continue
operation
and
want
to
come
into
compliance
with
the
requirements
of
this
subpart
after
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register,
but
before
the
date
two
years
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register,
then
you
must
petition
to
the
Administrator
to
grant
you
an
extension
by
following
the
procedures
outlined
in
paragraphs
(
a)
and
(
b)
of
this
section.
(
a)
You
must
submit
your
request
for
an
extension
to
the
EPA
Administrator
(
or
delegated
enforcement
authority)
on
or
before
the
date
two
months
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
b)
Your
request
must
include
documentation
of
the
analyses
undertaken
to
support
your
need
for
an
extension,
including
an
explanation
of
why
you
are
unable
to
meet
the
final
compliance
date
specified
in
§
62.14535(
a)(
3)
and
why
your
requested
extension
date
is
needed
to
provide
sufficient
time
for
you
to
design,
fabricate,
and
install
the
emissions
control
systems
necessary
to
meet
the
requirements
of
this
subpart.
A
request
based
upon
the
avoidance
of
costs
of
meeting
provisions
of
this
Subpart
is
not
acceptable
and
will
be
denied.
§
62.14540
When
must
I
complete
each
increment
of
progress?
If
you
plan
to
come
into
compliance
after
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register,
you
must
meet
the
two
increments
of
progress
specified
in
paragraphs
(
a)
and
(
b)
of
this
section.
(
a)
Increment
1.
Submit
a
final
control
plan
by
the
date
6
months
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
b)
Increment
2.
Reach
final
compliance
by
the
date
2
years
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
§
62.14545
What
must
I
include
in
each
notification
of
achievement
of
an
increment
of
progress?
Your
notification
of
achievement
of
an
increment
of
progress
must
include
the
four
items
specified
in
paragraphs
(
a)
through
(
d)
of
this
section.
(
a)
Notification
of
the
date
that
the
increment
of
progress
has
been
achieved.
(
b)
Any
items
required
to
be
submitted
with
each
increment
of
progress.
(
c)
Signature
of
the
owner
or
operator
of
the
CISWI
unit.
(
d)
The
date
you
were
required
to
complete
the
increment
of
progress.
§
62.14550
When
must
I
submit
a
notification
of
achievement
of
the
first
increment
of
progress?
Your
notification
for
achieving
the
first
increment
of
progress
must
be
postmarked
no
later
the
date
ten
days
after
the
date
that
is
six
months
from
the
date
of
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
§
62.14555
What
if
I
do
not
meet
an
increment
of
progress?
Failure
to
meet
an
increment
of
progress
is
a
violation
of
the
standards
under
this
subpart.
If
you
fail
to
meet
an
increment
of
progress,
you
must
submit
a
notification
to
the
Administrator
postmarked
within
10
business
days
after
the
due
date
for
that
increment
of
progress.
You
must
inform
the
Administrator
that
you
did
not
meet
the
increment,
and
you
must
continue
to
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submit
reports
each
subsequent
calendar
month
until
the
increment
of
progress
is
met.
§
62.14560
How
do
I
comply
with
the
increment
of
progress
for
submittal
of
a
control
plan?
For
your
control
plan
increment
of
progress,
you
must
satisfy
the
two
requirements
specified
in
paragraphs
(
a)
and
(
b)
of
this
section.
(
a)
Submit
the
final
control
plan
that
includes
the
six
items
described
in
paragraphs
(
a)(
1)
through
(
6)
of
this
section.
(
1)
A
description
of
the
devices
for
air
pollution
control
and
process
changes
that
you
will
use
to
comply
with
the
emission
limitations
and
other
requirements
of
this
subpart.
(
2)
The
type(
s)
of
waste
to
be
burned.
(
3)
The
maximum
design
waste
burning
capacity.
(
4)
The
anticipated
maximum
charge
rate.
(
5)
If
applicable,
the
petition
for
sitespecific
operating
limits
under
§
62.14640.
(
6)
A
schedule
that
includes
the
date
by
which
you
will
award
the
contracts
to
procure
emission
control
equipment
or
related
materials,
initiate
on
site
construction,
initiate
on
site
installation
of
emission
control
equipment,
and/
or
incorporate
process
changes,
and
the
date
by
which
you
will
initiate
on
site
construction.
(
b)
Maintain
an
onsite
copy
of
the
final
control
plan.
§
62.14565
How
do
I
comply
with
the
increment
of
progress
for
achieving
final
compliance?
For
the
final
compliance
increment
of
progress,
you
must
incorporate
all
process
changes
and
complete
retrofit
construction
of
control
devices,
as
specified
in
the
final
control
plan,
so
that,
when
the
affected
CISWI
unit
is
brought
online,
all
necessary
process
changes
and
air
pollution
control
devices
operate
as
designed.
§
62.14570
What
must
I
do
if
I
plan
to
permanently
close
my
CISWI
unit?
If
you
plan
to
permanently
close
your
CISWI
unit,
then
you
must
follow
the
requirements
in
either
paragraph
(
a)
or
(
b)
of
this
section
depending
on
when
you
plan
to
shut
down.
(
a)
If
you
plan
to
shut
down
by
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register,
rather
that
come
into
compliance
with
the
complete
set
of
requirements
in
this
subpart,
then
you
must
shut
down
by
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
You
must
meet
the
title
V
operating
permit
requirements
of
§
§
62.14830
and
62.14835
regardless
of
when
you
shut
down.
(
b)
If
you
plan
to
shut
down
rather
than
come
into
compliance
with
the
complete
set
of
requirements
of
this
subpart,
but
are
unable
to
shut
down
by
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register,
then
you
must
petition
EPA
for
and
be
granted
an
extension
by
following
the
procedures
outlined
in
paragraphs
(
b)(
1)
through
(
5)
of
this
section.
(
1)
You
must
submit
your
request
for
an
extension
to
the
EPA
Administrator
(
or
delegated
enforcement
authority)
by
the
date
two
months
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
Your
request
must
include:
(
i)
Documentation
of
the
analyses
undertaken
to
support
your
need
for
an
extension,
including
an
explanation
of
why
your
requested
extension
date
is
sufficient
time
for
you
to
shut
down
while
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register
does
not
provide
sufficient
time
for
shut
down.
A
request
based
upon
the
avoidance
of
costs
of
meeting
provisions
of
this
Subpart
is
not
acceptable
and
will
be
denied.
Your
documentation
must
include
an
evaluation
of
the
option
to
transport
your
waste
offsite
to
a
commercial
or
municipal
waste
treatment
and/
or
disposal
facility
on
a
temporary
or
permanent
basis;
and
(
ii)
Documentation
of
incremental
steps
of
progress,
including
dates
for
completing
the
increments
of
progress,
that
you
will
take
towards
shutting
down.
Some
suggested
incremental
steps
of
progress
towards
shut
down
are
provided
as
follows:
If
you
.
.
.
then
your
increments
of
progress
could
be
.
.
.
(
A)
Need
an
extension
so
you
can
install
on
onsite
alternative
waste
treatment
technology
before
you
shut
down
your
CISWI.
(
1)
Date
when
you
will
enter
into
a
contract
with
an
alternative
treatment
technology
vendor,
(
2)
Date
for
initiating
onsite
construction
or
installation
of
the
alternative
technology,
(
3)
Date
for
completing
onsite
construction
or
installation
of
the
alternative
technology
and
(
4)
Date
for
shutting
down
the
CISWI.
(
B)
Need
an
extension
so
you
can
acquire
the
services
of
a
commercial
waste
disposal
company
before
you
shut
down
your
CISWI.
(
1)
Date
when
price
quotes
will
be
obtained
from
commercial
disposal
companies,
(
2)
Date
when
you
will
enter
into
a
contract
with
a
commercial
disposal
company,
and
(
3)
Date
for
shutting
down
the
CISWI.
(
2)
You
must
shut
down
no
later
than
by
the
date
two
years
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
3)
You
must
comply
with
the
operator
training
and
qualification
requirements
and
inspection
requirements
(
if
applicable)
of
this
subpart
by
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
4)
You
must
submit
a
legally
binding
closure
agreement
to
the
Administrator
by
the
date
six
months
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
The
closure
agreement
must
specify
the
date
by
which
operation
will
cease.
The
closure
date
cannot
be
later
than
the
date
2
years
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
5)
You
must
meet
the
title
V
operating
permit
requirements
of
§
§
62.14830
and
62.14835
regardless
of
when
you
shut
down.
§
62.14575
What
must
I
do
if
I
close
my
CISWI
unit
and
then
restart
it?
If
you
temporarily
close
your
CISWI
unit
and
restart
the
unit
for
the
purpose
of
continuing
operation
of
your
CISWI
unit,
then
you
must
follow
the
requirements
in
paragraphs
(
a),
(
b),
or
(
c)
of
this
section
depending
on
when
you
plan
to
come
into
compliance
with
the
requirements
of
this
subpart.
You
must
meet
the
title
V
operating
permit
requirements
of
§
§
62.14830
and
62.14835
at
the
time
you
restart
your
CISWI
unit.
(
a)
If
you
plan
to
continue
operation
and
come
into
compliance
with
the
requirements
of
this
subpart
by
the
by
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register,
then
you
must
complete
the
requirements
of
§
62.14535(
a).
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(
b)
If
you
plan
to
continue
operation
and
come
into
compliance
with
the
requirements
of
this
subpart
on
or
before
the
date
two
years
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register,
then
you
must
complete
the
requirements
§
62.14535(
b).
You
must
have
first
requested
and
been
granted
an
extension
from
the
initial
compliance
date
by
following
the
requirements
of
§
62.14536.
(
c)
If
you
restart
your
CISWI
unit
after
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register
and
resume
operation,
but
have
not
previously
requested
an
extension
by
meeting
all
of
the
requirements
of
§
62.14536,
you
must
meet
all
of
the
requirements
of
§
62.14535(
a)(
1)
through
(
a)(
5)
at
the
time
you
restart
your
CISWI
unit.
Upon
restarting
your
CISWI
unit,
you
must
have
incorporated
all
process
changes
and
completed
retrofit
construction
of
control
devices
so
that
when
the
affected
CISWI
unit
is
brought
online,
all
necessary
process
changes
and
air
pollution
control
devices
operate
as
designed.
Waste
Management
Plan
§
62.14580
What
is
a
waste
management
plan?
A
waste
management
plan
is
a
written
plan
that
identifies
both
the
feasibility
and
the
methods
used
to
reduce
or
separate
certain
components
of
solid
waste
from
the
waste
stream
in
order
to
reduce
or
eliminate
toxic
emissions
from
incinerated
waste.
§
62.14585
When
must
I
submit
my
waste
management
plan?
You
must
submit
a
waste
management
plan
no
later
than
the
date
six
months
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
§
62.14590
What
should
I
include
in
my
waste
management
plan?
A
waste
management
plan
must
include
consideration
of
the
reduction
or
separation
of
waste
stream
elements
such
as
paper,
cardboard,
plastics,
glass,
batteries,
or
metals;
or
the
use
of
recyclable
materials.
The
plan
must
identify
any
additional
waste
management
measures,
and
the
source
must
implement
those
measures
considered
practical
and
feasible,
based
on
the
effectiveness
of
waste
management
measures
already
in
place,
the
costs
of
additional
measures,
the
emissions
reductions
expected
to
be
achieved,
and
any
other
environmental
or
energy
impacts
they
might
have.
Operator
Training
and
Qualification
§
62.14595
What
are
the
operator
training
and
qualification
requirements?
(
a)
You
must
have
a
fully
trained
and
qualified
CISWI
unit
operator
accessible
at
all
times
when
the
unit
is
in
operation,
either
at
your
facility
or
able
to
be
at
your
facility
within
one
hour.
The
trained
and
qualified
CISWI
unit
operator
may
operate
the
CISWI
unit
directly
or
be
the
direct
supervisor
of
one
or
more
other
plant
personnel
who
operate
the
unit.
If
all
qualified
CISWI
unit
operators
are
temporarily
not
accessible,
you
must
follow
the
procedures
in
§
62.14625.
(
b)
Operator
training
and
qualification
must
be
obtained
through
a
Stateapproved
program
or
by
completing
the
requirements
included
in
paragraph
(
c)
of
this
section.
(
c)
Training
must
be
obtained
by
completing
an
incinerator
operator
training
course
that
includes,
at
a
minimum,
the
three
elements
described
in
paragraphs
(
c)(
1)
through
(
3)
of
this
section.
(
1)
Training
on
the
thirteen
subjects
listed
in
paragraphs
(
c)(
1)(
i)
through
(
xiii)
of
this
section.
(
i)
Environmental
concerns,
including
types
of
emissions.
(
ii)
Basic
combustion
principles,
including
products
of
combustion.
(
iii)
Operation
of
the
specific
type
of
incinerator
to
be
used
by
the
operator,
including
proper
startup,
waste
charging,
and
shutdown
procedures.
(
iv)
Combustion
controls
and
monitoring.
(
v)
Operation
of
air
pollution
control
equipment
and
factors
affecting
performance
(
where
applicable).
(
vi)
Inspection
and
maintenance
of
the
incinerator
and
air
pollution
control
devices.
(
vii)
Actions
to
correct
malfunctions
or
conditions
that
may
lead
to
malfunction.
(
viii)
Bottom
and
fly
ash
characteristics
and
handling
procedures.
(
ix)
Applicable
Federal,
State,
and
local
regulations,
including
Occupational
Safety
and
Health
Administration
workplace
standards.
(
x)
Pollution
prevention.
(
xi)
Waste
management
practices.
(
xii)
Recordkeeping
requirements.
(
xiii)
Methods
to
continuously
monitor
CISWI
unit
and
air
pollution
control
device
operating
parameters
and
monitoring
equipment
calibration
procedures
(
where
applicable).
(
2)
An
examination
designed
and
administered
by
the
instructor.
(
3)
Written
material
covering
the
training
course
topics
that
can
serve
as
reference
material
following
completion
of
the
course.
§
62.14600
When
must
the
operator
training
course
be
completed?
(
a)
The
operator
training
course
must
be
completed
by
the
later
of
the
two
dates
specified
in
paragraphs
(
a)(
1)
and
(
2)
of
this
section.
(
1)
The
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
2)
Six
months
after
an
employee
assumes
responsibility
for
operating
the
CISWI
unit
or
assumes
responsibility
for
supervising
the
operation
of
the
CISWI
unit.
(
b)
You
must
follow
the
requirements
in
§
63.14625
if
all
qualified
operators
are
temporarily
not
accessible.
§
62.14605
How
do
I
obtain
my
operator
qualification?
(
a)
You
must
obtain
operator
qualification
by
completing
a
training
course
that
satisfies
the
criteria
under
§
62.14595(
b)
or
(
c).
(
b)
Qualification
is
valid
from
the
date
on
which
the
training
course
is
completed
and
the
operator
successfully
passes
the
examination
required
under
§
62.14595(
c)(
2).
§
62.14610
How
do
I
maintain
my
operator
qualification?
To
maintain
qualification,
you
must
complete
an
annual
review
or
refresher
course
of
at
least
4
hours
covering,
at
a
minimum,
the
five
topics
described
in
paragraphs
(
a)
through
(
e)
of
this
section.
(
a)
Update
of
regulations.
(
b)
Incinerator
operation,
including
startup
and
shutdown
procedures,
waste
charging,
and
ash
handling.
(
c)
Inspection
and
maintenance.
(
d)
Responses
to
malfunctions
or
conditions
that
may
lead
to
malfunction.
(
e)
Discussion
of
operating
problems
encountered
by
attendees.
§
62.14615
How
do
I
renew
my
lapsed
operator
qualification?
You
must
renew
a
lapsed
operator
qualification
by
one
of
the
two
methods
specified
in
paragraphs
(
a)
and
(
b)
of
this
section.
(
a)
For
a
lapse
of
less
than
3
years,
you
must
complete
a
standard
annual
refresher
course
described
in
§
62.14610.
(
b)
For
a
lapse
of
3
years
or
more,
you
must
repeat
the
initial
qualification
requirements
in
§
62.14605(
a).
§
62.14620
What
site
specific
documentation
is
required?
(
a)
Documentation
must
be
available
at
the
facility
and
readily
accessible
for
all
CISWI
unit
operators
that
addresses
the
ten
topics
described
in
paragraphs
(
a)(
1)
through
(
10)
of
this
section.
You
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Proposed
Rules
must
maintain
this
information
and
the
training
records
required
by
paragraph
(
c)
of
this
section
in
a
manner
that
they
can
be
readily
accessed
and
are
suitable
for
inspection
upon
request.
(
1)
Summary
of
the
applicable
standards
under
this
subpart.
(
2)
Procedures
for
receiving,
handling,
and
charging
waste.
(
3)
Incinerator
startup,
shutdown,
and
malfunction
procedures.
(
4)
Procedures
for
maintaining
proper
combustion
air
supply
levels.
(
5)
Procedures
for
operating
the
incinerator
and
associated
air
pollution
control
systems
within
the
standards
established
under
this
subpart.
(
6)
Monitoring
procedures
for
demonstrating
compliance
with
the
incinerator
operating
limits.
(
7)
Reporting
and
recordkeeping
procedures.
(
8)
The
waste
management
plan
required
under
§
§
62.14580
through
62.14590.
(
9)
Procedures
for
handling
ash.
(
10)
A
list
of
the
wastes
burned
during
the
performance
test.
(
b)
You
must
establish
a
program
for
reviewing
the
information
listed
in
paragraph
(
a)
of
this
section
with
each
employee
who
operates
your
incinerator.
(
1)
The
initial
review
of
the
information
listed
in
paragraph
(
a)
of
this
section
must
be
conducted
by
the
later
of
the
two
dates
specified
in
paragraphs
(
b)(
1)(
i)
through
(
ii)
of
this
section.
(
i)
The
date
1
year
after
publication
of
this
final
rule
in
the
Federal
Register.
(
ii)
Two
months
after
being
assigned
to
operate
the
CISWI
unit.
(
2)
Subsequent
annual
reviews
of
the
information
listed
in
paragraph
(
a)
of
this
section
must
be
conducted
no
later
than
12
months
following
the
previous
review.
(
c)
You
must
also
maintain
the
information
specified
in
paragraphs
(
c)(
1)
through
(
3)
of
this
section.
(
1)
Records
showing
the
names
of
all
plant
personnel
who
operate
your
CISWI
unit
who
have
completed
review
of
the
information
in
§
62.14620(
a)
as
required
by
§
62.14620(
b),
including
the
date
of
the
initial
review
and
all
subsequent
annual
reviews.
(
2)
Records
showing
the
names
of
all
plant
personnel
who
operate
your
CISWI
unit
who
have
completed
the
operator
training
requirements
under
§
62.14595,
met
the
criteria
for
qualification
under
§
62.14605,
and
maintained
or
renewed
their
qualification
under
§
62.14610
or
§
62.14615.
Records
must
include
documentation
of
training,
the
dates
of
the
initial
refresher
training,
and
the
dates
of
their
qualification
and
all
subsequent
renewals
of
such
qualifications.
(
3)
For
each
qualified
operator,
the
phone
and/
or
pager
number
at
which
they
can
be
reached
during
operating
hours.
§
62.14625
What
if
all
the
qualified
operators
are
temporarily
not
accessible?
If
all
qualified
operators
are
temporarily
not
accessible
(
i.
e.,
not
at
the
facility
and
not
able
to
be
at
the
facility
within
1
hour),
you
must
meet
one
of
the
two
criteria
specified
in
paragraphs
(
a)
and
(
b)
of
this
section,
depending
on
the
length
of
time
that
a
qualified
operator
is
not
accessible.
(
a)
When
all
qualified
operators
are
not
accessible
for
more
than
8
hours,
but
less
than
2
weeks,
the
CISWI
unit
may
be
operated
by
other
plant
personnel
familiar
with
the
operation
of
the
CISWI
unit
who
have
completed
a
review
of
the
information
specified
in
§
62.14620(
a)
within
the
past
12
months.
However,
you
must
record
the
period
when
all
qualified
operators
were
not
accessible
and
include
this
deviation
in
the
annual
report
as
specified
under
§
62.14730.
(
b)
When
all
qualified
operators
are
not
accessible
for
2
weeks
or
more,
you
must
take
the
two
actions
that
are
described
in
paragraphs
(
b)(
1)
and
(
2)
of
this
section.
(
1)
Notify
the
Administrator
of
this
deviation
in
writing
within
10
days.
In
the
notice,
state
what
caused
this
deviation,
what
you
are
doing
to
ensure
that
a
qualified
operator
is
accessible,
and
when
you
anticipate
that
a
qualified
operator
will
be
accessible.
(
2)
Submit
a
status
report
to
the
Administrator
every
4
weeks
outlining
what
you
are
doing
to
ensure
that
a
qualified
operator
is
accessible,
stating
when
you
anticipate
that
a
qualified
operator
will
be
accessible
and
requesting
approval
from
the
Administrator
to
continue
operation
of
the
CISWI
unit.
You
must
submit
the
first
status
report
4
weeks
after
you
notify
the
Administrator
of
the
deviation
under
paragraph
(
b)(
1)
of
this
section.
If
the
Administrator
notifies
you
that
your
request
to
continue
operation
of
the
CISWI
unit
is
disapproved,
the
CISWI
unit
may
continue
operation
for
90
days,
then
must
cease
operation.
Operation
of
the
unit
may
resume
if
you
meet
the
two
requirements
in
paragraphs
(
b)(
2)(
i)
and
(
ii)
of
this
section.
(
i)
A
qualified
operator
is
accessible
as
required
under
§
62.14595(
a).
(
ii)
You
notify
the
Administrator
that
a
qualified
operator
is
accessible
and
that
you
are
resuming
operation.
Emission
Limitations
and
Operating
Limits
§
62.14630
What
emission
limitations
must
I
meet
and
by
when?
You
must
meet
the
emission
limitations
specified
in
Table
1
of
this
subpart
by
the
applicable
final
compliance
date
for
your
CISWI
unit.
§
62.14635
What
operating
limits
must
I
meet
and
by
when?
(
a)
If
you
use
a
wet
scrubber
to
comply
with
the
emission
limitations,
you
must
establish
operating
limits
for
four
operating
parameters
(
as
specified
in
table
2
of
this
subpart)
as
described
in
paragraphs
(
a)(
1)
through
(
4)
of
this
section
during
the
initial
performance
test.
(
1)
Maximum
charge
rate,
calculated
using
one
of
the
two
different
procedures
in
paragraph
(
a)(
1)(
i)
or
(
ii),
as
appropriate.
(
i)
For
continuous
and
intermittent
units,
maximum
charge
rate
is
110
percent
of
the
average
charge
rate
measured
during
the
most
recent
performance
test
demonstrating
compliance
with
all
applicable
emission
limitations.
(
ii)
For
batch
units,
maximum
charge
rate
is
110
percent
of
the
daily
charge
rate
measured
during
the
most
recent
performance
test
demonstrating
compliance
with
all
applicable
emission
limitations.
(
2)
Minimum
pressure
drop
across
the
wet
scrubber,
which
is
calculated
as
90
percent
of
the
average
pressure
drop
across
the
wet
scrubber
measured
during
the
most
recent
performance
test
demonstrating
compliance
with
the
particulate
matter
emission
limitations;
or
minimum
amperage
to
the
wet
scrubber,
which
is
calculated
as
90
percent
of
the
average
amperage
to
the
wet
scrubber
measured
during
the
most
recent
performance
test
demonstrating
compliance
with
the
particulate
matter
emission
limitations.
(
3)
Minimum
scrubber
liquor
flow
rate,
which
is
calculated
as
90
percent
of
the
average
liquor
flow
rate
at
the
inlet
to
the
wet
scrubber
measured
during
the
most
recent
performance
test
demonstrating
compliance
with
all
applicable
emission
limitations.
(
4)
Minimum
scrubber
liquor
pH,
which
is
calculated
as
90
percent
of
the
average
liquor
pH
at
the
inlet
to
the
wet
scrubber
measured
during
the
most
recent
performance
test
demonstrating
compliance
with
the
hydrogen
chloride
emission
limitation.
(
b)
You
must
meet
the
operating
limits
established
during
the
initial
performance
test
on
the
date
the
initial
performance
test
is
required
or
completed
(
whichever
is
earlier).
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Proposed
Rules
(
c)
If
you
use
a
fabric
filter
to
comply
with
the
emission
limitations,
you
must
operate
each
fabric
filter
system
such
that
the
bag
leak
detection
system
alarm
does
not
sound
more
than
5
percent
of
the
operating
time
during
any
6
month
period.
In
calculating
this
operating
time
percentage,
if
inspection
of
the
fabric
filter
demonstrates
that
no
corrective
action
is
required,
no
alarm
time
is
counted.
If
corrective
action
is
required,
each
alarm
shall
be
counted
as
a
minimum
of
1
hour.
If
you
take
longer
than
1
hour
to
initiate
corrective
action,
the
alarm
time
shall
be
counted
as
the
actual
amount
of
time
taken
by
you
to
initiate
corrective
action.
§
62.14640
What
if
I
do
not
use
a
wet
scrubber
to
comply
with
the
emission
limitations?
If
you
use
an
air
pollution
control
device
other
than
a
wet
scrubber,
or
limit
emissions
in
some
other
manner,
to
comply
with
the
emission
limitations
under
§
62.14630,
you
must
petition
the
Administrator
for
specific
operating
limits
to
be
established
during
the
initial
performance
test
and
continuously
monitored
thereafter.
You
must
not
conduct
the
initial
performance
test
until
after
the
petition
has
been
approved
by
the
Administrator.
Your
petition
must
include
the
five
items
listed
in
paragraphs
(
a)
through
(
e)
of
this
section.
(
a)
Identification
of
the
specific
parameters
you
propose
to
use
as
additional
operating
limits.
(
b)
A
discussion
of
the
relationship
between
these
parameters
and
emissions
of
regulated
pollutants,
identifying
how
emissions
of
regulated
pollutants
change
with
changes
in
these
parameters,
and
how
limits
on
these
parameters
will
serve
to
limit
emissions
of
regulated
pollutants.
(
c)
A
discussion
of
how
you
will
establish
the
upper
and/
or
lower
values
for
these
parameters
which
will
establish
the
operating
limits
on
these
parameters.
(
d)
A
discussion
identifying
the
methods
you
will
use
to
measure
and
the
instruments
you
will
use
to
monitor
these
parameters,
as
well
as
the
relative
accuracy
and
precision
of
these
methods
and
instruments.
(
e)
A
discussion
identifying
the
frequency
and
methods
for
recalibrating
the
instruments
you
will
use
for
monitoring
these
parameters.
§
62.14645
What
happens
during
periods
of
startup,
shutdown,
and
malfunction?
(
a)
The
emission
limitations
and
operating
limits
apply
at
all
times
except
during
periods
of
CISWI
unit
startup,
shutdown,
or
malfunction
as
defined
in
§
62.14840.
(
b)
Each
malfunction
must
last
no
longer
than
three
hours.
Performance
Testing
§
62.14650
How
do
I
conduct
the
initial
and
annual
performance
test?
(
a)
All
performance
tests
must
consist
of
a
minimum
of
three
test
runs
conducted
under
conditions
representative
of
normal
operations.
(
b)
You
must
document
that
the
waste
burned
during
the
performance
test
is
representative
of
the
waste
burned
under
normal
operating
conditions
by
maintaining
a
log
of
the
quantity
of
waste
burned
(
as
required
in
§
62.14700(
b)(
1))
and
the
types
of
waste
burned
during
the
performance
test.
(
c)
All
performance
tests
must
be
conducted
using
the
minimum
run
duration
specified
in
Table
1
of
this
subpart.
(
d)
Method
1
of
40
CFR
part
60,
Appendix
A
must
be
used
to
select
the
sampling
location
and
number
of
traverse
points.
(
e)
Method
3A
or
3B
of
40
CFR
part
60,
Appendix
A
must
be
used
for
gas
composition
analysis,
including
measurement
of
oxygen
concentration.
Method
3A
or
3B
of
40
CFR
part
60,
Appendix
A
must
be
used
simultaneously
with
each
method.
(
f)
All
pollutant
concentrations,
except
for
opacity,
must
be
adjusted
to
7
percent
oxygen
using
Equation
1
of
this
section:
C
O
(
Eq.
1)
adj=
(
)
(
)
Cmeas
20
9
7
20
9
2
.
/
.
%
Where:
Cadj
=
pollutant
concentration
adjusted
to
7
percent
oxygen;
Cmeas
=
pollutant
concentration
measured
on
a
dry
basis;
(
20.9
7)
=
20.9
percent
oxygen
¥
7
percent
oxygen
(
defined
oxygen
correction
basis);
20.9
=
oxygen
concentration
in
air,
percent;
and
%
O2
=
oxygen
concentration
measured
on
a
dry
basis,
percent.
(
g)
You
must
determine
dioxins/
furans
toxic
equivalency
by
following
the
procedures
in
paragraphs
(
g)(
1)
through
(
3)
of
this
section.
(
1)
Measure
the
concentration
of
each
dioxin/
furan
tetra
through
octacongener
emitted
using
EPA
Method
23.
(
2)
For
each
dioxin/
furan
congener
measured
in
accordance
with
paragraph
(
g)(
1)
of
this
section,
multiply
the
congener
concentration
by
its
corresponding
toxic
equivalency
factor
specified
in
Table
3
of
this
subpart.
(
3)
Sum
the
products
calculated
in
accordance
with
paragraph
(
g)(
2)
of
this
section
to
obtain
the
total
concentration
of
dioxins/
furans
emitted
in
terms
of
toxic
equivalency.
§
62.14655
How
are
the
performance
test
data
used?
You
use
results
of
performance
tests
to
demonstrate
compliance
with
the
emission
limitations
in
Table
1
of
this
subpart.
Initial
Compliance
Requirements
§
62.14660
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations
and
establish
the
operating
limits?
You
must
conduct
an
initial
performance
test,
as
required
under
40
CFR
60.8,
to
determine
compliance
with
the
emission
limitations
in
Table
1
of
this
subpart
and
to
establish
operating
limits
using
the
procedure
in
§
62.14635
or
§
62.14640.
The
initial
performance
test
must
be
conducted
using
the
test
methods
listed
in
Table
1
of
this
subpart
and
the
procedures
in
§
62.14650.
§
62.14665
By
what
date
must
I
conduct
the
initial
performance
test?
The
initial
performance
test
must
be
conducted
no
later
than
90
days
after
your
final
compliance
date.
Continuous
Compliance
Requirements
§
62.14670
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations
and
the
operating
limits?
(
a)
You
must
conduct
an
annual
performance
test
for
particulate
matter,
hydrogen
chloride,
and
opacity
for
each
CISWI
unit
as
required
under
40
CFR
60.8
to
determine
compliance
with
the
emission
limitations.
The
annual
performance
test
must
be
conducted
using
the
test
methods
listed
in
Table
1
of
this
subpart
and
the
procedures
in
§
62.14650.
(
b)
You
must
continuously
monitor
the
operating
parameters
specified
in
§
62.14635
or
established
under
§
62.14640.
Operation
above
the
established
maximum
or
below
the
established
minimum
operating
limits
constitutes
a
deviation
from
the
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Register
/
Vol.
67,
No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
established
operating
limits.
Three
hour
rolling
average
values
are
used
to
determine
compliance
(
except
for
baghouse
leak
detection
system
alarms)
unless
a
different
averaging
period
is
established
under
§
62.14640.
Operating
limits
do
not
apply
during
performance
tests.
(
c)
You
must
only
burn
the
same
types
of
waste
used
to
establish
operating
limits
during
the
performance
test.
§
62.14675
By
what
date
must
I
conduct
the
annual
performance
test?
You
must
conduct
annual
performance
tests
for
particulate
matter,
hydrogen
chloride,
and
opacity
within
12
months
following
the
initial
performance
test.
Conduct
subsequent
annual
performance
tests
within
12
months
following
the
previous
one.
§
62.14680
May
I
conduct
performance
testing
less
often?
(
a)
You
can
test
less
often
for
a
given
pollutant
if
you
have
test
data
for
at
least
3
years,
and
all
performance
tests
for
the
pollutant
(
particulate
matter,
hydrogen
chloride,
or
opacity)
over
3
consecutive
years
show
that
you
comply
with
the
emission
limitation.
In
this
case,
you
do
not
have
to
conduct
a
performance
test
for
that
pollutant
for
the
next
2
years.
You
must
conduct
a
performance
test
during
the
third
year
and
no
later
than
36
months
following
the
previous
performance
test.
(
b)
If
your
CISWI
unit
continues
to
meet
the
emission
limitation
for
particulate
matter,
hydrogen
chloride,
or
opacity,
you
may
choose
to
conduct
performance
tests
for
these
pollutants
every
third
year,
but
each
test
must
be
within
36
months
of
the
previous
performance
test.
(
c)
If
a
performance
test
shows
a
deviation
from
an
emission
limitation
for
particulate
matter,
hydrogen
chloride,
or
opacity,
you
must
conduct
annual
performance
tests
for
that
pollutant
until
all
performance
tests
over
a
3
year
period
show
compliance.
§
62.14685
May
I
conduct
a
repeat
performance
test
to
establish
new
operating
limits?
(
a)
Yes.
You
may
conduct
a
repeat
performance
test
at
any
time
to
establish
new
values
for
the
operating
limits.
The
Administrator
may
request
a
repeat
performance
test
at
any
time.
(
b)
You
must
repeat
the
performance
test
if
your
feed
stream
is
different
than
the
feed
streams
used
during
any
performance
test
used
to
demonstrate
compliance.
Monitoring
§
62.14690
What
monitoring
equipment
must
I
install
and
what
parameters
must
I
monitor?
(
a)
If
you
are
using
a
wet
scrubber
to
comply
with
the
emission
limitation
under
§
62.14630,
you
must
install,
calibrate
(
to
manufacturers'
specifications),
maintain,
and
operate
devices
(
or
establish
methods)
for
monitoring
the
value
of
the
operating
parameters
used
to
determine
compliance
with
the
operating
limits
listed
in
Table
2
of
this
subpart.
These
devices
(
or
methods)
must
measure
and
record
the
values
for
these
operating
parameters
at
the
frequencies
indicated
in
Table
2
of
this
subpart
at
all
times
except
as
specified
in
§
62.14695(
a).
(
b)
If
you
use
a
fabric
filter
to
comply
with
the
requirements
of
this
subpart,
you
must
install,
calibrate,
maintain,
and
continuously
operate
a
bag
leak
detection
system
as
specified
in
paragraphs
(
b)(
1)
through
(
8)
of
this
section.
(
1)
You
must
install
and
operate
a
bag
leak
detection
system
for
each
exhaust
stack
of
the
fabric
filter.
(
2)
Each
bag
leak
detection
system
must
be
installed,
operated,
calibrated,
and
maintained
in
a
manner
consistent
with
the
manufacturer's
written
specifications
and
recommendations.
(
3)
The
bag
leak
detection
system
must
be
certified
by
the
manufacturer
to
be
capable
of
detecting
particulate
matter
emissions
at
concentrations
of
10
milligrams
per
actual
cubic
meter
or
less.
(
4)
The
bag
leak
detection
system
sensor
must
provide
output
of
relative
or
absolute
particulate
matter
loadings.
(
5)
The
bag
leak
detection
system
must
be
equipped
with
a
device
to
continuously
record
the
output
signal
from
the
sensor.
(
6)
The
bag
leak
detection
system
must
be
equipped
with
an
alarm
system
that
will
sound
automatically
when
an
increase
in
relative
particulate
matter
emissions
over
a
preset
level
is
detected.
The
alarm
must
be
located
where
it
is
easily
heard
by
plant
operating
personnel.
(
7)
For
positive
pressure
fabric
filter
systems,
a
bag
leak
detection
system
must
be
installed
in
each
baghouse
compartment
or
cell.
For
negative
pressure
or
induced
air
fabric
filters,
the
bag
leak
detector
must
be
installed
downstream
of
the
fabric
filter.
(
8)
Where
multiple
detectors
are
required,
the
system's
instrumentation
and
alarm
may
be
shared
among
detectors.
(
c)
If
you
are
using
something
other
than
a
wet
scrubber
to
comply
with
the
emission
limitations
under
§
62.14630,
you
must
install,
calibrate
(
to
the
manufacturers'
specifications),
maintain,
and
operate
the
equipment
necessary
to
monitor
compliance
with
the
site
specific
operating
limits
established
using
the
procedures
in
§
62.14640.
§
62.14695
Is
there
a
minimum
amount
of
monitoring
data
I
must
obtain?
(
a)
Except
for
monitoring
malfunctions,
associated
repairs,
and
required
quality
assurance
or
quality
control
activities
(
including,
as
applicable,
calibration
checks
and
required
zero
and
span
adjustments
of
the
monitoring
system),
you
must
conduct
all
monitoring
at
all
times
the
CISWI
unit
is
operating.
(
b)
Do
not
use
data
recorded
during
monitor
malfunctions,
associated
repairs,
and
required
quality
assurance
or
quality
control
activities
for
meeting
the
requirements
of
this
subpart,
including
data
averages
and
calculations.
You
must
use
all
the
data
collected
during
all
other
periods
in
assessing
compliance
with
the
operating
limits.
Recordkeeping
and
Reporting
§
62.14700
What
records
must
I
keep?
You
must
maintain
the
13
items
(
as
applicable)
as
specified
in
paragraphs
(
a)
through
(
m)
of
this
section
for
a
period
of
at
least
5
years:
(
a)
Calendar
date
of
each
record.
(
b)
Records
of
the
data
described
in
paragraphs
(
b)(
1)
through
(
6)
of
this
section:
(
1)
The
CISWI
unit
charge
dates,
times,
weights,
and
hourly
charge
rates.
(
2)
Liquor
flow
rate
to
the
wet
scrubber
inlet
every
15
minutes
of
operation,
as
applicable.
(
3)
Pressure
drop
across
the
wet
scrubber
system
every
15
minutes
of
operation
or
amperage
to
the
wet
scrubber
every
15
minutes
of
operation,
as
applicable.
(
4)
Liquor
pH
as
introduced
to
the
wet
scrubber
every
15
minutes
of
operation,
as
applicable.
(
5)
For
affected
CISWI
units
that
establish
operating
limits
for
controls
other
than
wet
scrubbers
under
§
62.14640,
you
must
maintain
data
collected
for
all
operating
parameters
used
to
determine
compliance
with
the
operating
limits.
(
6)
If
a
fabric
filter
is
used
to
comply
with
the
emission
limitations,
you
must
record
the
date,
time,
and
duration
of
each
alarm
and
the
time
corrective
action
was
initiated
and
completed,
and
a
brief
description
of
the
cause
of
the
alarm
and
the
corrective
action
taken.
You
must
also
record
the
percent
of
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Federal
Register
/
Vol.
67,
No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
operating
time
during
each
6
month
period
that
the
alarm
sounds,
calculated
as
specified
in
§
62.14635(
c).
(
c)
Identification
of
calendar
dates
and
times
for
which
monitoring
systems
used
to
monitor
operating
limits
were
inoperative,
inactive,
malfunctioning,
or
out
of
control
(
except
for
downtime
associated
with
zero
and
span
and
other
routine
calibration
checks).
Identify
the
operating
parameters
not
measured,
the
duration,
reasons
for
not
obtaining
the
data,
and
a
description
of
corrective
actions
taken.
(
d)
Identification
of
calendar
dates,
times,
and
durations
of
malfunctions,
and
a
description
of
the
malfunction
and
the
corrective
action
taken.
(
e)
Identification
of
calendar
dates
and
times
for
which
data
show
a
deviation
from
the
operating
limits
in
table
2
of
this
subpart
or
a
deviation
from
other
operating
limits
established
under
§
62.14640
with
a
description
of
the
deviations,
reasons
for
such
deviations,
and
a
description
of
corrective
actions
taken.
(
f)
The
results
of
the
initial,
annual,
and
any
subsequent
performance
tests
conducted
to
determine
compliance
with
the
emission
limits
and/
or
to
establish
operating
limits,
as
applicable.
Retain
a
copy
of
the
complete
test
report
including
calculations.
(
g)
Records
showing
the
names
of
CISWI
unit
operators
who
have
completed
review
of
the
information
in
§
62.14620(
a)
as
required
by
§
62.14620(
b),
including
the
date
of
the
initial
review
and
all
subsequent
annual
reviews.
(
h)
Records
showing
the
names
of
the
CISWI
operators
who
have
completed
the
operator
training
requirements
under
§
62.14595,
met
the
criteria
for
qualification
under
§
62.14605,
and
maintained
or
renewed
their
qualification
under
§
62.14610
or
§
62.14615.
Records
must
include
documentation
of
training,
the
dates
of
the
initial
and
refresher
training,
and
the
dates
of
their
qualification
and
all
subsequent
renewals
of
such
qualifications.
(
i)
For
each
qualified
operator,
the
phone
and/
or
pager
number
at
which
they
can
be
reached
during
operating
hours.
(
j)
Records
of
calibration
of
any
monitoring
devices
as
required
under
§
62.14690.
(
k)
Equipment
vendor
specifications
and
related
operation
and
maintenance
requirements
for
the
incinerator,
emission
controls,
and
monitoring
equipment.
(
l)
The
information
listed
in
§
62.14620(
a).
(
m)
On
a
daily
basis,
keep
a
log
of
the
quantity
of
waste
burned
and
the
types
of
waste
burned
(
always
required).
§
62.14705
Where
and
in
what
format
must
I
keep
my
records?
All
records
must
be
available
onsite
in
either
paper
copy
or
computer
readable
format
that
can
be
printed
upon
request,
unless
an
alternative
format
is
approved
by
the
Administrator.
§
62.14710
What
reports
must
I
submit?
See
Table
4
of
this
subpart
for
a
summary
of
the
reporting
requirements.
§
62.14715
When
must
I
submit
my
waste
management
plan?
You
must
submit
the
waste
management
plan
no
later
than
the
date
six
months
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
§
62.14720
What
information
must
I
submit
following
my
initial
performance
test?
You
must
submit
the
information
specified
in
paragraphs
(
a)
through
(
c)
of
this
section
no
later
than
60
days
following
the
initial
performance
test.
All
reports
must
be
signed
by
the
facilities
manager.
(
a)
The
complete
test
report
for
the
initial
performance
test
results
obtained
under
§
62.14660,
as
applicable.
(
b)
The
values
for
the
site
specific
operating
limits
established
in
§
62.14635
or
§
62.14640.
(
c)
If
you
are
using
a
fabric
filter
to
comply
with
the
emission
limitations,
documentation
that
a
bag
leak
detection
system
has
been
installed
and
is
being
operated,
calibrated,
and
maintained
as
required
by
§
62.14690(
b).
§
62.14725
When
must
I
submit
my
annual
report?
You
must
submit
an
annual
report
no
later
than
12
months
following
the
submission
of
the
information
in
§
62.14720.
You
must
submit
subsequent
reports
no
more
than
12
months
following
the
previous
report.
As
with
all
other
requirements
in
this
subpart,
the
requirement
to
submit
an
annual
report
does
not
modify
or
replace
the
operating
permit
requirements
of
40
CFR
parts
70
and
71.
§
62.14730
What
information
must
I
include
in
my
annual
report?
The
annual
report
required
under
§
62.14725
must
include
the
ten
items
listed
in
paragraphs
(
a)
through
(
j)
of
this
section.
If
you
have
a
deviation
from
the
operating
limits
or
the
emission
limitations,
you
must
also
submit
deviation
reports
as
specified
in
§
§
62.14735,
62.14740,
and
62.14745.
(
a)
Company
name
and
address.
(
b)
Statement
by
a
responsible
official,
with
that
official's
name,
title,
and
signature,
certifying
the
accuracy
of
the
content
of
the
report.
(
c)
Date
of
report
and
beginning
and
ending
dates
of
the
reporting
period.
(
d)
The
values
for
the
operating
limits
established
pursuant
to
§
62.14635
or
§
62.14640.
(
e)
If
no
deviation
from
any
emission
limitation
or
operating
limit
that
applies
to
you
has
been
reported,
a
statement
that
there
was
no
deviation
from
the
emission
limitations
or
operating
limits
during
the
reporting
period,
and
that
no
monitoring
system
used
to
determine
compliance
with
the
operating
limits
was
inoperative,
inactive,
malfunctioning
or
out
of
control.
(
f)
The
highest
recorded
3
hour
average
and
the
lowest
recorded
3
hour
average,
as
applicable,
for
each
operating
parameter
recorded
for
the
calendar
year
being
reported.
(
g)
Information
recorded
under
§
62.14700(
b)(
6)
and
(
c)
through
(
e)
for
the
calendar
year
being
reported.
(
h)
If
a
performance
test
was
conducted
during
the
reporting
period,
the
results
of
that
test.
(
i)
If
you
met
the
requirements
of
§
62.14680(
a)
or
(
b),
and
did
not
conduct
a
performance
test
during
the
reporting
period,
you
must
state
that
you
met
the
requirements
of
§
62.14680(
a)
or
(
b),
and,
therefore,
you
were
not
required
to
conduct
a
performance
test
during
the
reporting
period.
(
j)
Documentation
of
periods
when
all
qualified
CISWI
unit
operators
were
unavailable
for
more
than
8
hours,
but
less
than
2
weeks.
§
62.14735
What
else
must
I
report
if
I
have
a
deviation
from
the
operating
limits
or
the
emission
limitations?
(
a)
You
must
submit
a
deviation
report
if
any
recorded
3
hour
average
parameter
level
is
above
the
maximum
operating
limit
or
below
the
minimum
operating
limit
established
under
this
subpart,
if
the
bag
leak
detection
system
alarm
sounds
for
more
than
5
percent
of
the
operating
time
for
any
6
month
reporting
period,
or
if
a
performance
test
was
conducted
that
deviated
from
any
emission
limitation.
(
b)
The
deviation
report
must
be
submitted
by
August
1
of
that
year
for
data
collected
during
the
first
half
of
the
calendar
year
(
January
1
to
June
30),
and
by
February
1
of
the
following
year
for
data
you
collected
during
the
second
half
of
the
calendar
year
(
July
1
to
December
31).
§
62.14740
What
must
I
include
in
the
deviation
report?
In
each
report
required
under
§
62.14735,
for
any
pollutant
or
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parameter
that
deviated
from
the
emission
limitations
or
operating
limits
specified
in
this
subpart,
include
the
six
items
described
in
paragraphs
(
a)
through
(
f)
of
this
section.
(
a)
The
calendar
dates
and
times
your
unit
deviated
from
the
emission
limitations
or
operating
limit
requirements.
(
b)
The
averaged
and
recorded
data
for
those
dates.
(
c)
Duration
and
causes
of
each
deviation
from
the
emission
limitations
or
operating
limits
and
your
corrective
actions.
(
d)
A
copy
of
the
operating
limit
monitoring
data
during
each
deviation
and
any
test
report
that
documents
the
emission
levels.
(
e)
The
dates,
times,
number,
duration,
and
causes
for
monitoring
downtime
incidents
(
other
than
downtime
associated
with
zero,
span,
and
other
routine
calibration
checks).
(
f)
Whether
each
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction,
or
during
another
period.
§
62.14745
What
else
must
I
report
if
I
have
a
deviation
from
the
requirement
to
have
a
qualified
operator
accessible?
(
a)
If
all
qualified
operators
are
not
accessible
for
two
weeks
or
more,
you
must
take
the
two
actions
in
paragraphs
(
a)(
1)
and
(
2)
of
this
section.
(
1)
Within
ten
days
of
each
deviation,
you
must
submit
a
notification
that
includes
the
three
items
in
paragraphs
(
a)(
1)(
i)
through
(
iii)
of
this
section.
(
i)
A
statement
of
what
caused
the
deviation.
(
ii)
A
description
of
what
you
are
doing
to
ensure
that
a
qualified
operator
is
accessible.
(
iii)
The
date
when
you
anticipate
that
a
qualified
operator
will
be
available.
(
2)
Submit
a
status
report
to
the
Administrator
every
4
weeks
that
includes
the
three
items
in
paragraphs
(
a)(
2)(
i)
through
(
iii)
of
this
section.
(
i)
A
description
of
what
you
are
doing
to
ensure
that
a
qualified
operator
is
accessible.
(
ii)
The
date
when
you
anticipate
that
a
qualified
operator
will
be
accessible.
(
iii)
Request
approval
from
the
Administrator
to
continue
operation
of
the
CISWI
unit.
(
b)
If
your
unit
was
shut
down
by
the
Administrator,
under
the
provisions
of
§
62.14625(
b)(
2),
due
to
a
failure
to
provide
an
accessible
qualified
operator,
you
must
notify
the
Administrator
that
you
are
resuming
operation
once
a
qualified
operator
is
accessible.
§
62.14750
Are
there
any
other
notifications
or
reports
that
I
must
submit?
Yes.
You
must
submit
notifications
as
provided
by
40
CFR
60.7.
§
62.14755
In
what
form
can
I
submit
my
reports?
Submit
initial,
annual,
and
deviation
reports
electronically
or
in
paper
format,
postmarked
on
or
before
the
submittal
due
dates.
§
62.14760
Can
reporting
dates
be
changed?
If
the
Administrator
agrees,
you
may
change
the
semiannual
or
annual
reporting
dates.
See
40
CFR
60.19(
c)
for
procedures
to
seek
approval
to
change
your
reporting
date.
Air
Curtain
Incinerators
that
Burn
100
Percent
Wood
Wastes
and
Clean
Lumber
§
62.14765
What
is
an
air
curtain
incinerator?
An
air
curtain
incinerator
operates
by
forcefully
projecting
a
curtain
of
air
across
an
open
chamber
or
open
pit
in
which
combustion
occurs.
Incinerators
of
this
type
can
be
constructed
above
or
below
ground
and
with
or
without
refractory
walls
and
floor.
(
Air
curtain
incinerators
are
different
from
conventional
combustion
devices
which
typically
have
enclosed
fireboxes
and
controlled
air
technology
such
as
mass
burn,
modular,
and
fluidized
bed
combustors.)
§
62.14770
When
must
I
achieve
final
compliance?
If
you
plan
to
continue
operating,
then
you
must
achieve
final
compliance
by
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
It
is
unlawful
for
your
air
curtain
incinerator
to
operate
after
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register
if
you
have
not
achieved
final
compliance.
An
air
curtain
incinerator
that
continues
to
operate
after
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register
without
being
in
compliance
is
subject
to
penalties.
§
62.14795
How
do
I
achieve
final
compliance?
For
the
final
compliance,
you
must
complete
all
equipment
changes
and
retrofit
installation
control
devices
so
that,
when
the
affected
air
curtain
incinerator
is
placed
into
service,
all
necessary
equipment
and
air
pollution
control
devices
operate
as
designed
and
meet
the
opacity
limits
of
§
62.14815.
§
62.14805
What
must
I
do
if
I
close
my
air
curtain
incinerator
and
then
restart
it?
(
a)
If
you
close
your
incinerator
but
will
reopen
it
prior
to
the
final
compliance
date
in
this
subpart,
you
must
achieve
final
compliance
by
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
b)
If
you
close
your
incinerator
but
will
restart
it
after
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register,
you
must
have
completed
any
needed
emission
control
retrofits
and
meet
the
opacity
limits
of
§
62.14815
on
the
date
your
incinerator
restarts
operation.
(
c)
You
must
meet
the
title
V
operating
permit
requirements
of
§
§
62.14830
and
62.14835
at
the
time
you
restart
your
air
curtain
incinerator.
§
62.14810
What
must
I
do
if
I
plan
to
permanently
close
my
air
curtain
incinerator
and
not
restart
it?
If
you
plan
to
permanently
close
your
incinerator
rather
than
comply
with
this
subpart,
you
must
submit
a
closure
notification,
including
the
date
of
closure,
to
the
Administrator
by
the
date
by
the
180
days
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
You
must
meet
the
title
V
operating
permit
requirements
of
§
§
62.14830
and
62.14835
regardless
of
when
you
shut
down.
§
62.14815
What
are
the
emission
limitations
for
air
curtain
incinerators
that
burn
100
percent
wood
wastes
and
clean
lumber?
(
a)
After
the
date
the
initial
test
for
opacity
is
required
or
completed
(
whichever
is
earlier),
you
must
meet
the
limitations
in
paragraphs
(
a)(
1)
and
(
2)
of
this
section.
(
1)
The
opacity
limitation
is
10
percent
(
6
minute
average),
except
as
described
in
paragraph
(
a)(
2)
of
this
section.
(
2)
The
opacity
limitation
is
35
percent
(
6
minute
average)
during
the
startup
period
that
is
within
the
first
30
minutes
of
operation.
(
b)
Except
during
malfunctions,
the
requirements
of
this
subpart
apply
at
all
times,
and
each
malfunction
must
not
exceed
3
hours.
§
62.14820
How
must
I
monitor
opacity
for
air
curtain
incinerators
that
burn
100
percent
wood
wastes
and
clean
lumber?
(
a)
Use
Method
9
of
40
CFR
part
60,
Appendix
A
to
determine
compliance
with
the
opacity
limitation.
(
b)
Conduct
an
initial
test
for
opacity
as
specified
in
§
60.8
no
later
than
90
days
after
the
date
one
year
after
promulgation
of
the
CISWI
Federal
plan
in
the
Federal
Register.
(
c)
After
the
initial
test
for
opacity,
conduct
annual
tests
no
more
than
12
calendar
months
following
the
date
of
your
previous
test.
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§
62.14825
What
are
the
recordkeeping
and
reporting
requirements
for
air
curtain
incinerators
that
burn
100
percent
wood
wastes
and
clean
lumber?
(
a)
Keep
records
of
results
of
all
initial
and
annual
opacity
tests
onsite
in
either
paper
copy
or
electronic
format,
unless
the
Administrator
approves
another
format,
for
at
least
5
years.
(
b)
Make
all
records
available
for
submittal
to
the
Administrator
or
for
an
inspector's
onsite
review.
(
c)
Submit
an
initial
report
no
later
than
60
days
following
the
initial
opacity
test
that
includes
the
information
specified
in
paragraphs
(
c)(
1)
and
(
2)
of
this
section.
(
1)
The
types
of
materials
you
plan
to
combust
in
your
air
curtain
incinerator.
(
2)
The
results
(
each
6
minute
average)
of
the
initial
opacity
tests.
(
d)
Submit
annual
opacity
test
results
within
12
months
following
the
previous
report.
(
e)
Submit
initial
and
annual
opacity
test
reports
as
electronic
or
paper
copy
on
or
before
the
applicable
submittal
date
and
keep
a
copy
onsite
for
a
period
of
5
years.
Title
V
Requirements
§
62.14830
Does
this
subpart
require
me
to
obtain
an
operating
permit
under
title
V
of
the
Clean
Air
Act?
Yes.
If
you
are
subject
to
this
subpart,
you
are
required
to
apply
for
and
obtain
a
title
V
operating
permit
unless
you
meet
the
relevant
requirements
specified
in
40
CFR
62.14525(
a)
(
h)
and
(
j)
(
o)
and
all
of
the
requirements
specified
in
40
CFR
62.14531.
§
62.14835
When
must
I
submit
a
title
V
permit
application
for
my
existing
CISWI
unit?
(
a)
If
your
existing
CISWI
unit
is
not
subject
to
an
earlier
permit
application
deadline,
a
complete
title
V
permit
application
must
be
submitted
not
later
than
the
date
36
months
after
promulgation
of
40
CFR
part
60,
subpart
DDDD
(
December
1,
2003),
or
by
the
effective
date
of
the
applicable
State,
Tribal,
or
Federal
operating
permits
program,
whichever
is
later.
For
any
existing
CISWI
unit
not
subject
to
an
earlier
application
deadline,
this
final
application
deadline
applies
regardless
of
when
this
Federal
plan
is
effective,
or
when
the
relevant
State
or
Tribal
section
111(
d)/
129
plan
is
approved
by
EPA
and
becomes
effective.
See
sections
129(
e),
503(
c),
503(
d),
and
502(
a)
of
the
Clean
Air
Act.
(
b)
A
``
complete''
title
V
permit
application
is
one
that
has
been
determined
or
deemed
complete
by
the
relevant
permitting
authority
under
section
503(
d)
of
the
Clean
Air
Act
and
40
CFR
70.5(
a)(
2)
or
71.5(
a)(
2).
You
must
submit
a
complete
permit
application
by
the
relevant
application
deadline
in
order
to
operate
after
this
date
in
compliance
with
Federal
law.
See
sections
503(
d)
and
502(
a)
of
the
Clean
Air
Act;
40
CFR
70.7(
b)
and
71.7(
b).
Definitions
§
62.14840
What
definitions
must
I
know?
Terms
used
but
not
defined
in
this
subpart
are
defined
in
the
Clean
Air
Act,
subparts
A
and
B
of
part
60
and
subpart
A
of
this
part
62.
Administrator
means
the
Administrator
of
the
U.
S.
Environmental
Protection
Agency
or
his/
her
authorized
representative
or
Administrator
of
a
State
Air
Pollution
Control
Agency.
Agricultural
waste
means
vegetative
agricultural
materials
such
as
nut
and
grain
hulls
and
chaff
(
e.
g.,
almond,
walnut,
peanut,
rice,
and
wheat),
bagasse,
orchard
prunings,
corn
stalks,
coffee
bean
hulls
and
grounds,
and
other
vegetative
waste
materials
generated
as
a
result
of
agricultural
operations.
Air
curtain
incinerator
means
an
incinerator
that
operates
by
forcefully
projecting
a
curtain
of
air
across
an
open
chamber
or
pit
in
which
combustion
occurs.
Incinerators
of
this
type
can
be
constructed
above
or
below
ground
and
with
or
without
refractory
walls
and
floor.
(
Air
curtain
incinerators
are
different
from
conventional
combustion
devices
which
typically
have
enclosed
fireboxes
and
controlled
air
technology
such
as
mass
burn,
modular,
and
fluidized
bed
combustors.)
Auxiliary
fuel
means
natural
gas,
liquified
petroleum
gas,
fuel
oil,
or
diesel
fuel.
Bag
leak
detection
system
means
an
instrument
that
is
capable
of
monitoring
particulate
matter
loadings
in
the
exhaust
of
a
fabric
filter
(
i.
e.,
baghouse)
in
order
to
detect
bag
failures.
A
bag
leak
detection
system
includes,
but
is
not
limited
to,
an
instrument
that
operates
on
triboelectric,
light
scattering,
light
transmittance,
or
other
principle
to
monitor
relative
particulate
matter
loadings.
Calendar
quarter
means
three
consecutive
months
(
nonoverlapping)
beginning
on:
January
1,
April
1,
July
1,
or
October
1.
Calendar
year
means
365
consecutive
days
starting
on
January
1
and
ending
on
December
31.
Chemotherapeutic
waste
means
waste
material
resulting
from
the
production
or
use
of
antineoplastic
agents
used
for
the
purpose
of
stopping
or
reversing
the
growth
of
malignant
cells.
Clean
lumber
means
wood
or
wood
products
that
have
been
cut
or
shaped
and
include
wet,
air
dried,
and
kilndried
wood
products.
Clean
lumber
does
not
include
wood
products
that
have
been
painted,
pigment
stained,
or
pressure
treated
by
compounds
such
as
chromate
copper
arsenate,
pentachlorophenol,
and
creosote.
Commercial
and
industrial
solid
waste
incineration
(
CISWI)
unit
means
any
combustion
device
that
combusts
commercial
and
industrial
waste,
as
defined
in
this
subpart.
The
boundaries
of
a
CISWI
unit
are
defined
as,
but
not
limited
to,
the
commercial
or
industrial
solid
waste
fuel
feed
system,
grate
system,
flue
gas
system,
and
bottom
ash.
The
CISWI
unit
does
not
include
air
pollution
control
equipment
or
the
stack.
The
CISWI
unit
boundary
starts
at
the
commercial
and
industrial
solid
waste
hopper
(
if
applicable)
and
extends
through
two
areas:
(
1)
The
combustion
unit
flue
gas
system,
which
ends
immediately
after
the
last
combustion
chamber.
(
2)
The
combustion
unit
bottom
ash
system,
which
ends
at
the
truck
loading
station
or
similar
equipment
that
transfers
the
ash
to
final
disposal.
It
includes
all
ash
handling
systems
connected
to
the
bottom
ash
handling
system.
Commercial
and
industrial
waste,
for
the
purposes
of
this
subpart,
means
solid
waste
combusted
in
an
enclosed
device
using
controlled
flame
combustion
without
energy
recovery
that
is
a
distinct
operating
unit
of
any
commercial
or
industrial
facility
(
including
field
erected,
modular,
and
custom
built
incineration
units
operating
with
starved
or
excess
air),
or
solid
waste
combusted
in
an
air
curtain
incinerator
without
energy
recovery
that
is
a
distinct
operating
unit
of
any
commercial
or
industrial
facility.
Contained
gaseous
material
means
gases
that
are
in
a
container
when
that
container
is
combusted.
Cyclonic
barrel
burner
means
a
combustion
device
for
waste
materials
that
is
attached
to
a
55
gallon,
openhead
drum.
The
device
consists
of
a
lid,
which
fits
onto
and
encloses
the
drum,
and
a
blower
that
forces
combustion
air
into
the
drum
in
a
cyclonic
manner
to
enhance
the
mixing
of
waste
material
and
air.
Deviation
means
any
instance
in
which
an
affected
source
subject
to
this
subpart,
or
an
owner
or
operator
of
such
a
source:
(
1)
Fails
to
meet
any
requirement
or
obligation
established
by
this
subpart,
including
but
not
limited
to
any
emission
limitation,
operating
limit,
or
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operator
qualification
and
accessibility
requirements;
(
2)
Fails
to
meet
any
term
or
condition
that
is
adopted
to
implement
an
applicable
requirement
in
this
subpart
and
that
is
included
in
the
operating
permit
for
any
affected
source
required
to
obtain
such
a
permit;
or
(
3)
Fails
to
meet
any
emission
limitation,
operating
limit,
or
operator
qualification
and
accessibility
requirement
in
this
subpart
during
startup,
shutdown,
or
malfunction,
regardless
or
whether
or
not
such
failure
is
permitted
by
this
subpart.
Dioxins/
furans
means
tetra
through
octachlorinated
dibenzo
p
dioxins
and
dibenzofurans.
Discard
means,
for
purposes
of
this
subpart
and
40
CFR
part
60,
subpart
DDDD,
only,
burned
in
an
incineration
unit
without
energy
recovery.
Drum
reclamation
unit
means
a
unit
that
burns
residues
out
of
drums
(
e.
g.,
55
gallon
drums)
so
that
the
drums
can
be
reused.
Energy
recovery
means
the
process
of
recovering
thermal
energy
from
combustion
for
useful
purposes
such
as
steam
generation
or
process
heating.
Fabric
filter
means
an
add
on
air
pollution
control
device
used
to
capture
particulate
matter
by
filtering
gas
streams
through
filter
media,
also
known
as
a
baghouse.
Low
level
radioactive
waste
means
waste
material
which
contains
radioactive
nuclides
emitting
primarily
beta
or
gamma
radiation,
or
both,
in
concentrations
or
quantities
that
exceed
applicable
Federal
or
State
standards
for
unrestricted
release.
Low
level
radioactive
waste
is
not
high
level
radioactive
waste,
spent
nuclear
fuel,
or
by
product
material
as
defined
by
the
Atomic
Energy
Act
of
1954
(
42
U.
S.
C.
2014(
e)(
2)).
Malfunction
means
any
sudden,
infrequent,
and
not
reasonably
preventable
failure
of
air
pollution
control
equipment,
process
equipment,
or
a
process
to
operate
in
a
normal
or
usual
manner.
Failures
that
are
caused,
in
part,
by
poor
maintenance
or
careless
operation
are
not
malfunctions.
Modification
or
modified
CISWI
unit
means
a
CISWI
unit
you
have
changed
later
than
promulgation
of
the
final
CISWI
emission
guidelines
in
40
CFR
part
60,
subpart
DDDD
and
that
meets
one
of
two
criteria:
(
1)
The
cumulative
cost
of
the
changes
over
the
life
of
the
unit
exceeds
50
percent
of
the
original
cost
of
building
and
installing
the
CISWI
unit
(
not
including
the
cost
of
land)
updated
to
current
costs
(
current
dollars).
To
determine
what
systems
are
within
the
boundary
of
the
CISWI
unit
used
to
calculate
these
costs,
see
the
definition
of
CISWI
unit.
(
2)
Any
physical
change
in
the
CISWI
unit
or
change
in
the
method
of
operating
it
that
increases
the
amount
of
any
air
pollutant
emitted
for
which
section
129
or
section
111
of
the
Clean
Air
Act
has
established
standards.
Particulate
matter
means
total
particulate
matter
emitted
from
CISWI
units
as
measured
by
Method
5
or
Method
29
of
40
CFR
part
60,
Appendix
A.
Parts
reclamation
unit
means
a
unit
that
burns
coatings
off
parts
(
e.
g.,
tools,
equipment)
so
that
the
parts
can
be
reconditioned
and
reused.
Pathological
waste
means
waste
material
consisting
of
only
human
or
animal
remains,
anatomical
parts,
and/
or
tissue,
the
bags/
containers
used
to
collect
and
transport
the
waste
material,
and
animal
bedding
(
if
applicable).
Rack
reclamation
unit
means
a
unit
that
burns
the
coatings
off
racks
used
to
hold
small
items
for
application
of
a
coating.
The
unit
burns
the
coating
overspray
off
the
rack
so
the
rack
can
be
reused.
Reconstruction
means
rebuilding
a
CISWI
unit
and
meeting
two
criteria:
(
1)
The
reconstruction
begins
on
or
after
promulgation
of
the
final
CISWI
emission
guidelines
in
40
CFR
part
60,
subpart
DDDD.
(
2)
The
cumulative
cost
of
the
construction
over
the
life
of
the
incineration
unit
exceeds
50
percent
of
the
original
cost
of
building
and
installing
the
CISWI
unit
(
not
including
land)
updated
to
current
costs
(
current
dollars).
To
determine
what
systems
are
within
the
boundary
of
the
CISWI
unit
used
to
calculate
these
costs,
see
the
definition
of
CISWI
unit.
Refuse
derived
fuel
means
a
type
of
municipal
solid
waste
produced
by
processing
municipal
solid
waste
through
shredding
and
size
classification.
This
includes
all
classes
of
refuse
derived
fuel
including
two
fuels:
(
1)
Low
density
fluff
refuse
derived
fuel
through
densified
refuse
derived
fuel.
(
2)
Pelletized
refuse
derived
fuel.
Shutdown
means
the
period
of
time
after
all
waste
has
been
combusted
in
the
primary
chamber.
Solid
waste
means
any
garbage,
refuse,
sludge
from
a
waste
treatment
plant,
water
supply
treatment
plant,
or
air
pollution
control
facility
and
other
discarded
material,
including
solid,
liquid,
semisolid,
or
contained
gaseous
material
resulting
from
industrial,
commercial,
mining,
agricultural
operations,
and
from
community
activities,
but
does
not
include
solid
or
dissolved
material
in
domestic
sewage,
or
solid
or
dissolved
materials
in
irrigation
return
flows
or
industrial
discharges
which
are
point
sources
subject
to
permits
under
section
402
of
the
Federal
Water
Pollution
Control
Act,
as
amended
(
86
Stat.
880),
or
source,
special
nuclear,
or
byproduct
material
as
defined
by
the
Atomic
Energy
Act
of
1954,
as
amended
(
68
Stat.
923).
For
purposes
of
this
subpart
and
40
CFR
part
60,
subpart
DDDD,
only,
solid
waste
does
not
include
the
waste
burned
in
the
fifteen
types
of
units
described
in
40
CFR
60.2555
of
subpart
DDDD
and
§
62.14525
of
this
subpart.
Standard
conditions,
when
referring
to
units
of
measure,
means
a
temperature
of
68
°
F
(
20
°
C)
and
a
pressure
of
1
atmosphere
(
101.3
kilopascals).
Startup
period
means
the
period
of
time
between
the
activation
of
the
system
and
the
first
charge
to
the
unit.
Tribal
plan
means
a
plan
submitted
by
a
Tribal
Authority
pursuant
to
40
CFR
parts
9,
35,
49,
50,
and
81
that
implements
and
enforces
40
CFR
part
60,
subpart
DDDD.
Wet
scrubber
means
an
add
on
air
pollution
control
device
that
utilizes
an
aqueous
or
alkaline
scrubbing
liquor
to
collect
particulate
matter
(
including
nonvaporous
metals
and
condensed
organics)
and/
or
to
absorb
and
neutralize
acid
gases.
Wood
waste
means
untreated
wood
and
untreated
wood
products,
including
tree
stumps
(
whole
or
chipped),
trees,
tree
limbs
(
whole
or
chipped),
bark,
sawdust,
chips,
scraps,
slabs,
millings,
and
shavings.
Wood
waste
does
not
include:
(
1)
Grass,
grass
clippings,
bushes,
shrubs,
and
clippings
from
bushes
and
shrubs
from
residential,
commercial/
retail,
institutional,
or
industrial
sources
as
part
of
maintaining
yards
or
other
private
or
public
lands.
(
2)
Construction,
renovation,
or
demolition
wastes.
(
3)
Clean
lumber.
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25,
2002
/
Proposed
Rules
TABLE
1
OF
SUBPART
III
OF
PART
62.
EMISSION
LIMITATIONS
For
the
air
pollutant
You
must
meet
this
emission
limitation
a
Using
this
averaging
time
And
determining
compliance
using
this
method
Cadmium
................................................
0.004
milligrams
per
dry
standard
cubic
meter.
3
run
average
(
1
hour
minimum
sample
time
per
run).
Performance
test
(
Method
29
of
appendix
A
of
part
60)
Carbon
monoxide
...................................
157
parts
per
million
by
dry
volume.
3
run
average
(
1
hour
minimum
sample
time
per
run).
Performance
test
(
Method
10,
10A,
or
10B,
of
appendix
A
of
part
60)
Dioxins/
furans
(
toxic
equivalency
basis)
0.41
nanograms
per
dry
standard
cubic
meter.
3
run
average
(
4
hour
minimum
sample
time
per
run).
Performance
test
(
Method
23
of
appendix
A
of
part
60)
Hydrogen
chloride
..................................
62
parts
per
million
by
dry
volume.
3
run
average
(
1
hour
minimum
sample
time
per
run).
Performance
test
(
Method
26A
of
appendix
A
of
part
60)
Lead
........................................................
0.04
milligrams
per
dry
standard
cubic
meter.
3
run
average
(
1
hour
minimum
sample
time
per
run).
Performance
test
(
Method
29
of
appendix
A
of
part
60)
Mercury
...................................................
0.47
milligrams
per
dry
standard
cubic
meter.
3
run
average
(
1
hour
minimum
sample
time
per
run).
Performance
test
(
Method
29
of
appendix
A
of
part
60)
Opacity
...................................................
10
percent
.............................
6
minute
averages
................
Performance
test
(
Method
9
of
appendix
A
of
part
60)
Oxides
of
nitrogen
..................................
388
parts
per
million
by
dry
volume.
3
run
average
(
1
hour
minimum
sample
time
per
run).
Performance
test
(
Methods
average
7,
7A,
7C,
7D,
or
7E
of
appendix
A
of
part
60)
Particulate
matter
...................................
70
milligrams
per
dry
standard
cubic
meter.
3
run
average
(
1
hour
minimum
sample
time
per
run).
Performance
test
(
Method
5
or
29
of
appendix
A
of
part
60)
Sulfur
dioxide
..........................................
20
parts
per
million
by
dry
volume.
3
run
average
(
1
hour
minimum
sample
time
per
run).
Performance
test
(
Method
6
or
6c
of
appendix
A
of
part
volume
60)
a
All
emission
limitations
(
except
for
opacity)
are
measured
at
7
percent
oxygen,
dry
basis
at
standard
conditions.
TABLE
2
OF
SUBPART
III
OF
PART
62.
OPERATING
LIMITS
FOR
WET
SCRUBBERS
For
these
operating
parameters
You
must
establish
these
operating
limits
And
monitor
using
these
minimum
frequencies
Data
measurement
Data
recording
Averaging
time
Charge
rate
...........................
Maximum
charge
rate
..........
Continuous
.......
Every
hour
........
1.
Daily
(
batch
units).
2.
3
hour
rolling
(
continuous
and
intermittent
units).
a
Pressure
drop
across
the
wet
scrubber
or
amperage
to
wet
scrubber.
Minimum
pressure
drop
or
amperage.
Continuous
.......
Every
15
minutes
3
hour
rolling.
a
Scrubber
liquor
flow
rate
.......
Minimum
flow
rate
................
Continuous
.......
Every
15
minutes
3
hour
rolling.
a
Scrubber
liquor
pH
................
Minimum
pH
.........................
Continuous
.......
Every
15
minutes
3
hour
rolling
a
a
Calculated
each
hour
as
the
average
of
the
previous
3
operating
hours.
TABLE
3
OF
SUBPART
III
OF
PART
62.
TOXIC
EQUIVALENCY
FACTORS
Dioxin/
furan
congener
Toxic
equivalency
factor
A.
2,3,7,8
tetrachlorinated
dibenzo
p
dioxin
................................................................................................................................................
1
B.
12,3,7,8
pentachlorinated
dibenzo
p
dioxin
............................................................................................................................................
0.5
C.
1,2,3,4,7,8
hexachlorinated
dibenzo
p
dioxin
.........................................................................................................................................
0.1
D.
1,2,3,7,8,9
hexachlorinated
dibenzo
p
dioxin
.........................................................................................................................................
0.1
E.
12,3,6,7,8
hexachlorinated
dibenzo
p
dioxin
..........................................................................................................................................
0.1
F.
1,2,3,4,6,7,8
heptachlorinated
dibenzo
p
dioxin
.....................................................................................................................................
0.01
G.
0ctachlorinated
dibenzo
p
dioxin
............................................................................................................................................................
0.001
H.
2,3,7,8
tetrachlorinated
dibenzofuran
.....................................................................................................................................................
0.1
I.
2,3,4,7,8
pentachlorinated
dibenzofuran
..................................................................................................................................................
0.5
J.
1,2,3,7,8
pentachlorinated
dibenzofuran
..................................................................................................................................................
0.05
K.
1,2,3,4,7,8
hexachlorinated
dibenzofuran
...............................................................................................................................................
0.1
L.
1,2,3,6,7,8
hexachlorinated
dibenzofuran
...............................................................................................................................................
0.1
M.
1,2,3,7,8,9
hexachlorinated
dibenzofuran
..............................................................................................................................................
0.1
N.
2,3,4,6,7,8
hexachlorinated
dibenzofuran
...............................................................................................................................................
0.1
O.
1,2,3,4,6,7,8
heptachlorinated
dibenzofuran
..........................................................................................................................................
0.01
P.
1,2,3,4,7,8,9
heptachlorinated
dibenzofuran
...........................................................................................................................................
0.01
Q.
0ctachlorinated
dibenzofuran
..................................................................................................................................................................
0.001
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/
Vol.
67,
No.
227
/
Monday,
November
25,
2002
/
Proposed
Rules
TABLE
4
OF
SUBPART
III
OF
PART
62.
SUMMARY
OF
REPORTING
REQUIREMENTS
Report
Due
Date
Contents
Reference
A.
Waste
Management
Plan.
No
later
than
the
date
6
months
after
publication
of
the
final
rule
the
Federal
Register.
Waste
management
plan
......................................
§
62.14715.
B.
Initial
Test
Report
........
No
later
than
60
days
following
the
performance
test.
1.
Complete
test
report
for
the
initial
performance
test.
2.
The
values
for
the
site
specific
operating
limits
3.
Installation
of
bag
leak
detection
systems
for
fabric
filters.
§
62.14720.
C.
Annual
Report
.............
No
later
than
12
months
following
the
submission
of
the
initial
test
report.
Subsequent
reports
are
to
be
submitted
no
more
than
12
months
following
the
previous
report.
1.
Name
and
address
............................................
2.
Statement
and
signature
by
responsible
official
3.
Date
of
report
....................................................
4.
Values
for
the
operating
limits
..........................
5.
If
no
deviations
or
malfunctions
were
reported,
a
statement
that
no
deviations
occurred
during
reporting
period.
6.
Highest
recorded
3
hour
average
and
the
lowest
3
hour
average,
as
applicable,
for
each
operating
parameter
recorded
for
the
calendar
year
being
reported.
7.
Information
for
deviations
or
malfunctions
recorded
under
§
62.14700(
b)(
6)
and
(
c)
through
(
e).
8.
If
a
performance
test
was
conducted
during
the
reporting
period,
the
results
of
the
test.
9.
If
a
performance
test
was
not
conducted
during
the
reporting
period,
a
statement
that
the
requirements
of
§
62.14680(
a)
or
(
b)
were
met.
10.
Documentation
of
periods
when
all
qualified
CISWI
unit
operators
were
unavailable
for
more
than
8
hours
but
less
than
2
weeks.
§
§
62.14725
and
62.14730
Subsequent
reports
are
to
be
submmitted
no
moer
than
12
months
following
the
previous
report
D.
Emission
Limitation
or
Operating
Limit
Deviation
Report.
By
August
1
of
that
year
for
data
collected
during
the
first
half
of
the
calendar
year.
By
February
1
of
the
following
year
for
data
collected
during
the
second
half
of
the
calendar
year.
1.
Dates
and
times
of
deviations
..........................
2.
Averaged
and
recorded
data
for
these
dates
...
3.
Duration
and
causes
for
each
deviation
and
the
corrective
actions
taken.
4.
Copy
of
operating
limit
monitoring
data
and
any
test
reports.
5.
Dates,
times,
and
causes
for
monitor
downtime
incidents.
6.
Whether
each
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction.
§
§
62.14735
and
62.14740.
E.
Qualified
Operator
Deviation
Notification.
Within
10
days
of
deviation
1.
Statement
of
cause
of
deviation
.......................
2.
Description
of
efforts
to
have
an
accessible
qualified
operator.
3.
The
date
a
qualified
operator
will
be
accessible
§
62.14745(
a)(
1).
F.
Qualified
Operator
Deviation
Status
Report.
Every
4
weeks
following
deviation.
1.
Description
of
efforts
to
have
an
accessible
qualified
operator.
2.
The
date
a
qualified
operator
will
be
accessible
3.
Request
for
approval
to
continue
operation
.....
§
62.14745(
a)(
2).
G.
Qualified
Operator
Deviation
Notification
of
Resumed
Operation.
Prior
to
resuming
operation
Notification
that
you
are
resuming
operation
........
§
62.14745(
b).
a
This
table
is
only
a
summary,
see
the
referenced
sections
of
the
rule
for
the
complete
requirements.
[
FR
Doc.
02
28923
Filed
11
22
02;
8:
45
am]
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"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0069-0001/content.txt"
} |
EPA-HQ-OAR-2002-0074-0001 | Proposed Rule | "2002-12-04T05:00:00" | National Emission Standards for Hazardous Air Pollutants: Surface Coating of Plastic Parts and Products; Proposed Rule | Wednesday,
December
4,
2002
Part
II
Environmental
Protection
Agency
40
CFR
Part
63
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Surface
Coating
of
Plastic
Parts
and
Products;
Proposed
Rule
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Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[
FRL
7385
7]
RIN
2060
AG57
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Surface
Coating
of
Plastic
Parts
and
Products
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Proposed
rule.
SUMMARY:
This
action
proposes
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
plastic
parts
and
products
surface
coating
operations
located
at
major
sources
of
hazardous
air
pollutants
(
HAP).
The
proposed
standards
would
implement
section
112(
d)
of
the
Clean
Air
Act
(
CAA)
by
requiring
these
operations
to
meet
HAP
emission
standards
reflecting
the
application
of
the
maximum
achievable
control
technology
(
MACT).
The
proposed
rule
would
protect
air
quality
and
promote
the
public
health
by
reducing
emissions
of
HAP
emitted
in
the
largest
quantities
by
facilities
in
the
surface
coating
of
plastic
parts
and
products
source
category
to
include
methyl
ethyl
ketone
(
MEK),
methyl
isobutyl
ketone
(
MIBK),
toluene,
and
xylenes.
Exposure
to
these
substances
has
been
demonstrated
to
cause
adverse
health
effects
such
as
irritation
of
the
lung,
skin,
and
mucous
membranes,
and
effects
on
the
central
nervous
system,
liver,
and
heart.
In
general,
these
findings
have
only
been
shown
with
concentrations
higher
than
those
typically
in
the
ambient
air.
The
proposed
standards
would
reduce
nationwide
HAP
emissions
from
major
sources
in
this
source
category
by
approximately
80
percent.
DATES:
Comments.
Submit
comments
on
or
before
February
3,
2003.
Public
Hearing.
If
anyone
contacts
the
EPA
requesting
to
speak
at
a
public
hearing,
they
should
do
so
by
December
24,
2002.
If
requested,
a
public
hearing
will
be
held
within
approximately
30
days
following
publication
of
this
notice
in
the
Federal
Register.
ADDRESSES:
Comments.
By
U.
S.
Postal
Service,
written
comments
should
be
submitted
(
in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(
6102T),
Attention
Docket
Number
A
99
12,
U.
S.
EPA,
1200
Pennsylvania
Avenue,
NW,
Washington,
DC
20460.
In
person
or
by
courier,
deliver
comments
(
in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(
6102T),
Attention
Docket
Number
A
99
12,
U.
S.
EPA,
Public
Reading
Room,
Room
B102,
EPA
West
Building,
1301
Constitution
Avenue,
NW,
Washington
DC
20460.
The
EPA
requests
a
separate
copy
also
be
sent
to
the
contact
person
listed
in
FOR
FURTHER
INFORMATION
CONTACT.
Public
Hearing.
If
a
public
hearing
is
held,
it
will
be
held
at
the
new
EPA
facility
complex
in
Research
Triangle
Park,
North
Carolina.
You
should
contact
Ms.
Janet
Eck,
Coatings
and
Consumer
Products
Group,
Emission
Standards
Division
(
C539
03),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711,
telephone
number
(
919)
541
7946,
to
request
to
speak
at
a
public
hearing
or
to
find
out
if
a
hearing
will
be
held.
Docket.
Docket
No.
A
99
12
contains
supporting
information
used
in
developing
the
proposed
standards.
The
docket
is
located
at
the
U.
S.
EPA,
Public
Reading
Room,
Room
B102,
EPA
West
Building,
1301
Constitution
Avenue,
NW,
Washington
DC
20460,
and
may
be
inspected
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
FOR
FURTHER
INFORMATION
CONTACT:
Ms.
Kim
Teal,
Coatings
and
Consumer
Products
Group,
Emission
Standards
Division
(
C539
03),
U.
S.
EPA,
Research
Triangle
Park,
NC
27711;
telephone
number
(
919)
541
5580;
facsimile
number
(
919)
541
5689;
electronic
mail
(
e
mail)
address:
teal.
kim@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Comments.
Comments
and
data
may
be
submitted
by
e
mail
to:
a
and
rdocket
epa.
gov.
Electronic
comments
must
be
submitted
as
an
ASCII
file
to
avoid
the
use
of
special
characters
and
encryption
problems
and
will
also
be
accepted
on
disks
in
WordPerfect
file
format.
All
comments
and
data
submitted
in
electronic
form
must
note
the
docket
number:
A
99
12.
No
confidential
business
information
(
CBI)
should
be
submitted
by
e
mail.
Electronic
comments
may
be
filed
online
at
many
Federal
Depository
Libraries.
Commenters
wishing
to
submit
proprietary
information
for
consideration
must
clearly
distinguish
such
information
from
other
comments
and
clearly
label
it
as
CBI.
Send
submissions
containing
such
proprietary
information
directly
to
the
following
address,
and
not
to
the
public
docket,
to
ensure
that
proprietary
information
is
not
inadvertently
placed
in
the
docket:
Ms.
Kim
Teal,
c/
o
OAQPS
Document
Control
Officer
(
C404
02),
U.
S.
EPA,
109
TW
Alexander
Drive,
Research
Triangle
Park,
NC
27709.
The
EPA
will
disclose
information
identified
as
CBI
only
to
the
extent
allowed
by
the
procedures
set
forth
in
40
CFR
part
2.
If
no
claim
of
confidentiality
accompanies
a
submission
when
it
is
received
by
EPA,
the
information
may
be
made
available
to
the
public
without
further
notice
to
the
commenter.
Public
Hearing.
Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Ms.
Janet
Eck,
Coatings
and
Consumer
Products
Group,
Emission
Standards
Division
(
C539
03),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711;
telephone
number
(
919)
541
7946
at
least
2
days
in
advance
of
the
public
hearing.
Persons
interested
in
attending
the
public
hearing
should
also
contact
Ms.
Eck
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
the
proposed
emission
standards.
Docket.
The
docket
is
an
organized
and
complete
file
of
all
the
information
considered
by
EPA
in
the
development
of
this
rulemaking.
The
docket
is
a
dynamic
file
because
material
is
added
throughout
the
rulemaking
process.
The
docketing
system
is
intended
to
allow
members
of
the
public
and
industries
involved
to
readily
identify
and
locate
documents
so
that
they
can
effectively
participate
in
the
rulemaking
process.
Along
with
the
proposed
and
promulgated
standards
and
their
preambles,
the
contents
of
the
docket
will
serve
as
the
record
in
the
case
of
judicial
review.
(
See
section
307(
d)(
7)(
A)
of
the
CAA.)
The
regulatory
text
and
other
materials
related
to
this
rulemaking
are
available
for
review
in
the
docket
or
copies
may
be
mailed
on
request
from
the
Air
and
Radiation
Docket
and
Information
Center
by
calling
(
202)
566
1742.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.
World
Wide
Web
(
WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
this
proposed
rule
will
also
be
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature
by
the
EPA
Administrator,
a
copy
of
the
proposed
rule
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(
919)
541
5384.
Regulated
Entities.
The
source
category
definition
includes
facilities
that
apply
coatings
to
plastic
parts
and
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No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
products.
In
general,
facilities
that
coat
plastic
parts
and
products
are
covered
under
the
Standard
Industrial
Classification
(
SIC)
and
North
American
Industrial
Classification
System
(
NAICS)
codes
listed
in
Table
1.
However,
facilities
classified
under
other
SIC
or
NAICS
codes
may
be
subject
to
the
proposed
standards
if
they
meet
the
applicability
criteria.
Not
all
facilities
classified
under
the
SIC
and
NAICS
codes
in
the
following
table
will
be
subject
to
the
proposed
standards
because
some
of
the
classifications
cover
products
outside
the
scope
of
the
NESHAP
for
plastic
parts
and
products.
TABLE
1.
CATEGORIES
AND
ENTITIES
POTENTIALLY
REGULATED
BY
THE
PROPOSED
STANDARDS
Category
SIC
NAICS
Examples
of
potentially
regulated
entities
Industrial
......................................
2522
337214
...............................
Office
furniture,
except
wood.
3086
32614,
32615
.....................
Plastic
foam
products
(
e.
g.,
pool
floats,
wrestling
mats,
life
jackets
3089
326199
...............................
Plastic
products
not
elsewhere
classified
(
e.
g.,
name
plates,
coin
holders,
storage
boxes,
license
plate
housings,
cosmetic
caps,
cup
holders).
3579
333313
...............................
Office
machines.
3663
33422
.................................
Radio
and
television
broadcasting
and
communications
equipment
(
e.
g.,
cellular
telephones).
3711
336211
...............................
Motor
Vehicle
Body
Manufacturing.
3714
336399
...............................
Motor
vehicle
parts
and
accessories.
3715
336212
...............................
Truck
Trailer
Manufacturing.
3716
336213
...............................
Motor
Home
Manufacturing.
3792
336214
...............................
Travel
Trailer
and
Camper
Manufacturing.
3799
336999
...............................
Transportation
equipment
not
elsewhere
classified
(
e.
g.,
snowmobile
hoods,
running
boards,
tractor
body
panels,
personal
watercraft
parts).
3841
339111,
339112
.................
Medical
equipment
and
supplies.
3949
33992
.................................
Sporting
and
athletic
goods.
3993
33995
.................................
Signs
and
advertising
specialties.
3999
339999
...............................
Manufacturing
industries
not
elsewhere
classified
(
e.
g.,
bezels,
consoles,
panels,
lenses).
Federal,
State,
and
Local
Governments
................
.............................................
Government
owned
or
operated
facilities
that
perform
plastic
parts
and
products
surface
coating.
Examples
include
Department
of
Defense
facilities.
This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
your
coating
operation
is
regulated
by
this
action,
you
should
examine
the
applicability
criteria
in
§
63.4481
of
the
proposed
rule.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:
I.
Background
A.
What
is
the
source
of
authority
for
development
of
NESHAP?
B.
What
criteria
are
used
in
the
development
of
NESHAP?
C.
What
are
the
health
effects
associated
with
HAP
emissions
from
the
surface
coating
of
plastic
parts
and
products?
II.
Summary
of
the
Proposed
Rule
A.
What
source
categories
and
subcategories
are
affected
by
this
proposed
rule?
B.
What
is
the
relationship
to
other
rules?
C.
What
are
the
primary
sources
of
emissions
and
what
are
the
emissions?
D.
What
is
the
affected
source?
E.
What
are
the
emission
limits,
operating
limits,
and
other
standards?
F.
What
are
the
testing
and
initial
compliance
requirements?
G.
What
are
the
continuous
compliance
provisions?
H.
What
are
the
notification,
recordkeeping,
and
reporting
requirements?
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
did
we
select
the
source
category
and
subcategories?
B.
How
did
we
select
the
regulated
pollutants?
C.
How
did
we
select
the
affected
source?
D.
How
did
we
determine
the
basis
and
level
of
the
proposed
standards
for
existing
and
new
sources?
E.
How
did
we
select
the
format
of
the
proposed
standards?
F.
How
did
we
select
the
testing
and
initial
compliance
requirements?
G.
How
did
we
select
the
continuous
compliance
requirements?
H.
How
did
we
select
the
notification,
recordkeeping,
and
reporting
requirements?
I.
How
did
we
select
the
compliance
date?
IV.
Summary
of
Environmental,
Energy,
and
Economic
Impacts
A.
What
are
the
air
impacts?
B.
What
are
the
cost
impacts?
C.
What
are
the
economic
impacts?
D.
What
are
the
non
air
health,
environmental,
and
energy
impacts?
V.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Executive
Order
13132,
Federalism
C.
Executive
Order
13175,
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Executive
Order
13211,
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
F.
Unfunded
Mandates
Reform
Act
of
1995
G.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601,
et
seq.
H.
Paperwork
Reduction
Act
I.
National
Technology
Transfer
and
Advancement
Act
I.
Background
A.
What
Is
the
Source
of
Authority
for
Development
of
NESHAP?
Section
112
of
the
CAA
requires
us
to
list
categories
and
subcategories
of
major
sources
and
area
sources
of
HAP
and
to
establish
NESHAP
for
the
listed
source
categories
and
subcategories.
The
Plastic
Parts
and
Products
(
Surface
Coating)
category
of
major
sources
was
listed
on
July
16,
1992
(
57
FR
31576)
under
the
Surface
Coating
Processes
industry
group.
Major
sources
of
HAP
are
those
that
emit
or
have
the
potential
to
emit
equal
to,
or
greater
than,
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
megagrams
per
year
(
Mg/
yr)
(
10
tons
per
year
(
tpy))
of
any
one
HAP
or
22.7
Mg/
yr
(
25
tpy)
of
any
combination
of
HAP.
B.
What
Criteria
Are
Used
in
the
Development
of
NESHAP?
Section
112
of
the
CAA
requires
that
we
establish
NESHAP
for
the
control
of
HAP
from
both
new
and
existing
major
sources.
The
CAA
requires
the
NESHAP
to
reflect
the
maximum
degree
of
reduction
in
emissions
of
HAP
that
is
achievable.
This
level
of
control
is
commonly
referred
to
as
the
MACT.
The
MACT
floor
is
the
minimum
control
level
allowed
for
NESHAP
and
is
defined
under
section
112(
d)(
3)
of
the
CAA.
In
essence,
the
MACT
floor
ensures
that
the
standard
is
set
at
a
level
that
assures
that
all
major
sources
achieve
the
level
of
control
at
least
as
stringent
as
that
already
achieved
by
the
better
controlled
and
lower
emitting
sources
in
each
source
category
or
subcategory.
For
new
sources,
the
MACT
floor
cannot
be
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
bestcontrolled
similar
source.
The
MACT
standards
for
existing
sources
can
be
less
stringent
than
standards
for
new
sources,
but
they
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
bestperforming
12
percent
of
existing
sources
in
the
category
or
subcategory
(
or
the
best
performing
five
sources
for
categories
or
subcategories
with
fewer
than
30
sources).
In
developing
MACT,
we
also
consider
control
options
that
are
more
stringent
than
the
floor.
We
may
establish
standards
more
stringent
than
the
floor
based
on
the
consideration
of
the
cost
of
achieving
the
emission
reductions,
any
non
air
quality
health
and
environmental
impacts,
and
energy
requirements.
C.
What
Are
the
Health
Effects
Associated
With
HAP
Emissions
From
the
Surface
Coating
of
Plastic
Parts
and
Products?
The
major
HAP
emitted
from
the
plastic
parts
and
products
surface
coating
industry
include
MEK,
MIBK,
toluene,
and
xylenes.
These
compounds
account
for
over
85
percent
of
the
nationwide
HAP
emissions
from
this
source
category.
Other
HAP
identified
in
emissions
include
ethylene
glycol
monobutyl
ether
(
EGBE)
and
glycol
ethers.
The
HAP
that
would
be
controlled
with
this
proposed
rule
are
associated
with
a
variety
of
adverse
health
effects.
These
adverse
health
effects
include
chronic
health
disorders
(
e.
g.,
birth
defects
and
effects
on
the
central
nervous
system,
liver,
and
heart),
and
acute
health
disorders
(
e.
g.,
irritation
of
the
lung,
skin,
and
mucous
membranes,
and
effects
on
the
central
nervous
system).
We
do
not
have
the
type
of
current
detailed
data
on
each
of
the
facilities
covered
by
the
proposed
emission
standards
for
this
source
category,
and
the
people
living
around
the
facilities,
that
would
be
necessary
to
conduct
an
analysis
to
determine
the
actual
population
exposures
to
the
HAP
emitted
from
these
facilities
and
potential
for
resultant
health
effects.
Therefore,
we
do
not
know
the
extent
to
which
the
adverse
health
effects
described
above
occur
in
the
populations
surrounding
these
facilities.
However,
to
the
extent
the
adverse
effects
do
occur,
the
proposed
rule
would
reduce
emissions
and
subsequent
exposures.
II.
Summary
of
the
Proposed
Rule
A.
What
Source
Categories
and
Subcategories
Are
Affected
By
This
Proposed
Rule?
The
proposed
rule
will
apply
to
you
if
you
own
or
operate
a
plastic
parts
and
products
surface
coating
facility
that
is
a
major
source,
or
is
located
at
a
major
source,
or
is
part
of
a
major
source
of
HAP
emissions.
We
have
defined
a
plastic
parts
and
products
surface
coating
facility
as
any
facility
engaged
in
the
surface
coating
of
any
plastic
part
or
product.
You
will
not
be
subject
to
the
proposed
rule
if
your
plastic
parts
and
products
surface
coating
facility
is
located
at
an
area
source.
An
area
source
of
HAP
is
any
facility
that
has
the
potential
to
emit
HAP
but
is
not
a
major
source.
You
may
establish
area
source
status
by
limiting
the
source's
potential
to
emit
HAP
through
appropriate
mechanisms
available
through
your
permitting
authority.
The
source
category
does
not
include
research
or
laboratory
facilities
or
janitorial,
building,
and
facility
maintenance
operations,
or
hobby
shops
that
are
operated
for
personal
rather
than
commercial
purposes.
The
source
category
also
does
not
include
coating
of
magnet
wire,
coating
of
plastics
to
produce
fiberglass
boats
(
except
postmold
coating
of
personal
watercraft
or
their
parts),
or
the
extrusion
of
plastic
onto
a
part
or
product
to
form
a
coating.
Post
mold
coating
of
personal
watercraft
and
their
parts
is
included
in
the
source
category.
This
source
category
also
does
not
include
surface
coating
of
plastic
parts
and
products
that
would
be
subject
to
certain
other
subparts
of
40
CFR
part
63.
In
particular,
it
does
not
include
the
following
coating
operations:
(
1)
Coating
operations
that
are
subject
to
the
aerospace
manufacturing
and
rework
facilities
NESHAP
(
40
CFR
part
63,
subpart
GG).
(
2)
Operations
coating
plastic
and
wood
that
are
subject
to
the
wood
furniture
NESHAP
(
40
CFR
part
63,
subpart
JJ).
(
3)
Operations
coating
plastic
and
metal
parts
of
large
appliances
that
are
subject
to
the
large
appliance
surface
coating
NESHAP
(
40
CFR
part
63,
subpart
NNNN,
67
FR
48254,
July
23,
2002).
(
4)
Operations
coating
plastic
and
metal
parts
of
metal
furniture
that
would
be
subject
to
the
proposed
metal
furniture
surface
coating
NESHAP
(
67
FR
20206,
April
24,
2002).
(
5)
Operations
coating
plastic
and
wood
parts
of
wood
building
products
that
would
be
subject
to
the
proposed
wood
building
products
surface
coating
NESHAP
(
67
FR
42400,
June
21,
2002).
(
6)
In
mold
and
gel
coating
operations
in
manufacturing
of
reinforced
plastic
composites
that
are
subject
to
the
proposed
reinforced
plastics
composites
production
NESHAP
(
66
FR
40324,
August
2,
2001).
(
7)
Surface
coating
of
parts
that
are
pre
assembled
from
plastic
and
metal
components,
where
greater
than
50
percent
of
the
surface
area
coated
is
metal
and
subject
to
the
proposed
NESHAP
for
the
surface
coating
of
miscellaneous
metal
parts
and
products
(
subpart
MMMM
of
part
63;
67
FR
52780,
August
13,
2002).
If
you
can
demonstrate
that
more
than
50
percent
of
the
surface
area
coated
is
comprised
of
metal,
then
you
would
need
to
demonstrate
compliance
only
with
the
proposed
NESHAP
for
miscellaneous
metal
parts
and
products
(
proposed
subpart
MMMM
of
part
63;
67
FR
52780,
August
13,
2002).
You
must
maintain
records
to
document
that
more
than
50
percent
of
the
surface
area
coated
is
metal.
We
have
established
four
subcategories
in
the
plastic
parts
and
products
surface
coating
source
category:
(
1)
General
use
coating,
(
2)
thermoplastic
olefin
(
TPO)
coating,
(
3)
headlamp
coating,
and
(
4)
assembled
on
road
vehicle
coating.
The
general
use
coating
subcategory
includes
all
plastic
parts
and
products
coating
operations
except
TPO,
headlamp,
and
assembled
on
road
vehicle
coating.
This
includes
operations
that
coat
a
wide
variety
of
substrates,
surfaces,
and
types
of
plastic
parts,
as
well
as
more
specialized
coating
scenarios.
Each
subcategory
consists
of
all
coating
operations,
including
associated
surface
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Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
preparation,
equipment
cleaning,
mixing,
storage,
and
waste
handling.
As
discussed
in
section
III.
A.
of
this
preamble,
our
analysis
of
data
currently
available
to
us
indicates
that
while
subcategories
for
headlamp
coating,
TPO
coating,
and
assembled
on
road
vehicle
coating
are
appropriate,
there
is
no
need
for
further
subcategorization.
We
are,
however,
interested
in
public
comments
regarding
whether
there
is
additional
information
that
would
indicate
the
need
for
a
separate
subcategory
for
other
plastic
coating
operations.
Subcategorization
may
be
appropriate
in
operations
that
employ
separate
and
distinct
processes
for
which
there
is
no
technology
available
(
including
reformulation)
to
allow
compliance
with
the
general
use
limits.
We
welcome
public
comments
and
data
on
any
additional
separate
and
distinct
coating
operations,
including
facilityspecific
data
on
processes,
coating
and
cleaning
material
usage,
emissions,
and
control
techniques
that
may
require
consideration
for
subcategorization.
Late
in
development
of
the
proposed
rule,
Department
of
Defense
(
DoD)
stakeholders
approached
EPA
and
suggested
that
their
operations
are
distinctly
different
from
the
kinds
of
operations
addressed
in
these
standards.
Furthermore,
DoD
operations
may
present
unique
challenges
in
permitting,
demonstrating
compliance,
and
enforcement
of
potentially
overlapping
regulations.
The
DoD
stakeholders
suggested
that
a
separate
subcategory
or
source
category
dealing
with
multiple
surface
coating
operations
performed
by
DoD
civilian
and
military
personnel
or
performed
at
DoD
installations
may
be
appropriate.
Some
of
the
specific
concerns
expressed
by
DoD
stakeholders
include
the
requirement
to
purchase
materials
that
meet
military
specifications
for
their
surface
coating
operations.
Military
specifications
are
typically
based
on
the
coating's
performance
characteristics
(
e.
g.,
chemical
agent
resistance),
and
the
coatings
must
often
be
compatible
with
multiple
substrates.
These
materials
are
purchased
using
a
stock
number
which
could
represent
hundreds
of
different
formulations
that
meet
the
performance
specifications;
however,
the
HAP
content
of
such
materials
could
fluctuate
widely
between
formulations.
Additionally,
since
the
materials
may
be
used
at
the
maintenance
depot,
DoD
installation,
or
in
the
field,
the
options
available
to
achieve
emissions
reductions
(
e.
g.,
addon
control
technology)
could
be
limited.
Furthermore,
much
of
DoD
equipment
is
coated
as
an
assembled
product
comprised
of
as
many
as
five
different
substrates,
in
a
wide
range
of
shapes
and
sizes,
which
must
be
capable
of
serving
in
a
multitude
of
challenging
environments
and
situations.
We
are
currently
evaluating
the
need
for
a
DoD
source
category
or
subcategory,
and
we
request
comment
on
the
appropriate
approach
for
addressing
unique
DoD
coating
operations.
An
alternative
approach
to
establishing
separate
emission
limits
for
each
subcategory
would
be
to
establish
a
``
multi
component''
emission
limit
for
the
entire
source
category.
A
multicomponent
approach
could
allow
sources
to
calculate
a
source
specific
emission
limit
based
on
a
weightedaverage
using
the
MACT
limit
and
the
percentage
solids
for
each
component
of
the
limit.
The
source
would
then
calculate
its
emission
rate
to
determine
compliance
with
the
source
specific
emission
limit.
The
source
specific
emission
limit
would
be
calculated
as
follows:
Emission
Limit
=
[``
component
A''
MACT
limit)
×
(``
component
A''
%
solids)]+
[``
component
B''
MACT
limit)
×
(``
component
B''
%
solids)]
The
source's
emission
rate
would
be
calculated
as
follows:
Emission
Rate
Total
pounds
of
organic
HAP
emitted
ds
of
solids
used
=
Total
poun
The
source
specific
approach
would
allow
averaging
between
the
different
components
of
the
multi
component
emission
limit.
However,
there
would
be
some
additional
requirements.
In
addition
to
the
monitoring,
recordkeeping,
and
reporting
requirements
included
in
these
proposed
standards,
the
multicomponent
emission
limit
approach
would
require
a
source
to
calculate
and
record
the
source
specific
emission
limit
each
month.
The
calculation
would
reflect
a
rolling
12
month
compliance
period
based
on
the
amount
of
coating
solids
used
for
each
separate
component
during
each
rolling
12
month
period.
We
are
requesting
comments
on
the
feasibility,
and
burden
associated
with
each
of
the
approaches
(
i.
e.,
subcategory
or
multi
component
emission
limits).
Comments
should
include
specific
examples
and
supporting
information
for
the
advantages
and
disadvantages
of
each
approach.
B.
What
Is
the
Relationship
to
Other
Rules?
Affected
sources
subject
to
the
proposed
rule
may
also
be
subject
to
other
rules
if
they
perform
surface
coating
of
parts
or
products
that
are
regulated
by
other
NESHAP.
For
example,
there
may
be
facilities
that
coat
plastic
and
metal
parts
using
the
same
or
different
coatings,
coating
application
processes,
and
conveyance
equipment,
either
simultaneously
or
at
alternative
times.
These
facilities
could
be
required
to
demonstrate
compliance
with
two
surface
coating
NESHAP
(
e.
g.,
proposed
subparts
MMMM
(
67
FR
52780,
August
13,
2002)
and
PPPP)
with
limits
based
on
different
units
(
i.
e.,
pounds
HAP
emitted
per
gallon
of
coating
solids
used
versus
pounds
HAP
emitted
per
pound
of
coating
solids
used)
and
possibly
different
compliance
dates.
Furthermore,
because
their
operations
may
not
be
dedicated
to
particular
parts
or
products
(
e.
g.,
job
shops
or
contract
coaters),
their
compliance
requirements
could
vary
over
time
due
to
fluctuations
in
their
operations.
These
types
of
facilities
may
present
unique
challenges
with
respect
to
permitting,
demonstrating
compliance
(
e.
g.,
possibly
dual
recordkeeping
and
reporting
requirements),
and
enforcement.
Historically,
EPA
has
handled
this
situation
by
giving
facilities
the
option
of
complying
with
the
NESHAP
with
the
most
stringent
emission
limits
(
i.
e.,
the
NESHAP
that
results
in
the
lowest
emissions
from
the
affected
source),
in
lieu
of
complying
with
each
otherwise
applicable
NESHAP.
This
option
would
require
sources
to
demonstrate
which
of
the
applicable
standards
is
the
most
stringent.
This
demonstration
is
necessary
because,
as
stated
previously,
the
emission
limits
may
be
expressed
in
different
units.
Under
this
compliance
option,
once
the
demonstration
is
made,
a
facility
would
ensure
that
all
coating
operations
covered
by
a
NESHAP
comply
with
the
single,
more
stringent
NESHAP.
This
option
allows
a
facility
operational
flexibility,
while
ensuring
that
the
facility
is
in
compliance
with
the
requirements
of
the
CAA
(
i.
e.,
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72280
Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
achieving
emissions
reductions
consistent
with
section
112(
d)).
This
option
may
also
simplify
permitting
and
provide
clarity
for
compliance
and
enforcement.
The
EPA
believes
that
this
approach
towards
addressing
potentially
overlapping
regulations
is
appropriate
in
this
proposed
rule
and
solicits
comments
on
the
desirability
of
providing
such
a
compliance
option.
A
second
option
which
may
provide
facilities
with
the
desired
operational
flexibility
is
the
``
predominant
activity''
approach
which
was
shared
with
stakeholders
in
May
2001.
This
approach
would
allow
a
facility
to
determine
the
predominant
coating
activity
(
e.
g.,
plastic
parts)
among
all
the
coating
activities
that
are
subject
to
a
NESHAP
(
e.
g.,
plastic
parts
and
miscellaneous
metal
products)
and
demonstrate
compliance
with
the
NESHAP
established
for
the
source
category
represented
by
the
predominant
activity.
A
source
not
electing
to
comply
with
the
predominant
activity
option
would
continue
to
be
subject
to
separate
NESHAP
and
would
need
to
demonstrate
compliance
with
each
one.
Although
EPA
received
encouraging
feedback
for
a
predominant
activity
approach
from
many
stakeholders
(
e.
g.,
industry
representatives,
State
and
local
authorities),
there
were
few
suggestions
on
either
how
to
measure
and
document
predominant
(
e.
g.,
surface
area
coated,
volume
solids
used,
etc.)
or
the
appropriate
criteria
for
establishing
which
activity
is
predominant
(
e.
g.,
a
numerical
percent
of
the
facility's
surface
coating
operations
that
would
qualify
appropriately
as
predominant).
In
defining
a
predominant
activity
approach,
the
criteria
used
to
define
predominant
should,
for
practical
reasons,
minimize
fluctuation
of
the
predominant
activity
between
different
source
categories
at
job
shops/
contract
coaters.
In
addition,
the
basis
(
e.
g.,
surface
area
coated,
volume
solids
used,
etc.)
for
measuring
predominant
would
need
to
be
established
and
should
be
suitable
for
all
sources.
One
possible
way
to
help
minimize
fluctuation
over
time
in
what
is
identified
as
the
predominant
activity
would
be
to
base
predictions
about
which
activity
would
be
predominant
on
appropriate
records
for
the
most
recent
3
5
years.
Sources
would
then
comply
with
the
NESHAP
relevant
to
that
predominant
activity
under
its
operating
permit
and
would
have
the
opportunity
to
review
its
predominant
activity
designation,
and
modify
as
appropriate,
during
each
permit
renewal.
In
implementing
a
predominant
activity
option,
EPA
needs
to
balance
good
public
policy
(
avoiding
overlapping
regulations
where
feasible
and
sensible)
with
ensuring
emissions
reductions
consistent
with
the
legislative
mandate
of
sections
112(
d)(
3)
and
(
i)(
3)
of
the
CAA
(
i.
e.,
ensuring
emission
reductions
achieved
under
the
predominant
activity
option
are
comparable
to
those
achieved
through
compliance
with
each
applicable
NESHAP
separately).
We
specifically
request
comment
on
how
a
predominant
activity
approach
should
be
structured
to
ensure
that
emission
reductions
achieved
are
consistent
with
the
requirements
of
sections
112(
d)(
3)
and
(
i)(
3).
A
third
option
under
consideration
is
the
development
of
a
subcategory
for
facilities
with
coating
operations
that
would
otherwise
be
subject
to
more
than
one
coating
NESHAP.
Based
on
survey
data
collected
under
CAA
section
114,
we
would
establish
a
MACT
floor
that
reflects
HAP
emission
rates
from
the
relevant
coating
operations.
The
practical
advantages
associated
with
this
approach
are
similar
to
the
benefits
stated
for
the
more
stringent
NESHAP
approach
(
i.
e.,
simplification
of
permitting,
clarity
of
requirements,
and
achieving
mandated
emissions
reductions).
This
approach
may
also
limit
the
need
for
separate
tracking
systems
for
surface
coating
operations.
A
disadvantage
with
this
option
is
that
it
may
not
afford
facilities
as
much
operational
flexibility
as
the
other
two
options.
A
fourth
option
is
to
expand
the
definition
of
the
source
category
and
four
subcategories
currently
under
consideration
to
include
``
incidental''
surface
coating
operations
being
performed
on
other
substrates
(
e.
g.
metal)
that
meet
the
applicability
criteria
for
another
surface
coating
source
category.
Under
this
approach,
a
facility
could
demonstrate
that
a
specified
percentage
of
its
NESHAPregulated
surface
coating
activities
are
within
the
scope
of
a
specific
category
or
subcategory.
The
remaining
NESHAP
regulated
coating
operations
would
be
considered
incidental
for
purposes
of
determining
which
category
or
subcategory
the
overall
operations
were
in,
as
they
would
represent
a
small
portion
of
the
total
coating
operations.
Once
this
demonstration
is
made,
all
NESHAP
regulated
coating
operations
conducted
at
the
facility
would
be
included
in,
and
subject
to,
the
emission
limitations
for
the
primary
source
category.
We
request
comment
on
the
feasibility,
benefits,
and
disadvantages
associated
with
each
option
presented.
We
also
request
comment
on
additional
options
for
consideration.
For
all
options,
we
request
facility
specific
data
that
would
support
the
recommended
option.
These
data
include
information
on
the
processes;
coating
and
cleaning
material
usage;
the
proportion
of
coating
and
cleaning
material
being
used
with
different
substrates;
and
the
difference
in
the
emission
reductions
achieved
based
on
complying
with
each
applicable
NESHAP
separately
and
the
option
being
recommended.
Additionally,
we
request
comment
and
supporting
documentation
on
the
criteria
(
e.
g.,
numerical
percentage)
and
basis
(
e.
g.,
surface
area
coated)
for
determining
predominant
activity
and
defining
incidental
operations.
Finally,
we
request
comment
on
the
burden
associated
with
monitoring,
recordkeeping,
and
reporting
for
each
option.
Standards
of
Performance
for
Industrial
Surface
Coating:
Surface
Coating
of
Plastic
Parts
for
Business
Machines
40
CFR
Part
60,
Subpart
TTT
The
new
source
performance
standards
(
NSPS)
for
plastic
parts
for
business
machines
apply
to
facilities
that
apply
coatings
to
plastic
parts
for
use
in
business
machines
that
began
construction,
reconstruction,
or
modification
after
January
8,
1986.
The
pollutants
regulated
are
volatile
organic
compounds
(
VOC).
Emissions
of
VOC
are
limited
to
1.5
kilogram
VOC
per
liter
(
kg
VOC/
liter)
of
coating
solids
applied
for
primers
and
color
coats,
and
2.3
kg
VOC/
liter
of
coating
solids
applied
for
texture
coatings
and
touch
up
coatings.
The
affected
facility
is
each
individual
spray
booth.
The
proposed
rule
differs
from
the
NSPS
in
three
ways.
First,
the
affected
source
for
the
proposed
rule
is
defined
broadly
as
the
collection
of
all
coating
operations
and
related
activities
and
equipment
at
the
facility,
whereas
the
affected
facility
for
the
NSPS
is
defined
narrowly
as
each
individual
spray
booth.
The
broader
definition
of
an
affected
source
allows
a
facility's
emissions
to
be
combined
for
compliance
purposes.
Second,
the
proposed
rule
regulates
organic
HAP.
While
most,
although
not
all,
organic
HAP
emitted
from
plastic
parts
and
products
surface
coating
operations
are
VOC,
some
VOC
are
not
listed
as
HAP.
Therefore,
the
NSPS
regulate
a
potentially
different
range
of
pollutants
than
the
proposed
NESHAP.
Third,
the
HAP
emission
limitations
in
the
proposed
rule
are
based
on
the
amount
of
coating
solids
used
at
the
affected
source.
The
VOC
limitations
in
the
NSPS
are
based
on
the
amount
of
coating
solids
actually
applied
to
the
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Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
plastic
parts
and
products,
which
necessitates
estimates
of
transfer
efficiency
in
the
compliance
calculations.
Because
of
the
differences
between
the
NSPS
and
the
proposed
NESHAP,
compliance
with
either
rule
cannot
be
deemed
compliance
with
the
other.
A
plastic
parts
and
products
surface
coating
operation
that
meets
the
applicability
requirements
of
both
the
NSPS
and
the
proposed
NESHAP
must
comply
with
both.
Overlapping
reporting,
recordkeeping,
and
monitoring
requirements
may
be
resolved
through
your
title
V
permit.
Aerospace
Manufacturing
and
Rework
Facilities
NESHAP
(
40
CFR
Part
63,
Subpart
GG)
The
aerospace
NESHAP
establish
HAP
and
VOC
emission
limitations
for
aerospace
manufacturing
and
rework
facilities
that
produce
or
repair
aerospace
vehicles
(
e.
g.,
airplanes,
helicopters,
space
vehicles)
or
vehicle
parts.
The
aerospace
NESHAP
apply
only
to
parts
and
assemblies
that
are
critical
to
the
aerospace
vehicle's
structural
integrity
or
flight
performance.
Therefore,
the
possibility
exists
that
some
facilities
would
be
subject
to
the
requirements
of
both
the
aerospace
NESHAP
and
the
proposed
plastic
parts
and
products
surface
coating
NESHAP.
For
example,
a
facility
that
performs
maintenance
operations
consisting
of
both
exterior
and
interior
reconstruction
and
overhaul
of
commercial
airplanes
may
perform
coating
of
plastic
parts,
such
as
tray
tables
and
seat
panels,
that
are
not
considered
critical
to
the
structural
integrity
or
flight
performance.
These
parts
may
be
removed
from
the
airplane
and
painted
on
site
to
cover
scratches
and
other
wear
marks
before
being
reinstalled.
Such
coating
activities
and
associated
equipment
would
be
subject
to
the
proposed
plastic
parts
and
products
coating
NESHAP.
We
do
not
foresee
that
any
conflicts
will
exist
between
the
requirements
for
the
aerospace
NESHAP
and
the
proposed
plastic
parts
and
products
surface
coating
NESHAP.
If
a
plastic
part
that
is
critical
to
the
aerospace
vehicle's
structural
integrity
or
flight
performance
is
coated,
the
coating
operation
for
that
part
will
fall
under
the
aerospace
NESHAP.
Only
plastic
parts
that
are
not
critical
to
the
aerospace
vehicle's
structural
integrity
or
flight
performance
will
fall
under
the
proposed
plastic
parts
and
products
surface
coating
NESHAP.
C.
What
Are
the
Primary
Sources
of
Emissions
and
What
Are
the
Emissions?
The
proposed
NESHAP
would
regulate
emissions
of
organic
HAP.
Available
emission
data
collected
during
the
development
of
the
proposed
NESHAP
show
that
the
primary
organic
HAP
emitted
from
plastic
parts
and
products
surface
coating
operations
include
MEK,
MIBK,
toluene,
and
xylenes.
These
compounds
account
for
over
85
percent
of
this
source
category's
nationwide
organic
HAP
emissions.
Other
organic
HAP
emissions
identified
include
EGBE
and
glycol
ethers.
The
majority
of
organic
HAP
emissions
from
a
facility
engaged
in
plastic
parts
and
products
surface
coating
operations
can
be
attributed
to
the
application,
drying,
and
curing
of
coatings.
The
remaining
emissions
are
primarily
from
cleaning
operations.
In
most
cases,
organic
HAP
emissions
from
mixing,
storage,
and
waste
handling
are
relatively
small.
The
organic
HAP
emissions
associated
with
coatings
(
the
term
``
coatings''
includes
protective
and
decorative
coatings
as
well
as
adhesives)
occur
due
to
volatilization
of
solvents
and
carriers.
Coatings
are
most
often
applied
either
by
using
a
spray
gun
in
a
spray
booth
or
by
dipping
the
substrate
in
a
tank
containing
the
coating.
In
a
spray
booth,
volatile
components
evaporate
from
the
coating
as
it
is
applied
to
the
part
and
from
the
overspray.
The
coated
part
then
passes
through
a
flash
off
area
where
additional
volatiles
evaporate
from
the
coating.
Finally,
the
coated
part
passes
through
a
drying/
curing
oven,
or
is
allowed
to
air
dry,
where
the
remaining
volatiles
are
evaporated.
Organic
HAP
emissions
also
occur
from
the
activities
undertaken
during
cleaning
operations
where
solvent
is
used
to
remove
coating
residue
or
other
unwanted
materials.
Cleaning
in
this
industry
includes
cleaning
of
spray
guns
and
transfer
lines
(
e.
g.,
tubing
or
piping),
tanks,
and
the
interior
of
spray
booths.
Cleaning
also
includes
applying
solvents
to
manufactured
parts
prior
to
coating
application
and
to
equipment
(
e.
g.,
cleaning
rollers,
pumps,
conveyors,
etc.).
Mixing
and
storage
are
other
sources
of
emissions.
Organic
HAP
emissions
can
occur
from
displacement
of
organic
vapor
laden
air
in
containers
used
to
store
organic
HAP
solvents
or
to
mix
coatings
containing
organic
HAP
solvents.
The
displacement
of
vaporladen
air
can
occur
during
the
filling
of
containers
and
can
be
caused
by
changes
in
temperature
or
barometric
pressure,
or
by
agitation
during
mixing.
Volatilization
of
organic
HAP
can
also
occur
during
waste
handling.
D.
What
Is
the
Affected
Source?
We
define
an
affected
source
as
a
stationary
source,
a
group
of
stationary
sources,
or
part
of
a
stationary
source
to
which
a
specific
emission
standard
applies.
The
proposed
standards
define
the
affected
source
as
the
collection
of
all
operations
associated
with
the
surface
coating
of
plastic
parts
and
products
within
each
of
the
four
subcategories
(
TPO,
headlamps,
assembled
on
road
vehicle
and
general
use).
These
operations
include
preparation
of
a
coating
for
application
(
e.
g.,
mixing
with
thinners
or
other
additives);
surface
preparation
of
the
plastic
parts
and
products;
coating
application
and
flash
off;
drying
and/
or
curing
of
applied
coatings;
cleaning
of
equipment
used
in
surface
coating;
storage
of
coatings,
thinners,
and
cleaning
materials;
and
handling
and
conveyance
of
waste
materials
from
the
surface
coating
operations.
The
coating
operation
does
not
include
the
application
of
coatings
using
hand
held
aerosol
containers.
A
few
facilities
have
coating
operations
in
more
than
one
subcategory.
For
example,
a
few
facilities
have
TPO
coating
operations
that
are
in
the
TPO
coating
subcategory
and
also
have
other
plastic
parts
and
products
coating
operations
that
are
in
the
general
use
coating
subcategory.
In
such
a
case,
the
facility
would
have
two
separate
affected
sources:
(
1)
The
collection
of
all
operations
associated
with
the
surface
coating
of
TPO,
and
(
2)
the
collection
of
all
operations
associated
with
general
use
coating.
Each
of
these
affected
sources
would
be
required
to
meet
the
emission
limits
that
apply
to
its
subcategory.
Another
example
of
a
facility
with
coating
operations
in
more
than
one
subcategory
would
be
a
facility
that
assembles
and
paints
motor
homes.
The
use
of
adhesives,
caulks,
sealants,
and
associated
materials
in
assembling
the
motor
home
would
be
in
the
general
use
coating
subcategory
and
would
constitute
one
affected
source.
The
use
of
coatings
and
associated
materials
in
painting
the
assembled
motor
home
would
be
in
the
assembled
on
road
vehicle
subcategory
and
would
constitute
a
second
affected
source.
E.
What
Are
the
Emission
Limits,
Operating
Limits,
and
Other
Standards?
Emission
Limits.
We
are
proposing
to
limit
organic
HAP
emissions
from
each
existing
affected
source
using
the
emission
limits
in
Table
2.
The
proposed
emission
limits
for
each
new
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Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
or
reconstructed
affected
source
are
given
in
Table
3.
TABLE
2.
EMISSION
LIMITS
FOR
EXISTING
AFFECTED
SOURCES
For
any
affected
source
applying
coating
to
.
.
.
The
organic
HAP
emission
limit
you
must
meet,
in
kg
organic
HAP
emitted/
kg
coating
solids
used
(
lb
organic
HAP
source
emitted
lb
coating
solids
used),
is:
TPO
substrates
........................
0.23
Headlamps
...............................
0.45
Aassembled
on
road
vehicles
1.34
Other
(
general
use)
plastic
parts
and
products.
0.16
TABLE
3.
EMISSION
LIMITS
FOR
NEW
OR
RECONSTRUCTED
AFFECTED
SOURCES
For
any
affected
source
applying
coating
to
.
.
.
The
organic
HAP
emission
limit
you
must
meet,
in
kg
organic
HAP
emitted/
kg
coating
solids
used
(
lb
organic
HAP
emitted/
lb
coating
solids
used),
is:
TPO
substrates
........................
0.17
Headlamps
...............................
0.26
Assembled
on
road
vehicles
....
1.34
Other
(
general
use)
plastic
parts
and
products.
0.16
You
can
choose
from
several
compliance
options
in
the
proposed
rule
to
achieve
the
emission
limits.
You
could
comply
by
applying
materials
(
coatings,
thinners
and
other
additives,
and
cleaning
materials)
that
meet
the
emission
limits,
either
individually
or
collectively,
during
each
compliance
period.
You
could
also
use
a
capture
system
and
add
on
control
device
to
meet
the
emission
limits.
You
could
also
comply
by
using
a
combination
of
both
approaches.
Operating
Limits.
If
you
reduce
emissions
by
using
a
capture
system
and
add
on
control
device
(
other
than
a
solvent
recovery
system
for
which
you
conduct
a
liquid
liquid
material
balance),
the
proposed
operating
limits
would
apply
to
you.
These
limits
are
site
specific
parameter
limits
that
you
determine
during
the
initial
performance
test
of
the
system.
For
capture
systems
that
are
not
permanent
total
enclosures,
you
would
establish
average
volumetric
flow
rates
or
duct
static
pressure
limits
for
each
capture
device
(
e.
g.,
a
hood
or
enclosure)
in
each
capture
system.
For
capture
systems
that
are
permanent
total
enclosures,
you
would
establish
limits
on
average
facial
velocity
or
pressure
drop
across
openings
in
the
enclosure.
For
thermal
oxidizers,
you
would
monitor
the
combustion
temperature.
For
catalytic
oxidizers,
you
would
monitor
the
temperature
immediately
before
and
after
the
catalyst
bed,
or
you
would
monitor
the
temperature
before
the
catalyst
bed
and
prepare
and
implement
an
inspection
and
maintenance
plan
that
includes
periodic
catalyst
activity
checks.
For
carbon
adsorbers
for
which
you
do
not
conduct
a
liquid
liquid
material
balance,
you
would
monitor
the
carbon
bed
temperature
and
the
amount
of
steam
or
nitrogen
used
to
desorb
the
bed.
For
condensers
for
which
you
do
not
conduct
a
liquid
liquid
material
balance,
you
would
monitor
the
outlet
gas
temperature
from
the
condenser.
For
concentrators,
you
would
monitor
the
temperature
of
the
desorption
stream
and
the
pressure
drop
across
the
concentrator.
The
site
specific
parameter
limits
that
you
establish
must
reflect
operation
of
the
capture
system
and
control
device
during
a
performance
test
that
demonstrates
achievement
of
the
emission
limits
during
representative
operating
conditions.
Work
Practice
Standards.
If
you
use
an
emission
capture
system
and
control
device
for
compliance,
you
would
be
required
to
develop
and
implement
a
work
practice
plan
to
minimize
organic
HAP
emissions
from
mixing
operations,
storage
tanks
and
other
containers,
and
handling
operations
for
coatings,
thinners,
cleaning
materials,
and
waste
materials.
If
you
use
a
capture
system
and
control
device
for
compliance,
you
would
be
required
to
develop
and
operate
according
to
a
startup,
shutdown,
and
malfunction
plan
(
SSMP)
during
periods
of
startup,
shutdown,
or
malfunction
of
the
capture
system
and
control
device.
The
NESHAP
General
Provisions
at
40
CFR
part
63,
subpart
A,
codify
certain
procedures
and
criteria
for
all
40
CFR
part
63
NESHAP
and
would
apply
to
you
as
indicated
in
the
proposed
rule.
The
General
Provisions
contain
administrative
procedures,
preconstruction
review
procedures
for
new
sources,
and
procedures
for
conducting
compliance
related
activities
such
as
notifications,
reporting
and
recordkeeping,
performance
testing,
and
monitoring.
The
proposed
rule
refers
to
individual
sections
of
the
General
Provisions
to
emphasize
key
sections
that
are
relevant.
However,
unless
specifically
overridden
in
the
proposed
rule,
all
of
the
applicable
General
Provisions
requirements
would
apply
to
you.
F.
What
Are
the
Testing
and
Initial
Compliance
Requirements?
Existing
affected
sources
would
have
to
be
in
compliance
with
the
final
rule
no
later
than
3
years
after
the
effective
date
of
the
final
rule.
New
and
reconstructed
sources
would
have
to
be
in
compliance
upon
initial
startup
of
the
affected
source
or
by
the
effective
date
of
the
final
rule,
whichever
is
later.
The
effective
date
is
the
date
on
which
the
final
rule
is
published
in
the
Federal
Register.
However,
affected
sources
would
not
be
required
to
demonstrate
compliance
until
the
end
of
the
initial
compliance
period
when
they
will
have
accumulated
the
necessary
records
to
document
the
rolling
12
month
organic
HAP
emission
rate.
Compliance
with
the
emission
limits
is
based
on
a
rolling
12
month
organic
HAP
emission
rate
determined
each
month.
Each
12
month
period
is
a
compliance
period.
The
initial
compliance
period,
therefore,
is
the
12
month
period
beginning
on
the
compliance
date.
If
the
compliance
date
occurs
on
any
day
other
than
the
first
day
of
a
month,
then
the
initial
compliance
period
begins
on
the
compliance
date
and
extends
through
the
end
of
that
month
plus
the
following
12
months.
We
have
defined
``
month''
as
a
calendar
month
or
a
pre
specified
period
of
28
to
35
days
to
allow
for
flexibility
at
sources
where
data
are
based
on
a
business
accounting
period.
Being
``
in
compliance''
means
that
the
owner
or
operator
of
the
affected
source
meets
the
requirements
to
achieve
the
proposed
emission
limitations
during
the
initial
compliance
period.
However,
they
will
not
have
accumulated
the
records
for
the
rolling
12
month
organic
HAP
emission
rate
until
the
end
of
the
initial
compliance
period.
At
the
end
of
the
initial
compliance
period,
the
owner
or
operator
would
use
the
data
and
records
generated
to
determine
whether
or
not
the
affected
source
is
in
compliance
with
the
organic
HAP
emission
limit
and
other
applicable
requirements
for
that
period.
If
the
affected
source
does
not
meet
the
applicable
limit
and
other
requirements,
it
is
out
of
compliance.
Emission
Limits.
There
are
three
proposed
options
for
complying
with
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Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
the
proposed
emission
limits,
and
the
testing
and
initial
compliance
requirements
vary
accordingly.
You
may
choose
to
use
one
compliance
option
for
the
entire
affected
source,
or
you
may
use
different
compliance
options
for
different
coating
operations
within
the
affected
source.
You
may
also
use
different
compliance
options
for
the
same
coating
operation
at
different
times.
Option
1:
Compliant
Materials
This
option
is
a
pollution
prevention
option
that
allows
you
to
easily
demonstrate
compliance
by
using
low
HAP
or
non
HAP
coatings
and
other
materials.
If
you
use
coatings
that,
based
on
their
organic
HAP
content,
individually
meet
the
kg
(
pound
(
lb))
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used
levels
in
the
applicable
emission
limits
and
you
use
non
HAP
thinners
and
other
additives
and
cleaning
materials,
this
compliance
option
is
available
to
you.
For
this
option,
we
have
minimized
recordkeeping
and
reporting
requirements.
You
can
demonstrate
compliance
by
using
manufacturer's
formulation
data
and
readily
available
purchase
records
to
determine
the
organic
HAP
content
of
each
coating
or
other
material
and
the
amount
of
each
material
used.
You
would
not
need
to
perform
any
detailed
emission
rate
calculations.
If
you
demonstrate
compliance
based
on
the
coatings
and
other
materials
used,
you
would
demonstrate
that
the
organic
HAP
content
of
each
coating
meets
the
emission
limits
for
the
appropriate
subcategory
as
shown
in
Tables
2
and
3,
and
that
you
used
no
organic
HAP
containing
thinners,
other
additives,
or
cleaning
materials.
For
example,
if
you
are
using
the
compliant
materials
option
and
your
existing
source
has
TPO
coating
operations,
headlamp
coating
operations,
assembled
on
road
vehicle
coating
operations,
and
general
use
coating
operations,
you
would
demonstrate
that:
(
1)
Each
coating
used
in
the
TPO
coating
operation
has
an
organic
HAP
content
no
greater
than
0.23
kg
(
0.23
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used;
(
2)
each
coating
used
in
the
headlamp
coating
operations
has
an
organic
HAP
content
no
greater
than
0.45
kg
(
0.45
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used;
(
3)
each
coating
used
in
the
assembled
on
road
vehicle
coating
operations
has
an
organic
HAP
content
no
greater
than
1.34
kg
(
1.34
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used;
(
4)
each
general
use
coating
has
an
organic
HAP
content
no
greater
than
0.16
kg
(
0.16
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used;
(
5)
and
that
you
used
no
organic
HAP
containing
thinners,
other
additives,
or
cleaning
materials.
Note
that
``
no
organic
HAP''
is
not
intended
to
mean
absolute
zero.
Materials
that
contain
``
no
organic
HAP''
should
be
interpreted
to
mean
materials
that
contain
organic
HAP
levels
below
the
levels
specified
in
§
63.4541(
a)
of
the
proposed
rule,
which
are
typical
reporting
levels.
These
typical
reporting
levels
only
count
organic
HAP
that
are
present
at
0.1
percent
or
more
by
mass
for
Occupational
Safety
and
Health
Administration
(
OSHA)
defined
carcinogens
and
at
1.0
percent
or
more
by
mass
for
other
compounds.
To
determine
the
mass
of
organic
HAP
in
coatings,
thinners,
and
cleaning
materials
and
the
mass
fraction
of
coating
solids,
you
could
rely
on
manufacturer's
formulation
data.
You
would
not
be
required
to
perform
tests
or
analysis
of
the
material
if
formulation
data
are
available.
Alternatively,
you
could
use
results
from
the
test
methods
listed
below.
You
may
also
use
alternative
test
methods
provided
you
get
EPA
approval
in
accordance
with
the
NESHAP
General
Provisions,
40
CFR
63.7(
f).
However,
if
there
is
any
inconsistency
between
the
test
method
results
(
either
EPA's
or
an
approved
alternative)
and
manufacturer's
data,
the
test
method
results
would
prevail
for
compliance
and
enforcement
purposes.
If
you
elect
to
perform
tests:
For
organic
HAP
content,
use
Method
311
of
40
CFR
part
63,
appendix
A.
The
proposed
rule
would
allow
you
to
use
nonaqueous
volatile
matter
as
a
surrogate
for
organic
HAP,
which
would
include
all
organic
HAP
plus
all
other
organic
compounds,
and
excluding
water.
If
you
choose
this
option,
use
Method
24
of
40
CFR
part
60,
appendix
A.
For
mass
fraction
of
coating
solids,
use
Method
24.
Option
2:
Compliance
Based
on
the
Emission
Rate
Without
Add
on
Controls
This
option
is
a
pollution
prevention
option
where
you
can
demonstrate
compliance
based
on
the
organic
HAP
contained
in
the
mix
of
coatings,
thinners
and
other
additives,
and
cleaning
materials
you
use.
This
option
allows
you
the
flexibility
to
use
some
individual
coatings
that
do
not,
by
themselves,
meet
the
kg
(
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used
levels
in
the
applicable
emission
limits
if
you
use
other
low
HAP
or
non
HAP
coatings
such
that
overall
emissions
from
the
affected
source
over
a
12
month
period
meet
the
emission
limits.
You
must
use
this
option
if
you
use
HAP
containing
thinners,
other
additives,
and
cleaning
materials
and
do
not
have
add
on
controls.
You
would
keep
track
of
the
mass
of
organic
HAP
in
each
coating,
thinner
or
other
additive,
and
cleaning
material,
and
the
amount
of
each
material
you
use
in
your
affected
source
each
month
of
the
compliance
period.
You
would
use
this
information
to
determine
the
total
mass
of
organic
HAP
in
all
coatings,
thinners
and
other
additives,
and
cleaning
materials
divided
by
the
total
mass
of
coating
solids
used
during
the
compliance
period.
You
would
demonstrate
that
your
emission
rate
(
in
kg
(
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used)
meets
the
applicable
emission
limit.
You
can
use
readily
available
purchase
records
and
manufacturer's
formulation
data
to
determine
the
amount
of
each
coating
or
other
material
you
used
and
the
organic
HAP
in
each
material.
The
proposed
rule
contains
equations
that
show
you
how
to
perform
the
calculations
to
demonstrate
compliance.
If
you
demonstrate
compliance
using
Option
2,
you
would
be
required
to:
Determine
the
quantity
of
each
coating,
thinner
and
other
additive,
and
cleaning
material
used.
Determine
the
mass
of
organic
HAP
in
each
coating,
thinner
and
other
additive,
and
cleaning
material
using
the
same
types
of
data
and
methods
previously
described
for
Option
1.
You
may
rely
on
manufacturer's
formulation
data
or
you
may
choose
to
use
test
results
as
described
under
Option
1.
Determine
the
mass
fraction
of
coating
solids
for
each
coating
using
the
same
types
of
data
or
methods
described
under
Option
1.
Calculate
the
total
mass
of
organic
HAP
in
all
materials
and
total
mass
of
coating
solids
used
each
month.
You
may
subtract
from
the
total
mass
of
organic
HAP
the
amount
contained
in
waste
materials
you
send
to
a
hazardous
waste
treatment,
storage,
and
disposal
facility
regulated
under
40
CFR
part
262,
264,
265,
or
266.
Calculate
the
total
mass
of
organic
HAP
emissions
and
total
mass
of
coating
solids
for
the
initial
compliance
period
by
adding
together
all
the
monthly
values
for
mass
of
organic
HAP
and
for
mass
of
coating
solids
for
the
12
months
of
the
initial
compliance
period.
Calculate
the
ratio
of
the
total
mass
of
organic
HAP
emitted
for
the
materials
used
to
the
total
mass
of
coating
solids
used
(
kg
(
lb)
organic
HAP
emitted
per
kg
(
lb)
of
coating
solids
used)
for
the
initial
compliance
period.
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
Record
the
calculations
and
results
and
include
them
in
your
Notification
of
Compliance
Status.
Note
that
if
you
choose
to
use
this
option
for
a
particular
coating
operation
rather
than
for
an
entire
affected
source,
you
would
calculate
the
organic
HAP
emission
rate
using
just
the
materials
used
in
that
operation.
Similarly,
if
your
facility
has
multiple
affected
sources
using
this
option
(
e.
g.,
a
TPO
affected
source,
a
headlamp
affected
source,
an
assembled
on
road
vehicle
affected
source,
and
a
general
use
affected
source),
you
would
do
a
separate
calculation
for
each
affected
source
to
show
that
each
affected
source
meets
its
emission
limit.
Option
3:
Emission
Rate
With
Add
on
Controls
Option
This
option
allows
sources
to
use
a
capture
system
and
an
add
on
pollution
control
device,
such
as
a
combustion
device
or
a
recovery
device,
to
meet
the
emission
limits.
While
we
believe
that,
based
on
typical
emission
characteristics,
most
sources
will
not
use
control
devices,
we
are
providing
this
option
for
sources
that
can
use
control
devices.
Fewer
than
10
percent
of
the
existing
sources
for
which
we
have
data
use
control
devices
and
may
continue
using
the
control
devices
for
compliance
with
the
proposed
standards.
Under
this
option,
testing
is
required
to
demonstrate
the
capture
system
and
control
device
efficiency.
Alternatively,
you
may
conduct
a
liquid
liquid
material
balance
to
demonstrate
the
amount
of
organic
HAP
collected
by
your
recovery
device.
The
proposed
rule
provides
equations
showing
you
how
to
use
records
of
materials
usage,
organic
HAP
contents
of
each
material,
capture
and
control
efficiencies,
and
coating
solids
content
to
calculate
your
emission
rate
during
the
compliance
period.
If
you
demonstrate
compliance
based
on
this
option,
you
would
demonstrate
that
your
emission
rate
considering
controls
(
in
kg
(
lb)
organic
HAP
emitted
per
kg
(
lb)
of
coating
solids
used)
is
less
than
the
applicable
emission
limit.
For
a
capture
system
and
add
on
control
device
other
than
a
solvent
recovery
system
for
which
you
conduct
a
liquidliquid
material
balance,
your
testing
and
initial
compliance
requirements
would
be
as
follows:
Conduct
an
initial
performance
test
to
determine
the
capture
and
control
efficiencies
of
the
equipment
and
to
establish
operating
limits
to
be
achieved
on
a
continuous
basis.
The
performance
test
would
have
to
be
completed
no
later
than
the
compliance
date
for
existing
sources
and
180
days
after
the
compliance
date
for
new
and
reconstructed
sources.
Determine
the
mass
of
organic
HAP
in
each
coating
and
other
material,
and
the
mass
fraction
of
coating
solids
for
each
coating
used
each
month
of
the
initial
compliance
period.
Calculate
the
total
mass
of
organic
HAP
in
all
coatings
and
other
materials,
and
total
mass
of
coating
solids
used
each
month
in
the
controlled
operation
or
group
of
coating
operations.
You
may
subtract
from
the
total
mass
of
organic
HAP
the
amount
contained
in
waste
materials
you
send
to
a
hazardous
waste
treatment,
storage,
and
disposal
facility
regulated
under
40
CFR
part
262,
264,
265,
or
266.
Calculate
the
organic
HAP
emissions
from
the
controlled
coating
operations
each
month
using
the
capture
and
control
efficiencies
determined
during
the
performance
test,
and
the
total
mass
of
organic
HAP
in
materials
used
in
controlled
coating
operations
that
month.
Calculate
the
total
mass
of
organic
HAP
emissions
and
total
volume
of
coating
solids
for
the
initial
compliance
period
by
adding
together
all
the
monthly
values
for
mass
of
organic
HAP
emissions
and
for
mass
of
coating
solids
for
the
12
months
in
the
initial
compliance
period.
Calculate
the
ratio
of
the
total
mass
of
organic
HAP
emissions
to
the
total
mass
of
coating
solids
used
during
the
initial
compliance
period.
Record
the
calculations
and
results
and
include
them
in
your
Notification
of
Compliance
Status.
Develop
and
implement
a
work
practice
plan
to
minimize
emissions
from
storage,
mixing,
and
handling
of
organic
HAP
containing
materials.
Note
that
if
you
choose
to
use
this
option
for
a
particular
coating
operation
rather
than
for
the
entire
affected
source,
you
would
calculate
the
organic
HAP
emission
rate
using
just
the
materials
used
in
that
operation.
Similarly,
if
your
facility
has
multiple
affected
sources
using
this
option
(
e.
g.,
a
TPO
affected
source,
a
headlamp
affected
source,
an
assembled
on
road
vehicle
affected
source,
and
a
general
use
affected
source),
you
would
do
a
separate
calculation
for
each
affected
source
to
show
that
each
affected
source
meets
its
emission
limit.
If
you
use
a
capture
system
and
addon
control
device
other
than
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances,
you
would
use
specified
test
methods
to
determine
both
the
efficiency
of
the
capture
system
and
the
emission
reduction
efficiency
of
the
control
device.
To
determine
the
capture
efficiency,
you
would
either
verify
the
presence
of
a
permanent
total
enclosure
using
EPA
Method
204
of
40
CFR
part
51,
appendix
M
(
and
all
materials
must
be
applied
and
dried
within
the
enclosure);
or
use
one
of
three
protocols
in
§
63.4565
of
the
proposed
rule
to
measure
capture
efficiency.
If
you
have
a
permanent
total
enclosure
and
all
materials
are
applied
and
dried
within
the
enclosure
and
you
route
all
exhaust
gases
from
the
enclosure
to
a
control
device,
you
would
assume
100
percent
capture.
To
determine
the
emission
reduction
efficiency
of
the
control
device,
you
would
conduct
measurements
of
the
inlet
and
outlet
gas
streams.
The
test
would
consist
of
three
runs,
each
run
lasting
1
hour,
using
the
following
EPA
Methods
in
40
CFR
part
60,
appendix
A:
Method
1
or
1A
for
selection
of
the
sampling
sites.
Method
2,
2A,
2C,
2D,
2F,
or
2G
to
determine
the
gas
volumetric
flow
rate.
Method
3,
3A,
or
3B
for
gas
analysis
to
determine
dry
molecular
weight.
Method
4
to
determine
stack
moisture.
Method
25
or
25A
to
determine
organic
volatile
matter
concentration.
Alternatively,
any
other
test
method
or
data
that
have
been
validated
according
to
the
applicable
procedures
in
Method
301
of
40
CFR
part
63,
appendix
A,
and
approved
by
the
Administrator,
could
be
used.
If
you
use
a
solvent
recovery
system,
you
could
choose
to
determine
the
overall
control
efficiency
using
a
liquidliquid
material
balance
instead
of
conducting
an
initial
performance
test.
If
you
use
the
material
balance
alternative,
you
would
be
required
to
measure
the
amount
of
all
materials
used
in
the
controlled
coating
operations
served
by
the
solvent
recovery
system
during
each
month
of
the
initial
compliance
period
and
determine
the
total
volatile
matter
contained
in
these
materials.
You
would
also
measure
the
amount
of
volatile
matter
recovered
by
the
solvent
recovery
system
during
each
month
of
the
initial
compliance
period.
Then
you
would
compare
the
amount
recovered
to
the
amount
used
to
determine
the
overall
control
efficiency
each
month
and
apply
this
efficiency
to
the
total
mass
of
organic
HAP
in
the
materials
used
to
determine
total
organic
HAP
emissions
for
the
month.
You
would
total
these
12
monthly
organic
HAP
emission
values
and
divide
by
the
total
of
the
12
monthly
values
for
coating
solids
used
to
calculate
the
emission
rate
for
the
12
month
initial
compliance
period.
You
would
record
the
calculations
and
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Vol.
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233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
results
and
include
them
in
your
Notification
of
Compliance
Status.
Operating
Limits.
As
mentioned
above,
you
would
establish
operating
limits
as
part
of
the
initial
performance
test
of
a
capture
system
and
control
device
other
than
a
solvent
recovery
system
for
which
you
conduct
liquidliquid
material
balances.
The
operating
limits
are
the
minimum
or
maximum
(
as
applicable)
values
achieved
for
capture
systems
and
control
devices
during
the
most
recent
performance
test,
conducted
under
representative
conditions,
that
demonstrated
compliance
with
the
emission
limits.
The
proposed
rule
specifies
the
parameters
to
monitor
for
the
types
of
emission
control
systems
commonly
used
in
the
industry.
You
would
be
required
to
install,
calibrate,
maintain,
and
continuously
operate
all
monitoring
equipment
according
to
manufacturer's
specifications
and
ensure
that
the
continuous
parameter
monitoring
systems
(
CPMS)
meet
the
requirements
in
§
63.4568
of
the
proposed
rule.
If
you
use
control
devices
other
than
those
identified
in
the
proposed
rule,
you
would
submit
the
operating
parameters
to
be
monitored
to
the
Administrator
for
approval.
The
authority
to
approve
the
parameters
to
be
monitored
is
retained
by
EPA
and
is
not
delegated
to
States.
If
you
use
a
thermal
or
catalytic
oxidizer,
you
would
continuously
monitor
the
appropriate
temperature
and
record
it
at
least
every
15
minutes.
For
thermal
oxidizers,
the
temperature
monitor
is
placed
in
the
firebox
or
in
the
duct
immediately
downstream
of
the
firebox
before
any
substantial
heat
exchange
occurs.
The
operating
limit
would
be
the
average
temperature
measured
during
the
performance
test
and
for
each
consecutive
3
hour
period,
the
average
temperature
would
have
to
be
at
or
above
this
limit.
For
catalytic
oxidizers,
temperature
monitors
are
placed
immediately
before
and
after
the
catalyst
bed.
The
operating
limits
would
be
the
average
temperature
just
before
the
catalyst
bed
and
the
average
temperature
difference
across
the
catalyst
bed
during
the
performance
test.
For
each
3
hour
period,
the
average
temperature
and
the
average
temperature
difference
would
have
to
be
at
or
above
these
limits.
Alternatively,
you
would
be
allowed
to
meet
only
the
temperature
limit
before
the
catalyst
bed
if
you
develop
and
implement
an
inspection
and
maintenance
plan
for
the
catalytic
oxidizer.
If
you
use
a
carbon
adsorber
and
do
not
conduct
liquid
liquid
material
balances
to
demonstrate
compliance,
you
would
monitor
the
carbon
bed
temperature
after
each
regeneration
and
the
total
amount
of
steam
or
nitrogen
used
to
desorb
the
bed
for
each
regeneration.
The
operating
limits
would
be
the
carbon
bed
temperature
at
the
time
the
carbon
bed
is
returned
to
service
(
not
to
be
exceeded)
and
the
amount
of
steam
or
nitrogen
used
for
desorption
(
to
be
met
as
a
minimum).
If
you
use
a
condenser
and
do
not
conduct
liquid
liquid
material
balances
to
demonstrate
compliance,
you
would
monitor
the
outlet
gas
temperature
to
ensure
that
the
air
stream
is
being
cooled
to
a
low
enough
temperature.
The
operating
limit
would
be
the
average
condenser
outlet
gas
temperature
measured
during
the
performance
test
and
for
each
consecutive
3
hour
period
the
average
temperature
would
have
to
be
at
or
below
this
limit.
If
you
use
a
concentrator,
you
would
monitor
the
temperature
of
the
desorption
concentrate
stream
and
the
pressure
drop
across
the
concentrator.
These
values
would
be
recorded
at
least
once
every
15
minutes.
The
operating
limits
would
be
the
average
temperature
(
to
be
met
as
a
minimum)
and
the
average
pressure
drop
(
not
to
be
exceeded)
measured
during
the
performance
test.
For
each
capture
system
that
is
not
a
permanent
total
enclosure,
you
would
establish
operating
limits
for
gas
volumetric
flow
rate
or
duct
static
pressure
for
each
enclosure
or
capture
device.
The
operating
limit
would
be
the
average
volumetric
flow
rate
or
duct
static
pressure
during
the
performance
test,
to
be
met
as
a
minimum.
For
each
capture
system
that
is
a
permanent
total
enclosure,
the
operating
limit
would
require
the
average
facial
velocity
of
air
through
all
natural
draft
openings
to
be
at
least
200
feet
per
minute
or
the
pressure
drop
across
the
enclosure
to
be
at
least
0.007
inches
water.
Work
Practices.
If
you
use
a
capture
system
and
control
device
for
compliance,
you
would
be
required
to
develop
and
implement
on
an
ongoing
basis
a
work
practice
plan
for
minimizing
organic
HAP
emissions
from
storage,
mixing,
material
handling,
and
waste
handling
operations.
This
plan
would
include
a
description
of
all
steps
taken
to
minimize
emissions
from
these
sources
(
e.
g.,
using
closed
storage
containers,
practices
to
minimize
emissions
during
filling
and
transfer
of
contents
from
containers,
using
spill
minimization
techniques,
placing
solvent
laden
cloths
in
closed
containers
immediately
after
use,
etc.).
You
would
have
to
make
the
plan
available
for
inspection
if
the
Administrator
requests
to
see
it.
If
you
use
a
capture
system
and
control
device
for
compliance,
you
would
be
required
to
develop
and
operate
according
to
a
SSMP
during
periods
of
startup,
shutdown,
or
malfunction
of
the
capture
system
and
control
device.
G.
What
Are
the
Continuous
Compliance
Provisions?
Emission
Limits.
If
you
use
the
compliant
materials
option
(
Option
1),
you
would
demonstrate
continuous
compliance
if
each
coating
meets
the
applicable
emission
limit
and
you
use
no
organic
HAP
containing
thinners,
other
additives,
or
cleaning
materials.
If
you
use
the
emission
rate
without
addon
controls
option
(
Option
2),
you
would
demonstrate
continuous
compliance
if,
for
each
12
month
compliance
period,
the
ratio
of
kg
(
lb)
organic
HAP
emitted
to
kg
(
lb)
coating
solids
used
is
less
than
or
equal
to
the
applicable
emission
limit.
You
would
follow
the
same
procedures
for
calculating
the
organic
HAP
emitted
to
coating
solids
ratio
that
you
used
for
the
initial
compliance
period.
For
each
coating
operation
on
which
you
use
a
capture
system
and
control
device
(
Option
3)
other
than
a
solvent
recovery
system
for
which
you
conduct
a
liquid
liquid
material
balance,
you
would
use
the
continuous
parameter
monitoring
results
for
the
month
as
part
of
the
determination
of
the
mass
of
organic
HAP
emissions.
If
the
monitoring
results
indicate
no
deviations
from
the
operating
limits
and
there
were
no
bypasses
of
the
control
device,
you
would
assume
the
capture
system
and
control
device
are
achieving
the
same
percent
emission
reduction
efficiency
as
they
did
during
the
most
recent
performance
test
in
which
compliance
was
demonstrated.
You
would
then
apply
this
percent
reduction
to
the
total
mass
of
organic
HAP
in
materials
used
in
the
controlled
coating
operations
to
determine
the
emissions
from
those
operations
during
the
month.
If
there
were
any
deviations
from
the
operating
limits
during
the
month
or
any
bypasses
of
the
control
device,
you
would
account
for
them
in
the
calculation
of
the
monthly
emissions
by
assuming
the
capture
system
and
control
device
were
achieving
zero
emission
reduction
during
the
periods
of
deviation.
Then
you
would
determine
the
organic
HAP
emission
rate
by
dividing
the
total
mass
of
organic
HAP
emissions
for
the
12
month
compliance
period
by
the
total
mass
of
coating
solids
used
during
the
12
month
compliance
period.
Every
month,
you
would
calculate
the
emission
rate
for
the
previous
12
month
period.
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Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
For
each
coating
operation
on
which
you
use
a
solvent
recovery
system
and
conduct
a
liquid
liquid
material
balance
each
month,
you
would
use
the
liquidliquid
material
balance
to
determine
control
efficiency.
To
determine
the
overall
control
efficiency,
you
must
measure
the
amount
of
all
materials
used
during
each
month
and
determine
the
volatile
matter
content
of
these
materials.
You
must
also
measure
the
amount
of
volatile
matter
recovered
by
the
solvent
recovery
system
during
the
month,
calculate
the
overall
control
efficiency,
and
apply
it
to
the
total
mass
of
organic
HAP
in
the
materials
used
to
determine
total
organic
HAP
emissions
each
month.
Then
you
would
determine
the
12
month
organic
HAP
emission
rate
in
the
same
manner
described
above.
Operating
Limits.
If
you
use
a
capture
system
and
control
device,
the
proposed
rule
would
require
you
to
achieve
on
a
continuous
basis
the
operating
limits
you
establish
during
the
performance
test.
If
the
continuous
monitoring
shows
that
the
capture
system
and
control
device
are
operating
outside
the
range
of
values
established
during
the
performance
test,
you
have
deviated
from
the
established
operating
limits.
If
you
operate
a
capture
system
and
control
device
with
bypass
lines
that
could
allow
emissions
to
bypass
the
control
device,
you
would
have
to
demonstrate
that
captured
organic
HAP
emissions
within
the
affected
source
are
being
routed
to
the
control
device
by
monitoring
for
potential
bypass
of
the
control
device.
You
may
choose
from
the
following
four
monitoring
procedures:
Flow
control
position
indicator
to
provide
a
record
of
whether
the
exhaust
stream
is
directed
to
the
control
device;
Car
seal
or
lock
and
key
valve
closures
to
secure
the
bypass
line
valve
in
the
closed
position
when
the
control
device
is
operating;
Valve
closure
monitoring
to
ensure
any
bypass
line
valve
or
damper
is
closed
when
the
control
device
is
operating;
or
Automatic
shutdown
system
to
stop
the
coating
operation
when
flow
is
diverted
from
the
control
device.
A
deviation
would
occur
for
any
period
of
time
the
bypass
monitoring
indicates
that
emissions
are
not
routed
to
the
control
device.
Work
Practices.
If
you
use
an
emission
capture
system
and
control
device
for
compliance,
you
would
be
required
to
implement,
on
an
ongoing
basis,
the
work
practice
plan
you
developed
during
the
initial
compliance
period.
If
you
did
not
develop
a
plan
for
reducing
organic
HAP
emissions
or
you
do
not
implement
the
plan,
this
would
be
a
deviation
from
the
work
practice
standard.
If
you
use
a
capture
system
and
control
device
for
compliance,
you
would
be
required
to
operate
according
to
your
SSMP
during
periods
of
startup,
shutdown,
or
malfunction
of
the
capture
system
and
control
device.
H.
What
Are
the
Notification,
Recordkeeping,
and
Reporting
Requirements?
You
are
required
to
comply
with
the
applicable
requirements
in
the
NESHAP
General
Provisions,
subpart
A
of
40
CFR
part
63,
as
described
in
the
proposed
rule.
The
General
Provisions
notification
requirements
include:
initial
notifications,
notification
of
performance
test
if
you
are
complying
using
a
capture
system
and
control
device,
notification
of
compliance
status,
and
additional
notifications
required
for
affected
sources
with
continuous
monitoring
systems.
The
General
Provisions
also
require
certain
records
and
periodic
reports.
Initial
Notifications.
If
you
own
or
operate
an
existing
affected
source,
you
must
send
a
notification
to
the
EPA
Regional
Office
in
the
region
where
your
facility
is
located
and
to
your
State
agency
no
later
than
1
year
after
the
final
rule
is
published
in
the
Federal
Register.
For
new
and
reconstructed
sources,
you
must
send
the
notification
within
120
days
after
the
date
of
initial
startup
or
120
days
after
publication
of
the
final
rule,
whichever
is
later.
That
report
notifies
us
and
your
State
agency
that
you
have
an
existing
affected
source
that
is
subject
to
the
proposed
standards
or
that
you
have
constructed
a
new
affected
source.
Thus,
it
allows
you
and
the
permitting
authority
to
plan
for
compliance
activities.
You
would
also
need
to
send
a
notification
of
planned
construction
or
reconstruction
of
a
source
that
would
be
subject
to
the
proposed
rule
and
apply
for
approval
to
construct
or
reconstruct.
Notification
of
Performance
Test.
If
you
demonstrate
compliance
by
using
a
capture
system
and
control
device
for
which
you
do
not
conduct
a
liquidliquid
material
balance,
you
would
conduct
a
performance
test.
The
performance
test
would
be
required
no
later
than
the
compliance
date
for
an
existing
affected
source.
For
a
new
or
reconstructed
affected
source,
the
performance
test
would
be
required
no
later
than
180
days
after
startup
or
180
days
after
Federal
Register
publication
of
the
final
rule,
whichever
is
later.
You
must
notify
us
(
or
the
delegated
State
or
local
agency)
at
least
60
calendar
days
before
the
performance
test
is
scheduled
to
begin
and
submit
a
report
of
the
performance
test
results
no
later
than
60
days
after
the
test.
Notification
of
Compliance
Status.
You
must
submit
a
Notification
of
Compliance
Status
within
30
days
after
the
end
of
the
initial
12
month
compliance
period.
In
the
notification,
you
must
certify
whether
each
affected
source
has
complied
with
the
proposed
standards,
identify
the
option(
s)
you
used
to
demonstrate
initial
compliance,
summarize
the
data
and
calculations
supporting
the
compliance
demonstration,
and
provide
information
on
any
deviations
from
the
emission
limits,
operating
limits,
or
other
requirements.
If
you
elect
to
comply
by
using
a
capture
system
and
control
device
for
which
you
conduct
performance
tests,
you
must
provide
the
results
of
the
tests.
Your
notification
must
also
include
the
measured
range
of
each
monitored
parameter,
the
operating
limits
established
during
the
performance
test,
and
information
showing
whether
the
source
has
complied
with
its
operating
limits
during
the
initial
compliance
period.
Recordkeeping
Requirements.
You
must
keep
records
of
reported
information
and
all
other
information
necessary
to
document
compliance
with
the
proposed
rule
for
5
years.
As
required
under
the
General
Provisions,
records
for
the
2
most
recent
years
must
be
kept
on
site;
the
other
3
years'
records
may
be
kept
off
site.
Records
pertaining
to
the
design
and
operation
of
the
control
and
monitoring
equipment
must
be
kept
for
the
life
of
the
equipment.
Depending
on
the
compliance
option
that
you
choose,
you
may
need
to
keep
records
of
the
following:
Organic
HAP
content
or
volatile
organic
matter
content
and
coating
solids
content
(
for
all
compliance
options).
Quantity
of
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
during
each
compliance
period
(
for
all
compliance
options).
For
the
emission
rate
(
with
or
without
add
on
controls)
compliance
options,
calculations
of
your
emission
rate
for
each
12
month
compliance
period.
All
documentation
supporting
initial
notifications
and
notifications
of
compliance
status.
If
you
demonstrate
compliance
by
using
a
capture
system
and
control
device,
you
must
keep
records
of
the
following:
All
required
measurements,
calculations,
and
supporting
documentation
needed
to
demonstrate
compliance
with
the
standards.
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Vol.
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/
Wednesday,
December
4,
2002
/
Proposed
Rules
All
results
of
performance
tests
and
parameter
monitoring.
All
information
necessary
to
demonstrate
conformance
with
your
plan
for
minimizing
emissions
from
mixing,
storage,
and
waste
handling
operations.
All
information
necessary
to
demonstrate
conformance
with
the
affected
source's
SSMP
when
the
plan
procedures
are
followed.
The
occurrence
and
duration
of
each
startup,
shutdown,
or
malfunction
of
the
emission
capture
system
and
control
device.
Actions
taken
during
startup,
shutdown,
and
malfunction
that
are
different
from
the
procedures
specified
in
the
affected
source's
SSMP.
Each
period
during
which
a
CPMS
is
malfunctioning
or
inoperative
(
including
out
of
control
periods).
The
proposed
rule
would
require
you
to
collect
and
keep
records
according
to
certain
minimum
data
requirements
for
the
CPMS.
Failure
to
collect
and
keep
the
specified
minimum
data
would
be
a
deviation
that
is
separate
from
any
emission
limits,
operating
limits,
or
work
practice
standards.
Deviations,
as
determined
from
these
records,
would
need
to
be
recorded
and
also
reported.
A
deviation
is
any
instance
when
any
requirement
or
obligation
established
by
the
proposed
rule
including,
but
not
limited
to,
the
emission
limits,
operating
limits,
and
work
practice
standards,
is
not
met.
If
you
use
a
capture
system
and
control
device
to
reduce
organic
HAP
emissions,
you
would
have
to
make
your
SSMP
available
for
inspection
if
the
Administrator
requests
to
see
it.
The
plan
would
stay
in
your
records
for
the
life
of
the
affected
source
or
until
the
source
is
no
longer
subject
to
the
proposed
standards.
If
you
revise
the
plan,
you
would
need
to
keep
the
previous
superseded
versions
on
record
for
5
years
following
the
revision.
Periodic
Reports.
Each
reporting
year
is
divided
into
two
semiannual
reporting
periods.
If
no
deviations
occur
during
a
semiannual
reporting
period,
you
would
submit
a
semiannual
report
stating
that
the
affected
source
has
been
in
continuous
compliance.
If
deviations
occur,
you
would
include
them
in
the
report
as
follows:
Report
each
deviation
from
the
emission
limit.
Report
each
deviation
from
the
work
practice
standards
if
you
use
an
emission
capture
system
and
control
device.
If
you
use
an
emission
capture
system
and
control
device
other
than
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances,
report
each
deviation
from
an
operating
limit
and
each
time
a
bypass
line
diverts
emissions
from
the
control
device
to
the
atmosphere.
Report
other
specific
information
on
the
periods
of
time
the
deviations
occurred.
You
would
also
have
to
include
in
each
semiannual
report
an
identification
of
the
compliance
option(
s)
you
used
for
each
affected
source
and
any
time
periods
when
you
changed
to
another
compliance
option.
Other
Reports.
You
would
be
required
to
submit
reports
for
periods
of
startup,
shutdown,
or
malfunction
of
the
capture
system
and
control
device.
If
the
procedures
you
follow
during
any
startup,
shutdown,
or
malfunction
are
inconsistent
with
your
plan,
you
would
report
those
procedures
with
your
semiannual
reports
in
addition
to
immediate
reports
required
by
40
CFR
63.10(
d)(
5)(
ii).
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
Did
We
Select
the
Source
Category
and
Subcategories?
The
surface
coating
of
plastic
parts
and
products
is
a
source
category
that
is
on
the
list
of
source
categories
to
be
regulated
because
it
contains
major
sources
which
emit
or
have
the
potential
to
emit
at
least
9.07
Mg
(
10
tons)
of
any
one
HAP
or
at
least
22.7
Mg
(
25
tons)
of
any
combination
of
HAP
annually.
The
proposed
rule
would
control
organic
HAP
emissions
from
both
new
and
existing
major
sources.
Area
sources
are
not
being
regulated
under
this
proposed
rule.
The
plastic
parts
and
products
surface
coating
category
consists
of
facilities
that
apply
protective
or
decorative
coatings
and
adhesive
coatings
to
plastic
parts
and
products
through
a
post
mold
coating
process.
The
surface
coating
of
plastic
parts
and
products
includes
any
facility
engaged
in
the
surface
coating
of
plastic
parts
or
products,
including
panels,
housings,
bases,
covers,
and
other
components
formed
of
synthetic
polymers.
We
use
the
plastic
parts
and
products
lists
contained
in
the
SIC
and
NAICS
code
descriptions
to
describe
the
vast
array
of
plastic
parts
and
products.
Due
to
the
broad
scope
of
the
plastic
parts
and
products
surface
coating
source
category,
the
source
category
definition
likewise
needs
to
be
broad
in
order
to
include
the
varieties
of
operations
and
activities
that
might
occur
at
these
facilities.
However,
a
broad
description
has
the
potential
to
unintentionally
include
surface
coating
operations
that
we
would
not
consider
to
be
part
of
the
source
category.
We
intend
the
source
category
to
include
facilities
for
which
the
surface
coating
of
plastic
parts
and
products
is
either
their
principal
activity
or
an
integral
part
of
a
production
process
that
is
the
principal
activity.
Most
coating
operations
are
located
at
plant
sites
that
are
dedicated
to
these
activities.
However,
some
may
be
located
at
sites
for
which
some
other
activity
is
principal,
such
as
automobile
assembly
plants
that
coat
plastic
automobile
parts
or
accessories
off
the
assembly
line.
Colocated
surface
coating
operations
comparable
to
the
types
and
sizes
of
the
dedicated
plastic
parts
surface
coating
facilities,
in
terms
of
the
coating
operation
and
applicable
emission
control
techniques,
are
included
in
the
source
category.
We
reviewed
the
available
data
and
information
to
identify
a
descriptor
common
to
sources
we
intended
to
include
in
the
category
that
would
further
help
to
describe
the
category.
Based
on
our
review,
we
believe
the
quantity
of
coating
used
is
the
most
equitable
descriptor
for
purposes
of
defining
the
scope
of
the
category.
Other
descriptors
that
could
have
been
used
but
were
rejected
because
they
would
either
be
too
difficult
to
implement
or
they
are
not
as
equitable
as
coating
usage
include
production
rate,
quantity
of
emissions,
and
solvent
usage.
In
selecting
the
quantity
of
coating
used,
we
found
that
facilities
in
the
source
category
for
which
data
were
available
to
us
reported
annual
coating
usage
of
at
least
100
gallons
per
year.
Those
facilities
that
reported
below
this
amount
used
coatings
to
assist
in
or
repair
minor
defects
during
product
assembly
operations,
and
the
surface
coating
operations
were
not
integral
to
plastic
parts
and
products
surface
coating.
Therefore,
the
MACT
floor
determination
and
the
estimated
environmental,
energy,
cost,
and
economic
impacts
were
based
on
facilities
that
used
greater
than
100
gallons
per
year.
We
are
not
aware
of
any
surface
coating
operation
at
a
major
source
that
is
dedicated
to
plastic
parts
and
products
surface
coating
that
is
using
less
than
100
gallons
per
year
and,
thus,
did
not
evaluate
whether
the
MACT
level
of
control
would
be
appropriate
for
such
operations
if
they
exist.
The
source
category
does
not
include
research
or
laboratory
facilities
or
janitorial,
building,
and
facility
maintenance
operations,
or
hobby
shops
that
are
operated
for
personal
rather
than
commercial
purposes.
The
source
category
also
does
not
include
coating
of
magnet
wire,
coating
of
plastics
to
produce
fiberglass
boats
(
except
the
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Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
post
mold
coating
of
personal
watercraft
or
their
parts),
or
the
extrusion
of
plastic
onto
a
plastic
part
or
product
to
form
a
coating.
These
activities
and
operations
are
not
comparable
to
the
types
and
sizes
of
the
dedicated
facilities
in
terms
of
coating
operations
and
applicable
control
techniques
and
are
regulated
or
are
being
considered
for
regulation
as
part
of
other
source
categories.
Thus,
they
are
not
considered
to
be
within
the
scope
of
the
source
category.
The
postmold
coating
of
personal
watercraft
and
their
parts
is
considered
within
the
scope
of
the
source
category.
The
source
category
also
does
not
include
certain
other
coatings
of
plastic
parts
and
products
that
are
already
being,
or
would
be,
regulated
by
another
NESHAP
as
part
of
a
different
source
category.
We
want
to
avoid
overlap
of
source
categories
where
coating
of
the
same
part
would
be
subject
to
multiple
rules.
Subcategory
Selection.
The
statute
gives
us
discretion
to
determine
if
and
how
to
subcategorize.
Once
the
floor
has
been
determined
for
new
or
reconstructed
and
existing
affected
sources
for
a
source
category
or
subcategory,
we
must
set
MACT
standards
that
are
no
less
stringent
than
the
MACT
floor.
Such
standards
must
then
be
met
by
all
sources
within
the
source
category
or
subcategory.
A
subcategory
is
a
group
of
similar
sources
within
a
given
source
category.
As
part
of
the
regulatory
development
process,
we
evaluate
the
similarities
and
differences
between
industry
segments
or
groups
of
facilities
comprising
a
source
category.
In
establishing
subcategories,
we
consider
factors
such
as
process
operations
(
type
of
process,
raw
materials,
chemistry/
formulation
data,
associated
equipment,
and
final
products);
emission
characteristics
(
amount
and
type
of
HAP);
control
device
applicability;
and
opportunities
for
pollution
prevention.
We
may
also
consider
existing
regulations
or
guidance
from
States
and
other
regulatory
agencies
in
determining
subcategories.
After
reviewing
survey
responses
from
the
industry,
facility
site
visit
reports,
and
information
received
from
stakeholders
meetings,
we
found
that
the
plastic
parts
and
products
surface
coating
industry
could
be
grouped
into
four
subcategories:
(
1)
General
use
coating,
(
2)
TPO
coating,
(
3)
headlamp
coating,
and
(
4)
assembled
on
road
vehicle
coating.
The
general
use
coating
subcategory
includes
all
plastic
parts
and
products
coating
operations
except
TPO,
headlamp,
and
assembled
on
road
vehicle
coating.
This
includes
operations
that
coat
a
wide
variety
of
substrates,
surfaces,
and
types
of
plastic
parts,
as
well
as
more
specialized
coating
scenarios.
Each
of
the
subcategories
includes
coating
operations,
including
associated
surface
preparation,
equipment
cleaning,
mixing
and
storage,
and
waste
handling.
The
TPO
coating
is
considered
a
separate
subcategory
from
other
plastic
parts
and
products
coating
operations
because
the
surface
coating
of
TPO
substrates
requires
the
use
of
an
adhesion
promoter
in
order
to
apply
subsequent
coatings
to
the
substrate.
The
adhesion
promoters
required
in
TPO
coating
operations
contain
significant
levels
of
organic
HAP
because
these
materials
contain
organic
HAP
solvents
that
are
capable
of
wetting
the
TPO
substrate
and
swelling
the
rubber
content
of
the
substrate.
Wetting
of
the
substrate
requires
a
solvent
in
the
adhesion
promoter
that
spreads
out
over
the
substrate,
and
this
is
dictated
by
the
surface
tension
of
the
substrate
and
the
solvent.
The
surface
tensions
of
organic
HAP
solvents
such
as
toluene,
xylene,
and
other
aromatics
are
ideal
for
wetting
TPO
while
other
non
HAP
solvents
have
surface
tensions
too
high
to
allow
the
adhesion
promoter
to
spread
out
over
the
TPO
part.
In
conjunction
with
adequate
wetting
of
the
TPO,
the
solvents
in
the
adhesion
promoter
must
be
capable
of
migrating
through
the
surface
of
the
TPO
substrate
to
swell
the
rubber
content
(
elastomer)
in
the
TPO.
It
is
this
optimum
swelling
of
the
rubber
content
in
the
TPO
and
the
subsequent
entanglement
of
the
elastomer
with
the
paint
that
provides
the
adhesion
necessary
to
coat
TPO
successfully.
Many
non
HAP
solvents
either
evaporate
too
quickly
to
adequately
migrate
through
and
swell
the
rubber
or
the
solvents
swell
the
rubber
content
of
the
TPO
to
the
point
of
distortion
of
the
part.
Therefore,
the
adhesion
promoters
used
in
TPO
coating
operations
often
contain
high
levels
of
organic
HAP
solvents
to
achieve
adequate
wetting
of
the
substrate,
swelling
of
the
rubber,
and
ultimately,
adhesion
of
the
paint
to
the
substrate.
The
need
to
use
these
HAP
containing
materials
would
make
it
technically
difficult
for
existing
facilities
coating
TPO
to
achieve
the
lower
emission
rates
established
by
facilities
that
do
not
coat
TPO.
In
summary,
the
technical
differences
in
the
type
of
coatings
required
due
to
the
nature
of
the
TPO
substrate
warrant
a
separate
subcategory
for
TPO
coating.
Headlamp
coating
is
considered
as
a
separate
subcategory
because
these
coating
operations
require
specialized
reflective
argent
coatings
and
hard
clear
coatings
to
meet
U.
S.
Department
of
Transportation
Motor
Vehicle
Safety
Standards
for
reflectivity,
brightness,
color,
and
other
performance
criteria.
The
reflective
argent
coatings
often
used
in
automotive
headlamp
coating
operations
contain
significant
levels
of
organic
HAP
because
these
coatings
achieve
the
required
reflective
aluminum
appearance
with
aluminum
pigments
contained
in
the
coating.
These
coatings
require
the
use
of
aromatic
or
aliphatic
HAP
solvents
in
order
to
allow
the
aluminum
pigments
to
rise
to
the
surface
correctly
to
create
the
reflective
finish
required
by
Federal
safety
standards.
The
hard
clear
coatings
often
used
in
automotive
headlamp
coating
operations,
such
as
the
thermal
cure
and
silicone
hardcoat
technologies,
are
required
to
provide
the
polycarbonate
headlamp
substrate
with
necessary
abrasion
and
scratch
resistance.
Polycarbonate
is
currently
the
only
plastic
substrate
approved
by
the
National
Highway
Traffic
Safety
Administration
for
use
in
automotive
headlamps
because
this
material
is
shatter
resistant
and
resists
high
levels
of
heat.
The
hard
clear
coatings
used
on
the
polycarbonate
headlamps
require
the
use
of
certain
organic
HAP
solvents,
such
as
butyl
cellosolve,
in
these
coatings
to
avoid
etching
of
the
substrate
surface.
Other
non
HAP
solvents
can
etch
the
surface
of
the
polycarbonate
which
would
deflect
light
and
create
performance
and
safety
concerns
for
the
final
headlamp
product.
The
need
to
use
these
materials
would
make
it
technically
difficult
for
existing
facilities
coating
automotive
headlamps
to
achieve
the
lower
emission
rates
established
by
facilities
that
do
not
coat
headlamps.
In
summary,
technical
differences
in
the
type
of
coatings
required
to
meet
unique
end
product
requirements
warrant
a
separate
subcategory
for
headlamp
coating.
Assembled
on
road
vehicle
coating
is
considered
a
separate
subcategory
because
these
coating
operations
are
performed
on
fully
assembled
vehicles
that
may
contain
heat
sensitive
parts.
In
addition,
fully
assembled
on
road
vehicles
are
physically
larger
than
the
other
parts
and
products
coated
in
this
source
category.
The
large
size
and
presence
of
heat
sensitive
parts
make
certain
lower
HAP
technologies,
such
as
heat
cured
waterborne
coatings,
not
feasible
for
use
on
fully
assembled
onroad
vehicles
and
make
it
technically
difficult
for
these
sources
to
achieve
the
same
emission
level
as
sources
that
do
not
coat
assembled
on
road
vehicles.
The
problems
associated
with
coating
of
assembled
on
road
vehicles
were
first
raised
by
recreational
vehicle
manufacturers
that
build
motor
homes
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Federal
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
and
travel
trailers.
The
EPA
recognized
that
the
same
problems
(
i.
e.,
large
part
size
and
heat
sensitive
components)
would
be
encountered
by
other
facilities
that
coat
plastic
bodies
on
other
types
of
assembled
on
road
vehicles.
In
addition,
some
facilities
coat
a
mix
of
assembled
on
road
vehicles
including
automobiles,
recreational
vehicles,
public
transportation
vehicles,
and
fleet
trucks.
Therefore,
EPA
decided
to
include
all
of
these
in
the
assembled
onroad
vehicle
subcategory
and
not
limit
the
subcategory
to
just
recreational
vehicles.
The
on
road
vehicle
subcategory
is
limited
to
only
surface
coating
on
fully
assembled
on
road
vehicles
in
order
to
avoid
an
overlap
with
source
categories
that
include
assembly
line
coating
operations
at
automobile,
light
duty
truck,
and
heavyduty
truck
manufacturing
facilities.
The
EPA
also
recognizes
that
most
assembled
on
road
vehicles
are
a
mix
of
plastic
and
metal
body
components.
An
assembled
on
road
vehicle
coating
operation
is
considered
part
of
this
subcategory
if
greater
than
50
percent
of
the
surface
being
coated
on
a
vehicle
is
plastic.
B.
How
Did
We
Select
the
Regulated
Pollutants?
Available
emission
data
collected
during
the
development
of
the
proposed
NESHAP
show
that
the
primary
organic
HAP
emitted
from
the
surface
coating
of
plastic
parts
and
products
include
MEK,
MIBK,
toluene,
and
xylenes.
These
compounds
account
for
more
than
85
percent
of
this
category's
nationwide
organic
HAP
emissions.
Other
organic
HAP
emissions
include
EGBE
and
other
glycol
ethers.
However,
many
other
organic
HAP
are
used,
or
can
be
used,
in
coatings,
thinners,
and
cleaning
materials.
Therefore,
the
proposed
rule
would
regulate
emissions
of
all
organic
HAP.
Although
most
of
the
coatings
used
in
this
source
category
do
not
contain
inorganic
HAP,
a
few
special
purpose
coatings
used
by
a
few
facilities
in
this
source
category
contain
inorganic
HAP
such
as
chromium
and
lead.
No
inorganic
HAP
were
reported
in
cleaning
materials.
If
coatings
are
applied
by
spraying,
inorganic
HAP
components
remain
as
solids
in
the
dry
coating
film
on
the
parts
being
coated
or
are
deposited
onto
the
walls,
floor,
and
grates
of
the
spray
booths
in
which
they
are
applied.
Some
of
the
inorganic
HAP
particles
would
be
entrained
in
the
spray
booth
exhaust
air.
Although
these
emissions
have
not
been
quantified,
we
believe
that
the
inorganic
HAP
emission
levels
are
very
low.
Furthermore,
emissions
of
these
materials
to
the
atmosphere
are
minimal
because
very
few
of
the
facilities
in
this
source
category
use
spray
application
techniques
to
apply
coatings
that
contain
inorganic
HAP
compounds.
At
this
time,
it
does
not
appear
that
emissions
of
inorganic
HAP
from
this
source
category
warrant
Federal
regulation.
C.
How
Did
We
Select
the
Affected
Source?
In
selecting
the
affected
source(
s)
for
emission
standards,
our
primary
goal
is
to
ensure
that
MACT
is
applied
to
HAPemitting
operations
or
activities
within
the
source
category
being
regulated.
The
affected
source
also
serves
to
establish
where
new
source
MACT
applies
under
a
particular
standard.
Specifically,
the
General
Provisions
in
subpart
A
of
40
CFR
part
63
define
the
terms
``
construction''
and
``
reconstruction''
with
reference
to
the
term
``
affected
source''
(
40
CFR
63.2)
and
provide
that
new
source
MACT
applies
when
construction
or
reconstruction
of
an
affected
source
occurs
(
40
CFR
63.5).
The
collection
of
equipment
and
activities
evaluated
in
determining
MACT
(
including
the
MACT
floor)
is
used
in
defining
the
affected
source.
When
emission
standards
are
based
on
a
collection
of
emissions
sources
or
total
facility
emissions,
we
select
an
affected
source
based
on
that
same
collection
of
emission
sources
or
the
total
facility
as
well.
This
approach
for
defining
the
affected
source
broadly
is
particularly
appropriate
for
industries
where
a
single
emission
standard
encompassing
multiple
emission
points
within
the
plant
provides
the
opportunity
and
incentive
for
owners
and
operators
to
utilize
control
strategies
that
are
more
cost
effective
than
if
separate
standards
were
established
for
each
emission
point
within
a
facility.
The
affected
source
for
these
proposed
standards
is
broadly
defined
to
include
all
operations
associated
with
the
coating
of
plastic
parts
and
products
and
the
cleaning
of
products,
substrates
or
coating
operation
equipment
in
a
subcategory
(
i.
e.,
TPO
coating,
headlamp
coating,
assembled
on
road
vehicle
coating,
or
general
use
coating).
These
operations
include
storage
and
mixing
of
coatings
and
other
materials;
surface
preparation
of
the
plastic
parts
and
products
prior
to
coating
application;
coating
application
and
flash
off,
drying
and
curing
of
applied
coatings;
cleaning
operations;
and
waste
handling
operations.
A
few
facilities
have
coating
operations
in
more
than
one
subcategory.
For
example,
a
few
facilities
have
TPO
coating
operations
that
are
in
the
TPO
coating
subcategory
and
also
have
other
plastic
parts
and
products
coating
operations
that
are
in
the
general
use
coating
subcategory.
In
such
a
case,
the
facility
would
have
two
separate
affected
sources:
(
1)
The
collection
of
all
operations
associated
with
the
surface
coating
of
TPO,
and
(
2)
the
collection
of
all
operations
associated
with
general
use
coating.
Each
of
these
affected
sources
would
be
required
to
meet
the
emission
limits
that
apply
to
its
subcategory.
In
selecting
the
affected
source,
we
considered,
for
each
operation,
the
extent
to
which
HAP
containing
materials
are
used
and
the
amount
of
HAP
that
are
emitted.
Cleaning
and
coating
application,
flash
off,
and
curing/
drying
operations
account
for
the
majority
of
HAP
emissions
at
plastic
parts
and
products
surface
coating
operations.
These
operations
are
included
in
the
affected
source.
Mixing,
storage,
and
waste
handling
operations
are
included
in
the
affected
source.
Because
we
are
assuming
that
all
the
organic
HAP
in
the
materials
entering
the
affected
source
are
volatilized
(
emitted),
emissions
from
operations
occurring
within
the
affected
source
(
e.
g.,
mixing
operations
and
storage)
are
accounted
for
in
the
estimate
of
total
materials
usage
at
the
affected
source.
A
broad
definition
of
the
affected
source
was
selected
to
provide
maximum
flexibility
in
complying
with
the
proposed
emission
limits
for
organic
HAP.
In
planning
its
compliance,
each
facility
can
select
among
available
coatings,
thinners
and
other
additives,
and
cleaning
materials,
as
well
as
the
use
of
emissions
capture
and
add
on
control
systems,
to
comply
with
the
emission
limits
for
each
subcategory
in
the
most
cost
effective
manner.
Additional
information
on
the
plastic
parts
and
products
surface
coating
operations
selected
for
regulation,
and
other
operations,
are
included
in
the
docket
for
the
proposed
standards.
D.
How
Did
We
Determine
the
Basis
and
Level
of
the
Proposed
Standards
for
Existing
and
New
Sources?
The
MACT
floor
analysis
was
performed
using
a
sourcewide
emission
rate
approach
for
each
of
the
four
subcategories:
(
1)
General
use
coating,
(
2)
TPO
coating,
(
3)
headlamp
coating,
and
(
4)
assembled
on
road
vehicle
coating.
Because
organic
HAP
emissions
from
an
affected
source
are
directly
related
to
the
materials
used,
and
since
it
is
very
difficult
to
estimate
the
emissions
that
occur
in
any
one
area
within
the
affected
source,
an
emission
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Federal
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
rate
approach
for
affected
sources
in
each
subcategory
is
the
most
feasible
way
to
determine
emission
limits.
The
emission
rate
approach
covers
the
emissions
from
all
areas
within
the
affected
source
for
each
subcategory,
including
the
application
and
curing
process,
equipment
cleaning
and
surface
preparation
operations,
mixing
and
storage
of
organic
HAP
materials,
and
waste
handling.
The
broad
emission
rate
approach
will
allow
for
the
maximum
flexibility
for
those
affected
sources
in
the
general
use
coating
subcategory
that
perform
many
different
types
of
coating
applications
and
coat
many
different
types
of
parts
during
a
given
year.
It
would
be
very
difficult
to
define
and
set
limits
on
each
individual
coating
step
within
every
coating
process.
Also,
such
rules
would
allow
no
flexibility
and
might
not
be
technically
feasible
for
every
source.
An
emission
limit
that
includes
all
coating
operations
within
an
affected
source
allows
an
owner/
operator
to
determine
how
to
most
efficiently
and
cost
effectively
meet
the
emission
limit
for
each
subcategory.
To
determine
the
existing
and
new
source
MACT
floor
for
each
subcategory,
we
determined
the
organic
HAP
emission
rate
for
each
facility
in
units
of
kg
(
lb)
organic
HAP
emitted
per
kg
(
lb)
of
coating
solids
used
for
each
subcategory.
We
then
ranked
the
sources
in
each
subcategory
from
lowest
to
highest
emission
rate
to
identify
the
best
performing
sources.
We
used
information
obtained
from
industry
survey
responses
and
subsequent
changes
and
clarifications
received
from
the
facilities
to
estimate
the
sourcewide
organic
HAP
emission
rate
from
each
survey
respondent.
In
the
relatively
few
cases
where
a
facility
had
coating
operations
in
more
than
one
subcategory
(
e.
g.,
a
TPO
coating
operation,
headlamp
coating
operation,
or
assembled
on
road
vehicle
coating
operation,
and
a
general
use
coating
operation),
we
calculated
the
organic
HAP
emission
rate
for
each
subcategory
separately.
For
facilities
that
reported
no
add
on
control
devices,
we
calculated
total
organic
HAP
emissions
by
assuming
that
the
organic
HAP
components
in
all
coatings,
thinners
and
other
additives,
and
cleaning
materials
are
emitted.
If
add
on
control
devices
were
reported,
their
capture
and
control
efficiencies
were
taken
into
account.
Sources
included
in
the
population
for
determining
the
MACT
floor
emission
limits
were
those
facilities
that
are
identified
as
major
sources
based
on
their
potential
to
emit,
and
those
that
were
identified
as
``
synthetic
minor''
sources.
For
each
of
the
four
subcategories,
the
best
performing
12
percent
of
sources
(
or
the
best
five
sources)
were
the
sources
with
the
lowest
calculated
organic
HAP
emission
rates.
The
average,
or
arithmetic
mean,
of
the
bestperforming
12
percent
of
sources
(
or
best
five
sources)
was
calculated
to
determine
the
MACT
floor
level
for
each
subcategory.
For
the
general
use
coating
subcategory,
the
average
of
the
bestperforming
12
percent
of
existing
sources
was
determined
to
be
0.16
kg
(
0.16
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used.
For
the
TPO
coating
subcategory,
the
average
of
the
bestperforming
five
existing
sources
was
0.23
kg
(
0.23
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used.
For
the
headlamp
coating
subcategory,
the
average
of
the
best
performing
five
existing
sources
was
0.45
kg
(
0.45
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used.
For
the
assembled
on
road
vehicle
coating
subcategory,
the
average
of
the
best
performing
five
existing
sources
was
1.34
kg
(
1.34
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used.
The
facilities
represented
by
the
average
MACT
floor
emission
level
for
each
of
the
subcategories
were
reviewed
to
assess
the
achievability
of
the
emission
levels
for
the
range
of
sources
in
the
subcategory.
The
parameters
that
were
considered
in
the
review
included
coating
types
and
technologies,
application
methods,
curing
temperatures,
substrates,
regulatory
and
performance
specifications,
location
by
state,
part
types,
industry
sectors
and
amounts
of
materials
used.
The
review
resulted
in
the
determination
that
there
were
no
differences
in
the
ability
of
sources
within
a
given
subcategory
to
achieve
the
existing
source
MACT
floor
emission
levels,
and
therefore,
it
appears
that
all
sources
could
achieve
the
existing
source
MACT
floor
emission
rate
for
their
subcategory.
The
MACT
floor
memorandum
in
the
docket
includes
additional
details
of
our
review.
We
request
comment
on
the
analysis
and
our
conclusions.
The
new
source
MACT
floor
level
for
the
general
use
coating
subcategory
was
determined
to
be
the
same
as
the
MACT
floor
level
for
existing
sources.
For
the
general
use
coating
subcategory,
the
facilities
whose
emission
rates
were
lower
than
the
existing
source
floor
(
0.16
kg
(
0.16
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used)
were
evaluated
to
determine
whether
one
of
them
could
be
considered
the
bestperforming
similar
source
and
represent
the
diversity
of
operations
included
in
the
subcategory.
We
evaluated
whether
a
single
source
with
a
lower
emission
rate
was
sufficiently
similar
to
all
other
operations
in
the
subcategory
in
terms
of
parts
coated,
coating
types,
and
application
methods
used.
No
single
source
with
an
emission
rate
lower
than
the
existing
source
MACT
floor
emission
rate
represented
the
full
range
of
variability
in
the
subcategory.
For
example,
some
of
the
facilities
with
the
lowest
emission
rates
used
only
one
or
two
types
of
coatings
with
a
narrow
range
of
types
of
parts
and
coating
application
methods.
Because
a
new
facility
might
need
to
use
a
variety
of
coating
types
and
technologies,
we
rejected
facilities
using
only
one
or
two
types
of
coatings
with
a
limited
range
of
coated
parts
and
application
methods
as
similar
sources
for
the
purpose
of
setting
a
floor
for
new
sources.
Therefore,
the
new
source
MACT
floor
is
determined
to
be
the
same
as
the
MACT
floor
for
existing
sources.
You
may
refer
to
the
MACT
floor
memorandum
in
the
docket
for
additional
details.
The
new
source
MACT
floor
levels
for
the
TPO
coating
and
headlamp
coating
subcategories
are
more
stringent
than
the
existing
source
MACT
floor
levels
for
these
subcategories.
For
the
TPO
coating
subcategory,
the
best
performing
single
source
achieves
an
emission
level
of
0.17
kg
(
0.17
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used.
The
facility
is
using
a
waterborne
TPO
coating
process.
Available
information
indicates
that
waterborne
coatings
are
feasible
for
TPO
substrates,
including
TPO
used
in
external
parts
such
as
bumpers,
and
can
meet
performance
specifications
for
the
coated
parts.
When
designing
a
new
source,
it
would
be
feasible
to
design
the
TPO
coating
operations
to
use
a
waterborne
coating
process,
or
otherwise
control
emissions
to
achieve
the
emission
level
of
the
bestperforming
individual
source
in
this
subcategory.
Therefore,
the
MACT
floor
for
new
sources
in
the
TPO
subcategory
is
determined
to
be
0.17
kg
(
0.17
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used.
For
the
headlamp
coating
subcategory,
the
identification
of
bestperforming
similar
source
was
conducted
by
reviewing
the
emission
rates
for
existing
headlamp
coating
sources,
excluding
any
organic
HAP
and
solids
from
adhesives
that
are
used
in
these
operations.
The
two
bestperforming
headlamp
coating
sources
both
use
low
HAP,
high
solids
adhesives
in
the
headlamp
operation
to
do
final
assembly
of
the
headlamp.
While
the
use
of
these
adhesives
is
representative
of
the
operations
at
these
existing
sources,
it
is
unclear
whether
new
sources
in
the
headlamp
coating
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/
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2002
/
Proposed
Rules
subcategory
would
be
performing
final
assembly
of
the
headlamps
or
would
only
be
coating
one
component
of
the
headlamp
body.
The
use
of
adhesives
in
headlamp
coating
operations
is
purely
dependent
upon
individual
customer
needs
and
business
decisions
on
whether
to
assemble
the
headlamps
at
the
same
site.
New
headlamp
sources
with
lower
emission
rates
that
include
adhesives
do
not
represent
a
similar
source
that
would
establish
a
new
source
level
for
the
range
of
new
sources
in
the
subcategory.
The
two
bestperforming
similar
sources
in
the
headlamp
subcategory
achieve
emission
rates
(
excluding
adhesives)
of
0.034
kg
(
0.034
lb)
HAP
emitted
per
kg
(
lb)
coating
solids
used
and
0.26
kg
(
0.26
lb)
HAP
emitted
per
kg
(
lb)
coating
solids
used.
The
source
that
is
achieving
the
emission
rate
of
0.034
kg
(
0.034
lb)
HAP
emitted
per
kg
(
lb)
coating
solids
used
has
total
enclosures
and
add
on
control
devices
on
a
portion
of
its
headlamp
coating
operation.
It
is
uncertain
whether
other
new
headlamp
coating
sources
would
be
able
to
use
enclosures
and
add
on
control
devices
and
achieve
this
emission
rate.
Typical
organics
stream
concentrations
estimated
for
sources
in
this
subcategory
are
generally
too
low
to
make
the
use
of
enclosures
and
control
devices
technically
feasible.
However,
the
source
that
is
achieving
the
emission
rate
of
0.26
kg
(
0.26
lb)
HAP
emitted
per
kg
(
lb)
coating
solids
used
coats
automotive
headlamps
using
low
HAP,
ultra
violet
(
UV)
cure
clearcoat
technology
and
low
HAP,
vacuum
metallizing
technology
on
polycarbonate
substrate.
Although
this
emission
rate
is
not
achievable
for
existing
sources
that
do
not
currently
have
the
capability
to
use
UV
cure
clearcoat
technology
or
vacuum
metallizing
technology,
it
would
be
feasible
to
design
a
new
headlamp
coating
process
to
use
similar
low
HAP,
UV
cure
clearcoats
and
low
HAP,
vacuum
metallizing
technology,
or
otherwise
control
emissions
to
achieve
the
emission
level
of
this
bestperforming
similar
source
in
the
headlamp
subcategory.
Therefore,
the
MACT
floor
for
new
sources
in
the
headlamp
coating
subcategory
is
determined
to
be
0.26
kg
(
0.26
lb)
HAP
emitted
per
kg
(
lb)
coating
solids
used.
The
new
source
MACT
floor
level
for
the
assembled
on
road
vehicle
coating
subcategory
was
determined
to
be
the
same
as
the
MACT
floor
level
for
existing
sources.
For
this
coating
subcategory,
the
facilities
whose
emission
rates
were
lower
than
the
existing
source
floor
(
1.34
kg
(
1.34
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used)
were
evaluated
to
determine
whether
one
of
them
could
be
considered
the
best
performing
similar
source
(
and
sufficiently
representative
of
the
diversity
of
operations
encompassing
the
subcategory).
Some
of
the
variables
considered
were
the
types
of
vehicles
coated
(
e.
g.,
motorhomes
or
towable
RVs),
the
amount
of
the
vehicle
coated
(
either
fully
painted
or
only
partially
painted),
whether
multiple
colors
of
basecoat
were
used
and
the
overall
ratio
of
basecoat
to
clearcoat,
and
whether
or
not
repair
coating
operations
were
performed.
Given
the
diversity
of
assembled
on
road
vehicle
coating
operations
observed
during
EPA
site
visits
and
among
the
facilities
present
in
the
MACT
database,
EPA
has
determined
that
the
sources
with
emission
rates
lower
than
the
existing
source
MACT
floor
emission
rate
are
not
representative
of
the
possible
range
of
new
sources
in
the
subcategory.
For
example,
some
facilities
may
use
only
a
single
color
of
basecoat
per
vehicle,
while
others
may
use
up
to
four
colors
of
basecoat
in
more
elaborate
color
schemes.
Some
facilities
may
apply
a
single
layer
of
clearcoat
while
others
may
apply
two
or
three
layers
for
a
more
durable
finish.
Additionally,
some
facilities
may
perform
a
combination
of
these
during
a
single
compliance
period.
Given
the
variability
in
these
factors,
EPA
does
not
believe
that
any
single
source
with
a
lower
emission
rate
than
the
existing
source
floor
represents
a
similar
source
for
the
full
range
of
variability
for
this
subcategory.
Therefore,
the
new
source
MACT
floor
is
determined
to
be
the
same
as
the
MACT
floor
for
existing
sources.
After
the
MACT
floors
have
been
determined
for
new
and
existing
sources
in
a
source
category
or
subcategory,
we
must
set
emission
standards
that
are
technically
achievable
and
no
less
stringent
than
the
floors.
Such
standards
must
then
be
met
by
all
sources
within
the
category
or
subcategory.
We
identify
and
consider
any
reasonable
regulatory
alternatives
that
are
``
beyond
the
floor,''
taking
into
account
emissions
reductions,
cost,
non
air
quality
health
and
environmental
impacts,
and
energy
requirements.
These
alternatives
may
be
different
for
new
and
existing
sources
because
of
different
MACT
floors,
and
separate
standards
may
be
established
for
new
and
existing
sources.
No
options
beyond
the
MACT
floor
could
be
identified
for
the
general
use
coating
subcategory
that
would
be
technically
feasible
for
all
new
or
existing
facilities
in
the
subcategory.
For
the
TPO
coating
subcategory,
the
use
of
a
waterborne
coating
technology
was
identified
as
a
beyond
the
floor
option
for
existing
sources
to
be
considered.
There
are
currently
at
least
two
existing
sources
that
coat
TPO
using
waterborne
adhesion
promoters
and
other
coatings,
and
the
new
source
MACT
floor
(
0.17
kg
(
0.17
lb)
HAP
emitted
per
kg
(
lb)
coating
solids
used)
is
based
on
a
facility
using
the
waterborne
TPO
coating
process.
We
considered
the
beyond
the
floor
option
of
requiring
other
existing
sources
coating
TPO
to
switch
their
TPO
coating
operations
to
the
waterborne
process.
However,
requiring
existing
sources
to
switch
to
waterborne
coating
technology
would
require
many
costly
retrofits
to
an
existing
TPO
coating
operation,
including
the
addition
of
special
pretreatment
steps
prior
to
coating
application,
the
installation
of
curing
ovens
that
aren't
currently
available
at
all
existing
TPO
facilities,
a
lengthening
of
the
coating
line
to
allow
for
increased
drying/
flash
off
time
required
for
waterborne
coatings,
and
a
switch
to
stainless
steel
spray
guns
and
lines
to
prevent
corrosion
of
equipment.
Information
from
an
existing
TPO
source
that
retrofitted
its
existing
coating
lines
to
allow
for
waterborne
TPO
coating
indicates
that
their
cost
to
switch
to
waterborne
coating
was
approximately
$
9
million.
The
HAP
emissions
reductions
that
would
be
achieved
by
a
typical
existing
source
complying
with
the
MACT
floor
for
TPO
coating
sources
would
be
approximately
75
percent
reduction.
If
the
same
typical
existing
source
achieved
the
beyond
the
floor
level
of
0.17
kg
(
0.17
lb)
HAP
emitted
per
kg
(
lb)
coating
solids
used,
it
would
achieve
approximately
an
additional
7
percent
emission
reduction.
Without
having
information
on
the
benefits
that
would
be
achieved
by
further
reducing
emissions
beyond
thefloor
we
do
not
believe
the
additional
cost
of
going
beyond
the
floor
is
warranted
at
this
time
without
a
further
evaluation
of
risk.
Therefore,
we
are
not
requiring
beyond
the
floor
levels
of
emissions
reductions
at
this
time.
After
implementation
of
these
standards,
we
will
evaluate
the
remaining
health
and
environmental
risks
that
may
be
posed
as
a
result
of
exposure
to
emissions
from
the
plastic
parts
and
products
surface
coating
source
category.
At
that
time,
we
will
determine
whether
the
additional
costs
are
warranted
in
light
of
the
available
risk
information.
For
the
headlamp
coating
subcategory,
we
considered
two
low
HAP
technologies
as
beyond
the
floor
options
for
existing
sources.
These
technologies
are
UV
cure
clearcoat
and
vacuum
metallizing.
There
are
currently
two
existing
sources
that
use
UV
cure
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
clearcoats
and
one
existing
source
that
uses
vacuum
metallizing
to
obtain
the
necessary
reflectivity
for
the
headlamps.
The
new
source
MACT
floor
for
headlamp
coating
(
0.26
kg
(
0.26
lb)
HAP
emitted
per
kg
(
lb)
coating
solids
used)
is
based
on
a
facility
using
both
technologies
to
coat
automotive
headlamps.
We
considered
the
beyond
the
floor
option
of
requiring
other
existing
sources
to
switch
their
coating
operations
to
either
of
these
low
HAP
technologies.
However,
based
on
industry
information,
requiring
existing
sources
to
switch
to
UV
cure
clearcoats
or
vacuum
metallizing
could
require
costly
retrofits
to
an
existing
headlamp
coating
operation.
The
switch
to
UVcure
clearcoat
technology
could
require
extensive
modifications
to
coating
line
design
as
well
as
the
installation
of
UVlamps
to
cure
the
coatings.
Furthermore,
since
UV
cure
processes
do
not
have
production
capacities
as
high
as
thermal
cure
clearcoat
processes,
existing
sources
could
be
required
to
build
additional
coating
lines
to
maintain
the
same
production
capacity,
and
this
would
require
more
floor
space.
The
switch
to
vacuum
metallizing
from
liquid
argent
coatings
could
require
extensive
modifications
to
the
coating
line
design
and
raw
materials
used,
as
well
as
the
purchase
and
installation
of
vacuum
metallizing
equipment.
A
single
vacuum
metallizing
chamber
can
produce
approximately
500,000
headlamp
lens
bodies
a
year
and
could
cost
approximately
$
2
million
per
chamber.
Many
sources
could
need
multiple
chambers.
In
addition
to
the
purchase
and
installation
of
vacuum
metallizing
chambers,
existing
sources
would
need
to
purchase
more
expensive
raw
plastic
materials
(
i.
e.,
thermoplastics)
in
order
to
achieve
the
beyond
the
floor
level
of
0.26
kg
(
0.26
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used.
Vacuum
metallizing
requires
an
absolutely
smooth
surface
for
proper
reflectivity,
and
this
can
be
achieved
with
thermoplastics.
Less
expensive
thermoset
plastics
that
can
be
used
in
liquid
argent
coating
processes
do
not
produce
the
necessary
surface
to
vacuum
metallize,
without
a
pre
coating
step
that
would
result
in
additional
HAP
emissions.
For
an
existing
facility
to
switch
to
vacuum
metallizing
from
liquid
argent
coating
without
adding
a
pre
coating
step,
the
cost
of
thermoplastic
raw
materials
could
be
three
times
the
cost
of
thermoset
materials.
Therefore,
assuming
existing
headlamp
coating
sources
would
require
at
least
two
vacuum
metallizing
chambers
and
a
switch
to
thermoplastic
raw
materials,
retrofitting
an
existing
headlamp
source
could
result
in
capital
costs
of
at
least
$
4
million
for
the
metallizing
chambers
and
an
annual
material
purchase
cost
of
three
times
current
annual
material
costs.
These
costs
do
not
account
for
additional
process
line
modifications,
oven
replacements,
and
testing
requirements
that
will
vary
in
cost
from
source
to
source.
The
HAP
emission
reductions
that
would
be
achieved
by
a
typical
existing
source
complying
with
the
MACT
floor
for
headlamp
coating
sources
would
be
approximately
78
percent
reduction.
The
incremental
emission
reduction
that
would
be
achieved
for
the
same
typical
source
to
reduce
its
emissions
to
the
beyond
the
floor
level
would
be
approximately
9
percent.
Without
having
information
on
the
benefits
that
would
be
achieved
by
further
reducing
emissions
beyond
the
floor,
we
do
not
believe
the
additional
cost
of
going
beyond
the
floor
is
warranted
at
this
time
without
a
further
evaluation
of
risk.
Therefore,
we
are
not
requiring
beyond
the
floor
levels
of
emission
reductions
at
this
time.
After
implementation
of
these
standards,
we
will
evaluate
the
remaining
health
and
environmental
risks
that
may
be
posed
as
a
result
of
exposure
to
emissions
from
the
plastic
parts
and
products
surface
coating
source
category.
At
that
time,
we
will
determine
whether
the
additional
costs
are
warranted
in
light
of
the
available
risk
information.
No
options
beyond
the
MACT
floor
could
be
identified
for
the
assembled
on
road
vehicle
coating
subcategory
that
would
be
technically
feasible
for
all
new
or
existing
facilities
in
the
subcategory.
Add
on
controls
were
also
reviewed
to
determine
if
a
facility
using
add
on
controls
would
represent
a
technically
feasible
beyond
the
floor
option
for
all
new
or
existing
sources
in
any
of
the
four
subcategories.
Add
on
controls
are
used
at
a
few
individual
facilities
in
the
plastic
parts
and
products
surface
coating
source
category
and
three
of
its
four
subcategories.
No
add
on
controls
are
used
in
the
assembled
off
road
vehicle
subcategory.
However,
based
on
typical
organics
stream
concentrations
estimated
for
typical
facilities
in
the
four
subcategories,
add
on
control
techniques
are
generally
not
technically
feasible.
Therefore,
add
on
control
techniques
were
not
considered
as
a
beyond
the
floor
option.
For
existing
sources,
we
based
the
proposed
standards
on
the
existing
source
MACT
floors
for
each
of
the
four
subcategories.
As
described
earlier,
we
determined
that
beyond
the
floor
options
were
not
technically
or
economically
feasible
for
all
existing
sources.
For
the
same
reasons,
we
based
the
proposed
standards
for
new
sources
on
the
new
source
MACT
floor.
The
MACT
levels
of
control
for
new
and
existing
sources
can
be
achieved
in
several
different
ways.
Many
sources
would
be
able
to
use
lower
HAP
coatings,
although
they
may
not
be
available
to
meet
the
needs
of
every
source.
If
a
source
is
also
using
cleaning
materials
that
contain
organic
HAP,
then
it
may
be
able
to
switch
to
lower
HAP
or
non
HAP
cleaning
materials,
which
are
widely
available,
to
reduce
the
sourcewide
organic
HAP
emissions
rate
to
the
MACT
level.
Other
available
options
might
be
the
use
of
capture
systems
and
add
on
control
devices
to
reduce
emissions.
We
note
here
that
our
assumption,
used
in
the
development
of
the
MACT
floors,
that
100
percent
of
the
organic
HAP
in
the
materials
used
are
emitted
by
the
affected
source
would
not
apply
when
the
source
sends
organic
HAPcontaining
waste
materials
to
a
facility
for
treatment
or
disposal.
We
made
that
assumption
because
the
industry
survey
responses
provided
little
information
as
to
the
amount
of
organic
HAP
recovered
and
recycled
or
treated
and
disposed.
We,
therefore,
concluded
that
offsite
or
onsite
treatment
and
disposal
may
not
be
common
within
the
plastic
parts
and
products
surface
coating
industry.
We
recognize,
however,
that
some
facilities
may
conduct
such
activities
and
should
be
allowed
to
account
for
such
activities
in
determining
their
emissions.
Thus,
the
proposed
rule
allows
you
to
reduce
the
organic
HAP
emissions
by
the
amount
of
any
organic
HAP
contained
in
waste
treated
or
disposed
at
a
hazardous
waste
treatment,
storage,
and
disposal
facility
that
is
regulated
under
40
CFR
part
262,
264,
265,
or
266.
E.
How
Did
We
Select
the
Format
of
the
Proposed
Standards?
We
selected
the
format
of
the
proposed
standards
to
be
an
emission
rate
expressed
in
terms
of
the
mass
of
organic
HAP
emitted
per
mass
of
coating
solids
used.
The
emission
rate
format
would
allow
plastic
parts
and
products
surface
coating
operation
owners
and
operators
flexibility
in
choosing
any
combination
of
means
(
including
coating
reformulation,
use
of
lower
HAP
or
non
HAP
materials,
solvent
elimination,
work
practices,
and
add
on
control
devices)
that
is
workable
for
their
particular
situation
to
comply
with
the
emission
limits.
We
selected
mass
of
coating
solids
used
as
a
component
of
the
proposed
format
to
normalize
the
rate
of
organic
HAP
emissions
across
all
sizes
and
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Proposed
Rules
types
of
facilities.
We
also
selected
kg
(
lb)
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used
because
this
is
consistent
with
the
data
generally
available
in
this
industry
through
Material
Safety
Data
Sheets
and
other
manufacturers'
formulation
data.
Considering
the
primary
means
of
compliance
is
likely
to
be
the
use
of
low
and
no
organic
HAP
coatings
and
other
materials,
this
format
best
ensures
that
comparable
levels
of
control
are
achieved
by
all
affected
sources.
Also,
this
format
allows
sources
flexibility
to
use
a
combination
of
emission
capture
and
control
systems,
as
well
as
low
HAP
content
coatings
and
other
materials.
Other
choices
for
the
format
of
the
proposed
standards
that
we
considered,
but
rejected,
included
a
usage
limit
(
mass
per
unit
time)
and
a
never
to
beexceeded
limit
on
the
organic
HAP
content
of
each
coating,
solvent,
or
cleaning
material.
As
it
is
not
our
intent
to
limit
a
facility's
production
under
these
proposed
standards,
we
rejected
a
usage
limit.
We
also
rejected
a
never
tobe
exceeded
organic
HAP
content
limit
in
order
to
provide
for
averaging
of
HAP
emissions
from
the
materials
used
during
the
compliance
period.
In
this
decision,
we
considered
the
nature
of
the
available
data,
as
well
as
the
need
to
allow
for
seasonal
variations
and
frequent
changes
in
some
coating
operations,
such
as
job
shops.
Finally,
we
rejected
a
percent
reduction
limit
as
most
plastic
parts
and
products
surface
coating
facilities
are
not
expected
to
use
capture
systems
and
add
on
control
devices
for
compliance.
In
lieu
of
emission
standards,
section
112(
h)
of
the
CAA
allows
work
practice
standards
or
other
requirements
to
be
established
when
a
pollutant
cannot
be
emitted
through
a
conveyance
or
capture
system,
or
when
measurement
is
not
practicable
because
of
technological
and
economic
limitations.
Many
plastic
parts
and
products
surface
coating
facilities
use
some
type
of
work
practice
measure
to
reduce
HAP
emissions
from
mixing,
cleaning,
storage,
and
waste
handling
areas
as
part
of
their
standard
operating
procedures.
They
use
these
measures
to
decrease
solvent
usage
and
minimize
exposure
to
workers.
However,
we
do
not
have
data
to
quantify
accurately
the
emissions
reductions
achievable
by
the
work
practice
measures.
The
level
of
emissions
depends
on
the
type
of
equipment
and
the
work
practices
used
at
the
facility
and
would
be
very
sitespecific
For
example,
emissions
from
solvent
laden
rags
used
to
clean
spray
booths
would
depend
on
the
method
used
to
isolate
and
store
such
rags.
In
addition
to
lacking
adequate
data
and
information
to
quantify
an
emissions
level
for
such
operations,
it
is
not
practicable
to
measure
emissions
from
these
operations
since
they
often
occur
in
large
open
areas
not
amenable
to
testing.
Therefore,
work
practice
standards
are
appropriate
for
such
operations
under
section
112(
h)
of
the
CAA.
Under
the
compliance
options
where
emissions
are
reduced
by
using
low
or
no
HAP
materials,
the
compliance
determination
procedure
assumes
that
all
the
organic
HAP
in
the
materials
entering
the
affected
source
are
volatilized
(
emitted).
Therefore,
emissions
from
operations
occurring
within
the
affected
source
(
e.
g.,
mixing
operations)
are
accounted
for
in
the
determination
of
total
materials
usage
and
emission
rate
at
the
affected
source.
This
may
not
be
true
when
you
comply
by
using
capture
systems
and
add
on
control
devices,
particularly
if
some
coating
operations
at
your
facility
use
capture
systems
and
add
on
control
devices
and
others
do
not.
In
this
case,
you
might
determine
usage
of
coatings
and
other
materials
in
the
controlled
coating
operations
by
some
method
other
than
total
solvent
purchase
records.
It
is
possible
that
emissions
from
mixing
and
transport
of
the
materials
prior
to
their
use
in
the
controlled
coating
operation
might
not
be
included
in
your
usage
and
emission
rate
calculations.
Emissions
from
mixing,
storage,
and
waste
handling
operations
are
often
not
routed
to
the
control
devices
and
would
not
be
practicable
to
measure
for
inclusion
in
a
determination
of
compliance
with
the
emission
limit.
Therefore,
the
proposed
rule
would
require
development
and
implementation
of
an
emission
reduction
work
practice
plan
to
assure
that
emissions
are
reduced
from
such
operations.
F.
How
Did
We
Select
the
Testing
and
Initial
Compliance
Requirements?
The
proposed
standards
would
allow
you
to
choose
among
several
options
to
demonstrate
compliance
with
the
proposed
standards
for
organic
HAP:
compliant
materials
(
i.
e.,
coatings
and
other
materials
with
low
or
no
organic
HAP);
emission
rate
without
add
on
controls
option;
or
emission
rate
with
add
on
controls
option.
Compliant
Materials
Option.
You
would
be
required
to
document
the
organic
HAP
content
of
all
coatings
(
general
use,
TPO,
headlamp,
and
assembled
on
road
vehicle
coatings)
on
an
as
received
basis
and
show
that
each
is
less
than
the
applicable
emission
limit.
You
would
also
have
to
show
that
each
thinner,
other
additive,
and
cleaning
material
on
an
as
received
basis
contains
no
organic
HAP.
Note
that
``
no
organic
HAP''
is
not
intended
to
mean
absolute
zero.
Materials
that
contain
``
no
organic
HAP''
should
be
interpreted
to
mean
materials
that
contain
organic
HAP
levels
below
0.1
percent
by
mass
for
OSHA
defined
carcinogens
and
1.0
percent
by
mass
for
other
compounds.
You
may
use
manufacturer's
formulation
data
to
demonstrate
the
HAP
content
of
each
material
and
the
solids
content
of
each
coating.
If
you
choose
to
use
test
data,
you
would
use
the
following
procedures
on
each
coating,
thinner
or
other
additive,
and
cleaning
material
in
the
condition
it
is
in
when
it
is
received
from
its
manufacturer
or
supplier
and
before
any
alteration.
If
you
recycle
or
reclaim
coatings,
thinners,
cleaning
materials,
or
other
additives
at
your
facility,
you
do
not
need
to
demonstrate
that
these
materials
meet
the
emission
limit,
provided
they
were
initially
demonstrated
to
comply
with
the
compliant
material
option.
Method
311
is
the
method
developed
by
EPA
for
determining
the
mass
fraction
of
organic
HAP
in
coatings
and
has
been
used
in
previous
surface
coating
NESHAP.
We
have
not
identified
any
other
methods
that
provide
advantages
over
Method
311
for
use
in
the
proposed
standards
for
determining
organic
HAP
content.
Method
24
is
the
method
developed
by
EPA
for
determining
the
mass
fraction
of
volatile
matter
for
coatings
and
can
be
used
if
you
choose
to
determine
the
nonaqueous
volatile
matter
content
as
a
surrogate
for
organic
HAP.
In
past
standards,
VOC
emission
control
measures
have
been
implemented
in
coating
industries,
with
Method
24
as
the
compliance
method.
We
have
not
identified
any
other
methods
that
provide
advantages
over
Method
24
for
use
in
the
proposed
standards.
Method
24
is
the
method
specified
for
determining
the
coating
solids
content
of
each
coating.
We
have
not
identified
any
other
methods
that
provide
advantages
over
Method
24
for
use
in
the
proposed
standards.
Emission
Rate
Without
Add
on
Controls
Option.
To
demonstrate
initial
compliance
using
this
option,
you
would
calculate
the
organic
HAP
emission
rate
for
one
or
more
coating
operations
in
each
affected
source,
based
on
the
mass
of
organic
HAP
in
all
coatings,
thinners
and
other
additives,
and
cleaners,
and
the
mass
of
coating
solids
used
during
the
compliance
period.
You
would
demonstrate
that
your
emission
rate
does
not
exceed
the
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2002
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Proposed
Rules
applicable
emission
limit
for
the
affected
source.
You
would
determine
the
HAP
content
from
manufacturer's
formulation
data
or
by
using
EPA
Method
24
or
311
as
discussed
previously.
Emission
Rate
With
Add
on
Controls
Option.
If
you
use
a
capture
system
and
control
device
other
than
a
solvent
recovery
device
for
which
you
conduct
a
liquid
liquid
material
balance,
you
would
be
required
to
conduct
an
initial
performance
test
of
the
system
to
determine
its
overall
control
efficiency
using
EPA
Method
25
or
25A
depending
on
the
type
of
control
device
and
the
outlet
concentration.
You
would
also
need
to
determine
the
capture
efficiency
of
the
capture
system
using
EPA
Methods
204
and
204A
through
204F.
For
a
solvent
recovery
system
for
which
you
conduct
a
liquid
liquid
material
balance,
you
would
determine
the
quantity
of
volatile
matter
applied
and
the
quantity
recovered
during
the
initial
compliance
period
to
determine
its
overall
control
efficiency.
For
both
cases,
the
overall
control
efficiency
would
be
combined
with
the
monthly
mass
of
organic
HAP
in
the
coatings
and
other
materials
used
to
calculate
the
monthly
organic
HAP
emissions
in
kg
(
lb)
HAP
emitted.
The
monthly
amount
(
kg
(
lb))
of
coating
solids
used
would
also
be
determined.
These
values
would
be
combined
to
calculate
your
emission
rate
for
the
12
month
compliance
period
according
to
equations
in
the
proposed
rule.
You
would
demonstrate
that
your
emission
rate
does
not
exceed
the
applicable
emission
limit
for
the
affected
source.
If
you
conduct
a
performance
test,
you
would
also
determine
parameter
operating
limits
during
the
test.
The
proposed
test
methods
for
the
performance
test
have
been
required
in
many
NSPS
for
industrial
surface
coating
sources
under
40
CFR
part
60
and
NESHAP
under
40
CFR
part
63.
We
have
not
identified
any
other
methods
that
provide
advantages
over
these
methods.
G.
How
Did
We
Select
the
Continuous
Compliance
Requirements?
To
demonstrate
continuous
compliance
with
either
the
compliant
materials
option
or
the
emission
rate
without
add
on
controls
option,
you
would
need
records
of
the
data
and
calculations
supporting
your
determination
of
the
organic
HAP
content
and
solids
content
of
each
material
used.
You
would
also
need
records
of
the
quantity
of
coatings
and
other
materials
used.
For
the
compliant
materials
option,
you
would
demonstrate
compliance
for
each
material
used.
For
the
emission
rate
without
add
on
controls
option,
you
would
demonstrate
compliance
with
the
applicable
12
month
emission
limit
on
a
monthly
basis
using
data
from
the
previous
12
months
of
operation.
If
you
use
the
emission
rate
with
addon
controls
option,
you
would
also
be
required
to
continuously
monitor
operating
parameters
of
capture
systems
and
control
devices
and
maintain
records
of
this
monitoring.
We
selected
the
following
requirements
based
on
reasonable
cost,
ease
of
execution,
and
usefulness
of
the
resulting
data
to
both
the
owners
or
operators
and
EPA
for
ensuring
continuous
compliance
with
the
emission
limits
and/
or
operating
limits.
We
are
proposing
that
certain
parameters
be
continuously
monitored
for
the
types
of
capture
systems
and
control
devices
commonly
used
in
the
industry.
These
monitoring
parameters
have
been
used
in
other
standards
for
similar
industries
and
control
devices.
The
values
of
these
parameters
are
established
during
the
initial
or
most
recent
performance
test
that
demonstrates
compliance.
These
values
are
your
operating
limits
for
the
capture
system
and
control
device.
You
would
be
required
to
determine
3
hour
average
values
for
most
monitored
parameters
for
the
controlled
coating
operations
within
the
affected
source.
We
selected
this
averaging
period
to
reflect
operating
conditions
during
the
performance
test
to
ensure
the
control
system
is
continuously
operating
at
the
same
or
better
control
level
as
during
a
performance
test
demonstrating
compliance
with
the
emission
limits.
If
you
conduct
liquid
liquid
material
balances,
you
would
need
records
of
the
quantity
of
volatile
matter
used
and
the
quantity
recovered
by
the
solvent
recovery
system.
You
would
demonstrate
compliance
with
the
emission
limit
on
a
monthly
basis
using
data
from
the
previous
12
months
of
operation.
H.
How
Did
We
Select
the
Notification,
Recordkeeping,
and
Reporting
Requirements?
You
would
be
required
to
comply
with
the
applicable
requirements
in
the
NESHAP
General
Provisions,
subpart
A
of
40
CFR
part
63,
as
described
in
Table
2
of
the
proposed
subpart
PPPP.
We
evaluated
the
General
Provisions
requirements
and
included
those
we
determined
to
be
the
minimum
notification,
recordkeeping,
and
reporting
necessary
to
ensure
compliance
with,
and
effective
enforcement
of,
the
proposed
standards,
modifying
them
as
appropriate
for
the
plastic
parts
and
products
surface
coating
source
category.
I.
How
Did
We
Select
the
Compliance
Date?
You
would
be
allowed
3
years
to
comply
with
the
final
standards
for
existing
affected
sources.
This
is
the
maximum
period
allowed
by
the
CAA.
We
believe
that
3
years
for
compliance
is
necessary
to
allow
adequate
time
to
accommodate
the
variety
of
compliance
methods
that
existing
sources
may
use.
Most
sources
in
this
category
would
need
this
3
year
maximum
amount
of
time
to
develop
and
test
reformulated
coatings,
particularly
those
that
may
opt
to
comply
using
a
different
loweremitting
coating
technology.
We
want
to
encourage
the
use
of
these
pollution
prevention
technologies.
In
addition,
time
would
be
needed
to
establish
records
management
systems
required
for
enforcement
purposes.
Some
sources
may
need
the
time
to
purchase
and
install
emission
capture
and
control
systems.
In
such
cases,
you
would
need
to
obtain
permits
for
the
use
of
add
on
controls,
which
will
require
time
for
approval
from
the
permitting
authority.
The
CAA
requires
that
new
or
reconstructed
affected
sources
comply
with
standards
immediately
upon
startup
or
the
effective
date
of
the
final
rule,
whichever
is
later.
IV.
Summary
of
Environmental,
Energy,
and
Economic
Impacts
For
the
purpose
of
assessing
impacts,
we
assumed
that
all
sources
would
convert
to
liquid
coatings,
thinners,
and
other
additives
with
lower
organic
HAP
content
than
those
presently
used
and
would
convert
to
lower
HAP
or
no
HAP
cleaning
materials
rather
than
using
add
on
control
devices,
except
for
those
already
using
add
on
control
devices.
A.
What
Are
the
Air
Impacts?
The
1997
nationwide
baseline
organic
HAP
emissions
for
the
202
major
source
plastic
parts
and
products
surface
coating
facilities
of
which
EPA
is
aware
are
estimated
to
be
9,820
tpy.
Implementation
of
the
emission
limitations
as
proposed
would
reduce
these
emissions
by
approximately
80
percent
to
2,260
tpy.
In
addition,
the
proposed
emission
limitations
will
not
result
in
any
significant
secondary
air
impacts.
We
expect
that
the
majority
of
facilities
will
switch
to
low
or
noorganic
HAP
containing
materials
to
comply
with
the
standards
rather
than
installing
add
on
control
devices.
Thus,
increases
in
electricity
consumption
(
which
could
lead
to
increases
in
emissions
of
nitrogen
oxides,
sulfur
dioxide,
carbon
monoxide,
and
carbon
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4,
2002
/
Proposed
Rules
dioxide
from
electric
utilities)
will
be
minimal.
B.
What
Are
the
Cost
Impacts?
The
total
capital
cost
(
including
monitoring
costs)
for
existing
sources
is
estimated
to
be
approximately
$
803,830.
The
nationwide
annual
cost
(
including
monitoring,
recordkeeping,
and
reporting
costs)
for
existing
sources
is
approximately
$
10.7
million
per
year.
Costs
for
new
sources
were
based
on
an
estimate
of
six
new
sources
being
constructed
within
5
years
after
promulgation
of
the
final
standards.
The
total
capital
cost
(
including
monitoring
costs)
for
new
sources
is
$
28,000.
The
total
annual
cost
(
including
monitoring,
recordkeeping,
and
reporting
costs)
for
new
sources
is
estimated
to
be
approximately
$
194,000
per
year.
Cost
estimates
are
based
on
information
available
to
the
Administrator
and
presented
in
the
economic
analysis
of
this
rule.
The
costs
are
calculated
assuming
that
the
majority
of
sources
would
comply
by
using
lower
HAP
containing
or
non
HAP
coatings
and
cleaning
materials
because
such
materials
are
generally
available,
and
add
on
controls
would
not
be
technically
feasible
for
typical
facilities.
Waterborne
coatings
are
a
type
of
potentially
lower
HAP
coating
which
could
be
used
by
facilities
and
may
contribute
to
higher
costs
due
to
increased
drying
times
or
temperatures
that
may
be
needed
for
waterborne
coatings.
However,
the
data
available
in
the
plastic
parts
ICR
database
did
not
indicate
any
definite
relationship
between
coating
types
and
drying
times
or
curing
temperatures.
We
also
assumed
that
facilities
presently
equipped
with
add
on
controls
would
continue
to
operate
those
control
devices
and
capture
systems
and
would
perform
the
required
performance
tests
and
parameter
monitoring.
During
development
of
the
proposed
emission
limitations,
limited
information
was
available
on
the
costs
associated
with
the
switch
to
low
HAP
or
non
HAP
coatings
and
cleaning
materials.
Thus,
we
request
comment
on
the
assumptions
and
methodology
used
to
determine
these
costs.
Any
comments
should
provide
detailed
information
that
includes
identification
of
the
coatings
or
cleaning
materials
(
and
associated
costs)
currently
being
used
and
the
coatings
or
cleaning
materials
(
and
associated
costs)
that
would
be
used
to
comply
with
the
proposed
emission
limitations,
as
well
as
the
basis
for
the
cost
information.
You
may
refer
to
the
Determination
of
Baseline
Emissions
and
Costs
and
Emissions
Impacts
for
New
and
Existing
Sources
in
the
Plastic
Parts
and
Products
Surface
Coating
Source
Category
memorandum
in
the
docket
for
additional
details.
C.
What
Are
the
Economic
Impacts?
We
prepared
an
economic
impacts
analysis
(
EIA)
to
evaluate
the
impacts
the
proposed
rule
would
have
on
the
plastic
parts
and
products
surface
coating
industry,
consumers,
and
society.
Economic
impacts
were
calculated
on
a
facility
specific
basis,
as
well
as
on
a
market
segment
basis
(
e.
g.,
automobile
manufacturing,
sporting
goods,
electronics
equipment,
etc.).
Economic
impact
indicators
examined
included
price,
output,
and
employment
impacts.
The
EIA
shows
that
the
expected
price
increase
for
affected
plastic
parts
and
products
would
be
less
than
0.1
percent
as
a
result
of
the
proposed
standards.
Therefore,
we
do
not
expect
any
adverse
impact
to
occur
for
those
industries
that
produce
or
consume
plastic
parts
and
products
such
as
home
appliances,
computer
hardware
producers,
motor
vehicle
manufacturers,
and
recreational
vehicle
manufacturers.
The
distribution
of
costs
across
plastic
parts
and
products
production
facilities
is
slanted
toward
the
lower
impact
levels
with
many
facilities
incurring
costs
related
only
to
annually
recurring
monitoring,
reporting,
and
recordkeeping
activities.
The
EIA
indicates
that
these
regulatory
costs
are
expected
to
represent
only
0.25
percent
of
the
value
of
coating
services,
which
should
not
cause
producers
to
cease
or
alter
their
current
operations.
Hence,
no
firms
or
facilities
are
at
risk
of
closures
because
of
the
proposed
standards.
D.
What
Are
the
Non
air
Health,
Environmental,
and
Energy
Impacts?
Based
on
information
from
the
industry
survey
responses,
we
found
no
indication
that
the
use
of
low
organic
HAP
content
coatings,
thinners
and
other
additives,
and
cleaning
materials
at
affected
sources
would
result
in
any
increase
or
decrease
in
non
air
health,
environmental,
and
energy
impacts.
There
would
be
no
change
in
the
utility
requirements
associated
with
the
use
of
these
materials,
so
there
would
be
no
change
in
the
amount
of
energy
consumed
as
a
result
of
the
material
conversion.
We
estimate
that
the
proposed
emission
limitations
will
have
a
minimal
impact
on
water
quality
because
only
a
few
facilities
are
expected
to
comply
by
making
process
modifications
or
by
using
add
on
control
devices
that
would
generate
wastewater.
However,
because
many
low
HAP
and
no
HAP
materials
are
waterborne,
an
increase
in
wastewater
generation
from
cleaning
activities
may
result.
Although
additional
wastewater
may
be
generated
by
facilities
switching
to
waterborne
coatings,
the
amount
of
wastewater
generated
by
these
facilities
is
not
expected
to
increase
significantly.
We
also
estimate
that
the
proposed
emission
limitations
will
result
in
a
decrease
in
the
amount
of
both
solid
and
hazardous
waste
from
facilities,
as
the
majority
of
facilities
will
be
using
lower
organic
HAP
containing
materials
which
will
result
in
a
decrease
in
the
amount
of
waste
materials
that
would
have
to
be
disposed
of
as
hazardous.
In
addition,
we
expect
that
the
majority
of
facilities
will
comply
by
using
low
HAP
or
no
organic
HAP
containing
materials
rather
than
add
on
control
devices.
Thus,
there
will
be
little
or
no
increase
in
energy
usage
caused
by
the
operation
of
add
on
controls.
V.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
EPA
must
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(
2)
create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(
3)
materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligation
of
recipients
thereof;
or
(
4)
raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
OMB
has
notified
EPA
that
it
considers
this
a
``
significant
regulatory
action''
within
the
meaning
of
the
Executive
Order.
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.
B.
Executive
Order
13132,
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
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Rules
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
Under
section
6
of
Executive
Order
13132,
EPA
may
not
issue
a
regulation
that
has
federalism
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,
unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
State
and
local
governments,
or
EPA
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
The
EPA
also
may
not
issue
a
regulation
that
has
federalism
implications
and
that
preempts
State
law,
unless
the
Agency
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
This
proposed
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
Pursuant
to
the
terms
of
Executive
Order
13132,
it
has
been
determined
that
this
proposed
rule
does
not
have
``
federalism
implications''
because
it
does
not
meet
the
necessary
criteria.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
this
proposed
rule.
C.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
This
proposed
rule
does
not
have
tribal
implications.
It
will
not
have
substantial
direct
effects
on
tribal
governments,
or
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
No
tribal
governments
own
or
operate
plastic
parts
and
products
surface
coating
facilities.
Thus,
Executive
Order
13175
does
not
apply
to
this
proposed
rule.
EPA
specifically
solicits
additional
comment
on
this
proposed
rule
from
tribal
officials.
D.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045,
``
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks''
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
EPA
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.
The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
501
of
the
Executive
Order
has
the
potential
to
influence
the
regulation.
This
proposed
rule
is
not
subject
to
Executive
Order
13045
because
it
does
not
establish
environmental
standards
based
on
an
assessment
of
health
or
safety
risks.
No
children's
risk
analysis
was
performed
because
no
alternative
technologies
exist
that
would
provide
greater
stringency
at
a
reasonable
cost.
Furthermore,
this
proposed
rule
has
been
determined
not
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866.
E.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
proposed
rule
is
not
a
``
significant
energy
action''
as
defined
in
Executive
Order
13211,
``
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(
66
FR
28355,
May
22,
2001)
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.
Further,
we
have
concluded
that
this
proposed
rule
is
not
likely
to
have
any
adverse
energy
effects.
Affected
sources
are
expected
to
comply
with
the
proposed
rule
through
pollution
prevention
rather
than
end
of
pipe
controls,
and
therefore,
there
would
be
no
increase
in
energy
usage.
F.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
leastcostly
most
cost
effective,
or
leastburdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
The
EPA
has
determined
that
this
proposed
rule
does
not
contain
a
Federal
mandate
that
may
result
in
expenditures
of
$
100
million
or
more
for
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
The
maximum
total
annual
cost
of
this
proposed
rule
for
any
1
year
has
been
estimated
to
be
slightly
less
than
$
11
million.
Thus,
today's
proposed
rule
is
not
subject
to
the
requirements
of
sections
202
and
205
of
the
UMRA.
In
addition,
EPA
has
determined
that
this
proposed
rule
contains
no
regulatory
requirements
that
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/
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4,
2002
/
Proposed
Rules
might
significantly
or
uniquely
affect
small
governments
because
it
contains
no
requirements
that
apply
to
such
governments
or
impose
obligations
upon
them.
Therefore,
today's
proposed
rule
is
not
subject
to
the
requirements
of
section
203
of
the
UMRA.
G.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601,
et
seq.
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedures
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
proposed
rule
on
small
entities,
small
entity
is
defined
as:
(
1)
A
small
business
whose
parent
company
has
fewer
than
500
or
1,000
employees,
depending
on
the
size
definition
for
the
affected
NAICS
Code;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
forprofit
enterprise
that
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
It
should
be
noted
that
companies
in
32
NAICS
codes
are
affected
by
this
proposed
rule,
and
the
small
business
definition
applied
to
each
industry
by
NAICS
code
is
that
listed
in
the
Small
Business
Administration
size
standards
(
13
CFR
part
121).
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
We
have
determined
that
67
of
the
130
firms,
or
51
percent
of
the
total,
affected
by
this
proposed
rule
may
be
small
entities.
While
the
number
of
small
firms
appears
to
be
a
large
proportion
of
the
total
number
of
affected
firms,
the
small
firms
only
experience
21
percent
of
the
total
national
compliance
cost
of
$
11
million
(
1997
$).
Of
the
67
affected
small
firms,
only
three
firms
are
estimated
to
have
compliance
costs
that
exceed
1
percent
of
their
revenues.
The
maximum
impact
on
any
affected
small
entity
is
a
compliance
cost
of
1.8
percent
of
its
sales.
Finally,
while
there
is
a
difference
between
the
median
compliance
cost
tosales
estimates
for
the
affected
small
and
large
firms
(
0.08
percent
compared
to
0.01
percent
for
the
large
firms,
and
0.03
percent
across
all
affected
firms),
no
adverse
economic
impacts
are
expected
for
either
small
or
large
firms
affected
by
the
proposed
rule.
Therefore,
the
affected
small
firms
are
not
disproportionately
affected
by
this
proposed
rule
as
compared
to
the
affected
large
firms.
Although
this
proposed
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities,
EPA
nonetheless
has
tried
to
reduce
the
impact
of
this
proposed
rule
on
small
entities.
The
Agency
has
also
reached
out
to
small
entities
as
part
of
our
outreach
to
affected
industries.
Representatives
of
small
entities
have
participated
in
stakeholder
meetings
held
during
the
last
3
years
as
well
as
site
visits
conducted
by
the
EPA
for
data
gathering
purposes.
Small
entities
will
be
afforded
extensive
flexibility
in
demonstrating
compliance
through
pollution
prevention
rather
than
the
use
of
add
on
control
technology.
We
are
proposing
compliance
options
which
give
small
entities
flexibility
in
choosing
the
most
cost
effective
and
least
burdensome
alternative
for
their
operation.
For
example,
a
facility
could
purchase
and
use
low
HAP
coatings
and
other
materials
(
i.
e.,
pollution
prevention)
that
meet
the
proposed
standards
instead
of
using
add
on
capture
and
control
systems.
This
method
of
compliance
can
be
demonstrated
with
minimum
burden
by
using
purchase
and
usage
records.
No
testing
of
materials
would
be
required,
as
the
facility
owner
could
show
that
their
coatings
and
other
materials
meet
the
emission
limits
by
providing
formulation
data
supplied
by
the
manufacturer.
We
continue
to
be
interested
in
the
potential
impacts
of
the
proposed
standards
on
small
entities
and
welcome
comments
on
issues
related
to
such
impacts.
H.
Paperwork
Reduction
Act
The
information
collection
requirements
in
this
proposed
rule
have
been
submitted
for
approval
to
OMB
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501,
et
seq.
An
Information
Collection
Request
(
ICR)
document
has
been
prepared
by
EPA
(
ICR
No.
2044.01)
and
a
copy
may
be
obtained
from
Susan
Auby
by
mail
at
U.
S.
EPA,
Office
of
Environmental
Information,
Collection
Strategies
Division
(
2822T),
1200
Pennsylvania
Avenue,
NW.,
Washington
DC
20460,
by
e
mail
at
auby.
susan@
epa.
gov,
or
by
calling
(
202)
566
1672.
A
copy
may
also
be
downloaded
off
the
Internet
at
http://
www.
epa.
gov/
icr.
The
information
collection
requirements
are
not
effective
until
OMB
approves
them.
The
information
collection
requirements
are
based
on
notification,
recordkeeping,
and
reporting
requirements
in
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A),
which
are
mandatory
for
all
operators
subject
to
national
emission
standards.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(
42
U.
S.
C.
7414).
All
information
submitted
to
EPA
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
Agency
policies
set
forth
in
40
CFR
part
2,
subpart
B.
The
proposed
standards
would
require
maintaining
records
of
all
coatings,
thinners
and
other
additives,
and
cleaning
materials
data
and
calculations
used
to
determine
compliance.
This
information
includes
the
volume
used
during
each
compliance
period,
mass
fraction
of
organic
HAP,
density,
and
mass
fraction
of
coating
solids.
If
an
add
on
control
device
is
used,
records
must
be
kept
of
the
capture
efficiency
of
the
capture
system,
destruction
or
removal
efficiency
of
the
add
on
control
device,
and
the
monitored
operating
parameters.
In
addition,
records
must
be
kept
of
each
calculation
of
the
affected
source's
emissions
for
each
12
month
compliance
period
and
all
data,
calculations,
test
results,
and
other
supporting
information
used
to
determine
this
value.
The
monitoring,
recordkeeping,
and
reporting
burden
in
the
3rd
year
after
the
effective
date
of
the
promulgated
rule
is
estimated
to
be
118,835
labor
hours
at
a
cost
of
$
5.4
million
for
new
and
existing
sources.
This
estimate
includes
the
cost
of
determining
and
recording
organic
HAP
content,
solids
content,
and
density,
as
needed,
of
the
regulated
materials,
and
developing
a
system
for
determining
and
recording
the
amount
of
each
material
used
and
performing
the
calculations
needed
for
demonstrating
compliance.
For
those
affected
sources
using
an
add
on
control
device
to
comply,
the
costs
also
include
a
one
time
performance
test
and
report
(
with
repeat
tests
where
needed)
of
the
add
on
control
device,
one
time
purchase
and
installation
of
CPMS,
one
time
submission
of
a
SSMP,
and
any
required
startup,
shutdown,
and
malfunction
reports.
Total
capital/
startup
costs
associated
with
the
monitoring
requirements
over
the
3
year
period
of
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Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
the
ICR
are
estimated
at
$
133,000,
with
operation
and
maintenance
costs
of
$
655
per
year.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Comments
are
requested
on
the
EPA's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
By
U.
S.
Postal
Service,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
EPA
(
2822T),
1200
Pennsylvania
Avenue,
NW.,
Washington
DC
20460;
or
by
courier,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
EPA
(
2822T),
1301
Constitution
Avenue,
NW.,
Room
6143,
Washington
DC
20460
(
202
566
1700);
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
St.,
NW.,
Washington,
DC
20503,
marked
``
Attention:
Desk
Officer
for
EPA.''
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
December
4,
2002,
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
January
3,
2003.
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
this
proposal.
I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(
NTTAA),
Public
Law
104
113,
section
12(
d)
(
15
U.
S.
C.
272
note)
directs
EPA
to
use
voluntary
consensus
standards
(
VCS)
in
its
regulatory
and
procurement
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
The
VCS
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
and
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
annual
reports
to
OMB,
with
explanations
when
the
Agency
does
not
use
available
and
applicable
VCS.
This
proposed
rulemaking
involves
technical
standards.
The
EPA
proposes
in
this
rule
to
use
EPA
Methods
1,
1A,
2,
2A,
2C,
2D,
2F,
2G,
3,
3A,
3B,
4,
24,
25,
25A,
204,
204A
F,
and
311.
Consistent
with
the
NTTAA,
EPA
conducted
searches
to
identify
VCS
in
addition
to
these
EPA
methods.
No
applicable
VCS
were
identified
for
EPA
Methods
1A,
2A,
2D,
2F,
2G,
204,
204A
F,
and
311.
The
search
and
review
results
have
been
documented
and
are
placed
in
the
docket
(
Docket
No.
A
99
12)
for
this
proposed
rule.
Six
VCS:
ASTM
D1475
90,
ASTM
D2369
95,
ASTM
D3792
91,
ASTM
D4017
96a,
ASTM
D4457
85
(
Reapproved
91),
and
ASTM
D5403
93
are
already
incorporated
by
reference
in
EPA
Method
24.
In
addition,
we
are
separately
specifying
the
use
of
ASTM
D1475
98,
``
Standard
Test
Method
for
Density
of
Liquid
Coatings,
Inks,
and
Related
Products,''
for
measuring
the
density
of
individual
coating
components,
such
as
organic
solvents.
Five
VCS:
ASTM
D1979
91,
ASTM
D3432
89,
ASTM
D4747
87,
ASTM
D4827
93,
and
ASTM
PS9
94
are
incorporated
by
reference
in
EPA
Method
311.
The
VCS
ASTM
D4457
85
(
Reapproved
1996),
``
Standard
Test
Method
for
Determination
of
Dichloromethane
(
Methylene
chloride)
and
1,1,1
Trichloroethane
(
Methyl
chloroform)
in
Paints
and
Coatings
by
Direct
Injection
into
a
Gas
Chromatograph,''
is
not
a
complete
alternative
to
EPA
Method
311,
but
is
an
acceptable
alternative
to
EPA
Method
311
for
the
following
two
HAP:
(
1)
Dichloromethane
(
methylene
chloride)
and
(
2)
1,1,1
Trichlorethane
(
methyl
chloroform).
Therefore,
EPA
will
incorporate
by
reference
ASTM
D4457
into
40
CFR
63.14
in
the
future.
In
addition
to
the
VCS
EPA
proposes
to
use
in
this
proposed
rule,
the
search
for
emission
measurement
procedures
identified
17
other
VCS.
The
EPA
determined
that
13
of
these
17
standards
were
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
this
proposed
rulemaking.
Therefore,
EPA
does
not
propose
to
adopt
these
standards
today.
(
See
docket
A
99
12
for
further
information
on
the
methods.)
The
following
four
of
the
17
VCS
identified
in
this
search
were
not
available
at
the
time
the
review
was
conducted
for
the
purposes
of
this
proposed
rulemaking
because
they
are
under
development
by
a
voluntary
consensus
body:
ASME/
BSR
MFC
13M,
``
Flow
Measurement
by
Velocity
Traverse,''
for
EPA
Method
2
(
and
possibly
1);
ASME/
BSR
MFC
12M,
``
Flow
in
Closed
Conduits
Using
Multiport
Averaging
Pitot
Primary
Flowmeters,''
for
EPA
Method
2;
ISO/
DIS
12039,
``
Stationary
Source
Emissions
Determination
of
Carbon
Monoxide,
Carbon
Dioxide,
and
Oxygen
Automated
Methods,''
for
EPA
Method
3A;
and
ISO/
PWI
17895,
``
Paints
and
Varnishes
Determination
of
the
Volatile
Organic
Compound
Content
of
Water
based
Emulsion
Paints,''
for
EPA
Method
24.
While
we
are
not
proposing
to
include
these
four
VCS
in
today's
proposal,
the
EPA
will
consider
the
VCS
when
finalized.
The
EPA
takes
comment
on
the
compliance
demonstration
requirements
in
this
proposed
rulemaking
and
specifically
invites
the
public
to
identify
potentially
applicable
VCS.
Commentors
should
also
explain
why
this
proposed
rule
should
adopt
these
VCS
in
lieu
of
or
in
addition
to
EPA's
method.
Emission
test
methods
submitted
for
evaluation
should
be
accompanied
by
a
basis
for
the
recommendation,
including
method
validation
data
and
the
procedure
used
to
validate
the
candidate
method
(
if
a
method
other
than
Method
301,
40
CFR
part
63,
appendix
A,
was
used).
Sections
63.4541,
63.4551,
63.4561,
63.4565,
and
63.4566
of
the
proposed
standards
list
the
EPA
testing
methods
included
in
the
proposed
standards.
Under
40
CFR
63.7(
f)
of
the
General
Provisions,
a
source
may
apply
to
EPA
for
permission
to
use
alternative
test
methods
in
place
of
any
of
the
EPA
testing
methods.
List
of
Subjects
in
40
CFR
Part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Hazardous
substances,
Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.
Dated:
November
8,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
stated
in
the
preamble,
title
40,
chapter
I,
part
63
of
the
Code
of
Federal
Regulations
is
proposed
to
be
amended
as
follows:
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Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
PART
63
[
AMENDED]
1.
The
authority
citation
for
part
63
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401,
et
seq.
2.
Part
63
is
amended
by
adding
subpart
PPPP
to
read
as
follows:
Subpart
PPPP
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Surface
Coating
of
Plastic
Parts
and
Products
What
This
Subpart
Covers
Sec.
63.4480
What
is
the
purpose
of
this
subpart?
63.4481
Am
I
subject
to
this
subpart?
63.4482
What
parts
of
my
plant
does
this
subpart
cover?
63.4483
When
do
I
have
to
comply
with
this
subpart?
Emission
Limitations
63.4490
What
emission
limits
must
I
meet?
63.4491
What
are
my
options
for
meeting
the
emission
limits?
63.4492
What
operating
limits
must
I
meet?
63.4493
What
work
practice
standards
must
I
meet?
General
Compliance
Requirements
63.4500
What
are
my
general
requirements
for
complying
with
this
subpart?
63.4501
What
parts
of
the
General
Provisions
apply
to
me?
Notifications,
Reports,
and
Records
63.4510
What
notifications
must
I
submit?
63.4520
What
reports
must
I
submit?
63.4530
What
records
must
I
keep?
63.4531
In
what
form
and
for
how
long
must
I
keep
my
records?
Compliance
Requirements
for
the
Compliant
Material
Option
63.4540
By
what
date
must
I
conduct
the
initial
compliance
demonstration?
63.4541
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations?
63.4542
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
Compliance
Requirements
for
the
Emission
Rate
Without
Add
On
Controls
Option
63.4550
By
what
date
must
I
conduct
the
initial
compliance
demonstration?
63.4551
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations?
63.4552
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
Compliance
Requirements
for
the
Emission
Rate
With
Add
On
Controls
Option
63.4560
By
what
date
must
I
conduct
performance
tests
and
other
initial
compliance
demonstrations?
63.4561
How
do
I
demonstrate
initial
compliance?
63.4562
[
Reserved]
63.4563
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
63.4564
What
are
the
general
requirements
for
performance
tests?
63.4565
How
do
I
determine
the
emission
capture
system
efficiency?
63.4566
How
do
I
determine
the
add
on
control
device
emission
destruction
or
removal
efficiency?
63.4567
How
do
I
establish
the
emission
capture
system
and
add
on
control
device
operating
limits
during
the
performance
test?
63.4568
What
are
the
requirements
for
continuous
parameter
monitoring
system
installation,
operation,
and
maintenance?
Other
Requirements
and
Information
63.4580
Who
implements
and
enforces
this
subpart?
63.4581
What
definitions
apply
to
this
subpart?
Tables
to
Subpart
PPPP
of
Part
63
Table
1
to
Subpart
PPPP
of
Part
63
Operating
Limits
if
Using
the
Emission
Rate
with
Add
On
Controls
Option.
Table
2
to
Subpart
PPPP
of
Part
63
Applicability
of
General
Provisions
to
Subpart
PPPP
of
Part
63.
Table
3
to
Subpart
PPPP
of
Part
63
Default
Organic
HAP
Mass
Fraction
of
Solvents
and
Solvent
Blends.
Table
4
to
Subpart
PPPP
of
Part
63
Default
Organic
HAP
Mass
Fraction
for
Petroleum
Solvent
Groups.
Subpart
PPPP
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Surface
Coating
of
Plastic
Parts
and
Products
What
This
Subpart
Covers
§
63.4480
What
is
the
purpose
of
this
subpart?
This
subpart
establishes
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
plastic
parts
and
products
surface
coating
facilities.
This
subpart
also
establishes
requirements
to
demonstrate
initial
and
continuous
compliance
with
the
emission
limitations.
§
63.4481
Am
I
subject
to
this
subpart?
(
a)
Plastic
parts
and
products
include,
but
are
not
limited
to,
plastic
components
of
the
following
types
of
products
as
well
as
the
products
themselves:
motor
vehicle
parts
and
accessories
for
automobiles,
trucks,
recreational
vehicles;
sporting
and
recreational
goods;
toys;
business
machines;
laboratory
and
medical
equipment;
and
household
and
other
consumer
products.
Except
as
provided
in
paragraph
(
c)
of
this
section,
the
source
category
to
which
this
subpart
applies
is
the
surface
coating
of
any
plastic
part
or
product,
as
described
in
paragraph
(
a)(
1)
of
this
section,
and
it
includes
the
subcategories
listed
in
paragraphs
(
a)(
2)
through
(
5)
of
this
section.
(
1)
Surface
coating
is
the
application
of
coating
to
a
substrate
using,
for
example,
spray
guns
or
dip
tanks,
and
associated
activities,
such
as
surface
preparation,
cleaning,
mixing,
and
storage,
etc.
(
2)
The
general
use
coating
subcategory
includes
all
coating
operations
that
are
not
headlamp
coating
operations,
thermoplastic
olefin
(
TPO)
coating
operations,
or
assembled
on
road
vehicle
coating
operations.
(
3)
The
headlamp
coating
subcategory
includes
the
surface
coating
of
plastic
components
of
the
body
of
an
automotive
headlamp;
typical
coatings
used
are
reflective
argent
coatings
and
clear
topcoats.
(
4)
The
TPO
coating
subcategory
includes
the
surface
coating
of
TPO
substrates;
typical
coatings
used
are
adhesion
promoters,
primers,
color
coatings,
clear
coatings
and
topcoats.
The
coating
of
TPO
substrates
on
fully
assembled
on
road
vehicles
is
not
included
in
the
TPO
coating
subcategory.
(
5)
The
assembled
on
road
vehicle
coating
subcategory
includes
the
surface
coating
of
plastic
parts
on
fully
assembled
motor
vehicles
and
trailers
intended
for
on
road
use,
including,
but
not
limited
to,
plastic
parts
on:
automobiles
and
light
trucks
that
have
been
repaired
after
a
collision
or
otherwise
repainted,
fleet
delivery
trucks,
and
motor
homes
and
other
recreational
vehicles
(
including
camping
trailers
and
fifth
wheels).
The
assembled
on
road
vehicle
coating
subcategory
does
not
include
the
surface
coating
of
plastic
parts
prior
to
their
attachment
to
an
on
road
vehicle
on
an
original
equipment
manufacturer's
(
OEM)
assembly
line.
The
assembled
on
road
vehicle
coating
subcategory
also
does
not
include
the
use
of
adhesives,
sealants,
and
caulks
used
in
assembling
on
road
vehicles.
(
b)
You
are
subject
to
this
subpart
if
you
own
or
operate
a
new,
reconstructed,
or
existing
affected
source,
as
defined
in
§
63.4482,
that
uses
100
gallons
per
year,
or
more,
of
coatings
in
the
surface
coating
of
plastic
parts
and
products
defined
in
paragraph
(
a)
of
this
section;
and
that
is
a
major
source,
is
located
at
a
major
source,
or
is
part
of
a
major
source
of
emissions
of
hazardous
air
pollutants
(
HAP).
A
major
source
of
HAP
emissions
is
any
stationary
source
or
group
of
stationary
sources
located
within
a
contiguous
area
and
under
common
control
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
9.07
megagrams
(
Mg)
(
10
tons)
or
more
per
year
or
any
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
1
Proposed
at
67
FR
20206,
April
24,
2002.
2
Proposed
at
67
FR
42400,
June
21,
2002.
3
Proposed
at
66
FR
40323,
August
2,
2001.
4
Proposed
at
67
FR
62780,
August
13,
2002.
5
Proposed
at
67
FR
52780,
August
13,
2002.
6
Proposed
at
67
FR
52780,
August
13,
2002.
combination
of
HAP
at
a
rate
of
22.68
Mg
(
25
tons)
or
more
per
year.
(
c)
This
subpart
does
not
apply
to
surface
coating
that
meets
the
criteria
of
paragraphs
(
c)(
1)
through
(
12)
of
this
section.
(
1)
Surface
coating
conducted
at
a
source
that
uses
only
coatings,
thinners
and
other
additives,
and
cleaning
materials
that
contain
no
organic
HAP,
as
determined
according
to
§
63.4541(
a).
(
2)
Surface
coating
of
plastic
subject
to
the
NESHAP
for
aerospace
manufacturing
and
rework
facilities
(
subpart
GG
of
this
part).
(
3)
Surface
coating
of
plastic
and
wood
subject
to
the
NESHAP
for
wood
furniture
manufacturing
facilities
(
subpart
JJ
of
this
part).
(
4)
Surface
coating
of
plastic
and
metal
subject
to
the
NESHAP
for
large
appliance
surface
coating
(
subpart
NNNN
of
this
part).
(
5)
Surface
coating
of
plastic
and
metal
subject
to
the
NESHAP
for
metal
furniture
surface
coating.
1
(
6)
Surface
coating
of
plastic
and
wood
subject
to
the
NESHAP
for
wood
building
products
surface
coating.
2
(
7)
In
mold
coating
operations
or
gel
coating
operations
in
the
manufacture
of
reinforced
plastic
composite
parts
subject
to
the
NESHAP
for
reinforced
plastics
composites
production.
3
(
8)
Surface
coating
of
parts
that
are
pre
assembled
from
plastic
and
metal
components,
where
greater
than
50
percent
of
the
coatings
(
by
volume,
determined
on
a
rolling
12
month
basis)
are
applied
to
the
metal
surfaces,
and
where
the
source
is
subject
to
the
NESHAP
for
miscellaneous
metal
parts
surface
coating.
4
If
your
source
is
subject
to
the
NESHAP
for
miscellaneous
metal
parts
surface
coating
5
and
you
can
demonstrate
that
more
than
50
percent
of
coatings
are
applied
to
metal
surfaces,
then
compliance
with
the
NESHAP
for
miscellaneous
metal
parts
surface
coating
6
constitutes
compliance
with
subpart
PPPP.
You
must
maintain
records
(
such
as
coating
usage
or
surface
area)
to
document
that
more
than
50
percent
of
coatings
are
applied
to
metal
surfaces.
(
9)
Surface
coating
that
occurs
at
research
or
laboratory
facilities
or
is
part
of
janitorial,
building,
and
facility
maintenance
operations,
or
hobby
shops
that
are
operated
for
personal
rather
than
commercial
purposes.
(
10)
Surface
coating
of
magnet
wire.
(
11)
Surface
coating
of
fiberglass
boats
or
parts
of
fiberglass
boats
where
the
facility
is
subject
to
the
requirements
for
fiberglass
boat
manufacturing
facilities
in
the
NESHAP
for
boat
manufacturing
(
subpart
VVVV
of
this
part),
except
where
the
surface
coating
of
the
boat
is
a
post
mold
coating
operation
performed
on
personal
watercraft
or
parts
of
personal
watercraft.
This
subpart
applies
to
post
mold
coating
operations
performed
on
personal
watercraft
or
parts
of
personal
watercraft.
For
the
purposes
of
this
subpart,
a
personal
watercraft
is
defined
as
a
vessel
(
boat)
which
uses
an
inboard
motor
powering
a
water
jet
pump
as
its
primary
source
of
motive
power
and
which
is
designed
to
be
operated
by
a
person
or
persons
sitting,
standing,
or
kneeling
on
the
vessel,
rather
than
in
the
conventional
manner
of
sitting
or
standing
inside
the
vessel.
(
12)
Operations
where
plastic
is
extruded
onto
the
plastic
part
or
product
to
form
a
coating.
(
d)
If
you
own
or
operate
an
affected
source
that
is
subject
to
this
subpart
and
at
the
same
affected
source
you
also
perform
surface
coating
subject
to
any
other
NESHAP
in
this
part,
you
may
choose
to
be
subject
to
the
requirements
of
the
more
stringent
of
the
subparts
for
the
entire
surface
coating
facility.
If
you
choose
to
be
subject
to
the
requirements
of
another
subpart
and
demonstrate
that,
by
doing
so,
your
facility
wide
HAP
emissions
in
kilograms
(
kg)
per
year
(
tons
per
year)
from
surface
coating
operations
will
be
less
than
or
equal
to
the
emissions
achieved
by
complying
separately
with
all
applicable
subparts,
compliance
with
the
more
stringent
NESHAP
will
constitute
compliance
with
this
subpart.
§
63.4482
What
parts
of
my
plant
does
this
subpart
cover?
(
a)
This
subpart
applies
to
each
new,
reconstructed,
and
existing
affected
source
within
each
of
the
four
subcategories
listed
in
§
63.4481(
a).
(
b)
The
affected
source
is
the
collection
of
all
of
the
items
listed
in
paragraphs
(
b)(
1)
through
(
4)
of
this
section
that
are
used
for
surface
coating
of
plastic
parts
and
products
within
each
subcategory:
(
1)
All
coating
operations
as
defined
in
§
63.4581;
(
2)
All
storage
containers
and
mixing
vessels
in
which
coatings,
thinners
and
other
additives,
and
cleaning
materials
are
stored
or
mixed;
(
3)
All
manual
and
automated
equipment
and
containers
used
for
conveying
coatings,
thinners
and
other
additives,
and
cleaning
materials;
and
(
4)
All
storage
containers
and
all
manual
and
automated
equipment
and
containers
used
for
conveying
waste
materials
generated
by
a
coating
operation.
(
c)
An
affected
source
is
a
new
source
if
it
meets
the
criteria
in
paragraph
(
c)(
1)
of
this
section
and
the
criteria
in
either
paragraph
(
c)(
2)
or
(
3)
of
this
section.
(
1)
You
commenced
the
construction
of
the
source
after
December
4,
2002,
by
installing
new
coating
equipment.
(
2)
The
new
coating
equipment
is
used
to
coat
plastic
parts
and
products
at
a
source
where
no
plastic
parts
surface
coating
was
previously
performed.
(
3)
The
new
coating
equipment
is
used
to
perform
plastic
parts
and
products
coating
in
a
subcategory
that
was
not
previously
performed.
(
d)
An
affected
source
is
reconstructed
if
you
meet
the
criteria
as
defined
in
§
63.2.
(
e)
An
affected
source
is
existing
if
it
is
not
new
or
reconstructed.
§
63.4483
When
do
I
have
to
comply
with
this
subpart?
The
date
by
which
you
must
comply
with
this
subpart
is
called
the
compliance
date.
The
compliance
date
for
each
type
of
affected
source
is
specified
in
paragraphs
(
a)
through
(
c)
of
this
section.
The
compliance
date
begins
the
initial
compliance
period
during
which
you
conduct
the
initial
compliance
demonstration
described
in
§
§
63.4540,
63.4550,
and
63.4560.
(
a)
For
a
new
or
reconstructed
affected
source,
the
compliance
date
is
the
applicable
date
in
paragraph
(
a)(
1)
or
(
2)
of
this
section:
(
1)
If
the
initial
startup
of
your
new
or
reconstructed
affected
source
is
before
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register],
the
compliance
date
is
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register].
(
2)
If
the
initial
startup
of
your
new
or
reconstructed
affected
source
occurs
after
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register],
the
compliance
date
is
the
date
of
initial
startup
of
your
affected
source.
(
b)
For
an
existing
affected
source,
the
compliance
date
is
the
date
3
years
after
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register].
(
c)
For
an
area
source
that
increases
its
emissions
or
its
potential
to
emit
such
that
it
becomes
a
major
source
of
HAP
emissions,
the
compliance
date
is
specified
in
paragraphs
(
c)(
1)
and
(
2)
of
this
section.
(
1)
For
any
portion
of
the
source
that
becomes
a
new
or
reconstructed
affected
source
subject
to
this
subpart,
the
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No.
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/
Wednesday,
December
4,
2002
/
Proposed
Rules
compliance
date
is
the
date
of
initial
startup
of
the
affected
source
or
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register],
whichever
is
later.
(
2)
For
any
portion
of
the
source
that
becomes
an
existing
affected
source
subject
to
this
subpart,
the
compliance
date
is
the
date
1
year
after
the
area
source
becomes
a
major
source
or
3
years
after
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register],
whichever
is
later.
(
d)
You
must
meet
the
notification
requirements
in
§
63.4510
according
to
the
dates
specified
in
that
section
and
in
subpart
A
of
this
part.
Some
of
the
notifications
must
be
submitted
before
the
compliance
dates
described
in
paragraphs
(
a)
through
(
c)
of
this
section.
Emission
Limitations
§
63.4490
What
emission
limits
must
I
meet?
(
a)
For
a
new
or
reconstructed
affected
source,
you
must
limit
organic
HAP
emissions
to
the
atmosphere
from
the
affected
source
to
the
applicable
limit
specified
in
paragraphs
(
a)(
1)
through
(
4)
of
this
section,
determined
according
to
the
requirements
in
§
63.4541,
§
63.4551,
or
§
63.4561.
(
1)
For
each
new
general
use
coating
affected
source,
limit
organic
HAP
emissions
to
no
more
than
0.16
kg
(
0.16
pound
(
lb))
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used
during
each
12
month
compliance
period.
(
2)
For
each
new
headlamp
coating
affected
source,
limit
organic
HAP
emissions
to
no
more
than
0.26
kg
(
0.26
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used
during
each
12
month
compliance
period.
(
3)
For
each
new
TPO
coating
affected
source,
limit
organic
HAP
emissions
to
no
more
than
0.17
kg
(
0.17
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used
during
each
12
month
compliance
period.
(
4)
For
each
new
assembled
on
road
vehicle
coating
affected
source,
limit
organic
HAP
emissions
to
no
more
than
1.34
kg
(
1.34
lb)
of
organic
HAP
emitted
per
kg
(
lb)
of
coating
solids
used
during
each
12
month
compliance
period.
(
b)
For
an
existing
affected
source,
you
must
limit
organic
HAP
emissions
to
the
atmosphere
from
the
affected
source
to
the
applicable
limit
specified
in
paragraphs
(
b)(
1)
through
(
4)
of
this
section,
determined
according
to
the
requirements
in
§
63.4541,
§
63.4551,
or
§
63.4561.
(
1)
For
each
existing
general
use
coating
affected
source,
limit
organic
HAP
emissions
to
no
more
than
0.16
kg
(
0.16
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used
during
each
12
month
compliance
period.
(
2)
For
each
existing
headlamp
coating
affected
source,
limit
organic
HAP
emissions
to
no
more
than
0.45
kg
(
0.45
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used
during
each
12
month
compliance
period.
(
3)
For
each
existing
TPO
coating
affected
source,
limit
organic
HAP
emissions
to
no
more
than
0.23
kg
(
0.23
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used
during
each
12
month
compliance
period.
(
4)
For
each
existing
assembled
onroad
vehicle
coating
affected
source,
limit
organic
HAP
emissions
to
no
more
than
1.34
kg
(
1.34
lb)
of
organic
HAP
emitted
per
kg
(
lb)
of
coating
solids
used
during
each
12
month
compliance
period.
§
63.4491
What
are
my
options
for
meeting
the
emission
limits?
You
must
include
all
coatings
(
as
defined
in
§
63.4581),
thinners
and
other
additives,
and
cleaning
materials
used
in
the
affected
source
when
determining
whether
the
organic
HAP
emission
rate
is
equal
to
or
less
than
the
applicable
emission
limit
in
§
63.4490.
To
make
this
determination,
you
must
use
at
least
one
of
the
three
compliance
options
listed
in
paragraphs
(
a)
through
(
c)
of
this
section.
You
may
apply
any
of
the
compliance
options
to
an
individual
coating
operation,
or
to
multiple
coating
operations
as
a
group,
or
to
the
entire
affected
source.
You
may
use
different
compliance
options
for
different
coating
operations,
or
at
different
times
on
the
same
coating
operation.
However,
you
may
not
use
different
compliance
options
at
the
same
time
on
the
same
coating
operation.
If
you
switch
between
compliance
options
for
any
coating
operation
or
group
of
coating
operations,
you
must
document
this
switch
as
required
by
§
63.4530(
c),
and
you
must
report
it
in
the
next
semiannual
compliance
report
required
in
§
63.4520.
(
a)
Compliant
material
option.
Demonstrate
that
the
organic
HAP
content
of
each
coating
used
in
the
coating
operation(
s)
is
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4490,
and
that
each
thinner,
other
additive,
and
cleaning
material
used
contains
no
organic
HAP.
You
must
meet
all
the
requirements
of
§
§
63.4540,
63.4541,
and
63.4542
to
demonstrate
compliance
with
the
applicable
emission
limit
using
this
option.
(
b)
Emission
rate
without
add
on
controls
option.
Demonstrate
that,
based
on
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
in
the
coating
operation(
s),
the
organic
HAP
emission
rate
for
the
coating
operation(
s)
is
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4490,
calculated
as
a
rolling
12
month
emission
rate
and
determined
on
a
monthly
basis.
You
must
meet
all
the
requirements
of
§
§
63.4550,
63.4551,
and
63.4552
to
demonstrate
compliance
with
the
emission
limit
using
this
option.
(
c)
Emission
rate
with
add
on
controls
option.
Demonstrate
that,
based
on
the
coatings,
thinners
and
other
additives,
cleaning
materials
used
in
the
coating
operation(
s),
and
the
emissions
reductions
achieved
by
emission
capture
systems
and
add
on
controls,
the
organic
HAP
emission
rate
for
the
coating
operation(
s)
is
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4490,
calculated
as
a
rolling
12
month
emission
rate
and
determined
on
a
monthly
basis.
If
you
use
this
compliance
option,
you
must
also
demonstrate
that
all
emission
capture
systems
and
add
on
control
devices
for
the
coating
operation(
s)
meet
the
operating
limits
required
in
§
63.4492,
except
for
solvent
recovery
systems
for
which
you
conduct
liquid
liquid
material
balances
according
to
§
63.4561(
j),
and
that
you
meet
the
work
practice
standards
required
in
§
63.4493.
You
must
meet
all
the
requirements
of
§
§
63.4560
through
63.4568
to
demonstrate
compliance
with
the
emission
limits,
operating
limits,
and
work
practice
standards
using
this
option.
§
63.4492
What
operating
limits
must
I
meet?
(
a)
For
any
coating
operation(
s)
on
which
you
use
the
compliant
material
option
or
the
emission
rate
without
addon
controls
option,
you
are
not
required
to
meet
any
operating
limits.
(
b)
For
any
controlled
coating
operation(
s)
on
which
you
use
the
emission
rate
with
add
on
controls
option,
except
those
for
which
you
use
a
solvent
recovery
system
and
conduct
a
liquid
liquid
material
balance
according
to
§
63.4561(
j),
you
must
meet
the
operating
limits
specified
in
table
1
of
this
subpart.
These
operating
limits
apply
to
the
emission
capture
and
control
systems
on
the
coating
operation(
s)
for
which
you
use
this
option,
and
you
must
establish
the
operating
limits
during
the
performance
test
according
to
the
requirements
in
§
63.4567.
You
must
meet
the
operating
limits
at
all
times
after
you
establish
them.
(
c)
If
you
use
an
add
on
control
device
other
than
those
listed
in
table
1
of
this
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Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
subpart,
or
wish
to
monitor
an
alternative
parameter
and
comply
with
a
different
operating
limit,
you
must
apply
to
the
Administrator
for
approval
of
alternative
monitoring
under
§
63.8(
f).
§
63.4493
What
work
practice
standards
must
I
meet?
(
a)
For
any
coating
operation(
s)
on
which
you
use
the
compliant
material
option
or
the
emission
rate
without
addon
controls
option,
you
are
not
required
to
meet
any
work
practice
standards.
(
b)
If
you
use
the
emission
rate
with
add
on
controls
option,
you
must
develop
and
implement
a
work
practice
plan
to
minimize
organic
HAP
emissions
from
the
storage,
mixing,
and
conveying
of
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
in,
and
waste
materials
generated
by,
the
controlled
coating
operation(
s)
for
which
you
use
this
option;
or
you
must
meet
an
alternative
standard
as
provided
in
paragraph
(
c)
of
this
section.
The
plan
must
specify
practices
and
procedures
to
ensure
that,
at
a
minimum,
the
elements
specified
in
paragraphs
(
b)(
1)
through
(
5)
of
this
section
are
implemented.
(
1)
All
organic
HAP
containing
coatings,
thinners
and
other
additives,
cleaning
materials,
and
waste
materials
must
be
stored
in
closed
containers.
(
2)
Spills
of
organic
HAP
containing
coatings,
thinners
and
other
additives,
cleaning
materials,
and
waste
materials
must
be
minimized.
(
3)
Organic
HAP
containing
coatings,
thinners
and
other
additives,
cleaning
materials,
and
waste
materials
must
be
conveyed
from
one
location
to
another
in
closed
containers
or
pipes.
(
4)
Mixing
vessels
which
contain
organic
HAP
containing
coatings
and
other
materials
must
be
closed
except
when
adding
to,
removing,
or
mixing
the
contents.
(
5)
Emissions
of
organic
HAP
must
be
minimized
during
cleaning
of
storage,
mixing,
and
conveying
equipment.
(
c)
As
provided
in
§
63.6(
g),
we,
the
U.
S.
Environmental
Protection
Agency
(
EPA),
may
choose
to
grant
you
permission
to
use
an
alternative
to
the
work
practice
standards
in
this
section.
General
Compliance
Requirements
§
63.4500
What
are
my
general
requirements
for
complying
with
this
subpart?
(
a)
You
must
be
in
compliance
with
the
emission
limitations
in
this
subpart
as
specified
in
paragraphs
(
a)(
1)
and
(
2)
of
this
section.
(
1)
Any
coating
operation(
s)
for
which
you
use
the
compliant
material
option
or
the
emission
rate
without
add
on
controls
option,
as
specified
in
§
63.4491(
a)
and
(
b),
must
be
in
compliance
with
the
applicable
emission
limit
in
§
63.4490
at
all
times.
(
2)
Any
coating
operation(
s)
for
which
you
use
the
emission
rate
with
add
on
controls
option,
as
specified
in
§
63.4491(
c),
must
be
in
compliance
with
the
emission
limitations
as
specified
in
paragraphs
(
a)(
2)(
i)
through
(
iii)
of
this
section.
(
i)
The
coating
operation(
s)
must
be
in
compliance
with
the
applicable
emission
limit
in
§
63.4490
at
all
times
except
during
periods
of
startup,
shutdown,
and
malfunction.
(
ii)
The
coating
operation(
s)
must
be
in
compliance
with
the
operating
limits
for
emission
capture
systems
and
addon
control
devices
required
by
§
63.4492
at
all
times
except
during
periods
of
startup,
shutdown,
and
malfunction,
and
except
for
solvent
recovery
systems
for
which
you
conduct
liquid
liquid
material
balances
according
to
§
63.4561(
j).
(
iii)
The
coating
operation(
s)
must
be
in
compliance
with
the
work
practice
standards
in
§
63.4493
at
all
times.
(
b)
You
must
always
operate
and
maintain
your
affected
source,
including
all
air
pollution
control
and
monitoring
equipment
you
use
for
purposes
of
complying
with
this
subpart,
according
to
the
provisions
in
§
63.6(
e)(
1)(
i).
(
c)
If
your
affected
source
uses
an
emission
capture
system
and
add
on
control
device,
you
must
develop
and
implement
a
written
startup,
shutdown,
and
malfunction
plan
according
to
the
provisions
in
§
63.6(
e)(
3).
The
plan
must
address
the
startup,
shutdown,
and
corrective
actions
in
the
event
of
a
malfunction
of
the
emission
capture
system
or
the
add
on
control
device.
The
plan
must
also
address
any
coating
operation
equipment
that
may
cause
increased
emissions
or
that
would
affect
capture
efficiency
if
the
process
equipment
malfunctions,
such
as
conveyors
that
move
parts
among
enclosures.
§
63.4501
What
parts
of
the
General
Provisions
apply
to
me?
Table
2
of
this
subpart
shows
which
parts
of
the
General
Provisions
in
§
§
63.1
through
63.15
apply
to
you.
Notifications,
Reports,
and
Records
§
63.4510
What
notifications
must
I
submit?
(
a)
General.
You
must
submit
the
notifications
in
§
§
63.7(
b)
and
(
c),
63.8(
f)(
4),
and
63.9(
b)
through
(
e)
and
(
h)
that
apply
to
you
by
the
dates
specified
in
those
sections,
except
as
provided
in
paragraphs
(
b)
and
(
c)
of
this
section.
(
b)
Initial
notification.
You
must
submit
the
Initial
Notification
required
by
§
63.9(
b)
for
a
new
or
reconstructed
affected
source
no
later
than
120
days
after
initial
startup
or
120
days
after
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register],
whichever
is
later.
For
an
existing
affected
source,
you
must
submit
the
Initial
Notification
no
later
than
1
year
after
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register].
(
c)
Notification
of
compliance
status.
You
must
submit
the
Notification
of
Compliance
Status
required
by
§
63.9(
h)
no
later
than
30
calendar
days
following
the
end
of
the
initial
compliance
period
described
in
§
63.4540,
§
63.4550,
or
§
63.4560
that
applies
to
your
affected
source.
The
Notification
of
Compliance
Status
must
contain
the
information
specified
in
paragraphs
(
c)(
1)
through
(
9)
of
this
section
and
in
§
63.9(
h).
(
1)
Company
name
and
address.
(
2)
Statement
by
a
responsible
official
with
that
official's
name,
title,
and
signature,
certifying
the
truth,
accuracy,
and
completeness
of
the
content
of
the
report.
(
3)
Date
of
the
report
and
beginning
and
ending
dates
of
the
reporting
period.
The
reporting
period
is
the
initial
compliance
period
described
in
§
63.4540,
§
63.4550,
or
§
63.4560
that
applies
to
your
affected
source.
(
4)
Identification
of
the
compliance
option
or
options
specified
in
§
63.4491
that
you
used
on
each
coating
operation
in
the
affected
source
during
the
initial
compliance
period.
(
5)
Statement
of
whether
or
not
the
affected
source
achieved
the
emission
limitations
for
the
initial
compliance
period.
(
6)
If
you
had
a
deviation,
include
the
information
in
paragraphs
(
c)(
6)(
i)
and
(
ii)
of
this
section.
(
i)
A
description
and
statement
of
the
cause
of
the
deviation.
(
ii)
If
you
failed
to
meet
the
applicable
emission
limit
in
§
63.4490,
include
all
the
calculations
you
used
to
determine
the
kg
(
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used.
You
do
not
need
to
submit
information
provided
by
the
materials
suppliers
or
manufacturers,
or
test
reports.
(
7)
For
each
of
the
data
items
listed
in
paragraphs
(
c)(
7)(
i)
through
(
iv)
of
this
section
that
is
required
by
the
compliance
option(
s)
you
used
to
demonstrate
compliance
with
the
emission
limit,
include
an
example
of
how
you
determined
the
value,
including
calculations
and
supporting
data.
Supporting
data
can
include
a
copy
of
the
information
provided
by
the
supplier
or
manufacturer
of
the
example
coating
or
material,
or
a
summary
of
the
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Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
results
of
testing
conducted
according
to
§
63.4541(
a),
(
b),
or
(
c).
You
do
not
need
to
submit
copies
of
any
test
reports.
(
i)
Mass
fraction
of
organic
HAP
for
one
coating,
for
one
thinner
or
other
additive,
and
for
one
cleaning
material.
(
ii)
Mass
fraction
of
coating
solids
for
one
coating.
(
iii)
Density
for
one
coating,
one
thinner
or
other
additive,
and
one
cleaning
material,
except
that
if
you
use
the
compliant
material
option,
only
the
example
coating
density
is
required.
(
iv)
The
amount
of
waste
materials
and
the
mass
of
organic
HAP
contained
in
the
waste
materials
for
which
you
are
claiming
an
allowance
in
Equation
1
of
§
63.4551.
(
8)
The
calculation
of
kg
(
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used
for
the
compliance
option(
s)
you
used,
as
specified
in
paragraphs
(
c)(
8)(
i)
through
(
iii)
of
this
section.
(
i)
For
the
compliant
material
option,
provide
an
example
calculation
of
the
organic
HAP
content
for
one
coating,
using
Equation
1
of
§
63.4541.
(
ii)
For
the
emission
rate
without
addon
controls
option,
provide
the
calculation
of
the
total
mass
of
organic
HAP
emissions
for
each
month;
the
calculation
of
the
total
mass
of
coating
solids
used
each
month;
and
the
calculation
of
the
12
month
organic
HAP
emission
rate,
using
Equations
1
and
1A
through
1C,
2,
and
3,
respectively,
of
§
63.4551.
(
iii)
For
the
emission
rate
with
add
on
controls
option,
provide
the
calculation
of
the
total
mass
of
organic
HAP
emissions
for
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
each
month,
using
Equations
1
and
1A
through
1C
of
§
63.4551;
the
calculation
of
the
total
mass
of
coating
solids
used
each
month
using
Equation
2
of
§
63.4551;
the
mass
of
organic
HAP
emission
reduction
each
month
by
emission
capture
systems
and
add
on
control
devices,
using
Equations
1
and
1A
through
1D
of
§
63.4561
and
Equations
2,
3,
and
3A
through
3C
of
§
63.4561,
as
applicable;
the
calculation
of
the
total
mass
of
organic
HAP
emissions
each
month,
using
Equation
4
of
§
63.4561;
and
the
calculation
of
the
12
month
organic
HAP
emission
rate,
using
Equation
5
of
§
63.4561.
(
9)
For
the
emission
rate
with
add
on
controls
option,
you
must
include
the
information
specified
in
paragraphs
(
c)(
9)(
i)
through
(
iv)
of
this
section,
except
that
the
requirements
in
paragraphs
(
c)(
9)(
i)
through
(
iii)
of
this
section
do
not
apply
to
solvent
recovery
systems
for
which
you
conduct
liquidliquid
material
balances
according
to
§
63.4561(
j).
(
i)
For
each
emission
capture
system,
a
summary
of
the
data
and
copies
of
the
calculations
supporting
the
determination
that
the
emission
capture
system
is
a
permanent
total
enclosure
(
PTE)
or
a
measurement
of
the
emission
capture
system
efficiency.
Include
a
description
of
the
protocol
followed
for
measuring
capture
efficiency,
summaries
of
any
capture
efficiency
tests
conducted,
and
any
calculations
supporting
the
capture
efficiency
determination.
If
you
use
the
data
quality
objective
(
DQO)
or
lower
confidence
limit
(
LCL)
approach,
you
must
also
include
the
statistical
calculations
to
show
you
meet
the
DQO
or
LCL
criteria
in
appendix
A
to
subpart
KK
of
this
part.
You
do
not
need
to
submit
complete
test
reports.
(
ii)
A
summary
of
the
results
of
each
add
on
control
device
performance
test.
You
do
not
need
to
submit
complete
test
reports.
(
iii)
A
list
of
each
emission
capture
system's
and
add
on
control
device's
operating
limits
and
a
summary
of
the
data
used
to
calculate
those
limits.
(
iv)
A
statement
of
whether
or
not
you
developed
and
implemented
the
work
practice
plan
required
by
§
63.4493.
§
63.4520
What
reports
must
I
submit?
(
a)
Semiannual
compliance
reports.
You
must
submit
semiannual
compliance
reports
for
each
affected
source
according
to
the
requirements
of
paragraphs
(
a)(
1)
through
(
7)
of
this
section.
The
semiannual
compliance
reporting
requirements
may
be
satisfied
by
reports
required
under
other
parts
of
the
Clean
Air
Act
(
CAA),
as
specified
in
paragraph
(
a)(
2)
of
this
section.
(
1)
Dates.
Unless
the
Administrator
has
approved
a
different
schedule
for
submission
of
reports
under
§
63.10(
a),
you
must
prepare
and
submit
each
semiannual
compliance
report
according
to
the
dates
specified
in
paragraphs
(
a)(
1)(
i)
through
(
iv)
of
this
section.
Note
that
the
information
reported
for
each
of
the
months
in
the
reporting
period
will
be
based
on
the
last
12
months
of
data
prior
to
the
date
of
each
monthly
calculation.
(
i)
The
first
semiannual
compliance
report
must
cover
the
first
semiannual
reporting
period
which
begins
the
day
after
the
end
of
the
initial
compliance
period
described
in
§
63.4540,
§
63.4550,
or
§
63.4560
that
applies
to
your
affected
source
and
ends
on
June
30
or
December
31,
whichever
occurs
first
following
the
end
of
the
initial
compliance
period.
(
ii)
Each
subsequent
semiannual
compliance
report
must
cover
the
subsequent
semiannual
reporting
period
from
January
1
through
June
30
or
the
semiannual
reporting
period
from
July
1
through
December
31.
(
iii)
Each
semiannual
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
is
the
first
date
following
the
end
of
the
semiannual
reporting
period.
(
iv)
For
each
affected
source
that
is
subject
to
permitting
regulations
pursuant
to
40
CFR
part
70
or
40
CFR
part
71,
and
if
the
permitting
authority
has
established
dates
for
submitting
semiannual
reports
pursuant
to
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
you
may
submit
the
first
and
subsequent
compliance
reports
according
to
the
dates
the
permitting
authority
has
established
instead
of
according
to
the
date
specified
in
paragraph
(
a)(
1)(
iii)
of
this
section.
(
2)
Inclusion
with
title
V
report.
Each
affected
source
that
has
obtained
a
title
V
operating
permit
pursuant
to
40
CFR
part
70
or
40
CFR
part
71
must
report
all
deviations
as
defined
in
this
subpart
in
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A).
If
an
affected
source
submits
a
semiannual
compliance
report
pursuant
to
this
section
along
with,
or
as
part
of,
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
and
the
semiannual
compliance
report
includes
all
required
information
concerning
deviations
from
any
emission
limitation
in
this
subpart,
its
submission
will
be
deemed
to
satisfy
any
obligation
to
report
the
same
deviations
in
the
semiannual
monitoring
report.
However,
submission
of
a
semiannual
compliance
report
shall
not
otherwise
affect
any
obligation
the
affected
source
may
have
to
report
deviations
from
permit
requirements
to
the
permitting
authority.
(
3)
General
requirements.
The
semiannual
compliance
report
must
contain
the
information
specified
in
paragraphs
(
a)(
3)(
i)
through
(
v)
of
this
section,
and
the
information
specified
in
paragraphs
(
a)(
4)
through
(
7)
and
(
c)(
1)
of
this
section
that
is
applicable
to
your
affected
source.
(
i)
Company
name
and
address.
(
ii)
Statement
by
a
responsible
official
with
that
official's
name,
title,
and
signature,
certifying
the
truth,
accuracy,
and
completeness
of
the
content
of
the
report.
(
iii)
Date
of
report
and
beginning
and
ending
dates
of
the
reporting
period.
The
reporting
period
is
the
6
month
period
ending
on
June
30
or
December
31.
Note
that
the
information
reported
for
each
of
the
6
months
in
the
reporting
period
will
be
based
on
the
last
12
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months
of
data
prior
to
the
date
of
each
monthly
calculation.
(
iv)
Identification
of
the
compliance
option
or
options
specified
in
§
63.4491
that
you
used
on
each
coating
operation
during
the
reporting
period.
If
you
switched
between
compliance
options
during
the
reporting
period,
you
must
report
the
beginning
and
ending
dates
you
used
each
option.
(
v)
If
you
used
the
emission
rate
without
add
on
controls
or
the
emission
rate
with
add
on
controls
compliance
option
(
§
63.4491(
b)
or
(
c)),
the
calculation
results
for
each
rolling
12
month
organic
HAP
emission
rate
during
the
6
month
reporting
period.
(
4)
No
deviations.
If
there
were
no
deviations
from
the
emission
limitations
in
§
§
63.4490,
63.4492,
and
63.4493
that
apply
to
you,
the
semiannual
compliance
report
must
include
a
statement
that
there
were
no
deviations
from
the
emission
limitations
during
the
reporting
period.
If
you
used
the
emission
rate
with
add
on
controls
option
and
there
were
no
periods
during
which
the
continuous
parameter
monitoring
systems
(
CPMS)
were
out
ofcontrol
as
specified
in
§
63.8(
c)(
7),
the
semiannual
compliance
report
must
include
a
statement
that
there
were
no
periods
during
which
the
CPMS
were
out
of
control
during
the
reporting
period.
(
5)
Deviations:
Compliant
material
option.
If
you
used
the
compliant
material
option
and
there
was
a
deviation
from
the
applicable
HAP
content
requirements
in
§
63.4490,
the
semiannual
compliance
report
must
contain
the
information
in
paragraphs
(
a)(
5)(
i)
through
(
iv)
of
this
section.
(
i)
Identification
of
each
coating
used
that
deviated
from
the
applicable
emission
limit,
and
each
thinner,
other
additive,
and
cleaning
material
used
that
contained
organic
HAP,
and
the
dates
and
time
periods
each
was
used.
(
ii)
The
calculation
of
the
organic
HAP
content
(
using
Equation
1
of
§
63.4541)
for
each
coating
identified
in
paragraph
(
a)(
5)(
i)
of
this
section.
You
do
not
need
to
submit
background
data
supporting
this
calculation
(
e.
g.,
information
provided
by
coating
suppliers
or
manufacturers,
or
test
reports).
(
iii)
The
determination
of
mass
fraction
of
organic
HAP
for
each
thinner,
other
additive,
and
cleaning
material
identified
in
paragraph
(
a)(
5)(
i)
of
this
section.
You
do
not
need
to
submit
background
data
supporting
this
calculation
(
e.
g.,
information
provided
by
material
suppliers
or
manufacturers,
or
test
reports).
(
iv)
A
statement
of
the
cause
of
each
deviation.
(
6)
Deviations:
Emission
rate
without
add
on
controls
option.
If
you
used
the
emission
rate
without
add
on
controls
option
and
there
was
a
deviation
from
the
applicable
emission
limit
in
§
63.4490,
the
semiannual
compliance
report
must
contain
the
information
in
paragraphs
(
a)(
6)(
i)
through
(
iii)
of
this
section.
(
i)
The
beginning
and
ending
dates
of
each
compliance
period
during
which
the
12
month
organic
HAP
emission
rate
exceeded
the
applicable
emission
limit
in
§
63.4490.
(
ii)
The
calculations
used
to
determine
the
12
month
organic
HAP
emission
rate
for
the
compliance
period
in
which
the
deviation
occurred.
You
must
submit
the
calculations
for
Equations
1,
1A
through
1C,
2,
and
3
of
§
63.4551;
and
if
applicable,
the
calculation
used
to
determine
mass
of
organic
HAP
in
waste
materials
according
to
§
63.4551(
e)(
4).
You
do
not
need
to
submit
background
data
supporting
these
calculations
(
e.
g.,
information
provided
by
materials
suppliers
or
manufacturers,
or
test
reports).
(
iii)
A
statement
of
the
cause
of
each
deviation.
(
7)
Deviations:
Emission
rate
with
add
on
controls
option.
If
you
used
the
emission
rate
with
add
on
controls
option
and
there
was
a
deviation
from
an
emission
limitation
(
including
any
periods
when
emissions
bypassed
the
add
on
control
device
and
were
diverted
to
the
atmosphere),
the
semiannual
compliance
report
must
contain
the
information
in
paragraphs
(
a)(
7)(
i)
through
(
xiv)
of
this
section.
This
includes
periods
of
startup,
shutdown,
and
malfunction
during
which
deviations
occurred.
(
i)
The
beginning
and
ending
dates
of
each
compliance
period
during
which
the
12
month
organic
HAP
emission
rate
exceeded
the
applicable
emission
limit
in
§
63.4490.
(
ii)
The
calculations
used
to
determine
the
12
month
organic
HAP
emission
rate
for
each
compliance
period
in
which
a
deviation
occurred.
You
must
provide
the
calculation
of
the
total
mass
of
organic
HAP
emissions
for
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
each
month,
using
Equations
1
and
1A
through
1C
of
§
63.4551;
and,
if
applicable,
the
calculation
used
to
determine
mass
of
organic
HAP
in
waste
materials
according
to
§
63.4551(
e)(
4);
the
calculation
of
the
total
mass
of
coating
solids
used
each
month,
using
Equation
2
of
§
63.4551;
the
calculation
of
the
mass
of
organic
HAP
emission
reduction
each
month
by
emission
capture
systems
and
add
on
control
devices,
using
Equations
1
and
1A
through
1D
of
§
63.4561,
and
Equations
2,
3,
and
3A
through
3C
of
§
63.4561,
as
applicable;
the
calculation
of
the
total
mass
of
organic
HAP
emissions
each
month,
using
Equation
4
of
§
63.4561;
and
the
calculation
of
the
12
month
organic
HAP
emission
rate,
using
Equation
5
of
§
63.4561.
You
do
not
need
to
submit
the
background
data
supporting
these
calculations
(
e.
g.,
information
provided
by
materials
suppliers
or
manufacturers,
or
test
reports).
(
iii)
The
date
and
time
that
each
malfunction
started
and
stopped.
(
iv)
A
brief
description
of
the
CPMS.
(
v)
The
date
of
the
latest
CPMS
certification
or
audit.
(
vi)
The
date
and
time
that
each
CPMS
was
inoperative,
except
for
zero
(
low
level)
and
high
level
checks.
(
vii)
The
date,
time,
and
duration
that
each
CPMS
was
out
of
control,
including
the
information
in
§
63.8(
c)(
8).
(
viii)
The
date
and
time
period
of
each
deviation
from
an
operating
limit
in
Table
1
of
this
subpart;
date
and
time
period
of
any
bypass
of
the
add
on
control
device;
and
whether
each
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction
or
during
another
period.
(
ix)
A
summary
of
the
total
duration
of
each
deviation
from
an
operating
limit
in
Table
1
of
this
subpart
and
each
bypass
of
the
add
on
control
device
during
the
semiannual
reporting
period,
and
the
total
duration
as
a
percent
of
the
total
source
operating
time
during
that
semiannual
reporting
period.
(
x)
A
breakdown
of
the
total
duration
of
the
deviations
from
the
operating
limits
in
Table
1
of
this
subpart
and
bypasses
of
the
add
on
control
device
during
the
semiannual
reporting
period
into
those
that
were
due
to
startup,
shutdown,
control
equipment
problems,
process
problems,
other
known
causes,
and
other
unknown
causes.
(
xi)
A
summary
of
the
total
duration
of
CPMS
downtime
during
the
semiannual
reporting
period
and
the
total
duration
of
CPMS
downtime
as
a
percent
of
the
total
source
operating
time
during
that
semiannual
reporting
period.
(
xii)
A
description
of
any
changes
in
the
CPMS,
coating
operation,
emission
capture
system,
or
add
on
control
device
since
the
last
semiannual
reporting
period.
(
xiii)
For
each
deviation
from
the
work
practice
standards,
a
description
of
the
deviation,
the
date
and
time
period
of
the
deviation,
and
the
actions
you
took
to
correct
the
deviation.
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2002
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Rules
(
xiv)
A
statement
of
the
cause
of
each
deviation.
(
b)
Performance
test
reports.
If
you
use
the
emission
rate
with
add
on
controls
option,
you
must
submit
reports
of
performance
test
results
for
emission
capture
systems
and
add
on
control
devices
no
later
than
60
days
after
completing
the
tests
as
specified
in
§
63.10(
d)(
2).
(
c)
Startup,
shutdown,
malfunction
reports.
If
you
used
the
emission
rate
with
add
on
controls
option
and
you
had
a
startup,
shutdown,
or
malfunction
during
the
semiannual
reporting
period,
you
must
submit
the
reports
specified
in
paragraphs
(
c)(
1)
and
(
2)
of
this
section.
(
1)
If
your
actions
were
consistent
with
your
startup,
shutdown,
and
malfunction
plan,
you
must
include
the
information
specified
in
§
63.10(
d)
in
the
semiannual
compliance
report
required
by
paragraph
(
a)
of
this
section.
(
2)
If
your
actions
were
not
consistent
with
your
startup,
shutdown,
and
malfunction
plan,
you
must
submit
an
immediate
startup,
shutdown,
and
malfunction
report
as
described
in
paragraph
(
c)(
2)(
i)
and
(
ii)
of
this
section.
(
i)
You
must
describe
the
actions
taken
during
the
event
in
a
report
delivered
by
facsimile,
telephone,
or
other
means
to
the
Administrator
within
2
working
days
after
starting
actions
that
are
inconsistent
with
the
plan.
(
ii)
You
must
submit
a
letter
to
the
Administrator
within
7
working
days
after
the
end
of
the
event,
unless
you
have
made
alternative
arrangements
with
the
Administrator
as
specified
in
§
63.10(
d)(
5)(
ii).
The
letter
must
contain
the
information
specified
in
§
63.10(
d)(
5)(
ii).
§
63.4530
What
records
must
I
keep?
You
must
collect
and
keep
records
of
the
data
and
information
specified
in
this
section.
Failure
to
collect
and
keep
these
records
is
a
deviation
from
the
applicable
standard.
(
a)
A
copy
of
each
notification
and
report
that
you
submitted
to
comply
with
this
subpart,
and
the
documentation
supporting
each
notification
and
report.
(
b)
A
current
copy
of
information
provided
by
materials
suppliers
or
manufacturers,
such
as
manufacturer's
formulation
data,
or
test
data
used
to
determine
the
mass
fraction
of
organic
HAP
and
density
for
each
coating,
thinner
or
other
additive
and
cleaning
material,
and
the
mass
fraction
of
coating
solids
for
each
coating.
If
you
conducted
testing
to
determine
mass
fraction
of
organic
HAP,
density,
or
mass
fraction
of
coating
solids,
you
must
keep
a
copy
of
the
complete
test
report.
If
you
use
information
provided
to
you
by
the
manufacturer
or
supplier
of
the
material
that
was
based
on
testing,
you
must
keep
the
summary
sheet
of
results
provided
to
you
by
the
manufacturer
or
supplier.
You
are
not
required
to
obtain
the
test
report
or
other
supporting
documentation
from
the
manufacturer
or
supplier.
(
c)
For
each
compliance
period,
the
records
specified
in
paragraphs
(
c)(
1)
through
(
4)
of
this
section.
(
1)
A
record
of
the
coating
operations
on
which
you
used
each
compliance
option
and
the
time
periods
(
beginning
and
ending
dates
and
times)
you
used
each
option.
(
2)
For
the
compliant
material
option,
a
record
of
the
calculation
of
the
organic
HAP
content
for
each
coating,
using
Equation
1
of
§
63.4541.
(
3)
For
the
emission
rate
without
addon
controls
option,
a
record
of
the
calculation
of
the
total
mass
of
organic
HAP
emissions
for
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
each
month,
using
Equations
1,
1A
through
1C,
and
2
of
§
63.4551
and,
if
applicable,
the
calculation
used
to
determine
mass
of
organic
HAP
in
waste
materials
according
to
§
63.4551(
e)(
4);
the
calculation
of
the
total
mass
of
coating
solids
used
each
month
using
Equation
2
of
§
63.4551;
and
the
calculation
of
each
12
month
organic
HAP
emission
rate,
using
Equation
3
of
§
63.4551.
(
4)
For
the
emission
rate
with
add
on
controls
option,
records
of
the
calculations
specified
in
paragraphs
(
c)(
4)(
i)
through
(
v)
of
this
section.
(
i)
The
calculation
of
the
total
mass
of
organic
HAP
emissions
for
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
each
month,
using
Equations
1
and
1A
through
1C
of
§
63.4551;
and
if
applicable,
the
calculation
used
to
determine
mass
of
organic
HAP
in
waste
materials
according
to
§
63.4551(
e)(
4);
(
ii)
The
calculation
of
the
total
mass
of
coating
solids
used
each
month,
using
Equation
2
of
§
63.4551;
(
iii)
The
calculation
of
the
mass
of
organic
HAP
emission
reduction
by
emission
capture
systems
and
add
on
control
devices,
using
Equations
1
and
1A
through
1D
of
§
63.4561
and
Equations
2,
3,
and
3A
through
3C
of
§
63.4561,
as
applicable;
(
iv)
The
calculation
of
each
month's
organic
HAP
emission
rate,
using
Equation
4
of
§
63.4561;
and
(
v)
The
calculation
of
each
12
month
organic
HAP
emission
rate,
using
Equation
5
of
§
63.4561.
(
d)
A
record
of
the
name
and
volume
of
each
coating,
thinner
or
other
additive,
and
cleaning
material
used
during
each
compliance
period.
If
you
are
using
the
compliant
material
option
for
all
coatings
at
the
source,
you
may
maintain
purchase
records
for
each
material
used
rather
than
a
record
of
the
volume
used.
(
e)
A
record
of
the
mass
fraction
of
organic
HAP
for
each
coating,
thinner
or
other
additive,
and
cleaning
material
used
during
each
compliance
period.
(
f)
A
record
of
the
mass
fraction
of
coating
solids
for
each
coating
used
during
each
compliance
period.
(
g)
If
you
use
either
the
emission
rate
without
add
on
controls
or
the
emission
rate
with
add
on
controls
compliance
option,
the
density
for
each
coating,
thinner
or
other
additive,
and
cleaning
material
used
during
each
compliance
period.
(
h)
If
you
use
an
allowance
in
Equation
1
of
§
63.4551
for
organic
HAP
contained
in
waste
materials
sent
to
or
designated
for
shipment
to
a
treatment,
storage,
and
disposal
facility
(
TSDF)
according
to
§
63.4551(
e)(
4),
you
must
keep
records
of
the
information
specified
in
paragraphs
(
h)(
1)
through
(
3)
of
this
section.
(
1)
The
name
and
address
of
each
TSDF
to
which
you
sent
waste
materials
for
which
you
use
an
allowance
in
Equation
1
of
§
63.4551,
a
statement
of
which
subparts
under
40
CFR
parts
262,
264,
265,
and
266
apply
to
the
facility,
and
the
date
of
each
shipment.
(
2)
Identification
of
the
coating
operations
producing
waste
materials
included
in
each
shipment
and
the
month
or
months
in
which
you
used
the
allowance
for
these
materials
in
Equation
1
of
§
63.4551.
(
3)
The
methodology
used
in
accordance
with
§
63.4551(
e)(
4)
to
determine
the
total
amount
of
waste
materials
sent
to
or
the
amount
collected,
stored,
and
designated
for
transport
to
a
TSDF
each
month;
and
the
methodology
to
determine
the
mass
of
organic
HAP
contained
in
these
waste
materials.
This
must
include
the
sources
for
all
data
used
in
the
determination,
methods
used
to
generate
the
data,
frequency
of
testing
or
monitoring,
and
supporting
calculations
and
documentation,
including
the
waste
manifest
for
each
shipment.
(
i)
[
Reserved]
(
j)
You
must
keep
records
of
the
date,
time,
and
duration
of
each
deviation.
(
k)
If
you
use
the
emission
rate
with
add
on
controls
option,
you
must
keep
the
records
specified
in
paragraphs
(
k)(
1)
through
(
8)
of
this
section.
(
1)
For
each
deviation,
a
record
of
whether
the
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction.
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/
Wednesday,
December
4,
2002
/
Proposed
Rules
(
2)
The
records
in
§
63.6(
e)(
3)(
iii)
through
(
v)
related
to
startup,
shutdown,
and
malfunction.
(
3)
The
records
required
to
show
continuous
compliance
with
each
operating
limit
specified
in
Table
1
of
this
subpart
that
applies
to
you.
(
4)
For
each
capture
system
that
is
a
PTE,
the
data
and
documentation
you
used
to
support
a
determination
that
the
capture
system
meets
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
a
PTE
and
has
a
capture
efficiency
of
100
percent,
as
specified
in
§
63.4565(
a).
(
5)
For
each
capture
system
that
is
not
a
PTE,
the
data
and
documentation
you
used
to
determine
capture
efficiency
according
to
the
requirements
specified
in
§
§
63.4564
and
63.4565(
b)
through
(
e),
including
the
records
specified
in
paragraphs
(
k)(
5)(
i)
through
(
iii)
of
this
section
that
apply
to
you.
(
i)
Records
for
a
liquid
to
uncaptured
gas
protocol
using
a
temporary
total
enclosure
or
building
enclosure.
Records
of
the
mass
of
total
volatile
hydrocarbon
(
TVH)
as
measured
by
Method
204A
or
F
of
appendix
M
to
40
CFR
part
51
for
each
material
used
in
the
coating
operation,
and
the
total
TVH
for
all
materials
used
during
each
capture
efficiency
test
run,
including
a
copy
of
the
test
report.
Records
of
the
mass
of
TVH
emissions
not
captured
by
the
capture
system
that
exited
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run,
as
measured
by
Method
204D
or
E
of
appendix
M
to
40
CFR
part
51,
including
a
copy
of
the
test
report.
Records
documenting
that
the
enclosure
used
for
the
capture
efficiency
test
met
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
either
a
temporary
total
enclosure
or
a
building
enclosure.
(
ii)
Records
for
a
gas
to
gas
protocol
using
a
temporary
total
enclosure
or
a
building
enclosure.
Records
of
the
mass
of
TVH
emissions
captured
by
the
emission
capture
system
as
measured
by
Method
204B
or
C
of
appendix
M
to
40
CFR
part
51
at
the
inlet
to
the
add
on
control
device,
including
a
copy
of
the
test
report.
Records
of
the
mass
of
TVH
emissions
not
captured
by
the
capture
system
that
exited
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run
as
measured
by
Method
204D
or
E
of
appendix
M
to
40
CFR
part
51,
including
a
copy
of
the
test
report.
Records
documenting
that
the
enclosure
used
for
the
capture
efficiency
test
met
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
either
a
temporary
total
enclosure
or
a
building
enclosure.
(
iii)
Records
for
an
alternative
protocol.
Records
needed
to
document
a
capture
efficiency
determination
using
an
alternative
method
or
protocol
as
specified
in
§
63.4565(
e),
if
applicable.
(
6)
The
records
specified
in
paragraphs
(
k)(
6)(
i)
and
(
ii)
of
this
section
for
each
add
on
control
device
organic
HAP
destruction
or
removal
efficiency
determination
as
specified
in
§
63.4566.
(
i)
Records
of
each
add
on
control
device
performance
test
conducted
according
to
§
§
63.4564
and
63.4566.
(
ii)
Records
of
the
coating
operation
conditions
during
the
add
on
control
device
performance
test
showing
that
the
performance
test
was
conducted
under
representative
operating
conditions.
(
7)
Records
of
the
data
and
calculations
you
used
to
establish
the
emission
capture
and
add
on
control
device
operating
limits
as
specified
in
§
63.4567
and
to
document
compliance
with
the
operating
limits
as
specified
in
Table
1
of
this
subpart.
(
8)
A
record
of
the
work
practice
plan
required
by
§
63.4493
and
documentation
that
you
are
implementing
the
plan
on
a
continuous
basis.
§
63.4531
In
what
form
and
for
how
long
must
I
keep
my
records?
(
a)
Your
records
must
be
in
a
form
suitable
and
readily
available
for
expeditious
review,
according
to
§
63.10(
b)(
1).
Where
appropriate,
the
records
may
be
maintained
as
electronic
spreadsheets
or
as
a
database.
(
b)
As
specified
in
§
63.10(
b)(
1),
you
must
keep
each
record
for
5
years
following
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record.
(
c)
You
must
keep
each
record
on
site
for
at
least
2
years
after
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record,
according
to
§
63.10(
b)(
1).
You
may
keep
the
records
off
site
for
the
remaining
3
years.
Compliance
Requirements
for
the
Compliant
Material
Option
§
63.4540
By
what
date
must
I
conduct
the
initial
compliance
demonstration?
You
must
complete
the
initial
compliance
demonstration
for
the
initial
compliance
period
according
to
the
requirements
in
§
63.4541.
The
initial
compliance
period
begins
on
the
applicable
compliance
date
specified
in
§
63.4483
and
ends
on
the
last
day
of
the
12th
month
following
the
compliance
date.
If
the
compliance
date
occurs
on
any
day
other
than
the
first
day
of
a
month,
then
the
initial
compliance
period
extends
through
that
month
plus
the
next
12
months.
The
initial
compliance
demonstration
includes
the
calculations
according
to
§
63.4541
and
supporting
documentation
showing
that
during
the
initial
compliance
period,
you
used
no
coating
with
an
organic
HAP
content
that
exceeded
the
applicable
emission
limit
in
§
63.4490,
and
that
you
used
no
thinners,
other
additives,
or
cleaning
materials
that
contained
organic
HAP
as
determined
according
to
§
63.4541(
a).
§
63.4541
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations?
You
may
use
the
compliant
material
option
for
any
individual
coating
operation,
for
any
group
of
coating
operations
in
the
affected
source,
or
for
all
the
coating
operations
in
the
affected
source.
You
must
use
either
the
emission
rate
without
add
on
controls
option
or
the
emission
rate
with
add
on
controls
option
for
any
coating
operation
in
the
affected
source
for
which
you
do
not
use
this
option.
To
demonstrate
initial
compliance
using
the
compliant
material
option,
the
coating
operation
or
group
of
coating
operations
must
use
no
coating
with
an
organic
HAP
content
that
exceeds
the
applicable
emission
limit
in
§
63.4490
and
must
use
no
thinner
or
other
additive,
or
cleaning
material
that
contains
organic
HAP
as
determined
according
to
this
section.
Any
coating
operation
for
which
you
use
the
compliant
material
option
is
not
required
to
meet
the
operating
limits
or
work
practice
standards
required
in
§
§
63.4492
and
63.4493,
respectively.
You
must
conduct
a
separate
initial
compliance
demonstration
for
each
general
use
coating,
TPO
coating,
headlamp
coating,
and
assembled
onroad
vehicle
coating
affected
source.
You
must
meet
all
the
requirements
of
this
section.
Use
the
procedures
in
this
section
on
each
coating,
thinner
or
other
additive,
and
cleaning
material
in
the
condition
it
is
in
when
it
is
received
from
its
manufacturer
or
supplier
and
prior
to
any
alteration.
You
do
not
need
to
redetermine
the
HAP
content
of
coatings,
thinners
and
other
additives,
and
cleaning
materials
that
are
reclaimed
onsite
and
reused
in
the
coating
operation
for
which
you
use
the
compliant
material
option,
provided
these
materials
in
their
condition
as
received
were
demonstrated
to
comply
with
the
compliant
material
option.
(
a)
Determine
the
mass
fraction
of
organic
HAP
for
each
material
used.
You
must
determine
the
mass
fraction
of
organic
HAP
for
each
coating,
thinner
or
other
additive,
and
cleaning
material
used
during
the
compliance
period
by
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
using
one
of
the
options
in
paragraphs
(
a)(
1)
through
(
5)
of
this
section.
(
1)
Method
311
(
appendix
A
to
40
CFR
part
63).
You
may
use
Method
311
for
determining
the
mass
fraction
of
organic
HAP.
Use
the
procedures
specified
in
paragraphs
(
a)(
1)(
i)
and
(
ii)
of
this
section
when
performing
a
Method
311
test.
(
i)
Count
each
organic
HAP
that
is
measured
to
be
present
at
0.1
percent
by
mass
or
more
for
Occupational
Safety
and
Health
Administration
(
OSHA)
defined
carcinogens
as
specified
in
29
CFR
1910.1200(
d)(
4)
and
at
1.0
percent
by
mass
or
more
for
other
compounds.
For
example,
if
toluene
(
not
an
OSHA
carcinogen)
is
measured
to
be
0.5
percent
of
the
material
by
mass,
you
do
not
have
to
count
it.
Express
the
mass
fraction
of
each
organic
HAP
you
count
as
a
value
truncated
to
four
places
after
the
decimal
point
(
e.
g.,
0.3791).
(
ii)
Calculate
the
total
mass
fraction
of
organic
HAP
in
the
test
material
by
adding
up
the
individual
organic
HAP
mass
fractions
and
truncating
the
result
to
three
places
after
the
decimal
point
(
e.
g.,
0.763).
(
2)
Method
24
(
appendix
A
to
40
CFR
part
60).
For
coatings,
you
may
use
Method
24
to
determine
the
mass
fraction
of
nonaqueous
volatile
matter
and
use
that
value
as
a
substitute
for
mass
fraction
of
organic
HAP.
(
3)
Alternative
method.
You
may
use
an
alternative
test
method
for
determining
the
mass
fraction
of
organic
HAP
once
the
Administrator
has
approved
it.
You
must
follow
the
procedure
in
§
63.7(
f)
to
submit
an
alternative
test
method
for
approval.
(
4)
Information
from
the
supplier
or
manufacturer
of
the
material.
You
may
rely
on
information
other
than
that
generated
by
the
test
methods
specified
in
paragraphs
(
a)(
1)
through
(
3)
of
this
section,
such
as
manufacturer's
formulation
data,
if
it
represents
each
organic
HAP
that
is
present
at
0.1
percent
by
mass
or
more
for
OSHAdefined
carcinogens
as
specified
in
29
CFR
1910.1200(
d)(
4)
and
at
1.0
percent
by
mass
or
more
for
other
compounds.
For
example,
if
toluene
(
not
an
OSHA
carcinogen)
is
0.5
percent
of
the
material
by
mass,
you
do
not
have
to
count
it.
If
there
is
a
disagreement
between
such
information
and
results
of
a
test
conducted
according
to
paragraphs
(
a)(
1)
through
(
3)
of
this
section,
then
the
test
method
results
will
take
precedence.
(
5)
Solvent
blends.
Solvent
blends
may
be
listed
as
single
components
for
some
materials
in
data
provided
by
manufacturers
or
suppliers.
Solvent
blends
may
contain
organic
HAP
which
must
be
counted
toward
the
total
organic
HAP
mass
fraction
of
the
materials.
When
test
data
and
manufacturer's
data
for
solvent
blends
are
not
available,
you
may
use
the
default
values
for
the
mass
fraction
of
organic
HAP
in
these
solvent
blends
listed
in
Table
3
or
4
of
this
subpart.
If
you
use
the
tables,
you
must
use
the
values
in
Table
3
for
all
solvent
blends
that
match
Table
3
entries,
and
you
may
only
use
Table
4
if
the
solvent
blends
in
the
materials
you
use
do
not
match
any
of
the
solvent
blends
in
Table
3
and
you
only
know
whether
the
blend
is
aliphatic
or
aromatic.
However,
if
the
results
of
a
Method
311
test
indicate
higher
values
than
those
listed
on
Table
3
or
4
of
this
subpart,
the
Method
311
results
will
take
precedence.
(
b)
Determine
the
mass
fraction
of
coating
solids
for
each
coating.
You
must
determine
the
mass
fraction
of
coating
solids
(
pounds
of
coating
solids
per
pound
of
coating)
for
each
coating
used
during
the
compliance
period
by
a
test
or
by
information
provided
by
the
supplier
or
the
manufacturer
of
the
material,
as
specified
in
paragraphs
(
b)(
1)
through
(
3)
of
this
section.
If
test
results
obtained
according
to
paragraph
(
b)(
1)
or
(
2)
of
this
section
do
not
agree
with
the
information
obtained
under
paragraph
(
b)(
3)
of
this
section,
the
test
results
will
take
precedence.
(
1)
Method
24
(
appendix
A
to
40
CFR
part
60).
You
may
use
Method
24
for
determining
the
mass
fraction
of
solids
of
coatings.
(
2)
Alternative
method.
You
may
use
an
alternative
test
method
for
determining
the
solids
content
of
each
coating
once
the
Administrator
has
approved
it.
You
must
follow
the
procedure
in
§
63.7(
f)
to
submit
an
alternative
test
method
for
approval.
(
3)
Information
from
the
supplier
or
manufacturer
of
the
material.
You
may
obtain
the
mass
fraction
of
coating
solids
for
each
coating
from
the
supplier
or
manufacturer.
If
there
is
disagreement
between
such
information
and
the
test
method
results,
then
the
test
method
results
will
take
precedence.
(
c)
Calculate
the
organic
HAP
content
of
each
coating.
Calculate
the
organic
HAP
content,
kg
(
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used,
of
each
coating
used
during
the
compliance
period,
using
Equation
1
of
this
section:
H
W
S
Eq
c
c
c
=
(
.
1)
Where:
Hc
=
organic
HAP
content
of
the
coating,
kg
(
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used.
Wc
=
mass
fraction
of
organic
HAP
in
the
coating,
lb
organic
HAP
per
lb
coating,
determined
according
to
paragraph
(
a)
of
this
section.
Sc
=
mass
fraction
of
coating
solids,
lb
coating
solids
per
lb
coating,
determined
according
to
paragraph
(
b)
of
this
section.
(
d)
Compliance
demonstration.
The
calculated
organic
HAP
content
for
each
coating
used
during
the
initial
compliance
period
must
be
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4490;
and
each
thinner
or
other
additive,
and
cleaning
material
used
during
the
initial
compliance
period
must
contain
no
organic
HAP,
determined
according
to
paragraph
(
a)
of
this
section.
You
must
keep
all
records
required
by
§
§
63.4530
and
63.4531.
As
part
of
the
Notification
of
Compliance
Status
required
in
§
63.4510,
you
must
identify
the
coating
operation(
s)
for
which
you
used
the
compliant
material
option
and
submit
a
statement
that
the
coating
operation(
s)
was
(
were)
in
compliance
with
the
emission
limitations
during
the
initial
compliance
period
because
you
used
no
coatings
for
which
the
organic
HAP
content
exceeded
the
applicable
emission
limit
in
§
63.4490,
and
you
used
no
thinners,
other
additives,
or
cleaning
materials
that
contained
organic
HAP,
determined
according
to
the
procedures
in
paragraph
(
a)
of
this
section.
§
63.4542
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
(
a)
For
each
compliance
period
to
demonstrate
continuous
compliance,
you
must
use
no
coating
for
which
the
organic
HAP
content
(
determined
using
Equation
1
of
§
63.4541)
exceeds
the
applicable
emission
limit
in
§
63.4490,
and
use
no
thinner
or
other
additive,
or
cleaning
material
that
contains
organic
HAP,
determined
according
to
§
63.4541(
a).
A
compliance
period
consists
of
12
months.
Each
month,
after
the
end
of
the
initial
compliance
period
described
in
§
63.4540,
is
the
end
of
a
compliance
period
consisting
of
that
month
and
the
preceding
11
months.
(
b)
If
you
choose
to
comply
with
the
emission
limitations
by
using
the
compliant
material
option,
the
use
of
any
coating,
thinner
or
other
additive,
or
cleaning
material
that
does
not
meet
the
criteria
specified
in
paragraph
(
a)
of
this
section
is
a
deviation
from
the
emission
limitations
that
must
be
reported
as
specified
in
§
§
63.4510(
c)(
6)
and
63.4520(
a)(
5).
(
c)
As
part
of
each
semiannual
compliance
report
required
by
§
63.4520,
you
must
identify
the
coating
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Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
operation(
s)
for
which
you
used
the
compliant
material
option.
If
there
were
no
deviations
from
the
applicable
emission
limit
in
§
63.4490,
submit
a
statement
that
the
coating
operation(
s)
was
(
were)
in
compliance
with
the
emission
limitations
during
the
reporting
period
because
you
used
no
coatings
for
which
the
organic
HAP
content
exceeded
the
applicable
emission
limit
in
§
63.4490,
and
you
used
no
thinner
or
other
additive,
or
cleaning
material
that
contained
organic
HAP,
determined
according
to
§
63.4541(
a).
(
d)
You
must
maintain
records
as
specified
in
§
§
63.4530
and
63.4531.
Compliance
Requirements
for
the
Emission
Rate
Without
Add
On
Controls
Option
§
63.4550
By
what
date
must
I
conduct
the
initial
compliance
demonstration?
You
must
complete
the
initial
compliance
demonstration
for
the
initial
compliance
period
according
to
the
requirements
of
§
63.4551.
The
initial
compliance
period
begins
on
the
applicable
compliance
date
specified
in
§
63.4483
and
ends
on
the
last
day
of
the
12th
month
following
the
compliance
date.
If
the
compliance
date
occurs
on
any
day
other
than
the
first
day
of
a
month,
then
the
initial
compliance
period
extends
through
the
end
of
that
month
plus
the
next
12
months.
You
must
determine
the
mass
of
organic
HAP
emissions
and
mass
of
coating
solids
used
each
month
and
then
calculate
a
12
month
organic
HAP
emission
rate
at
the
end
of
the
initial
12
month
compliance
period.
The
initial
compliance
demonstration
includes
the
calculations
according
to
§
63.4551
and
supporting
documentation
showing
that
during
the
initial
compliance
period
the
organic
HAP
emission
rate
was
equal
to
or
less
than
the
applicable
emission
limit
in
§
63.4490.
§
63.4551
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations?
You
may
use
the
emission
rate
without
add
on
controls
option
for
any
individual
coating
operation,
for
any
group
of
coating
operations
in
the
affected
source,
or
for
all
the
coating
operations
in
the
affected
source.
You
must
use
either
the
compliant
material
option
or
the
emission
rate
with
add
on
controls
option
for
any
coating
operation
in
the
affected
source
for
which
you
do
not
use
this
option.
To
demonstrate
initial
compliance
using
the
emission
rate
without
add
on
controls
option,
the
coating
operation
or
group
of
coating
operations
must
meet
the
applicable
emission
limit
in
§
63.4490,
but
is
not
required
to
meet
the
operating
limits
or
work
practice
standards
in
§
§
63.4492
and
63.4493,
respectively.
You
must
conduct
a
separate
initial
compliance
demonstration
for
each
general
use
coating,
TPO
coating,
headlamp
coating,
and
assembled
on
road
vehicle
coating
affected
source.
You
must
meet
all
the
requirements
of
this
section.
When
calculating
the
organic
HAP
emission
rate
according
to
this
section,
do
not
include
any
coatings,
thinners
or
other
additives,
or
cleaning
materials
used
on
coating
operations
for
which
you
use
the
compliant
material
option
or
the
emission
rate
with
add
on
controls
option
or
coating
operations
in
a
different
affected
source
in
a
different
subcategory.
You
do
not
need
to
redetermine
the
mass
of
organic
HAP
in
coatings,
thinners
and
other
additives,
or
cleaning
materials
that
have
been
reclaimed
onsite
and
reused
in
the
coating
operation
for
which
you
use
the
emission
rate
without
add
on
controls
option.
(
a)
Determine
the
mass
fraction
of
organic
HAP
for
each
material.
Determine
the
mass
fraction
of
organic
HAP
for
each
coating,
thinner
or
other
additive,
and
cleaning
material
used
during
each
month
according
to
the
requirements
in
§
63.4541(
a).
(
b)
Determine
the
mass
fraction
of
coating
solids.
Determine
the
mass
fraction
of
coating
solids
(
pounds
of
solids
per
pound
of
coating)
for
each
coating
used
during
each
month
according
to
the
requirements
in
§
63.4541(
b).
(
c)
Determine
the
density
of
each
material.
Determine
the
density
of
each
coating,
thinner
or
other
additive,
and
cleaning
material
used
during
each
month
from
test
results
using
ASTM
Method
D1475
98,
information
from
the
supplier
or
manufacturer
of
the
material,
or
reference
sources
providing
density
or
specific
gravity
data
for
pure
materials.
If
there
is
disagreement
between
ASTM
Method
D1475
98
test
results
and
other
such
information
sources,
the
test
results
will
take
precedence.
(
d)
Determine
the
volume
of
each
material
used.
Determine
the
volume
(
gallons)
of
each
coating,
thinner
or
other
additive,
and
cleaning
material
used
during
each
month
by
measurement
or
usage
records.
(
e)
Calculate
the
mass
of
organic
HAP
emissions.
The
mass
of
organic
HAP
emissions
is
the
combined
mass
of
organic
HAP
contained
in
all
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
during
each
month
minus
the
organic
HAP
in
certain
waste
materials.
Calculate
the
mass
of
organic
HAP
emissions
using
Equation
1
of
this
section.
H
A
B
C
R
Eq
e
w
=
+
+
(
.
1)
Where:
He
=
total
mass
of
organic
HAP
emissions
during
the
month,
lb.
A
=
total
mass
of
organic
HAP
in
the
coatings
used
during
the
month,
lb,
as
calculated
in
Equation
1A
of
this
section.
B
=
total
mass
of
organic
HAP
in
the
thinners
and
other
additives
used
during
the
month,
lb,
as
calculated
in
Equation
1B
of
this
section.
C
=
total
mass
of
organic
HAP
in
the
cleaning
materials
used
during
the
month,
lb,
as
calculated
in
Equation
1C
of
this
section.
Rw
=
total
mass
of
organic
HAP
in
waste
materials
sent
or
designated
for
shipment
to
a
hazardous
waste
TSDF
for
treatment
or
disposal
during
the
month,
lb,
determined
according
to
paragraph
(
e)(
4)
of
this
section.
(
You
may
assign
a
value
of
zero
to
Rw
if
you
do
not
wish
to
use
this
allowance.)
(
1)
Calculate
the
lb
organic
HAP
in
the
coatings
used
during
the
month
using
Equation
1A
of
this
section:
A
Vol
D
W
Eq
c
i
i
m
c
i
c
i
=
(
)(
)(
)
=
,
,
,
(
.
1
1A)
Where:
A
=
total
mass
of
organic
HAP
in
the
coatings
used
during
the
month,
lb.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
month,
gallons.
Dc,
i
=
density
of
coating,
i,
lb
coating
per
gallon
coating.
Wc,
i
=
mass
fraction
of
organic
HAP
in
coating,
i,
lb
organic
HAP
per
lb
coating.
m
=
number
of
different
coatings
used
during
the
month.
(
2)
Calculate
the
lb
of
organic
HAP
in
the
thinners
and
other
additives
used
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72309
Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
during
the
month
using
Equation
1B
of
this
section:
B
Vol
D
W
Eq
t
j
j
n
t
j
t
j
=
(
)(
)(
)
=
,
,
,
(
.
1
1B)
Where:
B
=
total
mass
of
organic
HAP
in
the
thinners
and
other
additives
used
during
the
month,
lb.
Volt,
j
=
total
volume
of
thinner
or
other
additive,
j,
used
during
the
month,
gallons.
Dt,
j
=
density
of
thinner
or
other
additive,
j,
lb
per
gallon.
Wt,
j
=
mass
fraction
of
organic
HAP
in
thinner
or
other
additive,
j,
lb
organic
HAP
per
lb
thinner.
n
=
number
of
different
thinners
or
other
additives
used
during
the
month.
(
3)
Calculate
the
lb
organic
HAP
in
the
cleaning
materials
used
during
the
month
using
Equation
1C
of
this
section:
C
Vol
D
W
Eq
s
k
k
p
s
k
s
k
=
(
)(
)(
)
=
,
,
,
(
.
1
1C)
Where:
C
=
total
mass
of
organic
HAP
in
the
cleaning
materials
used
during
the
month,
lb.
Vols,
k
=
total
volume
of
cleaning
material,
k,
used
during
the
month,
gallons.
Ds,
k
=
density
of
cleaning
material,
k,
lb
per
gallon.
Ws,
k
=
mass
fraction
of
organic
HAP
in
cleaning
material,
k,
lb
organic
HAP
per
lb
material.
p
=
number
of
different
cleaning
materials
used
during
the
month.
(
4)
If
you
choose
to
account
for
the
mass
of
organic
HAP
contained
in
waste
materials
sent
or
designated
for
shipment
to
a
hazardous
waste
TSDF
in
Equation
1
of
this
section,
then
you
must
determine
it
according
to
paragraphs
(
e)(
4)(
i)
through
(
iv)
of
this
section.
(
i)
You
may
include
in
the
determination
only
waste
materials
that
are
generated
by
coating
operations
in
the
affected
source
for
which
you
use
Equation
1
of
this
section
and
that
will
be
treated
or
disposed
of
by
a
facility
that
is
regulated
as
a
TSDF
under
40
CFR
part
262,
264,
265,
or
266.
The
TSDF
may
be
either
off
site
or
on
site.
You
may
not
include
organic
HAP
contained
in
wastewater.
(
ii)
You
must
determine
either
the
amount
of
the
waste
materials
sent
to
a
TSDF
during
the
month
or
the
amount
collected
and
stored
during
the
month
and
designated
for
future
transport
to
a
TSDF.
Do
not
include
in
your
determination
any
waste
materials
sent
to
a
TSDF
during
a
month
if
you
have
already
included
them
in
the
amount
collected
and
stored
during
that
month
or
a
previous
month.
(
iii)
Determine
the
total
mass
of
organic
HAP
contained
in
the
waste
materials
specified
in
paragraph
(
e)(
4)(
ii)
of
this
section.
(
iv)
You
must
document
the
methodology
you
use
to
determine
the
amount
of
waste
materials
and
the
total
mass
of
organic
HAP
they
contain,
as
required
in
§
63.4530(
h).
To
the
extent
that
waste
manifests
include
this,
they
may
be
used
as
part
of
the
documentation
of
the
amount
of
waste
materials
and
mass
of
organic
HAP
contained
in
them.
(
f)
Calculate
the
total
mass
of
coating
solids
used.
Determine
the
total
mass
of
coating
solids
used,
lb,
which
is
the
combined
mass
of
coating
solids
for
all
coatings
used
during
each
month
using
Equation
2
of
this
section:
M
Vol
D
M
Eq
st
c
i
i
m
c
i
s
i
=
(
)(
)(
)
=
,
,
,
(
.
1
2)
Where:
Mst
=
total
mass
of
coating
solids
used
during
the
month,
lb.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
month,
gallons.
Dc,
i
=
density
of
coating,
i,
lbs
per
gallon
coating,
determined
according
to
63.4551(
c).
Ms,
i
=
mass
fraction
of
coating
solids
for
coating,
i,
lbs
solids
per
lb
coating,
determined
according
to
§
63.4541(
b).
m
=
number
of
coatings
used
during
the
month.
(
g)
Calculate
the
organic
HAP
emission
rate
for
the
12
month
compliance
period,
kg
(
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used,
using
Equation
3
of
this
section:
H
H
M
Eq
yr
e
y
st
y
=
=
=
1
12
1
12
(
.
3)
Where:
Hyr
=
average
organic
HAP
emission
rate
for
the
12
month
compliance
period,
kg
(
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used.
He
=
total
mass
of
organic
HAP
emissions
from
all
materials
used
during
month,
y,
lb,
as
calculated
by
Equation
1
of
this
section.
Mst
=
total
mass
of
coating
solids
used
during
month,
y,
lb,
as
calculated
by
Equation
2
of
this
section.
y
=
identifier
for
months.
(
h)
Compliance
demonstration.
The
organic
HAP
emission
rate
for
the
initial
12
month
compliance
period
must
be
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4490.
You
must
keep
all
records
as
required
by
§
§
63.4530
and
63.4531.
As
part
of
the
Notification
of
Compliance
Status
required
by
§
63.4510,
you
must
identify
the
coating
operation(
s)
for
which
you
used
the
emission
rate
without
add
on
controls
option
and
submit
a
statement
that
the
coating
operation(
s)
was
(
were)
in
compliance
with
the
emission
limitations
during
the
initial
compliance
period
because
the
organic
HAP
emission
rate
was
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4490,
determined
according
to
the
procedures
in
this
section.
§
63.4552
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
(
a)
To
demonstrate
continuous
compliance,
the
organic
HAP
emission
rate
for
each
compliance
period,
determined
according
to
§
63.4551(
a)
through
(
g),
must
be
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4490.
A
compliance
period
consists
of
12
months.
Each
month
after
the
end
of
the
initial
compliance
period
described
in
§
63.4550
is
the
end
of
a
compliance
period
consisting
of
that
month
and
the
preceding
11
months.
You
must
perform
the
calculations
in
§
63.4551(
a)
through
(
g)
on
a
monthly
basis
using
data
from
the
previous
12
months
of
operation.
(
b)
If
the
organic
HAP
emission
rate
for
any
12
month
compliance
period
exceeded
the
applicable
emission
limit
in
§
63.4490,
this
is
a
deviation
from
the
emission
limitation
for
that
compliance
period
and
must
be
reported
as
specified
in
§
§
63.4510(
c)(
6)
and
63.4520(
a)(
6).
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72310
Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
(
c)
As
part
of
each
semiannual
compliance
report
required
by
§
63.4520,
you
must
identify
the
coating
operation(
s)
for
which
you
used
the
emission
rate
without
add
on
controls
option.
If
there
were
no
deviations
from
the
emission
limitations,
you
must
submit
a
statement
that
the
coating
operation(
s)
was
(
were)
in
compliance
with
the
emission
limitations
during
the
reporting
period
because
the
organic
HAP
emission
rate
for
each
compliance
period
was
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4490,
determined
according
to
§
63.4551(
a)
through
(
g).
(
d)
You
must
maintain
records
as
specified
in
§
§
63.4530
and
63.4531.
Compliance
Requirements
for
the
Emission
Rate
With
Add
On
Controls
Option
§
63.4560
By
what
date
must
I
conduct
performance
tests
and
other
initial
compliance
demonstrations?
(
a)
New
and
reconstructed
affected
sources.
For
a
new
or
reconstructed
affected
source,
you
must
meet
the
requirements
of
paragraphs
(
a)(
1)
through
(
4)
of
this
section.
(
1)
All
emission
capture
systems,
addon
control
devices,
and
CPMS
must
be
installed
and
operating
no
later
than
the
applicable
compliance
date
specified
in
§
63.4483.
Except
for
solvent
recovery
systems
for
which
you
conduct
liquidliquid
material
balances
according
to
§
63.4561(
j),
you
must
conduct
a
performance
test
of
each
capture
system
and
add
on
control
device
according
to
§
§
63.4564,
63.4565,
and
63.4566
and
establish
the
operating
limits
required
by
§
63.4492
no
later
than
180
days
after
the
applicable
compliance
date
specified
in
§
63.4483.
For
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances
according
to
§
63.4561(
j),
you
must
initiate
the
first
material
balance
no
later
than
the
applicable
compliance
date
specified
in
§
63.4483.
(
2)
You
must
develop
and
begin
implementing
the
work
practice
plan
required
by
§
63.4493
no
later
than
the
compliance
date
specified
in
§
63.4483.
(
3)
You
must
complete
the
initial
compliance
demonstration
for
the
initial
compliance
period
according
to
the
requirements
of
§
63.4561.
The
initial
compliance
period
begins
on
the
applicable
compliance
date
specified
in
§
63.4483
and
ends
on
the
last
day
of
the
12th
month
following
the
compliance
date.
If
the
compliance
date
occurs
on
any
day
other
than
the
first
day
of
a
month,
then
the
initial
compliance
period
extends
through
the
end
of
that
month
plus
the
next
12
months.
You
must
determine
the
mass
of
organic
HAP
emissions
and
mass
of
coatings
solids
used
each
month
and
then
calculate
a
12
month
organic
HAP
emission
rate
at
the
end
of
the
initial
12
month
compliance
period.
The
initial
compliance
demonstration
includes
the
results
of
emission
capture
system
and
add
on
control
device
performance
tests
conducted
according
to
§
§
63.4564,
63.4565,
and
63.4566;
results
of
liquidliquid
material
balances
conducted
according
to
§
63.4561(
j);
calculations
according
to
§
63.4561
and
supporting
documentation
showing
that
during
the
initial
compliance
period
the
organic
HAP
emission
rate
was
equal
to
or
less
than
the
applicable
emission
limit
in
§
63.4490;
the
operating
limits
established
during
the
performance
tests
and
the
results
of
the
continuous
parameter
monitoring
required
by
§
63.4568;
and
documentation
of
whether
you
developed
and
implemented
the
work
practice
plan
required
by
§
63.4493.
(
4)
You
do
not
need
to
comply
with
the
operating
limits
for
the
emission
capture
system
and
add
on
control
device
required
by
§
63.4492
until
after
you
have
completed
the
performance
tests
specified
in
paragraph
(
a)(
1)
of
this
section.
Instead,
you
must
maintain
a
log
detailing
the
operation
and
maintenance
of
the
emission
capture
system,
add
on
control
device,
and
continuous
parameter
monitors
during
the
period
between
the
compliance
date
and
the
performance
test.
You
must
begin
complying
with
the
operating
limits
for
your
affected
source
on
the
date
you
complete
the
performance
tests
specified
in
paragraph
(
a)(
1)
of
this
section.
The
requirements
in
this
paragraph
do
not
apply
to
solvent
recovery
systems
for
which
you
conduct
liquid
liquid
material
balances
according
to
the
requirements
in
§
63.4561(
j).
(
b)
Existing
affected
sources.
For
an
existing
affected
source,
you
must
meet
the
requirements
of
paragraphs
(
b)(
1)
through
(
3)
of
this
section.
(
1)
All
emission
capture
systems,
addon
control
devices,
and
CPMS
must
be
installed
and
operating
no
later
than
the
applicable
compliance
date
specified
in
§
63.4483.
Except
for
solvent
recovery
systems
for
which
you
conduct
liquidliquid
material
balances
according
to
§
63.4561(
j),
you
must
conduct
a
performance
test
of
each
capture
system
and
add
on
control
device
according
to
the
procedures
in
§
§
63.4564,
63.4565,
and
63.4566
and
establish
the
operating
limits
required
by
§
63.4492
no
later
than
the
compliance
date
specified
in
§
63.4483.
For
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances
according
to
§
63.4561(
j),
you
must
initiate
the
first
material
balance
no
later
than
the
compliance
date
specified
in
§
63.4483.
(
2)
You
must
develop
and
begin
implementing
the
work
practice
plan
required
by
§
63.4493
no
later
than
the
compliance
date
specified
in
§
63.4483.
(
3)
You
must
complete
the
compliance
demonstration
for
the
initial
compliance
period
according
to
the
requirements
of
§
63.4561.
The
initial
compliance
period
begins
on
the
applicable
compliance
date
specified
in
§
63.4483
and
ends
on
the
last
day
of
the
12th
month
following
the
compliance
date.
If
the
compliance
date
occurs
on
any
day
other
than
the
first
day
of
a
month,
then
the
initial
compliance
period
extends
through
the
end
of
that
month
plus
the
next
12
months.
You
must
determine
the
mass
of
organic
HAP
emissions
and
mass
of
coatings
solids
used
each
month
and
then
calculate
a
12
month
organic
HAP
emission
rate
at
the
end
of
the
initial
12
month
compliance
period.
The
initial
compliance
demonstration
includes
the
results
of
emission
capture
system
and
add
on
control
device
performance
tests
conducted
according
to
§
§
63.4564,
63.4565,
and
63.4566;
results
of
liquidliquid
material
balances
conducted
according
to
§
63.4561(
j);
calculations
according
to
§
63.4561
and
supporting
documentation
showing
that
during
the
initial
compliance
period
the
organic
HAP
emission
rate
was
equal
to
or
less
than
the
applicable
emission
limit
in
§
63.4490;
the
operating
limits
established
during
the
performance
tests
and
the
results
of
the
continuous
parameter
monitoring
required
by
§
63.4568;
and
documentation
of
whether
you
developed
and
implemented
the
work
practice
plan
required
by
§
63.4493.
§
63.4561
How
do
I
demonstrate
initial
compliance?
(
a)
You
may
use
the
emission
rate
with
add
on
controls
option
for
any
coating
operation,
for
any
group
of
coating
operations
in
the
affected
source,
or
for
all
of
the
coating
operations
in
the
affected
source.
You
may
include
both
controlled
and
uncontrolled
coating
operations
in
a
group
for
which
you
use
this
option.
You
must
use
either
the
compliant
material
option
or
the
emission
rate
without
add
on
controls
option
for
any
coating
operation
in
the
affected
source
for
which
you
do
not
use
the
emission
rate
with
add
on
controls
option.
To
demonstrate
initial
compliance,
the
coating
operation(
s)
for
which
you
use
the
emission
rate
with
add
on
controls
option
must
meet
the
applicable
emission
limitations
in
§
§
63.4490,
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72311
Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
63.4492,
and
63.4493.
You
must
conduct
a
separate
initial
compliance
demonstration
for
each
general
use
coating,
TPO
coating,
headlamp
coating
and
assembled
on
road
vehicle
coating
affected
source.
You
must
meet
all
the
requirements
of
this
section.
When
calculating
the
organic
HAP
emission
rate
according
to
this
section,
do
not
include
any
coatings,
thinners
and
other
additives,
or
cleaning
materials
used
on
coating
operations
for
which
you
use
the
compliant
material
option
or
the
emission
rate
without
add
on
controls
option
or
coating
operations
in
a
different
affected
source
in
a
different
subcategory.
You
do
not
need
to
redetermine
the
mass
of
organic
HAP
in
coatings,
thinners
and
other
additives,
or
cleaning
materials
that
have
been
reclaimed
onsite
and
reused
in
the
coatings
operation(
s)
for
which
you
use
the
emission
rate
with
add
on
controls
option.
(
b)
Compliance
with
operating
limits.
Except
as
provided
in
§
63.4560(
a)(
4),
and
except
for
solvent
recovery
systems
for
which
you
conduct
liquid
liquid
material
balances
according
to
the
requirements
of
paragraph
(
j)
of
this
section,
you
must
establish
and
demonstrate
continuous
compliance
during
the
initial
compliance
period
with
the
operating
limits
required
by
§
63.4492,
using
the
procedures
specified
in
§
§
63.4567
and
63.4568.
(
c)
Compliance
with
work
practice
requirements.
You
must
develop,
implement,
and
document
your
implementation
of
the
work
practice
plan
required
by
§
63.4493
during
the
initial
compliance
period,
as
specified
in
§
63.4530.
(
d)
Compliance
with
emission
limits.
You
must
follow
the
procedures
in
paragraphs
(
e)
through
(
n)
of
this
section
to
demonstrate
compliance
with
the
applicable
emission
limit
in
§
63.4490
for
each
affected
source
in
each
subcategory.
(
e)
Determine
the
mass
fraction
of
organic
HAP,
density,
volume
used,
and
mass
fraction
of
coating
solids.
Follow
the
procedures
specified
in
§
63.4551(
a)
through
(
d)
to
determine
the
mass
fraction
of
organic
HAP,
density,
and
volume
of
each
coating,
thinner
or
other
additive,
and
cleaning
material
used
during
each
month;
and
the
mass
fraction
of
coating
solids
for
each
coating
used
during
each
month.
(
f)
Calculate
the
total
mass
of
organic
HAP
emissions
before
add
on
controls.
Using
Equation
1
of
§
63.4551,
calculate
the
total
mass
of
organic
HAP
emissions
before
add
on
controls
from
all
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
during
each
month
in
the
coating
operation
or
group
of
coating
operations
for
which
you
use
the
emission
rate
with
add
on
controls
option.
(
g)
Calculate
the
organic
HAP
emission
reduction
for
each
controlled
coating
operation.
Determine
the
mass
of
organic
HAP
emissions
reduced
for
each
controlled
coating
operation
during
each
month.
The
emission
reduction
determination
quantifies
the
total
organic
HAP
emissions
that
pass
through
the
emission
capture
system
and
are
destroyed
or
removed
by
the
add
on
control
device.
Use
the
procedures
in
paragraph
(
h)
of
this
section
to
calculate
the
mass
of
organic
HAP
emission
reduction
for
each
controlled
coating
operation
using
an
emission
capture
system
and
add
on
control
device
other
than
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances.
For
each
controlled
coating
operation
using
a
solvent
recovery
system
for
which
you
conduct
a
liquid
liquid
material
balance,
use
the
procedures
in
paragraph
(
j)
of
this
section
to
calculate
the
organic
HAP
emission
reduction.
(
h)
Calculate
the
organic
HAP
emission
reduction
for
each
controlled
coating
operation
not
using
liquid
liquid
material
balance.
For
each
controlled
coating
operation
using
an
emission
capture
system
and
add
on
control
device
other
than
a
solvent
recovery
system
for
which
you
conduct
liquidliquid
material
balances,
calculate
the
organic
HAP
emission
reduction,
using
Equation
1
of
this
section.
The
calculation
applies
the
emission
capture
system
efficiency
and
add
on
control
device
efficiency
to
the
mass
of
organic
HAP
contained
in
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
that
are
used
in
the
coating
operation
served
by
the
emission
capture
system
and
add
on
control
device
during
each
month.
For
any
period
of
time
a
deviation
specified
in
§
63.4563(
c)
or
(
d)
occurs
in
the
controlled
coating
operation,
including
a
deviation
during
a
period
of
startup,
shutdown,
or
malfunction,
then
you
must
assume
zero
efficiency
for
the
emission
capture
system
and
add
on
control
device.
Equation
1
of
this
section
treats
the
materials
used
during
such
a
deviation
as
if
they
were
used
on
an
uncontrolled
coating
operation
for
the
time
period
of
the
deviation.
H
A
B
C
H
CE
DRE
Eq
C
C
C
C
UNC
=
+
+
(
)
×
100
100
(
.
1)
Where:
HC
=
mass
of
organic
HAP
emission
reduction
for
the
controlled
coating
operation
during
the
month,
lb.
AC
=
total
mass
of
organic
HAP
in
the
coatings
used
in
the
controlled
coating
operation
during
the
month,
lb,
as
calculated
in
Equation
1A
of
this
section.
BC
=
total
mass
of
organic
HAP
in
the
thinners
and
other
additives
used
in
the
controlled
coating
operation
during
the
month,
lb,
as
calculated
in
Equation
1B
of
this
section.
CC
=
total
mass
of
organic
HAP
in
the
cleaning
materials
used
in
the
controlled
coating
operation
during
the
month,
lb,
as
calculated
in
Equation
1C
of
this
section.
HUNC
=
total
mass
of
organic
HAP
in
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
during
all
deviations
specified
in
§
63.4563(
c)
and
(
d)
that
occurred
during
the
month
in
the
controlled
coating
operation,
lb,
as
calculated
in
Equation
1D
of
this
section.
CE
=
capture
efficiency
of
the
emission
capture
system
vented
to
the
add
on
control
device,
percent.
Use
the
test
methods
and
procedures
specified
in
§
§
63.4564
and
63.4565
to
measure
and
record
capture
efficiency.
DRE
=
organic
HAP
destruction
or
removal
efficiency
of
the
add
on
control
device,
percent.
Use
the
test
methods
and
procedures
in
§
§
63.4564
and
63.4566
to
measure
and
record
the
organic
HAP
destruction
or
removal
efficiency.
(
1)
Calculate
the
mass
of
organic
HAP
in
the
coatings
used
in
the
controlled
coating
operation,
lb,
using
Equation
1A
of
this
section:
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72312
Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
A
Vol
D
W
Eq
C
ci
i
m
c
i
c
i
=
(
)(
)(
)
=
,
,
,
(
.
1
1A)
Where:
AC
=
total
mass
of
organic
HAP
in
the
coatings
used
in
the
controlled
coating
operation
during
the
month,
lb.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
month,
gallons.
Dc,
i
=
density
of
coating,
i,
lb
per
gallon.
Wc,
i
=
mass
fraction
of
organic
HAP
in
coating,
i,
lb
per
lb.
m
=
number
of
different
coatings
used.
(
2)
Calculate
the
mass
of
organic
HAP
in
the
thinners
and
other
additives
used
in
the
controlled
coating
operation,
lb
using
Equation
1B
of
this
section.
B
Vol
D
W
Eq
C
tj
j
n
t
j
t
j
=
(
)(
)(
)
=
,
,
,
(
.
1
1B)
Where:
BC
=
total
mass
of
organic
HAP
in
the
thinners
and
other
additives
used
in
the
controlled
coating
operation
during
the
month,
lb.
Volt,
j
=
total
volume
of
thinner
or
other
additive,
j,
used
during
the
month,
gallons.
Dt,
j
=
density
of
thinner
or
other
additive,
j,
lb
per
gallon.
Wt,
j
=
mass
fraction
of
organic
HAP
in
thinner
or
other
additive,
j,
lb
per
lb.
n
=
number
of
different
thinners
and
other
additives
used.
(
3)
Calculate
the
mass
of
organic
HAP
in
the
cleaning
materials
used
in
the
controlled
coating
operation
during
the
month,
lb,
using
Equation
1C
of
this
section.
C
Vol
D
W
Eq
C
sk
k
p
s
k
s
k
=
(
)(
)(
)
=
,
,
,
(
.
1
1C)
Where:
CC
=
total
mass
of
organic
HAP
in
the
cleaning
materials
used
in
the
controlled
coating
operation
during
the
month,
lb.
Vols,
k
=
total
volume
of
cleaning
material,
k,
used
during
the
month,
gallons.
Ds,
k
=
density
of
cleaning
material,
k,
lb
per
gallon.
Ws,
k
=
mass
fraction
of
organic
HAP
in
cleaning
material,
k,
lb
per
lb.
p
=
number
of
different
cleaning
materials
used.
(
4)
Calculate
the
mass
of
organic
HAP
in
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
in
the
controlled
coating
operation
during
deviations
specified
in
§
63.4563(
c)
and
(
d),
using
Equation
1D
of
this
section.
H
Vol
D
W
Eq
UNC
h
h
q
h
h
=
(
)(
)(
)
=
1
(
.
1D)
Where:
HUNC
=
total
mass
of
organic
HAP
in
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
during
all
deviations
specified
in
§
63.4563(
c)
and
(
d)
that
occurred
during
the
month
in
the
controlled
coating
operation,
lb.
Volh
=
total
volume
of
coating,
thinner
or
other
additive,
or
cleaning
material,
h,
used
in
the
controlled
coating
operation
during
deviations,
gallons.
Dh
=
density
of
coating,
thinner
or
other
additive,
or
cleaning
material,
h,
lb
per
gallon.
Wh
=
mass
fraction
of
organic
HAP
in
coating,
thinner
or
other
additive,
or
cleaning
material,
h,
lb
organic
HAP
per
lb
coating.
q
=
number
of
different
coatings,
thinners
and
other
additives,
and
cleaning
materials
used.
(
i)
[
Reserved]
(
j)
Calculate
the
organic
HAP
emission
reduction
for
each
controlled
coating
operation
using
liquid
liquid
material
balances.
For
each
controlled
coating
operation
using
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances,
calculate
the
organic
HAP
emission
reduction
by
applying
the
volatile
organic
matter
collection
and
recovery
efficiency
to
the
mass
of
organic
HAP
contained
in
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
that
are
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
each
month.
Perform
a
liquid
liquid
material
balance
for
each
month
as
specified
in
paragraphs
(
j)(
1)
through
(
6)
of
this
section.
Calculate
the
mass
of
organic
HAP
emission
reduction
by
the
solvent
recovery
system
as
specified
in
paragraph
(
j)(
7)
of
this
section.
(
1)
For
each
solvent
recovery
system,
install,
calibrate,
maintain,
and
operate
according
to
the
manufacturer's
specifications,
a
device
that
indicates
the
cumulative
amount
of
volatile
organic
matter
recovered
by
the
solvent
recovery
system
each
month.
The
device
must
be
initially
certified
by
the
manufacturer
to
be
accurate
to
within
±
2.0
percent
of
the
mass
of
volatile
organic
matter
recovered.
(
2)
For
each
solvent
recovery
system,
determine
the
mass
of
volatile
organic
matter
recovered
for
the
month,
based
on
measurement
with
the
device
required
in
paragraph
(
j)(
1)
of
this
section.
(
3)
Determine
the
mass
fraction
of
volatile
organic
matter
for
each
coating,
thinner
or
other
additive,
and
cleaning
material
used
in
the
coating
operation
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72313
Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
controlled
by
the
solvent
recovery
system
during
the
month,
lb
volatile
organic
matter
per
lb
coating.
You
may
determine
the
volatile
organic
matter
mass
fraction
using
Method
24
of
40
CFR
part
60,
appendix
A,
or
an
EPA
approved
alternative
method,
or
you
may
use
information
provided
by
the
manufacturer
or
supplier
of
the
coating.
In
the
event
of
any
inconsistency
between
information
provided
by
the
manufacturer
or
supplier
and
the
results
of
Method
24
of
40
CFR
part
60,
appendix
A,
or
an
approved
alternative
method,
the
test
method
results
will
govern.
(
4)
Determine
the
density
of
each
coating,
thinner
or
other
additive,
and
cleaning
material
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
lb
per
gallon,
according
to
§
63.4551(
c).
(
5)
Measure
the
volume
of
each
coating,
thinner
or
other
additive,
and
cleaning
material
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
gallons.
(
6)
Each
month,
calculate
the
solvent
recovery
system's
volatile
organic
matter
collection
and
recovery
efficiency,
using
Equation
2
of
this
section:
R
M
Vol
D
WV
Vol
D
WV
Vol
D
WV
Eq
v
VR
i
i
ci
j
j
t
j
j
n
k
k
sk
k
p
i
m
=
+
+
=
=
=
100
1
1
1
,
,
,
(
.
2)
Where:
RV
=
volatile
organic
matter
collection
and
recovery
efficiency
of
the
solvent
recovery
system
during
the
month,
percent.
MVR
=
mass
of
volatile
organic
matter
recovered
by
the
solvent
recovery
system
during
the
month,
lb.
Voli
=
volume
of
coating,
i,
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
gallons.
Di
=
density
of
coating,
i,
lb
per
gallon.
WVc,
i
=
mass
fraction
of
volatile
organic
matter
for
coating,
i,
lb
volatile
organic
matter
per
lb
coating.
Volj
=
volume
of
thinner
or
other
additive,
j,
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
gallons.
Dj
=
density
of
thinner
or
other
additive,
j,
lb
per
gallon.
WVt,
j
=
mass
fraction
of
volatile
organic
matter
for
thinner
or
other
additive,
j,
lb
volatile
organic
matter
per
lb
thinner
or
other
additive.
Volk
=
volume
of
cleaning
material,
k,
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
gallons.
Dk
=
density
of
cleaning
material,
k,
lb
per
gallon.
WVs,
k
=
mass
fraction
of
volatile
organic
matter
for
cleaning
material,
k,
lb
volatile
organic
matter
per
lb
cleaning
material.
m
=
number
of
different
coatings
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month.
n
=
number
of
different
thinners
and
other
additives
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month.
p
=
number
of
different
cleaning
materials
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month.
(
7)
Calculate
the
mass
of
organic
HAP
emission
reduction
for
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
using
Equation
3
of
this
section
and
according
to
paragraphs
(
j)(
7)(
i)
through
(
iii)
of
this
section:
H
A
B
C
R
Eq
CSR
CSR
CSR
CSR
V
=
+
+
(
)
100
(
.
3)
Where:
HCSR
=
mass
of
organic
HAP
emission
reduction
for
the
coating
operation
controlled
by
the
solvent
recovery
system
using
a
liquid
liquid
material
balance
during
the
month,
lb.
ACSR
=
total
mass
of
organic
HAP
in
the
coatings
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
lb,
calculated
using
Equation
3A
of
this
section.
BCSR
=
total
mass
of
organic
HAP
in
the
thinners
and
other
additives
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
lb,
calculated
using
Equation
3B
of
this
section.
CCSR
=
total
mass
of
organic
HAP
in
the
cleaning
materials
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
lb,
calculated
using
Equation
3C
of
this
section.
RV
=
volatile
organic
matter
collection
and
recovery
efficiency
of
the
solvent
recovery
system,
percent,
from
Equation
2
of
this
section.
(
i)
Calculate
the
mass
of
organic
HAP
in
the
coatings
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
lb,
using
Equation
3A
of
this
section:
A
=
Vol
D
W
(
Eq.
3A)
CSR
c,
i
c,
i
c,
i
i=
1
m
(
)(
)(
)
Where:
ACSR
=
total
mass
of
organic
HAP
in
the
coatings
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
lb.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
month
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
gallons.
Dc,
i
=
density
of
coating,
i,
lb
per
gallon.
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72314
Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
Wc,
i
=
mass
fraction
of
organic
HAP
in
coating,
i,
lb
organic
HAP
per
lb
coating.
m
=
number
of
different
coatings
used.
(
ii)
Calculate
the
mass
of
organic
HAP
in
the
thinners
and
other
additives
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
lb,
using
Equation
3B
of
this
section:
B
Vol
D
W
Eq
CSR
t
j
t
j
t
j
j
n
=
(
)(
)(
)
=
,
,
,
(
.
3B)
1
Where:
BCSR
=
total
mass
of
organic
HAP
in
the
thinners
and
other
additives
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
lb.
Volt,
j
=
total
volume
of
thinner
or
other
additive,
j,
used
during
the
month
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
gallons.
Dt,
j
=
density
of
thinner
or
other
additive,
j,
lb
per
gallon.
Wt,
j
=
mass
fraction
of
organic
HAP
in
thinner
or
other
additive,
j,
lb
organic
HAP
per
lb
thinner
or
other
additive.
n
=
number
of
different
thinners
and
other
additives
used.
(
iii)
Calculate
the
mass
of
organic
HAP
in
the
cleaning
materials
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
lb,
using
Equation
3C
of
this
section.
C
=
Vol
D
W
(
Eq.
3C)
CSR
s,
k
s,
k
s,
k
k=
1
p
(
)(
)(
)
Where:
CCSR
=
total
mass
of
organic
HAP
in
the
cleaning
materials
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
lb.
Vols,
k
=
total
volume
of
cleaning
material,
k,
used
during
the
month
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
gallons.
Ds,
k
=
density
of
cleaning
material,
k,
lb
per
gallon.
Ws,
k
=
mass
fraction
of
organic
HAP
in
cleaning
material,
k,
lb
organic
HAP
per
lb
cleaning
material.
p
=
number
of
different
cleaning
materials
used.
(
k)
Calculate
the
total
mass
of
coating
solids
used.
Determine
the
total
mass
of
coating
solids
used,
pounds,
which
is
the
combined
mass
of
coating
solids
for
all
the
coatings
used
during
each
month
in
the
coating
operation
or
group
of
coating
operations
for
which
you
use
the
emission
rate
with
add
on
controls
option,
using
Equation
2
of
§
63.4551.
(
l)
Calculate
the
mass
of
organic
HAP
emissions
for
each
month.
Determine
the
mass
of
organic
HAP
emissions,
lb,
during
each
month,
using
Equation
4
of
this
section:
H
H
H
H
Eq
HAP
e
C
i
i
q
CSR
j
j
r
=
(
)
(
)
=
=
,
,
(
.
1
1
4)
Where:
HHAP
=
total
mass
of
organic
HAP
emissions
for
the
month,
lb.
He
=
total
mass
of
organic
HAP
emissions
before
add
on
controls
from
all
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
during
the
month,
lb,
determined
according
to
paragraph
(
f)
of
this
section.
HC,
i
=
total
mass
of
organic
HAP
emission
reduction
for
controlled
coating
operation,
i,
not
using
a
liquid
liquid
material
balance,
during
the
month,
lb,
from
Equation
1
of
this
section.
HCSR,
j
=
total
mass
of
organic
HAP
emission
reduction
for
coating
operation,
j,
controlled
by
a
solvent
recovery
system
using
a
liquidliquid
material
balance,
during
the
month,
lb,
from
Equation
3
of
this
section.
q
=
Number
of
controlled
coating
operations
not
using
a
liquid
liquid
material
balance.
r
=
Number
of
coating
operations
controlled
by
a
solvent
recovery
system
using
a
liquid
liquid
material
balance.
(
m)
Calculate
the
organic
HAP
emission
rate
for
the
12
month
compliance
period.
Determine
the
organic
HAP
emission
rate
for
the
12
month
compliance
period,
kg
(
lb)
of
organic
HAP
emitted
per
kg
(
lb)
coating
solids
used,
using
Equation
5
of
this
section:
H
H
M
Eq
annual
HAP
y
y
st
y
y
=
=
=
,
,
(
.
1
12
1
12
5)
Where:
Hannual
=
organic
HAP
emission
rate
for
the
12
month
compliance
period,
kg
of
organic
HAP
emitted
per
kg
coating
solids
used
(
lb
organic
HAP
emitted
per
lb
coating
solids
used).
HHAP,
y
=
organic
HAP
emission
rate
for
month,
y,
determined
according
to
Equation
4
of
this
section.
Mst,
y
=
total
mass
of
coating
solids
used
during
month,
y,
lb,
from
Equation
2
of
§
63.4551.
y
=
identifier
for
months.
(
n)
Compliance
demonstration.
To
demonstrate
initial
compliance
with
the
emission
limit,
calculated
using
Equation
5
of
this
section,
must
be
less
than
or
equal
to
the
applicable
emission
limit
for
each
subcategory
in
§
63.4490.
You
must
keep
all
records
as
required
by
§
§
63.4530
and
63.4531.
As
part
of
the
Notification
of
Compliance
Status
required
by
§
63.4510,
you
must
identify
the
coating
operation(
s)
for
which
you
used
the
emission
rate
with
add
on
controls
option
and
submit
a
statement
that
the
coating
operation(
s)
was
(
were)
in
compliance
with
the
emission
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72315
Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
limitations
during
the
initial
compliance
period
because
the
organic
HAP
emission
rate
was
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4490,
and
you
achieved
the
operating
limits
required
by
§
63.4492
and
the
work
practice
standards
required
by
§
63.4493.
§
63.4562
[
Reserved.]
§
63.4563
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
(
a)
To
demonstrate
continuous
compliance
with
the
applicable
emission
limit
in
§
63.4490,
the
organic
HAP
emission
rate
for
each
compliance
period,
determined
according
to
the
procedures
in
§
63.4561,
must
be
equal
to
or
less
than
the
applicable
emission
limit
in
§
63.4490
for
that
subcategory.
A
compliance
period
consists
of
12
months.
Each
month
after
the
end
of
the
initial
compliance
period
described
in
§
63.4560
is
the
end
of
a
compliance
period
consisting
of
that
month
and
the
preceding
11
months.
You
must
perform
the
calculations
in
§
63.4561
on
a
monthly
basis
using
data
from
the
previous
12
months
of
operation.
(
b)
If
the
organic
HAP
emission
rate
for
any
12
month
compliance
period
exceeded
the
applicable
emission
limit
in
§
63.4490,
this
is
a
deviation
from
the
emission
limitation
for
that
compliance
period
and
must
be
reported
as
specified
in
§
§
63.4510(
b)(
6)
and
63.4520(
a)(
7).
(
c)
You
must
demonstrate
continuous
compliance
with
each
operating
limit
required
by
§
63.4492
that
applies
to
you,
as
specified
in
Table
1
of
this
subpart.
(
1)
If
an
operating
parameter
is
out
of
the
allowed
range
specified
in
Table
1
of
this
subpart,
this
is
a
deviation
from
the
operating
limit
that
must
be
reported
as
specified
in
§
§
63.4510(
b)(
6)
and
63.4520(
a)(
7).
(
2)
If
an
operating
parameter
deviates
from
the
operating
limit
specified
in
Table
1
of
this
subpart,
then
you
must
assume
that
the
emission
capture
system
and
add
on
control
device
were
achieving
zero
efficiency
during
the
time
period
of
the
deviation.
For
the
purposes
of
completing
the
compliance
calculations
specified
in
§
§
63.4561(
h),
you
must
treat
the
materials
used
during
a
deviation
on
a
controlled
coating
operation
as
if
they
were
used
on
an
uncontrolled
coating
operation
for
the
time
period
of
the
deviation
as
indicated
in
Equation
1
of
§
63.4561.
(
d)
You
must
meet
the
requirements
for
bypass
lines
in
§
63.4568(
b)
for
controlled
coating
operations
for
which
you
do
not
conduct
liquid
liquid
material
balances.
If
any
bypass
line
is
opened
and
emissions
are
diverted
to
the
atmosphere
when
the
coating
operation
is
running,
this
is
a
deviation
that
must
be
reported
as
specified
in
§
§
63.4510(
b)(
6)
and
63.4520(
a)(
7).
For
the
purposes
of
completing
the
compliance
calculations
specified
in
§
§
63.4561(
h),
you
must
treat
the
materials
used
during
a
deviation
on
a
controlled
coating
operation
as
if
they
were
used
on
an
uncontrolled
coating
operation
for
the
time
period
of
the
deviation
as
indicated
in
Equation
1
of
§
63.4561.
(
e)
You
must
demonstrate
continuous
compliance
with
the
work
practice
standards
in
§
63.4493.
If
you
did
not
develop
a
work
practice
plan,
or
you
did
not
implement
the
plan,
or
you
did
not
keep
the
records
required
by
§
63.4530(
k)(
8),
this
is
a
deviation
from
the
work
practice
standards
that
must
be
reported
as
specified
in
§
§
63.4510(
c)(
6)
and
63.4520(
a)(
7).
(
f)
As
part
of
each
semiannual
compliance
report
required
in
§
63.4520,
you
must
identify
the
coating
operation(
s)
for
which
you
used
the
emission
rate
with
add
on
controls
option.
If
there
were
no
deviations
from
the
emission
limitations,
submit
a
statement
that
you
were
in
compliance
with
the
emission
limitations
during
the
reporting
period
because
the
organic
HAP
emission
rate
for
each
compliance
period
was
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.4490,
and
you
achieved
the
operating
limits
required
by
§
63.4492
and
the
work
practice
standards
required
by
§
63.4493
during
each
compliance
period.
(
g)
During
periods
of
startup,
shutdown,
or
malfunction
of
the
emission
capture
system,
add
on
control
device,
or
coating
operation
that
may
affect
emission
capture
or
control
device
efficiency,
you
must
operate
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan
required
by
§
63.4500(
c).
(
h)
Consistent
with
§
§
63.6(
e)
and
63.7(
e)(
1),
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
of
the
emission
capture
system,
add
on
control
device,
or
coating
operation
that
may
affect
emission
capture
or
control
device
efficiency
are
not
violations
if
you
demonstrate
to
the
Administrator's
satisfaction
that
you
were
operating
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan.
The
Administrator
will
determine
whether
deviations
that
occur
during
a
period
you
identify
as
a
startup,
shutdown,
or
malfunction
are
violations,
according
to
the
provisions
in
§
63.6(
e).
(
i)
[
Reserved]
(
j)
You
must
maintain
records
as
specified
in
§
§
63.4530
and
63.4531.
§
63.4564
What
are
the
general
requirements
for
performance
tests?
(
a)
You
must
conduct
each
performance
test
required
by
§
63.4560
according
to
the
requirements
in
§
63.7(
e)(
1)
and
under
the
conditions
in
this
section,
unless
you
obtain
a
waiver
of
the
performance
test
according
to
the
provisions
in
§
63.7(
h).
(
1)
Representative
coating
operation
operating
conditions.
You
must
conduct
the
performance
test
under
representative
operating
conditions
for
the
coating
operation.
Operations
during
periods
of
startup,
shutdown,
or
malfunction
and
during
periods
of
nonoperation
do
not
constitute
representative
conditions.
You
must
record
the
process
information
that
is
necessary
to
document
operating
conditions
during
the
test
and
explain
why
the
conditions
represent
normal
operation.
(
2)
Representative
emission
capture
system
and
add
on
control
device
operating
conditions.
You
must
conduct
the
performance
test
when
the
emission
capture
system
and
add
on
control
device
are
operating
at
a
representative
flow
rate,
and
the
add
on
control
device
is
operating
at
a
representative
inlet
concentration.
You
must
record
information
that
is
necessary
to
document
emission
capture
system
and
add
on
control
device
operating
conditions
during
the
test
and
explain
why
the
conditions
represent
normal
operation.
(
b)
You
must
conduct
each
performance
test
of
an
emission
capture
system
according
to
the
requirements
in
§
63.4565.
You
must
conduct
each
performance
test
of
an
add
on
control
device
according
to
the
requirements
in
§
63.4566.
§
63.4565
How
do
I
determine
the
emission
capture
system
efficiency?
You
must
use
the
procedures
and
test
methods
in
this
section
to
determine
capture
efficiency
as
part
of
the
performance
test
required
by
§
63.4560.
(
a)
Assuming
100
percent
capture
efficiency.
You
may
assume
the
capture
system
efficiency
is
100
percent
if
both
of
the
conditions
in
paragraphs
(
a)(
1)
and
(
2)
of
this
section
are
met:
(
1)
The
capture
system
meets
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
a
PTE
and
directs
all
the
exhaust
gases
from
the
enclosure
to
an
add
on
control
device.
(
2)
All
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
in
the
coating
operation
are
applied
within
the
capture
system;
coating
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Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
solvent
flash
off,
curing,
and
drying
occurs
within
the
capture
system;
and
the
removal
or
evaporation
of
cleaning
materials
from
the
surfaces
they
are
applied
to
occurs
within
the
capture
system.
For
example,
this
criterion
is
not
met
if
parts
enter
the
open
shop
environment
when
being
moved
between
a
spray
booth
and
a
curing
oven.
(
b)
Measuring
capture
efficiency.
If
the
capture
system
does
not
meet
both
of
the
criteria
in
paragraphs
(
a)(
1)
and
(
2)
of
this
section,
then
you
must
use
one
of
the
three
protocols
described
in
paragraphs
(
c),
(
d),
and
(
e)
of
this
section
to
measure
capture
efficiency.
The
capture
efficiency
measurements
use
TVH
capture
efficiency
as
a
surrogate
for
organic
HAP
capture
efficiency.
For
the
protocols
in
paragraphs
(
c)
and
(
d)
of
this
section,
the
capture
efficiency
measurement
must
consist
of
three
test
runs.
Each
test
run
must
be
at
least
3
hours
duration
or
the
length
of
a
production
run,
whichever
is
longer,
up
to
8
hours.
For
the
purposes
of
this
test,
a
production
run
means
the
time
required
for
a
single
part
to
go
from
the
beginning
to
the
end
of
the
production,
which
includes
surface
preparation
activities
and
drying
and
curing
time.
(
c)
Liquid
to
uncaptured
gas
protocol
using
a
temporary
total
enclosure
or
building
enclosure.
The
liquid
touncaptured
gas
protocol
compares
the
mass
of
liquid
TVH
in
materials
used
in
the
coating
operation
to
the
mass
of
TVH
emissions
not
captured
by
the
emission
capture
system.
Use
a
temporary
total
enclosure
or
a
building
enclosure
and
the
procedures
in
paragraphs
(
c)(
1)
through
(
6)
of
this
section
to
measure
emission
capture
system
efficiency
using
the
liquid
touncaptured
gas
protocol.
(
1)
Either
use
a
building
enclosure
or
construct
an
enclosure
around
the
coating
operation
where
coatings,
thinners
and
other
additives,
and
cleaning
materials
are
applied,
and
all
areas
where
emissions
from
these
applied
coatings
and
materials
subsequently
occur,
such
as
flash
off,
curing,
and
drying
areas.
The
areas
of
the
coating
operation
where
capture
devices
collect
emissions
for
routing
to
an
add
on
control
device,
such
as
the
entrance
and
exit
areas
of
an
oven
or
spray
booth,
must
also
be
inside
the
enclosure.
The
enclosure
must
meet
the
applicable
definition
of
a
temporary
total
enclosure
or
building
enclosure
in
Method
204
of
appendix
M
to
40
CFR
part
51.
(
2)
Use
Method
204A
or
204F
of
appendix
M
to
40
CFR
part
51
to
determine
the
mass
fraction
of
TVH
liquid
input
from
each
coating,
thinner
and
other
additive,
and
cleaning
material
used
in
the
coating
operation
during
each
capture
efficiency
test
run.
To
make
the
determination,
substitute
TVH
for
each
occurrence
of
the
term
volatile
organic
compounds
(
VOC)
in
the
methods.
(
3)
Use
Equation
1
of
this
section
to
calculate
the
total
mass
of
TVH
liquid
input
from
all
the
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
in
the
coating
operation
during
each
capture
efficiency
test
run:
TVH
TVH
Vol
D
Eq
used
i
i
n
i
i
=
(
)(
)(
)
=
1
(
.
1)
Where:
TVHused
=
Mass
of
liquid
TVH
in
materials
used
in
the
coating
operation
during
the
capture
efficiency
test
run,
lb.
TVHi
=
mass
fraction
of
TVH
in
coating,
thinner
or
other
additive,
or
cleaning
material,
i,
that
is
used
in
the
coating
operation
during
the
capture
efficiency
test
run,
lb
TVH
per
lb
material.
Voli
=
total
volume
of
coating,
thinner
or
other
additive,
or
cleaning
material,
i,
used
in
the
coating
operation
during
the
capture
efficiency
test
run,
gallons.
Di
=
density
of
coating,
thinner
or
other
additive,
or
cleaning
material,
i,
lb
material
per
gallon
material.
n
=
number
of
different
coatings,
thinners
and
other
additives,
and
cleaning
materials
used
in
the
coating
operation
during
the
capture
efficiency
test
run.
(
4)
Use
Method
204D
or
E
of
appendix
M
to
40
CFR
part
51
to
measure
the
total
mass,
lb,
of
TVH
emissions
that
are
not
captured
by
the
emission
capture
system;
they
are
measured
as
they
exit
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run.
To
make
the
measurement,
substitute
TVH
for
each
occurrence
of
the
term
VOC
in
the
methods.
(
i)
Use
Method
204D
if
the
enclosure
is
a
temporary
total
enclosure.
(
ii)
Use
Method
204E
if
the
enclosure
is
a
building
enclosure.
During
the
capture
efficiency
measurement,
all
organic
compound
emitting
operations
inside
the
building
enclosure,
other
than
the
coating
operation
for
which
capture
efficiency
is
being
determined,
must
be
shut
down,
but
all
fans
and
blowers
must
be
operating
normally.
(
5)
For
each
capture
efficiency
test
run,
determine
the
percent
capture
efficiency
of
the
emission
capture
system
using
Equation
2
of
this
section:
CE
TVH
TVH
TVH
used
uncaptured
used
=
(
)
×
100
(
Eq.
2)
Where:
CE
=
capture
efficiency
of
the
emission
capture
system
vented
to
the
add
on
control
device,
percent.
TVHused
=
total
mass
of
TVH
liquid
input
used
in
the
coating
operation
during
the
capture
efficiency
test
run,
lb.
TVHuncaptured
=
total
mass
of
TVH
that
is
not
captured
by
the
emission
capture
system
and
that
exits
from
the
temporary
total
enclosure
or
building
enclosure
during
the
capture
efficiency
test
run,
lb.
(
6)
Determine
the
capture
efficiency
of
the
emission
capture
system
as
the
average
of
the
capture
efficiencies
measured
in
the
three
test
runs.
(
d)
Gas
to
gas
protocol
using
a
temporary
total
enclosure
or
a
building
enclosure.
The
gas
to
gas
protocol
compares
the
mass
of
TVH
emissions
captured
by
the
emission
capture
system
to
the
mass
of
TVH
emissions
not
captured.
Use
a
temporary
total
enclosure
or
a
building
enclosure
and
the
procedures
in
paragraphs
(
d)(
1)
through
(
5)
of
this
section
to
measure
emission
capture
system
efficiency
using
the
gas
to
gas
protocol.
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Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
(
1)
Either
use
a
building
enclosure
or
construct
an
enclosure
around
the
coating
operation
where
coatings,
thinners
and
other
additives,
and
cleaning
materials
are
applied,
and
all
areas
where
emissions
from
these
applied
coatings
and
materials
subsequently
occur,
such
as
flash
off,
curing,
and
drying
areas.
The
areas
of
the
coating
operation
where
capture
devices
collect
emissions
generated
by
the
coating
operation
for
routing
to
an
add
on
control
device,
such
as
the
entrance
and
exit
areas
of
an
oven
or
a
spray
booth,
must
also
be
inside
the
enclosure.
The
enclosure
must
meet
the
applicable
definition
of
a
temporary
total
enclosure
or
building
enclosure
in
Method
204
of
appendix
M
to
40
CFR
part
51.
(
2)
Use
Method
204B
or
204C
of
appendix
M
to
40
CFR
part
51
to
measure
the
total
mass,
lb,
of
TVH
emissions
captured
by
the
emission
capture
system
during
each
capture
efficiency
test
run
as
measured
at
the
inlet
to
the
add
on
control
device.
To
make
the
measurement,
substitute
TVH
for
each
occurrence
of
the
term
VOC
in
the
methods.
(
i)
The
sampling
points
for
the
Method
204B
or
204C
measurement
must
be
upstream
from
the
add
on
control
device
and
must
represent
total
emissions
routed
from
the
capture
system
and
entering
the
add
on
control
device.
(
ii)
If
multiple
emission
streams
from
the
capture
system
enter
the
add
on
control
device
without
a
single
common
duct,
then
the
emissions
entering
the
add
on
control
device
must
be
simultaneously
measured
in
each
duct
and
the
total
emissions
entering
the
add
on
control
device
must
be
determined.
(
3)
Use
Method
204D
or
204E
of
appendix
M
to
40
CFR
part
51
to
measure
the
total
mass,
lb,
of
TVH
emissions
that
are
not
captured
by
the
emission
capture
system;
they
are
measured
as
they
exit
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run.
To
make
the
measurement,
substitute
TVH
for
each
occurrence
of
the
term
VOC
in
the
methods.
(
i)
Use
Method
204D
if
the
enclosure
is
a
temporary
total
enclosure.
(
ii)
Use
Method
204E
if
the
enclosure
is
a
building
enclosure.
During
the
capture
efficiency
measurement,
all
organic
compound
emitting
operations
inside
the
building
enclosure,
other
than
the
coating
operation
for
which
capture
efficiency
is
being
determined,
must
be
shut
down,
but
all
fans
and
blowers
must
be
operating
normally.
(
4)
For
each
capture
efficiency
test
run,
determine
the
percent
capture
efficiency
of
the
emission
capture
system
using
Equation
3
of
this
section:
CE
TVH
TVH
TVH
captured
captured
uncaptured
=
+
(
)
×
100
(
Eq.
3)
Where:
CE
=
capture
efficiency
of
the
emission
capture
system
vented
to
the
add
on
control
device,
percent.
TVHcaptured
=
total
mass
of
TVH
captured
by
the
emission
capture
system
as
measured
at
the
inlet
to
the
add
on
control
device
during
the
emission
capture
efficiency
test
run,
lb.
TVHuncaptured
=
total
mass
of
TVH
that
is
not
captured
by
the
emission
capture
system
and
that
exits
from
the
temporary
total
enclosure
or
building
enclosure
during
the
capture
efficiency
test
run,
lb.
(
5)
Determine
the
capture
efficiency
of
the
emission
capture
system
as
the
average
of
the
capture
efficiencies
measured
in
the
three
test
runs.
(
e)
Alternative
capture
efficiency
protocol.
As
an
alternative
to
the
procedures
specified
in
paragraphs
(
c)
and
(
d)
of
this
section,
you
may
determine
capture
efficiency
using
any
other
capture
efficiency
protocol
and
test
methods
that
satisfy
the
criteria
of
either
the
DQO
or
LCL
approach
as
described
in
appendix
A
to
subpart
KK
of
this
part.
§
63.4566
How
do
I
determine
the
add
on
control
device
emission
destruction
or
removal
efficiency?
You
must
use
the
procedures
and
test
methods
in
this
section
to
determine
the
add
on
control
device
emission
destruction
or
removal
efficiency
as
part
of
the
performance
test
required
by
§
63.4560.
You
must
conduct
three
test
runs
as
specified
in
§
63.7(
e)(
3)
and
each
test
run
must
last
at
least
1
hour.
(
a)
For
all
types
of
add
on
control
devices,
use
the
test
methods
specified
in
paragraphs
(
a)(
1)
through
(
5)
of
this
section.
(
1)
Use
Method
1
or
1A
of
appendix
A
to
40
CFR
part
60,
as
appropriate,
to
select
sampling
sites
and
velocity
traverse
points.
(
2)
Use
Method
2,
2A,
2C,
2D,
2F,
or
2G
of
appendix
A
to
40
CFR
part
60,
as
appropriate,
to
measure
gas
volumetric
flow
rate.
(
3)
Use
Method
3,
3A,
or
3B
of
appendix
A
to
40
CFR
part
60,
as
appropriate,
for
gas
analysis
to
determine
dry
molecular
weight.
(
4)
Use
Method
4
of
appendix
A
to
40
CFR
part
60,
to
determine
stack
gas
moisture.
(
5)
Methods
for
determining
gas
volumetric
flow
rate,
dry
molecular
weight,
and
stack
gas
moisture
must
be
performed,
as
applicable,
during
each
test
run.
(
b)
Measure
total
gaseous
organic
mass
emissions
as
carbon
at
the
inlet
and
outlet
of
the
add
on
control
device
simultaneously,
using
either
Method
25
or
25A
of
appendix
A
to
40
CFR
part
60.
(
1)
Use
Method
25
if
the
add
on
control
device
is
an
oxidizer
and
you
expect
the
total
gaseous
organic
concentration
as
carbon
to
be
more
than
50
parts
per
million
(
ppm)
at
the
control
device
outlet.
(
2)
Use
Method
25A
if
the
add
on
control
device
is
an
oxidizer
and
you
expect
the
total
gaseous
organic
concentration
as
carbon
to
be
50
ppm
or
less
at
the
control
device
outlet.
(
3)
Use
Method
25A
if
the
add
on
control
device
is
not
an
oxidizer.
(
c)
If
two
or
more
add
on
control
devices
are
used
for
the
same
emission
stream,
then
you
must
measure
emissions
at
the
outlet
to
the
atmosphere
of
each
device.
For
example,
if
one
add
on
control
device
is
a
concentrator
with
an
outlet
to
the
atmosphere
for
the
high
volume,
dilute
stream
that
has
been
treated
by
the
concentrator,
and
a
second
add
on
control
device
is
an
oxidizer
with
an
outlet
to
the
atmosphere
for
the
lowvolume
concentrated
stream
that
is
treated
with
the
oxidizer,
you
must
measure
emissions
at
the
outlet
of
the
oxidizer
and
the
high
volume
dilute
stream
outlet
of
the
concentrator.
(
d)
For
each
test
run,
determine
the
total
gaseous
organic
emissions
mass
flow
rates
for
the
inlet
and
the
outlet
of
the
add
on
control
device,
using
Equation
1
of
this
section.
If
there
is
more
than
one
inlet
or
outlet
to
the
addon
control
device,
you
must
calculate
the
total
gaseous
organic
mass
flow
rate
using
Equation
1
of
this
section
for
each
inlet
and
each
outlet
and
then
total
all
of
the
inlet
emissions
and
total
all
of
the
outlet
emissions:
Mf
=
Qsd
Cc
(
12)
(
0.0416)
(
10
¥
6)
(
Eq.
1)
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72318
Federal
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
Where:
Mf
=
total
gaseous
organic
emissions
mass
flow
rate,
kg/
per
hour
(
h).
Cc
=
concentration
of
organic
compounds
as
carbon
in
the
vent
gas,
as
determined
by
Method
25
or
Method
25A,
parts
per
million
by
volume
(
ppmv),
dry
basis.
Qsd
=
volumetric
flow
rate
of
gases
entering
or
exiting
the
add
on
control
device,
as
determined
by
Method
2,
2A,
2C,
2D,
2F,
or
2G,
dry
standard
cubic
meters/
hour
(
dscm/
h).
0.0416
=
conversion
factor
for
molar
volume,
kg
moles
per
cubic
meter
(
mol/
m3)
(@
293
Kelvin
(
K)
and
760
millimeters
of
mercury
(
mmHg)).
(
e)
For
each
test
run,
determine
the
add
on
control
device
organic
emissions
destruction
or
removal
efficiency,
using
Equation
2
of
this
section:
DRE=
M
M
M
(
Eq.
2)
fi
fo
fi
·
100
Where:
DRE
=
organic
emissions
destruction
or
removal
efficiency
of
the
add
on
control
device,
percent.
Mfi
=
total
gaseous
organic
emissions
mass
flow
rate
at
the
inlet(
s)
to
the
add
on
control
device,
using
Equation
1
of
this
section,
kg/
h.
Mfo
=
total
gaseous
organic
emissions
mass
flow
rate
at
the
outlet(
s)
of
the
add
on
control
device,
using
Equation
1
of
this
section,
kg/
h.
(
f)
Determine
the
emission
destruction
or
removal
efficiency
of
the
add
on
control
device
as
the
average
of
the
efficiencies
determined
in
the
three
test
runs
and
calculated
in
Equation
2
of
this
section.
§
63.4567
How
do
I
establish
the
emission
capture
system
and
add
on
control
device
operating
limits
during
the
performance
test?
During
the
performance
test
required
by
§
63.4560
and
described
in
§
§
63.4564,
63.4565,
and
63.4566,
you
must
establish
the
operating
limits
required
by
§
63.4492
according
to
this
section,
unless
you
have
received
approval
for
alternative
monitoring
and
operating
limits
under
§
63.8(
f)
as
specified
in
§
63.4492.
(
a)
Thermal
oxidizers.
If
your
add
on
control
device
is
a
thermal
oxidizer,
establish
the
operating
limits
according
to
paragraphs
(
a)(
1)
and
(
2)
of
this
section.
(
1)
During
the
performance
test,
you
must
monitor
and
record
the
combustion
temperature
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
You
must
monitor
the
temperature
in
the
firebox
of
the
thermal
oxidizer
or
immediately
downstream
of
the
firebox
before
any
substantial
heat
exchange
occurs.
(
2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
combustion
temperature
maintained
during
the
performance
test.
This
average
combustion
temperature
is
the
minimum
operating
limit
for
your
thermal
oxidizer.
(
b)
Catalytic
oxidizers.
If
your
add
on
control
device
is
a
catalytic
oxidizer,
establish
the
operating
limits
according
to
either
paragraphs
(
b)(
1)
and
(
2)
or
paragraphs
(
b)(
3)
and
(
4)
of
this
section.
(
1)
During
the
performance
test,
you
must
monitor
and
record
the
temperature
just
before
the
catalyst
bed
and
the
temperature
difference
across
the
catalyst
bed
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
(
2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
temperature
just
before
the
catalyst
bed
and
the
average
temperature
difference
across
the
catalyst
bed
maintained
during
the
performance
test.
These
are
the
minimum
operating
limits
for
your
catalytic
oxidizer.
(
3)
As
an
alternative
to
monitoring
the
temperature
difference
across
the
catalyst
bed,
you
may
monitor
the
temperature
at
the
inlet
to
the
catalyst
bed
and
implement
a
site
specific
inspection
and
maintenance
plan
for
your
catalytic
oxidizer
as
specified
in
paragraph
(
b)(
4)
of
this
section.
During
the
performance
test,
you
must
monitor
and
record
the
temperature
just
before
the
catalyst
bed
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
temperature
just
before
the
catalyst
bed
during
the
performance
test.
This
is
the
minimum
operating
limit
for
your
catalytic
oxidizer.
(
4)
You
must
develop
and
implement
an
inspection
and
maintenance
plan
for
your
catalytic
oxidizer(
s)
for
which
you
elect
to
monitor
according
to
paragraph
(
b)(
3)
of
this
section.
The
plan
must
address,
at
a
minimum,
the
elements
specified
in
paragraphs
(
b)(
4)(
i)
through
(
iii)
of
this
section.
(
i)
Annual
sampling
and
analysis
of
the
catalyst
activity
(
i.
e,
conversion
efficiency)
following
the
manufacturer's
or
catalyst
supplier's
recommended
procedures.
(
ii)
Monthly
inspection
of
the
oxidizer
system,
including
the
burner
assembly
and
fuel
supply
lines
for
problems
and,
as
necessary,
adjust
the
equipment
to
assure
proper
air
to
fuel
mixtures.
(
iii)
Annual
internal
and
monthly
external
visual
inspection
of
the
catalyst
bed
to
check
for
channeling,
abrasion,
and
settling.
If
problems
are
found,
you
must
take
corrective
action
consistent
with
the
manufacturer's
recommendations
and
conduct
a
new
performance
test
to
determine
destruction
efficiency
according
to
§
63.4566.
(
c)
Carbon
adsorbers.
If
your
add
on
control
device
is
a
carbon
adsorber,
establish
the
operating
limits
according
to
paragraphs
(
c)(
1)
and
(
2)
of
this
section.
(
1)
You
must
monitor
and
record
the
total
regeneration
desorbing
gas
(
e.
g.,
steam
or
nitrogen)
mass
flow
for
each
regeneration
cycle,
and
the
carbon
bed
temperature
after
each
carbon
bed
regeneration
and
cooling
cycle
for
the
regeneration
cycle
either
immediately
preceding
or
immediately
following
the
performance
test.
(
2)
The
operating
limits
for
your
carbon
adsorber
are
the
minimum
total
desorbing
gas
mass
flow
recorded
during
the
regeneration
cycle
and
the
maximum
carbon
bed
temperature
recorded
after
the
cooling
cycle.
(
d)
Condensers.
If
your
add
on
control
device
is
a
condenser,
establish
the
operating
limits
according
to
paragraphs
(
d)(
1)
and
(
2)
of
this
section.
(
1)
During
the
performance
test,
you
must
monitor
and
record
the
condenser
outlet
(
product
side)
gas
temperature
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
(
2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
condenser
outlet
(
product
side)
gas
temperature
maintained
during
the
performance
test.
This
average
condenser
outlet
gas
temperature
is
the
maximum
operating
limit
for
your
condenser.
(
e)
Concentrator.
If
your
add
on
control
device
includes
a
concentrator,
you
must
establish
operating
limits
for
the
concentrator
according
to
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
paragraphs
(
e)(
1)
through
(
4)
of
this
section.
(
1)
During
the
performance
test,
you
must
monitor
and
record
the
desorption
concentrate
stream
gas
temperature
at
least
once
every
15
minutes
during
each
of
the
three
runs
of
the
performance
test.
(
2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
temperature.
This
is
the
minimum
operating
limit
for
the
desorption
concentrate
gas
stream
temperature.
(
3)
During
the
performance
test,
you
must
monitor
and
record
the
pressure
drop
of
the
dilute
stream
across
the
concentrator
at
least
once
every
15
minutes
during
each
of
the
three
runs
of
the
performance
test.
(
4)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
pressure
drop.
This
is
the
maximum
operating
limit
for
the
dilute
stream
across
the
concentrator.
(
f)
Emission
capture
system.
For
each
capture
device
that
is
not
part
of
a
PTE
that
meets
the
criteria
of
§
63.4565(
a),
establish
an
operating
limit
for
either
the
gas
volumetric
flow
rate
or
duct
static
pressure,
as
specified
in
paragraphs
(
f)(
1)
and
(
2)
of
this
section.
The
operating
limit
for
a
PTE
is
specified
in
Table
1
of
this
subpart.
(
1)
During
the
capture
efficiency
determination
required
by
§
63.4560
and
described
in
§
§
63.4564
and
63.4565,
you
must
monitor
and
record
either
the
gas
volumetric
flow
rate
or
the
duct
static
pressure
for
each
separate
capture
device
in
your
emission
capture
system
at
least
once
every
15
minutes
during
each
of
the
three
test
runs
at
a
point
in
the
duct
between
the
capture
device
and
the
add
on
control
device
inlet.
(
2)
Calculate
and
record
the
average
gas
volumetric
flow
rate
or
duct
static
pressure
for
the
three
test
runs
for
each
capture
device.
This
average
gas
volumetric
flow
rate
or
duct
static
pressure
is
the
minimum
operating
limit
for
that
specific
capture
device.
§
63.4568
What
are
the
requirements
for
continuous
parameter
monitoring
system
installation,
operation,
and
maintenance?
(
a)
General.
You
must
install,
operate,
and
maintain
each
CPMS
specified
in
paragraphs
(
c),
(
e),
(
f),
and
(
g)
of
this
section
according
to
paragraphs
(
a)(
1)
through
(
6)
of
this
section.
You
must
install,
operate,
and
maintain
each
CPMS
specified
in
paragraphs
(
b)
and
(
d)
of
this
section
according
to
paragraphs
(
a)(
3)
through
(
5)
of
this
section.
(
1)
The
CPMS
must
complete
a
minimum
of
one
cycle
of
operation
for
each
successive
15
minute
period.
You
must
have
a
minimum
of
four
equally
spaced
successive
cycles
of
CPMS
operation
in
1
hour.
(
2)
You
must
determine
the
average
of
all
recorded
readings
for
each
successive
3
hour
period
of
the
emission
capture
system
and
add
on
control
device
operation.
(
3)
You
must
record
the
results
of
each
inspection,
calibration,
and
validation
check
of
the
CPMS.
(
4)
You
must
maintain
the
CPMS
at
all
times
and
have
available
necessary
parts
for
routine
repairs
of
the
monitoring
equipment.
(
5)
You
must
operate
the
CPMS
and
collect
emission
capture
system
and
add
on
control
device
parameter
data
at
all
times
that
a
controlled
coating
operation
is
operating,
except
during
monitoring
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
(
including,
if
applicable,
calibration
checks
and
required
zero
and
span
adjustments).
(
6)
You
must
not
use
emission
capture
system
or
add
on
control
device
parameter
data
recorded
during
monitoring
malfunctions,
associated
repairs,
out
of
control
periods,
or
required
quality
assurance
or
control
activities
when
calculating
data
averages.
You
must
use
all
the
data
collected
during
all
other
periods
in
calculating
the
data
averages
for
determining
compliance
with
the
emission
capture
system
and
add
on
control
device
operating
limits.
(
7)
A
monitoring
malfunction
is
any
sudden,
infrequent,
not
reasonably
preventable
failure
of
the
CPMS
to
provide
valid
data.
Monitoring
failures
that
are
caused
in
part
by
poor
maintenance
or
careless
operation
are
not
malfunctions.
Any
period
for
which
the
monitoring
system
is
out
of
control
and
data
are
not
available
for
required
calculations
is
a
deviation
from
the
monitoring
requirements.
(
b)
Capture
system
bypass
line.
You
must
meet
the
requirements
of
paragraphs
(
b)(
1)
and
(
2)
of
this
section
for
each
emission
capture
system
that
contains
bypass
lines
that
could
divert
emissions
away
from
the
add
on
control
device
to
the
atmosphere.
(
1)
You
must
monitor
or
secure
the
valve
or
closure
mechanism
controlling
the
bypass
line
in
a
nondiverting
position
in
such
a
way
that
the
valve
or
closure
mechanism
cannot
be
opened
without
creating
a
record
that
the
valve
was
opened.
The
method
used
to
monitor
or
secure
the
valve
or
closure
mechanism
must
meet
one
of
the
requirements
specified
in
paragraphs
(
b)(
1)(
i)
through
(
iv)
of
this
section.
(
i)
Flow
control
position
indicator.
Install,
calibrate,
maintain,
and
operate
according
to
the
manufacturer's
specifications
a
flow
control
position
indicator
that
takes
a
reading
at
least
once
every
15
minutes
and
provides
a
record
indicating
whether
the
emissions
are
directed
to
the
add
on
control
device
or
diverted
from
the
add
on
control
device.
The
time
of
occurrence
and
flow
control
position
must
be
recorded,
as
well
as
every
time
the
flow
direction
is
changed.
The
flow
control
position
indicator
must
be
installed
at
the
entrance
to
any
bypass
line
that
could
divert
the
emissions
away
from
the
addon
control
device
to
the
atmosphere.
(
ii)
Car
seal
or
lock
and
key
valve
closures.
Secure
any
bypass
line
valve
in
the
closed
position
with
a
car
seal
or
a
lock
and
key
type
configuration.
You
must
visually
inspect
the
seal
or
closure
mechanism
at
least
once
every
month
to
ensure
that
the
valve
is
maintained
in
the
closed
position,
and
the
emissions
are
not
diverted
away
from
the
add
on
control
device
to
the
atmosphere.
(
iii)
Valve
closure
monitoring.
Ensure
that
any
bypass
line
valve
is
in
the
closed
(
nondiverting)
position
through
monitoring
of
valve
position
at
least
once
every
15
minutes.
You
must
inspect
the
monitoring
system
at
least
once
every
month
to
verify
that
the
monitor
will
indicate
valve
position.
(
iv)
Automatic
shutdown
system.
Use
an
automatic
shutdown
system
in
which
the
coating
operation
is
stopped
when
flow
is
diverted
by
the
bypass
line
away
from
the
add
on
control
device
to
the
atmosphere
when
the
coating
operation
is
running.
You
must
inspect
the
automatic
shutdown
system
at
least
once
every
month
to
verify
that
it
will
detect
diversions
of
flow
and
shut
down
the
coating
operation.
(
2)
If
any
bypass
line
is
opened,
you
must
include
a
description
of
why
the
bypass
line
was
opened
and
the
length
of
time
it
remained
open
in
the
semiannual
compliance
reports
required
in
§
63.4520.
(
c)
Thermal
oxidizers
and
catalytic
oxidizers.
If
you
are
using
a
thermal
oxidizer
or
catalytic
oxidizer
as
an
addon
control
device
(
including
those
used
with
concentrators
or
with
carbon
adsorbers
to
treat
desorbed
concentrate
streams),
you
must
comply
with
the
requirements
in
paragraphs
(
c)(
1)
through
(
3)
of
this
section:
(
1)
For
a
thermal
oxidizer,
install
a
gas
temperature
monitor
in
the
firebox
of
the
thermal
oxidizer
or
in
the
duct
immediately
downstream
of
the
firebox
before
any
substantial
heat
exchange
occurs.
(
2)
For
a
catalytic
oxidizer,
install
gas
temperature
monitors
both
upstream
and
downstream
of
the
catalyst
bed.
The
temperature
monitors
must
be
in
the
gas
stream
immediately
before
and
after
the
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Federal
Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
catalyst
bed
to
measure
the
temperature
difference
across
the
bed.
(
3)
For
all
thermal
oxidizers
and
catalytic
oxidizers,
you
must
meet
the
requirements
in
paragraphs
(
a)
and
(
c)(
3)(
i)
through
(
vii)
of
this
section
for
each
gas
temperature
monitoring
device.
(
i)
Locate
the
temperature
sensor
in
a
position
that
provides
a
representative
temperature.
(
ii)
Use
a
temperature
sensor
with
a
measurement
sensitivity
of
4
degrees
Fahrenheit
or
0.75
percent
of
the
temperature
value,
whichever
is
larger.
(
iii)
Shield
the
temperature
sensor
system
from
electromagnetic
interference
and
chemical
contaminants.
(
iv)
If
a
gas
temperature
chart
recorder
is
used,
it
must
have
a
measurement
sensitivity
in
the
minor
division
of
at
least
20
degrees
Fahrenheit.
(
v)
Perform
an
electronic
calibration
at
least
semiannually
according
to
the
procedures
in
the
manufacturer's
owners
manual.
Following
the
electronic
calibration,
you
must
conduct
a
temperature
sensor
validation
check
in
which
a
second
or
redundant
temperature
sensor
placed
nearby
the
process
temperature
sensor
must
yield
a
reading
within
30
degrees
Fahrenheit
of
the
process
temperature
sensor
reading.
(
vi)
Conduct
calibration
and
validation
checks
any
time
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
temperature
range
or
install
a
new
temperature
sensor.
(
vii)
At
least
monthly,
inspect
components
for
integrity
and
electrical
connections
for
continuity,
oxidation,
and
galvanic
corrosion.
(
d)
Carbon
adsorbers.
If
you
are
using
a
carbon
adsorber
as
an
add
on
control
device,
you
must
monitor
the
total
regeneration
desorbing
gas
(
e.
g.,
steam
or
nitrogen)
mass
flow
for
each
regeneration
cycle,
the
carbon
bed
temperature
after
each
regeneration
and
cooling
cycle,
and
comply
with
paragraphs
(
a)(
3)
through
(
5)
and
(
d)(
1)
and
(
2)
of
this
section.
(
1)
The
regeneration
desorbing
gas
mass
flow
monitor
must
be
an
integrating
device
having
a
measurement
sensitivity
of
plus
or
minus
10
percent
capable
of
recording
the
total
regeneration
desorbing
gas
mass
flow
for
each
regeneration
cycle.
(
2)
The
carbon
bed
temperature
monitor
must
have
a
measurement
sensitivity
of
1
percent
of
the
temperature
recorded
or
1
degree
Fahrenheit,
whichever
is
greater,
and
must
be
capable
of
recording
the
temperature
within
15
minutes
of
completing
any
carbon
bed
cooling
cycle.
(
e)
Condensers.
If
you
are
using
a
condenser,
you
must
monitor
the
condenser
outlet
(
product
side)
gas
temperature
and
comply
with
paragraphs
(
a)
and
(
e)(
1)
and
(
2)
of
this
section.
(
1)
The
gas
temperature
monitor
must
have
a
measurement
sensitivity
of
1
percent
of
the
temperature
recorded
or
1
degree
Fahrenheit,
whichever
is
greater.
(
2)
The
temperature
monitor
must
provide
a
gas
temperature
record
at
least
once
every
15
minutes.
(
f)
Concentrator.
If
you
are
using
a
concentrator,
such
as
a
zeolite
wheel
or
rotary
carbon
bed
concentrator,
you
must
comply
with
the
requirements
in
paragraphs
(
f)(
1)
and
(
2)
of
this
section.
(
1)
You
must
install
a
temperature
monitor
in
the
desorption
gas
stream.
The
temperature
monitor
must
meet
the
requirements
in
paragraphs
(
a)
and
(
c)(
3)
of
this
section.
(
2)
You
must
install
a
device
to
monitor
pressure
drop
across
the
zeolite
wheel
or
rotary
carbon
bed.
The
pressure
monitoring
device
must
meet
the
requirements
in
paragraphs
(
a)
and
(
f)(
2)(
i)
through
(
vii)
of
this
section.
(
i)
Locate
the
pressure
sensor(
s)
in
or
as
close
to
a
position
that
provides
a
representative
measurement
of
the
pressure.
(
ii)
Minimize
or
eliminate
pulsating
pressure,
vibration,
and
internal
and
external
corrosion.
(
iii)
Use
a
gauge
with
a
minimum
tolerance
of
0.5
inch
of
water
or
a
transducer
with
a
minimum
tolerance
of
1
percent
of
the
pressure
range.
(
iv)
Check
the
pressure
tap
daily.
(
v)
Using
a
manometer,
check
gauge
calibration
quarterly
and
transducer
calibration
monthly.
(
vi)
Conduct
calibration
checks
anytime
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
pressure
range
or
install
a
new
pressure
sensor.
(
vii)
At
least
monthly,
inspect
all
components
for
integrity,
all
electrical
connections
for
continuity,
and
all
mechanical
connections
for
leakage.
(
g)
Emission
capture
systems.
The
capture
system
monitoring
system
must
comply
with
the
applicable
requirements
in
paragraphs
(
g)(
1)
and
(
2)
of
this
section.
(
1)
For
each
flow
measurement
device,
you
must
meet
the
requirements
in
paragraphs
(
a)
and
(
g)(
1)(
i)
through
(
iv)
of
this
section.
(
i)
Locate
a
flow
sensor
in
a
position
that
provides
a
representative
flow
measurement
in
the
duct
from
each
capture
device
in
the
emission
capture
system
to
the
add
on
control
device.
(
ii)
Reduce
swirling
flow
or
abnormal
velocity
distributions
due
to
upstream
and
downstream
disturbances.
(
iii)
Conduct
a
flow
sensor
calibration
check
at
least
semiannually.
(
iv)
At
least
monthly,
inspect
components
for
integrity,
electrical
connections
for
continuity,
and
mechanical
connections
for
leakage.
(
2)
For
each
pressure
drop
measurement
device,
you
must
comply
with
the
requirements
in
paragraphs
(
a)
and
(
g)(
2)(
i)
through
(
vi)
of
this
section.
(
i)
Locate
the
pressure
sensor(
s)
in
or
as
close
to
a
position
that
provides
a
representative
measurement
of
the
pressure
drop
across
each
opening
you
are
monitoring.
(
ii)
Minimize
or
eliminate
pulsating
pressure,
vibration,
and
internal
and
external
corrosion.
(
iii)
Check
pressure
tap
pluggage
daily.
(
iv)
Using
an
inclined
manometer
with
a
measurement
sensitivity
of
0.0002
inch
water,
check
gauge
calibration
quarterly
and
transducer
calibration
monthly.
(
v)
Conduct
calibration
checks
any
time
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
pressure
range
or
install
a
new
pressure
sensor.
(
vi)
At
least
monthly,
inspect
components
for
integrity,
electrical
connections
for
continuity,
and
mechanical
connections
for
leakage.
Other
Requirements
and
Information
§
63.4580
Who
implements
and
enforces
this
subpart?
(
a)
This
subpart
can
be
implemented
and
enforced
by
us,
the
U.
S.
EPA,
or
a
delegated
authority
such
as
your
State,
local,
or
tribal
agency.
If
the
Administrator
has
delegated
authority
to
your
State,
local,
or
tribal
agency,
then
that
agency
(
as
well
as
the
EPA)
has
the
authority
to
implement
and
enforce
this
subpart.
You
should
contact
your
EPA
Regional
Office
to
find
out
if
implementation
and
enforcement
of
this
subpart
is
delegated
to
your
State,
local,
or
tribal
agency.
(
b)
In
delegating
implementation
and
enforcement
authority
of
this
subpart
to
a
State,
local,
or
tribal
agency
under
subpart
E
of
this
part,
the
authorities
contained
in
paragraph
(
c)
of
this
section
are
retained
by
the
Administrator
and
are
not
transferred
to
the
State,
local,
or
tribal
agency.
(
c)
The
authorities
that
will
not
be
delegated
to
State,
local,
or
tribal
agencies
are
listed
in
paragraphs
(
c)(
1)
through
(
4)
of
this
section:
(
1)
Approval
of
alternatives
to
the
work
practice
standards
in
§
63.4493
under
§
63.6(
g).
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/
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December
4,
2002
/
Proposed
Rules
(
2)
Approval
of
major
alternatives
to
test
methods
under
§
63.7(
e)(
2)(
ii)
and
(
f)
and
as
defined
in
§
63.90.
(
3)
Approval
of
major
alternatives
to
monitoring
under
§
63.8(
f)
and
as
defined
in
§
63.90.
(
4)
Approval
of
major
alternatives
to
recordkeeping
and
reporting
under
§
63.10(
f)
and
as
defined
in
§
63.90.
§
63.4581
What
definitions
apply
to
this
subpart?
Terms
used
in
this
subpart
are
defined
in
the
Clean
Air
Act,
in
40
CFR
63.2,
the
General
Provisions
of
this
part,
and
in
this
section
as
follows:
Additive
means
a
material
that
is
added
to
a
coating
after
purchase
from
a
supplier
(
e.
g.,
catalysts,
activators,
accelerators).
Add
on
control
means
an
air
pollution
control
device,
such
as
a
thermal
oxidizer
or
carbon
adsorber,
that
reduces
pollution
in
an
air
stream
by
destruction
or
removal
before
discharge
to
the
atmosphere.
Adhesive,
adhesive
coating
means
any
chemical
substance
that
is
applied
for
the
purpose
of
bonding
two
surfaces
together.
Assembled
on
road
vehicle
coating
means
any
coating
operation
in
which
coating
is
applied
to
the
surface
of
some
plastic
component
or
plastic
surface
of
a
fully
assembled
motor
vehicle
or
trailer
intended
for
on
road
use,
including,
but
not
limited
to,
plastic
components
or
surfaces
on:
automobiles
and
light
trucks
that
have
been
repaired
after
a
collision
or
otherwise
repainted,
fleet
delivery
trucks,
and
motor
homes
and
other
recreational
vehicles
(
including
camping
trailers
and
fifth
wheels).
Assembled
on
road
vehicle
coating
does
not
include
the
surface
coating
of
plastic
parts
prior
to
their
attachment
to
an
on
road
vehicle
on
an
original
equipment
manufacturer's
(
OEM)
assembly
line.
Assembled
onroad
vehicle
coating
also
does
not
include
the
use
of
adhesives,
sealants,
and
caulks
used
in
assembling
on
road
vehicles.
Capture
device
means
a
hood,
enclosure,
room,
floor
sweep,
or
other
means
of
containing
or
collecting
emissions
and
directing
those
emissions
into
an
add
on
air
pollution
control
device.
Capture
efficiency
or
capture
system
efficiency
means
the
portion
(
expressed
as
a
percentage)
of
the
pollutants
from
an
emission
source
that
is
delivered
to
an
add
on
control
device.
Capture
system
means
one
or
more
capture
devices
intended
to
collect
emissions
generated
by
a
coating
operation
in
the
use
of
coatings
or
cleaning
materials,
both
at
the
point
of
application
and
at
subsequent
points
where
emissions
from
the
coatings
and
cleaning
materials
occur,
such
as
flashoff,
drying,
or
curing.
As
used
in
this
subpart,
multiple
capture
devices
that
collect
emissions
generated
by
a
coating
operation
are
considered
a
single
capture
system.
Cleaning
material
means
a
solvent
used
to
remove
contaminants
and
other
materials,
such
as
dirt,
grease,
oil,
and
dried
or
wet
coating
(
e.
g.,
depainting),
from
a
substrate
before
or
after
coating
application
or
from
equipment
associated
with
a
coating
operation,
such
as
spray
booths,
spray
guns,
racks,
tanks,
and
hangers.
Thus,
it
includes
any
cleaning
material
used
on
substrates
or
equipment
or
both.
Coating
means
a
material
applied
to
a
substrate
for
decorative,
protective,
or
functional
purposes.
Such
materials
include,
but
are
not
limited
to,
paints,
sealants,
liquid
plastic
coatings,
caulks,
inks,
adhesives,
and
maskants.
Decorative,
protective,
or
functional
materials
that
consist
only
of
protective
oils
for
metal,
acids,
bases,
or
any
combination
of
these
substances
are
not
considered
coatings
for
the
purposes
of
this
subpart.
Coating
operation
means
equipment
used
to
apply
cleaning
materials
to
a
substrate
to
prepare
it
for
coating
application
(
surface
preparation)
or
to
remove
dried
coating;
to
apply
coating
to
a
substrate
(
coating
application)
and
to
dry
or
cure
the
coating
after
application;
or
to
clean
coating
operation
equipment
(
equipment
cleaning).
A
single
coating
operation
may
include
any
combination
of
these
types
of
equipment,
but
always
includes
at
least
the
point
at
which
a
coating
or
cleaning
material
is
applied
and
all
subsequent
points
in
the
affected
source
where
organic
HAP
emissions
from
that
coating
or
cleaning
material
occur.
There
may
be
multiple
coating
operations
in
an
affected
source.
Coating
application
with
handheld,
nonrefillable
aerosol
containers,
touchup
markers,
or
marking
pens
is
not
a
coating
operation
for
the
purposes
of
this
subpart.
Coatings
solids
means
the
nonvolatile
portion
of
the
coating
that
makes
up
the
dry
film.
Continuous
parameter
monitoring
system
(
CPMS)
means
the
total
equipment
that
may
be
required
to
meet
the
data
acquisition
and
availability
requirements
of
this
subpart,
used
to
sample,
condition
(
if
applicable),
analyze,
and
provide
a
record
of
coating
operation,
or
capture
system,
or
add
on
control
device
parameters.
Controlled
coating
operation
means
a
coating
operation
from
which
some
or
all
of
the
organic
HAP
emissions
are
routed
through
an
emission
capture
system
and
add
on
control
device.
Deviation
means
any
instance
in
which
an
affected
source
subject
to
this
subpart,
or
an
owner
or
operator
of
such
a
source:
(
1)
Fails
to
meet
any
requirement
or
obligation
established
by
this
subpart
including,
but
not
limited
to,
any
emission
limit
or
operating
limit,
or
work
practice
standard;
(
2)
Fails
to
meet
any
term
or
condition
that
is
adopted
to
implement
an
applicable
requirement
in
this
subpart
and
that
is
included
in
the
operating
permit
for
any
affected
source
required
to
obtain
such
a
permit;
or
(
3)
Fails
to
meet
any
emission
limit,
or
operating
limit,
or
work
practice
standard
in
this
subpart
during
startup,
shutdown,
or
malfunction,
regardless
of
whether
or
not
such
failure
is
permitted
by
this
subpart.
Emission
limitation
means
an
emission
limit,
operating
limit,
or
work
practice
standard.
Enclosure
means
a
structure
that
surrounds
a
source
of
emissions
and
captures
and
directs
the
emissions
to
an
add
on
control
device.
Exempt
compound
means
a
specific
compound
that
is
not
considered
a
VOC
due
to
negligible
photochemical
reactivity.
The
exempt
compounds
are
listed
in
40
CFR
51.100(
s).
Facility
maintenance
means
the
routine
repair
or
renovation
(
including
the
surface
coating)
of
the
tools,
equipment,
machinery,
and
structures
that
comprise
the
infrastructure
of
the
affected
facility
and
that
are
necessary
for
the
facility
to
function
in
its
intended
capacity.
General
use
coating
means
any
coating
operation
that
is
not
a
headlamp,
TPO,
or
assembled
on
road
vehicle
coating
operation.
Headlamp
coating
means
any
coating
operation
in
which
coating
is
applied
to
the
surface
of
some
component
of
the
body
of
an
automotive
headlamp,
including
the
application
of
reflective
argent
coatings
and
clear
topcoats.
Headlamp
coating
does
not
include
any
coating
operation
performed
on
an
assembled
on
road
vehicle.
Hobby
shop
means
any
surface
coating
operation,
located
at
an
affected
source,
that
is
used
exclusively
for
personal,
noncommercial
purposes
by
the
affected
source's
employees
or
assigned
personnel.
Liquid
plastic
coating
means
a
coating
made
from
fine,
particle
size
polyvinyl
chloride
(
PVC)
in
solution
(
also
referred
to
as
plastisol).
Manufacturer's
formulation
data
means
data
on
a
material
(
such
as
a
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233
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December
4,
2002
/
Proposed
Rules
coating)
that
are
supplied
by
the
material
manufacturer
based
on
knowledge
of
the
ingredients
used
to
manufacture
that
material,
rather
than
based
on
testing
of
the
material
with
the
test
methods
specified
in
§
63.4541.
Manufacturer's
formulation
data
may
include,
but
are
not
limited
to,
information
on
density,
organic
HAP
content,
volatile
organic
matter
content,
and
coating
solids
content.
Mass
fraction
of
coating
solids
means
the
ratio
of
the
mass
of
solids
(
also
known
as
the
mass
of
nonvolatiles)
to
the
mass
of
a
coating
in
which
it
is
contained;
lb
of
coating
solids
per
lb
of
coating.
Mass
fraction
of
organic
HAP
means
the
ratio
of
the
mass
of
organic
HAP
to
the
mass
of
a
material
in
which
it
is
contained,
expressed
as
lb
of
organic
HAP
per
lb
of
material.
Month
means
a
calendar
month
or
a
pre
specified
period
of
28
days
to
35
days
to
allow
for
flexibility
in
recordkeeping
when
data
are
based
on
a
business
accounting
period.
Organic
HAP
content
means
the
mass
of
organic
HAP
per
mass
of
coating
solids
for
a
coating
calculated
using
Equation
1
of
§
63.4541.
The
organic
HAP
content
is
determined
for
the
coating
in
the
condition
it
is
in
when
received
from
its
manufacturer
or
supplier
and
does
not
account
for
any
alteration
after
receipt.
Permanent
total
enclosure
(
PTE)
means
a
permanently
installed
enclosure
that
meets
the
criteria
of
Method
204
of
appendix
M,
40
CFR
part
51
for
a
PTE
and
that
directs
all
the
exhaust
gases
from
the
enclosure
to
an
add
on
control
device.
Personal
Watercraft
means
a
vessel
(
boat)
which
uses
an
inboard
motor
powering
a
water
jet
pump
as
its
primary
source
of
motive
power
and
which
is
designed
to
be
operated
by
a
person
or
persons
sitting,
standing,
or
kneeling
on
the
vessel,
rather
than
in
the
conventional
manner
of
sitting
or
standing
inside
the
vessel.
Plastic
part
and
product
means
any
piece
or
combination
of
pieces
of
which
at
least
one
has
been
formed
from
one
or
more
resins.
Such
pieces
may
be
solid,
porous,
flexible
or
rigid.
Protective
oil
means
an
organic
material
that
is
applied
to
metal
for
the
purpose
of
providing
lubrication
or
protection
from
corrosion
without
forming
a
solid
film.
This
definition
of
protective
oil
includes,
but
is
not
limited
to,
lubricating
oils,
evaporative
oils
(
including
those
that
evaporate
completely),
and
extrusion
oils.
Research
or
laboratory
facility
means
a
facility
whose
primary
purpose
is
for
research
and
development
of
new
processes
and
products,
that
is
conducted
under
the
close
supervision
of
technically
trained
personnel,
and
is
not
engaged
in
the
manufacture
of
final
or
intermediate
products
for
commercial
purposes,
except
in
a
de
minimis
manner.
Responsible
official
means
responsible
official
as
defined
in
40
CFR
70.2.
Startup,
initial
means
the
first
time
equipment
is
brought
online
in
a
facility.
Surface
preparation
means
use
of
a
cleaning
material
on
a
portion
of
or
all
of
a
substrate.
This
includes
use
of
a
cleaning
material
to
remove
dried
coating,
which
is
sometimes
called
``
depainting.''
Temporary
total
enclosure
means
an
enclosure
constructed
for
the
purpose
of
measuring
the
capture
efficiency
of
pollutants
emitted
from
a
given
source
as
defined
in
Method
204
of
appendix
M,
40
CFR
part
51.
Thermoplastic
olefin
(
TPO)
coating
means
any
coating
operation
in
which
the
coatings
are
components
of
a
system
of
coatings
applied
to
a
TPO
substrate,
including
adhesion
promoters,
primers,
color
coatings,
clear
coatings
and
topcoats.
Thermoplastic
olefin
coating
does
not
include
the
coating
of
TPO
substrates
on
assembled
on
road
vehicles.
Thinner
means
an
organic
solvent
that
is
added
to
a
coating
after
the
coating
is
received
from
the
supplier.
Total
volatile
hydrocarbon
(
TVH)
means
the
total
amount
of
nonaqueous
volatile
organic
matter
determined
according
to
Methods
204
and
204A
through
204F
of
appendix
M
to
40
CFR
part
51
and
substituting
the
term
TVH
each
place
in
the
methods
where
the
term
VOC
is
used.
The
TVH
includes
both
VOC
and
non
VOC.
Uncontrolled
coating
operation
means
a
coating
operation
from
which
none
of
the
organic
HAP
emissions
are
routed
through
an
emission
capture
system
and
add
on
control
device.
Volatile
organic
compound
(
VOC)
means
any
compound
defined
as
VOC
in
40
CFR
51.100(
s).
Wastewater
means
water
that
is
generated
in
a
coating
operation
and
is
collected,
stored,
or
treated
prior
to
being
discarded
or
discharged.
If
you
are
required
to
comply
with
operating
limits
by
§
63.4491(
c),
you
must
comply
with
the
applicable
operating
limits
in
the
following
table:
TABLE
1.
TO
SUBPART
PPPP
OF
PART
63
OPERATING
LIMITS
IF
USING
THE
EMISSION
RATE
WITH
ADD
ON
CONTROLS
OPTION
For
the
following
device
you
must
meet
the
following
operating
limit
.
.
.
and
you
must
demonstrate
continuous
compliance
with
the
operating
limit
by
.
.
.
1.
thermal
oxidizer
...............
a.
the
average
combustion
temperature
in
any
3
hour
period
must
not
fall
below
the
combustion
temperature
limit
established
according
to
§
63.4567(
a).
i.
collecting
the
combustion
temperature
data
according
to
§
63.4568(
c);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
combustion
temperature
at
or
above
the
temperature
limit.
2.
catalytic
oxidizer
..............
a.
the
average
temperature
measured
just
before
the
catalyst
bed
in
any
3
hour
period
must
not
fall
below
the
limit
established
according
to
§
63.4567(
b);
and
either.
i.
collecting
the
temperature
data
according
to
§
63.4568(
c);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
temperature
before
the
catalyst
bed
at
or
above
the
temperature
limit.
b.
ensure
that
the
average
temperature
difference
across
the
catalyst
bed
in
any
3
hour
period
does
not
fall
below
the
temperature
difference
limit
established
according
to
§
63.4567(
b)(
2);
or
i.
collecting
the
temperature
data
according
to
§
63.4568(
c),
reducing
the
data
to
3
hour
block
averages
and
maintaining
the
3
hour
average
temperature
difference
at
or
above
the
temperature
difference
limit;
or
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Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
TABLE
1.
TO
SUBPART
PPPP
OF
PART
63
OPERATING
LIMITS
IF
USING
THE
EMISSION
RATE
WITH
ADD
ON
CONTROLS
OPTION
Continued
For
the
following
device
you
must
meet
the
following
operating
limit
.
.
.
and
you
must
demonstrate
continuous
compliance
with
the
operating
limit
by
.
.
.
c.
develop
and
implement
an
inspection
and
maintenance
plan
according
to
§
63.4567(
b)(
4).
i.
maintaining
an
up
to
date
inspection
and
maintenance
plan,
records
of
annual
catalyst
activity
checks,
records
of
monthly
inspections
of
the
oxidizer
system,
and
records
of
the
annual
internal
inspections
of
the
catalyst
bed.
If
a
problem
is
discovered
during
a
monthly
or
annual
inspection
required
by
§
63.4567(
b)(
4),
you
must
take
corrective
action
as
soon
as
practicable
consistent
with
the
manufacturer's
recommendations.
3.
carbon
adsorber
...............
a.
the
total
regeneration
desorbing
gas
(
e.
g.,
steam
or
nitrogen)
mass
flow
for
each
carbon
bed
regeneration
cycle
must
not
fall
below
the
total
regeneration
desorbing
gas
mass
flow
limit
established
according
to
§
63.4567(
c).
i.
measuring
the
total
regeneration
desorbing
gas
(
e.
g.,
steam
or
nitrogen)
mass
flow
for
each
regeneration
cycle
according
to
§
63.4568(
d);
and
ii.
maintaining
the
total
regeneration
desorbing
gas
mass
flow
at
or
above
the
mass
flow
limit.
b.
the
temperature
of
the
carbon
bed,
after
completing
each
regeneration
and
any
cooling
cycle,
must
not
exceed
the
carbon
bed
temperature
limit
established
according
to
§
63.4567(
c).
i.
measuring
the
temperature
of
the
carbon
bed
after
completing
each
regeneration
and
any
cooling
cycle
according
to
§
63.4568(
d);
and
ii.
operating
the
carbon
beds
such
that
each
carbon
bed
is
not
returned
to
service
until
completing
each
regeneration
and
any
cooling
cycle
until
the
recorded
temperature
of
the
carbon
bed
is
at
or
below
the
temperature
limit.
4.
condenser
........................
a.
the
average
condenser
outlet
(
product
side)
gas
temperature
in
any
3
hour
period
must
not
exceed
the
temperature
limit
established
according
to
§
63.4567(
d).
i.
collecting
the
condenser
outlet
(
product
side)
gas
temperature
according
to
§
63.4568(
e);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
gas
temperature
at
the
outlet
at
or
below
the
temperature
limit.
5.
concentrators,
including
zeolite
wheels
and
rotary
carbon
adsorbers.
a.
the
average
gas
temperature
of
the
desorption
concentrate
stream
in
any
3
hour
period
must
not
fall
below
the
limit
established
according
to
§
63.4567(
e).
i.
collecting
the
temperature
data
according
to
63.4568(
f);
ii.
reducing
the
data
to
3
hour
block
averages
and
iii.
maintaining
the
3
hour
average
temperature
at
or
above
the
temperature
limit.
b.
the
average
pressure
drop
of
the
dilute
stream
across
the
concentrator
in
any
3
hour
period
must
not
fall
below
the
limit
established
according
to
§
63.4567(
e).
i.
collecting
the
pressure
drop
data
according
to
63.4568(
f);
and
ii.
reducing
the
pressure
drop
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
pressure
drop
at
or
above
the
pressure
drop
limit.
6.
emission
capture
system
that
is
a
PTE
according
to
§
63.4565(
a).
a.
the
direction
of
the
air
flow
at
all
times
must
be
into
the
enclosure;
and
either
b.
the
average
facial
velocity
of
air
through
all
natural
draft
openings
in
the
enclosure
must
be
at
least
200
feet
per
minute;
or.
c.
the
pressure
drop
across
the
enclosure
must
be
at
least
0.007
inch
H2O,
as
established
in
Method
204
of
appendix
M
to
40
CFR
part
51.
i.
collecting
the
direction
of
air
flow,
and
either
the
facial
velocity
of
air
through
all
natural
draft
openings
according
to
§
63.4568(
g)(
1)
or
the
pressure
drop
across
the
enclosure
according
to
§
63.4568(
g)(
2);
and
ii.
maintaining
the
facial
velocity
of
air
flow
through
all
natural
draft
or
the
pressure
drop
openings
at
or
above
the
facial
velocity
limit
or
pressure
drop
limit,
and
maintaining
the
direction
of
air
flow
into
the
enclosure
at
all
times.
7.
emission
capture
system
that
is
not
a
PTE
according
to
§
63.4565(
a).
a.
the
average
gas
volumetric
flow
rate
or
duct
static
pressure
in
each
duct
between
a
capture
device
and
add
on
control
device
inlet
in
any
3
hour
period
must
not
fall
below
the
average
volumetric
flow
rate
or
duct
static
pressure
limit
established
for
that
capture
device
according
to
§
63.4567(
f).
i.
collecting
the
gas
volumetric
flow
rate
or
duct
static
pressure
for
each
capture
device
according
to
§
63.4568(
g);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
gas
volumetric
flow
rate
or
duct
static
pressure
for
each
capture
device
at
or
above
the
gas
volumetric
flow
rate
or
duct
static
pressure
limit.
You
must
comply
with
the
applicable
General
Provisions
requirements
according
to
the
following
table:
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
TABLE
2
TO
SUBPART
PPPP
OF
PART
63.
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
PPPP
OF
PART
63
Citation
Subject
Applicable
to
subpart
PPPP
Explanation
§
63.1(
a)(
1)
(
14)
...............................
General
Applicability
...............................
Yes.
§
63.1(
b)(
1)
(
3)
.................................
Initial
Applicability
Determination
............
Yes
...............................
Applicability
to
subpart
PPPP
is
also
specified
in
§
63.4481.
§
63.1(
c)(
1)
.......................................
Applicability
After
Standard
Established
Yes.
§
63.1(
c)(
2)
(
3)
.................................
Applicability
of
Permit
Program
for
Area
Sources.
No
.................................
Area
sources
are
not
subject
to
subpart
PPPP.
§
63.1(
c)(
4)
(
5)
.................................
Extensions
and
Notifications
...................
Yes.
§
63.1(
e)
...........................................
Applicability
of
Permit
Program
Before
Relevant
Standard
is
Set.
Yes.
§
63.2
................................................
Definitions
...............................................
Yes
...............................
Additional
definitions
are
specified
in
§
63.4581.
§
63.3(
a)
(
c)
.....................................
Units
and
Abbreviations
..........................
Yes.
§
63.4(
a)(
1)
(
5)
.................................
Prohibited
Activities
.................................
Yes.
§
63.4(
b)
(
c)
.....................................
Circumvention/
Severability
......................
Yes.
§
63.5(
a)
...........................................
Construction/
Reconstruction
...................
Yes.
§
63.5(
b)(
1)
(
6)
.................................
Requirements
for
Existing,
Newly
Constructed
and
Reconstructed
Sources.
Yes.
§
63.5(
d)
...........................................
Application
for
Approval
of
Construction/
Reconstruction.
Yes.
§
63.5(
e)
...........................................
Approval
of
Construction/
Reconstruction
Yes.
§
63.5(
f)
............................................
Approval
of
Construction/
Reconstruction
Based
on
Prior
State
Review.
Yes.
§
63.6(
a)
...........................................
Compliance
With
Standards
and
Maintenance
Requirements
Applicability.
Yes.
§
63.6(
b)(
1)
(
7)
.................................
Compliance
Dates
for
New
and
Reconstructed
Sources.
Yes
...............................
§
63.4483
specifies
the
compliance
dates.
§
63.6(
c)(
1)
(
5)
.................................
Compliance
Dates
for
Existing
Sources
Yes
...............................
§
63.4483
specifies
the
compliance
dates.
§
63.6(
e)(
1)
(
2)
.................................
Operation
and
Maintenance
...................
Yes.
§
63.6(
e)(
3)
.......................................
Startup,
Shutdown,
and
Malfunction
Plan.
Yes
...............................
Only
sources
using
an
add
on
control
device
to
comply
with
the
standard
must
complete
startup,
shutdown,
and
malfunction
plans.
§
63.6(
f)(
1)
........................................
Compliance
Except
During
Startup,
Shutdown,
and
Malfunction.
Yes
...............................
Applies
only
to
sources
using
an
add
on
control
device
to
comply
with
the
standard.
§
63.6(
f)(
2)
(
3)
..................................
Methods
for
Determining
Compliance
....
Yes.
§
63.6(
g)(
1)
(
3)
.................................
Use
of
an
Alternative
Standard
..............
Yes.
§
63.6(
h)
...........................................
Compliance
With
Opacity/
Visible
Emission
Standards.
No
.................................
Subpart
PPPP
does
not
establish
opacity
standards
and
does
not
require
continuous
opacity
monitoring
systems
(
COMS).
§
63.6(
i)(
1)
(
16)
................................
Extension
of
Compliance
........................
Yes.
§
63.6(
j)
.............................................
Presidential
Compliance
Exemption
.......
Yes.
§
63.7(
a)(
1)
.......................................
Performance
Test
Requirements
Applicability
Yes
...............................
Applies
to
all
affected
sources.
Additional
requirements
for
performance
testing
are
specified
in
§
§
63.4564,
63.4565,
and
63.4566.
§
63.7(
a)(
2)
.......................................
Performance
Test
Requirements
Dates
Yes
...............................
Applies
only
to
performance
tests
for
capture
system
and
control
device
efficiency
at
sources
using
these
to
comply
with
the
standard
Section
63.4560
specifies
the
schedule
for
performance
test
requirements
that
are
earlier
than
those
specified
in
§
63.7(
a)(
2).
§
63.7(
a)(
3)
.......................................
Performance
Tests
Required
By
the
Administrator
Yes.
§
63.7(
b)
(
e)
.....................................
Performance
Test
Requirements
Notification
Quality
Assurance,
Facilities
Necessary
for
Safe
Testing,
Conditions
During
Test.
Yes
...............................
Applies
only
to
performance
tests
for
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standard.
§
63.7(
f)
............................................
Performance
Test
Requirements
Use
of
Alternative
Test
Method.
Yes
...............................
Applies
to
all
test
methods
except
those
used
to
determine
capture
system
efficiency.
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
TABLE
2
TO
SUBPART
PPPP
OF
PART
63.
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
PPPP
OF
PART
63
Continued
Citation
Subject
Applicable
to
subpart
PPPP
Explanation
§
63.7(
g)
(
h)
.....................................
Performance
Test
Requirements
Data
Analysis,
Recordkeeping,
Reporting,
Waiver
of
Test.
Yes
...............................
Applies
only
to
performance
tests
for
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standard.
§
63.8(
a)(
1)
(
3)
.................................
Monitoring
Requirements
Applicability
Yes
...............................
Applies
only
to
monitoring
of
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standard
Additional
requirements
for
monitoring
are
specified
in
§
63.4568.
§
63.8(
a)(
4)
.......................................
Additional
Monitoring
Requirements
.......
No
.................................
Subpart
PPPP
does
not
have
monitoring
requirements
for
flares.
§
63.8(
b)
...........................................
Conduct
of
Monitoring
.............................
Yes.
§
63.8(
c)(
1)
(
3)
.................................
Continuous
Monitoring
Sysem
(
CMS)
Operation
and
Maintenance.
Yes
...............................
Applies
only
to
monitoring
of
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standard
Additional
requirements
for
CMS
operations
and
maintenance
are
specified
in
§
63.4568.
§
63.8(
c)(
4)
.......................................
CMS
........................................................
No
.................................
§
63.4568
specifies
the
requirements
for
the
operation
of
CMS
for
capture
systems
and
add
on
control
devices
at
sources
using
these
to
comply.
§
63.8(
c)(
5)
.......................................
COMS
.....................................................
No
.................................
Subpart
PPPP
does
not
have
opacity
or
visible
emission
standards.
§
63.8(
c)(
6)
.......................................
CMS
Requirements
.................................
No
.................................
§
63.4568
specifies
the
requirements
for
monitoring
systems
for
capture
systems
and
add
on
control
devices
at
sources
using
these
to
comply.
§
63.8(
c)(
7)
.......................................
CMS
Out
of
Control
Periods
...................
Yes.
§
63.8(
c)(
8)
.......................................
CMS
Out
of
Control
Periods
and
Reporting
No
.................................
§
63.4520
requires
reporting
of
CMS
out
of
control
periods.
§
63.8(
d)
(
e)
.....................................
Quality
Control
Program
and
CMS
Performance
Evaluation.
No
.................................
Subpart
PPPP
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.8(
f)(
1)
(
5)
..................................
Use
of
an
Alternative
Monitoring
Method
Yes.
§
63.8(
f)(
6)
........................................
Alternative
to
Relative
Accuracy
Test
.....
No
.................................
Subpart
PPPP
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.8(
g)(
1)
(
5)
.................................
Data
Reduction
.......................................
No
.................................
§
§
63.4567
and
63.4568
specify
monitoring
data
reduction.
§
63.9(
a)
(
d)
.....................................
Notification
Requirements
.......................
Yes.
§
63.9(
e)
...........................................
Notification
of
Performance
Test
............
Yes
...............................
Applies
only
to
capture
system
and
add
on
control
device
performance
tests
at
sources
using
these
to
comply
with
the
standard.
§
63.9(
f)
............................................
Notification
of
Visible
Emissions/
Opacity
Test.
No
.................................
Subpart
PPPP
does
not
have
opacity
or
visible
emission
standards.
§
63.9(
g)(
1)
(
3)
.................................
Additional
Notifications
When
Using
CMS.
No
.................................
Subpart
PPPP
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.9(
h)
...........................................
Notification
of
Compliance
Status
...........
Yes
...............................
§
63.4510
specifies
the
dates
for
submitting
the
notification
of
compliance
status.
§
63.9(
i)
.............................................
Adjustment
of
Submittal
Deadlines
.........
Yes.
§
63.9(
j)
.............................................
Change
in
Previous
Information
.............
Yes.
§
63.10(
a)
.........................................
Recordkeeping/
Reporting
Applicability
and
General
Information.
Yes.
§
63.10(
b)(
1)
.....................................
General
Recordkeeping
Requirements
..
Yes
...............................
Additional
requirements
are
specified
in
§
§
63.4530
and
63.4531.
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/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
TABLE
2
TO
SUBPART
PPPP
OF
PART
63.
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
PPPP
OF
PART
63
Continued
Citation
Subject
Applicable
to
subpart
PPPP
Explanation
§
63.10(
b)(
2)(
i)
(
v)
............................
Recordkeeping
Relevant
to
Startup,
Shutdown,
and
Malfunction
Periods
and
CMS.
Yes
...............................
Requirements
for
Startup,
Shutdown
and
Malfunction
records
only
apply
to
add
on
control
devices
used
to
comply
with
the
standard.
§
63.10(
b)(
2)(
vi)
(
xi)
.........................
.................................................................
Yes.
§
63.10(
b)(
2)(
xii)
...............................
Records
...................................................
Yes.
§
63.10(
b)(
2)(
xiii)
...............................
.................................................................
No
.................................
Subpart
PPPP
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.10(
b)(
2)(
xiv)
..............................
.................................................................
Yes.
§
63.10(
b)(
3)
.....................................
Recordkeeping
Requirements
for
Applicability
Determinations.
Yes.
§
63.10(
c)(
1)
(
6)
...............................
Additional
Recordkeeping
Requirements
for
Sources
with
CMS.
Yes.
§
63.10(
c)(
7)
(
8)
...............................
.................................................................
No
.................................
The
same
records
are
required
in
§
63.4520(
a)(
7).
§
63.10(
c)(
9)
(
15)
.............................
.................................................................
Yes.
§
63.10(
d)(
1)
.....................................
General
Reporting
Requirements
...........
Yes
...............................
Additional
requirements
are
specified
in
§
63.4520.
§
63.10(
d)(
2)
.....................................
Report
of
Performance
Test
Results
......
Yes
...............................
Additional
requirements
are
specified
in
§
63.4520(
b).
§
63.10(
d)(
3)
.....................................
Reporting
Opacity
or
Visible
Emissions
Observations.
No
.................................
Subpart
PPPP
or
does
not
require
opacity
or
visible
emissions
observations
§
63.10(
d)(
4)
.....................................
Progress
Reports
for
Sources
With
Compliance
Extensions.
Yes.
§
63.10(
d)(
5)
.....................................
Startup,
Shutdown,
and
Malfunction
Reports
Yes
...............................
Applies
only
to
add
on
control
devices
at
sources
using
these
to
comply
withthe
standard.
§
63.10(
e)(
1)
(
2)
...............................
Additional
CMS
Reports
.........................
No
.................................
Subpart
PPPP
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.10(
e)(
3)
.....................................
Excess
Emissinos/
CMS
Performance
Reports.
No
.................................
§
63.4520(
b)
specifies
the
contents
of
periodic
compliance
reports.
§
63.10(
e)(
4)
.....................................
COMS
Data
Reports
...............................
No
.................................
Subpart
PPPP
does
not
specify
requirements
for
opacity
or
COMS.
§
63.10(
f)
..........................................
Recordkeeping/
Reporting
Waiver
...........
Yes.
§
63.11
..............................................
Control
Device
Requirements/
Flares
......
No
.................................
Subpart
PPPP
does
not
specify
use
of
flares
for
compliance.
§
63.12
..............................................
State
Authority
and
Delegations
.............
Yes.
§
63.13
..............................................
Addresses
...............................................
Yes.
§
63.14
..............................................
Incorporation
by
Reference
....................
Yes.
§
63.15
..............................................
Availability
of
Information/
Confidentiality
Yes.
You
may
use
the
mass
fraction
values
in
the
following
table
for
solvent
blends
for
which
you
do
not
have
test
data
or
manufacturer's
formulation
data.
TABLE
3
TO
SUBPART
PPPP
OF
PART
63.
DEFAULT
ORGANIC
HAP
MASS
FRACTION
FOR
SOLVENTS
AND
SOLVENT
BLENDS
Solvent/
solvent
blend
CAS
No.
Average
organic
HAP
mass
fraction
Typical
organic
HAP,
percent
by
mass
1.
Toluene
..............................................................................
108
88
3
1.0
Toluene
2.
Xylene(
s)
...........................................................................
1330
20
7
1.0
Xylenes,
ethylbenzene
3.
Hexane
..............................................................................
110
54
3
0.5
n
hexane
4.
n
Hexane
...........................................................................
110
54
3
1.0
n
hexane
5.
Ethylbenzene
.....................................................................
100
41
4
1.0
Ethylbenzene
6.
Aliphatic
140
......................................................................
..............................
0
None
7.
Aromatic
100
.....................................................................
..............................
0.02
1%
xylene,
1%
cumene
8.
Aromatic
150
.....................................................................
..............................
0.09
Naphthalene
9.
Aromatic
naphtha
..............................................................
64742
95
6
0.02
1%
xylene,
1%
cumene
10.
Aromatic
solvent
..............................................................
64742
94
5
0.1
Naphthalene
11.
Exempt
mineral
spirits
.....................................................
8032
32
4
0
None
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Register
/
Vol.
67,
No.
233
/
Wednesday,
December
4,
2002
/
Proposed
Rules
TABLE
3
TO
SUBPART
PPPP
OF
PART
63.
DEFAULT
ORGANIC
HAP
MASS
FRACTION
FOR
SOLVENTS
AND
SOLVENT
BLENDS
Continued
Solvent/
solvent
blend
CAS
No.
Average
organic
HAP
mass
fraction
Typical
organic
HAP,
percent
by
mass
12.
Ligroines
(
VM
&
P)
..........................................................
8032
32
4
0
None
13.
Lactol
spirits
....................................................................
64742
89
6
0.15
Toluene
14.
Low
aromatic
white
spirit
.................................................
64742
82
1
0
None
15.
Mineral
spirits
..................................................................
64742
88
7
0.01
Xylenes
16.
Hydrotreated
naphtha
......................................................
64742
48
9
0
None
17.
Hydrotreated
light
distillate
..............................................
64742
47
8
0.001
Toluene
18.
Stoddard
solvent
.............................................................
8052
41
3
0.01
Xylenes
19.
Super
high
flash
naphtha
................................................
64742
95
6
0.05
Xylenes
20.
Varsol
solvent
...............................................................
8052
49
3
0.01
0.5%
xylenes,
0.5%
ethylbenzene
21.
VM
&
P
naphtha
..............................................................
64742
89
8
0.06
3%
toluene,
3%
xylene
22.
Petroleum
distillate
mixture
.............................................
68477
31
6
0.08
4%
naphthalene,
4%
biphenyl
You
may
use
the
mass
fraction
values
in
the
following
table
for
solvent
blends
for
which
you
do
not
have
test
data
or
manufacturer's
formulation
data:
TABLE
4
TO
SUBPART
PPPP
OF
PART
63.
DEFAULT
ORGANIC
HAP
MASS
FRACTION
FOR
PETROLEUM
SOLVENT
GROUPS
a
Solvent
type
Average
organic
HAP
mass
fraction
Typical
organic
HAP
percent
by
mass
Aliphatic
b
.................................................................................
0.03
1%
Xylene,
1%
Toluene,
and
1%
Ethylbenzene
Aromatic
c
.................................................................................
0.06
4%
Xylene,
1%
Toluene,
and
1%
Ethylbenzene
a
Use
this
table
only
if
the
solvent
blend
does
not
match
any
of
the
solvent
blends
in
Table
3
to
this
subpart
and
you
only
know
whether
the
blend
is
aliphatic
or
aromatic.
b
Mineral
Spirits
135,
Mineral
Spirits
150
EC,
Naphtha,
Mixed
Hydrocarbon,
Aliphatic
Hydrocarbon,
Aliphatic
Naphtha,
Naphthol
Spirits,
Petroleum
Spirits,
Petroleum
Oil,
Petroleum
Naphtha,
Solvent
Naphtha,
Solvent
Blend.
c
Medium
flash
Naphtha,
High
flash
Naphtha,
Aromatic
Naphtha,
Light
Aromatic
Naphtha,
Light
Aromatic
Hydrocarbons,
Aromatic
Hydrocarbons
Light
Aromatic
Solvent.
[
FR
Doc.
02
29073
Filed
12
3
02;
8:
45
am]
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| epa | 2024-06-07T20:31:40.605919 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0074-0001/content.txt"
} |
EPA-HQ-OAR-2002-0076-0033 | Supporting & Related Material | "2002-04-02T05:00:00" | null | epa | 2024-06-07T20:31:40.647631 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0076-0033/content.txt"
} |
|
EPA-HQ-OAR-2002-0076-0037 | Supporting & Related Material | "2002-04-02T05:00:00" | null | Attachment
C.
Demonstration
that
the
SO,
Milestones
Provide
Greater
Reasonable
Progress
than
BART
A.
BackFround
On
July
1,
1999
the
Environmental
Protection
Agency
(
EPA)
published
regulations
to
address
regional
haze
visibility
impairment.
The
new
regulations
require
States
to
address
Best
Available
Retrofit
Technology
(
BART)
requirements
for
regional
haze
visibility
impairment.
The
nine
Grand
Canyon
Visibility
Transport
Region
States
have
the
option
to
address
this
requirement
as
part
of
an
overall
strategy
of
emission
reductions
developed
by
the
Grand
Canyon
Commission,
including
the
establishment
of
regional
sulfur
dioxide
(
S02)
milestones.
§
309(
f)(
l)(
I)
of
the
regional
haze
rule
establishes
the
requirements
for
regional
milestones
to
meet
the
stationary
source
obligations
for
the
first
long
term
planning
period.
The
rule
states,
The
emission
reduction
milestones
must
be
shown
to
provide
for
greater
reasonable
progress
than
would
be
achieved
by
application
of
best
available
retrofit
technology
(
BART)
pursuant
to
section
51.308(
e)(
2)
and
would
be
approvable
in
lieu
of
BART.
The
requirements
for
BART
are
described
in
greater
detail
in
section
51.308(
e)(
2)
as
follows:
A
State
may
opt
to
implement
an
emissions
trading
program
or
other
alternative
measure
rather
than
to
require
sources
subject
to
BART
to
install,
operate,
and
maintain
BART.
To
do
so,
the
State
must
demonstrate
that
this
emissions
trading
program
or
other
alternative
measure
will
achieve
greater
reasonable
progress
than
would
be
achieved
through
the
installation
and
operation
of
BART.
To
make
this
demonstration,
the
State
must
submit
an
implementation
plan
containing
the
following
plan
elements
and
include
documentation
for
all
required
analyses:
(
I)
A
demonstration
that
the
emissions
trading
program
or
other
alternative
measure
will
achieve
greater
reasonable
progress
than
would
have
resulted
fiom
the
installation
and
operation
of
BART
at
all
sources
subject
to
BART
in
the
State.
This
demonstration
must
be
based
on
the
following:
(
A)
A
list
of
all
BART
eligible
sources
within
the
State.
(
B)
An
analysis
of
the
best
system
of
continuous
emission
control
technology
available
and
associated
emission
reductions
achievable
for
each
source
within
the
State
subject
to
BART.
In
this
analysis,
the
State
must
take
into
consideration
the
technology
available,
the
costs
of
compliance,
the
energy
and
nonair
quality
environmental
impacts
of
compliance,
any
pollution
control
equipment
in
use
at
the
source,
and
the
remaining
useful
life
of
the
source.
The
best
system
of
continuous
emission
control
technology
and
the
above
factors
may
be
determined
on
a
source
category
basis.
The
State
may
elect
to
consider
both
source
specific
and
category
wide
information,
as
appropriate,
in
conducting
its
analysis.
(
C)
An
analysis
of
the
degree
of
visibility
improvement
that
would
be
achieved
in
each
mandatory
Class
I
Federal
area
as
a
result
of
the
emission
reductions
achievable
fkom
all
such
sources
subject
to
BART
located
within
the
region
that
contributes
to
visibility
impairment
in
the
Class
I
area,
based
on
the
analysis
conducted
under
section
51.308(
e)(
2)(
I)(
B).
In
order
to
address
these
BART
requirements,
the
WRAP
used
the
following
process:
Develop
a
list
of
BART
eligible
sources
for
the
region.
0
Estimate
emission
reductions
that
could
be
made
by
BART
eligible
sources
through
appropriate
retrofit
technology .
#
Estimate
baseline
emissions
in
the
year
2018.
a
Evaluate
the
visibility
improvement
that
could
occur
in
the
region
if
the
appropriate
retrofit
technology
emission
reductions
were
implemented.
#
Evaluate
additional
factors
that
would
contribute
to
greater
reasonable
progress
than
regional
haze
BART
0
Establish
2018
SO,
emissions
milestone
Each
of
these
steps
is
addressed
in
greater
detail
in
the
following
sections
of
this
report.
This
process
was
developed
through
the
best
efforts
of
the
WRAP
through
a
stakeholder
based
process
and
is
based
on
the
WRAP Sreading
of
the
regional
haze
rule
language
and
preamble.
It
is
important
to
note
that
EPA
guidance
for
determining
regional
haze
BART
is
under
development
and
so
the
WRAP
had
to
make
a
number
of
assumptions
about
the
analysis.
B.
List
of
BART
eligible
sources.
Each
of
the
nine
Transport
Region
States
developed
a
preliminary
list
of
BART
eligible
sources
for
SO,.
EPA
identified
BART
eligible
sources
on
tribal
lands.
EPA
guidance
for
regional
haze
BART
is
still
under
development
which
leaves
many
unanswered
applicability
questions.
The
WRAP
developed
a
draft
methodology
that
was
used
to
identify
all
of
the
BART
eligible
sources
in
the
region.
When
final
guidance
is
issued,
the
Transport
Region
States
and
Tribes
recognize
that
changes
to
their
initial
lists
of
BART
eligible
sources
may
be
necessary,
however
the
WRAP
believes
that
all
sources
that
emit
significant
levels
of
SO,
have
been
identified.
The
preliminary
list
compiled
by
the
states
is
included
as
Attachment
D
to
the
Annex.
The
draft
methodology
used
the
following
assumptions:
0
Where
appropriate,
BART
eligible
sources
were
identified
on
a
unit
by
unit
basis.
Only
individual
units
that
met
the
BART
criteria
were
included
on
the
list.
For
e
2
?
a.
?
i
Q
01
r;]
l
some
sources,
such
as
copper
smelters,
this
approach
did
not
work
because
the
units
were
so
inter
related.
In
those
cases
the
entire
source
was
examined
to
determine
if
it
was
BART
eligible.
Pollutants
were
treated
independently.
Therefore,
only
units
that
qualified
as
BART
eligible
for
SO,
were
included
on
the
list.
Modifications
during
the
15
yearBART
wiqdow
were
not
considered,
unless
the
modification
qualified
as
reconstruction
for
that
unit.
Units
were
not
considered
BART
eligible
if
the
only
modification
that
was
made
during
the
15
year
window
was
the
installation
of
pollution
control
equipment.
BART
eligible
sources
that
had,
were
in
the
process
of,
or
were
slated
to
have
new
emissions
controls
installed
(
Navajo
Generating
Station,
Page,
Arizona;
Hayden
Generating
Station,
Hayden,
Colorado;
Mojave
Generating
Station,
Laughlin,
Nevada)
were
not
included
in
the
spreadsheet
that
was
used
to
calculate
the
BART
level
emission
reductions.
In
addition,
BART
eligible
sources
that
will
be
controlled
as
part
of
the
voluntary
reductions
for
the
Front
Range
power
plants
in
Colorado
were
not
included
in
the
spreadsheet
(
Cherokee
Generating
Station
in
Denver
and
Valmont
Generating
Station
in
Boulder).
Emission
reductions
fiom
these
sources
were
treated
as
downward
adjustments
to
the
baseline.
B
C.
Appropriate
Retrofit
Technology
Estimates
The
next
step
in
the
process
was
the
identification
of
appropriate
retrofit
technologies
for
the
BART
eligible
sources.
BART
has
traditionally
been
developed
through
a
case
by
case
analysis
that
considers
the
unique
situation
of
the
source,
including
costs
and
the
impacts
that
the
source
has
on
a
particular
mandatory
Class
I
area.
As
provided
in
the
following
passage,
the
regional
haze
rule
provides
flexibility
to
states
in
developing,
for
comparative
purposes,
a
method
for
calculating
the
emission
reductions
that
would
result
fkom
the
installation
of
source
specific
BART:
To
compare
the
emissions
reductions
and
visibility
improvement
that
would
result
fkom
the
application
of
source
specific
BART
to
that
resulting
from
implementation
of
alternative
measures,
such
as
a
regional
emissions
trading
program,
the
state
must
estimate
the
emissions
reductions
that
would
result
from
the
use
of
BART
level
controls.
To
do
this,
the
states
could
undertake
a
source
specific
review
of
the
sources
in
the
state
subject
to
BART
or
it
could
use
a
modified
approach
that
simplifies
analysis...
the
states
accordinglyhave
flexibilityin
developing
a
method
to
determine
the
emissions
reductions
that
could
be
achieved
through
the
application
of
BART.'
The
WRAP
recognized
that
a
case
by
case
analysis
of
potential
controls
for
each
of
the
BART
eligible
sources
in
the
region
would
be
very
resource
intensive
and
require
more
time
than
allotted
for
the
development
of
the
Annex.
Because
the
goal
was
to
use
these
estimates
to
1
40
CFR
part
51,
page
35742
(
July
1,1999).
c
3
\
establish
a
regional
emission
cap,
the
individual
BART
reductions
were
less
important
than
the
overall
regional
number.
The
WRAP
therefore
approached
the
analysis
at
the
regional
level,
using
a
more
simplified
analysis,
as
provided
for
in
the
regional
haze
rule.
The
WRAP
used
the
following
assumptions
to
estimate
the
regional
emission
reductions
due
to
appropriate
retrofit
controls
on
the
BART
eligible
sources
in
the
region.
It
should
be
noted
that
the
WRAP
methodology
was
only
used
to
obtain
a
regional
estimate
for
BART
level
emission
reductions
to
calculate
the
2018
milestone.
It
was
not
intended
to
be
a
source
by
source
BART
analysis.
c]
r
Appropriate
retrofit
technologies
were
estimated
for
source
categories
rather
than
individual
sources.
a
Emission
reductions
were
estimated
at
the
regional
level.
a
All
estimates
of
the
level
of
control
constitute
an
assumed
average
for
that
industry
sector
in
the
WRAP
region.
a
The
BART
factors,
including
cost,
energy
and
non
air
environmental
impact,
existing
pollution
controls,
and
remaining
usell
life
were
addressed
in
a
broad
way
through
the
identification
of
technologies
that
were
currently
being
used
as
retrofits
in
the
region.
Some
consideration
of
the
techmcal
feasibility
of
installing
control
equipment
at
particular
sources
(
site
constraints,
special
conditions,
etc.)
was
considered.
However,
a
comprehensive
analysis
was
not
completed
for
individual
sources.
Instead,
the
MTF
looked
at
ranges
of
potential
retrofit
controls
and
established
a
level
that
was
expected
to
be
valid
as
a
regional
average.
Table
1
outlines
the
estimated
appropriate
retrofit
technology
for
specific
source
categories
in
the
region.
c
4
Source
Category
Copper
Smelters
Refineries
Lime
Plants
and
Cement
Kilns
Utility
Boilers
Industrial
Boilers
Pulp
and
Paper
TABLE
1
Retrofit
Technologies
or
Percentage
Reduction
Due
to
the
uniqueness
of
the
existing
smelters,
retrofit
technology
analysis
must
be
performed
on
a
smelter
by
smelter
basis.
Currently,
the
Hidalgo
smelter
is
the
only
BART
eligible
source
on
the
list
in
this
category.
A
double
contact
acid
plat
will
be
considered
the
appropriateretrofit
control
equipment
(
all
smeltersin
the
region
are
currently
equipped
with
double
contact
acid
plants).
On
August
2
1,2000
New
Mexico
completed
anengineeringanalysis
that
verified
earlier
determinations
by
the
MTF
that
the
fhgitive
SO,
capture
system
at
Hidalgo
satisfiesBART
at
96%
overall
capture.
There
are
three
sources
of
SO,
emissions
at
the
refiery
level:
Descriution
Assumed
Average
Control
Level
SRU
(
pollution
control
for
fuel
98%
control
or
the
equivalent
of
3
stage
Claus
gas
combustion
units)
units
(
most
already
have
th~
sin
place).
Catalytic
crackers
90%
control.
States
will
query
these
sources
as
to
whether
or
not
they
have
had
to
comply
with
subpart
J
with
low
sulh
catalyst
or
hydro
treating,
which
would
amount
to
90%
control.
If
not
already
subject
to
part
J,
then
90%
control
will
be
required.
Flares
no
additionalcontrols
0
(
Approximately
70%
of
refinery
emissions
come
from
Claus
unit,
25%
from
cat
crackers
if
uncontrolled,
and
remaining
5%
from
all
other
sources)
No
additional
reduction.
Approximately
50%
control
inherent
in
the
process.
Additional
SO,
controls
are
not
typically
applied
tO
these
kinds
of
sources.
Technology
determination
dependent
upon
current
level
of
control.
Descrintion
Assumed
Average
Level
of
Control
Uncontrolled
units
85%
Units
controlled
at
less
than
70%
Treat
as
uncontrolled(
see
above).
Units
controlled
between
70430%
Increase
reductionsby
5%
(
i.
e.,
if
a
unit
is
at
72%,
would
be
assumed
to
control
to
77%).
Units
controlled
greater
than
80%
No
additionalreductions.
Same
as
utility
boilers.
Sulk
sources
are
recovery
furnaces
and
boilers.
Boiler
discussions
covered
with
industrial
boilers.
Recovery
furnaces:
No
additional
reduction.
Low
emissionscoupled
withlack
of
more
than
one
example
of
scrubbing.
c
5
The
technology
assumptions
listed
above
were
incorporated
into
a
spreadsheet
(
Allstat7.
xls)
to
estimate
the
regional
emission
reductions
due
to
appropriate
retrofit
technologies.
The
spreadsheet
used
the
following
assumptions:
#
Existing
utility
generating
units
operating
at
an
average
capacity
factor
of
less
than
85%
of
nameplate
capacity
during
1999were
assumed
to
increase
their
capacity
factor
to
a
maximum
level
of
85%
of
nameplate
capacity
by
2018.
Utility
units
operating
at
a
capacity
factor
higher
than
85%
during
1999
were
assumed
to
continue
operating
at
that
level.
#
All
other
source
categories
were
assumed
to
continue
operating
at
their
current
level
of
actual
emissions,
based
on
an
average
of
1996
1998
emissions.
#
The
BART
eligible
units
were
assumed
to
reduce
actual
emissions
by
the
applying
the
control
efficiency
listed
in
Table
1
for
each
specific
source
category.
c1
The
total
emission
reductions
were
then
added
to
obtain
a
regional
estimate.
The
individual
source
estimates
were
only
calculated
as
part
of
the
regional
estimate,
and
are
not
intended
to
be
used
as
a
BART
estimate
for
those
individual
sources.
The
analysis
described
above
led
to
an
estimated
emission
reduction
of
168,176
tons
SO,
due
to
the
application
of
appropriate
control
technologies.
For
the
purposes
of
this
discussion,
this
number
will
be
rounded
to
168,000
tons.
D.
Baseline
Inventory
for
2018
As
part
of
the
process
of
developing
the
end
point
for
this
program,
an
inventory
of
expected
actual
emissions
in
2018
was
estimatec!.
The
baseline
inventory
was
calculated
separately
for
utilities
and
non
utilities
using
the
following
methods
and
assumptions:
1.
Utilities.
1999
emissions
data
that
were
submitted
to
EPA
for
the
acid
rain
program
were
used
as
the
base
inventory
for
the
utility
projections
to
2018.
In
addition,
data
for
several
small
power
plants
that
were
not
in
the
acid
rain
data
base
were
added
to
the
inventory
list.
The
1999
inventory
was
then
grown
to
account
for
increased
capacity
utilization
as
described
below.
Known
emission
reductions
that
have
already
been
agreed
to
by
the
Public
Service
Company
of
Colorado
(
a
number
of
power
plants
along
the
Front
Range
that
will
be
controlled
in
2003)
and
by
the
Mojave
Generating
Station
in
Nevada
(
controls
will
be
installed
by
2006)
were
subtracted
from
the
emission
projections.
a.
Capacity
Factor.
Western
utilities
are
increasing
their
utilization
to
meet
increasing
electricity
demand.
In
addition,
deregulation
of
the
power
industry
is
expected
to
further
increase
utilization
of
existing
plants
because
it
will
be
more
cost
effective
to
achieve
peak
performance
from
existing
plants
than
to
expend
the
capital
to
build
new
plants.
Even
though
utilization
is
increasing,
it
is
not
C
6
realistic
to
estimate
that
plants
will
consistently
operate
at
100%
capacity
because
units
will
require
maintenance
throughout
the
year.
In
addition,
power
demand
fluctuatesthroughout
the
year,
and
full
utilization
may
not
be
needed
every
day
of
the
year.
The
WRAP
has
assumed
that
all
coal
fired
power
plants
in
the
west
will
be
operating
at
an
average
of
85%
of
nameplate
capacity
in
the
year
2018.
Any
new
growth
in
demand,
beyond
this
capacity
factor
assumption,
is
assumed
to
be
met
by
new
power
generation
at
an
approximate
control
efficiencyof
98%
for
SO,.
b.
Retirement
Adjustment
for
Colorado
Front
Range
Power
Plants.
Public
Service
Company
of
Colorado
(
PSCO)
has
made
a
voluntary
agreement
with
the
State
of
Colorado
to
control
a
number
of
Front
Range
power
plants
by
the
year
2003.
Several
of
the
plants
that
will
install
controls
are
assumed
to
retire
before
the
year
2018
according
to
the
assumptions
of
the
model.
It
is
no
longer
realistic
to
assume
that
these
plants
will
retire,
because
the
capital
investment
in
the
plants
will
extend
their
lifetime.
Therefore,
a
4,000
ton
adjustment
was
made
to
the
inventory
to
account
or
the
continued
operation
of
these
plants.
2.
Co
generation
Facilities.
1998
inventory
data
provided
by
the
nine
transport
region
states
were
used
as
the
base
inventory
for
future
year
projections.
It
was
assumed
that
emissions
from
these
sources
would
remain
constant
through
the
year
2018
(
no
growth
or
retirements
would
occur).
3.
Smelters.
1998inventory
data
provided
by
the
nine
transport
region
states
were
used
as
the
base
inventory
for
fbture
year
projections.
There
are
two
smelters
that
were
operating
in
1998
that
have
temporarily
suspended
operations
due
to
economic
conditions.
For
this
reason,
the
inventory
was
projected
both
with
these
smelters
in
operation,
and
without.
The
milestones
developed
by
the
WRAP
contain
provisions
for
an
automatic
adjustment
if
one
or
both
of
the
smelters
come
back
on
line.
The
2018
inventory
for
smelters
in
the
region
if
neither
smelter
resumes
operation
is
assumed
to
be
48,000
tons.
This
inventory
number
assumes
that
emissions
fkom
smelters
would
remain
constant
(
no
growth
or
retirements
would
occur).
The
2018
inventory
if
both
smelters
resume
operation
is
assumed
to
be
78,000
tons.
This
estimate
assumes
that
there
will
be
additional
retirement
of
emissions
fkom
the
smelter
sector,
equivalent
to
the
estimates
made
by
the
Integrated
Assessment
System
(
IAS)
used
by
the
Grand
Canyon
Visibility
Transport
Commission
for
the
year
2020.
4.
Olther
sources.
1998
inventory
data
provided
by
the
nine
transport
region
states
were
used
as
the
base
inventory
for
kture
year
projections.
The
growth
and
retirement
assumptions
developed
for
the
IASwere
used
to
project
these
emissions
to
the
year
2018.
The
IAS
did
not
assume
any
increase
in
capacity
for
existing
sources,
instead,
their
emissions
were
retired
at
a
set
percentage
per
year.
Any
increase
in
demand
for
the
c
7
%
hr*&
&+&'
hLfl+
A
d$&
a,.&*
sector's
product,
as
predicted
by
the
REMI
economic
model,
was
assumed
to
be
met
by
new
sources,
operatbg
at
a
controlled
emission
rate.
The
growth
and
retirement
rates,
as
well
as
the
control
efficiency
for
new
sources,
vary
between
sectors.
5.
2018
Baseline
Inventory
of
Projected
Actual
Emissions
(
rounded
to
nearest
1,000)
?
?
&.
AN
a\
4
Jh
'
i
LJ=
Utility
Emissions
421,000*
r+
L
Front
Range
Retirement
Adjustment
4,000
+
iLJ&
L'i@*
imp
Co
Gen
Units
8,000
4L.
M~
dJ
\
rc
,4n'"\~
Smelter
Emissions
48,000
,
a\*
JdVI
bd*
Other
Source
Emissions
141.000
622,000
n/
sJz
:
e
G
lD.
2018
Inventory
with
Estimated
Emission
Reductions.
The
emission
reductions
estimated
i
for
appropriate
control
technologies
applied
to
BART
eligible
sources
were
then
subtracted
from
5@
the
2018
baseline.
1.
CEMs
Bias.
The
federal
acid
rain
program
requires
coal
fired
utilities
to
monitor
SO,
emissions
using
continuous
emission
monitors
(
CEMs).
These
monitors
measure
SO,
concentration
at
a
point
in
the
stack,
and
also
measure
the
volume
of
the
gas
stream
passing
through
the
stack.
The
combination
of
the
two
measurements
provides
total
mass
emissions
from
the
stack
in
tondyear.
Prior
to
the
use
of
CEMs,
utilities
calculated
their
emissions
using
a
mass
balance
methodology.
The
sulfur
content
of
the
coal
was
measured,
and
then
total
SO,
emissions
were
determined
by
tracking
the
amount
of
coal
burned.
Two
sources
of
bias
result
in
8n
over
estimation
of
emissions
as
compared
to
a
mass
balance
estimation.
a
If
two
dimensional
probes
are
used
to
measure
the
volume
of
gas
passing
through
the
stack,
gas
volume
will,
on
average,
be
over
estimated.
4.
#
If
a
CEMS
malfunctions,
the
rules
require
the
use
of
a
high
bias
estimate
in
the
place
of
missing
data.
The
bias
varies
from
plant
to
plant
depending
on
the
specific
configuration
of
the
stack,
and
other
variables.
:
In
mid
1999,
EPA
published
a
new
flow
measurement
technique
that
could
be
used
for
CEMs
under
the
acid
rain
program.
This
new
technique
is
voluntary,
and
it
is
not
known
how
many
sources
will
install
the
equipment
(
it
is
significantly
more
expensive
than
the
existing
equipment).
The
new
flow
measurement
technique
is
expected
to
reduce
the
CEM
bias,
but
bias
will
never
be
completely
eliminated
because
of
the
way
emissions
are
I
C
s
?
required
to
be
counted
when
data
are
missing.
The
WRAP
recognized
that
current
CEM
measurements
are
biased
high,
and
that
compliance
measurements
to
future
milestones
will
be
made
with
CEMs
that
have
less
bias
than
those
that
were
in
use
in
the
1999
base
inventory
that
was
used
for
projecting
future
utility
emissions.
However,
it
is
difficult
to
estimate
how
many
sources
will
install
the
new
measurement
devices,
and
how
much
CEM
bias
will
still
remain
after
these
changes.
Utility
emissions
in
the
yeas
2018
are
predicted
to
be
approximately
269,000
tons
(
afier
the
emission
reductions
due
to
appropriate
control
technology
applied
to
BART
eligible
sources).
Therefore
the
WRAP
assumed
an
adjustment
of
10,000
tons
to
account
for
the
CEMs
bias.
The
WRAP
also
acknowledges
thatCEMs
are
the
gold
standard
for
determining
compliance
with
the
federal
Acid
Rain
Program
requirements.
A
protocol
will
be
developed
to
make
appropriate
adjustments
to
the
operation
of
this
component
of
the
regional
haze
program
for
participating
states
and
Tribes
as
improvements
in
CEMs
technology
and
procedures
are
implemented.
This
protocol
is
necessary
to
prevent
a
system
of
dual
book
keeping
and
to
maintain
the
integrity
of
compliance
with
both
the
federal
Acid
Rain
Program
and
this
proposed
backstop
cap
and
trade
program.
The
CEPvIs
adjustment
protocol
is
discussed
in
more
detail
in
the
Annex.
2.
Operational
headroom
and
uncertainty.
The
GCVTC
agreements
and
recommendations
contain
two
tenets
that
have
uniquely
informed
the
establishment
of
operational
headroom
and
uncertainty
under
the
market
trading
program.
First,
the
Commission
recommended
that
the
market
trading
program
contain
specific
provisions
to
encourage
and
reward
early
emission
reductions,
including
reductions
achieved
before
2000.
2
The
GCVTC
committed
to
achieve
a
13%
reduction
in
SO2
emissions
fiom
stationary
sources
by
the
year
2000.
The
GCVTC
also
recognized
that
there
was
a
good
possibility
that
actual
emission
reductions
would
be
greater
than
this
13%
goal.
A
general
plan
was
derived
to
give
some
early
reductions
credit
to
the
region
and
some
to
the
environment.
The
emission
reductions
that
were
greater
than
13%
were
to
be
split,
with
?
4going
to
the
environment
(
through
the
establishment
of
milestones)
and
the
other
?
4prloviding
headr~
om.~
The
WRAP
currently
expects
that
emissions
in
the
region
will
show
greater
reductions
than
the
13%
commitment
of
the
GCVTC.
The
WRAP
has
sought
to
preserve
the
Comission s
approach
to
early
reductions
by
setting
aside
as
headroom
some
intermediate
portion
of
the
expected
reductions
in
excess
of
13%.
Recommendations
for
Improving
Western
Vistas
at
33
(
June
1996)
(
emphasis
added).
c
9
I
Second,
the
Commission
recommended
allocations
to
tribes
that
are
of
practical
benefit.'
This
recognized
the
concern
that
"
tribes,
by
and
large,
have
not
contributed
to
the
visibility
problem
in
the
region"
and
that
"[
tlribal
economies
are
much
less
developed
than
those
of
states,
and
tribes
must
have
the
opportunity
to
progress
to
reach
some
degree
of
parity
with
states
in
this
regard.'
I5
The
tribes
specifically
recommended
that
if
an
emission
trading
strategy
is
adopted
to
achieve
SO2
reductions
fi
om
stationary
sources
that
allocations
be
based
on
considerations
of
equity
rather
than
historical
emissions:
Credits
should
not
be
based
on
historical
emissions,
but
should
be
based
on
equitable
factors,
including
the
need
to
preserve
opportunities
for
economic
development
on
tribal
lands.
In
general,
these
lands
are
currently
lacking
in
economic
bases
and
have
not
contributed
to
the
visibility
problems.
6
Accordingly,
the
market
trading
program
proposed
by
the
WRAP
contains
a
20,000
allocation
to
tribes.
These
two
considerations
to
reward
emission
reductions
occurring
between
1990
and
2000,
and
to
provide
an
equitable
allocation
to
the
tribes
originate
from
the
GCVTC
recommendations.
They
reff
ect
distinct
policy
concerns
of
the
Commission
that
are
unique
to
the
program
under
section
309
of
the
regional
haze
rule
incorporating
the
Commission's
recommendations.
In
addition,
because
the
baseline
emissions
inventory
is
a
projection
of
actual
emissions,
uncertainty
exists
in
the
projection
method
including,
for
example,
fluctuations
in
weather
and
changing
economic
conditions.
There
are
inherent
uncertainties
in
the
inventory
calculation
that
need
to
be
recognized.
Inherent
measurement
uncertainties.
CEMs
are
calibrated
daily
to
a
relative
accuracy
of
20%
using
calibration
gases.
Fluctuations
in
measurements
can
occur
due
to
the
measurement
techniques
that
are
not
indicative
of
actual
changes
in
emissions.
Pluses
and
minuses
will
cancel
out
to
a
certain
degree,
but
some
consideration
of
these
fluctuations
is
needed.
Projections.
Projections
of
future
"
actual"
emissions
are
based
on
the
best
information
available,
but
are
inherently
uncertain.
This
uncertainty
increases
further
out
in
time.
Growth
rates
may
be
underestimated,
impacts
of
new
'
Id.
at
35.
51d.
at
66
67.
'
Id.
at
71.
3
c
10
technologies
or
regulatory
requirements
may
have
unexpected
effects,
etc.
The
WRAP
recognizes
that
there
are
some
competing
uncertainties
that
the
future
"
actual"
emissions
may
be
over
predicted.
However,
in
light
of
the
Commission's
specific
recommendation
to
reward
early
reductions
occurring
between
1990
and
2000,
the
WRAP
specifically
set
aside
15,000tons
in
2018
for
uncertaintyheadroom
in
addition
to
the
allocation
described
above
for
tribes.
The
15,000
tons
represents
2%
of
the
current
SO2
emissions
inventory
(
652,000
tons)^
encompassedwithin
the
trading
program.
The
WRAP
also
believes
the
likelihood
exists
that
the
hll
complement
of
emissions
set
aside
for
uncertainty
and
headroom
will
not
be
utilized.
All
sources
in
the
region
operate
below
their
allowable
emissions
to
ensure
that
they
are
in
compliance
with
emission
limits.
The
regional
milestones
are
comparable
to
allowable
emissions
because
an
exceedance
of
the
milestone
will
trigger
regulatory
consequences.
Individual
sources
will
be
tracking
their
emissions,
as
well
as
the
overall
regional
emissions,
and
the
possibility
of
avoiding
a
regulatory
program
will
provide
a
powerful
incentive
for
sources
to
keep
emissions
below
the
cap,
This
will
also
provide
a
disincentive
for
keeping
regional
emissions
close
to
the
cap,
because
that
will
increase
the
risk
that
an
unexpected
event
(
such
as
increased
production
fkom
one
sector)
will
trigger
the
regulatory
program.
The
incentive
to
operate
below
the
cap
should
be
especially
powerful
in
2018
when
individual
sources
will
face
penalties
if
the
cap
is
exceeded
and
a
source
has
emitted
SO2
in
excess
of
its
allowances.
3.
2018
SO,
Milestone
Calculation
2018
Baseline
622,000
Appropriate
Technology
Emission
Reductions
168,000
CEM
Bias
adjustment
10,000
Uncertainty/
Headroom
35.000
Total
479,000
=
480,000
In
thie
event
the
suspended
smelters
commence
operation
or
the
production
from
those
facilities
is
shifted
to
other
smelters,
as
much
as
30,000
tons
may
be
added
to
this
milestone.
c
11
1
E.
Visibility
Improvement
Section
169A
of
the
Clean
Air
Act
lists
a
number
of
factors
that
must
be
considered
as
part
of
the
BART
determination.
These
factors
are
addressed
in
the
regronal
haze
rule
in
a
two
step
process.
First,
an
analysis
of
the
best
system
of
continuous
emission
control
technology
available
is
performed,
considering
the
statutory
factors
of
cost
of
compliance,
the
energy
and
non
air
quality
environmental
impacts
of
compliance,
any
pollution
control
equipment
in
use
at
the
source,
and
the
remaining
useful
life
of
the
source.
Second,
an
analysis
of
the
degree
of
visibility
improvement
that
would
be
achieved
in
each
mandatory
Class
I
federal
area
as
a
result
of
the
emission
reductions
achievable
from
all
sources
subject
to
BART
located
within
the
region.
The
preamble
to
the
regional
haze
rule
indicates
that
the
visibility
analysis
should
be
conducted
using
the
cumulative
emission
reductions
fkom
all
BART
eligible
sources
in
the
transport
region,
not
the
impact
of
individual
sources.
The
preamble
also
indicates
that
the
States
and
Tribes
should
use
this
estimated
degree
of
visibility
improvement
in
determining
the
appropriate
BART
emission
limitations
for
specific
sou~
ces.~
When
defining
the
visibility
impact,
the
regional
haze
rule
identifies
the
deciview
metric
as
the
appropriate
measure
of
visibility
impairment,
and
improvement.
The
regional
haze
rule
preamble
discusses
the
value
of
measuring
visibility
using
a
metric
that
takes
into
account
both
measurement
of
physical
changes
(
i.
e.,
changes
in
air
quality)
and
human
perception.'
A
one
deciview
change
in
haziness
is
a
small
but
noticeable
change
in
haziness
under
most
circumstances
when
viewing
scenes
in
Mandatory
Class
I
areas.
g
The
preamble
also
recognizes
that
in
some
cases
a
visibility
change
of
less
than
one
deciview
is
perceptible,
while
under
other
conditions
a
change
of
more
than
one
deciview
might
be
required
in
order
for
the
change
to
be
perceptible.
lo
The
Regional
Haze
Rule
requires
the
assessment
of
reasonable
progress
in
terms
of
average
annual
visibility
improvement
overall,
and
for
each
of
the
20%
of
the
days
in
a
year
with
the
best
and
the
worst
visibility
(
the
first
and
last
quintiles).
Regional
haze
is
the
product
of
a
wide
variety
of
sources,
generally
associated
with
area
sources
and
long
range
transport
of
emissions.
Regional
haze
is,
therefore,
best
assessed
using
averages,
and
addressed
by
strategies
that
reduce
emissions
on
a
region
wide
scale.
In
keeping
with
this
requirement,
the
WRAP
conducted
modeling
of
the
degree
of
visibility
improvement
that
would
occur
on
average
and
for
the
20%
best
and
worst
visibility
days.
The
64
FR
35741
'
64
FR
35726
64
FR
35725
lo
64
FR
35726
35727
'
3
..
i
c
12
WRAP
used
the
transfer
coefficients
developed
as
part
of
the
Integrated
Assessment
System
(
US)
and
used
by
the
Grand
Canyon
Visibility
Transport
Commission.
This
modeling
has
1imitation.
swhich
must
be
considered
when
interpreting
the
results.
The
IAS
models
were
designed
to
assess
regional
transport
of
emissions,
and
therefore
only
offers
limited
insight
into
the
impact
of
local
emission
sources.
The
models
are
best
at
demonstrating
the
relative
effects
of
changes
in
regional
emissions
on
visibility.
One
other
important
limitation
involves
the
number
of
receptors
where
pollution
data
were
available.
The
GCVTC
c.
ollecteddata
from
only
six
receptors,
and
ultimately
scaled
its
modeling
for
only
four
of
these:
Hopi
Point,
Mesa
Verde,
Canyonlands,
and
Bryce
Canyon.
The
most
detailed
information
came
fiom
one
receptor,
Hopi
Point
in
Grand
Canyon
National
Park.
Although
the
IAS
has
limitations,
it
was
the
only
tool
that
could
realistically
be
used
in
the
short
time
frame
that
was
provided
to
develop
an
Annex
to
the
Grand
Canyon
Visibility
Transport
Commission
report.
Prior
to
the
development
of
the
IAS,
little
was
understood
about
the
contribution
of
various
emission
sources
to
regional
haze.
The
GCVTC
expended
considerable
time
and
energy
developing
the
tools
that
are
used
today
to
evaluate
the
sources
of
regional
haze.
The
WRAP
intends
to
keep
refining
and
improving
the
technical
tools
that
are
available
to
better
inform
policy
decisions.
The
visibility
modeling
measured
the
degree
of
visibility
improvement
that
would
occur
at
each
of
the
16
Class
I
areas
due
to
four
different
emission
reduction
scenarios
and
in
comparison
to
the
absence
of
any
regional
haze
program
(
i.
e.,
as
compared
to
the
baseline
emissions
inventory).
The
four
scenarios
were
developed
to
show
the
changes
in
visibility
that
would
occur
due
to
increasingky
stringent
emission
reductions.
Table
2
presents
the
visibility
improvements
for
the
scenario
that
best
matches
the
original
WRAP
estimate
of
SO,
reductions
associated
with
the
application
of
controls
on
BART
eligible
sources,
at
155,000
tons,
as
modeled
by
ICF
intheir
economic
impacts
study.
When
comparing
the
results
of
the
visibility
analysis
for
the
Command
and
Control
scenario
to
the
MTF
scenario,
it
is
important
to
recognize
the
following
facts:
a
The
emission
inventory
for
the
Command
and
Control
scenaSio
was
developed
as
part
of
the
economic
impacts
study
by
ICF
to
compare
the
cost
of
achieving
various
levels
of
emission
reduction
using
a
market
approach
with
the
cost
of
achieving
similar
reductions
using
a
source
specific
command
and
control
program.
Both
the
Command
and
Control
and
MTF
scenarios
started
with
the
same
baseline
emissions
inventory
for
2018
(
648,000
tons) .
Note
that
the
baseline
inventory
used
by
ICF
is
different
from
that
used
by
the
MTF.
This
is
an
artifact
of
the
way
the
economic
model
was
implemented.
The
important
consideratioin
is
that
the
same
baseline
is
used
to
assess
the
differences
among
the
options.
For
C
13
For
the
Command
and
Control
scenario,
ICF
applied
the
MTF
BART
assumptions
to
this
inventory
and
calculated
139,000
tons
of
emissions
reductions
in
2018.
These
reductions
were
subtracted
from
the
baseline,
yielding
an
inventory
of
509,000
tons.
For
the
MTF
scenario,
ICF
subtracted
the
MTF s
best
estimate
of
BART
reductions
at
the
time
(
155,000
tons)
and
added
back
35,000
tons
for
headrooduncertainty,
consistent
with
the
GCVTC
recommendations
discussed
in
section
D.
2.,
above.
This
yielded
an
inventory
of
528,000
tons.
Rounding
to
the
nearest
tenth
of
a
deciview
a
level
of
accuracy
beyond
which
the
results
cannot
be
compared
with
any
confidence
the
average
visibility
benefit
of
the
MTF
scenario
equals
that
of
the
Command
and
Control
scenario
0.1
dv.
The
use
of
the
Command
and
Control
scenario
as
a
surrogate
for
comparing
the
visibility
benefits
of
the
Annex
to
a
true
BART
scenario
is
limited
because
it
does
not
recognize
the
overall
air
quality
benefits
of
the
emissions
caps.
Some
of
the
air
quality
benefits
of
the
emissions
caps
as
compared
to
a
source
by
sourceBART
approach
are
described
in
SectionF,
beginning
on
page
D
17.
These
benefits
include
setting
caps
that
limit
increased
utilization
and
emission
rates
at
BART
and
non
BART
sources,
setting
caps
based
on
the
assumption
that
47,000
tons
of
emissions
from
existing
non
utilityhon
smelter
sources
will
be
retired
between
1998
and
2018,
and
setting
caps
based
on
the
assumption
that
new
source
growth
will
be
limited
to
27,000
tons
between
2003
and
2018.
While
the
Command
and
Control
scenario
used
for
the
visibility
modeling
has
these
same
assumptions
included,
in
actuality
these
benefits
would
not
accrue
to
a
BART
program
under
Section
308
of
the
Regional
Haze
Rule.
For
these
reasons
,
the
use
of
the
COWXUI~
and
Control
scenario
as
a
surrogate
for
comparing
the
benefits
of
the
Annex
to
a
true
BART
scenario
is
of
limited
value.
As
can
be
seen,
the
maximum
visibility
improvement
expected
f?
om
installation
of
appropriate
control
technology
for
SO,
on
BART
eligible
sources
in
the
Western
United
States,
amounts
to
about
one
third
of
a
deciview,
which
is
not
perceptible
to
the
average
person.
Table
3
provides
the
results
of
the
visibility
modeling
for
an
approximation
of
the
four
2018
milestones
offered
for
public
comment
in
May
2000.
The
modeling
distinguishes
among
the
milestones
based
on
the
estimated
BART
level
emissions
reductions.
These
visibility
results
show
that,
even
under
the
most
aggressive
emissions
reduction
scenario,
no
perceptible
change
in
visibility
will
accrue.
Further,
the
visibility
improvements
of
all
of
the
different
approaches
would
be
indistinguishable
for
regional
haze
purposes.
This
is
not
intended
to
imply
that
the
lack
ofperceptible
visibility
improvement
is
ajustification
for
taking
no
details,
refer
to
the
ICF
final
report,
Economic
Impacts
of
Implementing
a
ReGonal
SO,
Emissions
Cap
for
Stationarv
Sources
in
the
Western
United
States
(
September
2000).
C
14
action
to
<
reduceSO,
emissionsfrom
stationary
sources.
To
the
contrary,
it
emphasizes
the
need
to
develop
a
comprehensive
plan
that
reduces
visibility
impairing
emissions
from
all
types
of
sources
if
the
goals
of
Subpart
C
of
Title
I
of
the
Clean
Air
Act
are
to
be
achieved
in
the
West.
Table
2
Modeled
Visibility
Improvement
in
2018:
Command
and
Control
Scenario
Deciview
Improvement
Class
I
Area
Davs
Davs
Average
Arches
National
Park
0.17
0.28
0.22
Brvce
Canvon
0.02
0.16
0.08
Black
Canyon
of
the
Gunnison
0.08
0.08
0.10
l~
GG&
Ezj
Canyonlands
Cmitol
Reef
Flat
Tops
tHopi
Point
Maroon
Bells
t
Mesa
Verde
National
Park
Mt.
Baldy
Petrified
Forest
SanPedro
Parks
Sycamore
Canyon
Wleminuche
Wilderness
West
Elk
Zion
National
Park
0.16
0.26
0.21
0.06
0.21
0.13
0.09
0.23
0.16
0.03
0.15
0.09
0.10
0.07
0.10
0.09
0.35
0.19
0.04
0.20
0.12
0.07
0.14
0.11
0.08
0.32
0.21
0.05
0.08
0.07
0.06
0.34
0.18
0.10
0.07
0.10
0.02
0.10
0.06
Averacre
0.08
0.19
0.13
Min
0.02
0.07
0.06
Max
0.17
0.35
0.22
1
C
15
F.
Other
Considerations
There
are
a
number
of
other
considerations
that
must
be
taken
into
account
in
the
overall
determination
as
to
whether
or
not
the
2018
milestone
developed
by
the
WRAP
achieves
greater
'
reasonable
progress
than
would
be
achieved
by
the
application
of
BART.
1.
Remedy
and
Prevention.
When
Congress
established
the
visibility
program
in
1977
it
declared
as
a
national
goal
"
the
prevention
of
any
future,
and
the
remedying
of
any
existing"
anthropogenic
visibility
impairment
in
mandatory
class
I
federal
areas.
l2
BART
is
an
emission
limitation
established
at
a
specific
source
and
is
designed
as
a
remedy
to
impairment
at
specificmandatory
Class
I
areas.
By
contrast,
the
market
trading
program
proposed
by
the
WRAP
serves
the
dual
purpose
of
remedying
existing
impairment
and
preventing
future
impairment
by
requirin
issions
reductions
and
___
mpphgsmissions
for
stationary
sources.
is
prevented
by
capping
emissions
growth
fiom
sources
not
eligible
under
the
BART
requirements,
from
BART
sources
that
are
expected
to
significantly
increase
utilization,
and
from
entirely
new
sources
in
the
region.
2.
Additional
Sources
Included.
The
backstop
trading
program
designed
by
the
WRAP
will
include
all
stationary
sources
with
emissions
higher
than
100
tondyear
of
SO,.
The
W'XP
designed
this
program
as
part
of
an
overall
strategy
to
address
all
sources
of
visibility
impairing
pollutants,
rather
than
focusing
on
a
subset
of
stationary
sources.
2018
SO,
Number
of
Sources
Emissions"
BART
Eligible
47
201,615
Other
Stationary
Sources
157
4
246,570
"
Note:
The
2018
Emission
estimate
does
not
include
2
shut
down
smelters,
or
a
CEM's
bias
adjustment.
The
estimate
includes
an
emission
reduction
estimate
of
168,000Ji.
om
BART
eligible
sources.
The
inclusion
of
all
major
SO,
sources
in
the
progrqn
is
necessary
to
create
a
viable
trading
program,
and
also
sewes
a
broader
purpose
to
ensure
that
growth
inemissions
from
non
BART
eligible
sources
does
not
undermine
the
progress
that
has
been
achieved.
BART
applied
on
a
case
by
case
basis
would
not
affect
these
sources,
and
there
would
be
no
limitation
on
their
future
operations
under
their
existing
permit
conditions.
Because
the
milestones
will
cap
these
sources
at
actual
emissions
(
which
are
less
than
current
allowable
emissions),
the
overall
effect
of
their
inclusion
is
to
provide
greater
reasonable
$?
ogress*
would
have
been
acheved
if
only
BART
eligible
sources
were
included
in
the
program.
l2
CAA
0
169A(
a)(
l).
C
17
3.
Cap
on
New
Source
Growth.
The
milestones
designed
by
the
WRAP
will
cap
the
growth
of
SO,
emissions
in
the
west.
These
milestones
include
estimates
for
growth,
but
then
lock
these
estimates
in
as
an
enforceable
emission
cap.
The
WRAP
strategy
is
consistent
with
the
statutory
goal
of
preventing
any
hture
visibility
impairment
that
results
fkom
man
made
air
pollution.
The
entire
region
is
experiencing
rapid
growth
which
could
erode
the
progress
that
has
been
achieved
in
the
last
two
decades
towards
improving
visibility.
BART
applied
on
a
case
by
case
basis
would
have
no
impact
on
future
growth,
and
in
the
long
run
would
not
achieve
the
regional
emission
reductions
that
are
guaranteed
by
the
program.
4.
Actual
vs.
Allowable
Emissions.
The
baseline
emission
projections,
and
assumed
reductions
due
to
the
application
of
appropriate
retrofit
controls
to
BART
eligible
sources,
are
all
based
on
actual
emissions,
using
either
1998
or
1999
as
the
baseline.
The
use
of
actual
emissions
has
an
effect
in
several
ways.
If
the
BART
process
was
applied
on
a
case
by
case
basis
to
individual
soukes,
emission
limitations
would
be
established
based
on
the
maximum
level
of
operation
of
the
unit.
The
allowable
emissions
are
typically
higher
than
actual
emissions,
because
sources
do
not
always
rununder
full
load
conditions,
over
the
Eull
year s
available
time.
In
addition,
the
allowable
emissions
would
account
for
variations
in
the
sulk
content
of
fuel
and
alternative
operating
scenarios.
The
differencebetween
actual
emissions
and
allowable
emissions
is
particularly
large
when
a
source
is
permitted
to
burn
two
different
fuel
types,
such
as
oil
and
natural
gas,
or
when
the
source
is
part
of
a
cyclical
industry
where
production
varies
fi
om
year
to
year
due
to
the
changing
demand
for
their
product.
The
WRAP S
method
of
emission
projections
allows
for
some
increase
in
capacity
for
the
electric
utility
industry
which
will
partially
address
this
difference
between
actual
and
allowable
emissions.
Even
in
this
case,
the
utilities
are
assumed
to
operate
at
an
average
of
85%
of
nameplate
capacity,
even
though
they
are
permitted
to
operate
at
100%
capacity.
Non
utility
sources,
on
the
other
hand,
are
assumed
to
retire
at
a
certain
percentage
rate
each
year
with
no
provision
for
emission
growth
from
existing
sources.
Any
growth
that
is
projected
for
those
industries
(
refineries,
pulp
and
paper,
cement,
etc.)
is
assumed
to
be
met
by
new
sources
at
highly
controlled
emission
rates.
In
addition
to
the
cap
on
growth
of
actual
emissions,
the
difference
between
an
emission
projection
for
future
years,
and
a
regional
emission
cap
must
also
be
considered.
The
milestones
will
act
as
a
regulatory
trigger
that
will
be
converted
into
an
enforceable
emission
cap
if
the
milestones
are
not
met.
This
essentially
creates
a
regional
allowable
emission
level.
When
sources
are
managing
their
operations
they
have
a
large
incentive
to
maintain
headroom
under
any
enforceable
limit
to
ensure
that
they
stay
in
compliance.
This
process
is
expected
to
happen
on
a
voluntary
basis
prior
to
the
program
trigger,
and
will
be
strengthened
if
the
milestones
become
enforceable
emission
caps.
The
net
effect
is
that
compliancewith
the
milestones
should
lead
to
actual
emissions
that
are
below
the
milestone.
The
difference
between
actual
emissions
and
allowable
emissions
is
commonly
referred
to
as
headroom.
.,
C
18
5.
Mass
based
Cap
vs.
Rate
Based
Emission
Limits
for
BART.
Emission
limitations
folr
stationary
sources
(
including
BART
limits)
are
typically
expressed
as
emission
rates
(
Ibs/
how
or
IbsflMMBtu),
while
the
WRAP
milestones
are
expressed
as
total
mass
during
a
given
year
(
tons/
year).
One
effect
of
this
difference
is
that
rate
based
limits
can
lead
to
higher
emissions
when
production
is
increased
or
when
higher
sulfbr
he1
is
used,
as
explained
in
the
discussion
of
actual
vs.
allowable
emissions
above.
Another
difference
is
that
mass
based
limits
will
include
excess
emissions
that
may
occur
due
to
malfunctions
or
during
the
start
up
or
shut
down
of
emission
units.
A
good
example
of
this
difference
is
the
requirement
in
the
acid
rain
program
that
emissions
must
be
assumed
to
be
the
highest
value
recorded
from
the
past
year
during
the
time
period
that
continuous
emission
monitors
are
not
functioning
on
a
stack.
These
higher
emissions
are
calculated
as
part
of
the
overall
tonsfyear,
and
must
be
accounted
for
under
the
mass
based
cap
for
the
acid
rain
program.
6.
1990
as
a
baseline
for
Section
309
Regional
Haze
Plans.
The
regional
haze
rule
rec(
ognizedthe
significant
work
that
had
been
completed
by
the
Grand
Canyon
Commission,
and
section
309
ofthe
rule
was
therefore
designed
to
incorporatethe
Coinmission
recommendations.
A
key
element
of
this
section
of
the
rule
is
the
use
of
1990
as
a
baseline
for
measuring
progress.
There
have
been
significant
emission
reductions
in
the
west
since
1990,
and
this
improvement
needs
to
be
considered
when
measuring
the
overall
effects
of
the
Commission's
strategies.
The
Commission
established
a
goal
of
a
13%
reduction
from
1990
emissions.
It
is
anticipated
that
the
actual
emission
reductions
in
the
region
will
be
closer
to
20%.
Emission
reductions
due
to
the
application
of
appropriate
retrofit
technology
on
BART
eligible
sources
between
1990
and
2018
are
estimated
to
be
28'
7,176tons
of
SO,
(
See
Table
4).
This
estimate
includes
a
reduction
of
119,000
tons
of
SO,
&
om
BART
eligible
sources
that
have
occurred
or
have
been
legally
committed
to
between
1990and
2000
(
assuming
that
these
plants
are
operating
at
85%
of
nameplate
capacity).
The
2018
milestone
of
510,000
represents
a
regional
emission
reduction
of
around
321,000
tons
of
SO,
&
omthe
1990
baseline
emissions
of
831,000
tons.
This
overall
reduction
due
to
the
milestones
is
approximately
35,000
tons
greater
than
what
has
been
estimated
due
to
the
application
of
appropriate
retrofit
technology
to
BART
eligible
sources,
C
19
Table
4
Calculation
of
BART
Level
Emissions
Reductions
from
the
1990
Baseline
Emissions
1990
1990
1990
level
Emissions
at
Level
of
after
Emissions
Facility
and
Unit
Emissions
Capacity
of
control
85%
capacity
control
Controls
Reductions
Navajo
#
1
20,497
62%
0%
27,952
90%
2,050
18,447
Navajo
#
2
26,101
81%
0%
27,252
90%
2,610
23,491
Navajo
#
3
29,621
90%
36%
29,62
1
90%
2,962
26,659
Hayden
#
1
4,857
77%
0%
5,344
85%
729
4,128
Hayden
#
2
6,420
78%
0%
7,039
85%
963
5,457
Cherokee
#
4
4,689
55%
38%
7,298
85%
703
3,986
Valmont
#
5
3,007
65%
0%
3,924
85%
451
2,556
Mojave
#
1
21,605
56%
0%
32,834,
85%
3,241
18,364
Mojave
#
2
18,720
68%
0%
23,2971
85%
2,808
15,912
Total
Effected
and
Planned
Emission
Reductions
fiomBART
eligible
sources
119,000
WRAP
Calculated
BART
level
reductions
(
rounded
to
nearest
1,000.
from
allstat7.
xls)
168.000
I
TOTAL
I
287,0001
7.
Commission
Strategies
are
a
Total
Package.
The
GCVTC
recommendations
go
well
beyond
stationary
sources,
and
include
strategies
to
address
mobile
sources,
prescribed
fire,
pollution
prevention,
and
emissions
in
and
near
Mandatory
Class
I
areas.
The
reductions
from
these
additional
strategies
have
not
yet
been
quantified,
but
are
expected
to
be
significant.
The
stationary
source
strategies
need
to
be
viewed
as
part
of
this
overall
package.
Visibility
impairment
in
the
west
is
caused
by
multiple
sources
and
pollutants,
and
a
narrow
focus
on
stationary
sources
may
not
achieve
the
same
results
as
a
broad
based
program.
The
WRAP
is
in
the
process
of
quantifLingthe
effect
of
the
rest
of
the
Commission s
strategies,
and
the
entire
package
will
be
included
in
the
State
and
Tribal
Implementation
Plans
in
2003.
G.
Comparison
of
Trading
vs
Command
and
Control
BARTRequirements.
One
additional
issue
that
must
be
considered
when
determining
if
the
2018
milestone
achieves
greater
reasonable
progress
than
BART
is
the
geographic
location
where
emission
reductions
will
occur.
For
example,
if
all
of
the
emission
reductions
under
a
trading
program
scenario
are
concentrated
.
in
one
small
part
of
the
region,
the
visibility
improvement
may
be
less
than
what
would
be
achieved
if
reductions
occurred
at
specific
locations
under
a
command
and
control
approach.
To
address
this
question,
the
WRAP
modeled
the
improvement
in
visibility
impairment
that
would
occur
under
two
different
scenarios:
a
command
and
control
scenario
where
the
emission
reductions
due
to
the
application
of
appropriate
retrofit
controls
on
BART
eligible
sources
were
assumed
to
occur
at
locations,
and
a
second
scenario
where
least
cost
modeling
was
used
to
identify
where
these
same
emission
reductions
would
occw
under
a
trading
program.
The
visibility
transfer
coefficients
and
control
cost
assumptions
developed
as
part
of
the
Integrated
Assessment
System
were
used
for
this
analysis.
Tables
2
and
3
provide
the
data
for
the
comparison
of
the
visibility
improvement
associated
with
these
two
approaches
c
20
The
results
of
this
analysis
showed
that
there
would
be
an
imperceptible
improvement
in
visibility
,
impairmentunder
the
command
and
control
scenario.
The
maximum
difference
between
the
two
scenarios
at
any
of
the
16
Class
I
areas
was
only
0.1
deciview.
c
21
| epa | 2024-06-07T20:31:40.650299 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0076-0037/content.txt"
} |
EPA-HQ-OAR-2002-0076-0038 | Supporting & Related Material | "2002-04-02T05:00:00" | null | Attachment
D.
Preliminary
List
of
BART
Eligible
Sources
in
the
Grand
Canyon
Visibility
Transport
Region
Mote:
Thefollowing
list
of
BART
Eligible
sources
is
still
preliminary.
EPA
guidance
regarding
BART
applicability
is
still
under
development,
and
thefinal
guidance
may
add
or
remove
individual
unitsfrom
this
list.
Public
review
may
result
in
additional
changes
to'this
draft
list.
The
summay
for
each
state
was
drawnporn
a
number
of
sources,
primarily
the
Excel
spreadsheets
that
wereprepared
by
the
states
to
estimate
BART
emission
reductions
in
the
region.
Arizona
AEPCO
Apache
Unit
2
AEPCO
Apache
Unit
3
Arizona
Public
Senice,
Cholla
Unit
2
Arizona
Public
Service,
Cholla
Unit
3
Arizona
Public
Service,
Cholla
Unit
4
Chemical
Lime
Nelson:
&
ln
1
Chemical
Lime
Nelson:
Kiln
2
Chemical
Lime
Douglas:
KiIn
4
Chemical
Lime
Douglas:
Kiln
5
Chemical
Lime
Douglas:
Kiln
6
SRP
Coronado
u91
SRP
Coronado
UB2
Abitibi
Consolidated
Sales
Corporation,
Snowflake
Division;
#
1
power
boiler
Abitibi
Consolidated
Sales
Corporation,
Snowflake
Division;
#
2
power
boiler
Abitibi
Consolidated
Sales
Corporation,
SnowflakeDivision;
#
2
recovery
boiler
California
,
NoBART
eligible
sources
have
been
identified
in
California
Colorado
Public
Service
CO
Cherokee
#
4
Conoco
Inc
Denver;
FCC
Unit
Regenerator
Conoco
Inc
Denver;
Public
Service
CO
Valmont
#
5
SouthwesternPortland
Cement
Colorado
Springs
Utilities
Drake
#
5
Colorado
Springs
Utilities
Drake
#
6
Colorado
Springs
Utilities
Drake
#
7
Colorado
Springs
Utilities
Nixon
#
1
Holnam
Portland
Cement
#
3
Tristate
Generation
Craig
#
1
Tristate
Generation
Craig
#
2
Public
Service
CO
Comanche
#
1
Public
Service
CO
Comanche
#
2
Public
Service
CO
Hayden
#
1
Public
Service
CO
Hayden
#
2
Tri
Gen
Energy
#
4
Tri
Gen
Energy
#
5
__
_____
~
Idaho
No
BART
Eligible
sources
have
been
identified
in
Idaho
Nevada
Nevada
Cement
Co.,
Fernley
Plant,
Kiln#
1
Nevada
Cement
Co.,
Fernley
Plant,
Kiln#
2
Nevada
Power
Co.,
Reid
Gardner
Station,
Unit
#
1
Nevada
Power
Co.,
Reid
Gardner
Station,
Unit
#
2
Nevada
Power
Co.,
Reid
Gardner
Station,
Unit
#
3
Southern
California
Edison,
Mojave
Station,
Unit
#
1
Southern
California
Edison,
Mojave
Station,
Unit
#
2
New
Mexico
PNM,
San
Juan,
Boiler
#
1
PNM,
San
Juan,
Boiler
#
2
PNM,
San
Jum;
Boiler
#
3
PNM,
San
Juan,
Boiler
#
4
Phelps
Dodge,
Hidalgo
Smelter
Giant
Industries,
Bloomfield
Refinery,
1FCCP
ESP
stack
Giant
Refining,
Ciniza
Refinery,
4
B&
W
CO
boiler
Raton
Public
Service,
Raton
Pwr.
Plt.,
1
Erie
El
Paso
Electric,
Rio
Grande
Gen.
Sta.,
3
2
Oregon
Fort
James
Operating
Company,
PR808
Recovery
Furnace,
ESP
Outlet
Fort
James
Operating
Company,
PR831Power
Boiler,
Conventional
6
Burner
Boise
Cascade
Corporation,
No.
2
Recovery
Furnace
Boise
Cascade
Corporation,
No.
3
Recovery
Furnace
Boise
Cascade
Corporation,
Power
Boiler
6
9
Portland
General
Electric
Beaver,
Six
combustion
turbines
for
electric
power
generation
International
Paper
Gardner,
P U3047
Power
Boiler
Stack
International
Paper
Gardner,
PRB
048
Combined
Recovery
Boilers
Stack
Collins
Products
LLC,
Boiler
7
Collins
Proiducts
LLC,
Boiler
8
Willamette
Industries,
Inc.
Albany,
Recovery
Boiler
#
4Black
Liquor
Solids
Wah
Chang,
Boilers
1
3
Pope
&
Talbot,
Inc.,
Power
Boiler
1
Oil
Use
Amalgamated
Sugar
Co.
Nyssa,
S
B3,
Foster
Wheeler
Boiler
(
coal
fired)
Amalgamated
Sugar
Co.
Nyssa,
S
B2,
Foster
Riley
Boiler
(
coal
fired)
Portland
General
Electric
Company
Boarban,
Main
Boiler
Reynolds
Metals
Co.,
Potrooms
Rimary
Collection
System
Utah
PacifiCorp
Huntington
Plant
Unit#
l
PacifiCorp
HuntingtonUnit
#
2
PacifiCorp
Hunter
Unit
#
I
PacifiCorp
Hunter
Unit
#
2
Wyoming
Pacificorp
Wyodak
Coal
Power
Plant
(
Ul)
Black
Hills
Neil
Simpson
Coal
Power
Plant
(
Ul)
Pacificorp
Naughton
Coal
Power
Plant
PI)
Pacificorp
Ndughton
Coal
Power
Plant
(
U2)
Pacificorp
Naughton
Coal
Power
Plant
(
u3)
Pacificorp
Dave
Johnston
Coal
Power
Plant
(
U3)
Pacificorp
Dave
Johnston
Coal
Power
Plant
(
U4)
Pacificorp
Jim
Bridger
Coal
Power
Plant
(
Ul)
Pacificorp
Jim
Bridger
Coal
Power
Plant
(
U2)
Pacificorp
Jinn
Bridger
Coal
Power
Plant
(
U3)
Pacificorp
Jim
Bridger
Coal
Power
Plant
(
U4)
Basin
Electric:
Laramie
River
Coal
Power
Plant
(
Ul)
3
Basin
Electric
Laramie
River
Coal
Power
Plant
(
UZ)
Basin
Electric
Laramie
River
Coal
Power
Plant
(
U3)
Wyoming
Refining
TCC
Feed
Heater
(
H
03)
Wyoming
Refining
TCC
Plume
Burner
(
H
05)
Little
America
Oil
Refinery
#
7
Boiler
(
BL
1415)
FMC
Corp.
Trona
Plant
NS
1A
Coal
Boiler
FMC
Corp.
Trona
Plant
NS
1B
Coal
Boiler
General
Chemical
Trona
Plant
GR
2
L
Coal
Boiler
General
Chemical
Trona
Plant
GR
3
W
Coal
Boiler
FMC
Granger
(
Tg)
Trona
Plant
#
1
Coal
Boiler
(
14)
FMC
Granger
(
Tg)
Trona
Plant
#
2
Coal
Boiler
(
15)
Navajo
Nation
Arizona
Public
Service,
4
Comers,
Unit
#
1
Arizona
Public
Service,
4
ComersyUnit
#
2
Arizona
Public
Service,
4
Corners,
Unit
#
3
Arizona
Public
Service,
4
CornersyUnit
#
4
Arizona
Public
Service,
4
CornersYUnit
#
5
.4
r
.1
4
| epa | 2024-06-07T20:31:40.664563 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0076-0038/content.txt"
} |
EPA-HQ-OAR-2002-0076-0039 | Supporting & Related Material | "2002-04-02T05:00:00" | null | ATTACHMENT
E
PRELIMINARY
ESTIMATE
OF
STATE
AREA
ALLOCATIONS
The
following
table
is
a
preliminary
estimate
of
how
the
allocations
for
existing
sources
may
be
distributed
among
the
state
areas,
including
sources
located
within
Indian
Nations
(
e.
g.,
Navajo
Generating
Station
is
within
the
Navajo
Nation
and
the
geographic
boundaries
of
Arizona)
for
the
purposes
of
providing
an
indication
of
the
impact
of
jurisdictions
opting
in
or
out
of
the
backstop
cap
and
trade
program.
This
is
not
intended
to
presume
or
prescribe
assignment
of
allocations
to
states.
The
actual
distribution
will
be
based
upon
the
location
of
sources
according
to1
the
state
or
tribe
havingjurisdiction
over
those
sources.
Final
distribution
of
allocations
by
state
and
tribal
jurisdiction
will
be
determined
based
on
the
final
allocations
to
existing
sources,
as
submitted
in
the
section
309
SIP
revisions.
Note
that
this
includes
the
smelter
set
aside.
How
those
emissions
will
be
distributed
if
one
or
both
of
the
two
suspended
smelters
close
will
be
dependent
on
if
or
how
the
other
smelters
absorb
the
production
from
the
closed
ones,
as
described
in
the
body
of
the
Annex.
In
addition,
with
the
exception
of
the
emissions
reductions
at
the
Mohave
Generating
Station
in
Laughlin,
Nevada,
known
reductions
expected
to
occur
beyond
2003,
such
as
the
20,000
ton
reduction
from
the
Colorado
front
range
power
plants,
are
not
included.
| epa | 2024-06-07T20:31:40.667885 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0076-0039/content.txt"
} |
EPA-HQ-OAR-2002-0076-0040 | Supporting & Related Material | "2002-04-02T05:00:00" | null | Attachment
F:
Conceptual
Proposal
For
Re
Allocation
of
the
Tribal
Set
Aside
The
hex
provides
that,
upon
the
implementation
of
the
trading
program,
20,000
tons
per
year
will
be
established
as
a
general
tribal
allocation,
to
be
distributed
as
determined
by
the
tribes
in
the
region.
In
order
to
insure
that
all
tribes
in
the
region
have
a
fair
and
meaningful
opportunity
to
take
part
in
this
determination,
it
must
be
done
in
the
context
of
government
togovernment
consultationbetween
EPA
and
the
tribes,
during
the
rule
making
process
to
amend
Regional
HaLe
Rule
5
309.
This
Attachment
describes
the
parameters
governing
the
tribal
reallocation
(
distribution),
and
presents
a
preliminary
conceptual
proposal,
in
order
to
facilitate
tribal
comment.
This
Is
not
a
consensus
document.
In
general
terms,
the
members
and
participants
in
the
WRAP
have
agreed
that
the
re
allocation
of
the
tribal
set
aside
is
a
matter
internal
to
the
tribes.
However,
to
the
extent
the
methodology
affects
other
aspects
of
the
program,
other
members
and
participants
reserve
their
right
to
comment.
I.
Parameters
and
Principles
Governing
Re
Allocation
Methodology
A.
Provision
for
Late
(
Post
2003)
Opt
in
by
Tribes
The
re
allocation
scheme
should
provide
for
the
possibility
that
some
tribes
will
opt
to
participate
in
the
program
after
the
2003
deadline
applicable
to
states
for
their
SIPS.
1.
Policy
Rationale
Several
factors
point
to
the
need
to
allow
tribes
to
make
the
decision
to
participate
in
the
program
after
the
2003
deadline
applicable
to
states.
The
more
than
200
tribes
in
the
GCVTC
region
will
ace
a
formidable
task
in
deciding
whether
to
opt
in
to
6
309
over
the
next
three
years.
The
backstop
emission
trading
program
described
in
the
Annex
is
in
many
ways
an
innovative
and
even
experimental
program.
The
program
marks
the
first
time
tribes
will
be
integrated
into
a
multi
state
regional
trading
scheme,
raising
new
issues
regarding
tribal
sovereignty,
federalism,
and
relationships
to
states.
Additionally,
a
fhdamental
difference
between
it
and
existing
emission
trading
programs
is
the
concept
that
voluntary
measures
will
initially
be
relied
on
to
meet
emissions
goals,
with
the
actual
trading
program
serving
as
a
contingency
measure.
By
design,
it
is
structured
to
minimize
,
thelikelihood
of
triggering
the
trading
program
until
well
after
2003.
Because
most
tribes
will
likely
not
be
affected
until
the
actual
trading
program
is
triggered,
the
relevance
of
the
program
to
a
particular
tribe
may
be
hard
to
gauge
in
2003.
F
I
To
these
complicating
regulatory
factors
are
added
the
inherent
uncertainty
of
future
trends
in
technology,
energy
use,
and
economic
development,
both
within
the
region
as
a
whole
and
on
particular
tribal
lands.
In
this
regard,
tribes
face
a
different
situation
than
states.
States
comprise
larger
geographic
areas,
which
lessens
the
need
for
accuracy
in
predicting
exactly
where
economic
development
may
occm
simpliflmg
assumptions,
averaging,
and
other
smoothing
functions
can
be
used.
Moreover,
tribes
will
more
often
than
states
have
a
proprietary
interest
in
development
projects
within
their
jurisdiction,
and
thus
have
more
at
stake
in
insuring
that
the
regulatory
strategy
they
employ
is
complementaryto
their
development
strategy.
Finally,
tribes
are
faced
with
these
decisions
at
a
time
when
most
tribes
are
in
the
early
stages
of
establishing
air
programs
through
such
activities
as
creating
emissions
inventories,
implementing
ambient
monitoring
programs,
and
adopting
basic
air
quality
codes.
Tribal
government
resources
are
generally
not
available
for
dedication
to
the
type
of
economidair
quality
policy
analysis
required
to
assess
prospectively
the
ultimate
implications
of
the
decision
whether
to
opt
into
5
309.
Allowing
tribes
to
opt
into
the
program
after
2003
will
not
compromise
the
environmental
goals.
of
the
program.
In
fact,
it
would
be
environmentallybeneficial
to
encourage
the
inclusion
of
new
tribal
sources
in
the
program,
in
order
to
insure
the
integrity
of
the
regional
cap.
If
tribes
lose
the
option
of
opting
into
the
program
after
2003,
new
sources
on
tribal
lands
would
be
regulated
under
$
308
of
the
haze
rule.
This
means
they
would
be
subject
to
control
requirements,
but
their
emissions
would
not
be
mitigated
by
corresponding
reductions
elsewhere,
as
would
occur
under
the
trading
program.
(
A
different
analysis
may
apply
to
tribes
with
existing
sources.
As
noted
below,
EPA
has
the
authority
to
utilize
federal
implementation
where
necessary
to
ensure
reasonable
progress
with
respect
to
such
sources).
2.
Legal
Rationale
For
the
reasons
explained
below,
allowing
tribes
to
opt
in
to
the
trading
program
after
2003
is
consistent
with
the
framework
provided
by
the
Clean
Air
Act
and
implementing
regulations.
a.
Tribes
are
expressly
exempt
from
visibility
implementation
deadlines
under
the
Tribal
Authority
Rule.
The
Tribal
Authority
Rule
(
TAR),
40
CFR
$
49.1
49.11,
delineates
the
CAA
sections
for
which
it
is
appropriate
to
treat
tribes
in
the
same
manner
as
states.
Under
the
general
approach
of
the
TAR,
tribes
which
meet
certain
eligibility
criteria
may
apply
for
and
receive
treatment
in
the
same
manner
states
for
all
CAA
provisions
except
those
specifically
identified
as
inappropriate.
Among
provisions
identified
as
inappropriate
for
tribes
are
[
s]
pecific
visibility
implementation
plan
submittal
deadlines
established
under
169A
of
the
Act.
40
CFR
0
49.4(
e).
,
..
F
2
This
exemption
applies
to
the
deadlines
contained
in
the
RHR
sections
308
and
309.
Although
the
Regional
Haze
Rule
originated
from
a
process
prescribed
in
CAA
0
169B,
4
169B
requires
that
IEPA
respond
to
reports
fiom
Visibility
Transport
Commissions
by
carrying
out
its
regulatory
duties
under
169A.
See
42
U.
S.
C.
07492(
e).
Therefore
the
deadlines
in
the
RHR
are
established
under
9
169A
of
the
Act
and
are
not
applicable
to
tribes
under
the
TAR.
EPA
recognized
this
in
the
preamble
to
the
RHR:
Section
49.4(
f)
of
the
TAR
provides
that
deadlines
related
to
SIP
submittals
under
section
169(
B)(
e)(
2)
do
not
apply
to
Tribes.
64
Fed.
Reg.
35
714,
35759.
July
1,
1999.
b.
Nothing
in
the
structure
or
language
of
the
TAR
or
RHR
suggests
that
the
RHR
0309
option
would
disappear
for
tribes
upon
the
passing
of
the
state
applicable
deadline.
The
provisions
of
the
TAR
firmly
establish
that
the
RHR
implementation
deadlines
are
not
applicable
to
tribes.
Nevertheless,
an
argument
could
be
made
that
a
tribes
failure
to
submit
a
TIP
by
the
:
statedeadline
of
December
31,2003
would
preclude
a
tribe
from
submitting
a
0309
TIP
at
a
later
date,
even
though
the
date
is
not
a
deadline
in
the
sense
that
failure
to
meet
it
would
invoke
sanctions.
Such
a
reading
would
be
counter
to
the
spirit
of
the
TAR
and
the
RHR.
The
MtR
itself
is
silent
on
this
question.
The
only
language
addressing
tribal
implementation
of
3
309
is
found
in
9
309(
d)(
12):
Tribal
implementation.
Consistent
with
40
CFR
Part
49,
tribes
within
the
Transport
Region
may
implement
the
required
visibility
programs
for
the
16
Class
I
areas,
inthe
same
manner
as
States,
regardless
of
whether
such
tribes
have
participated
as
members
of
a
visibility
transport
commission.
One
might
argue
that
phrase
in
the
same
manner
as
States
implies
that
the
tribes
are
also
subject
to
the
same
restrictions
as
states.
However,
the
preamble
discussion
of
ths
language
makes
it
clear
that
the
purpose
of
this
language
is
to
emphasize
the
tribes
independence
from
states.
In
fact,
the
preamble
erroneously
states
that
this
provision
is
not
included
in
the
final
rule
because
it
would
be
superfluous
in
light
of
the
TAR:
The
WGA
called
for
EPA s
final
rule
topermit
tribes
within
the
GCVTC
Transport
Region
to
implement
visibilityprograms,
or
reasonably
severable
elements,
in
the
same
manner
as
States,
regardless
of
whether
such
tribes
have
participated
as
members
of
a
visibility
transport
GCVTC
[
sic].
The
EPA
has
not
included
the
WGA s
recommended
rule
provision
in
today s
action
because
the
necessary
authority
for
tribal
organizationshas
already
been
provided
in
a
previ.
ous
EPA
rulemaking
.
FN133
The
EPA
does,
however,
agree
with
the
position
expressed
in
the
WGA
recommendation.
The
EPA
wishes
to
clarify
that
F
3
tribes
may
directly
implement
the
requirements
of
this
section
of
the
regional
haze
rule
in
the
same
manner
as
States.
The
Tribal
Authority
Rule
provides
for
this,
as
discussed
further
in
unit
V
of
today s
notice.
The
independence
of
tribes
means
that
a
tribal
visibility
program
is
not
dependent
on
strategies
selected
by
the
State
or
States
in
whch
the
tribe
is
located.
64
Fed.
Reg.
At
35756
(
emphasis
added).
Section
309(
d)(
12)
was
in
fact
included
in
the
final
rule,
notwithstanding
the
explanation
in
the
preimble
of
why
it
was
not.
In
any
case,
it
is
clear
that
EPA
interpreted
the
language
of
3
309(
d)(
12)
to
be
merely
redundant
to
the
provisions
of
the
TAR,
and
not
in
any
way
limiting
the
options
available
to
tribes
under
the
TAR.
Moreover,
elsewhere
in
the
preamble,
the
non
applicability
of
visibility
implementation
plan
deadlines
to
tribes
is
discussed
at
some
length,
concluding
with
the
following
paragraph:
In
order
to
encourage
tribes
to
develop
self
sufficient
programs,
the
TAR
provides
tribes
with
the
flexibilityof
submitting
programs
as
they
are
developed,
rather
than
in
accordance
with
statutory
deadlines.
27zis
means
that
tribes
that
choose
to
develop
programs,
where
necessavy
may
take
additional
time
to
submit
implementationplansfor
regional
haze
over
and
above
the
deadlines
in
the
TEA21
legislation
as
codfled
in
today
S
rule.
.
.
.
We
encourage
tribes
choosing
to
develop
implementation
plans
to
make
every
effort
to
submit
by
the
deadlines
to
ensure
that
the
plans
are
integrated
with
and
coordinated
with
regional
planning
efforts.
In
the
interim,
EPA
will
work
with
the
States
and
tribes
to
ensure
that
achlevement
of
reasonable
progress
is
not
delayed.
64
Fed.
Re?.
35714,35759,
Julv
1.
1999.
(
Emphasis
added).
Significantly,
the
discussion
makes
no
distinctionbetween
development
of
tribal
implementation
plans
under
RHR
55
308
and
309.
Also
significantly,
nowhere
in
the
quoted
passage
or
the
entire
discussion
of
tribal
implementation
of
the
RHR
is
any
mention
made
of
consequences
to
tribes
of
failing
to
submit
TIPs
by
the
state
deadlines.
The
integration
and
coordination
of
state
and
tribal
planning
efforts
is
cited
as
a
positive
incentive
for
early
development
of
visibility
TIPs,
but
nowhere
is
the
possibility
of
any
negative
consequences
discussed.
If
EPA
had
intended
the
state
309
deadline
to
serve
as
a
cut
off
point
for
tribal
implementation
of
8
309,
it
is
reasonable
to
expect
that
it
would
have
written
such
a
provision
into
the
rule
that
or
at
least
discussed
in
the
preamble
the
rationale
for
such
an
effect.
Taken
together,
EPA s
assurances
that
tribes
may
choose
between
5
308
and
$
309
independently
of
state
decisions,
and
that
tribes
where
necessary
may
take
additional
time
to
submit
implementation
plans,
create
a
strong
implication
that
tribes
may
submit
implementation
plans
under
0
309
after
the
state
implementation
plan
deadline
for
that
section.
c.
Loss
of
the
5
309
option
upon
failure
to
meet
the
2003
deadline
would
effectively
constitute
a
sanction
to
tribes
and
thus
run
F
4
T
I
counter
to
the
spirit
of
the
TAR.
In
explaining
the
rationale
for
not
subjecting
tribes
to
SIP
submittal
deadlines,
EPA
in
the
preamble
to
the
TAR
noted
among
other
things
that:
[
Slince
..
.
tribal
authority
for
establishing
CAA
programs
was
expressly
addressed
for
the
first
time
in
the
1990
CAA
Amendments,
in
comparison
to
states,
tribes
in
general
are
in
the
early
stages
of
developing
air
planning
and
implementation
expertise.
Accordingly,
EPA
determined
that
it
would
be
infeasible
and
inappropriate
to
subject
tribes
to
the
mandatory
submittal
deadlines
imposed
by
the
Act
on
states,
and
to
the
related
federal
oversight
mechanisms
in
the
Act
which
are
triggered
when
EPA
makes
a
finding
that
states
have
failed
to
meet
required
deadlines
or
acts
to
disapprove
a
plan
submittal.
63.
Fed.
Reg;.
at
7265.
The
federal
oversight
mechanism
referred
to
is
implementation
of
a
federal
implementation
plan
(
FIP)
pursuant
to
CAA
0
1lO(
c)(
l).
Id.(
providing
for
FIPs
within
2
years
of
state s
failure
to
submit
SIP
or
SIP
revision)
The
preamble
goes
on
to
explain
that
0
1lO(
c)(
1)
is
therefore
among
those
listed
in
the
TAR
as
inappropriate
for
application
to
tribes,
although
EP.
A
retains
its
obligation
to
promulgate
FIPs
in
Indian
country
as
necessary
and
appropriate.
Id.
Enforcement
of
a
FIP
against
a
state
is
commonly
perceived
as
a
sanction
against
the
state,
as
it
represents
an
assertion
of
federal
supremacy
over
considerations
of
state
sovereignty.
Furthermore,
CAA
110
provides
for
additional
sanctions
in
the
event
of
a
state s
failure
to
submit
a
complete
and
timely
SIP,
in
the
form
of
withheld
highway
funding
and
emission
offfset
requirements.
See
42
U.
S.
C.
6
7410(
m)
and
67509.
EPA
correctly
determined
that,
given
the
relative
inexperience
of
tribes
in
air
regulation,
and
the
recentness
of
Congressional
authorization
of
tribal
CAA
implementation,
it
is
inappropriate
to
subject
tribes
to
deadlines
and
sanctions.
For
similar
reasons,
and
for
the
reasons
related
to
future
uncertainty
discussed
in
part
LA.
1
above,
tribes
should
not
be
punished
for
failure
to1
meet
the
2003
deadline
by
losing
the
option
to
implement
0
309.
Therefore,
the
methodology
should
accommodate
post
2003
entry
into
the
market
by
tribes.
B.
Accommodation
of
the
Multiple
Purposes
of
the
Tribal
Set
Aside
Tribal
participants
in
the
WRAP
cited
several
potential
uses
for
the
tribal
set
aside,
including
retirement
for
the
benefit
of
the
environment,
use
to
attract
development,
and
sale
for
revenue.
The
allocation
methodology
should
provide
for
all
these
needs
to
some
degree.
Naturally,
there
is
a
tension
between
these
purposes,
given
the
fact
that
there
are
many
tribes
who
may
have
differing
priorities.
There
are
many
ways
of
striking
a
balance
between
uses,
of
which
the
proposed
methodology
is
but
one.
For
example,
the
proposed
methodology
would
utilize
the
allowances
for
revenue
until
needed
for
development
(
with
individual
tribes
able
to
retire
a
F
5
portion
at
their
discretion).
An
alternative
method
would
be
to
effectivelyretire
the
allowances
until
needed
for
development
or
sale.
The
former
method
is
put
forth
here
under
the
assumption
that
the
monetary
benefit
to
tribes
outweighs
the
marginal
environmental
benefit
of
retiring
this
small
portion
of
the
total
emissions.
C.
Flexibility
to
Allow
for
Changes
If
the
New
Source
Set
Aside
Is
Exhausted
or
in
Accordance
with
Market
Prices.
The
tribal
set
aside
is
designed
to
help
insure
equitable
treatment
for
tribal
economies
and
to
prevent
barriers
to
economic
development.
It
is
not
the
only
source
of
allowances
for
tribes,
as
tribal
sources
also
have
access
to
allowances
under
the
general
existing
and
new
source
provisions.
The
new
source
set
aside
is
intended
to
be
sufficient
to
cover
all
new
sources
in
the
region,
whether
they
are
tribal
or
non
tribal.
The
reallocation
concept
presented
here
is
based
on
the
assumption
that
the
new
source
set
aside
is
adequate.
However,
if
for
unanticipated
reasons
SO2
new
source
growth
exceeds
projections,
the
use
of
the
tribal
set
aside
should
be
subject
to
change.
Similarly,
the
methodology
should
be
flexible
to
allow
changes
in
strategy
based
upon
the
market
price
of
credits.
For
example,
if
credits
become
very
valuable,
tribes
who
have
retired
allowances
may
wish
to
reconsider
the
option
of
selling.
Provisions
for
flexibilitymust
be
consistent
with
the
general
allocation
methodology
of
the
program,
which
provides
certainty
in
allocations
for
5
year
increments.
D.
Maximization
of
Benefit
to
Tribes
in
the
Aggregate.
The
methodology
should
be
structured
so
that
the
maximum
benefit
is
gained
from
the
allowances,
and
they
are
not
so
distributed
as
to
be
of
no
practical
use
to
any
one
tribe.
For
this
reason,
a
simple
pro
rata
distribution
is
not
proposed.
That
would
result
in
approximately
95
tondyear
per
tribe,
not
quite
enough
to
construct
a
major
source
(
100
tpy).
It
is
felt
that
better
use
can
be
made
of
the
allowances
by
pooling
them
and
using
the
revenue
for
a
common
good,
with
the
pool
being
dipped
into
as
needed
for
individual
tribal
projects.
Again,
however,
the
calculus
may
change
according
to
according
to
market
prices
for
credits.
II
Proposed
Conceptual
Methodology
The
conceptual
framework
put
forth
here
for
comment
is
quite
simple.
Essentially,
it
consists
of
the
following:
(
1)
Initially
the
allowances
would
be
pooled
and
sold,
with
revenue
used
for
the
benefit
of
common
tribal
interests,
(
2)
Individual
tribes
could
draw
from
the
pool
for
the
purpose
of
(
A)
SO2
emitting
development
projects,
and
(
B)
retirement
of
allowances
for
the
environment.
The
allocation
scheme
would
be
subject
to
change
at
the
5
year
check
points
built
into
the
program,
in
response
to
changed
conditions.
These
concepts
are
described
in
more
detail
below:
1.
Unclaimed
allowances
administered
as
pool
for
shared
revenue
F
6
i
'
.,
..
I
This
provision
is
intended
to
insure
that
the
tribal
allowance
is
used
in
a
manner
which
will
provide
benefits
to
tribes,
regardless
of
whether
individual
tribes
have
decided
to
apply
for
an
allocation
of
allowances.
Upon
the
commencement
of
the
trading
program,
those
tribal
allowances
whch
have
not
been
allocated
to
individual
tribes
according
to
the
procedures
below
would
be
sold
on
the
open
market,
at
a
fair
market
price.
The
proceeds
would
be
transferred
to
a
trustee,
who
would
use
the
funds
for
a
purpose
determined
after
consultation
With
the
tribes
in
the
region.
The
use
to
which
funds
are
put
should
be
logically
grounded
in
the
rationale
for
creating
the
set
aside.
For
example,
they
could
be
used
to
fund
tribal
environmental
programs,
to
partially
compensate
for
the
fact
that
the
benefits
of
energy
and
industrial
development
have
not
been
proportional.
ly
shared
with
tribes.
This
could
be
accomplished
by
using
the
monies
to
supply
tribes
with
rnatching
funds
in
order
to
meet
federal
grant
requirements
(
e.
g.
under
sections
103
or
105
of
the
CIAA),
to
help
tribes
acquire
monitoring
or
other
equipment,
or
to
assist
tribes
in
establishing
tribal,
non
federal
programs.
Another
promising
idea
which
has
been
suggested
is
the
establishment
of
a
scholarship
fund
to
encourage
the
development
of
tribal
environmental
professionals.
There
are
several
fundamental
issues
to
be
resolved
regarded
the
pooled
approach,
including:
the
mechanism
by
whch
tribal
allocations
would
be
sold
on
the
market
(
e.
g.,
by
the
program
administrator)
and
the
identity
or
method
of
selecting
the
trustee
to
administer
revenues
fiom
sales.
2.
Allowances
distributed
to
individual
tribes
via
application
process
A
p~
imarypurpose
of
the
tribal
set
aside
is
to
ensure
that
barriers
to
development
on
tribal
land
are
not
created,
where
such
development
is
desired
by
tribes.
Many
tribal
participants
also
insisted
that
tribes
should
be
able
to
retire
credits,
at
their
discretion.
In
order
to
accomplish
these
objectives,
there
must
be
means
for
individual
tribes
to
acquire
a
quantity
of
credits
over
which
the
tribe
has
sole
control.
A
method
for
doing
this
is
proposed
below:
A.
Retirement
quota
Tribes
would
be
able
to
apply
for
a
quota
of
allowances
for
the
express
purpose
of
retiring
them.
The
#
quotacould
be
either
a
flat,
pro
rata
amount
for
every
federally
recognized
tribe
in
the
region,
(
e.
g.,
20,000
tpy/
211
tribes
=
94.8
tpy/
tribe),
or
it
could
be
adjusted
on
a
tribe
specific
basis,
such
as
tribal
population.
A
flat
amount
would
reflect
the
equality
of
all
federally
recognized
tribes
as
sovereign
domestic
nations,
while
a
population
based
allocation
would
perhaps
better
reflect
the
amount
of
development
a
tribe
is
willing
to
forego,
by
retiring
the
credits.
F
7
Some
questions
raised
by
this
provision
are
whether
tribes
that
retire
credits
should
be
excluded
from
receiving
benefits
from
the
revenue
generated
by
the
sale
of
the
remainder
of
credits,
and
whether,
tribes
who
retire
credits
would
be
able
to
pursue
SO2
emitting
development
outside
of
the
trading
program?
(
E.
g.,
under
RHR
308).
3.
Formula
for
allowances
to
tribal
projects
A
central
feature
of
the
tribal
allocation
scheme
is
the
methodology
for
allocating
allowances
to
tribes
for
the
purpose
of
energy
or
economic
development,
so
tribal
development
can
be
included
in
the
regional
cap
without
creating
an
extra
economic
burden
on
tribes.
This
use
is
supplemental
to
the
use
.
ofallowances
from
the
new
source
set
aside
which
is
available
for
any
new
sources
in
the
region,
whether
tribal
or
not.
Under
this
provision,
at
the
time
a
proposed
new
major
SO2
source
on
tribal
land
applies
for
applicable
permits
(
Prevention
of
Significant
Deterioration,
New
Source
Review,
Title
V,
etc.),
it
would
also
apply
for
a
share
of
the
tribal
allowances.
These
allowances
would
be
in
addition
to
the
allowances
the
source
would
receive
fiom
the
general
new
source
provisions,
and
would
comprise
an
additional
percentage
of
credits
needed
to
operate.
For
example,
the
source
would
receive
100%
of
credits
needed
to
operate
under
applicable
control
requirements
from
the
new
source
set
aside,
and
an
additional
10%
(
a
purely
hypothetical
number)
from
the
tribal
set
aside.
The
extra
allowances
could
not
be
used
to
circumvent
applicable
control
requirements
or
permit
conditions.
They
could
be
banked
according
to
the
general
banking
provisions
of
the
program
to
provide
the
source
with
additional
flexibility,
or
sold,
in
effect
creating
a
small
economic
subsidy
to
the
source,
in
order
to
encourage
its
location
on
tribal
land.
(
Of
course,
this
provision
would
only
be
utilized
when
a
tribe
desired
to
attract
development).
3.
New
distribution
Methodology
if
new
source
set
aside
exhausted
Under
the
WEB
provisions,
allowances
would
be
allocated
to
sources
for
5
year
periods,
in
order
to
provide
sufficient
certainty
for
fbture
planning.
This
periodic
system
of
allocations
affords
anopportunity
to
change
the
tribal
allocation
scheme
in
response
to
changed
conditions.
Specifically,
if
the
new
source
set
aside
is
exhausted,
use
of
the
tribal
set
aside
could
be
shifted
from
retirements
or
revenue
towards
tribal
new
source
allocations,
in
order
to
ensure
economic
barriers
are
not
created.
By
tying
decisions
to
change
the
tribal
methodology
to
the
five
year
cycle,
all
parties
would
know
how
many
tribal
credits
would
be
in
play
and
how
many
will
be
retired
for
each
five
year
period.
i
1
!
F
8
| epa | 2024-06-07T20:31:40.671415 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0076-0040/content.txt"
} |
EPA-HQ-OAR-2002-0076-0060 | Supporting & Related Material | "2002-04-02T05:00:00" | null | February
23,2001
MEMORANDUM
WESTERN
TO:
Staff
Council
GOVERNORS'
State
Environmental
Directors
'
~
,_..
.
li
Ix
;*'
,
,
ASSOCIATION
State
Air
Directors
LA&
*:
p:~
FROM:
Jim
Souby
Dirk
Kempthorne
SUBJECT:
Energy
and
Air
Quality
Issues
Governor
of
Idaho
Chairman
As
many
of
you
are
aware,
recent
events
related
to
energy
supply
problems
in
the
West
have
led
to
questions
regarding
the
impact
of
Jane
Dee
Hull
various
environmental
policies.
One
of
the
questions
that
has
come
up
is
Governor
of
Arizona
whether
or
not
the
sulfur
dioxide
(
S02)
emission
reduction
milestones
Vice
Chairman
recently
proposed
by
the
Western
Regional
Air
Partnership
(
WRAP)
will
present
unreasonable
obstacles
to
the
construction
of
new
coal
fired
power
plants
in
the
West.
These
concerns
were
highlighted
in
a
February
1
letter
to
the
Governors
from
the
Western
Regional
Council
(
WRC).
In
the
last
couple
of
weeks,
WGA
staff
participated
in
a
constructive
James
M.
Souby
meeting
with
members
of
WRC's
Energy
and
Clean
Air
Committees.
We
Executive
Director
have
also
completed
an
analysis
of
the
SO2
milestones
and
their
impact
on
the
construction
of
new
coal
fired
plants.
A
copy
of
this
analysis
is
attached.
The
conclusion
is
that
the
sulfur
dioxide
emission
reduction
milestones
Headquarters:
should
in
no
way
impede
the
construction
of
new
coal
fired
power
plants
15
15
Cleveland
Place
in
the
West
as
long
as
we
continue
to
make
progress
in
reducing
SO2
Suite
200
Denver,
Colorado
80202
5114
emissions
from
the
existing
units,
as
called
for
by
the
Governors
in
the
final
recommendations
of
the
Grand
Canyon
Visibility
Transport
303
623
9378
Commission
and
required
by
the
federal
regional
haze
rules.
Fax
303
534
7309
Washington,
D.
C.
Office:
Please
do
not
hesitate
to
contact
me
or
Patrick
Cummins
with
any
400
N.
Capitol
Street,
N.
W.
questions.
Suite
388
Washington,
D.
C.
20001
202
624
5402
:
ax
202
624
7707
www.
westgov.
org
February
22,200
1
MEMORANDUM
TO:
Jim
Souby,
Executive
Director
Western
Governors
Association
FROM:
Patrick
Cummins
Air
Quality
Program
Manager
SUBJECT:
Energy
and
Air
Quality
Issues
Concerns
about
meeting
increased
energy
demand
in
the
West
have
led
to
questions
about
the
Western
Regional
Air
Partnership s
(
WRAP)
Voluntary
Sulfur
Dioxide
Emissions
Reduction
Program
and
Backstop
Market
Trading
Program,
which
was
submitted
to
EPA
in
October
2000.
This
program
was
submitted
as
an
Annex
to
the
1996
final
report
of
the
Grand
Canyon
Visibility
Transport
Commission,
in
accordance
with
the
requirements
of
the
federal
regional
haze
rules.
The
specific
question
that
has
arisen
is
whether
the
sulfur
dioxide
emission
reduction
milestones
contained
in
the
Annex
will
prohibit
the
construction
of
new
coal
fired
power
plants
in
the
West.
I
have
conducted
an
analysis
of
this
question
and
the
results
are
presented
in
the
attached
Technical
Memorandum.
The
conclusions
of
the
analysis
are
as
follows:
0
With
an
SO2
emission
control
rate
of
between
77%
and
85%
on
existing
power
plants
subject
to
the
Best
Available
Retrofit
Technology
(
BART)
requirements
of
the
Clean
Air
Act,
it
is
possible
to
build
approximately
7,000
megawatts
of
new
coal
fired
gheration
at
any
time
between
now
and
2018
without
exceeding
the
milestones.
This
is
the
level
of
control
assumed
by
the
WRAP
in
the
Annex.
Recent
information
indicates
that
there
are
about
5,000
MW
of
potential
new
coal
fired
power
plants
under
discussion
in
the
nine
state
region
covered
by
the
milestones.
0
Based
on
discussions
with
representatives
of
the
coal
industry,
we
have
also
evaluated
a
scenario
where
the
total
SO2
control
level
at
existing
plants
is
increased
to
85%.
Under
this
scenario,
it
is
possible
to
build
11,000
megawatts
of
new
coal
fired
generation
between
now
and
2012,
and
another
8,000
megawatts
after
2012,
for
a
total
of
19,000
megawatts
without
exceeding
the
milestones.
This
analysis
suggests
that
the
sulfur
dioxide
emission
reduction
milestones
contained
in
the
Annex
should
in
no
way
impede
the
construction
of
new
coal
fired
power
plants
in
the
West
as
long
as
we
continue
to
make
progress
in
reducing
SO2
emissions
fiom
the
existing
units.
I
would
be
happy
to
answer
any
questions
or
provide
additional
information
on
this
topic.
I
can
be
reached
at
(
303)
623
5635
ext.
112
or
pcummins@
westgov.
org.
February
22,2001
TECHNICAL
MEMORANDUM
ANALYSIS
OF
NEW
COAL
FIRED
POWER
PLANTS
UNDER
THE
PROPOSED
SULFUR
DIOXIDE
EMISSION
REDUCTION
MILESTONES
FOR
THE
NINE
STATE
GRAND
CANYON
VISIBILITY
TRANSPORT
REGION
BACKGROUND
In
accordance
with
the
recommendations
of
the
Grand
Canyon
Visibility
Transport
Commission
and
the
requirements
of
EPA s
Regional
Haze
Rules,
the
Western
Regional
Air
Partnership
(
WRAP)
submitted
a
set
of
sulfur
dioxide
emission
reduction
milestones
to
EPA
in
October
2000.
EPA
will
go
through
a
formal
rule
making
process
this
year
to
incorporate
this
voluntary,
market
based
program
into
section
309
of
the
Regional
Haze
Rules.
Nine
Western
states
(
Oregon,
California,
Nevada,
Idaho,
Utah,
Wyoming,
Colorado,
New
Mexico,
and
Arizona)
have
the
option
of
satisfying
their
Best
Available
Retrofit
Technology
Requirements
(
BART)
for
sulfur
dioxide
under
the
Regional
Haze
Rules
by
participating
in
this
voluntary,
market
based
program,
which
was
prepared
as
an
Annex
to
the
original
report
of
the
Grand
Canyon
Commission.
These
states
may
also
choose
not
to
participate
in
the
program,
in
which
case
they
must
apply
BART
through
the
traditional
source
by
source
approach
for
regulating
industrial
source
emissions.
The
milestones
contained
in
the
Annex
cover
sources
of
SO2
with
emissions
of
more
than
100
tons
per
year.
Compliance
with
the
milestones
is
to
be
achieved
through
voluntary
emission
reductions,
with
a
backstop
market
trading
program
that
will
take
effect
if
any
of
the
milestones
are
exceeded.
The
purpose
of
this
analysis
is
to
estimate
the
amount
of
new
coal
fired
electric
generating
capacity
that
can
be
added
in
these
states
while
remaining
under
the
milestones.
SCENARIOS
Two
scenarios
have
been
evaluated
in
order
to
provide
a
range
of
estimates
for
the
amount
of
new
coal
fired
plants
that
could
be
built
while
remaining
under
the
milestones
(
see
attached
charts).
Scenario
1:
WRAP
Annex
Scenario
This
scenario
uses
the
assumptions
regarding
growth,
retirements,
and
control
levels
developed
by
the
WRAP SMarket
Trading
Forum
(
MTF).
Scenario
2:
Alternative
Scenario
This
scenario
assumes
a
higher
level
of
control
on
existing
plants
in
order
to
create
more
room
under
the
milestones
for
new
plants.
SCENARIO
1
:
WRAP
ANNEX
SCENARIO
Combined
Heat
and
Power
(
Co
Gen)
Facilities:
SO2
emissions
from
these
sources
are
projected
to
remain
constant
at
8,000
tons
per
year
through
2018.
Smelters:
SO2
emissions
from
these
sources
are
projected
to
remain
constant
at
48,000
tons
per
year
through
2018.
The
Annex
contains
provisions
to
automatically
increase
the
milestones
by
up
to
38,000
tons
in
the
event
that
two
currently
suspended
smelters
resume
operations.
Other
Sources:
This
category
includes
SO2
sources
such
as
refineries
and
cement
kilns.
Using
information
developed
by
the
Grand
Canyon
Commission,
the
analysis
conducted
by
the
WRAP
indicates
that
the
net
effect
of
growth
and
retirements
in
this
category
will
lead
to
a
slight
decrease
in
emissions
between
now
and
2018
(
from
162,000
tons
in
1998to
141,000
tons
in
2018).
In
addition,
there
are
several
facilities
in
this
category
that
are
subject
to
the
BART
requirements.
The
additional
reductions
from
these
BART
eligible
sources
is
estimated
at
16,000
tons
per
year,
resulting
in
a
final
emissions
estimate
in
2018
of
125,000
tons
per
year.
Utilities:
SO2
emissions
from
existing
coal
fired
power
plants
were
projected
based
on
an
85%
nameplate
capacity
factor,
which
represents
a
12%
increase
from
1999
generation
levels
and
a
reasonable
upper
bound
for
the
annual
generating
capacity
of
the
existing
system.
Current
controls
and
already
committed
future
controls
were
also
applied.
This
resulted
in
an
emissions
estimate
of
42
1,500
tons
per
year
in
2018.
Based
on
the
BART
control
levels
agreed
to
in
the
Market
Trading
Forum,
utility
emissions
are
assumed
to
decrease
by
30,000
tons
in
2013
and
by
an
additional
117,000tons
by
2018
for
a
final
emissions
estimate
in
2018
of
275,000
tons
per
year.
This
analysis
assumes
no
retirements
of
existing
plants.
(
See
attached
table.)
New
Coal:
Emissions
from
new
coal
plants
were
projected
assuming
that
the
Best
Available
Control
Technology
requirements
which
apply
will
result
in
90%
control
of
SO2
emissions.
Based
on
feedstock
that
contains
0.9
#/
mmbtu
of
sulfur,
the
emission
rate
for
new
plants
was
calculated
at
0.09
#/
mmbtu.
Using
a
heat
rate
of
9500
btu/
kwh
and
an
annual
capacity
utilization
rate
of
90%
yields
an
emission
rate
of
3.4
tons/
MW/
year
for
new
coal
plants.
Result
As
shown
in
the
attached
graph
and
table,
this
scenario
indicates
that
it
is
possible
to
build
approximately
7,000
megawatts
of
new
coal
fired
generation
at
any
time
between
now
and
2018
without
exceeding
the
milestones.
This
represents
a
24%
increase
over
current
levels
of
coal
fired
generating
capacity
in
the
nine
state
region.
SCENARIO
2:
ALTERNATIVE
SCENARIO
Based
on
discussions
with
representatives
of
the
coal
industry,
an
alternative
scenario
was
evaluated
modifyingjust
two
of
the
assumptions
used
in
the
WRAP
Annex
scenario
described
above.
The
two
assumptions
used
in
this
scenario
are:
0
No
reductions
from
1998
SO2
emission
levels
from
the
other
source
category,
including
no
additional
controls
on
the
BART
eligible
sources
in
this
category.
This
has
the
effect
of
increasing
emissions
in
2018
by
37,000
tons
compared
to
the
WRAP
&
mex
scenario.
Assumes
an
overall
SO2
emission
control
rate
of
85%
on
existing
coal
fired
power
plants.
This
has
the
effect
of
reducing
emissions
in
2018
by
78,000
tons
compared
to
the
WRAP
Annex
scenario.
This
level
of
reduction
from
the
existing
plants
could
be
achieved
through
some
combination
of
increased
control
at
the
BART
eligible
plants
and
adding
controls
to
the
currently
uncontrolled
plants
that
are
not
subject
to
BART.
0
Result
As
shown
in
the
attached
graph
and
table,
this
scenario
indicates
that
it
is
possible
to
build
1
1,000
megawatts
of
new
coal
fired
generation
between
now
and
2012,
and
another
8,000
megawatts
after
2012,
for
a
total
of
19,000
megawatts
without
exceeding
the
milestones.
This
represents
a
65%
increase
over
current
levels
of
coal
fired
generating
capacity
in
the
nine
state
region.
| epa | 2024-06-07T20:31:40.677390 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0076-0060/content.txt"
} |
EPA-HQ-OAR-2002-0084-0001 | Rule | "2002-12-30T05:00:00" | National Emission Standards for Hazardous Air Pollutants for Secondary Aluminum Production; Final Rule; Amendments | Monday,
December
30,
2002
Part
IV
Environmental
Protection
Agency
40
CFR
Part
63
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Secondary
Aluminum
Production;
Final
Rule
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2002
/
Rules
and
Regulations
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
63
[
FRL
7430
6]
RIN
2060
AE77
National
Emission
Standards
for
Hazardous
Air
Pollutants
for
Secondary
Aluminum
Production
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Final
rule;
amendments.
SUMMARY:
On
March
23,
2000,
the
EPA
issued
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
secondary
aluminum
production
facilities
under
section
112
of
the
Clean
Air
Act
(
CAA).
This
action
amends
the
applicability
provisions
for
aluminum
die
casters,
foundries,
and
extruders.
The
amendments
also
add
new
provisions
governing
control
of
commonly
ducted
units;
revise
the
procedures
for
adoption
of
operation,
maintenance,
and
monitoring
plans;
revise
the
criteria
concerning
testing
of
representative
emission
units;
revise
the
standard
for
unvented
in
line
flux
boxes;
and
clarify
the
control
requirements
for
sidewell
furnaces.
These
changes
are
being
made
pursuant
to
settlement
agreements
in
two
cases
seeking
judicial
review
of
the
NESHAP
for
secondary
aluminum
production.
A
separate
rule
to
clarify
compliance
dates
and
defer
certain
early
compliance
obligations
which
might
have
otherwise
come
due
before
completion
of
this
rulemaking
was
published
on
September
24,
2002.
EFFECTIVE
DATE:
December
30,
2002.
ADDRESSES:
Docket
A
2002
05,
containing
supporting
information
used
in
developing
these
final
rule
amendments,
is
available
for
public
inspection
and
copying
between
8:
30
a.
m.
to
5:
30
p.
m.,
Monday
through
Friday,
excluding
Federal
holidays,
at
the
following
address:
U.
S.
EPA,
Air
and
Radiation
Docket
and
Information
Center,
Room
B
108,
1301
Constitution
Avenue,
NW.,
Washington,
DC
20460.
FOR
FURTHER
INFORMATION
CONTACT:
Mr.
John
Schaefer,
U.
S.
EPA,
Minerals
and
Inorganic
Chemicals
Group,
Emission
Standards
Division
(
C504
05),
Office
of
Air
Quality
Planning
and
Standards,
Research
Triangle
Park,
NC
27711,
telephone
number
(
919)
541
0296,
electronic
mail
address,
schaefer.
john@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Regulated
Entities.
The
amendments
change
the
applicability
provisions
of
the
NESHAP
for
three
types
of
facilities:
aluminum
extruded
product
manufacturing
facilities
(
NAICS
331316),
aluminum
die
casting
facilities
(
NAICS
331521),
and
aluminum
foundry
facilities
(
NAICS
331524).
Consequently,
categories
and
entities
potentially
regulated
by
this
action
include:
Category
NAICS*
Examples
of
regulated
entities
Industry
.....................................................
331314
Secondary
smelting
and
alloying
of
aluminum
facilities.
Secondary
aluminum
production
facility
affected
sources
that
are
collocated
at:
331312
Primary
aluminum
production
facilities.
331315
Aluminum
sheet,
plate,
and
foil
manufacturing
facilities.
331316
Aluminum
extruded
product
manufacturing
facilities.
331319
Other
aluminum
rolling
and
drawing
facilities.
331521
Aluminum
die
casting
facilities.
331524
Aluminum
foundry
facilities.
*
North
American
Information
Classification
System.
This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
your
facility
is
regulated
by
this
action,
you
should
examine
the
applicability
criteria
in
§
63.1500
of
the
final
rule.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Docket.
We
have
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
A
2002
06
and
EDocket
ID
No.
OAR
2002
0084.
The
official
public
docket
consists
of
the
documents
specifically
referenced
in
this
action,
any
public
comments
received,
and
other
information
related
to
this
action.
Although
a
part
of
the
official
docket,
the
public
docket
does
not
include
Confidential
Business
Information
or
other
information
whose
disclosure
is
restricted
by
statute.
The
official
public
docket
is
the
collection
of
materials
that
is
available
for
public
viewing
at
the
Air
Docket
in
the
EPA
Docket
Center
(
EPA/
DC),
EPA
West,
Room
B102,
1301
Constitution
Avenue,
NW,
Washington,
DC.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
1744,
and
the
telephone
number
for
the
Air
Docket
is
(
202)
566
1742.
Electronic
Docket
Access.
You
may
access
the
final
rule
electronically
through
the
EPA
Internet
under
the
``
Federal
Register''
listings
at
http://
www.
epa.
gov/
fedrgstr/.
An
electronic
version
of
the
public
docket
is
available
through
EPA's
electronic
public
docket
and
comment
system,
EPA
Dockets.
You
may
use
EPA
Dockets
at
http://
www.
epa.
gov/
edocket/
to
view
public
comments,
access
the
index
listing
of
the
contents
of
the
official
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Although
not
all
docket
materials
may
be
available
electronically,
you
may
still
access
any
of
the
publicly
available
docket
materials
through
the
docket
facility
in
the
above
paragraph
entitled
``
Docket.''
Once
in
the
system,
select
``
search,''
then
key
in
the
appropriate
docket
identification
number.
Worldwide
Web
(
WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
today's
amendments
will
also
be
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature,
a
copy
of
these
actions
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
rules
or
promulgated
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(
919)
541
5384.
Judicial
Review.
Under
section
307(
b)(
1)
of
the
CAA,
judicial
review
of
these
final
rule
amendments
is
available
only
by
filing
a
petition
for
review
in
the
U.
S.
Court
of
Appeals
for
the
District
of
Columbia
Circuit
by
February
28,
2003.
Under
section
307(
d)(
7)(
B)
of
the
CAA,
only
an
objection
to
these
final
rule
amendments
that
was
raised
with
reasonable
specificity
during
the
period
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30,
2002
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and
Regulations
for
public
comment
can
be
raised
during
judicial
review.
Moreover,
under
section
307(
b)(
2)
of
the
CAA,
the
requirements
established
by
these
final
rule
amendments
may
not
be
challenged
separately
in
any
civil
or
criminal
proceedings
brought
by
the
EPA
to
enforce
these
requirements.
Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:
I.
Background
II.
Summary
of
the
Final
Amendments
A.
How
Are
We
Amending
the
Applicability
provisions?
B.
What
Amendments
Are
We
Making
Concerning
Control
of
Commonly
Ducted
Units?
C.
How
Are
We
Amending
the
Procedures
for
Adoption
of
an
Operation,
Maintenance,
and
Monitoring
Plan?
D.
How
Are
We
Amending
the
Provisions
Concerning
Testing
of
Representative
Emission
Units?
E.
How
Are
We
Amending
the
Standards
for
Unvented
In
Line
Flux
Boxes?
F.
How
Are
We
Clarifying
the
Control
Requirements
for
Sidewell
Furnaces?
G.
What
Other
Amendments
Are
We
Making?
III.
Response
to
Comments
on
Amendments
to
the
NESHAP
for
Secondary
Aluminum
Production
IV.
Statutory
and
Executive
Order
Reviews
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Paperwork
Reduction
Act
C.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
et
seq.
D.
Unfunded
Mandates
Reform
Act
of
1995
E.
Executive
Order
13132,
Federalism
F.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
G.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
H.
Executive
Order
13211,
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
I.
National
Technology
Transfer
and
Advancement
Act
J.
Congressional
Review
Act
I.
Background
On
March
23,
2000
(
63
FR
15690),
we
promulgated
the
NESHAP
for
secondary
aluminum
production
(
40
CFR
part
63,
subpart
RRR).
Those
standards
were
established
under
the
authority
of
section
112(
d)
of
the
CAA
to
reduce
emissions
of
hazardous
air
pollutants
(
HAP)
from
major
and
area
sources.
After
promulgation
of
the
NESHAP
for
secondary
aluminum
production,
two
petitions
for
judicial
review
of
the
standards
were
filed
in
the
D.
C.
Circuit
Court
of
Appeals.
The
first
of
these
petitions
was
filed
by
the
American
Foundrymen's
Society,
the
North
American
Die
Casting
Association,
and
the
Non
Ferrous
Founders'
Society
(
American
Foundrymen's
Society
et
al.
v.
U.
S.
EPA,
Civ.
No
00
1208
(
D.
C.
Cir.)).
A
second
petition
for
judicial
review
was
filed
by
the
Aluminum
Association
(
The
Aluminum
Association
v.
U.
S.
EPA,
No.
00
1211
(
D.
C.
Cir.)).
There
was
no
significant
overlap
in
the
issues
presented
by
the
two
petitions,
and
the
cases
have
never
been
consolidated.
However,
we
did
thereafter
enter
into
separate
settlement
discussions
with
the
petitioners
in
each
case.
The
Foundrymen's
case
presented
issues
concerning
the
applicability
of
subpart
RRR
to
aluminum
die
casters
and
aluminum
foundries
which
were
considered
during
the
initial
rulemaking
development.
Because
aluminum
die
casters
and
foundries
sometimes
conduct
the
same
type
of
operations
as
other
secondary
aluminum
producers,
we
originally
intended
to
apply
the
standards
to
these
facilities,
but
only
in
those
instances
where
they
conduct
such
operations.
However,
representatives
of
the
affected
facilities
argued
that
they
should
not
be
considered
to
be
secondary
aluminum
producers
and
should
be
wholly
exempt
from
the
NESHAP.
During
the
rulemaking
development,
we
decided
to
permit
die
casters
and
foundries
to
melt
contaminated
internal
scrap
without
being
considered
to
be
secondary
aluminum
producers,
but
their
representatives
insisted
that
too
many
facilities
would
still
be
subject
to
the
NESHAP.
At
the
time
of
promulgation
of
the
standards,
in
response
to
a
request
by
the
die
casters
and
foundries,
we
announced
we
would
withdraw
the
standards
as
applied
to
die
casters
and
foundries
and
develop
separate
maximum
achievable
control
technology
(
MACT)
standards
for
these
facilities.
After
the
Foundrymen's
case
was
filed,
we
negotiated
an
initial
settlement
agreement
in
that
case
which
established
a
process
to
effectuate
our
commitment
to
develop
new
MACT
standards.
In
that
first
settlement,
EPA
agreed
that
it
would
stay
the
current
standards
for
these
facilities,
collect
comprehensive
data
to
support
alternate
standards,
and
promulgate
alternate
standards.
We
then
published
a
proposal
to
stay
the
standards
for
these
facilities
(
65
FR
55491,
September
14,
2000)
and
an
advance
notice
of
proposed
rulemaking
(
ANPR)
announcing
new
standards
for
these
facilities
(
65
FR
55489,
September
14,
2000).
During
the
subsequent
process
of
preparing
for
information
collection,
the
petitioners
concluded
that
the
existing
standards
were
not
as
sweeping
in
applicability
as
they
had
feared,
and
the
parties
then
agreed
to
explore
an
alternate
approach
to
settlement
based
on
clarifications
of
the
current
standards.
We
subsequently
reached
agreement
with
the
Foundrymen's
petitioners
on
a
new
settlement
which
entirely
supplanted
the
prior
settlement.
Accordingly,
we
published
a
notice
withdrawing
the
proposed
stay
of
the
existing
standards
for
aluminum
die
casters
and
foundries,
and
announcing
that
we
would
take
no
further
action
on
new
standards
for
those
facilities
(
67
FR
41138,
June
14,
2002).
In
the
new
settlement,
we
agreed
to
propose
some
changes
in
the
applicability
provisions
of
the
current
standards
concerning
aluminum
die
casters
and
foundries.
These
changes
included
permitting
customer
returns
without
paints
or
solid
coatings
to
be
treated
like
internal
scrap,
and
permitting
facilities
operated
by
the
same
company
at
different
locations
to
be
aggregated
for
purposes
of
determining
what
is
internal
scrap.
These
revisions
of
the
applicability
criteria
were
proposed
on
June
14,
2002
(
67
FR
41125)
and
are
being
adopted
in
today's
final
rule.
In
the
Foundrymen's
settlement,
we
also
agreed
to
defer
the
compliance
date
for
new
sources
constructed
or
reconstructed
at
existing
aluminum
die
casters,
foundries,
and
extruders
until
the
compliance
date
for
existing
sources,
so
that
the
rulemaking
on
general
applicability
issues
could
be
completed
first.
We
took
final
action
concerning
that
element
of
the
Foundrymen's
settlement
in
a
final
rule
published
on
September
24,
2002
(
67
FR
59787).
In
entirely
separate
discussions,
we
also
agreed
on
a
settlement
of
the
Aluminum
Association
case.
That
settlement
required
that
we
propose
a
number
of
substantive
clarifications
and
revisions
of
the
standards,
which
we
are
also
adopting
in
today's
final
rule.
The
Aluminum
Association
settlement
also
required
that
we
clarify
and
simplify
the
compliance
dates
for
the
standards,
and
defer
certain
early
compliance
obligations
which
might
otherwise
come
due
during
the
rulemaking
process.
We
took
final
action
concerning
those
compliance
issues
in
the
final
rule
published
on
September
24,
2002
(
67
FR
59787).
II.
Summary
of
the
Final
Amendments
A.
How
Are
We
Amending
the
Applicability
Provisions?
We
originally
intended
to
regulate
aluminum
die
casting
facilities,
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30,
2002
/
Rules
and
Regulations
aluminum
foundries,
and
aluminum
extruders
under
subpart
RRR
only
when
they
engage
in
the
same
types
of
operations
as
other
secondary
aluminum
producers.
We
decided
during
rulemaking
development
that
such
facilities
should
be
permitted
to
melt
their
own
internally
generated
scrap
without
being
automatically
treated
the
same
as
secondary
aluminum
producers,
who
typically
process
contaminated
aluminum
scrap
obtained
from
other
sources.
Thus,
§
63.1500(
d)
in
the
current
standards
exempts
such
facilities
if:
The
facility
does
not
melt
any
materials
other
than
clean
charge
and
materials
generated
within
the
facility;
and
The
facility
does
not
operate
a
thermal
chip
dryer,
sweat
furnace,
or
scrap
dryer/
delacquering
kiln/
decoating
kiln.
However,
it
became
apparent
during
discussions
with
representatives
of
these
facilities
that
some
aluminum
die
casting
facilities
that
do
not
otherwise
engage
in
secondary
aluminum
operations
might
fall
within
the
rule
solely
because
they
melt
certain
materials
which
do
not
fit
clearly
within
the
phrase
``
materials
generated
within
the
facility.''
In
particular,
some
facilities
routinely
have
defective
or
incorrect
aluminum
castings
returned
by
customers
and
then
remelt
them.
In
addition,
some
companies
conduct
operations
at
multiple
locations
and
may
melt
scrap
initially
generated
at
one
location
at
a
different
location.
To
address
these
issues,
the
amendments
contain
new
applicability
language
which
permits
aluminum
die
casters,
foundries,
and
extruders
to
melt
customer
returns
which
contain
no
paint
or
other
solid
coatings
without
thereby
becoming
subject
to
the
standards.
The
amendments
also
include
a
new
definition
of
internal
scrap
which
includes
all
scrap
originating
from
aluminum
castings
or
extrusions
that
remains
at
all
times
within
the
control
of
the
company
that
produced
the
castings
or
extrusions.
We
do
not
regard
either
of
these
changes
in
the
applicability
language
as
materially
altering
our
original
intent
to
only
cover
those
aluminum
die
casters,
foundries,
and
extruders
who
conduct
secondary
aluminum
operations.
Under
the
new
language
we
are
adopting,
customer
returns
would
not
qualify
if
they
have
been
painted
or
are
contaminated
with
other
solid
coatings
because
these
castings
would
normally
require
prior
cleaning
to
avoid
excess
emissions.
Moreover,
scrap
obtained
from
an
external
source
does
not
qualify
unless
it
fits
within
the
definition
of
clean
charge.
The
amendments
also
change
the
existing
definitions
of
``
secondary
aluminum
production
facility,''
``
clean
charge,''
``
internal
runaround''
(
now
called
``
runaround
scrap''),
and
``
thermal
chip
dryer,''
and
add
new
definitions
of
``
customer
returns''
and
``
internal
scrap.''
In
the
aggregate,
these
revisions
clarify
the
circumstances
when
aluminum
die
casters,
foundries,
and
extruders
are
considered
to
be
secondary
aluminum
production
facilities
and,
thus,
within
the
applicability
of
the
rule.
We
are
also
adding
a
new
section
to
the
general
applicability
provisions
which
permits
aluminum
die
casters,
foundries,
and
extruders
which
are
area
sources
to
operate
thermal
chip
dryers
subject
to
the
requirements
of
the
rule
without
automatically
subjecting
their
furnace
operations
to
the
rule.
We
are
making
this
change
to
eliminate
an
incentive
which
might
exist
for
small
facilities,
which
are
otherwise
outside
the
applicability
of
the
rule,
to
discontinue
their
use
of
thermal
chip
dryers.
As
long
as
such
chip
dryers
are
operated
in
conformity
with
the
rule,
we
think
their
use
will
promote
safety
and
lower
emissions
at
some
small
operations.
We
are
mindful
that
some
may
question
why
contaminated
internal
scrap
generated
by
aluminum
die
casters,
foundries,
and
extruders
should
be
treated
differently
than
external
scrap
with
similar
contamination
levels
which
is
processed
by
the
secondary
aluminum
industry.
We
stress
that
the
decision
we
made
during
the
original
secondary
aluminum
rulemaking
process
to
make
this
distinction
was
based
on
the
qualitative
differences
in
the
operations
being
undertaken
by
the
facilities
in
question,
rather
than
on
any
conclusions
regarding
the
likely
magnitude
of
emissions
from
such
operations.
Moreover,
we
think
that
the
additional
revisions
and
clarifications
of
applicability
for
aluminum
die
casters,
foundries,
and
extruders
which
we
have
made
are
reasonable
clarifications
and
fully
consistent
with
that
original
decision.
B.
What
Amendments
Are
We
Making
Concerning
Control
of
Commonly
Ducted
Units?
The
current
rule
permits
secondary
aluminum
producers
to
combine
existing
group
1
furnaces
and
in
line
fluxers
within
a
particular
facility
in
a
``
secondary
aluminum
processing
unit''
or
SAPU.
The
facility
can
then
demonstrate
compliance
by
determining
the
permissible
emissions
for
the
entire
SAPU
and
then
controlling
emissions
for
the
SAPU
to
that
level.
This
broader
definition
of
the
affected
source
which
must
be
controlled
gives
a
secondary
aluminum
production
facility
added
flexibility
in
fashioning
the
most
costeffective
control
strategies
which
will
meet
the
standards.
The
existing
rule
also
permits
new
group
1
furnaces
and
new
in
line
fluxers
to
be
included
in
a
new
SAPU.
However,
it
does
not
afford
a
facility
the
latitude
to
combine
new
and
existing
sources
in
the
same
SAPU.
This
is
because
the
respective
standards
for
existing
sources
and
new
sources
are
separate
legal
requirements,
and
we
construe
the
CAA
to
require
that
standards
be
separately
applied
to
all
affected
units.
Because
the
standards
for
an
existing
SAPU
and
the
standards
for
a
new
SAPU
happen
to
be
identical
in
this
instance,
the
legal
constraints
on
combining
existing
emission
units
with
new
emission
units
have
been
understandably
frustrating
to
some
facilities.
Moreover,
in
some
facilities
it
may
make
the
most
sense
from
an
engineering
perspective
to
manifold
emissions
from
units
which
are
subject
to
differing
standards
to
the
same
emission
control
device.
In
order
to
help
facilities
meet
the
standards
in
the
most
efficient
and
cost
effective
manner,
we
are
adding
additional
language
pertaining
to
commonly
ducted
units.
The
new
language
reflects
two
different
approaches
to
this
problem.
A
facility
subject
to
the
standards
may
use
either
approach
or
both
approaches
if
it
wishes.
First,
the
amendments
add
a
new
paragraph
to
§
63.1505(
k)
for
SAPU.
The
new
paragraph
(
k)(
6)
allows
the
owner
or
operator
to
redesignate
any
existing
group
1
furnace
or
in
line
fluxer
at
a
secondary
aluminum
processing
facility
as
a
new
emission
unit.
Any
redesignated
emission
unit
may
then
be
included
in
a
new
SAPU
at
that
facility.
Any
such
redesignation
(
which
requires
prior
approval
of
the
responsible
permitting
authority)
applies
only
under
subpart
RRR
and
is
irreversible.
Second,
we
are
also
adding
new
language
which
clarifies
the
procedures
by
which
units
which
are
subject
to
differing
standards
but
are
manifolded
to
the
same
control
device
can
demonstrate
compliance.
We
believe
that
this
new
language
is
not
required
to
permit
this
type
of
combined
compliance
demonstration,
but
we
think
it
will
give
useful
additional
guidance
to
permitting
authorities
in
establishing
sound
and
defensible
procedures
for
documenting
compliance
when
units
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30,
2002
/
Rules
and
Regulations
are
commonly
ducted
but
subject
to
separate
standards.
We
are
adding
two
new
paragraphs
to
§
63.1511
pertaining
to
compliance
demonstrations
for
commonly
ducted
units.
The
first
of
these
paragraphs
simply
confirms
other
provisions
of
the
rule
which
provide
that
aggregate
emissions
can
be
measured
to
demonstrate
compliance
for
all
emission
units
within
a
SAPU.
The
second
new
paragraph
covers
those
situations
where
commonlyducted
units
are
not
within
a
single
existing
or
new
SAPU.
In
this
instance,
the
following
criteria
apply:
Testing
must
be
designed
to
verify
that
each
affected
source
or
emission
unit
individually
satisfies
all
applicable
emission
requirements.
Emissions
must
be
tested
at
the
outlet
of
each
individual
affected
source
or
emission
unit
while
it
is
operating
under
the
highest
load
or
capacity
reasonably
expected
to
occur,
prior
to
the
point
that
the
emissions
are
combined
with
those
from
other
affected
sources
or
emission
units.
Combined
emissions
for
the
affected
sources
and
emission
units
must
be
tested
at
the
outlet
of
the
control
device
while
they
are
operating
simultaneously
under
the
highest
load
or
capacity
reasonably
expected
to
occur.
When
determining
compliance
for
a
commonly
ducted
unit,
emissions
of
a
particular
pollutant
from
the
individual
unit
are
presumed
to
be
controlled
by
the
same
percentage
as
total
emissions
of
that
pollutant
from
all
commonlyducted
units.
C.
How
Are
We
Amending
the
Procedures
for
Adoption
of
an
Operation,
Maintenance,
and
Monitoring
Plan?
In
the
final
rule
amendments
published
on
September
24,
2002
(
67
FR
59787),
we
clarified
the
timing
of
submission
of
an
operation,
maintenance,
and
monitoring
(
OM&
M)
plan
to
the
permitting
authority,
which
is
ambiguous
in
the
rule
as
initially
promulgated
on
March
23,
2000.
In
this
action,
we
are
clarifying
the
procedures
by
which
a
facility
submits
an
OM&
M
plan
to
the
permitting
authority
and
by
which
the
permitting
authority
can
require
any
necessary
revisions
of
the
plan.
Section
63.1505(
k)
of
the
existing
rule
refers
to
approval
of
an
OM&
M
plan
by
the
permitting
authority,
and
the
necessary
elements
of
an
OM&
M
plan
are
described
in
§
63.1510(
b),
but
the
procedures
for
submission
and
approval
of
the
plan
are
not
specified.
We
are
amending
the
existing
rule
to
correct
that
omission.
Under
the
amendments,
the
facility
is
required
to
certify
that
the
OM&
M
plan
it
is
submitting
complies
with
all
requirements
of
the
standards
and
to
comply
with
the
OM&
M
plan
as
submitted
to
the
permitting
authority,
unless
and
until
the
plan
is
revised.
If
the
permitting
authority
determines
that
any
revisions
of
the
plan
are
necessary
to
satisfy
the
requirements
of
the
standards,
the
facility
is
required
to
promptly
make
all
necessary
revisions
and
resubmit
the
revised
plan.
If
the
facility
itself
determines
that
revisions
of
the
OM&
M
plan
are
necessary,
such
revisions
will
not
become
effective
until
the
owner
or
operator
submits
a
description
of
the
changes
and
a
revised
plan
incorporating
them
to
the
permitting
authority.
These
same
general
procedures
also
apply
to
the
site
specific
monitoring
plan,
which
is
one
element
of
the
OM&
M
plan.
D.
How
Are
We
Amending
the
Provisions
Concerning
Testing
of
Representative
Emission
Units?
Section
63.1511(
f)
of
the
existing
rule
establishes
a
procedure
which
permits
a
secondary
aluminum
production
facility
to
test
a
representative
group
1
furnace
or
in
line
flux
box
in
order
to
determine
the
emission
rate
for
other
units
of
the
same
type
at
that
facility.
We
are
clarifying
the
criteria
for
demonstrating
compliance
by
testing
of
representative
emission
units.
In
particular,
the
existing
rule
provides
that
the
emission
unit
being
tested
must
use
``
identical
feed/
charge
and
flux
materials
in
the
same
proportions''
as
those
emission
units
it
represents.
Industry
representatives
have
expressed
concern
that
this
language
could
be
given
an
unduly
restrictive
construction.
To
clarify
our
original
intent,
we
are
amending
the
criteria
to
require
``
feed
materials
and
charge
rates
which
are
comparable''
and
``
the
same
type
of
flux
materials
in
the
same
proportions''
as
the
emission
units
the
tested
unit
represents.
E.
How
Are
We
Amending
the
Standards
for
Unvented
In
Line
Flux
Boxes?
The
existing
rule
requires
that
all
inline
flux
boxes
meet
the
same
emission
standards
and
be
tested
in
the
same
manner.
Industry
representatives
have
argued
that
the
testing
procedures
in
the
rule
are
not
practicable
for
in
line
flux
boxes
which
are
unvented
(
units
which
have
no
ventilation
ductwork
manifolded
to
an
outlet
or
emission
control
device).
Documenting
compliance
with
the
particulate
matter
(
PM)
standard
for
such
units
might
require
construction
of
a
temporary
enclosure
around
the
unit
to
capture
and
measure
emissions.
Industry
representatives
have
also
argued
that
the
emissions
of
hydrogen
chloride
(
HCl)
and
PM
from
such
units
are
intrinsically
low,
but
we
believe
it
is
quite
possible
for
the
HCl
emissions
from
such
units
to
exceed
the
applicable
standards.
The
existing
rule
provides
a
procedure
by
which
a
facility
can
demonstrate
compliance
for
HCl
by
limiting
its
use
of
reactive
chlorine
flux
and
then
assuming
that
all
chlorine
used
is
emitted
as
HCl.
However,
because
of
the
greater
complexity
of
the
reactions
which
generate
PM
emissions,
there
is
no
analogous
procedure
for
PM.
While
we
do
not
agree
with
the
industry
that
all
emissions
from
unvented
in
line
flux
boxes
are
intrinsically
low,
we
do
agree
that
the
physical
characteristics
of
these
units
and
the
nature
of
the
reactions
that
generate
PM
mean
that
we
can
reliably
conclude
that
an
unvented
unit
which
demonstrates
compliance
with
the
emission
standards
for
HCl
by
limiting
reactive
chlorine
flux
will
also
be
in
compliance
with
the
emission
standards
for
PM.
Therefore,
we
are
adding
new
language
to
§
63.1512(
h)
which
permits
a
facility
with
an
unvented
in
line
flux
box,
which
elects
to
demonstrate
compliance
with
the
emission
standards
for
HCl
by
limiting
use
of
reactive
chlorine
flux,
to
infer
compliance
with
the
emission
standards
for
PM
as
well.
This
gives
facilities
an
alternative
to
testing
of
actual
emissions,
which
could
require
costly
construction
of
an
enclosure
around
the
unit
or
other
engineering
modifications.
If
a
facility
infers
compliance
with
the
PM
standard
in
this
manner,
the
facility
is
also
required
to
use
the
maximum
permissible
PM
emission
rate
for
the
flux
box
when
determining
the
total
emissions
for
any
secondary
aluminum
processing
unit
which
includes
the
flux
box.
F.
How
Are
We
Clarifying
the
Control
Requirements
for
Sidewell
Furnaces?
Industry
representatives
have
pointed
out
that
§
63.1506(
m)(
6)
includes
language
that
could
require
installation
of
an
additional
control
device
on
sidewell
furnaces
whenever
the
level
of
molten
metal
is
permitted
to
fall
below
the
passage
between
the
sidewell
and
the
hearth,
or
reactive
flux
is
added
in
the
hearth.
While
we
believe
that
a
control
device
will
sometimes
be
necessary
in
these
circumstances,
this
result
was
not
our
intent.
As
indicated
in
the
preamble
to
our
original
proposal,
we
believe
that
there
is
a
potential
for
additional
emissions
if
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/
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No.
250
/
Monday,
December
30,
2002
/
Rules
and
Regulations
the
level
of
molten
metal
is
permitted
to
fall
below
the
top
of
the
passage
between
the
sidewell
and
the
hearth,
or
if
reactive
flux
is
added
in
the
hearth.
Therefore,
if
these
events
occur,
the
emissions
from
both
the
sidewell
and
the
hearth
must
be
captured
and
tested
in
order
to
demonstrate
compliance
with
the
applicable
emission
standards.
If
the
emission
tests
show
that
a
control
device
is
necessary
to
attain
compliance,
it
must
be
installed.
We
are
revising
the
language
in
question
to
clarify
our
intent.
In
addition,
we
are
amending
§
63.1505(
i)(
7)
to
correct
an
erroneous
cross
reference.
As
amended,
certain
sidewell
group
1
furnaces
are
required
to
meet
the
limits
in
paragraphs
(
i)(
1)
through
(
4)
rather
than
(
j)(
1)
through
(
4).
G.
What
Other
Amendments
Are
We
Making?
We
are
amending
§
63.1510(
w)
to
clarify
the
procedures
for
obtaining
approval
of
alternative
monitoring
methods.
The
new
language
makes
it
clear
that
this
section
refers
to
alternative
monitoring
methods
other
than
those
which
may
be
separately
authorized
pursuant
to
§
63.1510(
j)(
5)
or
§
63.1510(
v).
We
are
also
clarifying
the
recordkeeping
requirements
for
in
line
fluxers
which
do
not
use
reactive
flux.
Section
63.1517(
b)(
11)
is
amended
to
permit
the
facility
to
document
that
a
particular
in
line
fluxer
does
not
use
reactive
flux
through
the
use
of
operating
logs
that
show
that
no
source
of
reactive
flux
was
used,
labels
that
prohibit
use
of
reactive
flux,
or
operating
logs
which
document
the
type
of
flux
used
during
each
operating
cycle.
We
are
amending
§
63.1505(
f)(
1),
which
establishes
emission
standards
for
sweat
furnaces,
to
correct
an
erroneous
residence
time.
We
are
clarifying
the
definition
of
a
melting/
holding
furnace
in
§
63.1503.
We
are
amending
§
63.1517(
b)(
16)
to
clarify
that
both
major
and
area
sources
must
keep
a
copy
of
the
OM&
M
plan
onsite
by
deleting
language
in
§
63.1517(
b)(
16)(
ii)
that
requires
only
major
sources
to
keep
a
copy
of
the
OM&
M
plan
on
site.
We
are
also
making
minor
amendments
to
correct
printing
or
technical
errors
in
the
final
rule.
These
include:
Revising
Tables
2
and
3
of
subpart
RRR
to
correct
entries
which
were
inadvertently
printed
in
the
wrong
columns
and
an
incorrect
specification
for
a
weight
measurement
device.
Revising
Equation
2
of
§
63.1505(
k)(
2)
to
correct
the
HCl
emission
limit
(
LcHCl).
Revising
the
entry
for
§
63.14
in
appendix
A
to
subpart
RRR
to
include
incorporation
by
reference
for
a
second
document.
III.
Response
to
Comments
on
Amendments
to
the
NESHAP
for
Secondary
Aluminum
Production
Comment:
One
commenter
opposes
the
proposed
revision
of
the
applicability
criteria
which
would
permit
facilities
to
melt
customer
returns.
This
commenter
argues
that
there
is
no
reason
to
conclude
that
melting
scrap
contaminated
with
oils
and
coating
applied
outside
the
facility
is
less
likely
to
result
in
dioxin
formation
than
melting
purchased
scrap
with
similar
contaminants.
Response:
In
considering
this
comment,
it
should
be
noted
that
those
customer
returns
which
are
contaminated
with
paints
or
other
solid
coatings
are
not
included
in
the
proposed
applicability
change.
In
any
case,
our
decision
to
permit
melting
of
certain
customer
returns
is
based
on
a
decision
to
treat
this
scrap
like
contaminated
internal
scrap
in
deciding
whether
a
facility
is
engaged
in
secondary
aluminum
production.
Our
decision
is
not
based
on
any
technical
assessment
regarding
the
likelihood
of
dioxin
formation.
Comment:
One
commenter
argues
that
the
amendments
would
allow
foundries
and
die
casters,
including
those
facilities
which
are
major
sources
of
HAP,
to
permanently
avoid
emission
limitations,
testing
requirements
and
monitoring
requirements.
Response:
We
recognize
that
some
aluminum
foundries
and
die
casters
may
have
the
potential
to
emit
more
than
10
tons
per
year
of
chlorine
(
a
listed
HAP),
but
we
do
not
agree
with
the
conclusion
of
the
commenter
that
the
rule
will
permit
such
facilities
to
escape
regulation
entirely.
We
note
that
the
same
argument
could
be
made
concerning
the
applicability
exclusion
in
the
existing
subpart
RRR.
Our
decision
to
exclude
certain
aluminum
die
casters,
foundries,
and
extruders
from
the
applicability
of
subpart
RRR
does
not
constitute
a
determination
that
such
facilities
should
be
entirely
unregulated.
We
believe
that
most,
if
not
all,
of
the
excluded
facilities
are
only
area
sources
of
HAP.
However,
if
there
is
any
aluminum
foundry
or
die
caster
which
would
be
entirely
exempt
under
the
revised
applicability
provisions
for
the
secondary
aluminum
source
category
and
which
also
has
the
potential
to
emit
major
source
quantities
of
HAP,
a
separate
MACT
standard
may
ultimately
be
necessary.
If
the
commenter
identifies
any
facility
which
is
a
major
source
of
HAP
but
is
not
included
in
any
listed
source
category,
EPA
has
authority
to
augment
the
source
category
list
as
provided
in
CAA
section
112(
c)(
5).
Comment:
One
commenter
opposes
the
provisions
permitting
redesignation
of
existing
emission
units
as
new,
on
the
basis
that
uncontrolled
or
poorly
controlled
new
emission
units
could
comply
by
averaging
their
emissions
with
well
controlled
redesignated
older
units.
Response:
We
believe
the
commenter
has
misconstrued
the
effect
of
the
new
provisions.
The
existing
rule
provides
that
certain
types
of
emission
units
may
be
included
within
a
secondary
aluminum
processing
unit
or
SAPU,
which
is
the
affected
source
to
which
the
standards
apply.
We
construe
the
statute
to
prohibit
combining
new
emission
units
with
existing
emission
units.
The
final
rule
amendments
pursuant
to
the
settlement
provide
that
existing
emission
units
may
be
permanently
redesignated
as
new.
Because
the
standard
for
an
existing
SAPU
and
the
standard
for
a
new
SAPU
are
identical,
this
procedure
will
not
alter
the
basic
control
requirements
which
apply
to
the
redesignated
units.
The
final
rule
amendments
also
establish
a
procedure
under
which
multiple
units
can
be
ducted
to
the
same
control
device,
but
compliance
will
still
be
separately
demonstrated
for
each
commonly
ducted
unit.
Comment:
One
commenter
states
that
there
are
no
data
to
support
the
change
in
residence
time
requirements
for
sweat
furnace
afterburners.
Response:
We
established
the
emission
limits
for
sweat
furnaces
based
on
limited
performance
test
data.
The
EPA
established
the
work
practice
standards
for
sweat
furnaces
on
the
basis
of
conditions
which
were
thought
to
have
existed
during
these
performance
tests.
Upon
review
of
the
performance
test
data,
we
determined
incorrect
dimensional
data
provided
in
the
test
report
led
to
an
incorrect
calculation
of
afterburner
residence
time.
The
amendments
do
not
make
the
emission
limits
less
stringent
but
only
alter
the
work
practice
requirements
which
are
necessary
to
ensure
compliance
with
the
emission
limits.
We
have
no
further
sweat
furnace
emission
data
and
the
commenter
has
not
provided
any
such
data.
Comment:
The
same
commenter
who
questioned
the
technical
basis
for
the
decreased
residence
time
for
sweat
furnaces
argues
that
EPA
is
obligated
to
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Federal
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/
Vol.
67,
No.
250
/
Monday,
December
30,
2002
/
Rules
and
Regulations
consider
longer
residence
times
as
a
``
beyond
the
floor
control
option.''
Response:
We
are
not
aware
of
any
technologies
which
could
decrease
the
HAP
emission
rate
for
sweat
furnaces
beyond
the
floor
technology
and
have
no
data
upon
which
to
evaluate
any
such
technologies.
While
an
increase
in
the
residence
time
for
the
floor
technology
may
increase
the
overall
control
efficiency
by
a
marginal
amount,
no
data
are
available
to
make
this
determination.
Comment:
One
commenter
requests
that
the
amendments
include
a
work
practice
standard
for
thermal
chip
dryers,
analogous
to
the
work
practice
requirement
for
sweat
furnaces.
Response:
The
amendments
requested
by
the
commenter
are
outside
of
the
scope
of
these
amendments
and
cannot
be
considered
in
this
rulemaking.
In
any
event,
the
commenter
supplied
no
test
data
in
support
of
a
work
practice
standard
for
thermal
chip
dryers,
and
EPA
has
no
data
that
would
support
the
suggested
change
in
the
standard.
IV.
Statutory
and
Executive
Order
Review
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
the
EPA
must
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
OMB
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
a
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
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
entitlement,
grants,
user
fees,
or
loan
programs
or
the
rights
and
obligations
of
recipients
thereof;
or
(
4)
raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
it
has
been
determined
that
this
action
is
not
a
``
significant
regulatory
action''
and
was
not
submitted
to
OMB
for
review.
B.
Paperwork
Reduction
Act
The
Office
of
Management
and
Budget
(
OMB)
has
previously
approved
the
information
collection
requirements
in
the
existing
rule
(
subpart
RRR)
under
the
provisions
of
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
and
assigned
OMB
control
No.
2060
0433.
This
action
does
not
change
the
information
collection
requirements
in
subpart
RRR,
but
does
reduce
the
number
of
facilities
subject
to
the
rule.
An
amended
Information
Collection
Request
(
ICR)
document
has
been
prepared
by
EPA
(
ICR
No.
1894.01),
and
a
copy
may
be
obtained
from
Susan
Auby
by
mail
at
U.
S.
EPA,
Office
of
Environmental
Information,
Collection
Strategies
Division
(
2822T),
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460,
by
e
mail
at
auby.
susan@
epa.
gov,
or
by
calling
(
202)
566
1672.
A
copy
may
also
be
downloaded
from
the
Internet
at
http://
www.
epa.
gov.
icr.
The
information
requirements
in
the
existing
rule
include
mandatory
notifications,
records,
and
reports
required
by
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A).
These
information
requirements
are
needed
to
confirm
the
compliance
status
of
major
sources,
to
identify
any
nonmajor
sources
not
subject
to
the
standards
and
any
new
or
reconstructed
sources
subject
to
the
standards,
and
to
confirm
that
emission
control
devices
are
being
properly
operated
and
maintained.
Based
on
the
recorded
and
reported
information,
EPA
can
decide
which
facilities,
records,
or
processes
should
be
inspected.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
under
section
114
of
the
CAA.
All
information
submitted
to
EPA
for
which
a
claim
of
confidentiality
is
made
will
be
safeguarded
according
to
Agency
policies
in
40
CFR
part
2,
subpart
B.
Under
the
amendments,
fewer
facilities
would
be
subject
to
the
testing,
monitoring,
recordkeeping,
and
reporting
requirements.
For
this
reason,
the
overall
burden
estimate
for
the
existing
rule
will
be
reduced
by
approximately
20
percent.
As
a
result
of
these
amendments,
the
annual
public
reporting
and
recordkeeping
burden
for
this
collection
of
information
(
averaged
over
the
first
3
years
after
the
effective
date
of
the
rule)
is
estimated
to
decrease
by
28,000
labor
hours
per
year
and
$
8.5
million
per
year.
Total
capital
costs
associated
with
monitoring
requirements
over
the
3
year
period
of
the
ICR
remain
unchanged
at
an
estimated
$
1.3
million;
this
estimate
includes
the
capital
and
startup
costs
associated
with
installation
of
monitoring
equipment.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purpose
of
collecting,
validating,
and
verifying
information;
process
and
maintain
information
and
disclose
and
provide
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
respond
to
a
collection
of
information;
search
existing
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
Agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
C.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
et
seq.
The
EPA
has
determined
that
it
is
not
necessary
to
prepare
a
regulatory
flexibility
analysis
in
connection
with
these
final
rule
amendments.
The
EPA
has
also
determined
that
these
final
rule
amendments
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
final
rule
amendments
on
small
entities,
a
small
entity
is
defined
as:
(
1)
A
small
business
whose
parent
company
has
fewer
than
750
employees;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
or
(
3)
a
small
organization
that
is
any
notfor
profit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
After
considering
the
economic
impacts
of
today's
final
rule
amendments
on
small
entities,
the
EPA
has
concluded
that
this
action
will
not
create
any
new
costs
for
affected
firms,
large
or
small.
In
fact,
the
amendments
will
reduce
the
economic
impact
on
small
businesses
because
of
the
revised
applicability
requirements
for
die
casters,
extruders,
and
foundries.
Because
these
plants
will
not
incur
any
significant
costs
or
economic
impact,
EPA
has
determined
that
it
is
not
necessary
to
prepare
a
regulatory
flexibility
analysis
in
connection
with
these
final
rule
amendments.
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Federal
Register
/
Vol.
67,
No.
250
/
Monday,
December
30,
2002
/
Rules
and
Regulations
considering
the
economic
impact
of
today's
final
rule
amendments
on
small
entities,
the
EPA
has
concluded
that
they
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
D.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
the
EPA
generally
must
prepare
a
written
statement,
including
a
costbenefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
by
State,
local,
and
tribal
governments,
in
the
aggregate,
or
by
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
the
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
the
EPA
to
adopt
an
alternative
other
than
the
leastcostly
most
cost
effective,
or
leastburdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
the
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
The
EPA
has
determined
that
these
final
rule
amendments
do
not
contain
a
Federal
mandate
that
may
result
in
estimated
costs
of
$
100
million
or
more
to
either
State,
local,
or
tribal
governments,
in
the
aggregate,
or
to
the
private
sector
in
any
1
year.
No
incremental
costs
are
attributable
to
these
amendments.
In
addition,
the
amendments
do
not
significantly
or
uniquely
affect
small
governments
because
they
contain
no
requirements
that
apply
to
such
governments
or
impose
obligations
upon
them.
Therefore,
the
requirements
of
the
UMRA
do
not
apply
to
these
amendments.
E.
Executive
Order
13132,
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
Under
section
6
of
Executive
Order
13132,
EPA
may
not
issue
a
regulation
that
has
federalism
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,
unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
State
and
local
governments,
or
EPA
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
The
EPA
also
may
not
issue
a
regulation
that
has
federalism
implications
and
that
preempts
State
law
unless
the
EPA
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
These
rule
amendments
do
not
have
federalism
implications.
They
do
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
None
of
the
affected
plants
are
owned
or
operated
by
State
governments.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
these
rule
amendments.
F.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
6,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
``
Policies
that
have
tribal
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
one
or
more
Indian
tribes,
on
the
relationship
between
the
Federal
government
and
Indian
tribes.''
These
rule
amendments
do
not
have
tribal
implications.
They
do
not
have
substantial
direct
effects
on
tribal
governments,
on
the
relationship
between
the
Federal
government
and
Indian
tribes,
or
on
the
distribution
of
power
and
responsibilities
between
the
Federal
government
and
Indian
tribes,
as
specified
in
Executive
Order
13175.
No
tribal
governments
own
plants
subject
to
the
existing
rule
or
today's
amendments.
Thus,
Executive
Order
13175
does
not
apply
to
these
rule
amendments.
G.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant,''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
we
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives.
We
interpret
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
501
of
the
Executive
Order
has
the
potential
to
influence
the
regulation.
These
final
rule
amendments
are
not
subject
to
Executive
Order
13045
because
they
are
based
on
technology
performance
and
not
on
health
or
safety
risks.
H.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
These
final
rule
amendments
are
not
subject
to
Executive
Order
13211
(
66
FR
28355,
May
22,
2001)
because
they
are
not
a
significant
regulatory
action
under
Executive
Order
12866.
I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
(
NTTAA)
of
1995
(
Public
Law
104
113;
15
U.
S.
C.
272
note),
directs
EPA
to
use
voluntary
consensus
standards
in
their
regulatory
and
procurement
activities
unless
to
do
so
would
be
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Vol.
67,
No.
250
/
Monday,
December
30,
2002
/
Rules
and
Regulations
inconsistent
with
applicable
law
or
otherwise
impracticable.
Voluntary
consensus
standards
are
technical
standards
(
such
as
material
specifications,
test
methods,
sampling
procedures,
business
practices)
developed
or
adopted
by
one
or
more
voluntary
consensus
bodies.
The
NTTAA
requires
Federal
agencies
to
provide
Congress,
through
annual
reports
to
OMB,
with
explanations
when
an
agency
does
not
use
available
and
applicable
voluntary
consensus
standards.
The
EPA's
response
to
the
NTTAA
requirements
are
discussed
in
the
preamble
to
the
final
rule
(
65
FR
15690).
These
amendments
do
not
change
the
required
methods
or
procedures,
but
would
expand
provisions
for
the
use
of
alternative
methods.
If
a
plant
wishes
to
use
an
alternative
method
other
than
those
identified
in
the
existing
rule,
the
owner
or
operator
may
submit
an
application
to
EPA
according
to
the
procedures
described
in
the
existing
rule.
J.
Congressional
Review
Act
The
Congressional
Review
Act,
5
U.
S.
C.
801
et
seq.,
as
added
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996,
generally
provides
that
before
a
rule
may
take
effect,
the
agency
promulgating
the
rule
must
submit
a
rule
report,
which
includes
a
copy
of
the
rule,
to
each
House
of
the
Congress
and
to
the
Comptroller
General
of
the
United
States.
The
EPA
will
submit
a
report
containing
this
rule
and
other
required
information
to
the
U.
S.
Senate,
the
U.
S.
House
of
Representatives,
and
the
Comptroller
General
of
the
United
States
prior
to
publication
of
the
rule
in
the
Federal
Register.
A
major
rule
cannot
take
effect
until
60
days
after
it
is
published
in
the
Federal
Register.
These
final
rule
amendments
are
not
a
``
major
rule''
as
defined
by
5
U.
S.
C.
804(
2).
List
of
Subjects
in
40
CFR
Part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Hazardous
substances,
Reporting
and
recordkeeping
requirements.
Dated:
December
19,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
stated
in
the
preamble,
title
40,
chapter
I,
part
63
of
the
Code
of
Federal
Regulations
is
amended
as
follows:
PART
63
[
AMENDED]
1.
The
authority
citation
for
part
63
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401
et
seq.
Subpart
RRR
[
AMENDED]
2.
Section
63.1500
is
amended
by:
a.
Revising
paragraph
(
a);
b.
Removing
existing
paragraph
(
d);
c.
Redesignating
existing
paragraphs
(
e)
and
(
f)
as
(
d)
and
(
e);
and
d.
Adding
new
paragraph
(
f).
The
addition
and
revision
reads
as
follows:
§
63.1500
Applicability.
(
a)
The
requirements
of
this
subpart
apply
to
the
owner
or
operator
of
each
secondary
aluminum
production
facility
as
defined
in
§
63.1503.
*
*
*
*
*
(
f)
An
aluminum
die
casting
facility,
aluminum
foundry,
or
aluminum
extrusion
facility
shall
be
considered
to
be
an
area
source
if
it
does
not
emit,
or
have
the
potential
to
emit
considering
controls,
10
tons
per
year
or
more
of
any
single
listed
HAP
or
25
tons
per
year
of
any
combination
of
listed
HAP
from
all
emission
sources
which
are
located
in
a
contiguous
area
and
under
common
control,
without
regard
to
whether
or
not
such
sources
are
regulated
under
this
subpart
or
any
other
subpart.
In
the
case
of
an
aluminum
die
casting
facility,
aluminum
foundry,
or
aluminum
extrusion
facility
which
is
an
area
source
and
is
subject
to
regulation
under
this
subpart
only
because
it
operates
a
thermal
chip
dryer,
no
furnace
operated
by
such
a
facility
shall
be
deemed
to
be
subject
to
the
requirements
of
this
subpart
if
it
melts
only
clean
charge,
internal
scrap,
or
customer
returns.
3.
Section
63.1503
is
amended
by:
a.
Adding
in
alphabetical
order
new
definitions
for
the
terms
``
aluminum
scrap,''
``
customer
returns,''
``
internal
scrap,''
and
``
runaround
scrap'';
and
b.
Revising
definitions
for
the
terms
``
clean
charge,''
``
cover
flux,''
``
group
1
furnace,''
``
group
2
furnace,''
``
melting/
holding
furnace,''
``
reactive
fluxing,''
``
scrap
dryer/
delacquering
kiln/
decoating
kiln,''
``
secondary
aluminum
processing
unit
(
SAPU),''
``
secondary
aluminum
production
facility,''
and
``
thermal
chip
dryer.''
The
additions
and
revisions
read
as
follows:
§
63.1503
Definitions.
*
*
*
*
*
Aluminum
scrap
means
fragments
of
aluminum
stock
removed
during
manufacturing
(
i.
e.,
machining),
manufactured
aluminum
articles
or
parts
rejected
or
discarded
and
useful
only
as
material
for
reprocessing,
and
waste
and
discarded
material
made
of
aluminum.
*
*
*
*
*
Clean
charge
means
furnace
charge
materials
including
molten
aluminum,
T
bar,
sow,
ingot,
billet,
pig,
alloying
elements,
aluminum
scrap
known
by
the
owner
or
operator
to
be
entirely
free
of
paints,
coatings,
and
lubricants;
uncoated/
unpainted
aluminum
chips
that
have
been
thermally
dried
or
treated
by
a
centrifugal
cleaner;
aluminum
scrap
dried
at
343
°
C
(
650
°
F)
or
higher;
aluminum
scrap
delacquered/
decoated
at
482
°
C
(
900
°
F)
or
higher,
and
runaround
scrap.
Cover
flux
means
salt
added
to
the
surface
of
molten
aluminum
in
a
group
1
or
group
2
furnace,
without
agitation
of
the
molten
aluminum,
for
the
purpose
of
preventing
oxidation.
Customer
returns
means
any
aluminum
product
which
is
returned
by
a
customer
to
the
aluminum
company
that
originally
manufactured
the
product
prior
to
resale
of
the
product
or
further
distribution
in
commerce,
and
which
contains
no
paint
or
other
solid
coatings
(
i.
e.,
lacquers).
*
*
*
*
*
Group
1
furnace
means
a
furnace
of
any
design
that
melts,
holds,
or
processes
aluminum
that
contains
paint,
lubricants,
coatings,
or
other
foreign
materials
with
or
without
reactive
fluxing,
or
processes
clean
charge
with
reactive
fluxing.
Group
2
furnace
means
a
furnace
of
any
design
that
melts,
holds,
or
processes
only
clean
charge
and
that
performs
no
fluxing
or
performs
fluxing
using
only
nonreactive,
non
HAPcontaining
non
HAP
generating
gases
or
agents.
*
*
*
*
*
Internal
scrap
means
all
aluminum
scrap
regardless
of
the
level
of
contamination
which
originates
from
castings
or
extrusions
produced
by
an
aluminum
die
casting
facility,
aluminum
foundry,
or
aluminum
extrusion
facility,
and
which
remains
at
all
times
within
the
control
of
the
company
that
produced
the
castings
or
extrusions.
*
*
*
*
*
Melting/
holding
furnace
means
a
group
1
furnace
that
processes
only
clean
charge,
performs
melting,
holding,
and
fluxing
functions,
and
does
not
transfer
molten
aluminum
to
or
from
another
furnace
except
for
purposes
of
alloy
changes,
off
specification
product
drains,
or
maintenance
activities.
*
*
*
*
*
Reactive
fluxing
means
the
use
of
any
gas,
liquid,
or
solid
flux
(
other
than
cover
flux)
that
results
in
a
HAP
emission.
Argon
and
nitrogen
are
not
reactive
and
do
not
produce
HAP.
*
*
*
*
*
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Rules
and
Regulations
Runaround
scrap
means
scrap
materials
generated
on
site
by
aluminum
casting,
extruding,
rolling,
scalping,
forging,
forming/
stamping,
cutting,
and
trimming
operations
and
that
do
not
contain
paint
or
solid
coatings.
Uncoated/
unpainted
aluminum
chips
generated
by
turning,
boring,
milling,
and
similar
machining
operations
may
be
clean
charge
if
they
have
been
thermally
dried
or
treated
by
a
centrifugal
cleaner,
but
are
not
considered
to
be
runaround
scrap.
Scrap
dryer/
delacquering
kiln/
decoating
kiln
means
a
unit
used
primarily
to
remove
various
organic
contaminants
such
as
oil,
paint,
lacquer,
ink,
plastic,
and/
or
rubber
from
aluminum
scrap
(
including
used
beverage
containers)
prior
to
melting.
Secondary
aluminum
processing
unit
(
SAPU).
An
existing
SAPU
means
all
existing
group
1
furnaces
and
all
existing
in
line
fluxers
within
a
secondary
aluminum
production
facility.
Each
existing
group
1
furnace
or
existing
in
line
fluxer
is
considered
an
emission
unit
within
a
secondary
aluminum
processing
unit.
A
new
SAPU
means
any
combination
of
individual
group
1
furnaces
and
in
line
fluxers
within
a
secondary
aluminum
processing
facility
which
either
were
constructed
or
reconstructed
after
February
11,
1999,
or
have
been
permanently
redesignated
as
new
emission
units
pursuant
to
§
63.1505(
k)(
6).
Each
of
the
group
1
furnaces
or
in
line
fluxers
within
a
new
SAPU
is
considered
an
emission
unit
within
that
secondary
aluminum
processing
unit.
Secondary
aluminum
production
facility
means
any
establishment
using
clean
charge,
aluminum
scrap,
or
dross
from
aluminum
production,
as
the
raw
material
and
performing
one
or
more
of
the
following
processes:
scrap
shredding,
scrap
drying/
delacquering/
decoating,
thermal
chip
drying,
furnace
operations
(
i.
e.,
melting,
holding,
sweating,
refining,
fluxing,
or
alloying),
recovery
of
aluminum
from
dross,
inline
fluxing,
or
dross
cooling.
A
secondary
aluminum
production
facility
may
be
independent
or
part
of
a
primary
aluminum
production
facility.
For
purposes
of
this
subpart,
aluminum
die
casting
facilities,
aluminum
foundries,
and
aluminum
extrusion
facilities
are
not
considered
to
be
secondary
aluminum
production
facilities
if
the
only
materials
they
melt
are
clean
charge,
customer
returns,
or
internal
scrap,
and
if
they
do
not
operate
sweat
furnaces,
thermal
chip
dryers,
or
scrap
dryers/
delacquering
kilns/
decoating
kilns.
The
determination
of
whether
a
facility
is
a
secondary
aluminum
production
facility
is
only
for
purposes
of
this
subpart
and
any
regulatory
requirements
which
are
derived
from
the
applicability
of
this
subpart,
and
is
separate
from
any
determination
which
may
be
made
under
other
environmental
laws
and
regulations,
including
whether
the
same
facility
is
a
``
secondary
metal
production
facility''
as
that
term
is
used
in
42
U.
S.
C.
§
7479(
1)
and
40
CFR
52.21(
b)(
1)(
i)(
A)
(``
prevention
of
significant
deterioration
of
air
quality'').
*
*
*
*
*
Thermal
chip
dryer
means
a
device
that
uses
heat
to
evaporate
oil
or
oil/
water
mixtures
from
unpainted/
uncoated
aluminum
chips.
Pre
heating
boxes
or
other
dryers
which
are
used
solely
to
remove
water
from
aluminum
scrap
are
not
considered
to
be
thermal
chip
dryers
for
purposes
of
this
subpart.
*
*
*
*
*
4.
Section
63.1505
is
amended
by:
a.
Revising
the
section
heading;
b.
Revising
paragraph
(
f)(
1);
c.
Revising
paragraph
(
i)(
7);
d.
Republishing
the
introductory
text
of
paragraph
(
k)(
2)
and
revising
Equation
2;
and
e.
Adding
new
paragraph
(
k)(
6).
The
revisions
and
addition
read
as
follows:
§
63.1505
Emission
standards
for
affected
sources
and
emission
units.
*
*
*
*
*
(
f)
Sweat
furnace.
*
*
*
(
1)
The
owner
or
operator
is
not
required
to
conduct
a
performance
test
to
demonstrate
compliance
with
the
emission
standard
of
paragraph
(
f)(
2)
of
this
section,
provided
that,
on
and
after
the
compliance
date
of
this
rule,
the
owner
or
operator
operates
and
maintains
an
afterburner
with
a
design
residence
time
of
0.8
seconds
or
greater
and
an
operating
temperature
of
1600
°
F
or
greater.
*
*
*
*
*
(
i)
Group
1
furnace.
*
*
*
(
7)
The
owner
or
operator
of
a
sidewell
group
1
furnace
that
conducts
reactive
fluxing
(
except
for
cover
flux)
in
the
hearth,
or
that
conducts
reactive
fluxing
in
the
sidewell
at
times
when
the
level
of
molten
metal
falls
below
the
top
of
the
passage
between
the
sidewell
and
the
hearth,
must
comply
with
the
emission
limits
of
paragraphs
(
i)(
1)
through
(
4)
of
this
section
on
the
basis
of
the
combined
emissions
from
the
sidewell
and
the
hearth.
*
*
*
*
*
(
k)
Secondary
aluminum
processing
unit.
*
*
*
(
2)
The
owner
or
operator
must
not
discharge
or
allow
to
be
discharged
to
the
atmosphere
any
3
day,
24
hour
rolling
average
emissions
of
HCl
in
excess
of:
L
L
T
T
c
ti
ti
i
n
ti
i
n
HCl
HCl
=
×
(
)
(
)
=
=
1
1
(
Eq.
2)
*
*
*
*
*
(
6)
With
the
prior
approval
of
the
responsible
permitting
authority,
an
owner
or
operator
may
redesignate
any
existing
group
1
furnace
or
in
line
fluxer
at
a
secondary
aluminum
production
facility
as
a
new
emission
unit.
Any
emission
unit
so
redesignated
may
thereafter
be
included
in
a
new
SAPU
at
that
facility.
Any
such
redesignation
will
be
solely
for
the
purpose
of
this
MACT
standard
and
will
be
irreversible.
*
*
*
*
*
5.
Section
63.1506
is
amended
by:
a.
Removing
existing
paragraph
(
a)(
2);
b.
Redesignating
existing
paragraphs
(
a)(
3)
through
(
a)(
5)
as
paragraphs
(
a)(
2)
through
(
a)(
4);
and
c.
Revising
paragraphs
(
m)(
6)(
i)
and
(
ii).
The
revisions
read
as
follows.
§
63.1506
Operating
requirements.
*
*
*
*
*
(
m)
Group
1
furnace
with
add
on
air
pollution
control
devices.
*
*
*
(
6)
*
*
*
(
i)
The
level
of
molten
metal
remains
above
the
top
of
the
passage
between
the
sidewell
and
hearth
during
reactive
flux
injection,
unless
emissions
from
both
the
sidewell
and
the
hearth
are
included
in
demonstrating
compliance
with
all
applicable
emission
limits.
(
ii)
Reactive
flux
is
added
only
in
the
sidewell,
unless
emissions
from
both
the
sidewell
and
the
hearth
are
included
in
demonstrating
compliance
with
all
applicable
emission
limits.
*
*
*
*
*
6.
Section
63.1510
is
amended
by:
a.
Removing
the
last
sentence
in
the
introductory
text
of
paragraph
(
b),
``
Each
plan
must
contain
the
following
information'',
and
adding,
in
its
place,
five
new
sentences;
b.
Revising
the
introductory
text
of
paragraph
(
o)(
1);
and
c.
Revising
the
introductory
text
of
paragraph
(
w).
The
revisions
read
as
follows:
§
63.1510
Monitoring
requirements.
*
*
*
*
*
(
b)
Operation,
maintenance,
and
monitoring
(
OM&
M)
plan.
*
*
*
The
plan
must
be
accompanied
by
a
written
certification
by
the
owner
or
operator
that
the
OM&
M
plan
satisfies
all
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250
/
Monday,
December
30,
2002
/
Rules
and
Regulations
requirements
of
this
section
and
is
otherwise
consistent
with
the
requirements
of
this
subpart.
The
owner
or
operator
must
comply
with
all
of
the
provisions
of
the
OM&
M
plan
as
submitted
to
the
permitting
authority,
unless
and
until
the
plan
is
revised
in
accordance
with
the
following
procedures.
If
the
permitting
authority
determines
at
any
time
after
receipt
of
the
OM&
M
plan
that
any
revisions
of
the
plan
are
necessary
to
satisfy
the
requirements
of
this
section
or
this
subpart,
the
owner
or
operator
must
promptly
make
all
necessary
revisions
and
resubmit
the
revised
plan.
If
the
owner
or
operator
determines
that
any
other
revisions
of
the
OM&
M
plan
are
necessary,
such
revisions
will
not
become
effective
until
the
owner
or
operator
submits
a
description
of
the
changes
and
a
revised
plan
incorporating
them
to
the
permitting
authority.
Each
plan
must
contain
the
following
information:
*
*
*
*
*
(
o)
Group
1
furnace
without
add
on
air
pollution
control
devices.
*
*
*
(
1)
The
owner
or
operator
must
develop,
in
consultation
with
the
responsible
permitting
authority,
a
written
site
specific
monitoring
plan.
The
site
specific
monitoring
plan
must
be
submitted
to
the
permitting
authority
as
part
of
the
OM&
M
plan.
The
sitespecific
monitoring
plan
must
contain
sufficient
procedures
to
ensure
continuing
compliance
with
all
applicable
emission
limits
and
must
demonstrate,
based
on
documented
test
results,
the
relationship
between
emissions
of
PM,
HCl,
and
D/
F
and
the
proposed
monitoring
parameters
for
each
pollutant.
Test
data
must
establish
the
highest
level
of
PM,
HCl,
and
D/
F
that
will
be
emitted
from
the
furnace.
This
may
be
determined
by
conducting
performance
tests
and
monitoring
operating
parameters
while
charging
the
furnace
with
feed/
charge
materials
containing
the
highest
anticipated
levels
of
oils
and
coatings
and
fluxing
at
the
highest
anticipated
rate.
If
the
permitting
authority
determines
that
any
revisions
of
the
site
specific
monitoring
plan
are
necessary
to
meet
the
requirements
of
this
section
or
this
subpart,
the
owner
or
operator
must
promptly
make
all
necessary
revisions
and
resubmit
the
revised
plan
to
the
permitting
authority.
*
*
*
*
*
(
w)
Alternative
monitoring
methods.
If
an
owner
or
operator
wishes
to
use
an
alternative
monitoring
method
to
demonstrate
compliance
with
any
emission
standard
in
this
subpart,
other
than
those
alternative
monitoring
methods
which
may
be
authorized
pursuant
to
§
63.1510(
j)(
5)
and
§
63.1510(
v),
the
owner
or
operator
may
submit
an
application
to
the
Administrator.
Any
such
application
will
be
processed
according
to
the
criteria
and
procedures
set
forth
in
paragraphs
(
w)(
1)
through
(
6)
of
this
section.
*
*
*
*
*
7.
Section
63.1511
is
amended
by
revising
paragraph
(
f)
and
adding
paragraphs
(
h)
and
(
i)
to
read
as
follows:
§
63.1511
Performance
test/
compliance
demonstration
general
requirements.
*
*
*
*
*
(
f)
Testing
of
representative
emission
units.
With
the
prior
approval
of
the
permitting
authority,
an
owner
or
operator
may
utilize
emission
rates
obtained
by
testing
a
particular
type
of
group
1
furnace
which
is
not
controlled
by
any
add
on
control
device,
or
by
testing
an
in
line
flux
box
which
is
not
controlled
by
any
add
on
control
device,
to
determine
the
emission
rate
for
other
units
of
the
same
type
at
the
same
facility.
Such
emission
test
results
may
only
be
considered
to
be
representative
of
other
units
if
all
of
the
following
criteria
are
satisfied:
(
1)
The
tested
emission
unit
must
use
feed
materials
and
charge
rates
which
are
comparable
to
the
emission
units
that
it
represents;
(
2)
The
tested
emission
unit
must
use
the
same
type
of
flux
materials
in
the
same
proportions
as
the
emission
units
it
represents;
(
3)
The
tested
emission
unit
must
be
operated
utilizing
the
same
work
practices
as
the
emission
units
that
it
represents;
(
4)
The
tested
emission
unit
must
be
of
the
same
design
as
the
emission
units
that
it
represents;
and
(
5)
The
tested
emission
unit
must
be
tested
under
the
highest
load
or
capacity
reasonably
expected
to
occur
for
any
of
the
emission
units
that
it
represents.
*
*
*
*
*
(
h)
Testing
of
commonly
ducted
units
within
a
secondary
aluminum
processing
unit.
When
group
1
furnaces
and/
or
in
line
fluxers
are
included
in
a
single
existing
SAPU
or
new
SAPU,
and
the
emissions
from
more
than
one
emission
unit
within
that
existing
SAPU
or
new
SAPU
are
manifolded
to
a
single
control
device,
compliance
for
all
units
within
the
SAPU
is
demonstrated
if
the
total
measured
emissions
from
all
controlled
and
uncontrolled
units
in
the
SAPU
do
not
exceed
the
emission
limits
calculated
for
that
SAPU
based
on
the
applicable
equation
in
§
63.1505(
k).
(
i)
Testing
of
commonly
ducted
units
not
within
a
secondary
aluminum
processing
unit.
With
the
prior
approval
of
the
permitting
authority,
an
owner
or
operator
may
do
combined
performance
testing
of
two
or
more
individual
affected
sources
or
emission
units
which
are
not
included
in
a
single
existing
SAPU
or
new
SAPU,
but
whose
emissions
are
manifolded
to
a
single
control
device.
Any
such
performance
testing
of
commonly
ducted
units
must
satisfy
the
following
basic
requirements:
(
1)
All
testing
must
be
designed
to
verify
that
each
affected
source
or
emission
unit
individually
satisfies
all
emission
requirements
applicable
to
that
affected
source
or
emission
unit;
(
2)
All
emissions
of
pollutants
subject
to
a
standard
must
be
tested
at
the
outlet
from
each
individual
affected
source
or
emission
unit
while
operating
under
the
highest
load
or
capacity
reasonably
expected
to
occur,
and
prior
to
the
point
that
the
emissions
are
manifolded
together
with
emissions
from
other
affected
sources
or
emission
units;
(
3)
The
combined
emissions
from
all
affected
sources
and
emission
units
which
are
manifolded
to
a
single
emission
control
device
must
be
tested
at
the
outlet
of
the
emission
control
device;
(
4)
All
tests
at
the
outlet
of
the
emission
control
device
must
be
conducted
with
all
affected
sources
and
emission
units
whose
emissions
are
manifolded
to
the
control
device
operating
simultaneously
under
the
highest
load
or
capacity
reasonably
expected
to
occur;
and
(
5)
For
purposes
of
demonstrating
compliance
of
a
commonly
ducted
unit
with
any
emission
limit
for
a
particular
type
of
pollutant,
the
emissions
of
that
pollutant
by
the
individual
unit
shall
be
presumed
to
be
controlled
by
the
same
percentage
as
total
emissions
of
that
pollutant
from
all
commonly
ducted
units
are
controlled
at
the
outlet
of
the
emission
control
device.
8.
Section
63.1512
is
amended
by
revising
paragraph
(
h)
to
read
as
follows:
§
63.1512
Performance
test/
compliance
demonstration
requirements
and
procedures.
*
*
*
*
*
(
h)
In
line
fluxer.
(
1)
The
owner
or
operator
of
an
in
line
fluxer
that
uses
reactive
flux
materials
must
conduct
a
performance
test
to
measure
emissions
of
HCl
and
PM
or
otherwise
demonstrate
compliance
in
accordance
with
paragraph
(
h)(
2)
of
this
section.
If
the
in
line
fluxer
is
equipped
with
an
add
on
control
device,
the
emissions
must
be
measured
at
the
outlet
of
the
control
device.
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30,
2002
/
Rules
and
Regulations
(
2)
The
owner
or
operator
may
choose
to
limit
the
rate
at
which
reactive
chlorine
flux
is
added
to
an
in
line
fluxer
and
assume,
for
the
purposes
of
demonstrating
compliance
with
the
SAPU
emission
limit,
that
all
chlorine
in
the
reactive
flux
added
to
the
in
line
fluxer
is
emitted
as
HCl.
Under
these
circumstances,
the
owner
or
operator
is
not
required
to
conduct
an
emission
test
for
HCl.
If
the
owner
or
operator
of
any
in
line
flux
box
which
has
no
ventilation
ductwork
manifolded
to
any
outlet
or
emission
control
device
chooses
to
demonstrate
compliance
with
the
emission
limit
for
HCl
by
limiting
use
of
reactive
chlorine
flux
and
assuming
that
all
chlorine
in
the
flux
is
emitted
as
HCl,
compliance
with
the
HCl
limit
shall
also
constitute
compliance
with
the
emission
limit
for
PM,
and
no
separate
emission
test
for
PM
is
required.
In
this
case,
the
owner
or
operator
of
the
unvented
in
line
flux
box
must
utilize
the
maximum
permissible
PM
emission
rate
for
the
inline
flux
boxes
when
determining
the
total
emissions
for
any
SAPU
which
includes
the
flux
box.
*
*
*
*
*
9.
Section
63.1515
is
amended
by
revising
paragraphs
(
b)(
8)
and
(
b)(
9)
to
read
as
follows:
§
63.1515
Notifications.
*
*
*
*
*
(
b)
*
*
*
(
8)
Manufacturer's
specification
or
analysis
documenting
the
design
residence
time
of
no
less
than
0.8
seconds
and
design
operating
temperature
of
no
less
than
1,600
°
F
for
each
afterburner
used
to
control
emissions
from
a
sweat
furnace
that
is
not
subject
to
a
performance
test.
(
9)
The
OM&
M
plan
(
including
sitespecific
monitoring
plan
for
each
group
1
furnace
with
no
add
on
air
pollution
control
device).
*
*
*
*
*
10.
Section
63.1517
is
amended
by
revising
paragraphs
(
b)(
11)
and
(
b)(
16)(
ii)
to
read
as
follows:
§
63.1517
Records.
*
*
*
*
*
(
b)
*
*
*
(
11)
For
each
in
line
fluxer
for
which
the
owner
or
operator
has
certified
that
no
reactive
flux
was
used:
(
i)
Operating
logs
which
establish
that
no
source
of
reactive
flux
was
present
at
the
in
line
fluxer;
(
ii)
Labels
required
pursuant
to
§
63.1506(
b)
which
establish
that
no
reactive
flux
may
be
used
at
the
in
line
fluxer;
or
(
iii)
Operating
logs
which
document
each
flux
gas,
agent,
or
material
used
during
each
operating
cycle.
*
*
*
*
*
(
16)
*
*
*
(
ii)
OM&
M
plan;
and
*
*
*
*
*
11.
Table
2
to
subpart
RRR
is
amended
under
the
entry
for
``
Group
1
furnace
with
lime
injected
fabric
filter
(
including
those
that
are
part
of
secondary
aluminum
processing
unit)''
by
revising
in
column
2
the
entry
``
Fabric
filter
inlet
temperature''
to
read
as
follows:
TABLE
2
TO
SUBPART
RRR
OF
PART
63.
SUMMARY
OF
OPERATING
REQUIREMENTS
FOR
NEW
AND
EXISTING
AFFECTED
SOURCES
AND
EMISSION
UNITS
Affected
source/
emission
unit
Monitor
type/
operation/
process
Operating
requirements
*
*
*
*
*
*
*
Group
1
furnace
with
lime
injected
fabric
filter
filter
(
including
those
that
are
part
of
a
secondary
aluminum
processing
unit).
*
*
*
*
*
Fabric
filter
inlet
temperature
*
*
*
*
*
*
*
*
*
*
Maintain
average
fabric
filter
inlet
temperature
for
each
3
hour
period
at
or
below
average
temperature
during
the
performance
test
+
14
°
C
(+
25
°
F).
*
*
*
*
*
*
*
*
*
*
12.
Table
3
to
subpart
RRR
is
amended
by:
a.
Under
the
entry
for
``
Group
1
furnace
with
lime
injected
fabric
filter'',
revising
in
column
2
the
entry
``
Reactive
flux
injection
rate
Weight
measurement
device
accuracy
of
+
1%
b;
calibrate
every
3
months;
record
weight
and
type
of
reactive
flux
added
or
injected
for
each
15
minute
block
period
while
reactive
fluxing
occurs;
calculate
and
record
total
reactive
flux
injection
rate
for
each
operating
cycle
or
time
period
used
in
performance
test;
or
Alternative
flux
injection
rate
determination
procedure
per
§
63.1510(
j)(
5).'';
and
b.
Under
the
entry
for
``
Group
1
furnace
without
add
on
controls'',
revising
in
column
2
the
entry
for
``
Feed
material
(
melting/
holding
furnace)''.
The
revisions
read
as
follows:
TABLE
3
TO
SUBPART
RRR
OF
PART
63.
SUMMARY
OF
MONITORING
REQUIREMENTS
FOR
NEW
AND
EXISTING
AFFECTED
SOURCES
AND
EMISSION
UNITS
Affected
source/
emission
unit
Monitor
type/
Operation/
Process
Monitoring
requirements
*
*
*
*
*
*
*
Group
1
furnace
with
lime
injected
fabric
filter
.................
*
*
*
*
*
*
*
*
*
*
Reactive
flux
injection
rate
*
*
*
*
*
Weight
measurement
device
accuracy
of
±
1%
b;
calibrate
every
3
months;
record
weight
and
type
of
reactive
flux
added
or
injected
for
each
15
minute
block
period
while
reactive
fluxing
occurs;
calculate
and
record
total
reactive
flux
injection
rate
for
each
operating
cycle
or
time
period
used
in
performance
test;
or
Alternative
flux
injection
rate
determination
procedure
per
§
63.1510(
j)(
5).
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Vol.
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No.
250
/
Monday,
December
30,
2002
/
Rules
and
Regulations
TABLE
3
TO
SUBPART
RRR
OF
PART
63.
SUMMARY
OF
MONITORING
REQUIREMENTS
FOR
NEW
AND
EXISTING
AFFECTED
SOURCES
AND
EMISSION
UNITS
Continued
Affected
source/
emission
unit
Monitor
type/
Operation/
Process
Monitoring
requirements
*
*
*
*
*
Group
1
furnace
without
add
on
controls
.........................
*
*
*
*
*
*
*
*
*
*
Feed
material
(
melting/
holding
furnace).
Record
type
of
permissible
feed/
charge
material;
certify
charge
materials
every
6
months.
*
*
*
*
*
13.
Appendix
A
to
subpart
RRR
is
amended
under
the
entry
for
``
§
63.14''
by
revising
in
column
2
the
entry
for
``
Incorporation
by
reference''
to
read
as
follows:
APPENDIX
A
TO
SUBPART
RRR
OF
PART
63.
GENERAL
PROVISIONS
APPLICABILITY
TO
SUBPART
RRR
Citation
Requirement
Applies
to
RRR
Comment
*
*
*
*
*
*
*
§
63.14
........................
Incorporation
by
Reference
Yes
.............................
Chapters
3
and
5
of
ACGIH
Industrial
Ventilation
Manual
for
capture/
collection
systems;
and
Interim
Procedures
for
Estimating
Risk
Associated
with
Exposure
to
Mixtures
of
Chlorinated
Dibenzofurans
(
CDDs
and
CDFs)
and
1989
Update
(
incorporated
by
reference
in
§
63.1502).
*
*
*
*
*
[
FR
Doc.
02
32779
Filed
12
27
02;
8:
45
am]
BILLING
CODE
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| epa | 2024-06-07T20:31:40.682198 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0084-0001/content.txt"
} |
EPA-HQ-OAR-2002-0088-0046 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Attached table includes factors for scaling the NARCO annual emissions to estimate the annual rate of hexavalent chromium emissions from refractory production and the annual rates of phenol and formaldehyde emissions from resin-bonded refractory productio
| epa | 2024-06-07T20:31:40.695705 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0046/content.txt"
} |
EPA-HQ-OAR-2002-0088-0047 | Supporting & Related Material | "2002-11-08T05:00:00" | null |
Comment Info: =================
General Comment:Visit the manufacturing facilities assocociated with the production of refractory brick and gather information in preparation for hazardous air pollutants (HAP) emissions testings of the curing ovens and periodic (bell) kilns at this plant.
| epa | 2024-06-07T20:31:40.696357 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0047/content.txt"
} |
EPA-HQ-OAR-2002-0088-0049 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Conduct testing for a hazardous air pollutant (HAP) emissions from a drying oven and a periodic (Bell) kiln used to manufacture resin-bonded refractories at the the North American Refractories Company facility in Womelsdorf, Pennsylvania.
| epa | 2024-06-07T20:31:40.697406 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0049/content.txt"
} |
EPA-HQ-OAR-2002-0088-0173 | Supporting & Related Material | "2002-02-08T05:00:00" | null | epa | 2024-06-07T20:31:40.713520 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0173/content.txt"
} |
|
EPA-HQ-OAR-2002-0088-0175 | Supporting & Related Material | "2002-02-08T05:00:00" | null | epa | 2024-06-07T20:31:40.714222 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0175/content.txt"
} |
|
EPA-HQ-OAR-2002-0088-0179 | Supporting & Related Material | "2002-02-08T05:00:00" | null | epa | 2024-06-07T20:31:40.715195 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0179/content.txt"
} |
|
EPA-HQ-OAR-2002-0088-0195 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Letter regarding information requested on the Womelsdorf facility
| epa | 2024-06-07T20:31:40.717684 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0195/content.txt"
} |
EPA-HQ-OAR-2002-0088-0234 | Supporting & Related Material | "2002-01-28T05:00:00" | null |
Comment Info: =================
General Comment:This document concerns anhydrol solvent special, PM-4061, 190 Proof. The PDF was deleted in accordance with Agency direction. To review this document, please contact the EPA Docket Center or the Air Docket.
| epa | 2024-06-07T20:31:40.723655 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0234/content.txt"
} |
EPA-HQ-OAR-2002-0088-0242 | Supporting & Related Material | "2002-01-28T05:00:00" | null | epa | 2024-06-07T20:31:40.724439 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0242/content.txt"
} |
|
EPA-HQ-OAR-2002-0088-0244 | Supporting & Related Material | "2002-01-28T05:00:00" | null | epa | 2024-06-07T20:31:40.725185 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0244/content.txt"
} |
|
EPA-HQ-OAR-2002-0088-0245 | Supporting & Related Material | "2002-01-28T05:00:00" | null | epa | 2024-06-07T20:31:40.725872 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0245/content.txt"
} |
|
EPA-HQ-OAR-2002-0088-0246 | Supporting & Related Material | "2002-01-28T05:00:00" | null | epa | 2024-06-07T20:31:40.726586 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0246/content.txt"
} |
|
EPA-HQ-OAR-2002-0088-0250 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Letter concerning the review of the Refractory Manufacturers spreadsheet.
| epa | 2024-06-07T20:31:40.727262 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0250/content.txt"
} |
EPA-HQ-OAR-2002-0088-0254 | Supporting & Related Material | "2002-02-08T05:00:00" | null | epa | 2024-06-07T20:31:40.727800 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0254/content.txt"
} |
|
EPA-HQ-OAR-2002-0088-0289 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Letter concerning the granting of an extension to answer the Refractories MACT ICR. The PDF was deleted in accordance with Agency direction. To review this document, please contact the EPA Docket Center or Air Docket.
| epa | 2024-06-07T20:31:40.730515 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0289/content.txt"
} |
EPA-HQ-OAR-2002-0088-0409 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Snow Shoe, PA; South Webster, OH; and Washington, PA. Documents include numerous letters, memorandums, and surveys.
| epa | 2024-06-07T20:31:40.731570 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0409/content.txt"
} |
EPA-HQ-OAR-2002-0088-0411 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Documents concerning BMI France response to information collection request
| epa | 2024-06-07T20:31:40.732369 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0411/content.txt"
} |
EPA-HQ-OAR-2002-0088-0412 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:These documents concern pages 686-881of BMI France response to information collection request.
| epa | 2024-06-07T20:31:40.733072 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0412/content.txt"
} |
EPA-HQ-OAR-2002-0088-0413 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:This document concerns pages 882 through 1078 of BMI France response to an information collection request.
| epa | 2024-06-07T20:31:40.733831 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0413/content.txt"
} |
EPA-HQ-OAR-2002-0088-0414 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:This document concerns pages 1293 through 1507 of BMI France response to an information collection request.
| epa | 2024-06-07T20:31:40.734672 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0414/content.txt"
} |
EPA-HQ-OAR-2002-0088-0415 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:This document concerns pages 1508 through 1721 of BMI France response to an information collection request.
| epa | 2024-06-07T20:31:40.735435 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0415/content.txt"
} |
EPA-HQ-OAR-2002-0088-0416 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:This document concerns pages 1723 through 1957 of BMI France response of information collection request.
| epa | 2024-06-07T20:31:40.736165 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0416/content.txt"
} |
EPA-HQ-OAR-2002-0088-0417 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:This section concerns pages 1958 through 2157 of BMI France response to an information collection request.
| epa | 2024-06-07T20:31:40.736929 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0417/content.txt"
} |
EPA-HQ-OAR-2002-0088-0418 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:This document is a continuation of the previous document OAR-2002-0088-0417. This document concerns pages 2158 through 2341 of BMI France response to an information collection request.
| epa | 2024-06-07T20:31:40.737605 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0418/content.txt"
} |
EPA-HQ-OAR-2002-0088-0419 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:These documents concern pages 2342 through 2553 of BMI France response to an information collection request.
| epa | 2024-06-07T20:31:40.738460 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0419/content.txt"
} |
EPA-HQ-OAR-2002-0088-0420 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:These documents are continuation of document OAR-2002-0088-0419. They concern pages 2554 through 2747 of BMI France response to an information collection request.
| epa | 2024-06-07T20:31:40.739135 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0420/content.txt"
} |
EPA-HQ-OAR-2002-0088-0422 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:This document concerns pages 2946 through 3149 of BMI France response to an information collection request.
| epa | 2024-06-07T20:31:40.739963 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0422/content.txt"
} |
EPA-HQ-OAR-2002-0088-0423 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:This document concerns pages 3150 through 3348 of BMI France response to an information collection request.
| epa | 2024-06-07T20:31:40.740699 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0423/content.txt"
} |
EPA-HQ-OAR-2002-0088-0424 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:This document concerns pages 3349 through 3505 of BMI France response to an information collection request.
| epa | 2024-06-07T20:31:40.741552 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0424/content.txt"
} |
EPA-HQ-OAR-2002-0088-0425 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Letter and supporting documents concern pages 1 through 213 of 457 concerning an ICR regarding hazardous air pollutants for American Premier, Inc. operations.
| epa | 2024-06-07T20:31:40.742296 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0425/content.txt"
} |
EPA-HQ-OAR-2002-0088-0426 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Report and Project Number L4604.03 prepared by Environmental Resources Management. This document concerns pages 214 through 290 of 457 concerning an ICR request regarding hazardous air pollutants for American Premier, Inc. operations.
| epa | 2024-06-07T20:31:40.743009 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0426/content.txt"
} |
EPA-HQ-OAR-2002-0088-0427 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Report prepared by Environmental Resources Management for American Premier, Inc (pages 292 through 375). Four large charts were not scanned into the system. To review these documents, please contact the EPA Docket Center or the Air Docket.
| epa | 2024-06-07T20:31:40.743768 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0427/content.txt"
} |
EPA-HQ-OAR-2002-0088-0428 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Supporting documents included are from pages 376 through 457 of 457 pages concerning an ICR regarding hazardous air pollutants for American Premier, Inc. operations.
| epa | 2024-06-07T20:31:40.744623 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0428/content.txt"
} |
EPA-HQ-OAR-2002-0088-0429 | Supporting & Related Material | "2002-02-08T05:00:00" | null |
Comment Info: =================
General Comment:Letter and supporting documents concern refractories operations for Zircoa with Material Data Safety Sheets for raw materials Ohio USEPA permits.
| epa | 2024-06-07T20:31:40.745329 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0088-0429/content.txt"
} |
EPA-HQ-OAR-2002-0093-0001 | Proposed Rule | "2002-12-24T05:00:00" | National Emission Standards for Hazardous Air Pollutants: Surface Coating of Automobiles and Light-Duty Trucks | Tuesday,
December
24,
2002
Part
III
Environmental
Protection
Agency
40
CFR
Parts
63,
264,
and
265
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Surface
Coating
of
Automobiles
and
Light
Duty
Trucks;
Proposed
Rule
VerDate
0ct<
31>
2002
20:
02
Dec
23,
2002
Jkt
200001
PO
00000
Frm
00001
Fmt
4717
Sfmt
4717
E:\
FR\
FM\
24DEP2.
SGM
24DEP2
78612
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
63,
264,
and
265
[
FRL
7418
4]
RIN
2060
AG99
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Surface
Coating
of
Automobiles
and
Light
Duty
Trucks
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Proposed
rule;
amendments.
SUMMARY:
This
action
proposes
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
automobile
and
light
duty
truck
surface
coating
operations
located
at
major
sources
of
hazardous
air
pollutants
(
HAP).
The
proposed
NESHAP
would
implement
section
112(
d)
of
the
Clean
Air
Act
(
CAA)
by
requiring
these
operations
to
meet
HAP
emission
standards
reflecting
the
application
of
the
maximum
achievable
control
technology
(
MACT).
The
primary
HAP
emitted
by
these
operations
are
toluene,
xylene,
glycol
ethers,
methyl
ethyl
ketone
(
MEK),
methyl
isobutyl
ketone
(
MIBK),
ethylbenzene,
and
methanol.
The
proposed
rule
would
reduce
nationwide
HAP
emissions
from
these
major
sources
by
about
60
percent.
This
action
also
proposes
to
amend
the
Air
Emission
Standards
for
Equipment
Leaks
for
owners
and
operators
of
hazardous
waste
treatment,
storage,
and
disposal
facilities
to
exempt
certain
activities
covered
by
the
proposed
NESHAP
from
these
standards.
DATES:
Comments.
Submit
comments
on
or
before
February
7,
2003.
Public
Hearing.
If
anyone
contacts
EPA
requesting
to
speak
at
a
public
hearing,
they
should
do
so
by
January
3,
2003.
If
requested,
a
public
hearing
will
be
held
approximately
15
days
after
the
date
of
publication
of
this
document
in
the
Federal
Register.
ADDRESSES:
Comments.
By
U.
S.
Postal
Service,
written
comments
should
be
submitted
(
in
duplicate
if
possible)
to:
Office
of
Air
and
Radiation
Docket
and
Information
Center
(
6102T),
Attention
Docket
Number
A
2001
22,
U.
S.
EPA,
1200
Pennsylvania
Avenue,
NW,
Washington,
DC
20460.
In
person
or
by
courier,
deliver
comments
(
in
duplicate
if
possible)
to:
Office
of
Air
and
Radiation
Docket
and
Information
Center
(
6102T),
Attention
Docket
Number
A
2001
22,
U.
S.
EPA,
1301
Constitution
Avenue,
NW.,
Room
B102,
Washington,
DC
20460.
The
EPA
requests
a
separate
copy
also
be
sent
to
the
contact
person
listed
in
FOR
FURTHER
INFORMATION
CONTACT.
Public
Hearing.
If
a
public
hearing
is
held,
it
will
be
held
at
our
Office
of
Administration
auditorium
in
Research
Triangle
Park,
North
Carolina.
You
should
contact
Ms.
Janet
Eck,
Coatings
and
Consumer
Products
Group,
Emission
Standards
Division
(
C539
03),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711,
telephone
number
(
919)
541
7946
to
request
to
speak
at
a
public
hearing
or
to
find
out
if
a
hearing
will
be
held.
Docket.
Docket
No.
A
2001
22
contains
supporting
information
used
in
developing
the
proposed
standards.
The
docket
is
located
at
the
U.
S.
EPA,
1301
Constitution
Avenue,
NW,
Washington,
DC
20460
in
Room
B108,
and
may
be
inspected
from
8:
30
a.
m.
to
5:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
FOR
FURTHER
INFORMATION
CONTACT:
Mr.
David
Salman,
Coatings
and
Consumer
Products
Group,
Emission
Standards
Division
(
C539
03),
U.
S.
EPA,
Research
Triangle
Park,
NC
27711;
telephone
number
(
919)
541
0859;
facsimile
number
(
919)
541
5689;
electronic
mail
(
e
mail)
address:
salman.
dave@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Comments.
Comments
and
data
may
be
submitted
by
e
mail
to:
a
and
rdocket
epa.
gov.
Electronic
comments
must
be
submitted
as
an
ASCII
file
to
avoid
the
use
of
special
characters
and
encryption
problems
and
will
also
be
accepted
on
disks
in
WordPerfect
file
format.
All
comments
and
data
submitted
in
electronic
form
must
note
the
docket
number:
A
2001
22.
No
confidential
business
information
(
CBI)
should
be
submitted
by
e
mail.
Electronic
comments
may
be
filed
online
at
many
Federal
Depository
Libraries.
Commenters
wishing
to
submit
proprietary
information
for
consideration
must
clearly
distinguish
such
information
from
other
comments
and
clearly
label
it
as
CBI.
Send
submissions
containing
such
proprietary
information
directly
to
the
following
address,
and
not
to
the
public
docket,
to
ensure
that
proprietary
information
is
not
inadvertently
placed
in
the
docket:
Mr.
David
Salman,
c/
o
OAQPS
Document
Control
Officer
(
C404
02),
U.
S.
EPA,
Research
Triangle
Park,
NC
27711.
The
EPA
will
disclose
information
identified
as
CBI
only
to
the
extent
allowed
by
the
procedures
set
forth
in
40
CFR
part
2.
If
no
claim
of
confidentiality
accompanies
a
submission
when
it
is
received
by
the
EPA,
the
information
may
be
made
available
to
the
public
without
further
notice
to
the
commenter.
Public
Hearing.
Persons
interested
in
presenting
oral
testimony
or
inquiring
as
to
whether
a
hearing
is
to
be
held
should
contact
Ms.
Janet
Eck,
Coatings
and
Consumer
Products
Group,
Emission
Standards
Division
(
C539
03),
U.
S.
EPA,
Research
Triangle
Park,
North
Carolina
27711;
telephone
number
(
919)
541
7946.
Persons
interested
in
attending
the
public
hearing
should
also
contact
Ms.
Eck
to
verify
the
time,
date,
and
location
of
the
hearing.
The
public
hearing
will
provide
interested
parties
the
opportunity
to
present
data,
views,
or
arguments
concerning
these
proposed
emission
standards.
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
because
material
is
added
throughout
the
rulemaking
process.
The
docketing
system
is
intended
to
allow
members
of
the
public
and
industries
involved
to
readily
identify
and
locate
documents
so
that
they
can
effectively
participate
in
the
rulemaking
process.
Along
with
the
proposed
and
promulgated
standards
and
their
preambles,
the
contents
of
the
docket
will
serve
as
the
record
in
the
case
of
judicial
review.
(
See
section
307(
d)(
7)(
A)
of
the
CAA.)
The
regulatory
text
and
other
materials
related
to
this
rulemaking
are
available
for
review
in
the
docket
or
copies
may
be
mailed
on
request
from
the
Air
and
Radiation
Docket
and
Information
Center
by
calling
(
202)
566
1742.
A
reasonable
fee
may
be
charged
for
copying
docket
materials.
Worldwide
Web
(
WWW).
In
addition
to
being
available
in
the
docket,
an
electronic
copy
of
this
proposed
rule
will
also
be
available
on
the
WWW
through
the
Technology
Transfer
Network
(
TTN).
Following
signature
by
the
EPA
Administrator,
a
copy
of
the
proposed
rule
will
be
posted
on
the
TTN's
policy
and
guidance
page
for
newly
proposed
or
promulgated
rules
at
http://
www.
epa.
gov/
ttn/
oarpg.
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
more
information
regarding
the
TTN
is
needed,
call
the
TTN
HELP
line
at
(
919)
541
5384.
Regulated
Entities.
Categories
and
entities
potentially
regulated
by
this
action
are
listed
in
Table
1.
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No.
247
/
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December
24,
2002
/
Proposed
Rules
TABLE
1.
CATEGORIES
AND
ENTITIES
POTENTIALLY
REGULATED
BY
THE
PROPOSED
STANDARDS
Category
NAICS
Examples
of
potentially
regulated
entities
Industry
......................................
336111
336112
336211
Automobile
and
light
duty
truck
assembly
plants,
producers
of
automobile
and
light
duty
truck
bodies.
This
table
is
not
intended
to
be
exhaustive,
but
rather
provides
a
guide
for
readers
regarding
entities
likely
to
be
regulated
by
this
action.
To
determine
whether
your
coating
operation
is
regulated
by
this
action,
you
should
examine
the
applicability
criteria
in
section
§
63.3081
of
the
proposed
rule.
If
you
have
any
questions
regarding
the
applicability
of
this
action
to
a
particular
entity,
consult
the
person
listed
in
the
preceding
FOR
FURTHER
INFORMATION
CONTACT
section.
Outline.
The
information
presented
in
this
preamble
is
organized
as
follows:
I.
Background
A.
What
is
the
source
of
authority
for
development
of
NESHAP?
B.
What
criteria
are
used
in
the
development
of
NESHAP?
C.
What
are
the
health
effects
associated
with
HAP
emissions
from
automobile
and
light
duty
truck
surface
coating?
II.
Summary
of
the
Proposed
Rule
A.
What
source
categories
are
affected
by
this
proposed
rule?
B.
What
is
the
relationship
to
other
rules?
C.
What
are
the
primary
sources
of
emissions
and
what
are
the
emissions?
D.
What
is
the
affected
source?
E.
What
are
the
emission
limits,
operating
limits,
and
other
standards?
F.
What
are
the
testing
and
initial
compliance
requirements?
G.
What
are
the
continuous
compliance
provisions?
H.
What
are
the
notification,
recordkeeping,
and
reporting
requirements?
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
did
we
select
the
source
category?
B.
How
did
we
select
the
regulated
pollutants?
C.
How
did
we
select
the
affected
source?
D.
How
did
we
determine
the
basis
and
level
of
the
proposed
standards
for
existing
and
new
sources?
E.
How
did
we
select
the
format
of
the
proposed
standards?
F.
How
did
we
select
the
testing
and
initial
compliance
requirements?
G.
How
did
we
select
the
continuous
compliance
requirements?
H.
How
did
we
select
the
notification,
recordkeeping,
and
reporting
requirements?
I.
How
did
we
select
the
compliance
date?
IV.
Summary
of
Environmental,
Energy,
and
Economic
Impacts
A.
What
are
the
air
quality
impacts?
B.
What
are
the
cost
impacts?
C.
What
are
the
economic
impacts?
D.
What
are
the
non
air
health,
environmental,
and
energy
impacts?
E.
Can
we
achieve
the
goals
of
the
proposed
rule
in
a
less
costly
manner?
V.
How
will
the
proposed
amendments
to
40
CFR
parts
264
and
265,
subparts
BB
of
the
hazardous
waste
regulations
be
implemented
in
the
States?
A.
Applicability
of
Federal
Rules
in
Authorized
States
B.
Authorization
of
States
for
Today's
Proposed
Amendments
VI.
Solicitation
of
Comments
and
Public
Participation
VII.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
B.
Executive
Order
13132,
Federalism
C.
Executive
Order
13175,
Consultation
and
Coordination
with
Indian
Tribal
Governments
D.
Executive
Order
13045,
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
E.
Executive
Order
13211,
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
F.
Unfunded
Mandates
Reform
Act
of
1995
G.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601,
et
seq.
H.
Paperwork
Reduction
Act
I.
National
Technology
Transfer
and
Advancement
Act
I.
Background
A.
What
is
the
Source
of
Authority
For
Development
of
NESHAP?
Section
112
of
the
CAA
requires
us
to
list
categories
and
subcategories
of
major
sources
and
area
sources
of
HAP
and
to
establish
NESHAP
for
the
listed
source
categories
and
subcategories.
The
Surface
Coating
of
Automobiles
and
Light
duty
Trucks
category
of
major
sources
was
listed
on
July
16,
1992
(
57
FR
31576).
Major
sources
of
HAP
are
those
that
emit
or
have
the
potential
to
emit
equal
to,
or
greater
than,
9.1
megagrams
per
year
(
Mg/
yr)
(
10
tons
per
year
(
tpy))
of
any
one
HAP
or
22.7
Mg/
yr
(
25
tpy)
of
any
combination
of
HAP.
B.
What
Criteria
Are
Used
in
the
Development
of
NESHAP?
Section
112
of
the
CAA
requires
that
we
establish
NESHAP
for
the
control
of
HAP
from
both
new
and
existing
major
sources.
The
CAA
requires
the
NESHAP
to
reflect
the
maximum
degree
of
reduction
in
emissions
of
HAP
that
is
achievable.
This
level
of
control
is
commonly
referred
to
as
the
MACT.
The
MACT
floor
is
the
minimum
control
level
allowed
for
NESHAP
and
is
defined
under
section
112(
d)(
3)
of
the
CAA.
In
essence,
the
MACT
floor
ensures
that
the
standard
is
set
at
a
level
that
assures
that
all
major
sources
achieve
the
level
of
control
at
least
as
stringent
as
that
already
achieved
by
the
better
controlled
and
lower
emitting
sources
in
each
source
category
or
subcategory.
For
new
sources,
the
MACT
floor
cannot
be
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
bestcontrolled
similar
source.
The
MACT
standards
for
existing
sources
can
be
less
stringent
than
standards
for
new
sources,
but
they
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
bestperforming
12
percent
of
existing
sources
in
the
category
or
subcategory
(
or
the
best
performing
five
sources
for
categories
or
subcategories
with
fewer
than
30
sources).
In
developing
MACT,
we
also
consider
control
options
that
are
more
stringent
than
the
floor.
We
may
establish
standards
more
stringent
than
the
floor
based
on
the
consideration
of
cost
of
achieving
the
emissions
reductions,
any
non
air
quality
health
and
environmental
impacts,
and
energy
requirements.
C.
What
Are
the
Health
Effects
Associated
With
HAP
Emissions
From
Automobile
and
Light
Duty
Truck
Surface
Coating?
The
major
HAP
emitted
from
the
automobile
and
light
duty
truck
surface
coating
source
category
are
toluene,
xylene,
glycol
ethers,
MEK,
MIBK,
ethylbenzene,
and
methanol.
These
compounds
account
for
over
95
percent
of
the
nationwide
HAP
emissions
from
this
source
category.
These
pollutants
can
cause
toxic
effects
following
sufficient
exposure.
Some
of
the
potential
toxic
effects
include
effects
to
the
central
nervous
system,
such
as
fatigue,
nausea,
tremors,
and
lack
of
coordination;
adverse
effects
on
the
liver,
kidneys,
and
blood;
respiratory
effects;
and
developmental
effects.
The
degree
of
adverse
effects
to
human
health
from
exposure
to
HAP
can
range
from
mild
to
severe.
The
extent
and
degree
to
which
the
human
health
effects
may
be
experienced
are
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Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
dependent
upon
(
1)
the
ambient
concentration
observed
in
the
area
(
as
influenced
by
emission
rates,
meteorological
conditions,
and
terrain);
(
2)
the
frequency
and
duration
of
exposures;
(
3)
characteristics
of
exposed
individuals
(
genetics,
age,
preexisting
health
conditions,
and
lifestyle),
which
vary
significantly
with
the
population;
and
(
4)
pollutant
specific
characteristics
(
toxicity,
half
life
in
the
environment,
bioaccumulation,
and
persistence).
II.
Summary
of
the
Proposed
Rule
A.
What
Source
Categories
Are
Affected
by
This
Proposed
Rule?
The
proposed
rule
would
apply
to
you
if
you
own
or
operate
an
automobile
and
light
duty
truck
surface
coating
operation
that
is
a
major
source,
or
is
located
at
a
major
source,
or
is
part
of
a
major
source
of
HAP
emissions.
We
have
defined
an
automobile
and
lightduty
truck
surface
coating
operation
as
any
facility
engaged
in
the
surface
coating
of
new
automobile
or
new
lightduty
truck
bodies
or
collections
of
body
parts
for
new
automobiles
or
new
lightduty
trucks.
Coating
operations
included
in
this
source
category
include,
but
are
not
limited
to,
the
application
of
electrodeposition
primer,
primer
surfacer,
topcoat
(
including
basecoat
and
clear
coat),
final
repair,
glass
bonding
primer,
glass
bonding
adhesive,
sealer,
adhesive,
and
deadener.
The
application
of
blackout
and
anti
chip
materials
is
included
in
these
coating
operations,
as
is
the
cleaning
and
purging
of
equipment
associated
with
the
coating
operations.
Automobile
customizers,
body
shops,
and
refinishers
are
excluded
from
this
source
category.
Coating
of
separate,
non
body
miscellaneous
metal
parts
and
separate,
non
body
plastic
parts
that
are
not
attached
to
the
vehicle
body
at
the
time
that
the
coatings
are
applied
to
these
parts
is
excluded
from
this
source
category.
You
would
not
be
subject
to
the
proposed
rule
if
your
coating
operation
is
located
at
an
area
source.
An
area
source
is
any
stationary
source
of
HAP
that
is
not
a
major
source.
You
may
establish
area
source
status
prior
to
the
compliance
date
of
the
final
rule
by
limiting
the
source's
potential
to
emit
HAP
through
appropriate
mechanisms
available
through
the
permitting
authority.
The
source
category
does
not
include
research
or
laboratory
facilities
or
janitorial,
building,
and
facility
maintenance
operations.
We
are
also
proposing
to
amend
the
Resource
Conservation
and
Recovery
Act
(
RCRA)
Air
Emissions
Standards
for
Equipment
Leaks
at
40
CFR
parts
264
and
265,
subparts
BB.
The
amendments
would
exempt
facilities
which
would
otherwise
be
subject
to
requirements
of
subparts
BB
if
they
are
subject
to
the
requirements
of
this
proposed
NESHAP.
Generally,
subparts
BB
of
40
CFR
parts
264
and
265
apply
to
equipment
that
contains
or
contacts
RCRA
hazardous
wastes
with
organic
concentrations
of
at
least
10
percent
by
weight.
The
regulations
apply
to
large
quantity
generators
as
well
as
to
RCRA
treatment,
storage,
and
disposal
facilities.
The
regulations
were
designed
to
minimize
the
potential
for
leaks
from
pumps,
valves,
flanges,
and
connections.
The
work
practice
standards
that
must
be
met
in
this
proposed
NESHAP
in
§
63.3094
address
coating
line
purging
emissions
that
would
result
from
solvent
purging
of
coating
applicators,
and
the
subsequent
collection
and
transmission
of
the
paint/
solvent
mixture
to
reclamation
or
recovery
system.
The
collection
and
transmission
systems
would
potentially
be
subject
to
the
requirements
of
subparts
BB.
To
avoid
duplication,
and
because
any
potential
for
air
releases
from
these
sources
are
relatively
small,
we
are
proposing
that
if
such
a
collection,
transmission,
and
reclamation
or
recovery
system
is
located
at
a
facility
subject
to
this
proposed
NESHAP,
then
it
is
exempt
from
the
requirements
of
subparts
BB
of
40
CFR
parts
264
and
265.
As
stated
elsewhere
in
this
preamble,
the
HAP
emissions
from
these
sources
are
relatively
small
in
comparison
with
the
coating
application,
drying,
and
curing.
Measurements
made
by
industry
indicate
that
emissions
of
VOC
would
be
at
least
two
orders
of
magnitude
less
than
concentrations
that
would
meet
the
definition
of
a
leak
under
subparts
BB
of
40
CFR
parts
264
and
265.
Additionally,
because
the
mixture
is
usually
sold
to
a
solvent
recycler,
the
industry
has
an
incentive
to
capture
as
much
of
the
solvent
as
possible,
and
would
therefore
want
to
repair
any
leaks
as
quickly
as
possible.
In
addition
to
the
coating
operations
covered
under
the
proposed
NESHAP,
some
automobile
and
light
duty
truck
facilities
also
have
separate,
non
body
plastic
parts
coating
operations
or
separate,
non
body
metal
parts
coating
operations.
Purges
from
these
separate,
non
body
plastic
parts
coating
operations
and
separate,
non
body
metal
parts
coatings
operations
are
analogous
to
those
for
automobile
and
light
duty
truck
body
coatings
and
would
also
be
exempt
from
the
requirements
of
subparts
BB
of
40
CFR
parts
264
and
265,
if
the
operations
occur
in
the
same
facility
as
the
automobile
and
light
duty
truck
body
coating.
Many
of
the
coatings
applied
to
separate,
non
body
plastic
and
separate,
non
body
metal
parts
are
similar
in
composition
to
those
applied
to
automobile
and
light
duty
truck
bodies.
The
purged
materials
are
conveyed
to
waste
tanks
in
the
same
fashion
as
the
purged
materials
from
automobile
and
light
duty
truck
body
coating
operations.
B.
What
Is
the
Relationship
to
Other
Rules?
Affected
sources
subject
to
the
proposed
rule
may
also
be
subject
to
other
rules.
Automobile
and
light
duty
truck
surface
coating
operations
that
began
construction,
reconstruction,
or
modification
after
October
5,
1979
are
subject
to
new
source
performance
standards
(
NSPS)
under
40
CFR
part
60,
subpart
MM.
That
rule
limits
emissions
of
volatile
organic
compounds
(
VOC).
The
EPA
has
also
published
control
techniques
guidelines
which
establish
reasonably
available
control
technologies
for
limiting
VOC
emissions
from
automobile
and
light
duty
truck
surface
coating
operations.
Additional
VOC
emission
limitations
may
also
apply
to
these
facilities
through
conditions
incorporated
in
State
operating
permits
and
permits
issued
under
authority
of
title
V
of
the
CAA.
Facilities
in
this
subcategory
may
also
be
subject
to
various
emission
limitations
pursuant
to
State
air
toxics
rules.
An
automobile
and
light
duty
truck
surface
coating
facility
may
be
subject
to
other
NESHAP.
Rules
are
presently
under
development
which
will
limit
emissions
from
coating
operations
conducted
on
separate,
non
body
miscellaneous
metal
parts
and
separate,
non
body
plastic
parts
and
products.
Coating
of
parts
(
such
as
automobile
bumpers,
fascias,
brackets,
etc.)
for
subsequent
attachment
to
vehicle
bodies
would
be
subject
to
one
or
more
of
these
rules,
as
would
collocated
aftermarket
replacement
part
coating
operations.
Facilities
may
also
be
subject
to
other
rules
relating
to
collocated
equipment
such
as
foundries
and
boilers.
The
capture,
transmission,
and
storage
of
purge
materials
from
coating
equipment
may
also
be
subject
to
the
RCRA
Air
Emission
Standards
for
Equipment
Leaks
under
subparts
BB
of
40
CFR
parts
264
and
265.
Those
regulations
apply
to
equipment
that
contains
or
contacts
RCRA
hazardous
waste
with
organic
concentrations
of
at
least
10
percent
by
weight.
To
avoid
such
possible
duplication,
we
are
proposing
to
exempt
such
equipment
from
subparts
BB
if
it
is
located
at
a
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Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
facility
subject
to
this
proposed
NESHAP.
C.
What
Are
the
Primary
Sources
of
Emissions
and
What
Are
the
Emissions?
HAP
emission
sources.
Emissions
from
coating
application,
drying,
and
curing
account
for
most
of
the
HAP
emissions
from
automobile
and
lightduty
truck
surface
coating
operations.
The
remaining
emissions
are
primarily
from
cleaning
of
booths
and
application
equipment
and
purging
of
spray
equipment.
In
most
cases,
HAP
emissions
from
surface
preparation,
storage,
handling,
and
waste/
wastewater
operations
are
relatively
small.
Organic
HAP.
Available
emission
data
collected
during
the
development
of
the
proposed
NESHAP
show
that
the
primary
organic
HAP
emitted
from
automobile
and
light
duty
truck
surface
coating
operations
are
toluene,
xylene,
glycol
ethers,
MEK,
MIBK,
ethylbenzene,
and
methanol.
These
compounds
account
for
over
95
percent
of
the
nationwide
HAP
emissions
from
this
source
category.
Inorganic
HAP.
Based
on
information
reported
during
the
development
of
the
proposed
NESHAP,
lead,
manganese,
and
chromium
are
contained
in
some
of
the
coatings
used
by
this
source
category
but
are
not
likely
to
be
emitted
due
to
the
coating
application
techniques
used.
No
inorganic
HAP
were
reported
in
thinners
or
cleaning
materials.
Most
of
the
inorganic
HAP
components
remain
as
solids
in
the
dry
coating
film
on
the
parts
being
coated,
are
collected
by
the
circulating
water
under
the
spray
booth
floor
grates,
or
are
deposited
on
the
walls,
floor,
and
grates
of
the
spray
booths
and
other
equipment
in
which
they
are
applied.
Therefore,
inorganic
HAP
emission
levels
are
expected
to
be
very
low
and
have
not
been
quantified.
D.
What
Is
the
Affected
Source?
We
define
an
affected
source
as
a
stationary
source,
group
of
stationary
sources,
or
part
of
a
stationary
source
to
which
a
specific
emission
standard
applies.
The
proposed
rule
for
automobile
and
light
duty
truck
surface
coating
defines
the
affected
source
as
all
of
the
equipment
used
to
apply
coating
to
new
automobile
or
new
light
duty
truck
bodies
or
collections
of
body
parts
for
new
automobiles
or
new
light
duty
trucks
and
to
dry
or
cure
the
coating
after
application;
all
storage
containers
and
mixing
vessels
in
which
vehicle
body
coatings,
thinners,
and
cleaning
materials
are
stored
or
mixed;
all
manual
and
automated
equipment
and
containers
used
for
conveying
vehicle
body
coatings,
thinners,
and
cleaning
materials;
and
all
storage
containers
and
all
manual
and
automated
equipment
and
containers
used
for
conveying
waste
materials
generated
by
an
automobile
and
light
duty
truck
surface
coating
operation.
The
affected
source
does
not
include
research
or
laboratory
equipment
or
janitorial,
building,
and
facility
maintenance
operations.
E.
What
Are
the
Emission
Limits,
Operating
Limits,
and
Other
Standards?
Emission
limits.
We
are
proposing
to
limit
organic
HAP
emissions
from
each
new
or
reconstructed
automobile
and
light
duty
truck
surface
coating
facility
using
the
emission
limits
in
Table
2
of
this
preamble.
TABLE
2.
EMISSION
LIMITS
FOR
NEW
OR
RECONSTRUCTED
AFFECTED
SOURCES
(
MONTHLY
AVERAGE)
Operation
Limit
Combined
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair
glass
bonding
primer,
and
glass
bonding
adhesive
operation.
0.036
kilogram
(
kg)
(
0.30
pound
(
lb))
organic
HAP/
liter
(
HAP/
gallon
(
gal))
of
coating
solids
deposited).
Combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operation
(
for
sources
meeting
the
operating
limits
of
§
63.3092(
a)
and
(
b)).
0.060
kg
(
0.50
lb
organic
HAP/
1iter
(
HAP/
gal)
of
coating
solids
deposited
Adhesives
and
sealers,
other
than
glass
bonding
adhesive
...................
0.010
kg/
kg
(
lb/
lb)
of
material
used.
Deadener
..................................................................................................
0.010
kg/
kg
(
lb/
lb)
of
material
used.
We
are
proposing
to
limit
organic
HAP
emissions
from
each
existing
automobile
and
light
duty
truck
surface
coating
facility
using
the
emission
limits
in
Table
3
of
this
preamble.
TABLE
3.
EMISSION
LIMITS
FOR
EXISTING
AFFECTED
SOURCES
(
MONTHLY
AVERAGE)
Operation
Limit
Combined
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair
glass
bonding
primer,
and
glass
bonding
adhesive
operation.
0.072
kg
(
0.60
lb)
organic
HAP/
liter
(
HAP/
gal)
of
coating
deposited.
Combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operation
(
for
sources
meeting
the
operating
limits
of
§
63.3092(
a)
and
(
b)).
0.132
kg
(
1.10
lb)
organic
HAP/
liter
(
HAP/
gal)
of
coating
solids
deposited
Adhesives
and
sealers
other
than
glass
bonding
adhesive
....................
0.010
kg/
kg
(
lb/
lb)
of
material
used.
Deadener.
.................................................................................................
0.010
lb/
lb
(
kg/
kg)
of
material
used.
You
would
calculate
emissions
from
combined
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations,
or
from
combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations
using
the
procedures
in
the
proposed
rule,
which
account
for
variable
organic
HAP
contents
of
the
materials
applied
in
each
month,
as
well
as
transfer
efficiency
and
overall
efficiencies
of
any
capture
systems
and
control
devices
in
use.
You
would
average
organic
HAP
contents
of
other
materials
used
on
a
monthly
basis
to
determine
separately
those
emissions
from
sealers
and
adhesives
(
other
than
glass
bonding
adhesive),
and
deadeners.
Operating
limits.
If
you
use
an
emission
capture
and
control
system
to
reduce
emissions,
the
proposed
operating
limits
would
apply
to
you.
These
proposed
operating
limits
are
site
specific
parameter
limits
you
determine
during
the
initial
performance
test
of
the
system.
For
capture
systems,
you
would
identify
the
parameter(
s)
to
monitor
and
establish
the
limits
and
monitoring
procedures.
For
thermal
and
catalytic
oxidizers,
you
would
establish
temperature
limits.
For
solvent
recovery
systems,
you
would
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Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
monitor
the
outlet
concentration
or
carbon
bed
temperature
and
the
amount
of
steam
or
nitrogen
used
to
desorb
the
bed.
All
operating
limits
must
reflect
operation
of
the
capture
and
control
system
during
a
performance
test
that
demonstrates
achievement
of
the
emission
limit
during
representative
operating
conditions.
Work
practice
standards.
You
would
have
to
develop
and
implement
a
work
practice
plan
to
minimize
organic
HAP
emissions
from
the
storage,
mixing,
and
conveying
of
coatings,
thinners,
and
cleaning
materials
used
in
and
waste
materials
generated
by
all
coating
operations
for
which
emission
limits
are
proposed.
The
plan
would
have
to
specify
practices
and
procedures
to
ensure
that,
at
a
minimum,
the
following
elements
are
implemented:
All
organic
HAP
containing
coatings,
thinners,
cleaning
materials,
and
waste
materials
must
be
stored
in
closed
containers.
The
risk
of
spills
of
organic
HAPcontaining
coatings,
thinners,
cleaning
materials,
and
waste
materials
must
be
minimized.
Organic
HAP
containing
coatings,
thinners,
cleaning
materials,
and
waste
materials
must
be
conveyed
from
one
location
to
another
in
closed
containers
or
pipes.
Mixing
vessels,
other
than
day
tanks
equipped
with
continuous
agitation
systems,
which
contain
organic
HAP
containing
coatings
and
other
materials
must
be
closed
except
when
adding
to,
removing,
or
mixing
the
contents.
Emissions
of
organic
HAP
must
be
minimized
during
cleaning
of
storage,
mixing,
and
conveying
equipment.
You
would
also
have
to
develop
and
implement
a
work
practice
plan
to
minimize
organic
HAP
emissions
from
cleaning
and
from
purging
of
equipment
associated
with
all
coating
operations
for
which
emission
limits
are
proposed.
The
plan
would
have
to
specify
practices
and
procedures
to
ensure
that
emissions
of
HAP
from
the
following
operations
are
minimized:
Vehicle
body
wiping;
Coating
line
purging;
Flushing
of
coating
systems;
Cleaning
of
spray
booth
grates;
Cleaning
of
spray
booth
walls;
Cleaning
of
spray
booth
equipment;
Cleaning
external
spray
booth
areas;
and
Other
housekeeping
measures
(
e.
g.,
keeping
solvent
laden
rags
in
closed
containers.)
General
Provisions.
The
General
Provisions
(
40
CFR
part
63,
subpart
A)
also
would
apply
to
you
as
outlined
in
table
2
of
the
proposed
rule.
The
General
Provisions
codify
certain
procedures
and
criteria
for
all
40
CFR
part
63
NESHAP.
The
General
Provisions
contain
administrative
procedures,
preconstruction
review
procedures
for
new
sources,
and
procedures
for
conducting
compliancerelated
activities
such
as
notifications,
recordkeeping
and
reporting,
performance
testing,
and
monitoring.
The
proposed
rule
refers
to
individual
sections
of
the
General
Provisions
to
emphasize
key
sections
that
you
should
be
aware
of.
However,
unless
specifically
overridden
in
table
2
of
the
proposed
rule,
all
of
the
applicable
General
Provisions
requirements
would
apply
to
you.
F.
What
Are
the
Testing
and
Initial
Compliance
Requirements?
Compliance
dates.
Existing
affected
sources
would
have
to
be
in
compliance
with
the
final
standards
no
later
than
3
years
after
the
effective
date.
The
effective
date
is
the
date
on
which
the
final
rule
is
published
in
the
Federal
Register.
New
and
reconstructed
sources
would
have
to
be
in
compliance
upon
startup
of
the
affected
source
or
by
the
effective
date
of
the
final
rule,
whichever
is
later.
Compliance
with
the
emission
limits
is
based
on
a
monthly
organic
HAP
emission
rate.
The
initial
compliance
period,
therefore,
is
the
1
month
period
beginning
on
the
compliance
date.
If
the
compliance
date
occurs
on
any
day
other
than
the
first
day
of
a
month,
then
the
initial
compliance
period
begins
on
the
compliance
date
and
extends
through
the
end
of
that
month
plus
the
following
month.
We
have
defined
``
month''
as
a
calendar
month
or
a
prespecified
period
of
28
to
35
days
to
allow
for
flexibility
at
sources
where
data
are
based
on
a
business
accounting
period.
Being
``
in
compliance''
means
that
the
owner
or
operator
of
the
affected
source
meets
all
the
requirements
of
the
proposed
rule
to
achieve
the
emission
limit(
s)
and
operating
limits
by
the
end
of
the
initial
compliance
period,
and
that
the
facility
is
operated
in
accordance
with
the
approved
work
practice
plans.
At
the
end
of
the
initial
compliance
period,
the
owner
or
operator
would
use
the
data
and
records
generated
to
determine
whether
or
not
the
affected
source
is
in
compliance
for
that
period.
If
it
does
not
meet
the
applicable
limit(
s),
then
it
is
out
of
compliance
for
the
entire
initial
compliance
period.
Emission
limits.
Compliance
with
the
emission
limit
for
combined
electrodeposition
primer,
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive,
or
the
emission
limit
for
combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
would
be
based
on
mass
organic
HAP
emissions
per
volume
of
applied
coating
solids
as
calculated
monthly
using
the
procedures
in
the
proposed
rule.
Compliance
with
the
emission
limits
for
adhesives
and
sealers
(
other
than
glass
bonding
adhesive)
and
deadener
would
be
based
on
mass
average
organic
HAP
content
of
materials
used
each
month.
Electrodeposition
primer,
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive.
Compliance
with
this
emission
limit,
or
if
eligible,
with
the
emission
limit
for
combined
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive,
is
based
on
the
calculations
in
the
proposed
rule.
You
may
also
use
the
guidelines
presented
in
``
Protocol
for
Determining
Daily
Volatile
Organic
Compound
Emission
Rate
of
Automobile
and
Light
Duty
Truck
Topcoat
Operations,''
EPA
450/
3
88
018
(
docket
A
2001
22).
To
determine
the
organic
HAP
content,
the
volume
solids,
and
the
density
of
the
coatings
and
thinners,
you
could
rely
on
manufacturer's
data,
results
from
the
test
methods
listed
below,
or
alternative
test
methods
for
which
you
get
EPA
approval
on
a
caseby
case
basis
according
to
the
NESHAP
General
Provisions
in
40
CFR
63.7(
f).
However,
if
there
is
any
inconsistency
between
the
test
results
and
manufacturer's
data,
the
test
results
would
prevail
for
compliance
and
enforcement
purposes.
For
organic
HAP
content,
use
Method
311
of
40
CFR
part
63,
appendix
A.
The
proposed
rule
allows
you
to
use
nonaqueous
volatile
matter
as
a
surrogate
for
organic
HAP.
If
you
choose
this
option,
then
use
Method
24
of
40
CFR
part
60,
appendix
A.
For
volume
fraction
of
coating
solids,
use
either
ASTM
Method
D2697
86
(
1968)
or
ASTM
Method
D6093
97.
For
density,
use
ASTM
Method
D1475
98
or
information
from
the
supplier
or
manufacturer
of
the
material.
For
each
emission
capture
and
control
system
that
you
use,
you
would:
Conduct
an
initial
performance
test
to
determine
the
overall
control
efficiency
of
the
equipment
(
described
below)
and
to
establish
operating
limits
to
be
achieved
on
a
continuous
basis
(
also
described
below).
The
performance
test
would
have
to
be
completed
no
later
than
the
compliance
date.
You
would
also
need
to
schedule
it
in
time
to
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78617
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
obtain
the
results
for
use
in
completing
your
initial
compliance
determination
for
the
initial
compliance
period.
The
overall
control
efficiency
for
a
capture
and
control
system
would
be
demonstrated
based
on
emission
capture
and
reduction
efficiency.
To
determine
the
capture
efficiency,
you
would
either
verify
the
presence
of
a
permanent
total
enclosure
using
EPA
Method
204
of
40
CFR
part
51;
measure
the
capture
efficiency
using
either
EPA
Method
204A
through
F
of
40
CFR
part
51
or
appendix
A
of
40
CFR
part
63,
subpart
KK;
or
use
the
panel
test
procedures
in
ASTM
Method
D5087
91
(
1994),
ASTM
Method
D6266
00a,
or
the
guidelines
presented
in
``
Protocol
for
Determining
Daily
Volatile
Organic
Compound
Emission
Rate
of
Automobile
and
Light
Duty
Truck
Topcoat
Operations,''
EPA
450/
3
88
018
(
docket
A
2001
22).
If
you
have
a
permanent
total
enclosure
and
you
route
all
exhaust
gases
from
the
enclosure
to
a
control
device,
then
you
would
assume
100
percent
capture.
For
panel
testing,
the
coatings
used
may
be
grouped
based
on
similar
appearance
characteristics
(
e.
g.,
solid
color
or
metallic),
processing
sequences,
and
dry
film
thicknesses.
One
coating
from
each
group
can
be
tested
to
represent
all
of
the
coatings
in
that
group.
To
determine
the
emission
reduction
efficiency
of
the
control
device,
you
would
conduct
measurements
of
the
inlet
and
outlet
gas
streams.
The
test
would
consist
of
three
runs,
each
run
lasting
1
hour,
using
the
following
EPA
Methods
in
40
CFR
part
60,
appendix
A:
Method
1
or
1A
for
selection
of
the
sampling
sites.
Method
2,
2A,
2C,
2D,
2F,
or
2G
to
determine
the
gas
volumetric
flow
rate.
Method
3,
3A,
or
3B
for
gas
analysis
to
determine
dry
molecular
weight.
Method
4
to
determine
stack
moisture.
Method
25
or
25A
to
determine
organic
volatile
matter
concentration.
Alternatively,
any
other
test
method
or
data
that
have
been
validated
according
to
the
applicable
procedures
in
Method
301
of
40
CFR
part
63,
appendix
A,
and
approved
by
the
Administrator,
could
be
used.
You
would
be
required
to
determine
the
transfer
efficiency
for
primersurfacer
and
topcoat
materials
using
ASTM
Method
D5066
91
(
2001)
or
the
guidelines
presented
in
``
Protocol
for
Determining
Daily
Volatile
Organic
Compound
Emission
Rate
of
Automobile
and
Light
Duty
Truck
Topcoat
Operations,''
EPA
450/
3
88
018
(
docket
A
2001
22).
These
guidelines
include
provisions
for
testing
representative
coatings
instead
of
testing
every
coating.
You
may
assume
100
percent
transfer
efficiency
for
electrodeposition
primer
coatings,
glass
bonding
primers,
and
glass
bonding
adhesives.
For
final
repair
coatings,
you
may
assume
40
percent
transfer
efficiency
for
air
atomized
spray
and
55
percent
transfer
efficiency
for
electrostatic
spray
and
high
volume,
low
pressure
spray.
The
monthly
emission
rate,
in
terms
of
mass
of
organic
HAP
emitted
per
volume
of
coating
solids
deposited,
is
determined
in
accordance
with
the
procedures
in
the
proposed
rule.
These
procedures
incorporate
the
volume,
organic
HAP
content,
and
volume
solids
content
of
each
coating
applied,
as
well
as
the
transfer
efficiency
for
the
coatings
and
spray
equipment
used,
and
the
overall
control
efficiency
for
controlled
booths
or
bake
ovens
and
other
controlled
emission
points.
Adhesives
and
sealers,
and
deadener.
Compliance
with
emissions
limits
for
adhesives
and
sealers
(
other
than
windshield
materials)
would
be
based
on
the
monthly
mass
average
organic
HAP
content
of
all
materials
of
this
type
used
during
the
compliance
period.
Compliance
with
emission
limits
for
deadener
would
be
based
on
the
monthly
mass
average
organic
HAP
content
of
all
materials
of
this
type
used
during
the
compliance
period.
Operating
limits.
As
mentioned
above,
you
would
establish
operating
limits
during
the
initial
performance
test
of
an
emission
capture
and
control
system.
The
operating
limit
is
defined
as
the
minimum
or
maximum
(
as
applicable)
value
achieved
for
a
control
device
or
process
parameter
during
the
most
recent
performance
test
that
demonstrated
compliance
with
the
emission
limit.
The
proposed
rule
specifies
the
parameters
to
monitor
for
the
types
of
control
systems
commonly
used
in
the
industry.
You
would
be
required
to
install,
calibrate,
maintain,
and
continuously
operate
all
monitoring
equipment
according
to
manufacturer's
specifications
and
ensure
that
the
continuous
parameter
monitoring
systems
(
CPMS)
meet
the
requirements
in
§
63.3168
of
the
proposed
rule.
If
you
use
control
devices
other
than
those
identified
in
the
proposed
rule,
you
would
submit
the
operating
parameters
to
be
monitored
to
the
Administrator
for
approval.
The
authority
to
approve
the
parameters
to
be
monitored
is
retained
by
EPA
and
is
not
delegated
to
States.
If
you
use
a
thermal
or
catalytic
oxidizer,
you
would
continuously
monitor
temperature
and
record
it
at
least
every
15
minutes.
For
thermal
oxidizers,
the
temperature
monitor
is
placed
in
the
firebox
or
in
the
duct
immediately
downstream
of
the
firebox
before
any
substantial
heat
exchange
occurs.
The
operating
limit
would
be
the
average
temperature
measured
during
the
performance
test
and
for
each
3
hour
period,
the
average
temperature
would
have
to
be
at
or
above
this
limit.
For
catalytic
oxidizers,
temperature
monitors
are
placed
immediately
before
and
after
the
catalyst
bed.
The
operating
limit
would
be
the
average
temperature
increase
across
the
catalyst
bed
during
the
performance
test
and
for
each
3
hour
period,
the
average
temperature
increase
would
have
to
be
at
or
above
this
limit.
As
an
alternative
for
catalytic
oxidizers,
you
may
monitor
the
temperature
immediately
before
the
catalyst
bed
and
develop
and
implement
an
inspection
and
maintenance
plan.
If
you
use
a
solvent
recovery
system,
then
you
would
either:
(
1)
Continuously
monitor
the
outlet
concentration
of
organic
compounds,
and
the
operating
limit
would
be
the
average
organic
compound
outlet
concentration
during
the
performance
test
(
for
each
3
hour
period,
the
average
concentration
would
have
to
be
below
this
limit);
or
(
2)
monitor
the
carbon
bed
temperature
after
each
regeneration
and
the
total
amount
of
steam
or
nitrogen
used
to
desorb
the
bed
for
each
regeneration,
in
which
case
the
operating
limits
would
be
the
carbon
bed
temperature
(
not
to
be
exceeded)
and
the
amount
of
steam
or
nitrogen
used
for
desorption
(
to
be
met
as
a
minimum).
If
you
use
a
capture
and
control
system
to
meet
the
proposed
standards,
you
would
have
to
meet
operating
limits
for
the
capture
system.
If
the
emission
capture
system
is
a
permanent
total
enclosure,
you
would
be
required
to
establish
that
the
direction
of
flow
was
into
the
enclosure
at
all
times.
In
addition,
you
would
have
to
meet
an
operating
limit
of
either
an
average
facial
velocity
of
at
least
61
meters
per
minute
(
200
feet
per
minute)
through
all
natural
draft
openings
in
the
enclosure,
or
a
minimum
pressure
drop
across
the
enclosure
of
at
least
0.018
millimeter
water
(
0.007
inch
water),
as
established
by
Method
204
of
appendix
M
to
40
CFR
part
51.
If
the
emission
capture
system
was
not
a
permanent
total
enclosure,
you
would
have
to
establish
either
the
average
volumetric
flow
rate
or
the
duct
static
pressure
in
each
duct
between
the
capture
device
and
the
add
on
control
device
inlet
during
the
performance
test.
Either
the
average
volumetric
flow
rate
would
have
to
be
maintained
above
the
operating
limit
for
each
3
hour
period
or
the
average
duct
static
pressure
would
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Vol.
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/
Tuesday,
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24,
2002
/
Proposed
Rules
have
to
be
maintained
above
the
operating
limit
for
each
3
hour
period.
Work
practice
standards.
You
would
have
to
develop
and
implement
two
site
specific
work
practice
plans.
One
plan
would
address
practices
to
minimize
organic
HAP
emissions
from
storage,
mixing,
and
conveying
of
coatings,
thinners,
and
cleaning
materials
used
in
operations
for
which
emission
limits
are
established,
as
well
as
the
waste
materials
generated
from
these
operations.
A
second
site
specific
work
practice
plan
would
address
practices
to
minimize
emissions
from
cleaning
operations
and
purging
of
coating
equipment.
The
plans
would
have
to
address
specific
types
of
potential
organic
HAP
emission
points
and
are
subject
to
approval
of
the
Administrator.
Deviations
from
approved
work
practice
plans
would
be
reported
semiannually.
G.
What
Are
the
Continuous
Compliance
Provisions?
Emission
limits.
Continuous
compliance
with
the
emission
limit
for
combined
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive,
or
if
eligible,
the
emission
limit
for
combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive,
would
be
based
on
monthly
calculations
following
the
procedures
in
the
proposed
rule.
These
procedures
take
into
account
the
amount
of
each
coating
used,
the
organic
HAP
and
volume
solids
content
of
each
coating
used,
the
transfer
efficiency
of
each
coating
application
system,
and
the
organic
HAP
abatement
from
each
capture
and
control
system,
and
provide
for
calculating
monthly
mass
organic
HAP
emissions
per
volume
of
coating
solids
deposited.
Continuous
compliance
with
the
emission
limits
for
adhesives
and
sealers
(
other
than
components
of
the
windshield
adhesive
system),
and
deadener
is
based
on
the
monthly
average
mass
organic
HAP
concentration
of
all
materials
applied
in
each
category.
Operating
limits.
If
you
use
an
emission
capture
and
control
system,
the
proposed
rule
would
require
you
to
achieve
on
a
continuous
basis
the
operating
limits
you
establish
during
the
performance
test.
If
the
continuous
monitoring
shows
that
the
system
is
operating
outside
the
range
of
values
established
during
the
performance
test,
then
you
have
deviated
from
the
established
operating
limits.
If
you
operate
a
capture
and
control
system
that
allows
emissions
to
bypass
the
control
device,
you
would
have
to
demonstrate
that
HAP
emissions
from
each
emission
point
within
the
affected
source
are
being
routed
to
the
control
device
by
monitoring
for
potential
bypass
of
the
control
device.
You
may
choose
from
the
following
four
monitoring
procedures:
(
1)
Flow
control
position
indicator
to
provide
a
record
of
whether
the
exhaust
stream
is
directed
to
the
control
device;
(
2)
Car
seal
or
lock
and
key
valve
closures
to
secure
the
bypass
line
valve
in
the
closed
position
when
the
control
device
is
operating;
(
3)
Valve
closure
continuous
monitoring
to
ensure
any
bypass
line
valve
or
damper
is
closed
when
the
control
device
is
operating;
or
(
4)
Automatic
shutdown
system
to
stop
the
coating
operation
when
flow
is
diverted
from
the
control
device.
If
the
continuous
control
device
bypass
monitoring
shows
that
the
control
device
is
bypassed,
then
you
have
deviated
from
the
established
operating
limits.
Operations
during
startup,
shutdown,
and
malfunction.
When
using
an
emission
capture
and
control
system
for
compliance,
you
would
be
required
to
develop
and
operate
according
to
a
startup,
shutdown,
and
malfunction
plan
during
periods
of
startup,
shutdown,
and
malfunction
of
the
capture
and
control
system.
Work
practice
standards.
You
would
be
required
to
operate
your
facility
in
accordance
with
your
approved
sitespecific
work
practice
plans
at
all
times.
H.
What
Are
the
Notification,
Recordkeeping,
and
Reporting
Requirements?
You
are
required
to
comply
with
the
applicable
requirements
in
the
NESHAP
General
Provisions,
subpart
A
of
40
CFR
part
63,
as
described
in
Table
2
of
the
proposed
rule.
The
General
Provisions
notification
requirements
include:
initial
notifications,
notification
of
performance
test
if
you
are
complying
by
using
a
capture
and
control
system,
notification
of
compliance
status,
and
additional
notifications
required
for
affected
sources
with
continuous
monitoring
systems.
The
General
Provisions
also
require
certain
records
and
periodic
reports.
Initial
notifications.
If
the
standards
apply
to
you,
you
must
send
a
notification
to
the
EPA
Regional
Office
in
the
region
where
your
facility
is
located
and
to
your
State
agency
at
least
1
year
before
the
compliance
date
for
existing
sources,
and
within
120
days
after
the
date
of
initial
startup
for
new
and
reconstructed
sources,
or
120
days
after
publication
of
the
final
rule
in
the
Federal
Register,
whichever
is
later.
That
report
notifies
us
and
your
State
agency
that
you
have
an
existing
facility
that
is
subject
to
the
proposed
standards
or
that
you
have
constructed
a
new
facility.
Thus,
it
allows
you
and
the
permitting
authority
to
plan
for
compliance
activities.
You
would
also
need
to
send
a
notification
of
planned
construction
or
reconstruction
of
a
source
that
would
be
subject
to
the
proposed
rule
and
apply
for
approval
to
construct
or
reconstruct.
Notification
of
performance
test.
If
you
demonstrate
compliance
by
using
a
capture
and
control
system
for
which
you
do
not
conduct
a
monthly
liquidliquid
material
balance,
you
would
conduct
a
performance
test
no
later
than
the
compliance
date
for
your
affected
source.
You
must
notify
us
(
or
the
delegated
State
or
local
agency)
at
least
60
calendar
days
before
the
performance
test
is
scheduled
to
begin
as
indicated
in
the
General
Provisions
for
the
NESHAP.
Notification
of
compliance
status.
You
would
send
us
a
notification
of
compliance
status
within
30
days
after
the
end
of
the
initial
compliance
demonstration.
In
the
notification,
you
would
certify
whether
the
affected
source
has
complied
with
the
proposed
standards;
summarize
the
data
and
calculations
supporting
the
compliance
demonstration;
describe
how
you
will
determine
continuous
compliance;
and
for
capture
and
control
systems
for
which
you
conduct
performance
tests,
provide
the
results
of
the
tests.
Your
notification
would
also
include
the
measured
range
of
each
monitored
parameter
and
the
operating
limits
established
during
the
performance
test,
and
information
showing
whether
the
source
has
achieved
its
operating
limits
during
the
initial
compliance
period.
Recordkeeping
requirements.
The
proposed
rule
would
require
you
to
collect
and
keep
records
according
to
certain
minimum
data
requirements
for
the
CPMS.
Failure
to
collect
and
keep
the
specified
minimum
data
would
be
a
deviation
that
is
separate
from
any
emission
limit,
operating
limit,
or
work
practice
requirement.
You
would
be
required
to
keep
records
of
reported
information
and
all
other
information
necessary
to
document
compliance
with
the
proposed
rule
for
5
years.
As
required
under
the
General
Provisions,
records
for
the
2
most
recent
years
must
be
kept
on
site;
the
other
3
years'
records
may
be
kept
off
site.
Records
pertaining
to
the
design
and
operation
of
the
control
and
monitoring
equipment
must
be
kept
for
the
life
of
the
equipment.
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/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
You
would
have
to
keep
the
following
records:
A
current
copy
of
information
provided
by
materials
suppliers
such
as
manufacturer's
formulation
data
or
test
data
used
to
determine
organic
HAP
or
VOC
content,
solids
content,
and
quantity
of
the
coatings
and
thinners
applied.
All
documentation
supporting
initial
notifications
and
notifications
of
compliance
status.
The
occurrence
and
duration
of
each
startup,
shutdown,
or
malfunction
of
the
emission
capture
and
control
system.
All
maintenance
performed
on
the
emission
capture
and
control
system.
Actions
taken
during
startup,
shutdown,
and
malfunction
that
are
different
from
the
procedures
specified
in
your
startup,
shutdown,
and
malfunction
plan.
All
information
necessary
to
demonstrate
conformance
with
your
startup,
shutdown,
and
malfunction
plan
when
the
plan
procedures
are
followed.
Each
period
during
which
a
CPMS
is
malfunctioning
or
inoperative
(
including
out
of
control
periods).
All
required
measurements
needed
to
demonstrate
compliance
with
the
standards.
All
results
of
performance
tests.
Data
and
documentation
used
to
determine
capture
system
efficiency
or
to
support
a
determination
that
the
system
is
a
permanent
total
enclosure.
Required
work
practice
plans
and
documentation
to
support
compliance
with
the
provisions
of
these
plans.
Deviations,
as
determined
from
these
records,
would
need
to
be
recorded
and
also
reported.
A
deviation
is
any
instance
when
any
requirement
or
obligation
established
by
the
proposed
rule,
including
but
not
limited
to
the
emission
limits,
operating
limits,
and
work
practice
standards,
is
not
met.
If
you
use
a
capture
and
control
system
to
reduce
organic
HAP
emissions,
you
would
have
to
make
your
startup,
shutdown,
and
malfunction
plan
available
for
inspection
if
the
Administrator
requests
to
see
it.
It
would
stay
in
your
records
for
the
life
of
the
affected
source
or
until
the
source
is
no
longer
subject
to
the
proposed
standards.
If
you
revise
the
plan,
you
would
need
to
keep
the
previous
superceded
versions
on
record
for
5
years
following
the
revision.
Periodic
reports.
Each
reporting
year
is
divided
into
two
semiannual
reporting
periods.
If
no
deviations
occur
during
a
semiannual
reporting
period,
you
would
submit
a
semiannual
report
stating
that
the
affected
source
has
been
in
continuous
compliance.
If
deviations
occur,
you
would
need
to
include
them
in
the
report
as
follows:
Report
each
deviation
from
each
applicable
monthly
emission
limit.
Report
each
deviation
from
the
work
practice
plan.
If
you
are
complying
by
using
a
thermal
oxidizer,
report
all
times
when
a
3
hour
average
temperature
is
below
the
operating
limit.
If
you
are
complying
by
using
a
catalytic
oxidizer,
report
all
times
when
a
3
hour
average
temperature
increase
across
the
catalyst
bed
is
below
the
operating
limit.
If
you
are
complying
by
using
oxidizers
or
solvent
recovery
systems,
report
all
times
when
the
value
of
the
site
specific
operating
parameter
used
to
monitor
the
capture
system
performance
was
greater
than
or
less
than
(
as
appropriate)
the
operating
limit
established
for
the
capture
system.
Report
other
specific
information
on
the
periods
of
time
the
deviations
occurred.
You
would
also
have
to
send
us
explanations
in
each
semiannual
report
if
a
change
occurs
that
might
affect
your
compliance
status.
Other
reports.
You
would
be
required
to
submit
other
reports,
including
those
for
periods
of
startup,
shutdown,
and
malfunction
of
the
emission
capture
and
control
system.
If
the
procedures
you
follow
during
any
startup,
shutdown,
or
malfunction
are
inconsistent
with
your
plan,
you
would
report
those
procedures
with
your
semiannual
reports
in
addition
to
immediate
reports
required
by
40
CFR
63.10(
d)(
5)(
ii).
III.
Rationale
for
Selecting
the
Proposed
Standards
A.
How
Did
We
Select
the
Source
Category?
Automobile
and
light
duty
truck
surface
coating
is
a
source
category
that
is
on
the
list
of
source
categories
to
be
regulated
because
it
contains
major
sources
which
emit
or
have
the
potential
to
emit
at
least
9.7
Mg
(
10
tons)
of
any
one
HAP
or
at
least
22.7
Mg
(
25
tons)
of
any
combination
of
HAP
annually.
The
proposed
rule
would
control
HAP
emissions
from
both
new
and
existing
major
sources.
Area
sources
are
not
being
regulated
under
this
proposed
rule.
The
automobile
and
light
duty
truck
surface
coating
source
category
as
described
in
the
listing
includes
any
facility
engaged
in
the
surface
coating
of
new
automobile
and
light
duty
truck
bodies.
Excluded
from
this
source
category
are
automobile
customizers,
body
shops,
and
refinishers.
For
purposes
of
this
proposed
rule,
we
are
defining
the
source
category
to
include
the
application
of
electrodeposition
primer,
primer
surfacer,
topcoat
(
including
basecoat
and
clear
coat),
final
repair,
glass
bonding
primer,
glass
bonding
adhesive,
sealer,
adhesive,
and
deadener;
all
storage
containers
and
mixing
vessels
in
which
the
above
listed
coatings,
thinners,
and
cleaning
materials
associated
with
the
above
listed
coatings
are
stored
or
mixed;
all
manual
and
automated
equipment
and
containers
used
for
conveying
coatings,
thinners,
and
cleaning
materials;
and
all
storage
containers
and
manual
and
automated
equipment
used
for
conveying
waste
materials
generated
by
a
coating
operation.
We
intend
the
source
category
to
include
facilities
for
which
the
surface
coating
of
automobiles
and
light
duty
trucks
or
automobile
and
light
duty
truck
bodies
is
either
their
principal
activity
or
is
an
integral
part
of
an
automobile
or
light
duty
truck
assembly
plant.
The
initial
listing
for
this
source
category
included
the
surface
coating
of
body
parts
for
inclusion
in
new
vehicles.
As
provided
in
the
initial
source
category
listing
notice
(
57
FR
31576,
July
16,
1992):
.
.
.
the
Agency
recognizes
that
these
descriptions
[
in
the
initial
list],
like
the
list
itself,
may
be
revised
from
time
to
time
as
better
information
becomes
available.
The
Agency
intends
to
revise
these
descriptions
as
part
of
the
process
of
establishing
standards
for
each
category.
Ultimately,
a
definition
of
each
listed
category,
or
subsequently
listed
subcategories,
will
be
incorporated
in
each
rule
establishing
a
NESHAP
for
a
category.
Some
automobile
assembly
plants
operate
separate
lines
which
apply
coatings
to
parts
such
as
bumpers,
fascias,
and
brackets
for
attachment
to
separately
coated
vehicle
bodies.
However,
since
most
plastic
and
metal
parts
that
are
attached
to
coated
vehicle
bodies
are
produced
in
separate
facilities,
we
have
decided
that
it
makes
more
sense
to
regulate
these
off
line
plastic
and
metal
parts
coating
operations
under
separate
NESHAP
for
surface
coating
of
plastic
parts
and
products
and
miscellaneous
metal
parts
because
of
the
substantially
different
equipment
that
may
be
used
to
coat
these
parts
and
for
consistency
with
the
NSPS
and
other
air
pollution
control
regulations
affecting
these
coating
operations.
The
source
category
does
not
include
research
or
laboratory
facilities
or
janitorial,
building,
and
facility
maintenance
operations.
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/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
B.
How
Did
We
Select
the
Regulated
Pollutants?
Organic
HAP.
Available
emission
data
collected
during
the
development
of
the
proposed
NESHAP
show
that
the
primary
organic
HAP
emitted
from
automobile
and
light
duty
truck
surface
coating
operations
are
toluene,
xylene,
glycol
ethers,
MEK,
MIBK,
ethylbenzene
and
methanol.
These
compounds
account
for
over
95
percent
of
this
category's
nationwide
organic
HAP
emissions.
Because
coatings
used
in
automobile
and
light
duty
truck
surface
coating
contain
many
combinations
of
these
and
other
organic
HAP,
it
is
not
practical
to
regulate
them
individually.
Therefore,
the
proposed
standards
would
regulate
emissions
of
all
organic
HAP.
Inorganic
HAP.
Based
on
information
reported
during
the
development
of
the
proposed
NESHAP,
inorganic
HAP
contained
in
the
coatings
used
by
this
source
category
include
lead,
manganese,
and
chromium
compounds.
There
is
limited
opportunity
for
these
HAP
to
be
emitted
into
the
ambient
air.
The
lead
compounds
are
present
in
the
electrodeposition
primers.
This
technique
would
not
typically
generate
air
emissions
of
these
compounds
which
are
in
the
coating
solids.
Once
the
coating
solids
are
deposited
on
the
substrate,
they
remain
on
the
substrate
and
are
not
emitted
during
cure
of
the
coating.
Therefore,
we
conclude
that
there
are
limited
or
no
air
emissions
of
lead
compounds.
Based
on
information
reported
during
the
development
of
the
proposed
NESHAP,
a
small
amount
of
chromium
compounds
are
contained
in
a
few
of
the
coatings
used
by
this
source
category.
Because
these
inorganic
compounds
are
in
the
coating
solids,
they
are
retained
on
the
substrate
to
which
they
are
applied,
and
the
only
opportunity
for
them
to
enter
the
ambient
air
is
if
they
are
spray
applied.
Because
of
the
atomization
of
the
coating
during
spray
application,
inorganic
compounds
become
airborne,
and
they
are
either
deposited
on
the
substrate,
collected
by
the
circulating
water
under
the
spray
booth
floor
grates,
adhere
to
the
surrounding
walls
and
other
surfaces
in
the
area,
or
enter
the
air
and
become
susceptible
to
transport
to
other
areas
in
the
building
or
outside
into
the
ambient
air.
The
data
available
to
EPA
indicate
that
the
facilities
in
this
source
category
that
use
spray
application
techniques
sometimes
apply
coatings
that
contain
inorganic
HAP
compounds,
including
small
quantities
of
chromium
oxide.
Overspray,
including
that
containing
inorganic
HAP,
is
controlled
to
an
extremely
high
level
by
down
draft
impingement
in
circulating
sub
grate
water
systems.
C.
How
Did
We
Select
the
Affected
Source?
In
selecting
the
affected
sources
for
MACT
standards,
our
primary
goal
is
to
ensure
that
MACT
is
applied
to
HAPemitting
operations
or
activities
within
the
source
category
or
subcategory
being
regulated.
The
affected
source
also
serves
to
distinguish
where
new
source
MACT
applies
under
a
particular
standard.
Specifically,
the
General
Provisions
in
subpart
A
of
40
CFR
part
63
define
the
terms
``
construction''
and
``
reconstruction''
with
reference
to
the
term
``
affected
source''
(
40
CFR
60.2)
and
provide
that
new
source
MACT
applies
when
construction
or
reconstruction
of
an
affected
source
occurs
(
40
CFR
60.5).
The
collection
of
equipment
and
activities
evaluated
in
determining
MACT
(
including
the
MACT
floor)
is
used
in
defining
the
affected
source.
Some
source
categories
are
comprised
of
HAP
emitting
equipment
and
activities
that
are
independent,
have
no
functional
interactions
at
the
process
level,
and
are
not
related
to
each
other
in
terms
of
emission
control.
In
these
cases,
it
is
reasonable
from
a
MACT
implementation
perspective
to
have
separate,
narrowly
defined
affected
sources
for
purposes
of
focusing
MACT
applicability.
An
implication
of
a
narrow
definition
of
affected
source
is
that
new
source
MACT
requirements
could
be
triggered
more
frequently
as
equipment
is
replaced
(
potential
``
reconstruction'')
or
facilities
are
expanded
(
potential
``
construction'')
than
with
a
broader
definition
of
affected
source,
such
as
some
collection
of
equipment
or
even
the
entire
facility.
This
approach
is
sometimes
appropriate
based
on
consideration
of
emission
reductions,
cost
impacts,
and
implementation
factors.
When
a
MACT
standard
is
based
on
total
facility
emissions,
we
select
an
affected
source
based
on
the
entire
facility
as
well.
This
approach
for
defining
the
affected
source
broadly
is
particularly
appropriate
for
industries
where
a
plantwide
emission
standard
provides
the
opportunity
and
incentive
for
owners
and
operators
to
utilize
control
strategies
that
are
more
cost
effective
than
if
separate
standards
were
established
for
each
emission
point
within
a
facility.
The
affected
source
in
the
automobile
and
light
duty
truck
surface
coating
source
category
for
which
MACT
standards
are
being
proposed
is
the
equipment
used
for
electrodeposition
primer,
primer
surfacer,
topcoat
(
including
basecoat
and
clear
coat),
final
repair,
glass
bonding
primer,
glass
bonding
adhesive,
sealer,
adhesive,
and
deadener;
as
well
as
storage
containers
and
mixing
vessels
in
which
coatings,
thinners,
and
cleaning
materials
are
stored
and
mixed;
all
manual
and
automated
equipment
for
conveying
coatings,
thinners,
and
cleaning
materials;
and
all
storage
containers
and
all
manual
and
automated
equipment
and
containers
used
for
conveying
waste
materials
generated
by
a
coating
operation
for
which
an
emission
limit
is
proposed.
Standards
for
new
sources
apply
to
newly
constructed
or
reconstructed
paintshops.
All
of
the
organic
HAP
emitting
coating
operations
covered
by
this
source
category
occur
within
the
area
of
an
automobile
assembly
plant
referred
to
as
the
paint
shop,
except
for
the
operations
related
to
glass
installation
(
glass
bonding
primer,
glass
bonding
adhesive,
and
pre
installation
cleaning)
and
certain
off
line
final
repair
operations.
All
existing
affected
sources
are
located
at
automobile
assembly
plants.
Other
collocated
operations
at
automobile
assembly
plants
may
be
subject
to
other
NESHAP,
including
NESHAP
currently
under
development
for
source
categories
such
as
miscellaneous
metal
parts
coating
and
plastic
parts
and
products
coating.
Additional
information
on
the
operations
at
automobile
and
light
duty
truck
surface
coating
facilities
that
were
selected
for
regulation
and
other
operations
that
are
conducted
at
automobile
assembly
plants
are
included
in
the
docket
for
the
proposed
standards.
D.
How
Did
We
Determine
the
Basis
and
Level
of
the
Proposed
Standards
for
Existing
and
New
Sources?
After
we
identify
the
specific
source
categories
or
subcategories
of
sources
to
regulate
under
section
112
of
the
CAA,
we
must
develop
MACT
standards
for
each
category
or
subcategory.
Section
112
establishes
a
minimum
baseline
or
``
floor''
for
standards.
For
new
sources
in
a
category
or
subcategory,
the
standards
cannot
be
less
stringent
than
the
emission
control
that
is
achieved
in
practice
by
the
best
controlled
similar
source
(
section
112(
d)(
3)).
The
standards
for
existing
sources
can
be
less
stringent
than
standards
for
new
sources,
but
they
cannot
be
less
stringent
than
the
average
emission
limitation
achieved
by
the
bestperforming
12
percent
of
existing
sources
for
which
the
Administrator
has
emissions
information
(
or
the
bestperforming
five
sources
for
categories
or
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247
/
Tuesday,
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24,
2002
/
Proposed
Rules
subcategories
with
fewer
than
30
sources).
Electrodeposition
primer,
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive.
All
59
facilities
in
the
source
category
that
were
in
operation
in
1997
or
1998
responded
to
an
information
collection
request
(
ICR).
(
Several
facilities
did
not
have
operating
paint
shops
during
this
period,
but
submitted
information
pertaining
to
their
applications
of
sealers
and
adhesives
in
the
assembly
process.)
Two
facilities
that
presently
track
their
usage
and
emissions
on
a
line
by
line
basis
submitted
two
sets
of
data
each.
The
responses
contained
data
on
the
mass
of
organic
HAP
emissions
per
volume
of
coating
solids
deposited
for
each
month
of
a
calendar
year
for
electrodeposition
primer,
primer
surfacer,
and
topcoat
operations;
and
additional
information
on
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive.
Final
repair
and
glass
bonding
materials
are
functionally
tied
to
the
electrodeposition
primer,
primersurfacer
and
topcoat
materials.
Final
repair
materials
must
be
compatible
with
these
other
coatings
and
must
provide
an
exact
color
and
appearance
match.
Glass
bonding
materials
also
must
be
compatible
with
these
other
coatings.
The
choice
of
glass
bonding
materials
is
highly
dependent
on
the
performance
characteristics
of
and
interaction
with
these
other
coatings.
Glass
bonds
must
meet
safety
requirements
issued
by
the
National
Highway
Transportation
Safety
Administration.
Therefore,
we
have
included
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
with
electrodeposition
primer,
primersurfacer
and
topcoat.
In
most
cases,
facilities
calculated
their
monthly
emissions
from
primersurfacer
and
topcoat
operations
using
a
procedure
that
closely
matched
the
procedure
in
``
Protocol
for
Determining
Daily
Volatile
Organic
Compound
Emission
Rate
of
Automobile
and
Light
Duty
Truck
Topcoat
Operations,''
EPA
450/
3
88
018
(
docket
A
2001
22).
The
calculations
took
into
account
the
overall
efficiency
of
capture
systems
and
control
devices,
as
well
as
the
transfer
efficiency
of
spray
equipment
used
to
apply
coatings.
In
addition,
the
responses
included
the
mass
organic
HAP
content
and
the
volume
solids
content
of
all
materials
added
to
the
electrodeposition
system
on
a
monthly
basis.
Using
the
data,
we
ranked
the
facilities
on
the
basis
of
mass
of
organic
HAP
emissions
per
volume
of
coating
solids
deposited
on
an
annual
basis.
Several
of
the
lowest
emitting
facilities
did
not
apply
full
body
primer
surfacer
during
the
ICR
reporting
year
(
although
these
facilities
as
well
as
all
other
presently
operating
facilities
do
so
currently).
Since
the
data
from
these
facilities
did
not
represent
the
current
and
anticipated
industry
practices,
we
eliminated
them
from
the
ranking.
We
then
identified
the
eight
facilities
with
the
lowest
organic
HAP
emissions
(
from
electrodeposition,
primer
surfacer,
and
topcoat
combined)
per
volume
coating
solids
deposited.
As
four
of
the
eight
lowest
emitting
plants
used
a
powder
primer
surfacer
application
system
which
results
in
a
much
thicker
film
than
a
liquid
application
system,
we
adjusted
the
solids
deposited
volumes
for
the
powder
systems
to
reflect
liquid
primer
surfacer
thicknesses.
We
then
identified
the
month
of
the
reporting
year
with
the
peak
organic
HAP
emission
rate
for
the
eight
facilities
with
the
lowest
annual
emission
rates.
Since
the
proposed
rule
requires
compliance
each
and
every
month,
an
emission
limit
based
on
the
annual
emissions
would
be
unachievable
by
even
the
lowest
emitting
plants
approximately
6
months
of
the
year.
Variations
in
colors
or
vehicles
produced
and
the
organic
HAP
contents
of
different
basecoats
and
color
keyed
primer
surfacers
leads
to
unavoidable
fluctuations
in
organic
HAP
emission
rates,
even
with
the
same
application
equipment
and
capture
and
control
devices
in
use.
The
average
organic
HAP
emission
rate
for
the
peak
month
for
the
eight
lowest
emitting
plants
(
as
determined
on
an
annual
basis)
was
determined
to
be
the
MACT
floor
for
a
monthly
compliance
standard
for
combined
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations
at
existing
plants.
We
have
also
proposed
a
compliance
demonstration
option
based
on
emissions
from
combined
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations
for
those
plants
with
well
controlled
electrodeposition
operations,
or
that
use
very
low
organic
HAP
materials
in
their
electrodeposition
primer
operation.
This
was
based
on
the
emission
rate
from
primer
surfacer
and
topcoat
application
at
the
eight
lowest
emitting
plants.
(
The
same
plants
as
those
with
the
lowest
emission
rates
from
electrodeposition,
primer
surfacer,
and
topcoat
combined.)
The
emission
rate
without
electrodeposition
is
comparable
to
the
proposed
emission
rate
with
electrodeposition
when
the
lower
organic
HAP
emissions
per
volume
of
coating
solids
deposited
which
result
from
including
electrodeposition
primer
are
considered.
The
floor
for
new
sources
was
based
on
the
performance
of
the
plant
with
the
lowest
annual
emission
rate.
The
peak
monthly
emission
rate
for
this
plant
for
the
reporting
year
would
represent
the
best
consistently
achievable
emission
rate
for
new
sources.
Both
the
existing
source
MACT
floor
and
the
new
source
MACT
floor
are
based
on
monthly
compliance.
All
or
nearly
all
automobile
and
light
duty
truck
surface
coating
facilities
are
subject
to
compliance
with
existing
rules
demonstrated
by
calculations
based
on
monthly
coating
use.
The
ICR
responses
upon
which
the
MACT
determination
was
made
provided
data
on
a
monthly
basis.
A
1
month
time
period
is
the
shortest
compliance
period
for
which
data
are
available
to
reliably
determine
MACT.
Adhesives
and
sealers
(
other
than
glass
binding
adhesive),
and
deadeners.
All
facilities
in
the
source
category
submitted
responses
to
an
ICR.
The
responses
contained
data
on
the
mass
used,
and
the
mass
fraction
of
organic
HAP
in
each
of
the
materials
used
during
the
reporting
year.
The
average
mass
organic
HAP
content
of
the
materials
used
throughout
the
reporting
year
was
determined
for
each
facility.
The
eight
facilities
with
the
lowestaverage
organic
HAP
content
in
each
group
(
i.
e.,
adhesives
and
sealers
were
considered
separately
from
deadeners)
were
determined.
These
facilities
used
materials
with
an
average
mass
fraction
of
organic
HAP
of
less
than
0.01
kilogram
(
kg)/
kg
(
pound
(
lb)/
lb.
Because
of
imprecision
in
analytical
methods
at
this
level,
and
because
the
organic
HAP
reported
as
zero
for
some
materials
at
some
facilities
may
have
contained
traces
of
organic
HAP
that
were
not
reported
to
the
facility
by
the
material
supplier,
the
MACT
floor
mass
organic
HAP
content
was
determined
to
be
0.01
kg/
kg
(
lb/
lb).
This
is
the
lowest
level
for
both
new
and
existing
facilities
for
which
compliance
could
be
reliably
demonstrated.
The
proposed
rule
would
require
compliance
to
be
demonstrated
monthly
on
the
basis
of
a
mass
average
organic
HAP
content
of
the
materials
used.
A
shorter
compliance
time
interval
would
result
in
excessive
recordkeeping
with
little
or
no
additional
reduction
in
organic
HAP
emissions.
If
each
and
every
material
used
within
a
particular
group
of
materials
meets
the
monthly
average
emission
limit
on
an
individual
basis,
then
no
calculations
are
required
to
demonstrate
compliance.
Storage,
mixing,
and
conveying
of
coatings,
thinners,
and
cleaning
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2002
/
Proposed
Rules
materials.
The
proposed
rule
would
regulate
these
operations
in
accordance
with
a
site
specific
work
practice
plan
to
be
developed
subject
to
approval
by
the
Administrator
and
implemented
by
each
new
and
existing
source.
We
have
no
reliable
data
on
the
extent
of
emissions
from
these
operations
but
believe
them
to
be
low.
Cleaning
and
equipment
purging
emissions.
While
the
responses
to
the
ICR
contain
extensive
(
though
in
some
cases
inconsistent)
data
pertaining
to
the
volumetric
use
and
organic
HAP
content
of
cleaning
and
purging
materials,
a
substantial
but
unknown
fraction
of
the
organic
HAP
emissions
from
cleaning
and
purging
operations
are
captured
and
controlled.
We
have
no
reliable
data
that
would
enable
us
to
determine
an
emission
limit
for
these
operations
that
would
represent
MACT
level
control.
The
proposed
rule
would
regulate
these
operations
in
accordance
with
a
site
specific
work
practice
plan
to
be
developed
subject
to
approval
by
the
Administrator
and
implemented
by
each
new
and
existing
source.
After
the
floors
have
been
determined
for
new
and
existing
sources
in
a
source
category
or
subcategory,
we
must
set
MACT
standards
that
are
technically
achievable
and
no
less
stringent
than
the
floors.
Such
standards
must
then
be
met
by
all
sources
within
the
category
or
subcategory.
We
identify
and
consider
any
reasonable
regulatory
alternatives
that
are
``
beyond
the
floor,''
taking
into
account
emission
reduction,
cost,
non
air
quality
health
and
environmental
impacts,
and
energy
requirements.
These
alternatives
may
be
different
for
new
and
existing
sources
because
different
MACT
floors
and
separate
standards
may
be
established
for
new
and
existing
sources.
The
eight
facilities
with
the
lowestorganic
HAP
emission
rates
from
electrodeposition
primer,
primersurfacer
and
topcoat
application
employed
a
combination
of
various
organic
HAP
emission
limitation
techniques,
including
the
use
of
lowerorganic
HAP
electrodeposition
primer
materials,
powder
primer
surfacer,
waterborne
basecoats,
lower
organic
HAP
solvent
based
primer
surfacers,
lower
organic
HAP
solvent
based
basecoats
and
clearcoats,
and
improved
capture
and
control
systems.
However,
no
single
technology
or
combination
of
technologies
representing
a
beyond
thefloor
MACT
was
identified,
nor
did
we
identify
any
other
available
technologies
which
are
not
presently
in
use
with
the
potential
to
decrease
organic
HAP
emissions
beyond
the
floor
for
either
new
or
existing
sources.
We
expect
that
many
existing
plants
will
improve
capture
and
control
device
efficiency
as
a
means
of
compliance.
Control
options
beyond
the
floor
could
involve
even
higher
overall
efficiencies.
Because
of
the
dilute
nature
of
the
organic
HAP
containing
streams
available
for
capture,
the
cost
of
such
a
beyond
the
floor
limit
would
exceed
$
40,000
per
ton
of
incremental
organic
HAP
controlled.
We
are
not
proposing
beyond
the
floor
limits
at
this
time.
Following
a
future
analysis
of
residual
risk,
EPA
may
propose
a
beyond
thefloor
emission
limit,
if
it
is
found
to
be
justified.
The
facilities
which
presently
use
adhesives
and
sealers,
and
deadeners
with
the
lowest
mass
organic
HAP
contents
would
not
be
able
to
reliably
demonstrate
compliance
with
a
standard
more
stringent
than
the
floor
level
emission
limit
for
these
materials
due
to
uncertainty
in
the
analytical
methods
available
and
the
expected
inability
or
unwillingness
of
the
suppliers
of
the
materials
to
certify
lower
organic
HAP
contents.
A
wide
variety
of
techniques
exist
for
reducing
organic
HAP
emissions
from
mixing,
storage,
and
conveying
of
coatings,
thinners,
and
cleaning
materials,
and
from
cleaning
and
purging
of
equipment.
Because
we
have
no
data
upon
which
to
establish
a
numerical
organic
HAP
emission
limit
for
these
operations,
we
have
proposed
to
regulate
them
through
the
development
and
implementation
of
site
specific
work
practice
plans.
The
proposed
rule
identifies
a
number
of
potential
emission
control
practices
which
must
be
considered,
as
applicable,
in
these
work
plans.
Alternative
practices
which
achieve
equivalent
or
improved
emission
limitations
are
also
permitted
under
the
proposed
rule.
Because
we
are
unable
to
reliably
estimate
the
emissions
reductions
that
will
be
achieved
beyond
the
present
baseline
emissions
from
these
operations,
the
work
practices
requirements
may
represent
beyond
thefloor
standards.
We
believe
that
the
costs
of
implementing
these
work
practices
will
be
reasonable,
as
many
of
the
same
or
equivalent
practices
would
be
required
for
control
of
VOC
emissions
under
title
V
air
permits.
In
lieu
of
emission
standards,
section
112(
h)
of
the
CAA
allows
work
practice
standards
or
other
requirements
to
be
established
if:
(
1)
A
pollutant
cannot
be
emitted
through
a
conveyance
or
capture
system,
or
(
2)
measurement
is
not
practicable
due
to
technological
and
economic
limitations.
All
automobile
and
light
duty
truck
surface
coating
facilities
use
some
type
of
work
practice
measures
to
reduce
HAP
emissions
from
mixing,
storage,
conveying,
and
cleaning
and
purging
as
part
of
their
standard
operating
procedures.
They
use
these
measures
to
decrease
solvent
usage
and
minimize
exposure
to
workers.
However,
data
to
quantify
accurately
the
emissions
reductions
achievable
by
the
work
practice
measures
are
unavailable,
and
it
is
not
feasible
to
measure
emissions
or
enforce
a
numerical
standard
for
emissions
from
these
operations.
We
selected
MACT
floor
level
standards
for
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
glass
bonding
adhesive,
sealer,
and
adhesive
application,
and
deadener
because
we
were
unable
to
identify
any
specific
technologies
that
would
result
in
a
lower
level
of
emissions.
We
have
proposed
a
more
stringent
emission
limit
for
electrodeposition
primer,
primer
surfacer,
and
topcoat
application
for
new
sources.
This
more
stringent
limit
is
not
appropriate
for
existing
sources
because
of
the
difficulty,
uncertainty,
and
in
some
cases,
impossibility
of
retrofitting
the
best
combination
of
emission
limitation
techniques
to
existing
facilities,
as
well
as
the
high
cost
associated
with
what
would
be
a
beyond
the
floor
limit
for
existing
facilities.
We
believe
the
proposed
standards
for
existing
sources
are
achievable
because
they
are
presently
being
achieved
by
at
least
six
existing
sources.
We
believe
the
proposed
standards
for
new
sources
are
achievable
because
they
are
presently
being
achieved
by
the
best
performing
facility
in
the
source
category.
We
have
proposed
standards
for
which
compliance
would
be
demonstrated
on
a
monthly
basis.
The
data
used
to
determine
MACT
for
electrodeposition
primer,
primersurfacer
and
topcoat
were
based
on
organic
HAP
emission
limits
that
were
achieved
by
the
best
performing
plants
each
month
(
during
which
production
occurred)
during
the
reporting
year
for
the
ICR
responses.
We
used
annual
data
to
determine
MACT
for
adhesives
and
sealers,
and
deadeners,
but
believe
that
monthly
compliance
is
achievable
because
the
standards
are
based
on
organic
HAP
per
mass
of
material,
or
organic
HAP
per
volume
of
material
and
we
have
no
reason
to
believe
that
different
materials
are
used
at
different
times
throughout
the
year.
E.
How
Did
We
Select
the
Format
of
the
Proposed
Standards?
Numerical
emission
standards
are
required
by
section
112
of
the
CAA
unless
we
can
justify
that
it
is
not
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Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
feasible
to
prescribe
or
enforce
an
emission
standard,
in
which
case
a
design,
equipment,
work
practice,
or
operational
standard
can
be
set
(
section
112(
h)
of
the
CAA).
Formats
considered.
We
considered
the
following
formats
for
allowable
organic
HAP
emissions
from
the
affected
source:
(
1)
Mass
of
organic
HAP
per
unit
weight
or
volume
of
coating,
coating
solids,
or
coating
solids
deposited;
(
2)
mass
of
organic
HAP
per
unit
of
production;
(
3)
organic
HAP
concentration
exiting
a
control
device;
(
4)
organic
HAP
emissions
per
unit
surface
area
coated;
and
(
5)
percent
reduction
achieved
by
a
capture
system
and
control
device.
Each
format
is
defined,
and
the
major
advantages
and
disadvantages
are
discussed
below.
The
first
type
of
format
considered
would
express
the
emission
limitation
as
mass
of
organic
HAP
emissions
per
volume
of
coating,
mass
of
coating
solids,
volume
of
coating
solids,
or
volume
of
coating
solids
deposited.
An
advantage
of
this
type
of
format
is
that
it
relates
emissions
to
production
levels,
but
in
a
more
equitable
way
than
one
based
on
units
of
production.
Also,
an
affected
source
would
have
flexibility
in
choosing
among
several
compliance
options
to
achieve
a
standard
based
on
this
type
of
format.
This
type
of
standard,
when
based
on
mass
or
volume
of
coating
solids
deposited,
takes
into
account
the
transfer
efficiency,
i.
e.,
the
fraction
of
coating
solids
used
that
actually
adhere
to
the
substrate.
A
mass
of
HAP
per
volume
of
coating
format
(
i.
e.,
kg
HAP/
liter
(
lb
HAP/
gallon
(
gal))
of
coating)
either
for
each
coating
or
as
an
average
across
all
coatings
could
be
used.
While
this
format
is
simple
to
understand
and
use,
its
main
disadvantage
is
that
it
would
not
credit
sources
that
switch
to
lower
emitting,
higher
solids
coatings.
For
example,
a
facility
using
a
coating
with
a
solids
content
of
40
percent
and
a
HAP
content
of
3
lb/
gal
will
use
fewer
pounds
of
HAP
than
a
facility
using
a
coating
with
a
solids
content
of
20
percent
and
a
HAP
content
of
2
lb/
gal
because
the
first
facility
will
use
50
percent
less
coating
than
the
second.
A
comparison
of
the
emission
potential
of
two
coatings
using
a
mass
HAP
per
volume
coating
format
cannot
be
made.
An
alternative
format
is
a
mass
HAP
per
volume
of
coating
solids
(
i.
e.,
kg
HAP/
liter
(
lb
HAP/
gal)
of
coating
solids).
This
format
would
adequately
credit
sources
that
converted
conventional
higher
HAP
solvent
coatings
to
higher
solids
coatings.
The
same
is
true
for
a
format
of
mass
HAP/
mass
of
solids
(
i.
e.,
kg
HAP/
kg
(
lb
HAP/
lb)
solids).
For
example,
if
a
source
were
to
increase
the
solids
content
of
a
coating
and
thereby
decrease
the
quantity
of
coating
used,
either
of
these
formats
would
properly
credit
the
affected
source's
emissions
reductions.
However,
there
are
potential
drawbacks
to
the
mass
HAP/
mass
solids
format.
Such
a
standard
does
not
take
into
account
the
sometimes
considerable
differences
in
coating
solids
densities.
Either
the
mass
HAP/
mass
solid
or
the
mass
HAP/
volume
solid
formats
can
be
restated
to
consider
applied
solids
rather
than
solids
contained
in
the
coating
to
provide
credit
for
application
techniques
with
higher
transfer
efficiencies.
The
second
format
considered
is
mass
of
organic
HAP
emissions
per
unit
of
production
(
e.
g.,
kg
HAP
per
vehicle
coated).
Its
major
disadvantage
is
that
the
surface
area
of
automobiles
and
light
duty
trucks
varies
greatly.
The
third
format
considered,
a
limit
on
the
concentration
of
organic
HAP
in
the
exhaust
from
the
control
device
would
only
apply
to
sources
that
use
add
on
control
devices.
This
format
for
a
standard
is
the
easiest
to
enforce
because
direct
emissions
measurements
can
be
made
using
Method
25
or
25A.
However,
the
concentration
of
organic
HAP
emitted
from
the
control
device
does
not
reflect
total
emissions
because
of
the
possibility
of
uncaptured
emissions
from
the
coating
operation,
nor
does
it
limit
total
emissions
because
of
the
effect
of
varying
the
exhaust
flow
rates
(
i.
e.,
increasing
dilution
air).
For
example,
two
similar
coating
operations
could
produce
the
same
amount
of
organic
HAP
yet
have
different
inlet
concentrations
to
the
control
device
because
of
variations
in
capture
of
emissions
from
the
coating
operation
and
because
of
varying
oven
airflow
rates.
A
standard
based
on
outlet
concentration
would
require
the
line
with
the
higher
concentration
(
lower
airflow
rate)
to
control
more
organic
HAP
emissions
than
the
line
with
the
lower
inlet
concentration.
Because
management
of
airflow
rates
is
generally
under
the
control
of
the
operator,
this
format
would
not
reflect
the
application
of
MACT
for
the
coating
operation.
Furthermore,
this
format
would
limit
the
compliance
options
available
to
sources
because
it
would
not
accommodate
the
use
of
either
low
HAP
content
coatings
and
other
materials,
or
the
use
of
a
combination
of
capture
and
control
systems
in
conjunction
with
reduced
HAP
coatings
and
other
materials.
The
fourth
format,
organic
HAP
emissions
per
unit
surface
area
coated,
provides
flexibility
in
the
selection
of
coating
materials,
the
streams
to
be
controlled,
and
the
approach
to
capture
and
control.
We
requested
surface
area
data
for
vehicles
produced
during
the
ICR
reporting
year
and
received
data
of
this
type
from
a
number
of
respondents.
The
data
that
we
received
were
incomplete,
and
the
methods
of
estimating
vehicle
surface
areas
varied
widely.
In
many
cases,
computer
generated
design
drawings
were
analyzed
to
estimate
surface
areas.
The
algorithms
used
to
make
the
estimates
are
unlikely
to
be
consistent
from
manufacturer
to
manufacturer.
While
a
standard
in
this
format
has
some
advantages,
it
would
be
difficult
to
establish
MACT
because
of
the
inconsistent
basis
of
the
estimates.
The
fifth
format,
percent
reduction,
would
only
apply
to
sources
that
use
add
on
control
devices.
This
format
is
often
the
best
choice
when
capture
and
control
systems
are
widely
used
in
the
source
category,
and
the
achievable
percent
reduction
over
a
wide
range
of
operating
conditions
is
predictable.
The
advantages
of
this
format
are
that
it
would
reflect
MACT
at
all
facilities,
and
the
facilities
would
be
allowed
flexibility
in
the
method
selected
for
achieving
the
percent
reduction.
A
disadvantage
of
the
percent
reduction
format
is
that
it
does
not
credit
improvements
in
the
materials
or
processes.
For
example,
reduction
in
the
organic
HAP
content
of
a
coating
or
in
the
amount
of
coating
applied
per
unit
of
substrate
manufactured
would
not
be
credited
toward
compliance.
This
might
discourage
development
of
low
or
non
HAP
coatings.
Similar
to
the
concentration
format
for
a
standard,
this
format
also
would
not
accommodate
the
use
of
either
low
HAP
content
coatings
and
other
materials
or
a
combination
of
capture
and
control
systems
in
conjunction
with
reduced
HAP
coatings
and
other
materials
as
a
means
of
compliance.
Format
selected.
We
selected
mass
of
HAP
emitted
per
volume
of
coating
solids
deposited
as
the
format
for
the
proposed
emission
limit
for
electrodeposition
primer,
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive.
All
automobile
and
light
duty
truck
surface
coating
facilities
presently
calculate
VOC
emissions
from
primersurfacer
and
topcoat
application
in
this
format
and
have
recordkeeping
systems
in
place
to
track
coating
usage,
mass
fraction
of
VOC,
volume
fraction
of
solids,
and
transfer
efficiencies.
Responses
to
the
ICR
were,
for
the
most
part,
based
on
adaptions
of
these
systems
to
calculate
organic
HAP
emissions
from
both
topcoat
and
primer
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December
24,
2002
/
Proposed
Rules
surfacer
application.
Only
minor
adjustments
would
be
necessary
to
include
electrodeposition
coatings,
as
only
two
to
four
different
materials
are
used
for
this
process,
and
the
transfer
efficiency
is
essentially
100
percent.
Such
a
format
would
be
consistent
with
the
information
upon
which
MACT
determination
was
based.
This
format
gives
credit
for
the
use
of
low
or
zeroorganic
HAP
coatings
or
high
solids
coatings
in
one
or
more
application
processes,
as
well
as
improved
application
techniques
which
result
in
higher
transfer
efficiencies
for
primersurfacer
and
topcoat.
This
format
would
allow
sources
flexibility
to
use
a
combination
of
emission
capture
and
control
systems
as
well
as
low
HAP
content
coatings
and
other
materials.
We
selected
mass
of
organic
HAP
per
mass
of
coating
as
the
format
for
the
proposed
standards
for
adhesives
and
sealers,
and
deadeners.
These
materials
are
applied
with
nearly
100
percent
transfer
efficiency
in
most
cases
and
emissions
from
these
materials
are
rarely,
if
ever,
directed
to
add
on
control
devices.
F.
How
Did
We
Select
the
Testing
and
Initial
Compliance
Requirements?
We
have
proposed
a
compliance
procedure
for
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive.
The
procedure
takes
into
account
the
volume
of
each
coating
used,
its
mass
organic
HAP
content,
volume
solids
content,
and
density,
as
well
as
the
transfer
efficiency
and
the
overall
efficiency
of
any
add
on
control
devices.
The
procedure
is
modeled
after
the
procedure
in
``
Protocol
for
Determining
Daily
Volatile
Organic
Compound
Emission
Rate
of
Automobile
and
Light
Duty
Truck
Topcoat
Operations,''
EPA
450/
3
88
018
(
docket
A
2001
22),
presently
used
to
demonstrate
compliance
with
VOC
emission
limits
for
topcoat
and
primersurfacer
application
at
automobile
and
light
duty
truck
surface
coating
facilities.
We
have
proposed
a
monthly
average
mass
organic
HAP
content
determination
to
demonstrate
compliance
with
the
emission
limits
for
adhesives
and
sealers,
and
deadeners.
Method
311
of
40
CFR
part
63,
appendix
A,
is
the
method
developed
by
EPA
for
determining
the
HAP
content
of
coatings
and
has
been
used
in
previous
surface
coating
NESHAP.
We
have
not
identified
any
other
methods
that
provide
advantages
over
Method
311
for
use
in
the
proposed
rule.
Method
24
of
40
CFR
part
60,
appendix
A,
is
the
method
developed
by
EPA
for
determining
the
VOC
content
of
coatings
and
can
be
used
if
you
choose
to
determine
the
nonaqueous
volatile
matter
content
as
a
surrogate
for
organic
HAP.
In
past
rules,
VOC
emission
control
measures
have
been
implemented
in
the
coatings
industry
with
Method
24
as
the
compliance
method.
We
have
not
identified
any
other
methods
that
provide
advantages
over
Method
24
for
use
in
the
proposed
rule.
The
proposed
requirements
for
determining
volume
solids
would
allow
you
to
choose
between
calculating
the
value
using
either
ASTM
Method
D2697
86
(
1988)
or
ASTM
Method
D6093
97.
You
may
use
information
provided
by
your
coating
supplier
instead
of
conducting
the
HAP,
solids,
and
density
determinations
yourself.
The
above
specified
test
methods
will
take
precedence
if
there
is
any
discrepancy
between
the
result
of
the
methods
and
information
provided
by
your
suppliers.
Capture
and
control
systems.
If
you
use
an
emission
capture
and
control
system,
you
would
be
required
to
conduct
an
initial
performance
test
of
the
system
to
determine
its
overall
control
efficiency.
The
overall
control
efficiency
would
be
combined
with
the
monthly
HAP
content
of
the
coatings
and
other
materials
used
in
the
affected
source
to
derive
the
monthly
HAP
emission
rate
to
demonstrate
compliance
with
the
standard
for
electrodeposition
primer,
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive.
If
you
conduct
a
performance
test,
you
would
also
determine
parameter
operating
limits
during
the
test.
The
test
methods
that
the
proposed
rule
would
require
for
the
performance
test
have
been
required
for
many
industrial
surface
coating
sources
under
NSPS
in
40
CFR
part
60
and
NESHAP
in
40
CFR
part
63.
We
have
not
identified
any
other
methods
that
provide
advantages
over
these
methods.
Work
practices.
In
the
initial
compliance
report,
you
would
certify
that
you
have
met
the
proposed
work
practice
standards
during
the
initial
compliance
period.
You
would
also
keep
the
records
required
to
document
your
actions.
These
are
minimal
compliance
requirements
to
ensure
you
are
meeting
the
standards.
G.
How
Did
We
Select
the
Continuous
Compliance
Requirements?
To
ensure
continuous
compliance
with
the
proposed
emission
limits
and
operating
limits,
the
proposed
rule
would
require
continuous
parameter
monitoring
of
capture
systems,
add
on
control
devices,
and
recordkeeping.
We
selected
the
following
requirements
based
on:
reasonable
cost,
ease
of
execution,
and
usefulness
of
the
resulting
data
to
both
the
owners
or
operators
and
EPA
for
ensuring
continuous
compliance
with
the
emission
limits
and
operating
limits.
We
are
proposing
that
certain
parameters
be
continuously
monitored
for
the
types
of
capture
and
control
systems
commonly
used
in
the
industry.
These
monitoring
parameters
have
been
used
in
other
standards
for
similar
industries.
The
values
of
these
parameters
that
correspond
to
compliance
with
the
proposed
emission
limits
are
established
during
the
initial
or
most
recent
performance
test
that
demonstrates
compliance.
These
values
are
your
operating
limits
for
the
capture
and
control
system.
You
would
be
required
to
determine
3
hour
average
values
for
most
monitored
parameters
for
the
affected
source.
We
selected
this
averaging
period
to
allow
for
normal
variation
of
the
parameter
while
ensuring
that
the
control
system
is
continuously
operating
at
the
same
or
better
control
level
as
during
a
performance
test
demonstrating
compliance
with
the
emission
limits.
To
demonstrate
continuous
compliance
with
the
monthly
emission
limits,
you
would
also
need
records
of
the
quantity
of
coatings
and
other
materials
used
and
the
data
and
calculations
supporting
your
determination
of
their
HAP
content.
To
demonstrate
continuous
compliance
with
the
work
practice
standards,
you
would
keep
the
associated
records
specified
in
your
work
practice
plan,
as
required
by
the
proposed
rule,
and
comply
with
the
associated
reporting
requirements.
H.
How
Did
We
Select
the
Notification,
Recordkeeping,
and
Reporting
Requirements?
You
would
be
required
to
comply
with
the
applicable
requirements
in
the
NESHAP
General
Provisions,
subpart
A
of
40
CFR
part
63,
as
described
in
Table
2
of
the
proposed
rule.
We
evaluated
the
General
Provisions
requirements
and
included
those
we
determined
to
be
the
minimum
notification,
reporting,
and
recordkeeping
necessary
to
ensure
compliance
with,
and
effective
enforcement
of,
the
proposed
standards.
I.
How
Did
We
Select
the
Compliance
Date?
The
proposed
rule
allows
existing
sources
3
years
from
the
effective
date
of
the
final
standards
to
demonstrate
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Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
compliance.
This
is
the
maximum
compliance
period
permitted
by
the
CAA.
We
believe
that
3
years
may
be
necessary
for
some
affected
sources
to
design,
install,
and
test
improved
capture
systems
and
control
devices.
Sources
that
adopt
reformulated
lower
HAP
coatings
or
powder
coatings
may
also
need
3
years
to
specify,
adjust
application
equipment,
and
modify
existing
coating
processes.
New
or
reconstructed
affected
sources
must
comply
immediately
upon
startup
or
the
effective
date
of
the
proposed
rule,
whichever
is
later
as
required
by
the
CAA.
IV.
Summary
of
Environmental,
Energy,
and
Economic
Impacts
A.
What
Are
the
Air
Quality
Impacts?
The
proposed
rule
would
decrease
HAP
emissions
from
automobile
and
light
duty
truck
surface
coating
facilities
from
an
estimated
10,000
tpy
to
4,000
tpy.
This
represents
a
decrease
of
6,000
tpy
or
60
percent.
The
proposed
rule
would
also
decrease
VOC
by
approximately
12,000
to
18,000
tpy.
These
values
were
calculated
in
comparison
to
baseline
emissions
reported
to
EPA
by
individual
facilities
for
1996
or
1997.
B.
What
Are
the
Cost
Impacts?
The
estimated
total
capital
costs
of
compliance,
including
the
costs
of
monitors,
is
$
670
million.
This
will
result
in
an
additional
annualized
capital
cost
of
$
75
million
compared
to
a
baseline
total
capital
expenditure
of
$
4
to
$
5
billion
per
year.
The
projected
total
annual
costs,
including
capital
recovery,
operating
costs,
monitoring,
recordkeeping,
and
reporting
is
$
154
million
per
year.
This
represents
less
than
one
tenth
of
1
percent
of
the
baseline
industry
revenues
of
$
290
billion
and
just
over
1.0
percent
of
baseline
industry
pre
tax
earnings
of
$
14
billion.
The
cost
analysis
assumed
that
each
existing
facility
would
use,
in
the
order
presented,
as
many
of
the
following
four
steps
as
necessary
to
meet
the
proposed
emission
limit.
First,
if
needed,
facilities
that
did
not
already
control
their
electrodeposition
primer
bake
oven
exhaust
would
install
and
operate
such
control
at
an
average
cost
of
$
8,200
per
ton
of
HAP
controlled.
Next,
if
needed,
facilities
would
reduce
the
HAP
to
VOC
ratio
of
their
primer
surfacer
and
topcoat
materials
to
0.3
to
1.0
at
an
average
cost
of
$
540
per
ton
of
HAP
controlled.
Finally,
if
needed,
facilities
would
control
the
necessary
amount
of
primer
surfacer
and
topcoat
spray
booth
exhaust
at
an
average
cost
of
$
40,000
per
ton
of
HAP
controlled.
For
all
four
steps
combined,
the
average
cost
is
about
$
25,000
per
ton
of
HAP
controlled.
New
facilities
and
new
paint
shops
would
incur
little
additional
cost
to
meet
the
proposed
emission
limit.
These
facilities
would
already
include
bake
oven
controls
and
partial
spray
booth
exhaust
controls
for
VOC
control
purposes.
New
facilities
might
need
to
make
some
downward
adjustment
in
the
HAP
content
of
their
materials
to
meet
the
proposed
emission
limit.
C.
What
Are
the
Economic
Impacts?
The
EPA
prepared
an
economic
impact
analysis
to
evaluate
the
primary
and
secondary
impacts
the
proposed
rule
would
have
on
the
producers
and
consumers
of
automobiles
and
lightduty
trucks,
and
society
as
a
whole.
The
analysis
was
conducted
to
determine
the
economic
impacts
associated
with
the
proposed
rule
at
both
the
market
and
industry
levels.
Overall,
the
analysis
indicates
a
minimal
change
in
vehicle
prices
and
production
quantities.
Based
on
the
estimated
compliance
costs
associated
with
the
proposed
rule
and
the
predicted
changes
in
prices
and
production
in
the
affected
industry,
the
estimated
annual
social
costs
of
the
proposed
rule
is
projected
to
be
$
161
million
(
1999
dollars).
The
social
costs
take
into
account
changes
in
behavior
by
producers
and
consumers
due
to
the
imposition
of
compliance
costs
from
the
proposed
rule.
For
this
reason
the
estimated
annual
social
costs
differ
from
the
estimated
annual
engineering
costs
of
$
154
million.
Producers,
in
aggregate,
are
expected
to
bear
$
152
million
annually
in
costs
while
the
consumers
are
expected
to
incur
the
remaining
$
10
million
in
social
costs
associated
with
the
proposed
rule.
The
economic
model
projects
an
aggregate
price
increase
for
the
modeled
vehicle
classes
of
automobiles
and
lightduty
trucks
to
be
less
than
1/
100th
of
1
percent
as
a
result
of
the
proposed
standards.
This
represents
at
most
an
increase
in
price
of
$
3.00
per
vehicle.
The
model
also
projects
that
directly
affected
producers
would
reduce
total
production
by
approximately
1,400
vehicles
per
year.
This
represents
approximately
0.01
percent
of
the
12.7
million
vehicles
produced
by
the
potentially
affected
plants
in
1999,
the
baseline
year
of
analysis.
In
terms
of
industry
impacts,
the
automobile
and
light
duty
truck
manufacturers
are
projected
to
experience
a
decrease
in
pre
tax
earnings
of
about
1
percent
or
$
152
million.
In
comparison,
total
pre
tax
earnings
for
the
potentially
affected
plants
included
in
the
analysis
exceeded
$
14
billion
in
1999.
The
reduction
in
pre
tax
earnings
of
1
percent
reflects
an
increase
in
production
costs
and
a
decline
in
revenues
earned
from
a
reduction
in
the
quantity
of
vehicles
sold.
Through
the
market
and
industry
impacts
described
above,
the
proposed
rule
would
lead
to
a
redistribution
of
profits
within
the
industry.
Some
facilities
(
28
percent)
are
projected
to
experience
a
profit
increase
with
the
proposed
rule;
however,
the
majority
(
72
percent)
that
continue
operating
are
projected
to
lose
profits.
No
facilities
are
projected
to
close
due
to
the
proposed
rule.
D.
What
Are
the
Non
Air
Health,
Environmental,
and
Energy
Impacts?
Solid
waste
and
water
impacts
of
the
proposed
rule
are
expected
to
be
negligible.
Capture
of
additional
organic
HAP
laden
streams
and
control
of
these
streams
with
regenerative
thermal
oxidizers
is
expected
to
require
an
additional
180
million
kilowatt
hours
per
year
and
an
additional
4.9
billion
standard
cubic
feet
per
year
of
natural
gas.
E.
Can
We
Achieve
the
Goals
of
the
Proposed
Rule
in
a
Less
Costly
Manner?
We
have
made
every
effort
in
developing
this
proposal
to
minimize
the
cost
to
the
regulated
community
and
allow
maximum
flexibility
in
compliance
options
consistent
with
our
statutory
obligations.
We
recognize,
however,
that
the
proposal
may
still
require
some
facilities
to
take
costly
steps
to
further
control
emissions
even
though
those
emissions
may
not
result
in
exposures
which
could
pose
an
excess
individual
lifetime
cancer
risk
greater
than
1
in
1
million
or
exceed
thresholds
determined
to
provide
an
ample
margin
of
safety
for
protecting
public
health
and
the
environment
from
the
effects
of
HAP.
We
are,
therefore,
specifically
soliciting
comment
on
whether
there
are
further
ways
to
structure
the
proposed
rule
to
focus
on
the
facilities
which
pose
significant
risks
and
avoid
the
imposition
of
high
costs
on
facilities
that
pose
little
risk
to
public
health
and
the
environment.
During
the
rulemaking
process
on
a
separate
proposed
NESHAP,
representatives
of
the
plywood
and
composite
wood
products
industry
provided
EPA
with
descriptions
of
three
approaches
that
they
believed
could
be
used
to
implement
more
cost
effective
reductions
in
risk.
These
approaches
could
be
effective
in
focusing
regulatory
controls
on
facilities
that
pose
significant
risks
and
avoiding
the
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2002
/
Proposed
Rules
imposition
of
high
costs
on
facilities
that
pose
little
risk
to
public
health
or
the
environment,
and
we
are
seeking
public
comment
on
the
utility
of
each
of
these
approaches
with
respect
to
this
rule.
The
docket
for
today's
proposed
rule
contains
``
white
papers''
prepared
by
the
plywood
and
composite
wood
products
industry
that
outline
their
proposed
approaches
(
see
docket
number
A
2001
22).
One
of
the
approaches,
an
applicability
cutoff
for
threshold
pollutants,
would
be
implemented
under
the
authority
of
CAA
section
112(
d)(
4);
the
second
approach,
subcategorization
and
delisting,
would
be
implemented
under
the
authority
of
CAA
section
112(
c)(
1)
and
(
c)(
9);
and
the
third
approach
would
involve
the
use
of
a
concentration
based
applicability
threshold.
We
are
seeking
comment
on
whether
these
approaches
are
legally
justified
and,
if
so,
we
ask
for
information
that
could
be
used
to
support
such
approaches.
The
MACT
program
outlined
in
CAA
section
112(
d)
is
intended
to
reduce
emissions
of
HAP
through
the
application
of
MACT
to
major
sources
of
toxic
air
pollutants.
Section
112(
c)(
9)
is
intended
to
allow
EPA
to
avoid
setting
MACT
standards
for
categories
or
subcategories
of
sources
that
pose
less
than
a
specified
level
of
risk
to
public
health
and
the
environment.
The
EPA
requests
comment
on
whether
the
proposals
described
here
appropriately
rely
on
these
provisions
of
CAA
section
112.
The
two
health
based
approaches
focus
on
assessing
inhalation
exposures
or
accounting
for
adverse
environmental
impacts.
In
addition
to
the
specific
requests
for
comment
noted
in
this
section,
we
are
also
interested
in
any
information
or
comment
concerning
technical
limitations,
environmental
and
cost
impacts,
compliance
assurance,
legal
rationale,
and
implementation
relevant
to
the
identified
approaches.
We
also
request
comment
on
appropriate
practicable
and
verifiable
methods
to
ensure
that
sources'
emissions
remain
below
levels
that
protect
public
health
and
the
environment.
We
will
evaluate
all
comments
before
determining
whether
to
include
an
approach
in
the
final
rule.
1.
Industry
HAP
emissions
and
potential
health
effects
For
the
automobile
and
light
duty
truck
surface
coating
source
category,
seven
HAP
account
for
over
95
percent
of
the
total
HAP
emitted.
Those
seven
HAP
are
toluene,
xylene,
glycol
ethers
(
including
ethylene
glycol
monobutyl
ether
(
EGBE)),
MEK,
MIBK,
ethylbenzene,
and
methanol.
Additional
HAP
which
may
be
emitted
by
some
automobile
and
light
duty
truck
surface
coating
operations
are:
Ethylene
glycol,
hexane,
formaldehyde,
chromium
compounds,
diisocyanates,
manganese
compounds,
methyl
methacrylate,
methylene
chloride,
and
nickel
compounds.
Of
the
seven
HAP
emitted
in
the
largest
quantities
by
this
source
category,
all
can
cause
toxic
effects
following
sufficient
exposure.
The
potential
toxic
effects
of
these
seven
HAP
include
effects
to
the
central
nervous
system,
such
as
fatigue,
nausea,
tremors,
and
loss
of
motor
coordination;
adverse
effects
on
the
liver,
kidneys,
and
blood;
respiratory
effects;
and
developmental
effects.
In
addition,
one
of
the
seven
predominant
HAP,
EGBE,
is
a
possible
carcinogen,
although
information
on
this
compound
is
not
currently
sufficient
to
allow
us
to
quantify
its
potency.
In
accordance
with
CAA
section
112(
k),
EPA
developed
a
list
of
33
HAP
which
present
the
greatest
threat
to
public
health
in
the
largest
number
of
urban
areas.
None
of
the
predominant
seven
HAP
is
included
on
this
list
for
EPA's
Urban
Air
Toxics
Program,
although
three
of
the
other
emitted
HAP
(
formaldehyde,
manganese
compounds,
and
nickel
compounds)
appear
on
the
list.
In
November
1998,
EPA
published
``
A
Multimedia
Strategy
for
Priority
Persistent,
Bioaccumulative,
and
Toxic
(
PBT)
Pollutants.''
None
of
the
predominant
seven
HAP
emitted
by
automobile
and
light
duty
truck
surface
coating
operations
appears
on
the
published
list
of
compounds
referred
to
in
EPA's
PBT
strategy.
To
estimate
the
potential
baseline
risks
posed
by
the
source
category
and
the
potential
impact
of
applicability
cutoffs,
EPA
performed
a
``
rough''
risk
assessment
for
56
of
the
approximately
60
facilities
in
the
source
category
by
using
a
model
plant
placed
at
the
actual
location
of
each
plant
and
simulating
impacts
using
air
emissions
data
from
the
1999
EPA
Toxics
Release
Inventory
(
TRI).
In
addition
to
the
seven
predominant
HAP,
the
following
additional
HAP
were
included
in
this
rough
risk
assessment
because
they
were
reported
in
TRI
as
being
emitted
by
facilities
in
the
source
category:
ethylene
glycol,
hexane,
formaldehyde,
diisocyanates,
manganese
compounds,
nickel
compounds,
and
benzene.
The
benzene
emissions
and
some
of
the
nickel
emissions
are
from
non
surface
coating
activities
which
are
not
part
of
the
source
category.
Of
the
HAP
reported
in
TRI
which
are
emitted
from
automobile
and
light
duty
truck
surface
coating
operations,
three
(
formaldehyde,
nickel
compounds,
and
EGBE)
are
carcinogens
that,
at
present,
are
not
considered
to
have
thresholds
for
cancer
effects.
Ethylene
glycol
monobutyl
ether,
however,
may
be
a
threshold
carcinogen,
as
suggested
by
some
recent
evidence
from
animal
studies,
though
EPA,
at
present,
considers
it
to
be
a
nonthreshold
carcinogen
without
sufficient
information
to
quantify
its
cancer
potency.
Likewise,
formaldehyde
is
a
potential
threshold
carcinogen,
and
EPA
is
currently
revising
the
dose
response
assessment
for
formaldehyde.
Most
facilities
in
this
source
category
emit
some
small
quantity
of
formaldehyde.
In
the
1999
TRI,
however,
only
two
facilities
in
this
source
category
reported
formaldehyde
emissions.
No
other
facilities
exceeded
the
TRI
reporting
threshold
for
formaldehyde
in
1999.
The
baseline
cancer
risk
and
subsequent
cancer
risk
reductions
were
estimated
to
be
minimal
for
this
source
category.
Of
the
three
carcinogens
included
in
the
assessment,
emissions
reductions
attributable
to
the
proposed
standards
could
be
estimated
for
only
EGBE.
However,
since
EGBE
risks
cannot
currently
be
quantified,
the
cancer
risk
reductions
associated
with
the
proposed
rule
are
estimated
by
this
rough
assessment
to
be
minimal.
However,
noncancer
risks
are
projected
to
be
significantly
reduced
by
the
proposed
rule.
(
Details
of
this
assessment
are
available
in
the
docket.)
2.
Applicability
Cutoffs
for
Threshold
Pollutants
Under
CAA
Section
112(
d)(
4)
The
first
approach
is
an
``
applicability
cutoff''
for
threshold
pollutants
that
is
based
on
EPA's
authority
under
CAA
section
112(
d)(
4)
to
establish
standards
for
HAP
which
are
``
threshold
pollutants.''
A
``
threshold
pollutant''
is
one
for
which
there
is
a
concentration
or
dose
below
which
adverse
effects
are
not
expected
to
occur
over
a
lifetime
of
exposure.
For
such
pollutants,
section
112(
d)(
4)
allows
EPA
to
consider
the
threshold
level,
with
an
ample
margin
of
safety,
when
establishing
emission
standards.
Specifically,
section
112(
d)(
4)
allows
EPA
to
establish
emission
standards
that
are
not
based
upon
the
MACT
specified
under
section
112(
d)(
2)
for
pollutants
for
which
a
health
threshold
has
been
established.
Such
standards
may
be
less
stringent
than
MACT.
Historically,
EPA
has
interpreted
section
112(
d)(
4)
to
allow
categories
of
sources
that
emit
only
threshold
pollutants
to
avoid
further
regulation
if
those
emissions
result
in
ambient
levels
that
do
not
exceed
the
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Proposed
Rules
1
See
63
18754,
18765
66
(
April
15,
1998)
(
Pulp
and
Paper
Combustion
Sources
Proposed
NESHAP).
2
``
Methods
for
Derivation
of
Inhalation
reference
Concentrations
and
Applications
of
Inhalation
Dosimetry.''
EPA
600/
8
90
066F,
Office
of
Research
and
Development,
USEPA,
October
1994.
3
``
Supplementary
Guidance
for
Conducting
Health
Risk
Assessment
of
Chemical
Mixtures.
Risk
Assessment
Forum
Technical
Panel,''
EPA/
630/
R
00/
002.
USEPA,
August
2000.
http://
www.
epa.
gov/
nceawww1/
pdfs/
chem_
mix/
chem_
mix_
08_
2001.
pdf.
threshold,
with
an
ample
margin
of
safety.
1
A
different
interpretation
would
allow
us
to
exempt
individual
facilities
within
a
source
category
that
meet
the
section
112(
d)(
4)
requirements.
There
are
three
potential
scenarios
under
this
interpretation
of
the
section
112(
d)(
4)
provision.
One
scenario
would
allow
an
exemption
for
individual
facilities
that
emit
only
threshold
pollutants
and
can
demonstrate
that
their
emissions
of
threshold
pollutants
would
not
result
in
air
concentrations
above
the
threshold
levels,
with
an
ample
margin
of
safety,
even
if
the
category
is
otherwise
subject
to
MACT.
A
second
scenario
would
allow
the
section
112(
d)(
4)
provision
to
be
applied
to
both
threshold
and
nonthreshold
pollutants,
using
the
1
in
1
million
cancer
risk
level
for
decisionmaking
for
non
threshold
pollutants.
A
third
scenario
would
allow
a
section
112(
d)(
4)
exemption
at
a
facility
that
emits
both
threshold
and
nonthreshold
pollutants.
For
those
emission
points
where
only
threshold
pollutants
are
emitted
and
where
emissions
of
the
threshold
pollutants
would
not
result
in
air
concentrations
above
the
threshold
levels,
with
an
ample
margin
of
safety,
those
emission
points
could
be
exempt
from
the
MACT
standards.
The
MACT
standards
would
still
apply
to
nonthreshold
emissions
from
other
emission
points
at
the
source.
For
this
third
scenario,
emission
points
that
emit
a
combination
of
threshold
and
nonthreshold
pollutants
that
are
cocontrolled
by
MACT
would
still
be
subject
to
the
MACT
level
of
control.
However,
any
threshold
HAP
eligible
for
exemption
under
section
112(
d)(
4)
that
are
controlled
by
control
devices
different
from
those
controlling
nonthreshold
HAP
would
be
able
to
use
the
exemption,
and
the
facility
would
still
be
subject
to
the
sections
of
the
standards
that
control
non
threshold
pollutants
or
that
control
both
threshold
and
non
threshold
pollutants.
Estimation
of
hazard
quotients
and
hazard
indices.
Under
the
section
112(
d)(
4)
approach,
EPA
would
have
to
determine
that
emissions
of
each
of
the
threshold
pollutants
emitted
by
automobile
and
light
duty
truck
surface
coating
operations
at
the
facility
do
not
result
in
exposures
which
exceed
the
threshold
levels,
with
an
ample
margin
of
safety.
The
common
approach
for
evaluating
the
potential
hazard
of
a
threshold
air
pollutant
is
to
calculate
a
``
hazard
quotient''
by
dividing
the
pollutant's
inhalation
exposure
concentration
(
often
assumed
to
be
equivalent
to
its
estimated
concentration
in
air
at
a
location
where
people
could
be
exposed)
by
the
pollutant's
inhalation
Reference
Concentration
(
RfC).
An
RfC
is
an
estimate
(
with
uncertainty
spanning
perhaps
an
order
of
magnitude)
of
a
continuous
inhalation
exposure
that,
over
a
lifetime,
likely
would
not
result
in
the
occurrence
of
adverse
health
effects
in
humans,
including
sensitive
individuals.
The
EPA
typically
establishes
an
RfC
by
applying
uncertainty
factors
to
the
critical
toxic
effect
derived
from
the
lowest
or
no
observed
adverse
effect
level
of
a
pollutant
2.
A
hazard
quotient
less
than
one
means
that
the
exposure
concentration
of
the
pollutant
is
less
than
the
RfC
and,
therefore,
presumed
to
be
without
appreciable
risk
of
adverse
health
effects.
A
hazard
quotient
greater
than
one
means
that
the
exposure
concentration
of
the
pollutant
is
greater
than
the
RfC.
Further,
EPA
guidance
for
assessing
exposures
to
mixtures
of
threshold
pollutants
recommends
calculating
a
hazard
index
(
HI)
by
summing
the
individual
hazard
quotients
for
those
pollutants
in
the
mixture
that
affect
the
same
target
organ
or
system
by
the
same
mechanism
3.
The
HI
values
would
be
interpreted
similarly
to
hazard
quotients;
values
below
one
would
generally
be
considered
to
be
without
appreciable
risk
of
adverse
health
effects,
and
values
above
one
would
generally
be
cause
for
concern.
For
the
determinations
discussed
herein,
EPA
would
generally
plan
to
use
RfC
values
contained
in
EPA's
toxicology
database,
the
Integrated
Risk
Information
System
(
IRIS).
When
a
pollutant
does
not
have
an
approved
RfC
in
IRIS,
or
when
a
pollutant
is
a
carcinogen,
EPA
would
have
to
determine
whether
a
threshold
exists
based
upon
the
availability
of
specific
data
on
the
pollutant's
mode
or
mechanism
of
action,
potentially
using
a
health
threshold
value
from
an
alternative
source,
such
as
the
Agency
for
Toxic
Substances
and
Disease
Registry
(
ATSDR)
or
the
California
Environmental
Protection
Agency
(
CalEPA).
Table
4
provides
RfC,
as
well
as
unit
risk
estimates,
for
the
HAP
emitted
by
automobile
and
light
duty
truck
surface
coating
operations.
A
unit
risk
estimate
is
defined
as
the
upperbound
excess
lifetime
cancer
risk
estimated
to
result
from
continuous
exposure
to
an
agent
at
a
concentration
of
1
ug/
m
3
in
the
air.
TABLE
4.
DOSE
RESPONSE
ASSESSMENT
VALUES
FOR
HAP
REPORTED
EMITTED
BY
THE
AUTOMOBILE
AND
LIGHT
DUTY
TRUCK
SURFACE
COATING
SOURCE
CATEGORY
Chemical
name
CAS
No.
Reference
concentration
a
(
mg/
m3)
Unit
risk
estimate
b
(
1/(
ug/
m3))
Chromium
(
VI)
compounds
................................................................
18540
29
9
1.0E
04
(
IRIS)
1.2E
02
(
IRIS)
Chromium
(
VI)
trioxide,
chromic
acid
mist
........................................
11115
74
5
8.0E
06
(
IRIS)
Ethyl
benzene
....................................................................................
100
41
4
1.0E+
00
(
IRIS)
Ethylene
glycol
...................................................................................
107
21
1
4.0E
01
(
CAL)
Formaldehyde
....................................................................................
50
00
0
9.8E
03
(
ATSDR)
1.3E
05
(
IRIS)
Diethylene
glycol
monobutyl
ether
.....................................................
112
34
5
2.0E
02
(
HEAST)
Ethylene
glycol
monobutyl
ether
........................................................
111
76
2
1.3E+
01
(
IRIS)
Hexamethylene
1,
6
diisocyanate
......................................................
822
06
0
1.0E
05
(
IRIS)
n
Hexane
...........................................................................................
110
54
3
2.0E
01
(
IRIS)
Manganese
compounds
....................................................................
7439
96
5
5.0E
05
(
IRIS)
Methanol
............................................................................................
67
56
1
4.0E+
00
(
CAL)
Methyl
ethyl
ketone
............................................................................
78
93
3
1.0E+
00
(
IRIS)
Methyl
isobutyl
ketone
.......................................................................
108
10
1
8.0E
02
(
HEAST)
Methyl
methacrylate
...........................................................................
80
62
6
7.0E
01
(
IRIS)
Methylene
chloride
.............................................................................
75
09
2
1.0E+
00
(
ATSDR)
4.7E
07
(
IRIS)
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2002
/
Proposed
Rules
4
Ibid.
5
Senate
Debate
on
Conference
Report
(
October
27,
1990),
reprinted
in
``
A
Legislative
History
of
the
Clean
Air
Act
Amendments
of
1990,''
Comm.
Print
S.
Prt.
103
38
(
1993)
(``
Legis.
Hist.'')
at
868.
TABLE
4.
DOSE
RESPONSE
ASSESSMENT
VALUES
FOR
HAP
REPORTED
EMITTED
BY
THE
AUTOMOBILE
AND
LIGHT
DUTY
TRUCK
SURFACE
COATING
SOURCE
CATEGORY
Continued
Chemical
name
CAS
No.
Reference
concentration
a
(
mg/
m3)
Unit
risk
estimate
b
(
1/(
ug/
m3))
Methylene
diphenyl
diisocyanate
.......................................................
101
68
8
6.0E
04
(
IRIS)
Nickel
compounds
.............................................................................
7440
02
0
2.0E
04
(
ATSDR)
Nickel
oxide
.......................................................................................
1313
99
1
1.0E
04
(
CAL)
Toluene
..............................................................................................
108
88
3
4.0E
01
(
IRIS)
2,4/
2,6
Toluene
diisocyanate
mixture
(
TDI)
......................................
26471
62
5
7.0E
05
(
IRIS)
1.1E
05
(
CAL)
Xylenes
(
mixed)
.................................................................................
1330
20
7
4.3E
01
(
ATSDR)
a
Reference
Concentration:
An
estimate
(
with
uncertainty
spanning
perhaps
an
order
of
magnitude)
of
a
continuous
inhalation
exposure
to
the
human
population
(
including
sensitive
subgroups
which
include
children,
asthmatics,
and
the
elderly)
that
is
likely
to
be
without
an
appreciable
risk
of
deleterious
effects
during
a
lifetime.
It
can
be
derived
from
various
types
of
human
or
animal
data,
with
uncertainty
factors
generally
applied
to
reflect
limitations
of
the
data
used.
b
Unit
Risk
Estimate:
The
upper
bound
excess
lifetime
cancer
risk
estimated
to
result
from
continuous
exposure
to
an
agent
at
a
concentration
of
1
ug/
m3
in
air.
The
interpretation
of
the
Unit
Risk
Estimate
would
be
as
follows:
if
the
Unit
Risk
Estimate
=
1.5
×
10
¥
6
per
ug/
m3,
1.5
excess
tumors
are
expected
to
develop
per
1,000,000
people
if
exposed
daily
for
a
lifetime
to
1
ug
of
the
chemical
in
1
cubic
meter
of
air.
Unit
Risk
Estimates
are
considered
upper
bound
estimates,
meaning
they
represent
a
plausible
upper
limit
to
the
true
value.
(
Note
that
this
is
usually
not
a
true
statistical
confidence
limit.)
The
true
risk
is
likely
to
be
less,
but
could
be
greater.
Sources:
IRIS
=
EPA
Integrated
Risk
Information
System
(
http://
www.
epa.
gov/
iris/
subst/
index.
html)
ATSDR
=
U.
S.
Agency
for
Toxic
Substances
and
Disease
Registry
(
http://
www.
atsdr.
cdc.
gov/
mrls.
html)
CAL
=
California
Office
of
Environmental
Health
Hazard
Assessment
(
http://
www.
oehha.
ca.
gov/
air/
hot_
spots/
index.
html)
HEAST
=
EPA
Health
Effects
Assessment
Summary
Tables
(#
PB(=
97
921199,
July
1997).
To
establish
an
applicability
cutoff
under
section
112(
d)(
4),
EPA
would
need
to
define
ambient
air
exposure
concentration
limits
for
any
threshold
pollutants
involved.
There
are
several
factors
to
consider
when
establishing
such
concentrations.
First,
we
would
need
to
ensure
that
the
concentrations
that
would
be
established
would
protect
public
health
with
an
ample
margin
of
safety.
As
discussed
above,
the
approach
EPA
commonly
uses
when
evaluating
the
potential
hazard
of
a
threshold
air
pollutant
is
to
calculate
the
pollutant's
hazard
quotient,
which
is
the
exposure
concentration
divided
by
the
RfC.
The
EPA's
``
Supplementary
Guidance
for
Conducting
Health
Risk
Assessment
of
Chemical
Mixtures''
suggests
that
the
noncancer
health
effects
associated
with
a
mixture
of
pollutants
ideally
are
assessed
by
considering
the
pollutants'
common
mechanisms
of
toxicity.
4
The
guidance
also
suggests
that
when
exposures
to
mixtures
of
pollutants
are
being
evaluated,
the
risk
assessor
may
calculate
a
HI.
The
recommended
method
is
to
calculate
multiple
hazard
indices
for
each
exposure
route
of
interest
and
for
a
single
specific
toxic
effect
or
toxicity
to
a
single
target
organ.
The
default
approach
recommended
by
the
guidance
is
to
sum
the
hazard
quotients
for
those
pollutants
that
induce
the
same
toxic
effect
or
affect
the
same
target
organ.
A
mixture
is
then
assessed
by
several
HI,
each
representing
one
toxic
effect
or
target
organ.
The
guidance
notes
that
the
pollutants
included
in
the
HI
calculation
are
any
pollutants
that
show
the
effect
being
assessed,
regardless
of
the
critical
effect
upon
which
the
RfC
is
based.
The
guidance
cautions
that
if
the
target
organ
or
toxic
effect
for
which
the
HI
is
calculated
is
different
from
the
RfC's
critical
effect,
then
the
RfC
for
that
chemical
will
be
an
overestimate,
that
is,
the
resultant
HI
potentially
may
be
overprotective.
Conversely,
since
the
calculation
of
a
HI
does
not
account
for
the
fact
that
the
potency
of
a
mixture
of
HAP
can
be
more
potent
than
the
sum
of
the
individual
HAP
potencies,
a
HI
may
potentially
be
underprotective
in
some
situations.
Options
for
establishing
a
HI
limit.
One
consideration
in
establishing
a
HI
limit
is
whether
the
analysis
considers
the
total
ambient
air
concentrations
of
all
the
emitted
HAP
to
which
the
public
is
exposed.
5
There
are
several
options
for
establishing
a
HI
limit
for
the
section
112(
d)(
4)
analysis
that
reflect,
to
varying
degrees,
public
exposure.
One
option
is
to
allow
the
HI
posed
by
all
threshold
HAP
emitted
from
automobile
and
light
duty
truck
surface
coating
operations
at
the
facility
to
be
no
greater
than
one.
This
approach
is
protective
if
no
additional
threshold
HAP
exposures
would
be
anticipated
from
other
sources
at,
or
in
the
vicinity
of,
the
facility
or
through
other
routes
of
exposure
(
e.
g.,
through
dermal
absorption).
A
second
option
is
to
adopt
a
``
default
percentage''
approach,
whereby
the
HI
limit
of
the
HAP
emitted
by
the
facility
is
set
at
some
percentage
or
fraction
of
one
(
e.
g.,
20
percent
or
0.2).
This
approach
recognizes
the
fact
that
the
facility
in
question
is
only
one
of
many
sources
of
threshold
HAP
to
which
people
are
typically
exposed
every
day.
Because
noncancer
risk
assessment
is
predicated
on
total
exposure
or
dose,
and
because
risk
assessments
focus
only
on
an
individual
source,
establishing
a
HI
limit
of
0.2
would
account
for
an
assumption
that
20
percent
of
an
individual's
total
exposure
is
from
that
individual
source.
For
the
purposes
of
this
discussion,
we
will
call
all
sources
of
HAP,
other
than
operations
within
the
source
category
at
the
facility
in
question,
``
background''
sources.
If
the
affected
source
is
allowed
to
emit
HAP
such
that
its
own
impacts
could
result
in
HI
values
of
one,
total
exposures
to
threshold
HAP
in
the
vicinity
of
the
facility
could
be
substantially
greater
than
one
due
to
background
sources,
and
this
would
not
be
protective
of
public
health
since
only
HI
values
below
one
are
considered
to
be
without
appreciable
risk
of
adverse
health
effects.
Thus,
setting
the
HI
limit
for
the
facility
at
some
default
percentage
of
one
will
provide
a
buffer
which
would
help
to
ensure
that
total
exposures
to
threshold
HAP
near
the
facility
(
i.
e.,
in
combination
with
exposures
due
to
background
sources)
will
generally
not
exceed
one
and
can
generally
be
considered
to
be
without
appreciable
risk
of
adverse
health
effects.
The
EPA
requests
comment
on
using
the
``
default
percentage''
approach
and
on
setting
the
default
HI
limit
at
0.2.
The
EPA
is
also
requesting
comment
on
whether
an
alternative
HI
limit,
in
some
multiple
of
one,
would
be
a
more
appropriate
applicability
cutoff.
A
third
option
is
to
use
available
data
(
from
scientific
literature
or
EPA
studies,
for
example)
to
determine
background
concentrations
of
HAP,
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2002
/
Proposed
Rules
6
See
http://
www.
epa.
gov/
ttn/
atw/
nata.
7
See
http://
www.
atsdr.
cdc.
gov/
toxpro2.
html.
8
``
A
Tiered
Modeling
Approach
for
Assessing
the
Risks
due
to
Sources
of
Hazardous
Air
Pollutants.''
EPA
450/
4
92
001.
David
E.
Guinnup,
Office
of
Air
Quality
Planning
and
Standards,
USEPA,
March
1992.
9
``
Draft
Revised
Guidelines
for
Carcinogen
Risk
Assessment.''
NCEA
F
0644.
USEPA,
Risk
Assessment
Forum,
July
1999.
pp
3
9ff.
http://
www.
epa.
gov/
ncea/
raf/
pdfs/
cancer_
gls.
pdf.
possibly
on
a
national
or
regional
basis.
These
data
would
be
used
to
estimate
the
exposures
to
HAP
from
activities
other
than
automobile
and
light
duty
truck
surface
coating
operations.
For
example,
EPA's
National
Scale
Air
Toxics
Assessment
(
NATA)
6
and
ATSDR's
Toxicological
Profiles
7
contain
information
about
background
concentrations
of
some
HAP
in
the
atmosphere
and
other
media.
The
combined
exposures
from
an
affected
source
and
from
background
emissions
(
as
determined
from
the
literature
or
studies)
would
then
not
be
allowed
to
exceed
a
HI
limit
of
1.0.
The
EPA
requests
comment
on
the
appropriateness
of
setting
the
HI
limit
at
one
for
such
an
analysis.
A
fourth
option
is
to
allow
facilities
to
estimate
or
measure
their
own
facility
specific
background
HAP
concentrations
for
use
in
their
analysis.
With
regard
to
the
third
and
fourth
options,
EPA
requests
comment
on
how
these
analyses
could
be
structured.
Specifically,
EPA
requests
comment
on
how
the
analyses
should
take
into
account
background
exposure
levels
from
air,
water,
food,
and
soil
encountered
by
the
individuals
exposed
to
emissions
from
this
source
category.
In
addition,
we
request
comment
on
how
such
analyses
should
account
for
potential
increases
in
exposures
due
to
the
use
of
a
new
HAP
or
the
increased
use
of
a
previously
emitted
HAP,
or
the
effect
of
other
nearby
sources
that
release
HAP.
The
EPA
requests
comment
on
the
feasibility
and
scientific
validity
of
each
of
these
or
other
options.
Finally,
EPA
requests
comment
on
how
we
should
implement
the
section
112(
d)(
4)
applicability
cutoffs,
including
appropriate
mechanisms
for
applying
cutoffs
to
individual
facilities.
For
example,
would
the
title
V
permit
process
provide
an
appropriate
mechanism?
Tiered
analytical
approach
for
predicting
exposure.
Establishing
that
a
facility
meets
the
cutoffs
established
under
section
112(
d)(
4)
will
necessarily
involve
combining
estimates
of
pollutant
emissions
with
air
dispersion
modeling
to
predict
exposures.
The
EPA
envisions
that
we
would
promote
a
tiered
analysis
for
these
determinations.
A
tiered
analysis
involves
making
successive
refinements
in
modeling
methodologies
and
input
data
to
derive
successively
less
conservative,
more
realistic
estimates
of
pollutant
concentrations
in
air
and
estimates
of
risk.
As
a
first
tier
of
analysis,
EPA
could
develop
a
series
of
simple
look
up
tables
based
on
the
results
of
air
dispersion
modeling
conducted
using
conservative
input
assumptions.
By
specifying
a
limited
number
of
input
parameters,
such
as
stack
height,
distance
to
property
line,
and
emission
rate,
a
facility
could
use
these
look
up
tables
to
determine
easily
whether
the
emissions
from
their
sources
might
cause
a
HI
limit
to
be
exceeded.
A
facility
that
does
not
pass
this
initial
conservative
screening
analysis
could
implement
increasingly
more
sitespecific
and
resource
intensive
tiers
of
analysis
using
EPA
approved
modeling
procedures
in
an
attempt
to
demonstrate
that
exposure
to
emissions
from
the
facility
does
not
exceed
the
HI
limit.
Existing
EPA
guidance
could
provide
the
basis
for
conducting
such
a
tiered
analysis.
8
The
EPA
requests
comment
on
methods
for
constructing
and
implementing
a
tiered
analysis
for
determining
applicability
of
the
section
112(
d)(
4)
criteria
to
specific
automobile
and
light
duty
truck
surface
coating
sources.
Ambient
monitoring
data
could
possibly
be
used
to
supplement
or
supplant
the
tiered
modeling
analysis
described
above.
We
envision
that
the
appropriate
monitoring
to
support
such
a
determination
could
be
extensive.
The
EPA
requests
comment
on
the
appropriate
use
of
monitoring
in
the
determinations
described
above.
Accounting
for
dose
response
relationships.
In
the
past,
EPA
routinely
treated
carcinogens
as
non
threshold
pollutants.
The
EPA
recognizes
that
advances
in
risk
assessment
science
and
policy
may
affect
the
way
EPA
differentiates
between
threshold
and
non
threshold
HAP.
The
EPA's
draft
Guidelines
for
Carcinogen
Risk
Assessment
9
suggest
that
carcinogens
be
assigned
non
linear
dose
response
relationships
where
data
warrant.
Moreover,
it
is
possible
that
doseresponse
curves
for
some
pollutants
may
reach
zero
risk
at
a
dose
greater
than
zero,
creating
a
threshold
for
carcinogenic
effects.
It
is
possible
that
future
evaluations
of
the
carcinogens
emitted
by
this
source
category
would
determine
that
one
or
more
of
the
carcinogens
in
the
category
is
a
threshold
carcinogen
or
is
a
carcinogen
that
exhibits
a
non
linear
dose
response
relationship
but
does
not
have
a
threshold.
The
dose
response
assessment
for
formaldehyde
is
currently
undergoing
revision
by
EPA.
As
part
of
this
revision
effort,
EPA
is
evaluating
formaldehyde
as
a
potential
non
linear
carcinogen.
The
revised
dose
response
assessment
will
be
subject
to
review
by
the
EPA
Science
Advisory
Board,
followed
by
full
consensus
review,
before
adoption
into
the
EPA's
IRIS.
At
this
time,
EPA
estimates
that
the
consensus
review
will
be
completed
by
the
end
of
2003.
The
revision
of
the
dose
response
assessment
could
affect
the
potency
factor
of
formaldehyde,
as
well
as
its
status
as
a
threshold
or
non
threshold
pollutant.
At
this
time,
the
outcome
is
not
known.
In
addition
to
the
current
reassessment
by
EPA,
there
have
been
several
reassessments
of
the
toxicity
and
carcinogenicity
of
formaldehyde
in
recent
years,
including
work
by
the
World
Health
Organization
and
the
Canadian
Ministry
of
Health.
The
EPA
requests
comment
on
how
we
should
consider
the
state
of
the
science
as
it
relates
to
the
treatment
of
threshold
pollutants
when
making
determinations
under
section
112(
d)(
4).
In
addition,
EPA
requests
comment
on
whether
there
is
a
level
of
emissions
of
a
non
threshold
carcinogenic
HAP
at
which
it
would
be
appropriate
to
allow
a
facility
to
use
the
scenarios
discussed
under
the
section
112(
d)(
4)
approach.
Risk
assessment
results.
The
results
of
the
human
health
risk
assessments
described
below
are
based
on
approaches
for
quantifying
exposure,
risk,
and
cancer
incidence
that
carry
significant
assumptions,
uncertainties,
and
limitations.
For
example,
in
conducting
these
types
of
analyses,
there
are
typically
many
uncertainties
regarding
dose
response
functions,
levels
of
exposure,
exposed
populations,
air
quality
modeling
applications,
emission
levels,
and
control
effectiveness.
Because
the
estimates
derived
from
the
various
scoping
approaches
are
necessarily
rough,
we
are
concerned
that
they
not
convey
a
false
sense
of
precision.
Any
point
estimates
of
risk
reduction
or
benefits
generated
by
these
approaches
should
be
considered
as
part
of
a
range
of
potential
estimates.
If
the
final
rule
is
implemented
as
proposed
at
all
automobile
and
lightduty
truck
surface
coating
facilities,
the
number
of
people
exposed
to
HI
values
equal
to,
or
greater
than,
one
was
estimated
to
be
reduced
from
about
100
to
about
ten.
The
number
of
people
exposed
to
HI
values
of
0.2
or
greater
was
predicted
to
decrease
from
about
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3,500
to
about
1,200.
(
Details
of
these
analyses
are
available
in
the
docket.)
Based
on
the
results
of
this
rough
assessment,
if
the
section
112(
d)(
4)
approach
is
applied
only
to
threshold
pollutants,
EPA
estimates
that
none
of
the
facilities
in
this
source
category
could
obtain
an
exemption
from
regulation,
since
all,
or
nearly
all,
facilities
emit
some
amount
of
one
or
more
non
threshold
pollutants.
This
application
of
the
section
112(
d)(
4)
approach
is
estimated
to
produce
minimal
potential
cost
savings.
If
formaldehyde
and
EGBE
are
determined
to
be
threshold
carcinogens,
these
estimates
could
change.
The
second
scenario
under
the
section
112(
d)(
4)
provision
would
apply
to
both
threshold
and
non
threshold
pollutants.
If
this
scenario
is
selected,
EPA
estimates,
using
a
HI
limit
of
one
and
treating
10
¥
6
as
a
cancer
risk
threshold,
that
as
many
as
54
of
the
facilities
in
the
source
category
may
be
exempt
from
the
proposed
rule.
The
EPA
estimates
in
this
case
that
the
annualized
cost
of
the
proposed
rule
would
be
about
$
9
million
per
year,
resulting
in
cost
savings
of
about
$
145
million
per
year
(
as
compared
to
establishing
a
MACT
standard
for
all
plants
in
the
industry).
Using
a
HI
limit
of
0.2
and
treating
10
¥
6
as
a
cancer
risk
threshold,
EPA
estimates
that
as
many
as
41
facilities
may
be
exempt
from
the
proposed
rule.
The
EPA
estimates
in
this
case
that
the
annualized
cost
of
the
proposed
rule
would
be
about
$
66
million
per
year,
resulting
in
cost
savings
of
about
$
88
million
per
year
(
as
compared
to
establishing
a
MACT
standard
for
all
plants
in
the
industry).
The
EPA
does
not
expect
the
third
scenario,
which
would
allow
emission
point
exemptions,
to
be
applicable
for
the
automobile
and
light
duty
truck
surface
coating
source
category
because
mixtures
of
threshold
and
non
threshold
pollutants
are
co
emitted,
and
the
same
emission
controls
would
apply
to
both.
The
risk
estimates
from
this
rough
assessment
are
based
on
typical
facility
configurations
(
i.
e.,
model
plants)
and,
as
such,
they
are
subject
to
significant
uncertainties,
such
that
the
actual
risks
at
any
one
facility
could
be
significantly
higher
or
lower.
Therefore,
while
these
risk
estimates
assist
in
providing
a
broad
picture
of
impacts
across
the
source
category,
they
should
not
be
the
basis
for
an
exemption
from
the
requirements
of
the
proposed
rule.
Rather,
any
such
exemption
should
be
based
on
an
estimate
of
the
facilityspecific
risks
which
would
require
sitespecific
data
and
a
more
refined
analysis.
For
either
of
the
first
two
approaches
described
above,
the
actual
number
of
facilities
that
would
qualify
for
an
exemption
would
depend
upon
sitespecific
risk
assessments
and
the
specified
HI
limit
(
see
earlier
discussion
of
HI
limit).
If
the
section
112(
d)(
4)
approach
were
adopted,
the
requirements
of
the
proposed
rule
would
not
apply
to
any
source
that
demonstrates,
based
on
a
tiered
analysis
that
includes
EPA
approved
modeling
of
the
affected
source's
emissions,
that
the
anticipated
HAP
exposures
do
not
exceed
the
specified
HI
limit.
3.
Subcategory
Delisting
Under
Section
112(
c)(
9)(
B)
of
the
CAA
The
EPA
is
authorized
to
establish
categories
and
subcategories
of
sources,
as
appropriate,
pursuant
to
CAA
section
112(
c)(
1),
in
order
to
facilitate
the
development
of
MACT
standards
consistent
with
section
112
of
the
CAA.
Further,
section
112(
c)(
9)(
B)
allows
EPA
to
delete
a
category
(
or
subcategory)
from
the
list
of
major
sources
for
which
MACT
standards
are
to
be
developed
when
the
following
can
be
demonstrated:
(
1)
In
the
case
of
carcinogenic
pollutants,
that
``*
*
*
no
source
in
the
category
*
*
*
emits
(
carcinogenic)
air
pollutants
in
quantities
which
may
cause
a
lifetime
risk
of
cancer
greater
than
1
in
1
million
to
the
individual
in
the
population
who
is
most
exposed
to
emissions
of
such
pollutants
from
the
source
*
*
*'';
(
2)
in
the
case
of
pollutants
that
cause
adverse
noncancer
health
effects,
that
``*
*
*
emissions
from
no
source
in
the
category
or
subcategory
*
*
*
exceed
a
level
which
is
adequate
to
protect
public
health
with
an
ample
margin
of
safety
*
*
*'';
and
(
3)
in
the
case
of
pollutants
that
cause
adverse
environmental
effects,
that
``
no
adverse
environmental
effect
will
result
from
emissions
from
any
source.
*
*
*''
Given
these
authorities
and
the
suggestions
from
the
white
papers
prepared
by
industry
representatives
and
discussed
previously
(
see
docket
A
2001
22),
EPA
is
considering
whether
it
would
be
possible
to
establish
a
subcategory
of
facilities
within
the
larger
source
category
that
would
meet
the
risk
based
criteria
for
delisting.
Such
criteria
would
likely
include
the
same
requirements
as
described
previously
for
the
second
scenario
under
the
section
112(
d)(
4)
approach,
whereby
a
facility
would
be
in
the
low
risk
subcategory
if
its
emissions
of
threshold
pollutants
do
not
result
in
exposures
which
exceed
the
HI
limits,
and
if
its
emissions
of
non
threshold
pollutants
do
not
result
in
exposures
which
exceed
a
cancer
risk
level
of
10
¥
6.
The
EPA
requests
comment
on
what
an
appropriate
HI
limit
would
be
for
a
determination
that
a
facility
be
included
in
the
low
risk
subcategory.
Since
each
facility
in
such
a
subcategory
would
be
a
low
risk
facility
(
i.
e.,
each
would
meet
these
criteria),
the
subcategory
could
be
delisted
in
accordance
with
section
112(
c)(
9),
thereby
limiting
the
costs
and
impacts
of
the
proposed
MACT
rule
to
only
those
facilities
that
do
not
qualify
for
subcategorization
and
delisting.
The
EPA
estimates
that
the
maximum
potential
of
utilizing
this
approach
would
be
the
same
as
that
of
applying
the
section
112(
d)(
4)
approach
for
threshold
and
non
threshold
pollutants,
though
the
actual
impact
is
likely
to
be
less.
For
example,
with
a
HI
value
limit
of
one
and
treating
10
¥
6
as
a
cancer
risk
threshold,
as
many
as
54
of
the
facilities
may
be
exempted
under
this
approach.
Alternatively,
with
a
HI
limit
of
0.2
and
treating
10
¥
6
as
a
cancer
risk
threshold,
as
many
as
41
facilities
may
be
exempted
under
this
approach.
Facilities
seeking
to
be
included
in
the
delisted
subcategory
would
be
responsible
for
providing
all
data
required
to
determine
whether
they
are
eligible
for
inclusion.
Facilities
that
could
not
demonstrate
that
they
are
eligible
to
be
included
in
the
low
risk
subcategory
would
be
subject
to
MACT
and
possible
future
residual
risk
standards.
The
EPA
solicits
comment
on
implementing
a
risk
based
approach
for
establishing
subcategories
of
automobile
and
light
duty
truck
surface
coating
facilities.
Establishing
that
a
facility
qualifies
for
the
low
risk
subcategory
under
section
112(
c)(
9)
will
necessarily
involve
combining
estimates
of
pollutant
emissions
with
air
dispersion
modeling
to
predict
exposures.
The
EPA
envisions
that
we
would
employ
the
same
tiered
analysis
described
earlier
in
the
section
112(
d)(
4)
discussion
for
these
determinations.
One
concern
that
EPA
has
with
respect
to
the
section
112(
c)(
9)
approach
is
the
effect
that
it
could
have
on
the
MACT
floors.
If
many
of
the
facilities
in
the
low
risk
subcategory
are
wellcontrolled
that
could
make
the
MACT
floor
less
stringent
for
the
remaining
facilities.
One
approach
that
has
been
suggested
to
mitigate
this
effect
would
be
to
establish
the
MACT
floor
now
based
on
controls
in
place
for
the
entire
category
and
to
allow
facilities
to
become
part
of
the
low
risk
subcategory
in
the
future,
after
the
MACT
standards
are
established.
This
would
allow
lowrisk
facilities
to
use
the
section
112(
c)(
9)
exemption
without
affecting
the
MACT
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floor
calculation.
The
EPA
requests
comment
on
this
suggested
approach.
Another
scenario
under
the
section
112(
c)(
9)
approach
would
be
to
define
a
subcategory
of
facilities
within
the
source
category
based
upon
technological
differences,
such
as
differences
in
production
rate,
emission
vent
flow
rates,
overall
facility
size,
emissions
characteristics,
processes,
or
air
pollution
control
device
viability.
The
EPA
requests
comment
on
how
we
might
establish
subcategories
based
on
these,
or
other,
source
characteristics.
If
it
could
then
be
determined
that
each
source
in
this
technologically
defined
subcategory
presents
a
low
risk
to
the
surrounding
community,
the
subcategory
could
then
be
delisted
in
accordance
with
section
112(
c)(
9).
The
EPA
requests
comment
on
the
concept
of
identifying
technologically
based
subcategories
that
may
include
only
low
risk
facilities
within
the
source
category.
If
a
section
112(
c)(
9)
approach
were
adopted,
the
requirements
of
the
proposed
rule
would
not
apply
to
any
source
that
demonstrates
that
it
belongs
in
a
subcategory
which
has
been
delisted
under
section
112(
c)(
9).
Consideration
of
criteria
pollutants.
Finally,
EPA
projects
that
adoption
of
the
MACT
floor
level
of
controls
would
result
in
increases
in
nitrogen
oxide
(
NOX)
emissions.
This
pollutant
is
a
precursor
in
the
formation
of
ozone
and
fine
particulate
matter
(
PM).
Ozone
has
been
associated
with
a
variety
of
adverse
health
effects
such
as
reduced
lung
function,
respiratory
symptoms
(
e.
g.,
cough
and
chest
pain)
and
increased
hospital
admissions
and
emergency
room
visits
for
respiratory
causes.
Fine
PM
has
been
associated
with
a
variety
of
adverse
health
effects
such
as
premature
mortality,
chronic
bronchitis,
and
increased
frequency
of
asthma
attacks.
The
EPA
requests
comments
on
the
extent
to
which
consideration
should
be
given
to
the
adverse
effects
of
the
possible
increase
in
NOX
emissions
from
applying
MACT
technology,
in
the
context
of
implementing
our
authority
under
section
112(
c)(
9)
or
other
exemptions.
V.
How
Will
the
Proposed
Amendments
to
40
CFR
Parts
264
and
265,
Subparts
BB
of
the
Hazardous
Waste
Regulations
Be
Implemented
in
the
States?
A.
Applicability
of
Federal
Rules
in
Authorized
States
Under
section
3006
of
the
RCRA,
EPA
may
authorize
a
qualified
State
to
administer
and
enforce
a
hazardous
waste
program
within
the
State
in
lieu
of
the
Federal
program
and
to
issue
and
enforce
permits
in
the
State.
A
State
may
receive
authorization
by
following
the
approval
process
described
under
40
CFR
271.21.
See
40
CFR
part
271
for
the
overall
standards
and
requirements
for
authorization.
The
EPA
continues
to
have
independent
authority
to
bring
enforcement
actions
under
RCRA
sections
3007,
3008,
3013,
and
7003.
An
authorized
State
also
continues
to
have
independent
authority
to
bring
enforcement
actions
under
State
law.
After
a
State
receives
initial
authorization,
new
Federal
requirements
promulgated
under
RCRA
authority
existing
prior
to
the
1984
Hazardous
and
Solid
Waste
Amendments
(
HSWA)
do
not
apply
in
that
State
until
the
State
adopts
and
receives
authorization
for
equivalent
State
requirements.
In
contrast,
under
RCRA
section
3006(
g)
(
42
U.
S.
C.
6926(
g)),
new
Federal
requirements
and
prohibitions
promulgated
pursuant
to
HSWA
provisions
take
effect
in
authorized
States
at
the
same
time
that
they
take
effect
in
unauthorized
States.
As
such,
EPA
carries
out
HSWA
requirements
and
prohibitions
in
authorized
States,
including
the
issuance
of
new
permits
implementing
those
requirements,
until
EPA
authorizes
the
State
to
do
so.
Authorized
States
are
required
to
modify
their
programs
when
EPA
promulgates
Federal
requirements
that
are
more
stringent
or
broader
in
scope
than
existing
Federal
requirements.
The
RCRA
section
3009
allows
the
States
to
impose
standards
more
stringent
than
those
in
the
Federal
program.
(
See
also
section
271.1(
i)).
Therefore,
authorized
States
are
not
required
to
adopt
Federal
regulations,
both
HSWA
and
non
HSWA,
that
are
considered
less
stringent
than
existing
Federal
requirements.
B.
Authorization
of
States
for
Today's
Proposed
Amendments
Currently,
the
air
emissions
from
the
collection,
transmission,
and
storage
of
purged
paint
and
solvent
at
automobile
and
light
duty
truck
assembly
plants
are
regulated
under
the
authority
of
RCRA
(
see
40
CFR
parts
264
and
265,
subparts
BB).
The
proposed
amendments
would
exempt
these
wastes
from
regulation
under
RCRA
and
defer
regulation
to
the
CAA
requirements
of
40
CFR
part
63,
subpart
IIII,
which
is
also
being
proposed
today.
This
exemption
is
considered
to
be
less
stringent
than
the
existing
RCRA
regulations
and,
therefore,
States
are
not
required
to
adopt
and
seek
authorization
for
today's
proposed
exemption.
However,
EPA
will
strongly
encourage
States
to
adopt
today's
proposed
RCRA
provisions
and
seek
authorization
for
them
to
prevent
duplication
with
the
new
NESHAP
when
final.
VI.
Solicitation
of
Comments
and
Public
Participation
We
welcome
comments
from
interested
persons
on
any
aspect
of
the
proposed
standards
and
on
any
statement(
s)
in
this
preamble
or
in
the
referenced
supporting
documents.
In
particular,
we
request
comments
on
how
monitoring,
recordkeeping,
and
reporting
requirements
can
be
consolidated
for
sources
that
are
subject
to
more
than
one
rule.
For
example,
all
automobile
and
light
duty
truck
assembly
plants
are
subject
to
VOC
regulations
and
some
may
perform
coating
activities
which
would
be
subject
to
the
NESHAP
for
plastic
parts
coating
or
miscellaneous
metal
parts
coating,
both
currently
under
development.
Supporting
data
and
detailed
analyses
should
be
submitted
with
comments
to
allow
us
to
make
maximum
use
of
the
comments.
All
comments
should
be
directed
to
the
Air
and
Radiation
Docket
and
Information
Center,
Docket
No.
A
2001
22
(
see
ADDRESSES).
Comments
on
the
proposed
rule
must
be
submitted
on
or
before
the
date
specified
in
DATES.
VII.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
EPA
must
determine
whether
the
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
the
Executive
Order.
The
Executive
Order
defines
``
significant
regulatory
action''
as
one
that
is
likely
to
result
in
a
rule
that
may:
(
1)
Have
an
annual
effect
on
the
economy
of
$
100
million
or
more
or
adversely
affect
in
a
material
way
the
economy,
a
sector
of
the
economy,
productivity,
competition,
jobs,
the
environment,
public
health
or
safety,
or
State,
local,
or
tribal
governments
or
communities;
(
2)
create
a
serious
inconsistency
or
otherwise
interfere
with
an
action
taken
or
planned
by
another
agency;
(
3)
materially
alter
the
budgetary
impact
of
entitlements,
grants,
user
fees,
or
loan
programs,
or
the
rights
and
obligation
of
recipients
thereof;
or
(
4)
raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
Pursuant
to
the
terms
of
Executive
Order
12866,
it
has
been
determined
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/
Proposed
Rules
that
the
proposed
rule
is
a
``
significant
regulatory
action''
because
it
could
have
an
annual
impact
on
the
economy
of
over
$
100
million.
Consequently,
this
action
was
submitted
to
OMB
for
review
under
Executive
Order
12866.
Changes
made
in
response
to
OMB
suggestions
or
recommendations
will
be
documented
in
the
public
record.
As
stipulated
in
Executive
Order
12866,
in
deciding
how
or
whether
to
regulate,
EPA
is
required
to
assess
all
costs
and
benefits
of
available
regulatory
alternatives,
including
the
alternative
of
not
regulating.
To
this
end,
EPA
prepared
a
detailed
benefit
cost
analysis
in
the
``
Regulatory
Impact
Analysis
for
the
Proposed
Automobile
and
Light
Duty
Truck
Coatings
NESHAP,''
which
is
contained
in
the
docket.
The
following
is
a
summary
of
the
benefitcost
analysis:
It
is
estimated
that
5
years
after
implementation
of
the
rule
as
proposed,
HAP
emissions
will
be
reduced
from
10,000
tpy
to
4,000
tpy.
This
represents
a
60
percent
reduction
(
or
6,000
tpy)
of
toluene,
xylene,
glycol
ethers,
MEK,
MIBK,
ethylbenzene,
and
methanol.
Based
on
scientific
studies
conducted
over
the
past
20
years,
the
EPA
has
classified
ethylene
glycol
monobutyl
ether
(
EGBE),
one
of
the
glycol
ethers,
as
a
``
possible
human
carcinogen,''
while
ethylbenzene,
MEK,
toluene,
and
xylenes
are
considered
by
the
EPA
as
``
not
classifiable
as
to
human
carcinogenicity.''
At
this
time,
we
are
unable
to
provide
a
comprehensive
quantification
and
monetization
of
the
HAP
related
benefits
of
this
proposal.
Exposure
to
HAP
can
result
in
the
incidence
of
respiratory
irritation,
chest
constriction,
gastric
irritation,
eye,
nose,
and
throat
irritation
as
well
as
neurological
and
blood
effects.
Specifically,
exposure
to
EGBE
may
result
in
neurological
and
blood
effects,
including
fatigue,
nausea,
tremor,
and
anemia.
Though
no
reliable
human
epidemiological
study
is
available
to
address
the
potential
carcinogenicity
of
EGBE,
a
draft
report
of
a
2
year
rodent
inhalation
study
reported
equivocal
evidence
of
carcinogenic
activity
in
female
rats
and
male
mice.
Exposure
to
MEK
may
lead
to
eye,
nose,
and
throat
irritation
while
methanol
may
lead
to
blurred
vision,
headache,
dizziness,
and
nausea.
Toluene
may
cause
effects
to
the
central
nervous
system,
such
as
fatigue,
sleepiness,
headache,
and
nausea.
In
addition,
chronic
exposure
to
this
HAP
can
lead
to
tremors,
decreased
brain
size,
involuntary
eye
movements,
and
impairment
of
speech,
hearing,
and
vision.
Xylenes,
a
mixture
of
three
closely
related
compounds,
may
cause
nose
and
throat
irritation,
nausea,
vomiting,
gastric
irritation,
headache,
dizziness,
fatigue,
and
tremors.
The
control
technology
to
reduce
the
level
of
HAP
emitted
from
automobile
and
light
duty
truck
coating
operations
are
also
expected
to
reduce
emissions
of
criteria
pollutants,
particularly
VOC.
Specifically,
the
proposed
rule
achieves
a
12,000
to
18,000
tpy
reduction
in
VOC.
The
VOC
is
a
precursor
to
tropospheric
(
ground
level)
ozone
and
a
small
percentage
also
precipitate
in
the
atmosphere
to
form
PM.
Although
we
have
not
estimated
the
monetary
value
associated
with
VOC
reductions,
the
benefits
can
be
substantial.
Health
and
welfare
effects
from
exposure
to
ground
level
ozone
are
well
documented.
Elevated
concentrations
of
ground
level
ozone
primarily
may
result
in
acute
respiratory
related
impacts
such
as
coughing
and
difficulty
breathing.
Chronic
exposure
to
ground
level
ozone
may
lead
to
structural
damage
to
the
lungs,
alterations
in
lung
capacity
and
breathing
frequency,
increased
sensitivity
of
airways,
eye,
nose,
and
throat
irritation,
malaise,
and
nausea.
Adverse
ozone
welfare
effects
include
damage
to
agricultural
crops,
ornamental
plants,
and
materials
damage.
Though
only
a
small
fraction
of
VOC
forms
PM,
exposure
to
PM
can
result
in
human
health
and
welfare
effects
including
excess
deaths,
morbidity,
soiling
and
materials
damage,
as
well
as
reduced
visibility.
To
the
extent
that
reduced
exposure
to
HAP
and
VOC
reduces
the
instances
of
the
above
described
health
effects,
benefits
from
the
proposed
rule
are
realized
by
society
through
an
improvement
in
environmental
quality.
Benefit
cost
comparison
(
net
benefits)
is
a
tool
used
to
evaluate
the
reallocation
of
society's
resources
used
to
address
the
pollution
externality
created
by
the
coatings
operations
at
automobile
and
light
duty
truck
plants.
The
additional
costs
of
internalizing
the
pollution
produced
at
major
sources
of
emissions
from
automobile
and
lightduty
truck
manufacturing
facilities
can
be
compared
to
the
improvement
in
society's
well
being
from
a
cleaner
and
healthier
environment.
Comparing
benefits
of
the
proposed
rule
to
the
costs
imposed
by
the
alternative
methods
to
control
emissions
optimally
identifies
a
strategy
that
results
in
the
highest
net
benefit
to
society.
In
the
case
of
the
proposed
automobiles
and
light
duty
trucks
coating
NESHAP,
we
are
proposing
only
one
option,
the
minimum
level
of
control
mandated
by
the
CAA
or
the
MACT
floor.
Based
on
estimated
compliance
costs
associated
with
this
proposed
rule
and
the
predicted
change
in
prices
and
production
in
the
affected
industry,
the
estimated
social
costs
of
this
proposed
rule
are
$
161
million
(
1999
dollars).
B.
Executive
Order
13132,
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
Under
section
6
of
Executive
Order
13132,
EPA
may
not
issue
a
regulation
that
has
federalism
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,
unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
State
and
local
governments,
or
EPA
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
The
EPA
also
may
not
issue
a
regulation
that
has
federalism
implications
and
that
preempts
State
law,
unless
the
Agency
consults
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
The
proposed
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
Pursuant
to
the
terms
of
Executive
Order
13132,
it
has
been
determined
that
the
proposed
rule
does
not
have
``
federalism
implications''
because
it
does
not
meet
the
necessary
criteria.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
the
proposed
rule.
Although
section
6
of
Executive
Order
13132
does
not
apply
to
the
proposed
rule,
EPA
did
consult
with
State
and
local
officials
to
enable
them
to
provide
timely
input
in
the
development
of
the
proposed
regulation.
C.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
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24,
2002
/
Proposed
Rules
10
U.
S.
Department
of
Energy.
1999.
Electric
Power
Annual,
Volume
I.
Table
A2:
Industry
Capability
by
Fuel
Source
and
Industry
Sector,
1999
and
1998
(
Megawatts).
11
U.
S.
Department
of
Energy.
1999.
Natural
Gas
Annual.
Table
1:
Summary
Statistics
for
Natural
Gas
in
the
United
States,
1995
1999.
67249,
November
9,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
This
proposed
rule
does
not
have
tribal
implications,
as
specified
in
Executive
Order
13175.
No
tribal
governments
own
or
operate
automobile
and
light
duty
truck
surface
coating
facilities.
Thus,
Executive
Order
13175
does
not
apply
to
the
proposed
rule.
D.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045,
``
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks''
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that:
(
1)
Is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
EPA
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.
The
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
501
of
the
Executive
Order
has
the
potential
to
influence
the
regulation.
The
proposed
rule
is
not
subject
to
Executive
Order
13045
because
it
does
not
establish
environmental
standards
based
on
an
assessment
of
health
or
safety
risks.
No
children's
risk
analysis
was
performed
because
no
alternative
technologies
exist
that
would
provide
greater
stringency
at
a
reasonable
cost.
E.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
Executive
Order
13211,
``
Actions
Concerning
Regulations
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use''
(
66
FR
28355,
May
22,
2001),
requires
EPA
to
prepare
and
submit
a
Statement
of
Energy
Effects
to
the
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
for
certain
actions
identified
as
``
significant
energy
actions.''
Section
4(
b)
of
Executive
Order
13211
defines
``
significant
energy
actions''
as
``
any
action
by
an
agency
(
normally
published
in
the
Federal
Register)
that
promulgates
or
is
expected
to
lead
to
the
promulgation
of
a
final
rule
or
regulation,
including
notices
of
inquiry,
advance
notices
of
proposed
rulemaking,
and
notices
of
proposed
rulemaking:
(
1)(
i)
That
is
a
significant
regulatory
action
under
Executive
Order
12866
or
any
successor
order,
and
(
ii)
is
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy;
or
(
2)
that
is
designated
by
the
Administrator
of
the
Office
of
Information
and
Regulatory
Affairs
as
a
significant
energy
action.''
This
proposed
rule
is
not
a
``
significant
energy
action''
because
it
is
not
likely
to
have
a
significant
adverse
effect
on
the
supply,
distribution,
or
use
of
energy.
The
proposed
rule
affects
the
automobile
and
light
duty
truck
manufacturing
industries.
There
is
no
crude
oil,
fuel,
or
coal
production
from
these
industries,
therefore
there
is
no
direct
effect
on
such
energy
production
related
to
implementation
of
the
rule
as
proposed.
In
addition,
the
cost
of
energy
distribution
should
not
be
affected
by
this
proposal
at
all
since
this
proposed
rule
does
not
affect
energy
distribution
facilities.
The
proposed
rule
is
projected
to
trigger
an
increase
in
energy
use
due
to
the
installation
and
operation
of
additional
pollution
control
equipment.
The
estimated
increase
in
energy
consumption
is
4.9
billion
standard
cubic
feet
per
year
of
natural
gas
and
180
million
kilowatt
hours
per
year
of
electricity
nationwide.
The
nationwide
cost
of
this
increased
energy
consumption
is
estimated
at
$
26
million
per
year.
The
increase
in
energy
costs
does
not
reflect
changes
in
energy
prices,
but
rather
an
increase
in
the
quantity
of
electricity
and
natural
gas
demanded.
Given
that
the
existing
electricity
generation
capacity
in
the
United
States
was
785,990
megawatts
in
1999
10
and
that
23,755
billion
cubic
feet
of
natural
gas
was
produced
domestically
in
the
same
year,
11
the
proposed
rule
is
not
likely
to
have
any
significant
adverse
impact
on
energy
prices,
distribution,
availability,
or
use.
F.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Public
Law
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
We
have
determined
that
the
proposed
rule
contains
a
Federal
mandate
that
may
result
in
expenditures
of
$
100
million
or
more
for
State,
local,
and
tribal
governments,
in
the
aggregate,
or
the
private
sector
in
any
1
year.
Accordingly,
we
have
prepared
a
written
statement
(
titled
``
Unfunded
Mandates
Reform
Act
Analysis
for
the
Proposed
Automobiles
and
Light
Duty
Trucks
Coating
NESHAP'')
under
section
202
of
the
UMRA
which
is
summarized
below.
1.
Statutory
Authority
The
statutory
authority
for
this
rulemaking
is
section
112
of
the
CAA,
enacted
to
reduce
nationwide
air
toxic
emissions.
In
compliance
with
UMRA
section
205(
a),
we
identified
and
considered
a
reasonable
number
of
regulatory
alternatives.
Additional
information
on
the
costs
and
environmental
impacts
of
these
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/
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2002
/
Proposed
Rules
regulatory
alternatives
is
presented
in
the
docket.
The
regulatory
alternative
upon
which
the
proposed
rule
is
based
represents
the
MACT
floor
for
automobile
and
light
duty
truck
coating
operations
and,
as
a
result,
is
the
least
costly
and
least
burdensome
alternative.
2.
Social
Costs
and
Benefits
The
RIA
prepared
for
the
proposed
rule,
including
EPA's
assessment
of
costs
and
benefits,
is
detailed
in
the
``
Regulatory
Impact
Analysis
for
the
Automobiles
and
Light
Duty
Trucks
Coating
NESHAP''
in
the
docket.
Based
on
the
estimated
compliance
costs
associated
with
the
proposed
rule
and
the
predicted
changes
in
prices
and
production
in
the
affected
industry,
the
estimated
annual
social
costs
of
the
proposed
rule
is
projected
to
be
$
161
million
(
1999
dollars).
It
is
estimated
that
5
years
after
implementation
of
the
rule
as
proposed,
HAP
will
be
reduced
from
10,000
tpy
to
4,000
tpy.
This
represents
a
60
percent
reduction
(
6,000
tpy)
of
toluene,
xylene,
glycol
ethers,
MEK,
MIBK,
ethylbenzene,
and
methanol.
Based
on
scientific
studies
conducted
over
the
past
20
years,
EPA
has
classified
EGBE
as
a
``
possible
human
carcinogen,''
while
ethylbenzene,
MEK,
toluene,
and
xylenes
are
considered
by
the
Agency
as
``
not
classifiable
as
to
human
carcinogenicity.''
The
studies
upon
which
these
classifications
are
based
have
worked
toward
the
determination
of
a
relationship
between
exposure
to
these
HAP
and
the
onset
of
cancer.
However,
there
are
several
questions
remaining
on
how
cancers
that
may
result
from
exposure
to
these
HAP
can
be
quantified
in
terms
of
dollars.
Therefore,
EPA
is
unable
to
provide
a
monetized
estimate
of
the
benefits
of
HAP
reduced
by
the
proposed
rule
at
this
time.
Exposure
to
HAP
can
result
in
the
incidence
of
respiratory
irritation,
chest
constriction,
gastric
irritation,
eye,
nose,
and
throat
irritation,
as
well
as
neurological
and
blood
effects,
including
fatigue,
nausea,
tremor,
and
anemia.
The
control
technology
to
reduce
the
level
of
HAP
emitted
from
automobile
and
light
duty
truck
coating
operations
is
also
expected
to
reduce
emissions
of
criteria
pollutants,
particularly
VOC.
Specifically,
this
proposed
rule
achieves
a
12,000
to
18,000
tpy
reduction
in
VOC.
The
VOC
is
a
precursor
to
tropospheric
(
ground
level)
ozone
and
a
small
percentage
also
precipitate
in
the
atmosphere
to
form
PM.
Although
we
have
not
estimated
the
monetary
value
associated
with
VOC
reductions,
the
benefits
can
be
substantial.
Health
and
welfare
effects
from
exposure
to
ground
level
ozone
are
well
documented.
Elevated
concentrations
of
ground
level
ozone
primarily
may
result
in
acute
respiratory
related
impacts
such
as
coughing
and
difficulty
breathing.
Chronic
exposure
to
ground
level
ozone
may
lead
to
structural
damage
to
the
lungs,
alterations
in
lung
capacity
and
breathing
frequency,
increased
sensitivity
of
airways,
eye,
nose,
and
throat
irritation,
malaise,
and
nausea.
Adverse
ozone
welfare
effects
include
damage
to
agricultural
crops,
ornamental
plants,
and
materials
damage.
Though
only
a
small
fraction
of
VOC
forms
PM,
exposure
to
PM
can
result
in
human
health
and
welfare
effects,
including
excess
deaths,
morbidity,
soiling
and
materials
damage,
as
well
as
reduced
visibility.
To
the
extent
that
reduced
exposure
to
HAP
and
VOC
reduces
the
instances
of
the
above
described
health
effects,
benefits
from
the
proposed
rule
would
be
realized
by
society
through
an
improvement
in
environmental
quality.
3.
Future
and
Disproportionate
Costs
The
UMRA
requires
that
we
estimate,
where
accurate
estimation
is
reasonably
feasible,
future
compliance
costs
imposed
by
the
proposed
rule
and
any
disproportionate
budgetary
effects.
We
do
not
believe
that
there
will
be
any
disproportionate
budgetary
effects
of
the
proposed
rule
on
any
particular
areas
of
the
country,
State,
or
local
governments,
types
of
communities
(
e.
g.,
urban,
rural),
or
particular
industry
segments.
4.
Effects
on
the
National
Economy
The
UMRA
requires
that
we
estimate
the
effect
of
the
proposed
rule
on
the
national
economy.
To
the
extent
feasible,
we
must
estimate
the
effect
on
productivity,
economic
growth,
full
employment,
creation
of
productive
jobs,
and
international
competitiveness
of
United
States
goods
and
services
if
we
determine
that
accurate
estimates
are
reasonably
feasible
and
that
such
effect
is
relevant
and
material.
The
nationwide
economic
impact
of
the
proposed
rule
is
presented
in
the
``
Regulatory
Impact
Analysis
for
the
Automobiles
and
Light
Duty
Trucks
Coating
NESHAP.''
That
analysis
provides
estimates
of
the
effect
of
the
proposed
rule
on
some
of
the
categories
mentioned
above.
The
estimated
direct
cost
to
the
automobile
and
light
duty
truck
manufacturing
industry
of
compliance
with
the
proposed
rule
is
approximately
$
154
million
(
1999
dollars)
annually.
Indirect
costs
of
the
proposed
rule
to
industries
other
than
the
automobile
and
light
duty
truck
manufacturing
industry,
governments,
tribes,
and
other
affected
entities
are
expected
to
be
minor.
The
estimated
annual
costs
is
minimal
when
compared
to
the
nominal
gross
domestic
product
of
$
9,255
billion
reported
for
the
Nation
in
1999.
The
proposed
rule
is
expected
to
have
little
impact
on
domestic
productivity,
economic
growth,
full
employment,
energy
markets,
creation
of
productive
jobs,
and
the
international
competitiveness
of
United
States
goods
and
services.
5.
Consultation
With
Government
Officials
Although
this
proposed
rule
does
not
affect
any
State,
local,
or
tribal
governments,
EPA
has
consulted
with
State
and
local
air
pollution
control
officials.
The
EPA
has
held
meetings
on
the
proposed
rule
with
many
of
the
stakeholders
from
numerous
individual
companies,
environmental
groups,
consultants
and
vendors,
and
other
interested
parties.
The
EPA
has
added
materials
to
the
docket
to
document
these
meetings.
G.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1966
(
SBREFA),
5
U.
S.
C.
601,
et
seq.
The
RFA
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
the
automobile
and
light
duty
truck
surface
coating
industry,
a
small
entity
is
defined
as:
(
1)
A
small
business
according
to
Small
Business
Administration
size
standards
for
companies
identified
by
NAICS
codes
33611
(
automobile
manufacturing)
and
33621
(
light
duty
truck
and
utility
vehicle
manufacturing)
with
1,000
or
fewer
employees;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district,
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
forprofit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
Based
on
the
above
definition,
there
are
no
small
entities
presently
engaged
in
automobile
and
light
duty
truck
surface
coating.
After
considering
the
economic
impacts
of
today's
proposed
rule
on
small
entities,
I
certify
that
the
proposed
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Proposed
Rules
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
This
certification
is
based
on
the
observation
that
the
proposed
rule
affects
no
small
entities
since
none
are
engaged
in
the
surface
coating
of
automobiles
and
lightduty
trucks.
H.
Paperwork
Reduction
Act
The
information
collection
requirements
in
the
proposed
rule
have
been
submitted
for
approval
to
OMB
under
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501,
et
seq.
An
ICR
document
has
been
prepared
by
EPA
(
ICR
No.
2045.01)
and
a
copy
may
be
obtained
from
Susan
Auby
by
mail
at
the
U.
S.
EPA,
Office
of
Environmental
Information,
Collection
Strategies
Division
(
2822T),
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460,
by
email
at
auby.
susan@
epa.
gov,
or
by
calling
(
202)
566
1672.
A
copy
may
also
be
downloaded
off
the
internet
at
http://
www.
epa.
gov/
icr.
The
information
collection
requirements
are
based
on
notification,
recordkeeping,
and
reporting
requirements
in
the
NESHAP
General
Provisions
(
40
CFR
part
63,
subpart
A),
which
are
mandatory
for
all
operators
subject
to
national
emission
standards.
These
recordkeeping
and
reporting
requirements
are
specifically
authorized
by
section
114
of
the
CAA
(
42
U.
S.
C.
7414).
All
information
submitted
to
EPA
pursuant
to
the
recordkeeping
and
reporting
requirements
for
which
a
claim
of
confidentiality
is
made
is
safeguarded
according
to
Agency
policies
set
forth
in
40
CFR
part
2,
subpart
B.
The
proposed
standards
would
not
require
any
notifications
or
reports
beyond
those
required
by
the
General
Provisions.
The
recordkeeping
requirements
require
only
the
specific
information
needed
to
determine
compliance.
The
annual
monitoring,
reporting,
and
recordkeeping
burden
for
this
collection
(
averaged
over
the
first
3
years
after
the
effective
date
of
the
final
rule)
is
estimated
to
be
33,436
labor
hours
per
year
at
a
total
annual
cost
of
$
982,742.
This
estimate
includes
a
one
time
performance
test
and
report
(
with
repeat
tests
where
needed)
for
those
affected
sources
that
choose
to
comply
through
the
installation
of
new
capture
systems
and
control
devices;
one
time
purchase
and
installation
of
CPMS
for
those
affected
sources
that
choose
to
comply
through
the
installation
of
new
capture
systems
and
control
devices;
preparation
and
submission
of
work
practice
plans;
one
time
submission
of
a
startup,
shutdown,
and
malfunction
plan
with
semiannual
reports
for
any
event
when
the
procedures
in
the
plan
were
not
followed;
semiannual
excess
emission
reports;
maintenance
inspections;
notifications;
and
recordkeeping.
There
are
no
additional
capital/
startup
costs
associated
with
the
monitoring
requirements
over
the
3
year
period
of
the
ICR.
The
monitoring
related
operation
and
maintenance
costs
over
this
same
period
are
estimated
at
$
7,000.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Comments
are
requested
on
EPA's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
through
the
use
of
automated
collection
techniques.
By
U.
S.
Postal
Service,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
EPA
(
2822T),
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460;
or
by
courier,
send
comments
on
the
ICR
to
the
Director,
Collection
Strategies
Division,
U.
S.
EPA
(
2822T),
1301
Constitution
Avenue,
NW.,
Room
6143,
Washington,
DC
20460
((
202)
566
1700);
and
to
the
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget,
725
17th
St.,
NW.,
Washington,
DC
20503,
marked
``
Attention:
Desk
Officer
for
EPA.''
Include
the
ICR
number
in
any
correspondence.
Since
OMB
is
required
to
make
a
decision
concerning
the
ICR
between
30
and
60
days
after
December
24,
2002,
a
comment
to
OMB
is
best
assured
of
having
its
full
effect
if
OMB
receives
it
by
January
23,
2003.
The
final
rule
will
respond
to
any
OMB
or
public
comments
on
the
information
collection
requirements
contained
in
this
proposal.
I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(
NTTAA),
Public
Law
104
113,
section
12(
d)
(
15
U.
S.
C.
272
note),
directs
EPA
to
use
voluntary
consensus
standards
(
VCS)
in
its
regulatory
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
The
VCS
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
and
business
practices)
that
are
developed
or
adopted
by
VCS
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
OMB,
explanations
when
the
Agency
decides
not
to
use
available
and
applicable
VCS.
The
proposed
rulemaking
involves
technical
standards.
The
EPA
cites
the
following
standards
in
the
proposed
rule:
EPA
Methods
1,
1A,
2,
2A,
2C,
2D,
2F,
2G,
3,
3A,
3B,
4,
24,
25,
25A,
204,
204A
through
F,
and
311.
Consistent
with
the
NTTAA,
EPA
conducted
searches
to
identify
VCS
in
addition
to
these
EPA
methods.
No
applicable
VCS
were
identified
for
EPA
Methods
1A,
2A,
2D,
2F,
2G,
204A
through
F,
and
311.
The
search
and
review
results
have
been
documented
and
are
placed
in
the
docket
for
the
proposed
rule
(
docket
A
2001
22).
The
six
VCS
described
below
were
identified
as
acceptable
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rule.
The
VCS
ASME
PTC
19
10
1981
Part
10,
``
Flue
and
Exhaust
Gas
Analyses,''
is
cited
in
the
proposed
rule
for
its
manual
method
for
measuring
the
oxygen,
carbon
dioxide,
and
carbon
monoxide
content
of
exhaust
gas.
This
part
of
ASME
PTC
19
10
1981
Part
10,
is
an
acceptable
alternative
to
Method
3B.
The
two
VCS,
ASTM
D2697
86
(
1998),
``
Standard
Test
Method
for
Volume
Nonvolatile
Matter
in
Clear
or
Pigmented
Coatings''
and
ASTM
D6093
97,
``
Standard
Test
Method
for
Percent
Volume
Nonvolatile
Matter
in
Clear
or
Pigmented
Coatings
Using
a
Helium
Gas
Pycnometer,''
are
cited
in
the
proposed
rule
as
acceptable
alternatives
to
EPA
Method
24
to
determine
the
volume
solids
content
of
coatings.
Currently,
EPA
Method
24
does
not
have
a
procedure
for
determining
the
volume
of
solids
in
coatings.
The
two
VCS
standards
augment
the
procedures
in
Method
24,
which
currently
states
that
volume
solids
content
be
calculated
from
the
coating
manufacturer's
formulation.
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247
/
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December
24,
2002
/
Proposed
Rules
The
VCS
ASTM
D5066
91
(
2001),
``
Standard
Test
Method
for
Determination
of
the
Transfer
Efficiency
Under
Production
Conditions
for
Spray
Application
of
Automotive
Paints
Weight
Basis,''
is
cited
in
the
proposed
rule
as
an
acceptable
procedure
to
measure
transfer
efficiency
of
spray
coatings.
Currently,
no
EPA
method
is
available
to
measure
transfer
efficiency.
The
two
VCS,
ASTM
D6266
00a,
``
Test
Method
for
Determining
the
Amount
of
Volatile
Organic
Compound
(
VOC)
Released
from
Waterborne
Automotive
Coatings
and
Available
for
Removal
in
a
VOC
Control
Device
(
Abatement)''
and
ASTM
D5087
91
(
1994),
``
Standard
Test
Method
for
Determining
Amount
of
Volatile
Organic
Compound
(
VOC)
Released
from
Solventborne
Automotive
Coatings
and
Available
for
Removal
in
a
VOC
Control
Device
(
Abatement),''
are
cited
in
the
proposed
rule
as
acceptable
procedures
to
measure
solvent
loading
(
similar
to
capture
efficiency)
for
the
heated
flash
zone
for
waterborne
basecoats
and
for
bake
ovens.
Currently,
no
EPA
method
is
available
to
measure
solvent
release
potential
from
automobile
and
light
duty
truck
coatings
in
order
to
determine
the
potential
solvent
loading
from
the
coatings
used.
Six
VCS:
ASTM
D1475
90,
ASTM
D2369
95,
ASTM
D3792
91,
ASTM
D4017
96a,
ASTM
D4457
85
(
Reapproved
91),
and
ASTM
D5403
93
are
already
incorporated
by
reference
in
EPA
Method
24.
Five
VCS:
ASTM
D1979
91,
ASTM
D3432
89,
ASTM
D4747
87,
ASTM
D4827
93,
and
ASTM
PS9
94
are
incorporated
by
reference
in
EPA
Method
311.
In
addition
to
the
VCS
EPA
proposes
to
use,
the
search
for
emissions
measurement
procedures
identified
14
other
VCS.
The
EPA
determined
that
10
of
these
14
standards
identified
for
measuring
emissions
of
the
HAP
or
surrogates
subject
to
emission
standards
in
the
proposed
rule
were
impractical
alternatives
to
EPA
test
methods
for
the
purposes
of
the
proposed
rule.
Therefore,
EPA
does
not
intend
to
adopt
these
standards
for
this
purpose.
(
See
docket
A
2001
22
for
further
information
on
the
methods.)
Four
of
the
14
VCS
identified
in
this
search
were
not
available
at
the
time
the
review
was
conducted
for
the
purposes
of
the
proposed
rule
because
they
are
under
development
by
a
voluntary
consensus
body:
ASME/
BSR
MFC
13M,
``
Flow
Measurement
by
Velocity
Traverse,''
for
EPA
Method
2
(
and
possibly
1);
ASME/
BSR
MFC
12M,
``
Flow
in
Closed
Conduits
Using
Multiport
Averaging
Pitot
Primary
Flowmeters,''
for
EPA
Method
2;
ISO/
DIS
12039,
``
Stationary
Source
Emissions
Determination
of
Carbon
Monoxide,
Carbon
Dioxide,
and
Oxygen
Automated
Methods,''
for
EPA
Method
3A;
and
ISO/
PWI
17895,
``
Paints
and
Varnishes
Determination
of
the
Volatile
Organic
Compound
Content
of
Water
based
Emulsion
Paints,''
for
EPA
Method
24.
Sections
63.3161
and
63.3166
to
the
proposed
standards
list
the
EPA
testing
methods
included
in
the
proposed
rule.
Under
§
63.7(
f)
of
subpart
A
of
the
General
Provisions,
a
source
may
apply
to
EPA
for
permission
to
use
alternative
test
methods
in
place
of
any
of
the
EPA
testing
methods.
During
the
development
of
the
proposed
rulemaking,
EPA
searched
for
VCS
that
might
be
applicable
and
included
ASTM
test
methods
as
appropriate
for
determination
of
volume
fraction
of
coating
solids.
List
of
Subjects
40
CFR
Part
63
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Hazardous
substances,
Intergovernmental
relations,
Reporting
and
recordkeeping
requirements.
40
CFR
Part
264
Environmental
protection,
Air
pollution
control,
Hazardous
waste,
Insurance,
Packaging
and
containers,
Reporting
and
recordkeeping
requirements,
Security
measures,
Surety
bonds.
40
CFR
Part
265
Environmental
protection,
Air
pollution
control,
Hazardous
waste,
Insurance,
Packaging
and
containers,
Reporting
and
recordkeeping
requirements,
Security
measures,
Surety
bonds,
Water
supply.
Dated:
November
26,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
stated
in
the
preamble,
title
40,
chapter
I,
parts
63,
264,
and
265
of
the
Code
of
Federal
Regulations
are
proposed
to
be
amended
as
follows:
PART
63
[
AMENDED]
1.
The
authority
citation
for
part
63
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7401,
et
seq.
2.
Part
63
is
amended
by
adding
subpart
IIII
to
read
as
follows:
Subpart
IIII
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Surface
Coating
of
Automobiles
and
Light
Duty
Trucks
Sec.
What
This
Subpart
Covers
63.3080
What
is
the
purpose
of
this
subpart?
63.3081
Am
I
subject
to
this
subpart?
63.3082
What
parts
of
my
plant
does
this
subpart
cover?
63.3083
When
do
I
have
to
comply
with
this
subpart?
Emission
Limitations
63.3090
What
emission
limits
must
I
meet
for
a
new
or
reconstructed
affected
source?
63.3091
What
emission
limits
must
I
meet
for
an
existing
affected
source?
63.3092
How
must
I
control
emissions
from
my
electrodeposition
primer
system
if
I
want
to
comply
with
the
combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
emission
limit?
63.3093
What
operating
limits
must
I
meet?
63.3094
What
work
practice
standards
must
I
meet?
General
Compliance
Requirements
63.3100
What
are
my
general
requirements
for
complying
with
this
subpart?
63.3101
What
parts
of
the
General
Provisions
apply
to
me?
Notifications,
Reports,
and
Records
63.3110
What
notifications
must
I
submit?
63.3120
What
reports
must
I
submit?
63.3130
What
records
must
I
keep?
63.3131
In
what
form
and
for
how
long
must
I
keep
my
records?
Compliance
Requirements
for
Adhesive,
Sealer,
and
Deadener
63.3150
By
what
date
must
I
conduct
the
initial
compliance
demonstration?
63.3151
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations?
63.3152
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
Compliance
Requirements
for
the
Combined
Electrodeposition
Primer,
Primer
Surfacer,
Topcoat,
Final
Repair,
Glass
Bonding
Primer,
and
Glass
Bonding
Adhesive
Emission
Rates
63.3160
By
what
date
must
I
conduct
performance
tests
and
other
initial
compliance
demonstrations?
63.3161
How
do
I
demonstrate
initial
compliance?
63.3162
[
Reserved]
63.3163
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
63.3164
What
are
the
general
requirements
for
performance
tests?
63.3165
How
do
I
determine
the
emission
capture
system
efficiency?
63.3166
How
do
I
determine
the
add
on
control
device
emission
destruction
or
removal
efficiency?
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Vol.
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No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
1
Proposed
December
4,
2002
(
67
FR
72275).
2
Proposed
August
13,
2002
(
67
FR
52780).
63.3167
How
do
I
establish
the
add
on
control
device
operating
limits
during
the
performance
test?
63.3168
What
are
the
requirements
for
continuous
parameter
monitoring
system
installation,
operation,
and
maintenance?
Compliance
Requirements
for
the
Combined
Primer
Surfacer,
Topcoat,
Final
Repair,
Glass
Bonding
Primer,
and
Glass
Bonding
Adhesive
Emission
Rates
and
the
Separate
Electrodeposition
Primer
Emission
Rates
63.3170
By
what
date
must
I
conduct
performance
tests
and
other
initial
compliance
demonstrations?
63.3171
How
do
I
demonstrate
initial
compliance?
63.3172
[
Reserved]
63.3173
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
Other
Requirements
and
Information
63.3175
Who
implements
and
enforces
this
subpart?
63.3176
What
definitions
apply
to
this
subpart?
Tables
to
Subpart
IIII
of
Part
63
Table
1
to
Subpart
IIII
of
Part
63
Operating
Limits
for
Capture
Systems
and
Add
On
Control
Devices
Table
2
to
Subpart
IIII
of
Part
63
Applicability
of
General
Provisions
to
Subpart
IIII
of
Part
63
Table
3
to
Subpart
IIII
of
Part
63
Default
Organic
HAP
Mass
Fraction
for
Solvents
and
Solvent
Blends
Table
4
to
Subpart
IIII
of
Part
63
Default
Organic
HAP
Mass
Fraction
for
Petroleum
Solvent
Groups
Subpart
IIII
National
Emission
Standards
for
Hazardous
Air
Pollutants:
Surface
Coating
of
Automobiles
and
Light
Duty
Trucks
What
This
Subpart
Covers
§
63.3080
What
is
the
purpose
of
this
subpart?
This
subpart
establishes
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
for
facilities
which
surface
coat
new
automobile
or
light
duty
truck
bodies
or
collections
of
body
parts
for
new
automobiles
or
new
light
duty
trucks.
This
subpart
also
establishes
requirements
to
demonstrate
initial
and
continuous
compliance
with
the
emission
limitations.
§
63.3081
Am
I
subject
to
this
subpart?
(
a)
Except
as
provided
in
paragraph
(
c)
of
this
section,
the
source
category
to
which
this
subpart
applies
is
automobile
and
light
duty
truck
surface
coating.
(
b)
You
are
subject
to
this
subpart
if
you
own
or
operate
a
new,
reconstructed,
or
existing
affected
source,
as
defined
in
§
63.3082,
that
is
located
at
a
facility
which
surface
coats
new
automobile
or
new
light
duty
truck
bodies
or
collections
of
body
parts
for
new
automobiles
or
new
light
duty
trucks,
and
that
is
a
major
source,
is
located
at
a
major
source,
or
is
part
of
a
major
source
of
emissions
of
hazardous
air
pollutants
(
HAP).
A
major
source
of
HAP
emissions
is
any
stationary
source
or
group
of
stationary
sources
located
within
a
contiguous
area
and
under
common
control
that
emits
or
has
the
potential
to
emit
any
single
HAP
at
a
rate
of
9.07
megagrams
(
Mg)
(
10
tons)
or
more
per
year
or
any
combination
of
HAP
at
a
rate
of
22.68
Mg
(
25
tons)
or
more
per
year.
(
c)
This
subpart
does
not
apply
to
surface
coating,
surface
preparation,
or
cleaning
activities
that
meet
the
criteria
of
paragraph
(
c)(
1)
or
(
2)
of
this
section.
(
1)
Surface
coating
subject
to
any
other
NESHAP
in
this
part
as
of
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
Federal
Register],
including
plastic
parts
and
products
surface
coating
1
and
miscellaneous
metal
parts
surface
coating
.2
(
2)
Surface
coating
that
occurs
at
research
or
laboratory
facilities
or
that
is
part
of
janitorial,
building,
and
facility
maintenance
operations,
including
maintenance
spray
booths
used
for
painting
production
equipment,
furniture,
signage,
etc.,
for
use
within
the
plant.
§
63.3082
What
parts
of
my
plant
does
this
subpart
cover?
(
a)
This
subpart
applies
to
each
new,
reconstructed,
and
existing
affected
source.
(
b)
The
affected
source
is
the
collection
of
all
of
the
items
listed
in
paragraphs
(
b)(
1)
through
(
4)
of
this
section
that
are
used
for
surface
coating
of
new
automobile
or
light
duty
truck
bodies
or
collections
of
body
parts
for
new
automobiles
or
new
light
duty
trucks:
(
1)
All
coating
operations
as
defined
in
§
63.3176;
(
2)
All
storage
containers
and
mixing
vessels
in
which
coatings,
thinners,
and
cleaning
materials
are
stored
or
mixed;
(
3)
All
manual
and
automated
equipment
and
containers
used
for
conveying
coatings,
thinners,
and
cleaning
materials;
and
(
4)
All
storage
containers
and
all
manual
and
automated
equipment
and
containers
used
for
conveying
waste
materials
generated
by
a
coating
operation.
(
c)
An
affected
source
is
a
new
affected
source
if
you
commenced
its
construction
after
December
24,
2002,
and
the
construction
is
of
a
completely
new
automobile
and
light
duty
truck
assembly
plant
where
previously
no
automobile
and
light
duty
truck
assembly
plant
had
existed,
or
a
completely
new
automobile
and
lightduty
truck
paint
shop
where
previously
no
automobile
and
light
duty
truck
assembly
plant
had
existed.
(
d)
An
affected
source
is
reconstructed
if
it
contains
a
paint
shop
that
has
undergone
replacement
of
components
to
such
an
extent
that:
(
1)
The
fixed
capital
cost
of
the
new
components
exceeded
50
percent
of
the
fixed
capital
cost
that
would
be
required
to
construct
a
new
paint
shop;
and
(
2)
It
was
technologically
and
economically
feasible
for
the
reconstructed
source
to
meet
the
relevant
standards
established
by
the
Administrator
pursuant
to
section
112
of
the
Clean
Air
Act
(
CAA).
(
e)
An
affected
source
is
existing
if
it
is
not
new
or
reconstructed.
§
63.3083
When
do
I
have
to
comply
with
this
subpart?
The
date
by
which
you
must
comply
with
this
subpart
is
called
the
compliance
date.
The
compliance
date
for
each
type
of
affected
source
is
specified
in
paragraphs
(
a)
through
(
c)
of
this
section.
The
compliance
date
begins
the
initial
compliance
period
during
which
you
conduct
the
initial
compliance
demonstrations
described
in
§
§
63.3150,
63.3160
and
63.3170.
(
a)
For
a
new
or
reconstructed
affected
source,
the
compliance
date
is
the
applicable
date
in
paragraph
(
a)(
1)
or
(
2)
of
this
section:
(
1)
If
the
initial
startup
of
your
new
or
reconstructed
affected
source
is
before
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
the
compliance
date
is
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
(
2)
If
the
initial
startup
of
your
new
or
reconstructed
affected
source
occurs
after
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
the
compliance
date
is
the
date
of
initial
startup
of
your
affected
source.
(
b)
For
an
existing
affected
source,
the
compliance
date
is
the
date
3
years
after
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
(
c)
For
an
area
source
that
increases
its
emissions
or
its
potential
to
emit
such
that
it
becomes
a
major
source
of
HAP
emissions,
the
compliance
date
is
specified
in
paragraphs
(
c)(
1)
and
(
2)
of
this
section.
(
1)
For
any
portion
of
the
source
that
becomes
a
new
or
reconstructed
affected
source
subject
to
this
subpart,
the
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Proposed
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compliance
date
is
the
date
of
initial
startup
of
the
affected
source
or
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
whichever
is
later.
(
2)
For
any
portion
of
the
source
that
becomes
an
existing
affected
source
subject
to
this
subpart,
the
compliance
date
is
the
date
1
year
after
the
area
source
becomes
a
major
source
or
3
years
after
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
whichever
is
later.
(
d)
You
must
meet
the
notification
requirements
in
§
63.3110
according
to
the
dates
specified
in
that
section
and
in
subpart
A
of
this
part.
Some
of
the
notifications
must
be
submitted
before
the
compliance
dates
described
in
paragraphs
(
a)
through
(
c)
of
this
section.
Emission
Limitations
§
63.3090
What
emission
limits
must
I
meet
for
a
new
or
reconstructed
affected
source?
(
a)
Except
as
provided
in
paragraph
(
b)
of
this
section,
you
must
limit
combined
organic
HAP
emissions
to
the
atmosphere
from
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer
and
glass
bonding
adhesive
application
to
no
more
than
0.036
kilogram
(
kg)/
liter
(
0.30
pound
(
lb)/
gallon
(
gal))
of
coating
solids
deposited
during
each
month,
determined
according
to
the
requirements
in
§
63.3161.
(
b)
If
you
meet
the
operating
limits
of
§
63.3092(
a)
and
(
b),
you
must
either
meet
the
emission
limits
of
paragraph
(
a)
of
this
section
or
limit
combined
organic
HAP
emissions
to
the
atmosphere
from
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
application
to
no
more
than
0.060
kg/
liter
(
0.50
lb/
gal)
of
applied
coating
solids
used
during
each
month,
determined
according
to
the
requirements
in
§
63.3171.
If
you
do
not
have
an
electrodeposition
primer
system,
you
must
limit
combined
organic
HAP
emissions
to
the
atmosphere
from
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
application
to
no
more
than
0.060
kg/
liter
(
0.50
lb/
gal)
of
applied
coating
solids
used
during
each
month,
determined
according
to
the
requirements
in
§
63.3171.
(
c)
You
must
limit
average
organic
HAP
emissions
from
all
adhesive
and
sealer
materials
other
than
materials
used
as
components
of
glass
bonding
systems
to
no
more
than
0.010
kg/
kg
(
lb/
lb)
of
adhesive
and
sealer
material
used
during
each
month.
(
d)
You
must
limit
average
organic
HAP
emissions
from
all
deadener
materials
to
no
more
than
0.010
kg/
kg
(
lb/
lb)
of
deadener
material
used
during
each
month.
§
63.3091
What
emission
limits
must
I
meet
for
an
existing
affected
source?
(
a)
Except
as
provided
in
paragraph
(
b)
of
this
section,
you
must
limit
combined
organic
HAP
emissions
to
the
atmosphere
from
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
application
to
no
more
than
0.072
kg/
liter
0.60
lb/
gal)
of
coating
solids
deposited
during
each
month,
determined
according
to
the
requirements
in
§
63.3161.
(
b)
If
you
meet
the
operating
limits
of
§
63.3092(
a)
and
(
b),
you
must
either
meet
the
emission
limits
of
paragraph
(
a)
of
this
section
or
limit
combined
organic
HAP
emissions
to
the
atmosphere
from
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
application
to
no
more
than
0.132
kg/
liter
(
1.10
lb/
gal)
of
coating
solids
deposited
during
each
month,
determined
according
to
the
requirements
in
§
63.3171.
If
you
do
not
have
an
electrodeposition
primer
system,
you
must
limit
combined
organic
HAP
emissions
to
the
atmosphere
from
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
application
to
no
more
than
0.132
kg/
liter
(
1.10
lb/
gal)
of
coating
solids
deposited
during
each
month,
determined
according
to
the
requirements
in
§
63.3171.
(
c)
You
must
limit
average
organic
HAP
emissions
from
all
adhesive
and
sealer
materials
other
than
materials
used
as
components
of
glass
bonding
systems
to
no
more
than
0.010
kg/
kg
(
lb/
lb)
of
adhesive
and
sealer
material
used
during
each
month.
(
d)
You
must
limit
average
organic
HAP
emissions
from
all
deadener
materials
to
no
more
than
0.010
kg/
kg
(
lb/
lb)
of
deadener
material
used
during
each
month.
§
63.3092
How
must
I
control
emissions
from
my
electrodeposition
primer
system
if
I
want
to
comply
with
the
combined
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
emission
limit?
If
your
electrodeposition
primer
system
meets
the
requirements
of
either
paragraph
(
a)
or
(
b)
of
this
section,
you
may
choose
to
comply
with
the
emission
limits
of
§
63.3090(
b)
or
§
63.3091(
b)
instead
of
the
emission
limits
of
§
63.3090(
a)
or
§
63.3091(
a).
(
a)
Each
individual
material
added
to
the
electrodeposition
primer
system
contains
no
more
than:
(
1)
1.0
percent
by
weight
of
any
organic
HAP;
and
(
2)
0.10
percent
by
weight
of
any
organic
HAP
which
is
an
Occupational
Safety
and
Health
Administration
(
OSHA)
defined
carcinogen
as
specified
in
29
CFR
1910.1200(
d)(
4).
(
b)
Emissions
from
all
bake
ovens
used
to
cure
electrodeposition
primers
must
be
captured
and
ducted
to
a
control
device
having
a
control
efficiency
of
at
least
95
percent.
§
63.3093
What
operating
limits
must
I
meet?
(
a)
You
are
not
required
to
meet
any
operating
limits
for
any
coating
operation(
s)
without
add
on
controls.
(
b)
For
any
controlled
coating
operation(
s),
you
must
meet
the
operating
limits
specified
in
Table
1
to
this
subpart.
These
operating
limits
apply
to
the
emission
capture
and
addon
control
systems
on
the
coating
operation(
s)
for
which
you
use
this
option,
and
you
must
establish
the
operating
limits
during
the
performance
test
according
to
the
requirements
in
§
63.3167.
You
must
meet
the
operating
limits
at
all
times
after
you
establish
them.
(
c)
If
you
choose
to
meet
the
emission
limitations
of
§
63.3092(
b)
and
the
emission
limits
of
§
63.3090(
b)
or
§
63.3091(
b),
then
you
must
operate
the
capture
system
and
add
on
control
device
used
to
capture
and
control
emissions
from
your
electrodeposition
primer
bake
oven(
s)
so
that
they
meet
the
operating
limits
specified
in
Table
1
to
this
subpart.
(
d)
If
you
use
an
add
on
control
device
other
than
those
listed
in
Table
1
to
this
subpart,
or
wish
to
monitor
an
alternative
parameter
and
comply
with
a
different
operating
limit,
you
must
apply
to
the
Administrator
for
approval
of
alternative
monitoring
under
§
63.8(
f).
§
63.3094
What
work
practice
standards
must
I
meet?
(
a)
[
Reserved]
(
b)
You
must
develop
and
implement
a
work
practice
plan
to
minimize
organic
HAP
emissions
from
the
storage,
mixing,
and
conveying
of
coatings,
thinners,
and
cleaning
materials
used
in,
and
waste
materials
generated
by,
all
coating
operations
for
which
emission
limits
are
established
under
§
63.3090(
a)
through
(
d)
or
§
63.3091(
a)
through
(
d).
The
plan
must
specify
practices
and
procedures
to
ensure
that,
at
a
minimum,
the
elements
specified
in
paragraphs
(
b)(
1)
through
(
5)
of
this
section
are
implemented.
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24,
2002
/
Proposed
Rules
(
1)
All
organic
HAP
containing
coatings,
thinners,
cleaning
materials,
and
waste
materials
must
be
stored
in
closed
containers.
(
2)
The
risk
of
spills
of
organic
HAPcontaining
coatings,
thinners,
cleaning
materials,
and
waste
materials
must
be
minimized.
(
3)
Organic
HAP
containing
coatings,
thinners,
cleaning
materials,
and
waste
materials
must
be
conveyed
from
one
location
to
another
in
closed
containers
or
pipes.
(
4)
Mixing
vessels,
other
than
day
tanks
equipped
with
continuous
agitation
systems,
which
contain
organic
HAP
containing
coatings
and
other
materials
must
be
closed
except
when
adding
to,
removing,
or
mixing
the
contents.
(
5)
Emissions
of
organic
HAP
must
be
minimized
during
cleaning
of
storage,
mixing,
and
conveying
equipment.
(
c)
You
must
develop
and
implement
a
work
practice
plan
to
minimize
organic
HAP
emissions
from
cleaning
and
from
purging
of
equipment
associated
with
all
coating
operations
for
which
emission
limits
are
established
under
§
63.3090(
a)
through
(
d)
or
§
63.3091(
a)
through
(
d).
(
1)
The
plan
shall,
at
a
minimum,
address
each
of
the
operations
listed
in
paragraphs
(
c)(
1)(
i)
through
(
viii)
of
this
section
in
which
you
use
organic
HAPcontaining
materials
or
in
which
there
is
a
potential
for
emission
of
organic
HAP.
(
i)
The
plan
must
address
vehicle
body
wipe
emissions
through
one
or
more
of
the
techniques
listed
in
paragraphs
(
c)(
1)(
i)(
A)
through
(
E)
of
this
section,
or
an
approved
alternative.
(
A)
Use
of
solvent
moistened
wipes.
(
B)
Keeping
solvent
containers
closed
when
not
in
use.
(
C)
Keeping
wipe
disposal/
recovery
containers
closed
when
not
in
use.
(
D)
Use
of
tack
wipes.
(
E)
Use
of
solvents
containing
less
than
1
percent
organic
HAP
by
weight.
(
ii)
The
plan
must
address
coating
line
purging
emissions
through
one
or
more
of
the
techniques
listed
in
paragraphs
(
c)(
1)(
ii)(
A)
through
(
D)
of
this
section,
or
an
approved
alternative.
(
A)
Air/
solvent
push
out.
(
B)
Capture
and
reclaim
or
recovery
of
purge
materials
(
excluding
applicator
nozzles/
tips).
(
C)
Block
painting
to
the
maximum
extent
feasible.
(
D)
Use
of
low
HAP
or
no
HAP
solvents
for
purge.
(
iii)
The
plan
must
address
emissions
from
flushing
of
coating
systems
through
one
or
more
of
the
techniques
listed
in
paragraphs
(
c)(
1)(
iii)(
A)
through
(
D)
of
this
section,
or
an
approved
alternative.
(
A)
Keeping
solvent
tanks
closed.
(
B)
Recovering
and
recycling
solvents.
(
C)
Keeping
recovered/
recycled
solvent
tanks
closed.
(
D)
Use
of
low
HAP
or
no
HAP
solvents.
(
iv)
The
plan
must
address
emissions
from
cleaning
of
spray
booth
grates
through
one
or
more
of
the
techniques
listed
in
paragraphs
(
c)(
1)(
iv)(
A)
through
(
E)
of
this
section,
or
an
approved
alternative.
(
A)
Controlled
burn
off.
(
B)
Rinsing
with
high
pressure
water
(
in
place).
(
C)
Rinsing
with
high
pressure
water
(
off
line).
(
D)
Use
of
spray
on
masking
or
other
type
of
liquid
masking.
(
E)
Use
of
low
HAP
or
no
HAP
content
cleaners.
(
v)
The
plan
must
address
emissions
from
cleaning
of
spray
booth
walls
through
one
or
more
of
the
techniques
listed
in
paragraphs
(
c)(
1)(
v)(
A)
through
(
E)
of
this
section,
or
an
approved
alternative.
(
A)
Use
of
masking
materials
(
contact
paper,
plastic
sheet,
or
other
similar
type
of
material).
(
B)
Use
of
spray
on
masking.
(
C)
Use
of
rags
and
manual
wipes
instead
of
spray
application
when
cleaning
walls.
(
D)
Use
of
low
HAP
or
no
HAP
content
cleaners.
(
E)
Controlled
access
to
cleaning
solvents.
(
vi)
The
plan
must
address
emissions
from
cleaning
of
spray
booth
equipment
through
one
or
more
of
the
techniques
listed
in
paragraphs
(
c)(
1)(
vi)(
A)
through
(
E)
of
this
section,
or
an
approved
alternative.
(
A)
Use
of
covers
on
equipment
(
disposable
or
reusable).
(
B)
Use
of
parts
cleaners
(
off
line
submersion
cleaning).
(
C)
Use
of
spray
on
masking
or
other
protective
coatings.
(
D)
Use
of
low
HAP
or
no
HAP
content
cleaners.
(
E)
Controlled
access
to
cleaning
solvents.
(
vii)
The
plan
must
address
emissions
from
cleaning
of
external
spray
booth
areas
through
one
or
more
of
the
techniques
listed
in
paragraphs
(
c)(
1)(
vii)(
A)
through
(
F)
of
this
section,
or
an
approved
alternative.
(
A)
Use
of
removable
floor
coverings
(
paper,
foil,
plastic,
or
similar
type
of
material).
(
B)
Use
of
manual
and/
or
mechanical
scrubbers,
rags,
or
wipes
instead
of
spray
application.
(
C)
Use
of
shoe
cleaners
to
eliminate
coating
track
out
from
spray
booths.
(
D)
Use
of
booties
or
shoe
wraps.
(
E)
Use
of
low
HAP
or
no
HAP
content
cleaners.
(
F)
Controlled
access
to
cleaning
solvents.
(
viii)
The
plan
must
address
emissions
from
housekeeping
measures
not
addressed
in
paragraphs
(
c)(
1)(
i)
through
(
vii)
of
this
section
through
one
or
more
of
the
techniques
listed
in
paragraphs
(
c)(
1)(
viii)(
A)
through
(
C)
of
this
section,
or
an
approved
alternative.
(
A)
Keeping
solvent
laden
articles
(
cloths,
paper,
plastic,
rags,
wipes,
and
similar
items)
in
covered
containers
when
not
in
use.
(
B)
Storing
new
and
used
solvents
in
closed
containers.
(
C)
Transferring
of
solvents
in
a
manner
to
minimize
the
risk
of
spills.
(
2)
Notwithstanding
the
requirements
of
paragraphs
(
c)(
1)(
i)
through
(
viii)
of
this
section,
if
the
type
of
coatings
used
in
any
facility
with
surface
coating
operations
subject
to
the
requirements
of
this
section
are
of
such
a
nature
that
the
need
for
one
or
more
of
the
practices
specified
under
paragraphs
(
c)(
1)(
i)
through
(
viii)
is
eliminated,
then
the
plan
may
include
approved
alternative
or
equivalent
measures
that
are
applicable
or
necessary
during
cleaning
of
storage,
conveying,
and
application
equipment.
(
d)
As
provided
in
§
63.6(
g),
we,
EPA,
may
choose
to
grant
you
permission
to
use
an
alternative
to
the
work
practice
standards
in
this
section.
General
Compliance
Requirements
§
63.3100
What
are
my
general
requirements
for
complying
with
this
subpart?
(
a)
You
must
be
in
compliance
with
the
emission
limitations
in
§
§
63.3090
and
63.3091
at
all
times,
as
determined
on
a
monthly
basis.
(
b)
The
coating
operations
must
be
in
compliance
with
the
operating
limits
for
emission
capture
systems
and
add
on
control
devices
required
by
§
63.3093
at
all
times
except
during
periods
of
startup,
shutdown,
and
malfunction.
(
c)
You
must
be
in
compliance
with
the
work
practice
standards
in
§
63.3094
at
all
times.
(
d)
You
must
always
operate
and
maintain
your
affected
source
including
all
air
pollution
control
and
monitoring
equipment
you
use
for
purposes
of
complying
with
this
subpart
according
to
the
provisions
in
§
63.6(
e)(
1)(
i).
(
e)
You
must
maintain
a
log
detailing
the
operation
and
maintenance
of
the
emission
capture
systems,
add
on
control
devices,
and
continuous
parameter
monitors
(
CPM)
during
the
period
between
the
compliance
date
specified
for
your
affected
source
in
§
63.3083
and
the
date
when
the
initial
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Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
emission
capture
system
and
add
on
control
device
performance
tests
have
been
completed,
as
specified
in
§
63.3160.
(
f)
If
your
affected
source
uses
emission
capture
systems
and
add
on
control
devices,
you
must
develop
and
implement
a
written
startup,
shutdown,
and
malfunction
plan
according
to
the
provisions
in
§
63.6(
e)(
3).
The
plan
must
address
startup,
shutdown,
and
corrective
actions
in
the
event
of
a
malfunction
of
the
emission
capture
system
or
the
add
on
control
devices.
§
63.3101
What
parts
of
the
General
Provisions
apply
to
me?
Table
2
to
this
subpart
shows
which
parts
of
the
General
Provisions
in
§
§
63.1
through
63.15
apply
to
you.
Notifications,
Reports,
and
Records
§
63.3110
What
notifications
must
I
submit?
(
a)
General.
You
must
submit
the
notifications
in
§
§
63.7(
b)
and
(
c),
63.8(
f)(
4),
and
63.9(
b)
through
(
e)
and
(
h)
that
apply
to
you
by
the
dates
specified
in
those
sections,
except
as
provided
in
paragraphs
(
b)
and
(
c)
of
this
section.
(
b)
Initial
notification.
You
must
submit
the
Initial
Notification
required
by
§
63.9(
b)
for
a
new
or
reconstructed
affected
source
no
later
than
120
days
after
initial
startup
or
120
days
after
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER],
whichever
is
later.
For
an
existing
affected
source,
you
must
submit
the
Initial
Notification
no
later
than
1
year
after
[
DATE
OF
PUBLICATION
OF
FINAL
RULE
IN
THE
FEDERAL
REGISTER].
(
c)
Notification
of
compliance
status.
You
must
submit
the
Notification
of
Compliance
Status
required
by
§
63.9(
h)
no
later
than
30
calendar
days
following
the
end
of
the
initial
compliance
period
described
in
§
63.3160
that
applies
to
your
affected
source.
The
Notification
of
Compliance
Status
must
contain
the
information
specified
in
paragraphs
(
c)(
1)
through
(
12)
of
this
section
and
in
§
63.9(
h).
(
1)
Company
name
and
address.
(
2)
Statement
by
a
responsible
official
with
that
official's
name,
title,
and
signature,
certifying
the
truth,
accuracy,
and
completeness
of
the
content
of
the
report.
(
3)
Date
of
the
report
and
beginning
and
ending
dates
of
the
reporting
period.
The
reporting
period
is
the
initial
compliance
period
described
in
§
63.3160
that
applies
to
your
affected
source.
(
4)
Identification
of
the
compliance
option
specified
in
§
63.3090(
a)
or
(
b)
or
§
63.3091(
a)
or
(
b)
that
you
used
for
electrodeposition
primer,
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
application
in
the
affected
source
during
the
initial
compliance
period.
(
5)
Statement
of
whether
or
not
the
affected
source
achieved
the
emission
limitations
for
the
initial
compliance
period.
(
6)
If
you
had
a
deviation,
include
the
information
in
paragraphs
(
c)(
6)(
i)
and
(
ii)
of
this
section.
(
i)
A
description
and
statement
of
the
cause
of
the
deviation.
(
ii)
If
you
failed
to
meet
any
of
the
applicable
emission
limits
in
§
63.3090
or
§
63.3091,
include
all
the
calculations
you
used
to
determine
the
applicable
emission
rate
or
applicable
average
organic
HAP
content
for
the
emission
limit(
s)
that
you
failed
to
meet.
You
do
not
need
to
submit
information
provided
by
the
materials
suppliers
or
manufacturers,
or
test
reports.
(
7)
All
data
and
calculations
used
to
determine
the
monthly
average
mass
of
organic
HAP
emitted
per
volume
of
applied
coating
solids
from:
(
i)
The
combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations
if
you
were
eligible
for
and
chose
to
comply
with
the
emission
limits
of
§
63.3090(
b)
or
§
63.3091(
b);
or
(
ii)
The
combined
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations.
(
8)
All
data
and
calculations
used
to
determine
compliance
with
the
separate
limits
for
electrodeposition
primer
in
§
63.3092(
a)
or
(
b)
if
you
were
eligible
for
and
chose
to
comply
with
the
emission
limits
of
§
63.3090(
b)
or
§
63.3091(
b).
(
9)
All
data
and
calculations
used
to
determine
the
monthly
mass
average
HAP
content
of
materials
subject
to
the
emission
limits
of
§
63.3090(
c)
and
(
d)
or
§
63.3091(
c)
and
(
d).
(
10)
All
data
and
calculations
used
to
determine
the
transfer
efficiency
for
primer
surfacer
and
topcoat
coatings.
(
11)
You
must
include
the
information
specified
in
paragraphs
(
c)(
11)(
i)
through
(
iii)
of
this
section.
(
i)
For
each
emission
capture
system,
a
summary
of
the
data
and
copies
of
the
calculations
supporting
the
determination
that
the
emission
capture
system
is
a
permanent
total
enclosure
(
PTE)
or
a
measurement
of
the
emission
capture
system
efficiency.
Include
a
description
of
the
procedure
followed
for
measuring
capture
efficiency,
summaries
of
any
capture
efficiency
tests
conducted,
and
any
calculations
supporting
the
capture
efficiency
determination.
If
you
use
the
data
quality
objective
(
DQO)
or
lower
confidence
limit
(
LCL)
approach,
you
must
also
include
the
statistical
calculations
to
show
you
meet
the
DQO
or
LCL
criteria
in
appendix
A
to
subpart
KK
of
this
part.
You
do
not
need
to
submit
complete
test
reports.
(
ii)
A
summary
of
the
results
of
each
add
on
control
device
performance
test.
You
do
not
need
to
submit
complete
test
reports
unless
requested.
(
iii)
A
list
of
each
emission
capture
system's
and
add
on
control
device's
operating
limits
and
a
summary
of
the
data
used
to
calculate
those
limits.
(
12)
A
statement
of
whether
or
not
you
developed
and
implemented
the
work
practice
plans
required
by
§
63.3094(
b)
and
(
c).
§
63.3120
What
reports
must
I
submit?
(
a)
Semiannual
compliance
reports.
You
must
submit
semiannual
compliance
reports
for
each
affected
source
according
to
the
requirements
of
paragraphs
(
a)(
1)
through
(
7)
of
this
section.
The
semiannual
compliance
reporting
requirements
may
be
satisfied
by
reports
required
under
other
parts
of
the
CAA,
as
specified
in
paragraph
(
a)(
2)
of
this
section.
(
1)
Dates.
Unless
the
Administrator
has
approved
a
different
schedule
for
submission
of
reports
under
§
63.10(
a),
you
must
prepare
and
submit
each
semiannual
compliance
report
according
to
the
dates
specified
in
paragraphs
(
a)(
1)(
i)
through
(
iv)
of
this
section.
(
i)
The
first
semiannual
compliance
report
must
cover
the
first
semiannual
reporting
period
which
begins
the
day
after
the
end
of
the
initial
compliance
period
described
in
§
63.3160
that
applies
to
your
affected
source
and
ends
on
June
30
or
December
31,
whichever
occurs
first
following
the
end
of
the
initial
compliance
period.
(
ii)
Each
subsequent
semiannual
compliance
report
must
cover
the
subsequent
semiannual
reporting
period
from
January
1
through
June
30
or
the
semiannual
reporting
period
from
July
1
through
December
31.
(
iii)
Each
semiannual
compliance
report
must
be
postmarked
or
delivered
no
later
than
July
31
or
January
31,
whichever
date
is
the
first
date
following
the
end
of
the
semiannual
reporting
period.
(
iv)
For
each
affected
source
that
is
subject
to
permitting
regulations
pursuant
to
40
CFR
part
70
or
40
CFR
part
71,
and
if
the
permitting
authority
has
established
dates
for
submitting
semiannual
reports
pursuant
to
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
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FM\
24DEP2.
SGM
24DEP2
78641
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
71.6(
a)(
3)(
iii)(
A),
you
may
submit
the
first
and
subsequent
compliance
reports
according
to
the
dates
the
permitting
authority
has
established
instead
of
according
to
the
date
specified
in
paragraph
(
a)(
1)(
iii)
of
this
section.
(
2)
Inclusion
with
title
V
report.
If
you
have
obtained
a
title
V
operating
permit
pursuant
to
40
CFR
part
70
or
40
CFR
part
71,
you
must
report
all
deviations
as
defined
in
this
subpart
in
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A).
If
you
submit
a
semiannual
compliance
report
pursuant
to
this
section
along
with,
or
as
part
of,
the
semiannual
monitoring
report
required
by
40
CFR
70.6(
a)(
3)(
iii)(
A)
or
40
CFR
71.6(
a)(
3)(
iii)(
A),
and
the
semiannual
compliance
report
includes
all
required
information
concerning
deviations
from
any
emission
limit,
operating
limit,
or
work
practice
in
this
subpart,
its
submission
shall
be
deemed
to
satisfy
any
obligation
to
report
the
same
deviations
in
the
semiannual
monitoring
report.
However,
submission
of
a
semiannual
compliance
report
shall
not
otherwise
affect
any
obligation
you
may
have
to
report
deviations
from
permit
requirements
to
the
permitting
authority.
(
3)
General
requirements.
The
semiannual
compliance
report
must
contain
the
information
specified
in
paragraphs
(
a)(
3)(
i)
through
(
iv)
of
this
section,
and
the
information
specified
in
paragraphs
(
a)(
4)
through
(
9)
and
(
c)(
1)
of
this
section
that
are
applicable
to
your
affected
source.
(
i)
Company
name
and
address.
(
ii)
Statement
by
a
responsible
official
with
that
official's
name,
title,
and
signature,
certifying
the
truth,
accuracy,
and
completeness
of
the
content
of
the
report.
(
iii)
Date
of
report
and
beginning
and
ending
dates
of
the
reporting
period.
The
reporting
period
is
the
6
month
period
ending
on
June
30
or
December
31.
(
iv)
Identification
of
the
compliance
option
specified
in
§
63.3090(
b)
or
§
63.3091(
b)
that
you
used
for
electrodeposition
primer,
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
application
in
the
affected
source
during
the
initial
compliance
period.
(
4)
No
deviations.
If
there
were
no
deviations
from
the
emission
limitations,
operating
limits,
or
work
practices
in
§
§
63.3090,
63.3091,
63.3092,
63.3093,
and
63.3094
that
apply
to
you,
the
semiannual
compliance
report
must
include
a
statement
that
there
were
no
deviations
from
the
emission
limitations
during
the
reporting
period.
If
you
used
control
devices
to
comply
with
the
emission
limits,
and
there
were
no
periods
during
which
the
continuous
parameter
monitoring
systems
(
CPMS)
were
out
of
control
as
specified
in
§
63.8(
c)(
7),
the
semiannual
compliance
report
must
include
a
statement
that
there
were
no
periods
during
which
the
CPMS
were
out
of
control
during
the
reporting
period.
(
5)
Deviations:
adhesive,
sealer,
and
deadener.
If
there
was
a
deviation
from
the
applicable
emission
limits
in
§
63.3090(
c)
and
(
d)
or
§
63.3091(
c)
and
(
d),
the
semiannual
compliance
report
must
contain
the
information
in
paragraphs
(
a)(
5)(
i)
through
(
iv)
of
this
section.
(
i)
The
beginning
and
ending
dates
of
each
month
during
which
the
monthly
average
organic
HAP
content
exceeded
the
applicable
emission
limit
in
§
63.3090(
c)
and
(
d)
or
§
63.3091(
c)
and
(
d).
(
ii)
The
volume
and
organic
HAP
content
of
each
material
used
that
is
subject
to
the
applicable
organic
HAP
content
limit.
(
iii)
The
calculation
used
to
determine
the
average
monthly
organic
HAP
content
for
the
month
in
which
the
deviation
occurred.
(
iv)
The
reason
for
the
deviation.
(
6)
Deviations:
combined
electrodeposition
primer,
primersurfacer
topcoat,
final
repair,
glass
bonding
primer
and
glass
bonding
adhesive,
or
combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive.
If
there
was
a
deviation
from
the
applicable
emission
limits
in
§
63.3090(
a)
or
(
b)
or
§
63.3091(
a)
or
(
b),
the
semiannual
compliance
report
must
contain
the
information
in
paragraphs
(
a)(
6)(
i)
through
(
xiv)
of
this
section.
(
i)
The
beginning
and
ending
dates
of
each
month
during
which
the
monthly
organic
HAP
emission
rate
from
combined
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
exceeded
the
applicable
emission
limit
in
§
63.3090(
a)
or
§
63.3091(
a);
or
the
monthly
organic
HAP
emission
rate
from
combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
exceeded
the
applicable
emission
limit
in
§
63.3090(
b)
or
§
63.3091(
b).
(
ii)
The
calculation
used
to
determine
the
monthly
organic
HAP
emission
rate
in
accordance
with
§
63.3161
or
§
63.3171.
You
do
not
need
to
submit
the
background
data
supporting
these
calculations,
for
example
information
provided
by
materials
suppliers
or
manufacturers,
or
test
reports.
(
iii)
The
date
and
time
that
any
malfunctions
of
the
capture
system
or
add
on
control
devices
used
to
control
emissions
from
these
operations
started
and
stopped.
(
iv)
A
brief
description
of
the
CPMS.
(
v)
The
date
of
the
latest
CPMS
certification
or
audit.
(
vi)
The
date
and
time
that
each
CPMS
was
inoperative,
except
for
zero
(
low
level)
and
high
level
checks.
(
vii)
The
date
and
time
period
that
each
CPMS
was
out
of
control,
including
the
information
in
§
63.8(
c)(
8).
(
viii)
The
date
and
time
period
of
each
deviation
from
an
operating
limit
in
Table
1
to
this
subpart;
date
and
time
period
of
each
bypass
of
an
add
on
control
device;
and
whether
each
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction
or
during
another
period.
(
ix)
A
summary
of
the
total
duration
and
the
percent
of
the
total
source
operating
time
of
the
deviations
from
each
operating
limit
in
Table
1
to
this
subpart
and
the
bypass
of
each
add
on
control
device
during
the
semiannual
reporting
period.
(
x)
A
breakdown
of
the
total
duration
of
the
deviations
from
each
operating
limit
in
Table
1
to
this
subpart
and
bypasses
of
each
add
on
control
device
during
the
semiannual
reporting
period
into
those
that
were
due
to
startup,
shutdown,
control
equipment
problems,
process
problems,
other
known
causes,
and
other
unknown
causes.
(
xi)
A
summary
of
the
total
duration
and
the
percent
of
the
total
source
operating
time
of
the
downtime
for
each
CPMS
during
the
semiannual
reporting
period.
(
xii)
A
description
of
any
changes
in
the
CPMS,
coating
operation,
emission
capture
system,
or
add
on
control
devices
since
the
last
semiannual
reporting
period.
(
xiii)
For
each
deviation
from
the
work
practice
standards,
a
description
of
the
deviation,
the
date
and
time
period
of
the
deviation,
and
the
actions
you
took
to
correct
the
deviation.
(
xiv)
A
statement
of
the
cause
of
each
deviation.
(
7)
Deviations:
separate
electrodeposition
primer
organic
HAP
content
limit.
If
you
used
the
separate
electrodeposition
primer
organic
HAP
content
limits
in
§
63.3092(
a),
and
there
was
a
deviation
from
these
limits,
the
semiannual
compliance
report
must
contain
the
information
in
paragraphs
(
a)(
7)(
i)
through
(
iii)
of
this
section.
(
i)
Identification
of
each
material
used
that
deviated
from
the
emission
limit,
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E:\
FR\
FM\
24DEP2.
SGM
24DEP2
78642
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
and
the
dates
and
time
periods
each
was
used.
(
ii)
The
determination
of
mass
fraction
of
each
organic
HAP
for
each
material
identified
in
paragraph
(
a)(
7)(
i)
of
this
section.
You
do
not
need
to
submit
background
data
supporting
this
calculation,
for
example,
information
provided
by
material
suppliers
or
manufacturers,
or
test
reports.
(
iii)
A
statement
of
the
cause
of
each
deviation.
(
8)
Deviations:
separate
electrodeposition
primer
bake
oven
capture
and
control
limitations.
If
you
used
the
separate
electrodeposition
primer
bake
oven
capture
and
control
limitations
in
§
63.3092(
b),
and
there
was
a
deviation
from
these
limitations,
the
semiannual
compliance
report
must
contain
the
information
in
paragraphs
(
a)(
8)(
i)
through
(
xii)
of
this
section.
(
i)
The
beginning
and
ending
dates
of
each
month
during
which
there
was
a
deviation
from
the
separate
electrodeposition
primer
bake
oven
capture
and
control
limitations
in
§
63.3092(
b).
(
ii)
The
date
and
time
that
any
malfunctions
of
the
capture
systems
or
control
devices
used
to
control
emissions
from
the
electrodeposition
primer
bake
oven
started
and
stopped.
(
iii)
A
brief
description
of
the
CPMS.
(
iv)
The
date
of
the
latest
CPMS
certification
or
audit.
(
v)
The
date
and
time
that
each
CPMS
was
inoperative,
except
for
zero
(
lowlevel
and
high
level
checks.
(
vi)
The
date,
time,
and
duration
that
each
CPMS
was
out
of
control,
including
the
information
in
§
63.8(
c)(
8).
(
vii)
The
date
and
time
period
of
each
deviation
from
an
operating
limit
in
Table
1
to
this
subpart;
date
and
time
period
of
each
bypass
of
an
add
on
control
device;
and
whether
each
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction
or
during
another
period.
(
viii)
A
summary
of
the
total
duration
and
the
percent
of
the
total
source
operating
time
of
the
deviations
from
each
operating
limit
in
Table
1
to
this
subpart
and
the
bypasses
of
each
addon
control
device
during
the
semiannual
reporting
period.
(
ix)
A
breakdown
of
the
total
duration
of
the
deviations
from
each
operating
limit
in
Table
1
to
this
subpart
and
bypasses
of
each
add
on
control
device
during
the
semiannual
reporting
period
into
those
that
were
due
to
startup,
shutdown,
control
equipment
problems,
process
problems,
other
known
causes,
and
other
unknown
causes.
(
x)
A
summary
of
the
total
duration
and
the
percent
of
the
total
source
operating
time
of
the
downtime
for
each
CPMS
during
the
semiannual
reporting
period.
(
xi)
A
description
of
any
changes
in
the
CPMS,
coating
operation,
emission
capture
system,
or
add
on
control
devices
since
the
last
semiannual
reporting
period.
(
xii)
A
statement
of
the
cause
of
each
deviation.
(
9)
Deviations:
work
practice
plans.
If
there
was
a
deviation
from
an
applicable
work
practice
plan
developed
in
accordance
with
§
63.3094(
b)
or
(
c),
the
semiannual
compliance
report
must
contain
the
information
in
paragraphs
(
a)(
9)(
i)
through
(
iii)
of
this
section.
(
i)
The
time
period
during
which
each
deviation
occurred.
(
ii)
The
nature
of
each
deviation.
(
iii)
The
corrective
action(
s)
taken
to
bring
the
applicable
work
practices
into
compliance
with
the
work
practice
plan.
(
b)
Performance
test
reports.
If
you
use
add
on
control
devices,
you
must
submit
reports
of
performance
test
results
for
emission
capture
systems
and
add
on
control
devices
no
later
than
60
days
after
completing
the
tests
as
specified
in
§
63.10(
d)(
2).
(
c)
Startup,
shutdown,
and
malfunction
reports.
If
you
used
add
on
control
devices
and
you
had
a
startup,
shutdown,
or
malfunction
during
the
semiannual
reporting
period,
you
must
submit
the
reports
specified
in
paragraphs
(
c)(
1)
and
(
2)
of
this
section.
(
1)
If
your
actions
were
consistent
with
your
startup,
shutdown,
and
malfunction
plan,
you
must
include
the
information
specified
in
§
63.10(
d)
in
the
semiannual
compliance
report
required
by
paragraph
(
a)
of
this
section.
(
2)
If
your
actions
were
not
consistent
with
your
startup,
shutdown,
and
malfunction
plan,
you
must
submit
an
immediate
startup,
shutdown,
and
malfunction
report
as
described
in
paragraphs
(
c)(
2)(
i)
and
(
ii)
of
this
section.
(
i)
You
must
describe
the
actions
taken
during
the
event
in
a
report
delivered
by
facsimile,
telephone,
or
other
means
to
the
Administrator
within
2
working
days
after
starting
actions
that
are
inconsistent
with
the
plan.
(
ii)
You
must
submit
a
letter
to
the
Administrator
within
7
working
days
after
the
end
of
the
event,
unless
you
have
made
alternative
arrangements
with
the
Administrator
as
specified
in
§
63.10(
d)(
5)(
ii).
The
letter
must
contain
the
information
specified
in
§
63.10(
d)(
5)(
ii).
§
63.3130
What
records
must
I
keep?
You
must
collect
and
keep
records
of
the
data
and
information
specified
in
this
section.
Failure
to
collect
and
keep
these
records
is
a
deviation
from
the
applicable
standard.
(
a)
A
copy
of
each
notification
and
report
that
you
submitted
to
comply
with
this
subpart,
and
the
documentation
supporting
each
notification
and
report.
(
b)
A
current
copy
of
information
provided
by
materials
suppliers
or
manufacturers,
such
as
manufacturer's
formulation
data,
or
test
data
used
to
determine
the
mass
fraction
of
organic
HAP,
the
density
and
the
volume
fraction
of
coating
solids
for
each
coating,
the
mass
fraction
of
organic
HAP
and
the
density
for
each
thinner,
and
the
mass
fraction
of
organic
HAP
for
each
cleaning
material.
If
you
conducted
testing
to
determine
mass
fraction
of
organic
HAP,
density,
or
volume
fraction
of
coating
solids,
you
must
keep
a
copy
of
the
complete
test
report.
If
you
use
information
provided
to
you
by
the
manufacturer
or
supplier
of
the
material
that
was
based
on
testing,
you
must
keep
the
summary
sheet
of
results
provided
to
you
by
the
manufacturer
or
supplier.
If
you
use
the
results
of
an
analysis
conducted
by
an
outside
testing
lab,
you
must
keep
a
copy
of
the
test
report.
You
are
not
required
to
obtain
the
test
report
or
other
supporting
documentation
from
the
manufacturer
or
supplier.
(
c)
For
each
month,
the
records
specified
in
paragraphs
(
c)(
1)
through
(
5)
of
this
section.
(
1)
For
each
coating
material
used
for
electrodeposition
primer,
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations,
a
record
of
the
volume
used
in
each
month,
the
mass
fraction
organic
HAP
content,
the
density,
and
the
volume
fraction
of
solids.
(
2)
For
each
coating
material
used
for
deadener,
sealer,
or
adhesive,
a
record
of
the
mass
used
in
each
month
and
the
mass
organic
HAP
content.
(
3)
A
record
of
the
calculation
of
the
organic
HAP
emission
rate
for
electrodeposition
primer,
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
for
each
month
if
subject
to
the
emission
rate
limit
of
§
63.3090(
a)
or
§
63.3091(
a).
(
4)
A
record
of
the
calculation
of
the
organic
HAP
emission
rate
for
primersurfacer
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
for
each
month
if
subject
to
the
emission
rate
limit
of
§
63.3090(
b)
or
§
63.3091(
b),
and
a
record
of
the
weight
fraction
of
each
organic
HAP
in
each
material
added
to
the
electrodeposition
primer
system
if
subject
to
the
limitations
of
§
63.3092(
a).
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/
Proposed
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(
5)
A
record,
for
each
month,
of
the
calculation
of
the
average
monthly
mass
organic
HAP
content
of:
(
i)
Sealers
and
adhesives;
and
(
ii)
Deadeners.
(
d)
A
record
of
the
name
and
volume
of
each
cleaning
material
used
during
each
month.
(
e)
A
record
of
the
mass
fraction
of
organic
HAP
for
each
cleaning
material
used
during
each
month.
(
f)
A
record
of
the
density
for
each
cleaning
material
used
during
each
month.
(
g)
A
record
of
the
date,
time,
and
duration
of
each
deviation,
and
for
each
deviation,
a
record
of
whether
the
deviation
occurred
during
a
period
of
startup,
shutdown,
or
malfunction.
(
h)
The
records
required
by
§
63.6(
e)(
3)(
iii)
through
(
v)
related
to
startup,
shutdown,
and
malfunction.
(
i)
For
each
capture
system
that
is
a
PTE,
the
data
and
documentation
you
used
to
support
a
determination
that
the
capture
system
meets
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
a
PTE
and
has
a
capture
efficiency
of
100
percent.
(
j)
For
each
capture
system
that
is
not
a
PTE,
the
data
and
documentation
you
used
to
determine
capture
efficiency
according
to
the
requirements
specified
in
§
63.3164,
including
the
records
specified
in
paragraphs
(
j)(
1)
through
(
4)
of
this
section
that
apply
to
you.
(
1)
Records
for
a
liquid
touncaptured
gas
protocol
using
a
temporary
total
enclosure
or
building
enclosure.
Records
of
the
mass
of
total
volatile
hydrocarbon
(
TVH),
as
measured
by
Method
204A
or
F
of
appendix
M
to
40
CFR
part
51,
for
each
material
used
in
the
coating
operation,
and
the
total
TVH
for
all
materials
used
during
each
capture
efficiency
test
run,
including
a
copy
of
the
test
report.
Records
of
the
mass
of
TVH
emissions
not
captured
by
the
capture
system
that
exited
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run,
as
measured
by
Method
204D
or
E
of
appendix
M
to
40
CFR
part
51,
including
a
copy
of
the
test
report.
Records
documenting
that
the
enclosure
used
for
the
capture
efficiency
test
met
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
either
a
temporary
total
enclosure
or
a
building
enclosure.
(
2)
Records
for
a
gas
to
gas
protocol
using
a
temporary
total
enclosure
or
a
building
enclosure.
Records
of
the
mass
of
TVH
emissions
captured
by
the
emission
capture
system,
as
measured
by
Method
204B
or
C
of
appendix
M
to
40
CFR
part
51,
at
the
inlet
to
the
addon
control
device,
including
a
copy
of
the
test
report.
Records
of
the
mass
of
TVH
emissions
not
captured
by
the
capture
system
that
exited
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run,
as
measured
by
Method
204D
or
E
of
appendix
M
to
40
CFR
part
51,
including
a
copy
of
the
test
report.
Records
documenting
that
the
enclosure
used
for
the
capture
efficiency
test
met
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
either
a
temporary
total
enclosure
or
a
building
enclosure.
(
3)
Records
for
panel
tests.
Records
needed
to
document
a
capture
efficiency
determination
using
a
panel
test
as
described
in
§
63.3165(
e),
including
a
copy
of
the
test
report
and
calculations
performed
to
convert
the
panel
test
results
to
percent
capture
efficiency
values.
(
4)
Records
for
an
alternative
protocol.
Records
needed
to
document
a
capture
efficiency
determination
using
an
alternative
method
or
protocol,
if
applicable.
(
k)
The
records
specified
in
paragraphs
(
k)(
1)
and
(
2)
of
this
section
for
each
add
on
control
device
organic
HAP
destruction
or
removal
efficiency
determination
as
specified
in
§
63.3166.
(
1)
Records
of
each
add
on
control
device
performance
test
conducted
according
to
§
§
63.3164
and
63.3166.
(
2)
Records
of
the
coating
operation
conditions
during
the
add
on
control
device
performance
test
showing
that
the
performance
test
was
conducted
under
representative
operating
conditions.
(
l)
Records
of
the
data
and
calculations
you
used
to
establish
the
emission
capture
and
add
on
control
device
operating
limits
as
specified
in
§
63.3167
and
to
document
compliance
with
the
operating
limits
as
specified
in
Table
1
to
this
subpart.
(
m)
Records
of
the
data
and
calculations
you
used
to
determine
the
transfer
efficiency
for
primer
surfacer
and
topcoat
application.
(
n)
A
record
of
the
work
practice
plans
required
by
§
63.3094(
b)
and
(
c)
and
documentation
that
you
are
implementing
the
plan
on
a
continuous
basis.
§
63.3131
In
what
form
and
for
how
long
must
I
keep
my
records?
(
a)
Your
records
must
be
in
a
form
suitable
and
readily
available
for
expeditious
review
according
to
§
63.10(
b)(
1).
Where
appropriate,
the
records
may
be
maintained
as
electronic
spreadsheets
or
as
a
database.
(
b)
As
specified
in
§
63.10(
b)(
1),
you
must
keep
each
record
for
5
years
following
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record.
(
c)
You
must
keep
each
record
on
site
for
at
least
2
years
after
the
date
of
each
occurrence,
measurement,
maintenance,
corrective
action,
report,
or
record
according
to
§
63.10(
b)(
1).
You
may
keep
the
records
off
site
for
the
remaining
3
years.
Compliance
Requirements
for
Adhesive,
Sealer,
and
Deadener
§
63.3150
By
what
date
must
I
conduct
the
initial
compliance
demonstration?
You
must
complete
the
initial
compliance
demonstration
for
the
initial
compliance
period
according
to
the
requirements
of
§
63.3151.
The
initial
compliance
period
begins
on
the
applicable
compliance
date
specified
in
§
63.3083
and
ends
on
the
last
day
of
the
month
following
the
compliance
date.
If
the
compliance
date
occurs
on
any
day
other
than
the
first
day
of
a
month,
then
the
initial
compliance
period
extends
through
the
end
of
that
month
plus
the
next
month.
You
must
determine
the
mass
average
organic
HAP
content
of
the
materials
used
each
month
for
each
group
of
materials
for
which
an
emission
limitation
is
established
in
§
63.3090(
c)
and
(
d)
or
§
63.3091(
c)
and
(
d).
The
initial
compliance
demonstration
includes
the
calculations
according
to
§
63.3151
and
supporting
documentation
showing
that
during
the
initial
compliance
period,
the
mass
average
organic
HAP
content
for
each
group
of
materials
was
equal
to
or
less
than
the
applicable
emission
limits
in
§
63.3090(
c)
and
(
d)
or
§
63.3091(
c)
and
(
d).
§
63.3151
How
do
I
demonstrate
initial
compliance
with
the
emission
limitations?
You
must
separately
calculate
the
mass
average
organic
HAP
content
of
the
materials
used
during
the
initial
compliance
period
for
each
group
of
materials
for
which
an
emission
limit
is
established
in
§
63.3090(
c)
and
(
d)
or
§
63.3091(
c)
and
(
d).
If
every
individual
material
used
within
a
group
of
materials
meets
the
emission
limit
for
that
group
of
materials,
you
may
demonstrate
compliance
with
that
emission
limit
by
documenting
the
name
and
the
organic
HAP
content
of
each
material
used
during
the
initial
compliance
period.
If
any
individual
material
used
within
a
group
of
materials
exceeds
the
emission
limit
for
that
group
of
materials,
you
must
determine
the
mass
average
organic
HAP
content
according
to
the
procedures
of
paragraphs
(
d)
and
(
e)
of
this
section.
(
a)
Determine
the
mass
fraction
of
organic
HAP
for
each
material
used.
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No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
You
must
determine
the
mass
fraction
of
organic
HAP
for
each
material
used
during
the
compliance
period
by
using
one
of
the
options
in
paragraphs
(
a)(
1)
through
(
5)
of
this
section.
(
1)
Method
311
(
appendix
A
to
40
CFR
part
63).
You
may
use
Method
311
for
determining
the
mass
fraction
of
organic
HAP.
Use
the
procedures
specified
in
paragraphs
(
a)(
1)(
i)
and
(
ii)
of
this
section
when
performing
a
Method
311
test.
(
i)
Count
each
organic
HAP
that
is
measured
to
be
present
at
0.1
percent
by
mass
or
more
for
OSHA
defined
carcinogens,
as
specified
in
29
CFR
1910.1200(
d)(
4),
and
at
1.0
percent
by
mass
or
more
for
other
compounds.
For
example,
if
toluene
(
not
an
OSHA
carcinogen)
is
measured
to
be
0.5
percent
of
the
material
by
mass,
you
do
not
have
to
count
it.
Express
the
mass
fraction
of
each
organic
HAP
you
count
as
a
value
truncated
to
four
places
after
the
decimal
point
(
e.
g.,
0.3791).
(
ii)
Calculate
the
total
mass
fraction
of
organic
HAP
in
the
test
material
by
adding
up
the
individual
organic
HAP
mass
fractions
and
truncating
the
result
to
three
places
after
the
decimal
point
(
e.
g.,
0.7638
truncates
to
0.763).
(
2)
Method
24
(
appendix
A
to
40
CFR
part
60).
For
coatings,
you
may
use
Method
24
to
determine
the
mass
fraction
of
nonaqueous
volatile
matter
and
use
that
value
as
a
substitute
for
mass
fraction
of
organic
HAP.
(
3)
Alternative
method.
You
may
use
an
alternative
test
method
for
determining
the
mass
fraction
of
organic
HAP
once
the
Administrator
has
approved
it.
You
must
follow
the
procedure
in
§
63.7(
f)
to
submit
an
alternative
test
method
for
approval.
(
4)
Information
from
the
supplier
or
manufacturer
of
the
material.
You
may
rely
on
information
other
than
that
generated
by
the
test
methods
specified
in
paragraphs
(
a)(
1)
through
(
3)
of
this
section,
such
as
manufacturer's
formulation
data,
if
it
represents
each
organic
HAP
that
is
present
at
0.1
percent
by
mass
or
more
for
OSHAdefined
carcinogens,
as
specified
in
29
CFR
1910.1200(
d)(
4),
and
at
1.0
percent
by
mass
or
more
for
other
compounds.
For
example,
if
toluene
(
not
an
OSHA
carcinogen)
is
0.5
percent
of
the
material
by
mass,
you
do
not
have
to
count
it.
If
there
is
a
disagreement
between
such
information
and
results
of
a
test
conducted
according
to
paragraphs
(
a)(
1)
through
(
3)
of
this
section,
then
the
test
method
results
will
take
precedence.
(
5)
Solvent
blends.
Solvent
blends
may
be
listed
as
single
components
for
some
materials
in
data
provided
by
manufacturers
or
suppliers.
Solvent
blends
may
contain
organic
HAP
which
must
be
counted
toward
the
total
organic
HAP
mass
fraction
of
the
materials.
When
neither
test
data
nor
manufacturer's
data
for
solvent
blends
are
available,
you
may
use
the
default
values
for
the
mass
fraction
of
organic
HAP
in
the
solvent
blends
listed
in
Table
3
or
4
to
this
subpart.
If
you
use
the
tables,
you
must
use
the
values
in
Table
3
for
all
solvent
blends
that
match
Table
3
entries,
and
you
may
only
use
Table
4
if
the
solvent
blends
in
the
materials
you
use
do
not
match
any
of
the
solvent
blends
in
Table
3
and
you
only
know
whether
the
blend
is
aliphatic
or
aromatic.
However,
if
the
results
of
a
Method
311
test
indicate
higher
values
than
those
listed
on
Table
3
or
4
to
this
subpart,
the
Method
311
results
will
take
precedence.
(
b)
Determine
the
density
of
each
material
used.
Determine
the
density
of
each
material
used
during
the
compliance
period
from
test
results
using
ASTM
Method
D1475
98
or
information
from
the
supplier
or
manufacturer
of
the
material.
If
there
is
disagreement
between
ASTM
Method
D1475
98
test
results
and
the
supplier's
or
manufacturer's
information,
the
test
results
will
take
precedence.
(
c)
Determine
the
volume
of
each
material
used.
Determine
the
volume
(
liters)
of
each
material
used
during
each
month
by
measurement
or
usage
records.
(
d)
Determine
the
mass
average
organic
HAP
content
for
each
group
of
materials.
Determine
the
mass
average
organic
HAP
content
of
the
materials
used
during
the
initial
compliance
period
for
each
group
of
materials
for
which
an
emission
limit
is
established
in
§
63.3090(
c)
and
(
d)
or
§
63.3091(
c)
and
(
d),
using
Equations
1
and
2
of
this
section.
(
1)
Calculate
the
mass
average
organic
HAP
content
of
adhesive
and
sealer
materials
other
than
components
of
the
glass
bonding
system
used
in
the
initial
compliance
period
using
Equation
1
of
this
section:
C
Vol
D
W
Vol
D
Eq
avg
as
as
j
as
j
as
j
j
r
as
j
as
j
j
r
,
,
,
,
,
,
(
.
=
(
)(
)(
)
(
)(
)
=
=
1
1
1)
Where:
Cavg,
as
=
mass
average
organic
HAP
content
of
adhesives
and
sealers
used,
kg/
kg.
Volas,
j
=
volume
of
adhesive
or
sealer
j
used,
liters.
Das,
j
=
Density
of
adhesive
or
sealer
j
used,
kg
per
liter.
Was,
j
=
mass
fraction
of
organic
HAP
in
adhesive
or
sealer,
j,
kg/
kg.
r
=
number
of
adhesives
and
sealers
used.
(
2)
Calculate
the
mass
average
organic
HAP
content
of
deadener
used
in
the
initial
compliance
period
using
Equation
2
of
this
section:
C
Vol
D
W
Vol
D
Eq
avg
d
d
m
d
m
d
m
m
s
d
m
d
m
m
s
,
,
,
,
,
,
(
.
=
(
)(
)(
)
(
)(
)
=
=
1
1
2)
Where:
Cavg,
d
=
mass
average
organic
HAP
content
of
deadener
used,
kg/
kg.
Vold,
m
=
volume
of
deadener,
m,
used,
liters.
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FR\
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78645
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
Dd,
m
=
density
of
deadener,
m,
used,
kg
per
liter.
Wd,
m
=
mass
fraction
of
organic
HAP
in
deadener,
m,
kg/
kg.
s
=
number
of
deadener
materials
used.
(
e)
Compliance
demonstration.
The
mass
average
organic
HAP
content
for
the
compliance
period
must
be
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.3090(
c)
and
(
d)
or
§
63.3091(
c)
and
(
d).
You
must
keep
all
records
as
required
by
§
§
63.3130
and
63.3131.
As
part
of
the
Notification
of
Compliance
Status
required
by
§
63.3110,
you
must
submit
a
statement
that
the
coating
operations
were
in
compliance
with
the
emission
limitations
during
the
initial
compliance
period
because
the
mass
average
organic
HAP
content
was
less
than
or
equal
to
the
applicable
emission
limits
in
§
63.3090(
c)
and
(
d)
or
§
63.3091(
c)
and
(
d),
determined
according
to
this
section.
§
63.3152
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
(
a)
To
demonstrate
continuous
compliance,
the
mass
average
organic
HAP
content
for
each
compliance
period,
determined
according
to
§
63.3151(
a)
through
(
c),
must
be
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.3090(
c)
and
(
d)
or
§
63.3091(
c)
and
(
d).
A
compliance
period
consists
of
1
month.
Each
month
after
the
end
of
the
initial
compliance
period
described
in
§
63.3150
is
a
compliance
period
consisting
of
that
month.
(
b)
If
the
mass
average
organic
HAP
emission
content
for
any
compliance
period
exceeds
the
applicable
emission
limit
in
§
63.3090(
c)
and
(
d)
or
§
63.3091(
c)
and
(
d),
this
is
a
deviation
from
the
emission
limitations
for
that
compliance
period
and
must
be
reported
as
specified
in
§
§
63.3110(
c)(
6)
and
63.3120(
a)(
5).
(
c)
You
must
maintain
records
as
specified
in
§
§
63.3130
and
63.3131.
Compliance
Requirements
for
the
Combined
Electrodeposition
Primer,
Primer
Surfacer,
Topcoat,
Final
Repair,
Glass
Bonding
Primer,
and
Glass
Bonding
Adhesive
Emission
Rates
§
63.3160
By
what
date
must
I
conduct
performance
tests
and
other
initial
compliance
demonstrations?
(
a)
New
and
reconstructed
affected
sources.
For
a
new
or
reconstructed
affected
source,
you
must
meet
the
requirements
of
paragraphs
(
a)(
1)
through
(
4)
of
this
section.
(
1)
All
emission
capture
systems,
addon
control
devices,
and
CPMS
must
be
installed
and
operating
no
later
than
the
applicable
compliance
date
specified
in
§
63.3083.
You
must
conduct
a
performance
test
of
each
capture
system
and
add
on
control
device
according
to
§
§
63.3164
and
63.3166
and
establish
the
operating
limits
required
by
§
63.3093
no
later
than
180
days
after
the
applicable
compliance
date
specified
in
§
63.3083.
(
2)
You
must
develop
and
begin
implementing
the
work
practice
plans
required
by
§
63.3094(
b),
(
c),
and
(
e)
no
later
than
the
compliance
date
specified
in
§
63.3083.
(
3)
You
must
complete
the
initial
compliance
demonstration
for
the
initial
compliance
period
according
to
the
requirements
of
§
63.3161.
The
initial
compliance
period
begins
on
the
applicable
compliance
date
specified
in
§
63.3083
and
ends
on
the
last
day
of
the
month
following
the
compliance
date.
If
the
compliance
date
occurs
on
any
day
other
than
the
first
day
of
a
month,
then
the
initial
compliance
period
extends
through
the
end
of
that
month
plus
the
next
month.
You
must
determine
the
mass
of
organic
HAP
emissions
and
volume
of
coating
solids
deposited
in
the
initial
compliance
period.
The
initial
compliance
demonstration
includes
the
results
of
emission
capture
system
and
add
on
control
device
performance
tests
conducted
according
to
§
§
63.3164
and
63.3166;
supporting
documentation
showing
that
during
the
initial
compliance
period
the
organic
HAP
emission
rate
was
equal
to
or
less
than
the
emission
limit
in
§
63.3090(
a);
the
operating
limits
established
during
the
performance
tests
and
the
results
of
the
continuous
parameter
monitoring
required
by
§
63.3168;
and
documentation
of
whether
you
developed
and
implemented
the
work
practice
plans
required
by
§
63.3094(
b),
(
c),
and
(
e).
(
4)
You
do
not
need
to
comply
with
the
operating
limits
for
the
emission
capture
system
and
add
on
control
device
required
by
§
63.3093
until
after
you
have
completed
the
performance
tests
specified
in
paragraph
(
a)(
1)
of
this
section.
Instead,
you
must
maintain
a
log
detailing
the
operation
and
maintenance
of
the
emission
capture
system,
add
on
control
device,
and
CPM
during
the
period
between
the
compliance
date
and
the
performance
test.
You
must
begin
complying
with
the
operating
limits
for
your
affected
source
on
the
date
you
complete
the
performance
tests
specified
in
paragraph
(
a)(
1)
of
this
section.
(
b)
Existing
affected
sources.
For
an
existing
affected
source,
you
must
meet
the
requirements
of
paragraphs
(
b)(
1)
through
(
3)
of
this
section.
(
1)
All
emission
capture
systems,
addon
control
devices,
and
CPMS
must
be
installed
and
operating
no
later
than
the
applicable
compliance
date
specified
in
§
63.3083.
You
must
conduct
a
performance
test
of
each
capture
system
and
add
on
control
device
according
to
the
procedures
in
§
§
63.3164
and
63.3166
and
establish
the
operating
limits
required
by
§
63.3093
no
later
than
the
compliance
date
specified
in
§
63.3083.
(
2)
You
must
develop
and
begin
implementing
the
work
practice
plans
required
by
§
63.3094(
b),
(
c),
and
(
e)
no
later
than
the
compliance
date
specified
in
§
63.3083.
(
3)
You
must
complete
the
initial
compliance
demonstration
for
the
initial
compliance
period
according
to
the
requirements
of
§
63.3161.
The
initial
compliance
period
begins
on
the
applicable
compliance
date
specified
in
§
63.3083
and
ends
on
the
last
day
of
the
month
following
the
compliance
date.
If
the
compliance
date
occurs
on
any
day
other
than
the
first
day
of
a
month,
then
the
initial
compliance
period
extends
through
the
end
of
that
month
plus
the
next
month.
You
must
determine
the
mass
of
organic
HAP
emissions
and
volume
of
coating
solids
deposited
during
the
initial
compliance
period.
The
initial
compliance
demonstration
includes
the
results
of
emission
capture
system
and
add
on
control
device
performance
tests
conducted
according
to
§
§
63.3164
and
63.3166;
supporting
documentation
showing
that
during
the
initial
compliance
period
the
organic
HAP
emission
rate
was
equal
to
or
less
than
the
emission
limits
in
§
63.3091(
a);
the
operating
limits
established
during
the
performance
tests
and
the
results
of
the
continuous
parameter
monitoring
required
by
§
63.3168;
and
documentation
of
whether
you
developed
and
implemented
the
work
practice
plans
required
by
§
63.3094(
b),
(
c),
and
(
e).
§
63.3161
How
do
I
demonstrate
initial
compliance?
(
a)
You
must
meet
all
of
the
requirements
of
this
section
to
demonstrate
initial
compliance.
To
demonstrate
initial
compliance,
the
organic
HAP
emissions
from
the
combined
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations
must
meet
the
applicable
emission
limitation
in
§
63.3090(
a)
or
§
63.3091(
a).
(
b)
Compliance
with
operating
limits.
Except
as
provided
in
§
63.3160(
a)(
4),
you
must
establish
and
demonstrate
continuous
compliance
during
the
initial
compliance
period
with
the
operating
limits
required
by
§
63.3093,
VerDate
0ct<
31>
2002
20:
02
Dec
23,
2002
Jkt
200001
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00000
Frm
00035
Fmt
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E:\
FR\
FM\
24DEP2.
SGM
24DEP2
78646
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
using
the
procedures
specified
in
§
§
63.3167
and
63.3168.
(
c)
Compliance
with
work
practice
requirements.
You
must
develop,
implement,
and
document
your
implementation
of
the
work
practice
plans
required
by
§
63.3094(
b)
and
(
c)
during
the
initial
compliance
period,
as
specified
in
§
63.3130.
(
d)
Compliance
with
emission
limits.
You
must
follow
the
procedures
in
paragraphs
(
e)
through
(
o)
of
this
section
to
demonstrate
compliance
with
the
applicable
emission
limit
in
§
63.3090(
a)
or
§
63.3091(
a).
You
may
also
use
the
guidelines
presented
in
``
Protocol
for
Determining
Daily
Volatile
Organic
Compound
Emission
Rate
of
Automobile
and
Light
Duty
Truck
Topcoat
Operations,''
EPA
450/
3
88
018
(
docket
A
2001
22)
in
making
this
demonstration.
(
e)
Determine
the
mass
fraction
of
organic
HAP,
density
and
volume
used.
Follow
the
procedures
specified
in
§
63.3151(
a)
through
(
c)
to
determine
the
mass
fraction
of
organic
HAP
and
the
density
and
volume
of
each
coating
and
thinner
used
during
each
month.
(
f)
Determine
the
volume
fraction
of
coating
solids
for
each
coating.
You
must
determine
the
volume
fraction
of
coating
solids
(
liter
of
coating
solids
per
liter
of
coating)
for
each
coating
used
during
the
compliance
period
by
a
test
or
by
information
provided
by
the
supplier
or
the
manufacturer
of
the
material,
as
specified
in
paragraphs
(
f)(
1)
and
(
2)
of
this
section.
If
test
results
obtained
according
to
paragraph
(
f)(
1)
of
this
section
do
not
agree
with
the
information
obtained
under
paragraph
(
f)(
2)
of
this
section,
the
test
results
will
take
precedence.
(
1)
ASTM
Method
D2697
86(
1998)
or
D6093
97.
You
may
use
ASTM
Method
D2697
86(
1998)
or
D6093
97
to
determine
the
volume
fraction
of
coating
solids
for
each
coating.
Divide
the
nonvolatile
volume
percent
obtained
with
the
methods
by
100
to
calculate
volume
fraction
of
coating
solids.
(
2)
Information
from
the
supplier
or
manufacturer
of
the
material.
You
may
obtain
the
volume
fraction
of
coating
solids
for
each
coating
from
the
supplier
or
manufacturer.
(
g)
Determine
the
transfer
efficiency
for
each
coating.
You
must
determine
the
transfer
efficiency
for
each
primersurfacer
and
topcoat
coating
using
ASTM
Method
D5066
91(
2001)
or
the
guidelines
presented
in
``
Protocol
for
Determining
Daily
Volatile
Organic
Compound
Emission
Rate
of
Automobile
and
Light
Duty
Truck
Topcoat
Operations,''
EPA
450/
3
88
018
(
docket
A
2001
22).
Those
guidelines
include
provisions
for
testing
representative
coatings
instead
of
testing
every
coating.
You
may
assume
100
percent
transfer
efficiency
for
electrodeposition
primer
coatings,
glass
bonding
primers,
and
glass
bonding
adhesives.
For
final
repair
coatings,
you
may
assume
40
percent
transfer
efficiency
for
air
atomized
spray
and
55
percent
transfer
efficiency
for
electrostatic
spray
and
high
volume,
low
pressure
spray.
(
h)
Calculate
the
total
mass
of
organic
HAP
emissions
before
add
on
controls.
Calculate
the
total
mass
of
organic
HAP
emissions
before
consideration
of
addon
controls
from
all
coatings
and
thinners
used
during
each
month
in
the
combined
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations
using
Equation
1
of
this
section:
H
A
B
Eq
BC=
+
(
.
1)
Where:
HBC
=
total
mass
of
organic
HAP
emissions
before
consideration
of
add
on
controls
during
the
month,
kg.
A
=
total
mass
of
organic
HAP
in
the
coatings
used
during
the
month,
kg,
as
calculated
in
Equation
1A
of
this
section.
B
=
total
mass
of
organic
HAP
in
the
thinners
used
during
the
month,
kg,
as
calculated
in
Equation
1B
of
this
section.
(
1)
Calculate
the
kg
organic
HAP
in
the
coatings
used
during
the
month
using
Equation
1A
of
this
section:
A
Vol
D
W
Eq
c
i
i
m
c
i
c
i
=
(
)(
)(
)
=
,
,
,
(
.
1
1A)
Where:
A
=
total
mass
of
organic
HAP
in
the
coatings
used
during
the
month,
kg.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
month,
liters.
Dc,
i
=
density
of
coating,
i,
kg
coating
per
liter
coating.
Wc,
i
=
mass
fraction
of
organic
HAP
in
coating,
i,
kg
organic
HAP
per
kg
coating.
m
=
number
of
different
coatings
used
during
the
month.
(
2)
Calculate
the
kg
of
organic
HAP
in
the
thinners
used
during
the
month
using
Equation
1B
of
this
section:
B
Vol
D
W
Eq
t
j
j
n
t
j
t
j
=
(
)(
)(
)
=
,
,
,
(
.
1
1B)
Where:
B
=
total
mass
of
organic
HAP
in
the
thinners
used
during
the
month,
kg.
Volt,
j
=
total
volume
of
thinner,
j,
used
during
the
month,
liters.
Dt,
j
=
density
of
thinner,
j,
kg
per
liter.
Wt,
j
=
mass
fraction
of
organic
HAP
in
thinner,
j,
kg
organic
HAP
per
kg
thinner.
n
=
number
of
different
thinners
used
during
the
month.
(
i)
Calculate
the
organic
HAP
emission
reduction
for
each
controlled
coating
operation.
Determine
the
mass
of
organic
HAP
emissions
reduced
for
each
controlled
coating
operation
during
each
month.
The
emission
reduction
determination
quantifies
the
total
organic
HAP
emissions
captured
by
the
emission
capture
system
and
destroyed
or
removed
by
the
add
on
control
device.
Use
the
procedures
in
paragraph
(
j)
of
this
section
to
calculate
the
mass
of
organic
HAP
emission
reduction
for
each
controlled
coating
operation
using
an
emission
capture
system
and
add
on
control
device
other
than
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances.
For
each
controlled
coating
operation
using
a
solvent
recovery
system
for
which
you
conduct
a
liquid
liquid
material
balance,
use
the
procedures
in
paragraph
(
k)
of
this
section
to
calculate
the
organic
HAP
emission
reduction.
(
j)
Calculate
the
organic
HAP
emission
reduction
for
each
controlled
coating
operation
not
using
liquid
liquid
material
balances.
For
each
controlled
coating
operation
using
an
emission
capture
system
and
add
on
control
device
other
than
a
solvent
recovery
system
for
which
you
conduct
liquidliquid
material
balances,
calculate
the
mass
of
organic
HAP
emission
reduction
for
the
controlled
coating
operation
during
the
month
using
Equation
2
of
this
section.
The
calculation
of
mass
of
organic
HAP
emission
reduction
for
the
controlled
coating
operation
during
the
month
applies
the
emission
capture
system
efficiency
and
add
on
control
device
efficiency
to
the
mass
of
organic
HAP
contained
in
the
coatings
and
thinners
that
are
used
in
the
coating
operation
served
by
the
emission
capture
system
and
add
on
control
device
during
each
month.
For
any
period
of
time
a
deviation
specified
in
§
63.3163(
c)
or
(
d)
occurs
in
the
controlled
coating
operation,
including
a
deviation
during
a
period
of
startup,
shutdown,
or
malfunction,
you
must
assume
zero
efficiency
for
the
emission
capture
system
and
add
on
control
device.
Equation
2
of
this
section
treats
the
materials
used
during
such
a
deviation
as
if
they
were
used
on
an
uncontrolled
coating
operation
for
the
time
period
of
the
deviation.
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78647
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
H
A
B
H
CE
DRE
Eq
C
C
C
UNC
=
+
(
)
×
100
100
(
.
2)
Where:
HC
=
mass
of
organic
HAP
emission
reduction
for
the
controlled
coating
operation
during
the
month,
kg.
AC
=
total
mass
of
organic
HAP
in
the
coatings
used
in
the
controlled
coating
operation
during
the
month,
kg,
as
calculated
in
Equation
2A
of
this
section.
BC
=
total
mass
of
organic
HAP
in
the
thinners
used
in
the
controlled
coating
operation
during
the
month,
kg,
as
calculated
in
Equation
2B
of
this
section.
Hunc
=
total
mass
of
organic
HAP
in
the
coatings
and
thinners
used
during
all
deviations
specified
in
§
63.3163(
c)
and
(
d)
that
occurred
during
the
month
in
the
controlled
coating
operation,
kg,
as
calculated
in
Equation
2C
of
this
section.
CE
=
capture
efficiency
of
the
emission
capture
system
vented
to
the
add
on
control
device,
percent.
Use
the
test
methods
and
procedures
specified
in
§
§
63.3164
and
63.3165
to
measure
and
record
capture
efficiency.
DRE
=
organic
HAP
destruction
or
removal
efficiency
of
the
add
on
control
device,
percent.
Use
the
test
methods
and
procedures
in
§
§
63.3164
and
63.3166
to
measure
and
record
the
organic
HAP
destruction
or
removal
efficiency.
(
1)
Calculate
the
mass
of
organic
HAP
in
the
coatings
used
in
the
controlled
coating
operation,
kg,
using
Equation
2A
of
this
section.
A
Vol
D
W
Eq
C
ci
i
m
c
i
c
i
=
(
)(
)(
)
=
,
,
,
(
.
1
2A)
Where:
AC
=
total
mass
of
organic
HAP
in
the
coatings
used
in
the
controlled
coating
operation
during
the
month,
kg.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
month,
liters.
Dc,
i
=
density
of
coating,
i,
kg
per
liter.
Wc,
i
=
mass
fraction
of
organic
HAP
in
coating,
i,
kg
per
kg.
m
=
number
of
different
coatings
used.
(
2)
Calculate
the
mass
of
organic
HAP
in
the
thinners
used
in
the
controlled
coating
operation,
kg,
using
Equation
2B
of
this
section.
B
Vol
D
W
Eq
C
tj
j
n
t
j
t
j
=
(
)(
)(
)
=
,
,
,
(
.
1
2B)
Where:
BC
=
total
mass
of
organic
HAP
in
the
thinners
used
in
the
controlled
coating
operation
during
the
month,
kg.
Volt,
j
=
total
volume
of
thinner,
j,
used
during
the
month,
liters.
Dt,
j
=
density
of
thinner,
j,
kg
per
liter.
Wt,
j
=
mass
fraction
of
organic
HAP
in
thinner,
j,
kg
per
kg.
n
=
number
of
different
thinners
used.
(
3)
Calculate
the
mass
of
organic
HAP
in
the
coatings
and
thinners
used
in
the
controlled
coating
operation
during
deviations
specified
in
§
63.3163(
c)
and
(
d),
using
Equation
2C
of
this
section:
H
Vol
D
W
Eq
unc
h
h
h
h
q
=
(
)(
)
=
(
)
(
.
1
2C)
Where:
Hunc
=
total
mass
of
organic
HAP
in
the
coatings
and
thinners
used
during
all
deviations
specified
in
§
63.3163(
c)
and
(
d)
that
occurred
during
the
month
in
the
controlled
coating
operation,
kg.
Volh
=
total
volume
of
coating
or
thinner,
h,
used
in
the
controlled
coating
operation
during
deviations,
liters.
Dh
=
density
of
coating
or
thinner,
h,
kg
per
liter.
Wh
=
mass
fraction
of
organic
HAP
in
coating
or
thinner,
h,
kg
organic
HAP
per
kg
coating.
q
=
number
of
different
coatings
or
thinners.
(
k)
Calculate
the
organic
HAP
emission
reduction
for
each
controlled
coating
operation
using
liquid
liquid
material
balances.
For
each
controlled
coating
operation
using
a
solvent
recovery
system
for
which
you
conduct
liquid
liquid
material
balances,
calculate
the
mass
of
organic
HAP
emission
reduction
for
the
coating
operation
controlled
by
the
solvent
recovery
system
using
a
liquid
liquid
material
balance
during
the
month
by
applying
the
volatile
organic
matter
collection
and
recovery
efficiency
to
the
mass
of
organic
HAP
contained
in
the
coatings
and
thinners
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
each
month.
Perform
a
liquid
liquid
material
balance
for
each
month
as
specified
in
paragraphs
(
k)(
1)
through
(
6)
of
this
section.
Calculate
the
mass
of
organic
HAP
emission
reduction
by
the
solvent
recovery
system
as
specified
in
paragraph
(
k)(
7)
of
this
section.
(
1)
For
each
solvent
recovery
system,
install,
calibrate,
maintain,
and
operate
according
to
the
manufacturer's
specifications,
a
device
that
indicates
the
cumulative
amount
of
volatile
organic
matter
recovered
by
the
solvent
recovery
system
each
month.
The
device
must
be
initially
certified
by
the
manufacturer
to
be
accurate
to
within
±
2.0
percent
of
the
mass
of
volatile
organic
matter
recovered.
(
2)
For
each
solvent
recovery
system,
determine
the
mass
of
volatile
organic
matter
recovered
for
the
month,
kg,
based
on
measurement
with
the
device
required
in
paragraph
(
k)(
1)
of
this
section.
(
3)
Determine
the
mass
fraction
of
volatile
organic
matter
for
each
coating
and
thinner
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
kg
volatile
organic
matter
per
kg
coating.
You
may
determine
the
volatile
organic
matter
mass
fraction
using
Method
24
of
40
CFR
part
60,
appendix
A,
or
an
EPA
approved
alternative
method,
or
you
may
use
information
provided
by
the
manufacturer
or
supplier
of
the
coating.
In
the
event
of
any
inconsistency
between
information
provided
by
the
manufacturer
or
supplier
and
the
results
of
Method
24
of
40
CFR
part
60,
appendix
A,
or
an
approved
alternative
method,
the
test
method
results
will
govern.
(
4)
Determine
the
density
of
each
coating
and
thinner
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
kg
per
liter,
according
to
§
63.3151(
b).
(
5)
Measure
the
volume
of
each
coating
and
thinner
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
liters.
(
6)
Each
month,
calculate
the
solvent
recovery
system's
volatile
organic
matter
collection
and
recovery
efficiency,
using
Equation
3
of
this
section:
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78648
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
R
M
Vol
D
WV
Vol
D
WV
Eq
v
VR
i
i
ci
j
j
t
j
j
n
i
m
=
+
=
=
100
1
1
,
,
(
.
3)
Where:
RV
=
volatile
organic
matter
collection
and
recovery
efficiency
of
the
solvent
recovery
system
during
the
month,
percent.
MVR
=
mass
of
volatile
organic
matter
recovered
by
the
solvent
recovery
system
during
the
month,
kg.
Voli
=
volume
of
coating,
i,
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
liters.
Di
=
density
of
coating,
i,
kg
per
liter.
WVc,
i
=
mass
fraction
of
volatile
organic
matter
for
coating,
i,
kg
volatile
organic
matter
per
kg
coating.
Volj
=
volume
of
thinner,
j,
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
liters.
Dj
=
density
of
thinner,
j,
kg
per
liter.
WVt,
j
=
mass
fraction
of
volatile
organic
matter
for
thinner,
j,
kg
volatile
organic
matter
per
kg
thinner.
m
=
number
of
different
coatings
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month.
n
=
number
of
different
thinners
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month.
(
7)
Calculate
the
mass
of
organic
HAP
emission
reduction
for
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
using
Equation
4
of
this
section:
H
A
B
R
Eq
CSR
CSR
CSR
v
=
+
(
)
(.
100
4)
Where:
HCSR
=
mass
of
organic
HAP
emission
reduction
for
the
coating
operation
controlled
by
the
solvent
recovery
system
using
a
liquid
liquid
material
balance
during
the
month,
kg.
ACSR
=
total
mass
of
organic
HAP
in
the
coatings
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
kg,
calculated
using
Equation
4A
of
this
section.
BCSR
=
total
mass
of
organic
HAP
in
the
thinners
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
kg,
calculated
using
Equation
4B
of
this
section.
RV
=
volatile
organic
matter
collection
and
recovery
efficiency
of
the
solvent
recovery
system,
percent,
from
Equation
3
of
this
section.
(
i)
Calculate
the
mass
of
organic
HAP
in
the
coatings
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
kg,
using
Equation
4A
of
this
section.
A
Vol
D
W
Eq
CSR
c
i
c
i
i
m
c
i
=
(
)(
)(
)
=
,
,
,
(
.
1
4A)
Where:
ACSR
=
total
mass
of
organic
HAP
in
the
coatings
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
kg.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
month
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
liters.
Dc,
i
=
density
of
coating,
i,
kg
per
liter.
Wc,
i
=
mass
fraction
of
organic
HAP
in
coating,
i,
kg
per
kg.
m
=
number
of
different
coatings
used.
(
2)
Calculate
the
mass
of
organic
HAP
in
the
thinners
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
kg,
using
Equation
4B
of
this
section.
B
Vol
D
W
Eq
CSR
t
j
t
j
j
n
t
j
=
(
)(
)(
)
=
,
,
,
(
.
1
4B)
Where:
BCSR
=
total
mass
of
organic
HAP
in
the
thinners
used
in
the
coating
operation
controlled
by
the
solvent
recovery
system
during
the
month,
kg.
Volt,
j
=
total
volume
of
thinner,
j,
used
during
the
month
in
the
coating
operation
controlled
by
the
solvent
recovery
system,
liters.
Dt,
j
=
density
of
thinner,
j,
kg
per
liter.
Wt,
j
=
mass
fraction
of
organic
HAP
in
thinner,
j,
kg
per
kg.
n
=
number
of
different
thinners
used.
(
l)
Calculate
the
total
volume
of
coating
solids
deposited.
Determine
the
total
volume
of
coating
solids
deposited,
liters,
in
the
combined
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations
using
Equation
5
of
this
section:
V
Vol
V
TE
Eq
sdep
c
i
s
i
c
i
i
m
=
(
)(
)(
)
=
,
,
,
(
.
5)
1
Where:
Vsdep
=
total
volume
of
coating
solids
deposited
during
the
month,
liters.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
month,
liters.
Vs,
i
=
volume
fraction
of
coating
solids
for
coating,
i,
liter
solids
per
liter
coating,
determined
according
to
§
63.3161(
f).
TEc,
i
=
transfer
efficiency
of
coating,
i,
determined
according
to
§
63.3161(
g).
m
=
number
of
coatings
used
during
the
month.
(
m)
Calculate
the
mass
of
organic
HAP
emissions
for
each
month.
Determine
the
mass
of
organic
HAP
emissions,
kg,
during
each
month,
using
Equation
6
of
this
section.
H
H
H
H
Eq
HAP
BC
C
i
CSR
j
j
r
i
q
=
(
)
(
)
=
=
,
,
(
.
1
1
6)
Where:
HHAP
=
total
mass
of
organic
HAP
emissions
for
the
month,
kg.
HBC
=
total
mass
of
organic
HAP
emissions
before
add
on
controls
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78649
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
from
all
the
coatings
and
thinners
used
during
the
month,
kg,
determined
according
to
paragraph
(
h)
of
this
section.
HC,
i
=
total
mass
of
organic
HAP
emission
reduction
for
controlled
coating
operation,
i,
not
using
a
liquid
liquid
material
balance,
during
the
month,
kg,
from
Equation
2
of
this
section.
HCSR,
j
=
total
mass
of
organic
HAP
emission
reduction
for
coating
operation,
j,
controlled
by
a
solvent
recovery
system
using
a
liquidliquid
material
balance,
during
the
month,
kg,
from
Equation
4
of
this
section.
q
=
number
of
controlled
coating
operations
not
using
a
liquid
liquid
material
balance.
r
=
number
of
coating
operations
controlled
by
a
solvent
recovery
system
using
a
liquid
liquid
material
balance.
(
n)
Calculate
the
organic
HAP
emission
rate
for
the
month.
Determine
the
organic
HAP
emission
rate
for
the
month
compliance
period,
kg
organic
HAP
per
liter
coating
solids
deposited,
using
Equation
7
of
this
section:
H
H
V
Eq
rate
HAP
sdep
=(
)(
)
(
.
7)
Where:
Hrate
=
organic
HAP
emission
rate
for
the
month
compliance
period,
kg
organic
HAP
per
liter
coating
solids
deposited.
HHAP
=
mass
of
organic
HAP
emissions
for
the
month,
kg,
determined
according
to
Equation
6
of
this
section.
Vsdep
=
total
volume
of
coating
solids
deposited
during
the
month,
liters,
from
Equation
5
of
this
section.
(
o)
Compliance
demonstration.
To
demonstrate
initial
compliance,
the
organic
HAP
emissions
from
the
combined
electrodeposition
primer,
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations
must
meet
the
applicable
emission
limitation
in
§
63.3090(
a)
or
§
63.3091(
a).
You
must
keep
all
records
as
required
by
§
§
63.3130
and
63.3131.
As
part
of
the
Notification
of
Compliance
Status
required
by
§
63.3110,
you
must
submit
a
statement
that
the
coating
operation(
s)
was
(
were)
in
compliance
with
the
emission
limitations
during
the
initial
compliance
period
because
the
organic
HAP
emission
rate
was
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.3090(
a)
or
§
63.3091(
a)
and
you
achieved
the
operating
limits
required
by
§
63.3093
and
the
work
practice
standards
required
by
§
63.3094.
§
63.3162
[
Reserved]
§
63.3163
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
(
a)
To
demonstrate
continuous
compliance
with
the
applicable
emission
limit
in
§
63.3090(
a)
or
§
63.3091(
a),
the
organic
HAP
emission
rate
for
each
compliance
period,
determined
according
to
the
procedures
in
§
63.3161,
must
be
equal
to
or
less
than
the
applicable
emission
limit
in
§
63.3090(
a)
or
§
63.3091(
a).
A
compliance
period
consists
of
1
month.
Each
month
after
the
end
of
the
initial
compliance
period
described
in
§
63.3160
is
a
compliance
period
consisting
of
that
month.
You
must
perform
the
calculations
in
§
63.3161
on
a
monthly
basis.
(
b)
If
the
organic
HAP
emission
rate
for
any
1
month
compliance
period
exceeded
the
applicable
emission
limit
in
§
63.3090(
a)
or
§
63.3091(
a),
this
is
a
deviation
from
the
emission
limitation
for
that
compliance
period
and
must
be
reported
as
specified
in
§
§
63.3110(
c)(
6)
and
63.3120(
a)(
6).
(
c)
You
must
demonstrate
continuous
compliance
with
each
operating
limit
required
by
§
63.3093
that
applies
to
you,
as
specified
in
Table
1
to
this
subpart.
(
1)
If
an
operating
parameter
is
out
of
the
allowed
range
specified
in
Table
1
to
this
subpart,
this
is
a
deviation
from
the
operating
limit
that
must
be
reported
as
specified
in
§
§
63.3110(
c)(
6)
and
63.3120(
a)(
6).
(
2)
If
an
operating
parameter
deviates
from
the
operating
limit
specified
in
Table
1
to
this
subpart,
then
you
must
assume
that
the
emission
capture
system
and
add
on
control
device
were
achieving
zero
efficiency
during
the
time
period
of
the
deviation.
(
d)
You
must
meet
the
requirements
for
bypass
lines
in
§
63.3168(
b)
for
control
devices
other
than
solvent
recovery
systems
for
which
you
conduct
liquid
liquid
material
balances.
If
any
bypass
line
is
opened
and
emissions
are
diverted
to
the
atmosphere
when
the
coating
operation
is
running,
this
is
a
deviation
that
must
be
reported
as
specified
in
§
63.3110(
c)(
6)
and
63.3120(
a)(
6).
For
the
purposes
of
completing
the
compliance
calculations
specified
in
§
63.3161(
k),
you
must
assume
that
the
emission
capture
system
and
add
on
control
device
were
achieving
zero
efficiency
during
the
time
period
of
the
deviation.
(
e)
You
must
demonstrate
continuous
compliance
with
the
work
practice
standards
in
§
63.3094.
If
you
did
not
develop
a
work
practice
plan,
if
you
did
not
implement
the
plan,
or
if
you
did
not
keep
the
records
required
by
§
63.3130(
n),
this
is
a
deviation
from
the
work
practice
standards
that
must
be
reported
as
specified
in
§
§
63.3110(
c)(
6)
and
63.3120(
a)(
6).
(
f)
If
there
were
no
deviations
from
the
emission
limitations,
submit
a
statement
as
part
of
the
semiannual
compliance
report
that
you
were
in
compliance
with
the
emission
rate
limitations
during
the
reporting
period
because
the
organic
HAP
emission
rate
for
each
compliance
period
was
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.3090(
a)
or
§
63.3091(
a),
and
you
achieved
the
operating
limits
required
by
§
63.3093
and
the
work
practice
standards
required
by
§
63.3094
during
each
compliance
period.
(
g)
During
periods
of
startup,
shutdown,
or
malfunction
of
the
emission
capture
system,
add
on
control
device,
or
coating
operation
that
may
affect
emission
capture
or
control
device
efficiency,
you
must
operate
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan
required
by
§
63.3100(
f).
(
h)
Consistent
with
§
§
63.6(
e)
and
63.7(
e)(
1),
deviations
that
occur
during
a
period
of
startup,
shutdown,
or
malfunction
of
the
emission
capture
system,
add
on
control
device,
or
coating
operation
that
may
affect
emission
capture
or
control
device
efficiency
are
not
violations
if
you
demonstrate
to
the
Administrator's
satisfaction
that
you
were
operating
in
accordance
with
the
startup,
shutdown,
and
malfunction
plan.
The
Administrator
will
determine
whether
deviations
that
occur
during
a
period
you
identify
as
a
startup,
shutdown,
or
malfunction
are
violations
according
to
the
provisions
in
§
63.6(
e).
(
i)
[
Reserved]
(
j)
You
must
maintain
records
as
specified
in
§
§
63.3130
and
63.3131.
§
63.3164
What
are
the
general
requirements
for
performance
tests?
(
a)
You
must
conduct
each
performance
test
required
by
§
63.3160
according
to
the
requirements
in
§
63.7(
e)(
1)
and
under
the
conditions
in
this
section
unless
you
obtain
a
waiver
of
the
performance
test
according
to
the
provisions
in
§
63.7(
h).
(
1)
Representative
coating
operation
operating
conditions.
You
must
conduct
the
performance
test
under
representative
operating
conditions
for
the
coating
operation.
Operations
during
periods
of
startup,
shutdown,
or
malfunction,
and
during
periods
of
nonoperation
do
not
constitute
representative
conditions.
You
must
record
the
process
information
that
is
necessary
to
document
operating
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/
Vol.
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No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
conditions
during
the
test
and
explain
why
the
conditions
represent
normal
operation.
(
2)
Representative
emission
capture
system
and
add
on
control
device
operating
conditions.
You
must
conduct
the
performance
test
when
the
emission
capture
system
and
add
on
control
device
are
operating
at
a
representative
flow
rate,
and
the
add
on
control
device
is
operating
at
a
representative
inlet
concentration.
You
must
record
information
that
is
necessary
to
document
emission
capture
system
and
add
on
control
device
operating
conditions
during
the
test
and
explain
why
the
conditions
represent
normal
operation.
(
b)
You
must
conduct
each
performance
test
of
an
emission
capture
system
according
to
the
requirements
in
§
63.3165.
You
must
conduct
each
performance
test
of
an
add
on
control
device
according
to
the
requirements
in
§
63.3166.
§
63.3165
How
do
I
determine
the
emission
capture
system
efficiency?
You
must
use
the
procedures
and
test
methods
in
this
section
to
determine
capture
efficiency
as
part
of
the
performance
test
required
by
§
63.3160.
(
a)
Assuming
100
percent
capture
efficiency.
You
may
assume
the
capture
system
efficiency
is
100
percent
if
both
of
the
conditions
in
paragraphs
(
a)(
1)
and
(
2)
of
this
section
are
met:
(
1)
The
capture
system
meets
the
criteria
in
Method
204
of
appendix
M
to
40
CFR
part
51
for
a
PTE
and
directs
all
the
exhaust
gases
from
the
enclosure
to
an
add
on
control
device.
(
2)
All
coatings
and
thinners
used
in
the
coating
operation
are
applied
within
the
capture
system,
and
coating
solvent
flash
off
and
coating
curing
and
drying
occurs
within
the
capture
system.
For
example,
this
criterion
is
not
met
if
parts
enter
the
open
shop
environment
when
being
moved
between
a
spray
booth
and
a
curing
oven.
(
b)
Measuring
capture
efficiency.
If
the
capture
system
does
not
meet
both
of
the
criteria
in
paragraphs
(
a)(
1)
and
(
2)
of
this
section,
then
you
must
use
one
of
the
four
procedures
described
in
paragraphs
(
c)
through
(
f)
of
this
section
to
measure
capture
efficiency.
The
capture
efficiency
measurements
use
TVH
capture
efficiency
as
a
surrogate
for
organic
HAP
capture
efficiency.
For
the
protocols
in
paragraphs
(
c)
and
(
d)
of
this
section,
the
capture
efficiency
measurement
must
consist
of
three
test
runs.
Each
test
run
must
be
at
least
3
hours
duration
or
the
length
of
a
production
run,
whichever
is
longer,
up
to
8
hours.
For
the
purposes
of
this
test,
a
production
run
means
the
time
required
for
a
single
part
to
go
from
the
beginning
to
the
end
of
production,
which
includes
surface
preparation
activities
and
drying
or
curing
time.
(
c)
Liquid
to
uncaptured
gas
protocol
using
a
temporary
total
enclosure
or
building
enclosure.
The
liquid
touncaptured
gas
protocol
compares
the
mass
of
liquid
TVH
in
materials
used
in
the
coating
operation
to
the
mass
of
TVH
emissions
not
captured
by
the
emission
capture
system.
Use
a
temporary
total
enclosure
or
a
building
enclosure
and
the
procedures
in
paragraphs
(
c)(
1)
through
(
6)
of
this
section
to
measure
emission
capture
system
efficiency
using
the
liquid
touncaptured
gas
protocol.
(
1)
Either
use
a
building
enclosure
or
construct
an
enclosure
around
the
coating
operation
where
coatings,
thinners,
and
cleaning
materials
are
applied,
and
all
areas
where
emissions
from
these
applied
coatings
and
materials
subsequently
occur,
such
as
flash
off,
curing,
and
drying
areas.
The
areas
of
the
coating
operation
where
capture
devices
collect
emissions
for
routing
to
an
add
on
control
device,
such
as
the
entrance
and
exit
areas
of
an
oven
or
spray
booth,
must
also
be
inside
the
enclosure.
The
enclosure
must
meet
the
applicable
definition
of
a
temporary
total
enclosure
or
building
enclosure
in
Method
204
of
appendix
M
to
40
CFR
part
51.
(
2)
Use
Method
204A
or
F
of
appendix
M
to
40
CFR
part
51
to
determine
the
mass
fraction
of
TVH
liquid
input
from
each
coating,
thinner,
and
cleaning
material
used
in
the
coating
operation
during
each
capture
efficiency
test
run.
To
make
the
determination,
substitute
TVH
for
each
occurrence
of
the
term
volatile
organic
compounds
(
VOC)
in
the
methods.
(
3)
Use
Equation
1
of
this
section
to
calculate
the
total
mass
of
TVH
liquid
input
from
all
the
coatings
and
thinners
used
in
the
coating
operation
during
each
capture
efficiency
test
run.
TVH
TVH
Vol
D
Eq
used
i
i
i
i
n
=
(
)(
)(
)
=
1
(
.
1)
Where:
TVHi
=
mass
fraction
of
TVH
in
coating
or
thinner,
i,
used
in
the
coating
operation
during
the
capture
efficiency
test
run,
kg
TVH
per
kg
material.
Voli
=
total
volume
of
coating
or
thinner,
i,
used
in
the
coating
operation
during
the
capture
efficiency
test
run,
liters.
Di
=
density
of
coating
or
thinner,
i,
kg
material
per
liter
material.
n
=
number
of
different
coatings
and
thinners
used
in
the
coating
operation
during
the
capture
efficiency
test
run.
(
4)
Use
Method
204D
or
E
of
appendix
M
to
40
CFR
part
51
to
measure
the
total
mass,
kg,
of
TVH
emissions
that
are
not
captured
by
the
emission
capture
system;
they
are
measured
as
they
exit
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run.
To
make
the
measurement,
substitute
TVH
for
each
occurrence
of
the
term
VOC
in
the
methods.
(
i)
Use
Method
204D
if
the
enclosure
is
a
temporary
total
enclosure.
(
ii)
Use
Method
204E
if
the
enclosure
is
a
building
enclosure.
During
the
capture
efficiency
measurement,
all
organic
compound
emitting
operations
inside
the
building
enclosure,
other
than
the
coating
operation
for
which
capture
efficiency
is
being
determined,
must
be
shut
down,
but
all
fans
and
blowers
must
be
operating
normally.
(
5)
For
each
capture
efficiency
test
run,
determine
the
percent
capture
efficiency
of
the
emission
capture
system
using
Equation
2
of
this
section:
CE
TVH
TVH
TVH
Eq
used
uncaptured
used
=
(
)
×
100
(
.
2)
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/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
Where:
CE
=
capture
efficiency
of
the
emission
capture
system
vented
to
the
add
on
control
device,
percent.
TVHused
=
total
mass
of
TVH
liquid
input
used
in
the
coating
operation
during
the
capture
efficiency
test
run,
kg.
TVHuncaptured
=
total
mass
of
TVH
that
is
not
captured
by
the
emission
capture
system
and
that
exits
from
the
temporary
total
enclosure
or
building
enclosure
during
the
capture
efficiency
test
run,
kg.
(
6)
Determine
the
capture
efficiency
of
the
emission
capture
system
as
the
average
of
the
capture
efficiencies
measured
in
the
three
test
runs.
(
d)
Gas
to
gas
protocol
using
a
temporary
total
enclosure
or
a
building
enclosure.
The
gas
to
gas
protocol
compares
the
mass
of
TVH
emissions
captured
by
the
emission
capture
system
to
the
mass
of
TVH
emissions
not
captured.
Use
a
temporary
total
enclosure
or
a
building
enclosure
and
the
procedures
in
paragraphs
(
d)(
1)
through
(
5)
of
this
section
to
measure
emission
capture
system
efficiency
using
the
gas
to
gas
protocol.
(
1)
Either
use
a
building
enclosure
or
construct
an
enclosure
around
the
coating
operation
where
coatings,
thinners,
and
cleaning
materials
are
applied,
and
all
areas
where
emissions
from
these
applied
coatings
and
materials
subsequently
occur,
such
as
flash
off,
curing,
and
drying
areas.
The
areas
of
the
coating
operation
where
capture
devices
collect
emissions
generated
by
the
coating
operation
for
routing
to
an
add
on
control
device,
such
as
the
entrance
and
exit
areas
of
an
oven
or
a
spray
booth,
must
also
be
inside
the
enclosure.
The
enclosure
must
meet
the
applicable
definition
of
a
temporary
total
enclosure
or
building
enclosure
in
Method
204
of
appendix
M
to
40
CFR
part
51.
(
2)
Use
Method
204B
or
C
of
appendix
M
to
40
CFR
part
51
to
measure
the
total
mass,
kg,
of
TVH
emissions
captured
by
the
emission
capture
system
during
each
capture
efficiency
test
run
as
measured
at
the
inlet
to
the
add
on
control
device.
To
make
the
measurement,
substitute
TVH
for
each
occurrence
of
the
term
VOC
in
the
methods.
(
i)
The
sampling
points
for
the
Method
204B
or
C
measurement
must
be
upstream
from
the
add
on
control
device
and
must
represent
total
emissions
routed
from
the
capture
system
and
entering
the
add
on
control
device.
(
ii)
If
multiple
emission
streams
from
the
capture
system
enter
the
add
on
control
device
without
a
single
common
duct,
then
the
emissions
entering
the
add
on
control
device
must
be
simultaneously
measured
in
each
duct,
and
the
total
emissions
entering
the
add
on
control
device
must
be
determined.
(
3)
Use
Method
204D
or
E
of
appendix
M
to
40
CFR
part
51
to
measure
the
total
mass,
kg,
of
TVH
emissions
that
are
not
captured
by
the
emission
capture
system;
they
are
measured
as
they
exit
the
temporary
total
enclosure
or
building
enclosure
during
each
capture
efficiency
test
run.
To
make
the
measurement,
substitute
TVH
for
each
occurrence
of
the
term
VOC
in
the
methods.
(
i)
Use
Method
204D
if
the
enclosure
is
a
temporary
total
enclosure.
(
ii)
Use
Method
204E
if
the
enclosure
is
a
building
enclosure.
During
the
capture
efficiency
measurement,
all
organic
compound
emitting
operations
inside
the
building
enclosure,
other
than
the
coating
operation
for
which
capture
efficiency
is
being
determined,
must
be
shut
down,
but
all
fans
and
blowers
must
be
operating
normally.
(
4)
For
each
capture
efficiency
test
run,
determine
the
percent
capture
efficiency
of
the
emission
capture
system
using
Equation
3
of
this
section:
CE
TVH
TVH
TVH
Eq
captured
captured
uncaptured
=
+
(
)
×
100
(
.
3)
Where:
CE
=
capture
efficiency
of
the
emission
capture
system
vented
to
the
add
on
control
device,
percent.
TVHcaptured
=
total
mass
of
TVH
captured
by
the
emission
capture
system
as
measured
at
the
inlet
to
the
add
on
control
device
during
the
emission
capture
efficiency
test
run,
kg.
TVHuncaptured
=
total
mass
of
TVH
that
is
not
captured
by
the
emission
capture
system
and
that
exits
from
the
temporary
total
enclosure
or
building
enclosure
during
the
capture
efficiency
test
run,
kg.
(
5)
Determine
the
capture
efficiency
of
the
emission
capture
system
as
the
average
of
the
capture
efficiencies
measured
in
the
three
test
runs.
(
e)
Panel
testing
to
determine
the
capture
efficiency
of
flash
off
or
bake
oven
emissions.
You
may
determine
the
capture
efficiency
of
flash
off
or
bake
oven
emissions
using
ASTM
Method
D5087
91(
1994),
ASTM
Method
D6266
00a,
or
the
guidelines
presented
in
``
Protocol
for
Determining
Daily
Volatile
Organic
Compound
Emission
Rate
of
Automobile
and
Light
Duty
Truck
Topcoat
Operations,''
EPA
450/
3
88
018
(
docket
A
2001
22).
The
results
of
these
panel
testing
procedures
are
in
units
of
mass
of
VOC
per
volume
of
coating
solids
deposited.
These
results
must
be
converted
to
percent
capture
efficiency
values
using
Equation
4
of
this
section:
CE
P
V
VOC
Eq
i
i
sdep
i
i
=(
)(
)(
)
,
(
.
4)
Where:
CEi
=
capture
efficiency
for
coating
i
for
the
flash
off
area
or
bake
oven
for
which
the
panel
test
is
conducted,
percent.
Pi
=
panel
test
result
for
coating
i,
kg
of
VOC
per
liter
of
coating
solids
deposited.
Vsdep,
i
=
total
volume
of
coating
solids
deposited
for
coating
i
during
the
month
in
the
spray
booth(
s)
for
the
flash
off
area
or
bake
oven
for
which
the
panel
test
is
conducted,
liters,
from
Equation
5
of
this
section.
VOCi
=
total
mass
of
VOC
in
coating
i
used
during
the
month
in
the
spray
booth(
s)
for
the
flash
off
area
or
bake
oven
for
which
the
panel
test
is
conducted,
kg,
from
Equation
6
of
this
section.
(
1)
Calculate
the
total
volume
of
coating
solids
deposited
for
each
coating
used
during
the
month
in
the
spray
booth(
s)
for
the
flash
off
area
or
bake
oven
for
which
the
panel
test
is
conducted
using
equation
5
of
this
section:
V
Vol
V
TE
Eq
sdep
i
c
i
s
i
c
i
,
,
,
,
(
.
=(
)(
)(
)
5)
Where:
Vsdep,
i
=
total
volume
of
coating
solids
deposited
for
coating
i
during
the
month
in
the
spray
booth(
s)
for
the
flash
off
area
or
bake
oven
for
which
the
panel
test
is
conducted,
liters.
Volc,
i
=
total
volume
of
coating,
i,
used
during
the
month
in
the
spray
booth(
s)
for
the
flash
off
area
or
bake
oven
for
which
the
panel
test
is
conducted,
liters.
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Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
Vs,
i
=
volume
fraction
of
coating
solids
for
coating,
i,
liter
solids
per
liter
coating,
determined
according
to
§
63.3161(
f).
TEc,
i
=
transfer
efficiency
of
coating,
i,
in
the
spray
booth(
s)
for
the
flashoff
area
or
bake
oven
for
which
the
panel
test
is
conducted
determined
according
to
§
63.3161(
g).
(
2)
Calculate
the
total
mass
of
VOC
in
each
coating
used
during
the
month
in
the
spray
booth(
s)
for
the
flash
off
area
or
bake
oven
for
which
the
panel
test
is
conducted,
kg,
using
Equation
6
of
this
section:
VOC
Vol
D
Wvoc
Eq
i
ci
ci
ci
=(
)(
)(
)
,
,
,
(
.
6)
Where:
VOCi
=
total
mass
of
VOC
in
coating
i
used
during
the
month
in
the
spray
booth(
s)
for
the
flash
off
area
or
bake
oven
for
which
the
panel
test
is
conducted,
kg.
Volc,
i
=
total
volume
of
coating
i
used
during
the
month
in
the
spray
booth(
s)
for
the
flash
off
area
or
bake
oven
for
which
the
panel
test
is
conducted,
liters.
DC
=
density
of
coating
i,
kg
coating
per
liter
coating,
determined
according
to
§
63.3151(
b).
Wvocc,
i
=
mass
fraction
of
VOC
in
coating
i,
kg
organic
HAP
per
kg
coating,
determined
by
Method
24
(
appendix
A
to
40
CFR
part
60)
or
the
guidelines
presented
in
``
Protocol
for
Determining
Daily
Volatile
Organic
Compound
Emission
Rate
of
Automobile
and
Light
Duty
Truck
Topcoat
Operations,''
EPA
450/
3
88
018
(
docket
A
2001
22).
(
f)
Alternative
capture
efficiency
procedure.
As
an
alternative
to
the
procedures
specified
in
paragraphs
(
c)
through
(
e)
of
this
section,
you
may
determine
capture
efficiency
using
any
other
capture
efficiency
protocol
and
test
methods
that
satisfy
the
criteria
of
either
the
DQO
or
LCL
approach
as
described
in
appendix
A
to
subpart
KK
of
this
part.
§
63.3166
How
do
I
determine
the
add
on
control
device
emission
destruction
or
removal
efficiency?
You
must
use
the
procedures
and
test
methods
in
this
section
to
determine
the
add
on
control
device
emission
destruction
or
removal
efficiency
as
part
of
the
performance
test
required
by
§
63.3160.
You
must
conduct
three
test
runs
as
specified
in
§
63.7(
e)(
3),
and
each
test
run
must
last
at
least
1
hour.
(
a)
For
all
types
of
add
on
control
devices,
use
the
test
methods
specified
in
paragraphs
(
a)(
1)
through
(
5)
of
this
section.
(
1)
Use
Method
1
or
1A
of
appendix
A
to
40
CFR
part
60,
as
appropriate,
to
select
sampling
sites
and
velocity
traverse
points.
(
2)
Use
Method
2,
2A,
2C,
2D,
2F,
or
2G
of
appendix
A
to
40
CFR
part
60,
as
appropriate,
to
measure
gas
volumetric
flow
rate.
(
3)
Use
Method
3,
3A,
or
3B
of
appendix
A
to
40
CFR
part
60,
as
appropriate,
for
gas
analysis
to
determine
dry
molecular
weight.
The
ASME
PTC
19.10
1981
may
be
used
as
an
alternative
to
Method
3B.
(
4)
Use
Method
4
of
appendix
A
to
40
CFR
part
60
to
determine
stack
gas
moisture.
(
5)
Methods
for
determining
gas
volumetric
flow
rate,
dry
molecular
weight,
and
stack
gas
moisture
must
be
performed,
as
applicable,
during
each
test
run.
(
b)
Measure
total
gaseous
organic
mass
emissions
as
carbon
at
the
inlet
and
outlet
of
the
add
on
control
device
simultaneously,
using
either
Method
25
or
25A
of
appendix
A
to
40
CFR
part
60,
as
specified
in
paragraphs
(
b)(
1)
through
(
3)
of
this
section.
You
must
use
the
same
method
for
both
the
inlet
and
outlet
measurements.
(
1)
Use
Method
25
if
the
add
on
control
device
is
an
oxidizer
and
you
expect
the
total
gaseous
organic
concentration
as
carbon
to
be
more
than
50
parts
per
million
by
volume
(
ppmv)
at
the
control
device
outlet.
(
2)
Use
Method
25A
if
the
add
on
control
device
is
an
oxidizer
and
you
expect
the
total
gaseous
organic
concentration
as
carbon
to
be
50
ppmv
or
less
at
the
control
device
outlet.
(
3)
Use
Method
25A
if
the
add
control
device
is
not
an
oxidizer.
(
c)
If
two
or
more
add
on
control
devices
are
used
for
the
same
emission
stream,
then
you
must
measure
emissions
at
the
outlet
of
each
device.
For
example,
if
one
add
on
control
device
is
a
concentrator
with
an
outlet
for
the
high
volume,
dilute
stream
that
has
been
treated
by
the
concentrator,
and
a
second
add
on
control
device
is
an
oxidizer
with
an
outlet
for
the
lowvolume
concentrated
stream
that
is
treated
with
the
oxidizer,
you
must
measure
emissions
at
the
outlet
of
the
oxidizer
and
the
high
volume
dilute
stream
outlet
of
the
concentrator.
(
d)
For
each
test
run,
determine
the
total
gaseous
organic
emissions
mass
flow
rates
for
the
inlet
and
the
outlet
of
the
add
on
control
device,
using
Equation
1
of
this
section.
If
there
is
more
than
one
inlet
or
outlet
to
the
addon
control
device,
you
must
calculate
the
total
gaseous
organic
mass
flow
rate
using
Equation
1
of
this
section
for
each
inlet
and
each
outlet
and
then
total
all
of
the
inlet
emissions
and
total
all
of
the
outlet
emissions.
M
Q
C
Eq
f
sd
c
=
(
)(
)(
)
12
0
0416
10
6
.
(.
1)
Where:
Mf
=
total
gaseous
organic
emissions
mass
flow
rate,
kg/
per
hour
(
h).
Cc
=
concentration
of
organic
compounds
as
carbon
in
the
vent
gas,
as
determined
by
Method
25
or
Method
25A,
ppmv,
dry
basis.
Qsd
=
volumetric
flow
rate
of
gases
entering
or
exiting
the
add
on
control
device,
as
determined
by
Method
2,
2A,
2C,
2D,
2F,
or
2G,
dry
standard
cubic
meters/
hour
(
dscm/
h).
0.0416
=
conversion
factor
for
molar
volume,
kg
moles
per
cubic
meter
(
mol/
m3)
(@
293
Kelvin
(
K)
and
760
millimeters
of
mercury
(
mmHg)).
(
e)
For
each
test
run,
determine
the
add
on
control
device
organic
emissions
destruction
or
removal
efficiency
using
Equation
2
of
this
section:
DRE
M
M
M
Eq
fi
fo
fi
=
(
)
100
(
.
2)
Where:
DRE
=
organic
emissions
destruction
or
removal
efficiency
of
the
add
on
control
device,
percent.
Mfi
=
total
gaseous
organic
emissions
mass
flow
rate
at
the
inlet(
s)
to
the
add
on
control
device,
using
Equation
1
of
this
section,
kg/
h.
Mfo
=
total
gaseous
organic
emissions
mass
flow
rate
at
the
outlet(
s)
of
the
add
on
control
device,
using
Equation
1
of
this
section,
kg/
h.
(
f)
Determine
the
emission
destruction
or
removal
efficiency
of
the
add
on
control
device
as
the
average
of
the
efficiencies
determined
in
the
three
test
runs
and
calculated
in
Equation
2
of
this
section.
§
63.3167
How
do
I
establish
the
add
on
control
device
operating
limits
during
the
performance
test?
During
the
performance
test
required
by
§
63.3160
and
described
in
§
§
63.3164
and
63.3166,
you
must
establish
the
operating
limits
required
by
§
63.3193
according
to
this
section,
unless
you
have
received
approval
for
alternative
monitoring
and
operating
limits
under
§
63.8(
f)
as
specified
in
§
63.3193.
(
a)
Thermal
oxidizers.
If
your
add
on
control
device
is
a
thermal
oxidizer,
establish
the
operating
limits
according
to
paragraphs
(
a)(
1)
and
(
2)
of
this
section.
(
1)
During
the
performance
test,
you
must
monitor
and
record
the
combustion
temperature
at
least
once
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78653
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
every
15
minutes
during
each
of
the
three
test
runs.
You
must
monitor
the
temperature
in
the
firebox
of
the
thermal
oxidizer
or
immediately
downstream
of
the
firebox
before
any
substantial
heat
exchange
occurs.
(
2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
combustion
temperature
maintained
during
the
performance
test.
This
average
combustion
temperature
is
the
minimum
operating
limit
for
your
thermal
oxidizer.
(
b)
Catalytic
oxidizers.
If
your
add
on
control
device
is
a
catalytic
oxidizer,
establish
the
operating
limits
according
to
either
paragraphs
(
b)(
1)
and
(
2)
or
paragraphs
(
b)(
3)
and
(
4)
of
this
section.
(
1)
During
the
performance
test,
you
must
monitor
and
record
the
temperature
just
before
the
catalyst
bed
and
the
temperature
difference
across
the
catalyst
bed
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
(
2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
temperature
just
before
the
catalyst
bed
and
the
average
temperature
difference
across
the
catalyst
bed
maintained
during
the
performance
test.
These
are
the
minimum
operating
limits
for
your
catalytic
oxidizer.
(
3)
As
an
alternative
to
monitoring
the
temperature
difference
across
the
catalyst
bed,
you
may
monitor
the
temperature
at
the
inlet
to
the
catalyst
bed
and
implement
a
site
specific
inspection
and
maintenance
plan
for
your
catalytic
oxidizer
as
specified
in
paragraph
(
b)(
4)
of
this
section.
During
the
performance
test,
you
must
monitor
and
record
the
temperature
just
before
the
catalyst
bed
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
temperature
just
before
the
catalyst
bed
during
the
performance
test.
This
is
the
minimum
operating
limit
for
your
catalytic
oxidizer.
(
4)
You
must
develop
and
implement
an
inspection
and
maintenance
plan
for
your
catalytic
oxidizer(
s)
for
which
you
elect
to
monitor
according
to
paragraph
(
b)(
3)
of
this
section.
The
plan
must
address,
at
a
minimum,
the
elements
specified
in
paragraphs
(
b)(
4)(
i)
through
(
iii)
of
this
section.
(
i)
Annual
sampling
and
analysis
of
the
catalyst
activity
(
i.
e.,
conversion
efficiency)
following
the
oxidizer
manufacturer's
or
catalyst
supplier's
recommended
procedures.
(
ii)
Monthly
inspection
of
the
oxidizer
system,
including
the
burner
assembly
and
fuel
supply
lines
for
problems
and,
as
necessary,
adjustment
of
the
equipment
to
assure
proper
air
to
fuel
mixtures.
(
iii)
Annual
internal
and
monthly
external
visual
inspection
of
the
catalyst
bed
to
check
for
channeling,
abrasion,
and
settling.
If
problems
are
found,
you
must
replace
the
catalyst
bed
and
conduct
a
new
performance
test
to
determine
destruction
efficiency
according
to
§
63.3166.
(
c)
Carbon
adsorbers.
If
your
add
on
control
device
is
a
carbon
adsorber,
establish
the
operating
limits
according
to
paragraphs
(
c)(
1)
and
(
2)
of
this
section.
(
1)
You
must
monitor
and
record
the
total
regeneration
desorbing
gas
(
e.
g.,
steam
or
nitrogen)
mass
flow
for
each
regeneration
cycle
and
the
carbon
bed
temperature
after
each
carbon
bed
regeneration
and
cooling
cycle
for
the
regeneration
cycle
either
immediately
preceding
or
immediately
following
the
performance
test.
(
2)
The
operating
limits
for
your
carbon
adsorber
are
the
minimum
total
desorbing
gas
mass
flow
recorded
during
the
regeneration
cycle
and
the
maximum
carbon
bed
temperature
recorded
after
the
cooling
cycle.
(
d)
Condensers.
If
your
add
on
control
device
is
a
condenser,
establish
the
operating
limits
according
to
paragraphs
(
d)(
1)
and
(
2)
of
this
section.
(
1)
During
the
performance
test,
you
must
monitor
and
record
the
condenser
outlet
(
product
side)
gas
temperature
at
least
once
every
15
minutes
during
each
of
the
three
test
runs.
(
2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
condenser
outlet
(
product
side)
gas
temperature
maintained
during
the
performance
test.
This
average
condenser
outlet
gas
temperature
is
the
maximum
operating
limit
for
your
condenser.
(
e)
Concentrators.
If
your
add
on
control
device
includes
a
concentrator,
you
must
establish
operating
limits
for
the
concentrator
according
to
paragraphs
(
e)(
1)
through
(
4)
of
this
section.
(
1)
During
the
performance
test,
you
must
monitor
and
record
the
desorption
concentrate
stream
gas
temperature
at
least
once
every
15
minutes
during
each
of
the
three
runs
of
the
performance
test.
(
2)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
temperature.
This
is
the
minimum
operating
limit
for
the
desorption
concentrate
gas
stream
temperature.
(
3)
During
the
performance
test,
you
must
monitor
and
record
the
pressure
drop
of
the
dilute
stream
across
the
concentrator
at
least
once
every
15
minutes
during
each
of
the
three
runs
of
the
performance
test.
(
4)
Use
the
data
collected
during
the
performance
test
to
calculate
and
record
the
average
pressure
drop.
This
is
the
maximum
operating
limit
for
the
dilute
stream
across
the
concentrator.
(
f)
Emission
capture
systems.
For
each
capture
device
that
is
not
part
of
a
PTE
that
meets
the
criteria
of
§
63.3165(
a),
establish
an
operating
limit
for
either
the
gas
volumetric
flow
rate
or
duct
static
pressure,
as
specified
in
paragraphs
(
f)(
1)
and
(
2)
of
this
section.
The
operating
limit
for
a
PTE
is
specified
in
Table
1
to
this
subpart.
(
1)
During
the
capture
efficiency
determination
required
by
§
63.3160
and
described
in
§
§
63.3164
and
63.3165,
you
must
monitor
and
record
either
the
gas
volumetric
flow
rate
or
the
duct
static
pressure
for
each
separate
capture
device
in
your
emission
capture
system
at
least
once
every
15
minutes
during
each
of
the
three
test
runs
at
a
point
in
the
duct
between
the
capture
device
and
the
add
on
control
device
inlet.
(
2)
Calculate
and
record
the
average
gas
volumetric
flow
rate
or
duct
static
pressure
for
the
three
test
runs
for
each
capture
device.
This
average
gas
volumetric
flow
rate
or
duct
static
pressure
is
the
minimum
operating
limit
for
that
specific
capture
device.
§
63.3168
What
are
the
requirements
for
continuous
parameter
monitoring
system
installation,
operation,
and
maintenance?
(
a)
General.
You
must
install,
operate,
and
maintain
each
CPMS
specified
in
paragraphs
(
c),
(
e),
(
f),
and
(
g)
of
this
section
according
to
paragraphs
(
a)(
1)
through
(
6)
of
this
section.
You
must
install,
operate,
and
maintain
each
CPMS
specified
in
paragraphs
(
b)
and
(
d)
of
this
section
according
to
paragraphs
(
a)(
3)
through
(
5)
of
this
section.
(
1)
The
CPMS
must
complete
a
minimum
of
one
cycle
of
operation
for
each
successive
15
minute
period.
You
must
have
a
minimum
of
four
equally
spaced
successive
cycles
of
CPMS
operation
in
1
hour.
(
2)
You
must
determine
the
average
of
all
recorded
readings
for
each
successive
3
hour
period
of
the
emission
capture
system
and
add
on
control
device
operation.
(
3)
You
must
record
the
results
of
each
inspection,
calibration,
and
validation
check
of
the
CPMS.
(
4)
You
must
maintain
the
CPMS
at
all
times
and
have
available
necessary
parts
for
routine
repairs
of
the
monitoring
equipment.
(
5)
You
must
operate
the
CPMS
and
collect
emission
capture
system
and
add
on
control
device
parameter
data
at
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Proposed
Rules
all
times
that
a
controlled
coating
operation
is
operating,
except
during
monitoring
malfunctions,
associated
repairs,
and
required
quality
assurance
or
control
activities
(
including,
if
applicable,
calibration
checks
and
required
zero
and
span
adjustments).
(
6)
You
must
not
use
emission
capture
system
or
add
on
control
device
parameter
data
recorded
during
monitoring
malfunctions,
associated
repairs,
out
of
control
periods,
or
required
quality
assurance
or
control
activities
when
calculating
data
averages.
You
must
use
all
the
data
collected
during
all
other
periods
in
calculating
the
data
averages
for
determining
compliance
with
the
emission
capture
system
and
add
on
control
device
operating
limits.
(
7)
A
monitoring
malfunction
is
any
sudden,
infrequent,
not
reasonably
preventable
failure
of
the
CPMS
to
provide
valid
data.
Monitoring
failures
that
are
caused
in
part
by
poor
maintenance
or
careless
operation
are
not
malfunctions.
Any
period
for
which
the
monitoring
system
is
out
of
control
and
data
are
not
available
for
required
calculations
is
a
deviation
from
the
monitoring
requirements.
(
b)
Capture
system
bypass
line.
You
must
meet
the
requirements
of
paragraphs
(
b)(
1)
and
(
2)
of
this
section
for
each
emission
capture
system
that
contains
bypass
lines
that
could
divert
emissions
away
from
the
add
on
control
device
to
the
atmosphere.
(
1)
You
must
monitor
or
secure
the
valve
or
closure
mechanism
controlling
the
bypass
line
in
a
nondiverting
position
in
such
a
way
that
the
valve
or
closure
mechanism
cannot
be
opened
without
creating
a
record
that
the
valve
was
opened.
The
method
used
to
monitor
or
secure
the
valve
or
closure
mechanism
must
meet
one
of
the
requirements
specified
in
paragraphs
(
b)(
1)(
i)
through
(
iv)
of
this
section.
(
i)
Flow
control
position
indicator.
Install,
calibrate,
maintain,
and
operate
according
to
the
manufacturer's
specifications
a
flow
control
position
indicator
that
takes
a
reading
at
least
once
every
15
minutes
and
provides
a
record
indicating
whether
the
emissions
are
directed
to
the
add
on
control
device
or
diverted
from
the
add
on
control
device.
The
time
of
occurrence
and
flow
control
position
must
be
recorded,
as
well
as
every
time
the
flow
direction
is
changed.
The
flow
control
position
indicator
must
be
installed
at
the
entrance
to
any
bypass
line
that
could
divert
the
emissions
away
from
the
addon
control
device
to
the
atmosphere.
(
ii)
Car
seal
or
lock
and
key
valve
closures.
Secure
any
bypass
line
valve
in
the
closed
position
with
a
car
seal
or
a
lock
and
key
type
configuration.
You
must
visually
inspect
the
seal
or
closure
mechanism
at
least
once
every
month
to
ensure
that
the
valve
is
maintained
in
the
closed
position,
and
the
emissions
are
not
diverted
away
from
the
add
on
control
device
to
the
atmosphere.
(
iii)
Valve
closure
monitoring.
Ensure
that
any
bypass
line
valve
is
in
the
closed
(
nondiverting)
position
through
monitoring
of
valve
position
at
least
once
every
15
minutes.
You
must
inspect
the
monitoring
system
at
least
once
every
month
to
verify
that
the
monitor
will
indicate
valve
position.
(
iv)
Automatic
shutdown
system.
Use
an
automatic
shutdown
system
in
which
the
coating
operation
is
stopped
when
flow
is
diverted
by
the
bypass
line
away
from
the
add
on
control
device
to
the
atmosphere
when
the
coating
operation
is
running.
You
must
inspect
the
automatic
shutdown
system
at
least
once
every
month
to
verify
that
it
will
detect
diversions
of
flow
and
shut
down
the
coating
operation.
(
2)
If
any
bypass
line
is
opened,
you
must
include
a
description
of
why
the
bypass
line
was
opened
and
the
length
of
time
it
remained
open
in
the
semiannual
compliance
reports
required
in
§
63.3120.
(
c)
Thermal
oxidizers
and
catalytic
oxidizers.
If
you
are
using
a
thermal
oxidizer
or
catalytic
oxidizer
as
an
addon
control
device
(
including
those
used
to
treat
desorbed
concentrate
streams
from
concentrators
or
carbon
adsorbers),
you
must
comply
with
the
requirements
in
paragraphs
(
c)(
1)
through
(
3)
of
this
section:
(
1)
For
a
thermal
oxidizer,
install
a
gas
temperature
monitor
in
the
firebox
of
the
thermal
oxidizer
or
in
the
duct
immediately
downstream
of
the
firebox
before
any
substantial
heat
exchange
occurs.
(
2)
For
a
catalytic
oxidizer,
install
gas
temperature
monitors
both
upstream
and
downstream
of
the
catalyst
bed.
The
temperature
monitors
must
be
in
the
gas
stream
immediately
before
and
after
the
catalyst
bed
to
measure
the
temperature
difference
across
the
bed.
(
3)
For
all
thermal
oxidizers
and
catalytic
oxidizers,
you
must
meet
the
requirements
in
paragraphs
(
a)(
1)
through
(
6)
and
(
c)(
3)(
i)
through
(
vii)
of
this
section
for
each
gas
temperature
monitoring
device.
(
i)
Locate
the
temperature
sensor
in
a
position
that
provides
a
representative
temperature.
(
ii)
Use
a
temperature
sensor
with
a
measurement
sensitivity
of
4
degrees
Fahrenheit
or
0.75
percent
of
the
temperature
value,
whichever
is
larger.
(
iii)
Shield
the
temperature
sensor
system
from
electromagnetic
interference
and
chemical
contaminants.
(
iv)
If
a
gas
temperature
chart
recorder
is
used,
it
must
have
a
measurement
sensitivity
in
the
minor
division
of
at
least
20
degrees
Fahrenheit.
(
v)
Perform
an
electronic
calibration
at
least
semiannually
according
to
the
procedures
in
the
manufacturer's
owners
manual.
Following
the
electronic
calibration,
you
must
conduct
a
temperature
sensor
validation
check
in
which
a
second
or
redundant
temperature
sensor
placed
nearby
the
process
temperature
sensor
must
yield
a
reading
within
30
degrees
Fahrenheit
of
the
process
temperature
sensor
reading.
(
vi)
Conduct
calibration
and
validation
checks
any
time
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
temperature
range
or
install
a
new
temperature
sensor.
(
vii)
At
least
monthly,
inspect
components
for
integrity
and
electrical
connections
for
continuity,
oxidation,
and
galvanic
corrosion.
(
d)
Carbon
adsorbers.
If
you
are
using
a
carbon
adsorber
as
an
add
on
control
device,
you
must
monitor
the
total
regeneration
desorbing
gas
(
e.
g.,
steam
or
nitrogen)
mass
flow
for
each
regeneration
cycle,
the
carbon
bed
temperature
after
each
regeneration
and
cooling
cycle,
and
comply
with
paragraphs
(
a)(
3)
through
(
5)
and
(
d)(
1)
and
(
2)
of
this
section.
(
1)
The
regeneration
desorbing
gas
mass
flow
monitor
must
be
an
integrating
device
having
a
measurement
sensitivity
of
plus
or
minus
10
percent,
capable
of
recording
the
total
regeneration
desorbing
gas
mass
flow
for
each
regeneration
cycle.
(
2)
The
carbon
bed
temperature
monitor
must
have
a
measurement
sensitivity
of
1
percent
of
the
temperature
(
as
expressed
in
degrees
Fahrenheit)
recorded
or
1
degree
Fahrenheit,
whichever
is
greater,
and
must
be
capable
of
recording
the
temperature
within
15
minutes
of
completing
any
carbon
bed
cooling
cycle.
(
e)
Condensers.
If
you
are
using
a
condenser,
you
must
monitor
the
condenser
outlet
(
product
side)
gas
temperature
and
comply
with
paragraphs
(
a)(
1)
through
(
6)
and
(
e)(
1)
and
(
2)
of
this
section.
(
1)
The
gas
temperature
monitor
must
have
a
measurement
sensitivity
of
1
percent
of
the
temperature
(
expressed
in
degrees
Fahrenheit)
recorded
or
1
degree
Fahrenheit,
whichever
is
greater.
(
2)
The
temperature
monitor
must
provide
a
gas
temperature
record
at
least
once
every
15
minutes.
(
f)
Concentrators.
If
you
are
using
a
concentrator,
such
as
a
zeolite
wheel
or
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Proposed
Rules
rotary
carbon
bed
concentrator,
you
must
comply
with
the
requirements
in
paragraphs
(
f)(
1)
and
(
2)
of
this
section.
(
1)
You
must
install
a
temperature
monitor
in
the
desorption
gas
stream.
The
temperature
monitor
must
meet
the
requirements
in
paragraphs
(
a)(
1)
through
(
6)
and
(
c)(
3)
of
this
section.
(
2)
You
must
install
a
device
to
monitor
pressure
drop
across
the
zeolite
wheel
or
rotary
carbon
bed.
The
pressure
monitoring
device
must
meet
the
requirements
in
paragraphs
(
a)(
1)
through
(
6)
and
(
f)(
2)(
i)
through
(
vii)
of
this
section.
(
i)
Locate
the
pressure
sensor(
s)
in
a
position
that
provides
a
representative
measurement
of
the
pressure.
(
ii)
Minimize
or
eliminate
pulsating
pressure,
vibration,
and
internal
and
external
corrosion.
(
iii)
Use
a
gauge
with
a
minimum
tolerance
of
0.5
inch
of
water
or
a
transducer
with
a
minimum
tolerance
of
1
percent
of
the
pressure
range.
(
iv)
Check
the
pressure
tap
daily.
(
v)
Using
a
manometer,
check
gauge
calibration
quarterly
and
transducer
calibration
monthly.
(
vi)
Conduct
calibration
checks
anytime
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
pressure
range
or
install
a
new
pressure
sensor.
(
vii)
At
least
monthly,
inspect
components
for
integrity,
electrical
connections
for
continuity,
and
mechanical
connections
for
leakage.
(
g)
Emission
capture
systems.
The
capture
system
monitoring
system
must
comply
with
the
applicable
requirements
in
paragraphs
(
g)(
1)
and
(
2)
of
this
section.
(
1)
For
each
flow
measurement
device,
you
must
meet
the
requirements
in
paragraphs
(
a)(
1)
through
(
6)
and
(
g)(
1)(
i)
through
(
iv)
of
this
section.
(
i)
Locate
a
flow
sensor
in
a
position
that
provides
a
representative
flow
measurement
in
the
duct
from
each
capture
device
in
the
emission
capture
system
to
the
add
on
control
device.
(
ii)
Reduce
swirling
flow
or
abnormal
velocity
distributions
due
to
upstream
and
downstream
disturbances.
(
iii)
Conduct
a
flow
sensor
calibration
check
at
least
semiannually.
(
iv)
At
least
monthly,
inspect
components
for
integrity,
electrical
connections
for
continuity,
and
mechanical
connections
for
leakage.
(
2)
For
each
pressure
drop
measurement
device,
you
must
comply
with
the
requirements
in
paragraphs
(
a)(
1)
through
(
6)
and
(
g)(
2)(
i)
through
(
vi)
of
this
section.
(
i)
Locate
the
pressure
tap(
s)
in
a
position
that
provides
a
representative
measurement
of
the
pressure
drop
across
each
opening
you
are
monitoring.
(
ii)
Minimize
or
eliminate
pulsating
pressure,
vibration,
and
internal
and
external
corrosion.
(
iii)
Check
pressure
tap
pluggage
daily.
(
iv)
Using
an
inclined
manometer
with
a
measurement
sensitivity
of
0.0002
inch
water,
check
gauge
calibration
quarterly
and
transducer
calibration
monthly.
(
v)
Conduct
calibration
checks
any
time
the
sensor
exceeds
the
manufacturer's
specified
maximum
operating
pressure
range
or
install
a
new
pressure
sensor.
(
vi)
At
least
monthly,
inspect
components
for
integrity,
electrical
connections
for
continuity,
and
mechanical
connections
for
leakage.
Compliance
Requirements
for
the
Combined
Primer
Surfacer,
Topcoat,
Final
Repair,
Glass
Bonding
Primer,
and
Glass
Bonding
Adhesive
Emission
Rates
and
the
Separate
Electrodeposition
Primer
Emission
Rates
§
63.3170
By
what
date
must
I
conduct
performance
tests
and
other
initial
compliance
demonstrations?
(
a)
New
and
reconstructed
affected
sources.
For
a
new
or
reconstructed
affected
source,
you
must
meet
the
requirements
of
paragraphs
(
a)(
1)
through
(
4)
of
§
63.3160.
(
b)
Existing
affected
sources.
For
an
existing
affected
source,
you
must
meet
the
requirements
of
paragraphs
(
b)(
1)
through
(
3)
of
§
63.3160.
§
63.3171
How
do
I
demonstrate
initial
compliance?
(
a)
You
must
meet
all
of
the
requirements
of
this
section
to
demonstrate
initial
compliance.
To
demonstrate
initial
compliance,
the
organic
HAP
emissions
from
the
combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations
must
meet
the
applicable
emission
limitation
in
§
63.3090(
b)
or
§
63.3091(
b);
and
the
organic
HAP
emissions
from
the
electrodeposition
primer
operation
must
meet
the
applicable
emissions
limitations
in
§
63.3092(
a)
or
(
b).
(
b)
Compliance
with
operating
limits.
Except
as
provided
in
§
63.3160(
a)(
4),
you
must
establish
and
demonstrate
continuous
compliance
during
the
initial
compliance
period
with
the
operating
limits
required
by
§
63.3093,
using
the
procedures
specified
in
§
§
63.3167
and
63.3168.
(
c)
Compliance
with
work
practice
requirements.
You
must
develop,
implement,
and
document
your
implementation
of
the
work
practice
plans
required
by
§
63.3094(
b)
and
(
c)
during
the
initial
compliance
period,
as
specified
in
§
63.3130.
(
d)
Compliance
with
emission
limits.
You
must
follow
the
procedures
in
§
63.3161(
e)
through
(
n),
excluding
materials
used
in
electrodeposition
primer
operations,
to
demonstrate
compliance
with
the
applicable
emission
limit
in
§
63.3090(
b)
or
§
63.3091(
b).
You
must
follow
the
procedures
in
paragraph
(
e)
of
this
section
to
demonstrate
compliance
with
the
emission
limit
in
§
63.3092(
a),
or
paragraphs
(
f)
through
(
g)
of
this
section
to
demonstrate
compliance
with
the
emission
limitations
in
§
63.3092(
b).
(
e)
Determine
the
mass
fraction
of
each
organic
HAP
in
each
material
used
in
the
electrodeposition
primer
operation.
You
must
determine
the
mass
fraction
of
each
organic
HAP
for
each
material
used
in
the
electrodeposition
primer
operation
during
the
compliance
period
by
using
one
of
the
options
in
paragraphs
(
e)(
1)
through
(
3)
of
this
section.
(
1)
Method
311
(
appendix
A
to
40
CFR
part
63).
You
may
use
Method
311
for
determining
the
mass
fraction
of
each
organic
HAP.
(
2)
Alternative
method.
You
may
use
an
alternative
test
method
for
determining
the
mass
fraction
of
organic
HAP
once
the
Administrator
has
approved
it.
You
must
follow
the
procedure
in
§
63.7(
f)
to
submit
an
alternative
test
method
for
approval.
(
3)
Information
from
the
supplier
or
manufacturer
of
the
material.
You
may
rely
on
information
other
than
that
generated
by
the
test
methods
specified
in
paragraphs
(
e)(
1)
and
(
2)
of
this
section,
such
as
manufacturer's
formulation
data,
if
it
represents
each
organic
HAP
that
is
present
at
0.1
percent
by
mass
or
more
for
OSHAdefined
carcinogens,
as
specified
in
29
CFR
1910.1200(
d)(
4),
and
at
1.0
percent
by
mass
or
more
for
other
compounds.
If
there
is
a
disagreement
between
such
information
and
results
of
a
test
conducted
according
to
paragraph
(
e)(
1)
or
(
2)
of
this
section,
then
the
test
method
results
will
take
precedence.
(
f)
Capture
of
electrodeposition
bake
oven
emissions.
You
must
show
that
the
electrodeposition
bake
oven
meets
the
criteria
in
sections
5.3
through
5.5
of
Method
204
of
appendix
M
to
40
CFR
part
51
and
directs
all
of
the
exhaust
gases
from
the
bake
oven
to
an
add
on
control
device.
(
g)
Control
of
electrodeposition
bake
oven
emissions.
Determine
the
efficiency
of
each
control
device
on
each
electrodeposition
bake
oven
using
the
procedures
in
§
§
63.3164
and
63.3166.
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Proposed
Rules
(
h)
Compliance
demonstration.
To
demonstrate
initial
compliance,
the
organic
HAP
emissions
from
the
combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations
must
meet
the
applicable
emission
limitation
in
§
63.3090(
b)
or
§
63.3091(
b);
the
organic
HAP
emissions
from
the
electrodeposition
primer
operation
must
meet
the
applicable
emissions
limitations
in
§
63.3092(
a)
or
(
b).
You
must
keep
all
records
as
required
by
§
§
63.3130
and
63.3131.
As
part
of
the
Notification
of
Compliance
Status
required
by
§
63.3110,
you
must
submit
a
statement
that
the
coating
operation(
s)
was
(
were)
in
compliance
with
the
emission
limitations
during
the
initial
compliance
period
because
the
organic
HAP
emission
rate
from
the
combined
primer
surfacer,
topcoat,
final
repair,
glass
bonding
primer,
and
glass
bonding
adhesive
operations
was
less
than
or
equal
to
the
applicable
emission
limit
in
§
63.3090(
b)
or
§
63.3091(
b),
and
the
organic
HAP
emissions
from
the
electrodeposition
primer
operation
met
the
applicable
emissions
limitations
in
§
63.3092(
a)
or
(
b),
and
you
achieved
the
operating
limits
required
by
§
63.3093
and
the
work
practice
standards
required
by
§
63.3094.
§
63.3172
[
Reserved]
§
63.3173
How
do
I
demonstrate
continuous
compliance
with
the
emission
limitations?
(
a)
To
demonstrate
continuous
compliance
with
the
applicable
emission
limit
in
§
63.3090(
b)
or
§
63.3091(
b),
the
organic
HAP
emission
rate
for
each
compliance
period
determined
according
to
the
procedures
in
§
63.3171
must
be
equal
to
or
less
than
the
applicable
emission
limit
in
§
63.3090(
b)
or
§
63.3091(
b).
A
compliance
period
consists
of
1
month.
Each
month
after
the
end
of
the
initial
compliance
period
described
in
§
63.3170
is
a
compliance
period
consisting
of
that
month.
You
must
perform
the
calculations
in
§
63.3171
on
a
monthly
basis.
(
b)
If
the
organic
HAP
emission
rate
for
any
1
month
compliance
period
exceeded
the
applicable
emission
limit
in
§
63.3090(
b)
or
§
63.3091(
b),
this
is
a
deviation
from
the
emission
limitation
for
that
compliance
period
and
must
be
reported
as
specified
in
§
§
63.3110(
c)(
6)
and
63.3120(
a)(
6).
(
c)
You
must
meet
the
requirements
of
§
63.3163(
c)
through
(
j).
Other
Requirements
and
Information
§
63.3175
Who
implements
and
enforces
this
subpart?
(
a)
This
subpart
can
be
implemented
and
enforced
by
us,
EPA,
or
a
delegated
authority
such
as
your
State,
local,
or
tribal
agency.
If
the
Administrator
has
delegated
authority
to
your
State,
local,
or
tribal
agency,
then
that
agency
(
as
well
as
EPA)
has
the
authority
to
implement
and
enforce
this
subpart.
You
should
contact
your
EPA
Regional
Office
to
find
out
if
implementation
and
enforcement
of
this
subpart
is
delegated
to
your
State,
local,
or
tribal
agency.
(
b)
In
delegating
implementation
and
enforcement
authority
of
this
subpart
to
a
State,
local,
or
tribal
agency
under
subpart
E
of
this
part,
the
authorities
contained
in
paragraph
(
c)
of
this
section
are
retained
by
the
EPA
Administrator
and
are
not
transferred
to
the
State,
local,
or
tribal
agency.
(
c)
The
authorities
that
will
not
be
delegated
to
State,
local,
or
tribal
agencies
are
listed
in
paragraphs
(
c)(
1)
through
(
4)
of
this
section:
(
1)
Approval
of
alternatives
to
the
work
practice
standards
in
§
63.3094
under
§
63.6(
g).
(
2)
Approval
of
major
alternatives
to
test
methods
under
§
63.7(
e)(
2)(
ii)
and
(
f)
and
as
defined
in
§
63.90.
(
3)
Approval
of
major
alternatives
to
monitoring
under
§
63.8(
f)
and
as
defined
in
§
63.90.
(
4)
Approval
of
major
alternatives
to
recordkeeping
and
reporting
under
§
63.10(
f)
and
as
defined
in
§
63.90.
§
63.3176
What
definitions
apply
to
this
subpart?
Terms
used
in
this
subpart
are
defined
in
the
CAA,
in
40
CFR
63.2,
the
General
Provisions
of
this
part,
and
in
this
section
as
follows:
Add
on
control
device
means
an
air
pollution
control
device,
such
as
a
thermal
oxidizer
or
carbon
adsorber,
that
reduces
pollution
in
an
air
stream
by
destruction
or
removal
before
discharge
to
the
atmosphere.
Add
on
control
device
efficiency
means
the
ratio
of
the
emissions
collected
or
destroyed
by
an
add
on
air
pollution
control
device
to
the
total
emissions
that
are
introduced
into
the
control
device,
expressed
as
a
percentage.
Adhesive
means
any
chemical
substance
that
is
applied
for
the
purpose
of
bonding
two
surfaces
together.
Anti
chip
coating
means
a
specialty
type
of
coating
designed
to
reduce
stone
chipping
damage.
It
is
applied
on
selected
vehicle
surfaces
that
are
exposed
to
impingement
by
stones
and
other
road
debris.
It
is
typically
applied
after
the
electrodeposition
primer
and
before
the
topcoat
coating
materials
(
may
be
used
as
a
type
of
primersurfacer
Anti
chip
coatings
are
included
in
the
primer
surfacer
operation.
As
applied
means
the
condition
of
a
coating
material
after
any
dilution
as
it
is
being
applied
to
the
substrate.
As
supplied
means
the
condition
of
the
coating
material
as
provided
by
the
manufacturer
to
the
user,
either
before
or
after
reducing
for
application.
Automobile
means
a
motor
vehicle
designed
to
carry
up
to
eight
passengers,
excluding
vans,
sport
utility
vehicles,
and
motor
vehicles
designed
primarily
to
transport
light
loads
of
property.
See
also
Light
duty
truck.
Automobile
and/
or
light
duty
truck
assembly
plant
means
facilities
involved
primarily
in
assembly
of
automobiles
and
light
duty
trucks,
including
coating
facilities
and
processes.
Basecoat/
clearcoat
means
a
topcoat
system
applied
to
exterior
and
selected
interior
vehicle
surfaces
primarily
to
provide
an
aesthetically
pleasing
appearance
and
acceptable
durability
performance.
It
consists
of
a
layer
of
pigmented
basecoat
color
coating,
followed
directly
by
a
layer
of
a
clear
or
semitransparent
coating.
It
may
include
multiple
layers
of
color
coats
or
tinted
clear
materials.
Blackout
coating
means
a
type
of
specialty
coating
applied
on
selected
vehicle
surfaces
(
including
areas
of
the
engine
compartment
visible
through
the
grill,
and
window
and
pillar
trim)
to
provide
a
cosmetic
appearance.
Typically
black
or
dark
gray
color.
Blackout
coating
may
be
included
in
either
the
primer
surfacer
or
topcoat
operations.
Capture
device
means
a
hood,
enclosure,
room,
floor
sweep,
or
other
means
of
containing
or
collecting
emissions
and
directing
those
emissions
into
an
add
on
air
pollution
control
device.
Capture
efficiency
or
capture
system
efficiency
means
the
portion
(
expressed
as
a
percentage)
of
the
pollutants
from
an
emission
source
that
is
delivered
to
an
add
on
control
device.
Capture
system
means
one
or
more
capture
devices
intended
to
collect
emissions
generated
by
a
coating
operation
in
the
use
of
coatings,
both
at
the
point
of
application
and
at
subsequent
points
where
emissions
from
the
coatings
occur,
such
as
flashoff
drying,
or
curing.
As
used
in
this
subpart,
multiple
capture
devices
that
collect
emissions
generated
by
a
coating
operation
are
considered
a
single
capture
system.
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247
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24,
2002
/
Proposed
Rules
Catalytic
oxidizer
means
a
device
for
oxidizing
pollutants
or
waste
materials
via
flame
and
heat
incorporating
a
catalyst
to
aid
the
combustion
at
lower
operating
temperature.
Cleaning
material
means
a
solvent
used
to
remove
contaminants
and
other
materials
such
as
dirt,
grease,
oil,
and
dried
(
e.
g.,
depainting)
or
wet
coating
from
a
substrate
before
or
after
coating
application;
or
from
equipment
associated
with
a
coating
operation,
such
as
spray
booths,
spray
guns,
tanks,
and
hangers.
Thus,
it
includes
any
cleaning
material
used
on
substrates
or
equipment
or
both.
Coating
means
a
material
applied
to
a
substrate
for
decorative,
protective,
or
functional
purposes.
Such
materials
include,
but
are
not
limited
to,
paints,
sealants,
caulks,
inks,
adhesives,
primers,
deadeners,
and
maskants.
Decorative,
protective,
or
functional
materials
that
consist
only
of
protective
oils
for
metal,
acids,
bases,
or
any
combination
of
these
substances
are
not
considered
coatings
for
the
purposes
of
this
subpart.
Coating
operation
means
equipment
used
to
apply
coating
to
a
substrate
(
coating
application)
and
to
dry
or
cure
the
coating
after
application.
A
single
coating
operation
always
includes
at
least
the
point
at
which
a
coating
is
applied
and
all
subsequent
points
in
the
affected
source
where
organic
HAP
emissions
from
that
coating
occur.
There
may
be
multiple
coating
operations
in
an
affected
source.
Coating
application
with
hand
held
nonrefillable
aerosol
containers,
touchup
markers,
marking
pens,
or
pinstriping
equipment
is
not
a
coating
operation
for
the
purposes
of
this
subpart.
Coating
solids
means
the
nonvolatile
portion
of
the
coating
that
makes
up
the
dry
film.
Continuous
parameter
monitoring
system
(
CPMS)
means
the
total
equipment
that
may
be
required
to
meet
the
data
acquisition
and
availability
requirements
of
this
subpart;
used
to
sample,
condition
(
if
applicable),
analyze,
and
provide
a
record
of
coating
operation,
or
capture
system,
or
add
on
control
device
parameters.
Controlled
coating
operation
means
a
coating
operation
from
which
some
or
all
of
the
organic
HAP
emissions
are
routed
through
an
emission
capture
system
and
add
on
control
device.
Day
tank
means
tank
with
agitation
and
pumping
system
used
for
mixing
and
continuous
circulation
of
coatings
from
the
paint
storage
area
to
the
spray
booth
area
of
the
paintshop.
Deadener
means
a
specialty
coating
applied
to
selected
vehicle
underbody
surfaces
for
the
purpose
of
reducing
the
sound
of
road
noise
in
the
passenger
compartment.
Deposited
solids
means
the
solids
component
of
the
coating
remains
on
the
substrate
or
object
being
painted.
Deviation
means
any
instance
in
which
an
affected
source
subject
to
this
subpart,
or
an
owner
or
operator
of
such
a
source:
(
1)
Fails
to
meet
any
requirement
or
obligation
established
by
this
subpart
including,
but
not
limited
to,
any
emission
limit,
operating
limit,
or
work
practice
standard;
or
(
2)
Fails
to
meet
any
term
or
condition
that
is
adopted
to
implement
an
applicable
requirement
in
this
subpart
and
that
is
included
in
the
operating
permit
for
any
affected
source
required
to
obtain
such
a
permit;
or
(
3)
Fails
to
meet
any
emission
limit
or
operating
limit
or
work
practice
standard
in
this
subpart
during
startup,
shutdown,
or
malfunction,
regardless
of
whether
or
not
such
failure
is
permitted
by
this
subpart.
Electrodeposition
primer
or
electrocoating
primer
means
a
process
of
applying
a
protective,
corrosionresistant
waterborne
primer
on
exterior
and
interior
surfaces
that
provides
thorough
coverage
of
recessed
areas.
It
is
a
dip
coating
method
that
uses
an
electrical
field
to
apply
or
deposit
the
conductive
coating
material
onto
the
part.
The
object
being
painted
acts
as
an
electrode
that
is
oppositely
charged
from
the
particles
of
paint
in
the
dip
tank.
Also
referred
to
as
E
Coat,
Uni
Prime,
and
ELPO
Primer.
Emission
limitation
means
an
emission
limit,
operating
limit,
or
work
practice
standard.
Final
repair
means
the
operations
performed
and
coating(
s)
applied
outside
of
the
paint
shop
to
completelyassembled
motor
vehicles
or
in
lowbake
off
line
operations
within
the
paint
shop
to
correct
damage
or
imperfections
in
the
coating.
Flash
off
area
means
the
portion
of
a
coating
process
between
the
coating
application
station
and
the
next
coating
application
station
or
drying
oven
where
solvent
begins
to
evaporate
from
the
coated
vehicle.
Glass
bonding
adhesive
means
an
adhesive
used
to
bond
windshield
or
other
glass
to
an
automobile
or
lightduty
truck
body.
Glass
bonding
primer
means
a
primer
applied
to
windshield
or
other
glass,
or
to
body
openings
to
prepare
the
glass
or
body
openings
for
the
application
of
glass
bonding
adhesive,
or
the
installation
of
adhesive
bonded
glass.
Guide
coat
means
Primer
surfacer.
In
line
repair
operation
means
the
process
of
surface
preparation
and
application
of
coatings
on
the
paint
line
in
the
paint
shop
to
correct
damage
or
imperfections
in
the
coating
finish.
Also
referred
to
as
high
bake
repair
or
high
bake
reprocess.
Light
duty
truck
means
vans,
sport
utility
vehicles,
and
motor
vehicles
designed
primarily
to
transport
light
loads
of
property
with
gross
vehicle
weight
rating
of
8,500
lbs
or
less.
Manufacturer's
formulation
data
means
data
on
a
material
(
such
as
a
coating)
that
are
supplied
by
the
material
manufacturer
based
on
knowledge
of
the
ingredients
used
to
manufacture
that
material,
rather
than
based
on
testing
of
the
material
with
the
test
methods
specified
in
§
§
63.3151
and
63.3161.
Manufacturer's
formulation
data
may
include,
but
are
not
limited
to,
information
on
density,
organic
HAP
content,
volatile
organic
matter
content,
and
coating
solids
content.
Mass
fraction
of
organic
HAP
means
the
ratio
of
the
mass
of
organic
HAP
to
the
mass
of
a
material
in
which
it
is
contained,
expressed
as
kg
of
organic
HAP
per
kg
of
material.
Month
means
a
calendar
month
or
a
pre
specified
period
of
28
days
to
35
days
to
allow
for
flexibility
in
recordkeeping
when
data
are
based
on
a
business
accounting
period.
Organic
HAP
content
means
the
mass
of
organic
HAP
per
mass
of
coating
material.
Paint
shop
means
that
area
of
an
automobile
assembly
plant
in
which
vehicle
bodies
are
cleaned,
phosphated,
and
coatings
(
including
electrodeposition
primer,
primersurfacer
topcoat,
and
deadener)
are
applied.
Permanent
total
enclosure
(
PTE)
means
a
permanently
installed
enclosure
that
meets
the
criteria
of
Method
204
of
appendix
M,
40
CFR
part
51,
for
a
PTE
and
that
directs
all
the
exhaust
gases
from
the
enclosure
to
an
add
on
control
device.
Primer
surfacer
means
an
intermediate
protective
coating
applied
on
the
electrodeposition
primer
and
under
the
topcoat.
It
provides
adhesion,
protection,
and
appearance
properties
to
the
total
finish.
Also
called
a
guide
coat
or
surfacer.
Purge/
clean
operation
means
the
process
of
flushing
paint
out
and
cleaning
the
spray
lines
when
changing
colors
or
to
remove
undesired
material.
It
includes
use
of
air
and
solvents
to
clean
the
lines.
Purge
capture
means
the
capture
of
purge
solvent
and
materials
into
a
closed
collection
system
immediately
after
purging
the
system.
It
is
used
to
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Proposed
Rules
prevent
the
release
of
organic
HAP
emissions
and
includes
the
disposal
of
the
captured
purge
material.
Purge
material
means
the
coating
and
associated
cleaning
solvent
materials
expelled
from
the
spray
system
during
the
process
of
cleaning
the
spray
lines
and
applicators
when
color
changing
or
to
maintain
the
cleanliness
of
the
spray
system.
Protective
oil
means
an
organic
material
that
is
applied
to
metal
for
the
purpose
of
providing
lubrication
or
protection
from
corrosion
without
forming
a
solid
film.
This
definition
of
protective
oil
includes,
but
is
not
limited
to,
lubricating
oils,
evaporative
oils
(
including
those
that
evaporate
completely),
and
extrusion
oils.
Research
or
laboratory
facility
means
a
facility
whose
primary
purpose
is
for
research
and
development
of
new
processes
and
products,
that
is
conducted
under
the
close
supervision
of
technically
trained
personnel,
and
is
not
engaged
in
the
manufacture
of
final
or
intermediate
products
for
commercial
purposes,
except
in
a
de
minimis
manner.
Responsible
official
means
responsible
official
as
defined
in
40
CFR
70.2.
Spraybooth
means
a
ventilated
structure
housing
automatic
and/
or
manual
spray
application
equipment
for
coating
operations.
Includes
facilities
for
the
capture
and
entrapment
of
particulate
overspray.
Startup,
initial
means
the
first
time
equipment
is
brought
online
in
a
facility.
Surface
preparation
means
use
of
a
cleaning
material
on
a
portion
of
or
all
of
a
substrate.
This
includes
use
of
a
cleaning
material
to
remove
dried
coating,
which
is
sometimes
called
``
depainting.''
Surfacer
means
Primer
surfacer.
Tack
wipe
means
solvent
impregnated
cloth
used
to
remove
dust
from
surfaces
prior
to
application
of
coatings.
Temporary
total
enclosure
means
an
enclosure
constructed
for
the
purpose
of
measuring
the
capture
efficiency
of
pollutants
emitted
from
a
given
source
as
defined
in
Method
204
of
appendix
M,
40
CFR
part
51.
Thermal
oxidizer
means
a
device
for
oxidizing
air
pollutants
or
waste
materials
via
flame
and
heat.
Thinner
means
an
organic
solvent
that
is
added
to
a
coating
after
the
coating
is
received
from
the
supplier.
Topcoat
means
the
final
coating
system
applied
to
provide
the
final
color
and/
or
a
protective
finish.
May
be
a
Monocoat
color
or
Basecoat/
Clearcoat
system.
Total
volatile
hydrocarbon
(
TVH)
means
the
total
amount
of
nonaqueous
volatile
organic
matter
determined
according
to
Methods
204
and
204A
through
F
of
appendix
M
to
40
CFR
part
51
and
substituting
the
term
TVH
each
place
in
the
methods
where
the
term
VOC
is
used.
The
TVH
includes
both
VOC
and
non
VOC.
Transfer
efficiency
means
the
ratio
of
the
amount
of
coating
solids
deposited
onto
the
surface
of
the
object
to
the
total
amount
of
coating
solids
sprayed
while
applying
the
coating
to
the
object.
Uncontrolled
coating
operation
means
a
coating
operation
from
which
none
of
the
organic
HAP
emissions
are
routed
through
an
emission
capture
system
and
add
on
control
device.
Volatile
organic
compound
(
VOC)
means
any
compound
defined
as
VOC
in
40
CFR
51.100(
s).
Volume
fraction
of
coating
solids
means
the
ratio
of
the
volume
of
coating
solids
(
also
known
as
volume
of
nonvolatiles)
to
the
volume
of
coating;
liters
of
coating
solids
per
liter
of
coating.
Tables
to
Subpart
IIII
of
Part
63
TABLE
1
TO
SUBPART
IIII
OF
PART
63.
OPERATING
LIMITS
FOR
CAPTURE
SYSTEMS
AND
ADD
ON
CONTROL
DEVICES
[
If
you
are
required
to
comply
with
operating
limits
by
§
63.3093,
you
must
comply
with
the
applicable
operating
limits
in
the
following
table]
For
the
following
device
.
.
.
You
must
meet
the
following
operating
limit
.
.
.
And
you
must
demonstrate
continuous
compliance
with
the
operating
limit
by
1.
thermal
oxidizer
...............
a.
the
average
combustion
temperature
in
any
3
hour
period
must
not
fall
below
the
combustion
temperature
limit
established
according
to
§
63.3167(
a).
i.
collecting
the
combustion
temperature
data
according
to
§
63.3168(
c);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
combustion
temperature
at
or
above
the
temperature
limit.
2.
catalytic
oxidizer
..............
a.
the
average
temperature
measured
just
before
the
catalyst
bed
in
any
3
hour
period
must
not
fall
below
the
limit
established
according
to
§
63.3167(
b);
and
either.
i.
collecting
the
temperature
data
according
to
§
63.3168(
c);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
temperature
before
the
catalyst
bed
at
or
above
the
temperature
limit.
b.
ensure
that
the
average
temperature
difference
across
the
catalyst
bed
in
any
3
hour
period
does
not
fall
below
the
temperature
difference
limit
established
according
to
§
63.3167(
b)(
2);
or.
i.
collecting
the
temperature
data
according
to
§
63.3168(
c);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
temperature
difference
at
or
above
the
temperature
difference
limit;
or
c.
develop
and
implement
an
inspection
and
maintenance
plan
according
to
§
63.3167(
b)(
4).
i.
maintaining
an
up
to
date
inspection
and
maintenance
plan,
records
of
annual
catalyst
activity
checks,
records
of
monthly
inspections
of
the
oxidizer
system,
and
records
of
the
annual
internal
inspections
of
the
catalyst
bed.
If
a
problem
is
discovered
during
a
monthly
or
annual
inspection
required
by
§
63.3167(
b)(
4),
you
must
take
corrective
action
as
soon
as
practicable
consistent
with
the
manufacturer's
recommendations.
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Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
TABLE
1
TO
SUBPART
IIII
OF
PART
63.
OPERATING
LIMITS
FOR
CAPTURE
SYSTEMS
AND
ADD
ON
CONTROL
DEVICES
Continued
[
If
you
are
required
to
comply
with
operating
limits
by
§
63.3093,
you
must
comply
with
the
applicable
operating
limits
in
the
following
table]
For
the
following
device
.
.
.
You
must
meet
the
following
operating
limit
.
.
.
And
you
must
demonstrate
continuous
compliance
with
the
operating
limit
by
3.
carbon
adsorber
...............
a.
the
total
regeneration
desorbing
gas
(
e.
g.,
steam
or
nitrogen)
mass
flow
for
each
carbon
bed
regeneration
cycle
must
not
fall
below
the
total
regeneration
desorbing
gas
mass
flow
limit
established
according
to
§
63.3167(
c).
i.
measuring
the
total
regeneration
desorbing
gas
(
e.
g.,
steam
or
nitrogen)
mass
flow
for
each
regeneration
cycle
according
to
§
63.3168(
d);
and
ii.
maintaining
the
total
regeneration
desorbing
gas
mass
flow
at
or
above
the
mass
flow
limit.
b.
the
temperature
of
the
carbon
bed
after
completing
each
regeneration
and
any
cooling
cycle
must
not
exceed
the
carbon
bed
temperature
limit
established
according
to
§
63.3167(
c).
i.
measuring
the
temperature
of
the
carbon
bed
after
completing
each
regeneration
and
any
cooling
cycle
according
to
§
63.3168(
d);
and
ii.
operating
the
carbon
beds
such
that
each
carbon
bed
is
not
returned
to
service
until
completing
each
regeneration
and
any
cooling
cycle
until
the
recorded
temperature
of
the
carbon
bed
is
at
or
below
the
temperature
limit.
4.
condenser
........................
a.
the
average
condenser
outlet
(
product
side)
gas
temperature
in
any
3
hour
period
must
not
exceed
the
temperature
limit
established
according
to
§
63.3167(
d).
i.
collecting
the
condenser
outlet
(
product
side)
gas
temperature
according
to
§
63.3168(
e);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
gas
temperature
at
the
outlet
at
or
below
the
temperature
limit.
5.
concentrators,
including
zeolite
wheels
and
rotary
carbon
adsorbers.
a.
the
average
gas
temperature
of
the
desorption
concentrate
stream
in
any
3
hour
period
must
not
fall
below
the
limit
established
according
to
§
63.3167(
e).
i.
collecting
the
temperature
data
according
to
§
63.3168(
f);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
temperature
at
or
above
the
temperature
limit.
b.
the
average
pressure
drop
of
the
dilute
stream
across
the
concentrator
in
any
3
hour
period
must
not
fall
below
the
limit
established
according
to
§
63.3167(
e).
i.
collecting
the
pressure
drop
data
according
to
§
63.3168(
f);
and
ii.
reducing
the
pressure
drop
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
pressure
drop
at
or
above
the
pressure
drop
limit.
6.
emission
capture
system
that
is
a
PTE.
a.
the
direction
of
the
air
flow
at
all
times
must
be
into
the
enclosure;
and
either.
i.
collecting
the
direction
of
air
flow,
and
either
the
facial
velocity
of
air
through
all
natural
draft
openings
according
to
§
63.3168(
g)(
1)
or
the
pressure
drop
across
the
enclosure
according
to
§
63.3168(
g)(
2);
and
ii.
maintaining
the
facial
velocity
of
air
flow
through
all
natural
draft
openings
or
the
pressure
drop
at
or
above
the
facial
velocity
limit
or
pressure
drop
limit,
and
maintaining
the
direction
of
air
flow
into
the
enclosure
at
all
times.
b.
the
average
facial
velocity
of
air
through
all
natural
draft
openings
in
the
enclosure
must
be
at
least
200
feet
per
minute;
or.
i.
collecting
the
direction
of
air
flow,
and
either
the
facial
velocity
of
air
through
all
natural
draft
openings
according
to
§
63.3168(
g)(
1)
or
the
pressure
drop
across
the
enclosure
according
to
§
63.3168(
g)(
2);
and
ii.
maintaining
the
facial
velocity
of
air
flow
through
all
natural
draft
openings
or
the
pressure
drop
at
or
above
the
facial
velocity
limit
or
pressure
drop
limit,
and
maintaining
the
direction
of
air
flow
into
the
enclosure
at
all
times.
c.
the
pressure
drop
across
the
enclosure
must
be
at
least
0.007
inch
water,
as
established
in
Method
204
of
appendix
M
to
40
CFR
part
51.
i.
collecting
the
direction
of
air
flow,
and
either
the
facial
velocity
of
air
through
all
natural
draft
openings
according
to
§
63.3168(
g)(
1)
or
the
pressure
drop
across
the
enclosure
according
to
§
63.3168(
g)(
2);
and
ii.
maintaining
the
facial
velocity
of
air
flow
through
all
natural
draft
openings
or
the
pressure
drop
at
or
above
the
facial
velocity
limit
or
pressure
drop
limit,
and
maintaining
the
direction
of
air
flow
into
the
enclosure
at
all
times.
7.
emission
capture
system
that
is
not
a
PTE.
a.
the
average
gas
volumetric
flow
rate
or
duct
static
pressure
in
each
duct
between
a
capture
device
and
add
on
control
device
inlet
in
any
3
hour
period
must
not
fall
below
the
average
volumetric
flow
rate
or
duct
static
pressure
limit
established
for
that
capture
device
according
to
§
63.3167(
f).
i.
collecting
the
gas
volumetric
flow
rate
or
duct
static
pressure
for
each
capture
device
according
to
§
63.3168(
g);
ii.
reducing
the
data
to
3
hour
block
averages;
and
iii.
maintaining
the
3
hour
average
gas
volumetric
flow
rate
or
duct
static
pressure
for
each
capture
device
at
or
above
the
gas
volumetric
flow
rate
or
duct
static
pressure
limit.
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/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
TABLE
2
TO
SUBPART
IIII
OF
PART
63.
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
IIII
OF
PART
63
[
You
must
comply
with
the
applicable
General
Provisions
requirements
according
to
the
following
table]
Citation
Subject
Applicable
to
subpart
IIII
Explanation
§
63.1(
a)(
1)
(
14)
General
Applicability
..............................................
Yes
§
63.1(
b)(
1)
(
3)
Initial
Applicability
Determination
...........................
Yes
Applicability
to
subpart
IIII
is
also
specified
in
§
63.3181.
§
63.1(
c)(
1)
Applicability
After
Standard
Established
................
Yes
§
63.1(
c)(
2)
(
3)
Applicability
of
Permit
Program
for
Area
Sources
No
Area
sources
are
not
subject
to
or
subpart
IIII.
§
63.1(
c)(
4)
(
5)
Extensions
and
Notifications
..................................
Yes
§
63.1(
e)
Applicability
of
Permit
Program
Before
Relevant
Standard
is
Set.
Yes
§
63.2
Definitions
...............................................................
Yes
Additional
definitions
are
specified
in
§
63.3176.
§
63.3(
a)
(
c)
Units
and
Abbreviations
.........................................
Yes
§
63.4(
a)(
1)
(
5)
Prohibited
Activities
................................................
Yes
§
63.4(
b)
(
c)
Circumvention/
Severability
.....................................
Yes
§
63.5(
a)
Construction/
Reconstruction
..................................
Yes
§
63.5(
b)(
1)
(
6)
Requirements
for
Existing,
Newly
Constructed,
and
Reconstructed
Sources.
Yes
§
63.5(
d)
Application
for
Approval
of
Construction/
Reconstruction
Yes
§
63.5(
e)
Approval
of
Construction/
Reconstruction
...............
Yes
§
63.5(
f)
Approval
of
Construction/
Reconstruction
Based
on
Prior
State
Review.
Yes
§
63.6(
a)
Compliance
With
Standards
and
Maintenance
Requirements
Applicability.
Yes
§
63.6(
b)(
1)
(
7)
Compliance
Dates
for
New
and
Reconstructed
Sources.
Yes
§
63.3083
specifies
the
compliance
dates.
§
63.6(
c)(
1)
(
5)
Compliance
Dates
for
Existing
Sources
................
Yes
§
63.3083
specifies
the
compliance
dates.
§
63.6(
e)(
1)
(
2)
Operation
and
Maintenance
...................................
Yes
§
63.6(
e)(
3)
Startup,
Shutdown,
and
Malfunction
Plan
.............
Yes
Only
sources
using
an
add
on
control
device
to
comply
with
the
standard
must
complete
startup
shutdown,
and
malfunction
plans.
§
63.6(
f)(
1)
Compliance
Except
During
Startup,
Shutdown,
and
Malfunction.
Yes
Applies
only
to
sources
using
an
add
on
control
device
to
comply
with
the
standards.
§
63.6(
f)(
2)
(
3)
Methods
for
Determining
Compliance
...................
Yes
§
63.6(
g)(
1)
(
3)
Use
of
an
Alternative
Standard
..............................
Yes
§
63.6(
h)
Compliance
With
Opacity/
Visible
Emission
Standards
No
Subpart
IIII
does
not
establish
opacity
standards
and
does
not
require
continuous
opacity
monitoring
systems
(
COMS).
§
63.6(
i)(
1)
(
16)
Extension
of
Compliance
.......................................
Yes
§
63.6(
j)
Presidential
Compliance
Exemption
......................
Yes
§
63.7(
a)(
1)
Performance
Test
Requirements
Applicability
....
Yes
Applies
to
all
affected
sources.
Additional
requirements
for
performance
testing
are
specified
in
§
§
63.3164
and
63.3166.
§
63.7(
a)(
2)
Performance
Test
Requirements
Dates
..............
Yes
Applies
only
to
performance
tests
for
capture
system
and
control
device
efficiency
at
sources
using
these
to
comply
with
the
standards.
§
63.3160
specifies
the
schedule
for
performance
test
requirements
that
are
earlier
than
those
specified
in
§
63.7(
a)(
2).
§
63.7(
a)(
3)
Performance
Tests
Required
By
the
Administrator
Yes
§
63.7(
b)
(
e)
Performance
Test
Requirements
Notification,
Quality
Assurance,
Facilities
Necessary
for
Safe
Testing
Conditions
During
Test.
Yes
Applies
only
to
performance
tests
for
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standards
§
63.7(
f)
Performance
Test
Requirements
Use
of
Alternative
Test
Method.
Yes
Applies
to
alltest
methods
except
those
used
to
determine
capture
system
efficiency.
§
63.7(
g)
(
h)
Performance
Test
Requirements
Data
Analysis,
Recordkeeping,
Reporting,
Waiver
of
Test.
Yes
Applies
only
to
performance
tests
for
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standards
§
63.8(
a)(
1)
(
3)
Monitoring
Requirements
Applicability
................
Yes
Applies
only
to
monitoring
of
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standards.
Additional
requirements
for
monitoring
are
specified
in
§
63.3168.
§
63.8(
a)(
4)
Additional
Monitoring
Requirements
......................
No
Subpart
IIII
does
not
have
monitoring
requirements
for
flares.
§
63.8(
b)
Conduct
of
Monitoring
............................................
Yes
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/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
TABLE
2
TO
SUBPART
IIII
OF
PART
63.
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
IIII
OF
PART
63
Continued
[
You
must
comply
with
the
applicable
General
Provisions
requirements
according
to
the
following
table]
Citation
Subject
Applicable
to
subpart
IIII
Explanation
§
63.8(
c)(
1)
(
3)
Continuous
Monitoring
Systems
(
CMS)
Operation
and
Maintenance.
Yes
Applies
only
to
monitoring
of
capture
system
and
add
on
control
device
efficiency
at
sources
using
these
to
comply
with
the
standards.
Additional
requirements
for
CMS
operations
and
maintenance
are
specified
in
§
63.3168.
§
63.8(
c)(
4)
CMS
.......................................................................
No
§
63.3168
specifies
the
requirements
for
the
operation
of
CMS
for
capture
systems
and
add
on
control
devices
at
sources
using
these
to
comply
with
the
standards.
§
63.8(
c)(
5)
COMS
.....................................................................
No
Subpart
IIII
does
not
have
opacity
or
visible
emission
standards.
§
63.8(
c)(
6)
CMS
Requirements
................................................
No
§
63.3168
specifies
the
requirements
for
monitoring
systems
for
capture
systems
and
add
on
control
devices
at
sources
using
these
to
comply
with
the
standards.
§
63.8(
c)(
7)
CMS
Out
of
Control
Periods
..................................
No
§
63.8(
c)(
8)
CMS
Out
of
Control
Periods
Reporting
.................
No
§
63.3120
requires
reporting
of
CMS
out
of
control
periods.
§
63.8(
d)
(
e)
Quality
Control
Program
and
CMS
Performance
Evaluation.
No
Subpart
IIII
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.8(
f)(
1)
(
5)
Use
of
an
Alternative
Monitoring
Method
..............
Yes
§
63.8(
f)(
6)
Alternative
to
Relative
Accuracy
Test
....................
No
Subpart
IIII
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.8(
g)(
1)
Data
Reduction
......................................................
No
§
§
63.3167
and
(
5)
63.3168
specify
monitoring
data
reduction.
§
63.9(
a)
(
d)
Notification
Requirements
......................................
Yes
§
63.9(
e)
Notification
of
Performance
Test
...........................
Yes
Applies
only
to
capture
system
and
add
on
control
device
performance
tests
at
sources
using
these
to
comply
with
the
standards.
§
63.9(
f)
Notification
of
Visible
Emissions/
Opacity
Test
.....
No
Subpart
IIII
does
not
have
opacity
or
visible
emission
standards.
§
63.9(
g)(
1)
(
3)
Additional
Notifications
When
Using
CMS
.............
No
Subpart
IIII
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.9(
h)
Notification
of
Compliance
Status
..........................
Yes
§
63.3110
specifies
the
dates
for
submitting
the
notification
of
compliance
status.
§
63.9(
i)
Adjustment
of
Submittal
Deadlines
........................
Yes
§
63.9(
j)
Change
in
Previous
Information
............................
Yes
§
63.10(
a)
Recordkeeping/
Reporting
Applicability
and
General
Information.
Yes
§
63.10(
b)(
1)
General
Recordkeeping
Requirements
..................
Yes
Additional
are
requirements
specified
in
§
§
63.3130
and
63.3131.
§
63.10(
b)(
2)(
i)
(
v)
Recordkeeping
Relevant
to
Startup,
Shutdown,
and
Malfunction
Periods
and
CMS.
Yes
Requirements
for
startup,
shutdown,
and
malfunction
records
only
apply
to
capture
systems
and
add
on
control
devices
used
to
comply
with
the
standards.
§
63.10(
b)(
2)(
vi)
(
xi)
.................................................................................
Yes
§
63.10(
b)(
2)(
xii)
Records
..................................................................
Yes
§
63.10(
b)(
2)(
xiii)
.................................................................................
No
Subpart
IIII
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.10(
b)(
2)(
xiv)
.................................................................................
Yes
§
63.10(
b)(
3)
Recordkeeping
Requirements
for
Applicability
Determinations
Yes
§
63.10(
c)(
1)
(
6)
Additional
Recordkeeping
Requirements
for
Sources
with
CMS.
Yes
§
63.10(
c)(
7)
8)
.................................................................................
No
The
same
records
are
required
in
§
63.3120(
a)(
6).
§
63.10(
c)(
9)
(
15)
.................................................................................
Yes
§
63.10(
d)(
1)
General
Reporting
Requirements
..........................
Yes
Additional
requirements
are
specified
in
§
63.3120.
§
63.10(
d)(
2)
Report
of
Performance
Test
Results
.....................
Yes
Additional
requirements
are
specified
in
§
63.3120(
b).
§
63.10(
d)(
3)
Reporting
Opacity
or
Visible
Emissions
Observations
No
Subpart
IIII
does
not
require
opacity
or
visible
emissions
observations.
§
63.10(
d)(
4)
Progress
Reports
for
Sources
With
Compliance
Extensions.
Yes
§
63.10(
d)(
5)
Startup,
Shutdown,
and
Malfunction
Reports
........
Yes
Applies
only
to
capture
systems
and
add
on
control
devices
used
to
comply
with
the
standards.
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Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
TABLE
2
TO
SUBPART
IIII
OF
PART
63.
APPLICABILITY
OF
GENERAL
PROVISIONS
TO
SUBPART
IIII
OF
PART
63
Continued
[
You
must
comply
with
the
applicable
General
Provisions
requirements
according
to
the
following
table]
Citation
Subject
Applicable
to
subpart
IIII
Explanation
§
63.10(
e)(
1)
(
2)
Additional
CMS
Reports
.........................................
No
Subpart
IIII
does
not
require
the
use
of
continuous
emissions
monitoring
systems.
§
63.10(
e)(
3)
Excess
Emissions/
CMS
Performance
Reports
......
No
§
63.3120(
b)
specifies
the
contents
of
periodic
compliance
reports.
§
63.10(
e)(
4)
COMS
Data
Reports
..............................................
No
Subpart
IIII
does
not
specify
requirements
for
opacity
or
COMS.
§
63.10(
f)
Recordkeeping/
Reporting
Waiver
..........................
Yes
§
63.11
Control
Device
Requirements/
Flares
.....................
No
Subpart
IIII
does
not
specify
use
of
flares
for
compliance
§
63.12
State
Authority
and
Delegations
............................
Yes
§
63.13
Addresses
..............................................................
....................
Yes
§
63.14
Incorporation
by
Reference
....................................
Yes
§
63.15
Availability
of
Information/
Confidentiality
...............
Yes
TABLE
3
TO
SUBPART
IIII
OF
PART
63.
DEFAULT
ORGANIC
HAP
MASS
FRACTION
FOR
SOLVENTS
AND
SOLVENT
BLENDS
[
You
may
use
the
mass
fraction
values
in
the
following
table
for
solvent
blends
for
which
you
do
not
have
test
data
or
manufacturer's
formulation
data]
Solvent/
Solvent
blend
CAS.
No.
Average
organic
HAP
mass
fraction
Typical
organic
HAP,
percent
by
mass
1.
Toluene
.......................................................................
108
88
3
1.0
Toluene.
2.
Xylene(
s)
.....................................................................
1330
20
7
1.0
Xylenes,
ethylbenzene.
3.
Hexane
.......................................................................
110
54
3
0.5
n
hexane.
4.
n
Hexane
....................................................................
110
54
3
1.0
n
hexane.
5.
Ethylbenzene
..............................................................
100
41
4
1.0
Ethylbenzene.
6.
Aliphatic
140
...............................................................
......................
0
None.
7.
Aromatic
100
..............................................................
......................
0.02
1%
xylene,
1%
cumene.
8.
Aromatic
150
..............................................................
......................
0.09
Naphthalene.
9.
Aromatic
naphtha
.......................................................
64742
95
6
0.02
1%
xylene,
1%
cumene.
10.
Aromatic
solvent
.......................................................
64742
94
5
0.1
Naphthalene.
11.
Exempt
mineral
spirits
..............................................
8032
32
4
0
None.
12.
Ligroines
(
VM
&
P)
...................................................
8032
32
4
0
None.
13.
Lactol
spirits
..............................................................
64742
89
6
0.15
Toluene.
14.
Low
aromatic
white
spirit
..........................................
64742
82
1
0
None.
15.
Mineral
spirits
...........................................................
64742
88
7
0.01
Xylenes.
16.
Hydrotreated
naphtha
...............................................
64742
48
9
0
None.
17.
Hydrotreated
light
distillate
.......................................
64742
47
8
0.001
Toluene.
18.
Stoddard
solvent
.......................................................
8052
41
3
0.01
Xylenes.
19.
Super
high
flash
naphtha
.........................................
64742
95
6
0.05
Xylenes.
20.
Varsol
solvent
........................................................
8052
49
3
0.01
0.5%
xylenes,
0.5%
ethylbenzene.
21.
VM
&
P
naphtha
.......................................................
64742
89
8
0.06
3%
toluene,
3%
xylene.
22.
Petroleum
distillate
mixture
......................................
68477
31
6
0.08
4%
naphthalene,
4%
biphenyl.
TABLE
4
TO
SUBPART
IIII
OF
PART
63.
DEFAULT
ORGANIC
HAP
MASS
FRACTION
FOR
PETROLEUM
SOLVENT
GROUPS
a
[
You
may
use
the
mass
fraction
values
in
the
following
table
for
solvent
blends
for
which
you
do
not
have
test
data
or
manufacturer's
formulation
data]
Solvent
type
Average
organic
HAP
mass
fraction
Typical
organic
HAP,
percent
by
mass
Aliphatic
b
.....................................
0.03
1%
Xylene,
1%
Toluene,
and
1%
Ethylbenzene.
Aromatic
c
.....................................
0.06
4%
Xylene,
1%
Toluene,
and
1%
Ethylbenzene.
a
Use
this
table
only
if
the
solvent
blend
does
not
match
any
of
the
solvent
blends
in
Table
3
to
this
subpart,
and
you
only
know
whether
the
blend
is
aliphatic
or
aromatic.
b
e.
g.,
Mineral
Spirits
135,
Mineral
Spirits
150
EC,
Naphtha,
Mixed
Hydrocarbon,
Aliphatic
Hydrocarbon,
Aliphatic
Naphtha,
Naphthol
Spirits,
Petroleum
Spirits,
Petroleum
Oil,
Petroleum
Naphtha,
Solvent
Naphtha,
Solvent
Blend.
c
e.
g.,
Medium
flash
Naphtha,
High
flash
Naphtha,
Aromatic
Naphtha,
Light
Aromatic
Naphtha,
Light
Aromatic
Hydrocarbons,
Aromatic
Hydrocarbons
Light
Aromatic
Solvent.
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/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Proposed
Rules
PART
264
[
AMENDED]
1.
The
authority
citation
for
part
264
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
6905,
6912(
a),
6924,
6925,
6927,
6928(
h),
and
6974.
2.
Section
264.1050
is
amended
by
adding
paragraph
(
h)
to
read
as
follows:
§
264.1050
Applicability.
*
*
*
*
*
(
h)
Purged
coatings
and
solvents
from
automobile
and
light
duty
truck,
separate
non
body
plastic
parts,
and
separate
non
body
metal
parts
surface
coating
operations
at
facilities
subject
to
the
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
at
40
CFR
part
63,
subpart
IIII,
are
not
subject
to
the
requirements
of
this
subpart.
*
*
*
*
*
PART
265
[
AMENDED]
1.
The
authority
citation
for
part
265
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
6905,
6906,
6912,
6922,
6923,
6924,
6925,
6935,
6936,
and
6937,
unless
otherwise
noted.
2.
Section
265.1050
is
amended
by
adding
paragraph
(
g)
to
read
as
follows:
§
265.1050
Applicability.
*
*
*
*
*
(
g)
Purged
coatings
and
solvents
from
automobile
and
light
duty
truck,
separate
non
body
plastic
parts,
and
separate
non
body
metal
parts
surface
coating
operations
at
facilities
subject
to
the
national
emission
standards
for
hazardous
air
pollutants
(
NESHAP)
at
40
CFR
part
63,
subpart
IIII,
are
not
subject
to
the
requirements
of
this
subpart.
[
FR
Doc.
02
31420
Filed
12
23
02;
8:
45
am]
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"license": "Public Domain",
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} |
EPA-HQ-OAR-2002-0095-0001 | Rule | "2002-12-27T05:00:00" | Protection of Stratospheric Ozone: Allocation of Essential Use Allowances for Calendar Year 2003; Final Rule | Friday,
December
27,
2002
Part
X
Environmental
Protection
Agency
40
CFR
Part
82
Protection
of
Stratospheric
Ozone:
Allocation
of
Essential
Use
Allowances
for
Calendar
Year
2003;
Final
Rule
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/
Vol.
67,
No.
249
/
Friday,
December
27,
2002
/
Rules
and
Regulations
1
``
Consumption''
is
defined
as
the
amount
of
a
substance
produced
in
the
United
States,
plus
the
amount
imported
into
the
United
States,
minus
the
amount
exported
to
Parties
to
the
Montreal
Protocol
(
see
section
601(
6)
of
the
Clean
Air
Act).
Stockpiles
of
class
I
ODSs
produced
or
imported
prior
to
the
1996
phase
out
may
be
used
for
purposes
not
expressly
banned
at
40
CFR
part
82.
2
Class
I
ozone
depleting
substances
are
listed
at
40
CFR
part
82,
subpart
A,
appendix
A.
3
According
to
section
614(
b)
of
the
Act,
Title
VI
``
shall
be
construed,
interpreted,
and
applied
as
a
supplement
to
the
terms
and
conditions
of
the
Montreal
Protocol
*
*
*
and
shall
not
be
construed,
interpreted,
or
applied
to
abrogate
the
responsibilities
or
obligations
of
the
United
States
to
implement
fully
the
provisions
of
the
Montreal
Protocol.
In
the
case
of
conflict
between
any
provision
of
this
title
and
any
provision
of
the
Montreal
Protocol,
the
more
stringent
provision
shall
govern.''
EPA's
regulations
implementing
the
essential
use
provisions
of
the
Act
and
the
Protocol
are
located
in
40
CFR
part
82.
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
82
[
FRL
7430
7]
RIN
2060
AK48
Protection
of
Stratospheric
Ozone:
Allocation
of
Essential
Use
Allowances
for
Calendar
Year
2003
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Final
rule.
SUMMARY:
With
this
action,
EPA
is
allocating
essential
use
allowances
for
import
and
production
of
class
I
stratospheric
ozone
depleting
substances
(
ODSs)
for
calendar
year
2003.
Essential
use
allowances
enable
a
person
to
obtain
controlled
class
I
ODSs
as
an
exemption
to
the
regulatory
ban
of
production
and
import
of
these
chemicals,
which
became
effective
on
January
1,
1996.
EPA
allocates
essential
use
allowances
for
exempted
production
or
import
of
a
specific
quantity
of
class
I
ODS
solely
for
the
designated
essential
purpose.
Today
EPA
is
finalizing
the
allocations
proposed
in
the
Federal
Register
on
November
6,
2002
(
67
FR
67581).
These
allocations
total
3,270
metric
tons
of
chlorofluorocarbons
for
use
in
metered
dose
inhalers,
and
13.2
metric
tons
of
methyl
chloroform
for
use
in
the
U.
S.
Space
Shuttle
and
Titan
Rocket
programs.
DATES:
This
final
rulemaking
is
effective
December
27,
2002.
ADDRESSES:
Materials
relevant
to
this
rulemaking
are
contained
in
EPA
Air
Docket
No.
A
93
39.
The
Air
Docket
is
located
at
EPA
West
Building,
Room
B102,
1301
Constitution
Avenue,
NW.,
Washington,
DC,
20460.
The
Air
Docket
is
open
from
8:
30
a.
m.
until
4:
30
p.
m.
Monday
through
Friday.
EPA
may
charge
a
reasonable
fee
for
copying
docket
materials.
FOR
FURTHER
INFORMATION
CONTACT:
Scott
Monroe,
by
regular
mail:
U.
S.
Environmental
Protection
Agency,
Global
Programs
Division
(
6205J),
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC,
20460;
by
telephone:
(
202)
564
9712;
or
by
email:
monroe.
scott@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Table
of
Contents
I.
Basis
for
Allocating
Essential
Use
Allowances
A.
What
Are
Essential
Use
Allowances?
B.
Under
What
Authority
Does
EPA
Allocate
Essential
Use
Allowances?
C.
What
Is
the
Process
for
Allocating
Essential
Use
Allowances?
II.
Response
to
Comments
III.
Allocation
of
Essential
Use
Allowances
for
Calendar
Year
2003
IV.
Administrative
Requirements
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
B.
Paperwork
Reduction
Act
C.
Regulatory
Flexibility
Act
D.
Unfunded
Mandates
Reform
Act
E.
Executive
Order
13132:
Federalism
F.
Executive
Order
13175:
Consultation
and
Coordination
with
Indian
Tribal
Governments
G.
Executive
Order
13045:
Protection
of
Children
from
Environmental
Health
Risks
and
Safety
Risks
H.
Executive
Order
13211:
Actions
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
I.
National
Technology
Transfer
and
Advancement
Act
J.
Congressional
Review
Act
V.
Judicial
Review
I.
Basis
for
Allocating
Essential
use
Allowances
A.
What
Are
Essential
Use
Allowances?
Essential
use
allowances
are
allowances
to
produce
or
import
certain
ozone
depleting
chemicals
in
the
U.
S.
for
purposes
that
have
been
deemed
``
essential''
by
the
Parties
to
the
Montreal
Protocol
and
the
U.
S.
Government.
The
Montreal
Protocol
on
Substances
that
Deplete
the
Ozone
Layer
(
Protocol)
is
the
international
agreement
to
reduce
and
eventually
eliminate
the
production
and
consumption
1
of
all
stratospheric
ozone
depleting
substances
(
ODSs).
The
elimination
of
production
and
consumption
of
class
I
ODSs
is
accomplished
through
adherence
to
phase
out
schedules
for
specific
class
I
ODSs,
2
including:
chlorofluorocarbons
(
CFCs),
halons,
carbon
tetrachloride,
methyl
chloroform,
and
methyl
bromide.
As
of
January
1,
1996,
production
and
import
of
most
class
I
ODSs
were
phased
out
in
developed
countries,
including
the
United
States.
However,
the
Protocol
and
the
Clean
Air
Act
(
Act)
provide
exemptions
that
allow
for
the
continued
import
and/
or
production
of
class
I
ODS
for
specific
uses.
Under
the
Protocol,
exemptions
may
be
granted
for
uses
that
are
determined
by
the
Parties
to
be
``
essential.''
Decision
IV/
25,
taken
by
the
Parties
to
the
Protocol
in
1992,
established
criteria
for
determining
whether
a
specific
use
should
be
approved
as
essential,
and
set
forth
the
international
process
for
making
determinations
of
essentiality.
The
criteria
for
an
essential
use,
as
set
forth
in
paragraph
1
of
Decision
IV/
25,
are
the
following:
``(
a)
that
a
use
of
a
controlled
substance
should
qualify
as
``
essential''
only
if:
(
i)
it
is
necessary
for
the
health,
safety
or
is
critical
for
the
functioning
of
society
(
encompassing
cultural
and
intellectual
aspects);
and
(
ii)
there
are
no
available
technically
and
economically
feasible
alternatives
or
substitutes
that
are
acceptable
from
the
standpoint
of
environment
and
health;
(
b)
that
production
and
consumption,
if
any,
of
a
controlled
substance
for
essential
uses
should
be
permitted
only
if:
(
i)
all
economically
feasible
steps
have
been
taken
to
minimize
the
essential
use
and
any
associated
emission
of
the
controlled
substance;
and
(
ii)
the
controlled
substance
is
not
available
in
sufficient
quantity
and
quality
from
existing
stocks
of
banked
or
recycled
controlled
substances,
also
bearing
in
mind
the
developing
countries'
need
for
controlled
substances.''
B.
Under
What
Authority
Does
EPA
Allocate
Essential
Use
Allowances?
Title
VI
of
the
Act
implements
the
Protocol
for
the
United
States.
3
Section
604(
d)
of
the
Act
authorizes
EPA
to
allow
the
production
of
limited
quantities
of
class
I
ODSs
after
the
phase
out
date
for
the
following
essential
uses:
(
1)
Methyl
Chloroform,
``
solely
for
use
in
essential
applications
(
such
as
nondestructive
testing
for
metal
fatigue
and
corrosion
of
existing
airplane
engines
and
airplane
parts
susceptible
to
metal
fatigue)
for
which
no
safe
and
effective
substitute
is
available.''
EPA
issues
methyl
chloroform
allowances
to
the
U.
S.
Space
Shuttle
and
Titan
Rocket
programs.
(
2)
Medical
Devices
(
as
defined
in
section
601(
8)
of
the
Act),
``
if
such
authorization
is
determined
by
the
Commissioner
[
of
the
Food
and
Drug
Administration],
in
consultation
with
the
Administrator
[
of
EPA]
to
be
necessary
for
use
in
medical
devices.''
EPA
issues
allowances
to
manufacturers
of
metered
dose
inhalers,
which
use
CFCs
as
propellant
for
the
treatment
of
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/
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27,
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/
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and
Regulations
asthma
and
chronic
obstructive
pulmonary
diseases.
(
3)
Aviation
Safety,
for
which
limited
quantities
of
halon
1211,
halon
1301,
and
halon
2402
may
be
produced
``
if
the
Administrator
of
the
Federal
Aviation
Administration,
in
consultation
with
the
Administrator
[
of
EPA]
determines
that
no
safe
and
effective
substitute
has
been
developed
and
that
such
authorization
is
necessary
for
aviation
safety
purposes.''
Neither
EPA
nor
the
Parties
have
ever
granted
a
request
for
essential
use
allowances
for
halon,
because
alternatives
are
available,
or
because
existing
quantities
of
this
substance
are
large
enough
to
provide
for
any
needs
for
which
alternatives
have
not
yet
been
developed.
The
Protocol,
under
Decision
X/
19,
additionally
allows
a
general
exemption
for
laboratory
and
analytical
uses
through
December
31,
2005.
This
exemption
is
reflected
in
EPA's
regulations
at
40
CFR
part
82,
subpart
A.
While
the
Act
does
not
specifically
provide
for
this
exemption,
EPA
has
determined
that
an
allowance
for
essential
laboratory
and
analytical
uses
is
allowable
under
the
Act
as
a
de
minimis
exemption.
The
de
minimis
exemption
is
addressed
in
EPA's
final
rule
of
March
13,
2001
(
66
FR
14760
14770).
The
Parties
to
the
Protocol
subsequently
agreed
(
Decision
XI/
15)
that
the
general
exemption
does
not
apply
to
the
following
uses:
testing
of
oil
and
grease,
and
total
petroleum
hydrocarbons
in
water;
testing
of
tar
in
road
paving
materials;
and
forensic
finger
printing.
EPA
incorporated
this
exclusion
at
appendix
G
to
subpart
A
of
40
CFR
part
82
on
February
11,
2002
(
67
FR
6352).
C.
What
Is
the
Process
for
Allocating
Essential
Use
Allowances?
Before
EPA
may
allocate
essential
use
allowances,
the
Parties
to
the
Protocol
must
first
approve
the
United
States'
request
to
produce
or
import
essential
class
I
ODSs.
The
procedure
set
out
by
Decision
IV/
25
calls
for
individual
Parties
to
nominate
essential
uses
and
the
total
amount
of
ODSs
needed
for
those
essential
uses
on
an
annual
basis.
The
Protocol's
Technology
and
Economic
Assessment
Panel
evaluates
the
nominated
essential
uses
and
makes
recommendations
to
the
Protocol
Parties.
The
Parties
make
the
final
decisions
on
whether
to
approve
a
Party's
essential
use
nomination
at
their
annual
meeting.
This
nomination
cycle
occurs
approximately
two
years
before
the
year
in
which
the
allowances
would
be
in
effect.
The
allowances
allocated
through
today's
action
were
first
nominated
by
the
United
States
in
January
2001.
Once
the
U.
S.
nomination
is
approved
by
the
Parties,
EPA
allocates
essential
use
exemptions
to
specific
entities
through
notice
and
comment
rulemaking
in
a
manner
consistent
with
the
Act.
For
medical
devices,
EPA
requests
information
from
manufacturers
about
the
number
and
type
of
devices
they
plan
to
produce,
as
well
as
the
amount
of
CFCs
necessary
for
production.
EPA
then
forwards
the
information
to
the
Food
and
Drug
Administration
(
FDA),
which
determines
the
amount
of
CFCs
necessary
for
metered
dose
inhalers
in
the
coming
calendar
year.
Based
on
FDA's
assessment,
EPA
proposes
allocations
to
each
eligible
entity.
Under
the
Act
and
the
Protocol,
EPA
may
allocate
essential
use
allowances
in
quantities
that
together
are
below
or
equal
to
the
total
amount
approved
by
the
Parties.
EPA
may
not
allocate
essential
use
allowances
in
amounts
higher
than
the
total
approved
by
the
Parties.
For
methyl
chloroform,
Decision
X/
6
by
the
Parties
to
the
Protocol
established
that
``*
*
*
the
remaining
quantity
of
methyl
chloroform
authorized
for
the
United
States
at
previous
meetings
of
the
Parties
[
will]
be
made
available
for
use
in
manufacturing
solid
rocket
motors
until
such
time
as
the
1999
2001
quantity
of
176.4
tons
(
17.6
ODPweighted
tons)
allowance
is
depleted,
or
until
such
time
as
safe
alternatives
are
implemented
for
remaining
essential
uses.''
Section
604(
d)(
1)
of
the
Act
terminates
the
exemption
period
for
methyl
chloroform
on
January
1,
2005.
Therefore,
between
1999
and
2004
EPA
may
allow
production
or
import
up
to
a
total
of
176.4
metric
tons
of
methyl
chloroform
for
authorized
essential
uses.
According
to
EPA's
tracking
system,
the
total
amount
of
methyl
chloroform
produced
or
imported
by
essential
use
allowance
holders
in
the
years
1999
2001
was
28.3
metric
tons.
With
today's
allocation
totaling
13.2
tons,
the
U.
S.
remains
well
below
the
established
cap
on
allowances
for
methyl
choloroform.
II.
Response
to
Comments
EPA
received
one
comment
in
response
to
the
proposed
rule.
The
commenter
supported
the
proposed
allocations.
III.
Allocation
of
Essential
Use
Allowances
for
Calendar
Year
2003
With
today's
action,
EPA
is
allocating
essential
use
allowances
for
calendar
year
2003
to
entities
listed
in
Table
1.
These
allowances
are
for
the
production
or
import
of
the
specified
quantity
of
class
I
controlled
substances
solely
for
the
specified
essential
use.
TABLE
I.
ESSENTIAL
USE
ALLOCATION
FOR
CALENDAR
YEAR
2003
Company
Chemical
Quantity
(
metric
tons)
(
i)
Metered
Dose
Inhalers
(
for
oral
inhalation)
for
Treatment
of
Asthma
and
Chronic
Obstructive
Pulmonary
Disease
Armstrong
Pharmaceuticals
........................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
574
Aventis
........................................................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
48
Boehringer
Ingelheim
Pharmaceuticals
......................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
907
Glaxo
SmithKline
........................................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
535
Schering
Plough
Corporation
......................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
937
Sidmak
Laboratories
4
.................................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
136
3M
Pharmaceuticals
...................................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
133
(
ii)
Cleaning,
Bonding
and
Surface
Activation
Applications
for
the
Space
Shuttle
Rockets
and
Titan
Rockets
National
Aeronautics
and
Space
Administration
(
NASA)/
Thiokol
Rocket.
Methyl
Chloroform
......................................................................
9.8
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/
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27,
2002
/
Rules
and
Regulations
TABLE
I.
ESSENTIAL
USE
ALLOCATION
FOR
CALENDAR
YEAR
2003
Continued
Company
Chemical
Quantity
(
metric
tons)
United
States
Air
Force/
Titan
Rocket
.........................................
Methyl
Chloroform
......................................................................
3.4
4
EPA
proposed
to
allocate
allowances
to
Sidmak
Laboratories,
Inc.
for
136
metric
tons
for
use
in
2003.
Following
publication
of
the
proposal,
Sidmak
was
purchased
by
the
pharmaceutical
firm
PLIVA
d.
d.
In
2003,
a
subsidiary
of
PLIVA
d.
d.
reportedly
will
replace
Sidmak
Laboratories,
thereby
acquiring
Sidmak's
essential
use
allowances.
A
letter
to
EPA
describing
the
purchase
and
PLIVA's
commitment
to
execute
essential
use
allowances
in
accordance
with
EPA
regulations
and
Sidmak's
application
for
allowances
has
been
filed
in
Air
Docket
A
93
39,
Category
XII
A.
IV.
Administrative
Requirements
A.
Executive
Order
12866:
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
the
Agency
must
determine
whether
this
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
Office
of
Management
and
Budget
(
OMB)
and
the
requirements
of
the
Executive
Order.
The
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
(
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.
It
has
been
determined
that
this
action
is
not
a
``
significant
regulatory
action''
under
the
terms
of
Executive
Order
12866
and
is
therefore
not
subject
to
OMB
review.
B.
Paperwork
Reduction
Act
This
action
does
not
add
any
information
collection
requirements
or
increase
burden
under
the
provisions
of
the
Paperwork
Reduction
Act,
44
U.
S.
C.
3501
et
seq.
OMB
previously
approved
the
information
collection
requirements
contained
in
the
final
rule
promulgated
on
May
10,
1995,
and
assigned
OMB
control
number
2060
0170
(
EPA
ICR
No.
1432.21).
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instruction;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
An
Agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
1.
C.
Regulatory
Flexibility
Act
EPA
has
determined
that
it
is
not
necessary
to
prepare
a
regulatory
flexibility
analysis
in
connection
with
this
final
rule.
EPA
has
also
determined
that
this
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
For
purposes
of
assessing
the
impact
of
today's
rule
on
small
entities,
small
entities
are
defined
as:
(
1)
Pharmaceutical
preparations
manufacturing
businesses
(
NAICS
code
325412)
that
have
less
than
750
employees;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city,
county,
town,
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
forprofit
enterprise
that
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
After
considering
the
economic
impacts
of
today's
final
rule
on
small
entities,
EPA
has
concluded
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
In
determining
whether
a
rule
has
a
significant
economic
impact
on
a
substantial
number
of
small
entities,
the
impact
of
concern
is
any
significant
adverse
economic
impact
on
small
entities,
since
the
primary
purpose
of
the
regulatory
flexibility
analyses
is
to
identify
and
address
regulatory
alternatives
``
which
minimize
any
significant
economic
impact
of
the
proposed
rule
on
small
entities.''
5
U.
S.
C.
603
and
604.
Thus,
an
agency
may
conclude
that
a
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities
if
the
rule
relieves
regulatory
burden,
or
otherwise
has
a
positive
economic
effect
on
all
of
the
small
entities
subject
to
the
rule.
This
rule
provides
an
otherwise
unavailable
benefit
to
those
companies
that
are
receiving
essential
use
allowances.
We
have
therefore
concluded
that
today's
final
rule
will
relieve
regulatory
burden
for
all
small
entities.
D.
Unfunded
Mandates
Reform
Act
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Pub.
L.
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
one
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective,
or
least
burdensome
alternative,
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
a
small
government
agency
plan
under
section
203
of
the
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Regulations
UMRA.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
Today's
rule
contains
no
Federal
mandates
(
under
the
regulatory
provisions
of
Title
II
of
the
UMRA)
for
State,
local,
or
tribal
governments
or
the
private
sector,
since
it
merely
provides
exemptions
from
the
1996
phase
out
of
class
I
ODSs.
Similarly,
EPA
has
determined
that
this
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquely
affect
small
governments,
because
this
rule
merely
allocates
essential
use
exemptions
to
entities
as
an
exemption
to
the
ban
on
production
and
import
of
class
I
ODSs.
E.
Executive
Order
13132:
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
This
final
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
Thus,
Executive
Order
13132
does
not
apply
to
this
rule.
F.
Executive
Order
13175:
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
9,
2000),
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
This
final
rule
does
not
have
tribal
implications,
as
specified
in
Executive
Order
13175.
Today's
rule
affects
only
the
companies
that
requested
essential
use
allowances.
Thus,
Executive
Order
13175
does
not
apply
to
this
rule.
G.
Executive
Order
13045:
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045,
``
Protection
of
Children
from
Environmental
Health
risks
and
Safety
Risks''
(
62
FR
19885,
April
23,
1997),
applies
to
any
rule
that
(
1)
is
determined
to
be
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
and
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
the
Agency
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.
EPA
interprets
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
501
of
the
Order
has
the
potential
to
influence
the
regulation.
This
rule
is
not
subject
to
Executive
Order
13045
because
it
implements
the
phase
out
schedule
and
exemptions
established
by
Congress
in
Title
VI
of
the
Clean
Air
Act.
H.
Executive
Order
13211:
Actions
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
This
rule
is
not
subject
to
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
(
66
FR
28355,
May
22,
2001)
because
it
is
not
a
significant
regulatory
action
under
Executive
Order
12866.
I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(``
NTTAA),
Pub.
L.
104
113,
section
12(
d)
(
15
U.
S.
C.
272
note)
directs
EPA
to
use
voluntary
consensus
standards
in
this
regulatory
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
and
business
practices)
that
are
developed
or
adopted
by
voluntary
consensus
standards
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
OMB,
explanations
when
the
Agency
decides
not
to
use
available
and
applicable
voluntary
consensus
standards.
This
final
rule
does
not
involve
technical
standards.
Therefore,
EPA
did
not
consider
the
use
of
any
voluntary
consensus
standards.
J.
Congressional
Review
Act
The
Congressional
Review
Act,
5
U.
S.
C.
801
et
seq.,
as
added
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996,
generally
provides
that
before
a
rule
may
take
effect,
the
agency
promulgating
the
rule
must
submit
a
rule
report,
which
includes
a
copy
of
the
rule,
to
each
House
of
the
Congress
and
to
the
Comptroller
General
of
the
United
States.
Therefore,
EPA
will
submit
a
report
containing
this
rule
and
other
required
information
to
the
U.
S.
Senate,
the
U.
S.
House
of
Representatives,
and
the
Comptroller
General
of
the
United
States
prior
to
publication
of
the
rule
in
the
Federal
Register.
This
rule
is
not
a
``
major
rule''
as
defined
by
5
U.
S.
C.
804(
2).
This
rule
will
be
effective
December
27,
2002.
V.
Judicial
Review
Under
section
307(
b)(
1)
of
the
Act,
EPA
finds
that
these
regulations
are
of
national
applicability.
Accordingly,
judicial
review
of
the
action
is
available
only
by
the
filing
of
a
petition
for
review
in
the
United
States
Court
of
Appeals
for
the
District
of
Columbia
Circuit
within
sixty
days
of
publication
of
the
action
in
the
Federal
Register.
Under
section
307(
b)(
2),
the
requirements
of
this
rule
may
not
be
challenged
later
in
judicial
proceedings
brought
to
enforce
those
requirements.
List
of
Subjects
in
40
CFR
Part
82
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Chemicals,
Chlorofluorocarbons,
Exports,
Imports,
Laboratory
and
Analytical
Uses,
Methyl
Chloroform,
Ozone
layer,
Reporting
and
recordkeeping
requirements.
Dated:
December
19,
2002.
Christine
Todd
Whitman,
Administrator.
40
CFR
Part
82
is
amended
as
follows:
PART
82
PROTECTION
OF
STRATOSPHERIC
OZONE
1.
The
authority
citation
for
part
82
continues
to
read
as
follows:
Authority:
42
U.
S.
C.
7414,
7601,
7671
7671q.
Subpart
A
Production
and
Consumption
Controls
2.
Section
82.4
is
amended
by
revising
the
table
in
paragraph
(
t)(
2)
to
read
as
follows:
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Federal
Register
/
Vol.
67,
No.
249
/
Friday,
December
27,
2002
/
Rules
and
Regulations
§
82.4
Prohibitions.
*
*
*
*
*
(
t)
*
*
*
(
2)
*
*
*
TABLE
I.
ESSENTIAL
USE
ALLOCATION
FOR
CALENDAR
YEAR
2003
Company
Chemical
Quantity
(
metric
tons)
(
i)
Metered
Dose
Inhalers
(
for
oral
inhalation)
for
Treatment
of
Asthma
and
Chronic
Obstructive
Pulmonary
Disease
Armstrong
Pharmaceuticals
........................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
574
Aventis
........................................................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
48
Boehringer
Ingelheim
Pharmaceuticals
......................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
907
GlaxoSmithKline
..........................................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
535
Schering
Plough
Corporation
......................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
937
Sidmak
Laboratories
...................................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
136
3M
Pharmaceuticals
...................................................................
CFC
11
or
CFC
12
or
CFC
114
..............................................
133
(
ii)
Cleaning,
Bonding
and
Surface
Activation
Applications
for
the
Space
Shuttle
Rockets
and
Titan
Rockets
National
Aeronautics
and
Space
Administration
(
NASA)/
Thiokol
Rocket.
Methyl
Chloroform
......................................................................
9.8
United
States
Air
Force/
Titan
Rocket
.........................................
Methyl
Chloroform
......................................................................
3.4
*
*
*
*
*
[
FR
Doc.
02
32719
Filed
12
26
02;
8:
45
am]
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"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0095-0001/content.txt"
} |
EPA-HQ-OAR-2002-0096-0001 | Proposed Rule | "2002-12-31T05:00:00" | National Ambient Air Quality Standard: Particulate Matter | 80329
Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Proposed
Rules
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
58
[
AD
FRL
7388
3]
RIN
2060
AK05
National
Ambient
Air
Quality
Standard:
Particulate
Matter
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Proposed
rule.
SUMMARY:
EPA
is
taking
direct
final
action
to
revise
the
national
ambient
air
quality
standards
for
particulate
matter.
This
requirement
describes
the
number
of
collocated
sites
required
within
a
reporting
organization.
In
the
``
Rules
and
Regulations''
section
of
today's
Federal
Register,
we
are
approving
revisions
to
``
Quality
Assurance
Requirements
for
State
and
Local
Air
Monitoring
Stations''
(
SLAMS)
as
a
direct
final
rule
without
prior
proposal
because
we
view
this
as
a
noncontroversial
revision
and
anticipate
no
adverse
comment.
We
have
explained
our
reasons
for
this
approval
in
the
preamble
to
the
direct
final
rule.
If
we
receive
adverse
comment,
we
will
withdraw
the
direct
final
rule
and
it
will
not
take
effect.
We
will
address
all
public
comments
in
a
subsequent
final
rule
based
on
this
proposed
rule.
We
will
not
institute
a
second
comment
period
on
this
action.
Any
parties
interested
in
commenting
must
do
so
at
this
time.
DATES:
Comments
must
be
submitted
on
or
before
March
3,
2003.
ADDRESSES:
Written
comments
should
be
submitted
(
in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(
6102),
Attention:
Docket
No.
A96
51,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460.
In
person
or
by
courier,
deliver
comments
(
in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(
6102),
Attention
Docket
A96
51,
U.
S.
EPA,
401
M
Street,
SW.,
Washington,
DC
20460.
We
request
that
you
send
a
separate
copy
of
your
comments
to
Mr.
Michael
Papp,
Monitoring
and
Quality
Assurance
Group
(
C339
02),
Emissions,
Monitoring,
and
Analysis
Division,
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
North
Carolina
27711.
FOR
FURTHER
INFORMATION
CONTACT:
For
information
concerning
the
proposed
rule,
contact
Mr.
Michael
Papp,
Monitoring
and
Quality
Assurance
Group
(
C339
02),
Emissions,
Monitoring,
and
Analysis
Division,
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
North
Carolina
27711,
telephone
number
(
919)
541
2408.
SUPPLEMENTARY
INFORMATION:
This
document
concerns
revising
the
national
ambient
air
quality
standards
for
particulate
matter,
40
CFR
part
58,
appendix
A,
section
3.5.2.
For
further
information,
please
see
the
information
provided
in
the
direct
final
action
that
is
located
in
the
``
Rules
and
Regulations''
section
of
this
Federal
Register
publication.
Dated:
December
18,
2002.
Christine
Todd
Whitman,
Administrator.
[
FR
Doc.
02
32385
Filed
12
30
02;
8:
45
am]
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"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0096-0001/content.txt"
} |
EPA-HQ-OAR-2002-0097-0001 | Rule | "2002-12-31T05:00:00" | National Ambient Air Quality Standard: Particulate Matter; Direct Final Rule | Tuesday,
December
31,
2002
Part
VI
Environmental
Protection
Agency
40
CFR
Part
58
National
Ambient
Air
Quality
Standard:
Particulate
Matter;
Final
Rule
and
Proposed
Rule
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Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Part
58
[
AD
FRL
7388
4]
RIN
2060
AK05
National
Ambient
Air
Quality
Standard:
Particulate
Matter
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Direct
final
rule.
SUMMARY:
The
EPA
is
taking
direct
final
action
to
amend
the
national
ambient
air
quality
standards
for
particulate
matter.
The
revision
reduces
to
15
percent
the
requirement
that
reporting
organizations
collocate
25
percent
of
State
and
local
air
monitoring
station
(
SLAMS)
sites
with
a
second
sampler
in
order
to
estimate
precision
at
a
reporting
organization
level.
The
regulations
describe
the
number
of
collocated
sites
required
within
a
reporting
organization.
With
today's
action,
EPA
is
making
a
simple
change
in
the
regulations
by
changing
the
requirement
to
collocate
25
percent
of
reporting
organizations
sites
to
15
percent
of
the
reporting
organizations
sites.
The
effect
of
this
change
will
be
to
reduce
the
number
of
monitors
which
must
be
collocated.
This
in
turn
will
reduce
the
cost
of
implementing
and
maintaining
monitoring
networks
but
without
significantly
affecting
our
confidence
in
the
precision
at
the
reporting
organization
level
or
in
providing
acceptable
estimates
of
achievement
of
the
precision
Data
Quality
Objectives
(
DQOs).
Since
reporting
organizations
are
of
unequal
size
in
the
number
of
monitors
they
implement,
15
percent
was
considered
an
acceptable
limit
of
providing
enough
precision
information
for
smaller
reporting
organizations
while
not
unduly
burdening
larger
reporting
organizations.
DATES:
This
direct
final
rule
will
be
effective
on
March
31,
2003
without
further
notice,
unless
significant
adverse
comments
are
received
by
January
30,
2003.
If
significant
adverse
comments
are
received,
we
will
publish
a
timely
withdrawal
in
the
Federal
Register
informing
the
public
that
this
rule
will
not
take
effect.
ADDRESSES:
Written
comments
should
be
submitted
(
in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(
6102),
Attention:
Docket
No.
A96
51,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460.
In
person
or
by
courier,
deliver
comments
(
in
duplicate
if
possible)
to:
Air
and
Radiation
Docket
and
Information
Center
(
6102),
Attention
Docket
A96
51,
U.
S.
EPA,
401
M
Street,
SW.,
Washington,
DC
20460.
We
request
that
you
send
a
separate
copy
of
your
comments
to
Mr.
Michael
Papp,
Monitoring
and
Quality
Assurance
Group
(
C339
02),
Emissions,
Monitoring,
and
Analysis
Division,
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
North
Carolina
27711.
FOR
FURTHER
INFORMATION
CONTACT:
For
information
concerning
the
direct
final
rule,
contact
Mr.
Michael
Papp,
Monitoring
and
Quality
Assurance
Group
(
C339
02),
Emissions,
Monitoring,
and
Analysis
Division,
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
North
Carolina
27711,
telephone
number
(
919)
541
2408.
SUPPLEMENTARY
INFORMATION:
We
are
publishing
this
direct
final
without
prior
proposal
because
we
view
this
as
noncontroversial
and
do
not
anticipate
adverse
comments.
However,
in
the
Proposed
Rule
section
of
this
Federal
Register,
we
are
publishing
a
separate
document
that
will
serve
as
the
proposal
in
the
event
that
adverse
comments
are
filed.
If
we
receive
any
significant
adverse
comments,
we
will
publish
a
timely
withdrawal
in
the
Federal
Register
informing
the
public
that
this
direct
final
rule
will
not
take
effect.
We
will
address
all
public
comments
in
a
subsequent
final
rule
based
on
the
proposed
rule.
We
will
not
institute
a
second
comment
period
on
this
direct
final
rule.
Any
parties
interested
in
commenting
must
do
so
at
this
time.
Docket.
The
docket
is
an
organized
and
complete
file
of
information
compiled
by
EPA
in
developing
this
direct
final
rule.
The
docket
is
a
dynamic
file
because
material
is
added
throughout
the
rulemaking
process.
The
docketing
system
is
intended
to
allow
members
of
the
public
and
industries
involved
to
readily
identify
and
locate
documents
so
that
they
can
effectively
participate
in
the
rulemaking
process.
Along
with
the
proposed
and
promulgated
standards
and
their
preambles,
the
docket
contains
the
record
in
the
case
of
judicial
review.
The
docket
number
for
this
rulemaking
is
A
96
51.
Worldwide
Web
(
WWW).
In
addition
to
being
available
in
the
docket,
electronic
copies
of
this
action
will
be
posted
on
the
Technology
Transfer
Network
(
TTN).
Following
signature,
we
will
post
a
copy
of
the
supplemental
proposal
on
the
Air
Monitoring
Technology
Information
Center's
TTN
Web
site
at
http://
www.
epa.
gov/
ttn/
amtic/
pmcfr.
html
under
the
title
``
PM
2.5
Collocated
Precision
Reduction.''
The
TTN
provides
information
and
technology
exchange
in
various
areas
of
air
pollution
control.
If
you
need
more
information
regarding
the
TTN,
call
the
TTN
HELP
line
at
(
919)
541
5384.
Authority.
Sections
110,
301(
a),
and
319
of
the
Clean
Air
Act,
as
amended,
42
U.
S.
C.
7410,
7601
(
a),
7619.
I.
Background
The
Clean
Air
Act
as
amended
(
1990
Amendments),
established
requirements
for
States
to
prepare
and
submit
State
Implementation
plans
(
SIPs)
to
EPA
to
implement
and
enforce
national
ambient
air
quality
standards
(
NAAQS).
42
U.
S.
C.
7401
et
seq.
Specifically,
section
110
of
the
Clean
Air
Act
(
Act)
identifies
particular
requirements
for
these
SIPs
and
lists
the
elements
which
each
must
contain
in
order
to
be
approvable
by
EPA.
Included
in
these
provisions
is
the
requirement
that
each
SIP:
provide
for
establishment
and
operation
of
appropriate
devices,
methods,
systems,
and
procedures
necessary
to
(
i)
monitor,
compile,
and
analyze
data
on
ambient
air
quality,
and
(
ii)
upon
request,
make
such
data
available
to
the
Administrator;
42
U.
S.
C
7410(
a)(
2)(
B).
Any
air
quality
monitoring
systems
required
in
such
SIP's
were
further
required
to
utilize
standard
criteria
and
methodologies
established
by
regulations
to
be
promulgated
by
EPA
pursuant
to
section
319
of
the
Act.
When
EPA
promulgated
NAAQS
for
fine
particulate
matter
(
PM
2.5),
it
also
adopted
regulations
for
air
sampling
(
62
FR
38833,
July
18,
1997).
These
regulations
included
quality
assurance
(
QA)
requirements
in
Appendix
A
based
on
data
quality
objectives
developed
using
PM
2.5
data
available
in
EPA's
Aerometric
Information
Retrieval
System
(
AIRS)
and
other
sources
prior
to
the
July
18,
1997
rulemaking.
These
QA
objectives
were
developed
to
ensure
that
decision
makers
would
have
PM
2.5
data
of
adequate
quality
to
support
important
decisions
such
as
the
comparison
to
the
PM
2.5
NAAQS.
In
response
to
complaints
that
arose
under
previous
regulations
about
the
burden
of
QA
requirements,
62
FR
38767,
July
18,
1997
section
IV,
``
Discussion
of
Regulatory
Revisions
and
Major
Comments
on
Part
58,''
EPA
stated
that
``[
i]
n
an
effort
to
assist
State
and
local
agencies
in
achieving
the
data
quality
objectives
of
the
PM
2.5
monitoring
program,
an
incentive
program
has
been
established
that
is
based
on
network
performance
and
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Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
maturity
that
can
reduce
these
QA
requirements.''
Within
40
CFR
part
58,
appendix
A
data
quality
objectives
for
precision
(
10
percent)
and
bias
(
±
10
percent)
were
identified.
In
order
to
meet
the
precision
data
quality
objective,
reporting
organizations
are
currently
required
by
the
regulations
to
collocate
25
percent
of
the
monitoring
sites
with
a
second
federal
reference
method
monitor.
This
second
monitor
would
collect
a
sample
every
6
days.
The
data
quality
objective
is
assessed
using
3
years
of
this
collocated
information,
which
would
provide
approximately
182
values
for
any
one
site.
Over
the
data
collection
years
of
1999
and
2000,
EPA
performed
data
quality
assessments
on
PM
2.5
data
and
found
that
the
majority
of
the
reporting
organizations
are
achieving
the
precision
data
quality
objective.
In
2001,
EPA
also
reviewed
the
original
1997
data
quality
objectives
using
the
1999
and
2000
PM
2.5
data
set.
Using
this
more
robust
data
set,
EPA
determined
that
the
precision
data
quality
objective
was
less
influential
on
decision
errors
than
the
bias
data
quality
objective
and
therefore
greater
imprecision
could
be
tolerated
in
the
network
without
adverse
effect
on
overall
uncertainty
and
therefore
decision
making.
Based
on
the
data
quality
assessments
and
the
evaluation
of
the
original
data
quality
objective,
EPA
concluded
that
a
reduction
in
the
precision
siting
requirement
would
not
significantly
affect
confidence
in
precision
estimates
at
the
reporting
organization
level
or
in
providing
acceptable
estimates
of
achievement
of
the
precision
DQO.
Therefore,
in
keeping
with
the
commitment
established
in
the
July
18,
1997
Federal
Register
document,
EPA
has
determined
that
it
would
be
appropriate
to
reduce
the
monitor
collocation
requirements.
We
view
these
amendments
as
noncontroversial
and
anticipate
no
adverse
comments,
and
we
are
publishing
these
amendments
in
a
direct
final
rule.
II.
Administrative
Requirements
A.
Executive
Order
12866,
Regulatory
Planning
and
Review
Under
Executive
Order
12866
(
58
FR
51735,
October
4,
1993),
we
must
determine
whether
a
regulatory
action
is
``
significant''
and
therefore
subject
to
review
by
the
Office
of
Management
and
Budget
(
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
obligation
of
recipients
thereof;
or
(
4)
Raise
novel
legal
or
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
We
have
determined
that
this
direct
final
rule
does
not
qualify
as
a
``
significant
regulatory
action''
under
the
terms
of
Executive
Order
12866
and
therefore,
is
not
subect
to
review
by
OMB.
B.
Executive
Order
13211,
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution
or
Use.
This
direct
final
rule
is
not
subject
to
Executive
Order
13211
(
66
FR
28355,
May
22,
2001)
because
it
is
not
a
significant
regulatory
action
under
Executive
Order
12866.
C.
Executive
Order
13132,
Federalism
Executive
Order
13132,
entitled
``
Federalism''
(
64
FR
43255,
August
10,
1999),
requires
that
we
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications.''
``
Policies
that
have
federalism
implications''
is
defined
in
the
Executive
Order
to
include
regulations
that
have
``
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government.''
Under
section
6
of
Executive
Order
13132,
we
may
not
issue
a
regulation
that
has
federalism
implications,
that
imposes
substantial
direct
compliance
costs,
and
that
is
not
required
by
statute,
unless
the
Federal
government
provides
the
funds
necessary
to
pay
the
direct
compliance
costs
incurred
by
the
State
and
local
governments,
or
we
consult
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
We
also
may
not
issue
a
regulation
that
has
federalism
implications
and
that
preempts
State
law
unless
we
consult
with
State
and
local
officials
early
in
the
process
of
developing
the
proposed
regulation.
This
direct
final
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government,
as
specified
in
Executive
Order
13132.
This
rule
is
a
revision
to
an
existing
rule
governing
the
requirements
for
State
and
local
monitoring
networks
and
reduces
the
burden
on
affected
States.
Thus,
the
requirements
of
section
6
of
the
Executive
Order
do
not
apply
to
this
direct
final
rule.
D.
Executive
Order
13175,
Consultation
and
Coordination
With
Indian
Tribal
Governments
Executive
Order
13175,
entitled
``
Consultation
and
Coordination
with
Indian
Tribal
Governments''
(
65
FR
67249,
November
9,
2000)
requires
EPA
to
develop
an
accountable
process
to
ensure
``
meaningful
and
timely
input
by
tribal
officials
in
the
development
of
regulatory
policies
that
have
tribal
implications.''
This
direct
final
rule
does
not
impose
substantial
direct
compliance
costs
but
lessens
the
existing
requirements
on
the
tribal
governments.
This
rule
revises
an
existing
regulation
which
details
the
requirements
for
State,
local
and
tribal
air
monitoring
networks.
Accordingly,
the
requirements
of
Executive
Order
13175
do
not
apply
to
this
action.
E.
Executive
Order
13045,
Protection
of
Children
From
Environmental
Health
Risks
and
Safety
Risks
Executive
Order
13045
(
62
FR
19885,
April
23,
1997)
applies
to
any
rule
that
we
determine
(
1)
is
``
economically
significant''
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
the
Agency
must
evaluate
the
environmental
health
or
safety
effects
of
the
planned
rule
on
children,
and
explain
why
the
planned
regulation
is
preferable
to
other
potentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.
We
interpret
Executive
Order
13045
as
applying
only
to
those
regulatory
actions
that
are
based
on
health
or
safety
risks,
such
that
the
analysis
required
under
section
5
501
of
the
Order
has
the
potential
to
influence
the
regulation.
This
proposed
rule
is
not
subject
to
Executive
Order
13045
because
this
does
not
establish
an
environmental
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Federal
Register
/
Vol.
67,
No.
251
/
Tuesday,
December
31,
2002
/
Rules
and
Regulations
standard
intended
to
mitigate
health
or
safety
risks.
F.
Unfunded
Mandates
Reform
Act
of
1995
Title
II
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRA),
Pub.
L.
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
their
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
202
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
``
Federal
mandates''
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
in
any
1
year.
Before
promulgating
an
EPA
rule
for
which
a
written
statement
is
needed,
section
205
of
the
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
costeffective
or
least
burdensome
alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
tribal
governments,
it
must
have
developed
under
section
203
of
the
UMRA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating,
and
advising
small
governments
on
compliance
with
the
regulatory
requirements.
We
have
determined
that
this
direct
final
rule
does
not
include
a
Federal
mandate
that
may
result
in
estimated
costs
of
$
100
million
or
more
to
either
State,
local,
or
tribal
governments
in
the
aggregate,
or
to
the
private
sector
in
any
1
year.
This
rule
does
not
impose
new
requirements,
but
rather
reduces
somewhat
the
requirements
of
existing
regulations
for
State
and
local
air
monitoring
networks.
We
have
also
determined
that
this
rule
does
not
significantly
or
uniquely
impact
small
governments.
Therefore,
the
requirements
of
the
Unfunded
Mandates
Act
do
not
apply
to
this
rule.
G.
Regulatory
Flexibility
Act
(
RFA),
as
Amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
U.
S.
C.
601
et
seq.
The
RFA
generally
requires
that
we
conduct
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedures
Act
or
any
other
statute
unless
the
Agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
This
direct
final
rule
does
not
have
a
significant
impact
on
a
substantial
number
of
small
entities
because
no
additional
cost
will
be
incurred
by
such
entities
because
of
the
changes
specified
by
the
rule.
The
rule
reduces
the
requirements
for
the
number
of
sites
at
which
collocated
monitors
are
required.
Therefore,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
H.
Paperwork
Reduction
Act
This
proposed
rule
does
not
contain
any
information
collection
requirements
subject
to
the
Office
of
Management
and
Budget
review
under
the
Paperwork
Reduction
Act
of
1980,
44
U.
S.
C.
3501
et
seq.
I.
National
Technology
Transfer
and
Advancement
Act
Section
12(
d)
of
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(``
NTTAA''),
Pub.
L.
104
113,
§
12(
d)
(
15
U.
S.
C.
272
note)
directs
EPA
to
use
voluntary
consensus
standards
in
its
regulatory
activities
unless
to
do
so
would
be
inconsistent
with
applicable
law
or
otherwise
impractical.
Voluntary
consensus
standards
are
technical
standards
(
e.
g.,
materials
specifications,
test
methods,
sampling
procedures,
and
business
practices)
that
are
developed
or
adopted
by
voluntary
consensus
standards
bodies.
The
NTTAA
directs
EPA
to
provide
Congress,
through
OMB,
explanations
when
the
Agency
decides
not
to
use
available
and
applicable
voluntary
consensus
standards.
In
this
direct
final
rule
there
is
no
consensus
standard
for
the
setting
of
a
precision
requirement
for
a
monitoring
network.
The
determination
of
the
confidence
needed
in
the
estimates
derived
for
a
particular
monitoring
network
determine
the
amount
and
quality
of
the
precision
information.
EPA
used
accepted
statistical
practices
for
the
generation
of
the
number
of
collocated
sites
it
felt
was
appropriate
for
use
in
the
network
and
used
similar
techniques
for
determining
that
the
requirement
could
be
reduced.
J.
Congressional
Review
Act
The
Congressional
Review
Act,
5
U.
S.
C.
801,
et
seq.,
as
added
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996,
generally
provides
that
before
a
rule
may
take
effect,
the
agency
promulgating
the
rule
must
submit
a
rule
report,
which
includes
a
copy
of
the
rule,
to
each
House
of
the
Congress
and
to
the
Comptroller
General
of
the
United
States.
We
will
submit
a
report
containing
this
direct
final
rule
and
other
required
information
to
the
U.
S.
Senate,
the
U.
S.
House
of
Representatives,
and
the
Comptroller
General
of
the
United
States
prior
to
publication
of
this
direct
final
rule
in
the
Federal
Register.
A
major
rule
cannot
take
effect
until
60
days
after
it
is
published
in
the
Federal
Register.
This
direct
final
is
not
a
``
major
rule''
as
defined
by
5
U.
S.
C.
804(
2).
List
of
Subjects
in
40
CFR
Part
58
Environmental
protection,
Air
pollution
control,
Reporting
and
recordkeeping
requirements.
Dated:
December
18,
2002.
Christine
Todd
Whitman,
Administrator.
For
the
reasons
set
forth
in
the
preamble,
title
40,
chapter
I,
is
amended
as
follows:
PART
58
[
AMENDED]
1.
The
authority
citation
for
part
58
continues
to
read
as
follows:
42
U.
S.
C.
7401,
7416,
7601,
and
7619.
2.
In
Appendix
A
to
part
58,
section
3.5.2
is
amended
by
revising
paragraph
(
a)(
1)
to
read
as
follows:
Appendix
A
to
Part
58
Quality
Assurance
Requirements
for
State
and
Local
Air
Monitoring
Stations
(
SLAMS)
*
*
*
*
*
3.5.2
*
*
*
(
a)
*
*
*
(
1)
Have
15
percent
of
the
monitors
collocated
(
values
of
.5
and
greater
round
up).
*
*
*
*
*
[
FR
Doc.
02
32384
Filed
12
30
02;
8:
45
am]
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CODE
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"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2002-0097-0001/content.txt"
} |
EPA-HQ-OAR-2003-0017-0001 | Supporting & Related Material | "2002-05-08T04:00:00" | null | Y
"
4
Jz
B
U/
UNITED
STATES
ENVIRONMENTAL
PROTECTION
AGENCY
WASHINGTON,
D.
C.
20460
Application
for
Critical
Use
Exemption
of
Methyl
Bromide
for
Use
in
2005
in
the
United
States
WHY
IS
THIS
I
N
F
0
RM
AT
I
0
N
NEEDED?
Under
the
Clean
Air
Act
and
the
international
treaty
to
protect
the
ozone
layer
(
the
Montreal
Protocol
on
Substances
that
Deplete
the
Ozone
Layer),
the
production
and
import
of
methyl
bromide
will
be
phased
out
in
the
United
States
on
January
1,
2005.
This
application
seeks
information
to
support
a
U.
S.
request
to
produce
and
import
methyl
bromide
for
certain
critical
uses
and
circumstances
beyond
this
2005
phaseout
date.
The
information
in
this
application
will
be
used
to
review
whether
your
use
of
methyl
bromide
is
"
critical"
because
no
technically
and
economically
feasible
alternatives
are
available.
In
order
to
estimate
the
loss
as
a
result
of
not
having
methyl
bromide
available,
EPA
needs
to
compare
data
(
yields,
cropkommodity
prices,
revenues
and
costs)
for
your
use
of
methyl
bromide
with
uses
of
alternative
pest
control
regimens.
If
you
submit
a
well
documented
application
with
sound
reasons
why
alternatives
are
not
technically
and
economically
feasible,
the
U.
S.
government
can
be
a
better
advocate
for
your
exemption
request
internationally.
Click
on
the
Instructions
tab
located
at
the
bottom
of
the
screen
for
additional
information.
h
,
"
,
EPA
AIR
DOCKET
.
I
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information:
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
Public
reporting
burden
for
this
collection
of
information
is
estimated
to
average
324
hours
per
response
and
assumes
a
large
portion
of
applications
will
be
submitted
by
consortia
on
behalf
of
many
individual
users
of
methyl
bromide.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
current
OMB
control
number.
OMB
Control
#
2060
0482
UNITED
STATES
ENVIRONMENTAL
PROTECTION
AGENCY
WASHINGTON,
D.
C.
20460
INSTRUCTIONS
The
information
provided
by
you
in
this
application
will
be
used
to
evaluate
the
requested
methyl
bromide
use.
The
US.
and
other
countries
that
are
parties
to
the
Montreal
Protocol
On
Substances
That
Deplete
The
Ozone
Layer
decided
that:
"
a
use
of
methyl
bromide
should
qualify
as
"
critical"
only
if
the
nominating
Party
determines
that:
(
i)
The
specific
use
is
critical
because
the
lack
of
availability
of
methyl
bromide
for
that
use
would
result
in
a
significant
market
disruption;
and
(
ii)
There
are
no
technically
and
economically
feasible
alternatives
available
to
the
user
that
are
acceptable
from
the
standpoint
of
environment
and
health
and
are
suitable
to
the
crops
and
circumstances
of
the
nomination
...'
I
APPLIES?
r
CONTACTS
I
APPLY?
I
L
OMB
Control
#
If
you
anticipate
that
you
will
need
methyl
bromide
in
2005
because
you
believe
there
are
no
technically
and
economically
feasible
alternatives,
then
you
should
apply
for
the
critical
use
exemption.
This
application
may
be
submitted
either
by
a
consortium
representing
multiple
users
or
by
individual
users.
We
encourage
users
with
similar
circumstances
of
use
to
submit
a
single
application
(
for
example,
any
number
of
pre
plant
users
with
similar
soil,
pest,
and
climactic
conditions
can
submit
a
single
application.)
If
a
consortium
is
applying
for
multiple
methyl
bromide
users,
the
economic
data
should
be
for
a
representativc
or
typical
user
within
the
consortium
unless
otherwise
noted.
If
economic
or
technical
factors
(
such
as
size
of
the
farm)
affecting
the
ability
of
this
"
representative
user"
to
use
alternatives
are
significantly
different
than
other
users
in
the
consortium,
more
than
one
application
should
be
submitted
to
reflect
these
differences.
Please
contact
your
local,
state,
regional
or
national
commodity
association
and/
or
state
representative
agenc;
to
find
out
if
they
plan
on
submitting
an
application
on
behalf
of
your
commodity
group.
States
that
have
agreed
to
participate
in
the
exemption
process
are
listed
on
EPA's
website
at
www.
epa.
gov/
ozone/
mbr/
cueqa.
html
You
may
either
complete
an
electronic
(
Microsoft
Excel)
or
a
printed
version
of
the
application.
Please
fill
out
each
form
or
worksheet
in
the
application
as
completely
as
possible.
If
you
are
completing
the
printed
version
and
need
extra
space
you
may
attach
additional
sheets
as
needed.
Additional
information
may
be
available
from
your
local
state
department
of
agriculture
or
at
the
sites
listed
below
or
by
calling
1
800
296
1996,
Each
worksheet
number
corresponds
to
the
tab
number
in
the
electronic
version
of
the
application.
Instructions
specific
to
each
worksheet
are
provided
at
the
top
of
each
sheet.
A
header
row
is
included
on
each
worksheet
to
include
an
application
ID
number
that
EPA
will
assign.
Instructions
Worksheet
1.
Contact
and
Methyl
Bromide
Request
Information
Worksheet
2.
Methyl
Bromide
Historical
Data
2
A.
Methyl
Bromide
Use
1997
2000
2
B.
Methyl
Bromide
CroplCommodity
Yield
and
Revenue
1997
2000
2
C.
Methyl
Bromide
CroplCommodity
Yield
and
Revenue
2001
2
D.
Methyl
Bromide
Use
and
Costs
for
2001
?
E.
Methyl
Bromide
Other
Operating
Costs
for
2001
2
F.
Methyl
Bromide
Fixed
and
Overhead
Costs
,
..
Worksheet
3.
Alternatives
Feasibility
of
Alternatives
to
Methyl
Bromide
3
A.
Alternatives
Technical
Feasibility
Research
Summary
Worksheet
Example
Research
Sum
(
Summary)
Worksheet
3
B.
Alternatives
Pest
Control
Regimen
Costs
3
C.
Alternatives
Crop/
Commodity
Yield
and
Revenue
3
D.
Alternatives
Other
Operating
Costs
Worksheet
4.
Alternatives
Research
Plans
Worksheet
5.
Additional
Information
Worksheet
6.
Application
Summary
Fumigation
Cycle
Climate
Zone
Map
2060
0482
IS
MY
INFORMATION
>
ONFIDENTIAL?
WHEN
IS
THE
INFORMATION
NEEDED?
WHERE
DO
I
SUBMIT
THE
APPLICATION?
HOW
CAN
I
RECEIVE
ADDITIONAL
INFORMATION?
UNITED
STATES
ENVIRONMENTAL
PROTECTION
AGENCY
WASHINGTON,
D.
C.
20460
The
applicant
may
assert
a
business
confidentiality
claim
covering
part
or
all'of
the
information
in
the
application
by
placing
on
(
or
attaching
to)
the
information,
at
the
time
it
is
submitted
to
EPA,
a
cover
sheet,
stamped
or
typed
legend,
or
other
suitable
form
of
notice
employing
language
such
as
trade
secret,
proprietary,
or
company
confidential.
Allegedly
confidential
portions
of
otherwise
non
confidential
documents
should
be
clearly
identified
by
the
applicant,
and
may
be
submitted
separately
to
facilitate
identification
and
handling
by
EPA.
If
the
applicant
desires
confidential
treatment
only
until
a
certain
date
or
until
the
occurrence
of
a
certain
event,
the
notice
should
so
state.
Information
covered
by
a
claim
of
confidentiality
will
be
disclosed
by
EPA
only
to
the
extent,
and
by
means
of
the
procedures
set
forth
under
40
CFR
Part
2
Subpart
B;
41
FR
36902,43
FR
400000.
50
FR
51
661.
If
no
claim
of
confidentiality
accompanies
the
information
when
it
is
received
by
EPA,
it
may
be
made
available
to
the
public
by
EPA
without
further
notice
to
the
applicant.
Applicants
submitting
their
application
via
e
mail
assume
responsibility
for
the
confidentiality
of
the
electronic
rn
This
application
must
be
postmarked
to
the
EPA
address
below
no
later
than
120
days
after
the
Notice
was
published
in
the
Federal
Reaister
requesting
critical
use
exemption
applications.
Electronic
Address
for
applications:
methyl.
bromide@
epa.
gov
(
When
submitting
an
application
electronically,
you
should
also
print
a
hard
copy,
sign
the
copy,
and
submit
it
by
mail)
Mailing
Address
for
applications
being
submitted
by
mail
directly
to
the
EPA:
US
Environmental
Protection
Agency
Methyl
Bromide
Critical
Use
Exemption
Global
Programs
Division,
Mail
Code
6205J
1200
Pennsylvania
Ave,
NW
Washington,
DC
20460
0001
Address
for
applications
being
sent
by
courier
or
non
U.
S.
Postal
overniaht
express
delivery
to
EPA:
US
Environmental
Protection
Agency
Methyl
Bromide
Critical
Use
Exemption
Global
Programs
Division
501
3rd
St.
NW
Washington,
DC
20001
phone:
(
202)
564
9410
If
you
have
general
questions
about
this
application
call:
Stratospheric
Ozone
Hotline
1
800
296
1
996
1.
2.
3.
4.
5.
6.
7.
8.
9.
For
EPA
Use
Only
ID#
Worksheet
I.
Contact
and
Methyl
Bromide
Request
Information
The
following
information
will
be
used
to
determine
the
amount
of
methyl
bromide
requested
and
the
contact
person
for
this
request.
It
is
important
that
we
know
whom
to
contact
in
case
we
need
additional
information
during
the
review
of
the
application.
Location
(
Enter
the
state,
region,
or
county.
Provide
more
detail
about
the
location
if
relevant
to
the
feasibility
of
alternatives
to
methyl
bromide.)
Croplcommodity
(
Include
all
crops/
commodities
that
benefit
from
the
application
of
methyl
bromide
in
a
fumigation
cycle.
A
fumigation
cycle
is
the
period
of
time
between
methyl
bromide
fumigations.)
Climate
(
Individual
users
should
enter
their
climate
zone
designation
by
reviewing
the
U.
S.
climate
zone
map.
If
a
consortium
is
submitting
this
application,
please
indicate
the
estimated
percentage
of
consortium
users
in
each
climate
zone.
This
map
is
located
at
the
end
of
this
workbook
or
it
can
be
reviewed
online
at
http://
www.
usna.
usda.
gov/
Hardzone/
ushzmap.
htmI).
Soil
type
Check
the
box(
es)
for
the
soil
types
and
percent
organic
matter
that
apply
to
your
area.
If
a
consortium
is
submitting
this
application,
please
indicate
the
estimated
percentage
of
consortium
users
in
each
soil
type.
Soil
Type:
Light
Medium
Heavy
over
5%
Organic
Matter:
0
to
2%
2
t
0
5
%
Other
geographic
factors
that
may
affect
croplcommodity
yield
(
e.
g.,
water
table).
Consortium
name
Specialty
(
check
one)
Contact
name
agronomic
Address
economic
~
~
Daytime
phone
IO.
FAX
11.
E
mail
List
an
additional
contact
person
if
available.
Specialty
(
check
one)
12.
Contact
name
agronomic
13.
Address
economic
14.
Daytime
phone
15.
FAX
16.
E
mail
,
Year
2006
2007
For
EPA
Use
Only
ID#
Worksheet
I.
Contact
and
Methyl
Bromide
Request
Information
Quantity
ai
(
Ib.)
of
Methyl
Bromide
Area
to
be
Treated
Unit
of
Area
Treated
17.
How
much
active
ingredient
(
ai)
of
methyl
bromide
are
you
requesting
for
2005?
Ibs.
If
a
consortium
is
submitting
this
application,
the
data
for
question
17
and
17a.
should
be
the
total
for
the
consortium.
In
the
question
below,
area
is
defined
as
follows
for
each
user:
acres
for
growers,
cubic
feet
for
post
harvest
operations,
and
square
feet
for
structural
applications.
17a.
How
much
area
will
this
be
applied
to?
Please
list
units.
units
18.
Are
you
requesting
methyl
bromide
for
additional
years
beyond
2005?
Yes
No
18a'
If
yes,
please
list
year
and
quantity
active
ingredient
(
ai)
of
methyl
bromide
requested
in
the
table
below
and
explain
why
you
need
authorization
for
multiple
years.
19.
Target
Pest@)
or
Pest
Problem(
s):
(
Be
as
specific
as
possible
about
the
species
or
classes
of
pests
relevant
to
the
feasibility
of
alternatives.)
20.
If
applying
as
a
consortium
for
many
users
of
methyl
bromide,
please
define
a
representative
user.
Define
exactly,
issues
such
as
size
of
the
operation
(
acres
treated
with
methyl
bromide
for
growers,
cubic
feet
for
post
harvest
operations,
and
square
feet
for
structural
applications),
whether
the
representative
user
owns
or
rents
the
land
or
operation,
intensity
of
methyl
bromide
use
(
treat
regularly
or
only
when
pest
reaches
a
threshold),
pest
pressure,
etc.
20a.
Explain
why
this
user
represents
the
typical
user
in
the
consortium.
OMB
Control
#
2060
0482
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?
3
For
EPA
Use
Only
init
Worksheet
3
A.
Alternatives
Technical
Feasibility
of
Alternatives
to'Methyl
3romide
In
this
worksheet,
you
should
address
why
an
alternative
pest
management
strategy
on
the
list
(
see
previous
page)
is
or
is
not
effective
for
your
conditions.
This
worksheet
contains
9
questions.
You
must
complete
one
copy
of
worksheet
3
A
for
each
research
study
you
use
to
evaluate
a
single
methyl
bromide
alternative.
Use
additional
pages
as
need.
For
worksheet
3
A
you
must
complete
one
worksheet
for
each
alternative.
for
each
research
study
addressed.
Please
number
the
worksheets
as
follows.
For
the
same
alternative,
first
research
study,
label
the
worksheet
3
A(
l)(
a).
For
the
samc
alternative,
second
research
study,
label
the
worksheet
3
A(
l)(
b).
For
the
first
alternative,
third
research
study,
label
the
worksheet
3
A(
l)(
c).
For
the
second
alternative,
first
research
study,
label
the
worksheet
3(
A)(
Z)(
a).
For
the
second
alternative,
second
research
study,
label
the
worksheet
3(
A)(
2)(
b).
When
completing
Section
II,
if
you
cite
a
study
that
is
on
the
EPA
website,
you
only
need
to
complete
questions
1,5,
and
8.
Summarize
each
of
the
research
studies
you
cite
in
the
Research
Summary
Worksheet.
If
you
prefer,
you
may
provide
the
information
requested
in
this
worksheet
in
a
narrative
review
of
one
or
more
relevant
research
reports.
The
narrative
review
must
reply
to
Section
I
and
questions
1
through
8
in
Section
II.
A
Research
Summary
Worksheet
of
relevant
treatments
should
be
provided
for
each
study
reviewed.
BACKGROUND
EPA
must
consider
whether
alternative
pest
control
measures
(
pesticide
and
non
pesticidal,
and
their
combination)
could
be
used
successfully
instead
of
methyl
bromide
by
crop
and
circumstance
(
geographic
area.)
The
Agency
has
developed
a
list
of
possible
alternative
pest
control
regimens
for
various
crops,
which
can
be
found
at
http://
www.
epa.
gov/
ozone/
mbr
or
by
calling
1
800
296
1
996.
There
are
three
major
ways
you
can
provide
the
Agency
with
proof
of
your
investigative
work.
(
1)
Conduct
and
submit
your
own
research
(
2)
Cite
research
that
has
been
conducted
by
others
(
3)
Cite
research
listed
on
the
EPA
website
Whether
you
conduct
the
research
yourself
or
cite
studies
developed
by
others,
it
is
important
that
the
studies
be
conducted
in
a
scientifically
sound
manner.
The
studies
should
include
a
description
of
the
experimental
methodology
used,
such
as
application
rates,
application
intervals,
pest
pressure,
weather
conditions,
varieties
of
the
crop
used,
etc.
All
results
should
be
included,
regardless
of
outcome.
You
must
submit
copies
of
each
study
to
EPA
unless
they
are
listed
on
the
Agency
website.
The
Agency
has
posted
many
research
studies
on
a
variety
of
crops
on
its
website
and
knows
of
more
studies
currently
in
progress.
EPA
will
add
studies
to
its
website
as
they
become
publicly
available.
You
are
encouraged
to
review
the
EPA
website
and
other
websites
for
studies
that
pertain
to
your
crop
and
geographic
area.
In
addition,
EPA
acknowledges
that,
for
certain
circumstances,
some
alternatives
are
not
technically
feasible
and
therefore
no
researcr
has
been
conducted
(
Le.
solarization
may
not
be
feasible
in
Seattle).
You
should
look
at
the
list
of
alternatives
provided
by
the
Agency
and
explain
why
they
cannot
be
used
for
your
crop
and
in
your
geographic
area.
Use
additional
pages
as
needed.
Alternative:
Study:
[
in
Section
1.
Initial
Screening
on
Technical
Feasibility
of
Alternatives
I.
Are
there
any
location
specific
restrictions
that
inhibit
the
use
of
this
alternative
on
your
site?
l
a
.
Full
use
permitted
1
b.
Township
caps
1
c.
Alternative
not
acceptable
in
consuming
country
I
d
.
Other
(
Please
describe)
If
use
of
this
alternative
is
precluded
by
regulatory
restriction
for
all
users
covered
by
this
application,
the
applicant
should
not
complete
Section
II.
For
EPA
Use
Only
ID#
Worksheet
S
A.
Alternatives
Technical
Feasibility
ot
Alternatives
to
Methyl
Bromide
Section
II.
Existing
Research
Studies
on
Alternatives
to
Methyl
Bromide
1.
Is
the
study
on
EPA's
website?
Yes
No
la.
If
not
on
the
EPA
website,
please
attach
a
copy.
2.
Author(
s)
or
researcher(
s)
3.
Publication
and
Date
of
Publication
4.
Location
of
research
study
5.
Name
of
alternative(
s)
in
study.
If
more
than
one
alternative,
list
the
ones
you
wish
to
discuss.
6.
Was
crop
yield
measured
in
the
study?
Yes
No
7.
Describe
the
effectiveness
of
the
alternative
in
controlling
pests
in
the
study.
8.
Discuss
how
the
results
of
the
study
apply
to
your
situation.
Would
you
expect
similar
results?
Are
there
other
factors
that
would
affect
your
adoption
of
this
tool?
OMB
Control
#
2060
0482
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For
EPA
Use
Only
I
D#
Worksheet
4.
Alternatives
Future
Research
Plans
Please
describe
future
plans
to
test
alternatives
to
methyl
bromide.
(
All
available
methyl
bromide
alternatives
from
the
alternatives
list
should
have
been
tested
or
have
future
tests
planned.)
There
is
no
need
to
complete
a
separate
worksheet
for
future
research
plans
for
each
alternative
you
may
use
this
worksheet
to
describe
dl
future
research
plans.
I.
Name
of
study:
2.
Researcher(
s):
3.
Your
test
is
planned
for:
4.
Location:
5.
Name
of
alternative
to
be
tested:
6.
Will
crop
yield
be
measured
in
the
study?
Yes
No
7
If
additional
testing
is
not
planned,
please
explain
why.
(
For
example,
the
available
alternatives
have
been
tested
and
found
unsuitable,
an
alternative
has
been
identified
but
is
not
yet
registered
for
this
crop,
available
alternatives
are
too
expensive
for
this
crop,
etc.)
OMB
Control
#
2060
0482
j
m
m
o
01
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jspunod
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3
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Qpads
aseald
saA
41
For
EPA
Use
Only
ID#
I
Worksheet
5.
Add
i
t
i
ona
I
In
formation
(
con
t
i
n
u
ed)
8.
Range
of
square
feet
of
the
area
to
which
applicants
included
in
this
application
will
apply
methyl
bromide?
(
insert
number
of
users
in
each
category)
0
5,000
Sq.
ft.
5,001
10,000
Sq.
ft.
10,001
20,000
sq.
ft.
20,001
40,000
Sq.
ft.
40,001
80,000
Sq.
ft.
80,001
160,000
Sq.
ft.
over
160,000
sq.
ft.
I
certify
that
all
information
contained
in
this
document
is
factual
to
the
best
of
my
knowledge.
Signature
Date
Print
Name
Title
information
in
this
application
may
be
aggregated
with
information
from
other
applications
and
used
by
the
United
States
government
to
justify
claims
in
the
national
nomination
package
that
a
particular
use
of
methyl
bromide
be
considered
"
critical"
and
authorized
for
an
exemption
beyond
the
2005
phaseout.
Use
of
aggregate
data
will
be
crucial
to
making
compelling
arguments
in
favor
of
critical
use
exemptions.
By
signing
below,
you
agree
not
to
assert
any
claim
of
confidentiality
that
would
affect
the
disclosure
by
EPA
of
aggregate
information
based
in
part
on
information
contained
in
this
application.
Signature
Date
Print
Name
Title
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions:
develop.
acquire.
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information:
search
data
sources:
complete
and
review
the
collection
of
information:
and
transmit
or
otherwise
disclose
the
information.
Public
reporting
burden
for
this
collection
of
information
is
estimated
to
average
324
hours
per
response
and
assumes
a
large
portion
of
applications
will
be
submitted
by
consortia
on
behalf
of
many
individual
users
of
methyl
bromide.
An
agency
may
not
conduct
or
sponsor,
and
a
person
Is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
current
OMB
control
number.
OMB
Control
#
2060
0482
l
3
I
| epa | 2024-06-07T20:31:40.840735 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0017-0001/content.txt"
} |
EPA-HQ-OAR-2003-0017-0042 | Supporting & Related Material | "2002-01-16T05:00:00" | null | epa | 2024-06-07T20:31:40.849912 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0017-0042/content.txt"
} |
|
EPA-HQ-OAR-2003-0017-0049 | Supporting & Related Material | "2002-01-16T05:00:00" | null | epa | 2024-06-07T20:31:40.850592 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0017-0049/content.txt"
} |
|
EPA-HQ-OAR-2003-0017-0068 | Supporting & Related Material | "2002-01-16T05:00:00" | null | epa | 2024-06-07T20:31:40.851223 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0017-0068/content.txt"
} |
|
EPA-HQ-OAR-2003-0045-0168 | Supporting & Related Material | "2002-04-30T04:00:00" | null | EMISSION
FACTORS
Cruise
Load
0.8
RSZ
Maneuver
g/
hp
hr
HC
CO
NOx
PM
SO2
g/
hp
hr
HC
CO
NOx
PM
SO2
g/
hp
hr
2
0.395
0.82
17.6
1.29
9.56
2
0.395
0.82
17.6
1.29
9.56
2
4
0.395
0.52
12.38
1.31
9.69
4
0.395
0.52
12.38
1.31
9.69
4
Steam
0.05
0.22
2.09
1.86
15.0
Steam
0.05
0.22
2.09
1.86
15.0
Steam
Speed
6.5
knots
Speed
For
SO2
calcs:
Maneuverin
BSFC
(
g/
hp
hr)
2
stroke
253.7893025
163.3
slow
4
stroke
260.1601133
165.5
medium
Steam
255
255
Hotel
Load
0.1
All
Modes
HC
CO
NOx
PM
SO2
g/
hp
hr
HC
CO
NOx
PM
SO2
2.085717
6.072741
23.9113
2.168337
23.02
2
0.1
1.85
9.96
0.239
1.07
2.172732
4.432346
16.87605
2.216072
23.87
4
0.1
1.85
9.96
0.239
1.07
0.05
0.22
2.09
1.86
15.0
Steam
0.05
0.22
2.09
1.86
1.65
4
knots
ring
Adjustment
HC
CO
NOx
PM
CO2
5.28
7.41
1.36
1.68
1.55
5.500588
8.523742
1.36317
1.691658
1.571964
Lower
Mississippi
River
Ports
Emissions
by
Vessel
Type
(
TPY)
EMISSIONS
ESTIMATES
Vessel
Type
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
BARGE
CARRIER
1
1
26
4
28
1
2
44
7
51
0
1
3
0
4
1
12
BULK
CARRIER
68
139
2992
223
1651
93
192
4113
309
2289
24
69
271
25
266
70
1280
CONTAINER
SHIP
5
10
206
25
194
6
13
255
32
247
2
6
24
3
31
3
43
GENERAL
CARGO
8
14
313
25
185
18
35
761
60
446
4
10
38
4
39
8
155
MISCELLANEOUS
0
0
5
0
3
0
0
9
1
5
0
0
1
0
1
1
10
PASSENGER
3
6
114
13
102
4
9
182
22
169
1
3
12
2
15
1
14
REEFER
0
0
7
1
4
0
1
12
1
7
0
0
1
0
1
1
12
RORO
2
3
71
5
40
3
7
142
11
79
1
2
8
1
8
1
19
TANKER
21
43
930
72
532
61
124
2668
205
1525
12
33
129
12
129
17
307
VEHICLE
CARRIER
0
0
1
0
1
0
0
4
0
2
0
0
0
0
0
0
1
Grand
Total
107
218
4665
368
2741
188
382
8190
648
4820
43
123
487
47
495
101
1853
Lower
Mississippi
River
Ports
Emissions
by
Engine
Type
(
TPY)
EMISSIONS
ESTIMATES
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
2
stroke
99
206
4421
324
2401
172
358
7676
563
4169
40
116
457
41
440
91
1688
4
stroke
7
9
204
22
160
14
18
439
46
343
3
7
25
3
36
8
144
Steam
Engine
1
2
24
21
169
1
4
40
36
289
0
0
2
2
17
2
7
Grand
Total
107
218
4665
368
2741
188
382
8190
648
4820
43
123
487
47
495
101
1853
New
York
Ports
Emissions
by
Vessel
Type
(
TPY)
EMISSIONS
ESTIMATES
Vessel
Type
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
BARGE
CARRIER
0
0
1
1
6
0
0
0
0
2
0
0
0
0
1
0
1
BULK
CARRIER
5
10
215
17
128
6
12
249
19
143
3
8
32
3
32
6
110
CONTAINER
SHIP
38
80
1683
155
1171
15
32
660
61
461
13
36
144
15
155
12
210
GENERAL
CARGO
3
7
149
12
89
2
5
98
8
58
1
4
15
1
15
3
38
MISCELLANEOUS
0
0
3
0
2
0
0
2
0
2
0
0
0
0
0
0
1
PASSENGER
5
8
164
24
181
2
4
82
12
94
2
4
17
3
27
1
12
REEFER
1
2
38
3
21
0
1
15
1
8
0
1
3
0
3
0
8
RORO
4
8
182
14
101
2
4
87
6
48
2
6
24
2
24
2
31
TANKER
16
33
703
64
479
11
23
484
44
333
13
36
143
15
153
9
165
VEHICLES
CARRIER
5
9
188
15
109
2
4
91
7
53
2
6
25
2
26
1
19
Grand
Total
77
157
3325
304
2286
41
84
1769
160
1201
36
102
404
42
436
34
595
New
York
Ports
Emissions
by
Engine
Type
(
TPY)
EMISSIONS
ESTIMATES
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
2
stroke
67
139
2983
219
1620
36
74
1592
117
865
32
93
365
33
351
28
519
4
stroke
9
12
280
30
219
5
6
146
15
114
4
9
33
4
47
3
63
Steam
Engine
1
7
62
56
447
1
3
31
28
222
0
1
5
5
38
3
13
Grand
Total
77
157
3325
304
2286
41
84
1769
160
1201
36
102
404
42
436
34
595
Delaware
River
Ports
Emissions
by
Vessel
Type
(
TPY)
EMISSIONS
ESTIMATES
Vessel
Type
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
BULK
CARRIER
5
11
238
18
131
10
20
420
31
231
2
6
23
2
23
5
90
CONTAINER
SHIP
6
11
235
19
138
6
12
268
21
157
2
5
18
2
19
2
43
GENERAL
CARGO
3
6
127
10
77
5
10
215
17
129
1
3
12
1
13
3
50
MISCELLANEOUS
0
0
1
0
1
0
0
2
0
1
0
0
0
0
0
0
0
PASSENGER
0
0
9
2
18
0
0
8
2
20
0
0
1
0
2
0
1
REEFER
3
6
136
10
76
4
7
155
12
86
1
3
13
1
13
2
42
RORO
1
1
21
2
14
1
1
30
3
19
0
0
1
0
2
0
6
TANKER
14
29
607
53
397
24
51
1071
94
702
8
23
89
9
93
13
227
VEHICLE
CARRIER
1
2
39
3
22
1
1
31
2
18
0
1
3
0
3
0
4
Grand
Total
33
66
1413
117
873
51
103
2200
183
1363
14
41
161
16
168
26
465
Delaware
River
Ports
Emissions
by
Engine
Type
(
TPY)
EMISSIONS
ESTIMATES
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
2
stroke
28
59
1267
93
688
45
93
1999
147
1086
13
37
148
13
142
23
417
4
stroke
4
6
135
14
105
6
8
182
19
142
2
3
12
2
17
2
44
Steam
Engine
0
1
11
10
80
0
2
19
17
135
0
0
1
1
9
1
3
Grand
Total
33
66
1413
117
873
51
103
2200
183
1363
14
41
161
16
168
26
465
Puget
Sound
Ports
Emissions
by
Vessel
Type
(
TPY)
EMISSIONS
ESTIMATES
Vessel
Type
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
BULK
CARRIER
10
21
452
34
256
0
36
75
1605
124
925
4
11
43
4
43
11
208
CONTAINER
SHIP
27
57
1194
112
845
0
62
132
2747
255
1927
7
21
85
9
91
12
203
FISHING
1
1
17
2
170
2
3
65
9
67
0
1
4
1
6
3
50
GENERAL
CARGO
3
7
142
11
84
0
11
21
466
38
280
1
3
12
1
13
3
46
MISCELANEOUS
0
0
2
0
20
0
1
11
1
11
0
0
0
0
0
1
14
PASSENGER
0
0
10
1
8
0
1
1
24
3
20
0
0
1
0
1
0
3
REEFER
0
1
16
1
90
1
2
50
4
29
0
1
3
0
3
1
15
RORO
1
3
39
14
1090
2
6
79
33
260
0
0
3
1
10
2
9
TANKER
4
11
190
47
370
0
13
34
575
145
1143
4
11
47
11
100
4
45
VEHICLES
CARRIER
2
4
77
6
440
6
11
233
18
135
1
2
6
1
6
0
8
Grand
Total
49
104
2140
229
1745
134
285
5857
629
4796
17
50
204
28
273
37
600
Puget
Sound
Ports
Emissions
by
Engine
Type
(
TPY)
EMISSIONS
ESTIMATES
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
2
stroke
44
92
1980
145
1075
120
250
5367
393
2915
16
46
183
17
176
27
496
4
stroke
2
3
75
8
59
8
11
256
27
200
1
3
10
1
14
4
79
Steam
Engine
2
9
85
76
611
6
25
235
209
1681
0
1
12
10
84
6
25
Grand
Total
49
104
2140
229
1745
134
285
5857
629
4796
17
50
204
28
273
37
600
Port
of
Corpus
Christi
Emissions
by
Vessel
Type
(
TPY)
EMISSIONS
ESTIMATES
Vessel
Type
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
BARGE
CARRIER
0
0
0
0
2#
0
0
0
0
1
0
0
0
0
0
0
0
BULK
CARRIER
3
6
139
10
77
0
2
4
90
7
50
2
6
24
2
23
1
26
CONTAINER
SHIP
0
0
2
0
10
0
0
1
0
1
0
0
1
0
1
0
1
TANKER
13
29
574
78
600
0
8
18
355
47
364
8
24
98
13
125
5
75
GENERAL
CARGO
0
0
3
0
30
0
0
2
0
2
0
0
0
0
1
0
1
MISCELLANEOUS
0
0
1
0
1#
0
0
1
0
0
0
0
0
0
0
0
0
Grand
Total
17
36
720
89
684
10
22
449
54
418
11
31
123
15
150
6
103
Port
of
Corpus
Christi
Emissions
by
Engine
Type
(
TPY)
EMISSIONS
ESTIMATES
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
2
stroke
14
30
634
47
345
9
19
400
29
217
10
28
112
10
108
5
87
4
stroke
1
2
43
5
33
1
1
24
3
19
1
2
6
1
9
1
11
Steam
Engine
1
4
43
38
306
1
3
25
23
181
0
0
5
4
33
1
5
Grand
Total
17
36
720
89
684
10
22
449
54
418
11
31
123
15
150
6
103
Port
of
Tampa
Emissions
by
Vessel
Type
(
TPY)
EMISSIONS
ESTIMATES
Vessel
Type
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
BULK
CARRIER
7
14
299
24
175
0
4
7
155
12
90
4
10
41
4
41
5
90
CONTAINER
SHIP
0
0
4
0
20
0
0
2
0
1
0
0
1
0
1
0
3
GENERAL
CARGO
2
3
70
6
460
1
2
39
3
26
1
1
5
1
6
1
20
PASSENGER
3
6
127
10
73
0
1
3
63
5
36
1
2
9
1
9
1
21
REEFER
0
1
20
1
11
0
0
7
0
4
0
1
2
0
2
0
9
RORO
0
0
5
0
3
0
0
3
0
2
0
0
1
0
1
0
3
TANKER
4
8
157
20
157
2
4
83
11
82
1
3
12
2
17
1
21
TUG
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
VEHICLES
CARRIER
0
0
1
0
1
0
0
0
0
0
0
0
0
0
0
0
1
BARGE
DRY
CARGO
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
BARGE
TANKER
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
MISCELLANEOUS
0
0
2
0
2
0
0
1
0
1
0
0
0
0
0
0
6
UNSPECIFIED
MOTOR
0
0
0
0
0
#
0
0
0
0
0
0
0
0
0
0
0
0
Grand
Total
17
32
685
63
469
9
16
353
32
241
7
18
71
7
77
10
174
Port
of
Tampa
Emissions
by
Engine
Type
(
TPY)
EMISSIONS
ESTIMATES
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
2
stroke
9
19
403
30
219
5
10
208
15
113
4
12
49
4
47
5
94
4
stroke
1
1
23
2
18
0
0
11
1
9
0
0
2
0
3
1
16
Steam
Engine
0
1
10
9
72
0
1
5
5
37
0
0
1
1
5
0
2
Grand
Total
17
32
685
63
469
9
16
353
32
241
7
18
71
7
77
10
174
Port
of
Baltimore
by
Vessel
Type
(
TPY)
EMISSIONS
ESTIMATES
Vessel
Type
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
BULK
CARRIER
7
14
302
24
182
31
64
1354
108
809
2
6
25
2
25
6
111
CONTAINER
SHIP
11
24
510
40
299
31
66
1397
110
817
4
13
50
5
49
3
52
GENERAL
CARGO
2
4
85
7
52
9
17
363
30
225
1
2
8
1
8
2
35
MISCELLANEOUS
0
0
3
0
2
0
1
16
2
11
0
0
0
0
0
1
13
PASSENGER
0
0
9
2
12
1
1
20
4
29
0
0
1
0
1
0
5
REEFER
0
0
1
0
1
0
0
2
0
1
0
0
0
0
0
0
3
RORO
4
9
186
14
101
13
27
586
43
320
2
5
19
2
19
2
32
TANKER
2
3
70
6
45
7
14
291
25
191
1
2
6
1
7
1
13
VEHICLES
CARRIER
4
7
155
12
90
10
20
434
34
253
2
5
19
2
20
1
19
Grand
Total
30
62
1321
105
784
102
209
4463
356
2656
11
33
129
12
130
16
283
Port
of
Baltimore
Emissions
by
Engine
Type
(
TPY)
EMISSIONS
ESTIMATES
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
2
stroke
28
58
1248
91
678
95
196
4217
309
2290
11
31
122
11
117
13
244
4
stroke
2
3
65
7
51
7
9
219
23
171
1
2
6
1
9
2
37
Steam
Engine
0
1
8
7
55
1
3
27
24
194
0
0
1
0
4
1
2
Grand
Total
30
62
1321
105
784
102
209
4463
356
2656
11
33
129
12
130
16
283
Coos
Bay
Emissions
by
Vessel
Type
(
TPY)
EMISSIONS
ESTIMATES
Vessel
Type
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
BULK
CARRIER
2
4
76
6
41
0
1
16
1
9
0
1
3
0
2
1
21
GENERAL
CARGO
1
1
30
2
16
0
0
6
0
3
0
0
1
0
1
0
8
MISCELLANEOUS
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Grand
Total
2
5
106
8
58
1
1
23
2
12
0
1
4
0
3
2
29
Coos
Bay
Emissions
by
Engine
Type
(
TPY)
EMISSIONS
ESTIMATES
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
2
stroke
2
5
106
8
57
1
1
23
2
12
0
1
4
0
3
2
28
4
stroke
0
0
1
0
1
0
0
0
0
0
0
0
0
0
0
0
0
Steam
Engine
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Grand
Total
2
5
106
8
58
1
1
23
2
12
0
1
4
0
3
2
29
Port
of
Cleveland
Emissions
by
Vessel
Type
(
TPY)
EMISSIONS
ESTIMATES
Vessel
Type
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
BULK
CARRIER,
SALTY
0
1
16
1
9
0
0
3
0
2
0
1
5
0
5
1
15
BULK
CARRIER,
LAKER
1
3
60
5
41
0
1
15
1
10
5
13
51
5
55
0
0
CONTAINER
SHIP,
SALTY
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
EXCURSION
VESSEL
0
0
0
0
0
0
0
12
1
9
0
0
1
0
1
0
0
GENERAL
CARGO,
SALTY
0
0
1
0
1
0
0
0
0
0
0
0
0
0
0
0
1
TANKER,
SALTY
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Grand
Total
2
4
77
7
50
1
1
31
3
22
5
15
58
6
62
1
17
Port
of
Cleveland
Emissions
by
Engine
Type
(
TPY)
EMISSIONS
ESTIMATES
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
2
stroke
1
3
63
5
34
0
1
15
1
8
4
12
47
4
45
1
16
4
stroke
0
1
13
1
10
0
1
15
2
12
1
3
11
1
15
0
1
Steam
Engine
0
0
1
1
60
0
0
0
0
1
0
0
0
0
2
0
0
Grand
Total
2
4
77
7
50
0
1
1
31
3
22
5
15
58
6
62
1
17
Burns
Waterway
Harbor
Emissions
by
Vessel
Type
(
TPY)
EMISSIONS
ESTIMATES
Vessel
Type
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
BULK
CARRIER,
SALTY
0
0
10
1
6
0
0
2
0
1
0
1
3
0
3
0
5
BULK
CARRIER,
LAKER
1
1
23
2
14
0
0
5
0
3
1
1
5
1
6
0
1
GENERAL
CARGO,
SALTY
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
TANKER,
SALTY
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Grand
Total
1
2
34
3
20
0
0
8
1
5
1
2
9
1
9
0
6
Burns
Waterway
Harbor
Emissions
by
Engine
Type
(
TPY)
EMISSIONS
ESTIMATES
Cruise
HC
Cruise
CO
Cruise
NOx
Cruise
PM
Cruise
SO2
RSZ
HC
RSZ
CO
RSZ
NOx
RSZ
PM
RSZ
SO2
Maneuve
ring
HC
Maneuve
ring
CO
Maneuve
ring
NOx
Maneuve
ring
PM
Maneuvir
ing
SO2
Hotelling
HC
Hotelling
CO
2
stroke
1
1
31
2
17
0
0
7
1
4
1
2
8
1
8
0
6
4
stroke
0
0
3
0
2
0
0
1
0
1
0
0
1
0
1
0
0
Steam
Engine
0
0
0
0
10
0
0
0
0
0
0
0
0
0
0
0
0
Grand
Total
1
2
34
3
200
0
0
8
1
5
1
2
9
1
9
0
6
Lower
Mississippi
River
P
Vessel
Type
BARGE
CARRIER
BULK
CARRIER
CONTAINER
SHIP
GENERAL
CARGO
MISCELLANEOUS
PASSENGER
REEFER
RORO
TANKER
VEHICLE
CARRIER
Grand
Total
Lower
Mississippi
River
P
2
stroke
4
stroke
Steam
Engine
Grand
Total
New
York
Ports
Emissions
Vessel
Type
BARGE
CARRIER
BULK
CARRIER
CONTAINER
SHIP
GENERAL
CARGO
MISCELLANEOUS
PASSENGER
REEFER
RORO
TANKER
VEHICLES
CARRIER
Grand
Total
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
68
11
86
3
16
140
22
170
6901
181
865
254
1680
14277
737
5071
240
23
170
16
72
724
84
643
838
22
108
38
214
1950
111
778
54
1
6
1
11
68
3
15
78
7
52
9
32
386
44
338
65
2
7
1
13
85
3
18
102
2
11
7
31
323
19
138
1654
45
222
111
506
5381
334
2408
4
0
0
0
1
10
1
4
10002
296
1527
439
2576
23344
1358
9583
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
Transit
Modes
HC
Transit
Modes
CO
Transit
Modes
NOx
Transit
Modes
PM
Transit
Modes
SO2
9089
218
974
403
2368
21642
1146
7983
311
680
12,553
928
7,009
Slow
774
19
83
32
178
1443
90
622
24
34
669
71
539
Medium
64
57
462
3
14
131
116
937
3
14
131
116
937
Steamship
10002
296
1527
439
2576
23344
1358
9583
99
1,832
9,863
237
1,057
category
2
total
437
2,559
23,215
1,352
9,543
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
9
8
65
0
1
10
9
73
594
16
79
19
140
1091
56
381
1150
68
454
78
358
3636
300
2241
217
33
252
10
53
479
54
414
5
0
1
0
1
11
1
5
69
6
41
10
28
332
45
343
42
1
4
2
11
98
5
36
170
14
96
10
49
463
36
269
898
40
243
49
258
2228
162
1208
102
2
11
10
38
406
27
199
3257
188
1246
189
938
8755
694
5170
New
York
Ports
Emissions
2
stroke
4
stroke
Steam
Engine
Grand
Total
Delaware
River
Ports
Emis
Vessel
Type
BULK
CARRIER
CONTAINER
SHIP
GENERAL
CARGO
MISCELLANEOUS
PASSENGER
REEFER
RORO
TANKER
VEHICLE
CARRIER
Grand
Total
Delaware
River
Ports
Emis
2
stroke
4
stroke
Steam
Engine
Grand
Total
Puget
Sound
Ports
Emissi
Vessel
Type
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
Transit
Modes
HC
Transit
Modes
CO
Transit
Modes
NOx
Transit
Modes
PM
Transit
Modes
SO2
2793
67
299
163
825
7733
435
3136
135
306
4,940
368
2,836
Slow
337
8
36
21
89
796
58
416
18
27
459
49
380
Medium
127
113
911
5
24
225
201
1618
5
24
225
201
1,618
Steamship
3257
188
1246
189
938
8755
694
5170
31
581
3,130
75
336
category
2
total
189
938
8,755
694
5,170
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
484
12
53
22
127
1166
63
437
233
6
25
16
71
754
47
339
270
6
29
12
69
623
35
247
1
0
0
0
0
4
0
2
8
2
16
1
2
25
7
56
228
5
24
10
59
531
29
199
33
1
4
2
9
86
5
38
1234
55
339
59
329
3002
210
1532
24
1
3
2
8
96
6
45
2515
88
493
124
674
6288
403
2896
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
Transit
Modes
HC
Transit
Modes
CO
Transit
Modes
NOx
Transit
Modes
PM
Transit
Modes
SO2
2244
54
241
109
606
5658
307
2156
86
190
3,414
253
1,916
Slow
239
6
26
14
61
568
41
291
12
16
329
35
265
Medium
32
28
226
2
7
63
56
449
2
7
63
56
449
Steamship
2515
88
493
124
674
6288
403
2896
25
461
2,483
60
266
category
2
total
124
674
6,288
403
2,896
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
BULK
CARRIER
CONTAINER
SHIP
FISHING
GENERAL
CARGO
MISCELANEOUS
PASSENGER
REEFER
RORO
TANKER
VEHICLES
CARRIER
Grand
Total
Puget
Sound
Ports
Emissi
2
stroke
4
stroke
Steam
Engine
Grand
Total
Port
of
Corpus
Christi
Em
Vessel
Type
BARGE
CARRIER
BULK
CARRIER
CONTAINER
SHIP
TANKER
GENERAL
CARGO
MISCELLANEOUS
Grand
Total
Port
of
Corpus
Christi
Em
2
stroke
4
stroke
Steam
Engine
1122
30
142
62
315
3223
192
1366
1115
70
474
108
413
5141
446
3336
275
23
161
6
54
361
34
252
249
6
31
19
77
869
57
408
73
2
10
1
14
87
4
23
16
1
7
1
5
50
5
36
79
2
8
3
18
149
7
50
76
55
440
4
18
197
102
819
285
93
737
25
101
1098
296
2349
44
1
5
8
24
360
26
190
3334
283
2015
237
1041
11535
1170
8830
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
Transit
Modes
HC
Transit
Modes
CO
Transit
Modes
NOx
Transit
Modes
PM
Transit
Modes
SO2
2672
64
286
208
885
10201
619
4453
181
389
7,530
555
4,166
Slow
428
10
46
16
96
768
46
318
12
16
340
36
272
Medium
234
209
1683
14
60
566
504
4059
14
60
566
504
4,059
Steamship
3334
283
2015
237
1041
11535
1170
8830
31
576
3,100
74
332
category
2
total
237
1,041
11,535
1,170
8,830
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
1
1
7
0
0
1
1
10
138
3
15
9
42
391
23
166
4
0
0
0
1
7
0
3
423
47
350
35
146
1450
185
1439
4
0
1
0
1
10
1
6
1
0
0
0
0
3
0
1
571
52
373
44
191
1863
210
1624
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
Transit
Modes
HC
Transit
Modes
CO
Transit
Modes
NOx
Transit
Modes
PM
Transit
Modes
SO2
469
11
50
38
164
1615
97
720
33
77
1,146
86
669
Slow
58
1
6
4
15
131
9
68
3
5
74
8
62
Medium
44
39
317
3
12
117
104
837
3
12
117
104
837
Steamship
Grand
Total
Port
of
Tampa
Emissions
Vessel
Type
BULK
CARRIER
CONTAINER
SHIP
GENERAL
CARGO
PASSENGER
REEFER
RORO
TANKER
TUG
VEHICLES
CARRIER
BARGE
DRY
CARGO
BARGE
TANKER
MISCELLANEOUS
UNSPECIFIED
MOTOR
Grand
Total
Port
of
Tampa
Emissions
2
stroke
4
stroke
Steam
Engine
Grand
Total
Port
of
Baltimore
by
Vesse
Vessel
Type
BULK
CARRIER
CONTAINER
SHIP
GENERAL
CARGO
MISCELLANEOUS
PASSENGER
REEFER
571
52
373
44
191
1863
210
1624
5
98
527
13
57
category
2
total
44
191
1,863
210
1,624
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
487
12
57
20
122
981
52
363
17
0
2
0
4
24
1
6
107
3
15
4
26
222
13
93
115
3
12
6
32
314
18
130
46
1
6
1
10
75
3
23
16
0
2
0
3
25
1
8
121
17
127
8
36
373
50
383
0
0
0
0
0
0
0
0
5
0
1
0
1
7
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
32
1
3
0
6
36
1
6
0
0
0
0
0
0
0
0
946
38
225
41
241
2055
140
1013
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
Transit
Modes
HC
Transit
Modes
CO
Transit
Modes
NOx
Transit
Modes
PM
Transit
Modes
SO2
503
12
54
23
134
1164
61
433
18
41
660
49
379
Slow
89
2
10
2
18
125
6
40
1
2
36
4
30
Medium
17
15
125
1
4
33
30
239
1
4
33
30
239
Steamship
946
38
225
41
241
2055
140
1013
6
110
592
14
64category
2
total
26
156
1,322
97
713
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
600
18
91
46
195
2281
153
1107
281
10
53
50
154
2238
164
1219
192
11
69
13
58
648
49
354
68
2
7
1
14
88
4
22
31
7
54
1
7
61
12
96
15
0
2
0
3
19
1
3
RORO
TANKER
VEHICLES
CARRIER
Grand
Total
Port
of
Baltimore
Emission
2
stroke
4
stroke
Steam
Engine
Grand
Total
Coos
Bay
Emissions
by
V
Vessel
Type
BULK
CARRIER
GENERAL
CARGO
MISCELLANEOUS
Grand
Total
Coos
Bay
Emissions
by
E
2
stroke
4
stroke
Steam
Engine
Grand
Total
Port
of
Cleveland
Emissio
Vessel
Type
BULK
CARRIER,
SALTY
BULK
CARRIER,
LAKER
174
4
19
21
73
966
63
458
68
2
14
10
31
436
35
257
101
2
11
17
51
709
51
373
1532
56
320
160
586
7444
530
3889
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
Transit
Modes
HC
Transit
Modes
CO
Transit
Modes
NOx
Transit
Modes
PM
Transit
Modes
SO2
1311
31
141
146
529
6898
443
3226
133
285
5,586
412
3,085
Slow
199
5
21
12
51
490
36
253
10
14
291
31
232
Medium
22
20
158
1
6
57
51
410
1
6
57
51
410
Steamship
1532
56
320
160
586
7444
530
3889
15
280
1,510
36
162
category
2
total
160
586
7,444
530
3,889
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
110
3
12
3
25
205
10
65
42
1
5
1
10
79
4
25
1
0
0
0
0
2
0
1
154
4
16
5
36
287
14
90
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
Transit
Modes
HC
Transit
Modes
CO
Transit
Modes
NOx
Transit
Modes
PM
Transit
Modes
SO2
152
4
16
5
35
284
13
89
3
7
132
10
73
Slow
2
0
0
0
0
3
0
1
0
0
1
0
1Medium
0
0
0
0
0
0
0
0
0
0
0
0
0Steamship
154
4
16
5
36
287
14
90
2
29
154
4
16category
2
total
5
36
287
14
90
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
82
2
9
2
17
106
4
24
0
0
0
7
16
126
12
106
CONTAINER
SHIP,
SALTY
EXCURSION
VESSEL
GENERAL
CARGO,
SALTY
TANKER,
SALTY
Grand
Total
Port
of
Cleveland
Emissio
2
stroke
4
stroke
Steam
Engine
Grand
Total
Burns
Waterway
Harbor
E
Vessel
Type
BULK
CARRIER,
SALTY
BULK
CARRIER,
LAKER
GENERAL
CARGO,
SALTY
TANKER,
SALTY
Grand
Total
Burns
Waterway
Harbor
E
2
stroke
4
stroke
Steam
Engine
Grand
Total
1
0
0
0
0
1
0
0
0
0
0
0
1
13
1
11
7
0
1
0
1
8
0
2
0
0
0
0
0
1
0
1
90
2
10
9
36
255
18
143
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
Transit
Modes
HC
Transit
Modes
CO
Transit
Modes
NOx
Transit
Modes
PM
Transit
Modes
SO2
87
2
9
7
32
212
12
97
6
15
125
10
87
Slow
3
0
0
2
5
42
4
38
2
4
39
4
37Medium
0
0
0
0
0
1
1
9
0
0
1
1
9Steamship
90
2
10
9
36
255
18
143
1
17
90
2
10category
2
total
9
36
255
18
143
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
27
1
5
1
6
43
2
15
3
0
1
1
3
37
3
23
1
0
0
0
0
2
0
1
0
0
0
0
0
1
0
1
32
1
6
2
10
82
5
39
Hotelling
NOx
Hotelling
PM
Hotelling
SO2
All
Modes
HC
All
Modes
CO
All
Modes
NOx
All
Modes
PM
All
Modes
SO2
Transit
Modes
HC
Transit
Modes
CO
Transit
Modes
NOx
Transit
Modes
PM
Transit
Modes
SO2
30
1
3
2
9
76
4
32
2
4
46
4
28Slow
1
0
0
0
1
6
0
4
0
0
4
0
4Medium
0
0
3
0
0
1
0
4
0
0
1
0
4Steamship
32
1
6
2
10
82
5
39
0
6
31
1
3category
2
total
2
10
82
5
39
Lower
Mississippi
River
P
Vessel
Type
BARGE
CARRIER
BULK
CARRIER
CONTAINER
SHIP
GENERAL
CARGO
MISCELLANEOUS
PASSENGER
REEFER
RORO
TANKER
VEHICLE
CARRIER
Grand
Total
Lower
Mississippi
River
P
2
stroke
4
stroke
Steam
Engine
Grand
Total
New
York
Ports
Emissions
Vessel
Type
BARGE
CARRIER
BULK
CARRIER
CONTAINER
SHIP
GENERAL
CARGO
MISCELLANEOUS
PASSENGER
REEFER
RORO
TANKER
VEHICLES
CARRIER
Grand
Total
2
New
York
Ports
Emissions
2
stroke
4
stroke
Steam
Engine
Grand
Total
Delaware
River
Ports
Emis
Vessel
Type
BULK
CARRIER
CONTAINER
SHIP
GENERAL
CARGO
MISCELLANEOUS
PASSENGER
REEFER
RORO
TANKER
VEHICLE
CARRIER
Grand
Total
Delaware
River
Ports
Emis
2
stroke
4
stroke
Steam
Engine
Grand
Total
Puget
Sound
Ports
Emissi
Vessel
Type
2
2
BULK
CARRIER
CONTAINER
SHIP
FISHING
GENERAL
CARGO
MISCELANEOUS
PASSENGER
REEFER
RORO
TANKER
VEHICLES
CARRIER
Grand
Total
Puget
Sound
Ports
Emissi
2
stroke
4
stroke
Steam
Engine
Grand
Total
Port
of
Corpus
Christi
Em
Vessel
Type
BARGE
CARRIER
BULK
CARRIER
CONTAINER
SHIP
TANKER
GENERAL
CARGO
MISCELLANEOUS
Grand
Total
Port
of
Corpus
Christi
Em
2
stroke
4
stroke
Steam
Engine
2
Grand
Total
Port
of
Tampa
Emissions
Vessel
Type
BULK
CARRIER
CONTAINER
SHIP
GENERAL
CARGO
PASSENGER
REEFER
RORO
TANKER
TUG
VEHICLES
CARRIER
BARGE
DRY
CARGO
BARGE
TANKER
MISCELLANEOUS
UNSPECIFIED
MOTOR
Grand
Total
Port
of
Tampa
Emissions
2
stroke
4
stroke
Steam
Engine
Grand
Total
Port
of
Baltimore
by
Vesse
Vessel
Type
BULK
CARRIER
CONTAINER
SHIP
GENERAL
CARGO
MISCELLANEOUS
PASSENGER
REEFER
2
2
RORO
TANKER
VEHICLES
CARRIER
Grand
Total
Port
of
Baltimore
Emission
2
stroke
4
stroke
Steam
Engine
Grand
Total
Coos
Bay
Emissions
by
V
Vessel
Type
BULK
CARRIER
GENERAL
CARGO
MISCELLANEOUS
Grand
Total
Coos
Bay
Emissions
by
E
2
stroke
4
stroke
Steam
Engine
Grand
Total
Port
of
Cleveland
Emissio
Vessel
Type
BULK
CARRIER,
SALTY
BULK
CARRIER,
LAKER
2
2
CONTAINER
SHIP,
SALTY
EXCURSION
VESSEL
GENERAL
CARGO,
SALTY
TANKER,
SALTY
Grand
Total
Port
of
Cleveland
Emissio
2
stroke
4
stroke
Steam
Engine
Grand
Total
Burns
Waterway
Harbor
E
Vessel
Type
BULK
CARRIER,
SALTY
BULK
CARRIER,
LAKER
GENERAL
CARGO,
SALTY
TANKER,
SALTY
Grand
Total
Burns
Waterway
Harbor
E
2
stroke
4
stroke
Steam
Engine
Grand
Total
2
2
Table
6
6:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Lower
Mississippi
River
Ship
Type
Engine
Type
DWT
Range
Calls
DWT
(
Tonnes)
Power
(
hp)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
BARGE
CARRIER
2
35,000
45,000
9
44,799
26,100
18
ND
ND
1972
2.8
18.3
1.7
BARGE
CARRIER
2
>
45,000
10
49,835
26,000
18
ND
ND
1969
2.8
18.6
1.6
BARGE
CARRIER
ST
35,000
45,000
10
41,578
31,565
22
ND
ND
1974
2.3
18.2
1.8
BARGE
CARRIER
ST
>
45,000
6
47,036
31,565
22
ND
ND
1975
2.3
18.8
1.9
BARGE
CARRIER
0
0
3
45,701
28,570
20
ND
ND
1972
2.3
19.9
2.5
BARGE
CARRIER
Total
38
45,701
28,570
20
#
N/
A
#
N/
A
1972
2.5
18.6
1.8
BULK
CARRIER
2
<
25,000
438
18,138
8,060
15
140
39%
1979
3.4
20.7
2.4
BULK
CARRIER
2
25,000
35,000
717
29,492
10,768
15
132
51%
1978
3.3
19.9
2.5
BULK
CARRIER
2
35,000
45,000
507
39,596
11,266
15
114
15%
1982
3.4
20.8
2.5
BULK
CARRIER
2
>
45,000
1,183
72,142
14,501
15
98
0%
1984
7.8
18.4
2.7
BULK
CARRIER
4
<
25,000
70
15,614
6,606
14
479
100%
1975
3.5
21.7
2.4
BULK
CARRIER
4
25,000
35,000
13
27,092
9,528
14
278
100%
1987
3.5
21.5
2.6
BULK
CARRIER
4
35,000
45,000
10
38,731
12,650
16
464
100%
1981
3.3
21.6
2.7
BULK
CARRIER
4
>
45,000
26
63,419
13,531
14
342
73%
1983
3.5
16.9
2.8
BULK
CARRIER
ST
<
25,000
5
18,314
8,384
15
123
21%
1975
5.0
14.1
1.9
BULK
CARRIER
ST
25,000
35,000
1
33,373
11,837
15
123
21%
1983
3.3
35.1
2.5
BULK
CARRIER
ST
>
45,000
21
54,624
17,614
18
123
21%
1970
2.9
16.2
2.7
BULK
CARRIER
0
0
10
46,560
11,904
15
123
21%
1981
3.7
20.4
2.5
BULK
CARRIER
Total
3,001
46,560
11,904
15
123
21%
1981
5.1
19.6
2.6
CONTAINER
SHIP
2
<
25,000
120
18,707
15,717
19
117
27%
1987
2.7
14.6
1.7
CONTAINER
SHIP
2
25,000
35,000
6
28,019
19,411
19
111
0%
1984
2.8
14.5
2.0
CONTAINER
SHIP
2
35,000
45,000
66
38,743
27,387
21
91
0%
1987
2.5
12.9
1.8
CONTAINER
SHIP
2
>
45,000
4
53,726
28,845
19
97
0%
1985
3.1
13.1
1.8
CONTAINER
SHIP
4
<
25,000
84
10,063
12,157
17
425
100%
1991
2.8
12.8
1.6
CONTAINER
SHIP
ST
<
25,000
58
21,711
25,280
22
242
53%
1974
2.3
12.4
1.7
CONTAINER
SHIP
ST
25,000
35,000
37
26,803
32,787
22
242
53%
1974
2.3
12.8
1.6
CONTAINER
SHIP
ST
35,000
45,000
1
38,656
31,565
21
242
53%
1971
2.3
18.5
1.5
CONTAINER
SHIP
0
0
3
22,127
20,366
20
242
53%
1984
3.5
12.7
2.8
CONTAINER
SHIP
Total
379
22,127
20,366
20
242
53%
1984
2.6
13.4
1.7
GENERAL
CARGO
2
<
15,000
247
9,246
6,166
15
178
91%
1981
3.5
19.9
2.2
GENERAL
CARGO
2
15,000
30,000
265
20,223
11,344
16
134
30%
1982
3.1
19.0
2.0
GENERAL
CARGO
2
30,000
45,000
41
40,358
12,943
15
97
0%
1983
3.3
22.9
2.2
GENERAL
CARGO
2
>
45,000
4
46,648
14,313
17
105
0%
1995
3.0
13.9
1.9
GENERAL
CARGO
4
<
15,000
308
5,180
3,047
12
493
100%
1979
4.1
20.2
2.2
GENERAL
CARGO
4
15,000
30,000
43
18,775
8,922
15
460
100%
1979
3.3
21.1
2.2
GENERAL
CARGO
ST
15,000
30,000
2
22,536
23,673
21
212
64%
1969
3.0
16.8
3.0
6
8
Table
6
6:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Lower
Mississippi
River
Ship
Type
Engine
Type
DWT
Range
Calls
DWT
(
Tonnes)
Power
(
hp)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
GENERAL
CARGO
0
0
1
13,112
7,128
15
212
64%
1980
3.6
15.2
2.5
GENERAL
CARGO
Total
911
13,112
7,128
15
212
64%
1980
3.6
19.9
2.1
MISCELLANEOUS
2
<
1500
1
879
3,000
12
ND
ND
1978
4.2
36.8
2.5
MISCELLANEOUS
2
>
4,500
1
9,360
10,330
18
ND
ND
1980
2.8
19.7
1.5
MISCELLANEOUS
4
<
1500
11
878
3,478
14
ND
ND
1980
3.9
11.4
2.0
MISCELLANEOUS
4
>
4,500
1
9,950
13,800
15
ND
ND
1982
3.3
13.0
1.5
MISCELLANEOUS
0
0
7
2,132
4,670
14
ND
ND
1980
5.0
17.2
2.7
MISCELLANEOUS
Total
21
2,132
4,670
14
#
N/
A
#
N/
A
1980
4.2
14.9
2.2
PASSENGER
2
<
5,000
26
4,217
29,370
21
363
53%
1983
2.4
18.7
1.7
PASSENGER
2
5,000
10,000
54
6,473
30,083
19
363
53%
1985
2.6
18.7
1.5
PASSENGER
2
>
15,000
9
19,830
14,726
18
102
0%
1988
2.8
11.5
1.6
PASSENGER
4
<
5,000
4
1,358
9,167
17
750
100%
1967
3.1
18.5
1.9
PASSENGER
4
5,000
10,000
7
6,620
36,706
20
533
100%
1991
2.6
18.7
1.6
PASSENGER
ST
5,000
10,000
52
8,721
25,504
23
363
53%
1958
2.4
18.5
1.5
PASSENGER
Total
152
7,519
27,240
21
363
53%
1976
2.5
18.2
1.6
REEFER
2
5,000
10,000
5
8,467
10,440
18
141
50%
1982
2.9
16.3
1.9
REEFER
2
10,000
15,000
8
11,457
14,812
20
123
0%
1980
2.6
18.1
1.6
REEFER
4
<
5,000
1
4,196
4,400
15
128
14%
1981
3.3
10.9
3.0
REEFER
Total
14
9,871
12,507
19
128
14%
1980
2.8
17.0
1.8
RORO
2
<
5,000
4
4,613
6,100
17
451
86%
1979
3.0
19.4
1.5
RORO
2
5,000
10,000
7
6,521
7,014
17
451
86%
1983
3.0
19.2
1.9
RORO
2
10,000
15,000
10
12,777
11,512
17
157
100%
1989
3.0
16.6
2.1
RORO
2
>
15,000
45
37,027
27,881
19
102
0%
1982
2.8
19.7
1.8
RORO
4
<
5,000
8
3,262
3,336
12
1800
100%
1980
4.0
18.4
2.2
RORO
4
5,000
10,000
26
9,883
5,998
14
500
100%
1984
3.4
13.0
1.8
RORO
Total
100
21,412
16,259
17
451
86%
1983
3.1
17.5
1.8
TANKER
2
<
30,000
314
16,943
7,930
15
168
76%
1984
3.4
25.9
2.5
TANKER
2
30,000
60,000
304
40,559
12,593
15
111
2%
1984
3.3
21.7
2.5
TANKER
2
60,000
90,000
303
77,606
15,455
15
97
0%
1984
3.4
27.0
2.4
TANKER
2
90,000
120,000
287
97,851
15,067
15
95
0%
1990
3.4
27.5
2.4
TANKER
2
120,000
150,000
49
134,806
23,453
15
99
0%
1983
3.3
10.4
1.9
TANKER
2
>
150,000
4
157,345
19,605
14
85
0%
1992
3.5
19.8
2.5
TANKER
4
<
30,000
103
9,575
5,240
14
414
74%
1981
3.7
23.1
2.6
TANKER
4
30,000
60,000
19
46,237
15,072
16
132
20%
1979
3.2
25.2
2.6
TANKER
4
60,000
90,000
53
81,275
14,394
15
296
58%
1982
3.4
25.3
2.4
TANKER
ST
30,000
60,000
10
40,102
15,190
16
132
20%
1967
3.2
25.7
2.7
TANKER
ST
60,000
90,000
3
71,694
19,728
16
132
20%
1971
3.1
14.0
2.3
TANKER
ST
90,000
120,000
3
92,809
24,167
16
132
20%
1977
3.0
26.6
2.7
TANKER
ST
120,000
150,000
1
122,249
25,647
16
132
20%
1973
3.1
29.0
2.5
TANKER
0
0
5
57,586
12,699
15
132
20%
1985
3.4
16.5
2.5
TANKER
Total
1,458
57,586
12,699
15
132
20%
1985
3.4
24.7
2.4
TUG
2
<
1,000
3
669
6,717
15
ND
ND
1978
3.4
18.4
2.2
TUG
2
<
500
28
6
3,631
12
ND
ND
1970
4.3
18.7
2.5
TUG
4
<
500
4
0
3,628
13
ND
ND
1966
3.9
17.7
2.8
TUG
0
0
44
62
3,895
13
ND
ND
1970
4.0
14.1
2.6
TUG
Total
79
62
3,895
13
#
N/
A
#
N/
A
1970
4.1
16.1
2.6
6
9
Table
6
6:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Lower
Mississippi
River
Ship
Type
Engine
Type
DWT
Range
Calls
DWT
(
Tonnes)
Power
(
hp)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
VEHICLE
CARRIER
2
>
35,000
2
40,999
14,000
15
ND
ND
ND
3.3
26.4
2.5
VEHICLE
CARRIER
Total
2
40,999
14,000
15
#
N/
A
#
N/
A
#
N/
A
3.3
26.4
2.5
Grand
Total
6,155
40,829
12,393
15
154
30%
1982
4.2
20.3
2.4
6
10
Table
6
6:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Lower
Mississippi
River
Hotel
(
hr/
call)
80.1
81.4
107.7
76.7
134.0
91.4
144.7
172.9
153.8
195.2
124.7
193.2
252.9
200.2
81.7
38.7
198.4
206.7
173.9
58.4
66.6
25.5
30.0
20.5
28.7
31.8
250.8
190.0
38.6
141.7
88.4
84.2
32.8
193.2
138.1
230.8
6
11
Table
6
6:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Lower
Mississippi
River
Hotel
(
hr/
call)
24.9
140.4
1276.3
1072.3
502.4
234.7
355.5
512.1
25.5
16.9
36.1
188.5
26.7
20.3
25.7
251.1
383.5
186.9
322.2
89.4
120.7
192.2
44.9
101.7
25.5
66.2
81.8
91.6
71.0
66.6
76.3
107.7
79.8
454.9
66.2
96.0
73.9
73.1
134.5
143.7
83.0
280.2
558.6
1420.6
847.7
752.7
6
12
Table
6
6:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Lower
Mississippi
River
Hotel
(
hr/
call)
117.3
117.3
142.1
6
13
Table
7
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Consolidated
Port
of
New
York
and
Ports
on
the
Hudson
River
Ship
Type
Stroke
DWT
Category
Calls
DWT
(
tonnes)
Power
(
hp)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr)
Man.
(
hr)
Hotel
(
hr)
BARGE
CARRIER
ST
35,000
45,000
6
46,153
31,541
22
ND
ND
1974
2.3
3.4
1.6
209.4
BARGE
CARRIER
Total
6
46,153
31,541
22
ND
ND
1974
2.3
3.4
1.6
209.4
BULK
CARRIER
2
<
25,000
69
19,957
8,666
15
152
62%
1982
3.3
14.3
2.2
120.0
BULK
CARRIER
2
25,000
35,000
85
29,401
10,766
15
130
63%
1979
3.3
11.6
2.6
184.6
BULK
CARRIER
2
35,000
45,000
64
39,241
10,891
15
118
10%
1982
3.4
14.8
2.4
102.0
BULK
CARRIER
2
>
45,000
122
71,583
14,107
14
102
0%
1986
3.5
5.9
2.9
115.6
BULK
CARRIER
4
<
25,000
16
18,260
6,523
15
573
100%
1979
3.4
7.3
2.7
219.2
BULK
CARRIER
4
25,000
35,000
1
25,739
8,200
14
157
100%
1992
3.6
4.9
1.3
104.4
BULK
CARRIER
4
35,000
45,000
1
41,513
10,000
14
ND
ND
1982
3.6
2.4
5.0
226.2
BULK
CARRIER
4
>
45,000
4
70,719
12,075
14
ND
ND
1980
3.6
4.6
2.5
83.1
BULK
CARRIER
ST
<
25,000
28
18,314
8,378
15
ND
ND
1975
3.3
5.6
1.3
39.9
BULK
CARRIER
Total
390
41,733
11,119
15
132
24%
1982
3.4
10.1
2.5
127.5
CONTAINER
SHIP
2
<
25,000
396
20,258
16,922
19
117
10%
1987
2.7
4.2
1.2
24.9
CONTAINER
SHIP
2
25,000
35,000
167
30,162
22,994
20
102
0%
1984
2.6
4.1
1.2
22.3
CONTAINER
SHIP
2
35,000
45,000
348
40,772
40,589
23
99
0%
1982
2.2
4.2
1.1
19.7
CONTAINER
SHIP
2
>
45,000
491
51,853
38,622
22
95
0%
1988
2.3
4.2
1.1
22.2
CONTAINER
SHIP
4
<
25,000
92
9,833
8,018
17
481
100%
1989
3.0
4.2
1.1
22.1
CONTAINER
SHIP
4
25,000
35,000
5
27,396
15,962
18
386
100%
1980
2.7
4.0
1.4
16.0
CONTAINER
SHIP
4
>
45,000
24
62,685
50,235
24
99
0%
1993
2.1
4.2
1.1
31.0
CONTAINER
SHIP
ST
<
25,000
234
20,521
25,642
22
ND
ND
1971
2.3
4.1
1.1
25.5
CONTAINER
SHIP
ST
25,000
35,000
33
26,207
31,541
22
ND
ND
1973
2.3
4.2
1.1
20.5
CONTAINER
SHIP
ST
35,000
45,000
14
39,433
35,483
25
ND
ND
1976
2.0
4.1
1.1
15.7
CONTAINER
SHIP
ST
>
45,000
16
47,864
79,967
23
ND
ND
1973
2.2
4.2
1.1
16.2
CONTAINER
SHIP
Total
1,820
34,197
29,929
21
131
10%
1984
2.4
4.2
1.1
22.7
GENERAL
CARGO
2
<
15,000
49
11,029
7,586
16
146
25%
1986
3.2
4.3
1.9
70.3
GENERAL
CARGO
2
15,000
30,000
122
20,397
13,611
17
132
32%
1982
2.9
6.5
1.7
54.6
GENERAL
CARGO
2
30,000
45,000
54
39,365
13,689
15
ND
ND
1981
3.2
4.7
1.5
21.1
GENERAL
CARGO
2
>
45,000
2
46,865
10,345
15
111
0%
1993
3.3
4.5
2.1
29.7
GENERAL
CARGO
4
<
15,000
79
5,539
3,765
13
616
100%
1987
3.9
7.0
1.7
78.9
GENERAL
CARGO
4
15,000
30,000
11
19,019
8,896
17
ND
ND
1982
3.0
7.6
1.9
124.3
GENERAL
CARGO
ST
<
15,000
9
12,931
14,746
19
ND
ND
1962
2.6
4.0
1.3
1060.7
GENERAL
CARGO
Total
326
18,440
10,184
16
336
58%
1983
3.3
5.9
1.7
81.4
MISCELLANEOUS
2
<
1500
2
24,713
2,200
12
ND
ND
1968
4.2
21.1
4.3
146.4
MISCELLANEOUS
2
>
4,500
2
23,945
9,000
16
ND
ND
1987
3.1
5.2
2.3
77.6
MISCELLANEOUS
4
<
1500
18
11,783
2,320
14
ND
ND
1987
3.6
4.7
1.6
53.7
MISCELLANEOUS
4
>
4,500
1
5,009
13,581
14
720
100%
1992
3.6
2.3
0.5
1.5
MISCELLANEOUS
Total
23
13,670
5,860
14
720
100%
1985
3.6
6.1
1.9
61.5
PASSENGER
2
<
5,000
26
4,300
29,370
21
ND
ND
1984
2.4
5.2
1.3
6.3
PASSENGER
2
5,000
10,000
4
5,830
19,500
19
ND
ND
1971
2.7
5.2
1.3
15.6
PASSENGER
4
<
5,000
22
1,896
15,080
18
646
100%
1987
2.9
6.0
1.5
24.1
PASSENGER
4
5,000
10,000
97
6,467
21,809
19
588
100%
1974
2.7
5.2
1.4
8.8
PASSENGER
4
10,000
15,000
1
8,600
86,140
18
514
100%
1996
2.8
5.2
1.3
72.1
PASSENGER
4
>
15,000
19
15,521
130,005
28
ND
ND
1969
1.8
5.2
1.3
8.1
PASSENGER
ST
5,000
10,000
14
9,102
41,479
25
ND
ND
1963
2.0
5.2
1.3
10.5
PASSENGER
ST
10,000
15,000
1
13,960
40,177
18
ND
ND
1961
2.8
5.2
1.3
6.2
PASSENGER
ST
>
15,000
43
16,604
43,369
24
ND
ND
1961
2.1
5.1
1.3
7.8
PASSENGER
Total
227
8,648
36,700
21
600
100%
1973
2.4
5.2
1.4
10.2
REEFER
2
5,000
10,000
3
9,864
14,865
22
ND
ND
1980
2.3
4.7
0.8
24.9
REEFER
2
10,000
15,000
60
11,757
16,661
22
114
0%
1988
2.3
4.4
1.2
36.9
7
7
Table
7
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Consolidated
Port
of
New
York
and
Ports
on
the
Hudson
River
Ship
Type
Stroke
DWT
Category
Calls
DWT
(
tonnes)
Power
(
hp)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr)
Man.
(
hr)
Hotel
(
hr)
REEFER
2
>
15,000
1
15,100
20,500
22
ND
ND
1979
2.3
4.7
0.5
8.2
REEFER
Total
64
11,721
16,637
22
114
0%
1987
2.3
4.4
1.1
35.8
RORO
2
<
10,000
73
16,968
11,478
17
97
0%
1981
3.0
4.4
1.8
28.2
RORO
2
10,000
20,000
13
15,302
11,338
16
159
100%
1990
3.1
4.5
1.7
25.5
RORO
2
20,000
30,000
3
23,242
20,271
19
ND
ND
1981
2.6
4.2
4.1
277.1
RORO
2
>
30,000
119
46,217
25,750
19
97
0%
1983
2.7
4.7
2.1
17.0
RORO
4
<
10,000
14
5,979
7,851
15
425
100%
1977
3.3
7.5
2.0
93.7
RORO
4
20,000
30,000
1
20,303
25,920
19
ND
ND
1971
2.6
4.0
1.3
1490.5
RORO
ST
10,000
20,000
1
15,946
29,570
24
ND
ND
1970
2.1
3.2
3.2
1625.7
RORO
Total
224
31,817
19,088
18
104
3%
1982
2.9
4.7
2.0
43.2
TANKER
2
<
30,000
202
22,271
8,766
15
135
27%
1985
3.4
6.1
3.4
45.6
TANKER
2
30,000
60,000
489
34,820
12,546
15
117
7%
1985
3.4
6.3
3.9
61.6
TANKER
2
60,000
90,000
155
74,752
15,612
15
101
0%
1984
3.3
5.8
3.6
64.5
TANKER
2
90,000
120,000
81
95,769
13,993
14
98
0%
1991
3.5
6.1
3.2
62.6
TANKER
2
120,000
150,000
31
140,266
20,709
15
86
0%
1987
3.4
4.4
2.7
72.3
TANKER
2
>
150,000
9
137,489
20,940
14
85
0%
1991
3.6
6.3
3.2
72.2
TANKER
4
<
30,000
65
15,402
7,551
15
351
65%
1984
3.4
5.6
3.1
29.5
TANKER
4
30,000
60,000
21
43,052
14,917
16
ND
ND
1979
3.2
5.5
3.3
57.0
TANKER
4
60,000
90,000
29
71,780
13,598
14
256
39%
1985
3.5
6.2
3.7
58.8
TANKER
ST
<
30,000
14
26,459
14,784
18
ND
ND
1964
2.8
5.4
3.2
26.4
TANKER
ST
30,000
60,000
82
36,889
15,108
16
ND
ND
1964
3.1
6.1
3.6
50.1
TANKER
ST
60,000
90,000
2
63,000
19,713
16
ND
ND
1971
3.1
5.6
3.9
85.4
TANKER
ST
>
150,000
23
35,605
35,293
16
ND
ND
1975
3.1
5.5
2.6
23.8
TANKER
Total
1,203
45,538
13,120
15
128
12%
1983
3.4
6.0
3.6
56.0
VEHICLES
CARRIER
2
<
12,500
76
11,461
11,243
18
119
6%
1982
2.8
5.1
1.6
13.9
VEHICLES
CARRIER
2
12,500
15,000
73
13,788
13,961
19
107
0%
1986
2.7
4.9
1.9
17.7
VEHICLES
CARRIER
2
15,000
17,500
72
17,041
13,984
18
113
0%
1985
2.7
4.8
1.9
15.7
VEHICLES
CARRIER
2
>
17,500
54
22,727
16,382
19
106
0%
1985
2.6
4.9
2.3
22.9
VEHICLES
CARRIER
4
<
12,500
51
10,566
13,240
18
518
100%
1980
2.7
5.0
2.2
30.0
VEHICLES
CARRIER
4
12,500
15,000
19
13,498
14,287
18
520
100%
1980
2.9
4.9
1.9
24.7
VEHICLES
CARRIER
4
15,000
17,500
2
15,396
12,555
18
ND
ND
1982
2.8
4.9
1.3
6.1
VEHICLES
CARRIER
4
>
17,500
2
19,422
16,880
18
ND
ND
1981
2.8
5.1
2.1
6.8
VEHICLES
CARRIER
Total
349
14,890
13,670
18
178
18%
1984
2.7
4.9
2.0
19.3
Grand
Total
4,632
33,449
20,932
18
162
18%
1983
2.8
5.4
2.0
45.0
7
8
Table
8
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Delaware
River
Ports
Including
Philadelphia,
PA
Ship
Type
Engine
Type
DWT
Range
Calls
DWT
(
tonnes)
Power
(
HP)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
BULK
CARRIER
2
<
25,000
109
18,365
9,665
14
144
68%
1981
3.5
14.9
1.8
BULK
CARRIER
2
25,000
35,000
126
29,721
9,696
15
126
52%
1982
3.4
14.7
1.7
BULK
CARRIER
2
35,000
45,000
77
38,659
10,320
14
113
11%
1983
3.5
15.2
1.8
BULK
CARRIER
2
>
45,000
81
79,616
16,328
15
113
0%
1983
3.4
15.3
1.7
BULK
CARRIER
4
<
25,000
17
13,853
7,504
15
473
100%
1977
3.3
14.4
1.6
BULK
CARRIER
ST
<
25,000
1
18,314
8,300
15
131
36%
1975
3.3
12.3
1.5
BULK
CARRIER
Total
411
40,274
11,018
15
131
36%
1982
3.4
14.9
1.7
CONTAINER
SHIP
2
<
25,000
242
18,425
17,757
19
106
0%
1987
2.6
11.4
1.2
CONTAINER
SHIP
2
25,000
35,000
27
27,503
16,327
18
229
38%
1977
2.8
12.9
1.0
CONTAINER
SHIP
4
<
25,000
129
12,143
10,898
18
429
100%
1989
2.8
12.5
1.2
CONTAINER
SHIP
Total
398
18,208
15,383
19
229
38%
1987
2.7
11.9
1.1
GENERAL
CARGO
2
<
15,000
132
6,833
5,784
14
437
89%
1985
3.7
13.3
1.4
GENERAL
CARGO
2
15,000
30,000
90
18,918
10,456
16
140
63%
1980
3.2
14.6
2.0
GENERAL
CARGO
2
30,000
45,000
8
38,907
12,876
14
96
0%
1981
3.5
12.3
1.2
GENERAL
CARGO
2
>
45,000
1
46,956
12,170
14
117
0%
1992
3.6
12.4
1.0
GENERAL
CARGO
4
<
15,000
166
5,316
3,944
14
743
100%
1988
3.7
12.9
1.6
GENERAL
CARGO
4
15,000
30,000
16
18,775
7,536
15
561
90%
1981
3.4
15.1
1.7
GENERAL
CARGO
ST
<
15,000
1
10,538
6,284
14
561
90%
1918
3.6
14.2
1.0
GENERAL
CARGO
Total
414
10,538
6,284
14
561
90%
1985
3.6
13.4
1.6
MISCELLANEOUS
2
<
1,000
8
0
2,400
14
ND
ND
1943
3.6
10.9
1.2
MISCELLANEOUS
4
<
1,000
4
448
1,293
14
ND
ND
1978
3.6
12.4
1.4
MISCELLANEOUS
Total
12
149
2,031
14
#
N/
A
#
N/
A
1955
3.6
11.4
1.3
PASSENGER
4
<
5,000
6
1,332
16,108
18
532
100%
1983
2.9
11.4
1.0
PASSENGER
4
5,000
10,000
6
7,257
20,776
18
616
100%
1966
2.7
11.4
1.0
PASSENGER
ST
5,000
10,000
9
9,076
40,649
26
582
100%
1964
2.0
12.6
1.0
PASSENGER
ST
10,000
15,000
1
13,016
169,708
30
582
100%
1952
1.7
5.5
3.5
PASSENGER
Total
22
7,828
34,403
22
582
100%
1969
2.4
11.6
1.1
REEFER
2
<
5,000
28
4,988
9,553
18
146
65%
1984
2.7
10.7
1.6
REEFER
2
5,000
10,000
87
7,667
9,706
18
141
59%
1988
2.7
10.7
1.3
REEFER
2
10,000
15,000
153
11,833
12,500
19
116
0%
1987
2.6
12.2
1.4
REEFER
2
>
15,000
3
15,696
18,467
20
155
41%
1979
2.6
11.4
1.3
8
8
Table
8
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Delaware
River
Ports
Including
Philadelphia,
PA
Ship
Type
Engine
Type
DWT
Range
Calls
DWT
(
tonnes)
Power
(
HP)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
REEFER
4
<
5,000
16
4,880
7,048
16
202
100%
1992
3.1
13.6
2.5
REEFER
4
5,000
10,000
15
6,555
6,837
17
402
100%
1989
3.0
13.0
1.9
REEFER
4
10,000
15,000
3
11,087
15,672
22
428
100%
1992
2.3
11.2
1.0
REEFER
Total
305
10,137
10,958
19
155
41%
1987
2.7
11.7
1.5
RORO
2
<
15,000
26
7,074
8,280
17
242
100%
1981
2.9
13.2
1.2
RORO
2
15,000
30,000
5
22,845
12,852
18
102
0%
1988
2.8
8.8
1.0
RORO
4
<
15,000
26
7,601
8,553
14
720
100%
1981
3.7
13.3
1.2
RORO
Total
57
9,142
8,805
16
456
69%
1982
3.3
12.9
1.2
TANKER
2
<
30,000
237
13,261
10,008
14
132
30%
1984
3.6
14.4
2.1
TANKER
2
30,000
60,000
78
43,461
12,616
15
125
41%
1982
3.4
14.2
2.4
TANKER
2
60,000
90,000
111
77,375
16,026
15
95
0%
1983
3.3
14.9
2.2
TANKER
2
90,000
120,000
91
98,373
15,451
15
97
0%
1991
3.4
13.8
2.4
TANKER
2
120,000
150,000
150
137,083
23,046
15
93
0%
1982
3.4
16.5
3.2
TANKER
2
>
150,000
32
155,676
25,559
15
85
0%
1983
3.3
16.3
3.2
TANKER
4
<
30,000
57
15,655
7,077
14
413
89%
1981
3.7
14.0
2.0
TANKER
4
30,000
60,000
5
44,153
15,360
15
133
19%
1980
3.3
15.7
2.8
TANKER
4
60,000
90,000
17
80,320
14,305
15
416
75%
1981
3.4
14.7
2.6
TANKER
ST
<
30,000
24
26,755
14,646
16
133
19%
1959
3.1
14.0
2.3
TANKER
ST
30,000
60,000
54
35,574
15,498
16
133
19%
1962
3.1
13.8
2.0
TANKER
ST
90,000
120,000
2
92,760
23,923
16
133
19%
1976
3.1
14.6
2.3
TANKER
ST
>
150,000
10
276,808
36,324
16
133
19%
1973
3.2
15.4
3.0
TANKER
Total
868
74,084
15,137
15
133
19%
1982
3.4
14.8
2.4
VEHICLE
CARRIER
2
<
12,500
39
12,115
11,877
18
117
0%
1982
2.8
7.6
1.2
VEHICLE
CARRIER
2
12,500
15,000
5
13,813
12,859
18
111
0%
1986
2.7
10.1
1.3
VEHICLE
CARRIER
2
15,000
17,500
7
16,209
13,911
18
111
0%
1984
2.7
9.0
1.0
VEHICLE
CARRIER
2
>
17,500
13
18,558
15,224
19
101
0%
1987
2.7
6.9
1.0
VEHICLE
CARRIER
4
<
12,500
8
10,382
13,150
18
527
100%
1977
2.8
13.2
1.4
VEHICLE
CARRIER
4
12,500
15,000
1
14,501
14,770
18
143
8%
1983
2.7
9.5
1.0
VEHICLE
CARRIER
Total
73
13,678
12,914
18
143
8%
1983
2.7
8.4
1.2
Grand
Total
2,560
38,991
12,476
16
236
0
1984
3.2
13.5
1.8
8
9
Table
8
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Delaware
River
Ports
Including
Philadelphia,
PA
Ship
Type
Engine
Type
DWT
Range
Calls
DWT
(
tonnes)
Power
(
HP)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
Ship
Type
Engine
Type
DWT
Range
Calls
DWT
(
tonnes)
Power
(
HP)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
8
10
Table
8
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Delaware
River
Ports
Including
Philadelphia,
PA
Hotel
(
hr/
call)
81.0
100.8
95.1
110.9
86.3
64.3
95.8
37.4
35.7
25.8
33.5
63.0
119.3
62.3
33.0
98.1
122.6
18.1
91.3
45.4
41.1
44.0
24.3
23.4
15.9
20.5
20.5
51.4
56.8
64.8
33.6
8
11
Table
8
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Delaware
River
Ports
Including
Philadelphia,
PA
Hotel
(
hr/
call)
87.8
81.7
54.0
63.0
67.1
43.0
57.7
60.7
72.3
62.8
70.8
83.0
137.4
122.6
61.6
63.9
77.3
88.4
65.8
70.2
104.1
85.1
17.7
27.2
23.9
25.2
39.9
18.0
22.7
74.1
8
12
Table
8
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Delaware
River
Ports
Including
Philadelphia,
PA
Hotel
(
hr/
call)
Hotel
(
hr/
call)
8
13
Table
9
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
Puget
Sound
Area
Ports
Including
Seattle,
WA
Ship
Type
Manip
Stroke
type
DWT
Range
Calls
DWT
(
tonnes)
Power
(
HP)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
BULK
CARRIER
2
<
25,000
165
22,130
7,073
14
150
94%
1990
3.6
15.4
1.4
BULK
CARRIER
2
25,000
35,000
306
27,887
8,155
14
124
32%
1988
3.5
16.5
1.5
BULK
CARRIER
2
35,000
45,000
167
40,489
10,752
15
107
3%
1985
3.4
16.3
1.6
BULK
CARRIER
2
>
45,000
216
66,419
12,646
15
98
0%
1987
3.5
15.8
2.0
BULK
CARRIER
4
<
25,000
8
6,436
3,625
13
ND
ND
1977
4.0
17.7
5.1
BULK
CARRIER
4
25,000
35,000
2
32,019
10,400
15
518
100%
1983
3.5
14.6
1.4
BULK
CARRIER
4
35,000
45,000
2
41,642
10,943
14
117
0%
1989
3.6
13.4
0.9
BULK
CARRIER
4
>
45,000
13
63,029
14,806
15
400
100%
1983
3.4
16.6
2.1
BULK
CARRIER
ST
>
45,000
13
82,035
17,111
16
ND
ND
1968
3.1
21.5
1.4
BULK
CARRIER
Total
892
39,661
9,727
14
123
34%
1987
3.5
16.2
1.7
CONTAINER
SHIP
2
<
25,000
184
19,019
18,365
19
135
77%
1985
2.7
17.9
1.0
CONTAINER
SHIP
2
25,000
35,000
135
31,480
26,364
20
101
0%
1984
2.5
16.6
0.9
CONTAINER
SHIP
2
35,000
45,000
363
40,261
31,808
22
93
0%
1987
2.3
16.4
1.0
CONTAINER
SHIP
2
>
45,000
276
56,958
51,033
23
95
0%
1992
2.2
16.0
0.9
CONTAINER
SHIP
4
<
25,000
8
19,987
12,405
19
428
100%
1988
2.7
16.0
1.1
CONTAINER
SHIP
ST
<
25,000
3
19,800
26,797
21
ND
ND
1980
2.4
18.2
1.5
CONTAINER
SHIP
ST
25,000
35,000
93
28,628
30,080
20
ND
ND
1973
2.5
16.5
0.9
CONTAINER
SHIP
ST
35,000
45,000
64
38,988
31,565
21
ND
ND
1973
2.4
15.5
0.9
CONTAINER
SHIP
ST
>
45,000
24
47,851
80,006
23
ND
ND
1972
2.2
16.2
0.9
CONTAINER
SHIP
Total
1,150
38,791
34,337
21
98
5%
1985
2.4
16.5
0.9
FISHING
2
<
1500
12
789
1,897
12
ND
ND
1973
4.3
21.1
5.9
FISHING
2
1,500
3,000
3
1,883
3,626
14
150
100%
1987
3.5
15.9
1.8
FISHING
2
3,000
4,500
1
4,500
10,768
18
660
100%
1996
2.8
16.7
0.9
FISHING
2
>
4,500
2
9,360
10,331
18
ND
ND
1984
2.8
16.0
3.7
FISHING
4
<
1500
20
698
1,702
12
773
100%
1983
4.3
20.1
4.3
FISHING
4
1,500
3,000
10
1,861
5,159
16
720
100%
1978
3.1
13.2
1.8
FISHING
4
3,000
4,500
2
3,372
14,398
15
500
100%
1991
3.3
16.3
7.9
FISHING
4
>
4,500
27
5,805
8,048
14
720
100%
1993
3.6
14.8
4.3
FISHING
ST
>
4,500
4
19,286
37,976
20
ND
ND
1964
2.5
13.0
4.1
FISHING
Total
81
3,846
6,774
14
686
100%
1984
3.7
16.9
4.2
GENERAL
CARGO
2
<
15,000
7
3,540
3,647
12
200
100%
1987
4.3
17.9
2.8
GENERAL
CARGO
2
15,000
30,000
73
21,745
11,495
16
130
29%
1981
3.1
18.4
1.5
GENERAL
CARGO
2
30,000
45,000
52
41,323
12,006
15
104
5%
1984
3.3
13.3
1.0
GENERAL
CARGO
2
>
45,000
77
45,539
10,164
15
98
0%
1988
3.3
16.2
1.1
GENERAL
CARGO
4
<
15,000
21
9,063
9,493
15
278
100%
1982
3.5
17.9
2.1
GENERAL
CARGO
4
15,000
30,000
32
20,039
20,164
18
ND
ND
1985
2.9
17.6
2.1
GENERAL
CARGO
ST
<
15,000
1
14,897
15,289
19
ND
ND
1966
2.6
18.3
0.9
GENERAL
CARGO
Total
263
30,851
11,907
16
122
17%
1984
3.2
16.6
1.4
MISCELANEOUS
2
(
blank)
3
7,900
9,387
14
ND
ND
1991
3.6
19.3
2.4
MISCELANEOUS
2
(
blank)
1
1,200
1,860
12
ND
ND
1990
4.2
22.4
0.9
MISCELANEOUS
4
(
blank)
4
761
3,486
13
1225
100%
1986
3.8
16.1
3.2
MISCELANEOUS
ST
(
blank)
3
3,988
8,483
15
ND
ND
1940
3.3
15.4
0.9
MISCELANEOUS
Total
11
3,548
5,827
14
1225
100%
1983
3.7
17.3
2.1
PASSENGER
2
<
5,000
3
4,226
29,370
21
ND
ND
1983
2.4
14.5
1.4
PASSENGER
2
5,000
10,000
1
5,340
32,350
19
ND
ND
1986
2.6
17.5
0.9
9
8
Table
9
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
Puget
Sound
Area
Ports
Including
Seattle,
WA
Ship
Type
Manip
Stroke
type
DWT
Range
Calls
DWT
(
tonnes)
Power
(
HP)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
PASSENGER
4
<
5,000
4
850
9,906
16
788
100%
1983
3.2
17.1
0.9
PASSENGER
4
5,000
10,000
3
7,089
45,589
21
514
100%
1993
2.4
16.2
0.9
PASSENGER
ST
5,000
10,000
2
8,706
25,154
23
ND
ND
1958
2.2
17.6
0.9
PASSENGER
Total
13
4,623
26,704
19
670
100%
1982
2.6
16.4
1.0
REEFER
2
<
5,000
17
3,307
4,767
15
155
100%
1986
3.3
15.6
3.9
REEFER
2
5,000
10,000
21
6,642
6,945
17
163
100%
1988
3.0
14.1
3.4
REEFER
2
10,000
15,000
7
11,746
11,969
20
115
0%
1988
2.6
15.6
2.4
REEFER
4
<
5,000
7
2,004
1,730
11
230
100%
1970
4.7
22.1
1.5
REEFER
4
5,000
10,000
8
5,804
5,676
16
634
100%
1991
3.1
16.7
1.0
REEFER
Total
60
5,640
6,136
16
272
88%
1986
3.3
16.0
2.9
RORO
2
<
10,000
11
7,976
6,738
16
174
75%
1988
3.3
22.1
1.3
RORO
2
10,000
20,000
16
11,346
8,004
16
162
81%
1992
3.3
19.9
0.9
RORO
2
20,000
30,000
16
26,787
18,649
19
ND
ND
1983
2.6
17.9
0.9
RORO
2
>
30,000
4
41,856
15,136
14
ND
ND
1981
3.5
14.2
0.9
RORO
ST
10,000
20,000
121
17,084
29,764
25
ND
ND
1976
2.0
17.0
1.4
RORO
Total
168
17,455
24,777
23
166
79%
1979
2.3
17.6
1.3
TANKER
2
<
30,000
66
19,629
9,104
15
176
79%
1986
3.5
19.0
4.3
TANKER
2
30,000
60,000
79
46,934
12,451
15
107
0%
1984
3.4
15.9
4.0
TANKER
2
60,000
90,000
18
71,315
15,262
15
89
0%
1984
3.3
16.0
3.3
TANKER
2
90,000
120,000
20
100,679
14,738
14
94
0%
1991
3.5
15.8
2.6
TANKER
2
120,000
150,000
26
123,742
26,146
16
ND
ND
1974
3.1
14.5
7.2
TANKER
4
<
30,000
12
10,056
4,864
13
245
33%
1976
4.0
15.6
0.9
TANKER
4
30,000
60,000
1
37,350
11,700
14
520
100%
1981
3.6
17.0
4.2
TANKER
ST
<
30,000
18
19,992
14,795
18
ND
ND
1964
2.8
14.4
3.8
TANKER
ST
30,000
60,000
35
39,541
13,809
16
ND
ND
1969
3.1
15.4
3.5
TANKER
ST
60,000
90,000
125
71,997
19,286
17
ND
ND
1970
3.0
16.6
3.4
TANKER
ST
90,000
120,000
29
91,915
23,095
16
ND
ND
1977
3.2
15.9
5.3
TANKER
ST
120,000
150,000
119
122,732
26,360
16
ND
ND
1974
3.1
14.7
6.2
TANKER
ST
>
150,000
5
189,978
27,620
14
ND
ND
1978
3.5
11.1
1.9
TANKER
Total
553
73,490
18,099
16
129
22%
1977
3.2
16.0
4.4
VEHICLES
CARRIER
2
<
12,500
27
10,286
10,289
17
158
82%
1983
3.0
20.0
0.9
VEHICLES
CARRIER
2
12,500
15,000
33
13,709
14,049
18
109
9%
1985
2.7
18.6
1.2
VEHICLES
CARRIER
2
15,000
17,500
49
16,272
14,023
18
120
0%
1984
2.8
17.3
1.5
VEHICLES
CARRIER
2
>
17,500
7
19,783
15,501
18
98
0%
1985
2.7
18.4
1.7
VEHICLES
CARRIER
4
<
12,500
19
10,981
13,118
18
ND
ND
1981
2.7
20.2
0.9
VEHICLES
CARRIER
4
12,500
15,000
4
12,917
13,600
19
ND
ND
1980
2.6
20.2
0.9
VEHICLES
CARRIER
4
15,000
17,500
2
17,224
16,880
19
450
100%
1978
2.6
18.9
0.9
VEHICLES
CARRIER
4
>
17,500
1
19,712
16,880
18
ND
ND
1981
2.8
19.4
3.1
VEHICLES
CARRIER
Total
142
13,946
13,319
18
137
22%
1984
2.8
18.7
1.2
Grand
Total
3,333
40,347
20,617
18
139
25%
1984
2.9
16.5
1.9
9
9
Table
9
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
Puget
Sound
Area
Ports
Including
Seattle,
WA
Hotel
(
hr/
call)
70.6
128.1
88.1
154.1
84.4
96.8
64.3
177.9
58.8
115.4
34.3
25.9
30.9
28.4
59.5
138.7
40.4
17.8
30.3
30.8
1291.8
33.4
1432.0
654.3
915.6
321.5
1405.4
399.2
534.6
686.4
65.2
52.4
32.0
23.2
353.6
112.5
163.9
71.9
2189.6
472.8
300.1
49.0
762.6
67.1
7.7
9
10
Table
9
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
Puget
Sound
Area
Ports
Including
Seattle,
WA
Hotel
(
hr/
call)
9.5
54.6
67.5
42.0
315.7
163.2
201.5
259.8
51.5
207.3
30.1
24.4
25.0
10.3
73.8
60.1
43.7
67.6
45.2
64.0
63.9
16.2
84.7
59.7
45.3
62.4
52.1
62.8
103.4
58.3
32.2
19.0
19.6
19.9
20.2
13.5
22.0
21.1
21.8
83.9
9
11
Table
10
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Port
of
Corpus
Christi,
TX
Port
of
Corpus
Christ,
TX
SOURCE:
EPA
document
Commercial
Marine
Activity
of
Deep
Sea
Ports
,
Table
10
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Port
of
Corpus
Christi,
TX
Ship
Type
Manip
Stroke
type
DWT
Category
DWT
Range
Calls
DWT
(
tonnes)
Power
(
HP)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
BARGE
CARRIER
ST
2
25,000
35,000
2
30,298
31,564
22
ND
ND
1972
2.3
5.0
BARGE
CARRIER
Total
2
30,298
31,564
22
ND
ND
1972
2.3
5.0
BULK
CARRIER
2
1
<
25,000
38
14,322
6,448
13
151
67%
1974
3.9
5.0
BULK
CARRIER
2
2
25,000
35,000
35
28,117
11,029
15
150
100%
1977
3.3
5.0
BULK
CARRIER
2
3
35,000
45,000
21
39,326
11,298
15
108
17%
1981
3.3
5.0
BULK
CARRIER
2
4
45,000
90,000
60
68,076
14,830
15
93
0%
1982
3.4
5.0
BULK
CARRIER
2
5
>
90,000
36
133,928
19,693
15
91
0%
1989
3.4
6.6
BULK
CARRIER
4
1
<
25,000
5
18,600
8,100
15
ND
ND
1978
3.3
5.0
BULK
CARRIER
4
2
25,000
35,000
6
29,485
11,036
14
460
100%
1979
3.6
5.0
BULK
CARRIER
4
3
35,000
45,000
1
36,414
15,600
17
ND
ND
1981
2.9
5.0
BULK
CARRIER
4
4
45,000
90,000
7
70,656
12,057
14
440
100%
1981
3.6
5.0
BULK
CARRIER
Total
209
57,708
12,793
15
162
28%
1981
3.5
5.3
CONTAINER
SHIP
2
4
>
45,000
1
65,642
66,398
24
100
0%
1996
2.1
5.0
CONTAINER
SHIP
Total
1
65,642
66,398
24
100
0%
1996
2.1
5.0
TANKER
2
1
<
30,000
66
19,231
8,852
15
183
88%
1983
3.4
5.0
TANKER
2
2
30,000
60,000
276
44,487
11,085
15
123
44%
1984
3.4
5.0
TANKER
2
3
60,000
90,000
161
76,375
15,241
15
99
0%
1984
3.3
5.0
TANKER
2
4
90,000
120,000
171
98,320
15,403
15
89
0%
1991
3.4
6.6
TANKER
2
5
120,000
150,000
31
139,846
21,270
15
85
0%
1987
3.4
6.6
TANKER
2
6
above
150,000
5
155,042
20,124
14
85
0%
1991
3.5
6.6
TANKER
4
1
<
30,000
34
8,311
4,828
14
532
78%
1984
3.7
5.0
TANKER
4
2
30,000
60,000
24
43,869
15,369
16
ND
ND
1975
3.2
5.0
TANKER
4
3
60,000
90,000
27
77,584
14,563
15
275
50%
1983
3.4
5.0
TANKER
ST
1
<
30,000
2
25,943
10,968
16
ND
ND
1954
3.2
5.0
TANKER
ST
2
30,000
60,000
522
37,414
13,060
16
ND
ND
1957
3.2
5.0
TANKER
ST
3
60,000
90,000
4
63,000
19,727
16
ND
ND
1971
3.1
5.0
TANKER
ST
4
90,000
120,000
9
91,898
24,166
16
ND
ND
1977
3.1
6.6
TANKER
Total
1,332
53,948
13,178
15
128
24%
1974
3.3
5.3
GENERAL
CARGO
2
1
<
25,000
6
9,861
5,483
15
200
100%
1319
3.4
5.0
10
5
Table
11
6:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Port
of
Tampa,
FL
Tampa
Harbor,
FL
SOURCE:
EPA
document
Commercial
Marine
Activity
of
Deep
Sea
Ports
,
Table
11
6:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Port
of
Tampa,
FL
Ship
type
Engine
Type
DWT
CAT
DWT
RANGE
Calls
DWT
(
tonnes)
Power
(
HP)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
BULK
CARRIER
2
1
<
25,000
52
18,828
8,478
15
158
56%
1979
3.4
5.6
BULK
CARRIER
2
2
25,000
35,000
82
29,575
9,367
15
125
32%
1983
3.4
5.5
BULK
CARRIER
2
3
35,000
45,000
66
39,389
10,670
15
114
14%
1983
3.4
5.4
BULK
CARRIER
2
4
>
45,000
117
57,952
13,451
15
110
0%
1979
3.4
5.4
BULK
CARRIER
4
1
<
25,000
8
15,900
6,581
14
124
23%
1975
3.5
5.5
BULK
CARRIER
4
2
25,000
35,000
2
29,089
8,198
14
157
100%
1995
3.6
5.4
BULK
CARRIER
4
3
35,000
45,000
1
41,455
11,336
14
117
0%
1995
3.6
5.3
BULK
CARRIER
ST
4
>
45,000
1
92,854
10,876
16
124
23%
1975
3.1
5.3
BULK
CARRIER
0
0
0
229
39,830
10,876
15
124
23%
1981
3.4
5.4
BULK
CARRIER
Total
558
39,830
10,876
15
124
23%
1981
3.4
5.4
CONTAINER
SHIP
2
3
35,000
45,000
2
36,750
23,945
21
259
50%
1986
2.4
5.7
CONTAINER
SHIP
2
4
>
45,000
1
60,639
51,920
24
90
0%
1990
2.1
5.3
CONTAINER
SHIP
4
1
<
25,000
1
21,540
16,993
20
428
100%
1993
2.5
4.4
CONTAINER
SHIP
Total
4
38,920
29,201
22
259
50%
1989
2.3
5.3
GENERAL
CARGO
2
1
<
15,000
37
6,769
4,048
14
197
100%
1979
3.7
5.5
GENERAL
CARGO
2
2
15,000
30,000
22
21,512
9,736
16
130
50%
1982
3.2
5.8
GENERAL
CARGO
2
3
30,000
45,000
2
34,336
10,300
15
95
0%
1980
3.5
5.7
GENERAL
CARGO
2
4
>
45,000
1
46,641
8,950
15
105
0%
1995
3.3
5.3
GENERAL
CARGO
4
1
<
15,000
70
3,158
2,322
13
554
100%
1978
3.9
5.8
GENERAL
CARGO
4
2
15,000
30,000
5
19,880
10,120
15
280
86%
1981
3.5
5.9
GENERAL
CARGO
ST
1
<
15,000
14
14,897
4,428
19
280
86%
1966
2.6
5.4
GENERAL
CARGO
0
0
0
191
9,060
4,428
14
280
86%
1978
3.6
5.8
GENERAL
CARGO
Total
342
9,060
4,428
14
280
86%
1978
3.6
5.8
PASSENGER
2
1
<
5,000
26
4,243
29,370
21
559
75%
1984
2.4
6.0
PASSENGER
2
2
5,000
10,000
55
6,456
29,961
19
120
0%
1984
2.6
6.0
PASSENGER
4
1
<
5,000
5
1,254
9,313
17
769
100%
1979
3.0
6.0
PASSENGER
4
2
5,000
10,000
2
5,500
20,934
18
580
100%
1987
2.8
6.0
PASSENGER
0
0
0
32
5,485
28,408
20
559
75%
1984
2.5
6.0
PASSENGER
Total
120
5,485
28,408
20
559
75%
1984
2.5
6.0
REEFER
2
2
5,000
10,000
46
6,417
8,160
18
158
70%
1986
2.8
4.0
11
7
Table
11
6:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Port
of
Tampa,
FL
Tampa
Harbor,
FL
REEFER
2
3
10,000
15,000
6
11,054
12,983
20
120
0%
1976
2.6
3.5
REEFER
4
1
<
5,000
1
3,536
3,002
14
600
100%
1978
3.6
3.5
REEFER
4
2
5,000
10,000
1
6,502
6,933
16
168
100%
1995
3.1
3.5
REEFER
Total
54
6,880
8,578
18
168
70%
1985
2.8
3.9
RORO
2
1
<
5,000
30
872
1,948
14
650
100%
1959
3.6
5.6
RORO
4
1
<
5,000
12
2,697
2,849
13
750
100%
1977
3.9
6.0
RORO
4
2
5,000
10,000
2
7,440
9,000
15
600
100%
1993
3.3
6.0
RORO
Total
44
1,668
2,514
14
650
100%
1966
3.7
5.8
TANKER
2
1
<
30,000
111
19,007
11,871
16
136
47%
1978
3.1
5.5
TANKER
2
2
30,000
60,000
17
39,778
16,976
17
122
0%
1977
3.0
5.5
TANKER
4
1
<
30,000
45
3,121
1,542
11
459
100%
1972
4.5
5.6
TANKER
4
2
30,000
60,000
3
37,874
16,000
16
150
44%
1971
3.1
5.4
TANKER
ST
1
<
30,000
37
24,854
9,794
14
150
44%
1947
3.5
5.7
TANKER
ST
2
30,000
60,000
121
37,075
9,794
15
150
44%
1955
3.3
5.4
TANKER
ST
6
>
150,000
1
228,274
9,794
17
150
44%
1977
2.9
6.0
TANKER
0
0
0
148
25,893
9,794
15
150
44%
1966
3.4
5.4
TANKER
Total
483
25,893
9,794
15
150
44%
1966
3.4
5.5
TUG
2
0
0
701
75
4,905
12
ND
ND
1976
4.3
5.4
TUG
4
0
0
166
157
9,206
14
ND
ND
1978
3.7
5.6
TUG
0
0
0
459
91
5,768
13
ND
ND
1976
4.2
5.5
TUG
Total
1,326
91
5,768
13
#
N/
A
#
N/
A
1976
4.2
5.4
VEHICLES
CARRIER
2
2
12,500
15,000
2
13,208
11,500
18
111
0%
1984
2.8
5.7
VEHICLES
CARRIER
Total
2
13,208
11,500
18
111
0%
1984
2.8
5.7
BARGE
DRY
CARGO
0
0
0
525
ND
ND
ND
ND
ND
ND
ND
5.4
BARGE
DRY
CARGO
Total
525
#
N/
A
#
N/
A
#
N/
A
#
N/
A
#
N/
A
#
N/
A
#
N/
A
5.4
BARGE
TANKER
0
0
0
852
ND
ND
ND
ND
ND
ND
ND
5.5
BARGE
TANKER
Total
852
#
N/
A
#
N/
A
#
N/
A
#
N/
A
#
N/
A
#
N/
A
#
N/
A
5.5
MISCELLANEOUS
2
1
<
1,000
4
113
895
12
430
100%
1977
4.2
5.9
MISCELLANEOUS
2
3
5,000
10,000
1
9,360
10,332
18
430
100%
1984
2.8
3.5
11
8
Table
11
6:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Port
of
Tampa,
FL
Man.
(
hr/
call)
Hotel
(
hr/
call)
1.9
76.2
2.8
87.4
2.7
96.1
3.4
71.9
1.4
346.8
3.3
64.6
3.0
223.2
9.0
265.3
1.5
56.3
2.3
75.6
3.3
276.3
1.0
7.1
3.0
125.9
2.6
171.4
1.8
46.2
1.4
80.8
1.0
43.5
5.7
120.8
1.2
98.7
1.7
51.4
1.2
35.7
1.2
62.3
1.3
68.0
1.1
15.1
1.0
10.2
1.8
224.3
1.0
9.5
1.0
71.8
1.0
36.6
1.0
38.8
11
9
Table
11
6:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Port
of
Tampa,
FL
5.0
352.4
1.0
86.2
1.0
81.8
1.5
75.3
2.0
60.3
1.5
216.1
1.5
199.9
1.9
110.3
1.3
34.3
1.7
37.0
1.4
86.0
1.8
35.9
1.1
21.1
1.9
47.7
2.4
640.7
1.2
21.9
1.4
39.0
2.1
55.7
2.1
64.9
1.6
49.6
1.9
54.7
1.3
203.3
1.3
203.3
1.8
91.8
1.8
91.8
2.0
149.6
2.0
149.6
1.1
83.5
1.0
319.7
11
10
Table
12
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
Baltimore
Harbor,
MD
Ship
Type
Engine
Type
DWT
Range
Calls
DWT
(
tonnes)
Power
(
hp)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Biuld
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
Hotel
(
hr/
call)
BULK
CARRIER
2
<
25,000
50
18,690
8,707
15
146
63%
1981
3.4
16.0
1.5
113.5
BULK
CARRIER
2
25,000
35,000
85
29,958
10,618
15
131
61%
1982
3.3
16.7
1.5
167.7
BULK
CARRIER
2
35,000
45,000
73
39,143
10,435
15
109
5%
1984
3.4
16.6
1.6
133.1
BULK
CARRIER
2
45,000
90,000
144
68,715
13,970
14
100
3%
1986
3.5
17.4
1.5
79.1
BULK
CARRIER
2
>
90,000
76
133,223
18,241
14
86
0%
1985
3.5
18.9
1.4
49.5
BULK
CARRIER
4
<
25,000
10
12,466
5,700
14
ND
ND
1974
3.7
14.7
1.5
63.6
BULK
CARRIER
4
25,000
35,000
3
32,322
8,602
13
157
100%
1984
4.0
20.1
1.3
181.8
BULK
CARRIER
4
45,000
90,000
3
89,127
12,600
14
404
100%
1982
3.6
17.5
1.3
91.0
BULK
CARRIER
4
>
90,000
2
158,526
17,850
14
399
100%
1986
3.6
17.2
2.5
64.7
BULK
CARRIER
ST
<
25,000
29
18,232
9,115
15
ND
ND
1975
3.3
14.2
1.3
30.3
BULK
CARRIER
ST
25,000
35,000
1
33,373
11,837
15
ND
ND
1983
3.3
10.7
1.3
1.2
BULK
CARRIER
ST
>
90,000
5
159,743
27,126
16
ND
ND
1970
3.1
17.2
1.3
61.4
BULK
CARRIER
Total
481
59,304
12,611
15
111
16%
1983
3.4
17.0
1.5
98.8
CONTAINER
SHIP
2
<
25,000
247
21,107
18,352
19
118
16%
1987
2.6
14.1
1.3
23.7
CONTAINER
SHIP
2
25,000
35,000
96
29,065
16,979
19
102
0%
1984
2.7
14.5
1.3
17.2
CONTAINER
SHIP
2
35,000
45,000
92
39,319
46,221
23
105
0%
1979
2.2
16.9
1.4
16.1
CONTAINER
SHIP
2
45,000
90,000
72
55,730
41,379
22
94
0%
1988
2.2
17.1
1.3
13.7
CONTAINER
SHIP
4
<
25,000
13
8,793
6,508
16
475
100%
1984
3.2
13.4
1.3
105.4
CONTAINER
SHIP
ST
<
25,000
3
18,832
28,112
23
ND
ND
1973
2.2
14.1
1.3
12.7
CONTAINER
SHIP
ST
25,000
35,000
18
26,826
35,181
20
ND
ND
1973
2.5
15.5
1.3
20.7
CONTAINER
SHIP
Total
541
30,106
26,242
20
117
10%
1985
2.5
15.1
1.3
21.7
GENERAL
CARGO
2
<
25,000
114
16,545
10,516
16
154
55%
1982
3.1
16.7
1.5
108.3
GENERAL
CARGO
2
25,000
35,000
13
30,370
10,302
15
108
0%
1984
3.3
16.5
2.0
96.8
GENERAL
CARGO
2
35,000
45,000
9
41,141
13,058
16
ND
ND
1984
3.1
14.3
1.3
29.8
GENERAL
CARGO
2
45,000
90,000
1
45,000
12,300
16
93
0%
1994
3.1
17.4
1.3
180.0
GENERAL
CARGO
4
<
25,000
80
5,301
3,469
13
642
100%
1988
3.8
19.0
1.4
55.7
GENERAL
CARGO
4
25,000
35,000
4
29,719
12,000
14
ND
ND
1974
3.6
18.0
2.1
107.2
GENERAL
CARGO
ST
<
25,000
5
13,264
16,709
20
ND
ND
1962
2.6
17.4
1.3
358.9
GENERAL
CARGO
Total
226
14,626
8,281
15
435
78%
1984
3.4
17.4
1.5
91.7
Miscellaneous
2
<
10,000
4
6,450
3,500
15
ND
ND
1982
3.3
15.9
2.0
509.1
12
8
Table
12
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
Baltimore
Harbor,
MD
Ship
Type
Engine
Type
DWT
Range
Calls
DWT
(
tonnes)
Power
(
hp)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Biuld
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
Hotel
(
hr/
call)
Miscellaneous
4
<
10,000
6
7,053
11,671
14
720
100%
1990
3.5
18.3
1.8
790.1
Miscellaneous
Total
10
6,812
10,503
15
720
100%
1987
3.4
17.3
1.9
677.7
PASSENGER
2
<
10,000
3
6,291
22,000
20
ND
ND
1976
2.5
15.1
1.3
81.9
PASSENGER
4
<
10,000
6
5,478
32,171
20
524
100%
1986
2.6
15.1
1.3
85.7
PASSENGER
ST
<
10,000
6
7,942
35,363
24
ND
ND
1961
2.1
16.1
1.3
146.7
PASSENGER
Total
15
6,626
31,413
21
524
100%
1974
2.4
15.5
1.3
109.4
REEFER
2
10,000
20,000
2
11,560
13,100
19
117
0%
1987
2.6
10.9
1.6
531.4
REEFER
Total
2
11,560
13,100
19
117
0%
1987
2.6
10.9
1.6
531.4
RORO
2
<
10,000
66
5,420
9,650
16
96
0%
1981
3.1
17.1
1.5
47.8
RORO
2
10,000
20,000
46
15,272
14,935
19
98
0%
1985
2.7
15.1
2.0
30.3
RORO
2
20,000
30,000
51
26,522
16,952
20
102
0%
1984
2.6
14.6
1.9
32.6
RORO
2
>
30,000
83
45,016
26,562
19
98
0%
1983
2.7
17.4
1.3
19.8
RORO
4
<
10,000
3
8,903
10,332
15
425
100%
1979
3.3
15.8
1.3
33.6
RORO
4
20,000
30,000
1
24,106
27,000
22
ND
ND
1972
2.3
16.2
1.3
1301.3
RORO
Total
250
24,800
17,805
18
107
3%
1983
2.8
16.3
1.6
37.0
TANKER
2
<
30,000
53
19,174
8,165
14
157
52%
1984
3.5
15.6
1.6
34.3
TANKER
2
30,000
60,000
42
37,543
12,008
15
113
7%
1982
3.3
16.5
1.7
51.5
TANKER
2
60,000
90,000
13
64,867
14,170
15
108
0%
1985
3.3
15.9
1.4
34.3
TANKER
2
90,000
120,000
1
95,628
16,600
14
94
0%
1993
3.6
17.5
1.3
242.4
TANKER
2
>
150,000
1
281,559
29,460
15
75
0%
1995
3.3
17.2
2.3
93.3
TANKER
4
<
30,000
22
8,330
5,354
14
486
100%
1989
3.5
14.5
1.5
29.1
TANKER
4
30,000
60,000
7
36,753
14,760
16
ND
ND
1983
3.2
16.8
1.7
39.0
TANKER
ST
30,000
60,000
8
44,388
16,275
15
ND
ND
1958
3.3
18.1
1.3
30.9
TANKER
Total
147
31,354
10,331
15
222
46%
1983
3.4
15.9
1.6
40.3
TUG
2
<
10,000
15
177
4,713
13
900
100%
1975
4.0
16.6
1.3
52.9
TUG
4
<
10,000
27
430
15,252
16
750
100%
1978
3.2
14.9
1.4
29.3
TUG
Total
42
340
11,488
15
825
100%
1977
3.4
15.5
1.4
37.8
VEHICLES
CARRIER
2
<
10,000
3
9,352
10,978
18
124
33%
1984
2.8
16.1
2.9
35.4
VEHICLES
CARRIER
2
10,000
20,000
225
14,660
13,308
18
110
0%
1985
2.7
14.7
1.8
22.8
VEHICLES
CARRIER
2
20,000
30,000
3
26,342
13,963
19
101
0%
1990
2.7
17.0
1.7
17.0
VEHICLES
CARRIER
4
<
10,000
12
8,246
11,830
18
530
100%
1980
2.8
14.2
1.5
21.7
VEHICLES
CARRIER
4
10,000
20,000
50
12,863
13,649
18
502
100%
1981
2.8
15.5
1.9
28.1
VEHICLES
CARRIER
Total
293
14,156
13,289
18
173
17%
1984
2.7
14.9
1.8
23.7
Grand
Total
2,007
31,529
16,493
17
172
23%
1984
3.0
16.0
1.5
56.4
12
9
Table
13
5:
Summary
of
1996
Deep
Sea
Vessel
Data
for
the
Port
of
Coos
Bay,
OR
Ship
type
Engine
Type
DWT
Range
Calls
DWT
(
tonnes)
Power
(
HP)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
%
RPM
>
130
Date
of
Build
Cruise
(
hr/
call)
RSZ
(
hr/
call)
Maneuver
(
hr/
call)
Hotel
(
hr/
call)
BULK
CARRIER
2
<
25,000
26
22,978
7,007
14
149
96%
1993
3.6
3.6
0.6
64.0
BULK
CARRIER
2
25,000
35,000
39
30,108
9,756
15
127
13%
1983
3.4
3.4
0.6
69.4
BULK
CARRIER
2
35,000
45,000
60
42,436
9,136
14
105
6%
1987
3.5
3.0
0.6
58.9
BULK
CARRIER
2
>
45,000
28
46,825
10,249
14
106
0%
1990
3.5
3.5
0.6
94.8
BULK
CARRIER
2
(
blank)
2
36,790
9,136
14
117
24%
1987
3.5
4.0
0.3
179.7
BULK
CARRIER
Total
155
36,790
9,136
14
117
24%
1987
3
3.3
0.6
70.4
GENERAL
CARGO
2
<
25,000
10
20,800
11,770
16
103
0%
1980
3.1
3.6
0.6
65.3
GENERAL
CARGO
2
25,000
35,000
18
30,068
8,040
14
95
0%
1984
3.5
3.6
0.6
52.5
GENERAL
CARGO
2
35,000
45,000
20
42,857
13,010
15
119
0%
1982
3.2
2.7
0.6
56.5
GENERAL
CARGO
2
>
45,000
5
46,547
12,300
16
93
0%
1994
3.1
4.0
0.6
128.5
GENERAL
CARGO
4
<
25,000
1
23,168
7,800
15
103
0%
1978
3.3
3.0
0.6
67.4
GENERAL
CARGO
Total
54
34,486
10,962
15
103
0%
1983
3
3.3
0.6
63.7
MISCELLANEOUS
4
(
blank)
1
36,189
9,612
15
ND
ND
ND
3.4
4.0
0.3
128.7
MISCELLANEOUS
Total
1
#
N/
A
#
N/
A
15
#
N/
A
#
N/
A
#
N/
A
#
N/
A
4.0
0.3
128.7
Grand
Total
210
36,189
9,612
15
116
21%
1986
3
3.3
0.6
69.0
13
5
Cleveland
Harbor,
OH
SOURCE:
EPA
document
Commercial
Marine
Activity
for
Lake
and
Rive
Ship
Type
Engine
Type
DWT
Category
Trips
Year
Build
DWT
(
tonnes)
BULK
CARRIER,
SALTY
2
<
10,00
2
ND
8,186
BULK
CARRIER,
SALTY
2
10,000
20,0
23
ND
15,866
BULK
CARRIER,
SALTY
2
20,000
30,0
134
1984
27,225
BULK
CARRIER,
SALTY
2
>
30,00
60
1981
35,125
BULK
CARRIER,
SALTY
Total
219
1983
28,022
BULK
CARRIER,
LAKER
2
10,000
20,0
39
1943
17,500
BULK
CARRIER,
LAKER
2
20,000
30,0
717
1977
26,830
BULK
CARRIER,
LAKER
2
30,000
40,0
55
1974
37,107
BULK
CARRIER,
LAKER
2
>
40,00
37
1980
50,800
BULK
CARRIER,
LAKER
4
<
10,00
56
1959
7,686
BULK
CARRIER,
LAKER
4
10,000
20,0
350
1951
17,000
BULK
CARRIER,
LAKER
4
20,000
30,0
70
1973
21,303
BULK
CARRIER,
LAKER
4
30,000
40,0
16
1980
33,205
BULK
CARRIER,
LAKER
ST
10,000
20,0
106
1943
15,047
BULK
CARRIER,
LAKER
Total
1446
1967
23,445
CONTAINER
SHIP,
SALTY
2
<
10,00
4
ND
8,229
CONTAINER
SHIP,
SALTY
4
10,000
20,0
2
1995
10,187
CONTAINER
SHIP,
SALTY
Total
6
1995
8,882
EXCURSION
VESSEL
4
450
572
1981
ND
EXCURSION
VESSEL
4
1000
748
1990
ND
EXCURSION
VESSEL
Total
1320
1986
ND
GENERAL
CARGO,
SALTY
2
<
10,00
2
ND
7,805
GENERAL
CARGO,
SALTY
2
10,000
20,0
6
1980
15,658
GENERAL
CARGO,
SALTY
4
<
10,00
8
1963
7,251
GENERAL
CARGO,
SALTY
4
10,000
20,0
2
ND
17,154
GENERAL
CARGO,
SALTY
4
20,000
30,0
2
ND
23,000
GENERAL
CARGO,
SALTY
Total
20
1972
12,394
TANKER,
SALTY
2
<
10,00
5
1974
8,000
TANKER,
SALTY
4
10,000
20,0
12
1978
11,420
TANKER,
SALTY
Total
17
1976
10,280
Grand
Total
1665
1968
23,678
a
ST
refers
to
steam
turbine
b
Category
is
dead
weight
tonnes
for
all
ship
types
c
Hotelling
times
are
found
in
Table
3
7
Table
3
7.
Average
hotelling
times
by
ship
type
for
calls
on
Port
of
Cleveland
in
1996
Ship
type
Category
a
Calls
Hotelling
(
hrs/
call)
BULK
CARRIER,
SALTY
10,000
20
11
41.3
20,000
30
75
69.3
>
30,0
45
49.1
BULK
CARRIER,
SALTY
Total
131
60
BULK
CARRIER,
LAKER
20,000
30
1
7.8
>
30,0
1
7
BULK
CARRIER,
LAKER
Total
2
7.4
CONTAINER
SHIP,
SALTY
<
10,0
1
24.7
10,000
20
1
111.5
CONTAINER
SHIP,
SALTY
Total
2
68.1
GENERAL
CARGO,
SALTY
<
10,0
9
55.1
10,000
20
6
78.9
GENERAL
CARGO,
SALTY
Total
15
64.6
PASSENGER,
SALTY
all
2
30.5
TANKER,
SALTY
all
1
29
Grand
Total
153
59.3
EMISSION
FACT
iver
Ports
,
Table
3
4.
Summary
of
trips
for
the
Port
of
Cleveland
for
1996
Cruise
g/
hp
hr
2
4
Steam
Power
(
hp)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM)
Cruise
(
hr/
trip)
RSZ
(
hr/
trip)
Maneuver
(
hr/
trip)
Calls
Hotel
(
hr/
call)
6,200
14
ND
0.5
0.3
0.8
6,996
14
113
0.5
0.3
0.8
11
41.3
9,116
15
110
0.5
0.3
0.8
75
69.3
10,909
14
100
0.5
0.3
0.8
45
49.1
9,358
14
109
0.5
0.3
0.8
4,500
13
ND
0.5
0.3
0.8
7,098
13
750
0.5
0.3
2.4
0.911055
7.8
7,087
13
ND
0.5
0.4
1
0.774648
7
8,538
13
ND
0.5
0.3
0.9
4,303
14
ND
0.5
0.3
0.9
4,236
13
ND
0.5
0.3
2
5,503
14
ND
0.5
0.3
2.5
0.088945
7.8
9,601
12
ND
0.6
0.4
0.8
0.225352
7
8,269
15
ND
0.5
0.3
0.9
6,308
13
750
0.5
0.3
2
5,950
15
ND
0.5
0.3
0.8
1
24.7
7,382
16
500
0.4
0.3
0.8
1
111.5
6,427
15
500
0.5
0.3
0.8
460
10
ND
0
2
0.4
0.866667
30.5
850
12
ND
0
2
0.4
1.133333
30.5
655
11
ND
0
2
0.4
5,400
15
225
0.5
0.3
0.8
1.8
55.1
10,600
16
ND
0.4
0.3
0.8
4.5
78.9
3,391
12
550
0.6
0.4
0.8
7.2
55.1
6,000
14
ND
0.5
0.3
0.8
1.5
78.9
7,800
13
ND
0.5
0.4
0.8
6,456
14
442
0.5
0.3
0.8
2,950
12
750
0.5
0.3
2.6
0.294118
29
6,253
15
117
0.5
0.3
0.8
0.705882
29
5,152
14
328
0.5
0.3
1.4
6,664
13
519
0.5
0.3
1.8
Total
Grams
per
Year
2
stroke
Tons
per
Year
4
stroke
Tons
per
Year
Steam
Engine
Tons
per
Year
Total
Tons
per
Year
Load
0.8
RSZ
HC
CO
NOx
PM
SO2
g/
hp
hr
HC
0.395
0.82
17.6
1.29
9.56
2
0.395
0.395
0.52
12.38
1.31
9.69
4
0.395
0.05
0.22
2.09
1.86
15.0
Steam
0.05
Speed
9
Cruise
HC
g/
yr
Cruise
CO
g/
yr
Cruise
NOx
g/
yr
Cruise
PM
g/
yr
Cruise
SO2
g/
yr
RSZ
Load
RSZ
HC
g/
yr
1959
4067
87296
6398
47411
420
25423
52778
1132792
83029
615231
5453
193004
400666
8599670
630317
4670571
41395
103417
214689
4607962
337743
2502632
22181
323804
672201
14427720
1057486
7835845
0.29
69449
27729
57564
1235520
90558
671024
6910
804104
1669279
35828433
2626061
19458796
200386
61586
127849
2744086
201129
1490342
20463
49913
103617
2223978
163007
1207866
12439
38073
50121
1193274
126267
933784
9488
234251
308381
7341835
776882
5745277
58376
60863
80124
1907560
201850
1492741
15167
29126
38343
912848
96594
714339
8065
17530
77133
732064
652126
5245200
4369
1323175.00
2512411.51
54119598.15
4934475.64
36959369.04
0.33
335662.07
3760
7806
167552
12281
90999
708
1866
2457
58489
6189
45770
439
5627
10263
226041
18470
136769
0.25
1148
0
0
0
0
0
100481
0
0
0
0
0
242801
0
0
0
0
0
0.48
343282
1706
3542
76032
5573
41294
366
8039
16689
358195
26254
194540
2155
5143
6771
161205
17058
126150
1226
1896
2496
59424
6288
46502
407
2465
3245
77251
8174
60452
705
19250
32743
732108
63347
468937
0.29
4858
2331
4838
103840
7611
56397
500
11856
15607
371578
39319
290775
2543
14186
20445
475418
46930
347171
0.29
3043
1686041.41
3248063.69
69980884.99
6120709.01
45748091.69
757441.67
1.41
2.93
62.88
4.61
34.15
0.34
0.42
0.56
13.29
1.41
10.40
0.48
0.02
0.08
0.81
0.72
5.77
0.00
1.85
3.57
76.98
6.73
50.32
0.83
Maneuver
CO
NOx
PM
SO2
g/
hp
hr
HC
0.82
17.6
1.29
9.56
2
2.085717156
0.52
12.38
1.31
9.69
4
2.172732372
0.22
2.09
1.86
15.0
Steam
0.05
knots
Speed
4
EMISSION
RSZ
CO
g/
yr
RSZ
NOx
g/
yr
RSZ
PM
g/
yr
RSZ
SO2
g/
yr
Maneuvering
Load
Maneuvering
HC
g/
yr
872
18723
1372
10169
2407
11320
242958
17808
131953
31232
85934
1844432
135188
1001730
237101
46046
988302
72438
536757
127046
144172
3094415
226807
1680609
0.12
397786
14345
307896
22567
167221
35255
415990
8928569
654424
4849199
3067026
42481
911781
66829
495198
97876
25822
554223
40622
301004
71392
12490
297368
31466
232702
56729
76850
1829611
193602
1431743
775632
19967
475371
50302
371996
251907
10617
252761
26746
197795
32146
19222
182433
162512
1307122
4749
637783.49
13740012.44
1249070.36
9353981.62
0.12
4392711.14
1471
31567
2314
17144
4498
579
13774
1458
10779
2907
2049
45341
3771
27923
0.11
7405
132279
3149253
333241
2464415
30565
319637
7609816
805239
5954982
73856
451916
10759069
1138480
8419397
0.13
104420
760
16307
1195
8857
2096
4474
96031
7039
52155
12345
1614
38417
4065
30062
5485
535
12745
1349
9974
2426
928
22091
2338
17287
3154
8311
185591
15985
118335
0.12
25507
1038
22271
1632
12096
9305
3347
79695
8433
62364
15172
4385
101966
10065
74460
0.12
24477
1248615.90
27926394.13
2644178.51
19674706.43
4952306.03
0.72
15.36
1.13
8.34
4.07
0.64
15.16
1.60
11.86
1.37
0.02
0.20
0.18
1.44
0.01
1.37
30.72
2.91
21.64
5.45
Hotel
Load
CO
NOx
PM
SO2
g/
hp
hr
HC
6.072740558
23.91129555
2.168336646
23.02
2
0.1
4.432346073
16.87604551
2.216072174
23.87
4
0.1
0.22
2.09
1.86
15.0
Steam
0.05
knots
NS
ESTIMATES
Maneuvering
CO
g/
yr
Maneuvering
NOx
g/
yr
Maneuvering
PM
g/
yr
Maneuvering
SO2
g/
yr
Hotelling
HC
g/
yr
7008
27593
2502
26564
90935
358055
32469
344701
31783
690339
2718197
246493
2616820
473804
369905
1456492
132078
1402171
241034
1158187
4560337
413543
4390255
746621
102647
404172
36651
389098
8929903
35161316
3188517
33849944
504
284974
1122080
101753
1080231
384
207865
818463
74220
787938
115726
440624
57860
623168
1582280
6024490
791104
8520351
513886
1956608
256931
2767203
38
65578
249685
32787
353126
151
20894
198302
176648
1420824
11823752.51
46375740.40
4716472.97
49791883.47
1078.33
13097
51570
4677
49647
1470
5930
22579
2965
31932
8231
19027
74149
7641
81580
9701
62351
237401
31174
335753
122
150665
573653
75329
811309
294
213016
811054
106503
1147062
415
6103
24032
2179
23136
5356
35943
141524
12834
136245
37635
11190
42605
5595
60255
13453
4950
18846
2475
26654
7101
6435
24500
3217
34650
64620
251507
26300
280940
63545
27091
106671
9673
102693
252
30951
117844
15475
166666
1280
58042
224516
25148
269359
1532
13336645.03
52297301.95
5295608.01
55961078.44
822892.04
11.84
46.63
4.23
44.89
0.87
2.80
10.68
1.40
15.10
0.03
0.02
0.22
0.19
1.56
0.00
14.67
57.53
5.83
61.56
0.91
0.1
All
modes
CO
NOx
PM
SO2
1.85
9.96
0.239
1.07
1.85
9.96
0.239
1.07
0.22
2.09
1.86
15.00
Hotelling
CO
g/
yr
Hotelling
NOx
g/
yr
Hotelling
PM
g/
yr
Hotelling
SO2
g/
yr
All
Modes
HC
g/
yr
All
Modes
CO
g/
yr
All
Modes
NOx
g/
yr
4786.24
11947.22
133611.65
587982
3165570
75961
339316
93891.19
743014.79
4899374.74
8765376
47190888
1132392
5058377
945303.92
9942315.34
60353187.19
4459136
24007022
576072
2573305
493678.13
5089775.13
31059777.19
13812494
74363480
1784425
7970999
1537659.47
15787052.48
96445950.77
69893.95
174556.43
1947587.50
9331
50238
1206
5385
4072019.70
11024503.77
79968556.07
7109
38276
918
4103
180309.58
462413.80
4816223.36
133743.98
337303.62
3596664.42
104289.67
178337.82
1931265.47
1068259.14
1967510.12
15195936.08
706
3803
91
408
327975.20
614683.15
4343341.21
2802
15085
362
1617
69487.81
117338.83
1430378.44
26647.50
117249.01
1112799.67
19949.03
107401.25
2577.20
11512.31
6052626.54
14993896.54
114342752.23
27189
146377
3512
15690
10436.86
49562.96
397066.35
152272
819801
19672
87874
13443.49
161237.54
914642.37
179461
966178
23184
103564
23880.34
210800.51
1311708.72
2249
12111
291
1298
131167.14
196879.55
3398764.27
5436
29264
702
3137
316950.70
475737.37
8212733.07
7685
41375
993
4435
448117.85
672616.92
11611497.34
99081
533430
12800
57178
9524.38
109486.46
649801.15
696253
3748476
89948
401798
60174.30
753358.55
4344225.53
248876
1339896
32152
143623
25307.18
268450.85
1582123.02
131369
707260
16971
75811
11830.01
139349.59
798274.75
6323.93
10607.39
123842.56
1175579
6329062
151872
678410
113159.80
1281252.84
7498267.01
4655
25061
601
2686
12386.60
37621.81
257843.63
23680
127491
3059
13666
30850.55
73586.23
696608.31
28335
152552
3661
16352
43237.15
111208.04
954451.94
15223502.69
81960046.94
1966711.97
8785272.74
8218681.15
33056827.31
232164628.01
16.12
86.80
2.08
9.30
6.69
31.61
211.67
0.62
3.36
0.08
0.36
2.32
4.62
42.49
0.00
0.00
0.00
0.00
0.03
0.13
1.22
16.75
90.16
2.16
9.66
9.04
36.36
255.38
8.55
35.62
242.61
All
Modes
PM
g/
yr
All
Modes
SO2
g/
yr
10272.88
84143.59
209266.51
1431201.65
2144389.96
13347497.64
1118331.15
7014865.42
3482260.51
21877708.30
149776.67
1227343.00
6470207.21
58163324.86
370629.99
3069873.75
277849.83
2296808.00
215593.86
1789654.26
1761588.06
15697370.60
509174.35
4632348.27
156489.14
1266878.00
991287.07
7973145.70
10902596.17
96116746.44
22783.50
173480.67
30283.41
176355.49
53066.91
349836.16
364705.62
2801465.77
881270.27
6769428.15
1245975.89
9570893.92
21747.52
130464.52
136074.79
784738.29
58869.91
360090.35
27082.79
158939.83
13729.22
112389.42
257504.23
1546622.40
19517.97
173871.48
66285.82
533470.61
85803.79
707342.09
16027207.49
130169149.31
12.05
96.69
4.49
37.73
1.09
8.77
17.63
143.19
16.26
132.66
Burns
Waterway
Harbor,
IN
EMISS
SOURCE:
EPA
document
Commercial
Marine
Activity
for
Lake
and
River
Ports,
Table
3
12.
Summary
of
trips
for
Burns
Waterway
Harbor
for
1996
Ship
Type
Engine
Type
DWT
Category
Trips
Year
Build
DWT
(
tonnes)
Power
(
hp)
Vessel
Speed
(
knots)
Engine
Speed
(
RPM
g/
yr)
Cruise
(
hr/
trip)
RSZ
(
hr/
trip)
Maneuver
(
hr/
trip)
Calls
Hotel
(
hr/
call)
BULK
CARRIER,
LAKER
2
20,000
30,0
9
1973
24,827
8,531
13
750
0.5
0.4
0.7
2.423077
17.9
BULK
CARRIER,
LAKER
2
30,000
40,0
37
1974
34,925
7,108
13
ND
0.5
0.4
0.6
1.146018
18.7
BULK
CARRIER,
LAKER
2
>
40,000
162
1975
67,695
14,376
14
ND
0.5
0.3
0.6
5.017699
18.7
BULK
CARRIER,
LAKER
4
10,000
20,0
14
1952
17,978
4,800
13
ND
0.5
0.4
0.7
7
13.5
BULK
CARRIER,
LAKER
4
20,000
30,0
6
1971
22,491
6,600
15
ND
0.5
0.3
0.7
1.615385
17.9
BULK
CARRIER,
LAKER
4
30,000
40,0
27
1979
32,908
9,541
12
ND
0.6
0.4
0.7
0.836283
18.7
BULK
CARRIER,
LAKER
ST
20,000
30,0
11
1953
23,627
8,886
16
ND
0.4
0.3
0.6
2.961538
17.9
BULK
CARRIER,
LAKER
Total
266
1973
52,630
11,753
14
750
0.5
0.3
0.6
BULK
CARRIER,
SALTY
2
10,000
20,0
4
1976
14,631
6,700
14
ND
0.5
0.3
0.7
4
61
BULK
CARRIER,
SALTY
2
20,000
30,0
99
1973
27,329
8,839
13
219
0.5
0.3
0.7
35.77311
43.2
BULK
CARRIER,
SALTY
2
30,000
40,0
42
1982
32,449
10,132
14
105
0.5
0.3
0.7
19
48
BULK
CARRIER,
SALTY
ST
20,000
30,0
20
1961
26,175
3,551
16
ND
0.4
0.3
0.7
7.226891
43.2
BULK
CARRIER,
SALTY
Total
165
1974
28,185
8,476
14
193
0.5
0.3
0.7
GENERAL
CARGO,
SALTY
2
<
10,000
8
1962
8,395
4,100
14
ND
0.5
0.3
0.7
5.714286
26.3
GENERAL
CARGO,
SALTY
2
10,000
20,0
1
1982
16,467
11,200
16
150
0.4
0.3
0.7
1
23.9
GENERAL
CARGO,
SALTY
4
<
10,000
6
1979
5,785
3,667
12
ND
0.6
0.4
0.7
4.285714
26.3
GENERAL
CARGO,
SALTY
Total
15
1970
7,889
4,400
13
150
0.5
0.3
0.7
TANKER,
SALTY
4
<
10,000
200
1973
7,500
400
14
720
0.5
0.3
0.6
TANKER,
SALTY
Total
<
10,000
200
1973
7500
400
14
720
0.5
0.3
0.6
Grand
Total
646
1973
40,342
9,792
14
596
0.5
0.3
0.7
a
ST
refers
to
steam
turbine
b
Category
is
dead
weight
tonnes
for
all
ship
types
c
Hotelling
times
are
found
in
Table
3
15
Table
3
15.
Average
hotelling
times
by
ship
type
for
calls
on
Burns
Waterway
Harbor
Ship
type
Category
a
Calls
Hotelling
(
hrs/
call)
BULK
CARRIER,
LAKER
10,000
20,000
7
13.5
20,000
30,000
7
17.9
>
30,000
7
18.7
BULK
CARRIER,
LAKER
Total
21
16.6
BULK
CARRIER,
SALTY
10,000
20,000
4
61
20,000
30,000
43
43.2
>
30,000
19
48
BULK
CARRIER,
SALTY
Total
66
45.8
GENERAL
CARGO,
SALTY
<
10,000
10
26.3
20,000
30,000
1
23.9
GENERAL
CARGO
Total
11
26
DRY
CARGO
BARGE
<
2000
446
46.8
LIQUID
CARGO
BARGE
<
2000
23
52.9
2000
5000
27
29.7
LIQUID
CARGO
BARGE
Total
50
40.3
Grand
Total
594
44.4
a
Category
is
in
dead
weight
tonnes.
ISSION
FACT
Cruise
Load
0.8
RSZ
Maneuver
g/
hp
hr
HC
CO
NOx
PM
SO2
g/
hp
hr
HC
CO
NOx
PM
SO2
g/
hp
hr
HC
CO
2
0.395
0.82
17.6
1.29
9.56
2
0.395
0.82
17.6
1.29
9.56
2
2.085717156
6.072740558
4
0.395
0.52
12.38
1.31
9.69
4
0.395
0.52
12.38
1.31
9.69
4
2.172732372
4.432346073
Steam
0.05
0.22
2.09
1.86
15.0
Steam
0.05
0.22
2.09
1.86
15.0
Steam
0.05
0.22
Speed
9
knots
Speed
4
knots
EMISSIONS
Cruise
HC
g/
yr
Cruise
CO
g/
yr
Cruise
NOx
g/
yr
Cruise
PM
g/
yr
Cruise
SO2
g/
yr
RSZ
Load
RSZ
HC
g/
yr
RSZ
CO
g/
yr
RSZ
NOx
g/
yr
RSZ
PM
g/
yr
RSZ
SO2
g/
yr
Maneuvering
Load
Maneuvering
HC
g/
yr
Maneuvering
CO
g/
yr
12131
25184
540524
39618
293564
3469
7202
154573
11330
83950
13040
37967
41553
86263
1851492
135706
1005565
11883
24668
529470
38808
287561
38286
111472
367968
763883
16395540
1201719
8904589
78921
163835
3516467
257741
1909830
339030
987115
10618
13978
332774
35213
260409
3036
3997
95163
10070
74469
11889
24254
6257
8237
196099
20750
153455
1342
1767
42059
4450
32913
7006
14292
48842
64299
1530804
161983
1197915
11639
15323
364803
38602
285472
45576
92975
1564
6881
65310
58178
467942
419
1845
17509
15597
125454
341
1501
488933
968724
20912544
1653167
12283440
0.29
110710
218637
4720044
376598
2799649
0.12
455169
1269576
4234
8790
188672
13829
102470
908
1885
40466
2966
21977
4552
13252
138260
287020
6160429
451531
3345794
29654
61559
1321271
96843
717596
148618
432713
67236
139578
2995830
219581
1627066
14421
29936
642537
47095
348968
72273
210429
1136
5000
47453
42271
339996
305
1340
12722
11333
91152
289
1272
210866
440389
9392384
727212
5415326
0.29
45287
94721
2016995
158237
1179693
0.12
225732
657667
5182
10758
230912
16925
125411
1291
2681
57544
4218
31253
5765
16786
1416
2939
63078
4623
34259
441
915
19649
1440
10672
1969
5732
4172
5492
130745
13835
102313
1155
1521
36202
3831
28330
4029
8218
10770
19189
424735
35383
261982
0.33
2888
5117
113396
9489
70254
0.12
11763
30737
12640
16640
396160
41920
310011
2711
3569
84967
8991
66490
12132
24749
12640
16640
396160
41920
310011
0.29
2711
3569
84967
8991
66490
0.12
12132
24749
Total
Grams
per
Year
723209
1444941
31125823
2457682
18270759
161595
322044
6935402
553314
4116087
704795
1982728
2
stroke
Tons
per
Year
0.70
1.46
31.27
2.29
16.98
0.16
0.32
6.91
0.51
3.75
0.69
2.00
4
stroke
Tons
per
Year
0.09
0.12
2.85
0.30
2.23
0.02
0.03
0.69
0.07
0.54
0.09
0.18
Steam
Engine
Tons
per
Year
0.00
0.01
0.12
0.11
0.89
0.00
0.00
0.03
0.03
0.24
0.00
0.00
Total
Tons
per
Year
0.80
1.59
34.24
2.70
20.10
0.18
0.35
7.63
0.61
4.53
0.78
2.18
Hotel
Load
0.1
All
modes
NOx
PM
SO2
g/
hp
hr
HC
CO
NOx
PM
SO2
23.91129555
2.168336646
23.02
2
0.1
1.85
9.96
0.239
1.07
16.87604551
2.216072174
23.87
4
0.1
1.85
9.96
0.239
1.07
2.09
1.86
15.0
Steam
0.05
0.22
2.09
1.86
15.00
S
ESTIMATES
Maneuvering
NOx
g/
yr
Maneuvering
PM
g/
yr
Maneuvering
SO2
g/
yr
Hotelling
HC
g/
yr
Hotelling
CO
g/
yr
Hotelling
NOx
g/
yr
Hotelling
PM
g/
yr
Hotelling
SO2
g/
yr
All
Modes
HC
g/
yr
All
Modes
CO
g/
yr
All
Modes
NOx
g/
yr
All
Modes
PM
g/
yr
149494
13556
143918
3700
68453
368536
8843
39503
32340
138805
1213127
73347
438917
39802
422547
1523
28181
151719
3641
16263
93245
250583
2971598
217956
3886746
352460
3741787
13489
249549
1343518
32239
144011
799408
2164383
25142272
1844159
92346
12126
130603
4536
83916
451786
10841
48427
30079
126145
972069
68250
54418
7146
76963
1908
35306
190078
4561
20374
16513
59602
482654
36908
354002
46486
500659
1492
27603
148610
3566
15929
107550
200200
2398218
250637
14245
12689
102064
2355
10363
98357
87617
706591
4680
20590
195422
174083
4990167
484266
5118541
29004
503371
2752604
151309
991099
1083816
2960308
33375359
2665340
52181
4732
50235
16348
302438
1628261
39072
174533
26042
326366
1909580
60598
1703799
154505
1640254
136598
2527059
13605137
326469
1458330
453129
3308351
22790635
1029348
828561
75136
797659
92404
1709471
9203422
220845
986512
246333
2089415
13670350
562657
12075
10756
86517
5543
24390
231482
206205
1662942
7273
32002
303731
270565
2596616
245129
2574665
250893
4563357
24668301
792590
4282318
732778
5756134
38674296
1923168
66095
5994
63630
6162
113992
613707
14726
65783
18401
144217
968258
41863
22569
2047
21727
2677
49521
266609
6398
28578
6502
59107
371906
14508
31292
4109
44255
4133
76465
411670
9878
44127
13489
91696
609908
31653
119956
12149
129613
12972
239977
1291986
31002
138488
38392
295020
1950073
88024
94230
12374
133269
27483
44958
575358
63285
94230
12374
133269
0
0
0
0
0
27483
44958
575358
63285
7800969
753918
7956087
292869
5306706
28712892
974901
5411904
1882468
9056420
74575086
4739816
7.86
0.71
7.57
0.30
5.55
29.90
0.72
3.20
1.84
9.33
75.94
4.23
0.69
0.09
0.97
0.01
0.25
1.32
0.03
0.14
0.21
0.57
5.54
0.50
0.03
0.03
0.21
0.01
0.04
0.36
0.32
2.61
0.01
0.06
0.55
0.49
8.58
0.83
8.75
0.32
5.84
31.58
1.07
5.95
2.07
9.96
82.03
5.21
All
Modes
SO2
g/
yr
560936
1731935
14700218
513908
283705
1999976
1402050
21192728
349215
7161974
3760206
2180607
13452002
286077
95235
219025
600337
509770
509770
35754836
31.51
3.88
3.94
39.33
| epa | 2024-06-07T20:31:40.866335 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0045-0168/content.txt"
} |
EPA-HQ-OAR-2003-0072-0041 | Supporting & Related Material | "2002-06-21T04:00:00" | null | epa | 2024-06-07T20:31:40.904403 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0041/content.txt"
} |
|
EPA-HQ-OAR-2003-0072-0042 | Supporting & Related Material | "2002-09-20T04:00:00" | null | IL
t
I,
AN
ASME
REPORT
CRTD
Vol.
60
REFERENCE
METHOD
ACCURACY
AND
PRECISION
(
ReMAP):
PHASE
1
Precision
of
Manual
Stack
Emission
Measurements
Prepared
by:
W.
Steven
Lanier
GE
Energy
and
Environmental
Research
Corporation
Charles
D.
Hendrix
Statistical
Consultant
under
the
auspices
of:
American
Society
of
Mechanical
Engineers
Research
Committee
on
Industrial
and
Municipal
Waste
February
200
1
Disclaimer
(
hereinafter
referred
to
f,
make
any
warranty,
owned
rights.
Reference
herein
to
any
preparation
or
review
of
this
report,
or
any
agency
thereof.
Statement
from
the
by
laws
of
th
statements
or
opinions
advanced
Authorization
to
photocopy
falling
within
the
fair
use
provisions
libraries
and
other
users
registered
that
the
applicable
fee
is
paid
direct1
01923.
[
Telephone:
(
978)
750
8400]
Requests
for
special
permission
or
bulk
reproduction
shouId
be
addressed
to
the
ASME
Technical
Publishing
Department.
Society
shall
not
be
responsible
for
printed
in
publications
(
7.1.3).
or
personal
use
under
circumstances
not
Copyright
Act
is
granted
by
ASME
to
Copyright
Clearance
Center
(
CCC)
provided
CCC,
222
Rosewood
Drive,
Danvers,
MA
r
'
1
,
6"
I
I.%
Section
1
.
o
2.0
3.0
4.0
5.0
6.0
7.0
TABLE
OF
CONTENTS
Page
Executive
Summary
................................................................................................................
S
I
Introduction
........................................................................................................................
1
Background
.......................................................................................................................
.3
.
.
The
Analysis
Procedure
A
Layman's
Descnphon
..............................................................
1
1
Measures
of
Precision
................................................................................................
1
1
Estimating
Standard
Deviation
..................................................................................
13
The
Relationship
Between
S
and
C
.....
1
.....................................................................
17
Summary
of
ReMAP
Analysis
Procedure
.................................................................
21
3.1
3.2
3.3
3.4
Confidence
Intervals
..................................................................................................
18
3.5
EPA
Particulate
Matter
Methods
Method
5
and
5i
.............................................................
25
4.1
Method
5
Data
and
Precision
Analysis
......................................................................
28
4.2
Method
5i
Data
..........................................................................................................
50
4.3
Discussion
of
Particulate
Matter
Measurement
Results
............................................
61
EPA
Method
23
for
Measuring
Dioxin
and
Furan
Emissions
...............................................
67
5.1
5.2
Available
Multi
Train
Data
for
Method
23
as
Total
PCDDPCDF
...........................
69
Analysis
of
Method
23
Data
for
Total
Dioxin
and
Furan
..........................................
70
5.3
Available
Multi
Train
Data
for
Method
23
as
ITEQ
.................................................
8
1
EPA
Method
26
for
Hydrochloric
Acid
.................................................................................
9
1
EPA
Methods
29,
10
1
a
and
10
1
b
for
Mercury
......................................................................
103
TABLE
OF
CONTENTS
(
Cont.)
8.0
EPA
Method
29
for
Multi
Metals
..........................................................................................
1
19
8.1
EPA
Method
29
Data
for
Antimony,
Arsenic,
Beryllium,
Cadmium,
,
I
Chromium,
and
Lead
.......*.........,..............................................................................
l
19
8.1.1
Antimony
Data
..............................................................................................
.119
~
I
r
L
8.1.2
Arsenic
Data
...................................................................................................
126
8.1.3
Beryliium
Data
...............................................................................................
126
8.1.4
Cadmium
Data
...............................................................................................
126
??
8.1.5
Chxnium
Data
..............................................................................................
122
8.1.6
Lead
Data
...............................
...................................................................
I22
EPA
Method
29
Regression
Analyses
.......................................................................
138
??
8.2
9.0
Other
Measurement
Methods
.................................................................................................
167
10.0
Conclusions
........................................................................................................................
169
BNDi
References
........................................................
.........................................................
*.
I72
Appendix
Statistical
Analysis
Procedures
for
the
ReMap
Program
c
_*
...
111
TABLE
OF
CONTENTS
(
Cont.)
Figure
'
Page
1
2
3
4
5
6
7
8
9
10
11
I2
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Illustration
The
Difference
Between
Precision
and
Accuracy
............................................
7
Normal
Distribution
of
Field
Results
....................................................................................
.12
Simulated
Data
.......................................................................................................................
16
Regression
Line
and
Confidence
Interval
for
Simulated
Data
..............................................
19
Schematic
of
Method
5
Sampling
Train
................................................................................
26
EPA
Method
5
Data
Standard
Deviation
(
Fig.
6A)
............................................................
37
EPA
Method
5
Data
Relative
Standard
Deviation
(
Fig.
63)
.............................................
..
3
8
thod
5
.......................................
42
d
5
(
Front
Half
Only)
...........
48
..............................................
5
1
.............................................
56
eviation
(
Fig.
11B)
............................................
57
..............................................
60
..............................................
62
..............................................
68
viation
.........................................
.72
Deviation
..........................
..
7
....................................................
.76
nts
Using
EPA
Method
23
............
78
ion
................................................
83
....................
92
Method
26
.....................................
10
1
........................................................
104
iv
TABLE
OF
CONTENTS
(
Cont.)
Fimre
Page
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
Schematic
of
Method
29
Sampling
Train
..............................................................................
105
Schematic
of
Method
l
0
l
b
Sampling
Train
..........................................................................
106
EPA
Method
29/
10
1
all
0
1
b
Data
Total
Mercury
Standard
Deviation
.................
......
......
...
1
1
1
EPA
Method
29/
10
1
a
/
l
O
1
b
Data
Total
Mercury
Relative
Standard
Deviation
..........
........
1
12
Regression
Line
and
95%
Confidence
Interval
EPA
Method
29
Data
for
Antirn
ata
for
Antimon
ata
for
Arsenic
.....................................
140
......,............
143
Regression
Line
and
95%
C
Regression
Line
and
95%
EPA
Method
29
Precision
EPA
Method
29
Precision
d
29
Chromium
................
146
d
29
Lead
..........................
147
Precision
Estimates
for
Mea
Precision
Estimates
for
Mea
EPA
Method
29
Precision
Metrics
Composite
Data
.........
....
.
................._......
.....................
165
V
Table
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
TABLE
OF
CONTENTS
(
Cont.)
Paae
EPA
Method
5
Data
Hamil
and
Camann,
1974
and
1974b
................................................
29
EPA
Method
5
Data
Dade
County
MWC,
Hamil
and
Thomas,
1976
................................
3
1
EPA
Method
5
Data
Pittsfield
MWC,
E
g
o
and
Chandler,
1997
.......................................
32
SPC
Factors
for
Identification
of
Data
Outliers
.....................................................................
33
Consolidated
Method
5
Data
Set
...........................................................................................
34
Factors
for
Calculating
Unbiased
Estimates
of
sigma
ts
Based
on
S
.....................................
35
Method
5
Small
Sample
Bias
Correction
to
Standard
Deviation
.......................................
36
Method
5
Regression
Analysis
Results
..................................................................................
40
EPA
Method
5i
Data
and
Standard
Deviation
Eli
Lilly
Data,
(
Table
9A)
..........................
53
andard
Deviation
EPA
DuPont
Data,
(
Table
9B)
..................
55
Regression
Analysis
for
Method
5i
Data
..............................................................
58
Data
as
Total
Mass
of
Tetra
through
Octa
Dioxin
pIus
Furan
.............................
71
ate
of
Method
23
Standard
Deviation
...................................................................
79
Data
as
ITEQ
.......................................................................................................
82
Data
and
Standard
Deviation
for
HC1
...............................................
93
uture
HC1
Data
..................................................................................
102
a
for
Mercury
(
Table
16A)
.............................................................
109
a
for
Mercury
(
Table
16B)
.............................................................
1
10
cipated
Future
Mercury
Data
...........................................................................
1
18
ata
and
Standard
Deviation
for
Antimony
.....................................
120
ata
and
Standard
Deviation
for
Arsenic
.........................................
121
ata
and
Standard
Deviation
for
Beryllium
.....................................
122
ata
and
Standard
Deviation
for
Cadmium
......................................
123
ain
Data
and
Standard
Deviation
for
Chromium
....................................
124
ain
Data
m
d
Standard
Deviation
for
Lead
..............................................
125
gression
Analysis
for
Various
Metals
............................................
13
8
I
f
Measured
PCDDRCDF
Concentration
Based
on
Range
of
Anticipated
Future
Metals
Data
Antimony,
Arsenic,
Beryllium,
Chromium,
or
Lead
............................................................................................................
166
Vi
This
page
IntentionaIly
left
blank.
Reference
Method
Accuracy
and
Precision
(
ReMAP
Phase
I)
An
Assessment
of
the
Precision
of
EPA
Manual
Stack
Emission
Measurements
Executive
Summary
This
report
documents
results
from
the
first
phase
of
a
study
co
sponsored
by
the
American
Society
of
Mechanical
Engineers
(
ASME)
to
assess
the
accuracy
and
precision
of
manual
test
methods
adopted
by
the
US
Environmental
Protection
Agency
(
EPA)
for
determining
the
stack
concentration
of
selected
air
pollutants.
The
program
is
entitled
Reference
Method
Accuracy
and
Precision
and
is
referred
to
by
the
acronym
ReMAP.
The
Phase
1
effort
addresses
the
precision
of
the
selected
measurement
methods.
The
formal
Purpose
Statement
for
the
program
is:
"
To
determine
the
precision
of
pollutant
emission
measurements
based
on
analysis
of
available
simultaneous
sample
test
data
which
were
generated
using
EPA
Manual
Reference
Test
Methods
5
and
5i
(
Particulate
Matter),
23
(
Dioxin
and
Furan),
26
(
HCI),
29
(
multi
metals),
1Ola
and
lOlb
(
mercury)
and
108
(
arsenic)
at
a
number
of
stationaty
air
sources."
As
used
in
the
Re
rogram,
precision
is
defined
as
random
error
that
inadvertently
enters
the
measurement
process.
This
error
may
enter
at
any
stage
of
the
measurement
le
recovery,
or
sample
analysis.
The
impact
of
deviate
from
the
true
stack
concentration.
any
manual
test
of
the
selected
ibution.
This
distribution
is
xpected
indicating
measured
Because
these
e
Precision
of
a
curve.
One
c
o
r
n
dicated
by
the
horizontal
spread
of
the
bell
&
e
bell
curve
shape
is
to
determine
the
(
c)
of
the
distribution.
Alternately,
the
bell
distributian
also
peated
application
of
the
the
best
estimate
of
the
ators
of
data
quality
that
two
additional,
directly
measurement
99
out
of
100
future
single
measurements.
If
the
is
repeatedly
applied
to
a
stack
with
a
given
concentration,
this
nes
the
upper
and
lower
concentration
bounds
for
99%
of
measurement
ES
1
2.
The
anticipated
range
for
99
out
of
100
future
triplicate
measurements.
Since
most
environmental
regulations
define
the
re
able
stack
concentration
as
the
average
of
three
repeated
test
runs,
this
metric
defines
the
anticipated
range
of
results
in
triplicate
(
3
single
time
series)
measurements
due
to
random
error
in
the
measurement
process.
For
each
of
these
precision
metrics
it
is
important
to
note
the
inherent
assumption
that
faciiity
operation.
100
single
measurements
will
fall
withi
anticipated
range
for
the
average
of
repea
to
the
true
concentration.
More
precisely,
standard
deviation
of
concentration.
lities
must
be
assumed
to
of
method
precision
mu
trains
are
used
to
sim
deviation
of
the
particula
measurement
at
the
specific
stack
concentration.
ES
2
97
E
l
LJ
The
ReMAP
program
procedures
required
to
performed
a
careful
assessment
estimate
the
precision
of
Manual
of
the
statistical
analysis
Reference
Methods
using
multi
train
sampling
data
(
see
Appendix).
To
assure
the
quaiity
of
data
used
in
the
statistical
anaiysis,
an
extensive
effort
was
expended
in
gathering
data
from
the
original
sources
and
carefilly
evaluating
them
to
assure
that
consistent
data
reduction
procedures
were
used.
Conceptually,
the
ReMAP
statistical
analysis
procedure
is
straightforward.
First,
data
fiom
a
multi
train
test
run
are
averaged
to
provide
an
estimate
of
the
average
C
run
(
Ci).
The
standard
deviation
for
the
test
run
(
Si)
is
also
C
a
calculated
standard
deviation
fiom
a
single
test
using
a
dual
sampling
probe
provides
a
relatively
poor
estimate
of
the
true
standard
deviation
of
the
method
(
0)
at
the
true
concentration
(
p)
However,
after
accounting
for
various
biases,
a
significant
array
of
data
from
multi
train
tests
should
provide
a
reasonable
basis
for
estimating
the
true
standard
deviation
as
a
function
of
concentration.
The
ReMAP
procedure
is
to
ass
at
the
standard
deviation
varies
with
concentration
according
to
a
power
functio
nship
and
then
to
fit
the
data
to
that
equation
using
regression
analysis.
regression
analysis
represent
the
best
estimate
av
able
on
the
standard
measurement
method
at
any
given
concentration
ReMAP
analysis
procedure
also
provides
for
calculation
of
confidenc
s
define
the
upper
and
lowe
lyses
are
summariz
i
for
Particulate
Matter
Front
Half
Only
frdm
the
true
ave
h
tacks
with
particulate
concentrations
ual
train
sampling
and
ep
the
simultaneous
measurements.
eliminate
test
results
reening,
coupled
with
the
ReMAP
anaiysis
ant
variation
of
standard
deviation
with
concentration.
ES
3
Based
on
a
pooled
analysis,
the
characteristic
standard
deviation
for
Method
5i
was
found
to
be
1.43
mgdscm.
Based
on
this
best
estimate
of
standard
deviation,
the
ReMAP
analysis
indicates
that
99
out
of
100
Method
5i
single
measurements
should
deviate
from
the
true
concentration
by
no
more
than
f
2.68
mg/
dscm.
For
triplicate
measurements
99
out
of
100
Method
ata
results
should
deviate
from
the
true
concentration
by
no
more
than
f
2.12
rng
rs
ranging
from
zero
a
were
reported
in
both
forms.
Even
nts,
the
ReMAP
results
suggest
that
though
the
same
data
were
used
for
both
Table
ES
I
.
Anticipated
Range
o
analysis
found
no
statistically
significant
variation
of
standard
deviation
with
ES
4
r
I;
P
L1
r:
Li
concentration.
Pooled
analysis
indicates
that
the
best
estimate
of
standard
deviation
is
27
ng
ITEQ/
dscm.
when
the
emission
concentration
is
in
the
range
of
0.02
to
0.9
ng
ITEQ/
dscm.
This
further
indicates
that
99
out
of
100
future
single
measurements
shoufd
fall
with
50.069
ng
ITEQ/
dscm
of
the
m
e
concentration
and
99
out
of
100
triplicate
measurements
should
fall
within
50.04
ng
ITEQ/
dscm
of
the
true
concentration.
99
out
of
100
Single
Concentration
I
Measurements
Truestack
HCl
The
absolute
value
of
anticipated
range
for
future
Method
25
measurements
(
as
ITEQ)
are
quite
small
in
absolute
t
ut
they
are
on
the
same
order
as
regulatory
emission
limits
being
considered
in
regions.
As
indicated
above,
the
best
estimate
of
standard
deviation
is
0.027
ng
ITEQIdscm.
However,
at
95%
confidence,
the
standard
deviation
may
be
as
large
as
0.037
ng
ITEQ/
dscm
and
the
potential
range
for
99
out
of
100
future
measurements
might
deviate
from
the
true
concentration
by
as
much
as
Q/
dscm.
ReIying
upon
a
single
measurement
has
the
potential
to
create
mission
limits
were
set
at
0.095
ng
ITEQ/
dscm,
to
be
assured
confidence
level,
measurement
resuits
could
not
exceed
zero.
results
must
be
above
0.19
ng
ITEQ/
dscm
e
true
stack
concentration
exceeded
the
emissio
95%
confidence
Most
regulations
and
permit
limits
establish
compliance
based
on
averaging
results
from
triplicate
measurem
icipated
range
for
99
out
of
100
fkture
triplicate
to
single
measurements,
by
43.
Thus,
compliance
EQ/
dscm
is
assured
(
at
the
95%
codidence
level)
or
below
0.04
ng
ITEQ/
dscm.
Similarly,
at
95%
95
ng
ITEQ/
dscm
limit
is
assured
when
the
three
run
confidence,
exceeden
99
out
of
100
Triplicate
Measurements
I
Method
26
for
Hydrochloric
Acid
ReMAP
analysis
of
available
data
for
Method
26
for
HCI
indicated
that
RSD
is
typically
in
the
range
of
5%
to
10%.
RSD
does
increase
when
the
method
is
applied
to
stacks
with
very
low
concentration.
Table
ES
2
summarized
the
anticipated
upper
and
lower
bounds
for
99
out
of
100
Method
26
measurements
as
a
hction
of
true
stack
HCI
concentration.
TabIe
ES
2.
Anticipated
Range
of
HC1
Measurement
Results
Due
to
Random
Error
in
Application
of
Method
26.
I
20
16.1
23.9
17.7
22.3
50
41.9
58.1
45.3
54.7
100
85.8
1
14.2
91.8
108.2
I
I
I
I
I
J
ES
5
Methods
29,
lOla
and
lOlb
for
TotaI
Mercury
Several
measurement
methods
have
been
de
concentration
and
for
mercury
speciation,
multi
train
mercury
data
collected
using
Me
data
for
total
mercury
concentration.
concentration
range
of
50
to
78
9.6
to
12.4%.
As
concentration
from
12.4%
to
for
99
out
of
10
ped
for
measurement
of
rota1
emission
lysis
took
ail
availabIe
The
data
analysis
i
Results
Due
to
Random
Method
29
for
Multi
Metals
Method
29
is
also
used
for
measurement
of
several
other
metal
emissions.
Precision
analysis
was
completed
for
six
other
metals
including
antimony,
arsenic,
beryllium,
cadmium,
chromium,
and
lead.
With
exception
of
cadmium,
the
analysis
indicates
that
these
metals
behave
similarly
wi
to
measurement
method
precisio
composite
andysis
was
performed
for
the
g
metals
and
the
results
indicate
that
use
of
Method
29
provides
an
RSD
that
tween
13
and
18%
when
the
individual
metal
concentrations
are
b
pg/
dscm.
Table
ES
4
summarizes
the
anticipated
upper
and
1
9
out
of
100
Sb,
As,
Be,
Cr,
and
Pb
measurements
using
Method
e
stack
total
metal
concentration.
As
regards
cadmium
measurements
using
M
9,
the
analysis
indicates
that
standard
deviation
is
a
weaker
fiction
of
conce
at
least
at
higher
concentration
ranges.
The
best
estimate
of
R
oncentration
is
80
pg/
dscm
and
18.7
%
when
the
concentr
However,
at
5
pg/
dscm,
predicted
RSD
is
38.
to
exceed
75%.
ES
6
h
a
L
100
65.7
134.3
"
PLY
,
4
80.2
119.8
I
c
,
I
L
u
r
1
ES
7
This
page
Intentionally
left
blank.
REFERENCE
METHOD
ACCUR4Cl
PHASE
I
ZIYD
PRECISION
(
R
e
m
)
PRECISION
OF
MANUAL
STACK
EMISSION
MEASUREMENTS
1.0
Introduction
An
integral
part
of
efforts
to
regulate
and
control
air
pollution
emissions
is
collection
and
analysis
of
exhaust
stream
samples
to
determine
the
concentration
and
flow
rate
of
pollutants
released
to
the
atmosphere.
The
U.
S.
Environmental
Protection
Agency
(
EPA)
and
its
counterparts
in
other
countries
have
developed
formal
methods
defining
the
hardware
and
procedures
for
collecting
and
analyzing
samples
to
quanti
emissions
of
individual
pollutants.
A
significant
number
of
these
methods
involve
manual
extraction
of
a
sample
from
a
facility's
exhaust
stack,
sample
recovery
and
subsequent
laboratory
analysis
to
quantify
concentration
of
a
specific
pollutant(
s)
in
the
sample.
All
manual
processes,
inc
ing
the
various
EPA
measurement
methods,
are
subject
to
random
variations,
which
ultimately
impact
the
end
results.
Relatively
minor
variations
in
the
skill
of
the
sampler,
as
well
as
the
equipment
and
procedures
used
to
extract
the
sample
can
influence
the
indicated
quantity
of
sample
extracted
from
the
stack
and
the
eficiency
with
which
the
pollutant
of
interest
is
colIected
or
recovered.
Similarly,
minor
variation
in
laboratory
hardware
and
procedures
influence
quantification
of
the
mass
or
volume
of
pollutant
in
that
sample.
The
net
result
of
such
random
variation
is
imprecision
in
measurement
results.
The
current
report
documents
a
study
where
available
data
have
been
gathered
and
analyzed
to
quantify
the
precision
of
key
EPA
manual
measurement
methods.
The
study
has
been
conducted
under
the
auspices
of
the
American
Society
of
Mechanical
Engineers
(
ASME)
and
is
entitled
Reference
Method
Accuracy
and
Precision1
(
ReMAP),
Phase
1.
S
The
purpose
of
the
R
e
m
Phase
1
program
is
"
to
determine
the
precision
of
pollutant
emission
measurements
based
on
anaiysis
of
available
simultaneous
sample2
test
data
which
were
generated
1
Precision
is
defined
here
as
"
Random
Error"
according
to
the
new
ASME
PTC
19.1
1998.
2
Dual
train,
quad
train,
and
simultaneous
samples
from
different
sample
locations
at
a
stationary
emission
source.
1
using
EPA
Manual
Reference
Test
Merhods
5
and
j
i
(
PM).
23
(
dioxin
andfiran),
26
(
HCI).
29
(
multi
metals,
lOla
and
IOIb
(
mercury),
and
108
(
arsenic)
at
a
number
of
srationary
air
sources."
ASME
intends
ReMAP
to
be
a
multi
phase
effort
with
the
first
phase
focusing
exclusively
on
assessment
of
measurement
method
precision.
Consideration
o
sues
associated
with
measurement
accuracy
is
reserved
for
a
later
phase
of
ReMAP.
Three
major
groups
have
sponsored
the
ReMAP
Phase
1
effort.
First,
the
U.
S.
EPA
has
provided
funding
and
personnel
support
to
the
project.
Second,
several
industrial
groups
representing
manufacturing
companies
and
the
waste
combustion
industry
have
provided
program
funding.
Finally,
the
ASME's
Committee
on
Industrial
and
Municipal
Waste
has
provided
both
financial
support
and
overall
program
direction.
Although
Phase
I
results
indicate
that
th
Methods
provide
differing
levels
of
precision
and
that
the
precision
typically
varies
utant
concentratio
MAP
does
not
reach
conclusions
relative
to
p
be
used.
Answering
those
questions
is
appro
the
public.
The
role
o
rifically
sound
d
facilitate
meaningful
policy
debate
and
decisi
lated
industries,
an
It
is
important
to
note
from
the
outset
that
a
variety
of
stack
emission
concentrations.
In
addition
to
measure
skill
of
the
stack
tester),
variation
of
process
feed
mat
operations
impact
stack
emission
A
compliance
test
impacted
by
process
variation
over
time
and
will
potentially
indicate
greater
variability
method
itself.
ntribute
to
variability
in
measured
thod
precision
(
which
includes
the
luding
combustion
fuels)
and
unit
ngle
samples
will
be
ssion
concentrations
the
precision
of
fhe
measurement
2
2.0
Background
The
US
EPA
has
developed
and
published
a
wide
variety
of
methods
for
determining
the
concentration
of
pollutants
in
process
effluent
streams.
The
manual
air
sampling
methods
typically
invoIve
a
probe
for
extracting
a
representative
sample
of
stack
effluent
and
means
for
physically
capturing
or
chemically
extracting
selected
pollutants
from
that
sample.
The
methods
further
define
procedures
for
determining
the
volume
of
sample
gas
extracted
and
for
recovering
the
coIIected
pollutant(
s)
from
the
sampling
apparatus.
Finally,
the
methods
specify
laboratory
procedures
to
use
for
determining
the
quantity
of
pollutant
collected.
In
developing
new
measurement
procedures,
PA
has
traditionally
conducted
extensive
laboratory
and
field
validation
studies
including
tests
to
define
the
precision
and
biases
of
the
method.
Procedures
empioyed
by
EPA
have
evohecl
over
the
years
but
generally
conform
to
those
described
in
a
1977
paper
entitled,
"
How
PA
Validates
NSPS
Methodology"
(
Midgett,
1977).
Mos
procedures
discussed
by
Midgett
have
been
incorporated
into
EPA
Method
301
which
"
is
used
whenever
a
source
owner
or
operator
proposes
a
test
method
to
meet
a
U.
S.
Environmental
Protection
Agency
(
EPA)
requirement
in
the
absence
of
a
validated
method."(
EPA,
1992)
In
validation
of
a
new
method
or
in
tests
to
evaluate
an
alternate
method,
EPA
suggests
use
of
four
sampIing
trains
to
simultaneously
extract
samples
from
nominally
the
same
location
in
a
source
stack.
This
is
commonly
referred
to
as
a
quad
train.
For
method
validation,
two
of
the
four
trains
are
configured
and
operated
in
strict
accordance
with
the
proposed
method,
while
the
other
two
trains
are
spiked
with
known
quantities
of
the
target
analyte.
Comparison
of
data
from
the
two
unspiked
trains
provides
an
indication
of
measurement
precision
while
data
from
the
spiked
trains
provides
an
indication
of
measurement
bias.
Data
from
a
significant
number
of
repeated
multi
train
runs
provide
an
indication
of
the
precision
and
bias
of
the
method
itself.
Method
301
states
that
"
The
precision
of
the
method
at
the
level
of
the
standard
shall
not
be
greater
than
50
percent
relative
standard
deviation."
Several
of
the
EPA
measurement
methods
were
developed
and
validated
in
the
early
days
of
the
Agency.
PA
Method
5
for
measuring
stack
particulate
concentration
was
published
in
the
FederaI
Register
on
December
23,
1971
(
36FR
25876).
Tests
to
validate
that
method
were
performed
on
3
sources
with
particulate
emissions
ranging
from
45
to
240
mddscm.
In
that
time
period,
the
majority
of
Federal
particulate
emission
standa
were
established
at
180
mg/
dscm
(
0.08
gr/
dscf)
corrected
to
7%
02.
Thus,
the
me
ver
a
range
that
included
the
prevailing
regulatory
limits.
At
this
emission
limit,
the
EPA
validation
studies
indicate
that
precision
of
Method
5
,
expressed,
as
a
relative
standard
deviation
was
on
the
order
of
10%.
Passage
of
the
Clean
Air
Act
Amendments
of
1990
ushered
in
new
era
in
both
scope
and
stringency
of
environmental
regulations.
Rules
erning
release
of
Hazardous
Air
PolIutants
(
HAPS)
called
for
regulation
of
I79
specific
pollutants
from
both
new
and
existing
emission
sources.
Provisions
in
the
law,
stipulate
that
standards
must
consider
the
"
Maximum
Achievable
Control
Technology"
(
MACT).
For
existing
sources,
MACT
standards
shall
not
be
less
stringent
than
the
average
emission
performance
achieved
by
the
subcategory.
Implementation
of
this
congressional
mandate
has
resulted
in
many
new
emission
regulations
that
are
dramatically
more
stringent.
F
mple,
in
1999
the
particulate
emission
limit
for
hazardous
waste
incinerators
was
tig
t
performing
12%
of
the
sources
in
a
catego
ed
from
180
to
34
mg/
dscm
(@
7%
02).
Stringent
emission
standards
raise
numerous
concerns
a
methods.
The
particulate
standards
can
be
used
to
highli
method
validation
studies
assessed
acceptably
precise
over
a
rather
broad
applied
and
results
used
for
regulatory
for
which
it
was
validated.
Method
5
mav
be
ac
mgldscm)
but,
prior
to
ReMAP
Phas
meant
all
environmental
stakeholders
EPA
measurement
s.
As
noted,
initial
the
Method
to
be
for
Method
30
1.
Particulate
matter
is
not
the
only
EPA
Reference
measurement
Method
for
which
there
is
concern.
Another
example
is
PA
Method
23
for
determining
diox
d
furan
emission
concentration.
The
published
method
validation
studies
concentrated
almo
clusively
on
pre
on
and
bias
of
4
1
analytical
procedures
and
largely
ignored
the
sample
collection
portion
of
the
overall
method.
No
Agency
method
validation
data
were
provided
examining
the
precision
of
the
entire
sampling
and
analysis
procedure.
Method
23
does
provide
for
extensive
spiking
of
the
sampling
train
with
labeled
compounds
and
includes
tests
to
quantify
recovery
of
those
standards.
However,
data
are
considered
acceptable
if
the
fractional
recovery
of
the
labeled
compounds
falls
within
the
range
of
40%
to
130%.
With
such
broad
allowable
recoveries
and
in
the
absence
of
full
system
precision
analysis,
it
is
anticipated
that
Method
23
may
provide
results
with
exceedingly
wide
precision
bands.
The
above
noted
issues
do
not
imply
that
Methods
5
and
23
are
technically
unacceptable
procedures,
Instead,
these
issues
are
typical
of
senera1
concerns
that
develop
when
method
validations
are
incomplete
or
out
of
date.
In
the
absence
of
well
documented
assessments
of
measurement
method
precision,
many
reasonable
questions
are
formed
and
nurtured.
Typical
questions
include:
In
light
of
the
economic
and
public
perception
consequences
associated
with
a
failed
compIiance
test,
are
the
current
EPA
measurement
methods
technically
acceptable
procedures
for
determining
compliance
with
standards
that
have
become
more
stringent
over
time?
If
a
method
is
highly
imprecise,
will
indication
of
a
failed
compliance
test
withstand
scrutiny
of
a
legal
challenge?
Do
data
indicating
emission
concentrations
below
the
regulatory
limit
really
imply
Databases
used
to
establish
MACT
standards
are
generally
developed
based
on
reports
from
tests
using
published
EPA
methods.
A
critical
portion
of
these
data
data
from
facilities
defining
the
best
performing
12%
of
the
facilities
is
extracted
to
define
the
MACT
technology
or
the
MACT
based
emission
limits.
Do
these
data
characterize
exceotionallv
well
designed
and
operated
facilities
or
do
the
key
data
represent
imprecision
in
the
measurement
methods?
This
concern
applies
to
any
analysis
where
the
best
12%
of
the
data
are
selected
for
examination
but
it
is
even
more
critical
when
those
data
indicate
results
below
the
range
for
which
the
method
was
validated.
5
Concerns
extend
beyond
regulatory
compliance
and
regulatory
development.
Are
the
EPA
methods
acceptable
procedures
for
determining
whether
a
new
air
pollution
control
device
is
meeting
its
performance
guarantees?
is
the
indicated
performance
representative
of
the
control
device
or
do
the
test
results
reflect
significant
imprecision
in
the
method?
I
The
above
lists
of
issues
and
concerns
are
far
from
exhaustive.
However,
almost
invariably,
the
response
to
such
questions
is
that
the
measurement
methods
may
not
be
perfect
but
they
are
the
best
that
we
have.
That
answer
does
not,
however,
alleviate
stakeholder
fears.
The
sponsors
of
ReMAP,
including
the
US
EPA,
have
entered'into
the
program
to
provide
tools
that
might
be
used
to
develop
better
answers.
This
report
is,
however,
not
intended
methods
addressed
herein
or
as
a
substitute
for
Method
301.
APPROACH
There
is
often
confusion
concerning
the
terms,
precision
and
accuracy.
Figure
1,
adapted
from
a
presentation
by
Dr.
Greg
Rigo
at
a
meeting
of
ASME's
Committee
on
Industrial
and
Municipal
Waste
clearly
illustrates
what
the
two
terms
imply.
Imagine
shooting
at
a
target.
The
illustration
on
the
left
shows
a
wide
scattering
of
results,
almost
equally
distributed
around
the
bull's
eye.
The
illustration
on
the
right
shows
a
tightly
grouped
set
of
shot
in
these
results
is
an
indication
of
precision
while
proximity
to
the
bull'
accuracy.
The
target
on
the
left
illustrates
poor
precision
but
good
accuracy.
The
target
on
the
right
illustrates
highly
precise,
but
inaccurate
shooting.
Phase
I
of
ReMAP
is
concerned
with
precision.
Accuracy
is
an
issue
for
later
phases
of
ReMAP.
Many
facilities
have
Iarge
quantities
of
data
from
repeated
single
train
stack
tests.
These
resu
important
to
the
facility
but
typicaIly,
they
shed
little
light
on
the
precision
of
EPA
measurement
Methods.
Variation
in
repeat
measurements
is
in
also
influenced
by
variations
in
facility
operation.
Unfortu
for
separatinz
these
two
effects.
Determination
of
measurement
method
precision
must
be
based
on
simultaneous
determinations
of
stack
emission
concentrations,
preferably
with
co
located
probes.
6
k,
p9""
'
k
?
a
7
Results
from
two
or
more
simultaneous
measurements
provide
information
to
calculate
a
sample
standard
deviation
of
that
measurement.
Two
data
points
a
single
indication
of
standard
deviation
are
not.
however,
a
sufficient
basis
for
defining
the
precision
of
the
measurement
method.
Repeated
simultaneous
data
from
a
given
source
provide
an
improved
indication
of
method
precision.
Repeated
simultaneous
measurements
from
a
v
ty
of
facilities
further
improves
the
data
base
for
assessing
method
precision
since
the
data
co
tack
concentrations
and
a
broader
range
of
personnel
applying
the
method.
The
Re
assembled
a
database
consisting
of
available
multi
train
data
from
a
variety
of
selected
EPA
methods.
A
key
source
of
these
data
are
published
and
unpublished
EPA
reports
addressing
method
validation.
Additionally,
a
limited
number
of
industry
sponsored,
multi
train
studies
have
been
conducted
and
documented.
These
industry
reports
provide
significant
expansion
to
the
scope
of
available
multi
train
data.
Finally,
the
PA
has
sponsored
a
limited
number
of
studies
where
multi
train
tests
were
performed
to
expand
the
range
of
data
for
validation
of
previously
published
methods.
The
ReMAP
program
has
gathered
available
multi
train
data
sets
for
the
following
EPA
measurement
methods:
9
Methods
5
and
5i
for
particulate
matter
(
PM)
emissions
Method
23
for
dioxin
and
furan
emissibns
Method
26
for
hydrochloric
acid
and
chlorine
gas
Method
29
for
multi
metals,
and
9
9
9
c:
9
Methods
IO
1
a
and
10
1
b
for
mercury.
A
search
was
made
for
validation
data
on
the
follo
discovered:
ods
but
no
multi
train
results
were
Method
108
for
arsenic
Method
0030
and
00
10
for
volatile
and
semi
volatile
organics
respectively,
and
Method
00
1
1
for
formaldehyde.
8
After
the
initial
data
collection
activity,
the
ReMap
program
took
two
parallel
paths.
One
path
provided
for
detailed
validation
of
the
gathered
data.
Wherever
possible,
validation
began
with
the
original
field
run
sheets
and
continued
through
a
complete
re
reduction
of
the
data.
This
tedious
process
improved
the
database
by
providing
consistency
in
such
key
factors
as
use
of
consistent
standard
reference
conditions
and
blank
correction
procedures.
The
parallel
effort
involved
identifLing
and
refining
mathematical
procedures
for
analyzing
simultaneously
sampled
concentration
data
to
determine
measurement
precision
at
various
appropriate
concentrations.
Finally,
after
validating
the
database,
the
selected
statistical
analysis
procedures
(
see
Appendix)
were
applied
to
the
validated
database
to
determine
the
precision
of
the
selected
EPA
methods
at
appropriate
concentrations.
A
final
preliminary
point
concerns
the
issue
of
correcting
data
to
a
fixed
percentage
of
excess
oxygen.
Environmental
regulations
almost
always
set
a
limit
on
the
concentration
of
pollutants
in
the
stack
and
require
that
the
concentration
be
adjusted
to
reflect
a
standard
stack
excess
oxygen
(
typically
7%
oxygen).
For
several
reasons
the
ReMAP
study
does
not
include
oxygen
correction
in
the
analysis
of
measurement
method
precision.
The
primary
rationale
is
that
the
various
chemical
analyses
determine
the
quantity
of
a
specific
analyte
in
the
overall
sample
matrix.
If
the
quantity
of
analyte
is
low,
it
makes
little
difference
to
the
chemical
analysis
whether
the
loading
is
the
result
of
effective
air
pollution
control
or
if
the
stack
has
high
excess
air.
A
more
pragmatic
consideration
comes
from
the
available
data.
Several
of
the
key
EPA
method
validation
studies
failed
to
record
the
stack
oxygen
concentration
during
the
tests,
The
following
material
develops
estimates
of
measurement
method
precision
as
a
function
of
the
average
pollutant
concentration.
Both
the
concentration
and
the
precision
metrics
(
when
expressed
in
concentration
terms)
can
be
adjusted
to
a
fixed
oxygen
level
by
applying
the
following
0
2
correction
equation:
This,
of
course,
requires
that
one
have
knowledge
of
the
actual
stack
oxygen
level
as
well
as
the
desired
reference
oxygen
level.
More
specifically,
the
precision
of
a
measurement
method,
9
referenced
to
a
fixed
percent
excess
iir
(
say
7%
02)
will
vary
with
the
02
concentration
in
the
stack.
This
issue
will
be
discussed
in
further
detail
in
later
portions
of
the
report
Report
0
rganiza
tion
This
report
is
divided
into
two
different
sections
front
portion
of
the
repon
has
been
written
for
readers
with
only
a
passing
familiarity
with
st
a1
analysis.
Included
are
descriptions
of
the
measurement
methods
and
the
database
of
multi
train
results.
It
also
includes
a
layman's
presentation
of
the
data
analysis
procedures
and
a
presentation
of
the
study
results.
The
last
portion
of
the
report
(
actually
an
appendix)
provides
a
detailed
description
of
the
statistical
analysis
procedures
used
in
ReMAP.
A
serious
attemp
ade
10
make
the
main
body
ofthe
report
and
the
appendix
readable
and
understandable
to
non
statisticians.
3.0
The
Analysis
Procedure
A
Layman's
Description
Material
presented
in
this
section
provides
a
brief
summary
of
statistical
analysis
procedures
used
in
ReMAP
to
assess
precision
of
the
selected
EPA
measurement
methods.
The
presentation
is
written
for
the
statistical
layman
and
may
seem
overiy
simpiistic
ta
those
skilled
in
the
statistical
sciences.
Such
readers
are
referred
to
the
report's
Appendix
which
includes
detailed
development
of
the
.
statistical
analysis
procedures.
3.1
Measures
of
Precision
As
indicated
earlier,
imprecision
in
a
measurement
method
implies
that
random
error
in
the
sampling
ry
analysis
result
in
random
variation
in
the
indicated
emission
concentration.
otherical
stack
that
emits
a
nearly
constant
concentration
of
some
pollutant.
Imprecision
from
the
measurement
method
will
result
in
measured
concentrations
deviating
from
the
true
stack
concentration.
If
the
hypothetical
stack
is
sampled
many
times,
a
plot
of
the
results
should
such
as
the
one
illustrated
in
Figure
2.
The
average
of
a
large
number
of
ach
the
true
concentration
and
most
of
the
data
points
will
be
relatively
If
the
average
does
not
approach
the
true
concentration,
the
sed.
Individual
measurements
that
are
significantly
removed
from
the
decreasing
frequency.
The
core
objective
of
the
ReMAP
program
is
in
anticipated
results
for
different
manual
measurement
methods
and
measurements
should
concentrafion.
determination
of
how
that
spread
varies
with
the
stack
concentration.
There
are
a
variety
of
parameters
that
may
be
used
to
characterize
the
precision
of
a
method.
The
U.
S.
EPA
has
historically
used
standard
deviation
or
relative
standard
deviation
to
define
precision.
There
are,
however,
several
other
parameters
that
may
be
equally
valid
precision
indicators.
In
Figure
2,
standard
deviation
(
denoted
by
the
symbol
0)
is
indicated
as
a
distance
on
either
side
of
the
mean
value
in
the
distribution.
The
area
under
the
bell
shaped
curve
bounded
by
f
cr
has
special
mathematical
significance
but
for
current
purposes
it
is
sufficient
to
note
that
this
area
covers
68.2
percent
of
the
total
area
under
the
curve.
In
the
example
discussed
11
12
S
0
IIJ
C
.
I
.)
111
L
b.
0
I
.
above
relative
to
Figure
2,
the
bell
shaped
curve
represents
the
expected
frequency
of
many
future
measurements.
Sixty
eight
percent
of
those
future
measurements
are
expected
to
indicate
concentrations
within
k
one
standard
deviation
of
the
mean.
If
the
value
of
Q
is
small
relative
to
the
mean,
then
the
majority
of
the
measurement
results
will
occur
close
to
the
true
value.
Conversely,
if
the
relative
value
of
G
is
large,
a
larger
portion
of
the
measurement
results
will
deviate
significantly
from
the
true
concentration.
A
second
approach
for
describing
measurement
precision
is
to
define
a
data
spread
expected
to
encompass
the
majority
of
future
measurements.
A
convenient
approach
is
to
define
concentration
bounds
capturing
99%
of
the
future
data.
This
parameter
may
hold
special
significance
to
facility
owners
and
operators
who
must
comply
with
emission
regulations.
Essentially,
this
parameter
defines
the
expected
concentration
bounds
for
99
out
of
100
future
measurements.
Where
as
68.2
%
of
measurements
fall
within
A
1.0
(
r
of
the
mean,
99%
of
the
measurements
fall
within
k
2.567
G
of
the
mean.
Both
the
standard
deviation
and
99%
concentration
bounds
represent
the
spread
in
future
measurements
from
random
variation
of
the
measurement
method.
The
standard
deviation
and
99%
concentration
bounds
do
not
include
variation
of
the
emission
source.
A
third
precision
metric
is
the
expected
spread
in
the
average
of
triplicate
measurements.
That
parameter
may
have
special
significance
to
facility
owners,
since
compliance
with
emission
regulations
is
typically
based
on
the
average
of
three
runs.
All
three
precision
metrics
are
related
by
simple
proportion.
As
no
above,
99
out
of
100
future
single
measurements
will
fall
within
the
bounds
of
5
2.5670.
For
repeated
measurements,
the
range
decreases
inversely
with
the
square
root
of
the
number
of
repeat
measurements.
Thus,
ninety
nine
percent
of
the
average
of
future
triplicate
measurements
will
fall
within
the
bounds
off:
1.482
(
5
(
k
2.567/
43
G).
AH
three
metrics
will
be
calculated
in
the
ReMAP
precision
assessments
for
each
measurement
method.
3.2
Estimating
Standard
Deviation
Having
settled
on
metrics
for
describing
measurement
precision,
the
problem
is
reduced
to
determining
standard
deviation
as
a
function
of
measurement
concentration.
From
the
outset,
it
is
critical
to
understand
that
there
is
a
true
value
of
standard
deviation
at
any
given
concentration
but
13
we
will
never
know
its
exact
value.
In
accordance
with
normal
statistical
nomenclature,
the
true
value
of
standard
deviation
is
given
the
symbol
Q
(
si,
gna).
Information
concerning
G
can
be
obtained
from
special
tests
using
two
or
m
ampling
trains
operated
simultaneously
in
the
same
exhaust
stream.
Ideally,
such
tests
extract
sample
from
the
same
nomina
osition(
s)
in
the
stack.
Each
measurement
will
be
subject
to
ran
different
results
from
the
simultaneous
measurements.
Referring
to
the
bell
shaped
distribution
curve
in
Figure
2;
these
two
measurements
represent
two
data
points,
randomly
selected
from
the
total
population
of
potential
data
points.
If
a
larse
number
of
simultaneous
measurements
are
raken,
the
individual
dara
poinrs
should
generate
the
full
distribution.
Typically,
however,
only
two,
three
or
four
sampling
trains
are
operated
simultaneously.
An
estimate
of
the
standard
deviation
for
the
measurement
method
is
obtained
by
calculating
the
standard
deviation
from
dual
o
ad
train
tests
according
to
equation
1
below.
.
i
Eq.
1
Standard
deviation
calculated
from
experimental
data
is
referred
to
by
the
symbol
S
to
make
a
distinction
between
this
value
and
the
true
standard
deviation
Q.
Clearly,
selecting
two
random
points
from
the
full
population
of
points
that
ma
aped
distribution
provides
a
poor
estimate
of
Q.
Selecting
four
points
provides
a
b
ing
measurement
methods,
the
typi
eated
tests
provide
rep
deviation
under
nearly
s
for
assessing
method
e
method
precision
is
a
d
values
of
the
true
constant
concentration
conditions.
standard
deviation
at
the
characteris
very
strong
function
of
concentrat
standard
deviation
that
are
referred
to
in
this
report
as
Est.
c.
There
are
however,
several
complications
to
the
process
of
estimating
the
standard
deviation
from
dual
and
quad
train
test
results.
When
standard
deviation
is
calculated
from
smaIl
samples
of
a
large
population,
the
result
is
a
biased
estimate.
The
magnitude
of
the
bias
is
dependant
upon
the
number
of
data
points
used
to
estimate
each
value
of
S.
A
detaifed
presentation
on
the
source
of
this
bias
is
14
beyond
the
scope
of
the
current
discussion.
However,
for
illustrative
purposes,
consider
the
case
where
a
large
number
of
data
pairs
are
randomly
selected
from
a
known
distribution.
Standard
deviation
(
S)
can
be
calculated
for
each
data
pair
according
to
equation
1.
Most
non
statisticians
will
anticipate
that
the
average
of
the
standard
deviations
(
S)
calculated
from
many
data
pairs
would
closely
approximate
the
true
standard
deviation
(
a)
for
the
overall
distribution.
As
discussion
in
the
Appendix,
that
anticipation
would
not
be
realized.
In
fact,
using
data
pairs,
the
average
standard
deviation
would
be
biased
low
by
a
factor
of
1.253.
If
we
repeated
this
example
using
three
or
four
data
points
for
each
standard
deviation
calculation,
the
average
standard
deviation
will
be
closer
to
the
true
value
but
the
bias
will
still
be
present.
For
triplicate
measurements,
the
bias
factor
is
1.128
while
for
quad
train
the
bias
factor
is
only
1.085.
In
the
ReMAP
data
analysis,
the
standard
deviation
calculated
from
each
multi
train
test
must
be
multiplied
by
the
appropriate
small
sample
bias
correction
factor.
This
provides
an
unbiased
estimation
of
standard
deviation
at
the
selected
concentration.
This
calculated
parameter
is
referred
to
as
small
sample,
bias
corrected
S.
.
To
assess
the
impact
of
pollutant
concentration
on
method
precision,
it
is
necessary
to
gather
multi
train
measurement
data
over
a
broad
range
of
concentration
and
to
fit
the
data
to
an
equation
relating
S
to
average
concentration
(
C).
The
first
step
is
to
check
these
data
for
outliers
and
to
prepare
the
data
for
analysis.
Two
approaches
are
used
by
ReMAP
to
screen
data
for
outliers.
These
procedures
are
defined
in
the
Appendix
and
illustrated
in
the
next
section
of
the
report.
The
first
procedure
is
known
as
the
Dixon's
r
test.
This
procedure
is,
used
to
examine
a
group
of
data
points
collected
during
a
single,
multi
train
test
and
to
determine
if
one
or
more
data
points
in
the
group
are
outliers.
It
is
only
applicable
to
tests
with
three
or
more
simultaneous
sampling
trains.
The
second
screening
procedure
is
taken
from
Statistical
Process
Control
(
SPC)
methods
and
is
used
to
identify
outliers
from
multiple
simultaneous
measurements.
The
essence
of
this
procedure
is
to
compare
the
span
between
simultaneous
measurements
against
the
weighted
average
span
for
other
data
in
a
similar
concentration
range.
Special
provisions
are
included
to
account
for
the
fact
that
data
may
exist
as
pair,
triplicates,
or
as
quad
train
results.
After
outlier
screening,
the
validated
data
are
entered
into
a
spreadsheet;
standard
deviations
are
calculated
and
then
corrected
for
the
above
noted
small
sample
bias.
Figure
3
illustrates
a
hypothetical
set
of
data
showing
small
sample
bias
corrected
standard
deviation
versus
mean
15
.
.
.
c7
LL
T
O
0
0
0
..
0
0
0
?
0
0
P
T
P"
p"
9
1
b
concentration
from
several
multi
train
tests.
The
objective
is
to
fit
these
data
to
an
equation
relating
standard
deviation
(
Sbias
corrected)
to
average
concentration
(
C).
If
done
properly,
this
curve
fit
wilI
also
approximately
describe
the
relationship
between
G
and
C.
However,
before
fitting
the
data
to
a
functional
form,
it
is
necessary
to
account
for
the
differences
between
data
sets
consisting
of
2,
3,
or
4
simultaneous
measurements.
Equation
1
can
be
applied
to
dual
train
measurements
to
determine
the
standard
deviation
(
S)
with
only
one
degree
of
freedom.
Values
of
S
can
be
determined
from
triplicate
measurements
but
this
S
value
has
two
degrees
of
freedom.
Thus,
a
triplicate
measurement
provides
as
much
information
about
the
precision
of
the
measurement
method
as
two
dual
train
measurements.
Similariy
a
quad
train
provides
as
much
information
a
s
three
paired
trains.
In
curve
fin
g
the
data,
weighting
factors
must
be
applied
to
account
for
the
number
of
degrees
of
freedom
from
each
data
grouping.
r
3.3
The
Relationship
Between
S
and
C
i
As
discussed
in
the
Appendix,
a
wide
range
of
functional
forms
is
possible
for
describing
the
relationship
between
standard
deviation
and
concentration.
Based
on
the
characteristics
of
the
availabIe
data,
the
form
selected
and
justified
for
the
ReMAf
program
is
a
simple
power
function
as
6
L
=
m
described
in
Equation
2,
k
4
S
=
k
C
p
Eq.
2
7
Ld
where
S
is
the
estimated
standard
deviation
for
the
method,
C
is
concentration,
and
k
and
p
are
constants.
For
each
measurement
method,
the
available
data
are
fit
to
this
equation
using
a
least
squares
regression
analysis.
To
facilitate
that
regression,
it
is
convenient
to
first
transform
equation
2
by
taking
logarithms
to
yield,
r
Eq.
3.
Regression
analysis
yields
values
for
Ln(
k)
and
p
.
The
governing
equation
is
obtained
by
taking
inverse
logs.
Unfortunately,
the
transformation
processes
create
yet
another
bias
that
must
be
accounted
for.
17
In
the
database,
an
average
value
of
the
individual
standard
deviations
can
be
calculated
from
the
multi
train
data
for
a
selected
method.
The
individual
values
of
average
concentration
from
the
database
can
be
entered
into
the
regression
equation
(
Eq.
3)
to
predict
values
of
S
at
each
value
of
For
an
unbiased
model,
the
average
value
of
predicted
S
equals
the
average
value
of
S
With
transformation
of
data
into
the
loplog
plane,
that
value
of
Ln(
S)
{
Predicted]
will
equal
the
av
source
of
this
bias
is
that
Ln(
S)
f
L
n
(
3
This
bias
can
be
accounted
for
by
appropriately
adjusting
the
value
of
k
in
the
model.
Further
explanation
of
this
bias
and
the
procedure
for
bias
correct
The
above
procedure
provides
a
simple
means
of
using
available
data
to
estimate
the
standard
deviation
as
a
function
of
average
concentration
for
any
given
measurement
method.
At
any
selected
concentration,
the
regression
equation
can
be
determine
an
estimated
value
of
c.
Information
on
Est.
CJ
and
average
concentration
c
the
anticipated
range
for
99
out
of
100
future
ind
as
well
as
the
anticipated
range
for
the
average
o
note,
however,
that
even
after
correcting
for
the
various
biases,
the
regression
line
is
not
a
perfect
indicator
of
true
value
of
Q.
This
evaluation
is
a
best
estimate,
based
on
the
currently
available
data.
Addition
of
new
data
will
undoubtedly
cause
an
adjustment
to
the
regression
equa
relation
between
Est.
Q
and
C.
stack
concentration)
3.4
Confidence
Intervals
A
critical
question
that
must
be
examined
is
`&
HOW
good
is
the
correlation?"
Based
on
analysis
of
the
available
data,
it
is
possible
to
estimate
the
potential
for
the
regression
line
through
the
S
versus
C
data.
These
potential
bounds
are
referred
t
calculating
confidence
intervals
are
presented
in
the
Ap
he
Appendix
also
includes
several
example
calculations.
Figure
4,
taken
directly
from
the
Appendix,
illustrates
a
hypothetical
set
of
small
sample,
bias
corrected
S
versus
C
data.
The
heavy
solid
line
through
the
data
represents
the
regression
line
while
the
arched
lines
above
and
below
the
regression
line
illustrate
the
upper
and
P
*
*
4,
..
cn
C
0
m
>
.
e
.
8
O
I
I
0
0
0
F
0
0
F
0
0
0
0
0
a>
CI,
Q)
2
k
0
0
0
0
P
0
?
rn
Y
a"
0
Q,
Y
P
I
19
lower
confidence
intervals.
The
regression
line
represents
the
best
estimate
of
the
relationship
between
G
and
average
concentration.
The
analysis
used
to
determine
the
regression
line
also
provides
information
on
the
potential
bound
example,
the
analysis
provides
a
best
estim
analysis
ais0
provides
information
to
de
maximum
slope
of
the
reIation
@).
In
Fi
relation
where
p
is
at
the
minimum
and
confidence
level,
we
know
that
the
slope
Line
A
and
less
than
iliustrated
by
on
the
potential
range
of
the
leading
c
illustrated
in
Figure
4
represent
the
comb
Confidence
intervals
on
a
linear
relation
will
always
ha
the
potential
range
for
the
slope
term.
The
true
be
determined,
but
it
is
possible
to
provide
t
a
given
confidenc
r
the
slope
of
th
ression
equation
@).
The
,
at
a
given
confidence
level,
the
m
,
the
lines
labeled
A
and
B
illustrate
m
values
respectively.
Specifically,
at
the
95%
(
e.
g.,
95
YO),
the
regression
interval.
The
primary
task
for
the
Phase
I
Re
deviation
at
given
values
of
concentr
of
method
precision.
If
95%
confidence
interval
97.5%
confidence
that
the
method's
Similarly,
there
is
97.5%
confidenc
bound.
However,
neither
of
the
precision.
The
currently
available
method
precision.
Plots
such
as
that
provided
in
Figure
4,
frequently
cause
difficulty
for
readers.
Generally,
a
significant
portion
of
the
individual
data
p?
ints
(
circles
on
Figure
4)
fall
outside
the
confidence
limits.
This
is
an
expected
trend
since
the
confidence
intervals
represent
upper
and
lower
bounds
for
the
regression
line
not
upper
and
lower
bounds
for
the
data.
A
word
of
caution
is
in
order.
When
the
statistical
analysis
does
not
require
weighting,
it
is
relatively
simple
to
calculate
confidence
intervals
using
software
routines
contained
in
standard,
commercial
spreadsheet
computer
programs.
Recall
that
weighting
of
the
data
is
required
when
the
individual
data
points
have
different
degrees
of
freedom.
For
example,
standard
software
can
easily
be
used
to
calculate
confidence
intervals
in
situations
when
all
of
the
data
consist
of
paired
train
measurements.
When
data
weighting
is
required,
calculation
of
confidence
intervals
becomes
much
more
complex,
requiring
inversion
of
rather
messy
matrices.
Advanced
statistical
analysis
computer
software
generally
includes
routines
for
such
analyses.
Alternately,
special
computer
software
will
need
to
be
written.
For
the
current
report,
detailed
expianation
of
confidence
interval
calculation
has
been
limited
to
those
situations
where
calculations
can
be
performed
using
software
routines
in
standard
spreadsheet
computer
programs
such
as
Excel.
One
additional
subtle
issue
related
to
calculation
of
confidence
intervals
must
be
addressed
before
proceeding
with
the
ReMAP
analysis.
The
appropriate
calculation
process
depends
upon
bow
the
confidence
intervals
are
to
be
used.
For
the
ReMAP
study,
the
intended
use
of
the
various
analyses
is
to
determine
Est.
Q
at
discreet
values
of
average
concentration
and
to
use
Est.
Q
to
calculate
various
precision
metrics
at
those
average
concentrations.
Method
precision
metrics
are
also
calculated
assuming
that
the
true
value
of
Q
is
at
the
upper
and
lower
confidence
intervals
(
at
selected
concentrations).
There
are
alternate
ways
of
using
confidence
intervals
that
require
slightly
different
analysis
procedures.
Reh4AP
statistical
methodology
and
were
deemed
inappropriate
for
the
current
analysis
purposes.
Those
procedures
were
carefully
considered
in
establishing
the
3.5
Summary
of
ReMAP
Analysis
Process
In
summary,
the
ReMAP
analysis
procedure
begins
with
a
database
of
available
multi
train
data
from
application
of
an
EPA
measurement
method.
These
data
are
screened
for
outiiers
using
procedures
that
purposefully
try
to
include
as
much
data
as
possible.
Data
should
be
discarded
only
if
there
is
an
identified
problem
with
a
measurement
or
if
a
data
pair
(
or
a
single
measurement
from
a
triplicate
or
quad
test)
is
demonstrably
dissimilar
from
the
remainder
of
the
data
in
the
data
set.
For
each
test
run,
the
2,
3,
or
4
simultaneous
measurements
are
entered
into
equation
1
to
determine
21
the
standard
deviation
for
the
run.
Each
of
these
standard
deviation
estimates
is
then
multiplied
by
the
appropriate
correction
factor
to
account
for
small
sample
bias.
The
array
of
bias
corrected
standard
deviation
data
and
average
concentration
data
are
weighted
for
the
number
of
degrees
of
freedom,
transformed
to
the
Log
Log
plane,
and
subjected
t
linear
regression
analysis.
This
analysis
determines
values
of
k
and
p
in
the
power
fun
used
to
determine
a
predicted
value
of
standard
d
average
value
of
S
from
the
test
data
is
compared
to
the
average
value
of
S
from
determine
an
appropriate
value
for
the
second
bi
correction
factor.
That
factor
is
multiplied
by
the
k
parameter
to
provide
an
unbiased
equation
relating
our
best
estimate
of
standard
deviation
to
concentration.
Next,
the
95%
confidence
intervals
are
calculated
over
the
range
of
available
data.
mote,
the
confidence
intervals
are
actually
calculated
in
the
Log
Log
plane.
The
second
bias
correction
factor
is
applied
to
the
interval
when
it
is
transformed
back
to
the
Est.
a
C
plane.]
Data
are
presented
in
four
ways.
First,
the
data
are
presented
in
tabular
and
gaphicat
form
showing
a
scatter
plot
of
calculated
standard
deviation
and
relative
standard
deviation
concentration.
The
second
form
of
data
presentation
is
a
graph
of
the
three
precision
metrics
elorted
against
concentration.
Each
of
these
metrics
is
normalized
by
the
concentration
and
is
based
on
the
best
estimate
of
the
method
standard
deviation.
Third,
data
are
presented
to
illustrate
the
fact
that
the
true
value
of
method
standard
deviation
co
d
be
greater
than
or
less
than
the
best
estimate.
There
are
six
curves
of
interest.
The
first
two
curves,
representing
a
worst
case
scenario,
focus
on
the
situation
that
would
occur
;
f
the
true
method
standard
deviation
(
Q)
were
best
represented
by
the
upper
bound
of
the
95%
confidence
intervaI.
Using
that
upper
limit
of
Est.
o,
the
upper
and
lower
bounds
of
measured
concentration
are
calculated
that
encompasses
99%
of
future
measurements.
These
curves,
plotted
against
stack
concentration,
are
denoted
by
the
symbols
C99u/
S95+
and
C991/
S95+.
Next,
the
data
bands
encompassing
99%
of
future
measurements
are
calculated,
assuming
that
true
standard
deviation
varies
according
to
the
regression
equation.
These
two
lines
are
given
the
notation
C99u/
Sbest
and
C991lSbest.
Finally,
consideration
is
given
to
the
case
where
the
regression
analysis
has
provided
an
over
estimate
of
standard
deviation.
These
curves
are
similar
to
the
first
two
but
are
based
on
the
lower
95%
confidence
interval.
These
two
lines,
given
the
symbols
C99ulS95
and
C991/
S95,
can
be
considered
best
case
scenarios.
There
is
97.5%
confidence
that
the
method's
precision
is
worse
than
these
last
two
lines.
i
kr_
r
For
each
of
the
plots
describing
measurement
method
precision,
care
has
been
taken
to
limit
the
range
of
the
presentation
to
the
range
of
the
currently
available
data.
There
has
been
no
extrapolation
beyond
the
range
for
which
experimental
data
was
available.
The
final
data
presentation
is
a
table
quantifying
the
anticipated
range
of
fbture
measurements
at
selected
values
of
average
stack
concentration.
These
tables
list
C99dSbest
and
C99IISbest
over
a
range
of
concentrations
imposed
or
under
consideration
for
current
environmental
regulations.
As
regards
these
tables
as
well
as
all
other
methods
of
describing
method
precision,
it
is
important
to
reiterate
that
various
parameters
are
not
corrected
to
a
constant
excess
air
level.
The
sections
that
follow
examine
each
of
the
EPA
Measurement
Methods
of
interest.
The
first
method
discussed
is
Method
5
for
determining
particulate
matter
concentration.
The
precision
assessment
for
this
method
is
presented
in
great
detail
in
hope
that
the
reader
can
better
understand
the
fuIl
scope
of
the
assessment.
23
This
Page
IntentionaIIy
Left
Blank.
4.0
EPA
Particulate
Matter
Methods
Methods
5
and
5i
Sampling
hardware
used
for
the
majority
of
the
EPA
manual
isokinetic
measurement
methods
is
based
upon
the
hardware
used
for
measuring
particulate
matter
(
PM)
concentration
in
stacks.
The
procedure
for
measuring
stack
particulate
concentration
has
been
designated
EPA
Method
5
and
the
associated
hardware
is
referred
to
as
a
Method
5
train.
(
EPA,
1987)
Additional
details
on
Method
5
.
(
and
other
Methods
discussed
in
this
report)
can
be
found
in
40CFR
Part
60
Appendix
A
under
the
heading
for
the
Method.
Figure
5
illustrates
the
Method5
hardware.
Describing
the
key
features
of
a
Method
5
train
serves
as
a
convenient
basis
for
fbrther
discussion
of
other
measurement
methods
addressed
in
this
study.
In
general
terms,
application
of
Method
5
involves
inserting
a
probe
into
a
stack
and
extracting
a
composite
sample
that
is
representative
of
average
conditions
across
the
stack.
In
a
typical
sampling
run,
sample
gases
are
extracted
from
the
stack
for
a
period
of
approximately
one
hour.
The
stack
cross
section
is
divided
into
equal
area
segments.
The
probe
is
traversed
across
the
stack,
e
stack
flow
from
each
segment
for
equal
time
periods.
With
a
round
stack,
traversing
typical
two
ports,
located
perpendicular
to
each
other.
The
rate
of
sample
extraction
is
adjusted
t
the
velocity
of
gases
entering
the
probe
tip
is
essentially
equal
to
the
local
velocity
of
flue
gas
in
the
stack.
This
is
referred
to
as
isokinetic
sampling.
This
feature
of
manual
method
sampling
is
included
to
minimize
the
potential
for
sample
bias
associated
with
preferential
capture
of
solid
phase
material
according
to
particle
size.
The
extracted
sample
is
passed
through
a
heated
line
to
a
heated
filter
assembly
that
captures
solid
phase
particles.
The
mass
of
particulate
captured
during
the
entire
sampling
period
is
determined
gravimetrically.
Additional
features
of
the
method
include
procedures
for
determining
the
volume
of
flue
gas
extracted
from
the
stack
during
the
sampling
period.
Using
standardized
protocols,
the
particulate
concentration
is
determined
as
the
ratio
of
the
mass
of
particulate
collected
divided
by
the
volume
of
flue
gas
extracted.
25
26
ri
L
P
L
Figure
5
illustrates
the
hardware
components
and
their
arrangement
for
Method
5
sampling.
AS
indicated,
sample
gas
is
extracted
through
a
nozzle
and
transported
in
a
heated
glass
probe
to
a
heated
filter
assembly.
The
probe
assembly
consists
of
a
glass
nozzle,
a
heated
glass
probe
liner,
a
s
type
pitot
probe
and
a
thermocouple
(
TK).
The
T/
C
and
pitot
allow
determination
of
the
local
stack
gas
temperature
and
velocity,
which
provides
a
basis
for
adjusting
the
sample
extraction
rate
to
isokinetic
conditions.
Particulate
matter
in
the
sample
may
be
deposited
on
the
nozzle
and
probe
liner
walls
but
the
majority
of
the
particulate
matter
(
typically
>
go%)
is
collected
on
a
heated
filter.
Heating
of
both
the
probe
and
filter
assembly
is
required
to
prevent
condensation
of
water
and
other
condensable
materials
in
this
portion
of
the
sampIing
train
(
often
referred
to
as
the
front
half
of
the
train).
Located
downstream
of
the
heated
filter
box
is
a
series
of
impingers
in
an
ice
bath
that
remove
moisture
from
the
sample.
An
umbilical
cord
connects
the
impingers
to
the
meter
box.
The
meter
box
contains
a
dry
gas
meter
to
determine
the
volume
of
dry
sample
extracted,
means
for
determining
pitot
probe
AP,
read
outs
for
key
temperatures,
and
a
vacuum
pump
for
adjusting
sample
extraction
rate.
The
sampling
rate
is
usually
held
between
0.5
and
1.0
cubic
feet
per
minute.
After
completion
of
a
test
run,
the
field
technician
thoroughly
rinses
the
train
components
upstream
of
the
filter
with
the
appropriate
solvent
(
generally
acetone
for
paniculate
samples)
to
recover
any
particulate
that
may
have
been
deposited
on
the
probe
walls
or
nozzle
tip.
The
technician
must
also
record
a
number
of
sampling
system
parameters
necessary
to
determine
the
volume
of
gas
collected
and
the
moisture
content
of
the
flue
gas.
Typically
an
Orsat
analysis
is
performed
on
the
flue
gas
to
determine
the
major
constituents
of
the
flue
gas,
particularly
the
oxygen
concentration.
Back
in
the
laboratory,
the
probe
rinse
and
filter
are
dried
and
the
mass
of
particulate
collected
is
determined
gravimetrically.
To
assure
that
the
final
weig
gain
on
the
filter
represents
dried
particulate,
repeated
measurements
are
performed.
The
Sam
is
considered
dry
and
results
are
reported
when
subsequent
weighings
agree
within
0.5
mg.
Particulate
concentration
is
determined
as
the
ratio
of
the
particulate
mass
colIected
divided
by
the
volume
of
flue
gas
collected.
Usually,
the
sample
volume
is
determined
and
reported
on
a
dry
basis
and
adjusted
to
standard
temperature
and
pressure
conditions.
Standard
temperature
and
pressure
conditions
used
by
the
U
S
PA
are
20
°
C
and
760
mrn
Hg.
For
regulatory
purposes
dilution
effects
are
accounted
for
by
correcting
the
measured
concentration
to
a
fixed
percent
oxygen
(
or
carbon
dioxide).
27
Some
states
require
special
analysis
pro
ures
to
assess
the
mass
of
material
that
condenses
in
the
impinser
portion
of
the
Method
5
sampling
train.
Those
states
o
require
that
the
mass
of
condensed
phase
material
be
combined
with
the
particulate
catch
in
probe
and
filter
to
yield
a
total
particulate
phase
catch.
These
procedures
were
not
used
for
the
ReMAP
study.
All
particulate
concentration
data
presented
and
anaIyzed
in
the
following
sections
represent
solid
phase
material
collected
in
the
front
half
of
the
train
only.
Moreover,
the
performance
of
particulate
measurement
methods
sh
the
analysis
includes
back
half
catch
from
Method
not
be
applied
to
measurem
4.1
Method
5
Data
and
Precision
Analysis
Multi
train
data
included
in
the
ReMAP
database
come
from
three
main
reports.
The
first
data
set
includes
a
series
of
EPA
sponsored
studies
condu
search
Institute
in
the
early
1970s
to
validate
the
pa
date
method
(
Hamil
a
included
a
coal
fired
PO
plant
and
two
municip
units
were
performed
using
fou
ltaneously
(
quad
trains).
For
this
study,
each
train
was
operated
b
At
the
power
plant
site,
testi
providing
a
total
of
16
data
poi
For
the
first
MWC
test,
six
test
con
concentrations
ranging
from
runs,
providing
20
individual
these
three
test
series
are
provided
i
(
and
all
subsequent
tables
listing
reference.
Skips
in
run
numb
difficulties
and
suggest
that
t
nt
operating
conditions
thus
ge
from
141
to
240
mg/
dscm.
4
individual
data
points
with
28
w
*.
Table
1.
PA
Method
5
Data
Hamil
and
Cam
1974
and
I974b.
RunNumber
A
8
C
D
I
1
205
202
204
22
1
ower
Plant
207
240
155
150
141
I
I
1
5
60.4
61.9
63.2
64.6
Mwc
1
,
I
1
J
14
126
123
I34
,
144
15
153
141
161
139
16
103
106
104
103
All
data
expressed
as
mg/
dSm
Data
are
not
corrected
for
oxygen
content
29
The
next
set
of
multi
train
Method
5
data
is
provided
by
a
second
EPA
sponsored
study
at
an
MWC
in
Dade
County,
Florida.
The
tests
were
directed
by
Southwest
Research
Institute
(
H
a
d
and
Thomas,
1976).
These
tests
are
unique
among
all
data
collected
for
validation
of
PA
measurement
methods.
The
stack
test
location
provided
four
sampling
trains
were
used
in
each
port
providing
a
total
of
eight
simultaneous
measurements
for
each
test
condition.
Moreover,
a
total
of
nine
different
samplin
ams
were
used
in
the
collaborative
study.
The
experiments
covered
a
3
week
period
with
the
test
pian
calling
for
five
runs
per
week.
Seven
different
laboratories
analyzed
the
four
paired
sampling
trains
at
the
train
was
operated
by
a
single
technician
maintain
each
week
(
accounting
for
three
of
the
nine
parti
paired
trains,
a
separate
laboratory
operated
each
t
1
The
test
plan
called
for
fifteen
sampling
runs,
five
per
week
for
th
actually
completed;
three
the
first
week
and
five
each
the
second
and
summary
of
the
measurement
results.
A
total
of
104
data
points
were
collected.
For
run
10,
a
probe
liner
was
broken
on
one
of
the
eight
trains
(
Train
A
operated
by
Laboratory
103).
Accordingly,
that
data
point
was
eliminated
from
the
data
analysis.
The
final
data
source
was
an
ASME
sponsored
study
by
Rig0
and
Chandler
who
performed
extensive
muiti
train
experiments
on
a
municipal
w
Chandler,
1997).
A
total
of
I6
Method
5
data
pairs
are
re
tor
in
Piasfield,
Mass
(
Ri
.
The
data
range
for
these
from
14
to
74
mg/
dscm,
which
significantly
gathered
at
Pittsfield
used
essentially
every
nds
the
overall
range
of
the
full
data
set.
Data
method
of
interest
to
the
ReMAP
program.
Particulate
concentration
results
from
the
Rig0
and
Chandler
t
are
provided
in
Table
3.
The
first
step
in
the
ReMAP
analysis
is
to
determine
if
a
approach
is
outlined
in
the
Appendix
and
includes
the
Statistical
Process
Control
(
SPC)
methods.
consisting
of
three
or
more
simultaneous
measurements
and
is
used
to
identify
potential
outliers
f
the
data
groups
are
outliers.
The
n's
r
test,
a
procedure
taken
from
test
is
applied
to
individual
tests
The
Dixon's
c
I
Pi
3
al
g
31
d
E
e,
E
3
E
.
e,
10
2
0
e
L
B
0
e,
t:
3
0
l
0
c
8
CJ
eJ
L
4
d
TabIe
3.
EPA
Method
5
Data
Pitt
All
dara
expressed
as
mddscm.
Data
are
not
corrected
for
Oy~
gen
content
32
F?
f
within
the
test.
The
SPC
procedure
begins
by
breaking
the
data
into
groups
representing
ranges
of
similar
concentration.
The
span
of
data
is
calculated
for
each
simultaneous
measurement
and
then
weighted
according
to
a
factor
that
is
a
function
of
the
number
of
simultaneous
determinations
(
Le.,
pairs,
quads,
etc.).
Next,
the
average
weighted
span
is
calculated
for
each
concentration
group.
If
the
span
for
a
given
r
exceeds
the
weighted
average
span,
then
data
from
that
run
are
abnormally
large,
relative
to
afa
in
that
concentration
range.
In
SPC
terminology,
the
weighting
factors
are
referred
as
D4.
Table
4
provides
a
listing
of
D4
parameters
as
a
function
of
the
number
of
measurements
in
a
run.
,
Table
4:
SPC
Factors
for
Identification
of
Data
Outliers
Sample
Size,
n
The
choice
of
concentration
ran
were
tested.
There
is
a
strong
Table
5
combines
the
data
prese
procedures
outlined
above.
As
group
representing
power
plant,
at
MWC2
and
at
the
Dade
County
of
these
data
had
average
PM
ions
above
94
mddscm.
The
remaining
data
and
the
Pittsfield
MWC
had
M
concentrations
less
than
68
mgdscm.
The
weighted
average
spread
for
simultaneo
ments
in
the
low
concentration
range
was
13.1
5
mgdscm.
For
measurements
in
the
hig
ion
range,
the
weighted
average
data
spread
was
77.32
mg/
dscm.
Data
points
are
suspect
if
the
actual
measurement
spread
is
greater
than
these
values.
Data
point
number
17
in
the
Rigo
and
Chandler
set
marginally
exceeds
this
limit.
However,
this
data
point
has
the
highest
concentration
in
the
"
low
concentration"
data
group.
When
the
spread
on
this
data
point
is
normalized
by
the
mean
concentration,
the
spread
is
on
the
same
order
as
several
other
data
points
in
the
low
group.
The
ReMAP
program
has
a
bias
for
retaining
all
data
unless
it
is
somewhat
arbitrary.
For
the
ReMAP
analysis,
several
ranges
rence
for
minimizing
the
number
of
data
points
eliminated.
rlier
in
Tables
1,2
and
3
and
assesses
the
data
according
SPC
ut,
the
data
was
separated
into
two
range
groups
with
the
33
Table
5.
Consolidated
Method
5
Data
Set
A11
data
expressed
as
mg/
dscm.
Dam
are
not
corrected
for
0
3
an
obvious
and
significant
outlier.
retained
for
subsequent
anaiysis.
All
data
points
in
the
low
concentration
grouping
have
been
The
high
concentration
range
group
includes
quad
data
and
the
Dade
County
tests
using
octets.
Data
in
this
range
are
suspect
if
the
difference
is
greater
than
77.32
mgldscm.
Only
one
measurement,
run
number
12
from
the
Dade
County
tests,
fails
to
meet
this
criteria.
Data
from
run
number
I
in
the
Dade
County
tests
is
also
quite
large.
The
data
report
provides
no
indication
of
measurement
problems
associated
with
either
of
these
measurements
but
it
is
obvious
from
inspection
that,
for
run
number
i2
the
two
data
points
collected
by
Laboratory
103
(
labeled
A
and
B
in
Table
5)
are
higher
than
the
other
six
determinations.
For
run
number
1,
data
from
Run
C
also
appears
abnormally
high.
Dixon's
r
procedure
was
applied
to
the
data
from
b
ns
and
results
indicate
that
test
point
C
from
run
number
1
and
test
point
A
from
run
12
are
abn
y
high
and
should
be
considered
as
outliers.
All
other
data
points
in
this
data
set
pass
the
Dixon's
r
criteria.
After
eliminating
points,
the
remaining
data
in
the
ion
data
group
pass
the
SPA
criteria.
/
the
two
data
The
next
step
in
the
analysis
is
to
calculate
the
average
concentration
and
standard
deviation
for
each
group
of
simultaneous
measure
ts
and
to
correct
the
calculated
sample
standard
deviations
for
the
small
sample
bias.
As
noted
in
ier
discussion,
the
calculated
value
of
standard
deviation
from
the
data,
S,
is
a
biased
estimate
of
the
true
standard
deviation,
CT.
Table
6
presents
the
correction
factors
used
to
caIculate
a
data
points
used
to
calculate
S.
Results
of
these
calculations
are
presented
in
Table
7.
Figures
6a
and
6b
present
scatter
plots
of
the
data
from
Table
7.
Figure
6a
shows
the
scatter
of
bias
corrected
standard
deviation
versus
the
average
particulate
concentration.
Figure
6b
presents
the
same
data,
but
in
a
sIightIy
different
i
35
Facility
RunNo
N
Avg.
Standard
Bias
Esttmared~
Conccnnation
Deviation
Factor
Sisma
All
data
expressed
as
mg/
dscm.
Data
36
37
a
v)
0
ua
N
'
0
0
F1
0
m
r
0
z
0
m
0
d
u
u
L
..
.
.
L.
u
<
format.
Here
the
standard
deviation
has
been
normalized
by
the
concentration
and
presented
in
units
of
percent.
i
The
next
portion
of
the
data
analysis
is
to
evaluate
the
relationship
between
the
estimated
standard
deviation
and
the
average
particulate
concentration.
However,
before
performing
the
regression
analysis,
it
is
necessary
to
weight
the
data
according
to
the
number
of
degrees
of
freedom
for
each
measurement
group.
As
discussed
in
the
previous
section,
statistical
assessment
of
data
containing
differing
degrees
of
freedom
involves
complex
matrix
inversion
procedures.
Details
of
the
caIculation
procedure
are
not
included
here.
It
is
instructive
to
review
the
rationale
for
weighting
the
data.
With
a
quad
train,
the
four
individual
particulate
measurements
can
be
used
in
a
variety
of
ways.
For
example,
Train
A
can
be
grouped
with
Trains
B,
C,
and
D
to
calcuiate
three
different
standard
deviations
or
the
four
measurements
can
be
combined
in
the
calculation
of
a
single
value
of
S.
Determination
of
S
based
on
data
from
Trains
A
and
B
provides
the
same
level
of
information
achieved
from
dual
train
testing.
Similarly,
S
determinations
using
data
from
Trains
A
and
C
or
from
Trains
A
and
D
convey
the
same
level
of
information
as
dual
train
measurements.
Clearly,
a
calculated
value
of
S
using
ail
four
simultaneous
measurements
conta
more
information
than
a
calculation
based
on
two
measurements.
When
a
data
set
contains
results
from
dual,
triple,
quad,
etc.
measurements
it
is
necessary
to
weight
the
various
data
to
account
fo
e
relative
quantity
of
information
provided
in
each
test.
The
weighted
data
set
is
then
fit
to
a
power
function
relationship,
as
presented
below.
S
=
kCp
Eq.
1
To
assist
in
that
regression,
the
data
is
transformed
into
the
log
log
plane
such
that
the
governing
equation
becomes:
Ln(
S)
=
Ln(
k)
+
pLn(
C)
Eq.
2
By
performing
the
transformation,
the
regression
analysis
is
linearized.
Results
from
the
analysis
of
data
in
Table
7
are
summarized
in
Table
8
below.
.
.
39
A
regression
analysis
is
a
mathematical
procedure
that
yields
a
best
estimate
for
the
curve
fit
parameters.
One
critical
question
islwhether
the
indicated
values
of
k
and
p
are
statistically
significant.
One
approach
to
answering
this
question
is
the
Student
list
the
t
statistic
as
a
function
of
the
confidence
lev
g.
95%
confidence)
and
the
nulnber
of
degrees
of
freedom.
The
regression
analysis
also
produces
a
value
of
the
t
parameter.
If
the
calculated
t
parameter
is
greater
than
the
criticaI
are
statistically
significant.
Conversely,
if
the
statistic,
then
the
regression
analysis
results
co
Table
8,
the
calculated
value
of
the
t
paramet
parameter
for
42
degrees
of
freedom,
at
the
assures
that
there
is
a
relationship
between
S
regression
analysis,
did
not
occur
by
chance.
random
chance.
As
shown
in
The
large
relative
value
o
f
t
Transformation
of
data
from
the
real
plane
to
the
log
log
plane
greatly
eases
the
regression
analysis
but
it
introduces
a
potentialIy
significant
bias
to
the
results.
One
characteristic
of
a
linear
regression
analysis
is
that
the
average
of
the
predicted
values
for
the
dependent
var
le
should
equal
the
average
val6e
from
the
actual
data.
Since
the
regression
was
performed
in
the
log
log
plane,
the
weighted
average
value
of
Ln(
S)
will
be
the
same
for
both
the
actual
data
However,
the
average
value
of
the
predicted
values
of
S
will
not
necessarily
be
equal
to
the
average
of
the
small
sample
bias
corrected
S
values.
For
the
current
da
sample
bias
corrected
S
values
is
364.93
while'the
sum
of
the
(
at
the
observed
values
of
concentration)
is
351.013.
Thus,
the
predicted
values
of
S
are
biased
low
40
,
and
a
correction
factor
must
be
applied.
For
the
Method
5
data,
the
log
transformation
correction
factor
is
364.93/
35
1
.
O
1
3
=
1.0397.
The
equation
describing
the
estimated
values
of
standard
deviation
versus
concentration
is
the
best
estimate
available,
based
on
available
multi
train
experimental
data,
but
there
is
uncertainty
associated
with
this
equation.
The
slope
of
the
regression
line
@)
and
the
value
of
the
leading
constant
(
k)
may
be
greater
or
smaller
than
predicted.
Statisrical
data
in
Table
8
can
be
used
to
quantify
uncertainty
in
the
regression
equation.
Specifically,
the
95%
confidence
intervals
on
the
regression
equation
will
be
caiculated.
The
95%
confidence
interval
on
the
slope
term
can
be
expressed
as
I
p95%
=
Ppredicted
5
t95%*[
SE(
coeff)
l
Eq.
3
where
Pg5%
represents
the
upper
and
lower
bounds
of
the
slope
coefficient,
t95%
is
the
critical
t,
I
statistic
ax
the
95%
confidence
level
and
the
appropriate
number
of
desrees
of
freedom,
and1
SE(
coeff)
is
the
standard
error
of
the
coefficient.
I
,
As
indicated
in
Table
8,
the
predicted
value
of
the
power
term
in
the
regression
equation
@)
is
1.3063
and
the
standard
error
of
that
coefficient
is
0.1477.
The
critical
t
statistic
for
42
degrees
of
freedom,
at
the
95%
confidence
level
is
2.020
(
available
from
standard
statistical
tables).
Thus,
the
best
estimate
for
the
slope
of
the
regression
line
is
the
predicted
value
(
1.3063)
but
with
95%
confidence
it
can
only
be
concluded
that
the
value
of
the
p
coefficient
is
between
1.008
and
1.605:
'
Implications
of
the
potential
range
of
this
slope
term
are
discussed
in
more
detail
later.
r.
The
weighted
least
squares
numerical
analysis
provided
information
necessary
to
determine
confidence
intervals
on
the
regression
equation.
Results
of
those
calculations
(
at
the
95%
confidence
level)
are
presented
in
Figure
7.
When
plotted
on
log
log
scale,
the
regression
equation
is
a
straight
line
and
the
confidence
intervals
appear
as
horn
shaped
curves
on
either
side
of
the
prediction.
AI1
three
lines
in
this
figure
have
been
adjusted
to
include
the
log
log
transformation
41
0
0
s2
E
e
E
rq
i
bias
correction
factor.
Superimposed
on
Figure
7
is
the
small
sample
bias
corrected
data
from
Table
7.
The
meaning
of
confidence
intervals
often
confuses
those
with
limited
background
in
statistical
analysis.
The
straight
line
through
the
data
represents
the
best
estimate
of
the
relationship
between
standard
deviation
G
and
mean
concentration,
p.
The
confidence
intervals
define
potential
bounds
for
the
regressi
the
straight
line.
Confidence
intervals
do
not
represent
boundaries
for
the
actual
data.
It
is
le
to
calculate
potential
bounds
for
data,
but
those
bounds
are
referred
to
as
tolerance
intervals.
Thus,
it
is
fully
anticipated
that
a
portion
of
the
experimental
data
(
individual
determinations
of
S)
will
fall
outside
the
confidence
intervals.
Before
proceeding
with
additional
assessment
of
the
Method
5
results,
it
is
necessary
to
examine
the
implications
of
the
regression
analysis.
The
regression
equation
itself
was
found
to
be
'
s
=
0.021
Eq.
4
If
both
sides
of
the
equation
are
divided
by
the
mean
concentration,
the
left
hand
term
becomes
S/
C,
which
is
the
r
tandard
deviation
(
RSD).
After
performing
this
operation,
the
regression
equation
becomes
RSD
=
0.02
1
lC0.306
~
100%.
Eq.
5
This
implies
that
the
RSD
increases
with
increasing
concentration,
which
is
a
difficult
result
to
rationalize.
Typical
random
errors
that
might
be
attributed
to
the
sample
collection
process,
such
as
failure
to
adequateIy
rinse
particulate
matter
from
the
probe
liner,
should
produce
errors
that
are
roughly
proportionaI
to
the
PM
loading.
Another,
often
observed
error
in
sample
collection
is
for
a
small
portion
of
the
filer
to
stick
to
the
filter
housing.
This
type
of
error
causes
an
underestimation
of
the
mass
of
particulate
collected
but
the
magnitude
of
the
error
will
not
be
a
function
of
concentration.
Random
error
in
the
weighing
process
should
also
be
relatively
independent
of
PM
concentration.
It
can
even
be
argued
that
the
relative
magnitude
of
analytical
error
might
decrease
with
increasing
concentration.
These
considerations
suggest
that
the
value
of
the
slope
term
(
for
any
43
Method)
should
be
expected
to
fall
between
ze
slope
of
the
regression
line
in
Figure
7
and
in
d
1.0.
More
significa
ons
4
and
5
is
too
high.
The
forzoing
statistical
analysis
is
obvio
characteristics
of
those
data.
Two
facto
large
value
for
the
Standard
Error
of
th
1.008
to
1.605.
This
lower
limit
on
the
anticipated
bounds
on
the
regression
equ
by
the
confidence
interval
of
the
statistic
A
separate
argument
has
been
forwarded,
suggesting
that
it
may
not
be
valid
to
group
the
various
Method
5
data
sets
into
a
single
analysis.
The
mathematical
procedures
of
regression
analysis
predict
a
high
value
for
the
slo
excessively
high
S
or
if
the
data
at
lower
concentrations
have
uncharacteristically
low
values
of
S.
In
the
outlier
analysis
presented
earlier,
the
available
data
were
divided
into
two
concentration
groups.
The
high
concentration
group
contained
quad
train
and
octet
data
with
all
tests
reporting
data
at
high
concentra
average
PM
concentration
above
94
rngldscm.
These
data
were
collected
in
the
early
to
mid
1970s.
The
low
concentration
data
included
six
quad
t
aired
train
runs
from
the
tests
at
Pittsfield.
The
Pittsfield
data
was
collected
in
the
mid
1990s.
The
regression
analysis
is
heavily
weighted
by
the
Dade
County
octet
data
that
is
also
high
concentration
data.
If
the
Dade
County
data
exhibited
uncharacteristically
high
standard
deviation,
the
slope
term
from
the
regression
analysis
would
be
uncharacteristically
high.
It
has
been
suggested
that
the
high
concentration
data
were
collected
shortly
after
Method
5
was
first
developed
and
that
the
field
testing
crews
were
still
learning
how
to
properly
apply
the
Method
was
collected
more
than
a
decade
later,
allowing
the
test
contrast,
the
Pittsfieid
data
sampling
procedures.
A
second
consideration
involves
the
stack
sampling
ti
exception
of
the
Rig0
and
Chandler
data
However,
for
the
tests
at
Pittsfield,
stack
gases
we
difference
in
sampfing
time
could
possibly
result
i
particulate
concentration.
the
data
include
in
Tabfe
5.
With
the
es
were
nominally
r
approximately
4
hours.
This
es
for
data
coIlected
at
lower
44
There
is
certainly
merit
to
an
argument
that
the
skill
level
of
sampling
teams
directly
impact
the
standard
deviation
of
measurement
results.
However,
there
is
no
direct
information
available
to
quantify
the
capability
of
testing
teams
or
to
provide
relative
weighting
of
data
quality.
Similarly,
it
is
reasonable
to
speculate
that
sampling
time
might
impact
measurement
precision
but
there
is
nothing
within
Method
5
that
precludes
extended
sample
collection
times.
For
these
reason,
the
analysis
of
the
Method
5
data
will
continue
based
on
the
entirety
of
the
available
data
but
with
a
strong
caution
that
slope
of
the
true
S
versus
C
relation
is
probably
very
close
to
1.0.
Not
withstanding
the
forgoing
comments,
the
regression
line
in
Figure
7
provides
the
best
estimate
available
for
the
standard
deviation
of
data
collected
using
Method
5.
As
discussed
in
Section
3,
this
estimate
of
standard
deviation
also
defines
the
anticipated
distribution
of
future
measurements
collected
with
that
method.
For
example,
based
on
currently
available
data,
it
is
anticipated
that
repeated
Method
5
measurements
of
a
stack
gas
containing
100
mg/
dscm
of
particulate
matter
would
exhibit
a
standard
deviation
of
8.639
mg/
dscm
or
8.64
%
RSD.
This
is
a
hypothetical
source,
where
the
stack
PM
concentration
is
not
varying
with
time.
Sixty
eight
percent
of
future
measurements
taken
on
this
stack
should
1
within
1.0
cr
(
28.639
mgldscm)
and
ninety
nine
percent
of
those
measurements
should
fall
w
n
the
range
of
2
2.57*
0.
Thus,
in
the
example
of
a
stack
with
a
PM
loading
of
100
mgldscm,
99
ut
of
100
Method
5
measurements
are
expected
to
fall
within
&
22.20
mg/
dscm
of
the
true
conce
ration.
For
the
average
of
triplicate
measurements,
99
out
of
100
measurements
would
fall
within
the
range
o
f
f
2.57*
0/.\/
3.
Thus,
the
average
of
triplicate
Method
5
measurements
from
this
hypbthetical
stack
is
ex2ected
to
fall
within
5
12.82
mg/
dscm
af
the
true
I
I
concentration.
,
Figure
8
presents
the
predicted
relative
standard
deviation
and
the
99%
bounds
for
future
single
measurements
as
a
function
of
stack
PM
concentration.
Data
in
this
figure
are
based
on
currently
available
data
and
do
not
include
the
effect
of
time
variation
in
source
characteristics.
The
X
axis
of
Figure
8
represents
the
true
concentration
of
PM
in
the
hypothetical
stack.
Values
indicated
on
the
Y
axis
represent
the
precision
of
Method
5
at
the
selected
values
of
sack
concentration.
The
99%
bounds
are
also
normalized
by
the
stack
concentration
and
represent
the
anticipated
range
of
individual
measurements.
Compliance
with
regulatory
limits
is
typically
based
on
the
average
of.
45
m
.
I
c
M
I
.
I
;
0
0
N
0
46
c
triplicate
measurements.
The
predicted
range
for
99
out
of
100
triplicate
measurements
is
also
included
in
Figure
8.
When
Method
5
is
applied
to
a
real
stack,
a
wider
range
of
experimental
results
can
be
anticipated
due
to
time
variations
in
source
characteristics.
Data
presented
in
Figure
8
should
not
be
extrapolated
beyond
the
indicated
limits.
Further,
based
on
physical
considerations,
it
is
anticipated
that
the
true
variation
of
these
precision
metrics
with
concentration
are
expected
to
be
a
flat
line
or
even
to
decrease
slightly
(
whereas
the
curves
increase)
with
increasing
concentration.
Data
in
Figure
8
were
generated
using
the
predicted
values
of
standard
deviation,
Recall,
however,
that
there
is
uncertainty
in
those
estimates.
It
is
know
with
95%
confidence
that
the
relationship
between
standard
deviation
and
concentration
falls
between
the
upper
and
lower
confidence
limits
illustrated
in
Figure
7.
If
the
actual
relationship
between
a
versus
C
for
Method
5
conforms
to
the
upper
Confidence
limits,
the
anticipated
range
of
future
Method
5
data
will
be
greater
than
suggested
by
the
data
in
Figure
8.
Conversely,
a
tighter
ranse
of
concentrations
are
anticipated
if
the
variation
in
standard
deviation
conforms
to
the
lower
confidence
limit.
Figure
9
illustrates
the
ranges
of
anticipated
concentrati
data
under
three
scenarios:
(
1)
when
standard
deviation
conforms
to
theL
upper
confidence
limit
)
when
Est.
CT
conforms
to
the
predicted
reIationship;
and
(
3)
when
Est.
CT
conforms
to
the
lower
confidence
limit.
The
X
axis
in
Figure
9
represents
the
true
concentration
of
PM
in
a
hypothetical
stack
that
does
not
vary
with
time.
The
Y
axis
represents
the
anticipated
range
of
measured
concentra
using
Method
5.
The
upper
and
lower
curves
in
the
figure
represent
the
upper
and
lower
bo
99
out
of
100
future
measurements,
assuming
that
the
standard
deviation1
equals
the
upper
95%
confidence
limit.
There
is
97.5%
confidence3
that
99
out
of
100
future
measurements
would
fall
below
the
upper
curve
and
97.5%
confidence
that
the
future
measurements
will
fall
above
the
lower
curve.
Similar
curves
are
provided
for
the
cases
where
Est.
Q
conforms
to
the
regression
curve
fit
and
where
Est.
cs
is
equal
to
the
lower
confidence
limit.
Based
on
the
above
anaIysis,
and
concerns
over
the
slope
of
the
regression
equation,
it
is
difficult
to
draw
firm
conclusion
about
the
actual
precision
of
Method
5.
However,
certain
trends
do
appear
obvious.
Within
the
confidence
bounds
of
the
analysis
and
based
on
the
available
data,
it
appears
that
Method
5
standard
deviation
varies
approximately
linearly
with
concentration
and
that
the
395%
confidence
implies
that
there
is
a
2.5%
chance
that
the
a
relationship
falls
above
the
upper
confidence
limit
and
a
2.5%
chance
that
the
relationship
falls
below
the
Iower
confidence
limit.
47
m
m
n
U
M
L
.
I
F1
i
l
C)
P
t
0
P
,
I
h,
relative
standard
deviation
for
the
method
is
approximately
constant.
For
PM
concentrations
3
\
between
15
and
217
mg/
dscm,
the
best
estimate
of
the
relative
standard
deviation
for
Method
5
is
4'
between
about
4.8%
to
12.2%.
(
49
4.2
Method
5i
Data
In
the
middle
1990s
the
US.
PA
began
develop
ate
measurement
method,
specifically
desizned
to
improve
measurement
precision
at
low
loadings.
The
method
itself
was
published
in
1999
as
part
of
the
new
MACT
regulation
verning
hazardous
waste
incinerators
(
62
FR
52828,
Sept.
30,
1999)
and
has
been
giv
designation
Method
5i.
The
hardware
configuration
for
Method
5i
is
illustrated
in
Figure
10.
Methods
5
and
5i
are
similar
in
many
respects,
but
there
are
two
important
hardware
differences
and
several
operational
differences.
The
primary
hardware
differences
are
in
the
filter
assembly
for
the
two
methods.
Method
5
uses
a
large
diameter
filter
that
must
be
carefully
removed
from
its
holder
as
part
of
the
sample
recovery
process.
Often
a
small
quantity
of
the
collected
particulate
can
be
lost
or
a
small
portion
of
the
filter
itself
can
adhere
to
the
holder
walls.
This
results
in
measurement
imprecision
that
can
potentially
become
critical
when
the
total
particulate
catch
is
small.
Method
5i
uses
a
much
smaller
diameter
filter
and
filter
holder.
The
recovery
and
analysis
procedures
call
for
the
filter
to
remain
in
its
holder
through
the
entire
weishing
process.
This
eliminates
certain
sources
of
random
error
but
it
creates
another
potential
problem.
Since
the
weight
of
the
glass
filter
holder
is
much
larger
than
the
weight
of
the
collected
particulate,
the
analysis
process
must
determine
a
small
weight
gain
in
a
relatively
large
mass.
Because
of
the
small
filter
diameter,
Method
5i
is
intended
for
use
only
under
situations
where
the
particulate
concentration
is
expected
to
be
below
50
mg/
dscm.
The
second
key
feature
implemented
with
Method
5i
is
the
reauirement
that
tests
be
conducted
using
dual
trains.
Moreover,
measurement
precision
requirements
are
defined
as
part
of
the
method.
~
I
Data
on
the
precision
of
Method
5i
comes
from
two
studies
directed
primarily
at
evaluation
of
particulate
matter
continuous
emission
monitors.
The
first
of
these
studies,
conducted
under
EPA
sponsorship,
was
executed
on
a
hazardous
waste
incinerator
owned
by
Dupont
and
located
in
WiImington,
Delaware
(
62
FR
67788).
The
second
study,
sponsored
by
an
industry
consortium,
was
conducted
at
a
hazardous
waste
incinerator
owned
by
the
Eli
Lilly
Company
(
Eli
Lilly,
1999).
Results
from
these
two
studies
provide
a
large
database
for
assessment
of
Method
5i
precision.
Note
that
there
are
numerous
experimental
programs
that
were
recently
completed
(
or
still
underway)
using
Method
5i
for
calibration
of
PM
continuous
emission
monitoring
systems.
Since
Method
5i
50
c
I
51
requires
use
of
dual
trains,
the
available
database
ssessment
of
this
method's
precision
is
expected
to
greatly
expand
over
time.
As
noted
above,
Method
5i
is
a
relatively
new
meas
issues
associated
with
execution
of
the
method
that
si
Both
the
PA
test
report
and
the
Eli
Liliy
associated
with
obtaining
acceptab
were
performed
but
have
not
been
used
by
either
g
program,
the
only
data
used
are
Tables
9a
and
9b
provide
a
sum
actual
data
pairs,
the
average
concentration
pair,
and
the
small
sample
bias
corrected
st
there
are
a
variety
of
subtle
ct
the
precision
significant
learning
curve
er
of
paired
train
tests
ysis.
For
the
ReMAP
the
original
study
authors.
ncluded
in
the
tables
are
the
ted
standard
deviation
for
each
Figures
1
la
and
1
1
b
present
deviation
data
versus
averag
corrected
standard
deviation.
Fig
11
b
presents
relative
standard
d
almost
50
mg/
dscm.
Also
note
the
general
char
concentration
range,
the
individual
estimates
of
Stan
discernable
trend
to
either
ethod
5i
standard
small
sample
bias
gjdscm
while
Figure
om
less
than
10
to
Over
the
entire
distributed
with
no
I
~
1
The
data
in
Tables
9a
and
9b
we
concentration
range
grouping
were
examined
atte
particulate
concentrations.
runs
53,64,66
and
71
fro
sts.
Examination
of
these
data
points
suggests
that
runs
64,
66,
and
71
from
the
Eli
Lilly
tests
are
only
marginally
ng
criteria.
Several
I
r
b
f
b:
above
the
SPC
screening
criteria.
anaiysis.
The
spreads
for
data
point
53
(
Eli
Lilly)
and
60
(
EPA
D
they
have
been
deleted
from
the
following
analysis.
Accordingly,
those
data
poin
re
retained
for
subsequent
were
sufficiently
large
th
il
I
'
L'
Table
9a.
Method
5i
Data
and
Standard
Deviation
Eli
LiUy
Data
53
4
TabIe
9a
(
Continued).
Method
5i
Data
and
Stan
54
\
RIM
Number
Avg
Conccnmtion
Standard
S
Bias
RSD
*
Bias
mddscm
Deliation
RSD
Concctcd
Conected
Train
A
Train
B
P
1'
9
0
=
8
m
9
0
v
8
m
8
N
8
8
1
k,
c
L
a
++
+
++
111
I
B
a
11
I
t
P
i
L
57
i
k
all
Method
5i
data
were
obtained
using
dual
trains,
no
weighting
of
the
data
is
required.
Results
from
the
regression
analysis
are
presented
in
Table
I
O
below.
Table
10.
Results
of
Regression
Analysis
for
Method
5i
Data
Residuals
T
I
1.32
The
regression
analysis
indicates
that
the
estimated
standard
deviation
varies
with
according
to
the
relationship
concentration
P
=
0.243
5
0.366
or
from
0.123
to
0.6094
4
The
predicted
value
ofp
(
0.243)
is
taken
directly
from
the
regression
analysis.
The
2
0.3659
term
is
the
product
of
the
t
statistic
for
1
14
degrees
of
freedom
(
1.980)
and
the
s
error
forp
(
0.1
848).
This
finding
is
consistent
with
the
earlier
observation
(
see
Figure
1
la)
that
the
standard
deviation
data
appears
to
be
broadiy
distributed
in
a
box
covering
the
full
range
of
concentration
and
standard
deviation
between
zero
and
about
6
mgfdscm.
It
is
mathematically
possible
to
construct
a
range
of
method
precision
metric
for
Method
5i
as
a
function
of
concentration
but
the
indicated
relations
would
have
little
statistical
significance.
In
such
situations,
the
analysis
approach
is
to
calculate
a
pooled
standard
deviation
for
the
data.
The
analysis
procedure
is
described
in
the
Appendix
but
essentially
involves
calculation
of
the
weighted
average
of
the
variance
for
the
available
data.
Variance
is
equal
to
the
square
of
the
standard
deviation
and
the
weighting
factor
for
each
data
point
is
the
number
of
degrees
of
freedom
for
the
data
point.
Since
all
available
Method
5i
data
are
from
paired
train
tests
(
DF=
I)
all
weighting
factors
are
1.0
and
thus
the
pooled
standard
deviation
is
simply
the
square
root
of
the
sum
of
the
squares
for
the
Si
values.
As
expIained
in
the
Appendix,
the
appropriate
values
of
Si
to
calculate
the
pooled
standard
deviation
are
taken
directly
from
the
raw
data
without
adjustment
for
small
sample
bias.
The
above
described
pooling
procedures
were
applied
to
the
data
in
Table
9a
and
b.
There
are
114
individual
data
pairs
and
the
sum
of
the
individual
variances
is
234.13.
Accordingly
the
pooled
variance
is
2.054
(
234.13/
114)
and
the
pooled
standard
deviation
is
1.433
mg/
dscm.
This
single
value
is
the
best
estimate
available
for
the
Estimated
o
for
Method
5.
Table
1
in
the
Appendices
provides
a
list
of
factors
to
calculate
the
confidence
intervaI
(
at
the
95%
confidence
level)
for
a
pooIed
value
of
Est.
cr.
Using
linear
interpolation,
the
values
of
P0.025
and
P0.975
are
0.883
and
1.155
respectively.
Accordingly,
the
upper
and
Iower
95%
confidence
intervals
on
Estimated
c
are
1.265
and
1.655
mg/
dscm
respectively.
The
confidence
intervals
are
afso
constant
values
not
a
function
of
concentration.
Figure
12
presents
a
scatter
plot
of
the
Method
Si
data
along
with
the
estimated
values
of
standard
deviation
and
the
confidence
intervals.
Since
Est.
cr
and
the
confidence
intervals
are
constants,
they
are
illustrated
as
straight
lines
in
Figure
12.
59
.
.
I
'
1
0
8
I
!
The
estimate
of
standard
deviation
provides
information
on
the
anticipated
range
of
future
measurements
using
Method
5i.
Figure
13
presents
three
precision.
metrics
for
Method
5i.
Included
are
the
relative
standard
deviation,
the
expected
bounds
for
99
out
of
100
future
individual
measurements
as
well
as
the
anticipated
bounds
for
the
average
of
triplicate
measurements.
These
precision
metrics
have
been
normalized
by
the
concentration.
Thus,
even
though
Est.
G
is
a
constant,
normalized
precision
metrics
are
strong
functions
of
concentration.
The
general
presentation
approach
adopted
for
the
current
report
is
to
present
a
figure
defining
the
anticipated
range
of
concentrations
for
99
out
of
100
future
measurements,
under
three
different
scenarios
for
an
assumed
variation
of
standard
deviation.
Such
a
figure
provides
little
information
under
conditions
where
the
standard
deviation
is
evaluated
to
be
essentially
a
constant.
It
is
much
cleaner
to
simply
state
the
anticipated
variation
in
future
measurements.
If
the
true
standard
deviation
is
essentiaily
equal
to
the
pooled
standard
deviation,
then
99
out
of
100
future
Method
Si
measurements
are
anticipated
to
faif
with
2
3.68
mg/
dscm
of
the
true
concentration.
This
assumes
that
there
is
no
bias
in
the
measurements
and
that
the
m
e
concentration
is
between
about
4
and
50
mg/
dscm.
If
the
m
e
standard
deviation
for
Method
5i
is
essentially
equal
to
the
lower
95%
confidence
interval,
then
99
out
of
100
future
measurements
are
anticipated
to
fall
with
k
3.25
mg/
dscrn
of
the
true
concentration.
If
the
true
standard
deviation
for
Method
5i
is
essentially
equal
to
the
upper
95%
confidence
interval,
then
99
out
of
100
future
measurements
are
anticipated
to
fall
with
t
4.25
mg/
dscm
of
the
true
concentration.
4.3
Discussion
of
Particulate
Matter
Measurement
Results
The
forgoing
discussion
provides
strikingly
different
conclusions
relative
to
the
precision
of
Methods
5
and
5i.
Specifically,
the
regression
analysis
indicates
that
the
standard
deviation
of
Method
5
is
a
strong
function
of
concentration.
In
fact,
it
is
suggested
that
a
reasonable
interpretation
of
the
data
is
that
Method
5
has
a
constant
relative
standard
deviation.
In
contrast,
61
c,
u
E
Q)
L
3
M
tz
0
0
v)
0
w
0
c1
0
62
!
LA
I
`
Ld
analysis
of
Method
5i
data
could
detect
no
relationship
between
standard
deviation
and
concentration
at
the
95%
confidence
level.
Prior
discussion
has
suggested
that
random
error
associated
with
the
sample
collection
process
tends
to
drive
the
power
function
term
@)
in
the
regression
equation
toward
1.0.
Similarly,
random
error
in
the
analytical
process
tends
to
drive
p
toward
zero.
These
are
only
anticipated
trends
but
they
do
suggest
that
different
types
of
random
error
have
driven
the
assessment
of
these
two
particulate
measurement
methods.
w
'
When
Method
5
is
applied
at
high
particulate
concentration,
it
is
reasonable
to
anticipate
that
the
fiIter
weighing
process
is
sufficiently
precise
that
it
contributes
negligibly
to
the
overall
precision
of
the
method.
A
large
portion
of
the
multi
train
Method
5
data
was
collected
from
high
concentration
stacks
(>
90
mgidscm).
Further,
the
high
concentration
data
were
collected
during
a
time
frame
when
many
sampling
teams
were
gaining
experience
with
application
of
the
method.
Thus,
results
from
the
statistical
analysis
of
Method
5
data
can
ea
y
be
rationalized.
1
:
/
B_
u
h
I
The
Method
5i
data
were
all
collected
under
low
particulate
concentration
conditions
(
GO
mg/
dscm
with
the
majority
of
the
data
at
much
lower
concentration).
Under
these
conditions,
it
is
anticipated
Ld
I
that
imprecision
of
the
weighing
process
may
.
contribute
significantly
to
the
overall
Method's
precision.
As
described
earlier,
collected
samples
must
be
dried
before
recording
the
final
particulate
weight
gain.
Collected
samples
are
placed
in
a
dessicator
and
repeatedly
weighed
untii
the
tare
weight
is
stabiIized.
The
sample
is
considered
to
have
reached
its
final
weight
if
the
repeated
weighing5
agree
within
k0.5
mg
or
21.0%
of
the
tare
weight,
whichever
is
greater.
For
a
typical
Method
5
or
5i
particulate
measurement,
a
sample
is
collected
from
the
stack
for
approximately
one
hour
during
which
time
approximately
1
cubic
meter
of
flue
gas
is
extracted.
Thus
the
process
of
determining
particulate
loading
on
the
filter
is
no
more
precise
than
the
concentration
measurement
is
no
more
precise
than
20.5
mg/
dscm.
That
c
measurement
imprecision
is
insignificant
when
the
stack
concentration
is
on
the
order
of
100
mg/
dscm.
However,
for
measurements
in
stacks
with
PM
concentrations
on
the
order
of
10
mg/
dscm,
this
represents
a
significant
relative
contribution
to
overall
measurement
precision.
5
Samples
must
remain
in
a
dessicator
for
a
minimum
of
6
hours
between
weighings.
i.
1
L
L
P
,
L
.
L
A
r
Based
on
the
above
considerations
it
is
reasonable
to
anticipate
that
the
analytical
portion
of
Method
5i
measurements
will
contribute
significantly
to
the
overall
precision
of
the
method
and
that
random
error
in
the
weighing
p
also
subject
to
random
method
precision
should
vary
with
concentratio
available
Method
5i
data
have
been
collected
measurement
teams
expended
significant
effo
data
from
numerous
tests
were
discarded
as
a
result
of
personnel
climbing
the
learning
curve.
Finally,
all
data
in
the
Method
5i
data
set
above
about
15%.
All
of
these
factors
c
the
sampling
process
has
a
small
contribution
to
s
will
not
vary
significantly
with
particulate
concentration.
Method
5i
is
associated
with
The
above
considerations
are
provided
as
one
possible
rationalization
for
the
observed
differences
in
the
precision
characteristics
of
the
two
methods.
the
characteristics
of
the
measurement
methods
and
the
c
used
to
assess
the
methods.
As
regards
Method
5,
it
appears
like
mpling
teams
collecting
data
in
the
low
and
high
concentration
ran
ed
to
assess
the
method.
od
5
standard
deviation
on
concentration
is
less
than
indicated
by
the
current
data
set.
Further
it
is
likely
that
As
regards
Method
ji,
recall
that
regression
analy
CT
is
a
function
of
particulate
concentrati
can
be
confirmed
at
the
95%
confiden
performed.
Consid
for
Methods
5
and
5,
it
is
likely
that
stan
with
increasing
stack
particulate
conc
ncludes
that
no
relationship
It
is
important
to
place
the
above
considerations
into
practical
perspective.
When
Method
Si
is
used
to
measure
PM
loading
in
low
particulat
data
suggests
that
99
O
u
t
of
100
future
true
concentration.
The
original
data
set
(
before
outlier
screening)
contained
1
16
pairs
of
dual
train
f
L
n
t
results.
Assuming
that
the
true
concentration
for
each
test
is
the
average
of
the
test
pair,
dividing
the
spread
in
each
pair
by
2
provides
a
crude
way
to
assess
this
prediction.
For
the
entire
data
set
(
Tables
10a
and
10b)
the
maximum
spread
between
any
data
pair
occurred
in
run
number
53
from
the
Eli
Lilly
data
set.
The
reported
concentrations
for
that
data
pair
were
30.3
and
37.7
with
an
average
concentration
of
34.0
mg/
dscm.
Thus,
for
I
I6
paired
measurements
(
232
applications
of
the
Method)
the
maximum
difference
between
the
measured
concentration
and
the
estimated
true
concentration
was
3.7
mg/
dscm.
Interestingly,
that
measurement
was
determined
to
be
an
outlier
and
was
eliminated
from
the
overall
analysis.
It
is
certainly
possible
(
even
likely)
that
the
precision
of
Method
5i
has
some
dependence
on
concentration.
However,
the
forgoing
analysis
suggests
that
the
constant
si,
oma
assumption
provides
a
reasonable
and
practical
estimate
of
the
Method's
precision.
It
is
unlikely
that
the
imprecision
of
Method
5
increases
as
rapidly
with
concentration
as
suggested
by
the
data
in
Figures
7,8
and
9.
It
is
expected
that
increased
experience
of
field
sampling
teams,
including
the
lessons
learned
from
application
of
Method
5,
have
already
reduced
the
range
of
random
errors
impacting
Method
5
results.
It
is
anticipated
that
the
inherent
precision
of
Method
5
should
be
similar
to
that
for
Method
5i
but
CJ
for
the
method
almost
certainly
does
increase
with
concentration.
Note
that
the
Method
5
data
from
the
Pittsfield
tests
were
collected
in
the
mid
1990s
and
should
reflect
increased
experience
for
the
testing
team.
Data
from
this
test
series
(
16
valid
data
pairs
)
were
examined
to
determine
the
range
of
the
data
pairs
relative
to
the
pair
average.
For
runs
15
and
17,
the
spread
minus
the
mean
were
4.4
and
6.8
mg/
dscm
respectively
while
the
spreads
for
the
remainder
of
the
data
were
less
than
3.5
mg/
dscm.
This
suggests
that
Method
5
might
provide
'
slightly
less
precise
results
than
Method
5i
but
not
dramatically
less.
Even
this
observation
must
be
tempered
by
the
fact
that
the
standard
deviation
for
the
method
increases
with
increasing
concentration.
Based
on
these
qualitative
considerations,
it
is
suggested
that
the
data
in
Figures
7,8,
and
9
should
be
taken
a5
an
upper
limit
on
the
imprecision
of
Method
5.
To
fully
assess
Method
5
precision
at
higher
concentrations
(>
1
OOmg/
dscm)
additional
multi
train
data
is
required
in
that
concentration
range.
65
This
page
Intentionally
Left
Blank
r
t
5.0
EPA
Method
23
For
Measuring
Dioxin
and
Furan
Emissions
The
EPA
method
for
measurement
of
dioxin
and
furan
stack
emissions
is
denoted
as
Method
23
(
56
FR
67788
and
40
CFR
Part
60
Appendix
A).
The
hardware
for
the
method
is
illustrated
in
Figure
14
and
has
several
similarities
to
the
hardware
discussed
previously
for
Method
5.
The
major
difference
is
addition
of
a
module
filled
with
an
absorbent
material
known
as
XAD.
A
small
circulating
pump
maintains
the
temperature
of
the
XAD
module
at
approximately
60"
F.
The
XAD
module
is
spiked
with
known
quantities
of
labeled
compounds
that
are
used
for
both
system
calibration
and
to
experimentally
determine
the
recovery
of
the
overall
sampling
and
analysis
.
process.
The
quantity
of
dioxin
and
furan
collected
and
analyzed
by
the
method
is
extremely
small.
Typical
stack
concentrations
are
on
the
order
of
a
few
ng/
dscm.
To
collect
sufficient
material
for
analysis
by
high
resolution
GC/
MS,
each
sampling
run
extends
for
at
least'
three
hours
and
may
last
for
more
than
6
hours.
There
are
eight
possible
homologues
of
both
polychIorinated
dibenzo(
p)
dioxin
and
dibenzofuran.
Only
those
homolo,
oues
with
four
to
eight
chlorine
atoms
are
adverse
health
effects.
Acco
ngly,
some
environmental
regulations
@
e.,
the
rules
ipal
waste
combustors)
limit
the
release
of
all
tetra
through
octa
chlorinated
dioxins
nt
for
the
fact
that
different
dioxin
and
furan
congeners
and
ikrans.
Other
regulations
take
ac
have
vastly
different
toxici
Most
of
the
world
has
adopted
a
listing
of
relative
conge
that
was
developed
under
the
auspices
of
NATO.
These
relative
toxicity
factors
are
m
the
concentration
of
each
congener
to
yield
an
emission
concentration
that
is
equiv
toxicity
that
would
occur
if
all
of
the
indicated
mass
was
found
as
the
most
toxi
2,3,7,8
tetrachloro
dibenzo@)
dioxin).
Emissions
expressed
in
this
manner
are
International
Toxic
Equivalent,
or
ITEQ.
Regardless
of
whether
an
emission
stan
as
total
mass
of
tetra
through:
octa
or
as
ITEQ,
the
sampling
and
analysis
proce
Method
23
is
the
same.
The
only
difference
is
that
the
ITEQ
process
provides
significant
weighting
factors
to
a
select
group
of
individual
congeners.
As
will
be
shown
in
material
that
follows,
application
of
these
weighting
factors
does
impact
the
indicated
precision
of
the
measurement
method.
67
5.1
Available
Mufti
Train
Data
for
Method
23
as
Total
PCDDPCDF
Extensive
effort
has
been
expended
in
development
of
sampling
and
analytical
methodology
for
determination
of
dioxin
and
furan
emission
concentrations.
Separate
procedures
have
evolved
in
Europe,
Canada
and
the
US
which
are
similar
in
many
respects.
There
are
however,
small
differences
in
the
analytical
procedures
that
may
have
significant
impact
on
the
precision
of
measurement
results.
Accordingly,
the
current
study
focuses
onIy
on
US
EPA
Method
23
since
that
is
the
method
which
must
be
used
to
determine
compliance
with
US
emission
standards.
Before
presenting
the
available
multi
train
data
for
Method
23,
it
is
important
to
note
that
the
procedures
used
by
EPA
to
validate
Method
23
are
different
from
those
used
to
validate
other
methods.
Specifically,
in
lieu
of
gathering
multi
train
data
from
one
or
more
source
categories,
the
Agency
I
developed
hardware
and
a
procedure
for
dynamically
spiking
a
sampling
train
with
known
quantities
of
isotopically
la
eled
dioxin
and
furan
congeners.
Validation
of
the
method
focused
on
experiments
determining
the
fractional
recovery
of
the
dynamically
spiked
compounds.
There
are
a
variety
of
approaches
that
may
be
used
to
validate
performance
of
a
method.
Dynamically
spiking
a
sampling
train
with
a
known
quantity
of
a
tracer
compound
is
a
potentially
valid
approach.
In
fact
many
of
the
EPA
method
validation
efforts
have
used
dynamic
spiking
in
quad
train
tests
to
gain
information
on
both
precision
and
bias
of
an
emerging
method.
However,
use
of
dynamic
spiking
experiments
as
the
sole
approach
for
method
validation
is
valid
only
under
conditions
where
there
is
no
possibility
for
formation
of
the
pollutant
of
interest
in
the
sampling
train
itself
(
e.
g.,
for
methods
measuring
the
total
emission
of
an
element
such
as
a
heavy
metal).
As
regards
dioxin
and
furan
measurement,
there
is
a
significant
potential
for
formation
of
these
compounds
under
thermal
conditions
that
may
occur
within
a
sampling
probe
or
within
the
hot
filter
box
of
the
Method.
The
potential
for
formation
of
the
target
analytes
within
the
sampling
train
raises
serious
concern
about
the
completeness
of
EPA
studies
validating
Method
23.
The
report
describing
the
Method
23
validation
effort
indicates
that
a
quad
train
was
dynamically
spiked
with
isotopicaily
labeled
dioxin
and
furan
congeners
(
MRI,
1991).
The
report
indicates
that
the
collected
samples
were
analyzed
for
both
the
native
congeners
as
well
as
the
dynamically
spiked
congeners.
In
fact,
the
report
includes
tables
listing
the
collected
mass
of
native
dioxin
and
furan
in
69
5.2
Analysis
of
Method
23
Data
for
Total
Dioxin
and
Furan.
I
r
k'
Table
1
1.
Method
23
Data
as
Total
Mass
of
Tetra
through
Octa
Dioxi
t
L
71
vi
rl
c)
L
W
a
tk
.
I
f
u
d
111
73
.
The
SPS
data
outlier
procedures
were
applied
to
the
data
in
Table
11.
Several
different
range
groupings
were
evaluated
and
each
grouping
identified
Run
number
7
from
the
Rigo,
and
Chandler
tests
as
an
outlier.
The
basis
for
this
identification
is
easily
seen
in
Figure
15.
However,
when
presented
as
relative
standard
deviatio
remainder
of
the
data.
The
SPC
outlie
data
appears
to
be
abnormally
large.
,
In
decision
was
made
to
retain
the
data
for
the
n
number
7
is
only
slightly
identify
data
points
where
the
span
of
data
point
has
been
examined
and
a
Data
from
Table
1
I
were
submitted
to
regression
analysis
to
de
weighting
were
required
since
all
available
results
are
from
indicate
that
the
estimated
standard
deviation
varies
as
a
concentration
according
to
the
equation
S
(
for
Method
23
as
total
PCDD/
PCDF)
=
0.2722
*
Co.
56.
p
=
0.56
k
0.48
orp
lies
between
0.08
and
1.04.
Figure
17
presents
the
regression
results
including
the
small
sample
bias
corrected
data,
the
regression
line
and
the
upper
and
lower
95%
confiden
precision
metrics
for
Method
23.
Data
between
Est.
Q
and
C.
If
that
relation
is
ng/
dscm
(
excluding
temporal
variation),
99
out
of
should
fall
within
f
30%
of
the
true
concentration.
Source
variation
will
increase
those
bounds.
ents
using
Method
23
r
w
k
E
L
J
i
0
s
c
0
0
75
E
L,
r
a
L:
76
It
is
critical
to
recall
that
there
is
considerable
uncertainty
in
the
value
of
the
slope
term
in
the
regression
equation.
Figure
19
illustrates
the
anticipated
bounds
on
99
out
of
100
individual
measurements
for
three
different
scenarios
on
the
S
versus
C
relationship.
I
f
the
regression
relation
is
the
proper
description
of
how
standard
deviation
varies
with
concentration,
the
anticipated
spread
of
future
data
is
relatively
tight.
For
example,
in
that
situation,
samplins
a
stack
that
actually
contains
20
ng/
dscm
of
total
dioxin
plus
furan
should
result
in
99
out
of
100
measurements
falling
in
the
range
of
16.3
to
23.7
ng/
dscm.
Conversely,
if
the
standard
deviation
of
the
method
is
more
closely
described
by
the
upper
confidence
interval,
a
much
broader
range
of
data
can
be
anticipated.
In
this
case,
sampling
the
etical
stack
containing
20
ngldscm
dioxin
and
furan
using
Method
23
should
yield
99
out
of
1
surements
falling
in
the
range
of
9.13
to
30.87
ng/
dscm.
LL*
*
F
a
&
h
Y
L
r
P*
L
F""
b
t
I
Table
12
presents
a
tabular
summary
of
the
anticipated
range
of
measured
PCDDPCDF
concentration.
This
table
i
ased
on
the
assumption
that
the
regression
equation
properly
describes
the
variation
of
standard
deviation
with
concentration
for
the
best
estimate
of
standard
deviation.
This
is
the
best
estimate
available
for
method
precision
based
on
the
available
data.
It
is
critically
t
4
1
YLU"
important
to
reiterate
that
concentration
information
presented
in
this
table
(
as,
well
as
the
concentration
data
in
all
the
tables
and
figure
in
this
report)
are
not
corrected
to
constant
excess
air
level.
An
exam
s
in
order.
Assume
that
a
facility
operates
at
11%
0
2
in
the
stack
and
must
comply
with
a
Adjusting
the
emission
standard
from
7
0
2
shows
that
the
facility
must
maintain
PCDDRCDF
stack
concentration
below
24.9
ng/
dscm.
If
the
true
stack
concentration
was
exactly
24.9
ng/
dscm,
imprecision
from
repeated
application
of
Method
2
ouid
produce
99
out
of
100
measurement
results
ranging
from
20.7
to
29.2
ng/
dscm.
When
co
d
back
to
the
basis
of
the
standard,
the
anticipated
data
range
is
*
from
29.1
to
40.9
ng/
dscm
@
7%
02.
At
the
95%
confidence
level
for
this
hypothetical
facili
single
measurement
below
20.7ng/
dscm
is
below
the
standard
while
a
measurement
above
29.2
ngldscm
is
above
the
standard.
At
the
95%
confidence
level,
resuIts
between
20.7
and
29.2
could
be
E
PCDF
emission
limit
of
35
ng/
dscm
I@
7%
02.
I
&
LA
P
m
E
L
i
L
I
either
in
or
out
of
actual
compliance.
CY
c""
The
above
analysis
clearly
points
to
the
fact
that
there
is
an
insufficient
body
of
data
available
to
adequately
assess
the
precision
of
EPA
Method
23.
The
limited
quantity
of
available
data
suggests
that
the
precision
of
Method
23
conforms
to
the
predictions
presented
in
Table
12.
However,
there
is
t
'
Table
12.
Concentration
ng/
dscm
&
Anticipated
Range
of
Measured
PCDDRCDF
Concentration
Based
on
Best
Estimate
of
Method
23
Standard
Deviation
Measurements
Measurements
Lower
Limit
lupper
Limit
Lower
Limit1
Upper
Limj
I
I
0.5
0.97
0.03
0.77
0.23
2.0
4.0
6.0
8.0
0.97
2.60
I
1.40
3.03
5.52
2.4%
4.88
3.12
7.91
4.09
7.10
4.90
10.2
5.76
9.29
6.71
I
12.5
10.0
12.0
7.46
11.5
8.53
14.8
9.19
17.1
10.9
14.0
16.0
79
13.6
10.4
15.8
12.2
19.3
12.7
17.9
I
14.1
21.5
1
14.5
18.0
20.0
22.0
23.7
16.3
25.9
18.1
20.0
16.0
22.2
17.8
24.3
19.7
28.1
19.9
26.4
24.0
21.6
30.3
26.0
21.7
28.5
23.5
32.5
23.5
28.0
30.6
25.4
significant
uncertainty
associated
with
this
analysis.
if
the
actual
method
precision
conforms
to
the
upper
confidence
interval
in
the
analysis,
a
can
only
be
resolved
by
g
particular
importance
wo
included
in
the
current
data
set.
can
be
anticipated.
The
issue
of
concentrations.
Of
ions
above
the
levels
80
5.3
Available
Multi
Train
Data
for
Method
23
as
ITEQ.
Data
for
Method
23,
with
results
expressed
as
ITEQ,
are
the
same
as
those
for
Method
23
with
results
expressed
as
total
m
a
s
of
tetra
through
octa
dioxin
plus
furan.
Table
13
presents
the
ITEQ
results
including
the
results
of
each
run,
the
average
concentration
and
the
calcuiated
standard
deviation
from
the
run.
Also
included
are
data
following
application
of
the
srnall
sample,
bias
correction
factor.
These
data
are
illustrated
in
Figures
20
and
21
as
scatter
plots
of
standard
deviation
and
relative
standard
deviation
versus
the
average
concentration
calculated
fiom
the
data
pair.
The
results
are
generally
similar
to
those
for
the
Method
as
total
PCDDPCDE
except
that
the
scales
are
greatly
reduced.
The
range
of
the
concentration
data
is
i
The
above
Method
23
data
were
submitted
to
regression
analysis
and
results
indicate
that
S
is
related
to
C
according
to
the
equation,
S
=
0.4795C0.345.
Unfortunately
the
t
statistic
on
the
power
term
is
only
1.02
which
is
well
below
the
critical
value
lies
that
the
regression
equation
could
have
occurred
by
chance
and
that,
at
e
level,
no
statistically
meaningful
relationship
between
S
and
C
was
detected.
result
is
easily
observable
in
the
data
presented
in
Figure
20.
Note
that
the
appear
as
a
scattering
of
points
at
concentrations
below
0.4
ng
ITEQ/
dscm
onlbelow
0.04
ng
ITEQ/
dscm.
There
are
four
data
points
with
standard
054
dg
ITEQ/
dscm.
These
data
might
suggest
that
S
increases
with
increasing
t
e
f
UT
points
are
discounted,
one
can
easily
envision
an
opposite
slope
to
a
rkgression
,
analysis
allows
the
potential
range
of
the
power
term
to
be
/
confidence
level,
thep
parameter
could
be
as
large
as
1.051
and
as
small
as
0.36.
The
magnidde
of
the
'
uncertainty
concerning
the
precision
of
Method
23
for
dioxin
and
furan
as
ITEQ
is
further
ilhstrated
in
Figure
22.
This
figure
shows
the
small
sample
bias
corrected
data,
the
regression
equation
and
the
upper
and
lower
confidence
intervals.
It
is
I
,
?
%
I
u
s
0
f
r4
1
00
k
.
I
+
+
r
co
m
w
m
cv
8
8
8
8
8
8
83
0
I
.
I
d
0
0
9
0
0
0
2
8
I
85
Method.
Since
the
above
analysis
failed
to
determine
a
relationship
between
CT
and
C,
the
alternative
approach
is
to
reevaluate
the
data
assuming
that
CT
is
a
constant.
The
pooled
analysis
procedure
is
to
first
determine
the
pooled
variance.
The
22
individual
values
of
S
from
Table
13
are
squared,
summed,
and
then
divided
by
22
to
determine
the
pooled
variance.
The
pooled
variance
=
0.000712.
The
square
root
of
this
paramet
s
taken
to
determine
the
pooled
standard
deviation;
pooled
S
=
0.0267
with
22
degrees
o
provide
factors
for
determining
the
95%
confidence
bounds
on
0.
Those
bounds
are
0.0207
and
I
0.0374.
Figure
23
presents
the
pooled
standard
deviation
and
the
95%
confidence
intervals
overlaid
with
the
experimental
data.
Since
the
estimated
standard
deviation
and
the
confidence
intervals
are
constants,
they
are
illustrated
as
straight
lines
in
the
Figure.
The
various
precision
metrics
are
presented
in
Figure
24.
e
are
normalized
by
the
average
concentration
and
thus
show
The
data
shown
in
this
inverse
relationship
If
the
characteristic
standard
deviation
of
Method
deviation,
then
measurement
imprecision
should
cause
99
out
of
100
future
measurements
I
to
deviate
f?
om
the
true
concentration
no
more
than
20.068
ng
ITEQ/
dscm.
If
the
Method's
characteristic
standard
deviation
is
more
appropriately
approximated
by
the
upper
95%
confidence
bound,
then
method
imprecision
should
cause
99
out
of
10
deviate
from
the
true
concentration
by
no
more
than
59.095
ng
ITEQIdscm.
It
is
critically
important
that
the
above
estimates
for
Method
23
imprecision
be
placed
in
perspective.
Recent
EPA
regulations
governing
hazardous
waste
co
stion
SY
stems
and
fossil
fbeI
fired
cement
plants
have
set
dioxin
and
furan
emission
limits
of
0.2
ng
ITEQ/
dscm
@
7%
\
86
Y
L,
0
0
0
87
cu
a2
m
I
I
.
.
,
*
I
.
.
I
.
88
c1
I
L
0,
The
potential
range
for
future
measurements
fkom
measurement
imprecision
is
large
relative
to
the
standard.
At
the
upper
95
%
confidence
limit,
the
possible
range
of
a
single
measurement
(
minus
0.095
to
plus
0.095
=
0.19)
is
essentially
equal
the
standard
itself
EIC
i"""
i
kd
i
i
f
This
Page
Intentionally
Left
Blank
90
r
i
6.0
EPA
Me
od
26
for
Hydrochloric
Acid
The
method
for
measurement
of
hydrochloric
acid
and
chlorine
gas
is
designated
EPA
Method
26
and
is
fully
described
in
4OCFR
Part
60
Appendix
A
under
the
heading
for
the
Method.
The
hardware
arrangement
for
Method
26
is
illustrated
in
Figure
25.
Impingers
in
the
back
half
of
the
train
are
filled
with
sulfuric
acid
to
collect
HCl
while
the
sodium
hydroxide
impingers
collect
chlorine
gas.
ata
for
Method
26
are
available
from
three
sources,
summarized
in
Table
14.
As
indicated
in
the
table,
relatively
high
HCl
concentration
data
(
about
80
to
220
mgdscm)
are
provided
by
the
tests
of
Rig0
and
Chandler
at
an
MWC
facility
in
Pittsfield,
MA
Chandler,
1997).
These
data
were
collected
using
a
quad
train.
Entropy
Corp
collec
CI
concentration
(
4
to
74
mg/
dscm),
as
part
of
the
EPNOAQPS
effort
and
Margeson,
1989).
Two
ofthe
EPA/
OAQPS
tests
(
run
Method
26
(
Steinberg
and
12)
were
perfo
midget
impingers
in
what
is
now
considered
the
standard
Method
26
procedure.
The
other
trains
used
fidl
size
impingers
typically
associated
with
Method
5
trains.
A
significant
bias
detected
in
the
results
from
run
number
12
and
those
results
are
not
included
in
the
ReMAP
analysis.
The
remainder
of
the
EPNOAQPS
test
was
conducted
using
dual
trains
with
midget
impingers.
Finally,
very
low
HC1
concentration
data
(
0.3
to
2.0
mg/
dscm
HCI)
were
collected
by
EER
as
part
of
an
effort
for
EPNOSW
(
EER,
1997).
These
EPNOSW
tests
were
executed
using
quad
trains.
Data
outlier
analysis
was
performed
on
these
data
and
alI
data
points
passed
the
outlier
criteria
set
by
the
SPC
procedures.
Figures
26
and
27
provide
scatter
plots
of
the
available
HCI
data
illustrating
the
standard
deviation
as
a
fimction
of
average
HC1
concentration.
Figure
26
presents
all
of
the
available
data
while
Figure
27
includes
only
data
from
the
EPNOAQPS
and
EPNOSW
tests
(
low
HCl
concentration
data).
Figure
28
presents
these
data
as
relative
standard
deviation.
Data
presented
in
all
three
of
these
figures
have
been
corrected
for
smali
sample
bias.
As
shown,
when
the
91
L
P
I
T
(""
LA.%
Table
14.
Method
26
Multi
Train
Data
and
Standard
Deviation
for
HCI
Fq
L
E
l
i3
=
E
I
a
M
Lrc
.
I
Q
w
n
t;
(
v
95
0
(
0
0
w
0
m
0
w
0
F
0
.
,
_
I.._..
.._
..
..
,_,
"...
average
HCI
concentration
is
above
about
10
mg/
dscm,
relative
standard
deviation
(
RSD)
for
the
various
runs
is
consistently
below
10%.
Below
IO
mg/
dscm,
the
RSD
data
tend
to
increase
sharply.
Figures
26
and
27
show
that
the
sharp
increase
in
RSD
is
caused
by
the
rapidly
decreasing
value
of
the
Concentration
rather
than
a
sharp
increase
in
standard
deviation.
f
After
applying
appropriate
weighting
factors,
the
data
in
Table
14
were
submitted
to
a
weighted
regression
analysis
and
results
indicate
that
the
estimated
standard
deviation
for
the
Method
varies
with
HC1
concentration
according
to
the
relation:
S
(
Method
26
for
HCI)
=
0.15259
*
C0.803.
This
equation
includes
both
the
small
sample
bias
correction
and
the
bias
correction
associated
with
the
log
log
transfornation.
The
concentration
term
in
this
equation
is
in
units
of
mg/
dscm.
The
t
statistic
for
the
regression
is
17.22,
which
is
well
above
the
critical
t
statistic
for
95%
confidence
and
29
degrees
of
freedom
(
2.042).
At
the
95%
confidence
level,
the
value
of
the
power
coefficient
is
P
=
0.803
k
0.095
or
between
the
limits
of
0.707
and
0.898.
Figure
29
presents
a
plot
of
the
data,
along
with
the
regression
line
and
the
upper
and
lower
confidence
limits.
Note
that
the
confidence
inte
Is
do
not
deviate
sigificantIy
from
the
regression
line.
Using
the
regression
equation
to
describe
the
variation
of
Est.
G
with
concentration,
estimates
can
be
developed
for
the
probable
variation
in
measurements
associated
with
imprecision
in
the
Method
itself
Figure
30
presents
resuIts
of
those
calculations
including
the
variation
in
relative
standard
deviation,
the
estimated
spread
for
99
out
of
100
single
measurements,
and
the
estimated
spread
for
99
out
of
100
triplicate
measurements.
The
anticipated
spread
for
measurements
is
projected
to
be
relatively
close
to
the
true
stack
concentration.
For
example,
if
Method
26
is
applied
to
a
stack
containing
40
mg/
dscm
HCl,
results
from
99
out
of
100
triplicate
measurements
are
expected
fall
within
10.9
'
YO
of
the
true
concentration.
At
Iower
concentrations,
the
range
of
future
measurements
is
predicted
to
97
*
4
0
0
0
4
0
0
0
H
98
t
4
E
w
v1
0
.
I
L
Y
S
0
m
0
Q)
..
.
I
L
s
0
0
*
m
s
99
0
VI
(
u
0
0
(
u
0
VI
I
ul
I
0
G
ti
0
~
~~
i~~
~
~
~~
~~~
~
increase
(
as
a
percentage
of
the
true
concentration)
conditions,
the
actual
spread
in
data
&
om
method
imprecision
is
predicted
to
be
relatively
small.
For
example,
99
out
of
100
triplicate
measurements
in
a
stack
containing
1.0
mgldscm
HCI
are
expected
to
fa11
within
the
bounds
of
0.80
and
1.20
mgldscm.
The
data
in
Figure
30
assumed
that
the
standard
deviation
for
Method
26
varied
according
to
the
regression
equation.
Figure
29
presented
the
95%
confidence
bounds
for
the
regression
equation.
Those
data
have
been
used
to
estimate
the
anticipated
range
for
99
out
of
100
future
measurements
assuming
confidence
interval,
the
Results
for
those
calcul
The
best
estimate
of
the
precision
of
Method
26
is
provided
by
the
data
were
presented
graphically
in
Fi
these
data
in
tabular
form.
!
The
first
corrected
for
excess
oxygen).
The
second
out
of
100
future
single
measurements
(
at
the
fifth
columns
provide
the
i
IO1
I
i
I
i
I
I
I
1
i
1
E
Table
15.
Range
of
Anticipated
Future
HC
102
PY
E
l
b
r
i
L
,
I
I
i?
t
i
s
,
.
.
.
7.0
EPA
Methods
29,
lOla
and
lOlb
for
Mercury
Considerable
effort
has
been
expended
developing
methods
for
determination
of
mercury
emissions
from
combustion
sources.
For
details
on
the
Methods,
refer
to
40
CFR
Part
60
Appendix
A
under
the
headings
Method
29
and
Method
101.
Mercury
is
emitted
from
combustion
sources
as
either
the
base
metal
or
in
the
+
2
vaience
state.
It
may
be
in
the
vapor
state
or
it
may
be
associated
with
solid
phase
material.
At
least
three
EPA
Methods
have
been
published
or
proposed
and
one
additional
method
is
under
active
development.
Figure
32
illustrates
the
hardware
used
for
Method
101%
which
is
the
simplest
of
the
mercury
procedures.
The
sample
gas
is
passed
through
a
heated
filter
and
then
goes
to
impingers
filed
with
a
KMn04
10?
40H,
S0,
(
permanganate)
solution.
After
the
sampling
event
the
filter
and
permanganate
solutions
are
digested
and
a
single
combined
measurement
of
total
mercury
concentration
is
generated.
Method
29
was
developed
as
a
multi
metal
measurement
method,
including
mercury.
The
hardware
configuration
for
Method
29,
illustrated
in
Figure
33,
includes
a
pair
of
nitric
acid
impingers
foHowed
by
permanganate
irnpingers.
The
various
fractions
are
analyzed
separately
for
a
wide
range
of
metals
and
results
summed
to
develop
a
reported
stack
concentration.
Finally,
Method
10
1
b,
iIlustrated
in
Figure
34
is
a
simple
variant
on
Method
29.
Method
10
1
b
replaces
one
of
the
nitric
acid
impingers
in
Method
29
with
two
water
impingers.
The
various
fractions
are
analyzed
separately
in
an
attempt
to
determine
the
split
between
Wgo
and
Hg'
2.
The
total
mercury
concentration
is
determined
by
adding
the
catch
fiom
the
various
fiactions.
An
extensive
array
of
mdti
train
data
is
available
describing
the
precision
of
these
three
mercury
measurement
methods.
The
first
set
of
results
was
developed
by
EPNOAQPS
as
part
of
the
validation
of
Method
29
(
Radian,
1992).
Those
tests,
conducted
by
Radian
C
o
p
,
were
performed
at
a
municipal
waste
combustor
operated
by
American
Ref
Fuel
in
New
Jersey.
That
data
set
includes
8
quad
train
runs
with
stack
mercury
concentration
ranging
from
130
to
575
pg/
dscm.
The
next
set
of
data
comes
from
the
EPA
efforts
to
validate
Method
IOlb
(
EER,
1997).
Extensive
testing
was
conducted
at
a
hazardous
waste
burning
cement
kiln.
Testing
consisted
of
triplicate
train
runs
using
both
Methods
101
b
and
Method
29
(
test
series
1)
and
quad
_
l
"
103
Pi
m
m
r
,
pan
1
'
I
1
L
k
.
I
.....
..,.,
,
2
"
CI
+
Q=
a
P
I
4.
.
..
.
.".
I._
.
_
.
...
I
..
.
I
i,
I
106
c
c
train
runs
using
only
Method
101
b
(
test
series
2.).
The
tripiicate
train
tests
consisted
of
a
Method
1Olb
train
located
in
the
breaching
to
the
stack
(
downstream
of
all
air
pollution
controls)
as
well
as
Methods
10
1
b
and
29
trains
located
at
the
same
plane
of
the
stack.
These
three
measurements
all
treated
as
simultaneous
but
it
is
distinctly
possible
that
the
diverse
locations
could
contribute
to
an
increased
apparent
method
imprecision
for
this
data
set.
For
the
quad
train
tests
two
of
the
lines
were
dynamically
spiked
with
Hgo
and
HgC12.
For
the
ReMAP
analysis,
only
the
unspiked
data
fiom
the
quad
trains
have
been
used.
A
third
set
of
multi
train
data
was
provided
by
the
Rig0
and
Chandler
tests
on
the
MWC
facility
in
Pittsfield,
MA.
These
tests
provide
dual
train
measurements
using
EPA
Method
29.
A
fourth
set
of
multi
train
data
is
provided
in
EPA
tests
at
the
Stanislaus
County
MWC
(
Radian,
1992).
In
those
tests,
two
Method
29
measurements
were
made
simultaneously
in
the
stack.
From
these
tests,
the
only
dual
train
metal
data
available
from
the
EPA
were
for
mercury.
A
fifth
set
of
data
is
provided
by
tests
performed
at
EPA's
research
facilities
in
RTP,
NC
(
EPA,
1998).
There
are
several
key
features
to
the
data
fiom
these
tests
that
should
be
pointed
out
as
part
of
the
R
e
m
data
analysis.
First,
numerous
Method
29
tests
were
conducted
as
part
of
an
effort
to
assess
performance
of
multi
metal
continuous
emission
monitors.
The
EPA
combustion
facility
at
RTP
is
a
pilot
scale
rotary
kiln
incinerator
with
a
full
RCRA
permit.
As
part
of
the
CEMS
assessment,
the
metal
content
of
the
waste
feed
was
varied
to
adjust
the
range
of
metal
concentration
in
the
stack.
The
physical
arrangement
of
the
stack
causes
the
flow
to
travel
from
a
mezzanine
level,
down
m
e
floor,
and
then
horizontally
to
a
final
clean
up
baghouse.
A
series
of
multi
metals
CEMS
were
installed
in
the
vertical
portion
of
this
duct.
Method
29
trains
were
located
in
the
horizontal
duct
runs
at
the
meuanine
level
(
before
the
CEMS)
and
at
the
floor
Because
of
the
wide
concentration
range
of
these
paired
data,
these
results
are
extremely
important
to
the
overall
ReMAP
effort.
A
carefui
assessment
of
the
data
indicates
that
there
is
a
distinct
bias
in
the
results.
That
bi
only
detectable
because
of
the
large
number
of
metals
being
measured.
[
Material
presen
the
Appendix
discusses
the
data
trends
in
some
detail.]
The
essence
of
imprecision
is
that
simultaneous
measurements
of
the
same
stack
gas
yield
different
anual
method
data
were
collected
simultaneously.
107
measurement
results.
What
is
unusual
about
the
EPA
pilot
scale
tests
is
that
the
reported
concentrations
for
all
of
the
metals
tend
to
move
in
concert.
If
the
mezzanine
trai
higher
concentration
for
one
metal
(
relative
t
1
sampling
train),
it
will
also
indicate
a
higher
concentration
for
the
other
metals
as
SME
ReMAP
team
conducted
a
thorough
assessment
to
determine
the
se
of
this
bias.
Unfortunately
no
firm
conclusions
were
forth
co
e
problem
can
be
traced
to
the
sample
collection
process
or
the
h
pIe
as
opposed
to
the
laboratory
analytical
procedures.
Other
re
also
investigated.
Though
there
is
a
distinct
bias,
the
data
from
these
tests
have
been
used
as
provided
by
the
EPA
researchers.
The
effect
may
be
to
slightly
increase
indicated
standard
deviation
of
individual
method
29
data
points,
but
the
wide
range
of
d
atly
improves
the
overall
quality
of
the
method
precision
estimates.
Tables
16a
and
16b
provide
a
summary
of
all
the
merc
step
in
the
analysis
is
to
perform
an
outlier
analysis
outlined
previously.
The
data
were
grouped
into
sets
wi
lOOpg/
dscm.
The
analysis
identified
four
data
points
as
having
abnormally
large
spans.
Those
runs
included
Run
Number
9
from
the
EPA/
and
Runs
5
2,8
3
and
9
1
from
the
Stanislaus
County
tests.
The
span
clearly
out
of
line
with
the
remainder
o
data
with
concentrations
below
100
pg/
suspect
Runs
6
3,
8
1,
and
9
2
as
pote
program
and
generally
accepted
statistical
analysis
procedure
all
data
udess
there
is
a
clear
rationale
for
data
elimination.
Accordingly,
only
the
four
measurements
identified
as
having
abnormally
large
data
spans
have
been
eliminated
f?
om
further
analysis.
Figures
35
and
36
present
the
data
from
Tables
16a
and
16b
showing
s
plots
of
mndarcl
deviation
and
relative
standard
deviation
as
a
function
ng.
It
seems
appare
*
sion
data
noted
above.
The
first
that
test
series
as
well
as
with
values
of
RSD
there
is
also
reason
to
Table
16a.
Methods
29
and
101
Data
for
Mercury
109
c
0
0
c\
0
3
0
0
r
0
0
W
0
0
rn
0
0
3
0
0
cc)
0
0
N
0
0,
0
I12
I
=:
3
n
.
.
L
e
w
E
I
0
0
0
P
confidence
intervals
as
well
as
the
small
sample
bias
corrected
data.
The
t
statistic
for
the
regression
is
7.45,
which
is
well
above
the
critical
value
for
67
degrees
of
freedom
and
95%
confidence.
After
applying
a
bias
correction
factor
for
the
log
log
transformation
the
regression
relation
is
found
to
be:
S
(
Hg
total,
Methods
29
and
101)
=
0.208
*
Co.
877.
The
vaIue
of
the
power
coefficient,
at
th
fidence
level
is:
P
=
0.877
5
0.234
or
between
0.
Figure
38
presents
three
different
forms
of
the
p
total
mercury.
The
relative
standard
deviat
between
about
10
and
15%
above
10
pg/
dscrn.
Tripli
relatively
narrow
range
of
the
true
stack
concent
pg/
dscm,
Method
imprecision
is
anticipated
to
deviating
by
less
than
f
23.3%
from
the
actual
concentration
is
above
10
pgldscm,
99
out
of
100
single
m
licate
measurements
5
40.4%
of
the
true
stack
concentration.
Data
presented
in
Figure
36
are
based
on
the
assumption
that
standa
concentration
according
to
the
regression
relation
shown
in
Figure
it
is
possible
that
standard
deviation
could
be
as
high
as
the
upper
c
the
lower
confidence
interval.
The
potential
range
for
99
out
of
1
imprecision
in
the
measurement
method,
has
been
calculated
of
true
'
stack
concentration.
Results
from
those
calculations
are
presented
in
Figure
39.
If
the
precision
of
the
mercury
measurement
methods
is
as
large
as
the
upper
confidence
interval,
a
significant
variation
in
measurement
results
may
be
anticipated.
For
example,
if
the
method
standard
deviation
varies
according
to
the
upper
confidence
limit,
measurement
of
a
stack
containing
500
pg/
dscm
of
mercury
could
result
in
a
spread
for
99
out
of
100
data
points
ranging
from
275
to
725
pgldscm.
If
the
Method
precision
is
best
described
by
the
lower
confidence
interval,
Yo
confidence
level,
,
t)
3
u
.
e
t
I
Y
115
I16
measurement
of
that
same
stack
containing
500
pg/
dscm
mercury
should
result
in
a
99
out
of
100
future
data
points
falling
between
428
and
572
pg/
dscm.
It
is
noteworthy
that
the
RSD
data
listed
in
Tables
16a
and
16b
for
individual
mercury
measurements
occasionally
exceeded
50%
arid
that
the
firms
conducting
the
tests
were
highly
qualified
stack
festers
and
laboratory
anafysts.
This
serves
to
underline
the
critical
importance
of
precision
in
stack
testing.
From
an
owner's
perspective,
it
is
ow
the
precision
of
the
data
being
gathered
to
determine
compliance.
From
a
regulatory
development
perspective,
it
is
critically
important
to
know
the
precision
of
data
being
used
to
establish
regulations.
The
best
estimate
of
the
precision
of
Method
29/
101iV101B
is
provided
by
the
regression
analysis.
Those
data
were
presented
graphically
in
Figures
38
and
39.
To
assist
the
reader,
Table
17
presents
these
data
in
tabular
form,
focusing
on
the
range
of
concentrations
anticipated
to
be
of
primary
interest
to
facilities
being
regulated
under
the
new
and
emerging
US
EPA
emission
rules.
The
first
column
lists
the
true
concentration
of
total
mercury
in
the
stack
(
not
corrected
for
excess
oxygen).
The
second
and
third
columns
present
the
anticipated
range
for
99
out
of
100
future
single
measurements
(
at
the
given
true
stack
concentration).
The
fourth
and
fifth
columns
provide
the
anticipated
range
for
99
out
of
IO0
future
triplicate
measurements.
117
ij
L
Q,
v,
c
d
C
C
r
118
8.0
EPA
Method
29
for
Multi
Metals
The
essential
elements
of
PA
Method
29
were
presented
in
the
previous
section.
As
noted,
the
various
components
of
the
train
are
analyzed
to
determine
the
concentration
of
various
metals.
The
method
is
used
to
determine
compliance
with
a
wide
range
of
metals
but
there
are
very
limited
multi
train
data
available
to
assess
the
precision
of
the
method
for
those
pollutants.
For
three
of
the
key
metals,
cadmium,
chromium,
and
Iead,
the
Agency
did
perform
multi
train,
Method
validation
from
those
tests
suggest
that
additional
data
may
have
been
gathered
on
ocumentation
of
the
results
(
i
any)
were
not
available.
Note
that
lead
and
ed
pollutants
under
the
municipal
waste
combustor
MACT
rules.
Other
metals
rsenic,
and
beryllium.
Other
sources
of
multi
d
by
Rig0
and
ChandIer
as
well
as
the
EPA
EM
demonstration
program.
ta
for
Antimony,
Arsenic,
Beryllium,
Cadmium,
Chromium,
and
Lead
Tables
18
through
23
summarize
the
available
Method
29
data
for
antimony,
arsenic,
beryllium,
,
and
lead
respectively.
In
these
tables,
some
difficulty
may
be
experienced
umber
designations
for
data
from
the
EPA
pilot
scale
tests
and
for
the
EPA
able
22).
Tables
18
through
23
utilize
the
run
number
designations
provided
in
ce.
The
difficulty
is1
that
the
same
run
numbers
are
repeated.
Separate
runs
early
come
from
different
testing
series
but
insufficient
information
ly
describe
the
differences
between
run
series
or
why
run
designations
were
8.1.
I
Antimony
taFor
antimony,
data
is
available
from
the
Rig0
and
Chandler
tests
and
from
the
EPA
pilot
scale
tests.
The
Rigo
and
Chandler
tests
provide
dual
train
data
in
the
30
to
80
pgldscm
concentration
range.
The
EPA
pilot
scale
tests
were
also
dual
train.
They
provide
data
in
two
different
concentration
ranges;
a
lower
range
of
approximately
20
to
30
pg/
dscm
and
an
upper
range
of
approximately
60
to
90
pgldscm.
The
outlier
analysis
indicates
that
run
number
2
from
the
119
Table
18.
Method
29
Multi
Trai
eviation
For
t
Table
19.
Method
29
Multi
Train
Data
and
Standard
Deviation
For
Arsenic
121
Table
20.
Method
29
Multi
Train
Data
and
S
dard
Deviation
For
Beryllium
I
I
I
I
I
I
/
Table
21.
Method
29
Multi
Train
Data
and
Standard
Deviation
For
Cadmium
I23
Table
22.
Method
29
Multi
Train
Data
and
Standard
Deviation
For
Chromium
124
Table
23.
Method
29
Multi
Train
Data
and
Standard
Deviation
For
Lead
125
EPA
pilot
scale
tests
(
first
of
EPA
pilot
tests
designated
as
run
2)
has
an
abnormally
lar,
we
data
range.
After
examining
several
data
grouping,
it
was
concluded
that
this
run
represents
a
data
outlier
and
accordingly,
it
was
ehinated
from
the
precision
analysis.
Figures
40
and
41
prdsent
the
antimony
data
in
graphical
form.
Figure
40
is
a
scatter
plot
of
the
small
sample
standard
deviation
data
while
Figure
41
deviation.
As
sh
s
to
approximately
'
30%.
8.1.2
Arsenic
Dora
Multi
train
data
sour
standard
deviation
dat
relative
standard
d
on
the
Pittsfieid
M
limit
for
the
laborat
scale
tests.
Those
have
been
jnclwd
Iow
levels
to
h
DataMulti
train
data
for
cadmium
emissions
u
three
sources.
Tests
by
Rigo
and
Chandler
provide
data
pg/
dscrn.
The
EPA
pilot
scale
tests
provide
data
in
two
ranges;
a
low
range
centered
at
about
20
ge
of
about
20
to
50
/
,
I
i
i
j
m
N
+
+
+
I
.+
I
*
I
b
m
I
I
'
I
I
I
7
m
0
127
t
0
128
v,
cu
.
.
a
m
0
N
7
El
1
..
1
I
t
I29
0
0
0
0
o\
0
00
0
0
\
3
0
v)
0
u
0
m
0
N
0,
0
I
I
0
M
CJ
L
0
z
i
cy,
131
a
2
a
CD
Li
+
I
132
r:
ti
F
t
u
pg/
dscm
and
an
upper
range
that
spans
40
to
80
pg/
dscm.
The
EPA
method
validation
tests
provide
data
at
a
very
low
concentration
range
of
about
1.5
to
2.5
pg/
dscm.
AI1
data
in
this
data
set
pass
the
SPC
outlier
criteria
and
have
been
included
in
the
precision
analysis.
Figures
46
and
47
present
scatter
plots
of
the
data
including
the
small
sample
bias
corrected
standard
deviation
and
relative
standard
deviation
as
a
function
of
mn
average
concentration.
Figure
47
shows
that,
for
concentrations
above
about
20
pgldscrn,
the
RSD
covers
approximately
the
same
span
as
the
other
Method
29
metals
presented
above.
However,
the
low
concentration
data
from
the
Method
validation
tests
indicate
significantly
higher
RSD.
Data
in
Figure
46
show
that
the
actual
standard
deviation
tends
to
increase
with
increasing
concentration,
even
at
the
very
low
concentrations
of
the
validation
tests.
This
shows
that
the
significant
rise
in
RSD
is
a
result
of
the
denominator
in
the
RSD
calculation
tending
toward
zero
rather
than
rapid
expansion
of
the
standard
deviation.
8.1.5
Chromium
Data
Three
sets
of
multi
train
data
are
available
for
assessment
of
the
precision
of
Method
29
for
chromium.
The
Rig0
and
Chandler
tests
provide
data
with
concentration
in
the
range
of
about
4
to
10
pgidscm.
The
EPA
pilot
scale
tests
again
provide
data
in
two
ranges.
The
low
range
results
are
centered
at
about
20
pg/
dscm
while
the
high
concentration
results
cover
the
range
of
about
60
to
70
pgldscm.
Finally,
the
EPA
Method
validation
tests
are
at
very
low
cadmium
concentration
ranging
from
about
1
to
3
pddscm.
Outlier
analysis
for
this
data
set
indicates
that
two
data
points
have
abnormally
large
data
spreads.
Specifically,
run
number
7
from
the
Rigo
and
Chandler
tests
and
run
number
8
for
the
EPA
method
validation
tests.
Both
of
these
runs
are
specially
marked
in
the
run
number
column
of
Table
22.
The
Rigo
and
Chandler
run
was
eliminated
from
further
analysis,
while
only
the
data
from
train
C
of
the
EPA
tests
were
eliminated.
Note
that
there
were
several
other
data
points
indicating
very
large
spreads
but
they
have
all
been
included
in
the
analysis.
Figures
48
and
49
present
scatter
plots
of
the
small
sample
bias
corrected
data
for
standard
deviation
and
relative
standard
deviation
as
a
function
of
run
average
concentration.
8.1.6
Lead
Data
Three
sets
of
multi
train
data
are
also
available
for
Method
29
measurement
of
lead.
The
Rig0
and
Chandler
tests
at
the
Pittsfield
MWC
provide
data
at
lead
concentrations
ranging
from
about
400
to
1500
pgldscm.
The
EPA
piiot
scale
tests
provide
data
in
two
concentration
ranges.
The
low
range
data
cover
the
span
of
about
20
to
30
pg/
dscm
.
~
^
?
>
133
JL
;
si
m
3
f
m
I
+
+
+
+
+
+
+
+
I
134
n
u
bl,
e.
.
f""
I,.
E
w
I
I
i
I
I
B
E
0
VI
0
w
0
m
0
v)
0
J
`
136
P
r
F
L
r
t
11
...
F""
L
r
t.
IFLc"
4
I
h.
2
137
whiIe
the
higher
concentration
results
were
obtained
in
the
range
of
about
50
to
95
pddscrn.
Finally
the
EPA
Method
validation
test
result
ere
obtained
at
concentfations
in
*
e
range
of20
to
4o
pg/
dscm.
AI1
data
in
the
lead
data
set
pass
the
plots
ofthe
small
sampl
ias
corrected
stand
average
concentration.
Note
that
the
high
co
exhibit
RSD
values
less
than
13%,
while
th
data
exhibit
a
broader
range
of
RSD
values.
from
the
Rig0
and
Chandler
8.2
EPA
Method
29
Regression
Analyses
After
elimination
of
outliers,
the
Method
29
multi
train
data
for
antimony,
arsenic,
beryllium,
cadmium,
chromium,
and
lead
were
analyzed
with
weighted
regression
analysis.
Results
from
those
analyses
are
summarized
in
Table
24
below.
Table
24.
Results
of
Method
29
Regression
Analysis
for
Various
Metals
There
are
clearly
differences
between
the
regression
equations
for
the
six
metals
listed
above
but
there
are
also
significant
similarities.
The
variation
of
ndard
deviation
for
versus
concentration
appears
to
be
significantly
different
from
the
other
metals.
For
cadmium,
the
maximum
potential
value
for
the
p
term
in
the
p
0.61
1.
For
any
of
the
other
five
metals,
within
t
coefficient
could
fall
between
0.692
and
0.929.
Five
of
the
six
regression
analyses
produced
t
ction7
at
the
95%
con
confidence
bounds,
t
158
I39
c
c
statistics
that
are
above
the
critical
value
of
that
statistic.
For
antimony
the
t
statistics
(
at
the
95%
confidence
level)
is
slightly
below
the
critical
value
and
the
t
statistic
for
beryllium
is
only
marginally
above
the
critical
vaiues.
This
results
in
wide
ranges
for
the
potential
values
of
the
power
function
p
coefficient
for
both
antimony
and
beryllium.
Recall
that,
with
Method
29,
each
data
pair
provides
data
on
the
full
range
of
metals.
With
the
exception
of
the
EPA
Method
validation
tests,
every
data
point,
for
each
metal,
has
a
companion
data
point
for
the
other
five
metals.
This
is
important
since
random
error
enters
the
measurement
process
through
both
the
sampling
process
and
the
chemical
analysis
processes.
In
a
multi
metal
procedure
such
as
Method
29,
random
errors
in
the
sampling
process
should
be
reflected
in
every
metal
being
monitored.
Moreover,
when
the
value
of
the
power
coefficient
is
close
to
1.0,
random
error
in
the
sample
collection
process
is
a
significant
contributor
to
the
overall
Method
precision.
For
these
reasons,
there
is
increased
reason
to
anticipate
similarity
in
the
various
relationships
between
standard
deviation
and
concentration.
Figures
52
through
57
illustrate
the
regression
equations
and
the
95%
confidence
intervals
for
measurement
of
each
of
the
six
metals
using
Methud
29.
Figures
58
through
63
present
data
on
the
various
precision
metrics,
assuming
that
the
standard
deviation
varies
according
to
the
regression
equation.
It
is
instructive
to
compare
the
general
level
for
the
predicted
relative
standard
deviation
and
the
variation
of
RSD
for
each
of
the
six
metals.
Figure
58
indicates
that
the
RSD
for
antimony
measurement
using
Method
29
is
basically
a
flat
function
of
concentration
over
the
entire
range
of
available
data.
At
a
true
concentration
of
20
pddscm
the
predicted
RSD
is
11.8%
while
the
predicted
RSD
is
9.3%
at
90pg/
dscm.
In
the
concentration
range
between
about
20
to
100p~
ldscm,
a
relatively
flat
RSD
versus
concentration
trend
is
also
observed
for
arsenic,
beryllium,
and
chromium.
In
that
range,
the
RSD
for
arsenic
varies
between
about
15
and
16.3%
(
see
Figure
59).
For
beryllium,
RSD
only
varies
between
17.0%
and
17.8%
(
see
Figure
60).
SlightIy
greater
variation
is
predicted
for
chromium
but,
as
shown
in
Figure
62,
the
anticipated
variation
in
RSD
is
only
from
21.3%
at
20
pg/
dscm
to
18.2%
at
71
pddscm.
141
142
1
143
.
.
d
.
E
.
I
L
9
3
=
.
n
t
1
0
144
I45
a
0
0
0
c
r:
I
'
l.
a.
&
0
cr
0
3
.
I47
I
0
E
.
I
0
o\
0
00
0
P
5
VJ
9
a
M
I
1
v3
L
i
0
QI
0
01
0
b
0
W
0
Wl
0
d
0
m
0
N
0
I
0
I
149
0
v)
c
J
.
,
I
s
0,
0
151
s
0
3
3
z
0
rc
0
\
3
0
In
0
Q
0
m
0
r
4
2
0
E
0
m
=
\
M
a
I
I
m
u
L
c
..
I
2
~
.
I
4
k
F;;;
1
0
i
k:.
l
s
s
0
0
d
m
(
u
s
0
0
0
rn
.
0
0
d
1
0
0
c\
1
0
0
0
.
1
0
0
W
0
0
Q
0
0
d
0
0
c\
1
0
_.
t
anticipated
when
concentration
drops
below
20
p,
a/
dscm.
As
noted
earlier,
the
data
in
Figures
58
through
63
are
based
on
the
assumption
that
standard
deviation
varies
according
to
the
re
ssion
equations.
However,
within
g5%
confidence
bounds,
it
is
distinctly
possible
that
standard
ation
be
greater
Or
lines.
Figures
64
through
69
present
the
anticipated
ranges
for
99
out
of
100
future
a
function
of
the
true
stack
concentration,
assu
the
upper
95%
confidence
limit,
according
to
95%
confidence
limit.
These
figures
illustrate
the
critical
importance
overall
precision
assessment.
As
indicated
by
results
presented
in
Fisures
5
deviation
of
Method
29
antimony
measurements
varies
according
to
the
out
of
100
future
measurements
(
at
a
stack
concentration
within
23%
ofthe
true
stack
that
future
data
might
have
a
spread
as
large
as
+
5
1.9%
a
ng
that
that
standard
deviation
varies
according
to
e
regression
The
significance
of
the
unce
more
dramatic
for
Method
29
measurements
of
be
Method
29
beryllium
measurements
are
made
at
true
stack
concentrations
of
80
pg/
dscm,
available
data
indicate
that
99
out
of
100
future
measurements
Wil
concentration
(
45
to
115
pg/
dscm).
Also,
99
out
of
100
triplicate
measurements
are
expected
to
fall
within
k
25.3%
of
the
true
stack
concentration
(
when
true
concentration
equals
80
pddscm).
However,
at
the
95%
confidence
level,
it
is
only
possible
to
conclude
that
the
future
single
measurements
will
fall
within
f:
97.5%
of
the
true
concentration.
This
large
spread
between
our
best
estimate
and
the
95%
confidence
limits
is
a
direct
result
of
the
limited
amount
of
multi
train
data
for
beryllium
using
Method
29.
The
potential
range
for
fu
er
metals
is
standard
deviation
concentration
is
even
As
indicated
in
Figures
6o
and
66y
when
within
43
8%
Of
the
true
illustrated
on
the
respective
figures.
W
E
.
I
5
155
0
0
0
o\
0
00
0
b
0
\
3
0
v,
0
d
0
m
0
P
4
0
i
i""
PP
f
.).
5
157
M
E
3
a
f
0
U
rn
.
A
ki
p\
1
L,
E
L,
.1
0
m
0
ri
0
I
159
160
i_
Earlier
discussion
of
the
results
presented
in
Table
24
noted
a
similarity
in
the
regression
analysis
for
five
of
the
six
metals,
including
antimony,
arsenic,
beryllium,
chromium.
and
lead.
It
was
pointed
out
that
Method
29
collects
a
sample
that
is
subsequently
analyzed
for
all
of
the
target
metals.
Random
errors
in
the
sample
collection
and
sample
recovery
operations
are
likely
to
contribute
similar
random
error
to
each
of
the
measured
metal
concentrations.
Finally,
it
was
noted
that
random
error
in
the
sample
collection
and
recovery
process
tend
to
drive
the
value
of
the
power
function
coefficient
toward
1.0
while
random
error
in
the
analytical
analysis
are
more
typically
characterized
by
constant
standard
deviation
(
p
equals
zero
in
the
regression
equation).
In
Table
24,
note
that
with
the
exception
of
cadmium,
the
regression
analysis
for
five
metals
indicates
that
the
p
.
coefficient
is
between
0.703
and
1.039
sugsesting
that
random
error
in
sampling
and
recovery
are
major
contributors
to
overall
megsurement
imprecision.
The
general
similarity
in
these
resression
results
further
suggests
that
for
these
five
metaIs,
it
may
be
appropriate
to
assess
a
composite
precision
estimate
for
Method
29.
To
perform
that
assessment,
the
multi
train
data
presenred
in
Tables
18,
19,
20,
22,
and
23
were
combined
into
a
single
data
set.
With
the
exception
of
the
multi
train
data
for
tead,
the
majority
of
the
individual
data
sets
were
from
tests
where
the
metal
concentrations
ranged
from
single
digit
to
less
than
100
pg/
dscm.
Further
the
majority
of
the
lead
data
are
from
this
same
concentration
range.
To
form
a
composite
data
set
for
regression
analysis,
the
Rig0
and
Chandler
data
were
eliminated
from
the
lead
data
yielding
data
for
all
five
metals
in
the
same
concentration
range.
The
data
were
appropriately
weighted
for
the
number
of
degrees
of
freedom
and
then
subjected
to
a
regression
analysis.
The
resuItant
regression
equation
has
158
degrees
of
freedom
and
produced
a
t
statistic
equal
to
10.66
well
above
the
critical
t
statistic.
The
analysis
suggests
that
the
'
relationship
between
S
and
concentration
is
described
by
the
equation:
The
value
of
the
p
coefficient
(
0.821)
is
easily
within
the
95%
confidence
ranges
forp
determined
by
regression
analysis
for
each
of
the
five
individual
metals
(
see
Tabte
24).
Figure
70
is
a
plot
of
the
regression
equations
for
the
composite
data
set
including
the
95%
confidence
intervals
on
that
161
regression.
Figure
71
presents
a
comparison
of
the
re,
oression
equation
for
each
of
the
five
individual
metals
and
the
regression
equation
from
the
composite
analysis,
It
is
important
to
reiterate
that
only
a
limited
body
of
data
is
available
to
assess
the
precision
of
Method
29.
Moreover,
one
of
the
critically
important
data
sets,
the
EPA
pilot
scale
tests,
contains
a
known
bias,
Inchdins
these
biased
results
in
the
analysis
clearly
results
in
a
slight
over
estimate
of
the
standard
deviation
at
any
given
stack
concentration
(
partico
However,
if
those
data
were
eliminated
from
the
assessment,
the
result
would
be
an
even
larger
aver
estimate
of
the
Method's
imprecision.
As
a
result
of
the
limited
quantity
of
data
and
the
known
biases
in
some
of
those
data,
the
precision
of
Method
29
for
metals
can
only
be
generally
estimated.
The
analysis
of
the
composite
data
set
provides
a
basis
for
the
overall
assessment
of
the
method's
precision.
Figure
72
presents
various
precision
metrics
determined
from
the
regression
analysis
of
the
composite
d
t.
Based
on
the
available
data,
it
appears
that
Method
29
provides
an
RSD
between
13
and
when
the
metal
loading
is
between
20
arid
about
IOOug/
dscin.
At
ineta1
concentrations
b
about
10
pg/
dscm,
the
imprecision
of
the
method
appears
to
increase
asymptotically.
Relative
to
future
measurements,
if
the
precision
of
Method
29
conforms
to
the
composite
analysis
and
if
the
metals
concentration
is
greater
than
20
pg/
dscrn,
99
out
of
100
single
measurements
should
deviate
from
the
true
concentration
by
no
more
than
45%.
Similarly,
in
the
same
rage,
99
out
of
IO0
triplicate
measurements
should
deviate
from
the
true
concentration
by
less
than
26%.
Unfortunately,
the
available
data
do
not
support
a
more
definite
assessment.
Tabie
25
provides
a
summary
of
the
anticipated
range
of
measurement
results
for
application
of
Method
29
for
determination
of
the
concentration
of
antimony,
arsenic,
beryllium,
chromium,
and
lead.
Data
in
this
table
are
derived
from
analysis
of
the
composite
data
set
and
cover
the
concentration
range
of
4
to
100
pg/
dscm.
Note
that
the
data
in
the
table
do
not
include
correction
for
oxygen
content
in
the
stack.
163
,
6
l
e
0'
rl
P
2
E
f
ED
0
0
c
r
5:
a
3
+
M
c
164
i;
P
I65
I
Table
25.
Range
of
Anticipated
Future
Metals
Data
Antimony,
Arsenic,
Beryllium,
Chromium,
or
L
I
I66
9.0
Other
Measurement
Methods.
1
An
attempt
was
made
to
gather
multi
train
data
for
a
variety
of
additional
EPA
measurement
methods.
No
multi
train
data
or
method
validation
test
repons
were
uncovered
for
EPA
methods
0030
or
001
1
for
volatile
and
semi
volatile
organic
emissions.
The
same
can
be
said
for
EPA
Method
23a,
which
is
a
special
procedure
for
measuring
dioxin
and
furan
emissions.
In
the
absence
of
multi
train
measurement
data,
it
is
not
possible
to
fully
assess
the
precision
of
these
methods.
167
This
page
Intentionally
left
blank.
168
"~
10.
Conclusions
The
ReMAP
study
has
assembled
a
database
containins
all
known
multi
train
data
sets
using
various
EPA
measurement
Methods.
Data
in
that
database
have
been
subjected
to
a
detailed
analysis
to
assess
the
precision
of
the
Methods
as
a
function
of
stack
concentration.
The
scope
of
the
available
data
is
Cxtremely
limited,
especially
considering
the
importance
of
results
from
application
of
the
Methods.
Certain
of
the
Methods,
especia
Methods
5
and
5i
have
significant
databases
and
the
precision
of
those
methods
is
relatively
well
established.
Using
relative
standard
deviation
as
the
precision
metric,
the
precision
of
Method
5
is
between
5
and
1
I%
when
applied
to
stacks
with
a
broad
range
of
concentrations.
If
applied
with
attention
to
detail,
this
method
is
capable
of
providing
reasonably
precise
resuits,
even
at
stack
particulate
concentrations
as
low
as
15
mg/
dscrn.
Whether
an
RSD
of
5
to
1
I%
is
sufficiently
precise
is
likely
to
be
application
specific.
Methqd
5i
was
specifically
developed
to
provide
precise
measurement
resuIts
for
particulate
matter
concentrations
below
50
mgdscrn.
Based
on
available
data,
this
precision
of
this
Method
has
no
statistically
significant
variation
with
stack
concentration.
Pooled
anaiysis
of
the
data
indicates
that
the
Method
(
when
applied
at
concentrations
between
about
5
and
50
mg/
dscm)
has
a
characteristic
standard
deviation
of
1.43
mg/
dscm.
Method
23
for
dioxin
and
furan
emissions
is
a
critically
important
method
for
current
EPA
emission
regulations
and
for
public
perception
of
risk
associated
with
emissions
from
combustion
facilities.
There
is
only
a
very
small
database
for
assessment
of
the
precision
of
this
Method.
Based
on
available
data,
the
anticipated
RSD
for
measurements
of
the
total
mass
of
tetra
through
octa
chlorinated
dioxin
and,
furan
is
estimated
to
be
between
6.3
%
and
20%
for
stack
concentrations
in
the
range
of
2
to
27
ng/
dscm
(
higher
RSD
at
lower
concentration).
Recall
that
the
stated
range
of
stack
concentrations
are
given
on
an
"
as
measured
basis"
and
therefore
do
not
include
excess
air
diIution
correction
factors
(
e.
g.,
correction
to
7%
02).
The
anticipated
range
for
99%
of
future
individual
measurements
is
t
2.57
times
the
standard
deviation.
Method
23
is
also
used
to
determine
dioxin
and
furan
emissions
calculated
as
ITEQ.
Analysis
of
available
data
for
emissions
expressed
in
this
manner
did
not
yield
an
accep~
able
regression
169
expression.
That
is,
the
t
statistic
for
the
regression
was
less
than
the
critical
t
statistic
at
the
95%
confidence
kvel.
This
implies
that
stron
sociated
with
application
of
Toxic
Equivalence
Factors
may
be
masking
k
weighting
factors,
variation
between
simultaneous
significantly
amplified
relative
to
differe
data
and
when
used
to
dete
variation
of
Method
performed
to
determine
a
characteristic
Stan
the
pooled
standard
concentration
range
0.02
to
0.9
ng
ITE
confidence
limit,
the
possible
range
of
Method
23
data
point
indicates
stack
concentration
that
data
point
(
at
the
95%
confidence
level)
could
be
as
low
Moreover,
using
the
limited
quantity
of
currently
available
data
and
at
the
95%
confidence
level,
it
is
not
possible
to
determine
compliance
with
a
PCDDPCDF
emission
limit
below
0.095
ng
ITEQ/
dscrn.
on
the
avaiIabie
ote
that,
at
the
95%
Method
26
for
hydrochloric
acid
measurements
was
found
to
be
as
precise
as
any
of
the
manual
measurement
methods.
Typically,
the
RSD
for
this
and
lo%
RSD
does
increase
at
very
low
HCI
concentrations
but
the
regression
analysis
suggests
that
RSD
should
only
increase
to
15.9%
at
concentrations
as
low
as
1
mg/
dscrn.
Mercury
emission
measurements
are
also
regulations.
A
relatively
large
array
of
mult
analysis.
The
analysis
of
results
found
that
the
and
101
had
minimal
variation
with
ppldscm
the
measurement
method
RSD
varied
from
9.6
to
12.4
percent.
A
significant
portion
of
the
overall
database
is
for
measurements
at
relatively
low
mercury
concentrations.
Forty
out
of
73
mercury
data
points
had
average
concentrations
below
were
at
average
stack
concentration
less
than
30
pgld
data
was
available
for
the
ReMAP
ercury
measurements
by
Methods
29
As
concentration
drops
from
SO
to
5
pg/
dscm,
the
ReMAP
analysis
shows
that
RSD
is
anticipated
to
increase
from
12.4
to
I
5.4%.
170
Method
29
is
also
used
for
measurement
of
other
metals
Precision
analysis
was
completed
for
six
other
metals
including
antimony,
arsenic,
beryllium,
cadmium,
chromium,
and
lead.
The
analysis
shows
that
five
of
the
six
metals
all
behave
similarly
with
respect
to
measurement
method
precision.
Data
for
all
metals
except
cadmium
exhibit
a
standard
deviation
versus
concentration
relation
where
the
power
function
coefficient
(
p)
has
a
value
of
approximately
0.82.
Composite
analysis
of
data
for
this
group
of
metals
suggests
that
Method
29
provides
an
RSD
on
the
order
of
I3
to
18%
\
vhen
the
metal
loading
is
between
20
and
about
IOOpg/
dscm.
Data
for
lead
is
available
at
much
higher
concentration
and
the
method
RSD
for
lead
appears
to
asymptote
between
5
and
10%.
At
metal
concentrations
below
about
20
pg/
dscm,
the
imprecision
of
the
Method
appears
to
increase
asymptotically.
For
cadmium,
based
on
the
available
data
standard
deviation
of
the
Method
has
a
different
relation
with
concentration.
The
indicated
value
of
the
p
coeflicient
is
approximately
0.45
suggesting
that
for
the
available
cadmium
data,
random
error
(
or
differences)
in
the
chemical
analysis
was
a
significant
contributor
to
the
overall
imprecision
of
the
Method.
One
additional
conclusion
from
the
ReMAP
Phase
1
project
is
that
there
is
a
pressing
need
for
additional
multi
train
data
to
refine
the
precision
estimates
of
the
PA
Reference
Methods.
If
such
experimental
programs
are
to
be
conducted,
significant
attention
should
be
given
to
the
appropriate
range
of
stack
concentrations.
Results
presented
in
this
report
can
help
to
guide
the
test
planning
efforts.
1.
nn
A
C
9.
EPA
Reference
Method
23
Determination
of
Polychlorinated
Dibenzo
p
Dioxins
and
Polychlorinated
Dibenzofurans
from
Stationary
Sources.
56
FR
5758,
February
13,
1991
(
with
several
revisions).
10.
Validation
of
Emission
Test
Method
for
PCDDs
and
PCDfs.
Prepared
by
Midwest
Research
Institute,
EPA
Contract
No.
68
02
4395,
Work
Assignment
23
for
PA
EMSL.
February
24,
1989.
Rig0
&
Rig0
Associates
and
A.
J.
Chandler
and
Associates
under
the
Direction
of
ASME.
June
1
1.
Retrofit
of
Waste
to
Energy
Facilities
Equipped
with
Electrostatic
Precipitators.
Prepared
by
1997.
Aggregate
Kiln.
Prepared
by
Energy
and
Environmental
Research
Corporation,
Contract
No.
68
D2
0164
for
the
PA
Office
of
Solid
Waste.
October
10,
1997.
12.
Dioxins/
Furans,
HC1,
C12
and
Related
Testing
at
a
Hazardous
Waste
Bumin,
(
J
Light
Weight
v
13.
EPA
Reference
Method
23
Determination
of
Polychlorinated
Dibenzo
p
Dioxins
and
Polychlorinated
Dibenzofurans
from
Stationary
Sources.
56
FR
5758,
February
13,
199
I
.
14.
OMSS
Field
Test
Report
on
Carbon
Injection
for
Mercury
Control
Completed
at
the
Ogden
Martin
of
Stanislaus,
Inc.
Prepared
by
Radian
Corporation,
Conrract
No.
68
D
i
00
IO
for
the
EPA
Office
of
Research
and
Development.
September
1992.
15.
EPA
Reference
Method
29
Determination
of
Metals
Emissions
from
Stationary
Sources.
61
FRl8262,
April
25,
1996.
16.
PA
Reference
Method
1
0
1
a
Determination
of
Mercury
Emissions
from
Sewage
Sludge
Incinerators.
47
FR
24703,
June
8,
1982.
17.
Proposed
Draft
EPA
Method
10
1
b
Determination
of
Mercury
Species
from
Stationary
Sources.
18.
Validation
of
Draft
Method
29
at
a
Municipal
Waste
Combustor.
Prepared
by
Radian
Corporation,
Contract
No.
68
D9
0054
for
the
PA
Emission
Measurements
Branch.
September
30,
1992.
19.
Mercury
CEMS
Demonstration
at
the
HoInam,
Inc.
Hazardous
Waste
Burning
Cement
Kiln
in
Holly
Hill,
SC.
Energy
and
Environmental
Research
Corporation
for
EPA
Ofice
of
Solid
Waste
and
Emergency
Response.
October
1997.
(
also
see
62
FR
67788).
20.
Internal
EPA
Study
at
the
Pilot
Scale
Rotary
Kiln
Incinerator
Located
in
Research
Triangle
Park,
NC.
SarnpIing
and
Analysis
performed
by
PA.
21.
Emissions
of
Metals
and
Organics
from
Municipal
Wastewater
Sludge
Incinerators.
Prepared
by
Entropy
and
DEECO,
Contract
No.
68
CO
0027,
for
EPA
Risk
Reduction
Engineering
Laboratory.
\
I
y
c
,
c
i
Appendix
Statistical
Analysis
Procedures
for
the
ReMAP
Program
Prepared
by:
Charlie
Hendrix
Statis
tical
Consult
ant
r
I,"
u
Procedures
for
Analyzing
Simuitaneousfy
Sampled
Concentration
Data
to
Determine
Measurement
Precision
(
Random
Error)
This
appendix
is
concerned
with
the
statistical
methods
used
in
the
...
b
1
analysis
of
simultaneousiy
sampled
data.
Confidence
Interval
on
a
Mean
#
¶
W
i
ab+
Suppose
w
e
have
collected
the
following
replicate
data
from
a
process
operating
under
fixed
conditions.
103.2
107.9
101.6
109.1
105.3
The
average
of
these
is
105.42;
the
standard
deviation
is
3.132
with
4
degrees
of
freedom
(
df).
If
these
are
representative
data
from
this
process,
then
the
95%
confidence
interval
on
the
true
mean
p
is
105.42
of
freedom
(
df).
t
=
2.776.
The
95%
interval
on
p
is
105.42
3.89
or
101.53
to
109.31.
"
95%
of
the
intervals
calculated
in
this
manner
will
encompass
the
true
mean,
p"
From
this
we
infer
that
"
the
probability
is
95%
that
the
interval
101.53
to
109.31
has
captured
the
true
mean,
p"
t*
3.132/&
where
t
is
the
reference
value
of
t
with
4
degrees
cerns
about
whether
the
data
came
from
a
non
normal
little
bearing
on
this
calculation
under
most
Confidence
Interval
on
a
S
tandard
Deviation
The
following
replicate
data
also
came
from
a
process
operating
under
a
fixed
set
of
conditions.
1.03
1.24
0.91
1.36
0.97
1.22
The
standard
deviation
of
these
data
is
S
=
0.177
with
5
degrees
of
freedom
(
df).
If
these
are
representative
data
from
this
process,
then
the
95%
confidence
interval
on
the
true
standard
deviation
a
is
calculated
in
the
following
manner.
Go
to
Tabie
1;
ent
with
df
=
5;
find
the
factors
0.624
and
2.453
under
the
heading
"
For
95%
onf.
Int."
Multiply
0.177
by
each
of
these
factors
to
obtain
0.110
and
0.434.
df
1
2
3
4
5
6
7
8
.
9
10
12
15
20
25
30
50
100
200
500
paae
2
For
95%
Conf.
I
n
t
.
PF
il`
0.566
3.727
0.599
2.875
0.624
2.453
0
.644
2.202
0
661
0.675
I.
826
1.755
0.717
1.651
0.73
1.548
0.765
1.444
0.785
1.380
1.337
1.243
0
*
942
1.066
"
95%
of
the
intervals
calculated
in
this
ma
standard
deviation
0.''
that
the
interval
0.110
to
0.434
has
captured
the
true
standard
deviation
sigma
(
o)".
This
assumes
that
the
data
c
underlying
"
true
standard
deviation
o"
wh
accuracy
of
confidence
intervals
on
CT
is
affe
original
data.
er
encompass
the
true
e
from
a
process
with
an
From
this
we
infer
that
"
the
pro
biiity
'
is
95y0
Table
1
is
derived
from
the
Confidence
Interval
on
Siama
M
u
l
t
i
d
e
Measures
of
Variation
Suppose
we
have
data
from
six
tests.
Each
pair
of
data
was
obtained
by
drawing
simultaneous
samples
and
analyzing
those
samples
for
the
concentration
of
a
pollutant.
Time
Data
S
t
a
n
d
a
r
d
Deviation.
S
df
1
1
1
1
1
1
2:
30
PM
27.2
30.0
1.980
5:
50
PM
20.9
27.2
4.455
6:
25
PM
28.7
33.1
'
3.111
7:
15
PM
25.5
24.2
0.919
4:
15
PM
19.1
23.7
3.253
5:
05
PM
28.3
26.8
1.061
*"^
.
.
.).
,
.
,
.
s
I
/.
<
_
paae
3
We
are
concerned
with
the
inherent
variation
due
to
the
sampling
and
analysis
procedures
(
measurement
precision),
measured
as
the
variation
within
tests.
The
standard
deviation
of
each
pair
of
samples
is
shown.
Our
objectives
are
to
(
1)
estimate
the
standard
deviation
a
due
to
sampling
and
asurement
precision)
and
(
2)
to
calculate
a
95%
confidence
int
estimate
of
0.
cal
to
average
the
standard
deviations
and
report
that
as
t
h
e
estimate
of
0.
Unfortunately
that
average
will
be
a
of
ci.
This
bias
can
be
substantial.
A
more
accurate
estimate
of
CT
is
found
by
sed
estimate
iations.
Pooling
requires
squaring
the
individual
to
obtain
variances;
weight
averaging
the
variances
to
obtain
the
pooled
variance;
then
take
the
square
root
to
find
the
pooled
standard
devia
ance
is
weighted
by
the
number
of
degrees
of
freedom
assoc
variance.
The
number
of
degrees
of
freedom
andard
deviati
is
the
sum
of
the
degrees
of
ndard
deviati
Pooled
Variance
=
(
Sum
of
df*
Variance)/(
Surn
of
df)
80)
z
+
1"(
3.253)*
+
...
+
1*(
0.919)*]/[
1
+
1
+
1
+
1
+
1
+
11
=
45.99816
=
7.666
Pooled
S
=
67.666
=
2.77
with
6
df.
Pooled
S
is
an
estimate
of
G.
We
can
calculate
the
95%
confidence
interval
on
(
r
by
entering
Table
1
with
6
df
to
find
the
factors
0.644
and
2.202,
Multipl
2.77
by
each
of
these
factors
to
find
1.78
and
6.10.
The
probability
is
95%
th'at
this
interval
has
captured
the
true
value
of
0.
Can
we
calculate
a
confidence
interval
on
CJ
by
treating
the
individual
,
3.253,
...
a
0.919)
as
"
data";
calculate
those
"
data"
and
then
calculate
confidence
limits
data"
as
if
we
were
calculating
the
confidence
The
answer
is
a
qualified
"
yes",
but
only
after
taking
that
have
not
been
addressed
at
this
point.
d
for
the
analysis
of
the
R
MAP
data.
Although
the
involves
fitting
the
data
to
a
mode
by
least
squares
and
nderlying
principle
is
founded
on
weighted
~
~
_
111
__
_
paae
4
The
ReMAP
Procedu
re
The
structure
of
the
ReMAP
data
precludes
direct
pooling
to
estimate
CJ
h
e
primary
data
is
re
was
designed
t
of
deviations
in
e
fact
that
G
varies
nonlinear
least
square
method.
ition
to
obtaining
Tens
of
thousands
of
synthetic
d
were
examined.
The
sirnutat
scale
of
C
;
sometimes
Monte
Carlo
simulation
estimates
of
G
and
also
show
that
the
con
approximately
as
stated.
in
this
manner.
Cases
of
N
=
12
pairs
of
data;
N
=
24
airs
of
data;
and
other
cases
r
t
vals
on
(
sigma)
are
This
will
be
discussed
later.
d
PI
i
i
,
n
1,
The
ReMAP
Model
S
=
kCP
Out
of
all
the
possible
models
that
could
be
used
to
associate
S
with
Cy
why
was
S
=
kCp
chosen?
Is
this
mogel
adequate
for
all
of
the
pollutants?
These
questions
...
and
others
concerning
this
model
form,..
are
discussed
in
more
detail
in
Fittina
Sta
ndard
De
viation
vs.
Concentration
Data
to
Alternative
Models.
In
choosing
a
model
form,
one
of
the
first
requirements
is
that
the
variation
in
the
residuals
(
residual
=
difference
between
observed
and
e
constant
along
the
scale
of
concentration.
This
is
s
variance".
Simple
graphics
depicting
S
as
a
function
requirement
is
not
met
in
the
ReMAP
data
...
at
least
in
which
those
data
span
realistic
ranges
on
the
scale
of
C.
Before
fitting
the
data
to
a
model
we
need
to
stabilize
the
variance.
.
When
the
data
are
presented
in
Ln
tn
coordinates,
statistical
tests
confirm
that
the
variance
is
has
been
done
by
linearizing
S
=
kCP
to
mogeneous
along
the
scale
of
concentration.
Typical
values
of
p
range
from
0
5
to
0.9.
The
exceptions
were
pollutants
in
which
the
concentration
spanned
narrow
ra
ges
and
the
confidence
intervals
on
p
were
wide.
Since
values
of
p
have
been
associated
with
sampiing
variation
as
opposed
to
variation
due
to
chemical
analysis,
the
power
law
model
has
merit
aside
from
its
statistical
properties.
A
fundamental
difficulty
with
the
ReMAP
data
lies
in
the
fact
that
these
data
are
poorly
arranged
along
the
scale
of
concentration.
Rather
than
being
concentrated
at
two
.
or
three
positions
on
that
scale,
the
data
are
often
ttered;
sometimes
concentrated
near
the
centroid
and
sparse
at
the
seldom
focused
near
t
h
e
ends
of
the
concentration
scale.
Furthermore,
data
collected
from
one
source
are
sometimes
positioned
near
one
level
of
concentration
and
data
from
other
sources
are
positioned
at
other
levels.
in
order
to
obtain
precise
estimates
of
p,
we
need
data
that
spans
decades
(
factors
of
10)
on
the
scale
of
concentration;
in
reality
there
are
instances
in
which
the
data
bareiy
spans
one
decade.
These
factors
virtually
preclude
building
models
more
complex
than
the
form
S
=
kCp.
Where
there
were
questions
about
this,
the
adequacy
of
this
model
form
was
testing
by
t
h
e
usual
stati
tical
procedures;
in
every
instance
it
was
found
that
a
more
complex
mode
could
not
be
justified.
,
This
is
not
to
claim
that
a
power
law
model
will
be
adequate
for
ail
The
choice
of
model
form
is
presently
limited
by
the
factors
future
data.
noted
above.
paae
6
7
The
Relationshi
mi
n
r
d
D
v
i
i
n
A
standard
de
sigma.
Sigma
is
the
When
we
estimate
(
3
truth"
(
accuracy,
unbia
truth"
(
precise;
small
If
we
calculate
S
from
a
using
other
data
fro
e
interval
arou
If
we
collect
two
simultaneous
samples,
the
standard
deviation
of
that
sample
must
be
rnuitipli
1.253
to
make
it
an
unbiased
estimate
of
u.
With
larger
amounts
o
in
the
sample,
the
bias
is
s
is
a
brief
table
of
bias
cur
w
2
3
4
5
10
Bias
Correction
Factor
1.253
1.128
1.085
1
Remember
each
value
of
S
estimate
of
a.
r
estimate
of
6;
Averaging
values
this
average
will
be
rn
will
still
not
be
accur
r"
r
k
c
If
we
intend
must
multiply
each
before
averaging.
The
bias
relafed
to
the
number
of
sample
standard
deviation
standard
deviation;
it
is
rela
individual
sa
mpie
s
ta
nda
i
d
de
via
tio
n
s
tirnate
of
G,
the
as
correction
factor
t
the
average
sed
to
to
get
the
~~
An
Examole
Table
2
shows
data
in
which
the
standard
deviation
varies
with
t
h
e
average.
Our
purpose
is
to
find
an
empirical
relationship
between
S
and
the
sample
averages.'
For
N
=
2,
unbiased
S
=
1.253'
s.
3%
"
w,
'
F
&
I
klrd
1
I
Lr*
r
Table
2
Samo
le
Data
Ava.
c
1
893.7
1080.2
986.95
2
2240.4
2127.0
2183.70
3
2070.3
2219.7
2145.00
4
529.4
553.3
541.35
5
2351.1
2652.2
2501.65
6
358.9
342.7
350.80
1316.20
2434.95
2479.60
1434.80
743.6
655.9
699.75
1
3
960.3
1099.1
1030.00
1
5
247.2
297.6
272.40
16
1866.4
2247.1
2056.75
12
1356.8
1392.8
1374.
ao
1
4
1949.0
1803.1
1876.05
S
a
n
b
iS5
d
S
131.88
565.25
a
o
.
19
Z30.48
105.64
122.37
16.90
51.18
212.91
255.78
1
1
.
4
6
14
3
6
2
0
7
.
6
1
250.14
161.43
202.27
13.15
16.48
26.87
33.67
62.01
7
7
.
7
0
25.46
3
1
.
9
0
98.57
123.55.
103.17
129.27
35.64
4
4
.
6
6
269.20
337.31
Fig.
1
shows
the
relationship
between
S
and
Avg.
C.
Fig.
2
presents
the
same
data
in
Log
Log
coordinates.
The
nature
of
this
relationship
is
more
visible
in
Fig.
2
than
in
Fig.
1.
These
data
will
be
fit
to
the
rnqdel
p
after
linearizing
to
Ln(
S)
=
Ln(
k)
+
p*
tn(
C).
This
is
equivalent
to
working
in
Log
Log
coordinates
as
in
Fig.
2.
By
fitting
the
data
in
Table
2
to
Ln(
S)
=
Ln(
k)
+
p*
Ln(
C)
we
not
only
obtain
estimates
of
k
and
p
but
also
certain
statistics
that
tell
us
how
accurateiy
this
model
will
predict
G.
A
least
squares
analysis
of
these
data
is
shown
in
Table
3.
.
.
.
.
.
i
a
2
.
i
i
3
E
paae
8
0
0
0
0
0
0
rn
(
u
O
0
m
0
0
0
0
0
0
m
0
0
cu
rn
0
m
(
v
P
7
0
0
0
rc)
c3
0
w
B
L
c
[
,
r
l
El
!
j
iJ
P
L
i
'
c5
Y
p"
cn
P
2
9
LY
LJ
w
Table
3
RIT
0.05
&
0.01
=
2.17
&
2.98
VARIABLES
SH
OF
COEFF
T
0
Intercept
1
P
o
w
e
r
C
o
e
f
f
i
c
i
e
n
t
p
=
0
0.34030
2.15
RESSUMSQ
STDDEV
OF
RES
DF
12.16245
..
ics
I
n
Ln
U
n
i
t
s
In
O
r
i
a
i
n
a
l
Metr
OBSVD
PRED
RESID
STD
RES
O
b
s
e
r
v
e
d
P
r
e
d
i
c
t
e
d
D
i
f
f
.
68.69
96.56
1
5.107
4.230
0.878
0.94
165
2
5
2
4.610
4.810
0.200
0
.
2
1
100.48
122.73
22.25
3
4.886
4.797
0.089
0.10
132.37
121.14
11.23
4
3.053
3
.
7
9
1
0.738
0.79
21.18
44.29
23.11
5
5.586
4.909
0.677
0
.
7
3
266.78
135.55
131.23
6
2.664
3.474
0,809
0.87
14.36
32.25
17.89
7
5.561
4.440
1.121
1.20
8
5.310
4.890
0.420
0
.
4
5
9
2.802
4.903
2.101
2.25""
16.48
134.67
118.19
10
3.517
4.503
0.986
1.06
33.67
90.29
56.62
11
4.353
3.978
0.375
0.40
77.70
1
2
3.463
4.472
1.009
1.08
3
1
*
90
13
4.816
4
.
2
6
1
0.556
1
2
3
.
5
1
1
4
4.862
4.699
0.163
129.27
1
0
9
.
8
4
19.43
1
6
5.821
4,766
1.055
1.13
337.31
117.47
219.84
15
3.799
3.289
0.510
0
.
5
5
44.66
26.81
17.
as
RES
SUMSQ
FROM
REGRESSION
=
12.16245
RES
SUMSQ
DIRECT
=
12.16245
A
v
e
r
a
g
e
Observed
=
122.3331
A
v
e
r
a
g
e
P
r
e
d
i
c
t
e
d
=
89.5749
B
i
a
s
C
o
r
r
e
c
t
i
o
n
Factor
=
122.333
89.5749
=
1.3657
Ln(
S)
=
0.8093
+
0.731*
Ln(
C)
0.731
s
=
0.445.
c
ln
Table
3
the
observed
and
predicted
values
of
S
and
their
residuals
(
differences
between
observed
and
predicted)
are
shown
in
Ln
units,
then
in
their
original
metrics.
Sample
calculation:
From
Table
2,
first
row:
C
=
986.95
Spred
=
E~
p(
U.
8093)*
C*~
3~
=
0.445'
Co
737
=
68.69
(
Table
3)
The
average
of
the
observed
values
is
122.3331;
t
h
e
average
of
the
predicted
values
is
89.5749.
The
ratio
of
the
average
observed
to
average
predicted
is
122.3331/
89.5749
=
1.3657.
This
offset
or
bias
was
caused
by
linearizing
d
fitting
in
terms
of
Ln(
S)
followed
by
conversion
back
to
the
original
u
The
unbiased
model
for
predicting
CJ
from
C
is:
0.731
0.731
Est
G
=
1.3657*
0.445*
6
Or
Est
0
=
0.608.
C
where
Est
CY
is
an
unbiased
c
1
10
100
1000
BY
compare
for
other
estimate
of
sigma.
Fst
(
r
0.608
60.8%*
F(
sD
3
.
2
7
3
2
.
7
0
*
17.6%
9.5%
17.62
94
8
2
k
*
extrapolation
fitting
all
of
the
pollutant
data
to
consistent
models
we
can
model
coefficients
for
one
pollutant
against
model
coefficients
pollutants.
paae
12
vow
Good
is
This
Model?
The
answer
to
t
with
the
model.
Let`
model
building
process.
on
what
we
intend
to
do
T
CRIT
0.05
&
0.01
=
2.17
&
2
.
9
8
VARIABLES
F
COEFF
T
0
Intercept
1
Power
Coefficient
.
p
=
0.73084
.
0.34030
2.15
.
.
RESSUMSQ
STDDEV
OF
RES
DF
R
SQ
1
2
.
I6245
0.93207
1
4
0.2478
The
model
coefficients
are
0.8093
and
0.731.
SE
OF
COEFF
is
a
measure
of
how
well
we
have
estimated
the
coefficient,
p.
t
=
0.73087/
0.34031
=
2.15.
A
t
ratio
larger
abou
2
0
implies
we
have
detected
a
relationship
between
0;
and
C.
A
t
ratio
2
(
approx)
means
that
CT
is
not
a
constant,
but
is
associated
with
C.
substantially
larger
than
2.0
are
ecessary
to
a
coefficient.
The
reference
value
t
at
the
w
~
5
is
actually
2.1
5
.
See
the
line:
T
CRIT
0.05
&
0
.
1
7
Ed
2
9
8
.
So
our
observed
value
of
t
(
2.15
as
compared
to
the
reference
value
2.17)
is
"
right
on
the
edge".
However,
t
ratios
tely
estimate
a
model
5%
probability
level)
The
95%
confidence
interval
on
the
coefficient
p
is:
0.731
2.17*
0.340
or
from
0.00
to
1.47
which
suggests
that
the
true
coefficient
eo
d
be
as
small
as
"
zero"
(
implying
no
association
between
C
and
0)
r
as
large
as
1.47.
It
would
be
misleading
to
report
p
=
0.731
without
the
uncertainty
in
this
estimate.
If
we
compare
a
power
coefficie
r
one
pollutant
to
that
of
another,
we
must
recognize
that
when
t
or
P
is
modest,
th
confidence
interval
on
that
value
of
p
m
R
SQ
(
R
squared)
=
0.2478
means
this
model
explains
4778%
of
the
variation
in
t
h
e
data.
STDDEV
OF`
RES
is
t
h
e
standard
deviations
of
residuals.
This
is
t
h
e
standard
deviation
of
the
differences
between
observed
and
predicted
values
in
Ln(
S)
units.
This
is
not
an
estimate
of
0,
STDDEV
OF
RES
is
a
measure
of
variation
among
values
of
Ln(
S).
It
is
also
an
estimate
of
the
standard
deviation
that
we
would
find
if
we
could
run
replicate
tests
under
a
fixed
set
of
conditions
and
report
the
variation
among
values
of
Ln(
S).
In
this
context
"
the
data"
is
in
terms
of
Ln(
S).
paae
13
A
logical
extension
to
this
would
be
to
inquire
"
how
good
is
a
prediction
made
from
this
model?"
This
suggests
we
will
calcuiate
the
unbiased
estimate
of
C
(
Est
0)
for
a
fixed
value
of
C....
then
calculate
a
confidence
interval
on
that
predicted
value.
Before
doing
this,
here
are
two
values
that
we
will
need.
One
of
these
is
the
average
of
Ln(
C)
and
the
other
is
average
of
the
L
(
s).
Avg(
LnC)
7,1116.
Avg(
LnS)
=
4,3881.
The
confidence
interval
on
Est
CT
is
best
found
by
re
stating
the
model
in
a
different
format:
Original
Format:
Ln(
Est
CT)
=
0.8093
+
0.731*
Ln(
C)
New
Format:
Ln(
Est
0)
=
Avg(
LnS)
+
0.731*[
Ln(
C)
Avg(
LnC)]
New
Format:
Ln(
Est
o)
=
4.3881
+
0.731*[
Ln(
C)
7.11161
The
variance
of
a
prediction
of
Ln(
o)
is:
Var(
Lno)
=
[
StdDev
of
Res12/
N
+
[
SE(
Coeff)
12*[
Ln(
C)
7.1
11
6j2
Eq.
1
Table
vslue
of
t
I
T
CRIT
0.05
&
0.01
=
2.17
I
&
2.98
VARIIBLES
COEFFICIENTS
SE
OF
COEFF
T
RATIO
I
0
Intercept
0,80
932
RESSUMSQ
STDDEV
OF
RES
DF
R
SQ
12.16245
0.93207
14
0.2478
1
Power
Coefficient
p
=
0.73084
0.34030
2.15
I
I
I
t
ratio
calculated
r
N
=
1
6
f
r
o
m
data
L*
i
Var(
Lno)
=
[
0.9321
]*/
I6
+
[
0.3403]**[
Ln(
C)
7.1
1
16J2
Var(
Lncr)
=
0.0543
+
O.
l158*[
Ln(
C)
7.111612
P
LA
SE(
Lno)
=
dVar(
Lno)
predicted
value
of
Lno,
also
called
the
standard
error
of
This
is
the
standard
deviation
of
the
prediction.
See
note
at
the
bottom
of
page
14.
_.
"~
paae
14
Here
is
t
h
e
sequence
for
calculating
a
95%
confidence
interval
on
CT:
Step
1:
Calculate
the
predicted
valu
either
of:
Ln(
Est
CT)
=
0.
Ln(
Est
a)
=
4.3881
+.
0.731*[
Ln(
C)
7.1
1161
SE(
Est
0)
=
dVar(
Est
0)
See
footnote.
Step
3:
The
95%
confidence
interval
on
Ln(
Est
0)
is
then
Ln(
Est
G)
t*
SE(
Est
)
where
t
is
the
table
or
reference
value
of
t
at
the
0.05
level
of
significance.
t
=
2.17
in
this
instance.
r
L'
Step
4:
Revert
to
the
orig
I
units
and
the
unbiased
estimates:
Take
antiin
of
Est
CT
Take
antiLn
of
the
lower
bound
Take
antiLn
of
the
upper
bound
Multiply
Est
0,
the
lower
bound,
and
the
upper
bound
by
the
bias
correction
factor
1.3657
Est
G
and
t
h
e
95%
confide
e
On
are
shown
in
4
The
expression
Standard
Error
(
Symbol:
SE)
means
the
Standard
deviation
Of
a
StatiStiC.
Literally,
the
standard
deviation
of
a
value
calculated
from
data.
This
is
Stan
designed
to
keep
issues
about
"
t
~
e
standard
deviation"
(
calculated
from
"
the
from
issues
about
the
standard
deviation
of
other
quantities
calculated
from
data.
4
LOWlS
U?
p?
Z
A
V
P
T
;
I
~
~
C
LiFir
t
s
t
CT
Limbic
10
0
.
c93
3.254
118.073
20
0.249
5
.
4
2
5
118.174
50
0.946
10.600
118.756
100
2.583
17.594
119.830
500
24.797
57.058
131.283
1000
55.878
94.704
160.5C9
zoao
84.433
151.189
292.637
200
6.979
29.203
122.537
5000
96.804
307.125
974.353
A
graphical
analysis
of
this
table
is
presented
in
Fig.
3.
Minimiz,
ina
t
h
e
Width
of
the
Confidence
Interval
Equation
1
(
repeated
here)
determines
the
width
of
the
confidence
interval
'
on
the
estimated
value
of
sigma,
Est
G.
Var(
Est
a>
=
[
StdDev
of
ResI2/
N
+
[
SE(
Coeff)]**[
Ln(
C)
AvgLn(
C)]'
Eq.
1
Whereas
Est
CT
is
a
measure
of
variation
due
to
sampling
and
analyzing,
the
StdDev
of
Res
(
standard
deviation
of
residuals)
is
a
measure
of
the
variation
among
individual
values
of
LnfS).
Reducing
the
variation
in
sampling
and
analysis
methods
would
reduce
t
h
e
magnitude
of
probably
reduce
StdDev
of
Res
as
well.
A
reduction
in
StdOev
reduce
the
width
of
the
confidence
intervals.
N
is
the
"
number
of
tests"
(
number
of
duplicates,
triplicates,
quads,
etc.);
literally
t
h
e
number
of
rows
in
the
data
table
from
which
we
fit
S
vs
C.
Increasing
N
will
decrease
[
StdDev
of
Res]*/
N
and
will
therefore
decrease
the
width
of
the
confidence
interval.
SE(
Coeff)
is
strongly
influenced
by
the
span
of
t
h
e
data
along
the
scale
of
C,
the
concentration
of
a
pollutant.
Varying
C
over
a
wide
range
will
decrease
SE(
Coeff)
and
will
therefore
decrease
the
width
of
the
confidence
interval.
concentrated
at
a
"
low
value
of
C"
and
one
half
of
the
data
are
concentrated
at
a
"
high
value
of
C",
then
SEfCoeff)
will
be
minimized.
SE(
Coeff)
is
also
reduced
by
increasing
N
and
by
reducing
StdDev
of
Res.
Furthermore,
if
about
one
haif
of
the
data
are
[
Ln(
C)
AvgLn(
C)
J2
is
a
function
of
where
the
prediction
is
being
g
the
scale
of
C.
When
a
prediction
is
made
at
the
centroid
of
tn(
C)
=
AvgLn(
C)
and
this
term
goes
to
zero.
When
this
is
so,
then
Var(
Est
0)
=
[
StdOev
of
Res]*/
N.
This
means
that
the
width
of
the
confidence
interval
will
be
minimized
when
predictions
are
made
at
the
centroid
of
Ln(
C).
.
The
best
way
to
visualize
this
is
with
an
example
in
which
data
are
concentrated
at
two
points
on
the
scale
of
C.
The
data
in
Table
5
are
simulated
data
from
the
same
source
as
the
foregoing
example.
Data
Sample
1
243.3
2
5
3
.
6
2
237.3
233.7
3
151.1
143.5
4
2p0.4
216.6
5
1
7
3
.
1
207.6
6
141.8
159.0
7
233.2
208.4
8
139.9
153.6
9
1733.4
1828.4
10
2022.6
1754.9
11
2127.9
2014.9
12
2064.0
2047.6
13
2016.6
1934.1
1
4
1s
1
6
2003.9
1808.6
Ava.
C
s
147.36
5.37
248.45
7.28
235.50
2.55
233.50
23.90
190.35
24.40
150.40
12.16
220.80
17.54
146.75
9.69
67.18
1780.90
1888.75
189.29
2071.40
79.90
2055.80
11.60
1975.35
58.34
1822
.)
2
0
77.78
2326.75
233.98
1906.25
138.10
gzbiased
s
9.12
3.20
6.73
29.95
30.57
15.24
21.98
12.14
84.18
237.18
100.11
14.53
73.10
97.46
293.18
173.04
I
is,
Table
6
is
t
h
e
feast
squares
analysis
of
the
data
in
Table
5.
The
relationship
between
S
and
C
is
shown
in
Figures
4
and
5.
i
x
I
I
L
Se
are
equivalent
to
the
lower
and
upper
95%
confidence
!
inten/
af
on
the
slope
in
Ln
Ln
coordinates;
i.
e.,
on
the
model
coefficient
p.
Recall
that
the
,
L
lower
limit
on
p
was
0.00;
hence
"
A"
is
horizontal.
This
may
aid
in
seeing
how
the
imprecision
in
estimating
the
slope
impacts
the
confidence
interval
on
predicted
values
of
sigma.
This
imprecision
in
estimating
the
slope
is
reported
as
SE
of
Coeff.
pz"*
i
paae
18
.
.
.
.
i
f?
~
i
~
~
~.
~
~
__
paae
20
T
a
b
l
e
6
T
a
b
l
e
=
slue
of
t
I
T
CRIT
0.05
&
0.01
=
2.17
&
2.98
VAR
IA9
LES
COEFFICIENTS
SE
OF
COE?
F
T
RATIO
0
Intercep
I
1
Power
Co
0
18436
4.73
RESSUMsQ
STDDEV
OF
RES
I
.
"
10.51455
I
fficient
p
=
.
.
I
t
r
a
t
i
o
calculated
StdDev
of
Res
N
=
16
from
data
I
n
Ln
U
n
i
t
s
I
n
Oriainal
Metrics
OBSVD
PRSD
RESID
STD
RES
O
b
s
e
r
v
e
d
Predicted
D
i
f
f
.
1
2.210
2.791
0.580
0.67
9.1
16.29
7.17
2
1.163
2.744
1.581
1.82
3.20
15.55
12.35
3
1.907
2.335
0.429
0.49
6.73
10.33
3.60
15.43
14
52
4
3.400
2.737
0.663
0.76
29.95
5
3.420
2.559
0.861
0.99
30.57
12.92
1
7
.
6
5
6
2.724
2.353
0.371
0.4
15.24
io.
52
4
72
7
3.090
2.688
0.402
0
4
21.98
'
14.70
7.28
8
2.497
2.332
0.164
0.19
12.14
10.30
1.84
9
4.433
4.506
0.0t3
0.08
84.18
90.60
6.42
10
5.469
4.558
0.911
1.05
237.18
95.36
141.82
If
4.606
4.638
0.032
0.04
100.11
103.34
3.23
12
2.676
4.631
1.955
2.26**
14.53
102.66
88.13
73.10
99.16
26.06
13
4.292
4.597
0.305
0.35
14
4.579
4.526
0.053
0.06
92.42
5.04
15
5.681
4.739
0.941
1.09
114.36
178.82
16
5.154
4.566
0.588
68
173.04
96.13
76.91
RES
SUMSQ
FROM
REGXESSION
=
10.51455
RES
SUMSQ
DIRECT
=
10.51456
Average
O
b
s
e
r
v
e
d
=
75.1069
A
v
e
r
a
g
e
P
r
e
d
i
c
t
e
d
=
56.2545
B
i
a
s
Correction
Factor
=
75.1069/
56.2545
=
1.3351
0.871
Est
c
=
1.3351'
0.1335*
C
t
r
t
0.871
Est
CJi
=
0.178'
C
The
95%
confidence
interval
on
p
is:
an
improvement
over
0.00
to
1.47
in
the
previous
example,
New
Format:
Ln(
Est
G)
=
Savg
+
0.8712*[
Ln(
C)
Cavg]
New
Format:
Ln(
Est
0)
=
3.58126
+
0.8712+[
Ln(
C)
6.422821
The
variance
of
a
prediction
is
(
Eq.
1
is
repeated
here):
Var(
Est
0)
=
[
StdDev
of
Res]'/
N
+
[
SE(
Coeff)
J2"[
Ln(
C)
Avg
of
Ln(
C)
l2
Eq.
1
t
0)
=
[
0.86S63J2/
16
+
[
0.18436j2'[
Ln(
C)
6.422821'
Var(
Est
0
)
=
0.04694
+
0.0344*[
Ln(
C)
6.42282J2
Note
that
lSE(
Coeff)]*
=
0.0344
compared
to
0.1158
in
the
previous
exampfe.
By
concentrating
data
at
the
extremes
of
the
experimental
space
~
the
width
of
the
confidence
interval
has
been
reduced
significantly.
Est
oand
the
95%
con
ence
on
are
shown
in
Tab,
e
7.
Table
7
Lower
Averace
c
.
L
i
m
i
t
10
0.236
20
0.564
50
1.765
100
4.125
500
24.812
1000
43.978
5000
113.262
200
9.375
2000
68.641
1:
324
2.422
5.381
9.843
18.004
40.000
73.
1
6
7
133.836
297.342
Upper
Limit
7.421
10.400
16.402
23.484
34.577
64.235
121.723
260.95:
780.600
A
graphical
analysis
of
Table
7
is
presented
in
Figure
6
.
..
e
.
I
v3
O
I
I
I
0
0
paae
22
The
simulated
data
used
in
these
examples
(
Tables
2
and
5)
came
from
this
model:
0
=
0.28*
C0*
8.
The
value
of
C
was
varied
randomly
in
Table
2
and
varie
domly
around
two
points
on
the
scale
of
C
in
Table
5.
calculated
from
C;
from
a
Source
with
mean
C
and
n
0,
two
random
normal
numbers
were
generated;
those
numbers
are
the
data.
This
process
was
repeated
16
times.
When
C
=
100
the
true
RSD
=
11
.
WO;
when
C
=
1000
the
true
RSD
=
7.0%.
These
levels
of
ical
of
those
encountered
in
the
analysis
of
t
h
e
actual
The
model
derived
from
data
in
the
first
simulation
(
Tabfe
2)
is
Est
a
=
0.608*
C0*
73'
The
95%
confidence
interval
on
p
is
0.00
to
1.47.
The
model
derived
from
data
in
the
second
simulation
(
Table
5)
is
Est
0
=
0.178*
C0
871
The
95%
confidence
interval
on
p
is
0.47
to
1.27.
With
this
in
mind,
here
are
some
important
conclusions.
Even
when
simultaneously
sampled
data
come
from
a
"
perfect"
situ
ation
such
that:
e>
the
underlying
model
is
exact
and
the
data
are
contaminated
only
by
random
variation
C>
there
are
no
concerns
about
sample
contamination,
selective
or
biased
sampling
of
particles,
or
other
"
special
causesy'
finding
a
relationship
between
Est
CT
and
the
average
concentration
C
yields
model
coefficients
and
predictions
that
are
subject
to
statist
ica
1
u
nc
e
rt
ai
n
t
y
.
The
evidence
of
this
uncertainly
is
illustrated
by
the
fact
that
two
sets
of
data
from
a
"
perfect
situation"
produce
models
that
have
different
coefficients
and
therefore
different
estimates
of
Est
CF
as
a
function
of
the
average
concentration
C.
.
SE(
Coeff)
is
a
major
contributor
to
wide
confidence
intervals
Although
not
discussed
in
detail
here,
SE(
Coeff)
is
on
Est
0.
strongly
influenced
by
(
1)
the
allocation
of
experimental
points
along
the
scale
of
C;
(
2)
the
amount
of
data:
and
(
3)
the
inherent
variation
in
t
h
e
data.
Weiqhted
Rearession
Although
the
majorit
samples
with
octets.
Reca
When
those
values
are
derived
fro
should
be
weighted
in
acc
information
in
each
value
As
a
rule,
t
h
e
qua
21
there
were
insta
is
Q
=
Sum
of
W,
t(
S,
pred
Si)
2
where
Si
is
an
observed
standard
deviation;
pred
Si
is
the
predicted
is
the
weight
assigned
to
the
i
th
inversely
proportional
to
the
varia
approximation,
Minimize
Q
=
Sum
of
(
1/
Var
Si)'(
Si
pred
Si)
2
The
variance
of
Si
is
(
an
approximation)
proportional
to
O
be
assigned
to
each
servations
used
to
a
as
The
eight
assigned
to
each
of
that
standard
deviation;
and
Wi
weights
should
be
1/[
2(
N
I)].
Thus
the
re1
is
2(
N
1)
where
N
is
th
given
value
of
S.
This
is
observed
valu
freedom
associated
with
that
value
of
S.
If
N
=
2
the
weight
is
1.
If
N
=
3
the
weight
is
2,
etc.
unweighted
regre
)
But
the
for
weighted
regression
are
s
the
confidence
intervals
requires
For
these
reasons
we
reco
regression
be
used
for
this
Of
to
just
the
number
of
degrees
of
The
calculations
for
weighted
regression
to
those
for
In
particular,
calculating
matrix
Operations
e
designed
for
weighted
Errors.
Outliers,
and
Mavericks
paae
25
Questionable
data
is
given
a
diversity
of
names,
such
as
mavericks
fliers,
outliers,
sports,
and
blunders.
These
aberrations
can
be
caused
by
contamination
of
samples,
switched
or
mislabeled
samplss,
faulty
equipment
or
reagents,
key
entry
errors,
and
a
host
of
other
events.
Such
data
is
a
source
of
frustration,
and
often
causes
pointless
discussions
and
wasted
effort.
Some
statistical
criteria
are
available
to
assist
in
learning
whether
or
not
the
largest
or
smallest
observation
is
significantly
far
removed
from
the
main
body
of
the
data.
1
In
this
section
we
will
address
this
matter
from
two
perspectives.
The
first
of
these
is
an
omnibus
examination
of
all
of
the
data
in
one
pass.
The
other
is
more
focused,
and
addresses
only
one
triplicate
or
quad.
Table
8
was
derived
from
Table
5.
The
data
were
broken
into
two
categories...
low
C
and
high
C...
with
the
expectation
that
variation
will
be
constant
(
or
virtually
constant)
at
low
C
and
that
variation
will
be
constant
at
high
C.
Of
course
we
expect
that
variation
will
change
between
low
C
and
high
C,
which
was
the
point
to
breaking
the
table
into
these
two
categories.
Ranae
Ava,
C
248.45
10.3
1
243.3
253.6
3.6
2
237.3
233.7
235.50
147.30
7.6
3
151.1
143.5
233.50
33.8
4
250.4
216.6
5
173.1
207.6
150.40
17.2
6
141.8.
159.0
220.80
24.8
7
233.2
208.4
146.75
13.7
8
139.9
153.6
Data
SamDle
190.35
34.5
Avg
Range
=
18.19
9
1733.4
1828.4
1780.90
95.0
10
2022.6
1754.9
1888.75
267.7
11
2127.9
2014.9
2071.40
113.0
12
2064.0
2047.6
2055.80
16.4
13
2016.6.
1934.1
1975.35
82.
i
15
2161.3
2492.2
2326.75
330.9
16
2003.9
1808.6
1906.25
195.3
14
1877.2
1757.2
1822.20
110.0
Avg
3an'ge
=
151.35
The
range
is
shown
for
each
simultaneous
sample.
The
average
range
is
reported
for
each
of
the
two
groups.
In
Statistical
Process
Co
whether
any
of
these
ranges
a
quads
we
only
test
for
abnor
small
ranges
is
not
meaningful.
determine
whether
any
of
the
ra
s
customary
to
test
.
.
.
.
.
.
.
,
.
.
.
.
SamDle
Size,
n
2
4
2
3
.
2
6
7
3
2
.
5
7
5
4
2
2
8
2
5
2
.
1
1
5
Step
1:
The
data
used
to
calculate
ranges
were
duplicates.
The
sample
size
is
n
=
2.
Step
2:
Multiply
the
average
range
by
0,
for
each
category.
3.267
x
18.19
=
59.4
3.
151.35
=
494*
5
Step
3:
Compare
t
dividual
ranges
ag
these
limits.
When
C
is
ranges
larger
than
are
suspect.
When
C
is
questionable.
t
ges
larger
than
494.4
are
All
of
the
ranges
passed
the
test.
re
is
no
evidence
for
any
of
the
data.
WC
t
t
Now
let's
consider
how
t
data
was
not
concentrated
at
t
derived
from
Table
2.
Table
10
is
ran
ed
to
a
in
ca'e
Of
c.
Ta
and
then
broken
into
three
cat
ego
ries
.
r
t
*
F
k
Fm
247.2
297.6
358.9
342.7
743.6
655.9
893.7
1080.2
529.4
553.3
960.3
1099.7
7
1
4
6
3
.
0
1169.4
12
1356.8
1392.8
10
1415.8
1453.8
1
4
1949.0
1803.1
!
1
6
1865.4
2247.1
3
2070.3
2219.7
r
2
2240.4
2127.0
Lw
8
2
5
4
9
.
1
2320.8
9
2488.9
2470.3
5
2
3
5
1
.
1
2652.2
L
,
The
rules
are
applied
as
before.
i
I
L
c
t
9vrJ.
c
3.
a
?.?
a
350.80
15.2
272.40
5
3
.
4
541.35
23.9
699.75
87.7
985.95
185.5
72.94
=
k
v
g
Range
1030.00
1316.20
1374.80
1434.80
1
8
7
5
.
0
5
130
139.4
293.6
35.3
3
8
.
0
145.9
58
=
&..
g
R
a
n
g
e
2056.75
380.7
2145.00
149.4
2183.70
113.4
2434.95
228.3
2479.50
18.6
2501.65
301.1
238.22
=
Avg
R
a
n
g
e
Step
1:
The
data
used
to
calculate
ranges
were
duplicates.
The
sample
size
is
n
=
2.
D,
=
3.267
Step
2:
Multiply
the
average
range
by
0,
for
each
category.
3.267
x
72.94
=
238.3
3.267
x
130.58
=
426.6
3.267
x
238.22
=
778.3
Step
3:
Compare
the
individual
ranges
against
these
limits
category
by
category
as
before.
F
n
i
any
of
the
data.
.
AI1
of
the
ranges
passed
the
test.
There
is
no
evidence
for
excluding
L
as
an
exam
n
using
this
If
there
are
gaps
in
the
ranke
categories
at
those
points.
There
i
of
data
will
be
in
each
category.
ctice
we
should
average
C,
then
break
the
data
into
ement
that
t
h
e
same
amount
.
The
extension
of
this
t
quads
only
requires
using
.
.
other
values
of
D4.
n
If
we
examine
only
one
set
or
triplicates
or
quads,
then
Dixon's
r
procedure
is
appropriate.'
Consider
the
following
sirnultaneo
ly
data:
22.3
29.4
49.1
28.2
Step
1:
Rank
the
data
from
smallest
to
largest:
=
(
49
1
29
4M49.1
23
8)
23.8
28.2
29.4
49.1
Step
2:
Calculat
r
=
0.779
Table
11
P
o
95
P
o
.
99
n
3
0.941
0.988
4
0.765
0.889
5
0
I
642
0.780
Step
3:
The
sample
size
n
=
4.
Step
4:
The
calculated
value
r
than
Po.
95
(
POag5
=
0.765).
The
evidence
suggests
that
the
remainder
Of
Ihe
data*
If
the
calculated
value
of
r
exceeds
the
table
value
at
Po.
99
then
the
evidence
is
even
stronger.
_.
'
Dixon,
W.
J.
and
Massey,
F.
J.;
Introduction
to
StatisticaI
Analysis,
3rd
Ed.;
McGraw
Hill;
1969.
pages
328
330.
p
t
h
F
1
f
L
.
Dixon's
r
is
of
the
form:
r
=
(
Distance
between
the
largest
and
its
nearest
neighbor)/(
Full
Range
of
the
data.)
This
can
be
arranged
to
inquire
about
the
status
of
a
number
that
is
unusually
low
when
compared
to
the
remainder
of
the
data.
Examole:
121
179
185
193
r
=
(
179
121)/(
193
121)
=
0.805
This
is
farger
than
the
table
value
of
r
(
0.765)
with
n
=
4.
So
the
121
is
inconsistent
with
the
remainder
of
the
data.
Dixon's
r
cannot
be
used
with
n
=
2
data.
It
assumes
the
data
came
from
a
normal
distribution.
This
is
a
reasonable
assumption
with
simultaneously
sampled
concentration
data.
See
Table
2
test
9
and
Fig.
2.
S
=
16/
48
seems
to
be
unusually
low.
This
is
also
appears
as
a
I
small
samples
(
espe
standard
deviation
to
of
duplicates
s
may
even
be
"
zero"
occasionally.
So
even
though
these
may
seem
unusual,
they
are
not.
/
Iy
duplicates
and
triads)
is
is
very
low.
In
the
for
the
paae
30
A
power
law
model
was
used
throughout
this
report
because
the
data
will
not
support
more
than
two
There
may
be
instances
in
which
we
will
need
to
entertain
other
model
forms.
For
example,
please
draw
curve
to
expr
relationship
between
S
and
C
in
Fig.
7.
efore
proceedi
The
relationship
between
S
and
coordinates.
It
is
reasonable
to
con
model,
perhaps
S
=
a
i
kCP.
In
S
wifl
approach
a
when
C
=
0.
This
suggests
the
does
not
seem
to
be
linear
in
LkLn
Before
we
begin
setting
up
the
tools
to
estimat
a,
k,
and
p
in
this
extended
model,
we
should
work
through
the
1.
Test
the
data
to
deter
ther
the
appearance
of
curvature
(
in
Ln
Ln
coordinates)
is
"
real"
o
hance
variation
data.
If
the
perceived
curvatu
to
random
va
the
data
...
and
not
a
syst
then
attempting
to
fit
thes
will
be
misleading
and
disapp
transforming
to
t
n
L
n
coordinates,
of
course.
he
test
for
curvature
after
2.
The
most
direct
way
to
test
for
curvature
is
to
fit
the
data
to
the
usual
power
faw
model
...
Ln(
S)
=
Ln(
k)
i
pLn(
C)
...
then
ask
whether
there
is
evidence
of
"
lack
of
fit".
This
is
easily
done
by
testing
to
see
whether
the
data
will
support
adding
associated
with
b
is
larger
than
the
appropriate
reference
value
of
the
t
ratio
(
as
a
rule,
larger
than
21,
then
there
is
evidence
of
curvature;
the
simple
power
law
model
is
not
adequate.
If
the
t
ratio
associated
with
b
is
notably
smaller
than
2,
there
is
no
fir
evidence
of
curvature;
the
power
law
model
is
adequate;
attempting
to
f
t
h
e
data
to
a
more
.
complex
model
to
account
for
curvature
is
pointless
and
misleading.
b[
Ln(
C)
I2
to
the
model.
If
the
t
ratio
3.
The
purpose
of
(
2)
above
is
not
to
build
a
completed
model.
The
purpose
is
to
test
for
the
presence
of
curvature
beyond
that
which
is
accommodated
by
the
power
law
model.
If
curvature
is
detected
(
t
ratio
for
b
is
larger
than,
say,
2),
then
we
may
be
justified
in
considering
an
alternative
model.
S
=
a
+
kCp
would
be
a
candidate.
F"
L
F
!
U
0
0
P
0
0
T
O
T
0
0
0
0
0
r
M
p
paae
32
This
process
was
followed
to
make
that
judgement
about
these
data.
AS
A
S
248.5
7.28
2375.0
58.34
235.5
2.55
1622.0
77.78
147.3
5
37
234.0
233.5
23.9
24.4
150.4
12.16
.
220.8
.
17.54
146.7
9.69
1281.0
67.18
2189.0
189.29
2071.0
7
9
.
9
2056.0
11.6
1906.0
138.1
18.6
6.48
26.
1.19
.
23.
5.18
32.4
12.06
34.6
3.12
39.6
12.82
45.7
2.96
4
8
.
9
7
.
1
0
In
Fig.
8
t
h
e
power
law
mod
explained
66.5%
of
the
variation
in
Ln(
S).
In
Fig.
9
the
model
was
extended
by
adding
a
as
suggested
on
page
30.
This
extended
model
expla
variation
in
Ln(
S).
coefficient;
this
increas
in
R
sq
does
not
is
important.
The
t
ra
ratic
term
is
an
indication
of
whether
that
term
is
a
w
to
the
model.
adratic
coefficient
69.2%
of
the
R
sq
will
always
increas
when
we
add
another
model
rove
that
the
quadratic
term
The
t
ratio
for
t
h
e
quadratic
coefficient
is
on
3
6
;
far
below
the
reference
value
of
2.08
(
with
we
do
not
have
sufficient
evi
power
law
model
S
=
kCP.
What
have
come
from
a
straight
line
rela
This
does
not
mean
we
have
"
prove
relationship
prevails
in
Ln
Ln
coordin
evidence
in
favor
of
a
more
complex
justification
for
adding
a
quadratic
term
to
little
justification
for
pursuing
an
alternative
model
such
as
S
=
a
+
kCP.
It
is
possible
t
h
a
t
with
additional
data
we
may
learn
that
curvature
is
actually
present,
and
that
an
extended
model
form
was
justified.
attempting
to
build
a
model
more
complex
than
S
=
kCp
is
not
appropriate
with
the
existing
data.
(
say,
S
=
a
+
kCp)..
then
the
coefficients
in
that
model
will
be
poorly
estimated;
the
confidence
intervals
on
those
coefficients
will
be
extremely
wide;
and
we
have
gained
nothing
more
than
t
h
e
satisfaction
of
explaining
a
little
more
of
t
h
e
variation
in
t
h
e
data.
But
If
we
pursue
this
...
if
we
build
an
extended
model
Figure
8
page
33
smm.
2
Dstenninant
=
1.0000
mi?.
1
GOING
IN
VX?
IABUS
comrcms
SE
OF
am
T
IIATIO
T
CFUT
0.05
&
0.01
=
2.07
&
2.80
0
Intercept
2.77468
1
average
conc
0
.
68217
0.10316
6.61
ESSUMSQ
S?
pDEvOFRES
DF
R
SQ
16.02539
0.85348
22
0.6653
<
66.5%
In
In
Units
In
Original
Units
OBSVD
PREl
RESID
STD
RES
Observed
Pr&
i.
ct&
Diff
1.985
2.826
0.841
0.99
7.28
16.88
9.60
0.936
2.789
1.853
2.17
1.681
2.469
0.789
0.92
5.37
11.82
6
45
3.174
2.784
0.390
0.46
23.90
16.18
7.72
3.195
2.644
0.550
0.64
24.40
14.08
10
.
32
2.498
2.484
0.015
0.02
12.16
If.
98
0.18
2.864
2.746
0.119
0.14
17.54
15.57
1.97
2.271
2.467
0.196
0.23
9.69
11.78
2
.
09
4.207
3.945
0.263
0.31
67.18
51
.
67
15
.
51
5.243
4.310
0.933
1.09
189.29
74.47
114.82
4.381
4.273
0.108
0.13
79.90
71.71
8
19
2.451
4.268
1.817
2.13
11.60
71.35
59.7
4.066
4.366
0.300
0.35
58.34
78.73
20.3
4.354
4.106
0.248
0.29
77.78
60.70
17.08
5.4
4.352
1.104
1.29
234.00
77.62
156.38
16
0.712
0.83
138.10
67.76
70.34
1.869
1.058
0.811
0.95
0.174
1.294
1.120
1.31
1
645
1.312
0.333
0.39
2
40
1.436
1.054
1.23
1.138
1.481
0.343
0.40
2,551
1.573
0.978
1.15
1.085
1.686
0.601
0.70
1.960
1.717
0.243
0.28
2.55
16.27
13.72**
s
SQSQ
FEicM
REQESSION
=
16.02539
RES
rage
&.
served
=
42.0829
Average
Predi
Figure
9
page
34
s
w
m
.
3
Determinant
=
0.9
WRLABLES
S
SE
OF
EEET
T
EAT10
=
2*
08
6r
2*
82
0
Intercept
1
average
conc
6.39
2
quadratic
0.08073
1.36
<
14.12537
0.83738
21
0.6924
69.2%
.
.
66.5%
.
=
2.7%
_
.
RESSUJSQ
STDDEVOFWS
DF
R
SQ
Note
Ln(
S)
=
2.461
+
0.657*(
Ln(
C)
5.44)
+
O.
ll*(
Ln(
C)
5.44)
sq
1
2
3
4
5
6
I
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
In
Ln
U
n
i
t
s
In
Original
Units
OBSVD
PPED
RESID
STDRES
Observed
Predicted
D
i
f
f
1.985
2.511
0.526
0.63
7.28
12.32
5.04
1.681
2.
0.508
0.61
5.37
8.93
3.56
3.174
2.470
0.
23.90
11.82
12
.
08
24.40
10.38
14.02
12.16
9.03
3.13
2.864
2.433
0
17.54
11..
40
6.14
2.271
2.187
0
9.69
8.91
0
78
4.207
3.912
0.295
0.35
67
.
18
50.01
17.17
5.243
4,498
0.745
0.
189.29
89.83
99.46
4.381
4.434
79.90
84.31
4
.
41
2.451
4.426
11.60
83.61
72.01**
~
4.066
4.593
58.34
98.76
40
.
42
4.354
4.162
77*
78
64.23
13.55
5.455
4.568
0.887
1.06
234.00
96.38
137.62
4.928
4.341
0.
0.70
138.10
76.75
61.35
1.869
1.503
0.
6.48
4.50
1.98
1.645
1.557
0.
5.18
4.75
0.43
2.490
1,595
0.895
1.07
12
.
06
4.93
7.13
1.138
1.610
0.472
0.56
3.12
5.00
1.88
2.551
1.645
0.906
1.08
12.82
5.18
7.64
1.085
1.692
0.607
0.72
2.96
5.43
2.47
1.960
1.706
0
5
51
1.59
0.936
2.476
1.539
1.84
2.55
11.89
9
.
34
0.174
1.552
1.
1.19
4.72
3
.
53
EES
SmSQ
rn
REGRESSION
Average
Cbserved
=
42,0829
D
I
E
C
T
=
14.72535
Average
Predicted
=
32.0234
lxLaa5
The
foregoing
data
can
be
fit
directly
to
a
model
of
the
form
S
=
a
+
kCP
using
t
h
e
following
technique.
Set
p
to
a
constant
(
say,
0.6)
and
fit
S
=
a
+
kC0.6.
Since
this
model
is
linear
in
the
coefficients
a
and
k,
ordinary
least
squares
methods
can
be
used
to
estimate
those
coefficients.
Repeat
this
process
for
p
=
0.8,
1.0,
etc.
When
this
is
done:
0
a
k
Resi&
zl
Sum
S
a
0.6
10.27
1.24
40.52
0.8
1.61
0.25
39.96
1.0
2.95
0.053
39.66
1.2
5.60
0.012
39
50
1.4
7.26
0.0024
39.43
1.6
8.39
0.00052
39.41
The
coefficient
a
is
an
estimate
of
(
r
when
C
=
0.
Negative
values
of
a
imply
that
CT
becomes
negative
as
the
average
concentration
approaches
zero.
So
p
c
1
is
certainly
not
acceptable.
The
residual
SUM
of
squares
...
a
direct
measure
of
how
well
a
model
explains
the
variation
in
S,
is
insensitive
to
the
least
squares
combinations
of
a,
k,
and
p.
The
estimates
o
f
all
three
coefficients
are
highly
correlated.
minimizes
the
r
er.
This
m
very
wide.
This
will
happen
when
the
data
is
not
cap
There
is
no
unique
combination
of
coefficients
`
that
ual
sum
of
squares;
one
combination
is
as
good
as
any
that
the
confidence
intervals
on
the
model
coefficients
of
accurately
able
situation
estimating
the
coefficients
in
the
residual
s
u
m
of
squares
I{
have
a
"
sharp"
well
defined
minimum.
The
underlying
chemistry
or
physics
may
suggest
that
G
converges
to
a
iimit
greater
than
zero;
Fig.
7
suggests
this.
What
harm
is
done
by
fitting
the
S
vs.
C
data
to
a
model
...
viz.,
S
=
a
+
kC
p...
that
supports
this
theory
about
the
lower
bound
on
o?
That
depends
on
t
h
e
definition
of
harm.
The
prior
analysis
showed
there
is
insufficient
evidence
to
support
"
curvature"
in
Ln
Ln
coordinates.
If
an
alternative
model
is
used
to
claim
that
t
h
e
data
follows
a
certain
theory,
when
in
fact
the
model
coefficient
that
wouJd
support
that
theory
is
not
supported
by
the
data,
then
that
is
a
poorly
founded
claim.
The
resolution
to
this
is
to
g.
et
data
.
that
wilt
rr
properly
test
theory;
in
this
instance,
iet
data
at
very
low
levels
of
C.
In
any
event,
confidence
intervals
on
a,
k,
and
p
should
be
repofied.
,
h
np
paae
36
The
Performance
of
t
h
e
ReMAP
Process
The
ReMAP
process
i
ing
relationships
between
estimates
of
sigm
degrees
of
freedo
derived
from
small
samples
process
can
be
found
in
text
statistical
procedure.
It
is
ther
the
ReMAP.
process
perform
Monte
Carlo
simulati
ReMAP
process.
By
perfu
intervals
on
sigma
encu
verify
that
statements
interval
has
encompassed
sigma"
are
accurate.
The
simulations
are
comprised
of
the
following
s
I
.
Generate
data
that
lese
bles
actual
data.
The
model
used
to
models
cited
in
the
were
clustered
near
.2*
Co.
8
This
resembles
simulated
data
tions
they
were
scattered
d
we
mean
the
data
and
in
another
band
to
generate
the
random
normal
deviates
3.
Steps
1
2.
were
repeated
(
say)
20
times
to
generate
20
sets
of
simultaneous
samples,
each
comprised
of
a
pair
(
N
=
2)
of
4.
The
sample
average
and
sample
standard
deviation
S
were
calculated
for
each
pair
of
data.
of
S
was
m
by
the
small
sample
correction
factor
1.253
to
obtain
un
estimates
of
sigma.
L
paae
37
of
the
form
Ln(
S)
=
Ln(
K)
+
p'Ln(
C).
This
equation
was
used
to
predict
Ln(
S)
for
each
of
the
20
combinations.
5.
The
(
sample
average,
S)
combinations
were
used
to
build
a
model
I
r
b.
2
Estimates
of
1
Ln(
S)
were
converted
to
estimates
of
S
by
Exp(
Ln(
S)).
L
A
a.
6.
As
in
the
ReMAP
process,
the
ratio
of
the
average
of
the
observed
vatues
of
S
to
the
average
of
the
predicted
values
of
S
was
used
to
calculate
the
bias
correction
factor,
BCF.
7.
95%
confidence
intervals
were
calculated
in
terms
of
Ln(
Sj
and
8.
The
predicted
values
of
Ln(
S)
and
the
intervals
OR
Ln(
S)
were
'
r
kJ
F=
i
c
i
L
intervals
on
Ln{
S).
irrm
I
ienr
to
estimates
of
sigma
and
the
confidence
intervals
on
ugh
Exp(
Ln(
S)).
The
completed
prediction
equation
is
of
/
bR14
bur
t
h
e
form
Est
Sigma
=
BCF'kCP.
$""
9.
This
equation
...
the
line
of
regression
...
was
traversed
in
small
steps
along
t
h
e
entire
length
of
the
line
(
from
C
=
500
to
C
=
5000.
The
upper
and
lower
confidence
limits
were
calculated
The
frequency
with
which
those
intervals
the
true
values
of
Sigma
(
the
true
values
of
sigma
m
Sigma
=
0.2'
co.*)
was
recorded.
L
P
r
kn
n
8.
This
entire
process
from
Step
1
through
Step
9
was
repeated
The
foregoi
imulates
getting
10,000
complete
sets
of
ReMAP
data;
fitting
those
vto
the
model
Ln(
S)
=
Ln(
K)
+
p*
Ln(
C);
applying
the
L+
appropriate
bias
correction
factors;
and
(
because
we
know
the
true
value
of
Sigma
in
these
simulations)
observing
bow
frequently
the
population
of
confidence
intervals
actually
encompass
the
true
values
of
sigma.
..
.
...
""""
10,000
times;
in
some
instances
30,000
times.
L
UIIY
The
simulations
also
provided
information
about
biases
in
I
estimating
sigma
usi
the
ReMAP
process.
The
bias...
100'(
Est
Sigma
S
a)/
Sigma..,
ranged
from
0.1%
at
low
levels
of
C
(
hence
low
values
of
sigma)
to
+
1.1%
at
high
levels
of
C
(
high
levels
of
Y"
S
sigma).
This
means
that
hen
the
estimated
value
of
sigma
is,
for
example,
10,
the
true
of
sigma
could
be
as
low
as
9.89.
Using
the
*
same
examp
vel
of
concentration,
the
true
value
of
sigma
l__
y
could
be
10.
P
L
e
This
bias
is
trivial
when
compared
to
other
considerations
such
as
the
the
confidence
intervals
on
sigma.
I
*_
Y
~
~~
~
~
C~
oaae38
To
verify
the
software
of
this
software
was
written
generating
data
from
the
Y
=
60
+
0.3'
X
was
use
fitting
the
data
to
the
m
to
a
model
of
t
h
e
form
Y
=
?
he
usual
95%
confi
value
of
Y
in
the
mann
d
for
these
simulations,
an
identical
copy
h
the
following
changes.
Instead
of
...
these
data
were
fit
the
95%
confiden
designed
to
perform;
an
for
simulating
the
ReMA
3
that
purpose,
between
97%
a
encompassed
the
true
values
o
"
95%
confidence
intervals"
act
the
frequency
of
capturing
data;
simulations
were
run
z
I;
u
97%
of
the
intervals
calculat
the
frequency
of
capture
is
prese
ReMAP
process.
Simulations
were
run
to
understand
t
r,
The
magnitude
of
this
increase
Lui
i
1
compared
to
95%)
depends
up0
When
we
have
two
simultaneous
sarn
97%
98%
intervals.
Whe
"
95%
intervals"
are
actual1
produce
a
distribution
of
S
that
is
hig
will
produce
a
distribution
of
S
that
i
cause
of
intervals
t
h
a
t
are
somewhat
broader
t
h
a
n
expected.
paae
39
No
real
harm
has
been
done
by
this
small
deviation
from
expected.
it
just
means
that
we
should
remember
that
what
we
are
calling
95%
intervals
are
closer
to
97%
98%
intervals.
Our
probabifity
of
capturing
sigma
with
these
intervals
is
a
little
higher
than
anticipated,
In
the
foregoing
discussion
we
have
described
the
performance
of
the
ReMAP
process
in
terms
of
individual
confidence
intervals.
These
intervals
are
calculated
and
presented
throughout
this
report.
This
means
that
when
we
estimate
a
confidence
interval
at
a
point
along
the
scale
of
C,
we
can
declare
that
"
95%
of
the
intervals
calculated
in
this
manner
value
of
sigma.
(
We
know
it's
really
97%
98%,
but
is
discussion
we'll
skip
that
detail.)
This
also
means
n
the
scale
of
C)
"
the
probability
that
this
confidence
sigma
is
95%".
S
there
is
a
probability
that
sigma
is
a
litt
larger
than
the
calcu
ller
than
the
calcufated
lower
limit.
In
ity
of
"
about
1%
in
each
tail."
limit,
or
a
littl
reduces
to
a
There
is
another
concept
that
should
be
considered.
This
is
the
concept
of
a
confidence
interval
on
a
line
as
a
whole.
These
intervals
are
concerned
with
probability
that
a
confidence
interval
captures
the
true
values
of
sigma
at
every
point
along
a
line,
(
over
t
h
e
range
of
the
tated
as
"
the
probability
is
X%
that
this
confidence
the
true
values
of
sigma
at
all
points
alo
e
intervals
that
f
capture
sigma.
In
this
n
is
directed
to
the
frequency
at
which
sig
d
of
the
line
to
the
other,
rather
than
at
i
Thus
the
frequ
captured",
not
in
terms
of
individual
scale
of
c
u
m
on.
This
is
also
th
of
capturing
is
in
terms
of
"
lines
ts
captured.
Capturing
the
entire
line
(
the
line
is
Sigma
=
0.2`
Co.
8)
as
opposed
line
is
a
rather
stringent
requirement.
In
this
report
the
cited
confidence
intervals
intervals,
or
points
on
the
line,
not
whole
line
statement
"
95%
of
the
intervals
calculated
in
sigma"
means
95%
of
the
individual
intervals.
interpretation
of
confidence
intervals.
to
individual
points
on
the
are
in
terms
of
individual
intervals.
Thus
the
this
manner
will
encompass
This
is
the
usual
For
more
information
concerning
whole
line
confidence
intervals,
see
Natrella,
M.
G.;
Experimental
Statistics;
National
Bureau
of
Standards
Handbook
91;
August
7963;
pages
5
15
and
5
16.,
paae
40
Simulations
with
the
model
Y
=
60
+
0.3'
X
(
with
the
usual
confidence
interval
reporting
95%
ind
confidence
intervals
our
95%
confiden
s
of
the
mean
of
Y
at
.
every
point
along
t
h
e
entir
at
when
we
are
equivalent
to
86%
obability
is
86%
that
Simulations
of
the
ReM
with
the
model
)
show
that
the
fr
wal
is
91%
92%.
Th
ct
that
individual
ot
95%.
Thus
in
the
y
is
about
91%
92%
t
true
values
of
sigma
ai
the
line.
This
c
Remember,
in
the
context
of
a
whoie
line
"
failure
to
capture
the
indeed.
The
P
nfidence
interval,
a
would
be
counted
as
a
t
al
confidence
interv
uch
that
the
tr
wals.
This
is
'
The
precise
outcomes
from
these
simulations
are
dependent
on
several
factors:
7
1.
The
constants
k
and
p
in
the
underlying
model
Sig
i
1
2.
The
amount
of
data
in
the
simultaneous
samples.
3.
The
number
of
samples
us
to
build
the
models.
4.
The
points
at
which
predic
n
t
h
e
scale
of
C.
6
!
LJ
L
This
proprietary
simulation
software
can
be
modified
to
study
specific
situations
in
more
detail.
paae
41
What
If
There
Is
No
Relationshb
Betwe
en
Est
cs
a
nd
Co
ncen
tration
?
If
the
t
ratio
associated
with
p
is
trivial
(
notably
less
than
2)
then
we
have
failed
to
detect
a
relationship
between
Est
CY
and
C.
This
dues
not
mean
there
is
no
relationship;
it
only
means
that
whatever
relationship
there
may
be,
it
was
not
detected
in
this
set
of
data.
Our
ability
to
detect
such
a
relationship
is
influenced
by
the
range
over
which
the
concentration
w
varied.
If
the
data
span
a
narrow
range
(
viz.,
only
about
one
decade,
or
a
factor
of
10)
the
dispersion
in
the
values
of
S
may
be
too
small
to
detect
the
actual
change
in
0.
If
the
data
are
badly
distributed
along
the
scale
of
C...
for
instance,
concentrated
near
the
centroid
instead
of
near
the
ends
of
the
scale
...
our
ability
to
establish
the
relationship
between
0
and
C
may
be
degraded.
Thus
our
inability
to
establish
a
relationship
may
simply
be
due
to
data
that
are
poorly
distributed
on
the
scale
of
concentration.
The
inherent
variation
among
individual
values
of
S,
cannot
be
Attempting
to
establish
a
overcome
unless
we
have
sufficient
data.
relationship
between
G
and
C
with
insufficient
data
spread
over
narrow
ranges
virtualty
insures
that
the
t
ratio
for
p
will
be
low;
so
low,
in
fact,
that
we
may
not
detect
the
presence
of
a
relationship
much
less
establish
the
nature
of
it.
Any
of
the
foregoing
factors,
or
combinations
of
those
factors,
can
be
responsible
for
a
failure
to
detect
a
relationship
between
cr
and
C.
It.
cannot
be
overemphasized
that
a
"
failure
to
detect"
does
not
imply
there
is
no
relationship.
data
spread
over
a
wide
range
of
concentrations.
Rather,
it
implies
that
we
did
not
have
sufficient
If
the
t
ratio
for
p
is
low
(
notably
smaller
than
2)
then
we
may
decide
to
take
the
following
position.
Since
we
have
not
established
a
hip,
then
we
may
deciare
that
G
is
a
constant.
This
is
equivalent
ring
that
the
individual
vafues
of
S
effectively
came
from
one
ommon
source
whose
true
standard
deviation
is
G,
Under
this
practice
we
coutd
...
if
we
elect
to
do
so
....
simply
pool
the
individual
values
of
S
and
use
that
as
the
estimate
of
G.
When
doing
this,
it
is
appropriate
to
use
the
factors
in
Table
1
to
calculate
confidence
bounds
an
0.
L
paae
42
The
ITEQ
data
(
Table
12
of
the
main
body
of
this
report)
will
be
used
to
illustrate
this
practice.
The
reported
as
0.0457,
0.001
2,
...
of
these
provides
a
1
df
estirn
sum
and
divide
by
2
Variance
=
0.00071
2.
deviation;
pooled
S
=
1.40
(
interpolated
in
0.0207
and
0.0374;
equivalent
to
drawi
limits
are
re1
uncertainly
in
estimating
the
slope,
1
i
Pooling
is
not
the
same
as
averaging
standard
deviations
The
small
sample
bias
correction
factor
is
not
needed
when
pooling
if
the
number
of
pooled
degrees
of
freedom
is
greater
than
10.
Llau.
3
Recommendations
Although
the
variation
in
simultaneocsly
sampled
data
causes
uncertainly
in
the
relationship
between
G
and
C,
the
width
of
the
confidence
intervals
on
G
can
be
minimized
by
acquiring
data
at
well
chosen
points
along
the
scale
of
C.
In
planning
for
future
data
...
anticipating
a
model
of
the
form
Est
ci
=
kCP
...
about
one
half
of
the
data
"
high"
level
of
each
pollutant.
t
h
e
t
ratio
on
the
power
coefficient,
and
minimize
the
width
of
the
confidence
intervals
on
(
r
for
a
given
amount
of
data.
Id
be
collected
at
a
"
low"
level
and
one
half
should
be
collected
at
a
This
will
minimize
SE(
coeff),
maximize
if
there
is
interest
in
pursuing
alternative
models,
then
the
For
every
coefficient
in
the
model
used
to
following
rules
apply.
associate
0
with
C,
data
should
be
Concentrated
at
a
point
along
the
scale
of
C.
This
means
that
for
a
model
with
two
estimated
coefficients
(
viz.,
Est
CT
=
kCP)
the
experimental
data
should
be
concentrated
at
two
points'
on
the
scale
of
C,
as
in
Table
5
and
Fig.
5.
For
a
model
of
the
form
Est
CT
=
a
+
kCP
the
data
should
be
concentrated
at
three
distinct
points'
on
the
scale
of
C.
If
the
data
are
poorly
dispersed,
as
in
Table
2
and
Fig.
2
then
the
SE(
Coeffs)
will
be
large
and
the
confidence
intervals
on
estimates
of
Est
0
may
be
wide.
Attempting
to
estimate
three
model
coefficients
from
poorly
dispersed
data
can
only
lead
to
confusion.
There
is
no
justification
for
using
models
more
complex
than
Est
ci
=
kCp
with
the
ReMAP
data
at
this
time.
Within
this
report
there
is
sufficient
information
to
allow
u
s
to
estimate
the
amount
of
data
needed
and
the
best
positioning
of
that
data
on
the
scale
of
C
so
as
to
reduce
the
confidence
intervals
on
0
to
pre
specified
widths.
AIthoug
h
these
calculations
could
be
done
analytically,
it
is
better
to
do
them
with
Monte
Carlo
simulations
because
of
the
complexity
introduced
by
the
bias
corrections.
Moreover,
with
simulations
we
can
quickly
explore
"
what
if
cases"
before
investing
in
additional
data,
A
further
advantage
of
Monte
Carlo
is
that
it
makes
the
underlying
models
(
and
the
assumptions)
completely
visible
and
unambiguous
as
compared
to
analytical
methods
that
require
in
depth
knowledge
of
statistical
methods.
*
Data
should
be
concentrated
at
additional
points
on
the
scale
of
C
in
order
to
test
for
lack
of
fit.
| epa | 2024-06-07T20:31:40.930628 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0042/content.txt"
} |
EPA-HQ-OAR-2003-0072-0043 | Supporting & Related Material | "2002-07-10T04:00:00" | null | N
RESEARCH
GROUP.
I
N
C
.
MEMORANDUM
TO:
FROM:
DATE:
June
12.2002
SUBJECT:
Walt
Stevenson,
Ef
AlCombustion
Group
Jason
Huckaby.
Eastern
Research
Group.
Inc
2000
National
Inventory
of
Large
Municipal
Waste
Combustion
(
MWC)
Units
This
memorandum
presents
a
year
2000
national
inventory
of
large
municipal
waste
combustion
(
MWC)
units.
This
inventory
is
an
update
of
the
earlier
1995
inventory
of
large
MWCs'.
This
2000
inventory
represents
MWC
units
that
are
affected
by
the
Subpart
Cb
emission
guidelines
for
large
MWC
units'.
The
Subpart
Cb
emission
guideIines
were
adopted
1995,
States
where
large
MWCs
are
located
were
required
under
Secti
AA)
to
adopt
and
implement
a
State
plan
that
assures
dl
large
MWC
units
in
the
State
are
in
compliance
with
the
emission
guidelines
by
December
19?
2000.
Many
States
CFR
part
62.
EPA
adopted
a
Federal
plan
to
assure
compliance
or
large
MWC
units
not
covered
by
an
approved
State
plan,'
In
this
inventory
and
Subpa
WC
unit
is
defined
as
an
MWC
unit
with
a
municipal
solid
waste
(
MSW)
combustion
capacity
greater
than
250
tons
per
day.
This
2000
nationd
inventory
is
based
on
updated
data
submitted
by
Iarge*
MWC
units
following
maximum
achievable
control
technology
(
MACT)
compliance
in
December
2
creating
the
2000
inventory.
the
previous
large
MWC
database
was
updated
induding
changes
to
reflect
MWC
plant
ciosings.
combustor
type.
combustion
unit
capacity.
and
air
pol
device
used
%
I
yep
2000
to
comply
with
MACT
requirements.
Table
A
1
provides
s
u
m
m
q
information
for
each
MWC
rype.
In
2000.
the
large
MWC
category
contains
I67
units
distributed
into
two
groups
of
combustion
unit
types
as
follows:
133
mass
burn
units
and
34
refuse
derived
he1
units.
Table
A
2
shows
the
change
that
has
w
e
d
in
the
large
MWC
population
since
1995.
kamUC~\
DISJ\
I
1\
07W01
Large
MWCUniu
memo
wpd
I
Table
B
presents
the
MWC
s
for
year
2000
for
this
large
national
inventory.
This
includes:
plant
lo
plant.
large
MWC
unit
capacity,
1
construction
date,
and
start
up
date.
located
at
66
MWC
plants
with
a
total
Compared
to
the
1995
Iarge
MWC
n
number
of
large
MWC
units
(
from
1
(
from
63
to
66
plants),
and
a
I
perce
MWCunits.
air
pollution
control
equipment,
operating
capacity
of
89,477
tons
per
day
MSW.
(
from
88,652
to
89
By
location,
the
States
with
th
(
1
8
units),
and
Pennsylvania
(
1
6
uni
EPA
regions
with
the
most
Iarge
M
and
Region
I
(
31
units)
4.
Massachusetts
(
6
units).
On
a
regional
basis,
*
e
Region
4
(
39
units),
Region
3
(
33
units),
Attachment
I
provides
a
list
of
acrony
References
I.
Memorandum
from
Lauri
Stevenson,
EPA.
"
Large
July
7,
1997.
(
Docket
A
90
4
1Ieen
h
e
,
Eastern
Research
Group,
Inc.
to
Walt
WC
Inventory
Database."
2.
Emission
Guidelin
ustion
Unirs
Consirwed
o
Cb
or
60
FR
65415.
December
19
1
I
3.
Federal
Plan
Requireme
he
fore
Sepiernber
20,
I9
See
Am@
ment
2
for
E
4.
Table
A
1:
Summary
of
Table
A
2:
Summary
of
the
National
Inventory
of
Large
MWC
Units
for
years
1995
and
2000
3
I
I.
.
.
...
.
A
0154.1
11072001
Large
MWCUnrts
memo
wpd
5
I;
'
0154ii
1\
07'
2001
Large
MWC
Units
mano
wpd
6
CI
DSI
=
EA
=
ESP
=
FB
FF
MB
=
MOD
=
MSW
=
MWC
=
RC
=
RDF
=
REF
=
SA
=
SD
=
SNCR
=
TPD
=
ws
=
ww
=
List
of
Acronyms
Used
in
Table
B
carbon
injection
(
activated
carbon)
dry
sorbent
injection
excess
air
electrostatic
precipitator
fluidized
bed
fabric
filter
(
baghouse)
mass
bum
modular
combustion
municipal
solid
waste
municipal
waste
combustor
rotary
combustor
refuse
derived
he1
refiactory
walled
combustor
starved
air
spray
dryer
(
semi
dry
scrubber)
selective
non
cataiytic
reduction
tons
per
day
wet
scrubber
waterwail
.
\
Map
of
EPA
Regions
(
available
electronidly
at
http://
www.
epa.
gov/
epahome/
wiiereyoulive.
htm)
r
EPA:
pVChere
You
Live
9
*
Each
EPA
Regional
Off
ice
is
responsible
within
its
states
for
the
execution
of
the
Agency's
programs.
Select
a
region
by
cli
the
area
of
the
map
covered
by
the
region,
or
use
the
links
located
below
the
map
to
go
directly
to
a
region.
I
7
...
cihet
Rcgron
9
YZCS
0
Amorrcan
Samoa
m
Trust
Territories
e
Commonwealth
of
th.
Northern
M
a
r
h
a
hbnd.
...
other
Regcon
2
Y~
CS
Reaion
7
responsible
within
the
states
of
Connecticut,
Maine,
Massachusetts.
New
Hampshire.
Rhode
Island.
and
Vermont.
Region
2
responsible
within
the
states
of
New
Jersey.
New
York,
Puerto
Rico
and
lhe
U.
S.
Virgin
islands.
Reaion
3
responsible
within
the
states
of
Delaware.
Maryland.
Pennsylvanla.
Virginia,
West
Virginia.
and
the
District
of
Columbia.
ReQion
4
responsible
within
the
states
of
Alabama.
Florida.
Georgia.
Kentucky.
Mississippi.
North
Carolina.
South
Caroitna.
and
Tennessee.
Reaion
5
responsible
within
the
states
of
liilnois.
fnalana,
Mtchlgan.
Minnesotz,
Ohio.
and
Wisconsin.
Reaion
6
responsible
within
the
states
of
ArKansas.
Louisiana.
New
Mexico.
Oklahoma.
ana
Texas.
Reaion
7
responsible
within
the
states
of
Iowa.
Kansas,
Missourr.
and
Nebraska.
Reaion
8
responsible
within
the
states
of
Colorado,
Montana.
North
Dakota.
South
Dakota.
Utah.
and
Wyoming.
Region
9
responsibie
within
the
states
of
Arizona,
California.
Hawaii.
Nevada.
and
the
terntortes
of
Guam
and
American
Samoa.
http://
wWw
.
epa.
gov/
epahome/
wherey
oui
i
ve.
htm
7/
2/
02
~
~~
EPA:
,
Where
You
Live
Reaion
10
responsible
within
the
states
of
Alaska,
Idaho,
Oregon.
and
Washington,
U
1
http://
www.
epa.
gov/
epahome/
whereyoulive.
htm
7/
2/
02
,
EASTERN
RESEARCH
GROUP,
INC.
Vlll
B
6
MEMORANDUM
TO:
Walt
Stevenson,
EPNCombustion
Group
FROM:
Jason
Huckaby,
Eastern
Research
Group,
Inc
DATE:
June
12,2002
A
90
45
SUBJECT:
2000
National
Inventory
of
Large
Municipal
Waste
Combustion
(
n/
iwC)
Units
This
memorandum
presents
a
year
2000
national
inventory
of
large
municipal
waste
combustion
(
MWC)
units.
This
inventory
is
an
update
of
the
earlier
1995
inventory
of
large
MWCsl.
This
2000
inventory
represents
MWC
units
that
are
affected
by
the
Subpart
Cb
emission
guidelines
for
large
MWC
units2.
The
Subpart
Cb
emission
guidelines
were
adopted
December
19,
1995.
States
where
large
MWCs
are
located
were
required
under
Section
129
of
the
Clean
Air
Act
(
CAA)
to
adopt
and
implement
a
State
plan
that
assures
all
large
MWC
units
in
the
State
are
in
complidce
with
the
emission
guidelines
by
December
19,2000.
Many
States
adopted
State
plans,
as
listed
in
40
CFR
part
62.
EPA
adopted
a
Federal
plan
to
assure
compliance
for
large
MWC
units
not
covered
by
an
approved
State
p
h
3
In
this
inventory
and
MWC
unit
is
defined
as
an
MWC
unit
with
a
municipal
solid
waste
(
MSW)
ty
greater
than
250
tons
per
day.
This
2000
national
inventory
is
based
on
updated
data
submitted
by
large
MWC
units
/
following
maximum
achievable
control
technology
(
MACT)
compliance
in
December
2000.
In
creating
the
2000
inventory,
the
previous
large
MWC
database
was
updated
including
changes
to
closings,
combustor
type,
combustion
unit
capacity,
and
air
pollution
control
2000
to
comply
with
MACT
requirements.
rovides
summary
information
for
each
MWC
type.
In
2000,
the
large
MWC
67
units
distributed
into
two
groups
of
combustion
unit
types
as
follows:
133
mass
burn
units
and
34
refuse
derived
fuel
units.
Table
A
2
shows
the
change
that
has
occurred
in
the
large
MWC
population
since
1995.
Table
B
presents
the
MWC
specific
data
for
year
2000
for
this
large
MWC
unit
national
inventory.
This
includes:
plant
location,
plant
capacity,
number
of
large
MWC
units
at
each
plant,
large
MWC
unit
capacity,
large
MWC
unit
type,
air
pollution
control
equipment,
and
start
up
date.
There
are
167
large
MWC
units
in
the
2000
inventory
C
plants
with
a
total
natiqnal
operating
capacity
of
89,477
tons
per
day
MSW.
Compared
to
the
1995
large
MWC
national
inventory1,
t
b
s
shows
a
2
percent
increase
in
the
number
of
large
MWC
d
t
s
(
from
164
to
167),
a
5
percent
increase
in
the
number
of
plants
(
from
63
to
66
plants),
and
a
1
percent
increase
in
capacity
(
from
88,652
to
89,477
tpd)
for
large
MWC
units.
By
location,
the
States
with
the
most
large
MWC
units
are
Florida
(
29
units),
New
York
(
1
8
units),
and
Pennsylvania
(
16
units),
and
Massachusetts
(
6
units).
On
a
regional
basis,
the
EPA
regions
with
the
most
large
MWC
units
are
EPA
Region
4
(
39
units),
Region
3
(
33
units),
ides
a
list
of
acronyms
used
in
Table
B.
I
morandum
from
Laurie
Cone
and
Colleen
Kane,
Eastern
Research
Group,
Inc.
to
Walt
Stevenson,
EPA.
"
Large
and
Small
MWC
Units
in
the
1995
MWC
Inventory
Database."
July
7,
1997.
(
Docket
A
90
45;
Item
VI
B
2).
2.
Emission
Guidelines
and
Compliance
Times
for
Large
Municipal
Waste
Combustion
Units
Constructed
on
or
Before
September
20,
1994.
40
CFR
part
60,
Subpart
Cb
or
60
FR
65415.
December
19,1995.
3.
Federal
Plan
Requirements
for
Large
Municipal
Waste
Combustors
Constructed
on
or
before
September
20,1994.
40
CFR
part
62,
Subpart
FFF.
4.
See
Attachment
2
for
EPA
Region
Listing.
*
*
e
Large
MWC
Unit
Type
Mass
burn
Refuse
derived
fuel
Total
:
Table
A
1:
Summary
of
the
National
Inventory
of
Large
MWC
Units
for
year
2000
(
Distributed
into
types
of
large
MWC
units)
Number
of
Large
Number
of
Capacity
(
tpd)
Percent
MWC
Plants
Large
MWC
Capacity
Units
of
Total
53
133
67,968.
76%
13
34
21,509
24%
66
167
89,477
I
Year
Number
of
Large
RlwC
Number
of
Large
MWC
Capacity
(
tpd)
Plants
Units
I
I
Mass
burn
includes
mass
burn
water
wall,
mass
burn
refkactory,
and
mass
burn
rotating
combustion
units.
Refuse
derived
fuel
includes
all
combustion
units
that
combust
refuse
derived
fuel.
1995
2000
Table
A
2:
Summary
of
the
National
Inventory
of
Large
MWC
Units
for
years
1995
and
2000
63
164
88,652
66
167
89,477
I
I
i
.
e*
m
4
n
I
E
I
I
I
I
E
E
I
==
I
00
03
N
/
E
I
I
2
ATTACHMENT
1
List
of
Acronyms
Used
in
Table
B
CI
=
carbon
injection
(
activated
carbon)
DSI
=
dry
sorbent
injection
EA
=
excess
air
ESP
=
electrostatic
precipitator
FB
=
fluidizedbed
FF
=
fabric
filter
(
baghouse)
MB
=
massburn
MOD
=
modular
combustion
MSW
=
municipal
solid
waste
MWC
=
municipal
waste
combustor
RC
=
rotarycombustor
RDF
=
refuse
derived
fuel
REF
=
refi
actory
walled
combustor
SA
=
starved
air
=
spray
dryeEQemi
dry
scrubber)
SNCR
=
selective
non
catalytic
reduction
TPD
=
tonsper
day
WS
=
wet
scrubber
WW
=
watenvall
ATTACHMENT
2
Map
of
EPA
Regions
(
available
electronically
at
http://
wyw.
epa.
gov/
epahome/
whereyoulive.
htm)
~
| epa | 2024-06-07T20:31:40.977055 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0043/content.txt"
} |
EPA-HQ-OAR-2003-0072-0044 | Supporting & Related Material | "2002-06-21T04:00:00" | null | '
1
K,
n
EASTERN
RESEARCH
GROUP.
INC.
MEMORANDUM
TO:
Walt
Stevenson,
EPNCombustion
Group
FROM:
Jason
M.
Huckaby,
Eastern
Research
Group
DATE:
June
17,2002
m
D
3
SUBJECT:
National
Emission
Trends
for
Large
Municipal
Waste
Combustion
Units
[
Years
1990
to
20051
1.0
BACKGROUND
The
purpose
of
this
memorandum
is
to
present
national
emission
trends
for
large
Municipal
Waste
Combustor
(
EVIWC)
units.
Emission
trends
for
large
MWC
units
are
presented
for
dioxdhrans,
cadmium
(
Cd),
lead
(
Pb),
mercury
(
Hg),
particulate
matter
(
PM),
hydrochloric
acid
(
HCl),
sulfur
dioxide
(
S02),
and
nitrogen
oxides
(
NO,).
In
this
memorandum,
large
MWCs
are
those
with
a
combustion
capacity
greater
than
250
tons
per
day.
These
MWCs
are
regulated
under
40
CFR
part
60,
subpart
Cb.
The
enission
trends
are
presented
for
the
period
between
1990
and
2005.
The
Clean
Air
Act
(
CAA)
required
maximum
achievable
control
technology
(
MACT)
retrofits
at
all
large
MWC
units
by
December
2000.
Table
1
presents
a
summaiy
of
emissions
for
large
MWCs
for
year
1990
(
pre
MACT)
and
2000
(
post
MACT).
Substantial
emission
reductions
were
achieved.
A
separate
memorandum
presents
emission
trends
for
small
L
W
C
units
regulated
under
40
CFR
part
60,
subpart
BBBB
(
35
to
250
tons
per
day
capacity).
This
memorandum
for
large
MWCs
replaces
the
1999
national
emission
trend
memorandurn'
for
large
IvEVCs.
The
updated
PJIVVC
emissions
estimates
for
large
MWC
units
contained
in
this
memorandum
were
prepared
using
updated
emission
factors
and
volumetric
flow
data
based
on
recent
MWC
testing
and
MWC
operating
data.
This
information
is
discussed
below
under
Section
2.0
(
Results),
Section
3.0
(
Calculations)
and
Section
4.0
(
References).
C:\
SmallMWCUnventory\
LargelJnits\
LMWCemissians6ZO.
wpd
1
Table
1.
Emissions
for
Large
MWC
Units
for
Year
1990
and
2000
Pollutant
Percent
Emission
1990
Emissions
2000
Emissions
Reduction
(
tons
per
year)
(
tons
per
year)
Achieved
The
dioxin
emissions
are
presented
on
a
g/
yr,
toxic
equivalent
quantity
(
TEQ)
basis,
all
other
emksion
reductions
in
TPY.'
TEQ
dioxin
emissions
are
based
on
1989
NATO
Toxic
Equivalency
Factors.
g/
yr
=
gram
per
year
TPY
=
tons
per
year
2.0
RESULTS
Emissions
estimates
for
large
MWCs
were
prepared
for
years
1990,
1993,
1996,
1999,
2000,
and
2005.
Emissions
varied
with
time
as
MWC's
completed
retrofits
or
elected
to
close
rather
than
retrofit.
The
compliance
dates
used
in
the
emission
estimates
reflect
actual
retrofit
dates
and
include
staggered
retrofit
dates
for
MWC
facilities
with
multiple
MWC
units,
where
appropriate.
Inventories
of
NIWC
units
were
obtained
from
existing
inventory
memoranda
and
updated
with
recent
information
on
RlWC
unit
closures
and
air
pollution
control
device
(
APCD)
retrofits.
I
From
the
updated
inventory
of
MWC
units,
a
database
of
large
MWC
units
was
developed
for
the
years
of
1990,
1993,
1996,
1999,2000,
and
2005.
The
MWC
population
varies
with
time
as
older
MWC
units
closed
and
new
MWC
units
opened.
For
year
2000,
a
companion
large
MWC
inventory
has
been
prepared
to
document
the
final
large
MWC
population
and
APCD
application
following
MACT
retrofits.
2
A
summary
of
the
updated
inventory
for
large
MWC
units
and
total
MWG
capacity
is
presented
in
table
2.
A
graphical
representation
of
capacity
for
large
MWC
units
is
shown
in
figure
1.
The
emissions
projections
for
year
2005
assume
the
number
and
total
capacity
of
MWC
units
would
be
the
same
as
in
2000.
C:\
S~
mallMWC\
hventory\
Ly\~
slrgeUnits\
LMWCemid
2
Table
2.
Summary
of
the
number
of
Large
MWC
Facilities,
Units,
and
Total
Combustion
Capacity
Year
Total
Combustion
Number
of
Large
Number
of
Large
Capacity
MWC
Units
(
tons
per
day)
MWC
Facilities
Using
this
new
large
NlWC
inventory,
emissions
were
calculated
for
eight
section
129
pollutants
using
updated
emission
factors,
volumetric
flow
rate,
capacity
and
AP
42
type
emission
factors.
A
limited
amount
of
stack
test
data
was
also
used.
The
updated
emission
estimates
for
the
eight
pollutants
for
the
years
4990,
1993,
1996,
1999,2000,
and
2005
are
presented
in
table
3.
Table
3.
Summary
of
Emissions
Estimates
from
Large
MWC
Units
Dioxin/
Dioxin/
Furan.
Furall,
total
TEQ'
mass
Cd
Pb
Hg
PM
IC1
so2
Year
(
g/
yr)
(
dyr)
(
TPY)
(
TPY)
(
TPY)
(
TPY)
(
TPY)
(`
IPY)
Equivalency
Factors.
gfyr
=
grams
per
year
TPY
=
tons
pes
year
C:\
SmallMWC\
Inventory\
LargeUnits\
LM
WCemissions620.
wpd
3
50,600
1
*
r
k
E.
A
graphical
representation
of
the
pollutant
emissions
data
for
the
above
years
is
shown
in
figures
2
through
18.
These
emissions
estimates
include
only
large
MWC
units
(
greater
than
258
tons
per
day).
These
emissions
trends
show
that
substantial
reductions
in
large
MWC
unit
emissions
have
occurred
since
1990.
These
emission
reductions
are
a
result
of
(
1)
retrofit
of
APCD
on
existing
MWC
units,
(
2)
retirement
of
several
existing
MWC
units,
and
(
3)
special
actions,
most
notably
EPA's
dioxin
initiative
and
the
voluntary
mercury
reduction
by
battery
manufacturers
3.0
CALCULATIONS
Nationd
MWC
emissions
are
a
function
of
three
variables:
(
I)
MWC
unit
inventory,
(
2
)
emission
factors,
and
(
3)
APCD
retrofit
or
closure
schedule.
The
updated
large
MWC
inventory
is
presented
in
attachment
1.
Updated
emission
factors
were
developed
for
the
most
common
MCDkombustor
combinations
using
the
average
performance
determined
from
the
test
data
Rom
the
large
MWCs
retrofits.
This
information
was
supplemented
with
AP
42
emission
factors
for
less
common
AKBlcombustor
combination^.^
A
limited
amount
of
test
data
was
also
used.
See
attachment
2
for
a
listing
of
emission
factors
used.
See
table
4
for
identification
of
MWCs
where
test
data
was
used.
To
determine
annual
national
emissions
for
each
pollutant,
emissions
were
calculated
for
each
individual
h4WC
unit.
The
emissions
from
individual
units
were
then
summed
to
give
a
national
emission
rate.
The
calculation
of
individual
MWC
unit
emissions
was
conducted
using
plant
specific
information
such
as
rated
unit
capacity,
unit
capacity
factor,
type
of
combustor,
and
type
of
APCD.
Emission
concentrations,
flow
rate
data,
and
capacity
factor
representative
of
typical
emissions
was
used
for
the
emission
calculations.
Table
4
lists
the
large
MWC
where
test
data
were
used
ira
the
calculations.
The
following
equation
was
used
to
convert
pollutant
stack
concentrations
to
tons
per
year
(
TPU)
emitted:
PE=
C*
V*
T*
CF*
365
*
I.
1
C:
1Srna~
WC\
Znventory\
LargeUnits~
MWCem~
s~
ons620.
wpd
4
4
i.
t
E
Where:
PE
=
Pollutant
emission
rate
(
TPY);
C
=
Flue
gas
concentration
factor
(
Mg/
dscm
@
7%
02);
V
T
=
MWC
unit
capacity
(
tondday);
CF
=
Capacity
factor
(
dimensionless);
=
Volumetric
flow
factor
(
dscm
0
7%
02/
ton
of
waste
fired);
365
aaysiyr;
and
1.1
tQlXdbfg.
Table
4.
Large
MWC
Units
with
Test
Data
Based
Emission
Estimates
Facility
Name
1
State
I
Unit
Number
ll
Adkondack
RRF
NY
1
Adkondack
RRF
NY
2
C:\
SinallMWC\
lnventory~
r~~
Units\
LM
WCemissionsG20,
wpd
5
P
x
I
Relative
to
the
1999
estimates,
these
updated
estimates
have
been
prepared
talking
advantage
of
the
new
information
on
volumetric
flowrate
and
annual
capacity
factors
available
from
the
data
survey
of
the
MACT
retrofits
at
167
large
MWCS.~
The
volumetric
flow
factor
(
V)
for
rehse
derived
fuel
(
IRDF)
units
was
updated
to
5,026
dry
standard
cubic
meter
per
ton
(
~
s
c
~
t
~
~
)
MSW
combusted,
based
on
a
W
squared
analysis
of
MACT
compliance
test
d
a
k
4
Lkewise,
the
volumetric
flow
factor
(
V)
for
non
RP>
F
units
was
updated
to
4,299
dscdton
MSW
combusted.
Based
on
the
same
MACT
compliance
test
data,
the
capacity
factor
for
all
units
was
updated
to
0.86
(
86%)
based
on
a
R
squared
analysis.
A
companion
analysis
is
available
that
documents
the
actual
large
MWC
emissions
for
year
2000
using
year
2000
MACT
stack
test
compliance
data.
5
Those
data
agree
very
well
with
the
year
2000
estimates
contained
in
this
trends
memo
(
see
table
5).
i
Table
5.
Comparison
of
Actual
Versus
Estimated
Large
MWC
Emissions
for
2080
Actual
2000
emissions
based
on
individual
large
MWC
stack
test
compliance
data
(
Reference
5).
I,
Estimated
from
emissions
developed
following
procedures
in
this
memorandum
(
see
table
3).
I
4.
REFERENCES
I
1.
Memorandum
from
B.
Nelson,
Eastern
Research
Group,
Inc,
to
Walt
Stevenson,
U.
S.
Environmental
Protection
Agency.
Summary
of
the
National
Emission
Estimates
for
Municipal
Waste
Combustion
Units.
A
90
45:
VIII
B
1.
September
30,
1999.
Memorandum
from
J.
Huckaby,
Eastern
Research
Group,
Inc.
to
Walt
Stevenson,
U.
S.
Environmental
Protection
Agency.
200
1
National
Inventory
of
Large
Municipal
Waste
Combustion
(
WnWC)
Units.
A
90
45:
VIII
B
6.
June
17,
2002.
I
.
2.
I
3.
U.
S.
Environmental
Protection
Agency.
Compilation
of
Air
Pollution
Emission
Factors
AP
42,
Fifth
Edition,
Volume
1:
Stationary
Point
and
Area
Sources.
February
1996.
C:\
SmallMWC\
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o~
L~
geU~
1its\
LMWCemi20
wpd
6
4.
Memorandum
from
Can
Kuterdem
and
Bradley
Nelson,
Alpha
Gamma
Technologies,
Inc.
to
Walt
Stevenson,
U.
S.
Environmental
Protection
Agency.
Perfonnance/
Test
Data
for
Large
Municipal
Waste
Combustors
at
MACT
Compliance
(
year
2000
data).
A
90
45;
VIII
B
4.
June
18,2002.
5.
Memorandum
from
Bradley
Nelson,
Alpha
Gamma
Technologies,
Inc.
to
Walt
Stevenson,
U.
S
I
Environmental
Protection
Agency.
Emissions
from
Large
Municipal
Waste
Combustor
Units
(
MWGs)
Following
MACT
Retrofit
(
Year
2000
Test
Data).
A
90
45;
vm
B
3.
June
19,
2002.
I
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| epa | 2024-06-07T20:31:40.980710 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0044/content.txt"
} |
EPA-HQ-OAR-2003-0072-0045 | Supporting & Related Material | "2002-06-21T04:00:00" | null | rp
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| epa | 2024-06-07T20:31:40.983589 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0045/content.txt"
} |
EPA-HQ-OAR-2003-0072-0046 | Supporting & Related Material | "2002-07-10T04:00:00" | null | ALPHA
GAMMA
T
E
C
H
N
O
L
O
G
I
E
S
,
1
N
C
.
A
70
4
5
2
F
B
y
MEMORANDC'M
DATE:
March
22,
2002
i
i
arge
Municipal
SUBJECT:
Summary
of
Equations
used
to
Calcu
i
Waste
Combustion
Units
Following
MACT
Retrofit
(
Test
Data)
FROM:
Bradley
Nelson
Alpha
Gama
Technologies,
Inc.
TO:
'
Wait
Stevenson,
EPNCombustion
Group
The
purpose
of
this
memorandum
is
to
present
the
equations
used
to
calculate
the
annual
pollutant
emissions
from
large
Municipal
Waste
Combustor
(
MWC)
units.
This
memorandum
is
randum
titled
"
Emissions
from
Large
Municipal
Waste
Combustion
)
Following
MACT
Retrofit
(
Year
2000
Test
Data);
Docket
A
90
45;
VIII
B
3.
line
the
steps
that
were
used
to
calculate
MWC
unit
emissions.
to
convert
compliance
test
data
into
an
nts,
which
include
dioxins/
fUrans
(
CDD/
CDF),
cadmium
(
Cd),
hydrochloric
acid
(
HCI),
s
u
k
r
dioxide
(
SO,),
nitrogen
oxides
(
NO,),
and
ter
(
PM).
Emissions
for
CDDICDF
were
calculated
in
units
of
grams
per
year
total
mass
and
TEQ'
basis.
ns
were
summed
to
Toxic
Equivalency
Quantity
(
TEQ)
values
based
on
1989
NATO
Toxic
Equivalency
Factors.
As
background,
the
Emission
Guidelines
(
EG)
for
large
MWC
units
under
Section
129
of
the
Clean
Air
Act
were
adopted
in
1995
(
40
CFR
part
60,
subpart
Cb),
and
required
all
large
MWC
units
to
be
in.
compliance
with
either
a
compliance
test
reports
due
by
Au
167
large
NWC
units
located
ants
in
24
states.
From
these
reports,
data
was
extracted
on
pollutant
emission
concentratio
compliance
test,
steam
rate
during
the
compliance
test,
and
annu
as
used
to
calculate
the
annual
emissions
for
each
Section
129
pollutant
for
each
of
the
167
large
MFVC
units.
Annual
waste
combusted
data
(
tons
waste
cornbusted
pe
ratios
and
provide
information
on
the
total
plant
specific
data
were
used
except
for
th
or
a
Federal
Plan
by
December
2000,
with
obtained
the
compliance
te
ted
and
used
to
calculate
process
ted
in
the
U.
S.
In
all
cases,
i
Conversion
Factors
SO,
Ratio
The
EG
requires
all
unit
the
annual
emission
calcu
to
convert
SO,
geometric
mean
units
provided
values
for
generate
usable
data
for
units
of
1.12
to
1
was
calculated.
a
geometric
mean.
For
TEQ
Ratio
All
units
provided
CD
under
the
Emission
Guidelines.
T
were
calculated.
From
the
data,
and
TEQ
basis.
A
total
mass/
TEQ
rat
units
not
reporting
TEQ
data.
The
to
mass
basis.
This
is
required
The
equations
used
to
calculate
the
annual
emissions
of
the
Section
f29
pollutants
are
provided
in
Attachment
1.
The
calculation
ed
a
three
step
proce
C:\
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9.
wpd
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The
compliance
test
pollutant
emission
rate
(
masdtime)
was
calculated
by
multiplying
the
poUutant
concentration
(
mass/
volume)
by
the
stack
flow
rate
(
volume/
time)
during
the
test.
The
pollutant
emission
rate
(
masdtime)
was
divided
by
the
steam
flow
rate
during
the
test
(
ib
steamltime)
to
calculate
a
pollutant
to
steam
factor
(
mass/
lb
steam).
The
pollutant
to
steam
factor
(
massfib
steam)
was
multiplied
by
the
annual
steam
output
(
Ib
steamlyear)
to
calculate
the
annual
pollutant
emission
rate
(
madyear).
The
pollutant
concentration
units
varies
between
poUutants
and
are
as
follows;
ng/
dscm
and
HCI).
All
data
are
presented
on
a
dry
basis,
corrected
to
7%
0,.
For
NO,
and
SO,
the
fEst
24
hour
CEM
average
was
used
for
emission
calculations.
Q
(
CDD/
CDF),
mg/
dscm
(
PM,
Cd,
Pb,
and
Hg)
and
ppmV
(
NO,,
SO,,
CO,
Attachment
1
1000
mg/
g.
The
equation
for
calculating
compliance
test
pollutant
emission
rate
(
E)
is
as
follows:
C
V
*
6
0
E
Where:
E
=
Pollutant
emission
rate
(@
our);
C
=
Concentration
of
pollutant
(
m
F
=
Stack
flow
rate
(
dscdmin
@
I
60
min/
hr;
and
P
S
F
*
AS
453.593
*
2000
A
E
=
Where:
AE
=
Annual
emission
(
tons/
yr);
ant/
Steam
factor
(
g
pollutant/
lb
steam);
AS
=
Annual
steam
flow
for
unit
(
Ib
steady);
453.593
gjIb;
and
2000
lb/
ton.
Since
some
of
the
pollutant
concentration
data
in
the
compliance
tests
were
not
given
in
mg/
dscm,
conversion
factors
were
calculated
and
used
to
convert
the
given
values
into
mgld
convert
the
poilut
multipiied
by
the
conversion
factor.
The
conversion
factors
that
were
used
are
given
in
the
following
table.
concentration
to
mg/
dscm
the
concentration
value
(
ppmV
or
ng/
dscm}
is
Attachment
2
The
purpose
of
this
section
is
to
provide
a
sample
calculation
to
show
the
steps
and
equations
that
are
used
to
calculate
the
Combustor
(
MWC)
units.
A
750
ton
p
calculation.
Sample
calculations
are
sho
om
large
Municipal
Waste
Sample
Calculation
(
750
TPD
MWC
Unit):
Flue
gas
rate
during
compliance
test
(
F)
Steam
rate
during
compliance
rest
(
SF)
Steam
generation
per
year
(
AS)
=
I
P
Dioxifluran,
Total
M
Concentration
of
CDD/
CDF,
total
mass
b
Using
the
conversion
,
Thus,
E=
1.6~
10~~*
2159*
60/
tOOO
E
=
2.07
x
IO4
f
i
r
PSF
=
2.07
x
lo4
/
184,500
PSF
=
1.
f
2338
x
1
0
9
gllb
steam
AE
=
1.12338
x
io"
*
1,433,041,000
AE
=
1.61
g/
yr
CDD/
CD
ersion
from
tons
to
grams)
DioxinsJFurans,
TEQ
Basis:
6
C:\
SmaliMWC\
Oocket\
70802submittal\
A9045d
Concentration
of
CDDICDF,
TEQ
basis
=
0.032
ng/
dscm
(
given)
Using
the
conversion
factor
the
CDD/
CDF
concentration
is
3.2
x
IO'
mg/
dscm
Thus,
E
=
3.2
x
lo'
*
2159
*
60
/
1000
E
=
4.1453
x
IOv6
g/
hr
PSF
=
4.1453
x
PSF
=
2.2468
x
10'"
g/
lb
steam
/
184,500
Mercury
(
Hg):
Concentrarion
of
Hg
=
0.0197
mgldscm
(
given)
Thus,
E
=
0.0197
*
2159
*
60
/
1000
PSF
=
2.55
I9
/
184,500
PSF
=
1.383
x
g/
Ib
steam
AE
=
1.383
x
to'
*
1,433,04Z,
oOO
/
(
453.593
*
2000)
AE
=
0.02
18
ton/
yr
Hg
Lead
(
plb):
I
Doeket\
7O802su
bmittafV49045viiibS.
wpd
7
,
I
Concentration
of
Pb
=
0.039
mgldscm
(
given)
Thus,
E
=
0.039
*
2
60
/
1000
E
=
5.052
g
h
r
PSF
=
5.052
/
184,500
PSF
=
2.738
x
IO'
g/
lb
steam
AE
=
2.738
x
*
AE
=
0.0433
todyr
Pb
Cahaium
(
Cd):
Concentration
of
Cd
=
0.0033
mgldscm
(
given)
Thus,
E
=
0.0033
*
2159
*
60
/
1000
E
=
0.4275
g/
hr
PSF
=
0.4275
/
184,500
7
x
!
O
6
g/
Ib
steam
AE
=
2.3
17
x
lo6
*
1,433,041,000
J
(
453.
AE
=
0.00366
todyr
Cd
Hydrochloric
Acid
(
HCl):
Concentration
of
HCl
=
9.4
ppmV
(
given)
Using
the
conversion
factor
the
HCI
concentration
is
14.25
mg/
dscm
Thus,
E
=
14.25
*
2159
*
601
1000
E
=
I846
g/
hr
PSF
=
1846
/
184,500
PSF
=
0.01
g/
lb
steam
AEi
=
0.01
*
1,433,041,000
/
(
453.593
*
2000)
AE
=
15.8
todyr
HCI
Sulfur
Dioxide
(
SO&
The
concentration
of
SO,
=
4.9
ppmV
(
given)
Using
the
conversion
factor
the
SO,
concentration
is
13.05
mg/
dscm
Thus,
E
=
13.05
*
2159
*
60
/
1000
E
=
1690
g/
hr
PSF
=
1590
/`
184,500
PSF
=
0.00916
g/
lb
steam
AE
=
0.009
16
*
1,433,041,000
/
(
453.593
*
2000)
AE
=
14.5
ton/
yr
SO,
Nitrogen
Oxides
(
Nod:
Thus,
E
=
350
*
2159
*
60
/
LO00
E
=
45,324
PSF
=
45,324
/'
184.500
PSF
=
0.24566
gRb
steam
i
AE
=
0.24566
*
I,
433,041,000
/
(
453.593
*
2000)
I
AE
=
388
todyr
NO,
Particuiate
Matter
(
PM):
Concentration
of
PM
=
7.3
mgldscm
(
Thus,
*
E
=
7.3
*
2159
*
60
/
lo00
E
=
945.6
g
h
r
J
PSF
=
945.6
/
184,500
PSF
=
0.005
126
g/
lb
steam
AE
=
O.
005126
*
1,433,041
1
AE
=
8.10
toniys
PM
| epa | 2024-06-07T20:31:40.985566 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0046/content.txt"
} |
EPA-HQ-OAR-2003-0072-0047 | Supporting & Related Material | "2002-09-20T04:00:00" | null | EASTERN
RESEARCH
GROUP.
INC
It
Stevenson.
EPNCombustion
Group
Jason
Huckaby.
Eastern
Research
Croup,
Inc
FROM:
DATE:
September
4,2002
SUBJECT:
\
/
Lee
County
W
C
/
Emissions
Variability
Analysis
1.0
INTRODUCTION
This
memorandum
presents
an
analysis
qf
the
variability
in
emission
that
occurs
at
a
well
operated
municipal
waste
combustor
(
MWC).
The
analysis
reviews
the
performance
of
the
Lee
County
(
FL)
MWC.
The
Lee
County
facility
is
equipped
with
the
full
battery
of
high
efficiency
and
has
operated
unmodified
since
start
up
in
1994.
Additionally
the
ards
for
high
standards
of
operation
and
performance.
MWC
includes
data
for
the
following
pollutants
mium
(
Cd),
lead
(
Pb),
mercury
(
Hg).
hydrogen
ch
oxides
(
NO,).
The
foIlowing
se
performance,
parame
annual
test
results.
2.0
FACILITY
DESCRIPTION
The
Lee
County
M
W
C
is
Iocated
in
Fort
Myers,
FL.
The
facility
has
capacity
to
combust
1,200
tons
per
day
(
tpd)
of
municipal
solid
waste
(
MSW)
in
two
600
tpd
municipal
waste
combustor
(
MWC)
units.
The
combustors
are
mass
burn
designs
using
reverse
reciprocating
C;
iSmaiMWCVer
County\
LeeVanabllLyrnemoi
1
793
stoker
grates.
Process
control
is
achieved
through
the
use
of
a
distributive
control
system
(
Le.,
sensors
transmit
operating
data
to
compu
make
adjustments).
The
au
pollution
control
systems
include
s
carbon
injection
(
CI),
and
selective
non
catalytic
re
scrubbing
syste
is
used
for
NOx
nitrogen
oxide,
produdtion,
power
additional
Hg
and
dioxidfuran
ion,
continuous
emission
monitoring
syste
vated
carbon
usage,
combustion
ctrical
energy
is
produced
by
a
39.7
Mw
electric
generator
driven
by
a
condensing
steam
turbine.
Fresh
water
usage
is
minimized
through
the
use
of
secondary
treate
steam.
Fly
ash
an
ttom
ash
are
passed
t
scalper,
magnetic
separator,
and
non
ferrous
recovery
system
IO
recover
metals
from
the
as
3.0
PLANT
OPERATIONS
began
in
1994,
the
MWC
units'
co
operators
and
maintenance
personne
monthly
written
quizzes
on
plant
operatio
and
maintenance
personnei
attend
se
operation,
the
Lee
County
facility
has
recently
been
aw
Attachment
A).
4.0
PLANT
ENVIRONMENTAL
PERFORMANCE
Since
it
began
operations,
the
Lee
County
facility
has
been
in
full
compliance
with
all
federal,
state,
and
local
regulations.
The
facility
has
not
required
any
modification
to
demonstrated
compliance
with
permitted
levels
for
PM,
op
Ifuric
acid
mist,
fluorides,
NO,,
carbon
monoxid
nia,
and
dioxidfimns.
As
a
result
of
their
outs
e
Lee
County
facility
was
awarded
the
Environmental
Citizen
istrict
office
of
Florida's
DEP.
The,
ASME
award
no
(
Attachment
AI
contains
detailed
information
on
environmental
performance
for
both
air
I
5.0
PARAMETRIC
DATA
I
Operating
parameter
data
were
obtained
from
the
Lee
County
facility
for
the
years
a1
compliance
test
data
(
1994
2001
>.
This
data
includes
information
nd
the
operating
variables
associated
with
the
air
pollution
control
tains
the
parametric
data.
6.0
EMISSfO
BILITY
ANALYSIS
as
analyzed
to
determine
the
amount
of
emissions
variabili
aintained
IWC.
Statistical
tests
were
performe
th
units
couid
be
combined
for
analysis
and
what
type
of
distribution
(
is.,
t
closely
fit
the
data
for
each
polhtant.
Addition
was
necessary.
The
analysis
investi
compliance
jtevel.
The
les
I
and
2.
Additionally,
Figures
ugh
8
present
data
plots
of
the
test
1
.
The
complete
data
Table
1.
Summary
Statistics
for
Stack
ear
1994
through
Particulate
Matter
(
rng'dscm)
ail
values
corrected
to
3%
02.
'
arithmetic
average.
Particulate
Matter
variability
of
data
arithmetic
avera
4
4
CSmallMWCUee
County\
lneVanablttymemofutdwpd
Figure
1.
Lee
County
Dioxin/
furan
(
total
mass
basis)
I996
1997
1998
1999
2000
2001
1994
1995
Year
5
Figure
2.
Lee
County
Mercury
0.05
A
E
+
0.04
m
E
Y
$
2
0.03
0.02
0.01
0
1994
1995
1996
1997
1998
Year
1999
2000
2001
0.0014
0.001
.
cI
f3
s
t
.
I
o*
0008
E
0.0006
0
P
0.0004
Figure
3.
Lee
County
Cadmium
0.0013
0.0013
0.0013
0.0002
0
1997
1998
1999
2000
2001
1994
1995
1996
Year
7
'
s
h
11
4.
Lee
County
Lead
~
_
~
_
0.02
i
i
0.01
9
0.01
8
0.01
6
0.01
4
,
g
0.0t2
u
u)
5
0.01
1
x
2
0.008
0.006
0.004
0.002
0
1994
1995
1996
1997
f
998
8
Year
1999
2000
2001
t
P
E
I
Figure
5.
Lee
County
Particulate
Matter
9.2
9
8
7
6
5
4
3
2
1
0
1996
1997
1998
1999
2000
2001
1994
1995
Year
CISmaMWCUae
CountyUteVanabiltymemofma1
wpd
9
18
16
34
12
A
>
e
10
8
H
6
4
2
0
1994
1995
1996
1997
1998
1999
2000
2001
Year
45
40
35
25
e
n
Y
15
70
1994
I995
7
996
1997
1993
1999
Year
2000
2001
I
1
165
160
S:
155
E
n
P
150
145
140
135
1994
1995
1996
1997
t
998
Year
1999
2000
2001
C.
tSmallMWCU.
ee
Cuunty\
LrrVnriabilt~~
otinal
wpd
12
r
f
d
B
Attachment
A
Waste
to
Energy
Facility
Recognition
Award
by
ASME
i
I
~
3
1
:>
t,.
5
INTEROFFICE
MEMO
U
M
FROM
SOLID
WASTE
DMSION
Phone:
(
941)
479
8181
Fax:
(
941)
479
8119
e
county
SOUTRWEST
FLORIDA
Date:
April
30,2001
TO:
Jim
Lavender,
Director
From:
Lindsey
J.
Sampson,
P.
E.
s
ste
To
Energy
Facility
Recognition
Award
by
ASME
can
Society
of
Mechanical
that
an
award
will
be
pres
Solid
Waste
Processing
County
and
Covmta
L
the
facility's
contributions
to
the
field
of
solid
waste
proc
n
ual
North
American
hc.,
at
no
cost
to
the
County.
ation
that
was
included
in
the
Cc:
BOCC
Districts
1
5
D.
Stilwell
T.
Eriksen
4
American
Society
cal
Engineers
Solid
Waste
cility
Re
plication
ee
Solid
Waste
Resour
Facility
Facility
Recognition
Award
Nomination
Form
1.
Award
Category
Combustion
ame
Recovery
Facility
(
the
'%'
acility
'
3
10500
Ft.
My
4.
Owner
Lee
Cotinty
Solid
Waste
Division
(
the
''
County'
3
Address:
1500
Monroe
Sireet
Contact:
Telephone:
341
479
8
I81
Fax:
94
1
479
81
I9
5
.
0
r
Martin
Systems
of
Lee.
hc.
("
OMSL")
Contact:
Tom
Eriksen
Telephone:
Fa:
941
337
2510
1
1
?
4
6.
Throughput
Capacity
(
tons
per
day)
1,200
tons
per
day
7.
Facility
Description
Provide
a
general
description
of
the
Facility,
including
each
major
piece
of
equipment
Include
attachment
as
needed.
Dirtral
water
wall
Opaciiy,
Sulfiir
Dioxide,
total
st
used
to
condense
the
turbine
exhaust
steam.
l3k
8.
Summary
of
Facility
Operations
Provide
a
general
summary
of
Facility
opera
through
the
Facility,
materials
andor
energy
needed.
"
Firxt
fire"
at
this
Facility
to
Department
of
Environmental
first
followed
by
the
Turbine
Generator
on
September
2
Acceptance
testing
was
conducted
from
October
I7
Construction
Agreement
beiween
Ogden
and
Lee
Cotrn
Stan
up
of
the
Facility
>
vas
virtuallyfla
passing
of
acceptance
testing
I
,
1994.
The
project
was
completed
Since
going
commercial
the
FaciIiq
h
availability
of
99.6
percent.
A
prodiiced;
1,077.000
Ktyh
ofpower
generated;
tons
of
ferrous;
and
835
tons
of
Ron
ferroous
me
environmental
permits
and
regulations
tial
operating,
hour
ere4
staffing,
a
d
other
key
operationa1
hon,
flow
of
materials
Include
attachment
as
County,
Ogden
and
the
Florida
roblems
noted
With
the
on
effective
December
ASME
SWPD
Fa
d
Nomination
Form
9.
Key
Contributions
to
the
Field
of
Solid
Waste
Processing
The
ASME
Solid
Waste
Processing
Division
Facility
Recognition
Award
is
based
on
information
provided
in
this
section
regarding
the
Faciliq's
contributions
to
the
field
of
solid
waste
procesmg.
The
key
selection
criteria
and
weightin
are
as
follows:
I,
Success
in
Reaching
Facility
Operation
Requirements
(
20
percent)
the
established
operating
requirements
for
the
Facility,
and
the
history
of
the
Facility
with
respect
eeting
those
operating
requirements.
me,
at
a
minimum,
is
meamred
by
the
abiliiy
ofthe
Facility
to
operate
and
be
maintained
in
s
z
h
a
manner
te.
generate
steam,
and
convert
the
steam
into
electric
power
for
export,
at
a
level
consistent
nce
Guarantees
contained
in
the
Service
Agreement
between
the
County
and
The
ting
,
I
ce
Guarantees
contained
in
Schedule
2
of
the
Service
Agreement
are
used
as
the
basis
for
nce.
These
Pejormance
Guarantees
include:
erage
Energy
Guarantee
Utility
Utilization
Guarantee
hropane
gas)
~
nee
Guarantees*
petj4onnanceparameters
measured
during
the
Facility's
acceptance
test
Facility
perjomance.
These
perjormance
parameters
include:
ate&
1.8
million
tom
of
waste
in
fistfive
years
of
operation,
which
is
96.8
vailability
of
1,200
tons
per
day).
During
the
first
three
years
of
compliance
of
waste.
Waste
processed
by
the
Facility
has
increased
evey
year,
e
County's
waste
generation.
In
the
fifth
billing
year,
th
e
during
the
five
yearperiod.
This
is
26.5
percent
by
Mwh
of
electricity
for
sale.
The
Facility
P
net
elecrric
essed,
as
more
m
t
e
has
became
availablefiom
the
1
year
averaged
601
kWh
per
ton
of
wcrste
processed,
able
the
Facility
to
recover
energy
at
th&
rate,
high
e$
ciency
boilers,
wz
pressure
and
temperature,
were
installed
to
increase
the
turbine
efficiency.
generated
per
ton
of
waste
processed
has
generally
increased
over
the
seven
years
of
operation.
generator
over
the
first
seven
years
was
99.6percent.
3
ASME
SWPD
Facility
Recognitio
II.
Innovative
Contributions
to
Solid
Waste
P
Describe
the
Facility's
contributions
to
equipment,
or
operations;
approaches
applications
of
equipment
or
materials.
your
goals.
The
Lee
County
project
has
several
innovative
recovery
systm,
its
ecologically
sound
reuse
elements.
In
the
early
stages
ofnegotiations
L
standards.
The
Facility
was
therefore
sulpassed
rhese
standards
since
start
all
clean
air
retrofits
throughout
th
This
Facility
was
designed
to
pro
in
the
United
States
with
a
perm
wet
design.
one
where
acriv
into
a
mix
tankfiom
where
the
carbonfwater
s
to
comply
with
n
I50
ug/&
cm
standard.
This
consistently
rneefi
A
post
combustion
fenous
followed
by
a
screened
tro
that
would
have
been
destined
for
the
landfill
an
in
line
non
ferrous
The
Faciliw
also
provides
a
long
range
bene4t
20
area
wide
water
resource
management.
supplied
by
the
Ciiy
of
would
have
been
discharged
into
suface
waters,
now
serves
"
reciaaim"
water
IS
us
ue
air
pollution
control
system.
its
metals
ent
since
start
up
and
d.
Partially
due
to
the
\
i
1
0
gallons
per
day
of
the
atmosphere
in
the
~
1
i
Additionally,
the
water
transmission
lines
coILThsl~
conservation
efforts
in
the
area.
Many
exotic.
non
native
ecies
have
been
in
Fuctlity
war
irrf2sted
with
the
problematic
exotic
were
eradicated
and
the
weltand
rstored.
A
n
clogged
with
non
native
aquatic
wee&.
methods
to
remove
rhese
wee&
the
Fa
These
fish
have
since
condition.
4
1
E
d
MREE
SWPD
Facility
Recognition
Award
Nomination
Form
ore
important
to
the
Facdity
than
health
andsafety.
AI1
Facility
personnel
are
repued
to
attend
monthly
safe9
specific
OSHA
required
sdety
training
themes
me
presented
by
the
Facility
'
s
S
a
f
e
Coordinator.
onnel
also
attend
weekly
safety
meetings
where
plant
safity
procedures
are
discussed
e
in`
the
employee
medical
surveiilance
program
which
includes
annual
physicals.
indushial
hygiene
ring
outage
and
non
outage
periods
to
determine
ifl
where,
when
and
what
type
of
respiratory
may
be
required
Monthly
plant
walkdowns
are
conducted
by
the
Faciiitys
safety
committee.
d
and
quickly
resolved
\
mpiled
an
excellent
safety
record.
The
plant's
OSHA
Frequency
Index
not
surtained
any
lost
time
injuries.
in
1998.
I999
and
2000.
the
Facil
d
a
this
outstanding
performance
and
has
operated
the
Facility
for
the
last
3
years
with
excellent
relationship
with
the
local
environmental
agencies.
llzk
ilt
on
trust
and
the
howledge
that
the
Facility
has
and
will
continue
to
compi)
with
all
pennit
e
local
DEP
stag
to
attend
all
vendor
training
sessions
along
over
a
three
month
period
and
DEPpersonnel
attended
every
one.
By
el
were
able
to
understand
the
operation
of
not
just
the
pollution
control
equip
became
acquainted
with
the
FaciliQ
stuff
and
realized
the
level
of
education,
lied
by
vendors
prior
to
start
up,
in
fact
it
hadjust
begun.
AN
operators
are
required
to
rn
on
power
plantfitndumentals
as
well
as
Facility
speczjk
Step
Training
program
prior
continual
on
the
job
training
and
are
given
written
quizzes
each
month
on
plant
systems.
a
lunch
of
their
choice
as
recognition
and
a
competitive
incentive.
a1
management
training.
Maintenance
and
administrative
personnel
cafiold
erection,
pump
repair,
bearing
maintenance,
FaciIiq
c
i.
e.
chlorine
handling,
water
treatmznt
and
heavy
irtance.
Several
employees
are
pres
ining
relative
to
their
support
of
the
Facility
This
training
includes
ace
entry,
quarterly
fire
drills,
elevator
rescue.
and
chemical
handling.
all
operation
and
maintenance
personnel
receive
wee
erating
Manual.
These
Amendmew
also
required
th
Extensive
training
in
Facility
operations
an
ts.
Presently
the
Facility
Ma
as
Chief
Facility
Operator
Certification,
the
ng
in
vaste
ifi
Supervirors
have
the
four
Control
Room
I
Waste
Combustor
training
course.
5
`
I
1
4
~
ET.
Technical
Contn'butions
to
Solid
Waste
The
following
nunmarizes
the
Facility`
s
Technical
"
gent
regulations
created
by
the
iremen&
the
Faciliq
proved
that
Clean
Air
Act
Amendment
Acts
of
I990.
iVon
Ferrous
Recovery
overy
sysrem.
The
contractor
date.
The
system
was
installed
aiko
increasing
the
Inconel
Application
for
Corrosion
Control
The
Faciliy
has
obse
ally
related
to
the
pam
idenhBed.
The
entire
furnuce
area
"
R"
Stamp
recognized
the
need
to
have
an
proceeded
by
applyingfo
facility
personnel
to
pedom
required
boiler
rep
down
time.
Power
to
Newly
Constru
W%
en
a
new
recyclingfacii
The
company
perfrmed
a
the
new
faciliry.
The
res
ASME
SWPD
Facility
Recog
Facility
Preservation
O&
fSL
has
corntan
been
investigating,
experimenting
and
utilizing
erotic
materials
to
help
stem
conmion
occum
ng
in
high
humidity,
alkaline,
and
acidic
areas.
The
use
of
these
materials
result3
in
less
maintenance
and
a
longer
service
&
e
of
systems
inrtalled
in
iner
rmance
Enhancement
on
the
demineralization
system
due
to
decreasing
potable
water
quality.
OMSL
the
water
through
a
reverse
osmosis
membrane
water
treatment
system
in
a
much
improvedperfomance
of
the
demineralizer,
&
meased
chemical
.
acid
Wash
System
to
Ciem
Atombms
atomizers
proved
to
be
a
high
maintenance
item.
OMSL
designed
and
installed
and
acidgwh
operating
cleaner,
reducing
maintenance.
and
provided
proper
slurry
disrnhition
in
the
scmbbm
resulting
in
less
downtime
and
decreased
emissions.
On
line
Binsting
of
Baghouses
dnd
Off
line
Cleaning
of
Eloiler
to
energy
facilitis
to
utilize
on
line
percussion
cIeaning
to
improve
the
operation
of
the
harges
are
set
offin
the
fly
ash
hoppers
while
the
boilers
are
in
operation,
that
res&
in
a
a
longer
period
between
outages
increasing
availability.
aned
off
line
with
these
*
amile
charges.
ThiY
results
in
a
cleaner
boiler
and
no
w
e
of
water
corrosion.
TiiY
jiirther
provides
a
cleaner
working
environment
for
mainten
ed
outage
lime,
and
reduces
the
amount
of
wastewater
generatedfiom
the
Fa
rmance
of
the
Facility
with
respect
to
air
quality,
water
quality,
workplace
nt
environmental
areas.
Include
attachments
as
needed
(
e.
g.
monitoring
data,
graphs).
a
summary
of
the
Facility's
Environmental
Performance:
Environmental
Performance
ent
recordsince
starnip
The
Fucility
has
been
in
fill
compliance
with
all
an
Air
Act
of
i
995
without
performing
any
mod@
cations
to
the
plant.
i
n
uddigon,
tal
Citizen
Award
for
the
results.
Annual
Air
Emissions
Testing
dnnuai
uir
emissions
testing,
also
known
as
stack
teshg.
wusper$
ormed
at
the
Facility
in
June
2000.
During
this
stack
test.
issions
of
particulate
matter
(
P%$
l,
opacity,
arsenic,
bqliium,
lead,
mercuv,
sulfMic
,
carbon
monoxide,
volatile
organic
compounds
(
TOG),
mlfir
dioxide*
hydrogen
demonstrated
to
be
in
compliance
with
all
permitted
levelsfor
mercuy,
sulfiric
acid
mist.
fluorides,
nitrogen
oxides
(
WOd,
carbon
&
ir
dioxide.
hydrogen
chloride,
ammonia,
and
dioxinsi@
ram.
7
I
__
i
_
I
I
3
a
ASME
SWPD
Facili
ard
Nomination
Form
Tale
Y
Operating
Permit
0710119
0014
Vto
the
Facility
on
November
I
.
2000.
In
recognition
of
the
excellent
level
DEP
awarded
Ogden
Martin
Sys
me
honor
because
it
the
DEF,
the
award
tained
by
the
Facility
the
South
n
Award
''
on
September
12,19
V.
FaciIity
Economics
(
10
percent)
Discuss
comparative
costshipping
fe
management
facilities.
Long
rem
environmentally
responsible
solutions
to
VI.
Role
in
Integrated
Waste
Managemen
Describe
the
role
of
the
Facility
in
n.
and
agricllltural
waste
collection
center
(
under
cons
progrants
that
are
10.
Supplemental
Xnformation
c3
Photographs
ASME
SWPD
Facility
Recognition
Award
Nomination
Form
Submitted
By
Samer
Malcolm
Pirnie,
Inc.
Address:
1715
E.
9"'
Avenue
Tampa,
Florida
33605
Telephone:
(
8
13)
248
6900
Fax:
(
813)
248
8085
Number
of
Copies
Five
complete
copies
o
the
nomination
submittal
should
be
provided
Nomination
Due
Date
ASME
Solid
Waste
Processing
Division
Selection
Process
judged
by
the
SWPD's
Facility
Recogtion
Award
subcommittee
of
the
Honors
and
Awards
Committee,
selection
criteria
described
above.
The
selection
process
will
be
completed
upon
approval
ofthe
recommended
D's
Executive
CodUee.
ted
at
the
annual
Waste
Processing
Conference
@
JAWTEC).
The
award
will
consist
of
a
plaque
2suitabie
for
mounting
at
the
Facility.
ication
of
Award
will
publicize
the
award
through
press
releases
and
various
ASME
and
waste
management
industry
publication.
D
member
in
good
standing
may
nominale
a
FaciIity
for
the
SWPD
FaciSity
Recognition
Award.
Self
nomination
by
Facility
personnel
are
welcome.
9
PHOTOGRAPHS
An
array
of
instruments
in
the
plant's
control
room
Facility
staff
monitor
the
plant's
condition
1
A
view
of
plant
piping
le.
*
2
I
The
refuse
claw
in
action
Facility
tipping
floor.
The
refuse
pit
is
visible
to
the
left.
1
i'
ter
pumps
at
the
cool
tower.
Sid
4
The
Facility's
reverse
osmosis
plant.
&
.
t
i.
View
of
the
non
ferrous
metal
recovery
pile
7
t
EXCERPTS
OF
FDEP
2000
SOLID
WASTE
MANAGEMENT
ANNUAL
REPORT
LOU0
Solid
Waste
Management
m
Elonda
I
Employee
Directory
I
Help
1
SiteMap
1
Search
Solid
w
ment
in
Florida
2000
This
2000
Solid
Waste
Man
nual
Report
provides
a
comprehensive
analysis
of
solid
ludes
information
about
the
activities
of
the
Department,
ai
in
Florida
primarily
based
on
information
compiled
by
ling
with
waste
issues
t
n
s
for
downloading
rh3
whole
report
for
viewing
online
rt
is
availabie
in
Adobe's
Portable
Document
Format
(
PDF).
If
you
d
f
the
reader
software,
it
is
avaifable
free
of
charge
from
Adobe's
s
above
to
download
the
software
now.
Once
you
have
the
Acroba
you
may
download
the
entire
report
or
specfic
chapters.
PDF
file
is
too
small
to
read,
use
the
magnifyng
glass
tool
to
zoom
in.
n
the
appendices
can
also
be
downloaded
in
an
Microsoft
Excel
Instructions
the
chapters:
AVAILABLE
NOW!
These
files
will
dated
shortly,
so
please
be
patient,
you
may
wish
to
wait
until
the
efore
downloading.
Check
back
the
beginning
of
March.
1.
Create
a
directory
an
you
can
do
it
during
many
of
2.
rd
drive
for
the
report.
If
you
forget,
you
ng
file,
cDacwszisgzc
is,
saving
it
in
on
your
is
3
19
Megabytes
(
M8).
It
will
take
some
time
to
patient.
save
this
Droqram
to
disk"
oDtion
and
then
select
llowing
steps
also.
3.
http
://
www
.
dep
state
.
fl
.
us/
dwm/
documents/
sdswn
OO/
defauk
htm
03/
07/
200
Z
Counties
(
CY
1998)
have
recycling
rates
21
County
I
(
Jan.
1,
7998
Dec.
31,
7998)
4.
4
6.
6.
324
233.
133.
47.
1.450.
247.
13.
55.
892
107.
85.
106.
2.090.
210.
80.
33.
25.
13.
35.
19.
13
i
7
19
3
148
10
6
1%
109
175
54
13
321
32
147.
22
50.
14
34
21.
27
43.
21.
7.
38.
Studies
as
reported
by
eact~
c.
aUay
by
ma
end
of
19%
for
eachcancymth
apopubtia,
over
75.
W.
fa
these
materials
by
theand
of
1994
for
each
canty.
n
36
35
35
40
34
32
31
31
37
30
28
n
37
27
43
27
39
26
28
26
32
25
25
24
27
24
40
23
22
22
22
21
20
20
19
27
18
18
17
16
18
16
16
15
75
t5
15
14
13
13
13
12
12
12
11
10
10
9
9
9
8
7
5
4
3s
3
1
d
sd
11
55
56
41
84
22
39
26
20
48
61
85
63
53
42
36
44
57
53
73
17
0
12
33
29
42
75
31
47
35
7
21
9
7
8
3
7
1
93
11
0
100
t
4
40
21
37
n
55
20
11
0
17
22
0
0
31
20
3
15
26
17
5
30
0
2
n
0
26
76
64
94
14
26
0
6
33
37
16
40
12
27
3
5
63
35
75
29
0
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13
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a
1
FDEP
03/
0712001
&.
XIS
Attachment
B
Lee
County
Parametric
Data
Counq4LeeVambifrymemofmai.
wpd
e
*
I
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Attachment
C
Compliance
Test
Data
Analysis
for
Lee
County
Solid
Waste
Resource
Recovery
Facility
C:\
SmaUMWC\
Lee
County\
LeeVar1abiltymemofmaLwpd
COMPLIANCE
TEST
DATA
ANALYSIS
FOR
LEE
COUNTY
SOLID
WASTE
RESOURCE
RECOVERY
FACILITY
Prepared
for:
US.
Environmental
Protection
Agency
Office
of
Air
Quality
Planning
and
Standards
Emission
Standards
DivisiodCombustion
Group
Research
Triangle
Park,
NC
27560
Prepared
by:
Eastern
Research
Group
1600
Perimeter
Park
Drive
Morrisville,
North
Carolina
27560
September
4,2002
*
ERG
September
2002
TABLE
OF
CONTENTS
Section
Paye
#
1
.
O
DESCRIPTION
OF
LEE
COUNTY
SOLID
WASTE
RESOURCE
RECOVERY
FACILITYDATA
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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2.0
STUDYOBJECTIVES
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3.0
PRELIMINARY
DATA
ANALYSIS
.
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4
4.0
COMPREHENSIVE
DATA
ANALYSIS
.
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6
4.1
Statistical
Distribution
of
Pollutant
Emission
Measurements
.
.
e
.
.
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e
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6
4.1.1
Dioxin/
Furan
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,
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8
4.1.2
Particulate
Matter
(
PM)
.
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8
4.1.3
Cadmium
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9
.
4.1.4
Lead
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4.1.5
Mercury
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l
O
4.1.6
Mercury
Percent
Reduction
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10
4.1.7
Hydrogen
Chloride
(
HC1)
.
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.
1
1
4.1.8
Hydrogen
Chloride
(
HCl)
Percent
Reduction
.
.
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.
1
1
4.1.9
Sulfur
Dioxide
(
SO,)
Arithmetic
Average
.
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.
12
4.1.10
Sulfur
Dioxide
(
SO,)
Percent
Reduction
.
.
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12
4.1.11
Nitrogen
Oxides
(
NOJ
.
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13
4.2
95
and
99
Percent
Threshold
(
Le.,
Exceedance)
Values
.
.
.
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.
13
5.0
REFERENCES
.
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.
..
K
\
O
154U
1\
06\
mwc
analysis
report
September
2002.
wpd
11
ERG
September
2002
I
I
LIST
OF
TABLES
Page
Table
1
Raw
MWC
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Unit
1
...........................................
16
Recovery
Facility
Unit
2
............................
Table
2
Raw
MWC
Compliance
Data
from
Lee
County
Solid
Waste
Table
3
Summary
Statistics
for
MWC
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recov
1
.........................
18
Table
4
Summary
Statistics
for
M
W
a
from
Lee
County
Solid
Waste
lityUnit2
.
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.
.
.
.
Results
for
the
Two
Sample
F
Test
..................................
.20
Results
for
the
Two
Sample
t
Test
(
Equal
Variances)
.
.
.
.
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.
.21
Table
5
Table
6
Table
7
Summary
Statistics
for
MW
Solid
Waste
Resource
Reco
Units
1
and
2
Combined
.
*
*
*
*
*
*
*
*
*
.
*
*
*
m.
22
pliance
Data
from
Lee
County
Table
8
Summary
Statistics
for
C
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
..........................................
.23
Table
9
The
Shapiro
Wilk
Normality
Statistic
(
W)
for
the
Raw
and
Ln
TransformedMWC
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
..........
.24
Table
10
95
and
99
Percent
Thresholds
and
Threshold
Mean
Differences
for
the
Raw
and
Ln
transformed
MWC
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and2Combined
.
.
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2
5
...
111
K\
0154\
11\
06\
mwc
anaIysis
rq~
o1'
t
September
2002.
wpd
w
'
ERG
September
2002
LIST
OF
FIGURES
Page
Figure
l(
a)
Frequency
Histograms
for
Dioxifluran
(
ng/
dscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
..........................................
.26
Figure
1
(
b)
Normal
Probability
Plots
for
Dioxifluran
(
ng/
dscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Unitsland2Combined
...........................................
27
Frequency
Histograms
for
PM
(
mg/
dscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Unitsland2Combined
...........................................
28
Figure
2(
a)
Figure
2(
b)
Normal
Probability
Plots
for
PM
(
mddscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
..........................................
.29
Frequency
Histograms
for
Cadmium
(
mg/
dscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
..........................................
.30
Normal
Probability
Plots
for
Cadmium
(
mg/
dscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
..........................................
.31
Frequency
Histograms
for
Lead
(
mg/
dscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and2
Combined
..........................................
.32
Normal
Probability
Plots
for
Lead
(
mg/
dscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
..........................................
.33
Figure
3
(
a)
Figure
3(
b)
Figure
4(
a)
Figure
4(
b)
Figure
5(
a)
Frequency
Histograms
for
Mercury
(
mg/
dscm)
Compliance
Data
&
om
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
...........................................
34
Figure
5(
b)
Normal
Probability
Plots
for
Mercury
(
mg/
dscm)
Compliance
Data
fiom
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
..........................................
.
3
5
K:\
0154\
11\
06bnwc
analysis
report
September
2002.
wpd
iv
LIST
OF
FI
S
(
Continued)
Figure
6(
a)
Frequency
Histograms
for
Data
from
Lee
County
Units
1
and
2
Combine
.
.
.
.
.
.
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.
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.
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.
.
3
6
Figure
6(
b)
Normal
Probability
PI
Figure
7(
a)
Frequency
Histograms
for
Data
from
Lee
County
Sol
Units
1
and
2
Comb
Normal
Probability
Plots
for
HC1
(
ppmv)
Compliance
Data
from
Lee
County
Figure
7(
b)
Units
1
and
2
Combine
.
.
.
.
.
.
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.
.
.
.
.
.
Figure
8(
a)
Frequency
Histograms
for
H
Reduction
Compliance
Data
from
Lee
Co
Units
1
and
2
Comb
Normal
Probability
Plots
for
HC1
Percent
Reduction
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
.
.
,
.
.
.
.
.
.
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.
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.
.
.
.
.
.
.
.
Frequency
Histograms
for
SO,
Arithmetic
Average
(
ppmv)
Compliance
Data
from
Lee
County
Solid
Wast
Units
1
and
2
Com
e
Recovery
Facility
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
4
0
Figure
8(
b)
Figure
9(
a)
urce
Recovery
Fa
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Figure
9(
b)
Normal
Probability
Plots
for
SO,
Arithmetic
Average
(
ppmv)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Reco
Units
1
and
2
Combined
....................
'
*
*
*
*
43
Figure
1O(
a)
Frequency
Histograms
ent
Reduction
Compliance
Data
from
Lee
County
Units
1
and
2
Combined
Figure
1
O(
b)
Normal
Probability
Plots
for
SO,
Percent
Reduction
Compliance
Data
from
Lee
Coun
Units
1
and
2
Comb
Frequency
Histograms
for
NO,
(
ppmv)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Unitsland2Combined
.
.
.
.
.
.
.
.
.
.
.
.
,
.
.
.
.
.
.
.
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,
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.
4
6
Recovery
Facility
..........................................
.44
ery
Facility
.
.
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.
.
Figure
1
1
(
a)
V
K
\
O
154\
11\
06\
mwc
analysis
report
September
2002.
wpd
LIST
OF
FIGURES
(
Continued)
Figure
1
1
(
b)
Normal
Probability
Plots
for
NO,
(
ppmv)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
.
.
.
.
.
,
.
.
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,
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.
.
.47
KA0154\
11\
06\
mwc
anaiysis
report
September
2002.
wpd
.
.
Y
vi
'*
ERG
September
2002
1.0
DESCRIPTION
OF
LEE
COUNTY
SOLID
WASTE
RESOURCE
RECOVERY
FACILITY
DATA
Upon
request
from
the
U.
S.
Environmental
Protection
Agency,
COVANTA
Lee
Inc.
submitted
annual
municipal
waste
combustor
(
MWC)
compliance
data
for
the
period
1994
to
200
1
from
its
solid
waste
resource
recovery
facility
located
in
Lee
County,
Florida.
The
facility
consists
of
two
600
tons
per
day
(
tpd)
mass
burn
waterwall
units
(
referred
to
as
Unit
1
and
Unit
2)
each
of
which
is
equipped
with
spray
dryer,
fabric
filter,
carbon
injection,
and
selective
non
catalytic
reduction.
The
MWC
data
submitted
included
emissions
measurements
from
both
units
for
the
following
pollutants:
e
e
e
e
e
e
Dioxidfuran
(
ng/
dscm),
Particulate
matter
(
PM)
(
rng/
dscm),
Cadmium
(
mg/
dscm),
Lead
(
mg/
dscm),
Mercury
and
percent
mercury
reduction
if
available
(
mg/
dscm),
Hydrogen
Chloride
(
HCl)
and
percent
HC1
reduction
if
available
(
ppmv),
Sulfur
dioxide
(
SO,)
and
percent
SO,
reduction
if
available
(
ppmv),
Nitrogen
oxides
(
NOJ
(
ppmv).
The
tests
followed
the
procedures
required
by
the
large
MWC
New
Source
Performance
Standards
(
NSPS)
(
40
CFR
Subpart
Cb).
The
values
reported
for
dioxins/
furans,
PM,
cadmium,
lead,
mercury
and
HCl
are
the
arithmetic
average
control
device
outlet
levels
for
a
3
run
stack
test
using
the
EPA
test
methods
and
sampling
times
required
by
the
NSPS.
For
mercury,
the
average
percent
reduction
for
the
3
run
test
is
also
provided.
The
SO,
values
are
%
hour
arithmetic
average
outlet
concentration
and
percent
reduction
values
calculated
fiom
continuous
emission
monitoring
(
GEM)
data
during
the
first
24
hours
of
the
annual
performance
test.
(
Note
that
Subpart
Cb
requires
facilities
to
demonstrate
SO,
compliance
with
either
a
geometric
mean
outlet
concentration
or
a
percent
reduction.
The
facility
is
using
percent
reduction
and
did
not
K\
0154\
11\
06unwc
analysis
report
September
2002.
wpd
1
t
provide
the
geometric
mean.)
device
outlet
calculated
from
CEM
d
Tables
1
and
2
present
the
raw
MWC
compliance
data
provided
by
the
Lee
County
solid
waste
resource
recovery
facility
units
1
and
2
94
through
2001.
'
EQG
September
2002
2.0
STUDY
OBJECTIVES
The
main
objectives
of
the
study
are:
To
characterize
the
variability
in
pollutant
emission
measurements
(
due
to
variability
in
process
and
measurement)
using
basic
univariate
statistics
and
relative
frequency
histograms,
To
evaluate
the
statistical
distribution
of
pollutant
emission
measurements
(
ie.,
normal
versus
lognormal)
with
normality
tests
and
applicable
shape
statistics,
such
as
relative
frequency
histograms
and
normal
probability
plots,
and
To
compute
relevant
threshold
values
(
Le.,
exceedance
values),
based
on
computed
sample
means
and
standard
deviations,
for
which
the
probability
that
a
given
test
at
the
facility
will
be
above
the
threshold
value
is
95
and
99
percent.
*
K
\
O
1
5
4
1
1\
06\
mwc
analysis
report
September
2002.
wpd
3
I
~~~
1
"?
3.0
PRELIMINARY
DATA
ANALYSIS
Tables
3
and
4
present
the
routine
swnmary
statistics
for
the
annual
MWC
compliance
data
fiom
the
Lee
County
solid
waste
resource
recovery
facility
units
1
and
2,
respectively,
for
the
period
1994
to
200
1
pollutant,
ERG
first
evaluated
precision.
For
this,
ERG
empl
any
evidence
to
indic
the
two
units
are
substantial1
sts
that
assess
whether
there
is
First,
ERG
conducted
a
hypothesis
t
r
there
is
sufficie
indicate
a
significant
difference
in
the
variability
and
2.
Table
5
presents
the
results
of
the
hypothesis
test
(
two
sample
F
test)
conducted
for
each
pollutant.
Because
the
computed
value
of
the
F
statistic
was
less
than
the
critical
value,
Fa,
for
all
pollutants
at
the
95
and
99
percent
confidence
levels,
ERG
faiIed
to
reject
the
null
hypothesis
that
the
variability
of
pollutant
emission
measurements
from
the
two
units
are
statistically
equivalent.
Having
established
that
there
is
insufficient
evidence
to
support
that
the
observed
variability
of
pollutant
emission
measurements
for
Unit
1
is
different
than
that
of
Unit
2,
ERG
conducted
an
additional
hypothesis
test
to
evaluate
whether
there
is
sufficient
evidence
to
indicate
a
difference
in
the
mean
value
of
pollutant
emission
measurements
between
the
two
units.
Table
6
presents
the
results
of
the
hypothesis
test
(
two
sample
t
test)
conducted
for
each
pollutant.
From
the
table,
the
absolute
value
of
the
computed
t
statistic
is
less
than
the
critical
value,
t,,
for
all
pollutants
at
the
95
and
99
percent
confidence
levels.
This
indicates
that
there
is
insufficient
evidence
to
reject
the
null
hypothesis
that
the
mean
pollutant
emission
measurements
fiom
the
two
units
are
statistically
equivalent.
Because
both
hypothesis
tests
suggest
that
there
is
no
statistically
significant
difference
in
the
mean
pollutant
emission
measurement
and
its
variability
between
Units
1
and
2
for
each
4
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2002.
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c
ERG
September
2002
pollutant,
ERG
combined
the
data
for
the
two
units
for
all
pollutants.*
It
is
expected
that
the
data
from
the
two
units
would
be
similar
because
the
designs
of
the
combustors
and
control
equipment
are
identical,
they
were
installed
at
the
same
time,
they
receive
MSW
from
the
same
sources,
and
they
are
operated
and
maintained
similarly
at
the
same
MWC
facility.
Table
7
.
presents
the
routine
summary
statistics
for
MWC
compliance
data
from
the
Lee
County
solid
waste
resource
recovery
facility
units
1
and
2
combined.
Table
8
provides
the
same
summary
statistics
for
the
In
transformed
MWC
compliance
data.
*
It
should
be
noted
that
the
parametric
distributional
tests
conducted
are
relatively
low
power,
especially
for
small
sample
sizes.
Hence,
conclusions
obtained
fiom
these
tests
have
to
be
weighted
appropriately
in
light
of
other
relevant
considerations,
such
as
the
similarity
of
control
technologies
in
each
unit.
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September
2002.
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*
I
ERG
September
2002
(
1'
I
4.0
COMPREHENSIVE
DAT
ERG
utilized
several
statistical
an
data
for
both
units
combined.
These
techniques
1
0
ical
distribution
llutant
data
(
normal
ver
probability
plots,
s
and
normality
tests,
and
0
Computation
of
threshold
values
(
i.
e.,
exceedance
values)
for
each
pollutant
based
on
sample
means
and
standard
deviations.
The
following
sections
discuss
the
techniques
and
results
obtained
in
further
detail.
.
4.1
Statistical
Distribution
of
Pollutant
Emission
Measurements
There
are
numerous
methods
for
evaluating
the
statistical
distribution
of
a
given
data
set.
For
the
Lee
County
MWC
data,
ERG
employed
the
following
techniques
to
assess
whether
the
compliance
data
submitted
for
a
given
pollutant
is
normally
or
lognormally
distributed:
0
Frequency
histograms,
Normal
probability
plots,
0
Sample
moments
(
skewness
and
kurtosis),
and
0
Shapiro
Wilk
(
W)
test.
AJFequency
histogram
divides
the
data
range
into
units,
counting
the
number
of
points
within
the
units,
and
displaying
the
data
as
the
height
or
area
within
a
bar
graph.
The
frequency
histogram
provides
a
means
for
assessing
the
symmetry
and
variability
of
the
data.
If
the
data
afe
symmetric,
the
frequency
histogram
will
also
display
symmetry
around
a
central
point,
such
as
a
mean.
Typically,
the
frequency
histog
ibuted
data
will
be
bell
shaped.
6
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September
2002.
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i
U
#
ERG
September
2002
A
normalprobabilityplot
shows
the
observations
of
a
sample
plotted
against
a
cumulative
frequency
distribution
(
or
quantiles
of
a
data
set
against
the
quantiles
of
the
normal
distribution).
Comparing
against
the
standard
S
shaped
cumulative
frequency
distribution
is
difficult,
so
the
chart
transforms
the
observations
so
they
can
be
compared
against
a
straight
line.
Observations
for
a
normally
distributed
sample
should
closely
follow
a
straight
line.
For
non
normally
distributed
data,
there
will
be
large
deviations
in
the
tails
or
middle
of
a
normal
probability
plot.
The
normal
probability
plot
is
also
another
way
to
assess
the
degree
of
symmetry
(
or
asymmetry)
displayed
by
the
data.
For
example,
if
the
data
in
the
upper
tail
fall
above
and
the
data
in
the
lower
tail
fall
below
the
quartile
line,
the
data
are
too
slender
to
be
well
modeled
by
a
normal
distribution.
Similarly,
if
the
data
in
the
upper
tail
fall
below
and
the
data
in
the
lower
tail
fall
above
the
quartile
line,
then
the
tails
of
the
data
are
too
heavy
to
be
well
modeled
using
a
normal
distribution.
The
skewness
coeficient
measures
the
degree
of
symmetry
(
or
asymmetry)
displayed
by
a
data
set.
The
kurtosis
coefJicient,
on
the
other
hand,
measures
the
degree
of
flatness
of
a
distribution
near
its
center.
For
an
ideal
normal
distribution,
the
skewness
and
kurtosis
coefficients
are
equal
to
0.
Substantial
variations
from
the
0
value
indicate
that
the
data
may
not
be
modeled
using
a
normal
distribution.
The
Shapiro
Wilk
(
w)
test
is
one
of
most
commonly
employed
tests
of
normality.
The
test
involves
computing
a
correlation
between
the
quantiles
of
the
standard
normal
distribution
and
the
ordered
values
of
a
data
set
and
is
only
recommended
for
sample
sizes
less
than
or
equal
to
50.
The
statistical
power
of
the
test,
however,
declines
for
very
small
sample
sizes.
The
value
of
the
W
statistic
computed
for
a
given
set
of
data
can
range
from
0
to
1,
with
low
values
typically
leading
to
the
rejection
of
the
null
hypothesis
of
normality.
In
evaluating
the
most
appropriate
statistical
distribution
(
normal
versus
lognormal)
for
a
given
set
of
data,
the
results
obtained
from
the
application
of
the
above
statistical
techniques
have
to
be
considered
jointly.
Especially
for
small
sample
sizes,
no
single
technique
is
likely
to
yield
definitive
conclusions
on
the
type
of
distribution
displayed
by
the
data.
The
following
sections
present
the
results
of
the
statistical
analyses
performed
on
MWC
compliance
data
for
K:\
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September
2002.
wpd
7
,
each
pollutant.
The
sections
also
provide
an
assessment
the
data
based
on
the
analyses
performed
tatistical
distribution
displayed
by
4.1.1
Dioxin/
F'uran
The
frequency
histograms
dioxidfuran
data
are
depicted
in
Figures
1
(
a)
and
1
(
b
transformed
data
is
more
symmetric
aro
the
raw
data.
Further,
the
In
transforme
normal
probability
plot
depicted
in
Figure
1
data
(
0.0487)
is
much
statistics
for
the
raw
and
In
transformed
dioxidfuran
data
are
0.8568
and
0.9572,
respectively
(
see
Table
9).
The
W
statistic
indicates
a
normal
data
distribution
for
the
In
transformed
data
at
the
95
percent
level
of
confidence.
Overall,
the
analyses
performed
suggests
al
dioxidfbran
compliance
data
submitted
by
the
Lee
County
solid
wa
distribution.
4.1.2
Particulate
Matter
(
PM)
The
frequency
histograms
and
n
and
ln
tmnsformed
PM
data
are
depicted
in
Figures
2(
a)
and
2
is
more
symmetric
around
its
mean
with
so
the
In
transformed
data
is
more
evenly
spread
out
and
hence
more
close
straight
line
in
the
normal
probability
plot
depicted
in
Figure
2(
b).
The
skewness
coefficient
of
approximate
the
ed
data
(
0.0835)
is
7).
Similar
to
the
dioxin/
fbran
data,
ho
indicates
normality
at
the
95
percent
level
of
confidence.
r
the
In
transformed
PM
data
(
0.8688)
8
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September
2002.
wpd
P
Overall,
the
analyses
performed
suggests
that
the
annual
PM
compliance
data
submitted
by
the
Lee
County
solid
waste
resource
recovery
facility
display
a
lognormal
distribution.
4.1.3
Cadmium
I
The
fiequency
histograms
and
normal
probability
plots
of
the
raw
and
In
transformed
cadmium
data
are
depicted
in
Figures
3(
a)
and
3(
b),
respectively.
From
Figure
3(
a),
the
raw
data
appears
more
symmetric
around
its
mean
with
some
extreme
values
in
the
highest
bin
(
0.001
125
scm).
The
normal
probability
plot
of
the
raw
data
more
closely
approximates
the
straight
line
in
the
normal
probability
plot
depicted
in
Figure
3(
b).
Further,
the
skewness
coefficient
of
the
raw
data
(
0.544)
is
higher
(
closer
to
0,
the
value
for
an
ideal
normal
distribution)
than
that
of
the
In
transformed
data
(
0.9395).
The
W
tests
for
the
raw
and
ln
transformed
data
both
reject
the
null
hypothesis
of
normality
at
the
95
percent
level
of
confidence.
Overall,
the
analyses
performed
suggests
that
the
annual
cadmium
compliance
data
submitted
by
the
Lee
County
solid
waste
resource
recovery
facility
display
a
relatively
normal
distribution.
I
4.1.4
Lead
The
frequency
histograms
and
normal
probability
plots
of
the
raw
and
In
transformed
lead
data
are
depicted
in
Figures
4(
a)
and
4(
b),
respectively.
From
Figure
4(
a),
the
In
transformed
data
appears
more
symmetric
around
its
mean
with
some
extreme
values
in
the
5.25
to
4.75
range.
The
In
transformed
data
is
more
evenly
spread
and
hence
more
closely
approximates
the
straight
line
in
the
normal
probability
plot
depicted
in
Figure
4(
b).
Further,
the
skewness
coefficient
of
the
In
transformed
data
(
0.473
1)
is
lower
(
closer
to
0,
the
value
for
an
ideal
normal
distribution)
than
that
of
the
raw
data
(
0.876).
The
W
tests
conducted
for
the
raw
and
ln
transformed
data,
however,
both
fail
to
reject
the
null
hypothesis
of
normality
at
the
95
percent
level
of
confidence.
c
K:\
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reprt
September
2002.
wpd
9
I
Overall,
the
analyses
performed
suggests
that
the
annual
lead
compliance
data
suimitted
by
the
Lee
County
solid
waste
resource
recovery
display
a
lognormal
distribution.
,
4.1.5
Mercury
The
frequency
histograms
and
normal
probability
plots
of
the
raw
and
In
tr
mercury
data
are
depicted
in
Figures
5(
appears
more
symmetric
around
its
mean
with
fewer
extreme
v
evenly
spread
and
hence,
more
closely
appr
plot
depicted
in
Figure
5(
b)
as
well.
T
observations
clustered
along
higher,
hence
closer
t
(
2.6078).
The
computed
W
statistic
for
a
normal
data
distribution
at
the
95
percent
level
of
confidence.
the
value
for
an
Overall,
the
analyses
performed
sug
mercury
compliance
data
submitted
by
the
Lee
County
solid
waste
resource
recovery
facility
display
a
relatively
normal
distribution.
4.1.6
Mercury
Percent
Reduction
The
frequency
histograms
and
normal
probability
plots
of
the
raw
and
In
transformed
mercury
percent
reduction
data
are
depicted
in
Figures
6(
a)
and
6(
b),
respectively.
From
Figure
,
6(
a),
both
the
raw
and
the
ln
transformed
data
appear
to
be
positively
skewed.
There
also
is
no
substantial
difference
between
how
the
raw
and
In
transformed
data
are
spread
along
the
straight
line
in
the
normal
probability
data
(
1.3233)
is
higher,
henc
transformed
data
(
1
3549).
Fu
reduction
compliance
data
(
0
confidence.
efficient
of
the
raw
e
for
an
ideal
normal
distribution,
than
the
ln
raw
mercury
percent
95
percent
level
of
10
K.\
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154\
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wc
analysis
report
September
2002.
wpd
P
ERG
September
2002
Overall,
the
analyses
performed
suggests
that
the
annual
mercury
percent
reduction
compliance
data
submitted
by
the
Lee
County
solid
waste
resource
recovery
facility
display
a
relatively
normal
distribution.
4.1.7
Hydrogen
Chloride
(
HCI)
The
frequency
histograms
and
normal
probability
plots
of
the
raw
and
In
transformed
HCl
data
are
depicted
in
Figures
7(
a)
and
7(
b),
respectively.
From
Figure
7(
a),
the
In
transformed
data
appears
less
skewed
than
the
raw
data.
Further,
the
In
transformed
data
is
more
evenly
spread
out
and
hence
more
closely
approximates
the
straight
line
in
the
normal
probability
plot
depicted
in
Figure
7(
b).
The
skewness
coefficient
of
the
In
transformed
data
(
0.591
8)
is
lower
than
that
for
the
raw
data
(
1.3
140).
Finally,
the
W
test
for
the
In
transformed
data
fails
to
reject
the
null
hypothesis
of
normality
at
the
95
percent
level
of
confidence.
Overall,
the
analyses
performed
suggests
that
the
annual
HC1
compliance
data
submitted
by
the
Lee
County
solid
waste
resource
recovery
facility
display
a
lognormal
distribution.
4.1.8
HCI
Percent
Reduction
The
frequency
histograms
and
normal
probability
plots
of
the
raw
and
In
transformed
HCl
percent
reduction
data
are
depicted
in
Figures
8(
a)
and
8(
b),
respectively.
From
Figure
8(
a),
both
the
raw
and
the
In
transformed
data
appear
to
be
positively
skewed.
There
also
is
no
substantial
difference
between
how
the
raw
and
In
transformed
data
are
spread
along
the
straight
line
in
the
normal
probability
plot
depicted
in
Figure
S(
b).
The
skewness
coefficients
of
the
raw
and
In
transformed
data
are
nearly
identical
indicating
no
substantial
difference
between
using
the
two
distributional
assumptions.
Finally,
the
computed
W
statistics
for
the
raw
and
ln
transformed
data
both
fail
to
reject
the
assumption
of
normality
at
the
95
percent
level
of
confidence.
K
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September
2002.
wpd
11
4.1.9
Sulfur
Dioxide
(
SO,)
Arithmetic
Average
The
frequency
histograms
the
raw
and
ln
transformed
so,
ectively.
From
Figure
9(
a),
the
arithmetic
average
data
are
depicted
in
Figure
raw
data
is
negatively
skewed
wi
In
transformed
data
is
positively
ske
The
raw
data
is,
ho
plot
depicted
in
Figure
9(
b).
The
the
quartile
line
in
the
upper
tail.
hence
closer
to
0,
the
value
for
1.0151).
Additionally,
the
data
(
0.9030)
also
support
e
upper
tail
of
the
distribution.
0,
arithmetic
average
compliance
nt
level
of
confidence.
Overall,
the
analyses
performed
suggests
that
the
annual
SO,
ar
compliance
data
submitted
by
the
Lee
County
s
relatively
normal
distribution.
4.1.10
SO,
Percent
Reduction
1
The
frequency
histograms
an
probability
plots
of
the
percent
reduction
data
are
depicted
both
the
raw
and
the
In
transfo
percent
reduction
data,
there
is
no
s
data
are
spread
along
the
straight
li
skewness
coeffkients
of
the
raw
and
In
transformed
data
are
fairly
close
with
the
skewness
n
how
the
raw
and
In
transformed
coefficient
of
the
raw
data
slightly
better
than
that
of
the
In
transformed
one.
Finally,
the
'
ERG
September
2002
computed
W
statistics
for
the
raw
and
ln
transformed
data
both
fail
to
reject
the
assumption
of
normality
at
the
95
percent
level
of
confidence.
Overall,
the
analyses
performed
suggests
that
the
annual
SO,
percent
reduction
compliance
data
submitted
by
the
Lee
County
solid
waste
resource
recovery
facility
display
a
relatively
normal
distribution.
4.1.11
Nitrogen
Oxides
(
NO,)
The
frequency
histograms
anb
normal
probability
plots
of
the
raw
anc
In
transformed
NO,
data
are
depicted
in
Figures
1
1
(
a)
and
1
l(
b),
respectively.
From
Figure
1
1
(
a),
both
the
raw
and
In
transformed
data
are
positively
skewed
with
extreme
values
in
upper
tail
of
the
distribution.
Moreover,
there
are
no
substantial
differences
in
the
spread
of
observations
along
the
quartile
line
between
the
raw
and
In
transformed
data
in
the
normal
probability
plots
depicted
in
Figure
1
1
(
b).
The
skewness
coefficient
of
the
raw
data
(
1.5242),
however,
offers
a
slight
improvement
over
that
of
the
In
transformed
one
(
1.5905).
The
conducted
W
tests
for
the
raw
and
In
transformed
data
both
reject
the
normality
assumption
at
the
95
percent
level
of
confidence.
Overall,
the
analyses
performed
suggests
that
the
annual
NO,
compliance
data
submitted
by
the
Lee
County
solid
waste
resource
recovery
facility
display
a
relatively
normal
distribution.
4.2
95
and
99
Percent
Threshold
(
i.
e.
Exceedance)
Values
In
the
second
stage
of
the
comprehensive
data
analysis,
ERG
computed
compliance
thresholds
(
i.
e.,
exceedance
values)
at
95
and
99
percent
significance
levels
for
each
pollutant.
The
95
and
99
percent
exceedance
values
reflect
the
emission
levels
that
the
Lee
County
facility
can
meet
during
an
annual
test
with
95
and
99
percent
probability,
respectively,
and
are
computed
as:
K\
0154\
11\
06\
mwc
analysis
report
September
2002.
wpd
13
where:
tandard
Deviation
Mean
Standard
deviation
=
Sarnpl
ta
P
Table
10
presents
the
95
and
mean
by
pollutant
(
c
applicable
threshold
v
Section
4.1
for
each
p
.
I
Deviation
and
is
spec
threshold
and
the
mean
is
t,
'
Standard
j
14
K\
0154\
11\
06\
mwc
analysis
report
Septmber
2002.
wpd
'
c
'
ERG
September
2002
5.0
REFERENCES
Epperson,
David
and
David
White.
1995.
"
Supplemental
Analysis
of
NO,
Emissions
Data
from
the
Stanislaus
County
MWC."
Memorandum
from
Radian
Corporation
to
Walt
Stevenson,
EPA/
ESD.
August
30.
Lanier,
Steven
W.
and
Charles
D.
Hendrix.
2001.
Reference
Method
Accuracy
and
Precision
(
ReMAP):
Phase
I
:
Precision
of
Manual
Stack
Emission
Measurements.
American
Society
of
Mechanical
Engineers
(
ASME)
Research
Committee
on
Industrial
and
Municipal
Waste.
February.
Mendenhall,
William,
Dennis
D.
Wackerly,
and
Richard
L.
Scheaffer.
1990.
Mathematical
Statistics
with
Applications.
4&
Edition.
P
WS
Kent
Publishing
Company.
Boston,
MA.
U.
S.
Environmental
Protection
Agency
(
EPA).
2000.
Guidance
for
Data
Quality
Assessment:
Practical
Methods
for
Data
Analysis.
EAP
QNG
9
QAOO
Update.
Office
of
Environmental
Information.
Washington,
D.
C.
July.
K.\
O
154U
l\
O&
nwc
analysis
report
September
2002.
wpd
15
3
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n
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a"
FI
0
.*
Y
Y
3
3
k
d0"
w
l
w
l
n
a
a
5
W
ERG
September
2002
Frequency
Histograms
for
Dio
Data
from
Lee
County
Frequency
Hi
Frequency
Histogram:
in
transformed
Data
4.5
0.5
1
1.5
2
2.5
3
Ln(
dioxin/
furan
(
ngldscm))
Bins*
26
*
b
e
4
ERG
September
2002
Normal
Probability
Plots
for
DioxinB'uran
(
ng/
dscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
Normal
Probability
Plot:
Raw
Data
0
5
10
15
20
25
30
DioxinlFuran
(
ngldscm
)
Normal
Probability
Plot:
Ln
transformed
Data
0.5
1
1.5
2
2.5
3
3.5
Ln(
Dioxin/
furan
(
nglds
crn
))
K\
0154\
11\
06\
mwc
analysis
report
September
2002.
wpd
27
Frequency
Histograms
for
PM
(
mgldsc
ounty
Solid
Waste
Resource
Recove
9,
I
1
l
0
2
4
6
8
Particulate
Matter
(
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
+/
1
mg/
dscm
about
the
midpoint.
6
5
4
s
E
s
3
ET
$
2
1
0
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
+
I
0.25
In
(
mg/
dscm)
about
the
midpoint.
28
K:\
0154\
11\
06hwc
analysis
report
September
2002.
wpd
/
'
i
Figure
2(
b)
Normal
Probability
Plots
for
PM
(
mgdscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
Normal
Probability
Plot:
Raw
Data
0
2
4
6
8
10
Particulate
Matter
(
mg/
dscm)
Normal
Probability
Plot:
Ln
transformed
Data
2
.
2
1
.
Id
E
m
s
o
E
1
m
z
2
1
0.5
0
0.5
1
1.5
2
2.5
Ln(
Particu1ate
Matter
(
m
gldscm))
K\
0154\
11\
06\
mwc
analysis
report
September
2002.
wpd
29
a
Figure
3(
a)
Frequency
Histograms
for
Cadmium
(
m
ce
Data
from
Lee
Waste
Resource
Re
J
3.5
3
2.5
6
E
2
1.5
2
"
1
0.5
0
0
Cadmium
(
mgldscm)
Bins*
*
The
x
axis
labels
denote
the
midpoint
of
F
Frequency
Histogram:
Ln
transformed
ta
4.5
,
1
1
1
1
1
4
3.5
3
5
2.5
2
1.5
1
0.5
0
6
s
2
u.
8.25
8
7.75
7.5
7.25
7
6.75
Ln(
Cadmium
(
mg/
dscm))
Bins*
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
+/
0.125,
In
(
mddscm)
about
the
midpoint.
K\
0154\
11\
06\
mwc
analysis
report
September
2002.
wpd
30
'
E8G
September
2002
Figure
3(
b)
Normal
Probability
Plots
for
Cadmium
(
mg/
dscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
Normal
Probability
Plot:
Raw
Data
0.00025
0.0005
0.00075
0.001
0.00125
0.0015
Cadm
ium
(
mgldscm)
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
+
I
1
mg/
dscm
about
the
midpoint.
Normal
Probability
Plot:
Ln
transformed
Data
8.25
8
7.75
7.5
7.25
7
6.75
6.5
Ln(
Cadm
ium
(
ngldscm))
E.\
O154\
11\
06\
mwc
analysis
report
September
2002.
wpd
31
Frequency
Histograms
for
Lead
(
mg/
dscm)
Co
om
Lee
County
Solid
Waste
nd
2
Combined
Lead
(
mgldscm)
Bins*
*
The
x
axis
labels
denote
the
midpoint
of
the
b
rmed
Data
4.5
4
3.5
3
2.5
1.5
1
0.5
0
5
2
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
i.
e.,
+/
0.25
In
(
mg/
dscm)
about
the
midpoint.
32
K:\
0154\
11\
06\
mwc
analysis
report
September
2002.
wpd
r
=
4
.
:
September
2002
I
Figure
4(
b)
Normal
Probability
Plots
for
Lead
(
mg/
dscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
Normal
Probability
Plot:
Raw
Data
0
0.003
0.005
0.008
0.01
0.013
0.015
0.018
0.02
Lead
(
mgldscm)
Normal
Probability
Plot:
Ln
transformed
Data
2
I
I
I
I
b
I
i
7
6.5
6
5.5
5
4.5
4
3.5
Ln
(
Lead
(
m
g/
ds
cm
))
K\
0154\
11\
06hwc
analysis
report
September
2002.
wpd
33
Figure
5(
a)
1
Frequency
Histograms
for
Mercu
Waste
Resource
R
from
Lee
County
Solid
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
+/
0.005
mg/
dscm
about
the
midpoint.
ency
Histogram
med
Data
7
6
5
1
0
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
+/
0.25
In
(
mg/
dscm)
about
the
midpoint.
34
K\
0154\
11\
06\
mwc
analysis
repo~
September
2002.
wpd
Figure
5(
b)
Normal
Probability
Plots
for
Mercury
(
mg/
dscm)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
Normal
Probability
Plot:
Raw
Data
n
0
0.01
0.02
0.03
0.04
0.05
0.06
Mercury
(
m
glds
cm
)
Normal
Probability
Plot:
Ln
transformed
Data
2
1
0
.
E
O
m
3
m
0
u
1
2
3
4
7
6.5
6
5.5
5
4.5
4
3.5
3
2.5
Ln
(
M
e
rcury
(
m
glds
cm
))
K\
0154\
11\
06\
mwc
analysis
report
September
2002.
hpd
35
Frequency
Histograms
for
Merc
ata
from
Lee
County
ed
a
7
6
3
5
f
4
L
e
3
Q
i
2
1
I
0
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
+/
5%
about
the
midpoint.
Frequency
Histogram
Data
3
e
C
a,
3
Q
U.
I
O
,
I
I
I
I
9
7
6
5
4
3
2
1
0
a
3.6
4.4
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
+/
0.1
In
(%)
about
the
midpoint.
36
K\
0154\
11\
06\
mwc
analysis
report
September
2002.
wpd
Figure
6@)
Normal
Probability
Plots
for
Mercury
Percent
Reduction
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
Normal
Probability
Plot:
Raw
Data
2
1
Q)
.
I
+
I
5
0
I
5
2
I
I
ti
z
2
3
40
50
60
70
80
90
100
Mercury
%
Reduction
Normal
Probability
Plot:
Ln
transformed
Data
Q)
E
m
.
+
I
5
m
E
z
I
3.8
4
4.2
4.4
4.6
3.6
Ln(
Mercury
%
Reduction)
K
\
O
154\
11\
06\
mwc
analysis
report
September
2002.
wpd
37
~
~
~
LJ
~
~
~
~
~
a
I
.
.
>
Frequency
Histograms
for
HCl
(
ppm
Resource
Recovery
Lee
County
Solid
Waste
8
7
6
E
5
L
2
?
3
5
4
m
2
1
0
_
i
*
The
x
axis
labels
denote
the
midpoint
of
the
b
midpoint.
Frequency
Histogram;
Ln
transformed
Data
I
I
I
7
6
5
$
4
W
s3
2
L
2
1
0
2.25
2.5
Ln(
HCI
(
ppmv))
Bins*
38
K
\
O
154\
11\
06\
mwc
analysis
report
September
2002.
wpd
%
4
Figure
7(
b)
Normal
Probability
Plots
for
HCl
(
ppmv)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
Normal
Probability
Plot:
Raw
Data
2
0
I
10
.
15
20
25
30
35
40
HCI
(
PPmv)
Normal
Probability
Plot:
Ln
transformed
Data
K.\
0154\
11\
06\
mwc
analysis
report
Septernber
2002.
wpd
39
Frequency
Histograms
for
H
ta
from
Lee
County
ine
Solid
Waste
Reso
6
5
4
5
2
3
C
r
E
2
1
0
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
%
about
the
midpoint.
7
6
5
>,
E
4
Q)
5
3
2
L
2
1
0
K\
0154\
11\
06\
mwc
analysis
report
September
2002.
wpd
40
c
4'
T&
ERG
September
2002
Normal
Figure
8(
b)
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
Probability
Plots
for
HCI
Percent
Reduction
Compliance
Data
from
Lee
County
Q)
E
m
.
c
a
Normal
Probability
Plot:
Raw
Data
95.5
96
96.5
97
97.5
98
98.5
HCI
%
Reduction
Normal
Probability
Plot:
Ln
transformed
Data
4.56
4.565
4.57
4.575
4.58
4.585
4.59
Ln(
HCI
%
Reduction)
41
K
\
O
154\
11\
06\
mwc
analysis
repon
September
2002.
wpd
r
7
_
D_/
>
Frequency
Histogra
0
2.5
5
7.5
10
12.5
15
17.5
S
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
i.
e.,
+/
1.25
ppmv
about
the
midpoint.
Frequency
Histogra
Da
7
6
5
g
4
Q)
J
c
r
3
2
u
2
1
0
Ln(
S02
Arithmetic
Mean
(
ppmv))
Bins*
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
i.
e.,
+/
0.5
In(
ppmv)
about
the
midpoint.
42
KAO
154\
11\
06\
mwc
analysis
report
September
2002.
wpd
Figure
9(
b)
ormal
Probability
Plots
for
SO,
Arithmetic
Average
(
ppmv)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
Normal
Probability
Plot:
Raw
Data
0
2.5
5
7.5
10
12.5
15
17.5
20
SO2
Arithmetic
Average
(
ppmv)
.
Normal
Probability
Plot:
Ln
transformed
Data
1
0
1
2
3
3
2
Ln(
S02
Arithmetic
Mean
(
ppmv))
K:\
0154\
11\
06hwc
analysis
report
September
2002.
wpd
43
Frequency
Histograms
fo
Solid
8
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
+/
2
5
%
about
the
midpoint.
sformed
I
i
6
5
4
6
f
3
;
2
U
1
0
Ln(
S02
%
Reductio
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
i.
e.,
+/
0.025
In(%)
about
the
midpoint.
44
E
\
O
154\
11\
06\
mwc
analysis
report
September
2002.
wpd
Figure
1O(
b)
Normal
Probability
Plots
for
SO,
Percent
Reduction
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
Normal
Probability
Plot:
Raw
Data
2
85
90
95
100
80
SO2
%
Reduction
Normal
Probability
Plot:
Ln
transformed
Data
2
I
2
0,
3
,
4.35
4.4
4.45
4.5
4.55
4.6
4.65
ln(
S02
%
Reduction)
K:\
O
154U
1\
06\
mwc
analysis
report
September
2002.
wpd
45
.
I
Frequency
Histograms
Lee
County
So
ta
9
.
,
I
I
I
8
7
6
$
5
0
5
4
E
3
2
1
0
NOX
(
ppmv)
Bins*
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
+/
2.5
ppmv
about
the
midpoint.
9
8
7
6
3
f
5
$
4
E
3
2
1
0
*
The
x
axis
labels
denote
the
midpoint
of
the
bin
range,
Le.,
+
I
0.0125
ln(
ppmv)
about
the
midpoint.
46
K:\
0154\
11\
06\
mwc
analysis
qo~
September
2002.
wpd
%,
G
September
2002
3
Figure
ll(
b)
Normal
Probability
Plots
for
NO,
(
ppmv)
Compliance
Data
from
Lee
County
Solid
Waste
Resource
Recovery
Facility
Units
1
and
2
Combined
Normal
Probability
Plot:
Raw
Data
I
I
I
NOX
(
PPm
VI
I
155
160
165
170
145
150
Normal
Probability
Plot:
Ln
transformed
Data
K
\
O
154\
1
1\
06\
mwc
analysis
report
September
2002.
wpd
1
47
i
| epa | 2024-06-07T20:31:40.988824 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0047/content.txt"
} |
EPA-HQ-OAR-2003-0072-0048 | Supporting & Related Material | "2002-06-21T04:00:00" | null | epa | 2024-06-07T20:31:40.998202 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0048/content.txt"
} |
|
EPA-HQ-OAR-2003-0072-0049 | Supporting & Related Material | "2002-02-11T05:00:00" | null | 8458
Columbia
Road
(
440)
263
8214
/
FAX:
{
W)
2354982
Email:
92riPo@
rrai.
com
/
Website:
www.
rrai.
com
0
Olmsted
Falls,
Ohio
44138
2206
December
28,2001
whitman,
Administrator
ai
Protection
Agency
Headquarters
Washington,
D.
C.
2046
Subjecf:
Enforc
of
MACT
emissions
limitations
given
emissions
testing
methods.
Dear
Administrator
Whitman,
In
my
August
30,
1999
tetter
to
Administrator
Browner
on
this
subject,
I
explained
that
Document
(
TSD)
for
the
HWC
MACT
Rule
erroneously
stated
d
agreed
with
EPAs
assessment
of
the
expanded
uncertainty
of
methods,
the
range
of
a
d
emissions
represented
by
a
stack
i
at
there
were
significant
errors
in
the
TSD
analysis.
On
November
9
1999,
OSW'Director
Cotsworth
wrote
me
suggesting
that
review
of
the
rred
pending
completion
of
the
hexican
Society
of
Mechanical
h
Committee
on
Industrial
and
M
~
c
i
p
a
l
Waste's
ReMAP
(
Reference
and
Precision)
program
and
asked
that
I
involve
EMC's
Mr
William
H.
Lamason
in
tie
foilow
up.
,
The
inm
1
ReMAP
report
confirmed
the
methodologid
deficiencies
1
identified
1999
letter
and
identified
an
additional
problem
with
the
TSD
analysis.
In
A's
response
to
some
of
the
comments
I
made
on
the
Small
MWC
MACT
M
e
g
the
expanded
uncertainty
of
manual
sampling
methods
(
the
range
of
contain
the
measurand),
the
Agency
stated
that
dioxin
test
y
promulgated
and
that
measurement
uncertaimy
was
considered.
response
does
not
address
the
concern
because
EPA
never
established
fication
limit
for
Method
23
(
or
RCRA
Method
0023
for
that
#
d
could
not
have
because
the
Method
23
validation
oIumes
needed
to
calculate
concentration.
Hence,
the
capability
of
Method
23
at
the
regulatory
concentrations.
Environrnenra1
and
Statistical
Consuiting
c
Subject:
Enforceability
of
MACT
emissions
limitations
aven
the
uncertainty
of
manual
Page
2
December
28,2001
emissions
testing
methods.
Because
of
my
concerns
about
enforceability,
I
expanded
a
demonstration
project
I
was
conducting
in
November
1997
to
include
simultaneous
Method
23
sampling.
I
gave
those
data
to
EPA
and
ASME
used
them
in
ReMAP.
I
recently
incorporated
the
results
of
a
few
more
simultaneous
Method
23
tests
into
an
updated
assessment
of
dioxin
measurement
uncertainty,
which
I
have
expanded
to
include
"
3098
dioxin
toxic
equivalency
as
well.
The
range
of
the
data
now
covers
the
entire
range
of
regulated
concentrations
instead
of
ing
at
27.6
ng/
dsm3
(
no
diluent
correction).
Those
updated
results
are
attached
to
I
determined
the
relationship
between
the
standard
deviation
of
simultaneous
test
results
d
concentration
using
the
procedures
developed
in
ReMAP.
That
relationship
d
along
with
Monte
Carlo
Simulation
(
MCS)
to
determine
the
credible
range
of
standard
deviations
and
measured
values
likely
to
be
observed
(
Cox,
M.
G.,
M.
P.
Dainton
and
P.
M.
Harris,
So@
are
Support
for
Metwhgy
Best
Practice
Guide
No.
6,
Uncertainty
and
Stdistical
Modeling,
National
Physics
Laboratory,
Toddington,
March
2001).
Specific
characteristics
of
the
measurement
method
such
as
the
limit
were
extracted
from
the
Monte
Carlo
Simulation
results.
the
attachment
to
this
letter
conform
to
the
A
m
k
a
n
National
Uncertainty
U
S.
Guide
to
the
Expression
of
Uncertainty
in
SL
2540
2
199'
7).
The
data
and
results
are
attached
to
this
\
letter.
Method
301
is
the
only
promulgated
rule
establishing
the
lower
limit
of
applicability
of
an
emissions
test
method.
Both
Method
301
itself
and
the
preamble
make
it
clear
that
under
the
current
regulatory
scheme,
test
results
can
only
be
used
for
enforcement
when
above
the
practical
quantification
limit.
Of
course,
this
caveat
should
be
able
to
citly
waived
when
promulgated
emissions
limitations
explicitly
incorporate
ent
uncertainty.
I
The
statistical
concept
underlying
the
Method
30
1
definition
the
practical
quantification
limit
is
that
the
PQL
is
the
concentration
where
the
measured
concentration
(
measurement)
is
likely
to
be
within
10
percent
of
the
true,
but
unknowable
emitted
source
concentration
(
measurand).
I
used
the
statistical
concept
rather
than
the
formulas
found
in
Method
301.
because
the
HWC
MACT
TSD
correctly
states
that
the
Method
301
formulas
do
not
apply
for
manual
stack
emissions
testing
methods.
For
these
methods,
the
standard
deviation
between
simultaneous
replicate
measurements
is
neither
constant
nor
decreases
with
concentration;
rather,
it
increases
with
concent
,
Subject:
Enforceability
of
MACT
emissions
limitations
given
the
uncertzlinty
of
manual
Page
3
December
28,200
1
emissions
testing
methods.
The
practical
quantiation
limit
for
total
dioxins
is
34
&
dsm3.
Since
total
dioxin
MACT
limitations
include
7,
13
and
30
ng/
dsm3
corrected
to
7
percent
oxygen,
which
are
equivalent
to
5
75
9
14
and
21
32
ng/
dsm3
on
an
uncorrected
basis
for
typical
MWCs,
it
is
clear
that
that
PQL
is
above
the
enforcement
levels.
The
new
data
did
not
materially
change
the
results
for
ITEQ
dioxins.
The
PQL
for
ITEQ
dioxins
is
1.6
ng/
dsm3.
So,
the
PQL
is
above
0.2
and
0.4
ng/
dsm3
corrected
to
7
percent
oxygen
emissions
limitations
found
in
the
now
remanded
HWC
MACT
rule.
I
remain
convinced
that
measurement
uncertainty
must
be
known
and
properly
considered
when
MACT
standards
are
established.
Absent
such,
I
am
deeply
concerned
that
truly
excessive
emissions
will
not
be
reduced
while
sources
that
are
actually
achieving
MACT
risk
being
punished
in
the
press
and
by
unwarranted
enforcement
actions
every
time
they
conduct
a
source
emissions
test.
Very
truly
yours,
H
G
Rig0
&
Associates,
Inc.
H.
Gregor
Rigo,
PhD,
PE,
QEP,
DEE
President
Attachments:
Updated
measurement
uncertainty
results
for
Total,
ITEQ
and
WHO98
TEQ
Dioxins
RCRA
Docket:
F96
RCSP
FFFF
Air
&
Radiation
Docket
HWC:
A
9045
MWC:
A
98
18
MWI:
A
91
6
WC:
A
94
63
Mi.
William
H.
Lamason,
EMC,
EPA
7
Updated
measurement
uncertainty
results
for
Total,
ITEQ
and
TEQ
Dioxins
The
following
three
sheets
are
all
similarly
arranged.
They
provide
summary
statistical
characteristics
and
measurement
uncertainty
results
for
Total
Dioxins,
ITEQ
Dioxins
and
WHO98
TEQ
dioxins.
The
upper
lee
hand
corner
of
each
page
is
a
tabulation
of
the
statistical
characteristics
of
the
data.
These
statistical
characteristics
describe
the
applicable
range
of
the
results
and
provide
the
input
parameters
needed
to
determine
measurement
uncertainty
using
either
main
line
GUM
(
Guide
to
expressing
uncertainty
in
measurement)
or
Monte
Carlo
Simulation
WCS)
techniques.
MCS
is
the
correct
technique
to
apply
since
fbndamental
assumptions
implicit
in
main
line
GUM
are
violated
by
the
nature
of
the
relationship
between
standard
deviation
and
concentration
for
manual
emissions
measurements.
Using
the
total
dioxins
sheet
as
an
example:
0
Simultaneous
replicate
data
has
been
obtained
between
0.5
and
399
ng/
dsm3.
The
average
and
standard
deviation
of
the
natural
logarithms
of
the
concentration
averages
are
1.
.9
and
2.06
ln(
ng/
dsm")
respectively.
of
the
sample
size
bias
corrected
standard
deviation
estimates
is
4
while
the
average
of
the
predicted
standard
deviations
is
2.6
leading
to
a
retransformation
bias
correction
factor
of
1.58.
The
natural
logarithm
of
this
factor
is
added
to
the
regression
intercept
to
correct
for
this
bias
The
retransformation
bias
corrected
equation
relating
average
concentration
and
the
standard
deviation
of
the
measurements
used
to
generate
the
average
is:
S
=
1.69
+
0.83(
concentration).
The
statistical
characteristics
are
based
on
27
dual
train
samplings.
A
10,000
iteration
Monte
Carlo
Simulation
was
used
to
determine
that
for
total
dioxins:
Blank
trains
are
likely
to
yield
measured
total
dioxin
concentrations
up
to
0.07
ng/
dsm3.
The
detection
limit,
the
lowest
concentration
we
are
statistically
certain
is
greater
If
we
are
interested
in
making
sure
that
a
reported
result
has
at
least
one
significant
digit,
then
the
true
concentration
has
to
be
above
0.5
ng/
dsm3
and
the
lowest
level
at
which
two
significant
digits
may
be
properly
reported
is
24
ng/
dsm3.
than
a
blank
train,
is
0.9
ng/
dsm3.
I
The
long,
thin
dashed
line
on
the
graphs
is
the
central
value
estimated
&
om
the
data.
The
heavy
lines
demark
the
upper
and
lower
95%
(
2
tailed)
confidence
intervals
and
the
surrounding
light
dotted
lines
indicate
the
uncertainty
range
associated
with
these
bounds.
2
At
the
bottom
left
hand
comer:
0
The
relative
standard
deviation
is
plotted
against
measurand,
the
"
true"
but
unknown
and
unknowable
value
of
the
concentration.
PQL
is
the
concentration
corresponding
to
a
10
percent
relative
standard
deviation.
The
analytic
result
has
at
least
one
significant
digit
when
upper
confidence
limit
for
the
standard
deviation
equals
50
percent
and
may
have
more
than
one
significant
digit
when
the
lower
confidence
limit
for
the
standard
deviation
is
below
5
percent.
0
At
the
right
hand
side
of
each
sheet,
the
range
of
measured
values
is
plotted
against
the
measurand.
Like
a
typical
calibration
curve,
if
the
measurand
is
known
(
for
example,
when
a
standard
solution
is
analyzed)
then
reading
up
the
graph
indicates
the
range
of
Its
that
can
be
expected
using
the
Method.
In
stack
testing,
however,
the
s
are
what
we
have
and
the
measurand
is
both
unknown
and
unknowable.
If
I
conducted
5t
test
and
measured
100
ng/
dsm3,
the
total
dioxin
graphic
lets
me
figure
out
that
the
"
true"
measured
concentration
(
measurand)
is
between
80
and
130
ng/
dsm3.
Of
course,
these
concentrations
must
still
be
multiplied
by
the
dilution
correction
factor
to
express
the
result
in
the
units
of
a
diluent
corrected
regulatory
standard.
Summary
statistics
for
simultaneous
repIicate
Method
23
dioxin
measurements.
Run
ID
TO1
TO2
TO3
TO4
TO5
TO6
TO7
f
l
0
T11
T12
T13
T14
T15
T16
T17
T18
T19
EERTRCl
EERTRC2
EERTRC3
wes
runl
1
wes
run
1
2
wes
run13
wes
run2
2
wes
rur12
3
TOTAL
DIOXINS
totdxna
totdxns
2.1840
0.1291
2.8496
0.2731
1.3521
0.3703
3.2676
0.6022
0.8941
0.0900
15.3254
3.9617
0.0558
2.0002
8.2172
0.1709
5.3342
0.1218
1.9771
0.9554
5.5100
,0.8090
0.9638
0.1478
1.0459
0.7357
4.7550
1.8872
15.7800
0.7797
27.5550
0.2924
ITEQ
DIOXINS
iteqa
itqs
0.2524
0.0572
0.1086
0.0016
0.1256
0.0227
0.0731
0.0261
0.1486
0.0361
0.0426
0.01
30
0.5208
0.0833
0.9128
0.0537
0.41
90
0.0727
0.3813
0.0002
0.2489
0.0202
0.0508
0.01
71
0.0582
0.0354
0.0357
0.0009
0.0459
0.0286
0.0408
0.0117
0.0423
0.0222
0.0209
0.001
5
0.0489
0.01
17
0.1776
0.001
7
0.3182
0.0019
7.7605
0.2028
7.5280
0.7809
3.5069
0.4250
4.3743
0.4541
3.5287
0.2606
WHO98
DIOXINS
who98a
who98s
0.161
1
0.0349
0.0709
0.0039
0.0876
0.0042
0.0482
0.0130
0.0896
0.0229
0.0332
0.0035
0.3268
0.0087
0.6133
0.0420
0.2793
0.0437
0.2430
0.0071
0.1620
0.0126
0.0508
004
0.0496
055
0.0286
0.0006
0.031
1
0.01
05
0.0314
0.0043
0.0310
0.0217
0.0223
0.0027
0.0203
0.0022
8.5165
0.1963
8.1251
0.8271
3.8095
0.4470
4.4339
1.1388
3.9597
0.201
3
Notes:
all
standard
deviations
are
sample
size
bias
corrected
multiplied
by
1.253
all
statistical
results
derived
from
pairs,
EERTRC
results
are
cross
traverse
"
wes"
runs
are
new
since
ASMEIRCIMW
ReMAP
report
(
October
2000
testing)
0
0
0
'
8
3
Z
1
n
U
i
e
*
b
r
I
I
LI
U
¶
| epa | 2024-06-07T20:31:41.000419 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0049/content.txt"
} |
EPA-HQ-OAR-2003-0072-0050 | Supporting & Related Material | "2002-10-03T04:00:00" | null | UN~
TED
STATES
ENVIRONME~~
TAL
PROTEGT~
ON
AGENCY
WASHINGTON,
D.
C.
20460
OFFIGE
OF
AIR
AND
RnoMTlON
Dr.
H.
Gregor
Rigo,
President
H
G
Rig0
&
Associates,
Inc,
Columbia
Road
Is,
OH
44138
2206
Dear
Dr.
Rigo:
Thank
you
for
your
letter
dated
December
28,2001.
In
your
letter,
you
conclude
that
the
wtitation
(
PLQ)
for
Method
23,
the
Environmental
Protection
Agency's
test
method
for
measuring
polychlorinated
dibenzodioxins
(
PCDD's)
and
polychlorinated
dibenzofurans
(
PCDF's),
is
higher
than
the
emission
limits
for
PCDD's
and
the
various
regdations
limiting
the
emission
of
these
compounds
itom
municipal
Again,
according
to
your
letter,
this
is
important
because
the
EPA's
Method
"
that
under
the
current
regulatory
scheme,
test
results
can
only
be
used
for
they
are
above
the
practical
quantification
limit."
While
I
share
your
concern
about
measurement
uncertainty,
there
is
no
requirement
in
any
other
EPA
compliance
test
method
to
establish
a
PLQ
or
to
prohibit
the
use
ata
that
fall
below
the
PLQ.
The
procedure
in
Method
301
for
determiping
the
eled
as
an
"
optional"
procedure
and
not
a
required
one,
as
proposed
in
the
Federal
Register
on
June
13,1991
In
the
Preamble
to
the
final
rulemaking
for
Method
301,,
we
responded
to
several
comments
suggesting
the
EPA
revise
the
proposed
method
to
include
specific
procedures
to
defrne
the
meas
comments
noted
that
Method
301
re
level
of
the
pollutant
in
the
waste
s
limit
or
require
the
tester
to
estabIi
301
"
provided'
cedures
for
dete
I
t
range
of
the
method.
EPA's
ester
to
validate
measurement
methods
at
the
t
declined
to
set
an
absolute
lower
measurement
it.
Our
response
also
pointed
out
that
Method
g
a
limit
of
quantitation
and
that
it
`
advocated"
the
use
to
help
defrne
a
method's
measurement
range.
It
did
not
choose
to
make
I
regret
any
confusion
that
this
may
have
caused
and
appreciate
the
oppo
irements
of
Method
301.
Although
Metbod
301
does
not
require
that
a
tester
determine
the
PLQ
of
a
method,
it
does
have
limits
on
the
allowabie
precision
for
a
compliance
test
method.
As
defined
in
Section
6.3.1.1,
the
precision
of
a
method
is
unacceptable
if
the
relative
standard
deviation
is
equal
to
or
greater
than
50%.
Based
on
your
analysis
and
that
of
the
American
Society
of
Mechanical
,
h
Committee
on
Reference
Method
Accuracy
and
Precision,
the
relative
n
ofMethod
23
was
always
less
than
50%
over
the
entire
range
of
emission
Internet
A&
ress
(
URL)
http:
l/
www
epagov
Rffiycle&
RecycbWe
Prtnled
with
Vegetable
OII
Based
inks
on
Recycled
Peper
(
Minimum
30%
Postconsumer)
~
| epa | 2024-06-07T20:31:41.005140 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0050/content.txt"
} |
EPA-HQ-OAR-2003-0072-0051 | Supporting & Related Material | "2002-10-03T04:00:00" | null | 8
15
UNITED
STATES
ENVIRONMENTAL
PROTECTION
AGENCY
WASHINGTON,
D.
C.
20460
OFFICE
OF
6
2
2
2w
I
AIR
AND
RADIATION
Mr.
Frank
P.
Prager
Xcel
Energy
4653
Table
Mountain
Drive,
Golden,
Colorado
80403
Dear
Mr.
Prager:
Thank
you
for
your
petition
of
July
8,2002,
to
Christine
Todd
Whitman,
Administrator
of
the
U.
S.
Environmental
Protection
Agency,
in
which
you
requested
an
additional
carbon
monoxide
(
CO)
emission
limit
be
added
to
the
Clean
Air
Act
Section
129
maximum
achievable
control
technology
(
MACT)
standards
for
large
municipal
waste
combustion
(
MWC)
units
(
Subpart
Cb).
We
appreciate
your
concern
with
ths
issue.
As
you
note,
the
MACT
standards
adopted
in
2000
for
small
MWC
units
(
Subpart
BBBB)
do
contain
a
unique
CO
emission
limit
for
this
type
of
fluidized
bed
MWC.
We
understand
that
you
are
simply
requesting
that
the
CO
limit
in
the
small
MWC
standards
be
limits
in
the
large
MWC
standards.
After
careful
consideration
and
review,
I
add
your
request
to
the
issues
to
be
addressed
in
the
5
year
review
of
the
MACT
e
MWC
units.
That
review
will
be
initiated
next
month
(
September
2002).
As
you
are
aware,
any
changes
made
to
the
MACT
standards
will
go
through
proposal
and
public
comment
prior
to
adoption.
Changes
made
to
the
MACT
standards
would
then
be
incorporated
into
the
Federal
plan
(
Subpart
FFF)
for
laxge
MWC
units.
.
Again,
thank
you
for
your
petition.
I
appreciate
the
opportunity
to
be
of
service
and
trust
the
information
provided
is
helpful.
If
you
have
further
questions,
please
contact
Bob
Wayland
(
919
541
1045)
or
Walt
Stevenson
(
919
541
5264).
Sincerely,
Internet
Address
(
URL)
http://
www.
epa.
gov
Recycled/
Recyclable
Prlnted
with
Vegetable
011
Based
Inks
on
Recycled
Paper
(
Mlnlmum
30%
Postconsumer)
| epa | 2024-06-07T20:31:41.007492 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0051/content.txt"
} |
EPA-HQ-OAR-2003-0072-0052 | Supporting & Related Material | "2002-10-03T04:00:00" | null | MEMORANDUM
DATE:
September
18,2002
SUBJECT:
Addition
to
Performance
I
Test
Data
for
Large
Municipal
(
MWCs)
at
MACT
Compliance
(
Year
2000
data)
FROM:
Bradley
Nelson
Alpha
Gamma
Technologies,
Inc.
Walt
Stevenson,
EPAEmission
Standards
DivisiodCombus
TO:
The
attached
table
in
this
memorandum
is
a
companion
table
to
the
memorandum,
"
PerformanceJTest
Data
for
Large
Municipal
Waste
Combustors
(
MWCs)
at
MACT
Compliance
ear
2000
Data)"
Docket
A
90
45;
Item
VIII
3
2.
The
attached
table
provides
emission
factors
in
units
of
pollutant
emissions
per
electrical
generation
(
kg
pollutantlMWe
hr).
These
emission
factors
were
developed
using
the
emission
factors
from
Table
3
in
the
companion
memorandum
and
developing
a
conversion
factor
to
convert
from
tons
of
municipal
solid
waste
(
MSW)
fired
to
nerated.
The
conversion
factor
was
developed
by
totaling
the
MSW
fired
by
all
MWCs
(
Mg
per
year)
and
dividing
by
the
total
electrical
power
generated
(
m
e
h
r
per
year),
based
on
EIA
data
(
Year
2000).
The
conversion
factor
was
calculated
to
be
1.5
tons
MSWIMWe
hr.
1
Table
3b.
Emission
Factors
of
Large
MWC
units
after
MACT
Retrofits
Section
129
Pollutants
(
kg
pollutant
per
(
kg
pollutant
per
'
The
emissions
factors
(
kg
emissions
per
Mg
waste
fired)
were
developed
by
totaling
the
emissions
of
all167
units
and
dividing
by
the
total
waste
combusted.
(
see
Docket
A
90
45;
Item
VIII
B
3).
'
The
emissions
factors
in
the
first
coliumn
(
kg
emissions
per
Mg
waste
fired)
were
converted
into
units
of
ons
per
electrical
generation
by
using
a
conversion
factor
of
1.5.
The
conversion
factor
is
based
on
EIA
data
(
year
2000).
The
conversion
factor
was
developed
by
totaling
the
waste
fired
by
all
MWCs
(
Mg
per
year)
and
ding
by
the
total
electrical
power
generated
(
W
e
h
r
per
year).
(
The
Tulsa
MWC
was
excluded
because
of
incomplete
data).
| epa | 2024-06-07T20:31:41.010313 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OAR-2003-0072-0052/content.txt"
} |
EPA-HQ-OECA-2002-0004-0002 | Rule | "2002-08-19T04:00:00" | Civil Monetary Penalty Inflation Adjustment Rule,
Withdrawal of Direct Final Rule | Federal
Register/
Vol.
67,
No.
1601Monday.
August
19,
2002
Latitude
60
°
58.93'
N.
146O48.86W
and
southwest
of
a
line
bearing
307'
True
from
Tongue
Point
at
61
°
02.10'
N.
146
°
40.00'
W.
*
*
*
*
*
PART
1674FFSHORE
TRAFFIC
SEPARATION
SCHEMES
3.
The
authority
citation
for
part
167
Authority:
33
U.
S.
C.
1223;
49
CFR
1.46.
,
4.
Add
§
§
167.1700
through
167.1703
continues
to
read
as
follows:
to
read
as
follows:
§
167.1700
In
Prince
William
Sound:
General.
The
Prince
William
Sound
Traffic
Separation
Scheme
consists
of
four
parts:
Prince
William
Sound
Traffic
Separation
Scheme,
Valdez
Arm
Traffic
Separation
Scheme,
and
two
precautionary
areas.
These
parts
are
described
in
55
167.1701
through
167.1703.
The
geographic
coordinates
in
$
6
167.1701
throueh
167.1703
are
~.
Longitude
ACTION:
Withdrawal
of
direct
final
rule.
iefined
using
Nor&
American
Datum
1983
(
NAD
83).
................
60"
20.59"
60O49.49"
................
$
167.1701
In
Prince
William
Sound:
Precautionary
areas.
precautionary
area
is
established
and
is
bounded
by
a
line
connecting
the
following
geographical
positions:
(
a)
Cape
Hinchinbrook.
A
SUMMARY:
Because
EPA
received
146'
46.18'
W
146'
56.19W
Latitude
Latitude
60'
20.59"
................
60'
12.67"
................
6OD11.01'
N
................
60'
05.47"
................
60"
00.61'
N
................
60"
05.44"
................
59'
51.60"
................
59Y3.52"
................
60"
07.76"
................
60"
11,51'
N
................
60?
20.60"
................
Longitude
Latitude
I
Lonoitude
ENVIRONMENTAL
PROTECTION
60"
49
10'
h
6070
6
0
h
AGENCY
60"
20.77"
................
146'
52.31'
W
60"
46.12"
................
40
CFR
Parts
19
and
27
60"
48.29N
................
146"
59.77'
W
60"
20.93"
................
[
FRL
7261
51
147'
04
19W
146'
54
31'
W
(
b)
A
traffic
lane
for
northbound
Civil
Monetary
Penalty
Inflation
Adjustment
Rule
traffic
between
the
separation
zone
and
Latitude
146"
48.64'
W
146"
54,31'
W
a
line
connecting
the
following
geographical
positions:
AGENCY:
Environmental
Protection
Aaencv
IEPA).
Longitude
Washington,
DC
20460,
(
202)
564
2413.
60O49.39"
................
60'
58.04"
................
Dsted
August
13,
2002.
146O58.19'
W
146'
46.52'
W
John
Peter
Suarez,
the
direct
final
rule
amending
the
find
Civil
Monetary
Penalty
Inflation
Adjustment
~
~
l
~
,
which
was
by
the
Debt
Collection
Improvement
Act
of
1996.
That
leeislation
reauired
IC)
A
traffic
lane
for
southbound
traffic
between
the
separation
zone
and
a
line
connecting
the
following
geographical
positions:
federal
agencies
to
adjust
civil
monetary
penalties
for
inflation
on
a
periodic
basis.
EPA
published
the
direct
final
rule
on
June
18,2002
(
67
FR
41343).
We
stated
in
the
direct
final
rule
that
if
we
received
adverse
comment
by
July
18,
2002,
we
would
publish
a
timely
notice
of
withdrawal
in
the
Federal
Register.
The
Arm
Traffic
Separation
We
subseouentlv
received
one
adverse
$
157.1703
In
Prince
William
Sound:
Valdez
A
TraMc
Separation
scheme.
Scheme
consists
of
the
following:
line
connecting
the
following
geographical
positions:
comment
bn
thedirect
final
rule.
We
will
address
that
comment
in
a
subsequent
final
action
based
on
the
parallel
proposal
also
published
on
June
18,
2002
(
67
FR
41363).
As
stated
in
the
(
a)
A
separation
zone
bounded
by
a
Latitude
Longitude
oarallel
orooosal.
we
will
not
institute
(
b)
A
precautionary
area
is
established
of
radius
1.5
miles
centered
at
geographical
position
60'
49.63".
147~
01.33'
W.
(
4
A
pilot
hoarding
area
located
near
the
center
of
the
Biigh
Reef
precautionary
area
is
established.
Regulations
for
vessels
operating
in
these
areas
are
in
5
165.1109(
d)
of
this
chapter.
§
167.1702
In
Prince
William
Sound:
Prlnce
William
Sound
Traffic
Separation
Scheme.
The
Prince
William
Sound
Traffic
Separation
Scheme
consists
of
the
following:
(
a)
A
separation
zone
bounded
by
a
line
connecting
the
following
geographical
positions:
41344
Federal
Regisler
I
Vol.
67.
No.
11
7
I
Tu~
sdd)
~
]
uric
18.
2002
/
Kulus
dnd
Kegidation&
affei.?
the
terms
under
which
civil
penalties
UP
assess~
d
by
EPA.
In
addition.
Ef.
4
has
rilade
minor
conforming
ctimgcs
to
the
regulaticns
to
reflpct
thc
effective
date
of
the
new
rates
prescrihcd
by
Congress
w'lrich
haw
no
substantive
ctfwi.
The
furrimla
for
the
umount
of
the
penalty
aniusrrnciit
is
prescribed
hy
Congress
in
the
UCIA
and
the5echanw
a
e
n
o
l
subjert
to
the
exrrrisc
cf
dismction
by
EPA.
Ilo!
varer
1110
rounding
requirement
of
Ilk?
statute
is
subjuct
to
diffwenr
interpretations
and
EVA
has
rounded
based
on
the
amount
of
the
increase
resulting
friirn
the
CPI
pwcentagc
Lalculation.
This
apprnach
achiet'es
tllc
intcnl
uf
the
DClh
because
a
rounding
nilir
hnsed
on
thc
i
l
~
i
u
u
~
t
Of
the
increase
will
rcsult
in
incrcasc
~
m
u
u
~
i
t
s
that
more
closely
track
rhc
manges
in
the
CI'!
a
i
d
uould
$
readily
incro'isc
the
ilmuun!
of
the
CMPj
over
time
in
liue
wilh
increase$
in
thn
CPI.
Calculi~
tions
bas14
on
ut!
ier
interpret.
itions
oi
tho
rounding
requirercmt
could
resnlr
in
CMY
ndjustmeiits
that
i
y
i
r
either
several
tinleu
d
~
r
CPI
percentage
or
in
no
increase
at
all
p
w
n
with
increoscs
i
n
the
CPI.
In
the
"
Pmpoced
Rules"
section
01
today'.<
Pcderiil
Registur
publication.
we
are
publishing
R
separstc
dorumcnt
that
will
uenc
3s
the
proposal
to
adiusl
Et'A's
civil
mon&
q
ycrid~
tiez
fur
inflation
iiadversc
i.
umments
arc
f
i
l
d
This
nile
will
be
etttxtivo
on
August
19.
2002
wilhuut
further
notice
unless
we
receiae
adrorso
commmt
I
I
~
J
u
l
y
18,
2002.
If
EPA
rweii'?~
adverse
comment.
we
u<
ll
puhlish
n
tiinelv
ivithdrarval
in
the
Federal
Register
infornung
the
public
that
fhe
rule
will
not
take
oihn:
t.
\
Vu
Xviil
hddrcss
all
public
comments
in
II
subsequent
final
rule
based
on
the
proposed
rule
We
wil:
not
institute
a
secuud
coinmen\
period
on
tnis
action.
An)
partias
interested
in
cornrriimting
mnst
do
so
at
this
lime.
Under
Cxcculive
Order
12866.
I58
FR
51,705
(
OL.
tober
4,
1WJ))
thcAgcI1c).
must
determint?
whcther
tho
rcgulhtory
action
is
"
signifkant"
and
:
herefole
subject
tu
O
W
review
a
d
thc
requirements
of
the
Executive
Order.
The
Order
defines
"
significant
regulatory
action'
as
onc
that
is
like.?
io
resiilr
i
n
a
rule
thkr
mav:
IIJ
tin."
i
l
l
)
",
Nt"
dl
*
rr,!
eCl
011
IlW
,'
vu,
lolr>
y
id
$>
or
mi1l;
on
or
mom
nr
p
d
v
n
n
d
y
H
f
l
w
t
in
B
malexiitt
LWY
Iha
econum;.
a
S
R
~
U
I
ut
I
t
s
t
~
rxclucrmy
~
mncluriiwiy,
umqx!
ritior.,
iobr.
iht:
m
v
i
m
m
w
u
~
,
(
JUIAIS.
laultlr
iw
sixbl)
,
$
17
Stnlc.
IxA71.
of
1~
111.
t1
!
m
w
r
w
t
~
W
l
.
~
UT
~
communities;
otherwise
interfere
with
an
action
taken
or
[
Z]
Create
a
serious
inconsistency
or
planned
by
another
agency:
(
3)
Materially
slter
the
budgetary
impact
of
entitlements,
grants,
usm
fees,
or
loan
programs
or
Ihs
rights
and
obligations
of
recipiants
thereof,
or
(
4)
Raise
novel
legal
N
policy
issues
arising
out
of
legal
mandates,
the
President's
priorities,
or
the
principles
set
forth
in
the
Executive
Order.
It
has
been
determined
that
this
rule
is
not
a
"
significant
regulatory
action"
under
the
terms
of
Executive
Order
12866,
and
is
therefore
not
subject
to
review
by
the
Office
of
Management
and
Budget.
Title
I1
of
the
Unfunded
Mandates
Reform
Act
of
1995
(
UMRAI,
Public
Law
104
4,
establishes
requirements
for
Federal
agencies
to
assess
the
effects
of
theb
regulatory
actions
on
State,
local,
and
tribal
governments
and
the
private
sector.
Under
section
ZGZ
of
the
UMRA,
EPA
generally
must
prepare
a
written
statement,
including
a
cost
benefit
analysis,
for
proposed
and
final
rules
with
"
Federal
mandates"
that
may
result
in
expenditures
to
State,
local,
and
tribal
governments,
in
the
aggregate,
or
to
the
private
sector,
of
$
100
million
or
more
i
n
any
one
yeas.
Before
promulgating
an
EPA
rule
for
which
a
written
statament
is
needed,
section
205
of
tha
UMRA
generally
requires
EPA
to
identify
and
consider
a
reasonable
number
of
regulatory
alternatives
and
adopt
the
least
costly,
most
cast
effective
or
least
burdensome'alternative
that
achieves
the
objectives
of
the
rule.
The
provisions
of
section
205
do
not
apply
when
they
are
inconsistent
with
applicable
law.
Moreover,
section
205
allows
EPA
to
adopt
an
alternative
other
than
the
least
costly,
most
cost
effective
or
least
burdensome
alternative
if
the
Administrator
publishes
with
the
final
rule
an
explanation
why
that
alternative
was
not
adopted.
Before
EPA
establishes
any
regulatory
requirements
that
may
significantly
or
uniquely
affect
small
governments,
including
trihal
goveriiments,
it
must
have
developed
under
section
203
of
the
Uh4RA
a
small
government
agency
plan.
The
plan
must
provide
for
notifying
potentially
affected
small
governments,
enabling
officials
of
affected
small
governments
to
have
meaningful
and
timely
input
in
the
development
of
EPA
regulatory
proposals
with
significant
Federal
intergovernmental
mandates,
and
informing,
educating.
and
advising
small
governments
on
compliance
with
the
re
ulatnr
requirements.
Todgay's
d
e
contains
no
Federal
mandates
(
under
theregulatory
provisions
oETitle
IIof
the
UMRAl
for
State,
local,
or
trihal
governments
or
the
privete
sector
because
the
rule
implements
mandate($
specifically
and
explicitly
set
iorth
by
the
Congress
without
the
exercise
of
any
policy
discretion
by
EPA.
Thus,
today's
rule
is
not
subject
to
the
requirements
of
sections
202
and
205
of
the
UXIRA.
EPA
has
determined
that
this
rule
contains
no
regulatory
requirements
that
might
significantly
or
uniquoly
affect
small
governments.
'
Executive
Order
13175,
entitled
Consultation
and
Coordination
with
Indian
Tribal
Governments
(
65
FR
67249,
November
9,
ZOOO),
requires
EPA
to
develop
an
accountable
process
to
ensure
"
nieaningful
and
timely
input
by
tribal
officials
in
tho
development
of
regulatory
policies
that
have
tribal
implications."
As
this
direct
final
rule
will
not
have
substantial
direct
effects
on
tribal
governments,
on
the
relationship
between
the
Federal
government
and
Indian
tribes.
or
on
the
distribution
of
power
and
responsibilities
between
lhe
Federal
government
and
Indian
tribes,
Executive
Order
13175
does
not
apply
to
this
rule.
Executive
Order
13132,
mititled
Federalism
(
64
FR
43255,
August
10,
1999),
requires
EPA
to
develop
an
accountable
process
to
ensure
"
meaningful
and
timely
input
by
State
and
local
officials
in
the
development
of
regulatory
policies
that
have
federalism
implications."
"
Policies
that
have
federalism
implications"
is
defined
in
thc
Executive
Order
to
include
regulations
that
have
"
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
or
on
the
distribution
of
power
and
responsibilities
among
the
various
levels
of
government."
This
rule
does
not
have
federalism
implications.
It
will
not
have
substantial
direct
effects
on
the
States,
on
the
relationship
between
the
national
government
and
the
States,
nr
on
the
distribution
of
power
and
responsihilities
among
the
various
levels
of
government,
as
specified
in
executive
Order
13132.
Thus,
Executive
Ordsr
13132
does
not
apply
tn
this
rule.
The
Regulatory
Flexibility
Act,
8s
amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
[
SEREFA),
5
U.
S.
C.
GO1
et
seq.,
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
For
purposes
of
assessing
the
impacts
of
today's
rule
on
small
entities,
small
,
Federal
RegisterIVol.
67,
No.
117/
Tuesday,
June
18,
2002
/
Rules
and
Regulations
41345
7
U.
S.
C.
1361.(
a)(
l)
.........................
entity
is
defined
as
(
1)
a
small
business;
(
2)
a
small
governmental
jurisdiction
that
is
a
government
of
a
city.
county,
town
school
district
or
special
district
with
a
population
of
less
than
50,000;
and
(
3)
a
small
organization
that
is
any
not
for
profit
enterprise
which
is
independently
owned
and
operated
and
is
not
dominant
in
its
field.
This
action
will
not
have
a
significant
impact
on
a
substantial
number
of
small
entities
for
the
following
reasons:
EPA
is
required
by
the
DCIA
to
adjust
civil
monetary
penalties
for
inflation.
The
formula
for
the
amount
of
the
penalty
adjustment
is
prescribed
by
Congress
and
is
not
subject
to
the
exercise
of
discretion
by
EPA.
EPA's
action
implements
this
statutory
mandate
and
does
not
substantively
alter
the
existing
regulatory
framework.
This
rule
does
not
affect
mechanisms
already
in
place.
including
statutory
provisions
and
EPA
policies,
that
address
the
special
circumstances
of
small
entities
when
assessing
penalties
in
enforcement
actions.
EPA's
media
penalty
policies
generally
take
into
account
an
entity's
"
ability
to
pay"
in
determining
the
amount
of
a
penalty.
In
addition,
entities
may
he
affected
by
this
rule
only
if
the
federal
government
finds
them
in
violation
and
seeks
monetary
penalties.
This
would
constitute
a
very
small
fraction
of
the
universe
of
regulated
facilities.
Additionally,
the
final
amount
of
any
civil
penalty
assessed
against
a
violator
remains
committed
to
the
discretion
of
the
Federal
Judge
or
Administrative
Law
Judge
hearing
a
particular
case.
Accordingly,
although
EPA
cannot
predict
the
precise
impact
on
individual
cases,
the
adjustment
is
likely
to
result
in
at
most
a
relatively
minor
change
to
the
actual
penalties
in
cases
affecting
a
small
fraction
of
regulated
entities.
After
considering
the
economic
impacts
of
today's
rule
on
small
entities,
I
certify
that
this
action
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Executive
Order
13045,
Protection
of
Children
from
Environmental
health
Risks
and
Safety
Risks
(
62
FR
19885,
April
23,1997).
applies
to
any
rule
that:
(
11
Is
determined
to
he
"
economically
significant"
as
defined
under
Executive
Order
12866,
and
(
2)
concerns
an
environmental
health
or
safety
risk
that
EPA
has
reason
to
believe
may
have
a
disproportionate
effect
on
children.
If
the
regulatory
action
meets
both
criteria,
FEDERAL
INSECTICIDE,
FUNGICIDE,
8
RODENTICIDE
ACT
CIVIL
6,200
the
Agency
must
evaluate
the
envirimmental
health
or
safety
effects
(
tlie
planned
rule
on
children.
and
explain
why
the
planned
rcgulation
is
preferablo
to
other
polentially
effective
and
reasonably
feasible
alternatives
considered
by
the
Agency.
EPA
interprets
Executive
Order
13045
as
is
published
in
the
Federal
Register.
This
action
is
not
a
"
major
rule"
as
defined
by
5
U.
S.
C.
804(
2).
For
the
reasons
outlined
above.
however,
this
action
will
take
effect
August
19,
2002.
List
of
Subjects
4OCFRPori19
)
f
'
Environmental
protection,
Administrative
practice
and
procedure,
Penalties.
40
CFR
Pari
27
Administrative
practice
and
procedure,
Assessments,
False
claims,
False
statements,
Penalties.
,
Dated:
May
31.2002.
Christine
Todd
Whitman,
Administrator,
Envimnmentol
Protection
Agency.
preamble,
title
40,
chapter
I
of
the
Code
of
Federal
Regulations
is
amended
as
follows:
1.
Revise
part
19
to
read
as
follows:
For
the
reasons
set
out
in
the
PART
19
ADJUSTMENT
OF
CIVIL
MONETARY
PENALTIES
FOR
applying
only
to
those
re
ulatory
risks,
such
that
the
analysis
required
under
section
5
501
of
the
Order
has
the
potential
to
influence
the
regulation.
This
rule
is
not
subject
to
Executive
Order
13045
because
it
does
not
establish
an
environmental
standard
intended
to
mitigate
health
or
safety
risks.
Because
this
action
does
not
involve
technical
standards,
EPA
did
not
consider
the
use
of
any
voluntary
consensus
standards
under
the
National
Technology
Transfer
and
Advancement
Act
of
1995
(
15
U.
S.
C.
272
note).
This
action
does
not
impose
an
information
collection
burden
under
the
provisions
of
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.)
because
it
does
not
require
persons
to
obtain,
maintain,
retain,
report,
or
publicly
disclose
information
to
or
for
a
Federal
agency.
Nor
does
it
require
any
special
considerations
under
Executive
Order
Set.
12898.
entitled
Federal
Actions
to
Address
Environmental
Justice
in
19.3
[
Reserved]
Minority
Populations
and
Low
Income
Populations
`
59
7629'
16'
Authority:
Pub.
L.
101
410.28
U.
S.
C.
2461
1994).
This
action
is
not
subject
to
Executive
Order
13211,
Actions
Concerning
Regulations
That
p19.1
Applicability.
Significantly
Affect
Energy
Supply,
This
part
applies
to
each
statutory
Distribution,
or
Use
(
66
FR
28355,
May
provision
under
the
laws
administered
22,2001)
because
it
is
not
a
significant
regulatory
action
under
Executive
Order
the
Protection
concerning
the
maximum
civil
monetary
penalty
which
may
he
12866.
Congressional
Review
Act
assessed
in
either
civil
judicial
or
administrative
proceedings
U.
S.
C.
801
et
seq.,
as
added
by
the
Small
019,2
Effective
date,
Business
Regulatory
Enforcement
Fairness
Act
of
1996,
generally
provides
The
increased
penalty
set
that
before
a
rule
may
take
effect,
the
forth
in
this
Part
apply
to
all
violations
agency
promulgating
the
rule
must
under
the
applicable
statutes
and
copy
of
the
rule,
to
each
House
of
the
.
2o02.
Congress
and
to
the
Comptroller
General
619.3
peseweq
of
the
United
States.
EPA
will
submit
a
report
containing
this
rule
and
other
required
information
to
the
US.
Senate.
the
US.
House
of
Representatives,
and
the
Comptroller
General
of
the
United
States
prior
to
publication
of
the
rule
in
the
Federal
Register.
A
major
rule
cannot
take
effect
until
60
days
after
it
actions
that
are
based
on
a
ealth
or
safety
INFLATION
19.1
A
plicability.
19.2
Ekctive
Date.
19.4
penalty
adjustment
and
table.
note;
Pub.
L.
104
134,
31
U.
S.
C.
3701
note.
The
Congressional
Review
Act,
5
a
rule
which
includes
a
regulations
which
occur
after
August
19,
019.4
Penalty
adjustment
and
table.
The
adjusted
statutory
penalty
provisions
and
their
maximum
applicable
amounts
are
set
out
in
Table
1.
The
last
column
in
the
table
provides
the
newly
effective
maximum
penalty
amounts.
TABLE
1.
OF
SECTiON
19.4.
cIVIL
MONETARY
PENALTY
INFLATION
ADJUSTMENTS
I
New
maximum
penal&
amount
ldoilaml
US.
Code
citation
I
Civil
monetary
penalty
description
U.
S.
Code
citation
41346
Federal
Re&
ter/
Vol.
67,
No.
117
/
Tuesday,
June
18.
2002
/
Rules
and
Regulations
7
U.
S.
C.
136I.(
a)(
2)
........................
15
U.
S.
C.
2615(
a)
..........................
15
U.
S.
C.
2647(
a)
..........................
31
U.
S.
C.
3802(
a)(
1)
......................
31
U.
S.
C.
3802(
a)(
2)
........
:.............
33
U.
S.
C.
1319(
d)
..........................
33
U.
S.
C.
1319(
g)(
Z)(
A)
.................
33
U.
S.
C.
1319(
g)(
2)(
B)
.................
33
U.
S.
C.
1321(
b)(
6)(
8)(
1)
.............
33
U.
S.
C.
1321(
b)(
6)(
E)(
ii)
.............
33
U.
S.
C.
1321(
b)(
7)(
A)
___..............
33
U.
S.
C.
1321(
b)(
7)(
B)
.................
33
U.
S.
C.
1321(
b)(
7)(
C)
.................
33
U.
S.
C.
1321(
b)(
7)(
D)
.................
33
U.
S.
C.
1414b(
d)
........................
33
U.
S.
C.
1415(
a)
..........................
42
U.
S.
C.
300g3(
b)
......................
42
U.
S.
C.
300*
3(
c)
......................
42
U.
S.
C.
300*
3(
g)(
3)(
A)
42
U.
S.
C.
300p3(
g)(
3)(
B)
42
U.
S.
C.
300*
3(
g)(
3)(
C)
.............,
42
U.
S.
C.
300h
Z(
b)(
l)
...................
42
U.
S.
C.
300M(
c)(
l)
................_..
42
U.
S.
C.
3OOh
Z(
c)(
2)
...................
42
U.
S.
C.
300M(
c)(
l)
...................
42
U.
S.
C.
300h
3(
c)(
2)
...................
42
U.
S.
C.
300i(
b)
............................
42
U.
S.
C.
300cl(
c)
42
U.
S.
C.
300j(
e)(
2)
42
U.
S.
C.
300j
4(
c)
........................
42
U.
S.
C.
300@(
b)(
2)
....................
42
U.
S.
C.
300j
23(
d)
......................
42
U.
S.
C.
4852d(
b)(
5)
........___.........,
42
U.
S.
C.
4910(
a)(
2)
42
U.
S.
C.
6926(
a)(
3)
42
U.
S.
C.
6928(
c)
.........
Civil
monetaly
penalty
description
FEDERAL
INSECTICIDE,
FUNGICIDE,
a
RODENTICIDE
ACT
civiL
PENALTY4RIVATE
APPLICATORS
FIRST
AND
SUESE
'
QUENT
OFFENSES
OR
VIOLATIONS.
TOXIC
SUBSTANCES
CONTROL
ACT
CIVIL
PENALTY
...................
ASBESTOS
HAZARD
EMERGENCY
RESPONSE
ACT
CIVIL
PEN
PROGRAM
FRAUD
CIVIL
REMEDIES
ACTNIOLATION
INVOLVING
ALTY.
FALSE
CLAIM.
.
.
.
.
,
.
.
CLEAN
WATER
ACT
VIOLATIONICIVIL
JUDICIAL
PENALTY
OF
CLEAN
WATER
ACT
VIOLATIONICIVIL
JUDICIAL
PENALN
OF
SEC
3110).
CLEAN
WATER
ACT
VlOLATlONlMlNlMUM
CIVIL
JUDICIAL
PEN
ALTY
OF
SEC
311(
b)(
3)
PER
VIOLATION
OR
PER
BARREU
UNIT.
MARINE
PROTECTION,
RESEARCH
8
SANCTUARiES
ACT
VIOL
SEC
104b(
d).
MARINE
PROTECTION
RESEARCH
AND
SANCTUARIES
ACT
VIO
SAFE
DRINKING
WATER
ACTlClVlL
JUDICIAL
PENALN
OF
SEC
SAFE
DRINKING
WATER
ACTICIVIL
JUDICIAL
PENALTY
OF
SEC
SAFE
DRINKING
WATER
ACTICIVIL
JUDICIAL
PENALTY
OF
SEC
SEC
311(
c)
a
(
e)(
I)(
E).
LATIONS
FIRST
a
SUBSEQUENT
VIOLATIONS.
1414(
b).
1414(
c).
1414faM3Mal.
1
1
1
1
~
1
~
~
1
SAFE
DRINKING
WATER
ACTlMAXlMUM
ADMINISTRATIVE
PEN
SAFE
DRINKING
WATER
ACTTHRESHOLD
REQUIRING
CIVIL
JU
SDWNCIVIL
JUDICIAL
PENALTYNIOLATIONS
OF
REQS
UN
SDWNClVlL
ADMIN
PENALNNIOLATIONS
OF
UIC
R
E
Q
W
E
R
SDWNClVlL
ADMlN
PENALNNIOLATIONS
OF
UIC
REQS
PER
SDWANlOLATlONlOPERATlON
OF
NEW
UNDERGROUND
INJEC
SDWANYILLFUL
VIOLATION/
OPERATION
OF
NEW
UNDER
SDWNFAILURE
TO
COMPLY
WITH
IMMINENT
AND
SUESTAN
SDWNAlTEMPTiNG
TO
OR
TAMPERING
WITH
PUBLIC
WATER
SDWNFAILURE
TO
COMPLY
WIORDER
ISSUED
UNDER
SEC.
SDWNREFUSAL
TO
COMPLY
WITH
REQS.
OF
SEC.
14451a1
OR
ALTIES
PER
SEC
1414(
g)(
3)(
E).
DICIAL
ACTION
PER
SEC
1414(
g)(
3)(
C).
DERGROUND
INJECTION
CONTROL
(
UIC).
VIOLATION
AND
MAXIMUM.
VIOLATION
AND
MAXIMUM.
TION
WELL.
GROUND
INJECTION
WELL.
TlAL
ENDANGERMENT
ORDER.
SYSTEWCIVIL
JUDICIAL
PENALTY.
1441(
C)(
l).
.
.
(
b).
SDWNFAILURE
TO
COMPLY
WITH
ADMIN.
ORDER
ISSUED
TO
SDWANlOLATlONSlSECTlON
1463(
bHlRST
OFFENSHREPEAT
FEDERAL
FACILITY.
OFFFNSF
I
.
.
_.
RESIDENTIAL
LEAD
BASED
PAINT
HAZARD
REDUCTION
ACT
OF
NOISE
CONTROL
ACT
OF
19724IVIL
PENALTY
...........................
1992.
SEC
IOIB
CIVIL
PENALTY.
RESOURCE
CONSERVATION
a
RECOVERY
ACTNIOLATION
SUBTITLE
C
ASSESSED
PER
ORDER.
COMPLIANCE
ORDER.
RES.
CONS.
8
REC.
ACTICONTINUED
NONCOMPLIANCE
OF
1992
SEC
i
n
i
g
i
v
i
i
PFNAI
TY
.
.
.
.
.
.
.
.
.
.
.
.
.
..
.
.
.
.
New
maximum
penalty
amount
(
dollan)
63011,300
31,500
6,200
6,200
6.200
31,500
12,000/
31.600
12,0001157,500
12,000131,500
12.0001157.560
31.500
or
1,300
per
barrel
or
unit
31.500
31.500
125,000
or
3,700
per
barrel
or
unit
750
62,0001157.500
31.500
31,500
31.500
~,
200128.000
28.000
31,500
12,0001157,500
3,20011
57.500
3,200
12.000
17.000
25,000162,000
3.150
31,500
!
6.000
~.
200162,000
12.000
12,000
31,500
31,500
1
Federal
Register/
Vol.
67,
No.
117/
Tuesday,
June
18,
20021Rules
and
Regulations
41347
U.
S.
Code
citation
42
U.
S.
C.
6928(
g)
...........................
42
U.
S.
C.
6928(
h)(
2)
42
U.
S.
C.
6934(
e)
42
U.
S.
C.
6973(
b)
42
U.
S.
C.
6991e(
a)(
3)
42
U.
S.
C.
6991e(
d)(
l)
42
U.
S.
C.
6991e(
d)(
2)
42
U.
S.
C.
6992d(
a)(
2)
42
U.
S.
C.
6992d(
a)(
4)
.....................
42
U.
S.
C.
6992d(
d)
.........................
42
U.
S.
C.
7413(
b)
...........................
42
U.
S.
C.
7413(
d)(
i)
..............
:
........
42
U.
S.
C.
7413(
d)(
3)
.......................
42
U.
S.
C.
7524(
a)
...........................
42
U.
S.
C.
7524(
a)
...........................
42
U.
S.
C.
7524(
c)
...........................
42
U.
S.
C.
7545
d
42
U.
S.
C.
9604{
e](
42
U.
S.
C.
9606(
b)(
l)
.......................
42
U.
S.
C.
9609(
a)
8
(
b)
............__._..
42
U.
S.
C.
9609
b
42
U.
S.
C.
96091~
1
...........................
42
U.
S.
C.
9609(
c)
...........................
42
U.
S.
C.
11045(
a)
8
(
b)(
l).
(
2)
8
(
3).
42
U.
S.
C.
11045(
bp)
a
(
3)
...........
42
U.
S.
C.
11045(
c)(
I)
42
U.
S.
C.
11045(
c)(
2)
.....................
42
U.
S.
C.
11045(
d)(
l)
.....................
Civil
monetary
penalty
description
RESOURCE
CONSERVATION
a
RECOVERY
ACTNIOLATION
RES.
CONS.
a
REC.
ACTINONCOMPLIANCE
OF
CORRECTIVE
RES.
CONS.
a
REC.
ACTINONCOMPLIANCE
WITH
SECTION
3013
RES.
CONS.
a
REC.
ACTNIOLATIONS
OF
ADMINISTRATIVE
RES.
CONS.
a
REC.
ACTINONCOMPLIANCE
WITH
UST
ADMINIS
RES.
CONS.
a
REC.
ACTIFAILURE
TO
NOTIFY
OR
FOR
SUBMIT
SUBTITLE
C.
ACTION
ORDER.
ORDER.
ORDER.
TRATIVE
ORDER.
TlNG
FALSE
INFORMATION.
MENTS.
ASSESSED
THRU
ADMlN
ORDER.
ADMINISTRATIVE
ORDER.
ClAL
PENALTIES.
TIONARY
AIR
POLLUTION
SOURCEUUDICIAL
PENALTIES.
TIONARY
AIR
POLLUTION
SOURCEWDMINISTRATIVE
PEN
CLEAN
AIR
ACTMNOR
VIOLATIONS/
STATIONARY
AIR
POLLU
TION
SOURCES
FIELD
CITATIONS.
TAMPERING
OR
MANUFACTUREEALE
OF
DEFEAT
DEVICES
IN
VIOLATION
OF
7522(
a
(
3
(
A
OR
(
a)(
3
B)
BY
PERSONS.
VIOLATION
OF
7522(
a)(&
A)
b
R
(
a)(
3)(&
BY
MANUFACTURERS
OR
DEALERS:
ALL
VIOLATIONS
OF
7522(
a)(
I),
(
2).
(
4).
8
(
5)
BY
ANYONE.
ADMINISTRATIVE
PENALTIES
AS
SET
IN
7524(
a)
8
7545(
d)
WITH
A
MAXIMUM
ADMINISTRATIVE
PENALTY
VIOLATIONS
OF
FUELS
REGULATION
RCWIOLATIONS
OF
SPECIFIED
UST
REGULATORY
REQUIRE
RCWNONCOMPLIANCE
WlMEDlCAL
WASTE
TRACKING
ACT
RCWNONCOMPLIANCE
WlMEDlCAL
WASTE
TRACKING
ACT
RCRANIOLATIONS
OF
MEDICAL
WASTE
TRACKING
ACTAUDI
CLEAN
AIR
ACTNIOLATION~
OWNERS
a
OPERATORS
OF
STA
CLEAN
AIR
ACTNIOLATIONIOWNERS
a
OPERATORS
OF
STA
ALTIES
PER
VIOLATION
a
MAX.
SUPERFUND'AMEND.
a
REAUTHOR
ANCE
WIREQUEST
FOR
INFO
OR
ACCESS.
TIAL
ENDANGERMENT.
SECT.
9603,
9608.
OR
9622.
SUPERFUNDNVORK
NOT
PERFORMED
W/
IMMINENT.
SUBSTAN
SUPERFUNDIADMIN.
PENALTY
VIOLATIONS
UNDER
42
U.
S.
C.
SUPERFUNDIADMIN.
PENALTY
VIOLATIONMUBSEQUENT
.....,
SUPERFUNDICIVIL
JUDICIAL
PENALTYNIOLATIONS
OF
SECT.
SUPERFUNDlClVlL
JUDICIAL
PENALTYEUBSEQUENT
VIOLA
EMERGENCY
PLANNING
AND
COMMUNITY
RIGHT
TO
KNOW
9603,
9608,
9622.
TIONS
OF
SECT.
9603,
9608.
9622.
ACT
CLASS
I
a
II
ADMINISTRATIVE
AND
CIVIL
PENALTIES.
EPCRA
CLASS
I
a
II
ADMINISTRATIVE
AND
CIVIL
PENALTIES
SUBSEQUENT
VIOLATIONS.
EPCRA
CIVIL
AND
ADMINISTRATIVE
REPORTING
PENALTIES
FOR
VIOLATIONS
OF
SECTIONS
11022
OR
11023.
EPCRA
CIVIL
AND
ADMINISTRATIVE
REPORTING
PENALTIES
FORVIOLATIONS
OF
SECTIONS
11021
OR
11043(
b).
EPCRA4RIVOLOUS
TRADE
SECRET
CLAIMS
CIVIL
AND
AD
MINISTRATIVE
PENALTIES.
New
maximum
penally
amount
(
dollars)
31,500
31.500
6,200
6,200
31,500
12,000
12,000
31.500
31.500
31,500
31.500
31,5001250,000
6.200
3.150
31,500
250,000
31,500
31,500
31,500
31,500
92,500
31.500
92,500
31,500
92,500
31,500
12,000
$
31.500
PART
27+
AMENDED]
2.
The
authority
citation
for
part
27
continues
to
read
as
follows:
Authority:
31
U.
S.
C.
3601
3812:
Pub.
L.
101
410.104
Stat.
690,
28
U.
S.
C.
2461
note;
Pub
L.
104
134.110
Stat.
1321,
31
U.
S.
C.
3701
note.
3.
Section
27.3
is
amended
by
revising
paragraphs
(
a)(
l)(
iv)
and
(
b)(
l)(
ii)
to
read
as
follows:
021.3
Bask
for
civil
penalties
and
assessments.
(
a)
*
*
(
1)
*
f
*
(
iv)
Is
for
payment
for
the
provision
of
property
or
services
which
the
person
has
not
provided
as
claimed,
shall
he
subject.
in
addition
to
any
other
remedy
that
may
be
prescribed
by
law,
to
a
civil
penalty
of
not
more
than
$
6,200
1
for
each
such
claim.
*
.
*
*
*
(
b)
*
*
*
(
1)
*
*
(
ii)
Contains,
or
is
accompanied
by,
an
express
certification
or
affirmation
of
2
As
adjusted
in
accordance
with
ths
Federal
Civil
Penellies
Inflation
Adjustment
Act
of
1990
[
pub.
L.
101
410.104
Stst.
8901,
as
amended
by
the
Deb1
Collection
hpmvemenl
Act
of
1996
(
Pub.
L.
104
134,110Slat.
1321).
41348
.
Federal
Register/
Vol.
67,
No.
117/
Tuesday,
June
18,
20021Rules
and
Regulations
the
truthfulness
and
accuracy
of
the
contents
of
the
statement,
shall
be
subject,
in
addition
to
any
other
remedy
that
may
he
prescribed
by
law,
to
a
civil
penalty
of
not
more
than
$
6,2002
for
each
such
statement.
[
FR
Doc.
02
15190
Filed
6
1
7
4
2
:
8:
45
aml
BlLUNG
CODE
w.
'
*
*
*
.
.
DEPARTMENT
OF
TRANSPORTATION
National
Highway
Traffic
Safety
Administration
49
CFR
Pad
571
[
Docket
No.
02
124801
RIN
2127
Al86
Federal
Motor
Vehicle
Safety
Standards;
Head
Impact
Protection
AGENCY:
National
Highway
Traffic
Safety
Administration
(
NHTSA],
Department
of
Transportation
[
DOT).
ACTION:
Interim
final
rule,
request
for
comments.
SUMMARY:
This
interim
final
rule
amends
the
schedule
for
compliance
by
manufacturers
of
vehicles
built
in
two
or
more
stages
with
the
upper
interior
~
head
protection
requirements
of
Federal
Motor
Vehicle
Safety
Standard
No.
201,
Occupant
Protection
in
Interior
impact.
This
intbrim
final
rule
delays
the
date
on
which
manufacturers
of
vehicles
built
in
two
or
more
stages
must
produce
vehicles
meeting
the
upper
interior
head
protection
performance
requirements
of
Standard
No.
201
from
September
1.
2002,
until
September
1,
2003.
The
agency
is
issuing
this
interim
final
rule
to
provide
the
agency
time
to
complete
a
rulemakiing
action
initiated
by
petitions
for
rulemaking
requesting
that
NHTSA
consider
modifying
the
requirements
of
Standard
No.
201
as
they
apply
to
vehicles
manufactured
in
two
or
more
stages.
As
that
rulemaking
action
may
result
in
modification
of
Standard
No.
201
as
it
applies
to
these
multi
stage
vehicles,
the
agency
has
decided
to
extend
the
compliance
date
until
the
final
action
is
taken
on
the
petitions,
It
expects
to
take
final
action
before
September
1,2003.
DATES:
This
interim
final
rule
becomes
effective
on
July
18,2002.
Comments
on
this
interim
rule
are
due
no
later
than
August
19,2002.
Penalties
Innation
Adjusunenl
Act
of
1990
(
Pub.
L.
101
410.104
Stet.
890).
as
amended
by
the
DBbt
Collection
lmpmvernent
Act
of
1996
(
Pub.
L.
104
134.110StBl.
13211.
'
As
adjusted
in
accordance
wilh
ths
Federal
Civil
ADDRESSES:
You
may
submit
your
comments
in
writing
or
electronically.
Written
comments
should
refer
to
the
docket
number
of
this
notice
and
he
submitted
(
preferably
in
two
copies1
to:
Docket
Management,
P
01,
Nassif
Building,
400
Seventh
Street,
SW.,
Washington,
DC
20590.
(
Docket
hours
are
Monday
Friday
from
10
a.
m.
to
5
pm.,
excluding
holidays.)
Electronic
comments
can
he
submitted
through
the
worldwide
web
at
http://
dms.
dot.
gov.
FOR
FURTHER
INFORMATION
CONTACT,:
For
non
legal
issues,
you
may
call
Dr.
William
Fan,
Office
of
Crashworthiness
Standards,
at
(
202)
366
4922,
facsimile
(
202)
3664329.
For
legal
issues,
you
may
call
Otto
Matheke,
Office
of
the
Chief
Counsel,
at
202
366
5263.
SUPPLEMENTARY
INFORMATION:
Table
of
Cantents
added
proc6dures
for
a
new
in
vehicle
component
test
in
which
a
Free
Motion
Headform
(
m)
is
fired
at
certain
target
locations
on
the
upper
interior
of
a
vehicle
at
an
impact
speed
of
up
to
and
including
24
kmlh
(
15
mph).
Data
collected
from
a
FMH
impact
are
translated
into
a
value
known
as
a
Head
Injury
Criterion
(
HIC]
score.
The
resultant
HIC
must
not
exceed
1000.
April
8.1997
(
62
FR
16718).
provides
manufacturers
with
four
alternate
phase
in
schedules
for
complying
with
the
upper
interior
impact
requirements.
First,
as
set
forth
in
S6.1.1.
manufacturers
may
comply
by
having
the
following
percentages
of
their
production
meet
the
upper
interior
impact
requirements:
10
percent
of
production
on
or
after
September
1.
1998
and
before
September
1,1999;
25
percent
of
production
on
or
after
September
I,
1999
and
before
September
1,2000,
40
percent
of
production
on
or
after
September
1,
2000
and
before
Seotemher
1.2001.70
The
standard.
as
further
amended
on
.
.
.
.
_.
.
111.
Standard
201
and
Vehicles
Built
in
Two
or
More
Stages
IV.
Interim
Final
Rule
percent
of
productibn
on
or
after
September
1,2001
and
before
Seutember
1.2002.
and
100
nercent
of
V
Written
Comments
VI
Regulatury
Analyses
nnd
Notices
prbduction
after
Scptembcr
i,
2002.
Second,
an
alternative
schedule
set
I.
Background
18,
1995,
amending
Federal
Motor
Vehicle
Safety
Standard
No.
201.
Occupant
Protection
in
Interior
Impact,
to
require
passenger
cars,
and
trucks,
buses
and
multipurpose
passenger
vehicles
with
a
gross
vehicle
weight
rating
of
4,536
kilograms
(
10,000
pounds)
or
less,
to
provide
head
protection
during
a
crash
when
an
occupant's
head
strikes
the
upper
interior,
i.
e.,
the
roof
pillars,
side
rails,
headers.
and
the
roof
itself
of
the
vehicle.
(
60
FR
430341)
The
final
rule
responded
to
the
NHTSA
Authorization
Act
of
1991
(
sections
2500
2509
of
the
Internodal
Surface
Transportation
Efficiency
Act
("
ISTEA']),
Pub.
L.
102
240).
ISTEA
required
NHTSA
to
address
several
vehicle
safety
matters
through
rulemaking.
One
of
these
matters,
set
forth
in
section
2503(
5),
is
improved
bead
impact
protection
from
interior
components
(
i.
e,,
roof
rails,
pillars,
and
front
headers)
of
passenger
cars.
The
final
rule,
which
mandated
compliance
with
the
new
requirements
beginning
on
September
1,
1998,
significantly
expanded
the
scope
of
Standard
201.
Previously,
the
standard
applied
to
the
instrument
panel,
seat
hacks,
interior
compartment
doors,
arm
rests
and
sun
visors.
To
determine
compliance
with
the
upper
interior
impact
requirements,
the
final
rule
NHTSA
issued
a
final
rule
on
August
forth
in
56.1.2
provides
that
manufacturers
may
comply
hy.
meeting
the
following
phase
in
schedule:
7
percent
of
the
vehicles
manufactured
on
or
after
September
1,1998
and
before
September
1,1999;
31
percent
of
vehicles
manufactured
on
or
after
September
1,1999
and
before
September
1,2000:
40
percent
of
vehicles
manufactured
on
or
after
September
1,2000
and
before
September
1,2001;
70
percent
of
vehicles
manufactured
on
or
after
September
1.2001
and
before
September
1.2002;
and
100
percent
of
all
vehicles
manufactured
after
Se
temher
1,
2002.
fhird,
under
the
phase
in
schedule
set
forth
in
S6.1.3,
manufacturers
need
not
produce
any
complying
vehicles
before
September
1,
1999.
However,
all
vehicles
produced
on
or
after
that
date
must
comply.
Fourth,
56.1.4
of
the
April
8,1997
final
rule
provided
that
multi
stage
vehicles
produced
after
September
1,
2002,
were
required
to
comply.
11.
Petitions
for
Rulemaking
The
Recreation
Vehicle
Industry
Association
(
RVIA)
filed
a
petition
for
rulemaking
on
October
4,2001
requesting
that
the
agency
modify
Standard
No.
201
to
exclude
conversion
vans
and
motor
homes
with
gross
vehicle
weight
rating
of
4,536
kilograms
(
10,000
pounds)
or
less,
from
the
application
of
the
upper
interior
head
| epa | 2024-06-07T20:31:41.030499 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OECA-2002-0004-0002/content.txt"
} |
EPA-HQ-OECA-2002-0004-0003 | Supporting & Related Material | "2002-08-09T04:00:00" | null | ~
a
o
o
l
s
o
~
I
V
D
00
j
United
States
General
Accounting
Office
Washington,
DC
20548
B
290021
I
Received
I
flus
g
,2002
Enfmement
&
Compliance
oockt
#
'
u
8
Information
Center
July
15,2002
Mr.
Robert
E.
Fabricant
General
Counsel
US.
Environmental
Protection
Agency
Subject
Federal
Civil
Penalties
Inflation
Adiustment
Act
Dear
Mr.
Fabricant
Earlier
this
year,
GAO
initiated
a
review
of
the
implementation
of
the
Federal
Civil
Penalties
Inflation
Adjustment
Act
of
1990,
as
amended
("
Inflation
Adjustment
Act").'
This
act
generally
requires.
federal
agencies
to
issue
regulations
adjusting
their
covered
civil
monetary
penalties
for
changes'in
the
cost
of
living
by
October
23,1996,
and
to
make
necessary
adjustments
at
least
once
every
&
years
thereafter.
Section
4,
28
U.
S.
C.
$
2461
note.
The
statute
defines
a
"
cost
of
living
adjustment"
as
the
percentage
change
in
the
Consumer
Price
Index
(
CPI)
between
June
of
the
calendar
year
indhich
the
penalty
was
last
set
or
adjusted
and
June
of
the
calendar
year
preceding
the
adjustment.
Section
5,28
U.
S.
C.
$
2461
note.
The
statute
limited
the
fistadjustment
to
10
percent
and
includes
a
mechanism
for
rounding
penalty
increases.
Sections
5
and
6,28
U.
S.
C.
$
2461
note.
With
regard
to
rounding,
the
statute
sets
out
penalty
ranges,
from
amounts
less
than
or
equal
to
$
100
to
amounts
greater
than
$
200,000,
and
provides
different
dollar
multiples
for
rounding
the
increase
in
each
penalty
range.
Section
5,28
U.
S.
C.
$
2461
note.
The
statute
provides,
for
example,
that
"[
ajny
increase
shall
be
rounded
to
the
nearest.
.
.
multiple
of
$
10
in
the
case
of
Denalties
less
than
or
equal
to
$
100."
Id.
(
Emphasis
added.)
The
Environmental
Protection
Agency
@
PA)
made
its
fist
round
of
civil
penalty
adjustments
under
the
Inflation
Adjustment
Act
on
December
31,1996.
61
Fed.
Reg.
69,360:
Because
all
of
EPA's
covered
penalties
had
been
in
place
for
at
least
5
years,
and
the
amount
of
inflation
occurring
during
that
period
was
more
than
'
The
Inflation
Adjustmpt
Act
is
codified
at
28
U.
S.
C.
$
2461
note.
The
1990
act
was
amended
in
1996
by
the
Debt
Collection
Improvement
Act,
which
added
the
requirement
for
agencies
to
adjust
their
civil
penalties
by
regulation.
Pub.
L.
NO.
104134,
$
31001,
110
Stat.
1321
373
(
1996).
,
.1
.
.,
10
percent,
the
agency
adjusted
all
of
its
penalties
by
the
statutory
maximum
of
10
percent,
and
the
rounding
mechanism
did
not
apply.
On
June
18,2002,
EPA
published
a
direct
final
rule
implementing
a
second
round
of
penalty
acljustments
to
account
for
the
13.6
percent
change
in
the
CPI
between
1996
and
June
2001.
67
Fed.
Reg.
41,343
(
June
18,2002).
2
EPA
calculated
the
penalty
increase
by
multiplying
the
existing
penalty
amounts
by
13.6
percent.
EPA
then
used
the
size
of
the
penalty
increase
to
determine
the
category
of
rounding.
However,
the
statute
provides
that
the
category
of
rounding
should
be
determined
by
the
size
of
the
penalty,
not
the
size
of
the
increase.
In
the
preamble
to
the
June
2002
direct
final
rule,
EPA
noted
that
the
agency's
approach
of
rounding
based
on
the
amount
of
the
increase
achieves
the
intent
of
the
Inflation
Adjustment
Act
because
it
"
will
result
in
increase
amounts
that
more
closely
track
the
changes
in
the
CPI."
67
Fed.
Reg.
41,344.
EPA
also
indicated
that
calculations
based
on
other
rounding
approaches
"
could
result
in
penalty
adjustments
that
are
several
times
the
CPI
percentage
or
in
no
increase
at
all
even
with
increases
in
the
CPI."
Id.
As
noted
in
our
informal
discussions
with
your
staff,
the
method
of
rounding
that
the
EPA
proposes
in
its
June
2002
NPRM
and
direct
final
rule
is
inconsistent
with
the
requirements
of
the
statute.
The
so
called
"
plain
meaning"
rule
of
statutory
construction
dictates
that
"
if
the
Congress
has
clearly
expressed
its
intent
in
the
plain
language
of
the
statute,"
then
the
courts
and
the
agency
must
give
effect
to
that
intent.
MississiDDi
Poultrv
Ass'n.
Inc.
v.
Madigan,
31
F.
3d
293
(
5"
Cir.
1994).
The
language
in
the
Inflation
Adjustment
Act
makes
clear
that
rounding
is
based
on
the
dollar
amount
of
the
penalty.
In
this
regard,
the
statute
specifically
requires
the
rounding
of
"
the
increase,"
rather
than
the
penalty,
and
uses
the
term
"
penalty"
for
determining
which
rounding
range
should
be
used
to
round
the
increase.
Thus,
when
the
statute
states
that
any
increase
"
shall
be
rounded
to
the
nearest.
.
.
multiple
of
$
100
in
the
case
of
penalties
greater
than
$
100
but
less
than
or
equal
to
$
1,000,"
you
must
iirst
determine
the
percent
increase,
apply
it
to
the
current
penalty,
and
then,
if
the
penalty
falls
in
the
range
of
greater
than
$
100
but
less
than
or
equal
to
$
1,000,
round
the
increase
to
the
nearest
multiple
of
$
100.
Nothing
in
the
plain
language
of
the
statute,
nor
in
the
legislative
history,
permits
an
agency
to
use
the
size
of
the
increase
to
determine
the
appropriate
category
of
rounding.
On
that
same
date,
EPA
published
a
notice
of
proposed
rulemaking
(
NPRM),
67
Fed.
Reg.
41,363,
that
proposed
to
similarly
adjust
the
civil
monetary
penalties
for
inflation,
because,
if
"
EPA
receives
adverse
comment
by
July
18,2002,"
the
direct
final
rule
"
will
not
take
effect."
EPA
would
then
address
all
public
comments
in
a
subsequent
final
rule
based
on
this
proposed
rule.
Page
2
E290021
Other
agencies
have
used
the
Same
analysis
of
the
statute
to
reach
the
Same
result
as
we
do.
3
In
addition,
the
Department
of
the
Treasury
guidelines
issued
in
1996,
after
the
Mation
Aaustment
Act
was
enacted,
state
that
rounding
is
based
on
the
amount
of
the
penalty,
not
the
amount
of
the
increase.
We
also
note
that
Congress
used
identical
language
for
rounding
when
it
enacted
the
Consumer
Product
Safety
Improvement
Act
(
Improvement
Act),
Pub.
L.
No.
101
608,104
Stat.
3110
(
1990).
The
Improvement
Act
authorized
the
Consumer
Product
Safety
Commission
to
acijust
civil
penalties
for
inflation
every
5
years.
15
U.
S.
C.
$
2069
(
2000).
From
a
reading
of
the
Commission's
acijustment
regulations,
it
is
clear
that
the
Commission
also
rounds
on
the
basis
of
the
penalty,
and
not
on
the
in~
rease.~
While
we
recognize
some
advantages
to
rounding
on
the
basis
of
the
size
of
the
increase
rather
than
the
size
of
the
penalty,
such
a
determination
does
not
comport
with
the
language
of
the
statute.
Consequently,
if
EPA
wishes
to
pursue
the
approach
outlined
in
the
Federal
Register
notices,
we
respectfully
suggest
that
EPA
seek
appropriate
legislation.
If
you
have
any
questions
regarding
this
matter,
please
contact
me
on
202
512
5400
or
Ms.
Susan
Poling,
Managing
Associate
General
Counsel,
on
202
512
2667.
Sincerely
yours,
See,
u,
the
National
Credit
Union
Administration's
inflation
adjustment
regulation,
65
Fed.
Reg.
57,277,
n.
5
(
2000).
'
59
Fed.
Reg.
66,523
(
1994)
and
64
Fed.
Reg.
51,963
(
1999).
Page
3
E290021
| epa | 2024-06-07T20:31:41.045583 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OECA-2002-0004-0003/content.txt"
} |
EPA-HQ-OECA-2002-0005-0003 | Notice | "2002-12-24T05:00:00" | Agency Information Collection Activities; Submission for OMB for
Review and Approval; Comment Request; NSPS for Hot Mix Asphalt
Facilities, ICR Number 1127.07, OMB Number 2060-0083
| 78452
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Notices
(
202)
566
1514.
An
electronic
version
of
the
public
docket
is
available
through
EPA
Dockets
(
EDOCKET)
at
http://
www.
epa.
gov/
edocket.
Use
EDOCKET
to
submit
or
view
public
comments,
access
the
index
listing
of
the
contents
of
the
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,''
then
key
in
the
docket
ID
number
identified
above.
Any
comments
related
to
this
ICR
should
be
submitted
to
EPA
and
OMB
within
30
days
of
this
notice,
and
according
to
the
following
detailed
instructions:
(
1)
Submit
your
comments
to
EPA
online
using
EDOCKET
(
our
preferred
method),
by
e
mail
to
docket.
oeca@
epa.
gov,
or
by
mail
to:
EPA
Docket
Center,
Environmental
Protection
Agency,
Mailcode:
2201T,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460,
and
(
2)
Mail
your
comments
to
OMB
at:
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget
(
OMB),
Attention:
Desk
Officer
for
EPA,
725
17th
Street,
NW.,
Washington,
DC
20503.
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
in
paper,
will
be
made
available
for
public
viewing
in
EDOCKET
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
public
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
EDOCKET.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Although
identified
as
an
item
in
the
official
docket,
information
claimed
as
CBI,
or
whose
disclosure
is
otherwise
restricted
by
statute,
is
not
included
in
the
official
public
docket,
and
will
not
be
available
for
public
viewing
in
EDOCKET.
For
further
information
about
the
electronic
docket,
see
EPA's
Federal
Register
notice
describing
the
electronic
docket
at
67
FR
38102
(
May
31,
2002),
or
go
to
www.
epa.
gov/
edocket.
Title:
NSPS
for
Kraft
Pulp
Mills
subpart
BB
(
OMB
Control
Number
2060
0021
and
EPA
ICR
Number
1055.07).
This
is
a
request
to
renew
an
existing
approved
collection
that
is
scheduled
to
expire
on
February
28,
2003.
Under
OMB
regulations,
the
Agency
may
continue
to
conduct
or
sponsor
the
collection
of
information
while
this
submission
is
pending
at
OMB.
Abstract:
The
NSPS
for
Kraft
Pulp
Mills,
published
at
40
CFR
part
60,
subpart
BB,
was
proposed
on
September
24,
1976,
and
promulgated
on
February
23,
1978.
Revisions
to
the
standards
were
promulgated
on
May
20,
1986.
This
rule
addresses
total
reduced
sulfur
(
TRS)
and
particulate
matter
emissions
from
new,
modified
and
reconstructed
Kraft
Pulp
Mills.
In
addition
to
the
monitoring,
recordkeeping
and
reporting
requirements
listed
in
the
General
Provisions
(
40
CFR
part
60,
subpart
A),
Kraft
Pulp
Mills
are
required
to
continuously
monitor
and
record
at
least
once
per
shift
specific
parameters
at
the
applicable
affected
facilities:
The
opacity
of
the
gases
discharged
into
the
atmosphere
from
any
recovery
furnace;
the
concentration
of
TRS
emissions
on
a
dry
basis
and
the
percent
of
oxygen
by
volume
on
a
dry
basis
in
the
gases
discharged
to
the
atmosphere;
for
an
incinerator,
the
combustion
temperature
at
the
point
of
incineration
of
effluent
gases
being
emitted
by
the
affected
facilities;
and
for
any
lime
kiln
or
smelt
discharge
tank
using
a
scrubber
emission
control
device,
the
pressure
loss
of
the
gas
stream
through
the
control
equipment
and
the
scrubbing
liquid
pressure
to
the
control
equipment.
Sources
are
also
required
to
record
on
a
daily
basis
12
hour
average
TRS
concentrations
and
oxygen
concentrations
(
for
the
recovery
furnace
and
lime
kiln)
for
two
consecutive
periods
of
each
operation.
Sources
must
report
semiannually
measurements
of
excess
emissions
as
defined
by
the
standard
for
the
applicable
affected
facility.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15,
and
are
identified
on
the
form
and/
or
instrument,
if
applicable.
Burden
Statement:
The
annual
public
reporting
and
recordkeeping
burden
for
this
collection
of
information
is
estimated
to
average
62.4
hours
per
response.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
Respondents/
Affected
Entities:
Kraft
Pulp
Mills/
brown
stock
washer
systems,
recovery
furnaces,
smelt
dissolving
tanks,
lime
kilns,
black
liquor
oxidation
systems
and
condensate
stripper
systems.
Estimated
Number
of
Respondents:
92.
Frequency
of
Response:
Initial,
semiannual
and
on
occasion.
Estimated
Total
Annual
Hour
Burden:
12,107.
Estimated
Total
Annual
Non
labor
Cost:
$
3,143,600,
includes
$
300,000
annualized
capital
costs
and
$
2,844,000
annualized
O&
M
costs.
There
is
an
increase
of
2,148
hours
in
the
total
estimated
burden
currently
identified
in
the
OMB
Inventory
of
Approved
ICR
Burdens.
This
increase
is
due
to
an
increase
and
a
more
accurate
estimate
of
the
number
of
kraft
pulp
mills
in
the
United
States.
The
estimates
on
the
number
of
existing
and
new
sources
were
based
on
the
active
ICR,
Federal
Register
publications
on
other
sector
related
rules,
consultation
with
OAQPS
and
industry,
and
queries
conducted
on
two
EPA
databases
including
the
Sector
Facility
Index
Project
and
the
Aerometric
Information
Retrieval
System
Facility
Subsystem.
Dated:
December
10,
2002.
Oscar
Morales,
Director,
Collection
Strategies
Division.
[
FR
Doc.
02
32392
Filed
12
23
02;
8:
45
am]
BILLING
CODE
6560
50
P
ENVIRONMENTAL
PROTECTION
AGENCY
[
OECA
2002
0005;
FRL
7426
6]
Agency
Information
Collection
Activities;
Submission
for
OMB
for
Review
and
Approval;
Comment
Request;
NSPS
for
Hot
Mix
Asphalt
Facilities,
ICR
Number
1127.07,
OMB
Number
2060
0083
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Notice.
SUMMARY:
In
compliance
with
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.),
this
document
announces
that
the
following
Information
Collection
Request
(
ICR)
has
been
forwarded
to
the
Office
of
Management
and
Budget
(
OMB)
for
review
and
approval:
NSPS
for
Hot
Mix
Asphalt
Facilities
(
40
CFR
part
60,
subpart
I),
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2002
19:
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23,
2002
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Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Notices
(
OMB
Control
Number
2060
0083,
EPA
ICR
Number
1127.07).
The
ICR,
which
is
abstracted
below,
describes
the
nature
of
the
information
collection
and
its
estimated
burden
and
cost.
DATES:
Additional
comments
may
be
submitted
on
or
before
January
23,
2003.
ADDRESSES:
Follow
the
detailed
instructions
in
the
SUPPLEMENTARY
INFORMATION
section.
FOR
FURTHER
INFORMATION
CONTACT:
Gregory
Fried,
Compliance
Assessment
and
Media
Programs
Division,
Office
of
Compliance,
Mail
Code
2223A,
Environmental
Protection
Agency,
1200
Pennsylvania
Avenue,
NW.,
Washington,
D.
C.
20460;
telephone
number:
(
202)
564
7016;
fax
number:
(
202)
564
0050;
E
mail
address:
fried.
gregory@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
EPA
has
submitted
the
following
ICR
to
OMB
for
review
and
approval
according
to
the
procedures
prescribed
in
5
CFR
1320.12.
On
June
20,
2002
(
67
FR
41981),
EPA
sought
comments
on
this
ICR
pursuant
to
5
CFR
1320.8(
d).
EPA
received
no
comments.
EPA
has
established
a
public
docket
for
this
ICR
under
Docket
ID
No.
OECA
2002
0005,
which
is
available
for
public
viewing
at
the
Enforcement
and
Compliance
Docket
and
Information
Center
(
ECDIC)
in
the
EPA
Docket
Center
(
EPA/
DC),
EPA
West,
Room
B102,
1301
Constitution
Avenue,
NW.,
Washington,
DC.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
1744,
and
the
telephone
number
for
the
ECDIC
is
(
202)
566
1514.
An
electronic
version
of
the
public
docket
is
available
through
EPA
Dockets
(
EDOCKET)
at
http://
www.
epa.
gov/
edocket.
Use
EDOCKET
to
submit
or
view
public
comments,
access
the
index
listing
of
the
contents
of
the
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,''
then
key
in
the
docket
ID
number
identified
above.
Any
comments
related
to
this
ICR
should
be
submitted
to
EPA
and
OMB
within
30
days
of
this
notice,
and
according
to
the
following
detailed
instructions:
(
1)
Submit
your
comments
to
EPA
online
using
EDOCKET
(
our
preferred
method),
by
E
mail
to:
docket.
oeca@
epa.
gov,
or
by
mail
to:
EPA
Docket
Center,
Environmental
Protection
Agency,
Mail
Code:
2201T,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460,
and
(
2)
Mail
your
comments
to
OMB
at:
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget
(
OMB),
Attention:
Desk
Officer
for
EPA,
725
17th
Street,
NW.,
Washington,
DC
20503.
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
in
paper,
will
be
made
available
for
public
viewing
in
EDOCKET
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
public
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
EDOCKET.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Although
identified
as
an
item
in
the
official
docket,
information
claimed
as
CBI,
or
whose
disclosure
is
otherwise
restricted
by
statute,
is
not
included
in
the
official
public
docket,
and
will
not
be
available
for
public
viewing
in
EDOCKET.
For
further
information
about
the
electronic
docket,
see
EPA's
Federal
Register
notice
describing
the
electronic
docket
at
67
FR
38102
(
May
31,
2002),
or
go
to
http://
www.
epa.
gov/
edocket.
Title:
NSPS
for
Hot
Mix
Asphalt
Facilities
(
40
CFR
part
60,
subpart
I)
(
OMB
Control
Number
2060
0083,
EPA
ICR
Number
1127.07).
This
is
a
request
to
renew
an
existing
approved
collection
that
is
scheduled
to
expire
on
January
31,
2003.
Under
the
OMB
regulations,
the
Agency
may
continue
to
conduct
or
sponsor
the
collection
of
information
while
this
submission
is
pending
at
OMB.
Abstract:
The
New
Source
Performance
Standards
(
NSPS)
for
Hot
Mix
Asphalt
Facilities
were
proposed
on
June
11,
1973,
and
promulgated
on
July
25,
1977.
These
regulations
apply
to
the
following
facilities
in
40
CFR
part
60,
subpart
I:
Dryers;
systems
for
screening,
handling,
storing,
and
weighing
hot
aggregate;
systems
for
loading,
transferring,
and
storing
mineral
filler;
systems
for
mixing
hot
mix
asphalt;
and
the
loading,
transfer,
and
storage
systems
associated
with
emission
control
systems.
The
Administrator
has
judged
that
Particulate
Matter
(
PM)
emissions
from
hot
mix
asphalt
facilities
cause
or
contribute
to
air
pollution
that
may
reasonably
be
anticipated
to
endanger
public
health
or
welfare.
Therefore,
the
purpose
of
this
NSPS
is
to
control
the
emissions
of
particulate
matter
(
PM)
from
hot
mix
asphalt
facilities.
The
standards
limit
particulate
emissions
to
90
milligrams
per
dry
standard
cubic
meter
(
mg/
DCM)
and
a
20%
opacity.
This
information
is
being
collected
to
assure
compliance
with
40
CFR
part
60,
subpart
I.
In
order
to
ensure
compliance
with
the
standards
promulgated
to
protect
public
health,
adequate
reporting
and
recordkeeping
is
necessary.
Owners/
operators
of
hot
mix
asphalt
facilities
must
notify
EPA
of
construction,
modification,
or
reconstruction
of
a
new
or
existing
facility
and
submit
a
notification
and
the
results
of
an
initial
performance
test.
In
addition,
a
facility
subject
to
this
NSPS
must
record
any
startups,
shutdowns
or
malfunctions.
The
purpose
of
the
notifications
is
to
inform
the
Agency
or
delegated
authority
when
a
source
becomes
subject
to
this
standard.
Performance
tests
are
conducted
to
ensure
that
the
new
plants
operate
within
the
boundaries
outlined
in
the
standard.
In
the
absence
of
such
information,
enforcement
personnel
would
be
unable
to
determine
whether
the
standards
are
being
met
on
a
continuous
basis,
as
required
by
the
Clean
Air
Act.
Under
this
standard
the
data
collected
by
the
affected
industry
is
retained
at
the
facility
for
a
minimum
of
two
years
and
made
available
for
inspection
by
the
Administrator.
The
only
type
of
industry
costs
associated
with
the
information
collection
activity
in
the
standards
are
labor
costs.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
Control
Number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15,
and
are
identified
on
the
form
and/
or
instrument,
if
applicable.
Burden
Statement:
The
annual
public
reporting
and
recordkeeping
burden
for
this
collection
of
information
is
estimated
to
average
3
hours
per
response.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
Respondents/
Affected
Entities:
Hot
Mix
Asphalt
Facilities.
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Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Notices
Estimated
Number
of
Respondents:
2,835.
Frequency
of
Response:
Initial
and
on
occasion.
Estimated
Total
Annual
Hour
Burden:
10,303
hours.
Estimated
Total
Annual
Labor
Cost:
$
588,507.
Changes
in
the
Estimates:
There
is
an
increase
of
3,413
hours
in
the
total
estimated
burden
currently
identified
in
the
OMB
Inventory
of
Approved
ICR
Burdens.
This
increase
is
due
to
an
increase
in
the
number
of
existing
facilities
that
will
undergo
modifications
such
that
they
will
be
required
to
submit
notifications
and
conduct
the
appropriate
performance
tests
required
by
the
standard.
Dated:
December
10,
2002.
Oscar
Morales,
Director,
Collection
Strategies
Division.
[
FR
Doc.
02
32393
Filed
12
23
02;
8:
45
am]
BILLING
CODE
6560
50
P
ENVIRONMENTAL
PROTECTION
AGENCY
[
FRL
7426
8]
Agency
Information
Collection
Activities:
Submission
for
OMB
Review;
Comment
Request;
Voluntary
Customer
Satisfaction
Surveys
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Notice.
SUMMARY:
In
compliance
with
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.),
this
document
announces
that
the
following
Information
Collection
Request
(
ICR)
has
been
forwarded
to
the
Office
of
Management
and
Budget
(
OMB)
for
review
and
approval:
Voluntary
Customer
Satisfaction
Surveys,
OMB
Control
Number
2090
0019,
expiring
March
31,
2003.
The
ICR
describes
the
nature
of
the
information
collection
and
its
expected
burden
and
cost,
where
appropriate,
it
includes
the
actual
data
collection
instrument.
DATES:
Comments
must
be
submitted
on
or
before
January
23,
2003.
ADDRESSES:
Send
comments,
referencing
EPA
ICR
No.
1711.04
and
OMB
Control
No
2090
0019
to
the
following
addresses:
Susan
Auby,
U.
S.
Environmental
Protection
Agency,
Collection
Strategies
Division
(
Mail
Code
2822T),
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460
0001,
and
to
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget
(
OMB),
Attention:
Desk
Officer
for
EPA,
725
17th
Street,
NW.,
Washington,
DC
20503.
FOR
FURTHER
INFORMATION
CONTACT:
For
a
copy
of
the
ICR
contact
Susan
Auby
at
EPA
by
phone
at
202
566
1672,
by
e
mail
at
auby.
susan@
epa.
gov,
or
download
off
the
Internet
at
http://
www.
epa.
gov/
icr
and
refer
to
EPA
ICR
No
1711.04.
For
technical
questions
about
the
ICR
contact:
Patricia
Bonner
by
phone
at
202
566
2204
or
by
e
mail
at
bonner.
patricia@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
Title:
Voluntary
Customer
Satisfaction
Surveys,
OMB
Control
No.
2090
0019,
EPA
ICR
Number
1711.04
expiring
March
31,
2003.
This
is
a
request
for
extension
of
a
currently
approved
collection.
Abstract:
EPA
uses
voluntary
surveys
to
learn
how
satisfied
EPA
customers
are
with
our
services,
and
how
we
can
improve
services,
products
and
processes.
EPA
surveys
individuals
who
use
services
or
could
have.
During
the
next
three
years,
EPA
plans
up
to
185
surveys,
and
will
use
results
to
target/
measure
service
delivery
improvements.
By
seeking
renewal
of
the
generic
clearance
for
customer
surveys,
EPA
will
have
the
flexibility
to
gather
the
views
of
our
customers
to
better
determine
the
extent
to
which
our
services,
products
and
processes
satisfy
their
needs
or
need
to
be
improved.
The
generic
clearance
will
speed
the
review
and
approval
of
customer
surveys
that
solicit
opinions
from
EPA
customers
on
a
voluntary
basis,
and
do
not
involve
``
fact
finding''
for
the
purposes
of
regulatory
development
or
enforcement.
An
Agency
may
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
has
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
The
Federal
Register
document
required
under
5
CFR
1320.8(
d),
soliciting
comments
on
this
information
collection
was
published
July
26,
2002
(
FR
67
48893);
no
comments
were
received.
Burden
Statement:
The
annual
public
reporting
and
record
keeping
burden
for
this
collection
of
information
is
estimated
to
average
5
minutes
to
2
hours
per
response.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
Respondents/
Affected
Entities:
Individuals
or
households.
Estimated
Number
of
Respondents:
58,827.
Frequency
of
Response:
On
occasion.
Estimated
Total
Annual
Hour
Burden:
2,966.
Estimated
Total
Annualized
Capital,
O&
M
Cost
Burden:
0.
Send
comments
on
the
Agency's
need
for
this
information,
the
accuracy
of
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
use
of
automated
collection
techniques,
to
the
following
addresses.
Please
refer
to
EPA
ICR
No.
1711.04
and
OMB
Control
No.
2090
0019
in
any
correspondence.
Dated:
December
10,
2002.
Oscar
Morales,
Director,
Collection
Strategies
Division.
[
FR
Doc.
02
32395
Filed
12
23
02;
8:
45
am]
BILLING
CODE
6560
50
P
ENVIRONMENTAL
PROTECTION
AGENCY
[
FRL
7426
9]
Agency
Information
Collection
Activities:
Submission
for
OMB
Review;
Comment
Request;
Emergency
Planning
and
Release
Notification
Requirements
Under
Emergency
Planning
and
Community
Right
to
Know
Act
Sections
302,
303,
and
304
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Notice.
SUMMARY:
In
compliance
with
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.),
this
document
announces
that
the
following
Information
Collection
Request
(
ICR)
has
been
forwarded
to
the
Office
of
Management
and
Budget
(
OMB)
for
review
and
approval:
Emergency
Planning
and
Release
Notification
Requirements
under
Emergency
Planning
and
Community
Right
to
Know
Act
Sections
302,
303,
and
304,
OMB
Control
Number
2050
0092,
expiring
January
31,
2003.
The
ICR
describes
the
nature
of
the
information
collection
and
its
expected
burden
and
cost;
where
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| epa | 2024-06-07T20:31:41.050041 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OECA-2002-0005-0003/content.txt"
} |
EPA-HQ-OECA-2002-0006-0003 | Notice | "2002-12-24T05:00:00" | Agency Information Collection Activities: Submission of EPA ICR No. 1130.07 (OMB No. 2060-0082) to OMB for
review and Approval; Comment Request
| 78457
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Notices
for
Enforcement
Analysis
(
IDEA)
database.
Dated:
December
10,
2002.
Oscar
Morales,
Director,
Collection
Strategies
Division.
[
FR
Doc.
02
32397
Filed
12
23
02;
8:
45
am]
BILLING
CODE
6560
50
P
ENVIRONMENTAL
PROTECTION
AGENCY
[
OECA
2002
0006;
FRL
7427
2]
Agency
Information
Collection
Activities:
Submission
of
EPA
ICR
No.
1130.07
(
OMB
No.
2060
0082)
to
OMB
for
Review
and
Approval;
Comment
Request
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Notice.
SUMMARY:
In
compliance
with
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.),
this
document
announces
that
the
following
Information
Collection
Request
(
ICR)
has
been
forwarded
to
the
Office
of
Management
and
Budget
(
OMB)
for
review
and
approval:
NSPS
for
Grain
Elevators
subpart
DD,
OMB
Control
No.
2060
0082,
EPA
ICR
No.
1130.07,
expiration
date
January
31,
2003.
The
ICR,
which
is
abstracted
below
describes
the
nature
of
the
information
collection
and
its
expected
burden
and
cost.
DATES:
Additional
Comments
must
be
submitted
on
or
before
January
23,
2003.
ADDRESSES:
Follow
the
detailed
instructions
in
the
SUPPLEMENTARY
INFORMATION
section.
FOR
FURTHER
INFORMATION
CONTACT:
Kenneth
R.
Harmon,
Compliance
Assistance
and
Sector
Programs
Division,
Office
of
Compliance,
2224A,
Environmental
Protection
Agency,
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460;
telephone
number:
(
202)
564
7049;
fax
number:
(
202)
564
7083;
e
mail
address:
harmon.
kenneth
@
epa.
gov.
Refer
to
EPA
ICR
Number
1130.07.
SUPPLEMENTARY
INFORMATION:
EPA
has
submitted
the
following
ICR
to
OMB
for
review
and
approval
according
to
the
procedures
prescribed
in
5
CFR
1320.12.
On
June
20,
2002
(
67
FR
41981),
EPA
sought
comments
on
this
ICR
pursuant
to
5
CFR
1320.8(
d).
EPA
received
no
comments.
EPA
has
established
a
public
docket
for
this
ICR
under
Docket
ID
No.
OECA
2002
0006,
which
is
available
for
public
viewing
at
the
Enforcement
and
Compliance
Docket
and
Information
Center
(
EDIC)
Docket
in
the
EPA
Docket
Center
(
EPA/
DC),
EPA
West,
Room
B102,
1301
Constitution
Ave.,
NW.,
Washington,
DC.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
1744,
and
the
telephone
number
of
the
EDIC
is
(
202)
566
1514.
An
electronic
version
of
the
public
docket
is
available
through
EPA
Dockets
(
EDOCKET)
at
http://
www.
epa.
gov/
edocket.
Use
EDOCKET
to
submit
or
view
public
comments,
access
the
index
listing
of
the
contents
of
the
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,''
then
key
in
the
docket
ID
number
identified
above.
Any
comments
related
to
this
ICR
should
be
submitted
to
EPA
and
OMB
within
30
days
of
this
notice,
and
according
to
the
following
detailed
instructions:
(
1)
Submit
your
comments
to
EPA
online
using
EDOCKET
(
our
preferred
method),
by
e
mail
to
docket.
oeca@
epa.
gov,
or
by
mail
to:
EPA
Docket
Center,
Environmental
Protection
Agency,
Mailcode:
2201T,
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460,
and
(
2)
Mail
your
comments
to
OMB
at:
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget
(
OMB),
Attention:
Desk
Officer
for
EPA,
725
17th
Street,
NW.,
Washington,
DC
20503.
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
in
paper,
will
be
made
available
for
public
viewing
in
EDOCKET
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
public
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
EDOCKET.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Although
identified
as
an
item
in
the
official
docket,
information
claimed
as
CBI,
or
whose
disclosure
is
otherwise
restricted
by
statute,
is
not
included
in
the
official
public
docket,
and
will
not
be
available
for
public
viewing
in
EDOCKET.
For
further
information
about
the
electronic
docket,
see
EPA's
Federal
Register
notice
describing
the
electronic
docket
at
67
FR
38102
(
May
31,
2002),
or
go
to
http://
www.
epa.
gov./
edocket.
Title:
NSPS
Grain
Elevators
subpart
DD
(
OMB
Control
No.
2060
0082;
EPA
ICR
No.
1130.07).
This
is
a
request
to
renew
a
collection
that
is
scheduled
to
expire
on
January
31,
2003.
Under
the
Paperwork
Reduction
Act,
the
Agency
may
continue
to
conduct
or
sponsor
the
collection
of
information
while
this
submission
is
pending
at
OMB.
Abstract:
This
ICR
contains
recordkeeping
and
reporting
requirements
that
are
mandatory
for
compliance
with
40
CFR
60.300,
et
seq.,
subpart
DD,
New
Source
Performance
Standards
for
Grain
Elevators.
This
information
notifies
EPA
when
a
source
becomes
subject
to
the
regulations,
informs
the
Agency
if
a
source
is
in
compliance.
In
the
Administrator's
judgment,
particulate
matter
emissions
from
grain
elevators
cause
or
contribute
to
air
pollution
that
may
reasonably
be
anticipated
to
endanger
public
health
or
welfare.
Therefore,
NSPS
were
promulgated
for
this
source
category,
as
required
under
section
111
of
the
Clean
Air
Act.
Controlling
emissions
of
particulate
matter
from
grain
elevators
requires
not
only
the
installation
of
properly
designed
equipment,
but
also
the
operation
and
maintenance
of
that
equipment.
Particulate
emissions
from
grain
elevators
are
the
result
of
grain
drying
and
grain
handling
operations,
including
loading
and
unloading.
These
standards
rely
on
the
proper
operation
of
particulate
control
devices
such
as
baghouses
and
equipment
such
as
shed
doors
and
spouts
designed
to
reduce
particulate
emission
during
grain
unloading
and
loading.
Owners
or
operators
of
the
affected
facilities
subject
to
NSPS
subpart
DD
must
make
the
following
one
time
only
reports:
notification
of
the
date
of
construction
or
reconstruction;
notification
of
the
anticipated
and
actual
dates
of
startup;
notification
of
any
physical
or
operational
change
to
an
existing
facility
that
may
increase
the
rate
of
emission
of
the
regulated
pollutant;
notification
of
the
date
of
the
initial
performance
test;
and
the
results
of
the
initial
performance
test,
including
information
necessary
to
determine
the
conditions
of
the
performance
test
and
performance
test
measurements
and
results,
including
particulate
matter
concentration
and
opacity.
Owners
or
operators
are
also
required
to
maintain
records
of
the
occurrence
and
duration
of
any
startup,
shutdown,
or
malfunction
in
the
operation
of
an
affected
facility,
as
well
as
the
nature
and
cause
of
the
malfunction
(
if
known)
and
corrective
measures
taken.
These
notifications,
reports
and
records
are
required,
in
general,
of
all
sources
subject
to
NSPS.
Without
such
information,
enforcement
personnel
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Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Notices
would
be
unable
to
determine
if
the
standards
are
being
met.
The
required
information
consists
of
emissions
data
and
other
information
that
have
been
determined
not
to
be
private.
However,
any
information
submitted
to
the
Agency
for
which
a
claim
of
confidentiality
is
made
will
be
safeguarded
according
to
the
Agency
policies
set
forth
in
Title
40,
chapter
1,
part
2,
subpart
B
Confidentiality
of
Business
Information
(
see
40
CFR
2;
41
FR
36902,
September
1,
1976;
amended
by
43
FR
40000,
September
8,
1978;
43
FR
42251,
September
20,
1978;
44
FR
1764,
March
23,
1979).
Approximately
127
sources
are
currently
subject
to
the
standard.
EPA
estimates
that
three
additional
sources
will
become
subject
to
the
standard
in
each
of
the
next
three
years.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Burden
Statement:
The
annual
public
reporting
and
recordkeeping
burden
for
this
collection
of
information
is
estimated
to
average
2
hours
per
response.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
Respondents/
Affected
Entities:
Entities
potentially
affected
by
this
action
are
each
truck
unloading
station,
truck
loading
station,
barge
and
ship
unloading
station,
barge
and
ship
loading
station,
railcar
loading
station,
railcar
unloading
station,
grain
dryer,
and
all
grain
handling
operations
at
any
grain
terminal
elevator
or
any
grain
storage
elevator
subject
to
NSPS
subpart
DD.
Estimated
Number
of
Respondents:
132.
Frequency
of
Response:
155
annually.
Estimated
Total
Annual
Hour
Burden:
259.
Estimated
Total
Annual
Cost:
$
14,811.
Changes
in
the
Estimates:
There
is
an
increase
of
9
hours
in
the
total
estimated
burden
currently
identified
in
the
OMB
Inventory
of
Approved
ICR
Burdens.
This
slight
increase
in
burden
results
from
the
slight
growth
in
the
number
of
regulated
grain
elevators.
Dated:
December
10,
2002.
Oscar
Morales,
Director,
Collection
Strategies
Division.
[
FR
Doc.
02
32398
Filed
12
23
02;
8:
45
am]
BILLING
CODE
6560
50
P
ENVIRONMENTAL
PROTECTION
AGENCY
[
OECA
2002
0007;
FRL
7427
3]
Agency
Information
Collection
Activities;
Submission
of
EPA
ICR
No.
1167.07
(
OMB
No.
2060
0063)
to
OMB
for
Review
and
Approval;
Comment
Request
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Notice.
SUMMARY:
In
compliance
with
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.),
this
document
announces
that
the
following
Information
Collection
Request
(
ICR)
has
been
forwarded
to
the
Office
of
Management
and
Budget
(
OMB)
for
review
and
approval:
NSPS
for
Lime
Manufacturing,
(
OMB
Control
No.
2060
0063,
EPA
ICR
No.
1167.07).
The
ICR,
which
is
abstracted
below,
describes
the
nature
of
the
information
collection
and
its
estimated
burden
and
cost.
DATES:
Additional
comments
may
be
submitted
on
or
before
January
23,
2003.
ADDRESSES:
Follow
the
detailed
instructions
in
the
SUPPLEMENTARY
INFORMATION
section.
FOR
FURTHER
INFORMATION
CONTACT:
Gregory
Fried,
Compliance
Assessment
and
Media
Programs
Division,
Office
of
Compliance,
mail
code
2223A,
Environmental
Protection
Agency,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460;
telephone
number
(
202)
564
7016,
fax
number:
(
202)
564
0050;
e
mail
address:
fried.
gregory@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
EPA
has
submitted
the
following
ICR
to
OMB
for
review
and
approval
according
to
the
procedures
prescribed
in
5
CFR
1320.12.
On
June
20,
2002
(
67
FR
41981),
EPA
sought
comments
on
this
ICR
pursuant
to
5
CFR
1320.8(
d).
EPA
received
no
comments.
EPA
has
established
a
public
docket
for
this
ICR
under
Docket
ID
No.
OECA
2002
0007,
which
is
available
for
public
viewing
at
the
Enforcement
and
Compliance
Docket
and
Information
Center
(
ECDIC)
Docket
in
the
EPA
Docket
Center
(
EPA/
DC),
EPA
West,
Room
B102,
1301
Constitution
Avenue,
NW.,
Washington,
DC.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
1744,
and
the
telephone
number
for
the
Enforcement
and
Compliance
Docket
and
Information
Center
(
ECDIC)
is
(
202)
566
1514.
An
electronic
version
of
the
public
docket
is
available
through
EPA
Dockets
(
DOCKET)
at
http://
www.
epa.
gov/
edocket.
Use
DOCKET
to
submit
or
view
public
comments,
access
the
index
listing
of
the
contents
of
the
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,''
then
key
in
the
docket
ID
number
identified
above.
Any
comments
related
to
this
ICR
should
be
submitted
to
EPA
and
OMB
within
30
days
of
this
notice,
and
according
to
the
following
detailed
instructions:
(
1)
Submit
your
comments
to
EPA
online
using
DOCKET
(
our
preferred
method),
by
e
mail
to
oeca@
epa.
gov,
or
by
mail
to:
EPA
Docket
Center,
Environmental
Protection
Agency,
Mailcode:
2201T,
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460,
and
(
2)
Mail
your
comments
to
OMB
at:
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget
(
OMB),
Attention:
Desk
Officer
for
EPA,
725
17th
Street,
NW.,
Washington,
DC
20503.
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
in
paper,
will
be
made
available
for
public
viewing
in
DOCKET
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
public
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
DOCKET.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Although
identified
as
an
item
in
the
official
docket,
information
claimed
as
CBI,
or
whose
disclosure
is
otherwise
restricted
by
statute,
is
not
included
in
the
official
public
docket,
and
will
not
be
available
for
public
viewing
in
DOCKET.
For
further
information
about
the
electronic
docket,
see
EPA's
Federal
VerDate
0ct<
31>
2002
19:
49
Dec
23,
2002
Jkt
200001
PO
00000
Frm
00049
Fmt
4703
Sfmt
4703
E:\
FR\
FM\
24DEN1.
SGM
24DEN1
| epa | 2024-06-07T20:31:41.067817 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OECA-2002-0006-0003/content.txt"
} |
EPA-HQ-OECA-2002-0007-0003 | Notice | "2002-12-24T05:00:00" | Agency Information Collection Activities; Submission of EPA ICR No. 1167.07 (OMB No. 2060-0063) to OMB for
Review and Approval; Comment Request
| 78458
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Notices
would
be
unable
to
determine
if
the
standards
are
being
met.
The
required
information
consists
of
emissions
data
and
other
information
that
have
been
determined
not
to
be
private.
However,
any
information
submitted
to
the
Agency
for
which
a
claim
of
confidentiality
is
made
will
be
safeguarded
according
to
the
Agency
policies
set
forth
in
Title
40,
chapter
1,
part
2,
subpart
B
Confidentiality
of
Business
Information
(
see
40
CFR
2;
41
FR
36902,
September
1,
1976;
amended
by
43
FR
40000,
September
8,
1978;
43
FR
42251,
September
20,
1978;
44
FR
1764,
March
23,
1979).
Approximately
127
sources
are
currently
subject
to
the
standard.
EPA
estimates
that
three
additional
sources
will
become
subject
to
the
standard
in
each
of
the
next
three
years.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15.
Burden
Statement:
The
annual
public
reporting
and
recordkeeping
burden
for
this
collection
of
information
is
estimated
to
average
2
hours
per
response.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
Respondents/
Affected
Entities:
Entities
potentially
affected
by
this
action
are
each
truck
unloading
station,
truck
loading
station,
barge
and
ship
unloading
station,
barge
and
ship
loading
station,
railcar
loading
station,
railcar
unloading
station,
grain
dryer,
and
all
grain
handling
operations
at
any
grain
terminal
elevator
or
any
grain
storage
elevator
subject
to
NSPS
subpart
DD.
Estimated
Number
of
Respondents:
132.
Frequency
of
Response:
155
annually.
Estimated
Total
Annual
Hour
Burden:
259.
Estimated
Total
Annual
Cost:
$
14,811.
Changes
in
the
Estimates:
There
is
an
increase
of
9
hours
in
the
total
estimated
burden
currently
identified
in
the
OMB
Inventory
of
Approved
ICR
Burdens.
This
slight
increase
in
burden
results
from
the
slight
growth
in
the
number
of
regulated
grain
elevators.
Dated:
December
10,
2002.
Oscar
Morales,
Director,
Collection
Strategies
Division.
[
FR
Doc.
02
32398
Filed
12
23
02;
8:
45
am]
BILLING
CODE
6560
50
P
ENVIRONMENTAL
PROTECTION
AGENCY
[
OECA
2002
0007;
FRL
7427
3]
Agency
Information
Collection
Activities;
Submission
of
EPA
ICR
No.
1167.07
(
OMB
No.
2060
0063)
to
OMB
for
Review
and
Approval;
Comment
Request
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Notice.
SUMMARY:
In
compliance
with
the
Paperwork
Reduction
Act
(
44
U.
S.
C.
3501
et
seq.),
this
document
announces
that
the
following
Information
Collection
Request
(
ICR)
has
been
forwarded
to
the
Office
of
Management
and
Budget
(
OMB)
for
review
and
approval:
NSPS
for
Lime
Manufacturing,
(
OMB
Control
No.
2060
0063,
EPA
ICR
No.
1167.07).
The
ICR,
which
is
abstracted
below,
describes
the
nature
of
the
information
collection
and
its
estimated
burden
and
cost.
DATES:
Additional
comments
may
be
submitted
on
or
before
January
23,
2003.
ADDRESSES:
Follow
the
detailed
instructions
in
the
SUPPLEMENTARY
INFORMATION
section.
FOR
FURTHER
INFORMATION
CONTACT:
Gregory
Fried,
Compliance
Assessment
and
Media
Programs
Division,
Office
of
Compliance,
mail
code
2223A,
Environmental
Protection
Agency,
1200
Pennsylvania
Avenue,
NW.,
Washington,
DC
20460;
telephone
number
(
202)
564
7016,
fax
number:
(
202)
564
0050;
e
mail
address:
fried.
gregory@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
EPA
has
submitted
the
following
ICR
to
OMB
for
review
and
approval
according
to
the
procedures
prescribed
in
5
CFR
1320.12.
On
June
20,
2002
(
67
FR
41981),
EPA
sought
comments
on
this
ICR
pursuant
to
5
CFR
1320.8(
d).
EPA
received
no
comments.
EPA
has
established
a
public
docket
for
this
ICR
under
Docket
ID
No.
OECA
2002
0007,
which
is
available
for
public
viewing
at
the
Enforcement
and
Compliance
Docket
and
Information
Center
(
ECDIC)
Docket
in
the
EPA
Docket
Center
(
EPA/
DC),
EPA
West,
Room
B102,
1301
Constitution
Avenue,
NW.,
Washington,
DC.
The
EPA
Docket
Center
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Reading
Room
is
(
202)
566
1744,
and
the
telephone
number
for
the
Enforcement
and
Compliance
Docket
and
Information
Center
(
ECDIC)
is
(
202)
566
1514.
An
electronic
version
of
the
public
docket
is
available
through
EPA
Dockets
(
DOCKET)
at
http://
www.
epa.
gov/
edocket.
Use
DOCKET
to
submit
or
view
public
comments,
access
the
index
listing
of
the
contents
of
the
public
docket,
and
to
access
those
documents
in
the
public
docket
that
are
available
electronically.
Once
in
the
system,
select
``
search,''
then
key
in
the
docket
ID
number
identified
above.
Any
comments
related
to
this
ICR
should
be
submitted
to
EPA
and
OMB
within
30
days
of
this
notice,
and
according
to
the
following
detailed
instructions:
(
1)
Submit
your
comments
to
EPA
online
using
DOCKET
(
our
preferred
method),
by
e
mail
to
oeca@
epa.
gov,
or
by
mail
to:
EPA
Docket
Center,
Environmental
Protection
Agency,
Mailcode:
2201T,
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460,
and
(
2)
Mail
your
comments
to
OMB
at:
Office
of
Information
and
Regulatory
Affairs,
Office
of
Management
and
Budget
(
OMB),
Attention:
Desk
Officer
for
EPA,
725
17th
Street,
NW.,
Washington,
DC
20503.
EPA's
policy
is
that
public
comments,
whether
submitted
electronically
or
in
paper,
will
be
made
available
for
public
viewing
in
DOCKET
as
EPA
receives
them
and
without
change,
unless
the
comment
contains
copyrighted
material,
CBI,
or
other
information
whose
public
disclosure
is
restricted
by
statute.
When
EPA
identifies
a
comment
containing
copyrighted
material,
EPA
will
provide
a
reference
to
that
material
in
the
version
of
the
comment
that
is
placed
in
DOCKET.
The
entire
printed
comment,
including
the
copyrighted
material,
will
be
available
in
the
public
docket.
Although
identified
as
an
item
in
the
official
docket,
information
claimed
as
CBI,
or
whose
disclosure
is
otherwise
restricted
by
statute,
is
not
included
in
the
official
public
docket,
and
will
not
be
available
for
public
viewing
in
DOCKET.
For
further
information
about
the
electronic
docket,
see
EPA's
Federal
VerDate
0ct<
31>
2002
19:
49
Dec
23,
2002
Jkt
200001
PO
00000
Frm
00049
Fmt
4703
Sfmt
4703
E:\
FR\
FM\
24DEN1.
SGM
24DEN1
78459
Federal
Register
/
Vol.
67,
No.
247
/
Tuesday,
December
24,
2002
/
Notices
Register
notice
describing
the
electronic
docket
at
67
FR
38102
(
May
31,
2002),
or
go
to
http://
www.
epa.
gov./
edocket.
Title:
NSPS
for
Lime
Manufacturing
(
40
CFR
part
60,
subpart
HH)
(
OMB
Control
No.
2060
0063,
EPA
ICR
Number
1167.07).
This
is
a
request
to
renew
an
existing
approved
collection
that
is
scheduled
to
expire
on
January
31,
2003.
Under
the
OMB
regulations,
the
Agency
may
continue
to
conduct
or
sponsor
the
collection
of
information
while
this
submission
is
pending
at
OMB.
Abstract:
The
New
Source
Performance
Standards
(
NSPS)
for
Lime
Manufacturing
Plants
were
proposed
on
May
3,
1977
and
promulgated
on
April
26,
1984.
These
standards
apply
to
each
rotary
lime
kiln
used
in
lime
manufacturing,
which
commenced
construction,
modification
or
reconstruction
after
May
3,
1977.
The
standards
do
not
apply
to
facilities
used
in
the
manufacture
of
lime
at
kraft
pulp
mills.
The
purpose
of
this
NSPS
is
to
control
the
emissions
of
particulate
matter
(
PM)
from
lime
manufacturing
plants,
specifically
from
the
operation
of
the
rotary
lime
kilns.
The
standards
limit
particulate
emissions
to
0.30
kilogram
per
megagram
(
0.60
lb/
ton)
of
stone
feed,
and
limit
opacity
to
15%
when
exiting
from
a
dry
emission
control
device.
This
information
is
being
collected
to
assure
compliance
with
40
CFR
part
60,
subpart
HH.
There
are
three
types
of
reporting
requirements
for
owners
or
operators
of
facilities
under
this
NSPS:
(
1)
Notifications
(
e.
g.,
notice
for
new
construction
or
reconstruction,
anticipated
and
actual
startup
dates,
initial
performance
test,
and
demonstration
of
the
CMS);
(
2)
a
report
on
the
results
of
the
performance
test;
and
(
3)
semiannual
reports
of
instances
of
occurrence
and
duration
of
any
startup,
shutdown,
or
malfunctions.
The
purpose
of
the
notifications
are
to
inform
the
Agency
or
delegated
authority
when
a
source
becomes
subject
to
this
standard.
Performance
tests
are
conducted
to
ensure
that
the
new
plants
operate
within
the
boundaries
outlined
in
the
standard.
The
semiannual
reports
are
used
for
problem
identification,
as
a
check
on
source
operation
and
maintenance,
and
for
compliance
determinations.
Under
this
standard
the
data
collected
by
the
affected
industry
is
retained
at
the
facility
for
a
minimum
of
two
years
and
made
available
for
inspection
by
the
Administrator.
The
Administrator
has
judged
that
PM
emissions
from
lime
manufacturing
plants
cause
or
contribute
to
air
pollution
that
may
reasonably
be
anticipated
to
endanger
public
health
or
welfare.
Owners/
operators
of
lime
manufacturing
plants
must
notify
EPA
of
construction,
modification,
startups,
shutdowns,
malfunctions
and
performance
test
dates,
as
well
as
provide
reports
on
the
initial
performance
test
and
annual
excess
emissions.
The
industry
costs
associated
with
the
information
collection
activity
in
the
standards
are
capital
costs
and
O&
M
costs
associated
with
continuous
emissions
monitoring
and
labor
costs
associated
with
recordkeeping
and
reporting.
In
order
to
ensure
compliance
with
the
standards
promulgated
to
protect
public
health,
adequate
reporting
and
recordkeeping
is
necessary.
In
the
absence
of
such
information,
enforcement
personnel
would
be
unable
to
determine
whether
the
standards
are
being
met
on
a
continuous
basis,
as
required
by
the
Clean
Air
Act.
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to,
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
are
listed
in
40
CFR
part
9
and
48
CFR
chapter
15,
and
are
identified
on
the
form
and/
or
instrument,
if
applicable.
Burden
Statement:
The
annual
public
reporting
and
recordkeeping
burden
for
this
collection
of
information
is
estimated
to
average
42
hours
per
response.
Burden
means
the
total
time,
effort,
or
financial
resources
expended
by
persons
to
generate,
maintain,
retain,
or
disclose
or
provide
information
to
or
for
a
Federal
agency.
This
includes
the
time
needed
to
review
instructions;
develop,
acquire,
install,
and
utilize
technology
and
systems
for
the
purposes
of
collecting,
validating,
and
verifying
information,
processing
and
maintaining
information,
and
disclosing
and
providing
information;
adjust
the
existing
ways
to
comply
with
any
previously
applicable
instructions
and
requirements;
train
personnel
to
be
able
to
respond
to
a
collection
of
information;
search
data
sources;
complete
and
review
the
collection
of
information;
and
transmit
or
otherwise
disclose
the
information.
Respondents/
Affected
Entities:
Lime
Manufacturing
Plants.
Estimated
Number
of
Respondents:
53.
Frequency
of
Response:
On
occasion,
initial,
and
semiannual.
Estimated
Total
Annual
Hour
Burden:
4,434
hours.
Estimated
Total
Annual
Cost:
$
91,500.
Changes
in
the
Estimates:
There
is
an
increase
of
244
hours
in
the
total
estimated
burden
currently
identified
in
the
OMB
Inventory
of
Approved
ICR
Burdens.
This
increase
is
due
to
an
increase
in
the
number
of
existing
facilities
subject
to
this
standard
resulting
from
the
availability
of
more
accurate
data.
Dated:
December
10,
2002.
Oscar
Morales,
Director,
Collection
Strategies
Division.
[
FR
Doc.
02
32399
Filed
12
23
02;
8:
45
am]
BILLING
CODE
6560
50
P
ENVIRONMENTAL
PROTECTION
AGENCY
[
OPP
2002
0283;
FRL
7277
5]
Bronopol;
Notice
of
Filing
a
Pesticide
Petition
to
Establish
a
Tolerance
for
a
Certain
Pesticide
Chemical
in
or
on
Food
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Notice.
SUMMARY:
This
notice
announces
the
initial
filing
of
a
pesticide
petition
proposing
the
establishment
of
regulations
for
residues
of
a
certain
pesticide
chemical
in
or
on
various
food
commodities.
DATES:
Comments,
identified
by
docket
ID
number
OPP
2002
0283,
must
be
received
on
or
before
January
23,
2003.
ADDRESSES:
Comments
may
be
submitted
electronically,
by
mail,
or
through
hand
delivery/
courier.
Follow
the
detailed
instructions
as
provided
in
Unit
I.
of
the
SUPPLEMENTARY
INFORMATION.
FOR
FURTHER
INFORMATION
CONTACT:
Bipin
Gandhi,
Registration
Division
(
7505C),
Office
of
Pesticide
Programs,
Environmental
Protection
Agency,
1200
Pennsylvania
Ave.,
NW.,
Washington,
DC
20460
0001;
telephone
number:
(
703)
308
8380;
e
mail
address:
gandhi.
bipin@
epa.
gov.
SUPPLEMENTARY
INFORMATION:
I.
General
Information
A.
Does
this
Action
Apply
to
Me?
You
may
be
potentially
affected
by
this
action
if
you
are
an
agricultural
producer,
food
manufacturer,
pesticide
manufacturer,
or
antimicrobial
pesticide
manufacturer.
Potentially
affected
entities
may
include,
but
are
not
limited
to:
Industry
(
NAICS
111),
e.
g.,
Crop
production.
Industry
(
NAICS
112),
e.
g.,
Animal
production.
Industry
(
NAICS
311),
e.
g.,
Food
manufacturing.
VerDate
0ct<
31>
2002
19:
49
Dec
23,
2002
Jkt
200001
PO
00000
Frm
00050
Fmt
4703
Sfmt
4703
E:\
FR\
FM\
24DEN1.
SGM
24DEN1
| epa | 2024-06-07T20:31:41.073061 | regulations | {
"license": "Public Domain",
"url": "https://downloads.regulations.gov/EPA-HQ-OECA-2002-0007-0003/content.txt"
} |