Document ID: EPA-HQ-OAR-2003-0012-1027
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2004-05-11T04:00Z

1
The
EPA
Administrator
signed
the
following
final
rule
on
May
11,
2004.
It
is
being
submitted
for
publication
in
the
Federal
Register.
While
EPA
has
taken
steps
to
ensure
the
accuracy
of
this
Internet
version,
it
is
not
the
official
version
of
the
rule.
Please
refer
to
the
official
version
in
a
forthcoming
Federal
Register
publication
and
on
GPO's
Web
Site.
The
rule
will
likely
be
published
in
the
Federal
Register
around
the
end
of
May
2004.
You
can
access
the
Federal
Register
at:
http://
www.
access.
gpo.
gov/
su_
docs/
aces/
aces140.
html.
When
using
this
site,
note
that
"
text"
files
may
be
incomplete
because
they
don't
include
graphics.
Instead,
select
"
Adobe
Portable
Document
File"
(
PDF)
files.

ENVIRONMENTAL
PROTECTION
AGENCY
40
CFR
Parts
9,
69,
80,
89,
94,
1039,
1048,
1051,
1065,
and
1068
[
OAR­
2003­
0012;
FRL­
XXXX­
X]
RIN
2060­
AK27
Control
of
Emissions
of
Air
Pollution
from
Nonroad
Diesel
Engines
and
Fuel
AGENCY:
Environmental
Protection
Agency
(
EPA).
ACTION:
Final
Rule.
SUMMARY:
Nonroad
diesel
engines
contribute
considerably
to
our
nation's
air
pollution.
These
engines,
used
primarily
in
construction,
agricultural,
and
industrial
applications,
are
projected
to
continue
to
contribute
large
amounts
of
particulate
matter,
nitrogen
oxides,
and
sulfur
oxides,
all
of
which
contribute
to
serious
public
health
problems
in
the
United
States.
These
problems
include
premature
mortality,
aggravation
of
respiratory
and
cardiovascular
disease,
aggravation
of
existing
asthma,
acute
respiratory
symptoms,
chronic
bronchitis,
and
decreased
lung
function.
We
believe
that
diesel
exhaust
is
likely
to
be
carcinogenic
to
humans
by
inhalation.

Today,
EPA
is
adopting
new
emission
standards
for
nonroad
diesel
engines
and
sulfur
reductions
in
nonroad
diesel
fuel
that
will
dramatically
reduce
harmful
emissions
and
will
directly
help
States
and
local
areas
recently
designated
as
8­
hour
ozone
nonattainment
areas
to
improve
their
air
quality.
This
comprehensive
national
program
regulates
nonroad
diesel
engines
and
diesel
fuel
as
a
system.
New
engine
standards
will
begin
to
take
effect
in
the
2008
model
year,
phasing
in
over
a
number
of
years.
These
standards
are
based
on
the
use
of
advanced
exhaust
emission
control
devices.
We
estimate
particulate
matter
reductions
of
95
percent,
nitrogen
oxides
reductions
of
90
percent,
and
the
virtual
elimination
of
sulfur
oxides
from
nonroad
engines
meeting
the
new
standards.
Nonroad
diesel
fuel
sulfur
reductions
of
more
than
99
percent
from
existing
levels
will
provide
significant
health
benefits
as
well
as
facilitate
the
introduction
of
highefficiency
catalytic
exhaust
emission
control
devices
as
these
devices
are
damaged
by
sulfur.
These
fuel
controls
will
be
phased­
in
starting
in
mid­
2007.
Today's
nonroad
final
rule
is
largely
based
on
the
Environmental
Protection
Agency's
2007
highway
diesel
program.

To
better
ensure
the
benefits
of
the
standards
are
realized
in­
use
and
throughout
the
useful
life
of
these
engines,
we
are
also
adopting
new
test
procedures,
including
not­
to­
exceed
requirements,
and
related
certification
requirements.
The
rule
also
includes
provisions
to
facilitate
the
transition
to
the
new
engine
and
fuel
standards
and
to
encourage
the
early
introduction
of
2
clean
technologies
and
clean
nonroad
diesel
fuel.
We
have
also
developed
provisions
for
both
the
engine
and
fuel
programs
designed
to
address
small
business
considerations.

The
requirements
in
this
rule
will
result
in
substantial
benefits
to
public
health
and
welfare
through
significant
reductions
in
emissions
of
nitrogen
oxides
and
particulate
matter,
as
well
as
nonmethane
hydrocarbons,
carbon
monoxide,
sulfur
oxides,
and
air
toxics.
We
are
now
projecting
that
by
2030,
this
program
will
reduce
annual
emissions
of
nitrogen
oxides
and
particulate
matter
by
738,000
and
129,000
tons,
respectively.
These
emission
reductions
will
prevent
12,000
premature
deaths,
over
8,900
hospitalizations,
and
almost
a
million
work
days
lost,
and
will
achieve
other
quantifiable
benefits
every
year.
The
total
benefits
of
this
rule
will
be
approximately
$
80
billion
annually
by
2030.
The
substantial
health
and
welfare
benefits
we
are
projecting
for
this
final
action
exceed
those
we
anticipated
at
the
time
of
this
proposal.
Costs
for
both
the
engine
and
fuel
requirements
will
be
many
times
less,
at
approximately
$
2
billion
annually.

DATES:
This
final
rule
is
effective
on
[
insert
date
60
days
after
publication
in
the
Federal
Register].

The
incorporation
by
reference
of
certain
publications
listed
in
this
regulation
is
approved
by
the
Director
of
the
Federal
Register
as
of
[
insert
date
60
days
after
publication
in
the
Federal
Register].

ADDRESSES:
EPA
has
established
a
docket
for
this
action
under
Docket
ID
Nos.
OAR­
2003­
0012
and
A­
2001­
28.
All
documents
in
the
docket
are
listed
in
the
EDOCKET
index
at
http://
www.
epa.
gov/
edocket.
Although
listed
in
the
index,
some
information
is
not
publicly
available,
i.
e.,
CBI
or
other
information
whose
disclosure
is
restricted
by
statute.
Certain
other
material,
such
as
copyrighted
material,
is
not
placed
on
the
Internet
and
will
be
publicly
available
only
in
hard
copy
form.
Publicly
available
docket
materials
are
available
either
electronically
in
EDOCKET
or
in
hard
copy
at
the
Air
Docket
in
the
EPA
Docket
Center,
EPA/
DC,
EPA
West,
Room
B102,
1301
Constitution
Ave.,
NW,
Washington,
DC.
The
Public
Reading
Room
is
open
from
8:
30
a.
m.
to
4:
30
p.
m.,
Monday
through
Friday,
excluding
legal
holidays.
The
telephone
number
for
the
Public
Reading
Room
is
(
202)
566­
1744,
and
the
telephone
number
for
the
Air
Docket
is
(
202)
566­
1742.

FOR
FURTHER
INFORMATION
CONTACT:
Carol
Connell,
Assessment
and
Standards
Division,
Office
of
Transportation
and
Air
Quality,
Environmental
Protection
Agency,
2000
Traverwood
Drive,
Ann
Arbor,
MI
48105;
telephone
number:
(
734)
214­
4349;
fax
number:
(
734)
214­
4050;
e­
mail
address:
connell.
carol@
epa.
gov,
or
Assessment
and
Standards
Division
Hotline;
telephone
number:
(
734)
214­
4636;
e­
mail
address:
asdinfo@
epa.
gov.

SUPPLEMENTARY
INFORMATION:
Does
this
action
apply
to
me?
3
This
action
may
affect
you
if
you
produce
or
import
new
diesel
engines
which
are
intended
for
use
in
nonroad
vehicles
or
equipment,
such
as
agricultural
and
construction
equipment,
or
if
you
produce
or
import
such
nonroad
vehicles
or
equipment.
It
may
also
affect
you
if
you
convert
nonroad
vehicles
or
equipment,
or
the
engines
used
in
them,
to
use
alternative
fuels.
It
may
also
affect
you
if
you
produce,
import,
distribute,
or
sell
nonroad
diesel
fuel.

The
following
table
gives
some
examples
of
entities
that
may
have
to
follow
the
regulations.
But
because
these
are
only
examples,
you
should
carefully
examine
the
regulations
in
40
CFR
parts
80,
89,
1039,
1065,
and
1068.
If
you
have
questions,
call
the
person
listed
in
the
FOR
FURTHER
INFORMATION
CONTACT
section
of
this
preamble:

Category
NAICS
codesa
SIC
codesb
Examples
of
potentially
regulated
entities
Industry.....
333618
3519
Manufacturers
of
new
nonroad
diesel
engines
Industry.....
333111
3523
Manufacturers
of
farm
machinery
and
equipment
Industry.....
333112
3524
Manufacturers
of
lawn
and
garden
tractors
(
home)

Industry.....
333924
3537
Manufacturers
of
industrial
trucks
Industry.....
333120
3531
Manufacturers
of
construction
machinery
Industry.....
333131
3532
Manufacturers
of
mining
machinery
and
equipment
Industry.....
333132
3533
Manufacturers
of
oil
and
gas
field
machinery
and
equipment
Industry.....
811112
811198
7533
7549
Commercial
importers
of
vehicles
and
vehicle
components
Industry.....
324110
2911
Petroleum
refiners
Industry.....
422710
422720
5171
5172
Diesel
fuel
marketers
and
distributors
Industry.....
484220
484230
4212
4213
Diesel
fuel
carriers
Notes:
a
North
American
Industry
Classification
System
(
NAICS).
b
Standard
Industrial
Classification
(
SIC)
system
code.

How
Can
I
Get
Copies
of
This
Document
and
Other
Related
Information?
Docket.
EPA
has
established
an
official
public
docket
for
this
action
under
Docket
ID
No.
OAR­
2003­
0012
at
http://
www.
epa.
gov/
edocket.
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
4
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
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
1742,
and
the
telephone
number
for
the
Air
Docket
is
(
202)
566­
1742.

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
above.
Once
in
the
system,
select
"
search,"
then
key
in
the
appropriate
docket
identification
number.

Outline
of
This
Preamble
I.
Overview
A.
What
is
EPA
Finalizing?
B.
Why
Is
EPA
Taking
this
Action?

II.
Nonroad
Engine
Standards
A.
What
Are
the
New
Engine
Standards?
B.
Are
the
New
Standards
Feasible?
C.
Why
Do
We
Need
15ppm
Sulfur
Diesel
Fuel?

III.
Requirements
for
Engine
and
Equipment
Manufacturers
A.
Averaging,
Banking,
and
Trading
B.
Transition
Provisions
for
Equipment
Manufacturers
C.
Engine
and
Equipment
Small
Business
Provisions
(
SBREFA)
D.
Certification
Fuel
E.
Temporary
In­
Use
Compliance
Margins
F.
Test
Cycles
G.
Other
Test
Procedure
Issues
H.
Engine
Power
I.
Auxiliary
Emission
Control
Devices
and
Defeat
Devices
J.
Not­
To­
Exceed
Requirements
K.
Investigating
and
Reporting
Emission­
Related
Defects
L.
Compliance
with
the
Phase­
In
Provisions
5
M.
Incentive
Program
for
Early
or
Very
Low
Emission
Engines
N.
Labeling
and
Notification
Requirements
O.
General
Compliance
P.
Other
Issues
Q.
Highway
Engines
R.
Changes
That
Affect
Other
Engine
Categories
IV.
Our
Program
for
Controlling
Nonroad,
Locomotive
and
Marine
Diesel
Fuel
Sulfur
A.
Nonroad,
Locomotive
and
Marine
Diesel
Fuel
Quality
Standards
B.
Hardship
Relief
Provisions
for
Qualifying
Refiners
C.
Special
Provisions
for
Alaska
and
the
Territories
D.
NRLM
Diesel
Fuel
Program
Design
E.
How
Are
State
Diesel
Fuel
Programs
Affected
by
the
Sulfur
Diesel
Program?
F.
Technological
Feasibility
of
the
500
and
15
ppm
Sulfur
Diesel
Fuel
Program
G.
What
Are
the
Potential
Impacts
of
the
15
ppm
Sulfur
Diesel
Program
on
Lubricity
and
Other
Fuel
Properties?
H.
Refinery
Air
Permitting
V.
Nonroad,
Locomotive
and
Marine
Diesel
Fuel
Program:
Details
of
the
Compliance
and
Enforcement
Provisions
A.
Special
Fuel
Provisions
and
Exemptions
B.
Additional
Requirements
for
Refiners
and
Importers
C.
Requirements
for
Parties
Downstream
of
the
Refinery
or
Import
Facility
D.
Diesel
Fuel
Sulfur
Sampling
and
Testing
Requirements
E.
Selection
of
the
Marker
for
Heating
Oil
F.
Fuel
Marker
Test
Method
G.
Requirements
for
Record­
keeping,
Reporting,
and
PTDs
H.
Liability
and
Penalty
Provisions
for
Noncompliance
I.
How
Will
Compliance
with
the
Sulfur
Standards
Be
Determined?

VI.
Program
Costs
and
Benefits
A.
Refining
and
Distribution
Costs
B.
Cost
Savings
to
the
Existing
Fleet
from
the
Use
of
Low
Sulfur
Fuel
C.
Engine
and
Equipment
Cost
Impacts
D.
Annual
Costs
and
Cost
Per
Ton
E.
Do
the
Benefits
Outweigh
the
Costs
of
the
Standards?
F.
Economic
Impact
Analysis
VII.
Alternative
Program
Options
Considered
A.
Summary
of
Alternatives
B.
Introduction
of
15
ppm
Nonroad
Diesel
Sulfur
Fuel
in
One
Step
C.
Applying
the
15
ppm
Sulfur
Cap
to
Locomotive
and
Marine
Diesel
Fuel
D.
Other
Alternatives
6
VIII.
Future
Plans
A.
Technology
Review
B.
Test
Procedure
Issues
C.
In­
use
Testing
D.
Engine
Diagnostics
E.
Future
NO
X
Standards
for
Engines
in
Mobile
Machinery
Over
750
hp
F.
Emission
Standards
for
Locomotive
and
Marine
Diesel
Engines
G.
Retrofit
Programs
H.
Reassess
the
Marker
Specified
for
Heating
Oil
IX.
Public
Participation
X.
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
USC
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
Advancement
Act
J.
Congressional
Review
Act
XI.
Statutory
Provisions
and
Legal
Authority
7
I.
Overview
EPA
today
is
completing
the
third
recent
major
program
to
reduce
emissions
from
the
nation's
mobile
sources.
Today's
final
rule
establishes
standards
for
nonroad
diesel
engines
and
fuel
and
builds
on
the
recently
adopted
Tier
2
program
for
cars
and
light
trucks
and
the
2007
highway
diesel
program
for
on­
highway
diesel
engines.
These
three
programs
have
in
common
large
reductions
in
sulfur
levels
in
fuel
that
will
not
only
achieve
public
health
benefits
but
also
facilitate
the
introduction
of
advanced
emissions
control
technologies.
In
1996,
emissions
from
land­
based
nonroad,
marine,
and
locomotive
diesel
engines
were
estimated
to
be
about
40
percent
of
the
total
mobile
source
inventory
of
PM
2.5
(
particulate
matter
less
than
2.5
microns
in
diameter)
and
25
percent
of
the
NO
X
(
nitrogen
oxides)
inventory.
Without
today's
final
rule,
these
contributions
would
be
expected
to
grow
to
44
percent
and
47
percent
by
2030
for
PM
2.5
and
NO
X,
respectively.
By
themselves,
land­
based
nonroad
diesel
engines
are
a
very
large
part
of
the
diesel
mobile
source
PM
2.5
inventory,
contributing
about
47
percent
in
1996,
and
growing
to
70
percent
of
this
inventory
by
2020
without
today's
final
rule.
In
order
to
meet
the
Clean
Air
Act's
goal
of
cleaning
up
the
nation's
air,
emissions
reductions
from
the
nonroad
sector
are
necessary.

This
program
begins
to
get
important
emission
reductions
in
2008,
and
by
2030
we
estimate
that
this
program
will
reduce
over
129,000
tons
PM
2.5
and
738,000
tons
of
NO
X
annually.
These
emission
reductions
will
be
directly
helpful
to
the
474
counties
nationwide
that
have
been
recently
designated
as
nonattainment
areas
for
the
8­
hour
ozone
standard
and
for
counties
that
will
be
designated
as
nonattainment
for
PM
2.5
later
this
year.
The
resulting
ambient
PM
2.5
and
NO
X
reductions
correspond
to
public
health
improvements
in
2030
including
approximately
12,000
fewer
premature
mortalities,
15,000
fewer
heart
attacks,
1
million
fewer
lost
days
of
work
due
to
adults
with
respiratory
symptoms,
5.9
million
fewer
days
when
adults
have
to
restrict
their
activities
due
to
respiratory
symptoms,
and
almost
6,000
emergency
room
visits
for
asthma
attacks
in
children.
Our
projections
in
this
final
rule
for
public
health
and
welfare
improvements
are
greater
than
estimated
at
proposal.

This
final
rule
sets
out
emission
standards
for
nonroad
diesel
engines
­
engines
used
mainly
in
construction,
agricultural,
industrial
and
mining
operations
­
that
will
achieve
reductions
in
PM
and
NO
X
emissions
levels
in
excess
of
95
percent
and
90
percent
respectively.
This
action
also
regulates
nonroad
diesel
fuel
for
the
first
time
by
reducing
sulfur
levels
in
this
fuel
more
than
99
percent
to
15
parts
per
million
(
ppm).
These
provisions
mirror
those
already
in
place
for
highway
diesel
engines,
which
will
lead
to
the
introduction
of
15
ppm
sulfur
diesel
fuel,
followed
by
stringent
engine
standards
in
that
sector
beginning
in
2007
based
on
advanced
aftertreatment
technologies.
We
believe
it
is
highly
appropriate
to
bring
the
same
types
of
expected
advanced
aftertreatment
technologies
to
the
nonroad
market
as
soon
as
possible
and
we
believe
today's
nonroad
fuel
and
engine
program
represents
the
next
step
in
a
feasible
progression
in
the
application
of
clean
technologies
to
nonroad
diesel
engines
and
the
associated
diesel
fuel.
8
As
we
did
with
the
proposed
nonroad
rulemaking,
we
followed
specific
principles
when
developing
this
final
rule.
First,
the
program
achieves
reductions
in
NO
X,
sulfur
oxides
(
SO
X),
and
PM
emissions
as
early
as
possible.
Second,
it
does
so
by
implementing
the
fuel
program
as
soon
as
possible
while
at
the
same
time
not
interfering
with
the
implementation
and
expected
benefits
of
introducing
ultra
low
sulfur
fuel
(
diesel
fuel
containing
no
greater
than
15
ppm
sulfur)
in
the
highway
market
as
required
by
the
2007
highway
diesel
rule.
Next,
we
are
generally
treating
vehicles
and
fuels
as
a
system,
that
is
promulgating
engine
and
fuel
standards
in
tandem
in
order
to
cost­
effectively
achieve
the
greatest
emission
reductions.
Lastly,
the
program
provides
sufficient
lead
time
to
allow
the
migration
of
advanced
emissions
control
technologies
from
the
highway
sector
to
nonroad
diesel
engines
as
well
as
the
expansion
of
ultra
low
sulfur
diesel
fuel
production
to
the
nonroad
market.

The
May
2003
proposed
rulemaking
culminated
a
multi­
year
effort
to
develop
control
strategies
for
nonroad
engines.
EPA
worked
collaboratively
with
stakeholders
from
industry,
state
and
local
government,
and
public
health
organizations
in
putting
together
its
comprehensive
(
and
widely
praised)
new
engine
standards
and
sulfur
fuel
controls.
We
received
about
150,000
comments
on
the
proposal,
almost
all
of
them
in
support.
We
held
three
public
hearings
on
the
proposal
and
have
participated
in
scores
of
meetings
with
commenters
in
developing
the
provisions
of
today's
final
rule.
An
important
aspect
of
this
collaborative
development
effort
has
been
EPA's
coordination
with
other
governments
in
helping
to
further
world
harmonization
of
nonroad
engine
controls
and
fuel
sulfur
levels.
Information
gathered
in
these
comments
and
discussions,
taken
in
context
with
the
principles
described
above,
has
been
the
basis
for
our
action
today.

In
summary,
this
rule
sets
out
engine
standards
and
emission
test
procedures
(
including
not­
to­
exceed
requirements)
for
new
nonroad
diesel
engines,
and
sulfur
control
requirements
for
diesel
fuel
used
in
land­
based
nonroad,
locomotive,
and
marine
engines
(
NRLM
fuel).
Beginning
in
2008,
the
new
Tier
4
engine
standards
for
five
power
categories
for
engines
from
under
25
horsepower
(
hp)
to
above
750
horsepower
will
be
phased
in.
New
engine
emissions
test
procedures
will
be
phased
in
along
with
these
new
standards
to
better
ensure
emissions
control
over
real­
world
engine
operation
and
to
help
provide
for
effective
compliance
determination.
The
sulfur
reductions
to
land­
based
nonroad
diesel
fuel
will
be
accomplished
in
two
steps,
with
an
interim
step
from
currently
uncontrolled
levels
to
a
500
ppm
cap
starting
in
June,
2007
and
the
final
step
to
15
ppm
in
June,
2010.
This
change
in
fuel
quality
will
directly
lead
to
important
health
and
welfare
benefits
associated
with
the
reduced
generation
of
sulfate
PM
and
SO
X.
Even
more
important,
introduction
of
15
ppm
sulfur
nonroad
diesel
fuel
facilitates
the
introduction
of
advanced
aftertreatment
devices
for
nonroad
engines.

Although
we
did
not
propose
to
control
locomotive
and
marine
diesel
fuel
sulfur
levels
to
15
ppm
in
the
NPRM,
recognizing
the
important
environmental
and
public
welfare
benefits
that
such
a
program
could
enable,
we
have
decided
to
finalize
this
second
step
to
15
ppm
sulfur
fuel
control
program
for
locomotive
and
marine
diesel
fuel
beginning
in
2012.
Locomotive
and
marine
diesel
fuel
will
first
be
reduced
from
current
uncontrolled
levels
to
a
500
ppm
cap
starting
in
June
1
EPA
is
issuing
an
Advanced
Notice
of
Proposed
Rulemaking
for
locomotive
and
marine
engine
standards
as
part
of
this
effort.

9
2007
and
the
second
step
down
to
a
15
ppm
cap
will
take
place
in
June,
2012.
While
we
have
chosen
to
reduce
sulfur
levels
in
locomotive
and
marine
diesel
fuel
to
15
ppm
in
this
rulemaking
without
adopting
corresponding
engine
controls,
we
note
that
the
Agency
has
already
begun
work
to
promulgate
appropriate
new
standards
for
these
engines.
1
The
monetized
health
and
welfare
benefits
associated
with
further
sulfur
reduction
to
15
ppm
outweigh
the
costs
of
the
sulfur
reductions.
Also,
doing
so
now
allows
for
the
promulgation
of
a
single
integrated
fuel
program
and
provides
the
refining
industry
with
long
term
predictability
for
sulfur
control.

The
requirements
in
this
rule
will
result
in
substantial
benefits
to
public
health
and
welfare
and
the
environment
through
significant
reductions
in
NO
X
and
PM
as
well
as
nonmethane
hydrocarbons
(
NMHC),
carbon
monoxide
(
CO),
SO
X,
and
air
toxics.
As
noted,
by
2030
this
program
will
reduce
annual
emissions
of
NO
X
and
PM
by
738,000
and
129,000
tons,
respectively.
We
estimate
these
annual
emission
reductions
will
prevent
12,000
premature
deaths,
over
8,900
hospitalizations,
15,000
nonfatal
heart
attacks,
and
approximately
1
million
days
that
people
miss
work
because
of
respiratory
symptoms,
among
quantifiable
benefits.
The
overall
quantifiable
benefits
will
total
$
83
billion
annually
by
2030
using
a
3
percent
discount
rate
and
$
78
billion
using
a
7
percent
discount
rate
at
a
cost
of
approximately
$
2
billion,
with
a
30­
year
net
present
value
for
the
benefits
of
$
805
billion
at
3
percent
discounting
and
$
352
billion
at
7
percent
discounting
at
a
net
present
value
cost
of
$
27
billion
at
3
percent
discounting
and
$
14
billion
at
7
percent
discounting.
Clearly
the
benefits
of
this
program
dramatically
outweigh
its
cost
at
a
ratio
of
approximately
40:
1
in
2030.

A.
What
is
EPA
Finalizing?

As
part
of
the
proposed
rulemaking,
we
set
out
very
detailed
provisions
for
new
engine
exhaust
emission
controls,
sulfur
limitations
in
nonroad
and
locomotive/
marine
diesel
fuels,
test
procedures,
compliance
requirements,
and
other
information.
We
also
looked
at
a
number
of
alternative
program
options,
such
as
requiring
refiners
to
reduce
sulfur
from
uncontrolled
levels
to
15
ppm
in
one
step
in
2008.
We
continue
to
believe
that
the
main
program
options
set
out
in
the
proposal
are
feasible
and
the
most
cost­
effective
requirements,
taking
into
account
other
factors
such
as
lead
time
and
interaction
with
the
highway
diesel
program,
so
we
are
generally
adopting
the
engine
and
fuel
provisions
which
we
proposed.

1.
Nonroad
Diesel
Engine
Emission
Standards
Today's
action
adopts
Tier
4
standards
for
nonroad
diesel
engines
of
all
horsepower
ratings.
These
standards
are
technology­
neutral
in
the
sense
that
manufacturers
are
the
responsible
party
in
determining
which
emission
control
technologies
will
be
needed
to
meet
the
requirements.
Applicable
emissions
standards
are
determined
by
model
year
for
each
of
five
engine
power
band
categories.
For
engines
less
than
25
hp,
we
are
adopting
a
new
engine
10
standard
for
PM
of
0.30
g/
bhp­
hr
(
grams
per
brake­
horsepower­
hour)
beginning
in
2008,
and
leaving
the
previously­
set
5.6
g/
bhp­
hr
combined
standard
for
NMHC+
NO
X
in
place.
For
engines
of
25
to
75
hp,
we
are
adopting
standards
reflecting
approximately
50
percent
reductions
in
PM
control
from
today's
engines,
again
applicable
beginning
in
2008.
Then,
starting
in
2013,
standards
of
0.02
g/
bhp­
hr
for
PM
and
3.5
g/
bhp­
hr
for
NMHC+
NO
X
will
apply
for
this
power
category.
For
engines
of
75
to
175
hp,
the
standards
will
be
0.01
g/
bhp­
hr
for
PM,
0.30
g/
bhp­
hr
for
NO
X
and
0.14
g/
bhp­
hr
for
NMHC
starting
in
2012,
with
the
NO
X
and
NMHC
standards
phased
in
over
a
period
of
three
to
four
years
in
order
to
address
lead
time,
workload,
and
feasibility
considerations.
These
same
standards
will
apply
to
engines
of
175
to
750
hp
as
well
starting
in
2011,
with
a
similar
phase­
in.
These
PM,
NO
X,
and
NMHC
standards
and
phase­
in
schedules
are
similar
in
stringency
to
the
2007
highway
diesel
standards
and
are
expected
to
require
the
use
of
high­
efficiency
aftertreatment
systems
to
ensure
compliance.

For
engines
above
750
hp,
we
are
requiring
PM
and
NMHC
control
to
0.075
g/
bhp­
hr
and
0.30
g/
bhp­
hr,
respectively,
starting
in
2011.
More
stringent
standards
take
effect
in
2015
with
PM
standards
of
0.02
g/
bhp­
hr
(
for
engines
used
in
generator
sets)
and
0.03
g/
bhp­
hr
(
for
nongenerator
set
engines),
and
an
NMHC
standard
of
0.14
g/
bhp­
hr.
The
NO
X
standard
in
2011
will
be
0.50
g/
bhp­
hr
for
generator
set
engines
above
1200
hp,
and
2.6
g/
bhp­
hr
for
all
other
engines
in
the
above
750
hp
category.
This
application
of
advanced
NO
X
emission
control
technologies
to
generator
set
engines
above
1200
hp
will
provide
substantial
NO
X
reductions
and
will
occur
earlier
than
we
had
proposed
in
the
NPRM.
In
2015,
the
750­
1200
hp
generator
set
engines
will
be
added
to
the
stringent
0.50
g/
bhp­
hr
NO
X
requirement
as
well.
The
long­
term
NO
X
standard
for
engines
not
used
in
generator
sets
(
mobile
machinery)
will
be
addressed
in
a
future
action
(
we
are
currently
considering
such
an
action
in
the
2007
time
frame).

We
are
also
continuing
the
averaging,
banking,
and
trading
provisions
engine
manufacturers
can
use
to
demonstrate
compliance
with
the
standards.
We
also
are
continuing
provisions
providing
flexibilities
which
equipment
manufacturers
may
use
to
facilitate
transition
to
compliance
with
the
new
standards.
In
addition,
we
are
including
turbocharged
diesels
in
the
existing
regulation
of
crankcase
emissions,
effective
in
the
same
year
that
the
new
standards
first
apply
in
each
power
category.

As
discussed
at
length
in
the
proposal,
new
test
procedures
and
compliance
provisions,
especially
the
not­
to­
exceed
and
transient
tests,
are
necessary
to
ensure
the
benefits
of
the
standards
being
adopted
today
are
achieved
when
the
aftertreatment­
based
standards
go
into
place.
We
are
therefore
adopting
the
proposed
test
procedures
and
compliance
provisions,
with
slight
modifications
designed
to
better
implement
the
provisions,
in
today's
rule.
We
continue
to
believe
the
new
transient
test,
cold
start
transient
test,
and
not­
to­
exceed
test
procedures
and
standards
will
all
help
achieve
our
goal
of
emissions
reductions
being
achieved
in
actual
engine
operation.

As
noted,
the
final
rule
also
continues,
and
in
some
cases
modifies,
existing
provisions
that
will
facilitate
the
transition
to
the
new
engine
and
fuel
standards.
Many
of
these
provisions
will
11
help
small
business
engine
and
equipment
manufacturers
meet
the
requirements.
They
will
also
aid
manufacturers
in
managing
their
development
of
engines
and
equipment
that
will
meet
our
new
standards.

2.
Nonroad,
Locomotive,
and
Marine
Diesel
Fuel
Quality
Standards
The
fuel
program
requirements
are
very
similar
to
those
included
in
the
proposal,
with
two
notable
exceptions.
The
first
involves
the
standards
themselves
with
the
inclusion
of
locomotive
and
marine
diesel
fuel
in
the
15
ppm
standard.
The
second
addresses
the
compliance
provisions
designed
to
ensure
the
effectiveness
of
the
program.

We
are
adopting
the
two­
step
approach
to
sulfur
control,
with
all
land­
based
nonroad,
locomotive,
and
marine
diesel
fuel
going
from
uncontrolled
sulfur
levels
of
approximately
3,000
ppm
sulfur
to
500
ppm
in
June,
2007.
The
interim
step
will
by
itself
achieve
significant
PM
and
SO
X
emission
reductions
with
associated
important
health
benefits
as
early
as
is
practicable.
Then,
in
June
2010,
the
sulfur
cap
for
land­
based
nonroad
engine
diesel
fuel
will
be
reduced
to
the
final
standard
of
15
ppm.
Two
years
later,
in
2012,
the
15
ppm
cap
for
locomotive
and
marine
engine
diesel
fuel
will
go
into
effect.
The
reduction
to
15
ppm
sulfur
provides
additional
direct
control
of
PM
and
SO
X
emissions
and
is
an
enabling
technology
for
the
application
of
advanced
catalyst­
based
emission
control
technologies.

Although
we
did
not
propose
to
control
locomotive
and
marine
diesel
fuel
to
15
ppm
in
the
NPRM,
after
careful
consideration
and
reviewing
substantial
comments
from
stakeholders,
we
have
decided
to
include
fuel
used
in
locomotive
and
marine
applications
in
the
final
step
to
15
ppm
beginning
in
2012.
The
incremental
PM
health
and
welfare
benefits
associated
with
this
standard
outweigh
the
costs.
The
locomotive
and
marine
diesel
fuel
program
provides
a
nearterm
positive
impact
on
public
health
and
welfare.
Also,
the
15
ppm
sulfur
diesel
fuel
provides
an
opportunity
that
may
enable
the
application
of
advanced
catalyst­
based
emission
control
technologies
to
locomotive
and
marine
diesel
engines.
We
are
issuing
an
Advance
Notice
of
Proposed
Rulemaking
for
locomotive
and
marine
diesel
engines
that
investigates
this
potential.
Recognizing
the
value
that
a
locomotive
and
marine
fuel
program
could
have
for
public
health
and
welfare,
State
and
local
authorities
and
public
health
advocacy
organizations
provided
a
large
number
of
comments
encouraging
us
to
take
action
in
this
rulemaking
to
address
emissions
from
this
category.

Including
locomotive
and
marine
fuel
in
the
15
ppm
sulfur
diesel
fuel
pool
also
simplifies
the
overall
design
of
the
fuel
program
and
will
simplify
the
distribution
of
diesel
fuel.
At
the
same
time,
we
have
finalized
this
standard
with
flexibilities
designed
specifically
to
address
fuel
program
implementation
issues
raised
in
the
comments.

Noting
that
sulfur
levels
in
highway
diesel
fuel
will
generally
be
at
or
below
15
ppm
starting
in
2006
and
not
wanting
to
reduce
the
benefits
of
introducing
this
clean
fuel,
we
spent
considerable
time
developing
a
compliance
assurance
scheme
for
introducing
our
nonroad
diesel
12
sulfur
program
to
mesh
with
the
highway
program
requirements.
We
initially
thought
that
a
"
baseline"
approach
essentially
requiring
refiners
to
maintain
a
constraint
on
sulfur
levels
of
various
distillate
fuels,
based
on
historical
production
volumes,
was
the
most
appropriate
mechanism.
Subsequently
we
learned
that
the
other
mechanism
we
discussed
in
the
proposal,
a
"
designate
and
track"
type
approach,
is
better
suited
to
address
our
priorities
and
commitments
for
the
nonroad
diesel
sulfur
control
program.
This
approach
allows
refiners
to
designate
volumes
of
nonroad
fuel
into
various
categories
and
these
designations
would
follow
the
fuel
throughout
the
distribution
system.
We
have
successfully
worked
through
our
enforceability
and
other
concerns
with
this
approach
and
are
now
including
it
as
our
compliance
mechanism
for
the
fuel
standards
of
today's
program.

B.
Why
Is
EPA
Taking
this
Action?

As
we
have
discussed
extensively
in
both
the
proposal
and
today's
action,
EPA
strongly
believes
it
is
appropriate
to
take
steps
now
to
reduce
future
emissions
from
nonroad,
locomotive,
and
marine
diesel
engines.
Emissions
from
these
engines
contribute
greatly
to
a
number
of
serious
air
pollution
problems
and
would
continue
to
do
so
in
the
future
absent
further
reduction
measures.
Such
emissions
lead
to
adverse
health
and
welfare
effects
associated
with
ozone,
PM,
NO
X,
SO
X,
and
volatile
organic
compounds,
including
toxic
compounds.
In
addition,
diesel
exhaust
is
of
specific
concern
because
it
is
likely
to
be
carcinogenic
to
humans
by
inhalation
as
well
as
posing
a
hazard
from
noncancer
respiratory
effects.
Ozone,
NO
X,
and
PM
also
cause
significant
public
welfare
harm
such
as
damage
to
crops,
eutrophication,
regional
haze,
and
soiling
of
building
materials.

Millions
of
Americans
continue
to
live
in
areas
with
unhealthy
air
quality
that
may
endanger
public
health
and
welfare.
As
discussed
in
more
detail
below,
there
are
approximately
159
million
people
living
in
areas
that
either
do
not
meet
the
8­
hour
ozone
National
Ambient
Air
Quality
Standards
(
NAAQS)
or
contribute
to
violations
in
other
counties
as
noted
in
EPA's
recent
nonattainment
designations
for
part
or
all
of
474
counties.
In
addition,
approximately
65
million
people
live
in
counties
where
air
quality
measurements
violate
the
PM
2.5
NAAQS.
These
numbers
do
not
include
the
tens
of
millions
of
people
living
in
areas
where
there
is
a
significant
future
risk
of
failing
to
maintain
or
achieve
the
ozone
or
PM
2.5
NAAQS.
Federal,
state,
and
local
governments
are
working
to
bring
ozone
and
PM
levels
into
compliance
with
the
NAAQS
attainment
and
maintenance
plans
and
the
reductions
included
in
today's
rule
will
play
a
critical
part
in
these
actions.
Reducing
regional
emissions
of
SO
X
is
critical
to
this
strategy
for
attaining
the
PM
NAAQS
and
meeting
regional
haze
goals
in
our
treasured
national
parks.
SO
X
levels
can
themselves
pose
a
respiratory
hazard.

Although
controlling
air
pollution
from
nonroad
diesel
exhaust
is
challenging,
we
strongly
believe
it
can
be
accomplished
through
the
application
of
high­
efficiency
emissions
control
technologies.
As
discussed
in
much
greater
detail
in
section
II,
very
large
emission
reductions
(
in
excess
of
90
percent)
are
possible,
especially
through
the
use
of
catalytic
emission
control
devices
installed
in
the
nonroad
equipment's
exhaust
system
and
integrated
with
the
engine
controls.
To
13
meet
the
standards
being
adopted
today,
application
of
such
technologies
for
both
PM
and
NO
X
control
will
be
needed
for
most
engines.
High­
efficiency
PM
exhaust
emission
control
technology
has
been
available
for
several
years,
and
it
is
the
same
technology
we
expect
to
be
applied
to
meet
the
PM
standards
for
highway
diesel
engines
in
2007.
For
NO
X,
we
expect
the
same
highefficiency
technologies
being
developed
for
the
2007
highway
diesel
engine
program
will
be
used
to
meet
our
new
nonroad
requirements.
All
of
these
technologies
are
dependent
on
the
15
ppm
maximum
sulfur
levels
for
nonroad
diesel
fuel
being
adopted
today.
The
fuel
control
program
being
adopted
today
also
yields
significant
and
important
reductions
in
SO
X
from
these
sources.

1.
Basis
For
Action
Under
the
Clean
Air
Act
Section
213
of
the
Clean
Air
Act
("
the
Act"
or
CAA)
gives
us
the
authority
to
establish
emissions
standards
for
nonroad
engines
and
vehicles.
Section
213(
a)(
3)
authorizes
the
Administrator
to
set
standards
for
NO
X,
volatile
organic
compounds
(
VOCs),
and
CO
which
"
standards
shall
achieve
the
greatest
degree
of
emission
reduction
achievable
through
the
application
of
technology
which
the
Administrator
determines
will
be
available
for
the
engines
or
vehicles."
As
part
of
this
determination,
the
Administrator
must
give
appropriate
consideration
to
cost,
lead
time,
noise,
energy,
and
safety
factors
associated
with
the
application
of
such
technology.
The
standards
adopted
today
for
NO
X
implement
this
provision.
Section
213(
a)(
4)
authorizes
the
Administrator
to
establish
standards
to
control
emissions
of
pollutants
(
other
than
those
covered
by
section
213(
a)(
3))
which
"
may
reasonably
be
anticipated
to
endanger
public
health
and
welfare."
Here,
the
Administrator
may
promulgate
regulations
that
are
deemed
appropriate
for
new
nonroad
vehicles
and
engines
which
cause
or
contribute
to
such
air
pollution,
taking
into
account
costs,
noise,
safety,
and
energy
factors.
EPA
believes
the
new
controls
for
PM
in
today's
rule
are
an
appropriate
exercise
of
EPA's
discretion
under
the
authority
of
section
213(
a)(
4).

We
believe
the
evidence
provided
in
section
II
of
this
preamble
and
in
the
Regulatory
Impact
Analysis
(
RIA)
indicates
that
the
stringent
emission
standards
adopted
today
are
feasible
and
reflect
the
greatest
degree
of
emission
reduction
achievable
in
the
model
years
to
which
they
apply.
We
have
given
appropriate
consideration
to
costs
in
promulgating
these
standards.
Our
review
of
the
costs
and
cost­
effectiveness
of
these
standards
indicate
that
they
will
be
reasonable
and
comparable
to
the
cost­
effectiveness
of
other
emission
reduction
strategies
for
the
same
pollutants
that
have
been
required
or
could
be
required
in
the
future.
We
have
also
reviewed
and
given
appropriate
consideration
to
the
energy
factors
of
this
rule
in
terms
of
fuel
efficiency
and
effects
on
diesel
fuel
supply,
production,
and
distribution,
as
discussed
below,
as
well
as
any
safety
factors
associated
with
these
new
standards.

The
information
in
this
section
and
chapters
2
and
3
of
the
RIA
regarding
air
quality
and
the
contribution
of
nonroad,
locomotive,
and
marine
diesel
engines
to
air
pollution
provides
strong
evidence
that
emissions
from
such
engines
significantly
and
adversely
impact
public
health
or
welfare.
First,
as
noted
earlier,
there
is
a
significant
risk
that
several
areas
will
fail
to
attain
or
maintain
compliance
with
the
NAAQS
for
8­
hour
ozone
concentrations
or
the
NAAQS
for
PM
2.5
2
See
Clean
Air
Act
section
213(
b).

14
during
the
period
that
these
new
vehicle
and
engine
standards
will
be
phased
into
the
vehicle
population,
and
that
nonroad,
locomotive,
and
marine
diesel
engines
contribute
to
such
concentrations,
as
well
as
to
concentrations
of
other
criteria
pollutants.
This
risk
will
be
significantly
reduced
by
the
standards
adopted
today,
as
also
noted
above.
However,
the
evidence
indicates
that
some
risk
remains
even
after
the
reductions
achieved
by
these
new
controls
on
nonroad
diesel
engines
and
nonroad,
locomotive,
and
marine
diesel
fuel.
Second,
EPA
believes
that
diesel
exhaust
is
likely
to
be
carcinogenic
to
humans.
The
risk
associated
with
exposure
to
diesel
exhaust
includes
the
particulate
and
gaseous
components
among
which
are
benzene,
formaldehyde,
acetaldehyde,
acrolein,
and
1,3­
butadiene,
all
of
which
are
known
or
suspected
human
or
animal
carcinogens,
or
have
noncancer
health
effects.
Moreover,
these
compounds
have
the
potential
to
cause
health
effects
at
environmental
levels
of
exposure.
Third,
emissions
from
nonroad
diesel
engines
(
including
locomotive
and
marine
diesel
engines)
contribute
to
regional
haze
and
impaired
visibility
across
the
nation,
as
well
as
to
odor,
acid
deposition,
polycyclic
organic
matter
(
POM)
deposition,
eutrophication
and
nitrification,
all
of
which
are
serious
environmental
welfare
problems.

EPA
has
already
found
in
previous
rules
that
emissions
from
new
nonroad
diesel
engines
contribute
to
ozone
and
CO
concentrations
in
more
than
one
area
which
has
failed
to
attain
the
ozone
and
CO
NAAQS
(
59
FR
31306,
June
17,
1994).
EPA
has
also
previously
determined
that
it
is
appropriate
to
establish
standards
for
PM
from
new
nonroad
diesel
engines
under
section
213(
a)(
4),
and
the
additional
information
on
diesel
exhaust
carcinogenicity
noted
above
reinforces
this
finding.
In
addition,
we
have
already
found
that
emissions
from
nonroad
engines
significantly
contribute
to
air
pollution
that
may
reasonably
be
anticipated
to
endanger
public
welfare
due
to
regional
haze
and
visibility
impairment
(
67
FR
68242
­
68243,
Nov.
8,
2002).
We
find
here,
based
on
the
information
in
this
section
of
the
preamble
and
chapters
2
and
3
of
the
RIA,
that
emissions
from
the
new
nonroad
diesel
engines
covered
by
this
final
action
likewise
contribute
to
regional
haze
and
to
visibility
impairment
that
may
reasonably
be
anticipated
to
endanger
public
welfare.
Taken
together,
these
findings
indicate
the
appropriateness
of
the
nonroad
diesel
engine
standards
adopted
today
for
purposes
of
section
213(
a)(
3)
and
(
4)
of
the
Act.
These
findings
were
unchallenged
by
commenters.

These
standards
must
take
effect
at
the
"
the
earliest
possible
date
considering
the
lead
time
necessary
to
permit
development
and
application
of
the
requisite
technology,"
giving
"
appropriate
consideration"
to
cost,
energy,
and
safety.
2
The
compliance
dates
we
are
adopting
reflect
careful
consideration
of
these
factors.
The
averaging,
banking,
and
trading
(
ABT),
equipment
manufacturer
flexibilities,
and
phase­
in
provisions
for
NO
X
are
elements
in
our
determination
that
we
have
selected
appropriate
lead
times
for
the
standards.

Section
211(
c)
of
the
CAA
allows
us
to
regulate
fuels
where
emission
products
of
the
fuel
either:
1)
cause
or
contribute
to
air
pollution
that
reasonably
may
be
anticipated
to
endanger
public
health
or
welfare,
or
2)
will
impair
to
a
significant
degree
the
performance
of
any
emission
15
control
device
or
system
which
is
in
general
use,
or
which
the
Administrator
finds
has
been
developed
to
a
point
where
in
a
reasonable
time
it
will
be
in
general
use
were
such
a
regulation
to
be
promulgated.
This
rule
meets
both
of
these
criteria.
Sulfur
dioxide
(
SO
2)
and
sulfate
PM
emissions
from
nonroad,
locomotive,
marine
and
diesel
vehicles
are
due
to
sulfur
in
diesel
fuel.
As
discussed
above,
emissions
of
these
pollutants
cause
or
contribute
to
ambient
levels
of
air
pollution
that
endanger
public
health
and
welfare.
Control
of
sulfur
to
15
ppm
for
this
fuel
through
a
two­
step
program
would
lead
to
significant,
cost­
effective
reductions
in
emissions
of
these
pollutants.
Control
of
sulfur
to
15
ppm
in
nonroad
diesel
fuel
will
also
enable
emissions
control
technology
that
will
achieve
significant,
cost­
effective
reduction
in
emissions
of
these
pollutants,
as
discussed
in
section
I.
B.
2
below.
The
substantial
adverse
effect
of
high
sulfur
levels
on
the
performance
of
diesel
emission
control
devices
or
systems
that
would
be
expected
to
be
used
to
meet
the
nonroad
standards
is
discussed
in
detail
in
section
II.
Control
of
sulfur
to
15
ppm
for
locomotive
and
marine
diesel
fuel,
as
with
nonroad
diesel
fuel,
will
provide
meaningful
additional
benefits
that
outweigh
the
costs.
In
addition,
our
authority
under
section
211(
c)
is
discussed
in
more
detail
in
Appendix
A
to
chapter
5
of
the
RIA.

2.
What
Is
the
Air
Quality
Impact
of
this
Final
Rule?

a.
Public
Health
and
Environmental
Impacts
With
this
rulemaking,
we
are
acting
to
extend
advanced
emission
controls
to
another
major
source
of
diesel
engine
emissions:
nonroad
land­
based
diesel
engines.
This
final
rule
sets
out
emission
standards
for
nonroad
land­
based
diesel
engines
­
engines
used
mainly
in
construction,
agricultural,
industrial
and
mining
operations
­
that
will
achieve
reductions
in
PM
and
NO
X
standards
in
excess
of
95
percent
and
90
percent,
respectively
for
this
class
of
vehicles.
This
action
also
regulates
nonroad
diesel
fuel
for
the
first
time
by
reducing
sulfur
levels
in
this
fuel
more
than
99
percent
to
15
ppm.
The
diesel
fuel
sulfur
requirements
will
decrease
PM
and
SO
2
emissions
for
land­
based
diesel
engines,
as
well
as
for
three
other
nonroad
source
categories:
commercial
marine
diesel
vessels,
locomotives,
and
recreational
marine
diesel
engines.

These
sources
are
significant
contributors
to
atmospheric
pollution
of
(
among
other
pollutants)
PM,
ozone
and
a
variety
of
toxic
air
pollutants.
In
1996,
emissions
from
these
four
source
categories
were
estimated
to
be
40
percent
of
the
mobile
source
inventory
for
PM
2.5
and
25
percent
for
NO
X,
and
10
percent
and
13
percent
of
overall
emissions
for
these
potential
health
hazards,
respectively.
Without
further
controls
beyond
those
we
have
already
adopted,
these
sources
will
emit
44
percent
of
PM
2.5
from
mobile
sources
and
47
percent
of
NO
X
emissions
from
mobile
sources
by
the
year
2030.

Nonroad
engines,
and
most
importantly
nonroad
diesel
engines,
contribute
significantly
to
ambient
PM
2.5
levels,
largely
through
direct
emissions
of
carbonaceous
and
sulfate
particles
in
the
fine
(
and
even
ultrafine)
size
range.
Nonroad
diesels
also
currently
emit
high
levels
of
NO
X
which
react
in
the
atmosphere
to
form
secondary
PM
2.5
(
namely
ammonium
nitrate)
as
well
as
ozone.
Nonroad
diesels
also
emit
SO
2
and
hydrocarbons
which
react
in
the
atmosphere
to
form
3
Note
this
analysis
does
not
include
the
effects
of
the
proposed
Rule
to
Reduce
Interstate
Transport
of
Fine
Particulate
Matter
and
Ozone
(
Interstate
Air
Quality
Rule).
69
FR
4566
(
January
30,

2004).
See
http://
www.
epa.
gov/
interstateairquality/
rule.
html
16
secondary
PM
2.5
(
namely
sulfates
and
organic
carbonaceous
PM
2.5).
This
section
summarizes
key
points
regarding
the
nonroad
diesel
engine
contribution
to
these
pollutants
and
their
impacts
on
human
health
and
the
environment.
EPA
notes
that
we
are
relying
not
only
on
the
information
presented
in
this
preamble,
but
also
on
the
more
detailed
information
in
chapters
2
and
3
of
the
RIA
and
technical
support
documents,
as
well
as
information
in
the
preamble,
RIA,
and
support
documents
for
the
proposed
rule.

When
fully
implemented,
this
final
rule
will
reduce
nonroad
(
equipment
such
as
construction,
agricultural,
and
industrial),
diesel
PM
2.5
and
NO
X
emissions
by
95
percent
and
90
percent,
respectively.
It
will
also
virtually
eliminate
nonroad
diesel
SO
2
emissions,
which
amounted
to
approximately
234,000
tons
in
1996,
and
would
otherwise
grow
to
approximately
326,000
tons
by
2020.
These
dramatic
reductions
in
nonroad
emissions
are
a
critical
part
of
the
effort
by
federal,
state
and
local
governments
to
reduce
the
health
related
impacts
of
air
pollution
and
to
reach
attainment
of
the
NAAQS
for
PM
and
ozone,
as
well
as
to
improve
other
environmental
effects
such
as
atmospheric
visibility.
Based
on
the
most
recent
data
available
for
this
rule,
such
problems
are
widespread
in
the
United
States.
There
are
almost
65
million
people
living
in
120
counties
with
monitored
PM
2.5
levels
(
2000­
2002)
exceeding
the
PM
2.5
NAAQS,
and
159
million
people
living
in
areas
recently
designated
as
exceeding
8­
hour
ozone
NAAQS.
Figure
I­
1
illustrates
the
widespread
nature
of
these
problems.
Shown
in
this
figure
are
counties
exceeding
the
PM
2.5
NAAQS
or
designated
for
nonattainment
with
the
8­
hour
ozone
NAAQS
plus
mandatory
Federal
Class
I
areas,
which
have
particular
needs
for
reductions
in
atmospheric
haze.

Our
air
quality
modeling
also
indicates
that
similar
conditions
are
likely
to
continue
to
persist
in
the
future
in
the
absence
of
additional
controls
and
that
the
emission
reductions
would
assist
areas
with
attainment
and
future
maintenance
of
the
PM
and
ozone
NAAQS.
3
For
example,
in
2020,
based
on
emission
controls
currently
adopted,
we
project
that
66
million
people
will
live
in
79
counties
with
average
PM
2.5
levels
above
15
micrograms
per
cubic
meter
(
ug/
m3).
In
2030,
the
number
of
people
projected
to
live
in
areas
exceeding
the
PM
2.5
standard
is
expected
to
increase
to
85
million
in
107
counties.
An
additional
24
million
people
are
projected
to
live
in
counties
within
10
percent
of
the
standard
in
2020,
which
will
increase
to
64
million
people
in
2030.
Furthermore,
for
ozone,
in
2020,
based
on
emission
controls
currently
adopted,
the
number
of
counties
violating
the
8­
hour
ozone
standard
is
expected
to
decrease
to
30
counties
where
43
million
people
are
projected
to
live.
Thereafter,
exposure
to
unhealthy
levels
of
ozone
is
expected
to
begin
to
increase
again.
In
2030
the
number
of
counties
violating
the
8­
hour
ozone
NAAQS
is
projected
to
increase
to
32
counties
where
47
million
people
are
projected
to
live.
In
addition,
in
2030,
82
counties
where
44
million
people
are
projected
to
live
will
be
within
10
percent
of
violating
the
ozone
8­
hour
NAAQS.
17
Figure
I­
1.
Air
Quality
Problems
are
Widespread
4
The
following
are
sample
comments
from
states
and
state
associations
on
the
proposed
rule,

which
corroborate
that
this
rule
is
a
critical
element
in
States'
NAAQS
attainment
efforts.
Fuller
information
can
be
found
in
the
Summary
and
Analysis
of
Comments.

­
"
Unless
emissions
from
nonroad
diesels
are
sharply
reduced,
it
is
very
likely
that
many
areas
of
the
country
will
be
unable
to
attain
and
maintain
health­
based
NAAQS
for
ozone
and
PM."

(
STAPPA/
ALAPCO)

­
"
Adoption
of
the
proposed
regulation
...
is
necessary
for
the
protection
of
public
health
in
California
and
to
comply
with
air
quality
standards...
The
need
for
15
ppm
sulfur
diesel
fuel
cannot
be
overstated."
(
California
Air
Resources
Board)

­
"
The
EPA's
proposed
regulation
is
necessary
if
the
West
is
to
make
reasonable
progress
towards
improving
visibility
in
our
nation's
Class
I
areas."
(
Western
Regional
Air
Partnership
(
WRAP))

­
"
Attainment
of
the
NAAQS
for
ozone
and
PM2.5
is
of
immediate
concern
to
the
states
in
the
northeast
region....
Thus,
programs
...
such
as
the
proposed
rule
for
nonroad
diesel
engines
are
essential."
(
NESCAUM)

5
U.
S.
EPA
(
1996.)
Air
Quality
Criteria
for
Particulate
Matter
­
Volumes
I,
II,
and
III,
EPA,

Office
of
Research
and
Development.
Report
No.
EPA/
600/
P­
95/
001a­
cF.
This
material
is
available
18
EPA
is
still
developing
the
implementation
process
for
bringing
the
nation's
air
into
attainment
with
the
PM
2.5
and
8­
hour
ozone
NAAQS.
Based
on
section
172(
a)
provisions
in
the
Act,
designated
areas
will
need
to
attain
the
PM
2.5
NAAQS
in
the
2010
(
based
on
2007
­
2009
air
quality
data)
to
2015
(
based
on
2012
to
2014
air
quality
data)
time
frame,
and
then
be
required
to
maintain
the
NAAQS
thereafter.
Similarly,
we
expect
that
most
areas
covered
under
subpart
1
and
2
will
attain
the
ozone
standard
in
the
2007
to
2014
time
frame,
depending
on
an
area's
classification
and
other
factors,
and
then
be
required
to
maintain
the
NAAQS
thereafter.

Since
the
emission
reductions
expected
from
this
final
rule
would
begin
in
this
same
time
frame,
the
projected
reductions
in
nonroad
emissions
would
be
used
by
states
in
meeting
the
PM
2.5
and
ozone
NAAQS.
In
their
comments
on
the
proposal,
states
told
EPA
that
they
need
nonroad
diesel
engine
reductions
in
order
to
be
able
to
meet
and
maintain
the
PM
2.5
and
ozone
NAAQS
as
well
as
to
make
progress
toward
visibility
requirements.
4
Furthermore,
this
action
would
ensure
that
nonroad
diesel
emissions
will
continue
to
decrease
as
the
fleet
turns
over
in
the
years
beyond
2014;
these
reductions
will
be
important
for
maintenance
of
the
NAAQS
following
attainment.

Scientific
studies
show
ambient
PM
is
associated
with
a
series
of
adverse
health
effects.
These
health
effects
are
discussed
in
detail
in
the
EPA
Criteria
Document
for
PM
as
well
as
the
draft
updates
of
this
document
released
in
the
past
year.
5,
6
EPA's
"
Health
Assessment
Document
electronically
at
http://
www.
epa.
gov/
ttn/
oarpg/
ticd.
html.

6
U.
S.
EPA
(
2003).
Air
Quality
Criteria
for
Particulate
Matter
­
Volumes
I
and
II
(
Fourth
External
Review
Draft)
This
material
is
available
electronically
at
http://
cfpub.
epa.
gov/
ncea/
cfm/
partmatt.
cfm.

7
U.
S.
EPA
(
2002).
Health
Assessment
Document
for
Diesel
Engine
Exhaust.

EPA/
600/
8­
90/
057F
Office
of
Research
and
Development,
Washington
DC.
This
document
is
available
electronically
at
http://
cfpub.
epa.
gov/
ncea/
cfm/
recordisplay.
cfm?
deid=
29060.

8
Dockery,
DW;
Pope,
CA,
III;
Xu,
X;
et
al.
(
1993)
An
association
between
air
pollution
and
mortality
in
six
U.
S.
cities.
N
Engl
J
Med
329:
1753­
1759.

9
Pope,
CA,
III;
Burnett,
RT;
Calle,
EE;
et
al.
(
2002)
Lung
cancer,
cardiopulmonary
mortality,

and
long­
term
exposure
to
fine
particulate
air
pollution.
JAMA
287:
1132­
1141.

19
for
Diesel
Engine
Exhaust,"
(
the
"
Diesel
HAD")
also
reviews
health
effects
information
related
to
diesel
exhaust
as
a
whole
including
diesel
PM,
which
is
one
component
of
ambient
PM.
7
In
the
Diesel
HAD,
we
note
that
the
particulate
characteristics
in
the
zone
around
nonroad
diesel
engines
are
likely
to
be
substantially
the
same
as
published
air
quality
measurements
made
along
busy
roadways.
This
conclusion
supports
the
relevance
of
health
effects
associated
with
highway
diesel
engine­
generated
PM
to
nonroad
applications.

As
described
in
these
documents,
health
effects
associated
with
short­
term
variation
in
ambient
PM
have
been
indicated
by
epidemiologic
studies
showing
associations
between
exposure
and
increased
hospital
admissions
for
ischemic
heart
disease,
heart
failure,
respiratory
disease,
including
chronic
obstructive
pulmonary
disease
(
COPD)
and
pneumonia.
Short­
term
elevations
in
ambient
PM
have
also
been
associated
with
increased
cough,
lower
respiratory
symptoms,
and
decrements
in
lung
function.
Additional
studies
have
associated
changes
in
heart
rate
and/
or
heart
rhythm
in
addition
to
changes
in
blood
characteristics
with
exposure
to
ambient
PM.
Short­
term
variations
in
ambient
PM
have
also
been
associated
with
increases
in
total
and
cardiorespiratory
mortality.
Studies
examining
populations
exposed
to
different
levels
of
air
pollution
over
a
number
of
years,
including
the
Harvard
Six
Cities
Study
and
the
American
Cancer
Society
Study,
suggest
an
association
between
long­
term
exposure
to
ambient
PM
2.5
and
premature
mortality,
including
deaths
attributed
to
lung
cancer.
8,
9
Two
studies
further
analyzing
the
Harvard
Six
Cities
Study's
air
quality
data
have
also
established
a
specific
influence
of
mobile
source­
related
PM
2.5
on
daily
mortality
and
a
concentration­
response
function
for
mobile
source­
associated
PM
2.5
and
daily
mortality.
Another
recent
study
in
14
U.
S.
cities
examining
the
effect
of
PM
10
(
particulate
matter
less
than
10
microns
in
diameter)
on
daily
hospital
admissions
for
cardiovascular
disease
found
that
the
effect
of
PM
10
was
significantly
greater
in
areas
with
a
larger
proportion
of
PM
10
10
Janssen,
NA;
Schwartz
J;
Zanobetti
A;
et
al.
(
2002)
Air
conditioning
and
source­
specific
particles
as
modifiers
of
the
effect
of
PM10
on
hospital
admissions
for
heart
and
lung
disease.
Environ
Health
Perspect
110(
1):
43­
49.

11
Hoek,
G;
Brunekreef,
B;
Goldbohm,
S;
et
al.
(
2002)
Association
between
mortality
and
indicators
of
traffic­
related
air
pollution
in
the
Netherlands:
a
cohort
study.
Lancet
360(
9341):
1203­
1209.

12
Brunekreef,
B;
Janssen
NA;
de
Hartog,
J;
et
al.
(
1997)
Air
pollution
from
traffic
and
lung
function
in
children
living
near
motor
ways.
Epidemiology
(
8):
298­
303.

13
Delfino
RJ.
(
2002)
Epidemiologic
evidence
for
asthma
and
exposure
to
air
toxics:
linkages
between
occupational,
indoor,
and
community
air
pollution
research.
Env
Health
Perspect
Suppl
110(
4):

573­
589.

14
Yifang
Zhu,
William
C.
Hinds,
Seongheon
Kim,
Si
Shen
and
Constantinos
Sioutas
Zhu
Y;
Hinds
WC;
Kim
S;
et
al.
(
2002)
Study
of
ultrafine
particles
near
a
major
highway
with
heavy­
duty
diesel
traffic.
Atmos
Environ
36(
27):
4323­
4335.

20
coming
from
motor
vehicles,
indicating
that
PM
10
from
these
sources
may
have
a
greater
effect
on
the
toxicity
of
ambient
PM
10
when
compared
with
other
sources.
10
Of
particular
relevance
to
this
rule
is
a
recent
cohort
study
which
examined
the
association
between
mortality
and
residential
proximity
to
major
roads
in
the
Netherlands.
Examining
a
cohort
of
55
to
69
year­
olds
from
1986
to
1994,
the
study
indicated
that
long­
term
residence
near
major
roads,
an
index
of
exposure
to
primary
mobile
source
emissions
(
including
diesel
exhaust),
was
significantly
associated
with
increased
cardiopulmonary
mortality.
11
Other
studies
have
shown
children
living
near
roads
with
high
truck
traffic
density
have
decreased
lung
function
and
greater
prevalence
of
lower
respiratory
symptoms
compared
to
children
living
on
other
roads.
12
A
recent
review
of
epidemiologic
studies
examining
associations
between
asthma
and
roadway
proximity
concluded
that
some
coherence
was
evident
in
the
literature,
indicating
that
asthma,
lung
function
decrement,
respiratory
symptoms,
and
other
respiratory
problems
appear
to
occur
more
frequently
in
people
living
near
busy
roads.
13
As
discussed
later,
nonroad
diesel
engine
emissions,
especially
particulate,
are
similar
in
composition
to
those
from
highway
diesel
vehicles.
Although
difficult
to
associate
directly
with
PM
2.5,
these
studies
indicate
that
direct
emissions
from
mobile
sources,
and
diesel
engines
specifically,
may
explain
a
portion
of
respiratory
health
effects
observed
in
larger­
scale
epidemiologic
studies.
Recent
studies
conducted
in
Los
Angeles
have
illustrated
that
a
substantial
increase
in
the
concentration
of
ultrafine
particles
is
evident
in
locations
near
roadways,
indicating
substantial
differences
in
the
nature
of
PM
immediately
near
mobile
source
emissions.
14
For
additional
information
on
health
effects,
see
the
RIA.

In
addition
to
its
contribution
to
ambient
PM
concentrations,
diesel
exhaust
is
of
specific
concern
because
it
has
been
judged
to
pose
a
lung
cancer
hazard
for
humans
as
well
as
a
hazard
15
U.
S.
EPA
(
2002).
National­
Scale
Air
Toxics
Assessment.
This
material
is
available
electronically
at
http://
www.
epa.
gov/
ttn/
atw/
nata/.

16
U.
S.
EPA
(
2002).
Health
Assessment
Document
for
Diesel
Engine
Exhaust.

EPA/
600/
8­
90/
057F
Office
of
Research
and
Development,
Washington
DC.
This
document
is
available
electronically
at
http://
cfpub.
epa.
gov/
ncea/
cfm/
recordisplay.
cfm?
deid=
29060.

21
from
noncancer
respiratory
effects.
In
this
context,
diesel
exhaust
PM
is
generally
used
as
a
surrogate
measure
for
diesel
exhaust.
Further,
nonroad
diesel
engine
emissions
also
contain
several
substances
known
or
suspected
as
human
or
animal
carcinogens,
or
that
have
noncancer
health
effects
as
described
in
the
Diesel
HAD.
Moreover,
these
compounds
have
the
potential
to
cause
health
effects
at
environmental
levels
of
exposure.
These
other
compounds
include
benzene,
1,3­
butadiene,
formaldehyde,
acetaldehyde,
acrolein,
dioxin,
and
POM.
For
some
of
these
pollutants,
nonroad
diesel
engine
emissions
are
believed
to
account
for
a
significant
proportion
of
total
nation­
wide
emissions.
All
of
these
compounds
were
identified
as
national
or
regional
"
risk
drivers"
in
the
1996
NATA.
15
That
is,
these
compounds
pose
a
significant
portion
of
the
total
inhalation
cancer
risk
to
a
significant
portion
of
the
population.
Mobile
sources
contribute
significantly
to
total
emissions
of
these
air
toxics.
As
discussed
in
more
detail
in
the
RIA,
this
final
rulemaking
will
result
in
significant
reductions
of
these
emissions.

In
EPA's
Diesel
HAD,
16
diesel
exhaust
was
classified
as
likely
to
be
carcinogenic
to
humans
by
inhalation
at
environmental
exposures,
in
accordance
with
the
revised
draft
1996/
1999
EPA
cancer
guidelines.
A
number
of
other
agencies
(
National
Institute
for
Occupational
Safety
and
Health,
the
International
Agency
for
Research
on
Cancer,
the
World
Health
Organization,
California
EPA,
and
the
U.
S.
Department
of
Health
and
Human
Services)
have
made
similar
classifications.

EPA
generally
derives
cancer
unit
risk
estimates
to
calculate
population
risk
more
precisely
from
exposure
to
carcinogens.
In
the
simplest
terms,
the
cancer
unit
risk
is
the
increased
risk
associated
with
average
lifetime
exposure
of
1
ug/
m3.
EPA
concluded
in
the
Diesel
HAD
that
it
is
not
possible
currently
to
calculate
a
cancer
unit
risk
for
diesel
exhaust
due
to
a
variety
of
factors
that
limit
the
current
studies,
such
as
lack
of
an
adequate
dose­
response
relationship
between
exposure
and
cancer
incidence.

However,
in
the
absence
of
a
cancer
unit
risk,
the
EPA
Diesel
HAD
sought
to
provide
additional
insight
into
the
significance
of
the
cancer
hazard
by
estimating
possible
ranges
of
risk
that
might
be
present
in
the
population.
The
possible
risk
range
analysis
was
developed
by
comparing
a
typical
environmental
exposure
level
for
highway
diesel
sources
to
a
selected
range
of
occupational
exposure
levels
and
then
proportionally
scaling
the
occupationally
observed
risks
according
to
the
exposure
ratios
to
obtain
an
estimate
of
the
possible
environmental
risk.
A
number
of
calculations
are
needed
to
accomplish
this,
and
these
can
be
seen
in
the
EPA
Diesel
HAD.
The
outcome
was
that
environmental
risks
from
diesel
exhaust
exposure
could
range
from
17
U.
S.
EPA
(
1996).
Air
Quality
Criteria
for
Ozone
and
Related
Photochemical
Oxidants,

EPA/
600/
P­
93/
004aF.
Docket
No.
A­
99­
06.
Document
Nos.
II­
A­
15
to
17.

18
U.
S.
EPA.
(
1996).
Review
of
National
Ambient
Air
Quality
Standards
for
Ozone,
Assessment
of
Scientific
and
Technical
Information,
OAQPS
Staff
Paper,
EPA­
452/
R­
96­
007.
Docket
No.
A­
99­
06.

Document
No.
II­
A­
22.

19
U.
S.
EPA
(
1996).
Air
Quality
Criteria
for
Ozone
and
Related
Photochemical
Oxidants,

EPA/
600/
P­
93/
004aF.
Docket
No.
A­
99­
06.
Document
Nos.
II­
A­
15
to
17.

20
U.
S.
EPA.
(
1996).
Review
of
National
Ambient
Air
Quality
Standards
for
Ozone,
Assessment
of
Scientific
and
Technical
Information,
OAQPS
Staff
Paper,
EPA­
452/
R­
96­
007.
Docket
No.
A­
99­
06.

Document
No.
II­
A­
22.

22
a
low
of
10­
4
to
10­
5
or
be
as
high
as
10­
3
this
being
a
reflection
of
the
range
of
occupational
exposures
that
could
be
associated
with
the
relative
and
absolute
risk
levels
observed
in
the
occupational
studies.
Because
of
uncertainties,
the
analysis
acknowledged
that
the
risks
could
be
lower
than
10­
4
or
10­
5
and
a
zero
risk
from
diesel
exhaust
exposure
was
not
ruled
out.
Although
the
above
risk
range
is
based
on
environmental
exposure
levels
for
highway
mobile
sources
only,
the
1996
NATA
estimated
exposure
for
nonroad
diesel
sources
as
well.
Thus,
the
exposure
estimates
were
somewhat
higher
than
those
used
in
the
risk
range
analysis
described
above.
The
EPA
Diesel
HAD,
therefore,
stated
that
the
NATA
exposure
estimates
result
in
a
similar
risk
perspective.

The
ozone
precursor
reductions
expected
as
a
result
of
this
rule
are
also
important
because
of
health
and
welfare
effects
associated
with
ozone,
as
described
in
the
Air
Quality
Criteria
Document
for
Ozone
and
Other
Photochemical
Oxidants.
Ozone
can
irritate
the
respiratory
system,
causing
coughing,
throat
irritation,
and/
or
uncomfortable
sensation
in
the
chest.
17,
18
Ozone
can
reduce
lung
function
and
make
it
more
difficult
to
breathe
deeply,
and
breathing
may
become
more
rapid
and
shallow
than
normal,
thereby
limiting
a
person's
normal
activity.
Ozone
also
can
aggravate
asthma,
leading
to
more
asthma
attacks
that
require
a
doctor's
attention
and/
or
the
use
of
additional
medication.
In
addition,
ozone
can
inflame
and
damage
the
lining
of
the
lungs,
which
may
lead
to
permanent
changes
in
lung
tissue,
irreversible
reductions
in
lung
function,
and
a
lower
quality
of
life
if
the
inflammation
occurs
repeatedly
over
a
long
time
period
(
months,
years,
a
lifetime).
People
who
are
of
particular
concern
with
respect
to
ozone
exposures
include
children
and
adults
who
are
active
outdoors.
Those
people
particularly
susceptible
to
ozone
effects
are
people
with
respiratory
disease,
such
as
asthma,
and
people
with
unusual
sensitivity
to
ozone,
and
children.
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.
19,
20
21
New
Ozone
Health
and
Environmental
Effects
References,
Published
Since
Completion
of
the
Previous
Ozone
AQCD,
National
Center
for
Environmental
Assessment,
Office
of
Research
and
Development,
U.
S.
Environmental
Protection
Agency,
Research
Triangle
Park,
NC
27711
(
7/
2002)

Docket
No.
A­
2001­
28,
Document
II­
A­
79.

23
New
research
suggests
additional
serious
health
effects
beyond
those
that
were
known
when
the
8­
hour
ozone
health
standard
was
set.
Since
1997,
over
1,700
new
health
and
welfare
studies
relating
to
ozone
have
been
published
in
peer­
reviewed
journals.
21
Many
of
these
studies
investigate
the
impact
of
ozone
exposure
on
such
health
effects
as
changes
in
lung
structure
and
biochemistry,
inflammation
of
the
lungs,
exacerbation
and
causation
of
asthma,
respiratory
illnessrelated
school
absence,
hospital
and
emergency
room
visits
for
asthma
and
other
respiratory
causes,
and
premature
mortality.
EPA
is
currently
evaluating
these
and
other
studies
as
part
of
the
ongoing
review
of
the
air
quality
criteria
and
NAAQS
for
ozone.
A
revised
Air
Quality
Criteria
Document
for
Ozone
and
Other
Photochemical
Oxidants
will
be
prepared
in
consultation
with
EPA's
Clean
Air
Science
Advisory
Committee
(
CASAC).
Key
new
health
information
falls
into
four
general
areas:
development
of
new­
onset
asthma,
hospital
admissions
for
young
children,
school
absence
rate,
and
premature
mortality.
In
all,
the
new
studies
that
have
become
available
since
the
8­
hour
ozone
standard
was
adopted
in
1997
continue
to
demonstrate
the
harmful
effects
of
ozone
on
public
health
and
the
need
for
areas
with
high
ozone
levels
to
attain
and
maintain
the
NAAQS.

Finally,
nonroad
diesel
emissions
contribute
to
nine
categories
of
non­
health
impacts:
visibility
impairment,
soiling
and
material
damage,
acid
deposition,
eutrophication
of
water
bodies,
plant
and
ecosystem
damage
from
ozone,
water
pollution
resulting
from
deposition
of
toxic
air
pollutants
with
resulting
effects
on
fish
and
wildlife,
and
odor.
In
particular,
EPA
determined
that
nonroad
engines
contribute
significantly
to
unacceptable
visibility
conditions
where
people
live,
work
and
recreate,
including
contributing
to
visibility
impairment
in
Federally
mandated
Class
I
areas
that
are
given
special
emphasis
in
the
Clean
Air
Act
(
67
FR
68242,
November
8,
2002).
Visibility
is
impaired
by
fine
PM
and
precursor
emissions
from
nonroad
diesel
engines
subject
to
this
final
rule.
Reductions
in
emissions
from
this
final
rule
will
improve
visibility
as
well
as
other
environmental
outcomes
as
described
in
the
RIA.

As
supplementary
information,
we
have
made
estimates
using
air
quality
modeling
to
illustrate
the
types
of
change
in
future
PM
2.5
and
ozone
levels
that
we
would
expect
to
result
from
a
final
rule
like
this
as
described
in
chapter
2
of
the
RIA.
That
modeling
shows
that
control
of
nonroad
emissions
would
produce
nationwide
air
quality
improvements
in
PM
2.5
and
ozone
levels
as
well
as
visibility
improvements.
On
a
population­
weighted
basis,
the
average
modeled
change
in
future­
year
PM
2.5
annual
averages
is
projected
to
decrease
by
0.42
µ
g/
m3
(
3.3%)
in
2020,
and
0.59
µ
g/
m3
(
0.6%)
in
2030.
In
addition,
the
population­
weighted
average
modeled
change
in
future
year
design
values
for
ozone
would
decrease
by
1.8
parts
per
billion
(
ppb)
in
2020,
and
2.5
ppb
in
2030.
Within
areas
predicted
to
violate
the
ozone
NAAQS
in
the
projected
base
case,
the
average
decrease
would
be
somewhat
higher:
1.9
ppb
in
2020
and
3.0
ppb
in
2030.
22
We
are
also
adopting
a
few
minor
adjustments
of
a
technical
nature
to
current
CO
standards.

Emissions
effects
from
these
standards
are
discussed
in
the
RIA.

23
The
estimates
of
baseline
emissions
and
emissions
reductions
from
the
final
rule
reported
here
for
nonroad
land­
based,
recreational
marine,
locomotive,
and
commercial
marine
vessel
diesel
engines
are
based
on
50
state
emissions
inventory
estimates.
A
48
state
inventory
was
used
for
air
quality
modeling
that
EPA
conducted
for
this
rule,
of
which
Alaska
and
Hawaii
are
not
a
part.
In
cases
where
land­
based
nonroad
diesel
engine
emissions
are
compared
with
non­
mobile
source
portions
of
the
inventory,
we
use
a
48
state
emissions
inventory,
to
match
the
48
state
nature
of
those
other
inventories.

24
Please
see
the
Summary
and
Analyses
of
Comments
document
for
discussions
of
issues
raised
about
the
emission
inventory
estimates
during
the
comment
period
for
the
NPRM.

24
The
PM
air
quality
improvements
expected
from
this
final
rule
are
anticipated
to
produce
major
benefits
to
human
health
and
welfare,
with
a
combined
value
in
excess
of
half
a
trillion
dollars
between
2007
and
2030.
For
example,
in
2030,
we
estimate
that
this
program
will
reduce
approximately
129,000
tons
PM
2.5
and
738,000
tons
of
NO
X.
The
resulting
ambient
PM
reductions
correspond
to
public
health
improvements
in
2030,
including
12,000
fewer
premature
mortalities,
15,000
fewer
heart
attacks,
200,000
fewer
asthma
exacerbations
in
children,
and
1
million
fewer
days
when
adults
miss
work
due
to
their
respiratory
symptoms,
and
5.9
million
fewer
days
when
adults
have
to
restrict
their
activities
due
to
respiratory
symptoms.
The
reductions
will
also
improve
visibility
and
reduce
diesel
odor.
For
further
details
on
the
economic
benefits
of
this
rule,
please
refer
to
the
benefit­
cost
discussion
in
section
VI
of
this
preamble
and
chapter
9
of
the
RIA.

b.
Emissions
From
Nonroad
Diesel
Engines
The
engine
and
fuel
standards
in
this
final
rule
will
affect
emissions
of
direct
PM
2.5,
SO
2,
NO
X,
VOCs,
and
air
toxics
for
land­
based
nonroad
diesel
engines.
22
For
locomotive,
commercial
marine
vessel
(
CMV),
and
recreational
marine
vessel
(
RMV)
engines,
the
final
fuel
standards
will
affect
direct
PM
2.5
and
SO
2
emissions.
Each
sub­
section
below
discusses
one
of
these
pollutants,
23
including
expected
emission
reductions
associated
with
the
final
standards.
24
Table
I.
B­
1
summarizes
the
impacts
of
this
rule
for
2020
and
2030.
Further
details
on
our
inventory
estimates,
including
results
for
other
years,
are
available
in
chapter
3
of
the
RIA.
25
Table
I.
B­
1.
 
Estimated
National
(
50
State)
Reductions
in
Emissions
From
Nonroad
Land­
Based,
Locomotive,
Commercial
Marine,
and
Recreational
Marine
Diesel
Engines
Pollutant
[
short
tons]
2020
2030
Direct
PM2.5
PM2.5
Emissions
Without
Rule
167,000
181,000
PM2.5
Emissions
With
500
ppm
Sulfur
in
2007
and
No
Other
Controls
144,000
155,000
PM2.5
Emissions
With
15
ppm
Sulfur
in
2012
and
No
Other
Controls
141,000
152,000
PM2.5
Emissions
With
Entire
Rule
81,000
52,000
PM2.5
Reductions
Resulting
from
this
Rule
86,000
129,000
SO2
SO2
Emissions
Without
Rule
326,000
379,000
SO2
Emisions
With
500
ppm
Sulfur
in
2007
37,000
43,000
SO2
Emissions
With
Entire
Rule
(
15
ppm
Sulfur
in
2012)
3,000
3,000
SO2
Reductions
Resulting
from
this
Rule
323,000
376,000
NOX
­
Land­
Based
Nonroad
Engines
Onlya
NOX
Emissions
Without
Rule
1,125,000
1,199,000
NOX
Emissions
With
Rule
681,000
461,000
NOX
Reductions
Resulting
from
this
Rule
444,000
738,000
VOC
­
Land­
Based
Nonroad
Engines
Onlya
VOC
Emissions
Without
Rule
98,000
97,000
VOC
Emissions
With
Rule
75,000
63,000
VOC
Reductions
Resulting
from
this
Rule
23,000
34,000
Notes:
a
NOX
and
VOC
numbers
only
include
emissions
for
land­
based
nonroad
diesel
engines
because
the
Tier
4
controls
will
not
be
applied
to
locomotive,
commercial
marine,
and
recreational
marine
engines;
and
no
NOX
and
VOC
emission
reductions
are
generated
through
the
lowering
of
fuel
sulfur
levels.

i.
Direct
PM
2.5
As
described
earlier,
the
Agency
believes
that
reductions
of
diesel
PM
2.5
emissions
are
needed
as
part
of
the
nation's
progress
toward
clean
air.
Direct
PM
2.5
emissions
from
land­
based
nonroad
diesel
engines
amount
to
increasingly
large
percentages
of
total
man­
made
diesel
PM
2.5.
Between
1996
and
2030,
we
estimate
that
the
percentage
of
total
man­
made
diesel
PM
2.5
25
Highway
fuel
is
currently
used
in
a
significant
fraction
of
land
based
nonroad
equipment,

locomotives,
and
marine
vessels,
reducing
the
in­
use
average
sulfur
level
from
about
3,000
ppm
for
uncontrolled
high­
sulfur
fuel
to
2,300
or
2,400
ppm.

26
emissions
coming
from
land­
based
nonroad
diesel
engines
will
increase
from
about
46
percent
to
72
percent
(
based
on
a
48
state
inventory).

Emissions
of
direct
PM
2.5
from
land­
based
nonroad
diesel
engines
based
on
a
50
state
inventory
are
shown
in
table
I.
B­
1,
along
with
our
estimates
of
the
reductions
in
2020
and
2030
we
expect
would
result
from
our
final
rule
for
a
PM
2.5
exhaust
emission
standard
and
from
changes
in
the
sulfur
level
in
land­
based
nonroad,
locomotive,
and
marine
diesel
fuel.
Land­
based
nonroad,
locomotive,
and
marine
diesel
fuel
sulfur
levels
will
be
lowered
to
about
340
ppm
in­
use
(
500
ppm
maximum)
in
2007.
Land­
based
nonroad
diesel
fuel
sulfur
will
be
lowered
further
to
about
11
ppm
in­
use
(
15
ppm
maximum)
in
2010
and
locomotive
and
marine
diesel
fuel
sulfur
will
be
lowered
to
the
same
level
in
2012.
In
addition
to
PM
2.5
emissions
estimates
with
the
final
rule,
emissions
estimates
based
on
lowering
diesel
fuel
sulfur
without
any
other
controls
are
shown
in
table
I.
B­
1
for
2020
and
2030.

Figure
I.
B­
1a
shows
our
estimate
of
PM
2.5
emissions
between
2000
and
2030
both
without
and
with
the
final
standards
and
fuel
sulfur
requirements
of
this
rule.
We
estimate
that
PM
2.5
emissions
from
this
source
would
be
reduced
by
71
percent
in
2030.

ii.
SO
2
We
estimate
that
land­
based
nonroad,
CMV,
RMV,
and
locomotive
diesel
engines
emitted
about
234,000
tons
of
SO
2
in
1996,
accounting
for
about
33
percent
of
the
SO
2
from
mobile
sources
(
based
on
a
48
state
inventory).
With
no
reduction
in
diesel
fuel
sulfur
levels,
we
estimate
that
these
emissions
will
continue
to
increase,
accounting
for
about
44
percent
of
mobile
source
SO
2
emissions
by
2030.

As
part
of
this
final
rule,
sulfur
levels
in
fuel
will
be
significantly
reduced,
leading
to
large
reductions
in
nonroad,
locomotive,
and
marine
diesel
SO
2
emissions.
By
2007,
the
sulfur
in
diesel
fuel
used
by
all
land­
based
nonroad,
locomotive,
and
marine
diesel
engines
will
be
reduced
from
the
current
average
in­
use
level
of
between
2,300
to
2,400
ppm25
to
an
average
in­
use
level
of
about
340
ppm,
with
a
maximum
level
of
500
ppm.
By
2010,
the
sulfur
in
diesel
fuel
used
by
land­
based
nonroad
engines
will
be
reduced
to
an
average
in­
use
level
of
11
ppm
with
a
maximum
level
of
15
ppm.
Sulfur
in
diesel
fuel
used
by
locomotive
and
marine
engines
will
be
reduced
to
the
same
level
by
2012.
Table
II.
B­
1
and
figure
II.
B­
1b
show
the
estimated
reductions
from
these
sulfur
changes.
27
iii.
NO
X
Table
I.
B­
1
shows
the
50
state
estimated
tonnage
of
NO
X
emissions
for
2020
and
2030
without
the
final
rule
and
the
estimated
tonnage
of
emissions
eliminated
with
the
final
rule
in
place.
These
results
are
shown
graphically
in
Figure
I.
E­
1c
at
the
end
of
this
section.
We
estimate
that
NO
X
emissions
from
these
engines
will
be
reduced
by
62
percent
in
2030.

We
note
that
the
magnitude
of
NO
X
reductions
determined
in
the
final
rule
analysis
is
somewhat
less
than
what
was
reported
in
the
proposal's
preamble
and
RIA,
especially
in
the
later
years
when
the
fleet
has
mostly
turned
over
to
Tier
4
designs.
The
greater
part
of
this
is
due
to
the
fact
that
we
have
deferred
setting
a
long­
term
NO
X
standard
for
mobile
machinery
over
750
horsepower
to
a
later
action.
When
this
future
action
is
completed,
we
would
expect
roughly
equivalent
reductions
between
the
proposal
and
the
overall
final
program,
though
there
are
some
other
effects
reflected
in
the
differing
NO
X
reductions
as
well,
due
to
updated
modeling
assumptions
and
the
adjusted
NO
X
standards
levels
for
engines
over
750
horsepower.
Section
II.
A.
4
of
this
preamble
contains
a
detailed
discussion
of
the
NO
X
standards
we
are
adopting
for
engines
over
750
horsepower
as
well
as
the
basis
for
those
standards.

iv.
VOCs
and
Air
Toxics
Based
on
a
48
state
emissions
inventory,
we
estimate
that
land­
based
nonroad
diesel
engines
emitted
over
221
thousand
tons
of
VOC
in
1996.
Between
1996
and
2030,
we
estimate
that
land­
based
nonroad
diesel
engines
will
contribute
about
2
to
3
percent
of
mobile
source
VOC
emissions.
Without
further
controls,
land­
based
nonroad
diesel
engines
will
emit
about
97
thousand
tons/
year
of
VOC
in
2020
and
2030
nationally.

Table
I.
B­
1
shows
our
projection
of
the
reductions
in
2020
and
2030
for
VOC
emissions
that
we
expect
from
implementing
the
final
NMHC
standards.
This
estimate
is
based
on
a
50
state
emissions
inventory.
By
2030,
VOC
emissions
from
this
category
would
be
reduced
by
35
percent
from
baseline
levels.

While
we
are
not
adopting
any
specific
gaseous
air
toxics
standards
in
today's
rule,
air
toxics
emissions
would
nonetheless
be
significantly
reduced
through
the
NMHC
standards
included
in
the
final
rule.
By
2030,
we
estimate
that
emissions
of
air
toxics
pollutants,
such
as
benzene,
formaldehyde,
acetaldehyde,
1,3­
butadiene,
and
acrolein,
would
be
reduced
by
35
percent
from
land­
based
nonroad
diesel
engines.
Diesel
PM
reductions
were
discussed
above.
For
specific
air
toxics
reduction
estimates,
see
chapter
3
of
the
RIA.
28
Figure
I.
B­
1a:
Estimated
PM2.5
Reductions
From
Nonroad
Land­
Based
Diesel
Engine
Standard
and
Diesel
Fuel
Sulfur
Reductions
0
50,000
100,000
150,000
200,000
250,000
2000
2005
2010
2015
2020
2025
2030
Year
Short
Tons/

Year
Uncontrolled
50
State
Controlled
50
State
Figure
I.
B­
1b:
Estimated
SO2
Reductions
From
Lowering
Diesel
Fuel
Sulfur
For
Land­
Based
Nonroad
Engines,

CMVs,
RMVs,
and
Locomotives
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
2000
2005
2010
2015
2020
2025
2030
Year
Short
Tons/

Year
Uncontrolled
50
State
Controlled
50
State
Figure
I.
B­
1c:
Estimated
NOx
Reductions
From
Land­

Based
Nonroad
Diesel
Engine
Standard
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1,800,000
2000
2005
2010
2015
2020
2025
2030
Year
Short
Tons/

Year
Uncontrolled
50
State
Controlled
50
State
II.
Nonr
oad
Engine
Standards
In
this
section
we
describe
the
emission
standards
for
nonroad
diesel
engines
that
we
are
setting
to
address
the
serious
air
quality
problems
discussed
in
section
I.
These
Tier
4
standards,
which
take
effect
starting
in
2008,
are
very
similar
to
those
proposed,
and
obtain
very
similar
emissions
reductions.
The
long­
term
PM
filter­
based
standards
that
apply
to
all
engines
over
25
hp,
combined
with
the
fuel
change
and
new
requirements
to
ensure
robust
control
in
the
field,
will
yield
PM
reductions
of
over
95%
from
the
in­
use
levels
of
26
Consistent
with
past
EPA
rulemakings
for
nonroad
diesel
engines,
our
regulations
express
standards,
power
ratings,
and
other
quantities
in
international
SI
(
metric)
units­­
kilowatts,
gram
per
29
today's
cleanest
Tier
2
engines.
Likewise,
the
long­
term
NO
X
standards
we
are
adopting
for
nearly
all
engines
above
75
hp
will
yield
NO
X
reductions
of
about
90%
from
the
NO
X
levels
expected
from
even
the
low­
emitting
Tier
3
engines
due
to
first
reach
the
market
in
2006
or
later.
The
Tier
4
standards
will
bring
about
large
reductions
in
toxic
hydrocarbon
emissions
as
well.

In
this
final
rule
we
are
largely
adopting
the
standards
and
timing
we
proposed,
with
the
exception
of
those
that
apply
to
engines
over
750
hp.
We
restructured
and
modified
the
standards
and
timing
for
these
engines
to
address
technical
concerns
and
to
focus
on
achieving
comparable
emission
reductions
through
the
introduction
of
advanced
technology
as
early
as
feasible
from
specific
applications
within
this
power
category.
See
section
II.
A.
4
for
a
detailed
discussion.
We
also
are
not
adopting
the
proposed
minor
adjustments
to
the
CO
standard
levels
for
some
engines
under
75
hp,
as
explained
in
section
II.
A.
6.
In
addition,
there
are
minor
changes
from
the
proposal
in
the
phase­
in
approach
we
are
adopting
for
NO
X
and
NMHC
standards,
as
detailed
in
this
section.

In
this
section
we
discuss:
°
The
Tier
4
engine
standards,
and
the
schedule
for
implementing
them;
°
The
feasibility
of
the
Tier
4
standards
(
in
conjunction
with
the
low­
sulfur
nonroad
diesel
fuel
requirement
discussed
in
section
IV);
and
°
How
diesel
fuel
sulfur
affects
an
engine's
ability
to
meet
the
new
standards.

Additional
provisions
for
engine
and
equipment
manufacturers
are
discussed
in
detail
in
section
III.
These
include:
°
The
averaging,
banking,
and
trading
(
ABT)
program.
°
The
transition
program
for
equipment
manufacturers.
°
The
addition
of
a
"
not­
to­
exceed"
program
to
ensure
in­
use
emissions
control.
This
program
includes
new
emission
standards
and
related
test
procedures
to
supplement
the
standards
discussed
in
this
section.
°
The
test
procedures
and
other
compliance
requirements
associated
with
the
emission
standards.
°
Special
provisions
to
aid
small
businesses
in
implementing
our
requirements.
°
An
incentive
program
to
encourage
innovative
technologies
and
the
early
introduction
of
new
technologies.

A.
What
Are
the
New
Engine
Standards?

The
Tier
4
exhaust
emissions
standards
for
PM,
NO
X,
and
NMHC
are
summarized
in
tables
II.
A­
1,
2,
and
4.26
Crankcase
emissions
control
requirements
are
discussed
in
section
kilowatt­
hour,
etc.
This
aids
in
achieving
harmonization
with
standards­
setting
bodies
outside
the
U.
S.,

and
in
laboratory
operations
in
which
these
units
are
the
norm.
However,
in
this
preamble
and
in
other
rulemaking
documents
for
the
general
reader,
we
have
chosen
to
use
terms
more
common
in
general
usage
in
the
U.
S.
Hence
standards
are
expressed
in
units
of
grams
per
brake
horsepower­
hour,
power
ratings
in
horsepower,
etc.
In
any
compliance
questions
that
might
arise
from
differences
in
these
due
to,

for
example,
rounding
conventions,
the
regulations
themselves
establish
the
applicable
requirements.

30
II.
A.
7.
Previously
adopted
CO
emission
standards
continue
to
apply
as
well.
All
of
these
standards
apply
to
covered
nonroad
engines
over
the
useful
life
periods
specified
in
our
regulations,
except
where
temporary
in­
use
compliance
margins
apply
as
discussed
in
section
III.
E.
To
help
ensure
that
these
emission
reductions
will
be
achieved
in
use,
we
have
adopted
test
procedures
for
measuring
compliance
with
these
standards
tailored
to
both
steady­
state
and
transient
nonroad
engine
operating
characteristics.
These
test
procedures
are
discussed
in
several
subsections
of
section
III.
Another
component
of
our
program
to
ensure
control
of
emissions
inuse
is
the
new
"
not­
to­
exceed"
(
NTE)
emission
standards
and
associated
test
procedures,
discussed
in
section
III.
J.

Table
II.
A­
1.
 
Tier
4
PM
Standards
(
g/
bhp­
hr)
and
Schedule
Engine
Power
Model
Year
2008
2009
2010
2011
2012
2013
hp
<
25
(
kW
<
19)
0.30
a
25

hp
<
75
(
19

kW
<
56)
0.22
b
0.02
75

hp
<
175
(
56

kW
<
130)
0.01
175

hp

750
(
130

kW

560)
0.01
hp
750
(
kW
>
560)
see
table
II.
A­
4
Notes:

a
For
air­
cooled,
hand­
startable,
direct
injection
engines
under
11
hp,
a
manufacturer
may
instead
delay
implementation
until
2010
and
demonstrate
compliance
with
a
less
stringent
PM
standard
of
0.45
g/
bhp­
hr,

subject
also
to
additional
provisions
discussed
in
section
II.
A.
3.
a.

b
A
manufacturer
has
the
option
of
skipping
the
0.22
g/
bhp­
hr
PM
standard
for
all
50­
75
hp
engines.
The
0.02
g/
bhp­
hr
PM
standard
would
then
take
effect
one
year
earlier
for
all
50­
75
hp
engines,
in
2012.
27
Note
that
we
are
grouping
all
standards
in
this
rule,
including
those
that
take
effect
in
2008,

under
the
general
designation
of
"
Tier
4
standards."
As
a
result,
there
are
no
"
Tier
3"
standards
in
the
multi­
tier
nonroad
program
for
engines
below
50
hp
or
above
750
hp.

31
Table
II.
A­.
2
 
Tier
4
NOX
and
NMHC
Standards
and
Schedule
Engine
Power
Standard
(
g/
bhp­
hr)
Phase­
in
Schedule
(
model
year)

NOX
NMHC
2011
2012
2013
2014
25

hp
<
75
(
19

kW
<
56)
3.5
NMHC+
NOX
a
100%

75

hp
<
175
(
56

kW
<
130)
0.30
0.14
50%
b
50%
b
100%
b
175

hp

750
(
130

kW

560)
0.30
0.14
50%
50%
50%
100%

hp
>
750
(
kW
>
560)
see
table
II.
A­
4
Notes:
Percentages
indicate
production
required
to
comply
with
the
Tier
4
standards
in
the
indicated
model
year.

a
This
is
the
existing
Tier
3
combined
NMHC+
NOX
standard
level
for
the
50­
75
hp
engines
in
this
category.

In
2013
it
applies
to
the
25­
50
hp
engines
as
well.

b
Manufacturers
may
use
banked
Tier
2
NMHC+
NOX
credits
from
engines
at
or
above
50
hp
to
demonstrate
compliance
with
the
75­
175
hp
engine
NOX
standard
in
this
model
year.
Alternatively,
manufacturers
may
forego
this
special
banked
credit
option
and
instead
meet
an
alternative
phase­
in
requirement
of
25/
25/
25%
in
2012,
2013,
and
2014
through
December
30,
with
100%
compliance
required
beginning
December
31,
2014.

See
sections
III.
A
and
II.
A.
2.
b.

The
long­
term
0.01
and
0.02
g/
bhp­
hr
Tier
4
PM
standards
for
75
 
750
hp
and
25
 
75
hp
engines,
respectively,
combined
with
the
fuel
change
and
new
requirements
to
ensure
robust
control
in
the
field,
represent
a
reduction
of
over
95%
from
in­
use
levels
expected
with
Tier
2/
Tier
3
engines.
27
The
0.30
g/
bhp­
hr
Tier
4
NO
X
standard
for
75
 
750
hp
engines
represents
a
NO
X
reduction
of
about
90%
from
in­
use
levels
expected
with
Tier
3
engines.
Emissions
reductions
from
engines
over
750
hp
are
discussed
in
section
II.
A.
4.

In
general,
there
was
widespread
support
in
the
comments
for
the
proposed
Tier
4
engine
standards
and
for
the
timing
we
proposed
for
them.
Some
commenters
raised
category­
specific
concerns,
especially
for
the
smaller
and
the
very
large
engine
categories.
These
comments
are
discussed
below.
28
"
Nonroad
Diesel
Emissions
Standards
Staff
Technical
Paper,"
EPA420­
R­
01­
052,
October
2001.

32
1.
Standards
Timing
a.
2008
Standards
The
timing
of
the
Tier
4
engine
standards
is
closely
tied
to
the
timing
of
fuel
quality
changes
discussed
in
section
IV,
in
keeping
with
the
systems
approach
we
are
taking
for
this
program.
The
earliest
Tier
4
engine
standards
take
effect
in
model
year
2008,
in
conjunction
with
the
introduction
of
500
ppm
maximum
sulfur
nonroad
diesel
fuel
in
mid­
2007.
This
fuel
change
serves
a
dual
environmental
purpose.
First,
it
provides
a
large
immediate
reduction
in
PM
and
SO
X
emissions
for
the
existing
fleet
of
engines
in
the
field.
Second,
its
widespread
availability
by
the
end
of
2007
aids
engine
designers
in
employing
emissions
controls
capable
of
achieving
the
Tier
4
standards
for
model
year
2008
and
later
engines;
this
is
because
the
performance
and
durability
of
such
technologies
as
exhaust
gas
recirculation
(
EGR)
and
diesel
oxidation
catalysts
is
improved
by
lower
sulfur
fuel.
28
The
reduction
of
sulfur
in
nonroad
diesel
fuel
will
also
provide
sizeable
economic
benefits
to
machine
operators
as
it
will
reduce
wear
and
corrosion
and
will
allow
them
to
extend
oil
change
intervals
(
see
section
VI.
B).
These
economic
benefits
will
occur
for
all
diesel
engines
using
the
new
fuel,
not
just
for
those
built
in
2008
or
later.

As
we
proposed,
these
2008
Tier
4
engine
standards
apply
only
to
engines
below
75
hp.
We
are
not
setting
Tier
4
standards
taking
effect
in
2008
for
larger
engines.
The
reasons
for
this
differ
depending
on
the
engines'
hp
rating.
Setting
Tier
4
2008
standards
for
engines
at
or
above
100
hp
would
provide
an
insufficient
period
of
stability
(
an
element
of
lead
time)
between
Tier
2/
3
and
Tier
4,
and
so
would
not
be
appropriate.
This
is
because
these
engines
become
subject
to
existing
Tier
2
or
3
NMHC+
NO
X
standards
in
2006
or
2007.
Setting
new
2008
standards
for
them
thus
would
provide
only
one
or
two
years
of
Tier
2/
Tier
3
stability
before
another
round
of
design
changes
would
have
to
be
made
in
2008
for
Tier
4.

It
is
also
inappropriate
to
establish
2008
Tier
4
standards
for
engines
of
75
 
100
hp.
The
stability
issue
just
noted
for
larger
engines
is
not
present
for
these
engines,
because
these
engines
are
subject
to
Tier
3
NMHC+
NO
X
standards
starting
in
2008,
so
that
our
setting
a
Tier
4
PM
standard
for
them
in
the
same
year
would
not
create
the
situation
in
which
engines
have
to
be
redesigned
twice
to
comply
with
new
standards
within
a
space
of
one
or
two
years.
However,
EPA
believes
the
more
significant
concern
for
these
engines
is
meeting
the
stringent
aftertreatment­
based
standards
for
PM
and
NO
X
in
2012.
We
are
concerned
that
adopting
interim
2008
standards
for
these
engines
would
divert
resources
needed
to
achieve
these
2012
standards
and
indeed
jeopardize
attaining
them.
Thus,
although
early
emission
reductions
from
these
engines
in
2008
would
of
course
be
desirable,
we
felt
that
the
focus
we
are
putting
on
obtaining
much
larger
reductions
from
them
in
2012,
together
with
the
fact
that
we
already
have
a
Tier
3
NMHC+
NO
X
standard
taking
effect
for
75
 
100
hp
engines
in
2008,
warrants
our
not
adding
additional
control
requirements
for
these
engines
during
this
interim
period.
33
We
note
that
the
50­
75
hp
engines
also
have
a
Tier
3
NMHC+
NO
X
standard
taking
effect
in
2008
and,
as
noted
above,
we
are
setting
a
new
Tier
4
2008
PM
standard
for
them.
Unlike
the
larger
75
 
100
hp
engines,
however,
the
50­
75
hp
engines
have
one
additional
year,
until
2013,
before
filter­
based
PM
standards
take
effect,
and
also
have
no
additional
NO
X
control
requirement
being
set
beyond
the
2008
Tier
3
standard.
These
differences
justify
including
the
interim
Tier
4
PM
standard
for
these
engines.
We
note
too
that
achieving
the
2008
PM
standard
is
enabled
in
part
by
the
large
reduction
in
certification
fuel
sulfur
that
applies
in
2008
(
see
section
III.
D).
Fuel
sulfur
has
a
known
correlation
to
PM
generation,
even
for
engines
without
aftertreatment.
Moreover,
for
any
manufacturers
who
believe
that
accomplishing
this
PM
pull­
ahead
will
hamper
their
Tier
3
compliance
efforts
for
these
engines,
there
is
an
alternative
Tier
4
compliance
option.
Instead
of
meeting
new
Tier
4
PM
standards
in
both
2008
and
2013,
manufacturers
may
skip
the
Tier
4
2008
PM
standard,
and
instead
focus
design
efforts
on
introducing
PM
filters
for
these
engines
one
year
earlier,
by
complying
with
the
aftertreatment­
based
standard
for
PM
in
2012.
These
options
are
discussed
in
more
detail
in
section
II.
A.
3.
b.

We
view
the
2008
portion
of
the
Tier
4
program
as
highly
important
because
it
provides
substantial
PM
and
SO
X
emissions
reductions
during
the
several
years
prior
to
2011.
Initiating
Tier
4
in
2008
also
fits
well
with
the
lead
time
(
including
stability),
cost,
and
technology
availability
considerations
of
the
overall
program.
Initiating
the
Tier
4
engine
standards
in
2008
provides
three
to
four
years
of
stability
after
the
start
of
Tier
2
for
engines
under
50
hp.
As
mentioned
above,
it
also
coincides
with
the
start
date
of
Tier
3
NMHC+
NO
X
standards
for
50
 
75
hp
engines
and
so
introduces
no
stability
issues
for
these
engines
(
as
redesign
for
both
PM
and
NO
X
occurs
at
the
same
time).
The
2008
start
date
provides
almost
4
years
of
lead
time
to
accomplish
redesign
and
testing.
The
evolutionary
character
of
the
2008
standards,
based
as
they
are
on
proven
technologies,
and
the
fact
that
some
certified
engines
already
meet
these
standards
as
discussed
in
section
II.
B,
leads
us
to
conclude
that
the
standards
are
appropriate
within
the
meaning
of
section
213(
a)(
4)
of
the
Clean
Air
Act
and
that
we
are
providing
adequate
lead
time
to
achieve
those
standards.

Engine
and
equipment
manufacturers
argued
in
their
comments
that
the
PM
pull­
ahead
option
for
50
 
75
hp
engines
is
inappropriate
because
it
constitutes
a
re­
opening
of
the
Tier
3
rule,
involving
as
it
does
a
Tier
4
PM
standard
in
2008,
the
same
year
that
the
Tier
3
NMHC+
NO
X
takes
effect.
They
further
argued
that
the
non­
pull­
ahead
option
is
not
a
real
option
because
PM
aftertreatment
cannot
be
implemented
for
these
engines
in
2012.

We
disagree
with
both
contentions.
We
determined,
as
part
of
our
feasibility
analysis
for
Tier
4,
that
it
is
feasible
to
design
engines
to
meet
the
2008
PM
standard
in
the
same
year
that
a
Tier
3
NMHC+
NO
X
standard
takes
effect.
See
section
II.
B
and
RIA
sections
4.1.4
and
4.1.5.
One
reason
is
that
a
substantial
part
of
the
2008
PM
emission
reductions
do
not
result
from
engine
redesign,
but
rather
are
due
to
the
reduction
in
certification
test
fuel
maximum
sulfur
levels
from
2000
to
500
ppm
that
results
from
the
fuel
change
in
the
field.
This
reduction
in
sulfur
levels
also
aids
engine
designers
in
employing
emission
control
technologies
that
are
detrimentally
affected
by
sulfur,
not
only
for
PM
control,
but
also
for
NMHC
and
NO
X
control.
Examples
of
34
these
sulfur­
sensitive
technologies
are
oxidation
catalysts,
which
can
substantially
reduce
PM
and
NMHC,
and
EGR,
which
is
effective
at
reducing
NO
X.
We
note
further
that
designing
engines
to
meet
the
2008
PM
standard
is
also
made
less
difficult
by
our
not
requiring
engine
designers
to
consider
the
transient
test,
cold
start,
and
not­
to­
exceed
requirements
that
are
otherwise
part
of
the
Tier
4
program.
These
requirements
do
not
take
effect
for
these
engines
until
the
0.02
g/
bhphr
standard
is
implemented
in
2012
or
2013.
See
section
III.
F
for
details.

We
also
believe
that
the
second
option
(
compliance
with
the
aftertreatment­
based
PM
standard
in
2012,
with
no
interim
2008
standard)
is
viable,
and
may
be
an
attractive
choice
especially
for
engine
families
on
the
higher
side
of
the
50­
75
hp
range
that
share
a
design
platform
with
larger
engines
being
equipped
with
PM
filters
to
meet
the
Tier
4
standard
for
75
 
175
hp
engines
in
2012.
We
believe
75
hp
is
the
appropriate
cutpoint
for
setting
and
timing
emissions
standards
(
see
section
II.
A.
5),
but
it
obviously
is
not
a
hard­
and­
fast
separator
between
engine
platforms
for
all
manufacturers
in
all
product
lines.
Even
for
many
50
 
75
hp
engines
that
do
not
share
a
design
platform
with
larger
engines,
we
believe
that
a
2012
implementation
date
for
PM
filter
technology
may
be
practical,
considering
the
4­
year
lead
time
it
affords
after
Tier
3
begins
for
these
engines
(
in
2008),
8­
year
lead
time
after
the
last
PM
standard
change
(
in
2004),
and
5­
year
lead
time
after
full­
scale
PM
filter
technology
implementation
on
highway
engines
(
in
2007).

Engine
manufacturers
also
commented
that
the
two­
options
approach
would
cause
their
customers
to
switch
engine
suppliers
in
2012
to
get
the
least
expensive
engines
possible
in
every
year,
thus
compromising
the
environmental
objectives
and
creating
market
disruptions.
We
have
addressed
these
concerns
as
discussed
in
section
II.
A.
3.
b.

b.
2011
and
Later
Standards
The
second
fuel
change
for
nonroad
diesel
fuel,
to
15
ppm
maximum
sulfur
in
mid­
2010,
and
the
related
engine
standards
for
PM,
NO
X,
and
NMHC
that
begin
to
phase­
in
in
the
2011
model
year,
provide
most
of
the
environmental
benefits
of
the
program.
Like
the
2008
standards,
these
standards
are
timed
to
provide
adequate
lead
time
for
engine
and
equipment
manufacturers.
They
also
are
phased
in
over
time
to
allow
for
the
orderly
transfer
of
technology
from
the
highway
sector,
and
to
spread
the
overall
workload
for
engine
and
equipment
manufacturers
engaged
in
redesigning
a
large
number
and
variety
of
products
for
Tier
4.

As
we
explained
at
proposal,
we
believe
that
the
high­
efficiency
exhaust
emission
control
technologies
being
developed
to
meet
our
2007
emission
standards
for
heavy­
duty
highway
diesel
engines
can
be
adapted
to
most
nonroad
diesel
applications.
The
engines
for
which
we
believe
this
adaptation
from
highway
applications
will
be
most
straightforward
are
those
in
the
175
 
750
hp
power
range,
and
thus
these
engines
are
subject
to
new
standards
requiring
high­
efficiency
exhaust
emission
controls
as
soon
as
the
15
ppm
sulfur
diesel
fuel
is
widely
available,
that
is,
in
the
2011
model
year.
Engines
of
75
 
175
hp
are
subject
to
the
new
standards
in
the
following
model
year,
2012,
reflecting
the
need
to
spread
the
redesign
workload
and,
to
some
extent,
the
greater
effort
that
may
be
involved
in
adapting
highway
technologies
to
these
engines.
Engines
35
between
25
and
75
hp
are
subject
to
new
standards
for
PM
based
on
high­
efficiency
exhaust
emission
controls
in
2013,
reflecting
again
the
need
to
spread
the
workload
and
the
challenge
of
adapting
this
technology
to
these
engines
which
typically
do
not
have
highway
counterparts.
Engines
over
750
hp
involve
a
number
of
special
considerations,
necessitating
an
implementation
approach
unique
to
these
engines
as
explained
in
section
II.
A.
4.
Lastly
,
there
are
additional
provisions
discussed
in
sections
III.
B.
2
and
III.
M
to
encourage
early
technology
introduction
and
to
further
draw
from
the
highway
technology
experience.

This
approach
of
implementing
Tier
4
standards
by
power
category
over
2011
 
2013
provides
for
the
orderly
migration
of
technology
and
distribution
of
redesign
workload
over
three
model
years,
as
EPA
provided
in
Tier
3.
Overall,
this
approach
provides
4
to
6
years
of
real
world
experience
with
the
new
technology
in
the
highway
sector,
involving
millions
of
engines
(
in
addition
to
the
several
additional
years
provided
by
demonstration
fleets
on
the
road
in
earlier
years),
before
the
new
standards
take
effect.
We
consider
the
implementation
of
Tier
4
standard
start
dates
over
2011
 
2013
as
described
above
to
be
responsive
to
the
technology
migration
and
workload
distribution
concerns.

2.
Phase­
In
of
NO
X
and
NMHC
Standards
for
75
 
750
hp
Engines
a.
Percent­
of­
Production
Phase­
In
for
NO
X
and
NMHC
We
are
finalizing
the
percent­
of­
production
phase­
in
for
NO
X
and
NMHC
that
we
proposed
for
75
 
750
hp
engines.
Because
Tier
4
NO
X
emissions
control
technology
is
expected
to
be
derived
from
technology
first
introduced
in
highway
heavy­
duty
diesels,
we
proposed
to
adopt
the
implementation
pattern
for
the
Tier
4
NO
X
standard
which
we
adopted
for
the
heavyduty
highway
diesel
program.
This
will
help
to
ensure
a
focused,
orderly
development
of
robust
high­
efficiency
NO
X
control
in
the
nonroad
sector
and
will
also
help
to
ensure
that
manufacturers
are
able
to
take
maximum
advantage
of
the
highway
engine
development
program,
with
resulting
cost
savings.

The
heavy­
duty
highway
rule
allows
for
a
gradual
phase­
in
of
the
NO
X
and
NMHC
requirements
over
multiple
model
years:
50%
of
each
manufacturer's
U.
S.­
directed
production
volume
must
meet
the
new
standard
in
2007­
2009,
and
100%
must
do
so
by
2010.
Through
the
use
of
emissions
averaging,
this
phase­
in
approach
also
provides
the
flexibility
for
highway
engine
manufacturers
to
meet
that
program's
environmental
goals
by
allowing
somewhat
less­
efficient
NO
X
controls
on
more
than
50%
of
their
production
during
the
2007
 
2009
phase­
in
years.

We
follow
the
same
pattern
in
this
rule.
As
proposed,
we
are
phasing
in
the
NO
X
standards
for
nonroad
diesels
over
2011
 
2013
as
indicated
in
table
II.
A­
2,
based
on
compliance
with
the
Tier
4
standards
for
50%
of
a
manufacturer's
U.
S.­
directed
production
in
each
power
category
between
75
and
750
hp
in
each
phase­
in
model
year.
The
phase­
in
of
standards
for
engines
over
750
hp
is
discussed
in
section
II.
A.
4.
With
a
NO
X
phase­
in,
all
manufacturers
are
able
to
introduce
their
new
technologies
on
a
limited
number
of
engines,
thereby
gaining
valuable
36
experience
with
the
technology
prior
to
implementing
it
on
their
entire
product
line.
In
tandem
with
the
equipment
manufacturer
transition
program
discussed
in
section
III.
B,
the
phase­
in
ensures
timely
progress
to
the
Tier
4
standard
levels
while
providing
a
great
degree
of
implementation
flexibility
for
the
industry.

This
"
percent
of
production
phase­
in"
is
intended
to
take
maximum
advantage
of
the
highway
program
technology
development.
It
adds
a
new
dimension
of
implementation
flexibility
to
the
staggered
"
phase­
in
by
power
category"
used
in
the
nonroad
program
for
Tiers
1
 
3
(
and
also
in
this
Tier
4)
which,
though
structured
to
facilitate
technology
development
and
transfer,
is
more
aimed
at
spreading
the
redesign
workload.
Because
the
Tier
4
program
involves
challenges
in
addressing
both
technology
development
and
redesign
workload,
we
believe
that
incorporating
both
of
these
phase­
in
mechanisms
into
the
program
is
warranted,
resulting
in
the
coordinated
phase­
in
plan
shown
in
table
II.
A­
2,
which
we
are
finalizing
essentially
as
proposed.
Note
that
this
results
in
the
new
NO
X
requirements
for
75
 
175
hp
engines
taking
effect
starting
in
the
second
year
of
the
2011­
2013
general
phase­
in,
in
effect
creating
a
50­
50%
phase­
in
in
2012
 
2013
for
this
category.
This
then
staggers
the
Tier
4
start
years
by
power
category
as
in
past
tiers:
2011
for
engines
at
or
above
175
hp,
2012
for
75
 
175
hp
engines,
and
2013
for
25
 
75
hp
engines
(
for
which
no
NO
X
adsorber­
based
standard
and
thus
no
percentage
phase­
in
is
being
adopted),
while
still
providing
a
production­
based
phase­
in
for
advanced
NO
X
control
technologies.

Comments
from
the
States
and
environmental
organizations
argued
for
the
completion
of
the
phase­
in
by
the
end
of
2012,
contending
that
technology
progress
for
NO
X
control
in
the
highway
sector
has
been
good
to
date
and
would
support
an
accelerated
phase­
in
in
the
nonroad
sector.
However,
our
assessment
continues
to
show
unique
(
though
surmountable)
challenges
in
adapting
advanced
technologies
to
nonroad
engines,
especially
for
engines
least
like
highway
diesels,
and
it
is
these
engines
that
would
be
most
affected
by
a
truncated
phase­
in
schedule.
Furthermore,
even
if
we
were
to
conclude
that
advanced
technologies
will
be
ready
earlier
than
expected,
we
would
not
be
able
to
move
up
the
start
of
phase­
in
dates
because
these
dates
also
depend
on
low­
sulfur
fuel
availability.
Thus
an
end­
of­
2012
phase­
in
completion
date
would
result
in
phase­
ins
as
short
as
one
year,
thus
degrading
the
industry's
opportunity
to
distribute
the
redesign
workload
and
departing
from
the
pattern
set
by
the
highway
program.
Both
of
these
are
critical
factors
in
our
assessment
that
the
proposed
engine
standards
are
feasible,
and
so
a
change
to
shorter
phase­
ins
would
jeopardize
achievement
of
our
environmental
objectives
for
nonroad
diesels.
Therefore
we
are
not
adopting
the
suggested
earlier
completion
of
the
phase­
in.

As
proposed,
we
are
phasing
in
the
Tier
4
NMHC
standard
for
75
 
750
hp
engines
with
the
NO
X
standard,
as
is
being
done
in
the
highway
program.
Engines
certified
to
the
new
NO
X
requirement
would
be
expected
to
certify
to
the
NMHC
standard
as
well.
The
"
phase­
out"
engines
(
those
not
certified
to
the
new
Tier
4
NO
X
and
NMHC
standards)
would
continue
to
be
certified
to
the
applicable
Tier
3
NMHC+
NO
X
standard.
As
discussed
in
section
II.
B,
we
believe
that
the
NMHC
standard
is
readily
achievable
through
the
application
of
PM
traps
to
meet
the
PM
standard,
which
does
not
involve
such
a
phase­
in.
However,
in
the
highway
program
we
chose
to
29
Note
exceptions
to
the
percent
phase­
in
requirements
during
the
phase­
in
model
years
discussed
in
sections
III.
L
and
III.
M.
These
deal
with
differences
between
a
manufacturer's
actual
and
projected
production
levels,
and
with
incentives
for
early
or
very
low
emission
engine
introductions.

37
phase
in
the
NMHC
standard
with
the
NO
X
standard
to
simplify
the
phase­
in
under
the
percentof
production
approach
taken
there,
thus
avoiding
subjecting
the
"
phase­
out"
engines
to
separate
standards
for
NMHC
and
NMHC+
NO
X
(
which
could
lead
to
increased
administrative
costs
with
essentially
no
different
environmental
result).
The
same
reasoning
applies
here
because,
as
in
the
highway
program,
the
previous­
tier
standards
are
combined
NMHC+
NO
X
standards.
No
commenters
objected
to
this
approach.

Because
of
the
tremendous
variety
of
engine
sizes
represented
in
the
nonroad
diesel
sector,
we
are
finalizing
our
proposed
requirement
that
the
phase­
in
requirement
be
met
separately
in
both
of
the
power
categories
with
a
phase­
in
(
75
 
175
hp
and
175
 
750
hp).
29
For
example,
a
manufacturer
that
produces
1000
engines
for
the
2011
U.
S.
market
in
the
175
to
750
hp
range
would
have
to
demonstrate
compliance
with
the
NO
X
and
NMHC
standards
on
at
least
500
of
these
engines,
regardless
of
how
many
complying
engines
the
manufacturer
produces
in
the
75
 
175
hp
category.
(
Note
however
that
we
are
allowing
averaging
of
emissions
between
these
engine
categories
through
the
use
of
power­
weighted
ABT
program
credits.)
We
believe
that
this
restriction
reflects
the
availability
of
emissions
control
technology,
and
is
needed
to
avoid
erosion
of
environmental
benefits
that
might
occur
if
a
manufacturer
with
a
diverse
product
offering
were
to
meet
the
phase­
in
with
relatively
low
cost
smaller
engines,
thereby
delaying
compliance
on
larger
engines
with
much
higher
lifetime
emissions
potential.
Even
so,
the
horsepower
ranges
for
these
power
categories
are
fairly
broad,
so
this
restriction
allows
ample
freedom
to
manufacturers
to
structure
compliance
plans
in
the
most
cost­
effective
manner.
There
were
no
adverse
comments
on
this
approach.

b.
Special
Considerations
for
the
75
 
175
hp
Category
As
discussed
in
the
proposal,
the
75
 
175
hp
category
of
engines
and
equipment
may
involve
added
workload
challenges
for
the
industry
to
develop
and
transfer
technology.
Though
spanning
only
100
hp,
this
category
represents
a
great
diversity
of
applications,
and
comprises
a
disproportionate
number
of
the
total
nonroad
engine
and
machine
models.
Some
of
these
engines,
though
having
characteristics
comparable
to
many
highway
engines
such
as
turbocharging
and
electronic
fuel
control,
are
not
directly
derived
from
highway
engine
platforms
and
so
are
likely
to
require
more
development
work
than
larger
engines
to
transfer
emission
control
technology
from
the
highway
sector.
Furthermore,
the
engine
and
equipment
manufacturers
have
greatly
varying
market
profiles
in
this
category,
from
focused
one­
or
two­
product
offerings
to
very
diverse
product
lines
with
a
great
many
models.

Therefore,
in
addition
to
the
flexibility
provided
through
the
phase­
in
mechanism,
we
proposed
two
optional
measures
to
provide
added
flexibility
in
implementing
the
Tier
4
NO
X
38
standards,
while
keeping
a
priority
on
bringing
PM
emissions
control
into
this
diverse
power
category
as
quickly
as
possible.
First,
we
proposed
to
allow
manufacturers
to
use
NMHC+
NO
X
credits
generated
by
any
Tier
2
engines
over
50
hp
(
in
addition
to
any
other
allowable
credits)
to
demonstrate
compliance
with
the
Tier
4
requirement
for
75
 
175
hp
engines
in
2012,
2013,
and
2014
only.
Second,
we
proposed
allowing
a
manufacturer
to
instead
demonstrate
compliance
with
a
reduced
phase­
in
requirement
of
25%
for
NO
X
and
NMHC
in
each
of
2012,
2013,
and
the
first
9
months
of
2014.
Full
compliance
(
100%
phase­
in)
with
the
Tier
4
standards
would
have
needed
to
be
demonstrated
beginning
October
1,
2014.

Engine
manufacturers
reinforced
the
points
we
made
in
the
proposal
regarding
added
workload
challenges
for
this
diverse
category
of
engines
and
machines.
However,
they
suggested
that
the
first
of
the
proposed
options
to
address
these
challenges
(
allowing
use
of
Tier
2
credits)
is
not
likely
to
be
used
due
to
a
lack
of
available
Tier
2
credits,
and
therefore
should
be
dropped,
and
that
the
second
option
(
allowing
a
slower
phase­
in)
provided
too
short
a
stability
period,
and
should
be
modified
to
delay
final
compliance
by
an
additional
3
months,
to
December
31,
2014
or
January
1,
2015.
In
addition
to
describing
the
very
large
redesign
workload,
they
pointed
out
that
engines
and
machines
in
this
category
typically
do
not
have
a
model
year
that
differs
from
the
calendar
year,
and
so
the
substantial
changes
required
for
Tier
4
compliance
in
October
2014
could
force
the
need
to
change
the
product
for
all
of
2014,
effectively
shortening
the
phase­
in
to
two
years.
One
manufacturer
argued
that
the
compliance
date
for
the
75
 
100
hp
engines
in
this
category
should
be
delayed
an
additional
year,
to
2016,
and
that
the
start
of
the
phase­
in
for
these
engines
should
be
likewise
delayed
from
2012
to
2013.

We
do
not
feel
that
the
first
option
(
allowing
use
of
Tier
2
credits)
should
be
dropped,
as
it
provides
an
alternative
flexibility
mechanism
for
a
power
category
in
which
flexibility
is
clearly
important,
and
is
environmentally
helpful
as
it
provides
an
option
for
manufacturers
to
achieve
NO
X
emission
reductions
earlier
than
under
the
second
option.
By
providing
an
opportunity
to
use
Tier
2
credits
in
the
75
 
175
hp
category,
it
coordinates
well
with
the
Tier
2
credit
use
opportunity
we
are
providing
for
the
50
 
75
hp
engines
meeting
the
2008
PM
standard
(
see
section
III.
A),
and
allows
for
coordinated
redesign
and
credit
use
planning
by
a
manufacturer
over
this
wide
power
range
over
many
years.
Nonetheless,
recognizing
that
the
second
option
may
be
more
attractive
to
manufacturers,
and
considering
the
comments
they
provided
on
it,
we
have
concluded
that
a
three
month
phase­
in
extension
until
the
end
of
2014
is
warranted
to
address
the
workload
burden
and
to
align
product
cycle
dates.
Thus
we
are
adopting
the
December
31,
2014
implementation
date
suggested
in
comments
for
completion
of
the
75
 
175
hp
engine
phase­
in.

We
do
not
agree
that
an
additional
year
of
delay
is
appropriate
for
the
75
 
100
hp
engines
in
this
category.
The
comment
expressing
interest
in
our
doing
so
did
not
provide
any
basis
for
it
in
technological
feasibility
or
in
workload
burden,
and
we
do
not
see
any
basis
for
it
ourselves.

Therefore,
we
are
adopting
both
of
the
proposed
optional
measures
for
the
75
 
175
hp
engine
phase­
in,
except
that
in
the
second
option,
full
compliance
(
100%
phase­
in)
with
the
Tier
4
standards
will
need
to
be
demonstrated
beginning
December
31,
2014.
As
proposed,
30
See
the
recently
published
"
Highway
Diesel
Progress
Review
Report
2,"
EPA420­
R­
04­
004,

available
at
http://
www.
epa.
gov/
otaq/
diesel.
htm#
progreport2.

39
manufacturers
using
this
reduced
phase­
in
option
will
not
be
allowed
to
generate
NO
X
credits
from
engines
in
this
power
category
in
2012,
2013,
and
2014,
except
for
use
in
averaging
within
the
75
 
175
hp
category
(
that
is,
no
banking
or
trading,
or
averaging
with
engines
in
other
power
categories).
We
believe
that
this
restriction
on
credit
use
is
appropriate,
considering
that
larger
engine
categories
will
be
required
to
demonstrate
a
substantially
greater
degree
of
compliance
with
the
0.30
g/
bhp­
hr
NO
X
standard
several
years
earlier
than
engines
built
under
this
option.
As
the
purpose
of
this
option
is
to
aid
manufacturers
in
implementing
Tier
4
NO
X
standards
for
this
challenging
power
category,
we
do
not
want
any
manufacturers
who
might
be
capable
of
building
substantially
greater
numbers
of
cleaner
engines
to
use
this
option
as
an
easy
and
copious
source
of
credits
(
owing
to
its
slower
phase­
in
of
stringent
standards)
that
in
turn
can
be
used
to
delay
building
clean
engines
in
other
categories
or
model
years.

c.
Alternative
Phase­
In
Standards
To
ensure
that
Tier
4
engine
development
is
able
to
take
maximum
advantage
of
highway
diesel
technology
advances,
we
proposed
to
adopt
nonroad
diesel
provisions
in
the
averaging,
banking,
and
trading
program
that
would
parallel
the
heavy­
duty
highway
engine
program's
"
split
family
provisions"
(
see
68
FR
28470,
May
23,
2003).
In
essence,
these
allow
a
manufacturer
to
declare
an
engine
family
during
the
phase­
in
years
that
is
certified
at
NO
X
levels
roughly
midway
between
the
phase­
out
standard
and
phase­
in
standard,
without
the
complication
of
tracking
credit
generation
and
use.
Because
they
constitute
a
calculational
simplification
of
the
emissions
averaging
provisions,
these
split
family
provisions
do
not
result
in
a
loss
in
environmental
benefits
compared
to
what
the
phase­
in
can
achieve.

The
nonroad
proposal
also
included
specific
emission
levels
for
these
split
families,
rather
than
just
describing
how
they
are
calculated.
Commenters
suggested
that
we
go
one
step
further
still
and
express
these
levels
as
alternative
standards.
They
argued
that
this
would
facilitate
attempts
at
harmonizing
standards
globally,
especially
for
standards­
setting
bodies
such
as
the
European
Commission
that
do
not
have
emissions
averaging
programs.
We
are
also
aware
that
most
manufacturers
of
highway
diesel
engines
are
now
planning
to
comply
with
our
2007
standards
using
this
emissions
averaging
approach,
increasing
the
significance
of
comments
on
the
topic
from
nonroad
engine
manufacturers,
many
of
whom
also
make
highway
engines.
30
After
carefully
considering
the
issues
involved,
we
agree
that
the
proposed
approach
lends
itself
to
expression
in
terms
outside
of
the
averaging,
banking,
and
trading
program
and
that
it
makes
sense
to
do
so.
We
are
creating
such
an
alternative
in
the
final
regulations
accordingly.
These
alternative
standards
do
not
substantively
change
our
Tier
4
program
from
what
we
proposed,
but
rather
respond
to
manufacturers'
suggestions
for
administrative
simplifications
to
what
is
essentially
an
averaging­
based
flexibility
option
in
demonstrating
compliance
with
the
percent­
of­
production
NO
X
phase­
in.
The
alternative
NO
X
phase­
in
standards
are
shown
in
table
40
II.
A­
3.
They
apply
only
during
the
NO
X
phase­
in
years.
Manufacturers
may
use
both
approaches
within
a
power
category
if
desired,
certifying
some
engines
to
the
alternative
standards,
with
the
rest
subject
to
the
phase­
in
percentage
requirement.
Note
that
engines
under
75
hp
subject
to
Tier
4
NO
X
standards
do
not
have
an
alternative
standard
because
they
do
not
have
a
NO
X
phasein
and
engines
over
750
hp
do
not
have
an
alternative
standard
because
of
the
separate
standards
we
are
adopting
for
these
engines
(
explained
in
section
II.
A.
4).

Table
II.
A­
3.
 
Tier
4
Alternative
NOX
Phase­
in
Standards
(
g/
bhp­
hr)

Engine
Power
NO
X
Standard
(
g/
bhp­
hr)

75

hp
<
175
(
56

kW
<
130)
1.7
a
175

hp

750
(
130

kW

560)
1.5
Notes:
a
Under
the
option
identified
in
footnote
b
of
table
II.
A­
2,
by
which
manufacturers
may
meet
an
alternative
phase­
in
requirement
of
25/
25/
25%
in
2012,
2013,
and
2014
through
December
30,
the
corresponding
alternative
NOX
standard
is
2.5
g/
bhp­
hr.

The
engines
certified
under
these
standards
will
of
course
also
need
to
meet
the
Tier
4
PM
and
crankcase
control
requirements
that
take
effect
for
all
engines
in
the
first
phase­
in
year.
They
will
also
need
to
comply
with
all
Tier
4
provisions
that
would
apply
to
phase­
in
engines,
including
the
0.14
g/
bhp­
hr
NMHC
standard
and
the
NTE
and
transient
test
requirements
for
all
pollutants.
We
recognize
that
this
differs
from
what
is
required
under
the
phase­
in
approach,
in
which
these
requirements
would
not
apply
to
the
50%
of
engines
categorized
as
"
phase­
out"
engines.
However,
under
the
alternative
standards
approach,
what
would
have
been
two
different
engine
families
(
one
meeting
phase­
in
requirements
and
one
meeting
phase­
out
requirements,
with
NO
X
and
PM
emissions
averaging
allowed
between
them
under
the
ABT
provisions)
are
replaced
by
a
single
engine
family
meeting
the
one
set
of
alternative
standards.
Therefore
all
of
the
engines
in
this
family
must
by
default
meet
the
phase­
in
requirements
for
provisions
that
lack
any
sort
of
averaging
mechanism
(
NMHC
standard,
NTE,
etc).
As
a
result,
any
manufacturer
choosing
to
design
to
the
alternative
standards
rather
than
using
the
phase­
in
approach
provides
some
additional
environmental
benefit
as
an
indirect
result
of
choosing
this
approach.

We
also
believe
that
this
alternative
standards
provision
makes
appropriate
a
further
adjustment
to
the
NO
X
phase­
in
scheme
to
better
preserve
both
the
advanced
technology
phase­
in
approach,
for
those
manufacturers
choosing
that
compliance
path,
and
the
alternative
standards
approach,
for
those
choosing
that
path.
Under
the
proposal,
the
provision
for
certifying
a
split
engine
family
at
a
pre­
designated
NO
X
level
would
not
allow
credit
generation
by
or
credit
use
on
engines
in
the
split
family
(
other
than
for
averaging
within
the
family).
This
was
consistent
with
our
goal
of
providing
a
simple,
single
average
NO
X
standard
level
for
the
family,
equivalent
to
arbitrarily
designating
a
portion
of
the
engines
in
the
family
as
"
phase­
out"
engines
(
credit
41
generators)
and
the
rest
as
"
phase­
in"
engines
(
credit
users)
with
a
net
credit
balance
of
zero,
while
avoiding
the
burden
of
actually
calculating
and
tracking
credits.
This
was
also
consistent
with
our
approach
under
the
2007
highway
engine
program
from
which
this
concept
is
derived.

However,
because
this
split
family
provision
has
evolved
into
a
set
of
alternative
standards,
there
is
no
longer
a
need
to
prohibit
the
generation
and
use
of
ABT
credits
for
these
engines
to
preserve
a
de
facto
net
zero
credit
balance,
and
so,
considering
that
it
is
also
not
environmentally
detrimental,
we
believe
it
is
appropriate
to
allow
credit
use
and
generation
for
these
engines
as
for
other
engines.
A
consequence
of
doing
so,
consistent
with
all
of
our
ABT
programs,
is
the
adoption
of
NO
X
FEL
caps
for
these
engines.
To
maintain
the
character
of
this
compliance
path
as
producing
engines
during
the
phase­
in
years
that
emit
at
NO
X
levels
which
are
roughly
averaged
between
Tier
3
and
final
Tier
4
levels,
we
are
setting
NO
X
FEL
caps
for
these
engines
at
levels
reasonably
close
to
the
alternative
standards.
(
See
section
III.
A
for
details.)
Because
we
are
also
maintaining
the
original
phase­
in/
phase­
out
compliance
path,
a
manufacturer
wishing
to
build
engines
with
NO
X
levels
higher
than
these
FEL
caps,
at
or
approaching
the
Tier
3
levels,
could
still
do
so;
in
fact
these
would
in
actuality
fit
the
description
of
a
phase­
out
engine.
This
manufacturer
would
also,
of
course,
have
to
produce
a
corresponding
number
of
phase­
in
engines
meeting
the
aftertreatment­
based
Tier
4
NO
X
standards.

We
also
observe
that
the
creation
of
alternative
standards
provides
the
opportunity
to
adjust
the
phase­
in/
phase­
out
provisions
so
as
to
reinforce
their
focus
on
introducing
highefficiency
NO
X
aftertreatment
technology
during
the
phase­
in
years,
which
is,
of
course,
their
aim.
We
are
doing
this
by
setting
NO
X
family
emission
limit
(
FEL)
caps
for
phase­
in
engines
at
the
same
low
levels
as
for
Tier
4
engines
produced
in
the
post­
phase­
in
years.
(
Again,
see
section
III.
A
for
details.)
Although
the
engine
manufacturers
indicated
in
their
comments
that
they
did
not
believe
it
likely
that
anyone
would
choose
this
phase­
in/
phase­
out
compliance
path,
we
believe
that
preserving
it
and
focusing
it
on
encouraging
very
low­
NO
X
engines
as
early
as
possible
provides
a
potentially
useful
and
environmentally
desirable
alternative
path.
Thus
these
two
concepts
have
been
developed
to
provide
complementary
compliance
paths
obtaining
equivalent
overall
NO
X
reductions,
one
focused
on
phasing
in
high­
efficiency
NO
X
aftertreatment
and
the
other
on
achieving
NO
X
control
for
all
subject
engines
during
the
phase­
in
years
at
an
average
level
between
the
Tier
3
and
final
Tier
4
standards
levels.

3.
Standards
for
Smaller
Engines
a.
Engines
under
25
hp
We
are
finalizing
the
Tier
4
program
we
proposed
for
engines
under
25
hp.
In
the
proposal
we
presented
our
view
that
standards
based
on
the
use
of
PM
filters
should
not
be
set
at
this
time
for
the
very
small
diesel
engines
below
25
hp.
We
also
discussed
our
plan
to
reassess
the
appropriate
long­
term
standards
in
a
technology
review.
However,
for
the
nearer­
term,
we
concluded
that
other
proven
PM­
reducing
technologies
such
as
diesel
oxidation
catalysts
and
engine
optimization
could
be
applied
to
engines
under
25
hp.
Accordingly,
we
proposed
Tier
4
42
PM
standards
to
take
effect
beginning
in
2008
for
these
engines
based
on
use
of
these
technologies.

In
contrast
to
our
proposals
for
other
engine
categories,
the
proposed
Tier
4
standards
for
this
category
elicited
very
little
comment
from
the
engine
manufacturers
other
than
an
expression
of
support
for
deferring
consideration
of
any
more
stringent
standards
pending
results
of
a
future
technology
review.
The
States
and
environmental
organizations
expressed
disappointment
that
EPA
had
not
proposed
more
stringent
standards
for
these
engines,
given
the
very
large
number
of
these
engines
in
the
field
and
the
significant
risk
they
pose
due
to
individuals'
exposure
to
diesel
PM
and
air
toxics.
They
urged
more
stringent
2008
PM
standards
and
the
adoption
of
standards
obtaining
emission
reductions
of
90%
or
more
by
the
end
of
2012.
Emissions
control
manufacturers
argued
that
more
stringent
2008
standards
based
on
the
use
of
more
efficient
oxidation
catalysts
are
feasible.

As
discussed
in
section
II.
B.
4,
we
continue
to
believe
that
the
standards
we
proposed
for
engines
under
25
hp
are
feasible,
and
commenters
in
the
nonroad
diesel
industry
provided
no
comments
to
the
contrary.
Our
reasons
for
not
proposing
more
stringent
Tier
4
standards
for
these
engines
based
on
the
use
of
PM
filters
and
NO
X
aftertreatment
were
mainly
focused
on
the
cost
of
equipping
these
relatively
low
cost
engines
with
such
devices,
especially
considering
the
prerequisite
need
for
electronic
fuel
control
systems
to
facilitate
regeneration.
The
comments
supporting
more
stringent
standards
were
not
convincing,
as
they
did
not
address
these
cost
issues.
However,
we
do
agree
that
these
small
engines
likely
have
a
large
impact
on
human
health,
and,
as
discussed
in
section
VIII.
A,
we
are
reaffirming
the
plan
we
described
in
the
proposal
to
reassess
the
appropriate
long­
term
standards
for
these
engines
in
a
technology
review
to
take
place
in
2007.
We
will
set
more
stringent
standards
for
these
engines
at
that
time,
if
appropriate.

We
also
disagree
with
comments
supporting
more
stringent
2008
standards
that
would
require
the
use
of
diesel
oxidation
catalysts
on
all
small
engines.
Although
we
agree
that
these
catalysts
can
be
applied
so
as
to
achieve
emission
reductions
on
some
small
engines,
the
emissions
performance
data
we
have
analyzed
do
not
support
our
setting
a
more
stringent
standard.
Section
4.1.5
of
the
RIA
summarizes
such
data
showing
a
very
wide
range
of
engine­
out
PM
emissions
in
this
power
category.
Applying
oxidation
catalyst
technology
to
these
engines,
though
capable
of
some
PM
reduction
if
properly
designed
and
matched
to
the
application,
is
limited
by
sulfur
in
the
diesel
fuel.
Specifically,
precious­
metal
oxidation
catalysts
(
which
have
the
greatest
potential
for
reducing
PM)
can
oxidize
the
sulfur
in
the
fuel
and
form
particulate
sulfates.
Even
with
the
500
ppm
maximum
sulfur
fuel
available
after
2007,
the
sulfate
production
potential
is
large
enough
to
limit
what
can
be
done
to
set
more
stringent
2008
PM
standards
through
the
use
of
these
catalysts.
The
15
ppm
maximum
sulfur
fuel
available
after
2010
will
greatly
improve
the
potential
for
use
of
oxidation
catalysts,
but
as
we
discussed
above,
we
believe
that
the
much
larger
potential
reduction
afforded
by
PM
filter
technology
warrants
our
waiting
until
the
technology
review
in
2007
to
evaluate
the
appropriate
long­
term
standards
for
these
engines.
See
section
II.
B.
5
and
RIA
section
4.1.5
for
further
discussion.
43
When
implemented,
the
Tier
4
PM
standard
and
related
provisions
we
are
adopting
today
for
engines
under
25
hp
will
yield
an
in­
use
PM
reduction
of
over
50%
for
these
engines,
and
large
reductions
in
toxic
hydrocarbons
as
well.
Achieving
these
emission
reductions
is
very
important,
considering
the
fact
that
many
of
these
smaller
engines
operate
in
populated
areas
and
in
equipment
without
closed
cabs­­
in
mowers,
portable
electric
power
generators,
small
skid
steer
loaders,
and
the
like.

We
are
also
adopting
the
alternative
compliance
option
that
we
proposed
for
air­
cooled,
direct
injection
engines
under
11
hp
that
are
startable
by
hand,
such
as
with
a
crank
or
recoil
starter.
As
we
explained
in
the
proposal,
the
alternative
is
justified
due
(
among
other
things)
to
these
engines'
need
for
loose
design
fit
tolerances,
their
small
cylinder
displacement
and
bore
sizes,
and
the
difficulty
in
obtaining
components
for
them
with
tight
enough
tolerances
(
68
FR
28363,
May
23,
2003).
This
alternative
allows
manufacturers
of
these
engines
to
delay
Tier
4
compliance
until
2010,
and
in
that
year
to
certify
them
to
a
PM
standard
of
0.45
g/
bhp­
hr,
rather
than
to
the
0.30
g/
bhp­
hr
PM
standard
applicable
beginning
in
2008
to
the
other
engines
in
this
power
category.
As
proposed,
engines
certified
under
this
alternative
compliance
requirement
will
not
be
allowed
to
generate
credits
as
part
of
the
ABT
program,
although
credit
use
by
these
engines
will
still
be
allowed.

We
received
no
adverse
comments
on
this
proposed
alternative
for
qualifying
engines
under
11
hp.
Euromot
commented
that
there
are
hand­
startable
engines
in
the
11
 
25
hp
range,
and
that
we
should
extend
the
alternative
compliance
option
to
these
engines
as
well.
However,
hand­
startability
is
not
the
sole
defining
feature
of
engines
for
which
we
established
this
alternative.
Rather,
the
alternative
is
for
a
class
of
engines
typified
by
a
combination
of
characteristics
(
very
small,
air­
cooled,
direct
injection,
hand­
startable),
which
give
rise
to
the
potential
technical
difficulties
noted
above.
To
extend
the
alternative
to
other
engines
simply
because
they
have
a
hand­
start
is
not
justified,
because
they
do
not
share
these
technical
difficulties
(
or
do
not
share
them
to
the
same
degree).
Such
an
extension
could
also
potentially
encourage
manufacturers
of
the
many
models
of
these
larger
engines
to
market
a
hand­
start
option
simply
to
avoid
more
stringent
standards.

b.
Standards
for
25
 
75
hp
Engines
We
proposed
a
0.22
g/
bhp­
hr
PM
standard
for
25
 
75
hp
engines,
to
take
effect
in
2008.
We
also
proposed
a
filter­
based
0.02
g/
bhp­
hr
PM
standard
for
these
engines,
to
take
effect
in
2013,
the
year
in
which
filter­
based
technology
for
these
engines
is
expected
to
be
applicable
on
a
widespread
basis
(
see
section
II.
A.
1).
Also
in
2013,
the
25
 
50
hp
engines
would
be
subject
to
the
3.5
g/
bhp­
hr
NMHC+
NO
X
standard
already
adopted
for
50
 
75
hp
engines
(
taking
effect
in
2008
as
part
of
Tier
3).
We
are
adopting
all
of
these
proposed
standards
in
this
final
rule.

The
2008
PM
standard
for
these
engines
should
maximize
reduction
of
PM
emissions
using
technology
available
in
that
year.
We
believe
that
the
2008
PM
standard
is
feasible
for
these
engines,
based
on
the
same
engine
or
oxidation
catalyst
technologies
feasible
for
engines
under
25
31
"
Nonroad
Diesel
Emissions
Standards
Staff
Technical
Paper,"
EPA420­
R­
01­
052,
October
2001.

44
hp
in
2008,
following
the
introduction
of
nonroad
diesel
fuel
with
sulfur
levels
reduced
below
500
ppm.
We
expect
in­
use
PM
reductions
for
these
engines
of
over
50%
(
and
large
reductions
in
toxic
hydrocarbons
as
well)
over
the
five
model
years
this
standard
would
be
in
effect
(
2008
 
2012).
These
engines
will
constitute
a
large
portion
of
the
in­
use
population
of
nonroad
diesel
engines
for
many
years
after
2008.
Although
we
are
finalizing
the
2013
standards
for
25
 
75
hp
engines
today,
we
are
also
reaffirming
our
commitment
to
conducting
a
technology
review
for
these
standards
in
2007.
This
planned
review
is
discussed
in
section
VIII.
A.
Additional
discussion
of
our
feasibility
assessment
for
the
2008
and
2013
standards
can
be
found
in
section
II.
B.
4
and
RIA
section
4.1.4.

In
comments,
emissions
controls
manufacturers
argued
that
more
stringent
2008
standards
for
PM
and
NMHC
based
on
the
use
of
more
efficient
oxidation
catalysts
are
feasible
and
should
be
adopted.
Environmental
organizations
argued
that
PM
and
NO
X
standards
for
2008
should
be
set
at
more
stringent
levels,
based
on
the
use
of
oxidation
catalysts
and
improved
engine
optimization.
The
California
Air
Resources
Board
argued
for
more
stringent
2008
standards
for
HC+
NO
X,
PM
and
toxics,
based
on
the
use
of
oxidation
catalysts.

We
disagree
with
the
comments
calling
for
more
stringent
2008
standards
than
proposed
for
25
 
75
hp
engines,
based
on
the
use
of
diesel
oxidation
catalysts.
The
standards
we
proposed
and
are
adopting
for
these
engines
pull
ahead
sizeable
PM
reductions
starting
three
years
ahead
of
the
earliest
PM
filter­
based
standards
for
any
engine
size.
The
pull­
ahead
standard
level
balances
early
reductions
with
the
need
to
ensure
that
the
PM
filter­
based
standards
and
Tier
3
NMHC+
NO
X
standards
are
not
jeopardized
by
an
overemphasis
on
early
reductions.
Although
we
agree
that
oxidation
catalysts
can
be
applied
to
these
engines,
the
emissions
performance
data
we
have
analyzed
do
not
support
our
setting
a
more
stringent
standard,
for
the
same
reasons
described
above
in
section
II.
A.
3.
a
for
engines
under
25
hp.
Refer
to
section
II.
B.
4
and
to
section
4.1.4
of
the
RIA
for
additional
discussion.
For
a
discussion
of
comments
opposed
to
new
standards
in
2008,
see
sections
II.
A.
1
and
II.
B
of
this
preamble.

We
also
do
not
agree
that
more
stringent
NO
X
requirements
based
on
improved
engine
optimization
are
appropriate
for
these
engines
in
2008.
In
2001
we
reviewed
and
confirmed
the
previously
set
NMHC+
NO
X
emission
standards
that
will
be
in
effect
for
these
engines
during
the
time
frame
in
question.
31
Because
of
the
focus
we
are
putting
on
achieving
large
PM
reductions
from
these
engines
as
early
as
possible,
we
felt
that
it
was
important
to
strike
a
balance
between
PM
and
NO
X
control.
As
a
result,
we
did
not
propose
more
stringent
NO
X
standards
for
50
 
75
hp
engines,
and
we
proposed
to
apply
the
3.5
g/
bhp­
hr
NMHC+
NO
X
standard
to
25­
50
hp
engines
in
2013
because
this
is
the
year
in
which
the
PM
filter­
based
standard
is
being
implemented.
Requiring
new
NO
X
controls
for
these
engines
earlier
than
2013
would
add
a
third
redesign
step
to
those
already
called
for
in
2008
and
2013.
This
would
add
a
potentially
45
unacceptable
amount
of
redesign
workload,
to
a
point
that
it
could
jeopardize
our
objective
of
bringing
stringent
PM
control
to
these
engines
as
early
as
possible.

Consistent
with
the
proposal,
we
are
not
setting
more
stringent
NO
X
standards
for
engines
below
75
hp
at
this
time
based
on
the
use
of
NO
X
aftertreatment.
As
discussed
in
section
4.1.2.3
of
the
RIA,
a
high
degree
of
complexity
and
engine/
aftertreatment
integration
will
be
involved
in
applying
NO
X
adsorber
technology
to
nonroad
diesel
engines.
The
similarity
of
larger
nonroad
engines
(
above
75
hp)
to
highway
diesel
engines,
which
will
provide
the
initial
experience
base
for
this
integration
process,
is
key
to
our
assessment
that
NO
X
adsorbers
are
feasible
for
these
engines.
On
the
other
hand,
although
engines
under
75
hp
are
gradually
increasing
in
sophistication
over
time,
the
accumulation
of
experience
with
designing
and
operating
these
engines
with
more
advanced
technology
clearly
lags
significantly
behind
the
sizeable
experience
base
already
developed
for
larger
engines.
At
this
point,
we
are
unable
to
forecast
how
quickly
adequate
experience
may
accrue.
Because
this
experience
is
crucial
to
ensuring
the
successful
integration
of
the
engines
with
NO
X
adsorber
technology,
we
are
not
adopting
NO
X
adsorberbased
standards
for
engines
under
75
hp
in
this
final
rule.
Rather,
as
discussed
in
section
VIII.
A,
we
plan
to
undertake
a
technology
assessment
in
the
2007
time
frame
which
would
evaluate
the
status
of
engine
and
emission
control
technologies,
including
NO
X
controls,
for
engines
less
than
75
hp.

As
described
in
section
II.
A.
1.
a,
we
are
providing
two
PM
standard
compliance
options
to
engine
manufacturers
for
50­
75
hp
engines.
As
part
of
this,
we
also
proposed
a
measure
to
ensure
that
it
would
not
be
abused
by
equipment
manufacturers
who
use
engines
that
do
not
meet
the
PM
pull­
ahead
standard
in
2008­
2011,
but
who
then
switch
engine
suppliers
to
avoid
PM
filter­
equipped
engines
in
2012
as
well
(
68
FR
28360,
May
23,
2003).
We
proposed
that
an
equipment
manufacturer
making
a
product
with
engines
not
meeting
the
pull­
ahead
standard
in
any
of
the
years
2008
 
2011
must
use
engines
in
that
product
in
2012
meeting
the
0.02
g/
bhp­
hr
PM
standard;
that
is,
the
equipment
manufacturer
would
have
to
use
an
engine
from
the
same
engine
manufacturer
or
from
another
engine
manufacturer
choosing
the
same
compliance
option.
We
also
solicited
comment
on
possible
alternative
solutions
using
a
numerical
basis,
describing
an
example
that
would
require
the
percentage
of
50
 
75
hp
machines
equipped
with
PM
filters
in
2012
to
be
no
less
than
the
same
percentage
of
50
 
75
hp
machines
produced
with
non­
pull­
ahead
engines
in
2008
 
2011.

The
Engine
Manufacturers
Association
(
EMA)
and
Deere
commented
on
the
unenforceability
of
the
proposed
"
no
switch"
measure
as
part
of
a
broader
objection
to
our
proposal
for
50
 
75
hp
engines.
They
pointed
out
that
changing
equipment
model
designations
could
easily
allow
an
equipment
manufacturer
seeking
to
avoid
PM
filter­
equipped
engines
in
2012
to
declare
a
product
in
this
model
year
a
"
new
product,"
not
the
same
as
the
2008
 
2011
product.
We
have
concluded
that
there
is
indeed
potential
for
this
abuse
to
occur
and,
although
no
one
commented
specifically
on
the
alternative
approach,
we
believe
it
clearly
addresses
this
problem
because
it
does
not
depend
on
product
designations.
32
The
2011
production
is
not
included
in
the
percentage
calculation
to
avoid
the
need
for
post­

2011
confirmation
of
production
volumes
which,
as
it
would
occur
in
2012,
would
be
too
late
to
easily
refocus
2012
production
if
the
confirmed
volumes
differ
from
projections.
It
is
not
likely
that
manufacturers
would
abuse
the
program
by
switching
engine
suppliers
for
this
one
year
of
production.

33
That
is:
[
200/(
1000­
500)]
=
40%;
subtracting
the
5%
margin
then
yields
35%.

46
Therefore,
we
are
adopting
a
provision
to
discourage
engine
switching
based
on
this
alternative
approach.
An
equipment
manufacturer
who
uses
50
 
75
hp
engines
will
have
three
options:

1)
The
manufacturer
may
exclusively
use
engines
certified
to
the
0.22
g/
bhp­
hr
PM
standard
(
including
through
use
of
ABT
credits)
over
the
2008­
2011
period.
This
manufacturer
is
then
free
to
use
any
number
of
50
 
75
hp
engines
not
certified
to
the
0.02
g/
bhp­
hr
standards
in
2012.
2)
The
manufacturer
may
exclusively
use
engines
not
certified
to
the
0.22
g/
bhp­
hr
PM
standard
over
the
2008
 
2011
period.
This
manufacturer
must
then
use
only
50
 
75
hp
engines
that
are
certified
to
the
0.02
g/
bhp­
hr
standards
in
2012
(
including
through
use
of
ABT
credits).
3)
The
manufacturer
may
use
a
mix
of
engines
in
2008
 
2011.
In
this
case,
the
manufacturer
must
calculate
the
percentage
of
50
 
75
hp
engines
used
(
in
U.
S.­
directed
equipment)
over
the
2008
 
2010
period
that
are
not
certified
to
the
0.22
g/
bhp­
hr
PM
pull­
ahead
standard.
Then
the
percentage
of
50
 
75
hp
engines
this
manufacturer
uses
in
2012
that
are
certified
to
the
0.02
g/
bhp­
hr
PM
standard
must
be
no
less
than
this
2008
 
2010
non­
pull­
ahead
percentage
figure
minus
a
5%
margin.
32
As
an
example
of
this
third
option,
consider
an
equipment
manufacturer
who
does
not
use
the
transition
flexibility
provisions
(
described
in
section
III.
B),
and
over
the
2008
 
2010
period
makes
1000
50
 
75
hp
machines
for
use
in
the
U.
S.,
200
(
20%)
of
which
use
engines
not
certified
to
the
0.22
g/
bhp­
hr
standard.
In
2012,
that
manufacturer
must
make
at
least
15%
of
his
50
 
75
hp
machines
for
use
in
the
U.
S.
using
engines
certified
to
the
0.02
g/
bhp­
hr
standard.
We
feel
that
the
5%
margin
is
needed
to
allow
for
some
reasonable
sales
shifts
within
the
manufacturer's
product
offering
over
time,
but
is
small
enough
to
ensure
that
any
possible
advantage
gained
from
selling
higher­
emissions
products
remains
minimal.
Equipment
manufacturers
must
keep
production
records
sufficient
to
prove
compliance.
This
restriction
and
the
percentage
calculation
will
not
apply
to
any
2008
 
2012
engines
at
issue
that
are
being
produced
under
the
equipment
manufacturer
transition
flexibility
provisions
discussed
in
section
III.
B.
For
example,
if
in
addition
to
the
200
engines
in
2008­
2010
not
certified
to
the
0.22
g/
bhp­
hr
standard
in
the
above
example,
this
manufacturer
also
used
500
previous­
tier
engines
in
2008
 
2010
under
the
flexibility
allowance
program,
his
percentage
target
for
PM
filter­
equipped
engines
in
2012
would
be
35%
of
all
the
engines
used
in
2012
that
are
not
previous­
tier
engines
under
the
flexibility
allowance
program.
33
47
4.
Standards
for
Engines
Above
750
hp
We
are
adopting
different
Tier
4
standards
for
over
750
hp
engines
from
those
we
proposed,
and
we
are
also
adopting
different
implementation
dates
for
these
engine
standards,
though
both
the
proposed
and
final
programs
have
as
their
primary
focus
the
implementation
of
high­
efficiency
exhaust
emission
controls
as
quickly
as
possible.
The
approach
being
adopted
reflects
our
careful
review
of
the
technical
issues
presented
by
these
engines.
For
some
of
these
engines,
we
are
accelerating
standards
based
on
the
use
of
aftertreatment
controls.
For
others,
we
are
deferring
a
decision
on
such
aftertreatment­
based
standards.
This
approach
represents
a
feasible
and
efficient
approach
to
redesigning
engines
and
installing
aftertreatment
in
a
coordinated,
orderly
manner
over
a
decade
or
more,
and
will
achieve
major
reductions
in
PM
and
NO
X
from
these
large
diesel
engines.

Under
the
proposal,
all
engines
above
750
hp
were
treated
the
same,
with
a
phase­
in
of
PM
and
NO
X
aftertreatment
technology
that
started
in
2011
and
finished
in
2014.
The
final
standards
are
based
on
our
evaluation
of
the
differing
technical
issues
presented
by
the
two
primary
kinds
of
equipment
in
this
category,
mobile
power
generation
equipment
(
generator
sets)
and
mobile
machinery.
For
both
generator
sets
and
mobile
machinery,
PM
aftertreatment­
based
standards
will
start
in
2015,
with
no
prior
phase­
in.
EPA
is
replacing
the
proposed
phase­
in
with
a
PM
standard
starting
in
2011
that
is
comparable
to
the
overall
level
of
control
that
the
proposed
phase­
in
would
achieve.
Differences
within
these
applications,
however,
call
for
different
approaches
to
the
implementation
of
NO
X
aftertreatment
technology.
For
generator
sets
above
1200
hp,
an
aftertreatment­
based
NO
X
standard
will
start
in
2011,
three
years
earlier
than
the
date
we
proposed
for
full
implementation
of
such
standards.
For
generator
sets
below
1200
hp,
the
same
aftertreatment­
based
NO
X
standard
will
start
in
2015.
As
with
the
PM
standard,
there
is
no
phase­
in.
For
engines
used
in
mobile
machinery,
which
is
assumed
to
include
all
equipment
that
is
not
a
generator
set,
EPA
is
deferring
a
decision
on
setting
aftertreatment­
based
NO
X
standards
to
allow
additional
time
to
evaluate
the
technical
issues
involved
in
adapting
NO
X
adsorber
technology
to
these
applications
and
engines.
However,
EPA
is
adopting
a
NO
X
standard
for
these
engines
starting
in
2011
that
will
achieve
large
NO
X
reductions
by
relying
on
engine­
based
emissions
control
technology.
Consistent
with
the
different
approaches
we
are
taking
to
setting
standards
for
engines
above
and
below
750
hp,
we
are
also
adopting
restrictions
on
ABT
credit
use
between
these
power
categories,
as
described
in
section
III.
A.

Consistent
with
the
approach
we
took
in
previous
standard­
setting
for
these
engines,
we
proposed
that
nonroad
diesels
above
750
hp
be
given
more
lead
time
than
engines
in
other
power
categories
to
fully
implement
Tier
4
standards,
due
primarily
to
the
relatively
long
product
design
cycles
typical
of
these
high­
cost,
low­
sales
volume
engines
and
machines.
Specifically,
we
proposed
that
this
category
of
engines
move
directly
from
Tier
2
to
Tier
4,
and
that
the
Tier
4
PM
standard
be
phased
in
for
these
engines
on
the
same
50­
50­
50­
100%
schedule
as
the
NO
X
and
NMHC
phase­
in
schedule,
over
the
2011
 
2014
model
years.
This
would
provide
engine
manufacturers
with
up
to
8
years
of
design
stability
to
address
concerns
specific
to
this
category.
Although
we
expressed
our
belief
that
these
proposed
provisions
would
enable
the
manufacturers
48
to
meet
proposed
Tier
4
engine
standards,
we
also
acknowledged
concerns
the
manufacturers
had
expressed
to
us,
and
asked
for
comment
on
whether
this
category,
or
some
subset
of
it
defined
by
hp
or
application,
should
have
a
later
phase­
in
start
date,
a
later
phase­
in
end
date,
adjusted
standards,
additional
equipment
manufacturer
transition
flexibility
provisions,
or
some
combination
of
these
(
68
FR
28364,
May
23,
2003).

Comments
from
manufacturers
of
engines
and
equipment
in
this
power
category
expressed
their
widespread
view
that
the
proposed
standards
were
inappropriate
in
critical
respects.
In
addition
to
reiterating
the
need
for
extra
lead
time
due
to
long
product
design
cycles,
they
pointed
to
difficulties
with
aftertreatment
placement,
with
fabrication
of
the
large
filters
that
would
be
needed
for
these
engines,
with
potential
failures
caused
by
uneven
soot
loading
and
regeneration
in
large
filters,
with
stresses
due
to
thermal
gradients
across
large
filters,
and
with
mechanical
stresses
in
mining
applications
with
high
shock
loads.
The
manufacturers
noted
that
aftertreatment­
based
standards
for
NO
X
and
PM
were
feasible
for
engines
used
in
large
mobile
power
generators.
However,
manufacturers
did
not
believe
aftertreatment­
based
NO
X
standards
could
be
implemented
in
the
time
frame
proposed
for
engines
used
in
large
mobile
machinery
such
as
bulldozers
and
mine
haul
trucks.
States,
environmental
organizations,
and
manufacturers
of
emissions
controls,
on
the
other
hand,
expressed
support
for
the
standards
we
proposed
for
these
engines.

After
evaluating
these
issues,
EPA
is
adopting
an
approach
that
tailors
the
standards
to
the
circumstances
presented
by
the
different
kinds
of
engines
in
this
power
category.
The
NO
X
standards
we
are
adopting
will
achieve
effective
NO
X
control
by
accelerating
the
proposed
schedule
for
final
NO
X
standards
based
on
high­
efficiency
NO
X
aftertreatment
for
the
largest
generator
sets,
and
by
requiring
engines
in
other
generator
sets
to
also
meet
aftertreatment­
based
NO
X
standards,
although
we
are
delaying
the
implementation
date
for
these
standards
compared
to
the
implementation
schedule
we
proposed.
We
believe
that
NO
X
adsorber
technology
will
be
feasible
for
these
generator
set
engines.
We
also
believe
that
they
may
be
an
especially
attractive
application
for
Selective
Catalytic
Reduction
(
SCR)
technology,
which
relies
on
the
injection
of
urea
into
the
exhaust
stream.
There
are
many
stationary
diesel
generator
sets
using
SCR
today.
Large
mobile
generator
sets,
though
moved
from
location
to
location,
operate
much
like
stationary
units
once
in
place,
with
fuel
(
and
potentially
urea)
delivered
and
replenished
periodically.
See
section
II.
B.
3
for
further
discussion.

For
equipment
other
than
generator
sets,
we
are
deferring
a
decision
on
setting
aftertreatment­
based
NO
X
standards
to
allow
additional
time
to
evaluate
the
technical
issues
involved
in
adapting
NO
X
control
technology
to
these
applications
and
engines.
We
are
still
evaluating
the
issues
involved
for
these
engines
to
achieve
a
more
stringent
NO
X
standard,
and
believe
that
these
issues
are
resolvable.
We
intend
to
continue
evaluating
the
appropriate
longterm
NO
X
standard
for
mobile
machinery
over
750
hp
and
expect
to
announce
further
plans
regarding
these
issues
(
we
are
currently
considering
such
an
action
in
the
2007
time
frame).
The
basis
for
the
0.50
g/
bhp­
hr
NO
X
standard
we
are
adopting
for
generator
sets
over
750
hp
is
discussed
in
section
II.
B.
3.
We
are
also
modifying
the
PM
and
NMHC
standards
we
proposed
(
as
49
well
as
certain
implementation
dates
for
these
provisions),
and
modifying
our
proposed
approach
to
ensuring
transient
emissions
control
for
these
engines
(
discussed
in
section
III.
F).
The
Tier
4
standards
for
engines
over
750
hp
are
shown
in
table
II.
A­
4.

Table
II.
A­
4.
 
Tier
4
Standards
for
Engines
Over
750
hp
(
g/
bhp­
hr)

engines
used
in:
2011
2015
PM
NO
X
NMHC
PM
NO
X
NMHC
generator
sets

1200
hp
0.075
2.6
0.30
0.02
0.50
0.14
generator
sets
>
1200
hp
0.075
0.50
0.30
0.02
no
new
standard
0.14
all
other
equipment
0.075
2.6
0.30
0.03
no
new
standard
0.14
Unlike
NO
X
control
technology,
we
believe
that
the
more
advanced
state
of
PM
filter
technology
development
today
makes
their
availability
for
these
engines
by
2015,
with
over
ten
years
of
development
lead
time,
more
certain,
and
so
we
are
setting
PM
standards
for
both
mobile
machinery
and
generator
sets
based
on
use
of
this
technology.
We
note
in
section
II.
B.
3
that
achieving
durable
PM
filter
designs
for
these
large
applications
will
likely
require
the
use
of
wire
mesh
filter
technology
rather
than
the
somewhat
more
efficient
wall
flow
ceramic­
based
technology
applicable
to
smaller
engines,
justifying
the
somewhat
higher
level
for
the
2015
PM
standards
shown
in
table
II.
A­
4
(
0.03
or
0.02
g/
bhp­
hr
compared
to
0.01
g/
bhp­
hr).
Section
II.
B.
3
also
contains
discussion
of
our
bases
for
the
other
Tier
4
standard
levels
in
this
category.
We
believe
that
the
2015
implementation
year
(
versus
the
proposed
2014
date
for
the
fully
phased­
in
standard)
is
necessary
to
allow
development
of
the
requisite
technologies
for
these
large
engines,
and
to
deal
with
the
redesign
workload
Tier
4
will
create
for
the
many
engine
and
equipment
models
in
this
category
which,
as
noted,
typically
have
very
low
production
volumes
and
long
product
cycles.

For
the
purpose
of
determining
which
nonroad
engines
are
subject
to
the
generator
set
standards,
we
are
defining
a
generator
set
engine
as:
"
An
engine
used
primarily
to
operate
an
electrical
generator
or
alternator
to
produce
electric
power
for
other
applications."
This
definition
makes
it
clear
that
generator
set
engines
do
not
include
engines
used
in
machines
such
as
mine
trucks
that
do
mechanical
work
but
that
employ
engine­
powered
electric
motors
to
propel
the
machine,
but
they
do
include
engines
in
nonroad
equipment
for
which
the
primary
purpose
is
to
generate
electric
power,
even
if
the
machine
is
also
self­
propelled.

Similar
to
other
power
categories,
we
proposed
a
50%
phase­
in
to
the
final
Tier
4
PM,
NO
X
and
NMHC
standards,
with
opportunity
to
average
PM
and
NO
X
between
phase­
in
and
phase­
out
engines
in
the
2011­
2013
phase­
in
years
via
the
ABT
program.
Because
in
this
rule
we
are
no
longer
phasing
in
to
a
final
NO
X
standard
for
some
engines
over
750
hp,
it
no
longer
makes
50
sense
to
express
the
2011
standards
for
these
engines
in
this
manner.
Instead
we
are
setting
brake­
specific
emission
standards
effective
in
2011.
Furthermore,
to
avoid
further
complicating
an
already
complex
standards
structure,
we
are
adopting
this
pattern
for
the
entire
category,
even
with
engines
such
as
those
used
in
generator
sets
for
which
the
standards
could
still
be
expressed
as
a
percent
phase­
in
to
final
standards.
Except
for
the
pull­
ahead
of
the
long­
term
NO
X
standard
for
large
generator
sets
(
which
will
increase
the
environmental
benefit
compared
to
the
proposal),
these
2011
PM
and
NO
X
standards
essentially
correspond
to
averaged
standards
under
a
50%
phase­
in
to
aftertreatment­
based
standards,
hence
our
conclusion
that
the
Tier
4
program
will
provide
a
level
of
control
in
2011
that
is
substantially
equivalent
to
that
of
the
proposal.
In
addition,
PM
and
NO
X
emissions
averaging
through
the
ABT
program
will
allow
a
manufacturer
to
comply
by
phasing
in
aftertreatment
technologies
as
in
the
proposed
program,
should
they
desire
to
do
so.
Although
there
is
no
such
averaging
program
for
NMHC,
the
2011
NMHC
standard
can
be
achieved
without
the
use
of
advanced
aftertreatment
(
as
explained
in
section
II.
B.
3),
thus
helping
to
enable
a
manufacturer
to
pursue
this
compliance
strategy
if
desired.

This
approach
involving
separate
2011
and
2015
standards
is
comparable
to
the
proposed
percent
phase­
in
approach
with
emissions
averaging.
We
believe
that
it
enables
manufacturers
to
redesign
engines
and
equipment
in
a
coordinated,
orderly
manner
over
a
decade
or
more,
and
effectively
gives
targeted
additional
flexibility
to
the
industry.
Given
the
continuing
availability
of
emissions
averaging,
we
do
not
view
this
change
as
the
creation
of
an
additional,
separate
tier
of
standards
compared
to
the
proposal's
phase­
in
of
the
Tier
4
standards.

5.
Establishment
of
New
Power
Categories
We
are
finalizing
our
proposal
to
regroup
the
nine
power
categories
established
for
previous
tiers
into
the
five
Tier
4
power
categories
shown
in
table
II.
A­
1.
As
we
explained
in
the
proposal,
this
regrouping
will
more
closely
match
the
degree
of
challenge
involved
in
transferring
advanced
emissions
control
technology
from
highway
engines
to
nonroad
engines.
The
proposed
choice
of
75
hp
as
the
appropriate
cutpoint
for
applying
aftertreatment­
based
NO
X
control
drew
particular
attention.
In
the
proposal,
we
recognized
that
there
is
not
an
abrupt
power
cutpoint
above
and
below
which
the
highway­
derived
nonroad
engine
families
do
and
do
not
exist,
but
noted
further
that
75
hp
is
a
more
appropriate
cutpoint
to
generally
identify
nonroad
engines
in
Tier
4
that
will
most
likely
be
using
highway­
like
engine
technology
than
either
of
the
closest
previously­
adopted
power
category
cutpoints
of
50
or
100
hp.
Nonroad
diesels
produced
today
with
rated
power
above
75
hp
(
up
to
several
hundred
hp)
are
mostly
variants
of
nonroad
engine
platforms
with
four
or
more
cylinders
and
per­
cylinder
displacements
of
one
liter
or
more.
These
in
turn
are
largely
derived
from
or
are
similar
to
heavy­
duty
highway
engine
platforms.
Even
where
nonroad
engine
models
above
75
hp
are
not
so
directly
derived
from
highway
models,
they
typically
share
many
common
characteristics
such
as
displacements
of
one
liter
per
cylinder
or
more,
direct
injection
fueling,
turbocharging,
and,
increasingly,
electronic
fuel
injection.
These
common
features
provide
key
building
blocks
in
transferring
high­
efficiency
exhaust
emission
control
technology
from
highway
to
similar
nonroad
diesel
engines.
We
therefore
proposed
to
regroup
power
ratings
using
the
75
hp
cutpoint.
51
The
Engine
Manufacturers
Association
and
Euromot,
which
together
represent
the
companies
that
make
all
but
a
tiny
fraction
of
nonroad
diesel
engines
sold
in
the
U.
S.,
expressed
their
support
for
the
75
hp
cutpoint,
as
did
every
individual
engine
manufacturer
who
commented
on
this
subject.
These
companies
generally
endorsed
EPA's
reasoning
that
the
75
hp
level
is
appropriate
to
"
delineate
those
engines
(
and
applications)
for
which
the
application
of
on­
highway
like
NO
X
aftertreatment
technologies
is
not
likely
to
be
feasible
or
practical"
(
EMA
Comments
p.
10).

However,
the
Association
of
Equipment
Manufacturers
(
AEM)
and
the
equipment
manufacturer
Ingersoll­
Rand
commented
that
100
hp
is
the
more
appropriate
cutpoint
for
application
of
advanced
NO
X
control
technology.
They
based
this
view
on
their
observations
that
75­
100
hp
engines
do
not
share
many
of
the
characteristics
of
highway
diesels,
thus
making
technology
transfer
from
the
highway
sector
very
costly,
and
customers
will
be
negatively
affected
due
to
the
relatively
large
cost
impacts
of
NO
X
aftertreatment
on
these
smaller
engines.
They
also
argued
that
the
75
hp
cutpoint
would
create
significant
misalignment
in
the
global
marketplace
because
European
regulations
do
not
use
this
cutpoint.

We
agree
with
the
equipment
manufacturers'
observation
that
there
are
engines
above
75
hp
without
turbocharging
or
electronic
controls.
However,
EPA
did
not
choose
the
75
hp
cutpoint
with
the
expectation
that
all
engines
above
it
had
the
same
technology
characteristics.
There
is
a
continuum
in
the
degree
to
which
key
technology
characteristics
exist
on
engines
throughout
the
power
spectrum,
and
the
75
hp
cutpoint
was
based
on
information
from
the
current
fleet
of
engines
and
on
manufacturers'
and
EPA's
expectations
for
future
design
trends,
showing
there
is
a
marked
difference
in
the
prevalence
of
these
and
other
key
engine
design
characteristics
for
engines
above
and
below
75
hp,
and
that,
over
time,
75
 
100
hp
engines
increasingly
share
advanced
technology
characteristics
common
in
larger
engines.
Clear
evidence
of
this
trend
over
recent
model
years
is
documented
in
the
RIA,
section
4.1.4.
As
discussed
in
section
II.
B.
2,
the
kind
of
engine
technology
generally
employed
by
engines
in
the
75
 
100
hp
range,
combined
with
the
lead
time
and
phase­
in
provided
for
the
Tier
4
NO
X
standards,
leads
us
to
conclude
that
highway­
like
NO
X
aftertreatment
can
be
transferred
to
these
engines.
In
addition,
since
our
proposal,
the
Council
of
the
European
Union
(
EU)
has
issued
a
revised
final
version
of
new
nonroad
diesel
emission
standards
that
essentially
aligns
their
power
cutpoints
with
our
own,
including
adoption
of
the
75
hp
cutpoint
for
advanced
technology
NO
X
control.
EPA
does
not
believe
that
the
costs
of
meeting
the
NO
X
standard
for
engines
in
the
75­
100
hp
range
are
unreasonable,
and
we
refer
the
reader
to
section
VI
for
a
detailed
discussion
of
our
cost
analysis
for
engines
and
equipment
meeting
Tier
4
standards
in
this
power
range.
Moreover,
EPA
firmly
believes
such
standards
are
technologically
feasible
for
75
 
100
hp
engines.
(
See
section
II.
B.
2.)

Ingersoll­
Rand
also
expressed
concern
that
the
proposed
consolidation
of
3
previous
power
categories
into
a
single
175
 
750
hp
category
creates
significant
hardship
by
requiring
the
introduction
of
aftertreatment
technologies
in
a
single
year,
contrasting
this
with
the
Tier
2
standards,
which
phased
in
over
2001
 
2003
for
these
engines.
In
response,
we
note
that
the
Tier
52
3
standards,
which
were
set
in
the
same
rule
that
established
the
Tier
2
standards,
will
be
introduced
in
a
single
year
for
these
engines
(
2006),
and
that
the
Tier
2
phase­
in
over
3
years
was
established
in
response
to
particular
issues
and
opportunities
that
were
identified,
specific
to
that
time
frame
(
see
62
FR
50181,
September
24,
1997).
In
addition
to
the
gradual
phase­
in
of
Tier
4
standards
over
several
years,
we
are
adopting
significant
flexibility
provisions
specifically
to
provide
adequate
lead
time
for
equipment
manufacturers
to
make
the
transition
to
the
new
standards,
including
some
provisions
that
provide
additional
flexibility
from
what
we
proposed,
as
explained
in
section
III.
B.

6.
CO
Standards
We
proposed
minor
changes
in
CO
standards
for
some
engines
solely
for
the
purpose
of
helping
to
consolidate
power
categories.
We
stated
in
the
proposal
that
we
were
not
exercising
our
authority
to
revise
the
CO
standard
for
the
purpose
of
improving
air
quality,
but
rather
for
purposes
of
administrative
efficiency.
However,
manufacturers
objected
to
these
proposed
changes,
citing
technological
feasibility
concerns,
and
a
lack
of
parity
with
highway
diesel
and
nonroad
spark­
ignition
engines,
given
that
existing
CO
standards
levels
for
nonroad
engines
are
already
five
times
lower
than
the
standard
level
for
highway
engines.

Because
we
proposed
the
CO
standard
changes
for
the
sake
of
simplifying
and
consolidating
power
categories
and
not
because
of
any
technical
considerations
relating
to
emission
reductions,
we
do
not
believe
it
productive
to
take
issue
with
the
views
expressed
that
these
proposed
changes
raise
serious
feasibility
concerns.
We
instead
are
withdrawing
this
aspect
of
the
proposal,
the
result
being
that
the
existing
CO
standards
remain
in
place.
In
doing
so,
we
are
not
considering
or
reexamining
(
and
at
proposal
did
not
consider
or
reexamine)
the
substantive
basis
for
those
standards.
Having
multiple
CO
standards
within
a
power
category
will,
at
worst,
create
minor
inconveniences
in
certification
and
compliance
efforts.
As
a
result,
in
the
less
than
25
hp
category,
Tier
4
engines
below
11
hp
will
continue
to
be
subject
to
a
different
CO
standard
than
11
 
25
hp
engines,
identical
to
Tier
2.
Likewise,
different
CO
standards
will
continue
to
apply
in
Tier
4
to
engines
above
and
below
50
hp
in
the
25
 
75
hp
category.

We
do
note,
however,
that
we
are
applying
new
certification
tests
to
all
pollutants
covered
by
the
rule,
the
result
being
that
Tier
4
engines
will
have
to
certify
to
CO
standards
measured
by
the
transient
test
(
NRTC)
(
which
includes
a
cold
start
test),
and
the
NTE.
Our
intent
in
adopting
these
new
certification
requirements
is
not
to
alter
the
level
of
stringency
of
the
standard
but
rather
to
ensure
robust
control
of
emissions
to
this
standard
in
use.
The
CO
standards
remain
readily
achievable
using
these
tests,
and
we
anticipate
that
no
additional
engine
adjustments
are
necessary
for
the
standards
to
be
achievable
(
so
there
are
no
significant
associated
costs).
We
also
explain
there
that
the
CO
standards
can
be
achieved
without
jeopardizing
the
ability
to
achieve
all
of
the
other
engine
standards.
53
7.
Crankcase
Emissions
Control
We
currently
require
the
control
of
crankcase
emissions
from
naturally­
aspiriated
nonroad
diesel
engines.
We
proposed
to
extend
this
requirement
to
turbocharged
nonroad
diesel
engines
as
well,
starting
in
the
same
model
year
that
Tier
4
exhaust
emission
standards
first
apply
in
each
power
category.

EMA
opposed
the
proposed
extension,
reiterating
concerns
expressed
in
comments
on
a
similar
proposed
provision
in
the
2007
heavy­
duty
highway
rule,
including
concerns
over
the
impact
that
recirculating
crankcase
emissions
may
have
on
the
feasibility
of
engine
standards
over
the
full
useful
life.
These
concerns
are
addressed
in
the
Summary
and
Analysis
of
Comments
document
for
that
rule,
which
is
included
in
the
docket
for
today's
rule.
Besides
the
feasibility
issues
raised
by
EMA
for
nonroad
diesels
that
are
addressed
in
the
highway
rule,
two
nonroadspecific
issues
were
raised
as
well:
(
1)
the
need
to
design
crankcase
emission
control
systems
that
operate
at
the
high
angularity
experienced
by
some
nonroad
machines
on
uneven
ground,
and
(
2)
the
concern
that
this
requirement
adds
to
the
large
number
of
"
first
time"
requirements
being
adopted
for
Tier
4.
We
agree
that
high
angularity
operation
may
add
new
design
considerations
for
these
controls,
but
do
not
see
how
it
would
pose
a
serious
barrier
that
could
not
be
overcome
in
time.
The
grouping
of
new
EPA
requirements
in
a
specific
model
year
is
an
important
objective
of
our
program
aimed
at
providing
stability
to
the
design
process,
a
goal
much
supported
by
the
engine
manufacturers.
We
have
accounted
for
this
in
assessing
feasibility,
costs,
and
flexibility
needs
for
the
program.
One
flexibility
we
are
providing
is
the
three­
path
opportunity
to
satisfy
our
crankcase
control
requirement,
as
described
below.
In
fact,
in
its
written
comments
EMA
recommended
that,
if
EPA
were
to
proceed
with
crankcase
emission
control
requirements
for
Tier
4,
it
adopt
all
three
options
for
demonstrating
compliance.
This
is
indeed
what
we
are
doing.

Thus,
as
proposed,
in
addition
to
allowing
for
compliance
through
the
routing
of
crankcase
emissions
to
the
engine
air
intake
system,
we
are
also
allowing
manufacturers
to
instead
meet
the
requirement
by
routing
the
crankcase
gases
into
the
exhaust
stream,
provided
they
keep
the
combined
total
of
the
crankcase
emissions
and
the
exhaust
emissions
below
the
applicable
exhaust
emission
standards.
Also
as
proposed,
we
are
allowing
manufacturers
to
instead
meet
the
requirement
by
measuring
crankcase
emissions
instead
of
completely
eliminating
them,
provided
manufacturers
add
these
measured
emissions
to
exhaust
emissions
in
assessing
compliance
with
exhaust
emissions
standards.
Manufacturers
using
this
option
must
also
modify
their
exhaust
deterioration
factors
or
develop
separate
deterioration
factors
to
account
for
increases
in
crankcase
emissions
as
the
engine
ages,
and
must
ensure
that
crankcase
emissions
can
be
readily
measured
in
use.
We
see
no
reason
to
treat
naturally­
aspirated
engines
differently
than
turbocharged
engines,
and
so
are
allowing
these
options
for
all
Tier
4
engines
subject
to
the
crankcase
control
requirement,
both
turbocharged
and
naturally­
aspirated.
The
wording
of
the
proposed
regulations
limiting
the
options
to
turbocharged
engines
was
inadvertent.
34
Council
of
the
European
Union,
"
Directive
of
the
European
Parliament
and
of
the
Council
amending
Directive
97/
68/
EC",
March
15,
2004.

54
8.
Prospects
for
International
Harmonization
We
received
numerous
comments,
especially
from
engine
and
equipment
manufacturers,
stressing
the
need
for
EPA
to
work
with
other
governmental
standards­
setting
bodies
to
harmonize
standards.
We
recognize
the
importance
of
harmonization
of
international
standards
and
have
worked
diligently
with
our
colleagues
in
Europe
and
Japan
to
achieve
that
objective.
Harmonization
of
these
standards
will
allow
manufacturers
continued
access
to
world
markets
and
lower
the
required
research
and
development
and
tooling
costs
needed
to
meet
different
standards.
We
will
continue
to
work
with
standards­
setting
governmental
entities
and
with
foreign
and
domestic
manufacturers.

In
October
2003,
the
Council
and
Parliament
of
the
European
Union
reached
agreement
on
revisions
to
a
proposal
developed
by
the
European
Commission
that
would
amend
Directive
97/
68/
EC
to
include
nonroad
diesel
emissions
standards
similar
to
those
in
our
Tier
4
program,
and,
as
in
the
U.
S.,
coordinated
with
low
sulfur
diesel
fuel
requirements
in
the
Europe.
This
revised
proposal
has
since
been
finalized.
34
This
revised
Directive
aligns
well
with
our
program
in
the
Tier
4
time
frame,
even
more
so
than
did
the
original
Commission
proposal.
It
also
closely
aligns
with
our
Tier
3
standards
in
the
Tier
3
time
frame.

For
engines
of
50
 
750
hp,
the
Directive's
standards
are
very
closely
aligned
with
our
own
Tier
4
standards,
including
emissions
levels,
implementation
dates,
the
defined
power
categories,
and
the
lower
hp
limit
of
NO
X
control
based
on
high­
efficiency
exhaust
emission
controls
(
75
hp).
Exceptions
are
noted
below:
°
The
2008
PM
standard
level
for
50
 
75
hp
engines
(
the
equivalent
of
0.3
g/
bhp­
hr
vs
our
0.22
g/
bhp­
hr
level).
Note,
however,
that
we
do
allow
certification
to
the
0.3
g/
bhp­
hr
level
as
an
option,
provided
the
manufacturer
must
then
meet
our
0.02
g/
bhp­
hr
standard
in
2012,
one
year
earlier
than
otherwise.
°
The
2013
PM
standard
level
for
50
 
75
hp
engines
(
the
equivalent
of
0.01
g/
bhp­
hr
vs
our
0.02
g/
bhp­
hr
level).
°
An
October
1,
2014
start
for
the
final
75
 
175
hp
NO
X
standard
(
the
same
as
our
proposed
date),
compared
to
the
December
31,
2014
date
we
are
adopting
in
this
final
rule.
°
For
constant
speed
engines:
no
Tier
4­
equivalent
standards.
Also,
the
EU's
Tier
3­
equivalent
standards
are
not
implemented
on
these
engines
until
2011
 
2012.

As
the
EU
program
does
not
provide
for
emissions
averaging,
the
alternative
NO
X
standards
we
are
setting
for
75
 
750
hp
engines
are
the
NO
X
levels
at
which
the
EU
standards
are
generally
aligned
during
our
NO
X
phase­
in
years.
The
EU
Directive
also
includes
transition
flexibility
provisions
for
equipment
manufacturers
similar
to
those
in
our
program,
discussed
in
section
III.
B.
55
The
EU
program
for
nonroad
diesels
has
not
adopted
or
proposed
any
current
or
future
standards
for
engines
above
750
hp
or
below
25
hp,
and
its
revised
Directive
for
25
 
50
hp
engines
does
not
subject
them
to
any
future
standards
beyond
those
entering
into
force
in
2007
(
equivalent
to
0.45
g/
bhp­
hr
PM
and
5.6
g/
bhp­
hr
hydrocarbon+
NO
X),
in
contrast
to
our
2013
standards
based
the
use
of
PM
filters
and
more
advanced
engine­
based
control
technologies
(
0.02
g/
bhp­
hr
PM
and
3.5
g/
bhp­
hr
NMHC+
NO
X).
However,
as
discussed
further
in
section
VIII.
A,
the
EU
Directive
includes
plans
to
conduct
a
future
technology
review
of
appropriate
standards
for
engines
below
50
hp
and
above
750
hp.
The
year
that
this
is
planned
for
is
2007,
the
same
year
in
which
we
are
planning
a
technology
review
for
engines
below
75
hp.
Considering
progress
to
date,
and
announced
plans
for
reviews
in
2007,
we
believe
that
prospects
for
harmonized
standards
are
excellent.

9.
Exclusion
of
Marine
Engines
For
reasons
outlined
in
the
proposal,
we
are
not
applying
Tier
4
standards
to
the
marine
diesel
engines
under
50
hp
that
are
covered
under
our
Tier
1
and
2
standards.
We
believe
it
is
more
appropriate
to
consider
more
stringent
standards
for
a
range
of
marine
diesel
engines,
including
these,
in
a
future
action.
It
should
be
noted
that
the
existing
Tier
2
standards
will
continue
to
apply
to
marine
diesel
engines
under
50
hp
until
that
future
action
is
completed.
We
did
not
receive
any
adverse
comments
on
this
proposed
approach.

B.
Are
the
New
Standards
Feasible?

Today
we
are
finalizing
a
program
of
stringent
new
standards
for
a
broad
category
of
nonroad
diesel
engines
coupled
with
a
new
nonroad
diesel
fuel
standard
that
dramatically
lowers
the
sulfur
level
in
nonroad
diesel
fuel
ultimately
to
15
ppm.
We
believe
these
standards
are
technically
feasible
in
the
leadtime
provided
given
the
availability
of
15
ppm
sulfur
fuel
and
the
rapid
progress
to
develop
the
needed
emission
control
technologies.
We
acknowledge,
as
pointed
out
by
a
number
of
commenters,
that
these
standards
will
be
challenging
for
industry
to
meet,
in
part
due
to
differences
in
operating
conditions
and
duty
cycles
for
nonroad
equipment
and
the
diesel
engines
used
in
that
equipment.
Also,
we
recognize
that
transferring
and
effectively
applying
these
technologies,
which
have
largely
been
developed
for
highway
engines,
will
require
additional
time
after
the
application
of
the
technology
to
on­
highway
engines.
Diesel
engine
industry
commenters
and
environmental
stakeholder
commenters
on
our
proposal
consistently
agreed
with
our
position
that
for
most
engine
horsepower
categories
the
technologies
to
meet
the
standards
exist
and
that
the
transfer
of
these
technologies
to
nonroad
is
possible.
The
biggest
difference
of
opinions
in
the
range
of
comments
received
by
the
Agency
concerns
the
timing
of
the
emission
standards
and
the
flexibility
provisions
(
i.
e.,
the
leadtime
necessary
to
transfer
the
technology).
One
of
the
most
important
tasks
for
a
feasibility
analysis
is
to
determine
the
appropriate
amount
of
development
time
needed
to
successfully
bring
new
technologies
to
market.
We
have
carefully
weighed
the
desire
to
have
clean
engines
sooner,
with
the
challenges
yet
to
be
overcome
in
applying
the
technologies
to
nonroad
engines
and
equipment,
in
determining
the
appropriate
timing
and
emission
levels
for
the
standards
finalized
today.
35
Regulatory
Impact
Analysis:
Heavy­
Duty
Engine
and
Vehicle
Standards
and
Highway
Diesel
Fuel
Sulfur
Control
Requirements,
United
States
Environmental
Protection
Agency,
December
2000,

EPA420­
R­
00­
026.
Copy
Available
in
EPA
Air
Docket
A­
2001­
28
Item
II­
A­
01.

36
Regulatory
Impact
Analysis:
Control
of
Emissions
of
Air
Pollution
from
Highway
Heavy­
Duty
Engines,
United
States
Environmental
Protection
Agency,
June
2000,
EPA420­
R­
00­
010.
Copy
available
in
EPA
Air
Docket
A­
2001­
28
Item
II­
A­
02.

37
Highway
Diesel
Progress
Review,
United
States
Environmental
Protection
Agency,
June
2002,
EPA
420­
R­
02­
016.
Copy
available
in
EPA
Air
Docket
A­
2001­
28
Item
II­
A­
52.

38
Highway
Diesel
Progress
Review
Report
2,
United
States
Environmental
Protection
Agency,

March
2004,
EPA420­
R­
04­
004.
Copy
available
in
Docket
OAR­
2003­
0012­
0918.

56
The
RIA
associated
with
today's
action
contains
a
detailed
description
and
analysis
of
diesel
emission
control
technologies,
issues
specific
to
applying
these
technologies
to
nonroad
engines,
and
why
we
believe
the
new
emission
standards
are
feasible.
Additional
in­
depth
discussion
of
these
technologies
can
be
found
in
the
final
RIA
for
the
HD2007
emission
standards,
the
final
RIA
for
the
HD2004
emission
standards,
the
2002
Highway
Diesel
Progress
Review
and
the
recently
released
Highway
Diesel
Progress
Review
Report
2.35,36,37,38
The
following
sections
summarize
the
challenges
to
applying
these
technologies
to
nonroad
engines
and
why
we
believe
the
emission
standards
finalized
today
are
technically
feasible
in
the
leadtime
provided.

1.
Can
Advanced
Diesel
Emission
Control
Technologies
Be
Applied
to
Nonroad
Engines
and
Equipment?

The
emission
standards
and
the
introduction
dates
for
those
standards,
as
described
earlier
in
this
section,
are
premised
on
the
transfer
of
diesel
engine
technologies
being
or
already
developed
to
meet
light­
duty
and
heavy­
duty
vehicle
standards
that
begin
in
2007.
The
advanced
technology
standards
that
we
are
finalizing
today
for
engines
over
25
horsepower
will
begin
to
go
into
effect
four
years
later.
This
time
lag
between
equivalent
highway
and
nonroad
diesel
engine
standards
is
necessary
in
order
to
allow
time
for
engine
and
equipment
manufacturers
to
further
develop
these
highway
technologies
for
nonroad
engines
and
to
align
this
program
with
nonroad
Tier
3
emission
standards
that
begin
to
go
into
effect
in
2006.

This
section
summarizes
the
engineering
challenges
to
applying
advanced
emission
control
technologies
to
nonroad
engines
and
equipment,
and
why
we
believe
that
technologies
developed
for
highway
diesel
engines
can
be
further
refined
to
address
these
issues
in
a
timely
manner
for
nonroad
engines
consistent
with
the
emission
standards
finalized
today.
57
a.
Nonroad
Operating
Conditions
and
Exhaust
Temperatures
Nonroad
equipment
is
highly
diverse
in
design,
application,
and
typical
operating
conditions.
This
variety
of
operating
conditions
affects
emission
control
systems
through
the
resulting
variety
in
the
torque
and
speed
demands
(
i.
e.,
power
demands).
In
our
proposal,
we
highlighted
the
challenge
for
design
and
implementation
of
advanced
emission
control
technologies
posed
by
this
wide
range
in
what
constitutes
typical
nonroad
operation.
Some
commenters
emphasized
their
concerns
regarding
this
issue
as
well,
and
their
belief
that
these
issues
make
the
application
of
the
technology
to
nonroad
infeasible.
While
we
recognize
and
agree
with
the
commenters
regarding
the
nature
of
the
challenges,
we
disagree
with
their
conclusion
regarding
feasibility
because,
as
described
in
the
following
section,
we
see
a
clear
path
to
overcome
the
challenges.

The
primary
concern
for
catalyst­
based
emission
control
technologies
is
exhaust
temperature.
In
general,
exhaust
temperature
increases
with
engine
power
and
can
vary
dramatically
as
engine
power
demands
vary.
For
catalyzed
diesel
particulate
filters
(
CDPFs),
exhaust
temperature
determines
the
rate
of
filter
regeneration,
and
if
too
low,
causes
a
need
for
supplemental
means
to
ensure
proper
filter
regeneration.
In
the
case
of
the
CDPF,
it
is
the
aggregate
soot
regeneration
rate
that
is
important,
not
the
regeneration
rate
at
any
particular
moment
in
time.
A
CDPF
controls
PM
emissions
under
all
conditions
and
can
function
properly
(
i.
e.,
not
plug)
even
when
exhaust
temperatures
are
low
for
an
extended
time
and
the
regeneration
rate
is
lower
than
the
soot
accumulation
rate,
provided
that
occasionally
exhaust
temperatures
and
thus
the
soot
regeneration
rate
are
increased
enough
to
regenerate
the
CDPF.
Similarly,
there
is
a
minimum
temperature
(
e.
g.,
200
°
C)
for
NO
X
adsorbers
below
which
NO
X
regeneration
is
not
readily
possible
and
a
maximum
temperature
(
e.
g.,
500
°
C)
above
which
NO
X
adsorbers
are
unable
to
effectively
store
NO
X.
Therefore,
there
is
a
need
to
match
diesel
exhaust
temperatures
to
conditions
for
effective
catalyst
operation
under
the
various
operating
conditions
of
nonroad
engines.

Although
the
range
of
products
for
highway
vehicles
is
not
as
diverse
as
for
nonroad
equipment,
the
need
to
match
exhaust
temperatures
to
catalyst
characteristics
is
still
present.
This
is
an
important
concern
for
highway
engine
manufacturers
and
has
been
a
focus
of
our
ongoing
2007
diesel
engine
progress
review.
There
we
have
learned
that
substantial
progress
is
being
made
to
broaden
the
operating
temperature
window
of
catalyst
technologies
while
at
the
same
time
to
design
engine
systems
to
better
control
average
exhaust
temperatures
(
for
ongoing
catalyst
performance)
and
to
attain
periodically
higher
temperatures
(
to
control
PM
filter
regeneration
and
NO
X
adsorber
desulfation).
Highway
diesel
engine
manufacturers
are
working
to
address
this
need
through
modifications
to
engine
design,
modifications
to
engine
control
strategies,
and
modifications
to
exhaust
system
designs.
New
engine
control
strategies
designed
to
take
advantage
of
engine
and
exhaust
system
modifications
can
be
used
to
manage
exhaust
temperatures
across
a
broad
range
of
engine
operation.
The
technology
solutions
being
developed
for
highway
engines
to
better
manage
exhaust
temperature
are
built
upon
the
same
emission
control
technologies
(
i.
e.,
advanced
air
handling
systems
and
electronic
fuel
injection
39
Sasaki,
S.,
Ito,
T.,
and
Iguchi,
S.,
"
Smoke­
less
Rich
Combustion
by
Low
Temperature
Oxidation
in
Diesel
Engines,"
9th
Aachener
Kolloquim
Fahrzeug
­
und
Motorentechnik
2000.
Copy
available
in
EPA
Air
Docket
A­
2001­
28
Item
II­
A­
56.

40
Jeuland,
N.,
et
al,
"
Performances
and
Durability
of
DPF
(
Diesel
Particulate
Filter)
Tested
on
a
Fleet
of
Peugeot
607
Taxis
First
and
Second
Test
Phases
Results,"
October
2002,
SAE
2002­
01­
2790.

58
systems)
that
we
expect
nonroad
engine
manufacturers
to
use
in
order
to
comply
with
the
existing
Tier
3
emission
standards.

Matching
the
emission
control
technology
and
the
operating
temperature
window
of
the
broad
range
of
nonroad
equipment
may
be
somewhat
more
challenging
for
nonroad
engines
than
for
many
highway
diesel
engines
simply
because
of
the
diversity
in
equipment
design
and
equipment
use.
Nonetheless,
the
problem
has
been
successfully
solved
in
highway
applications
facing
low
exhaust
temperature
performance
situations
as
difficult
to
address
as
any
encountered
by
nonroad
applications.
The
most
challenging
temperature
regime
for
highway
engines
are
encountered
at
very
light­
loads
as
typified
by
congested
urban
driving
with
periods
of
extended
idle
operation.
Under
congested
urban
driving
conditions,
exhaust
temperatures
may
be
too
low
for
effective
NO
X
reduction
with
a
NO
X
adsorber
catalyst.
Similarly,
exhaust
temperatures
may
be
too
low
to
ensure
passive
CDPF
regeneration.
To
address
these
concerns,
light­
duty
diesel
engine
manufacturers
have
developed
active
temperature
management
strategies
that
provide
effective
emissions
control
even
under
these
difficult
light­
load
conditions.
Toyota
has
shown
with
their
prototype
diesel
particulate
NO
X
reduction
(
DPNR)
vehicles
that
changes
to
EGR
and
fuel
injection
strategies
can
realize
an
increase
in
exhaust
temperatures
of
more
than
100
°
F
under
even
very
light­
load
conditions
allowing
the
NO
X
adsorber
catalyst
to
function
under
these
normally
cold
exhaust
conditions.
39
Similarly,
PSA
Peugeot
Citroen
(
PSA)
has
demonstrated
effective
CDPF
regeneration
under
demanding
light­
load
taxi
cab
conditions
with
current
production
technologies.
40
Both
of
these
are
examples
of
technology
paths
available
to
nonroad
engine
manufacturers
to
increase
temperatures
under
light­
load
conditions.

While
a
number
of
commenters
expressed
concerns
about
low
temperature
operation
for
nonroad
equipment,
no
commenters
provided
data
showing
that
nonroad
equipment
in­
use
operating
cycles
would
be
more
demanding
of
low
temperature
performance
than
passenger
car
urban
driving.
Both
the
Toyota
and
PSA
systems
are
designed
to
function
even
with
extended
idle
operation
as
would
be
typified
by
a
taxi
waiting
to
pick
up
a
fare.

It
is
our
conclusion
that
by
actively
managing
exhaust
temperatures,
for
example
through
engine
management
to
increase
exhaust
temperatures,
engine
manufacturers
can
ensure
highly
effective
catalyst­
based
emission
control
performance
(
i.
e.,
compliance
with
the
emission
standards
across
the
applicable
tests)
and
reliable
filter
regeneration
across
a
wide
range
of
engine
operation
as
would
be
typified
by
the
broad
range
of
in­
use
nonroad
duty
cycles.
Active
methods
of
regenerating
PM
filters
have
been
shown
to
be
reliable
under
all
operating
conditions
and
can
41
We
do
not
have
Tier
3
emission
standards
for
engines
in
the
horsepower
category
from
25­
50
hp.
However,
we
expect
that
similar
Tier
3
emission
control
technologies
will
form
part
of
the
emission
control
technology
package
used
for
compliance
with
the
Tier
4
standards
for
these
engines
in
2013.
Our
cost
analysis
reflects
the
additional
cost
to
apply
these
technologies
for
NOX
and
PM
control.

59
be
applied
to
nonroad
diesel
engines
in
the
time
frame
required
by
these
regulations.
The
additional
cost
for
active
regeneration,
beyond
the
cost
for
the
PM
filter
alone,
has
been
accounted
for
in
the
cost
analysis
summarized
in
section
VI
of
this
preamble.

We
have
conducted
an
analysis
of
various
nonroad
equipment
operating
cycles
and
various
nonroad
engine
power
density
levels
to
better
understand
the
matching
of
nonroad
engine
exhaust
temperatures,
catalyst
installation
locations
and
catalyst
technologies.
This
analysis,
documented
in
the
RIA,
shows
that
for
many
engine
power
density
levels
and
equipment
operating
cycles,
exhaust
temperatures
are
quite
well
matched
to
catalyst
temperature
window
characteristics.
In
particular,
the
nonroad
transient
cycle
(
NRTC),
the
cycle
we
are
finalizing
to
use
for
certification
for
most
engines
with
rated
power
less
than
750
hp,
was
shown
to
be
well
matched
to
the
NO
X
adsorber
characteristics
with
estimated
performance
in
excess
of
90
percent
for
a
turbocharged
diesel
engine
tested
under
a
range
of
power
density
levels.
The
analysis
also
indicated
that
the
exhaust
temperatures
experienced
over
the
NRTC
are
better
matched
to
the
NO
X
adsorber
catalyst
temperature
window
than
the
temperatures
that
would
be
expected
over
the
highway
FTP
test
cycle.
This
suggests
(
when
coupled
with
the
fact
that
PM
filters
function
with
equal
effectiveness
at
essentially
all
conditions)
that
compliance
based
on
testing
with
the
nonroad
Tier
4
standards
on
the
NRTC
will
be
somewhat
easier,
using
similar
technology,
than
complying
with
the
highway
2007
emission
standards
on
the
highway
transient
test
cycle.

In
sum,
we
believe
based
on
our
analysis
of
nonroad
engines
and
equipment
operating
characteristics,
that,
in
use,
some
nonroad
engines
will
experience
conditions
that
require
the
use
of
temperature
management
strategies
(
e.
g.,
active
regeneration)
in
order
to
effectively
use
the
NO
X
adsorber
and
CDPF
systems.
We
have
assumed
in
our
cost
analysis
that
all
nonroad
engines
complying
with
a
PM
standard
of
0.03
g/
bhp­
hr
or
lower
will
have
an
active
means
to
control
temperature
(
i.
e.
we
have
costed
a
backup
regeneration
system,
although
some
applications
likely
may
not
need
one).
We
have
made
this
assumption
believing,
as
indicated
by
a
number
of
commenters,
that
manufacturers
will
not
be
able
to
accurately
predict
in­
use
conditions
for
every
piece
of
equipment
and
will
thus
choose
to
provide
the
technologies
on
a
back­
up
basis.
As
explained
earlier,
the
technologies
necessary
to
accomplish
this
temperature
management
are
enhancements
of
both
the
Tier
3
emission
control
technologies
that
will
form
the
starting
point
for
Tier
4
engines
larger
than
50
hp,
and
the
control
strategies
being
developed
for
highway
diesel
engines.
41
Based
on
our
analyses,
we
believe
that
there
are
no
nonroad
engine
applications
above
25
horsepower
for
which
these
highway
engine
approaches
for
temperature
management
will
not
work.
However,
we
agree
with
commenters
that
given
the
diversity
in
nonroad
equipment
design
and
application,
additional
time
will
be
needed
in
order
to
match
the
engine
performance
characteristics
to
the
full
range
of
nonroad
equipment.
42
"
Summary
of
Conference
Call
between
U.
S.
EPA
and
Deutz
Corporation
on
September
19,

2002
regarding
Deutz
Diesel
Particulate
Filter
System",
EPA
Memorandum
to
Air
Docket
A­
2001­
28
60
We
have
concluded
that,
given
the
timing
of
the
emissions
standards
finalized
today,
and
the
availability
and
continuing
development
of
technologies
to
address
temperature
management
for
highway
engines
which
technologies
are
transferrable
to
all
nonroad
engines
with
greater
than
25
hp
power
rating,
nonroad
engines
can
be
designed
to
meet
the
new
standards
in
the
lead
time
provided,
and
can
be
provided
to
equipment
makers
in
a
timely
manner
within
that
lead
time.

b.
Nonroad
Operating
Conditions
and
Durability
Nonroad
equipment
is
designed
to
be
used
in
a
wide
range
of
tasks,
from
mining
equipment
to
crop
cultivation
and
harvesting
to
excavation
and
loading,
and
operated
in
harsh
environments.
In
the
normal
course
of
equipment
operation
the
engine
and
its
associated
hardware
will
experience
levels
of
vibration,
impacts,
and
dust
that
may
exceed
conditions
typical
of
highway
diesel
vehicles.
For
this
reason,
some
commenters
said
that
the
PM
filter
technology
was
infeasible
for
nonroad
equipment.
We
disagree
with
this
assertion
and
continue
to
believe
that
PM
filter
technologies
can
be
applied
to
a
wide
range
of
nonroad
equipment.

Specific
efforts
to
design
for
the
nonroad
operating
conditions
will
be
required
in
order
to
ensure
that
the
benefits
of
these
new
emission
control
technologies
are
realized
for
the
life
of
nonroad
equipment.
Much
of
the
engineering
knowledge
and
experience
to
address
these
issues
already
exists
with
the
nonroad
equipment
manufacturers.
Vibration
and
impact
issues
are
fundamentally
mechanical
durability
concerns
(
rather
than
issues
of
technical
feasibility
of
achieving
emissions
reductions)
for
any
component
mounted
on
a
piece
of
equipment
(
e.
g.,
an
engine
coolant
overflow
tank).
Equipment
manufacturers
must
design
mounting
hardware
such
as
flanges,
brackets,
and
bolts
to
support
the
new
component
without
failure.
Further,
the
catalyst
substrate
material
itself
must
be
able
to
withstand
the
conditions
encountered
on
nonroad
equipment
without
itself
cracking
or
failing.
There
is
a
large
body
of
real
world
testing
with
retrofit
emission
control
technologies
on
engines
up
to
750
hp
that
demonstrate
the
durability
of
the
catalyst
components
themselves
even
in
the
harshest
of
nonroad
equipment
applications.
The
evidence
for
even
larger
engines
(
i.
e.,
those
above
750
hp)
is
less
conclusive
because
of
the
limited
number
of
applications.

Deutz,
a
nonroad
engine
manufacturer,
sold
approximately
2,000
diesel
particulate
filter
systems
for
nonroad
equipment
in
the
period
from
1994
through
2000.
The
very
largest
of
these
systems
were
limited
to
engine
sizes
below
850
hp.
The
majority
of
these
systems
were
sold
into
significantly
smaller
applications.
Many
of
these
systems
were
sold
for
use
in
mining
equipment.
Mining
equipment
is
exposed
to
extraordinarily
high
levels
of
vibration,
experiences
impacts
with
the
mine
walls
and
face,
and
encounters
high
levels
of
dust.
Yet
in
meetings
with
the
Agency,
Deutz
shared
their
experience
that
no
system
had
failed
due
to
mechanical
failure
of
the
catalyst
or
catalyst
housing.
42
The
Deutz
system
utilized
a
conventional
cordierite
PM
filter
substrate
as
is
Item
II­
B­
31.

61
commonly
used
for
heavy­
duty
highway
truck
CDPF
systems.
The
canning
and
mounting
of
the
system
was
a
Deutz
design.
Deutz
was
able
to
design
the
catalyst
housing
and
mounting
in
such
a
way
as
to
protect
the
catalyst
from
the
harsh
environment
as
evidenced
by
its
excellent
record
of
reliable
function.

A
number
of
commenters
asserted
that
it
was
not
possible
to
apply
conventional
CDPF
technologies
(
i.
e.,
ceramic
wall­
flow
filter
media)
to
the
largest
diesel
engines
with
power
ratings
above
750
hp.
In
the
draft
RIA
for
the
proposal,
we
described
our
expectation
that
these
highway­
based
systems
could
be
assembled
into
larger
systems
to
work
well
for
these
largest
diesel
engines.
While
we
continue
to
believe
that
it
may
be
possible
in
the
time
frame
of
this
rulemaking
for
these
conventional
CDPFs
to
be
applied
to
engines
with
more
than
750
hp,
based
on
the
evidence
provided
by
the
commenters,
we
now
agree
that
too
much
uncertainty
remains
for
us
to
reach
that
conclusion
today.
We
cannot
clearly
today
describe
a
method
to
monitor
the
soot
loading
of
individual
filter
elements
in
a
parallel
system
made
up
of
a
significant
number
of
smaller
components.
This
is
because
for
parallel
systems
the
pressure
drop
(
the
best
current
method
to
monitor
filter
condition)
across
all
of
the
parallel
components
is
exactly
the
same.
If
a
single
filter
begins
to
plug
and
needs
to
be
regenerated
it
may
not
be
detected
in
such
a
system.
Therefore,
we
believe
that
instead
of
a
massively
parallel
filter
system,
an
alternate
PM
filtering
media
may
be
more
appropriate
in
order
to
address
issues
of
scalability,
durability
and
packaging
for
these
largest
engines.
Fortunately,
there
are
other
filter
media
technologies
(
e.
g.,
wire
or
fiber
mesh
depth
filters)
that
can
be
successfully
scaled
to
any
size
and
which
we
have
confidence
in
projecting
today
will
be
a
more
appropriate
solution
for
the
bulk
of
the
engines
in
this
size
category.
Because
these
depth
filtration
technologies
are
not
quite
as
efficient
at
filtering
PM
as
the
ceramic
systems
that
are
the
dominant
solution
for
the
smaller
highway
diesel
engines,
we
are
finalizing
a
set
of
PM
filter­
based
standards
for
engines
greater
than
750
hp
which
are
slightly
higher
than
the
proposed
PM
standards
for
these
engines.
Those
standards
are
discussed
in
sections
II.
A
and
II.
B.
3
below.
Our
cost
estimates
summarized
in
section
VI
for
engines
greater
than
750
hp
are
consistent
with
the
use
of
either
silicon
carbide
or
wire
mesh
PM
filter
technologies.

Certain
nonroad
applications,
including
some
forms
of
harvesting
equipment,
consumer
lawn
and
garden
equipment,
and
mining
equipment,
may
have
specific
limits
on
maximum
surface
temperature
for
equipment
components
in
order
to
ensure
that
the
components
do
not
serve
as
ignition
sources
for
flammable
dust
particles
(
e.
g.
coal
dust
or
fine
crop/
lawn
dust).
Some
commenters
have
raised
concerns
that
these
design
constraints
might
limit
the
equipment
manufacturers
ability
to
install
advanced
diesel
catalyst
technologies
such
as
NO
X
adsorbers
and
CDPFs.
This
concern
seems
to
be
largely
based
upon
anecdotal
experience
with
gasoline
catalyst
technologies
where
under
certain
circumstances
catalyst
temperatures
can
exceed
1,000
°
C
and
without
appropriate
design
considerations
could
conceivably
serve
as
an
ignition
source.
We
do
not
believe
that
these
concerns
are
justified
in
the
case
of
either
the
NO
X
adsorber
catalyst
or
the
CDPF
technology.
Catalyst
temperatures
for
NO
X
adsorbers
and
CDPFs
should
not
exceed
the
43
The
hottest
surface
on
a
diesel
engine
is
typically
the
exhaust
manifold
which
connects
the
engines
exhaust
ports
to
the
inlet
of
the
turbocharger.
The
hot
exhaust
gases
leave
the
engine
at
a
very
high
temperature
(
800
°
C
at
high
power
conditions)
and
then
pass
through
the
turbocharger
where
the
gases
expand
driving
the
turbocharger
providing
work.
The
process
of
extracting
work
from
the
hot
gases
cools
the
exhaust
gases.
The
exhaust
leaving
the
turbocharger
and
entering
the
catalyst
and
the
remaining
pieces
of
the
exhaust
system
is
cooler
(
as
much
as
200
°
C
at
very
high
loads)
than
in
the
exhaust
manifold.

44
"
Engine
Technology
and
Application
Aspects
for
Earthmoving
Machines
and
Mobile
Cranes,
Dr.
E.
Brucker,
Liebherr
Machines
Bulle,
SA,
AVL
International
Commercial
Powertrain
Conference,
October
2001.
Copy
available
in
EPA
Air
Docket
A­
2001­
28,
Docket
Item
#
II­
A­
12.

62
maximum
exhaust
manifold
temperatures
already
commonly
experienced
by
diesel
engines
(
i.
e,
catalyst
temperatures
are
expected
to
be
below
800
°
C).
43
CDPF
temperatures
are
not
expected
to
exceed
approximately
700
°
C
in
normal
use
and
are
expected
to
only
reach
the
650
°
C
temperature
during
periods
of
active
regeneration.
Similarly,
NO
X
adsorber
catalyst
temperatures
are
not
expected
to
exceed
700
°
C
and
again
only
during
periods
of
active
sulfur
regeneration
as
described
in
section
III.
C
below.
Under
conditions
where
diesel
exhaust
temperatures
are
naturally
as
high
as
650
°
C,
no
supplemental
heat
addition
from
the
emission
control
system
will
be
necessary
for
regeneration
and
therefore
exhaust
temperatures
will
not
exceed
their
natural
level.
When
natural
exhaust
temperatures
are
too
low
for
effective
emission
system
regeneration
then
supplemental
heating,
as
described
earlier,
may
be
necessary
but
would
not
be
expected
to
produce
temperatures
higher
than
the
maximum
levels
normally
encountered
in
diesel
exhaust.
Furthermore,
even
if
it
were
necessary
to
raise
exhaust
temperatures
to
a
higher
level
in
order
to
promote
effective
emission
control,
there
are
technologies
available
to
isolate
the
higher
exhaust
temperatures
from
flammable
materials
such
as
dust.
One
approach
would
be
the
use
of
airgapped
exhaust
systems
(
i.
e.,
an
exhaust
pipe
inside
another
concentric
exhaust
pipe
separated
by
an
air­
gap)
that
serve
to
insulate
the
inner
high
temperature
surface
from
the
outer
surface
which
could
come
into
contact
with
the
dust.
The
use
of
such
a
system
also
may
be
desirable
in
order
to
maintain
higher
exhaust
temperatures
inside
the
catalyst
in
order
to
promote
better
catalyst
function.
Another
technology
to
control
surface
temperature
already
used
by
some
nonroad
equipment
manufacturers
is
water
cooled
exhaust
systems.
44
This
approach
is
similar
to
the
airgapped
system
but
uses
engine
coolant
water
to
actively
cool
the
exhaust
system.

We
thus
do
not
believe
that
flammable
dust
concerns
will
prevent
the
use
of
either
a
NO
X
adsorber
or
a
CDPF
because
catalyst
temperatures
are
not
expected
to
be
unacceptably
high
and
because
remediation
technologies
exist
to
address
these
concerns.
In
fact,
exhaust
emission
control
technologies
(
i.
e.,
aftertreatment)
have
already
been
applied
on
both
an
original
equipment
manufacturer
(
OEM)
basis
and
for
retrofit
to
nonroad
equipment
for
use
in
potentially
explosive
environments.
Many
of
these
applications
must
undergo
Underwriters
Laboratory
(
UL)
approval
45
Phone
conversation
between
Byron
Bunker,
United
States
Environmental
Protection
Agency
and
Dale
McKinnon,
Manufacturers
of
Emission
Control
Association
(
MECA),
9
April,
2003
confirming
the
use
of
emission
control
technologies
on
nonroad
equipment
used
in
coal
mines,
refineries,
and
other
locations
where
explosion
proofing
may
be
required.

46
As
an
alternative
to
compliance
with
the
ISO
C1
test
procedure,
a
manufacturer
can
show
compliance
with
the
standards
by
testing
over
the
Ramped
Modal
Cycle
(
RMC)
as
described
in
section
III.
F.

63
before
they
can
be
used.
45
Therefore,
while
we
appreciate
the
commenters'
concerns
regarding
safety,
we
remain
convinced
that
the
application
of
these
emission
control
technologies
will
not
compromise
(
or
decrease)
equipment
safety.

We
agree
that
nonroad
equipment
must
be
designed
to
address
safety
and
durable
performance
for
a
wide
range
of
operating
conditions
and
applications
that
would
not
commonly
be
experienced
by
highway
vehicles.
We
believe
further
as
demonstrated
by
retrofit
experiences
around
the
world
that
technical
solutions
exist
which
allow
catalyst­
based
emission
control
technologies
to
be
applied
to
nonroad
equipment.

2.
Are
the
Standards
for
Engines
75
 
750
hp
feasible?

There
are
three
primary
test
provisions
and
associated
standards
in
the
Tier
4
program
we
are
finalizing
today.
These
are
the
Nonroad
Transient
Cycle
(
NRTC),
the
existing
International
Organization
for
Standardization
(
ISO)
C1
steady­
state
cycle,
and
the
highway­
based
Not­
To­
Exceed
(
NTE)
provisions.
46
Under
today's
rules,
most
nonroad
diesel
engines
must
meet
the
new
standards
for
each
of
these
three
test
cycles
(
the
exceptions
are
noted
below).
Compliance
on
the
transient
test
cycle
includes
weighting
the
results
from
a
cold
start
and
hot
start
test
with
the
cold
start
emissions
weighted
at
1/
20
and
hot
start
emissions
weighted
at
19/
20.
Additionally,
we
have
alternative
optional
test
cycles
including
the
existing
ISO­
D2
steady­
state
cycle
and
the
Transportation
Refrigeration
Unit
(
TRU)
cycle
which
a
manufacturer
can
choose
to
use
for
certification
in
lieu
of
the
NRTC
and
the
ISO­
C1,
provided
that
the
manufacturer
can
demonstrate
to
the
Agency
that
the
engine
will
only
be
used
in
a
limited
range
of
nonroad
equipment
with
known
operating
conditions.
A
complete
discussion
of
these
various
test
cycles
can
be
found
in
chapter
4.2,
4.3,
and
4.4
of
the
RIA.

The
standards
we
are
finalizing
today
for
nonroad
engines
with
rated
power
from
75
to
750
hp
are
based
upon
the
performance
of
technologies
and
standards
for
highway
diesel
engines
which
go
into
effect
in
2007.
As
explained
above,
we
believe
these
technologies,
namely
NO
X
adsorbers
and
catalyzed
diesel
particulate
filters
enabled
by
15
ppm
sulfur
diesel
fuel,
can
be
applied
to
nonroad
diesel
engines
in
a
similar
manner
as
for
highway
diesel
engines.
The
combustion
process
and
the
means
to
modify
that
process
are
fundamentally
the
same
for
highway
and
nonroad
diesel
engines
regardless
of
engine
size.
The
formation
mechanism
and
quantity
of
64
pollutants
formed
in
diesel
engines
are
fundamental
characteristics
of
engine
design
and
are
not
inherently
different
for
highway
and
nonroad
engines
regardless
of
engine
size.
The
effectiveness
of
NO
X
adsorbers
to
control
NO
X
emissions
and
CDPFs
to
control
PM,
NMHC,
and
CO
emissions
are
determined
by
fundamental
catalyst
and
filter
characteristics.
Therefore,
we
disagree
with
commenters
who
suggest
that
these
highway
technology
based
emission
standards
are
infeasible
for
nonroad
engines.
We
acknowledge
the
comments
raised
regarding
the
unique
characteristics
nonroad
diesel
engines
which
must
be
considered
in
setting
these
standards,
and
we
have
addressed
those
issues
by
allowing
(
where
appropriate)
for
additional
lead
time
or
slightly
less
stringent
standards
for
nonroad
diesel
engines
in
comparison
to
highway
diesel
engines
(
and
likewise
have
made
appropriate
cost
estimates
to
account
for
the
technology
and
engineering
needed
to
address
these
issues).

PM
Standard
We
are
finalizing
a
PM
standard
for
engines
in
this
category
of
0.01
g/
bhp­
hr
based
upon
the
emissions
reductions
possible
through
the
application
of
a
CDPF
and
15ppm
sulfur
diesel
fuel.
This
is
the
same
emissions
level
as
for
highway
diesel
engines
in
the
heavy­
duty
2007(
HD2007)
program
(
66
FR
5001,
January
18,
2001).
While
emission
levels
of
engine­
out
soot
(
the
solid
carbon
fraction
of
PM)
may
be
somewhat
higher
for
some
nonroad
engines
when
compared
to
highway
engines,
these
emissions
are
virtually
eliminated
(
reduced
by
99
percent)
by
the
CDPF
technology.
With
application
of
the
CDPF
technology,
the
soluble
organic
fraction
(
SOF)
portion
of
diesel
PM
is
predicted
to
be
all
but
eliminated.
The
primary
emissions
from
a
CDPF
equipped
engine
are
sulfate
PM
emissions
formed
from
sulfur
in
diesel
fuel.
The
emissions
rate
for
sulfate
PM
is
determined
primarily
by
the
sulfur
level
of
the
diesel
fuel
and
the
rate
of
fuel
consumption.
With
the
15
ppm
sulfur
diesel
fuel,
the
PM
emissions
level
from
a
CDPF
equipped
nonroad
diesel
engine
will
be
similar
to
the
emissions
rate
of
a
comparable
highway
diesel
engine.
Therefore,
the
0.01
g/
bhp­
hr
emission
level
is
feasible
for
nonroad
engines
tested
on
the
NRTC
cycle
and
on
the
steady­
state
cycles,
ISO­
C1
and
ISO­
D2.
Put
another
way,
control
of
PM
using
CDPF
technology
is
essentially
independent
of
duty
cycle
given
active
catalyst
technology
(
for
reliable
regeneration
and
SOF
oxidation),
adequate
control
of
temperature
(
for
reliable
regeneration)
and
low
sulfur
diesel
fuel
(
for
reliable
regeneration
and
low
PM
emissions).
While
some
commenters
argued
that
PM
filters
will
not
enable
the
0.01
PM
emission
standard
for
nonroad
engines,
we
remain
convinced
by
the
demonstration
of
0.01
or
lower
PM
emission
levels
from
a
number
of
diesel
engines
described
in
the
RIA,
that
the
standard
is
feasible
given
the
leadtime
provided
and
the
availability
of
15
ppm
sulfur
diesel
fuel.
Likewise,
the
NTE
provisions
for
nonroad
engines
are
the
same
as
for
on­
highway
engines
meeting
an
equivalent
PM
control
level.
The
maximum
PM
emission
level
from
a
CDPF
equipped
diesel
engine
is
primarily
determined
by
the
maximum
fuel
sulfur
conversion
level
experienced
at
the
highest
operating
conditions.
As
documented
in
RIA
chapter
4.1.1.3,
testing
of
diesel
engines
at
conditions
representative
of
the
highest
sulfate
PM
formation
rates
shows
PM
levels
below
the
level
required
by
the
NTE
provisions
when
tested
on
less
than
15
ppm
sulfur
diesel
fuel.

NO
X
Standard
47
For
engines
between
75
and
100
horsepower,
this
may
require
re­
optimization
of
the
engine
to
lower
NOX
emissions
if
they
are
higher
than
3.0,
but
we
would
not
expect
any
new
hardware
beyond
the
Tier
3
hardware
to
be
required
in
the
Tier
4
timeframe
to
accomplish
this
reduction.

65
We
are
finalizing
a
NO
X
standard
of
0.30
g/
bhp­
hr
for
engines
in
this
category
based
upon
the
emission
reductions
possible
from
the
application
of
NO
X
adsorber
catalysts
and
the
expected
emission
levels
for
Tier
3
compliant
engines
which
form
the
baseline
technology
for
Tier
4
engines.
The
Tier
3
emission
standards
are
a
combined
NMHC+
NO
X
standard
of
3.0
g/
bhp­
hr
for
engines
greater
than
100
hp
and
less
than
750
horsepower.
For
engines
less
than
100
hp
but
greater
than
50
horsepower
the
Tier
3
NMHC+
NO
X
emission
standard
is
3.5
g/
bhp­
hr.
We
believe
that
in
the
time­
frame
of
the
Tier
4
emission
standards,
all
engines
from
75
to
750
hp
can
be
developed
to
control
NO
X
emissions
to
engine­
out
levels
of
3.0
g/
bhp­
hr
or
lower.
47
This
means
that
all
engines
will
need
to
apply
Tier
3
emission
control
technologies
(
i.
e.,
turbochargers,
charge­
air­
coolers,
electronic
fuel
systems,
and
for
some
manufacturers
EGR
systems)
to
get
to
this
baseline
level.
As
discussed
in
more
detail
in
the
RIA,
our
analysis
of
the
NRTC
and
the
ISOC1
cycles
indicates
that
the
NO
X
adsorber
catalyst
can
provide
a
90
percent
or
greater
NO
X
reduction
level
on
the
cycles.
The
standard
of
0.30
g/
bhp­
hr
reflects
a
baseline
emissions
level
of
3.0
g/
bhp­
hr
and
a
greater
than
90
percent
reduction
of
NO
X
emissions
through
the
application
of
the
NO
X
adsorber
catalyst.
The
additional
lead
time
available
to
nonroad
engine
manufacturers
and
the
substantial
learning
that
will
be
realized
from
the
introduction
of
these
same
technologies
to
highway
diesel
engines,
plus
the
lack
of
any
fundamental
technical
impediment,
makes
us
confident
that
the
new
NO
X
standards
can
be
met.

Given
the
fundamental
similarities
between
highway
and
nonroad
diesel
engines,
we
believe
that
the
NO
X
adsorber
technology
developed
for
highway
engines
can
be
applied
with
equal
effectiveness
to
nonroad
diesel
engines
with
additional
developments
in
engine
thermal
management
(
as
discussed
in
section
II.
B.
2
above)
to
address
the
more
widely
varied
nonroad
operating
cycles.
In
fact,
as
discussed
previously,
the
NO
X
adsorber
catalyst
temperature
window
is
particularly
well
matched
to
transient
operating
conditions
as
typified
by
the
NRTC.

As
pointed
out
by
some
commenters,
compliance
with
the
NTE
provisions
will
be
challenging
for
the
nonroad
engine
industry
due
to
the
diversity
of
nonroad
products
and
operating
cycles.
However,
the
technical
challenge
is
reduced
somewhat
by
the
1.5
multiplier
used
to
calculate
the
NTE
standard
as
discussed
in
section
III.
J.
Controlling
NO
X
emissions
under
NTE
conditions
is
fundamentally
similar
for
both
highway
and
nonroad
engines.
The
range
of
control
is
the
same
and
the
amount
of
reduction
required
is
also
the
same.
We
know
of
no
technical
impediment,
nor
were
any
raised
by
commenters,
that
would
prevent
achieving
the
NTE
standard
under
the
zone
of
operating
conditions
required
by
the
NTE.

NMHC
Standard
48
"
The
Impact
of
Sulfur
in
Diesel
Fuel
on
Catalyst
Emission
Control
Technology,"
report
by
the
Manufacturers
of
Emission
Controls
Association,
March
15,
1999,
pp.
9
&
11.
Copy
available
in
EPA
Air
Docket
A­
2001­
28
Item
II­
A­
67.

66
Meeting
the
NMHC
standard
under
the
lean
operating
conditions
typical
of
the
biggest
portion
of
NO
X
adsorber
operation
should
not
present
any
special
challenges
to
nonroad
diesel
engine
manufacturers.
Since
CDPFs
and
NO
X
adsorbers
contain
platinum
and
other
precious
metals
to
oxidize
NO
to
NO
2,
they
are
also
very
efficient
oxidizers
of
hydrocarbons.
NMHC
reductions
of
greater
than
95
percent
have
been
shown
over
transient
and
steady­
state
test
procedures.
48
Given
that
typical
engine­
out
NMHC
is
expected
to
be
in
the
0.40
g/
bhp­
hr
range
or
lower
for
engines
meeting
the
Tier
3
standards,
this
level
of
NMHC
reduction
will
mean
that
under
lean
conditions
emission
levels
will
be
well
below
the
standard.
For
the
same
reasons,
there
is
no
obstacle
which
would
prevent
achieving
the
NTE
standard.

Under
the
brief
episodic
periods
of
rich
operation
necessary
to
regenerate
NO
X
adsorber
catalysts,
it
is
possible
to
briefly
experience
higher
levels
of
NMHC
emissions.
Absent
a
controlling
standard,
it
is
possible
that
these
NMHC
emissions
could
be
high.
There
are
two
possible
means
to
control
the
NMHC
emissions
during
these
periods
in
order
to
meet
the
NMHC
standard
finalized
today.
Manufacturers
can
design
the
regeneration
system
and
the
oxygen
storage
(
oxidation
function
under
rich
conditions)
of
the
NO
X
adsorber
catalyst
such
that
the
NMHC
emissions
are
inherently
controlled.
This
is
similar
to
the
control
realized
on
today's
three­
way
automotive
catalysts
which
also
experience
operation
that
toggles
between
rich
and
lean
conditions.
Secondly,
a
downstream
clean­
up
catalyst
can
be
used
to
oxidize
the
excess
NMHC
emissions
to
a
level
below
the
standard.
This
approach
has
been
used
in
the
NO
X
adsorber
demonstration
program
at
EPA
described
in
the
RIA.
Our
cost
analysis
for
engines
in
the
75
to
750
hp
category
includes
a
cost
for
a
clean­
up
catalyst
to
perform
this
function.

Cold
Start
The
standards
include
a
cold
start
provision
for
the
NRTC
procedure.
This
means
that
the
results
of
a
cold
start
transient
test
will
be
weighted
with
the
emissions
of
a
hot
start
test
in
order
to
calculate
the
emissions
for
compliance
against
the
standards.
In
a
change
from
the
proposed
rule,
the
weightings
are
1/
20
cold
start
and
19/
20
for
the
hot
start
(
as
opposed
to
the
proposed
weightings
of
1/
10
and
9/
10,
respectively)
as
described
more
fully
in
chapter
4.2
of
the
RIA
and
section
III.
F
below.
Because
exhaust
temperatures
are
so
important
to
catalyst
performance,
a
cold
start
provision
is
an
important
tool
to
ensure
that
the
emissions
realized
in
use
are
consistent
with
the
expectations
of
this
program.
Achieving
this
standard
represents
an
additional
technical
challenge
for
NO
X
control
and
to
a
lesser
extent
CO
and
NMHC
control
(
i.
e.,
control
of
gaseous
pollutants).
PM
control
with
a
CDPF
is
not
expected
to
be
significantly
impacted
by
cold­
start
provisions
due
to
the
primary
filter
mechanism
being
largely
unaffected
by
temperature.
49
The
combined
weighted
average
performance
is
calculated
as
1/
20
(
cold­
start)
+
19/
20
(

hotstart
Hence
it
can
be
seen
that
1/
20
(
70%)
+
19/
20
(
91%)
=
90%
and
likewise
that
1/
20
(
50%)
+
19/
20
67
With
respect
to
achievability
of
the
NO
X,
CO
and
NMHC
standards,
during
the
initial
start
and
warmup
period
for
a
diesel
engine,
the
exhaust
temperatures
are
typically
below
the
light­
off
temperature
of
a
catalyst.
As
a
result,
exhaust
stack
emissions
may
initially
be
higher
during
this
period
of
operation.
The
cold
start
test
procedure
is
designed
to
quantify
these
emissions
to
ensure
that
emission
control
systems
are
designed
appropriately
to
minimize
the
contribution
of
cold­
start
emissions.
Cold­
start
emissions
can
be
minimized
by
improving
catalyst
technology
to
allow
for
control
at
lower
exhaust
temperatures
(
i.
e.,
by
lowering
the
catalyst
light­
off
temperature)
and
by
applying
strategies
to
quickly
raise
the
exhaust
temperature
to
a
level
above
the
catalyst
light­
off
temperature.

There
are
number
of
technologies
available
to
the
engine
manufacturer
to
promote
rapid
warmup
of
the
exhaust
and
emission
control
system.
These
include
retarding
injection
timing,
increasing
EGR,
and
potentially
late
cycle
injection,
all
of
which
are
technologies
we
expect
manufacturers
to
apply
as
part
of
the
normal
operation
of
the
NO
X
adsorber
catalyst
system.
These
are
the
same
technologies
we
expect
highway
engine
manufacturers
to
use
in
order
to
comply
with
the
highway
cold
start
FTP
provision
which
weights
cold
start
emissions
more
heavily
with
a
1/
7
weighting.
As
a
result,
we
expect
the
transfer
of
highway
technology
to
be
well
matched
to
accomplish
this
control
need
for
nonroad
engines
as
well.
Using
these
technologies
we
expect
nonroad
engine
manufacturers
to
be
able
to
comply
with
the
new
Tier
4
NO
X,
CO,
and
NMHC
emission
standards
including
the
cold
start
provisions
of
the
transient
test
procedure.

One
commenter
has
raised
the
concern
that
if
diesel
engines
are
no
cleaner
than
3
g/
bhp­
hr
NO
X
and
if
NO
X
adsorbers
can
be
no
more
efficient
than
90
percent,
then
any
increase
in
NO
X
emissions
above
the
0.30
g/
bhp­
hr
level
on
a
cold­
start
test
will
make
the
emission
standards
infeasible.
We
should
clarify,
when
discussing
the
emission
reduction
potential
of
the
NO
X
adsorber
catalyst
generically
in
the
NPRM,
we
have
sometimes
simply
stated
that
it
is
90
percent
or
more
effective
without
plainly
saying
that
this
refers
to
our
expectation
for
average
performance
considering
both
cold
and
hot
start
emissions.
More
precisely
then,
we
would
expect
lower
effectiveness
over
the
cold­
start
test
procedure
with
somewhat
higher
effectiveness
realized
over
the
hot­
start
test
procedure.
Because
of
the
relative
weightings
of
the
two
test
cycles
(
i.
e.,
1/
20
for
the
cold­
start
and
19/
20
for
the
hot­
start),
although
the
degradation
of
performance
below
90
percent
over
the
cold­
start
cycle
can
be
substantially
greater
than
the
performance
above
90
percent
realized
over
the
hot­
start
cycle,
the
standards
remain
feasible.
For
example,
even
if
the
average
NO
X
adsorber
performance
over
the
cold­
start
test
cycle
was
only
70
percent,
the
average
NO
X
adsorber
performance
over
the
hot­
start
portion
of
the
test
cycle
would
only
need
to
be
91
percent
in
order
to
realize
a
weighted
average
performance
of
90
percent.
Similarly,
were
the
cold­
start
test
cycle
performance
only
50
percent,
the
hot­
start
performance
would
only
need
to
be
92
percent
in
order
to
realize
a
weighted
average
performance
of
90
percent.
49
We
are
confident,
based
on
our
estimates
of
NO
X
adsorber
performance
over
the
(
92%)
=
90%.

68
nonroad
test
cycle
summarized
in
the
RIA,
that
NO
X
adsorber
performance
in
excess
of
92
percent
can
be
expected
in
the
time
frame
of
the
requirements
finalized
today.

Complying
with
the
PM
standard
given
consideration
of
the
cold
start
test
procedure
is
not
expected
to
be
as
challenging
as
compliance
with
the
NO
X
standard.
The
effectiveness
for
PM
filtration
is
not
significantly
effected
by
exhaust
temperatures,
as
noted
earlier.
Thus,
PM
emission
levels
are
similar
over
the
cold
and
hot
start
tests.

The
standards
that
we
are
finalizing
today
for
nonroad
engines
with
rated
horsepower
levels
from
75
to
750
hp
are
based
upon
the
same
emission
control
technologies,
clean
15ppm
or
lower
sulfur
diesel
fuel,
and
relative
levels
of
emission
control
effectiveness
as
the
HD
2007
emission
standards.
We
have
given
consideration
to
the
diversity
of
nonroad
equipment
for
which
these
technologies
must
be
developed
and
the
timing
of
the
Tier
3
emissions
standards
in
determining
the
appropriate
timing
for
the
Tier
4
standards.
Based
upon
the
availability
of
the
emission
control
technologies,
the
proven
effectiveness
of
the
technologies
to
control
diesel
emissions
to
these
levels,
the
technology
paths
identified
here
to
address
constraints
specific
to
nonroad
equipment,
and
the
additional
lead
time
afforded
by
the
timing
of
the
standards,
we
have
concluded
that
the
standards
are
technically
feasible
in
the
leadtime
provided.

3.
Are
the
Standards
for
Engines
above
750
hp
Feasible?

The
preceding
discussion
of
the
standards
for
engines
of
75
to
750
hp
highlights
the
main
thrust
of
our
new
Tier
4
program,
a
focus
on
realizing
very
low
on­
highway
like
emission
levels
for
the
vast
majority
of
nonroad
diesel
engines.
The
emission
standards
and
the
combination
of
technologies
that
we
expect
will
be
used
to
meet
those
standards
are
virtually
identical
to
the
HD2007
program
for
on­
highway
engines.
The
following
three
sections
(
II.
B.
3,
II.
B.
4,
and
II.
B.
5)
describing
the
feasibility
of
the
standards
for
engines
above
750
hp,
from
25
to
75
hp,
and
below
25
hp,
while
following
the
same
pattern
and
objective,
take
additional
consideration
of
the
fact
that
engines
and
equipment
in
these
size
categories
have
no
direct
on­
highway
equivalent
and
differ
from
highway
engines
in
substantial
ways
that
cause
us
to
reach
differing
conclusions
regarding
the
appropriate
standards
and
timing
for
those
standards.
Whether
in
scale,
or
use,
or
operating
conditions,
the
characteristics
of
these
engines
and
equipment
are
such
that
we
have
taken
particular
consideration
of
them
in
setting
the
timing
and
level
of
the
standards.
The
remainder
of
this
section
(
II.
B.
3)
discusses
what
makes
the
above
750
hp
category
unique
and
why
the
standards
which
we
are
adopting
are
technologically
feasible.

a.
What
makes
the
over
750
hp
category
different?

The
first
and
most
obvious
difference
for
engines
in
this
horsepower
category
is
scale.
No
on­
highway
engines
come
close
to
the
size
of
the
largest
engines
in
this
category
which
can
produce
in
excess
of
3,000
horsepower,
consist
of
16
or
more
cylinders
and
have
12
or
more
69
turbochargers.
The
engines,
and
the
equipment
that
they
power,
are
quite
simply
significantly
larger
than
any
on­
highway
diesel
engine.
Many
commenters
argued
that
emission
technologies
from
on­
highway
vehicles
could
not
be
simply
scaled
up
for
these
larger
engines
and
that
if
they
were,
the
consequences
of
this
resizing
would
include
structural
weakness
and
reduced
system
robustness.
As
discussed
below,
our
review
of
the
information
provided
with
these
comments
and
our
subsequent
analysis
of
the
technical
characteristics
of
some
emission
control
components
has
led
us
to
conclude
that
revised
emission
standards
(
based
on
performance
of
different
technologies
that
those
whose
performance
formed
the
basis
for
the
proposed
rule)
from
those
we
proposed
for
this
horsepower
category
are
appropriate
and
available.

We
have
concluded
that
it
is
appropriate
to
distinguish
between
two
broad
categories
of
engines
over
750
hp
grouped
by
application:
mobile
machines
and
generator
sets.
Mobile
machines
include
the
very
largest
nonroad
equipment
used
in
mining
trucks
and
large
excavation
equipment.
The
environment
and
operating
conditions
(
especially
for
vibration)
represent
the
harshest
application
into
which
nonroad
engines
are
applied.
Design
considerations
for
technologies
used
to
control
emissions
from
engines
in
these
applications
must
first
consider
robustness
to
the
harsh
environments
that
will
be
experienced
in
use.
In
contrast,
mobile
nonroad
generator
sets
operate
in
relatively
good
operating
environments.
In
addition,
while
mobile
nonroad
generator
sets
can,
and
are
moved
between
operating
locations,
they
are
always
stationary
during
actual
operation.
Thus
the
levels
of
vibration
and
the
general
environment
for
engine
operation
are
significantly
less
demanding
for
generator
sets
than
for
mobile
machines.
Also
the
dynamic
range
of
operation
is
significantly
narrower
and
less
demanding
for
generator
sets.
Designed
to
operate
at
a
set
engine
speed,
synchronous
to
the
frequency
cycle
desired
for
electric
generation
(
i.
e.,
1200
or
1800
RPM
for
60hz),
diesel
engines
designed
for
generator
set
applications
can
be
optimized
for
operation
in
this
narrow
range.

We
have
given
specific
consideration
to
the
unique
engineering
challenges
for
engines
in
this
horsepower
category
in
determining
the
appropriate
emission
standards
set
in
today's
action.
We
have
also
taken
into
account
the
important
differences
between
generator
set
applications
and
other
mobile
applications
in
developing
standards
for
this
horsepower
category.

b.
Are
the
new
Tier
4
standards
for
over
750
hp
engines
technologically
feasible?

The
emission
standards
described
in
section
II.
A
above
describe
a
comprehensive
program
for
engines
over
750
hp
that
give
consideration
to
both
the
physical
size
of
these
engines
and
the
applications
into
which
these
engines
are
applied.
Engines
in
this
power
category
must
show
compliance
with
the
C1
or
D2
steady­
state
test
cycles
as
appropriate
as
well
as
with
the
NTE
provisions
finalized
today.
As
described
in
sections
III.
F
and
III.
G,
these
engines
will
not
be
tested
over
the
NRTC
nor
will
they
be
subject
to
a
cold­
start
test
procedure.
The
feasibility
discussion
in
this
section
describes
expected
performance
of
the
engines
over
the
required
test
cycles
and
the
NTE.
This
section
will
briefly
summarize
the
feasibility
analysis
contained
in
the
RIA
for
these
engines.
70
PM
Standards
Beginning
in
2011
all
nonroad
diesel
engines
above
750
hp
must
meet
a
PM
standard
of
0.075
g/
bhp­
hr.
We
believe
that
this
PM
standard
is
feasible
based
on
the
substantial
reductions
in
sulfate
PM
due
to
the
use
of
15
ppm
sulfur
diesel
fuel
and
the
potential
to
improve
the
combustion
process
to
reduce
PM
emissions
formed
in
the
engine.
Specifically,
we
believe
based
on
the
evidence
in
the
RIA
that
increasing
fuel
injection
pressure,
improving
electronic
controls
and
optimizing
the
combustion
system
geometry
will
allow
engine
manufacturers
to
meet
this
level
of
PM
control
in
2011.
Some
engine
manufacturers
have
in
fact
indicated
to
the
Agency
that
this
level
of
control
represents
an
achievable
goal
by
2011.
One
commenter
argued
however,
that
a
more
relaxed
standard
of
0.1
g/
bhp­
hr
based
on
today's
on­
highway
diesel
engine
performance
would
be
appropriate.
We
disagree
with
this
comment,
believing
that
given
the
substantial
leadtime
available
and
the
potential
for
further
improvements
in
combustion
systems,
that
it
is
appropriate
to
set
a
forward
looking
PM
standard
of
0.075
g/
bhp­
hr.
Conversely,
other
commenters
argued
that
future
on­
highway
PM
filter
technology
should
be
applied
to
this
class
of
engines
as
early
as
2011
(
i.
e.,
that
a
standard
of
0.01
g/
bhp­
hr
PM
is
appropriate).
While
we
agree
with
the
commenters
that
in
the
long­
term
it
will
be
appropriate
to
apply
filter­
based
emission
control
technologies
to
these
engines,
we
do
not
agree
that
such
control
is
appropriate
as
early
as
2011.
As
the
following
section
explains,
we
believe
that
there
are
remaining
technical
challenges
to
be
addressed
prior
to
the
application
of
PM
filters
to
these
engines
and
that
it
is
necessary
to
allow
additional
leadtime
for
those
challenges
to
be
addressed.

Beginning
in
2015
all
nonroad
engines
over
750
hp
must
meet
stringent
PM
filter
technology­
based
emission
standards
of
0.02
g/
bhp­
hr
for
engines
used
in
generator
set
applications
and
0.03
g/
bhp­
hr
for
engines
used
in
mobile
machine
applications.
We
are
predicating
these
emission
standards
based
on
the
application
of
a
different
form
of
diesel
particulate
filter
technology,
a
wire
or
fiber
mesh
depth
filter
rather
than
a
ceramic
wall
flow
filter.
Wire
mesh
filters
are
capable
of
reducing
PM
by
70
percent
or
more.
We
have
not
based
these
standards
upon
the
more
efficient
(>
90
percent)
control
possible
from
ceramic
wall
flow
style
PM
filters,
because
we
believe
that
the
application
of
the
wall
flow
filter
technology
on
engines
of
this
size
has
not
been
adequately
demonstrated
at
this
time.
While
it
would
certainly
be
possible
to
apply
the
ceramic­
based
technology
to
these
larger
engines,
we
cannot
today
conclude
with
certainty
that
such
systems
would
be
as
robust
in­
use
as
needed
(
see
earlier
discussion
in
section
II.
B.
1.
b).
Considering
the
information
available
to
the
Agency
today,
we
believe
it
appropriate
to
set
the
long
term
PM
standard
for
these
very
large
engines
based
on
technologies
which
we
can
project
with
confidence
will
give
high
levels
of
emission
reduction,
durability,
and
robustness
when
scaled
to
these
very
large
engine
sizes.

The
0.01
g/
bhp­
hr
difference
in
the
PM
emission
standards
between
the
standard
for
generator
sets
and
for
other
mobile
applications
in
this
category
(
0.01
g/
bhp­
hr
lower
for
generator
sets)
reflects
our
expectation
that
engine­
out
emissions
from
generator
sets
can
be
reduced
below
the
level
for
mobile
machines
due
to
generator
set
operation
at
a
single
engine
speed.
Without
the
need
to
provide
full
power
and
control
over
the
wider
range
of
possible
71
operating
conditions
that
mobile
machines
must
deliver,
we
believe
that
the
air
handling
systems
(
especially
the
turbocharger
match
to
the
engine)
can
be
improved
to
provide
a
moderate
reduction
in
engine­
out
emissions.
This,
coupled
with
the
reduction
afforded
by
the
PM
filter
technology,
would
allow
generator
sets
to
meet
a
more
stringent
0.02
g/
bhp­
hr
standard.
Diesel
engines
designed
for
use
in
generator
sets
meeting
this
standard
will
need
to
demonstrate
compliance
over
the
appropriate
test
cycles,
either
the
ISO
C1
or
D2
tests.
As
discussed
in
RIA
chapter
4.3.6.2,
PM
emission
rates
are
nearly
the
same
for
steady­
state
testing
or
for
alternative
ramped
modal
cycle
(
RMC)
testing.
These
test
cycles,
like
the
engines,
are
designed
to
be
representative
of
the
range
of
operation
expected
from
a
generator
set.

As
discussed
previously,
PM
emission
control
over
the
NTE
region
for
PM
filter
equipped
diesel
engines
is
predominantly
a
function
of
sulfate
formation
at
high
exhaust
temperatures.
Given
that
fuel
consumption
(
and
thus
sulfur)
consumption
rates
on
a
brake
specific
basis
tend
to
be
lower
for
engines
above
750hp,
we
can
conclude
that
the
increase
in
PM
emissions
over
the
NTE
region
will
likely
be
lower
for
these
engines
than
for
engines
meeting
the
0.01
g/
bhp­
hr
standard.
Thus,
we
can
conclude
based
on
the
evidence
in
the
RIA
that
compliance
with
the
NTE
provisions
for
PM
is
feasible
for
engines
over
750
hp.

Although
we
are
projecting
that
manufacturers
will
comply
with
this
standard
using
a
slightly
less
efficient
PM
filter
technology,
we
remain
convinced
that
15
ppm
sulfur
diesel
fuel
will
still
be
a
necessity
for
this
technology
to
be
applied.
Regardless
of
the
filter
media
chosen
for
the
PM
filter,
the
filter
will
still
require
catalyst­
based
systems
to
ensure
robust
regeneration
and
adequate
control
of
the
SOF
portion
of
PM.
As
these
catalyst­
based
technologies
are
adversely
impacted
by
sulfur
in
diesel
fuel
as
described
in
II.
C
below,
15
ppm
sulfur
diesel
fuel
will
be
required
in
order
to
ensure
compliance
with
the
PM
standards
finalized
here
for
engines
over
750
hp.

NO
X
Standards
As
with
the
PM
standards,
we
are
setting
distinct
NO
X
standards
for
this
category
of
engines
reflecting
particular
concerns
with
the
application
of
technologies
to
engines
of
this
size
and
our
desire
to
realize
significant
NO
X
reductions
as
soon
as
possible.
There
are
two
sets
of
NO
X
standards
that
we
are
finalizing
today,
a
0.50
g/
bhp­
hr
NO
X
standard
for
engines
used
in
generator
set
applications
and
a
2.6
g/
bhp­
hr
NO
X
standard
for
mobile
machines.

For
engines
used
in
generator
set
applications
we
are
finalizing
a
0.50
g/
bhp­
hr
standard
that
goes
into
effect
for
engines
above
1,200
hp
in
2011
and
in
2015
for
engines
above
750
hp.
We
see
two
possible
technology
options
for
manufacturers
to
meet
these
standards.
First,
compliance
with
this
NO
X
standard
will
be
possible
through
the
application
of
a
dual
bed
NO
X
adsorber
system
(
i.
e.,
a
system
that
allows
regeneration
to
be
controlled
external
to
the
engine).
This
approach
can
work
well
for
generator
set
applications
where
packaging
constraints
and
vibration
issues
are
greatly
reduced.
Since
this
approach
requires
limited
engine
redesign,
it
would
be
an
appealing
approach
for
these
large
engines
sold
in
very
low
volumes.
NO
X
adsorber
50
Emerachem
EMxTM
Datasheet
­
Describing
the
EMx
IC
(
Internal
Combustion)
System
Air
Docket
OAR­
2003­
0012­
0948.

51
See
for
example
68
FR
28375,
May
23,
2003.

52
Fleetguard
StableGuardTM
Urea
Premix
for
use
with
SCR
NOX
Reduction
Systems,
Air
Docket
A­
2001­
28
Item
IV­
A­
04.

72
systems
for
stationary
power
generation
(
systems
that
never
move)
are
available
today
on
a
retrofit
basis,
and
we
believe
with
further
development
to
address
packaging
and
durability
concerns
that
similar
systems
can
be
applied
to
mobile
generator
sets.
50
A
second
possible
technology
option
for
engines
in
this
category
is
urea
SCR.
The
challenges
for
urea
SCR
in
mobile
applications
are
well
known,
specifically
a
lack
of
urea
infrastructure
to
provide
urea
refill
at
diesel
fueling
locations
and
a
need
to
ensure
that
urea
is
added
as
necessary
in
use.
51
These
hurdles
can
be
addressed
more
easily
for
generator
sets
than
for
virtually
any
other
mobile
source
emission
category.
Although
nonroad
generator
sets
are
mobile,
in
operation
they
remain
at
a
fixed
location
where
fuel
is
delivered
to
them
periodically
(
i.
e.,
a
1,200
hp
generator
set
does
not
and
cannot
pull
into
the
local
truck
stop
for
a
fuel
fill).
Therefore,
the
same
infrastructure
that
currently
provides
urea
delivery
for
stationary
power
generation
can
also
be
utilized
for
nonroad
generator
set
applications.
52
It
would
still
remain
for
the
manufacturer
to
develop
a
mechanism
to
ensure
urea
refill,
but
we
believe
it
is
likely
that
solutions
to
this
problem
can
be
addressed
through
monitoring
as
for
stationary
source
emissions
or
other
technology
options
(
e.
g.,
a
urea
interlock
that
precludes
engine
operation
without
the
presence
of
urea).

Either
of
these
technology
approaches
could
be
applied
to
realize
an
approximately
90
percent
reduction
from
the
current
Tier
2
emission
levels
for
these
engines
in
order
to
comply
with
an
emission
standard
of
0.50
g/
bhp­
hr.
The
0.50
g/
bhp­
hr
standard
is
different
from
our
proposed
level
of
0.30
g/
bhp­
hr
reflecting
the
changes
we
have
made
in
this
final
action
to
the
implementation
schedule
for
this
class
of
engines
and
therefore
our
projections
for
a
technology
path.
At
the
time
of
the
proposal,
we
projected
that
this
class
of
engine
would
follow
an
integrated
two­
step
technology
path.
We
are
now
finalizing
a
program
that
anticipates
the
application
of
90
percent
effective
NO
X
control
to
diesel
engines
for
use
in
generator
sets
without
a
reduction
in
engine­
out
NO
X
levels
beyond
Tier
2.
This
reflects
our
desire
to
focus
on
getting
the
largest
emission
reduction
possible
in
the
near
term
(
beginning
in
2011)
from
these
engines.
Where
we
believe
additional
technology
development
is
needed,
as
is
the
case
for
mobile
machines
over
750
hp,
we
are
finalizing
a
more
gradual
emission
reduction
technology
pathway
anticipating
further
reductions
in
engine­
out
NO
X
emissions
followed
by
a
possible
future
action
to
reduce
emissions
further
as
described
in
section
II.
A.
RIA
chapter
4.1.2.3.3
describes
NO
X
adsorber
effectiveness
to
control
NO
X
emissions
including
effectiveness
over
the
NTE
region.
The
discussion
there
is
equally
applicable
to
engines
above
and
below
750
hp
regarding
NTE
73
performance
because
the
key
attribute
of
NTE
performance
(
exhaust
temperature)
is
similar
for
engines
across
the
horsepower
range.

For
engines
over
750
hp
used
in
mobile
machines
(
and
for
750
 
1200
hp
generator
sets
from
2011
until
2015)
we
are
setting
a
new
NO
X
standard
of
2.6
g/
bhp­
hr
beginning
in
2011.
We
are
predicating
this
level
of
emission
control
(
an
approximate
50
percent
reduction
from
Tier
2)
on
an
improved
combustion
system
and
proven
engine­
based
NO
X
control
technologies.
Specifically,
we
believe
manufacturers
can
apply
either
proven
cooled
EGR
technology,
or
apply
additional
levels
of
engine
boost,
a
limited
form
of
Miller
Cycle
operation,
and
increased
intercooling
capacity
for
the
two­
stage
turbocharging
systems
that
are
used
on
these
engines.
The
second
approach
for
in­
cylinder
emissions
reductions
is
similar
in
description
at
least
to
the
Caterpillar
ACERT
technology
which
we
believe
could
be
another
path
for
compliance
with
this
standard.
We
are
projecting
a
modest
increase
in
heat­
rejection
to
the
engine
coolant
for
these
incylinder
emission
control
solutions
and
have
accounted
for
those
costs
in
our
cost
analysis.
These
approaches
for
NO
X
reduction
have
been
proven
for
on­
highway
diesel
engines
since
2003
including
compliance
with
NTE
provisions
similar
to
those
for
nonroad
engines
finalized
here.
We
can
conclude
based
on
the
on­
highway
experience
that
the
NTE
provisions
can
be
met
for
engines
in
this
horsepower
category.
One
commenter
suggested
that
a
standard
of
3.5
g/
bhp­
hr
would
be
achievable
in
this
time
frame.
As
described
here,
we
believe
that
further
emission
reductions
to
2.6
g/
bhp­
hr
are
possible
in
this
time
frame.
Engine
manufacturers
have
indicated
to
the
Agency
that
they
believe
this
level
of
in­
cylinder
emission
control
can
be
realized
for
these
very
large
diesel
engines
by
2011.
We
are
deferring
any
decision
on
setting
aftertreatment
based
NO
X
standards
for
mobile
machinery
above
750
hp
to
allow
additional
time
to
evaluate
the
technical
issues
involved,
as
discussed
in
section
II.
A.
4.

NMHC
Standards
We
are
setting
two
different
NMHC
emission
standards
for
engines
in
this
category
linked
to
the
technologies
used
to
control
PM
emissions.
We
are
requiring
all
engines
over
750
hp
to
meet
an
NMHC
standard
of
0.30
g/
bhp­
hr
starting
in
2011.
As
explained
earlier,
in
2011
all
engines
over
750
hp
must
meet
a
PM
emission
standard
of
0.075
g/
bhp­
hr.
We
are
projecting
that
manufacturers
will
meet
this
standard
through
improvements
in
in­
cylinder
emission
control
of
PM
(
in
conjunction
with
use
of
15
ppm
sulfur
diesel
fuel).
These
PM
control
technologies,
increased
fuel
injection
pressure,
improved
electronic
controls
and
enhanced
combustion
system
designs
will
concurrently
lower
NMHC
emissions
to
the
NMHC
standard
of
0.30
g/
bhp­
hr.

The
second
step
in
our
NMHC
standards
is
to
a
level
of
0.14
g/
bhp­
hr,
consistent
with
the
standard
for
on­
highway
diesels
beginning
in
2007
and
for
other
nonroad
diesel
engines
from
75
to
750
hp
beginning
in
2011.
This
change
in
NMHC
standards
is
timed
to
coincide
with
the
requirement
that
engines
over
750
hp
meet
stringent
PM
emission
standards
that
we
believe
will
require
the
use
of
catalyst­
based
diesel
particulate
filter
systems.
These
systems
are
expected
to
incorporate
oxidation
catalyst
functions
to
control
the
SOF
portion
of
diesel
PM
and
to
promote
robust
soot
regeneration
within
the
filter.
This
same
oxidation
function
is
highly
effective
at
53
The
2013
NOX+
NMHC
standard
is
a
new
standard
only
for
engines
in
the
25­
50
hp
category.

For
engines
in
the
50­
75
hp
category,
3.5
g/
bhp­
hr
NOX+
NMHC
is
the
existing
Tier
3
emission
standard
which
will
now
also
apply
across
the
new
regulated
test
cycles
(
e.
g.,
NRTC).

74
controlling
NMHC
emissions
(
the
RIA
documents
reductions
of
more
than
80
percent)
and
will
result
in
a
reduction
in
NMHC
emissions
below
the
0.14
g/
bhp­
hr
standard
for
these
engines.
As
the
high
level
of
NMHC
control
afforded
by
the
application
of
this
technology
is
broadly
realized
across
the
wide
range
of
diesel
engine
operation,
it
will
allow
for
compliance
with
the
NTE
provisions
as
well.
Although
in
practice
we
expect
that
NMHC
emissions
may
be
lower
than
the
0.14
g/
bhp­
hr
standard,
we
have
not
finalized
a
more
stringent
standard
for
NMHC
in
order
to
maintain
consistency
with
the
NMHC
standard
we
are
finalizing
for
engines
from
75
hp
to
750
hp,
for
which
the
NMHC
standard
is
in
part
based
on
feasibility
considerations
for
NO
X
adsorber
catalyst
systems
that
use
diesel
fuel
to
regenerate
themselves
(
with
consequent
increased
NMHC
emissions
during
regeneration
events).
We
believe
this
is
appropriate
considering
our
expectation
that
NO
X
adsorber
technology
will
be
found
feasible
for
all
nonroad
engines
over
750
hp.

4.
Are
the
New
Tier
4
Standards
for
Engines
25
 
75
hp
Feasible?

As
discussed
in
section
II.
B,
our
standards
for
25
 
75
hp
engines
consist
of
a
2008
transitional
standard
and
long­
term
2013
standards.
The
transitional
standard
is
a
0.22
g/
bhp­
hr
PM
standard.
The
2013
standards
consist
of
a
0.02
g/
bhp­
hr
PM
standard
and
a
3.5
g/
bhp­
hr
NMHC+
NO
X
standard.
53
As
discussed
in
section
II.
A,
the
transitional
standard
is
optional
for
50­
75
hp
engines,
as
the
2008
implementation
date
is
the
same
as
the
effective
date
of
the
Tier
3
standards.
Manufacturers
may
decide,
at
their
option,
not
to
undertake
the
2008
transitional
PM
standard,
in
which
case
their
implementation
date
for
the
0.02
g/
bhp­
hr
PM
standard
begins
in
2012.
The
remainder
of
this
section
discusses
what
makes
the
25­
75
hp
category
unique
and
why
the
standards
are
technologically
feasible.

a.
What
makes
the
25
 
75
hp
category
unique?

As
EPA
explained
in
the
proposal,
and
as
discussed
in
section
II.
A,
one
cannot
assume
that
highway
technologies
are
automatically
transferable
to
25
 
75
hp
nonroad
engines.
In
contrast
with
75
 
750
hp
engines,
which
share
similarities
in
displacement,
aspiration,
fuel
systems,
and
electronic
controls
with
highway
diesel
engines,
engines
in
the
25
 
75
hp
category
have
a
number
of
technology
differences
from
the
larger
engines.
These
include
a
higher
percentage
of
indirect­
injection
fuel
systems,
and
a
low
fraction
of
turbocharged
engines
(
see
generally
RIA
chapter
4.1).
The
distinction
in
the
under
25
hp
category
is
even
more
pronounced,
with
no
turbocharged
engines,
nearly
one­
fifth
of
the
engines
have
two
cylinders
or
less,
and
a
significant
majority
of
the
engines
have
indirect­
injection
fuel
systems.

The
distinction
is
particularly
marked
with
respect
to
electronically
controlled
fuel
systems.
These
are
commonly
available
in
the
power
categories
greater
than
or
equal
to
75
hp,
54
As
discussed
in
section
II.
B.,
manufacturers
can
choose,
at
their
option,
to
pull­
ahead
the
2013
PM
standard
for
the
50­
75
hp
engines
to
2012,
in
which
case
they
do
not
need
to
comply
with
the
transitional
2008
PM
standard.

55
However,
a
manufacturer
can
choose
to
comply
over
the
TRU
cycle
including
the
associated
NTE
provisions.
Compliance
with
the
NTE
for
engines
selecting
to
certify
on
the
TRU
cycle
is
straightforward
because
by
the
very
nature
of
the
products,
their
operation
is
directly
limited
to
a
small
range
of
operating
modes
over
which
compliance
with
the
emission
standard
has
already
been
shown.

75
but,
based
on
the
available
certification
data
as
well
as
our
discussions
with
engine
manufacturers,
we
believe
there
are
very
limited
numbers,
if
any,
in
the
25
 
75
hp
category
(
and
no
electronic
fuel
systems
in
the
less
than
25
hp
category).
The
research
and
development
work
being
performed
today
for
the
heavy­
duty
highway
market
is
targeted
at
engines
which
are
4­
cylinders
or
more,
direct­
injection,
electronically
controlled,
turbocharged,
and
with
per­
cylinder
displacements
greater
than
0.5
liters.
As
discussed
in
more
detail
below,
as
well
as
in
section
II.
B.
5
(
regarding
the
under
25
hp
category),
these
engine
distinctions
are
important
from
a
technology
perspective
and
warrant
a
different
set
of
standards
for
the
25
 
75
hp
category
(
as
well
as
for
the
under
25
hp
category).

b.
Are
the
new
Tier
4
standards
for
25
 
75
hp
engines
technologically
feasible?

This
section
will
discuss
the
technical
feasibility
of
both
the
interim
2008
PM
standard
and
the
2013
standards.
For
an
explanation
and
discussion
of
the
implementation
dates,
please
refer
to
section
II.
A.

i.
2008
PM
Standards54
We
are
today
finalizing
the
interim
PM
control
program
as
proposed
for
engines
in
the
power
category
from
25
 
75
hp.
The
new
PM
standard
for
2008
is
0.22
g/
bhp­
hr
over
the
appropriate
steady­
state
test
cycle
(
the
NRTC
and
NTE
do
not
apply,
for
the
reasons
explained
below).
55
The
standard
is
premised
on
the
use
of
500
ppm
sulfur
diesel
fuel
and
the
potential
for
improvements
in
engine­
out
emission
control
where
possible
or
the
application
of
a
diesel
oxidation
catalyst
(
DOC).
Some
commenters
raised
concerns
that
this
level
of
emission
control
from
diesel
engines
may
not
be
possible
in
2008
without
fuel
cleaner
than
500
ppm
or
without
changes
in
the
Tier
3
NMHC+
NO
X
emission
standards.
Other
commenters,
including
some
engine
manufacturers,
supported
this
interim
program.
As
explained
in
the
following
sections,
we
continue
to
believe
that
these
standards
are
appropriate
and
feasible
in
the
leadtime
provided.

Engines
in
the
25
 
50
hp
category
must
meet
Tier
2
NMHC+
NO
X
and
PM
standards
today.
We
have
examined
the
model
year
2004
engine
certification
data
for
engines
in
the
25
 
50
hp
category.
These
data
indicate
that
over
35
percent
of
the
engine
families
meet
the
2008
0.22
g/
bhp­
hr
PM
standard
and
5.6
g/
bhp­
hr
NMHC+
NO
X
standard
(
unchanged
from
Tier
2
in
2008)
56
The
Tier
1
and
Tier
2
standards
for
this
power
category
must
be
demonstrated
on
one
of
a
variety
of
different
engine
test
cycles.
The
appropriate
test
cycle
is
selected
by
the
engine
manufacturer
based
on
the
intended
in­
use
application
of
the
engine.

57
EPA
Memorandum
"
Documentation
of
the
Availability
of
Diesel
Oxidation
Catalysts
on
Current
Production
Nonroad
Diesel
Equipment,"
William
Charmley.
Copy
available
in
EPA
Air
Docket
A­
2001­
28
Item
II­
B­
15.

76
today
(
even
without
500
ppm
sulfur
diesel
fuel).
At
the
time
of
the
proposal,
we
had
analyzed
model
year
2002
data
for
this
power
range,
which
at
that
time
indicated
approximately
10
percent
of
the
engine
families
complied
with
the
2008
requirements.
The
most
recent
data
for
model
year
2004
indicates
substantial
progress
has
already
been
made
in
just
the
past
few
year
in
lowering
emissions
from
these
engines.
This
is
primarily
due
to
the
implementation
of
the
Tier
2
standards
in
model
year
2004.
The
model
year
2001
certification
data
also
showed
the
2008
standard
were
achievable
using
a
mix
of
engine
technologies
(
IDI
and
DI,
turbocharged
and
naturally
aspirated)
tested
on
a
variety
of
certification
test
cycles.
56
A
detailed
discussion
of
these
data
is
contained
in
the
RIA.

At
the
time
of
the
proposal,
no
certification
data
was
available
for
engines
in
the
50­
75
hp
range,
because
those
engines
were
not
subject
to
a
Tier
1
standard
and
were
not
subject
to
Tier
2
standards
until
model
year
2004.
We
have
now
had
an
opportunity
to
analyze
the
model
year
2004
certification
data
for
engines
in
the
50­
75
hp
range.
These
data
shows
that
more
than
70
percent
of
the
engine
families
in
this
power
range
are
capable
of
meeting
the
2008
PM
standards
today.
However,
most
of
these
engines
do
not
yet
meet
the
3.5
g/
bhp­
hr
Tier
3
NMHC+
NO
X
standard,
which
is
required
in
2008.
We
expect
that
to
comply
with
the
Tier
3
standards,
these
engines
will
use
technologies
such
as
EGR
and
electronically
controlled
fuel
injection
systems
(
and
we
included
the
costs
of
these
technologies
in
assessing
the
costs
of
the
Tier
3
standards).
These
technologies
have
been
shown
to
reduce
NO
X
emissions
by
50
percent
without
increasing
PM
emissions.
The
certification
data
show
that
for
the
70
percent
of
the
engine
families
which
meet
the
2008
Tier
4
PM
standard
(
0.22
g/
bhp­
hr),
a
NO
X
reduction
of
less
than
50
percent
is
needed
for
most
of
these
engines
to
meet
the
2008
Tier
4
NMHC+
NO
X
standard.
A
detailed
discussion
of
these
data
is
contained
in
the
RIA.

In
addition
to
using
known
engine­
out
techniques,
we
also
project
that
the
2008
standards
can
be
achieved
with
the
use
of
DOCs.
DOCs
are
passive
flow­
through
emission
control
devices
which
are
typically
coated
with
a
precious
metal
or
a
base­
metal
washcoat.
DOCs
have
been
proven
to
be
durable
in
use
on
both
light­
duty
and
heavy­
duty
diesel
applications.
In
addition,
DOCs
have
already
been
used
to
control
carbon
monoxide
on
some
nonroad
applications.
57
Some
commenters
raised
concerns
that
DOCs
could
actual
increase
PM
emissions
when
used
on
500
ppm
sulfur
diesel
fuel
due
to
the
potential
for
oxidation
of
the
sulfur
in
the
fuel
to
sulfate
PM.
While
we
agree
with
the
commenters
that
sulfur
reductions
are
important
to
control
PM
and
in
the
long
term
that
a
15
ppm
fuel
sulfur
level
will
be
the
best
solution,
we
disagree
with
the
77
assertion
that
the
amount
of
sulfate
PM
formed
from
a
DOC
will
be
such
that
compliance
with
the
0.22
g/
bhp­
hr
standard
will
be
infeasible.
While
commenters
shared
data
showing
increased
PM
emissions
when
DOCs
are
used,
we
have
similarly
found
data
(
included
in
the
RIA)
that
shows
an
overall
reduction
in
emissions.
To
understand
this
discrepancy,
it
is
important
to
realize
that
DOCs
can
be
designed
for
operation
on
a
range
of
fuel
sulfur
levels.
The
lower
the
fuel
sulfur
level,
the
more
effective
the
PM
oxidation
function,
but
even
at
500
ppm
sulfur
a
properly
designed
DOC
will
realize
a
net
reduction
in
PM
emissions.
DOCs
have
been
successfully
applied
to
diesel
engines
for
on­
highway
applications
for
PM
control
on
500
ppm
fuel
since
1994
through
careful
design
of
the
DOC
trading­
off
PM
reduction
potential
and
sulfur
oxidation
potential.
The
RIA
contains
additional
analysis
describing
DOC
function,
and
its
expected
effectiveness
when
applied
to
nonroad
diesel
engines.

Other
commenters
argued
that
the
application
of
DOC
to
diesel
engines
in
this
category
would
lead
to
an
even
greater
emission
reduction
than
estimated
in
our
proposal,
thus
allowing
the
Agency
to
finalize
a
lower
PM
standard.
While
we
agree
that
some
engines
will
have
lower
emissions
than
required
to
meet
the
standard
and
that
in
the
long
term
(
once
15
ppm
fuel
is
widely
available)
the
PM
emissions
will
be
further
reduced,
we
do
not
believe
that
an
emission
level
lower
than
0.22
g/
bhp­
hr
will
be
generally
feasible
in
2008
due
to
the
sulfur
level
of
diesel
fuel
of
500
ppm
sulfur
and
the
potential
for
sulfate
PM
formation.

In
summary
then,
there
are
two
likely
means
by
which
companies
can
comply
with
the
interim
2008
PM
standard.
First,
engine
manufacturers
can
comply
with
this
standard
using
known
engine­
out
techniques
(
e.
g.,
optimizing
combustion
chamber
designs,
fuel­
injection
strategies).
In
fact,
some
fraction
of
engines
already
would
comply
with
the
emission
standard.
In
addition,
some
engine
manufacturers
may
choose
to
use
diesel
oxidation
catalysts
to
meet
this
standard.
Our
cost
analysis
makes
the
conservative
assumption
(
i.
e.,
the
higher
cost
assumption)
that
all
manufacturers
will
use
DOC
catalysts
to
comply
with
these
emission
standards.

Based
on
the
existence
of
a
number
of
engine
families
which
already
comply
with
the
0.22
g/
bhp­
hr
PM
standard
(
and
the
2008
NMHC+
NO
X
standard),
and
the
availability
of
well
known
PM
reduction
technologies
such
as
engine­
out
improvements
and
diesel
oxidation
catalysts,
we
project
that
the
0.22
g/
bhp­
hr
PM
standards
is
technologically
feasible
by
model
year
2008.

ii.
2013
Standards
For
engines
in
the
25­
50
range,
we
are
finalizing
standards
commencing
in
2013
of
3.5
g/
bhp­
hr
for
NMHC+
NO
X
and
0.02
g/
bhp­
hr
for
PM.
For
the
50
 
75
hp
engines,
we
are
finalizing
a
0.02
g/
bhp­
hr
PM
standard
which
will
be
implemented
in
2013,
and
for
those
manufacturers
who
choose
to
pull­
ahead
the
standard
one­
year,
2012
(
manufacturers
who
choose
to
pull­
ahead
the
2013
standard
for
engines
in
the
50
 
75
range
do
not
need
to
comply
with
the
transitional
2008
PM
standard).
A
more
complete
discussion
of
the
options
available
to
manufacturers
and
the
nature
of
the
transitional
program
can
be
found
in
section
II.
A.
These
58
"
The
Optimized
Deutz
Service
Diesel
Particulate
Filter
System
II,"
H.
Houben
et.
al.,
SAE
Technical
Paper
942264,
1994
and
"
Development
of
a
Full­
Flow
Burner
DPF
System
for
Heavy
Duty
Diesel
Engines,"
P.
Zelenka
et.
al.,
SAE
Technical
Paper
2002­
01­
2787,
2002.

78
standards
are
measured
using
the
NRTC
and
steady­
state
tests.
These
engines
also
will
be
subject
to
the
NTE
starting
with
the
2013
model
year.

PM
Standard
For
engines
in
the
horsepower
category
from
25
 
75
hp,
we
are
finalizing
a
PM
standard
of
0.02
g/
bhp­
hr
based
on
the
application
of
catalyzed
diesel
particulate
filters
to
engines
in
this
category.
We
received
a
wide
range
of
comments
on
our
proposal
with
some
arguing
that
the
emission
standard
could
be
met
earlier
than
2013
and
others
arguing
that
while
technically
possible
to
apply
PM
filters
to
engines
in
this
category,
that
it
was
not
economically
or
otherwise
practical
to
do
so.

The
RIA
discusses
in
detail
catalyzed
diesel
particulate
filters,
including
explanations
of
how
CDPFs
reduce
PM
emissions,
and
how
to
apply
CDPFs
to
nonroad
engines.
We
have
concluded,
as
explained
above,
that
CDPFs
can
be
used
to
achieve
the
0.01
g/
bhp­
hr
PM
standard
for
75
 
750
hp
engines.
As
also
discussed
in
section
II.
B.
2.
a
above,
PM
filters
will
require
active
back­
up
regeneration
systems
for
many
nonroad
applications
above
and
below
75
hp
because
low
temperature
operation
is
an
issue
across
all
power
categories.
One
commenter
raised
concerns
regarding
the
low
exhaust
temperatures
possibly
experienced
by
small
nonroad
engines
and
argued
that
such
low
temperatures
make
PM
filter
regeneration
impossible
absent
the
use
of
active
regeneration
technologies.
We
agree
with
the
commenter
that
active
regeneration,
as
described
previously,
may
be
necessary
and
have
included
the
cost
for
such
systems
in
our
cost
estimates.
See
section
II.
B.
1.
a.
A
number
of
secondary
technologies
are
likely
required
to
enable
proper
regeneration,
including
possibly
electronic
fuel
systems
such
as
common
rail
systems
which
are
capable
of
multiple
post­
injections
which
can
be
used
to
raise
exhaust
gas
temperatures
to
aid
in
filter
regeneration.

Particulate
filter
technology,
with
the
requisite
trap
regeneration
technology,
can
also
be
applied
to
engines
in
the
25
to
75
hp
range.
As
explained
earlier,
the
fundamentals
of
how
a
filter
is
able
to
reduce
PM
emissions
are
not
a
function
of
engine
power,
so
that
CDPF's
are
just
as
effective
at
capturing
soot
emissions
and
oxidizing
SOF
on
smaller
engines
as
on
larger
engines.
The
PM
filter
regeneration
systems
described
in
section
II.
B.
2
are
also
applicable
to
engines
in
this
size
range
and
are
likewise
feasible.
There
are
specific
trap
regeneration
technologies
which
we
believe
engine
manufacturers
in
the
25
 
75
hp
category
may
prefer
over
others.
For
example,
some
manufacturers
may
choose
to
apply
an
electronically­
controlled
secondary
fuel
injection
system
(
i.
e.,
a
system
which
injects
fuel
into
the
exhaust
upstream
of
a
PM
filter).
Such
a
system
has
been
commercially
used
successfully
by
at
least
one
nonroad
engine
manufacturer,
and
other
systems
have
been
tested
by
technology
companies.
58
However,
we
recognize
that
the
application
79
of
these
technologies
will
be
challenging
and
will
require
additional
time
to
develop.
We
therefore
disagree
with
commenters
who
say
that
the
standard
could
be
met
sooner
and
have
decided
to
finalize
the
implementation
schedule
as
proposed.

As
we
proposed,
we
are
finalizing
a
slightly
higher
PM
standard
(
0.02
g/
bhp­
hr
rather
than
0.01)
for
engines
in
this
power
category.
As
discussed
in
the
preamble
to
the
proposed
rule
and
in
some
detail
in
the
RIA,
with
the
use
of
a
CDPF,
the
PM
emissions
emitted
by
the
filter
are
primarily
derived
from
the
fuel
sulfur
(
68
FR
28389­
28390,
May
23,
2003).
The
smaller
power
category
engines
tend
to
have
higher
fuel
consumption
per
unit
of
work
than
larger
engines.
This
occurs
for
a
number
of
reasons.
First,
the
lower
power
categories
include
a
high
fraction
of
IDI
engines
which
by
their
nature
consume
approximately
15
percent
more
fuel
than
a
DI
engine.
Second,
as
engine
displacements
get
smaller,
the
engine's
combustion
chamber
surface­
to­
volume
ratio
increases.
This
leads
to
higher
heat­
transfer
losses
and
therefore
lower
efficiency
and
higher
fuel
consumption.
In
addition,
frictional
losses
are
a
higher
percentage
of
total
power
for
the
smaller
displacement
engines
which
also
results
in
higher
fuel
consumption.
Because
of
the
higher
fuel
consumption
rate,
we
expect
a
higher
particulate
sulfate
level,
and
therefore
we
have
set
a
0.02
g/
bhp­
hr
standard
for
engines
in
this
power
category.
We
did
not
receive
any
comments
on
our
proposal
arguing
that
the
technical
basis
for
this
higher
PM
level
was
inappropriate.

The
0.02
g/
bhp­
hr
standard
applies
to
all
of
the
test
cycles
applicable
to
engines
in
this
power
category
(
i.
e.,
the
NRTC
including
cold­
start,
the
ISO
C1,
D2
and
G2
cycles
and
the
alternative
TRU
and
RMC
cycles,
as
appropriate).
Our
feasibility
analysis
summarized
here
and
detailed
in
the
RIA
takes
into
consideration
these
different
test
cycles.
The
control
technologies
work
in
a
similar
manner
and
provide
the
same
high
level
of
emission
control
across
these
different
operating
regimes
including
the
NTE.
The
most
significant
effect
on
emission
performance
is
related
to
sulfate
PM
formation
at
high
load,
high
temperature
operating
conditions.
As
the
RIA
details,
this
level
of
high
sulfate
formation
rate
is
not
high
enough
to
preclude
compliance
with
the
PM
emission
standard
with
15
ppm
fuel
sulfur
on
the
regulated
test
cycles
nor
is
it
high
enough
to
preclude
compliance
with
the
NTE
provisions.
At
higher
fuel
sulfur
levels
however,
compliance
with
the
PM
emission
standard
would
not
be
feasible.

The
majority
of
negative
comments
on
our
proposal
to
set
a
PM
standard
based
on
the
control
possible
from
PM
filter
technologies
focused
on
the
economic
and
technical
challenges
to
apply
these
technologies
and
the
major
engine
technology
enabler,
electronic
fuel
systems,
to
smaller
diesel
engines.
Some
commenters
acknowledged
that
the
technologies
were
"
technically
feasible"
but
not
economically
feasible
or
practical
for
engines
in
this
power
category.
While
we
acknowledge
that
the
application
of
these
technologies
to
diesel
engines
in
this
horsepower
category
will
be
challenging
and
have
given
consideration
to
this
in
setting
the
timing
for
the
new
standard,
we
believe
that
the
technical
path
for
compliance
is
clear
and
that
the
cost
estimates
we
have
made
for
these
engines
accurately
represent
this
technical
path.
As
discussed
in
the
RIA,
at
the
time
of
the
proposal
we
projected
no
significant
penetration
of
electronic
fuel
systems
for
engines
in
the
50
 
100
hp
range
prior
to
the
Tier
3
standards
(
2008).
Since
the
proposal,
new
information
regarding
model
year
2004
engine
certifications
has
become
available.
That
data
59
See
section
2.2
through
2.3
in
"
Nonroad
Diesel
Emission
Standards
­
Staff
Technical
Paper,"

EPA
Publication
EPA420­
R­
01­
052,
October
2001.
Copy
available
in
EPA
Air
Docket
A­
2001­
28.

80
show
18
percent
of
the
engines
in
the
75
 
100
hp
category
already
use
electronically
controlled
fuel
systems.
In
model
year
2001,
no
engines
in
this
category
used
electronic
fuel
systems.
We
believe
this
strong
trend
toward
the
introduction
of
more
advanced
electronic
fuel
system
technology
will
continue
in
the
future
and,
importantly
for
engines
in
the
25
 
75
hp
category,
will
extend
to
ever
smaller
engine
categories
due
to
the
user
benefits
provided
by
the
technology
and
the
falling
cost
for
such
systems.
However,
acknowledging
the
substantial
time
between
now
and
2012,
and
the
potential
for
technologies
to
mature
faster
or
slower
than
we
are
estimating
here,
we
have
decided
to
conduct
a
technology
review
of
these
standards
as
described
in
section
II.
A
above.
This
review
will
provide
EPA
with
another
opportunity
to
confirm
that
the
technical
path
laid
out
here
is
indeed
progressing
in
a
manner
consistent
with
our
expectations.

NMHC+
NO
X
Standard
As
we
proposed,
we
are
finalizing
a
3.5
g/
bhp­
hr
NMHC+
NO
X
standard
for
engines
in
the
25
 
50
hp
range
for
2013.
We
received
limited
comments
arguing
that
the
NMHC+
NO
X
standard
should
be
less
stringent.
Like
the
PM
standard,
some
commenters
argued
that
the
NO
X
standard
would
be
costly
and
complicated,
although
not
necessarily
infeasible
to
apply.
Other
commenters
argued
that
the
NO
X
standard
for
engines
in
this
category
like
the
new
standard
for
larger
engines,
should
be
based
upon
the
application
of
advanced
NO
X
catalyst­
based
technologies.
As
described
previously
in
section
II.
A,
we
do
not
believe
that
the
catalyst­
based
NO
X
technologies
have
matured
to
a
state
were
we
can
accurately
define
a
feasible
technical
path
for
compliance
for
engines
in
this
power
category.
We
intend
to
revisit
this
question
in
our
technology
review
and
if
we
find
that
a
viable
technical
path
can
be
described
we
will
consider
the
appropriateness
of
a
more
stringent
catalyst­
based
standard.

The
new
standard
aligns
the
NMHC+
NO
X
standard
for
engines
in
this
power
range
with
the
Tier
3
standard
for
engines
in
the
50
 
75
hp
range
which
are
implemented
in
2008.
EPA's
recent
Staff
Technical
paper
which
reviewed
the
technological
feasibility
of
the
Tier
3
standards
contains
a
detailed
discussion
of
a
number
of
technologies
which
are
capable
of
achieving
a
3.5
g/
bhp­
hr
standard.
These
include
cooled
EGR,
uncooled
EGR,
as
well
as
advanced
in­
cylinder
technologies
relying
on
electronic
fuel
systems
and
turbocharging.
59
These
technologies
are
capable
of
reducing
NO
X
emissions
by
as
much
as
50
percent.
Given
the
Tier
2
NMHC+
NO
X
standard
of
5.6
g/
bhp­
hr,
a
50
percent
reduction
would
allow
a
Tier
2
engine
to
comply
with
the
3.5
g/
bhp­
hr
NMHC+
NO
X
standard
set
in
this
action.
Therefore,
we
are
projecting
that
3.5
g/
bhp­
hr
NO
X+
NMHC
standard
is
feasible
with
the
addition
of
cooled
EGR
(
the
basis
for
our
cost
analysis)
or
other
equally
effective
in­
cylinder
NO
X
control
technology
as
described
in
the
RIA
and
our
recent
Staff
Technical
Paper.
In
addition,
because
this
NMHC+
NO
X
standard
is
concurrent
with
the
0.02
g/
bhp­
hr
PM
standards
which
we
project
will
be
achievable
with
the
use
of
particulate
filters,
engine
designers
will
have
significant
additional
flexibility
in
reducing
NO
X
60
See
section
8
of
"
Control
of
Emissions
of
Air
Pollution
from
2004
and
Later
Model
Year
Heavy­
Duty
Highway
Engines
and
Vehicles:
Response
to
Comments,"
EPA
document
EPA420­
R­
00­
011,

July
2000,
and
chapter
3
of
"
Regulatory
Impact
Analysis:
Control
of
Emissions
of
Air
Pollution
from
Highway
Heavy­
duty
Engines,"
EPA
document
EPA420­
R­
00­
010,
July
2000.
Copies
of
both
documents
available
in
EPA
docket
A­
2001­
28.

81
because
the
PM
filter
will
lessen
the
traditional
concerns
with
the
engine­
out
NO
X
vs.
PM
tradeoff

Our
recent
highway
2004
standard
review
rulemaking
(
see
65
FR
59896,
October
2000)
demonstrated
that
a
diesel
engine
with
advanced
electronic
fuel
injection
technology
as
well
as
NO
X
control
technology
such
as
cooled
EGR
is
capable
of
complying
with
an
NTE
standard
set
at
1.25
times
the
laboratory­
based
FTP
standard.
We
project
that
the
same
technology
(
electronic
fuel
systems
and
cooled
EGR)
are
also
capable
for
engine
in
the
25­
75
hp
range
of
complying
with
the
NTE
standard
of
4.4
g/
bhp­
hr
NMHC+
NO
X
(
1.25
x
3.5)
in
2013.
This
is
based
on
the
broad
NO
X
reduction
capability
of
cooled
EGR
technology,
which
is
capable
of
reducing
NO
X
emissions
across
the
engine
operating
map
(
including
the
NTE
region)
by
at
least
30
percent
even
under
high
load
conditions.
60
Based
on
the
information
available
to
EPA
and
presented
here,
and
giving
appropriate
consideration
to
the
lead
time
necessary
to
apply
the
technology
as
well,
we
have
concluded
the
0.02
g/
bhp­
hr
PM
standard
for
engines
in
the
25
 
75
hp
category
and
the
3.5
g/
bhp­
hr
NMHC+
NO
X
standards
for
the
25
 
50
hp
engines
are
achievable.

5.
Are
the
Standards
for
Engines
under
25
hp
Feasible?

As
we
explained
at
proposal
and
as
discussed
in
section
II.
A,
the
new
PM
standard
for
engines
less
than
25
hp
is
0.30
g/
bhp­
hr
beginning
in
2008.
The
certification
test
cycle
for
this
standard
is
the
ISO
C1
cycle
(
or
other
appropriate
steady­
state
test
as
defined
by
the
engine's
intended
use)
from
2008
through
2012.
Beginning
in
2013,
the
NRTC
(
with
cold­
start)
and
the
NTE
will
also
apply
to
engines
in
this
category.
As
discussed
below,
we
are
not
setting
a
new
standard
more
stringent
than
the
existing
Tier
2
NMHC+
NO
X
standard
for
this
power
category
at
this
time.
This
section
describes
what
makes
the
less
than
25
hp
category
different
and
why
the
standards
are
technologically
feasible.

a.
What
makes
the
under
25
hp
category
unique?

As
we
explained
at
proposal
and
in
the
RIA,
nonroad
engines
less
than
25
hp
are
the
least
sophisticated
nonroad
diesel
engines
from
a
technological
perspective.
All
of
the
engines
currently
sold
in
this
power
category
lack
electronic
fuel
systems
and
turbochargers.
Nearly
20
percent
of
the
products
have
two­
cylinders
or
less,
and
14
percent
of
the
engines
sold
in
this
category
are
single­
cylinder
products,
a
number
of
these
have
no
batteries
and
are
crank­
start
61
The
Tier
1
and
Tier
2
standards
for
this
power
category
must
be
demonstrated
on
one
of
a
variety
of
different
engine
test
cycles.
The
appropriate
test
cycle
is
selected
by
the
engine
manufacturer
based
on
the
intended
in­
use
applications(
s)
of
the
engine.

82
machines,
much
like
today's
simple
walk
behind
lawnmower
engines.
In
addition,
given
what
we
know
today
and
taking
into
account
the
Tier
2
standards
which
have
not
yet
been
implemented,
we
are
not
projecting
any
significant
penetration
of
advanced
engine
technology,
such
as
electronically
controlled
fuel
systems,
into
this
category
in
the
next
5
to
10
years.

b.
What
data
indicate
that
the
standards
are
feasible?

We
project
the
Tier
4
PM
standard
can
be
met
by
2008
based
on:
the
existence
of
a
large
number
of
engine
families
which
meet
the
new
standards
today;
the
use
of
engine­
out
reduction
techniques;
and
the
use
of
diesel
oxidation
catalysts.

Engines
in
the
less
than
25
hp
category
must
meet
Tier
1
NMHC+
NO
X
and
PM
standards
today.
We
have
examined
the
2004
model
year
engine
certification
data
for
nonroad
diesel
engines
less
than
25
hp.
These
data
indicate
that
a
number
of
engine
families
meet
the
new
Tier
4
PM
standard
(
and
the
2008
NMHC+
NO
X
standard,
unchanged
from
Tier
2)
today.
The
data
show
that
31
percent
of
the
engine
families
are
at
or
below
the
PM
standard
today,
while
meeting
the
2008
NMHC+
NO
X
standard.
At
the
time
of
the
proposal,
we
examined
the
model
year
2002
certification,
which
indicated
approximately
30
percent
of
the
engine
families
were
at
or
below
the
2008
emission
standards.
This
certification
data
includes
both
IDI
and
DI
engines,
as
well
as
a
range
of
certification
test
cycles.
61
Many
of
the
engine
families
are
certified
well
below
the
Tier
4
standard
while
meeting
the
2008
NMHC+
NO
X
level.
Specifically,
for
the
model
year
2002
data,
15
percent
of
the
engine
families
are
cleaner
than
the
new
Tier
4
PM
standard
by
more
than
20
percent.
The
public
certification
data
indicate
that
these
engines
do
not
use
turbocharging,
electronic
fuel
systems,
exhaust
gas
recirculation,
or
aftertreatment
technologies.
We
saw
little
change
between
the
model
year
2002
and
2004
data
for
this
power
category
primarily
because
both
model
years
are
subject
to
the
Tier
1
standards,
and
many
engine
families
are
simply
carried
over
from
the
previous
model
year.
Tier
2
standards
for
these
engines
will
not
be
implemented
until
model
year
2005.
A
detailed
discussion
of
these
data
is
contained
in
the
RIA.

In
summary
then,
there
are
two
likely
means
by
which
companies
can
comply
with
the
2008
PM
standard
for
engines
under
25
hp.
First,
engine
manufacturers
can
comply
with
this
standard
using
known
engine­
out
techniques
(
e.
g.,
optimizing
combustion
chamber
designs,
fuelinjection
strategies).
In
fact,
some
fraction
of
engines
already
would
comply
with
the
emission
standard.
In
addition,
some
engine
manufacturers
may
choose
to
use
diesel
oxidation
catalysts
to
meet
this
standard.
Our
cost
analysis
makes
the
conservative
assumption
(
i.
e.,
the
higher
cost
assumption)
that
all
manufacturers
will
use
DOCs
to
comply
with
these
emission
standards.
83
As
discussed
in
section
II.
A,
we
are
finalizing
supplemental
test
procedures
and
standards
(
nonroad
transient
test
cycle
and
not­
to­
exceed
requirements)
for
engines
in
the
under
25
hp
category
beginning
in
2013.
The
supplemental
test
procedures
and
standards
will
apply
not
only
to
PM,
but
also
to
NMHC+
NO
X.
The
engine
technologies
necessary
to
comply
with
the
supplemental
test
procedures
and
standards
are
the
same
as
the
technology
necessary
to
comply
with
the
2008
standard,
and
we
have
given
consideration
to
these
test
conditions
in
setting
this
standard.
The
range
of
operating
conditions
covered
by
the
various
test
cycles
and
the
mechanism
for
emission
control
over
those
ranges
of
operation
are
substantially
similar
allowing
us
to
conclude
that
emission
control
will
be
substantially
uniform
across
these
test
procedures.
However,
we
are
delaying
the
implementation
of
the
supplemental
test
procedures
and
standards
until
2013,
as
proposed,
in
order
to
implement
these
supplemental
requirements
on
the
larger
powered
nonroad
engines
before
the
smallest
power
category.
(
There
were
no
adverse
comments
on
this
aspect
of
the
proposed
rule.)
This
will
also
provide
engine
manufacturers
with
additional
time
to
install
any
emission
testing
equipment
upgrades
they
may
need
in
order
to
implement
the
new
nonroad
transient
test
cycle.

Based
on
the
existence
of
a
number
of
engine
families
which
already
comply
with
the
new
Tier
4
PM
standard
(
and
the
2008
NMHC+
NO
X
standard),
and
the
availability
of
PM
reduction
technologies
such
as
improved
mechanical
fuel
systems,
combustion
chamber
improvements,
and
in
particular
diesel
oxidation
catalysts,
we
project
that
the
0.30
g/
bhp­
hr
PM
standards
is
technologically
feasible
by
model
year
2008.

6.
Meeting
the
Crankcase
Emissions
Requirements
The
most
common
way
to
eliminate
crankcase
emissions
has
been
to
vent
the
blow­
by
gases
into
the
engine
air
intake
system,
so
that
the
gases
can
be
recombusted.
Prior
to
the
HD2007
rulemaking,
we
have
required
that
crankcase
emissions
be
controlled
only
on
naturally
aspirated
diesel
engines.
We
had
made
an
exception
for
turbocharged
diesel
engines
(
both
highway
and
nonroad)
because
of
concerns
in
the
past
about
fouling
that
could
occur
by
routing
the
diesel
particulates
(
including
engine
oil)
into
the
turbocharger
and
aftercooler.
However,
this
is
an
environmentally
significant
exception
since
most
nonroad
equipment
over
75
hp
use
turbocharged
engines,
and
a
single
engine
can
emit
over
100
pounds
of
NO
X,
NMHC,
and
PM
from
the
crankcase
over
its
lifetime.

Given
the
available
means
to
control
crankcase
emissions,
we
eliminated
this
exception
for
highway
engines
in
2007
and
similarly
in
today's
action
are
eliminating
the
exception
for
nonroad
diesel
engines
as
well.
A
number
of
commenters
supported
this
provision
noting
that
the
necessary
technologies
are
already
in
application
in
Europe
and
will
be
required
for
heavy­
duty
diesel
trucks
in
the
United
States
beginning
in
2007.

We
anticipate
that
the
diesel
engine
manufacturers
will
be
able
to
control
crankcase
emissions
through
the
use
of
closed
crankcase
filtration
systems
or
by
routing
unfiltered
blow­
by
gases
directly
into
the
exhaust
system
upstream
of
the
emission
control
equipment.
However,
the
84
provisions
have
been
written
such
that
if
adequate
control
can
be
had
without
"
closing"
the
crankcase
then
the
crankcase
can
remain
"
open."
Compliance
would
be
ensured
by
adding
the
emissions
from
the
crankcase
ventilation
system
to
the
emissions
from
the
engine
control
system
downstream
of
any
emission
control
equipment.
We
have
limited
this
provision
for
controlling
emissions
from
open
crankcases
to
turbocharged
engines,
which
is
the
same
as
for
heavy­
duty
highway
diesel
engines.

Some
commenters
in
essence
argued
that
the
Agency
was
obligated
to
show
that
all
potential
compliance
paths
were
feasible
and
absent
that
showing
that
the
Agency
should
reconsider
this
provision.
Our
feasibility
analysis
is
based
on
the
use
of
closed
crankcase
technologies
designed
to
filter
crankcase
gases
sending
the
clean
gas
to
the
engine
intake
for
combustion
and
returning
the
oil
filtered
from
the
gases
to
the
engine
crankcase.
These
systems
are
proven
in
use
and
the
use
of
this
technology
to
eliminate
crankcase
emissions
is
acceptable
to
demonstrate
compliance.
The
other
options,
the
option
to
vent
crankcase
emissions
into
the
exhaust
or
to
continue
to
vent
crankcase
emissions
to
the
atmosphere
provided
the
total
emissions
including
tailpipe
and
crankcase
emissions
do
not
exceed
the
standards
are
provided
as
alternate
solutions
that
are
clearly
effective
to
control
emissions
(
i.
e.,
if
the
emissions
are
measured
and
are
below
the
standard
they
are
adequately
controlled).
The
commenter
suggests
however,
that
they
may
not
be
able
to
control
the
emissions
to
the
required
level
using
these
alternate
approaches.
In
this
case,
a
manufacturer
would
need
to
use
the
primary
approach
identified
by
EPA,
closing
the
crankcase
and
routing
the
filtered
gases
to
the
engine's
intake
(
this
is
the
approach
we
used
in
the
cost
analysis
summarized
in
section
VI).
We
have
allowed
the
alternative
approaches
at
the
recommendation
of
some
in
industry,
because
if
they
prove
to
be
effective
we
accept
that
resulting
total
emissions
will
be
acceptably
low.

C.
Why
Do
We
Need
15ppm
Sulfur
Diesel
Fuel?

The
new
Tier
4
emission
standards
for
most
categories
of
nonroad
diesel
engines
are
predicated
on
the
application
of
advanced
diesel
emission
control
technologies
that
are
being
developed
for
on­
highway
diesel
engines
to
meet
the
HD2007
emission
standards,
namely
catalyzed
diesel
particulate
filters
and
NO
X
adsorber
catalysts.
Sulfur
in
diesel
fuel
significantly
impacts
the
durability,
efficiency
and
cost
of
applying
these
technologies.
Therefore,
we
required
that
on­
highway
diesel
fuel
produced
for
use
in
2007
or
newer
on­
highway
diesel
engines
have
sulfur
content
no
higher
than
15
ppm.
Based
on
the
same
concerns
outlined
in
the
2007
rulemaking,
discussed
in
the
proposal
at
68
FR
28395­
28400,
set
out
in
the
RIA,
and
briefly
summarized
below,
we
today
are
finalizing
a
requirement
that
diesel
fuel
for
nonroad
engines
be
reduced
to
no
higher
than
15
ppm
beginning
in
2010.
There
was
consensus
among
commenters
that
such
standards
were
necessary
if
the
proposed
standards
based
on
advanced
diesel
emission
control
technologies
were
to
be
achievable.

Sulfur
in
diesel
fuel
acts
to
poison
the
oxidation
function
of
platinum­
based
catalysts
including
DOCs
and
CDPFs
reducing
the
oxidation
efficiency
substantially,
especially
at
lower
temperatures.
This
poisoning
limits
the
effectiveness
of
DOCs
and
CDPFs
to
oxidize
CO
and
HC
85
emissions.
Of
even
greater
concern
is
the
reduction
in
NO
oxidation
efficiency
of
the
CDPF
due
to
sulfur
poisoning.
NO
oxidation
to
NO
2
is
a
fundamental
mechanism
for
PM
filter
regeneration
necessary
to
ensure
robust
operation
of
the
CDPF
(
i.
e.,
to
prevent
filter
plugging).
Sulfur
poisoning
from
sulfur
in
diesel
fuel
at
levels
higher
than
15
ppm
has
been
shown
to
increase
the
likelihood
of
PM
filter
failure
due
to
a
depressed
NO
to
NO
2
oxidation
efficiency
of
the
CDPF.
The
RIA
documents
substantial
field
experience
in
Europe
regarding
this
phenomenon.

Sulfur
in
diesel
fuel
can
itself
be
oxidized
to
form
sulfate
PM
emitted
into
the
environment.
CDPFs
in
particular
are
designed
for
robust
regeneration
and
are
highly
effective
at
oxidizing
sulfur
to
sulfate
PM
(
approaching
100
percent
conversion
under
some
circumstances).
The
sulfate
PM
emissions
from
a
CDPF
when
operated
on
350
ppm
fuel
can
be
so
high
as
to
actually
increase
the
PM
emission
rate
above
the
baseline
level
for
an
engine
without
a
PM
filter.
In
spite
of
more
than
ten
years
of
research,
no
effective
means
has
been
found
to
provide
the
NO
to
NO
2
oxidation
efficiency
needed
to
ensure
robust
filter
regeneration
without
similarly
increasing
efficiency
to
oxidize
sulfur
to
sulfate
PM.
Conversely,
technologies
developed
to
suppress
sulfate
PM
formation
(
e.
g.,
the
addition
of
vanadium
to
DOCs
designed
to
operate
on
500
ppm
sulfur
fuel)
also
suppress
NO
to
NO
2
formation.
Therefore,
it
is
not
possible
to
apply
the
robust
CDPF
technology
to
achieve
the
PM
standards
without
first
having
lower
diesel
fuel
sulfur
levels.
The
RIA
documents
substantial
test
data
showing
the
impact
of
sulfur
in
diesel
fuel
on
total
PM
emissions
due
to
an
increase
in
sulfate
PM
emissions.

Sulfur
from
diesel
fuel
likewise
poisons
the
storage
function
of
the
NO
X
adsorber
catalyst.
Sulfur
in
the
exhaust
in
the
form
of
SO
X
is
stored
on
the
catalyst
in
the
same
way
as
the
NO
X
emissions
are
stored.
Unfortunately,
due
to
the
chemical
properties
of
the
materials,
the
sulfur
is
stored
preferentially
to
the
NO
X
and
will
actually
displace
the
stored
NO
X
emissions.
The
stored
sulfur
is
not
easily
removed
from
the
catalyst.
A
sulfur
removal
step,
called
a
desulfation,
can
be
accomplished
by
raising
exhaust
temperatures
to
a
very
high
level
while
simultaneously
increasing
the
reductant
content
of
the
exhaust
above
the
stoichiometric
level
(
i.
e.,
more
fuel
than
oxygen
in
the
exhaust).
This
process
can
be
effective
to
remove
sulfur
from
the
catalyst
but
at
the
expense
of
damaging
the
catalyst
slightly.
Over
the
lifetime
of
a
diesel
engine
the
cumulative
damage
from
repeated
desulfation
events,
as
would
be
required
if
operation
on
higher
than
15
ppm
sulfur
fuels
were
attempted,
would
lead
to
excessive
damage
and
loss
in
NO
X
control.
The
RIA
contains
an
extensive
description
of
this
phenomena
including
the
tradeoff
between
higher
fuel
sulfur
levels
and
more
frequent
desulfation
events.

The
damage
that
sulfur
inflicts
on
both
the
CDPF
and
NO
X
adsorber
technologies
not
only
reduces
their
effectiveness
but
also
impacts
the
fuel
economy
of
their
application.
Reduced
soot
regeneration
potential
due
to
sulfur
poisoning
would
lead
to
the
need
for
more
frequent
active
CDPF
regeneration.
As
each
active
soot
regeneration
event
consumes
fuel,
more
frequent
regeneration
events
with
higher
fuel
sulfur
levels
leads
to
an
increase
in
fuel
consumption.
Similarly,
higher
fuel
sulfur
levels
would
necessitate
more
frequent
NO
X
adsorber
desulfation
events
and
thus
higher
fuel
consumption.
An
estimate
of
the
impact
of
higher
fuel
sulfur
levels
on
fuel
economy
due
to
more
frequent
desulfation
events
can
be
found
in
the
RIA.
86
For
all
of
the
reasons
documented
in
the
RIA
and
summarized
here,
we
remain
convinced
that
a
cap
of
15
ppm
fuel
sulfur
is
necessary
for
both
on­
highway
and
nonroad
diesel
engines
in
order
to
apply
the
advanced
emission
control
technologies
necessary
to
meet
the
emission
standards
we
are
finalizing
today.
87
III.
Requirements
for
Engine
and
Equipment
Manufacturers
This
section
describes
the
regulatory
changes
being
made
for
the
engine
and
equipment
compliance
program.
A
number
of
specific
items
are
discussed
in
this
section,
including
test
procedures,
certification
fuels,
and
credit
program
provisions.
These
provisions
are
important
in
that
they
help
us
ensure
the
engines
and
equipment
will
meet
the
new
requirements
throughout
their
entire
useful
life,
thus
achieving
the
expected
emission
and
public
health
benefits.

One
of
the
most
obvious
changes
from
the
Tier
2/
Tier
3
program
is
that
the
regulations
for
Tier
4
engines
have
been
written
in
a
plain
language
format.
They
are
structured
to
contain
the
provisions
that
are
specific
to
nonroad
compression
ignition
(
CI)
engines
in
a
new
part
1039,
and
to
apply
the
general
provisions
of
existing
parts
1065
and
1068.
The
plain
language
regulations,
however,
are
not
intended
to
significantly
change
the
compliance
program,
except
as
specifically
noted
in
today's
notice
and
supporting
documents.
These
plain
language
regulations
will
only
apply
for
Tier
4
engines.
The
changes
from
the
existing
nonroad
program
are
described
below
along
with
other
notable
aspects
of
the
compliance
program.

As
described
below,
we
received
comments
from
a
broad
range
of
commenters
for
some
of
these
issues
.
For
other
issues,
we
received
only
manufacturer
comments
or
no
comments
at
all.
See
Chapter
9
of
the
Summary
and
Analysis
of
Comments
for
more
information
about
the
comments
received
and
our
responses
to
them.

A.
Averaging,
Banking,
and
Trading
1.
Why
are
we
adopting
an
ABT
program
for
Tier
4
nonroad
diesel
engines?

EPA
has
included
averaging,
banking,
and
trading
(
ABT)
programs
in
almost
all
of
its
recent
mobile
source
emission
control
programs.
Our
existing
regulations
for
nonroad
diesel
engines
include
an
ABT
program
(
40
CFR
89.201
through
89.212).
With
today's
action
we
are
retaining
the
basic
structure
of
the
existing
nonroad
diesel
ABT
program,
though
we
are
adopting
a
number
of
changes
to
accommodate
implementation
of
the
newly
adopted
Tier
4
emission
standards.
The
ABT
program
is
intended
to
enhance
the
ability
of
engine
manufacturers
to
meet
the
stringent
standards
adopted
today.
The
program
is
also
structured
to
limit
production
of
very
high­
emitting
engines
and
to
avoid
unnecessary
delay
of
the
transition
to
the
new
exhaust
emission
control
technologies.

We
view
the
ABT
program
as
an
important
element
in
setting
emission
standards
that
are
appropriate
under
CAA
section
213(
a)
with
regard
to
technological
feasibility,
lead
time,
and
cost,
given
the
wide
breadth
and
variety
of
engines
covered
by
the
standards.
As
we
noted
at
proposal,
if
there
are
engine
families
that
will
be
particularly
costly
or
have
a
particularly
hard
time
coming
into
compliance
with
the
standard,
this
flexibility
allows
the
manufacturer
to
adjust
the
compliance
schedule
accordingly,
without
special
delays
or
exceptions
having
to
be
written
88
into
the
rule.
Emission­
credit
programs
also
create
an
incentive
for
the
early
introduction
of
new
technology
(
for
example,
to
generate
credits
in
early
years
to
create
compliance
flexibility
for
later
engines),
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.
Early
introduction
of
such
engines
also
secures
earlier
emission
benefits.

In
an
effort
to
make
information
on
the
ABT
program
more
available
to
the
public,
we
intend
to
issue
an
annual
report
summarizing
use
of
the
ABT
program
by
engine
manufacturers.
The
information
contained
in
the
reports
will
be
based
on
the
information
submitted
to
us
by
engine
manufacturers
in
their
annual
reports,
and
summarized
in
a
way
that
protects
the
confidentiality
of
individual
engine
manufacturers.
We
believe
this
information
will
also
be
helpful
to
engine
manufacturers
by
giving
them
a
better
indication
of
the
availability
of
credits.

2.
What
are
the
provisions
of
the
ABT
program?

The
following
section
describes
the
ABT
provisions
being
adopted
with
today's
action.
Areas
in
which
we
have
made
changes
to
the
proposed
ABT
program
are
highlighted.
A
complete
summary
of
comments
received
on
the
proposed
ABT
program
and
our
response
to
those
comments
are
contained
in
the
Summary
and
Analysis
of
Comments
document
for
this
rule.

The
ABT
program
has
three
main
components.
Averaging
means
the
exchange
of
emission
credits
between
engine
families
within
a
given
engine
manufacturer's
product
line.
Engine
manufacturers
divide
their
product
line
into
"
engine
families"
that
are
comprised
of
engines
expected
to
have
similar
emission
characteristics
throughout
their
useful
life.
Averaging
allows
a
manufacturer
to
certify
one
or
more
engine
families
at
levels
above
the
applicable
emission
standard,
but
below
a
set
upper
limit.
However,
the
increased
emissions
must
be
offset
by
one
or
more
engine
families
within
that
manufacturer's
product
line
that
are
certified
below
the
same
emission
standard,
such
that
the
average
emissions
from
all
the
manufacturer's
engine
families,
weighted
by
engine
power,
regulatory
useful
life,
and
production
volume,
are
at
or
below
the
level
of
the
emission
standard.
(
The
inclusion
of
engine
power,
useful
life,
and
production
volume
in
the
averaging
calculations
is
designed
to
reflect
differences
in
the
in­
use
emissions
from
the
engines.)
Averaging
results
are
calculated
for
each
specific
model
year.
The
mechanism
by
which
this
is
accomplished
is
certification
of
the
engine
family
to
a
"
family
emission
limit"
(
FEL)
set
by
the
manufacturer,
which
may
be
above
or
below
the
standard.
An
FEL
that
is
established
above
the
standard
may
not
exceed
an
upper
limit
specified
in
the
ABT
regulations.
Once
an
engine
family
is
certified
to
an
FEL,
that
FEL
becomes
the
enforceable
emissions
limit
for
all
the
engines
in
that
family
for
purposes
of
compliance
testing.
Averaging
is
allowed
only
between
engine
families
in
the
same
averaging
set,
as
defined
in
the
regulations.
89
Banking
means
the
retention
of
emission
credits
by
the
engine
manufacturer
for
use
in
future
model
year
averaging
or
trading.
Trading
means
the
exchange
of
emission
credits
between
nonroad
diesel
engine
manufacturers
which
can
then
be
used
for
averaging
purposes,
banked
for
future
use,
or
traded
to
another
engine
manufacturer.

The
existing
ABT
program
for
nonroad
diesel
engines
covers
NMHC+
NO
X
emissions
as
well
as
PM
emissions.
With
today's
action
and
as
proposed,
we
are
making
the
ABT
program
available
for
the
Tier
4
NO
X
standards
(
and
NMHC+
NO
X
standards,
where
applicable)
and
the
Tier
4
PM
standards.
As
proposed,
ABT
will
not
be
available
for
the
Tier
4
NMHC
standards
for
engines
above
75
horsepower.

Engine
manufacturers
commented
that
ABT
will
most
likely
be
necessary
for
the
Tier
4
CO
standards,
given
the
reductions
in
PM
and
NO
X
emissions.
In
the
Tier
4
proposal,
we
proposed
minor
changes
in
CO
standards
for
some
engines
solely
for
the
purpose
of
helping
to
consolidate
power
categories
and
improving
administrative
efficiency.
However,
as
noted
earlier
in
section
II.
A.
6,
we
have
withdrawn
this
aspect
of
the
proposal.
We
do
note,
however,
that
we
are
applying
new
certification
tests
to
all
pollutants
covered
by
the
rule,
the
result
being
that
Tier
4
engines
will
have
to
certify
to
CO
standards
measured
by
the
transient
test
(
including
a
cold
start
component),
and
the
NTE.
However,
as
shown
in
RIA
chapter
4.1.1.2
(
see
e.
g.,
note
F),
we
believe
that
application
of
Tier
4
technologies
will
lead
to
a
reduction
in
CO
emissions
over
the
Tier
3
baseline.
We
thus
believe
the
CO
standards
will
be
readily
achievable
under
the
transient
test
and
NTE.
Moreover,
we
believe
that
there
will
not
be
any
associated
costs:
the
CO
standards
can
be
met
without
any
further
technological
improvements
(
i.
e.,
improvements
other
than
those
already
necessary
to
meet
the
Tier
4
standards)
and
these
tests
will
already
be
used
for
certification.
Since
CO
standards
measured
by
the
new
certification
tests
are
achievable
without
cost,
there
is
no
basis
for
allowing
ABT
because
no
additional
lead
time
is
needed.

As
noted
earlier,
the
existing
ABT
program
for
nonroad
diesel
engines
includes
FEL
caps
­­
limits
on
how
high
the
emissions
from
credit­
using
engine
families
can
be.
No
engine
family
may
be
certified
above
these
FEL
caps.
These
limits
provide
manufacturers
with
compliance
flexibility
while
protecting
against
the
introduction
of
unnecessarily
high­
emitting
engines.
In
the
past,
we
have
generally
set
the
FEL
caps
at
the
emission
levels
allowed
by
the
previous
standard,
unless
there
was
some
specific
reason
to
do
otherwise.
With
today's
action,
we
are
taking
a
different
approach
because
the
level
of
the
standards
being
adopted
for
most
engines
are
significantly
lower
than
the
current
level
of
the
standards.
The
transfer
to
new
technology
is
feasible
and
appropriate.
Thus,
as
proposed,
to
ensure
that
the
ABT
provisions
are
not
used
to
continue
unnecessarily
to
produce
old­
technology
high­
emitting
engines
under
the
new
program,
the
FEL
caps
are
not,
in
general,
set
at
the
previous
standards.
Exceptions
have
been
made
for
the
NMHC+
NO
X
standard
for
engines
between
25
and
50
horsepower
effective
in
model
year
2013
and
the
NO
X
standards
applicable
to
engines
above
750
horsepower
in
2011,
where
we
are
using
the
estimated
NO
X­
only
equivalent
for
the
previously
applicable
NMHC+
NO
X
standard
for
the
FEL
cap
since
the
gap
between
the
previous
and
newly
adopted
standards
is
approximately
40
percent
(
rather
than
90
percent
for
engines
between
75
and
750
horsepower),
and
because
the
90
technology
basis
for
these
standards
can
be
a
form
of
engine­
out
control,
like
the
previous
tier
standards.
This
approach
of
setting
FEL
caps
at
lower
levels
than
the
previously
applicable
standards
is
consistent
with
the
level
of
the
FEL
limits
set
in
the
2007
on­
highway
heavy­
duty
diesel
engine
program.

STAPPA/
ALAPCO
supported
the
proposed
FEL
caps.
The
Engine
Manufacturers
Association
(
EMA)
commented
that
EPA
should
eliminate
the
FEL
caps
altogether.
They
believe
FEL
caps
are
unnecessary
because
the
zero­
sum
requirement
of
ABT
will
ensure
that
there
are
no
adverse
emission
impacts.
Short
of
eliminating
the
FEL
caps,
they
commented
that
EPA
should
set
FEL
caps
at
the
level
of
the
previous
standards,
not
the
more
stringent
levels
proposed.
With
today's
action,
EPA
is
adopting
the
FEL
caps
as
proposed,
with
some
exceptions
for
engines
above
750
horsepower
(
where
we
are
adopting
different
standards
than
originally
proposed)
and
for
phase­
in
engines
between
75
and
750
horsepower
(
where
we
have
adopted
an
option
for
manufacturers
to
certify
to
alternative
NO
X
standards
during
the
phase­
in
period).
We
continue
to
believe
that
it
is
important
to
ensure
that
technology
turns
over
in
a
timely
manner
and
that
manufacturers
do
not
continue
producing
large
numbers
of
high­
emitting,
old
technology
engines
once
the
Tier
4
standards
become
fully
effective.
(
As
noted
below,
however,
we
are
adopting
provisions
that
allow
manufacturers
to
produce
a
limited
number
of
75
to
750
horsepower
engines
for
a
limited
period
that
are
certified
with
FELs
as
high
as
the
previous
tier
of
standards.)
For
the
Tier
4
standards,
where
the
standards
are
being
reduced
by
an
order
of
magnitude,
we
believe
this
goal
to
be
particularly
important,
and
in
keeping
with
the
technology­
forcing
provisions
of
section
213(
a).
It
simply
would
not
be
appropriate
to
have
long­
term
FEL
caps
that
allowed
engines
to
indefinitely
have
emissions
as
high
as
ten
times
the
level
of
the
standard.

For
engines
between
75
and
750
horsepower
certified
using
the
phase­
in/
phase­
out
approach,
there
will
be
two
separate
sets
of
engines
with
different
FEL
caps.
For
engines
certified
to
the
existing
(
Tier
3)
NMHC+
NO
X
standards
during
the
NO
X
phase­
in
(
referred
to
generally
as
"
phase­
out"
engines),
the
FEL
cap
for
these
pollutants
will
(
almost
necessarily)
be
the
existing
FEL
caps
adopted
in
the
October
1998
Tier
3
rule.
For
engines
certified
to
the
newly
adopted
Tier
4
NO
X
standard
during
the
phase­
in
(
referred
to
generally
as
"
phase­
in"
engines),
we
have
revised
the
proposed
FEL
cap
to
be
0.60
g/
bhp­
hr,
consistent
with
the
proposed
long­
term
Tier
4
NO
X
FEL
cap.
As
described
in
section
II.
A.
2.
c
above,
we
have
used
the
creation
of
alternative
NO
X
standards
for
engines
between
75
and
750
horsepower
to
restate
the
phase­
in/
phase­
out
concept
as
a
path
truly
focused
on
achieving
high­
efficiency
NO
X
aftertreatment
during
the
phasein
years.
Setting
the
NO
X
FEL
cap
at
0.60
g/
bhp­
hr
for
phase­
in
engines
will
ensure
this
happens
if
a
manufacturer
chooses
to
certify
to
the
phase­
in
provisions.
In
contrast,
the
higher
FEL
caps
which
we
proposed
(
see
68
FR
28467
 
28468)
would
not
have
achieved
this
objective.

Beginning
in
model
year
2014
when
the
Tier
4
NO
X
standards
for
engines
between
75
and
750
horsepower
take
full
effect,
we
are
adopting
a
NO
X
FEL
cap
of
0.60
g/
bhp­
hr
for
all
engines.
We
reiterate
that
given
the
fact
that
the
Tier
4
NO
X
standard
is
approximately
a
90
percent
reduction
from
the
existing
standards
for
engines
between
75
and
750
horsepower,
we
do
not
believe
the
previous
standard
is
appropriate
as
the
FEL
cap
for
engines
having
to
comply
with
the
91
Tier
4
NO
X
standard
of
0.30
g/
bhp­
hr.
We
believe
that
the
NO
X
FEL
caps
will
ensure
that
manufacturers
adopt
NO
X
aftertreatment
technology
across
all
of
their
engine
designs.

For
the
interim
PM
standards
for
engines
between
25
and
75
horsepower
effective
in
model
year
2008
and
for
the
Tier
4
PM
standards
for
engines
below
25
horsepower,
we
are
adopting
the
previously
applicable
Tier
2
PM
standards
for
the
FEL
caps
(
which
do
vary
within
the
25
to
75
horsepower
category)
because
the
gap
between
the
previous
standards
and
the
newly
adopted
standards
is
approximately
50
percent
(
rather
than
in
excess
of
90
percent
for
engines
between
75
and
750
horsepower),
and
the
technology
basis
for
the
2008
PM
standards
can
be
a
form
of
engine­
out
control,
like
the
previous
tier
standard.
For
the
Tier
4
PM
standard
effective
in
model
year
2013
for
engines
between
25
and
75
horsepower,
we
are
adopting
a
PM
FEL
cap
of
0.04
g/
bhp­
hr,
and
for
the
Tier
4
PM
standard
effective
in
model
years
2011
and
2012
for
engines
between
75
and
750
horsepower,
we
are
adopting
a
PM
FEL
cap
of
0.03
g/
bhp­
hr.
As
with
the
Tier
4
NO
X
standards
for
these
engines,
given
the
fact
that
these
Tier
4
aftertreatment­
based
PM
standards
for
engines
between
25
and
750
horsepower
are
over
90
per
cent
more
stringent
than
the
previous
standards,
we
do
not
believe
the
previous
standards
are
appropriate
as
FEL
caps
once
the
Tier
4
standards
take
effect.
We
believe
that
the
newly
adopted
PM
FEL
caps
will
ensure
that
manufacturers
adopt
PM
aftertreatment
technology
across
all
of
their
engine
designs
(
except
for
a
limited
number
of
engines),
yet
will
still
provide
substantial
flexibility
in
meeting
the
standards.

The
final
Tier
4
standards
for
engines
above
750
horsepower
have
been
revised
from
the
proposal.
We
similarly
revised
a
number
of
the
proposed
ABT
provisions
for
engines
above
750
horsepower.
Beginning
in
2011,
all
engines
above
750
horsepower
will
be
required
to
meet
a
NO
X
standard
of
2.6
g/
bhp­
hr,
except
for
those
above
1200
horsepower
used
in
generator
sets
which
will
be
required
to
meet
a
NO
X
standard
of
0.50
g/
bhp­
hr.
The
NO
X
FEL
cap
for
the
2011
standards
will
be
4.6
g/
bhp­
hr,
which
is
an
estimate
of
the
NO
X
emissions
level
that
is
expected
under
the
combined
NMHC+
NO
X
standards
that
apply
with
the
previously
applicable
tier
for
engines
above
750
horsepower.
Beginning
in
2011,
all
engines
above
750
horsepower
will
have
to
meet
a
PM
standard
of
0.075
g/
bhp­
hr.
The
PM
FEL
cap
for
the
2011
PM
standard
will
be
the
previously­
applicable
Tier
2
standard
of
0.15
g/
bhp­
hr.
As
noted
above,
because
the
2011
NO
X
and
PM
standards
are
approximately
50
percent
lower
than
the
previous
standard
(
rather
than
in
excess
of
90
percent
for
engines
between
75
and
750
horsepower),
and
for
most
engines
are
based
on
performance
of
the
same
type
of
technology
(
engine­
out),
we
are
adopting
the
previously
applicable
Tier
2
standards
for
the
FEL
caps.

Beginning
in
model
year
2015,
the
0.50
g/
bhp­
hr
NO
X
standard
will
apply
to
all
engines
above
750
horsepower
used
in
generator
sets.
Beginning
in
model
year
2015,
the
PM
standard
drops
to
0.02
g/
bhp­
hr
for
engines
greater
than
750
horsepower
used
in
generator
sets
and
0.03
g/
bhp­
hr
for
engines
greater
than
750
horsepower
used
in
other
machines.
Consistent
with
the
Tier
4
FEL
caps
for
lower
horsepower
categories
where
the
new
standards
are
significantly
lower
than
the
previously
applicable
standards
and
reflect
performance
of
aftertreatment
technology,
we
are
adopting
a
NO
X
FEL
cap
of
0.80
g/
bhp­
hr
for
engines
used
in
generator
sets
and
PM
FEL
92
caps
of
0.04
g/
bhp­
hr
for
engines
used
in
generator
sets
and
0.05
g/
bhp­
hr
for
engines
used
in
other
machines
(
i.
e.,
mobile
machines).
We
believe
that
the
FEL
caps
for
engines
above
750
horsepower
will
ensure
that
manufacturers
adopt
PM
aftertreament
technology
across
all
of
their
engine
designs
and
NO
X
aftertreatment
for
generator
sets
once
the
2015
standards
are
adopted,
while
allowing
for
some
meaningful
use
of
averaging
beginning
in
2015.

Table
III.
A­
1
contains
the
FEL
caps
and
the
effective
model
year
for
the
FEL
caps
(
along
with
the
associated
standards
adopted
for
Tier
4).
It
should
be
noted
that
for
Tier
4,
where
we
are
adopting
a
new
transient
test
for
most
engines,
as
well
as
retaining
the
current
steady­
state
test,
the
FEL
established
by
the
engine
manufacturer
will
be
used
as
the
enforceable
limit
for
the
purpose
of
compliance
testing
under
both
test
cycles.
In
addition,
under
the
NTE
requirements,
the
FEL
times
the
appropriate
multiplier
will
be
used
as
the
enforceable
limit
for
the
purpose
of
such
compliance
testing.
This
is
consistent
with
how
FELs
are
used
for
compliance
purposes
in
the
2007
on­
highway
heavy­
duty
diesel
engine
program.
93
Table
III.
A­
1.
 
FEL
Caps
for
the
Tier
4
Standards
in
the
ABT
Program
(
g/
bhp­
hr)

Power
Category
Effective
Model
Year
NOX
Standard
NOX
FEL
Cap
PM
Standard
PM
FEL
Cap
hp
<
25
(
kW
<
19)
2008+
5.6a
7.8a
for
<
11hp
7.1a
for
>
11hp
0.30c
0.60
25

hp
<
50
(
19

kW
<
37)
2008­
2012
5.6a
7.1a
0.22
0.45
25

hp
<
50
(
19

kW
<
37)
2013+
3.5b
5.6b
0.02
0.04f
50

hp
<
75
(
37

kW
<
56)
2008­
2012d
3.5a
5.6a
0.22
0.30
50

hp
<
75
(
37

kW
<
56)
2013+
e
3.5a
5.6a
0.02
0.04f
75

hp
<
175
(
56

kW
<
130)
2012+
0.30
0.60f,
g,
h
0.01
0.03f
175

hp

750
(
130

kW

560)
2011+
0.30
0.60f,
g,
h
0.01
0.03f
hp
>
750
(
kW
>
560)
2011­
2014
2.6
4.6
0.075
0.15
0.50i
4.6
Generator
Sets
hp
>
750
(
kW
>
560)
2015+
0.50
0.80f
0.02
0.04f
Other
Machines
hp
>
750
(
kW
>
560)
2015+
2.6j
4.6j
0.03
0.05f
Notes:
a
These
are
the
previous
tier
NMHC+
NOX
standards
and
FEL
caps.
These
levels
are
not
being
revised
with
today's
rule
and
are
printed
here
solely
for
readers'
convenience.
b
These
are
a
combined
NMHC+
NOX
standard
and
FEL
cap.
c
A
manufacturer
may
delay
implementation
until
2010
and
then
comply
with
a
PM
standard
of
0.45
g/
bhp­
hr
for
air­
cooled,
hand­
startable,
direct
injection
engines
under
11
horsepower.
d
These
FEL
caps
do
not
apply
if
the
manufacturer
opts
out
of
the
2008
standards.
In
such
cases,
the
existing
Tier
3
standards
and
FEL
caps
continue
to
apply.
e
The
FEL
caps
apply
in
model
year
2012
if
the
manufacturer
opts
out
of
the
2008
standards.
f
As
described
in
this
section,
a
small
number
of
engines
are
allowed
to
exceed
these
FEL
caps.
g
For
engines
certified
as
phase­
out
engines,
the
NMHC+
NOX
FEL
caps
for
the
Tier
3
standards
apply.
h
For
engines
certified
to
the
alternative
NOX
standards
during
the
phase­
in,
the
NOX
FEL
caps
shown
in
tables
III.
A­
3
and
III.
A­
4
apply.
i
The
0.50
g/
bhp­
hr
NOX
standard
applies
only
to
engines
above
1200
horsepower
used
in
generator
sets.
j
The
2011
NOX
standard
and
FEL
cap
continue
to
apply
unless
and
until
revised
by
EPA
in
a
future
action.
94
As
noted
above,
we
are
allowing
a
limited
number
of
engines
to
have
a
higher
FEL
than
the
caps
noted
in
table
III.
A­
1
in
certain
instances.
The
FEL
cap
for
such
engines
would
be
set
based
on
the
level
of
the
standards
that
applied
in
the
year
prior
to
the
new
standards
and
will
allow
manufacturers
to
produce
a
limited
number
of
engines
certified
to
these
earlier
standards
in
the
Tier
4
timeframe.
The
allowance
to
certify
up
to
these
higher
FEL
caps
will
apply
to
Tier
4
engines
between
25
and
750
horsepower
beginning
as
early
as
the
2011
model
year,
and
will
apply
to
engines
above
750
horsepower
starting
with
the
2015
model
year.
The
provisions
are
intended
to
provide
some
limited
flexibility
for
engine
manufacturers
as
they
make
the
transition
to
the
aftertreatment­
based
Tier
4
standards
while
ensuring
that
the
vast
majority
of
engines
are
converted
to
the
advanced
low­
emission
technologies
expected
under
the
Tier
4
program.

Under
the
proposal,
manufacturers
would
have
been
allowed
to
certify
at
levels
up
to
these
FEL
caps
for
ten
percent
of
its
engines
in
each
of
the
first
four
years
after
the
Tier
4
standards
took
effect
and
then
five
percent
for
subsequent
years.
The
California
Air
Resources
Board
supported
the
proposed
allowance.
The
Engine
Manufacturers
Association
commented
that
the
percentages
of
engines
allowed
to
the
higher
FEL
caps
may
not
be
sufficient,
noting
that
it
is
too
early
to
tell
if
the
proposed
amounts
provided
enough
flexibility.

In
an
effort
to
provide
flexibility
to
engine
manufacturers
while
preserving
the
effective
number
of
engines
allowed
to
certify
at
levels
up
to
the
higher
FEL
caps,
we
are
revising
the
proposed
provisions
with
today's
action.
The
revised
provisions
are
intended
to
allow
manufacturers
to
produce
the
same
number
of
engines
certified
to
the
higher
FEL
caps
as
would
have
been
allowed
under
the
proposal,
but
provide
added
flexibility
in
how
they
distribute
the
allowances
over
the
first
four
years
of
the
transition
to
the
new
standards.
This
additional
lead
time
appears
appropriate,
given
the
potential
that
a
limited
set
of
nonroad
engines
may
face
especially
challenging
compliance
difficulties.
Under
the
provisions
adopted
today
and
subject
to
the
limitations
explained
below,
a
manufacturer
would
be
allowed
to
certify
up
to
40
percent
of
its
engines
above
the
FEL
caps
shown
in
table
III.
A­
1
over
the
first
four
years
the
aftertreatmentbased
Tier
4
standards
take
effect
(
calculated
as
a
cumulative
total
of
the
percent
of
engines
exceeding
these
FEL
caps
in
each
year
over
the
four
years),
with
a
maximum
of
20
percent
allowed
in
any
given
year
(
provided
the
FELs
for
these
engines
do
not
exceed
levels
specified
below).
During
this
four
year
period,
manufacturers
would
not
be
required
to
perform
transient
testing
or
NTE
testing
on
these
engines
because
we
expect
these
engines
would
be
carried
over
directly
from
the
previous
tier
without
any
modification.
(
NTE
testing
would
apply
to
engines
above
750
horsepower
because
the
previously
applicable
set
of
standards
required
NTE
testing.)
Similarly,
for
engines
between
75
and
750
horsepower,
manufacturers
would
not
be
required
to
have
closed
crankcase
controls
on
these
engines
because
we
also
expect
that
these
engines
would
be
carried
over
directly
from
the
previous
tier
without
any
modification.
(
Engines
between
25
and
75
horsepower,
and
engines
above
750
horsepower,
would
be
required
to
have
closed
crankcase
controls
because
the
previously
applicable
set
of
standards
require
closed
crankcase
controls.)

For
the
purpose
of
calculating
the
number
of
credits
such
engines
would
use,
the
manufacturer
would
include
an
adjustment
to
the
FEL
to
be
used
in
the
credit
calculation
95
equation.
The
adjustment
would
be
included
by
multiplying
the
steady­
state
FEL
by
a
Temporary
Compliance
Adjustment
Factor
(
TCAF)
of
1.5
for
PM
and
1.1
for
NO
X.
(
The
NO
X
TCAF
would
not
apply
to
engines
that
are
not
subject
to
the
transient
testing
requirements
for
NO
X
as
discussed
in
section
III.
F.)
We
are
adopting
TCAFs
in
part
to
assure
in­
use
control
of
emission
from
these
engines
in
the
absence
of
transient
and
NTE
testing,
and
also
to
assure
that
any
credits
these
engines
use
reflect
the
level
of
reductions
expected
in
use.
The
level
of
the
TCAFs
are
based
on
data
from
pre­
control,
Tier
1,
and
Tier
2
engines
which
show
that
the
emissions
from
such
engines
tested
over
transient
test
cycles
which
are
more
representative
of
real
in­
use
operation
are
higher
than
emissions
from
those
engines
tested
over
the
steady­
state
certification
test
cycle.
This
is
a
sales
weighted
version
of
the
Transient
Adjustment
Factor
used
in
the
NONROAD
model.
For
compliance
purposes,
a
manufacturer
would
be
held
accountable
to
the
unadjusted
steady­
state
FEL
established
for
the
engine
family.

As
proposed,
after
the
fourth
year
the
Tier
4
standards
apply,
the
allowance
to
certify
engines
using
the
higher
FEL
caps
shown
in
table
III.
A­
2
will
still
be
available
but
for
no
more
than
five
percent
of
the
engines
a
manufacturer
produces
in
each
power
category
in
a
given
year.
When
the
5
percent
allowance
takes
effect,
these
engines
will
be
considered
Tier
4
engines
and
all
other
requirements
for
Tier
4
engines
will
also
apply,
including
the
Tier
4
NMHC
standard,
transient
testing,
NTE
testing,
and
closed
crankcase
controls.
TCAFs
thus
do
not
apply
when
calculating
the
number
of
credits
such
engines
would
use.

In
the
two
power
categories
where
we
are
adopting
phase­
in
provisions
(
i.
e.,
75
to
175
horsepower
engines
and
175
to
750
horsepower
engines),
the
allowance
to
use
a
higher
FEL
cap
will
only
apply
to
PM
from
phase­
out
engines
during
the
phase­
in
years.
We
originally
proposed
that
the
allowance
to
use
a
higher
FEL
cap
would
apply
to
PM
from
either
phase­
in
or
phase­
out
engines
during
the
phase­
in
years.
On
reflection,
this
is
inconsistent
with
our
policy
that
phase­
in
engines
truly
have
low
emissions
reflecting
use
of
aftertreatment
(
see
also
the
discussion
above
where
we
explain
that,
for
the
same
reason,
we
are
adopting
a
NO
X
FEL
cap
of
0.60
g/
bhp­
hr
for
phase­
in
engines).
We
consequently
are
revising
the
proposed
allowance
so
that
it
is
available
for
PM
emissions
only
from
phase­
out
engines.
As
proposed,
the
allowance
to
use
a
higher
FEL
cap
for
NO
X
will
apply
starting
in
2014
when
the
phase­
in
period
is
complete.

For
the
power
category
between
25
and
75
horsepower,
this
allowance
to
certify
engines
at
levels
up
to
the
higher
FEL
caps
will
apply
beginning
with
the
Tier
4
standards
taking
effect
in
the
2013
model
year
and
will
apply
to
PM
only.
For
manufacturers
choosing
to
opt
out
of
the
2008
model
year
Tier
4
standards
for
engines
between
50
and
75
horsepower
and
instead
comply
with
the
Tier
4
standards
beginning
in
2012,
the
40%
allowance
would
apply
to
model
years
2012
through
2015,
and
the
5%
allowance
would
apply
to
model
year
2016
and
thereafter.
The
allowance
to
use
the
higher
FEL
caps
is
not
applicable
for
the
2008
standards
or
the
2013
NMHC+
NO
X
standards
for
these
engines
because
the
FEL
caps
for
those
standards
already
are
set
at
the
level
of
the
standard
which
previously
applied.
96
For
engines
above
750
horsepower,
the
allowance
to
certify
a
limited
number
of
engines
at
levels
up
to
the
higher
FEL
caps
would
apply
beginning
in
model
year
2015.
(
As
noted,
this
is
because
the
FEL
caps
being
adopted
for
the
2011
standards
for
engines
above
750
horsepower
are
the
previous
tier
PM
standard
and
the
NO
X­
only
equivalent
of
the
previous
tier
standard.)
For
NO
X,
the
allowance
to
certify
a
limited
number
of
engines
above
the
FEL
cap
beginning
in
model
year
2015
will
apply
only
to
engines
used
in
generator
sets.
Engines
used
in
other
machines
are
still
subject
to
the
model
year
2011
NO
X
standard
and
FEL
caps.
For
PM,
the
allowance
to
certify
a
limited
number
of
engines
above
the
FEL
caps
beginning
in
model
year
2015
will
apply
to
all
engines
above
750
horsepower.

Table
III.
A­
2
presents
the
model
years,
percent
of
engines,
and
higher
FEL
caps
that
will
apply
under
these
allowances.
As
noted
above,
engines
certified
under
these
higher
FEL
caps
during
the
first
four
years
would
not
be
required
to
perform
transient
testing
or
NTE
testing
and
engines
between
75
and
750
horsepower
would
not
be
required
to
have
closed
crankcase
controls
on
these
engines.
However,
as
also
noted
earlier,
beginning
in
the
fifth
year,
when
the
5
percent
allowance
takes
effect,
these
engines
will
be
considered
Tier
4
engines
and
all
other
requirements
for
Tier
4
engines
will
also
apply,
including
the
Tier
4
NMHC
standard,
transient
testing,
NTE
testing,
and
closed
crankcase
controls.
97
Table
III.
A­
2.
 
Allowance
for
Limited
Use
of
an
FEL
Cap
Higher
than
the
Tier
4
FEL
Caps
Power
Category
Model
Years
Engines
Allowed
to
have
Higher
FELs
NOX
FEL
Cap
(
g/
bhp­
hr)
PM
FEL
Cap
(
g/
bhp­
hr)

25

hp
<
75
(
19

kW
<
56)
2013­
2016a
40%
b
Not
applicable
0.22
2017+
a
5%

75

hp
<
175
(
56

kW
<
130)
2012­
2015
40%
b
3.3c
for
hp
<
100
2.8c
for
hp

100
0.30d
for
hp
<
100
0.22d
for
hp

100
2016+
5%

175

hp

750
(
130

kW

560)
2011­
2014
40%
b
2.8c
0.15d
2015+
5%

>
750
hp
(>
560
kW)
2015­
2018
40%
b,
e
2.6
0.075
2019+
5%
e
Notes:

a
For
manufacturers
choosing
to
opt
out
of
the
2008
model
year
Tier
4
standards
for
engines
between
50
and
75
horsepower
and
instead
comply
with
the
Tier
4
standards
beginning
in
2012,
the
40%
allowance
would
apply
to
model
years
2012
through
2015,
and
the
5%
allowance
would
apply
to
model
year
2016
and
thereafter.

b
Compliance
with
the
40%
limit
is
determined
by
adding
the
percent
of
engines
that
have
FELs
above
the
FEL
caps
shown
in
table
III.
A.­
1
in
each
of
the
four
years.
A
manufacturer
may
not
have
more
than
20%
of
its
engines
exceed
the
FEL
caps
shown
in
table
III.
A­
1
in
any
model
year
in
any
power
category.

c
The
allowance
to
certify
to
these
higher
NOX
FEL
caps
is
not
applicable
during
the
phase­
in
period.

d
These
higher
PM
FEL
caps
are
applicable
to
phase­
out
engines
only
during
the
phase­
in
period.

e
The
limits
of
40%
or
5%
allowed
to
exceed
the
NOX
FEL
cap
would
apply
to
engines
used
in
generator
sets
only.
(
Engines
>
750
hp
used
in
other
machines
are
allowed
to
have
an
NOX
FEL
as
high
as
4.6
g/
bhp­
hr.)
The
limits
of
40%
or
5%
allowed
to
exceed
the
PM
FEL
cap
would
apply
to
all
engines
above
750
hp.

Under
the
Tier
4
program,
there
will
be
two
different
groups
of
75­
750
horsepower
engines
during
the
NO
X
phase­
in
period.
In
one
group
("
phase­
out
engines"),
engines
will
certify
to
the
applicable
Tier
3
NMHC+
NO
X
standard
and
will
be
subject
to
the
NMHC+
NO
X
ABT
restrictions
and
allowances
previously
established
for
Tier
3.
In
the
other
group
("
phase­
in
engines"),
engines
will
certify
to
the
0.30
g/
bhp­
hr
NO
X
standard,
and
will
be
subject
to
the
restrictions
and
allowances
in
this
program.
Although
engines
in
each
group
are
certified
to
different
standards,
we
are
(
as
proposed)
allowing
manufacturers
to
transfer
credits
across
these
two
groups
of
engines
with
the
following
adjustment
to
the
amount
of
credits
generated.
98
Manufacturers
will
be
able
to
use
credits
generated
during
the
phase­
out
of
engines
subject
to
the
Tier
3
NMHC+
NO
X
standard
to
average
with
engines
subject
to
the
0.30
g/
bhp­
hr
NO
X
standard,
but
these
credits
will
be
subject
to
a
20
percent
discount,
the
adjustment
reflecting
the
NMHC
contribution.
Thus,
each
gram
of
NMHC+
NO
X
credits
from
the
phase­
out
engines
will
be
worth
0.8
grams
of
NO
X
credits
in
the
new
ABT
program.
The
ability
to
average
credits
between
the
two
groups
of
engines
will
give
manufacturers
a
greater
opportunity
to
gain
experience
with
the
low­
NO
X
technologies
before
they
are
required
to
meet
the
final
Tier
4
standards
across
their
full
production.
The
20
percent
discount
will
also
apply,
for
the
same
reason,
to
all
NMHC+
NO
X
credits
used
for
averaging
purposes
with
the
NO
X
standards
for
engines
greater
than
75
horsepower.

The
California
Air
Resources
Board
supported
the
proposed
discount
of
20
percent
on
NMHC+
NO
X
credits
used
for
NO
X
compliance.
The
Engine
Manufacturer's
Association
commented
that
we
should
eliminate
the
20
percent
"
discount"
on
NMHC+
NO
X
credits
used
for
NO
X
compliance.

We
disagree
with
the
Engine
Manufacturer's
Association
comments.
As
noted
in
the
proposal,
we
have
two
main
reasons
for
adopting
this
adjustment.
First,
the
discounting
addresses
the
fact
that
NMHC
reductions
can
provide
substantial
NMHC+
NO
X
credits,
which
are
then
treated
as
though
they
were
NO
X
credits.
For
example,
a
2010
model
year
175
horsepower
engine
emitting
at
2.7
g/
bhp­
hr
NO
X
and
0.3
g/
bhp­
hr
NMHC
meets
the
3.0
g/
bhp­
hr
NMHC+
NO
X
standard
in
that
year,
but
gains
no
credits.
In
2011,
that
engine,
equipped
with
a
PM
trap
to
meet
the
new
PM
standard,
will
have
very
low
NMHC
emissions
because
of
the
trap,
an
emission
reduction
already
accounted
for
in
our
assessment
of
the
air
quality
benefit
of
this
program.
As
a
result,
without
substantially
redesigning
the
engine
to
reduce
NO
X
or
NMHC,
the
manufacturer
could
garner
nearly
0.3
g/
bhp­
hr
of
NMHC+
NO
X
credit
for
each
of
these
engines
produced.
Allowing
these
NMHC­
derived
credits
to
be
used
undiscounted
to
offset
NO
X
emissions
on
the
phase­
in
engines
in
2011
(
for
which
each
0.1
g/
bhp­
hr
of
margin
can
make
a
huge
difference
in
facilitating
the
design
of
engines
to
meet
the
0.30
g/
bhp­
hr
NO
X
standard)
would
be
inappropriate.
Therefore,
while
we
are
reducing
the
value
of
credits
earned
from
Tier
2/
Tier
3
engines,
the
adjustment
accounts
for
the
NMHC
fraction
of
the
credits
which
we
do
not
believe
should
be
used
to
demonstrate
compliance
with
the
NO
X­
only
Tier
4
standards
(
such
credits
would
be
"
windfalls"
because
they
would
necessarily
occur
by
virtue
of
the
technology
needed
to
meet
the
PM
standard)
(
68
FR
28469,
May
23,
2003).
Second,
the
discounting
will
work
toward
providing
a
small
net
environmental
benefit
from
the
ABT
program,
such
that
the
more
manufacturers
use
banked
and
averaged
credits,
the
greater
the
potential
emission
reductions
overall.
Most
basically,
it
is
inherently
reasonable,
in
using
NO
X
+
NMHC
reductions
to
show
credit
with
a
NO
X­
only
standard,
to
use
only
that
portion
which
represents
NO
X
reductions.
(
Indeed,
for
this
reason,
terming
the
20
per
cent
a
`
discount
factor'
is
a
misnomer;
it
apportions
the
NMHC
fraction
of
the
reduction.)
As
noted,
this
is
further
supported
by
the
fact
that
the
NMHC
reductions
for
phase­
out
engines
are
not
extra
reductions
above
and
beyond
what
would
otherwise
occur,
and
therefore
don't
warrant
eligibility
as
credits.
99
We
are
adopting
one
additional
restriction
on
the
use
of
credits
under
the
ABT
program.
For
the
Tier
4
standards,
we
proposed
that
manufacturers
could
only
use
credits
generated
from
other
Tier
4
engines
or
from
engines
certified
to
the
previously
applicable
tier
of
standards
(
i.
e.,
Tier
2
for
engines
below
50
horsepower,
Tier
3
for
engines
between
50
and
750
horsepower,
and
Tier
2
engines
above
750
horsepower).
This
proposed
restriction
was
similar
to
a
restriction
we
currently
have
that
prohibits
the
use
of
Tier
1
credits
to
demonstrate
Tier
3
compliance.
STAPPA/
ALAPCO
and
the
Natural
Resources
Defense
Council
supported
the
proposed
approach
that
limited
the
use
of
previous­
tier
credits
for
Tier
4.
The
Engine
Manufacturer's
Association
commented
that
by
limiting
the
use
of
previous­
tier
credits,
we
are
engaged
in
an
unconstitutional
taking
because
EPA
had
guaranteed
in
the
previous
Tier
2/
Tier
3
rulemaking
that
such
credits
would
not
expire.
We
disagree
that
adopting
a
restriction
on
the
use
of
the
previous
tier
ABT
credits
is
an
unconstitutional
taking.
EPA
did
not,
and
could
not,
decide
in
the
Tier
2/
3
rulemaking
that
Tier
2/
3
credits
could
be
used
to
show
compliance
with
some
future
standards
that
had
not
yet
even
been
adopted.
Thus,
EPA
in
this
rulemaking
is
not
taking
away
something
previously
given.
We
are
not
revisiting
the
Tier
2/
3
standards
but
establishing
a
new
set
of
engine
standards.
In
doing
so,
we
necessarily
must
evaluate
the
provisions
of
previous
rules
and
their
potential
impact
on
the
future
standards
being
considered.
We
are
reasonably
concerned
that
credits
from
engines
certified
to
relatively
high
standards
could
be
used
to
significantly
delay
the
implementation
of
the
final
Tier
4
program
and
its
benefits,
resulting
in
a
situation
where
the
standards
would
no
longer
reflect
the
greatest
degree
of
emission
reduction
available
as
required
under
section
213(
a)(
3)
of
the
Clean
Air
Act,
or
would
no
longer
be
appropriate
under
section
213(
a)(
4)
of
the
Clean
Air
Act.
Therefore,
with
today's
action,
we
are
adopting
the
proposed
provisions
regarding
the
use
of
credits
from
previous
tier
engines,
with
one
minor
revision.

Under
today's
action,
manufacturers
may
only
use
credits
generated
from
other
Tier
4
engines
or
from
engines
certified
to
the
previously
applicable
tier
of
standards
­
except
for
engines
between
50
and
75
horsepower.
Because
we
are
adopting
Tier
4
standards
that
take
effect
as
early
as
2008
for
those
engines,
the
same
year
the
previously­
adopted
Tier
3
standards
are
scheduled
to
take
effect
(
see
section
II.
A.
1.
a
above),
there
is
no
possibility
to
earn
credits
against
the
Tier
3
standards
for
manufacturers
that
certify
with
the
pull­
ahead
standards
in
2008
for
engines
between
50
and
75
horsepower.
Therefore,
we
will
allow
manufacturers
to
use
credits
from
engines
in
the
Tier
2
power
category
that
includes
50
to
75
horsepower
(
i.
e.,
the
50
to
100
horsepower
category)
that
are
certified
to
the
Tier
2
standards
if
they
choose
to
demonstrate
compliance
with
the
pull­
ahead
Tier
4
standards
in
2008
for
engines
between
50
and
75
horsepower.
Manufacturers
that
do
not
choose
to
comply
with
the
2008
Tier
4
standards
for
engines
between
50
and
75
horsepower
and
instead
comply
with
the
2012
Tier
4
standards
for
such
engines
will
not
be
allowed
to
use
Tier
2
credits
in
Tier
4,
but
instead
will
be
allowed
to
use
Tier
3
credits
as
allowed
under
the
standard
provisions
regarding
use
of
previous­
tier
credits
only
for
Tier
4
compliance
demonstration.

With
regard
to
other
restrictions
on
the
use
of
ABT
credits,
we
are
adopting
one
restriction
on
the
use
of
credits
across
the
750
horsepower
threshold.
In
previous
rulemakings,
EPA
has
defined
"
averaging
sets"
within
which
manufacturers
may
use
credits
under
the
ABT
100
program.
Credits
may
not
be
used
outside
of
the
averaging
set
in
which
they
were
generated.
As
described
in
section
II.
A.
4
of
today's
action,
we
have
revised
the
Tier
4
standards
for
engines
above
750
horsepower.
Because
the
standards
for
Tier
4
engines
greater
than
750
horsepower
will
not
be
based
on
the
use
of
PM
aftertreatment
technology
in
2011
or
NO
X
aftertreatment
technology
for
all
mobile
machinery
engines
in
2015,
we
are
adopting
provisions
that
prevent
manufacturers
from
using
credits
from
model
year
2011
and
later
model
year
engines
greater
than
750
horsepower
to
demonstrate
compliance
with
engines
below
750
horsepower.
Without
such
a
limit,
we
are
concerned
that
manufacturers
could
use
credits
from
such
engines
to
significantly
delay
compliance
with
the
numerically
lower
standards
for
engines
below
750
horsepower.
In
addition,
without
such
a
limit,
we
are
concerned
that
manufacturers
could
use
credits
from
engines
below
750
horsepower
to
delay
implementation
of
aftertreatment
technology
for
engines
above
750
horsepower.

One
engine
manufacturer
commented
that
EPA
should
include
a
barrier
to
trading
credits
across
the
75
horsepower
level.
They
cited
concerns
over
the
ability
of
manufacturers
that
produce
a
large
range
of
engine
sizes
to
use
credits
from
high
horsepower
engines
to
offset
emissions
from
their
small
horsepower
engines.
We
are
not
adopting
any
averaging
set
restrictions
for
Tier
4
engines
below
750
horsepower
in
today's
action.
In
the
current
nonroad
diesel
ABT
program,
there
are
averaging
set
restrictions.
The
current
averaging
sets
consist
of
engines
less
than
25
horsepower
and
engines
greater
than
or
equal
to
25
horsepower.
We
adopted
this
restriction
because
of
concerns
over
the
ability
of
manufacturers
to
generate
significant
credits
from
the
existing
engines
and
use
the
credits
to
delay
compliance
with
the
newly
adopted
standards
(
63
FR
56977,
October
23,
1998).
We
believe
the
Tier
4
standards
for
engines
below
750
horsepower
are
sufficiently
rigorous
to
limit
the
ability
of
manufacturers
to
generate
significant
credits
from
their
engines.
In
addition,
we
believe
the
FEL
caps
being
adopted
today
provide
sufficient
assurance
that
low­
emissions
technologies
will
be
introduced
in
a
timely
manner.
Therefore,
we
believe
averaging
can
be
allowed
between
all
engine
power
categories
below
750
horsepower
without
restriction
effective
with
the
Tier
4
standards.
(
It
should
be
noted
that
the
averaging
set
restriction
placed
on
credits
generated
from
Tier
2
and
Tier
3
engines
will
continue
to
apply
if
they
are
used
to
demonstrate
compliance
for
Tier
4
engines.)

EPA
also
proposed
to
allow
engine
manufacturers
to
demonstrate
compliance
with
the
NO
X
phase­
in
requirements
by
certifying
evenly
split
engine
families
at,
or
below,
specified
NO
X
FELs
(
68
FR
28470,
May
23,
2003).
As
described
in
section
II.
A.
2.
c
above,
EPA
is
revising
the
evenly
split
family
provisions
for
the
Tier
4
program
and
is
now
codifying
them
as
alternative
standards.
(
As
described
in
section
III.
L,
we
also
are
adopting
the
proposed
provisions
allowing
manufacturers
to
certify
"
split"
engine
families
during
the
phase­
in
years.)
Because
the
evenly
split
family
provision
has
evolved
into
a
set
of
alternative
NO
X
standards,
we
believe
it
is
appropriate
to
allow
manufacturers
to
use
ABT
for
them.
Table
III.
A­
3
presents
the
FEL
caps
that
will
apply
to
engines
certified
to
the
alternative
NO
X
standards
during
the
phase­
in
years.
The
FEL
caps
for
these
alternative
standards
have
been
set
at
levels
reasonably
close
to
the
alternative
standards
and
are
intended
to
ensure
sizeable
emission
reductions
from
the
previouslyapplicable
Tier
3
standards.
(
For
engines
between
75
and
175
horsepower
certified
under
the
101
reduced
phase­
in
option,
the
FEL
cap
is
the
NO
X­
only
equivalent
of
the
previously
applicable
NMHC+
NO
X
standards
because
the
alternative
standard
is
sufficiently
close
to
the
Tier
3
standard.)

Table
III.
A­
3.
 
NOX
FEL
Caps
for
Engines
Certified
to
the
Alternative
NOX
Standards
Power
Category
Alternative
NOX
Standard
(
g/
bhp­
hr)
NOX
FEL
Cap
(
g/
bhp­
hr)

50/
50/
100
phase­
in
option
for
75

hp
<
175
(
56

kW
<
130)
1.7
2.2
25/
25/
25/
100
phase­
in
option
for
75

hp
<
175
(
56

kW
<
130)
2.5
3.3
(
for
75­
100
hp)

2.8
(
for
100­
175
hp)

175

hp

750
(
130

kW

560)
1.5
2.0
Because
we
are
allowing
manufacturers
to
use
ABT
for
demonstrating
compliance
with
the
alternative
standards
for
engines
between
75
and
750
horsepower,
we
are
allowing
manufacturers
to
exceed
the
FEL
caps
noted
in
table
III.
A­
3
and
include
them
in
the
count
of
engines
allowed
to
exceed
the
FEL
caps
(
i.
e.,
the
40
percent
over
the
first
four
years
the
Tier
4
standards
take
effect
as
described
earlier).
Table
III.
A­
4
presents
the
NO
X
FEL
caps
that
would
apply
to
engines
certified
under
the
alternative
standards
(
limited
by
the
40
percent
cap
over
the
first
four
years).
The
higher
NO
X
FEL
caps
are
set
at
the
estimated
NO
X­
only
equivalent
of
the
previous­
tier
NMHC+
NO
X
standards.
For
manufacturers
certifying
under
the
reduced
phase­
in
(
25
percent)
option,
because
the
FEL
caps
are
the
NO
X­
only
equivalent
of
the
Tier
3
NMHC+
NO
X
standards,
they
may
not
exceed
the
FEL
cap
during
the
years
the
alternative
standard
applies.
102
Table
III.
A­
4.
 
Limited­
Use
NOX
FEL
Caps
Under
the
Alternative
NOX
Standards
Power
Category
Model
Years
NOX
FEL
Cap
(
g/
bhp­
hr)

50/
50/
100
phase­
in
option
for
75

hp
<
175a
(
56

kW
<
130)
2012­
2013
3.3
for
hp
<
100
2.8
for
hp

100
175

hp

750
(
130

kW

560)
2011­
2013
2.8
103
For
reasons
explained
in
section
II.
A.
1.
b.
i
above,
we
are
also
adopting
unique
phase­
in
requirements
for
NO
X
standards
for
engines
between
75
and
175
horsepower
in
order
to
ensure
appropriate
lead
time
for
these
engines.
Because
of
these
unique
phase­
in
provisions,
as
proposed,
we
are
adopting
slightly
different
provisions
regarding
75
to
175
horsepower
engines'
use
of
previous­
tier
credits.
Under
today's
action,
manufacturers
that
choose
to
demonstrate
compliance
with
these
phase­
in
requirements
(
i.
e.,
50
percent
in
2012
and
2013
and
100
percent
in
2014)
or
the
1.7
g/
bhp­
hr
alternative
NO
X
standard
(
which
is
based
on
the
50
percent
phase­
in
option)
will
be
allowed
to
use
Tier
2
NMHC+
NO
X
credits
generated
by
engines
between
50
and
750
horsepower
(
even
though
they
are
not
generated
by
previous­
tier
engines),
along
with
any
other
allowable
credits,
to
demonstrate
compliance
with
the
Tier
4
NO
X
standards
for
engines
between
75
and
175
horsepower
during
model
years
2012,
2013
and
2014
(
the
years
of
the
phase­
in)
only.
These
Tier
2
credits
will
be
subject
to
the
power
rating
conversion
already
established
in
our
ABT
program,
and
to
the
20%
credit
adjustment
being
adopted
today
for
use
of
NMHC+
NO
X
credits
as
NO
X
credits.

The
requirements
for
manufacturers
that
choose
to
demonstrate
compliance
with
the
optional
reduced
phase­
in
requirement
for
engines
between
75
and
175
horsepower
(
i.
e,
the
25/
25/
25
percent
phase­
in
option;
see
Table
II.
A.­
2,
note
b)
or
the
2.5
g/
bhp­
hr
alternative
NO
X
standard
(
which
is
based
on
the
25
percent
phase­
in
option)
are
different.
Under
the
reduced
phase­
in
requirement,
use
of
credits
will
be
allowed
in
accordance
with
the
general
ABT
program
provisions.
In
other
words,
manufacturers
will
not
have
the
special
allowance
to
use
Tier
2
NMHC+
NO
X
credits
generated
by
engines
between
50
and
750
horsepower
noted
above
to
demonstrate
compliance
with
the
Tier
4
standards.
In
addition,
manufacturers
choosing
the
reduced
phase­
in
option
will
not
be
allowed
to
generate
NO
X
credits
from
engines
in
this
power
category
in
2012,
2013,
and
most
of
2014,
except
for
use
in
averaging
within
this
power
category
(
i.
e.,
no
banking
or
trading,
or
averaging
with
engines
in
other
power
categories
will
be
permitted).
This
restriction
will
apply
throughout
this
period
even
if
the
reduced
phase­
in
option
is
exercised
during
only
a
portion
of
this
period.
We
believe
that
this
restriction
is
important
to
avoid
potential
abuse
of
the
added
flexibility
allowance,
considering
that
larger
engine
categories
will
be
required
to
demonstrate
substantially
greater
compliance
levels
with
the
0.30
g/
bhp­
hr
NO
X
standard
several
years
earlier
than
engines
built
under
the
reduced
phase­
in
option.

As
described
in
section
II.
A.
3.
a
of
today's
action,
and
as
proposed,
we
are
adopting
an
optional
PM
standard
for
air­
cooled,
hand­
startable,
direct
injection
engines
under
11
horsepower
effective
in
2010.
In
order
to
avoid
potential
abuse
of
this
standard,
engines
certified
under
this
requirement
will
not
be
allowed
to
generate
any
credits
as
part
of
the
ABT
program.
Credit
use
by
these
engines
will
be
allowed.
The
restriction
on
generating
credits
should
not
be
a
burden
to
manufacturers,
as
it
will
apply
only
to
those
air­
cooled,
hand­
startable,
direct
injection
engines
under
11
horsepower
that
are
certified
under
the
optional
approach,
and
the
production
of
creditgenerating
engines
would
be
contrary
to
the
standard's
purpose.
No
adverse
comments
were
submitted
to
EPA
on
this
issue.
104
The
current
ABT
program
contains
a
restriction
on
trading
credits
generated
from
indirect
injection
engines
greater
than
25
horsepower.
The
restriction
was
originally
adopted
because
of
concerns
over
the
ability
of
manufacturers
to
generate
significant
credits
from
existing
technology
engines
(
63
FR
56977,
October
23,
1998).
With
today's
action,
there
will
be
no
restriction
prohibiting
manufacturers
from
trading
credits
generated
on
Tier
4
indirect
fuel
injection
engines
greater
than
25
horsepower.
Based
on
the
certification
levels
of
indirect
injection
engines,
we
do
not
believe
there
is
the
potential
for
manufacturers
to
generate
significant
credits
from
their
currently
certified
engines
against
the
Tier
4
standards.
Therefore,
as
proposed,
we
are
not
adopting
any
restrictions
on
the
trading
of
credits
generated
on
Tier
4
indirect
injection
engines
to
other
manufacturers.
The
restriction
placed
on
the
trading
of
credits
generated
from
Tier
2
and
Tier
3
indirect
injection
engines
will
continue
to
apply
in
the
Tier
4
timeframe.
No
adverse
comments
were
submitted
to
EPA
on
this
issue.

As
explained
in
the
proposal,
we
are
not
applying
a
specific
discount
to
Tier
3
PM
credits
used
to
demonstrate
compliance
with
the
Tier
4
standards
(
68
FR
28471,
May
23,
2003).
PM
credits
generated
under
the
Tier
3
standards
are
based
on
testing
performed
over
a
steady­
state
test
cycle.
Under
the
Tier
4
standards,
the
test
cycle
is
being
supplemented
with
a
transient
test
(
see
section
III.
F.
1
below).
Because
in­
use
PM
emissions
from
Tier
3
engines
will
vary
depending
on
the
type
of
application
in
which
the
engine
is
used
(
most
applications
having
higher
in­
use
PM
emissions,
some
having
lower
in­
use
PM
emissions),
the
relative
"
value"
of
the
Tier
3
PM
credits
in
the
Tier
4
timeframe
will
differ.
Instead
of
requiring
manufacturers
to
gather
information
to
estimate
the
level
of
in­
use
PM
emissions
compared
to
the
PM
level
of
the
steadystate
test,
we
believe
allowing
manufacturers
to
bring
Tier
3
PM
credits
directly
into
the
Tier
4
time
frame
without
any
adjustment
is
appropriate
because
it
discounts
their
value
for
use
in
the
Tier
4
timeframe
(
since
the
initial
baseline
being
reduced
is
higher
than
measured
in
the
Tier
2
test
procedure
for
most
applications).
No
adverse
comments
were
submitted
to
EPA
on
this
issue.

3.
Are
We
Expanding
the
Nonroad
ABT
Program
to
Include
Credits
from
Retrofit
of
Nonroad
Engines?

In
the
proposal,
we
requested
comment
on
expanding
the
scope
of
the
standards
by
setting
voluntary
new
engine
emission
standards
applicable
to
the
retrofit
of
nonroad
diesel
engines
(
68
FR
28471,
May
23,
2003).
As
described
in
the
proposal,
retrofit
nonroad
engines
would
be
able
to
generate
PM
and
NO
X
credits
which
would
be
available
for
use
by
new
nonroad
engines
in
the
certification
ABT
program.
We
received
a
significant
number
of
comments
on
a
retrofit
ABT
program.
A
number
of
commenters
associated
with
the
agricultural
sector
were
concerned
retrofits
would
be
mandatory.
Some
commenters
were
opposed
to
a
retrofit
credit
program
that
would
allow
use
of
the
credits
under
the
certification
ABT
program.
However,
a
number
of
commenters
supported
the
concept
of
a
retrofit
program,
but
noted
a
number
of
concerns
regarding
the
details
of
such
a
program,
including
making
sure
that
any
credits
earned
would
be
verifiable
and
enforceable.
Some
commenters
suggested
that
EPA
consider
the
establishment
of
a
retrofit
credit
program
through
a
separate
rulemaking
because
there
were
many
details
of
the
program
that
needed
to
be
explored
more
fully
before
adopting
such
a
program.
In
response
to
62
See
memorandum
referenced
at
68
FR
28471
(
May
23,
2003),
footnote
299.

105
the
comments,
we
are
not
adopting
a
retrofit
credit
program
with
today's
action.
Although
we
provided
a
detailed
explanation
of
a
potential
program
at
proposal,
62
we
believe
it
is
important
to
more
fully
consider
the
details
of
a
nonroad
engine
retrofit
credit
program
and
work
with
interested
parties
in
determining
whether
a
viable
program
can
be
developed.
EPA
intends
to
explore
the
possibility
of
a
voluntary,
opt­
in
nonroad
retrofit
credit
program
through
a
separate
action
later
this
year.
Such
a
program
would
be
based
on
the
generation
of
credits
beyond
the
scope
of
any
existing
retrofit
program.
The
final
rule
contains
no
requirements
for
retrofitting
existing
engines
or
equipment.

B.
Transition
Provisions
for
Equipment
Manufacturers
1.
Why
are
we
adopting
transition
provisions
for
equipment
manufacturers?

As
EPA
developed
the
1998
Tier
2/
3
standards
for
nonroad
diesel
engines,
we
determined,
as
an
aspect
of
determining
an
appropriate
lead
time
for
application
of
the
requisite
technology
(
pursuant
to
section
213
(
b)
of
the
Act),
that
provisions
were
needed
to
avoid
unnecessary
hardship
and
to
create
additional
flexibility
for
equipment
manufacturers.
The
specific
concern
is
the
amount
of
work
required
and
the
resulting
time
needed
for
equipment
manufacturers
to
incorporate
all
of
the
necessary
equipment
redesigns
into
their
applications
in
order
to
accommodate
engines
that
meet
the
new
emission
standards.
We
therefore
adopted
a
set
of
provisions
for
equipment
manufacturers
to
provide
them
with
reasonable
lead
time
for
the
transition
process
to
the
newly
adopted
standards.
The
program
consisted
of
four
major
elements:
(
1)
a
percent­
of­
production
allowance,
(
2)
a
small­
volume
allowance,
(
3)
availability
of
hardship
relief,
and
(
4)
continuance
of
the
allowance
to
use
up
existing
inventories
of
engines
(
63
FR
56977­
56978,
October
23,
1998
and
68
FR
28472­
28476,
May
23,
2003).

Given
the
levels
of
the
newly
adopted
Tier
4
standards,
we
believe
that
there
will
be
engine
design
and
other
changes
at
least
comparable
in
magnitude
to
those
involved
during
the
transition
to
Tier
2/
3.
Therefore,
with
a
few
exceptions
described
in
more
detail
below,
we
are
adopting
transition
provisions
for
Tier
4
that
are
similar
to
those
adopted
with
the
previous
Tier
2/
3
rulemaking.
We
also
note
that
opportunities
for
greater
flexibility
arises
from
the
structure
of
the
Tier
4
rule.
For
example,
Tier
4
consolidates
the
nine
power
categories
in
Tier2/
3
into
five
categories,
providing
opportunities
for
more
flexibility
by
allowing
more
engine
families
within
each
power
category,
with
consequent
increased
averaging
possibilities.
The
NO
X
phase­
in
also
provides
increased
flexibility
opportunities,
as
do
the
longer
Tier
4
lead
times.

We
are
adding
new
notification,
reporting,
and
labeling
requirements
to
the
Tier
4
program.
We
believe
these
additional
provisions
are
necessary
for
EPA
to
gain
a
better
understanding
of
the
extent
to
which
these
provisions
will
be
used
and
to
ensure
compliance
with
the
Tier
4
transition
provisions.
We
are
also
adopting
new
provisions
dealing
specifically
with
foreign
equipment
manufacturers
and
the
special
concerns
raised
by
the
use
of
the
transition
106
provisions
for
equipment
imported
into
the
U.
S.
The
following
section
describes
the
Tier
4
transition
provisions
available
to
equipment
manufacturers.
(
Section
III.
C
of
this
preamble
describes
all
of
the
provisions
that
will
be
available
specifically
for
small
businesses.)

As
under
the
existing
Tier2/
Tier
3
provisions,
equipment
manufacturers
are
not
obligated
to
use
any
of
these
provisions,
but
all
equipment
manufacturers
are
eligible
to
do
so.
Also,
as
under
the
existing
program,
all
entities
under
the
control
of
a
common
entity,
and
that
meet
the
regulatory
definition
of
a
nonroad
vehicle
or
nonroad
equipment
manufacturer,
must
be
considered
together
for
the
purpose
of
applying
exemption
allowances.
This
will
not
only
provide
certain
benefits
for
the
purpose
of
pooling
exemptions,
but
will
also
preclude
the
abuse
of
the
small­
volume
allowances
that
would
exist
if
companies
could
treat
each
operating
unit
as
a
separate
equipment
manufacturer.

2.
What
transition
provisions
are
we
adopting
for
equipment
manufacturers?

The
following
section
describes
the
transition
provisions
being
adopted
with
today's
action.
Areas
in
which
we
have
made
changes
to
the
proposed
transition
program
are
highlighted.
A
complete
summary
of
comments
received
on
the
proposed
transition
program
and
our
response
to
those
comments
are
contained
in
the
Summary
and
Analysis
of
Comments
document
for
this
rule.

EPA
believes
that
the
lead
time
provided
through
the
equipment
maker
transition
flexibilities,
as
adopted
in
this
rule,
will
be
sufficient,
as
has
proved
the
case
in
past
tiers.
These
flexibilities
provide
equipment
manufacturers
with
the
selective
ability
to
delay
use
of
the
Tier
4
engines
in
those
applications
where
additional
time
is
needed
to
successfully
incorporate
the
redesigned
engines
into
their
equipment.

Ingersoll­
Rand,
an
equipment
manufacturer,
submitted
a
number
of
comments
arguing
that
significant
expansions
of
the
proposed
flexibility
program
are
needed
if
equipment
manufacturers
are
to
produce
compliant
applications
within
the
effective
dates
of
the
standards.
One
suggestion
was
for
EPA
to
include
provisions
that
provide
a
definitive
period
of
lead
time
for
incorporation
of
Tier
4
engines
into
nonroad
equipment.
Ingersoll­
Rand
would
have
the
rules
specify
a
"
made
available"
date
before
which
each
engine
supplier
must
provide
technical
and
performance
specifications,
complete
drawings,
and
a
final
compliant
engine
to
EPA
and
the
open
market.
After
the
mandated
"
made
available"
date,
equipment
manufacturers
should
be
provided
a
minimum
18
months
of
lead
time
to
incorporate
the
new
engines
into
nonroad
equipment.
One
form
of
the
suggestion
also
entailed
a
prohibition
on
design
changes
once
the
engine,
specifications,
drawings,
etc.
had
been
initially
provided
to
EPA
and
to
the
open
market.
As
an
alternative,
Ingersoll­
Rand
urged
that
the
percent
of
production
allowance
flexibility
be
expanded
to
150
percent
for
the
power
categories
between
75
and
750
horsepower
and
120
percent
for
the
power
category
between
25
and
75
horsepower.
Ingersoll­
Rand
believes
these
levels
correspond
proportionately
to
the
increased
challenges
facing
equipment
manufacturers
during
Tier
4
as
opposed
to
Tier
2
and
Tier
3.
63
"
Tier
4
Nonroad
Diesel
Equipment
Flexibility
Provisions,"
memorandum
from
Byron
Bunker,

et.
al.,
(
EPA)
to
EPA
Air
Docket
OAR­
2003­
0012.

107
As
discussed
in
greater
detail
in
the
Summary
and
Analysis
of
Comments,
as
well
as
in
later
parts
of
this
section
of
this
preamble
and
elsewhere
in
the
administrative
record,
we
disagree
with
most
of
Ingersoll­
Rand's
suggestions.
Our
fundamental
disagreement
is
with
Ingersoll­
Rand's
premise
that
Tier
4
will
create
a
situation
where
need
for
expanded
equipment
maker
lead
time
is
the
norm
rather
than
the
exception
so
that
the
rule
must
provide
a
drastic,
across­
the­
board
expansion
of
equipment
manufacturer
lead
time.
We
believe
that
the
lead
time
provided
for
equipment
makers
in
this
rule
is
adequate,
and
that
the
equipment
maker
flexibilities
we
are
adopting
provide
a
reasonable
and
targeted
safety
valve
to
deal
with
isolated
problems.
There
is
no
across­
the­
board
problem
necessitating
a
drastic
expansion
of
equipment
manufacturer
lead
time,
or
a
drastic
expansion
of
equipment
manufacturer
flexibilities.
We
base
these
conclusions
largely
on
three
factors:
a)
our
investigation
and
understanding
of
the
engineering
process
by
which
engine
makers
and
equipment
manufacturers
bring
new
products
to
market;
b)
the
specific
engineering
challenges
which
equipment
manufacturers
will
address
in
complying
with
the
Tier
4
rule;
and
c)
past
practice
of
equipment
manufacturers
under
previous
rules
providing
transition
flexibilities
for
nonroad
equipment.

Because
it
is
in
both
parties'
interest
for
new
engines
and
new
equipment
applications
to
reach
the
market
expeditiously,
engine
makers
and
equipment
manufacturers
usually
adopt
concurrent
engineering
programs
whereby
the
new
equipment
design
process
occurs
simultaneous
to
the
new
engine
development
process.
We
believe
that
this
concurrent
process
should
work
well
for
Tier
4
because,
in
many
important
ways,
the
engineering
challenges
facing
equipment
manufacturers
can
be
anticipated
and
dealt
with
early
in
the
design
process.
We
expect
that
relatively
early
in
the
design
process,
engine
manufacturers
will
be
able
to
define
the
size
and
characteristics
of
the
emission
control
technologies
(
e.
g.,
NO
X
adsorbers
and
CDPFs),
based
on
the
same
systems
that
will
be
in
production
for
on­
highway
engines.
The
equipment
manufacturers
will
concurrently
redesign
their
equipment
to
accommodate
these
new
technologies,
including
designing,
mounting
and
supporting
the
catalytic
equipment
similar
to
current
exhaust
muffler
systems.

Moreover,
while
we
expect
the
redesign
challenge
for
Tier
4
equipment
to
be
similar
to
that
for
Tier
2/
3,
we
also
expect
the
redesign
to
be
better
and
more
clearly
defined
well
in
advance
of
the
Tier
4
introduction
dates.
This
is
because
we
do
not
expect
the
catalyst
system
size
or
shape
to
change
significantly
during
the
last
24
months
of
the
engine
design
and
validation
process.
63
We
also
have
studied
the
extent
to
which
equipment
manufacturers
have
used
their
flexibilities
under
the
Tier
2/
3
program.
Although
at
an
early
stage
in
the
Tier
2/
3
process,
initial
indications
are
that
the
flexibility
program
is
being
used
by
many
equipment
manufacturers,
but
in
64
"
Tier
4
Nonroad
Diesel
Equipment
Flexibility
Provisions,"
memorandum
from
Byron
Bunker,

et.
al.,
(
EPA)
to
EPA
Air
Docket
OAR­
2003­
0012.

108
general,
manufacturers
do
not
appear
to
be
using
the
full
level
of
allowances.
64
It
appears
that
the
flexibilities
are
being
used
as
EPA
intended,
providing
manufacturers
with
flexibility
to
deal
with
specific
limited
situations,
rather
than
to
deal
with
an
across­
the­
board
problem.

The
emerging
pattern
is
thus
the
one
on
which
the
flexibility
program
is
predicated:
there
is
not
a
need
for
across­
the­
board
drastic
expansion
of
equipment
manufacturer
lead
time.
Indeed,
such
an
expansion
would
be
inconsistent
with
the
lead
time­
forcing
nature
of
section
213
(
b)
of
the
Act.
This
is
not
to
say
that
there
is
no
need
for
equipment
manufacturer
flexibilities,
or
that
the
Tier
2/
3
flexibility
format
need
not
be
adjusted
to
accommodate
potential
problems
to
be
faced
under
the
Tier
4
regime.
Instances
where
additional
lead
time
could
be
justified
are
where
resource
constraints
prevent
completion
of
certain
applications,
or
where
for
business
reasons
it
makes
sense
for
equipment
manufacturers
to
delay
completion
of
small
volume
families
in
order
to
complete
larger
volume
equipment
applications.
In
addition,
the
Tier
2/
3
experience
illustrates
that
there
can
be
instances
where
emission
control
optimization
which
necessitates
equipment
design
changes
occurs
late
in
the
design
cycle,
resulting
in
a
need
for
additional
equipment
manufacturer
lead
time.
The
equipment
manufacturer
flexibilities
adopted
in
today's
rule
accommodate
these
possibilities.

We
have
specific
objections
to
Ingersoll­
Rand's
preferred
approach
of
a
mandated
made
available
date,
followed
by
18
months
of
additional
lead
time
for
equipment
manufacturers.
Superimposing
a
government
mandate
on
the
engine
maker
­
equipment
manufacturer
business
relationship
insinuates
EPA
into
the
middle
of
contractual/
market
relationships
(
e.
g.,
when
is
an
objectively
reasonable
delivery
date?),
forcing
EPA
to
prejudge
myriad
differing
business
relationships/
engineering
situations.
Moreover,
selection
of
any
single
made
available
date
is
bound
to
be
arbitrary
in
most
situations.
We
also
believe
that
the
18­
month
lead
time
following
a
made
available
date
entails
a
mandated
18­
month
period
(
at
least)
with
no
return
on
investment
to
engine
suppliers
(
i.
e.
the
period
between
when
the
Tier
4
engine
would
be
produced
and
when
it
could
lawfully
be
sold),
which
would
increase
the
engine
cost,
and
discourage
design
changes
(
since
such
changes
would
entail
more
investment
with
delayed
return
on
that
investment).
The
ultimate
result
would
be
a
costlier
rule
and
less
environmental
benefit
due
to
the
delay
in
introducing
Tier
4
engines.
Even
were
EPA
to
put
forth
such
a
regulation,
it
is
not
clear
that
it
could
be
enforced
or
that
it
would
help
the
situation.
It
would
only
be
natural
for
engine
manufacturers
to
continue
to
improve
its
products
even
after
the
predefined
"
made
available
date"
and
equipment
manufacturers
would
want
to
use
this
improved
product
even
if
it
meant
they
had
to
make
last
minute
changes
to
the
equipment
design.
For
EPA
to
preclude
engine
manufacturers
from
changing
their
product
designs
over
the
period
between
the
certification
date
and
the
equipment
manufacturer
date
would
be
both
unusual
and
counterproductive
to
our
goal
of
seeing
the
best
possible
products
available
in
the
market.
Moreover,
EPA
sees
no
need
to
interfere
with
the
concurrent
design
market
mechanism,
which
allows
engine
makers
and
equipment
109
manufacturers
to
negotiate
optimal
solutions.
We
believe
it
is
better
to
leave
to
the
market
participants
the
actual
decision
for
how
and
when
to
conduct
concurrent
engineering
designs.

The
California
Air
Resources
Board
commented
that
EPA
should
eliminate
or
reduce
the
amount
of
flexibilities
provided
for
less
than
25
horsepower
engines,
because
the
Tier
4
engine
standards
are
not
aftertreatment­
based.
The
Engine
Manufacturers
Association
commented
that
we
should
expand
the
amount
of
flexibilities
for
engines
greater
than
750
horsepower,
given
the
difficulty
of
complying
with
the
proposed
standards
for
engines
above
750
horsepower.
With
today's
action,
we
are
applying
the
same
flexibility
for
all
power
categories,
including
engines
below
25
horsepower
and
engines
above
750
horsepower.
While
it
is
true
that
the
Tier
4
standards
for
engines
below
25
horsepower
are
not
aftertreatment­
based,
we
believe
there
will
be
changes
in
engine
design
for
many
of
those
engines
in
response
to
the
Tier
4
standards.
As
engine
designs
change,
there
is
the
potential
for
impacts
on
equipment
design
as
well
(
as
shown
in
implementing
the
Tier
2/
3
rule).
Therefore,
we
believe
providing
equipment
manufacturer
flexibility
for
engines
below
25
horsepower
is
appropriate
and
we
are
adopting
the
same
flexibilities
for
engines
below
25
horsepower
as
for
other
power
categories.
With
regard
to
engines
above
750
horsepower,
we
are
retaining
the
same
flexibilities
for
those
engines
as
for
other
power
categories.
As
described
in
section
II.
A.
4,
the
Tier
4
standards
being
adopted
today
for
engines
above
750
horsepower
have
been
revised
from
the
proposal.
We
believe
that
these
revisions
have
appropriately
accommodated
concerns
for
the
most
difficult
to
design
applications
(
i.
e.,
NO
X
adsorbers
for
engines
in
mobile
applications),
so
that
additional
equipment
flexibilities
are
not
warranted
for
these
engines.

The
Engine
Manufacturers
Association
commented
that
some
equipment
manufacturers
may
be
capable
of
making
an
on­
time
transition
to
the
interim
Tier
4
standards
(
e.
g.
the
2011
standards
applicable
for
175­
750
horsepower
engines)
without
the
use
of
flexibilities.
Such
equipment
manufacturers
would
like
the
ability
to
start
the
seven­
year
period
in
which
they
may
use
flexibilities
in
the
year
the
final
Tier
4
standards
(
the
aftertreatment­
based
standards
for
both
PM
and
NO
X)
take
effect.
Put
another
way,
they
would
not
need
more
lead
time
for
equipment
to
meet
the
interim
standards,
but
could
need
more
lead
time
for
equipment
required
to
meet
the
final
standards.
In
addition,
the
commenter
suggested
a
modified
approach
that
could
lead
to
earlier
emission
reductions
than
under
the
proposed
rule:
requiring
delayed
flexibility
engines
to
meet
the
interim
Tier
4
standards
instead
of
meeting
the
Tier
2/
3
standards
(
as
would
have
been
allowed
under
the
proposal
if
the
flexibilities
started
in
the
first
year
of
the
interim
Tier
4
standards).

EPA
wants
to
encourage
the
implementation
of
the
Tier
4
standards
as
early
as
possible.
Therefore,
we
believe
it
makes
sense
to
provide
incentives
to
equipment
manufacturers
to
use
interim
Tier
4
compliant
engines
in
their
equipment
during
the
transition
to
the
final
Tier
4
standards.
Moreover,
it
is
reasonable
to
expect
that
more
lead
time
will
be
needed
for
the
aftertreatment­
based
standards
than
for
the
interim
standards.
Therefore,
in
response
to
these
comments,
we
are
revising
the
proposed
flexibility
provisions
to
allow
equipment
manufacturers
to
have
the
option
of
starting
the
seven­
year
period
in
which
flexibility
engines
may
be
used
in
110
either
the
first
year
of
the
interim
Tier
4
standards
or
the
first
year
of
the
final
Tier
4
standards.
For
engines
between
25
and
75
horsepower,
the
final
Tier
4
standards
may
begin
in
2012
or
2013
depending
on
whether
the
manufacturer
chooses
to
comply
with
the
interim
2008
Tier
4
standards.
An
equipment
manufacturer
who
does
not
use
flexibilities
in
2008
thus
may
need
flexibilities
as
early
as
2012.
Therefore,
the
seven­
year
period
for
the
final
Tier
4
standards
for
engines
between
25
and
75
horsepower
will
begin
in
2012
instead
of
2013.
Moreover,
it
is
clearly
appropriate
that
these
delayed
flexibility
engines
meet
the
interim
Tier
4
standards,
in
order
not
to
backslide
from
existing
levels
of
performance.

Table
III.
B­
1
shows
the
years
in
which
manufacturers
could
choose
to
start
the
Tier
4
flexibilities
given
the
standards
being
adopted
today.
(
The
seven­
year
period
for
engines
below
25
horsepower
takes
effect
in
2008
as
proposed,
because
there
are
no
interim
standards
for
such
engines.)

Table
III.
B­
1.
 
Flexibility
Periods
for
the
Tier
4
Standards
Power
Category
Model
Year
Flexibility
Period
Options
Standards
to
which
Flexibility
Engines
would
have
to
Certify
25

hp
<
75
(
19

kW
<
56)
2008­
2014
Tier
2
standards
2012­
2018
Model
Year
2008
Tier
4
standards
75

hp
<
175
(
56

kW
<
130)
2012­
2018
Tier
3
standards
2014­
2020
Model
Year
2012
Tier
4
standards
175

hp

750
(
130

kW

560)
2011­
2017
Tier
3
standards
2014­
2020
Model
Year
2011
Tier
4
standards
>
750
hp
(>
560
kW)
2011­
2017
Tier
2
standards
2015­
2021
Model
Year
2011
Tier
4
standards
Under
today's
action,
and
as
proposed,
only
those
nonroad
equipment
manufacturers
that
install
engines
and
have
primary
responsibility
for
designing
and
manufacturing
equipment
will
qualify
for
the
allowances
or
other
relief
provided
under
the
Tier
4
transition
provisions.
As
a
result
of
this
definition,
importers
that
have
little
involvement
in
the
manufacturing
and
assembling
of
the
equipment
will
be
ineligible
to
receive
any
allowances.
The
Engine
Manufacturers
Association
and
one
engine
manufacturer
commented
that
the
proposed
definition
of
equipment
manufacturer
needed
to
be
revised
to
cover
situations
in
which
a
manufacturer
contracts
out
the
design
and
production
of
equipment
to
another
manufacturer.
While
we
understand
there
are
many
different
types
of
relationships
between
equipment
manufacturers,
we
believe
it
is
important
111
to
establish
firm
criteria
for
determining
eligibility
to
use
the
equipment
manufacturer
allowances.
We
are
concerned
that
the
change
to
the
equipment
manufacturer
definition
suggested
by
the
commenters
would
allow
entities
that
have
little
or
no
involvement
in
the
actual
design,
manufacture
and
assembly
of
equipment
(
e.
g.,
companies
that
only
import
equipment)
to
claim
they
contracted
with
an
equipment
manufacturer
to
produce
equipment
for
them
and
therefore
claim
allowances.
This
is
the
exact
situation
we
are
attempting
to
prevent
with
the
changes
to
the
eligibility
requirements
for
the
allowances.
Therefore,
we
are
adopting
the
proposed
requirement
that
only
those
nonroad
equipment
manufacturers
that
install
engines
and
have
primary
responsibility
for
designing,
and
manufacturing
equipment
will
qualify
for
the
allowances
or
other
relief
provided
under
the
Tier
4
transition
provisions.
However,
we
are
revising
the
provisions
regarding
which
engines
an
equipment
manufacturer
may
include
in
its
total
count
of
U.
S.­
directed
equipment
production,
which
in
turn
affects
the
number
of
allowances
an
equipment
manufacturer
may
claim.
Under
today's
action,
an
equipment
manufacturer
may
include
equipment
produced
by
other
manufacturers
under
license
to
them
for
which
they
had
primary
design
responsibility
(
see
section
1039.625(
a)
of
the
regulations).
This
should
cover
the
type
of
situation
described
by
the
commenters
while
preventing
an
import­
only
entity
from
claiming
it
is
an
equipment
manufacturer
and
thereby
gaining
access
to
the
allowances.

a.
Percent­
of­
Production
Allowance
Under
the
percent­
of­
production
allowance
adopted
today,
each
equipment
manufacturer
will
be
allowed
to
install
engines
not
certified
to
the
Tier
4
emission
standards
in
a
limited
percentage
of
machines
produced
for
the
U.
S.
market.
Equipment
manufacturers
will
need
to
provide
written
assurance
to
the
engine
manufacturer
that
such
engines
are
being
procured
for
the
purpose
of
the
transition
provisions
for
equipment
manufacturers.
These
engines
will
instead
have
to
be
certified
to
the
standards
that
would
apply
in
the
absence
of
the
Tier
4
standards
(
see
Table
III.
B­
1
for
the
applicable
standards).
As
proposed,
this
percentage
will
apply
separately
to
each
of
the
Tier
4
power
categories
(
engines
below
25
horsepower,
engines
between
25
and
75
horsepower,
engines
between
75
and
175
horsepower,
engines
between
175
and
750
horsepower,
and
engines
above
750
horsepower)
and
is
expressed
as
a
cumulative
percentage
of
80
percent
over
the
seven
years
beginning
when
the
Tier
4
standards
apply
in
a
category
(
see
Table
III.
B­
1
for
the
applicable
seven­
year
periods).
No
exemptions
will
be
allowed
after
the
seventh
year.
For
example,
an
equipment
manufacturer
could
install
engines
certified
to
the
Tier
3
standards
in
40
percent
of
its
entire
2011
production
of
nonroad
equipment
that
use
engines
rated
between
175
and
750
horsepower,
30
percent
of
its
entire
2012
production
in
this
horsepower
category,
and
10
percent
of
its
entire
2013
production
in
this
horsepower
category.
(
During
the
transitional
period
for
the
Tier
4
standards,
the
fifty
percent
of
engines
that
are
allowed
to
certify
to
the
previous
tier
NO
X
standard
but
meet
the
Tier
4
PM
standard
are
considered
Tier
4­
compliant
engines
for
the
purpose
of
the
equipment
manufacturer
transition
provisions.)
If
the
same
manufacturer
produces
equipment
using
engines
rated
above
750
horsepower,
a
separate
cumulative
percentage
allowance
of
80
percent
will
apply
to
those
machines
during
the
seven
years
beginning
in
2011
or
2015.
This
percent­
of­
production
allowance
is
almost
identical
to
the
percent­
of­
production
allowance
adopted
in
the
October
1998
final
rule
(
63
FR
56967,
October
23,
2003),
the
difference
65
As
explained
at
proposal,
for
emissions
modeling
purposes,
we
have
assumed
that
manufacturers
take
full
advantage
of
the
allowances
under
the
existing
transition
program
for
equipment
manufacturers
(
adopted
in
the
October
1998
rule;
see
63
FR
56967
(
October
23,
2003)
in
establishing
the
baseline
emissions
inventory.
In
modeling
the
impact
of
the
Tier
4
standards,
because
the
standards
will
not
take
effect
for
many
years
and
it
is
not
possible
to
accurately
forecast
use
of
the
transition
program
for
equipment
manufacturers,
so
to
assess
costs
in
a
conservative
manner,
we
have
assumed
that
all
engines
will
meet
the
Tier
4
standards
in
the
timeframe
required
by
the
standards
without
use
of
the
Tier
4
transition
provisions.
As
discussed
in
section
VI.
C,
this
is
consistent
with
our
cost
analysis,
which
assumes
no
use
of
the
transition
program
for
equipment
manufacturers.

112
being,
as
explained
earlier,
that
there
are
fewer
power
categories
(
and
consequent
increased
flexibility
in
spreading
the
flexibility
among
engine
families)
associated
with
the
Tier
4
standards.

The
80
percent
exemption
allowance,
were
it
to
be
used
to
its
maximum
extent
by
all
equipment
manufacturers,
will
bring
about
the
introduction
of
cleaner
engines
several
months
later
than
would
have
occurred
if
the
new
standards
were
to
be
implemented
on
their
effective
dates.
However,
the
equipment
manufacturer
flexibility
program
has
been
integrated
with
the
standardsetting
process
from
the
initial
development
of
this
rule,
and
as
such
we
believe
it
is
a
key
factor
in
assuring
that
there
is
sufficient
lead
time
to
initiate
the
Tier
4
standards
according
to
the
final
implementation
schedule.
65
As
proposed,
machines
that
use
engines
built
before
the
effective
date
of
the
Tier
4
standards
do
not
have
to
be
included
in
an
equipment
manufacturer's
percent
of
production
calculations
under
this
allowance.
Machines
that
use
engines
certified
to
the
previous
tier
of
standards
under
our
Small
Business
provisions
(
as
described
in
section
III.
C
of
this
preamble
)
do
not
have
to
be
included
in
an
equipment
manufacturer's
percent
of
production
calculations
under
this
allowance.
All
engines
certified
to
the
Tier
4
standards,
including
those
engines
that
produce
emissions
at
higher
levels
than
the
standards,
but
for
which
an
engine
manufacturer
uses
ABT
credits
to
demonstrate
compliance,
will
count
as
Tier
4
complying
engines
and
do
not
have
to
be
included
in
an
equipment
manufacturer's
percent
of
production
calculations.
Engines
that
meet
the
Tier
4
PM
standards
but
are
allowed
to
meet
the
Tier
3
NMHC+
NO
X
standards
during
the
phase­
in
period
also
count
as
Tier
4
complying
engines
and
do
not
have
to
be
included
in
an
equipment
manufacturer's
percent
of
production
calculations.

The
choice
of
a
cumulative
percent
allowance
of
80
percent
is
based
on
our
best
estimate
of
the
degree
of
reasonable
lead
time
needed
by
equipment
manufacturers.
We
believe
the
80
percent
allowance
responds
to
the
need
for
flexibility
identified
by
equipment
manufacturers,
while
ensuring
a
significant
level
of
emission
reductions
in
the
early
years
of
the
program.
(
As
noted
in
the
following
section
III.
B.
2.
b,
we
are
adopting
a
technical
hardship
provision
that
allows
an
equipment
manufacturer
to
request
additional
relief
under
the
percent
of
production
allowance
under
certain
conditions
and
with
EPA
approval.)
113
b.
Technical
Hardship
Flexibility
Ingersoll­
Rand
commented
that
the
80%
percent
of
production
allowance
level
is
not
sufficient
for
Tier
4
given
the
stringency
of
the
standard
and
the
difficulty
engine
manufacturers
will
have
complying
with
the
standards.
In
further
discussions
with
Ingersoll­
Rand
on
this
issue,
they
suggested
that
a
percent
of
production
allowance
level
of
150%
for
totally
non­
integrated
equipment
manufacturers
(
i.
e.,
equipment
manufacturers
producing
no
diesel
engines)
was
appropriate
for
Tier
4
power
categories
above
25
horsepower.
A
fully
integrated
manufacturer
would
still
receive
the
80%
level
and
partially­
integrated
companies
would
receive
somewhere
between
80%
and
150%
depending
on
the
share
of
self­
produced
engines
in
each
specific
power
category.
The
basis
for
this
comment
is
their
belief
that
non­
integrated
manufacturers
are
at
a
disadvantage
to
integrated
manufacturers
(
manufacturers
making
both
the
engine
and
equipment)
when
it
comes
to
planning
for
new
Tier
4
engine
designs.

Although
we
do
not
accept
the
premise
that
equipment
manufacturer
lead
time
must
be
drastically
expanded
across­
the­
board
for
the
Tier
4
program,
we
do
agree,
as
explained
earlier,
that
there
may
be
situations
where
additional
lead
time,
in
the
form
of
increased
equipment
manufacturer
transition
flexibilities,
can
be
justified.
Therefore,
we
have
added
an
additional
flexibility
(
which
has
no
direct
analogue
in
the
Tier
2/
3
rule)
to
this
rule
in
order
to
provide
additional
needed
lead
time
in
appropriate,
individualized
circumstances
based
on
a
showing
of
extreme
technical
or
engineering
hardship.
Ingersoll­
Rand
has
agreed,
by
letter
to
EPA,
that
this
provision
satisfies
all
of
its
concerns
regarding
adequacy
of
lead
time
for
meeting
Tier
4
standards.

This
additional
flexibility
would
be
available
for
the
three
Tier
4
power
categories
between
25
and
750
horsepower.
As
noted
earlier,
Ingersoll­
Rand
did
not
believe
additional
flexibility
was
needed
for
engines
below
25
horsepower.
We
agree
because
the
Tier
4
standards
for
engines
below
25
horsepower
are
not
based
on
the
use
of
advanced
aftertreatment.
We
also
are
not
including
this
new
provision
for
engines
above
750
horsepower
because
nearly
all
of
the
equipment
manufacturers
utilizing
engines
above
750
horsepower
make
small
volumes
of
equipment.
The
small­
volume
allowance
(
described
in
the
following
section)
allows
a
manufacturer
to
exempt
a
specific
number
of
engines
over
a
seven­
year
period,
which
in
most
cases
will
be
greater
than
the
increased
percentage
potentially
available
under
this
new
provision.

This
new
provision,
found
in
new
section
1039.625(
m),
is
a
case­
by­
case
exemption
granted
by
EPA
to
an
equipment
manufacturer.
The
equipment
manufacturer
would
have
the
burden
of
demonstrating
existence
of
extreme
technical
or
engineering
hardship
conditions
that
are
outside
its
control.
It
must
also
demonstrate
that
it
has
exercised
reasonable
due
diligence
to
avoid
the
situation.
EPA
would
treat
each
request
for
technical
hardship
separately,
with
no
guarantee
that
it
would
grant
the
exemption.
If
EPA
grants
the
exemption,
the
equipment
manufacturer
could
receive
up
to
an
additional
70
percent
under
the
percent
of
production
allowance
for
each
of
the
three
power
categories
noted
above
(
meaning
that
there
is
a
potential
total
150
percent
under
the
percent
of
production
allowance
available,
the
initial
80
percent
114
available
without
application,
and
an
additional
potential
increment
of
up
to
70
percent
available
on
a
case­
by­
case
basis).

The
exemption
could
only
be
granted
upon
written
application
to
EPA
setting
forth
essentially
why
the
normally
successful
elements
of
engine
maker/
equipment
manufacturer
design
cycle
have
not
provided
adequate
lead
time
for
a
particular
equipment
model.
The
application
would
therefore
have
to
address,
with
documentation:
the
engineering
or
technical
problems
that
have
proved
unsolvable
within
the
lead
time
provided,
the
normal
design
cycle
between
the
engine
maker
and
equipment
manufacturer
and
why
that
cycle
has
not
worked
in
this
instance,
all
information
(
such
as
written
specifications,
performance
data,
prototype
engines)
the
equipment
manufacturer
has
received
from
the
engine
supplier,
and
a
comparison
of
the
design
process
for
the
equipment
model
for
which
the
exemption
is
requested
with
the
design
process
for
other
models
for
which
no
exemption
is
needed.
The
equipment
manufacturer
also
would
have
to
make
and
describe
all
efforts
to
find
other
compliant
engines
for
the
model.
EPA
will
then
evaluate
and
determine
whether
or
not
to
grant
each
such
request,
and
what
additional
increment
under
the
percent
of
production
allowance
(
above
the
80
percent
normally
allowed)
is
justified
(
not
to
exceed
an
additional
70
percent
as
noted
above).
As
part
of
our
evaluation
of
requests
based
on
technical
hardship,
we
may
contact
the
engine
supplier(
s)
listed
by
the
equipment
manufacturer
to
check
on
the
accuracy
of
the
engine­
related
information
supplied
by
the
equipment
manufacturer.
This
extension
of
lead
time
is
premised
on
the
existence
of
extreme
technical
or
engineering
problems,
in
contrast
to
the
economic
hardship
provision
described
in
section
III.
B.
2.
f
below,
where
consideration
of
economic
impact
is
critical.

EPA
would
not
grant
an
application
for
technical
hardship
exemption
unless
the
equipment
manufacturer
demonstrates
that
the
full
80
percent
allowed
under
the
percent
of
production
allowance
is
reasonably
expected
to
be
used
up
in
the
first
two
years
of
the
seven­
year
flexibility
period.
The
reason
is
obvious.
If
that
allowance
would
not
be
fully
utilized,
then
no
further
extension
of
lead
time
can
be
justified.
Furthermore,
any
technical
hardship
allowance
would
have
to
be
used
up
within
two
years
after
the
Tier
4
percent
of
production
allowances
start
for
any
power
category.
This
is
because,
although
we
believe
that
circumstances
of
extreme
technical
or
engineering
hardship
may
arise,
we
cannot
see
that
these
circumstances
could
not
be
solved
within
the
first
two
years
of
the
transition.
Indeed,
Ingersoll­
Rand
itself
clearly
indicated
that
this
is
a
temporary
burden
which
exists
during
initial
model
transition
and
indicated
that
only
18
months
(
rather
than
two
years)
could
be
needed
from
receipt
of
the
certified
engine.

This
flexibility
will
be
available
to
all
equipment
manufacturers,
but
may
only
be
requested
for
equipment
in
which
the
equipment
manufacturer
is
different
than
the
engine
manufacturer.
We
believe
that
integrated
manufacturers
who
produce
both
the
equipment
and
the
engine
used
in
the
piece
of
equipment
could
have
an
advantage
in
the
equipment
redesign
process
(
compared
to
an
equipment
manufacturer,
whether
integrated
or
not,
that
uses
engines
from
a
different
manufacturer)
that
makes
additional
relief
under
the
percent
of
production
allowance
unnecessary.
In
addition,
integrated
equipment
manufacturers
have
other
programs
available
to
them
(
that
nonintegrated
manufacturers
do
not
have)
such
as
the
engine
averaging,
banking
and
trading
66
"
Analysis
of
Small
Volume
Equipment
Manufacturer
Flexibilities,"
memo
from
Phil
Carlson
(
EPA)
to
Docket
A­
2001­
28.

115
program,
which
can
provide
lead
time
flexibility
during
the
transition
years.
Most
basically,
integrated
manufacturers
should
be
able
to
design
concurrently
in
all
circumstances,
so
that
extreme
technical
or
engineering
hardships
should
not
arise.

c.
Small­
Volume
Allowance
The
percent­
of­
production
approach
described
above
may
provide
little
benefit
to
businesses
focused
on
a
small
number
of
equipment
models,
and
hence
there
could
be
situations
where
there
is
insufficient
lead
time
for
such
models.
Therefore,
with
today's
action,
we
are
adopting
a
small­
volume
allowance
that
will
allow
any
equipment
manufacturer
to
exceed
the
percent­
of­
production
allowances
described
above
during
the
same
seven­
year
period,
provided
the
manufacturer
limits
the
number
of
exempted
engines
to
700
total
over
the
seven
years,
and
to
200
in
any
one
year.
The
limit
of
700
exempted
engines
(
and
no
more
than
200
engines
per
year)
applies
separately
to
each
of
the
Tier
4
power
categories
(
engines
below
25
horsepower,
engines
between
25
and
75
horsepower,
engines
between
75
and
175
horsepower,
engines
between
175
and
750
horsepower,
and
engines
above
750
horsepower).
In
addition,
manufacturers
making
use
of
this
provision
must
limit
exempted
engines
to
a
single
engine
family
in
each
Tier
4
power
category.

We
are
also
adopting
an
alternative
small­
volume
allowance,
which
equipment
manufacturers
have
the
option
of
utilizing.
In
discussions
regarding
the
current
small­
volume
allowance,
some
manufacturers
expressed
the
desire
to
be
able
to
exempt
engines
from
more
than
one
engine
family,
but
still
fall
under
the
number
of
exempted
engine
limit.
For
that
reason,
we
solicited
comment
on
a
small­
volume
allowance
program
that
would
allow
manufacturers
to
exempt
engines
in
more
than
one
family,
but
have
lower
numerical
limits.
Under
this
alternative,
manufacturers
using
the
small­
volume
allowance
could
exempt
525
machines
over
seven
years
(
with
a
maximum
of
150
in
any
given
year)
for
each
of
the
three
power
categories
below
175
horsepower,
and
350
machines
over
seven
years
(
with
a
maximum
of
100
in
any
given
year)
for
the
two
power
categories
above
175
horsepower.
Concurrent
with
the
revised
caps
of
525
or
350,
depending
on
power
category,
manufacturers
could
exempt
engines
from
more
than
one
engine
family
under
the
small­
volume
allowance
program.
Based
on
sales
information
for
small
businesses,
we
estimated
that
the
alternative
small­
volume
allowance
program
to
include
lower
numbers
of
eligible
engines
and
allow
manufacturers
to
exempt
more
than
one
engine
family
would
keep
the
total
number
of
engines
eligible
for
the
allowance
at
roughly
the
same
overall
level
as
the
700­
unit
program.
66
We
also
requested
comment
on
allowing
equipment
manufacturers
to
choose
between
the
two
small­
volume
allowance
programs
described
above
(
68
FR
28474­
28475,
May
23,
2003).

Both
engine
and
equipment
manufacturers
supported
dropping
the
one
engine
family
restriction
from
the
700
unit
small­
volume
allowance.
In
addition,
they
commented
that
if
the
one
67
Memorandum,
Phil
Carlson
to
Docket
A­
2001­
28,
"
Analysis
of
Equipment
Manufacturer
Flexibilities,"
April
15,
2003.
Docket
A­
2001­
28,
document
no.
II­
B­
24.

116
engine
family
restriction
was
not
dropped
from
the
700
unit
option,
they
supported
the
option
of
allowing
equipment
manufacturers
to
choose
between
the
two
small­
volume
allowance
options.
With
today's
action,
we
are
revising
the
proposed
small­
volume
allowance
to
allow
equipment
manufacturers
to
choose
between
the
700
unit
over
seven
years
option,
with
exempted
engines
limited
to
one
engine
family,
or
the
proposed
alternative
which
would
allow
equipment
manufacturers
to
exempt
fewer
engines
over
seven
years
(
525
or
350
units,
depending
on
the
power
category),
but
with
no
restriction
on
the
number
of
engine
families
that
could
be
included
in
the
exempted
engine
count.
Based
on
our
analysis
of
small
businesses
noted
above,
we
expect
the
number
of
engines
that
could
be
exempted
under
either
option
is
roughly
the
same.
Giving
equipment
manufacturers
the
ability
to
choose
between
the
two
options
should
not
significantly
impact
the
number
of
engines
likely
to
be
exempted
under
the
small­
volume
allowance.
We
have
not
chosen
to
drop
the
one
engine
family
restriction
from
the
700­
unit
small­
volume
allowance
because
it
would
result
in
a
significant
increase
in
the
number
of
engines
eligible
to
be
exempted
to
levels
which
we
believe
are
not
needed
to
provide
adequate
lead
time
for
the
Tier
4
program.
67
As
with
the
percent­
of­
production
allowance,
machines
that
use
engines
built
before
the
effective
date
of
the
Tier
4
standards
do
not
have
to
be
included
in
an
equipment
manufacturer's
count
of
engines
under
the
small­
volume
allowance.
Similarly,
machines
that
use
engines
certified
to
the
previous
tier
of
standards
under
our
Small
Business
provisions
(
as
described
in
section
III.
C
of
today's
action)
do
not
have
to
be
included
in
an
equipment
manufacturer's
count
of
engines
under
the
small­
volume
allowance.
All
engines
certified
to
the
Tier
4
standards,
including
those
that
produce
emissions
at
higher
levels
than
the
standards
but
for
which
an
engine
manufacturer
uses
ABT
credits
to
demonstrate
compliance,
will
be
considered
to
be
Tier
4
complying
engines
and
do
not
have
to
be
included
in
an
equipment
manufacturer's
count
of
engines
under
the
smallvolume
allowance.
Engines
that
meet
the
Tier
4
PM
standards
but
are
allowed
to
meet
the
Tier
3
NMHC+
NO
X
standards
during
the
phase­
in
period
(
i.
e.,
phase­
out
engines)
will
also
be
considered
as
Tier
4
complying
engines
and
do
not
have
to
be
included
in
an
equipment
manufacturer's
count
of
engines
under
the
small­
volume
allowance.
All
engines
used
under
the
small­
volume
allowance
must
certify
to
the
standards
that
would
be
in
effect
in
the
absence
of
the
Tier
4
standards
(
see
Table
III.
B­
1
for
the
applicable
standards).
As
noted
earlier,
equipment
manufacturers
will
need
to
provide
written
assurance
to
the
engine
manufacturer
when
it
purchases
engines
under
the
transition
provisions
for
equipment
manufacturers.

The
Engine
Manufacturers
Association
commented
that
the
proposed
regulations
for
the
small­
volume
allowance
established
a
limit
on
the
total
number
of
engines
an
equipment
manufacturer
could
use
that
did
not
meet
the
Tier
4
standards
and
should
be
revised
to
set
a
limit
based
on
U.
S.­
directed
production
(
consistent
with
the
proposed
regulatory
language
for
the
percent­
of­
production
allowance).
EPA
agrees
that
the
limit
under
the
small­
volume
allowance
should
apply
to
U.
S.­
directed
production
only
­
as
the
commenter
surmised,
this
is
what
EPA
intended
­
and
has
revised
the
final
regulations
for
the
small­
volume
allowance
accordingly.
117
We
are
also
finalizing
a
technical
hardship
provision
for
small
business
equipment
manufacturers
using
25­
50
horsepower
engines,
as
discussed
in
III.
C.
2.
b.
ii
d.
Early
Use
of
Tier
4
Flexibilities
in
the
Tier
2/
3
Timeframe
As
proposed,
we
are
also
adopting
provisions
that
allow
equipment
manufacturers
to
start
using
a
limited
number
of
the
new
Tier
4
percent
of
production
allowances
or
Tier
4
small
volume
allowances
once
the
seven­
year
period
for
the
existing
Tier
2/
Tier
3
program
expires
(
and
so
continue
using
engines
meeting
Tier
1
or
Tier
2
standards).
In
this
way,
a
manufacturer
can
potentially
continue
exempting
the
most
difficult
applications
once
the
seven­
year
period
of
the
current
Tier
2/
3
flexibility
provisions
is
finished.
(
Under
the
existing
transition
program
for
equipment
manufacturers,
any
unused
Tier2/
3
allowances
expire
after
the
seven­
year
period.)
However,
opting
to
start
using
Tier
4
allowances
once
the
seven­
year
period
from
the
current
Tier
2/
Tier
3
program
expires
will
reduce
the
number
of
exemptions
available
from
the
Tier
4
standards
under
either
the
percent
of
production
allowance
or
the
small
volume
allowance.

With
today's
action,
equipment
manufacturers
may
use
up
to
a
total
of
10
percent
of
their
Tier
4
percent
of
production
allowances
or
up
to
100
of
their
Tier
4
small
volume
allowances
prior
to
the
effective
date
of
the
Tier
4
standards.
(
The
early
use
of
Tier
4
allowances
will
be
allowed
in
each
Tier
4
power
category.)
This
amount
of
equipment
utilizing
the
early
Tier
4
allowances
will
be
subtracted
from
either
the
Tier
4
allowance
of
80
percent
under
the
percent
of
production
allowance
or
the
applicable
limit
under
the
small
volume
allowance
for
the
appropriate
power
category,
resulting
in
fewer
allowances
once
the
Tier
4
standards
take
effect.
For
example,
if
an
equipment
manufacturer
uses
the
maximum
amount
of
early
Tier
4
percent
of
production
allowances
of
10
percent,
then
the
manufacturer
will
have
a
cumulative
total
of
70
percent
remaining
for
that
power
category
when
the
Tier
4
standards
take
effect
(
i.
e.,
80
percent
production
allowance
minus
10
percent).

The
California
Air
Resources
Board
commented
that
we
should
discount
the
early
use
of
Tier
4
flexibilities
to
discourage
abuse
of
the
provisions,
by
requiring
equipment
manufacturers
to
give
up
more
than
one
flexibility
after
Tier
4
begins
for
every
flexibility
used
prior
to
Tier
4.
California
did
not
specifically
recommend
what
the
discount
level
should
be.
We
are
not
adopting
a
discount
for
early
use
of
the
Tier
4
flexibilities.
The
intent
of
allowing
manufacturers
to
use
the
Tier
4
flexibilities
early
was
to
allow
them
to
carry
over
the
few
remaining
equipment
models
that
might
not
have
been
redesigned
at
the
end
of
the
seven­
year
Tier
2/
Tier
3
flexibility
period
until
Tier
4
begins,
and
not
requiring
a
possible
double
redesign
in
a
short
period
of
time.
Because
we
have
placed
a
relatively
low
cap
(
10%
under
the
percent
of
production
allowance
or
100
units
under
the
small
volume
allowance)
on
the
amount
an
equipment
manufacturer
could
use
early
from
Tier
4,
we
do
not
believe
that
manufacturers
will
be
able
to
abuse
the
program
and
therefore
should
not
have
to
discount
the
number
of
Tier
4
flexibilities
used
early.

We
view
this
provision
on
early
use
of
Tier
4
allowances
as
providing
reasonable
lead
time
for
introducing
Tier
4
engines,
since
it
should
result
in
earlier
introduction
of
Tier
4­
compliant
118
engines
(
assuming
that
the
allowances
would
otherwise
be
fully
utilized)
with
resulting
net
environmental
benefit
(
notwithstanding
longer
utilization
of
earlier
Tier
engines,
due
to
the
stringency
of
the
Tier
4
standards)
and
should
do
so
at
net
reduction
in
cost
by
providing
cost
savings
for
the
engines
that
have
used
the
Tier
4
allowances
early.
(
This
is
another
reason
we
see
no
reason
to
discount
the
allowance.)

e.
Early
Tier
4
Engine
Incentive
Program
for
Equipment
Manufacturers
Ingersoll­
Rand
commented
that
non­
integrated
equipment
manufacturers
who
incorporate
Tier
4
compliant
engines
into
their
equipment
prior
to
the
applicable
date
for
the
Tier
4
standards
should
be
able
to
earn
early
compliance
credits.
These
early
compliance
credits
could
allow
use
of
the
previous­
tier
engine
(
above
and
beyond
the
base
percentage
granted
under
the
flexibility
program)
for
up
to
18
months
after
the
certification
date
of
the
engine.
Ingersoll­
Rand
also
commented
that
such
early
compliance
credits
should
be
able
to
be
traded
across
power
categories
with
appropriate
weightings
applied.

We
believe
a
program
that
provides
an
incentive
for
equipment
manufacturers
to
use
early
Tier
4­
compliant
engines
is
worthwhile
from
both
a
technology
development
perspective
and
an
environmental
perspective.
As
we
noted
at
proposal
when
we
proposed
a
similar
incentive
program
for
engine
makers,
early
use
of
Tier
4
compliant
engines
will
help
foster
technology
development
by
getting
the
Tier
4
technologies
out
in
the
market
early
and
provide
real­
world
experience
to
manufacturers
and
users
(
68
FR
28482,
May
23,
2003).
It
will
also
lead
to
additional
emission
reductions
above
and
beyond
those
expected
under
the
existing
Tier
2/
3
standards
in
the
years
prior
to
Tier
4
taking
effect.
Moreover,
equipment
manufacturers
(
and
especially
non­
integrated
equipment
manufacturers)
are
unlikely
to
buy
early
Tier
4
engines
without
some
incentive
to
do
so
since
these
engines
are
likely
to
be
more
expensive
than
Tier
2/
3
engines.
For
these
reasons,
we
are
adopting
new
provisions
that
will
allow
any
equipment
manufacturer
to
earn
early
compliance
credits
that
could
be
used
to
increase
the
number
of
equipment
flexibilities
above
and
beyond
the
levels
allowed
under
the
percent
of
production
allowance
or
small­
volume
allowance
(
and
for
reasons
independent
of
those
allowances:
namely,
an
inducement
to
make
early
use
of
Tier
4
engines).

The
program
will
be
available
to
all
equipment
manufacturers
regardless
of
whether
they
are
integrated
or
non­
integrated.
While
Ingersoll­
Rand
commented
that
the
program
should
be
available
to
non­
integrated
equipment
manufacturers
only,
we
believe
the
program
should
provide
an
incentive
for
all
equipment
manufacturers
to
use
early
Tier
4
engines
(
since
the
benefits
accruing
from
early
use
of
such
engines
exist
regardless
of
whether
the
equipment
manufacturer
is
integrated
with
the
engine
maker).

Before
describing
this
provision
further,
it
is
desirable
to
put
it
in
context
by
explaining
its
relationship
to
the
engine
manufacturer
incentive
program
for
early
Tier
4
or
very
low
emission
engines
(
described
in
section
III.
M
below),
as
well
as
to
the
similar
incentive
provisions
for
engine
manufacturers
which
we
proposed
(
68
FR
28482,
May
23,
2003).
We
are,
in
essence,
redirecting
119
the
proposed
incentive
for
using
early
Tier
4
compliant
engines
to
equipment
manufacturers.
Thus,
under
today's
rule,
an
engine
manufacturer
could
use
the
incentive
program
(
as
described
in
section
III.
M)
only
if
an
equipment
manufacturer
uses
an
early
Tier
4
engine
but
(
for
whatever
reason)
declines
to
use
the
early
engine
flexibility
allowance.
In
such
a
case,
the
engine
manufacturer
could
opt
to
earn
either
"
engine
offsets"
(
which
would
allow
them
to
make
fewer
engines
certified
to
the
Tier
4
standards
once
the
Tier
4
program
takes
effect)
or
ABT
credits,
but
not
both.
In
the
more
likely
case
of
an
equipment
manufacturer
using
early
Tier
4
engines
and
using
the
incentive
flexibilities
itself,
the
engine
manufacturer
would
be
eligible
to
generate
ABT
credits
from
such
early
Tier
4
compliant
engines.

The
early
Tier
4
engine
incentive
program
for
equipment
manufacturers
will
apply
to
the
four
power
categories
above
25
horsepower
where
the
use
of
advanced
exhaust
aftertreatment
is
expected
under
the
Tier
4
standards.
Because
the
Tier
4
standards
for
engines
below
25
horsepower
are
not
expected
to
result
in
the
use
of
advanced
aftertreatment
technologies,
we
are
not
including
such
engines
in
the
program.

In
order
for
an
engine
to
be
considered
an
early
Tier
4
compliant
engine,
it
will
need
to
be
certified
to
the
final
Tier
4
standards
for
PM,
NO
X,
and
NMHC
(
i.
e.,
the
2013
standards
for
engines
between
25
and
75
horsepower,
the
2014
standards
for
engines
between
75
and
175
horsepower,
the
2014
standards
for
engines
between
175
and
750
horsepower,
and
the
2015
standards
for
engines
above
750
horsepower)
or
to
the
final
PM
and
NMHC
standards
and
the
alternative
NO
X
standards
during
the
phase­
in
(
as
described
in
section
II.
A.
2.
c
of
today's
rule
for
engines
between
75
and
750
horsepower).
In
order
to
be
an
early
Tier
4
compliant
engine,
these
engines
would
also
have
to
certify
to
the
Tier
4
CO
standards.
Because
15
ppm
sulfur
diesel
fuel
will
be
available
on
a
widespread
basis
in
time
for
2007
(
due
to
the
requirements
for
on­
highway
heavy­
duty
engines),
we
are
allowing
engine
manufacturers
to
begin
certifying
engines
to
the
Tier
4
standards,
and
therefore
have
engines
eligible
for
the
early
Tier
4
engine
incentive
program,
beginning
with
the
2007
model
year.

In
order
to
provide
assurance
that
early
Tier
4
compliant
engines
are
placed
into
equipment
earlier
than
would
otherwise
happen
under
the
Tier
4
program,
engine
manufacturers
will
be
required
to
certify
and
start
producing
such
engines
before
September
1
of
the
year
prior
to
the
post­
2011
Tier
4
standards
taking
effect
or
before
September
1,
2010
for
engines
in
the
175
to
750
horsepower
category.
Similarly,
equipment
manufacturers
will
be
required
to
install
such
engines
in
equipment
before
January
1
of
the
year
the
post­
2011
Tier
4
standards
take
effect
or
before
January
1,
2011
for
engines
in
the
175
to
750
horsepower
category.
In
addition,
in
order
to
be
considered
an
early
Tier
4
compliant
engine,
such
engines
would
be
required
to
comply
with
all
of
the
requirements
associated
with
the
final
Tier
4
standards
such
as
NTE
requirements,
transient
testing
(
where
otherwise
required
for
certification,
i.
e.
for
25­
750
horsepower
engines),
and
closed
crankcase
requirements.
Finally,
for
engines
certified
prior
to
model
year
2011,
the
engine
manufacturer
would
be
allowed
to
demonstrate
early
compliance
with
the
Tier
4
standards
on
a
15
ppm
sulfur
fuel
(
as
allowed
under
the
certification
fuel
requirements
specified
in
section
III.
D
of
today's
rule)
provided
the
engine
manufacturer
120
demonstrates
that
the
equipment
in
which
the
engines
are
placed
will
use
fuel
meeting
this
low
sulfur
specification
and
includes
appropriate
information
on
the
engine
label
and
ensures
that
ultimate
purchasers
of
equipment
using
these
engines
are
informed
that
ultra
low­
sulfur
diesel
fuel
is
recommended
(
see
section
1039.104(
e)
of
the
regulations).
Equipment
manufacturers
using
such
pre­
2011
engines
in
their
equipment
would
likewise
need
to
take
steps
to
ensure
that
fuel
meeting
this
low
sulfur
specification
is
used
in
the
equipment
once
operated
in
use
to
earn
the
additional
flexibility
allowances.

Equipment
manufacturers
installing
engines
complying
with
the
final
Tier
4
standards
(
as
described
above)
would
earn
one
flexibility
allowance
for
each
early
Tier
4
compliant
engine
used
in
its
equipment.
Equipment
manufacturers
installing
engines
between
75
and
750
horsepower
that
comply
with
the
final
Tier
4
PM
standard
and
the
alternative
NO
X
standard
(
described
in
section
II.
A.
2.
c)
would
earn
one­
half
of
a
flexibility
allowance
for
each
early
Tier
4
compliant
engine
used
in
its
equipment.
Table
III.
B­
2
presents
the
requirements
an
engine
would
need
to
meet
to
be
considered
an
early
Tier
4
engine
for
the
purposes
of
this
early
Tier
4
engine
incentive
program.
121
Table
III.
B­
2.
 
Requirements
for
Engines
Under
the
Early
Tier
4
Engine
Incentive
Program
Power
Category
Tier
4
Standards
the
Engines
Must
Meet
Date
before
which
Engines
must
Be
Installed
by
the
Equipment
Manufacturer
Number
of
Flexibility
Allowances
Earned
for
Use
of
Early
Tier
4
Engines
25

hp
<
75
(
19

kW
<
56)
Model
Year
2013
January
1,
2013a
1­
to­
1
75

hp
<
175
(
56

kW
<
130)
Model
Year
2014
January
1,
2012
1­
to­
1
Model
Year
2012b
January
1,
2012
0.5­
to­
1
175

hp

750
(
130

kW

560)
Model
Year
2014
January
1,
2011
1­
to­
1
Model
Year
2011b
January
1,
2011
0.5­
to­
1
Generator
Sets
>
750
hp
(>
560
kW)
Model
Year
2015
January
1,
2015
1­
to­
1
Other
Machines
>
750
hp
(>
560
kW)
Model
Year
2015
January
1,
2015
1­
to­
1
Notes:
a
The
installation
date
for
50
to
75
horsepower
engines
purchased
from
manufacturers
choosing
to
opt
out
of
the
2008
model
year
Tier
4
standards
and
instead
comply
with
the
Tier
4
standards
beginning
in
2012
would
be
January
1,
2012.
b
To
be
eligible,
engines
must
meet
the
0.01g/
bhp­
hr
PM
standard
and
the
alternative
NOX
standards
in
section
1039.102
(
e)
described
in
section
II.
A.
2.
c.

As
described
above,
equipment
manufacturers
using
early
Tier
4
compliant
engines
can
earn
flexibility
allowances
that
can
be
used
to
effectively
increase
the
number
of
allowances
provided
under
the
percent
of
production
allowance
or
the
small
volume
allowance
in
the
same
power
category.
For
example,
an
equipment
manufacturer
that
uses
500
engines
in
the
175
to
750
horsepower
category
that
met
the
model
year
2011
PM
standards
and
alternative
NO
X
standards
would
earn
250
additional
flexibility
allowances
in
that
power
category.
That
manufacturer
could
then
exclude
250
engines
from
its
calculations
before
demonstrating
compliance
with
the
80
percent
limit
under
the
percent
of
production
allowance
(
or
the
applicable
limit
under
the
small
volume
allowance
if
the
equipment
manufacturer
is
using
that
option)
once
Tier
4
starts
in
that
power
category.
122
Equipment
manufacturers
would
be
required
to
report
certain
information
regarding
the
early
Tier
4
compliant
engines
(
such
as
engine
family
name,
number
of
engines
used
prior
to
Tier
4
in
each
power
category,
the
rated
power
of
the
engines,
and
the
type
of
application
the
engines
above
750
horsepower
were
used
in)
when
they
submit
their
first
report
under
the
Tier
4
flexibility
program.
For
engines
above
750
horsepower,
equipment
manufacturers
also
would
be
required
to
keep
records
of
how
many
early
Tier
4
compliant
engines
are
used
in
generator
sets,
versus
how
many
are
used
in
other
machinery.
This
is
because
the
additional
flexibility
allowances
earned
from
the
use
of
early
Tier
4
compliant
engines
used
in
generator
sets
could
only
be
used
for
additional
flexibility
allowances
for
generator
sets.
Likewise,
the
additional
flexibility
allowances
earned
from
the
use
of
early
Tier
4
compliant
engines
used
in
mobile
machinery
(
labeled
`
other
machinery'
in
the
table
above)
applications
could
only
be
used
for
additional
flexibility
allowances
for
other
non­
generator
set
applications.

Under
the
early
Tier
4
engine
incentive
program,
we
will
allow
equipment
manufacturers
to
"
trade"
the
additional
flexibilities
earned
in
the
two
power
categories
between
75
and
750
horsepower,
with
the
power
rating
of
the
engines
factored
into
the
"
trade"
to
ensure
equivalent
emissions
for
the
engines
generating
the
early
allowances
and
the
engines
using
the
allowances.
For
example,
an
equipment
manufacturer
that
earned
100
additional
flexibility
allowances
under
the
early
Tier
4
engine
incentive
program
from
100
horsepower
engines,
could
"
trade"
those
flexibilities
into
the
next
power
category
up
(
175
to
750
horsepower).
The
equipment
manufacturer
would
generate
10,000
horsepower­
allowances
from
those
early
engines
(
i.
e.,
100
horsepower
times
100
allowances).
The
equipment
manufacturer
could
then
produce,
for
this
example,
an
additional
25
engines
with
a
power
rating
of
400
horsepower
above
and
beyond
the
normal
limit
on
allowances
(
or
any
other
combination
of
engines
such
that
the
sum
of
the
horsepower­
weighted
allowances
adds
up
to
the
10,000
horsepower­
allowances
used
in
this
example).
We
are
not
allowing
trading
for
engines
in
the
25
to
75
horsepower
category
because
the
Tier
4
standards
for
these
engines
are
based
on
the
application
of
only
PM
aftertreatment
technology.
Similarly,
we
are
not
allowing
trading
for
engines
in
the
above
750
horsepower
category
because
the
Tier
4
standards
are
based
on
the
application
of
PM
aftertreatment
to
all
engines,
but
NO
X
aftertreatment
for
only
some
engines.

f.
Economic
Hardship
Relief
Provision
With
today's
action,
and
as
proposed,
we
are
providing
an
additional
Tier
4
transition
flexibility
for
"
economic
hardship
relief"
for
equipment
manufacturers.
Under
the
economic
hardship
relief
provisions,
an
equipment
manufacturer
that
does
not
make
its
own
engines
could
obtain
limited
additional
relief
by
providing
evidence
that,
despite
its
best
efforts,
it
cannot
meet
the
implementation
dates,
even
with
the
Tier
4
equipment
flexibility
program
provisions
outlined
above.
Such
a
situation
could
occur
if
an
engine
supplier
without
a
major
business
interest
in
the
equipment
manufacturer
were
to
change
or
drop
an
engine
model
very
late
in
the
implementation
process.
The
purpose
of
the
provision
is
to
redress
individual
situations
of
extreme
economic
hardship,
not
merely
to
perpetuate
existing
market
share.
That
is,
if
situations
arise
where
one
equipment
maker
cannot
produce
equipment
using
Tier
4­
compliant
engines
by
the
compliance
123
date,
but
another
can,
ordinarily
EPA
would
not
adjust
the
program
to
allow
use
of
the
noncompliant
application
absent
extreme,
compelling
equitability
considerations.

Applications
for
economic
hardship
relief
will
have
to
be
made
in
writing,
and
will
need
to
be
submitted
before
the
earliest
date
of
noncompliance.
The
application
will
also
have
to
include
evidence
that
failure
to
comply
is
not
the
fault
of
the
equipment
manufacturer
(
such
as
a
supply
contract
broken
by
the
engine
supplier),
and
include
evidence
that
serious
economic
hardship
to
the
company
will
result
if
relief
is
not
granted.
(
As
explained
in
section
III.
B.
2.
b
above,
this
is
a
significant
difference
between
this
economic
hardship
provision
and
the
technical
hardship
flexibility,
where
consideration
of
cost
is
generally
irrelevant.)
We
expect
to
work
with
the
applicant
to
ensure
that
all
other
remedies
available
under
the
flexibility
provisions
are
exhausted
before
granting
additional
relief
(
if
appropriate),
and
place
a
limit
on
the
period
of
relief
to
no
more
than
one
year.
Applications
for
economic
hardship
relief
generally
will
only
be
accepted
during
the
first
year
after
the
effective
date
of
an
applicable
new
emission
standard.

The
Agency
expects
this
provision
will
be
rarely
used.
This
expectation
has
been
supported
by
our
initial
experience
with
the
Tier
2
standards
in
which
only
one
equipment
manufacturer
has
applied
under
the
existing
hardship
relief
provisions
(
and
the
request
was
subsequently
denied).
Requests
for
economic
hardship
relief
will
be
evaluated
by
EPA
on
a
caseby
case
basis,
and
may
require,
as
a
condition
of
granting
the
applications,
that
the
equipment
manufacturer
agree
(
in
writing)
to
some
appropriate
measure
to
recover
the
lost
environmental
benefit.

Ingersoll­
Rand
commented
that
the
provisions
regarding
eligibility
for
hardship
relief
should
be
revised
so
that
they
do
not
require
a
demonstration
of
severe
economic
hardship,
noting
that
such
a
showing
would
invariably
preclude
large
entities
(
like
Ingersoll­
Rand)
from
utilizing
the
provision,
even
though
delays
were
beyond
their
control.
As
described
earlier
in
this
section,
we
have
included
an
additional
flexibility
in
the
Tier
4
rule
in
order
to
provide
additional
needed
lead
time
in
appropriate,
individualized
circumstances
based
on
a
showing
of
extreme
technical
or
engineering
hardship.
We
believe
the
provisions
of
the
technical
hardship
address
the
concerns
noted
by
Ingersoll­
Rand
in
their
comments,
and
therefore
we
are
not
revising
the
existing
economic
hardship
relief
provisions
(
which
require
a
demonstration
of
severe
economic
impact)
for
the
Tier
4
final
program.

g.
Existing
Inventory
Allowance
The
current
program
for
nonroad
diesel
engines
includes
a
provision
for
equipment
manufacturers
to
continue
to
use
engines
built
prior
to
the
effective
date
of
new
standards,
until
the
older
engine
inventories
are
depleted.
It
also
prohibits
stockpiling
of
previous
tier
engines.
As
proposed,
we
are
extending
these
provisions
for
the
transition
to
the
Tier
4
standards
adopted
today.
We
are
also
extending
the
existing
provision
that
provides
an
exception
to
the
applicable
compliance
regulations
for
the
sale
of
replacement
engines.
In
extending
this
provision,
we
are
requiring
that
engines
built
to
replace
certified
engines
be
identical
in
all
material
respects
to
an
124
engine
of
a
previously
certified
configuration
that
is
of
the
same
or
later
model
year
as
the
engine
being
replaced.
The
term
"
identical
in
all
material
respects"
allows
for
minor
differences
that
would
not
reasonably
be
expected
to
affect
emissions
such
as
a
change
in
materials
or
a
change
in
the
company
supplying
the
components
of
the
engine.

3.
What
are
the
recordkeeping,
notification,
reporting,
and
labeling
requirements
associated
with
the
equipment
manufacturer
transition
provisions?

The
following
section
describes
the
recordkeeping,
notification,
reporting,
and
labeling
requirement
being
adopted
today.
As
proposed,
failure
to
comply
with
these
requirements
will
subject
the
noncomplying
party
to
penalties
as
described
in
40
CFR
1068.101.

a.
Recordkeeping
Requirements
for
Engine
and
Equipment
Manufacturers
With
today's
action,
we
are
extending
the
recordkeeping
requirements
from
the
current
equipment
manufacturer
transition
program.
Under
the
Tier
4
transition
program,
engine
manufacturers
will
be
allowed
to
continue
to
build
and
sell
previous
tier
engines
needed
to
meet
the
market
demand
created
by
the
equipment
manufacturer
flexibility
program,
provided
they
receive
written
assurance
from
the
engine
purchasers
that
such
engines
are
being
procured
for
this
purpose.
Engine
manufacturers
will
be
required
to
keep
copies
of
the
written
assurance
from
the
engine
purchasers
for
at
least
five
full
years
after
the
final
year
in
which
allowances
are
available
for
each
power
category.

Equipment
manufacturers
choosing
to
take
advantage
of
the
Tier
4
allowances
will
be
required
to:
(
1)
keep
records
of
the
production
of
all
pieces
of
equipment
excepted
under
the
allowance
provisions
for
at
least
five
full
years
after
the
final
year
in
which
allowances
are
available
for
each
power
category;
(
2)
include
in
such
records
the
serial
and
model
numbers
and
dates
of
production
of
equipment
and
installed
engines,
and
the
rated
power
of
each
engine,
(
3)
calculate
annually
the
number
and
percentage
of
equipment
made
under
these
transition
provisions
to
verify
compliance
that
the
allowances
have
not
been
exceeded
in
each
power
category;
and
(
4)
make
these
records
available
to
EPA
upon
request.

b.
Notification
Requirements
for
Equipment
Manufacturers
We
are
adopting
new
notification
requirements
for
equipment
manufacturers
with
the
Tier
4
program.
Under
the
Tier
4
transition
program,
equipment
manufacturers
wishing
to
participate
in
the
Tier
4
transition
provisions
will
be
required
to
notify
EPA
prior
to
their
use
of
the
Tier
4
transition
provisions.
Equipment
manufacturers
will
be
required
to
submit
their
notification
before
the
first
calendar
year
in
which
they
intend
to
use
the
transition
provisions.
We
believe
that
prior
notification
will
greatly
enhance
our
ability
to
ensure
compliance.
Under
the
newly
adopted
notification
requirements,
each
equipment
manufacturer
will
be
required
to
notify
EPA
in
writing
and
provide
the
following
information
prior
to
the
start
of
the
first
year
in
which
the
manufacturer
intends
to
use
the
flexibilities:
125
(
1)
the
nonroad
equipment
manufacturer's
name,
address,
and
contact
person's
name,
phone
number;
(
2)
the
allowance
program
that
the
nonroad
equipment
manufacturer
intends
to
use
by
power
category;
(
3)
the
calendar
years
in
which
the
nonroad
equipment
manufacturer
intends
to
use
the
exception;
(
4)
an
estimation
of
the
number
of
engines
to
be
exempted
under
the
transition
provisions
by
power
category;
(
5)
the
name
and
address
of
the
engine
manufacturer
from
whom
the
equipment
manufacturer
intends
to
obtain
exempted
engines;
and
(
6)
identification
of
the
equipment
manufacturer's
prior
use
of
Tier
2/
3
transition
provisions.

Engine
manufacturers
supported
the
new
notification
requirements
for
equipment
manufacturers.
One
equipment
company,
however,
commented
that
the
notification
requirements
are
of
minimal
value
and
should
be
deleted.
We
disagree
and
continue
to
believe
the
new
notification
requirements
will
greatly
enhance
our
ability
to
ensure
compliance
with
the
flexibility
provisions.
Given
the
limited
information
that
must
be
provided
by
equipment
manufacturers,
we
do
not
expect
that
the
notifications
will
require
any
significant
effort
to
pull
the
information
together
and
submit
to
EPA.

EPA
had
requested
comment
on
whether
the
notification
provisions
should
also
apply
to
the
current
Tier
2/
Tier
3
transition
program,
and
if
so,
how
these
provisions
should
be
phased
in
for
equipment
manufacturers
using
the
current
Tier
2/
Tier
3
transition
provisions.
We
did
not
receive
any
comments
on
this
issue.
However,
consistent
with
our
approach
to
several
other
Tier
4
requirements
that
we
were
considering
applying
to
the
Tier
2/
Tier
3
transition
program,
we
are
not
adopting
such
notification
requirements
for
equipment
manufacturers
for
the
current
Tier
2/
Tier
3
program.

c.
Reporting
Requirements
for
Engine
and
Equipment
Manufacturers
As
with
the
current
program,
engine
manufacturers
who
participate
in
the
Tier
4
program
will
be
required
to
submit
information
each
year
on
the
number
of
such
engines
produced
and
to
whom
the
engines
are
provided.
The
purpose
of
these
submittals
is
to
help
EPA
monitor
compliance
with
the
program
and
prevent
abuse
of
the
program.

We
are
adopting
new
reporting
requirement
for
equipment
manufacturers
participating
in
the
Tier
4
equipment
manufacturer
transition
provisions.
With
today's
action,
equipment
manufacturers
participating
in
the
program
will
be
required
to
submit
an
annual
written
report
to
EPA
that
calculates
its
annual
number
of
exempted
engines
under
the
transition
provisions
by
power
category
in
the
previous
year.
Equipment
manufacturers
using
the
percent
of
production
allowance,
will
also
have
to
calculate
the
percent
of
production
the
exempted
engines
represented
for
the
appropriate
year.
Each
report
will
include
a
cumulative
calculation
(
both
total
number
126
and,
if
appropriate,
the
percent
of
production)
for
all
years
the
equipment
manufacturer
is
using
the
transition
provisions
for
each
of
the
Tier
4
power
categories.
In
order
to
ease
the
reporting
burden
on
equipment
manufacturers,
EPA
intends
to
work
with
the
manufacturers
to
develop
an
electronic
means
for
submitting
information
to
EPA.

EPA
had
requested
comment
on
whether
these
new
reporting
requirements
for
equipment
manufacturers
should
also
apply
to
the
current
Tier
2/
Tier
3
transition
program,
and
if
so,
how
these
provisions
should
be
phased
in
for
equipment
manufacturers
using
the
current
Tier
2/
Tier
3
transition
provisions.
We
did
not
receive
any
comments
on
this
issue.
However,
consistent
with
our
approach
to
several
other
Tier
4
requirements
that
we
were
considering
applying
to
the
Tier
2/
Tier
3
transition
program,
we
are
not
adopting
reporting
requirements
for
equipment
manufacturers
for
the
current
Tier
2/
Tier
3
program.

d.
Labeling
Requirements
for
Engine
and
Equipment
Manufacturers
Engine
manufacturers
are
currently
required
to
label
their
certified
engines
with
a
label
that
contains
a
variety
of
information.
Under
today's
action,
as
proposed,
we
are
adopting
requirements
that
engine
manufacturers
be
required
to
identify
on
the
engine
label
if
the
engine
is
exempted
under
the
Tier
4
transition
program.
In
addition,
and
also
as
proposed,
equipment
manufacturers
will
be
required
to
apply
a
label
to
the
engine
or
piece
of
equipment
that
identifies
the
equipment
as
using
an
engine
produced
under
the
Tier
4
transition
program
for
equipment
manufacturers.

Engine
manufacturers
were
opposed
to
the
new
labeling
requirements.
We
believe
these
new
labeling
requirements
will
allow
EPA
to
easily
identify
the
exempted
engines
and
equipment,
verify
which
equipment
manufacturers
are
using
these
exceptions,
and
more
easily
monitor
compliance
with
the
transition
provisions.
Labeling
of
the
equipment
should
also
help
U.
S.
Customs
to
quickly
identify
equipment
being
imported
using
the
exemptions
for
equipment
manufacturers.

4.
What
are
the
requirements
associated
with
use
of
transition
provisions
for
equipment
produced
by
foreign
manufacturers?

Under
the
current
regulations
in
40
CFR
89.2,
importers
are
treated
as
equipment
manufacturers
and
are
each
allowed
the
full
allowance
under
the
transition
provisions
in
40
CFR
89.102(
d).
Therefore,
under
the
current
provisions,
importers
of
equipment
from
a
foreign
equipment
manufacturer
could
as
a
group
import
more
excepted
equipment
from
that
foreign
manufacturer
than
80%
of
that
manufacturer's
production
for
the
U.
S.
market
(
i.
e.,
more
than
the
percent­
of­
production),
or
more
than
the
small­
volume
allowance.
Therefore,
the
current
regulation
creates
a
potentially
significant
adverse
environmental
impact.
EPA
did
not
intend
this
outcome,
and
does
not
believe
it
is
needed
to
provide
reasonable
lead
time
to
foreign
equipment
manufacturers.
EPA
thus
proposed
to
change
the
current
regulations
to
eliminate
this
disparity.
68
See,
for
example,
40
CFR
80.410
concerning
provisions
for
foreign
refiners
with
individual
gasoline
sulfur
baselines.

127
As
noted
earlier,
with
today's
action,
only
those
nonroad
equipment
manufacturers
that
install
engines
and
have
primary
responsibility
for
designing
and
manufacturing
equipment
will
qualify
for
the
allowances
or
other
relief
provided
under
the
Tier
4
transition
provisions.
Foreign
equipment
manufacturers
who
comply
with
the
compliance
related
provisions
discussed
below
will
receive
the
same
allowances
and
other
transition
provisions
as
domestic
manufacturers.
Foreign
equipment
manufacturers
who
do
not
comply
with
these
compliance
related
provisions
will
not
receive
allowances.
Importers
that
have
little
involvement
in
the
manufacturing
and
assembling
of
the
equipment
will
not
receive
any
allowances
or
other
transition
relief
directly,
but
can
import
exempt
equipment
if
it
is
covered
by
an
allowance
or
transition
provision
associated
with
a
foreign
equipment
manufacturer.
These
provisions
allow
the
transition
allowances
and
other
provisions
to
be
used
by
foreign
equipment
manufacturers
in
the
same
way
as
domestic
equipment
manufacturers,
while
avoiding
the
potential
for
importers
using
unnecessary
allowances.

Under
today's
action,
a
foreign
equipment
manufacturer
includes
any
equipment
manufacturer
that
produces
equipment
outside
of
the
United
States
that
is
eventually
sold
in
the
United
States.
All
foreign
nonroad
equipment
manufacturers
wishing
to
use
the
transition
provisions
will
have
to
comply
with
all
requirements
of
the
regulation
discussed
above
including:
notification,
recordkeeping,
reporting
and
labeling.
Along
with
the
equipment
manufacturer's
notification
described
earlier,
a
foreign
nonroad
equipment
manufacturer
will
have
to
comply
with
various
compliance
related
provisions
similar
to
those
adopted
in
several
fuel
regulations
relating
to
foreign
refiners.
68
As
part
of
the
notification,
the
foreign
nonroad
equipment
manufacturer
will
have
to:

1)
Agree
to
provide
EPA
with
full,
complete
and
immediate
access
to
conduct
inspections
and
audits;
2)
Name
an
agent
in
the
District
of
Columbia
for
service
of
process;
3)
Agree
that
any
enforcement
action
related
to
these
provisions
will
be
governed
by
the
Clean
Air
Act;
4)
Submit
to
the
substantive
and
procedural
laws
of
the
United
States;
5)
Agree
to
additional
jurisdictional
provisions;
6)
Agree
that
the
foreign
nonroad
equipment
manufacturer
will
not
seek
to
detain
or
to
impose
civil
or
criminal
remedies
against
EPA
inspectors
or
auditors
for
actions
performed
within
the
scope
of
EPA
employment
related
to
the
provisions
of
this
program;
7)
Agree
that
the
foreign
nonroad
equipment
manufacturer
becomes
subject
to
the
full
operation
of
the
administrative
and
judicial
enforcement
powers
and
provisions
of
the
United
States
without
limitation
based
on
sovereign
immunity;
and
8)
Submit
all
reports
or
other
documents
in
the
English
language,
or
include
an
English
language
translation.
128
In
addition
to
these
requirements,
we
are
adopting
a
new
provision
for
foreign
equipment
manufacturers
that
participate
in
the
transition
program
to
comply
with
a
bond
requirement
for
engines
imported
into
the
U.
S.
We
believe
the
bond
requirements
are
an
important
tool
to
ensure
that
foreign
equipment
manufacturers
are
subject
to
the
same
level
of
enforcement
as
domestic
equipment
manufacturers.
Furthermore,
we
believe
that
a
bonding
requirement
for
the
foreign
equipment
manufacturer
is
an
important
enforcement
tool
in
order
to
ensure
that
EPA
has
the
ability
to
collect
any
judgements
assessed
against
a
foreign
equipment
manufacturer
for
violations
of
these
transition
provisions.

Under
the
bond
program
adopted
today,
a
participating
foreign
equipment
manufacturer
will
have
to
obtain
annually
a
bond
in
the
proper
amount
that
is
payable
to
satisfy
United
States
judicial
judgments
that
results
from
administrative
or
judicial
enforcement
actions
for
conduct
in
violation
of
the
Clean
Air
Act.
The
foreign
equipment
manufacturer
will
have
two
options
for
complying
with
the
bonding
requirement.
The
foreign
equipment
manufacturer
can:

1)
Obtain
a
bond
in
the
proper
amount
from
a
third­
party
surety
agent
that
is
cited
in
the
U.
S.
Department
of
Treasury
Circular
570,
"
Companies
Holding
Certificates
of
Authority
as
Acceptable
Sureties
on
Federal
Bonds
and
as
Acceptable
Reinsuring
Companies";
or
2)
Obtain
an
EPA
waiver
from
the
bonding
requirement,
if
the
foreign
equipment
manufacturer
can
show
that
it
has
assets
of
an
appropriate
value
in
the
United
States.

EPA
expects
the
second
bond
option
to
address
instances
where
an
equipment
manufacturer
produces
equipment
outside
the
United
States
containing
flexibility
engines,
but
also
has
facilities
(
and
thus
significant
assets)
inside
the
United
States.
Under
this
second
option,
such
a
manufacturer
can
apply
to
the
EPA
for
a
waiver
of
the
bonding
requirement.

Because
EPA's
concerns
of
compliance
will
relate
to
the
nature
and
tier
of
engines
used
in
the
transition
equipment,
we
believe
the
bond
value
should
be
related
to
the
value
of
the
engine
used.
Therefore,
we
are
adopting
requirements
that
the
bond
be
set
at
a
level
designed
to
represent
approximately
10%
of
the
cost
of
the
engine
for
each
piece
of
transition
equipment
produced
for
import
into
the
United
States
under
this
program.
So
that
manufacturers
have
certainty
regarding
the
bond
amounts
and
so
that
there
isn't
a
need
for
extensive
data
submittals
and
evaluation
between
EPA
and
the
manufacturer,
the
rule
specifies
the
bond
value
for
each
imported
engine
based
on
the
estimated
average
cost
for
a
Tier
4
engine
on
which
the
bond
would
be
based.
Based
on
average
engine
cost
estimates
from
table
6.2­
5
of
the
final
RIA,
equipment
using
engines
exempted
under
the
transition
program
will
require
a
bond
in
the
amount
shown
in
table
III.
B­
3.
129
Table
III.
B­
3.
 
Bond
Value
For
Engines
Imported
Under
the
Tier
4
Transition
Program
Power
Range
Per
Engine
Bond
Value
0<
hp<
25
$
150
25

hp<
75
$
300
75

hp<
175
$
500
175

hp<
300
$
1,000
300

hp<
600
$
3,000
hp

600
hp
$
8,000
Depending
on
the
number
of
engines/
equipment
brought
into
the
U.
S.
each
year,
the
value
of
the
bond
calculated
using
the
above
values
could
change
from
year
to
year.
Under
the
provisions
adopted
today,
an
importer
would
calculate
the
estimated
bond
amount
using
the
values
in
table
III.
B­
3
and
be
required
to
obtain
a
bond
equal
to
the
highest
bond
value
estimated
over
the
seven­
year
flexibility
period.
Because
we
have
the
authority
to
bring
enforcement
actions
against
a
manufacturer
for
five
years
beyond
the
end
of
the
program,
the
manufacturer
would
be
required
to
maintain
the
bond
for
five
years
beyond
the
end
of
the
flexibility
period
or
five
years
after
using
up
all
of
its
available
allowances,
whichever
occurs
first.
Finally,
if
a
foreign
equipment
manufacturer's
bond
is
used
to
satisfy
a
judgment
within
the
seven­
year
flexibility
period,
the
foreign
equipment
manufacturer
will
then
be
required
to
increase
the
bond
to
cover
the
amount
used
within
90
days
of
the
date
the
bond
is
used.

Most
comments
received
on
this
issue
supported
the
proposed
provisions.
However,
Ingersoll­
Rand
commented
that
EPA
should
clarify
whether
the
special
requirements
for
foreign
equipment
manufacturers
apply
to
U.
S.­
based
companies
that
have
foreign
manufacturing
facilities.
Ingersoll­
Rand
believes
that
such
requirements
should
not
apply
because
EPA
appears
to
be
concerned
about
abuse
of
the
program
by
foreign
companies
that
export
machines
into
the
U.
S.
With
today's
action,
all
equipment
manufacturers
who
import
equipment
into
the
U.
S.
will
be
required
to
comply
with
the
provisions
for
foreign
equipment
manufacturers,
even
if
they
are
U.
S.­
based
companies.
Because
there
is
a
wide
range
of
actual
presence
in
this
country
for
"
U.
S.
 
based"
companies,
EPA
believes
it
is
important
that
all
companies
importing
equipment
to
the
U.
S.
comply
with
the
requirements
for
foreign
equipment
manufacturers.
Neither
the
notification
requirements
described
earlier
for
foreign
equipment
manufacturers
nor
the
bonding
requirements
should
cause
any
burden
for
companies
with
significant
presence
in
this
country.
We
would
expect
that
only
those
companies
with
limited
presence
or
no
presence
in
this
country
will
be
impacted
to
any
measurable
degree
because
of
the
requirements
placed
on
foreign
equipment
manufacturers.
130
In
addition
to
the
foreign
equipment
manufacturer
requirements
discussed
above,
EPA
is
also
requiring
importers
of
exempted
equipment
from
a
complying
foreign
equipment
manufacturer
to
comply
with
certain
provisions.
EPA
believes
these
importer
provisions
are
essential
to
EPA's
ability
to
monitor
compliance
with
the
transition
provisions.
Under
today's
action,
each
importer
will
be
required
to
notify
EPA
prior
to
their
initial
importation
of
equipment
exempted
under
the
Tier
4
transition
provisions.
Importers
will
be
required
to
submit
their
notification
prior
to
the
first
calendar
year
in
which
they
intend
to
import
exempted
equipment
from
a
complying
foreign
equipment
manufacturer
under
the
transition
provisions.
The
importer's
notification
will
need
to
include
the
following
information:

1)
The
name
and
address
of
importer
(
and
any
parent
company);
2)
The
name
and
address
of
the
manufacturers
of
the
exempted
equipment
and
engines
the
importer
expects
to
import;
3)
Number
of
exempted
equipment
the
importer
expects
to
import
for
each
year
broken
down
by
equipment
manufacturer
and
power
category;
and
4)
The
importer's
use
of
the
transition
provisions
in
prior
years
(
number
of
flexibility
engines
imported
in
a
particular
year,
under
what
power
category,
and
the
names
of
the
equipment
and
engine
manufacturers).

In
addition,
EPA
is
requiring
that
any
importer
electing
to
import
to
the
United
States
exempted
equipment
from
a
complying
foreign
equipment
manufacturer
will
have
to
submit
annual
reports
to
EPA.
The
annual
report
will
have
to
include
the
number
of
exempted
equipment
the
importer
actually
imported
to
the
United
States
in
the
previous
calendar
year;
and
the
identification
of
the
equipment
manufacturers
and
engine
manufacturers
whose
exempted
equipment/
engines
were
imported.

C.
Engine
and
Equipment
Small
Business
Provisions
(
SBREFA)

The
Regulatory
Flexibility
Act
(
RFA)
generally
requires
an
agency
to
prepare
a
regulatory
flexibility
analysis
of
any
rule
subject
to
notice
and
comment
rulemaking
requirements
under
the
Administrative
Procedure
Act
or
any
other
statute,
unless
the
agency
certifies
that
the
rule
will
not
have
a
significant
economic
impact
on
a
substantial
number
of
small
entities.
Small
entities
include
small
businesses,
small
organizations,
and
small
governmental
jurisdictions.
As
EPA
believed
that
the
ultimate
rule
could
have
a
significant
economic
impact
on
small
businesses,
we
prepared
a
regulatory
flexibility
analysis
as
part
of
this
rulemaking.
We
prepared
an
Initial
Regulatory
Flexibility
Analysis
(
IRFA)
pursuant
to
section
603
of
the
RFA
which
is
part
of
the
record
for
the
NPRM,
and
we
prepared
a
Final
Regulatory
Flexibility
Analysis
(
FRFA)
to
support
today's
action.

Under
section
609(
b)
of
the
RFA,
a
Small
Business
Advocacy
Review
Panel
(
SBAR
Panel
or
Panel)
is
required
to
be
convened
prior
to
publication
of
both
an
IRFA
and
a
FRFA.
Section
609(
b)
of
the
RFA
directs
the
Panel
to,
through
outreach
with
small
entity
representatives
(
SERs),
report
on
the
comments
of
the
SERs
and
make
findings
under
section
603
of
the
RFA
on
131
issues
related
to
identified
elements
of
an
IRFA
during
the
proposal
stage
of
a
rulemaking.
During
the
development
of
the
rulemaking,
EPA
is
to
analyze
the
elements
of
the
IRFA
in
developing
the
FRFA
for
the
final
rulemaking
(
see
section
X.
C
of
this
preamble
for
more
discussion
on
the
elements
of
a
FRFA).
The
purpose
of
the
Panel
was
to
gather
information
to
identify
impacts
on
small
businesses
and
to
develop
potential
regulatory
options
to
mitigate
these
concerns.
At
the
completion
of
the
SBAR
Panel
process,
the
Panel
prepared
a
Final
Panel
Report.
This
report
includes:
°
background
information
on
the
proposed
rule
being
developed;
°
information
on
the
types
of
small
entities
that
would
be
subject
to
the
proposed
rule;
°
a
description
of
efforts
made
to
obtain
the
advice
and
recommendations
of
representatives
of
those
small
entities;
and,
°
a
summary
of
the
comments
that
had
been
received
to
date
from
those
representatives.
The
Panel
report
was
included
in
the
proposal's
rulemaking
record
(
and
hence
in
the
rulemaking
record
for
this
final
rule),
and
provided
the
Panel
and
the
Agency
with
an
opportunity
to
identify
and
explore
potential
ways
of
shaping
the
rule
to
minimize
the
burden
of
the
rule
on
small
entities
while
achieving
the
rule's
purposes
and
being
consistent
with
Clean
Air
Act
statutory
requirements.

EPA
approached
this
process
with
care
and
diligence.
To
identify
representatives
of
small
businesses
for
this
process,
we
used
the
definitions
provided
by
the
Small
Business
Administration
(
SBA)
for
manufacturers
of
nonroad
diesel
engines
and
vehicles.
The
categories
of
small
entities
in
the
nonroad
diesel
sector
that
will
potentially
be
affected
by
this
rulemaking
are
defined
in
the
following
table:

Industry
Defined
as
small
entity
by
SBA
if:
Major
SIC
Codes
Engine
manufacturers
Less
than
1,000
employees
Major
Group
35
Equipment
manufacturers:

­
construction
equipment
Less
than
750
employees
Major
Group
35
­
industrial
truck
manufacturers
(
i.
e.,
forklifts)
Less
than
750
employees
Major
Group
35
­
all
other
nonroad
equipment
manufacturers
Less
than
500
employees
Major
Group
35
One
small
engine
manufacturer
and
5
small
equipment
manufacturers
agreed
to
serve
as
Small
Entity
Representatives
(
SERs)
throughout
the
SBAR
Panel
process
for
this
proposal.
These
companies
represented
the
nonroad
market
well,
as
the
group
of
SERs
consisted
of
businesses
that
manufacture
various
types
of
nonroad
diesel
equipment.
132
The
following
are
the
provisions
recommended
by
the
SBAR
Panel.
As
described
in
section
III.
B
above,
there
are
other
provisions
that
apply
to
all
equipment
manufacturers;
however,
the
discussion
in
this
section
focuses
mainly
on
small
entities.

1.
Nonroad
Diesel
Small
Engine
Manufacturers
a.
Lead
Time
Transition
Provisions
for
Small
Business
Engine
Manufacturers
i.
Panel
Recommendations
and
Our
Proposal
The
transition
provisions
recommended
by
the
SBAR
Panel
for
engines
produced
or
imported
by
small
entities
are
listed
below.
For
all
of
the
provisions,
the
Panel
recommended
that
small
business
engine
manufacturers
and
small
importers
must
have
certified
engines
in
model
year
2002
or
earlier
in
order
to
take
advantage
of
these
provisions.
Each
manufacturer
would
be
limited
to
2,500
units
per
year
as
this
number
allows
for
some
market
growth.
The
Panel
recommended
these
stipulations
in
order
to
prohibit
the
misuse
of
the
transition
provisions
as
a
tool
to
enter
the
nonroad
diesel
market
or
to
gain
unfair
market
position
relative
to
other
manufacturers.

Currently,
certified
nonroad
diesel
engines
produced
by
small
manufacturers
all
have
a
horsepower
rating
of
80
or
less.
At
proposal,
we
considered
both
a
one­
step
approach,
and
the
two­
step
approach
which
we
are
finalizing
today.
Due
to
the
structure
of
the
standards
and
their
timing,
EPA
proposed
transition
provisions
for
small
business
engine
manufacturers
which
encompassed
both
approaches
recommended
by
the
Panel,
with
the
inclusion
of
the
2,500
unit
limit
(
as
suggested
by
the
Panel)
for
each
manufacturer.
Given
the
two­
step
structure
of
the
final
rule,
we
are
only
providing
those
proposed
provisions
related
to
that
approach
(
a
complete
description
of
the
provisions
proposed
by
the
Panel,
and
also
by
specific
Panel
members,
is
located
in
the
SBAR
Final
Panel
Report).

For
a
two­
step
approach
the
Panel
recommended
that:
°
an
engine
manufacturer
should
be
allowed
to
skip
the
first
phase
and
comply
on
time
with
the
second;
or,
°
a
manufacturer
could
delay
compliance
with
each
phase
of
standards
for
up
to
three
years.

We
proposed
the
following
provisions
in
the
NPRM
(
based
on
available
data,
we
believe
that
there
are
no
small
manufacturers
of
nonroad
diesel
engines
above
the
75­
175
hp
category):
With
regard
to
PM­
°
Engines
under
25
hp
and
those
between
75
and
175
hp
have
only
one
standard
so
the
manufacturer
could
delay
compliance
with
these
standards
for
up
to
three
years.
°
For
engines
between
50
and
75
hp,
we
proposed
to
delay
compliance
for
one
year
if
the
2008
interim
standards
are
met,
with
the
stipulation
that
small
business
133
manufacturers
cannot
use
PM
credits
to
meet
the
interim
standard.
However,
if
a
small
manufacturer
elects
the
optional
approach
to
the
standard
(
elects
to
skip
the
interim
standard),
no
further
relief
will
be
provided.
With
regard
to
NO
X­
°
There
is
no
change
in
the
level
of
the
NO
X
standard
for
engines
under
25
hp
and
those
between
50
and
75
hp,
so
we
did
not
propose
any
special
provisions
for
these
categories.
°
For
engines
in
the
25­
50
hp
and
the
75­
175
hp
categories
we
proposed
a
three
year
delay
in
the
program
consistent
with
the
one­
phase
approach
recommendation
above.

ii.
What
We
are
Finalizing
We
are
finalizing
all
of
the
provisions
set
out
above
for
NO
X.
For
PM,
we
are
finalizing
some
of
the
proposed
provisions
with
certain
revisions,
as
described
below.
In
finalizing
these
provisions,
we
considered
not
only
the
recommendations
of
the
Panel,
but
also
the
public
comments
on
the
proposed
small
business
engine
manufacturer
transition
provisions.
Extensions
of
an
applicable
standard
also
apply
to
all
certification
requirements
associated
with
that
standards
(
so
that
transient
and
NTE
testing
would
not
be
required
until
expiration
of
the
extension).
Based
on
available
data,
and
further
conversations
with
manufacturers
during
the
development
of
this
rulemaking
(
documented
in
the
administrative
record),
we
have
found
no
small
business
manufacturers
of
nonroad
diesel
engines
above
175
hp.

For
engines
under
25
hp:
°
PM­
a
manufacturer
may
elect
to
delay
compliance
with
the
standard
for
up
to
three
years.
°
NO
X
­
there
is
no
change
in
the
level
of
the
existing
NO
X
standard
for
engines
in
this
category,
so
no
special
provisions
are
being
provided.

For
engines
in
the
25­
50
hp
category:
°
PM­
manufacturers
must
comply
with
the
interim
standards
(
the
Tier
4
requirements
that
begin
in
model
year
2008)
on
time,
and
may
elect
to
delay
compliance
with
the
2013
Tier
4
requirements
(
0.02
g/
bhp­
hr
PM
standard)
for
up
to
three
years.
Due
to
an
oversight
at
proposal,
we
did
not
include
transition
provisions
for
this
category
in
the
NPRM,
but
there
is
no
reason
to
exclude
them
when
all
other
small
business
engines
are
eligible
for
extensions.
We
therefore
are
adopting
a
three
year
extension
with
today's
action.
As
engines
in
this
category
must
meet
the
2008
standard,
we
are
not
conditioning
this
three
year
extension
on
meeting
this
standard.
(
Please
note
the
distinction
between
these
engines
and
engines
in
the
50­
75
hp
power
band,
where
we
are
conditioning
a
three­
year
extension
on
meeting
the
2008
standards.
The
difference
is
that
engines
in
the
50­
75
hp
category
have
an
option
of
whether
or
not
to
meet
those
2008
standards.
134
We
consequently
have
structured
the
small
business
engine
extension
to
encourage
a
choice
to
comply
with
those
standards.)
°
NO
X
­
a
manufacturer
may
elect
to
delay
compliance
with
the
standard
for
up
to
three
years.

For
engines
in
the
50­
75
hp
category:
°
As
proposed,
EPA
is
adopting
special
provisions
for
these
engines,
reflecting
the
special
provisions
in
the
rules
which
give
engine
manufacturers
the
choice
of
meeting
an
interim
standard
for
PM
in
2008
and
meeting
the
aftertreatment­
based
standard
in
2013,
or
meeting
the
aftertreatment­
based
standard
in
2012
without
meeting
an
interim
standard.
A
small
business
engine
manufacturer
may
delay
compliance
with
the
2013
Tier
4
requirement
of
0.02
g/
bhp­
hr
PM
for
up
to
three
years
provided
that
it
complies
with
the
interim
Tier
4
requirements
that
begin
in
model
year
2008
on
time,
without
the
use
of
credits.
We
proposed
an
extension
of
only
one
year,
but
this
would
be
inconsistent
with
the
extension
period
we
are
adopting,
and
which
we
proposed,
for
all
of
the
other
power
categories.
In
addition,
this
provision
for
50­
75
hp
engines
is
structured
to
encourage
small
business
engine
manufacturers
to
opt
for
early
PM
reductions
by
meeting
the
2008
interim
PM
standard,
so
that
an
extension
of
three
years
is
appropriate
as
an
incentive.
We
are
requiring
that
these
engines
achieve
the
2008
standard
without
use
of
credits
to
assure
that
there
be
improvements
in
actual
performance
by
engines
certifying
to
the
standard.
We
believe
that
such
assurance
is
a
necessary
and
reasonable
balance
for
the
three
year
additional
lead
time
for
meeting
the
aftertreatment­
based
standard.
There
were
no
adverse
comments
on
conditioning
the
extension
in
this
manner.
In
the
alternative,
a
manufacturer
may
elect
to
skip
the
interim
standard
completely.
However,
manufacturers
choosing
this
option
will
receive
only
one
additional
year
for
compliance
with
the
0.02
g/
bhp­
hr
standard
(
i.
e.
compliance
in
2013,
rather
than
2012).
These
engines
would
already
have
had
eight
years
of
lead
time
to
prepare
for
the
PM
standard
without
any
diversion
of
resources
to
meet
an
interim
PM
standard,
so
that
an
extension
of
longer
than
one
year
would
not
be
appropriate,
within
the
meaning
of
section
213
(
b)
of
the
Act.
In
addition,
structuring
the
extension
in
this
way
encourages
small
engine
manufacturers
to
choose
to
meet
the
2008
interim
standard
for
PM,
furthering
the
objective
of
early
PM
emission
reductions.
°
NO
X
­
there
is
no
change
in
the
NO
X
standard
for
engines
in
this
category,
therefore
no
special
provisions
are
being
provided.

For
engines
in
the
75
to
175
hp
category:
°
PM­
a
manufacturer
may
elect
to
delay
compliance
with
the
standard
for
up
to
three
years.
°
NO
X
­
a
manufacturer
may
elect
to
delay
compliance
with
the
standard
for
up
to
three
years.
135
These
provisions
are
also
set
out
below
in
the
following
table
(
in
all
instances,
these
engines
must
meet
the
previously
applicable
standards
as
set
out
in
§
1039.104
(
c):

Horsepower
Category
Provision
<
25
hp
NO
X
No
special
provisions
are
being
provided
PM
Manufacturers
may
delay
compliance
with
the
standard
for
three
years
25
­
50
hp
NO
X
Manufacturers
may
delay
compliance
with
the
standard
for
three
years
PM
Manufacturers
must
comply
with
the
interim
standards
in
2008,
and
may
delay
compliance
with
the
2013
Tier
4
requirements
(
0.02
g/
bhp­
hr
PM
standard)
for
three
years
50
­
75
hp
NO
X
No
special
provisions
are
being
provided
PM
Manufacturers
must
comply
with
the
interim
Tier
4
requirements
in
2008,
without
the
use
of
credits,
and
may
elect
to
delay
compliance
with
the
2013
Tier
4
requirements
(
0.02
g/
bhp­
hr
PM
standard)
for
three
years
­­
OR
­­

Manufacturers
may
skip
the
interim
standard
completely,
and
will
receive
an
additional
year
for
compliance
with
the
0.02
g/
bhp­
hr
PM
Tier
4
standard
(
i.
e.

compliance
in
2013,
rather
than
2012)

75
­
175
hp
NO
X
Manufacturers
may
delay
compliance
with
the
standard
for
three
years
PM
Manufacturers
may
delay
compliance
with
the
standard
for
three
years
b.
Hardship
Provisions
for
Small
Business
Engine
Manufacturers
i.
Panel
Recommendations
and
Our
Proposals
The
Panel
recommended
two
types
of
hardship
provisions
for
small
business
engine
manufacturers.
These
provisions
would
allow
for
relief
in
the
following
cases:
°
a
catastrophic
event,
or
other
extreme
unforseen
circumstances,
beyond
the
control
of
the
manufacturer
that
could
not
have
been
avoided
with
reasonable
discretion
(
i.
e.,
fire,
tornado,
supplier
not
fulfilling
contract,
etc.);
and
°
the
event
where
a
manufacturer
has
taken
all
reasonable
business,
technical,
and
economic
steps
to
comply
but
cannot.

The
Panel
believed
that
either
hardship
relief
provision
would
provide
lead
time
for
up
to
2
years,
and
that
a
manufacturer
should
have
to
demonstrate
to
EPA's
satisfaction
that
failure
to
69
The
one
comment
that
we
received
supported
the
provisions
proposed
for
small
business
engine
manufacturers.

136
sell
the
noncompliant
engines
would
jeopardize
the
company's
solvency.
EPA
may
also
require
that
the
manufacturer
make
up
the
lost
environmental
benefit.

We
proposed
the
Panel
recommendations
for
hardship
provisions
for
small
business
engine
manufacturers.
While
perhaps
ultimately
not
necessary
given
the
phase­
in
schedule
discussed
above,
we
stated
that
such
provisions
provide
a
useful
safety
valve
in
the
event
of
unforeseen
extreme
hardship.

ii.
What
We
are
Finalizing
We
received
two
comments
on
the
provisions
for
small
business
engine
manufacturers.
SBA's
Office
of
Advocacy
commented
that
the
rule
would
impose
significant
burdens
on
a
substantial
number
of
small
entities
with
little
corresponding
environmental
benefit;
and
further,
that
we
should
exclude
smaller
engines
(
those
under
75
hp)
from
further
regulation
in
order
to
comply
with
the
Regulatory
Flexibility
Act
and
fulfill
the
requirement
of
reducing
the
burden
on
small
engine
classes.
As
proposed,
we
are
not
adopting
standards
based
on
performance
of
NO
X
aftertreatment
technologies
for
engines
under
75
hp.
As
described
in
more
detail
in
section
II
of
this
preamble,
the
Summary
and
Analysis
of
Comment
Document,
and
the
RIA,
we
have
found
no
factual
basis
supporting
the
assertion
that
standards
for
PM
for
engines
between
25
and
75
hp
based
on
use
of
advanced
aftertreatment
impose
costs
out
of
relation
to
environmental
benefit,
have
a
disproportionate
impact
on
small
businesses,
or
are
otherwise
inappropriate.
In
fact,
it
is
our
finding
that
these
standards
for
PM
are
"
appropriate"
within
the
meaning
of
section
213(
a)(
4)
of
the
Clean
Air
Act,
and
that
PM
standards
for
these
engines
not
based
on
performance
of
advanced
aftertreatment
would
be
inappropriate
as
failing
to
reflect
standards
based
on
available
treatment
for
these
engines
(
taking
into
account
costs,
noise,
safety,
and
energy
factors).
We
received
no
adverse
comments
from
small
business
engine
manufacturers
on
the
proposed
transition
provisions
for
those
manufacturers.
69
Accordingly,
we
are
finalizing
the
small
business
engine
manufacturer
hardship
provisions
that
we
proposed
in
the
NPRM
(
as
recommended
by
the
Panel).
We
believe
that
these
provisions
will
provide
adequate
regulatory
flexibility
for
these
manufacturers,
while
remaining
consistent
with
the
requirements
of
section
213(
a)(
4)
and
213
(
b)
of
the
Clean
Air
Act.

c.
Other
Small
Business
Engine
Manufacturer
Issues
i.
Panel
Recommendations
and
Our
Proposals
The
Panel
also
recommended
that
an
ABT
program
be
included
as
part
of
the
overall
rulemaking
program.
In
addition,
the
Panel
suggested
that
EPA
take
comment
on
including
specific
ABT
provisions
for
small
business
engine
manufacturers.
We
proposed
an
ABT
program
137
for
all
engine
manufacturers,
with
this
program
retaining
the
basic
structure
of
the
current
nonroad
diesel
ABT
program.

We
did
not
include
small
business
engine
manufacturer­
specific
ABT
provisions
in
the
proposal.
Discussions
during
the
SBAR
process
indicated
that
small
volume
manufacturers
would
need
extra
time
to
comply
due
to
cost
and
personnel
constraints,
and
there
is
little
reason
to
believe
that
small
business
manufacturer
specific
ABT
provisions
could
create
an
incentive
to
accelerate
compliance.

ii.
What
We
are
Finalizing
As
discussed
above
in
section
III.
B,
we
are
finalizing
an
ABT
program
in
today's
action
similar
to
that
already
in
place
for
nonroad
engine
manufacturers.
We
have
also
made
a
number
of
changes
to
accommodate
implementation
of
these
new
emission
standards.

2.
Small
Nonroad
Diesel
Equipment
Manufacturers
a.
Transition
Provisions
for
Small
Business
Equipment
Manufacturers
i.
Panel
Recommendations
and
Our
Proposals
The
Panel
recommended
that
we
adopt
the
transition
provisions
described
below
for
small
business
manufacturers
and
small
business
importers
of
nonroad
diesel
equipment.
These
transition
provisions
are
similar
to
those
in
the
Tier
2/
3
rule
(
see
40
CFR
89.102).
The
recommended
transition
provisions
were
as
follows:

°
Percent­
of­
Production
Allowance:
Over
a
seven
model
year
period,
equipment
manufacturers
may
install
engines
not
certified
to
the
new
emission
standards
in
an
amount
of
equipment
equivalent
to
80
percent
of
one
year's
production.
This
is
to
be
implemented
by
power
category
with
the
average
determined
over
the
period
in
which
the
flexibility
is
used.

°
Small
Volume
Allowance:
A
manufacturer
may
exceed
the
80
percent
allowance
in
seven
years
as
described
above,
provided
that
the
previous
Tier
engine
use
does
not
exceed
700
total
over
seven
years,
and
200
in
any
given
year.
This
is
limited
to
one
family
per
power
category.
Alternatively,
the
Panel
recommended,
at
the
manufacturer's
choice
by
hp
category,
a
program
that
eliminates
the
"
single
family
provision"
restriction
with
revised
total
and
annual
sales
limits
as
shown
below:
­
for
categories
<
175
hp­
525
previous
Tier
engines
(
over
7
years)
with
an
annual
cap
of
150
units
(
these
engine
numbers
are
separate
for
each
hp
category
defined
in
the
regulations)
70
The
Panel
recognized
that,
similar
to
the
Tier
2/
3
standards,
it
may
be
necessary
to
provide
transition
provisions
for
all
equipment
manufacturers,
not
just
for
small
entities,
and
the
Panel
recommended
that
this
be
taken
into
account.

138
­
for
categories
of
>
175
hp­
350
previous
Tier
engines
(
over
7
years)
with
an
annual
cap
of
100
units
(
these
engine
numbers
are
separate
for
each
hp
category
defined
in
the
regulations)

The
Panel
recommended
that
EPA
seek
comment
on
the
total
number
of
engines
and
annual
cap
values
listed
above.
In
contrast
to
the
Tier
2/
Tier3
rule,
the
SBA
Office
of
Advocacy
expected
the
transition
to
the
Tier
4
technology
will
be
more
costly
and
technically
difficult.
Therefore,
the
small
business
equipment
manufacturers
may
need
more
liberal
flexibility
allowances
especially
for
equipment
using
the
lower
hp
engines.
The
Panel's
recommended
flexibility
may
not
adequately
address
the
approximately
50
percent
of
small
business
equipment
models
where
the
annual
sales
per
model
is
less
than
300
and
the
fixed
costs
are
higher.
Thus,
the
SBA
Office
of
Advocacy
and
the
Office
of
Management
and
Budget
(
OMB)
Panel
members
recommended
that
comment
be
sought
on
implementing
the
small
volume
allowance
(
700
engine
provision)
for
small
business
equipment
manufacturers
without
a
limit
on
the
number
of
engine
families
which
could
be
covered
in
any
hp
category.

°
Due
to
the
changing
nature
of
the
technology
as
the
manufacturers
make
the
transition
from
Tier
2
to
Tier
3
and
Tier
4,
the
Panel
recommended
that
the
equipment
manufacturers
be
permitted
to
borrow
from
the
Tier3/
Tier
4
flexibilities
for
use
in
the
Tier
2/
Tier
3
time
frame.

°
Lastly,
the
Panel
recommended
proposing
a
continuation
of
the
current
transition
provisions,
without
modifications
to
the
levels
or
nature
of
the
provisions,
that
are
available
to
these
manufacturers.

To
maximize
the
likelihood
that
the
application
of
these
provisions
will
result
in
the
availability
of
previous
Tier
engines
for
use
by
the
small
business
equipment
manufacturers,
the
Panel
recommended
that
­
similar
to
the
application
of
flexibility
options
that
are
currently
in
place
­
these
provisions
should
be
provided
to
all
equipment
manufacturers.
70
We
did
in
fact
propose
the
Percent­
of­
Production
and
Small
Volume
Allowances
listed
above
for
all
equipment
manufacturers,
and
explicitly
took
the
Panel
report
into
account
in
making
that
proposal.
We
also
requested
comment
on
a
number
of
additional
items,
some
of
which
were
proposed
by
the
Panel
(
see
section
III.
B
above).
139
ii.
What
We
are
Finalizing
We
are
finalizing
the
Percent­
of­
Production
and
Small
Volume
Allowances
for
all
equipment
manufacturers,
with
a
few
changes.
Some
non­
small
equipment
manufacturers
commented
that
the
small­
volume
provision
should
enable
manufacturers
to
exempt
up
to
700
pieces
of
equipment
over
a
seven­
year
period,
with
no
engine
family
restriction.
As
explained
earlier
in
section
III.
B.
2.
c,
we
are
finalizing
provisions
that
allow
manufacturers
to
choose
between
two
options:
a)
manufacturers
would
be
allowed
to
exempt
700
pieces
of
equipment
over
seven
years,
within
one
engine
family;
or
b)
manufacturers
using
the
small­
volume
allowance
could
exempt
525
machines
over
seven
years
(
with
a
maximum
of
150
in
any
given
year)
for
each
of
the
three
power
categories
below
175
horsepower,
and
350
machines
over
seven
years
(
with
a
maximum
of
100
in
any
given
year)
for
the
two
power
categories
above
175
horsepower.
Concurrent
with
the
revised
caps,
manufacturers
could
exempt
engines
from
more
than
one
engine
family
under
the
small­
volume
allowance
program.
As
explained
earlier,
based
on
sales
information
for
small
businesses,
we
estimated
that
the
alternative
small­
volume
allowance
program
to
include
lower
caps
and
allow
manufacturers
to
exempt
more
than
one
engine
family
would
keep
the
total
number
of
engines
eligible
for
the
allowance
at
roughly
the
same
overall
level
as
the
700­
unit
program.
The
Agency
believes
that
these
provisions
will
afford
manufacturers
the
type
of
transition
leeway
recommended
by
the
Panel.
Further,
these
transition
provisions
could
allow
small
business
equipment
manufacturers
to
postpone
any
redesign
needed
on
low
sales
volume
or
difficult
equipment
packages,
thus
saving
both
money
and
strain
on
limited
engineering
staffs.
Within
limits,
small
equipment
manufacturers
would
be
able
to
continue
to
use
their
current
engine/
equipment
configuration
and
avoid
out­
of­
cycle
equipment
redesign
until
the
allowances
are
exhausted
or
the
time
limit
passes.

During
the
SBREFA
Panel
process,
the
Panel
discussed
the
possible
misuse
of
the
transition
provisions
by
using
them
as
a
loophole
to
enter
the
nonroad
diesel
equipment
market
or
to
gain
unfair
market
position
relative
to
other
manufacturers.
See
68
FR
at
28481.
EPA
was
concerned
that
importers
of
equipment
from
a
foreign
equipment
manufacturer
could,
as
a
group,
import
more
exempted
equipment
from
that
foreign
manufacturer
than
80
percent
of
that
manufacturer's
production
for
the
United
States
market
or
more
than
the
small
volume
allowances
identified
in
the
transition
provisions.
This
would
create
a
potentially
significant
disparity
between
the
treatment
of
foreign
and
domestic
equipment
manufacturers.
EPA
did
not
intend
this
outcome,
and
did
not
believe
it
was
needed
to
provide
reasonable
lead
time
to
foreign
equipment
manufacturers.
The
Panel
recognized
that
this
was
a
possible
problem,
and
believed
that
a
requirement
that
small
equipment
manufacturers
and
importers
must
have
reported
equipment
sales
using
certified
engines
in
model
year
2002
or
earlier
in
order
to
be
eligible
to
access
the
transition
provisions
was
sufficient
to
alleviate
this
problem.
Upon
further
analysis
during
the
development
of
the
proposal,
EPA
decided
to
limit
the
availability
of
transition
provisions
to
entities
that
install
engines
and
have
primary
responsibility
for
designing
and
manufacturing
equipment
and
included
such
a
requirement
in
the
proposal.
Id.
at
28477.
Therefore,
a
company
that
only
imported
equipment,
and
had
no
involvement
in
the
actual
manufacturing
of
the
equipment,
would
be
ineligible
to
access
the
transition
provisions.
As
140
described
in
section
III.
B.
4,
we
are
finalizing
the
proposed
requirements
associated
with
the
use
of
transition
provisions
by
foreign
importers.
Therefore,
we
no
longer
believe
it
is
necessary
to
have
a
separate
requirement
that
small
equipment
manufacturers
and
importers
have
reported
equipment
sales
using
certified
engines
in
model
year
2002
or
earlier,
and
therefore
are
not
finalizing
this
redundant
provision.

We
are
also
finalizing
the
Panel's
recommendation
that
equipment
manufacturers
be
allowed
to
borrow
from
Tier
4
flexibilities
in
the
Tier2/
3
time
frame.
See
the
more
extended
discussion
on
this
issue
in
section
III.
B.
2.
d
above.

We
are
not
finalizing
the
Panel
recommendation
of
a
provision
allowing
small
manufacturers
to
request
limited
"
application
specific"
alternative
standards
for
equipment
configurations
which
present
unusually
challenging
technical
issues
for
compliance.
We
do
not
believe
that
the
need
for
such
a
provision
has
been
established,
and
further,
it
could
likely
provide
more
lead
time
than
can
be
justified,
and
undermine
emission
reductions
which
are
achievable.
Moreover,
no
participant
in
the
SBAR
process
or
during
the
public
comment
period
offered
any
empirical
support
that
such
a
problem
even
exists.
Nor
have
such
issues
been
demonstrated
(
or
raised)
by
equipment
manufacturers,
small
or
large,
in
implementing
the
current
nonroad
standards.
In
addition,
we
believe
that
any
application­
specific
difficulties
can
be
accommodated
by
the
transition
provisions
the
Agency
is
proposing
including
ABT.

We
are
also
finalizing
two
additional
provisions
for
all
equipment
manufacturers
that
small
business
equipment
manufacturers
may
take
advantage
of.
These
provisions
are
the
Technical
Hardship
Provision
and
the
Early
Tier
4
Engine
Incentive
Program.
Both
provisions
are
discussed
in
greater
detail
in
sections
III.
B.
2.
b
and
e
above.

b.
Hardship
Provisions
for
Small
Business
Equipment
Manufacturers
i.
Panel
Recommendations
and
Our
Proposals
The
Panel
also
recommended
that
two
types
of
hardship
provisions
be
extended
to
small
business
equipment
manufacturers.
These
provisions
would
allow
for
relief
in
the
following
cases:

°
a
catastrophic
event,
or
other
extreme
unforseen
circumstances,
beyond
the
control
of
the
manufacturer
that
could
not
have
been
avoided
with
reasonable
discretion
(
i.
e.,
fire,
tornado,
supplier
not
fulfilling
contract,
etc.).

°
the
event
where
a
manufacturer
has
taken
all
reasonable
business,
technical,
and
economic
steps
to
comply
but
cannot.
In
this
case
relief
would
have
to
be
sought
before
there
is
imminent
jeopardy
that
a
manufacturer's
equipment
could
not
be
sold
and
a
manufacturer
would
have
to
demonstrate
to
the
Agency's
satisfaction
that
failure
to
get
permission
to
sell
equipment
with
a
previous
Tier
engine
would
create
a
serious
economic
hardship.
Hardship
relief
of
this
nature
cannot
be
141
sought
by
an
`
integrated'
manufacturer
(
one
which
also
manufactures
the
engines
for
its
equipment).

We
proposed
that
the
hardship
provisions
recommended
by
the
Panel
be
extended
to
small
business
equipment
manufacturers
in
addition
to
the
transition
provisions
described
above.
We
also
requested
comment
on
the
stipulation
that,
to
be
eligible
for
these
hardship
provisions
(
as
well
as
the
other
proposed
transition
provisions),
equipment
manufacturers
and
importers
must
have
reported
equipment
sales
using
certified
engines
in
model
year
2002
or
earlier.

ii.
What
We
are
Finalizing
We
are
finalizing
the
Panel­
recommended
hardship
provisions
for
small
business
equipment
manufacturers
(
which
are
the
same
provisions
that
are
being
adopted
for
all
equipment
manufacturers).

EPA
also
received
comment
concerning
the
situation
faced
by
small
business
equipment
manufacturers
using
engines
in
the
25­
50
horsepower
range.
The
concern
was
raised
that
small
businesses
in
this
power
grouping
will
face
a
greater
relative
burden
in
designing
equipment
for
engines
with
aftertreatment,
and
that
they
may
need
additional
lead
time
beyond
that
provided
by
the
small
volume
allowances.
EPA
believes
that
in
general
the
small
volume
allowances
should
provide
reasonable
lead
time
opportunity
for
these
manufacturers,
but
recognizes
that
there
may
be
individual
cases
where
more
lead
time
would
be
appropriate
for
small
business
manufacturers
in
this
power
category.
EPA
is
therefore
adopting
a
technical
hardship
provision
similar
to
that
adopted
for
the
percent
of
production
allowance.
Small
business
manufacturers
using
engines
in
the
25­
50
hp
range
could
petition
EPA
to
approve
additional
needed
lead
time
in
appropriate,
individualized
circumstances,
based
on
a
showing
of
extreme
technical
or
engineering
hardship
as
provided
in
40
CFR
1039.625(
m).
EPA
could
approve
additional
small
volume
allowances,
up
to
a
total
number
of
1100
units.
This
total
number
includes
the
allowances
that
are
already
available
under
the
rule
without
request.
These
additional
allowances
could
only
be
used
for
engines
in
the
25­
50
horsepower
range,
and
could
only
be
approved
for
qualifying
small
business
equipment
manufacturers.
The
limitations
on
the
use
of
small
volume
allowances
(
such
as
when
allowances
may
only
be
used
within
a
single
engine
family
and
the
annual
limits)
continue
to
apply
to
the
standard
allowances
(
that
are
available
under
the
rule
without
request).
Finally,
any
additional
allowances
granted
under
this
provision
would
have
to
be
used
within
36
months
after
the
transition
flexibility
period
commences
for
these
engines.
The
additional
allowances
would
not
be
subject
to
the
annual
limits
noted
earlier
but
they
could
only
be
used
after
the
maximum
amount
of
standard
allowances
are
used
in
a
given
year
(
e.
g.,
a
manufacturer
using
the
700
unit
allowance
would
have
to
use
200
of
their
standard
allowances
for
that
year
before
they
could
use
any
of
the
additional
allowances
granted
by
EPA
under
this
technical
hardship
provisions).

EPA
recognizes
that
it
is
important
to
facilitate
the
process
for
small
business
equipment
manufacturers
to
seek
such
approval,
and
intends
to
work
with
small
manufacturers
so
that
any
transaction
costs
for
them
or
for
EPA
can
be
minimized.
For
example,
EPA
could
consider
at
one
142
time
a
common
request
from
similarly
situated
small
business
equipment
manufacturers,
as
long
as
all
of
the
necessary
individual
information
for
each
applicant
were
provided.
Given
that
information
in
such
an
application
would
still
be
both
company­
and
fact­
specific
(
and
likely
confidential
as
well),
and
that
the
criteria
for
relief
as
well
as
the
scope
of
appropriate
relief
are
case­
specific,
we
would
necessarily
evaluate
and
decide
whether
or
not
to
approve
additional
small
volume
allowances
on
a
company­
by­
company,
case­
by­
case
basis.

For
a
detailed
description
of
the
comments
received
on
small
business
engine
and
equipment
manufacturer
issues,
please
refer
to
the
Summary
and
Analysis
of
comments,
which
is
a
part
of
the
rulemaking
record
(
E­
DOCKET
number
OAR­
2003­
0012,
and
legacy
docket
number
A­
2001­
28).
A
summary
of
the
SBREFA
process
is
located
in
section
X.
C
of
this
preamble.

D.
Certification
Fuel
It
is
well­
established
that
measured
emissions
may
be
affected
by
the
properties
of
the
fuel
used
during
the
test.
For
this
reason,
we
have
historically
specified
allowable
ranges
for
test
fuel
properties
such
as
cetane
number
and
sulfur
content.
These
specifications
are
intended
to
represent
most
typical
fuels
that
are
commercially
available
in
use.
This
helps
to
ensure
that
the
emissions
reductions
expected
from
the
standards
occur
in
use
as
well
as
during
emissions
testing.

We
are
establishing
all
6
provisions
that
we
proposed
related
to
the
sulfur
content
of
fuel
used
in
conducting
nonroad
diesel
engine
emissions
testing:
°
300­
500
ppm
for
model
year
2008
to
2010
engines,
°
7­
15
ppm
for
2011
and
later
model
year
engines,
°
Extension
through
model
year
2007
of
the
maximum
2000
ppm
specification
for
Agency
testing
on
pre­
Tier
4
engines,
°
7­
15
ppm
for
2007­
2010
model
year
engines
that
use
sulfur­
sensitive
technology,
°
7­
15
ppm
for
2008­
2010
model
year
engines
under
75
hp,
°
300­
500
ppm
for
some
model
year
2006­
2007
engines
at
or
above
100
hp.
The
last
3
of
these
provisions
are
at
the
certifying
manufacturer's
option,
and
involve
additional
measures
that
the
manufacturer
must
take
to
help
ensure
that
the
specified
fuel
is
used
in
the
field.
The
below
discussion
provides
more
detail
on
each
of
these
provisions.

We
received
very
little
comment
on
our
proposed
certification
fuel
provisions.
Detroit
Diesel
commented
that
we
should
set
a
maximum
sulfur
specification
of
500
ppm
for
Tier
3
engines,
which
we
are
in
fact
doing
beginning
in
model
year
2008
after
this
fuel
is
introduced
in
the
nonroad
market,
and
optionally
allowing
as
early
as
2006,
the
earliest
Tier
3
model
year,
provided
manufacturers
take
steps
to
encourage
the
use
of
this
fuel,
as
discussed
below.

Because
we
are
lowering
the
upper
limit
for
in­
use
nonroad
diesel
fuel
sulfur
content
to
500
ppm
in
2007,
and
again
to
15
ppm
in
2010,
we
are
also
establishing
new
ranges
of
allowable
sulfur
content
for
testing.
These
are
300
to
500
ppm
(
by
weight)
for
model
year
2008
to
2010
71
See
66
FR
5112­
5113
(
January
18,
2001)
where
we
adopted
a
similar
approach
to
certification
fuels
for
highway
heavy­
duty
diesel
engines
(
HDDEs).

143
engines,
and
7
to
15
ppm
(
by
weight)
for
2011
and
later
model
year
engines.
We
believe
that
these
ranges
best
correspond
to
the
fuels
that
diesel
machines
will
potentially
see
in
use.
71
These
specifications
will
apply
to
emission
testing
conducted
for
certification,
selective
enforcement
audits,
in­
use,
and
NTE
testing,
as
well
as
any
other
laboratory
engine
testing
for
compliance
purposes
for
engines
in
the
designated
model
years.
Any
compliance
testing
of
previous
model
year
engines
will
be
done
with
the
fuels
designated
in
our
regulations
for
those
model
years.
Note
that,
as
proposed,
we
are
allowing
certification
with
fuel
meeting
the
7
to
15
ppm
sulfur
specification
in
2010
for
under
11
hp,
air­
cooled,
hand­
startable,
direct
injection
(
DI)
engines
certified
under
the
optional
standard
provision
discussed
in
section
II.
A.
3.
a.

It
is
important
to
note
that
while
these
specifications
include
the
maximum
sulfur
level
allowed
for
in­
use
fuel,
we
believe
that
it
is
generally
appropriate
to
test
using
the
most
typical
fuels.
As
for
highway
fuel,
we
expect
that,
under
the
15
ppm
maximum
sulfur
requirement,
refineries
will
typically
produce
diesel
fuel
with
about
7
ppm
sulfur,
and
that
the
fuel
could
have
slightly
higher
sulfur
levels
after
distribution.
Thus,
we
expect
that
we
will
use
fuel
having
a
sulfur
content
between
7
and
10
ppm
sulfur
for
our
emission
testing.
This
is
the
same
as
the
range
we
indicated
will
be
used
for
heavy­
duty
diesel
engine
(
HDDE)
engine
testing
in
model
year
2007
and
later
(
66
FR
5002,
January
18,
2001).
As
with
the
highway
fuel,
should
we
determine
that
the
typical
in­
use
nonroad
diesel
fuel
has
significantly
more
sulfur
than
this,
we
would
adjust
this
target
upward.

We
are
also
adopting
two
options
for
early
use
of
the
new
7
to
15
ppm
sulfur
diesel
test
fuel.
The
first
will
be
available
beginning
in
the
2007
model
year
for
engines
employing
sulfur­
sensitive
technology.
(
Model
year
2007
coincides
approximately
with
the
introduction
of
15
ppm
highway
fuel.)
This
allowance
to
use
the
new
fuel
in
model
years
before
2011
will
only
be
available
for
engines
which
the
manufacturer
demonstrates
will
be
operated
in
use
on
fuel
with
15
ppm
sulfur
or
less.
Any
testing
that
we
perform
on
these
engines
will
also
use
fuel
meeting
this
lower
sulfur
specification.
This
optional
certification
fuel
provision
is
intended
to
encourage
the
introduction
of
low­
emission
diesel
technologies
in
the
nonroad
sector.
These
engines
will
be
able
to
use
the
lower
sulfur
fuel
throughout
their
operating
life,
given
the
early
availability
of
this
fuel
under
the
highway
program,
and
the
assured
availability
of
this
fuel
for
nonroad
engines
by
mid­
2010.

Considering
that
our
Tier
4
program
will
subject
engines
under
75
hp
to
new
emission
standards
in
2008
when
15
ppm
maximum
sulfur
fuel
will
be
readily
available
from
highway
fuel
pumps
(
and
will
enter
the
nonroad
fuel
market
shortly
after
in
2010),
we
believe
it
is
appropriate
to
provide
a
second,
less
proscriptive,
option
for
use
of
15
ppm
sulfur
certification
fuel.
This
option
will
be
available
to
any
manufacturers
willing
to
take
extra
steps
to
encourage
the
use
of
this
fuel
before
it
is
required
in
the
field.
We
are
allowing
the
early
use
of
15
ppm
certification
fuel
for
2008­
2010
engines
under
75
hp,
provided
the
certifying
manufacturer
ensures
that
144
ultimate
purchasers
of
equipment
using
these
engines
are
informed
that
the
use
of
fuel
meeting
the
15
ppm
specification
is
recommended,
and
also
recommends
to
equipment
manufacturers
buying
these
engines
that
labels
be
applied
at
the
fuel
inlet
to
remind
users
of
this
recommendation.
This
option
does
not
apply
to
those
50­
75
hp
engines
not
being
certified
to
the
0.22
g/
bhp­
hr
PM
standard,
under
the
manufacturers'
option
discussed
in
section
II.
A.
1.
a.

We
believe
that
there
may
be
a
very
small
loss
of
emissions
benefit
from
any
of
these
engines
for
which
the
operator
chooses
to
ignore
the
recommendation.
This
is
because
the
engine
manufacturer
will
be
designing
the
engine
to
comply
with
the
emissions
standards
when
tested
using
15
ppm
fuel,
potentially
resulting
in
slightly
higher
emissions
when
it
is
not
operated
on
the
15
ppm
fuel.
We
also
believe,
however,
that
this
is
more
than
offset
overall
by
the
encouragement
this
provision
provides
for
early
use
of
15
ppm
fuel.
We
are
not
making
this
option
available
for
engine
designs
employing
oxidation
catalysts
or
other
sulfur­
sensitive
exhaust
emission
control
devices
except
under
the
more
restrictive
provision
for
early
use
of
15
ppm
fuel
described
above,
involving
a
demonstration
by
the
manufacturer
that
the
fuel
will
indeed
be
used.
Because
these
devices
could
potentially
have
very
high
sulfur­
to­
sulfate
conversion
rates
(
see
section
II.
B.
4
and
5
above),
and
because
very
high­
sulfur
fuels
will
still
be
available
to
some
extent,
we
believe
that
allowing
this
provision
for
these
engines
would
risk
very
high
PM
emissions
until
the
15
ppm
nonroad
fuel
is
introduced.
We
are
not
making
this
second
early
15
ppm
test
fuel
option
available
for
engines
not
subject
to
a
new
Tier
4
standard
in
2008
as
these
engines
should
already
be
designed
to
meet
applicable
standards
in
earlier
years
without
need
for
the
15
ppm
fuel.

We
are
also
adopting
a
similar
provision
for
use
of
certification
fuel
meeting
the
300­
500
ppm
sulfur
specification
before
the
2008
model
year.
We
believe
certification
of
model
year
2006
and
2007
engines
being
designed
without
the
use
of
sulfur­
sensitive
technologies
to
meet
new
Tier
2
or
Tier
3
emission
standards
taking
effect
in
those
years
(
2006
for
engines
at
or
above
175
hp
and
2007
for
100­
175
hp
engines)
should
be
able
to
use
this
fuel,
provided
the
certifying
manufacturer
is
willing
to
take
measures
equivalent
to
those
discussed
above
to
encourage
the
early
use
of
this
fuel
(
a
recommendation
to
the
ultimate
purchaser
to
use
fuel
with
500
ppm
maximum
sulfur
and
a
recommendation
to
equipment
manufacturers
to
so
label
their
equipment).

The
widespread
availability
of
500
ppm
sulfur
highway
fuel,
the
short
time
that
these
2006
and
2007
engines
could
use
higher
sulfur
fuels
if
an
operator
were
to
ignore
the
recommendation,
and
the
eventual
use
of
15
ppm
sulfur
fuel
in
most
of
these
engines
for
most
of
their
operating
lives,
gives
us
confidence
that
this
provision
to
encourage
early
use
of
lower
sulfur
fuel
will
be
beneficial
to
the
environment
overall.
As
with
the
change
to
300­
500
ppm
cert
fuel
for
model
years
2008­
2010,
engine
manufacturers
will
design
their
engines
to
comply
based
on
the
test
fuel
specifications
for
certification
and
compliance
testing.
The
change
from
a
fuel
specification
for
compliance
testing
that
ranges
up
to
2000
ppm
sulfur
for
Tier
2
and
3
engines
to
a
specification
of
500
ppm
sulfur
maximum
could
have
some
limited
effect
on
the
emissions
control
designs
used
on
these
Tier
2
and
3
engines,
in
that
it
will
be
slightly
easier
to
meet
the
Tier
2
and
3
standards
using
the
lower
sulfur
test
fuel.
In
general,
it
is
reasonable
to
set
specifications
of
test
fuel
reflecting
representative
in­
use
fuels,
and
here
the
engines
are
expected
to
be
using
fuel
with
sulfur
levels
of
145
500
ppm
or
lower
until
2010,
and
15
ppm
or
lower
after
that.
In
this
case,
any
impact
on
expected
engine
emissions
from
this
change
in
test
fuel
for
Tier
2
and
3
is
expected
to
be
slight.

We
note
that
under
current
regulations
manufacturers
are
already
allowed
to
conduct
testing
with
certification
fuel
sulfur
levels
as
low
as
300
ppm.
The
additional
provision
for
early
use
of
300­
500
ppm
sulfur
test
fuel
will,
however,
result
in
any
compliance
testing
conducted
by
the
Agency
being
done
with
fuel
meeting
the
300­
500
ppm
specification.
Likewise
choice
of
the
option
for
early
use
of
15
ppm
sulfur
test
fuel
would
result
in
any
Agency
testing
being
done
using
that
fuel.
However,
under
both
of
these
early
certification
fuel
options
involving
a
recommended
fuel
use
provision,
the
Agency
will
not
reject
engines
from
in­
use
testing
for
which
there
is
evidence
or
suspicion
that
the
engine
had
been
fueled
at
some
time
with
higher
sulfur
fuel.

Finally,
we
are
extending
a
provision
adopted
in
the
1998
final
rule
(
63
FR
56967,
October
23,
1998).
In
that
rule
we
set
a
2000
ppm
upper
limit
on
the
test
fuel
sulfur
concentration
for
any
testing
to
be
performed
by
the
Agency
on
Tier
1
engines
under
50
hp
and
Tier
2
engines
at
or
above
50
hp.
We
did
not
extend
this
provision
to
later
model
year
engines
at
that
time
because
we
felt
that
more
time
was
needed
to
assess
trends
in
fuel
sulfur
levels
for
fuels
used
in
nonroad
diesels.
At
this
time
we
are
not
aware
of
any
additional
information
that
would
indicate
that
a
change
in
this
test
specification
is
warranted.
More
importantly,
because
the
fuel
regulation
we
are
adopting
will
make
500
ppm
maximum
sulfur
nonroad
diesel
fuel
available
by
mid­
2007,
Tier
3
engines
at
or
above
50
hp
(
which
phase
in
beginning
in
2006)
will
be
in
the
field
for
only
1
½
years
prior
to
the
in­
use
introduction
of
500
ppm
fuel,
and
Tier
2
engines
under
50
hp
(
which
phase
in
beginning
in
2004)
will
be
in
the
field
for
at
most
3
½
years
prior
to
this
time.
We
believe
it
is
appropriate
to
avoid
adding
the
unnecessary
complication
of
frequent
multiple
changes
to
the
test
fuel
specification.
We
are
therefore
extending
the
2000
ppm
limit
to
testing
conducted
on
engines
until
the
2008
model
year
when
the
500
ppm
maximum
test
fuel
sulfur
level
takes
effect
as
discussed
above.

E.
Temporary
In­
Use
Compliance
Margins
The
Tier
4
standards
will
be
challenging
for
diesel
engine
manufacturers
to
achieve,
and
will
require
manufacturers
to
develop
and
adapt
new
technologies
for
a
large
number
and
wide
variety
of
engine
platforms.
Not
only
will
manufacturers
be
responsible
for
ensuring
that
these
technologies
enable
compliance
with
Tier
4
standards
at
the
time
of
certification,
they
will
also
have
to
ensure
that
these
technologies
continue
to
be
highly
effective
in
a
wide
range
of
in­
use
environments
so
that
their
engines
will
comply
in
use
when
tested
by
EPA.
Furthermore,
for
the
first
time,
these
nonroad
diesel
engines
will
be
subject
to
transient
emissions
control
requirements
and
to
NTE
standards.

However,
in
the
early
years
of
a
program
that
introduces
new
technology,
there
are
risks
of
in­
use
compliance
problems
that
may
not
appear
in
the
certification
process
or
during
developmental
testing.
Thus,
we
believe
that
for
a
limited
number
of
model
years
after
new
standards
take
effect
it
is
appropriate
to
adjust
the
compliance
levels
for
assessing
in­
use
146
compliance
for
diesel
engines
equipped
with
high­
efficiency
exhaust
emissions
control
devices.
This
provides
assurance
to
the
manufacturers
that
they
will
not
face
recall
if
they
exceed
standards
by
a
small
amount
during
this
transition
to
clean
technologies.
This
approach
is
very
similar
to
that
taken
in
the
light­
duty
highway
Tier
2
final
rule
(
65
FR
6796,
February
10,
2000)
and
the
highway
heavy­
duty
rule
(
66
FR
5113­
5114,
January
18,
2001),
both
of
which
involve
similar
approaches
to
introducing
the
new
technologies.
In
fact,
the
similarities
of
nonroad
diesel
engines
and
expected
Tier
4
control
technologies
to
counterpart
engines
and
technologies
for
heavy­
duty
highway
diesel
engines
led
us
to
model
the
proposed
Tier
4
add­
on
provisions
after
the
2007
heavy­
duty
highway
diesel
program,
with
add­
on
levels
chosen
to
be
roughly
equivalent
to
the
levels
adopted
in
the
highway
rule.

Comments
on
the
proposal
were
received
from
engine
manufacturers,
requesting
changes
that
would
make
the
temporary
in­
use
adjustments
more
closely
parallel
the
highway
requirements.
Specifically,
they
requested:
(
1)
providing
two
full
model
years
of
applicability
following
the
completion
of
standards
phase­
in
for
the
75­
175
hp
category,
as
was
proposed
for
the
other
power
categories,
(
2)
adjusting
the
NO
X
threshold
for
applicability
of
the
provisions
to
a
level
8%
above
the
split
family
standard,
(
3)
adopting
3
levels
of
add­
ons
based
on
how
many
hours
the
test
engine
had
been
used,
with
cutpoints
at
2000
and
3400
hours,
and
(
4)
a
25%
upward
adjustment
to
the
add­
on
levels.
We
agree
that
these
changes
would
result
in
a
closer
approximation
to
the
highway
program.
Our
goal
in
proposing
provisions
somewhat
different
from
the
highway
program
was
to
avoid
unnecessary
complexity.
However,
we
believe
that
maintaining
consistency
with
the
highway
program
is
a
more
important
goal
and
the
manufacturers'
suggested
changes
do
not
overly
complicate
the
program,
and
so
we
have
decided
to
make
these
changes.

We
note
too
that
changes
we
are
making
to
the
Tier
4
program
for
engines
over
750
hp
necessitate
other
changes
to
the
in­
use
add­
on
program
for
these
engines
as
well.
Specifically,
these
are
the
extension
of
model
year
applicability
to
2016,
two
years
after
the
final
Tier
4
standards
take
effect,
and
the
clarification
of
what
PM
thresholds
apply
for
engines
used
in
generator
sets
and
for
other
engines.

Table
III.
E­
1
shows
the
in­
use
adjustments
that
we
will
apply.
These
in­
use
add­
on
levels
will
be
applied
only
to
engines
certified
in
the
indicated
model
years
and
having
FELs
(
or
certifying
to
standards
without
FELs)
at
or
below
the
specified
threshold
levels.
These
adjustments
are
added
to
the
appropriate
FELs
(
see
section
III.
A)
or,
for
engines
certified
to
the
standards
without
the
use
of
ABT
program
credits,
to
the
standards
themselves,
in
determining
the
in­
use
compliance
level
for
a
given
in­
use
hours
accumulation
on
the
engine
being
tested.
Note
that
the
PM
adjustment
is
the
same
for
all
in­
use
hours
accumulation.
Note
also
that,
because
the
standards
in
the
regulations
are
expressed
in
g/
kW­
hr,
the
adjustments
included
in
the
regulations
are
set
at
levels
that
make
the
resulting
adjusted
in­
use
standard
equivalent
in
stringency
to
the
standards
in
this
preamble
(
expressed
in
g/
bhp­
hr)
adjusted
by
the
values
in
Table
III.
E­
1
(
also
expressed
in
g/
bhp­
hr).
147
Note
too
that,
as
part
of
the
certification
demonstration,
manufacturers
will
still
be
required
to
demonstrate
compliance
with
the
unadjusted
Tier
4
certification
standards
using
deteriorated
emission
rates.
Therefore,
the
manufacturer
will
not
be
able
to
use
these
in­
use
standards
as
the
design
targets
for
the
engine.
They
will
need
to
project
that
most
engines
will
meet
the
standards
in­
use
without
adjustment.
The
in­
use
adjustments
will
merely
provide
some
assurance
that
they
will
not
be
forced
to
recall
engines
because
of
some
small
miscalculation
of
the
expected
deterioration
rates.

Table
III.
E­
1.
 
Add­
on
Levels
Used
in
Determining
In­
use
Standards
Engine
Power
Model
Years
NOX
PM
Add­
On
Level
a
(
g/
bhp­
hr)
for
operating
hours
Add­
On
Level
b
(
g/
bhp­
hr)

25

hp
<
75
(
19

kW
<
56)
2013­
2014
none
0.01
75

hp
<
175
(
56

kW
<
130)
2012­
2016
0.12

2000
0.01
0.19
2001­
3400
0.25
>
3400
175

hp

750
(
130

kW

560)
2011­
2015
0.12

2000
0.01
0.19
2001­
3400
0.25
>
3400
hp
>
750
(
kW
>
560)
2011­
2016
0.12

2000
0.01
0.19
2001­
3400
0.25
>
3400
Notes:

a
Applicable
only
to
those
engines
certifying
to
standards
or
with
FELs
at
or
below
1.6
g/
bhp­
hr
NOX.

b
Applicable
only
to
those
engines
certifying
to
standards
or
with
FELs
at
or
below
the
filter­
based
Tier
4
PM
standards
(
0.01
g/
bhp­
hr
for
75­
750
hp
engines,
0.02
g/
bhp­
hr
for
25­
75
hp
engines
and
for
>
750
hp
engines
in
generator
sets,
and
0.03
g/
bhp­
hr
for
all
other
>
750
hp
engines).

F.
Test
Cycles
72
See
EPA
Dear
Manufacturer
Letter
VPCD­
98­
13,
"
Heavy­
duty
Diesel
Engines
Controlled
by
Onboard
Computers:
Guidance
on
Reporting
and
Evaluating
Auxiliary
Emission
Control
Devices
and
the
Defeat
Device
Prohibition
of
the
Clean
Air
Act,"
October
15,
1998
and
EPA
Advisory
Circular
24­
3,

"
Implementation
of
Requirements
Prohibiting
Defeat
Devices
for
On­
Highway
Heavy­
Duty
Diesel
Engines."
A
copy
of
both
of
these
documents
is
available
in
EPA
Air
Docket
A­
2001­
28.

73
Letter
from
Jed
Mandel
of
the
Engine
Manufacturers
Association
to
Chet
France
of
US
EPA,

Office
of
Transportation
and
Air
Quality,
"
Development
of
appropriate
transient
test
cycle
for
variable
speed
land­
based
compression
ignition
non­
road
engines,"
Air
Docket
A­
2001­
28,
II­
B­
33.

148
1.
Transient
Test
In
the
1998
final
rule
that
set
new
emission
standards
for
nonroad
diesel
engines,
EPA
expressed
a
concern
that
the
steady­
state
test
cycles
used
to
demonstrate
compliance
with
emission
standards
did
not
adequately
reflect
transient
operation
as
many
nonroad
engines
are
used
in
applications
that
are
largely
transient
in
nature
and
would
not
therefore
yield
adequate
control
of
emissions
in
use
(
63
FR
56984,
October
23,
1998).
Although
we
were
not
prepared
to
adopt
a
transient
test
at
that
time,
we
announced
our
intention
in
that
final
rule
to
move
forward
with
the
development
of
such
a
test.
This
development
progressed
steadily
and
has
resulted
in
the
creation
of
the
Nonroad
Transient
Composite
(
NRTC)
test
cycle
which
we
are
adopting
in
our
Tier
4
nonroad
diesel
program.
The
NRTC
cycle
supplements
the
existing
nonroad
steady­
state
test
requirements.
Thus,
most
nonroad
engines
subject
to
today's
Tier
4
standards
will
be
required
to
certify
using
both
of
these
tests.
72
The
NRTC
cycle
captures
transient
emissions
over
much
of
the
typical
nonroad
engine
operating
range,
and
thus
helps
to
ensure
effective
control
of
all
regulated
pollutants.
The
speed
and
load
operating
schedule
for
EPA's
NRTC
test
cycle
is
described
in
regulations
at
40
CFR
1039.505.
A
detailed
discussion
of
the
transient
test
cycle
and
its
derivation
is
contained
in
chapter
4.2
of
the
RIA
for
this
rule.

We
expect
that
this
transient
test
requirement
will
significantly
reduce
real
world
emissions
from
nonroad
diesel
equipment.
Proper
transient
operation
testing
captures
engine
emissions
from
the
broad
range
of
engine
speed
and
load
combinations
that
the
engine
may
attain
in­
use,
while
the
steady­
state
emission
test
characterizes
emissions
at
the
few
isolated
operating
points
that
may
be
typical
for
that
family
of
engines.
Testing
for
transient
emissions
will
likewise
identify
emissions
which
result
from
the
operation
of
the
engine,
as
with
speed
and
load
changes,
turbocharger
lag,
etc.

In
keeping
with
our
goal
to
maximize
the
harmonization
of
emissions
control
programs
as
much
as
possible,
we
have
developed
this
cycle
in
collaboration
with
nonroad
engine
manufacturers
and
regulatory
bodies,
both
domestic
and
foreign,
over
the
last
several
years.
73
Further,
the
NRTC
cycle
has
been
introduced
as
a
work
item
for
possible
adoption
as
a
potential
74
Informal
Document
No.
2,
ISO
­
45th
GRPE,
"
Proposal
for
a
Charter
for
the
Working
Group
on
a
New
Test
Protocol
for
Exhaust
Emissions
from
Nonroad
Mobile
Machinery,"
Jan.
13­
17,
2003,
Air
Docket
A­
2001­
28,
document
II­
A­
171.

149
global
technical
regulation
under
the
1998
Agreement
for
Working
Party
29
at
the
United
Nations.
74
EPA's
nonroad
transient
test
will
apply
(
with
one
exception
noted
below)
to
a
nonroad
diesel
engine
when
that
engine
must
first
show
compliance
with
EPA's
Tier
4
PM
and
NO
X+
NMHC
emissions
standards
which
are
based
on
the
performance
of
the
advanced
postcombustion
emissions
control
systems
(
e.
g.
catalyzed­
diesel
particulate
filters
and
NO
X
adsorbers).
This
is
2011
for
engines
at
175
hp
­
750
hp,
2012
for
75
­
175
hp
engines
(
2012,
as
well,
for
50
­
75
hp
engines
made
by
a
manufacturer
choosing
the
option
to
not
comply
with
the
2008
transitional
PM
standard.),
and
2013
for
engines
under
75
hp.
The
transient
test
cycle
will
not
apply
to
engines
greater
than
750
hp.
Specific
provision
is
made
for
engines
under
25
hp
for
PM
and
under
75
hp
for
NO
X
(
which
are
not
based
on
performance
of
advanced
aftertreatment).
Constant­
speed,
variable­
load
engines
of
any
horsepower
category
currently
certify
to
EPA's
5­
Mode
Steady
State
duty
cycle
and
are
not
subject
to
transient
duty
cycle
testing.
As
with
current
nonroad
diesel
standards,
today's
Tier
4
emission
standards
will
apply
to
certification,
Selective
Enforcement
Audits
(
SEAs)
and
to
recall
testing
of
equipment
in­
use
for
all
engines
subject
to
these
standards.

Table
III.
F­
1.
 
Implementation
Model
Year
for
Nonroad
Transient
Testing
Power
Category
Transient
Test
Implementation
Model
Years
<
25
hp
2013
25

hp
<
75
2013
75

hp
<
175
2012
175

hp
<
750
2011
In
addition,
any
engines
for
which
an
engine
manufacturer
(
see
section
III.
M)
or
equipment
maker
(
see
section
III.
B.
2.
c)
claims
credit
under
the
incentive
program
for
earlyintroduction
engines
will
have
to
be
certified
to
that
program's
standards
under
applicable
Tier
4
nonroad
transient
and
steady­
state
duty
cycles,
e.
g.,
NRTC,
8­
mode
and
5­
mode
steady­
state
cycles.
In
turn,
any
2011
or
later
model
year
engine
that
uses
these
engine
count­
based
credits
will
not
need
to
demonstrate
compliance
under
the
NRTC
cycle.
Engines
in
any
power
category
certified
to
an
alternate
NO
X
standard
are
all
subject
to
the
transient
test
requirement,
as
they
clearly
will
be
substantially
redesigned
to
achieve
Tier
4
compliance,
regardless
of
whether
or
not
they
use
high­
efficiency
exhaust
emission
controls.
See
section
II.
A.
1.
c
above.

We
solicited
comment
on
whether
the
transient
duty
cycle
should
apply
to
NO
X
emissions
from
phase­
out
engines
(
68
FR
28484,
May
23,
2003)
and
received
comment
from
EMA.
EMA
75
Please
note
that
this
discussion
does
not
apply
to
engines
certifying
to
the
alternative
NOX
phase­
in
standards,
which
engines
are
required
to
meet
transient
and
NTE
requirements
for
gaseous
pollutants
(
as
well
as
all
other
requirements
that
would
apply
to
phase­
in
engines).
See
discussion
at
II.
A.
2.
c;
also
please
note
that
these
engines
are
expressly
not
defined
as
phase­
out
engines
in
the
rules;
see
section
1039.801
and
1039.102
(
e).

76
As
noted
elsewhere,
the
TCAFs
are
derived
identically
to
the
Transient
Adjustment
Factor
used
in
the
NONROAD
emissions
model.

150
prefers
that
the
transient
cycle
only
be
applicable
to
PM
emission
testing
and
not
for
NO
X,
NMHC
and
CO
for
phase­
out
engine
families.
They
believe
that
the
application
of
the
transient
NRTC
and
standards
could
result
in
the
need
to
redevelop
the
NO
X/
NMHC/
CO
emission
control
systems
used
for
their
members'
compliance
with
Tier
3
standards.

We
essentially
agree
with
this
comment
to
the
extent
that
phase­
out
engines
do
not
include
improvements
in
gaseous
pollutant
emission
control
(
i.
e.
they
remain
essentially
Tier
3
engines
for
emissions
other
than
PM).
Imposing
new
requirements
with
respect
to
these
engines'
gaseous
pollutant
emissions
could
divert
resources
inappropriately.
The
rule
therefore
states
(
in
40
CFR
1039.102
(
a)(
2))
that
gaseous
pollutant
emissions
from
these
engines
are
not
subject
to
transient
testing
standards.
This
would
not
apply
if
a
manufacturer
declares
a
new
NO
X+
NMHC
FEL
for
the
engine
family
(
since
the
manufacturer
would
then
already
be
choosing
to
alter
these
engines'
performance
with
respect
to
gaseous
pollutant
emissions).
75
Transient
testing
standards
do
apply
with
respect
to
PM
emissions
from
phase­
out
engines,
however.
The
reason
is
evident:
the
PM
standard
for
phase­
out
(
and
phase­
in)
engines
is
based
on
performance
of
aftertreatment,
so
the
full
complement
of
test
cycles
(
NTE
as
well
as
transient
testing)
should
apply.
A
consequence
of
this
is
that
phase­
out
engines
will
generally
be
tested
over
the
transient
cycle,
since
they
must
do
so
with
respect
to
PM
emissions.
We
repeat,
however,
that
although
the
engines
will
do
transient
testing,
only
PM
(
and
not
gaseous
pollutants)
is
subject
to
the
transient
test
standard.

In
addition,
manufacturers
choosing
to
certify
engines
under
750
hp
using
alternative
FEL
caps
during
the
first
four
years
that
the
alternative
caps
are
available
(
see
section
III.
A.
i.
2
above)
will
not
be
subject
to
the
transient
or
NTE
standards.
However,
to
properly
account
for
the
transient
effects
when
calculating
credits,
we
are
requiring
the
FELs
of
such
engines
to
be
adjusted
upwards
by
applying
a
Temporary
Compliance
Adjustment
Factor
(
TCAF)
76.
See
40
CFR
1039.104
(
g)
(
2).

Even
though
we
are
requiring
that
NRTC
testing
start
when
the
PM
aftertreatment­
based
standards
take
effect,
one
should
not
infer
that
the
NRTC
is
directed
at
solely
(
or
even
primarily)
at
PM
control.
In
fact,
we
believe
that
advanced
NO
X
emission
controls
may
be
even
more
sensitive
to
transient
operation
than
PM
filters,
since
the
PM
filters
ordinarily
operate
equally
151
effectively
in
all
operating
modes,
as
noted
earlier.
It
is,
however,
our
intent
that
the
control
of
emissions
during
transient
operation
be
an
integral
part
of
Tier
4
engine
design
considerations.
We
have
therefore
chosen
to
apply
the
transient
test
requirement
starting
with
the
PM
filter­
based
Tier
4
PM
standards
as
these
standards
precede
or
accompany
the
earliest
Tier
4
NO
X
or
NMHC
standards
in
all
power
categories
except
engines
over
750
hp.

As
EPA
is
not
promulgating
PM
filter­
based
standards
for
engines
below
25
hp
in
today's
rulemaking,
we
are
likewise
not
requiring
these
engines
to
be
tested
over
the
NRTC
test
cycle
until
model
year
2013.
More
broadly,
though
we
intend
for
transient
emissions
control
to
be
an
integral
part
of
Tier
4
design
considerations,
we
do
not
believe
it
appropriate
to
mandate
compliance
with
the
transient
test
for
the
engines
under
50
hp
which
are
subject
to
PM
standards
in
2008.
We
recognize
that
transient
emission
testing,
though
routine
in
highway
engine
programs,
involves
a
fair
amount
of
laboratory
equipment
and
new
expertise
in
the
nonroad
engine
certification
process.
As
with
the
transfer
of
advanced
emission
control
technology
itself,
we
believe
that
the
transient
test
requirement
should
be
implemented
first
for
larger
displacement
engines.
These
engines
are
more
likely
to
be
made
by
manufacturers
who
provide
engines
to
the
on­
highway
market
and
therefore
have
had
prior
on­
highway
engine
development
and
certification
experience.
We
do
not
believe
that
the
smaller
engines
should
be
the
power
categories
first
charged
with
implementing
the
new
transient
test,
as
early
as
2008,
especially
because
manufacturers
of
these
engines
do
not
generally
make
highway
engines
and
are
neither
as
experienced
nor
as
well­
equipped
as
their
larger
engine
manufacturer
counterparts
at
conducting
transient
cycle
testing.
However,
to
encourage
earlier
transient
emission
control
in
these
engines,
EPA
will
allow
manufacturers
of
engines
below
25
hp
to
submit
data
describing
emission
levels
for
their
engines
over
the
appropriate
certification
transient
duty
cycle
beginning
in
model
year
2008.
We
extend
this
option
as
well
to
manufacturers
of
25­
50
hp
engines,
subject
to
those
engines
meeting
the
Tier
4
transitional
PM
standard
in
2008.
Should
a
manufacturer
choose
to
submit
data
in
the
2008­
2011
time
frame,
prior
to
required
certification
data
submissions,
that
transient
data
will
not
be
used
for
compliance
enforcement.

EPA
requested
comment
on
whether
engines
greater
than
750
hp
should
be
subject
to
the
transient
cycle,
noting
concerns
of
technical
difficulties
and
cost
for
these
engines
(
68
FR
28484,
May
23,
2003).
STAPPA­
ALAPCO
and
other
agencies
representing
the
States'
interests
responded
to
EPA
that
all
nonroad
engines
should
be
uniformly
required
to
test
their
transient
emissions.
Likewise,
they
asked
that
the
Agency
not
delay
implementation
of
this
particular
requirement.
However,
at
this
time,
the
Agency
is
not
adopting
a
transient
emission
testing
requirement
for
engines
750
hp
and
over.
EPA
sees
the
burden
of
transient
cycle
testing
in
these
very
large
displacement
engines
as
being
greater
than
the
benefit
of
gathering
transient
emission
measurements
from
them.
For
example,
in
many
instances,
these
engines
will
have
multiple
aspiration
and
exhaust
systems
requiring
a
test
cell
designed
to
accommodate
multiple
large
flow
volumes
in
real­
time
on
a
five
Hertz,
or
faster,
basis.
New
transient
test
requirements
could
require
manufacturers
to
create
new
or
expanded
testing
facilities
to
house,
prepare
and
run
transient
tests
on
these
larger
engines.
The
space
requirements,
i.
e.,
"
footprint,"
of
such
facilities
could
make
building
them
cost­
prohibitive.
77
Memorandum
from
Kent
Helmer
to
Cleophas
Jackson,
"
Applicability
EPA's
NRTC
cycle
to
Nonroad
Diesel
Population,"
Air
Docket
A­
2001­
28,
document
II­
B­
34.

152
Absent
transient
testing,
these
engines
will
still
be
required
to
certify
to
both
steady­
state
and
NTE
test
requirements.
Moreover,
we
are
modifying
the
certification
requirements
to
include
additional
information
for
engines
under
750
hp.
For
more
detail
on
this
submission,
see
the
discussion
in
section
III.
I
of
this
preamble
and
40
CFR
1039.205(
p)
of
the
regulations.

Finally,
engines
in
this
power
category
are
found
in
a
relatively
small
proportion
of
the
nonroad
equipment
population
and,
despite
the
potential
for
large
quantities
of
emissions
from
this
class
of
engines
during
operation,
units
equipped
with
these
engines
have
likewise
been
noted
to
contribute
a
small
proportion
of
total
diesel
nonroad
engine
emissions.
77
Many
of
these
largerdisplacement
engines
operate
predominately
in
a
constant­
speed
fashion
with
few
transient
excursions,
as
with
electric
power
generation
sets
(
gen
sets)
which
make
up
a
significant
percent
of
these
larger
engines.
Many
of
these
gen
sets,
too,
operate
on
an
intermittent
or
stand­
by
only
basis.
Indeed,
as
explained
below,
such
constant­
speed,
variable­
load
engines
(
for
example,
those
certifying
exclusively
to
the
5­
mode
steady­
state
cycle)
of
any
horsepower
category
are
not
subject
to
the
nonroad
transient
test
cycle.

Further,
the
Agency
does
not
intend
at
this
time
to
require
that
manufacturers
use
partialflow
sampling
systems
(
PFSS)
to
determine
PM
emissions
from
their
engines
for
certification.
A
large
engine
manufacturer
may,
however,
choose
to
submit
PM
data
to
the
Agency
using
PFSS
as
an
alternative
test
method,
if
that
manufacturer
can
demonstrate
test
equivalency
using
a
paired­
T
test
and
F­
Test,
as
outlined
in
regulations
at
40
CFR
86.1306­
07.

Transient
testing
requires
consideration
of
statistical
parameters
for
verifying
that
test
engines
adequately
follow
the
prescribed
schedule
of
speed
and
load
values.
The
regulations
in
40
CFR
1065.514,
table
1,
detail
these
statistical
parameters,
also
known
as
cycle
performance
statistics.
These
values
are
somewhat
different
than
the
comparable
values
for
highway
diesel
engines
to
take
into
account
the
characteristics
of
nonroad
engine
operation.
The
values
are
an
outgrowth
of
the
long
development
process
for
the
NRTC
test
cycle,
itself.

2.
Cold
Start
Transient
Testing
Nonroad
diesel
engines
typically
operate
in
the
field
by
starting
and
warming
to
a
point
of
stabilized
hot
operation
at
least
once
in
a
workday.
Such
"
cold­
start"
conditions
may
also
occur
at
other
times
over
the
course
of
the
workday,
such
as
after
a
lunch
break.
We
have
observed
that
certain
test
engines,
which
generally
had
emission­
control
technologies
for
meeting
Tier
2
or
Tier
3
standards,
had
elevated
emission
levels
for
about
10
minutes
after
starting
from
a
cold
condition.
The
extent
and
duration
of
increased
cold­
start
emissions
will
likely
be
affected
by
changing
technology
for
meeting
Tier
4
standards,
but
there
is
no
reason
to
believe
that
this
effect
will
lessen.
In
fact,
cold­
start
concerns
are
especially
pronounced
for
engines
with
catalytic
devices
for
controlling
exhaust
emissions,
because
many
require
heating
to
a
"
light­
off"
or
peak­
78
Note
that
this
discussion
applies
only
to
engines
that
are
subject
to
testing
with
transient
test
procedures.
For
example,
this
excludes
constant­
speed
engines
and
all
engines
over
750
hp.

153
efficiency
temperature
to
begin
working.
See,
for
example,
RIA
section
4.1.2.2
and
following.
EPA's
highway
engine
and
vehicle
programs,
which
increasingly
involve
such
catalytic
devices,
address
this
by
specifying
a
test
procedure
that
first
measures
emissions
with
a
cold
engine,
then
repeats
the
test
after
the
engine
is
warmed
up,
weighting
emission
results
from
the
two
tests
for
a
composite
emission
measurement.

In
the
proposal,
we
described
an
analytical
approach
that
led
to
a
weighting
of
10
percent
for
the
cold­
start
test
and
90
percent
for
the
hot­
start
test.
Manufacturers
pointed
out
that
their
analysis
of
the
same
data
led
to
a
weighting
of
about
4
percent
for
cold­
start
testing
and
that
a
high
cold­
start
weighting
would
affect
the
feasibility
of
the
proposed
emission
standards.
Manufacturers
also
expressed
a
concern
that
there
would
be
a
significant
test
burden
associated
with
cold­
start
testing.

Unlike
steady­
state
tests,
which
always
start
with
hot­
stabilized
engine
operation,
transient
tests
come
closer
to
simulating
actual
in­
use
operation,
in
which
engines
may
start
operating
after
only
a
short
cool­
down
(
hot­
start)
or
after
an
extended
soak
(
cold­
start).
The
new
transient
test
and
manufacturers'
expected
use
of
catalytic
devices
to
meet
Tier
4
emission
standards
make
it
imperative
to
address
cold­
start
emissions
in
the
measurement
procedure.
78
We
are
therefore
adopting
a
test
procedure
that
requires
measurement
of
both
cold­
start
and
hot­
start
emissions
over
the
transient
duty
cycle,
much
like
for
highway
diesel
engines.
We
acknowledge,
however,
that
limited
data
are
available
to
establish
an
appropriate
cold­
start
weighting.
For
this
final
rule,
we
are
therefore
opting
to
establish
a
cold­
start
weighting
of
5
percent.
This
is
based
on
a
typical
scenario
of
engine
operation
involving
an
overnight
soak
and
a
total
of
seven
hours
of
operation
over
the
course
of
a
workday.
Under
this
scenario,
the
20­
minute
cold­
start
portion
constitutes
5
percent
of
total
engine
operation
for
the
day.
Section
II.
B
above
addresses
the
feasibility
of
meeting
the
emission
standards
with
cold­
start
testing.
Regarding
the
test
burden
associated
with
cold­
start
testing,
we
believe
that
manufacturers
will
be
able
to
take
steps
to
minimize
the
burden
by
taking
advantage
of
the
provision
that
allows
for
forced
cooling
to
reduce
total
testing
time
(
40
CFR
1039.510(
c)).

We
believe
the
5­
percent
weighting
is
based
on
a
reasonable
assessment
of
typical
in­
use
operation
and
it
addresses
the
need
to
design
engines
to
control
emissions
under
cold­
start
operation.
We
believe
cold­
start
testing
with
these
weighting
factors
will
be
sufficient
to
require
manufacturers
to
take
steps
to
minimize
emission
increases
under
cold­
start
conditions.
Once
manufacturers
have
applied
technologies
and
strategies
to
minimize
cold­
start
emissions,
they
will
be
achieving
the
greatest
degree
of
emission
reductions
achievable
under
those
conditions.
A
higher
weighting
factor
for
cold­
start
testing
is
not
likely
be
more
effective
in
achieving
in­
use
emission
control
as
new
technologies
will
be
expected
to
have
resulted
in
significant
control
of
emissions
at
engine
startup.
79
Two
Memoranda
from
Kent
Helmer
to
Cleophas
Jackson,
"
Speed
and
Load
Operating
Schedule
for
the
Constant
Speed
Variable
Load
(
CSVL)
transient
test
cycle,"
e­
Docket
OAR­
2003­
0012­

0993,
and
"
CSVL
Cycle
Construction,"
A­
2001­
28,
II­
B­
50.

80
Memorandum
from
Kent
Helmer
to
Cleophas
Jackson,
"
Brake­
specific
Emissions
Impact
of
Nonroad
Diesel
Engine
Testing
Over
the
NRTC,
AWQ,
and
AW1
duty
cycles,"
Docket
A­
2001­
28,
#
.

154
However,
given
our
interest
in
controlling
emissions
under
cold­
start
conditions
and
the
relatively
small
amount
of
information
available
in
this
area
at
this
time,
we
intend
to
revisit
the
cold­
start
weighting
factor
for
transient
testing
in
the
future
as
additional
data
become
available.
Since
the
composite
transient
test
represents
a
combination
of
variable­
speed
and
constant­
speed
operation,
we
would
consider
operation
from
both
of
these
types
of
engines
in
evaluating
the
cold­
start
weighting.
Also,
we
intend
to
apply
the
same
cold­
start
weighting
when
we
adopt
a
transient
duty
cycle
specifically
for
engines
certified
only
for
constant­
speed
operation.

The
planned
data­
collection
effort
will
focus
on
characterizing
cold­
start
operation
for
nonroad
diesel
equipment.
The
objective
will
be
to
reassess,
and
if
necessary,
redevelop
a
weighting
factor
that
properly
accounts
for
the
degree
of
cold­
start
operation
so
that
in­
use
engines
effectively
control
emissions
during
these
conditions.
As
we
move
forward
with
this
investigation,
other
interested
parties,
including
the
State
of
California,
will
be
invited
to
participate.
We
are
interested
in
pursuing
a
joint
effort,
in
consultation
with
other
national
government
bodies,
to
ensure
a
robust
and
portable
data
set
that
will
facilitate
common
global
technical
regulations.
This
effort
will
require
consideration
of
at
least
the
following
factors:


What
types
of
equipment
will
we
investigate?


How
many
units
of
each
equipment
type
will
we
instrument?


How
do
we
select
individual
models
that
will
together
provide
an
accurate
crosssection
of
the
type
of
equipment
they
represent?


When
will
the
program
start
and
how
long
will
it
last?


How
should
we
define
a
cold­
start
event
from
the
range
of
in­
use
operation?

We
expect
to
complete
our
further
evaluation
of
the
cold­
start
weighting
in
the
context
of
the
2007
Technology
Review,
if
not
sooner.
In
case
changes
to
the
regulation
are
necessary,
this
timing
will
allow
enough
time
for
manufacturers
to
adjust
their
designs
as
needed
to
meet
the
Tier
4
standards.

3.
Constant­
Speed
Tests
The
Agency
proposed
that
engine
manufacturers
could
certify
constant­
speed
engines
using
EPA's
Constant­
Speed,
Variable­
Load
(
CSVL)
transient
duty
cycle79
as
an
alternative
to
certifying
these
engines
under
its
NRTC
test
cycle.
The
CSVL
transient
cycle
was
developed
to
approximate
the
speed
and
load
operating
characteristics
of
many
constant­
speed
nonroad
diesel
applications.
80
It,
too,
would
have
been
subject
to
the
cold­
start
requirement
of
nonroad
transient
155
test
cycles
as
is
the
NRTC.
However,
after
considerable
discussion
with
and
comment
from
engine
manufacturers,
equipment
makers
and
other
interested
parties,
the
Agency
has
decided
not
to
promulgate
an
alternative
nonroad
transient
test
cycle
for
constant­
speed
engines
at
this
time.
EMA,
in
its
comments
on
the
CSVL
cycle,
felt
generally
that:
1)
the
average
load
factor
is
much
too
low;
2)
the
frequency
of
the
transient
operations
was
too
high;
3)
the
amplitudes
of
the
transients
were
too
great;
and
4)
the
rates
of
transient
load
increase
and
response
were
too
fast.

It
was
further
noted
that
the
CSVL
test
cycle
is
based
solely
upon
the
operation
of
a
single,
relatively
small,
naturally­
aspirated
arc
welder
engine,
which
EMA
claims
is
a
variable­
speed
type
of
engine
certified
generally
on
the
8­
mode
test
cycle.
Arc
welders,
Cummins
noted,
are
not
much
like
generator
sets,
which
comprise
around
50%
of
population
of
constant­
speed
engines
and
have
a
very
different
operation
and
test
cycle
than
the
typical
portable
generator
set.
Generator
sets,
DDC
wrote,
were
built
generally
for
a
higher
power
capability
at
a
single
speed,
many
having
larger,
less­
responsive
turbochargers
to
achieve
the
higher
brake
mean
effective
pressure
(
BMEP).
This
made
it
difficult
for
these
engines
to
shed
load
as
quickly
as
the
CSVL
test
cycle
would
require
them
to
do.
Commenters
likewise
wrote
that
the
test
cycle
was
costly
and
burdensome
for
equipment
which,
like
generator
sets,
was
only
operated
infrequently
or
when
emergencies
occurred.
Some
wrote
that
it
would
compromise
generator
set
engine
performance
if
manufacturers
had
to
re­
engineer
their
products
to
run
over
the
CSVL
test
cycle,
especially
for
larger
BMEP
engines.
One
commenter
noted
that
these
changes
to
nonroad
engines
would
carry
over
to
other
stationary
applications
of
these
generator
sets.
A
more
extensive
discussion
of
comments
relating
to
the
CSVL
cycle
may
be
read
in
the
Summary
and
Analysis
of
Comment
document
for
this
rule.

Given
these
potential
problems
and
the
strong
possibility
of
fixing
them
by
2007,
the
Agency
has
decided
to
defer
adopting
the
CSVL
test
cycle
here.
Instead,
EPA
with
all
of
its
stakeholders
in
this
regard
will
map
out
a
process
of
engine
testing
and
analysis
to
better
characterize
constant­
speed
equipment
in­
use
to
design
the
most
appropriate
test
cycle
for
the
largest
number
of
constant­
speed
engines.
EPA
undertakes
this
process
with
an
eye
to
initiating
rulemaking
which
would
lead
to
promulgation
of
a
transient
cycle
for
constant­
speed
engines
before
the
Agency's
2007
Nonroad
Diesel
Technical
Review.

EPA
defines
a
constant­
speed
engine
in
this
regard
as
one
which
is
certified
to
constantspeed
operation,
in
other
words,
an
engine
which
may
not
operate
at
a
speed
outside
a
single,
fixed
reference
speed
set
by
the
engine's
governor.
It
should
be
clear
then
that
any
engine
for
which
the
governor
doesn't
strictly
limit
the
engine
speed
in­
use
to
constant­
speed
operation,
that
engine
will
be
subject
to
the
NRTC.
Thus,
if
a
manufacturer's
engine
is
certified
to
EPA's
8­
mode
steady­
state
test,
the
engine
would
also
need
to
certify
to
the
NRTC,
since
the
8­
mode
test
does
not
limit
the
engine's
fixed
operating
speed.
Conversely,
those
manufacturers
who
certify
their
engines
to
EPA's
constant­
speed
steady­
state
test,
the
5­
mode
test
cycle
are
not
required
to
have
their
engines
certify
to
the
NRTC.
156
By
utilizing
an
inclusive,
data­
driven
approach
(
see
Summary
and
Analysis
document
for
more
detail),
the
Agency
is
allowing
time
to
develop,
and
if
appropriate,
finalize
and
implement
a
test
procedure
that
meets
the
needs
of
the
Agency,
manufacturers,
and
other
parties
in
advance
of
the
2007
Technology
Review.
In
fact,
the
Agency
envisions
constant
speed
variable
load
cycle
generation
to
be
completed
by
July
2005.
This
approach
should
allow
the
Agency
to
develop
a
testing
program
which
ensures
robust
control
in­
use,
is
data­
driven
and
remains
globally
harmonized.
We
expect
to
initiate
this
effort
within
3
months
of
promulgation
of
this
rule
and
to
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.
If
we
encounter
unforeseen
and
unavoidable
delays
or
complications
in
this
process,
we
will
consider
approaches
to
control
based
on
available
data
at
the
time
of
the
2007
Technology
Review.

The
Agency
is
adopting
additional
requirements,
in
conjunction
with
existing
steady­
state
test
requirements,
which
will
help
ensure
that
constant­
speed
nonroad
diesel
engines
are
subject
to
a
rigorous
program
of
in­
use
control
of
emissions
and
that
diesel
engine
emissions
will
be
controlled
over
a
wide
range
of
speed
and
load
combinations.
EPA
is
finalizing
stringent
nonroad
NTE
limits
and
related
test
procedures
for
all
new
nonroad
diesel
engines
subject
to
the
Tier
4
emissions
standards
beginning
in
2011
which
will
supplement
the
existing
steady­
state
five­
mode
test
cycle
for
constant­
speed
application
engines.
NTE
testing
for
transient
operation
will
add
further
assurance
that
emissions
from
constant­
speed
engines
within
this
class,
which
have
a
limited
speed
response
in­
use,
are
controlled
under
in­
use
operation.
Typically,
engines
which
are
designed
to
a
particular
transient
cycle
will
control
emissions
effectively
under
other
types
of
transient
operation
not
specifically
included
in
that
certification
procedure.
Engines
that
are
capable
of
meeting
emission
standards
on
a
constant­
speed,
variable­
load
cycle
will
have
the
transient­
response
characteristics
that
are
appropriate
for
controlling
emissions
at
higher
engine
loads
and
for
less
dynamic
transient
operation.
EPA,
engine
manufacturers,
and
interested
parties
will,
in
the
mean
time,
work
to
develop
a
more
appropriate
transient
test
for
constant­
speed
engines.
A
transient
test
for
this
broad
class
of
nonroad
engines
will
ensure
a
robust
level
of
emissions
control
in­
use
within
the
diverse
population
of
constant­
speed
engines
and
equipment.

4.
Steady­
State
Tests
Recognizing
the
variety
of
both
power
classes
and
work
applications
to
be
found
within
the
nonroad
equipment
and
engine
population,
and
as
proposed,
EPA
is
retaining
current
Federal
steady­
state
test
procedures
for
nonroad
engines.
(
Manufacturers
are
thus
required
to
meet
emission
standards
under
steady­
state
conditions,
in
addition
to
meeting
emission
standards
under
the
transient
test
cycle,
whenever
the
transient
test
cycle
applies.)
This
requirement,
like
NTE
emission
testing,
is
one
of
two
tests
which
apply
to
every
Tier
4
engine.
Table
III­
2
below
sets
out
the
particular
steady­
state
duty
cycle
applicable
to
each
of
the
following
categories:
1)
nonroad
engines
25
hp
and
greater;
2)
nonroad
engines
less
than
25
hp;
and
3)
nonroad
engines
81
These
three
steady­
state
test
cycles
are
similar
to
test
cycles
found
in
the
International
Standard
ISO
8178­
4:
1996
(
E)
and
remain
consistent
with
the
existing
40
CFR
part
89
steady­
state
duty
cycles.

157
having
constant­
speed,
variable­
load
applications,
(
e.
g.,
gen
sets).
The
steady­
state
cycles
remain,
respectively,
the
8­
mode
cycle,
the
6­
mode
cycle
and
the
5­
mode
cycle.
81
Steady­
state
test
cycles
are
needed
so
that
testing
for
certification
will
reflect
the
broad
range
of
operating
conditions
experienced
by
these
engines.
A
steady­
state
test
cycle
represents
an
important
type
of
modern
engine
operation,
in
power
and
speed
ranges
that
are
typical
in­
use.
The
mid­
to­
high
speeds
and
loads
represented
by
present
steady­
state
testing
requirements
are
the
speeds
and
loads
at
which
these
engines
are
designed
to
operate
for
extended
periods
for
maximum
efficiency
and
durability.
Details
concerning
the
three
steady­
state
procedures
for
nonroad
engines
and
equipment
are
found
in
regulations
at
40
CFR
1039.505
and
in
Appendices
I­
III
to
40
CFR
part
1039.

Manufacturers
will
perform
each
steady­
state
test
following
all
applicable
test
procedures
in
the
regulations
at
40
CFR
part
1039,
e.
g.,
procedures
for
engine
warm­
up
and
exhaust
emissions
measurement.
The
testing
must
be
conducted
with
all
emission­
related
engine
control
variables
in
the
maximum
NO
X­
producing
condition
which
could
be
encountered
for
a
30
second
or
longer
averaging
period
at
a
given
test
point.
Table
III.
F­
2
below
summarizes
the
steady­
state
testing
requirements
by
individual
engine
power
categories.

Table
III.
F­
2.
 
Summary
of
Steady­
State
Test
Requirements
Nonroad
Engine
Power
Classes
Steady­
State
Testing
Requirements
8­
Mode
Cycle
(
C1weighting)
6­
Mode
Cycle
(
G3
weighting)
5­
Mode
Cycle
(
D2
weighting)

hp
<
25
(
kW
<
19)
applies
a
applies
a
applies
b
25

hp
<
75
(
19

kW
<
56)
applies
NA
c
applies
b
75

hp
<
175
(
56

kW
<
130)
applies
NA
c
applies
b
175

hp

750
(
130

kW

560)
applies
NA
c
applies
b
hp
>
750
(
kW
>
560)
applies
NA
c
applies
b
Notes:

a
Manufacturers
may
use
either
of
these
tests
for
this
class
of
engines.

b
For
constant,
or
nearly
constant,
speed
engines
and
equipment
with
variable,
or
intermittent,
load.

c
Testing
procedures
not
applicable
to
this
class
of
engines.
82
Letter
from
EMA
(
Engine
Manufacturers
Association)
to
EPA
Air
Docket
A­
2001­
28,
IV­
D­

402,
pp
64.

83
Memorandum
and
summary
of
technical
discussions
(
including
Appendix
"
A"
text)
in
the
e­

Docket
submission,
OAR­
2003­
0012­
0028,
to
EPA's
Air
Docket.

158
Nonroad
engine
manufacturers82,
have
called
for
steady­
state
testing
which
would
collect
emissions
continuously
"
in
a
pseudo­
transient
manner,"
proposing
in
effect,
one­
filter
PM
collections
during
a
steady­
state
duty
cycle.
In
response
to
these
and
other
manufacturer
concerns
for
emission
variability
during
certification
testing
due
to
unanticipated
emission
control
system
regeneration
between
steady­
state
test
modes,
the
Agency83
has
adopted,
in
its
40
CFR
1065.515
regulations,
the
concept
of
modifying
EPA's
40
CFR
part
89
steady­
state
engine
certification
duty
cycles.
The
section
describes
ramped
"
modal"
steady­
state
certification
tests
which
would
link
the
modes
of
a
steady­
state
test
together
for
the
purpose
of
collecting
a
continuous
stream
of
engine
emissions.
These
tests
provide
for
operating
an
engine
at
all
of
the
modes
specified
in
the
present
steady­
state
nonroad
test
cycles
but
without
the
breaks
in
emission
collection
required
by
switching
between
modes,
stabilizing
engine
operation,
and
collecting
emissions
at
that
next
operating
mode.
Since
a
ramped
modal
cycle
(
RMC)
test
cycle
may
more
reliably
and
consistently
report
engine
emissions
from
particulate
trap
and
other
emission
control
hardware­
equipped
nonroad
engines
than
the
comparable
steady­
state
duty
cycle
from
which
it
was
derived,
the
Agency
is
providing
the
option
of
using
these
RMC
versions
of
its
steady­
state
engine
duty
cycles
for
nonroad
diesel
engine
certification
testing
in
lieu
of
the
otherwise
applicable
steady­
state
cycles.
Details
on
the
procedures
may
be
found
in
chapter
4.2
of
the
RIA
for
this
rule
and
at
regulations
at
40
CFR
1039.505
and
Appendix
I
of
part
1039.

The
optional
RMC
duty
cycles
do
not
represent
a
relaxation
in
stringency
of
emission
testing
nor
are
they
an
unreasonable
increase
in
the
emission
test
burden
of
diesel
engine
manufacturers.
Rather,
the
RMC
versions
of
EPA's
steady­
state
test
cycles
allow
for
more
consistent
and
predictable
emission
testing
of
emission
control
system
hardware­
equipped
diesel
engines.
Eliminating
the
"
downtime"
between
modes
for
the
emission
collection
equipment
allows
sampling
of
emissions
to
be
done
on
a
composite
basis
for
the
whole
test
as
opposed
to
sampling
emissions
mode­
by­
mode.
The
RMC
versions
of
these
tests
simply
create
a
negligible
transition
period
20
seconds
long
connecting
each
mode
and
collects
emissions
during
these
brief
transitions,
as
well
as
collecting
emissions
during
the
running
of
each
test's
discrete
operating
modes.
The
continuous
emission
sampling
allows
regeneration
events
from
engine
emission
control
hardware
to
be
captured
more
reliably
and
repeatably.
By
running
emission
testing
without
breaks
and
over
the
same
engine
duty
schedule
for
each
repetition
of
a
RMC
test,
regeneration
within
the
engine's
emission
control
hardware
should
become
almost
a
predictable
event.
The
longer
sampling
times
of
RMCs,
while
creating
an
identical
weighting
of
each
mode's
emissions,
also
help
to
avoid
collecting
a
minuscule,
possibly
unreliably
measured,
amount
of
sample
over
the
course
of
any
single
operating
mode.
PM
emissions,
for
example,
can
be
collected
and
measured
more
precisely
under
these
test
conditions
as
either
batch
or
continuous
samples.
The
opportunities
for
loss
of
emissions
during
sampling
and
storage
due
to
sample
159
retention
by
equipment
at
shut­
down
between
modes
or
by
filter
handling
and
weighing
are
greatly
reduced.
As
well,
running
a
"
steady­
state"
test
on
a
continuous
basis
allows
cycle
performance
statistics
to
be
applied
to
RMC
emission
tests
(
see
40
CFR,
part
39).
Manufacturers
are
familiar
with
test
cycles
run
with
a
set
of
statistical
engine
duty
cycle
performance
"
targets".
Further,
their
test
runs
will
be
subject
to
less
test
cell
"
tuning",
modifying
control
strategies
using
repeat
testing
runs
to
fit
the
emission
test
cycle
and
the
dynamometer
to
operate
a
particular
engine.
Finally,
statistical
targets
serve
to
increase
repeatability
and
reduce
variability
of
engine
operating
parameters
and
emission
test
results
on
a
test­
to­
test
basis.

Transport
refrigeration
unit
(
TRU)
engines,
a
specific
application
of
a
steady­
state
operation
engine
(
68
FR
28485,
May
23,
2003),
will
be
subject
to
both
steady­
state
and
NTE
standards
based
on
any
normal
operation
that
these
engines
would
experience
in
the
field.
To
that
end,
EPA
has
adopted
a
four­
mode
steady­
state
test
cycle
designed
specifically
for
engines
used
in
TRU
applications
which
may
be
used
by
the
manufacturer
in
lieu
of
normal
steady­
state
testing.
Commenters
to
the
rule
agreed
that
a
TRU
test
cycle
would
be
more
representative
of
refrigeration
unit
operation
than
the
nonroad
cycles
currently
available
to
manufacturers
of
TRU
engines,
but
some
took
issue
with
EPA's
usage
restrictions
in
paragraphs
(
d)(
2),
(
e)(
2),
and
(
e)(
3)
of
regulations
proposed
at
40
CFR
part
1039
subpart
G.
In
response,
the
final
rule
allows
manufacturers
to
test
their
engines
under
a
broad
definition
of
intermediate
test
speed.
The
definition
covers
the
60­
75
%
range
of
engine
rpm
at
the
specified
test
cycle
engine
load
points,
as
defined
in
40
CFR,
89.2.
This
will
enable
an
engine
manufacturer
to
more
closely
match
the
TRU
cycle
to
the
operation
of
their
engines
in­
use.
Further,
the
engine
is
allowed
to
exhibit
no
more
than
2%
variation
in
transient
operation
(
speed
or
torque
change)
around
the
four
operating
modes
defined
under
this
test
cycle.
The
provisions
to
address
load
set
point
drift
are
discussed
in
detail
in
the
RIA
chapter
4.3.2
and
in
regulations
at
40
CFR
part
1039
subpart
G.

In
choosing
to
certify
their
engine
as
a
TRU
engine,
manufacturers
will
need
to
state
on
the
engine
emission
control
label
that
the
engine
will
only
be
used
in
a
TRU
application
and
records
must
be
kept
on
the
delivery
destination(
s)
for
their
engines.
Manufacturers
of
these
engines
may
petition
EPA
at
certification
for
a
waiver
of
the
requirement
to
provide
smoke
emission
data
for
their
constant­
torque
engines.
A
more
detailed
discussion
of
the
TRU
associated
provisions
is
contained
in
chapter
4.2
of
the
RIA.
It
should
be
noted
that
an
RMC
version
of
the
steady
state
TRU
duty
cycle
is
provided
in
Table
2
of
40
CFR
part
1039
subpart
G.

G.
Other
Test
Procedure
Issues
This
section
contains
further
detail
and
explanation
regarding
several
related
nonroad
diesel
engine
emissions
test
and
measurement
provisions.
The
test
procedures
are
specified
in
40
CFR
part
1065
and
part
1039
subpart
F.
Part
1065
contains
general
test
procedure
requirements
and
part
1039
contains
the
provisions
that
are
specific
to
CI
nonroad
engines,
such
as
test
cycles.
The
changes
described
here
will
not
significantly
affect
the
stringency
of
the
standards.
While
some
of
the
changes
being
made
may
appear
to
increase
the
stringency
of
the
standards
when
considered
by
themselves,
others
would
appear
to
have
the
opposite
effect.
When
considered
160
together,
however,
they
will
result
in
more
repeatable
and
less
subjective
testing
that
is
equivalent
to
the
existing
procedures
with
respect
to
stringency.

1.
Smoke
Testing
To
control
smoke
emissions,
we
are
requiring
in
this
final
rule
that
the
current
smoke
standards
and
procedures
will
continue
to
apply
to
certain
engines.
We
proposed
to
change
these
smoke
standards
and
procedures,
based
on
recent
developments
toward
an
established
international
protocol
that
was
designed
to
allow
a
straightforward
method
to
test
engines
in
the
field
(
68
FR
28486,
May
23,
2003).
We
have
chosen
not
to
adopt
the
proposed
approach,
mainly
because
it
is
becoming
increasingly
clear
that
ongoing
development
of
in­
use
testing
equipment
will
allow
direct
measurement
of
PM
emissions
in
the
field.
We
believe
this
will
provide
the
best
long­
term
control
of
both
PM
emissions.
Controlling
smoke
is
in
some
ways
independent
of
PM,
but
the
interest
in
developing
an
in­
use
smoke
test
was
primarily
as
a
means
of
providing
a
secondary
indicator
of
high
in­
use
PM
emissions
from
these
engines.
Direct
PM
measurement
removes
much
of
the
advantage
of
in­
use
smoke
measurements.
Relying
on
the
existing
smoke
test
also
addresses
concerns
raised
by
manufacturers
that
the
effort
to
comply
with
the
new
smoke
requirements
would
be
a
large
testing
and
development
burden
with
little
air­
quality
benefit.
We
believe
that
aftertreatment­
based
Tier
4
PM
standards
will
control
smoke
emissions
as
well
as
improved
smoke
testing
standards
and
procedures.
Engines
below
19
kilowatts
(
kW)
will
generally
not
have
particulate
filters,
but
most
of
these
are
constant­
speed
engines
and
are
therefore
not
subject
to
smoke
standards,
as
described
below.

We
are
continuing
the
established
policy
of
exempting
constant­
speed
engines
and
singlecylinder
engines
from
smoke
standards.
We
do
not
believe
that
constant­
speed
engines
undergo
the
kind
of
acceleration
or
lugging
events
that
occur
during
this
smoke
test
procedure,
so
it
would
not
be
appropriate
for
these
engines
to
be
subject
to
smoke
standards.
We
exempt
singlecylinder
engines
for
a
different
reason.
These
engines,
which
very
often
provide
power
for
generator
sets
and
other
constant­
speed
applications,
but
may
in
some
cases
experience
accelerations,
the
nature
of
single­
cylinder
engine
operation
makes
it
difficult
to
get
a
valid
smoke
emission
measurement.
Single­
cylinder
engines
generally
have
discrete
puffs
of
smoke,
rather
than
a
stable
emission
stream
for
measuring
smoke
values.
We
believe
it
is
not
appropriate
to
use
such
erratic
measurements
to
evaluate
an
engine's
emission
performance.
As
a
result,
we
will
not
require
single­
cylinder
engines
to
meet
our
smoke
standards
until
we
find
a
test
method
that
takes
this
into
account.

Also,
as
described
in
the
proposed
rule,
we
are
exempting
from
smoke
emission
standards
any
engines
that
are
certified
to
PM
emission
standards
or
FELs
at
or
below
0.07
g/
kW­
hr.
We
believe
any
engine
that
has
such
low
PM
emissions
will
have
inherently
low
smoke
emissions.
No
commenters
disagreed
with
this
position.
161
2.
Maximum
Test
Speed
We
are
changing
how
test
cycles
are
specified.
As
proposed,
we
are
applying
the
existing
definition
of
maximum
test
speed
in
40
CFR
part
1065
to
nonroad
CI
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.
This
is
intended
to
ensure
that
the
maximum
speed
of
the
test
is
representative
of
actual
engine
operating
characteristics
and
is
not
improperly
used
to
influence
the
parameters
under
which
their
engines
are
certified.
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,
in
past
discussions,
some
manufacturers
have
indicated
that
it
is
possible
for
the
maximum
test
speed
to
be
unrepresentative
of
in­
use
operation.
Since
we
were
aware
of
this
potential
during
the
original
development
of
this
definition,
we
included
provisions
to
address
issues
such
as
these.
Part
1065
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
(
see
regulations
at
40
CFR
1065.10
(
c)).

3.
Improvements
to
the
Test
Procedures
As
we
proposed,
we
are
making
changes
to
the
test
procedures
to
improve
the
precision
of
emission
measurements.
These
changes
address
the
potential
effect
of
measurement
precision
on
the
feasibility
of
the
standards.
It
is
important
to
note
that
these
changes
are
not
intended
to
bias
results
high
or
low,
but
only
to
improve
the
precision
of
the
measurements.
Based
on
our
experience
with
these
modified
test
procedures,
and
our
discussions
with
manufacturers
about
their
experiences,
we
are
confident
that
these
changes
will
not
affect
the
stringency
of
the
standards.
These
changes
are
summarized
briefly
here.
The
rationale
for
the
changes
are
discussed
in
detail
elsewhere.
The
changes
affecting
Constant
Volume
Sampling
(
CVS)
and
PM
testing
are
discussed
in
a
memo
to
the
docket
(
Air
Docket
A­
99­
06,
IV­
B­
11),
which
was
originally
submitted
in
support
of
the
recent
highway
heavy­
duty
diesel
engine
rule
(
66
FR
5001,
January
18,
2001).

In
general,
we
are
applying
the
highway
heavy­
duty
engine
test
procedures
to
nonroad
CI
engines
in
this
rulemaking.
Many
of
the
specific
changes
being
adopted
are
to
the
PM
sampling
procedures.
The
PM
procedures
are
the
procedures
finalized
as
part
of
the
highway
heavy­
duty
diesel
engine
rule
(
66
FR
5001,
January
18,
2001).
These
include
changes
to
the
type
of
PM
filters
that
are
used
and
improvements
in
how
PM
filters
are
weighed
before
and
after
emission
measurements,
including
requirements
for
more
precise
microbalances.

It
is
also
worth
noting
that
we
intend
to
make
additional
improvements
to
the
test
procedures
in
a
separate
rulemaking
that
will
be
proposed
later
this
year
to
incorporate
the
latest
162
measurement
technologies.
Many
of
the
improvements
being
considered
were
discussed
in
the
previously­
mentioned
memo
to
the
docket
(
Air
Docket
A­
99­
06,
IV­
B­
11).
We
recognize
the
importance
of
these
improvements
for
use
in
testing
by
nonroad
diesel
engine
manufacturers
and
EPA.
However,
since
we
expect
that
the
changes
would
also
apply
to
many
nonroad
sparkignition
engine
manufacturers,
it
is
appropriate
to
conduct
a
separate
notice
and
comment
rulemaking
for
all
affected
parties.
We
remain
committed
to
incorporating
appropriate
additional
improvements
to
the
test
procedures.
We
have
placed
into
the
docket
a
draft
revised
version
of
part
1065
that
represents
our
current
thinking
on
appropriate
testing
regulations.

H.
Engine
Power
Currently,
rated
power
and
power
rating
are
undefined,
and
we
are
concerned
that
this
makes
the
applicability
of
the
standards
too
subjective
and
confusing.
One
manufacturer
may
choose
to
define
rated
power
as
the
maximum
measured
power
output,
while
another
may
define
it
as
the
maximum
measured
power
at
a
specific
engine
speed.
Using
this
second
approach,
an
engine's
rated
power
may
be
somewhat
less
than
the
true
maximum
power
output
of
the
engine.
Given
the
importance
of
engine
power
in
defining
which
standards
an
engine
must
meet
and
when,
we
believe
that
it
is
critical
that
a
singular
power
value
be
determined
objectively
according
to
a
specific
regulatory
definition.

To
address
this,
we
proposed
to
add
a
definition
of
"
maximum
engine
power"
to
the
regulations.
This
term
was
to
be
used
instead
of
previously
undefined
terms
such
as
"
rated
power"
or
"
power
rating"
to
specify
the
applicability
of
the
standards.
The
addition
of
this
definition
was
intended
to
allow
for
more
objective
applicability
of
the
standards.
More
specifically,
we
proposed
that:

Maximum
engine
power
means
the
measured
maximum
brake
power
output
of
an
engine.
The
maximum
engine
power
of
an
engine
configuration
is
the
average
maximum
engine
power
of
the
engines
within
the
configuration.
The
maximum
engine
power
of
an
engine
family
is
the
highest
maximum
engine
power
of
the
engines
within
the
family.

During
the
comment
period,
manufacturers
opposed
the
proposed
definition.
(
We
received
no
other
comments
on
this
issue.)
The
manufacturers
correctly
pointed
out
that
they
cannot
know
the
average
actual
power
of
production
engines
when
they
certify
an
engine
family,
because
certification
typically
occurs
before
production
begins.
Therefore
the
definition
of
"
maximum
engine
power"
being
finalized
today
relies
primarily
upon
the
manufacturer's
design
specifications
and
the
maximum
torque
curve
that
the
manufacturer
expects
to
represent
the
actual
production
engines.
This
provision
is
specified
in
a
new
section
40
CFR
1039.140.
Under
this
approach
the
manufacturer
would
take
the
torque
curve
that
is
projected
for
an
engine
configuration,
based
on
the
manufacturer's
design
and
production
specifications,
and
convert
it
into
a
"
nominal
power
curve"
that
would
relate
the
maximum
power
that
would
be
expected
to
engine
speed
when
a
production
engine
is
mapped
according
our
specified
mapping
procedures.
84
Auxiliary
emission
control
device
is
defined
at
40
CFR
89.2
as
"
any
element
of
design
that
senses
temperature,
vehicle
speed,
engine
RPM,
transmission
gear,
or
any
other
parameter
for
the
purpose
of
activating,
modulating,
delaying
or
deactivating
the
operation
of
any
part
of
the
emission
control
163
The
maximum
engine
power
is
being
defined
as
the
maximum
power
point
on
that
nominal
power
curve.

Manufacturers
will
be
required
to
report
the
maximum
engine
power
of
each
configuration
in
their
applications
for
certification.
As
with
other
engine
parameters,
manufacturers
will
be
required
to
ensure
that
the
engines
that
they
produce
under
the
certificate
have
maximum
engine
power
consistent
with
those
described
in
their
applications.
However,
since
we
recognize
that
variability
is
a
normal
part
of
engine
production,
we
will
not
require
that
all
production
engines
have
exactly
the
power
specified
in
the
application.
Instead,
we
will
only
require
that
the
power
specified
in
the
application
be
within
the
normal
range
of
powers
of
the
production
engines.
Typically,
we
would
expect
the
specified
power
to
be
within
one
standard
deviation
of
the
mean
power
of
the
production
engines.
If
a
manufacturer
determines
that
the
specified
power
is
outside
of
the
normal
range,
we
may
require
the
manufacturer
to
change
the
settings
of
the
engines
being
produced
and/
or
amend
the
application
for
certification.
In
deciding
whether
to
require
such
amendment,
we
would
consider
the
degree
to
which
the
specified
power
differed
from
the
production
engines,
the
normal
power
variability
for
those
engines,
whether
the
engine
used
or
generated
emission
credits,
and
whether
the
error
affected
which
standards
applied
to
the
engine.

The
preceding
discussion
presumes
that
each
manufacturer
will
develop
its
production
processes
to
produce
the
engines
described
in
the
application.
If
a
manufacturer
were
to
intentionally
produce
engines
different
than
those
described
in
the
application,
we
would
consider
the
application
to
be
fraudulent,
and
could
void
the
certificate
ab
initio
for
those
engines.
For
example,
for
engines
that
use
emission
credits,
this
could
occur
if
a
manufacturer
deliberately
biased
its
production
variability
so
that
the
engines
have
higher
average
power
than
described
in
the
application.
If
we
voided
the
certificate
for
those
engines
the
manufacturer
would
be
subject
to
large
fines
and
any
other
appropriate
enforcement
provisions
for
each
engine.

Finally,
in
light
of
some
of
the
comments
that
we
received,
it
is
worth
clarifying
that
the
maximum
engine
power
will
not
be
used
during
engine
testing.
It
is
only
used
to
define
power
categories
and
calculate
ABT
emission
credits.

I.
Auxiliary
Emission
Control
Devices
and
Defeat
Devices
Existing
nonroad
regulations
prohibit
the
use
of
a
defeat
device
(
see
40
CFR
89.107)
in
nonroad
diesel
engines.
The
defeat
device
prohibition
is
intended
to
ensure
that
engine
manufacturers
do
not
use
auxiliary
emission
control
devices
(
AECD)
which
sense
engine
operation
in
a
regulatory
test
procedure
and
as
a
result
reduce
the
emission
control
effectiveness
of
that
procedure.
84
In
today's
notice
we
are
supplementing
existing
nonroad
test
procedures
system."

85
40
CFR
89.107(
b)(
1)
states
"
Defeat
device
includes
any
auxiliary
emission
control
device
(
AECD)
that
reduces
the
effectiveness
of
the
emission
control
system
under
conditions
which
may
reasonably
be
expected
to
be
encountered
in
normal
operation
and
use
unless
such
conditions
are
included
in
the
test
procedure."

164
with
a
transient
engine
test
cycle
and
NTE
emission
standards
with
associated
test
requirements.
As
such,
the
Agency
believes
that
a
clarification
of
the
existing
nonroad
diesel
engine
regulations
regarding
defeat
devices
is
required
in
light
of
these
additional
emission
test
requirements.
The
defeat
device
prohibition
makes
it
clear
that
AECDs
which
reduce
the
effectiveness
of
the
emission
control
system
are
defeat
devices,
unless
one
of
several
conditions
is
met.
One
of
these
conditions
is
that
an
AECD
which
operates
under
conditions
"
included
in
the
test
procedure"
is
not
a
defeat
device.
85
While
the
existing
defeat
device
definition
does
contain
the
term
"
test
procedure,"
and
therefore
should
be
interpreted
as
including
the
supplemental
testing
requirements,
we
want
to
make
it
clear
that
both
the
supplemental
transient
test
cycle
and
NTE
emission
test
procedures
are
included
within
the
defeat
device
regulations
as
conditions
under
which
an
operational
AECD
will
not
be
considered
a
defeat
device.
Therefore,
we
are
clarifying
the
defeat
device
regulations
by
specifying
the
appropriate
test
procedures
(
i.
e.,
the
existing
steady­
state
procedures
and
the
supplemental
tests).
We
are
clarifying
the
engine
manufacturers
certification
reporting
requirements
with
respect
to
the
description
of
AECDs.
Under
the
previous
nonroad
engine
regulations,
manufacturers
are
required
to
provide
a
generalized
description
of
how
the
emissions
control
system
operates
and
a
"
detailed"
description
of
each
AECD
installed
on
the
engine
(
see
40
CFR
89.115(
d)(
2)).
This
change
clarifies
what
is
meant
by
"
detailed."

For
engines
rated
above
750
horsepower,
the
expanded
interpretation
of
"
included
in
the
test
cycle"
extends
only
to
the
NTE
because
we
are
not
requiring
these
engine
to
be
tested
over
the
supplemental
transient
test
cycle.
Transient
emissions
control
strategies
that
are
substantially
included
in
the
NTE
will
be
considered
to
comply
with
the
defeat
device
criteria.
For
instances
where
transient
emissions
control
strategies
are
not
well
represented
over
the
official
test
requirements,
we
will
rely
on
the
defeat
device
provisions
to
ensure
appropriate
transient
off­
cycle
emissions
control.
The
defeat
device
provisions
restrict
the
ability
of
manufacturers
to
reduce
the
level
of
emissions
control
during
transient
operation
compared
to
that
employed
over
the
steady
state
cycle.
In
order
to
evaluate
transient
emissions
control
strategies
for
compliance
with
the
defeat
device
provisions,
we
are
requiring
manufacturers
to
submit
information
which
indicates
how
transient
emissions
are
controlled
during
normal
operation
and
use.
Information
that
would
adequately
fulfill
this
requirement
includes
but
is
not
limited
to:

A.
Emissions
data
gathered
with
portable
emissions
measurement
systems
from
inservice
engines
operating
over
a
broad
range
of
typical
transient
conditions;
86
Base
emissions
control
maps
describe
the
modulation
of
an
emissions
control
parameter
as
a
function
of
changing
engine
speed
and
torque.

165
B.
Emissions
data
generated
under
laboratory
conditions
representing
a
broad
range
of
typical
transient
operation;
C.
Transient
test
cycle
results
from
certified
engines
rated
at
or
below
750
horsepower
which
share
nearly
identical
transient
emissions
control
strategies;
D.
Base
emissions
control
maps
along
with
an
explanation
for
differences
in
control
between
portions
of
the
map
substantially
included
in
the
steady­
state
test
cycle
and
that
which
is
predominately
associated
with
transient
operation;
86
E.
A
comparative
analysis
of
the
base
emissions
control
maps
from
certified
engines
rated
at
or
below
750
horsepower
and
those
rated
over
750
horsepower.

We
will
use
this
information
to
determine
the
degree
to
which
the
design
and
effectiveness
of
the
transient
emissions
control
system
compares
to
the
control
demonstrated
over
the
steadystate
cycle
as
well
as
the
transient
control
used
for
certified
engines
at
or
below
750
horsepower
where
compliance
over
the
transient
cycle
is
required.

A
thorough
disclosure
of
the
presence
and
purpose
of
AECDs
is
essential
in
allowing
EPA
to
evaluate
the
AECD
and
determine
whether
it
represents
a
defeat
device.
Clearly,
any
AECD
which
is
not
fully
identified
in
the
manufacturer's
application
for
certification
cannot
be
appropriately
evaluated
by
EPA
and
therefore
cannot
be
determined
to
be
acceptable
by
EPA.
Our
clarifications
to
the
certification
application
requirements
include
additional
detail
specific
to
those
AECDs
which
the
manufacturer
believes
are
necessary
to
protect
the
engine
or
the
equipment
in
which
it
is
installed
against
damage
or
accident
("
engine
protection"
AECDs).
While
the
definition
of
a
defeat
device
allows
as
an
exception
strategies
needed
to
protect
the
engine
and
equipment
against
damage
or
accident,
we
intend
to
continue
our
policy
of
closely
reviewing
the
use
of
this
exception.
In
evaluating
whether
a
reduction
in
emissions
control
effectiveness
is
needed
for
engine
protection,
EPA
will
closely
evaluate
the
actual
technology
employed
on
the
engine
family,
as
well
as
the
use
and
availability
of
other
emission
control
technologies
across
the
industry,
taking
into
consideration
how
widespread
the
use
is,
including
its
use
in
similar
engines
and
similar
equipment.
While
we
have
specified
additional
information
related
to
engine
protection
AECDs
in
the
regulations,
we
reserve
the
right
to
request
additional
information
on
a
case­
by­
case
basis
as
necessary.

In
the
last
several
years,
EPA
has
issued
extensive
guidance
on
the
disclosure
of
AECDs
for
both
highway
and
nonroad
diesel
engine
manufactures.
These
provisions
do
not
impose
any
new
certification
burden
on
engine
manufacturers,
rather,
it
clarifies
the
existing
certification
application
regulations
by
specifying
what
type
of
information
manufacturers
must
submit
regarding
AECDs.

Finally,
we
take
this
opportunity
to
emphasize
that
the
information
submitted
must
be
specific
to
each
engine
family.
The
practice
of
describing
AECDs
in
a
"
common"
section,
87
Torque
is
a
measure
of
rotational
force.
The
torque
curve
for
an
engine
is
determined
by
an
engine
"
mapping"
procedure
specified
in
the
Code
of
Federal
Regulations.
The
intent
of
the
mapping
procedure
is
to
determine
the
maximum
available
torque
at
all
engine
speeds.
The
torque
curve
is
merely
a
graphical
representation
of
the
maximum
torque
across
all
engine
speeds.

166
wherein
the
strategies
are
described
in
general
for
all
the
manufacturer's
engines,
is
acceptable
as
long
as
each
engine
family's
application
contains
specific
references
to
the
AECDs
in
the
common
section
which
clearly
indicate
which
AECDs
are
present
on
that
engine
family,
and
the
application
contains
specific
calibration
information
for
that
engine
family's
AECDs.
The
regulatory
requirements
can
be
found
at
40
CFR
89.115(
d)(
2)
in
today's
notice.

J.
Not­
To­
Exceed
Requirements
In
today's
action
we
are
finalizing
not­
to­
exceed
(
NTE)
emission
standards
for
all
new
nonroad
diesel
engines
subject
to
the
Tier
4
emissions
standards
beginning
in
2011.
These
NTE
standards
and
requirements
are
largely
identical
to
the
NTE
provisions
we
proposed,
except
as
noted
below.

The
NTE
standards
and
test
procedures
are
being
finalized
to
help
ensure
that
nonroad
diesel
emissions
are
controlled
over
the
wide
range
of
speed
and
load
combinations
commonly
experienced
in­
use.
EPA
has
similar
NTE
standards
for
highway
heavy­
duty
diesel
engines,
compression
ignition
marine
engines,
and
nonroad
spark­
ignition
engines.
The
NTE
requirements
supplement
the
existing
steady­
state
test
as
well
as
the
new
transient
test
which
is
also
being
finalized
today.

The
NTE
standards
and
test
procedures
which
we
proposed,
and
which
we
are
finalizing,
are
derived
from
similar
NTE
standards
and
test
procedures
which
EPA
adopted
for
highway
heavy­
duty
diesel
engines.
In
the
proposal,
we
requested
comment
on
an
alternative
NTE
test
procedure
approach
(
see
68
FR
28369,
May
23,
2003).
As
discussed
in
the
proposal,
the
two
NTE
approaches
would
result
in
the
same
overall
level
of
emission
control,
but
the
implementation
of
each
approach
from
an
in­
use
measurement
and
data
gathering
perspective
are
quite
different.
We
have
decided
not
to
finalize
this
alternative
approach.
This
decision
is
based
primarily
on
our
belief
that
nonroad
engine
manufacturers
will
more
easily
transfer
the
knowledge
and
experience
gained
from
the
highway
NTE
implementation
(
which
begins
in
2007)
to
the
nonroad
program
if
the
two
programs
have
similar
requirements.
For
additional
discussion
regarding
our
decision
to
not
finalize
the
alternative
approach,
please
see
the
Summary
and
Analysis
of
Comments.

The
NTE
requirements
establish
an
area
(
the
"
NTE
zone"
or
"
NTE
control
area")
under
the
torque
curve
of
an
engine
where
emissions
must
not
exceed
a
specified
value
for
any
of
the
regulated
pollutants.
87
An
illustrative
NTE
zone
is
shown
in
Figure
III.
J­
1.
167
Figure
III.
J­
1:
Example
NTE
Control
Area
Note:
PM
Carve­
Out
region
only
applies
for
engines
with
a
PM
standard
or
FEL
greater
than
or
equal
to
0.05
g/
bhp­
hr
The
NTE
standard
applies
during
any
conditions
that
could
reasonably
be
expected
to
be
seen
by
that
engine
in
normal
operation
and
use,
within
certain
broad
ranges
of
real
ambient
conditions.
The
NTE
requirements
will
help
to
ensure
emission
benefits
over
the
full
range
of
in­
use
operating
conditions.
The
NTE
being
finalized
today
for
nonroad
contains
the
same
basic
provisions
as
the
highway
NTE.
This
NTE
control
area
is
defined
in
the
same
manner
as
the
highway
NTE
control
area,
and
is
therefore
a
subset
of
the
engine's
possible
speed
and
load
operating
range.
The
NTE
standard
applies
to
emissions
sampled
during
a
time
duration
as
small
as
30
seconds.
The
NTE
standard
requirements
for
nonroad
diesel
engines
are
summarized
below
and
specified
in
the
regulations
at
40
CFR
1039.101
and
40
CFR
1039.515.
These
requirements
will
take
effect
as
early
as
2011,
as
shown
in
shown
in
table
III.
J­
1.
The
NTE
standard
applies
to
engines
at
the
time
of
certification
as
well
as
in
use
throughout
the
useful
life
of
the
engine.
168
Table
III.
J­
1.
 
NTE
Standard
Implementation
Schedule
Power
Category
NTE
Implementation
Model
Yeara
<
25
hp
2013
25­
75
hp
2013b
75­
175
hp
2012
175­
750
hp
2011
>
750
hp
2011
Notes:

a
The
NTE
applies
for
each
power
category
once
Tier
4
standards
are
implemented,

such
that
all
engines
in
a
given
power
category
are
required
to
meet
NTE
standards.

b
The
NTE
standard
would
apply
in
2012
for
any
engines
in
the
50­
75
hp
range
which
choose
not
to
comply
with
the
proposed
2008
transitional
PM
standard.

The
NTE
test
procedure
can
be
run
in
nonroad
equipment
during
field
operation
or
in
an
emissions
testing
laboratory
using
an
appropriate
dynamometer.
The
test
itself
does
not
involve
a
specific
operating
cycle
of
any
specific
length;
rather,
it
involves
nonroad
equipment
operation
of
any
type
which
could
reasonably
be
expected
to
occur
in
normal
nonroad
equipment
operation
that
could
occur
within
the
bounds
of
the
NTE
control
area.
The
nonroad
engine
is
operated
under
conditions
that
may
reasonably
be
expected
to
be
encountered
in
normal
operation
and
use,
including
operation
under
steady­
state
or
transient
conditions
and
under
varying
ambient
conditions.
Emissions
are
averaged
over
a
minimum
time
of
thirty
seconds
and
then
compared
to
the
applicable
emission
standard.
The
NTE
standard
applies
over
a
wide
range
of
ambient
conditions,
including
up
to
an
altitude
of
5,500
feet
above­
sea
level
at
ambient
temperatures
as
high
as
86
deg.
F,
and
at
sea­
level
up
to
ambient
temperatures
as
high
as
100
deg.
F.
The
specific
temperature
and
altitude
conditions
under
which
the
NTE
applies,
as
well
as
the
methodology
for
correcting
emissions
results
for
temperature
and/
or
humidity,
are
specified
in
the
regulations.

For
new
nonroad
diesel
engines
subject
to
the
NTE
standards,
we
will
require
that
manufacturers
state
in
their
application
for
certification
that
they
are
able
to
meet
the
NTE
standards
under
all
conditions
that
may
reasonably
be
expected
to
occur
in
normal
equipment
operation
and
use.
Manufacturers
will
have
to
maintain
a
detailed
description
of
any
testing,
engineering
analysis,
and
other
information
that
forms
the
basis
for
their
statement.
We
believe
that
there
is
a
variety
of
information
that
a
manufacturer
could
use
as
a
reasonable
basis
for
a
statement
that
engines
are
expected
to
meet
NTE
standards.
For
example,
a
reasonable
basis
could
include
data
from
laboratory
steady­
state
and
transient
test
cycle
operation,
a
robust
engine
emissions
map
derived
from
laboratory
testing
(
e.
g.,
an
emissions
map
of
similar
resolution
to
the
engine's
base
fuel
injection
timing
map)
and
technical
analysis
relying
on
good
engineering
judgment
which
are
sufficient,
in
combination,
to
project
emissions
levels
under
NTE
conditions
169
reasonably
expected
to
be
encountered
in
normal
operation
and
use.
Data
generated
from
in­
use
nonroad
equipment
testing
to
determine
emission
levels
could,
at
the
manufacturer's
option,
also
be
part
of
this
combination.
However,
a
reasonable
basis
for
the
manufacturer's
statement
does
not
require
in­
use
emissions
test
data.
This
statement
could
reasonably
be
based
solely
on
laboratory
test
data,
analysis,
and
other
information
reasonably
sufficient
to
support
a
conclusion
that
the
engine
will
meet
the
NTE
under
conditions
reasonably
expected
to
be
encountered
in
normal
vehicle
operation
and
use.
If
a
manufacturer
has
relevant
in­
use
nonroad
emissions
test
data,
it
should
be
taken
into
consideration
by
the
manufacturer
in
developing
the
basis
for
its
statement.

In
addition,
as
we
proposed,
we
are
finalizing
a
transition
period
during
which
a
manufacturer
could
apply
for
an
NTE
deficiency
for
a
nonroad
diesel
engine
family.
The
NTE
deficiency
provisions
would
allow
the
Administrator
to
accept
a
nonroad
diesel
engine
as
compliant
with
the
NTE
standards
even
though
some
specific
requirements
are
not
fully
met.
We
are
finalizing
these
NTE
deficiency
provisions
because
we
believe
that,
despite
the
best
efforts
of
manufacturers,
for
the
first
few
model
years
it
is
possible
some
manufacturers
may
have
technical
problems
that
are
limited
in
nature
but
cannot
be
remedied
in
time
to
meet
production
schedules.
We
are
not
limiting
the
number
of
NTE
deficiencies
a
manufacturer
can
apply
for
during
the
first
three
model
years
for
which
the
NTE
applies.
For
the
fourth
through
the
seventh
model
year
after
which
the
NTE
standards
are
implemented,
a
manufacturer
could
apply
for
no
more
than
three
NTE
deficiencies
per
engine
family.
Within
an
engine
family,
NTE
deficiencies
must
be
applied
for
on
an
engine
model
or
power
rating
basis;
however,
the
same
deficiency
when
applied
to
multiple
ratings
or
models
counts
as
a
single
deficiency
within
an
engine
family.
No
deficiency
may
be
applied
for
or
granted
after
the
seventh
model
year.
The
NTE
deficiency
provision
will
only
be
considered
for
failures
to
meet
the
NTE
requirements.
EPA
will
not
consider
an
application
for
a
deficiency
for
failure
to
meet
the
FTP
or
supplemental
transient
standards.

Similar
to
the
2007
highway
HD
rule,
we
are
also
finalizing
a
provision
which
would
allow
a
manufacturer
to
exclude
defined
regions
of
the
NTE
engine
control
zone
from
NTE
compliance
if
the
manufacturer
could
demonstrate
that
the
engine,
when
installed
in
a
specified
nonroad
equipment
applications(
s),
is
not
capable
of
operating
in
such
regions.
We
have
also
finalized
a
provision
which
would
allow
a
manufacturer
to
petition
the
Agency
to
limit
testing
in
a
defined
region
of
the
NTE
engine
control
zone
during
NTE
testing.
This
optional
provision
would
require
the
manufacturer
to
provide
the
Agency
with
in­
use
operation
data
which
the
manufacturer
could
use
to
define
a
single,
continuous
region
of
the
NTE
control
zone.
This
single
area
of
the
control
zone
must
be
specified
such
that
operation
within
the
defined
region
accounts
for
5
percent
or
less
of
the
total
in­
use
operation
of
the
engine,
based
on
the
supplied
data.
Further,
to
protect
against
"
gaming"
by
manufacturers,
the
defined
region
must
generally
be
elliptical
or
rectangular
in
shape,
and
share
a
boundary
with
the
NTE
control
zone.
If
approved
by
EPA,
the
regulations
then
disallow
testing
with
sampling
periods
in
which
operation
within
the
defined
region
constitutes
more
than
5.0
percent
of
the
time­
weighted
operation
within
the
sampling
period.
170
The
NTE
numerical
standard
is
a
function
of
FTP
emission
standards
contained
in
today's
final
rule,
which
standards
are
described
in
section
II.
As
with
the
NTE
standards
we
have
established
for
the
2007
highway
rule,
the
nonroad
NTE
standard
is
determined
as
a
multiple
of
the
engine
families'
underlying
FTP
emission
standard.
In
addition,
as
with
the
2007
highway
standard,
the
multiple
is
either
1.25
or
1.5,
depending
on
the
emission
pollutant
type
and
the
value
of
the
FTP
standard
(
or
the
engine
families'
FEL).
These
multipliers
are
based
on
EPA's
assessment
of
the
technological
feasibility
of
the
NTE
standard,
and
our
assessment
that
as
the
underlying
FTP
standard
becomes
more
stringent,
the
NTE
multiplier
should
increase
(
from
1.25
to
1.5).
The
FTP
standard
or
FEL
thresholds
for
the
NTE
standard's
1.25x
multiplier
and
the
1.5x
multiplier
are
specified
for
each
regulated
emission
in
table
III.
J­
2.

Table
III.
J­
2.
 
Thresholds
for
Applying
NTE
Standard
of
1.25xFTP
standard
vs.
1.5x
FTP
Standard
Emission
Apply
1.25x
NTE
when...
Apply
1.5x
when...

NOX
NOX
std
or
FEL

1.9
g/
bhp­
hr
NOX
std
or
FEL<
1.9
g/
bhp­
hr
NMHC
NOX
std
or
FEL

1.9
g/
bhp­
hr
NOX
std
or
FEL<
1.9
g/
bhp­
hr
NOX+
NMHC
NMHC+
NOX
std
or
FEL

2.0
g/
bhp­
hr
NMHC+
NOX
std
or
FEL<
2.0
g/
bhp­
hr
PM
PM
std
or
FEL

0.05
g/
bhp­
hr
PM
std
or
FEL<
0.05
g/
bhp­
hr
CO
All
stds
or
FELs
No
stds
or
FELs
For
example,
beginning
in
2011,
the
NTE
standard
for
engines
meeting
a
FTP
PM
standard
of
0.01
g/
bhp­
hr
and
a
FTP
NO
X
standard
of
0.30
g/
bhp­
hr
would
be
0.02
g/
bhp­
hr
PM
and
0.45
g/
bhp­
hr
NO
X.
In
the
NPRM,
we
proposed
a
NO
X
threshold
value
of
1.5
g/
bhp­
hr
as
the
value
at
which
the
NTE
multiplier
would
switch
from
1.5
to
1.25.

We
proposed
this
NO
X
emission
threshold
level
(
1.5
g/
bhp­
hr)
primarily
because
it
is
the
same
value
as
we
finalized
for
the
highway
NTE.
As
shown
in
table
III.
J­
2,
we
have
finalized
a
threshold
value
of
1.9
g/
bhp­
hr
NO
X
for
nonroad
engines.
We
have
finalized
this
higher
NO
X
threshold
based
on
the
differences
in
the
emission
performance
of
NO
X
control
technologies
between
highway
and
nonroad
diesel
engines.
Specifically,
nonroad
diesel
NO
X
standards
have
traditionally
been
higher
than
the
equivalent
highway
NO
X
standard
due
primarily
to
the
effectiveness
of
charge­
air­
cooling
and
the
lack
of
ram­
air
for
nonroad
applications.
For
example,
the
nonroad
Tier
3
NMHC+
NO
X
standards
are
higher
than
the
2004
heavy­
duty
highway
standards
(
e.
g.,
3.0
g/
bhp­
hr
vs.
2.5
g/
bhp­
hr),
and
the
Tier
4
NO
X
standard
is
higher
than
the
2007
heavy­
duty
highway
standard
(
e.
g.,
0.3
g/
bhp­
hr
vs.
0.2
g/
bhp­
hr).
We
expect
that
the
nonroad
Tier
3
standard
for
engines
above
100
hp
will
require
NO
X
levels
of
approximately
2.5
g/
bhp­
hr
and
we
expect
that
for
the
2004
highway
heavy­
duty
standards,
NO
X
levels
are
approximately
2
g/
bhp­
hr.
In
both
cases,
these
emission
levels
are
the
building
blocks
for
the
next
set
of
EPA
standards
(
e.
g.,
Tier
4
for
nonroad
and
2007
for
highway).
Because
the
nonroad
Tier
171
3
NO
X
emission
levels
are
expected
to
be
approximately
25
percent
greater
than
the
2004
highway
level
(
2.5
vs
2),
we
believe
that
the
NTE
NO
X
multiplier
threshold
for
nonroad
should
be
25
percent
greater
for
nonroad
as
compared
to
highway.
For
these
reasons,
we
have
finalized
a
NO
X
multiplier
threshold
of
1.9
g/
bhp­
hr,
which
is
25
percent
greater
than
the
highway
multiplier
threshold.

In
addition,
as
proposed,
we
are
finalizing
a
number
of
specific
engine
operating
conditions
during
which
the
nonroad
NTE
standard
would
not
apply.
The
exact
criteria
for
these
conditions
are
defined
in
the
regulations,
but
in
summary:
the
NTE
does
not
apply
during
engine
start­
up
conditions;
the
NTE
does
not
apply
during
very
cold
engine
intake
air
temperatures
for
EGR­
equipped
engines
during
which
the
engine
may
require
an
engine
protection
strategy;
and,
finally,
for
engines
equipped
with
NO
X
and/
or
NMHC
aftertreatment
(
such
as
a
NO
X
adsorber),
the
NTE
does
not
apply
during
warm­
up
conditions
for
the
exhaust
emission
control
device.
Finally,
while
we
did
not
propose
this,
we
are
finalizing
the
NTE
PM
carve­
out
provisions
for
engines
which
will
not
require
PM
filters.
The
PM
only
carve­
out
is
a
sub­
region
of
the
NTE
zone
in
which
the
NTE
PM
standard
does
not
apply.
Figure
III.
J­
1
contains
an
illustration
of
the
PM
carve­
out.
This
is
a
region
of
high
engine
speed
and
low
engine
torque
during
which
engineout
PM
emissions
are
difficult
to
control
to
levels
below
the
PM
NTE
standard.
The
dimensions
of
the
PM
carve­
out
are
specified
in
the
regulations.
For
engines
equipped
with
a
PM
filter,
compliance
with
the
PM
NTE
standard
in
this
region
is
achievable
due
to
the
highly
efficient
PM
reduction
capabilities
of
the
CDPF
technology.
However,
for
engines
in
the
under
25
hp
category,
for
which
we
have
established
Tier
4
emission
standards
that
do
not
require
the
use
of
a
PM
filter,
PM
control
in
this
sub­
region
of
the
NTE
zone
with
conventional
PM
reduction
technologies
may
not
be
achievable.
Therefore,
as
we
allowed
with
highway
heavy­
duty
engines
certifying
to
the
0.1
g/
bhp­
hr
standard,
we
have
created
a
PM
carve­
out
for
nonroad
engines
that
use
in­
cylinder
PM
control
technologies.
Specifically,
the
PM
carve­
out
applies
to
engines
meeting
a
PM
standard
or
FEL
greater
than
or
equal
to
0.05
g/
bhp­
hr.

K.
Investigating
and
Reporting
Emission­
Related
Defects
In
40
CFR
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.
Under
these
defect­
reporting
requirements,
manufacturers
must
track
available
warranty
claims
and
any
other
available
information
from
dealers,
hotlines,
diagnostic
reports,
or
fieldservice
personnel
to
identify
possible
defects.
If
the
number
of
possible
defects
exceeds
certain
thresholds,
they
must
investigate
future
warranty
claims
and
other
information
to
establish
whether
these
are
actual
defects.

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
for
systems
or
parts
that
may
have
an
impact
on
emissions.
In
the
past,
defect
reports
were
submitted
based
on
a
very
low
threshold
with
the
same
threshold
applicable
to
all
size
engine
172
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
new
approach
may
trigger
some
additional
reports
for
small­
volume
families,
but
the
percentage­
based
approach
will
ensures
that
investigations
and
reports
correspond
to
issues
that
are
likely
to
be
significant.

Part
1068,
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
possible
emission­
related
defects
as
the
requirements
of
40
CFR
1068.501.
Thus
manufacturers
will
have
the
flexibility
to
develop
defect
tracking
and
reporting
programs
that
work
better
for
their
standard
business
practices.
However,
until
we
approve
such
a
request,
the
thresholds
and
procedures
of
subpart
F
continue
to
apply.

Manufacturers
may
also
ask
for
our
approval
to
use
an
alternate
defect­
reporting
methodology
when
the
requirements
of
40
CFR
1068.501
can
be
demonstrated
to
be
highly
impractical
or
unduly
burdensome.
In
such
cases,
we
will
generally
allow
alternate
methodologies
that
are
at
least
as
effective
in
identifying,
correcting,
and
informing
EPA
of
possible
emissionrelated
defects
as
the
requirements
of
40
CFR
1068.501.
We
expect
this
flexibility
to
be
useful
in
special
circumstances
such
as
when
new
models
of
very
large
engines
are
introduced
for
the
first
time.
In
this
situation,
it
may
be
appropriate
to
allow
an
alternate
defect
reporting
method
because
the
high
cost
of
these
engines
often
makes
it
impractical
to
build
and
test
large
numbers
of
prototype
engines.
The
initial
production
of
these
engines
can
have
similar
defect
rates
to
the
high
levels
often
associated
with
prototype
engines.
While
we
are
concerned
about
such
defects
and
want
to
be
kept
informed
about
them,
it
is
not
clear
that
our
basic
program
would
be
the
best
way
to
address
these
defects.
In
such
cases,
we
believe
it
may
be
more
appropriate
for
manufacturers
to
propose
an
alternative
approach
that
consolidates
reports
on
a
regular
interval,
such
as
quarterly,
and
identifies
obvious
early­
life
defects
without
a
formal
tracking
process.
In
general,
we
would
encourage
manufacturers
to
propose
an
alternate
approach
to
ensure
that
these
defects
are
properly
addressed
while
minimizing
the
associated
burden.

Issues
related
to
parts
shipments
received
the
most
attention
from
commenters
who
pointed
out
that
the
proposed
requirement
to
track
shipments
of
all
emission­
related
components
was
overly
burdensome
and
not
likely
to
reveal
useful
information.
We
have
concluded
that
it
is
not
appropriate
to
use
parts
shipments
as
a
quantitative
indicator
to
evaluate
whether
manufacturers
exceed
the
threshold
that
would
trigger
an
investigation.
We
generally
agree
with
manufacturers
concerns
that
parts­
shipments
data
would
be
too
difficult
to
evaluate,
for
example,
because
parts
are
often
shipped
for
stocking
purposes,
parts
are
installed
in
compliant
and
noncompliant
products
(
such
as
exported
engines),
and
part
shipments
are
generally
not
identifiable
by
model
year.
The
final
rule
therefore
requires
manufacturers
to
pursue
a
defect
173
investigation
if
the
number
of
shipped
parts
is
higher
than
the
manufacturer
would
expect
based
on
historical
shipment
levels,
specifications
for
scheduled
maintenance,
or
other
factors.

We
have
modified
the
proposed
thresholds
to
address
concerns
that
manufacturers
would
be
required
to
investigate
and
report
defects
too
frequently.
For
engines
under
750
hp,
we
are
adopting
investigation
thresholds
of
10
percent
of
total
production
or
50
engines,
whichever
is
greater,
for
any
single
engine
family
in
one
model
year.
Similarly,
we
are
adopting
defectreporting
thresholds
of
2
percent
of
total
production
or
20
engines,
whichever
is
greater.
For
engines
over
750
hp,
the
same
percentage
thresholds
apply,
but
we
are
extending
the
percentage
values
down
to
smaller
engine
families
to
reflect
their
disproportionate
contribution
to
total
emissions.
For
these
engines,
the
absolute
thresholds
are
25
engines
for
investigations
and
10
or
15
engines
for
defects
(
see
table
III.
K­
1).
We
believe
these
thresholds
adequately
balance
the
desire
to
document
emission­
related
defects
without
imposing
an
unreasonable
reporting
burden.
Also,
we
believe
this
approach
to
adopting
thresholds
adequately
addresses
reporting
requirements
for
aftertreatment
and
non­
aftertreatment
components.

Table
III.
K­
1.
 
Investigation
and
Defect­
Reporting
Thresholds
for
Varying
Sizes
of
Engine
Families1
Engine
Size
Investigation
Threshold
Defect­
reporting
Threshold

750
hp
less
than
500:
50
500­
50,000:
10
%

50,000+:
5,000
less
than
1,000:
20
1,000­
50,000:
2
%

50,000+:
1,000
>
750
hp
less
than
250:
25
250+:
10
%
less
than
150:
10
150­
750:
15
750+:
2
%

Notes:

1
For
varying
sizes
of
engine
families,
based
on
sales
per
family
in
a
given
model
year.

EMA
also
expressed
concern
about
the
existing
regulatory
language
in
40
CFR
1068.501(
b)(
3),
which
states
that
manufacturers
must
"
consider
defects
that
occur
within
the
useful
life
period,
or
within
five
years
after
the
end
of
the
model
year,
whichever
is
longer."
However,
this
provision
has
no
effect
on
the
diesel
engines
subject
to
the
Tier
4
standards
being
adopted
today,
since
they
all
have
useful
lives
of
at
least
five
years.
We
recognize
that
this
issue
may
be
relevant
to
engine
categories
that
do
not
have
five­
year
useful
lives,
such
as
small
SI
engines,
and
will
consider
these
concerns
in
our
future
regulation
of
such
engines.
174
When
manufacturers
start
an
investigation,
they
must
consider
any
available
information
that
would
help
them
evaluate
whether
any
of
the
possible
defects
that
contributed
to
triggering
the
investigation
threshold
would
lead
them
to
conclude
that
these
were
actual
defects.
Otherwise,
manufacturers
are
expected
to
look
prospectively
at
any
possible
defects
and
attempt
to
determine
whether
these
are
actual
defects.
Also,
during
an
investigation,
manufacturers
should
use
appropriate
statistical
methods
to
project
defect
rates
if
they
are
unable
to
collect
information
to
evaluate
possible
defects,
taking
steps
as
necessary
to
prevent
bias
in
sampled
data
(
or
making
adjusted
calculations
to
take
into
account
any
bias
that
may
remain).
For
example,
if
75
percent
of
the
components
replaced
under
warranty
are
available
for
evaluation,
it
would
be
appropriate
to
extrapolate
known
information
on
failure
rates
to
the
components
that
are
unavailable
for
evaluation.

The
second
threshold
in
40
CFR
1068.501
specifies
when
a
manufacturer
must
report
that
there
is
an
emission­
related
defect.
This
threshold
involves
a
smaller
number
of
engines
because
each
possible
occurrence
has
been
screened
to
confirm
that
it
is
in
fact
an
emission­
related
defect.
In
counting
engines
to
compare
with
the
defect­
reporting
threshold,
the
manufacturer
generally
considers
a
single
engine
family
and
model
year.
Where
information
cannot
be
differentiated
by
engine
family
and
model
year,
the
manufacturer
must
use
good
engineering
judgment
to
evaluate
whether
the
information
leads
to
a
conclusion
that
the
number
of
defects
exceeds
the
applicable
thresholds.
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.

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
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.

If
manufacturers
trigger
the
threshold
to
start
an
investigation,
they
must
promptly
and
thoroughly
investigate
whether
their
parts
are
defective,
collecting
specific
information
to
prepare
a
report
describing
their
conclusions.
Manufacturers
must
send
the
report
if
an
investigation
concludes
that
the
number
of
actual
defects
did
not
exceed
reporting
thresholds.
Manufacturers
must
also
send
these
as
status
reports
twice
annually
during
an
investigation.
After
investigating
for
several
months,
or
perhaps
a
couple
years,
it
may
become
clear
that
the
problems
that
triggered
the
investigation
will
never
show
enough
actual
defects
to
trigger
a
defect
report.
In
this
case,
the
manufacturer
would
send
us
a
report
justifying
this
conclusion.
175
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.

Note
that
misbuilds
are
a
special
type
of
emission­
related
defect.
An
engine
that
is
not
built
consistent
with
its
application
for
certification
violates
the
prohibited
act
of
introducing
into
commerce
engines
that
are
not
covered
by
a
certificate
of
conformity.

L.
Compliance
with
the
Phase­
In
Provisions
In
section
II
we
described
the
NO
X
and
NMHC
standards
phase­
in
schedule,
which
is
intended
to
allow
engine
manufacturers
to
phase­
in
their
new
advanced
technology
engines,
while
they
phase­
out
existing
engines.
This
phase­
in
requirement
is
based
on
percentages
of
a
manufacturer's
production
for
the
U.
S.
market.
We
recognize,
however,
that
manufacturers
need
to
plan
for
compliance
well
in
advance
of
the
start
of
production,
and
that
actual
production
volumes
for
any
one
model
year
may
differ
from
their
projections.
On
the
other
hand,
we
believe
that
it
would
be
inappropriate
and
infeasible
to
base
compliance
solely
on
a
manufacturer's
projections.
That
could
encourage
manufacturers
to
overestimate
their
production
of
complying
phase­
in
engines,
and
could
result
in
significantly
lower
emission
benefits
during
the
phase­
in.
In
response
to
these
concerns,
we
proposed
to
initially
only
require
nonroad
diesel
manufacturers
to
project
compliance
with
the
phase­
in
based
on
their
projected
production
volumes,
provided
that
they
made
up
any
deficits
(
in
terms
of
percent
of
production)
the
following
year.
We
received
no
comments
on
this
issue
and
are
finalizing
it
as
proposed.

Because
we
expect
that
a
manufacturer
making
a
good­
faith
projection
of
sales
would
not
be
very
far
off
of
the
actual
production
volumes,
we
are
limiting
the
size
of
the
deficit
that
would
be
allowed,
as
in
the
highway
program.
In
all
cases,
the
manufacturer
would
be
required
to
produce
at
least
25%
of
its
production
in
each
phase­
in
power
category
as
"
phase­
in"
engines
(
meeting
the
NO
X
and
NMHC
standards
or
demonstrating
compliance
through
use
of
ABT
credits)
in
the
phase­
in
years
(
after
factoring
in
any
adjustments
for
early
introduction
engine
credits;
see
section
III.
M).
This
minimum
required
production
level
would
be
20%
for
the
75­
175
hp
category
if
a
manufacturer
exercises
the
option
to
comply
with
a
reduced
phase­
in
schedule
in
lieu
of
using
banked
Tier
2
ABT
credits,
as
discussed
in
section
III.
A.
1.
b.
Another
important
restriction
is
that
manufacturers
would
not
be
allowed
to
have
a
deficit
in
the
year
immediately
preceding
the
completion
of
the
phase­
in
to
100%.
This
would
help
ensure
that
manufacturers
are
able
to
make
up
the
deficit.
Since
they
could
not
produce
more
than
100%
low­
NO
X
engines
after
the
final
phase­
in
year,
it
would
not
be
possible
to
make
up
a
deficit
from
this
year.
These
provisions
are
identical
to
those
adopted
in
the
highway
HDDE
program.

We
are
also
finalizing
the
proposed
"
split
family"
allowance
for
the
phase­
in
years.
This
provision,
which
is
similar
to
a
provision
of
the
highway
program,
allows
manufacturers
to
certify
engine
families
to
both
the
phase­
in
and
phase­
out
standards.
Manufacturers
choosing
this
option
must
assign
at
the
end
of
the
model
year
specific
numbers
of
engines
to
the
phase­
in
and
phase­
out
176
categories.
All
engines
in
the
family
must
be
labeled
with
the
same
NO
X
and
PM
FELs,
which
apply
for
all
compliance
testing,
and
must
meet
all
other
requirements
that
apply
to
phase­
in
engines.
Engines
assigned
to
the
phase­
out
category
may
generate
emission
credits
relative
to
the
phase­
out
standards.

M.
Incentive
Program
for
Early
or
Very
Low
Emission
Engines
We
believe
that
it
is
appropriate
and
beneficial
to
provide
voluntary
incentives
for
manufacturers
to
introduce
engines
emitting
at
very
low
levels
early.
Such
inducements
may
help
pave
the
way
for
greater
and/
or
more
cost
effective
emission
reductions
from
future
engines
and
vehicles.
To
encourage
early
introduction
of
low­
emission
engines,
the
proposal
contained
provisions
to
allow
engine
manufacturers
to
benefit
from
producing
engines
certified
to
the
final
(
aftertreatment­
based)
Tier
4
standards
prior
to
the
2011
model
year,
by
being
allowed
to
make
fewer
engines
certified
to
these
standards
once
the
Tier
4
program
takes
effect,
a
concept
that
we
are
terming
"
engine
offsets"
to
avoid
confusion
with
ABT
program
credits.
The
number
of
offsets
that
could
be
generated
would
depend
on
the
degree
to
which
the
engines
are
able
to
meet,
or
perform
better
than,
the
final
Tier
4
standards.
Commenters
generally
supported
this
approach,
as
long
EPA
ensures
that
compliance
requirements
for
these
engines
are
enforced.

However,
one
equipment
manufacturer
submitted
comments
suggesting
that
we
should
adopt
a
program
that
would
provide
incentives
for
equipment
manufacturers
to
use
the
early
Tier
4
engines
in
their
equipment.
For
an
early
low­
emission
engine
program
to
be
successful,
we
agree
that
it
is
important
to
provide
incentives
to
both
the
engine
manufacturer
and
the
equipment
manufacturer,
who
may
incur
added
cost
to
install
and
market
the
advanced
engine
in
the
equipment.
As
was
pointed
out
in
comments,
the
proposed
program
did
not
provide
clear
incentives
to
equipment
manufacturers
to
use
the
(
presumably
more
expensive)
early
low­
emission
engines.
Therefore,
we
are
adding
such
provisions.
Section
III.
B.
2.
e
describes
these
early
Tier
4
engine
incentive
provisions
under
which
equipment
manufacturers
can
earn
increased
allowance
flexibilities.
Under
those
provisions,
the
engine
manufacturer's
incentive
to
produce
the
lowemitting
engines
will
come
from
customers'
demand
for
them,
and
from
the
fact
that
the
engine
manufacturer
can
earn
ABT
program
credits
for
these
engines
in
the
same
way
as
without
these
incentive
provisions.
If
the
equipment
manufacturer
does
not
wish
to
earn
the
increased
allowance
flexibilities,
then
the
engine
manufacturer
would
be
allowed
to
use
the
provisions
of
the
incentive
program
for
early
low­
emission
engines
described
below
in
this
subsection,
though
to
do
so
would
require
the
forfeiture
of
any
ABT
credits
earned
by
the
subject
engines,
essentially
to
avoid
double
counting,
as
explained
below.
This
engine
manufacturer
incentive
program
is
being
adopted
as
proposed,
except
for
engines
above
750
hp,
for
which
the
proposed
program
requires
some
adjustment
to
account
for
the
approach
we
are
taking
to
final
standards.

As
discussed
in
section
II.
A.
4,
the
final
rule
does
not
phase
in
standards
for
engines
above
750
hp
as
proposed,
and
instead
adopts
application­
specific
standards
in
2011
and
2015.
The
2011
standards
are
not
based
on
advanced
aftertreatment
except
for
NO
X
on
engines
above
1200
hp
used
in
generator
sets.
To
avoid
overcomplication
of
the
incentive
program,
which
might
177
discourage
its
use,
we
are
not
separating
over
and
under
1200
hp
generator
set
engines
into
separate
groups
for
these
provisions.
Instead,
any
of
these
engines
that
meet
the
2015
standards
before
2015
can
earn
offsets.
We
are,
however,
separating
the
generator
set
engines
and
nongenerator
set
engines
above
750
hp
into
separate
groups,
because
we
are
deferring
setting
a
NO
X
standard
for
the
latter
that
is
based
on
use
of
advanced
aftertreatment
technology.

Table
III.
M­
1
summarizes
the
requirements
and
available
offsets
for
engine
manufacturers
in
this
program.
As
the
purpose
of
the
incentive
is
to
encourage
the
introduction
of
clean
technology
engines
earlier
than
required,
we
require
that
the
emission
standard
levels
actually
be
met,
and
met
early,
by
qualifying
engines
to
earn
the
early
introduction
offsets.
The
regulations
specify
that
the
standards
must
be
met
without
the
use
of
ABT
credits
and
actual
production
of
the
engines
must
begin
by
September
1
preceding
the
first
model
year
when
the
standards
would
otherwise
be
applicable.
Also,
to
avoid
double­
counting,
as
explained
in
the
proposal,
the
early
engines
can
earn
either
the
engine
offsets
or
the
ABT
emission
credit,
but
not
both.
Note
that
this
is
different
than
the
approach
taken
in
the
early
Tier
4
engine
incentive
program
for
equipment
manufacturers
described
in
section
III.
B.
2.
e,
where
incentives
for
both
the
engine
manufacturer
(
ABT
credits)
and
the
equipment
manufacturer
(
allowance
flexibilities)
are
needed
to
ensure
successful
early
introduction
of
clean
engines.
Because
15
ppm
sulfur
diesel
fuel
will
be
available
on
a
widespread
basis
in
time
for
2007
(
due
to
the
requirements
for
on­
highway
heavy­
duty
engines),
we
are
allowing
engine
manufacturers
to
begin
certifying
engines
to
the
very
low
emission
levels
required
to
be
eligible
for
this
incentive
program,
beginning
with
the
2007
model
year.
178
Table
III.
M­
1.
 
Program
for
Early
Introduction
of
Clean
Engines
Category
Engine
Group
Must
Meet
a
Per­
Engine
Offset
Early
PM­
only
b
25­
75
hp
0.02
g/
bhp­
hr
PM
1.5­
to­
1
PM­
only
75­
750
hp
0.01
g/
bhp­
hr
PM
Early
Engine
b
25­
75
hp
0.02
/
3.5
g/
bhp­
hr
PM
/
NMHC+
NO
X
1.5­
to­
1
75­
750
hp
0.01
/
0.30
/
0.14
g/
bhp­
hr
PM
/
NO
X
/
NMHC
>
750
hp
generator
set
0.02
/
0.50
/
0.14
g/
bhp­
hr
PM
/
NO
X
/
NMHC
>
750
hp
nongenerator
set
0.03
/
2.6
/
0.14
g/
bhp­
hr
PM
/
NO
X
/
NMHC
Low
NO
X
Engine
>
25
hp
as
above
for
Early
Engine,
except
must
meet
0.15
g/
bhp­
hr
NO
X
standard
2­
to­
1
Notes:

a
All
engines
must
also
meet
the
Tier
4
crankcase
emissions
requirements.
Engines
must
certify
using
all
test
and
other
requirements
(
such
as
NRTC
and
NTE)
otherwise
required
for
final
Tier
4
standards.

b
Offsets
must
be
earned
prior
to
the
start
of
phase­
in
requirements
in
applicable
engine
groups
(
prior
to
2013
for
25­
75
hp
engines,
prior
to
2012
for
75­
175
hp
engines,
prior
to
2011
for
175­
750
hp
engines,
prior
to
2015
for
>
750
hp
engines).

For
any
engines
being
certified
under
this
program
before
the
2011
model
year
using
15
ppm
sulfur
certification
fuel,
the
manufacturer
would
have
to
meet
the
requirements
described
in
section
III.
D,
including
demonstrating
that
the
engine
would
indeed
be
fueled
with
15
ppm
sulfur
fuel
in
the
field.
We
expect
this
would
occur
through
selling
such
engines
into
fleet
applications,
such
as
municipal
maintenance
fleets,
large
construction
company
fleets,
or
any
such
well­
managed
centrally­
fueled
fleet.
While
obtaining
a
reliable
supply
of
15
ppm
maximum
sulfur
diesel
fuel
prior
to
the
2011
model
year
will
be
possible,
it
will
require
some
effort
by
nonroad
diesel
machine
operators.
We
therefore
believe
it
is
necessary
and
appropriate
to
provide
a
greater
incentive
for
early
introduction
of
clean
diesel
technology.
Thus,
as
proposed,
we
would
count
one
early
engine
(
that
is,
an
engine
meeting
the
final
Tier
4
standards)
as
offsetting
1.5
engines
later.
This
means
that
fewer
clean
diesel
engines
than
otherwise
required
may
enter
the
market
in
later
years,
but,
more
importantly,
it
means
that
emission
reductions
would
be
realized
earlier
than
under
our
base
179
program.
We
believe
that
providing
incentives
for
early
emission
reductions
is
a
worthwhile
goal
for
this
program,
because
improving
air
quality
is
an
urgent
need
in
many
parts
of
the
country
as
explained
in
section
I,
and
because
the
early
learning
opportunity
with
new
technologies
can
help
to
ensure
a
smooth
transition
to
Tier
4
standards.

We
are
providing
this
early
introduction
offset
for
engines
over
25
hp
that
meet
all
of
today's
Tier
4
emissions
standards
(
NO
X,
PM,
and
NMHC)
in
the
applicable
engine
category.
We
are
also
providing
this
early
introduction
offset
to
engines
that
pull
ahead
compliance
with
only
the
PM
standard.
However,
a
PM­
only
early
engine
would
offset
only
the
PM
standard
for
an
offsetusing
engine.
For
engines
in
power
categories
with
a
percentage
phase­
in,
this
would
correspond
(
during
the
phase­
in
years)
to
offset
use
for
"
phase­
out"
engines
(
those
required
to
meet
the
new
Tier
4
standard
for
PM
but
not
for
NO
X
or
NMHC).
Engines
using
the
PM­
only
offset
would
be
subject
to
the
other
applicable
Tier
4
emission
standards,
including
applicable
transient
and
NTE
standards
(
see
Section
III.
F)
and
crankcase
requirements.
The
applicable
PM
standard
and
requirements
for
these
PM­
only
offset­
using
engines
would
be
those
of
Tier
3
(
Tier
2
for
25­
50
hp
engines).
PM­
only
offsets
would
not
offset
engines
required
to
meet
other
Tier
4
standards
such
as
the
phase­
in
NO
X
and
NMHC
standards
(
since
there
is
no
reason
for
PM
offsets
to
offset
emissions
of
other
pollutants).
Tier
4
engines
between
25
and
75
hp
certified
to
the
2008
PM
standard
would
not
participate
in
this
program,
nor
would
engines
below
25
hp,
because
they
do
not
have
advanced
aftertreatment­
based
standards.

An
important
aspect
of
the
early
incentive
provision
is
that
it
must
be
done
on
an
engine
count
basis.
That
is,
a
diesel
engine
meeting
new
standards
early
would
count
as
1.5
such
diesel
engines
later.
This
contrasts
with
a
provision
done
on
an
engine
percentage
basis
which
would
count
one
percent
of
diesel
engines
early
as
1.5
percent
of
diesel
engines
later.
Basing
the
incentive
on
an
engine
count
alleviates
any
possible
influence
of
fluctuations
in
engine
sales
in
different
model
years.

Another
important
aspect
of
this
program
is
that
it
is
limited
to
engines
sold
prior
to
the
2013
model
year
for
engines
between
25
and
75
hp,
prior
to
the
2012
model
year
for
engines
between
75
and
175
hp,
and
prior
to
the
2011
model
year
for
engines
between
175
and
750
hp.
In
other
words,
as
in
the
highway
program,
nonroad
diesel
engines
sold
during
the
transitional
"
phase­
in"
model
years
would
not
be
considered
"
early"
introduction
engines
and
would
therefore
be
ineligible
to
generate
early
introduction
offsets.
However,
such
engines
and
vehicles
would
still
be
able
to
generate
ABT
credits.
Because
the
engines
over
750
hp
engines
have
no
percent­
ofproduction
phase­
in
provisions,
we
are
allowing
offsets
for
early
engines
in
any
model
year
prior
to
2015.
For
the
same
reason,
there
is
no
PM­
only
offset
for
these
engines.
As
with
the
phase­
in
itself,
and
for
the
same
reasons,
an
early
introduction
engine
could
only
be
used
to
offset
requirements
for
engines
in
the
same
engine
group
(
25­
75
hp,
75­
175
hp,
175­
750
hp,
>
750
hp
generator
sets,
and
>
750
hp
non­
generator
sets)
as
the
offset­
generating
engine.

As
a
further
incentive
to
introduce
clean
engines
and
vehicles
early,
we
are
also
adopting
the
proposed
provision
that
gives
engine
manufacturers
an
early
introduction
offset
equal
to
two
88
We
also
required
that
highway
vehicles
be
labeled
on
the
dashboard.
Given
the
type
of
equipment
using
nonroad
CI
engines,
we
are
not
adopting
any
dashboard
requirement
here.

180
engines
during
or
after
the
phase­
in
years
for
engines
with
NO
X
levels
well
below
the
final
Tier
4
NO
X
standard.
This
incentive
applies
for
diesel
engines
achieving
a
0.15
g/
bhp­
hr
NO
X
standard
level
(
one­
half
of
the
aftertreatment­
based
standard
for
most
engines)
while
also
meeting
the
NMHC
and
PM
standards.
Due
to
the
extremely
low
emission
levels
to
which
these
engines
and
vehicles
would
need
to
certify,
we
believe
that
the
double
engine
count
offset
is
appropriate.

In
the
NPRM
we
asked
for
comment
on
whether
or
not
we
should
extend
the
existing
Blue
Sky
program
that
encourages
the
early
introduction
of
engines
with
emission
levels
(
as
measured
on
a
transient
test)
about
40%
lower
than
the
Tier
2
standards
levels.
See
68
FR
at
28483.
We
received
comments
both
for
and
against
doing
so,
but
no
commenter
provided
substantive
arguments
or
information.
Given
the
very
low
emissions
levels
being
adopted
in
Tier
4,
we
have
decided
not
to
extend
the
existing
Blue
Sky
Series
program,
because
it
does
not
encourage
engines
emitting
at
such
low
emission
levels.

N.
Labeling
and
Notification
Requirements
As
explained
in
section
II,
the
emissions
standards
will
make
it
necessary
for
manufacturers
to
employ
exhaust
emission
control
devices
that
require
very
low­
sulfur
fuel
(
less
than
15
ppm)
to
ensure
proper
operation.
This
action
restricts
the
sulfur
content
of
diesel
fuel
used
in
these
engines.
However,
the
2008
emissions
standards
would
be
achievable
with
less
sensitive
technologies
and
thus
it
could
be
appropriate
for
those
engines
to
use
diesel
fuel
with
up
to
500
ppm
sulfur.
There
could
be
situations
in
which
vehicles
requiring
either
15
ppm
fuel
or
500
ppm
may
be
accidentally
or
purposely
misfueled
with
higher­
sulfur
fuel.
Any
of
these
misfueling
events
could
seriously
degrade
the
emission
performance
of
sulfur­
sensitive
exhaust
emission
control
devices,
or
perhaps
destroy
their
functionality
altogether.

In
the
highway
rule,
we
adopted
a
requirement
that
heavy­
duty
vehicle
manufacturers
notify
each
purchaser
that
the
vehicle
must
be
fueled
only
with
the
applicable
low­
sulfur
diesel
fuel.
We
also
required
that
diesel
vehicles
be
equipped
by
the
manufacturer
with
labels
near
the
refueling
inlet
to
indicate
that
low
sulfur
fuel
is
required.
We
are
adopting
similar
requirements
here.
88
Specifically,
manufacturers
will
be
required
to
notify
each
purchaser
that
the
nonroad
engine
must
be
fueled
only
with
the
applicable
low­
sulfur
diesel
fuel,
and
ensure
that
the
equipment
is
labeled
near
the
refueling
inlet
to
indicate
that
low
sulfur
fuel
is
required.
We
believe
that
these
measures
would
help
owners
find
and
use
the
correct
fuel
and
would
be
sufficient
to
address
misfueling
concerns.
Thus,
more
costly
provisions,
such
as
fuel
inlet
restrictors,
should
not
be
necessary.

In
general,
beginning
in
model
year
2011,
nonroad
engines
will
be
required
to
use
the
Ultra
Low
Sulfur
diesel
fuel
(
with
less
than
15
ppm
sulfur).
Thus,
the
default
label
will
state
"
ULTRA
LOW
SULFUR
FUEL
ONLY."
The
labeling
requirements
for
earlier
model
year
Tier
4
engines
are
specified
in
§
1039.104(
e).
Some
new
labeling
requirements
for
earlier
model
year
Tier
3
181
engines
are
specified
in
40
CFR
89.330(
e).
These
requirements
for
earlier
years
generally
require
that
engines
and
equipment
be
labeled
consistent
with
the
sulfur
of
the
test
fuel
used
for
their
certification.
So
where
the
engine
is
certified
using
Low
Sulfur
diesel
fuel
(
with
less
than
500
ppm
sulfur),
the
required
label
will
state
"
LOW
SULFUR
FUEL
ONLY."
See
section
III.
D
and
the
regulatory
text
for
the
other
specific
requirements
related
to
labeling
the
earlier
model
years.

O.
General
Compliance
1.
Good
engineering
judgment
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.
EPA
has
the
authority
to
evaluate
whether
a
manufacturer's
use
of
engineering
judgment
is
reasonable.
The
regulations
describe
the
methodology
we
use
to
address
any
concerns
related
to
how
manufacturers
use
good
engineering
judgment
in
cases
where
the
manufacturer
has
such
discretion
(
see
40
CFR
1068.5).
If
we
find
a
problem
with
a
manufacturer's
use
of
engineering
judgment,
we
will
take
into
account
the
degree
to
which
any
error
in
judgment
was
deliberate
or
in
bad
faith.
If
manufacturers
object
to
a
decision
we
make
under
this
provisions,
they
are
entitled
to
a
hearing.
This
subpart
is
consistent
with
provisions
already
adopted
for
light­
duty
highway
vehicles,
marine
diesel
engines,
industrial
spark­
ignition
engines,
and
recreational
vehicles.

2.
Replacement
engines
In
the
proposal
we
included
a
provision
allowing
manufacturers
to
sell
a
new,
noncompliant
engine
intended
to
replace
an
engine
that
fails
in
service.
The
proposed
language
closely
mirrored
the
existing
provisions
in
40
CFR
89.1003(
b)(
7),
except
that
it
specified
that
manufacturers
could
produce
new,
noncompliant
replacement
engines
if
no
engine
from
any
manufacturer
were
available
with
the
appropriate
physical
or
performance
characteristics.
Manufacturers
objected
to
this
provision
and
requested
that
the
final
regulations
follow
the
language
in
40
CFR
part
89,
in
which
the
manufacturer
of
the
new
engine
confirm
that
no
appropriate
engine
is
available
from
its
product
line
(
or
that
of
the
manufacturer
of
the
original
engine,
if
that
were
a
different
company).
We
agree
that
the
language
from
40
CFR
part
89
is
appropriate,
but
we
note
two
things
to
address
remaining
concerns
that
manufacturers
could
potentially
use
the
replacement­
engine
provisions
to
produce
large
numbers
of
noncompliant
products.
First,
we
are
including
a
specific
statement
in
the
regulations
that
manufacturers
may
not
use
the
replacement­
engine
exemption
to
circumvent
the
regulations.
Second,
we
plan
to
use
the
data­
collection
provision
under
40
CFR
1068.205(
d)
to
ask
manufacturers
to
report
the
number
of
engines
they
sell
under
the
replacement­
engine
exemption.
Rather
than
adopting
a
specific
data­
reporting
requirement,
we
believe
this
more
flexible
approach
is
most
appropriate
to
allow
us
to
get
information
to
evaluate
how
manufacturers
are
using
the
exemption
without
imposing
reporting
requirements
that
may
involve
more
or
less
information
than
is
actually
needed.
182
3.
Warranty
We
are
modifying
40
CFR
1068.115
regarding
engine
manufacturers'
warranty
obligations
by
removing
paragraph
(
b).
This
paragraph
addresses
specific
circumstances
under
which
manufacturers
may
not
deny
emission­
related
warranty
claims,
while
paragraph
(
a)
of
this
section
addresses
the
circumstances
under
which
manufacturers
may
deny
such
claims.
As
described
in
our
Summary
and
Analysis
of
Comments
related
to
our
November
8,
2002
final
rule
(
67
FR
68242),
we
intended
to
adopt
40
CFR1068.115
without
this
paragraph.
We
wanted
to
remove
paragraph
(
b)
because
we
agreed
with
a
comment
pointing
out
that
publishing
both
paragraphs
leaves
ambiguous
which
provision
applies
if
a
situation
applies
that
is
not
on
either
list.
Since
neither
list
can
be
comprehensive,
we
believe
the
provisions
in
paragraph
(
a)
describing
when
manufacturers
may
deny
warranty
claims
appropriately
addresses
the
issue.
As
a
result,
paragraph
(
b)
was
inadvertently
adopted
as
part
of
the
November
2002
final
rule.

4.
Separate
catalyst
shipment
We
are
adopting
provisions
that
will
allow
engine
manufacturers
to
ship
engines
to
equipment
manufacturers
where
the
engine
manufacturer
had
not
yet
installed
the
aftertreatment
or
otherwise
included
it
as
part
of
the
engine
shipment.
This
allows
the
engine
manufacturer
to
ship
the
engine
without
the
aftertreatment;
for
example,
in
cases
where
it
would
be
impractical
to
install
aftertreatment
devices
on
the
engine
before
shipment
or
even
ship
products
with
the
aftertreatment
devices
uninstalled
along
with
the
engine;
or
where
shipping
it
already
installed
would
require
it
to
be
disassembled
and
reinstalled
when
the
engine
was
placed
in
the
equipment.
Today's
final
rule
requires
that
the
components
be
included
in
the
price
of
the
engine
and
that
the
engine
manufacturer
provide
sufficiently
detailed
and
clear
instructions
so
that
the
equipment
manufacturer
can
readily
install
the
engine
and
its
ancillary
components
in
a
configuration
covered
under
the
certificate
of
conformity
held
by
the
engine
manufacturer.
We
are
also
requiring
that
the
engine
manufacturer
have
a
contractual
agreement
obligating
the
equipment
manufacturer
to
complete
the
final
assembly
into
a
certified
configuration.
The
engine
manufacturer
must
ship
any
components
directly
to
the
equipment
manufacturer
or
arrange
for
their
shipment
from
a
component
supplier.
The
engine
manufacturer
must
tag
the
engines
and
keep
records.
The
engine
manufacturer
must
obtain
annual
affidavits
from
each
equipment
manufacturer
as
to
the
parts
and
part
numbers
that
the
equipment
manufacturer
installed
on
each
engine
and
must
conduct
a
limited
number
of
audits
of
equipment
manufacturers'
facilities,
procedures,
and
production
records
to
monitor
adherence
to
the
instructions
it
provided.
Where
an
equipment
manufacturer
is
located
outside
of
the
U.
S.,
the
audits
may
be
conducted
at
U.
S.
port
of
distribution
facilities.

The
rule
also
contains
various
provisions
establishing
responsibility
for
proper
installation.
Where
the
engines
are
not
in
a
certified
configuration
when
installed
in
nonroad
equipment
because
the
equipment
manufacturer
used
improper
emission­
control
devices
or
failed
to
install
the
shipped
parts
or
failed
to
install
the
devices
correctly,
then
both
the
engine
manufacturer
and
the
installer
have
responsibility.
For
the
engine
maker,
the
exemption
is
void
for
those
engines
that
are
not
in
their
certified
configuration
after
installation.
We
may
also
suspend
or
revoke
the
exemption
for
183
future
engines
where
appropriate,
or
void
the
exemption
for
the
entire
engine
family.
The
installer
is
also
liable.
We
may
find
the
equipment
manufacturer
to
be
in
violation
of
the
tampering
prohibitions
at
40
CFR
1068.101(
b)(
1)
for
the
improper
installation,
which
could
subject
it
to
substantial
civil
penalties.
In
any
event,
the
engine
manufacturer
remains
liable
for
the
in­
use
compliance
of
the
engine
as
installed.
For
example,
it
has
responsibility
for
the
emission­
related
warranty,
including
for
the
aftertreatment,
and
is
responsible
for
any
potential
recall
liability.
However,
if
noncompliance
of
the
in­
use
engines
stems
from
improper
installation
of
the
aftertreatment,
then
the
tampering
that
occurred
by
the
installer
may
remove
recall
liability.
Where
the
engine
manufacturer
had
complied
with
the
regulations
and
the
failure
was
solely
due
to
the
equipment
manufacturer's
actions,
we
would
not
be
inclined
to
revoke
or
suspend
the
exemption
or
to
void
the
exemption
for
the
entire
engine
family.
We
may
deny
the
exemption
for
future
model
years
if
the
engine
manufacturer
does
not
take
action
to
address
the
factors
causing
the
nonconformity.
On
the
other
hand,
if
the
manufacturer
failed
to
comply,
had
shipped
improper
parts,
had
provided
instructions
that
led
to
improperly
installed
parts,
or
had
otherwise
contributed
to
the
installation
of
engines
in
an
uncertified
configuration,
we
might
suspend,
revoke,
or
void
the
exemption
for
the
engine
family.
In
this
case,
the
engine
manufacturer
would
be
subject
to
substantial
civil
penalties.

P.
Other
Issues
We
are
also
making
other
minor
changes
to
the
compliance
program.
These
changes
are
summarized
in
table
III.
Q­
1
below.
For
more
information
about
these
changes,
you
should
read
the
NPRM
and
Summary
and
Analysis
of
Comments
for
this
rulemaking.
We
believe
that
these
changes
are
straightforward
and
noncontroversial.
184
Table
III.
Q­
1.
 
Regulatory
Changes
Issue
Regulatory
provision
Applicability
to
alcohol­
fueled
engines
§
§
1039.101,
1039.107
Prohibited
controls
§
1039.115
Emission­
related
maintenance
instructions
§
1039.125
Engine
installation
instructions
§
1039.130
Engines
labels
§
§
1039.20,
1039.135,
1068.320
Engine
family
definition
§
1039.230
Test
engine
selection
§
1039.235
Deterioration
factors
§
1039.240
Engines
that
use
noncommercial
fuels
§
1039.615
Use
of
good
engineering
judgment
§
1068.5
Separate
shipment
of
aftertreatment
§
1068.260
Exemptions
40
CFR
1068
Subpart
C
Importing
engines
40
CFR
1068
Subpart
D
Hearings
40
CFR
1068
Subpart
G
Q.
Highway
Engines
We
are
changing
the
diesel
engine/
vehicle
labeling
requirements
in
40
CFR
86.007­
35
to
be
consistent
with
the
new
pump
labels.
This
change
corrects
a
mistake
in
the
proposal
that
would
have
resulted
in
confusion
for
highway
vehicle
operators.
(
We
received
no
comment
on
this
issue.)

R.
Changes
That
Affect
Other
Engine
Categories
We
are
making
some
minor
changes
to
the
regulations
in
40
CFR
parts
1048
and
1051
for
nonroad
spark­
ignition
engines
over
19
kW
and
recreational
vehicles,
respectively.
We
are
also
changing
several
additional
provisions
in
40
CFR
parts
1065
and
1068,
which
define
test
procedures
and
compliance
provisions
for
these
same
categories
of
engines.
See
the
regulatory
text
for
the
specific
changes.
The
proposed
rule
included
most
of
these
changes.
To
the
extent
there
were
comments
on
any
of
these
changes,
those
issues
are
addressed
elsewhere
in
this
document
or
in
the
Summary
and
Analysis
of
Comments.
185
!
In
40
CFR
1048.125
and
40
CFR
1051.125,
we
are
correcting
the
provisions
related
to
critical
emission­
related
maintenance
to
allow
manufacturers
to
do
maintenance
during
service
accumulation
for
durability
testing,
as
long
as
their
maintenance
steps
meet
the
specified
criteria
ensuring
that
in­
use
engines
will
undergo
those
maintenance
procedures.

!
In
40
CFR
1068.27,
we
clarify
that
manufacturers
must
make
available
a
reasonable
number
of
production­
line
engines
so
we
can
test
or
inspect
them
if
we
make
such
a
request.

!
We
are
changing
the
definition
of
nonroad
engine
to
explicitly
exclude
aircraft
engines.
This
is
consistent
with
our
longstanding
interpretation
of
the
Clean
Air
Act.
Clarifying
the
definition
this
way
allows
us
to
more
clearly
specify
the
applicability
of
the
fuel
requirements
to
nonroad
engines
in
this
final
rule.

!
We
are
adding
a
provision
directing
equipment
manufacturers
to
request
duplicate
labels
from
engine
manufacturers
and
keep
appropriate
records
if
the
original
label
is
obscured
in
the
final
installation.
The
former
approach
under
40
CFR
part
1068
was
to
require
equipment
manufacturers
to
make
their
own
duplicate
labels
as
needed.
We
intend
to
amend
40
CFR
parts
1048
and
1051
to
correspond
with
this
change.

!
As
described
above
in
section
III,
we
are
revising
the
criteria
manufacturers
would
use
to
show
that
they
may
use
the
replacement­
engine
exemption
under
40
CFR
1068.240.
We
also
clarify
that
we
may
require
manufacturers
to
report
to
us
how
many
engines
they
sell
in
given
year
under
the
replacement­
engine
exemption.

!
As
described
above
and
in
the
Summary
and
Analysis
of
Comments,
we
are
adding
a
provision
in
40
CFR
1068.260
to
allow
manufacturers
to
ship
aftertreatment
devices
directly
from
the
component
supplier
to
the
equipment
manufacturer.
This
regulatory
section
includes
several
provisions
to
ensure
that
the
equipment
manufacturer
installs
the
aftertreatment
device
in
a
way
that
brings
the
engine
to
its
certified
configuration.

!
As
described
above,
we
are
modifying
the
defect­
reporting
requirements
in
40
CFR
1068.501.

!
While
most
of
the
changes
being
adopted
for
part
1065
will
only
affect
diesel
nonroad
engines,
we
are
also
making
minor
changes
that
will
also
apply
for
SI
engines.
These
changes,
however,
are
generally
limited
to
clarifications,
corrections,
and
options.
They
will
not
affect
the
stringency
of
the
standards
or
create
new
burdens
for
manufacturers.
186
IV.
Our
Program
for
Controlling
Nonroad,
Locomotive
and
Marine
Diesel
Fuel
Sulfur
We
are
finalizing
today
a
two­
step
sulfur
standard
for
nonroad,
locomotive
and
marine
(
NRLM)
diesel
fuel
that
will
achieve
significant,
cost­
effective
sulfate
PM
and
SO
2
emission
reductions.
These
emission
reductions
will,
by
themselves,
provide
dramatic
environmental
and
public
health
benefits
which
far
outweigh
the
cost
of
meeting
the
standards
necessary
to
achieve
them.
In
addition,
the
final
sulfur
standards
for
nonroad
diesel
fuel
will
enable
advanced
high
efficiency
emission
control
technology
to
be
applied
to
nonroad
engines.
As
a
result,
these
nonroad
fuel
sulfur
standards,
coupled
with
our
program
for
more
stringent
emission
standards
for
new
nonroad
engines
and
equipment,
will
also
achieve
dramatic
NO
X
and
PM
emission
reductions.
Sulfur
significantly
inhibits
or
impairs
the
function
of
the
diesel
exhaust
emission
control
devices
which
will
generally
be
necessary
for
nonroad
diesel
engines
to
meet
the
emission
standards
finalized
today.
With
the
15
ppm
sulfur
standard
for
nonroad
diesel
fuel,
we
have
concluded
that
this
emission
control
technology
will
be
available
for
model
year
2011
and
later
nonroad
diesel
engines
to
achieve
the
NO
X
and
PM
emission
standards
adopted
today.
The
benefits
of
today's
program
also
include
the
sulfate
PM
and
SO
2
reductions
achieved
by
establishing
the
same
standard
for
the
sulfur
content
of
locomotive
and
marine
diesel
fuel.

The
sulfur
requirements
established
under
today's
program
are
similar
to
the
sulfur
limits
established
for
highway
diesel
fuel
in
prior
rulemakings
 
500
ppm
in
1993
(
55
FR
34120,
August
21,
1990)
and
15
ppm
in
2006
(
66
FR
5002,
January
18,
2001).
Beginning
June
1,
2007,
refiners
will
be
required
to
produce
NRLM
diesel
fuel
with
a
maximum
sulfur
content
of
500
ppm.
Then,
beginning
June
1,
2010,
the
sulfur
content
will
be
reduced
for
nonroad
diesel
fuel
to
a
maximum
of
15
ppm.
The
sulfur
content
of
locomotive
and
marine
diesel
fuel
will
be
reduced
to
15
ppm
beginning
June
1,
2012.
The
program
contains
certain
provisions
to
ease
refiners'
transition
to
the
lower
sulfur
standards
and
to
enable
the
efficient
distribution
of
all
diesel
fuels.
These
provisions
include
the
2012
date
for
locomotive
and
marine
diesel
fuel,
early
credits
for
refiners
and
importers
and
special
provisions
for
small
refiners,
transmix
processors,
and
entities
in
the
fuel
distribution
system.

In
general,
the
comments
we
received
during
the
public
comment
period
supported
the
proposed
program.
Adjustments
we
have
made
to
the
proposed
program
will
make
the
final
program
even
stronger,
both
in
terms
of
our
ability
to
enforce
it
and
the
environmental
and
public
health
benefits
that
it
will
achieve.
In
particular,
today's
final
program
contains
provisions
to
smooth
the
refining
industry's
transition
to
the
low
sulfur
fuel
requirements,
encourage
earlier
introduction
of
cleaner
burning
fuel,
maintain
the
fuel
distribution
system's
flexibility
to
fungibly
distribute
similar
products,
and
provide
an
outlet
for
off­
specification
distillate
product,
all
while
maintaining,
and
even
enhancing,
the
health
and
environmental
benefits
of
today's
program.

The
first
adjustment
that
we
made
to
the
proposed
program
was
to
move
from
the
"
refiner
baseline"
approach
discussed
in
the
proposal
to
a
"
designate
and
track"
approach.
Under
the
proposed
refiner
baseline
approach,
any
refiner
or
importer
could
choose
to
fungibly
distribute
its
187
500
ppm
sulfur
NRLM
and
highway
diesel
fuels
without
adding
red
dye
to
the
NRLM
at
the
refinery
gate.
However,
the
refiners'
production
would
then
be
subject
to
a
non­
highway
distillate
baseline,
established
as
a
percentage
of
its
total
distillate
fuel
production
volume.
While
EPA
preferred
this
approach
in
the
proposal,
we
decided
not
to
finalize
it
because
we
concluded
that
it
would
have
unnecessarily
constrained
refiners'
ability
to
meet
market
demands.
It
would
have
encouraged
them
to
dye
500
ppm
sulfur
NRLM
at
the
refinery
gate,
resulting
in
an
additional
grade
of
diesel
fuel
and,
consequently,
an
added
burden
to
the
distribution
system.
Furthermore,
we
were
concerned
that
it
would
have
created
a
trend
that
could
reduce
the
volume
of
15
ppm
sulfur
highway
diesel
fuel
and
potential
options
to
remove
the
market
constraints
could
have
increased
the
possibility
for
reduced
volume.

In
place
of
the
refiner
baseline
approach,
we
are
finalizing
a
designate
and
track
approach.
The
final
designate
and
track
approach
is
a
modified
version
of
the
designate
and
track
approach
discussed
in
the
proposal.
As
finalized
it
now
allows
us
to
enforce
the
program
through
the
entire
distribution
system.
In
essence,
the
final
designate
and
track
approach
requires
refiners
and
importers
to
designate
the
volumes
of
diesel
fuel
they
produce
and/
or
import.
Refiners/
importers
will
identify
whether
their
diesel
fuel
is
highway
or
NRLM
and
the
applicable
sulfur
level.
They
may
then
mix
and
fungibly
ship
highway
and
NRLM
diesel
fuels
that
meet
the
same
sulfur
specification
without
dyeing
their
NRLM
diesel
fuel
at
the
refinery
gate.
The
designations
will
follow
the
fuel
through
the
distribution
system
with
limits
placed
on
the
ability
of
downstream
parties
to
change
the
designation.
These
limits
are
designed
to
restrict
the
inappropriate
sale
of
500
ppm
sulfur
NRLM
diesel
fuel
into
the
highway
market
,
the
inappropriate
sale
of
heating
oil
into
the
NRLM
market,
the
inappropriate
sale
of
500
ppm
sulfur
LM
into
the
nonroad
market,
and
to
implement
the
downgrading
restrictions
that
apply
to
15
ppm
sulfur
highway
diesel
fuel.
The
designate
and
track
approach
includes
record
keeping
and
reporting
requirements
for
all
parties
in
the
fuel
distribution
system,
associated
with
tracking
designated
fuel
volumes
through
each
custodian
in
the
distribution
chain
until
the
fuel
exits
the
terminal.
The
program
also
includes
enforcement
and
compliance
assurance
provisions
to
enable
the
Agency
to
rapidly
and
accurately
review
for
discrepancies
the
large
volume
of
data
collected
on
fuel
volume
hand­
offs.
The
bulk
of
the
designate
and
track
provisions
end
May
31,
2010
when
all
highway
diesel
fuel
must
meet
the
15
ppm
sulfur
standard.
However,
as
discussed
below,
scaled
back
designate
and
track
provisions
continue
beyond
2010
for
purposes
of
enforcing
against
heating
oil
being
used
in
the
NRLM
market
and
to
enforce
against
500
ppm
LM
diesel
fuel
being
used
in
the
nonroad
market.

The
second
adjustment
that
we
made
to
the
proposed
NRLM
diesel
fuel
program
was
to
establish
a
15
ppm
sulfur
standard
at
the
refinery
gate
for
locomotive
and
marine
(
LM)
diesel
fuel
89
While
today's
program
does
not
establish
more
stringent
emission
standards
for
locomotive
or
marine
diesel
engines,
the
Agency
intends
in
the
near
future
to
initiate
a
rulemaking
to
adopt
new
emission
standards
for
locomotive
and
marine
engines
based
on
the
use
of
high
efficiency
exhaust
emission
control
technology
like
that
required
for
the
nonroad
standards
adopted
in
today's
rule.
An
advanced
notice
of
proposed
rulemaking
(
ANPRM)
for
this
rule
is
published
elsewhere
in
today's
Federal
Register
[
INSERT
DATE
OF
PUBLICATION].

188
in
addition
to
nonroad
(
NR)
diesel
fuel.
89
We
are
finalizing
this
standard
for
several
reasons
as
discussed
below.

While
we
are
finalizing
a
15
ppm
sulfur
standard
for
locomotive
and
marine
diesel
fuel,
we
are
doing
so
in
a
manner
that
responds
to
the
primary
concerns
raised
in
comments
regarding
the
need
for
an
outlet
for
off­
specification
product.
We
are
setting
a
refinery
gate
standard
of
15
ppm
sulfur
beginning
June
1,
2012,
two
years
later
than
for
nonroad
diesel
fuel.
We
are
also
continuing
to
provide
an
outlet
for
off­
specification
product
generated
in
the
distribution
system,
thereby
affording
the
opportunity
to
reduce
reprocessing
and
transportation
costs.
We
are
leaving
the
downstream
standard
for
LM
diesel
fuel
at
500
ppm
sulfur.
In
this
way
the
LM
diesel
fuel
pool
may
remain
an
outlet
for
off­
specification
distillate
product
and
interface/
transmix
material.

In
developing
the
provisions
of
the
NRLM
diesel
fuel
program
adopted
today,
we
identified
several
principles
that
we
want
the
program
to
achieve.
Specifically,
as
described
in
more
detail
below,
we
believe
the
fuel
program
 
1)
Achieves
the
greatest
reduction
in
sulfate
PM
and
SO
2
emissions
from
nonroad,
locomotive,
and
marine
diesel
engines
as
early
as
practicable;

2)
Provides
for
a
smooth
transition
of
the
NRLM
diesel
fuel
pool
to
15
ppm
sulfur;

3)
Ensures
that
15
ppm
sulfur
diesel
fuel
is
produced
and
distributed
widely
for
use
in
all
2011
and
later
model
year
nonroad
diesel
engines;

4)
Ensures
that
the
fuel
program's
requirements
are
enforceable
and
verifiable.

5)
Enables
the
efficient
distribution
of
all
diesel
fuels;
and
6)
Maintains
the
benefits
and
program
integrity
of
the
highway
diesel
fuel
program.

The
remainder
of
this
section
covers
several
topics.
In
section
IV.
A,
we
discuss
the
fuel
that
is
covered
by
today's
program,
the
standards
that
apply
for
refiners
and
importers
(
for
both
steps
of
the
program),
and
the
standards
that
apply
for
downstream
entities.
In
section
IV.
B,
we
address
the
various
hardship
provisions
that
we
are
including
in
today's
program.
In
section
IV.
C,
we
describe
the
special
provisions
that
apply
in
the
State
of
Alaska
and
the
Territories.
Next,
in
90
Category
3
marine
engines
frequently
are
designed
to
use
residual
fuels
and
include
special
fuel
handling
equipment
to
use
the
residual
fuel.

91
For
the
purposes
of
this
final
rule,
the
term
heating
oil
basically
refers
to
any
No.
1
or
No.
2
distillate
other
than
jet
fuel,
kerosene,
and
diesel
fuel
used
in
highway,
nonroad,
locomotive,
or
marine
applications.
For
example,
heating
oil
includes
fuel
which
is
suitable
for
use
in
furnaces,
boilers,

stationary
diesel
engines
and
similar
applications
and
is
commonly
or
commercially
known
or
sold
as
heating
oil,
fuel
oil,
or
other
similar
trade
names.

189
section
IV.
D,
we
describe
the
design
of
the
designate
and
track
provisions
of
the
NRLM
diesel
fuel
program
for
compliance
purposes
and
how
it
differs
from
what
we
proposed.
In
section
IV.
E,
we
discuss
the
impact
of
today's
program
on
state
NRLM
diesel
fuel
programs.
In
sections
IV.
F
and
G,
we
discuss
the
technological
feasibility
of
the
NRLM
diesel
fuel
standards
adopted
today
and
the
impacts
of
today's
program
on
lubricity
and
other
fuel
properties.
Finally,
in
section
IV.
H,
we
discuss
the
steps
the
Agency
will
take
to
streamline
the
refinery
air
permitting
process
for
the
equipment
that
refiners
may
need
to
install
to
meet
today's
NRLM
diesel
fuel
standards..

Analyses
supporting
the
design
and
cost
of
the
fuel
program
are
located
in
chapters
5,
7,
and
8
of
the
RIA.
Section
V
of
this
preamble
discusses
the
details
of
the
additional
compliance
and
enforcement
provisions
affecting
NRLM
diesel
fuel
and
explains
various
additional
elements
of
the
program.

A.
Nonroad,
Locomotive
and
Marine
Diesel
Fuel
Quality
Standards
1.
What
Fuel
Is
Covered
by
this
Program?

The
fuel
covered
by
today's
final
rule
is
generally
the
same
as
the
fuel
that
was
covered
by
the
proposal.
We
have
not
expanded
or
reduced
the
pool
of
diesel
fuel
that
will
be
subject
to
the
lower
sulfur
standards.
However,
the
second
step
of
the
program
now
includes
the
same
ultra
low
sulfur
standard
for
locomotive
and
marine
diesel
fuel
as
for
nonroad
diesel
fuel.

Specifically,
the
sulfur
standards
finalized
under
today's
program
apply
to
all
the
diesel
fuel
that
is
used
in
nonroad,
locomotive,
and
marine
diesel
applications
 
fuel
not
already
covered
by
the
previous
standards
for
highway
diesel
fuel.
This
includes
all
fuel
used
in
nonroad,
locomotive,
and
marine
diesel
engines,
except
for
fuels
heavier
than
a
No.
2
distillate
used
in
Category
2
and
3
marine
engines90
and
any
fuel
that
is
exempted
for
national
security
or
other
reasons.
While
we
are
not
adopting
sulfur
standards
for
other
distillate
fuels
(
such
as
jet
fuel,
heating
oil,
kerosene,
and
No.
4
fuel
oil)
we
are
adopting
provisions
to
prevent
the
inappropriate
use
of
these
other
fuels.
Use
of
distillate
fuels
in
nonroad,
locomotive,
or
marine
diesel
engines
will
generally
be
prohibited
unless
they
meet
the
fuel
sulfur
standards
finalized
today.
91
The
program
includes
several
provisions,
as
described
below
in
section
IV.
D,
to
ensure
that
heating
oil
and
other
higher
sulfur
distillate
fuels
will
not
be
used
in
nonroad,
locomotive,
or
marine
applications.
190
The
regulated
fuels
under
today's
program
include
the
following:

1)
Any
No.
1
and
2
distillate
fuels
used,
intended
for
use,
or
made
available
for
use
in
nonroad,
locomotive,
or
marine
diesel
engines.
Fuels
under
this
category
include
those
meeting
the
American
Society
for
Testing
and
Materials
(
ASTM)
D
975
or
D
396
specifications
for
grades
No.
1­
D
and
No.
2­
D.
Fuels
meeting
ASTM
DMX
and
DMA
specifications
would
be
covered;

2)
Any
No.
1
distillate
fuel
(
e.
g.,
kerosene)
added
to
such
No.
2
diesel
fuel,
e.
g.,
to
improve
its
cold
flow
properties;

3)
Any
other
fuel
used
in
nonroad,
locomotive,
or
marine
diesel
engines
or
blended
with
diesel
fuel
for
use
in
such
engines.
Fuels
under
this
category
include
nondistillate
fuels
such
as
biodiesel
and
certain
specialty
fuel
grades
such
as
JP­
5,
JP­
8,
and
F76
if
used
in
a
nonroad,
locomotive,
or
marine
diesel
engine,
except
when
a
national
security
or
research
and
development
exemption
has
been
approved.
See
V.
A.
1.
and
2.

On
the
other
hand,
the
sulfur
standards
do
not
apply
to
 
1)
No.
1
distillate
fuel
used
to
power
aircraft;

2)
No.
1
or
No.
2
distillate
fuel
used
for
stationary
source
purposes,
such
as
to
power
stationary
diesel
engines,
industrial
boilers,
or
for
heating;

3)
Number
4,
5,
and
6
fuels
(
e.
g.,
residual
fuels
or
residual
fuel
blends,
IFO
Heavy
Fuel
Oil
Grades
30
and
higher),
used
for
stationary
source
purpose
;

4)
Any
distillate
fuel
with
a
T­
90
distillation
point
greater
than
700F,
when
used
in
Category
2
or
3
marine
diesel
engines.
This
includes
Number
4,
5,
and
6
fuels
(
e.
g.,
IFO
Heavy
Fuel
Oil
Grades
30
and
higher),
as
well
as
fuels
meeting
ASTM
specifications
DMB,
DMC,
and
RMA­
10
and
heavier;
and
5)
Any
fuel
for
which
a
national
security
or
research
and
development
exemption
has
been
approved
or
fuel
that
is
exported
from
the
U.
S.
(
see
section
V.
A.
1.
and
2).

It
is
useful
to
clarify
what
marine
diesel
fuels
are
covered
by
the
sulfur
standards.
As
with
nonroad
and
locomotive
diesel
fuel,
our
basic
approach
is
that
the
standards
apply
to
any
diesel
or
distillate
fuel
used
or
intended
for
use
in
marine
diesel
engines.
However,
the
fuel
used
by
marine
diesel
engines
spans
a
wide
variety
of
fuels,
ranging
from
No.
1
and
2
diesel
fuel
to
residual
fuel
and
residual
fuel
blends
used
in
the
largest
engines.
It
is
not
EPA's
intention
to
cover
all
such
fuels,
and
EPA
has
adopted
an
objective
criteria
to
identify
those
marine
fuels
subject
to
regulation
and
those
that
are
not.
Any
distillate
fuel
with
a
T­
90
greater
than
700F
will
not
be
subject
to
the
191
sulfur
standards
when
used
in
Category
2
or
3
marine
engines.
This
criteria
is
designed
to
exclude
fuels
heavier
than
No.
2
distillate,
including
blends
containing
residual
fuel.
In
addition,
residual
fuel
is
not
subject
to
the
sulfur
standards.

While
many
marine
diesel
engines
use
No.
2
distillate,
ASTM
specifications
for
marine
fuels
identify
four
kinds
of
marine
distillate
fuels:
DMX,
DMA,
DMB,
and
DMC.
DMX
is
a
special
light
distillate
intended
mainly
for
use
in
emergency
engines.
DMA
(
also
called
MGO)
is
a
general
purpose
marine
distillate
that
is
to
contain
no
traces
of
residual
fuel.
These
fuels
can
be
used
in
all
marine
diesel
engines
but
are
primarily
used
by
Category
1
engines.
DMX
and
DMA
fuels
intended
for
use
in
any
marine
diesel
engine
are
subject
to
the
fuel
sulfur
standards.

DMB,
also
called
marine
diesel
oil,
is
not
typically
used
with
Category
1
engines,
but
is
used
for
Category
2
and
3
engines.
DMB
is
allowed
to
have
a
trace
of
residual
fuel,
which
can
be
high
in
sulfur.
This
contamination
with
residual
fuel
usually
occurs
due
to
the
distribution
process,
when
distillate
is
brought
on
board
a
vessel
via
a
barge
that
has
previously
contained
residual
fuel,
or
using
the
same
supply
lines
as
are
used
for
residual
fuel.
DMB
is
produced
when
fuels
such
as
DMA
are
brought
on
board
the
vessel
in
this
manner.
EPA's
sulfur
standards
will
apply
to
the
distillate
that
is
used
to
produce
the
DMB,
for
example
the
DMA
distillate,
up
to
the
point
that
it
becomes
DMB.
DMB
itself
is
not
subject
to
the
sulfur
standards
when
it
is
used
in
Category
2
or
3
engines.

DMC
is
a
grade
of
marine
fuel
that
may
contain
some
residual
fuel
and
is
often
a
residual
fuel
blend.
This
fuel
is
similar
to
NO.
4
diesel,
and
can
be
used
in
Category
2
and
Category
3
marine
diesel
engines.
DMC
is
produced
by
blending
a
distillate
fuel
with
residual
fuel,
for
example
at
a
location
downstream
in
the
distribution
system.
EPA's
standards
will
apply
to
the
distillate
that
is
used
to
produce
the
DMC,
up
to
the
point
that
it
is
blended
with
the
residual
fuel
to
produce
DMC.
DMC
itself
is
not
subject
to
the
sulfur
standards
when
it
is
used
in
Category
2
or
3
marine
engines.

Residual
fuel
is
typically
designated
by
the
prefix
RM
(
e.
g.,
RMA,
RMB,
etc.).
These
fuels
are
also
identified
by
their
nominal
viscosity
(
e.
g.,
RMA10,
RMG35,
etc.).
Most
residual
fuels
require
treatment
by
a
purifier­
clarifier
centrifuge
system,
although
RMA
and
RMB
do
not
require
this.
For
the
purpose
of
this
rule,
we
consider
all
RM
grade
fuel
as
residual
fuel.
Residual
fuel
is
not
covered
by
the
sulfur
content
standards
as
it
is
not
a
distillate
fuel.

The
distillation
criteria
adopted
by
EPA,
T­
90
greater
than
700F,
is
designed
to
identify
those
fuels
that
are
not
subject
to
the
sulfur
standards
when
used
in
Category
2
or
3
marine
diesel
engines.
It
is
intended
to
exclude
DMB,
DMC,
and
other
heavy
distillates
or
blends,
when
used
in
Category
2
or
3
marine
diesel
engines.

Hence,
the
fuel
that
refiners
and
importers
are
required
to
produce
to
the
more
stringent
sulfur
standards
include
those
No.
1
and
No.
2
diesel
fuels
as
well
as
similar
distillate
or
nondistillate
fuels
that
are
intended
or
made
available
for
use
in
NRLM
diesel
engines.
Furthermore,
192
the
sulfur
standard
also
covers
any
fuel
that
is
blended
with
or
substituted
for
No.
1
or
No.
2
diesel
fuel
for
use
in
nonroad,
locomotive,
or
marine
diesel
engines.
For
instance,
as
required
under
the
highway
diesel
fuel
program,
in
those
situations
where
the
same
batch
of
kerosene
is
distributed
for
two
purposes
(
e.
g.,
kerosene
to
be
used
for
heating
and
to
improve
the
cold
flow
of
No.
2
NRLM
diesel
fuel),
or
where
a
batch
distributed
just
for
heating
is
later
distributed
for
blending
with
No.
2
diesel
fuel,
that
batch
of
kerosene
must
meet
the
standards
adopted
today
for
NRLM
diesel
fuel.
The
purpose
of
this
requirement
is
to
ensure
that
fuels
like
jet
fuel,
kerosene,
and/
or
military
specification
fuels
meet
the
diesel
fuel
sulfur
standards
adopted
under
today's
program
when
they
are
used
in
nonroad,
locomotive,
or
marine
diesel
engines.

2.
Standards
and
Deadlines
for
Refiners
and
Importers
The
NRLM
diesel
fuel
program
adopted
today
is
a
two­
step
approach
to
reduce
the
sulfur
content
of
NRLM
diesel
fuel
from
uncontrolled
levels
down
to
15
ppm
sulfur.
While
we
received
several
comments
supporting
a
single
step
down
to
15
ppm
sulfur,
the
vast
majority
of
commenters,
especially
most
refiners
and
engine
manufacturers,
supported
the
two­
step
approach.
We
are
finalizing
the
two­
step
approach
primarily
because
it
achieves
the
greatest
reduction
in
sulfate
PM
and
SO
2
emissions
from
nonroad,
locomotive,
and
marine
diesel
engines
as
early
as
practicable.
By
starting
with
an
initial
step
of
500
ppm
sulfur
we
can
achieve
significant
emission
reductions
and
associated
health
and
welfare
benefits
from
the
current
fleet
of
equipment
as
soon
as
possible.
As
discussed
in
section
VI,
the
health­
related
benefits
of
the
fuel
standards
finalized
today,
even
without
the
engine
standards,
amount
to
more
than
$
28
billion
in
2030,
while
the
projected
costs,
after
taking
into
account
engine
maintenance
benefits
amount
to
just
$
0.7
billion.

In
addition,
the
two­
step
approach
encourages
a
more
smooth
and
orderly
transition
by
the
refining
industry
to
15
ppm
sulfur
NRLM
diesel
fuel,
by
providing
more
time
for
refiners
to
develop
the
most
cost­
effective
approaches,
finance
them,
and
then
implement
the
necessary
refinery
modifications.

Finally,
by
waiting
until
2010
to
drop
to
the
15
ppm
sulfur
standard
for
NR
diesel
fuel,
the
two­
step
approach
harmonizes
with
the
highway
diesel
fuel
program
by
delaying
the
implementation
of
the
15
ppm
sulfur
standard
for
NR
diesel
fuel
until
the
end
of
the
phase­
in
period
for
15
ppm
sulfur
highway
diesel
fuel.
The
2010
date
also
harmonizes
with
the
date
15
ppm
nonroad
fuel
is
needed
to
enable
the
nonroad
engines
standards
finalized
today.
The
second
step
to
15
ppm
sulfur
for
the
LM
diesel
fuel
is
set
for
2012.
On
balance
we
believe
that
the
advantages
of
the
two­
step
approach
outweigh
those
of
a
single
step
down
to
15
ppm.

As
discussed
in
section
IV.
C,
below,
later
deadlines
for
meeting
the
500
and
15
ppm
sulfur
standards
apply
to
refineries
covered
by
special
hardship
provisions
as
well
as
transmix
processors.
92
Off­
specification
fuel
here
refers
to
15
ppm
diesel
fuel
that
becomes
contaminated
such
that
it
no
longer
meets
the
15
ppm
sulfur
cap.
In
most
cases,
off­
specification
15
ppm
sulfur
diesel
fuel
is
expected
to
easily
meet
a
500
ppm
sulfur
cap.

193
a.
The
First
Step
to
500
ppm
Sulfur
NRLM
Diesel
Fuel
Under
today's
program,
NRLM
diesel
fuel
produced
by
refiners
or
imported
into
the
U.
S.
by
importers
must
meet
a
500
ppm
sulfur
standard
beginning
June
1,
2007.
Refiners
and
importers
may
comply
by
either
producing
such
fuel
at
or
below
500
ppm
sulfur,
or
they
may
comply
by
obtaining
credits
as
discussed
in
section
IV.
D
below.

We
believe
that
the
adopted
level
of
500
ppm
sulfur
is
appropriate
for
several
reasons.
First,
the
reduction
to
500
ppm
sulfur
is
significant
environmentally.
The
500
ppm
sulfur
level
achieves
approximately
90
percent
of
the
sulfate
PM
and
SO
2
benefits
otherwise
achievable
by
going
all
the
way
to
15
ppm
sulfur.
Second,
because
this
first
step
is
only
to
500
ppm
sulfur,
it
also
allows
for
a
short
lead
time
for
implementation,
enabling
the
environmental
benefits
to
begin
accruing
as
soon
as
possible.
Third,
it
is
consistent
with
the
current
specification
for
highway
diesel
fuel,
a
grade
which
may
remain
for
highway
purposes
until
2010.
As
such,
adopting
the
same
500
ppm
sulfur
level
for
NRLM
diesel
fuel
helps
to
avoid
issues
and
costs
associated
with
more
grades
of
fuel
in
the
distribution
system
during
this
initial
step
of
the
program.

b.
The
Second
Step
to
15
ppm
Sulfur
NRLM
Diesel
Fuel
We
are
finalizing
a
second
step
of
sulfur
control
down
to
15
ppm
sulfur
for
all
NRLM.
This
second
step
provides
additional
important
direct
sulfate
PM
and
SO
2
emission
reductions
and
associated
health
benefits.
As
discussed
in
the
RIA,
the
health
related
benefits
for
this
second
step
of
fuel
control
by
itself
are
greater
than
the
associated
cost.
Furthermore,
the
second
step
for
nonroad
diesel
fuel
is
essential
to
enable
the
application
of
high
efficiency
exhaust
emission
control
technologies
to
nonroad
diesel
engines
beginning
with
the
2011
model
year
as
discussed
in
Section
II
of
this
preamble.

In
the
proposal,
the
second
step
of
the
program
only
applied
to
nonroad
diesel
fuel,
while
locomotive
and
marine
diesel
fuel
could
remain
at
500
ppm
sulfur.
We
also
sought
comment
on
finalizing
the
15
ppm
sulfur
standard
for
LM
diesel
fuel
in
2010
along
with
nonroad
diesel
fuel,
as
well
as
delaying
it
until
as
late
as
2012
to
allow
for
an
additional
outlet
for
any
off­
specification
product
a
refinery
might
produce
as
it
shifts
all
of
its
distillate
production
to
15
ppm
sulfur.
92
We
are
finalizing
the
15
ppm
sulfur
standard
for
locomotive
and
marine
diesel
fuel,
along
with
nonroad
diesel
fuel,
for
several
reasons.
First,
it
will
provide
important
health
and
welfare
benefits
from
the
additional
sulfate
PM
and
SO
2
emission
reductions
as
early
as
possible.
Second,
it
is
technologically
feasible,
as
it
is
for
nonroad
diesel
fuel.
Third,
the
benefits
outweigh
the
costs
and
the
costs
do
not
otherwise
warrant
delaying
this
second
step
for
locomotive
and
marine.
As
194
shown
in
chapter
8
of
the
RIA,
the
costs
for
the
increment
of
LM
diesel
fuel
going
from
500
to
15
ppm
sulfur
is
just
$
0.20
billion
in
2030.
Fourth,
it
will
simplify
the
fuel
distribution
system
and
overall
design
of
the
fuel
program.
For
example,
the
addition
of
a
marker
to
locomotive
and
marine
diesel
fuel
after
2012
is
no
longer
necessary
to
successfully
enforce
the
program.
Finally,
it
will
allow
refiners
to
coordinate
plans
to
reduce
the
sulfur
content
of
all
of
their
off­
highway
diesel
fuel
at
one
time.

Our
primary
reason
in
the
NPRM
for
leaving
locomotive
and
marine
diesel
fuel
at
the
500
ppm
sulfur
specification
was
to
preserve
an
outlet
for
off­
specification
product
that
may
be
created
in
the
distribution
system
through
contamination
of
15
ppm
sulfur
diesel
fuel
with
higher
sulfur
distillates
and
for
off­
specification
batches
of
fuel
that
are
produced
by
refineries
during
the
first
couple
years
of
the
15
ppm
sulfur
program
(
when
they
are
still
perfecting
their
production
processes).
However,
we
have
concluded
that
it
is
not
necessary
to
leave
the
standard
for
all
locomotive
and
marine
diesel
fuel
at
the
500
ppm
sulfur
specification
to
address
these
concerns.
Setting
a
15
ppm
sulfur
standard
for
refiners
and
importers
in
2012,
but
maintaining
a
downstream
standard
for
locomotive
and
marine
diesel
fuel
at
500
ppm
sulfur
and
allowing
off­
specification
product
to
continue
to
be
sold
into
this
market
accomplishes
the
same
goal.

In
addition,
controlling
the
sulfur
content
of
NRLM
diesel
fuel
from
uncontrolled
levels
to
15
ppm
is
clearly
a
cost­
effective
fuel
control
program.
While
the
incremental
cost­
effectiveness
from
500
ppm
sulfur
to
15
ppm
sulfur
is
less
cost­
effective,
the
benefits
of
this
second
step
outweigh
the
costs,
the
concerns
about
a
market
for
off­
specification
product
have
been
addressed,
and
other
factors
discussed
above
support
the
reasonableness
of
this
approach.
The
body
of
evidence
strongly
supports
the
view
that
controlling
sulfur
in
NRLM
fuel
to
15
ppm,
through
a
two­
step
process,
is
quite
reasonable
in
light
of
the
emissions
reductions
achieved,
taking
costs
into
consideration.

Implementation
of
today's
rule
will
reduce
the
sulfur
level
of
almost
all
distillate
fuel
to
a
15
ppm
maximum
sulfur
level.
In
addition
to
the
small
refiner,
hardship,
and
other
provisions
adopted
in
this
rule,
EPA
is
adopting
several
provisions
that
will
help
ensure
a
smooth
transition
to
the
second
step
of
15
ppm
sulfur
diesel
fuel.
First,
refiners
and
importers
of
locomotive
and
marine
diesel
fuel,
a
small
segment
of
the
entire
distillate
pool,
will
be
required
to
meet
a
15
ppm
sulfur
standard
starting
June
1,
2012,
two
years
later
than
for
nonroad
diesel
fuel.
Second,
500
ppm
sulfur
diesel
fuel
generated
in
the
distribution
system
through
contamination
of
15
ppm
sulfur
fuel
can
be
marketed
in
the
nonroad,
locomotive
and
marine
market
until
June
2014,
and
in
the
locomotive
and
marine
market
after
that
date.
Third,
500
ppm
sulfur
diesel
fuel
produced
by
transmix
processors
from
contaminated
downstream
diesel
fuel
can
also
be
marketed
to
the
nonroad,
locomotive
and
marine
markets,
under
the
same
schedule.
While
today's
rule
does
not
contain
an
end
date
for
the
downstream
distribution
of
500
ppm
sulfur
locomotive
and
marine
fuel,
we
will
review
the
appropriateness
of
allowing
this
flexibility
based
on
experience
gained
from
implementation
of
the
15
ppm
sulfur
NRLM
diesel
fuel
standard.
We
expect
to
conduct
such
an
evaluation
in
2011.
93
In
some
cases
the
off­
specification
product
can
not
be
added
to
the
adjoining
products
because
of
the
applicable
sulfur
standards.
In
other
cases,
the
off­
specification
product,
called
transmix,
must
be
re­
processed
before
it
can
be
used.

195
When
EPA
adopted
a
15
ppm
sulfur
standard
for
highway
diesel
fuel,
we
included
several
provisions
to
ensure
a
smooth
transition
to
15
ppm
sulfur
highway
fuel.
One
provision
was
a
temporary
compliance
option,
with
an
averaging,
banking
and
trading
component.
In
a
similar
manner,
the
2012
deadline
for
15
ppm
sulfur
LM
fuel,
the
last,
relatively
small
segment
of
diesel
fuel,
will
help
ensure
that
the
entire
pool
of
diesel
fuel
is
smoothly
transitioned
to
the
15
ppm
sulfur
level
over
a
short
period
of
time.
(
See
section
8.3
of
the
summary
and
analysis
of
comments.)

EPA
is
also
adopting
two
provisions
aimed
at
smoothing
the
transition
of
the
distribution
system
to
ultra
low
sulfur
diesel
fuel.
These
provisions
are
designed
to
accommodate
offspecification
fuel
generated
in
the
distribution
system,
such
as
through
the
mixing
that
occurs
at
product
interfaces.
This
off­
specification
material
generally
cannot
be
added
in
any
significant
quantity
to
either
of
the
adjoining
products
that
produced
the
interface.
93
Under
today's
program,
as
discussed
in
more
detail
in
section
A.
3,
below,
off­
specification
material
that
is
generated
in
the
distribution
system
may
be
distributed
as
500
ppm
NRLM
diesel
fuel
from
June
1,
2010
through
May
31,
2014
and
as
500
ppm
LM
from
June
1,
2014
and
beyond.
Furthermore,
as
discussed
in
section
IV.
C,
below,
transmix
processors,
which
are
facilities
that
process
transmix
by
separating
it
into
its
components
(
e.
g.,
separating
gasoline
from
diesel
fuel),
are
treated
as
a
separate
class
of
refiners.
One
hundred
percent
of
the
diesel
fuel
they
produce
from
transmix
may
be
sold
as
high
sulfur
NRLM
until
June
1,
2010,
500
ppm
sulfur
NRLM
until
June
1,
2014,
and
500
ppm
sulfur
LM
diesel
fuel
after
June
1,
2014.

These
provisions
provide
refiners
and
importers
with
a
similar
degree
of
flexibility
for
offspecification
product
as
the
proposal
which
held
the
sulfur
standard
for
all
locomotive
and
marine
diesel
fuel
at
500
ppm
indefinitely.
If
off­
specification
product
is
produced,
there
is
a
temporary
outlet
for
it.
If
providing
the
off­
specification
product
to
a
locomotive
and
marine
market
is
difficult
under
this
final
rule,
such
that
a
refiner
will
choose
to
re­
process
it,
then
the
refiner
would
have
been
in
the
same
position
under
the
proposal.
Furthermore,
these
provisions
provide
the
refining
industry
an
alternative
to
reprocessing
the
off­
specification
material
created
in
the
distribution
system,
which
preserves
refining
capacity
for
the
production
of
new
fuel
volume,
helping
to
maintain
overall
diesel
fuel
supply.

As
with
the
500
ppm
sulfur
standard
under
the
first
step
of
today's
program,
refiners
and
importers
may
comply
with
the
15
ppm
sulfur
standard
by
either
producing
NRLM
diesel
fuel
containing
no
more
than
15
ppm
sulfur
or
by
obtaining
sulfur
credits
(
until
June
1,
2014),
as
described
below.
94
The
Effect
of
Cetane
Number
Increase
Due
to
Additives
on
NOX
Emissions
from
Heavy­
Duty
Highway
Engines,
Final
Technical
Report,
February
2003,
EPA420­
R­
03­
002.

196
c.
Cetane
Index
or
Aromatics
Standard
Currently,
in
addition
to
containing
no
more
than
500
ppm
sulfur,
highway
diesel
fuel
must
meet
a
minimum
cetane
index
level
of
40
or,
as
an
alternative,
contain
no
more
than
35
volume
percent
aromatics.
Today's
program
extends
this
cetane
index/
aromatics
content
specification
to
NRLM
diesel
fuel.

One
refining
company
commented
that
EPA
should
not
implement
the
cetane
index
and
aromatic
requirements
in
the
proposed
rule
since
the
impacts
are
weak
or
nonexistent
for
engines
to
be
used
in
the
future.
In
addition,
the
commenter
stated
that
the
vast
majority
of
diesel
fuel
already
meets
the
EPA
cetane
index/
aromatics
specification
for
highway
diesel
fuel
and
that
there
is
nothing
in
the
RIA
that
either
demonstrates
the
benefits
or
supports
the
need
for
such
a
requirement.
The
commenter
also
stated
that
EPA
should
not
set
a
requirement
simply
because
the
ASTM
standard
has
a
cetane
number
specification
for
a
particular
fuel.

Low
cetane
levels
are
associated
with
increases
in
NO
X
and
PM
emissions
from
current
nonroad
diesel
engines.
94
Thus,
we
expect
that
extending
the
cetane
index
specification
to
NRLM
diesel
fuel
will
directionally
lead
to
a
reduction
in
these
emissions
from
the
existing
fleet.
However,
because
the
vast
majority
of
NRLM
diesel
fuel
already
meets
the
specification,
the
NO
X
and
PM
emission
reductions
will
be
small.
At
the
same
time,
the
refining/
production
costs
associated
with
extending
the
cetane
index
specification
to
NRLM
diesel
fuel
are
negligible
as
current
NRLM
diesel
fuel
already
meets
a
more
stringent
ASTM
specification.

ASTM
already
recommends
a
cetane
number
specification
of
40
for
NRLM
diesel
fuel,
which
is,
in
general,
more
stringent
than
the
similar
40
cetane
index
specification.
Because
of
this,
the
vast
majority
of
current
NRLM
diesel
fuel
already
meets
the
EPA
cetane
index/
aromatics
specification
for
highway
diesel
fuel.
Thus,
the
cetane
index
specification
will
impact
only
a
few
refiners
and
there
will
be
little
overall
cost
associated
with
producing
fuel
to
meet
the
cetane/
aromatic
requirement.
In
fact,
as
discussed
in
chapter
5.9
of
the
RIA,
compliance
with
the
sulfur
standards
adopted
today
is
expected
to
result
in
a
small
cetane
increase
as
increases
in
cetane
correlate
with
decreases
in
sulfur,
leaving
little
or
no
further
control
to
meet
the
standard.

While
the
emissions
benefits
and
refining/
production
costs
of
extending
the
specification
to
NRLM
diesel
fuel
may
be
small,
the
extension
will
reduce
costs
by
giving
refiners
and
distributors
the
ability
to
fungibly
distribute
highway
and
NRLM
diesel
fuels
of
like
sulfur
content.
For
that
small
fraction
of
NRLM
diesel
fuel
today
that
does
not
meet
the
cetane
index
or
aromatics
specification,
the
requirement
will
eliminate
the
need
for
refiners
and
fuel
distributors
to
separately
distribute
fuels
of
different
cetane/
aromatics
specifications.
Requiring
NRLM
diesel
fuel
to
meet
this
cetane
index
specification
thus
gives
fuel
distributors
certainty
in
being
able
to
combine
shipments
of
highway
and
NRLM
diesel
fuels.
Perhaps
more
importantly,
it
can
also
give
engine
197
manufacturers
and
end­
users
the
confidence
they
need
that
their
fuel
will
meet
the
minimum
cetane
or
maximum
aromatics
standard.
Given
the
inherent
difficulty
in
segregating
two
otherwise
identical
fuels,
were
we
not
to
carry
over
these
standards
to
NRLM,
lower
cetane
NRLM
could
easily
find
its
way
into
current
highway
engines.
If
not
designed
for
this
lower
cetane
fuel,
these
engines
could
have
elevated
emission
levels
and
performance
problems.

Overall,
we
believe
that
there
will
be
a
small
reduction
in
NO
X
and
PM
emissions
from
current
engines
and
the
economic
benefits
from
more
efficient
fuel
distribution
will
likely
exceed
the
cost
of
raising
the
cetane
level
for
the
small
volume
of
NRLM
diesel
fuel
that
does
not
already
meet
the
cetane
index
or
aromatics
content
specification.

3.
Standards,
Deadlines,
and
Flexibilities
for
Fuel
Distributors
The
first
years
of
the
NRLM
diesel
fuel
program
include
various
flexibilities
to
smooth
the
refining
and
distribution
industry's
transition
to
15
ppm
sulfur
fuel.
These
flexibilities
include
a
2012
deadline
for
production
of
15
ppm
sulfur
locomotive
and
marine
diesel
fuel,
credit
provisions,
small
refiner
provisions,
hardship
provisions,
and
downstream
off­
specification
fuel
provisions.
As
a
result,
during
the
transition
years,
we
are
not
able
to
simply
enforce
the
sulfur
standards
downstream
based
on
a
single
sulfur
level
of
the
new
standard.
From
June
1,
2007
through
May
31,
2010,
both
500
ppm
sulfur
diesel
fuel
and
high
sulfur
diesel
fuel
can
be
produced,
distributed,
and
sold
for
use
in
NRLM
diesel
engines.
From
June
1,
2010
through
May
31,
2014,
both
15
ppm
sulfur
and
500
ppm
sulfur
diesel
fuel
can
be
produced,
distributed,
and
sold
for
use
in
NRLM
diesel
engines.
Beyond
June
1,
2014,
both
15
ppm
sulfur
and
500
ppm
sulfur
diesel
fuel
that
is
produced
from
fuel
product
downgrade
and
transmix
in
the
distribution
system
can
be
distributed
and
sold
for
use
in
locomotive
and
marine
diesel
engines.
As
these
transition
flexibilities
expire,
however,
we
are
able
to
streamline
our
downstream
enforcement
provisions.

a.
Standards
and
Deadlines
from
June
1,
2007
through
May
31,
2010
As
soon
as
the
program
begins
on
June
1,
2007,
all
NRLM
diesel
fuel
must
be
designated
or
classified
and
must
comply
with
the
designation
or
classification
stated
on
its
product
transfer
document
(
PTD),
pump
label,
or
other
documentation.
In
other
words,
if
the
fuel
is
intended
for
sale
as
NRLM
diesel
fuel
and
is
labeled
as
500
ppm
sulfur
diesel
fuel,
then
beginning
June
1,
2007,
it
must
comply
with
the
500
ppm
sulfur
standard.
Similarly,
if
fuel
is
intended
for
sale
as
NRLM
diesel
fuel
and
is
labeled
as
15
ppm
sulfur,
then
beginning
June
1,
2010
(
or
June
1,
2009
under
the
early
credit
provisions),
it
must
comply
with
the
15
ppm
sulfur
standard.

Beginning
June
1,
2010,
all
NRLM
diesel
fuel
produced
or
imported
is
required
to
meet
at
least
a
500
ppm
sulfur
limit.
In
order
to
allow
for
a
smooth
and
orderly
transition
to
500
ppm
sulfur
NRLM
diesel
fuel
in
the
distribution
system,
and
allow
any
remaining
high
sulfur
fuel
to
be
sold,
we
are
providing
parties
downstream
of
refineries
time
to
turnover
their
NRLM
tanks
to
500
ppm
sulfur
diesel
fuel.
At
the
terminal
level,
all
NRLM
diesel
fuel
must
meet
at
least
the
500
ppm
sulfur
standard
beginning
August
1,
2010.
At
any
wholesale
purchaser­
consumer
facilities
and
any
95
A
bulk
plant
is
a
secondary
distributor
of
refined
petroleum
products.
They
typically
receive
fuel
from
terminals
and
distribute
fuel
in
bulk
by
truck
to
end
users.
Consequently,
while
for
highway
fuel,
bulk
plants
often
serve
the
role
of
a
fuel
distributor,
delivering
fuel
to
retail
stations,
for
nonroad
fuel,

they
often
serve
the
role
of
the
retailer,
delivering
fuel
directly
to
the
end­
user.

96
By
December
1,
2010,
all
NRLM
diesel
fuel,
including
fuel
in
end­
user
tanks,
must
comply
with
at
least
the
500
ppm
sulfur
standard.

97
By
December
1,
2014,
all
NR
diesel
fuel,
including
fuel
in
end­
user
tanks,
must
comply
with
at
least
the
15
ppm
sulfur
standard.

198
retail
stations
carrying
NRLM
diesel
fuel,
including
bulk
plants
that
serve
as
retailers,
all
diesel
fuel
must
meet
the
500
ppm
sulfur
standard
beginning
October
1,
2010.95
Thus,
beginning
October
1,
2010,
high
sulfur
(
greater
than
500
ppm
sulfur)
NRLM
diesel
fuel
may
no
longer
legally
exist
in
the
fuel
distribution
system.
96
Although
we
expect
that
most
NRLM
diesel
fuel
in
the
distribution
system
will
be
subject
to
the
500
ppm
sulfur
standard
during
the
period
from
June
1,
2007
through
May
31,
2010,
based
on
its
designation
or
classification,
some
of
the
500
ppm
sulfur
NRLM
diesel
fuel
may
be
mixed
with
high
sulfur
NRLM
diesel
fuel.
Since
the
blended
product
will
likely
no
longer
meet
the
500
ppm
sulfur
standard,
it
must
be
re­
designated
and
labeled
as
high
sulfur
NRLM
diesel
fuel.
Similarly,
fuel
that
results
from
blending
500
ppm
sulfur
NRLM
diesel
fuel
and
heating
oil
must
be
re­
designated
and
labeled
as
heating
oil.

b.
Standards
and
Deadlines
from
June
1,
2010
through
May
31,
2014
Beginning
June
1,
2010,
most
NR
diesel
fuel
will
be
required
to
meet
the
15
ppm
sulfur
standard,
and
beginning
June
1,
2012,
most
LM
diesel
fuel
will
be
required
to
meet
the
15
ppm
sulfur
standard.
However,
some
production
of
500
ppm
sulfur
NRLM
diesel
fuel
may
continue
through
May
31,
2014.
As
with
the
delayed
downstream
compliance
dates
for
the
500
ppm
sulfur
standard
under
the
first
step
of
today's
program,
parties
downstream
of
refineries
will
be
allowed
additional
time
to
turnover
their
tanks
to
15
ppm
sulfur
NR
diesel
fuel.
Specifically,
at
the
terminal
level,
all
NR
diesel
fuel
will
be
required
to
meet
the
15
ppm
sulfur
standard
beginning
August
1,
2014.
At
any
wholesale
purchaser­
consumer
facilities
and
retail
stations
carrying
all
NR
diesel
fuel,
including
bulk
plants
serving
as
retailers,
NR
diesel
fuel
must
meet
the
15
ppm
sulfur
standard
beginning
October
1,
2014.
Thus,
beginning
October
1,
2014,
500
ppm
sulfur
NR
diesel
fuel
may
no
longer
legally
exist
in
the
fuel
distribution
system.
97
Like
the
first
step
to
500
ppm
sulfur,
prior
to
these
2014
downstream
deadlines
all
NRLM
diesel
fuel
would
still
be
designated
or
classified
with
respect
to
sulfur
level
and
required
to
meet
the
designation
or
classification
stated
on
its
PTD,
pump
label,
or
other
documentation.
98
Segregated
interface
refers
to
the
mixing
zone
between
two
batches
of
fuel
that
abut
each
other
in
the
pipeline,
where
the
volume
in
the
mixing
zone
can
not
be
cut
into
either
of
the
fuel
batches,
but
can
still
meet
another
fuel
product
specification
without
reprocessing,
provided
that
it
is
drawn
off
of
the
pipeline
separately
and
segregated.

199
c.
Sulfur
Standard
for
NRLM
Diesel
Fuel
Beginning
June
1,
2014
As
discussed
above,
all
refiners
will
be
required
to
produce
and
importers
will
be
required
to
import
only
15
ppm
sulfur
NRLM
diesel
fuel
by
June
1,
2014.
However,
we
will
continue
to
allow
500
ppm
sulfur
diesel
fuel
to
be
sold
into
the
LM
diesel
fuel
markets
beyond
2014.
The
LM
diesel
fuel
markets
are
expected
to
provide
a
valuable
outlet
for
higher
sulfur
distillate
fuel
produced
in
the
distribution
system,
at
least
through
the
early
years
of
the
program.
Consequently,
beyond
2014,
both
15
ppm
sulfur
and
500
ppm
sulfur
LM
diesel
fuel
may
continue
to
exist
in
the
distribution
system,
and
each
fuel
must
comply
with
the
designation
stated
on
its
PTD,
pump
label,
or
other
documentation.

d.
Interface/
Transmix
Flexibility
for
Fuel
Distributors
As
described
above,
today's
program
provides
flexibility
to
the
distribution
system
by
allowing
interface/
transmix
material
generated
within
the
distribution
system
to
be
sold
into
the
NRLM
diesel
fuel
markets.
Specifically,
any
fuel
interface/
transmix
generated
in
the
fuel
distribution
system
may
be
sold
as
1)
high
sulfur
NRLM
diesel
fuel
or
heating
oil
from
June
1,
2007
through
May
31,
2010;
2)
500
ppm
sulfur
NRLM
diesel
fuel
or
heating
oil
from
June
1,
2010
through
May
31,
2014;
or
3)
500
ppm
sulfur
LM
diesel
fuel
or
heating
oil
after
June
1,
2014.

Hence,
beginning
June
1,
2014,
interface/
transmix
material
exceeding
15
ppm
sulfur
may
only
be
sold
into
the
LM
diesel
fuel
or
heating
oil
markets.
As
discussed
above,
the
downstream
standard
for
LM
diesel
fuel
will
be
500
ppm
sulfur.
However,
heating
oil
may
not
be
shifted
into
the
LM
markets.
Parties
in
the
distribution
system
receiving
diesel
fuel
with
a
sulfur
content
greater
than
15
ppm
sulfur
must
maintain
records
and
report
to
EPA
information
demonstrating
that
they
did
not
shift
heating
oil
into
the
LM
markets,
as
discussed
in
section
IV.
D.

The
generation
of
greater
than
15
ppm
sulfur
distillate
fuel
from
pipeline
interface/
transmix
cannot
be
avoided
due
to
the
physical
realities
of
a
multi­
product
fuel
distribution
system.
Such
fuel
first
appears
at
the
terminus
of
the
pipeline
distribution
system;
at
terminals
due
to
the
generation
of
segregated
interface,
or
at
transmix
processing
facilities.
98
In
areas
where
there
is
a
strong
demand
for
heating
oil,
much
of
this
pipeline­
generated
off­
specification
fuel
can
be
sold
into
the
heating
oil
market,
just
as
it
is
today.
However,
in
many
areas
of
the
country
the
demand
99
As
mentioned
above,
the
Agency
intends
in
the
near
future
to
initiate
a
rulemaking
to
adopt
new
emission
standards
for
locomotive
and
marine
engines.
An
advanced
notice
of
proposed
rulemaking
(
ANPRM)
for
this
rule
is
published
elsewhere
in
today's
Federal
Register
[
INSERT
DATE
OF
PUBLICATION].
While
we
are
not
finalizing
a
sunset
date
for
this
downgrade
provision
in
today's
final
rule,
we
are
evaluating
the
appropriateness
of
establishing
a
sunset
date
on
this
provision
in
the
context
of
the
subsequent
engine
standards
rule.
We
also
intend
to
review
the
appropriateness
of
any
sunset
provision
in
light
of
experience
gained
from
implementation
of
the
15
ppm
sulfur
NRLM
diesel
fuel
standard.
We
would
conduct
such
an
evaluation
in
2011.

100
Although,
as
mentioned
above,
the
Agency
intends
in
the
near
future
to
initiate
a
rulemaking
to
adopt
new
emission
standards
for
locomotive
and
marine
engines.
An
advanced
notice
of
proposed
rulemaking
(
ANPRM)
for
this
rule
is
published
elsewhere
in
today's
Federal
Register
[
INSERT
200
for
heating
oil
would
not
be
sufficient
to
accommodate
distillate
fuel
exceeding
15
ppm
sulfur
that
is
generated
in
the
pipeline.
Therefore,
such
fuel
would
need
to
be
returned
to
a
refinery
for
reprocessing
to
meet
a
15
ppm
sulfur
standard.
In
addition,
some
refiners
may
be
reluctant
to
accept
such
material
for
reprocessing
given
the
impact
this
would
have
on
their
refinery
operations.
More
importantly,
because
such
material
appears
at
the
terminus
of
the
pipeline
distribution
system
and
often
where
no
access
to
pipeline
or
marine
shipment
is
available,
it
would
have
to
be
shipped
back
to
a
refinery
by
truck,
or
rail
if
available,
at
additional
cost.

As
discussed
in
chapter
7
of
the
RIA,
fuel
generated
from
such
interface/
transmix
will
typically
meet
a
500
ppm
sulfur
standard.
Therefore,
allowing
the
continued
use
of
such
500
ppm
sulfur
diesel
fuel
in
locomotive
and
marine
engines
could
reduce
the
burden
on
the
fuel
distribution
industry
by
lowering
costs.
Our
cost
estimates
of
marketing
such
fuel
include
additional
shipping
charges
for
situations
where
there
is
not
a
local
locomotive
or
marine
market
(
see
section
VI
of
this
preamble).
99
Allowing
the
continued
sale
of
500
ppm
sulfur
diesel
fuel
into
the
locomotive
and
marine
markets
without
requiring
it
to
be
reprocessed
will
also
help
preserve
refining
capacity
for
the
overall
diesel
fuel
production.
Therefore,
this
provision
also
serves
to
address
lingering
concerns
expressed
by
some
refiners
regarding
the
impacts
of
the
15
ppm
sulfur
standard
for
highway
and
NRLM
diesel
fuel
on
overall
diesel
fuel
supply.

Downstream­
generated
500
ppm
sulfur
diesel
fuel
may
only
be
used
in
nonroad
engines
until
December
1,
2014,
due
to
concerns
regarding
enforceability
and
the
increased
potential
for
misfueling
of
nonroad
equipment
(
equipment
with
advanced
emission
controls).
Beginning
with
the
2011
model
year,
such
equipment
will
require
the
use
of
15
ppm
sulfur
diesel
fuel
to
operate
properly.
The
same
concerns
do
not
exist
regarding
the
continued
use
of
such
500
ppm
sulfur
diesel
fuel
in
locomotive
and
marine
engines
for
three
reasons.
First,
locomotive
and
marine
engines
are
not
currently
required
to
be
equipped
with
the
sulfur
sensitive
emissions
aftertreatment
that
will
start
being
used
on
nonroad
equipment
in
2011.100
Second,
locomotive
and
marine
DATE
OF
PUBLICATION].

201
markets
are
centrally
fueled
to
a
much
greater
extent
than
nonroad
markets,
and
thus
enforceability
is
not
as
significant
of
an
issue.
Finally,
we
believe
the
program's
designate
and
track
provisions
discussed
below
will
be
sufficient
to
enforce
the
limits
on
production
and
use
of
500
ppm
sulfur
diesel
fuel.

It
is
difficult
to
project
exactly
how
much
of
this
downstream
generated
downgraded
fuel
could
be
segregated
and
shipped
to
LM
markets.
However,
it
is
clear
that
this
provision
represents
an
important
flexibility
for
the
distribution
system.
In
fact,
it
provides
virtually
the
same
flexibility
as
provided
by
the
proposal
to
handle
off­
specification
product.
In
both
cases,
use
of
the
flexibility
is
dependent
on
the
ability
to
segregate
the
interface
and
transport
it
to
available
LM
markets.
While
today's
rule
does
not
contain
an
end
date
for
the
downstream
distribution
of
500
ppm
sulfur
locomotive
and
marine
fuel,
we
will
review
the
appropriateness
of
allowing
this
flexibility
based
on
experience
gained
from
implementation
of
the
15
ppm
sulfur
NRLM
diesel
fuel
standard.
We
expect
to
conduct
such
an
evaluation
in
2011.

A
summary
of
the
NRLM
sulfur
levels
and
final
deadlines
for
refiners,
importers,
terminals,
and
other
downstream
parties
is
shown
in
table
IV­
1
below.

Table
IV­
1.
 
500
ppm
Sulfur
and
15
ppm
Sulfur
NRLM
Final
Compliance
Dates
Refiners
and
Importers
Credit,

Small
Refiner
Terminals
Bulk
Plants,

Wholesale
Purchaser­

Consumers
and
Retail
Outlets
Other
Locations
500
ppm
NRLM
June
1,
2007
June
1,
2010
August
1,
2010
October
1,
2010
December
1,
2010
15
ppm
NR
June
1,
2010
June
1,
2014
August
1,
2014
October
1,
2014
December
1,
2014
15
ppm
LM
June
1,
2012
June
1,
2014
­
­
­

4.
Diesel
Sulfur
Credit
Banking
and
Trading
Provisions
Today's
final
program
includes
provisions
for
refiners
and
importers
to
generate
early
credits
for
the
production
of
500
ppm
sulfur
NRLM
diesel
fuel
prior
to
June
1,
2007
and
for
the
production
of
15
ppm
sulfur
NRLM
diesel
fuel
prior
to
June
1,
2010.
These
credit
banking
and
trading
provisions
will
provide
implementation
flexibility
by
facilitating
a
somewhat
smoother
transition
at
the
start
of
the
program
in
2007,
with
some
refineries/
import
facilities
complying
early,
others
on
time,
and
others
a
little
later.
These
credit
banking
and
trading
provisions
may
101
We
are
not
adopting
specific
provisions
to
generate
credits
for
early
production
of
LM
diesel
fuel
prior
to
June
1,
2012.
The
difference
in
start
date
between
2010
and
2012
already
provides
additional
flexibility
to
producers
of
LM
diesel
fuel,
and
setting
separate
credit
generation
periods
for
NR
and
LM
diesel
fuel
would
unnecessarily
complicate
the
compliance
assurance
provisions.

202
also
facilitate
some
of
the
environmental
benefits
of
the
program
being
achieved
earlier
than
otherwise
required,
and
may
increase
the
overall
environmental
benefits
of
the
program.
As
discussed
below,
overall
benefits
will
accrue
if
refiners
produce
500
ppm
earlier
in
lieu
of
high
sulfur
NRLM
and
then
bank
those
credits
to
continue
producing
500
ppm
sulfur
NR
diesel
fuel
in
2010
or
500
ppm
LM
diesel
fuel
in
2012
in
lieu
of
15
ppm.
101
Specifically,
credits
generated
under
the
NRLM
diesel
fuel
program
may
be
banked
and
later
used
to
delay
compliance
with
either
the
500
ppm
sulfur
NRLM
standard
that
begins
in
2007,
the
15
ppm
sulfur
NR
standard
that
begins
in
2010,
or
the
15
ppm
sulfur
LM
standard
that
begins
in
2012.
Credits
may
also
be
traded
within
companies
such
that
credits
generated
at
one
refinery/
import
facility
in
a
given
company
may
be
traded
to
another
refinery/
import
facility
within
that
same
company.
In
addition,
refiners
or
importers
may
purchase
credits
generated
by
other
refiners
or
importers
to
meet
the
program
requirements.
Finally,
and
perhaps
most
importantly,
individual
refineries/
import
facilities
may
be
able
to
use
credits
to
permit
the
continued
sale
of
otherwise
off­
specification
product
at
the
beginning
of
the
program's
second
step
when
they
are
still
adjusting
their
operations
for
consistent
production/
importation
of
NRLM
diesel
fuel
that
is
subject
to
the
new
sulfur
standards.

a.
Credit
Generation
from
June
1,
2006
through
May
31,
2007
Credits
may
be
generated
under
today's
program
to
allow
for
the
production
of
high
sulfur
NRLM
diesel
fuel
after
June
1,
2007.
A
refiner
or
importer
may
obtain
credit
for
early
production/
importation
of
fuel
meeting
the
500
ppm
sulfur
standard
that
they
designate
as
NRLM
diesel
fuel,
from
June
1,
2006
through
May
31,
2007.
In
addition,
small
refiners
may
also
generate
credits
for
the
early
production
of
500
ppm
sulfur
diesel
fuel
that
they
designate
as
NRLM
diesel
fuel.
As
described
in
section
IV.
B,
below,
small
refiners
are
not
required
to
produce
any
500
ppm
sulfur
NRLM
diesel
fuel
until
June
1,
2010.
Those
small
refiners
who
choose
to
comply
with
the
500
ppm
sulfur
standard
earlier
than
required,
that
is
before
June
1,
2010,
may
generate
credits
for
any
volume
of
diesel
fuel
they
produce
from
June
1,
2007
through
May
31,
2010
and
designate
as
NRLM.
Credits
for
the
early
production
of
500
ppm
sulfur
fuel
(
including
by
small
refineries)
are
fungible,
may
be
banked
for
future
use,
or
traded
to
any
other
refiner
or
importer
nationwide.
In
order
to
ensure
that
these
early
credits
are
real
and
not
merely
shifts
from
the
highway
market,
both
early
credits
and
small
refinery
credits
will
be
subject
to
a
limit
determined
by
the
following
formula:

Credit
HS
=
(
Vol
15
+
Vol
500)
­
Vol
hwy
102
For
the
purposes
of
this
rule,
credits
are
labeled
on
the
basis
of
their
use
in
order
to
follow
the
convention
used
in
the
highway
diesel
rule.
A
high­
sulfur
credit
is
generated
through
the
production
of
one
gallon
of
500
ppm
sulfur
NRLM
diesel
fuel
and
allows
the
production
of
one
gallon
of
high
sulfur
NRLM
diesel
fuel.

203
Credit
HS
Limit
=
(
Vol
15
+
Vol
500)
­
Base
hwy
Where:
Credit
500
Limit
=
Limit
for
500
ppm
NRLM
credits
Credit
HS
=
High­
Sulfur
NRLM
credits102
Vol
15
=
Volume
of
15
ppm
sulfur
diesel
fuel
produced
and
designated
as
highway
or
NRLM
Vol
500
=
Volume
of
500
ppm
sulfur
diesel
fuel
produced
and
designated
as
highway
or
NRLM
Base
hwy
=
2003­
2005
highway
diesel
fuel
baseline
volume
Vol
hwy
=
Volume
of
diesel
fuel
produced
and
designated
as
highway
If
the
excess
production
is
15
ppm
sulfur
diesel
fuel
instead
of
500
ppm
sulfur
diesel
fuel,
then
the
refiner
will
have
the
option
of
generating
500
ppm
sulfur
credits
under
the
highway
diesel
fuel
program.
Credit
may
not
be
earned
under
both
programs
for
a
given
volume
of
500
ppm
sulfur
or
15
ppm
sulfur
diesel
fuel.

b.
Credit
Generation
from
June
1,
2009
through
May
31,
2010
In
addition
to
allowing
credit
for
the
early
production
of
500
ppm
sulfur
NRLM
diesel
fuel,
today's
program
also
allows
credit
for
the
early
production
of
15
ppm
sulfur
NRLM
diesel
fuel.
Specifically,
refiners
and
importers
may
obtain
credit
for
early
production/
importation
of
fuel
meeting
the
15
ppm
sulfur
standard
and
that
they
designate
as
NRLM
from
June
1,
2009
through
May
31,
2010.
In
addition,
small
refiners,
which
are
not
required
to
produce
any
15
ppm
sulfur
NRLM
diesel
fuel
until
June
1,
2014,
may
also
generate
credits
for
the
early
production
of
any
volume
of
15
ppm
sulfur
diesel
fuel
that
they
designate
as
NRLM
from
June
1,
2010
through
December
31,
2013.
Again,
these
early
credits
are
fungible,
may
be
banked
for
future
use,
or
traded
to
any
other
refinery
or
importer
nationwide.
However,
in
order
to
ensure
these
credits
are
real
and
not
merely
shifts
from
the
highway
market,
credits
for
the
early
production
or
importation
of
15
ppm
sulfur
fuel
will
be
subject
to
a
limit
determined
by
the
following
formula:

Credit
500
=
Vol
15
­
Vol
15hwy
Credit
500
Limit
=
Vol
15
­
Base
15hwy
Where:
Credit
500
Limit
=
Limit
for
500
ppm
sulfur
NRLM
credits
204
Vol
15
=
Volume
of
15
ppm
sulfur
diesel
fuel
produced
and
designated
as
highway
or
NRLM
Base
15hwy
=
2006­
2008
15
ppm
sulfur
highway
diesel
fuel
baseline
volume
Hence,
to
generate
credits,
a
refiner
or
importer's
highway
diesel
fuel
volume
for
the
compliance
period
must
be
greater
than
or
equal
to
the
baseline
volume.
That
is,
a
refiner
or
importer
may
only
generate
credits
for
"
new"
volumes
of
15
ppm
sulfur
diesel
fuel
that
it
produces.
If
their
highway
diesel
fuel
volume
were
to
drop
below
the
baseline
volume,
that
would
likely
indicate
a
shift
in
production
from
the
highway
market
to
generate
15
ppm
sulfur
NRLM
diesel
fuel
credits.

c.
Credit
Use
There
are
two
ways
in
which
refiners
or
importers
may
use
high­
sulfur
NRLM
credits
under
the
NRLM
diesel
fuel
program.
First,
credits
may
be
used
during
the
period
from
June
1,
2007
through
May
31,
2010
to
continue
to
produce
high
sulfur
NRLM
diesel
fuel.
Any
high
sulfur
NRLM
diesel
fuel
that
is
produced,
however,
must
be
designated
and
labeled
as
such
for
tracking
purposes
throughout
the
distribution
system
and
be
dyed
red
at
the
refinery
gate.

The
second
way
in
which
refiners
and
importer
could
use
high­
sulfur
NRLM
credits
is
by
banking
them
for
use
during
the
June
1,
2010
through
May
31,
2014
period.
Credits
used
in
this
manner
would
provide
a
net
environmental
benefit,
since
they
were
generated
by
reducing
the
sulfur
level
from
approximately
3000
ppm
to
less
than
500
ppm
(
a
net
change
of
2500
ppm
sulfur),
but
when
used
only
allow
the
sulfur
level
to
increase
from
15
ppm
to
500
ppm
(
a
net
change
of
less
than
500
ppm
sulfur).
500
ppm
sulfur
credits
generated
from
the
early
production
of
15
ppm
sulfur
NRLM
diesel
fuel
may
also
be
used
from
June
1,
2010
through
May
31,
2014.
Thus,
during
this
period,
when
the
15
ppm
sulfur
standard
is
in
effect
for
nonroad
diesel
fuel,
refiners/
importers
may
use
either
high
sulfur
credits
or
500
ppm
sulfur
credits
to
continue
producing/
importing
500
ppm
sulfur
nonroad
diesel
fuel.
Any
500
ppm
sulfur
diesel
fuel
that
is
produced,
however,
must
be
appropriately
designated
and
labeled
for
tracking
purposes
throughout
the
distribution
system,
and
cannot
be
sold
for
use
in
2011
and
later
model
year
nonroad
engines.
From
June
1,
2012,
when
the
15
ppm
sulfur
standard
for
LM
diesel
fuel
becomes
effective,
through
May
31,
2014,
refiners/
importers
may
use
either
high
sulfur
credits
or
500
ppm
sulfur
credits
to
continue
producing/
importing
500
ppm
sulfur
NRLM
diesel
fuel.
All
credits
expire
after
May
31,
2014.
Hence,
beginning
June
1,
2014,
all
NRLM
diesel
fuel
produced
by
refiners
or
imported
in
the
U.
S.
will
be
subject
to
the
15
ppm
sulfur
standard,
except
LM
diesel
fuel
produced
by
transmix
processors
from
transmix
can
continue
to
meet
the
500
ppm
sulfur
limit.

We
proposed
that
all
credits
would
expire
May
31,
2012,
however
we
are
finalizing
an
expiration
date
of
May
31,
2014
based
on
the
comments
we
received.
The
additional
two
years
that
we
are
now
allowing
for
credit
use
1)
will
provide
a
longer
period
for
refiners
to
sell
off­
205
specification
fuel
instead
of
having
to
reprocess
it,
2)
is
an
environmentally
neutral
change
to
the
overall
program,
and
3)
is
now
consistent
with
the
end­
date
for
small
refiner
flexibility.

While
credits
can
be
generated
and
traded
nationwide,
they
are
restricted
from
use
in
certain
parts
of
the
country
under
the
provisions
of
this
final
rule.
As
discussed
in
section
IV.
D,
we
are
avoiding
the
burden
to
terminals
of
adding
marker
to
heating
oil
in
those
areas
of
the
country
where
demand
for
heating
oil
is
expected
to
continue
to
remain
high
after
today's
final
rule.
The
NRLM
diesel
fuel
sulfur
standards
will
be
enforced
based
on
sulfur
level
in
these
areas,
not
through
the
refinery
designation
and
marker
provisions.
Consequently,
in
the
area
defined
in
section
IV.
D
comprising
most
of
the
Northeast
and
Mid­
Atlantic
region
of
the
country,
as
well
as
in
the
State
of
Alaska,
many
of
the
fuel
program's
flexibilities,
including
refiners'
ability
to
use
credits,
are
not
allowed.
Refiners
and
importers
may
not
use
credits
to
produce
or
import
diesel
fuel
with
a
sulfur
content
greater
than
500
ppm
beginning
June
1,
2007
or
15
ppm
beginning
June
1,
2010,
for
sale
or
distribution
in
this
Northeast/
Mid­
Atlantic
area
or
the
State
of
Alaska.
However,
credits
generated
in
these
areas
can
be
sold
to
other
refiners
and/
or
importers
for
use
outside
these
areas.

B.
Hardship
Relief
Provisions
for
Qualifying
Refiners
As
in
our
gasoline
sulfur
and
highway
diesel
fuel
sulfur
programs,
today's
program
contains
the
following
hardship
relief
provisions
to
provide
regulatory
flexibility
to
challenged
refiners:
°
Small
refiner
hardship
for
qualifying
small
refiners;
°
General
hardship
for
any
refiner
experiencing
either
­
1)
extreme
unforeseen
circumstances
such
as
natural
disaster
or
acts
of
God;
or
2)
extreme
hardship
circumstances
such
as
financial
or
technical
hardship.

Similar
provisions
have
proved
invaluable
for
some
refiners
in
the
recent
implementation
of
the
gasoline
sulfur
standards,
as
well
as
for
refiners'
planning
for
the
highway
diesel
standards.
The
details
of
these
provisions
are
discussed
below.

1.
Hardship
Provisions
for
Qualifying
Small
Refiners
As
in
previous
fuel
rulemakings,
our
justification
for
including
provisions
specific
to
small
refiners
is
that,
in
general,
small
refiners
generally
have
a
degree
of
hardship
in
complying
with
the
standards
compared
to
other
refiners.
In
the
NPRM,
we
proposed
flexibilities/
transition
provisions,
or
"
hardship
provisions"
(
these
terms
are
equivalent),
for
small
refiners.
We
are
adopting
the
provisions
that
were
proposed
for
small
refiners
virtually
unchanged,
and
including
similar
provisions
for
the
treatment
of
locomotive
and
marine
fuel.

a.
Regulatory
Process
and
Justification
for
Small
Refiner
Relief
In
developing
our
NRLM
diesel
fuel
sulfur
program,
we
evaluated
the
environmental
need
as
well
as
the
technical
and
financial
ability
of
refiners
to
meet
the
500
and
15
ppm
sulfur
standards
206
as
expeditiously
as
possible.
We
believe
it
is
feasible
and
necessary
for
the
vast
majority
of
the
program
to
be
implemented
in
the
established
time
frame
to
achieve
the
air
quality
benefits
as
soon
as
possible.
Based
on
information
available
from
small
refiners
and
others,
we
believe
that
refiners
classified
as
small
generally
face
unique
circumstances
with
regard
to
compliance
with
environmental
programs,
compared
to
larger
refiners.
Consequently,
as
discussed
below,
we
are
finalizing
several
special
provisions
for
refiners
that
qualify
as
"
small
refiners"
to
reduce
the
disproportionate
burden
that
today's
program
will
have
on
them.

Small
refiners
generally
lack
the
resources
that
are
available
to
large
refining
companies,
including
those
large
companies
that
own
small­
capacity
refineries,
to
raise
capital
for
investing
in
desulfurization
equipment,
such
as
shifting
of
internal
funds,
securing
of
financing,
or
selling
of
assets.
Small
refiners
are
also
likely
to
have
more
difficulty
in
competing
for
engineering
and
construction
resources
needed
for
the
installation
of
the
desulfurization
equipment
which
will
likely
be
required
to
meet
the
standards
finalized
in
this
action.

Because
small
refiners
are
more
likely
to
face
adverse
circumstances
with
regard
to
regulatory
compliance
than
larger
refiners,
we
are
finalizing
interim
provisions
that
will
provide
additional
time
for
refineries
owned
by
small
refiners
to
meet
the
sulfur
standards.
This
approach
will
allow
the
overall
program
to
begin
as
early
as
possible,
avoiding
the
need
for
delay
in
order
to
address
the
ability
of
small
refiners
to
comply.

i.
Regulatory
Flexibility
Process
for
Small
Refiners
As
explained
in
the
discussion
of
our
compliance
with
the
Regulatory
Flexibility
Act
(
RFA)
in
section
X.
C
of
this
preamble,
and
in
the
Final
Regulatory
Flexibility
Analysis
in
chapter
11
of
the
RIA,
we
considered
the
impacts
of
today's
regulations
on
small
businesses.
Most
of
our
analysis
of
small
business
impacts
was
performed
as
part
of
the
Small
Business
Advocacy
Review
(
SBAR)
Panel
convened
by
EPA,
pursuant
to
the
RFA
as
amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA).
The
Panel's
final
report
is
available
in
the
rulemaking
public
docket
(
Docket
A­
2001­
28,
Document
No.
II­
A­
172).

For
the
SBREFA
process,
EPA
conducted
outreach,
fact­
finding,
and
analysis
of
the
potential
impacts
of
the
proposed
nonroad
regulations
on
small
businesses.
Based
on
these
discussions
and
analyses
by
all
panel
members,
the
Panel
concluded
that
small
refiners
in
general
would
likely
experience
a
significant
and
disproportionate
financial
burden
in
reaching
the
objectives
of
the
proposed
nonroad
diesel
fuel
sulfur
program.

One
indication
of
the
disproportionate
burden
on
small
refiners
is
the
relatively
high
cost
per
gallon
projected
for
producing
NRLM
diesel
fuel
under
today's
program.
Refinery
modeling
of
refineries
owned
by
refiners
likely
to
qualify
as
small
refiners,
and
of
refineries
owned
by
other
non­
small
refiners,
indicates
significantly
higher
refining
costs
for
small
refiners.
Specifically,
we
project
that
without
special
provisions,
refining
costs
for
small
refiners
on
average
would
be
about
207
two
cents
per
gallon
higher
than
for
other
refiners
in
the
same
PADD
to
meet
the
15
ppm
sulfur
standard.

The
Panel
also
noted
that
the
burden
imposed
on
small
refiners
by
the
proposed
sulfur
standards
may
vary
from
refiner
to
refiner.
Thus,
the
Panel
recommended
more
than
one
type
of
burden
mitigation
so
that
most,
if
not
all,
small
refiners
could
benefit.
We
considered
the
issues
raised
during
the
SBREFA
process,
and
discussed
them
in
the
NPRM,
and
have
decided
to
finalize
each
of
the
provisions
recommended
by
the
Panel.
A
discussion
of
the
comments
we
received
regarding
small
refiners
and
terminal
operators,
and
our
responses
to
those
comments,
can
be
found
in
section
X.
C
of
this
preamble,
and
also
the
Summary
and
Analysis
of
Comments.

ii.
Rationale
for
Small
Refiner
Regulatory
Flexibility
Provisions
Generally,
we
structured
the
small
refiner
provisions
to
reduce
the
burden
on
small
refiners
while
expeditiously
achieving
air
quality
benefits
and
ensuring
that
the
availability
of
15
ppm
sulfur
NR
diesel
fuel
will
coincide
with
the
introduction
of
2011
model
year
nonroad
diesel
engines
and
equipment.
We
believe
the
special
provisions
for
small
refiners
are
necessary
and
appropriate
for
several
reasons.

First,
the
compliance
schedule
for
today's
program,
combined
with
special
relief
provisions
for
small
refiners,
will
achieve
the
air
quality
benefits
of
the
program
as
soon
as
possible,
while
helping
to
ensure
that
small
refiners
will
have
adequate
time
to
raise
capital
for
new
or
upgraded
fuel
desulfurization
equipment.
Most
small
refiners
have
limited
additional
sources
of
income
beyond
refinery
earnings
for
financing
and
typically
do
not
have
the
financial
backing
that
larger
and
generally
more
integrated
companies
have.
Therefore,
additional
time
to
accumulate
capital
internally
or
to
secure
capital
financing
from
lenders
can
be
central
to
their
ability
to
comply.

Second,
we
recognize
that
while
the
sulfur
levels
in
today's
program
can
be
achieved
using
conventional
refining
technologies,
new
technologies
are
also
being
developed
that
may
reduce
the
capital
and/
or
operating
costs
of
sulfur
removal.
Thus,
we
believe
that
providing
small
refiners
some
additional
time
to
allow
for
new
technologies
to
be
proven
out
by
other
refiners
will
have
the
added
benefit
of
reducing
the
risks
faced
by
small
refiners.
The
added
time
will
likely
enable
small
refiners
to
benefit
from
the
lower
costs
of
these
improvements
in
desulfurization
technology
(
e.
g.,
better
catalyst
technology
or
lower­
pressure
hydrotreater
technology).
This
will
help
to
offset
the
disproportionate
financial
burden
that
may
be
imposed
upon
small
refiners.

Finally,
providing
small
refiners
more
time
to
comply
will
spread
out
the
availability
of
engineering
and
construction
resources.
Most
refiners
will
need
to
install
additional
processing
equipment
to
meet
the
NRLM
diesel
fuel
sulfur
requirements.
We
anticipate
that
there
may
be
significant
competition
for
technology
services,
engineering
resources,
and
construction
management
and
labor.
In
addition,
as
has
been
the
experience
in
gasoline
sulfur
control,
vendors
will
be
more
likely
to
contract
their
services
with
the
larger
refiners
first,
as
their
projects
will
offer
larger
profits
for
the
vendors.
Temporarily
delaying
compliance
for
small
refiners
will
spread
out
208
the
demand
for
these
resources
and
may
help
reduce
cost
premiums
for
everyone
caused
by
limited
engineering
and
construction
supply.

We
discuss
below
the
provisions
that
we
are
finalizing
to
minimize
the
degree
of
hardship
imposed
upon
small
refiners
by
this
program.
With
these
provisions
we
are
confident
in
going
forward
with
the
500
ppm
sulfur
standard
for
NRLM
diesel
fuel
in
2007
and
the
15
ppm
sulfur
standard
for
NR
diesel
fuel
in
2010
and
for
LM
diesel
fuel
in
2012,
for
the
rest
of
the
industry.
The
provisions
for
small
refiners
will
allow
these
refiners
to
continue
to
produce
higher
sulfur
NRLM
fuel
until
June
1,
2010,
and
similarly,
will
allow
for
the
production
of
500
ppm
nonroad
NRLM
fuel
until
June
1,
2014.
Without
small
refiner
relief,
we
would
have
to
consider
delaying
the
overall
program
until
the
burden
of
the
program
on
many
small
refiners
was
diminished,
which
would
delay
the
air
quality
benefits
of
the
overall
program.
By
providing
temporary
relief
to
small
refiners,
we
are
able
to
adopt
a
program
that
expeditiously
reduces
NRLM
diesel
fuel
sulfur
levels
in
a
feasible
manner
for
the
industry
as
a
whole.

The
four­
year
leadtime
from
which
begins
in
2010
for
small
refiners
for
locomotive
and
marine
diesel
fuel
is
identical
to
the
relief
that
was
supported
by
small
refiners
for
nonroad
diesel
fuel.
We
believe
that
this
relief
is
necessary
and
adequate
to
reduce
the
burden
on
small
entities
while
still
achieving
our
air
quality
goals.
Small
refineries
vary
considerably
in
their
markets
for
NRLM
diesel
fuels.
Consequently,
the
proposal
to
control
nonroad
diesel
fuel
to
15
ppm
sulfur
impacted
small
refiners
with
significant
nonroad
market
shares,
but
left
those
with
significant
locomotive
and
marine
market
shares
relatively
untouched.
With
control
of
all
NRLM
diesel
fuel
to
15
ppm
sulfur
in
this
final
rule,
all
small
refiners
of
NRLM
diesel
fuel
will
face
similar
challenges,
and
therefore
the
same
four
year
lead
time
from
2010
proposed
for
those
small
refiners
impacted
by
nonroad
fuel
control
alone
is
also
appropriate
when
the
standards
are
expanded
to
all
NRLM.
In
essence,
while
more
small
refiners
face
the
challenge
of
desulfurizing
all
of
their
diesel
fuel
to
the
15
ppm
sulfur
standard,
the
magnitude
of
this
challenge
is
not
any
greater.
Furthermore,
providing
additional
relief
(
beyond
2014)
to
small
refiners
would
undermine
the
program
by
further
delaying
air
quality
benefits.
The
2014
deadline
for
all
small
refiner
diesel
fuel
to
15
ppm
sulfur
will
also
simplify
the
fuel
program
and
it
will
allow
small
refiners
the
ability
to
coordinate
their
plans
to
reduce
the
sulfur
content
of
all
off­
highway
diesel
fuel
at
the
same
time.

iii.
Impact
of
Small
Refiner
Options
on
Program
Emissions
Benefits
Small
refiners
that
choose
to
delay
the
NRLM
diesel
fuel
sulfur
requirements
will
also
delay
to
some
extent
the
emission
reductions
that
would
otherwise
have
been
achieved.
However,
for
several
reasons,
the
overall
impact
of
these
postponed
emission
reductions
will
be
small.
First,
small
refiners
represent
only
a
fraction
of
national
non­
highway
diesel
production.
Today,
refiners
that
we
expect
to
qualify
as
small
refiners
represent
only
about
six
percent
of
all
high­
sulfur
diesel
production.
Second,
the
delayed
compliance
provisions
described
below
will
affect
only
engines
without
new
emission
controls.
During
the
program's
first
step
to
500
ppm
sulfur
NRLM
diesel
fuel,
small
refiner
NRLM
diesel
fuel
could
be
well
above
500
ppm
sulfur,
but
the
new
advanced
engine
controls
will
not
yet
be
required.
During
the
second
step
to
15
ppm
sulfur
NRLM
diesel
209
fuel,
equipment
with
the
new
controls
will
be
entering
the
market,
but
use
of
the
500
ppm
small
refiner
fuel
will
be
restricted
to
older
engines
without
the
new
controls.
There
will
be
some
loss
of
sulfate
PM
control
in
the
older
engines
that
operate
on
higher
sulfur
small
refiner
fuel,
but
no
effect
on
the
major
emission
reductions
that
the
new
engine
standards
will
achieve
starting
in
2011.
Finally,
because
small
diesel
refiners
are
generally
dispersed
geographically
across
the
country,
the
limited
loss
of
sulfate
PM
control
will
also
be
dispersed.

One
option
for
small
refiner
relief
will
allow
a
modest
20
percent
relaxation
in
the
gasoline
sulfur
interim
standards
for
small
refiners
that
produce
all
of
their
NRLM
diesel
fuel
at
15
ppm
sulfur
by
June
1,
2006.
To
the
extent
that
small
refiners
elect
this
option,
a
small
loss
of
emission
control
from
Tier
2
gasoline
vehicles
that
use
the
higher
sulfur
gasoline
could
occur.
We
believe
that
such
a
loss
of
control
will
be
very
small.
Very
few
small
refiners
will
be
in
a
position
to
use
this
provision.
Further,
the
relatively
small
production
of
gasoline
with
slightly
higher
sulfur
levels
should
have
no
measurable
impact
on
the
emissions
of
new
Tier
2
vehicles,
even
if
the
likely
"
blending
down"
of
sulfur
levels
does
not
occur
as
this
fuel
mixed
with
lower
sulfur
fuel
during
distribution.
This
provision
will
also
maintain
the
maximum
450
ppm
gasoline
sulfur
per­
gallon
cap
standard
in
all
cases,
providing
a
reasonable
sulfur
ceiling
for
any
small
refiners
using
this
provision.

b.
Small
Refiner
Definition
for
Purposes
of
the
Hardship
Provisions
The
definition
of
small
refiner
under
the
NRLM
diesel
program
is
similar
to
the
definitions
under
the
Tier
2/
Gasoline
Sulfur
and
Highway
Diesel
rules.
Under
the
NRLM
program,
a
small
refiner
must
demonstrate
that
it
meets
the
following
criteria:

°
produced
NRLM
diesel
from
crude;

°
no
more
than
1,500
employees
corporate­
wide,
based
on
the
average
number
of
employees
for
all
pay
periods
from
January
1,
2002
to
January
1,
2003;
and,

°
a
corporate
crude
oil
capacity
less
than
or
equal
to
155,000
barrels
per
calendar
day
(
bpcd)
for
2002.

As
with
the
earlier
fuel
sulfur
programs,
the
effective
dates
for
the
determination
of
employee
count
and
for
calculation
of
the
crude
capacity
represent
the
most
recent
complete
year
prior
to
the
issuing
of
the
proposed
rulemaking
(
2002,
in
this
case).

In
determining
its
total
number
of
employees
and
crude
oil
capacity,
a
refiner
must
include
the
number
of
employees
and
crude
oil
capacity
of
any
subsidiary
companies,
any
parent
company
and
subsidiaries
of
the
parent
company,
and
any
joint
venture
partners.
We
define
a
subsidiary
of
a
company
to
mean
any
subsidiary
in
which
the
company
has
a
50
percent
or
greater
ownership
interest.
However,
refiners
owned
and
controlled
by
an
Alaska
Regional
or
Village
Corporation
organized
under
the
Alaska
Native
Claims
Settlement
Act
(
43
U.
S.
C.
1626),
are
also
eligible
for
210
small
refiner
status,
based
only
on
the
refiner's
employees
and
crude
oil
capacity.
Such
an
exclusion
is
consistent
with
our
desire
to
grant
regulatory
relief
to
that
part
of
the
industry
that
is
the
most
challenged
with
respect
to
regulatory
compliance.
We
believe
that
very
few
refiners,
probably
only
one,
will
qualify
under
this
provision.
We
are
also
incorporating
this
exclusion
into
the
small
refiner
provisions
of
the
highway
diesel
and
gasoline
sulfur
rules,
which
did
not
address
this
issue.

As
under
the
gasoline
sulfur
and
highway
diesel
fuel
rules,
refiners
that
either
acquire
or
restart
a
refinery
in
the
future
may
be
eligible
for
small
refiner
status
under
the
NRLM
program.
Specifically,
a
refiner
that
either
acquires
or
restarts
a
refinery
that
was
shut
down
or
nonoperational
between
January
1,
2002
and
January
1,
2003
may
apply
for
small
refiner
status.
In
such
cases,
we
will
judge
eligibility
under
the
employment
and
crude
oil
capacity
criteria
based
on
the
most
recent
12
consecutive
months
of
data
unless
we
conclude
from
the
data
provided
by
the
refiner
that
another
period
of
time
is
more
appropriate.
Companies
with
refineries
built
after
January
1,
2002
are
not
eligible
for
the
small
refiner
provisions.
Similarly,
entities
that
do
not
own
or
operate
a
refinery
are
not
eligible
to
apply
for
small
refiner
status.

c.
Provisions
for
Small
Refiners
We
are
finalizing
several
provisions
intended
to
reduce
the
regulatory
burden
of
today's
program
on
small
refiners
as
well
as
to
encourage
their
early
compliance
whenever
possible.
As
described
below,
these
small
refiner
relief
options
consist
of
additional
time
for
compliance
and,
for
small
refiners
that
choose
to
comply
earlier
than
required,
the
option
of
either
generating
diesel
fuel
sulfur
credits
or
receiving
a
limited
relaxation
of
their
gasoline
sulfur
standards.

i.
NRLM
Delay
Option
First,
we
are
finalizing
an
option
that
allows
small
refiners
to
postpone
their
compliance
with
the
NRLM
diesel
fuel
sulfur
standards.
The
delayed
compliance
schedule
for
small
refiners
is
intended
to
compensate
for
the
relatively
higher
compliance
burdens
on
these
refiners.
It
is
not
intended
as
an
opportunity
for
those
refiners
to
greatly
expand
their
production
of
uncontrolled
diesel
fuel
(
2007­
2010)
or
500
ppm
sulfur
diesel
fuel
(
2010­
2014).
To
help
ensure
that
any
significant
expansion
of
refining
capacity
that
a
small
refiner
might
undertake
in
the
future
is
accompanied
by
an
expansion
of
desulfurization
capacity,
small
refiners
producing
higher
sulfur
fuel
must
limit
their
production
to
baseline
volume
levels.
Specifically,
during
the
first
step
of
today's
diesel
fuel
program
to
500
ppm
sulfur,
from
June
1,
2007
through
May
31,
2010,
a
small
refiner
may
at
any
or
all
of
its
refineries
produce
uncontrolled
NRLM
diesel
fuel
up
to
the
2003
through
2005
non­
highway
baseline
volume
for
the
refinery(
s).
Any
diesel
fuel
produced
over
the
baseline
volume
will
be
subject
to
the
500
ppm
sulfur
standard
applying
to
other
refiners.
Similarly,
from
June
1,
2010
through
May
31,
2014,
a
small
refiner
may
produce
at
any
or
all
of
its
refineries
NRLM
diesel
fuel
subject
to
the
500
ppm
sulfur
standard
at
a
volume
equal
to
or
less
than
the
refineries'
2006­
2008
non­
highway
baseline
volumes.
LM
fuel
produced
to
the
500
ppm
standard
during
2010
to
2012
would
be
counted
towards
meeting
this
baseline
volume.
NRLM
211
fuel
produced
in
excess
of
the
baseline
volume
will
be
subject
to
the
15
ppm
sulfur
NRLM
diesel
fuel
standard.
The
baseline
for
2003­
2005
will
be
determined
by
subtracting
the
refinery's
highway
volume
from
its
total
highway
and
heating
oil
volume
production.
The
baseline
for
2006­
2008
will
be
determined
based
upon
the
volume
of
the
refinery's
NRLM
fuel
designations
discussed
in
section
IV.
D.

As
discussed
in
section
IV.
D,
the
costs
to
the
distribution
system
to
mark
heating
oil
in
areas
of
PADD
1
with
high
heating
oil
demand
to
distinguish
it
from
small
refiner
or
credit­
using
high
sulfur
NRLM
made
this
option
undesirable
in
these
areas.
Based
on
our
review
of
anticipated
small
refiner
situations,
this
portion
of
PADD
1
appears
unlikely
to
provide
a
meaningful
market
for
small
refiners
seeking
this
option.
Therefore,
in
this
part
of
the
country
it
imposed
costs
without
providing
the
intended
benefit.
Consequently,
while
this
option
was
proposed
to
be
available
nationwide,
we
are
not
finalizing
it
for
a
portion
of
PADD
1.
This
change
from
the
proposal
should
have
no
meaningful
impact
on
small
refiners'
flexibility,
but
will
reduce
the
costs
for
fuel
distributors.

Since
new
engines
with
sulfur
sensitive
emission
controls
will
begin
to
become
widespread
beginning
in
2011,
small
refiner
fuel
can
only
be
sold
for
use
in
pre­
2011
nonroad
equipment
or
in
locomotives
or
marine
engines
during
this
time.
Section
IV.
D
below
discusses
the
requirements
for
designating
and
tracking
the
production
of
500
ppm
sulfur
NRLM
diesel
fuel
produced
by
small
refiners
during
this
period.

The
following
table
illustrates
the
small
refiner
NRLM
diesel
fuel
sulfur
standards
as
compared
to
the
standards
for
the
base
NRLM
diesel
fuel
program.
As
previously
stated,
small
refiners
will
receive
additional
lead
time,
compared
to
non­
small
refiners
for
15
ppm
sulfur
locomotive
and
marine
diesel
fuel.
This
lead
time
is
identical
to
that
which
had
been
proposed
for
15
ppm
sulfur
nonroad
diesel
fuel.
This
will
ensure
that
emission
benefits
of
ultra
low
sulfur
diesel
fuel
are
achieved
as
soon
as
possible,
and
should
not
significantly
change
the
nature
or
magnitude
of
the
burden
on
affected
small
refiners.
212
Table
IV­
4.
 
Small
Refiner
NRLM
Diesel
Fuel
Sulfur
Standards,
ppma
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015+

Non­
Small
Refiners­
NR
fuel
­­
500
500
500
15
15
15
15
15
15
Non­
Small
Refiners­
LM
fuel
­­
500
500
500
500
500
15
15
15
15
Small
Refiners­
NR
diesel
fuel
­­
­­
­­
­­
500
500
500
500
15
15
Small
Refiners­
LM
diesel
fuel
­­
­­
­­
­­
500
500
500
500
15
15
Notes:
a
New
standards
will
take
effect
on
June
1
of
the
applicable
year.

ii.
NRLM
Credit
Option
Some
small
refiners
have
indicated
that,
for
a
variety
of
reasons,
they
might
need
to
produce
fuel
meeting
the
NRLM
diesel
fuel
sulfur
standards
earlier
than
required
under
the
small
refiner
program
described
above.
For
some
small
refiners,
the
distribution
system
might
limit
the
number
of
grades
of
diesel
fuel
that
will
be
carried.
Others
might
find
it
economically
advantageous
to
make
500
ppm
or
15
ppm
sulfur
NRLM
diesel
fuel
earlier
than
required
to
prevent
losing
market
share.
At
least
one
small
refiner
has
indicated
that
it
might
decide
to
desulfurize
its
NRLM
pool
at
the
same
time
as
it
desulfurizes
its
highway
diesel
fuel,
in
June
2006,
due
to
limitations
in
its
distribution
system
and
to
take
advantage
of
economies
of
scale.

The
NRLM
Credit
option
allows
small
refiners
to
participate
in
the
NRLM
diesel
fuel
sulfur
credit
banking
and
trading
program
discussed
earlier
in
this
section.
Under
this
option,
a
small
refiner
may
generate
diesel
fuel
sulfur
credits
by
producing
any
volume
of
500
ppm
sulfur
NRLM
diesel
fuel
from
crude
oil
prior
to
from
June
1,
2006
through
May
31,
2010,
and
by
producing
any
volume
from
crude
oil
of
15
ppm
sulfur
NRLM
diesel
fuel
from
June
1,
2010
through
December
31,
2013.
The
specifics
of
the
credit
program
are
described
in
section
IV.
A.
4,
including
how
the
program
applies
to
small
refiners.
Generating
and
selling
credits
could
provide
small
refiners
with
funds
to
help
defray
the
costs
of
early
NRLM
compliance.

iii.
NRLM/
Gasoline
Compliance
Option
The
NRLM/
Gasoline
Compliance
option
is
available
to
small
refiners
that
produce
greater
than
95
percent
of
their
NRLM
diesel
fuel
at
the
15
ppm
sulfur
standard
by
June
1,
2006
and
elect
not
to
use
the
provision
described
above
to
earn
NRLM
diesel
fuel
sulfur
credits
for
this
early
compliance.
2
Refiners
choosing
this
option
will
receive
a
modest
revision
in
their
small
refiner
interim
gasoline
sulfur
standards,
beginning
January
1,
2004.
Specifically,
the
applicable
small
refiner
annual
average
and
per­
gallon
cap
gasoline
sulfur
standards
will
be
increased
by
20
percent
for
the
duration
of
the
interim
program.
The
interim
program
is
through
either
2007
or
2010,
213
depending
on
whether
the
refiner
extended
the
duration
of
its
interim
gasoline
sulfur
standards
by
producing
15
ppm
sulfur
highway
diesel
fuel
by
June
1,
2006,
as
provided
under
40
CFR
80.552(
c).
In
no
case
may
the
per­
gallon
gasoline
sulfur
cap
exceed
450
ppm,
the
highest
level
allowed
under
the
gasoline
sulfur
program.

We
believe
it
is
very
important
to
link
any
relaxation
of
a
small
refiner's
interim
gasoline
sulfur
standards
with
the
environmental
benefit
of
early
desulfurization
of
a
significant
volume
of
NRLM
diesel
fuel.
As
such,
a
small
refiner
choosing
to
use
this
option
must
produce
a
minimum
volume
of
NRLM
diesel
fuel
at
the
15
ppm
sulfur
standard
by
June
1,
2006.
Each
participating
small
refiner
must
produce
a
volume
of
15
ppm
sulfur
fuel
that
is
at
least
85
percent
of
the
annual
average
volume
of
non­
highway
diesel
fuel
it
produced
from
2003­
2005.
If
the
refiner
began
to
produce
gasoline
in
2004
at
the
higher
interim
standard
under
this
provision
but
then
either
fails
to
meet
the
15
ppm
sulfur
standard
for
its
NRLM
diesel
fuel
by
June
1,
2006
or
fails
to
meet
the
85
percent
minimum
volume
requirement,
the
original
small
refiner
interim
gasoline
sulfur
standard
applicable
to
that
refiner
will
automatically
apply
retroactively
to
2004.
In
addition,
the
refiner
must
compensate
for
the
higher
gasoline
sulfur
levels
by
purchasing
gasoline
sulfur
credits
or
producing
an
equivalent
volume
of
gasoline
below
the
required
sulfur
levels.
Under
this
option,
a
small
refiner
could
in
effect
shift
some
funds
from
its
gasoline
sulfur
program
to
accelerate
desulfurization
of
NRLM
diesel
fuel.
While
there
would
be
a
small
potential
loss
of
emission
reduction
under
the
gasoline
sulfur
program
from
fuel
produced
by
the
very
few
small
refiners
that
we
believe
would
choose
this
second
option,
there
are
also
environmental
benefits
gained
from
the
production
of
15
ppm
sulfur
diesel
fuel
earlier
than
otherwise
required.

iv.
Relationship
of
the
Options
to
Each
Other
A
small
refiner
may
choose
to
use
the
NRLM
Delay
option,
the
NRLM
Credit
option
or
both
in
combination,
since
it
has
no
requirement
to
produce
500
ppm
sulfur
NRLM
diesel
fuel
before
June
1,
2010,
or
15
ppm
sulfur
NRLM
diesel
fuel
before
June
1,
2014.
Thus
any
fuel
that
it
produces
from
crude
at
or
below
the
sulfur
standards
earlier
than
required
will
qualify
for
generating
credits.

On
the
other
hand,
the
NRLM/
Gasoline
Compliance
option
may
not
be
used
in
combination
with
either
the
NRLM
Delay
option
or
the
NRLM
Credit
option,
since
a
small
refiner
must
produce
at
least
85
percent
of
its
NRLM
diesel
fuel
at
the
15
ppm
sulfur
standard
under
the
NRLM/
Gasoline
Compliance
option.

d.
How
Do
Refiners
Apply
for
Small
Refiner
Status?

A
refiner
applying
for
small
refiner
status
must
provide
the
Agency
with
several
types
of
information
by
December
31,
2004.
The
detailed
application
requirements
are
summarized
in
section
V.
F.
2
below.
In
general,
a
potential
small
refiner
must
own
the
refinery/
refineries
in
question
and
must
provide
the
following
information
for
the
parent
company
and
all
subsidiaries
at
all
locations:
1)
the
average
number
of
employees
for
all
pay
periods
from
January
1,
2002
214
through
January
1,
2003;
2)
the
total
corporate
crude
oil
capacity,
which
must
be
a
positive
number;
and
3)
an
indication
of
which
small
refiner
option
the
refiner
intends
to
use
(
see
section
IV.
B.
1.
c
above).
As
with
applications
for
relief
under
other
fuel
programs,
applications
for
small
refiner
status
under
this
rule
that
are
later
found
to
contain
false
or
inaccurate
information
will
be
void
ab
initio.

e.
The
Effect
of
Financial
and
Other
Transactions
on
Small
Refiner
Status
and
Small
Refiner
Relief
Provisions
Since
the
gasoline
sulfur
and
highway
diesel
fuel
sulfur
programs
were
finalized,
several
refiners
have
raised
concerns
about
how
various
financial
and
other
transactions
could
affect
implementation
of
the
small
refiner
fuel
sulfur
provisions.
These
types
of
transactions
typically
involve
refiners
with
approved
small
refiner
status
that
are
involved
in
potential
or
actual
sales
of
the
small
refiner's
refinery,
or
involve
the
small
refiner
merging
with
another
refiner
or
purchasing
another
refinery
(
or
other
non­
refining
asset).
We
believe
that
these
concerns
are
also
relevant
to
the
small
refiner
provisions
described
below
for
the
NRLM
diesel
fuel
sulfur
program.

i.
Large
Refiner
Purchasing
a
Small
Refiner's
Refinery
The
first
type
of
transaction
involves
a
"
non­
small"
refiner
that
wishes
to
purchase
a
refinery
owned
by
an
approved
small
refiner.
In
some
cases,
the
small
refiner
may
not
have
completed
or
even
begun
refinery
upgrades
to
meet
the
long­
term
fuel
sulfur
standards
if
it
was
using
an
interim
small
refiner
compliance
provision.
Under
the
gasoline
sulfur
and
highway
diesel
fuel
sulfur
programs,
once
such
a
purchase
transaction
is
completed,
the
"
non­
small"
buyer
does
not
have
the
benefit
of
the
small
refiner
relief
provisions
that
had
applied
to
the
previous
owner.

The
purchasing
refiner
would
have
to
perform
the
necessary
upgrades
on
the
acquired
refinery
for
it
to
meet
the
"
non­
small"
sulfur
standards.
As
the
gasoline
sulfur
and
highway
diesel
fuel
sulfur
provisions
existed
prior
to
today's
action,
such
a
refiner
would
be
left
with
very
little
or,
in
the
case
of
the
gasoline
sulfur
program
which
has
already
begun,
no
lead
time
to
bring
the
refinery
into
compliance.
The
refiners
that
have
raised
this
issue
have
claimed
that
refiners
in
this
situation
would
not
be
able
to
immediately
comply
with
the
"
non­
small
refiner"
standards
upon
acquisition
of
the
new
refinery.
These
refiners
claim
that
this
could
prevent
them
from
purchasing
a
refinery
from
a
small
refiner
and,
as
a
result,
this
would
severely
limit
the
ability
of
small
refiners
to
sell
such
an
asset.
The
refiners
that
raised
this
issue
requested
additional
lead
time
before
the
non­
small
refiner
sulfur
standards
take
effect.

We
received
comments
on
this
issue
from
two
refiners.
Both
refiners
commented
that
lead
time
for
refiners
losing
their
small
refiner
status
should
only
be
allowed
for
the
case
where
a
small
refiner
merges
with,
or
acquires,
another
small
refiner.
Neither
refiner
supports
allowing
additional
lead
time
for
a
large
refiner
that
merges
with
or
acquires
a
small
refiner.
In
addition,
these
refiners
also
commented
that
it
would
be
inappropriate
to
allow
a
small
refiner
that
receives
this
lead
time
215
to
be
able
to
generate
credits
for
"
early"
production
of
lower
sulfur
diesels
during
this
two­
year
period.

Nevertheless,
we
continue
to
believe
these
lead­
time
concerns
are
valid.
Failure
to
address
them
could
lead
to
unnecessary
disruption
to
the
diesel
fuel
market.
Therefore,
we
are
adopting
a
provision
to
provide
an
appropriate
period
of
lead
time
for
compliance
with
the
NRLM
diesel
fuel
sulfur
requirements
for
situations
in
which
a
refiner
purchases
any
refinery
owned
by
a
small
refiner,
whether
by
purchase
of
the
refinery
or
purchase
of
the
small
refiner
entity.
Refiners
that
acquire
a
refinery
from
an
approved
small
refiner
will
be
provided
30
additional
months
from
the
date
of
the
completion
of
the
purchase
transaction
(
but
no
later
than
June
1,
2010
for
500
ppm
NRLM
fuel
and
June
1,
2014
for
15
ppm
NRLM
fuel).
During
this
interim
period,
production
at
the
newly­
acquired
refinery
may
remain
at
the
interim
sulfur
levels
that
applied
to
that
refinery
for
the
previous
small
refiner
owner
under
the
small
refiner
options
discussed
below.
At
the
end
of
this
period,
the
refiner
must
comply
with
the
"
non­
small
refinery"
sulfur
standards.

We
received
comments
suggesting
that
the
proposed
24
months
of
additional
lead
time
would
not
be
adequate,
and
further,
discussions
with
several
refiners
indicated
that
in
most
cases,
24
months
would
be
inadequate.
As
discussed
in
section
IV.
F,
we
project
a
range
of
27­
39
months
is
needed
to
design
and
construct
a
diesel
hydrotreater.
Therefore,
in
order
to
allow
a
reasonable
opportunity
for
complying,
we
are
finalizing
the
provision
that
30
months
of
additional
lead
time
will
be
afforded.
Thirty
months
should
in
most
cases
be
sufficient
for
the
new
refinerowner
to
accomplish
the
necessary
engineering,
permitting,
construction,
and
start­
up
of
the
necessary
desulfurization
equipment.
However,
if
there
are
instances
where
the
technical
characteristics
of
its
planned
desulfurization
project
will
require
additional
lead
time,
we
have
included
provisions
for
the
refiner
to
apply
for
up
to
six
months
of
additional
time
and
for
EPA
to
consider
such
requests
on
a
case­
by­
case
basis.
Such
an
application
must
be
based
on
the
technical
factors
supporting
the
need
for
more
time
and
should
include
detailed
technical
information
and
projected
schedules
for
engineering,
permitting,
construction,
and
startup.
Based
on
information
provided
in
such
an
application
and
other
relevant
information,
EPA
will
decide
whether
additional
time
is
technically
necessary
and,
if
so,
how
much
additional
time
is
appropriate.
However,
we
anticipate
that
in
most
cases
30
months
will
be
sufficient,
since
developing
plans
for
compliance
should
be
expected
to
be
a
part
of
any
purchase
decision.

All
existing
small
refiner
provisions
and
restrictions,
as
described
below,
will
also
remain
in
place
for
that
refinery
during
the
30
months
of
additional
lead
time
and
any
further
lead
time
approved
by
EPA
for
the
purchasing
refiner;
including
the
per­
refinery
volume
limitation
on
the
amount
of
NRLM
diesel
that
may
be
produced
at
the
small
refiner
standards.
Furthermore,
since
the
purpose
of
this
grace
period
is
solely
to
provide
time
to
bring
the
refinery
into
compliance
with
the
NRLM
standards,
refiners
will
not
be
allowed
to
generate
credits
for
early
compliance
during
this
30
month
period.
There
will
be
no
adverse
environmental
impact
of
this
provision,
since
the
small
refiner
would
have
already
been
provided
this
same
relief
prior
to
the
purchase
and
this
provision
is
no
more
generous.
216
ii.
Small
Refiner
Losing
Its
Small
Refiner
Status
due
to
Merger
or
Acquisition
Another
type
of
transaction
involves
a
refiner
with
approved
small
refiner
status
that
later
loses
its
small
refiner
status
because
it
exceeds
the
small
refiner
criteria.
Under
the
gasoline
sulfur
and
highway
diesel
fuel
sulfur
regulations,
an
approved
small
refiner
that
exceeds
1,500
employees
due
to
merger
or
acquisition
will
lose
its
small
refiner
status.
We
also
intended
for
refiners
that
exceeded
the
155,000
barrel
per
calendar
day
crude
capacity
limit
due
to
merger
or
acquisition
to
lose
its
small
refiner
status
and
in
this
rule
we
are
amending
the
regulations
to
reflect
that
criterion
as
well.
This
includes
exceedances
of
the
employee
or
crude
capacity
criteria
caused
by
acquisitions
of
assets
such
as
plant
and
equipment,
as
well
as
acquisitions
of
business
entities.

Our
intent
in
the
gasoline
and
highway
diesel
fuel
sulfur
programs,
as
well
as
the
NRLM
diesel
fuel
sulfur
program,
has
been
and
continues
to
be,
limiting
the
small
refiner
relief
provisions
to
a
small
subset
of
refiners
that
are
challenged,
as
discussed
above.
At
the
same
time,
it
is
also
our
intent
to
avoid
stifling
normal
business
growth.
Therefore,
the
regulations
we
are
adopting
today
will
disqualify
a
refiner
from
small
refiner
status
if
it
exceeds
the
small
refiner
criteria
through
its
involvement
in
transactions
such
as
being
acquired
by
or
merging
with
another
entity,
through
the
small
refiner
itself
purchasing
another
entity
or
assets
from
another
entity,
or
when
it
ceases
to
process
crude
oil.
However,
an
approved
small
refiner
who
exceeds
the
employee
or
crude
oil
capacity
criteria
without
merger
or
acquisition,
may
retain
its
small
refiner
status
for
the
purposes
of
the
complying
with
the
NRLM
diesel
fuel
standards.
Furthermore,
in
the
sole
case
of
a
merger
between
two
approved
small
refiners
we
will
allow
such
refiners
to
retain
their
small
refiner
status
for
purposes
of
complying
with
the
NRLM
diesel
fuel
program.
Commenters
explained
that
additional
financial
resources
would
not
typically
be
provided
in
the
case
of
a
merger
between
small
refiners.
In
light
of
these
comments,
we
believe
the
justification
for
continued
small
refiner
relief
for
the
merged
entity
is
valid.
Small
refiner
status
for
the
two
entities
of
the
merger
will
not
be
affected,
hence
the
original
compliance
plans
of
the
two
refiners
should
not
be
impacted.
Moreover,
no
environmental
detriment
will
result
from
the
two
small
refiners
maintaining
their
small
refiner
status
within
the
merged
entity
as
they
would
have
likely
maintained
their
small
refiner
status
had
the
merger
not
occurred.

Consistent
with
our
intent
in
the
gasoline
sulfur
and
highway
diesel
fuel
sulfur
programs
to
limit
the
use
of
the
small
refiner
hardship
provisions,
we
also
intended
in
the
gasoline
sulfur
and
highway
diesel
fuel
sulfur
programs
that
an
exceedance
of
corporate
crude
oil
capacity
limit
of
155,000
bpcd,
due
to
merger
or
acquisition,
would
be
grounds
for
disqualifying
a
refiner's
small
refiner
status.
However,
we
inadvertently
failed
to
include
this
second
criterion
as
grounds
for
disqualification
in
the
regulations.
In
today's
action,
we
are
resolving
this
error
by
including
the
crude
capacity
limit,
along
with
the
employee
limit
for
both
the
gasoline
sulfur
and
highway
diesel
fuel
sulfur
programs,
effective
January
1,
2004.
Thus,
a
refiner
exceeding
either
criterion
due
to
merger
or
acquisition
will
lose
its
small
refiner
status.
The
exception
to
this
would
be
in
the
case
of
merger
only
between
two
small
refiners.
We
received
comments
supporting
the
allowance
of
additional
lead
time
for
small
refiners
that
lose
their
small
refiner
status
through
a
merger
with,
or
acquisition
of,
another
small
refiner.
217
We
recognize
that
a
small
refiner
that
loses
its
small
refiner
status
because
of
a
merger
with,
or
acquisition
of,
a
non­
small
refiner
would
face
the
same
type
of
lead
time
concerns
in
complying
with
the
non­
small
refiner
standards
as
a
non­
small
refiner
that
acquired
a
small
refiner's
refinery
would.
Therefore,
the
additional
lead
time
described
above
for
non­
small
refiners
purchasing
a
small
refiner's
refinery
will
also
apply
to
this
situation.
Thus,
this
30
month
lead
time
will
apply
to
all
of
the
refineries,
existing
or
newly­
purchased,
that
had
previously
been
subject
to
the
small
refiner
program,
but
would
not
apply
to
a
newly­
purchased
refinery
that
is
subject
to
the
non­
small
refiner
standards.
Again,
there
would
be
no
adverse
environmental
impact
because
of
the
pre­
existing
relief
provisions
that
applied
to
the
newly­
purchased
small
refiner.

The
issues
discussed
in
this
section
apply
equally
to
the
gasoline
sulfur
and
highway
diesel
fuel
sulfur
programs.
Thus,
we
are
also
adopting
the
same
provisions
relating
to
additional
lead
time
in
cases
of
certain
financial,
or
other,
transactions
for
the
small
refiner
programs
in
the
earlier
fuel
sulfur
programs.

In
the
proposal
for
today's
final
rule,
we
invited
comment
on
several
other
related
provisions
that
were
considered
during
the
development
of
this
rulemaking:

(
1)
Instead
of
merely
allowing
small
refiners
a
grace
period
to
come
into
compliance
if
they
lose
their
small
refiner
status,
we
also
asked
for
comment
on
whether
or
not
such
a
small
refiner
should
instead
be
allowed
to
"
grandfather"
the
small
refiner
relief
provisions
for
its
existing
refinery
or
refineries.
We
did
not
receive
any
specific
comments
on
this
issue
and
we
are
not
finalizing
this
provision
in
today's
action.

(
2)
Regarding
small
refiners
that
exceed
the
small
refiner
criteria
due
to
the
purchase
of
a
non­
small
refiner's
refinery,
we
requested
comment
on
whether
or
not
the
proposed
additional
lead
time
should
apply
to
the
purchased
refinery.
We
also
requested
comment
on
whether
or
not
the
refiner
should
be
required
to
meet
the
non­
small
refiner
standards
on
schedule
at
the
purchased
refinery,
since
the
previous
owner
could
be
assumed
to
have
anticipated
the
new
standards
and
taken
steps
to
accomplish
this
prior
to
the
purchase.
One
refiner
commented
that
merger
acquisition
flexibility
for
refineries
that
lose
their
small
refiner
status
should
be
limited
to
instances
where
a
small
refiner
merges
with
another
small
refiner.
They
believed
that
any
small
refiner
that
loses
its
small
refiner
status
due
to
an
acquisition
of
a
non­
small
refiner's
refinery
should
not
be
eligible
for
hardship
relief.
Similarly,
another
refiner
commented
that
a
refiner
should
not
retain
small
refiner
status
if
it
has
the
financial
resources
to
acquire
additional
refineries
that
increase
corporate­
wide
crude
processing
above
155,000
bpd.
We
are
not
adopting
any
flexibility
for
the
purchased
refinery
in
this
situation
(
except
in
the
case
of
a
merger
between
two
small
refiners,
as
discussed
above).

f.
Provisions
for
Approved
Gasoline
and
Highway
Diesel
Fuel
Small
Refiners
that
do
not
Qualify
for
Small
Refiner
Status
Under
Today's
Program
218
Some
refiners
that
have
approved
small
refiner
status
under
the
gasoline
sulfur
and
highway
diesel
fuel
programs
may
not
qualify
for
small
refiner
status
under
today's
program
if
they
have
grown
through
normal
business
operations
and
now
exceed
the
qualification
criteria
for
NRLM
small
refiner
status.
One
refiner
commented
on
the
lack
of
a
"
grandfather"
provision
in
the
nonroad
proposal
that
would
automatically
continue
small
refiner
status
to
refiners
already
approved
as
small
refiners
under
the
gasoline
and
highway
diesel
fuel
sulfur
programs.
Without
such
a
provision
some
refiners
could
be
approved
small
refiners
under
the
gasoline
sulfur
and
highway
diesel
fuel
sulfur
programs
(
because
they
grew
through
normal
business
expansions
and
not
through
merger
or
acquisition)
but
would
not
qualify
under
the
NRLM
program
because
they
now
exceed
the
criteria.
As
a
consequence,
the
commenter
argued
that
in
some
cases
benefits
afforded
to
such
small
refiners
under
the
gasoline
and
highway
diesel
fuel
sulfur
programs
could
be
negated.
Specifically,
under
the
highway
diesel
rule
they
were
allowed
until
2010
before
needing
to
have
diesel
fuel
hydrotreating
capacity.
Under
the
nonroad
rule,
they
would
have
to
do
so
in
2007.
Since
it
would
only
make
sense
to
invest
for
adequate
15
ppm
capacity
when
they
do
invest,
the
nonroad
standards
essentially
would
require
them
to
invest
to
bring
all
highway
and
nonroad
diesel
to
15
ppm
sulfur
in
2007,
eliminating
the
flexibility
granted
them
in
the
highway
rule.
Furthermore,
the
refiners'
clean
fuel
projects
for
low
sulfur
gasoline,
highway
diesel
fuel,
and
NRLM
diesel
fuel
could
no
longer
be
staggered.
In
fact,
small
refiners
in
such
situations
would
be
required
to
make
investments
for
compliance
with
all
three
fuel
programs
in
the
same
three
to
four
year
period,
if
not
virtually
all
at
once.

We
believe
that
a
refiner
who
no
longer
meets
the
criteria
for
small
refiner
status,
since
it
has
successfully
grown
through
normal
business
operations,
does
not
face
the
same
level
of
hardship
described
earlier
in
this
section.
We
do
not
intend
for
the
NRLM
program
to
undermine
the
benefits
afforded
to
small
refiners
under
the
gasoline
and
highway
diesel
fuel
sulfur
programs,
as
described
in
the
comments.
At
the
same
time,
however,
we
want
to
preserve
small
refiner
status
under
today's
program
only
for
those
businesses
that
meet
the
criteria
described
above.
Under
the
nonroad
proposal,
a
refiner
with
approved
small
refiner
status
under
the
highway
diesel
fuel
program
but
not
the
NRLM
program
would
be
required
to
produce
500
ppm
sulfur
NRLM
diesel
fuel
in
2007
and
both
15
ppm
sulfur
highway
and
NR
diesel
fuel
in
2010.
Under
today's
final
program,
such
a
refiner
may
instead
skip
the
2007
500
ppm
interim
sulfur
standard
for
its
NRLM
diesel
fuel,
and
meet
the
15
ppm
sulfur
standard
for
both
its
highway
and
NR
diesel
fuel
in
2010
and
LM
diesel
fuel
in
2012.
Such
an
approach
will
maintain
the
refiner's
flexibility
under
the
highway
program
by
allowing
it
to
delay
diesel
hydrotreating
investment
until
2010,
while
limiting
its
flexibility
under
the
nonroad
diesel
program.

g.
Additional
Provisions
and
Program
Elements
To
reduce
the
burden
on
all
refiners
(
including
small
refiners),
we
have
chosen
to
finalize
the
designate
and
track
approach,
rather
than
the
baseline
approach.
Discussions
with
parties
in
all
parts
of
the
distribution
system
led
us
to
believe
that
this
is
the
preferred
approach,
as
tracking
is
currently
done
by
parties
throughout
the
distribution
system.
We
are
also
finalizing
provisions
to
simplify
the
segregation,
marking,
and
dyeing
requirements.
In
addition,
we
are
finalizing
219
provisions
to
alleviate
the
concern
raised
by
small
terminal
operators
regarding
the
heating
oil
marker.
Terminals
in
parts
of
PADD
1
(
Northeast/
Mid­
Atlantic
Area)
will
not
have
to
add
the
marker
to
home
heating
oil.
Therefore
we
expect
that
no
terminals
inside
of
the
Northeast/
Mid­
Atlantic
Area
will
need
to
install
injection
equipment.
These
provisions
are
discussed
in
greater
detail
in
section
IV.
D,
below.

2.
General
Hardship
Provisions
a.
Temporary
Waivers
from
NRLM
Diesel
Fuel
Sulfur
Requirements
in
Extreme
Unforseen
Circumstances
We
are
finalizing
a
provision
which,
at
our
discretion,
will
permit
any
domestic
or
foreign
refiner
to
seek
a
temporary
relief
from
the
NRLM
diesel
fuel
sulfur
standards
under
certain
rare
circumstances.
This
waiver
provision
is
similar
to
provisions
in
the
reformulated
gasoline,
low
sulfur
gasoline,
and
highway
diesel
fuel
sulfur
regulations.
It
is
intended
to
provide
refiners
shortterm
relief
due
to
unanticipated
circumstances,
such
as
a
refinery
fire
or
a
natural
disaster,
that
cannot
be
reasonably
foreseen
now
or
in
the
near
future.

Under
this
provision,
a
refiner
may
seek
a
waiver
to
distribute
NRLM
diesel
fuel
that
does
not
meet
the
applicable
500
ppm
or
15
ppm
sulfur
standards
for
a
brief
time
period.
An
approved
waiver
of
this
type
could,
for
example,
allow
a
refiner
to
produce
and
distribute
diesel
fuel
with
higher
than
allowed
sulfur
levels,
so
long
as
the
other
conditions
described
below
were
met.
Such
a
request
must
be
based
on
the
refiner's
inability
to
produce
complying
NRLM
diesel
fuel
because
of
extreme
and
unusual
circumstances
outside
the
refiner's
control
that
could
not
have
been
avoided
through
the
exercise
of
due
diligence.
The
request
must
also
show
that
other
avenues
for
mitigating
the
problem,
such
as
the
purchase
of
credits
to
be
used
toward
compliance,
had
been
pursued
yet
were
insufficient.
As
with
other
types
of
regulatory
relief
established
in
this
rule,
this
type
of
temporary
waiver
will
have
to
be
designed
to
prevent
fuel
exceeding
the
15
ppm
sulfur
standard
from
being
used
in
2011
and
later
model
year
nonroad
engines.

The
conditions
for
obtaining
a
NRLM
diesel
fuel
sulfur
waiver
are
similar
to
those
under
the
RFG,
gasoline
sulfur,
and
highway
diesel
fuel
sulfur
regulations.
These
conditions
are
necessary
and
appropriate
to
ensure
that
any
waivers
that
are
granted
are
limited
in
scope,
and
that
refiners
do
not
gain
economic
benefits
from
a
waiver.
Therefore,
refiners
seeking
a
waiver
will
be
required
to
show
that
the
waiver
is
in
the
best
public
interest
and
that
they:
1)
were
not
able
to
avoid
the
nonconformity;
2)
will
make
up
the
air
quality
detriment
associated
with
the
waiver;
3)
will
make
up
any
economic
benefit
from
the
waiver;
and
4)
will
meet
the
applicable
diesel
fuel
sulfur
standards
as
expeditiously
as
possible.

b.
Temporary
Relief
Based
on
Extreme
Hardship
Circumstances
In
addition
to
the
provision
for
short­
term
relief
under
extreme
unforseen
circumstances,
we
are
finalizing
a
provision
for
relief
based
on
extreme
hardship
circumstances
such
as
220
circumstances
that
impose
extreme
hardship
and
significantly
affect
a
refiners
ability
to
comply
with
the
program
requirements
by
the
applicable
dates.
This
provision
is
also
very
similar
to
those
established
under
the
gasoline
sulfur
and
highway
diesel
fuel
sulfur
programs.
Under
the
gasoline
sulfur
program,
we
have
granted
relief
in
the
form
of
individual
compliance
plans
to
five
refiners.
Under
the
highway
diesel
program,
we
have
approved
two.
Each
plan
was
designed
for
the
specific
situation
of
that
refiner.
In
all
cases,
the
companies
would
have
experienced
severe
hardship
if
temporary
relief
had
not
been
granted.
Moreover,
some
refineries
were
at
a
high
risk
of
shutting
down
without
the
relief.

In
developing
today's
program,
as
under
our
other
fuel
programs,
we
considered
whether
any
refiners
would
face
particular
difficulty
in
complying
with
the
standards
in
the
lead
time
provided.
As
described
earlier
in
this
section,
we
concluded
that,
in
general,
small
refiners
would
experience
more
difficulty
in
complying
with
the
standards
on
time
because
they
have
less
ability
to
raise
the
capital
necessary
for
refinery
investments,
face
proportionately
higher
costs
because
of
poorer
economies
of
scale,
and
are
less
able
to
successfully
compete
for
limited
engineering
and
construction
resources.
However,
it
is
possible
that
other
refiners
that
are
not
small
refiners
may
also
face
particular
difficulty
in
complying
on
time
with
the
sulfur
standards
required
under
today's
program.
Therefore,
we
are
including
in
this
rulemaking
a
provision
which
allows
us,
at
our
discretion,
to
grant
temporary
waivers
from
the
NRLM
diesel
fuel
sulfur
standards
based
on
a
showing
of
extreme
hardship
circumstances.

The
extreme
hardship
provision
allows
any
domestic
or
foreign
refiner
to
request
relief
from
the
sulfur
standards
based
on
a
showing
of
unusual
circumstances
that
result
in
extreme
hardship
and
significantly
affect
a
refiner's
ability
to
comply
with
either
the
500
ppm
or
15
ppm
sulfur
NRLM
diesel
fuel
standards
by
either
June
1,
2007,
June
1,
2010,
or
June
1,
2012,
respectively.
The
Agency
will
evaluate
each
application
on
a
case­
by­
case
basis,
considering
the
factors
described
below.
Approved
hardship
applications
may
include
compliance
plans
with
relief
similar
to
the
provisions
for
small
refiners,
which
are
described
in
detail
above
in
section
IV.
B.
1.
c.
Depending
on
the
refiner's
specific
situation,
such
approved
delays
in
meeting
the
sulfur
requirements
may
be
more
stringent
than
those
allowed
for
small
refiners,
but
will
not
likely
be
less
stringent.
Given
such
an
approval,
we
expect
to
impose
appropriate
conditions
to:
1)
assure
the
refiner
is
making
its
best
effort;
and
2)
minimize
any
loss
of
emissions
benefits
from
the
program.
As
with
other
relief
provisions
established
in
this
rule,
any
waiver
under
this
provision
will
be
designed
to
prevent
fuel
exceeding
the
15
ppm
sulfur
standard
from
being
used
in
2011
and
later
model
year
nonroad
engines.

Providing
short­
term
relief
to
those
refiners
that
need
additional
time
because
they
face
hardship
circumstances
facilitates
adoption
of
an
overall
program
that
reduces
NRLM
diesel
fuel
sulfur
to
500
ppm
beginning
in
2007,
and
NRLM
diesel
fuel
sulfur
to
15
ppm
in
2010
and
2012,
for
the
majority
of
the
industry.
However,
we
do
not
intend
for
this
waiver
provision
to
encourage
refiners
to
delay
the
planning
and
investments
they
would
otherwise
make.
We
do
not
expect
to
grant
temporary
waivers
that
apply
to
more
than
approximately
one
percent
of
the
national
NRLM
diesel
fuel
pool
in
any
given
year.
221
The
regulatory
language
for
today's
action
includes
a
list
of
the
information
that
must
be
included
in
a
refiner's
application
for
an
extreme
hardship
waiver.
If
a
refiner
fails
to
provide
all
of
the
information
specified
in
the
regulations
as
part
of
its
hardship
application,
we
will
deem
the
application
void.
In
addition,
we
may
request
additional
information
as
needed.
Our
experience
to
date
shows
that
detailed
technical
and
financial
information
from
the
companies
seeking
relief
has
been
necessary
to
fully
evaluate
whether
a
hardship
situation
exists.
The
following
are
some
examples
of
the
types
of
information
that
must
be
contained
in
an
application:

­
The
crude
oil
refining
capacity
and
fuel
sulfur
level(
s)
of
each
diesel
fuel
product
produced
at
each
of
the
refiner's
refineries.

­
A
technical
plan
for
capital
equipment
and
operating
changes
to
achieve
the
NRLM
diesel
fuel
sulfur
standards.

­
The
anticipated
timing
for
the
overall
project
the
refiner
is
proposing
and
key
milestones
to
ultimately
produce
100
percent
of
NRLM
diesel
fuel
at
the
15
ppm
sulfur
cap.

­
The
refiner's
capital
requirements
for
each
step
of
its
proposed
projects.

­
Detailed
plans
for
financing
the
project
and
financial
statements
demonstrating
the
nature
of
and
degree
of
financial
hardship
and
how
the
requested
relief
would
mitigate
this
hardship.
This
would
include
a
description
of
the
overall
financial
situation
of
the
company
and
its
plans
to
secure
financing
for
the
desulfurization
project
(
e.
g.,
internal
cash
flow,
bank
loans,
issuing
of
bonds,
sale
of
assets,
or
sale
of
stock).

­
A
plan
demonstrating
how
the
refiner
would
achieve
the
standards
as
quickly
as
possible,
including
a
timetable
for
obtaining
the
necessary
capital,
contracting
for
engineering
and
construction
resources,
obtaining
any
necessary
permits,
and
beginning
and
completing
construction.

­
A
description
of
the
market
area
for
the
refiner's
diesel
fuel
products.

­
In
some
cases,
it
could
also
include
a
compliance
plan
for
how
the
refiner's
diesel
fuel
will
be
segregated
through
to
the
end­
user
and
information
on
each
of
the
end­
users
to
whom
its
fuel
is
delivered.

We
will
consider
several
factors
in
our
evaluation
of
any
hardship
waiver
applications
that
we
receive.
Such
factors
include
whether
a
refinery's
configuration
is
unique
or
atypical;
the
proportion
of
non­
highway
diesel
fuel
production
relative
to
other
refinery
products;
whether
the
refiner,
its
parent
company,
and
its
subsidiaries
are
faced
with
severe
economic
limitations
and
steps
the
refiner
has
taken
to
attempt
to
comply
with
the
standards,
including
efforts
to
obtain
credits
towards
compliance.
In
addition,
we
will
consider
the
total
crude
oil
capacity
of
the
refinery
and
its
parent
or
subsidiary
corporations,
if
any,
in
assessing
the
degree
of
hardship
and
the
103
In
a
tank
lock
out
situation
a
storage
tank
can
no
longer
accept
product
from
upstream
in
the
distribution
system
because
there
is
not
sufficient
outlet
for
the
product
it
holds.
A
tank
lock
our
downstream
can
quickly
propagate
upstream.

222
refiner's
role
in
the
diesel
market.
Finally,
we
will
consider
where
the
diesel
fuel
is
intended
to
be
sold
in
evaluating
the
environmental
impacts
of
granting
a
waiver.
Typically,
because
of
EPA's
comprehensive
evaluation
of
both
financial
and
technical
information,
action
on
hardship
applications
can
take
six
or
more
months.

This
extreme
hardship
provision
is
intended
to
address
unusual
circumstances
that
should
be
apparent
now
or
could
emerge
in
the
near
future.
Thus,
refiners
seeking
additional
time
under
this
provision
must
apply
for
relief
by
June
1,
2005,
although
we
retain
the
discretion
to
consider
hardship
applications
later
as
well
for
good
cause.

3.
Provisions
for
Transmix
Facilities
In
the
petroleum
products
distribution
system,
certain
types
of
interface
mixtures
in
product
pipelines
cannot
be
added
in
any
significant
quantity
to
either
of
the
adjoining
products
that
produced
the
interface.
These
mixtures
are
known
as
"
transmix."
The
pipeline
and
terminal
industry's
practice
is
to
transport
transmix
via
truck,
pipeline,
or
barge
to
a
facility
with
an
on­
site
fractionator
that
is
designed
to
separate
the
products.
The
owner
or
operator
of
such
a
facility
is
called
a
"
transmix
processor."
Such
entities
are
generally
considered
to
be
a
refiner
under
existing
EPA
fuel
regulations.

Transmix
processors,
like
conventional
refiners,
are
also
currently
subject
to
the
"
80
percent
/
20
percent"
production
requirement
for
15
ppm
and
500
ppm
sulfur
highway
diesel
fuel.
This
requirement,
however,
is
inconsistent
with
the
inherent
nature
of
the
transmix
processors'
business.
Unlike
conventional
refiners,
transmix
processors
refine
batches
of
fuel
that
vary
in
volume
and
timing
 
largely
unpredictably.
Complying
with
set
percentages
of
different
highway
diesel
fuel
sulfur
grades
would
be
very
difficult,
probably
resulting
in
either
a
need
to
purchase
credits
or
to
postpone
processing
of
some
shipments.
Transmix
processors
commented
that
it
would
not
be
appropriate
to
have
any
additional
restrictions,
beyond
those
based
on
sulfur
content,
imposed
on
their
ability
to
market
the
fuel
that
they
produce.
They
stated
that
the
implementation
of
other
restrictions,
such
as
those
under
the
highway
diesel
program's
80/
20
requirement,
would
force
them
to
ship
large
volumes
of
blendstocks
back
to
refineries
by
truck,
resulting
in
tank
lock­
outs
that
could
cascade
upstream
though
the
distribution
system
potentially
interfering
with
pipeline
operations.
103
Furthermore,
transmix
processors
do
not
have
the
ability
to
change
the
nature
of
their
products,
as
their
processing
equipment
consists
only
of
a
distillation
column
to
separate
the
blendstocks.
This
simple
refinery
configuration
further
limits
their
ability
to
install
and
operate
a
distillate
hydrotreater.
The
commenters
added
that
the
sulfur
content
of
the
slate
of
fuel
products
223
that
they
produce
is
completely
dependant
on
feed
material
that
they
receive,
and
that
it
is
not
feasible
for
them
to
install
desulfurization
equipment.
We
agree
that
it
is
not
feasible
for
transmix
processors
to
alter
the
sulfur
content
of
the
fuels
that
they
produce
and
that
limiting
the
market
for
these
fuels
could
potentially
lead
to
disruptions
in
the
fuel
distribution
system.

In
light
of
this
disproportionate
burden
on
transmix
processors,
today's
final
rule
removes
the
restriction
on
the
volume
of
highway
or
NRLM
diesel
fuel
they
produce,
if
they
produce
diesel
fuel
according
to
typical
operational
practices
involving
the
separation
of
transmix
and
not,
for
example,
by
blending
of
blendstocks
or
processing
crude
or
heavy
oils.
Therefore,
under
today's
final
rule,
transmix
processors
may
choose
to
continue
to
produce
all
of
their
highway
diesel
fuel
to
the
500
ppm
sulfur
standard
until
2010.
They
may
further
choose
to
continue
to
produce
all
of
their
NRLM
diesel
fuel
as
high
sulfur
diesel
fuel
until
June
1,
2010,
all
of
their
NRLM
diesel
fuel
to
the
500
ppm
sulfur
standard
until
June
1,
2014,
and
all
of
their
LM
diesel
fuel
to
a
500
ppm
sulfur
limit
indefinitely.

Transmix
processors
will
be
required
to
properly
designate
their
fuel
with
the
proper
PTDs.
Because
the
volume
of
fuel
involved
will
be
small
and
the
fuel
processed
will
already
have
been
off­
specification,
we
believe
that
providing
this
flexibility
for
transmix
processors
will
have
essentially
no
environmental
impact
and
will
not
affect
the
efficient
functioning
of
the
NRLM
diesel
fuel
program
or
the
existing
highway
diesel
fuel
program.
Rather,
this
approach
will
allow
fuel
volume
to
remain
in
the
highway,
NRLM,
or
LM
(
as
applicable
based
on
time
frame)
markets
that
might
otherwise
be
forced
into
the
heating
oil
market.

C.
Special
Provisions
for
Alaska
and
the
Territories
1.
Alaska
The
nationwide
engine
emission
standards
established
today
apply
to
all
NR
engines
throughout
Alaska.
The
nationwide
NRLM
diesel
fuel
sulfur
standards
and
implementation
dates
apply
to
NRLM
diesel
fuel
used
in
the
areas
of
Alaska
served
by
the
federal
aid
highway
system
(
FAHS).
In
this
final
rule,
EPA
is
not
finalizing
fuel
sulfur
standards
and
implementation
deadlines
for
NRLM
diesel
fuel
used
in
the
areas
of
Alaska
not
served
by
the
FAHS
(
i.
e.,
the
"
rural"
areas).
They
will
be
addressed
in
a
separate
rulemaking
to
allow
EPA
to
address
the
requirements
for
highway
and
NRLM
diesel
fuel
in
the
rural
areas
in
the
same
rulemaking.
This
final
rule
does,
however,
adopt
the
prohibition
in
the
rural
areas
on
the
use
of
high
sulfur
(
greater
than
15
ppm)
diesel
fuel
in
model
year
2011
and
later
nonroad
engines,
which
will
be
manufactured
to
operate
on
ultra­
low
sulfur
diesel
fuel.

a.
How
do
the
Highway
Diesel
Engine
Standards,
the
Highway
Diesel
Fuel
Standards,
and
Implementation
Deadlines
Apply
in
Alaska?

Unlike
the
rest
of
the
nation,
Alaska
is
currently
exempt
from
the
500
ppm
sulfur
standard
for
highway
diesel
fuel
and
the
dye
provisions
for
diesel
fuel
not
subject
to
this
standard.
Since
the
104
Copies
of
information
regarding
Alaska's
petition
for
exemption,
subsequent
requests
by
Alaska,
public
comments
received,
and
actions
by
EPA
are
available
in
public
docket
A
B
96
B
26.

105
Letter
and
attached
document
to
Jeffrey
Holmstead
of
EPA
from
Michele
Brown
of
the
Alaska
Department
of
Environmental
Conservation,
dated
April
1,
2002.
The
communities
on
the
connected
road
system
or
served
by
the
Alaska
State
ferry
system
are
listed
in
the
attached
document.

106
Letter
and
attached
document
to
Jeffrey
Holmstead
of
EPA
from
Ernesta
Ballard
of
the
Alaska
Department
of
Environmental
Conservation,
dated
June
12,
2003.

224
beginning
of
the
500
ppm
sulfur
highway
diesel
fuel
program,
we
have
granted
Alaska
exemptions
from
both
the
sulfur
standard
and
dye
provisions
because
of
its
unique
geographical,
meteorological,
air
quality,
and
economic
factors.
104
On
December
12,
1995,
Alaska
submitted
a
petition
for
a
permanent
exemption
for
all
areas
of
the
state
served
by
the
FAHS,
that
is,
those
areas
previously
covered
only
by
a
temporary
exemption.
While
considering
that
petition,
we
started
work
on
a
nationwide
rule
to
consider
more
stringent
highway
diesel
fuel
requirements
for
sulfur
content.

In
the
January
18,
2001,
highway
diesel
rule
EPA
fully
applied
the
2007
motor
vehicle
engine
emission
standards
in
Alaska.
Based
on
factors
unique
to
Alaska,
we
provided
the
state
with:
(
1)
an
extension
of
the
exemption
from
the
500
ppm
sulfur
fuel
standard
until
the
effective
date
of
the
new
15
ppm
sulfur
standard
for
highway
diesel
fuel
in
2006;
(
2)
an
opportunity
to
request
an
alternative
implementation
plan
for
the
15
ppm
sulfur
diesel
fuel
program;
and
(
3)
a
permanent
exemption
from
the
diesel
fuel
dye
provisions.
In
response
to
these
provisions
in
our
January
18,
2001,
highway
rule,
Alaska
informed
us
that
areas
served
by
the
FAHS,
i.
e.,
communities
on
the
connected
road
system
or
served
by
the
Alaska
state
ferry
system
("
urban"
areas),
would
follow
the
nationwide
requirements.
105
Diesel
fuel
produced
for
use
in
areas
of
Alaska
served
by
the
FAHS
will
therefore
be
required
to
meet
the
same
requirements
for
highway
diesel
fuel
as
diesel
fuel
produced
for
the
rest
of
the
nation.
For
the
rural
parts
of
the
state
 
areas
not
served
by
the
FAHS
 
Alaska
requested
that
highway
diesel
fuel
not
be
subject
to
the
highway
diesel
fuel
sulfur
standard
until
June
1,
2010.
Between
2006
and
2010,
the
rural
communities
would
choose
their
own
fuel
management
strategy,
except
that
all
2007
model
year
and
newer
diesel
vehicles
would
require
ultra­
low
sulfur
diesel
fuel.
Beginning
June
1,
2010,
all
highway
diesel
fuel
in
the
rural
areas
would
be
subject
to
the
15
ppm
sulfur
highway
diesel
fuel
sulfur
standard.
106
EPA
intends
to
propose
and
request
comment
on
an
amendment
to
the
highway
diesel
sulfur
rule
to
incorporate
the
rural
area
transition
plan
submitted
by
the
state.

b.
What
NRLM
Diesel
Fuel
Standards
Are
We
Establishing
for
Urban
Areas
of
Alaska?

Since
Alaska
is
currently
exempt
from
the
500
ppm
sulfur
standard
for
highway
diesel
fuel,
we
also
considered
exempting
Alaska
from
the
500
ppm
sulfur
step
of
the
proposed
NRLM
225
standards.
However,
despite
the
exemption,
officials
from
the
state
of
Alaska
have
informed
us
that
some
500
ppm
sulfur
diesel
fuel
is
nevertheless
being
marketed
in
many
parts
of
Alaska.
Market
forces
have
brought
the
prices
for
500
ppm
diesel
fuel
down
such
that
it
is
now
becoming
competitive
with
higher
sulfur,
uncontrolled
diesel
fuel.
Assuming
this
trend
continues,
requiring
that
NRLM
diesel
fuel
be
produced
to
500
ppm
beginning
June
1,
2007
would
not
appear
to
be
unduly
burdensome.
Even
if
500
ppm
diesel
fuel
were
not
available
in
Alaska
today,
our
expectation
is
that
compliance
with
the
highway
program
described
above
will
likely
result
in
the
transition
of
all
of
the
urban
area
highway
diesel
fuel
distribution
system
to
15
ppm
sulfur
beginning
in
2006.
It
could
prove
very
challenging
for
the
distribution
system
in
some
of
the
areas
to
segregate
a
500
ppm
sulfur
grade
of
NRLM
from
a
15
ppm
sulfur
grade
of
highway
and
an
uncontrolled
grade
for
other
purposes.
We
believe
economics
would
determine
whether
the
distribution
system
would
handle
the
new
grade
of
fuel
or
substitute
15
ppm
sulfur
highway
diesel
fuel
for
NRLM
applications.
Thus,
in
the
2007
to
2010
time
frame,
the
NRLM
market
in
some
urban
areas
might
be
supplied
with
500
ppm
sulfur
diesel,
and
in
other
areas
might
be
supplied
with
15
ppm
sulfur
diesel.
For
this
reason,
today's
action
applies
the
500
ppm
sulfur
standard
for
NRLM
diesel
fuel
to
Alaska's
urban
areas.

Regardless
of
what
occurs
prior
to
2010,
we
anticipate
that
15
ppm
sulfur
highway
diesel
fuel
will
be
made
available
in
urban
areas
of
Alaska
by
this
time
frame.
The
2007
and
later
model
year
highway
fleet
will
be
growing,
demanding
more
and
more
supply
of
15
ppm
sulfur
diesel
fuel.
Adding
nonroad
volume
to
this
would
not
appear
to
create
any
undue
burden.
Thus,
today's
action
also
applies
the
15
ppm
sulfur
standard
for
NR
and
LM
diesel
fuel
in
the
urban
areas
of
Alaska,
along
with
the
rest
of
the
nation
beginning
June
1,
2010
and
June
1,
2012,
respectively.

The
state,
in
its
comments
on
the
proposal,
supports
today's
action
for
the
urban
areas
described
above.
One
refiner
in
Alaska
commented
that
we
should
implement
a
one­
step
approach
requiring
15
ppm
sulfur
diesel
fuel
starting
in
2010.
The
refiner
indicated
that,
due
to
the
limited
NRLM
market,
the
benefits
of
introducing
500
ppm
sulfur
diesel
fuel
in
2007
would
be
minimal.
Also,
the
distribution
system
in
Alaska
is
not
capable
of
handling
the
two
grades
of
diesel
fuel
that
would
be
required
between
2007
and
2010,
thus
15
ppm
sulfur
fuel
would
be
distributed
as
NRLM.
We
agree
that
the
distribution
system
in
Alaska
is
limited
compared
to
the
rest
of
the
nation,
and
that
consumption
of
diesel
fuel
by
NRLM
applications
in
Alaska
is
small.
However,
as
previously
discussed,
we
expect
that
some
500
ppm
sulfur
diesel
fuel
will
be
available
due
to
market
forces,
and
that
15
ppm
sulfur
highway
diesel
fuel
will
be
available
beginning
in
2006
in
the
urban
areas.
Thus,
requiring
500
ppm
sulfur
diesel
fuel
(
or
15
ppm
sulfur
diesel
fuel
as
a
substitute)
for
the
limited
NRLM
applications
beginning
in
2007
does
not
appear
to
create
any
undue
burden
on
the
fuel
supply
or
the
distribution
system
in
urban
Alaska.

During
the
development
of
the
original
500
ppm
sulfur
highway
diesel
fuel
standards
in
the
early
1990'
s,
refiners
and
distributors
in
Alaska
expressed
concern
that
if
Alaska
were
required
to
dye
its
non­
highway
diesel
fuel
red
along
with
the
rest
of
the
country,
residual
dye
in
tanks
or
other
equipment
would
be
enough
to
contaminate
and
disqualify
Jet­
A
kerosene
used
as
aviation
fuel.
Since
much
of
the
diesel
fuel
in
Alaska
is
No.
1
and
is
indistinguishable
from
Jet­
A
kerosene,
not
226
only
would
tanks
and
transfer
equipment
have
to
be
cleaned,
but
separate
tankage
would
be
needed.
Consequently,
we
granted
Alaska
temporary
exemptions
from
the
dye
requirement
and
in
the
January
18,
2001,
highway
diesel
rule
granted
the
state
a
permanent
exemption.

The
proposed
use
of
a
marker
for
heating
oil
in
the
2007
B
10
time
period
presents
similar
concerns
in
Alaska's
distribution
system.
In
response
to
our
request
for
comments
on
this
issue,
the
state
and
refiners
indicated
that
Alaska's
system
is
not
capable
of
accommodating
dyes
or
markers
and
segregation.
The
priority
of
the
state
and
fuel
industry
is
to
keep
dyes
and
markers
out
of
the
fuel
stream
to
prevent
contamination
of
Jet­
A
and
facilitate
movement
of
the
fuel.
The
comments
suggested
that
implementation
of
refiner
product
designations,
labeling
of
fuel
pumps,
retailer
education,
and
rapid
transition
to
ULSD
would
ensure
that
500
ppm
sulfur
diesel
fuel
is
used
in
NRLM
equipment
from
2007
B
10
and
that
15
ppm
sulfur
diesel
fuel
is
used
in
nonroad
equipment
after
2010.

In
section
IV.
D
below,
we
discuss
the
provisions
that
we
are
adopting
for
the
State
of
Alaska
that
will
allow
us
to
enforce
the
NRLM
diesel
fuel
program
without
requiring
the
fuel
marker.

c.
Why
Are
We
Deferring
Final
Action
on
NRLM
Diesel
Fuel
Standards
for
Rural
Areas
of
Alaska?

We
are
deferring
final
action
on
the
fuel
sulfur
standards
and
implementation
deadlines
for
the
rural
areas
of
Alaska.
We
proposed
to
permanently
exempt
NRLM
diesel
fuel
used
in
the
rural
areas
from
fuel
content
standards,
except
that
diesel
fuel
used
in
2011
and
later
model
year
nonroad
engines
would
have
had
to
meet
the
sulfur
content
standard
of
15
ppm
sulfur.
However,
this
proposed
action
is
inconsistent
with
the
action
requested
by
the
state
in
its
comments
to
the
proposal.
It
is
also
inconsistent
with
the
state's
alternative
implementation
plan
for
highway
diesel
fuel
in
rural
Alaska,
which
was
submitted
after
publication
of
the
proposal.

We
intend
to
issue
a
supplemental
proposal
that
would
address
both
highway
and
NRLM
diesel
fuel
sulfur
standards
for
Alaska's
rural
areas.
This
proposal
will
address
the
comments
submitted
by
the
state,
as
well
as
the
state's
alternative
implementation
plan
for
highway
diesel
fuel.

2.
American
Samoa,
Guam,
the
Commonwealth
of
Northern
Mariana
Islands,
and
Puerto
Rico
a.
What
Provisions
Apply
in
American
Samoa,
Guam,
and
the
Commonwealth
of
Northern
Mariana
Islands?

As
we
proposed,
we
are
excluding
American
Samoa,
Guam
and
the
Commonwealth
of
the
Northern
Mariana
Islands
(
CNMI)
from
the
NRLM
diesel
fuel
sulfur
standards
and
associated
requirements.
We
also
are
excluding
these
territories
from
the
tier
4
nonroad
engine
emissions
standards,
and
other
requirements
associated
with
those
emission
standards.
The
territories
will
107
See
57
FR
32010,
July
20,
1992
for
American
Samoa;
57
FR
32010,
July
30,
1992
for
Guam;
and
59
FR
26129,
May
19,
1994
for
CNMI.

227
continue
to
have
access
to
new
nonroad
diesel
engines
and
equipment
using
pre­
tier
4
technologies,
at
least
as
long
as
manufacturers
choose
to
market
those
technologies.
In
the
future,
if
manufacturers
choose
to
market
nonroad
diesel
engines
and
equipment
only
with
tier
4
emission
control
technologies,
we
believe
the
market
will
determine
if
and
when
the
territories
will
make
the
investment
needed
to
obtain
and
distribute
the
diesel
fuel
necessary
to
support
these
technologies.

We
are
also
requiring
that
all
nonroad
diesel
engines
and
equipment
for
these
territories
be
certified
and
labeled
to
the
applicable
requirements
 
either
to
the
previous­
tier
standards
and
associated
requirements
under
this
exclusion,
or
to
the
Tier
4
standards
and
associated
requirements
applicable
for
the
model
year
of
production
under
the
nationwide
requirements
of
today's
action.
The
engines
would
still
be
emissions
warranted,
as
otherwise
required
under
the
CAA
and
EPA
regulations.
Special
recall
and
warranty
considerations
due
to
the
use
of
excluded
high
sulfur
fuel
would
be
the
same
as
those
for
Alaska
during
its
exemption
and
transition
periods
for
highway
diesel
fuel
and
for
these
territories
for
highway
diesel
fuel
(
see
66
FR
5086,
5088,
January
18,
2001).

To
protect
against
circumvention
of
the
emission
requirements
applicable
to
the
rest
of
the
U.
S.,
we
are
restricting
the
importation
of
nonroad
engines
and
equipment
from
these
territories
into
the
rest
of
the
U.
S.
After
the
2010
model
year,
nonroad
diesel
engines
and
equipment
certified
under
this
exclusion
for
sale
in
American
Samoa,
Guam
and
the
Commonwealth
of
the
Northern
Mariana
Islands
will
not
be
permitted
entry
into
the
rest
of
the
U.
S.

b.
Why
Are
We
Treating
These
Territories
Uniquely?

Like
Alaska,
these
territories
are
currently
exempt
from
the
500
ppm
sulfur
standard
for
highway
diesel
fuel.
Unlike
Alaska,
they
are
also
exempt
from
the
new
highway
diesel
fuel
sulfur
standard
effective
in
2006
and
the
new
highway
vehicle
and
engine
emission
standards
effective
beginning
in
2007
(
see
66
FR
5088,
January
18,
2001).

Section
325
of
the
CAA
provides
that
upon
request
of
Guam,
American
Samoa,
the
Virgin
Islands,
or
the
Commonwealth
of
the
Northern
Mariana
Islands,
we
may
exempt
any
person
or
source,
or
class
of
persons
or
sources,
in
that
territory
from
any
requirement
of
the
CAA,
with
some
specific
exceptions.
The
requested
exemption
could
be
granted
if
we
determine
that
compliance
with
such
requirement
is
not
feasible
or
is
unreasonable
due
to
unique
geographical,
meteorological,
or
economic
factors
of
the
territory,
or
other
local
factors
as
we
consider
significant.
Prior
to
the
effective
date
of
the
current
highway
diesel
fuel
sulfur
standard
of
500
ppm,
the
territories
of
American
Samoa,
Guam
and
the
Commonwealth
of
the
Northern
Mariana
Islands
petitioned
us
for
an
exemption
under
section
325
of
the
CAA
from
the
sulfur
requirement
under
section
211(
i)
of
the
CAA
and
associated
regulations
at
40
CFR
80.29.
We
subsequently
granted
the
petitions.
107
Consistent
with
this
decision,
in
our
January
18,
2001
highway
rule
(
66
228
FR
5088),
we
determined
that
the
2007
heavy­
duty
engine
emission
standards
and
2006
diesel
fuel
sulfur
standard
would
not
apply
to
these
territories.

Compliance
with
the
NRLM
diesel
fuel
sulfur
standards
would
result
in
major
economic
burden
on
the
territories.
All
three
of
these
territories
lack
internal
petroleum
supplies
and
refining
capabilities
and
rely
on
long
distance
imports.
Given
their
remote
location
from
Hawaii
and
the
U.
S.
mainland,
most
petroleum
products
are
imported
from
east
rim
nations,
particularly
Singapore.
Australia,
the
Philippines,
and
certain
other
Asian
countries
are
beginning
to
consider
and
in
some
cases
implement
lower
sulfur
diesel
fuel
standards.
However,
it
is
not
clear
that
supply,
especially
of
15
ppm
sulfur
diesel
fuel,
would
be
possible
to
these
territories.

Furthermore,
compliance
with
new
15
ppm
sulfur
requirement
for
highway
diesel
fuel
beginning
in
2006
and
today's
15
ppm
sulfur
requirement
for
NRLM
diesel
fuel
beginning
in
2010
(
or
the
500
ppm
sulfur
requirement
for
NRLM
diesel
fuel
beginning
2007)
would
require
construction
of
separate
storage
and
handling
facilities
for
a
unique
grade
of
diesel
fuel
for
highway
and
nonroad
purposes,
or
use
of
15
ppm
sulfur
diesel
fuel
for
all
diesel
applications
to
avoid
segregation.
Either
of
these
alternatives
would
require
importation
of
500
and
15
ppm
sulfur
diesel
fuel
from
Hawaii
or
the
U.
S.
mainland,
and
would
significantly
add
to
the
already
high
cost
of
diesel
fuel
in
these
territories,
which
rely
heavily
on
U.
S.
support
for
their
economies.
At
the
same
time,
it
is
not
clear
that
the
environmental
benefits
in
these
areas
would
warrant
this
cost.
Therefore,
we
are
not
applying
the
fuel
and
engine
standards
to
these
territories.

The
Caribbean
Petroleum
Corporation
(
CPC)
commented
that
the
proposed
nonroad
diesel
rule
would
result
in
a
major
economic
burden
for
Puerto
Rico,
the
environmental
benefits
do
not
warrant
the
cost,
and
that
Puerto
Rico
should
be
exempt.
However,
the
CPC
did
not
include
any
cost
or
environmental
information
to
support
its
claims.
We
have
no
reason
to
believe
that
the
costs
of
the
NRLM
diesel
fuel
program
in
Puerto
Rico
will
be
significantly
greater
than
that
of
the
U.
S.
For
example,
Puerto
Rico
is
close
to
the
U.
S.
mainland,
and
to
South
American
and
Central
American
suppliers
of
fuel
to
the
U.
S.
mainland,
and
therefore
has
ready
access
to
nearby
fuel
supplies
that
meet
U.
S.
requirements.
Similar
to
the
fuel
distribution
system
in
the
rest
of
the
country,
the
fuel
distribution
system
in
Puerto
Rico
is
geared
to
separate
fuel
handling
and
storage
facilities
for
highway
and
non­
highway
diesel
fuels.
Today's
rule
will
require
additional
segregation
for
the
NRLM
diesel
fuels,
but
no
differently
for
Puerto
Rico
than
for
the
U.
S.
Nevertheless,
to
avoid
that
additional
fuel
segregation,
Puerto
Rico
could
substitute
highway
fuel
for
use
in
NRLM
diesel
engines
and
equipment.
We
also
believe
that
the
important
air
quality
benefits
to
be
realized
by
today's
rule
for
the
four
million
people
in
Puerto
Rico
should
not
be
significantly
different
than
those
for
the
rest
of
the
country.
Consequently,
today's
rule
includes
Puerto
Rico
in
the
NRLM
diesel
fuel
program.

D.
NRLM
Diesel
Fuel
Program
Design
In
addition
to
specifying
the
sulfur
standards
and
the
implementation
dates
when
the
standards
take
effect,
the
diesel
fuel
program
compliance
provisions
must
be
designed
and
108
Diesel
fuel
produced
to
highway
specifications
but
used
for
non­
highway
purposes
is
referred
to
as
"
spill­
over."
It
leaves
the
refinery
gate
and
is
fungibly
distributed
as
if
it
were
highway
diesel
fuel,
and
is
typically
dyed
at
a
point
later
in
the
distribution
system.
Once
it
is
dyed
it
is
no
longer
available
for
use
in
highway
vehicles,
and
is
not
part
of
the
supply
of
highway
fuel.

229
structured
carefully
to
achieve
the
overall
principles
of
the
program.
Specifically,
the
health
and
welfare
benefits
of
the
NRLM
diesel
fuel
and
the
highway
diesel
programs,
and
the
need
for
widespread
availability
of
15
ppm
sulfur
highway
diesel
fuel
must
be
maintained.
The
program
benefits
and
fuel
availability
will
only
happen
if
the
NRLM
diesel
fuel
program
is
designed
such
that
the
amount
of
15
ppm
sulfur
fuel
expected
to
be
produced
under
the
highway
diesel
fuel
program
is
in
fact
produced
and
that
500
ppm
highway
fuel
is
not
overproduced.
Likewise,
the
benefits
of
the
NRLM
diesel
fuel
sulfur
standards
adopted
today
will
only
be
achieved
if
the
program
is
designed
to
ensure
that
the
volume
of
diesel
fuel
consumed
by
NRLM
diesel
engines
is
matched
by
the
supply
of
NRLM
diesel
fuel
produced
to
the
appropriate
low
sulfur
levels.
At
the
same
time,
promoting
the
efficiency
of
the
distribution
system
calls
for
fungible
distribution
of
physically
similar
products,
and
minimizing
the
need
for
product
segregation.

As
discussed
below,
the
situation
faced
in
1993
when
EPA
first
regulated
the
sulfur
content
of
highway
diesel
fuel
parallels
some
of
the
issues
that
EPA
needed
to
address
in
today's
rule.
Prior
to
the
implementation
of
the
500
ppm
sulfur
standard
for
highway
diesel
fuel
in
1993,
most
No.
2
distillate
fuel
was
produced
to
essentially
the
same
specifications,
shipped
fungibly,
and
used
interchangeably
by
highway
diesel
engines,
nonroad
diesel
engines,
locomotive
and
marine
diesel
engines,
and
heating
oil
applications.
Beginning
in
1993,
highway
diesel
fuel
was
required
to
meet
a
500
ppm
sulfur
cap
and
was
segregated
from
other
distillate
fuels
as
it
left
the
refinery
by
the
use
of
a
visible
level
of
dye
solvent
red
164
in
all
non­
highway
distillate.
At
about
the
same
time,
the
Internal
Revenue
Service
(
IRS)
similarly
required
non­
highway
diesel
fuel
to
be
dyed
red
to
a
much
higher
concentration
prior
to
retail
sale
to
distinguish
it
from
highway
diesel
fuel
for
excise
tax
purposes.
Dyed
non­
highway
fuel
is
exempt
from
this
tax.
This
splitting
of
the
distillate
pool
necessitated
changes
in
the
distribution
system
to
ship
and
store
the
now
distinct
products
separately.
In
some
parts
of
the
country
where
the
costs
to
segregate
non­
highway
diesel
fuel
from
highway
diesel
fuel
could
not
be
justified,
both
fuels
have
been
produced
to
highway
specifications.
108
1.
Requirements
During
the
First
Step
of
the
Fuel
Program
EPA
is
adopting
specific
compliance
provisions
during
the
first
step
of
today's
NRLM
diesel
fuel
sulfur
control
program
for
three
reasons.
The
first
is
to
maintain
the
integrity
of
the
highway
diesel
program,
while
allowing
the
efficient
distribution
of
highway
and
NRLM
diesel
fuel.
Since
500
ppm
sulfur
highway
diesel
fuel
allowed
under
the
highway
diesel
fuel
program's
Temporary
Compliance
Option
(
TCO)
and
NRLM
diesel
fuel
meeting
today's
500
ppm
sulfur
standard
will
be
physically
the
same,
it
would
be
impossible
to
maintain
the
benefits
and
program
230
integrity
of
the
highway
diesel
fuel
program
without
some
means
of
differentiating
highway
diesel
fuel
from
NRLM
diesel
fuel.

Continuing
the
current
practice
of
dyeing
NRLM
diesel
fuel
at
the
refinery
gate
and
requiring
that
it
be
segregated
throughout
the
distribution
system
is
not
a
practical
way
to
differentiate
NRLM
diesel
fuel
from
highway
fuel.
At
the
same
time,
allowing
the
unrestricted
fungible
distribution
of
highway
and
NRLM
diesel
fuel
with
the
same
sulfur
level
risks
the
loss
of
important
benefits
of
the
highway
program.
For
example,
if
a
refiner
produced
all
500
ppm
sulfur
fuel
and
designated
it
as
NRLM
diesel
fuel,
that
refiner
would
have
no
obligation
to
produce
any
15
ppm
sulfur
highway
diesel
fuel.
Without
an
effective
way
of
limiting
the
use
in
the
highway
market
of
500
ppm
sulfur
diesel
fuel
produced
as
NRLM
diesel
fuel,
much
more
500
ppm
sulfur
fuel
could,
and
likely
would
find
its
way
into
the
highway
market
than
would
otherwise
happen
under
the
current
highway
program.
This
would
displace
15
ppm
sulfur
diesel
fuel
that
would
have
otherwise
been
produced.
This
likely
series
of
events
would
circumvent
the
intent
of
the
highway
program's
TCO
and
sacrifice
some
of
the
resulting
PM
and
SO
2
emission
benefits
of
the
overall
highway
diesel
program.
If
this
occurred
to
any
significant
degree,
it
could
also
undermine
the
integrity
of
the
highway
program
by
threatening
the
availability
of
15
ppm
sulfur
diesel
fuel
nationwide
for
the
vehicles
that
need
it.
This
is
no
longer
a
concern
after
2010,
when
all
highway
diesel
fuel
is
required
to
meet
a
15
ppm
sulfur
standard.

The
second
reason
is
to
maintain
the
integrity
of
the
NRLM
diesel
fuel
program,
while
allowing
the
efficient
distribution
of
NRLM
diesel
fuel
and
heating
oil
where
they
have
similar
sulfur
levels.
By
establishing
new
sulfur
standards
for
NRLM
diesel
fuel
but
not
heating
oil,
today's
program
creates
the
need
to
distinguish
the
fuel
used
for
these
two
purposes.
Currently,
there
is
no
grade
of
diesel
fuel
which
is
produced
and
marketed
as
a
distinguishable
grade
for
NRLM
diesel
engine
uses.
It
is
typically
produced
and
shipped
fungibly
with
other
distillate
used
for
heating
oil
purposes,
and
it
is
all
dyed
red
in
accordance
with
EPA
and
IRS
regulations.
Because
today's
rule
includes
small
refiner
and
credit
provisions
that
allow
the
limited
production
of
high
sulfur
(
greater
than
500
ppm)
NRLM
diesel
fuel
through
2010,
it
is
not
possible
to
rely
on
sulfur
content
alone
to
differentiate
NRLM
diesel
fuel
from
heating
oil
during
the
first
step
of
the
program.
Without
adequate
controls,
a
refiner
could
choose
not
to
desulfurize
any
of
its
fuel
that
is
destined
for
the
NRLM
diesel
fuel
market,
instead
designating
that
volume
as
heating
oil
at
the
refinery
gate.
This
fuel,
ostensibly
manufactured
for
use
as
heating
oil
could
be
misdirected
for
use
in
NRLM
diesel
equipment,
and
would
be
indistinguishable
from
legal
high
sulfur
NRLM
diesel
fuel
produced
by
small
refiners
and/
or
through
the
use
of
credits.
This
could
substantially
reduce
the
environmental
benefits
of
today's
rule.

After
2010,
when
the
15
ppm
sulfur
standard
for
NR
diesel
fuel
goes
into
effect,
small
refiner
and
credit
NR
fuel
must
meet
a
500
ppm
standard.
Therefore,
after
2010
NRLM
diesel
fuel
can
be
distinguished
from
high
sulfur
(
greater
than
500
ppm)
home
heating
fuel
based
on
sulfur
content.
However,
500
ppm
NR
(
small
refiner,
credit)
produced
from
June
1,
2010
through
May
31,
2012,
and
500
ppm
NRLM
(
small
refiner,
credit)
diesel
fuel
produced
from
June
1,
2012
through
May
31,
2014,
could
not
be
distinguished
from
heating
oil
produced
to
meet
a
similar
500
109
The
IRS
requirements
concerning
dyeing
of
non­
highway
fuel
prior
to
sale
to
consumers
are
not
changed
by
this
rulemaking.

231
ppm
sulfur
limit.
Likewise,
from
June
1,
2010
to
June
1,
2012,
500
ppm
NR
(
small
refiner,
credit)
diesel
fuel
and
LM
diesel
fuel
need
to
be
distinguished
from
each
other,
so
that
diesel
fuel
produced
as
500
ppm
LM
is
not
later
misdirected
to
the
NR
diesel
market.
Such
misdirected
500
ppm
sulfur
LM
diesel
fuel
would
be
indistinguishable
from
legal
500
ppm
sulfur
NR
diesel
fuel,
reducing
the
environmental
benefits
of
today's
rule.
These
various
500
ppm
fuels
could
not
be
distinguished
based
on
sulfur
level.
As
previously
discussed,
the
situation
which
was
faced
in
1993
regarding
the
need
to
differentiate
500
ppm
sulfur
highway
diesel
fuel
from
other
diesel
fuel
is
similar
to
the
need
today
to
differentiate
highway
diesel
fuel,
NRLM
diesel
fuel,
and
heating
oil.

The
third
reason
is
to
maintain
the
integrity
of
the
anti­
downgrading
requirements
in
the
highway
diesel
program.
The
highway
diesel
program
requires
that
each
entity
in
the
distribution
system
downgrade
no
more
than
20
percent
of
the
15
ppm
sulfur
highway
diesel
fuel
for
which
it
assumes
custody
to
500
ppm
sulfur
highway
diesel
fuel.
These
provisions
are
necessary
to
ensure
the
widespread
availability
of
15
ppm
sulfur
diesel
fuel
for
use
in
model
year
2007
and
later
highway
vehicles,
in
which
the
use
of
15
ppm
sulfur
fuel
is
essential
to
facilitate
the
projected
emissions
benefits
of
the
highway
program.
The
highway
program
placed
no
restrictions
on
the
volume
of
highway
diesel
fuel
that
could
be
downgraded
to
NRLM
diesel
fuel.
Under
the
proposed
rule
there
would
be
no
way
to
distinguish
500
ppm
sulfur
NRLM
diesel
fuel
from
500
ppm
sulfur
highway
diesel
fuel
downstream
of
the
refinery.
Therefore,
to
preserve
the
integrity
of
the
highway
program,
the
proposal
would
have
made
the
highway
program's
anti­
downgrade
requirements
more
stringent
by
also
restricting
downgrades
to
500
ppm
sulfur
NRLM
diesel
fuel.
We
received
several
negative
comments
on
this
proposed
restriction.
The
compliance
and
record
keeping
requirements
finalized
to
address
the
two
concerns
discussed
above,
can
be
utilized
to
facilitate
the
implementation
of
the
highway
program's
anti­
downgrading
requirements
without
the
need
to
further
restrict
downgrading.
As
a
result,
today's
rule
also
contains
several
modifications
which
clarify
the
anti­
downgrading
provisions
of
the
highway
diesel
program.

The
requirements
described
below
will
help
ensure
that
the
projected
benefits
of
the
highway
diesel
program
and
of
today's
NRLM
diesel
program
are
achieved.

a.
Ensuring
Refiner
Production
Volumes
of
15
ppm
Sulfur
Highway
Diesel
Fuel
are
Consistent
with
the
Highway
Rule's
80/
20
Requirement
To
avoid
adding
unnecessary
cost
to
the
fuel
distribution
system,
we
proposed
that
the
current
requirement
of
dyeing
non­
highway
distillate
fuels
at
the
refinery
gate
become
voluntary
as
of
June
1,
2006.109
As
discussed
in
the
proposal,
continuing
to
require
that
NRLM
diesel
fuel
and
heating
oil
contain
a
visible
trace
of
red
dye
at
the
refinery
gate
would
allow
for
simple
enforcement
of
the
highway
standards
throughout
the
duration
of
the
highway
program's
TCO.
Clear,
undyed
diesel
fuel
would
have
to
meet
the
80/
20
ratio
of
15
ppm
to
500
ppm
sulfur
highway
diesel
fuel,
and
dyed
fuel
could
only
be
used
in
NRLM
diesel
equipment
or
as
heating
oil.
110
Under
the
highway
program
the
potential
exists
to
add
a
third
grade
of
diesel
fuel
in
an
estimated
40
percent
of
the
country,
and
we
projected
one­
time
tankage
and
distribution
system
costs
of
$
1.05
billion
to
accomplish
this.
Using
similar
assumptions,
to
add
a
second
500
ppm
grade
nationwide
would
cost
in
excess
of
$
2
billion.
This
assumes
that
the
capability
exists
to
add
such
new
tankage.

232
Continuing
the
current
dye
provisions
would
therefore
ensure
that
the
intended
benefits
of
the
highway
program
are
achieved.
However,
maintaining
this
dye
distinction
would
also
require
segregation
of
a
new
grade
of
dyed
500
ppm
sulfur
NRLM
diesel
fuel
throughout
the
entire
distribution
system.
The
costs
of
requiring
segregation
of
two
otherwise
identical
fuels
throughout
the
entire
distribution
system
could
be
quite
substantial.
110
Comments
on
the
proposed
rule
confirmed
EPA's
assessment
that
the
ability
of
the
fuel
distribution
system
to
distribute
these
fuels
fungibly
is
essential,
since
segregating
the
fuels
could
result
in
substantial
additional
transportation
costs
and
necessitate
additional
storage
tanks
throughout
the
system.

The
NPRM
invited
comment
on
two
alternative
approaches
to
ensure
that
refiner
production
of
15
ppm
sulfur
highway
diesel
fuel
met
the
highway
rule's
80/
20
requirement;
the
"
refiner
baseline"
approach,
and
the
"
designate
and
track"
approach.
The
baseline
approach
is
essentially
a
constraint
on
the
sulfur
levels
of
the
various
distillate
fuel
products
a
refiner
produces,
based
on
historical
production
volumes.
Fuel
with
similar
sulfur
levels
could
then
be
fungibly
distributed
with
only
limited
controls
on
the
downstream
distribution
system.
The
designate
and
track
approach
requires
that
a
refiner
designate
into
which
market
discrete
volumes
of
the
distillate
fuels
it
produces
must
be
sold,
without
any
consideration
of
historical
production
volumes.
The
fuel
must
then
be
tracked
through
the
distribution
system
and
sold
only
for
its
designated
purpose
(
or
a
purpose
that
requires
less
control).
As
with
the
baseline
approach,
diesel
fuel
with
similar
sulfur
levels
could
be
fungibly
shipped
up
to
the
point
of
distribution
from
a
terminal
where
offhighway
diesel
fuel
must
be
dyed
red
pursuant
to
IRS
requirements
to
indicate
its
tax
exempt
status.

We
proposed
the
baseline
approach
because,
in
the
absence
of
a
red
dye
requirement
at
the
refinery­
gate
for
NRLM
diesel
fuel,
we
expected
that
it
would:
1)
allow
for
the
fungible
distribution
of
500
ppm
sulfur
highway
and
NRLM
diesel
fuel;
2)
ensure
the
enforceability
of
the
highway
diesel
fuel
and
NRLM
diesel
fuel
standards;
3)
maintain
the
projected
production
volume
of
15
ppm
sulfur
highway
diesel
fuel;
4)
allow
refinery
production
of
500
ppm
sulfur
NRLM
diesel
fuel
and
heating
oil
to
remain
flexible
to
meet
market
demand;
and
5)
enable
the
efficient
distribution
of
diesel
fuel
while
imposing
the
least
burden
on
the
parties
in
the
fuel
production
and
distribution
system.
In
the
proposal,
we
also
discussed
how
a
refiner's
baseline
would
be
set,
and
invited
comment
on
ways
to
account
for
changes
refiners
might
make
from
their
historical
production
practices
in
response
to
the
highway
diesel
program.

In
the
NPRM,
we
expressed
concerns
that
a
designate
and
track
approach
would
raise
significant
workability
and
enforceability
issues
and
therefore
might
not
maintain
the
integrity
of
highway
and
NRLM
diesel
fuel
sulfur
programs.
Our
concerns
about
the
workability
and
233
enforceability
of
a
designate
and
track
approach
amplified
potential
concerns
regarding
whether
the
approach
might
reduce
the
volume
of
15
ppm
sulfur
diesel
fuel
required
to
be
produced
under
the
highway
diesel
program,
leading
to
a
reduction
in
the
environmental
benefits
of
the
highway
diesel
program
and
calling
into
question
the
availability
of
15
ppm
sulfur
diesel
fuel.
We
were
also
concerned
about
whether
this
approach
would
place
too
much
burden
on
the
numerous
entities
in
the
fuel
distribution
system,
as
compliance
was
focused
on
downstream
parties.
While
the
designate
and
track
approach
provided
greater
production
flexibility
to
refiners
than
the
baseline
approach,
it
appeared
to
increase
the
burden
and
restrictions
on
downstream
parties.

Of
the
approaches
discussed
in
the
NPRM,
we
expected
that
the
baseline
approach
would
provide
the
best
mechanism
to
achieve
the
fuel
program
goals
described
at
the
beginning
of
this
section.
Since
the
proposal,
we
have
comprehensively
evaluated
the
advantages
and
disadvantages
of
both
approaches.
Based
on
this
review,
we
now
believe
that
a
baseline
approach
would
produce
significant
adverse
problems
because
of
its
overly
restrictive
impact
on
the
ability
of
fuel
producers
and
distributors
to
efficiently
respond
to
the
myriad
and
daily
needs
of
the
markets
for
highway
and
NRLM
diesel
fuel.
Implementation
of
the
approach
could
also
produce
an
unintended
bias
that
would
tend
to
reduce
the
benefits
of
the
highway
program
and
reduce
the
availability
of
15
ppm
sulfur
highway
diesel
fuel.
At
the
same
time,
our
review
of
the
approaches
shows
that
the
designate
and
track
approach
can
be
implemented
in
an
enforceable
manner
and
likely
would
not
cause
a
reduction
in
the
environmental
benefits
of
the
highway
diesel
program
or
adversely
impact
the
widespread
availability
of
15
ppm
sulfur
highway
diesel
fuel.
Our
evaluation
of
these
alternate
approaches
is
discussed
in
more
detail
in
the
following
sections.

i.
Proposed
Refiner
Baseline
Approach
Under
the
refiner
baseline
approach,
we
proposed
that
from
June
1,
2007
through
May
31,
2010,
any
refiner
or
importer
could
choose
to
distribute
its
500
ppm
sulfur
NRLM
and
highway
diesel
fuels
fungibly
without
adding
red
dye
at
the
refinery
gate.
Refiners
and
importers
who
elect
to
distribute
these
fuels
fungibly
would
need
to
establish
a
non­
highway
distillate
baseline,
defined
as
a
percentage
of
its
total
distillate
fuel
production
volume
based
on
historical
production
data.
For
future
production
purposes,
this
percentage
of
the
volume
of
diesel
fuel
produced
would
have
to
either
meet
the
500
ppm
sulfur
NRLM
diesel
fuel
sulfur
standard
or
be
marked
as
heating
oil.
All
the
remaining
production
of
diesel
fuel
would
have
to
meet
the
requirements
of
the
highway
fuel
program
(
i.
e.,
80
percent
of
this
fuel
would
have
to
meet
a
15
ppm
sulfur
cap).
Refiners
not
wishing
to
participate
in
the
baseline
approach
would
have
to
dye
all
of
their
500
ppm
sulfur
NRLM
diesel
fuel
at
the
refinery.
However,
we
anticipated
that
few
refiners
would
opt
to
dye
500
ppm
sulfur
NRLM
diesel
fuel,
other
than
the
volumes
that
they
dispense
from
their
own
racks,
since
this
would
eliminate
the
ability
to
fungibly
distribute
500
ppm
sulfur
highway
and
NRLM
diesel
fuels.

Since
the
publication
of
the
proposed
rule,
we
have
developed
a
better
understanding
of
refiner
concerns
about
the
constraints
associated
with
the
baseline
approach.
Specifically,
it
is
now
clear
that
individual
refiners
would
be
significantly
constrained
by
the
baseline
approach
from
234
efficiently
responding
to
changes
in
contract
arrangements
with
their
clients
and
changes
in
market
demands.
Refiners
commented
that
they
win
and
lose
contracts
on
a
daily
basis
and
that
depending
on
which
contracts
they
secure,
they
may
not
be
able
to
comply
with
their
baseline.
Specific
concerns
were
raised
regarding
the
ability
of
refiners
to
compensate
for
the
loss
of
export
contracts
and
to
respond
to
spikes
in
the
demand
for
heating
oil
which
periodically
result
from
an
unexpectedly
cold
winter.
Refiners
also
related
that
the
constraints
under
the
baseline
approach
could
cause
an
anti­
competitive
dynamic
between
fuel
refiners
and
their
customers.

Based
on
our
reevaluation
of
the
baseline
approach
and
the
information
gathered
from
the
public
comments,
it
is
now
clear
that
the
constraints
on
the
slate
of
fuels
that
a
refiner
produces
under
the
baseline
approach
could
interfere
with
a
refiner's
ability
to
meet
market
demands,
which
in
turn
could
result
in
supply
shortages
and
increased
fuel
prices.
For
example,
if
a
refiner
were
to
lose
an
export
contract
for
high
sulfur
diesel
fuel,
the
baseline
approach
could
prevent
that
refiner
from
seeking
to
market
that
product
domestically.
This
could
impact
the
overall
supply
of
diesel
fuel
since
the
refiner
may
not
have
sufficient
facilities
to
desulfurize
diesel
fuel.
Also,
knowing
that
losing
such
an
export
contract
would
leave
the
refiner
with
no
ability
to
market
its
fuel
domestically
could
give
the
refiner's
export
client
an
undue
advantage
during
contract
negotiations.

In
the
case
of
a
spike
in
heating
oil
demand
due
to
an
usually
cold
winter,
the
baseline
approach
would
limit
a
refiner's
ability
to
produce
additional
volumes
of
high
sulfur
distillate
fuel
beyond
the
volume
established
under
its
baseline.
Refiners
that
were
limited
in
their
ability
to
produce
additional
high
sulfur
fuel
could
choose
to
supply
low
sulfur
diesel
fuel
to
the
heating
oil
market.
However,
they
may
not
have
sufficient
hydrotreating
capacity
to
do
so.
This
could
limit
their
ability
to
respond
to
a
supply
shortage.

The
proposed
rule
suggested
various
potential
modifications
to
the
baseline
approach
to
address
refiner
concerns
regarding
the
associated
constraints
on
the
slate
of
fuels
they
produce.
We
received
comments
on
the
potential
modifications
discussed
in
the
NPRM
as
well
as
other
potential
changes
to
the
baseline
approach.
Some
commenters
suggested
that
if
EPA
were
to
finalize
a
baseline
approach,
refiners
should
be
able
to
apply
to
EPA
for
a
yearly
adjustment
to
their
baseline
based
on
annual
demand
forecasts.
Even
with
such
flexibility,
refiners
still
concluded
that
in
many
cases
they
would
likely
be
forced
to
dye
their
fuel
instead.
For
fuel
distributors,
having
refiners
dye
their
NRLM
diesel
fuel
presented
an
unacceptable
situation
due
to
the
need
to
distribute
another
grade
of
fuel.
As
a
result,
all
comments
from
the
refining
and
fuel
distribution
community
were
in
agreement
that
the
baseline
approach
may
be
unworkable.

Based
on
our
review
of
the
comments
and
our
discussions
with
fuel
producers
and
distributions,
it
has
become
clear
that
none
of
the
potential
modifications
to
the
baseline
approach
would
adequately
compensate
for
the
inherent
inflexibility
of
requiring
refiners
to
comply
with
set
production
ratios.
Even
if
EPA
were
to
adjust
such
ratios
on
an
annual
basis,
refiners
might
need
to
approach
EPA
for
an
interim
adjustment
if
their
contractual
agreements
changed
or
if
market
demand
shifted
unexpectedly.
The
process
of
evaluating
requests
for
baseline
adjustments
could
111
"
Summary
and
Analysis
of
the
Highway
Diesel
Fuel
2003
Pre­
compliance
Reports,"
EPA
420­
R­
03­
103,
October
2003.

235
be
very
burdensome
to
the
industry
and
to
EPA,
and
EPA
would
unlikely
be
able
to
respond
quickly
enough
to
changing
market
conditions.

More
importantly,
all
of
the
potential
alternatives
that
we
might
implement
to
mitigate
the
constraints
of
the
baseline
approach
could
potentially
undermine
the
environmental
benefits
of
the
highway
program.
Such
alternatives
all
would
involve
granting
allowances
to
some
refiners
to
produce
additional
volumes
of
non­
highway
fuels
above
the
set
baseline
to
facilitate
a
refiner
meeting
the
market
demand
for
such
fuels.
At
the
same
time,
it
would
not
be
possible
for
EPA
to
reduce
the
ability
of
other
refiners
to
produce
non­
highway
fuel
who
may
have
lost
these
markets.
Therefore,
for
such
alternatives
to
be
effective
in
responding
to
changing
market
conditions,
an
unintended
downward
bias
would
result
regarding
the
required
production
of
15
ppm
sulfur
highway
diesel
fuel.

Even
without
any
changes
we
discovered
from
the
highway
diesel
program
pre­
compliance
reports
that
the
proposed
baseline
approach
has
a
downward
bias
that
could
result
in
a
reduction
in
the
volume
of
15
ppm
sulfur
diesel
fuel
produced
under
the
highway
diesel
program.
111
We
proposed
that
refiners
could
choose
to
calculate
their
off­
highway
baseline
using
either
an
average
of
2003
through
2005
production
data
or
2006
production
data.
Providing
the
option
for
a
2006
baseline
was
necessary
because
a
number
of
refiners
will
be
changing
the
slate
of
fuels
that
they
produce
in
response
to
the
highway
diesel
rule
which
becomes
effective
in
2006.
While
the
highway
diesel
pre­
compliance
reports
indicate
an
overall
increase
in
production
volume,
they
also
indicate
that
40
percent
of
highway
diesel
refiners
will
decrease
the
volume
of
highway
diesel
fuel
they
produce.
If
all
of
these
refiners
were
to
take
a
2006
baseline
to
determine
the
volume
of
15
ppm
sulfur
diesel
fuel
they
would
be
required
to
produce,
a
substantial
drop
in
the
total
volume
of
15
ppm
sulfur
diesel
fuel
produced
could
result.

The
pre­
compliance
reports
indicate
that
the
other
60
percent
of
refiners
will
be
increasing
the
volume
of
highway
diesel
fuel
they
produce.
We
projected
that
these
shifts
in
the
slate
of
fuel
products
that
refiners
produce
would
have
an
overall
positive
impact
on
diesel
fuel
supply.
However,
refiners
that
increase
the
volume
of
highway
fuel
they
produce
would
likely
chose
to
calculate
their
baseline
using
their
lower
2003­
2005
production
volumes.
Doing
so
would
result
in
a
lower
percentage
of
their
distillate
fuel
that
would
be
required
to
be
produced
for
highway
diesel
use,
and
subject
to
a
15
ppm
sulfur
standard.

The
volume
of
spillover
could
also
be
reduced
if
refiners
were
to
dye
500
ppm
sulfur
diesel
they
manufactured
to
meet
anticipated
NRLM
diesel
fuel
demand
in
order
to
avoid
needing
to
comply
with
the
baseline
approach.
Many
refiners
commented
that
they
considered
the
baseline
approach
so
unworkable
and
onerous
that
they
would
choose
to
dye
all
of
their
500
ppm
sulfur
NRLM
diesel
fuel
at
the
refinery
gate.
This
could
force
some
parts
of
the
distribution
systems
236
which
had
previously
not
carried
two
grades
of
diesel
fuel
for
highway
and
off­
highway
uses
to
begin
doing
so.

In
summary,
we
are
not
finalizing
the
proposed
baseline
system
because
we
believe
 
1.
It
could
unnecessarily
constrain
refiners
ability
to
meet
market
demands,
encouraging
them
to
dye
500
ppm
sulfur
NRLM
diesel
fuel
at
the
refinery
resulting
in
an
added
burden
to
the
distribution
system;

2.
It
could
create
a
bias
that
could
result
in
a
loss
in
the
volume
of
15
ppm
sulfur
highway
diesel
fuel
produced,
and
the
options
to
remove
these
market
constraints
would
only
increase
the
bias
to
reduce
the
volume
of
15
ppm
sulfur
highway
diesel
fuel;
and
3.
The
baseline
approach
would
not
ensure
that
the
environmental
benefits
of
the
2007
highway
diesel
program
would
be
maintained.

ii.
Designate
and
Track
Approach
At
the
time
of
the
NPRM,
we
invited
comment
on
an
alternative
to
the
baseline
approach
called
the
"
designate
and
track"
approach.
Under
the
envisioned
designate
and
track
approach,
refiners
and
importers
would
designate
the
volumes
of
500
ppm
sulfur
diesel
fuel
they
produce/
import
as
either
highway
or
NRLM
diesel
fuel
and
would
ship
them
fungibly.
These
designations
would
follow
the
fuel
through
the
distribution
system
and
be
used
to
restrict
the
sale
of
500
ppm
sulfur
NRLM
diesel
fuel
from
the
highway
market.
While
we
sought
comment
on
various
forms
of
the
designate
and
track
approach,
we
also
expressed
serious
reservations
regarding
its
workability,
enforceability,
impact
on
the
benefits
of
the
highway
rule,
and
constraints
on
the
distribution
system.
For
example,
at
the
time
of
the
proposal,
refiners
supported
a
designate
and
track
approach
where
certain
parts
of
the
distribution
system
(
e.
g.,
pipelines)
did
not
have
to
report.
EPA
believed
that
such
an
approach
was
unenforceable.
Refiners
were
also
supporting
the
designate
and
track
approach
as
an
option
for
refiners
to
choose
in
addition
to
the
baseline
approach.
However,
EPA
believed
that
the
two
approaches
were
incompatible.

As
noted
in
the
proposal,
the
designate
and
track
approach
allows
maximum
flexibility
for
refiners
and
importers,
but
EPA
had
concerns
that
the
volume
reconciliation
requirements
would
inappropriately
restrict
the
flexibility
of
downstream
parties
to
respond
to
market
changes.
EPA
also
had
concerns
that
it
would
reduce
the
amount
of
15
ppm
spillover
from
the
highway
market,
reducing
the
environmental
benefits
of
that
rule.

Since
the
proposal,
we
received
extensive
input
both
in
the
written
comments
and
through
in­
depth
meetings
with
representatives
of
all
segments
of
the
fuel
distribution
industry
on
how
the
designate
and
track
system
might
be
structured
to
provide
the
needed
compliance
oversight
without
placing
an
undue
burden
on
industry.
Refiners
now
agree
that
the
designate
and
track
237
approach
should
not
be
an
option
for
refiners
in
addition
to
the
baseline
approach,
and
support
it
as
a
stand
alone
approach.
All
parties
in
the
fuel
distribution
system
have
also
now
expressed
support
for
the
record
keeping
and
reporting
requirements
associated
with
tracking
designated
fuel
volumes
through
each
custodian
in
the
distribution
chain
until
the
fuel
leaves
the
terminal
either
taxed
or
dyed.
Furthermore,
commenters
from
all
segments
of
the
fuel
distribution
industry
from
the
refiner
through
to
the
terminal
stated
that
the
information
needed
to
support
the
designate
and
track
approach
is
already
kept
as
part
of
normal
business
practices.
Commenters
stated
that
only
modest
upgrades
in
their
record
keeping
procedures
would
be
needed
to
compile
the
needed
information
and
that
preparing
the
necessary
reports
would
not
represent
a
significant
burden.
Thus,
our
concerns
that
a
designate
and
track
approach
might
represent
a
large
burden
to
fuel
distributors
were
unfounded.

In
addition,
we
have
developed
appropriate
solutions
to
the
various
open
questions
and
issues
that
we
had
with
the
designate
and
track
approach
at
the
time
of
the
proposal.
In
the
proposal
it
was
unclear
how
a
designate
and
track
approach
would
be
structured
to
account
for
the
swell
in
highway
diesel
fuel
volumes
in
the
winter
that
results
from
downstream
kerosene
blending
to
improve
cold
flow
properties.
Without
an
adequate
control
mechanism,
normal
swell
in
downstream
highway
diesel
fuel
volumes
in
the
North
due
to
kerosene
blending
during
winter
months
could
mask
the
inappropriate
shifting
of
NRLM­
designated
500
ppm
sulfur
fuel
to
the
highway
diesel
pool.
We
have
developed
an
appropriate
mechanism
to
address
this
situation
as
described
in
section
IV.
D.
3.

In
the
proposal,
we
also
expressed
concerns
regarding
how
normal
volumetric
fluctuations
in
the
distribution
system
such
as
those
caused
by
product
downgrading
in
pipelines
could
be
adequately
accounted
for
under
a
designate
and
track
system
so
that
such
fluctuations
would
not
mask
the
inappropriate
shifting
of
500
ppm
sulfur
NRLM
diesel
fuel
to
the
highway
pool.
We
have
subsequently
developed
a
periodic
volume
account
balance
system
to
account
for
such
fluctuations.

Through
discussions
with
terminal
operators,
we
have
also
resolved
concerns
expressed
in
the
NPRM
that
a
designate
and
track
approach
might
limit
a
terminal
operator's
ability
to
respond
to
shifts
in
demand
for
500
ppm
sulfur
highway
versus
NRLM
diesel
fuel.
To
avoid
this
potential
problem
today's
rule
allows
terminal
operators
and
others
to
switch
the
designation
of
500
ppm
sulfur
NRLM
diesel
fuel
to
highway
diesel
fuel
on
a
temporary
basis
but
not
on
a
cumulative
basis
over
time.
This
will
allow
terminal
operators
to
sell
NRLM
designated
500
ppm
sulfur
fuel
into
the
highway
market
provided
that
they
later
sell
the
same
volume
of
highway­
designated
500
ppm
sulfur
fuel
into
the
NRLM
market.
To
ensure
that
500
ppm
sulfur
NRLM
diesel
fuel
is
not
inappropriately
shifted
into
the
highway
diesel
pool,
terminal
operators
will
need
to
demonstrate
that
the
volume
of
500
ppm
sulfur
highway
diesel
fuel
they
delivered
is
less
than
or
equal
to
the
volume
received.

In
the
NPRM,
we
stated
that
determining
the
responsible
party
for
a
violation
of
the
restriction
against
shifting
500
ppm
sulfur
NRLM
diesel
fuel
into
the
highway
pool
would
be
112
This
highway
diesel
fuel
would
meet
the
currently­
applicable
500
ppm
sulfur
standard
for
highway
diesel
fuel.

238
difficult
under
a
designate
and
track
approach
because
a
number
of
parties
in
the
distribution
chain
take
custody
of
the
fuel
without
taking
ownership.
However,
this
concern
can
be
addressed
by
structuring
the
provisions
to
hold
the
custodian
of
the
fuel
accountable
for
any
such
violation
that
takes
place
while
the
fuel
is
in
their
custody.
Review
of
electronic
data
submitted
from
all
custodians
in
the
highway
and
NRLM
diesel
fuel
distribution
chain
will
reveal
the
custodian
responsible
for
a
violation.
By
comparing
such
data
on
the
hand­
offs
of
designated
fuel
volumes
between
all
adjacent
pairs
of
custodians
in
the
distribution
chain
for
discrepancies,
we
can
identify
any
party
responsible
for
inappropriately
shifting
volumes
of
500
ppm
sulfur
fuel
designated
for
use
in
NRLM
equipment
to
the
highway
market.
Many
terminals
do
not
take
ownership
of
the
fuel
that
they
handle.
Terminals
that
lease
storage
tanks
to
multiple
owners
will
need
to
enter
into
contractual
agreements
with
their
tenants
to
ensure
that
they
understand
their
obligations
as
a
custodian
of
designated
fuel
and
do
not
inappropriately
change
the
designation
of
fuels
stored
in
such
leased
tanks.

An
effective
enforcement
and
compliance
assurance
program
must
include
the
ability
to
rapidly
and
accurately
review
the
large
amount
of
data
on
the
hand­
offs
of
designated
fuel
volumes
for
discrepancies.
This
can
be
accomplished
if
all
parties
report
electronically
to
a
database
which
can
reconcile
hand­
off
volumes
between
all
parties
in
the
distribution
chain
in
an
automated
fashion.
All
segments
in
the
fuel
distribution
system
are
now
in
support
of
providing
the
necessary
information
to
such
an
electronic
reporting
system.
We
have
conducted
a
review
of
the
Agency
resources
that
would
be
needed
to
compile
the
industry
reports
on
the
transfer
of
designated
fuel
volumes,
perform
quality
assurance
on
these
data,
and
to
perform
the
necessary
analysis
of
the
database
to
discover
potential
violations.
Our
review
indicates
that
the
reporting
forms
can
be
standardized
and
the
review
process
automated
in
such
a
fashion
as
to
minimize
the
Agency
resource
requirements,
while
at
that
same
time
ensuring
the
quality
of
the
data
and
completeness
of
the
review
process.
In
light
of
the
above
discussion,
we
are
now
convinced
that
a
designate
and
track
approach
can
be
designed
to
meet
our
enforcement
and
compliance
assurance
needs
under
today's
rule.

In
addition
to
concerns
regarding
the
workability
and
enforceability
of
a
designate
and
track
approach,
the
NPRM
expressed
concerns
that
application
of
such
an
approach
could
reduce
the
benefits
of
the
highway
diesel
program
by
reducing
the
amount
of
highway
diesel
fuel
that
is
used
in
nonroad
equipment
due
to
the
logistical
constraints
in
the
distribution
system
("
spillover").
Specifically,
it
was
thought
that
the
opportunity
to
fungibly
ship
batches
of
500
ppm
sulfur
NRLM
diesel
fuel
and
500
ppm
sulfur
highway
diesel
fuel
might
allow
refiners
to
supply
highway
and
NRLM
diesel
fuel
to
markets
where
they
would
otherwise
have
supplied
just
highway
fuel
for
both
purposes.
Our
reevaluation
since
the
proposal
indicates
that
this
is
not
a
significant
concern.
As
noted
earlier,
there
are
currently
substantial
regions
of
the
country
where
only
highway
diesel
fuel
is
supplied
by
bulk
shipments
to
both
the
highway
and
NRLM
markets
due
to
the
high
costs
associated
with
segregating
an
additional
distillate
grade
in
the
distribution
system.
112
These
are
239
the
same
areas
where
the
majority
of
spillover
occurs
today.
After
the
highway
diesel
program
becomes
effective
in
2006,
we
project
that
only
15
ppm
sulfur
highway
diesel
fuel
will
be
supplied
in
bulk
shipments
to
both
the
highway
and
NRLM
markets
in
most
of
these
same
areas.
Although
500
ppm
sulfur
highway
diesel
fuel
could
be
shipped
in
bulk
to
these
areas
through
2010
under
the
highway
program's
TCO,
the
potential
demand
for
such
fuel
and
for
500
ppm
sulfur
NRLM
diesel
fuel
would
not
be
sufficient
to
justify
the
cost
of
segregating
an
additional
grade
of
500
ppm
sulfur
diesel
fuel
in
these
areas
for
a
short
period
of
time.
The
designate
and
track
approach
does
not
impact
the
costs
of
segregation,
and
therefore
is
not
expected
to
change
distribution
patterns
that
are
based
on
these
costs.

After
2010,
when
500
ppm
sulfur
highway
fuel
no
longer
exists,
the
total
volume
of
500
ppm
sulfur
diesel
fuel
in
the
distribution
system
will
be
substantially
reduced,
and
there
will
be
even
less
incentive
to
distribute
an
additional
grade
of
500
ppm
sulfur
diesel
fuel
in
bulk.
Therefore,
the
only
areas
where
substantial
flexibility
will
exist
under
today's
program
to
supply
either
highway
or
NRLM
diesel
fuel
to
the
NRLM
market
is
in
areas
where
this
flexibility
exists
today.
Despite
this
flexibility
in
the
current
regulations,
spillover
currently
still
occurs.
Therefore,
we
project
that
there
will
be
little
additional
potential
due
to
today's
rule
for
refiners
to
reduce
highway
spillover
into
the
NRLM
market
under
a
designate
and
track
approach
and
that
such
spillover
levels
would
not
be
significantly
reduced
from
historical
levels.
In
contrast,
as
discussed
above,
we
now
believe
that
the
baseline
approach
would
have
resulted
in
a
significant
loss
of
15
ppm
diesel
production.

Furthermore,
concerns
regarding
a
potential
reduction
in
the
spillover
of
15
ppm
sulfur
highway
diesel
into
the
NRLM
markets
has
been
lessened
by
the
information
provided
in
the
highway
program
pre­
compliance
reports.
These
reports
suggest
that
more
than
95
percent
of
highway
diesel
fuel
will
be
produced
to
a
15
ppm
sulfur
standard
beginning
in
2006.
In
calculating
the
projected
benefits
of
the
highway
diesel
program,
we
assumed
that
only
80
percent
of
highway
diesel
fuel
would
meet
a
15
ppm
sulfur
standard.
Therefore,
the
actual
benefits
of
the
highway
program
will
be
substantially
greater
than
estimated
if
the
projections
in
the
pre­
compliance
reports
are
realized.

Based
on
the
above
discussion,
we
believe
that
the
concerns
regarding
the
designate
and
track
approach's
workability,
enforceability,
and
ability
to
preserve
the
benefits
of
the
highway
program
and
today's
NRLM
diesel
fuel
program
have
been
satisfactorily
resolved.

b.
Ensuring
that
Heating
Oil
is
not
Used
in
NRLM
Equipment
from
June
1,
2007
Through
June
1,
2010
i.
Use
of
a
Fuel
Marker
in
Heating
Oil
To
prevent
shifting
heating
oil
into
the
NRLM
market,
we
proposed
that
a
fuel
marker
be
added
to
heating
oil
at
the
refinery
gate.
We
proposed
that
the
presence
of
the
marker
required
in
heating
oil
would
be
strictly
prohibited
in
NRLM
diesel
fuel.
As
noted
earlier,
this
approach
is
113
Additional
injection
equipment
will
be
required
to
inject
the
heating
oil
marker.

114
Including
every
end­
user
of
heating
oil.

115
Letter
to
Paul
Machiele,
EPA,
from
James
Thomas,
American
Society
for
Testing
and
Materials
(
ASTM),
entitled
"
Withdrawal
of
ASTM
Request,"
January
19,
2004.
In
this
letter
ASTM
withdraws
its
request
for
a
postponement
of
the
finalization
of
the
heating
oil
marker
requirements
in
today's
rule.
See
section
V.
E
regarding
the
selection
of
the
heating
oil
marker
required
in
today's
rule.

240
similar
to
red
dye
requirements
for
high
sulfur
diesel
fuel
that
were
implemented
in
1993
to
prevent
its
use
as
highway
diesel
fuel
subject
to
the
then
applicable
500
ppm
sulfur
standard.

We
proposed
that
the
marker
be
added
at
the
refinery
gate
rather
than
at
the
terminal
for
several
reasons.
First,
this
seemed
to
be
the
most
efficient
and
lowest
cost
option
for
addition
of
the
marker
given
that
the
number
of
terminals
is
far
greater
than
the
number
of
refineries.
113
Second,
requiring
that
the
marker
be
present
in
heating
oil
when
it
is
introduced
into
the
distribution
system
would
ensure
that
we
could
differentiate
high
sulfur
small
refiner
and
credit
fuel
from
heating
oil
at
any
point
in
the
system.
This
approach
would
provide
good
assurance
that
the
inability
to
use
fuel
sulfur
content
to
differentiate
heating
oil
from
high
sulfur
NRLM
diesel
fuel
produced
under
the
small
refiner
and
credit
provisions
in
today's
rule
(
effective
until
June
1,
2010)
would
not
provide
an
opportunity
to
mask
the
potential
use
of
heating
oil
in
NRLM
equipment.
Providing
such
assurance
is
an
essential
element
to
enable
the
implementation
of
the
small
refiner
and
credit
provisions
in
today's
rule.
Lastly,
under
the
proposed
baseline
approach,
there
was
no
other
way
to
ensure
that
heating
oil
was
not
shifted
into
the
NRLM
diesel
fuel
pool
during
distribution
from
the
refinery/
importer
to
the
terminal.

We
received
numerous
comments
that
the
upstream
addition
of
the
proposed
marker
to
heating
oil
would
raise
significant
concerns
that
the
marker
might
contaminate
jet
fuel.
Commenters
stated
that
this
would
represent
a
substantial
safety
concern
unless
the
proposed
marker
was
proven
not
to
adversely
impact
the
quality
of
jet
fuel
and
the
operation
of
jet
engines.

The
designate
and
track
approach
described
above
for
500
ppm
sulfur
NRLM
diesel
fuel,
however,
also
provides
an
effective
means
to
address
concerns
about
the
use
of
the
fuel
marker.
By
extending
the
designate
and
track
approach
to
high
sulfur
NRLM
diesel
fuel
and
heating
oil,
these
otherwise
identical
fuel
grades
can
be
tracked
down
to
the
terminal,
and
the
marker
then
can
be
added
at
the
terminal
instead
of
at
the
refinery
gate.
Going
beyond
the
terminal
with
designate
and
track
is
not
feasible
give
the
breadth
and
nature
of
entities
involved.
114
As
a
result,
the
marker
is
still
required
downstream
of
the
terminal.
However,
shifting
the
point
of
marker
addition
downstream
to
the
terminal
should
eliminate
any
significant
opportunity
for
jet
fuel
contamination.
Subsequent
comments
and
discussions
appear
to
have
confirmed
this.
115
EPA
will
continue
to
work
with
other
federal
agencies,
including
FAA
and
DoD,
and
to
follow
ongoing
research
and
studies
regarding
the
effect
of
dyes
and
markers
on
jet
fuel,
particularly
potential
contamination
that
could
have
an
adverse
impact
on
the
safe
operation
of
aircraft.
We
will
keep
abreast
of
the
116
See
section
VIII.
H.
of
today's
preamble.

117
To
test
for
contamination,
jet
fuel
marketers
typically
fill
a
white
five
gallon
bucket
with
jet
fuel.
The
presence
of
a
pink
tinge
to
the
light
straw
colored
jet
fuel
indicates
that
the
fuel
has
been
contaminated
with
fuel
that
contains
red
dye.

118
If
IRS
amends
its
red
dye
requirements,
EPA
will
also
seriously
consider
amending
the
fuel
marker
and
associated
red
dye
requirements
contained
in
today's
rule.
See
section
V.
E.
of
today's
preamble.

241
ASTM,
CRC,
FAA,
IRS,
and
EU
activities
regarding
the
evaluation
of
the
use
of
SY­
124
and
commit
to
a
review
of
our
use
of
SY­
124
under
today's
rule
based
on
these
findings.
If
alternative
markers
are
identified
that
do
not
raise
concerns
regarding
the
potential
contamination
of
jet
fuel,
we
will
initiate
a
rulemaking
to
evaluate
the
use
of
one
of
these
markers
in
place
of
SY­
124.116
We
also
received
a
number
of
comments
expressing
concern
over
the
inability
of
the
proposed
marker
to
be
detected
using
the
standard
simple
test
used
today
to
detect
contamination
with
red
dye.
117
The
marker
finalized
by
today's
rule
does
not
provide
visual
evidence
of
its
presence.
However,
if
the
marker
is
added
at
the
terminal
it
will
only
be
present
in
heating
oil
when
red
dye
is
also
present.
The
fact
that
heating
oil
will
be
dyed
red
pursuant
to
IRS
requirements
before
it
leaves
the
terminal
will
enable
jet
fuel
distributors
to
continue
to
use
the
"
white
bucket
test"
to
detect
heating
oil
contamination,
and
hence
marker
contamination
of
jet
fuel.
Today's
rule
also
includes
a
stand­
alone
requirement
that
any
fuel
to
which
the
fuel
marker
is
added
must
also
contain
visible
evidence
of
red
dye.
118
ii.
Provisions
to
Ensure
Heating
Oil
is
not
Used
in
NRLM
Equipment
in
the
Northeast
and
Mid­
Atlantic
In
the
Northeast,
heating
oil
will
continue
to
be
distributed
in
significant
quantities
after
implementation
of
the
NRLM
diesel
fuel
program.
Discussions
with
terminal
operators
in
the
Northeast,
and
other
representatives
of
heating
oil
users
and
distributors,
revealed
concerns
that
the
proposed
heating
oil
marker
requirement
would
represent
a
substantial
new
burden
on
terminal
operators
and
users
of
heating
oil.
Terminal
operators
stated
that
the
cost
of
installing
new
injection
equipment
would
be
burdensome,
and
that
the
cost
of
the
marker
itself
would
be
significant
given
the
large
volume
of
heating
oil
used
in
the
Northeast.
They
also
stated
that
they
did
not
expect
any
small
refiner
or
credit
fuel
to
be
used
in
the
Northeast,
and
that
consequently,
the
marker
requirement
was
not
needed
in
this
area.
They
suggested
that
if
we
prohibited
the
sale
of
small
refiner
and
credit
fuel
in
PADD
I
,
this
area
could
be
exempted
from
the
heating
oil
marker
requirement.

We
evaluated
the
viability
of
avoiding
the
heating
oil
marker
requirement
in
portions
of
PADD
I
and
instead
enforcing
the
NRLM
diesel
fuel
standards
on
the
basis
of
sulfur
content
alone.
242
The
heating
oil
marker
is
needed
to
ensure
that
heating
oil
is
not
sold
into
the
NRLM
market
as
high
sulfur
NRLM
fuel.
The
marker
is
needed
only
if
high
sulfur
NRLM
fuels
will
otherwise
be
in
the
market.
High
sulfur
NRLM
fuel
can
be
produced
under
the
small
refiner
and
credit
provisions,
and
through
the
generation
of
high
sulfur
NRLM
in
the
distribution
system
from
the
downgrading
of
500
ppm
sulfur
NRLM.
In
evaluating
the
feasibility
of
avoiding
the
heating
oil
marker,
EPA
therefore
focused
on
determining
the
likely
production
and
marketing
of
these
high
sulfur
NRLM
fuels
in
portions
of
PADD
I
in
this
time
frame.

We
held
in­
depth
discussions
with
organizations
representing
refiners,
pipelines,
and
terminal
operators
to
evaluate
this
issue.
Representatives
of
non­
small
refiners
including
API
and
NPRA
stated
that
being
precluded
from
selling
sulfur
credit
fuel
in
the
Northeast
and
Mid­
Atlantic
would
not
significantly
reduce
the
intended
benefits
to
refiners
of
the
credit
provisions
in
today's
rule.
We
also
spoke
with
small
refiner
representatives
of
and
the
specific
small
refiners
whose
marketing
area
might
include
the
Northeast
and
Mid­
Atlantic
and
found
that
in
fact,
small
refiners
were
not
expected
to
market
fuel
in
this
area.
Finally,
we
evaluated
the
current
and
likely
future
practices
in
the
Northeast
and
Mid­
Atlantic
areas
for
the
sale
of
downgraded
fuel
generated
in
the
distribution
system.
We
found
that
this
downgraded
diesel
fuel
could
easily
continue
to
be
sold
in
the
very
large
and
ubiquitous
heating
oil
market
that
is
expected
to
continue
to
exist
in
this
region.
This
avoids
any
need
for
additional
storage
or
tankage
for
both
high
sulfur
and
low
sulfur
NRLM
fuels,
and
fits
into
the
pre­
existing
market
structure
for
heating
oil.

Consequently,
unlike
the
rest
of
the
country,
there
was
little
expected
need
to
maintain
a
high
sulfur
NRLM
market
in
this
part
of
the
country
as
an
outlet
for
small
refiner,
credit,
or
offspecification
downgraded
diesel
fuel.
Based
on
this
input,
we
concluded
that
codifying
this
expected
practice
and
making
it
enforceable,
i.
e.
not
allowing
high
sulfur
fuel
to
be
marketed
as
NRLM
in
this
area
of
the
country,
would
be
consistent
with
the
current
distribution
practices
in
this
area
of
the
country
and
that
the
potential
impact
of
taking
such
an
approach
on
the
flexibility
offered
in
the
program
would
be
minimal
or
nonexistent.
If
we
codified
it
we
would
no
longer
need
the
marker
requirement,
and
the
resulting
benefits
and
cost
savings
to
terminals
would
be
substantial.
The
approach
would
also
simplify
and
strengthen
the
enforcement
of
today's
sulfur
requirements
in
this
area
by
allowing
EPA
to
enforce
the
NRLM
standards
simply
based
on
the
measurement
of
the
sulfur
content
of
the
fuel.
There
would
be
little
expected
impact
on
the
environment
as
this
is
not
expected
to
change
the
amount
of
high
sulfur
fuel
produced
from
small
refiners,
credit
usage,
or
downgrade
in
the
distribution
system,
only
the
market
into
which
it
is
sold.

In
deciding
which
parts
of
PADD
I
to
use
this
enforcement
mechanism,
we
attempted
to
minimize
the
number
of
terminals
that
would
need
to
install
new
injection
equipment
and
the
amount
of
heating
oil
that
would
need
to
be
marked,
while
preserving
the
benefits
of
the
small
refiner
and
credit
fuel
provisions
in
today's
rule
to
the
maximum
extent
possible.
To
assess
the
placement
of
the
boundary
for
the
Northeast/
Mid­
Atlantic
area
where
the
marker
requirement
was
waived,
we
evaluated
the
magnitude
of
heating
oil
demand
by
state,
(
see
chapter
5
of
the
RIA)
solicited
input
from
the
potentially
affected
parties,
evaluated
the
area
supplied
by
the
pipeline
119
See
chapter
V
of
the
RIA
for
a
detailed
discussion
of
the
analysis
which
supports
our
definition
of
the
Northeast/
Mid­
Atlantic
areas
where
the
marker
requirement
is
waived.
See
section
VI
of
today's
preamble
and
chapter
VII
of
the
RIA
for
a
discussion
of
the
costs
of
the
heating
oil
marker
requirements
finalized
by
today's
rule.

243
distribution
systems
that
are
expected
to
continue
to
ship
heating
oil
after
the
implementation
of
today's
rule,
evaluated
the
locations
of
terminals
that
are
likely
to
receive
bulk
shipments
of
heating
oil,
evaluated
the
distribution
area
of
small
refiner(
s)
for
high
sulfur
NRLM
diesel
fuel,
and
reviewed
heating
oil
use
levels
in
areas
that
will
have
access
to
bulk
shipments
of
heating
oil.
Based
on
our
assessment
we
concluded
that
defining
the
Northeast/
Mid­
Atlantic
area
as
described
below
would
best
achieve
our
goals.
119
In
most
cases,
whole
states
in
PADD
1
were
assigned
to
this
"
Northeast/
Mid­
Atlantic"
area.
This
decision
was
primarily
based
on
the
continued
high
level
of
heating
oil
use
projected
in
these
states
and
the
lack
of
significant
concern
regarding
the
elimination
of
the
program's
flexibilities
to
produce
high
sulfur
NRLM
diesel
fuel
in
these
states.
A
few
counties
in
Eastern
West
Virginia
were
also
assigned
to
the
Northeast/
Mid­
Atlantic
area
based
on
supply
patterns
in
the
area.
On
the
other
hand,
a
number
of
counties
in
Western
New
York
and
Pennsylvania
were
not
assigned
to
the
Northeast/
Mid­
Atlantic
area
due
to
the
need
to
maintain
flexibilities
for
refiners
serving
this
area.

In
summary,
the
areas
excluded
from
the
marker
requirement
and
where
the
sale
of
NRLM
diesel
fuel
produced
or
imported
under
the
credit
and
hardship
provisions
or
from
the
downstream
downgrade
provisions
of
today's
rule
is
prohibited
are:
North
Carolina,
Virginia,
Maryland,
Delaware,
New
Jersey,
Connecticut,
Rhode
Island,
Massachusetts,
Vermont,
New
Hampshire,
Maine,
Washington
D.
C.,
New
York
(
except
for
the
counties
of
Chautauqua,
Cattaraugus,
and
Allegany),
Pennsylvania
(
except
for
the
counties
of
Erie,
Warren,
Mc
Kean,
Potter,
Cameron,
Elk,
Jefferson,
Clarion,
Forest,
Venango,
Mercer,
Crawford,
Lawrence,
Beaver,
Washington,
and
Greene),
and
the
eight
eastern­
most
counties
in
West
Virginia
(
namely:
Jefferson,
Berkely,
Morgan,
Hampshire,
Mineral,
Hardy,
Grant,
and
Pendleton).
The
Northeast/
Mid­
Atlantic
Area
is
illustrated
in
the
following
figure:
244
Figure
IV.
D­
1.
 
Northeast/
Mid­
Atlantic
Area
Where
Marker
is
not
Required
245
As
discussed
in
section
IV.
D.
2
below,
the
marker
requirement
for
500
ppm
sulfur
LM
diesel
fuel
that
will
be
effective
outside
of
this
Northeast/
Mid­
Atlantic
area
and
Alaska
from
June
1,
2010,
through
May
31,
2012,
was
not
a
significant
factor
in
our
evaluation
how
to
define
the
boundary
of
the
Northeast/
Mid­
Atlantic
area.
We
expect
that
locomotive
and
marine
diesel
fuel
subject
to
the
marker
requirements
will
primarily
be
distributed
via
segregated
pathways
from
a
limited
number
of
refineries.
Therefore,
a
significant
number
of
terminals
will
not
need
to
handle
LM
diesel
fuel
that
is
subject
to
the
marker
requirement.
Thus,
the
potential
cost
of
installing
injection
equipment
to
add
the
marker
to
500
ppm
sulfur
LM
diesel
fuel
which
is
subject
to
the
marker
requirement
will
be
limited
to
only
a
few
refineries
and
terminals
(
i.
e.
approximately
15,
see
section
VI.
A
of
today's
preamble).

In
all
areas
of
the
country
other
than
the
Northeast/
Mid­
Atlantic
area
shown
in
figure
IV.
D­
1
(
and
Alaska
as
discussed
below),
heating
oil,
and
high
sulfur
NRLM
diesel
fuel
will
be
designated
at
the
refinery
or
importer
and
tracked
through
the
distribution
system
to
the
terminal.
From
June
1,
2010,
through
May
31,
2012,
500
ppm
sulfur
LM
diesel
fuel
and
500
ppm
nonroad
diesel
fuel
must
also
be
designated
at
the
refinery
or
importer
and
tracked
through
the
distribution
system
to
the
terminal
outside
of
the
Northeast/
Mid­
Atlantic
area
and
Alaska.
The
specified
fuel
marker
(
see
section
V.
E
of
this
preamble)
must
be
added
to
heating
oil
distributed
from
all
terminals
located
outside
of
the
Northeast/
Mid­
Atlantic
area
defined
above
and
Alaska.
The
same
fuel
marker
must
also
be
added
to
500
ppm
sulfur
LM
diesel
fuel
produced
at
a
refinery
or
imported
that
is
distributed
from
terminals
located
outside
of
the
Northeast/
Mid­
Atlantic
area
and
Alaska
from
June
1,
2010,
through
May
31,
2012.
This
includes
all
heating
oil
and
the
subject
500
ppm
sulfur
LM
diesel
fuel
distributed
from
terminals
outside
of
the
Northeast/
Mid­
Atlantic
area
regardless
of
whether
the
fuel
is
delivered
to
a
retailer,
wholesale
purchaser­
consumer,
or
end­
user
located
inside
or
outside
of
the
Northeast/
Mid­
Atlantic
area.

Terminals
inside
the
Northeast/
Mid­
Atlantic
area
are
exempted
from
the
fuel
marker
requirements
in
today's
rule,
but
only
for
the
volume
of
heating
oil
and
500
ppm
sulfur
LM
diesel
fuel
subject
to
the
marker
requirements
that
is
used
by
wholesale­
purchaser­
consumers
and
endusers
that
are
located
inside
the
Northeast/
Mid­
Atlantic
area.
Any
heating
oil
and
subject
500
ppm
sulfur
LM
diesel
fuel
distributed
from
terminals
inside
the
Northeast/
Mid­
Atlantic
area
to
a
retailer,
wholesale­
purchaser­
consumer,
or
end­
user
that
is
located
outside
of
the
Northeast/
Mid­
Atlantic
area
must
be
marked.

Terminal
operators
do
not
often
distribute
fuel
to
retailers,
wholesale­
purchaserconsumers
and
end­
users
directly.
This
task
is
frequently
accomplished
by
"
jobbers"
who
pick
up
large
tank
truck
loads
of
fuel
from
the
terminal
for
delivery
to
their
retailer
and
wholesalepurchaser
consumer
customers,
"
heating
oil
dealers"
who
pick
up
fuel
from
a
terminal
using
a
smaller
capacity
tank
truck
(
often
referred
to
as
a
tank
wagon)
for
direct
delivery
to
heating
oil
users,
and
by
bulk
plant
operators.
Bulk
plant
operators
pick
up
fuel
from
terminals
as
described
above.
However,
since
they
maintain
their
own
bulk
fuel
storage
facilities,
they
have
the
choice
of
storing
the
fuel
at
their
facility
prior
to
eventual
delivery
to
their
customers.
Under
the
provisions
of
today's
rule,
as
long
as
a
bulk
plant
only
receives
heating
oil
to
which
the
marker
has
already
246
been
added,
it
does
not
have
to
register,
keep
records,
or
report.
However,
if
it
chooses
to
receive
any
unmarked
heating
oil,
then
it
will
be
treated
the
same
as
a
large
terminal
under
the
provisions
of
today's
final
rule.
We
do
not
expect
that
bulk
plants
will
handle
LM
diesel
fuel
to
a
significant
degree.
For
bulk
plant
operators
that
might
handle
LM
diesel
fuel,
today's
rule
provides
that
as
long
as
a
bulk
plant
does
not
receive
any
500
ppm
sulfur
LM
diesel
fuel
which
is
required
to
be
marked
under
today's
rule,
but
which
has
not
yet
been
marked,
it
does
not
have
to
register,
keep
records,
or
report.
However,
if
it
chooses
to
receive
any
unmarked
500
ppm
sulfur
LM
diesel
fuel
which
is
subject
to
the
marker
requirements
under
today's
rule,
then
it
will
be
treated
the
same
as
a
large
terminal
under
the
provisions
of
today's
final
rule.

Any
party
that
transports
bulk
quantities
of
heating
oil
solely
to
the
Northeast/
Mid­
Atlantic
area
or
within
this
area
is
not
subject
to
the
designate
and
track
requirements
for
heating
oil
described
below.
Similarly,
any
party
that
transports
bulk
quantities
of
500
ppm
sulfur
LM
diesel
fuel
solely
to
the
Northeast/
Mid­
Atlantic
area
or
within
this
area
is
not
subject
to
the
designate
and
track
requirements
for
LM
diesel
fuel.
However,
any
high
sulfur
fuel
distributed
from
inside
the
Northeast/
Mid­
Atlantic
area
to
outside
of
the
Northeast/
Mid­
Atlantic
area
must
be
designated
as
heating
oil
by
the
party
responsible
for
the
transfer
and
must
be
marked.
Likewise,
any
500
ppm
sulfur
LM
diesel
fuel
distributed
from
inside
the
Northeast/
Mid­
Atlantic
area
from
June
1,
2010,
through
May
31,
2012
must
be
designated
as
500
ppm
sulfur
LM
diesel
fuel
by
the
party
responsible
for
the
transfer
and
must
be
marked.

Entities
who
are
required
to
inject
marker
into
heating
oil
must
maintain
records
of
the
volume
of
marker
used
in
heating
oil,
and
the
volume
of
heating
oil
distributed
over
the
compliance
period.
Entities
that
are
required
to
inject
marker
into
500
ppm
sulfur
LM
diesel
fuel
must
maintain
records
of
the
volume
of
marker
used
in
500
ppm
sulfur
LM
diesel
fuel,
and
the
volume
of
500
ppm
sulfur
LM
diesel
that
is
required
to
be
marked
which
is
distributed
over
the
compliance
period.
These
records
must
demonstrate
that
the
prescribed
marker
concentration
was
present
in
the
heating
oil
and
the
500
ppm
sulfur
LM
diesel
fuel
subject
to
the
marker
requirement
that
they
discharged.

iii.
State
of
Alaska
Although
the
fuel
marker
facilitates
the
enforcement
of
the
NRLM
diesel
fuel
sulfur
standards
by
distinguishing
it
from
heating
oil,
as
described
above,
we
are
not
requiring
use
in
Alaska.
Unlike
the
situation
in
the
Northeast
and
Mid­
Atlantic
area,
however,
we
are
not
prohibiting
the
production
of
high
sulfur
NRLM
diesel
fuel
after
2007,
and
500
ppm
nonroad
diesel
fuel
from
after
2010
by
small
refiners
in
Alaska.
While
such
a
prohibition
in
the
Northeast/
Mid­
Atlantic
area
does
not
impact
small
refiners,
flexibility
for
small
refiners
is
expected
to
be
important
in
Alaska.
Thus,
we
need
to
preserve
the
flexibility
for
high
sulfur
NRLM
diesel
fuel
in
Alaska
for
small
refiners
along
with
eliminating
the
marker.
The
program
must
therefore
provide
another
means
of
enforcing
the
NRLM
diesel
fuel
sulfur
standards
without
eliminating
a
small
refiner's
ability
to
produce
and
distribute
high
sulfur
NRLM
diesel
fuel.
247
Under
today's
program
we
are
finalizing
a
provision
that
will
allow
flexibility
for
small
refiners
to
delay
compliance
with
the
NRLM
diesel
fuel
sulfur
standards
as
discussed
in
section
IV.
B.
Small
refiners
in
Alaska
may
avail
themselves
of
this
option
provided
that
the
refiner
first
obtains
approval
from
the
administrator
for
a
compliance
plan.
The
plan
must
at
a
minimum
show
the
following
information:
1)
How
they
will
segregate
its
fuel
through
to
end­
users;
2)
How
they
will
segregate
its
fuels
from
other
grades
and
other
refiners'
fuels;
and
3)
All
end­
users
to
whom
the
fuel
is
sold
as
well
as
the
fuel
volumes.

End­
users
who
receive
the
fuel
must
retain
records
of
all
fuel
shipments
to
demonstrate
that
no
heating
oil
was
used
in
NRLM
diesel
equipment
and
that
no
500
ppm
sulfur
LM
diesel
was
used
in
nonroad
equipment.
In
order
to
limit
the
potential
sources
of
fuel
not
meeting
the
sulfur
standard,
constrain
the
number
of
end­
users
who
may
legitimately
have
higher
sulfur
fuel
in
their
NRLM
diesel
equipment,
and
thus
maintain
the
overall
program's
enforceability,
we
are
not
finalizing
the
other
provisions
that
allow
for
higher
sulfur
fuel
to
be
produced
and/
or
distributed
in
Alaska
(
i.
e.,
credit,
transmix
processor,
or
downstream
distribution
system
provisions).
In
this
regard,
Alaska
is
treated
in
the
same
manner
as
the
Northeast/
Mid­
Atlantic
area.

c.
Updating
the
Highway
Program's
Anti­
Downgrade
Requirements
Under
the
highway
diesel
fuel
program,
each
entity
in
the
distribution
system
may
downgrade
a
maximum
of
20
percent
of
the
15
ppm
sulfur
highway
diesel
fuel
it
receives
to
500
ppm
sulfur
highway
diesel
fuel.
However,
there
was
no
limit
on
the
volume
of
15
ppm
sulfur
highway
diesel
fuel
that
could
be
downgraded
to
NRLM
diesel
fuel.
Prior
to
today's
rule,
this
was
appropriate
because
the
sulfur
content
of
NRLM
diesel
fuel
was
uncontrolled,
and
hence
once
15
ppm
sulfur
highway
diesel
fuel
was
downgraded
to
NRLM
diesel
fuel
such
fuel
could
not
be
used
in
the
500
ppm
sulfur
highway
diesel
market.
The
implementation
of
today's
500
ppm
sulfur
standard
for
NRLM
diesel
fuel,
however,
means
that
15
ppm
sulfur
highway
fuel
downgraded
to
500
ppm
sulfur
NRLM
diesel
fuel
potentially
could
be
shifted
into
the
highway
market.
This
could
undermine
the
benefits
of
the
highway
program
for
the
reasons
described
previously.
To
prevent
this
situation,
we
proposed
that
the
anti­
downgrading
requirements
under
the
highway
diesel
program
would
also
apply
to
the
downgrading
15
ppm
sulfur
highway
diesel
fuel
to
500
ppm
sulfur
NRLM
diesel
fuel.
We
received
comments
from
refiners
and
fuel
distributors
that
such
a
limitation
would
restrict
their
ability
to
supply
the
NRLM
diesel
market,
particularly
in
areas
where
refiners
plan
to
supply
only
15
ppm
sulfur
diesel
fuel
for
both
the
highway
and
NRLM
markets.

Putting
in
place
the
designate
and
track
provisions
allows
500
ppm
sulfur
highway
and
500
ppm
sulfur
NRLM
diesel
fuel
to
be
tracked
separately.
This
enables
the
anti­
downgrading
requirements
to
only
apply
to
the
downgrading
of
15
ppm
sulfur
highway
diesel
fuel
to
500
ppm
sulfur
highway
fuel
as
originally
required
in
the
2007
highway
final
rule.
In
the
context
of
the
designate
and
track
requirements
in
today's
rule,
the
highway
program's
anti­
downgrading
provisions
are
clarified
as
described
below.
Similar
to
the
approach
described
above
regarding
the
prevention
of
the
use
of
500
ppm
sulfur
NRLM
diesel
fuel
in
the
highway
market,
each
custodian
248
of
15
ppm
sulfur
No.
2
highway
diesel
fuel
must
maintain
records
that
demonstrate
their
compliance
with
the
highway
program's
anti­
downgrade
requirements.
The
anti­
downgrading
requirements
do
not
apply
to
15
ppm
sulfur
No
1,
diesel
fuel.
Such
fuel
will
be
manufactured
for
wintertime
blending
to
improve
diesel
cold
flow
properties.
In
a
number
of
areas
we
expect
that
15
ppm
sulfur
No.
1
fuel
will
be
the
only
No.
1
fuel
available
for
winterizing
highway
and
NRLM
diesel
fuel,
and
heating
oil.
Therefore,
applying
the
anti­
downgrading
requirements
to
15
ppm
sulfur
No.
1
fuel
would
be
unnecessary
to
maintain
the
availability
of
15
ppm
sulfur
highway
diesel
fuel,
and
would
interfere
with
its
intended
use
in
the
range
of
No.
2
fuels.

From
October
1,
2006,
through
May
31,
2010,
all
fuel
distributors
downstream
of
the
refiner
or
import
facility
must
satisfy
one
of
four
criteria
as
outlined
in
40
CFR
80.598
of
today's
regulation
to
demonstrate
compliance
with
the
highway
program's
anti­
downgrading
requirements.
These
criteria
are
based
on
the
designate
and
track
system
for
different
grades
of
fuel
through
the
distribution
system.
The
first
criteria
is
the
simplest
and
most
straightforward,
with
the
least
record
keeping
burden.
It
merely
tracks
a
facility's
No.
2
15
ppm
sulfur
highway
diesel
volume
receipts
and
deliveries
and
requires
the
deliveries
to
be
at
least
80
percent
of
the
receipts.
Since
the
anti­
downgrading
provisions
were
implemented
to
protect
against
intentional
downgrading
and
not
to
limit
downgrading
that
would
occur
in
the
normal
distribution
of
15
ppm
sulfur
fuel,
we
anticipate
that
most
facilities
will
be
able
to
easily
meet
this
simple
criteria.

The
second
criteria
tracks
a
facility's
receipts
and
distribution
of
both
No.
2
15
ppm
sulfur
fuel
and
No.
2
500
ppm
sulfur
highway
diesel
fuel,
and
limits
deliveries
of
No.
2
500
ppm
sulfur
highway
diesel
fuel
to
no
more
than
what
was
received
plus
20
percent
of
the
No.
2
15
ppm
sulfur
highway
diesel
fuel
volume
received.
This
allows
more
flexibility
than
the
first
criteria
by
not
constraining
downgrades
to
NRLM
diesel
fuel
or
heating
oil,
but
does
so
by
requiring
tracking
and
records
of
volumes
of
No.
2
15
ppm
sulfur
highway
diesel
fuel
received
and
the
products
to
which
it
is
downgraded.

The
third
and
fourth
criteria
provide
even
more
flexibility,
especially
for
wintertime
blending
of
No.
1
15
ppm
sulfur
highway
diesel
fuel,
and
also
for
any
temporary
shifts
that
might
occur
between
NRLM
diesel
fuel
and
highway
diesel
fuel
markets
from
2007­
2010.
However,
a
facility
will
have
to
meet
more
extensive
criteria
to
demonstrate
compliance.

Today's
final
rule
does
not
change
any
other
aspects
of
the
anti­
downgrading
provisions
finalized
in
the
2007
highway
diesel
final
rule,
such
as
the
provisions
unique
to
fuel
retailers.

2.
Requirements
During
the
Second
Step
of
Today's
Sulfur
Control
Program
Beginning
June
1,
2010,
all
NR
diesel
fuel
and
beginning
June
1,
2012
all
LM
diesel
fuel
produced
or
imported
must
meet
a
15
ppm
sulfur
standard
except
for
fuel
manufactured
under
the
credit
and
small
refiner
provisions
in
today's
rule.
This
credit
and
small
refiner
diesel
fuel
must
meet
a
500
ppm
sulfur
level.
From
June
1,
2010
to
June
1,
2012,
all
LM
diesel
fuel
must
meet
a
500
ppm
sulfur
standard.
Today's
rule
also
allows
500
ppm
sulfur
diesel
fuel
generated
in
the
120
The
use
of
500
ppm
fuel
in
nonroad
equipment
is
restricted
to
2011
model
year
and
earlier
equipment.

121
Unless,
in
the
case
of
Alaska,
the
refiner
segregates
its
fuel
through
to
the
end
user
as
discussed
in
section
IV.
D.
1.
b.
ii.

249
pipeline
distribution
system
to
be
used
in
NRLM
equipment
through
May
31,
2014120
and
in
locomotive
and
marine
equipment
thereafter.
After
May
31,
2014,
the
credit
and
small
refiner
provisions
expire.

We
proposed
that
once
refiners
were
no
longer
able
to
produce
500
ppm
sulfur
diesel
fuel
for
use
in
nonroad
engines
and
such
fuel
had
a
few
months
to
work
its
way
through
the
distribution
system,
that
500
ppm
sulfur
diesel
fuel
could
no
longer
be
used
in
nonroad
equipment.
Today's
rule
adopts
this
proposed
prohibition.
Although
today's
rule
extends
the
15
ppm
sulfur
nonroad
diesel
standard
to
locomotive
and
marine
diesel
fuel,
we
have
elected
not
to
extend
the
prohibition
against
the
use
of
500
ppm
sulfur
diesel
fuel
in
locomotive
and
marine
equipment
after
refiners
and
importers
are
no
longer
allowed
to
produce/
import
such
fuel.
Diesel
fuel
with
a
maximum
sulfur
concentration
of
500
ppm
that
is
generated
in
the
pipeline
distribution
system
can
continue
to
be
used
in
locomotive
and
marine
equipment
after
June
1,
2014,
as
discussed
in
section
IV.
A
above.

Providing
for
the
continued
use
of
500
ppm
sulfur
diesel
fuel
in
NRLM
equipment
through
May
31,
2014,
means
that
without
adequate
controls
similar
to
those
under
the
first
step
of
today's
program,
a
refiner
could
manufacture
500
ppm
sulfur
diesel
fuel
ostensibly
for
use
as
heating
oil
which
could
actually
be
sold
downstream
into
the
NRLM
market
through
May
31,
2014.
Similarly,
the
continued
use
of
500
ppm
fuel
in
locomotive
and
marine
engines
after
May
31,
2014,
means
that
without
adequate
controls,
a
refiner
could
continue
to
manufacture
500
ppm
sulfur
diesel
fuel
ostensibly
for
use
as
heating
oil
which
could
actually
be
sold
downstream
into
the
locomotive
and
marine
market
indefinitely.
To
prevent
this
possibility,
we
have
elected
to
continue
the
designate
and
track
and
marker
requirements
for
heating
oil
applicable
under
the
first
step
of
today's
program
indefinitely
with
some
simplifications.
It
is
a
significantly
smaller
program
during
the
second
step,
since
only
heating
oil
needs
to
be
tracked,
and
we
expect
that
by
then
very
little
heating
oil
will
be
produced
for
sale
outside
of
the
Northeast/
Mid­
Atlantic
area.
Consistent
with
the
approach
taken
during
the
first
step
of
today's
program,
these
designate
and
track
provisions
would
not
be
applicable
in
the
Northeast/
Mid­
Atlantic
area
or
Alaska,
since
the
flexibility
to
sell
greater
than
15
ppm
sulfur
diesel
fuel
into
the
NRLM
market
there
does
not
exist
under
this
final
rule.
121
Any
diesel
fuel
with
a
sulfur
content
greater
than
500
ppm
beginning
June
1,
2007,
any
NR
diesel
fuel
with
greater
than
15
ppm
sulfur
beginning
June
1,
2010,
and
any
LM
diesel
fuel
with
greater
than
15
ppm
sulfur
beginning
June
1,
2012
in
the
Northeast/
Mid­
Atlantic
area
can
only
be
sold
as
heating
oil,
and
if
shipped
outside
of
the
Northeast/
Mid­
Atlantic
area
must
be
marked
as
heating
oil.

While
today's
rule
does
not
contain
an
end
date
for
the
downstream
distribution
of
500
ppm
sulfur
locomotive
and
marine
fuel,
we
will
review
the
appropriateness
of
allowing
this
250
flexibility
based
on
experience
gained
from
implementation
of
the
15
ppm
sulfur
NRLM
diesel
fuel
standard.
We
expect
to
conduct
such
an
evaluation
in
2011.
Were
we
to
discontinue
the
downstream
provision
for
downgraded
fuel,
we
would
also
evaluate
discontinuing
the
designate
and
track
and
marker
requirements
for
heating
oil,
as
is
the
case
now
for
the
Northeast/
Mid­
Atlantic
area.

Providing
for
the
continued
production
and
import
of
500
ppm
sulfur
LM
diesel
fuel
from
June
1,
2010
to
June
1,
2012
means
that
without
adequate
controls
similar
to
those
under
the
first
step
of
today's
program,
a
refiner
could
manufacture
500
ppm
sulfur
diesel
fuel
ostensibly
for
use
as
LM
diesel
fuel
which
could
actually
be
sold
downstream
into
the
NR
market.
To
prevent
this
possibility,
we
have
adopted
designate
and
track
and
marker
requirements
similar
to
those
applicable
to
heating
oil
under
the
first
step
of
today's
program.
For
these
two
years,
500
ppm
sulfur
NR
and
LM
diesel
fuel
would
be
tracked,
and
the
500
ppm
sulfur
LM
fuel
would
be
marked
in
the
same
manner
as
heating
oil.
The
same
provisions
that
apply
to
marking
of
heating
oil,
such
as
the
Northeast/
Mid­
Atlantic
area,
would
also
apply
to
the
marking
of
500
ppm
sulfur
LM
fuel.
The
tracking
and
marking
provisions
would
not
apply
to
any
15
ppm
sulfur
LM
diesel
fuel.

3.
Summary
of
the
Designate
and
Track
Requirements
The
designate
and
track
program
requires
refiners
and
importers
to
designate
the
volumes
of
diesel
fuel
they
produce
and/
or
import.
Refiners/
importers
will
identify
whether
their
diesel
fuel
is
highway
or
NRLM
and
the
applicable
sulfur
level.
They
may
then
mix
and
fungibly
ship
highway
and
NRLM
diesel
fuels
that
meet
the
same
sulfur
specification
without
dyeing
their
NRLM
diesel
fuel
at
the
refinery
gate.
The
volume
designations
will
follow
the
fuel
through
the
distribution
system
with
limits
placed
on
the
ability
of
downstream
parties
to
change
the
designation.
These
limits
are
designed
to
restrict
the
inappropriate
sale
of
500
ppm
sulfur
NRLM
diesel
fuel
into
the
highway
market;
from
2007
to
2010,
the
inappropriate
sale
of
500
ppm
sulfur
LM
diesel
fuel
into
the
500
ppm
sulfur
NR
market
from
2010
to
2012;
and
the
inappropriate
sale
of
heating
oil
into
the
NRLM
market.
The
designate
and
track
approach
includes
record
keeping
and
reporting
requirements
for
all
parties
in
the
fuel
distribution
system,
associated
with
tracking
designated
fuel
volumes
through
each
custodian
in
the
distribution
chain
until
the
fuel
exits
the
terminal.
The
program
also
includes
enforcement
and
compliance
assurance
provisions
to
enable
the
Agency
to
rapidly
and
accurately
review
for
discrepancies
the
large
volume
of
data
collected
on
fuel
volume
hand­
offs.

a.
Registration
Each
entity
in
the
fuel
distribution
system,
up
through
and
including
the
point
where
fuel
is
loaded
onto
trucks
for
distribution
to
retailers
or
wholesale
purchaser­
consumers,
must
register
each
of
its
facilities
with
EPA
no
later
than
December
31,
2005,
or
six
months
prior
to
122
This
requirement
also
applies
to
parties
inside
of
the
Northeast/
Mid­
Atlantic
area
who
handle
heating
oil.

123
Transmix
operators
that
produce
diesel
fuel
from
transmix
and
terminal
operators
that
produce
from
segregated
interface
will
be
treated
as
a
refiner
for
the
purposes
of
compliance
with
these
requirements.

251
commencement
of
producing,
importing,
generating,
or
distributing
any
designated
diesel
fuel.
122
A
facility
is
defined
as
the
physical
location(
s)
where
a
party
has
custody
of
designated
fuel,
from
when
it
was
produced,
imported,
or
received
from
one
party
to
when
it
is
delivered
to
another
party.
The
definition
also
include
mobile
components,
such
as
the
vessels
in
a
barge
facility.
Examples
of
facilities
include
refineries,
import
terminals,
pipelines,
terminals,
bulk
plants,
and
barge
systems.
Where
the
same
entity
owns
and
operates
a
series
of
locations
in
the
distribution
system
(
e.
g.,
refiner
to
pipeline
to
terminal),
it
may
choose
to
register
them
as
a
single
aggregated
facility,
provided
the
entity
maintains
custody
of
the
fuel
throughout
the
facility.
However,
if
the
aggregated
facility
includes
a
refinery,
then
it
may
not
receive
any
diesel
fuel
from
another
entity
at
any
place
within
the
aggregated
facility.
Under
this
approach,
a
pipeline
could
be
treated
as
one
facility
from
the
point
where
it
receives
fuel
to
the
point
where
it
either
delivers
it
to
a
terminal,
or
into
a
tank
truck
after
passing
through
their
terminal.
The
choice
made
by
the
entity
to
treat
these
places
as
a
single
facility
or
separate
facilities
may
not
change
during
any
applicable
compliance
period.
These
same
definitions
for
facility
will
apply
for
both
the
designate
and
track
provisions,
as
well
as
the
anti­
downgrading
provisions
of
the
highway
rule.
Therefore,
if
a
proprietary
system
chooses
to
aggregate
into
one
facility
for
purposes
of
the
designate
and
track
provisions,
it
will
also
be
treated
as
one
facility
for
determining
compliance
with
the
20
percent
anti­
downgrading
limit
of
the
highway
rule.
EPA
will
provide
a
unique
registration
number
to
each
custodial
facility
of
designated
fuels.
In
addition,
EPA
intends
to
work
with
industry
subsequent
to
this
final
rule
to
provide
guidance
regarding
facility
boundary
and
aggregation
decisions
that
will
address
the
many
unique
situations.

The
designation
provisions
described
below
require
refiners
and
importers
to
designate
all
distillates
they
produce
or
import
consistent
with
the
production
and
end­
use
requirements
in
today's
rule.
These
designations
serve
as
the
foundation
upon
which
the
fuel
distributors
are
able
to
properly
track,
designate,
redesignate,
and
label
the
fuel
they
receive.

b.
Designation
by
Refiners
and
Importers
i.
Designation
of
500
ppm
and
15
ppm
Sulfur
Diesel
Fuel
From
June
1,
2006,
through
May
31,
2010,
any
refiner123
or
importer
that
produces
or
imports
15
ppm
sulfur
diesel
fuel,
and/
or
500
ppm
sulfur
diesel
fuel
must
designate
all
batches
of
such
fuel
as
one
of
the
following.
The
purpose
of
this
designation
requirement
is
to
ensure
that
252
500
ppm
sulfur
NRLM
diesel
fuel
is
not
shifted
into
the
highway
market,
and
to
evaluate
compliance
with
the
highway
program's
anti­
downgrade
requirements.

°
15
ppm
sulfur
No.
2
highway
diesel
fuel;
°
15
ppm
sulfur
No.
1
highway
diesel
fuel;
°
500
ppm
sulfur
No.
2
highway
diesel
fuel;
°
500
ppm
sulfur
No.
1
highway
diesel
fuel;
°
500
ppm
sulfur
No.
2
NRLM
diesel
fuel;
°
500
ppm
sulfur
No.
1
NRLM
diesel
fuel;
°
500
ppm
sulfur
jet
fuel;
or
°
500
ppm
sulfur
kerosene.

The
start
date
for
these
requirements
coincides
with
the
start
date
for
the
early
credit
program
under
today's
final
rule,
and
the
start
date
for
the
highway
diesel
program
for
the
purposes
of
anti­
downgrading.
The
end
date
for
these
requirements
coincides
with
the
end
date
for
the
highway
program's
Temporary
Compliance
Option
and
today's
NRLM
diesel
fuel
early
credit
program.

Any
batch
of
15
ppm
or
500
ppm
No.
1
diesel
fuel
which
is
also
suitable
for
use
as
kerosene
or
jet
fuel
(
referred
to
as
dual­
purpose
kerosene)
may
be
considered
kerosene
or
jet
fuel
and
need
not
be
designated
as
highway
or
NRLM
diesel
fuel,
even
if
it
may
later
be
blended
into
highway
or
NRLM
diesel
fuel
downstream
of
the
refinery
to
improve
the
cold­
flow
properties
of
the
fuel.
Upon
such
blending,
the
kerosene
or
jet
fuel
takes
on
the
designation
of
the
diesel
fuel
into
which
it
was
blended.
We
expect
refiners
and
importers
will
elect
to
designate
all
of
their
15
ppm
sulfur
No.
1
diesel
fuel
as
highway
fuel,
since
this
will
aid
in
their
compliance
with
the
highway
program's
80/
20
highway
fuel
production
requirement.
Designation
as
highway
diesel
fuel
by
the
refiner
will
also
help
avoid
downstream
blending
from
causing
a
violation
by
the
downstream
party
under
the
tracking
and
compliance
calculations
finalized
today.
We
also
expect
that
refiners
and
importers
will
elect
to
designate
their
500
ppm
sulfur
No.
1
fuel
as
kerosene
or
jet
fuel
since
this
will
be
the
predominant
use
for
such
fuel,
and
designating
it
as
highway
would
hinder
their
compliance
with
the
80/
20
highway
requirements.
As
with
15
ppm
sulfur
kerosene
or
jet
fuel,
downstream
parties
would
later
redesignate
it
as
highway
or
NRLM
diesel
fuel
if
blended
in
or
used
for
these
purposes.
Any
500
ppm
sulfur
diesel
fuel
containing
visible
evidence
of
red
dye
must
be
designated
as
NRLM
diesel
fuel
or
heating
oil
unless
it
is
tax
exempt
highway
diesel
fuel
(
e.
g.,
fuel
for
use
in
school
buses
or
certain
municipal
fleets).

The
reported
volumes
of
designated
fuels
must
be
the
volumes
delivered
to
the
first
downstream
party.
This
is
typically
a
pipeline
facility,
a
marine
barge/
tanker
loading
dock
that
accepts
product
from
a
refiner/
importer,
or
the
refiner's/
importer's
truck
loading
rack.
This
is
consistent
with
normal
business
practices.
Refiners,
importers,
and
transmix
processors
are
not
required
to
add
red
dye
to
NRLM
diesel
fuel
unless
the
fuel
is
distributed
over
their
truck
loading
rack
such
that
the
IRS
requires
the
addition
of
red
dye
for
the
assessment
of
taxes.
253
Fuel
designated
by
a
refiner
or
importer
as
highway
diesel
fuel
must
comply
with
the
highway
program's
80/
20
requirement
for
15
ppm/
500
ppm
sulfur
highway
diesel
fuel.
The
volume
of
fuel
designated
as
NRLM
early
credit
fuel
must
be
consistent
with
the
credit
provisions
in
today's
rule.
Since
highway
diesel
fuel
volumes
are
determined
at
the
point
of
delivery
from
the
refiner/
importer
to
another
party,
the
anti­
downgrade
requirements
do
not
apply
to
refiners
and
importers.
Under
the
highway
diesel
fuel
program,
refiners
that
are
required
to
produce
100
percent
of
their
highway
diesel
fuel
to
a
15
ppm
sulfur
standard
are
provided
with
an
allowance
to
deliver
a
small
percentage
of
500
ppm
sulfur
diesel
fuel
to
the
pipeline
(
e.
g.,
small
refiners
and
GPA
refiners
who
exercise
an
option
under
the
2007
highway
rule
to
delay
compliance
with
gasoline
sulfur
standards).
This
allowance
is
provided
because
a
small
volume
of
"
line­
wash"
is
typically
generated
in
the
feed
line
from
the
refiner's
facility
to
the
pipeline.
This
line­
wash
will
often
be
suitable
for
use
as
500
ppm
sulfur
highway
diesel
fuel.
Under
the
provisions
of
the
highway
rule
this
line­
wash
could
have
been
excluded
from
compliance
with
the
15
ppm
standard
if
the
refiner
accounted
for
their
production
volume
prior
to
shipment.
However,
in
this
rule,
all
volume­
related
requirements
are
keyed
to
the
volume
actually
delivered.
As
a
result
of
this
change
in
the
point
of
fuel
volume
measurement
(
delivered
versus
produced),
we
are
amending
the
highway
diesel
fuel
program
requirements
such
that
refiner
who
was
previously
required
to
produce
100
percent
of
its
highway
diesel
fuel
to
the
15
ppm
sulfur
standard
may
now
produce
95
percent
to
the
15
ppm
sulfur
standard
(
in
order
to
avail
itself
of
the
extended
gasoline
sulfur
interim
standards).

ii.
Designation
of
High
Sulfur
NRLM
Diesel
Fuel,
Heating
Oil,
and
Jet
Fuel/
Kerosene
From
June
1,
2007
through
May
31,
2010,
any
refiner,
or
importer
not
located
in
the
Northeast/
Mid­
Atlantic
area
or
Alaska,
that
produces
or
imports
unmarked
high
sulfur
distillate
fuel
must
designate
all
batches
of
such
fuel
as
one
of
the
following:
heating
oil,
high
sulfur
NRLM
diesel
fuel,
or
jet
fuel/
kerosene.
Any
heating
oil
distributed
from
a
refiner's
or
importer's
rack
not
located
in
the
Northeast/
Mid­
Atlantic
area
or
Alaska
must
contain
the
designated
marker
and
red
dye.
Any
heating
oil
distributed
from
a
refiner/
importer
rack
inside
of
the
Northeast/
Mid­
Atlantic
area
or
Alaska
is
exempted
from
the
marker
requirement
except
any
heating
oil
that
is
delivered
outside
the
Northeast/
Mid­
Atlantic
area
must
be
marked.

As
discussed
previously,
500
ppm
sulfur
diesel
fuel
may
be
used
in
NRLM
equipment
through
May
31,
2014
and
in
locomotive
and
marine
equipment
thereafter.
Therefore,
designate
and
track
provisions
for
heating
oil
will
be
needed
to
ensure
that
heating
oil
is
not
shifted
into
the
NRLM
market
from
June
1,
2007
through
May
31,
2014,
and
to
the
locomotive
and
marine
market
thereafter.
Consequently,
from
June
1,
2010
through
May
31,
2014,
refiners
and
importers
must
continue
to
designate
any
heating
oil
they
produce
as
such
as
well
as
any
500
ppm
sulfur
NRLM
diesel
fuel
produced
under
the
small
refiner,
transmix/
segregated
interface,
and
credit
provisions.
254
Beginning
June
1,
2014,
refiners
and
importers
may
no
longer
produce
or
import
500
ppm
sulfur
diesel
fuel
for
use
in
NRLM
equipment.
Therefore,
beginning
June
1,
2014,
all
diesel
fuel
with
a
sulfur
level
greater
than
15
ppm
must
be
designated
as
heating
oil,
jet
fuel,
or
kerosene.
The
one
exception
to
this
is
transmix
processors
and
terminals
acting
as
refiners
which
will
be
permitted
to
produce
500
ppm
sulfur
diesel
fuel
for
use
in
locomotive
and
marine
equipment
from
transmix
and
segregated
interface.

iii.
Designation
of
500
ppm
NR
and
500
ppm
LM
Sulfur
Diesel
Fuel
From
June
1,
2010,
through
May
31,
2012,
any
refiner
or
importer
that
produces
or
imports
500
ppm
sulfur
NR
diesel
fuel
(
small
refiner
and
credit)
and/
or
500
ppm
sulfur
LM
diesel
fuel
must
designate
all
batches
of
such
fuel.
The
purpose
of
this
designation
requirement
is
to
ensure
that
500
ppm
sulfur
LM
diesel
fuel
is
not
shifted
into
the
NR
market.
Any
500
ppm
sulfur
LM
diesel
fuel
distributed
from
a
refiner's
or
importer's
rack
not
located
in
the
Northeast/
Mid­
Atlantic
area
or
Alaska
must
contain
the
designated
marker
and
red
dye,
along
with
heating
oil.
Any
500
ppm
sulfur
LM
diesel
fuel
distributed
from
a
refiner/
importer
rack
inside
of
the
Northeast/
Mid­
Atlantic
area
or
Alaska
is
exempted
from
the
marker
requirement
except
any
500
ppm
sulfur
LM
fuel
that
is
delivered
outside
the
Northeast/
Mid­
Atlantic
area
must
be
marked.

c.
Designation
and
Tracking
Requirements
Downstream
of
the
Refinery
or
Importer
The
result
of
the
refiner/
importer
designation
provisions
is
that
all
of
the
diesel
fuel
received
by
distributors
will
be
clearly
and
accurately
designated.
The
distributors
are
then
subject
to
their
own
designation
and
tracking
requirements.
The
downstream
provisions
are
designed
to
ensure
that
certain
fuel
shifts
do
not
occur,
such
as
the
inappropriate
shifting
of
500
ppm
sulfur
NRLM
diesel
fuel
to
the
highway
market,
the
inappropriate
shifting
of
500
ppm
sulfur
LM
diesel
fuel
into
the
nonroad
market,
the
inappropriate
downgrading
of
15
ppm
sulfur
to
500
ppm
sulfur
highway
diesel
fuel,
and
the
inappropriate
shifting
of
heating
oil
to
the
NRLM
market.
The
downstream
provisions
are
designed
to
ensure
these
results
in
a
readily
enforceable
manner
while
maximizing
downstream
flexibility
to
address
changing
market
conditions.

In
general,
each
time
custody
of
designated
fuel
is
transferred
from
one
facility
to
another
facility,
the
transferor
must
designate
the
fuel
and
record
it's
volume.
The
party
who
receives
custody
must
record
the
same
information,
to
ensure
that
each
party
relies
on
the
same
designation
and
volume
for
its
own
compliance
purposes.
This
process
occurs
each
time
custody
of
diesel
fuel
is
transferred.
Each
distributor
may
redesignate
fuel
while
in
its
custody
or
when
it
is
delivered,
subject
to
certain
basic
requirements.
First,
any
re­
designation
must
be
accurate.
For
example,
500
ppm
sulfur
NRLM
diesel
fuel
can
not
be
redesignated
as
15
ppm
unless
it
in
fact
meets
the
15
ppm
standard.
The
sulfur
standard
applicable
to
downstream
fuel
is
based
on
the
fuel's
designation.
Second,
there
are
limits
on
the
fuel
volumes
that
can
be
redesignated,
calculated
as
a
volume
balance
over
a
specified
compliance
period.
Specifically,
the
volumes
of
15
ppm
and
500
ppm
sulfur
highway
received
must
be
compared
to
the
volumes
of
these
fuels
delivered,
to
ensure
that
the
amount
of
15
ppm
sulfur
highway
diesel
fuel
that
is
downgraded
to
500
ppm
sulfur
124
Any
party
is
free
to
redesignate
highway
diesel
fuel
to
NRLM
diesel
fuel
or
heating
oil
at
any
time.
The
required
volume
balance
does
not
limit
such
designations.

255
highway
diesel
fuel
complies
with
the
highway
program's
anti­
downgrading
requirements.
The
volumes
of
500
ppm
sulfur
highway
and
NRLM
diesel
fuel
that
a
distributor
receives
must
also
be
compared
to
the
volumes
of
500
ppm
sulfur
highway
and
NRLM
diesel
fuel
delivered,
to
ensure
that
NRLM
diesel
fuel
was
not
inappropriately
transferred
to
the
highway
market.
The
volumes
of
500
ppm
sulfur
NR
and
LM
diesel
fuel
received
must
be
compared
to
the
volumes
of
500
ppm
sulfur
NR
and
LM
diesel
fuel
delivered,
to
ensure
that
the
500
ppm
sulfur
LM
fuel
was
not
inappropriately
transferred
to
the
NR
market.
In
addition,
the
volumes
of
heating
oil
received
must
be
compared
to
the
volumes
distributed
to
ensure
it
was
not
inappropriately
transferred
to
the
NRLM
market.
These
volume
balances
are
calculated
over
a
compliance
period,
providing
distributor's
the
day
to
day
flexibility
to
redesignate
fuel
based
on
market
conditions,
as
long
as
the
required
volume
balance
is
achieved
over
the
compliance
period.
Finally,
once
NRLM
diesel
fuel
is
dyed,
500
ppm
sulfur
LM
diesel
fuel
is
marked
(
2010­
2012),
or
heating
oil
is
marked,
the
dye
and
marker
may
be
used
to
ensure
the
fuels
are
not
inappropriately
shifted
to
other
markets,
and
the
designation,
tracking
and
volume
balance
requirements
are
no
longer
needed;
just
the
PTD,
labeling,
and
record
keeping
provisions
typical
of
our
other
fuel
regulations
(
e.
g.,
highway
diesel)
apply.

In
large
part,
the
designate
and
track
provisions
are
structured
to
be
compatible
with
the
normal
business
practices
currently
used
by
the
industry
to
record
and
reconcile
volume
transactions
between
parties.
As
such,
EPA
expects
that
these
downstream
provisions
can
be
implemented
in
a
fairly
straightforward
manner.

i.
Designation
and
Tracking
of
500
ppm
and
15
ppm
Sulfur
Diesel
Fuel
From
June
1,
2006
through
May
31,
2010,
facilities
downstream
of
the
refiner
or
importer
must
designate
and
maintain
records
of
all
volumes
of
fuel
designated
as
15
ppm
sulfur
highway
diesel
fuel,
500
ppm
sulfur
highway
diesel
fuel,
or
500
ppm
sulfur
NRLM
diesel
fuel
that
they
receive
and
deliver.
In
many
cases,
we
expect
that
downstream
facilities
will
not
change
the
designation
of
500
ppm
sulfur
diesel
fuel
from
NRLM
diesel
fuel
to
highway
while
the
fuel
is
in
their
custody.
However,
to
accommodate
fluctuations
in
the
demand
for
highway­
designated
versus
NRLM­
designated
500
ppm
sulfur
fuel,
today's
rule
allows
terminals
and
other
distributors
to
change
the
designation
of
500
ppm
sulfur
fuel
from
NRLM
diesel
fuel
to
highway
diesel
fuel
on
a
daily
basis,
as
long
as
the
required
volume
balance
is
achieved
over
the
compliance
period.
124
Terminal
operators
must
ensure
that
the
running
balance
of
total
highway­
designated
fuel
that
they
discharged
from
the
beginning
of
today's
program
does
not
exceed
the
volume
of
highway
fuel
that
they
received
since,
and
had
in
their
possession
at
the
beginning
of
today's
program
(
adjusted
for
changes
in
inventory).
This
simple
one­
sided
test
allows
15
ppm
sulfur
highway
diesel
fuel
to
flow
to
500
ppm
sulfur
highway
diesel
fuel
(
subject
to
anti­
downgrading
limits),
500
ppm
sulfur
NRLM
diesel
fuel,
or
heating
oil.
It
also
allows
500
ppm
sulfur
highway
diesel
fuel
to
flow
to
NRLM
diesel
fuel
or
heating
oil.
However,
the
flow
of
NRLM
diesel
fuel
to
highway
diesel
fuel
256
must
first
have
been
offset
by
shifts
from
highway
to
NRLM
diesel
fuel.
In
this
way
we
can
have
assurance
that
the
500
ppm
sulfur
fuel
sold
for
highway
purposes
was
in
fact
produced
pursuant
to
the
80/
20
requirements
of
the
highway
rule.
Since
any
500
ppm
sulfur
diesel
fuel
in
the
possession
of
parties
downstream
of
the
refiner
at
the
beginning
of
today's
program
will
be
considered
as
highway
diesel
fuel,
each
custodian
will
begin
today's
program
with
a
positive
volumetric
account
balance
regarding
their
input/
output
of
highway­
designated
500
ppm
sulfur.
Conformity
with
this
requirement
will
be
evaluated
by
EPA
at
the
end
of
each
quarterly
compliance
period.

In
order
to
accommodate
volumetric
fluctuations
due
to
such
factors
as
thermal
expansion
of
the
fuel,
facilities
such
as
pipelines
upstream
of
the
terminal
can
use
the
same
volumetric
balance.
However,
since
these
facilities
typically
do
not,
and
should
not
change
designations,
the
compliance
periods
can
be
annual.
In
addition,
to
ensure
that
there
are
no
significant
redesignations,
we
are
also
requiring
that
the
volume
of
highway­
designated
500
ppm
sulfur
diesel
fuel
that
a
facility
discharges
from
its
custody
must
be
no
greater
than
102
percent
of
the
volume
of
such
fuel
that
it
received
during
each
annual
compliance
period.
All
parties
downstream
of
the
refiner,
importer,
or
transmix
processor
also
must
demonstrate
that
over
any
given
compliance
period,
they
did
not
downgrade
more
than
20
percent
of
the
15
ppm
highway
diesel
fuel
that
they
received
to
500
ppm
sulfur
highway
diesel
fuel.

From
June
1,
2006
through
May
31,
2010,
distributors
must
maintain
records
regarding
each
transfer
of
a
designated
fuel
into
and
out
of
their
facility
on
a
batch­
by­
batch
basis.
These
records
must
include
the
EPA
registration
number
of
the
source
or
recipient
facility,
and
the
volume
of
each
designated
fuel
transfer.
However,
for
transfers
of
dyed
NRLM
and
highway
diesel
fuel
on
which
taxes
have
been
assessed,
the
recipient
or
source
facility
need
not
be
specifically
identified.
In
such
cases,
records
must
be
kept
regarding
the
total
volume
of
dyed
and
tax
assessed
fuel
that
is
received,
discharged,
and
in
inventory
during
each
compliance
period.
After
May
31,
2010,
unique
records
for
these
designate
and
track
provisions
are
no
longer
required,
but
the
normal
records
and
PTDs
must
still
be
kept
regarding
compliance
with
the
fuel
standards.

ii.
Designation
and
Tracking
of
High
Sulfur
NRLM
Diesel
Fuel
and
Heating
Oil
The
requirements
regarding
the
designation
and
tracking
of
heating
oil
and
high
sulfur
or
500
ppm
sulfur
NRLM
diesel
fuel
parallel
those
regarding
the
designation
and
tracking
of
500
ppm
sulfur
highway
and
NRLM
diesel
fuel
discussed
above.
However,
the
requirements
described
below
pertain
only
to
facilities
not
in
the
Northeast/
Mid­
Atlantic
area
or
Alaska,
and
to
facilities
inside
of
the
Northeast/
Mid­
Atlantic
area
that
transport
heating
oil
outside
of
the
Northeast/
Mid­
Atlantic
area.

From
June
1,
2007
through
May
31,
2010,
facilities
downstream
of
the
refiner
or
importer
must
designate
all
high
sulfur
diesel
fuel
they
distribute
as
NRLM
diesel
fuel
and
all
heating
oil
they
distribute
as
heating
oil,
and
must
keep
records
of
all
volumes
of
fuel
designated
as
high
sulfur
NRLM
diesel
fuel
or
heating
oil.
In
many
cases,
we
expect
that
downstream
facilities
will
not
125
As
discussed
in
section
V,
these
records
must
be
kept
for
five
years.

257
change
the
designation
of
diesel
fuel
from
heating
oil
to
high
sulfur
NRLM
diesel
fuel
while
the
fuel
is
in
their
custody.
However,
today's
final
rule
provides
the
flexibility
to
make
this
change
in
designation
provided
that
volume
balance
requirements
for
high
sulfur
NRLM
diesel
fuel
are
met.

The
volume
balance
for
heating
oil
requires
that
the
volumes
of
high
sulfur
NRLM
diesel
fuel
and
heating
oil
received
must
be
compared
to
the
volumes
of
high
sulfur
NRLM
diesel
fuel
and
heating
oil
delivered
over
a
compliance
period.
The
volume
of
high
sulfur
NRLM
diesel
fuel
may
not
increase
by
a
greater
proportion
than
the
volume
of
heating
oil
over
a
compliance
period.
There
are
many
reasons
why
the
combined
pool
of
high
sulfur
fuel
will
increase
in
volume
such
as
the
inevitable
downgrades
from
15
ppm
and
500
ppm
when
these
fuels
are
shipped
by
pipeline.
The
volume
balance
allows
for
this
to
occur
while
keeping
fuel
produced
as
heating
oil
from
being
shifted
to
NRLM
diesel
fuel.
The
volume
balance
calculation
allows
high
sulfur
NRLM
diesel
fuel
and
heating
oil
to
increase
proportionately,
satisfying
both
needs.
As
discussed
previously,
high
sulfur
NRLM
diesel
fuel
and
heating
oil
compliance
will
be
required
on
a
quarterly
basis
for
terminal
facilities
that
add
marker/
dye
(
and
are
more
likely
to
change
designations
on
a
day
to
day
basis),
while
compliance
for
other
entities
(
e.
g.,
pipelines)
will
be
on
an
annual
basis.
Compliance
with
the
volume
balance
requirement
is
determined
by
comparing
volumes
received
and
delivered
during
that
compliance
period.
There
is
no
need
to
have
a
running
total
volume
of
high
sulfur
NRLM
diesel
fuel
delivered
from
the
beginning
of
the
program
since
we
do
not
expect
any
party
will
need
to
redesignate
heating
oil
to
high
sulfur
NRLM
diesel
fuel,
even
on
a
day­
to­
day
basis.
Further,
we
are
not
providing
any
tolerance
since
sufficient
flexibility
already
exists
due
to
the
many
sources
of
downgrade
to
heating
oil.

Facilities
must
maintain
records
regarding
each
transfer
of
heating
oil
and
high
sulfur
NRLM
diesel
fuel
that
they
receive
and
discharge
from
June
1,
2007
through
May
31,
2010
on
a
batch­
by­
batch
basis125.
These
records
must
include
the
EPA
registration
number
of
the
source
or
recipient
facility,
and
the
volume
of
each
fuel
transfer.
However,
for
transfers
of
marked
heating
oil,
the
recipient
or
source
facility
need
not
be
specifically
identified.
In
such
cases,
records
must
be
kept
regarding
the
total
volume
of
marked
heating
oil
that
is
received,
discharged,
and
in
inventory
during
each
compliance
period.
For
transfers
of
dyed
high
sulfur
NRLM
diesel
fuel
from
a
truck
loading
rack,
the
specific
recipients
also
do
not
need
to
be
identified.
In
such
cases,
records
must
be
kept
regarding
the
total
volume
of
high
sulfur
NRLM
diesel
fuel
that
is
received,
discharged,
and
in
inventory
during
each
compliance
period.

From
June
1,
2010
through
May
31,
2014,
facilities
downstream
of
the
refiner
or
importer
must
continue
to
designate
heating
oil
and
any
500
ppm
sulfur
NRLM
diesel
fuel
that
they
distribute.
Beyond
June
1
2014,
they
must
designate
500
ppm
sulfur
LM
diesel
fuel
in
addition
to
heating
oil.
Designations
for
heating
oil
are
subject
to
the
volume
balance
requirements
and
records
must
be
kept
on
the
designations.
258
Beginning
June
1,
2010,
the
volume
balance
requirement
for
heating
oil
is
simply
that
the
volume
of
heating
oil
may
not
decrease.
As
discussed
previously,
there
are
many
reasons
why
the
volume
could
increase.
Consequently,
if
the
volume
decreases
it
would
mean
that
heating
oil
is
being
shifted
to
NRLM
or
locomotive
and
marine
uses,
thereby
allowing
refiners
to
circumvent
the
NRLM
diesel
fuel
sulfur
standards.
Given
the
likely
increase
in
heating
oil
volume
for
other
reasons,
there
should
be
ample
flexibility
provided
with
this
one­
sided
test
to
account
for
minor
variations
due
to
volume
swell/
shrinkage
related
to
temperature,
meter
differences,
or
other
causes,
so
no
additional
tolerance
or
flexibility
is
necessary.

iii.
Designation
and
Tracking
of
500
ppm
Sulfur
NR
and
LM
Diesel
Fuel
The
requirements
regarding
the
designation
and
tracking
of
500
ppm
sulfur
NR
and
LM
diesel
fuel
parallel
those
regarding
the
designation
and
tracking
of
500
ppm
sulfur
highway
and
NRLM
diesel
fuel
discussed
above.
However,
the
requirements
described
below
pertain
only
to
facilities
not
in
the
Northeast/
Mid­
Atlantic
area
or
Alaska,
and
to
facilities
inside
of
the
Northeast/
Mid­
Atlantic
area
that
transport
500
ppm
sulfur
NR
and
LM
diesel
fuel
outside
of
the
Northeast/
Mid­
Atlantic
area.

From
June
1,
2010
through
May
31,
2012,
facilities
downstream
of
the
refiner
or
importer
must
continue
to
designate
500
ppm
sulfur
NR
and
LM
diesel
fuel
that
they
distribute,
and
must
keep
records
of
all
volumes
of
fuel
designated
as
these
fuels.
In
many
cases,
we
expect
that
downstream
facilities
will
not
change
the
designation
of
diesel
fuel
from
500
ppm
sulfur
LM
to
500
ppm
sulfur
NR
diesel
fuel
while
the
fuel
is
in
their
custody.
However,
today's
final
rule
provides
the
flexibility
to
make
this
change
in
designation
provided
that
volume
balance
requirements
for
500
ppm
sulfur
NR
diesel
fuel
are
met.

The
volume
balance
for
500
ppm
sulfur
NR
and
LM
diesel
fuel
requires
that
the
volumes
of
500
ppm
sulfur
NR
and
LM
diesel
fuel
received
must
be
compared
to
the
volumes
of
500
ppm
sulfur
NR
and
LM
diesel
fuel
delivered
over
a
compliance
period.
The
volume
of
500
ppm
sulfur
NR
diesel
fuel
may
not
increase
by
a
greater
proportion
than
the
volume
of
500
ppm
sulfur
LM
diesel
fuel
over
a
compliance
period.
The
combined
pool
of
500
ppm
sulfur
diesel
fuel
may
increase
in
volume
such
as
the
inevitable
downgrades
from
15
ppm
and
500
ppm
sulfur
diesel
fuel
when
these
fuels
are
shipped
by
pipeline.
The
volume
balance
allows
for
this
to
occur
while
keeping
fuel
produced
as
500
ppm
sulfur
LM
diesel
fuel
from
being
shifted
to
NR
fuel.
The
volume
balance
calculation
allows
500
ppm
sulfur
NR
and
LM
diesel
fuel
to
increase
proportionately,
satisfying
both
needs.
500
ppm
sulfur
NR
and
LM
diesel
fuel
compliance
will
be
required
on
an
annual
basis,
for
terminal
facilities
as
well
as
other
entities.
Compliance
with
the
volume
balance
requirement
is
determined
by
comparing
volumes
received
and
delivered
during
that
compliance
period.

Facilities
must
maintain
records
regarding
each
transfer
of
500
ppm
sulfur
NR
and
LM
diesel
fuel
that
they
receive
and
discharge
from
June
1,
2010
through
May
31,
2012
on
a
batch­
bybatch
basis.
These
records
must
include
the
EPA
registration
number
of
the
source
or
recipient
259
facility,
and
the
volume
of
each
fuel
transfer.
However,
for
transfers
of
marked
500
ppm
sulfur
LM
diesel
fuel,
the
recipient
or
source
facility
need
not
be
specifically
identified.
In
such
cases,
records
must
be
kept
regarding
the
total
volume
of
marked
500
ppm
sulfur
LM
diesel
fuel
that
is
received,
discharged,
and
in
inventory
during
each
compliance
period.
For
transfers
of
dyed
500
ppm
sulfur
NR
diesel
fuel
from
a
truck
loading
rack,
the
specific
recipients
also
do
not
need
to
be
identified.
In
such
cases,
records
must
be
kept
regarding
the
total
volume
of
500
ppm
sulfur
NR
diesel
fuel
that
is
received,
discharged,
and
in
inventory
during
each
compliance
period.

EPA
plans
to
work
closely
with
members
of
the
diesel
fuel
refining
and
distribution
industry,
to
provide
clear
and
comprehensive
guidance
on
what
is
expected
of
the
various
parties
under
the
designate
and
track
and
volume
balance
provisions
adopted
in
this
rule.
EPA
invites
suggestions
from
these
parties
on
the
most
useful
ways
to
provide
such
guidance.

d.
Reporting
Requirements
i.
Compliance
and
Reporting
Periods
We
believe
that
any
regulatory
program
should
promote
compliance
and
deter
noncompliance
Today's
program
includes
compliance
and
reporting
provisions
to
deter
noncompliance
and
to
detect
and
correct
instances
of
noncompliance
in
a
timely
fashion.
Under
today's
program
entities
must
submit
to
the
Agency
compliance
reports
containing
information
on
the
diesel
fuel
volumes
they
handle,
separately
by
fuel
designation
category.
Compliance
with
these
volume
designation
and
tracking
requirements
will
be
determined
on
an
annual
basis
for
refiners
and
pipelines
and
a
quarterly
basis
for
terminals
during
the
first
step
of
today's
program.
Compliance
will
be
determined
on
an
annual
basis
for
everyone
after
2010.
To
demonstrate
compliance,
refiners,
pipelines,
and
terminals
will
be
required
to
submit
reports
on
a
quarterly
basis
during
the
first
step
of
today's
program
and
then
on
an
annual
basis
every
year
thereafter.

We
are
requiring
the
submission
of
volume
reports
on
a
quarterly
basis
during
the
first
step
of
today's
program
for
several
reasons.
First,
and
most
importantly,
today's
program
allows
entities
to
change
the
designations
of
500
ppm
sulfur
diesel
fuel
from
NRLM
diesel
fuel
to
highway
diesel
fuel
and
heating
oil
to
NRLM
diesel
fuel
on
a
daily
basis
(
provided
that
they
later
redesignate
the
same
volume
of
500
ppm
diesel
fuel
from
highway
diesel
fuel
to
NRLM
diesel
fuel
and
the
same
volume
of
NRLM
diesel
fuel
to
heating
oil).
Second,
quarterly
reporting
coupled
with
quarterly
compliance
by
terminals
will
constrain
the
magnitude
of
any
noncompliance.
Finally,
during
the
start
up
of
the
designate
and
track
system,
there
may
also
be
a
greater
potential
for
errors
in
the
transmission
of
records
between
custodians
of
designated
fuels,
in
the
calculations
related
to
compliance
with
the
volume
account
balance
requirements,
and
in
the
materials
provided
in
reports.

Today's
program
establishes
quarterly
compliance
periods
which
are
based
on
standard
industry
practices.
Specifically,
the
quarterly
compliance
periods
finalized
in
today's
rule
are
as
follows:
260
°
1st
quarter:
July
1
­
September
30;
°
2nd
quarter:
October
1
­
December
31;
°
3rd
quarter:
January
1
­
March
31;
°
4th
quarter:
April
1
­
June
30.

Where
the
start
and
end
dates
of
the
program
do
not
line
up
with
these
dates,
the
quarters
are
lengthened
or
shortened
accordingly
(
e.
g.,
June
1,
2007
­
September
30,
2007,
and
April
1,
2010
­
May
31,
2010).
Quarterly
reports
are
due
two
months
following
the
end
of
the
quarterly
compliance
period
(
i.
e.,
December
1,
March
1,
June
1,
and
September
1).
Annual
compliance
periods
begin
on
July
1
and
end
June
30
of
the
following
year.
Again,
certain
annual
compliance
periods
were
lengthened
or
shortened
to
match
the
significant
dates
of
the
program
(
e.
g.,
June
1,
2007
­
June
30,
2008).
Annual
reports
are
due
by
August
31
following
the
annual
compliance
period.
For
the
sake
of
simplifying
compliance
and
record
keeping,
the
compliance
periods
for
the
highway
final
rule
have
been
adjusted
to
match
these.

Reports
must
be
submitted
electronically,
or
in
a
form
which
facilitates
direct
entry
into
an
electronic
database.
Without
reliance
on
an
electronic
database
and
reporting
system
to
cross
check
and
verify
reported
information,
the
designate
and
track
provisions
would
become
so
cumbersome
as
to
be
virtually
unenforceable
by
EPA
staff
given
projected
resource
availability.

ii.
Reporting
Requirements
During
the
First
Step
of
Today's
Program
During
the
first
step
of
today's
program,
from
June
1,
2007
through
May
31,
2010,
entities
must
report
to
EPA
for
each
of
their
facilities
regarding
the
total
volume
of
each
of
the
designated
fuels
that
they
receive
from,
or
discharge
to,
another
entity's
facility
in
the
fuel
distribution
system.
If
a
facility
is
a
refiner
as
well
as
a
distributor
(
e.
g.,
a
blender
of
biodiesel
or
blendstocks
from
unfinished
diesel
fuel
or
heating
oil
or
otherwise
both
accepts
previously
designated
fuel
and
also
produces
fuel),
it
must
also
report
both
volumes
produced
and
released
to
other
entities
in
its
capacity
as
refiner
and
also
report
the
volumes
received
and
released
for
each
designation
like
any
other
terminal
or
pipeline.

For
example,
an
entity
that
operates
a
pipeline
may
have
multiple
points
where
it
discharges
fuel,
and
at
each
of
these
points
it
may
supply
multiple
terminals.
The
pipeline
operator
must
report
on
the
receipt
of
designated
fuel
from
each
party
that
transfers
fuel
to
it,
and
on
the
designated
fuel
transferred
by
the
pipeline
at
each
discharge
point
which
specifies
the
fuel
transferred,
separately
for
each
of
its
terminal
customers.
Entities
must
report
for
each
of
their
facilities
the
total
volumes
of
the
designated
fuels
that
were
either
dyed
red,
marked,
or
on
which
taxes
were
assessed
tax
while
in
their
custody.
Reports
regarding
these
volumes
do
not
need
to
include
details
on
the
recipients
of
the
fuel
(
but
product
transfer
documents
must
be
kept
to
facilitate
EPA's
ability
to
compare
the
outgoing
transfers
and
to
fuel
received).

Entities
that
handle
only
dyed
NRLM
diesel
fuel,
dyed
and
marked
500
ppm
sulfur
LM
diesel
fuel
(
2010­
2012)
and
heating
oil,
or
highway
diesel
fuel
on
which
taxes
have
been
assessed
126
500
ppm
sulfur
NR
diesel
fuel,
and
starting
June
1,
2012,
500
ppm
sulfur
NRLM
diesel
fuel,

is
not
permitted
in
the
Northeast/
Mid­
Atlantic
area
and
only
in
the
State
of
Alaska
in
limited
circumstances.

261
do
not
need
to
report
to
EPA.
Information
from
such
entities
is
not
needed
for
compliance
purposes,
because
there
is
no
chance
of
violating
the
prohibitions
against
the
shifting
of
fuel
from
one
pool
to
another
contained
in
today's
rule
without
also
violating
either
the
requirement
that
highway
diesel
fuel
contain
no
red
dye,
or
the
requirement
that
NRLM
diesel
fuel
contain
no
heating
oil
marker.
Furthermore,
consistent
with
the
highway
rule,
there
are
no
periodic
reporting
requirements
regarding
the
demonstration
of
compliance
with
the
highway
program's
antidowngrading
requirements
in
today's
rule.
Maintenance
of
records
should
be
sufficient
for
EPA
to
adequately
monitor
compliance
with
these
requirements,
as
insufficient
15
ppm
sulfur
diesel
fuel
availability
in
an
area
should
highlight
potential
anti­
downgrading
violations.

Quarterly
reports
from
facilities
downstream
of
the
refinery
and
importer
must
also
include
data
on
the
total
volume
of
the
designated
fuels
received,
discharged,
and
in
inventory
during
the
quarterly
reporting
period.
Using
these
data,
the
reporting
party
must
demonstrate
compliance
with
the
volume
account
balance
requirements
regarding
highway
diesel
fuel
and
high
sulfur
NRLM.

iii.
Reporting
Requirements
During
the
Second
Step
of
Today's
Program
We
believe
that
we
may
safely
dispense
with
quarterly
reporting
and
compliance
evaluations
starting
June
1,
2010
and
instead
rely
on
annual
reports.
During
the
second
step
of
today's
rule,
the
designate
and
track
requirements
will
be
focused
on
preventing
the
use
of
heating
oil
in
NRLM
equipment,
and
during
2010­
2012
preventing
the
use
of
500
ppm
sulfur
LM
diesel
fuel
in
nonroad
equipment.
By
2010,
all
reporting
parties
in
the
system
will
have
had
experience
in
complying
with
the
program's
designate
and
track
provisions.
In
addition,
the
Agency
will
have
had
ample
experience
in
administering
the
system.
Consequently,
we
expect
that
there
will
be
few
errors
or
omissions
in
reports
and
that
EPA
will
have
determined
how
best
to
detect
and
remedy
instances
of
noncompliance.
We
believe
an
annual
reporting
period
is
therefore
sufficient
and
appropriate.

Beginning
June
1,
2010,
entities
that
produce,
import,
or
take
custody
of
500
ppm
sulfur
NRLM
diesel
fuel,
marked
heating
oil,
or
unmarked
heating
oil
outside
of
the
Northeast/
Mid­
Atlantic
area
and
Alaska,
must
submit
an
annual
report
to
EPA
that
provides
summary
information
regarding
the
transfer
of
these
fuels.
126
Entities
must
report
for
each
of
their
facilities
the
total
volume
of
each
of
these
fuels
that
they
received
from,
or
discharge
to,
another
entity's
facility
in
the
fuel
distribution
system
during
each
annual
compliance
period.
For
batches
of
heating
oil
that
are
delivered
marked,
the
reports
do
not
need
to
indicate
the
entities
to
which
the
batches
were
delivered
 
only
the
total
volume
of
marked
heating
oil
delivered
during
each
compliance
period
must
be
reported.
If
an
entity
only
receives
marked
heating
oil
(
i.
e.,
it
does
not
receive
any
127
During
this
time
period,
500
ppm
sulfur
NR
diesel
fuel
is
not
permitted
in
the
Northeast/
Mid­
Atlantic
area
and
only
in
the
State
of
Alaska
in
limited
circumstances.

128
See
66
FR
36543,
July
12,
2001
(
notice
proposing
approval
of
Houston
SIP
revisions).
See
also
letter
from
Carl
Edlund,
Director,
Multimedia
Planning
and
Permitting
Division,
U.
S.
Environmental
Protection
Agency,
Region
VI,
to
Jeffrey
Saitas,
Executive
Director,
Texas
Natural
Resources
Conservation
Commission,
dated
September
25,
2000,
providing
comments
on
proposed
revisions
to
the
Texas
State
Implementation
Plan
for
the
control
of
ozone,
specifically
the
Post
99
Rate
of
Progress
Plan
and
Attainment
Demonstration
for
the
Houston/
Galveston
area.
This
letter
noted
that
preemption
under
section
211(
c)(
4)
of
the
CAA
did
not
apply
to
controls
on
nonroad
diesel
fuel.

262
unmarked
heating
oil),
it
does
not
need
to
report
at
all.
If
a
facility
received
marked
heating
oil
in
addition
to
unmarked
heating
oil,
it
must
report
the
volume
of
marked
heating
oil
separately
and
indicate
the
facility
from
which
the
marked
heating
oil
was
received.

Beginning
June
1,
2010
to
June
1,
2012,
entities
that
produce,
import,
or
take
custody
of
500
ppm
sulfur
NR
and
LM
diesel
fuel
outside
of
the
Northeast/
Mid­
Atlantic
area
and
Alaska,
must
submit
an
annual
report
to
EPA
that
provides
summary
information
regarding
the
transfer
of
these
fuels.
127
Entities
must
report
for
each
of
their
facilities
the
total
volume
of
each
of
these
fuels
that
they
received
from,
or
discharge
to,
another
entity's
facility
in
the
fuel
distribution
system
during
each
annual
compliance
period.
For
batches
of
500
ppm
sulfur
LM
diesel
fuel
that
are
delivered
marked,
the
reports
do
not
need
to
indicate
the
entities
to
which
the
batches
were
delivered
 
only
the
total
volume
of
marked
500
ppm
sulfur
LM
diesel
fuel
delivered
during
each
compliance
period
must
be
reported.
If
an
entity
only
receives
marked
500
ppm
sulfur
LM
diesel
fuel
(
i.
e.,
it
does
not
receive
any
unmarked
500
ppm
sulfur
LM
diesel
fuel),
it
does
not
need
to
report
at
all.
If
a
facility
received
marked
in
addition
to
unmarked
500
ppm
sulfur
LM
diesel
fuel,
it
must
report
the
volume
of
marked
500
ppm
sulfur
LM
diesel
fuel
separately
and
indicate
the
facility
from
which
the
marked
500
ppm
sulfur
LM
diesel
fuel
was
received.

E.
How
Are
State
Diesel
Fuel
Programs
Affected
by
the
Sulfur
Diesel
Program?

Section
211(
c)(
4)(
A)
of
the
CAA
prohibits
states
and
political
subdivisions
of
states
from
prescribing
or
attempting
to
enforce,
for
purposes
of
motor
vehicle
emission
control,
"
any
control
or
prohibition
respecting
any
characteristic
or
component
of
a
fuel
or
fuel
additive
in
a
motor
vehicle
or
motor
vehicle
engine,"
if
EPA
has
prescribed
"
a
control
or
prohibition
applicable
to
such
characteristic
or
component
of
the
fuel
or
fuel
additive"
under
section
211(
c)(
1).
This
prohibition
applies
to
all
states
except
California,
as
explained
in
section
211(
c)(
4)(
B).
This
express
preemption
provision
in
section
211(
c)(
4)(
A)
applies
only
to
controls
or
prohibitions
respecting
any
characteristics
or
components
of
fuels
or
fuel
additives
for
motor
vehicles
or
motor
vehicle
engines,
that
is,
highway
vehicles.
It
does
not
apply
to
controls
or
prohibitions
respecting
any
characteristics
or
components
of
fuels
or
fuel
additives
for
nonroad
engines
or
nonroad
vehicles.
128
263
Section
211(
c)(
4)(
A)
specifically
mentions
only
controls
respecting
characteristics
or
components
of
fuel
or
fuel
additives
in
a
"
motor
vehicle
or
motor
vehicle
engine,"
adopted
"
for
purposes
of
motor
vehicle
emissions
control,"
and
the
definitions
of
motor
vehicle
and
nonroad
engines
and
vehicles
in
CAA
section
216
are
mutually
exclusive.
This
is
in
contrast
to
sections
211(
a)
and
(
b),
which
specifically
mention
application
to
fuels
or
fuel
additives
used
in
nonroad
engines
or
nonroad
vehicles,
and
with
section
211(
c)(
1)
which
refers
to
fuel
used
in
motor
vehicles
or
engines
or
nonroad
engines
or
vehicles.

Thus,
today's
action
does
not
preempt
state
controls
or
prohibitions
respecting
characteristics
or
components
of
fuel
or
fuel
additives
used
in
nonroad,
locomotive,
or
marine
engines
or
nonroad,
locomotive,
or
marine
vehicles
under
the
provisions
of
section
211(
c)(
4)(
A).
At
the
same
time,
a
state
control
that
regulates
both
highway
fuel
and
nonroad
fuel
is
preempted
to
the
extent
that
the
state
control
respects
a
characteristic
or
component
of
highway
fuel
regulated
by
EPA
under
section
211(
c)(
1).

A
court
may
consider
whether
a
state
control
for
fuels
or
fuel
additives
used
in
nonroad
engines
or
nonroad
vehicles
is
implicitly
preempted
under
the
supremacy
clause
of
the
U.
S.
constitution.
Courts
have
determined
that
a
state
law
is
preempted
by
federal
law
where
the
state
requirement
actually
conflicts
with
federal
law
by
preventing
compliance
with
the
federal
requirement,
or
by
standing
as
an
obstacle
to
accomplishment
of
congressional
objectives.
A
court
could
thus
consider
whether
a
given
state
standard
for
sulfur
in
nonroad,
locomotive
or
marine
diesel
fuel
is
preempted
if
it
places
such
significant
cost
and
investment
burdens
on
refiners
that
refiners
cannot
meet
both
state
and
federal
requirements
in
time,
or
if
the
state
control
would
otherwise
meet
the
criteria
for
conflict
preemption.

F.
Technological
Feasibility
of
the
500
and
15
ppm
Sulfur
Diesel
Fuel
Program
This
section
summarizes
our
assessment
of
the
feasibility
of
refining
and
distributing
500
ppm
NRLM
diesel
fuel
starting
in
2007
and
15
ppm
nonroad
diesel
fuel
in
2010
and
locomotive
and
marine
diesel
fuel
in
2012.
Based
on
this
evaluation,
we
believe
it
is
technologically
feasible
for
refiners
and
distributors
to
meet
both
sulfur
standards
in
the
lead
time
provided
with
the
desulfurization
technology
available.
We
begin
this
section
by
describing
the
nonroad,
locomotive
and
marine
diesel
fuel
market
and
how
these
fuels
differ
from
current
highway
diesel
fuel.
We
discuss
desulfurization
technologies,
both
conventional
and
advanced,
which
are
available
for
complying
with
the
500
ppm
and
15
ppm
NRLM
standards.
We
then
present
what
mix
of
technologies
we
believe
will
be
used.
Next
we
provide
our
analysis
of
the
lead
time
for
complying
with
either
standard.
Finally,
we
analyze
the
feasibility
of
distributing
low
sulfur
NRLM
diesel
fuel.
We
refer
the
reader
to
the
Final
RIA
for
more
details
regarding
these
assessments.

1.
What
Is
the
Nonroad,
Locomotive
and
Marine
Diesel
Fuel
Market
Today?

Nonroad,
locomotive
and
marine
(
NRLM)
engines
almost
exclusively
use
No.
2
distillate
fuel.
No.
2
distillate
fuel
is
a
class
of
fuel
defined
by
its
boiling
range.
It
boils
at
a
higher
average
129
"
Standard
Specification
for
Diesel
Fuel
Oils,"
ASTM
D
975­
98b
and
"
Standard
Specifications
for
Fuel
Oils,"
ASTM
D
396­
98.

130
These
ASTM
requirements
were
formed
after
and
are
consistent
with
the
EPA
regulations
for
highway
diesel
fuel.

131
Some
states,
particularly
those
in
the
Northeast,
limit
the
sulfur
content
of
No.
2
fuel
oil
to
2000
­
3000
ppm.

264
temperature
than
gasoline,
No.
1
distillate,
jet
fuel
and
kerosene,
and
at
a
lower
average
temperature
than
residual
fuel
(
or
bunker
fuel).
ASTM
defines
three
No.
2
distillate
fuels:
1)
low
sulfur
No.
2
diesel
fuel
(
No.
2­
D);
2)
high
sulfur
No.
2­
D;
and
3)
No.
2
fuel
oil.
129
Low
sulfur
No.
2­
D
fuel
must
contain
500
ppm
sulfur
or
less,
have
a
minimum
cetane
number
of
40,
and
have
a
minimum
cetane
index
limit
of
40
(
or
a
maximum
aromatic
content
of
35
volume
percent)(
i.
e.,
meet
the
EPA
standard
for
highway
diesel
fuel).
130
Both
high
sulfur
No.
2­
D
and
No.
2
fuel
oil
must
contain
no
more
than
5000
ppm
sulfur,
131
and
currently
averages
3000
ppm
nationwide.
The
ASTM
specification
for
high
sulfur
No.
2­
D
fuel
also
includes
a
minimum
cetane
number
of
40.
Practically,
since
most
No.
2
fuel
oil
meets
this
minimum
cetane
number
specification,
pipelines
which
ship
fuel
fungibly
need
only
carry
one
high
sulfur
No.
2
distillate
fuel
which
meets
both
sets
of
specifications.
Currently,
nonroad,
locomotive
and
marine
engines
can
be
and
are
fueled
with
both
low
and
high
sulfur
No.
2­
D
fuels.
If
No.
1
distillate
is
blended
into
highway
diesel
fuel,
as
is
sometimes
done
to
prevent
gelling
in
the
winter,
the
final
blend
must
meet
the
500
ppm
EPA
cap.

No.
1
distillate
(
e.
g.,
jet
fuel
and
kerosene)
meets
lower
boiling
point
and
viscosity
specifications
requirements
than
No.
2
distillate.
No.
1
distillate,
or
any
of
these
other
similar
boiling
distillates,
added
to
No.
2
NRLM
distillate
becomes
NRLM
diesel
fuel
and
thus,
must
meet
the
applicable
specifications
for
No.
2
distillate.

For
the
purpose
of
this
rule,
we
split
the
No.
2
distillate
market
into
three
pieces,
according
to
the
sulfur
standard
which
each
must
meet:
1)
highway
diesel
fuel,
2)
NRLM
diesel
fuel,
and
heating
oil,
which
is
used
in
both
furnaces
and
boilers,
as
well
as
in
stationary
diesel
engines
to
generate
power.

In
the
NPRM,
EPA
estimated
current
production
and
demand
for
NRLM
fuel
from
studies
conducted
by
the
U.
S.
Energy
Information
Administration
(
EIA).
We
projected
growth
in
nonroad
fuel
demand
using
EPA's
NONROAD
emission
model.
We
based
the
growth
in
locomotive
and
marine
fuel
demand
from
analyses
supporting
EPA's
locomotive
and
marine
engine
rulemaking.
These
future
levels
of
NRLM
fuel
demand
differed
from
those
implicit
in
our
projection
of
the
emission
reductions
associated
with
the
rule,
which
were
based
primarily
on
EPA's
NONROAD
emission
model.
We
pointed
out
this
inconsistency
in
the
rule
and
indicated
that
we
would
resolve
this
inconsistency
for
the
final
rule.
265
In
their
comments
on
the
NPRM,
the
American
Petroleum
Institute
(
API),
the
Engine
Manufacturers
Association
(
EMA)
and
others
highlighted
this
inconsistency
and
suggested
that
EPA
resolve
it
by
basing
its
projection
of
future
NRLM
fuel
demand
using
information
developed
by
EIA
and
not
from
the
NONROAD
emission
model.
API
pointed
to
a
lower
estimate
of
nonroad
fuel
demand
developed
in
a
contracted
study
performed
by
Baker
and
O'Brien.
A
detailed
analysis
of
these
comments
and
additional
technical
analyses
of
distillate
fuel
demand
are
described
in
Section
4.6.3.1
of
the
Summary
and
Analysis
document
to
this
rule.
In
summary,
we
decided
to
continue
using
the
NONROAD
emission
model
to
project
the
emission
benefits
of
this
rule.
To
eliminate
the
inconsistency
in
the
NPRM,
we
also
use
the
NONROAD
model
to
determine
demand
for
nonroad
fuel
and
project
the
economic
impacts
of
this
final
rule.
However,
the
analyses
presented
in
Section
4.6.3.1
of
the
Summary
and
Analysis
document
to
this
rule
identified
uncertainties
in
the
current
and
future
level
of
nonroad
fuel
demand.
To
insure
that
these
uncertainties
did
not
affect
the
outcome
of
this
rulemaking
process,
we
evaluate
the
emissions,
costs
and
cost
effectiveness
of
the
standards
contained
in
this
rule
using
an
alternative
estimate
of
nonroad
fuel
demand
derived
from
EIA
information.
This
alternative
analysis
is
presented
in
Appendix
8A
of
the
Final
RIA.
In
addition
to
use
of
the
NONROAD
model
to
project
nonroad
fuel
demand,
we
also
updated
our
projections
of
the
production
of
and
demand
for
highway
fuel
and
heating
oil
using
more
recent
versions
of
the
same
EIA
reports
used
in
the
NPRM
analysis.

In
2001,
nationwide
outside
of
California,
nonroad
diesel
fuel
comprised
about
18
percent
of
all
No.
2
distillate
fuel,
while
locomotive
and
marine
diesel
fuel
comprised
about
eight
percent
of
all
No.
2
distillate
fuel.
Diesel
fuel
consumed
by
highway
vehicles/
engines
comprised
about
56
percent
of
all
No.
2
distillate
fuel.
Heating
oil
comprised
about
19
percent
of
No.
2
distillate.
Because
of
limitations
in
the
fuel
distribution
system
and
other
factors,
about
18
percent
of
all
non­
highway
distillate
met
the
500
ppm
highway
diesel
fuel
cap.
Thus,
about
64
percent
of
No.
2
distillate
pool
met
the
500
ppm
sulfur
cap,
not
just
the
56
percent
used
in
highway
vehicles.
We
project
that
this
spillover
of
highway
fuel
to
the
NRLM
diesel
fuel
market
will
continue
under
the
highway
diesel
fuel
program.
Thus,
today's
rule
will
only
materially
affect
about
19
percent
of
today's
distillate
market.
The
remaining
17
percent
of
No.
2
distillate
which
is
high
sulfur
heating
oil
is
estimated
to
remain
at
higher
sulfur
levels.

This
rule
will
also
affect
any
No.
1
distillate
which
is
blended
into
wintertime
NRLM
fuel.
Because
gelling
can
also
be
prevented
through
the
use
of
pour
point
additives,
the
current
and
future
level
of
this
of
No.
1
distillate
blending
is
uncertain.
However,
the
feasibility
of
desulfurizing
and
distributing
this
No.
1
distillate
will
also
be
addressed
below.

2.
What
Technology
Will
Refiners
Use
to
Meet
the
500
ppm
Sulfur
Cap?

Refiners
currently
hydrotreat
most
or
all
of
their
distillate
blendstocks
using
what
is
commonly
referred
to
as
"
conventional"
hydrotreating
technology
to
meet
the
500
ppm
sulfur
and
cetane
limits
applicable
to
highway
diesel
fuel.
This
conventional
technology
has
been
available
and
in
use
for
many
years.
U.
S.
refiners
have
nearly
ten
years
of
experience
with
this
technology
in
producing
highway
diesel
fuel.
The
distillate
blendstocks
comprising
NRLM
fuel
do
not
differ
132
These
refiners
have
said
that
they
will
leave
the
highway
market
in
2006
in
their
precompliance
reports
for
complying
with
the
Highway
Diesel
Rule,
thus
freeing
up
their
existing
hydrotreaters
to
produce
500
ppm
NRLM
diesel
fuel.

266
substantially
from
those
comprising
highway
diesel
fuel.
Thus,
the
technology
to
produce
500
ppm
sulfur
NRLM
diesel
fuel
has
clearly
been
demonstrated
and
optimized
over
the
last
decade.
Additionally,
this
technology
continues
to
evolve
primarily
through
the
development
of
more
active
catalysts
and
motivated
by
the
15
ppm
cap
applicable
to
most
highway
diesel
fuel
starting
in
2006.

Several
advanced
desulfurization
technologies
are
being
developed
and
are
discussed
in
more
detail
in
the
next
section.
However,
the
fact
that
none
of
these
technologies
have
been
demonstrated
commercially
for
a
typical
catalyst
life
(
i.
e.,
two
years)
makes
it
unlikely
that
they
would
be
selected
by
many
refiners
for
use
in
mid­
2007.
Also,
these
advanced
technologies
promise
the
greatest
cost
savings
in
achieving
15
ppm
levels,
rather
than
500
ppm.
These
advanced
technologies
can
also
be
combined
with
a
conventional
hydrotreater
to
meet
the
15
ppm
standard
in
2010
and
2012.
EPA
therefore
projects
that
the
500
ppm
sulfur
cap
NRLM
standard
will
be
met
using
conventional
hydrotreating
technology.
We
made
this
same
projection
in
the
NPRM
and
no
comments
to
the
contrary
were
received.

In
some
cases,
refiners
will
also
need
to
install
or
expand
several
ancillary
processes
related
to
sulfur
removal
(
e.
g.,
hydrogen
production
and
purification,
sulfur
processing,
and
sour
water
treatment).
These
technologies
are
all
commercially
demonstrated,
as
nearly
all
refineries
already
have
such
units.

3.
Is
the
Leadtime
Sufficient
to
Meet
the
2007
500
ppm
NRLM
Sulfur
Standard?

After
the
highway
diesel
fuel
program
is
implemented,
we
project
that
92
refineries
in
U.
S.
will
be
producing
high
sulfur
distillate
fuel.
We
project
that
36
of
these
refineries
will
likely
produce
500
ppm
sulfur
NRLM
diesel
fuel
in
2007.
Of
those
36,
30
will
have
to
build
new
hydrotreaters
while
the
other
6
are
expected
to
use
existing
hydrotreaters
to
produce
500
ppm
NRLM
diesel
fuel.
132
The
remaining
56
refineries
are
projected
to
continue
to
produce
high
sulfur
distillate
fuel,
with
26
of
the
56
refineries
producing
heating
oil.
The
other
30
refineries
are
owned
by
small
refiners
and
will
likely
produce
high
sulfur
NRLM
diesel
fuel.
The
56
refineries
continuing
to
produce
high
sulfur
distillate
will
not
have
to
add
or
modify
any
equipment
to
continue
producing
this
fuel.

This
rule
will
provide
refiners
and
importers
37
months
before
they
will
have
to
begin
producing
500
ppm
NRLM
diesel
fuel
on
June
1,
2007.
Our
lead
time
analysis
projects
that
27­
39
133
"
Highway
Diesel
Progress
Review,"
USEPA,
EPA420­
R­
02­
016,
June
2002.
The
leadtime
analysis
in
the
RIA
can
be
found
in
section
5.3.

267
months
are
typically
needed
to
design
and
construct
a
diesel
fuel
hydrotreater.
133
As
discussed
below,
we
believe
that
37
months
will
be
sufficient
for
all
refiners
of
NRLM
fuel.

Easing
the
task
is
the
fact
that
we
project
that
essentially
all
refiners
will
use
conventional
hydrotreating
to
comply
with
the
500
ppm
sulfur
NRLM
diesel
fuel
cap.
This
technology
has
been
used
extensively
for
more
than
10
years
and
its
capabilities
to
process
a
wide
range
of
diesel
fuel
blendstocks
are
well
understood.
Thus,
the
time
necessary
to
apply
this
technology
for
a
specific
refiner's
situation
should
be
relatively
short.

Twenty­
six
out
of
the
36
refineries
projected
to
produce
500
ppm
NRLM
diesel
fuel
in
2007
have
indicated
that
they
will
produce
highway
diesel
fuel
in
their
highway
diesel
fuel
pre­
compliance
reports,
see
RIA
section
7.2.1.3.4.1,
Table
7.2.1­
38
and
following
discussion
for
description
of
these
refineries.
Thus,
roughly
70%
of
the
refiners
likely
to
produce
500
ppm
sulfur
NRLM
diesel
fuel
in
2007
are
already
well
into
their
planning
for
meeting
the
15
ppm
highway
diesel
fuel
standard,
effective
June
1,
2006.
It
is
likely
that
these
refiners
have
already
chemically
characterized
their
high
sulfur
diesel
fuel
blendstocks,
as
well
as
their
highway
diesel
fuel,
in
assessing
how
to
meet
produce
15
ppm
fuel.
They
will
also
have
already
assessed
the
various
technologies
for
producing
15
ppm
diesel
fuel.
This
provides
an
extensive
base
of
information
on
how
to
design
a
hydrotreater
to
produce
500
ppm
NRLM
fuel,
as
well
as
how
to
revamp
this
hydrotreater
to
produce
15
ppm
NRLM
diesel
fuel
in
2010
and
2012.
Those
refiners
only
producing
high
sulfur
distillate
fuel
today
will
be
able
to
take
advantage
of
the
significant
experience
that
technology
vendors
have
obtained
in
assisting
refiners
of
highway
diesel
fuel
meet
the
15
ppm
cap
in
2006.

We
also
expect
that
roughly
20
percent
of
the
101
refineries
in
the
U.
S.
and
its
territories
will
build
a
new
hydrotreater
to
produce
15
ppm
highway
fuel.
Those
which
also
produce
high
sulfur
distillate
will
be
able
to
produce
500
ppm
NRLM
fuel
with
their
existing
highway
hydrotreater.
In
2007,
we
conservatively
assumed
that
20%
of
the
500
ppm
NRLM
production
from
refineries
that
produce
highway
and
high
sulfur
distillate
could
be
produced
with
these
existing
treaters
at
no
capital
costs
(
existing
highway
treater
capacity
available
for
500
ppm
NRLM
production
would
be
higher
if
based
on
highway
treater
capacity).
Thus,
in
2007
we
project
that
four
refineries
will
be
able
to
use
their
recently
idled
highway
treater
due
to
building
a
new
highway
treater
unit
for
2006.
Furthermore,
the
highway
diesel
program
pre­
compliance
reports
indicate
that
another
7
refineries
currently
producing
500
ppm
highway
fuel
will
likely
leave
the
highway
fuel
market
in
2006.
We
project
that
2
of
these
would
use
their
existing
treater
to
produce
500
ppm
NRLM
with
no
investment
costs.
Another
three
of
these
101
refineries
produce
relatively
small
volumes
of
high
sulfur
distillate
compared
to
highway
diesel
fuel
today.
We
project
that
they
will
be
able
to
produce
500
ppm
sulfur
NRLM
fuel
from
their
high
sulfur
distillate
with
only
minor
modification
to
their
existing
highway
diesel
fuel
hydrotreater.
268
Refiners
not
planning
on
producing
100
percent
highway
fuel
in
2006
will
also
need
some
time
to
assess
which
distillate
market
in
which
to
participate
starting
in
2007,
NRLM
or
heating
oil.
While
this
is
a
decision
which
requires
some
amount
of
time
for
analysis,
refiners
also
needed
to
assess
what
market
they
would
participate
in
for
the
1993
500
ppm
highway
diesel
fuel
sulfur
cap.
In
all,
we
project
that
the
task
of
producing
500
ppm
sulfur
NRLM
fuel
in
2007
will
be
less
difficult
than
the
task
refiners
faced
with
the
implementation
of
the
500
ppm
highway
diesel
fuel
cap
in
1993.
Refiners
had
just
over
three
years
of
lead
time
for
complying
with
the
1993
500
ppm
highway
diesel
fuel
cap,
as
is
the
case
here,
and
this
proved
sufficient.

No
explicit
comments
were
made
by
refiners
on
the
lead
time
needed
for
complying
with
the
proposed
NRLM
500
ppm
sulfur
standard.
However,
their
comments
supported
the
two
step
approach,
preferring
it
over
a
one
step,
15
ppm
NRLM
cap
starting
in
2008.

4.
What
Technology
Will
Refiners
Use
to
Meet
the
15
ppm
Sulfur
Cap?

In
the
highway
diesel
rule,
we
projected
that
refiners
producing
15
ppm
fuel
in
2006
would
utilize
extensions
of
conventional
hydrotreating
technology.
We
also
projected
that
refiners
first
producing
15
ppm
fuel
in
2010
would
use
a
mix
of
extensions
of
conventional
and
advanced
technologies.
Based
on
the
refiners'
highway
pre­
compliance
reports,
it
appears
that
95%
of
highway
fuel
could
meet
the
15
ppm
cap
in
2006.
We
expect
that
virtually
all
of
this
15
ppm
fuel
will
be
produced
with
conventional
hydrotreating.
Thus,
it
appears
that
conventional
hydrotreating
will
be
used
to
produce
the
vast
majority
of
15
ppm
highway
diesel
fuel.

In
the
nonroad
NPRM,
we
projected
that
refiners
would
use
advanced
desulfurization
technologies
to
produce
80
percent
of
15
ppm
nonroad
diesel
fuel
in
2010,
with
the
balance
using
conventional
hydrotreating.
At
the
time
of
the
NPRM,
all
of
the
advanced
technologies
appeared
to
be
progressing
rapidly.
Since
the
proposal,
we
have
learned
that
a
couple
of
these
technologies,
Unipure
and
S­
Zorb,
are
not
going
to
be
commercially
demonstrated
as
soon
as
expected.
However,
one
refiner
is
already
using
Process
Dynamics'
IsoTherming
technology
to
commercially
produce
15
ppm
diesel
fuel.
Thus,
we
continue
to
believe
that
advanced
technologies
will
be
used
to
produce
a
large
percentage
of
15
ppm
NRLM
fuel.
However,
the
number
of
advanced
technologies
used
may
be
smaller.
Because
of
the
more
limited
choices,
we
project
that
the
penetration
of
advanced
technologies
will
be
only
60
percent.
The
remainder
of
this
section
discusses
the
production
of
15
ppm
diesel
fuel
using
conventional
and
advanced
technologies.

One
approach
to
produce
15
ppm
NRLM
fuel
would
be
to
revamp
the
conventional
hydrotreater
built
to
produce
500
ppm
NRLM
fuel
in
2007.
Knowing
that
the
500
ppm
NRLM
cap
will
only
be
in
effect
for
three
years
for
nonroad
refiners
and
five
years
for
locomotive
and
marine
refiners
(
four
years
for
small
refiners),
we
expect
that
refiners
will
design
their
500
ppm
hydrotreater
to
allow
the
production
of
15
ppm
fuel
through
the
addition
of
reactor
volume
or
a
second
hydrotreating
stage.
Refiners
might
also
shift
to
a
more
active
catalyst
in
the
existing
reactor,
as
the
life
of
that
catalyst
might
be
nearing
its
end.
Equipment
to
further
purify
its
hydrogen
supply
could
also
be
added.
Producing
15
ppm
NRLM
fuel
via
these
steps
will
be
134
"
Highway
Diesel
Progress
Review,"
USEPA,
EPA420­
R­
02­
016,
June
2002.

269
feasible
as
they
are
essentially
the
same
steps
refiners
will
be
using
in
2006
to
produce
15
ppm
highway
diesel
fuel.

EPA
recently
reviewed
the
progress
being
made
by
refining
technology
vendors
and
refiners
in
meeting
the
2006
highway
diesel
sulfur
cap.
134
All
evidence
available
confirms
EPA's
projection
that
conventional
hydrotreating
will
be
capable
of
producing
diesel
fuel
containing
less
than
10
ppm
sulfur.
Furthermore,
as
part
of
the
highway
program's
reporting
requirements,
refiners
are
required
to
report
their
progress
in
complying
with
the
15
ppm
highway
diesel
fuel
standard.
In
those
reports
they
indicated
that
they
primarily
will
be
applying
extensions
of
conventional
hydrotreating.
NRLM
fuel
refiners
will
have
the
added
advantage
of
being
able
to
design
their
500
ppm
hydrotreater
with
the
production
of
15
ppm
fuel
in
mind.
Additionally,
refiners
producing
15
ppm
NRLM
fuel
will
be
able
to
take
advantage
of
the
experience
gained
from
those
producing
15
ppm
highway
fuel.

As
mentioned
above,
several
advanced
technologies
are
presently
being
developed
to
produce
15
ppm
diesel
fuel
at
lower
cost.
One
of
these
advanced
technologies,
Process
Dynamics
IsoTherming,
improves
the
contact
between
hydrogen,
diesel
fuel
and
the
desulfurization
catalyst.
The
IsoTherming
process
dissolves
the
hydrogen
in
the
liquid
fuel
phase
prior
to
passing
the
liquid
over
the
catalyst,
eliminating
the
need
for
a
two­
phase
(
gas
and
liquid)
reactor.
The
liquid,
plug
flow
reactor
design
also
avoids
the
poor
liquid
distribution
over
the
catalyst
bed
often
present
in
a
two­
phase
reactor
design.
Process
Dynamics
projects
that
their
IsoTherming
process
could
reduce
the
hydrotreater
volume
required
to
achieve
sub­
15
ppm
sulfur
levels
by
roughly
a
factor
of
two.

Process
Dynamics
has
already
built
a
commercial­
sized
demonstration
unit
(
5000
barrels
per
day)
at
a
refinery
in
New
Mexico.
They
have
been
operating
the
unit
since
September
2002,
and
demonstrating
the
capability
to
meet
a
15
ppm
cap
since
the
spring
of
2003.
Thus,
refiners
will
have
4­
5
years
of
operating
data
on
this
process
before
they
would
have
to
select
a
technology
to
produce
15
ppm
nonroad
diesel
fuel
in
2010,
and
6­
7
years
before
producing
15
ppm
locomotive
and
marine
diesel
fuel
in
2012.
This
should
be
more
than
sufficient
for
essentially
all
refiners
to
consider
this
process
for
2010
or
2012.
Based
on
information
received
from
Process
Dynamics,
we
estimate
that
this
technology
could
reduce
the
cost
of
meeting
the
15
ppm
cap
for
many
refiners
by
about
30
percent.
This
savings
arises
from
a
smaller
reactor,
less
catalyst
and
avoiding
the
need
for
a
recycle
gas
compressor
and
reactor
distributor.
Refineries
facing
poorer
economies
of
scale,
such
as
small
refineries,
would
particularly
benefit
from
this
desulfurization
process.

A
second
process
being
developed
to
produce
15
ppm
diesel
fuel
is
the
Unipure
oxidation
process.
This
process
oxidizes
the
sulfur
in
distillate
molecules,
facilitating
its
removal.
Unipure
Corporation
installed
a
small
(
50
barrels
per
day),
continuous
flow
demonstration
unit
at
Valero's
Krotz
Spring
refinery
in
the
spring
of
2003.
It
appears
that
this
technology
could
reduce
the
cost
270
of
producing
15
ppm
diesel
fuel
for
some
refiners
compared
to
conventional
hydrotreating.
However,
the
small
size
of
the
demonstration
unit
may
make
the
risk
associated
with
a
new
technology
too
large.
Thus,
we
believe
that
this
technology
needs
be
demonstrated
further
before
most
refiners
will
seriously
considered
it
for
commercial
application.
This
technology,
however,
may
be
ideal
for
use
at
transmix
processing
plants
or
large
terminals
to
reprocess
15
ppm
diesel
fuel
which
have
become
contaminated
during
shipment.
We
discuss
this
distillate
downgrade
in
greater
detail
in
Section
VI.
A.
2
of
this
preamble.
This
oxidation
process
avoids
the
need
for
high
pressure
hydrogen,
which
is
usually
not
economically
available
at
these
smaller
facilities.

Finally,
Conoco­
Phillips
has
adapted
their
S­
Zorb
adsorption
technology
which
was
originally
designed
for
gasoline
desulfurization,
for
diesel
fuel
desulfurization.
At
the
time
of
the
NPRM,
Conoco­
Phillips
had
signed
23
licensing
agreements
with
refiners
in
North
America
regarding
the
use
of
S­
Zorb
to
comply
with
the
Tier
2
gasoline
sulfur
standards.
Furthermore,
Conoco­
Phillips
had
plans
for
the
quick
installation
of
an
S­
Zorb
unit
to
demonstrate
the
production
of
15
ppm
diesel
fuel.
However,
we
have
since
learned
that
Conoco­
Phillips
has
dropped
its
plans
to
build
a
commercial
demonstration
unit
for
desulfurizing
diesel
fuel.
Without
a
commercial
unit
operating
in
the
2006
time
frame,
we
do
not
believe
that
many
refiners
will
seriously
consider
S­
Zorb
to
produce
15
ppm
NRLM
diesel
fuel
in
2010
and
2012.

Due
to
the
fact
that
the
Process
Dynamics
IsoTherming
process
is
already
operating
commercially
and
operational
data
indicate
a
30
percent
reduction
in
the
cost
of
producing
15
ppm
fuel
relative
to
conventional
hydrotreating,
we
project
that
60
percent
of
the
new
volume
of
15
ppm
NRLM
diesel
fuel
will
be
produced
using
this
technology.
We
project
that
the
remaining
40
percent
of
15
ppm
NRLM
diesel
fuel
will
use
extensions
of
conventional
hydrotreating.
We
assume
this
60/
40
mix
of
Isotherming
and
extensions
of
conventional
hydrotreating,
respectively,
for
2010,
2012
and
even
for
2014
when
the
small
refiners
exemptions
expire.

API
commented
that
the
advanced
desulfurization
technologies
have
not
been
commercially
demonstrated
and
thus
should
not
be
used
as
the
basis
for
estimating
the
cost
of
desulfurizing
NRLM
diesel
fuel
to
15
ppm.
While
this
is
true
for
the
Unipure
oxidation
and
Conoco­
Phillip's
SZorb
processes,
the
Process
Dynamics
IsoTherming
process
has
been
commercially
demonstrated.
It
is
therefore
appropriate
for
use
as
a
partial
basis
for
the
refining
costs
associated
with
today's
final
rule.
To
indicate
the
effect
that
this
projection
for
the
use
of
IsoTherming
has
on
the
rule's
cost,
in
Section
7.2.2
of
the
Final
RIA,
we
estimate
the
cost
of
producing
15
ppm
NRLM
fuel
with
only
the
use
of
conventional
hydrotreating
technology.

5.
Is
the
Leadtime
Sufficient
to
Meet
the
2010
and
2012
15
ppm
NRLM
Sulfur
Cap?

We
project
that
32
refineries
will
produce
15
ppm
nonroad
diesel
fuel
in
2010,
with
two
of
these
being
owned
by
small
refiners.
In
2012,
we
project
that
15
refineries
will
produce
15
ppm
locomotive
and
marine
diesel
fuel.
We
project
that
an
additional
15
refineries
will
produce
500
ppm
nonroad
diesel
fuel
in
2010
under
the
small
refiner
provisions
included
in
the
today's
final
271
rule.
Then
in
2014,
we
project
that
the
15
refineries
exempted
under
the
small
refiner
provisions
will
begin
producing
15
ppm
NRLM
diesel
fuel
in
2014.

The
timing
of
this
rule
provides
refiners
and
importers
with
more
than
six
years
before
they
will
have
to
produce
15
ppm
nonroad
diesel
fuel,
and
two
years
more
for
producing
15
ppm
locomotive
and
marine
diesel
fuel.
Our
leadtime
analysis,
which
is
presented
in
Section
5.4.2
of
the
Final
RIA,
projects
that
30­
39
months
are
typically
needed
to
design
and
construct
a
diesel
fuel
hydrotreater,
perhaps
less
if
it
is
a
Process
Dynamics
unit.
Thus,
refiners
will
have
about
three
years
before
they
would
have
to
begin
detailed
design
and
construction
for
2010,
and
five
years
before
2012.
This
will
allow
sufficient
time
to
consult
with
vendors,
test
their
diesel
fuel
in
pilot
plants
to
assess
the
difficulty
of
its
desulfurization
via
a
variety
of
technologies,
and
to
select
its
technology
for
2010
and
2012.
In
addition,
these
refiners
will
also
have
the
chance
to
observe
the
performance
of
the
hydrotreaters
being
used
to
produce
15
ppm
highway
diesel
fuel
for
at
least
one
year
for
those
complying
in
2010,
and
two
years
more
for
those
complying
in
2012.
While
not
a
full
catalyst
cycle,
any
unusual
degradation
in
catalyst
performance
should
be
apparent
within
the
first
year.
Based
on
the
pre­
compliance
reports,
some
refineries
in
the
U.
S.
will
be
producing
15
ppm
sulfur
highway
diesel
fuel
earlier
than
2006.
Some
refineries
are
expected
to
produce
complying
fuel
earlier
than
the
compliance
date
in
Europe
as
well.
The
refineries
which
are
complying
early
will
accrue
experience
earlier
and
longer
providing
refiners
a
better
sense
of
the
reliability
of
producing
15
ppm
diesel
fuel.
Thus,
we
project
that
the
2010
and
2012
start
dates
will
allow
refiners
to
be
quite
certain
that
the
designs
they
select
in
mid­
2007
will
perform
adequately
in
2010
and
2012.

In
addition,
refiners
will
have
three
to
four
years
or
more
to
observe
the
performance
of
the
Process
Dynamics
IsoTherming
process
before
having
to
make
their
technology
selections
for
2010
and
2012
.
This
should
be
more
than
adequate
to
fully
access
the
costs
and
capabilities
of
this
technology
for
all
but
the
most
cautious
refiners.

Considering
the
amount
of
leadtime
available
and
the
desulfurization
technologies
which
will
be
available
and
proven
for
complying
with
a
15
ppm
sulfur
standard,
we
do
not
expect
that
the
leadtime
for
complying
with
the
15
ppm
NRLM
cap
standard
in
2010
and
2012
will
be
an
issue
for
refiners.

6.
Feasibility
of
Distributing
500
and
15
ppm
NRLM
Fuel
There
are
two
considerations
with
respect
to
the
feasibility
of
distributing
non­
highway
diesel
fuels
meeting
the
sulfur
standards
in
today's
rule.
The
first
pertains
to
whether
sulfur
contamination
can
be
adequately
managed
throughout
the
distribution
system
so
that
fuel
delivered
to
the
end­
user
does
not
exceed
the
specified
maximum
sulfur
concentration.
The
second
pertains
to
the
physical
limitations
of
the
system
to
accommodate
any
additional
segregation
of
product
grades.
272
a.
Limiting
Sulfur
Contamination
With
respect
to
limiting
sulfur
contamination
during
distribution,
the
physical
hardware
and
distribution
practices
for
non­
highway
diesel
fuel
do
not
differ
significantly
from
those
for
highway
diesel
fuel.
Therefore,
we
do
not
anticipate
any
new
issues
with
respect
to
limiting
sulfur
contamination
during
the
distribution
of
non­
highway
fuel
that
would
not
have
already
been
accounted
for
in
distributing
highway
diesel
fuel.
Highway
diesel
fuel
has
been
required
to
meet
a
500
ppm
sulfur
standard
since
1993.
Thus,
we
expect
that
limiting
contamination
during
the
distribution
of
500
ppm
non­
highway
diesel
engine
fuel
can
be
readily
accomplished
by
the
industry.
This
applies
to
locomotive
and
marine
diesel
fuel
as
well
as
nonroad
diesel
fuel.

In
the
highway
diesel
rule,
EPA
acknowledged
that
meeting
a
15
ppm
sulfur
specification
would
pose
a
substantial
new
challenge
to
the
distribution
system.
Refiners,
pipelines,
and
terminals
would
have
to
pay
careful
attention
to
and
eliminate
any
potential
sources
of
contamination
in
the
system
(
e.
g.,
tank
bottoms,
deal
legs
in
pipelines,
leaking
valves,
interface
cuts,
etc.).
In
addition,
bulk
plant
operators
and
delivery
truck
operators
would
have
to
carefully
observe
recommended
industry
practices
to
limit
contamination,
including
practices
as
simple
as
cleaning
out
transfer
hoses,
proper
sequencing
of
fuel
deliveries,
and
parking
on
a
level
surface
when
draining
the
storage
tank.
Due
to
the
need
to
prepare
for
compliance
with
the
highway
diesel
program,
we
anticipate
that
issues
related
to
limiting
sulfur
contamination
during
the
distribution
of
15
ppm
NRLM
diesel
fuel
will
be
resolved
well
in
advance
of
the
2010
and
2012
implementation
dates
.
We
are
not
aware
of
any
additional
issues
that
might
arise
unique
to
NRLM
diesel
fuel.
If
anything
we
anticipate
limiting
contamination
will
become
easier
as
batch
sizes
are
allowed
to
increase
and
potential
sources
of
contamination
decrease
as
more
and
more
of
the
diesel
pool
turns
over
to
500
and
15
ppm
sulfur.
Industry
representatives
acknowledge
that
the
task
can
be
accomplished.
However,
they
are
still
in
the
process
of
identifying
all
of
the
measures
that
will
need
to
be
taken.

b.
Potential
Need
for
Additional
Product
Segregation
As
discussed
in
section
IV.
D,
we
have
designed
the
NRLM
diesel
fuel
program
to
minimize
the
need
for
additional
product
segregation
and
the
feasibility
and
cost
issues
associated
with
it.
This
final
rule
allows
for
the
fungible
distribution
of
500
ppm
highway
and
500
ppm
sulfur
NRLM
diesel
fuel
in
2007,
and
15
ppm
highway
and
15
ppm
NR
diesel
fuel
in
2010
and
15
ppm
NRLM
diesel
fuel
in
2012,
up
until
the
point
where
NRLM,
LM,
or
nonroad
fuel
must
be
dyed
for
IRS
excise
tax
purposes.
We
proposed
that
heating
oil
would
be
required
to
be
segregated
throughout
the
distribution
system
by
the
use
of
a
marker
added
at
the
refiners
from
2007
through
2010.
We
received
comments
that
addition
of
the
marker
at
the
refinery
would
cause
significant
concerns
regarding
potential
marker
contamination
in
the
jet
fuel.
In
responding
to
these
and
other
comments,
we
have
chosen
to
adopt
a
designate
and
track
system
of
ensuring
refiner
compliance
with
desulfurization
requirements
(
see
IV.
D.).
This
allows
the
point
of
marker
addition
to
be
moved
downstream
to
the
terminal
where
such
contamination
concerns
are
minimal.
As
a
result
135
The
fuel
marker
requirements
only
apply
outside
of
the
Northeast/
Mid­
Atlantic
area.
Inside
the
Northeast/
Mid­
Atlantic
area,
high
sulfur
NRLM
cannot
be
sold
to
end
users.
See
section
IV.
D
for
a
detailed
discussion
of
the
fuel
marker
provisions.

136
15
ppm
diesel
fuel
and
high
sulfur
heating
oil
will
be
the
largest
volume
products
at
such
terminals.

137
The
definition
of
a
refiner
includes
persons
who
produce
highway
or
NRLM
diesel
fuel
by
blending.

138
This
fuel
will
be
produced
by
transmix
processors
and
at
terminals
by
segregating
the
pipeline
interface
between
15
ppm
diesel
fuel
and
jet
fuel.

273
heating
oil
and
high­
sulfur
NRLM
will
also
be
fungible
in
the
distribution
system
up
to
the
point
where
the
fuel
marker
must
be
added
at
the
terminal.
135
The
design
of
today's
fuel
program
eliminates
any
potential
feasibility
issues
associated
with
the
need
for
product
segregation.
This
is
not
to
say
that
additional
steps
will
not
have
to
be
taken.
However,
this
program
will
result
in
only
a
limited
number
of
entities
in
the
distribution
system
choosing
to
add
new
tankage
due
to
new
product
segregation.
Bulk
plants
in
areas
of
the
country
where
heating
oil
is
expected
to
remain
in
the
market
will
have
to
decide
whether
to
add
tankage
to
distribute
both
heating
oil
and
500
ppm
sulfur
NRLM
fuel.
Terminal
operators
commented
that
the
proposed
presence
of
a
fuel
marker
in
heating
oil
would
make
it
impossible
for
them
to
blend
500
ppm
sulfur
diesel
from
15
ppm
sulfur
and
high
sulfur
fuels.
They
related
that
this
ability
would
be
important
to
certain
terminal
operators
who
would
not
have
the
storage
facilities
available
for
three
grades
of
diesel
fuel,
but
would
still
not
wish
to
forgo
selling
500
ppm
diesel
fuel.
136
Today's
rule
allows
the
required
marker
to
be
added
to
heating
oil
before
it
leaves
the
terminal
(
see
section
IV.
D
of
this
preamble).
Therefore,
terminals
will
be
able
to
blend
500
ppm
diesel
from
15
ppm
and
high
sulfur
diesel
fuels,
provided
they
fulfill
all
of
the
responsibilities
associated
with
acting
as
a
fuel
refiner
(
see
section
V
of
this
preamble).
137
However,
because
this
will
be
a
relatively
costly
way
of
producing
500
ppm
diesel
fuel,
we
do
not
expect
that
the
practice
will
be
widespread.
In
all
other
cases
we
anticipate
segments
of
the
distribution
system
will
choose
to
avoid
any
fuel
segregation
costs
by
limiting
the
range
of
sulfur
grades
they
choose
to
carry,
just
as
they
do
today.
Regardless,
however,
the
costs
and
impacts
of
these
choices
are
small.
A
more
detailed
explanation
of
this
assessment
can
be
found
in
chapter
7
of
the
RIA.

A
limited
volume
of
500
ppm
sulfur
diesel
fuel
is
projected
to
be
produced
downstream
due
to
interface
mixing
in
the
distribution
system
(
see
section
IV.
A).
138
Fuel
from
these
sources
is
currently
sold
into
the
NRLM
and
heating
oil
markets.
The
implementation
of
the
15
ppm
sulfur
standard
for
NR
diesel
fuel
in
2010
and
for
LM
diesel
fuel
in
2012
raises
the
concern
that
the
heating
oil
market
might
be
insufficient
to
absorb
all
such
downstream
500
ppm
sulfur
diesel
fuel
in
areas
outside
of
the
Northeast
(
where
most
heating
oil
is
used).
If
the
market
for
this
fuel
was
139
While
today's
rule
does
not
contain
an
end
date
for
the
downstream
distribution
of
500
ppm
sulfur
locomotive
and
marine
fuel,
we
will
review
the
appropriateness
of
allowing
this
flexibility
based
on
experience
gained
from
implementation
of
the
15
ppm
sulfur
NRLM
diesel
fuel
standard.
We
expect
to
conduct
such
an
evaluation
in
2011.

140
DoD
Performance
Specification,
Inhibitor,
Corrosion/
Lubricity
Improver,
Fuel
Soluble,

MIL­
PRF­
25017F,
10
November
1997,
Superseding
MIL­
I­
25017E,
15
June
1989.

141
Chevron
Products
Diesel
Fuel
Technical
Review
provides
a
discussion
of
the
impacts
on
fuel
lubricity
of
current
diesel
fuel
compositional
requirements
in
California
versus
the
rest
of
the
nation;

see
http://
www.
chevron.
com/
prodserv/
fuels/
bulletin/
diesel/
l2%
5F7%
5F2%
5Frf.
htm.

274
limited,
it
would
have
to
be
trucked
back
to
a
refinery
to
be
desulfurized
which
could
raise
significant
logistical
and
cost
issues.
Consequently,
today's
rule
provides
that
500
ppm
sulfur
diesel
fuel
produced
due
to
interface
mixing
can
continue
to
be
used
in
nonroad
equipment
until
2014
(
subject
to
specific
sulfur
requirements
for
new
equipment),
and
in
locomotive
and
marine
engines
indefinitely.
139
These
provisions
ensure
that
there
will
be
a
sufficient
market
for
such
500
ppm
sulfur
diesel
fuel.

G.
What
Are
the
Potential
Impacts
of
the
15
ppm
Sulfur
Diesel
Program
on
Lubricity
and
Other
Fuel
Properties?

1.
What
Is
Lubricity
and
Why
Might
it
Be
a
Concern?

Engine
manufacturers
and
owner/
operators
depend
on
diesel
fuel
lubricity
properties
to
lubricate
and
protect
moving
parts
within
fuel
pumps
and
injection
systems
for
reliable
performance.
Unit
injector
systems
and
in­
line
pumps,
commonly
used
in
diesel
engines,
are
actuated
by
cams
lubricated
with
crankcase
oil,
and
have
minimal
sensitivity
to
fuel
lubricity.
However,
rotary
and
distributor
type
pumps,
commonly
used
in
light
and
medium­
duty
diesel
engines,
are
completely
fuel
lubricated,
resulting
in
high
sensitivity
to
fuel
lubricity.
The
types
of
fuel
pumps
and
injection
systems
used
in
nonroad
diesel
engines
are
the
same
as
those
used
in
highway
diesel
vehicles.
Consequently,
nonroad
and
highway
diesel
engines
share
the
same
need
for
adequate
fuel
lubricity
to
maintain
fuel
pump
and
injection
system
durability.

Diesel
fuel
lubricity
concerns
were
first
highlighted
for
private
and
commercial
vehicles
during
the
initial
implementation
of
the
federal
500
ppm
sulfur
highway
diesel
program
and
the
state
of
California's
diesel
program.
The
Department
of
Defense
(
DoD)
also
has
a
longstanding
concern
regarding
the
lubricity
of
distillate
fuels
used
in
its
equipment
as
evidenced
by
the
implementation
of
its
own
fuel
lubricity
improver
performance
specification
in
1989.140
The
diesel
fuel
requirements
in
the
state
of
California
differed
from
the
federal
requirements
by
substantially
restricting
the
aromatic
content
of
diesel
fuel
which
requires
more
severe
hydrotreating
than
reducing
the
sulfur
content
to
meet
a
500
ppm
standard.
141
Consequently,
concerns
regarding
142
The
cost
from
the
increased
use
of
lubricity
additives
in
500
ppm
NRLM
diesel
fuel
in
2007
and
in
15
ppm
nonroad
diesel
fuel
in
2010
and
locomotive
and
marine
diesel
fuel
in
2012
is
discussed
in
section
VI
of
this
preamble.

275
diesel
fuel
lubricity
have
primarily
been
associated
with
California
diesel
fuel
and
some
California
refiners
treat
their
diesel
fuel
with
a
lubricity
additive
as
needed.
Outside
of
California,
hydrotreating
to
meet
the
current
500
ppm
sulfur
specification
does
not
typically
result
in
a
substantial
reduction
of
lubricity.
Diesel
fuels
outside
of
California
seldom
require
the
use
of
a
lubricity
additive.
Therefore,
we
anticipate
only
a
marginal
increase
in
the
use
of
lubricity
additives
in
NRLM
diesel
fuel
meeting
the
500
ppm
sulfur
standard
for
2007.142
Today's
action
requires
diesel
fuel
used
in
nonroad,
locomotive,
and
marine
diesel
engines
to
meet
a
15
ppm
sulfur
standard
in
2010
and
2012,
respectively.
Based
on
the
following
discussion,
we
believe
that
the
increase
in
the
use
of
lubricity
additives
in
15
ppm
sulfur
NRLM
diesel
fuel
would
be
the
same
as
that
estimated
for
15
ppm
highway
diesel
fuel.

The
state
of
California
currently
requires
the
same
standards
for
diesel
fuel
used
in
nonroad
equipment
as
in
highway
equipment.
Outside
of
California,
highway
diesel
fuel
is
often
used
in
nonroad
equipment
when
logistical
constraints
or
market
influences
in
the
fuel
distribution
system
limit
the
availability
of
high
sulfur
fuel.
Thus,
for
nearly
a
decade
nonroad
equipment
has
been
using
federal
500
ppm
sulfur
diesel
fuel
and
California
diesel
fuel,
some
of
which
may
have
been
treated
with
lubricity
additives.
During
this
time,
there
has
been
no
indication
that
the
level
of
diesel
lubricity
needed
for
fuel
used
in
nonroad
engines
differs
substantially
from
the
level
needed
for
fuel
used
in
highway
diesel
engines.

Blending
small
amounts
of
lubricity­
enhancing
additives
increases
the
lubricity
of
poorlubricity
fuels
to
acceptable
levels.
These
additives
are
available
in
today's
market,
are
effective,
and
are
in
widespread
use
around
the
world.
Among
the
available
additives,
biodiesel
has
been
suggested
as
one
potential
means
for
increasing
the
lubricity
of
conventional
diesel
fuel.
Indications
are
that
low
concentrations
of
biodiesel
might
be
sufficient
to
raise
the
lubricity
to
acceptable
levels.
Biodiesel
is
a
renewable
fuel
made
from
agricultural
sources
such
as
soybean
oil,
peanut
oil
and
other
vegetable
oils
as
well
as
rendered
and
animal
fats
and
recycled
cooking
oils.
Biodiesel
generally
contains
very
low
amounts
of
sulfur,
which
is
an
attractive
characteristic
for
use
in
diesel
engines
using
advanced
aftertreatment
systems.
Additionally,
biodiesel,
by
virtue
of
its
lubricity
properties,
may
be
a
good
alternative
to
additives
currently
used
to
ensure
adequate
fuel
lubricity.
According
to
the
U.
S.
Department
of
Agriculture,
there
is
a
current
capacity
to
produce
100
million
gallons
annually.
Thus,
we
believe
that
biodiesel
is
a
feasible
technology
that
could
help
support
today's
clean
diesel
fuel
program.

Research
remains
to
be
performed
to
better
understand
which
fuel
components
are
most
responsible
for
lubricity.
Consequently,
it
is
unclear
whether
and
to
what
degree
the
sulfur
standards
for
NRLM
diesel
fuel
will
impact
fuel
lubricity.
Nevertheless,
there
is
evidence
that
the
typical
process
used
to
remove
sulfur
from
diesel
fuel
 
hydrotreating
 
can
impact
lubricity
143
See
chapter
5
of
the
RIA
for
a
discussion
of
the
potential
impacts
on
fuel
lubricity
of
this
proposal.

144
Nonroad
and
highway
diesel
engines
meeting
similar
emissions
standards
use
similar
fuel
systems
provided
by
common
suppliers.
For
example,
a
nonroad
engine
meeting
the
2001
Tier
2
nonroad
diesel
engine
emission
standards
would
have
the
same
fuel
system
as
a
highway
diesel
engine
meeting
the
1998
highway
diesel
engine
emissions
standards.

276
depending
on
the
severity
of
the
treatment
process
and
characteristics
of
the
crude.
We
expect
that
hydrotreating
will
be
the
predominant
process
used
to
reduce
the
sulfur
content
of
NRLM
diesel
fuel
to
meet
the
500
ppm
sulfur
standard
during
the
first
step
of
the
program.
Similarly,
we
project
that
both
conventional
hydrotreating
and
the
Linde
Isotherming
process
will
be
used
to
meet
the
15
ppm
sulfur
standard
for
NRLM
diesel
fuel.

Based
on
our
comparison
of
the
blendstocks
and
processes
used
to
manufacture
nonhighway
diesel
fuels,
we
believe
that
the
potential
decrease
in
the
lubricity
of
these
fuels
from
hydrotreating
that
might
result
from
the
sulfur
standards
should
be
approximately
the
same
as
that
experienced
in
desulfurizing
highway
diesel
fuel.
143
To
provide
a
conservative,
high
cost
estimate,
we
assumed
that
the
potential
impact
on
fuel
lubricity
from
the
use
of
the
new
desulfurization
processes
would
be
the
same
as
that
experienced
when
hydrotreating
diesel
fuel
to
meet
a
15
ppm
sulfur
standard.
Given
that
the
requirements
for
fuel
lubricity
in
highway
and
nonroad
engines
are
the
same,
and
the
potential
decrease
in
lubricity
from
desulfurization
of
NRLM
diesel
fuel
would
be
no
greater
than
that
experienced
in
desulfurizing
highway
diesel
fuel,
we
estimate
that
the
potential
need
for
lubricity
additives
in
NRLM
diesel
fuel
under
today's
action
would
be
the
same
as
that
for
highway
diesel
fuel
meeting
the
same
sulfur
standard.

a.
Farm
and
Mining
Equipment
The
types
of
fuel
pumps
and
injection
systems
used
in
the
nonroad
diesel
engines
found
in
farm
and
mining
equipment
are
similar
to
those
used
in
highway
diesel
vehicles.
144
The
hydrotreating
process
for
generating
500
ppm
diesel
fuel
will
not
adversely
effect
fuel
injection
equipment
in
farm
and
mining
equipment
based
on
the
use
of
comparable
injection
systems
in
highway
diesel
vehicles.
We
believe
that
the
use
of
lubricity
additives
in
15
ppm
sulfur
NRLM
diesel
fuel
will
be
required
and
result
in
adequate
protection
of
fuel
injection
equipment
and
is
similar
to
that
needed
for
15
ppm
sulfur
highway
diesel
fuel.

b.
Locomotives
One
of
the
locomotive
manufacturers
expressed
concern
in
its
comments
that
low
sulfur
fuel
might
damage
existing
locomotives.
However,
the
manufacturer
provided
no
evidence
to
show
that
such
damage
would
likely
occur.
Locomotives
already
use
a
significant
amount
of
low
sulfur
fuel,
especially
in
California,
and
we
have
not
seen
any
evidence
of
sulfur­
related
problems.
277
The
railroads
expressed
a
similar
concern,
but
acknowledged
that
any
potential
problems
would
be
manageable
with
sufficient
lead
time.
At
this
time,
we
see
no
reason
for
any
special
concern
related
to
locomotives
using
low
sulfur
fuel.

2.
A
Voluntary
Approach
on
Lubricity
In
the
United
States,
there
is
no
government
or
industry
standard
for
diesel
fuel
lubricity.
Therefore,
specifications
for
lubricity
are
determined
by
the
market.
Since
the
beginning
of
the
500
ppm
sulfur
highway
diesel
program
in
1993,
refiners,
engine
manufacturers,
engine
component
manufacturers,
and
the
military
have
been
working
with
ASTM
to
develop
protocols
and
standards
for
diesel
fuel
lubricity
in
its
D
975
specifications
for
diesel
fuel.
ASTM
is
working
towards
a
single
lubricity
specification
that
is
applicable
to
all
diesel
fuel
used
in
any
type
of
engine.
Although
ASTM
has
not
yet
adopted
specific
protocols
and
standards,
refiners
that
supply
the
U.
S.
market
have
been
treating
diesel
fuel
with
lubricity
additives
on
a
batch
by
batch
basis,
when
poor
lubricity
fuel
is
produced.
ASTM's
target
implementation
date
for
this
specification
is
January
1,
2005.

The
potential
need
for
lubricity
additives
in
diesel
fuel
meeting
a
15
ppm
sulfur
specification
was
evaluated
during
the
development
of
EPA's
highway
diesel
rule.
In
response
to
the
proposed
highway
diesel
rule,
all
comments
submitted
regarding
lubricity
either
stated
or
implied
that
the
proposed
sulfur
standard
of
15
ppm
would
likely
cause
the
refined
fuel
to
have
lubricity
characteristics
that
would
be
inadequate
to
protect
fuel
injection
equipment,
and
that
mitigation
measures
such
as
lubricity
additives
would
be
necessary.
However,
the
commenters
suggested
varied
approaches
for
addressing
lubricity.
For
example,
some
suggested
that
we
need
to
establish
a
lubricity
requirement
by
regulation
while
others
suggested
that
the
current
voluntary,
market
based
system
would
be
adequate.
The
Department
of
Defense
recommended
that
we
encourage
the
industry
(
ASTM)
to
adopt
lubricity
protocols
and
standards
before
the
2006
implementation
date
of
the
15
ppm
sulfur
standard
for
highway
diesel
fuel.

The
final
highway
diesel
rule
did
not
establish
a
lubricity
standard
for
highway
diesel
fuel.
We
believe
the
issues
related
to
the
need
for
diesel
lubricity
in
fuel
used
in
nonroad
diesel
engines
are
substantially
the
same
as
those
related
to
the
need
for
diesel
lubricity
for
highway
engines.
Consequently,
we
expect
the
same
industry­
based
voluntary
approach
to
ensuring
adequate
lubricity
in
nonroad
diesel
fuels
that
we
recognized
for
highway
diesel
fuel.
We
believe
the
best
approach
is
to
allow
the
market
to
address
the
lubricity
issue
in
the
most
economical
manner,
while
avoiding
an
additional
regulatory
scheme.
A
voluntary
approach
should
provide
adequate
customer
protection
from
engine
failures
due
to
low
lubricity,
while
providing
the
maximum
flexibility
for
the
industry.
This
approach
would
be
a
continuation
of
current
industry
practices
for
diesel
fuel
produced
to
meet
the
current
federal
and
California
500
ppm
sulfur
highway
diesel
fuel
specifications,
and
benefits
from
the
considerable
experience
gained
since
1993.
It
would
also
include
any
new
specifications
and
test
procedures
that
we
expect
would
be
adopted
by
ASTM
regarding
lubricity
of
NRLM
diesel
fuel
quality.
145
ASTM
sub
committee
D02.
E0.

278
In
any
event,
this
is
an
issue
that
will
be
resolved
to
meet
the
demands
of
the
highway
diesel
market,
and
whatever
resolution
is
reached
for
highway
diesel
fuel
could
be
applied
to
NRLM
diesel
fuel
with
sufficient
advance
notice.
We
are
continuing
to
participate
in
the
ASTM
Diesel
Fuel
Lubricity
Task
Force145
and
will
assist
their
efforts
to
finalize
a
lubricity
standard.
We
are
hopeful
that
ASTM
can
reach
a
consensus
this
summer
at
the
next
meeting
of
the
ASTM's
Lubricity
Task
Force.
If
for
some
reason
ASTM
does
not
take
action
to
set
a
lubricity
specification,
EPA
will
consider
taking
appropriate
action
to
ensure
15
ppm
sulfur
diesel
fuel
has
adequate
lubricity.

3.
What
Other
Impact
Would
Today's
Actions
Have
on
the
Performance
of
Diesel
and
Other
Fuels?

We
do
not
expect
that
the
fuel
program
finalized
today
will
have
any
negative
impacts
on
the
performance
of
diesel
engines
in
the
existing
fleet
which
would
use
the
fuels
regulated
today.

While
the
process
of
lowering
sulfur
levels
to
500
ppm
does
lower
polynuclear
aromatic
hydrocarbons
(
PNAs)
and
total
aromatics
in
general,
it
does
not
achieve
the
near­
zero
levels
previously
seen
in
California.
The
15
ppm
sulfur
standard
will
further
reduce
PNAs,
however,
in
most
diesel
fuel,
there
will
still
be
PNAs
present.
Furthermore,
since
the
1990'
s,
diesel
engine
manufacturers
have
switched
to
alternative
materials
(
such
as
Viton),
which
do
not
experience
leakage
when
PNAs
are
reduced.
We
believe
that
there
will
be
no
issues
with
leaking
fuel
pump
O­
rings
with
the
changes
in
diesel
fuel
sulfur
levels
required
by
this
rulemaking.

The
moderate
reduction
in
PNAs
and
total
aromatics
associated
with
the
hydrotreating
of
diesel
fuel
will
tend
to
increase
the
cetane
index
and
number
of
diesel
fuel.
This
will
improve
the
driveability
of
vehicles
operating
on
this
higher
cetane
diesel
fuel.

We
do
not
expect
any
negative
impacts
on
other
fuels,
such
as
jet
fuel
or
heating
oil.
We
do
expect
that
the
sulfur
levels
of
heating
oil
may
decrease
because
of
this
rulemaking
.
Beginning
in
mid­
2007,
we
expect
that
controlling
NRLM
diesel
fuel
to
500
ppm
sulfur
will
lead
many
pipelines
to
discontinue
carrying
high
sulfur
heating
oil
as
a
separate
grade.
In
areas
served
by
these
pipelines,
heating
oil
users
will
likely
switch
to
500
ppm
sulfur
diesel
fuel.
This
will
reduce
emissions
of
SO
2
and
sulfate
PM
from
furnaces
and
boilers
fueled
with
heating
oil.
The
primary
exception
to
this
will
likely
be
the
Northeast,
where
a
distinct
higher
sulfur
heating
oil
will
still
be
distributed
as
a
separate
fuel.
Also,
we
expect
that
a
small
volume
of
moderate
sulfur
distillate
fuel
will
be
created
during
distribution
from
the
mixing
of
low
sulfur
diesel
fuels
and
higher
sulfur
fuels,
such
as
jet
fuel
in
the
pipeline
interface.
Such
moderate
sulfur
distillate
will
often
be
sold
by
the
terminal
as
high
sulfur
heating
oil,
but
in
fact
its
sulfur
level
will
be
lower
than
that
normally
sold
as
heating
oil.
146
Hydrotreating
diesel
fuel
involves
the
use
of
process
heaters,
which
have
the
potential
to
emit
pollutants
associated
with
combustion,
such
as
NOX,
PM,
CO
and
SO2.
In
addition,
reconfiguring
refinery
processes
to
add
desulfurization
equipment
could
increase
fugitive
VOC
emissions.
The
emissions
increases
associated
with
diesel
desulfurization
would
vary
widely
from
refinery
to
refinery,

depending
on
many
source­
specific
factors,
such
as
crude
oil
supply,
refinery
configuration,
type
of
desulfurization
technology,
amount
of
diesel
fuel
produced,
and
type
of
fuel
used
to
fire
the
process
heaters.

279
H.
Refinery
Air
Permitting
Prior
to
beginning
diesel
desulfurization
projects,
some
refineries
may
be
required
to
obtain
a
preconstruction
permit,
under
the
New
Source
Review
(
NSR)
program,
from
the
applicable
state/
local
air
pollution
control
agency.
146
We
believe
that
today's
program
provides
sufficient
lead
time
for
refiners
to
obtain
any
necessary
NSR
permits
well
in
advance
of
the
applicable
compliance
dates.

Given
that
today's
diesel
sulfur
program
provides
roughly
three
years
of
lead
time
before
the
500
ppm
standard
takes
effect,
we
believe
refiners
will
have
time
to
obtain
any
necessary
preconstruction
permits.
In
addition,
the
experience
gained
by
many
refineries
to
obtain
the
preconstruction
permits
needed
to
comply
with
the
Tier
2
and
highway
diesel
fuel
programs
should
benefit
them
in
obtaining
the
necessary
permits
to
comply
with
today's
new
diesel
fuel
requirements.
Nevertheless,
we
believe
it
is
reasonable
to
continue
our
efforts
under
the
Tier
2
and
highway
diesel
fuel
programs,
to
help
states
in
facilitating
the
issuance
of
permits
under
the
NRLM
diesel
fuel
sulfur
program
whenever
such
assistance
may
be
needed
and
requested.
We
anticipate
that
such
assistance
may
include
both
technical
and
procedural
assistance
as
would
be
provided
by
the
appropriate
EPA
Regional
and
Headquarters
offices.
Finally,
to
facilitate
the
processing
of
permits,
we
encourage
refineries
to
begin
discussions
with
permitting
agencies
and
to
submit
permit
applications
as
early
as
possible.
280
V.
Nonroad,
Locomotive
and
Marine
Diesel
Fuel
Program:
Details
of
the
Compliance
and
Enforcement
Provisions
As
with
earlier
fuel
programs,
we
have
developed
a
comprehensive
set
of
compliance
and
enforcement
provisions
designed
to
promote
effective
and
efficient
implementation
of
this
fuel
program
and
thus
to
achieve
the
full
environmental
potential
of
the
program.
The
compliance
provisions
under
today's
final
rule
are
designed
to
ensure
that
nonroad,
locomotive,
and
marine
diesel
fuel
sulfur
content
requirements
are
met
throughout
the
distribution
system,
from
the
refiner
or
importer
through
to
the
end
user,
subject
to
certain
provisions
applicable
during
the
early
transition
years.
Section
IV
above
describes
our
program
for
the
reduction
of
sulfur
in
nonroad,
locomotive
and
marine
(
NRLM)
diesel
fuel
including
the
standards
and
basic
design
of
the
compliance
and
enforcement
program.
This
section
contains
additional
details
regarding
the
compliance
and
assurance
program.
The
provisions
discussed
in
this
section
fall
into
several
broad
categories:

­
Special
fuel
provisions
and
exemptions;
­
Additional
provisions
applicable
to
refiners
and
importers;
­
Additional
provisions
applicable
to
parties
downstream
of
the
refinery
or
importer;
­
Special
provisions
regarding
additives,
kerosene,
and
the
prohibition
against
the
use
of
motor
oil
in
fuel;
­
Fuel
testing
and
sampling
requirements;
­
Records
required
to
be
kept,
including
those
applying
under
the
designate
and
track,
credit
provisions,
small
refiner,
and
refiner
hardship
provisions;
­
Reporting
requirements;
­
Exemptions
from
the
program;
­
Provisions
concerning
liability,
defenses,
and
penalties
for
noncompliance;
and
­
The
selection
of
the
marker
for
heating
oil
and
500
ppm
sulfur
LM
diesel
fuel.
(
The
specific
requirements
with
respect
to
heating
oil
and
500
ppm
sulfur
LM
diesel
fuel
inside
and
outside
of
the
Northeast/
Mid­
Atlantic
Area
are
discussed
in
section
IV.
D.)

A.
Special
Fuel
Provisions
and
Exemptions
As
discussed
in
section
IV.
A.
1
above,
the
sulfur
standards
in
today's
rule
generally
cover
all
the
diesel
fuel
that
is
intended
for
use
in
or
used
in
nonroad,
locomotive,
and
marine
(
NRLM)
applications
that
is
not
already
covered
by
the
standards
for
highway
diesel
fuel.
For
the
purposes
of
this
preamble,
this
fuel
is
defined
primarily
by
the
type
of
engine
which
it
is
used
to
power:
land­
based
nonroad,
locomotive,
and
marine
diesel
engines.
Section
IV.
A.
1
above
also
describes
several
types
of
petroleum
distillate
that
are
not
covered
by
the
sulfur
standards
promulgated
today,
including
jet
fuel
and
heating
oil,
provided
they
are
not
used
in
NRLM
engines.
The
following
paragraphs
discuss
several
provisions
and
exemptions
for
NRLM
diesel
fuel
that
will
apply
in
special
circumstances.
281
1.
Fuel
Used
in
Military
Applications
NRLM
diesel
fuel
used
in
military
applications
is
treated
in
the
same
manner
as
under
the
recent
highway
diesel
rule.
Refiners
are
not
required
to
produce
these
fuels
to
the
NRLM
standards.
However,
at
the
same
time,
their
use
is
limited
only
to
certain
military
applications.
NRLM
diesel
fuel
is
defined
so
that
JP­
5,
JP­
8,
F76,
and
any
other
military
fuel
that
is
used
or
intended
for
use
in
NRLM
diesel
engines
or
equipment
is
initially
subject
to
all
of
the
requirements
applicable
to
NRLM
diesel
fuel.
However,
today's
rule
also
exempts
these
military
fuels
from
the
diesel
fuel
sulfur
content
and
other
requirements
in
certain
circumstances.
First,
these
fuels
are
exempt
if
they
are
used
in
tactical
military
motor
vehicles
or
nonroad
engines,
or
equipment
that
have
a
national
security
exemption
from
the
vehicle
or
engine
emissions
standards.
Due
to
national
security
considerations,
EPA's
existing
regulations
allow
the
military
to
request
and
receive
national
security
exemptions
(
NSE)
for
their
motor
vehicles
and
NRLM
diesel
engines
and
equipment
from
emissions
regulations
if
the
operational
requirements
for
such
vehicles,
engines,
or
equipment
warrant
such
an
exemption.
This
final
rule
does
not
change
these
provisions.
Fuel
used
in
these
applications
is
exempt.
Second,
these
fuels
are
also
exempt
if
they
are
used
in
tactical
military
vehicles,
engines,
or
equipment
that
are
not
covered
by
a
national
security
exemption
but,
for
national
security
reasons
(
such
as
the
need
to
be
ready
for
immediate
deployment
overseas),
these
vehicles,
engines,
and
equipment
need
to
be
fueled
on
the
same
fuel
as
vehicles,
engines,
or
equipment
with
a
national
security
exemption.
Use
of
JP­
5,
JP­
8,
F76,
or
any
other
fuel
not
meeting
NRLM
diesel
fuel
standards
in
a
motor
vehicle
or
NRLM
diesel
engine
or
equipment
other
than
the
those
described
above
is
prohibited
under
today's
rule.

EPA
and
the
Department
of
Defense
have
developed
a
process
to
address
the
tactical
vehicles,
engines,
and
equipment
covered
by
the
diesel
fuel
exemption
and
are
discussing
whether
changes
to
it
might
be
appropriate.
Based
on
data
provided
by
the
Department
of
Defense
to
date
in
the
context
of
implementing
a
similar
exemption
provision
in
the
highway
program,
EPA
believes
that
providing
an
exemption
for
military
fuel
used
in
tactical
nonroad
engines
and
equipment
will
not
have
any
significant
environmental
impact.

The
Department
of
Defense
(
DoD)
commented
that
EPA
should
reconsider
its
determination
that
the
definition
of
diesel
fuel
includes
JP8
and
JP5.
DoD
cited
a
1995
letter
from
EPA
which
stated
that
there
was
insufficient
reason
to
conclude
that
JP­
8
is
commonly
and
commercially
known
as
diesel
fuel
under
the
then
applicable
definition
of
motor
vehicle
diesel
fuel.
Since
the
time
of
this
letter,
EPA
has
become
aware
of
a
substantial
number
of
cases
of
the
misuse
of
aviation
turbine
fuel
in
highway
engines.
The
potential
for
misuse
of
JP­
8
or
similar
fuels
in
NRLM
equipment
where
no
national
security
exemption
exists
would
remain.
To
ensure
that
NRLM
equipment
is
properly
fueled
with
low
sulfur
fuel,
the
definition
of
NRLM
diesel
fuel
has
been
written
to
encompass
all
diesel
or
other
distillate
fuels
used
or
intended
for
use
in
NRLM
engines,
which
would
include
JP­
8
and
JP­
5.
Furthermore,
the
provisions
in
today's
rule
allow
vehicles,
engines,
and
equipment
to
be
fueled
with
military
specification
fuels
that
are
exempt
from
the
sulfur
standards
when
needed
for
national
security.
We
believe
that
this
provides
DoD
with
the
282
needed
flexibility
to
meet
its
goals
of
keeping
vehicles,
engines,
and
equipment
ready
for
quick
deployment
overseas.

2.
Fuel
Used
in
Research,
Development,
and
Testing
Today's
final
rule
permits
parties
to
request
an
exemption
from
the
sulfur
or
other
standards
for
NRLM
diesel
fuel
used
for
research,
development
and
testing
purposes
("
R
&
D
exemption").
We
recognize
that
there
may
be
legitimate
research
programs
that
require
the
use
of
diesel
fuel
with
higher
sulfur
levels
than
allowed
under
today's
rule.
As
a
result,
this
final
rule
contains
provisions
for
obtaining
an
exemption
from
the
prohibitions
for
persons,
producing,
distributing,
transporting,
storing,
selling,
or
dispensing
NRLM
diesel
fuel
that
exceeds
the
standards,
where
such
diesel
fuel
is
necessary
to
conduct
a
research,
development,
or
testing
program.

Parties
seeking
an
R
&
D
exemption
must
submit
an
application
for
exemption
to
EPA
that
describes
the
purpose
and
scope
of
the
program,
and
the
reasons
why
higher­
sulfur
diesel
fuel
is
necessary.
Upon
presentation
of
the
required
information,
an
exemption
can
be
granted
at
the
discretion
of
the
Administrator,
with
the
condition
that
EPA
can
withdraw
the
exemption
in
the
event
the
Agency
determines
the
exemption
is
not
justified.
In
addition,
an
exemption
based
on
false
or
inaccurate
information
will
be
considered
void
ab
initio.
Fuel
subject
to
an
exemption
is
exempt
from
certain
provisions
of
this
rule,
including
the
sulfur
standards,
provided
certain
requirements
are
met.
These
requirements
include
the
segregation
of
the
exempt
fuel
from
nonexempt
NRLM
and
highway
diesel
fuel,
identification
of
the
exempt
fuel
on
PTDs,
pump
labeling,
and
where
appropriate,
the
replacement,
repair,
or
removal
from
service
of
emission
systems
damaged
by
the
use
of
the
high
sulfur
fuel.

3.
Fuel
Used
in
Racing
Equipment
There
are
no
provisions
for
an
exemption
from
the
sulfur
or
other
content
standard
and
other
requirements
for
diesel
fuel
used
in
racing
in
today's
final
rule.
Under
certain
conditions,
racing
vehicles
are
not
considered
nonroad
vehicles.
See,
for
example,
40
CFR
§
89.2,
definition
of
"
nonroad
vehicle."
The
fuel
used
by
such
racing
vehicles
would
not
necessarily
be
considered
nonroad
diesel
fuel.
However,
we
believe
that
there
is
a
realistic
chance
that
such
fuel
also
could
be
used
in
NRLM
equipment,
and
therefore,
should
be
considered
NRLM
diesel
fuel.
We
received
no
comments
supporting
the
need
for
an
exemption
for
racing
fuel.
We
are
not
aware
of
any
advantage
for
racing
vehicles
or
racing
equipment
to
use
fuel
having
higher
sulfur
levels
than
are
required
by
this
rule,
and
we
are
concerned
about
the
potential
for
misfueling
of
nonroad
equipment
and
motor
vehicles
that
could
result
from
having
a
high
sulfur
(
e.
g.,
3,000
ppm)
fuel
for
vehicle
or
nonroad
equipment
available
in
the
marketplace.
Consequently,
as
was
the
case
with
the
highway
diesel
rule,
this
final
rule
does
not
provide
an
exemption
from
the
nonroad
diesel
fuel
requirements
for
fuel
used
in
racing
vehicles
or
equipment.
283
4.
Fuel
for
Export
Fuel
produced
for
export,
and
that
is
actually
exported
for
use
in
a
foreign
country,
is
exempt
from
the
fuel
content
standards
and
other
requirements
of
this
final
rule.
Such
fuel
will
be
considered
as
intended
for
use
in
the
U.
S.
and
subject
to
the
standards
in
today's
rule
unless
it
is
designated
by
the
refiner
as
for
export
only
and
PTDs
state
that
the
fuel
is
for
export
only.
Fuel
intended
for
export
must
be
segregated
from
all
fuel
intended
for
use
in
the
U.
S.,
and
distributing
or
dispensing
such
fuel
for
domestic
use
is
illegal.

B.
Additional
Requirements
for
Refiners
and
Importers
The
primary
requirements
for
refiners
and
importers
under
today's
final
rule
are
discussed
in
section
IV
above.
In
that
section,
we
discuss
the
general
structure
of
the
compliance
and
enforcement
provisions
applicable
to
refiners
and
importers,
including
fuel
content
standards,
fuel
volume
designation
and
tracking
provisions,
and
credit
provisions.
In
this
subsection,
we
discuss
several
additional
requirements
for
refiners
and
importers
that
are
not
addressed
in
section
IV.
In
addition,
sections
V.
G,
V.
H,
and
V.
I
below
discuss
several
provisions
that
apply
to
all
parties
in
the
diesel
fuel
production
and
distribution
system,
including
refiners
and
importers.

1.
Transfer
of
Credits
This
final
rule
includes
provisions
for
NRLM
diesel
sulfur
credit
transfers
that
are
essentially
identical
to
other
fuels
rules
that
have
credits
provisions.
As
in
other
fuels
rules,
NRLM
diesel
sulfur
credits
can
only
be
transferred
between
the
refiner
or
importer
generating
the
credits
and
the
refiner
or
importer
using
the
credits.
If
a
credit
purchaser
can
not
use
all
the
credits
it
purchased
from
the
refiner
who
generated
them,
the
credits
can
be
transferred
one
additional
time.
We
recognize
that
there
is
potential
for
credits
to
be
generated
by
one
party
and
subsequently
purchased
and
used
in
good
faith
by
another
party,
where
the
credits
are
later
found
to
have
been
calculated
or
created
improperly,
or
otherwise
found
to
be
invalid.
As
with
the
reformulated
gasoline
rule,
the
Tier
2/
Gasoline
Sulfur
rule,
and
the
highway
diesel
sulfur
rule,
invalid
credits
purchased
in
good
faith
are
not
valid
for
use
by
the
purchaser.
To
allow
such
use
would
not
be
consistent
with
the
environmental
goals
of
the
regulation.
In
addition,
both
the
seller
and
purchaser
of
invalid
credits
must
adjust
their
credit
calculations
to
reflect
the
proper
credits
and
either
party
(
or
both)
can
be
deemed
in
violation
if
the
adjusted
calculations
demonstrated
noncompliance.
We
expect
that
the
parties
to
such
a
credit
transaction
will
develop
contractual
provisions
to
address
these
circumstances.

Nevertheless,
in
a
situation
where
invalid
credits
are
transferred,
our
strong
preference
will
be
to
hold
the
credit
seller
liable
for
the
violation,
rather
than
the
credit
purchaser.
As
a
general
matter
we
expect
to
enforce
a
shortfall
in
credit
compliance
calculations
against
the
credit
seller,
and
we
expect
to
enforce
a
compliance
shortfall
(
caused
by
the
good
faith
purchase
of
invalid
credits)
against
a
good
faith
purchaser
only
in
cases
where
we
are
unable
to
recover
sufficient
valid
credits
from
the
seller
to
cover
the
shortfall.
Moreover,
in
settlement
of
such
cases
we
will
284
strongly
encourage
the
seller
to
purchase
credits
to
cover
the
good
faith
purchaser's
credit
shortfall.
EPA
will
consider
the
covering
of
a
credit
deficit
through
the
purchase
of
valid
credits
a
very
important
factor
in
mitigation
of
any
case
against
a
good
faith
purchaser,
whether
the
purchase
of
valid
credits
is
made
by
the
seller
or
by
the
purchaser.

2.
Additional
Provisions
for
Importers
and
Foreign
Refiners
Subject
to
the
Credit
Provisions
or
Hardship
Provisions
Since
this
final
rule
includes
several
compliance
options
that
can
be
used
by
NRLM
diesel
fuel
importers
and
foreign
refiners,
we
are
also
finalizing
specific
compliance
and
enforcement
provisions
to
ensure
compliance
for
imported
NRLM
diesel
fuel.
These
additional
foreign
refiner
provisions
are
similar
to
those
under
the
gasoline
anti­
dumping
regulations,
the
gasoline
sulfur
regulations
and
the
highway
diesel
fuel
regulations
(
see
40
CFR
§
80.94,
§
80.410,
and
§
80.620).

Under
today's
final
rule,
the
per
gallon
standards
for
NRLM
diesel
fuel
produced
by
refineries
owned
by
foreign
refiners
must
be
met
by
the
importer,
unless
the
foreign
refiner
has
been
approved
to
produce
NRLM
diesel
fuel
under
the
credit
provisions,
small
refiner
provisions
or
hardship
provisions
of
this
final
rule.
If
the
foreign
refiner
is
approved
under
any
of
these
provisions,
the
volume
and
other
requirements
must
be
met
by
the
foreign
refiner
for
its
refinery(
s)
and
the
foreign
refiner
must
be
the
entity(
s)
generating,
using,
banking
or
trading
any
credits
for
the
NRLM
diesel
fuel
produced
for
and
imported
into
the
U.
S.
Importers
themselves
are
not
eligible
for
small
refiner
or
hardship
relief
as
they
do
not
face
the
same
capital
cost
and
lead­
time
issues
faced
by
refiners.
Importers
may
participate
in
the
credit
programs,
however,
an
importer
and
a
foreign
refiner
may
not
generate
credits
for
the
same
fuel.

Any
foreign
refiner
that
produces
NRLM
diesel
fuel
subject
to
the
credit
provisions,
small
refiner
provisions
or
the
hardship
provisions
will
be
subject
to
the
same
requirements
as
domestic
refiners
operating
under
the
same
provisions.
Additionally,
provisions
for
foreign
refiners
exist
that
are
similar
to
the
provisions
at
40
CFR
§
80.94,
§
80.410,
and
§
80.620,
which
include:

­
Segregation
of
NRLM
diesel
fuel
produced
at
the
foreign
refinery
until
it
reaches
the
U.
S.
and
separate
tracking
of
volumes
imported
into
each
PADD;
­
Controls
on
product
designation;
­
Load
port
and
port
of
entry
testing;
and
­
Requirements
regarding
bonds
and
sovereign
immunity.

These
provisions
will
aid
the
Agency
in
tracking
NRLM
diesel
fuel
from
the
foreign
refinery
to
its
point
of
import
into
this
country.
We
believe
these
provisions
are
necessary
and
sufficient
to
ensure
that
foreign
refiners'
compliance
can
be
monitored
and
that
the
diesel
fuel
requirements
in
today's
rule
can
be
enforced
against
foreign
refiners.
147
Volumes
of
previously
designated
diesel
fuel
would
be
reported
as
volumes
received
under
the
designate
and
track
provisions
of
Section
IV.
D.

148
Importer/
refiners
availing
themselves
of
the
DTAB
provisions
are
still
subject
to
the
downgrading
provisions,
and
other
provisions
applicable
to
any
importer
or
refiner.

285
3.
Diesel
Fuel
Treated
as
Blendstock
(
DTAB)

Under
today's
program,
a
situation
could
arise
for
importers
where
fuel
that
was
expected
to
comply
with
the
15
ppm
sulfur
NRLM
standard
is
found
to
be
slightly
higher
in
sulfur
than
the
standard.
Rather
than
require
that
importer
to
account
for,
and
report,
that
fuel
as
500
ppm
sulfur
fuel,
an
importer
will
be
able
to
designate
the
non­
complying
fuel
as
blendstock
 
"
diesel
fuel
treated
as
blendstock"
or
DTAB
 
rather
than
as
NRLM
diesel
fuel.
In
its
capacity
as
a
refiner,
the
party
can
then
blend
this
DTAB
fuel
with
lower
sulfur
diesel
fuel
or
with
other
blendstocks
to
cause
the
sulfur
level
of
the
combined
product
to
meet
the
15
ppm
sulfur
NRLM
diesel
fuel
standard
prior
to
delivery
to
another
entity.
The
same
situation
exists
with
respect
to
compliance
with
the
15
ppm
sulfur
highway
standard.
However,
no
provision
was
made
in
the
2007
highway
final
rule
for
this.
Consequently,
we
are
also
finalizing
these
DTAB
provisions
in
this
final
rule
for
application
to
15
ppm
sulfur
highway
diesel
fuel.

Where
diesel
fuel
that
has
been
previously
designated
by
a
refiner
is
used
to
reduce
the
sulfur
level
of
the
DTAB
to
15
ppm
or
less,
the
party,
in
its
refiner
capacity,
is
required
to
report
only
the
volume
of
the
imported
DTAB
as
the
amount
of
diesel
fuel
produced.
147
This
avoids
the
double
counting
that
would
result
if
the
same
diesel
fuel
is
reported
twice
(
i.
e.,
once
by
the
refiner
who
originally
produced
it
and
again
by
the
refiner
using
it
to
blend
with
DTAB).
If
the
product
that
is
blended
with
the
DTAB
is
not
previously
designated
diesel
fuel,
but
is
also
blendstock,
the
total
combined
volume
of
the
DTAB
and
other
blendstock
constitutes
the
batch
produced.

When
an
importer
classifies
diesel
fuel
as
DTAB,
that
DTAB
does
not
count
toward
the
importer's
calculations
under
the
highway
diesel
rule's
temporary
compliance
option,
toward
credit
generation
or
use,
or
for
volume
account
balance
compliance
calculations
(
see
section
IV).
148
The
same
party,
however,
must
include
the
DTAB
in
such
calculations
in
its
capacity
as
a
refiner.
We
believe
such
an
approach
will
increase
the
supply
of
15
ppm
sulfur
fuel
by
reducing
the
volume
of
near­
compliant
fuel
that
is
downgraded
to
higher
sulfur
designations.
In
essence,
it
allows
importers
the
same
flexibility
that
refiners
have
within
their
refinery
gate.

Similar
to
the
provisions
discussed
above
regarding
the
manufacture
of
15
ppm
sulfur
diesel
fuel
using
DTAB,
500
ppm
sulfur
NRLM
and
highway
diesel
fuel
can
also
be
manufactured
using
DTAB
provided
that
this
is
appropriately
reflected
in
the
importer's
compliance
calculations.
149
An
owner/
operator
of
a
tanker
truck
that
delivers
fuel
directly
from
the
tanker
truck
tank
into
motor
vehicles
or
nonroad
equipment
of
another
business
entity
(
i.
e.
a
mobile
refueler)
would
be
acting
as
a
retailer,
and
the
truck
would
be
operating
as
a
retail
outlet.
In
other
words,
the
term
retail
outlet
is
not
limited
to
stationary
facilities.
EPA
proposed
specific
textual
changes
to
the
definition
of
retail
outlet
to
clarify
this,
but
has
decided
there
is
no
need
to
change
the
definition,
as
it
has
always
had
this
plain
meaning.
The
owner/
operator
of
such
a
tanker
truck
may
also
be
subject
to
distributor
requirements
and
prohibitions,
or
carrier
responsibilities
if
the
trucker
company
does
not
take
title
to
the
fuel.
As
the
definitions
in
40
CFR
80.2
make
clear,
it
is
the
functions
performed
by
the
owner/
operator
that
determine
whether
they
come
within
the
scope
of
the
applicable
definitions,
and
the
resulting
obligations
or
requirements
that
apply.
Mobile
refuelers
are
not
subject
to
the
labeling
requirements
applicable
to
other
retailers
but
are
required
to
provide
PTDs
to
their
customers.

150
For
example:
Once
the
required
marker
is
added
to
heating
oil
at
the
terminal,
heating
oil
must
be
segregated
from
all
other
fuel
grades.
Once
red
dye
is
added
to
NRLM
it
must
be
segregated
from
highway
diesel
fuel.

286
C.
Requirements
for
Parties
Downstream
of
the
Refinery
or
Import
Facility
In
order
for
the
environmental
benefits
of
the
NRLM
diesel
program
to
be
realized,
parties
in
the
fuel
distribution
system
downstream
of
the
refinery
(
including
pipelines,
terminals,
bulk
plants,
wholesale
purchaser­
consumers,
and
retailers149)
must
ensure
that
the
sulfur
level
of
fuels
supplied
to
the
various
end­
users
covered
by
today's
rule
complies
with
the
requirements
in
today's
rule.
At
certain
points
in
the
distribution
system,
such
parties
must
keep
the
various
grades
of
fuel
having
different
sulfur
specifications
physically
separate,
150
and
ensure
that
the
fuel
is
properly
designated
and
labeled.
In
other
words,
fuel
represented
as
15
ppm
sulfur
must
comply
with
the
15
ppm
sulfur
standard,
and
fuel
represented
as
500
ppm
sulfur
must
meet
the
500
ppm
sulfur
standard.
At
other
points
in
the
distribution
system,
certain
fuels
may
be
commingled
provided
that
the
fuel
volumes
are
appropriately
designated
and
accounted
for
in
the
custody
holders
volume
account
balance.
Owners
and
operators
of
NRLM
diesel
equipment
must
also
use
fuels
meeting
specific
sulfur
content
standards.
The
following
paragraphs
discuss
several
provisions
that
apply
to
these
parties:
distribution
of
various
fuel
sulfur
grades;
diesel
fuel
pump
labeling;
use
of
used
motor
oil
in
diesel
fuel;
use
of
kerosene
in
diesel
fuel;
use
of
additives
in
diesel
fuel;
requirements
for
end
users;
and
provisions
covering
downgrading
of
undyed
diesel
fuel
to
different
grades
of
fuel.
These
provisions
are
analogous
to
similar
provisions
that
apply
to
highway
diesel
fuel
under
the
highway
program.
Section
IV
discusses
in
detail
the
provisions
applicable
to
downstream
parties
under
the
designate
and
track
program.
151
Fuel
produced
in
the
distribution
system
that
meets
a
500
ppm
sulfur
specification
may
be
used
in
NRLM
equipment
through
June
1,
2014,
and
in
locomotive
and
marine
equipment
thereafter.

152
This
requirement
becomes
effective
June
1,
2006
to
support
the
anti­
downgrade
requirements
in
the
highway
diesel
rule.

287
1.
Product
Segregation
and
End
Use
Requirements
The
main
requirements
for
compliance
with
the
fuel
sulfur
standards
under
today's
rule,
including
the
designate
and
track
provisions,
are
discussed
in
section
IV
of
today's
preamble.
The
sulfur
content
of
all
fuels
subject
to
the
sulfur
requirements
in
today's
rule
must
be
appropriately
represented
(
designated/
classified/
labeled)
at
all
times
through
to
the
retailer
or
wholesale
purchaser
consumer.
Furthermore,
the
designation
and
classification
information
on
the
label
and
PTD,
and
the
actual
sulfur
content
of
any
subject
fuel
must
be
consistent
with
the
requirements
detailed
in
section
IV.
Section
IV
also
details
how
to
accurately
redesignate,
reclassify,
and
relabel
fuel
volumes.
This
subsection
discusses
the
various
grades
and
uses
of
NRLM
fuel
under
the
NRLM
diesel
program.
In
later
subsections,
we
discuss
related
requirements
for
PTDs
to
identify
fuels
throughout
the
distribution
system
and
provisions
relating
to
the
liability
that
all
parties
in
the
distribution
face
for
failing
to
maintain
the
standards
of
these
different
fuel
sulfur
grades.

a.
The
Period
From
June
1,
2007
through
May
31,
2010
From
June
1,
2007
through
May
31,
2010,
all
fuel
used
in
NRLM
equipment
must
meet
a
500
ppm
sulfur
standard
except
for
fuel
produced
or
imported
under
the
hardship,
small
refiner,
and
credit
provisions.
151
Outside
of
the
Northeast/
Mid­
Atlantic
Area
and
Alaska,
we
will
not
be
able
to
rely
upon
the
measurement
of
sulfur
content
alone
to
enforce
the
segregation
requirements
for
heating
oil,
and
are
therefore
requiring
that
heating
oil
be
marked
before
it
leaves
the
terminal
by
the
addition
of
6
mg/
L
of
SY­
124.
Fuel
containing
more
than
0.1
mg/
L
of
the
marker
will
be
deemed
to
be
heating
oil
and
may
not
be
used
as
nonroad,
locomotive
or
marine
fuel.

NRLM
fuel
designated
or
labeled
as
500
ppm
sulfur
must
meet
the
500
ppm
sulfur
standard
and
any
fuel
designated
or
labeled
as
15
ppm
must
meet
the
15
ppm
sulfur
standard.
152
If
a
fuel
meeting
these
standards
is
mixed
or
contaminated
with
a
higher
sulfur
fuel
it
must
be
downgraded
to
the
higher
sulfur
product
and
new
documentation
(
e.
g.,
PTD,
label)
must
be
created
to
reflect
the
downgrade.
During
this
period
there
will
also
be
nonroad
equipment
that
is
expected
to
be
equipped
with
sulfur
sensitive
emissions
control
technology
that
needs
to
operate
on
500
ppm
sulfur
or
less
fuel
in
order
to
meet
the
NRLM
program's
emission
standards
in­
use.
Fuels
sold
for
use
in,
or
dispensed
into,
these
engines
must
be
identified
as
meeting
the
15
ppm
sulfur
standard
or
the
500
ppm
sulfur
standard,
as
applicable,
and
if
so
identified
must
meet
such
standard.
Distributors
and
retailers
must
avoid
contaminating
fuel
represented
by
them
on
PTDs
or
pump
labels
as
15
ppm
sulfur
fuel
or
500
ppm
sulfur
fuel
with
higher
sulfur
fuels.
End
users
are
required
to
use
only
the
fuel
grades
identified
as
appropriate
for
use
on
the
label
affixed
to
their
NRLM
equipment.
153
Such
500
ppm
sulfur
downstream
flexibility
nonroad
diesel
fuel
may
be
also
be
used
in
LM
equipment
since
it
complies
with
the
LM
sulfur
standard
applicable
during
this
time
period.
Thus,
both
marked
and
unmarked
500
ppm
sulfur
fuel
may
be
used
in
LM
equipment
during
this
time
period.

154
These
flexibilities
do
not
exist
in
the
Northeast/
Mid­
Atlantic
Area,
and
only
the
small
refiner
option
exists
in
Alaska.

288
b.
The
Period
From
June
1,
2010
through
May
31,
2012
Beginning
June
1,
2010,
all
fuel
used
in
nonroad
equipment
must
meet
a
15
ppm
sulfur
standard
except
for
500
ppm
sulfur
fuel
produced
or
imported
under
the
hardship,
small
refiner,
and
credit
provisions,
or
downstream
flexibility
provisions
which
may
continue
to
be
used
in
nonroad
engines
produced
prior
to
2011.
Locomotive
and
marine
fuel
will
continue
to
be
subject
to
the
sulfur
requirements
applicable
beginning
June
1,
2007,
until
May
31,
2012.

During
this
time
period,
we
will
not
be
able
to
rely
upon
the
measurement
of
sulfur
content
alone
to
enforce
the
segregation
requirements
for
LM
fuel
and
NR
500
ppm
sulfur
fuel
outside
of
the
Northeast/
Mid­
Atlantic
Area
and
Alaska,
and
are
therefore
requiring
that
LM
fuel
produced
or
imported
for
use
outside
of
the
Northeast/
Mid­
Atlantic
Area
and
Alaska
be
marked
before
it
leaves
the
terminal
by
the
addition
of
6
mg/
L
of
SY­
124.
Fuel
containing
more
than
0.1
mg/
L
of
the
marker
will
be
deemed
to
be
either
LM
fuel
or
heating
oil
and
may
not
be
used
as
nonroad
fuel.
Fuel
containing
the
marker
that
meets
a
500
ppm
sulfur
standard
will
be
deemed
to
be
LM
fuel,
whereas
fuel
containing
the
marker
with
a
sulfur
content
above
500
ppm
will
be
deemed
to
be
heating
oil.

As
discussed
in
section
IV
above,
small
refiners
will
be
able
to
continue
to
produce
500
ppm
sulfur
nonroad
fuel,
through
May
31,
2014.
Other
refiners
may
use
credits
through
May
31,
2014
to
continue
to
produce
fuel
to
the
500
ppm
sulfur
nonroad
diesel
fuel
standard.
Nonroad
diesel
fuel
meeting
a
500
ppm
sulfur
standard
may
also
be
produced
due
to
interface
mixing
in
the
distribution
system.
153
In
any
case,
15
ppm
sulfur
diesel
fuel
must
be
segregated
from
500
ppm
sulfur
NRLM
diesel
fuel
throughout
the
distribution
system
including
the
end
user,
such
that
it
maintains
its
designation,
or
it
must
be
redesignated
and
labeled
to
its
downgraded
specification.
154
Because
of
the
sulfur
sensitivity
of
the
expected
engine
emission
control
systems
beginning
in
model
year
2011
for
nonroad
diesel
engines,
it
is
imperative
that
the
distribution
system
segregate
nonroad
diesel
fuel
subject
to
the
15
ppm
sulfur
standard
from
higher
sulfur
distillate
products,
such
as
500
ppm
sulfur
LM
fuel,
500
ppm
sulfur
nonroad
diesel
fuel
produced
by
small
refiners
or
through
the
use
of
credits,
heating
oil,
and
jet
fuel.
End
users
are
required
to
use
only
the
fuel
grades
identified
as
appropriate
for
use
on
the
label
affixed
to
their
NR
and
LM
equipment.
155
Allowing
four
months
for
the
LM
fuel
distribution
system
to
sufficiently
purge
itself
of
marked
fuel
is
consistent
with
the
time
allowed
for
LM
diesel
fuel
to
comply
with
a
500
ppm
sulfur
standard
after
the
refinery
gate
15
ppm
sulfur
standard
for
LM
fuel
becomes
effective.

289
We
are
also
concerned
about
potential
misfueling
of
engines
requiring
15
ppm
sulfur
fuel
at
retail
or
wholesale
purchaser­
consumer
facilities
(
as
defined
under
this
program),
or
other
end­
user
facilities,
even
when
segregation
of
15
ppm
sulfur
fuel
from
the
higher­
sulfur
grades
of
diesel
fuel
has
been
maintained
in
the
distribution
system.
Thus,
downstream
compliance
and
enforcement
provisions
of
this
rule
are
aimed
at
both
preventing
contamination
of
nonroad
diesel
fuel
subject
to
the
15
ppm
sulfur
standard
(
i.
e.,
fuel
represented
to
meet
that
standard)
and
preventing
misfueling
of
new
nonroad
equipment.

c.
The
Period
From
June
1,
2012
through
May
31,
2014
Beginning
June
1,
2012,
all
fuel
used
in
locomotive
and
marine
equipment
must
meet
a
15
ppm
sulfur
standard
except
for
500
ppm
sulfur
fuel
produced
or
imported
under
the
hardship,
small
refiner,
and
credit
provisions,
or
downstream
flexibility
provisions.
As
discussed
in
section
IV
above,
small
refiners
will
be
able
to
continue
to
produce
500
ppm
sulfur
LM
fuel,
through
May
31,
2014.
Other
refiners
may
use
credits
through
May
31,
2014
to
continue
to
produce
fuel
to
the
500
ppm
sulfur
LM
diesel
fuel
standard.
Locomotive,
and
marine
diesel
fuel
meeting
a
500
ppm
sulfur
standard
may
also
be
produced
due
to
interface
mixing
in
the
distribution
system
indefinitely.

The
marker
requirement
for
500
ppm
sulfur
LM
diesel
fuel
expires
on
June
1,
2012.
After
June
1,
2012,
only
heating
oil
must
continue
to
be
marked
and
any
LM
diesel
fuel
distributed
from
the
terminal
must
not
contain
the
marker.
To
allow
marked
LM
diesel
fuel
distributed
prior
to
June
1,
2012
to
be
consumed
by
end­
users,
the
downstream
prohibition
against
LM
fuel
containing
the
marker
will
not
become
effective
until
October
1,
2012.
Beginning
October
1,
2012,
LM
diesel
fuel
at
any
location
must
contain
no
more
that
0.1
mg/
L
of
the
marker.
155
We
believe
that
allowing
four
months
for
downstream
parties
to
blend
down
their
stocks
of
marked
LM
diesel
fuel
with
receipts
of
unmarked
LM
diesel
fuel
will
be
sufficient
for
such
parties
to
comply
with
the
prohibition
against
possessing
LM
fuel
with
a
marker
concentration
greater
than
0.1
mg/
L.

The
requirements
that
became
effective
for
fuel
used
in
nonroad
equipment
on
June
1,
2010,
will
remain
effective
until
May
31,
2014.

d.
After
May
31,
2014
After
the
small
refiner,
credit,
and
off­
specification
fuel
flexibilites
have
expired,
the
remaining
sulfur
grades
of
diesel
fuel
will
be
15
ppm
sulfur
highway
and
NRLM
fuel,
500
ppm
sulfur
LM
diesel
fuel
(
produced
due
to
interface
mixing
in
the
distribution
system
outside
of
the
Northeast/
Mid­
Atlantic
Area
and
Alaska),
and
heating
oil,
some
of
which
may
meet
a
500
ppm
sulfur
standard.
Product
transfer
documents
are
required
to
accompany
the
batches
of
such
fuels
156
In
the
highway
diesel
rule,
the
term
"
high­
sulfur"
means
diesel
fuel
with
a
sulfur
level
greater
than
15
ppm,
whereas
in
this
rule
it
means
diesel
fuel
with
a
sulfur
level
greater
than
500
ppm.
In
the
highway
diesel
rule,
the
term
"
low­
sulfur"
means
diesel
fuel
with
a
sulfur
level
less
than
or
equal
to
15
ppm,
whereas
in
this
rule
it
means
diesel
fuel
with
a
sulfur
level
less
than
or
equal
to
500
ppm.
In
addition,
the
term
"
nonroad"
as
used
in
the
highway
diesel
rule
means
"
non­
highway"
(
i.
e.,
all
fuel
that
is
not
highway
fuel),
but
the
term
"
nonroad"
as
used
in
this
rule
does
not
include
locomotive
diesel,
marine
diesel
and
heating
oil.

290
which
must
contain
the
specified
identifying
information.
Highway
and
NRLM
diesel
fuel
meeting
a
15
ppm
sulfur
specification
must
be
segregated
from
500
ppm
sulfur
LM
diesel
fuel,
and
heating
oil.
Today's
rule
contains
provisions
for
the
fungible
shipment
of
LM
diesel
fuel
with
any
heating
oil
meeting
a
500
ppm
sulfur
cap
up
to
the
point
where
the
fuel
leaves
the
terminal
that
are
similar
to
the
provisions
that
allow
the
fungible
shipment
of
high
sulfur
NRLM
diesel
fuel
and
high
sulfur
heating
oil
discussed
in
the
previous
section.
Under
such
circumstances
the
designate
and
track
and
heating
oil
account
balance
requirements
must
be
satisfied.

2.
Diesel
Fuel
Pump
Labeling
to
Discourage
Misfueling
For
any
multiple­
fuel
program
like
the
two­
step
program
we
are
finalizing
today,
we
believe
that
the
clear
labeling
of
nonroad
diesel
fuel
pumps
is
vital
so
that
end
users
can
readily
distinguish
between
the
several
grades
of
fuel
that
may
be
available
at
fueling
facilities,
and
properly
fuel
their
nonroad
equipment.
Section
III.
N
above
describes
the
labels
that
manufacturers
are
required
to
place
on
nonroad
equipment,
and
the
information
that
must
be
provided
to
nonroad
equipment
owners.
Section
VI
discusses
the
likely
benefit
for
many
nonroad
engines
to
utilize
500
ppm
sulfur
diesel
fuel
as
soon
as
it
becomes
available
in
2007.
Today's
final
rule
includes
requirements
for
labeling
fuel
pump
stands
used
to
fuel
NRLM
equipment
and
highway
diesel
vehicles.

To
help
prevent
misfueling
of
nonroad,
locomotive
and
marine
engines,
and
to
thus
ensure
that
the
environmental
benefits
of
the
program
are
realized,
we
are
finalizing
pump
labeling
requirements
similar
to
those
adopted
in
the
highway
diesel
rule
(
40
CFR
§
80.570).
Today's
pump
dispenser
labeling
requirements
are
discussed
separately
according
to
the
date
they
become
effective:
June
1,
2006,
June
1,
2007,
June
1,
2010,
and
June
1,
2014.

Today's
final
rule
also
amends
the
pump
dispenser
labeling
language
in
the
highway
diesel
regulations
for
consistency
with
the
NRLM
program.
Because
existing
highway
diesel
regulations
prohibit
highway
diesel
fuel
with
sulfur
levels
above
500
ppm,
the
highway
diesel
final
rule
and
this
program
have
different
meanings
for
the
terms
"
low
sulfur"
and
"
high
sulfur,"
and
the
highway
diesel
final
rule
does
not
use
the
term
"
ultra
low­
sulfur."
Further,
because
the
highway
diesel
final
rule
did
not
need
to
categorize
the
different
uses
of
non­
highway
diesel
fuel,
the
highway
diesel
final
rule
and
this
program
have
different
meanings
for
the
term
"
nonroad."
156
The
amendments
to
291
the
highway
pump
dispenser
labeling
language
finalized
by
today's
rule
are
meant
to
avoid
confusion
at
the
fuel
pumps
caused
by
labels
that
would
have
different
meanings
depending
on
whether
the
pump
is
dispensing
highway
or
non­
highway
diesel
fuel.
Today's
final
rule
adds
effective
dates
to
each
paragraph
of
the
labeling
provisions
of
the
highway
diesel
rule
for
consistency
with
the
additional
pump
labeling
sections
of
this
program,
and
to
distinguish
the
nonhighway
labeling
requirement
effective
June
1,
2006
under
the
highway
diesel
rule
from
the
nonhighway
labeling
requirements
of
this
rule
that
are
effective
in
2007.

Alternate
labels
to
those
specified
in
today's
rule
may
be
used
if
they
are
approved
by
the
Administrator.

Today's
rule
also
finalizes
labeling
requirements
for
pumps
in
Alaska
that
dispense
NRLM
diesel
fuel
and
heating
oil
which
is
exempt
from
the
red
dye
and
fuel
marker
requirements
which
differ
from
the
labeling
requirements
discussed
in
this
section.
Please
refer
to
§
69.52(
e)
of
the
regulatory
text
to
today's
rule
for
these
pump
labeling
requirements
applicable
in
Alaska.

a.
Pump
Labeling
Requirements
that
Become
Effective
June
1,
2006
The
pump
labeling
requirements
described
in
this
section
become
effective
June
1,
2006.

i.
Pumps
Dispensing
Highway
Diesel
Fuel
Subject
to
the
15
ppm
Sulfur
Standard
The
label
on
pumps
dispensing
highway
diesel
fuel
subject
to
the
15
ppm
sulfur
standard
must
read
as
follows:

ULTRA
LOW­
SULFUR
HIGHWAY
DIESEL
FUEL
(
15
ppm
Sulfur
Maximum)
Required
for
use
in
all
model
year
2007
and
later
highway
diesel
vehicles
and
engines.
Recommended
for
use
in
all
diesel
vehicles
and
engines.

The
above
labeling
requirement
for
15
ppm
sulfur
highway
diesel
fuel
continues
through
May
31,
2010,
after
which
time
different
pump
label
requirements
for
this
fuel
become
effective
as
described
in
section
V.
C.
2.
c.
3.
of
this
preamble.

ii.
Pumps
Dispensing
Highway
Diesel
Fuel
Subject
to
the
500
ppm
Sulfur
Standard
The
label
on
pumps
dispensing
highway
diesel
fuel
subject
to
the
500
ppm
sulfur
standard
must
read
as
follows:

LOW­
SULFUR
HIGHWAY
DIESEL
FUEL
(
500
ppm
Sulfur
Maximum)
WARNING
Federal
law
prohibits
use
in
model
year
2007
and
later
highway
vehicles
and
engines.
Its
use
may
damage
these
vehicles
and
engines.
292
Dispensing
highway
diesel
fuel
that
has
a
sulfur
content
above
15
ppm
is
prohibited
into
any
highway
vehicle
after
September
30,
2010.
Hence
no
pumps
may
display
the
above
label
after
September
30,
2010.

iii.
Pumps
Dispensing
Diesel
Fuel
for
Non­
Highway
Equipment
that
Does
not
Meet
the
Standards
for
Motor
Vehicle
Diesel
Fuel
The
label
on
pumps
dispensing
diesel
fuel
for
non­
highway
equipment
that
does
not
meet
the
standards
for
motor
vehicle
diesel
fuel
must
read
as
follows:

NON­
HIGHWAY
DIESEL
FUEL
(
May
Exceed
500
ppm
Sulfur)
WARNING
Federal
law
prohibits
use
in
any
highway
vehicle
or
engine
Its
use
may
damage
these
vehicles
and
engines.

This
labeling
requirement
is
effective
until
May
31,
2007,
after
which
high
sulfur
nonhighway
diesel
fuel
must
be
labeled
according
to
the
provisions
described
in
section
V.
C.
2.
b.
iii
and
500
ppm
sulfur
non­
highway
diesel
fuel
must
be
labeled
according
to
the
provisions
described
in
section
V.
C.
2.
b.
1.
of
today's
preamble.

b.
Pump
Labeling
Requirements
that
Become
Effective
June
1,
2007
As
discussed
in
section
IV,
between
June
1,
2007
and
September
30,
2010,
end
users
are
not
always
required
to
dispense
fuel
meeting
the
500
ppm
sulfur
standard
into
nonroad,
equipment,
locomotives
or
marine
vessels.
During
this
time
period,
small
refiner
fuel
and
fuel
produced
under
the
credit
provisions
with
sulfur
levels
exceeding
500
ppm
will
continue
to
exist
in
the
distribution
system.
During
this
time
period,
there
will
also
be
nonroad
equipment
with
engines
certified
as
meeting
the
Tier
4
emission
standards
(
i.
e.,
engines
equipped
with
emission
controls
that
allow
them
to
meet
the
Tier
4
standards
earlier
than
required).
Some
of
this
equipment
is
expected
to
be
equipped
with
sulfur
sensitive
technology
that
will
need
to
operate
on
fuel
with
a
sulfur
content
of
500
ppm
or
less
to
function
properly.
For
this
reason,
it
is
important
that
NRLM
end
users
be
able
to
know
the
sulfur
level
of
the
fuel
they
are
purchasing
and
dispensing.
Therefore,
fuel
pump
dispensers
for
the
various
sulfur
grades
must
also
be
properly
labeled.
The
following
pump
labeling
requirements
become
effective
from
June
1,
2007:

i.
Pumps
Dispensing
NRLM
Diesel
Fuel
Subject
to
the
500
ppm
Sulfur
Standard
The
label
on
pumps
dispensing
500
ppm
(
maximum)
sulfur
content
diesel
fuel
for
use
in
NRLM
engines
must
read
as
follows:
157
The
IRS
requires
that
15
ppm
sulfur
non­
highway
diesel
fuel
must
contain
red
dye
after
it
leaves
the
terminal.

293
LOW­
SULFUR
NON­
HIGHWAY
DIESEL
FUEL
(
500
ppm
Sulfur
Maximum)
WARNING
Federal
law
prohibits
use
in
any
highway
vehicle
or
engine
The
above
labeling
requirement
remains
effective
until
May
31,
2010,
after
which
it
is
superceded
by
the
requirements
described
below.

ii.
Pumps
Dispensing
NRLM
Diesel
Fuel
Subject
to
the
15
ppm
Sulfur
Standard
It
is
also
likely
that
prior
to
June
1,
2010
some
15
ppm
sulfur
(
maximum)
diesel
fuel
will
be
introduced
into
the
nonroad
market
early.
Both
the
engine
and
fuel
credit
provisions
envision
such
early
introduction
of
2011­
compliant
engines
and
15
ppm
sulfur
diesel
fuel.
Thus,
it
is
important
that
nonroad
end
users
be
able
to
know
when
they
are
purchasing
diesel
fuel
with
15
ppm
or
less
sulfur.
157
The
label
on
pumps
dispensing
15
ppm
sulfur
diesel
fuel
for
use
in
NRLM
engines
must
read
as
follows:

ULTRA­
LOW
SULFUR
NON­
HIGHWAY
DIESEL
FUEL
(
15
ppm
Sulfur
Maximum)
Required
for
use
in
all
model
year
2011
and
newer
nonroad
diesel
engines.
Recommended
for
use
in
all
nonroad,
locomotive
and
marine
diesel
engines.
WARNING
Federal
law
prohibits
use
in
any
highway
vehicle
or
engine
The
above
labeling
requirement
continues
until
May
31,
2014,
after
which
it
is
superceded
by
the
labeling
provisions
described
in
section
V.
C.
2.
e.
i
of
today's
preamble.

iii.
Pumps
Dispensing
Diesel
Fuel
with
a
Sulfur
Content
Greater
than
500
ppm
for
Use
in
Older
NRLM
Equipment
The
label
on
pumps
dispensing
diesel
fuel
having
a
sulfur
content
greater
than
500
ppm
(
for
use
in
older
nonroad,
locomotive,
and
marine
diesel
engines)
must
read
as
follows:

HIGH­
SULFUR
NON­
HIGHWAY
DIESEL
FUEL
(
May
Exceed
500
ppm
Sulfur)
WARNING
Federal
law
prohibits
use
in
highway
vehicles
or
engines
May
damage
nonroad,
diesel
engines
required
to
use
low­
sulfur
or
ultra­
low
sulfur
diesel
fuel.
158
Production
of
500
ppm
sulfur
fuel
under
the
credit
provisions
is
allowed
until
June
1,
2012,

but
small
refiner
fuel
subject
to
the
500
ppm
sulfur
standard
can
continue
to
be
produced
until
June
1,

2014
and
will
be
available
to
end
users
until
September
1,
2014.

294
The
above
labeling
requirement
remains
effective
until
Sept
30,
2010.
After
Sept
30,
2010
no
pump
may
display
this
label.

iv.
Pumps
Dispensing
Heating
Oil
As
discussed
in
section
IV.
B.
2.
b,
it
is
necessary
to
segregate
heating
oil
from
NRLM
diesel
fuel
to
ensure
that
the
fuel
used
in
nonroad,
locomotive,
and
marine
equipment
is
compliant
with
the
sulfur
standards
in
today's
rule.
The
label
on
pumps
dispensing
non­
highway
diesel
fuel
for
use
other
than
in
nonroad,
locomotive
or
marine
engines,
such
as
for
use
in
stationary
diesel
engines
or
as
heating
oil,
must
read
as
follows:

HEATING
OIL
(
May
Exceed
500
ppm
Sulfur)
WARNING
Federal
law
prohibits
use
in
highway
vehicles
or
engines,
or
in
nonroad,
locomotive,
or
marine
engines.
Its
use
may
damage
these
diesel
engines.

The
above
labeling
will
remain
effective
indefinitely.

c.
Pump
Labeling
Requirements
that
Become
Effective
June
1,
2010
Beginning
October
1,
2010,
all
diesel
fuel
introduced
into
highway
diesel
vehicles,
regardless
of
the
year
of
manufacture,
must
meet
the
15
ppm
sulfur
standard.
Furthermore,
with
certain
exceptions,
fuel
introduced
into
any
nonroad
engine
must
meet
the
15
ppm
sulfur
standard.
The
exceptions
are
fuel
allowed
to
meet
the
500
ppm
sulfur
standard
for
use
only
in
pre­
model
year
2011
nonroad
engines
and
locomotive
and
marine
engines,
for
example,
small
refiner
nonroad
diesel
fuel
and
credit
nonroad
diesel
fuel,
as
well
as
downgraded
15
ppm
sulfur
diesel
fuel
from
the
distribution
system.
This
use
of
500
ppm
sulfur
diesel
fuel
in
nonroad
engines
will
continue
through
September
30,
2014,158
after
which
all
nonroad
diesel
fuel
must
meet
the
15
ppm
sulfur
standard.
The
following
pump
labeling
requirements
become
effective
June
1,
2010:

i.
Pumps
Dispensing
NRLM
Diesel
Fuel
Subject
to
the
500
ppm
Sulfur
Standard
The
label
on
pumps
dispensing
500
ppm
(
maximum)
nonroad,
locomotive,
and
marine
diesel
fuel,
as
discussed
in
section
IV.
B.
3.
b,
must
read
as
follows:
295
LOW­
SULFUR
NON­
HIGHWAY
DIESEL
FUEL
(
500
ppm
Sulfur
Maximum)
WARNING
Federal
law
prohibits
use
in
all
model
year
2011
and
newer
nonroad
engines.
May
damage
model
year
2011
and
newer
nonroad
engines.
Federal
Law
Prohibits
Use
in
any
Highway
Vehicle
or
Engine.
Recommended
for
use
in
all
locomotive
and
marine
equipment.

The
above
labeling
requirement
remains
effective
until
September
30,
2014.
After
September
30,
2014,
no
pump
may
display
this
label.

ii.
Pumps
Dispensing
Marked
LM
fuel
The
label
on
pumps
dispensing
500
ppm
sulfur
locomotive,
and
marine
diesel
fuel,
as
discussed
in
section
IV.
B.
3.
b.,
must
read
as
follows:

LOW­
SULFUR
LOCOMOTIVE
AND
MARINE
DIESEL
FUEL
(
500
ppm
Sulfur
Maximum)
WARNING
Federal
law
prohibits
use
in
nonroad
engines
or
in
highway
vehicles
or
engines.

The
above
labeling
requirement
remains
effective
until
September
30,
2012.
After
September
30,
2012,
no
pump
may
display
this
label.

iii.
Pumps
Dispensing
Highway
Diesel
Fuel
Subject
to
the
15
ppm
Sulfur
Standard
The
label
on
pumps
dispensing
highway
diesel
fuel
subject
to
the
15
ppm
sulfur
standard
of
§
80.520(
a)(
1)
must
read
as
follows:

ULTRA
LOW­
SULFUR
HIGHWAY
DIESEL
FUEL
(
15
ppm
Sulfur
Maximum)
Required
for
use
in
all
highway
diesel
vehicles
and
engines.
Recommended
for
use
in
all
diesel
vehicles
and
engines.

The
above
labeling
requirement
for
15
ppm
sulfur
highway
diesel
fuel
continues
indefinitely.

d.
Pump
Labeling
Requirements
that
Become
Effective
June
1,
2014
Beginning
October
1,
2014,
all
nonroad
fuel
distributed
to
end­
users
is
required
to
meet
the
15
ppm
sulfur
standard,
without
exception.
Locomotive
and
marine
fuel
downstream
of
the
refinery
or
importer
is
still
subject
to
the
500
ppm
sulfur
standard.
The
pump
labels
for
heating
oil
will
continue
to
be
the
same
as
for
the
period
2010
through
2014.
The
following
pump
labeling
requirements
become
effective
beginning
June
1,
2014:
296
i.
Pumps
Dispensing
NRLM
Diesel
Fuel
Subject
to
the
15
ppm
Sulfur
Standard
For
pumps
dispensing
nonroad
diesel
fuel
the
label
must
read
as
follows:

ULTRA­
LOW
SULFUR
NON­
HIGHWAY
DIESEL
FUEL
(
15
ppm
Sulfur
Maximum)
Required
for
use
in
all
nonroad
diesel
engines.
Recommended
for
use
in
all
locomotive
and
marine
diesel
engines.
WARNING
Federal
law
prohibits
use
in
any
highway
vehicle
or
engine.

The
above
labeling
requirement
continues
indefinitely.

ii.
Pumps
Dispensing
Locomotive
and
Marine
Diesel
Fuel
Subject
to
the
500
ppm
Sulfur
Standard
For
pumps
dispensing
locomotive
or
marine
diesel
fuel,
the
label
must
read
as
follows:

LOW­
SULFUR
LOCOMOTIVE
OR
MARINE
DIESEL
FUEL
(
500
ppm
Sulfur
Maximum)
WARNING
Federal
law
prohibits
use
in
nonroad
engines
or
in
highway
vehicles
or
engines.
Its
use
may
damage
these
engines.

The
above
labeling
requirement
will
remain
effective
indefinitely.

f.
Nozzle
Size
Requirements
or
other
Requirements
to
Prevent
Misfueling
Like
the
highway
diesel
fuel
program,
the
NRLM
diesel
fuel
program
does
not
include
a
nozzle
size
requirement.
In
part
this
is
because
we
are
not
aware
of
an
effective
and
practicable
scheme
to
prevent
misfueling
through
the
use
of
different
nozzle
sizes
or
shapes,
and
in
part
because
we
do
not
believe
that
improper
fueling
will
be
a
significant
enough
problem
to
warrant
such
an
action.
In
the
preamble
to
the
highway
diesel
fuel
rule,
we
stated
our
belief
that
the
use
of
unique
nozzles,
color­
coded
scuff­
guards,
or
dyes
to
distinguish
the
grades
of
diesel
fuel
may
be
useful
in
preventing
accidental
use
of
the
wrong
fuel.
(
See
66
FR
5119,
January
18,
2001.)
However,
we
did
not
finalize
any
such
requirements,
for
the
reasons
described
in
the
RIA
for
that
final
rule
(
section
IV.
E).

Similar
reasoning
applies
to
the
NRLM
diesel
fuel
program.
For
example,
15
ppm
sulfur
diesel
fuel
will
be
the
dominant
fuel
in
the
market
by
2010,
likely
comprising
more
than
80
percent
of
all
number
2
distillate.
Further,
we
believe
that
500
ppm
sulfur
diesel
fuel
will
have
limited
availability
between
2010
and
2014.
High­
sulfur
distillate
for
heating
oil
uses
will
remain,
but
will
297
only
exist
in
significant
volumes
in
certain
parts
of
the
country.
In
addition,
as
with
highway
diesel
engines,
there
is
currently
no
standardization
of
fuel
tank
openings
and
filler
necks
that
would
allow
for
a
simple,
inexpensive,
standardization
of
nozzles.
In
any
event,
we
believe
that
most
owners
and
operators
of
new
nonroad
diesel
engines
and
equipment
will
not
risk
voiding
the
general
warranty
and
the
emissions
warranty
by
misfueling.

Although
in
the
highway
diesel
fuel
rule
we
did
not
finalize
any
provisions
beyond
fuel
pump
labeling
requirements,
we
recognized
that
some
potential
for
misfueling
could
still
exist.
Consequently,
we
expressed
a
desire
to
continue
to
explore
with
industry
simple,
cost­
effective
approaches
that
could
further
minimize
misfueling
potential
such
as
color­
coded
nozzles/
scuff
guards.
Since
the
highway
diesel
rule
was
promulgated,
we
have
had
discussions
with
fuel
retailers,
wholesale
purchaser­
consumers,
vehicle
manufacturers,
and
nozzle
manufacturers,
and
continue
to
examine
different
methods
for
preventing
accidental
or
intentional
misfueling
under
the
highway
diesel
fuel
sulfur
program.
To
date,
the
affected
stakeholders,
including
engine
and
truck
manufacturers,
truck
operators,
fuel
retailers,
and
fuel
nozzle
manufacturers
have
not
reached
any
common
view
that
the
concerns
over
misfueling
warrant
any
additional
prevention
measures.

3.
Prohibition
Against
the
Use
of
Used
Motor
Oil
in
New
Nonroad
Diesel
Equipment
We
understand
that
used
motor
oil
is
sometimes
blended
with
diesel
fuel
today
for
use
as
fuel
in
nonroad
diesel
equipment.
Such
practices
include
blending
used
motor
oil
directly
into
the
equipment
fuel
tank,
blending
it
into
the
fuel
storage
tanks,
and
blending
small
amounts
of
motor
oil
from
the
engine
crank
case
into
the
fuel
system
as
the
equipment
is
operated.

However,
motor
oil
normally
contains
high
levels
of
sulfur.
Thus,
the
addition
of
used
motor
oil
to
nonroad
diesel
fuel
could
substantially
impair
the
sulfur­
sensitive
emissions
control
equipment
expected
to
be
used
by
engine
manufacturers
to
meet
the
emissions
standards
in
today's
final
rule.
Depending
on
how
the
oil
is
blended,
it
could
increase
the
sulfur
content
of
the
fuel
by
as
much
as
200
ppm
sulfur.
As
a
result,
we
believe
blending
used
motor
oil
into
nonroad
diesel
fuel
could
render
inoperative
the
expected
emission
control
technology
and
potentially
cause
driveability
problems.
Consequently,
it
would
violate
the
tampering
prohibition
in
the
Act.
See
CAA
sections
203(
a)(
3),
and
213(
d).

Therefore,
like
the
highway
diesel
rule,
today's
rule
prohibits
any
person
from
introducing
or
causing
or
allowing
the
introduction
of
used
motor
oil,
or
diesel
fuel
containing
used
motor
oil,
into
the
fuel
delivery
systems
of
nonroad
equipment
engines
manufactured
in
model
year
2011
and
later.
The
only
exception
to
this
will
be
where
the
engine
was
explicitly
certified
to
the
emission
standard
with
used
motor
oil
added
and
the
oil
was
added
in
a
manner
consistent
with
the
certification.
Furthermore,
as
discussed
in
section
IV,
today's
rule
includes
certain
sunset
dates
when
all
NRLM
diesel
fuel
in
the
distribution
system
must
meet
the
applicable
sulfur
standard,
and
before
that
date
any
NRLM
designated,
classified,
or
labeled
as
15
ppm
sulfur
fuel
must
meet
that
sulfur
standard.
Blending
of
used
motor
oil
into
NRLM
could
cause
these
standards
to
be
exceeded
in
violation
of
today's
rule.
Any
party
who
causes
the
sulfur
content
of
nonroad
diesel
298
fuel
subject
to
the
15
ppm
sulfur
standard
to
exceed
15
ppm
by
blending
motor
oil
into
nonroad
diesel
fuel,
or
by
using
motor
oil
as
nonroad
diesel
fuel,
is
subject
to
liability
for
violating
the
sulfur
standard.
Similarly,
parties
who
cause
the
sulfur
level
of
nonroad
diesel
fuel
subject
to
the
500
ppm
sulfur
nonroad
diesel
fuel
standard
to
exceed
that
standard
by
blending
motor
oil
into
the
fuel,
are
also
be
subject
to
liability.

4.
Use
of
Kerosene
in
Diesel
Fuel
As
we
discussed
in
the
highway
diesel
final
rule,
kerosene
is
commonly
added
to
diesel
fuel
to
reduce
fuel
viscosity
in
cold
weather
(
see
66
FR
5120,
January
18,
2001).
This
final
rule
does
not
limit
this
practice
with
regard
to
15
ppm
sulfur
or
500
ppm
sulfur
NRLM
diesel
fuel.
However
the
resulting
blend
will
still
be
subject
to
the
15
ppm
sulfur
or
500
ppm
sulfur
standard.
Kerosene
that
is
used,
intended
for
use,
or
made
available
for
use
as,
or
for
blending
with,
15
ppm
sulfur
or
500
ppm
sulfur
diesel
fuel
is
itself
required
to
meet
the
15
ppm
sulfur
or
500
ppm
sulfur
standard.

As
a
general
matter,
any
party
who
blends
kerosene,
or
any
blendstock,
into
NRLM
diesel
fuel,
or
who
produces
NRLM
diesel
fuel
by
mixing
blendstocks,
will
be
treated
as
a
refiner
and
will
be
subject
to
the
requirements
and
prohibitions
applicable
to
refiners
under
today's
rule.
For
example,
the
fuel
that
they
manufacture
must
meet
the
sulfur
standards
established
in
this
rule,
and
represented
on
the
PTD.
However,
in
deference
to
the
longstanding
and
widespread
practice
of
blending
kerosene
into
diesel
fuel
at
downstream
locations,
downstream
parties
who
only
blend
kerosene
into
NRLM
and
highway
diesel
fuel
will
not
be
subject
to
the
requirements
applicable
to
other
refiners,
provided
that
they
do
not
alter
the
fuel
in
any
other
way,
and
do
not
violate
the
volume
balance
requirements
discussed
in
section
IV.
D.
For
example,
they
will
not
need
to
meet
the
80/
20
requirements
under
the
highway
diesel
program.
This
activity
is
treated
the
same
way
under
the
final
highway
diesel
rule.
Parties
that
blend
kerosene
into
diesel
fuel
are
subject
to
the
downstream
designate
and
track
provisions
applicable
to
other
downstream
parties.

In
order
to
ensure
the
continued
compliance
of
15
ppm
sulfur
fuel
with
the
15
ppm
sulfur
standard,
downstream
parties
choosing
to
blend
kerosene
into
15
ppm
sulfur
NRLM
diesel
fuel
are
required
to
either
have
a
PTD
for
that
kerosene
indicating
compliance
with
the
15
ppm
sulfur
standard,
or
to
have
test
results
for
the
kerosene
establishing
such
compliance.
Further,
downstream
parties
choosing
to
blend
kerosene
into
15
ppm
sulfur
NRLM
diesel
fuel
are
entitled
to
the
two
ppm
adjustment
factor
discussed
in
section
V.
D.
2.
for
both
the
kerosene
and
the
diesel
fuel
into
which
it
is
blended
at
downstream
locations,
provided
that
the
kerosene
had
been
transferred
to
the
party
with
a
PTD
indicating
compliance
with
that
standard.
Sulfur
test
results
from
downstream
locations
of
parties
who
do
not
have
such
a
PTD
for
their
kerosene
will
not
be
subject
to
this
adjustment
factor,
either
for
the
kerosene
itself,
or
for
the
NRLM
diesel
fuel
into
which
it
is
blended.

Any
party
who
causes
the
sulfur
content
of
NRLM
diesel
fuel
represented
as
meeting
the
15
ppm
sulfur
standard
to
exceed
15
ppm
sulfur
by
blending
kerosene
into
NRLM
diesel
fuel,
or
by
using
greater
than
15
ppm
sulfur
kerosene
as
NRLM
diesel
fuel,
is
subject
to
liability
for
159
Diesel
fuel
additives
are
used
at
concentrations
commonly
expressed
in
parts
per
million.

Diesel
fuel
additives
can
include
specially­
formulated
polymers
and
other
complex
chemical
components.

Kerosene
is
used
at
much
higher
concentrations,
expressed
in
volume
percent.
Unlike
diesel
fuel
additives,
kerosene
is
a
narrow
distillation
fraction
of
the
range
of
hydrocarbons
normally
contained
in
diesel
fuel.

299
violating
the
sulfur
standard.
Similarly,
parties
who
cause
the
sulfur
level
of
NRLM
diesel
fuel
subject
to
the
500
ppm
sulfur
diesel
fuel
standard
to
exceed
that
standard
by
blending
kerosene
into
the
fuel,
are
also
be
subject
to
liability.

Today's
rule
does
not
require
refiners
or
importers
of
kerosene
to
produce
or
import
kerosene
meeting
the
15
ppm
sulfur
standard.
However,
we
believe
that
refiners
will
produce
ultra
low
sulfur
kerosene
in
the
same
refinery
processes
that
they
use
to
produce
ultra
low
sulfur
diesel
fuel,
and
that
the
market
will
drive
supply
of
ultra
low
sulfur
kerosene
for
those
areas
where,
and
during
those
seasons
when,
the
product
is
needed
for
blending
with
NRLM,
as
well
a
highway,
diesel
fuel.

As
discussed
in
section
IV.
D,
kerosene
blending
also
factors
into
the
designate
and
track
provisions
finalized
today
from
June
1,
2006
until
June
1,
2010.
During
this
time
period
it
is
possible,
and
in
fact
likely,
that
kerosene
meeting
the
15
ppm
sulfur
standard
will
instead
be
designated
as
No.
1
highway
diesel
fuel,
and
will
simply
need
to
meet
all
of
the
requirements
of
highway
diesel
fuel.
It
is
also
possible,
though
less
likely
that
kerosene
meeting
the
500
ppm
sulfur
standard
will
be
designated
as
No.
1
highway
diesel
fuel.
However,
if
it
is,
it
would
also
merely
need
to
comply
with
all
the
requirements
applicable
to
highway
diesel
fuel.

5.
Use
of
Diesel
Fuel
Additives
Diesel
fuel
additives
include
lubricity
improvers,
corrosion
inhibitors,
cold­
operability
improvers,
and
static
dissipaters.
Use
of
such
additives
is
distinguished
from
the
use
of
kerosene
or
biodiesel
by
the
low
concentrations
at
which
they
are
used
(
defined
to
be
one
percent
or
less)
and
their
relatively
more
complex
chemistry.
159
The
suitability
of
diesel
fuel
additives
for
use
in
diesel
fuel
meeting
a
500
ppm
sulfur
specification
has
been
well
established
due
to
the
existence
of
500
ppm
sulfur
highway
diesel
fuel
in
the
marketplace
since
1993.
The
suitability
of
additives
for
use
in
15
ppm
sulfur
diesel
fuel
was
first
addressed
by
EPA
in
the
highway
diesel
program,
which
requires
highway
diesel
fuel
to
meet
a
15
ppm
sulfur
standard
beginning
in
2006.
At
the
time
of
the
finalization
of
the
highway
diesel
final
rule
and
during
our
development
of
the
proposed
NRLM
diesel
rule,
our
review
of
data
submitted
by
additive
and
fuel
manufacturers
to
comply
with
EPA's
Fuel
and
Fuel
Additive
Registration
requirements
indicated
that
additives
to
meet
every
purpose,
160
See
Chapter
IV.
D.
of
the
RIA
for
the
highway
diesel
fuel
rule
for
more
information
on
diesel
fuel
additives,
EPA
Air
docket
A­
99­
06,
docket
item
V­
B­
01.
Also
See
40
CFR
part
79.

161
Most
diesel
fuel
additives
are
added
at
the
terminal
to
bulk
fuel
volumes
before
sale
to
the
consumer.
These
additives
are
referred
to
as
bulk
additives.
End
users
and
wholesale
purchaser
consumers
sometimes
also
add
additives
to
diesel
fuel
by
hand
blending
into
the
vehicle
fuel
tank
or
fleet
fuel
storage
tanks.
Such
additives
are
referred
to
as
aftermarket
additives.
As
discussed
at
the
end
of
this
section,
today's
rule
contains
different
requirements
regarding
the
use
of
aftermarket
additives.

300
including
static
dissipation,
are
currently
in
common
use
which
meet
a
15
ppm
cap
on
sulfur
content.
160
a.
Additives
Used
in
15
ppm
Sulfur
Diesel
Fuel
Similar
to
the
highway
diesel
rule,
today's
rule
allows
the
bulk
addition
of
diesel
fuel
additives
with
a
sulfur
content
greater
than
15
ppm
in
NRLM
diesel
fuel
under
certain
circumstances.
161
However,
NRLM
diesel
fuel
containing
such
additives
will
continue
to
be
subject
to
the
15
ppm
sulfur
cap.
We
believe
that
it
is
most
appropriate
for
the
market
to
determine
how
best
to
accommodate
increases
in
fuel
sulfur
content
from
the
refinery
gate
to
the
end
user,
while
maintaining
the
15
ppm
sulfur
cap,
and
whether
such
increases
result
from
contamination
in
the
distribution
system
or
bulk
diesel
additive
use.
By
providing
this
flexibility,
we
anticipate
that
market
forces
will
encourage
an
optimal
balance
between
the
competing
demands
of
manufacturing
fuel
lower
than
the
15
ppm
sulfur
cap,
limiting
contamination
in
the
distribution
system,
and
limiting
the
bulk
additive
contribution
to
fuel
sulfur
content.

Thus,
as
in
the
highway
diesel
program,
additive
manufacturers
that
market
bulk
diesel
additives
with
a
sulfur
content
higher
than
15
ppm
and
blenders
that
use
them
in
nonroad
diesel
have
additional
requirements
to
ensure
that
the
15
ppm
sulfur
cap
for
NRLM
diesel
fuel
is
not
exceeded.

The
15
ppm
sulfur
cap
on
highway
diesel
fuel
that
becomes
effective
in
2006
may
encourage
the
gradual
retirement
of
additives
that
do
not
meet
a
15
ppm
sulfur
cap.
The
15
ppm
sulfur
cap
for
NR
fuel
in
2010
and
for
LM
fuel
in
2012
may
further
this
trend.
However,
we
do
not
anticipate
that
this
will
result
in
disruption
to
additive
users
and
producers
or
a
significant
increase
in
cost.
Additive
manufacturers
commonly
reformulate
their
additives
on
a
periodic
basis
as
a
result
of
competitive
pressures.
We
anticipate
that
any
reformulation
that
might
need
to
occur
to
meet
a
15
ppm
sulfur
cap,
will
be
accomplished
prior
to
the
implementation
of
the
15
ppm
sulfur
cap
on
highway
diesel
fuel
in
2006.

Like
the
highway
diesel
fuel
rule,
this
rule
will
limit
the
continued
use
in
15
ppm
sulfur
fuel
of
a
bulk
additive
that
exceeds
15
ppm
sulfur
to
a
concentration
of
less
than
one
volume
percent.
We
believe
that
this
limitation
is
appropriate
and
will
not
cause
any
undue
burden
because
the
301
diesel
fuel
additives
for
which
this
flexibility
was
included
are
always
used
today
at
concentrations
well
below
one
volume
percent.
Further,
one
volume
percent
is
the
threshold
above
which
the
blender
of
an
additive
becomes
subject
to
all
the
requirements
applicable
to
a
refiner.
See
40
CFR
§
79.2(
d)(
1)
and
40
CFR
part
80.

The
specific
requirements
regarding
the
use
of
bulk
diesel
fuel
additives
in
NRLM
fuel
subject
to
the
15
ppm
sulfur
standard
are
as
follows:

­
Bulk
additives
that
have
a
sulfur
content
at
or
below
15
ppm
must
be
accompanied
by
a
PTD
that
states:
"
The
sulfur
content
of
this
additive
does
not
exceed
15
ppm."

­
Bulk
additives
that
exceed
15
ppm
sulfur
could
continue
to
be
used
in
diesel
fuel
subject
to
the
15
ppm
sulfur
standard
provided
that
they
are
used
at
a
concentration
of
less
than
one
volume
percent
and
their
transfer
is
accompanied
by
a
PTD
that
lists
the
following:
1)
a
warning
that
the
additive's
sulfur
content
may
exceed
15
ppm
and
that
improper
use
of
the
additive
may
result
in
non­
complying
fuel
2)
the
additive's
maximum
sulfur
concentration
3)
the
maximum
recommended
concentration
for
use
of
the
additive
in
diesel
fuel,
and
4)
the
contribution
to
the
sulfur
level
of
the
fuel
that
would
result
if
the
additive
is
used
at
the
maximum
recommended
concentration.

We
proposed
that
the
affirmative
defenses
to
presumptive
liability
for
blenders
of
bulk
additives
with
a
sulfur
content
greater
than
15
ppm
must
include
periodic
sulfur
tests
after
the
addition
of
the
additive
showing
that
the
finished
fuel
does
not
exceed
the
15
ppm
sulfur
cap.
We
are
adopting
this
proposed
requirement
for
additives
other
than
static
dissipater
additives.

b.
Static
Dissipater
Additives
Comments
from
diesel
fuel
distributors
and
additive
manufactures
stated
that
static
dissipater
additives
are
unique
among
the
various
types
of
diesel
fuel
additives
in
that
there
are
currently
none
available
with
a
sulfur
content
below
15
ppm
which
are
fully
effective.
Considering
the
lack
of
static
dissipater
additives
meeting
a
15
ppm
sulfur
cap,
and
the
inability
to
add
static
dissipater
(
S­
D)
additives
prior
to
shipment
by
pipeline,
commenters
stated
that
the
prohibitive
cost
of
testing
fuel
batches
after
the
addition
of
static
dissipater
additives
could
discourage
their
use.
To
avoid
the
potential
adverse
impact
on
the
safety
of
the
fuel
distribution
industry
which
could
result,
commenters
requested
that
we
provide
an
alternative
method
for
use
in
demonstrating
their
affirmative
defense
to
presumptive
liability
when
they
use
static
dissipater
additives
with
a
sulfur
content
above
15
ppm.
Manufacturers
of
static
dissipater
additives
stated
that
due
to
very
low
treatment
rates
that
are
needed
for
such
additives,
their
use
will
raise
the
sulfur
content
of
the
finished
fuel
by
no
more
than
0.02
ppm.
Commenters
stated
that
because
of
the
extremely
low
potential
contribution
to
the
sulfur
level
of
the
finished
diesel
fuel
which
might
result
from
the
use
162
All
additives
must
be
registered
with
EPA
Fuel
and
Fuel
Additive
Database
prior
to
their
use
in
motor
vehicle
diesel
fuel.

302
of
static
dissipater
additives,
there
was
little
risk
that
use
of
such
additives
would
result
in
noncompliance
with
the
15
ppm
sulfur
cap.

We
contacted
all
of
the
additive
manufactures
that
have
registered
static
dissipater
additives
in
EPA's
Fuel
and
Fuel
Additive
Database.
162
All
of
these
manufactures
stated
that
there
are
no
fully­
effective
static
dissipater
additives
available
that
have
a
sulfur
content
below
15
ppm.
They
further
stated
that
sulfur
is
an
essential
component
in
static
dissipater
additives,
and
that
it
is
currently
unclear
how
to
formulate
a
static
dissipater
additive
that
would
have
a
sulfur
content
below
15
ppm.
Because
of
this
input,
we
now
recognize
that
static
dissipater
additives
are
in
a
unique
category
with
respect
to
the
ability
to
comply
with
a
15
ppm
sulfur
cap.
Additive
manufactures
stated
that
reformulation
of
static
dissipater
additives
to
meet
a
15
ppm
sulfur
cap
will
likely
be
a
lengthy
undertaking.

It
is
unclear
which
of
the
naturally­
occurring
components
in
diesel
fuel
act
to
dissipate
static
electricity.
However,
certain
batches
of
fuel
are
periodically
found
which
do
not
have
adequate
static
dissipating
qualities.
In
such
cases,
static
dissipater
additives
are
necessary
to
prevent
a
static
discharge
from
occurring
during
the
transfer
of
fuel
into
a
storage
tank
which
might
cause
an
explosion.
Therefore,
it
is
essential
that
today's
rule
is
structured
in
such
a
way
so
as
to
not
impede
the
use
static
dissipater
additives.
Because
of
the
lack
of
static
dissipater
additives
meeting
a
15
ppm
sulfur
specification,
the
unique
difficulty
in
reformulating
them
to
meet
a
15
ppm
sulfur
standard,
the
fact
that
they
are
essential
to
the
safety
of
the
fuel
distribution
system,
and
the
impracticability
for
them
to
be
added
at
the
refinery,
today's
rule
includes
special
affirmative
defense
provisions
to
reduce
the
sulfur
testing
burden
associated
with
the
use
of
static
dissipater
additives
that
have
a
sulfur
content
greater
than
15
ppm.

Commenters
suggested
an
alternative
mechanism
to
demonstrate
an
affirmative
defense
to
presumptive
liability
for
blenders
of
static­
dissipater
(
S­
D)
additives
which
would
avoid
the
need
to
test
every
batch
of
fuel
at
the
terminal
after
additization.
Under
this
approach,
blenders
of
S­
D
additives
would
be
required
to
provide
volume
accounting
reconciliation
(
VAR)
records
similar
to
those
under
EPA's
deposit
control
additive
rule
(
40
CFR
part
80,
subpart
G)
which
would
show
whether
the
S­
D
additive
is
being
added
at
the
appropriate
rate
on
average
over
a
course
of
a
monthly
accounting
period.
Today's
rule
finalizes
the
approach
suggested
by
commenters
with
certain
modifications.
In
cases
where
a
violation
of
the
15
ppm
sulfur
cap
for
diesel
fuel
is
discovered
on
a
batch
of
fuel
downstream
of
a
blender
of
S­
D
additives
that
have
a
sulfur
content
above
15
ppm,
the
S­
D
additive
blender
must
provide
the
following
information
to
EPA
in
order
to
meet
their
affirmative
defense
to
presumptive
liability
regarding
the
potential
that
the
use
of
S­
D
additive
might
have
caused
or
contributed
to
the
violation:

°
A
sulfur
test
on
the
diesel
batch
prior
to
the
addition
of
the
S­
D
additive
package
that
indicates
that
the
additive,
when
added,
will
not
cause
the
fuel
to
exceed
15
ppm
303
°
A
product
transfer
document
that
accompanied
the
transfer
of
the
S­
D
additive
package
to
the
additive
blender
which
contains
the
following:
­
A
statement
that
the
S­
D
additive
package
exceeds
15
ppm
in
sulfur
content
and
that
special
requirements
apply
if
it
is
to
be
used
in
diesel
fuel
subject
to
the
15
ppm
sulfur
cap
­
The
maximum
sulfur
level
of
the
S­
D
additive
package
including
other
additive
components
such
as
diesel
detergents
and
carrier
fluid
to
the
extent
that
they
are
part
of
the
package.
Each
component
of
the
additive
package
other
than
the
S­
D
additive
itself
must
comply
with
the
15
ppm
sulfur
cap.
­
The
maximum
recommended
concentration
for
the
S­
D
additive
package.
­
The
contribution
to
the
final
sulfur
content
of
a
finished
fuel
when
the
additive
is
added
at
the
maximum
recommended
concentration.
The
maximum
recommended
concentration
must
result
in
a
potential
increase
in
the
sulfur
content
of
the
finished
fuel
of
no
more
than
0.05
ppm.
°
Monthly
volume
accounting
reconciliation
(
VAR)
records
that
include:
­
the
amount
of
S­
D
additive
package
used
during
the
month
­
the
volume
of
the
fuel
into
which
the
additive
was
injected
during
the
month
­
the
measured
sulfur
level
of
each
fuel
batch
prior
to
injection
of
the
additive
which
shows
that
the
contribution
to
the
sulfur
level
of
the
finished
diesel
fuel
from
the
use
of
the
additive
at
the
treatment
level
at
which
it
was
injected
would
not
cause
any
such
batch
of
fuel
to
exceed
the
15
ppm
sulfur
specification
°
Quality
assurance
records
which
show
that
the
precision
of
the
additive
injection
equipment
has
been
maintained
in
such
a
manner
as
to
prevent
malfunctions
which
could
result
in
the
injection
of
the
S­
D
additive
at
a
higher
concentration
than
that
reported.

The
additive
blender
must
also
be
able
to
meet
its
normal
diesel
fuel
defense
elements:
that
the
additive
blender­
fuel
distributor
did
not
cause
the
violation;
that
PTDs
account
for
all
the
fuel
and
show
apparent
compliance;
and
that
quality
assurance
sampling
and
testing
has
occurred,
as
modified
by
the
discussion
above.

In
addition,
the
ratio
of
the
amount
of
additive
used
to
the
amount
of
fuel
into
which
the
additive
was
injected
over
any
given
monthly
VAR
period
must
not
exceed
the
maximum
treatment
rate
which
could
be
added
to
any
batch
of
fuel
additized
during
the
period.
If
not,
the
blender
could
be
liable
for
any
batch
of
diesel
fuel
found
that
exceeded
the
15
ppm
sulfur
cap
which
had
been
in
their
possession.
The
above
provisions
are
only
relevant
for
establishing
affirmative
defense
to
presumptive
liability
regarding
the
potential
that
the
use
of
S­
D
additives
might
have
caused
a
violation.
Under
no
circumstances
may
an
additive
blender
cause
the
sulfur
level
of
any
batch
of
finished
fuel
to
exceed
the
15
ppm
sulfur
cap.
Blenders
of
S­
D
additives
must
meet
all
other
requirements
for
distributors
of
15
ppm
sulfur
diesel
fuel.
Regardless
of
the
cause
of
a
violation
of
the
15
ppm
sulfur
standard,
any
party
that
had
custody
or
title
of
off­
specification
fuel
is
potentially
liable
and
responsible
for
their
affirmative
defense
elements.
163
Phone
conversation
with
Eon
McMullen,
Octel
additives,
February
12,
2004.

304
These
provisions
may
only
be
used
for
static
dissipater
additives
which
have
the
potential
to
raise
the
sulfur
content
of
the
finished
fuel
by
no
more
than
0.050
ppm
when
used
at
their
maximum
recommended
treatment
level.
Based
on
the
input
from
additive
manufacturers
noted
above,
this
will
allow
the
use
of
S­
D
additives
that
are
fully
effective
for
this
purpose.
The
use
of
S­
D
additives
that
might
have
a
higher
contribution
to
the
sulfur
content
of
the
finished
fuel,
therefore,
is
unnecessary.
To
establish
affirmative
defense
to
presumptive
liability,
blenders
that
use
S­
D
additives
that
could
contribute
more
than
0.050
ppm
to
the
sulfur
content
of
a
finished
fuel
subject
to
the
15
ppm
sulfur
specification
when
used
at
the
maximum
recommended
treatment
level
are
required
to
conduct
a
sulfur
test
on
the
fuel
batch
after
the
addition
of
the
additive.
Blenders
of
additives
other
than
S­
D
additives
which
have
a
sulfur
content
greater
than
15
ppm
into
diesel
fuel
subject
to
the
15
ppm
sulfur
standard
are
also
required
to
conduct
a
sulfur
test
on
the
fuel
batch
after
the
addition
of
the
additive
for
affirmative
defense
purposes.

EPA
may
require
additive
manufactures
to
supply
samples
of
the
additive
packages
(
or
the
components
additives
in
such
packages)
that
are
used
in
15
ppm
sulfur
diesel
fuel,
or
may
sample
from
additive
batches
already
in
the
distribution
system.
In
such
cases,
we
may
test
the
sulfur
content
of
these
additives
to
evaluate
whether
they
are
in
compliance
with
the
information
provided
on
the
PTDs
or
other
relevant
documentation.
In
cases
where
a
violation
is
discovered,
any
party
in
the
distribution
system
that
had
custody
of
the
additive
batch
found
to
be
in
violation
may
be
held
presumptively
liable
for
the
violation.

Today's
rule
amends
the
highway
diesel
regulation
so
that
the
provisions
finalized
today
regarding
the
use
of
S­
D
additives
with
a
sulfur
content
above
15
ppm
in
NRLM
diesel
fuel
also
apply
to
the
use
of
such
additives
in
highway
diesel
fuel
subject
to
a
15
ppm
sulfur
standard.
However,
we
continue
to
be
concerned
about
the
use
of
additives
having
a
sulfur
content
greater
than
15
ppm.
We
will
continue
to
monitor
this
issue
and
may
initiate
an
additional
rulemaking
in
the
future
to
consider
further
limiting
or
prohibiting
the
use
of
greater
than15
ppm
sulfur
additives
in
diesel
fuel
subject
to
a
15
ppm
sulfur
cap.

The
special
provisions
for
static­
dissipater
additives
finalized
in
today's
rule
will
ensure
that
the
unique
challenges
regarding
the
manufacture
and
use
of
such
additives
do
not
present
a
barrier
to
their
continued
use.
Additive
manufactures
have
stated
that
they
are
working
on
reformulation
of
their
S­
D
additives
to
meet
a
15
ppm
sulfur
limit.

We
recently
learned
that
industry
is
beginning
to
develop
a
standardized
test
to
quantify
the
concentration
of
static­
dissipater
additives
in
finished
fuel.
163
If
such
a
test
were
available,
it
might
be
useful
for
establishing
an
additive
blender's
affirmative
defense
to
presumptive
liability
in
place
of
some
of
the
VAR
provisions
described
above.
If
a
batch
of
fuel
was
found
to
exceed
the
15
ppm
sulfur
cap,
the
use
of
such
a
test
would
allow
for
the
measurement
of
the
contribution
to
the
sulfur
level
of
the
finished
fuel
which
resulted
from
the
addition
of
the
static
dissipater
additive.
If
the
contribution
was
below
the
permissible
level
given
the
sulfur
measurements
on
each
batch
of
164
The
500
ppm
sulfur
highway
diesel
final
rule
contains
the
requirement
that
highway
diesel
fuel
not
exceed
500
ppm
sulfur
at
any
point
in
the
fuel
distribution
system
including
after
the
blending
of
additives.
Fuel
Quality
Regulations
for
Highway
Diesel
Fuel
Sold
in
1993
and
Later
Calendar
Years,

Final
Rule,
55
FR
34120,
August
21,
1990.

305
fuel
additized
with
the
greater
than15
ppm
S­
D
additive,
it
might
be
useful
in
association
with
other
blender
records
to
demonstrate
that
the
additive
blender
was
not
at
fault
for
the
violation.
If
such
a
standardized
test
becomes
available,
EPA
will
work
with
the
appropriate
industry
parties
to
evaluate
its
applicability
for
affirmative
defense
purposes,
and
conduct
a
rulemaking
if
appropriate
to
amend
the
elements
required
to
establish
affirmative
defense
to
presumptive
liability
under
the
NRLM
and
highway
diesel
programs.

c.
Additives
Used
in
500
ppm
Sulfur
Diesel
Fuel
The
1993
and
2007
highway
diesel
programs
did
not
contain
any
requirements
regarding
the
maximum
sulfur
content
of
additives
used
in
highway
diesel
fuel
subject
to
a
500
ppm
sulfur
cap.
164
Our
experience
under
the
highway
program
indicates
that
application
of
the
500
ppm
sulfur
cap
throughout
the
distribution
system
to
the
end­
user
has
been
sufficient
to
prevent
the
use
of
additives
from
jeopardizing
compliance
with
the
500
ppm
sulfur
standard.
The
potential
increase
of
several
ppm
in
the
sulfur
content
of
diesel
fuel
which
might
result
from
the
use
of
some
diesel
additives
raises
substantial
concerns
regarding
the
impact
on
compliance
with
a
15
ppm
sulfur
cap.
However,
this
is
not
the
case
with
respect
to
the
potential
impact
on
compliance
with
a
500
ppm
sulfur
cap.
The
current
average
sulfur
content
of
highway
diesel
fuel
of
340
ppm
provides
ample
margin
for
the
minimal
increase
in
the
fuel
sulfur
content
which
might
result
from
the
use
of
additives.
We
expect
that
this
will
also
be
the
case
for
NRLM
fuel
subject
to
the
500
ppm
sulfur
standard.
Therefore,
we
are
not
finalizing
any
requirements
regarding
the
sulfur
content
of
additives
used
in
NRLM
fuel
subject
to
the
500
ppm
sulfur
standard.
We
believe
that
the
requirement
that
NRLM
fuel
comply
with
a
500
ppm
sulfur
cap
throughout
the
distribution
system
to
the
end­
user
will
be
sufficient
to
ensure
that
entities
who
introduce
additives
into
such
fuel
take
into
account
the
potential
increase
in
fuel
sulfur
content.

d.
Aftermarket
Additives
We
believe
that
more
stringent
requirements
are
needed
for
aftermarket
additives
than
for
bulk
additives
due
to
the
lack
of
practical
safeguards
to
ensure
that
the
use
of
such
additives
do
not
cause
a
violation
of
the
sulfur
standards
in
today's
rule.
Also,
the
presence
of
multiple
grades
of
aftermarket
additives,
some
suitable
for
use
in
engines
equipped
with
sulfur
sensitive
emissions
control
equipment
as
well
as
pre­
control
engines,
and
some
suitable
for
use
only
in
pre­
control
engines
would
raise
significant
concerns
regarding
the
misuse.
The
misuse
of
a
high
sulfur
additive
in
an
engine
with
sulfur
sensitive
emissions
control
equipment
could
damage
this
equipment.
Therefore,
today's
rule
requires
that
all
aftermarket
additives
sold
for
use
in
nonroad,
locomotive,
and
marine
equipment
must
meet
a
500
ppm
sulfur
cap
beginning
June
1,
2007,
and
306
that
all
aftermarket
additives
sold
for
use
in
nonroad
equipment
must
meet
a
15
ppm
sulfur
specification
beginning
June
1,
2010.
After
June
1,
2010,
aftermarket
additives
with
a
sulfur
content
less
than
500
ppm
may
continue
to
be
used
in
locomotive
and
marine
engines.
This
approach
is
consistent
with
that
taken
in
the
highway
diesel
rule
which
requires
all
aftermarket
additives
to
meet
a
15
ppm
sulfur
specification
beginning
June
1,
2006.

6.
End
User
Requirements
In
light
of
the
importance
of
ensuring
that
the
proper
fuel
is
used
in
nonroad,
locomotive,
and
marine
engines
covered
by
this
program,
any
person
is
prohibited
from
fueling
such
an
engine
with
fuel
not
meeting
the
applicable
sulfur
standard.

Specifically:
1)
No
person
may
introduce,
or
permit
the
introduction
of
fuel
containing
the
heating
oil
marker
into
nonroad,
locomotive,
marine
or
highway
diesel
engines;

2)
No
person
may
introduce,
or
permit
the
introduction
of,
fuel
that
exceeds
15
ppm
sulfur
content
into
nonroad
equipment
with
a
model
year
2011
or
later
engine;

3)
Beginning
December
1,
2010,
no
person
may
introduce,
or
permit
the
introduction
of
any
fuel
exceeding
500
ppm
sulfur
content
into
any
nonroad,
locomotive,
and
marine
engine;
and
4)
Beginning
December
1,
2014,
no
person
may
introduce,
or
permit
the
introduction
of
any
fuel
exceeding
15
ppm
sulfur
content
into
any
nonroad
diesel
engine
regardless
of
year
of
manufacture.

D.
Diesel
Fuel
Sulfur
Sampling
and
Testing
Requirements
1.
Testing
Requirements
Today's
action
provides
a
new
approach
for
fuel
sulfur
measurement.
The
details
of
this
approach
are
described
below,
followed
by
a
description
of
who
will
be
required
to
conduct
fuel
sulfur
testing
as
well
as
what
fuel
must
be
tested.
The
diesel
fuel
sulfur
sampling
and
testing
provisions
described
below
are
similar
to
those
that
were
proposed.
Adjustments
we
made
to
the
proposed
provisions
were
in
response
to
comments
we
received
during
the
public
comment
period.
307
a.
Test
Method
Approval,
Record­
keeping,
and
Quality
Control
Requirements
165
Other
EPA
fuels
regulations
have
allowed
downstream
parties
conducting
periodic
quality
assurance
testing
for
defense
purposes
to
use
methods
other
than
the
designated
method,
so
long
as
the
method
is
an
ASTM
method
appropriate
for
testing
for
the
applicable
fuel
property,
and
so
long
as
the
instrument
is
correlated
to
the
designated
method.

308
Most
current
and
past
EPA
fuel
programs
designated
specific
analytical
methods
which
refiners,
importers,
and
downstream
parties165
use
to
analyze
fuel
samples
at
all
points
in
the
fuel
distribution
system
for
regulatory
compliance
purposes.
Some
of
these
programs
have
also
allowed
certain
specific
alternative
methods
which
may
be
used
as
long
as
the
test
results
are
correlated
to
the
designated
test
method.
The
highway
diesel
rule
(
66
FR
5002,
January
18,
2001),
for
example,
specifies
one
designated
test
method
and
three
alternative
methods
for
measuring
the
sulfur
content
of
highway
diesel
fuel
subject
to
the
15
ppm
sulfur
standard.
The
rule
also
specifies
one
designated
method
and
three
alternative
methods
for
measuring
the
sulfur
content
of
highway
diesel
fuel
subject
to
the
500
ppm
sulfur
standard.
309
Table
V.
H­
1.
 
Designated
and
Alternative
Sulfur
Test
Methods
Allowed
Under
the
Highway
Diesel
Program
Sulfur
Test
Method
500
ppm
15
ppm
ASTM
D
2622­
03,
as
modified,
Standard
Test
Method
for
Sulfur
in
Petroleum
Products
by
Wavelength
Dispersive
X­
ray
Fluorescence
Spectrometry
Designated
Alternative
ASTM
D
3120­
03a,
Standard
Test
Method
for
Trace
Quantities
of
Sulfur
in
Light
Liquid
Petroleum
Hydrocarbons
by
Oxidative
Microcoulometry
Alternative
ASTM
D
4294­
03,
Standard
Test
Method
for
Sulfur
in
Petroleum
and
Petroleum
Products
by
Energy­
Dispersive
X­
ray
Fluorescence
Spectrometry
Alternative
ASTM
D
5453­
03a,
Standard
Test
Method
for
Determination
of
Total
Sulfur
in
Light
Hydrocarbons,
Motor
Fuels
and
Motor
Oils
by
Ultraviolet
Fluorescence
Alternative
Alternative
ASTM
D
6428­
99,
Test
Method
for
Total
Sulfur
in
Liquid
Aromatic
Hydrocarbons
and
Their
Derivatives
by
Oxidative
Combustion
and
Electrochemical
Detection.
Alternative
Designated
The
highway
diesel
fuel
rule
also
announced
the
Agency's
intention
to
adopt
a
performance­
based
test
method
approach
in
the
future,
as
well
as
our
intention
to
continue
working
with
the
industry
to
develop
and
improve
sulfur
test
methods.
Today's
action
adopts
such
a
performance­
based
test
method
approach
for
both
highway
and
NRLM
diesel
fuel
subject
to
the
15
ppm
and
500
ppm
sulfur
standards.
In
addition,
the
current
approach
for
measuring
the
sulfur
content
of
diesel
fuel
subject
to
the
500
ppm
sulfur
standard,
i.
e.,
using
the
designated
sulfur
test
method
or
one
of
the
alternative
test
methods
with
correlation
will
remain
applicable.

Under
the
performance­
based
approach,
a
given
test
method
can
be
approved
for
use
in
a
specific
laboratory
by
meeting
certain
precision
and
accuracy
criteria
specified
in
the
regulations.
The
method
can
be
approved
for
use
by
that
laboratory
as
long
as
appropriate
quality
control
procedures
are
followed.
Properly
selected
precision
and
accuracy
values
allow
multiple
methods
and
multiple
commercially
available
instruments
to
be
approved,
thus
providing
greater
flexibility
in
method
and
instrument
selection
while
also
encouraging
the
development
and
use
of
better
166
These
are
standard­
setting
organizations,
like
ASTM,
and
ISO
that
have
broad
representation
of
all
interested
stakeholders
and
make
decisions
by
consensus.

167
Sulfur
Repeatability
of
Diesel
by
Method
at
15
ppm,
ASTM
Report
on
Low
Level
Sulfur
Determination
in
Gasoline
and
Diesel
Interlaboratory
Study
­
A
Status
Report,
June
2002.

310
methods
and
instrumentation
in
the
future.
Under
today's
rule,
there
is
no
designated
sulfur
test
method
as
specified
under
previous
regulations.

Since
any
test
method
that
meets
the
specified
performance
criteria
may
qualify,
this
type
of
approach
does
not
conflict
with
the
"
National
Technology
Transfer
and
Advancement
Act
of
1995"
(
NTTAA),
section
12(
d)
of
Public
Law
104­
113,
and
the
Office
of
Management
and
Budget
(
OMB)
Circular
A
­
119.
Both
of
these
are
designed
to
encourage
the
adoption
of
standards
developed
by
"
voluntary
consensus
standards
bodies"
(
VCSB)
166
and
to
reduce
reliance
on
government­
unique
standards
where
such
consensus
standards
would
suffice.
Under
the
performance
criteria
approach
in
today's
rule,
methods
developed
by
consensus
bodies
as
well
as
methods
not
yet
approved
by
a
consensus
body
qualify
for
approval
provided
they
meet
the
specified
performance
criteria
as
well
as
the
record­
keeping
and
reporting
requirements
for
quality
control
purposes.

i.
How
Can
a
Given
Method
be
Approved?

A
given
test
method
can
be
approved
for
use
under
today's
program
by
meeting
certain
precision
and
accuracy
criteria.
Approval
applies
on
a
laboratory/
facility­
specific
basis.
If
a
company
chooses
to
employ
more
than
one
laboratory
for
fuel
sulfur
testing
purposes,
then
each
laboratory
must
separately
seek
approval
for
each
method
it
intends
to
use.
Likewise,
if
a
laboratory
chooses
to
use
more
than
one
sulfur
test
method,
then
each
method
must
be
approved
separately.
Separate
approval
is
not
necessary
for
individual
operators
or
laboratory
instruments
within
a
given
laboratory
facility.

The
specific
precision
and
accuracy
criteria
were
derived
from
existing
sulfur
test
methods
that
are
either
required
or
allowed
under
the
highway
diesel
fuel
sulfur
program.
The
first
criterion,
precision,
refers
to
the
consistency
of
a
set
of
measurements
and
is
used
to
determine
how
closely
analytical
results
can
be
duplicated
based
on
repeat
measurements
of
the
same
material
under
prescribed
conditions.
To
demonstrate
the
precision
of
a
given
sulfur
test
method
under
the
performance­
based
approach,
a
laboratory
facility
must
perform
20
repeat
tests
over
20
days
on
samples
taken
from
a
homogeneous
supply
of
a
commercially
available
diesel
fuel.
Based
on
the
comments
we
received
on
this
issue,
we
are
also
clarifying
that
the
test
results
must
in
general
be
a
sequential
record
of
the
analyses
with
no
omissions.
A
laboratory
facility
may
exclude
a
given
sample
or
test
result
only
if
1)
the
exclusion
is
for
a
valid
reason
under
good
laboratory
practices
and
2)
it
maintains
records
regarding
the
sample
and
test
results
and
the
reason
for
excluding
them.
Using
the
test
results167
of
ASTM
D
3120
for
diesel
fuel
subject
to
the
15
ppm
sulfur
standard,
the
168
0.72
ppm
is
equal
to
1.5
times
the
standard
deviation
of
ASTM
D
3120,
where
the
standard
deviation
is
equal
to
the
repeatability
of
ASTM
D
3120
(
1.33)
divided
by
2.77.
9.68
ppm
is
equal
to
1.5
times
the
standard
deviation
of
ASTM
D
2622,
where
the
standard
deviation
is
equal
to
the
repeatability
of
ASTM
D
2622
(
17.88)
divided
by
2.77.
In
the
proposal,
we
stated
that
the
repeatability
of
ASTM
D
2622
was
26.81.
While
that
reported
value
was
incorrect
due
to
either
a
typographical
or
a
computational
error,
the
resulting
precision
value
that
we
are
finalizing
today
was
correctly
calculated
and
reported
as
9.68
ppm.
The
"
sample
standard
deviation"
should
be
used
for
this
purpose.
By
its
use
of
N­
1
in
the
denominator,
this
measure
applies
a
correction
for
the
small
sample
bias
and
provides
an
unbiased
estimate
of
the
standard
deviation
of
the
larger
population
from
which
the
sample
was
drawn.
Since
the
conditions
of
the
precision
qualification
test
admit
more
sources
of
variability
than
the
conditions
under
which
ASTM
repeatability
is
determined
(
longer
time
span,
different
operators,
environmental
conditions,

etc.)
the
repeatability
standard
deviation
derived
from
the
round
robin
was
multiplied
by
what
we
believe
to
be
a
reasonable
adjustment
factor,
1.5,
to
compensate
for
the
difference
in
conditions.

169
0.54
and
7.26
are
equal
to
0.75
times
the
precision
values
of
0.72
for
15
ppm
sulfur
diesel
and
9.68
for
500
ppm
sulfur
diesel,
respectively.

311
precision
must
be
less
than
0.72
ppm.
168
Similarly,
using
the
test
results
of
ASTM
D
2622
for
diesel
fuel
subject
to
the
500
ppm
sulfur
standard,
the
precision
must
be
less
than
9.68
ppm.

The
second
criterion,
accuracy,
refers
to
the
closeness
of
agreement
between
a
measured
or
calculated
value
and
the
actual
or
specified
value.
To
demonstrate
the
accuracy
of
a
given
test
method
under
the
performance­
based
approach,
a
laboratory
facility
is
required
to
perform
10
repeat
tests
on
a
standard
sample,
the
mean
of
which
for
diesel
fuel
subject
to
the
15
ppm
sulfur
standard
can
not
deviate
from
the
Accepted
Reference
Value
(
ARV)
of
the
standard
by
more
than
0.54
ppm
and
for
diesel
fuel
subject
to
the
500
ppm
sulfur
standard
can
not
deviate
from
the
ARV
of
the
standard
by
more
than
7.26
ppm169.
These
tests
must
be
performed
using
commercially
available
gravimetric
sulfur
standards.
Ten
tests
are
required
using
each
of
two
different
sulfur
standards.
For
15
ppm
fuel,
one
must
be
in
the
range
of
1
 
10
ppm
sulfur
and
the
other
in
the
range
of
10
 
20
ppm
sulfur.
For
500
ppm
fuel,
one
must
be
in
the
range
of
100
 
200
ppm
sulfur
and
the
other
in
the
range
of
400
 
500
ppm
sulfur
for
500
ppm
sulfur
diesel
fuel.
Therefore,
a
minimum
of
20
total
tests
is
required
for
sufficient
demonstration
of
accuracy
for
a
given
sulfur
test
method
at
a
given
laboratory
facility.
As
with
the
requirement
for
precision
demonstration
described
above,
the
test
results
must
be
a
sequential
record
of
the
analyses
with
no
omissions.
Finally,
any
known
interferences
for
a
given
test
method
must
be
mitigated.

Some
commenters
remarked
that
the
ARV
of
the
standards
does
not
account
for
any
uncertainty
given
that
all
commercially
available
standards
have
an
uncertainty
associated
with
the
certified
value.
The
commenters
added
that
EPA
should
specify
what
maximum
value
in
the
uncertainty
associated
with
the
ARV
is
allowed.
312
These
requirements
are
not
intended
be
overly
burdensome.
Indeed,
we
believe
these
requirements
are
equivalent
to
what
a
laboratory
would
do
during
the
normal
start
up
procedure
for
a
given
test
method.
In
addition,
we
believe
this
approach
will
allow
regulated
entities
to
know
that
they
are
measuring
diesel
fuel
sulfur
levels
accurately
and
within
reasonable
site
reproducibility
limits.

ii.
What
Information
Must
Be
Reported
to
the
Agency?

For
test
methods
that
have
already
been
approved
by
a
VCSB,
such
as
ASTM
or
the
International
Standards
Organization
(
ISO),
each
laboratory
facility
must
report
to
the
Agency
the
precision
and
accuracy
results
as
described
above
for
each
method
for
which
it
is
seeking
approval.
Such
submissions
to
EPA,
as
described
elsewhere,
are
subject
to
the
Agency's
review
for
90
days,
and
the
method
will
be
considered
approved
in
the
absence
of
EPA
comment.
Laboratory
facilities
are
required
to
retain
the
fuel
samples
used
for
precision
and
accuracy
demonstration
for
90
days.
While
we
proposed
a
30
day
sample
retention
period,
commenters
stated
that
the
sample
retention
period
for
fuel
samples
that
are
used
for
precision
and
accuracy
demonstrations
should
be
equivalent
to
the
length
of
EPA's
review
period
(
i.
e.,
90
days).
We
agree
with
the
commenters
and
are
thus
finalizing
a
90
day
sample
retention
period
in
today's
rule.
This
sample
retention
requirement
also
applies
to
non­
VCSB
methods
which
are
described
below.

For
test
methods
that
have
not
been
approved
by
a
VCSB,
full
test
method
documentation,
including
a
description
of
the
technology/
instrumentation
that
makes
the
method
functional,
as
well
as
subsequent
EPA
approval
of
the
method
is
also
required.
These
submissions
will
also
be
subject
to
the
Agency's
review
for
90
days,
and
the
method
will
be
considered
approved
in
the
absence
of
EPA
comment.
Submission
of
VCSB
methods
is
not
required
since
they
are
available
in
the
public
domain.
In
addition,
industry
and
the
Agency
will
likely
have
had
substantial
experience
with
such
methods.

As
described
above,
federal
government
and
EPA
policy
is
to
use
standards
developed
by
voluntary
consensus
bodies
when
available.
The
purpose
of
the
NTTAA,
at
least
in
part,
is
to
foster
consistency
in
regulatory
requirements,
to
take
advantage
of
the
collective
industry
wisdom
and
wide­
spread
technical
evaluation
required
before
a
test
method
is
approved
by
a
consensus
body,
and
to
take
advantage
of
the
ongoing
oversight
and
evaluation
of
a
test
method
by
the
consensus
body
that
results
from
wide­
spread
use
of
an
approved
method
e.
g.,
the
ongoing
roundrobin
type
analysis
and
typical
annual
updating
of
the
method
by
the
consensus
body.
These
goals
are
not
met
where
the
Agency
allows
use
of
a
non­
consensus
body
test
method
in
perpetuity.
Moreover,
it
is
not
possible
to
realize
many
of
the
advantages
that
result
from
consensus
status
where
a
test
method
is
used
by
only
one
or
a
few
companies.
It
will
not
have
the
practical
scrutiny
that
comes
from
ongoing
wide­
spread
use,
or
the
independent
scrutiny
of
the
consensus
body
and
periodic
updating.
In
addition,
EPA
does
not
have
the
resources
to
conduct
the
degree
of
initial
scrutiny
or
ongoing
scrutiny
that
are
practiced
by
consensus
bodies.
Nevertheless,
EPA
believes
it
is
appropriate
to
allow
limited
use
of
a
proprietary
test
method
for
a
limited
time,
even
though
the
significant
advantages
of
consensus
test
methods
are
absent,
because
EPA
can
evaluate
the
initial
170
1.44
ppm
is
equal
to
two
times
the
precision
value
of
0.72
ppm
for
15
ppm
diesel
and
19.36
is
equal
to
two
times
the
precision
value
of
9.68
ppm
for
500
ppm
diesel.

313
quality
of
a
method
and
a
company
may
have
invested
significant
resources
in
developing
a
method.
However,
if
after
a
reasonable
time
a
test
method
fails
to
gain
consensus
body
approval,
EPA
believes
approval
of
the
method
should
be
withdrawn
because
of
the
absence
of
ongoing
consensus
oversight.
Accordingly,
a
non­
VCSB
method
will
cease
to
be
qualified
five
years
from
the
date
of
its
original
approval
by
EPA
in
the
absence
of
VCSB
approval.

To
assist
the
Agency
in
determining
the
performance
of
a
given
sulfur
test
method,
non­
VCSB
methods,
in
particular,
we
reserve
the
right
to
send
samples
of
commercially
available
fuel
to
laboratories
for
evaluation.
Such
samples
are
intended
for
situations
in
which
the
Agency
has
concerns
regarding
a
test
method
and,
in
particular,
its
ability
to
measure
the
sulfur
content
of
a
random
commercially
available
diesel
fuel.
Laboratory
facilities
are
required
to
report
their
results
from
tests
of
this
material
to
the
Agency.

iii.
What
Quality
Control
Provisions
are
Required?

We
are
requiring
ongoing
Quality
Control
(
QC)
procedures
for
sulfur
measurement
instrumentation.
These
are
procedures
used
by
laboratory
facilities
to
ensure
that
the
test
methods
they
have
qualified
and
the
instruments
on
which
the
methods
are
run
are
yielding
results
with
appropriate
accuracy
and
precision,
e.
g.,
that
the
results
from
a
particular
instrument
do
not
"
drift"
over
time
to
yield
unacceptable
values.
It
is
our
understanding
that
most
laboratories
already
employ
QC
procedures,
and
that
these
are
commonly
viewed
as
important
good
laboratory
practices.
Laboratories
will
be
required,
at
a
minimum,
to
abide
by
the
following
QC
procedures
for
each
instrument
used
to
test
batches
of
diesel
fuel
under
these
regulations
even
where
a
laboratory
elects
to
use
the
test
method
used
to
establish
the
precision
and
accuracy
criteria
finalized
in
today's
rule:

1)
Follow
the
mandatory
provisions
of
ASTM
D
6299­
02,
Standard
Practice
for
Applying
Statistical
Quality
Assurance
Techniques
to
Evaluate
Analytical
Measurement
System
Performance.
Laboratories
are
required
to
construct
control
charts
from
the
mandatory
QC
sample
testing
prescribed
in
paragraph
7.1,
following
the
guidelines
under
A
1.5.1
for
individual
observation
charts
and
A
1.5.2
for
moving
range
charts.

2)
Follow
ASTM
D
6299­
02
paragraph
7.3.1
(
check
standards)
using
a
standard
reference
material.
Check
standard
testing
is
required
to
occur
at
least
monthly
and
should
take
place
following
any
major
change
to
the
laboratory
equipment
or
test
procedure.
Any
deviation
from
the
accepted
reference
value
of
the
check
standard
greater
than
1.44
ppm
for
diesel
fuel
subject
to
the
15
ppm
sulfur
standard
and
19.36
ppm
for
diesel
fuel
subject
to
the
500
ppm
sulfur
standard170
must
be
investigated.
314
3)
Upon
discovery
of
any
QC
testing
violation
of
A
1.5.2.1
or
A
1.5.3.2
or
check
standard
deviation
greater
than
1.44
ppm
and
19.36
ppm
for
15
ppm
sulfur
diesel
and
500
ppm
sulfur
diesel,
respectively,
as
provided
in
item
2
above,
any
measurement
made
while
the
system
was
out
of
control
must
be
tagged
as
suspect
and
an
investigation
conducted
into
the
reasons
for
this
anomalous
performance.
Refiners
and
importers
are
required
to
retain
batch
samples
for
30
days
or
the
period
equal
to
the
interval
between
QC
sample
tests,
whichever
is
longer.
If
an
instrument
is
found
to
be
out
of
control,
all
of
the
retained
samples
since
the
last
time
the
instrument
was
shown
to
be
in
control
must
be
retested.

4)
QC
records,
including
investigations
under
item
3
above
must
be
retained
for
five
years
and
must
be
provided
to
the
Agency
upon
request.

b.
Requirements
to
Conduct
Fuel
Sulfur
Testing
Given
the
importance
of
assuring
that
NRLM
diesel
fuel
designated
to
meet
the
15
ppm
sulfur
standard
in
fact
meets
that
standard,
we
are
requiring
that
refiners,
importers,
and
transmix
processors
test
each
batch
of
NRLM
diesel
fuel
designated
to
meet
the
15
ppm
sulfur
standard
and
maintain
records
of
such
testing.
Requiring
that
refiners,
importers,
and
transmix
processors
test
each
batch
of
fuel
subject
to
the
15
ppm
sulfur
NRLM
standard
assures
that
compliance
can
be
confirmed
through
testing
records,
and
even
more
importantly,
assures
that
diesel
fuel
exceeding
the
15
ppm
standard
is
not
introduced
into
commerce
as
fuel
for
use
in
nonroad
equipment
having
sulfur­
sensitive
emission
control
devices.
Batch
testing
was
not
required
under
the
highway
diesel
fuel
rule.
Instead,
such
testing
was
expected
to
be
performed
to
establish
a
defense
to
potential
liability.
However,
for
the
same
reasons
discussed
above,
today's
rule
extends
this
batch
testing
requirement
to15
ppm
sulfur
highway
diesel
fuel
beginning
in
2006.

In
order
to
address
situations
where
refiners
produce
NRLM
diesel
fuel
using
computercontrolled
inline
blending
equipment
and
do
not
have
storage
tanks
from
which
to
withdraw
samples,
we
are
including
in
today's
final
rule
a
provision
to
allow
refiners
to
test
a
composited
sample
of
a
batch
of
diesel
fuel
for
its
sulfur
content
after
the
diesel
fuel
has
been
shipped
from
the
refinery.
This
inline
blending
provision
is
similar
to
the
provision
that
exists
under
the
reformulated
gasoline
and
gasoline
sulfur
programs
and
applies
to
both
highway
and
NRLM
diesel
fuel
under
today's
action.

Today's
rule
does
not
require
downstream
parties
to
conduct
every­
batch
testing.
However,
we
believe
that
most
downstream
parties
will
voluntarily
conduct
"
periodic"
sampling
and
testing
for
quality
assurance
purposes
if
they
want
to
establish
a
defense
to
presumptive
liability,
as
discussed
in
section
V.
H.
below.
171
65
FR
6833­
34
(
Feb.
10,
2000).
Today's
rule
also
provides
that
these
methods
be
used
under
the
RFG
and
CG
rules.
See
62
FR
37337
et
seq.
(
July
11,
1997).

315
2.
Two
Part­
Per­
Million
Downstream
Sulfur
Measurement
Adjustment
We
believe
that
it
is
appropriate
to
recognize
sulfur
test
variability
in
determining
compliance
with
the
15
ppm
sulfur
NRLM
diesel
fuel
standards
downstream
of
a
refinery
or
import
facility.
Thus,
today's
rule
provides
that
for
all
15
ppm
sulfur
NRLM
diesel
fuel
at
locations
downstream
of
a
refinery
or
import
facility,
sulfur
test
results
can
be
adjusted
by
subtracting
two
ppm.
In
the
same
manner
as
finalized
for
15
ppm
sulfur
highway
diesel
fuel,
the
sole
purpose
of
this
downstream
compliance
provision
is
to
address
test
variability
concerns
(
see
the
highway
diesel
fuel
rule).
We
received
comments
suggesting
that
a
higher
downstream
test
tolerance
is
needed
based
on
the
current
values
for
test
method
variability.
However,
we
anticipate
that
the
reproducibility
of
sulfur
test
methods
is
likely
to
improve
to
two
ppm
or
even
less
by
the
time
the
15
ppm
sulfur
standard
for
highway
diesel
fuel
is
implemented
 
four
years
before
implementation
date
of
the
15
ppm
standard
for
NRLM
diesel
fuel.
With
this
provision,
we
anticipate
that
refiners
will
be
able
to
produce
diesel
fuel
with
an
average
sulfur
level
of
approximately
7­
8
ppm
and
some
contamination
could
occur
throughout
the
distribution
system,
without
fear
of
causing
a
downstream
violation
due
solely
to
test
variability.
As
test
methods
improve
in
the
future,
we
will
reevaluate
whether
two
ppm
is
the
appropriate
allowance
for
purposes
of
this
compliance
provision.
We
also
received
comments
that
a
test
tolerance
should
be
provided
in
determining
compliance
with
the
500
ppm
sulfur
standards
for
NRLM
fuel.
We
believe
that
such
a
tolerance
is
not
needed
for
fuels
subject
to
a
500
ppm
sulfur
standard
because
of
the
flexibility
that
refiners
possess
to
produce
fuel
with
a
sufficiently
low
sulfur
content
to
accommodate
test
variability.

3.
Sampling
Requirements
Today's
rule
adopts
the
same
sampling
methods
adopted
by
the
highway
diesel
rule
(
66
FR
5002,
January
18,
2001).
These
sampling
methods
are
American
Society
for
Testing
and
Materials
(
ASTM)
D
4057­
95
(
manual
sampling)
and
D
4177­
95
(
automatic
sampling
from
pipelines/
in­
line
blending).
The
requirement
to
use
these
methods
becomes
effective
for
NRLM
diesel
fuel
on
June
1,
2007.
These
same
methods
were
also
adopted
for
use
in
the
Tier
2/
Gasoline
Sulfur
rule.
171
4.
Alternative
Sampling
and
Testing
Requirements
for
Importers
of
Diesel
Fuel
Who
Transport
Diesel
Fuel
by
Tanker
Truck
We
understand
that
importers
who
transport
diesel
fuel
into
the
U.
S.
by
tanker
truck
are
frequently
relatively
small
businesses
that
could
be
subject
to
a
substantial
burden
if
they
were
required
to
sample
and
test
each
batch
of
NRLM
or
highway
diesel
fuel
imported
by
truck,
especially
where
a
trucker
imports
many
small
loads
of
diesel
fuel.
Therefore,
today's
rule
provides
that
truck
importers
may
comply
with
an
alternative
sampling
and
testing
requirement,
involving
a
sampling
and
testing
program
of
the
foreign
truck
loading
terminal,
if
certain
conditions
are
met.
For
an
importer
to
be
eligible
for
the
alternative
sampling
and
testing
requirement,
the
172
Heating
oil
sold
inside
the
Northeast/
Mid­
Atlantic
Area
adopted
under
today's
rule
and
Alaska
does
not
need
to
contain
a
marker
(
see
section
IV.
D.).

316
terminal
must
conduct
sampling
and
testing
of
the
NRLM
or
highway
diesel
fuel
immediately
after
each
receipt
into
its
terminal
storage
tank
but
before
loading
product
into
the
importer's
tanker
truck
storage
compartments
or
immediately
prior
to
loading
product
into
the
importer's
tanker
truck
if
it
hasn't
tested
after
each
receipt.
Moreover,
the
importer
will
be
required
to
conduct
periodic
quality
assurance
testing
of
the
terminal's
diesel
fuel,
and
the
importer
will
be
required
to
assure
EPA
that
we
will
be
allowed
to
make
unannounced
inspections
and
audits,
to
sample
and
test
fuel
at
the
foreign
terminal
facility,
to
assure
that
the
terminal
maintained
sampling
and
testing
records,
and
to
submit
such
records
to
EPA
upon
request.

E.
Selection
of
the
Marker
for
Heating
Oil
As
discussed
in
section
IV.
D,
to
ensure
that
heating
oil
is
not
shifted
into
the
NRLM
market,
we
need
a
way
to
distinguish
heating
oil
from
high
sulfur
or
500
ppm
sulfur
NRLM
diesel
fuel
produced
under
the
small
refiner
and
credit
provisions
in
today's
rule.
Currently,
there
is
no
differentiation
today
between
fuel
used
for
NRLM
uses
and
heating
oil.
Both
are
typically
produced
to
the
same
sulfur
specification,
and
both
are
required
to
have
the
same
red
dye
added
prior
to
distribution
from
downstream
of
the
terminal.
Based
on
recommendations
from
refiners,
in
the
NPRM,
we
concluded
that
the
best
approach
to
differentiate
heating
oil
from
NRLM
diesel
fuel
would
be
to
require
that
a
marker
be
added
to
heating
oil
at
the
refinery
gate.
Since
the
proposal
we
received
additional
information
which
allows
us
to
rely
upon
record­
keeping
and
reporting
provisions
to
differentiate
heating
oil
from
NRLM
up
to
the
point
where
it
leaves
the
terminal
(
see
section
IV.
D).
Therefore,
today's
rule
requires
that
a
marker
be
added
to
heating
oil
before
it
leaves
the
terminal
gate
rather
than
the
refinery
gate
as
proposed.
172
Section
IV.
D
of
today's
preamble
also
discusses
the
need
to
distinguish
500
ppm
sulfur
locomotive
and
marine
fuel
produced
by
refiners
and
imported
from
2010
 
2012
from
500
ppm
sulfur
nonroad
diesel
fuel
produced
during
this
time
frame
under
the
small
refiner,
credit,
and
downstream
flexibility
provisions
in
today's
rule.
Without
this
ability,
it
would
be
possible
for
500
ppm
sulfur
LM
diesel
fuel
to
be
shifted
into
the
nonroad
market
during
this
time
period
outside
of
the
Northeast/
Mid­
Atlantic
Area
and
Alaska.
Therefore,
today's
rule
requires
that
from
June
1,
2010
through
May
31,
2012,
the
same
marker
added
to
heating
oil
must
also
be
added
to
500
ppm
sulfur
LM
diesel
fuel
produced
by
a
refiner
or
imported
for
use
outside
of
the
Northeast/
Mid­
Atlantic
Area
and
Alaska
before
the
fuel
leaves
the
terminal.
Nonroad
diesel
fuel
meeting
a
500
ppm
sulfur
standard
produced
under
the
small
refiner
or
credit
provisions,
and
500
ppm
sulfur
NRLM
diesel
fuel
generated
under
the
downstream
flexibility
provisions
in
today's
rule
could
be
sold
into
the
LM
market
outside
of
the
Northeast/
Mid­
Atlantic
Area
and
Alaska.
Such
500
ppm
sulfur
NRLM
diesel
fuel
does
not
need
to
be
marked.
Therefore,
both
marked
and
unmarked
500
173
Inside
the
Northeast/
Mid­
Atlantic
Area,
500
ppm
sulfur
fuel
produced
from
transmix
or
segregated
interface
could
be
sold
into
the
LM
or
heating
oil
markets
from
2010­
2012,
and
could
only
be
sold
into
the
heating
oil
market
after
2012.
Outside
of
the
Northeast/
Mid­
Atlantic
Area,
such
fuel
could
be
sold
into
the
NRLM
market
from
2010
­
2012,
and
into
the
LM
market
thereafter.

317
ppm
sulfur
diesel
fuel
could
be
used
in
locomotive
and
marine
diesel
equipment
outside
of
the
Northeast/
Mid­
Atlantic
Area
and
Alaska
from
2010
through
2012.173
As
discussed
in
section
IV.
D.,
use
of
the
same
marker
in
heating
oil
and
500
ppm
sulfur
LM
fuel
is
feasible
because
the
underlying
goal
is
the
same,
i.
e.,
keeping
500
ppm
sulfur
diesel
fuel
produced
as
heating
oil
or
LM
fuel
from
begin
shifted
into
the
nonroad
diesel
market
from
2010
through
2012.
We
will
be
able
to
determine
whether
heating
oil
with
a
sulfur
content
greater
than
500
ppm
has
been
shifted
into
the
LM
market
downstream
of
the
terminal
by
testing
the
sulfur
content
of
LM.
500
ppm
fuel
initially
designated
as
heating
oil
can
be
later
shifted
into
the
LM
market,
since
the
sulfur
standard
for
LM
diesel
fuel
during
this
period
is
500
ppm.

Terminal
operators
suggested
that
we
might
be
able
to
rely
on
record­
keeping
and
reporting
downstream
of
the
terminal
as
well
as
above
the
terminal
level,
thereby
eliminating
any
need
for
a
fuel
marker.
However,
we
believe
such
record­
keeping
and
reporting
mechanisms
would
be
insufficient
to
keep
heating
oil
out
of
the
NRLM
market
and
500
ppm
sulfur
LM
fuel
produced
by
a
refiner
or
imported
out
of
the
nonroad
market
downstream
of
the
terminal
under
typical
circumstances.
We
can
rely
on
such
measures
before
the
fuel
leaves
the
terminal
because
it
is
feasible
to
require
all
of
the
facilities
in
the
distribution
system
to
report
to
EPA
on
their
fuel
transfers.
As
discussed
in
section
IV.
D.,
these
electronic
reports
can
be
compared
by
EPA
to
identify
parties
responsible
for
shifting
heating
oil
into
the
NRLM
market
from
2007
­
2014,
500
ppm
sulfur
LM
fuel
into
the
nonroad
market
from
2010
­
2012,
and
heating
oil
into
the
LM
market
beginning
2014.
Downstream
of
the
terminal
the
parties
involved
in
the
fuel
distribution
system
become
far
too
numerous
for
such
a
system
to
be
implemented
and
enforced
(
including
jobbers,
bulk
plant
operators,
heating
oil
dealers,
retailers,
and
even
end­
users
with
storage
tanks
such
as
farmers.
Reporting
errors
for
even
a
small
fraction
would
require
too
many
resources
to
track
down
and
correct
and
would
eliminate
the
effectiveness
of
the
system.

Our
proposal
envisioned
that
a
fuel
marker
would
be
required
in
heating
oil
from
June
1,
2006
through
May
31,
2010,
and
that
the
same
marker
would
be
required
in
locomotive
and
marine
fuel
from
June
1,
2010
through
May
31,
2014.
As
a
consequence
of
finalizing
the
15
ppm
sulfur
standard
for
locomotive
and
marine
fuel
in
2012,
we
no
longer
need
to
require
that
LM
diesel
fuel
be
marked
after
June
1,
2012.
The
2010­
2012
marking
requirement
for
500
ppm
sulfur
LM
diesel
fuel
does
not
apply
to
500
ppm
sulfur
LM
fuel
produced
by
a
refiner
or
imported
in
the
Northeast/
Mid­
Atlantic
Area
or
in
Alaska.
There
is
an
ongoing
need
to
require
the
continued
use
of
the
marker
in
heating
oil
indefinitely
(
see
section
IV
of
today's
preamble).
174
See
section
IV.
D
of
today's
preamble
for
a
discussion
of
the
provisions
for
the
Northeast/
Mid­
Atlantic
Area
and
Alaska.

175
Opinion
on
Selection
of
a
Community­
wide
Mineral
Oils
Marking
System,
("
Euromarker"),

European
Union
Scientific
Committee
for
Toxicity,
Ecotoxicity
and
the
Environment
plenary
meeting,

September
28,
1999.

318
We
proposed
that
beginning
June
1,
2007
SY­
124
must
be
added
to
heating
oil
in
the
U.
S.
at
a
concentration
of
6
milligrams
per
liter
(
mg/
L).
Today's
rule
adopts
this
requirement
except
for
heating
oil
used
in
the
Northeast/
Mid­
Atlantic
Area
and
Alaska.
174
The
chemical
composition
of
SY­
124
is
as
follows:
N­
ethyl­
N­[
2­[
1­(
2­
methylpropoxy)
ethoxyl]­
4­
phenylazo]­
benzeneamine.
175
This
concentration
is
sufficient
to
ensure
detection
of
SY­
124
in
the
distribution
system,
even
if
diluted
by
a
factor
of
50.
Any
fuel
found
with
a
marker
concentration
of
0.1
milligrams
per
liter
or
more
will
be
presumed
to
be
heating
oil.
Below
this
level,
the
prohibition
on
use
in
highway,
nonroad,
locomotive,
or
marine
applications
would
not
apply.

There
are
a
number
of
other
types
of
dyes
and
markers.
Visible
dyes
are
most
common,
are
inexpensive,
and
are
easily
detected.
Using
a
second
dye
in
addition
to
the
red
dye
required
by
IRS
in
all
non­
highway
fuel
for
segregation
of
heating
oil
based
on
visual
identification
raises
certain
challenges.
The
marker
that
we
require
in
heating
oil
and
500
ppm
sulfur
LM
diesel
fuel
must
be
different
from
the
red
dye
currently
required
by
IRS
and
EPA
and
not
interfere
with
the
identification
of
red
dye
in
distillate
fuels.
Invisible
markers
are
beginning
to
see
more
use
in
branded
fuels
and
are
somewhat
more
expensive
than
visible
markers.
Such
markers
are
detected
either
by
the
addition
of
a
chemical
reagent
or
by
their
fluorescence
when
subjected
to
near­
infrared
or
ultraviolet
light.
Some
chemical­
based
detection
methods
are
suitable
for
use
in
the
field.
Others
must
be
conducted
in
the
laboratory
due
to
the
complexity
of
the
detection
process
or
concerns
regarding
the
toxicity
of
the
reagents
used
to
reveal
the
presence
of
the
marker.
Nearinfra
red
and
ultra­
violet
flourescent
markers
can
be
easily
detected
in
the
field
using
a
small
device
and
after
brief
training
of
the
operator.
There
are
also
more
exotic
markers
available
such
as
those
based
on
immunoassay,
and
isotopic
or
molecular
enhancement.
Such
markers
typically
need
to
be
detected
by
laboratory
analysis.

We
selected
SY­
124,
however,
for
a
number
of
reasons:
1)
There
is
considerable
data
and
experience
with
it
which
indicates
there
are
no
significant
issues
with
its
use;
2)
It
is
compatible
with
the
existing
red
dye;
3)
Test
methods
exist
to
quantify
its
concentration,
even
if
diluted
by
a
factor
of
50
to
one;
4)
It
is
reasonably
inexpensive;
and
5)
It
can
be
produced
and
provided
by
a
number
of
sources.
176
The
European
Union
marker
legislation,
2001/
574/
EC,
document
C(
2001)
1728,
was
published
in
the
European
Council
Official
Journal,
L203
28.072001.

177
The
color
of
distillate
fuel
can
range
from
near
water
white
to
a
dark
blackish
brown
but
is
most
frequently
straw
colored.

319
Effective
in
August
2002,
the
European
Union
(
EU)
enacted
the
requirement
that
SY­
124
be
added
at
6
mg/
L
to
diesel
fuel
that
is
taxed
at
a
lower
rate
in
all
EU
member
states.
176
Solvent
yellow
124
is
referred
to
as
the
"
Euromarker"
in
the
EU.
The
EU
has
found
this
treatment
rate
to
be
sufficient
for
their
enforcement
purposes
while
not
interfering
with
the
identification
of
the
various
different
colored
dyes
required
by
different
EU
member
states
(
including
the
same
red
dye
that
is
required
in
the
U.
S.).
Despite
its
name,
SY­
124
does
not
impart
a
strong
color
to
diesel
fuel
when
used
at
a
concentration
of
6
mg/
L.
Most
often
it
is
reportedly
nearly
invisible
in
distillate
fuel
given
that
the
slight
yellow
color
imparted
is
similar
to
the
natural
color
of
many
distillate
fuels.
177
In
the
presence
of
red
dye,
SY­
124
can
impart
a
slight
orange
tinge
to
the
fuel.
However,
it
does
not
interfere
with
the
visual
identification
of
the
presence
of
red
dye
or
the
quantification
of
the
concentration
of
red
dye
in
distillate
fuel.
Thus,
the
use
of
SY­
124
at
6
mg/
L
in
diesel
fuel
would
not
interfere
with
the
use
of
the
red
dye
by
IRS
to
identify
non­
taxed
fuels.

Solvent
yellow
124
is
chemically
similar
to
other
additives
used
in
gasoline
and
diesel
fuel,
and
has
been
registered
by
EPA
as
a
fuel
additive
under
40
CFR
part
79.
Therefore,
we
expect
that
its
products
of
combustion
would
not
have
an
adverse
impact
on
emission
control
devices,
such
as
a
catalytic
converter.
Extensive
evaluation
and
testing
of
SY­
124
was
conducted
by
the
European
Commission.
This
included
combustion
testing
which
showed
no
detectable
difference
between
the
emissions
from
marked
and
unmarked
fuel.
Norway
specifically
evaluated
the
use
of
distillate
fuel
containing
SY­
124
for
heating
purposes
and
determined
that
the
presence
of
the
Euromarker
did
not
cause
an
increase
in
harmful
emissions
from
heating
equipment.
Based
on
the
European
experience
with
SY­
124,
we
do
not
expect
that
there
would
be
concerns
regarding
the
compatibility
of
SY­
124
in
the
U.
S.
fuel
distribution
system
or
for
use
in
motor
vehicle
engines
and
other
equipment
such
as
in
residential
furnaces.

Our
evaluation
of
the
process
conducted
by
the
EU
in
selecting
SY­
124
for
use
in
the
EU
convinced
us
that
SY­
124
was
also
the
most
appropriate
marker
to
propose
for
use
in
heating
oil
under
today's
program.
We
received
a
number
of
comments
expressing
concern
about
the
use
of
SY­
124
in
heating
oil.
Based
on
our
evaluation
of
these
comments
(
summarized
below
and
in
the
S&
A),
we
continue
to
believe
that
SY­
124
is
the
most
appropriate
marker
to
specify
for
use
in
heating
oil
and
500
ppm
sulfur
LM
diesel
fuel
under
today's
rule.
Therefore,
today's
rule
requires
that
beginning
June
1,
2007,
SY­
124
be
added
to
heating
oil,
and
that
from
June
1,
2010
through
May
31,
2012,
SY­
124
be
added
to
500
ppm
sulfur
LM
diesel
fuel
produced
by
a
refiner
or
imported
at
a
concentration
of
6
mg/
L
before
such
fuel
leaves
the
terminal
except
in
the
Northeast/
Mid­
Atlantic
Area
and
Alaska.
178
See
the
Summary
and
Analysis
of
Comments
for
a
more
detailed
discussion
of
our
response
to
concerns
about
the
possible
contamination
of
jet
fuel
with
the
marker
prescribed
for
use
in
heating
oil
and
500
ppm
sulfur
LM
fuel
under
today's
rule.

320
The
concerns
regarding
the
use
of
SY­
124
in
heating
oil
primarily
pertained
to:
the
potential
impact
on
jet
engines
if
jet
fuel
were
contaminated
with
SY­
124;
the
potential
health
effects
of
SY­
124
when
used
in
fuel
for
heating
purposes,
particularly
for
unvented
heaters;
the
potential
cost
impact
on
fuel
distributors
and
transmix
processors;
and
the
potential
conflict
with
IRS
red
dye
requirements.

The
American
Society
of
Testing
and
Materials
(
ASTM),
the
Coordinating
Research
Council
(
CRC),
and
the
Federal
Aviation
Administration
(
FAA)
requested
that
we
delay
finalizing
the
selection
of
a
specific
marker
for
use
in
heating
oil
in
today's
rule.
They
requested
that
selection
of
a
specific
marker
should
be
deferred
until
testing
could
be
conducted
regarding
the
potential
impact
of
SY­
124
on
jet
engines.
The
Air
Transport
Association
stated
that
EPA
should
conduct
an
extensive
study
regarding
the
potential
for
contamination,
determine
the
levels
at
which
the
marker
will
not
pose
a
risk
to
jet
engines,
and
seek
approval
of
SY­
124
as
a
jet
fuel
additive.
Other
parties
including
the
Department
of
Defense
(
DoD)
also
stated
that
EPA
should
refrain
from
specifying
a
heating
oil
marker
under
today's
rule
until
industry
and
other
potentially
affected
parties
can
recommend
an
appropriate
marker.
Representatives
of
the
heating
oil
industry
stated
that
they
were
concerned
that
EPA
had
not
conducted
an
independent
review
regarding
the
safety/
suitability
of
SY­
124
for
use
in
heating
oil.

We
met
and
corresponded
with
numerous
and
diverse
parties
to
evaluate
the
concerns
expressed
regarding
the
use
of
SY­
124,
and
to
determine
whether
it
might
be
more
appropriate
to
specify
a
different
marker
for
use
in
heating
oil.
These
parties
include
IRS,
FAA,
ASTM,
CRC,
various
marker/
dye
manufacturers,
European
distributors
of
fuels
containing
the
Euromarker,
marker
suppliers,
and
members
of
all
segments
in
the
U.
S.
fuel
distribution
system.

We
believe
that
concerns
related
to
potential
jet
fuel
contamination
have
been
sufficiently
addressed
for
us
to
finalize
the
selection
of
SY­
124
as
the
required
heating
oil
marker
in
today's
rule.
178
As
discussed
in
section
IV.
D
of
today's
preamble,
changes
in
the
structure
of
the
fuel
program
finalized
in
today's
rule
from
that
in
the
proposed
program
have
allowed
us
to
move
the
point
where
the
marker
must
be
added
from
the
refinery
gate
to
the
terminal.
The
vast
majority
of
concerns
regarding
the
potential
for
contamination
of
jet
fuel
with
SY­
124
pertained
to
the
shipment
of
marked
fuel
by
pipeline.
All
parties
were
in
agreement
that
nearly
all
of
the
potential
for
marker
contamination
of
jet
fuel
would
disappear
if
the
point
of
marker
addition
was
moved
to
the
terminal.
We
spoke
with
terminal
operators,
both
large
and
small,
who
confirmed
that
they
maintain
strictly
segregated
distribution
facilities
for
red
dyed
fuel
and
jet
fuel
because
of
jet
fuel
contamination
concerns.
The
same
type
of
segregation
practices
will
apply
to
the
handling
of
marked
heating
oil,
marked
500
ppm
sulfur
LM
diesel
fuel,
and
jet
fuel
since
the
marker
will
only
be
present
in
heating
oil
and
locomotive
and
marine
fuel
when
red
dye
is
also
present.
Therefore,
321
these
practices
will
be
equally
effective
in
limiting
contamination
of
jet
fuel
with
SY­
124.
Downstream
of
the
terminal,
the
only
other
chance
for
marker
contamination
of
jet
fuel
pertains
to
bulk
plant
operators
and
jobbers
that
handle
marked
heating
oil
and
jet
fuel.
For
the
most
part,
these
parties
also
currently
maintain
strict
segregation
of
the
facilities
used
to
transport
jet
fuel
and
heating
oil.
The
one
exception
is
that
small
bulk
plant
operators
that
supply
small
airports
sometimes
use
the
same
tank
truck
to
alternately
transport
jet
fuel
and
heating
oil.
In
such
cases,
they
flush
the
tank
compartment
prior
to
transporting
jet
fuel
to
remove
any
residual
heating
oil
left
behind
after
the
tank
is
drained.
Since
few,
if
any
bulk
plants
handle
LM
fuel,
it
is
unlikely
that
the
same
tank
trucks
will
be
used
to
alternately
transport
LM
fuel
and
jet
fuel.
Thus,
we
expect
that
there
will
be
even
less
chance
for
LM
fuel
containing
the
marker
to
contaminate
jet
fuel.

Today's
rule
requires
that
heating
oil
and
locomotive
and
marine
fuel
which
contains
the
marker
must
also
contain
visible
evidence
of
red
dye.
Therefore,
the
"
white
bucket"
test
that
distributors
currently
use
to
detect
red
dye
contamination
of
jet
fuel
can
also
be
relied
upon
to
detect
marker
contamination
of
jet
fuel.
Based
on
the
above
discussion,
we
concluded
that
the
required
addition
of
the
marker
to
heating
oil
and
500
ppm
sulfur
locomotive
and
marine
fuel
from
2010
 
2012
would
not
significantly
increase
the
likelihood
of
jet
fuel
contamination,
and
that
when
such
contamination
might
occur,
it
could
be
readily
identified
without
the
need
for
additional
testing.
Our
finalization
of
the
Northeast/
Mid­
Atlantic
Area
in
(
see
section
IV.
D)
also
minimizes
potential
concerns
regarding
the
potential
that
jet
fuel
may
become
contaminated
with
the
marker,
since
no
marker
is
required
in
this
area.
Furthermore,
there
is
expected
to
be
little
heating
oil
used
outside
of
the
Northeast/
Mid­
Atlantic
Area,
the
locomotive
and
marine
market
outside
of
the
Northeast/
Mid­
Atlantic
Area
is
limited.
We
anticipate
that
the
distribution
of
marked
LM
diesel
fuel
will
primarily
be
by
segregated
pathways,
and
the
duration
of
the
marker
requirement
for
500
ppm
sulfur
LM
diesel
fuel
produced
by
refiners
or
imported
for
use
outside
of
the
Northeast/
Mid­
Atlantic
Area
and
Alaska
is
only
two
years.
On
the
whole,
we
actually
expect
that
today's
rule
will
reduce
the
potential
for
jet
fuel
to
become
contaminated
with
the
azo
dyes
such
as
the
IRSrequired
red
dye
and
SY­
124
since
visual
evidence
will
no
longer
be
required
leaving
the
refinery
gate
in
500
ppm
NRLM
fuel
beginning
June
1,
2007,
and
will
no
longer
be
required
in
any
offhighway
diesel
fuel
beginning
June
1,
2010.

This
final
rule
requires
addition
of
the
marker
at
the
terminal
rather
than
the
refinery
gate
as
proposed.
Based
on
this
change,
ASTM
withdrew
its
request
to
delay
the
finalization
of
the
marker
requirements
in
today's
rule.
However,
ASTM
stated
that
some
concern
remains
regarding
jet
fuel
contamination
downstream
of
the
terminal
(
due
to
the
limited
use
of
the
same
tank
wagons
to
alternately
transport
jet
fuel
and
heating
oil
discussed
above).
Nevertheless,
ASTM
related
that
these
concerns
need
not
delay
finalization
of
the
marker
requirements
in
this
rule.
ASTM
intends
to
support
a
CRC
program
to
evaluate
the
compatibility
of
markers
with
jet
fuel.
The
Federal
Aviation
Administration
is
also
undertaking
an
effort
to
identify
fuel
markers
that
would
be
compatible
for
use
in
jet
fuel.
We
commit
to
a
review
of
the
use
of
SY­
124
in
the
future
based
on
the
findings
of
the
CRC
and
the
FAA,
experience
with
the
use
of
SY­
124
in
Europe,
and
future
input
from
ASTM
or
other
concerned
parties.
If
alternative
markers
are
identified
that
do
not
raise
322
concerns
regarding
the
potential
contamination
of
jet
fuel,
we
will
initiate
a
rulemaking
to
evaluate
the
use
of
one
of
these
markers
in
place
of
SY­
124.

Since
the
NPRM,
no
new
information
has
been
provided
which
indicates
that
the
combustion
of
SY­
124
in
heating
equipment
would
result
in
more
harmful
emissions
than
when
combusted
in
engines,
or
would
result
in
more
harmful
emissions
than
combustion
of
unmarked
heating
oil.
The
European
experience
with
the
use
of
SY­
124
and
the
evaluation
process
it
underwent
prior
to
selection
by
the
EU,
provides
strong
support
regarding
the
compatibility
of
SY
124
in
the
U.
S.
fuel
distribution
system,
and
for
use
in
motor
vehicle
engines
and
other
equipment
such
as
in
residential
furnaces
and
nonroad,
locomotive,
and
marine
engines.
We
believe
that
concerns
regarding
the
potential
health
impacts
from
the
use
of
SY­
124
do
not
present
sufficient
cause
to
delay
finalization
of
the
requirement
for
it's
use
that
is
contained
in
today's
rule.

The
European
Union
intends
to
review
the
use
of
SY­
124
after
December
2005,
but
may
undertake
the
review
earlier
if
any
health
and
safety
or
environmental
concerns
about
its
use
are
raised.
We
intend
to
keep
abreast
of
such
activities
and
may
initiate
our
own
review
of
the
use
of
SY­
124
depending
on
the
European
Union's
findings,
or
other
relevant
information.
There
will
be
nearly
four
years
of
accumulated
field
experience
with
the
use
of
SY­
124
in
Europe
at
the
time
of
the
review
by
the
EU
and
nearly
5
years
by
the
implementation
of
the
marker
requirement
under
today's
rule.
This
will
provide
ample
time
for
any
potential
unidentified
issues
with
SY­
124
to
be
identified,
and
for
us
to
choose
a
different
marker
if
warranted.

Commenters
stated
that
potential
health
concerns
regarding
the
use
of
SY­
124
might
be
exacerbated
with
respect
to
its
use
in
unvented
space
heaters.
Commenters
further
stated
that
there
are
prohibitions
against
the
dyeing
of
kerosene
(
No.
1
diesel)
used
in
such
heaters.
No
information
was
provided
to
support
these
concerns,
however,
and
we
have
no
information
to
suggest
any
health
concerns
exist
regarding
the
use
of
SY­
124
in
unvented
heaters.
Nevertheless,
even
if
there
were
such
concerns,
today's
rule
will
not
require
SY­
124
to
be
used
in
the
fuel
used
in
unvented
heaters.
Furthermore,
today's
rule,
does
not
require
that
SY­
124
be
added
to
kerosene.
This
resolves
most
of
what
concern
might
remain
regarding
this
issue,
since
kerosene
is
the
predominate
fuel
used
in
unvented
heaters.
However,
the
DoD
stated
that
No.
2
diesel
fuel
is
sometimes
used
in
its
tent
heaters
and
expressed
concern
regarding
the
presence
of
SY­
124
in
fuel
used
for
this
purpose.
We
understand
that
to
simplify
the
DoD
fuel
distribution
system,
it
is
DoD
policy
to
use
a
single
fuel
called
JP­
8
for
multiple
purposes
where
practicable,
including
space
heating.
JP­
8
used
for
such
a
purpose
would
not
be
subject
to
today's
fuel
marker
requirement.
In
cases
where
JP­
8
might
not
be
available
for
space
heating,
DoD
could
avoid
the
use
of
SY­
124
containing
fuel
by
using
kerosene
in
their
space
heaters.

We
believe
that
the
concerns
expressed
regarding
the
potential
impact
on
distributors
and
transmix
processors
from
the
presence
of
SY­
124
in
heating
oil
and
500
ppm
sulfur
LM
fuel
have
been
addressed
by
moving
the
point
of
marker
addition
to
the
terminal.
Terminal
operators
stated
that
they
desire
the
flexibility
to
blend
500
ppm
diesel
fuel
from
15
ppm
diesel
fuel
and
heating
oil.
This
practice
would
have
been
prevented
by
the
proposed
addition
of
the
marker
at
the
refinery
179
Terminals
that
manufacture
500
ppm
diesel
fuel
by
blending
15
ppm
and
high
sulfur
fuel
are
treated
as
a
refiner
under
today's
rule.
They
must
also
comply
with
all
applicable
designate
and
track
requirements,
anti­
downgrading
provisions,
and
the
other
applicable
requirements
in
today's
rule
(
see
section
IV.
D
of
today's
preamble).

180
We
do
not
expect
that
there
will
be
sufficient
demand
for
500
ppm
sulfur
LM
diesel
fuel
produced
by
refiners
or
importers
to
justify
its
shipment
by
pipeline
after
2010.

323
gate.
Under
today's
rule,
terminal
operators
will
have
access
to
unmarked
high
sulfur
fuel
with
which
to
manufacture
500
ppm
diesel
fuel
by
blending
with
15
ppm
diesel
fuel.
179
Transmix
processors
stated
that
the
presence
of
a
marker
in
transmix
would
limit
the
available
markets
for
their
reprocessed
distillates.
The
feed
material
for
transmix
processors
primarily
consists
of
the
interface
mixing
zone
between
batches
of
fuels
that
abut
each
other
during
shipment
by
pipeline
where
this
mixing
zone
can
not
be
cut
into
either
of
the
adjacent
products.
If
marked
heating
oil
and
locomotive
and
marine
fuel
was
shipped
by
pipeline,
the
source
material
for
transmix
processors
fed
by
pipelines
that
carry
marked
fuel
could
contain
SY­
124.180
Transmix
processors
stated
that
it
would
be
prohibitively
expensive
to
segregate
pipeline­
generated
transmix
containing
the
marker
from
that
which
does
not
contain
the
marker
prior
to
processing,
and
that
they
could
not
economically
remove
the
marker
during
reprocessing.
Thus,
in
cases
where
the
marker
would
be
present
in
a
transmix
processor's
feed
material,
they
would
be
limited
to
marketing
their
reprocessed
distillate
fuels
into
the
heating
oil
market.
Since
today's
final
rule
requires
that
the
marker
be
added
at
the
terminal
gate
(
rather
than
at
the
refinery
gate),
the
feed
material
that
transmix
processors
receive
from
pipelines
will
not
contain
the
marker.
Hence,
they
will
not
typically
need
to
process
transmix
containing
the
fuel
marker
prescribed
in
today's
rule,
and
today's
marker
requirement
is
not
expected
to
significantly
alter
their
operations.
There
is
little
opportunity
for
marker
contamination
of
fuels
that
are
not
subject
to
the
marker
requirements
to
occur
at
the
terminal
and
further
downstream.
In
the
rare
instances
where
this
might
occur,
the
fuel
contaminated
would
likely
also
be
a
distillate
fuel,
and
thus
could
be
sold
into
the
heating
oil
market
without
need
for
reprocessing.

We
do
not
expect
that
the
fuel
marker
requirements
will
result
in
the
need
for
additional
fuel
storage
tanks
or
tank
trucks
in
the
distribution
system.
As
discussed
in
section
VI.
A
of
today's
preamble,
the
implementation
of
the
NRLM
sulfur
standards
in
today's
rule
is
projected
to
result
in
the
need
for
additional
storage
tanks
and
tank
truck
de­
manifolding
at
a
limited
number
of
bulk
plant
facilities.
The
marker
requirement
does
not
add
another
criteria
apart
from
the
sulfur
content
of
the
fuel
which
would
force
additional
product
segregation.
As
discussed
above,
industry
has
expressed
concern
about
the
use
of
the
same
tank
trucks
to
alternately
transport
heating
oil
and
jet
fuel.
We
do
not
expect
that
the
addition
of
marker
to
heating
oil
and
500
ppm
sulfur
LM
diesel
fuel
will
exacerbate
these
concerns.
However,
depending
on
the
outcome
of
the
aforementioned
CRC
program,
the
addition
of
marker
to
heating
oil
may
hasten
the
current
trend
to
avoid
the
use
of
tank
trucks
to
alternately
transport
jet
fuel
and
heating
oil.
To
the
extent
that
181
Phone
conversation
between
Carl
Dalton
and
Rick
Stiff,
IRS
and
Jeff
Herzog
and
Paul
Machiele,
EPA,
February
19,
2004.

182
ibid.

324
this
does
occur,
we
do
not
expect
that
it
would
result
in
substantial
additional
costs
since
few
tank
truck
operators
currently
use
the
same
tank
truck
compartments
to
alternately
transport
heating
oil
and
jet
fuel.

Through
our
discussions
with
the
IRS,
we
have
confirmed
that
the
presence
of
SY­
124
will
not
interfere
with
enforcement
of
their
red
dye
requirement.
181
Although,
SY­
124
may
impart
a
slight
orange
tint
to
red­
dyed
diesel
fuel,
this
will
not
complicate
the
identification
of
the
presence
of
the
IRS
red
dye.
In
fact,
IRS
has
determined
that
the
presence
of
SY­
124
may
even
enhance
enforcement
of
their
fuel
tax
program.
182
However,
as
identified
in
the
comments,
the
implementation
of
today's
marker
requirement
for
heating
oil
arguably
may
be
in
conflict
with
IRS
regulations
at
26
CFR
§
48.4082­
1(
b)
which
state
that
no
dye
other
than
the
IRS­
specified
red
dye
must
be
present
in
untaxed
diesel
fuel.
IRS
is
evaluating
what
actions
might
be
necessary
to
clarify
that
the
addition
of
SY­
124
to
heating
oil
would
not
be
in
violation
of
IRS
regulations.

IRS
also
related
that
they
are
investigating
new
markers
for
potential
use
either
to
supplement
or
to
replace
red
dye
under
their
diesel
tax
program
which
might
be
compatible
with
jet
fuel.
IRS
stated
that
it
might
result
in
a
reduced
burden
on
industry
if
EPA
were
to
adopt
one
of
the
markers
from
the
family
of
markers
that
they
are
investigating.
Given
the
changes
to
our
program
in
today's
final
rule,
the
marker
provisions
will
not
impose
a
significant
burden.
However,
if
the
IRS
program
were
to
develop
an
alternate
marker
that
would
be
compatible
with
jet
we
will
initiate
a
rulemaking
to
evaluate
the
use
of
one
of
these
markers
in
place
of
SY­
124
(
see
section
VIII.
H.).

Commenters
also
expressed
concerns
regarding
the
proprietary
rights
related
to
the
manufacture
and
use
of
SY­
124,
and
stated
that
EPA
should
adopt
a
nonproprietary
marker
if
possible.
The
proprietary
rights
related
to
SY­
124
expire
several
months
after
the
implementation
of
the
marker
requirements
finalized
in
today's
rule.
Therefore,
we
do
not
expect
that
the
current
proprietary
rights
regarding
SY­
124
are
a
significant
concern.
Commenters
also
stated
that
our
estimated
cost
of
SY­
124
in
the
NPRM
(
0.2
cents
per
gallon
of
treated
fuel)
was
high
compared
to
other
markers
that
cost
hundredths
of
a
cent
per
gallon.
Since
the
proposal
we
have
obtained
more
accurate
information
which
indicates
that
the
current
cost
of
bulk
quantities
of
SY­
124
is
approximately
0.03
cents
per
gallon
of
treated
fuel
(
see
section
VI.
A.).
Based
on
conversations
with
various
marker
manufacturers,
this
cost
is
comparable
to
or
less
than
other
fuel
markers.

F.
Fuel
Marker
Test
Method
As
discussed
in
section
V.
E
above,
today's
rule
requires
the
use
of
SY­
124
at
a
concentration
of
6mg/
L
in
heating
oil
beginning
in
2007,
and
in
500
ppm
sulfur
LM
diesel
fuel
183
Memorandum
to
the
docket
entitled
"
Use
of
a
Visible
Spectrometer
Based
Test
Method
in
Detecting
the
Presence
and
Determining
the
Concentration
of
Solvent
Yellow
124
in
Diesel
Fuel."

184
Today's
rule
requires
that
red
dye
be
present
in
heating
oil
which
contains
the
marker.

325
produced
by
a
refiner
or
importer
from
2010
through
2012,
except
for
such
fuels
that
used
in
the
Northeast/
Mid­
Atlantic
Area
and
Alaska.
There
is
currently
no
industry
standard
test
procedure
to
quantify
the
presence
of
SY­
124
in
distillate
fuels.
The
most
commonly
accepted
method
is
based
on
the
chemical
extraction
of
the
SY­
124
using
hydrocloric
acid
solution
and
cycloxane,
and
the
subsequent
evaluation
of
the
extract
using
a
visual
spectrometer
to
determine
the
concentration
of
the
marker.
183
This
test
is
inexpensive
and
easy
to
use
for
field
inspections.
However,
the
test
involves
reagents
that
require
some
safety
precautions
and
the
small
amount
of
fuel
required
in
the
test
must
be
disposed
of
as
hazardous
waste.
Commenters
expressed
concerns
about
the
use
of
a
test
procedure
which
involves
a
hazardous
reagent
(
hydrochloric
acid)
and
which
generates
a
waste
product
that
must
be
disposed
of
as
hazardous
waste.
Nevertheless,
we
continue
to
believe
that
such
safety
concerns
are
manageable
here
in
the
U.
S.
just
as
they
are
in
Europe
and
that
the
small
amount
of
waste
generated
can
be
handled
along
with
other
similar
waste
generated
by
the
company
conducting
the
test,
and
that
the
associated
effort
and
costs
will
be
negligible.

Changes
made
in
today's
final
rule
from
the
proposal
will
mean
that
few
parties
in
industry
will
need
to
test
for
the
marker,
thereby
minimizing
concerns
about
the
burden
of
such
testing.
Much
of
the
testing
for
the
fuel
marker
that
was
envisioned
by
industry
was
associated
with
detecting
marker
contamination
in
other
fuels.
By
moving
the
required
point
of
marker
addition
downstream
to
the
terminal,
today's
rule
virtually
eliminates
these
concerns.
Where
such
concerns
continue
to
exist,
the
presence
of
the
red
dye
will
provide
a
visual
means
of
detecting
marker
contamination.
184
Therefore,
we
expect
that
the
instances
where
parties
will
need
to
test
for
marker
contamination
will
be
rare.
Also,
the
Northeast/
Mid­
Atlantic
Area
provisions
finalized
in
today's
rule
will
exempt
the
vast
majority
of
heating
oil
used
in
the
U.
S.
from
the
marker
requirement.
Based
on
the
above
discussion,
we
believe
that
the
vast
majority
of
testing
for
the
presence
of
the
fuel
marker
that
will
be
conducted
will
be
that
by
EPA
for
enforcement
purposes.

Similar
to
the
approach
proposed
regarding
the
measurement
of
fuel
sulfur
content
discussed
in
section
V.
H
above,
we
are
finalizing
a
performance­
based
procedure
to
measure
the
concentration
of
SY­
124
in
distillate
fuel.
Section
V.
H
above
describes
our
rationale
for
finalizing
performance­
based
test
procedures.
Under
the
performance­
based
approach,
a
given
test
method
can
be
approved
for
use
in
a
specific
laboratory
or
for
field
testing
by
meeting
certain
precision
and
accuracy
criteria.
Properly
selected
precision
and
accuracy
values
allow
multiple
methods
and
multiple
commercially
available
instruments
to
be
approved,
thus
providing
greater
flexibility
in
method
and
instrument
selection
while
also
encouraging
the
development
and
use
of
better
methods
and
instrumentation
in
the
future.
For
example,
we
are
hopeful
that
with
more
time
and
effort
a
simpler
test
can
be
developed
for
SY­
124
that
can
avoid
the
use
of
reagents
and
the
generation
of
hazardous
waste
that
is
by
product
of
the
current
commonly
accepted
method.
185
Memorandum
to
the
docket
entitled
"
Use
of
a
Visible
Spectrometer
Based
Test
Method
in
Detecting
the
Presence
and
Determining
the
Concentration
of
Solvent
Yellow
124
in
Diesel
Fuel."

186
Technical
Data
on
Fuel/
Dye/
Marker
&
Color
Analyzers,
as
downloaded
from
the
Petroleum
Analyzer
Company
L.
P.
website
at
http://
www.
petroleum­
analyzer.
com/
product/
PetroSpec/
lit_
pspec/
DTcolor.
pdf.

326
Under
the
performance
criteria
approach,
methods
developed
by
consensus
bodies
as
well
as
methods
not
yet
approved
by
a
consensus
body
will
qualify
for
approval
provided
they
meet
the
specified
performance
criteria
as
well
as
the
record­
keeping
and
reporting
requirements
for
quality
control
purposes.
There
is
no
designated
marker
test
method.

1.
How
Can
a
Given
Marker
Test
Method
be
Approved?

A
marker
test
method
can
be
approved
for
use
under
today's
program
by
meeting
certain
precision
and
accuracy
criteria.
Approval
will
apply
on
a
laboratory/
facility­
specific
basis.
If
a
company
chooses
to
employ
more
than
one
laboratory
for
fuel
marker
testing
purposes,
then
each
laboratory
will
have
to
separately
seek
approval
for
each
method
it
intends
to
use.
Likewise,
if
a
laboratory
chooses
to
use
more
than
one
marker
test
method,
then
each
method
will
have
to
be
approved
separately.
Separate
approval
will
not
be
necessary
for
individual
operators
or
laboratory
instruments
within
a
given
laboratory
facility.
The
method
will
be
approved
for
use
by
that
laboratory
as
long
as
appropriate
quality
control
procedures
were
followed.

In
developing
the
precision
and
accuracy
criteria
for
the
sulfur
test
method,
EPA
drew
upon
the
results
of
an
inter­
laboratory
study
conducted
by
the
American
Society
for
Testing
and
Materials
(
ASTM)
to
support
ASTM's
standardization
of
the
sulfur
test
method.
Unfortunately,
there
has
not
been
sufficient
time
for
industry
to
standardize
the
test
procedure
used
to
measure
the
concentration
of
SY­
124
in
distillate
fuels
or
to
conduct
an
inter­
laboratory
study
regarding
the
variability
of
the
method.
Nevertheless,
the
European
Union
has
been
successful
in
implementing
its
marker
requirement
while
relying
on
the
marker
test
procedures
which
are
currently
available,
as
noted
above.
We
used,
the
most
commonly
used
marker
test
procedure
to
establish
the
precision
and
accuracy
criteria
on
which
a
marker
test
procedure
would
be
approved
under
the
today's
rule.
185
There
has
been
substantial
experience
in
the
use
of
this
reference
market
test
method
since
the
August
2002
effective
date
of
the
European
Union's
marker
requirement.
However,
EPA
is
aware
of
only
limited
summary
data
on
the
variability
of
the
reference
test
method
from
a
manufacturer
of
the
visible
spectrometer
apparatus
used
in
the
testing.
186
The
stated
resolution
of
the
test
method
from
the
materials
provided
by
this
equipment
manufacturer
is
0.1
mg/
L,
with
a
187
Repeatability
and
reproducibility
are
terms
related
to
test
variability.
ASTM
defines
repeatability
as
the
difference
between
successive
results
obtained
by
the
same
operator
with
the
same
apparatus
under
constant
operating
conditions
on
identical
test
materials
that
would,
in
the
long
run,
in
the
normal
and
correct
operation
of
the
test
method
be
exceeded
only
in
one
case
in
20.
Reproducibility
is
defined
by
ASTM
as
the
difference
between
two
single
and
independent
results
obtained
by
different
operators
working
in
different
laboratories
on
identical
material
that
would,
in
the
long
run,
be
exceeded
only
in
one
case
in
twenty.

188
See
section
V.
H
of
this
proposal
for
a
discussion
of
the
methodology
used
in
deriving
the
proposed
precision
and
accuracy
values
for
the
sulfur
test
method.

327
repeatability
of
plus
or
minus
0.08
mg/
L
and
a
reproducibility
of
plus
or
minus
0.2
mg/
L.
187
Given
the
lack
of
more
extensive
data,
we
have
decided
to
use
these
available
data
as
the
basis
of
the
precision
and
accuracy
criteria
for
the
marker
test
procedure
under
today's
rule
(
as
discussed
below).
EPA
may
initiate
a
review
of
the
precision
and
accuracy
criteria
finalized
in
today's
rule
should
additional
test
data
become
available.

Using
a
similar
methodology
to
that
employed
in
deriving
the
sulfur
test
procedure
precision
value
results
in
a
precision
value
for
the
marker
test
procedure
of
0.043
mg/
L
(
see
section
V.
H).
188
However,
we
are
concerned
that
the
use
of
this
precision
value,
because
it
is
based
on
very
limited
data,
might
preclude
the
acceptability
of
test
procedures
that
would
be
adequate
for
the
intended
regulatory
use.
In
addition,
the
lowest
measurement
of
marker
concentration
that
will
have
relevance
under
the
regulations
is
0.1
mg
per
liter.
Consequently,
today's
rule
requires
that
the
precision
of
a
marker
test
procedure
will
need
to
be
less
than
0.1
mg/
L
for
it
to
qualify.

To
demonstrate
the
accuracy
of
a
given
test
method,
a
laboratory
facility
will
be
required
to
perform
10
repeat
tests,
the
mean
of
which
can
not
deviate
from
the
Accepted
Reference
Value
(
ARV)
of
the
standard
by
more
than
0.05
mg/
L.
We
believe
that
this
accuracy
level
is
not
overly
restrictive,
while
being
sufficiently
protective
considering
that
the
lowest
marker
level
of
regulatory
significance
would
be
0.1
mg/
L.
Ten
tests
will
be
required
using
each
of
two
different
marker
standards,
one
in
the
range
of
0.1
to
1
mg/
L
and
the
other
in
the
range
of
4
to
10
mg/
L
of
SY­
124.
Therefore,
a
minimum
of
20
total
tests
will
be
required
for
sufficient
demonstration
of
accuracy
for
a
given
marker
test
method
at
a
given
laboratory
facility.
Finally,
any
known
interferences
for
a
given
test
method
will
have
to
be
mitigated.
These
tests
must
be
performed
using
commercially
available
SY­
124
standards.
Since
the
European
Union's
marker
requirement
will
have
been
in
effect
for
nearly
5
years
by
the
implementation
date
of
today's
marker,
we
believe
that
such
standards
will
be
available
by
the
implementation
date
for
today's
rule.

These
requirements
are
not
overly
burdensome.
To
the
contrary,
these
requirements
are
equivalent
to
what
a
laboratory
would
do
during
the
normal
start
up
procedure
for
a
given
test
189
These
are
standard­
setting
organizations,
like
ASTM,
and
ISO
that
have
broad
representation
of
all
interested
stakeholders
and
make
decisions
by
consensus.

328
method.
In
addition,
we
believe
the
performance
based
approach
finalized
in
today's
rule
will
allow
regulated
entities
to
know
that
they
are
measuring
fuel
marker
levels
accurately
and
within
reasonable
site
reproducibility
limits.

2.
What
Information
Would
Have
To
Be
Reported
to
the
Agency?

As
noted
above,
the
European
Union's
(
EU)
marker
requirement
will
have
been
in
effect
for
nearly
five
years
prior
to
the
effective
data
for
the
proposed
marker
requirements
and
we
expect
the
EU
requirement
to
continue
indefinitely.
Thus,
we
anticipate
that
the
European
testings
standards
community
will
likely
have
standardized
a
test
procedure
to
measure
the
concentration
of
SY­
124
in
distillate
fuels
prior
to
the
implementation
of
the
marker
requirement
in
today's
final
rule.
The
United
States
testing
standards
community
may
also
enact
such
a
standardized
test
procedure.
To
the
extent
that
marker
test
methods
that
have
already
been
approved
by
a
voluntary
consensus
standards
body189
(
VCSB),
such
as
the
International
Standards
Organization
(
ISO)
or
the
American
Society
for
Testing
and
Materials
(
ASTM),
each
laboratory
facility
would
be
required
to
report
to
the
Agency
the
precision
and
accuracy
results
as
described
above
for
each
method
for
which
it
is
seeking
approval.
Such
submissions
to
EPA,
as
described
elsewhere,
will
be
subject
to
the
Agency's
review
for
30
days,
and
the
method
will
be
considered
approved
in
the
absence
of
EPA
comment.
Laboratory
facilities
are
required
to
retain
the
fuel
samples
used
for
precision
and
accuracy
demonstration
for
30
days.

For
test
methods
that
have
not
been
approved
by
a
VCSB,
full
test
method
documentation,
including
a
description
of
the
technology/
instrumentation
that
makes
the
method
functional,
as
well
as
subsequent
EPA
approval
of
the
method
is
also
required.
These
submissions
are
subject
to
the
Agency's
review
for
90
days,
and
the
method
will
be
considered
approved
in
the
absence
of
EPA
comment.
Submission
of
VCSB
methods
is
not
required
since
they
are
available
in
the
public
domain.
In
addition,
industry
and
the
Agency
will
likely
have
had
substantial
experience
with
such
methods.

To
assist
the
Agency
in
determining
the
performance
of
a
given
marker
test
method
(
non­
VCSB
methods,
in
particular),
we
reserve
the
right
to
send
samples
of
commercially
available
fuel
to
laboratories
for
evaluation.
Such
samples
are
intended
for
situations
in
which
the
Agency
has
concerns
regarding
a
test
method
and,
in
particular,
its
ability
to
measure
the
marker
content
of
a
random
commercially
available
diesel
fuel.
Laboratory
facilities
are
required
to
report
the
results
from
tests
on
this
material
to
the
Agency.

G.
Requirements
for
Record­
keeping,
Reporting,
and
PTDs
190
"
Subsidiary"
here
covers
entities
of
which
the
parent
company
has
50
percent
or
greater
ownership.

329
1.
Registration
Requirements
As
discussed
in
section
IV.
D,
by
December
31,
2005,
or
six
months
prior
to
handling
fuels
subject
to
the
designation
requirements
of
today's
rule,
each
entity
in
the
fuel
distribution
system,
up
through
and
including
the
point
where
fuel
is
loaded
onto
trucks
for
distribution
to
retailers
or
wholesale
purchaser­
consumers,
must
register
each
of
its
facilities
with
EPA.

An
entity's
registration
must
include
the
following
information:

°
Corporate
name
and
address
­
Contact
name,
telephone
number,
and
e­
mail
address
°
For
each
facility
operated
by
the
entity:
­
Type
of
facility
(
e.
g.
refinery,
import
facility,
pipeline,
terminal)
­
Facility
name
­
Physical
location
­
Contact
name,
telephone
number,
and
e­
mail
address
2.
Applications
for
Small
Refiner
Status
An
application
of
a
refiner
for
small
refiner
status
must
be
submitted
to
EPA
by
December
31,
2004
and
shall
include
the
following
information:

°
The
name
and
address
of
each
location
at
which
any
employee
of
the
company,
including
any
parent
companies,
subsidiaries,
or
joint
venture
partners190
worked
From
January
1,
2002
until
January
1,
2003;

°
The
average
number
of
employees
at
each
location,
based
on
the
number
of
employees
for
each
of
the
company's
pay
periods
from
January
1,
2002
until
January
1,
2003;

°
The
type
of
business
activities
carried
out
at
each
location;
and
°
The
total
crude
oil
refining
capacity
of
the
corporation.
We
define
total
capacity
as
the
sum
of
all
individual
refinery
capacities
for
multiple­
refinery
companies,
including
any
and
all
subsidiaries,
and
joint
venture
partners
as
reported
to
the
Energy
Information
Administration
(
EIA)
for
2002,
or
in
the
case
of
foreign
refiners,
a
comparable
reputable
source,
such
as
professional
publication
or
trade
191
We
will
evaluate
each
foreign
refiner's
documentation
of
crude
oil
capacity
on
an
individual
basis.

330
journal.
191
Refiners
do
not
need
to
include
crude
oil
capacity
used
in
2002
through
a
lease
agreement
with
another
refiner
in
which
it
has
no
ownership
interest.

The
crude
oil
capacity
information
reported
to
the
EIA
is
presumed
to
be
correct.
However,
in
cases
where
a
company
disputes
this
information,
we
will
allow
60
days
after
the
company
submits
its
application
for
small
refiner
status
for
that
company
to
petition
us
with
detailed
data
it
believes
shows
that
the
EIA's
data
was
in
error.
We
will
consider
this
data
in
making
a
final
determination
about
the
refiner's
crude
oil
capacity.

Finally,
applications
for
small
refiner
status
must
also
include
information
on
which
small
refiner
option
the
refiner
expects
to
use
at
each
of
its
refineries.

3.
Applications
for
Refiner
Hardship
Relief
As
discussed
above
in
section
IV.
C,
a
refiner
seeking
general
hardship
relief
under
today's
program
will
apply
to
EPA
and
provide
several
types
of
financial
and
technical
information,
such
as
internal
cash
flow
data
and
information
on
bank
loans,
bonds,
and
assets
as
well
as
detailed
engineering
and
construction
plans
and
permit
status.
Applications
for
general
hardship
relief
are
due
June
1,
2005.

4.
Pre­
Compliance
Reports
for
Refiners
We
believe
that
an
early
general
understanding
of
the
refining
industry's
progress
in
complying
with
the
requirements
in
today's
rule
will
be
valuable
to
both
the
industry
and
EPA.
As
with
the
highway
diesel
program,
we
are
requiring
that
each
refiner
and
importer
provide
annual
reports
on
the
progress
of
compliance
and
plans
for
compliance
for
each
of
their
refineries
or
import
facilities.
These
pre­
compliance
reports
are
due
June
1
of
each
year
beginning
in
2005
and
continuing
through
2011,
or
until
the
production
of
15
ppm
sulfur
NR
and
LM
diesel
fuel
commences,
whichever
is
later.

EPA
will
maintain
the
confidentiality
of
information
submitted
in
pre­
compliance
reports
to
the
full
extent
authorized
by
law.
We
will
report
generalized
summaries
of
this
data
following
receipt
of
the
pre­
compliance
reports.
We
recognize
that
plans
may
change
for
many
refiners
or
importers
as
the
compliance
dates
approach.
Thus,
submission
of
the
reports
will
not
impose
an
obligation
to
follow
through
on
plans
projected
in
the
reports.

Pre­
compliance
reports
can,
at
the
discretion
of
the
refiner/
importer,
be
submitted
in
conjunction
with
the
annual
compliance
reports
discussed
below
and/
or
the
pre­
compliance
and
annual
compliance
reports
required
under
the
highway
diesel
program,
as
long
as
all
of
the
information
that
is
required
in
all
reports
is
clearly
provided.
Based
on
experience
with
the
first
331
pre­
compliance
reports
for
the
highway
diesel
program,
we
are
clarifying
the
information
request
for
the
pre­
compliance
reports
as
shown
below.
This
should
provide
responses
in
a
more
standardized
format
which
will
allow
for
better
aggregation
of
the
data,
as
well
as
eliminate
reporting
of
unnecessary
information.

Pre­
compliance
reports
must
include
the
following
information:

°
Any
changes
in
the
basic
corporate
or
facility
information
since
registration;
°
Estimates
of
the
average
daily
volumes
(
in
gallons)
of
each
sulfur
grade
of
highway
and
NRLM
diesel
fuel
produced
(
or
imported)
at
each
refinery
(
or
facility).
These
volume
estimates
must
be
provided
both
for
fuel
produced
from
crude
oil,
as
well
as
any
fuel
produced
from
other
sources,
and
must
be
provided
for
the
periods
of
June
1,
2010
­
December
31,
2010,
calendar
years
2011­
13,
January
1,
2014
­
May
31,
2014,
and
June
1,
2014
­
December
31,
2014;
°
For
entities
expecting
to
participate
in
the
credit
program,
estimates
of
numbers
of
credits
to
be
earned
and/
or
used;
°
Information
on
project
schedule
by
known
or
projected
completion
date
(
by
quarter)
by
the
stage
of
the
project.
For
example,
following
the
five
project
phases
described
in
EPA's
June
2002
Highway
Diesel
Progress
Review
report
(
EPA420­
R­
02­
016):
1)
Strategic
planning,
2)
planning
and
front­
end
engineering,
3)
detailed
engineering
and
permitting,
4)
procurement
and
construction,
and
5)
commissioning
and
startup.
°
Basic
information
regarding
the
selected
technology
pathway
for
compliance
(
e.
g.,
conventional
hydrotreating
vs
other
technologies,
revamp
vs
grassroots,
etc.);
°
Whether
capital
commitments
have
been
made
or
are
projected
to
be
made
;
and
°
The
pre­
compliance
reports
in
2006
and
later
years
must
provide
an
update
of
the
progress
in
each
of
these
areas.

5.
Compliance
Reports
for
Refiners,
Importers,
and
Distributors
of
Designated
Diesel
Fuel
a.
Designate
and
Track
Reporting
Requirements
i.
Quarterly
Reports
From
June
1,
2007
and
through
September
1,
2010,
all
entities
who
are
required
to
maintain
records
must
report
the
following
information
by
facility
to
EPA
on
a
quarterly
basis:

°
The
total
volume
in
gallons
of
each
type
of
designated
diesel
fuel
for
which
custody
was
transferred
by
the
entity
to
any
other
entity,
and
the
EPA
entity
and
facility
identification
number(
s),
as
applicable,
of
the
transferee;
and
332
°
The
total
volume
in
gallons
of
each
type
of
designated
diesel
fuel
for
which
custody
was
received
by
the
entity
from
any
other
entity
and
the
EPA
entity
and
facility
identification
number(
s),
as
applicable,
of
the
transferor.

If
a
facility
receives
fuel
from
another
facility
that
does
not
have
an
EPA
facility
identification
number
then
that
batch
of
fuel
must
be
designated
and
reported
as
1)
heating
oil
if
it
is
marked,
2)
highway
diesel
fuel
if
taxes
have
been
assessed,
3)
NRLM
diesel
fuel
if
the
fuel
is
dyed
but
not
marked.

Terminals
must
also
report
the
results
of
all
compliance
calculations
including
the
following:
°
The
total
volumes
received
of
each
fuel
designation
required
to
be
reported
over
the
quarterly
compliance
period;
°
The
total
volumes
transferred
of
each
fuel
designation
required
to
be
reported
over
the
quarterly
compliance
period;
°
Beginning
and
ending
inventories
of
each
fuel
designation
required
to
be
reported
over
the
quarterly
compliance
period;
°
Calculations
showing
that
the
volume
of
highway
diesel
fuel
distributed
from
the
facility
relative
to
the
volume
received
did
not
increase
since
June
1,
2007;
and
°
Calculations
showing
that
the
volume
of
high
sulfur
NRLM
diesel
fuel
did
not
increase
by
a
greater
proportion
than
the
volume
of
heating
oil
over
the
quarterly
compliance
period
(
not
applicable
in
the
Northeast/
Mid­
Atlantic
Area
or
Alaska).

The
quarterly
compliance
periods
and
dates
by
which
the
reports
are
due
for
each
period
are
as
follows.

Table
V.
G­
1.
Quarterly
Compliance
Periods
and
Reporting
Datesa
Quarterly
Compliance
Period
Report
Due
Date
July
1
through
September
30
November
30
October
1
though
December
31
February
28
January
1
through
March
31
May
31
April
1
through
June
30
August
31
Notes:
a
The
first
quarterly
reporting
period
will
be
from
June
1,
2007
though
September
30,
2007
and
the
last
quarterly
compliance
period
will
be
from
April
1,
2010
through
May
31,
2010.

ii.
Annual
Reports
Beginning
June
1,
2007,
all
entities
that
are
required
to
maintain
records
for
batches
of
fuel
must
report
by
facility
on
an
annual
basis
(
due
August
31)
information
on
the
total
volumes
received
of
each
fuel
designation
as
well
as
the
results
of
all
compliance
calculations
including
the
following:
333
°
The
total
volumes
transferred
of
each
fuel
designation;
°
Beginning
and
ending
inventories
of
each
fuel
designation;
°
In
Alaska,
for
diesel
fuel
designated
as
high
sulfur
NRLM
delivered
from
June
1,
2007
through
May
31,
2010
and
for
diesel
fuel
designated
as
500
ppm
sulfur
NRLM
delivered
from
June
1,
2010
through
May
31,
2014,
refiners
must
report
all
information
required
under
their
individual
compliance
plan,
including
the
end­
users
to
whom
each
batch
of
fuel
was
delivered
and
the
total
delivered
to
each
end­
user
for
the
compliance
period;
°
Ending
with
the
report
due
August
31,
2010,
calculations
showing
that
the
volume
of
highway
diesel
fuel
distributed
from
the
facility
relative
to
the
volume
received
did
not
increase
since
June
1,
2007;
°
Ending
with
the
report
due
August
31,
2010,
calculations
showing
that
the
volume
of
highway
diesel
fuel
distributed
from
the
facility
relative
to
new
volume
received
did
not
increase
over
the
annual
compliance
period
by
more
than
two
percent
of
the
total
volume
of
highway
diesel
fuel
received;
°
Ending
with
the
report
due
August
31,
2010,
calculations
showing
that
the
volume
of
high
sulfur
NRLM
diesel
fuel
did
not
increase
by
a
greater
proportion
than
the
volume
of
heating
oil
over
the
annual
compliance
period
(
not
applicable
in
the
Northeast/
Mid­
Atlantic
Area
or
Alaska);
°
Calculations
showing
that
the
volume
of
heating
oil
did
not
decrease
over
the
annual
compliance
period,
beginning
June
1,
2010
(
not
applicable
in
the
Northeast/
Mid­
Atlantic
Area
or
Alaska);
and
°
From
June
1,
2010
through
August
1,
2012,
calculations
showing
that
the
volume
of
500
ppm
sulfur
NR
diesel
fuel
did
not
increase
by
a
greater
proportion
than
the
volume
of
500
ppm
sulfur
LM
diesel
fuel
over
the
annual
compliance
period
(
not
applicable
in
the
Northeast/
Mid­
Atlantic
Area
and
Alaska.

b.
Other
Reporting
Requirements
After
the
NRLM
diesel
fuel
sulfur
requirements
begin
on
June
1,
2007,
refiners
and
importers
will
be
required
to
submit
annual
compliance
reports
for
each
refinery
or
import
facility.
If
a
refiner
produces
15
ppm
sulfur
or
500
ppm
sulfur
fuel
early
under
the
credit
provisions,
its
annual
compliance
reporting
requirement
will
begin
on
June
1
following
the
beginning
of
the
early
fuel
production.
These
reporting
requirements
will
sunset
after
all
flexibility
provisions
end
(
i.
e.,
after
May
31,
2014).
Annual
compliance
reports
will
be
due
on
August
31.

A
refiner's
or
importer's
annual
compliance
report
must
include
the
following
information
for
each
of
its
facilities:

°
Batch
reports
for
each
batch
produced
or
imported
providing
information
regarding
volume,
designation
(
e.
g.,
500
highway),
sulfur
level
and
whether
the
fuel
was
dyed
and/
or
marked.
Each
batch
can
only
have
one
designation.
Therefore,
if
a
refiner
ships
100
gallons
of
500
ppm
sulfur
fuel
in
2007
and
wants
to
designate
50
gallons
334
as
highway
500
and
50
gallons
as
NR
500,
the
refiner
must
report
two
separate
batches
and
there
must
be
two
PTDs
 
one
for
50
gallons
of
highway
500
and
one
for
50
gallons
of
NR
500).

°
Report
on
the
generation,
use,
transfer
and
retirement
of
diesel
sulfur
credits.
Credit
transfer
information
must
include
the
identification
of
the
number
of
credits
obtained
from,
or
transferred
to,
each
entity.
Reports
must
also
show
the
credit
balance
at
the
start
of
the
period,
and
the
balance
at
the
end
of
the
period.
NRLM
or
nonroad
diesel
sulfur
credit
information
is
required
to
be
stated
separately
from
highway
diesel
credit
information
since
the
two
credit
programs
are
treated
separately.

°­
For
a
small
refiner
that
elects
to
produce
15
ppm
sulfur
NRLM
diesel
fuel
by
June
1,
2006
and
therefore
is
eligible
for
a
limited
relaxation
in
its
interim
small
refiner
gasoline
sulfur
standards,
the
annual
reports
must
also
include
specific
information
on
gasoline
sulfur
levels
and
progress
toward
highway
and
NRLM
diesel
fuel
desulfurization.

6.
PTDs
Refiners,
importers,
and
other
parties
in
the
distribution
system
must
provide
information
on
commercial
PTDs
that
identify
diesel
fuel
distributed
by
use
designation
and
sulfur
content;
i.
e.,
for
use
in
or
motor
vehicles,
nonroad
equipment,
locomotive
and
marine
equipment,
or
nonroad,
locomotive,
and
marine
diesel
equipment,
as
appropriate,
and
the
sulfur
standard
to
which
the
fuel
is
subject.
The
PTD
must
indicate
whether
the
fuel
is
diesel
fuel,
heating
oil,
kerosene,
exempt
fuel,
or
other.
It
must
further
state
whether
it
is
No.
1
or
No.
2,
dyed
or
undyed,
marked
heating
oil,
marked
LM
fuel,
or
unmarked.
The
specific
designations
on
PTDs
will
change
during
the
course
of
the
program.
For
example,
the
highway
designation
for
500
ppm
sulfur
fuel
ends
after
2010.
Where
a
party
delivers
or
receives
a
particular
load
of
fuel
that
has
a
uniform
sulfur
content
but
that
has
two
different
designations,
the
parties
must
utilize
two
different
PTDs.
For
example,
if,
in
2007
a
refiner
moves
1,000
gallons
of
500
ppm
sulfur
diesel
into
a
pipeline,
and
the
refiner's
designation
is
that
half
of
that
product
is
highway
500
and
half
is
nonroad
500,
the
parties
would
utilize
one
PTD
for
500
gallons
of
highway
500
ppm
sulfur
diesel
fuel
and
another
for
500
gallons
of
nonroad
500
diesel
fuel.

As
in
other
fuels
programs,
PTDs
must
accompany
each
transfer
of
either
title
or
custody
of
fuel.
However,
only
custody
transfers
are
relevant
to
compliance
with
the
designation
and
tracking
requirements
and
the
downgrade
limitations,
and
transfers
to
retail
outlets
and
wholesale
purchaser­
consumers
of
fuel
by
distributors
below
the
truck
rack
are
not
covered
by
the
designate
and
track
scheme.
Therefore,
the
PTDs
for
these
non­
designate
and
track
transfers
are
somewhat
more
straightforward.
192
Only
one
PTD
is
required
for
each
fuel
designation
or
classification
regardless
of
the
number
of
motor
vehicles
or
the
number
of
diesel­
powered
NRLM
equipment
that
are
fueled.

335
We
believe
this
additional
information
on
commercial
PTDs
is
necessary
to
maintain
the
integrity
of
the
various
grades
of
diesel
fuel
in
the
distribution
system.
Parties
in
the
system
will
be
better
able
to
identify
which
type
of
fuel
they
are
dealing
with
and
more
effectively
ensure
that
they
are
meeting
the
requirements
of
today's
program.
This
in
turn
will
help
to
ensure
that
misfueling
of
sulfur
sensitive
engines
does
not
occur
and
that
the
program
results
in
the
needed
emission
reductions.

Today's
rule
allows
the
use
of
product
codes
to
convey
the
required
information,
except
for
transfers
to
truck
carriers,
retailers
and
wholesale
purchaser­
consumers.
We
believe
that
more
explicit
language
on
PTDs
to
these
parties
is
necessary
since
employees
of
such
parties
are
less
likely
to
be
aware
of
the
meaning
of
product
codes.
PTDs
will
not
be
required
for
transfers
of
product
into
nonroad,
locomotive,
or
marine
equipment
at
retail
outlets
or
wholesale
purchaserconsumer
facilities
with
the
exception
of
mobile
refuelers.
Mobile
refuellers
are
required
to
provide
a
separate
PTD
to
their
customers
for
each
type
of
fuel
(
e.
g.,
500
ppm
sulfur
NRLM
diesel
fuel,
15
ppm
sulfur
NRLM
diesel
fuel,
or
15
ppm
highway
diesel
fuel)
that
they
dispense
from
tanker
trucks
or
other
vessels
into
motor
vehicles,
nonroad
diesel
engines
or
nonroad
diesel
engine
equipment,
for
each
instance
when
they
refuel
such
equipment
at
a
given
location.
192
a.
Kerosene
and
Other
Distillates
to
Reduce
Viscosity
To
ensure
that
downstream
parties
can
determine
the
sulfur
level
of
kerosene
or
other
distillates
that
may
be
distributed
for
use
for
blending
into
15
ppm
sulfur
highway
or
NRLM
diesel
fuel,
for
example,
to
reduce
viscosity
in
cold
weather,
we
are
requiring
that
PTDs
identify
distillates
specifically
distributed
for
such
use
as
meeting
the
15
ppm
sulfur
standard.

b.
Exported
Fuel
Consistent
with
other
EPA
fuel
programs,
NRLM
diesel
fuel
exported
from
the
U.
S.
is
not
required
to
meet
the
sulfur
standards
of
today's
regulations.
For
example,
where
a
refiner
designates
a
batch
of
diesel
fuel
for
export,
and
can
demonstrate
through
commercial
documents
that
the
fuel
was
exported,
such
fuel
would
not
be
required
to
comply
with
the
NRLM
sulfur
standards
in
today's
rule.
Product
transfer
documents
accompanying
the
transfer
of
custody
of
the
fuel
at
each
point
in
the
distribution
system
are
required
to
state
that
the
fuel
is
for
export
only
and
may
not
be
used
in
the
United
States.

c.
Additives
Today's
rule
requires
that
PTDs
for
additives
for
use
in
NRLM
diesel
fuel
state
whether
the
additive
complies
with
the
15
ppm
sulfur
standard.
Like
the
highway
diesel
rule,
this
program
193
Transmix
processors
and
terminal
operators
acting
as
refiners
that
produce
500
ppm
sulfur
diesel
fuel
for
sale
into
the
locomotive
and
marine
markets
are
also
subject
to
the
recordkeeping
requirements.

336
allows
the
sale
of
additives,
for
use
by
fuel
terminals
or
other
parties
in
the
diesel
fuel
distribution
system,
that
have
a
sulfur
content
greater
than
15
ppm
under
specified
conditions.

For
additives
that
have
a
sulfur
content
less
than
15
ppm,
the
PTD
must
state:
"
The
sulfur
content
of
this
additive
does
not
exceed
15
ppm."
For
additives
that
have
a
sulfur
content
greater
than
15
ppm,
the
additive
manufacturer's
PTD,
and
PTDs
accompanying
all
subsequent
transfers,
must
provide
a
warning
that
the
additive's
sulfur
content
exceeds
15
ppm;
the
maximum
sulfur
content
of
the
additive;
the
maximum
recommended
concentration
for
use
of
the
additive
in
diesel
fuel
(
stated
as
gallon
of
additive
per
gallon
of
diesel
fuel);
and
the
increase
in
sulfur
concentration
of
the
fuel
the
additive
will
cause
when
used
at
the
maximum
recommended
concentration.

Today's
rule
contains
provisions
for
aftermarket
additives
sold
to
owner/
operators
for
use
in
diesel
powered
nonroad
equipment.
These
provisions
are
in
response
to
concerns
that
additives
designed
for
engines
not
requiring
15
ppm
sulfur
fuel,
such
as
locomotive
or
marine
engines,
could
accidentally
be
introduced
into
nonroad
engines
if
they
had
no
label
stating
appropriate
use.
Beginning
June
1,
2010,
aftermarket
additives
for
use
in
nonroad
equipment
must
be
accompanied
by
information
that
states
that
the
additive
complies
with
the
15
ppm
sulfur
standard.
We
believe
this
information
is
necessary
for
end
users
to
determine
if
an
additive
is
appropriate
for
use.

7.
Record­
keeping
Requirements
for
Refiners
and
Importers
Refiners
and
importers
of
distillate
fuel
must
maintain
the
following
designate
and
track
records
for
the
distillate
fuel
they
produce
and/
or
import.
The
specific
types
of
distillate
fuel
that
are
subject
to
these
record­
keeping
requirements
are
described
below
for
the
various
periods
of
the
program.
193
°
Batch
number
(
including
whether
it
is
an
incoming
or
out­
going
batch
for
refineries
that
also
handle
previously
designated
fuel);
°
Batch
designation;
°
Volume
in
gallons;
°
Date/
time
of
day
of
custody
transfer;
and
°
Name
and
EPA
entity
and
facility
identification
number
of
the
facility
to
which
the
batch
was
transferred.

For
highway
diesel
fuel,
the
records
must
also
identify
whether
the
batch
was
received
or
delivered
with
or
without
taxes
assessed.
For
NRLM
diesel
fuel,
the
records
must
also
identify
whether
the
batch
was
received
or
delivered
with
or
without
the
IRS
red
dye.
For
heating
oil,
the
records
must
indicate
whether
the
batch
was
received
or
delivered
with
or
without
the
fuel
marker.
337
From
June
1,
2010,
through
May
31,
2012,
the
records
for
LM
fuel
batches
must
also
indicate
whether
the
batch
was
received
or
delivered
with
or
without
the
fuel
marker.

In
addition
to
the
designate
and
track
records,
refiners
and
importers
must
maintain
the
following
records
on
the
highway
and
NRLM
diesel
fuel
that
they
produce
and/
or
import:
°
PTDs;
°
Sampling
and
testing
results
for
sulfur
content
(
for
highway
and
NRLM
diesel
fuel
that
is
subject
to
either
the
15
ppm
or
500
ppm
sulfur
standards),
as
well
as
sampling
and
testing
results
that
are
part
of
a
quality
assurance
program;
°
Sampling
and
testing
results
for
the
cetane
index
or
aromatics
content,
as
well
as
sampling
and
testing
results
for
additives;
°
Records
on
credit
generation,
use,
transfer,
purchase,
or
termination,
maintained
separately
for
the
highway
and
NRLM
diesel
fuel
credit
programs;
and
°
Records
related
to
individual
compliance
plans,
if
applicable,
and
annual
compliance
calculations.

a.
June
1,
2006
through
May
31,
2007
Refiners
and
importers
must
maintain
the
records
listed
above
for
each
batch
of
diesel
fuel
that
they
designate
and
transfer
custody
of
during
the
time
period
from
June
1,
2006
through
May
31,
2007,
with
the
following
fuel
types:

°
No.
1
15
ppm
sulfur
highway
diesel
fuel;
°
No.
2
15
ppm
sulfur
highway
diesel
fuel;
°
15
ppm
sulfur
NRLM
diesel
fuel;
°
No.
1
500
ppm
sulfur
highway
diesel
fuel;
°
No.
2
500
ppm
sulfur
highway
diesel
fuel;
or
°
500
ppm
sulfur
NRLM
diesel
fuel.

b.
June
1,
2007
through
May
31,
2010
Refiners
and
importers
must
maintain
the
records
listed
above
for
each
batch
of
distillate
fuel
that
they
designate
and
transfer
custody
of
during
the
time
period
from
June
1,
2007
through
May
31,
2010
with
the
following
fuel
types:

°
No.
1
15
ppm
sulfur
highway
diesel
fuel;
°
No.
2
15
ppm
sulfur
highway
diesel
fuel;
°
15
ppm
sulfur
NRLM
diesel
fuel;
°
No.
1
500
ppm
sulfur
highway
diesel
fuel;
°
No.
2
500
ppm
sulfur
highway
diesel
fuel;
or
°
500
ppm
sulfur
NRLM
diesel
fuel;
°
High
sulfur
NRLM
diesel
fuel;
or
°
Heating
oil.
338
c.
June
1,
2010
through
May
31,
2012
Refiners
and
importers
must
maintain
the
records
listed
above
for
each
batch
of
diesel
fuel
that
they
designate
and
transfer
custody
of
during
the
time
period
from
June
1,
2010
through
May
31,
2012,
with
the
following
fuel
types:

°
500
ppm
sulfur
NR
diesel
fuel;
°
500
ppm
sulfur
LM
diesel
fuel;
or
°
Heating
oil.

d.
June
1,
2012
through
May
31,
2014
Refiners
and
importers
must
maintain
the
records
listed
above
for
each
batch
of
distillate
fuel
that
they
transfer
custody
of
and
designate
during
the
time
period
from
June
1,
2012
through
May
31,
2014
with
the
following
fuel
types:

°
15
ppm
sulfur
highway
or
NRLM
diesel
fuel;
°
500
ppm
sulfur
NRLM
diesel
fuel
diesel
fuel;
or
°
Heating
oil.

d.
June
1,
2014
and
Beyond
Refiners
and
importers
must
maintain
the
records
listed
above
for
each
batch
of
heating
oil
that
they
transfer
custody
of
and
designate
during
the
time
period
from
June
1,
2014
and
beyond.

8.
Record­
keeping
Requirements
for
Distributors
Distributors
of
distillate
fuel
must
maintain
the
following
designate
and
track
records
on
a
facility­
specific
basis
for
the
distillate
fuel
they
distribute.
The
specific
distillate
fuel
designations
that
are
subject
to
these
record­
keeping
requirements
are
described
below
for
the
various
periods
of
the
program.

°
Batch
number
(
including
whether
it
is
an
incoming
or
out­
going
batch);
°
Batch
designation;
°
Volume
in
gallons;
°
Date/
time
of
day
of
custody
transfer;
°
Name
and
EPA
entity
and
facility
identification
number
of
the
facility
from
which
the
fuel
batch
was
received
or
to
which
the
fuel
batch
was
delivered;
°
Beginning
and
ending
inventory
volumes
on
a
quarterly
basis;
and
°
Inventory
adjustments.
194
After
August
1,
2012,
LM
fuel
distributed
from
terminals
must
contain
a
concentration
of
the
marker
no
greater
than
0.1
mg/
L.
After
October
1,
2012,
LM
fuel
at
any
location
in
the
fuel
distribution
system
must
contain
no
more
than
a
trace
amount
of
the
marker
(
0.1
mg/
L).

339
For
highway
diesel
fuel,
the
records
must
also
identify
whether
the
batch
was
received
or
delivered
with
or
without
taxes
assessed.
For
NRLM
diesel
fuel,
the
records
must
also
identify
whether
the
batch
was
received
or
delivered
with
or
without
the
IRS
red
dye.
For
heating
oil,
the
records
must
indicate
whether
the
batch
was
received
or
delivered
with
our
without
the
fuel
marker.
From
June
1,
2010,
through
October
1,
2012,
the
records
must
indicate
whether
LM
fuel
was
received
or
delivered
with
or
without
the
fuel
marker.
194
In
addition
to
these
designate
and
track
records,
distributors
will
be
required
to
maintain
records
related
to
their
quarterly
and
annual
compliance
calculations
as
well
as
copies
of
all
PTDs.

If
a
facility
receives
fuel
from
another
facility
that
does
not
have
an
EPA
facility
identification
number
then
that
batch
of
fuel
must
be
designated
as
1)
heating
oil
if
it
is
marked,
or
from
2010
through
2012,
LM
diesel
fuel
if
the
fuel
is
dyed
and
marked
and
is
not
heating
oil
2)
highway
diesel
fuel
if
taxes
have
been
assessed,
and
3)
NRLM
diesel
fuel
if
the
fuel
is
dyed
but
not
marked.

If
a
facility
delivers
fuel
to
other
facilities
and
that
fuel
is
either
500
ppm
sulfur
highway
diesel
fuel
on
which
taxes
have
been
assessed
or
500
ppm
sulfur
NRLM,
or
LM
diesel
fuel
into
which
red
dye
has
been
added
pursuant
to
IRS
requirements,
then
the
facility
does
not
need
to
maintain
separate
records
for
each
of
the
other
facilities
to
which
it
delivered
fuel.
Similarly,
if
a
facility
delivers
batches
of
marked
heating
oil
to
other
facilities,
then
it
does
not
need
to
maintain
separate
records
for
each
of
the
other
facilities
to
which
it
delivered
the
marked
heating
oil.
If
a
facility
only
receives
marked
heating
oil
(
i.
e.,
it
does
not
receive
any
unmarked
heating
oil),
then
it
does
not
need
to
maintain
any
heating
oil
records.
Similarly,
if
a
facility
only
receives
highway
diesel
fuel
on
which
taxes
have
been
assessed
or
NRLM
diesel
fuel
which
has
been
dyed
pursuant
to
IRS
regulations
(
i.
e.,
it
does
not
receive
any
untaxed
highway
diesel
fuel
or
undyed
NRLM
diesel
fuel),
then
it
does
not
need
to
maintain
records
of
the
500
ppm
sulfur
highway
or
NRLM
diesel
fuel
that
it
receives.

a.
June
1,
2006
through
May
31,
2007
Facilities
that
receive
No.
2
15
ppm
sulfur
highway
diesel
fuel
and
distribute
any
No.
2
500
ppm
sulfur
highway
diesel
fuel,
must
maintain
records
for
each
batch
of
diesel
fuel
with
the
following
designations
that
they
receive
or
deliver
during
the
time
period
from
June
1,
2006
through
May31,
2007:

°
No.
1
15
ppm
sulfur
highway
diesel
fuel;
°
No.
2
15
ppm
sulfur
highway
diesel
fuel;
°
No.
2
500
ppm
sulfur
highway
diesel
fuel;
and
340
°
500
ppm
sulfur
NRLM
diesel
fuel.

b.
June
1,
2007
through
May31,
2010
All
facilities
must
maintain
records
for
each
batch
of
diesel
fuel
or
heating
oil
with
the
following
designations
for
which
they
receive
or
transfer
custody
during
the
time
period
from
June
1,
2007
through
May31,
2010:

°
No.
1
15
ppm
sulfur
highway
diesel
fuel;
°
No.
2
15
ppm
sulfur
highway
diesel
fuel;
°
No.
1
500
ppm
sulfur
highway
diesel
fuel;
°
No.
2
500
ppm
sulfur
highway
diesel
fuel;
°
500
ppm
sulfur
NRLM
diesel
fuel;
°
15
ppm
sulfur
NRLM
diesel
fuel;
°
High
sulfur
NRLM
diesel
fuel;
and
°
Heating
oil.

c.
June
1,
2010
through
May31,
2012
All
facilities
must
maintain
records
for
each
batch
of
diesel
fuel
or
heating
oil
with
the
following
designations
for
which
they
receive
or
transfer
custody
during
the
time
period
from
June
1,
2007
through
May
31,
2012.
This
requirement
does
not
apply
to
facilities
located
in
the
Northeast/
Mid­
Atlantic
Area
or
Alaska.

°
500
ppm
sulfur
NR
diesel
fuel;
°
500
ppm
sulfur
LM
diesel
fuel;
or
°
Heating
oil.

c.
June
1,
2012
through
May
31,
2014
Facilities
that
receive
unmarked
fuel
designated
as
heating
oil,
must
maintain
records
for
each
batch
of
diesel
fuel
with
the
following
designations
that
they
receive
or
deliver
during
the
time
period
from
June
1,
2012
through
May
31,
2014.
This
requirement
does
not
apply
to
facilities
located
in
Alaska
or
the
Northeast/
Mid­
Atlantic
Area
unless
they
deliver
marked
heating
oil
to
facilities
outside
of
these
areas.

°
500
ppm
sulfur
NRLM
diesel
fuel;
and
°
Heating
oil.
341
d.
June
1,
2014
and
Beyond
Facilities
that
receive
unmarked
fuel
designated
as
heating
oil
must
maintain
records
for
each
batch
of
diesel
fuel
with
the
following
designations
that
they
receive
or
deliver
during
the
time
period
beginning
June
1,
2014.
This
requirement
does
not
apply
to
facilities
located
in
Alaska
or
the
Northeast/
Mid­
Atlantic
Area
unless
they
deliver
marked
heating
oil
to
facilities
outside
of
these
areas.

°
500
ppm
sulfur
LM
diesel
fuel,
and
°
Heating
oil.

9.
Record­
keeping
Requirements
for
End­
Users
Today's
program
also
contains
certain
record­
keeping
provisions
for
end­
users.
From
June
1,
2007
through
October
1,
2010,
end­
users
that
receive
any
batch
of
high
sulfur
NRLM
in
Alaska
must
maintain
records
of
each
batch
of
fuel
received
for
use
in
NRLM
equipment
unless
otherwise
allowed
by
EPA.
From
June
1,
2010
through
October
1,
2012,
end­
users
that
receive
any
batch
of
500
ppm
sulfur
NR
in
Alaska
must
maintain
records
of
each
batch
of
fuel
received
for
use
in
NR
equipment
unless
otherwise
allowed
by
EPA.
In
addition,
from
June
1,
2012
through
October
1,
2014,
end­
users
that
receive
any
batch
of
500
ppm
sulfur
NRLM
in
Alaska
must
maintain
records
of
each
batch
of
fuel
received
for
use
in
NRLM
equipment
unless
otherwise
allowed
by
EPA.

10.
Record
Retention
We
are
adopting
a
retention
period
of
five
years
for
all
records
required
to
be
kept
under
today's
rule.
This
is
the
same
period
of
time
required
in
other
fuels
rules,
and
it
coincides
with
the
applicable
statute
of
limitations.
We
believe
that
most
parties
in
the
distribution
system
would
maintain
some
or
all
of
these
records
for
this
length
of
time
even
without
the
requirement.

This
retention
period
applies
to
PTDs,
records
required
under
the
designate
and
track
provisions,
records
of
any
test
results
performed
by
any
regulated
party
for
quality
assurance
purposes
or
otherwise
(
whether
or
not
such
testing
was
required
by
this
rule),
along
with
supporting
documentation
such
as
date
of
sampling
and
testing,
batch
number,
tank
number,
and
volume
of
product.
Business
records
regarding
actions
taken
in
response
to
any
violations
discovered
must
also
be
maintained
for
five
years.

All
records
that
are
required
to
be
maintained
by
refiners
or
importers
participating
in
the
generation
or
use
of
credits,
hardship
options
(
or
by
importers
of
diesel
fuel
produced
by
a
foreign
refiner
approved
for
the
temporary
compliance
option
or
a
hardship
option),
including
small
refiner
options,
are
also
covered
by
the
retention
period.
195
See
section
80.5
(
penalties
for
fuels
violations);
section
80.23
(
liability
for
lead
violations);

section
80.28
(
liability
for
gasoline
volatility
violations);
section
80.30
(
liability
for
highway
diesel
violations);
section
80.79
(
liability
for
violation
of
RFG
prohibited
acts);
section
80.80
(
penalties
for
RFG/
CG
violations);
section
80.395
(
liability
for
gasoline
sulfur
violations);
section
80.405
(
penalties
for
gasoline
sulfur
regulations).;
and
section
80.610­
614
(
prohibited
acts,
liability
for
violations,
and
penalties
for
highway
diesel
sulfur
regulations.

196
Today's
rule,
in
40
CFR
§
80.610,
provides
that
no
person
shall,
inter
alia,
"
dispense,

supply,
offer
for
supply,
store
or
transport
.
.
."
fuel
not
in
compliance
with
applicable
standards
and
requirements
starting
on
a
certain
date.
These
prohibitions
apply
at
downstream
locations
such
as
retail
outlets,
wholesale
purchaser­
consumer
facilities
as
well
as
end­
user
locations.
The
act
of
storage
or
transport
refers
to
storage
or
transport
in
fuel
storage
tanks
from
which
fuel
is
dispensed
into
motor
vehicles
or
NRLM
engines
or
equipment.
It
does
not
refer
to
storing
or
transporting
the
fuel
that
is
in
the
motor
vehicle
propulsion
tank
or
other
tank
that
is
incorporated
in
the
NRLM
equipment
for
the
purpose
of
supplying
the
engine
with
fuel.
While
the
prohibition
against
dispensing
inappropriate
fuels
does
apply
as
of
the
applicable
date,
the
motor
vehicle
or
NRLM
engine
or
equipment
may
continue
to
burn
any
fuel
in
the
motor
vehicle
fuel
tank
or
NRLM
equipment
fuel
tank
that
was
properly
dispensed
into
such
tank
.

342
H.
Liability
and
Penalty
Provisions
for
Noncompliance
1.
General
The
liability
and
penalty
provisions
of
the
today's
NRLM
diesel
sulfur
rule
are
very
similar
to
the
liability
and
penalty
provisions
found
in
the
highway
diesel
sulfur
rule,
the
gasoline
sulfur
rule,
the
reformulated
gasoline
rule
and
other
EPA
fuels
regulations.
195
Regulated
parties
are
subject
to
prohibitions
which
are
typical
in
EPA
fuels
regulations,
such
as
prohibitions
on
selling
or
distributing
fuel
that
does
not
comply
with
the
applicable
standard,
and
causing
others
to
commit
prohibited
acts.
For
example,
liability
will
also
arise
under
the
NRLM
diesel
rule
for
violating
certain
prohibited
acts
and
requirements,
such
as:
distributing
or
dispensing
NR
diesel
fuel
not
meeting
the
15
ppm
sulfur
standard
for
use
in
model
year
2011
or
later
nonroad
equipment
(
and
after
Dec
1,
2014
into
any
nonroad
diesel
equipment);
distributing
or
dispensing
diesel
fuel
not
meeting
the
500
ppm
sulfur
standard
for
locomotive
and
marine
engines;
distributing
fuel
containing
the
marker
for
use
in
engines
that
require
the
use
of
fuel
that
does
not
contain
the
marker;
prohibitions
and
requirements
under
the
designate
and
track
provisions
in
today's
rule,
including
specific
prohibitions
and
requirements
regarding
fuel
produced
or
distributed
in
the
Northeast/
Mid­
Atlantic
Area
or
in
Alaska.
196
Small
refiners
and
refiners
using
credits
can
produce
high
sulfur
NRLM
when
NRLM
would
otherwise
be
required
to
meet
a
500
ppm
sulfur
standard,
and
can
produce
500
ppm
sulfur
197
An
additional
type
of
liability,
vicarious
liability,
is
also
imposed
on
branded
refiners
under
today's
rule.

343
NR
or
LM
diesel
fuel
when
nonroad
or
LM
diesel
fuel
would
otherwise
be
required
to
meet
a
15
ppm
sulfur
standard.
A
refiner
that
produces
fuel
under
the
small
refiner
and
credit
provisions
would
be
in
violation
unless
they
can
demonstrate
that
they
meet
the
definition
of
a
small
refiner
or
have
sufficient
credits
for
the
volume
of
fuel
produced.
All
regulated
parties
will
be
liable
for
a
failure
to
meet
certain
requirements,
such
as
the
record­
keeping,
reporting,
or
PTD
requirements,
or
causing
others
to
fail
to
meet
such
requirements.

Under
today's
rule,
the
party
in
the
diesel
fuel
distribution
system
that
controls
the
facility
where
a
violation
occurred,
and
other
parties
in
that
fuel
distribution
system
(
such
as
the
refiner,
reseller,
and
distributor),
will
be
presumed
to
be
liable
for
the
violation.
197
As
in
the
Tier
2
gasoline
sulfur
rule
and
the
highway
diesel
fuel
rule,
today's
rule
explicitly
prohibits
causing
another
person
to
commit
a
prohibited
act
or
causing
non­
conforming
diesel
fuel
to
be
in
the
distribution
system.
Non­
conforming
fuels
include:
1)
diesel
fuel
with
sulfur
content
above
15
ppm
incorrectly
represented
as
appropriate
for
model
year
2011
or
later
nonroad
equipment
or
other
engines
requiring
15
ppm
fuel;
2)
diesel
fuel
with
sulfur
content
above
500
ppm
incorrectly
represented
as
appropriate
for
nonroad
equipment
or
locomotives
or
marine
engines
after
the
applicable
date
for
the
500
ppm
sulfur
standard
for
these
pieces
of
equipment;
3)
heating
oil
that
is
required
to
contain
the
marker
which
does
not,
LM
fuel
which
is
required
to
contain
the
marker
which
does
not,
or
other
fuels
that
are
required
to
be
free
of
the
marker
in
which
the
marker
is
present;
4)
fuel
designated
or
labeled
as
500
ppm
sulfur
highway
diesel
fuel
above
and
beyond
the
volume
balance
limitations;
5)
fuel
designated
or
labeled
as
NRLM
above
and
beyond
the
volume
balance
limitations;
or
6)
fuels
otherwise
not
complying
with
the
requirements
of
this
rule.
Parties
outside
the
diesel
fuel
distribution
system,
such
as
diesel
additive
manufacturers
and
distributors,
are
also
subject
to
liability
for
those
diesel
rule
violations
which
could
have
been
caused
by
their
conduct.

Today's
rule
also
provides
affirmative
defenses
for
each
party
presumed
liable
for
a
violation,
and
all
presumptions
of
liability
are
rebuttable.
In
general,
in
order
to
rebut
the
presumption
of
liability,
parties
will
be
required
to
establish
that:
1)
the
party
did
not
cause
the
violation;
2)
PTD(
s)
exist
which
establish
that
the
fuel
or
diesel
additive
was
in
compliance
while
under
the
party's
control;
and
3)
the
party
conducted
a
quality
assurance
sampling
and
testing
program.
As
part
of
their
affirmative
defense
diesel
fuel
refiners
or
importers,
diesel
fuel
additive
manufacturers,
and
blenders
of
high
sulfur
additives
into
diesel
fuel,
will
also
be
required
to
provide
test
results
establishing
the
conformity
of
the
product
prior
to
leaving
that
party's
control.
Blenders
of
static
dissipater
additives
have
alternative
defense
provisions
as
discussed
in
section
V.
C.
Branded
refiners
have
additional
affirmative
defense
elements
to
establish.
The
defenses
under
the
nonroad
diesel
sulfur
rule
are
similar
to
those
available
to
parties
for
violations
of
the
highway
diesel
sulfur,
reformulated
gasoline,
gasoline
volatility,
and
the
gasoline
sulfur
regulations.
Today's
rule
also
clarifies
that
parent
corporations
are
liable
for
violations
of
subsidiaries,
in
a
manner
consistent
with
the
gasoline
sulfur
rule
and
the
highway
diesel
sulfur
rule.
Finally,
the
198
This
limit
is
amended
periodically
pursuant
to
Congressional
authority
to
change
maximum
civil
penalties
to
account
for
inflation.

199
At
downstream
locations
the
violation
will
occur
if
EPA's
test
result
show
a
sulfur
content
of
greater
than
17
ppm,
which
takes
into
account
the
two
ppm
adjustment
factor
for
testing
reproducibility
for
downstream
parties.

344
NRLM
diesel
sulfur
rule
mirrors
the
gasoline
sulfur
rule
and
the
highway
diesel
sulfur
rule
by
clarifying
that
each
partner
to
a
joint
venture
will
be
jointly
and
severally
liable
for
the
violations
at
the
joint
venture
facility
or
by
the
joint
venture
operation.

As
is
the
case
with
the
other
EPA
fuels
regulations,
today's
rule
will
apply
the
provisions
of
section
211(
d)(
1)
of
the
Clean
Air
Act
(
Act)
for
the
collection
of
penalties.
These
penalty
provisions
currently
subject
any
person
that
violates
any
requirement
or
prohibition
of
the
diesel
sulfur
rule
to
a
civil
penalty
of
up
to
$
32,500
for
every
day
of
each
such
violation
and
the
amount
of
economic
benefit
or
savings
resulting
from
the
violation.
198
A
violation
of
a
NRLM
diesel
sulfur
standard
will
constitute
a
separate
day
of
violation
for
each
day
the
diesel
fuel
giving
rise
to
the
violation
remains
in
the
fuel
distribution
system.
Under
today's
regulation,
the
length
of
time
the
diesel
fuel
in
question
remains
in
the
distribution
system
is
deemed
to
be
twenty­
five
days
unless
there
is
evidence
that
the
fuel
remained
in
its
distribution
system
a
lesser
or
greater
amount
of
time.
This
is
the
same
time
presumption
that
is
incorporated
in
the
RFG,
gasoline
sulfur
and
highway
diesel
sulfur
rules.
The
penalty
provisions
in
today
rule
are
also
be
similar
to
the
penalty
provisions
for
violations
of
these
regulations.

EPA
has
included
in
today's
rule
two
prohibitions
for
"
causing"
violations:
1)
causing
another
to
commit
a
violation;
and
2)
causing
non­
complying
diesel
fuel
to
be
in
the
distribution
system.
These
causation
prohibitions
are
like
similar
prohibitions
included
in
the
gasoline
sulfur
and
the
highway
diesel
sulfur
regulations,
and,
as
discussed
in
the
preamble
to
those
rules,
EPA
believes
they
are
consistent
with
EPA's
implementation
of
prior
motor
vehicle
fuel
regulations.
See
the
liability
discussion
in
the
preamble
to
the
gasoline
sulfur
final
rule,
at
65
FR
6812
et
seq.

The
prohibition
against
causing
another
to
commit
a
violation
will
apply
where
one
party's
violation
is
caused
by
the
actions
of
another
party.
For
example,
EPA
may
conduct
an
inspection
of
a
terminal
and
discover
that
the
terminal
is
offering
for
sale
nonroad
diesel
fuel
designated
as
complying
with
the
15
ppm
sulfur
standard,
while
the
fuel,
in
fact,
had
an
actual
sulfur
content
greater
than
the
standard.
199
In
this
scenario,
parties
in
the
fuel
distribution
system,
as
well
as
parties
in
the
distribution
system
of
any
diesel
additive
that
had
been
blended
into
the
fuel,
will
be
presumed
liable
for
causing
the
terminal
to
be
in
violation.
Each
party
will
have
the
right
to
present
an
affirmative
defense
to
rebut
this
presumption.

The
prohibition
against
causing
non­
compliant
diesel
fuel
to
be
in
the
distribution
system
will
apply,
for
example,
if
a
refiner
transfers
non­
compliant
diesel
fuel
to
a
pipeline.
This
prohibition
could
encompass
situations
where
evidence
shows
high
sulfur
diesel
fuel
was
345
transferred
from
an
upstream
party
in
the
distribution
system,
but
EPA
may
not
have
test
results
to
establish
that
parties
downstream
also
violated
a
prohibited
act
with
this
fuel.

The
Agency
expects
to
enforce
the
liability
scheme
of
the
NRLM
diesel
sulfur
rule
in
the
same
manner
that
we
have
enforced
the
similar
liability
schemes
in
our
prior
fuels
regulations.
As
in
other
fuels
programs,
we
will
attempt
to
identify
the
party
most
responsible
for
causing
the
violation,
recognizing
that
party
should
primarily
be
liable
for
penalties
for
the
violation.

2.
What
are
the
Liability
Provisions
for
Additive
Manufacturers
and
Distributors,
and
Parties
That
Blend
Additives
into
Diesel
Fuel?

a.
General
The
final
highway
diesel
rule
permits
the
blending
of
diesel
fuel
additives
with
sulfur
content
in
excess
of
15
ppm
into
15
ppm
highway
diesel
fuel
under
limited
circumstances.
As
more
fully
discussed
earlier
in
this
preamble,
this
rule
also
permits
downstream
parties
to
blend
fuel
additives
having
a
sulfur
content
exceeding
15
ppm
into
15
ppm
nonroad
diesel,
provided
that:
1)
the
blending
of
the
additive
does
not
cause
the
diesel
fuel's
sulfur
content
to
exceed
the
15
ppm
sulfur
standard;
2)
the
additive
is
added
in
an
amount
no
greater
than
one
volume
percent
of
the
blended
product;
and
3)
the
downstream
party
obtained
from
its
additive
supplier
a
product
transfer
document
("
PTD")
with
the
additive's
sulfur
content
and
the
recommended
treatment
rate,
and
that
it
complied
with
such
treatment
rate.
As
discussed
in
section
V.
C,
today's
rule
includes
alternate
affirmative
defense
requirements
for
blenders
of
S­
D
additives
that
can
contribute
a
maximum
of
0.050
ppm
to
the
sulfur
content
of
finished
fuel
subject
to
the
15
ppm
sulfur
standard.
Today's
rule
also
implements
these
same
alternate
defense
requirements
regarding
the
blending
of
such
additives
into
15
ppm
highway
diesel
fuel.

Since
today's
rule
permits
the
limited
use
in
nonroad
diesel
fuel
of
additives
with
high
sulfur
content,
the
Agency
believes
it
might
be
more
likely
that
a
diesel
fuel
sulfur
violation
could
be
caused
by
the
use
of
high
sulfur
additives.
This
could
result
from
the
additive
manufacturer's
misrepresentation
or
inaccurate
statement
of
the
additive's
sulfur
content
or
recommended
treat
rate
on
the
additive's
PTD,
or
an
additive
distributor's
contamination
of
low
sulfur
additives
with
high
sulfur
additives
during
transportation.
The
increased
probability
that
parties
in
the
diesel
additive
distribution
system
could
cause
a
violation
of
the
sulfur
standard
warrants
the
imposition
by
the
Agency
of
increased
liability
for
such
parties.
Therefore,
today's
rule,
like
the
final
highway
diesel
rule,
explicitly
makes
parties
in
the
diesel
additive
distribution
system
liable
for
the
sale
of
nonconforming
diesel
fuel
additives,
even
if
such
additives
have
not
yet
been
blended
into
diesel
fuel.
In
addition,
today's
rule
imposes
presumptive
liability
on
parties
in
the
additive
distribution
system
if
diesel
fuel
into
which
the
additive
has
been
blended
is
determined
to
have
a
sulfur
level
in
excess
of
its
permitted
concentration.
This
presumptive
liability
will
differ
depending
on
whether
the
blended
additive
was
designated
as
meeting
the
15
ppm
sulfur
standard
(
a
"
15
ppm
additive")
or
designated
as
a
greater
than
15
ppm
sulfur
additive
(
a
"
high
sulfur
additive"),
as
discussed
below.
346
b.
Liability
When
the
Additive
Is
Designated
as
Complying
with
the
15
ppm
Sulfur
Standard
Additives
blended
into
diesel
fuel
downstream
of
the
refinery
are
required
to
have
a
sulfur
content
no
greater
than
15
ppm,
and
be
accompanied
by
PTD(
s)
accurately
identifying
them
as
complying
with
the
15
ppm
sulfur
standard,
with
the
sole
exception
of
diesel
additives
blended
into
nonroad
diesel
fuel
at
a
concentration
no
greater
than
one
percent
by
volume
of
the
blended
fuel.

All
parties
in
the
fuel
and
additive
distribution
systems
will
be
subject
to
presumptive
liability
if
the
blended
fuel
exceeds
the
sulfur
standard.
The
two
ppm
downstream
adjustment
will
apply
when
EPA
tests
the
fuel
subject
to
the
15
ppm
sulfur
standard.
Low
sulfur
additives
present
a
less
significant
threat
to
diesel
fuel
sulfur
compliance
than
would
occur
with
the
use
of
additives
designated
as
possibly
exceeding
15
ppm
sulfur.
Thus,
parties
in
the
additive
distribution
system
of
the
low
sulfur
additive
could
rebut
the
presumption
of
liability
by
showing
the
following:
1)
additive
distributors
will
only
be
required
to
produce
PTDs
stating
that
the
additive
complies
with
the
15
ppm
sulfur
standard;
2)
additive
manufacturers
are
also
be
required
to
produce
PTDs
accurately
indicating
compliance
with
the
regulatory
requirements,
as
well
as
producing
test
results,
or
retained
samples
on
which
tests
could
be
run,
establishing
the
additive's
compliance
with
the
15
ppm
sulfur
standard
prior
to
leaving
the
manufacturer's
control.
Once
they
meet
their
defense
to
presumptive
liability,
these
additive
system
parties
will
only
be
held
responsible
for
the
diesel
fuel
non­
conformity
in
situations
in
which
EPA
can
establish
that
the
party
actually
caused
the
violation.

Under
today's
rule,
parties
in
the
diesel
fuel
distribution
system
will
have
the
typical
affirmative
defenses
of
other
fuels
rules.
For
parties
blending
an
additive
into
their
diesel
fuel,
the
requirement
to
maintain
PTDs
showing
that
the
product
complied
with
the
regulatory
standards
will
necessarily
include
PTDs
for
the
additive
that
was
used,
affirming
the
compliance
of
the
additive
and
the
fuel.

c.
Liability
When
the
Additive
Is
Designated
as
Having
a
Possible
Sulfur
Content
Greater
than
15
ppm
Under
today's
rule,
a
nonroad
diesel
fuel
additive
will
be
permitted
to
have
a
maximum
sulfur
content
above
15
ppm
if
the
blended
fuel
continues
to
meet
the
15
ppm
standard
and
the
additive
is
used
at
a
concentration
no
greater
than
one
volume
percent
of
the
blended
fuel.
However,
if
nonroad
diesel
fuel
containing
that
additive
is
found
by
EPA
to
have
high
sulfur
content,
then
all
the
parties
in
both
the
additive
and
the
fuel
distribution
chains
will
be
presumed
liable
for
causing
the
nonroad
diesel
fuel
violation.

Since
this
type
of
high
sulfur
additive
presents
a
much
greater
probability
of
causing
diesel
fuel
non­
compliance,
parties
in
the
additive's
distribution
system
will
have
to
satisfy
an
additional
element
to
establish
an
affirmative
defense.
In
addition
to
the
elements
of
an
affirmative
defense
described
above,
parties
in
the
additive
distribution
system
for
such
a
high
sulfur
additive
will
also
347
be
required
to
establish
that
they
did
not
cause
the
violation,
an
element
of
an
affirmative
defense
that
is
typically
required
in
EPA
fuel
programs
to
rebut
presumptive
liability.

Parties
in
the
diesel
fuel
distribution
system
will
essentially
have
to
establish
the
same
affirmative
elements
as
in
other
fuels
rules,
with
an
addition
comparable
to
the
highway
diesel
rule.
Blenders
of
high
sulfur
additives
into
15
ppm
sulfur
nonroad
diesel
fuel,
will
have
to
establish
a
more
rigorous
quality
control
program
than
will
exist
without
the
addition
of
such
a
high
sulfur
additive.
For
additives
other
than
static
dissipater
additives,
to
establish
a
defense
to
presumptive
liability,
the
Agency
has
adopted
the
proposal
to
require
test
results
establishing
that
the
blended
fuel
was
in
compliance
with
the
15
ppm
sulfur
standard
after
being
blended
with
the
high
sulfur
additive.
This
additional
defense
element
will
be
required
as
a
safeguard
to
ensure
nonroad
diesel
fuel
compliance,
since
the
blender
has
voluntarily
chosen
to
use
an
additive
which
increases
the
risk
of
diesel
fuel
non­
compliance.

An
exception
to
this
defense
element
is
made
for
blenders
of
static
dissipater
additives,
that
are
allowed
by
today's
rule
to
contribute
no
more
than
0.05
ppm
to
the
sulfur
content
of
a
finished
fuel
subject
to
the
15
ppm
sulfur
standard.
As
discussed
in
section
V.
C.
5,
blenders
of
such
additives
may
rely
on
volume
accounting
reconciliation
records
in
lieu
of
the
requirement
to
sample
and
test
each
batch
of
fuel
subject
to
the
15
ppm
sulfur
standard
after
the
addition
of
an
additive
that
exceeds
the
15
ppm
sulfur
standard.
Today's
rule
also
implements
these
same
alternate
defense
requirements
regarding
the
blending
of
such
additives
into
15
ppm
highway
diesel
fuel.

I.
How
Will
Compliance
with
the
Sulfur
Standards
Be
Determined?

Today's
rule
provides
that
compliance
with
the
sulfur
standards
and
use
requirements
under
today's
rule
can
be
determined
by
evaluating
the
designate
and
track
records
(
discussed
in
section
IV.
D.)
and
other
records,
such
as
PTDs;
by
evaluating
compliance
with
the
fuel
marker
requirements
discussed
in
section
IV.
D
and
V.
E;
and
by
sampling
fuel
and
testing
for
sulfur
content.
Today's
rule
includes
a
requirement
for
refiners
and
importers
to
measure
the
sulfur
content
of
every
batch
of
NRLM
fuel
designated
under
the
rule,
using
a
testing
methodology
approved
under
the
provisions
discussed
in
section
V.
H
of
this
preamble.
In
general,
downstream
parties
must
conduct
only
periodic
sampling
and
testing
as
an
element
of
a
defense
to
presumptive
liability
(
retailers
are
exempt
from
sampling
and
testing).
Today's
rule
further
provides
that
in
determining
compliance,
any
evidence
from
any
source
or
location
can
be
used
to
establish
the
diesel
fuel
sulfur
level,
provided
that
such
evidence
is
relevant
to
whether
the
sulfur
level
would
have
met
the
applicable
standard
had
compliance
been
determined
using
an
approved
test
methodology.
While
the
use
of
a
non­
approved
test
method
might
produce
results
relevant
to
determining
sulfur
content,
this
does
not
remove
any
liability
for
failing
to
conduct
required
batch
testing
using
an
approved
test
method.
This
is
consistent
with
the
approach
taken
under
the
gasoline
sulfur
rule
and
the
highway
diesel
sulfur
rule.

For
example,
the
Agency
might
not
have
sulfur
results
derived
from
an
approved
test
method
for
diesel
fuel
sold
by
a
terminal,
yet
the
terminal's
own
test
results,
based
on
testing
using
348
methods
other
than
those
approved
under
the
regulations,
could
reliably
show
a
violation
of
the
sulfur
standard.
Under
today's
rule,
evidence
from
the
non­
approved
test
method
could
be
used
to
establish
the
diesel
fuel's
sulfur
level
that
would
have
resulted
if
an
approved
test
method
had
been
conducted.
This
type
of
evidence
is
available
for
use
by
either
the
EPA
or
the
regulated
party,
and
could
be
used
to
show
either
compliance
or
noncompliance.
Similarly,
absent
the
existence
of
sulfur
test
results
using
an
approved
method,
commercial
documents
asserting
the
sulfur
level
of
diesel
fuel
or
additive
could
be
used
as
some
evidence
of
what
the
sulfur
level
of
the
fuel
would
be
if
the
product
would
have
been
tested
using
an
approved
method.

The
Agency
believes
that
the
same
statutory
authority
for
EPA
to
adopt
the
gasoline
sulfur
rule's
evidentiary
provisions,
Clean
Air
Act
section
211(
c),
provides
appropriate
authority
for
the
evidentiary
provisions
of
today's
diesel
sulfur
rule.
For
a
fuller
explanation
of
this
statutory
authority,
see
the
gasoline
sulfur
final
rule
preamble,
65
FR
6815,
February
10,
2000.
349
VI.
Program
Costs
and
Benefits
In
this
section,
we
present
the
projected
cost
impacts
and
cost
effectiveness
of
the
nonroad
Tier
4
emission
standards
and
fuel
sulfur
requirements.
We
also
present
a
benefit­
cost
analysis
and
an
economic
impact
analysis.
The
benefit­
cost
analysis
explores
the
net
yearly
economic
benefits
to
society
of
the
reduction
in
mobile
source
emissions
likely
to
be
achieved
by
this
rulemaking.
The
economic
impact
analysis
explores
how
the
costs
of
the
rule
will
likely
be
shared
across
the
manufacturers
and
users
of
the
engines,
equipment
and
fuel
that
would
be
affected
by
the
standards.

We
revised
our
cost
and
benefit
analysis
to
reflect
the
comments
we
received
on
our
analysis.
The
fuel­
related
costs
have
been
updated
to
reflect
information
received
from
refiners
as
part
of
EPA's
highway
diesel
fuel
program,
comments
received
on
the
nonroad
NPRM,
as
well
as
more
recent
information
available
on
future
energy
costs
and
the
cost
of
advanced
desulfurization
technologies.
The
engine
and
equipment­
related
costs
were
revised
to
reflect
additional
R&
D
costs
associated
with
tailoring
R&
D
to
each
particular
engine
line
and
to
accommodate
changes
in
the
final
emission
control
requirements,
particularly
with
regard
to
engines
above
750
hp.
These
costs
also
now
presented
in
2002
instead
of
2001
dollars.
With
regard
to
the
benefits
analysis,
we
have
updated
our
methods
consistent
with
Science
Advisory
Board
(
SAB)
advice
as
specified
in
RIA
chapter
9.
Finally,
we
adjusted
the
economic
impact
analysis
to
reflect
the
revised
cost
inputs
and
to
explicitly
model
the
impacts
on
the
locomotive
and
marine
intermediate
market
sectors.

The
results
detailed
below
show
that
this
rule
would
be
highly
beneficial
to
society,
with
net
present
value
benefits
through
2036
of
$
805
billion
using
a
3
percent
discount
rate
and
$
352
billion
using
a
7
percent
discount
rate,
compared
to
a
net
present
value
of
social
cost
of
about
$
27
billion
using
a
3
percent
discount
rate
and
$
14
billion
using
a
7
percent
discount
rate.
The
impact
of
these
costs
on
society
should
be
minimal,
with
the
prices
of
goods
and
services
produced
using
equipment
and
fuel
affected
by
standards
being
expected
to
increase
about
0.1
percent.

Further
information
on
these
and
other
aspects
of
the
economic
impacts
of
this
emission
control
program
are
summarized
in
the
following
sections
and
are
presented
in
more
detail
in
the
Final
RIA
for
this
rulemaking.

A.
Refining
and
Distribution
Costs
Meeting
the
500
and
15
ppm
sulfur
caps
will
generally
require
that
refiners
add
hydrotreating
equipment
and
possibly
new
or
expanded
hydrogen
and
sulfur
plants
in
their
refineries.
We
have
estimated
the
cost
of
building
and
operating
this
equipment
using
the
same
basic
methodology
which
was
described
in
the
NPRM.
We
have
updated
that
analysis
with
new
information
obtained
from
the
vendors
of
advanced
desulfurization
technology,
to
better
reflect
current
crude
oil
properties
and
refinery
configurations,
as
well
as
future
hydrogen
costs.
We
have
also
incorporated
information
received
from
refiners
regarding
their
plans
to
produce
15
ppm
highway
diesel
fuel
from
2006­
2010.
Finally,
we
incorporated
the
15
ppm
cap
on
locomotive
and
350
marine
fuel
in
2012,
as
well
as
improving
our
analysis
of
the
impact
of
this
cap
on
costs
incurred
in
the
distribution
system.

The
costs
to
provide
NRLM
fuel
under
the
two­
step
fuel
program
are
summarized
in
Table
VI.
A­
1
below.
All
of
the
following
costs
estimates
are
in
2002
dollars.
Capital
investments
have
been
amortized
at
7
percent
per
annum
before
taxes.
These
estimates
do
not
include
costs
associated
with
fuel
sulfur
testing,
labeling,
reporting
or
record
keeping,
which
we
believe
will
be
small
relative
to
those
associated
with
refining,
distribution
and
lubricity
additives.
A
more
detailed
description
of
the
costs
associated
with
this
final
rule
is
presented
in
the
Final
RIA.

Table
VI.
A­
1.
 
Cost
of
Providing
NRLM
Diesel
Fuel
(
cents
per
gallon
of
affected
fuel)

NRLM
Diesel
Fuel
Years
Affected
Fuel
Volume
(
million
gallons
per
year)
a
Refining
Distribution
(
and
Lubricity)
Total
500
ppm
2007­
2010
11,860
1.9
0.2
2.1
2010­
2012
3,589
2.7
0.6
3.3
2012­
2014
715
2.9
0.6
3.5
15
ppm
2010­
2012
8,145
5.0
0.8
5.8
2012­
2014
12,068
5.6
0.8
6.4
2014
+
13,399
5.8
1.2
7.0
Notes:
a
Volumes
shown
are
for
first
full
year
in
each
period
(
2008,
2011,
2013,
and
2015).

The
costs
shown
(
and
all
of
the
costs
described
in
the
rest
of
this
section)
apply
to
the
74
percent
of
current
NRLM
fuel
that
currently
contains
more
than
500
ppm
sulfur
(
hereafter
referred
to
as
the
affected
volume).

In
2014,
the
affected
volume
of
NRLM
fuel
is
14.6
billion
gallons
out
of
total
NRLM
fuel
volume
of
19.7
billion
gallons.
The
other
5.1
billion
gallons
of
NRLM
fuel
is
currently
spillover
from
fuel
certified
to
the
highway
diesel
fuel
standards.
We
expect
this
to
continue
under
the
2007
highway
diesel
fuel
program.
Thus,
26
percent
of
NRLM
fuel
will
already
meet
at
least
a
500
ppm
sulfur
cap
by
2007
and
a
15
ppm
cap
by
2010
and
will
not
be
affected
by
today's
rule.
The
costs
and
benefits
of
desulfurizing
this
highway
fuel
which
spills
over
into
the
non­
highway
markets
was
included
in
our
cost
estimates
for
the
2007
highway
diesel
fuel
rule.

The
estimated
cost
of
the
first
step
of
the
NRLM
fuel
program
is
slightly
less
than
that
projected
in
the
NPRM
(
cents
per
gallon).
However,
we
have
increased
our
estimated
cost
of
the
second
step
significantly
in
response
to
comments.
These
comments
and
the
changes
to
our
cost
estimates
are
discussed
in
more
detail
in
the
next
two
sections.
The
combined
cost
for
both
steps
351
is
therefore
somewhat
higher
than
expected
in
the
NPRM,
but
nevertheless
consistent
with
projections
for
the
cost
of
15
ppm
highway
diesel
fuel.

We
expect
that
the
increased
cost
of
refining
and
distributing
500
ppm
NRLM
fuel
will
be
completely
offset
by
reductions
in
maintenance
costs,
while
those
for
15
ppm
NRLM
fuel
will
be
significantly
offset.
These
savings
will
apply
to
all
diesel
engines
in
the
fleet
due
to
the
reduced
fuel
sulfur
content,
not
just
new
engines.
Refer
to
section
V.
B
for
a
more
complete
discussion
on
the
projected
maintenance
savings
associated
with
lower
sulfur
fuels.

1.
Refining
Costs
Methodology:
We
followed
the
same
process
that
we
used
in
the
NPRM
to
project
refining
costs,
though
we
have
broken
down
the
description
into
five
steps
instead
of
four.

First,
we
estimate
the
total
volume
of
NRLM
fuel
which
must
be
desulfurized
during
each
step
of
the
program,
as
well
as
each
refinery's
future
total
production
of
distillate
fuel.
Current
and
future
demand
for
all
distillate
fuels
except
diesel
fuel
for
land­
based
equipment
were
based
on
estimates
from
the
Energy
Information
Administration's
(
EIA)
Fuel
Oil
and
Kerosene
Survey
(
FOKS)
for
2001
and
the
2003
Annual
Energy
Outlook
(
AEO).
EPA's
NONROAD
emission
model
was
used
to
estimate
both
current
and
future
fuel
consumption
by
land­
based
nonroad
equipment
to
ensure
the
consistent
treatment
of
both
the
costs
and
benefits
associated
with
this
rule.
Table
VI.
A­
2
shows
our
projections
of
the
volumes
of
fuel
affected
by
today's
rule.
These
volumes
exclude
NRLM
fuel
expected
to
be
certified
to
highway
diesel
fuel
sulfur
caps
prior
to
the
implementation
of
this
rule.
They
also
exclude
distillate
fuel
meeting
a
500
ppm
cap
which
is
produced
during
distribution
from
highway
diesel
fuel,
jet
fuel,
etc.

Table
VI.
A­
2.
 
Volume
of
NRLM
Fuel
Affected
by
Today's
Rule
(
billion
gallons
per
year)

Nonroad
Locomotive
and
Marine
Total
500
ppm
15
ppm
500
ppm
15
ppm
500
ppm
15
ppm
2008
8,406
0
3,454
0
11,860
0
2011
614
8,145
2,975
0
3,589
8,145
2013
468
8,671
247
3,395
715
12,066
2015
0
10,539
2,860
0
13,399
This
marks
a
change
from
the
proposal,
where
all
distillate
fuel
volumes
were
based
on
EIA
FOKS
and
AEO
estimates.
Commenters
pointed
out
that
this
approach
underestimated
fuelrelated
costs
relative
to
emission
reductions
and
monetized
benefits,
since
the
NONROAD
fuel
volumes
used
to
estimate
the
latter
were
larger.
We
in
fact
had
acknowledged
this
inconsistency
in
the
proposal
and
had
said
we
would
address
it
in
the
final
rule.
Our
approach
to
address
the
200
The
year
2014
represents
a
mid­
point
between
the
initial
year
of
today's
fuel
program
and
the
end
of
the
expected
life
of
desulfurization
equipment
(
roughly
15
years).

201
Under
EPA's
2007
highway
diesel
program,
refiners
are
required
to
submit
their
production
plans
for
highway
diesel
fuel
for
2006­
2010.
The
first
of
these
reports
were
due
during
the
summer
of
2003.
EPA
published
a
summary
of
the
results
this
past
fall.
We
consider
these
reports
to
provide
a
more
accurate
projection
of
individual
refinery
plans
than
our
projections
made
during
the
highway
fuel
FRM.

The
latter
was
based
on
cost
minimization
using
our
refinery­
specific
desulfurization
refinery
model.

352
inconsistency
was
to
utilize
the
land­
based
nonroad
fuel
volumes
estimated
by
the
NONROAD
model
for
both
the
costs
and
monetized
benefits.
However,
we
also
conducted
a
sensitivity
analysis
whereby
both
emissions
and
costs
were
estimated
using
EIA
estimates
of
fuel
demand
by
land­
based
nonroad
equipment.
The
results
of
that
analysis
are
discussed
in
chapter
VII
of
the
Final
RIA.

We
made
one
other
revision
to
the
volume
of
diesel
fuel
affected
by
this
rule.
In
analyzing
the
impact
of
the
2007
highway
diesel
fuel
program
for
the
NPRM
analysis,
we
estimated
that
4.4
percent
of
15
ppm
highway
diesel
fuel
would
be
contaminated
during
shipment
and
not
available
for
sale
as
15
ppm
highway
fuel.
This
increased
the
volume
of
15
ppm
highway
fuel
which
had
to
be
produced
at
refineries
before
accounting
for
the
production
of
additional
500
and
15
ppm
NRLM
fuel
in
response
to
the
NRLM
fuel
program.
Due
to
comments
made
on
the
NRPM
(
discussed
in
section
VI.
A.
3.
below),
we
have
improved
our
analysis
to
track
the
disposition
of
this
contaminated
15
ppm
fuel.
Much
of
this
contaminated
fuel
can
be
sold
as
500
ppm
NRLM
from
2007­
2014
and
as
L&
M
fuel
thereafter.
Thus,
the
contaminated
15
ppm
fuel
reduces
the
volume
of
500
and
15
ppm
NRLM
fuel
which
must
be
produced
at
refineries.

Second,
total
distillate
production
by
individual
refineries
were
based
on
their
actual
production
volumes
in
2002,
as
reported
to
EIA.
This
represents
a
minor
revision
to
the
NPRM
analysis,
which
utilized
actual
refiner
production
in
2000.
The
number
of
refineries
needing
to
produce
500
ppm
and
15
ppm
diesel
fuel
under
today's
final
rule
was
based
on
the
projected
diesel
fuel
and
heating
oil
demand
in
2014.200
To
be
consistent,
the
2002
distillate
production
volumes
of
individual
refiners
were
increased
to
2014
levels
using
EIA
projections
of
growth
in
total
distillate
production
by
domestic
refiners.

Third,
we
estimated
the
cost
to
desulfurize
diesel
fuel
to
both
500
ppm
and
15
ppm
for
each
domestic
refinery.
This
considered
both
the
volume
of
diesel
fuel
being
produced
and
its
composition
(
e.
g.,
percentage
of
straight
run,
light
cycle
oil,
etc.).
Estimates
of
the
volumes
of
diesel
fuel
already
being
desulfurized
to
meet
the
highway
diesel
fuel
standards
in
2006­
2010
prior
to
the
implementation
of
this
final
rule
were
based
on
refiners'
pre­
compliance
reports.
201
This
marks
a
change
from
the
NPRM
analysis,
where
we
assumed
that
refiners
would
continue
to
produce
their
current
mix
of
highway
and
high
sulfur
diesel
fuel.
While
many
refiners
indicated
that
their
plans
were
preliminary
and
subject
to
change,
we
consider
these
projections
to
be
more
353
probable
than
assuming
that
current
producers
of
diesel
fuel
will
make
no
change
to
their
product
mix
in
complying
with
the
highway
rule.
Meeting
the
15
ppm
highway
diesel
fuel
cap
will
require
significant
investment,
but
some
refiners
will
face
more
than
others.
Some
refiners
will
be
able
to
revamp
their
current
hydrotreater,
while
others
will
need
to
build
an
entirely
new
unit.
Some
refiners
will
be
able
to
expand
their
production
of
highway
fuel
at
little
incremental
cost,
while
others
will
be
able
to
reduce
their
investment
substantially
by
reducing
their
production
volume.
Use
of
refiners'
own
projections,
as
opposed
to
our
own
cost
methodology
assumptions,
allows
us
to
incorporate
as
much
refinery­
specific
information
as
is
currently
possible.

In
projecting
desulfurization
costs,
we
updated
a
number
of
the
inputs
to
our
cost
estimation
methodology.
We
increased
natural
gas
and
utility
costs
to
reflect
those
projected
in
EIA's
2003
AEO.
The
NPRM
analysis
utilized
projections
from
2002
AEO.
Forecasted
natural
gas
costs
in
2003
AEO
are
considerable
higher
than
in
2002
AEO,
though
still
lower
than
current
market
prices.
In
response
to
comments,
we
also
increased
the
factor
for
off­
site
capital
costs
to
better
reflect
the
cost
of
sulfur
plant
expansions.
The
NPRM
analysis
utilized
an
off­
site
factor
developed
in
support
of
the
Tier
2
gasoline
and
2007
highway
diesel
fuel
programs,
where
the
amount
of
sulfur
removed
per
gallon
was
a
fraction
of
that
occurring
here
with
NRLM
fuel.
We
also
continued
to
update
our
cost
estimates
for
advanced
desulfurization
technologies,
as
these
technologies
continue
their
evolution.
As
discussed
in
Section
IV,
the
latest
information
concerning
Process
Dynamics's
IsoTherming
process
indicate
somewhat
higher
costs
than
earlier
estimates.
We
also
reduced
our
projection
of
the
penetration
of
these
advanced
technologies
in
2010
from
80
to
60
percent.

Fourth,
we
estimated
which
refineries
will
likely
find
it
difficult
to
stay
in
the
heating
oil
market
after
the
implementation
of
the
NRLM
sulfur
standards,
due
to
their
location
relative
to
major
pipelines
and
the
size
of
the
heating
oil
market
in
their
area.
Those
not
located
in
major
heating
oil
markets
and
not
connected
to
pipelines
serving
these
areas
were
projected
to
have
to
meet
the
500
and
15
ppm
caps
in
2007
and
2010,
respectively.

Fifth,
we
estimated
which
of
the
remaining
refineries
would
likely
produce
NLRM
fuel
under
today's
program.
As
was
done
in
the
proposal,
we
assumed
that
those
refineries
with
the
lowest
projected
compliance
costs
would
be
the
most
likely
to
produce
the
required
fuel
until
demand
was
met.
Inter­
PADD
transfers
of
fuel
between
PADD
3
and
PADD
1
were
not
constrained.
PADD
3
refineries
were
also
assumed
to
supply
PADD
2
with
15
ppm
NRLM
fuel
once
all
PADD
2
refineries
were
producing
15
ppm
distillate
fuel.
We
also
assumed
that
domestic
refineries
would
preferentially
supply
the
lowest
sulfur
fuels
compared
to
imports.
Thus,
imports
of
15
and
500
ppm
NRLM
fuel
were
only
assumed
after
all
refineries
in
a
PADD
were
projected
to
produce
either
15
or
500
ppm
fuel,
respectively.
The
small
refiner
provisions
included
in
today's
NRLM
fuel
program
were
considered,
as
these
provisions
temporarily
reduce
the
volume
of
500
and
15
ppm
fuel
required
to
be
produced
in
2007
and
2010,
respectively.
This
portion
of
the
methodology
was
the
same
as
that
used
in
the
NRPM
analysis.
354
Results:
Based
on
EIA
data,
in
2002
114
refineries
produced
highway
diesel
fuel
and
102
refineries
produce
high
sulfur
diesel
fuel
or
heating
oil.
Based
on
refiners'
pre­
compliance
reports,
we
project
that
100
refineries
will
produce
15
ppm
highway
diesel
fuel;
96
refineries
starting
in
2006
and
4
in
2010.
Of
these
100
refineries,
96
currently
produce
some
volume
of
highway
diesel
fuel,
while
4
refineries
currently
only
produce
high
sulfur
distillate
fuel.
Also,
18
refineries
will
cease
to
produce
highway
diesel
fuel
and
shift
to
producing
solely
high
sulfur
distillate
fuel.
This
will
leave
a
total
of
92
refineries
still
producing
high
sulfur
distillate
after
full
implementation
of
the
2007
highway
diesel
fuel
program.

The
number
of
these
92
domestic
refineries
expected
to
produce
either
15
or
500
ppm
NRLM
diesel
fuel
in
response
to
today's
rule
is
summarized
in
Table
VI.
A­
3.

Table
VI.
A­
3.
 
Refineries
Projected
to
Produce
NRLM
Diesel
Fuel
Under
This
Final
Rule
Year
of
Program
500
ppm
NRLM
Diesel
Fuel
15
ppm
NRLM
Diesel
Fuel
All
Refineries
Small
Refineries
All
Refineries
Small
Refineries
2007­
2010
36
0
0
0
2010­
2012
26
13
32
2
2012­
2014
15
13
47
2
2014+
0
0
63
15
During
the
four
periods
shown
in
table
VI.
A­
3,
two
roughly
parallel
sets
of
standards
become
effective.
For
non­
small
refiners,
the
500
ppm
NRLM
fuel
cap
starts
in
2007,
followed
by
the
15
ppm
nonroad
fuel
cap
in
2010,
in
turn
followed
by
the
15
ppm
L&
M
fuel
cap
in
2012.
For
small
refiners,
the
500
ppm
NRLM
fuel
cap
starts
in
2010,
followed
by
the
15
ppm
nonroad
NRLM
fuel
cap
in
2014.
As
shown,
beginning
in
2014,
63
refineries
are
projected
to
be
affected
by
today's
final
rule.
After
complete
implementation
of
today's
rule,
29
refineries
are
expected
to
be
able
to
produce
high
sulfur
heating
oil,
some
as
their
entire
distillate
production,
others
along
with
15
ppm
fuel.
The
number
of
refineries
estimated
to
be
affected
by
today's
rule
is
one
more
than
that
projected
in
the
NPRM.
There,
we
estimated
that
62
refineries
would
have
to
produce
either
15
or
500
ppm
NRLM
fuel
in
2014
and
beyond.

We
project
that
the
capital
cost
involved
to
meet
the
2007
500
ppm
sulfur
cap
will
be
$
310
million.
This
represents
about
$
10
million
for
each
of
the
30
refineries
building
a
new
hydrotreater.
Six
refineries
are
expected
to
produce
500
ppm
NRLM
fuel
using
existing
hydrotreaters
no
longer
being
used
to
produce
500
ppm
highway
fuel.
The
total
investment
cost
is
roughly
half
that
projected
in
the
NPRM
($
600
million).
The
decrease
is
due
to
a
greater
volume
of
500
ppm
NRLM
fuel
coming
from
existing
hydrotreaters.
This
conclusion
is
based
on
the
number
of
refineries
leaving
the
highway
diesel
fuel
market
according
to
the
refiners'
highway
program
pre­
compliance
reports.
The
investment
per
refinery
that
we
projected
in
the
NPRM
355
($
9.7
million)
was
essentially
unchanged.
Operating
costs
will
be
about
$
4.9
million
per
year
for
the
average
refinery,
or
slightly
greater
than
that
projected
in
the
NPRM
(
due
to
higher
hydrogen
costs
and
a
lower
percentage
of
hydrocrackate
in
the
NRLM
pool).
The
average
cost
of
producing
500
ppm
NRLM
fuel
in
2007
will
be
1.9
cents
per
gallon,
0.3
cent
per
gallon
lower
than
that
projected
in
the
NPRM,
due
primarily
to
the
reduced
capital
expenditure.

In
2010,
an
additional
$
1170
million
will
be
invested
in
revamped
and
new
desulfurization
equipment,
$
1090
million
to
meet
the
15
ppm
nonroad
fuel
cap
and
$
80
million
to
produce
500
ppm
NRLM
fuel
no
longer
eligible
for
a
small
refiner
exemption
to
sell
high
sulfur
NRLM
fuel.
In
2012,
an
additional
$
590
million
will
be
invested
in
revamped
and
new
desulfurization
equipment
to
meet
the
15
ppm
L&
M
cap
Finally,
in
2014
an
additional
$
210
million
will
be
invested
in
additional
15
ppm
fuel
capacity.
Thus,
total
capital
cost
of
new
equipment
and
revamps
related
to
the
NRLM
fuel
program
will
be
$
2280
million,
or
$
36
million
per
refinery,
roughly
5
percent
greater
than
that
projected
in
the
NPRM.
Total
operating
costs
will
be
about
$
8.1
million
per
year
for
the
average
refinery,
slightly
lower
than
that
projected
in
the
NPRM
($
8.3
million
per
year).
The
total
refining
cost,
including
the
amortized
cost
of
capital,
will
be
5.0,
5.6
and
5.8
cents
per
gallon
of
new
15
ppm
NRLM
fuel
in
2010,
2012,
and
2014,
respectively.

The
500
pm
NRLM
fuel
being
produced
in
2010
is
projected
to
cost
2.7
cents
per
gallon.
The
cost
of
this
500
ppm
fuel
is
higher
than
that
projected
in
the
NPRM,
due
primarily
to
a
higher
cost
for
natural
gas
in
the
future.
The
500
pm,
small
refiner
fuel
being
produced
in
2012
is
projected
to
cost
2.9
cents
per
gallon.
All
of
these
costs
are
relative
to
the
cost
of
producing
high
sulfur
fuel
today,
and
includes
the
cost
of
meeting
the
500
ppm
standard
beginning
in
2007.

The
15
ppm
refining
costs
are
significantly
higher
than
the
4.4
cent
per
gallon
cost
projected
in
the
NPRM
for
the
option
where
L&
M
fuel
was
controlled
to
15
ppm
in
addition
to
nonroad
fuel.
The
increase
is
due
to
the
changes
in
refining
cost
methodology
described
above,
particularly
the
reduced
use
of
advanced
desulfurization
technology,
reduced
synergies
with
the
highway
fuel
program
and
increased
natural
gas
costs.

The
average
refining
costs
by
refining
region
are
shown
in
table
VI.
A­
4
below.
These
costs
include
consideration
of
the
small
refiner
provisions.
Combined
costs
are
shown
for
PADDs
1
and
3
because
of
the
large
volume
of
diesel
fuel
which
is
shipped
from
PADD
3
to
PADD
1.
202
See
chapter
7
of
the
RIA
for
further
details
regarding
our
estimation
of
distribution
costs.

356
Table
VI.
A­
4.
 
Average
Refining
Costs
by
Region
(
cents
per
gallon)

500
ppm
Cap
15
ppm
Cap
2007­
2010
2010­
2012
2012­
2014
2010­
2012
2012­
2014
2014+

PADDs
1
&
3
1.6
3.7
2.5
4.6
4.9
5.1
PADD
2
2.8
2.9
3.7
7.1
7.8
7.8
PADD
4
3.3
9.0
9.0
11.6
11.7
11.8
PADD
5
1.2
2.8
3.5
4.3
4.3
5.7
Nationwide
1.8
2.7
2.9
5.0
5.6
5.8
Fuel­
Only
Control
Programs:
We
used
the
same
methodology
to
estimate
refining
costs
for
stand­
alone
500
ppm
and
15
ppm
NRLM
fuel
programs.
The
fully
phased
in
refining
impacts
of
a
15
ppm
NRLM
standard
are
the
same
as
those
described
above
for
the
final
rule
in
2014
and
beyond.
A
fully
phased
in
500
ppm
NRLM
fuel
program
is
projected
to
affect
63
refineries,
cost
2.0
cents
per
gallon
and
require
a
capital
investment
of
$
480
million.

2.
Distribution
Costs
Today's
rule
is
projected
to
impact
distribution
costs
in
four
ways.
First,
we
project
that
a
slightly
greater
volume
of
diesel
fuel
will
have
to
be
distributed,
due
to
the
fact
that
some
of
the
desulfurization
processes
reduce
the
fuel's
volumetric
energy
density
during
processing.
Total
energy
is
not
lost
during
processing,
as
the
total
volume
of
fuel
is
increased
in
the
hydrotreater.
However,
a
greater
volume
of
fuel
must
be
consumed
in
the
engine
to
produce
the
same
amount
of
power.
We
project
that
desulfurizing
diesel
fuel
to
500
ppm
will
reduce
volumetric
energy
content
by
0.7
percent.
The
cost
of
which
is
equivalent
to
0.08
cent
per
gallon
of
affected
NRLM
fuel.
202
We
project
that
desulfurizing
diesel
fuel
to
15
ppm
will
reduce
volumetric
energy
content
by
an
additional
0.52
percent.
This
will
increase
the
cost
of
distributing
fuel
by
an
additional
0.05
cents
per
gallon,
for
a
total
cost
of
0.13
cents
per
gallon
of
affected
15
ppm
NRLM
fuel.

The
second
impact
on
distribution
costs
relates
to
the
disposition
of
15
ppm
fuel
contaminated
during
pipeline
shipment.
We
received
comments
that
the
control
of
L&
M
fuel
sulfur
content,
particularly
to
15
ppm,
would
make
it
difficult
to
sell
off­
specification
15
ppm
fuel.
The
comments
argued
that
much
of
this
material
would
have
to
be
shipped
back
to
refineries
and
reprocessed
to
meet
the
15
ppm
cap.
We
designed
the
program
finalized
today
to
allow
the
continued
sale
of
500
ppm
fuel
into
the
NRLM
market
until
June
1,
2014,
and
into
the
locomotive
and
marine
market
indefinitely.
By
doing
so,
we
were
able
to
minimize,
though
not
eliminate,
357
much
of
the
reprocessing
and
distribution
cost
impacts
of
concern.
We
have
evaluated
both
the
production
and
potential
sale
of
distillate
interface
and
estimated
the
distribution
cost
impacts
of
today's
final
rule
provisions.
The
details
of
this
analysis
are
contained
in
chapter
7
of
the
Final
RIA.

In
our
analysis
of
the
15
ppm
highway
fuel
program,
we
projected
that
the
need
to
protect
the
quality
of
15
ppm
highway
diesel
fuel
would
increase
the
volume
of
highway
diesel
fuel
downgraded
to
a
lower
value
product,
such
as
high
sulfur
diesel
fuel
and
heating
oil,
from
its
current
level
of
approximately
2.2
percent
to
4.4
percent.
Under
today's
rule,
we
expect
that
15
ppm
NRLM
fuel
will
be
shipped
together
with
15
ppm
highway.
Thus,
the
size
of
each
batch
of
15
ppm
fuel
will
increase,
but
the
number
of
batches
will
not.
As
the
downgrade
occurs
at
the
interface
between
batches,
the
volume
being
downgraded
should
not
increase.
At
the
same
time,
we
are
not
projecting
that
interface
volume
will
decrease,
as
high
sulfur
fuels,
such
as
jet
fuel
and,
in
some
cases
heating
oil,
will
still
be
in
the
system.

The
issue
here
is
the
market
to
which
this
interface
volume
can
be
sold.
When
this
interface
volume
meets
the
specifications
of
one
of
the
two
fuels
being
shipped
next
to
each
other,
the
interface
is
simply
added
to
the
batch
of
that
fuel.
For
example,
the
interface
between
regular
and
premium
gasoline
is
added
to
the
regular
grade
batch.
Or,
the
interface
between
jet
fuel
and
heating
oil
is
added
to
the
heating
oil
batch.
One
interface
which
is
never
added
to
either
adjacent
batch
is
a
mixture
of
gasoline
and
any
distillate
fuel,
such
as
jet
or
diesel
fuel.
If
this
interface
was
added
to
the
distillate
batch,
the
gasoline
content
in
the
interface
would
result
in
a
violation
of
the
distillate's
flash
point
specification.
If
this
interface
was
added
to
the
gasoline
batch,
it
would
cause
the
gasoline
to
violate
its
end
point
specification.
Therefore,
this
interface
must
be
shipped
to
a
transmix
processor
to
separate
the
mixture
into
naphtha
(
a
sub­
octane
gasoline)
and
distillate.
The
2007
highway
diesel
fuel
program
will
not
change
this
practice.
The
naphtha
produced
by
transmix
processors
from
gasoline/
distillate
mixtures
is
usually
blended
with
premium
gasoline
to
produce
regular
grade
gasoline.
The
distillate
produced
is
an
acceptable
high
sulfur
diesel
fuel
or
heating
oil,
though
if
the
feed
material
was
primarily
low
sulfur
distillate
and
gasoline
it
will
likely
also
meet
the
current
500
ppm
highway
fuel
cap.

With
the
implementation
of
the
highway
diesel
rule,
there
is
another
incompatible
interface,
that
between
jet
fuel
and
15
ppm
diesel
fuel.
This
interface
can
not
be
cut
into
jet
fuel
due
to
end
point
and
other
concerns.
However,
it
can
usually
be
cut
into
500
ppm
diesel
fuel
as
long
as
the
sulfur
level
of
the
jet
fuel
is
not
too
high.
With
the
lowering
of
the
highway
standard
to
15
ppm,
however,
this
will
no
longer
be
possible.
We
expect
that
pipelines
minimize
this
interface
by
abutting
jet
fuel
and
high
sulfur
distillate
in
the
pipeline
whenever
possible.
However,
it
will
be
unavoidable
under
many
circumstances.
A
substantial
part
of
the
pipeline
distribution
system
currently
does
not
handle
high
sulfur
distillate,
and
we
expect
that
the
highway
program
and
today's
rule
will
likely
cause
additional
pipeline
systems
to
discontinue
carrying
high
sulfur
distillate.
Pipelines
that
do
not
carry
high
sulfur
distillates
will
generate
this
interface
whenever
203
We
expect
that
only
three
types
of
fuel
will
be
carried
by
such
pipeline
systems:
jet
fuel,
15
ppm
diesel
fuel,
and
gasoline
(
premium
and
regular).
Premium
and
regular
gasolines
are
always
shipped
next
to
each
other
so
the
interface
between
premium
and
regular
gasoline
can
be
cut
into
the
batch
of
regular
gasoline.
Thus,
whenever
jet
fuel
is
shipped
it
will
abut
15
ppm
diesel
fuel
on
one
end
and
gasoline
on
the
other.

204
See
chapter
7.1.7
of
the
RIA
regarding
our
analysis
of
the
sulfur
levels
of
this
interface
material.
This
analysis
indicated
that
although
the
maximum
sulfur
specification
of
jet
fuel
3,000
ppm,

in­
use
jet
fuel
sulfur
levels
are
frequently
below
500
ppm.

358
they
ship
jet
fuel.
203
The
highway
rule,
and
today's
rule
projects
that
pipeline
operators
will
segregate
this
interface
by
cutting
it
into
a
separate
storage
tank.
Because
this
interface
can
be
sold
as
500
ppm
NRLM
fuel
or
heating
oil,
and
because
these
markets
exist
nationwide,
there
is
little
impact
beyond
the
need
for
refiners
to
produce
more
15
ppm
highway
diesel
fuel
(
compared
to
the
volume
of
highway
diesel
fuel
produced
prior
to
the
implementation
of
the
15
ppm
standard),
which
was
considered
as
part
of
the
refining
costs
in
the
highway
diesel
rule.

With
control
of
nonroad
fuel
to
15
ppm
sulfur
in
2010
and
LM
fuel
to
15
ppm
sulfur
in
2012,
the
opportunities
to
downgrade
interface
to
another
product
become
increasing
limited.
Where
limited
this
will
increase
costs
due
to
the
need
to
transport
the
interface
to
where
it
can
be
marketed
or
to
a
facility
for
reprocessing.
In
areas
with
large
heating
oil
markets,
such
as
the
Northeast
and
the
Gulf
Coast,
the
control
of
NRLM
sulfur
content
will
still
have
little
impact
on
the
sale
of
this
interface.
However,
in
areas
lacking
a
large
heating
oil
market,
the
sale
of
this
distillate
interface
will
be
more
restricted.
Because
this
interface
will
composed
of
15
ppm
diesel
fuel
and
jet
fuel,
we
estimate
that
the
distillate
interface
created
should
nearly
always
meet
a
500
ppm
cap.
204
Thus,
this
interface
can
be
added
to
500
ppm
NRLM
batches
(
as
well
as
heating
oil,
where
it
is
present
at
the
terminal)
through
2014.
After
2014,
this
500
ppm
interface
fuel
can
only
be
sold
as
L&
M
fuel
or
heating
oil.
An
exception
to
this
applies
in
the
Northeast/
Mid­
Atlantic
Area,
where
this
interface
cannot
be
sold
into
the
nonroad
fuel
market
after
2010,
nor
into
the
L&
M
fuel
market
after
2012.

In
chapter
7
of
the
Final
RIA,
we
estimate
the
costs
related
to
handling
this
interface
fuel
during
the
four
time
periods
(
2007­
2010,
2010­
2012,
2012­
2014,
and
2014
and
beyond).
We
project
that
there
will
be
no
additional
costs
prior
to
2010,
as
500
ppm
fuel
will
be
the
primary
NRLM
fuel
and
be
widely
distributed.
Beyond
2010,
we
estimate
that
terminals
will
have
to
add
a
small
storage
tank
for
this
fuel,
as
500
ppm
highway
diesel
fuel
and
the
majority
of
500
ppm
NRLM
disappears
from
the
distribution
system.
In
many
places,
this
interface
will
be
the
primary,
if
not
sole
source
of
500
ppm
fuel,
so
existing
tankage
to
add
this
interface
to
will
be
limited.
We
have
also
added
shipping
costs
to
transport
this
fuel
to
NRLM
and
heating
oil
users.
The
volume
of
this
interface
is
significant,
sometimes
a
sizeable
percentage
of
the
combined
NRLM
fuel
and
heating
oil
markets.
In
the
post­
2014
period,
the
volume
of
this
interface
fuel
is
larger
than
the
combined
L&
M
fuel
and
heating
oil
markets
in
certain
PADDs.
Also,
the
volume
of
interface
359
received
at
each
terminal
will
vary
substantially,
depending
on
where
that
terminal
is
on
the
pipeline.
The
advantage
of
this
is
that
where
the
interface
accumulates
it
may
be
of
sufficient
volume
to
justify
marketing
as
a
separate
grade
of
fuel.
Conversely,
the
potential
users
of
this
500
ppm
interface
fuel
may
not
be
located
near
the
terminals
with
the
fuel
necessitating
additional
transportation
costs.

Prior
to
2014,
500
ppm
fuel
can
be
used
as
NRLM
fuel
and
heating
oil
outside
of
the
Northeast/
Mid­
Atlantic
Area.
Additional
storage
tanks
will
be
needed
in
some
cases,
as
this
will
be
the
only
source
of
500
ppm
fuel
in
the
marketplace.
Amortizing
the
cost
of
a
range
of
storage
tank
sizes
over
15
years
of
weekly
shipments
at
a
seven
percent
rate
of
return
before
taxes
costs
produced
an
amortized
cost
of
0.2­
1.6
cents
per
gallon.
These
costs
include
the
carrying
cost
of
the
fuel
stored
in
the
tank.
We
estimate
that
the
average
storage
cost
will
be
closer
to
the
lower
end
of
this
range,
or
0.5
cent
per
gallon.
Nonroad
fuel
users
are
fairly
ubiquitous.
Thus,
increased
shipping
distances
should
be
fairly
short.
We
estimated
45
miles
at
a
cost
of
roughly
1.5
cents
per
gallon.
The
distance
to
L&
M
fuel
users
will
likely
be
longer,
roughly
100
miles,
but
cost
the
same
due
to
greater
efficiencies
of
rail
transport.
It
will
likely
cost
more
to
deliver
interface
fuel
to
heating
oil
users,
as
many
of
these
users
are
smaller,
not
evenly
dispersed
geographically,
purchase
fuel
seasonally,
and
lack
rail
connections.
We
estimate
that
transport
distances
will
increase
an
average
of
85
miles
and
cost
an
additional
3.0
cents
per
gallon
over
today's
costs
to
deliver
this
fuel
to
the
end
user,
in
addition
to
the
0.5
cent
per
gallon
storage
cost.
When
spread
over
all
the
15
and
500
ppm
NRLM
fuel
being
produced
from
2010­
2014
due
to
today's
rule,
the
additional
distribution
cost
from
2010­
2014
is
0.4
cents
per
gallon.

Starting
in
2014,
this
interface
fuel
can
no
longer
be
sold
to
the
nonroad
fuel
market.
Since
the
interface
volume
does
not
change,
this
increases
the
volume
of
fuel
that
must
be
sold
to
the
L&
M
and
heating
oil
markets.
Thus,
overall,
transportation
distances
and
costs
will
likely
increase.
We
expect
that
the
transportation
cost
for
fuel
sold
to
the
L&
M
market
will
increase
from
1.5
to
3.0
cents
per
gallon,
while
that
for
heating
oil
will
increase
to
5.0
cents
per
gallon,
both
including
fuel
storage.
However,
in
PADD
5,
the
volume
of
interface
generated
exceeds
the
total
fuel
demand
of
these
two
markets.
Thus,
we
estimate
that
some
fuel
will
have
to
be
shipped
back
to
refineries
and
reprocessed
to
meet
a
15
ppm
cap
and
shipped
out
a
second
time.
We
estimate
that
the
cost
of
this
shipping
and
reprocessing
will
cost
10
cents
per
gallon.
When
spread
over
all
the
15
ppm
NRLM
fuel
being
produced
after
2014
due
to
today's
rule,
the
additional
distribution
cost
is
0.8
cent
per
gallon.

The
third
impact
of
today's
rule
on
distribution
costs
is
related
to
the
need
for
additional
storage
tanks
to
market
additional
product
grades
at
bulk
plants.
While
this
final
rule
minimizes
the
segregation
of
similar
fuels,
some
additional
segregation
of
products
in
the
distribution
system
will
still
be
required.
The
allowance
that
highway
and
NRLM
diesel
fuel
meeting
the
same
sulfur
specification
can
be
shipped
fungibly
until
it
leaves
the
terminal
obviates
the
need
for
additional
storage
tanks
in
this
segment
of
the
distribution
system
except
for
the
limited
tankage
at
terminals
205
Including
the
refinery,
pipeline,
terminal,
marine
tanker,
and
barge
segments
of
the
distribution
system.

206
This
estimated
cost
includes
the
addition
of
a
separate
delivery
system
on
the
tank
truck.

207
To
avoid
sulfur
contamination
of
NRLM
fuel,
the
tank
compartment
would
need
to
be
flushed
with
some
NRLM
fuel
prior
to
switching
from
carrying
heating
oil
to
NRLM
fuel.

360
necessary
to
handle
500
ppm
sulfur
interface
fuel
discussed
above.
205
Today's
final
rule
also
allows
500
ppm
NRLM
diesel
fuel
to
be
mixed
with
high­
sulfur
NRLM
(
though
it
can
no
longer
be
sold
as
500
ppm
fuel).

However,
we
expect
that
the
implementation
of
the
500
ppm
standard
for
NRLM
diesel
fuel
in
2007
will
compel
some
bulk
plants
in
those
parts
of
the
country
still
distributing
heating
oil
as
a
separate
fuel
grade
to
install
a
second
diesel
storage
tank
to
handle
this
500
ppm
NRLM
fuel.
These
bulk
plants
currently
handle
only
high­
sulfur
fuel
and
hence
will
need
a
second
tank
to
continue
their
current
practice
of
selling
fuel
into
the
heating
oil
market
in
the
winter
and
into
the
nonroad
market
in
the
summer.
We
believe
that
some
of
these
bulk
plants
will
convert
their
existing
diesel
tank
to
500
ppm
fuel
in
order
to
avoid
the
expense
of
installing
an
additional
tank.
However,
to
provide
a
conservatively
high
estimate
we
assumed
that
10
percent
of
the
approximately
10,000
bulk
plants
in
the
U.
S.
(
1,000)
will
install
a
second
tank
in
order
to
handle
both
500
ppm
NRLM
diesel
fuel
and
heating
oil.

The
cost
of
an
additional
storage
tank
at
a
bulk
plant
is
estimated
at
$
90,000
and
the
cost
of
de­
manifolding
a
delivery
truck
is
estimated
at
$
10,000.206
In
the
NPRM,
we
estimated
that
each
bulk
plant
that
needed
to
install
a
new
storage
tank
would
need
to
de­
manifold
a
single
tank
truck.
Thus,
the
NPRM
estimated
the
cost
per
bulk
plant
would
be
$
100,000.
Fuel
distributors
stated
that
the
assumptions
and
calculations
made
by
EPA
in
characterizing
costs
for
bulk
plant
operators
seem
reasonable.
However,
they
also
stated
that
our
estimate
that
a
single
tank
truck
would
service
a
bulk
plant
is
probably
not
accurate.
No
suggestion
was
offered
regarding
what
might
be
a
more
appropriate
estimate
other
than
the
number
is
likely
to
be
much
greater.
Part
of
the
reason
why
we
estimated
that
only
a
single
tank
truck
would
need
to
be
de­
manifolded,
is
that
we
expected
that
due
to
the
seasonal
nature
of
the
demand
for
heating
oil
versus
nonroad
fuel,
it
would
primarily
only
be
at
the
juncture
of
these
two
seasons
that
both
fuels
would
need
to
be
distributed
in
substantial
quantities.
We
also
expected
that
the
small
demand
for
heating
oil
in
the
summer
and
the
small
demand
for
nonroad
fuel
in
the
winter
could
be
serviced
using
a
single
demanifolded
truck.
The
primary
fuel
distributed
during
a
given
season
would
be
distributed
by
single
compartment
tank
trucks.
During
the
crossover
between
seasons,
bulk
plant
operators
would
switch
the
fuel
to
which
such
single
compartment
tank
trucks
are
used
from
nonroad
to
heating
oil
and
back
again.
207
Nevertheless,
we
agree
that
the
subject
bulk
plant
operators
would
likely
be
compelled
to
de­
manifold
more
that
a
single
tank
truck.
Lacking
additional
specific
information,
we
believe
that
assuming
that
each
bulk
plant
operator
de­
manifolds
three
tank
trucks
will
provide
a
conservatively
high
estimate
of
the
cost
to
bulk
plant
operators
due
to
today's
rule.
208
See
Section
IV
of
today's
preamble
for
additional
discussion
of
our
rational
for
this
conclusion.

361
If
all
1,000
bulk
plants
were
to
install
a
new
tank
and
de­
manifold
three
tank
trucks,
the
cost
for
each
bulk
plant
would
$
120,000,
and
the
total
one­
time
capital
cost
would
be
$
120,000,000.
To
provide
a
conservatively
high
estimate
of
the
costs
to
bulk
plant
operators,
we
are
assuming
that
all
1,000
bulk
plants
will
do
so.
Amortizing
the
capital
costs
over
20
years,
results
in
a
estimated
cost
for
tankage
at
such
bulk
plants
of
0.1
cents
per
gallon
of
affected
NRLM
diesel
fuel
supplied.
Although
the
impact
on
the
overall
cost
of
the
program
is
small,
the
cost
to
those
bulk
plant
operators
who
need
to
put
in
a
separate
storage
tank
may
represent
a
substantial
investment.
Thus,
we
believe
many
of
these
bulk
plants
will
search
out
other
arrangements
to
continue
servicing
both
heating
oil
and
NRLM
markets
such
as
an
exchange
agreement
between
two
bulk
plants
that
serve
a
common
area.

As
a
consequence
of
the
end
of
the
highway
program's
temporary
compliance
option
(
TCO)
in
2010
and
the
disappearance
of
high­
sulfur
diesel
fuel
from
much
of
the
fuel
distribution
system
resulting
from
the
implementation
of
today's
rule,
we
expect
that
storage
tanks
at
many
bulk
plants
that
were
previously
devoted
to
500
ppm
TCO
highway
fuel
and
high­
sulfur
fuel
will
become
available
for
dyed
15
ppm
nonroad
fuel
service.
Based
on
this
assessment,
we
do
not
expect
that
a
significant
number
of
bulk
plants
will
need
to
install
an
additional
storage
tank
in
order
to
provide
dyed
and
undyed
15
ppm
diesel
fuel
to
their
customers
beginning
in
2010
(
the
implementation
date
for
the
15
ppm
nonroad
standard)
.208
There
could
potentially
be
some
additional
costs
related
to
the
need
for
new
tankage
in
some
areas
not
already
carrying
500
ppm
fuel
under
the
temporary
compliance
option
of
the
highway
diesel
program
and
which
continue
to
carry
high
sulfur
fuel.
However,
we
expect
them
to
be
minimal
relative
to
the
above
0.1
cent
per
gallon
cost.
Thus,
we
estimate
that
the
total
cost
of
additional
storage
tanks
at
bulk
plants
that
will
result
from
today's
rule
will
be
0.1
cent
per
gallon
of
affected
NRLM
diesel
fuel
supplied.

The
fourth
impact
on
fuel
distribution
costs
is
a
result
of
the
requirement
that
high
sulfur
heating
oil
be
marked
beginning
June
1,
2007
and
that
500
ppm
sulfur
LM
diesel
produced
by
refiners
or
imported
be
marked
from
2010
through
2012
outside
of
the
Northeast/
Mid­
Atlantic
Area
and
Alaska.
The
NPRM
projected
that
there
would
be
no
capital
costs
associated
with
the
proposed
marker
requirement.
We
proposed
that
the
marker
would
be
added
at
the
refinery
gate,
and
that
the
current
requirement
that
non­
highway
fuel
be
dyed
red
at
the
refinery
gate
be
made
voluntary.
Thus,
we
believed
that
the
refiner's
additive
injection
equipment
that
is
currently
used
to
inject
red
dye
into
off­
highway
diesel
fuel
could
instead
be
used
to
inject
the
marker
as
needed.
As
a
result
of
the
allowance
provided
in
today's
final
rule
that
the
marker
be
added
at
the
terminal
rather
than
the
refinery
gate,
and
our
reevaluation
of
the
conditions
for
dye
injection
at
the
refinery,
we
are
now
assessing
capital
costs
for
terminals
and
refiners
related
to
compliance
with
the
fuel
marker
requirements.

Except
for
fuel
that
is
distributed
directly
from
a
refiner's
rack,
today's
final
rule
allows
the
marker
to
be
added
at
the
terminal
rather
than
at
the
refinery
as
we
proposed
(
see
section
IV.
D
for
209
A
refinery
rack
functions
similar
to
a
terminal
in
that
it
distributes
fuel
by
truck
to
wholesale
purchaser
consumers
and
retailers.

210
Small
refiner
and
credit
high
sulfur
NRLM
will
not
be
permitted
to
be
sold
in
the
area
where
terminals
are
not
required
to
add
the
fuel
marker
to
heating
oil
(
the
"
Northeast/
Mid­
Atlantic
Area").
See
section
IV.
D.

362
a
discussion
of
the
fuel
marker
requirements).
209
We
expect
that
except
for
fuel
dispensed
directly
from
the
refinery
rack,
the
fuel
marker
will
be
added
to
at
the
terminal
to
avoid
the
potential
for
marked
fuel
to
contaminate
jet
fuel
during
distribution
by
pipeline.
Terminals
that
need
to
inject
the
fuel
marker
will
need
to
purchase
a
new
injection
system,
including
a
marker
storage
tank
and
a
segregated
line
and
injector
for
each
truck
loading
station
at
which
fuel
that
is
required
to
be
marked
is
dispensed.
Terminals
will
still
be
subject
to
IRS
red
dye
requirements,
and
thus
will
not
be
able
to
rededicate
such
injection
equipment
to
inject
the
fuel
marker.
Due
to
concerns
regarding
the
need
to
maintain
a
visible
evidence
of
the
presence
of
the
fuel
marker,
today's
rule
also
contains
a
requirement
that
nay
fuel
which
contains
the
fuel
marker
also
contains
visible
evidence
of
red
dye.
Furthermore,
there
is
little
chance
to
adapt
parts
of
the
red
dye
injection
system
(
such
as
the
feed
lines
and
injectors)
for
the
alternate
injection
of
red
dye
and
the
fuel
marker
due
to
concerns
that
NRLM
fuel
become
contaminated
with
the
marker.

Terminal
operators
expressed
concern
regarding
the
potential
burden
on
terminal
operators
from
the
capital
costs
of
adding
new
additive
injection
equipment
for
heating
oil.
In
response
to
these
comments,
today's
rule
includes
provisions
that
exempt
terminal
operators
from
the
fuel
marker
requirements
in
a
geographic
"
Northeast/
Mid­
Atlantic
Area"
and
Alaska.
210
These
provisions
provide
that
any
heating
oil
or
500
ppm
sulfur
LM
diesel
fuel
that
would
otherwise
be
subject
to
the
fuel
marker
requirements
which
is
delivered
to
a
retailer
or
wholesale­
purchaser
consumer
inside
the
Northeast/
Mid­
Atlantic
Area
or
Alaska
does
not
need
to
contain
the
marker.
The
costs
of
the
marker
requirements
for
heating
oil
beginning
in
2007
and
for
500
ppm
sulfur
LM
diesel
fuel
from
2010
through
2012
are
discussed
separately
below.

The
Northeast/
Mid­
Atlantic
Area
was
defined
to
include
the
region
where
the
majority
of
heating
oil
in
the
country
is
projected
to
continue
to
be
supplied
though
the
bulk
distribution
system
(
the
Northeast
and
Mid­
Atlantic).
The
vast
majority
of
heating
oil
consumption
in
the
U.
S.
will
be
within
the
Northeast/
Mid­
Atlantic
Area.
Outside
of
the
Northeast/
Mid­
Atlantic
Area,
we
expect
that
only
limited
quantities
of
heating
oil
will
be
supplied,
primarily
from
certain
refiner's
racks.
We
estimate
that
30
refineries
and
transmix
processor
facilities
outside
of
the
Northeast/
Mid­
Atlantic
Area
will
distribute
heating
oil
from
their
racks
(
in
limited
volumes)
on
a
sufficiently
frequent
basis
to
warrant
the
installation
of
a
marker
injection
system
at
a
total
one
time
cost
of
$
1,500,000.

Terminals
outside
of
the
Northeast/
Mid­
Atlantic
Area
will
mostly
be
located
in
areas
without
continued
production
and/
or
bulk
shipment
of
heating
oil.
Consequently,
any
high
sulfur
211
The
estimated
marker
injection
equipment
costs
include
the
cost
of
marker
storage
tanks,

lines,
and
injectors.

363
diesel
fuel
they
sell
will
typically
be
NRLM.
Terminals
located
within
the
Northeast/
Mid­
Atlantic
Area
will
not
need
to
mark
their
heating
oil,
except
for
those
few
that
choose
to
ship
heating
oil
outside
of
the
Northeast/
Mid­
Atlantic
Area.
The
terminals
most
likely
to
install
marker
injection
equipment
will
therefore
be
those
in
states
outside
the
Northeast/
Mid­
Atlantic
Area
with
modest
markets
for
heating
oil
after
the
implementation
of
this
program.
As
discussed
in
chapter
7
of
the
RIA,
in
analyzing
the
various
situations,
we
project
that
fewer
than
60
terminals
nationwide
will
choose
to
install
marker
injection
equipment
at
a
total
cost
of
$
4,150,000.211
The
total
capital
cost
to
refiners
and
terminals
to
install
marker
injection
equipment
is
estimated
to
be
$
5,650,000.
Thus,
the
Northeast/
Mid­
Atlantic
Area
provisions
in
today's
rule
minimizes
the
number
of
terminals
that
will
need
to
install
additive
injection
equipment
and
its
associated
cost
to
comply
with
the
marker
requirement
for
heating
oil.

In
the
NPRM
we
estimated
that
the
cost
to
blenders
of
the
fuel
marker
in
bulk
quantities
would
translate
to
0.2
cents
per
gallon
of
fuel
treated
with
the
marker.
This
estimate
was
based
on
the
fee
charged
by
a
major
pipeline
to
inject
red
dye
at
the
IRS
concentration
into
its
customers
diesel
fuel.
We
used
this
estimate
because
we
lacked
specific
cost
information
on
the
proposed
marker,
and
we
believed
that
it
provided
a
conservatively
high
estimate
of
marker
cost.
Since
the
proposal,
we
received
input
from
a
major
distributor
of
fuel
markers
and
dyes,
regarding
the
cost
of
bulk
deliveries
of
the
specified
fuel
marker
to
terminals
which
translates
to
a
cost
of
0.03
cents
per
gallon
of
fuel
treated
with
the
marker.
The
volume
of
heating
oil
that
we
expect
will
need
to
be
marked
has
also
decreased
substantially
from
that
estimated
in
the
NPRM
due
to
the
Northeast/
Mid­
Atlantic
Area
provisions.
We
estimate
that
1.4
billion
gallons
of
heating
oil
will
be
marked
annually,
for
an
annual
marker
cost
of
$
425,000.
In
the
NPRM,
we
projected
that
the
cost
of
marking
heating
oil
would
continue
for
three
years
(
2007
­
2010).
Under
today's
final
rule,
heating
oil
must
be
marked
indefinitely
beginning
in
2007,
but
only
outside
of
the
Northeast/
Mid­
Atlantic
Area
and
Alaska.

Because
heating
oil
outside
of
the
Northeast/
Mid­
Atlantic
Area
is
being
marked
to
prevent
its
use
in
NRLM
engines,
for
the
purposes
of
estimating
the
impact
of
the
marker
requirement
on
the
cost
of
the
NRLM
program
we
have
spread
the
cost
for
the
marker
for
heating
oil
over
NRLM
diesel
fuel.
Amortizing
the
capital
costs
of
marker
injection
equipment
over
20
years,
results
in
an
estimated
cost
of
0.006
cents
per
gallon
of
affected
NRLM
diesel
fuel
supplied.
Spreading
the
cost
of
the
marker
over
the
volume
of
affected
NRLM
fuel
results
in
an
estimated
cost
of
0.003
cents
per
gallon
of
affected
NRLM
fuel.
Adding
the
amortized
cost
of
the
injection
equipment
necessary
to
add
the
marker
to
heating
oil
and
the
cost
or
the
marker
results
in
a
total
estimated
cost
of
the
marker
requirement
for
heating
oil
in
today's
rule
of
0.01
cents
per
gallon
of
affected
NRLM
fuel.

The
final
NRLM
rule
also
requires
that
500
ppm
L&
M
fuel
produced
at
refineries
or
imported
be
marked
from
mid­
2010
through
mid­
2012
outside
of
the
Northeast/
Mid­
Atlantic
Area
364
and
Alaska.
The
adoption
of
a
15
ppm
sulfur
standard
for
LM
diesel
fuel
in
2012
in
today's
rule
allows
us
to
require
that
LM
fuel
be
marked
from
2010
through
2012
rather
than
from
2010
through
2014
as
proposed
(
see
section
IV.
A).
In
addition,
the
way
in
which
the
program
was
crafted
to
avoid
requiring
the
fuel
marker
be
added
to
heating
oil
in
the
Northeast/
Mid­
Atlantic
Area
and
Alaska
allows
us
to
also
provide
that
500
ppm
sulfur
LM
diesel
fuel
in
these
areas
is
not
subject
to
the
marker
requirement
(
see
section
IV.
D).
We
project
that
only
a
small
number
of
refiners
will
produce
500
ppm
sulfur
diesel
fuel
subject
to
the
marker
requirements
fuel
and
that
it
will
not
be
shipped
via
pipeline.
Thus,
most
of
this
fuel
can
be
marked
at
the
refinery,
limiting
the
number
of
facilities
which
need
to
add
marking
equipment
in
response
to
this
requirement.
We
estimate
that
15
facilities
will
have
to
do
so,
at
a
cost
of
$
60,000
each,
for
a
total
of
$
900,000.
Amortizing
this
over
the
total
volume
of
affected
NRLM
fuel
produced
from
mid­
2010
to
mid­
2012
at
seven
percent
per
year
before
taxes
yields
a
cost
for
the
LM
marker
requirement
of
0.004
cent
per
gallon.
Including
the
cost
of
the
marker
(
0.03
cent
per
gallon
of
marked
fuel)
increases
this
cost
to
0.01
cent
per
gallon
of
NRLM
fuel.

We
summed
these
various
costs
incurred
to
the
distribution
system
over
four
different
time
periods.
As
shown
in
table
VI.
A­
5,
the
total
additional
distribution
cost
will
be
0.2
cent
per
gallon
of
NRLM
fuel
during
the
first
step
of
the
fuel
program
(
from
2007
through
2010),
0.6
cents
gallon
of
NRLM
fuel
from
2010
to
2012
and
from
2012
to
2014,
and
increase
to
1.0
cent
per
gallon
thereafter.
A
more
detailed
description
of
the
costs
associated
with
downgraded
jet
fuel
and
15
ppm
diesel
fuel
is
presented
in
chapter
7
of
the
Final
RIA.

Table
VI.
A­
5.
 
Summary
of
Distribution
Costs
(
cents
per
gallon)

Cause
of
Increase
in
Distribution
Costs
Time
Period
Over
Which
Costs
Apply
2007­
2010
2010­
2012
2010­
2014
2014+

Distribution
of
additional
NRLM
volume
0.08
0.1
0.1
0.1
Distillate
interface
handling
0
0.4
0.4
0.8
Bulk
plant
storage
tanks
0.1
0.1
0.1
0.1
Heating
oil
and
L&
M
fuel
marker
0.01
0.02
0.01
0.01
Total
0.2
0.6
0.6
1.0
3.
Cost
of
Lubricity
Additives
Hydrotreating
diesel
fuel
tends
to
reduce
the
natural
lubricating
quality
of
diesel
fuel,
which
is
necessary
for
the
proper
functioning
of
certain
fuel
system
components.
There
are
a
variety
of
fuel
additives
which
can
be
used
to
restore
diesel
fuel's
lubricating
quality.
These
additives
are
currently
used
to
some
extent
in
highway
diesel
fuel.
We
expect
that
the
need
for
lubricity
additives
that
will
result
from
the
proposed
500
ppm
sulfur
standard
for
NRLM
diesel
fuel
will
be
212
Please
refer
to
section
IV
in
today's
preamble
for
additional
discussion
regarding
our
projections
of
the
potential
impact
on
fuel
lubricity
of
this
proposed
rule.

365
similar
to
that
for
highway
diesel
fuel
meeting
the
current
500
ppm
sulfur
cap
standard.
212
Industry
experience
indicates
that
the
vast
majority
of
highway
diesel
fuel
meeting
the
current
500
ppm
sulfur
cap
does
not
need
lubricity
additives.
Therefore,
we
expect
that
the
great
majority
of
NRLM
diesel
fuel
meeting
the
proposed
500
ppm
sulfur
standard
will
also
not
need
lubricity
additives.
In
estimating
lubricity
additive
costs
for
500
ppm
diesel
fuel,
we
assumed
that
fuel
suppliers
will
use
the
same
additives
at
the
same
concentration
as
we
projected
will
be
used
in
15
ppm
highway
diesel
fuel.
Based
on
our
analysis
of
this
issue
for
the
2007
highway
diesel
fuel
program,
the
cost
per
gallon
of
the
lubricity
additive
is
about
0.2
cents.
This
level
of
use
is
likely
conservative,
as
the
amount
of
lubricity
additive
needed
increases
substantially
as
diesel
fuel
is
desulfurized
to
lower
levels.
We
also
project
that
only
five
percent
of
all
500
ppm
NRLM
diesel
fuel
will
require
the
use
of
a
lubricity
additive.
Thus,
we
project
that
the
cost
of
additional
lubricity
additives
for
the
affected
500
ppm
NRLM
diesel
fuel
will
be
0.01
cent
per
gallon.
See
the
Final
RIA
for
more
details
on
the
issue
of
lubricity
additives.
We
have
no
reason
to
expect
that
the
implementation
of
today's
NRLM
sulfur
standards
will
impact
diesel
properties
other
than
fuel
lubricity
in
such
a
way
as
to
require
the
use
of
additives.

We
project
that
all
NRLM
fuel
meeting
a
15
ppm
cap
will
require
treatment
with
lubricity
additives.
Thus,
the
projected
cost
will
be
0.2
cent
per
affected
gallon
of
15
ppm
NRLM
fuel.

4.
How
EPA's
Projected
Costs
Compare
to
Other
Available
Estimates
Historically,
the
price
of
highway
diesel
fuel
meeting
a
500
ppm
sulfur
cap
has
exceeded
that
of
high
sulfur
diesel
fuel,
ranging
from
0­
5
cents
per
gallon
from
1995­
99
and
averaging
2.2
cent
per
gallon
over
this
time
period
(
see
chapter
7
of
the
Final
RIA).
Fuel
prices
are
often
a
function
of
market
forces
which
might
not
reflect
the
cost
of
producing
the
fuel.
Still,
given
this
is
a
five­
year
average
price
difference,
it
is
likely
a
reasonable
indication
of
the
cost
of
reducing
highway
diesel
fuel
sulfur
to
500
ppm.
Once
the
small
refiner
provisions
applicable
to
500
ppm
fuel
expire
in
2010,
we
project
that
the
total
cost
of
the
500
ppm
NRLM
fuel
cap
will
be
2.4
cents
per
gallon,
well
within
the
range
of
the
historical
highway­
high
sulfur
fuel
price
difference.
This
similarity
exists
despite
changes
in
a
number
of
factors.
One,
our
projection
of
future
natural
gas
costs
are
significantly
higher
than
those
existing
during
the
above
price
comparison.
Two,
the
refineries
producing
highway
diesel
fuel
historically
likely
did
so
because
they
faced
lower
costs
than
those
refineries
continuing
to
produce
high
sulfur
distillate.
Three,
desulfurization
catalyst
efficiency
has
improved
dramatically
since
the
highway
units
were
installed
and
significant
operating
experience
has
been
obtained
on
highway
units.
Four,
inflation
since
the
early
1990'
s
will
have
increased
the
cost
of
constructing
the
same
hydrotreater.
Five,
and
perhaps
most
importantly,
the
construction
of
some
new
hydrotreaters
to
produce
15
ppm
highway
diesel
fuel
will
allow
the
existing
hydrotreaters
to
produce
500
ppm
NRLM
fuel
at
no
capital
cost.
Thus,
there
are
at
least
five
significant
factors,
two
of
which
would
tend
to
decrease
costs
and
three
of
which
would
tend
to
increase
costs.
It
is
not
surprising
that
these
factors
could
counter­
balance
213
Hirshfeld,
David,
MathPro,
Inc.,
"
Refining
economics
of
diesel
fuel
sulfur
standards,"

performed
for
the
Engine
Manufactuers
Association,
October
5,
1999.

366
each
other,
leading
to
the
conclusion
that
the
500
ppm
cap
could
be
extended
to
NRLM
fuel
at
roughly
the
same
cost
as
for
highway
diesel
fuel.

The
only
existing
market
for
15
ppm
diesel
fuel
is
a
niche
market
for
fleets
and
the
prices
for
this
fuel
likely
bear
little
resemblance
to
the
costs
of
the
15
ppm
highway
or
NRLM
caps.
Thus,
the
only
cost
comparisons
which
can
be
made
are
those
between
engineering
studies.
One
such
study
was
performed
by
Mathpro
for
the
Engine
Manufactures
Association
(
EMA).
Mathpro
estimated
the
cost
of
controlling
the
sulfur
content
of
highway
and
NRLM
fuel
to
levels
consistent
with
both
500
ppm
and
15
ppm
cap
standards.
213
A
detailed
evaluation
of
the
Mathpro
costs
is
presented
in
the
Final
RIA.
There
are
a
number
of
aspects
of
the
study
that
make
direct
comparisons
between
its
estimates
and
our
cost
estimates
difficult.
Nonetheless,
a
crude
comparison
of
15
ppm
costs
indicates
that
our
average
cost
range
of
5.7­
5.9
cent
per
gallon
is
quite
similar
to
the
5.4­
6.6
cents
per
gallon
cost
range
estimated
by
Mathpro.

The
other
available
study
of
15
ppm
fuel
costs
was
performed
by
Baker
and
O'Brien
for
API
and
submitted
in
response
to
the
nonroad
NPRM.
Baker
and
O'Brien
analyzed
two
NRLM
fuel
control
scenarios,
but
neither
one
matched
today's
final
NRLM
fuel
program.
The
scenario
closest
to
today's
program
assumed
that
a
NRLM
fuel
would
be
capped
at
15
ppm
in
2008.
In
this
case,
Baker
and
O'Brien
projected
that
the
refinery­
specific
cost
of
15
ppm
NRLM
fuel
would
range
from
4­
17
cents
per
gallon.
This
is
higher
than
our
projected
range
of
2­
14
cents
per
gallon.
In
addition,
as
described
in
the
next
section,
Baker
and
O'Brien
projected
that
the
volume
of
NRLM
fuel
produced
at
these
costs
would
not
fully
satisfy
NRLM
fuel
demand.
Presumably,
totally
fulfilling
NRLM
fuel
demand
with
domestic
production
would
have
cost
more.

Baker
and
O'Brien
described
portions
of
their
cost
methodology
and
indicated
some
general
assumptions
which
they
made
during
the
study.
However,
the
absence
of
detail
prevents
any
detailed
comparisons
of
their
results
to
ours.
It
was
clear
from
their
report,
though,
that
Baker
and
O'Brien
made
a
number
of
pessimistic
assumptions
about
refiners'
willingness
to
invest
in
desulfurization
capacity
and
that
this
limited
the
number
of
refineries
which
they
assumed
would
invest
to
meet
the
NRLM
sulfur
caps.
This
inevitably
led
to
higher
projected
costs
(
and
lower
production
volumes),
than
if
all
refineries
had
been
considered.
Thus,
it
is
not
surprising
that
they
would
derive
slightly
higher
costs
for
a
much
smaller
volume
of
fuel.
A
more
detailed
evaluation
of
the
Baker
and
O'Brien
cost
estimates
can
be
found
in
the
Final
RIA
and
RTC.

5.
Supply
of
Nonroad,
Locomotive
and
Marine
Diesel
Fuel
We
have
developed
today's
NRLM
fuel
program
to
minimize
its
impact
on
the
supply
of
distillate
fuel.
For
example:
we
have
split
the
control
of
NRLM
fuel
to
15
ppm
sulfur
into
two
steps,
providing
8
years
of
leadtime
for
the
final
step.
We
are
proposing
to
provide
flexibility
to
refiners
through
the
availability
of
banking
and
trading
provisions.
We
have
provided
relief
for
367
small
refiners
and
hardship
relief
for
any
qualifying
refiner.
We
are
also
allowing
500
ppm
diesel
fuel
generated
in
the
distribution
system
to
be
sold
as
L&
M
fuel
indefinitely.

In
the
NPRM,
we
evaluated
four
possible
reasons
why
refiners
might
reduce
their
production
of
NRLM
fuel:
1)
chemical
processing
loses
during
the
desulfurization
process,
2)
refiners
might
leave
the
NRLM
fuel
market,
3)
refiners
might
stop
operations
altogether
(
i.
e.,
shut
down),
and
4)
refiners
might
remove
certain
blendstocks
from
the
fuel
pool
to
reduce
desulfurization
costs.
In
all
four
cases,
we
concluded
that
the
answer
was
no,
that
the
supply
of
NRLM
fuel
would
likely
remain
adequate
after
implementation
of
the
proposed
fuel
program.
All
of
these
findings
started
from
the
position
that
there
would
be
adequate
supply
of
diesel
fuel
after
implementation
of
the
2007
highway
diesel
fuel
program.

Several
commenters,
namely
API
and
NPRA,
took
issue
with
the
above
four
sets
of
arguments,
as
well
as
with
our
conclusion
that
refiners
would
not
reduce
NRLM
fuel
production.
While
not
requesting
any
changes
to
the
2007
highway
diesel
fuel
program,
they
reiterated
previous
concerns
that
supply
shortages
could
occur
under
the
highway
diesel
fuel
program,
even
without
the
added
challenge
of
producing
low
sulfur
NRLM
fuel.
The
primary
basis
for
their
comments
was
a
study
they
had
sponsored
by
Baker
and
O'Brien,
which
evaluated
the
costs
and
likely
supply
impacts
of
the
proposal.

Baker
and
O'Brien
evaluated
two
NRLM
fuel
scenarios:
1)
a
15
ppm
NRLM
fuel
cap
starting
in
2008,
and
2)
a
500
ppm
NRLM
fuel
cap
starting
in
2008,
followed
by
a
15
ppm
cap
only
for
nonroad
fuel
in
2010.
First,
Baker
and
O'Brien
projected
that
13
refineries
with
a
total
crude
oil
capacity
of
971,000
barrels
per
day
would
close
in
response
to
the
2007
highway
rule,
roughly
half
in
2006
and
half
in
2010.
(
Total
U.
S.
refining
capacity
is
currently
16
million
barrels
per
day.)
Then
Baker
and
O'Brien
projected
that
adding
a
15
ppm
NRLM
cap
would
cause
all
of
the
refineries
shutting
down
in
2010
to
close
in
2008,
plus
one
additional
refinery
(
for
a
total
of
14).
Delaying
the
15
ppm
cap
until
2010
and
leaving
L&
M
fuel
at
500
ppm
reduced
the
number
of
refineries
projected
to
close
in
2008,
but
did
not
change
Baker
and
O'Brien's
projection
that
14
refineries
would
close
by
2010.
Given
the
fact
that
Baker
and
O'Brien
projected
the
same
number
of
refinery
closures
for
scenarios
#
1
and
#
2,
it
is
reasonable
to
assume
that
they
would
project
similar
results
for
today's
final
NRLM
fuel
program.
214
Closure
would
occur
at
the
beginning
of
the
15
ppm
highway
fuel
program,
or
2006.

368
Table
VI.
A­
6.
 
Projected
Refinery
Closures:
API
Sponsored
Study
by
Baker
and
O'Brien
No.
of
Refineries
Lost
Crude
Capacity
(
1000
bbl/
day)

2008
2010
2008
2010
2007
Highway
Fuel
Program
8214
13
504
971
Plus
One­
Step
15
ppm
NRLM
Program
14
14
1043
1043
Plus
Two­
Step
NRLM
Program
12
14
924
1043
As
a
result
of
these
refinery
closures,
Baker
and
O'Brien
projected
shortfalls
in
15
and
500
ppm
supply
domestic
refiners.
The
net
shortfalls
are
shown
in
table
VI.
A­
7
below.
Baker
and
O'Brien
stated
that
imports
would
have
to
make
up
the
shortfall,
with
potentially
high
price
impacts.

Table
VI.
A­
7.
 
Projected
Shortfall
in
Near­
Term
Diesel
Fuel
Supply
(
1000
barrels
per
day)

15
ppm
Fuel
500
ppm
Fuel
2008
2010
2008
2010
2007
Highway
Fuel
Program
359
579
308
22
Plus
One­
Step
15
ppm
NRLM
Program
684
930
165
0
Plus
Two­
Step
NRLM
Program
351
639
481
82
To
put
these
projected
shortfalls
in
context,
Baker
and
O'Brien
projects
total
diesel
fuel
demand
to
be
3.3
million
barrels
per
day
in
this
timeframe
(
slightly
lower
than
our
own
projection
summarized
above).
Thus,
these
projected
shortfalls
total
roughly
10­
20
percent
of
total
diesel
fuel
demand,
which
if
true,
would
be
very
significant.

We
evaluated
the
Baker
and
O'Brien
study
and
their
findings.
Baker
and
O'Brien
made
very
pessimistic
assumptions
regarding
the
likelihood
that
refiners
would
invest
in
desulfurization
capacity.
Their
judgment
that
a
refinery
would
close
rather
than
invest
also
was
apparently
based
only
on
what
they
perceived
to
be
excessively
high
desulfurization
costs.
Baker
and
O'Brien
presents
no
information
regarding
the
location
of
these
refineries,
the
competition
they
face,
costs
related
to
closing
down,
nor
the
profits
that
they
would
forego
by
closing.
Baker
and
O'Brien
also
makes
no
mention
of
EPA's
special
provisions
for
refiners
facing
economic
hardship,
nor
the
small
refiner
provisions.
369
We
believe
that
it
is
not
possible
to
project
refinery
closures
without
considering
these
factors.
This
is
supported
by
comments
made
in
response
to
our
proposal
of
the
2007
highway
diesel
fuel
program
by
Mathpro
and
the
National
Economic
Research
Associates.
While
we
are
aware
of
a
couple
of
refineries
that
are
being
offered
for
sale
and
whose
plans
for
producing
low
sulfur
fuels
are
uncertain,
we
have
no
indications
of
as
many
as
eight
refineries
closing
in
2006
in
response
to
the
highway
fuel
program.
In
addition,
despite
uncertainties
at
a
few
refineries,
refiners'
pre­
compliance
reports
for
the
highway
fuel
program
indicate
that
they
are
planning
to
produce
a
sufficient
supply
of
15
and
500
ppm
highway
diesel
fuel
from
2006­
2010.
Therefore,
there
is
ample
evidence
that
Baker
and
O'Brien's
projections
for
the
highway
diesel
fuel
program
are
overly
pessimistic.
It
therefore
appears
likely
that
their
projection
that
the
NRLM
fuel
program
will
cause
an
additional
refinery
to
close
is
also
overly
pessimistic.
The
reader
is
referred
to
the
RTC
for
a
summary
of
these
comments
and
our
detailed
response
to
them.

In
their
comments,
API
also
challenged
our
findings
that
refiners
would
maintain
sufficient
supply
under
the
proposed
NRLM
fuel
program.
After
a
careful
review
of
their
comments
and
other
information
newly
available
since
the
NPRM,
we
do
not
believe
that
the
arguments
presented
by
API
and
NPRA
justify
changing
our
position
that
1)
chemical
processing
loses
during
the
desulfurization
process
will
be
very
small,
2)
refiners
will
be
unlikely
to
leave
the
NRLM
fuel
market,
and
3)
refiners
are
unlikely
to
shut
down
due
to
this
rule.

Regarding
point
#
1,
the
distillate
material
lost
during
desulfurization,
our
position
is
that
the
amount
lost
is
small
(
two
percent),
and
most
of
it
is
lost
in
the
form
of
naphtha
which
can
be
blended
into
gasoline.
Refiners
can
then
adjust
their
mix
of
gasoline
and
distillate
production
to
compensate.
API
claimed
that
in
the
winter,
refiners
were
already
at
maximum
distillate
production
and
could
not
shift
any
additional
heavy
gasoline
material
into
the
distillate
pool.
API
did
not
present
any
evidence
that
this
is
in
fact
the
case.
The
fact
that
some
refiners
actually
crack
distillate
material
into
gasoline
makes
it
difficult
to
accept
their
position.

Regarding
point
#
2,
refiners
leaving
the
NRLM
fuel
market,
we
argued
that
the
only
high
sulfur
distillate
market
remaining
after
2007
was
heating
oil.
Heating
oil
demand
is
flat
or
declining
over
time.
We
project
that
over
30
domestic
refiners
will
still
be
able
to
produce
heating
oil
after
2007,
while
other
refiners
will
be
able
to
produce
sufficient
quantities
of
NRLM
fuel.
If
more
refiners
choose
to
produce
heating
oil,
this
market
will
be
oversupplied
and
prices
will
drop
significantly.
Exporting
high
sulfur
distillate
is
a
possibility
for
some
refiners,
but
this
entails
both
transport
costs,
as
well
as
relatively
low
prices
overseas.
Thus,
a
decision
to
not
invest
in
NRLM
fuel
desulfurization
has
to
be
compared
to
the
losses
involved
with
the
other
options.
API
argued
that
some
refiners
face
much
higher
desulfurization
costs
than
others
and
this
would
lead
those
refiners
to
leave
the
NRLM
fuel
market.
API
did
not
estimate
the
losses
that
refiners
would
entail
when
they
left
the
market.
Studies
performed
for
the
highway
fuel
program
indicate
that
these
losses
can
be
quite
significant
and
inappropriate
conclusions
can
be
drawn
if
they
are
ignored.
The
highway
program
pre­
compliance
reports
also
indicate
that
some
highway
fuel
refiners
are
planning
on
leaving
the
highway
fuel
market
in
2006,
while
others
will
enter
it
for
the
first
time.
Decisions
215
Shifting
NRLM
fuel
blendstocks
to
heating
oil
is
essentially
the
same
as
leaving
the
NRLM
market,
which
was
discussed
under
Point
#
2
above.

370
to
stay
in
or
leave
the
NRLM
fuel
market
are
analogous.
We
have
no
reason
to
believe
refiners
would
approach
this
market
any
differently
than
the
highway
market.

Regarding
point
#
3,
refineries
shutting
down,
API
again
pointed
towards
the
high
costs
faced
by
some
refineries
and
the
fact
that
a
number
of
refineries
have
shut
down
over
the
past
ten
years.
There
have
been
a
number
of
refinery
closures
over
the
past
decade,
though
the
trend
has
slowed
considerably.
API
pointed
towards
two
specific
refineries
which
identified
EPA's
gasoline
and
diesel
fuel
sulfur
controls
as
prime
reasons
for
their
shutting
down.
A
closer
look
at
these
situations
showed
that
the
future
capital
investment
related
to
the
sulfur
controls
could
have
been
a
contributing
factor.
However,
these
refineries
faced
many
other
challenges
and
the
timing
of
their
closure
(
2000
and
2001,
respectively)
showed
that
the
EPA
rules
were
not
the
direct
cause.
The
refiner
involved
did
not
approach
EPA
concerning
any
relief
from
the
rules'
requirements
due
to
economic
hardship.
Thus,
the
connection
between
their
closure
and
our
sulfur
controls
appears
even
more
tenuous.

Another
example
of
a
refinery
closure
unrelated
to
desulfurization
costs
was
Shell's
recent
decision
to
close
their
refinery
in
Bakersfield,
California.
The
reason
was
an
insufficient
supply
of
crude
oil
being
produced
locally.

Analogous
to
a
decision
to
leave
the
NRLM
fuel
market,
shutting
down
completely
involves
the
total
loss
of
any
profit
being
made
on
the
production
of
other
fuels.
API
presented
no
economic
calculations
or
projections
showing
that
it
would
be
in
the
best
interest
of
any
refiner
to
shut
down
rather
than
invest
in
NRLM
fuel
desulfurization.

This
leaves
point
#
4,
that
refiners
might
shift
NRLM
fuel
blendstocks
to
other
markets.
This
is
really
only
an
issue
if
the
blendstocks
are
shifted
to
a
non­
distillate
market.
215
The
most
likely
place
that
NRLM
fuel
blendstocks
might
be
shifted
is
to
the
residual
fuel
market.
In
particular,
heavy
(
material
with
high
densities
and
high
distillation
temperatures)
LCO
and
LCGO
could
be
shifted
to
residual
fuel
using
existing
refining
equipment.
The
heavy
portions
of
these
two
blendstocks
contain
the
greatest
concentrations
of
sulfur
which
is
the
most
difficult
to
remove.
Shifting
this
material
to
residual
fuel,
which
currently
does
not
have
a
sulfur
standard,
would
reduce
the
size
and
cost
of
desulfurization
equipment
needed
to
meet
a
15
ppm
cap.
Or,
it
would
increase
the
volume
of
15
ppm
NRLM
fuel
which
could
be
produced
in
an
existing
hydrotreater.

To
evaluate
this
possibility,
we
estimated
the
cost
of
processing
LCO
(
the
worse
of
the
two
blendstocks)
into
15
ppm
diesel
fuel
for
each
domestic
refinery.
On
average,
desulfurizing
LCO
to
15
ppm
sulfur
cost
11.4
cents
per
gallon.
However,
in
some
cases,
this
cost
reached
15
cents
per
gallon.
The
cost
to
process
heavy
LCO
could
be
twice
these
amounts,
since
the
concentration
of
both
total
sulfur
and
the
most
difficult
to
remove
sulfur
are
concentrated
in
the
heaviest
molecules.
371
A
review
of
historic
fuel
prices
showed
that
residual
fuel
is
usually
priced
25­
30
cents
per
gallon
less
than
diesel
fuel.
The
highest
incremental
desulfurization
costs
for
heavy
LCO
could
potentially
exceed
this
loss.
Thus,
a
few
refiners
could
find
it
economical
to
shift
a
portion
of
their
LCO
to
the
residual
fuel
market.
The
U.
S.
residual
fuel
market
is
small
relative
to
the
distillate
fuel
market,
flat,
and
already
being
fulfilled.
Worldwide,
the
residual
fuel
market
is
shrinking.
Thus,
it
is
unlikely
that
large
volumes
of
LCO
could
leave
the
NRLM
fuel
market.
However,
we
cannot
rule
out
the
possibility
that
some
LCO,
particularly
that
produced
by
capital­
strapped
refiners,
could
be
shifted
to
residual
fuel.
To
estimate
the
upper
limit
of
this
shift,
we
estimated
the
volume
of
heavy
LCO
produced
by
refineries
whose
LCO
processing
costs
exceeded
12
cents
per
gallon
and
which
were
not
owned
by
large,
integrated
oil
companies
or
small
refiners.
This
costly,
heavy
LCO
represents
0.4
percent
of
total
NRLM
fuel
demand,
a
very
small
volume.
In
this
case,
we
would
expect
that
this
loss
could
easily
be
made
up
by
increased
imports
of
15
ppm
diesel
fuel
or
domestic
refiners
facing
lower
15
ppm
NRLM
fuel
costs.

Overall,
we
expect
that
domestic
refiners
will
continue
to
produce
sufficient
supplies
of
NRLM
fuel.
The
greatest
potential
for
near
term
loss
will
be
due
to
the
possibility
that
some
refiners
might
decide
to
limit
their
capital
investment
in
desulfurization
capacity
by
shifting
some
heavy
LCO
to
the
residual
fuel
market.

Fuel­
Only
Control
Programs:
The
potential
supply
impacts
of
a
long­
term
500
ppm
NRLM
cap
would
necessarily
be
less
than
those
of
today's
final
NRLM
fuel
program.
In
particular,
desulfurizing
"
difficult"
blendstocks,
like
LCO,
to
500
ppm
is
not
technically
challenging
and
does
not
have
the
potential
to
cost
more
than
would
be
lost
in
shifting
LCO
or
heavy
LCO
to
residual
fuel.
The
capital
investment
to
meet
a
500
ppm
cap
is
also
half
of
that
needed
to
meet
a
15
ppm
cap
or
less.
Thus,
the
likelihood
that
raising
this
capital
would
prove
difficult
is
much
less.
Given
that
we
expect
the
final
fuel
program
to
have
a
very
minimal
impact
on
supply,
a
500
ppm
NRLM
cap
would
be
negligible.

The
potential
impact
of
a
long­
term
15
ppm
NRLM
cap
is
the
same
as
that
for
today's
final
fuel
program.

6.
Fuel
Prices
It
is
well
known
that
it
is
difficult
to
predict
fuel
prices
in
absolute
terms
with
any
accuracy.
The
price
of
crude
oil
dominates
the
cost
of
producing
gasoline
and
diesel
fuel.
Crude
oil
prices
have
varied
by
more
than
a
factor
of
two
in
the
past
two
years.
In
addition,
unexpectedly
warm
or
cold
winters
can
significantly
affect
heating
oil
consumption,
which
affects
the
amount
of
gasoline
produced
and
the
amount
of
distillate
material
available
for
diesel
fuel
production.
Economic
growth,
or
its
lack,
affects
fuel
demand,
particularly
for
diesel
fuel.
Finally,
both
planned
and
unplanned
shutdowns
of
refineries
for
maintenance
and
repairs
can
significantly
affect
total
fuel
production,
inventory
levels
and
resulting
fuel
prices.
216
Executive
Order
13211,
"
Actions
Concerning
Regulations
That
Significantly
Affect
Energy
Supply,
Distribution,
or
Use"
(
66
FR
28355,
May
22,
2001).

372
Predicting
the
impact
of
any
individual
factor
on
fuel
price
is
also
difficult.
The
overall
volatility
in
fuel
prices
limits
the
ability
to
determine
the
effect
of
a
factor
which
changed
at
a
specific
point
in
time
which
might
have
led
to
the
price
change,
as
other
factors
continue
to
change
over
time.
Occasionally,
a
fuel
quality
change,
such
as
reformulated
gasoline
or
a
500
ppm
cap
on
diesel
fuel
sulfur
content,
only
affects
a
portion
of
the
fuel
pool.
In
this
case,
an
indication
of
the
impact
on
price
can
be
inferred
by
comparing
the
prices
of
the
two
fuels
at
the
same
general
location
over
time.
However,
this
is
still
only
possible
after
the
fact,
and
cannot
be
done
before
the
fuel
quality
change
takes
place.

Because
of
these
difficulties,
EPA
has
generally
not
attempted
to
project
the
impact
of
its
rules
on
fuel
prices.
However,
in
response
to
Executive
Order
13211,
we
are
doing
so
here.
216
To
reflect
the
inherent
uncertainty
in
making
such
projections,
we
developed
three
projections
for
the
potential
impact
of
the
proposed
fuel
program
on
fuel
prices.
The
range
of
potential
long­
term
price
increases
are
shown
in
table
VI.
A­
8.
(
Due
to
their
similarity,
we
have
grouped
the
potential
price
impacts
for
similar
quality
fuels
in
the
2010­
2012
and
2012­
2014
time
periods.)
Short­
term
price
impacts
are
highly
volatile,
as
are
short­
term
swings
in
absolute
fuel
prices,
and
much
too
dependent
on
individual
refiners'
decisions,
unexpected
shutdowns,
etc.
to
be
predicted
even
with
broad
ranges.
373
Table
VI.
A­
8.
 
Range
of
Possible
Total
Diesel
Fuel
Price
Increases
(
cents
per
gallon)
a
Maximum
Operating
Cost
Average
Total
Cost
Maximum
Total
Cost
500
ppm
Sulfur
Cap:
Nonroad,
Locomotive
and
Marine
Diesel
Fuel
(
2007­
2010)

PADDs
1
and
3
2.9
1.8
4.5
PADD
2
3.0
2.5
3.8
PADD
4
3.7
3.5
6.1
PADD
5
1.2
1.5
1.5
15
ppm
Sulfur
Cap:
NRLM
Fuel
(
2010­
2014)

PADDs
1
and
3
5.6
5.7
9.4
PADD
2
7.3
7.4
10.8
PADD
4
7.9
12.6
13.6
PADD
5
4.5
5.1
5.2
15
ppm
Sulfur
Cap:
NRLM
Fuel
(
fully
implemented
program:
2014
+)

PADDs
1
and
3
7.7
6.3
9.8
PADD
2
7.7
7.9
11.2
PADD
4
8.3
13.0
13.9
PADD
5
5.1
6.9
7.3
Notes:
a
At
the
current
wholesale
price
of
approximately
$
1.00
per
gallon,
these
values
also
represent
the
percentage
increase
in
diesel
fuel
price.

The
lower
end
of
the
range
assumes
that
prices
within
a
PADD
increased
to
reflect
the
highest
operating
cost
increase
faced
by
any
refiner
in
that
PADD
(
please
see
the
Final
RIA
for
details
on
this
methodology).
This
refiner
with
the
highest
operating
cost
will
not
recover
any
of
his
invested
capital,
but
all
other
refiners
will
recover
some
or
all
of
their
investment.
In
this
case,
the
price
of
NRLM
fuel
will
increase
in
2007
by
1
 
3
cents
per
gallon,
depending
on
the
area
of
the
country.
In
2010,
the
price
of
15
ppm
NRLM
fuel
will
increase
a
total
of
3
 
7
cents
per
gallon.
In
2014,
under
this
pricing
scenario,
15
ppm
NRLM
fuel
prices
will
increase
slightly,
to
4
 
7
cents
per
gallon.
The
increase
in
2014
is
due
to
the
expiration
of
the
small
refiner
provisions,
as
well
as
the
217
"
Potential
Impacts
of
Environmental
Regulations
on
Diesel
Fuel
Prices,"
NERA,
for
AAM,

December
2000.

374
fact
that
500
ppm
fuel
created
in
the
distribution
system
can
no
longer
be
sold
to
the
land­
based
nonroad
market.

The
mid­
range
estimate
of
price
impacts
assumes
that
prices
within
a
PADD
increase
by
the
average
refining
and
distribution
cost
within
that
PADD,
including
full
recovery
of
capital
(
at
seven
percent
per
annum
before
taxes).
Lower
cost
refiners
will
recover
more
than
their
capital
investment,
while
those
with
higher
than
average
costs
recover
less.
Under
this
assumption,
the
price
of
NRLM
fuel
will
increase
in
2007
by
1­
3
cents
per
gallon,
depending
on
the
area
of
the
country.
In
2010,
the
price
of
15
ppm
NRLM
fuel
will
increase
a
total
of
4
 
11
cents
per
gallon.
In
2014,
under
this
pricing
scenario,
15
ppm
NRLM
fuel
prices
will
increase
slightly,
to
5
 
11
cents
per
gallon.

The
upper
end
estimate
of
price
impacts
assumes
that
prices
within
a
PADD
increase
by
the
maximum
total
refining
and
distribution
cost
of
any
refinery
within
that
PADD,
including
full
recovery
of
capital
(
at
seven
percent
per
annum
before
taxes).
All
other
refiners
will
recover
more
than
their
capital
investment.
Under
this
assumption,
the
price
of
NRLM
fuel
will
increase
in
2007
by
1
 
4
cents
per
gallon,
depending
on
the
area
of
the
country.
In
2010,
the
price
of
15
ppm
NRLM
fuel
will
increase
a
total
of
4
 
13
cents
per
gallon.
In
2014,
under
this
pricing
scenario,
15
ppm
NRLM
fuel
prices
will
increase
further
to
6
 
13
cents
per
gallon.
All
these
potential
price
impacts
for
500
and
15
ppm
fuel,
relative
to
those
projected
in
the
NPRM,
reflect
the
differences
in
cost
estimates
discussed
above.

There
are
a
number
of
assumptions
inherent
in
all
three
of
the
above
price
projections.
First,
both
the
lower
and
upper
limits
of
the
projected
price
impacts
described
above
assume
that
the
refinery
facing
the
highest
compliance
costs
is
currently
the
price
setter
in
their
market.
This
is
a
worse
case
assumption
which
is
impossible
to
validate.
Many
factors
affect
a
refinery's
total
costs
of
fuel
production.
Most
of
these
factors,
such
as
crude
oil
cost,
labor
costs,
age
of
equipment,
etc.,
are
not
considered
in
projecting
the
incremental
costs
associated
with
lower
NRLM
diesel
fuel
sulfur
levels.
Thus,
current
prices
may
very
well
be
set
in
any
specific
market
by
a
refinery
facing
lower
incremental
compliance
costs
than
other
refineries.
This
point
was
highlighted
in
a
study
by
the
National
Economic
Research
Associates
(
NERA)
for
AAM
of
the
potential
price
impacts
of
EPA's
2007
highway
diesel
fuel
program.
217
In
that
study,
NERA
criticized
the
above
referenced
study
performed
by
Charles
River
Associates,
et.
al.
for
API,
which
projected
that
prices
will
increase
nationwide
to
reflect
the
total
cost
faced
by
the
U.
S.
refinery
with
the
maximum
total
compliance
cost
of
all
the
refineries
in
the
U.
S.
producing
highway
diesel
fuel.
To
reflect
the
potential
that
the
refinery
with
the
highest
projected
compliance
costs
under
the
maximum
price
scenario
is
not
the
current
price
setter,
we
included
the
mid­
point
price
impacts
above.
It
is
possible
that
even
the
lower
limit
price
impacts
are
too
high,
if
the
conditions
exist
where
prices
are
set
based
on
operating
costs
alone.
However,
these
price
impacts
are
sufficiently
218
"
Cost
of
Diesel
Fuel
Desulfurization
In
Asian
Refineries,"
Estrada
International
Ltd.,
for
the
Asian
Development
Bank,
December
17,
2002.

375
low
that
considering
even
lower
price
impacts
was
not
considered
critical
to
estimating
the
potential
economic
impact
of
this
rule.

Second,
we
assumed
in
some
cases
that
a
single
refinery's
costs
could
affect
fuel
prices
throughout
an
entire
PADD.
While
this
is
a
definite
improvement
over
analyses
which
assume
that
a
single
refinery's
costs
could
affect
fuel
prices
throughout
the
entire
nation,
it
is
still
conservative.
High
cost
refineries
are
more
likely
to
have
a
more
limited
geographical
impact
on
market
pricing
than
an
entire
PADD.
In
many
cases,
high
cost
refiners
continue
to
operate
simply
because
they
are
in
a
niche
location
where
transportation
costs
limit
competition.

Third,
by
focusing
solely
on
the
cost
of
desulfurizing
NRLM
diesel
fuel,
we
assume
that
the
production
of
NRLM
diesel
fuel
is
independent
of
the
production
of
other
refining
products,
such
as
gasoline,
jet
fuel
and
highway
diesel
fuel.
However,
this
is
clearly
not
the
case.
Refiners
have
some
flexibility
to
increase
the
production
of
one
product
without
significantly
affecting
the
others,
but
this
flexibility
is
quite
limited.
It
is
possible
that
the
relative
economics
of
producing
other
products
could
influence
a
refiner's
decision
to
increase
or
decrease
the
production
of
NRLM
diesel
fuel
under
today's
fuel
program.
It
is
this
price
response
that
causes
fuel
supply
to
match
fuel
demand.
And,
this
response
in
turn
could
increase
or
decrease
the
price
impact
relative
to
those
projected
above.

Fourth,
all
three
of
the
above
price
projections
are
based
on
the
projected
cost
for
U.
S.
refineries
of
meeting
the
NRLM
fuel
sulfur
caps.
Thus,
these
price
projections
assume
that
imports
of
NRLM
fuel,
which
are
currently
significant
in
the
Northeast,
are
available
at
roughly
the
same
cost
as
those
for
U.
S.
refineries
in
PADDs
1
and
3.
We
have
not
performed
any
analysis
of
the
cost
of
lower
sulfur
caps
on
diesel
fuel
produced
by
foreign
refiners.
However,
there
are
reasons
to
believe
that
imports
of
500
and
15
ppm
NRLM
diesel
fuel
will
be
available
at
prices
in
the
ranges
of
those
projected
for
U.
S.
refiners.

One
recent
study
analyzed
the
relative
cost
of
lower
sulfur
caps
for
Asian
refiners
relative
to
those
in
the
U.
S.,
Europe
and
Japan.
218
It
concluded
that
costs
for
Asian
refiners
will
be
comparatively
higher,
due
to
the
lack
of
current
hydrotreating
capacity
at
Asian
refineries.
This
conclusion
is
certainly
valid
when
evaluating
lower
sulfur
levels
for
highway
diesel
fuels
which
are
already
at
low
levels
in
the
U.
S.,
Europe
and
Japan
and
for
which
refineries
in
these
areas
have
already
invested
in
hydrotreating
capacity.
It
appears
to
be
less
valid
when
assessing
the
relative
cost
of
meeting
lower
sulfur
standards
for
NRLM
fuels
and
heating
oils
which
are
currently
at
much
higher
sulfur
levels
in
the
U.
S.,
Europe
and
Japan.
All
refineries
face
additional
investments
to
remove
sulfur
from
these
fuels
and
so
face
roughly
comparable
control
costs
on
a
per
gallon
basis.
219
See
Heavy­
duty
2007
Highway
Final
RIA,
Chapter
V.
C.
5,
and
"
Study
of
the
Effects
of
Reduced
Diesel
Fuel
Sulfur
Content
on
Engine
Wear,"
EPA
report
#
460/
3­
87­
002,
June
1987.

376
One
factor
arguing
for
competitively
priced
imports
is
the
fact
that
refinery
utilization
rates
are
currently
higher
in
the
U.
S.
and
Europe
than
in
the
rest
of
the
world.
The
primary
issue
is
whether
overseas
refiners
will
invest
to
meet
tight
sulfur
standards
for
U.
S.,
European
and
Japanese
markets.
Many
overseas
refiners
will
not
invest,
instead
focusing
on
local,
higher
sulfur
markets.
However,
many
overseas
refiners
focus
on
exports.
Both
Europe
and
the
U.
S.
are
moving
towards
highway
and
nonroad
diesel
fuel
sulfur
caps
in
the
10
 
15
ppm
range.
Europe
is
currently
and
projected
to
continue
to
need
to
import
large
volumes
of
highway
diesel
fuel.
Thus,
it
seems
reasonable
to
expect
that
a
number
of
overseas
refiners
will
invest
in
the
capacity
to
produce
some
or
all
of
their
diesel
fuel
at
these
levels.
Many
overseas
refiners
also
have
the
flexibility
to
produce
10­
15
ppm
diesel
fuel
from
their
cleanest
blendstocks,
as
most
of
their
available
markets
have
less
stringent
sulfur
standards.
Thus,
there
are
reasons
to
believe
that
some
capacity
to
produce
10
 
15
ppm
diesel
fuel
will
be
available
overseas
at
competitive
prices.
If
these
refineries
were
operating
well
below
capacity,
they
might
be
willing
to
supply
complying
product
at
prices
which
only
reflect
incremental
operating
costs.
This
could
hold
prices
down
in
areas
where
importing
fuel
is
economical.
However,
it
is
unlikely
that
these
refiners
could
supply
sufficient
volumes
to
hold
prices
down
nationwide.
Despite
this
expectation,
to
be
conservative,
in
the
refining
cost
analysis
conducted
earlier
in
this
chapter,
we
assumed
no
imports
of
500
ppm
or
15
ppm
NRLM
diesel
fuel.
All
500
ppm
and
15
ppm
NRLM
fuel
was
produced
by
domestic
refineries.
This
raised
the
average
and
maximum
costs
of
500
ppm
and
15
ppm
NRLM
diesel
fuel
and
increased
the
potential
price
impacts
projected
above
beyond
what
would
have
been
projected
had
we
projected
that
5­
10
percent
of
NRLM
diesel
fuel
will
be
imported
at
competitive
prices.

Fuel­
Only
Control
Programs:
We
used
the
same
methodology
to
estimate
the
potential
price
impacts
for
stand­
alone
500
ppm
and
15
ppm
NRLM
fuel
programs.
The
potential
price
impacts
of
long­
term
500
ppm
and
15
ppm
NRLM
caps
would
be
the
same
as
those
shown
in
table
VI.
A­
8
above
for
the
500
ppm
NRLM
cap
in
2007
and
for
the
15
ppm
NRLM
cap
in
2014
and
beyond,
respectively.

B.
Cost
Savings
to
the
Existing
Fleet
from
the
Use
of
Low
Sulfur
Fuel
We
estimate
that
reducing
fuel
sulfur
to
500
ppm
would
reduce
engine
wear
and
oil
degradation
to
the
existing
nonroad
diesel
equipment
fleet
and
that
a
further
reduction
to
15
ppm
sulfur
would
result
in
even
greater
reductions.
This
reduction
in
wear
and
oil
degradation
would
provide
a
dollar
savings
to
users
of
nonroad
equipment.
The
cost
savings
would
also
be
realized
by
the
owners
of
future
nonroad
engines
that
are
subject
to
the
standards
in
this
proposal.
As
discussed
below,
these
maintenance
savings
have
been
conservatively
estimated
to
be
greater
than
3
cents
per
gallon
for
the
use
of
15
ppm
sulfur
fuel
when
compared
to
the
use
of
today's
unregulated
nonroad
diesel
fuel.
A
summary
of
the
range
of
benefits
from
the
use
of
low­
sulfur
fuel
is
presented
in
Table
VI.
B­
1.219
377
Table
VI.
B­
1.
 
Engine
Components
Potentially
Affected
by
Lower
Sulfur
Levels
in
Diesel
Fuel
a
Affected
Components
Effect
of
Lower
Sulfur
Potential
Impact
on
Engine
System
Piston
Rings
Reduced
corrosion
wear
Extended
engine
life
and
less
frequent
rebuilds
Cylinder
Liners
Reduced
corrosion
wear
Extended
engine
life
and
less
frequent
rebuilds
Oil
Quality
Reduced
deposits,

reduced
acid
build­
up,

and
less
need
for
alkaline
additives
Reduce
wear
on
piston
ring
and
cylinder
liner
and
less
frequent
oil
changes
Exhaust
System
(
tailpipe)
Reduced
corrosion
wear
Less
frequent
part
replacement
Exhaust
Gas
Recirculation
System
Reduced
corrosion
wear
Less
frequent
part
replacement
Notes:
a
The
degree
to
which
all
of
these
benefits
may
occur
for
any
specific
engine
will
vary.
For
example,
the
impact
of
high
sulfur
fuel
on
piston
rings,
cylinder
liners
and
oil
quality
are
somewhat
interdependent.
To
the
extent
an
end­
user
lengthens
the
oil
drain
interval,
the
benefit
of
the
low
sulfur
fuel
on
piston
ring
and
cylinder
liner
wear
will
be
lessened
(
though
not
eliminated).

For
users
who
do
not
alter
oil
drain
intervals,
the
benefit
of
low
sulfur
fuel
on
extending
piston
ring
and
cylinder
liner
wear
will
be
greater.
The
benefit
of
low
sulfur
fuel
on
reducing
exhaust
system
and
EGR
system
corrosion
are
independent
of
oil
drain
intervals.

The
monetary
value
of
these
benefits
over
the
life
of
the
equipment
will
depend
upon
the
length
of
time
that
the
equipment
operates
on
low­
sulfur
diesel
fuel
and
the
degree
to
which
engine
and
equipment
manufacturers
specify
new
maintenance
practices
and
the
degree
to
which
equipment
operators
change
engine
maintenance
patterns
to
take
advantage
of
these
benefits.
For
equipment
near
the
end
of
its
life
in
the
2008
time
frame,
the
benefits
will
be
quite
small.
However,
for
equipment
produced
in
the
years
immediately
preceding
the
introduction
of
500
ppm
378
sulfur
fuel,
the
savings
would
be
substantial.
Additional
savings
would
be
realized
in
2010
when
the
15
ppm
sulfur
fuel
would
be
introduced
We
estimate
the
single
largest
savings
would
be
the
impact
of
lower
sulfur
fuel
on
oil
change
intervals.
The
RIA
presents
our
analysis
for
the
oil
change
interval
extension
which
would
be
realized
by
the
introduction
of
500
ppm
sulfur
fuel
in
2007,
as
well
as
the
additional
oil
extension
which
would
be
realized
with
the
introduction
of
15
ppm
sulfur
nonroad
diesel
fuel
in
2010.
As
explained
in
the
RIA,
these
estimates
are
based
on
our
analysis
of
publically
available
information
from
nonroad
engine
manufacturers.
Due
to
the
wide
range
of
diesel
fuel
sulfur
which
today's
nonroad
engines
may
see
around
the
world,
engine
manufacturers
specify
different
oil
change
intervals
as
a
function
of
diesel
sulfur
levels.
We
have
used
this
data
as
the
basis
for
our
analysis.
Taken
together,
when
compared
to
today's
relatively
high
nonroad
diesel
fuel
sulfur
levels,
we
estimate
the
use
of
15
ppm
sulfur
fuel
will
enable
an
oil
change
interval
extension
of
35
percent
from
today's
products.

We
received
comments
on
our
estimated
maintenance
savings
primarily
from
a
number
of
end­
user
groups
(
e.
g.,
equipment
dealers,
equipment
rental
organizations,
farming
organizations).
Several
commenters
believed
our
estimates
were
too
high,
and
one
commenter
believed
the
estimate
was
too
low.
However,
all
of
the
commenters
who
believed
our
cost
savings
estimates
were
too
high
provided
no
data
to
support
their
comments,
beyond
unsubstantiated
opinions,
nor
did
they
comment
on
EPA's
substantial
related
technical
analysis.
The
commenter
who
suggested
the
estimates
were
too
low
provided
an
example
cost
estimate
for
existing
oil
change
intervals
which,
if
used
in
our
analysis,
would
have
resulted
in
an
estimated
cost
savings
4
times
EPA's
estimate.
We
have
not
changed
our
estimate
based
on
the
comments
we
received.

We
present
here
a
fuel
operating
cost
savings
attributed
to
the
oil
change
interval
extension
in
terms
of
a
cents
per
gallon
operating
cost.
We
estimate
that
an
oil
change
interval
extension
of
31
percent,
as
would
be
enabled
by
the
use
of
500
ppm
sulfur
fuel
in
2007,
results
in
a
fuel
operating
costs
savings
of
2.9
cents
per
gallon
for
the
nonroad
fleet.
We
estimate
an
additional
cost
savings
of
0.3
cents
per
gallon
for
the
oil
change
interval
extension
which
would
be
enabled
by
the
use
of
15
ppm
sulfur
beginning
in
2010.
Thus,
for
the
nonroad
fleet
as
a
whole,
beginning
in
2010
nonroad
equipment
users
can
realize
an
operating
cost
savings
of
3.2
cents
per
gallon
compared
to
today's
engine.
This
means
that
the
end
cost
to
the
typical
user
for
15
ppm
sulfur
fuel
is
approximately
3.8
cents
per
gallon
(
7.0
cent
per
gallon
cost
for
fuel
minus
3.2
cent
per
gallon
maintenance
savings).
For
a
typical
100
horsepower
nonroad
engine
this
represents
a
net
present
value
lifetime
savings,
excluding
the
higher
fuel
costs,
of
more
than
$
500.

These
savings
will
occur
without
additional
new
cost
to
the
equipment
owner
beyond
the
incremental
cost
of
the
low­
sulfur
diesel
fuel,
although
these
savings
are
dependent
on
changes
to
existing
maintenance
schedules.
Such
changes
seem
likely
given
the
magnitude
of
the
savings.
There
are
many
mechanisms
by
which
end­
users
could
become
aware
of
the
opportunity
to
extend
oil
drain
intervals.
First,
it
is
typical
practice
for
engine
and
equipment
manufacturers
to
issue
220
For
example,
Appendix
A
of
EPA
Memorandum
"
Estimate
of
the
Impact
of
Low
Sulfur
Fuel
on
Oil
Change
Intervals
for
Nonroad
Diesel
Equipment"
contains
a
service
bulletin
from
a
nonroad
diesel
engine
manufacturer.
Copy
of
memo
available
in
EPA
Air
Docket
A­
2001­
28,
item
II­
A­
194.

221
For
example,
Appendix
C
of
EPA
Memorandum
"
Estimate
of
the
Impact
of
Low
Sulfur
Fuel
on
Oil
Change
Intervals
for
Nonroad
Diesel
Equipment",
which
indicates
Caterpillar
recommends
owners
use
Scheduled
Oil
Sampling
analysis
as
the
best
means
to
for
users
to
determine
appropriate
oil
change
intervals.
Copy
of
memo
available
in
EPA
Air
Docket
A­
2001­
28,
item
II­
A­
194.

379
service
bulletins
regarding
lubrication
and
fueling
guidance
for
end­
users.
220
Manufacturers
provide
these
service
bulletins
to
equipment
dealerships
and
large
equipment
customers
(
such
as
rental
companies).
In
addition,
the
equipment
and
end­
user
industries
have
a
number
of
annual
conferences
which
are
used
to
share
information,
including
information
regarding
appropriate
engine
and
equipment
maintenance
practices.
The
end­
user
conferences
are
also
designed
to
help
specific
industries
and
business
reduce
operating
costs
and
maximize
profits,
which
would
include
information
on
equipment
maintenance
practices.
There
are
trade
journals
and
publications
which
provide
information
and
advice
to
their
users
regarding
proper
equipment
maintenance.
Finally,
some
nonroad
users
perform
routine
oil
sample
analysis
in
order
to
determine
appropriate
oil
drain
intervals,
and
in
some
cases
to
monitor
overall
engine
wear
rates
in
order
to
determine
engine
rebuild
needs.
221
We
have
not
estimated
the
value
of
the
savings
from
all
of
the
benefits
listed
in
table
VI.
B­
1,
and
therefore
we
believe
the
3.2
cents
per
gallon
savings
is
conservative
as
it
only
accounts
for
the
impact
of
low
sulfur
fuel
on
oil
change
intervals.
While
some
of
these
benefits
are
impacted
by
changes
in
oil
change
interval,
a
number
are
independent
and
not
included
in
our
cost
savings
estimate.

C.
Engine
and
Equipment
Cost
Impacts
The
following
sections
briefly
discuss
the
various
engine
and
equipment
cost
elements
considered
for
this
final
rule
and
present
the
total
costs
we
have
estimated.
The
reader
is
referred
to
the
RIA
for
a
complete
discussion.
Estimated
engine
and
equipment
costs
depend
largely
on
both
the
size
of
the
piece
of
equipment
and
its
engine,
and
on
the
technology
package
being
added
to
the
engine
to
ensure
compliance
with
the
new
Tier
4
standards.
The
wide
size
variation
(
e.
g.,
engines
under
4
horsepower
through
engines
above
2500
horsepower)
and
the
broad
application
variation
(
e.
g.,
lawn
equipment
through
large
mining
trucks)
that
exists
in
the
nonroad
industry
makes
it
difficult
to
present
here
an
estimated
cost
for
every
possible
engine
and/
or
piece
of
equipment.
Nonetheless,
for
illustrative
purposes,
we
present
some
examples
of
engine
and
equipment
cost
impacts
throughout
this
discussion.
Note
that
the
costs
presented
here
are
for
those
nonroad
engines
and
equipment
that
are
mobile
nonroad
equipment
and
are,
therefore,
subject
to
nonroad
engine
standards.
These
costs
would
not
apply
for
that
equipment
that
is
stationary
 
some
portion
of
some
equipment
segments
such
as
generator
sets,
pumps,
compressors
 
and
not
subject
to
nonroad
engine
standards.
The
analysis
summarized
here
is
presented
in
detail
in
chapter
6
of
the
RIA.
222
In
order
to
avoid
inconsistencies
in
the
way
our
emission
reductions,
and
cost­
effectiveness
estimates
are
calculated,
our
cost
methodology
for
engines
and
equipment
relies
on
the
same
projections
of
new
nonroad
engine
growth
as
those
used
in
our
emissions
inventory
projections.
Our
NONROAD
emission
inventory
model
includes
estimates
of
future
engine
populations
that
are
consistent
with
the
future
engine
sales
used
in
our
cost
estimates.
The
NONROAD
model
inputs
include
an
estimate
of
what
percentage
of
generator
sets
sold
in
the
U.
S.
are
"
mobile"
and,
thus,
subject
to
the
nonroad
standards,
and
what
percentage
are
"
stationary"
and
not
subject
to
the
nonroad
standards.
These
percentages
vary
by
power
category
and
are
documented
in
"
Nonroad
Engine
Population
Estimates,"
EPA
Report
420­
P­
02­

004,
December
2002.
For
generator
sets
above
750
horsepower,
NONROAD
assumes
100
percent
are
stationary
and,
therefore,
not
subject
to
the
new
nonroad
standards.
For
generator
sets
under
750
horsepower,
we
have
assumed
other
percentages
of
mobile
versus
stationary.
During
our
discussions
with
engine
manufacturers
after
the
proposal,
it
became
apparent
not
only
that
our
estimate
for
generator
sets
above
750
horsepower
may
not
be
correct
and
many
are
indeed
mobile,
but
also
that
some
of
our
estimates
for
generator
sets
above
750
horsepower
may
also
not
be
correct
and
many
more
than
we
estimate
may
380
Note
that
the
costs
presented
here
do
not
reflect
any
savings
that
are
expected
to
occur
because
of
the
engine
ABT
program
and/
or
the
equipment
manufacturer
transition
program,
which
are
discussed
in
sections
III.
A
and
B.
These
optional
programs
have
the
potential
to
provide
significant
savings
for
both
engine
and
equipment
manufacturers.
As
a
result,
we
consider
our
cost
estimates
to
be
conservative,
in
the
sense
that
they
likely
overstate
total
engine
and
equipment
costs.

In
general,
the
final
engine
and
equipment
cost
analysis
is
the
same
as
that
done
for
our
proposal.
We
have
made
the
following
changes:

°
In
response
to
a
comment,
we
have
increased
our
engine
research
and
development
(
R&
D)
costs.
In
the
proposal,
we
estimated
the
R&
D
expenditure
that
each
engine
manufacturer
would
make
to
comply
with
the
Tier
4
standards.
In
response
to
the
comment,
we
have
refined
that
analysis
and
increased
our
estimate
of
engine
R&
D
by
roughly
50
percent.
We
did
not
receive
any
other
comments
with
respect
to
our
estimates
for
engine
R&
D.

°
Because
the
final
standards
for
engines
above
750
horsepower
have
changed
from
the
proposed
standards,
we
have
made
changes
to
the
engine
R&
D
expenditures
attributed
to
those
engines.
For
costing
purposes,
the
NO
X
portion
of
the
engine
R&
D
expenditures
are
no
longer
shared
by
engines
above
750
horsepower.
This
increases
NO
X
R&
D
attributed
to
other
engines
because
a
significant
portion
of
engine
R&
D
costs
are
costs
shared
across
a
wide
range
of
products.
We
have
also
reduced
the
engine
variable
costs
for
engines
above
750
horsepower
since
we
are
no
longer
projecting
that
NO
X
adsorbers
will
be
added
to
them.
222
This
has
no
impact
on
the
engine
variable
costs
for
other
engines.
We
have
indeed
be
mobile.
If
true,
this
increased
percentage
of
mobile
generator
sets
will
be
subject
to
the
new
nonroad
standards.
Unfortunately,
we
have
not
received
sufficient
data
to
make
a
conclusive
change
to
the
NONROAD
model
to
include
the
potentially
increased
percentages
of
mobile
generator
sets
and,

therefore,
for
the
above
described
purpose
of
maintaining
consistency,
we
have
not
included
their
costs
or
their
emissions
reductions
in
our
official
estimates
for
this
final
rule
(
costs
and
emissions
reductions
for
the
current
percentages
in
the
NONROAD
model
are
included
in
our
estimates
for
the
final
rule).
Instead,

we
present
a
sensitivity
analysis
in
Chapter
8
of
the
RIA
that
includes
both
an
estimate
of
the
costs
and
emissions
reductions
that
would
result
from
including
a
higher
percentage
of
generator
sets
as
mobile
equipment
and
subject
to
the
new
standards.

381
also
reduced
the
equipment
redesign
costs
for
engines
above
750
horsepower
since
less
redesign
effort
is
projected
to
accommodate
only
a
catalyzed
diesel
particulate
filter
(
CDPF).
This
has
no
impact
on
the
redesign
costs
of
other
equipment.
Lastly,
we
have
decreased
the
equipment
variable
costs
for
engines
above
750
horsepower
for
the
same
reason
as
was
done
for
engine
variable
costs.

°
We
have
changed
the
engine
operating
costs
for
engines
above
750
horsepower
to
reflect
a
different
fuel
economy
impact
than
was
associated
with
the
proposed
standards
and
to
reflect
the
new
timing
for
adding
the
CDPF
and
therefore
incurring
the
maintenance
costs
associated
with
it.

°
We
have
included
costs
for
additional
cooling
on
engines
adding
cooled
EGR
systems
(
engines
of
25
to
50
horsepower
and
greater
than
750
horsepower).
These
costs
include
the
larger
radiator
and/
or
engine
cooling
fan
that
may
be
required
on
engines
expected
to
add
cooled
EGR
to
meet
the
new
standards.
In
the
proposal,
we
had
estimated
the
costs
for
the
EGR
system
but
not
the
costs
for
additional
cooling.

°
We
have
expressed
all
costs
in
2002
dollars
for
the
final
rule
rather
than
the
proposal's
use
of
2001
dollars.

We
received
comments
on
other
aspects
of
the
proposed
engine
and
equipment
cost
analysis
that
are
not
reflected
in
the
final
analysis.
Some
of
the
comments
were:

°
Some
commenters
claimed
that
we
had
underestimated
costs
for
engines
under
75
horsepower,
and
in
the
75
to
100
horsepower
range.
For
the
engines
under
75
horsepower,
one
commenter
suggested
the
costs
were
higher
than
EPA
estimated.
Please
see
section
5.4.1
of
the
Summary
and
Analysis
of
Comments
for
a
detailed
discussion
of
the
comments
and
our
response.
In
the
75
to
100
horsepower
range,
one
commenter
suggested
that
we
were
incorrect
in
our
assumption
that
those
engines
would
have
electronic
fuel
systems
in
the
NRT4
baseline
case,
maintaining
the
electronic
fuel
systems
would
have
to
be
added
to
these
engines
to
comply
with
the
Tier
4
standards
and,
382
therefore,
are
a
cost
of
the
Tier
4
rule.
From
this
premise,
the
commenter
argued
that
the
costs
for
75
to
100
horsepower
engines
will
be
disproportionately
high.

We
disagree.
In
the
proposal,
we
estimated
that
by
2012,
engines
in
this
power
range
would
already
have
electronic
fuel
injection
systems.
This
estimate
was
based
on
our
engineering
assessment
of
what
technologies
would
be
required
to
comply
with
the
Tier
2
and
Tier
3
emission
standards,
as
well
as
technical
discussions
we
had
with
engine
manufacturers
regarding
future
product
plans.
Therefore,
the
costs
of
these
electronic
fuel
injection
systems
are
not
attributable
to
the
Tier
4
rule.
Our
assessment
at
proposal
is
consistent
with
our
projections
in
the
Tier2/
3
rulemaking
where
we
estimated
costs
for
electronic
fuel
injection
systems
as
a
cost
of
complying
with
those
standards.
In
the
preamble
to
the
proposed
Tier
4
rule,
we
presented
estimates
of
the
penetration
of
various
engine
technologies
into
several
power
ranges,
including
75
to
100
horsepower,
based
on
engine
manufacturers'
2001
model
year
certification
data.
See
68
FR
28386,
May
23,
2003.
Since
then,
model
year
certification
data
for
2004
are
available,
and
these
data
substantiate
our
earlier
prediction.
These
model
year
2004
data
represent
implementation
of
the
Tier
2
standards
so
these
data
illustrate
the
technologies
engine
manufacturers
are
using
to
comply
with
those
standards.
These
data
show
that
nearly
20
percent
of
the
engines
that
will
be
produced
in
this
power
range
will
have
electronically
controlled
fuel
systems,
while
the
model
year
2001
data
show
no
engines
in
this
power
range
had
electronic
fuel
systems.
This
dramatic
increase
in
electronics
as
a
result
of
the
Tier
2
standards,
let
alone
the
Tier
3
standards,
gives
us
confidence
that
our
projections
regarding
2012
are
reasonable.
Section
4.1.4
of
the
RIA
contains
a
detailed
discussion
of
this
information;
see
also
the
discussions
in
sections
II.
B.
4.
b.
i
and
II.
B.
5
above.
Thus,
we
continue
to
believe
that
we
have
properly
attributed
costs
of
electronic
fuel
systems
to
the
Tier
3
rule,
or,
put
another
way,
that
the
cost
of
an
electronic
fuel
system
is
not
a
cost
attributable
to
this
Tier
4
rule
for
engines
in
the
75
to
100
horsepower
category.
Since
the
cost
of
electronic
fuel
systems
is
the
essential
difference
in
the
costs
we
attribute
to
the
Tier
4
rule
for
these
engines
versus
the
costs
the
commenter
would
attribute,
we
therefore
disagree
with
the
comment
and
believe
our
estimates
to
be
reasonable.
See
also
section
II.
A.
5
above.

°
One
commenter
took
exception
to
our
method
of
amortizing
fixed
costs
over
a
period
of
years
following
implementation
of
the
new
standards.
The
commenter
suggested
that
we
used
such
a
method
to
imply
to
the
regulated
industries
that
they
would
not
only
recover
their
investments
but
would
also
make
a
gain
on
those
investments.
This
is
not
the
case.
We
use
this
method
of
amortization,
briefly
described
here
and
more
fully
in
the
RIA,
only
to
reflect
the
time
value
of
money
so
that
we
can
get
a
more
accurate
estimate
of
the
cost
to
the
companies.

The
Summary
and
Analysis
of
Comments
document
contains
the
details
of
all
comments
and
our
responses.
383
1.
Engine
Cost
Impacts
Estimated
engine
costs
are
broken
into
fixed
costs
(
for
research
and
development,
retooling,
and
certification),
variable
costs
(
for
new
hardware
and
assembly
time),
and
life­
cycle
operating
costs.
Total
operating
costs
include
the
estimated
incremental
cost
for
low­
sulfur
diesel
fuel,
any
expected
increases
in
maintenance
costs
associated
with
new
emission
control
devices,
any
costs
associated
with
increased
fuel
consumption,
and
any
decreases
in
operating
cost
(
i.
e.,
maintenance
savings)
expected
due
to
low­
sulfur
fuel.
Cost
estimates
presented
here
represent
an
expected
incremental
cost
of
engines
in
the
model
year
of
their
introduction.
Costs
in
subsequent
years
will
be
reduced
by
several
factors,
as
described
below.
All
engine
and
equipment
costs
are
presented
in
2002
dollars
since
producer
price
indexes
for
2003
were
not
available
in
time
for
use
in
this
analysis.

a.
Engine
Fixed
Costs
i.
Engine
and
Emission
Control
Device
R&
D
The
technologies
described
in
Section
II
represent
those
technologies
we
believe
will
be
used
to
comply
with
the
Tier
4
emission
standards.
For
many
manufacturers,
these
technologies
are
part
of
an
ongoing
research
and
development
effort
geared
toward
compliance
with
the
2007
heavy­
duty
diesel
highway
emission
standards.
The
engine
manufacturers
making
R&
D
expenditures
toward
compliance
with
highway
emission
standards
will
have
to
undergo
some
additional
R&
D
effort
to
transfer
emission
control
technologies
to
engines
they
wish
to
sell
into
the
nonroad
market.
These
R&
D
efforts
will
allow
engine
manufacturers
to
develop
and
optimize
these
new
technologies
for
maximum
emission­
control
effectiveness
with
minimum
negative
impacts
on
engine
performance,
durability,
and
fuel
consumption.

Many
nonroad
engine
manufacturers
are
not
part
of
the
ongoing
R&
D
effort
toward
compliance
with
highway
emissions
standards
because
they
do
not
sell
engines
into
the
highway
market.
Nonetheless,
these
manufacturers
are
expected
to
benefit
from
the
R&
D
work
that
has
already
occurred
and
will
continue
through
the
coming
years
through
their
contact
with
highway
manufacturers,
emission
control
device
manufacturers,
and
the
independent
engine
research
laboratories
conducting
relevant
R&
D.

We
project
the
use
of
several
technologies
for
complying
with
the
Tier
4
emission
standards.
We
are
projecting
that
NO
X
adsorbers
and
catalyzed
diesel
particulate
filters
(
CDPFs)
will
be
the
most
likely
technologies
applied
by
industry
to
meet
our
new
emissions
standards
for
engines
above
75
horsepower.
The
fact
that
these
technologies
are
being
developed
for
implementation
in
the
highway
market
before
the
Tier
4
implementation
dates,
and
the
fact
that
engine
manufacturers
will
have
several
years
before
implementation
of
the
Tier
4
standards,
ensures
that
the
technologies
used
to
comply
with
the
nonroad
standards
will
undergo
significant
development
before
reaching
production.
This
ongoing
development
could
lead
to
reduced
costs
in
three
ways.
First,
we
expect
research
will
lead
to
enhanced
effectiveness
for
individual
384
technologies,
allowing
manufacturers
to
use
simpler
packages
of
emission
control
technologies
than
we
would
predict
given
the
current
state
of
development.
Similarly,
we
anticipate
that
the
continuing
effort
to
improve
the
emission
control
technologies
will
include
innovations
that
allow
lower­
cost
production.
Finally,
we
believe
that
manufacturers
will
focus
research
efforts
on
any
drawbacks,
such
as
fuel
economy
impacts
or
maintenance
costs,
in
an
effort
to
minimize
or
overcome
any
potential
negative
effects.

We
anticipate
that,
in
order
to
meet
the
Tier
4
standards,
industry
will
introduce
a
combination
of
primary
technology
upgrades.
Achieving
very
low
NO
X
emissions
will
require
basic
research
on
NO
X
exhaust
emission
control
technologies
and
improvements
in
engine
management
to
take
advantage
of
the
new
exhaust
emission
control
system
capabilities.
The
manufacturers
are
expected
to
address
the
challenge
by
optimizing
the
engine
and
new
exhaust
emission
control
system
to
realize
the
best
overall
performance.
This
will
entail
optimizing
the
engine
and
emission
control
system
for
both
emissions
and
fuel
economy
performance
in
light
of
the
presence
of
the
new
exhaust
emission
control
devices
and
their
ability
to
control
pollutants
previously
controlled
only
via
in­
cylinder
means
or
with
exhaust
gas
recirculation.
Since
most
research
to
date
with
exhaust
emission
control
technologies
for
nonroad
applications
has
focused
on
retrofit
programs
which
typically
add
an
exhaust
emission
control
device
without
making
engine
control
changes,
there
remains
room
for
significant
improvements
by
taking
such
a
systems
approach.
The
NO
X
adsorber
technology
in
particular
is
expected
to
benefit
from
re­
optimization
of
the
engine
management
system
to
better
match
the
NO
X
adsorber's
performance
characteristics.
The
majority
of
the
dollars
we
have
estimated
for
research
is
expected
to
be
spent
on
developing
this
synergy
between
the
engine
and
NO
X
exhaust
emission
control
systems.
Therefore,
for
engines
where
we
project
use
of
both
a
CDPF
and
a
NO
X
adsorber
(
i.
e.,
75
to
750
horsepower),
we
have
attributed
two­
thirds
of
the
R&
D
expenditures
to
NO
X
control,
and
one­
third
to
PM
control.

As
we
mentioned
earlier,
we
have
further
refined
our
estimate
of
engine
R&
D
costs
since
our
proposal.
We
have
taken
these
R&
D
costs
and
have
broken
them
into
two
components.
The
first
of
these
components
estimates
the
corporate
R&
D
applicable
across
all
engine
lines.
The
second
of
these
estimates
the
engine
line
by
engine
line
R&
D
cost.
The
estimates
of
line
by
line
R&
D
correlate
to
power
range
 
$
1
million
for
under
75
horsepower
engine
lines,
$
3
million
for
75
to
750
horsepower
engine
lines,
and
$
6
million
for
above
750
horsepower
engine
lines.
We
estimated
these
expenditures
based
on
the
confidential
information
provided
by
the
commenter
and
our
analysis
of
that
information.
The
end
result
is
consistent
with
the
commenter's
suggested
expenditure
levels.
We
have
applied
these
engine­
line
R&
D
estimates
only
where
CDPFs
and/
or
CDPF/
NO
X
adsorber
systems
are
expected
to
be
implemented
(
i.
e.,
this
R&
D
is
not
applied
for
the
under
75
horsepower
engines
in
2008
because
the
R&
D
already
estimated
for
complying
with
those
standards
should
not
require
the
same
effort
to
tailor
it
to
each
engine).
We
have
also
applied
these
estimates
only
for
those
engines
without
a
highway
counterpart
(
note
that
only
16
of
a
total
133
nonroad
engine
lines
had
a
highway
counterpart).
223
In
the
2007
rule,
we
estimated
a
value
of
$
35
million
in
1999
dollars.
Here
we
have
adjusted
that
value
to
express
it
in
2002
dollars.

224
In
the
proposal,
we
estimated
a
value
of
$
3.5
million
in
1999
dollars.
Here
we
have
adjusted
that
value
to
express
it
in
2002
dollars.

225
In
the
proposal,
we
estimated
a
value
of
$
24.5
million
in
1999
dollars.
Here
we
have
adjusted
that
value
to
express
it
in
2002
dollars.

385
In
the
2007
HD
highway
rule,
we
estimated
that
each
engine
manufacturer
would
expend
$
36.1
million
for
R&
D
to
redesign
their
engines
and
apply
catalyzed
diesel
particulate
filters
(
CDPF)
and
NO
X
adsorbers.
223
For
their
nonroad
R&
D
efforts
on
engines
where
we
project
that
compliance
will
require
CDPFs
and
NO
X
adsorbers
(
i.
e.,
75
to
750
horsepower)
and
on
greater
than
750
horsepower
engines
requiring
a
CDPF,
engine
manufacturers
that
also
sell
into
the
highway
market
will
incur
some
level
of
R&
D
effort
but
not
at
the
level
incurred
for
the
highway
rule.
In
many
cases,
the
engines
used
by
highway
manufacturers
in
nonroad
products
are
based
on
the
same
engine
platform
as
those
used
in
highway
products.
However,
horsepower
and
torque
characteristics
are
often
different
so
some
effort
will
have
to
be
expended
to
accommodate
those
differences.
For
these
manufacturers,
we
have
estimated
that
they
will
incur
an
average
R&
D
expense
of
$
3.6
million224
not
including
the
nonroad
engine
line
R&
D
noted
above.
This
$
3.6
million
R&
D
expense
will
allow
for
the
transfer
of
R&
D
knowledge
from
their
highway
experience
to
their
nonroad
engine
product
line.
For
the
reasons
stated
above,
two­
thirds
of
this
R&
D
is
attributed
to
NO
X
control
and
one­
third
to
PM
control
for
75
to
750
horsepower
engines;
for
engines
above
750
horsepower,
all
of
this
R&
D
is
attributed
to
PM
control.

For
those
manufacturers
that
sell
larger
engines
only
into
the
nonroad
market,
and
where
we
project
those
engines
will
add
a
CDPF
and
a
NO
X
adsorber
(
75
to
750
horsepower)
or
a
CDPF­
only
(
above
750
horsepower),
we
believe
that
they
will
incur
an
R&
D
expense
nearing
that
incurred
by
highway
manufacturers
for
the
highway
rule
although
not
quite
at
the
same
level.
Nonroad
manufacturers
will
be
able
to
learn
from
the
R&
D
efforts
already
underway
for
both
the
highway
rule
and
for
the
Tier
2
light­
duty
highway
rule
(
65
FR
6698,
February
10,
2000).
This
learning
could
be
done
via
seminars,
conferences,
and
contact
with
highway
manufacturers,
emission
control
device
manufacturers,
and
the
independent
engine
research
laboratories
conducting
relevant
R&
D.
Therefore,
for
these
manufacturers,
we
have
estimated
an
average
expenditure
of
$
25.3
million225
not
including
the
nonroad
engine
line
R&
D
noted
above.
This
lower
number
 
$
25.3
million
versus
$
36.1
million
in
the
highway
rule
 
reflects
the
transfer
of
knowledge
to
nonroad
manufacturers
that
will
occur
from
the
many
stakeholders
in
the
diesel
industry.
Two­
thirds
of
this
R&
D
is
attributed
to
NO
X
control
and
one­
third
to
PM
control.

Note
that
the
$
3.6
million
and
$
25.3
million
estimates
represent
our
estimate
of
the
average
R&
D
expected
by
manufacturers
to
gain
knowledge
about
the
anticipated
emission
control
devices.
These
estimates
will
be
different
for
each
manufacturer
 
some
higher,
some
lower
 
depending
on
product
mix
and
the
number
of
engine
lines
in
their
product
line.
226
In
the
proposal,
we
estimated
values
of
$
1.2
million
and
$
8
million
in
1999
dollars.
Here
we
have
adjusted
those
values
to
express
them
in
2002
dollars.

227
In
the
proposal,
we
estimated
values
of
$
600,000
and
$
4
million
in
1999
dollars.
Here
we
have
adjusted
those
values
to
express
them
in
2002
dollars.

386
For
those
engine
manufacturers
selling
smaller
engines
that
we
project
will
add
a
CDPFonly
(
i.
e.,
25
to
75
horsepower
engines
in
2013),
we
have
estimated
that
the
average
R&
D
they
will
incur
will
be
roughly
one­
third
that
incurred
by
manufacturers
conducting
CDPF/
NO
X
adsorber
R&
D.
We
believe
this
is
a
good
estimate
because
CDPF
technology
is
further
along
in
its
development
than
is
NO
X
adsorber
technology
and,
therefore,
a
50/
50
split
is
not
appropriate.
Using
this
estimate,
the
R&
D
incurred
by
manufacturers
that
already
have
been
selling
any
engines
into
both
the
highway
and
the
nonroad
markets
will
be
$
1.2
million
not
including
their
nonroad
engine
line
R&
D,
and
the
R&
D
for
manufacturers
selling
engines
into
only
the
nonroad
market
will
be
roughly
$
8.3
million226
not
including
their
nonroad
engine
line
R&
D.
All
of
this
R&
D
is
attributed
to
PM
control.

For
those
engine
manufacturers
selling
engines
that
we
project
will
add
only
a
DOC
or
make
some
engine­
out
modifications
(
i.
e.,
engines
under
75
horsepower
in
2008),
we
have
estimated
that
the
average
R&
D
they
will
incur
will
be
roughly
one­
half
the
amount
estimated
for
their
CDPF­
only
R&
D.
Using
this
estimate,
the
R&
D
incurred
by
manufacturers
selling
any
engines
into
both
the
highway
and
nonroad
markets
will
be
roughly
$
600,000,
and
the
R&
D
for
manufacturers
selling
engines
into
only
the
nonroad
market
will
be
roughly
$
4.2
million.
227
All
of
this
R&
D
is
attributed
to
PM
control.

We
have
assumed
that
all
R&
D
expenditures
occur
over
a
five
year
span
preceding
the
first
year
any
emission
control
device
is
introduced
into
the
market.
There
is
one
exception
to
this
assumption
in
that
the
expenditures
for
DOC­
only
R&
D
are
assumed
to
occur
over
the
four
year
span
between
the
final
rule
and
the
2008
standards.
Where
a
phase­
in
exists
(
e.
g.,
for
NO
X
standards
on
75
to
750
horsepower
engines),
expenditures
are
assumed
to
occur
over
the
five
year
span
preceding
the
first
year
NO
X
adsorbers
will
be
introduced,
and
then
to
continue
during
the
phase­
in
years.
The
expenditures
will
be
incurred
in
a
manner
consistent
with
the
phase­
in
of
the
standard.
All
R&
D
expenditures
are
then
recovered
by
the
engine
manufacturer
over
an
identical
time
span
following
the
introduction
of
the
technology,
with
the
exception
that
expenditures
for
DOC­
only
R&
D
are
recovered
over
a
five
year
span
rather
than
a
four
year
span.
We
assume
an
opportunity
cost
of
capital
of
seven
percent
for
all
R&
D.
We
have
apportioned
these
R&
D
costs
across
all
engines
that
are
expected
to
use
these
technologies,
including
those
sold
in
other
countries
or
regions
that
are
expected
to
have
similar
standards.
We
have
estimated
the
fraction
of
the
U.
S.
sales
to
this
total
sales
at
42
percent.
Therefore,
we
have
attributed
this
amount
to
U.
S.
sales.
Note
that
all
engine
R&
D
costs
for
engines
under
25
horsepower
have
been
attributed
to
U.
S.
sales
since
other
countries
are
not
expected
to
have
similar
standards
on
these
engines.
228
In
the
2007
rule,
we
estimated
a
value
of
$
1.6
million
in
1999
dollars.
Here
we
have
adjusted
that
value
to
express
it
in
2002
dollars.

387
Using
this
methodology,
we
have
estimated
the
total
R&
D
expenditures
attributable
to
the
new
standards
at
$
323
million
with
$
206
million
spent
on
corporate
R&
D
and
$
118
million
spent
on
engine
line
R&
D.
For
comparison,
our
proposal
estimated
$
199
million
for
basic
R&
D
and
none
for
engine
line
R&
D.
The
amount
for
corporate
R&
D
is
higher
here
solely
due
to
the
change
to
2002
dollars.

ii.
Engine­
Related
Tooling
Costs
Once
engines
are
ready
for
production,
new
tooling
will
be
required
to
accommodate
the
assembly
of
the
new
engines.
We
have
indicated
below
where
our
tooling
cost
estimates
have
changed
from
the
proposal.
In
the
2007
highway
rule,
we
estimated
approximately
$
1.65
million
per
engine
line
for
tooling
costs
associated
with
CDPF/
NO
X
adsorber
systems.
228
For
the
nonroad
Tier
4
standards,
we
have
estimated
that
nonroad­
only
manufacturers
will
incur
the
same
$
1.65
million
per
engine
line
requiring
a
CDPF/
NO
X
adsorber
system
and
that
these
costs
will
be
split
evenly
between
NO
X
control
and
PM
control.
For
those
systems
requiring
only
a
CDPF,
we
have
estimated
one­
half
that
amount,
or
$
825,000
per
engine
line.
For
those
systems
requiring
only
a
DOC
or
some
engine­
out
modifications,
we
have
applied
a
one­
half
factor
again,
or
$
412,500
per
engine
line.
Tooling
costs
for
CDPF­
only
and
for
DOC
engines
are
attributed
solely
to
PM
control.
None
of
these
estimates
have
changed
since
our
proposal,
with
the
exception
of
being
expressed
in
2002
dollars.
We
received
no
comments
on
our
tooling
cost
estimates.

For
those
manufacturers
selling
into
both
the
highway
and
nonroad
markets,
we
have
estimated
one­
half
the
baseline
tooling
cost,
or
$
825,000,
for
those
engine
lines
requiring
a
CDPF/
NO
X
adsorber
system.
We
believe
this
is
reasonable
since
many
nonroad
engines
are
produced
on
the
same
engine
line
with
their
highway
counterparts.
For
such
lines,
we
believe
very
little
to
no
tooling
costs
will
be
incurred.
For
engine
lines
without
a
highway
counterpart,
something
approaching
the
$
1.65
million
tooling
cost
is
applicable.
For
this
analysis,
we
have
assumed
a
50/
50
split
of
engine
product
lines
for
highway
manufacturers
and,
therefore,
a
50
percent
factor
applied
to
the
$
1.65
million
baseline.
These
tooling
costs
will
be
split
evenly
between
NO
X
control
and
PM
control.
For
engine
lines
under
75
horsepower
and
above
750
horsepower,
we
have
used
the
same
tooling
costs
as
the
nonroad­
only
manufacturers
because
these
engines
tend
not
to
have
a
highway
counterpart.
Therefore,
for
those
engine
lines
requiring
only
a
CDPF
(
i.
e.,
those
between
25
and
75
horsepower
and
those
above
750
horsepower),
we
have
estimated
a
tooling
cost
of
$
825,000.
Note
that
this
is
a
change
from
the
proposal
for
engines
above
750
horsepower;
the
proposal
used
the
full
$
1.65
million
since
both
a
CDPF
and
a
NO
X
adsorber
were
being
projected.
The
tooling
costs
for
DOC
and/
or
engine­
out
engine
lines
has
also
been
estimated
to
be
$
412,500.
Tooling
costs
for
CDPF­
only
and
for
DOC
engines
are
attributed
solely
to
PM
control.
With
the
exception
of
the
greater
than
750
horsepower
change,
none
of
these
tooling
estimates
have
changed
since
our
proposal,
with
the
exception
of
being
expressed
in
2002
dollars.
388
We
expect
engines
in
the
25
to
50
horsepower
range
to
apply
EGR
systems
to
meet
the
Tier
4
NO
X
standards
for
2013.
For
these
engines,
we
have
included
an
additional
tooling
cost
of
$
41,300
per
engine
line,
consistent
with
the
EGR­
related
tooling
cost
estimated
for
50­
100
horsepower
engines
in
our
Tier
2/
3
rulemaking.
The
EGR
tooling
costs
are
applied
equally
to
all
engine
lines
in
that
horsepower
range
regardless
of
the
markets
into
which
the
manufacturer
sells.
We
have
applied
this
tooling
cost
equally
because
engines
in
this
horsepower
range
tend
not
to
have
highway
counterparts.
Tooling
costs
for
EGR
systems
are
attributed
solely
to
NO
X
control.

We
have
also
estimated
some
tooling
costs
for
engines
above
750
horsepower
to
meet
the
2011
standards.
We
have
estimated
this
amount
at
ten
times
the
amount
for
25
to
50
horsepower
engines,
or
$
413,000
per
engine
line.
This
cost
was
not
in
the
proposal
since
NO
X
adsorbers
were
being
projected
for
engines
above
750
horsepower.
We
have
applied
this
tooling
to
all
engine
lines
above
750
horsepower,
regardless
of
what
markets
into
which
a
manufacturer
sells,
since
such
engines
clearly
have
no
highway
counterpart.
For
the
purpose
of
allocating
costs,
we
have
attributed
this
cost
entirely
to
NO
X
control.
Note
that
there
is
a
new
2011
PM
standard
for
engines
above
750
horsepower.
However,
we
believe
that
PM
standard
could
be
met
via
engineout
control
which
would
result
in
no
new
tooling
costs
associated
with
that
standard.

We
have
applied
all
the
above
tooling
costs
to
all
manufacturers
that
appear
to
actually
make
engines.
We
have
not
eliminated
joint
venture
manufacturers
because
these
manufacturers
will
still
need
to
invest
in
tooling
to
make
the
engines
even
if
they
do
not
conduct
any
R&
D.
We
have
assumed
that
all
tooling
costs
are
incurred
one
year
in
advance
of
the
new
standard
and
are
recovered
over
a
five
year
period
following
implementation
of
the
new
standard;
all
tooling
costs
include
a
capital
opportunity
cost
of
seven
percent.
As
done
for
R&
D
costs,
we
have
attributed
a
portion
of
the
tooling
costs
to
U.
S.
sales
and
a
portion
to
sales
in
other
countries
expected
to
have
similar
levels
of
emission
control.
Note
that
all
engine
tooling
costs
for
under
25
horsepower
engines
have
been
attributed
to
U.
S.
sales
since
other
countries
are
not
expected
to
have
similar
standards
on
these
engines.
More
information
is
contained
in
chapter
6
of
the
RIA.

Using
this
methodology,
we
estimate
the
total
tooling
expenditures
attributable
to
the
new
Tier
4
standards
at
$
74
million.
For
comparison,
our
proposal
estimated
$
67
million.
The
higher
value
here
is
a
result
of:
expressing
values
in
2002
dollars
rather
than
2001
dollars;
attributing
all
under
25
horsepower
tooling
costs
to
U.
S.
sales
while
the
proposal
attributed
42
percent
of
those
costs
to
U.
S.
sales;
and,
above
750
horsepower
tooling
is
slightly
higher
because
of
the
proposal's
phase­
in
(
50/
50/
50/
100)
of
one
set
of
standards
while
the
final
rule
has
two
sets
of
standards.

iii.
Engine
Certification
Costs
The
comments
we
received
with
respect
to
our
estimated
certification
costs
noted
that
we
had
underestimated
costs
associated
with
new
test
procedures,
especially
transient
testing
for
engines
above
750
horsepower.
For
the
final
rule,
we
have
tripled
the
costs
associated
with
new
test
procedures.
Because
we
are
not
finalizing
transient
test
procedures
for
engines
above
750
229
In
the
proposal
we
added
a
certification
fee
to
this
cost.
In
the
final
rule
we
have
not
included
the
certification
fee
because
that
cost
will
be
accounted
for
in
the
certification
fees
rulemaking
(
see
67
FR
51402
for
the
proposed
rule).
Including
in
the
proposal
was
essentially
double
counting
that
fee.
Similarly,
if
we
were
to
include
it
in
this
final
rule,
we
would
be
double
counting
that
fee.

230
Note
that
the
transport
refrigeration
unit
(
TRU)
test
cycle
is
an
optional
duty
cycle
for
steadystate
certification
testing
specifically
tailored
to
the
operation
of
TRU
engines.
Likewise,
the
ramped
modal
cycles
are
available
test
cycles
that
can
be
used
to
replace
existing
steady­
state
test
requirements
for
nonroad
constant­
speed
engines,
generally.
Manufacturers
of
these
engines
who
opt
to
use
one
of
these
test
cycles
would
incur
no
new
costs
above
those
estimated
here
and
may
incur
less
cost.

231
Note
that
the
proposal
incorrectly
used
a
value
of
$
10,500
for
costs
associated
with
the
new
test
procedures.
Here,
we
have
corrected
this
error
by
using
a
value
of
$
31,500.
Note
also
that
the
proposal
erroneously
did
not
include
certification
costs
associated
with
transient
testing
and
the
NTE
for
engines
under
25
horsepower.
We
have
corrected
that
error
in
the
final
analysis.

389
horsepower,
comments
about
the
cost
of
these
engines
certifying
using
the
transient
test
are
now
moot.

Manufacturers
will
incur
more
than
the
normal
level
of
certification
costs
during
the
first
few
years
of
implementation
because
engines
will
need
to
be
certified
to
the
new
emission
standards
using
new
test
procedures
(
at
least
in
some
instances).
Consistent
with
our
recent
standard
setting
regulations,
we
have
estimated
engine
certification
costs
at
$
60,000
per
new
engine
certification
to
cover
existing
testing
and
administrative
costs.
229
The
$
60,000
certification
cost
per
engine
family
was
used
for
25
to
75
horsepower
engines
certifying
to
the
2008
standards.
For
25
to
75
horsepower
engines
certifying
to
the
2013
standards,
and
for
75
to
750
horsepower
engines
certifying
to
their
new
standards,
we
have
added
costs
to
cover
the
new
test
procedures
for
nonroad
diesel
engines
(
e.
g.,
the
transient
test,
the
NTE);
230
these
costs
are
estimated
at
$
31,500
per
engine
family.
231
For
engines
under
25
horsepower,
we
have
assumed
(
for
cost
purposes)
that
all
engines
will
certify
to
the
transient
test
and
the
NTE
in
2008.
We
believe
manufacturers
may
choose
to
do
this
rather
than
certifying
all
engines
again
in
2013
when
the
transient
test
and
NTE
requirements
actually
begin
for
those
engines.
This
assumption
results
in
higher
certification
costs
in
2008
than
if
these
engines
certified
only
to
the
steady­
state
standard.
However,
we
believe
manufacturers
may
choose
to
do
this
because
it
would
avoid
the
need
to
recertify
all
engines
under
25
horsepower
again
in
2013.
These
certification
costs
 
whether
it
be
the
$
60,000
or
the
$
91,500
per
engine
family
 
apply
equally
to
all
engine
families
for
all
manufacturers
regardless
of
into
what
markets
the
manufacturer
sells.
For
engines
above
750
horsepower,
the
certification
costs
used
were
$
87,000
per
family
since
these
engines
will
not
be
certifying
over
the
new
transient
test
procedure.
We
have
applied
these
certification
costs
to
all
U.
S.
sold
engine
families
and
then
spread
the
total
over
U.
S.
sales.
In
other
words,
we
have
not
390
presumed
that
certification
conducted
for
U.
S.
engines
would
fulfill
the
certification
requirements
of
other
countries
and
have,
therefore,
not
spread
total
costs
over
engine
sales
outside
the
U.
S..

Applying
these
costs
to
each
of
the
665
engine
families
as
they
are
certified
to
a
new
emissions
standard
results
in
total
costs
of
$
91
million
expended
during
implementation
of
the
Tier
4
standards.
These
costs
are
attributed
to
NO
X
and
PM
control
consistent
with
the
phase­
in
of
the
new
emissions
standards
 
where
new
NO
X
and
PM
standards
are
introduced
together,
the
certification
costs
are
split
evenly;
where
only
a
new
PM
standard
is
introduced,
the
certification
costs
are
attributed
to
PM
only;
where
a
NO
X
phase­
in
becomes
100
percent
in
a
year
after
full
implementation
of
a
PM
standard,
the
certification
costs
are
attributed
to
NO
X
only.
All
certification
costs
are
assumed
to
occur
one
year
prior
to
the
new
emission
standard
and
are
then
recovered
over
a
five
year
period
following
compliance
with
the
new
standard;
all
certification
costs
include
a
capital
opportunity
cost
of
seven
percent.
For
comparison,
our
proposal
estimated
certification
costs
at
$
72
million.
The
increase
here
is
a
result
of
using
a
higher
cost
associated
with
the
new
test
procedures
than
was
used
in
the
proposal.

We
also
received
comment
that
we
should
estimate
certification
costs
based
on
use
of
the
ABT
program
rather
than
based
on
the
phase­
in.
Doing
this
would
result
in
higher
certification
costs
because
all
engine
families
would
be
certified
in
year
one
of
the
phase­
in
and
all
families
would
again
be
certified
in
the
final
year
of
the
phase­
in.
In
contrast,
since
we
have
based
certification
costs
on
the
phase­
in,
all
engine
families
are
certified
in
year
one
(
PM
standards
have
no
phase­
in)
and
only
half
are
again
certified
in
the
final
year
(
the
50
percent
not
meeting
the
new
NO
X
standard
in
year
one).
We
have
chosen
not
to
estimate
certification
or
any
costs
based
on
use
of
the
ABT
program
(
or
the
TPEM
program)
since
it
is
so
difficult
to
predict
how
this
program
will
be
used.
Furthermore,
we
must
remain
consistent
throughout
our
cost
analysis
so
that,
if
we
estimated
certification
costs
based
on
use
of
the
ABT
program,
we
should
also
base
engine
variable
costs
and
equipment
variable
costs
on
use
of
the
ABT
program.
Doing
so,
we
believe,
would
decrease
engine
variable
costs
since
that
is
the
primary
reason
manufacturers
choose
to
make
use
of
the
ABT
program.
Since
engine
variable
costs,
as
discussed
below,
are
a
much
greater
fraction
of
the
overall
program
costs,
we
believe
that
we
are
being
conservative
by
generating
our
costs
based
on
use
of
the
phase­
in.
Therefore,
we
believe
that
use
of
the
ABT
program
(
and
the
TPEM
program)
will
provide
substantial
net
savings
to
industry
even
though
widespread
use
of
ABT
might
cause
certification
costs
to
be
higher.

b.
Engine
Variable
Costs
This
section
summarizes
the
detailed
analysis
presented
in
chapter
6
of
the
RIA.
For
our
analysis,
we
have
used
the
2002
annual
average
costs
for
platinum
and
rhodium
(
the
two
platinum
group
metals
(
PGMs)
we
expect
will
be
used)
because
we
believe
they
represent
a
better
estimate
of
the
cost
for
PGM
than
other
metrics.
In
the
RIA,
we
present
a
cost
sensitivity
that
estimates
the
recovery
value
of
precious
metals
returned
to
the
open
market
upon
retirement
of
an
aftertreatment
device.
We
present
that
analysis
to
gauge
the
true
social
cost
of
these
devices
when
new.
232
Note
that
the
change
to
2002
dollars
had
different
effects
on
different
pieces
of
hardware.

We
have
used
two
different
PPI
adjustments
in
the
analysis:
one
for
motor
vehicle
catalytic
converters
which
was
used
to
adjust
costs
for
DOCs,
NOX
adsorbers,
and
CDPFs;
and
another
for
motor
vehicle
parts
and
accessories
which
was
used
for
all
other
pieces
of
hardware.
The
former
of
these
adjustments
actually
caused
costs
to
decrease
relative
to
the
proposal
while
the
latter
caused
costs
to
increase
slightly.

391
We
have
not
made
any
changes
to
our
engine
variable
costs
as
a
result
of
public
comments.
Some
commenters
(
engine
manufacturers)
claimed
that
we
had
underestimated
these
costs
but
did
not
provide
any
detailed
information
about
where
they
believed
we
had
erred
or
what
they
believed
the
costs
should
be.
Other
commenters
(
emission
control
device
manufacturers)
claimed
that
we
had
done
a
fair
job
with
our
estimates.
Some
commenters
(
equipment
manufacturers)
claimed
that
our
assumptions
with
respect
to
baseline
engine
configurations
were
not
accurate.
However,
as
discussed
earlier,
based
on
our
own
engineering
judgement
and
the
positive
comments
of
the
engine
manufacturers
 
who
we
consider
a
better
source
for
such
information
than
equipment
manufacturers
since
engine
manufacturers
are
the
directly
affected
entities
 
we
have
maintained
our
original
assumptions
for
baseline
engine
configurations.
Further,
our
assumed
Tier
4
baseline
engine
configurations
are
consistent
with
our
assumed
compliant
technology
packages
for
T2/
3,
and
those
packages
included
the
things
equipment
manufacturers
are
claiming
will
not
be
present
in
the
Tier
4
baseline.
As
a
result,
we
have
already
considered
the
costs
associated
with
reaching
our
Tier
4
baseline
engine
configurations
in
the
context
of
the
T2/
3
rule.

We
have
made
changes
to
engine
variable
costs
to
remain
consistent
with
the
final
program
 
i.
e.,
we
have
changed
our
greater
than
750
horsepower
cost
estimates
since
the
final
standards
differ
from
those
that
were
proposed.
We
have
also
changed
the
costs
by
expressing
them
in
2002
dollars
rather
than
2001
dollars.
232
i.
NO
X
Adsorber
System
Costs
The
NO
X
adsorber
system
that
we
are
anticipating
will
be
used
to
comply
with
Tier
4
engine
standards
will
be
the
same
as
that
used
for
highway
applications.
In
order
for
the
NO
X
adsorber
to
function
properly,
a
systems
approach
that
includes
a
reductant
metering
system
and
control
of
engine
A/
F
ratio
is
also
necessary.
Many
of
the
new
air
handling
and
electronic
system
technologies
developed
in
order
to
meet
the
Tier
2/
3
nonroad
engine
standards
can
be
applied
to
accomplish
the
NO
X
adsorber
control
functions
as
well
(
these
costs
were
accounted
for
in
our
T2/
3
rule).
Some
additional
hardware
for
exhaust
NO
X
or
O
2
sensing
and
for
fuel
metering
will
likely
be
required.
The
cost
estimates
include
a
DOC
for
clean­
up
of
hydrocarbon
emissions
that
occur
during
NO
X
adsorber
regeneration
events.
We
have
also
estimated
that
warranty
costs
will
increase
due
to
the
application
of
this
new
hardware.
Chapter
6
of
the
RIA
contains
the
details
for
how
we
estimated
costs
associated
with
the
new
NO
X
control
technologies
required
to
meet
the
Tier
4
emission
standards.
These
costs
are
estimated
to
increase
engine
costs
by
roughly
$
670
in
the
near­
term
for
a
150
horsepower
engine,
and
$
2,040
in
the
near­
term
for
a
500
horsepower
engine.
In
the
long­
term,
we
estimate
these
costs
to
be
$
550
and
$
1,650
for
the
150
horsepower
and
500
233
This
is
particularly
true
with
respect
to
engines
above
750
horsepower
where
we
believe
that
manufacturers
may
in
fact
use
a
wire
mesh
substrate
rather
than
the
SiC
substrate
we
have
costed
and,

indeed,
we
have
based
the
level
of
the
2015
PM
standard
on
this
use
of
wire
mesh
substrates
(
see
section
II.
B.
3.
b).
We
have
chosen
to
remain
conservative
in
our
cost
estimates
by
assuming
use
of
a
SiC
substrate
for
all
engines.

392
horsepower
engines,
respectively.
These
costs
may
differ
slightly
from
the
proposal
due
to
the
adjustments
to
2002
dollars.
Note
that
we
have
estimated
costs
for
all
engines
in
all
horsepower
ranges,
and
these
estimates
are
presented
in
detail
in
the
RIA.
Throughout
this
discussion
of
engine
and
equipment
costs,
we
present
costs
for
a
150
and
a
500
horsepower
engine
for
illustrative
purposes.

ii.
Catalyzed
Diesel
Particulate
Filter
(
CDPF)
Costs
CDPFs
can
be
made
from
a
wide
range
of
filter
materials
including
wire
mesh,
sintered
metals,
fibrous
media,
or
ceramic
extrusions.
The
most
common
material
used
for
CDPFs
for
heavy­
duty
diesel
engines
is
cordierite.
Here
we
have
based
our
cost
estimates
on
the
use
of
silicon
carbide
(
SiC)
even
though
it
is
more
expensive
than
other
filter
materials.
233
We
estimate
that
the
CDPF
systems
will
add
$
760
to
engine
costs
in
the
near­
team
for
a
150
horsepower
engine
and
$
2,710
in
the
near­
term
for
a
500
horsepower
engine.
In
the
long­
term,
we
estimate
these
CDPF
system
costs
to
be
$
580
and
$
2,070
for
the
150
horsepower
and
the
500
horsepower
engines,
respectively.
These
costs
may
differ
slightly
from
the
proposal
due
to
the
adjustments
to
2002
dollars.

iii.
CDPF
Regeneration
System
Costs
Application
of
CDPFs
in
nonroad
applications
may
present
challenges
beyond
those
of
highway
applications.
For
this
reason,
we
anticipate
that
some
additional
hardware
beyond
the
diesel
particulate
filter
itself
may
be
required
to
ensure
that
CDPF
regeneration
occurs.
For
some
engines
this
may
be
new
fuel
control
strategies
that
force
regeneration
under
some
circumstances,
while
in
other
engines
it
might
involve
an
exhaust
system
fuel
injector
to
inject
fuel
upstream
of
the
CDPF
to
provide
necessary
heat
for
regeneration
under
some
operating
conditions.
We
estimate
the
near­
term
costs
of
a
CDPF
regeneration
system
to
be
$
200
for
a
150
horsepower
engine
and
$
330
for
a
500
horsepower
engine.
In
the
long­
term,
we
estimate
these
costs
at
$
150
and
$
250,
respectively.
These
costs
may
differ
slightly
from
the
proposal
due
to
the
adjustments
to
2002
dollars.

iv.
Closed­
Crankcase
Ventilation
System
(
CCV)
Costs
Today's
final
rule
eliminates
the
exemption
that
allows
turbo­
charged
nonroad
diesel
engines
to
vent
crankcase
gases
directly
to
the
environment.
Such
engines
are
said
to
have
an
open
crankcase
system.
We
project
that
this
requirement
to
close
the
crankcase
on
turbo­
charged
234
We
refer
here
to
PM
standards.
There
also
is
a
NOX+
NMHC
standard
for
25­
50
horsepower
engines
that
takes
effect
in
2013
and
is
equivalent
to
the
Tier
3
NOX+
NMHC
standard
for
50­
75
horsepower
engines
(
see
section
II.
A).

393
engines
will
force
manufacturers
to
rely
on
engineered
closed
crankcase
ventilation
systems
that
filter
oil
from
the
blow­
by
gases
prior
to
routing
them
into
either
the
engine
intake
or
the
exhaust
system
upstream
of
the
CDPF.
We
have
estimated
the
initial
cost
of
these
systems
to
be
roughly
$
30
for
low
horsepower
engines
and
up
to
$
90
for
very
high
horsepower
engines.
These
costs
are
incurred
only
by
turbo­
charged
engines
because
today's
naturally
aspirated
engines
already
have
CCV
systems.
These
costs
may
differ
slightly
from
the
proposal
due
to
the
adjustments
to
2002
dollars.

v.
Variable
Costs
for
Engines
Below
75
Horsepower
and
Above
750
Horsepower
The
Tier
4
program
includes
standards
for
engines
under
25
horsepower
that
begin
in
2008,
and
two
sets
of
standards
for
25
to
75
horsepower
engines
 
one
set
that
begins
in
2008
and
another
that
begins
in
2013.234
The
2008
standards
for
all
engines
under
75
horsepower
are
of
similar
stringency
and
are
expected
to
result
in
use
of
similar
technologies
(
i.
e.,
the
possible
addition
of
a
DOC).
The
2013
standards
for
25
to
75
horsepower
engines
are
considerably
more
stringent
than
the
2008
standards
and
are
expected
to
force
the
addition
of
a
CDPF
along
with
some
other
engine
hardware
to
enable
the
proper
functioning
of
that
new
technology.
More
detail
on
the
mix
of
technologies
expected
for
all
engines
under
75
horsepower
is
presented
in
section
II.
B.
4
and
5.
As
discussed
there,
if
changes
are
needed
to
comply,
we
expect
manufacturers
to
comply
with
the
2008
standards
through
either
engine­
out
improvements
or
through
the
addition
of
a
DOC.
From
a
cost
perspective,
we
have
projected
that
engines
will
add
a
DOC.
Presumably,
the
manufacturer
will
choose
the
least
costly
approach
that
provides
the
necessary
reduction.
If
engine­
out
modifications
are
less
costly
than
a
DOC,
our
estimate
here
is
conservative.
If
the
DOC
proves
to
be
less
costly,
then
our
estimate
is
representative
of
what
most
manufacturers
will
do.
Therefore,
we
have
assumed
that,
beginning
in
2008,
all
engines
below
75
horsepower
add
a
DOC.
Note
that
this
estimate
is
made
more
conservative
since
we
have
assumed
this
cost
for
all
engines
when,
in
fact,
some
engines
below
75
horsepower
currently
meet
the
Tier
4
PM
standard
(
for
2008)
and
will
not,
therefore,
incur
any
incremental
costs
to
meet
it.
We
have
estimated
this
added
hardware
to
result
in
an
increased
engine
cost
of
$
143
in
the
near­
term
and
$
136
in
the
long­
term
for
a
30
horsepower
engine.
These
costs
may
differ
slightly
from
the
proposal
due
to
the
adjustments
to
2002
dollars.

We
have
also
projected
that
some
engines
in
the
25
to
75
horsepower
range
will
have
to
upgrade
their
fuel
systems
to
accommodate
the
CDPF.
We
have
estimated
the
incremental
costs
for
these
fuel
systems
at
roughly
$
870
for
a
three
cylinder
engine
in
the
25
 
50
horsepower
range,
and
around
$
450
for
a
four
cylinder
engine
in
the
50­
75
horsepower
range.
This
difference
reflects
a
different
base
fuel
system,
with
the
smaller
engines
assumed
to
have
mechanical
fuel
systems
and
the
larger
engines
assumed
to
already
be
electronic.
The
electronic
systems
will
incur
lower
costs
235
For
example,
see,
"
Learning
Curves
in
Manufacturing,"
Linda
Argote
and
Dennis
Epple,

Science,
February
23,
1990,
Vol.
247,
pp.
920­
924.

394
because
they
already
have
the
control
unit
and
electronic
fuel
pump.
Also,
we
have
assumed
these
fuel
changes
will
occur
for
only
direct
injection
(
DI)
engines;
indirect
injection
engines
(
IDI)
are
assumed
to
remain
IDI
but
to
add
more
hardware
as
part
of
their
CDPF
regeneration
system
to
ensure
proper
regeneration
under
all
operating
conditions.
Such
a
regeneration
system,
described
above,
is
expected
to
cost
roughly
twice
that
expected
for
DI
engines,
or
around
$
320
for
a
30
horsepower
IDI
engine
versus
$
160
for
a
DI
engine.
These
costs
may
differ
slightly
from
the
proposal
due
to
the
adjustments
to
2002
dollars.

We
have
also
projected
that
engines
in
the
25
 
50
horsepower
range
will
add
cooled
EGR
to
comply
with
their
new
NO
X
standard
in
2013.
Additionally,
we
have
estimated,
for
cost
purposes,
that
engines
above
750
horsepower
will
add
cooled
EGR
to
comply
with
their
new
NO
X
standard
in
2011.
This
represents
a
conservative
estimate
since
we
do
not
necessarily
anticipate
that
cooled
EGR
will
be
applied
to
all,
if
any,
engines
above
750
horsepower.
Nonetheless,
we
do
expect
some
changes
to
be
made
(
most
probably
some
form
of
engine­
out
emission
control)
and,
consistent
with
our
approach
to
costing
DOCs
for
engines
below
75
horsepower
in
2008,
we
have
conservatively
costed
cooled
EGR
for
engines
above
750
horsepower
in
2011.
We
have
estimated
that
the
EGR
system
will
add
$
100
in
the
near­
term
and
$
70
in
the
long­
term
to
the
cost
of
a
30
horsepower
engine,
and
$
550
and
$
420,
respectively,
for
engines
above
750
horsepower.
These
costs
may
differ
slightly
from
the
proposal
due
to
the
adjustments
to
2002
dollars.
To
these
costs,
we
have
added
costs
associated
with
additional
cooling
that
may
be
needed
to
reject
the
heat
generated
by
the
cooled
EGR
system
or
other
in­
cylinder
technologies.
These
costs
were
not
included
in
the
proposal.
Such
additional
cooling
might
take
the
form
of
a
larger
radiator
and/
or
a
larger
or
more
powerful
cooling
fan.
Based
on
cost
estimates
from
our
Nonconformance
Penalty
rule
(
67
FR
51464),
we
have
estimated
that
the
costs
associated
with
additional
cooling
will
add
$
40
in
the
near­
term
and
$
30
in
the
long­
term
to
the
cost
of
a
30
horsepower
engine,
and
$
710
in
the
near­
term
and
$
560
in
the
long­
term
for
engine
above
750
horsepower.
Note
that
we
are
also
projecting
use
of
a
CDPF
for
engines
above
750
horsepower,
as
was
discussed
above.

We
believe
there
are
factors
that
will
cause
variable
hardware
costs
to
decrease
over
time,
making
it
appropriate
to
distinguish
between
near­
term
and
long­
term
costs.
Research
in
the
costs
of
manufacturing
has
consistently
shown
that
as
manufacturers
gain
experience
in
production,
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.
235
Our
analysis,
as
described
in
more
detail
in
the
RIA,
incorporates
the
effects
of
this
learning
curve
by
projecting
that
the
variable
costs
of
producing
the
low­
emitting
engines
decreases
by
20
percent
starting
with
the
third
year
of
production.
For
this
analysis,
we
have
assumed
a
baseline
that
represents
such
learning
already
having
occurred
once
due
to
the
2007
highway
rule
(
i.
e.,
a
20
percent
reduction
in
emission
control
device
costs
is
reflected
in
our
near­
term
costs).
We
have
then
applied
a
single
learning
step
from
that
point
in
this
analysis.
Additionally,
manufacturers
are
expected
to
apply
ongoing
research
to
make
emission
controls
more
effective
and
to
have
lower
operating
costs
over
395
time.
However,
because
of
the
uncertainty
involved
in
forecasting
the
results
of
this
research,
we
conservatively
have
not
accounted
for
it
in
this
analysis.

c.
Engine
Operating
Costs
We
are
projecting
that
a
variety
of
new
technologies
will
be
introduced
to
enable
nonroad
engines
to
meet
the
new
Tier
4
emissions
standards.
Primary
among
these
are
advanced
emission
control
technologies
and
low­
sulfur
diesel
fuel.
The
technology
enabling
benefits
of
low­
sulfur
diesel
fuel
are
described
in
Section
II,
and
the
incremental
cost
for
low­
sulfur
fuel
is
described
in
section
VI.
A.
The
new
emission
control
technologies
are
themselves
expected
to
introduce
additional
operating
costs
in
the
form
of
increased
fuel
consumption
and
increased
maintenance
demands.
Operating
costs
are
estimated
in
the
RIA
over
the
life
of
the
engine
and
are
expressed
in
terms
of
cents/
gallon
of
fuel
consumed.
In
section
VI.
C.
3,
we
present
these
lifetime
operating
costs
as
a
net
present
value
(
NPV)
in
2002
dollars
for
several
example
pieces
of
equipment.

Total
operating
cost
estimates
include
the
following
elements:
the
change
in
maintenance
costs
associated
with
applying
new
emission
controls
to
the
engines;
the
change
in
maintenance
costs
associated
with
low
sulfur
fuel
such
as
extended
oil
change
intervals;
the
change
in
fuel
costs
associated
with
the
incrementally
higher
costs
for
low
sulfur
fuel,
and
the
change
in
fuel
costs
due
to
any
fuel
consumption
impacts
associated
with
applying
new
emission
controls
to
the
engines.
This
latter
cost
is
attributed
to
the
CDPF
and
its
need
for
periodic
regeneration
which
we
estimate
may
result
in
a
one
percent
fuel
consumption
increase
where
a
NO
X
adsorber
is
also
applied,
or
a
two
percent
fuel
consumption
increase
where
no
NO
X
adsorber
is
applied
(
refer
to
chapter
6,
section
6.2.3.3
of
the
RIA).
Maintenance
costs
associated
with
the
new
emission
controls
on
the
engines
are
expected
to
increase
since
these
devices
represent
new
hardware
and,
therefore,
new
maintenance
demands.
For
CDPF
maintenance,
we
have
used
a
maintenance
interval
of
3,000
hours
for
smaller
engines
and
4,500
hours
for
larger
engines
and
a
cost
of
$
65
through
$
260
for
each
maintenance
event.
For
closed­
crankcase
ventilation
(
CCV)
systems,
we
have
used
a
maintenance
interval
of
675
hours
for
all
engines
and
a
cost
per
maintenance
event
of
$
8
to
$
48
for
small
to
large
engines.
Offsetting
these
maintenance
cost
increases
will
be
a
savings
due
to
an
expected
increase
in
oil
change
intervals
because
low
sulfur
fuel
will
be
far
less
corrosive
than
is
current
nonroad
diesel
fuel.
Less
corrosion
will
mean
a
slower
acidification
rate
(
i.
e.,
less
degradation)
of
the
engine
lubricating
oil
and,
therefore,
more
operating
hours
between
needed
oil
changes.
As
discussed
in
section
VI.
B,
the
use
of
15
ppm
sulfur
fuel
can
extend
oil
change
intervals
by
as
much
as
35
percent
for
both
new
and
existing
nonroad
engines
and
equipment.
We
have
used
a
35
percent
increase
in
oil
change
interval
along
with
costs
per
oil
change
of
$
70
through
$
400
to
arrive
at
estimated
savings
associated
with
increased
oil
change
intervals.

These
operating
costs
are
expressed
as
a
cent/
gallon
cost
(
or
savings).
As
a
result,
operating
costs
are
directly
proportional
to
the
amount
of
fuel
consumed
by
the
engine.
We
have
estimated
these
operating
costs
 
fuel­
related
refining
and
distribution
costs,
maintenance
related
costs,
and
fuel
economy
impacts
 
to
be
5.4
cents/
gallon
for
a
150
horsepower
engine
and
6.5
396
cents/
gallon
for
a
500
horsepower
engine.
More
detail
on
operating
costs
can
be
found
in
Chapter
6
of
the
RIA.

The
existing
fleet
will
also
benefit
from
lower
maintenance
costs
due
to
the
use
of
low
sulfur
diesel
fuel.
The
operating
costs
for
the
existing
fleet
are
discussed
in
section
VI.
B.
We
did
receive
comments
with
respect
to
our
oil
change
maintenance
savings
estimates.
These
comments
were
address
in
section
VI.
B.
We
received
no
comments
on
our
CDPF
and
CCV
maintenance
costs
or
our
CDPF
regeneration
costs.

2.
Equipment
Cost
Impacts
In
addition
to
the
costs
directly
associated
with
engines
that
incorporate
new
emission
controls
to
meet
new
standards,
costs
will
increase
due
to
the
need
to
redesign
the
nonroad
equipment
in
which
these
engines
are
used.
Such
redesigns
will
probably
be
necessary
due
to
the
expected
addition
of
new
emission
control
systems,
but
could
also
occur
if
the
engine
has
a
different
shape
or
heat
rejection
rate,
or
is
no
longer
made
available
in
the
configuration
previously
used.
We
have
accounted
for
these
potential
changes
in
establishing
the
lead
time
for
the
Tier
4
emissions
standards.
The
transition
flexibility
provisions
for
equipment
manufacturers
that
are
included
in
this
final
rule
are
an
element
of
that
lead
time.
These
flexibility
provisions
are
described
in
detail
in
section
III.
B.

In
assessing
the
economic
impact
of
the
new
emission
standards,
EPA
has
made
a
best
estimate
of
the
modifications
to
equipment
that
relate
to
packaging
(
installing
engines
in
equipment
engine
compartments).
The
incremental
costs
for
new
equipment
will
be
comprised
of
fixed
costs
(
for
redesign
to
accommodate
new
emission
control
devices)
and
variable
costs
(
for
new
equipment
hardware
to
affix
the
new
emission
control
devices
and
for
labor
to
install
those
emission
control
devices).
Note
that
the
fixed
costs
do
not
include
certification
costs
because
the
equipment
is
not
certified
to
emission
standards.
The
engine
is
certified
by
the
engine
manufacturer;
therefore,
the
related
certification
costs
are
counted
as
an
engine
fixed
cost.
We
have
also
attributed
all
changes
in
operating
costs
(
e.
g.,
additional
maintenance)
to
the
cost
estimates
for
engines.
Included
in
section
VI.
C.
3
is
a
discussion
of
several
example
pieces
of
equipment
(
e.
g.,
skid/
steer
loader,
dozer,
etc.)
and
the
costs
we
have
estimated
for
these
specific
example
pieces
of
equipment
Full
details
of
our
equipment
cost
analysis
can
be
found
in
chapter
6
of
the
RIA.
All
costs
are
presented
in
2002
dollars.

We
have
made
only
limited
changes
relative
to
the
proposal
with
respect
to
our
estimated
equipment
costs,
as
discussed
below.
We
did
receive
comment
that
we
underestimated
costs
for
equipment
redesign
and
for
markups
on
equipment
variable
costs.
The
commenters
making
these
claims
relative
to
equipment
redesign
costs
tended
to
be
those
that
have
relative
high
equipment
sales
volumes.
Such
manufacturers
tend
to
expend
levels
higher
than
we
estimated
in
our
proposal
for
equipment
redesign
because
they
sell
into
highly
competitive
markets
and
they
can
spread
costs
over
many
units.
However,
some
equipment
manufacturers
we
have
met
with,
most
notably
those
with
small
sales
volumes,
do
not
appear
to
expend
nearly
the
level
we
estimated
in
the
proposal.
236
"
Meeting
between
Staff
of
Eagle
Crusher
Company,
Inc.,
and
EPA,"
memorandum
from
Todd
Sherwood
to
Air
Docket
A­
2001­
28,
Docket
Item
IV­
E­
40,
EDOCKET
OAR­
2003­
0012­
0868,

March
16,
2004.

397
These
manufacturers
tend
to
sell
into
markets
with
few
competitors,
produce
machines
by
hand,
and
expend
less
redesign
effort
relative
to
a
high
sales
volume
manufacturer.
236
Our
goal
in
the
proposal
was
to
estimate
the
redesign
costs
spent
by
industry
(
i.
e.,
the
average
cost
per
piece
of
equipment
multiplied
by
all
equipment
resulting
in
an
estimated
total
industry
cost),
rather
than
estimating
the
maximum
cost
to
be
spent
by
any
particular
manufacturer.
As
a
result,
our
equipment
redesign
estimates
per
model
may
be
too
low
for
some
manufacturers,
but
they
are
also
too
high
for
others.
We
believe
this
cost
methodology
provides
as
accurate
an
estimate
as
can
be
made.
We
have
used
the
same
methodology
for
the
final
cost
estimates
presented
here.

As
for
the
comments
with
respect
to
equipment
variable
costs,
we
did
indeed
include
a
markup
of
29
percent
and
disagree
with
the
commenter
that
a
two­
to­
one
markup
would
be
more
appropriate.
Such
a
high
markup
on
equipment
variable
costs
is
not
sustainable
in
a
competitive
market,
at
least
on
average,
and
the
commenter
provided
no
data
nor
study
that
supported
the
comment.

We
have
made
minor
changes
to
the
proposed
numbers
to
express
them
in
2002
dollars
and
to
reflect
where
the
program
has
changed
(
i.
e.,
greater
than
750
horsepower
mobile
machines).
We
have
also
attributed
all
under
25
horsepower
redesign
costs
to
U.
S.
sales
since
we
do
not
expect
other
countries
to
have
similar
emission
standards
for
these
engines/
equipment.
Lastly,
we
have
corrected
some
minor
errors
made
in
the
proposal
in
determining
motive
versus
non­
motive
models
and
determining
the
number
of
unique
equipment
models
needing
redesign.
We
now
estimate
that
a
total
of
over
4,500
equipment
models
will
be
redesigned
as
compared
to
the
proposal's
estimate
of
just
over
4,100
equipment
models.
Further
discussion
of
these
changes
can
be
found
in
Chapter
6
of
the
RIA.

a.
Equipment
Fixed
Costs
As
we
noted
in
the
proposal,
the
most
significant
changes
anticipated
for
equipment
redesign
are
changes
to
accommodate
the
physical
changes
to
engines,
especially
for
those
engines
that
add
PM
traps
and
NO
X
adsorbers.
The
costs
for
engine
development
and
the
emission
control
devices
are
included
as
costs
to
the
engines,
as
described
above.
Equipment
manufacturers
must
still
incur
the
effort
and
expense
of
integrating
the
engine
and
emissions
control
devices
into
the
piece
of
equipment.
Therefore,
we
have
allocated
extensive
engineering
time
for
this
effort.

The
costs
we
have
estimated
are
based
on
engine
power
and
whether
an
application
is
nonmotive
(
e.
g.,
a
generator
set)
or
motive
(
e.
g.,
a
skid
steer
loader).
The
designs
we
have
considered
to
be
non­
motive
are
those
that
lack
a
propulsion
system.
In
addition,
the
new
emission
standards
for
engines
rated
under
25
horsepower
and
the
2008
standards
for
25
 
75
horsepower
engines
are
237
Note
that
the
equipment
redesign
estimates,
and
all
other
equipment
related
costs,
have
been
adjusted
from
the
NPRM
to
express
them
in
2002
dollars.

398
projected
to
require
no
significant
equipment
redesign
beyond
that
done
to
accommodate
the
Tier
2
standards.
As
explained
earlier,
we
expect
that
these
engines
will
comply
with
the
new
Tier
4
standards
through
either
engine
modifications
to
reduce
engine­
out
emissions
or
through
the
addition
of
a
DOC.
We
have
projected
that
engine
modifications
will
not
affect
the
outer
dimensions
of
the
engine
and
that
a
DOC
will
replace
the
existing
muffler.
Therefore,
either
approach
taken
by
the
engine
manufacturer
should
have
limited
to
no
impact
on
the
equipment
design.
Nonetheless,
we
have
conservatively
estimated
their
redesign
costs
at
$
53,100
per
model.
237
A
number
of
equipment
manufacturers
have
shared
detailed
information
with
us
regarding
the
investments
made
for
Nonroad
Tier
2
equipment
redesign
efforts,
as
well
as
redesign
estimates
for
significant
changes
such
as
installing
a
new
engine
design.
These
estimates
range
from
approximately
$
53,100
for
some
lower
powered
equipment
models
to
well
over
$
1
million
dollars
for
high
horsepower
equipment
with
very
challenging
design
constraints.
We
believe
that
the
equipment
redesign
efforts
undertaken
for
the
T2/
3
are
representative
of
the
effort
that
will
be
required
for
Tier
4
because
the
changes
needed
are
the
same
in
nature
 
increasing
available
space
within
the
machine
to
accommodate
new
hardware.
We
have
based
our
Tier
4
estimates,
in
part,
on
that
industry
input
and
have
estimated
that
equipment
redesign
costs
will
range
from
$
53,100
per
model
for
25
horsepower
equipment
up
to
$
796,500
per
model
for
300
horsepower
equipment
and
above.
For
mobile
machines
greater
than750
horsepower,
we
have
used
a
new
redesign
cost
of
$
106,000
associated
with
the
2011
standards
which
is
consistent
in
scale
with
the
estimate
used
for
25
to
50
horsepower
equipment
that
add
both
EGR
and
a
CDPF
in
the
2013
timeframe.
This
estimate
was
not
in
the
proposal.
For
this
larger
equipment,
we
have
continued
with
an
estimate
of
$
796,500
associated
with
the
2015
standards
even
though
we
project
no
need
to
accommodate
a
NO
X
adsorber.
We
have
attributed
only
a
portion
of
the
equipment
redesign
costs
to
U.
S.
sales
in
a
manner
consistent
with
that
taken
for
engine
R&
D
costs
and
engine
tooling
costs.
In
addition,
we
expect
manufacturers
to
incur
some
fixed
costs
to
update
service
and
operation
manuals
to
address
the
maintenance
demands
of
new
emission
control
technologies
and
the
new
oil
service
intervals;
we
estimate
these
service
manual
updates
to
cost
between
$
2,660
and
$
10,620
per
equipment
model.

These
equipment
fixed
costs
(
redesign
and
manual
updates)
were
then
allocated
appropriately
to
each
new
model
to
arrive
at
a
total
equipment
fixed
cost
of
$
828
million.
We
have
assumed
that
these
costs
will
be
recovered
over
a
ten
year
period
with
a
seven
percent
opportunity
cost
of
capital.
By
comparison,
our
proposal
estimated
equipment
fixed
costs
at
$
698
million.
The
costs
are
higher
now
because
of
the
changes
mentioned
above
 
expressing
costs
in
2002
dollars;
attributing
all
under
25
horsepower
redesign
costs
to
U.
S.
sales;
and,
correcting
upward
the
number
of
equipment
models
to
be
redesigned.
399
b.
Equipment
Variable
Costs
Equipment
variable
cost
estimates
are
based
on
costs
for
additional
materials
to
mount
the
new
hardware
(
i.
e.,
brackets
and
bolts
required
to
secure
the
aftertreatment
devices)
and
additional
sheet
metal
assuming
that
the
body
cladding
of
a
piece
of
equipment
(
i.
e.,
the
hood)
might
change
to
accommodate
the
aftertreatment
system.
Variable
costs
also
include
the
labor
required
to
install
these
new
pieces
of
hardware.
For
engines
above
75
horsepower
 
those
expected
to
incorporate
CDPF
and
NO
X
adsorber
technology
 
the
amount
of
sheet
metal
is
based
on
the
size
of
the
aftertreatment
devices.

For
equipment
of
150
horsepower
and
500
horsepower,
respectively,
we
have
estimated
the
costs
to
be
roughly
$
60
to
$
150.
Note
that
we
have
estimated
costs
for
equipment
in
all
horsepower
ranges,
and
these
estimates
are
presented
in
detail
in
the
RIA.
Throughout
this
discussion
of
engine
and
equipment
costs,
we
present
costs
for
a
150
and
a
500
horsepower
engine
for
illustrative
purposes.

3.
Overall
Engine
and
Equipment
Cost
Impacts
To
illustrate
the
engine
and
equipment
cost
impacts
we
are
estimating
for
the
Tier
4
standards,
we
have
chosen
several
example
pieces
of
equipment
and
have
presented
the
estimated
costs
for
them.
Using
these
examples,
we
can
calculate
the
costs
for
a
specific
piece
of
equipment
in
several
horsepower
ranges
and
better
illustrate
the
cost
impacts
of
the
new
standards.
These
costs
along
with
information
about
each
example
piece
of
equipment
are
shown
in
table
VI.
C­
1.
Costs
presented
are
near­
term
and
long­
term
costs
for
the
final
standards
to
which
each
piece
of
equipment
will
comply.
Long­
term
costs
are
only
variable
costs
and,
therefore,
represent
costs
after
all
fixed
costs
have
been
recovered
and
all
projected
learning
has
taken
place.
Included
in
the
table
are
estimated
prices
for
each
piece
of
equipment
to
provide
some
perspective
on
how
our
estimated
control
costs
relate
to
existing
equipment
prices.
400
Table
VI.
C­
1.
 
Near­
Term
and
Long­
Term
Costs
for
Several
Example
Pieces
of
Equipmenta
($
2002,
for
the
final
emission
standards
to
which
the
equipment
must
comply)

Gen­

Set
Skid/
Steer
Loader
Backhoe
Dozer
Ag
Tractor
Dozer
Off­

Highway
Truck
Horsepower
9
hp
33
hp
76
hp
175
hp
250
hp
503
hp
1000
hp
Incremental
Engine
&
Equipment
Cost
Long­
Term
Near­
Term
$
120
$
180
$
790
$
1,160
$
1,200
$
1,700
$
2,560
$
3,770
$
1,970
$
3,020
$
4,140
$
6,320
$
4,670
$
8,610
Estimated
Equipment
Price
when
Newb
$
4,000
$
20,000
$
49,000
$
238,000
$
135,000
$
618,000
$
840,000
Incremental
Operating
Costsc
­$
80
$
70
$
610
$
2,480
$
2,110
$
7,630
$
20,670
Baseline
Operating
Costs
(
Fuel
&
Oil
only)
c
$
940
$
2,680
$
7,960
$
27,080
$
23,750
$
77,850
$
179,530
Notes:
a
Near­
term
costs
include
both
variable
costs
and
fixed
costs;
long­
term
costs
include
only
variable
costs
and
represent
those
costs
that
remain
following
recovery
of
all
fixed
costs.
b
"
Price
Database
for
New
Nonroad
Equipment,"

memorandum
from
Zuimdie
Guerra
to
EDOCKET
OAR­
2003­
0012­
0960.
c
Present
value
of
lifetime
costs.

More
detail
and
discussion
regarding
what
these
costs
and
prices
mean
from
an
economic
impact
perspective
can
be
found
in
section
VI.
E.

D.
Annual
Costs
and
Cost
Per
Ton
One
tool
that
can
be
used
to
assess
the
value
of
the
Tier
4
standards
for
NRLM
fuel
and
nonroad
engines
is
the
costs
incurred
per
ton
of
emissions
reduced.
This
analysis
involves
a
comparison
of
our
new
program
to
other
measures
that
have
been
or
could
be
implemented.
As
summarized
in
this
section
and
detailed
in
the
RIA,
the
program
being
finalized
today
represents
a
highly
cost
effective
mobile
source
control
program
for
reducing
PM,
NO
X,
and
SO
2
emissions.

We
have
calculated
the
cost
per
ton
of
our
Tier
4
program
based
on
the
net
present
value
of
all
costs
incurred
and
all
emission
reductions
generated
over
a
30
year
time
window
following
implementation
of
the
program
(
i.
e.,
calendar
years
2007
through
2036).
This
approach
captures
all
of
the
costs
and
emissions
reductions
from
our
new
program
including
those
costs
incurred
and
238
We
are
not
analyzing
a
scenario
involving
just
the
engine
standards
because
the
nonroad
engine
standards
involving
advanced
emissions
control
technologies
require
the
use
of
the
15ppm
fuel.

401
emissions
reductions
generated
by
the
existing
fleet.
The
baseline
for
this
evaluation
is
the
existing
set
of
fuel
and
engine
standards
(
i.
e.,
unregulated
NRLM
fuel
and
the
Tier
2/
Tier
3
program).
The
30
year
time
window
chosen
is
meant
to
capture
both
the
early
period
of
the
program
when
very
few
new
engines
that
meet
the
new
standards
will
be
in
the
fleet,
and
the
later
period
when
essentially
all
engines
will
meet
the
new
standards.

We
have
analyzed
the
cost
per
ton
reduced
of
several
different
scenarios.
The
costs
and
emissions
reductions
of
each
of
these
scenarios
are
presented
in
detail
in
chapter
8
of
the
RIA.
Here,
we
present
information
of
the
cost
and
cost
effectiveness
for
the
following
two
scenarios:
(
1)
the
full
NRLM
fuel
and
nonroad
engine
program,
meaning
two
steps
of
fuel
control
(
to
500
ppm
and
then
to
15
ppm)
for
both
NR
and
L&
M
fuel
and
all
of
the
nonroad
engine
standards;
and,
(
2)
the
NRLM
fuel­
only
program,
meaning
two
steps
of
fuel
control
(
to
500
ppm
and
then
to
15
ppm)
for
both
NR
and
L&
M
fuel
but
without
any
new
nonroad
engine
standards.
238
For
the
first
of
these
scenarios,
the
discussion
illustrates
the
costs
and
relative
cost
effectiveness
of
the
final
NRT4
program
to
other
programs.
For
the
second
of
these
scenarios,
the
discussion
illustrates
the
costs
and
cost
effectiveness
associated
with
the
fuel
program
as
if
implemented
as
a
stand
alone
program
without
new
engine
standards.

In
sections
VI.
D.
1
and
2,
we
present
the
cost
of
the
full
NRLM
fuel
and
nonroad
engine
program
and
the
cost
per
ton
of
PM,
NO
X+
NMHC,
and
SO
2
reductions
that
will
be
realized.
The
analysis
presented
in
sections
VI.
D.
1
and
2
represents
the
total
Tier
4
program
for
nonroad
diesel
engines
and
NRLM
fuel
being
finalized
today.
In
sections
VI.
D.
3
and
4,
we
summarize
the
cost
for
the
NRLM
fuel­
only
scenario
and
the
cost
per
ton
of
PM
and
SO
2
reductions
that
would
be
realized.

1.
Annual
Costs
for
the
Full
NRLM
Fuel
and
Nonroad
Engine
Program
The
costs
of
the
full
NRLM
fuel
and
nonroad
engine
program
include
costs
associated
with
both
steps
in
the
NRLM
fuel
program
 
the
NR
fuel
reduction
to
500
ppm
sulfur
in
2007
and
to
15
ppm
sulfur
in
2010
and
the
L&
M
fuel
reduction
to
500
ppm
sulfur
in
2007
and
to
15
ppm
sulfur
in
2012.
Also
included
are
costs
for
the
2008
nonroad
engine
standards
for
engines
less
than
75
horsepower,
the
2013
standards
for
25
to
75
horsepower
engines,
and
costs
for
the
nonroad
engine
standards
for
engines
above
75
horsepower.
All
maintenance
and
operating
costs
are
included
along
with
maintenance
savings
realized
by
both
the
existing
fleet
(
nonroad,
locomotive,
and
marine)
and
the
new
fleet
of
engines
complying
with
the
Tier
4
standards.
402
Figure
VI.
D­
1
presents
these
results.
All
capital
costs
for
NRLM
fuel
production
and
nonroad
engine
and
equipment
fixed
costs
have
been
amortized
at
seven
percent.
The
figure
shows
that
total
annual
costs
are
estimated
to
be
$
50
million
in
the
first
year
the
new
engine
standards
apply,
increasing
to
a
peak
of
$
2.2
billion
in
2036
as
increasing
numbers
of
engines
become
subject
to
the
new
nonroad
standards
and
an
ever
increasing
amount
of
NRLM
fuel
is
consumed.
The
net
present
value
of
the
annualized
costs
over
the
period
from
2007
to
2036
is
$
27
billion
using
a
3
percent
discount
rate
and
$
14
billion
using
a
7
percent
discount
rate.

Figure
VI.
D­
1.
 
Annual
Costs
of
the
Full
NRT4
Fuel
and
Engine
Program
­$
1,000
­$
500
$
0
$
500
$
1,000
$
1,500
$
2,000
$
2,500
2004
2008
2012
2016
2020
2024
2028
2032
2036
Year
Program
Costs
($
Millions)

Engine
Costs
Equipment
Costs
Fuel
Costs
Other
Operating
Costs
Total
Program
Costs
2.
Cost
per
Ton
of
Emissions
Reduced
for
the
Full
NRLM
Fuel
and
Nonroad
Engine
Program
We
have
calculated
the
cost
per
ton
of
emissions
reduced
associated
with
the
NRT4
engine
and
NRLM
fuel
program.
The
resultant
cost
per
ton
numbers
depend
on
how
the
costs
presented
above
are
allocated
to
each
pollutant.
Therefore,
we
have
carefully
allocated
costs
according
to
403
the
pollutants
for
which
they
are
incurred.
Where
fuel
changes
occur
in
conjunction
with
new
engine
standards
(
engine
standards
enabled
by
those
fuel
changes),
we
allocate
one­
half
of
the
fuelrelated
costs
to
fuel­
derived
emissions
reductions
(
PM
and
SO
2,
with
one­
third
of
that
half
allocated
to
PM
and
two­
thirds
to
SO
2)
and
one­
half
to
engine­
derived
emissions
reductions
(
NO
X+
NMHC
and
PM,
with
that
half
split
50/
50
between
each
pollutant).
Where
fuel
changes
occur
without
new
engine
standards
on
which
fuel
changes
are
premised
(
i.
e.,
500ppm
NRLM
fuel
and
15ppm
L&
M
fuel),
we
have
allocated
costs
associated
with
fuel­
derived
emissions
reductions
one­
third
to
PM
and
two­
thirds
to
SO
2.
We
have
allocated
costs
associated
with
engine­
derived
emissions
reductions
(
i.
e.,
engine/
equipment
costs)
directly
to
the
pollutant
for
which
the
cost
is
incurred.
These
engine
and
equipment
cost
allocations
are
noted
throughout
the
discussion
in
section
VI.
C,
and
are
detailed
in
full
in
chapter
8
of
the
RIA.

We
have
calculated
the
costs
per
ton
using
the
net
present
value
of
the
annualized
costs
of
the
program
through
2036
and
the
net
present
value
of
the
annual
emission
reductions
through
2036.
We
have
also
calculated
the
cost
per
ton
of
emissions
reduced
in
the
year
2030
using
the
annual
costs
and
emissions
reductions
in
that
year
alone.
This
number
represents
the
long­
term
cost
per
ton
of
emissions
reduced.
The
cost
per
ton
numbers
include
costs
and
emission
reductions
that
will
occur
from
the
existing
fleet
(
i.
e.,
those
pieces
of
nonroad
equipment
that
were
sold
into
the
market
prior
to
the
new
emission
standards).
These
results
are
shown
in
Table
VI.
D­
1
using
both
a
three
percent
and
a
seven
percent
social
discount
rate.

Table
VI.
D­
1.
 
Total
Fuel
and
Engine
Program
30
Year
Aggregate
Cost
per
Ton
and
Long­
Term
Annual
Cost
Per
Ton
($
2002)

Pollutant
30
Year
Discounted
Lifetime
Cost
per
ton
at
3%
30
Year
Discounted
Lifetime
Cost
per
ton
at
7%
Long­
Term
Cost
per
Ton
in
2030
NOX+
NMHC
$
1,010
$
1,160
$
680
PM
$
11,200
$
11,800
$
9,300
SOX
$
690
$
620
$
810
3.
Annual
Costs
for
the
NRLM
Fuel­
only
Scenario
Cent
per
gallon
costs
for
the
new
500
ppm
NRLM
fuel,
the
new
500
ppm
L&
M
fuel,
the
new
15
ppm
NR
fuel,
and
the
new
15
ppm
NRLM
fuel
were
presented
in
section
IV.
A.
Having
this
fuel
will
result
in
maintenance
savings
associated
with
increased
oil
change
intervals
for
both
the
new
and
the
existing
fleet
of
nonroad,
locomotive,
and
marine
engines.
These
maintenance
savings
were
discussed
in
section
VI.
B.
There
are
no
engine
and
equipment
costs
associated
with
the
NRLM
fuel­
only
scenario
because
new
engine
emissions
standards
are
not
included
in
that
scenario.
Figure
VI.
D­
2
shows
the
annual
costs
associated
with
the
NRLM
fuel­
only
program.
404
As
can
be
seen
in
figure
VI.
D­
1,
the
costs
for
refining
and
distributing
the
fuel
range
from
$
250
million
in
2008
to
nearly
$
1.3
billion
in
2036.
The
increase
in
fuel
costs
in
2010
reflect
the
change
to
higher
cost
15
ppm
NR
fuel.
Fuel
costs
continue
to
grow
as
more
fuel
is
consumed
by
the
increasing
number
of
engines
and
equipment.
The
fuel
costs
are
largely
offset
by
the
maintenance
savings
that
range
from
$
250
million
in
2008
to
$
500
million
in
2036.
As
a
whole,
the
net
cost
of
the
program
in
each
year
ranges
from
a
small
net
savings
in
2008
to
around
$
780
million
in
2036.
The
net
present
value
(
i.
e.,
the
value
in
2004)
of
the
net
costs
associated
with
the
NRLM
fuel­
only
program
during
the
30
year
period
from
2007
to
2036
is
estimated
at
$
9.2
billion
using
a
3
percent
discount
rate
and
$
4.6
billion
using
a
7
percent
discount
rate.

Figure
VI.
D­
2.
 
Annual
Costs
of
the
NRLM
Fuel­
only
Scenario
$(
1,000)
$(
500)
$­
$
500
$
1,000
$
1,500
$
2,000
$
2,500
2004
2008
2012
2016
2020
2024
2028
2032
2036
Year
Program
Costs
($
Million)

Fuel
Costs
Other
Operating
Costs
Net
Costs
4.
Cost
Per
Ton
of
Emissions
Reduced
for
the
NRLM
Fuel­
only
Scenario
The
fuel­
borne
sulfur
reduction
under
the
NRLM
fuel­
only
scenario
will
result
in
significant
reductions
of
both
SO
2
and
PM
emissions.
Since
there
are
no
new
engine
standards
associated
405
with
the
NRLM
fuel­
only
scenario,
the
emissions
reductions
that
result
are
entirely
fuel­
derived.
Roughly
98
percent
of
fuel­
borne
sulfur
is
converted
to
SO
2
in
the
engine
with
the
remaining
two
percent
being
exhausted
as
sulfate
PM.
We
have
allocated
one­
third
of
the
costs
of
this
program
to
PM
control
and
two­
thirds
to
SO
2
control.
This
is
consistent
with
the
cost
accounting
we
have
used
throughout
our
analysis
in
that
costs
associated
with
fuel­
derived
emissions
reductions
are
attributed
one­
third
to
PM
control
and
two­
thirds
to
SO
2
control.

As
discussed
above,
the
30
year
net
present
value
of
costs
associated
with
the
fuel­
only
program
are
estimated
at
$
9.2
billion
using
3
percent
discounting
and
$
4.6
billion
using
7
percent
discounting.
We
have
estimated
the
30
year
net
present
value
of
the
SO
2
emission
reductions
at
5.7
million
tons
and
PM
emission
reductions
at
462,000
tons
using
3
percent
discounting,
3.2
million
tons
and
255,000
tons,
respectively,
using
7
percent
discounting.

Table
VI.
D­
1
shows
the
cost
per
ton
of
emissions
reduced
as
a
result
of
the
NRLM
fuelonly
scenario.
The
cost
per
ton
numbers
include
costs
and
emissions
reductions
that
will
occur
from
both
the
new
and
the
existing
fleet
(
i.
e.,
those
pieces
of
nonroad
equipment
that
were
sold
into
the
market
prior
to
the
new
fuel
standards)
of
nonroad,
locomotive,
and
marine
engines.

Table
VI.
D­
2.
 
NRLM
Fuel­
only
Scenario
30
year
Aggregate
Cost
per
Ton
and
Long­
Term
Annual
Cost
Per
Ton
($
2002)

Pollutant
30
Year
Discounted
Lifetime
Cost
per
ton
at
3%
30
Year
Discounted
Lifetime
Cost
per
ton
at
7%
Long­
Term
Cost
per
Ton
in
2030
PM
$
6,600
$
6,000
$
7,900
SO2
$
1,070
$
970
$
1,270
We
also
considered
the
cost
per
ton
of
the
NRLM
fuel­
only
scenario
without
including
the
expected
maintenance
savings
associated
with
low
sulfur
fuel.
Without
the
maintenance
savings,
the
30
year
discounted
cost
per
ton
of
PM
reduced
would
be
$
11,800
and
of
SO
2
reduced
would
be
$
1,900
using
3
percent
discounting
and
$
11,200
and
$
1,800,
respectively,
using
7
percent
discounting.
More
detail
on
how
the
costs
and
cost
per
ton
numbers
associated
with
the
NRLM
fuel­
only
scenario
were
calculated
can
be
found
in
the
RIA.

5.
Comparison
With
Other
Means
of
Reducing
Emissions
In
comparison
with
other
emissions
control
programs,
we
believe
that
the
Tier
4
programs
represent
a
cost
effective
strategy
for
generating
substantial
NO
X+
NMHC,
PM,
and
SO
2
reductions.
This
can
be
seen
by
comparing
the
cost
per
ton
of
emissions
reduced
by
the
NRLM
fuel­
only
scenario
(
i.
e.,
reducing
fuel
sulfur
to
500
ppm
in
2007
and
15
ppm
in
2010
without
any
new
nonroad
engine
standards)
and
the
cost
per
ton
of
emissions
reduced
by
the
full
NRLM
fuel
406
and
nonroad
engine
program
(
i.
e.,
fuel
control
and
new
engine
standards)
with
a
number
of
standards
that
EPA
has
adopted
in
the
past.
Tables
VI.
D­
3
and
VI.
D­
4
summarize
the
cost
per
ton
of
several
past
EPA
actions
to
reduce
emissions
of
NO
X+
NMHC
and
PM
from
mobile
sources,
all
of
which
were
considered
by
EPA
to
be
appropriate.
407
Table
VI.
D­
3.
 
NRT4
Cost
Per
Ton
comparison
to
Previous
Mobile
Source
Programs
for
NOX
+
NMHC
Program
$/
ton
Tier
4
Nonroad
Diesel
(
full
program)

Tier
2
Nonroad
Diesel
Tier
3
Nonroad
Diesel
Tier
2
vehicle/
gasoline
sulfur
2007
Highway
HD
2004
Highway
HD
Tier
1
vehicle
NLEV
Marine
SI
engines
On­
board
diagnostics
Marine
CI
engines
Large
SI
Exhaust
Recreational
Marine
1,010
630
430
1,400
­
2,350
2,240
220
­
430
2,150
­
2,910
2,020
1,220
­
1,930
2,410
30
­
190
80
670
Note:
Costs
adjusted
to
2002
dollars
using
the
Producer
Price
Index
for
Total
Manufacturing
Industries.

Table
VI.
D­
4.
 
NRT4
Cost
Per
Ton
Comparison
To
Previous
Mobile
Source
Programs
for
PM
Program
$/
ton
Tier
4
Nonroad
Diesel
(
full
program)

Tier
4
NRLM
fuel­
only
(
fuel­
only
scenario)

Tier
1/
Tier
2
Nonroad
Diesel
2007
Highway
HD
Marine
CI
engines
1996
urban
bus
Urban
bus
retrofit/
rebuild
1994
highway
HD
diesel
11,200
6,800
2,390
14,180
4,040
­
5,440
12,780
­
20,450
31,530
21,780
­
25,500
Note:
Costs
adjusted
to
2002
dollars
using
the
Producer
Price
Index
for
Total
Manufacturing
Industries.

To
compare
the
cost
per
ton
of
SO
2
emissions
reduced,
we
looked
at
the
cost
per
ton
for
the
Title
IV
(
acid
rain)
SO
2
trading
programs.
This
information
is
found
in
EPA
report
430/
R­
02­
408
004,
"
Documentation
of
EPA
Modeling
Applications
(
V.
2.1)
Using
the
Integrated
Planning
Model",
in
Figure
9.11
on
page
9­
14
(
www.
epa.
gov/
airmarkets/
epaipm
index.
html#
documentation).
The
SO
2
cost
per
ton
results
of
the
full
Tier
4
program
presented
in
table
VI.
D­
2
compare
very
favorably
with
the
program
shown
in
table
VI.
D­
5.

Table
VI.
D­
5.
 
NRT4
Cost
Per
Ton
Comparison
to
SO2
from
both
the
EPA
Base
Case
2000
for
the
Title
IV
SO2
Trading
Programs
and
the
Proposed
Interstate
Air
Quality
Rule
Program
$/
ton
Tier
4
Nonroad
Diesel
(
full
program)

Tier
4
Nonroad
Diesel
(
fuel­
only
scenario)

Title
IV
SO
2
Trading
Programs
Interstate
Air
Quality
Rule
(
average
cost)
$
690
$
1,070
$
490
in
2010
to
$
610
in
2020
$
730
in
2010
to
$
830
in
2015
Note:
Costs
adjusted
to
2002
dollars
using
the
Producer
Price
Index
for
Total
Manufacturing
Industries.

As
the
above
comparisons
show,
both
the
NRLM
fuel­
only
scenario,
when
viewed
by
itself,
and
the
combination
of
NRLM
fuel
and
nonroad
engine
standards,
are
both
cost
effective
strategies
to
achieve
the
associated
emissions
reductions.

E.
Do
the
Benefits
Outweigh
the
Costs
of
the
Standards?

Our
analysis
of
the
health
and
environmental
benefits
to
be
expected
from
this
final
rule
are
presented
in
this
section.
Briefly,
the
analysis
projects
major
benefits
throughout
the
period
from
initial
implementation
of
the
rule
over
a
30
year
period
through
2036.
As
described
below,
thousands
of
deaths
and
other
serious
health
effects
would
be
prevented,
yielding
a
net
present
value
in
2004
of
those
benefits
we
could
monetize
of
approximately
$
805
billion
dollars
using
a
3
percent
discount
rate
and
$
352
billion
using
a
7
percent
discount
rate.
These
benefits
exceed
the
net
present
value
of
the
social
cost
of
the
proposal
($
27
billion
using
a
3
percent
discount
rate
and
$
14
billion
using
a
7
percent
discount
rate)
by
$
780
billion
using
a
3
percent
discount
rate
and
$
340
billion
using
a
7
percent
discount
rate.

1.
What
Were
the
Results
of
the
Benefit­
Cost
Analysis?

Table
VI.
E­
1
presents
the
primary
estimate
of
reduced
incidence
of
PM­
related
health
effects
for
the
years
2020
and
2030.
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
PM­
related
benefits
associated
with
the
reduction
of
several
health
effects.
In
2030,
we
estimate
that
there
will
be
239
While
we
did
not
include
separate
estimates
of
the
number
of
premature
deaths
that
would
be
avoided
due
to
reductions
in
ozone
levels,
recent
evidence
has
been
found
linking
short­
term
ozone
exposures
with
premature
mortality
independent
of
PM
exposures.
Recent
reports
by
Thurston
and
Ito
(
2001)
and
the
World
Health
Organization
(
WHO)
support
an
independent
ozone
mortality
impact,
and
the
EPA
Science
Advisory
Board
has
recommended
that
EPA
reevaluate
the
ozone
mortality
literature
for
possible
inclusion
in
the
estimate
of
total
benefits.
Based
on
these
new
analyses
and
recommendations,

EPA
is
sponsoring
three
independent
meta­
analyses
of
the
ozone­
mortality
epidemiology
literature
to
inform
a
determination
on
inclusion
of
this
important
health
endpoint.
Upon
completion
and
peer­
review
of
the
meta­
analyses,
EPA
will
make
its
determination
on
whether
and
how
benefits
of
reductions
in
ozone­
related
mortality
will
be
included
in
the
benefits
analysis
for
future
rulemakings.

240
Our
PM­
related
estimate
in
2030
incorporates
significant
reductions
of
160,000
fewer
cases
of
lower
respiratory
symptoms
in
children
ages
7
to
14
each
year,
120,000
fewer
cases
of
upper
respiratory
symptoms
(
similar
to
cold
symptoms)
in
asthmatic
children
each
year,
and
13,000
fewer
cases
of
acute
bronchitis
in
children
ages
8
to
12
each
year.
In
addition,
we
estimate
that
this
rule
will
reduce
almost
6,000
emergency
room
visits
for
asthma
attacks
in
children
each
year
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.

409
12,000
fewer
fatalities
in
adults239
and
20
fewer
fatalities
in
infants
per
year
associated
with
fine
PM,
and
the
rule
will
result
in
about
5,600
fewer
cases
of
chronic
bronchitis,
8,900
fewer
hospitalizations
(
for
respiratory
and
cardiovascular
disease
combined),
and
result
in
1
million
days
per
year
when
adults
miss
work
because
of
their
respiratory
symptoms
and
5.9
million
days
of
when
adults
must
restrict
their
activity
due
to
respiratory
illness.
We
also
estimate
substantial
health
improvements
for
children
from
reduced
upper
and
lower
respiratory
illness,
acute
bronchitis,
and
asthma
attacks.
240
We
were
unable
to
quantify
the
benefits
related
to
ozone
and
other
pollutants
for
the
final
rule,
although
we
do
present
some
preliminary
ozone
modeling
in
Chapter
9
of
the
RIA.

Table
VI.
E­
2
presents
the
total
monetized
benefits
for
the
years
2020
and
2030.
This
table
also
indicates
with
a
"
B"
those
additional
health
and
environmental
effects
which
we
were
unable
to
quantify
or
monetize.
These
effects
are
additive
to
estimate
of
total
benefits,
and
EPA
believes
there
is
considerable
value
to
the
public
of
the
benefits
that
could
not
be
monetized.
A
full
listing
of
the
benefit
categories
that
could
not
be
quantified
or
monetized
in
our
estimate
are
provided
in
table
VI.
E­
6.

In
summary,
EPA's
primary
estimate
of
the
benefits
of
the
rule
are
$
83
+
B
billion
in
2030
using
a
3
percent
discount
rate
and
$
78
+
B
billion
using
a
7
percent
discount
rate.
In
2020,
total
monetized
benefits
are
$
42
+
B
billion
using
a
3
percent
discount
rate
and
$
41
+
B
billion
using
a
7
410
percent
discount
rate.
These
estimates
account
for
growth
in
real
gross
domestic
product
(
GDP)
per
capita
between
the
present
and
the
years
2020
and
2030.
As
the
table
indicates,
total
benefits
are
driven
primarily
by
the
reduction
in
premature
fatalities
each
year,
which
account
for
over
90
percent
of
total
benefits.

Table
VI.
E­
1.
 
Reductions
in
Incidence
of
PM­
related
Adverse
Health
Effects
Associated
with
the
Final
Nonroad
Diesel
Engine
and
Fuel
Standards
Full
Program
Endpoint
Avoided
Incidencea
(
cases/
year)

2020
2030
Premature
mortalityb:
Long­
term
exposure
(
adults,
30
and
over)
6,500
12,000
Infant
mortality
(
infants
under
one
year)
15
22
Chronic
bronchitis
(
adults,
26
and
over)
3,500
5,600
Non­
fatal
myocardial
infarctions
(
adults,
18
and
older)
8,700
15,000
Hospital
admissions
 
Respiratory
(
adults,
20
and
older)
c
2,800
5,100
Hospital
admissions
 
Cardiovascular
(
adults,
20
and
older)
d
2,300
3,800
Emergency
Room
Visits
for
Asthma
(
18
and
younger)
3,800
6,000
Acute
bronchitis
(
children,
8­
12)
8,400
13,000
Asthma
exacerbations
(
asthmatic
children,
6­
18)
120,000
200,000
Lower
respiratory
symptoms
(
children,
7­
14)
100,000
160,000
Upper
respiratory
symptoms
(
asthmatic
children,
9­
11)
76,000
120,000
Work
loss
days
(
adults,
18­
65)
670,000
1,000,000
Minor
restricted
activity
days
(
adults,
age
18­
65)
4,000,000
5,900,000
Notes:
a
Incidences
are
rounded
to
two
significant
digits.
b
Premature
mortality
associated
with
ozone
is
not
separately
included
in
this
analysis.
c
Respiratory
hospital
admissions
for
PM
includes
admissions
for
COPD,
pneumonia,
and
asthma.
d
Cardiovascular
hospital
admissions
for
PM
includes
total
cardiovascular
and
subcategories
for
ischemic
heart
disease,
dysrhythmias,
and
heart
failure.
411
Table
VI.
E­
2.
 
EPA
Primary
Estimate
of
the
Annual
Quantified
and
Monetized
Benefits
Associated
with
Improved
PM
Air
Quality
Resulting
from
the
Final
Nonroad
Diesel
Engine
and
Fuel
Standards
Full
Program
Endpoint
Monetary
Benefitsa,
b
(
millions
2000$,
Adjusted
for
Income
Growth)

2020
2030
Premature
mortalityc:
(
adults,
30
and
over)

3%
discount
rate
$
41,000
$
77,000
7%
discount
rate
$
38,000
$
72,000
Infant
mortality
(
infants
under
one
year)
$
97
$
150
Chronic
bronchitis
(
adults,
26
and
over)
$
1,500
$
2,400
Non­
fatal
myocardial
infarctionsd
3%
discount
rate
$
750
$
1,200
7%
discount
rate
$
720
$
1,200
Hospital
Admissions
from
Respiratory
Causese
$
49
$
92
Hospital
Admissions
from
Cardiovascular
Causesf
$
51
$
83
Emergency
Room
Visits
for
Asthma
$
1.1
$
1.7
Acute
bronchitis
(
children,
8­
12)
$
3.2
$
5.2
Asthma
exacerbations
(
asthmatic
children,
6­
18)
$
5.7
$
9.2
Lower
respiratory
symptoms
(
children,
7­
14)
$
1.7
$
2.7
Upper
respiratory
symptoms
(
asthmatic
children,
9­
11)
$
2.0
$
3.2
Work
loss
days
(
adults,
18­
65)
$
92
$
130
Minor
restricted
activity
days
(
adults,
age
18­
65)
$
210
$
320
Recreational
visibility
(
86
Class
I
Areas)
$
1,000
$
1,700
Monetized
Totalg
3%
discount
rate
7%
discount
rate
$
44,000+
B
$
42,000+
B
$
83,000+
B
$
78,000+
B
Notes:
a
Monetary
benefits
are
rounded
to
two
significant
digits.
b
Monetary
benefits
are
adjusted
to
account
for
growth
in
real
GDP
per
capita
between
1990
and
the
analysis
year
(
2020
or
2030).
c
Valuation
of
base
estimate
assumes
discounting
over
the
lag
structure
described
in
the
RIA
Chapter
9.
d
Estimates
assume
costs
of
illness
and
lost
earnings
in
later
life
years
are
discounted
using
either
3
or
7
percent.
e
Respiratory
hospital
admissions
for
PM
includes
admissions
for
COPD,
pneumonia,
and
asthma.
f
Cardiovascular
hospital
admissions
for
PM
includes
total
cardiovascular
and
subcategories
for
ischemic
heart
disease,
dysrhythmias,
and
heart
failure.
g
B
represents
the
monetary
value
of
the
unmonetized
health
and
welfare
benefits.
A
detailed
listing
of
unquantified
PM,
ozone,
CO,
and
NMHC
related
health
effects
is
provided
in
Table
VI.
E­
6.
412
The
estimated
social
cost
(
measured
as
changes
in
consumer
and
producer
surplus)
in
2030
to
implement
the
final
rule
from
table
VI.
E­
3
is
$
2.0
billion
(
2000$).
Thus,
the
net
benefit
(
social
benefits
minus
social
costs)
of
the
program
at
full
implementation
is
approximately
$
81
+
B
billion
using
a
3
percent
discount
rate
and
$
78
+
B
billion
using
a
7
percent
discount
rate.
In
2020,
partial
implementation
of
the
program
yields
net
benefits
of
$
42
+
B
billion
using
a
3
percent
discount
rate
and
$
41
+
B
billion
using
a
7
percent
discount
rate.
Therefore,
implementation
of
the
final
rule
is
expected
to
provide
society
with
a
net
gain
in
social
welfare
based
on
economic
efficiency
criteria.
Table
VI.
E­
3
presents
a
summary
of
the
benefits,
costs,
and
net
benefits
of
the
final
rule's
full
program.
Figure
VI­
E.
1
displays
the
stream
of
benefits,
costs,
and
net
benefits
of
the
Nonroad
Diesel
Vehicle
Rule
from
2007
to
2036
using
two
different
discount
rates.
In
addition,
table
VI.
E­
4
presents
the
net
present
value
of
the
stream
of
benefits,
costs,
and
net
benefits
associated
with
the
rule
for
this
30
year
period.
The
total
net
present
value
in
2004
of
the
stream
of
net
benefits
(
benefits
minus
costs)
is
$
780
billion
using
a
3
percent
discount
rate
and
$
340
billion
using
a
7
percent
discount
rate.
413
Table
VI.
E­
3.
 
Summary
of
Benefits,
Costs,
and
Net
Benefits
of
the
Final
Nonroad
Diesel
Engine
and
Fuel
Standards
Full
Program
2020a
(
Billions
of
2000
dollars)
2030a
(
Billions
of
2000
dollars)

Social
Costsb
$
1.8
$
2.0
Social
Benefits:
b,
c,
d
CO,
VOC,
Air
Toxic­
related
benefits
Not
monetized
Not
monetized
Ozone­
related
benefits
Not
monetized
Not
monetized
PM­
related
Welfare
benefits
$
1.0
$
1.7
PM­
related
Health
benefits
[
3%
discount]
$
43
+
B
$
81
+
B
PM­
related
Health
benefits
[
7%
discount]
$
41
+
B
$
78
+
B
Net
Benefits
(
Benefits­
Costs)
[
3%
discount]
c
$
44
+
B
$
81
+
B
Net
Benefits
(
Benefits­
Costs)
[
7%
discount]
c
$
42
+
B
$
78
+
B
Notes:
a
All
costs
and
benefits
are
calculated
using
3
and
7
percent
discount
rates
and
are
rounded
to
two
significant
digits.
Numbers
may
appear
not
to
sum
due
to
rounding.
b
Note
that
costs
are
the
total
costs
of
reducing
all
pollutants,
including
CO,
VOCs
and
air
toxics,
as
well
as
NOX
and
PM.
Costs
were
converted
to
2000$
using
the
PPI
for
Total
Manufacturing
Industries.
Benefits
in
this
table
are
associated
only
with
PM
endpoints
related
to
direct
PM,
NOX
and
SO2
reductions
in
48­
states.
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
VI.
E­
6.
B
is
the
sum
of
all
unquantified
benefits
and
disbenefits.
414
$(
20,000)
$­
$
20,000
$
40,000
$
60,000
$
80,000
$
100,000
$
120,000
2005
2010
2015
2020
2025
2030
2035
Millions
dollars
Total
Social
Benefits
Total
Social
Costs
Net
Benefits
Figure
VI.
E­
1.
 
Stream
of
Benefits,
Costs,
and
Net
Benefits
of
the
Final
Nonroad
Diesel
Engine
and
Fuel
Standards
Full
Program
415
Table
VI.
E­
4.
 
Net
Present
Value
in
2004
of
the
Stream
of
30
years
of
Benefits,
Costs,
and
Net
Benefits
for
the
Full
Nonroad
Diesel
Engine
and
Fuel
Standards
(
Billions
of
2000$)

Billions
of
2000$
3%
Discount
Rate
Billions
of
2000$
7%
Discount
Rate
Social
Costs
$
27
$
14
Social
Benefits
$
805
$
352
Net
Benefits
a
$
780
$
340
Notes:
a
Numbers
do
not
add
due
to
rounding.
Benefits
represent
48­
state
benefits
and
exclude
home
heating
oil
sulfur
reduction
benefits,
whereas
costs
include
50­
state
estimates.

In
addition,
we
analyzed
the
social
benefits
and
costs
of
the
fuel­
only
components
of
the
program,
as
discussed
in
the
RIA.
EPA's
primary
estimate
of
the
benefits
of
the
fuel­
only
component
of
the
final
rule
are
approximately
$
28
+
B
billion
in
2030
using
a
3
percent
discount
rate
and
$
25
+
B
billion
using
a
7
percent
discount
rate.
In
2020,
total
monetized
benefits
are
approximately
$
18
+
B
billion
using
a
3
percent
discount
rate
and
$
16
+
B
billion
using
a
7
percent
discount
rate.
These
estimates
account
for
growth
in
real
gross
domestic
product
(
GDP)
per
capita
between
the
present
and
the
years
2020
and
2030.
We
present
the
engineering
costs
of
implementing
the
fuel­
only
components
of
the
rule.
Engineering
compliance
costs
are
very
similar
to
the
total
social
costs
for
the
entire
program.
The
net
benefit
(
social
benefits
minus
engineering
costs)
of
the
fuel­
only
program
at
full
implementation
is
approximately
$
330
+
B
billion
using
a
3
percent
discount
rate
and
$
160
+
B
billion
using
a
7
percent
discount
rate.
Therefore,
implementation
of
the
fuel­
only
components
of
the
final
rule
is
expected
to
provide
society
with
a
net
gain
in
social
welfare
based
on
economic
efficiency
criteria.
Table
VI.
E­
5
presents
a
summary
of
the
social
benefits,
engineering
costs,
and
net
benefits
of
the
final
rule's
fuel­
only
program
for
a
30
year
period.
416
Table
VI.
E­
5.
 
Net
Present
Value
in
2004
of
the
Stream
of
Benefits,
Costs,
and
Net
Benefits
for
the
Fuel­
Only
Standards
(
Billions
of
2000$)

3%
Discount
Rate
7%
Discount
rate
Costs
$
9.2
$
4.6
Social
Benefits
$
340
$
160
Net
Benefits
$
330
$
160
Notes:
A
Results
are
rounded
to
two
significant
digits.
Sums
may
differ
because
of
rounding.
B
Engineering
costs
are
presented
instead
of
social
costs.
As
discussed
in
previous
chapters,
total
engineering
costs
include
fuel
costs
(
refining,
distribution,
lubricity)
and
other
operating
costs
(
oil
change
maintenance
savings).
C
Note
that
costs
are
the
total
costs
of
reducing
all
pollutants,
including
CO,
VOCs
and
air
toxics,
as
well
as
NOX
and
PM.
Benefits
in
this
table
are
associated
only
with
PM,
NOX
and
SO2
reductions.
The
estimates
do
not
include
the
benefits
of
reduced
sulfur
in
home
heating
oil
or
benefits
in
Alaska
or
Hawaii.

2.
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
proposed
rulemaking?"
In
designing
an
analysis
to
address
this
question,
we
selected
two
future
years
for
analysis
(
2020
and
2030)
that
are
representative
of
the
stream
of
benefits
and
costs
at
partial
and
full­
implementation
of
the
program.

To
quantify
benefits,
we
evaluated
PM­
related
health
effects
(
including
directly
emitted
PM
and
sulfate,
as
well
as
SO
2
and
NO
X
contributions
to
fine
particulate
matter).
Our
approach
requires
the
estimation
of
changes
in
air
quality
expected
from
the
rule
and
then
estimating
the
resulting
impact
on
health.
In
order
to
characterize
the
benefits
of
today's
action,
given
the
constraints
on
time
and
resources
available
for
the
analysis,
we
adopted
a
benefits
transfer
technique
that
relies
on
air
quality
and
benefits
modeling
for
a
preliminary
control
option
for
nonroad
diesel
engines
and
fuels.
Results
from
this
modeling
conducted
for
2020
and
2030
are
then
scaled
and
transferred
to
the
emission
reductions
expected
from
the
final
rule.
We
also
transferred
modeled
results
by
using
scaling
factors
associated
with
time
to
examine
the
stream
of
benefits
in
years
other
than
2020
and
2030.

More
specifically,
our
health
benefits
assessment
is
conducted
in
two
phases.
Due
to
the
time
requirements
for
running
the
sophisticated
emissions
and
air
quality
models,
it
is
often
241
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'');
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.

242
Interested
parties
may
want
to
consult
the
webpage:
http://
www.
epa.
gov/
science1
regarding
components
of
our
analytical
blueprint.

417
necessary
to
select
an
example
set
of
emission
reductions
to
use
for
the
purposes
of
emissions
and
air
quality
modeling
early
in
the
development
of
the
proposal.
In
phase
one,
we
evaluate
the
PMand
ozone­
related
health
effects
associated
with
a
modeled
preliminary
control
option
that
was
a
close
approximation
of
the
standards
in
the
years
2020
and
2030.
Using
information
from
the
modeled
preliminary
control
option
on
the
changes
in
ambient
concentrations
of
PM
and
ozone,
we
then
estimate
the
number
of
reduced
incidences
of
illnesses,
hospitalizations,
and
premature
fatalities
associated
with
this
scenario
and
estimate
the
total
economic
value
of
these
health
benefits.
Based
on
public
comment
and
other
data
described
in
the
RIA,
the
standards
we
are
finalizing
in
this
rulemaking
are
slightly
different
in
the
amount
of
emission
reductions
expected
to
be
achieved
in
2020
and
2030
relative
to
the
modeled
scenario.
Thus,
in
phase
two
of
the
analysis,
we
apportion
the
results
of
the
phase
one
analysis
to
the
underlying
NO
X,
SO
2,
and
PM
emission
reductions
and
scale
the
apportioned
benefits
to
reflect
differences
in
emissions
reductions
between
the
modeled
preliminary
control
option
and
the
proposed
standards.
The
sum
of
the
scaled
benefits
for
the
PM,
SO
2,
and
NO
X
emission
reductions
provide
us
with
the
total
benefits
of
the
rule.

The
benefit
estimates
derived
from
the
modeled
preliminary
control
option
in
phase
one
of
our
analysis
uses
an
analytical
structure
and
sequence
similar
to
that
used
in
the
benefits
analyses
for
the
Heavy
Duty
Engine/
Diesel
Fuel
final
rule
and
in
the
"
section
812
studies"
to
estimate
the
total
benefits
and
costs
of
the
full
Clean
Air
Act.
241
We
used
many
of
the
same
models
and
assumptions
used
in
the
Heavy
Duty
Engine/
Diesel
Fuel
analysis
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.
In
addition,
we
will
be
working
through
the
next
section
812
study
process
to
enhance
our
methods.
242
The
benefits
transfer
method
used
in
phase
two
of
the
analysis
is
similar
to
that
used
to
estimate
benefits
in
the
recent
analysis
of
the
Nonroad
Large
Spark­
Ignition
Engines
and
Recreational
Engines
standards
(
67
FR
68241,
November
8,
2002).
A
similar
method
has
also
been
used
in
recent
benefits
analyses
for
the
proposed
Industrial
Boilers
and
Process
Heaters
NESHAP
and
the
Reciprocating
Internal
Combustion
Engines
NESHAP.
418
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
PM.

In
its
report,
the
NAS
panel
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:

°
Include
benefits
estimates
for
a
range
of
regulatory
options;

°
Estimate
benefits
for
intervals,
such
as
every
five
years,
rather
than
a
single
year;

°
Clearly
state
the
projected
baseline
statistics
used
in
estimating
health
benefits,
including
those
for
air
emissions,
air
quality,
and
health
outcomes;

°
Examine
whether
implementation
of
proposed
regulations
might
cause
unintended
impacts
on
human
health
or
the
environment;

°
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;
and
°
Begin
to
move
the
assessment
of
uncertainties
from
its
ancillary
analyses
into
its
Base
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.

EPA
has
addressed
many
of
the
NAS
comments
in
our
analysis
of
the
final
rule.
We
provide
benefits
estimates
for
each
year
over
the
rule
implementation
period
for
a
wide
range
of
regulatory
alternatives,
in
addition
to
our
final
emission
control
program.
We
use
the
estimated
time
path
of
benefits
and
costs
to
calculate
the
net
present
value
of
benefits
of
the
rule.
In
the
RIA,
we
provide
baseline
statistics
for
air
emissions,
air
quality,
population,
and
health
outcomes.
We
have
examined
how
our
benefits
estimates
might
be
impacted
by
expanding
the
age
ranges
to
which
epidemiological
studies
are
applied,
and
we
have
added
several
new
health
endpoints,
including
non­
fatal
heart
attacks,
which
are
supported
by
both
U.
S.
studies
and
studies
conducted
in
Europe.
We
have
also
improved
the
documentation
of
our
methods
and
provided
additional
details
about
model
assumptions.
419
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.

EPA
plans
to
continue
to
refine
its
plans
for
addressing
uncertainty
in
its
analyses.
EPA
conducted
a
pilot
study
to
address
uncertainty
in
important
analytical
parameters
such
as
the
concentration­
response
relationship
for
PM­
related
premature
mortality.
EPA
is
also
conducting
longer­
term
elements
intended
to
provide
scientifically
sound,
peer­
reviewed
characterizations
of
the
uncertainty
surrounding
a
broader
set
of
analytical
parameters
and
assumptions,
including
but
not
limited
to
emissions
and
air
quality
modeling,
demographic
projections,
population
health
status,
concentration­
response
functions,
and
valuation
estimates.

3.
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
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,
odor,
and
ecological
benefits
of
reduction
in
CO,
VOCs,
air
toxics,
and
ozone);

°
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
scaling
of
the
results
of
the
modeled
benefits
analysis
to
the
proposed
standards,
especially
regarding
the
assumption
of
similarity
in
geographic
distribution
between
emissions
and
human
populations
and
years
of
analysis;

°
Variability
in
the
estimated
relationships
of
health
and
welfare
effects
to
changes
in
pollutant
concentrations;

°
Uncertainties
in
exposure
estimation;
and
420
°
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.
Accordingly,
we
present
a
primary
estimate
of
the
total
benefits,
based
on
our
interpretation
of
the
best
available
scientific
literature
and
methods
and
supported
by
the
SABHES
and
the
NAS.

Some
of
the
key
assumptions
underlying
the
primary
estimate
for
the
premature
mortality
which
accounts
for
90
percent
of
the
total
benefits
we
were
able
to
quantify
include
the
following:

(
1)
Inhalation
of
fine
particles
is
causally
associated
with
premature
death
at
concentrations
near
those
experienced
by
most
Americans
on
a
daily
basis.
Although
biological
mechanisms
for
this
effect
have
not
yet
been
definitively
established,
the
weight
of
the
available
epidemiological
evidence
supports
an
assumption
of
causality.
(
2)
All
fine
particles,
regardless
of
their
chemical
composition,
are
equally
potent
in
causing
premature
mortality.
This
is
an
important
assumption,
because
PM
produced
via
transported
precursors
emitted
from
EGUs
may
differ
significantly
from
direct
PM
released
from
diesel
engines
and
other
industrial
sources,
but
no
clear
scientific
grounds
exist
for
supporting
differential
effects
estimates
by
particle
type.
(
3)
The
impact
function
for
fine
particles
is
approximately
linear
within
the
range
of
ambient
concentrations
under
consideration.
Thus,
the
estimates
include
health
benefits
from
reducing
fine
particles
in
areas
with
varied
concentrations
of
PM,
including
both
regions
that
are
in
attainment
with
fine
particle
standard
and
those
that
do
not
meet
the
standard.
(
4)
The
forecasts
for
future
emissions
and
associated
air
quality
modeling
are
valid.
Although
recognizing
the
difficulties,
assumptions,
and
inherent
uncertainties
in
the
overall
enterprise,
these
analyses
are
based
on
peer­
reviewed
scientific
literature
and
up­
to­
date
assessment
tools,
and
we
believe
the
results
are
highly
useful
in
assessing
this
rule.

We
provide
sensitivity
analyses
to
illustrate
the
effects
of
uncertainty
about
key
analytical
assumptions
in
the
RIA.

In
addition,
one
significant
limitation
to
the
benefit
transfer
method
applied
in
this
analysis
is
the
inability
to
scale
ozone­
related
benefits.
Because
ozone
is
a
homogeneous
gaseous
pollutant,
it
is
not
possible
to
apportion
ozone
benefits
to
the
precursor
emissions
of
NO
X
and
VOC.
Coupled
with
the
potential
for
NO
X
reductions
to
either
increase
or
decrease
ambient
ozone
levels,
this
prevents
us
from
scaling
the
benefits
associated
with
a
particular
combination
of
VOC
and
NO
X
emissions
reductions
to
another.
Because
of
our
inability
to
scale
ozone
benefits,
we
do
421
not
include
ozone
benefits
as
part
of
the
monetized
benefits
of
the
proposed
standards.
For
the
most
part,
ozone
benefits
contribute
substantially
less
to
the
monetized
benefits
than
do
benefits
from
PM,
thus
their
omission
will
not
materially
affect
the
conclusions
of
the
benefits
analysis.
Although
we
expect
economic
benefits
to
exist,
we
were
unable
to
quantify
or
to
value
specific
changes
in
ozone,
CO
or
air
toxics
because
we
did
not
perform
additional
air
quality
modeling.

There
are
also
a
number
of
health
and
environmental
effects
which
we
were
unable
to
quantify
or
monetize.
A
full
appreciation
of
the
overall
economic
consequences
of
the
proposed
rule
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
complete
listing
of
the
benefit
categories
that
could
not
be
quantified
or
monetized
in
our
estimate
are
provided
in
Table
VI.
E­
6.
These
effects
are
denoted
by
"
B"
in
Table
VI.
E­
3
above,
and
are
additive
to
the
estimates
of
benefits.
422
Table
VI.
E­
6.
 
Additional,
Non­
monetized
Benefits
of
the
Nonroad
Diesel
Engine
and
Fuel
Standards
Pollutant
Unquantified
Effects
Ozone
Health
Premature
mortalitya
Respiratory
hospital
admissions
Minor
restricted
activity
days
Increased
airway
responsiveness
to
stimuli
Inflammation
in
the
lung
Chronic
respiratory
damage
Premature
aging
of
the
lungs
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
Decreased
yields
for
fruits
and
vegetables
Decreased
yields
for
non­
commercial
crops
Damage
to
urban
ornamental
plants
Impacts
on
recreational
demand
from
damaged
forest
aesthetics
Damage
to
ecosystem
functions
PM
Health
Low
birth
weight
Changes
in
pulmonary
function
Chronic
respiratory
diseases
other
than
chronic
bronchitis
Morphological
changes
Altered
host
defense
mechanisms
Cancer
Non­
asthma
respiratory
emergency
room
visits
PM
Welfare
Visibility
in
many
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
Impacts
of
nitrogen
deposition
on
recreation
in
estuarine
ecosystems
Damage
to
ecosystem
functions
CO
Health
Premature
mortalitya
Pollutant
Unquantified
Effects
243
This
analysis
is
based
on
an
earlier
version
of
the
engineering
costs
developed
for
this
rule.

The
final
cost
estimates
for
the
engine
program
are
slightly
higher
($
142
million)
and
the
final
fuel
costs
are
slightly
lower
($
246
million),
resulting
in
a
30­
year
net
present
value
of
$
27.1
billion
(
30
year
net
present
values
in
the
year
2004,
using
a
3
percent
discount
rate,
$
2002)
or
$
104
million
less
than
the
engineering
costs
used
in
this
analysis.
We
do
not
expect
that
the
revised
engineering
costs
would
change
the
overall
results
of
this
economic
impact
analysis
given
the
small
portion
of
engine,
equipment,
and
fuel
costs
to
total
production
costs
for
goods
and
services
using
these
inputs
and
given
the
inelastic
value
of
the
estimated
demand
elasticities
for
the
application
markets.

423
HC
Healthb
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)

HC
Welfare
Direct
toxic
effects
to
animals
Bioaccumulation
in
the
food
chain
Damage
to
ecosystem
function
Odor
Notes:
a
Premature
mortality
associated
with
ozone
and
carbon
monoxide
is
not
separately
included
in
this
analysis.
In
this
analysis,
we
assume
that
the
Pope,
et
al.
C­
R
function
for
premature
mortality
captures
both
PM
mortality
benefits
and
any
mortality
benefits
associated
with
other
air
pollutants.
b
Many
of
the
key
hydrocarbons
related
to
this
rule
are
also
hazardous
air
pollutants
listed
in
the
Clean
Air
Act.

F.
Economic
Impact
Analysis
We
prepared
a
draft
Economic
Impact
Analysis
(
EIA)
for
this
rule
to
estimate
the
economic
impacts
of
the
proposed
control
program
on
producers
and
consumers
of
nonroad
engines,
equipment,
fuel,
and
related
industries.
243
We
received
comments
on
our
draft
analysis
from
stakeholders
representing
agricultural
interests,
equipment
rental
and
dealer
interests,
and
equipment
manufacturers.
The
commenters
conveyed
their
concerns
about
our
general
analytic
244
EPA
Guidelines
for
Preparing
Economic
Analyses,
EPA
240­
R­
00­
003,
September
2000,
p
113.

424
approach
and
some
of
the
model
assumptions.
As
explained
in
our
responses
to
these
comments,
which
can
be
found
in
the
Summary
and
Analysis
of
Comments
document
prepared
for
this
final
rule,
we
do
not
believe
these
comments
require
us
to
adjust
our
EIA
methodology.
We
did
adjust
the
methodology,
however,
to
estimate
the
economic
impacts
of
the
fuel
sulfur
content
requirements
on
the
locomotive
and
marine
sectors.
As
explained
below,
this
revision
was
necessary
to
correct
an
oversight
in
the
draft
EIA.
We
also
revised
the
price
and
quantity
data
inputs
to
the
model
to
make
them
consistent
with
the
revised
engine
and
fuel
cost
analyses
described
earlier
in
this
section.

This
section
briefly
describes
the
methodology
we
used
to
estimate
the
economic
impacts
of
this
final
rule,
including
the
model
revisions
for
the
marine
and
locomotive
fuel
sectors,
and
the
results
of
that
analysis.
A
detailed
description
of
the
Nonroad
Diesel
Economic
Impact
Model
(
NDEIM)
prepared
for
this
analysis,
the
model
inputs,
and
several
sensitivity
analyses
can
be
found
in
Chapter
10
of
Final
Regulatory
Impact
Analysis
prepared
for
this
rule.

1.
What
is
an
Economic
Impact
Analysis?

An
Economic
Impact
Analysis
is
prepared
to
inform
decision
makers
within
the
Agency
about
the
potential
economic
consequences
of
a
regulatory
action.
The
analysis
contains
estimates
of
the
social
costs
of
a
regulatory
program
and
explores
the
distribution
of
these
costs
across
stakeholders.
These
estimated
social
costs
can
then
be
compared
with
estimated
social
benefits
(
as
presented
in
Section
VI.
E).
As
defined
in
EPA's
Guidelines
for
Preparing
Economic
Analyses,
social
costs
are
the
value
of
the
goods
and
services
lost
by
society
resulting
from
a)
the
use
of
resources
to
comply
with
and
implement
a
regulation
and
b)
reductions
in
output.
244
In
this
analysis,
social
costs
are
explored
in
two
steps.
In
the
first
step,
called
the
market
analysis,
we
estimate
how
prices
and
quantities
of
good
directly
and
indirectly
affected
by
the
emission
control
program
can
be
expected
to
change
once
the
emission
control
program
goes
into
effect.
The
estimated
price
and
quantity
changes
for
engines,
equipment,
fuel,
and
goods
produced
using
these
inputs
are
examined
separately.
In
the
second
step,
called
the
economic
welfare
analysis,
we
look
at
the
total
social
costs
associated
with
the
program
and
their
distribution
across
stakeholders.
The
analysis
is
based
on
compliance
cost
estimates
and
baseline
market
conditions
for
prices
and
quantities
of
engines,
equipment,
and
fuel
produced
presented
earlier
in
this
section.

In
this
EIA,
we
look
at
price
and
quantity
impacts
for
engine,
equipment,
diesel
fuel,
and
goods
produced
with
these
inputs.
With
regard
to
the
goods
produced
with
these
inputs,
we
distinguish
between
three
application
markets:
agriculture,
construction,
and
manufacturing.
It
should
be
noted
from
the
outset
that
diesel
engines,
equipment,
and
fuel
represent
only
a
small
portion
of
the
total
production
costs
for
each
of
the
three
application
market
sectors
(
the
final
users
of
the
engines,
equipment
and
fuel
affected
by
this
rule).
Other
more
significant
production
costs
include
land,
labor,
other
capital,
raw
materials,
insurance,
profits,
etc.
These
other
425
production
costs
are
not
affected
by
this
emission
control
program.
This
is
important
because
it
means
that
this
rule
directly
affects
only
a
small
part
of
total
inputs
for
the
relevant
markets.
Therefore,
the
rule
is
not
expected
to
have
a
large
adverse
impact
on
output
and
prices
of
goods
produced
in
the
three
application
sectors.

It
should
also
be
noted
that
our
analysis
of
the
impacts
on
the
three
application
markets
is
limited
to
market
output.
The
economic
impacts
on
particular
groups
of
application
market
suppliers
(
e.
g.,
the
profitability
of
farm
production
units
or
manufacturing
or
construction
firms)
or
particular
groups
of
consumers
(
e.
g.,
households
and
companies
that
consume
agricultural
goods,
buildings,
or
durable
or
consumer
goods)
are
not
estimated.
In
other
words,
while
we
estimate
that
the
application
markets
will
bear
most
of
the
burden
of
the
regulatory
program
and
we
apportion
the
decrease
in
application
market
surplus
between
application
market
producers
and
application
market
consumers,
we
do
not
estimate
how
those
social
costs
will
be
shared
among
specific
application
market
producers
and
consumers
(
e.
g.,
farmers
and
households).
In
some
cases,
application
market
producers
may
be
able
to
pass
most
if
not
all
of
their
increased
costs
to
the
ultimate
consumers
of
their
products;
in
other
cases,
they
may
be
obliged
to
absorb
a
portion
of
these
costs.
While
some
commenters
requested
that
we
perform
a
sector­
by­
sector
analysis
of
application
market
producers
and
consumers,
we
do
not
believe
this
is
appropriate.
The
focus
on
market­
level
impacts
in
this
analysis
is
appropriate
because
the
standards
in
this
emission
control
program
are
technical
standards
that
apply
to
nonroad
engines,
equipment,
and
fuel
regardless
of
how
they
are
used
and
the
structure
of
the
program
does
not
suggest
that
different
sectors
will
be
affected
differently
by
the
requirements.
In
addition,
the
results
of
our
EIA
suggest
that
the
overall
burden
on
the
application
market
is
expected
to
be
small:
approximately
0.1
percent
increase
in
prices,
on
average,
and
less
than
0.02
percent
decrease
in
production,
on
average.
Estimated
economic
impacts
of
this
size
do
not
warrant
performing
a
sector­
by­
sector
analysis
to
investigate
whether
some
subsectors
may
be
affected
disproportionately.

Finally,
as
a
market­
level
model,
the
NDEIM
estimates
the
economic
impacts
of
the
rule
on
the
engine,
equipment,
and
application
markets
and
the
transportation
service
sector.
It
is
not
a
firm­
level
analysis
and
therefore
the
equipment
demand
elasticity
facing
any
particular
manufacturer
may
be
greater
than
the
demand
elasticity
of
the
market
as
a
whole.
This
difference
can
be
important,
particularly
where
the
rule
affects
different
firms'
costs
over
different
volumes
of
production.
However,
to
the
extent
there
are
differential
effects,
EPA
believes
that
the
wide
array
of
flexibilities
provided
in
this
rule
are
adequate
to
address
any
cost
inequities
that
are
likely
to
arise.

2.
What
methodology
did
EPA
use
in
this
Economic
Impact
Analysis?

EPA
used
the
same
methodology
in
this
final
EIA
as
was
used
in
the
draft
EIA.
The
model
was
revised
to
accommodate
analysis
of
the
locomotive
and
marine
fuel
sectors.
426
a.
Conceptual
Approach
The
Nonroad
Diesel
Economic
Impact
Model
(
NDEIM)
uses
a
multi­
market
analysis
framework
that
considers
interactions
between
regulated
markets
and
other
markets
to
estimate
how
compliance
costs
can
be
expected
to
ripple
through
these
markets.
In
the
NDEIM,
compliance
costs
are
directly
borne
by
engine
manufacturers,
equipment
manufacturers,
petroleum
refiners
and
fuel
distributors.
Depending
on
market
characteristics,
some
or
all
of
these
compliance
costs
will
be
passed
on
through
the
supply
chain
in
the
form
of
higher
input
prices
for
the
application
markets
(
in
this
case,
construction,
agriculture,
and
manufacturing)
which
in
turn
affect
prices
and
quantities
of
goods
produced
in
those
application
markets.
Producers
in
the
application
markets
adjust
their
demand
for
diesel
engines,
equipment,
and
fuel
in
response
to
these
input
price
changes
and
consumer
demand
for
application
market
outputs.
This
information
is
passed
back
to
the
suppliers
of
diesel
equipment,
engines,
and
fuel
in
the
form
of
purchasing
decisions.
The
NDEIM
explicitly
models
these
interactions
and
estimates
behavioral
responses
that
lead
to
new
equilibrium
prices
and
output
for
all
sectors
and
the
resulting
distribution
of
social
costs
across
the
modeled
sectors.

b.
Markets
Examined
The
NDEIM
uses
a
multi­
market
partial
equilibrium
approach
to
track
changes
in
price
and
quantity
for
62
integrated
product
markets,
as
follows:

7
diesel
engine
markets:
less
than
25
hp,
26
to
50
hp,
51
to
75
hp,
76
to
100
hp,
101
to
175
hp,
176
to
600
hp,
and
greater
than
600
hp.
The
EIA
includes
more
horsepower
categories
than
the
standards
to
allow
more
efficient
use
of
the
engine
compliance
costs
estimates.
The
additional
categories
also
allow
estimating
economic
impacts
for
a
more
diverse
set
of
markets.

42
diesel
equipment
markets:
7
horsepower
categories
within
7
application
categories:
agricultural,
construction,
general
industrial,
pumps
and
compressors,
generator
and
welder
sets,
refrigeration
and
air
conditioning,
and
lawn
and
garden.
There
are
7
horsepower/
application
categories
that
did
not
have
sales
in
2000
and
are
not
included
in
the
model,
so
the
total
number
of
diesel
equipment
markets
is
42
rather
than
49.

3
application
markets:
agricultural,
construction,
and
manufacturing.

8
nonroad
diesel
fuel
markets:
2
sulfur
content
levels
(
15
ppm
and
500
ppm)
for
each
of
4
PADDs.
PADDs
1
and
3
are
combined
for
the
purpose
of
this
analysis.
It
should
be
noted
that
PADD
5
includes
Alaska
and
Hawaii.
Also,
California
fuel
volumes
that
are
not
affected
by
the
program
(
because
they
are
covered
by
separate
California
nonroad
diesel
fuel
standards)
are
not
included
in
the
analysis.

2
transportation
service
markets:
locomotive
and
marine.

As
noted
above,
this
final
EIA
also
estimates
the
economic
impact
on
two
additional
markets
that
were
not
included
in
the
draft
analysis:
the
locomotive
and
marine
diesel
245
U.
S.
Environmental
Protection
Agency,
Office
of
Air
Quality
Planning
and
Standards,

Innovative
Strategies
and
Economics
Group,
OAQPS
Economic
Analysis
Resource
Document,
April
1999.
A
copy
of
this
document
can
be
found
in
Docket
A­
2001­
28,
Document
No.
II­
A­
14.

427
transportation
service
markets.
In
the
NPRM,
we
proposed
to
set
fuel
sulfur
standards
for
locomotive
and
distillate
marine
diesel
as
well
as
for
nonroad
diesel
fuel.
We
developed
cost
estimates
for
these
two
types
of
fuel
as
well
as
for
nonroad
diesel
fuel.
In
the
draft
EIA,
however,
we
did
not
consider
the
economic
impacts
of
these
fuel
costs
on
the
locomotive
and
marine
sectors
separately.
Instead,
we
applied
all
of
these
additional
fuel
costs
to
the
manufacturing
application
market.

In
preparing
the
final
RIA
for
this
rule,
we
determined
that
it
would
be
more
appropriate
to
consider
the
impacts
of
the
fuel
program
on
the
diesel
marine
and
locomotive
sectors
separately.
This
is
because
the
locomotive
and
marine
markets
are
directly
affected
by
the
higher
diesel
fuel
prices
associated
with
the
rule.
In
addition,
production
and
consumption
decisions
of
downstream
end­
use
markets
that
use
these
services
are
influenced
by
the
prices
of
transportation
services.
At
the
same
time,
locomotive
and
marine
diesel
transportation
services
are
not
used
solely
in
the
three
application
markets
modeled
in
the
NDEIM.
These
services
are
also
provided
to
electric
utilities
(
transporting
coal
to
electric
power
plants),
non­
manufacturing
service
industries
(
public
transportation)
and
governments.
We
take
this
into
account
and
report
impacts
on
those
sectors
separately.

c.
Model
Methodology
A
detailed
description
of
the
model
methodology,
inputs,
and
parameters
used
in
this
economic
impact
analysis
is
provided
in
Chapter
10
of
the
Final
RIA
prepared
for
this
rule.
The
model
methodology
is
firmly
rooted
in
applied
microeconomic
theory
and
was
developed
following
the
OAQPS
Economic
Analysis
Resource
Document.
245
The
NDEIM
is
a
computer
model
comprised
of
a
series
of
spreadsheet
modules
that
define
the
baseline
characteristics
of
the
supply
and
demand
for
the
relevant
markets
and
the
relationships
between
them.
The
model
is
constructed
based
on
the
market
characteristics
and
inter­
connections
summarized
in
this
section
and
described
in
more
detail
in
Chapter
10
of
the
RIA.
The
model
is
shocked
by
applying
the
engineering
compliance
cost
estimates
to
the
appropriate
market
suppliers,
and
then
numerically
solved
using
an
iterative
auctioneer
approach
by
"
calling
out"
new
prices
until
a
new
equilibrium
is
reached
in
all
markets
simultaneously.
The
output
of
the
model
is
new
equilibrium
prices
and
quantities
for
all
affected
markets.
This
information
is
used
to
estimate
the
social
costs
of
the
model
and
how
those
costs
are
shared
among
affected
markets.

The
NDEIM
uses
a
multi­
market
partial
equilibrium
approach
to
track
changes
in
price
and
quantity
for
the
modeled
product
markets.
As
explained
in
the
EPA
Guidelines
for
Preparing
Economic
Analyses,
`
partial'
equilibrium
refers
to
the
fact
that
the
supply
and
demand
functions
246
EPA
Guidelines
for
Preparing
Economic
Analyses,
EPA
240­
R­
00­
003,
September
2000,
p.

125­
6.

247
See,
for
example,
EPA
Guidelines
for
Preparing
Economic
Analyses,
EPA
240­
R­
00­
003,

September
2000,
p
126.
See
also
the
Final
RIA
for
this
rule,
Chapter
10,
Section
10.2.3.1.

428
are
modeled
for
just
one
or
a
few
isolated
markets
and
that
conditions
in
other
markets
are
assumed
either
to
be
unaffected
by
a
policy
or
unimportant
for
social
cost
estimation.
Multimarket
models
go
beyond
partial
equilibrium
analysis
by
extending
the
inquiry
to
more
than
just
a
single
market.
Multi­
market
analysis
attempts
to
capture
at
least
some
of
the
interactions
between
markets.
246
The
NDEIM
uses
an
intermediate
run
time
frame.
The
use
of
the
intermediate
run
means
that
some
factors
of
production
are
fixed
and
some
are
variable.
This
modeling
period
allows
analysis
of
the
economic
effects
of
the
rule's
compliance
costs
on
current
producers.
The
short
run,
in
contrast,
imposes
all
compliance
costs
on
the
manufacturers
(
no
pass­
through
to
consumers),
while
the
long
run
imposes
all
costs
on
consumers
(
full
cost
pass­
through
to
consumers).
The
use
of
the
intermediate
run
time
frame
is
consistent
with
economic
practices
for
this
type
of
analysis.

The
NDEIM
assumes
perfect
competition
in
the
market
sectors.
This
assumption
was
questioned
by
one
commenter,
who
noted
that
the
25
to
75
hp
engine
category
does
not
appear
to
be
competitive
based
on
the
number
of
firms
in
that
subsector.
Specifically,
one
firm
has
nearly
29
percent
of
the
market
and
the
top
nine
firms
have
about
88
percent.
The
remaining
twelve
percent
of
this
market
shared
among
nineteen
other
firms.
While
the
commenter
is
correct
in
noting
the
limited
number
of
firms
in
this
subsector,
we
believe
it
is
still
appropriate
to
rely
on
the
perfect
competition
assumption
in
this
analysis.
The
perfect
competition
assumption
relies
not
only
on
the
number
of
firms
in
a
market
but
also
on
other
market
characteristics.
For
example,
there
are
no
indications
of
barriers
to
entry,
the
firms
in
these
markets
are
not
price
setters,
and
there
is
no
evidence
of
high
levels
of
strategic
behavior
in
the
price
and
quantity
decisions
of
the
firms.
In
addition,
the
products
produced
within
each
market
are
somewhat
homogeneous
in
that
engines
from
one
firm
can
be
purchased
instead
of
engines
from
another
firm.
Finally,
according
to
contestable
market
theory,
oligopolies
and
even
monopolies
will
behave
very
much
like
firms
in
a
competitive
market
if
it
is
possible
to
enter
particular
markets
costlessly
(
i.
e.,
there
are
no
sunk
costs
associated
with
market
entry
or
exit).
With
regard
to
the
nonroad
engine
market,
production
capacity
is
not
fully
utilized.
This
means
that
manufacturers
could
potentially
switch
their
product
line
to
compete
in
another
segment
of
the
market
without
a
significant
investment.
For
all
these
reasons,
the
number
of
firms
in
a
particular
engine
submarket
does
not
prevent
us
from
relying
on
the
perfect
competition
assumption
for
that
submarket.
This
is
true
of
other
engine
and
equipment
subsectors
as
well.
In
addition,
changing
the
assumption
of
perfect
competition
based
on
the
limited
evidence
raised
by
the
commenter
would
break
with
widely
accepted
economic
practice
for
this
type
of
analysis.
247
248
If
the
elasticity
of
demand
for
a
final
product
is
less
than
the
elasticity
of
substitution
between
an
input
and
other
inputs
to
the
final
product,
then
the
demand
for
the
input
is
less
elastic
the
smaller
its
cost
share.
Hicks,
J.
R.,
1961.
Marshall's
Third
Rule:
A
Further
Comment.
Oxford
Economic
Papers
13:
262­
65;
Hicks,
J.
R.,
1963.
The
Theory
of
Wages.
St.
Martins
Press,
NY,
pp.
233­
247.
See
Docket
A­

2001­
28,
Document
No.
IV­
B­
25
for
relevant
excerpts.
See
Docket
A­
2001­
28,
Document
No.
IV­
B­
25
for
relevant
excerpts.

429
d.
Model
Inputs
­
Elasticities
The
estimated
social
costs
of
this
emission
control
program
are
a
function
of
the
ways
in
which
producers
and
consumers
of
the
engines,
equipment,
and
fuels
affected
by
the
standards
change
their
behavior
in
response
to
the
costs
incurred
in
complying
with
the
standards.
As
the
compliance
costs
ripple
through
the
markets,
producers
and
consumers
change
their
production
and
purchasing
decisions
in
response
to
changes
in
prices.
In
the
NDEIM,
these
behavioral
changes
are
modeled
by
the
demand
and
supply
elasticities
(
behavioral­
response
parameters),
which
measure
the
price
sensitivity
of
consumers
and
producers.

The
supply
elasticities
for
the
equipment,
engine,
diesel
fuel,
and
transportation
service
markets
and
the
demand
and
supply
elasticities
for
the
application
markets
used
in
the
NDEIM
were
obtained
from
peer­
reviewed
literature
sources
or
were
estimated
using
econometric
methods.
These
econometric
methods
are
well­
documented
and
are
consistent
with
generally
accepted
econometric
practice.
Appendix
10H
of
the
RIA
contains
detailed
information
on
how
the
elasticities
were
estimated.

The
equipment
and
engine
supply
elasticities
are
elastic,
meaning
that
quantities
supplied
are
expected
to
be
fairly
sensitive
to
price
changes.
The
supply
elasticities
for
the
fuel,
transportation,
and
application
markets
are
inelastic
or
unit
elastic,
meaning
that
the
quantity
supplied/
demanded
is
expected
to
be
fairly
insensitive
to
price
changes
or
will
vary
one­
to­
one
with
price
changes.
The
demand
elasticities
for
the
application
markets
are
also
inelastic.
This
is
consistent
with
the
Hicks­
Allen
derived
demand
relationship,
according
to
which
a
low
cost­
share
in
production
combined
with
limited
substitution
yields
inelastic
demand.
248
As
noted
above,
diesel
engines,
equipment,
and
fuel
represent
only
a
small
portion
of
the
total
production
costs
for
each
of
the
three
application
sectors.
The
limited
ability
to
substitute
for
these
inputs
is
discussed
below.

In
contrast
to
the
above,
the
demand
elasticities
for
the
engine,
equipment,
fuel,
and
transportation
markets
are
internally
derived
as
part
of
the
process
of
running
the
model.
This
is
an
important
feature
of
the
NDEIM,
which
allows
it
to
link
the
separate
market
components
of
the
model
and
simulate
how
compliance
costs
can
be
expected
to
ripple
through
the
affected
economic
sectors.
In
the
real
world,
for
example,
the
quantity
of
nonroad
equipment
units
produced
in
a
particular
period
depends
on
the
price
of
engines
(
the
engine
market)
and
the
demand
for
equipment
(
the
application
markets).
Similarly,
the
number
of
engines
produced
depends
on
the
430
demand
for
engines
(
the
equipment
market)
which
depends
on
the
demand
for
equipment
(
the
application
markets).
Changes
in
conditions
in
one
of
these
markets
will
affect
the
others.
By
designing
the
model
to
derive
the
engine,
equipment,
transportation
market,
and
fuel
demand
elasticities,
the
NDEIM
simulates
these
connections
between
supply
and
demand
among
all
the
product
markets
and
replicates
the
economic
interactions
between
producers
and
consumers.

e.
Model
Inputs
­
Fixed
and
Variable
Costs
The
EIA
treats
the
fixed
costs
expected
to
be
incurred
by
engine
and
equipment
manufacturers
differently
in
the
market
and
social
costs
analyses.
This
feature
of
the
model
is
described
in
greater
detail
in
Section
10.2.3.3
of
the
RIA.
In
the
market
analysis,
estimated
engine
and
equipment
market
impacts
(
changes
in
prices
and
quantities)
are
based
solely
on
the
expected
increase
in
variable
costs
associated
with
the
standards.
Fixed
costs
are
not
included
in
the
market
analysis
reported
in
Table
VI­
F­
1
because
in
an
analysis
of
competitive
markets
the
industry
supply
curve
is
based
on
its
marginal
cost
curve
and
fixed
costs
are
not
reflected
in
changes
in
the
marginal
cost
curve.
In
addition,
the
fixed
costs
associated
with
the
rule
are
primarily
R&
D
costs
for
design
and
engineering
changes.
Firms
in
the
affected
industries
currently
allocate
funds
for
R&
D
programs
and
this
rule
is
not
expected
to
lead
firms
to
change
the
size
of
their
R&
D
budgets.
Therefore,
changes
in
fixed
costs
for
engine
and
equipment
redesign
associated
with
this
rule
are
not
likely
to
affect
the
prices
of
engines
or
equipment.
Fixed
costs
are
included
in
the
social
cost
analysis
reported
in
Table
VI­
F­
2,
however,
as
an
additional
cost
to
producers.
This
is
appropriate
because
even
though
firms
currently
allocated
funds
to
R&
D
those
resources
are
intended
for
other
purposes
such
as
increasing
engine
power,
ease
of
use,
or
comfort.
These
improvements
will
therefore
be
postponed
for
the
length
of
the
rule­
related
R&
D
program.
This
is
a
cost
to
society.

One
commenter
recommended
that
EPA
include
engine
and
equipment
R&
D
(
fixed)
costs
in
the
market
analysis.
This
commenter
argued
that
while
in
the
long
run
total
costs
are
not
determined
by
changes
in
fixed
costs,
total
costs
are
determined
initially
by
both
fixed
and
variable
costs.
This
commenter
was
concerned
that
by
not
including
fixed
costs,
EPA's
analysis
underestimates
the
increase
in
the
average
price
of
goods
and
services
produced
using
engines
affected
by
the
rule.
In
fact,
we
included
R&
D
costs
in
a
sensitivity
analysis
performed
for
the
draft
EIA,
which
has
been
updated
and
can
be
found
in
Appendix
I
to
Chapter
10
of
the
Final
RIA.
Including
fixed
costs
results
in
a
transfer
of
economic
welfare
losses
from
engine
and
equipment
markets
to
the
application
markets
(
engine
and
equipment
producer
surplus
losses
decrease;
consumer
surplus
losses
increase),
but
does
not
change
the
overall
economic
welfare
losses
associated
with
the
rule.

Unlike
for
engines
and
equipment,
most
of
the
petroleum
refinery
fixed
costs
are
for
production
hardware.
Refiners
are
expected
to
have
to
make
physical
changes
to
their
refineries
and
purchase
additional
equipment
to
produce
500
ppm
and
then
15
ppm
fuel.
Therefore,
fixed
costs
are
included
in
the
market
analysis
for
fuel
price
and
quantity
impacts.
431
f.
Model
Inputs
­
Substitution
by
Application
Suppliers
In
modeling
the
market
impacts
and
social
costs
of
this
rule,
the
NDEIM
considers
only
diesel
equipment
and
fuel
inputs
to
the
production
of
goods
in
the
applications
markets.
It
does
not
explicitly
model
alternate
production
inputs
that
would
serve
as
substitutes
for
new
nonroad
equipment
or
nonroad
diesel
fuel.
In
the
model,
market
changes
in
the
final
demand
for
application
goods
and
services
directly
correspond
to
changes
in
the
demand
for
nonroad
equipment
and
fuel
(
i.
e.,
in
normalized
terms
there
is
a
one­
to­
one
correspondence
between
the
quantity
of
the
final
goods
produced
and
the
quantity
of
nonroad
diesel
equipment
and
fuel
used
as
inputs
to
that
production).
We
believe
modeling
the
market
in
this
manner
is
economically
sound
and
reflects
the
general
experience
for
the
nonroad
market.

Some
commenters
suggested
that
the
NDEIM
should
consider
substitution
to
alternate
means
of
production
such
as
pre­
buying,
delayed
buying,
extending
the
life
of
a
current
machine,
and
substituting
with
different
(
e.
g.,
gasoline­
powered)
equipment.
These
commenters
did
not
provide
detailed
explanations
for
their
comments
or
data
in
support
of
their
substitution
arguments.
After
considering
these
comments,
we
conclude
that
revising
the
NDEIM
to
include
these
effects
would
be
inappropriate.

The
term
"
pre­
buying"
appears
to
refer
to
the
possibility
that
the
suppliers
in
the
application
market
may
choose
to
buy
additional
unneeded
quantities
of
nonroad
equipment
prior
to
the
beginning
of
the
Tier
4
program,
thus
avoiding
the
higher
cost
for
the
Tier
4
equipment.
It
should
be
noted
that
this
effect
is
limited
to
equipment
and
does
not
extend
to
nonroad
diesel
fuel.
We
believe
that
equipment
pre­
buying
will
not
be
economically
viable
in
most
cases
due
to
the
cost
of
holding
capital
(
equipment)
idle
and
of
maintaining
unused
equipment.
Such
strategic
purchases,
if
they
occur
at
all,
would
be
limited
to
a
period
of
a
few
months
before
the
effective
date
of
the
standards.
The
NDEIM
models
market
reactions
in
the
intermediate
time
frame,
beyond
the
scope
of
any
potential
pre­
buy.
For
these
reasons,
we
do
not
believe
it
is
appropriate
to
revise
the
model
to
include
pre­
buy
as
a
means
of
substitution
in
NDEIM.

"
Delayed­
buying"
appears
to
refer
to
the
possibility
that
suppliers
in
the
application
market
would
defer
purchasing
new
equipment
initially
but
would
eventually
make
those
purchases.
Similarly
to
pre­
buying,
this
appears
to
be
a
short­
term
effect
and
would
therefore
be
inappropriate
to
include
in
an
economic
model
designed
to
model
the
intermediate
time
frame.

Extending
the
life
of
a
current
machine
is
suggested
as
another
alternative
to
purchasing
new
equipment.
We
believe
this
would
also
be
a
short
term
phenomena
that
is
not
relevant
for
the
intermediate
time
frame
of
the
NDEIM.
Based
on
our
meetings
with
equipment
users
and
suppliers,
we
do
not
believe
that
extending
the
life
of
nonroad
equipment
will
prove
to
be
an
economically
viable
substitute
in
the
near
or
long
term.
Most
users
of
nonroad
equipment
already
extend
the
life
of
their
equipment
to
the
maximum
extent
possible
and
purchase
new
equipment
only
when
the
existing
equipment
can
no
longer
perform
its
function,
when
new
demand
for
production
requires
additional
means
for
production,
or
when
new
equipment
offers
a
cheaper
432
means
of
production
than
existing
equipment.
This
situation
is
not
expected
to
change
as
a
result
of
this
rule.
In
addition,
even
if
it
were
possible
to
extend
equipment
life
even
more,
this
would
lower
the
cost
of
nonroad
equipment
as
an
input
to
production
(
because
it
would
be
less
expensive
to
maintain
old
equipment
than
purchase
new
equipment)
and
thus
would
reduce
the
economic
impact
of
the
Tier
4
program
compared
to
our
estimate.
For
all
of
the
reasons
stated
here,
we
have
decided
not
to
attempt
to
model
an
extended
equipment
life
alternative
in
the
NDEIM.

Finally,
some
commenters
noted
that
equipment
users
may
chose
to
substitute
with
different
equipment,
particularly
gasoline­
powered
equipment.
We
believe
substitution
to
gasoline­
powered
equipment
is
an
alternative
only
for
the
smaller
power
categories
(
below
75
hp).
Based
on
discussions
with
equipment
manufacturers
and
users,
the
dominant
reasons
for
choosing
diesel
engines
over
the
substantially
less
expensive
gasoline
engines
include
better
performance
from
diesel
engines,
lower
fuel
consumption
from
diesel
engines,
and
the
ability
to
use
diesel
fuel.
The
use
of
diesel
fuel
is
preferable
for
two
reasons:
it
is
safer
to
store
and
dispense,
and
it
is
compatible
with
the
fuel
needed
for
larger
equipment
at
the
same
worksite.
Where
these
issues
are
not
a
concern,
gasoline
engines
already
enjoy
a
substantial
economic
advantage
over
diesel.
We
do
not
believe
that
the
incremental
increase
in
new
equipment
cost
associated
with
this
program
would
provide
the
necessary
economic
incentives
for
switching
to
gasoline
equipment.
Equipment
users
who
can
use
gasoline­
fueled
equipment
already
do
so,
while
those
who
can't
due
to
the
high
costs
of
storing
and
dispensing
gasoline
fuel
already
use
diesel
engines.
Therefore,
we
have
not
attempted
to
model
the
possibility
of
substitution
to
gasoline
equipment
in
NDEIM.

g.
Model
Inputs
­
Other
Compliance
Costs.
The
NDEIM
uses
the
estimated
engine,
equipment,
and
fuel
compliance
costs
described
in
above
and
presented
in
Chapters
6
and
7
of
the
RIA.
Engine
and
equipment
costs
vary
over
time
because
fixed
costs
are
recovered
over
five
to
ten
year
periods
while
total
variable
costs,
despite
learning
effects
that
serve
to
reduce
costs
on
a
per
unit
basis,
continue
to
increase
at
a
rate
consistent
with
new
sales
increases.
Similarly,
engine
operating
costs
also
vary
over
time
because
oil
change
maintenance
savings,
PM
filter
maintenance,
and
fuel
economy
effects,
all
of
which
are
calculated
on
the
basis
of
gallons
of
fuel
consumed,
change
over
time
consistent
with
the
growth
in
nationwide
fuel
consumption.
Fuel­
related
compliance
costs
(
costs
for
refining
and
distributing
regulated
fuels)
also
change
over
time.
These
changes
are
more
subtle
than
the
engine
costs,
however,
as
the
fuel
provisions
are
largely
implemented
in
discrete
steps
instead
of
phasing
in
over
time.
Compliance
costs
were
developed
on
a
¢
/
gallon
basis;
total
compliance
costs
are
determined
by
multiplying
the
¢
/
gallon
costs
by
the
relevant
fuel
volumes.
Therefore,
total
fuel
costs
increase
as
the
demand
for
fuel
increases.
The
variable
operating
costs
are
based
on
the
natural
gas
cost
of
producing
hydrogen
and
for
heating
diesel
fuel
for
the
new
desulfurization
equipment,
and
thus
would
fluctuate
along
with
the
price
of
natural
gas.

Operating
Savings.
Operating
savings
refers
to
changes
in
operating
costs
that
are
expected
to
be
realized
by
users
of
both
existing
and
new
nonroad
diesel
equipment
as
a
result
of
the
reduced
sulfur
content
of
nonroad
diesel
fuel.
These
include
operating
savings
(
cost
433
reductions)
due
to
fewer
oil
changes,
which
accrue
to
nonroad,
marine
and
locomotive
engines
that
are
already
in
use
as
well
as
new
nonroad
engines
that
will
comply
with
the
standards
(
see
Section
VI.
B).
These
also
include
any
extra
operating
costs
associated
with
the
new
PM
emission
control
technology
which
may
accrue
to
certain
new
engines
that
use
this
technology.
Operating
savings
are
not
included
in
the
market
analysis
because
some
of
the
savings
accrue
to
existing
engines
and
because,
as
explained
in
Section
VI.
C.
1.
c,
these
savings
are
not
expected
to
affect
consumer
decisions
with
respect
to
new
engines.
Operating
savings
are
included
in
the
social
cost
analysis,
however,
because
they
accrue
to
society.
They
are
added
into
the
estimated
social
costs
as
an
additional
savings
to
the
application
and
transportation
service
markets,
since
it
is
the
users
of
these
engines
and
fuels
who
will
see
these
savings.
A
sensitivity
analysis
was
performed
as
part
of
this
EIA
that
includes
the
operating
savings
in
the
market
analysis.
The
results
of
this
sensitivity
analysis
are
presented
in
Appendix
10.
I.

Fuel
Marker
Costs.
Fuel
marker
costs
refers
to
costs
associated
with
marking
high
sulfur
heating
oil
to
distinguish
it
from
high
sulfur
diesel
fuel
produced
after
2007
through
the
use
of
early
sulfur
credits
or
small
refiner
provisions.
Only
heating
oil
sold
outside
of
the
Northeast
is
affected.
The
higher
sulfur
NRLM
fuel
is
not
allowed
to
be
sold
in
most
of
the
Northeast,
so
the
marker
need
not
be
added
in
this
large
heating
oil
market.
These
costs
are
expected
to
be
about
$
810,000
in
2007,
increasing
to
$
1.38
million
in
2008,
but
steadily
decreasing
thereafter
to
about
$
940,000
in
2040
(
see
Chapter
10
of
the
RIA).
Because
these
costs
are
relatively
small,
they
are
incorporated
into
the
estimated
compliance
costs
for
the
fuel
program
(
see
discussion
of
fuel
costs,
above).
They
are
therefore
not
counted
separately
in
this
economic
impact
analysis.
This
means
that
the
costs
of
marking
heating
fuel
are
allocated
to
all
users
of
the
fuel
affected
by
this
rule
(
nonroad,
locomotive,
and
marine)
instead
of
uniquely
to
heating
oil
users.
This
is
a
reasonable
approach
since
it
is
likely
that
refiners
will
pass
the
marker
costs
along
their
complete
nonroad
diesel
product
line
and
not
just
to
heating
oil.

Fuel
Spillover.
Spillover
fuel
is
highway
grade
diesel
fuel
consumed
by
nonroad
equipment,
stationary
diesel
engines,
boilers,
and
furnaces.
As
described
in
Section
7.1
of
Chapter
7
of
the
final
RIA,
refiners
are
expected
to
produce
more
15
ppm
fuel
than
is
required
for
the
highway
diesel
market.
This
excess
15
ppm
fuel
will
be
sold
into
markets
that
allow
fuel
with
a
higher
sulfur
level
(
i.
e.,
nonroad
for
a
limited
period
of
time,
locomotive,
marine
diesel
and
heating
oil).
This
spillover
fuel
is
affected
by
the
diesel
highway
rule
and
is
not
affected
by
this
regulation.
Therefore,
it
is
important
to
differentiate
between
spillover
and
nonspillover
fuel
to
ensure
that
the
compliance
costs
for
that
fuel
pool
are
not
counted
twice.
In
the
NDEIM,
this
is
done
by
incorporating
the
impact
of
increased
fuel
costs
associated
with
the
highway
rule
prior
to
analysis
of
the
final
nonroad
rule
(
see
RIA
Section
10.3.8).

Compliance
Flexibility
Provisions.
Consistent
with
the
engine
and
equipment
cost
discussion
in
Section
VI.
C,
the
EIA
does
not
include
any
cost
savings
associated
with
the
equipment
transition
flexibility
program
or
the
nonroad
engine
ABT
program.
As
a
result,
the
results
of
this
EIA
can
be
viewed
as
somewhat
conservative.
434
Locomotive
and
Marine
Fuel
Costs.
The
locomotive
and
marine
transportation
sectors
are
affected
by
this
rule
through
the
sulfur
limits
on
the
diesel
fuel
used
by
these
engines.
These
sectors
provide
transportation
to
the
three
application
markets
as
well
as
to
other
markets
not
considered
in
the
NDEIM
(
e.
g.,
public
utilities,
nonmanufacturing
service
industries,
government).
As
explained
in
Section
10.3.1.5
of
the
RIA,
the
NDEIM
applies
only
a
portion
of
the
locomotive
and
marine
fuel
costs
to
the
three
application
markets.
The
rest
of
the
locomotive
and
marine
fuel
costs
are
added
as
a
separate
item
to
the
total
social
cost
estimates
(
as
Application
Markets
Not
Included
in
NDEIM).

3.
What
Are
the
Results
of
this
Analysis?

Using
the
revised
cost
data
described
earlier
in
this
section
and
the
NDEIM
described
above
and
in
Chapter
10
of
the
Final
RIA,
we
estimated
the
economic
impacts
of
the
nonroad
engine,
equipment
and
fuel
control
program.
Economic
impact
results
for
2013,
2020,
2030,
and
2036
are
presented
in
this
section.
The
first
of
these
years,
2013,
corresponds
to
the
first
year
in
which
the
standards
affect
all
engines,
equipment,
and
fuels.
It
should
be
noted
that,
as
illustrated
in
Table
VI­
F­
3,
aggregate
program
costs
peak
in
2014;
increases
in
costs
after
that
year
are
due
to
increases
in
the
population
of
engines
over
time.
The
other
years,
2020,
2030
and
2036,
correspond
to
years
analyzed
in
our
benefits
analysis.
Detailed
results
for
all
years
are
included
in
the
appendices
to
Chapter
10
of
the
RIA.

In
the
following
discussion,
social
costs
are
computed
as
the
sum
of
market
surplus
offset
by
operating
savings.
Market
surplus
is
equal
to
the
aggregate
change
in
consumer
and
producer
surplus
based
on
the
estimated
market
impacts
associated
with
the
rule.
As
explained
above,
operating
savings
are
not
included
in
the
market
analysis
but
instead
are
listed
as
a
separate
category
in
the
social
cost
results
tables.

In
considering
the
results
of
this
analysis,
it
should
be
noted
that
the
estimated
output
quantities
for
diesel
engines,
equipment,
and
fuel
are
not
identical
to
those
estimated
in
the
engineering
cost
described
in
above
and
presented
in
Chapters
6
and
7
of
the
RIA.
The
difference
is
due
to
the
different
methodologies
used
to
estimate
these
costs.
As
noted
above,
social
costs
are
the
value
of
goods
and
services
lost
by
society
resulting
from
a)
the
use
of
resources
to
comply
with
and
implement
a
regulation
(
i.
e.,
compliance
costs)
and
b)
reductions
in
output.
Thus,
the
social
cost
analysis
considers
both
price
and
output
(
quantity)
effects
associated
with
consumer
and
producer
reaction
to
increased
prices
associated
with
the
regulatory
compliance
costs.
The
engineering
cost
analysis,
on
the
other
hand,
is
based
on
applying
additional
technology
to
comply
with
the
new
regulations.
The
engine
population
in
the
engineering
cost
analysis
does
not
reflect
consumer
and
producer
reactions
to
the
compliance
costs.
Consequently,
the
estimated
output
quantities
from
the
cost
analysis
are
slightly
larger
than
the
estimated
output
quantities
from
the
social
cost
analysis.

The
results
of
this
analysis
suggest
that
the
economic
impacts
of
this
rule
are
likely
to
be
small,
on
average.
Price
increases
in
the
application
markets
are
expected
to
average
about
0.1
249
The
NDEIM
distinguishes
between
"
merchant"
engines
and
"
captive"
engines.
"
Merchant"

engines
are
produced
for
sale
to
another
company
and
are
sold
on
the
open
market
to
anyone
who
wants
to
buy
them.
"
Captive"
engines
are
produced
by
a
manufacturer
for
use
in
its
own
nonroad
equipment
line
(
this
equipment
is
said
to
be
produced
by
"
integrated"
manufacturers).
The
market
analysis
for
engines
includes
compliance
costs
for
merchant
engines
only.
The
market
analysis
for
equipment
includes
equipment
compliance
costs
plus
a
portion
of
the
engine
compliance
costs
attributable
to
captive
engines.

435
percent
per
year.
Output
decrease
in
the
application
markets
are
expected
average
less
than
0.02
percent
for
all
years.
The
price
increases
for
engines,
equipment,
and
fuel
are
expected
to
be
about
20
percent,
3
percent,
and
7
percent,
respectively
(
total
impact
averaged
over
the
relevant
years).
The
number
of
engines
and
equipment
produced
is
expected
to
decrease
by
less
than
250
units,
and
the
amount
of
fuel
produced
annually
is
expected
to
decrease
by
less
than
4
million
gallons.
With
respect
to
the
economic
welfare
analysis,
producers
and
consumers
in
the
application
markets
are
expected
to
bear
about
83
percent
of
the
burden
in
2013;
this
will
increase
to
about
96
percent
in
2030
and
beyond.
In
other
words,
despite
the
almost
total
pass­
through
of
costs
the
average
price
of
goods
and
services
in
the
application
markets
is
expected
to
increase
by
only
0.1
percent.
This
outcome
reflects
the
fact
that
diesel
engines,
equipment,
and
fuel
are
only
a
small
part
of
total
costs
for
the
application
markets.
These
results
are
described
in
more
detail
below
and
in
Chapter
10
of
the
Final
RIA.

a.
Expected
Market
Impacts
The
estimated
market
impacts
for
2013,
2020,
and
2030
are
presented
in
Table
VI.
F­
1.
The
market­
level
impacts
presented
in
this
table
represent
production­
weighted
averages
of
the
individual
market­
level
impact
estimates
generated
by
the
model:
the
average
expected
price
increase
and
quantity
decrease
across
all
of
the
units
in
each
of
the
engine,
equipment,
fuel,
and
final
application
markets.
For
example,
the
model
includes
seven
individual
engine
markets
that
reflect
the
seven
different
horsepower
size
categories.
The
21.4
percent
price
change
for
engines
shown
in
Table
VI.
F­
1
for
2013
is
an
average
price
change
across
all
engine
markets
weighted
by
the
number
of
production
units.
Similarly,
the
equipment
impacts
presented
in
Table
VI.
F­
1
are
the
weighted
averages
of
42
equipment­
application
markets,
such
as
small
(<
25hp)
agricultural
equipment
and
large
(>
600hp)
industrial
equipment.
Note
that
price
increases
and
quantity
decreases
for
specific
types
of
engines,
equipment,
application
sectors,
or
diesel
fuel
markets
are
likely
to
be
different.
The
aggregated
data
presented
in
this
table
provide
a
broad
overview
of
the
expected
market
impacts
that
is
useful
when
considering
the
impacts
of
the
rule
on
the
economy
as
a
whole.
The
individual
market­
level
impacts
are
presented
in
Chapter
10
of
the
Final
RIA.
249
The
market
impacts
of
this
rule
suggest
that
the
overall
economic
impact
of
the
emission
control
program
on
society
is
expected
to
be
small,
on
average.
According
to
this
analysis,
the
average
prices
of
goods
and
services
produced
using
equipment
and
fuel
affected
by
the
rule
are
expected
to
increase
by
about
0.1
percent
(
as
noted
above),
despite
the
almost
total
pass­
through
of
compliance
costs
to
those
markets.
250
It
should
be
noted
that
the
equipment
prices
used
in
this
analysis
reflect
current
market
conditions.
An
increase
in
equipment
prices
associated
with
the
nonroad
Tier
3
standards
would
reduce
size
of
the
percentage
increase
in
price.
In
this
sense,
our
Economic
Impact
Analysis
is
conservative
as
it
is
based
on
the
impact
of
the
Tier
4
program
on
Tier
1
and
Tier
2
equipment
prices
and
therefore
overestimates
the
market
impacts
of
the
Tier
4
program.

436
Engine
Market
Results:
This
analysis
suggests
that
most
of
the
variable
costs
associated
with
the
rule
will
be
passed
along
in
the
form
of
higher
prices.
The
average
price
increase
in
2013
for
engines
is
estimated
to
be
about
21.4
percent.
This
percentage
is
expected
to
decrease
to
about
18.3
percent
by
2020.
In
2036,
the
last
year
considered,
the
average
price
increase
is
expected
to
be
about
18.2
percent.
This
expected
price
increase
varies
by
engine
size
because
compliance
costs
are
a
larger
share
of
total
production
costs
for
smaller
engines.
In
2013,
the
largest
expected
percent
price
increase
is
for
engines
between
25
and
50
hp:
29
percent
or
$
850;
the
average
price
for
an
engine
in
this
category
is
about
$
2,900.
However,
this
price
increase
is
expected
to
drop
to
22
percent,
or
about
$
645,
for
2015
and
later.
The
smallest
expected
percent
price
increase
in
2013
is
for
engines
in
the
greater
than
600
hp
category.
These
engines
are
expected
to
see
price
increases
of
about
3
percent
increase
in
2013,
increasing
to
about
7.6
percent
in
2015
and
then
decreasing
to
about
6.6
percent
in
2017
beyond.
The
expected
price
increase
for
these
engines
is
about
$
2,240
in
2013,
increasing
to
about
$
6,150
in
2015
and
then
decreasing
to
$
5,340
in
2017
and
later,
for
engines
that
cost
on
average
about
$
80,500.

The
market
impact
analysis
predicts
that
even
with
these
increased
in
engine
prices,
total
demand
is
not
expected
to
change
very
much.
The
expected
average
change
in
quantity
is
less
than
150
engines
per
year,
out
of
total
sales
of
more
than
500,000
engines.
The
estimated
change
in
market
quantity
is
small
because
as
compliance
costs
are
passed
along
the
supply
chain
they
become
a
smaller
share
of
total
production
costs.
In
other
words,
firms
that
use
these
engines
and
equipment
will
continue
to
purchase
them
even
at
the
higher
cost
because
the
increase
in
costs
will
not
have
a
large
impact
on
their
total
production
costs
(
diesel
equipment
is
only
one
factor
of
production
for
their
output
of
construction,
agricultural,
or
manufactured
goods).

Equipment
Market
Results:
Estimated
price
changes
for
the
equipment
markets
reflect
both
the
direct
costs
of
the
new
standards
on
equipment
production
and
the
indirect
cost
through
increased
engine
prices.
In
general,
the
estimated
percentage
price
changes
for
the
equipment
are
less
than
that
for
engines
because
the
engine
is
only
one
input
in
the
production
of
equipment.
In
2013,
the
average
price
increase
for
nonroad
diesel
equipment
is
estimated
to
be
about
2.9
percent.
250
This
percentage
is
expected
to
decrease
to
about
2.5
percent
for
2020
and
beyond.
The
range
of
estimated
price
increases
across
equipment
types
parallels
the
share
of
engine
costs
relative
to
total
equipment
price,
so
the
estimated
percentage
price
increase
among
equipment
types
also
varies.
For
example,
the
market
price
in
2013
for
agricultural
equipment
between
175
and
600
hp
is
estimated
to
increase
about
1.2
percent,
or
$
1,740
for
equipment
with
an
average
cost
of
$
143,700.
This
compares
with
an
estimated
engine
price
increase
of
about
$
1,700
for
engines
of
that
size.
The
largest
expected
price
increase
in
2013
for
equipment
is
$
2,290,
or
2.6
437
percent,
for
pumps
and
compressors
over
600
hp.
This
compares
with
an
estimated
engine
price
increase
of
about
$
2,240
for
engines
of
that
size.
The
smallest
expected
price
increase
in
2013
for
equipment
is
$
120,
or
0.7
percent,
for
construction
equipment
less
than
25
hp.
This
compares
with
an
estimated
engine
price
increase
of
about
$
120
for
engines
of
that
size.

Again,
the
market
analysis
predicts
that
even
with
these
increased
equipment
prices
total
demand
is
not
expected
to
change
very
much.
The
expected
average
change
in
quantity
is
less
than
250
pieces
of
equipment
per
year,
out
of
a
total
sales
of
more
than
500,000
units.
The
average
decrease
in
the
quantity
of
nonroad
diesel
equipment
produced
as
a
result
of
the
regulation
is
estimated
to
be
about
0.02
percent
for
all
years.
The
largest
expected
decrease
in
quantity
in
2013
is
18
units
of
construction
equipment
per
year
for
construction
equipment
between
100
and
175
hp,
out
of
about
63,000
units.
The
smallest
expected
decrease
in
quantity
in
2013
is
less
than
one
unit
per
year
in
all
hp
categories
of
pumps
and
compressors.

It
should
be
noted
that
the
absolute
change
in
the
number
of
engines
and
equipment
does
not
match.
This
is
because
the
absolute
change
in
the
quantity
of
engines
represents
only
engines
sold
on
the
market.
Reductions
in
engines
consumed
internally
by
integrated
engine/
equipment
manufacturers
are
not
reflected
in
this
number
but
are
captured
in
the
cost
analysis.
438
Table
VI.
F­
1.
 
Summary
of
Market
Impacts
($
2002)

Market
Engineering
Cost
Change
in
Price
Change
in
Quantity
Per
Unit
Absolute
($
million)
Percent
Absolute
Percent
2013
Engines
$
1,052
$
821
21.4
 
79a
 
0.014
Equipment
$
1,198
$
975
2.9
 
139
 
0.017
Loco/
Marine
Transpb
0.009
 
0.007
Application
Marketsb
0.097
 
0.015
No.
2
Distillate
Nonroad
$
0.06
$
0.07
6.0
 
2.75c
 
0.019
2020
Engines
$
950
$
761
18.3
 
98a
 
0.016
Equipment
$
1,107
$
976
2.5
 
172
 
0.018
Loco/
Marine
Transpb
0.01
 
0.008
Application
Marketsb
0.105
 
0.017
No.
2
Distillate
Nonroad
$
0.07
$
0.07
7.0
 
3.00c
 
0.021
2030
Engines
$
937
$
751
18.2
 
114a
 
0.016
Equipment
$
968
$
963
2.5
 
200
 
0.018
Loco/
Marine
Transpb
0.010
 
0.008
Application
Marketsb
0.102
 
0.016
No.
2
Distillate
Nonroad
$
0.07
$
0.07
7.0
 
3.53c
 
0.022
2036
Engines
$
931
$
746
18.2
 
124a
 
0.016
Equipment
$
962
$
956
2.5
 
216
 
0.018
Loco/
Marine
Transpb
0.010
 
0.008
Application
Marketsb
0.101
 
0.016
Market
Engineering
Cost
Change
in
Price
Change
in
Quantity
Per
Unit
Absolute
($
million)
Percent
Absolute
Percent
439
No.
2
Distillate
Nonroad
$
0.07
$
0.07
7.0
 
3.85c
 
0.022
Notes:
a
The
absolute
change
in
the
quantity
of
engines
represents
only
engines
sold
on
the
market.
Reductions
in
engines
consumed
internally
by
integrated
engine/
equipment
manufacturers
are
not
reflected
in
this
number
but
are
captured
in
the
cost
analysis.
For
this
reason,
the
absolute
change
in
the
number
of
engines
and
equipment
does
not
match.
b
The
model
uses
normalized
commodities
in
the
application
markets
because
of
the
great
heterogeneity
of
products.
Thus,
only
percentage
changes
are
presented.
c
Units
are
in
million
of
gallons.

Transportation
Market
Results:
The
estimated
price
increase
associated
with
the
proposed
standards
in
the
locomotive
and
marine
transportation
markets
is
negligible,
at
0.01
percent
for
all
years.
This
means
that
these
transportation
service
providers
are
expected
to
pass
along
nearly
all
of
their
increased
costs
to
the
agriculture,
construction,
and
manufacturing
application
markets,
as
well
as
other
application
markets
not
explicitly
modeled
in
the
NDEIM.
This
price
increases
represent
a
small
share
of
total
application
market
production
costs,
and
therefore
are
not
expected
to
affect
demand
for
these
services.

Application
Market
Results:
The
estimated
price
increase
associated
with
the
new
standards
in
all
three
application
markets
is
very
small
and
averages
about
0.1
percent
for
all
years.
In
other
words,
on
average,
the
prices
of
goods
and
services
produced
using
the
affected
engines,
equipment,
and
fuel
are
expected
to
increase
negligibly.
This
results
from
the
observation
that
compliance
costs
passed
on
through
price
increases
represent
a
very
small
share
of
total
production
costs
in
all
the
application
markets.
For
example,
the
construction
industry
realizes
an
increase
in
production
costs
of
approximately
$
580
million
in
2013
because
of
the
price
increases
for
diesel
equipment
and
fuel.
However,
this
represents
less
than
0.001
percent
of
the
$
820
billion
value
of
shipments
in
the
construction
industry
in
2000.
The
estimated
average
commodity
price
increase
in
2013
ranges
from
0.08
percent
in
the
manufacturing
application
market
to
about
0.5
percent
in
the
construction
market.
The
percentage
change
in
output
is
also
estimated
to
be
very
small
and
averages
less
than
0.02
percent
for
all
years.
Note
that
these
estimated
price
increases
and
quantity
decreases
are
average
for
these
sectors
and
may
vary
for
specific
subsectors.
Also,
note
that
absolute
changes
in
price
and
quantity
are
not
provided
for
the
application
markets
in
Table
VI.
F­
1
because
normalized
commodity
values
are
used
in
the
market
model.
Because
of
the
great
heterogeneity
of
manufactured
or
agriculture
products,
a
normalized
commodity
($
1
unit)
is
used
in
the
application
markets.
This
has
no
impact
on
the
estimated
percentage
change
impacts
but
makes
interpretation
of
the
absolute
changes
less
informative.

Fuel
Markets
Results:
The
estimated
average
price
increase
across
all
nonroad
diesel
fuel
is
about
7
percent
for
all
years.
For
15
ppm
fuel,
the
estimated
price
increase
for
2013
ranges
from
5.6
percent
in
the
East
Coast
region
(
PADD
1&
3)
to
9.1
percent
in
the
mountain
region
(
PADD
440
4).
The
average
national
output
decrease
for
all
fuel
is
estimated
to
be
about
0.02
percent
for
all
years,
and
is
relatively
constant
across
all
four
regional
fuel
markets.

b.
Expected
Economic
Welfare
Impacts
Estimated
social
costs
are
presented
in
Table
VI.
F­
2.
In
2013,
the
total
social
costs
are
projected
to
be
about
$
1,510
million
($
2002).
About
83
percent
of
the
total
social
costs
is
expected
to
be
borne
by
producers
and
consumers
in
the
application
markets
in
2013,
indicating
that
the
majority
of
the
compliance
costs
associated
with
the
rule
are
expected
to
be
passed
on
in
the
form
of
higher
prices.
When
these
estimated
impacts
are
broken
down,
about
58.5
percent
of
the
social
costs
are
expected
to
be
borne
by
consumers
in
the
application
markets
and
about
41.5
percent
are
expected
to
be
borne
by
producers
in
the
application
markets.
Equipment
manufacturers
are
expected
to
bear
about
9.5
percent
of
the
total
social
costs.
Engine
manufacturers
and
diesel
fuel
refineries
are
expected
to
bear
2.8
percent
and
0.5
percent,
respectively.
The
remaining
4.2
percent
of
the
social
costs
is
expected
to
be
borne
by
the
locomotive
and
marine
transportation
service
sector.
In
this
last
sector,
about
97
percent
of
the
gross
decrease
in
market
surplus
is
expected
to
be
borne
by
the
application
markets
that
are
not
included
in
the
NDEIM
but
that
use
these
services
(
e.
g.,
public
utilities,
nonmanufacturing
service
industries,
government)
while
about
3
percent
is
expected
to
be
borne
by
locomotive
and
marine
service
providers.
Because
of
the
way
the
NDEIM
is
structured,
with
the
fuel
savings
added
separately,
the
results
imply
that
locomotive
and
marine
service
provides
would
see
net
benefits
from
the
rule
due
to
the
operating
savings
associated
with
low
sulfur
fuel.
In
fact,
they
are
likely
to
pass
along
some
or
all
of
those
operating
savings
to
the
users
of
their
services,
reducing
the
size
of
the
welfare
losses
for
those
users.

Total
social
costs
continue
to
increase
over
time
and
are
projected
to
be
about
$
2,046
million
by
2030
and
$
2,227
million
in
2036
($
2002).
The
increase
is
due
to
the
projected
annual
growth
in
the
engine
and
equipment
populations.
Producers
and
consumers
in
the
application
markets
are
expected
to
bear
an
even
larger
portion
of
the
costs,
approximately
96
percent.
This
is
consistent
with
economic
theory,
which
states
that,
in
the
long
run,
all
costs
are
passed
on
to
the
consumers
of
goods
and
services.

The
present
value
of
total
social
costs
through
2036,
contained
in
Table
VI.
F­
3,
is
estimated
to
be
$
27.2
billion
($
2002).
This
present
value
is
calculated
using
a
social
discount
rate
of
3
percent
from
2004
through
2036.
We
also
performed
an
analysis
using
a
7
percent
social
discount
rate.
Using
that
discount
rate,
the
present
value
of
the
social
costs
through
2036
is
estimated
to
be
$
13.9
billion
($
2002).
As
shown
in
Table
VI.
F­
3,
these
results
suggest
that
total
engineering
costs
exceed
compliance
costs
by
a
small
amount.
This
is
due
primarily
to
the
fact
that
the
estimated
output
quantities
for
diesel
engines,
equipment,
and
fuel
are
not
identical
to
those
estimated
in
the
engineering
cost
analysis,
which
is
due
to
the
different
methodologies
used
to
estimate
these
costs
(
see
previous
discussion
in
this
Section
IV.
F.
3).

Table
VI.
F­
2.
 
441
Summary
of
Social
Costs
Estimates
Associated
with
Primary
Program
2015,
2020,
2030,
and
2036
($
2002,
$
Million)
a,
b
2013
Market
Surplus
($
106)
Operating
Savings
($
106)
Total
Percent
Engine
Producers
Total
$
42.0
$
42.0
2.8%

Equipment
Producers
Total
$
143.1
$
143.1
9.5%

Construction
Equipment
$
64.0
$
64.0
Agricultural
Equipment
$
51.8
$
51.8
Industrial
Equipment
$
27.2
$
27.2
Application
Producers
&
Consumers
Total
$
1,496.7
($
243.2)
$
1,253.5
83.0%

Total
Producer
$
620.9
41.5%

Total
Consumer
$
875.7
58.5%

Construction
$
584.3
($
115.2)
$
469.2
Agriculture
$
430.0
($
78.2)
$
351.8
Manufacturing
$
482.4
($
49.8)
$
432.5
Fuel
Producers
Total
$
8.0
$
8.0
0.5%

PADD
I&
III
$
4.1
$
4.1
PADD
II
$
3.3
$
3.3
PADD
IV
$
0.0
$
0.0
PADD
V
$
0.6
$
6.0
Transportation
Services,
Total
$
104.9
($
41.5)
$
63.4
4.2%

Locomotive
$
1.6
($
12.4)
($
10.8)

Marine
$
0.9
($
9.9)
($
9.0)

Application
markets
not
included
in
NDEIM
$
102.4
($
19.2)
$
83.2
Total
$
1,794.7
($
284.7)
$
1,510.0
100.0%

2020
Market
Surplus
($
106)
Operating
Savings
($
106)
Total
Percent
Engine
Producers
Total
$
0.1
$
0.1
0.0%

Equipment
Producers
Total
$
122.7
$
122.7
6.7%

Construction
Equipment
$
57.8
$
57.8
Agricultural
Equipment
$
39.7
$
39.7
Industrial
Equipment
$
25.2
$
25.2
442
Application
Producers
&
Consumers
Total
$
1,826.1
($
192.3)
$
1,633.8
89.4%

Total
Producer
$
762.2
41.7%

Total
Consumer
$
1,063.8
58.3%

Construction
$
744.0
($
91.1)
$
653.0
Agriculture
$
524.3
($
61.8)
$
462.5
Manufacturing
$
557.8
($
39.4)
$
518.3
Fuel
Producers
Total
$
11.2
$
11.2
0.6%

PADD
I&
III
$
5.6
$
5.6
PADD
II
$
4.6
$
4.6
PADD
IV
$
0.2
$
0.2
PADD
V
$
0.8
$
0.8
Transportation
Services,
Total
$
95.7
($
35.1)
$
60.6
3.3%

Locomotive
$
2.0
($
7.2)
($
5.2)

Marine
$
1.1
($
11.6)
($
10.5)

Application
markets
not
included
in
NDEIM
$
92.6
($
16.3)
$
76.3
Total
$
2,055.7
($
227.4)
$
1,828.3
100.0%

2030
Engine
Producers
Total
$
0.1
$
0.1
0.0%

Equipment
Producers
Total
$
5.9
$
5.9
0.3%

Construction
Equipment
$
4.0
$
4.0
Agricultural
Equipment
$
1.9
$
1.9
Industrial
Equipment
$
0.1
$
0.1
Application
Producers
&
Consumers
Total
$
2,112.3
($
154.2)
$
1,958.1
95.7%

Total
Producer
$
882.2
41.7%

Total
Consumer
$
1,230.1
58.3%

Construction
$
863.8
($
73.0)
$
790.8
Agriculture
$
606.8
($
49.6)
$
557.2
Manufacturing
$
641.6
($
31.6)
$
610.0
Fuel
Producers
Total
$
13.2
$
13.2
0.6%

PADD
I&
III
$
6.7
$
6.7
PADD
II
$
5.2
$
5.2
PADD
IV
$
0.3
$
0.3
PADD
V
$
1.0
$
1.0
Transportation
Services,
Total
$
109.1
($
39.9)
$
69.2
3.4%

Locomotive
$
2.5
($
7.8)
($
5.3)

Marine
$
1.4
($
13.6)
($
12.2)

Application
markets
not
included
in
NDEIM
$
105.2
($
18.5)
$
86.7
Total
$
2,240.6
($
194.1)
$
2,046.4
100.0%
443
2036
Market
Surplus
($
106)
Operating
Savings
($
106)
Total
Percent
Engine
Producers
Total
$
0.2
$
0.2
0.0%

Equipment
Producers
Total
$
6.4
$
6.4
0.3%

Construction
Equipment
$
4.3
$
4.3
Agricultural
Equipment
$
2.0
$
2.0
Industrial
Equipment
$
0.1
$
0.1
Application
Producers
&
Consumers
Total
$
2,287.4
($
155.7)
$
2,131.7
95.7%

Total
Producer
$
955.5
41.7%

Total
Consumer
$
1,331.9
58.3%

Construction
$
936.4
($
50.0)
$
862.7
Agriculture
$
657.8
($
73.7)
$
607.8
Manufacturing
$
693.2
($
31.9)
$
661.3
Fuel
Producers
Total
$
14.5
$
14.5
0.7%

PADD
I&
III
$
7.3
$
7.3
PADD
II
$
5.8
$
5.8
PADD
IV
$
0.3
$
0.3
PADD
V
$
1.0
$
1.0
Transportation
Services,
Total
$
116.9
($
42.6)
$
74.3
3.3%

Locomotive
$
2.8
($
8.2)
($
5.4)

Marine
$
1.6
($
14.6)
($
13.0)

Application
markets
not
included
in
NDEIM
$
112.5
($
19.8)
$
92.7
Total
$
2,425.3
($
198.4)
$
2,227.0
100.0%

Notes:
a
Figures
are
in
2002
dollars.
b
Operating
savings
are
shown
as
negative
costs.
444
Table
VI.
F­
3.
 
National
Engineering
Compliance
Costs
and
Social
Costs
Estimates
for
the
Rule
(
2004
­
2036)
($
2002;
$
Million)

Year
Engineering
Compliance
Costs
Total
Social
Costs
2004
$
0
$
0
2005
$
0
$
0
2006
$
0
$
0
2007
($
17)
($
18)

2008
$
54
$
54
2009
$
54
$
54
2010
$
328
$
327
2011
$
923
$
922
2012
$
1,305
$
1,304
2013
$
1,511
$
1,510
2014
$
1,691
$
1,690
2015
$
1,742
$
1,741
2016
$
1,743
$
1,743
2017
$
1,763
$
1,762
2018
$
1,778
$
1,778
2019
$
1,795
$
1,795
2020
$
1,829
$
1,828
2021
$
1,816
$
1,815
2022
$
1,819
$
1,818
2023
$
1,844
$
1,843
2024
$
1,858
$
1,857
2025
$
1,888
$
1,887
2026
$
1,921
$
1,920
2027
$
1,954
$
1,952
2028
$
1,985
$
1,984
2029
$
2,017
$
2,016
2030
$
2,047
$
2,046
2031
$
2,078
$
2,077
2032
$
2,108
$
2,107
2033
$
2,139
$
2,137
2034
$
2,169
$
2,167
2035
$
2,198
$
2,197
2036
$
2,228
$
2,227
NPV
at
3%
$
27,247
$
27,232
NPV
at
7%
$
13,876
$
13,868
445
VII.
Alternative
Program
Options
Considered
Our
final
emission
control
program
for
nonroad
engines
and
equipment
consists
of
a
twostep
program
to
reduce
the
sulfur
content
of
nonroad
diesel
fuel
in
conjunction
with
Tier
4
engine
standards.
The
rule
also
contains
limits
on
sulfur
levels
in
locomotive
and
marine
diesel
fuel.
As
described
in
the
draft
Regulatory
Impact
Analysis
for
the
proposal,
we
evaluated
a
number
of
alternative
options
with
regard
to
the
scope,
level,
and
timing
of
the
standards.
This
section
presents
a
summary
of
those
alternative
program
options
and
our
reasons
for
either
adopting
or
not
adopting
these
options.

A.
Summary
of
Alternatives
For
our
Notice
of
Proposed
Rulemaking
(
NPRM),
we
developed
emissions,
benefits,
and
cost
analyses
for
a
number
of
alternative
program
options
involving
variations
in
both
the
fuel
and
engine
programs.
The
alternatives
we
considered
can
be
categorized
according
to
the
structure
of
their
fuel
requirements:
whether
the
15
ppm
fuel
sulfur
limit
for
nonroad
diesel
fuel
is
reached
in
two
steps,
like
the
program
we
are
finalizing
today,
or
in
one
step.
Within
each
of
these
two
broad
fuel
program
categories,
we
considered
a
number
of
different
engine
programs.
This
section
summarizes
the
alternatives.
A
more
detailed
description
of
the
alternatives
can
be
found
in
the
NPRM
and
the
draft
RIA.

One­
step
alternatives
were
those
in
which
the
15
ppm
fuel
sulfur
standard
for
nonroad
diesel
fuel
is
applied
in
a
single
step.
We
evaluated
three
one­
step
alternatives,
summarized
in
table
VII­
1.
Option
1
represented
an
engine
program
that
was
similar
to
that
in
our
proposed
program,
the
primary
difference
being
the
generally
earlier
phase­
in
dates
for
the
PM
standards.
We
considered
the
Option
1
engine
program
as
being
the
most
stringent
one­
step
program
that
could
be
considered
even
potentially
feasible
considering
cost,
lead­
time,
and
other
factors.
Option
1
also
included
a
June
2008
start
date
for
the
15
ppm
sulfur
standard
applicable
to
nonroad
diesel
fuel
and
the
500
ppm
sulfur
standard
applicable
to
locomotive
and
marine
fuel.
We
also
considered
two
other
one­
step
alternatives
which
differ
from
Option
1.
As
described
in
table
VII­
1,
Option
1b
differed
from
Option
1
regarding
the
timing
of
the
fuel
standards,
while
Option
1a
differed
from
Option
1
in
terms
of
the
engine
standards.
Options
1a
and
1b
also
differed
from
Option
1
by
extending
the
15
ppm
fuel
sulfur
limit
to
locomotive
and
marine
diesel
fuel.

Two­
step
alternatives
were
those
in
which
the
nonroad
diesel
fuel
sulfur
standard
was
set
first
at
500
ppm
and
then
was
reduced
to
15
ppm.
The
two­
step
alternatives
varied
from
the
proposed
program
in
terms
of
both
the
timing
and
levels
of
the
engine
standards
and
the
timing
of
the
fuel
standards.
Option
2a
was
the
same
as
the
proposed
program
except
the
500
ppm
fuel
standard
was
introduced
a
year
earlier,
in
2006.
Option
2b
was
the
same
as
the
proposed
program
except
the
15
ppm
fuel
standard
was
introduced
a
year
earlier
(
in
2009)
and
the
trap­
based
PM
standards
began
earlier
for
all
engines.
Option
2c
was
the
same
as
the
proposed
program
except
the
15
ppm
fuel
standard
was
introduced
a
year
earlier
in
2009
and
the
trap­
based
PM
standards
began
earlier
for
engines
175­
750
hp.
Option
2d
was
the
same
as
the
proposed
program
except
446
the
NO
X
standard
was
reduced
to
0.30
g/
bhp­
hr
for
engines
of
25­
75
hp,
and
this
standard
was
phased
in.
Finally,
Option
2e
was
the
same
as
the
proposed
program
except
there
were
no
new
Tier
4
NO
X
limits.

In
the
NPRM,
option
3
was
identical
to
the
proposed
program,
except
that
it
would
have
exempted
mining
equipment
over
750
hp
from
the
Tier
4
standards.
We
explained
in
detail
in
section
12.6.2.2.7
of
the
draft
RIA
that
we
had
very
serious
reservations
regarding
the
legality
of
this
option
given
these
engines'
high
emission
rates
of
PM,
NO
X
and
NMHC
and
the
availability
of
further
emissions
control
at
reasonable
cost.
We
adhere
to
these
conclusions
here.
We
do
note,
however,
that
we
are
adopting
somewhat
different
provisions
for
this
engine
category
than
we
proposed.
As
explained
in
sections
II.
A.
and
II.
B
above,
although
we
have
adopted
aftertreatment­
based
PM
standards
for
these
engines,
the
standards
are
slightly
higher
than
those
proposed
to
assure
their
technical
feasibility.
We
also
have
deferred
a
decision
on
whether
to
adopt
aftertreatment­
based
standards
for
NO
X
for
mobile
machines
with
engines
greater
than
750
hp.
We
also
have
provided
ample
lead
time
for
these
engines
to
comply
with
the
Tier
4
standards,
both
in
terms
of
the
rule's
compliance
dates
(
which
include
a
2015
date
for
the
final
Tier
4
standards,
one
year
later
than
we
proposed)
and
the
ABT
and
equipment
manufacturer
flexibilities.
This
lead
time
takes
into
account
the
long
design
periods,
high
cost,
and
low
sales
volumes
of
these
engines.
Thus,
although
we
strongly
disagree
with
the
option
of
not
adopting
Tier
4
standards
for
these
engines,
we
do
recognize
their
need
for
unique
standards
and
compliance
dates.

Option
4
included
applying
the
15
ppm
sulfur
limit
to
both
locomotive
and
marine
diesel
fuel
in
addition
to
nonroad
fuel.
On
the
basis
of
comments
received
and
additional
analyses,
we
have
determined
that
a
15ppm
sulfur
standard
for
locomotive
and
marine
fuel
is
appropriate,
though
we
have
included
certain
options
for
utilization
of
off­
specification
fuel
and
transmix
not
represented
in
our
original
Option
4.
This
aspect
of
our
final
program
is
discussed
in
detail
in
section
IV.

Options
5a
and
5b
were
identical
to
the
proposed
program
except
with
respect
to
standards
for
engines
less
than
75
hp.
Option
5a
was
identical
to
the
proposed
program
except
that
no
new
program
requirements
would
be
set
in
Tier
4
for
engines
under
75
hp.
Instead,
Tier
2
standards
and
testing
requirements
for
engines
under
50
hp,
and
Tier
3
standards
and
testing
requirements
for
50­
75
hp
engines,
would
continue
indefinitely.
The
Option
5b
program
was
identical
to
the
proposed
program
except
that
for
engines
under
75
hp
only
the
2008
engine
standards
would
be
set,
i.
e.
there
would
be
no
additional
PM
filter­
based
standard
in
2013
for
25­
75
hp
engines,
and
no
additional
NO
X+
NMHC
standard
in
2013
for
25­
50
hp
engines.
We
are
not
adopting
Options
5a
or
5b
in
today's
action.
As
explained
at
8.
2.3
of
the
Summary
and
Analysis
of
Comments,
and
in
sections
12.6.2.2.9
and
12.6.2.2.10
of
chapter
12
of
the
draft
RIA,
these
options
would
forego
substantial
PM
and
NO
X
+
NMHC
emission
reductions
(
on
the
order
of
hundreds
of
thousands
of
tons
of
each
pollutant)
which
are
feasible
at
reasonable
cost.
We
note
further
that
many
of
these
smaller
engines
operate
in
populated
areas
and
in
equipment
without
closed
cabs
 
in
mowers,
small
construction
machines,
and
the
like
 
where
personal
exposures
to
toxic
emissions
(
both
PM
and
air
toxics
which
are
part
of
the
NMHC
fraction)
may
be
pronounced
well
beyond
what
is
447
indicated
simply
by
a
comparison
of
nationwide
emissions
inventory
estimates.
We
would
also
emphasize
the
remarkable
growth
in
recent
sales
and
usage
for
these
smaller
diesel
machines,
and
we
expect
this
trend
to
continue,
pointing
up
the
need
for
effective
PM
emissions
control
from
these
engines.
We
thus
do
not
see
a
basis
in
law
or
policy
to
adopt
either
of
these
options.

In
response
to
comments
on
our
NPRM
we
also
investigated
a
number
of
other
variations
in
the
engine
standards
as
we
developed
our
final
rule.
These
variations
were
generally
related
to
the
phase­
in
of
engine
standards
in
a
number
of
different
horsepower
categories.
A
discussion
of
these
variations
is
provided
in
section
II
as
well
as
in
various
background
documents.

Table
VII­
1
contains
a
summary
of
a
number
of
these
alternatives.
The
expected
emission
reductions,
costs,
and
monetized
benefits
associated
with
them
in
comparison
to
the
proposed
program
were
evaluated
for
the
NPRM.
Those
analyses
were
not
revised
for
this
final
rulemaking
to
reflect
changes
in
our
empirical
models
or
assumptions.
We
received
no
new
information
that
would
cause
us
to
believe
that
the
relative
impacts
and
differences
for
those
alternative
program
options
relative
to
our
final
program
would
change
enough
to
make
an
impact
on
our
assessments
of
the
feasibility
or
appropriateness
of
the
options.
The
remainder
of
this
section
will
summarize
some
of
the
comments
we
received
on
the
options
and
our
responses
to
those
comments.
448
Table
VII­
1.
 
Summary
of
Alternative
Program
Options
Option
Fuel
Standards
Engine
Standards
a
Final
program

500
PPM
in
2007
for
NR,
loco/
marine

15
ppm
in
2010
for
NR

15
ppm
in
2012
for
loco/
marine

<
75
hp:
PM
standards
in
2008

25­
75
hp:
PM
AT­
based
standards
in
2013

75­
175
hp:
PM
AT­
based
standards
in
2012

175­
750
hp:
PM
AT­
based
standards
in
2011

75­
175
hp:
NO
X
AT­
based
standards
phase­
in
2012­
2014

175­
750
hp:
NO
X
AT­
based
standards
phase­
in
2011­
2014

>
750
hp:
PM
and
NO
X
AT
phased­
in
2011
and
2015
1­
Step
Fuel
Options
1

15
ppm
in
2008
for
NR
and
loco/
marine

<
50
hp:
PM
stds
only
in
2009

25­
75
hp:
PM
AT
stds
and
EGR
or
equivalent
NO
X
technology
in
2013;
no
NO
X
AT

>
75
hp:
PM
AT
stds
phasing
in
beginning
in
2009;
NO
X
AT
phasing
in
beginning
in
2011
1a

15
ppm
in
2008
for
NR,
loco/
marine

PM
AT
introduced
in
2009­
10

NO
X
AT
introduced
in
2011­
12
1b

15
ppm
in
2006
for
NR,
loco/
marine
Same
as
1a
2­
Step
Fuel
Options
2a
Same
as
proposed
program
except
 

500
ppm
in
2006
for
NR,
loco/
marine
Same
as
proposed
program
2b
Same
as
proposed
program
except
 

15
ppm
in
2009
for
NR
and
loco/
marine
Same
as
proposed
program
except
 

Move
PM
AT
up
1
year
for
all
engines
>
25
hp
(
phase
in
starts
2010)

2c
Same
as
proposed
program
except
 

15
ppm
in
2009
for
NR
and
loco/
marine
Same
as
proposed
program
except
 

Move
PM
AT
up
1
year
for
all
engines
175­
750
hp
(
phase
in
starts
2010)

2d

Same
as
proposed
program
Same
as
proposed
program
except
 

Phase­
in
NO
X
AT
for
25­
75hp
beginning
in
2013
Other
Options
3

Same
as
proposed
program
Same
as
proposed
program
except
 

Mining
equipment
over
750
hp
left
at
Tier
2
4
Same
as
proposed
program
except
 

Downgrade
flexibilities
for
loco/
marine
not
included
Same
as
proposed
program
5a

Same
as
proposed
program
Same
as
proposed
program
except­

No
Tier
4
standards
<
75
hp
5b

Same
as
proposed
program
Same
as
proposed
program
except­

No
new
<
75hp
standards
after
2008
(
i.
e.,
no
CDPFs
in
2013)

Notes:
a
AT
=
aftertreatment
B.
Introduction
of
15
ppm
Nonroad
Diesel
Sulfur
Fuel
in
One
Step
EPA
carefully
evaluated
an
alternative
which
would
require
that
the
nonroad
diesel
sulfur
level
be
reduced
to
15ppm
in
a
single
step,
beginning
June
1,
2008.
The
one­
step
fuel
options,
including
the
three
variations
Option
1,
Option
1a,
and
Option
1b,
were
presented
and
discussed
in
detail
in
the
NPRM
and
in
the
draft
RIA.

Many
comments
were
received
about
a
one
step
diesel
fuel
sulfur
control
approach
taking
effect
in
2008.
Refiners
commented
that
they
did
not
think
that
they
could
reduce
both
the
highway
and
nonroad
diesel
fuel
pools
down
to
15
ppm
in
the
same
timeframe
while
maintaining
449
the
supply
of
these
two
diesel
fuel
pools.
The
refiners
went
on
to
say
that
having
a
500
ppm
outlet
for
off­
specification
material
in
the
nonroad
diesel
fuel
pool
is
critical
in
the
years
after
reducing
the
highway
diesel
fuel
pool
to
15
ppm
to
ensure
supply
of
highway
fuel.
The
refining
industry
further
commented
that
the
one
step
program
would
provide
fewer
environmental
benefits
and
also
provide
the
refining
industry
less
time
and
flexibility
to
make
the
transition
to
the
15
ppm
sulfur
level
for
nonroad
diesel
fuel
compared
to
a
two
step
approach.
While
many
environmental
organizations
and
the
Engine
Manufacturers
Association
(
EMA)
commented
that
they
preferred
a
15
ppm
standard
as
soon
as
possible,
EMA
also
pointed
out
that
a
quick
transition
to
500
ppm
would
provide
important
fleet­
wide
emission
reductions,
reduce
maintenance
costs
and
enable
the
use
of
certain
emission
control
technology
such
as
exhaust
gas
recirculation
and
oxidation
catalysts.
Commenters
generally
said
little
about
the
engine
standards
associated
with
the
one­
step
options,
other
than
to
point
out
that
earlier
introduction
of
15
ppm
sulfur
fuel
means
that
aftertreatment­
based
standards
and
nonroad
engine
retrofits
can
also
be
introduced
earlier.

The
reasons
provided
in
the
NPRM
for
choosing
the
two
step
program
over
the
one­
step
program
still
apply
and
generally
address
the
comments
received
(
see
section
12.6.2
of
the
draft
RIA).
Although
there
would
be
greater
PM
and
NO
X
emission
reductions
with
the
one­
step
approach
due
to
earlier
introduction
of
aftertreatment
technology
enabled
by
the
15
ppm
sulfur
diesel
fuel,
the
SO
2
emission
benefits
for
the
two­
step
approach
are
greater
due
to
the
earlier
adoption
of
the
500
ppm
sulfur
standard.
Thus,
even
assuming
that
the
one­
step
approach
would
not
jeopardize
implementation
of
the
highway
diesel
emission
rule,
the
emission
impacts
of
these
two
options
are
mixed.
Moreover,
the
costs
for
achieving
the
second
step
(
15
ppm)
of
the
two
step
approach
are
likely
to
be
lower
than
under
the
one
step
approach.
This
is
because
advanced
desulfurization
technologies
are
much
more
likely
to
be
used
in
2010
after
additional
testing
and
demonstration,
while
they
may
hardly
be
considered
at
all
if
they
would
have
to
be
installed
for
2008.
One
advanced
desulfurization
technology,
Process
Dynamics
Isotherming,
is
expected
to
lower
the
cost
of
complying
with
the
15
ppm
step
by
about
one
cent
per
gallon.
This
cost
discrepancy
is
expected
to
persist
since
it
is
associated
with
the
investment
of
significant
capital
which
cannot
be
modified
or
replaced
without
significant
additional
expense.
Additionally,
under
the
two
step
program,
refiners
will
be
able
to
use
their
experience
in
complying
with
15
ppm
highway
diesel
fuel
sulfur
standard
to
better
design
their
nonroad
hydrotreaters
needed
for
2010.

After
careful
consideration
of
these
matters,
we
have
decided
to
finalize
the
two­
step
approach
in
today's
action.

C.
Applying
the
15
ppm
Sulfur
Cap
to
Locomotive
and
Marine
Diesel
Fuel
In
the
NPRM,
we
requested
comment
on
extending
the
15
ppm
cap
to
locomotive
and
marine
diesel
fuel
in
2010
or
some
later
year
as
part
of
this
rule.
The
costs
and
inventory
impacts
of
this
alternative
were
explored
in
the
context
of
Option
4
in
the
NPRM.
A
15ppm
sulfur
cap
for
locomotive
and
marine
fuel
would
increase
the
long­
term
PM
and
SO
2
benefits
of
the
rule
and
would
reduce
the
number
of
fuels
being
carried
in
the
distribution
system
after
2014,
when
the
small
refiner
provisions
of
this
rule
expire.
It
would
also
allow
refiners
to
plan
to
comply
with
the
450
15
ppm
cap
for
locomotive
and
marine
diesel
fuel
at
the
same
time
as
they
plan
to
comply
with
the
500
ppm
cap
for
NRLM
fuel
and
the
15
ppm
cap
for
nonroad
fuel.

As
a
result
of
comments
received
and
additional
analyses
performed
since
the
NPRM,
we
are
finalizing
a
15
ppm
sulfur
cap
for
locomotive
and
marine
fuel
in
today's
notice.
A
full
discussion
of
the
feasibility
and
benefits
of
a
15
ppm
sulfur
cap
for
locomotive
and
marine
fuel
can
be
found
in
section
IV,
along
with
a
summary
of
the
comments
we
received
and
our
responses
to
those
comments.
In
addition,
we
are
planning
a
separate
rule
to
implement
new
emission
standards
for
locomotive
and
marine
diesel
engines
that
will
build
upon
the
15
ppm
sulfur
standard
applicable
to
fuel
used
by
these
engines.
We
are
publishing
an
Advanced
Notice
of
Proposed
Rulemaking
in
another
section
of
today's
Federal
Register
describing
our
plans
in
this
area.

D.
Other
Alternatives
We
also
analyzed
a
number
of
other
alternatives
in
the
NPRM,
as
summarized
in
table
VII­
1.
Some
of
these
focused
on
control
options
more
stringent
than
our
final
program
while
others
reflect
modified
engine
requirements
that
result
in
less
stringent
control.
In
the
NPRM
we
presented
our
assessment
of
these
options
in
terms
of
the
feasibility,
emission
reductions,
costs,
and
other
relevant
factors.
Few
comments
were
received
on
these
other
alternatives,
and
no
new
information
arose
to
alter
what
we
believe
are
significant
concerns
with
respect
to
these
Options
compared
to
the
final
program.
Hence,
with
the
exception
of
the
few
alternative
program
elements
that
we
did
incorporate
into
our
final
program
as
described
earlier
in
this
section,
we
did
not
include
these
options
into
our
final
program.
Our
detailed
responses
to
all
the
comments
received
on
the
other
alternatives
can
be
found
in
section
8
of
the
Summary
and
Analysis
of
Comments
document.
451
VIII.
Future
Plans
The
above
discussion
describes
the
contents
of
this
final
rule.
This
section
addresses
a
variety
of
areas
not
addressed
by
this
rule.
In
these
several
areas,
we
expect
to
continue
our
efforts
to
improve
our
compliance
programs
and
achieve
further
reductions
in
emissions
from
nonroad
engines.

A.
Technology
Review
As
we
described
in
sections
III.
E
and
G
of
the
proposal,
there
are
some
technology
issues
that
warrant
our
planning
a
future
review
of
emissions
control
technology
for
engines
under
75
hp.
Under
our
implementation
schedule
presented
in
section
II.
A,
standards
based
on
the
use
of
PM
filter
technology
will
take
effect
in
the
2013
model
year
for
25
 
75
hp
engines
(
or
in
the
2012
model
year
for
manufacturers
opting
to
skip
the
transitional
standards
for
50
 
75
hp
engines).
However,
at
this
time
we
have
not
decided
what
long­
term
PM
standards
for
engines
under
25
hp
are
appropriate.
No
PM
filter­
based
standards
are
being
adopted
for
these
under
25
hp
engines
in
this
final
rule.
Likewise,
we
have
not
decided
what
the
long­
term
NO
X
standards
for
engines
under
75
hp
should
be,
and
no
NO
X
adsorber­
based
standards
are
being
set
for
these
engines
in
this
final
rule.
As
part
of
the
technology
review,
we
plan
to
thoroughly
evaluate
progress
made
toward
applying
advanced
PM
and
NO
X
control
technologies
to
these
smaller
engines.

We
plan
to
conduct
the
technology
review
in
2007,
and
to
conclude
it
by
the
end
of
that
year,
to
give
manufacturers
lead
time
should
an
adjustment
in
the
program
be
considered
appropriate.
We
do
not
intend
to
include
in
the
technology
review
a
reassessment
of
PM
filter
technology
needed
to
meet
the
optional
0.02
g/
hp­
hr
PM
standard
for
50
 
75
hp
engines
in
2012.
We
assume
that
manufacturers
would
only
choose
this
option
if
they
had
confidence
that
they
could
meet
the
0.02
g/
hp­
hr
standard
in
2012,
a
year
earlier
than
otherwise
required.

Numerous
commenters
expressed
support
for
the
planned
technology
review.
MECA
and
STAPPA/
ALAPCO
stressed
that
the
review
should
not
be
limited
to
considering
the
need
to
relax
PM
filter­
based
standards
for
small
engines,
but
should
also
consider
technology
innovations
that
would
justify
increasing
the
stringency
of
small
engine
standards
that
are
not
currently
aftertreatment­
based.
This
is
indeed
our
intent.
Yanmar
suggested
that
the
review
be
deferred
to
2010
or
later,
because
NO
X
control
experience
from
highway
diesels
will
not
be
sufficient
by
2007.
On
the
contrary,
based
on
the
rate
of
technology
development
progress
to
date
for
highway
engines,
we
believe
that
there
will
be
a
very
large
amount
of
pertinent
new
information
available
by
2007,
even
though
widespread
field
experience
may
be
lacking.
Waiting
longer
to
conduct
the
technology
review
would,
we
believe,
provide
insufficient
leadtime
to
the
industry
should
an
adjustment
to
the
2013
standards
be
found
appropriate.
Some
engine
and
equipment
manufacturers
called
for
expanding
the
technology
review
to
other
power
categories.
As
discussed
in
the
proposal,
we
do
not
believe
that
a
generalized
technology
review
of
the
sort
being
conducted
for
the
heavy­
duty
highway
engine
program
is
warranted,
primarily
due
to
the
very
fact
251
Council
of
the
European
Union,
"
Directive
of
the
European
Parliament
and
of
the
Council
amending
Directive
97/
68/
EC,"
March
15,
2004.

452
that
the
nonroad
standards
are
modeled
on
the
highway
program,
and
the
highway
program
does
include
this
comprehensive
review.
We
also
do
not
see
the
specific
technical
issues
for
engines
above
75
hp
that
have
been
identified
for
smaller
engines,
such
as
might
warrant
our
expanding
the
review
at
this
time.
Engine
manufacturers
also
expressed
interest
in
a
consultative
process
in
the
near
future
that
would
establish
the
scope,
outputs,
and
criteria
for
the
review,
possibly
including
assigning
responsibility
for
the
review
to
an
independent
entity.
Although
we
plan
and
hope
to
have
the
active
participation
of
all
interested
parties
in
the
review
process,
assigning
responsibility
for
the
review
to
groups
or
individuals
outside
the
Agency
would
be
inappropriate.
As
the
review
would
be
closely
tied
to
potential
subsequent
rulemaking
action
by
the
Agency,
it
is
essential
that
it
adequately
cover
the
relevant
issues.
To
ensure
this,
it
is
imperative
that
we
retain
overall
responsibility
for
the
review.
We
have
not
yet
worked
out
process
details
for
the
review,
but
will
do
so
at
some
later
date.

Several
commenters
strongly
stressed
the
need
for
EPA
to
work
with
governmental
standards­
setting
bodies
in
other
countries
to
harmonize
future
standards.
As
discussed
in
section
II.
A.
8,
we
recognize
the
importance
of
harmonizing
nonroad
diesel
standards
and
have
worked
diligently
with
our
colleagues
responsible
for
setting
such
standards
outside
the
U.
S.,
thus
far
with
good
success.
The
March
2004
Directive
that
sets
future
nonroad
diesel
standards
in
the
European
Union
(
EU)
will
very
closely
align
the
EU
program
with
our
program
in
the
Tier
4
timeframe.
251
Further
enhancing
prospects
for
close
harmonization,
the
Directive
includes
plans
for
a
future
technical
review:
"
There
are
still
some
uncertainties
regarding
the
cost
effectiveness
of
using
aftertreatment
equipment
to
reduce
emissions
of
particulate
matter
(
PM)
and
of
oxides
of
nitrogen
(
NO
X).
A
technical
review
should
be
carried
out
before
31
December
2007
and,
where
appropriate,
exemptions
or
delayed
entry
into
force
dates
should
be
considered."

Note
that
the
timing
for
this
review
coincides
with
that
of
our
own
planned
review.
Among
other
things,
both
our
review
and
the
EU
review
will
consider
the
appropriate
long­
term
standards
for
engines
between
25
and
50
hp,
engines
for
which
we
have
set
PM­
filter
based
standards
and
for
which
the
EU
has
not.
Furthermore,
in
addition
to
re­
evaluating
the
standards,
the
EU
technical
review
will
consider
the
need
to
introduce
standards
for
engines
below
25
hp
and
above
750
hp,
the
two
categories
for
which
the
EU
has
not
yet
set
emission
standards,
and
for
which
harmonization
is
thus
most
lacking.
We
are
greatly
encouraged
by
the
degree
of
harmonization
achieved
thus
far,
and,
given
our
common
interests,
issues
and
planned
timing,
expect
to
work
closely
with
Commission
staff
in
carrying
out
the
2007
technology
review,
with
an
aim
of
preserving
and
enhancing
harmonization
of
standards.

In
response
to
comments
received
on
the
proposal,
we
wish
to
clarify
that
the
technology
review
for
engines
under
75
hp
will
be
a
comprehensive
undertaking
that
may
result
in
adjustments
to
standards,
implementation
dates,
or
other
provisions
(
such
as
flexibilities)
in
either
direction
(
that
is,
toward
more
or
less
stringency),
depending
on
conclusions
reached
in
the
review
about
453
appropriate
standards
under
the
Clean
Air
Act.
All
relevant
factors
including
technical
feasibility
and
commercial
viability
of
engines
and
machines
designed
to
meet
the
standards
will
be
taken
into
account.

B.
Test
Procedure
Issues
Section
III
describes
two
issues
related
to
test
procedures
that
warrant
further
attention
in
the
future.
First,
we
are
adopting
transient
test
procedures
for
engines
subject
to
Tier
4
emission
standards,
but
we
intend
to
collect
data
that
would
help
us
adopt
a
duty
cycle
that
would
appropriately
test
constant­
speed
engines.
Second,
we
are
adopting
cold­
start
test
procedures,
but
are
interested
in
collecting
additional
data
that
could
be
used
to
revise
those
procedures
if
appropriate.

C.
In­
use
Testing
Although
this
final
rule
does
not
include
an
in­
use
testing
program
for
nonroad
diesel
engines,
we
expect
to
establish
such
a
program
for
the
future
in
a
separate
rulemaking
action.
The
goal
of
this
program
will
be
to
ensure
that
emissions
standards
are
met
throughout
the
useful
life
of
the
engines,
under
conditions
normally
experienced
in­
use.
The
Agency
expects
to
pattern
the
inuse
testing
requirements
for
nonroad
diesel
engines
after
a
program
that
is
being
developed
for
heavy­
duty
diesel
highway
vehicles.
This
program
will
be
funded
and
conducted
by
the
manufacturer's
of
heavy­
duty
diesel
highway
engines
with
our
oversight.
We
expect
it
will
incorporate
a
two­
year
pilot
program.
The
pilot
program
will
allow
the
Agency
and
manufacturers
to
gain
the
necessary
experience
with
the
in­
use
testing
protocols
and
generation
of
in­
use
test
data
using
portable
emission
measurement
devices
prior
to
fully
implementing
program.
A
similar
pilot
program
is
expected
to
be
part
of
any
manufacturer­
run,
in­
use
NTE
test
program
for
nonroad
engines.

The
Agency
plans
to
promulgate
the
in­
use
testing
requirements
for
heavy­
duty
highway
vehicles
in
the
December
2004
time
frame.
We
anticipate
proposing
a
manufacturer­
run,
in­
use
testing
program
for
nonroad
diesel
engines
by
2005
or
earlier.
As
mentioned
above,
the
nonroad
diesel
engine
program
is
expected
to
be
patterned
after
the
heavy­
duty
highway
program.

D.
Engine
Diagnostics
We
are
also
in
the
process
of
defining
diagnostic
requirements
that
would
apply
to
highway
diesel
engines.
Once
we
have
adopted
requirements
for
highway
engines,
we
would
aim
to
adapt
the
requirements
as
needed
to
appropriately
address
diagnostic
needs
for
nonroad
diesel
engines.
These
programs
would
likely
be
very
similar,
but
the
diagnostics
for
nonroad
engines
my
need
to
differ
in
some
ways,
depending
on
the
technologies
used
by
different
types
and
sizes
of
engines
and
on
an
assessment
of
an
appropriate
level
of
information
and
control
for
engines
used
in
nonroad
applications.
454
E.
Future
NOX
Standards
for
Engines
in
Mobile
Machinery
Over
750
hp
In
section
II.
A.
4,
we
explain
that
we
are
not,
at
this
time,
setting
Tier
4
NO
X
standards
for
mobile
machinery
over
750
hp
based
on
the
performance
of
high­
efficiency
aftertreatment,
although
we
note
that
the
2.6
g/
bhp­
hr
NO
X
standard
taking
effect
for
these
engines
in
2011
represents
a
more
than
60%
NO
X
reduction
from
the
6.9
g/
bhp­
hr
Tier
1
level
in
effect
today,
and
a
more
than
40%
reduction
from
the
4.8
g/
bhp­
hr
NO
X+
NMHC
Tier
2
standard
level
that
takes
effect
in
2006.
We
are
still
evaluating
the
issues
involved
for
these
engines
to
achieve
a
more
stringent
NO
X
standard,
and
believe
that
these
issues
are
resolvable.
We
intend
to
continue
evaluating
the
appropriate
long­
term
NO
X
standard
for
mobile
machinery
over
750
hp
and
expect
to
announce
further
plans
regarding
these
issues,
perhaps
as
early
as
2007.

F.
Emission
Standards
for
Locomotive
and
Marine
Diesel
Engines
This
final
rule
adopts
limited
requirements
to
limit
sulfur
levels
in
distillate
fuels
used
in
locomotive
and
many
marine
diesel
engines,
which
will
help
reduce
PM
emissions
from
these
engines.
In
an
upcoming
rulemaking,
we
will
consider
an
additional
tier
of
NO
X
and
PM
standards
for
marine
diesel
engines
less
than
30
liters
per
cylinder
and
for
locomotive
engines.
These
standards
would
reflect
the
application
of
advanced
emission­
control
technology,
including
the
potential
to
use
the
high­
efficiency
catalytic
emission­
control
devices
like
those
described
elsewhere
in
this
preamble.
In
developing
these
new
standards,
we
will
consider
the
substantial
overlap
in
engine
technology
between
the
locomotive
and
marine
engines
and
the
nonroad
engines
covered
by
this
final
rule.
We
will
also
take
into
account
the
unique
features
associated
with
locomotive
and
marine
engines
(
and
their
respective
markets)
and
the
extent
to
which
these
differences
may
constrain
the
feasibility
of
applying
advanced
emission
control
technologies
to
those
engines.

We
are
concurrently
publishing
an
Advance
Notice
of
Proposed
Rulemaking
that
describes
the
emission­
control
program
we
are
contemplating
for
these
engines.
After
consideration
of
comments
submitted
on
the
Advance
Notice,
we
will
publish
a
Notice
of
Proposed
Rulemaking.
Our
proposal
will
be
subject
to
comment
before
its
expected
completion
in
the
2006
time
frame.

The
engine
emission
control
program
to
be
described
in
the
Advance
Notice
will
cover
all
locomotive
engines
subject
to
40
CFR
part
92
and
all
marine
diesel
engines
with
displacement
below
30
liters
per
cylinder.
Note
that
the
rule
will
therefore
cover
marine
diesel
engines
below
37
kW,
which
are
currently
regulated
through
Tier
3
with
land­
based
nonroad
engines
in
40
CFR
part
89.
The
rule
will
also
address
both
recreational
and
commercial
marine
diesel
engines
with
displacement
below
30
liters
per
cylinder.
Marine
engines
at
or
above
30
liters
per
cylinder
typically
use
a
different
kind
of
fuel,
residual
fuel,
and
will
be
considered
in
a
separate
rulemaking
to
be
finalized
by
April
27,
2007,
pursuant
to
a
regulatory
provision
adopted
in
our
recent
rule
setting
standards
for
those
engines
(
68
FR
9783,
February
28,
2003).
455
G.
Retrofit
Programs
In
the
proposal,
we
requested
comment
on
setting
voluntary
new
engine
emission
standards
applicable
to
the
retrofit
of
nonroad
diesel
engines.
As
described
in
section
III.
A,
we
are
not
adopting
a
retrofit
credit
program
with
today's
action.
We
believe
it
is
important
to
more
fully
consider
the
details
of
a
retrofit
credit
program
and
work
with
interested
parties
in
determining
whether
a
viable
program
can
be
developed.
EPA
intends
to
explore
the
possibility
of
a
voluntary
nonroad
retrofit
credit
program
through
future
action.

H.
Reassess
the
Marker
Specified
for
Heating
Oil
As
discussed
in
sections
IV
and
V,
we
are
requiring
that
the
chemical
marker
solvent
yellow
124
(
SY­
124)
be
added
to
heating
oil
outside
of
the
Northeast/
Mid­
Atlantic
Area.
We
received
comments
from
the
American
Society
of
Testing
and
Materials
(
ASTM),
the
Coordinating
Research
Council
(
CRC),
the
Department
of
Defense
(
DoD),
and
the
Federal
Aviation
Administration
(
FAA)
requesting
that
we
delay
finalizing
the
selection
of
a
specific
marker
for
use
in
this
final
rule
due
to
concerns
for
jet
fuel
contamination.
ASTM
withdrew
its
request
for
a
postponement
in
the
regulation,
given
that
this
final
rule
requires
addition
of
the
marker
at
the
terminal,
rather
than
the
refinery
gate
as
proposed.
This
eliminates
most
of
the
concern
regarding
jet
fuel
contamination.
However,
ASTM
stated
that
some
concern
remains
regarding
jet
fuel
contamination
downstream
of
the
terminal.
Nevertheless,
ASTM
related
that
these
concerns
need
not
delay
finalization
of
the
marker
requirements
in
this
rule,
since
a
CRC
program
to
evaluate
these
concerns
is
expected
to
be
completed
well
before
SY­
124
must
be
added
to
heating
oil.
FAA
is
also
undertaking
an
effort
to
identify
fuel
markers
that
would
be
compatible
for
use
in
jet
fuel.

We
also
received
comments
from
the
heating
oil
industry
and
the
Department
of
Defense,
which
expressed
concerns
regarding
the
potential
health
effects
and
maintenance
impacts
on
heating
oil
equipment
from
the
use
of
SY­
124
in
heating
oil.
As
discussed
in
section
V,
we
believe
these
concerns
have
been
adequately
addressed
for
us
to
specify
the
use
of
SY­
124
in
this
final
rule.
The
EU
has
required
the
use
of
SY­
124
in
heating
oil
since
August
2002.
The
EU
intends
to
re­
evaluate
the
use
of
SY­
124
after
December
2005
or
earlier
if
they
learn
of
any
health,
safety,
or
environmental
concerns
from
their
in­
use
experience
with
SY­
124.

We
will
keep
abreast
of
the
ASTM,
CRC,
FAA,
IRS,
and
EU
activities
and
commit
to
a
review
of
our
use
of
SY­
124
under
today's
rule
based
on
these
findings.
If
alternative
markers
are
identified
that
do
not
raise
concerns
regarding
the
potential
contamination
of
jet
fuel,
we
will
initiate
a
rulemaking
to
evaluate
the
use
of
one
of
these
markers
in
place
of
SY­
124.
456
IX.
Public
Participation
Many
interested
parties
provided
their
input
on
the
proposed
rulemaking
during
our
public
comment
period.
This
comment
period,
along
with
the
three
public
hearings
that
were
held
in
New
York,
Chicago,
and
Los
Angeles,
provided
ample
opportunity
for
public
participation.
Throughout
the
rulemaking
process,
EPA
met
with
stakeholders
including
representatives
from
the
fuel
refining
and
distribution
industry,
engine
and
equipment
manufacturing
industries,
emission
control
manufacturing
industry,
environmental
organizations,
states,
agricultural
interests,
and
others.

A
detailed
Response
to
Comments
document
was
prepared
for
this
rulemaking
that
describes
the
comments
that
we
received
on
the
proposal
along
with
our
response
to
each
of
these
comments.
The
Response
to
Comments
document
is
available
in
the
air
docket
and
e­
docket
for
this
rule,
as
well
as
on
the
Office
of
Transportation
and
Air
Quality
homepage.
In
addition,
comments
and
responses
for
many
key
issues
are
included
throughout
this
preamble.
457
X.
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
Impact
Analysis
has
been
prepared
and
is
available
in
the
docket
for
this
rulemaking
and
at
the
internet
address
listed
under
"
How
Can
I
Get
Copies
of
This
Document
and
Other
Related
Information?"
above.
This
action
was
submitted
to
the
Office
of
Management
and
Budget
for
review
under
Executive
Order
12866.
Estimated
annual
costs
of
this
rulemaking
are
estimated
to
be
$
2
billion
per
year,
thus
this
proposed
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
in
this
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.
The
information
collection
requirements
are
not
enforceable
until
OMB
approves
them.
The
OMB
control
number
for
engine­
related
information
collection
is
2060­
0460
(
EPA
ICR
number
1897.07)
and
for
fuel­
related
information
collection
is
2060­
0308
(
EPA
ICR
number
1718.07).

We
will
use
the
engine­
related
information
to
ensure
that
new
nonroad
diesel
engines
comply
with
emission
standards
through
certification
requirements
and
various
subsequent
compliance
provisions.
This
information
collection
is
mandatory
under
the
provisions
of
42
U.
S.
C.
7401
­
7671(
q).
We
will
use
the
fuel­
related
information
to
ensure
that
diesel
fuel
meets
the
sulfur
limits
and
corresponding
requirements
related
to
marking
and
segregating
the
different
types
and
458
grades
of
diesel
fuel.
This
information
collection
is
mandatory
under
the
provisions
of
42
U.
S.
C.
7545(
c),
(
g)
and
(
i),
and
7625­
1.

In
addition,
this
notice
announces
OMB's
approval
of
the
information
collection
requirements
for
other
programs,
as
summarized
in
Table
X.
B­
1.

Table
X.
B­
1
 
Approved
Information
Collection
Requests
from
Other
Programs
Program
Final
Rule
Cite
OMB
Control
Number
EPA
ICR
Number
OMB
Approval
Nonroad
spark­
ignition
engines
over
19
kW
November
8,
2002
(
67
FR
68242)
2060­
0460
1897.04
January
31,
2003
Recreational
vehicles
November
8,
2002
(
67
FR
68242)
2060­
0460
1897.04
January
31,
2003
Rebuilders
of
various
types
of
engines
November
8,
2002
(
67
FR
68242)
2060­
0104
0783.46
June
11,
2003
Highway
motorcycles
January
15,
2004
(
69
FR
2398)
2060­
0104
0783.46
March
26,
2004
The
estimated
annual
public
reporting
and
recordkeeping
burden
for
collecting
information
from
all
these
programs
is
shown
in
Table
X.
B­
2.
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.
459
Table
X.
B­
2.
 
Information
Collection
Burdens
Engine
Type
Respondents
Hours
per
Respondent
Hours
for
All
Respondents
Capital
Costs
for
All
Respondents
Operating
and
Maintenance
Costs
for
All
Respondents
Total
Costs
for
All
Respondents
Nonroad
diesel
engine
manufacturers
75
3,304
247,783
$
0
$
5,894,802
$
18,661,614
Diesel
Fuel
Suppliers
2,615
75
196,288
$
1,800,000
$
1,800,000
$
18,371,600
Nonroad
sparkignition
engine
manufacturers
12
1,832
21,986
$
174,419
$
2,507,790
$
3,617,683
Recreational
vehicle
manufacturers
39
684
26,669
$
1,627,907
$
2,137,115
$
4,869,253
Highway
Motorcycles
46
32
1,449
$
0
$
23,686
$
79,428
Importers
40
13
529
$
0
$
150,000
$
169,223
Rebuilders
200
6
1,200
$
0
$
0
$
38,800
An
agency
may
not
conduct
or
sponsor,
and
a
person
is
not
required
to
respond
to
a
collection
of
information
unless
it
displays
a
currently
valid
OMB
control
number.
The
OMB
control
numbers
for
EPA's
regulations
in
40
CFR
are
listed
in
40
CFR
part
9.
When
this
ICR
is
approved
by
OMB,
the
Agency
will
publish
a
technical
amendment
to
40
CFR
part
9
in
the
Federal
Register
to
display
the
OMB
control
number
for
the
approved
information
collection
requirements
contained
in
this
final
rule.
EPA
received
various
comments
on
the
rulemaking
provisions
covered
by
the
ICRs,
but
no
comments
on
the
paperwork
burden
or
other
information
in
the
ICRs.
All
comments
that
were
submitted
to
EPA
are
considered
in
the
relevant
Summary
and
Analysis
of
Comments,
which
can
be
found
in
the
docket.
A
copy
of
any
of
the
submitted
ICR
documents
may
be
obtained
from
Susan
Auby,
Collection
Strategies
Division,
U.
S.
Environmental
Protection
Agency
(
2822­
T),
1200
Pennsylvania
Ave.,
NW,
Washington,
DC
20460
or
by
email
at
auby.
susan@
epa.
gov.

To
comment
on
the
Agency's
need
for
this
information,
the
accuracy
of
the
provided
burden
estimates,
and
any
suggested
methods
for
minimizing
respondent
burden,
including
the
use
of
automated
collection
techniques,
EPA
has
a
public
docket
for
this
rule,
which
includes
this
ICR,
under
Docket
ID
number
OAR­
2003­
0012.
Submit
any
comments
related
to
the
ICR
for
this
rule
to
EPA
and
OMB.
Address
comments
to
OMB
by
email
to
drostker@
omb.
eop.
gov
or
fax
to
(
202)
395­
7285.
Please
do
not
send
comments
to
OMB
via
U.
S.
Mail.
460
C.
Regulatory
Flexibility
Act
(
RFA),
as
amended
by
the
Small
Business
Regulatory
Enforcement
Fairness
Act
of
1996
(
SBREFA),
5
USC
601
et.
seq
EPA
has
decided
to
prepare
a
Regulatory
Flexibility
Analysis
(
RFA)
in
connection
with
this
final
rule.
For
purposes
of
assessing
the
impacts
of
today's
rule
on
small
entities,
a
small
entity
is
defined
as:
(
1)
a
small
business
that
is
primarily
engaged
in
the
manufacturing
of
nonroad
diesel
engines
and
equipment
that
meets
the
definitions
based
on
the
Small
Business
Administration's
(
SBA)
size
standards
(
see
table
X.
C.­
1
below);
(
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
X.
C­
1.
 
Small
Business
Administration
Size
Standards
for
Various
Business
Categories
Industry
Defined
as
small
entity
by
SBA
if:
Major
SICa
Codes
Engine
manufacturers
Less
than
1,000
employees
Major
Group
35
Equipment
manufacturers:

­
construction
equipment
Less
than
750
employees
Major
Group
35
­
industrial
truck
manufacturers
(
i.
e.
forklifts)
Less
than
750
employees
Major
Group
35
­
all
other
nonroad
equipment
manufacturers
Less
than
500
employees
Major
Group
35
Fuel
refiners
Less
than
1500
employeesb
2911
Fuel
distributors
<
varies>
<
varies>

Notes:

a
Standard
Industrial
Classification
b
EPA
has
included
in
past
fuels
rulemakings
a
provision
that,
in
order
to
qualify
for
the
small
refiner
flexibilities,
a
refiner
must
also
have
a
company­
wide
crude
refining
capacity
of
no
greater
than
155,000
barrels
per
calendar
day.
EPA
has
included
this
criterion
in
the
small
refiner
definition
for
a
nonroad
diesel
sulfur
program
as
well.

Pursuant
to
5
U.
S.
C.
section
603,
EPA
prepared
an
Initial
Regulatory
Flexibility
Analysis
(
IRFA)
for
the
proposed
rule
and
convened
a
Small
Business
Advocacy
Review
Panel
(
SBAR
Panel,
or
`
the
Panel')
to
obtain
advice
and
recommendations
of
representatives
of
the
regulated
small
entities
pursuant
to
5
U.
S.
C.
section
609(
b)
(
see
68
FR
28518­
28521,
May
23,
2003).
A
detailed
discussion
of
the
Panel's
advice
and
recommendations
can
be
found
in
the
Panel
Report
(
Docket
A­
2001­
28,
Document
No.
II­
A­
172).
See
also
section
III.
C
above.
461
We
have
also
prepared
a
Regulatory
Flexibility
Analysis
for
today's
rule.
The
Regulatory
Flexibility
Analysis
addresses
the
issues
raised
in
public
comments
on
the
IRFA,
which
was
part
of
the
proposal
of
this
rule.
The
Regulatory
Flexibility
Analysis
is
available
for
review
in
the
docket
and
is
summarized
below.
The
key
elements
of
a
regulatory
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
requirements
of
the
rule;
and
­
The
steps
taken
to
minimize
the
impact
of
the
rule
on
small
entities,
consistent
with
the
stated
objectives
of
the
applicable
statute.

1.
Need
For
and
Objectives
of
the
Rule
Controlling
emissions
from
nonroad
engines
and
equipment,
in
conjunction
with
controls
on
sulfur
concentrations
in
diesel
fuel,
has
very
significant
public
health
and
welfare
benefits,
as
explained
in
section
I
of
this
preamble.
We
are
finalizing
new
engine
standards
and
related
provisions
under
sections
213(
a)(
3)
and
(
4)
of
the
Clean
Air
Act
which,
among
other
things,
direct
us
to
establish
(
and
from
time
to
time
revise)
emission
standards
for
new
nonroad
diesel
engines.
Similarly,
section
211(
c)(
1)
authorizes
EPA
to
regulate
fuels
if
any
emission
product
of
the
fuel
causes
or
contributes
to
air
pollution
that
may
endanger
public
health
or
welfare,
or
that
may
impair
the
performance
of
emission
control
technology
on
engines
and
vehicles.
We
are
finalizing
new
fuel
standards
today
for
both
of
these
reasons.

2.
Summary
of
Significant
Public
Comments
on
the
IRFA
We
received
comments
from
engine
and
equipment
manufacturers,
fuel
refiners,
fuel
distributors
and
marketers,
and
consumers
during
the
public
comment
period
following
the
proposal
of
this
rulemaking.
All
of
the
following
comments
were
taken
into
account
in
developing
today's
final
rule.
Responses
to
these
comments
are
located
in
subsection
5
below,
along
with
the
description
of
the
provisions
that
we
are
finalizing
to
reduce
the
rule's
impact
on
small
businesses.
More
detailed
information
in
response
to
these
comments
can
be
found
in
sections
III.
C.
(
Engine
and
Equipment
Small
Business
Provisions)
and
IV.
B
(
Hardship
Relief
Provisions
for
Qualifying
Refiners)
of
this
preamble.
Additional
detail
may
also
be
found
in
the
Final
Regulatory
Flexibility
Analysis,
located
in
the
Regulatory
Impact
Analysis,
as
well
as
in
the
Summary
and
Analysis
of
Comments
for
this
final
rule.

a.
Public
Comments
Received
on
Engine
and
Equipment
Standards
One
small
engine
manufacturer
commented
that
the
proposed
provisions
for
small
business
engine
manufacturers
are
appropriate
and
strongly
supported
their
inclusion
in
the
final
rule.
The
462
manufacturer
raised
many
concerns
of
why
it
believes
that
it
is
necessary
to
include
provisions,
such
as:
larger/
higher­
volume
manufacturers
will
have
priority
in
supply
of
new
technologies
and
will
have
more
R&
D
time
to
complete
development
of
these
systems
before
they
are
available
to
smaller
manufacturers;
smaller
manufacturers
do
not
command
the
same
amount
of
attention
from
potential
suppliers
of
critical
technologies
for
Tier
4
controls,
and
are
thus
concerned
that
they
may
not
be
able
to
attract
a
manufacturer
to
work
with
them
on
the
development
of
compliant
technologies.
This
small
manufacturer
believes
that
the
additional
three­
year
time
period
proposed
for
small
engine
manufacturers
in
the
NPRM
is
necessary
for
the
company,
and
is
their
estimate
of
the
time
that
it
will
take
for
these
technologies
to
be
available
to
small
engine
manufacturers.

The
Small
Business
Administration's
Office
of
Advocacy
("
Advocacy")
raised
the
concern
that
the
rule
would
impose
significant
burdens
on
a
substantial
number
of
small
entities
producing
engines
of
75
hp
or
less,
with
little
corresponding
environmental
benefit.
Advocacy
therefore
recommended
that
PM
standards
for
engines
in
the
25­
75
hp
range
not
be
based
on
performance
of
aftertreatment
technologies.
Advocacy
believed
that
the
proposed
flexibilities
will
not
suffice
on
their
own
to
appropriately
minimize
the
regulatory
burdens
on
small
entities;
and
Advocacy
noted
that
during
the
SBREFA
process
some
small
equipment
manufacturers
stated
that
although
EPA
would
allow
some
equipment
to
be
sold
which
would
not
require
new
emissions
controls,
engine
manufacturers
would
not
produce
or
sell
such
equipment.
Advocacy
also
commented
that
we
have
not
shown
that
substantial
numbers
of
small
businesses
have
taken
advantage
of
previous
small
business
flexibilities,
or
that
small
businesses
would
be
able
to
take
advantage
of
the
flexibilities
under
this
rule.
Lastly,
Advocacy
commented
that
although
full
compliance
with
the
more
stringent
emissions
controls
requirements
would
be
delayed
for
small
manufacturers,
small
business
manufacturers
eventually
will
be
required
to
produce
equipment
meeting
the
new
requirements.

b.
Public
Comments
Received
on
Fuel
Standards
i.
General
Comments
on
Small
Refiner
Flexibility
One
small
refiner
commented
that
it
is
not
feasible
at
this
time
to
evaluate
the
impact
of
the
three
fuels
regulations
on
the
refining
industry
(
and
small
refiners),
however
it
stated
that
we
should
continue
to
evaluate
the
impacts
and
act
quickly
to
avoid
shortages
and
price
spikes
and
we
should
be
prepared,
if
necessary,
to
act
quickly
in
considering
changes
in
the
regulations
to
avoid
these
problems.
We
also
received
comment
that
some
small
refiners
that
produce
locomotive
and
marine
fuels
fear
that
future
sulfur
reductions
to
these
markets
could
be
very
damaging.

ii.
Comments
on
the
Small
Refiner
Definition
A
small
refiner
commented
that
the
proposed
redefinition
of
a
small
refiner
(
to
not
grandfather
as
small
refiners
those
that
were
small
for
highway
diesel)
would
both
negate
the
benefits
afforded
under
the
small
refiner
provisions
in
the
Highway
Diesel
Sulfur
rule
and
disqualify
its
status
as
a
small
refiner.
The
small
refiner
is,
however,
in
support
of
the
addition
of
the
capacity
limit
in
the
small
refiner
definition
which
will
correct
the
problem
of
the
inadvertent
loop­
hole
in
463
the
two
previous
fuel
rules.
Though
the
refiner
is
concerned
that
the
wording
of
the
proposed
language
may
result
in
small
refiners
such
as
itself,
who
grew
by
normal
business
practice,
being
disqualified
as
small
refiners.
The
refiner
suggested
that
we
clarify
the
language
and
include
provisions
for
continuance
of
small
refiner
flexibility
for
refiners
who
qualified
under
the
Highway
Diesel
Sulfur
rule
(
and
have
not
been
disqualified
as
the
result
of
a
merger
or
acquisition).

iii.
Comments
on
the
Baseline
Approach
A
coalition
of
small
refiners
provided
comments
on
a
few
aspects
of
concern.
The
small
refiners
believe
that
the
fuel
segregation,
and
ensuing
marking
and
dying,
provisions
are
quite
complex.
One
small
refiner
believes
that
mandating
a
minimum
volume
of
NRLM
production
would
conflict
with
the
purpose
of
maintaining
adequate
on­
highway
volumes
of
15ppm
sulfur
fuel
and
unnecessarily
restricts
small
refiners,
and
offered
suggestions
in
their
comments
on
how
to
improve
the
language.
In
addition,
the
small
refiner
believes
that
mandating
a
minimum
volume
of
NRLM
production
would
conflict
with
the
purpose
of
maintaining
adequate
on­
highway
volumes
of
15ppm
sulfur
fuel
and
unnecessarily
restricts
small
refiners,
and
offered
suggestions
in
their
comments
on
how
to
improve
the
language.

iv.
Comments
on
Small
Refiner
`
Option
4'

A
coalition
of
small
refiners
commented
that
if
the
final
rule
is
not
issued
before
January
1,
2004,
a
provision
should
be
made
to
accommodate
those
small
refiners
planning
to
take
advantage
of
the
proposed
small
refiner
"
Option
4"
(
the
NRLM/
Gasoline
Compliance
option).
A
small
refiner
echoed
the
concerns
of
the
small
refiner
coalition,
commenting
that
delayed
finalization
of
the
final
rule
would
undermine
the
benefits
of
small
refiner
flexibility
Option
4.
The
small
refiner
is
concerned
that
a
delay
in
issuing
the
rule,
and
subsequent
delay
in
the
opportunity
to
apply
the
interim
gasoline
flexibility,
would
negate
its
opportunity
to
take
full
advantage
of
the
credits
the
refiner
now
has,
as
it
would
not
be
able
to
comply
with
the
300
ppm
cap.
The
small
refiner
suggested
that
we
allow
small
refiners
to
apply
for
temporary
relief
and
operate
under
the
Option
4
provision.
Another
small
refiner
commented
that,
in
the
NPRM,
it
was
unclear
if
a
small
refiner
could
elect
to
use
any
or
all
of
the
first
three
of
the
small
refiner
provisions
if
it
did
not
elect
to
use
Option
4.
Further,
the
refiner
understood
that
if
Option
4
was
chosen,
a
small
refiner
could
not
use
any
of
the
first
three
options.
The
refiner
believes
that
it
is
important
that
a
small
refiner
be
able
to
use
Options
1,
2,
and
3
in
combination
with
each
other,
and
stated
that
we
need
to
clarify
the
intent
in
the
final
rule.
The
small
refiner
also
commented
that
the
provisions
in
40
CFR
§
§
80.553
and
80.554
are
not
clear
and
should
be
revised
to
clarify
their
intent.
Specifically,
the
refiner
questioned
whether
or
not
a
small
refiner
who
committed
to
producing
ULSD
by
June
1,
2006
in
exchange
for
an
extension
of
its
interim
gasoline
sulfur
standards
(
under
40
CFR
80.553)
could
elect
to
exercise
the
options
allowed
under
40
CFR
80.554.

A
small
refiner
raised
the
concern
that
the
small
refiner
Option
4
only
provides
an
adjustment
to
those
small
refiners
whose
small
refiner
gasoline
sulfur
standards
were
established
through
the
hardship
process
of
40
CFR
80.240.
The
small
refiner
suggested
that
we
finalize
a
464
compliance
option
that
allows
a
20
percent
increase
in
small
refiner
gasoline
sulfur
standards
be
extended
to
all
small
refiners,
not
just
those
with
standards
established
pursuant
40
CFR
80.240(
a),
and
offers
suggested
language
in
its
comments.

v.
Comments
on
Emission
Impacts
of
the
Small
Refiner
Provisions
A
state
environmental
group
commented
that
the
provisions
for
small
refiners
raise
substantial
environmental
concerns.
The
group
is
concerned
that
these
provisions
will
allow
small
refiners
the
ability
to
produce
gasoline
with
an
unknown
sulfur
content
for
an
unknown
length
of
time;
this
fuel
may
then
be
sold
at
the
refiner's
retail
outlet,
and
may
become
the
primary
fuel
for
some
vehicles,
which
alters
vehicle
fleet
emissions
performance.
This
environmental
group
also
commented
that
the
absence
of
any
process
of
notification
regarding
small
business
provisions
to
notify
States
of
these
provisions
is
troubling.
The
concern
is
that
these
deviations
from
fuel
content
that
affects
fuels
consumed
in
states
that
use
emissions
inventories
for
air
quality
planning
purposes,
and
can
significantly
alter
inventories.
The
group
suggested
that
in
the
future
there
should
be
greater
communication
from
us
regarding
decisions
that
impact
the
quality
of
fuels
consumed
in
a
state,
and
thus
impact
the
quality
of
that
state's
air.

Another
state
environmental
group
commented
on
the
flexibility
provisions
for
small
refiners;
the
group
is
concerned
that
the
exemption
will
not
have
a
minor
effect
on
the
nation's
fuel
supply,
as
the
state
is
an
intermountain
western
state.
The
group
comments
that
the
impact
of
this
exemption
is
concentrated
in
these
states,
namely
Washington
and
Oregon
 
states
which
are
served
primarily
by
refineries
that
will
be
allowed
to
delay
compliance
with
the
ULSD
standards
until
2014.
Therefore,
the
group
commented,
residents
of
these
areas
are
denied
air
quality
benefits
equivalent
to
those
promised
the
rest
of
the
country.
Those
seeking
to
purchase
and
use
equipment
in
these
areas
will
be
subject
to
the
ULSD
standard
regardless
of
fuel
supply
and
availability
in
their
area,
would
be
faced
with
misfueling,
deferring
purchase
of
new
equipment,
or
paying
a
premium
for
a
"
boutique"
fuel.

vi.
Comments
on
Inclusion
of
a
Crude
Capacity
Limit
for
Small
Refiners
and
Leadtime
Afforded
for
Mergers
and
Acquisitions
A
non­
small
refiner
supported
the
inclusion
of
the
155,000
bpcd
limit,
but
suggested
that
we
limit
the
provision
of
affording
a
two­
year
leadtime
to
small
refiners
who
lose
their
small
status
due
to
merger
or
acquisition
to
the
case
where
a
small
refiner
merges
with
another
small
refiner.
Further,
the
refiner
commented
that
it
would
be
inappropriate
to
allow
such
small
refiners
to
be
able
to
generate
credits
for
"
early"
production
of
lower
sulfur
diesels
during
this
two­
year
leadtime.
Lastly,
the
refiner
commented
that
a
small
refiner
which
acquires
a
non­
small
refiner,
and
thus
loses
its
small
refiner
status,
should
not
be
eligible
for
hardship
provisions.
Another
commenter
stated
that
if
we
were
to
finalize
the
155,000
bpcd
limit,
we
should
not
apply
it
in
cases
of
a
merger
between
two
small
refiners.
The
commenter
further
stated
that
a
merger
of
two
small
companies
in
a
hardship
condition
does
not
imply
improved
financial
health
in
the
same
way
that
an
acquisition
would.
Another
non­
small
refiner
commented
that
it
supports
the
two­
year
lead
time
252
All
sales
information
used
for
this
analysis
was
2000
data.

465
for
refineries
that
lose
their
status
as
a
small
refiner;
the
refiner
believes
that
any
refiner
with
the
financial
wherewithal
to
acquire
additional
refineries
to
allow
its
crude
capacity
to
exceed
155,000
bpcd
should
not
be
able
to
retain
status
as
a
small
refiner.

vii.
Necessity
of
Small
Refiner
Program
A
non­
small
refiner
provided
comment
on
the
NPRM
stating
the
belief
that
the
proposed
provisions
for
small
refiners
are
not
practical.
The
refiner
is
concerned
that
having
provisions
for
small
refiners
adds
a
level
of
complication,
results
in
emissions
losses,
increases
the
potential
for
ULSD
contamination,
and
create
an
unfair
situation
in
the
marketplace.
Similarly,
another
nonsmall
refiner
and
a
trade
group
representing
many
refiners
and
others
in
the
fuels
industry
commented
that
they
oppose
the
extension
of
compliance
deadlines
for
small
refiners,
as
this
can
result
in
inequitable
situations
that
may
affect
the
refining
industry
for
some
time
and
can
put
the
distribution
system
at
risk
for
contamination
of
lower
sulfur
fuels.
They
further
stated
that
all
refiners
will
face
challenges
in
complying
with
the
upcoming
standards
and
would
not
significantly
alter
the
business
decisions
that
small
refiners
would
make.
They
also
stated
that
non­
small
refiners
face
similar
issues
with
their
older
and/
or
smaller
refineries,
but
will
not
have
the
benefit
of
being
able
to
postpone
making
these
decisions
as
small
refiners
will.

viii.
Comments
on
Fuel
Marker
We
received
comments
from
terminal
operators
stating
that
the
proposed
heating
oil
marker
requirements
would
force
small
terminal
operators
to
install
expensive
injection
equipment
and
that
they
would
not
be
able
to
recoup
the
costs.

3.
Types
and
Number
of
Small
Entities
The
small
entities
directly
regulated
by
this
final
rule
are
nonroad
diesel
engine
and
equipment
manufacturers,
nonroad
diesel
fuel
refiners,
and
nonroad
diesel
fuel
distributors
and
marketers.
These
categories
are
described
in
more
detail
below,
and
the
definitions
of
small
entities
in
those
categories
are
listed
in
table
X.
C­
1
above.

a.
Nonroad
Diesel
Engine
Manufacturers
Before
beginning
the
SBREFA
process,
EPA
conducted
an
industry
profile
for
the
nonroad
diesel
sector.
We
have
not
received
any
new
information
since
that
time
and
we
continue
to
believe
that
this
is
a
valid
characterization
of
the
industry.
Using
information
from
the
industry
profile,
EPA
identified
a
total
of
61
engine
manufacturers.
The
top
10
engine
manufacturers
comprise
80
percent
of
the
total
market,
while
the
other
51
companies
make
up
the
remaining
20
percent.
252
Of
the
61
manufacturers,
four
fit
the
SBA
definition
of
a
small
entity.
These
four
manufacturers
were
Anadolu
Motors,
Farymann
Diesel
GMBH,
Lister­
Petter
Group,
and
V
&
L
466
Tools
(
parent
company
of
Wisconsin
Motors
LLC,
formerly
"
Wis­
Con
Total
Power").
These
businesses
comprised
eight
percent
of
the
total
nonroad
engine
sales
for
the
year
2000.

b.
Nonroad
Diesel
Equipment
Manufacturers
We
also
used
the
industry
profile
to
determine
the
number
of
nonroad
small
business
equipment
manufacturers.
EPA
identified
over
700
manufacturers
with
sales
and/
or
employment
data
that
could
be
included
in
the
screening
analysis.
These
businesses
included
manufacturers
in
the
construction,
agricultural,
mining,
and
outdoor
power
equipment
(
mainly,
lawn
and
garden
equipment)
sectors
of
the
nonroad
diesel
market.
The
equipment
produced
by
these
manufacturers
ranged
from
small
walk­
behind
equipment
(
sub­
25
hp
engines)
to
large
mining
and
construction
equipment
(
using
engines
in
excess
of
750
hp).
Of
the
manufacturers
with
available
sales
and
employment
data
(
approximately
500
manufacturers),
nonroad
small
business
equipment
manufacturers
represent
68
percent
of
total
nonroad
equipment
manufacturers
(
and
these
manufacturers
accounted
for
11
percent
of
nonroad
diesel
equipment
industry
sales
in
2000).

c.
Nonroad
Diesel
Fuel
Refiners
Our
current
assessment
is
that
26
refiners
(
collectively
owning
33
refineries)
meet
SBA's
definition
of
a
small
business
for
the
refining
industry.
The
33
refineries
appear
to
meet
both
the
employee
number
and
production
volume
criteria
mentioned
above.
These
small
refiners
currently
produce
approximately
6
percent
of
the
total
high­
sulfur
diesel
fuel.
It
should
be
noted
that
because
of
the
dynamics
in
the
refining
industry
(
e.
g.,
mergers
and
acquisitions),
the
actual
number
of
refiners
that
ultimately
qualify
for
small
refiner
status
under
the
nonroad
diesel
sulfur
program
could
be
different
than
this
assessment.

d.
Nonroad
Diesel
Fuel
Distributors
and
Marketers
The
industry
that
transports,
distributes,
and
markets
nonroad
diesel
fuel
encompasses
a
wide
range
of
businesses,
including
bulk
terminals,
bulk
plants,
fuel
oil
dealers,
and
diesel
fuel
trucking
operations,
and
totals
thousands
of
entities
that
have
some
role
in
this
activity.
Over
90
percent
of
these
entities
meet
small
entity
criteria.
Common
carrier
pipeline
companies
are
also
a
part
of
the
distribution
system;
10
of
them
are
small
businesses.

4.
Reporting,
Recordkeeping
and
Other
Compliance
Requirements
This
section
describes
the
expected
burden
of
the
compliance
requirements
(
for
all
manufacturers
and
refiners)
for
the
standards
being
finalized
in
today's
action.

a.
Nonroad
Diesel
Engine
and
Equipment
Manufacturers
For
engine
and
equipment
standards,
we
must
have
the
assurance
that
engines
and/
or
equipment
produced
by
manufacturers
meet
the
applicable
standard,
and
will
continue
to
meet
this
467
standard
as
the
equipment
passes
through
to
the
ultimate
end
user.
We
are
continuing
many
of
the
reporting,
recordkeeping,
and
compliance
requirements
prescribed
for
nonroad
engines
and
equipment,
as
set
out
in
40
CFR
part
89.
These
include,
certification
requirements
and
reporting
of
production,
emissions
information,
use
of
transition
provisions,
etc.
The
types
of
professional
skills
required
to
prepare
reports
and
records
are
also
similar
to
the
types
of
skills
that
were
needed
to
meet
the
regulatory
requirements
set
out
in
40
CFR
part
89.
Key
differences
in
the
requirements
of
today's
rule
as
related
to
40
CFR
part
89
are
the
additional
testing
and
defect
reporting.
We
are
finalizing
an
increase
in
the
number
of
data
points
(
i.
e.,
transient
testing)
that
will
be
required
for
reporting
emissions
information.
Also,
as
proposed,
we
are
requiring
additional
defect
reporting
for
Tier
4
and
later
engines.
We
are
requiring
that
manufacturers
report
to
us
if
they
learn
that
a
substantial
number
of
their
engines
have
emission­
related
defects.
This
is
generally
not
a
requirement
to
collect
information;
however
if
manufacturers
learn
that
there
are
or
might
be
a
substantial
number
of
emission­
related
defects,
then
they
must
send
us
information
describing
the
defects.

b.
Nonroad
Diesel
Fuel
Refiners,
Distributors,
and
Marketers
For
any
fuel
control
program,
we
must
have
the
assurance
that
fuel
produced
by
refiners
meets
the
applicable
standard,
and
that
the
fuel
continues
to
meet
this
standard
as
it
passes
downstream
through
the
distribution
system
to
the
ultimate
end
user.
This
is
particularly
important
in
the
case
of
diesel
fuel,
where
the
aftertreatment
technologies
expected
to
be
used
to
meet
the
engine
standards
are
highly
sensitive
to
sulfur.
Many
of
the
recordkeeping,
reporting
and
compliance
provisions
of
the
today's
action
are
fairly
consistent
with
those
in
place
today
for
other
fuel
programs,
including
the
current
15
ppm
highway
diesel
regulation.
For
example,
recordkeeping
involves
the
use
of
product
transfer
documents,
which
are
already
required
under
the
15
ppm
highway
diesel
sulfur
rule
(
40
CFR
80.560).
Under
today's
final
rule
we
are
adding
additional
recordkeeping
and
reporting
requirements
for
refiners,
importers,
and
fuel
distributors
to
implement
the
designate
and
track
provisions.
However,
interactions
with
parties
from
all
segments
of
the
distribution
system
indicated
that
the
records
necessary
were
analogous
to
records
already
kept
as
a
normal
process
of
doing
business.
Consequently,
the
only
significant
additional
burden
would
be
associated
with
the
reporting
requirement.

General
requirements
for
reporting
for
refiners
and
importers
include:
registration
(
only
in
the
case
where
a
refiner
or
importer
is
not
registered
under
a
previous
fuel
program),
precompliance
reports
(
on
a
refiner
or
importer's
progress
towards
meeting
the
nonroad
diesel
fuel
requirements
as
specified
in
this
rule),
quarterly
designation
reports,
and
annual
reports.
All
parties
from
the
refiner
to
the
terminal
will
be
required
to
report
volumes
of
designated
fuels
received
and
distributed,
as
well
as
compliance
with
quarterly
and
annual
limits.
All
parties
in
the
distribution
system
are
required
to
keep
product
transfer
documents
(
PTDs),
though
refiners
and
importers
are
required
to
initially
generate
and
provide
information
on
commercial
PTDs
that
identify
the
diesel
fuel
with
meeting
specific
needs
(
i.
e.,
15
ppm
highway
diesel,
500
ppm
highway
diesel,
etc.).
Also,
refiners
in
Alaska
and
small
refiner/
credit
fuel
users
must
report
end
users
of
468
their
fuel.
These
end
users
must
also
keep
records
of
these
fuel
purchases.
Lastly,
small
refiners
are
required
to
apply
for
small
refiner
status
and
small
refiner
baselines.

In
general,
we
are
requiring
that
all
records
be
kept
for
at
least
five
years.
This
recordkeeping
requirement
should
impose
little
additional
burden,
as
five
years
is
the
applicable
statute
of
limitations
for
current
fuel
programs.

See
section
X.
B,
above,
for
a
discussion
of
the
estimated
burden
hours
and
costs
of
the
recordkeeping
and
reporting
that
will
be
required
by
this
final
rule.
Detailed
information
on
the
reporting
and
recordkeeping
measures
associated
with
this
rulemaking
are
described
in
the
Information
Collection
Requests
(
ICRs)
for
this
rulemaking
 
1897.05
for
nonroad
diesel
engines,
and
1718.05
for
fuel­
related
items.

5.
Regulatory
Alternatives
To
Minimize
Impact
on
Small
Entities
Below
we
discuss
the
Panel
recommendations,
EPA
proposals,
and
final
regulatory
alternatives
to
minimize
the
rule's
impact
on
small
entities.
More
detailed
information
on
the
provisions
for
these
entities
can
be
found
in
sections
III.
C
and
IV.
B
of
this
preamble
(
for
small
business
engine
and
equipment
manufacturers
and
small
entities
throughout
the
fuel
distribution
system,
respectively).

a.
Panel
Recommendations
During
the
SBREFA
process,
the
Panel
recommended
transition
flexibilities
that
we
considered
during
the
development
of
the
NPRM.
The
Panel
recommended
provisions
for
both
the
one­
step
and
two­
step
options.
Since
we
are
finalizing
a
two­
step
approach,
only
the
recommendations
for
this
approach
are
being
discussed
here.
(
A
complete
discussion
of
all
of
the
Panel
recommendations
and
our
proposals
for
small
entities
is
located
in
section
X.
C.
of
the
NPRM.)

Following
the
SBREFA
process,
the
Panel
(
or
some
Panel
members),
recommended
the
following
transition
flexibilities
and
hardship
provisions
to
help
mitigate
the
impacts
of
the
rulemaking
on
small
entities.
We
proposed
and
requested
comment
on
these
recommendations
in
the
NPRM.

i.
Panel
Recommendations
for
Small
Business
Engine
Manufacturers
For
nonroad
diesel
small
business
engine
manufacturers,
we
proposed
the
following
provisions:
°
a
manufacturer
must
have
certified
in
model
year
2002
or
earlier
and
would
be
limited
to
2500
units
per
year
to
be
eligible
for
all
provisions
set
out
below;
°
for
PM­
253
There
is
no
change
in
the
NOX
standard
for
engines
under
25
hp
and
those
between
50
and
75
hp.
For
these
two
power
bands
EPA
proposed
no
special
provisions.

469
­
small
engine
manufacturers
could
delay
compliance
with
the
standards
for
up
to
three
years
for
engines
under
25
hp,
and
those
between
75
and
175
hp
(
as
these
engines
only
have
one
standard)
­
small
engine
manufacturers
have
the
option
to
delay
compliance
for
one
year
if
interim
standards
are
met
for
engines
between
50
and
75
hp
(
for
this
power
category
we
are
treating
the
PM
standard
as
a
two
phase
standard
with
the
stipulation
that
small
manufacturers
cannot
use
PM
credits
to
meet
the
interim
standard;
also,
if
a
small
manufacturer
elects
the
optional
approach
to
the
standard
(
elects
to
skip
the
interim
standard),
no
further
relief
will
be
provided)
°
for
NOx253­
­
a
three
year
delay
in
the
program
for
engines
in
the
25­
50
hp
and
the
75­
175
hp
categories,
consistent
with
the
one­
phase
approach
recommendation
above;
°
a
small
engine
manufacturer
could
be
afforded
up
to
two
years
of
hardship
(
in
addition
to
the
transition
flexibilities)
upon
demonstrating
to
EPA
a
significant
hardship
situation;
°
small
engine
manufacturers
would
be
able
to
participate
in
an
averaging,
banking,
and
trading
(
ABT)
program
(
which
we
proposed
as
part
of
the
overall
rulemaking
program
for
all
manufacturers);
°
engines
under
25
hp
would
not
be
subject
to
standards
based
on
use
of
advanced
aftertreatment;
and,
°
no
NO
X
aftertreatment­
based
standards
for
engines
75
hp
and
under.

ii.
Panel
Recommendations
for
Small
Business
Equipment
Manufacturers
We
proposed
the
following
provisions
for
nonroad
diesel
small
business
equipment
manufacturers:
°
small
business
nonroad
diesel
equipment
manufacturers
must
have
reported
equipment
sales
using
certified
engines
in
model
year
2002
or
earlier
to
be
eligible
for
all
provisions;
°
essential
continuance
of
the
transition
flexibilities
offered
for
the
Tier
1
and
Tier
2
nonroad
diesel
emission
standards
(
40
CFR
89.102),
which
are
available
to
all
nonroad
diesel
equipment
manufacturers
S
`
percent­
of­
production
allowance'­
over
seven
model­
year
period
manufacturers
may
install
engines
not
certified
to
the
new
emission
standards
in
an
amount
of
equipment
equivalent
to
80
percent
of
one
year's
production,
implemented
by
power
category
with
the
average
determined
over
the
period
in
which
the
flexibility
is
used
(
this
proposal
would
afford
additional
flexibility
over
the
comparable
470
flexibility
in
Tier
2/
3,
however,
because
of
the
smaller
number
of
horsepower
categories
in
the
Tier
4
rule)
­
`
small
volume
allowance'­
a
manufacturer
may
exceed
the
80
percent
allowance
in
seven
years
as
described
above,
provided
that
the
previous
Tier
engine
use
does
not
exceed
700
total
over
seven
years,
and
200
in
any
given
year,
limited
to
one
family
per
power
category;
alternatively,
at
the
manufacturer's
choice
by
horsepower
category,
a
program
that
eliminates
the
"
single
family
provision"
restriction
with
revised
total
and
annual
sales
limits
as
shown
below:
<
175
hp:
525
previous
Tier
engines
(
over
7
years)
with
an
annual
cap
of
150
units
(
separate
for
each
hp
category)
>
175
hp:
350
previous
Tier
engines
(
over
7
years)
with
an
annual
cap
of
100
units
(
separate
for
each
hp
category);
°
small
business
equipment
manufacturers
would
be
allowed
to
borrow
from
the
Tier
3/
Tier
4
flexibilities
for
use
in
the
Tier
2/
Tier
3
time
frame;
and,
°
small
business
equipment
manufacturers
could
be
afforded
up
to
two
years
of
hardship
after
other
transition
allowances
are
exhausted,
similar
to
that
offered
small
business
engine
manufacturers.

In
addition,
we
proposed
the
Panel's
recommendation
that
the
provisions
for
small
equipment
manufacturers
be
extended
to
all
equipment
manufacturers,
regardless
of
size.
We
also
sought
comment
on
the
total
number
of
engines
and
annual
cap
values
proposed
and
on
implementing
the
small
volume
allowance
provision
without
a
limit
on
the
number
of
engine
families.

iii.
Panel
Recommendations
for
Small
Refiners,
Distributors,
and
Marketers
The
following
provisions
were
proposed
for
nonroad
diesel
small
refiners:
°
small
refiners
would
be
required
to
use
500
ppm
sulfur
fuel
beginning
June
1,
2010
and
15
ppm
fuel
beginning
June
1,
2014;
°
small
refiners
may
choose
one
of
the
following
transition
provisions,
which
serve
to
encourage
early
compliance
with
the
diesel
fuel
sulfur
standards:
­
Credits
for
Early
Desulfurization:
would
allow
small
refiners
to
generate
and
sell
credits
for
nonroad
diesel
fuel
that
meets
the
small
refiner
standards
earlier
than
required
in
the
regulation;
or,
­
Limited
Relief
on
Small
Refiner
Interim
Gasoline
Sulfur
Standards:
a
small
refiner
producing
its
entire
nonroad
diesel
fuel
pool
at
15
ppm
sulfur
by
June
1,
2006,
and
who
chooses
not
to
generate
nonroad
credits
for
early
compliance,
would
receive
a
20
percent
relaxation
in
its
assigned
small
refiner
interim
gasoline
sulfur
standards
(
with
the
maximum
per­
gallon
sulfur
cap
for
any
small
refiner
remaining
at
450
ppm);
and,
471
°
a
small
refiner
would
be
afforded
hardship
similar
to
the
provisions
established
under
40
CFR
80.270
and
80.560
(
the
gasoline
sulfur
and
highway
diesel
fuel
sulfur
programs,
respectively),
case­
by­
case
approval
of
hardship
applications
must
be
sought
based
on
demonstration
of
extreme
hardship
circumstances.

We
did
not
propose
specific
provisions
for
nonroad
diesel
fuel
distributors
and
marketers
in
the
NPRM.
During
the
SBREFA
process,
distributors
commented
that
they
would
support
a
onestep
approach
to
eliminate
the
possibility
of
having
multiple
grades
of
fuel
in
the
distribution
system
and
the
Panel
recommended
that
we
further
study
this
issue
during
the
development
of
the
rule.

iv.
Additional
Panel
Recommendations
Some,
but
not
all,
Panel
members
recommended
that
the
following
provisions
be
included
in
the
NPRM;
we
requested
comment
on
these
items
but
did
not
propose
them:
°
the
inclusion
of
a
technological
review
of
the
standards
in
the
2008
time
frame
°
no
PM
aftertreatment­
based
standards
for
engines
between
25
and
75
hp
b.
Discussion
of
Items
Being
Finalized
in
Today's
Action
i.
Provisions
for
Small
Business
Engine
Manufacturers
For
nonroad
diesel
small
business
engine
manufacturers,
we
are
finalizing
many
of
the
provisions
set
out
above
with
some
significant
revisions,
as
described
below.
We
are
finalizing
all
of
the
hardship
provisions
that
we
proposed.
We
believe
these
provisions
are
an
element
of
providing
appropriate
lead
time
for
this
class
of
engines.

For
engines
under
25
hp:
°
PM­
a
manufacturer
may
elect
to
delay
compliance
with
the
standard
for
up
to
three
years.
°
NOx­
there
is
no
change
in
the
existing
NO
X
standard
for
engines
in
this
category,
so
no
special
provisions
are
being
provided.

For
engines
in
the
25
to
50
hp
category:
°
PM­
manufacturers
must
comply
with
the
interim
standards
(
the
Tier
4
requirements
that
begin
in
model
year
2008)
on
time,
and
may
elect
to
delay
compliance
with
the
2013
Tier
4
requirements
(
0.02
g/
bhp­
hr
PM
standard)
for
up
to
three
years.
°
NOx­
a
manufacturer
may
elect
to
delay
compliance
with
the
standard
for
up
to
three
years.
254
As
the
cost
issues
raised
in
SBA's
comments
relate
to
all
manufacturers
(
not
just
small
business
manufacturers),
further
information
on
the
costs
of
this
technology
as
well
as
the
benefits
analysis,
can
be
found
in
section
VI
of
this
preamble
(
and
also
chapters
6
and
9,
respectively,
of
the
Regulatory
Impact
Analysis).

472
For
engines
in
the
50
to
75
hp
category:
°
PM­
A
small
business
engine
manufacturer
may
delay
compliance
with
the
2013
Tier
4
requirement
of
0.02
g/
bhp­
hr
PM
for
up
to
three
years
provided
that
it
complies
with
the
interim
Tier
4
requirements
that
begin
in
model
year
2008
on
time,
without
the
use
of
credits
(
as
manufacturers
of
engines
in
this
category
still
have
the
option
to
comply
with
the
Tier
3
standard).
Alternatively,
a
manufacturer
may
elect
to
skip
the
interim
standard
completely.
Manufacturers
choosing
this
option
will
receive
only
one
additional
year
for
compliance
with
the
0.02
g/
bhp­
hr
standard
(
i.
e.
compliance
in
2013,
rather
than
2012).
°
NO
X
­
there
is
no
change
in
the
NO
X
standard
for
engines
in
this
category,
therefore
no
special
provisions
are
being
provided.

For
engines
in
the
75
to
175
hp
category:
°
PM­
a
manufacturer
may
elect
to
delay
compliance
with
the
standard
for
up
to
three
years.
°
NOx­
a
manufacturer
may
elect
to
delay
compliance
with
the
standard
for
up
to
three
years.

In
regard
to
the
Office
of
Advocacy's
concern
regarding
the
technical
feasibility
of
PM
and
NO
X
aftertreatment
devices,
as
proposed
in
the
NPRM,
we
are
not
adopting
standards
based
on
performance
of
NO
X
aftertreatment
technologies
for
engines
under
75
hp.
We
believe
the
factual
record
 
as
documented
in
the
RIA,
the
Summary
and
Analysis
of
Comments,
and
this
preamble
 
does
not
support
the
claim
that
the
PM
standards
will
not
be
technically
feasible
in
2013
for
the
25­
75
hp
engines.
As
set
out
at
length
in
section
4.1.3
of
the
RIA,
among
other
places,
performance
of
PM
traps
is
not
dependent
on
engine
size.

We
disagree
with
the
statement
made
by
the
Office
of
Advocacy
that,
based
on
available
information,
we
do
not
have
a
sufficient
basis
for
engines
between
25
and
75
hp
to
be
subject
to
PM
standards
based
on
use
of
advanced
aftertreatment.
As
we
have
documented
earlier
and
in
the
RIA,
we
believe
that
such
standards
are
feasible
for
these
engines
at
reasonable
cost,
254
and
will
help
to
improve
very
important
air
quality
problems,
especially
by
reducing
exposure
to
diesel
PM
and
by
aiding
in
attainment
of
the
PM
2.5
National
Ambient
Air
Quality
Standard.
See
generally,
comment
response
8.2.3
of
the
Summary
and
Analysis
of
Comments,
and
sections
12.6.2.2.9
and
12.6.2.2.10
of
chapter
12
of
the
Draft
RIA.
These
standards
will
also
result
in
significant
reductions
of
NMHC,
which
includes
many
carcinogenic
air
toxics.
Indeed,
given
these
facts,
we
are
skeptical
that
an
alternative
of
no
aftertreatment­
based
PM
standards
for
these
engines
would
be
appropriate
under
section
213(
a)(
4)
of
the
Clean
Air
Act
(
see
section
VII.
A
above,
where
we
473
found
that
"[
w]
e
...
do
not
see
a
basis
in
law
or
policy
to
adopt
either
of
these
options").
We
believe
that
the
transition
and
hardship
provisions
being
finalized
for
small
business
engine
manufacturers
in
today's
action
are
reasonable
and
are
a
factor
in
our
ultimate
finding
that
the
PM
standards
for
engines
in
the
25
 
75
hp
range
are
appropriate.

ii.
Provisions
for
Small
Business
Equipment
Manufacturers
The
transition
and
hardship
provisions
that
were
proposed
for
small
business
nonroad
equipment
manufacturers
are
being
finalized
today,
with
some
modifications.

Adopting
an
alternative
on
which
we
solicited
comment,
the
final
rule
allows
all
equipment
manufacturers
the
opportunity
to
choose
between
two
options:
a)
manufacturers
would
be
allowed
to
exempt
700
pieces
of
equipment
over
seven
years,
with
one
engine
family;
or
b)
manufacturers
using
the
small­
volume
allowance
could
exempt
525
machines
over
seven
years
(
with
a
maximum
of
150
in
any
given
year)
for
each
of
the
three
power
categories
below
175
horsepower,
and
350
machines
over
seven
years
(
with
a
maximum
of
100
in
any
given
year)
for
the
two
power
categories
above
175
horsepower.
Concurrent
with
the
revised
caps,
manufacturers
could
exempt
engines
from
more
than
one
engine
family
under
the
small­
volume
allowance
program.
Based
on
sales
information
for
small
businesses,
we
estimated
that
the
alternative
small­
volume
allowance
program
to
include
lower
caps
and
allow
manufacturers
to
exempt
more
than
one
engine
family
would
keep
the
total
number
of
engines
eligible
for
the
allowance
at
roughly
the
same
overall
level
as
the
700­
unit
program.
We
believe
that
these
provisions
will
afford
small
manufacturers
the
type
of
transition
leeway
recommended
by
the
Panel.
Further,
these
transition
provisions
could
allow
small
business
equipment
manufacturers
to
postpone
any
redesign
needed
on
low
sales
volume
or
difficult
equipment
packages,
thus
saving
both
money
and
strain
on
limited
engineering
staffs.
Within
limits,
small
business
equipment
manufacturers
would
be
able
to
continue
to
use
their
current
engine/
equipment
configuration
and
avoid
out­
of­
cycle
equipment
redesign
until
the
allowances
are
exhausted
or
the
time
limit
passes.

We
are
not
finalizing
the
requirement
that
small
equipment
manufacturers
and
importers
have
reported
equipment
sales
using
certified
engines
in
model
year
2002
or
earlier.
Please
see
section
III.
C.
2.
a.
ii
above
for
a
detailed
discussion
on
our
decision
to
eliminate
this
requirement
from
today's
rule.

We
are
also
finalizing
three
additional
provisions
today.
Two
of
these
provisions
are
being
finalized
for
all
equipment
manufacturers,
and
therefore
small
business
equipment
manufacturers
may
also
take
advantage
of
them.
These
are
the
Technical
Hardship
Provision
and
the
Early
Tier
4
Engine
Incentive
Program,
and
are
discussed
in
greater
detail
in
sections
III.
B.
2.
b
and
e
above.
The
third
provision
is
being
finalized
for
small
business
equipment
manufacturers
only,
for
the
20­
50
hp
category.
This
provision
is
discussed
in
greater
detail
in
section
III.
C.
2.
b.
ii
above.
255
Since
new
engines
with
sulfur
sensitive
emission
controls
will
begin
to
become
widespread
during
this
time,
small
refiner
fuel
will
need
to
be
segregated
and
only
supplied
for
use
in
pre­
2011
nonroad
equipment
or
in
locomotives
or
marine
engines.

474
iii.
Provisions
for
Small
Refiners
As
previously
discussed,
we
are
finalizing
standards
for
locomotive
and
marine
diesel
fuel
today.
Below
are
the
regulatory
transition
and
hardship
provisions
that
we
are
finalizing
to
minimize
the
degree
of
hardship
imposed
upon
small
refiners
by
this
program.
With
these
provisions
we
are
confident
about
going
forward
with
the
500
ppm
sulfur
standard
for
NRLM
diesel
fuel
in
2007,
and
the
15
ppm
sulfur
standard
for
nonroad
diesel
fuel
in
2010
and
locomotive
and
marine
diesel
fuel
in
2012,
for
the
rest
of
the
industry.
Given
the
small
refiner
relief
provisions
that
are
being
finalized
today,
small
refiners
will
be
the
only
refiners
permitted
to
continue
selling
500
ppm
fuel
to
nonroad,
locomotive,
and
marine
markets
from
2010
until
2014
without
the
use
of
credits.

We
are
finalizing
delayed
compliance
for
small
refiners
today
("
NRLM
Delay"
option).
We
are
confident
with
going
forward
with
these
sulfur
standards
given
the
regulatory
transition
provisions
being
offered
for
small
refiners.
These
delayed
standards
would
allow
for
the
continued
production
of
higher
sulfur
NRLM
fuel
until
June
1,
2010,
and
similarly,
for
the
production
of
500
ppm
NRLM
fuel
until
June
1,
2014.255
This
is
identical
to
the
relief
proposed
in
the
NPRM
(
which
small
refiners
considered
sufficient
and
supported)
with
the
exception
that
it
applies
not
only
to
nonroad
fuel,
but
also
to
locomotive
and
marine
fuel
given
the
decision
to
finalize
15
ppm
sulfur
standards
for
locomotive
and
marine
diesel
fuel.
Table
X.
C­
2
below
illustrates
the
delayed
standards
in
relation
to
the
general
program.
This
delay
option
is
not
being
finalized
for
the
Northeast
and
mid­
Atlantic
areas
due
to
the
removal
of
the
heating
oil
marker
in
these
areas.
However
this
is
not
expected
to
impact
small
refiners,
and
this
will
provide
significant
relief
for
small
terminal
operators.
Further,
this
provision
will
be
finalized
in
Alaska
only
if
a
refiner
gets
an
approved
compliance
plan
for
segregating
their
fuel
to
the
end
user.

We
also
are
finalizing
transition
provisions
to
encourage
early
compliance
with
the
standards
being
finalized
today.
These
provisions
are:

°
The
NRLM
credit
option­
Some
small
refiners
have
indicated
that
they
might
need
to
produce
fuel
meeting
the
NRLM
diesel
fuel
sulfur
standards
earlier
than
required
under
the
small
refiner
program
described
above
(
distribution
systems
might
limit
the
number
of
grades
of
diesel
fuel
that
will
be
carried,
it
may
be
economically
advantageous
to
make
compliant
NRLM
diesel
fuel
earlier
to
prevent
losing
market
share,
etc.)
This
option
allows
small
refiners
to
participate
in
the
NRLM
diesel
fuel
sulfur
credit
banking
and
trading
program
discussed
in
section
IV.
Generating
and
selling
256
This
is
down
from
the
100
percent
requirement
proposed
to
allow
for
some
contamination
losses
in
the
process
of
delivering
fuel
from
the
refinery.
As
discussed
earlier
in
this
section,
production
volumes
in
the
final
rule
are
based
upon
actual
delivered
volumes.
The
5
percent
allowance
for
greater
than
15
ppm
fuel
should
provide
adequate
flexibility
for
any
refiner's
contamination
issues,
while
not
providing
any
opportunity
to
significantly
alter
their
compliance
plans.

475
credits
could
provide
small
refiners
with
funds
to
help
defray
the
costs
of
early
NRLM
compliance.
°
The
NRLM/
Gasoline
Compliance
Option­
This
option
is
available
to
small
refiners
that
produce
greater
than
95
percent
of
their
NRLM
diesel
fuel
at
the
15
ppm
sulfur
standard
by
June
1,
2006
and
elect
not
to
use
the
provision
described
above
to
earn
NRLM
diesel
fuel
sulfur
credits
for
this
early
compliance.
256
For
small
refiners
choosing
this
option
the
applicable
small
refiner
annual
average
and
per­
gallon
cap
gasoline
sulfur
standards
will
be
increased
by
20
percent
for
the
duration
of
the
interim
program;
however,
in
no
case
may
the
per­
gallon
gasoline
sulfur
cap
exceed
450
ppm.

A
small
refiner
may
choose
to
use
the
relaxed
standards
(
the
NRLM
Delay
option),
the
NRLM
Credit
option,
or
both
in
combination.
Thus
any
fuel
that
it
produces
from
crude
at
or
below
the
sulfur
standards
earlier
than
required
will
qualify
for
generating
credits.
However,
the
NRLM/
Gasoline
Compliance
option
may
not
be
used
in
combination
with
either
the
NRLM
Delay
option
or
the
NRLM
Credit
option,
since
a
small
refiner
must
produce
at
least
85
percent
of
its
NRLM
diesel
fuel
at
the
15
ppm
sulfur
standard
under
the
NRLM/
Gasoline
Compliance
option.

Small
refiners
that
choose
to
make
use
of
the
delayed
nonroad
diesel
sulfur
requirements
would
also
delay
to
some
extent
the
emission
reductions
that
would
otherwise
have
been
achieved.
However,
the
overall
impact
of
these
postponed
emission
reductions
would
be
small
in
comparison
to
the
overall
program
benefits,
as
small
refiners
represent
only
a
fraction
of
national
non­
highway
diesel
production.
Further,
we
are
aware
of
some
small
refiners
that
plan
to
take
advantage
of
one
of
the
flexibility
provisions
that
encourages
early
compliance
with
the
standards.
Absent
specific
provisions
for
small
refiners,
we
would
have
to
consider
delaying
the
overall
program
until
the
burden
of
the
program
on
many
small
refiners
was
diminished,
which
would
delay
the
air
quality
benefits
of
the
overall
program.
By
providing
temporary
relief
to
small
refiners,
we
are
able
to
adopt
a
program
that
expeditiously
reduces
NRLM
diesel
fuel
sulfur
levels
in
a
feasible
manner
for
the
industry
as
a
whole.
257
The
cost­
to­
sales
ratio
test
assumes
that
control
costs
are
completely
absorbed
by
each
entity
and
does
not
account
for
or
consider
interaction
between
manufacturers/
producers
and
consumers
in
a
market
context.

476
Table
X.
C­
2.
 
Sulfur
Standards
for
the
Nonroad
Diesel
Fuel
Small
Refiner
Program
(
in
parts
per
million
(
ppm))
a
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015+

Non­
Small­
NR
­­
500
500
500
15
15
15
15
15
15
Non­
Small­
LM
­­
500
500
500
500
500
15
15
15
15
Small­
all
fuel
­­
­­
­­
­­
500
500
500
500
15
15
Notes:
a
New
standards
are
assumed
to
take
effect
June
1
of
the
applicable
year.

iv.
Provisions
for
Small
Distributors
and
Fuel
Marketers
Though
we
did
not
propose
any
specific
regulatory
relief
for
small
distributors
and
marketers
of
nonroad
fuel,
we
are
finalizing
provisions
to
avoid
the
negative
impact
to
small
terminal
operators
raised
in
the
public
comments
on
our
NPRM
(
that
heating
oil
marker
requirements
would
force
small
terminal
operators
to
install
expensive
injection
equipment
and
that
they
would
not
be
able
to
recoup
the
costs).
To
mitigate
the
burden
on
these
operators,
terminals
in
much
of
PADD
1
will
not
have
to
add
the
fuel
marker
to
home
heating
oil.
No
small
refiner
or
credit
fuel
could
be
sold
in
this
exclusion
area.
The
exclusion
area
covers
the
vast
majority
of
heating
oil
that
will
be
marketed.
Further,
very
little
fuel
above
500
ppm
will
be
marketed
outside
of
the
exclusion
area
except
directly
from
the
refinery
gate.
Therefore,
we
expect
that
few
terminals
outside
of
the
exclusion
area
would
need
to
put
in
injection
equipment.

6.
Conclusion
A
cost­
to­
sales
ratio
test,
a
ratio
of
the
estimated
annualized
compliance
costs
to
the
value
of
sales
per
company,
was
performed
for
these
entities
during
the
proposal
stage
of
the
rulemaking.
257
From
this
cost­
to­
sales
test,
we
found
that
approximately
four
percent
(
13
companies)
of
small
entities
in
the
engine
and
equipment
manufacturing
industry
would
be
affected
by
between
one
and
three
percent
of
sales
(
i.
e.,
the
estimated
costs
of
compliance
with
the
rule
would
be
greater
than
one
percent,
but
less
than
three
percent,
of
their
sales).
One
percent
(
four
companies)
of
small
entities
would
be
affected
by
greater
than
three
percent.
In
all,
17
of
the
518
potentially
affected
small
engine
and
equipment
manufacturers
are
estimated
to
have
compliance
costs
that
could
exceed
one
percent
of
their
sales.
(
A
complete
discussion
of
the
costs
to
engine
and
equipment
manufacturers
as
a
result
of
this
final
rule
is
located
in
Chapter
6
of
the
Final
Regulatory
Impact
Analysis.)
477
Based
on
our
outreach,
fact­
finding,
and
analysis
of
the
potential
impacts
of
our
regulations
on
small
businesses,
it
was
determined
that
small
refiners
in
general
would
likely
experience
a
significant
and
disproportionate
financial
hardship
in
reaching
the
objectives
of
the
nonroad
diesel
fuel
sulfur
program.
One
indication
of
this
disproportionate
hardship
for
small
refiners
is
the
relatively
high
cost
per
gallon
projected
for
producing
nonroad
diesel
fuel
under
the
proposed
program.
Refinery
modeling
(
of
all
refineries),
indicates
significantly
higher
refining
costs
for
small
refiners.
Specifically,
without
special
provisions,
refining
costs
(
for
full
compliance
with
the
15
ppm
sulfur
standards)
for
small
refiners
on
average
would
be
about
7
cents
per
gallon
compared
to
about
5.7
cents
per
gallon
for
non­
small
refiners.
(
A
complete
discussion
of
the
fuel­
related
costs
as
a
result
of
this
final
rule
is
located
in
Chapter
7
of
the
Final
Regulatory
Impact
Analysis.)
However,
we
believe
that
the
regulatory
transition
provisions
that
we
are
affording
to
small
entities
will
significantly
minimize
this
impact
on
these
entities.

In
addition,
as
contemplated
by
section
212
of
SBREFA,
EPA
is
also
preparing
a
compliance
guide
to
help
small
entities
comply
with
this
rule.
This
guide
will
be
available
within
60
days
of
the
effective
publication
date
of
this
rulemaking,
and
will
be
available
on
the
Office
of
Transportation
and
Air
Quality
website.
Small
entities
may
also
contact
our
office
to
obtain
copies
of
the
compliance
guide.

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.
478
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
the
final
rule
represents
the
least
costly,
most
cost­
effective
approach
to
achieve
the
air
quality
goals
of
the
rule.
The
costs
and
benefits
associated
with
the
final
rule
are
discussed
above
and
in
the
Regulatory
Impact
Analysis,
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"
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
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.
479
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
solicited
comment
on
the
proposed
rule
from
State
and
local
officials,
including
from
the
State
of
Alaska.

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."

This
final
rule
does
not
have
tribal
implications
as
specified
in
Executive
Order
13175.
This
rule
will
be
implemented
at
the
Federal
level
and
impose
compliance
costs
only
on
engine
manufacturers
and
diesel
fuel
producers
and
distributors.
Tribal
governments
will
be
affected
only
to
the
extent
they
purchase
and
use
equipment
with
regulated
engines.
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
EPA
believes
that
the
emissions
reductions
from
the
strategies
proposed
in
this
rulemaking
will
further
improve
air
quality
and
will
further
improve
children's
health.

H.
Executive
Order
13211:
Actions
that
Significantly
Affect
Energy
Supply,
Distribution,
or
Use
480
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."
We
have
prepared
a
Statement
of
Energy
Effects
for
this
action
as
follows:

We
have
prepared
a
Statement
of
Energy
Effects
for
this
action
as
follows.

This
rule's
potential
adverse
effects
on
energy
supply,
distribution,
or
use
have
been
analyzed,
and
are
discussed
in
detail
within
the
following
documents:

1.
Fuel
provisions
of
the
rule
and
flexibilities,
including
hardship
provisions,
are
described
in
this
Preamble,
section
IV.
B.
The
provision
of
sufficient
lead
time
for
refiners
is
discussed
in
section
IV.
F.
2.
Potential
impacts
on
fuel
supplies
are
summarized
in
Preamble
section
VI.
A.
5,
RIA
section
VI.
A.
5,
and
within
the
Summary
and
Analysis
of
Comments
document,
section
4.6.3.
3.
Costs
of
low­
sulfur
fuel
are
discussed
in
Preamble
section
VI.
F,
and
RIA
Chapter
7
(
demand
and
production
in
7.1,
and
refining
costs
in
7.2).
4.
Price
impacts
are
summarized
in
Preamble
section
VI.
A,
and
RIA
section
7.6,
with
distribution
costs
in
section
7.4,
alternative
estimates
of
costs
in
7.2,
and
effects
of
alternative
demand
projections
in
7.2
as
well.
Uncertainty
in
fuel
demand
is
also
discussed
in
the
Summary
and
Analysis
of
Comments
section
2.3.2.2.
5.
The
need
for
adequate
short­
term
investment
in
low
sulfur
refining
capacity
is
addressed
in
RIA
section
5.9.
6.
The
impacts
of
regulatory
alternatives
that
were
considered
are
discussed
in
Preamble
section
VII.

In
summary,
the
cost
of
No.
2
distillate
nonroad
fuel
is
projected
to
increase
overall
by
approximately
7
cents
per
gallon
(
in
2002
dollar
terms)
as
a
result
of
this
rule.
This
would
have
a
very
small
effect
on
production
(
projected
reduction
of
approximately
0.02
%,
or
less
than
4
million
gallons
per
year
by
2036).

The
analysis
also
concludes
that
we
do
not
expect
this
rule
to
have
any
adverse
effect
on
the
supply
or
distribution
of
NRLM
fuel,
nor
to
result
in
a
significant
increase
in
imports
of
NRLM
481
fuel.
Refiners
will
be
unlikely
to
leave
the
NRLM
fuel
market
and
are
unlikely
to
shut
down
due
to
this
rule.

Price
impacts
will
vary
regionally
in
the
U.
S.,
and
are
difficult
to
project
precisely.
Analysis
of
various
scenarios
in
RIA
section
7.6
suggests
that
in
PADDs
1
and
3
as
well
as
2,
which
account
for
the
bulk
of
demand,
prices
could
increase
by
almost
11
cents
per
gallon
in
the
unlikely
"
maximum
total
cost"
scenario
of
constrained
capacity.
In
contrast,
the
"
average
total
cost"
scenario
predicts
a
5
cent
per
gallon
increase
in
PADDs
1
and
3.

We
do
not
believe
there
are
any
reasonable
alternatives
to
the
control
of
sulfur
in
nonroad
fuel
which
would
allow
the
reduction
in
NO
X
and
PM
emissions
from
nonroad
equipment
required
by
today's
rule.
There
are
also
no
reasonable
alternatives
to
the
control
of
sulfur
in
locomotive
and
marine
fuel
which
would
provide
the
associated
reductions
in
sulfur
dioxide
and
sulfate
PM
emissions
provided
by
the
500
and
15
ppm
caps
on
the
sulfur
content
of
this
fuel.

I.
National
Technology
Transfer
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
(
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
rule
involves
technical
standards.
The
following
paragraph
describes
how
we
specify
testing
procedures
for
engines
subject
to
this
proposal.

The
International
Organization
for
Standardization
(
ISO)
has
a
voluntary
consensus
standard
that
can
be
used
to
test
nonroad
diesel
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
Regulatory
Impact
Analysis,
transient
testing
is
an
important
part
of
the
new
emission­
control
program
for
these
engines.
We
are
therefore
not
adopting
the
ISO
procedures
in
this
rulemaking.

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.
482
House
of
Representatives,
and
the
Comptroller
General
of
the
United
States
before
the
rule
is
published
in
the
Federal
Register.
This
rule
is
a
"
major
rule"
as
defined
by
5
U.
S.
C.
804(
2).
483
XI.
Statutory
Provisions
and
Legal
Authority
Statutory
authority
for
the
engine
controls
adopted
today
can
be
found
in
sections
213
(
which
specifically
authorizes
controls
on
emissions
from
nonroad
engines
and
vehicles),
203
­
209,
216
and
301
of
the
Clean
Air
Act,
42
U.
S.
C.
7547,
7522,
7523,
7424,
7525,
7541,7542,
7543,
7550
and
7601.

Statutory
authority
for
the
new
fuel
controls
is
found
in
sections
211
(
c)
and
211
(
i)
of
the
Clean
Air
Act,
which
allow
EPA
to
regulate
fuels
that
either
contribute
to
air
pollution
which
endangers
public
health
or
welfare
or
which
impair
emission
control
equipment
which
is
in
general
use
or
has
been
in
general
use.
42
U.
S.
C.
7545
(
c)
and
(
i).
Additional
support
for
the
procedural
and
enforcement­
related
aspects
of
the
fuel
controls
in
the
final
rule,
including
the
record
keeping
requirements,
comes
from
sections
114
(
a)
and
301
(
a)
of
the
CAA.
42
U.
S.
C.
sections
7414
(
a)
and
7601
(
a).
484
List
of
Subjects
40
CFR
Part
9
Reporting
and
recordkeeping
requirements.

40
CFR
Part
69
Environmental
protection,
Air
pollution
controls.

40
CFR
Part
80
Fuel
additives,
Gasoline,
Imports,
Incorporation
by
reference,
Labeling,
Motor
vehicle
pollution,
Penalties,
Reporting
and
recordkeeping
requirements.

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
94
Environmental
protection,
Administrative
practice
and
procedure,
Air
pollution
control,
Confidential
business
information,
Imports,
Incorporation
by
reference,
Penalties,
Reporting
and
recordkeeping
requirements,
Vessels,
Warranties.

40
CFR
Part
1039,
1048,
and
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.
485
40
CFR
Part
1068
Environmental
protection,
Administrative
practice
and
procedure,
Confidential
business
information,
Imports,
Motor
vehicle
pollution,
Penalties,
Reporting
and
recordkeeping
requirements,
Warranties.

Dated_____________

ORIGINAL
SIGNED
BY
MICHAEL
LEAVITT
MAY
11,
2004
___________________________________
Michael
O.
Leavitt,
Administrator