[[pp. 6747-6796]] Control of Air Pollution From New Motor Vehicles: Tier 2 Motor

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[Federal Register: February 10, 2000 (Volume 65, Number 28)]
[Rules and Regulations]
[Page 6747-6796]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr10fe00-19]

[[pp. 6747-6796]] Control of Air Pollution From New Motor Vehicles: Tier 2 Motor
Vehicle Emissions Standards and Gasoline Sulfur Control Requirements

[[Continued from page 6746]]

[[Page 6747]]

In the NPRM, we proposed that, for LDV/LLDTs, all bins with
NO_X values over 0.20 g/mi would expire at the end of the
2006 model year when there are no longer any interim LDV/LLDTs. Table
IV-B.-4 shows that the two highest bins, bins 9 and 10, which were
derived from NLEV and included to smooth the transition from NLEV to
the interim program will be unuseable for LDV/LLDTs after 2006--the
last year of the LDV/LLDT phase-in. Otherwise all bins will remain
viable for the duration of the Tier 2 program unless altered by another
rulemaking.
We proposed to align the useful life periods for interim standards
with those of the Tier 2 standards (full useful life of 120,000 miles),
as discussed in Section V.B. below. The end result of this proposal
would have been that all LDV/LLDTs--whether in the Tier 2 program or
interim program--would go from 100,000 mile useful lives to 120,000
mile useful lives in 2004. However, manufacturers were extremely
concerned about the certification workload burden for 2004. They
commented that they would be unable to carry any of their LDV/LLDTs
over from 2003 and that they would have to recertify all of their
vehicles in 2004 and then likely recertify them again as they were
phased into the Tier 2 standards. Therefore, based upon comments, we
are finalizing that useful lives of the interim LDV/LLDTs may remain at
100,000 miles. Our reasons for this change are discussed in greater
detail in Section V.B.
We are finalizing as proposed a corporate average full useful life
NO_X standard of 0.30 g/mi for this interim program. This
standard is derived from the NLEV program and represents the full
useful life NO_X standard in NLEV that is associated with LEV
LDVs and LDT1s. LDVs and LDT1s will already be at this level, on
average, under the NLEV program. LDT2s are subject to standards that
effectively impose a NO_X average standard of 0.5 g/mi under
NLEV, but we believe they should readily be able to meet the 0.30 g/mi
average especially since they can be averaged with the LDVs and LDT1s.
To aid LDV/LLDTs in meeting the 0.30 g/mi corporate average
NO_X standard in the interim program, we are providing an
optional NMOG value for LDT2s certifying to bin 9 (where the
NO_X standard=0.3 g/mi). This option is only for LDT2s, and
only for those produced by manufacturers that elect to comply with the
interim requirements for all of their HLDTs for the 2004 model year
(see next section). The optional NMOG values for qualifying LDT2s are
0.130 g/mi at full useful life and 0.100 at intermediate useful life.
The 0.30 g/mi corporate average NO_X standard will apply
only to non-Tier 2 (interim) LDV/LLDTs and only for the 2004-2006 model
years. Manufacturers will compute, bank, average, trade, account for,
and report interim NO_X credits via the same processes and
equations described in this preamble for Tier 2 vehicles, substituting
the 0.30 g/mi corporate average standard for the 0.07 g/mi corporate
average standard in the basic program. Also, EPA will condition the
certificates of conformity on compliance with the corporate average
standard, as described for Tier 2 vehicles. These NO_X
credits will be good only for the 2004-2006 model years and will only
apply to the interim non-Tier 2 LDV/LLDTs. Credits will not be subject
to any discounts, and credit deficits can be carried forward as
described under Section IV.B.4.d.vi. above.
NMOG credits from the NLEV program can not be used in this interim
program in any way. NO_X credits generated under this interim
program will not be applicable to the Tier 2 NO_X average
standard of 0.07 g/mi because of our concern that a windfall credit
situation could occur. This could happen because credits are relatively
easy to generate under a 0.30 g/mi standard compared to generating
credits under a 0.07 g/mi standard. As we indicated in the preamble to
the NPRM we believe the application of credits earned under the interim
standard to the Tier 2 standards could significantly delay the fleet
turnover to Tier 2 vehicles. We do not believe there is a need or that
it would be appropriate to allow such a delay. The requirements of the
interim program will be monitored and enforced in the same fashion as
for Tier 2 vehicles.
For the reasons cited above, we believe it is appropriate to extend
interim, NLEV-like standards beyond 2003 as a mandatory program and to
bring all LDVs and LLDTs within its scope. Manufacturers have already
demonstrated their ability to make LDVs and LLDTs that comply at levels
well below these standards. As the interim standards for LDV/LLDTs are
essentially `phase-out'' standards, we did not propose and are not
finalizing early banking provisions for the interim LDV/LLDTs.

ii. Interim Exhaust Emission Standards for HLDTs

We believe these interim standards are necessary and reasonable for
HLDTs. While these trucks make up a fairly small portion of the light-
duty fleet (about 14%), their current standards under Tier 1 are far
less stringent than the NLEV standards that apply to current model year
LDVs and LLDTs. Given the delayed phase-in we are finalizing for HLDTs,
we believe it is appropriate to require some interim reductions from
these vehicles. Further, manufacturers have already demonstrated their
ability to meet these interim standards with HLDTs. These standards are
a reasonable first step toward the Tier 2 program and will provide
meaningful reductions in the near term relative to current
certification levels under the Tier 1 emission standards.
We also proposed interim standards to begin in 2004 for HLDTs.
These vehicles are not included in the NLEV program and will be subject
only to the Tier 1 standards prior to today's rule taking effect. Tier
1 standards permit NO_X emissions of 0.98 g/mi for LDT3s and
1.53 g/mi for LDT4s. We are finalizing these standards generally as
proposed; to address statutory lead time requirements, we are offering
two options for the phase-in of HLDTs to the interim standards.
Manufacturers can choose between either of these two options:
(Option 1) Like we proposed in the NPRM, manufacturers must bring
their entire production of 2004 model year HLDTs under the interim
requirements and phase 25% of them into the 0.20 g/mi fleet average
NO_X requirement, followed by 50% in 2005, 75% in 2006, and
then 100% in 2007; or
(Option 2) We are including this option to address statutory lead
time requirements for HLDTs. In the case of 2004 model year test groups
whose model years commence before the fourth anniversary of the
signature date of today's rule, the manufacturer may exclude those test
groups from the interim HLDT provisions of the rule. In the case of
2004 model year test groups whose model years commence on or after the
fourth anniversary of this rule's signature, the manufacturer must
bring all such HLDTs under the requirements of our interim program, and
all such vehicles or 25% of the manufacturer's sales of 2004 model year
HLDTs, whichever is less, must comply with the corporate average
NO_X standard of 0.20 g/mi. The manufacturer must then bring
all of its HLDTs into the interim requirements beginning with the 2005
model year including a 50%, 75%, 100% phase-in to the 0.20 g/mi fleet
average NO_X standard beginning that year. The beginning of a
test group's model year is determined under section 202(b)(3) of the
Act and 40 CFR Part 85 Subpart X.

[[Page 6748]]

Our final rule is consistent with the requirements of the Act
because manufacturers won't have to phase-in HLDTs until the model year
that commences four years from the signature of this rule if they don't
want to. However, to provide incentive for manufacturers to comply with
the interim requirements for all of their HLDTs beginning with the 2004
model year, i.e. to elect Option 1, we are finalizing a provision to
permit those manufacturers to use higher NMOG values in two situations.
Manufacturers electing to meet the interim requirements for all of
their 2004 model year HLDTs including the 25% phase-in number must so
declare in their 2004 model year HLDT certification applications. They
may then:
Use a full useful life NMOG value, through the 2008 model
year, of 0.280 g/mi for LDT4s certified to bin 10 (0.195 g/mi at
intermediate life); and
Use a full useful life NMOG value, through the 2006 model
year, of 0.130 g/mi for LDT2s certified to bin 9 (0.100 g/mi at
intermediate life). \70\
---------------------------------------------------------------------------

\70\ Manufacturers must cite this declaration in their LDT2
certification applications for the 2004-2006 model years and in
their LDT4 applications for the 2004-2008 model years. If
manufacturers employ alternate phase-in schedules that begin prior
to 2004, they must also make the declaration in each applicable year
before 2004.
---------------------------------------------------------------------------

In the case of the LDT4s, the optional NMOG standard will enable
manufacturers to more easily meet our interim HLDT NO_X
standards, the highest of which (0.6 g/mi) is one-third tighter than
what will be required in California under Cal LEV I through 2006. For
the LDT2s, the optional NMOG standard will help manufacturers certify
more LDT2s to bin 9 (0.3 g/mi) than they likely would otherwise (they
would probably certify some LDT2s to bin 10 where NO_X=0.6 g/
mi). Therefore, both of these optional standards are consistent with
our goal to achieve important early NO_X benefits from our
program.
Except for the application of the new option described above, the
interim standards for HLDTs will apply as proposed, and will phase-in
through the 2007 model year, as shown in Table IV.B.-2. We are
finalizing the proposed corporate average full-life NO_X
standard of 0.20 g/mi for interim HLDTs. Manufacturers will comply with
the corporate average HLDT NO_X standard by certifying their
interim HLDTs to any of the full useful life bins shown in Table IV-B.-
4. Where applicable, manufacturers will also comply with the
intermediate useful life standards shown in Table IV.B.-5. Interim
HLDTs not needed to meet the phase-in percentages during model years
2004-2006 will have to be certified to the standards of one of the bins
in Table IV.B.-4 (and -5), and NO_X will thus be capped at
0.60 g/mi. These trucks will not be included in the calculation to
demonstrate compliance with the 0.20 g/mi average.
At the end of each model year, manufacturers will determine their
compliance with the 0.20 NO_X standard by calculating a sales
weighted average of all the bins to which they certified any interim
HLDTs, excluding those not needed to meet the applicable phase-in
requirements during 2004-2006. The excluded trucks must comply with the
standards from one of the bins in Table IV-B-4 (and -5) which
effectively caps their emissions at 0.60 g/mi.
For HLDT test groups that are not subject to the phase-in in model
year 2004 under Option 2 above, the same requirements as described
above apply except that there are no new standards for these vehicles
in the 2004 model year. Also, the optional higher NMOG values for LDT2s
and LDT4s do not apply for any manufacturer that uses Option 2.
Given that the interim HLDT standards are ``phase-in'' standards
through 2007 (as opposed to the interim LDV/LLDT standards, which are
``phase-out'' standards), we are including provisions that
manufacturers may employ alternative phase-in schedules as proposed for
the Tier 2 standards and described in detail in section IV.B.4.b.ii. of
this preamble. These schedules provide manufacturers with greater
flexibility and we believe they also provide incentive for
manufacturers to introduce advanced emission control technology at an
earlier date. Alternative phase-in schedules will have to provide 100%
phase-in by the same year as the primary phase-in schedule (2007).
Manufacturers will be eligible for alternate phase-in schedules to the
extent that they produce HLDTs that meet or surpass the NO_X
average standard for interim HLDTs of 0.20 g/mi in 2001-2003 or to the
extent that they produce more HLDTs than required that meet the 0.20
average standard in 2004 or later.
Where manufacturers elect not to meet the phase-in requirements for
all of their 2004 model year HLDTs, as discussed above under Option 2,
they may still employ alternate phase-in schedules, but the sum of 225
percent is required rather than the 250 percent required for alternate
phase-ins described in section IV.B.4.b.ii. In this case, the sum of
phase-in percentages up through the 2005 model year must total to at
least 50%. Also, manufacturers must raise the 225% value to the extent
that any of their 2004 HLDTs' model years commence on or after the
fourth anniversary of the signature date of this rule and are brought
into compliance with the 0.20 g/mi average NO_X standard.
Lastly, note that for bin 10, which is only usable during the
interim program, we have established a PM standard of 0.08 g/mi, which
is more stringent than the Tier 1 standard previously in effect for
these vehicles. We do not expect low sulfur diesel fuel to be widely
available during the time frame of the interim program but we expect
that bin 10 levels can be reached by diesel technology on current
diesel fuel. As a part of this overall approach, we are making the
intermediate life standards optional for diesels for this bin.
f. Light-Duty Evaporative Emission Standards
We are finalizing as proposed a set of more stringent evaporative
emission standards for all Tier 2 light-duty vehicles and light-duty
trucks. The standards we are finalizing are shown in Table IV.B.-9 and
represent, for most vehicles, more than a 50% reduction in diurnal plus
hot soak standards from those that will be in effect in the years
immediately preceding Tier 2 implementation. The higher standards for
HLDTs provide allowance for greater non-fuel emissions related to
larger vehicle size.

[[Page 6749]]

Table IV.B.-9.--Final Evaporative Emission Standards
[Grams per test]
------------------------------------------------------------------------
Supplemental 2
Vehicle class 3 day diurnal day diurnal
+hot soak +hot soak
------------------------------------------------------------------------
LDVs and LLDTs.......................... 0.95 1.2
HLDTs................................... 1.2 1.5
------------------------------------------------------------------------

Evaporative emissions from LDVs and LDTs represent nearly half of
the light duty VOC inventory projected for the 2007-2010 time frame,
according to MOBILE5 projections. Manufacturers are currently
certifying to levels that are, on average, about half of the current
standards, and in many cases, much less than half the standards. Thus,
meeting these standards appears readily feasible. Even though
manufacturers are already certifying at levels much below the current
standard, we believe that reducing the standards will result in
emission reductions as all manufacturers seek to certify with adequate
margins to allow for in-use deterioration. Further, we believe that
tighter standards will prevent ``backsliding'' toward the current
standards as manufacturers pursue cost reductions.
As mentioned in section IV.B.-4.b above, we will phase in the Tier
2 evaporative standards by the same mechanism as the Tier 2 exhaust
standards; e.g., 25/50/75/100 percent beginning in 2004 for LDV/LLDTs
and 50/100 percent beginning in 2008 for HLDTs (as shown in Table
IV.B.-2). As for the exhaust standards, alternative phase-in plans will
also be available.
The evaporative emission standards we proposed and are finalizing
today are the same as those that manufacturers' associations proposed
during the development of California's LEV II proposal. California
ultimately opted for more stringent standards; we believe that our
standards are appropriate for federal vehicles certified on higher-
volatility federal test fuel.
g. Passenger Vehicles Above 8,500 Pounds GVWR
Historically, we have categorized all vehicles above 8,500 pounds
GVWR as heavy-duty vehicles regardless of their application and they
have been subject to standards and test procedures designed for
vehicles used in heavier work applications. \71\ In the Tier 2 NPRM, we
requested comment on whether some portion of vehicles above 8,500
pounds GVWR should be included in the Tier 2 program, based on vehicle
use or design characteristics. The Tier 2 proposals, however, applied
to light-duty vehicles and light-duty trucks and did not cover any
vehicles above 8,500 pounds GVWR.
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\71\ The heavy-duty definition also includes vehicles that weigh
over 6000 lbs curb weight regardless of their GVWR. We are not aware
that any vehicles currently produced have curb weights above 6,000
lbs, but GVWRs of 8,500 lbs or less. Nevertheless, this discussion
and our requirements includes such vehicles.
---------------------------------------------------------------------------

On October 29, 1999, after carefully considering all of the
comments on this issue, we proposed to include all personal use
passenger vehicles (both gasoline and diesel fueled) between 8,500 and
10,000 pounds GVWR in the Tier 2 program. This group of vehicles would
include large SUVs and passenger vans and may include other types of
``crossover'' multipurpose vehicles in the future, depending on new
vehicle designs. We proposed this Tier 2 program change in our NPRM
concerning emissions standards for 2004 and later heavy-duty vehicles
and engines, (64 FR 58472).
Specifically, we proposed to revise the definition of light-duty
truck to include any complete vehicle between 8,500 and 10,000 pounds
GVWR that is designed primarily for the transportation of persons and
has a capacity of not more than 12 persons. We expected that this
definition would exclude vehicles that have been designed for a
legitimate work function as their primary use, such as the largest
pick-up trucks, the largest passenger vans, and cargo vans; these
vehicles would continue to be categorized as heavy-duty and would be
subject to applicable heavy-duty standards. We requested comment on
whether the proposed definition would adequately exclude these
vehicles, or whether additional criteria may be needed and how that
criteria might be used.
Today, we are finalizing Tier 2 standards for passenger vehicles
above 8,500 pounds GVWR. These vehicles are included in the Tier 2
program beginning in 2004 and are required to meet the final Tier 2
standards in 2009 and later. As we intended in the proposal, these
vehicles will generally be subject to the same requirements as HLDTs.
We have made modifications to the program, primarily in response to
comments we received in two areas: (1) Changing the definition of
light-duty truck and (2) the interim program requirements.

New Vehicle Category: Medium-Duty Passenger Vehicles (MDPVs)

The mechanism we proposed to bring the passenger vehicles over
8,500 pounds into the Tier 2 program, was to modify the definition of
light-duty truck to include those vehicles. The objective of this
proposal was to have these vehicles treated as HLDTs within Tier 2. We
are finalizing requirements which remain consistent with our objective
of including these vehicles in Tier 2 beginning in 2004. However, the
approach we are finalizing is somewhat different than that proposed.
Rather than finalizing the revised definitions for light-duty truck
as we proposed, we are creating a new category of heavy-duty vehicles
termed ``medium-duty passenger vehicles'' (MDPVs). These vehicles will
generally be grouped with and treated as HLDTs in the Tier 2 program.
The MDPV category is defined along the lines of the proposed definition
change for the LDT category, with some modification, as described
below. Our decision to create a new sub-category of heavy-duty vehicles
rather than modify the existing LDT definition does not, in and of
itself, change the way in which Tier 2 standards are applied to the
vehicles.
We decided upon the above approach because section 216 of the CAA
establishes the definition for LDT as having the meaning contained in
the CFR as of 1990. We received several comments that EPA may not
change the definition and must instead devise a way to categorize the
vehicles for purposes of Tier 2 which does not change the definition of
light-duty truck. Rather than adopt a change to the LDT definition that
would be questionable from a legal perspective, we are adopting an
approach that we believe is clearly legally acceptable. Under this
approach (as with the proposed approach), the standards for these
vehicles are promulgated under

[[Page 6750]]

section 202(a)(3), which applies to heavy-duty vehicles/engines.
We are defining medium-duty passenger vehicles as any complete
heavy duty vehicle less than10,000 pounds GVWR designed primarily for
the transportation of persons including conversion vans (i.e., vans
which are intended to be converted to vans primarily intended for the
transportation of persons. The conversion from cargo to passenger use
usually includes the installation of rear seating, windows, carpet, and
other amenities). We are not including any vehicle that (1) has a
capacity of more than 12 persons total or, (2) that is designed to
accommodate more than 9 persons in seating rearward of the driver's
seat or, (3) has a cargo box (e.g., a pick-up box or bed) of six feet
or more in interior length. We would consider vehicles designed
primarily for passenger use to be those that have seating available
behind the driver's seat. We have added the rear passenger seating
capacity criterion to exclude large passenger vehicles which are
primarily used in heavy-load passenger applications. We do not believe
vehicles designed primarily for personal use passenger transportation
would be equipped with rear seating for more than 9 passengers. \72\
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\72\ Vehicles that are ``designed'' to accommodate more than
nine passengers in the rearward seating area in their standard
configuration but that have some of the standard rear seating
removed to accommodate two or more wheel chair tie downs would
usually not be considered MDPVs.
---------------------------------------------------------------------------

We have added the pick-up bed length criterion to the definition to
clearly distinguish standard pick-ups from other vehicles meeting the
GVWR and seating capacity criteria. We received several comments that
although the proposal clearly states our intention not to include
heavy-duty pick-up trucks in the Tier 2 program, the proposed
regulatory definition was unclear. Currently, heavy-duty pick-ups have
beds in excess of six feet. Any future offerings of vehicles that are
equipped with significantly shorter beds would be included in the MDPV
category, if the vehicle also met the weight and seating capacity
criteria. EPA is making a distinction based on bed length because a
vehicle introduced with a shorter bed would have reduced cargo capacity
and would likely have increased seating capacity relative to current
pick-ups, making it more likely to be used primarily as a passenger
vehicle.

Interim Standards

As noted above, the MDPVs and HLDTs must meet the final Tier 2
standards by 2009 at the latest. Prior to 2009, HLDTs and MDPVs are
required to meet interim standards. The interim standards, as described
earlier in section IV.B.4, are based on a corporate average full life
NO_X standard of 0.20 g/mile which is phased in 25/50/75/100
percent in 2004-2007. MDPVs must be grouped with HLDTs for the interim
standards phase-in.
We received several comments from manufacturers that requiring
these larger vehicles to meet a new, unique standard prior to phase-in
to the interim program would worsen the workload burden created by the
Tier 2 program. Manufacturers do not currently have facilities
available for chassis-testing diesel vehicles and there is not enough
time to fold diesel vehicles into a chassis-based program by 2004.\73\
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\73\ Currently, diesel heavy-duty engines are certified to
heavy-duty engine standards rather than vehicle standards.
---------------------------------------------------------------------------

To address this situation, we are providing the following temporary
additional flexibilities for MDPVs. We are finalizing an additional
upper bin for MDPVs for the interim program (effective in model years
2004 through 2008). This bin would only be available for MDPVs. The
bin, shown in Table IV.B-10, is equivalent to the California LEV I
standards that are applicable to these vehicles prior to 2004. Vehicles
certified to this bin must be tested at adjusted loaded vehicle weight
(ALVW), consistent with California program testing requirements.\74\
Including this upper bin provides manufacturers with the ability to
carry over their California vehicles to the federal program prior to
their phase-in to the interim and final Tier 2 standards. Once phased
in to the interim standards manufacturers may continue to use the upper
bin but the vehicles must be included in the 0.20 g/mi NO_X
average. The upper bin is not available to manufacturers for the final
Tier 2 program.
---------------------------------------------------------------------------

\74\ ALVW is the average of curb weight and GVWR. The test
weight is sometimes refered to as ``half payload''.

Table IV.B.-10.--Temporary Interim Exhaust Emission Standards Bin for MDPVs a
----------------------------------------------------------------------------------------------------------------
NO_X NMOG CO HCHO PM
----------------------------------------------------------------------------------------------------------------
Full Useful Life (120,000 mile)........... 0.9 0.280 7.3 0.032 0.12
----------------------------------------------------------------------------------------------------------------
Notes:
\a\ Bin expires after model year 2008.

We proposed that HLDTs not needed to meet the phase-in percentages
for the interim program during model years 2004--2006 would be required
to meet one of the interim bins. Such vehicles, however, would not be
included in the calculation to demonstrate compliance with the 0.20 g/
mile average. Thus, we proposed that the emissions of all interim HLDTs
would be capped at a NO_X value of 0.6 g/mile. We are
retaining the bin structure and requirements which effectively cap
NO_X emissions at 0.6 g/mile for all HLDTs below 8,500 pounds
GVWR, as described in section IV.B. Similarly, for MDPVs, the 0.9 g bin
described above is the highest bin available and acts as the cap for
vehicles not yet phased-in to the interim standards.
In addition, for diesel MDPVs prior to 2008, we are allowing
manufacturers the option of meeting the heavy-duty engine standards in
place for the coinciding model year. Diesels meeting the engine-based
standards would be excluded from the interim program averaging pool. In
2008, the manufacturers must chassis certify diesel vehicles and
include them either in the interim program or in the final Tier 2
program. In 2009 and later, all MDPVs, including diesels, must be
brought into the final Tier 2 program. As with the higher bin of
chassis-based standards, the purpose of this diesel provision is to
provide the option of carry-over of vehicles until they are brought
into the Tier 2 program. We believe these modifications to the program
will substantially ease the workload concerns of manufacturers in the
interim years by allowing them to carry-over vehicle models and engine
families. The provisions also remain consistent with EPA's goal of
including the vehicles in the overall Tier 2 program structure.

[[Page 6751]]

For diesel engines that are engine certified and used in MDPVs, as
allowed through model year 2007, we are requiring those engines to
comprise a separate averaging set under the averaging, banking and
trading requirements applicable to heavy-duty diesel engines. We are
permitting engine-based certification for these diesel vehicles to
provide time and flexibility for manufacturers who may have limited
experience with chassis certifying vehicles containing such engines.
However, we do not want to create a situation where engines above
applicable engine standards could be used in these vehicles, when other
MDPVs are being brought under stringent standards. Therefore we believe
it is appropriate to constrain the application of credits to these
engines. We note that we are not permitting credits from other programs
(like NLEV) to be applied in any way to Tier 2 or interim vehicles.
For LDT4s, we have finalized an optional higher NMOG level of 0.280
g/mile for bin 10 (0.6 g/mile NO_X), as described in section
IV.B.4.a of the preamble. MDPVs placed in bin 10 may also certify to
the higher NMOG level of 0.280 g/mile. This provision provides
manufacturers with the incentive of selecting the lower NO_X
bin for MDPVs, since the NMOG level is not an obstacle to compliance.
As described in section IV. B.4.e.ii., manufacturers have two
options for the start of the program requirements. In Option 1, the
program begins with the 2004 model year for 25 percent all vehicles. In
Option 2, manufacturers can exempt 2004 model year vehicle test groups
whose model years begin on or after the fourth anniversary of this
rule's signature. These options are also available for MDPVs for the
same reasons we are providing them for HLDTs. However, the additional
0.9 g bin contained in Table IV.B.-10, the optional higher NMOG
standard of 0.280 g/mile for bin 10, and the option of certifying to
the engine-based standards for diesels are available only with Option
1.

Other Emission Control Requirements

We are requiring all non-diesel MDPVs to be OBDII compliant
beginning in 2004. California requires OBDII for their LEV I program
and therefore, the new OBDII requirements are consistent with the
approach of allowing vehicles to be carried over from California. \75\
Diesel vehicles which are carried over from the California program are
required to be equipped with the OBD system as the system is certified
in California. Diesel vehicles not carried over from California are not
required as part of this rulemaking to be equipped with OBDII. However,
we have proposed OBDII requirements for heavy-duty diesel engines in
our heavy-duty engines NPRM (64 FR 58472). If OBDII requirements are
finalized for heavy-duty engines and vehicles as part of that
rulemaking the OBDII requirements would likewise apply to diesels in
the MDPV category.
---------------------------------------------------------------------------

\75\ As with HLDTs, the California OBDII compliance option is
available for MDPVs.
---------------------------------------------------------------------------

As proposed, we are applying Tier 2 evaporative emissions standards
and existing HLDT ORVR requirements to MDPVs. MDPVs must be grouped
with HLDTs for purposes of phasing in to the Tier 2 evaporative
emission standards contained in this rule. We have added somewhat
higher standards for the MDPVs to account for their larger fuel tanks
and vehicle sizes.\76\ However, the stringency of the standards remains
similar to that for HLDTs. These standards are described in section
IV.B.4.f of the preamble. ORVR requirements currently exist for HLDTs
and are to be phased-in through model years 2004-2006.\77\ We proposed
to apply the same standards and phase-in requirements to vehicles over
8,500 pounds GVWR. We are finalizing these ORVR requirements for MDPVs,
which must be grouped with HLDTs for purposes of phased-in to the ORVR
requirements.
---------------------------------------------------------------------------

\76\ For Tier 2 MDPVs, evaporative standards will be 1.4 g/test
for the 3 day diurnal+hot soak test and 1.75 g/test for the
supplemental 2 day diurnal+hot soak test.
\77\ ORVR requirements are phased in for HLDTs, at 40/80/100
percent in 2004-2006 (see 40 CFR 86.1810-01 (k)).
---------------------------------------------------------------------------

For those manufacturers electing option 2, OBD is required when the
vehicle family is covered under these new requirements (i.e., 2004 or
2005 depending on when certification occurs). For ORVR, the situation
is similar. The phase-in is 40 percent of any 2004 certifications which
occur four years after this rule is promulgated, 80 percent in 2005,
and 100 percent in 2006. As before, the vehicles covered by these
phase-ins must be combined with those in the LDT3/4 phase-in for
purposes of calculating compliance.
We are finalizing Cold CO and Certification Short Test requirements
for Tier 2 MDPVs. However, we are not finalizing SFTP standards for
MDPVs in today's rulemaking. Currently, SFTP standards do not apply to
any vehicles above 8,500 pounds GVWR, including those in the California
LEV I and LEV II programs. We are concerned, therefore, that finalizing
SFTP requirements in today's rulemaking would prevent manufacturers
from carrying over vehicle models during the phase-in years of the
program. We are currently contemplating a new SFTP rulemaking which
would consider ``Tier 2'' SFTP standards for all vehicles, including
MDPVs. California is also interested in developing more stringent SFTP
standards within the context of their LEV II program and we are
coordinating with California on these new SFTP standards.

Sustained Severe Use; In-Use Testing of MDPVs

While we are confident that MDPVs can comply in-use with the
standards we are finalizing, manufacturers are concerned about in-use
liability for MDPVs that are in sustained severe-use. In our in-use
emission testing program, we generally screen vehicles for proper
maintenance and use and delete vehicles that we believe may have been
misused or malmaintained. Also, in the regulations for manufacturer in-
use testing, we permit manufacturers to delete vehicles from samples if
they have been used for ``severe duty (trailer towing for passenger
cars, snow plowing, racing)'', and we provide that vehicles may be
deleted for other reasons upon EPA approval.
We recognize that MDPVs will be marketed and used for carrying many
passengers, carrying heavy loads and trailer towing. While it is not
our intention to exempt vehicles from in-use liability that have been
used for their intended purposes, we understand that some MDPVs may be
subject to sustained severe service applications, such as frequent
overloading or frequent towing beyond manufacturer's advertised
capacity and could not be considered to be representative of properly
maintained and used vehicles. Furthermore, we would not necessarily
consider to be representative MDPVs which are routinely or regularly
used in heavy-load hauling application or towing even within the
manufacturers limits. Thus, for example, an SUV MDPV used on a daily
basis to haul a work crew and tow equipment to a distant work site may
not be representative while the same SUV used to haul the family and
tow a boat to the lake on weekend excursions would be representative.
MDPVs in sustained severe operations should not be included in
manufacturer or EPA in-use test programs, while those that see less
frequent severe operation should be included.

[[Page 6752]]

C. Our Program for Controlling Gasoline Sulfur

As with our program for vehicles, the program we are establishing
today for reducing sulfur levels in commercial gasoline will achieve
the same large NO_X reductions that we projected for the
proposed program. Here, too, the final program is very similar to our
proposed program. Adjustments we have made to the proposed program will
smooth the refining industry's transition to the low-sulfur
requirements and encourage earlier introduction of cleaner fuel.
With today's action, we are requiring substantial reductions in
gasoline sulfur levels nationwide. As we explained in Section IV.A,
because sulfur significantly inhibits the ability of automotive
catalysts to control emissions, we had to consider sulfur's impact in
setting the Tier 2 standards. We knew at the time of proposal that
newer catalysts were more sensitive to sulfur than older technologies,
and projected that Tier 2 catalysts would be as or even more sensitive
than those used in today's NLEV vehicles. Furthermore, we believed that
the sulfur build-up on Tier 2 catalysts may be irreversible. Since the
proposal, additional data we've collected have confirmed and
strengthened our concerns. It now appears that the catalysts expected
to be used in Tier 2 vehicles will be even more sensitive to sulfur
than we originally estimated, and that this sulfur impact will be
approximately 45 percent irreversible under typical driving conditions.
Thus, the gasoline sulfur standards we finalize today will enable the
stringent tailpipe emission standards we're implementing for Tier 2
vehicles and will help to ensure that these low emission levels will be
realized throughout the life of the vehicle. Furthermore, since
vehicles already on the road, including NLEV vehicles, are in many
cases quite sensitive to sulfur, gasoline sulfur control will also help
to reduce emissions of pollutants that endanger public health and
welfare from these vehicles.
In developing this gasoline sulfur control program, we gave
substantial consideration to the ability of the refining industry to
meet these requirements. We proposed a set of standards applying to
refiners and to individual refineries combined with a sulfur averaging,
banking, and trading (ABT) program intended to provide flexibility in
meeting the standards. We concluded that our proposal was reasonable
and cost-effective based on our projections regarding the number of
refineries that would (1) need to reduce sulfur levels each year as the
standards tightened, (2) need sulfur ABT credits to meet the 30 ppm
refinery average standard in 2004 and/or 2005 to defer installation of
desulfurization equipment, and (3) install desulfurization equipment
prior to 2004, generating the needed sulfur credits. This analysis
formed our picture of the industry's investment stream--a year-by-year
estimate of how many refineries would be constructing new equipment and
what technologies these refineries would choose. We assumed that any
investments would be in the new, lower cost technologies, and that
these technologies would be available and adequately demonstrated to
allow refiners to select them as early as the year 2000 to begin
operation (and thus, credit generation) as early as 2002. Based on
these assumptions, our analysis showed that sufficient credits would be
generated before 2004 to enable a number of refineries to delay
construction and use credits to meet the 30 ppm standard in 2004, and
in some cases, even in 2005. Overall, we believed our analysis
represented a reasonable and balanced rate of investment by the
industry over a several year time period.
In response to our proposal, we received many comments which raised
concerns about the feasibility of our program. Some comments suggested
that our proposed declining cap (300 ppm cap for 2004 and a reduced cap
of 180 ppm for 2005) could be an additional and burdensome expense for
most refiners to meet. Specifically, these commenters believed that the
declining cap would be more constraining than compliance with the
corporate average or even the refinery average standards (as long as
the ABT program produced sufficient credits). Because refiners probably
would not make multiple investments in such a short time, the 180 ppm
cap could force some refiners to install the equipment needed to get to
the 80 ppm cap earlier than otherwise needed. The commenters argued
that this would force all of the industry's investments into the first
years of the program rather than allowing for a smoother transition
over several years as we had originally envisioned. Many comments also
suggested that since there have not been long-term commercial
demonstrations of the newer gasoline desulfurization technologies,
refiners would not consider these technologies to be viable and, if
faced with our proposed 30 ppm standard in 2004, may select the more
traditional, higher cost sulfur reduction processes. Some of these
commenters suggested that we should delay the 30 ppm standard, and
recommended a range of suggested deadlines (2005-2007).
We also received many comments which suggested that the ABT program
restricted the generation of credits, and provided no certainty that
credits would be generated prior to 2004. Commenters stated that two
features in particular--the delay in establishing each refinery's
sulfur baseline due to 1997-98 data review and the strict 150 ppm
``trigger'' for generating credits--caused them to question whether
adequate sulfur credits would be available. If credits could not be
guaranteed early enough to forestall investment decisions, refiners
would be forced to begin construction earlier than we had projected.
Under such a scenario, the costs of the program would be substantially
greater, and many commenters suggested that, regardless of cost, it
would be impossible for the entire industry to meet the deadline (due
to limitations on engineering design and construction resources as well
as the time required to obtain permits).
Finally, we received many comments which argued that not all
refineries would be able to concurrently comply with the proposed
standards in the time period provided, given the competition for
engineering resources and the time needed for construction of
desulfurization equipment. These comments focused specifically on small
refineries (owned by both small and large corporations) and refineries
that were relatively isolated geographically (such as many refineries
in the Rocky Mountain region) which had little access to other sources
of gasoline should they have difficulty in complying with our
requirements. The commenters generally argued that these refiners
needed more time than the rest of the industry to meet our proposed
standards. Some of the commenters also argued that the standards
applicable to many of these refiners should be less stringent because
of their belief that the environmental needs of the states where these
refineries were located and/or marketed gasoline were small relative to
the needs of other states. Suggestions for temporary and permanent
regional programs which provided less stringent control in the Western
half of the country were included with many of these comments.
Based on what we've learned from the comments received and
additional information we've gathered, we have revised our analysis of
when refiners will invest in desulfurization equipment and how the
sulfur ABT program can

[[Page 6753]]

best help to distribute these investments over several years while
maintaining the original goals of the program. The following is a brief
summary of our new analysis; a more complete explanation of our
assumptions can be found in the RIA.
About 15 percent of current domestic gasoline production already
meets the gasoline sulfur standard, or can do so with very little
additional capital investment, and at most a small increase in
operating cost. The remainder of the industry--the majority of U.S.
refineries--will have to install at least one desulfurization
processing unit to lower gasoline sulfur to the required levels.
Furthermore, many of these refineries will need to make changes to
their operations in advance of 2004 simply to comply with the 300 ppm
cap standard, even if they can obtain sufficient ABT credits to delay
compliance with the 30 ppm refinery average standard. Refiners facing
this situation will need to make their decisions within a year or at
most two from today's action. From the comments we received and
discussions we've had with refiners and technology vendors, we
acknowledge that some of the newer, more promising processes may not be
in operation for sufficient time to gain valuable operating experience
(one to two years of operation) until 2002 or later. Hence, we now
believe that some refiners may choose from one of the traditional,
commercially-demonstrated desulfurization processes, even though these
technologies may be more costly, to meet our standards.
However, we continue to believe that the majority of refiners will
delay construction (taking advantage of the sulfur ABT program and
perhaps making modest operational changes in the interim) and will have
a wide range of technological options to choose from, at reduced
capital investment and operating costs compared to the more traditional
approaches. Examples of these technologies are CDHydro and CDHDS
(licensed by the company CDTECH), Octgain 125 and Octgain 220 (licensed
by Mobil Oil), S Zorb (licensed by Phillips), IRVAD (licensed by Black
& Veatch), and others. These technologies generally use conventional
refining processes combined in new ways, with improved catalysts and
other design changes that minimize the undesirable impacts (such as a
substantial loss in octane) and maximize the effectiveness of the
desulfurization approach. Since these processes provide less costly
ways to reduce gasoline sulfur, we have based our economic assessment
(summarized in Section IV.D. below) on the presumption that the
majority of refiners will elect to use one of these processes to meet
the 30 ppm standard, even if it requires delaying compliance (through
the purchase of ABT program credits) until 2006.
However, after considering the data available to us about current
refinery sulfur levels and the ability of refiners to reduce sulfur
levels to meet the standards, we have made several modest changes to
the program. These changes will not affect the environmental
performance of the proposed program. We agree that the declining cap
had the unintended consequence of forcing investments earlier than
desired for an orderly transition to the 80 ppm cap. Thus, we have
changed the program from the proposal, establishing a 300 ppm per-
gallon cap in 2004 and 2005. We do not expect this change to have an
impact on the environment (or on the Tier 2 vehicles that will be
introduced in this interim period) since average sulfur levels will be
required to decrease due to the declining corporate average, which
begins in 2004. We kept the corporate average standards proposed for
2004 and 2005, but are permitting inter-company trading around these
standards. We believe this change will provide further flexibility to
the industry in allowing some refineries to delay construction and
encourage others to move forward sooner. Having now concluded that many
refiners would benefit from an additional year to evaluate and consider
the technological options before having to install equipment to meet
the 30 ppm standard, we have delayed this standard for one year. In
acknowledgment that some areas of the country have less urgent
environmental needs for the emissions reductions that this program will
bring, and that many of the refiners that supply gasoline to these
areas are ones which will have the most difficulty in meeting the
standards, we have finalized a geographic phase-in of the standards to
complement the temporal phase-in applicable to the rest of the
industry. Thus, in certain states in the West, refiners have the option
of meeting interim standards while delaying compliance with the 30 ppm
average until 2007. Finally, we have made changes to the sulfur
baseline requirements and the credit trigger to help ensure that the
sulfur ABT program functions as we originally envisioned it would.
These changes will encourage reductions in gasoline sulfur levels
beginning as early as 2000, while providing enough flexibility to
require the majority of refineries to meet a 30 ppm average sulfur
standard by 2006. Overall, the industry will be able to spread the
needed investments over several years rather than having to comply as a
whole by 2004, and will be able to maximize the use of the most
efficient and lowest cost technologies. While we have provided
additional flexibility for the industry, we have done so without
compromising the environmental benefits of the program in 2004 and
beyond when compared to our proposal.
The following sections summarize the requirements for gasoline
refiners and importers, including our geographic phase-in requirements;
special provisions for small refiners, and our plans to facilitate the
construction permitting process to enable refiners to install gasoline
desulfurization technology in a timely manner. Section VI provides
additional information about the compliance and enforcement provisions
that will accompany these requirements. More detailed information in
support of the conclusions presented here is found in the RIA and in
our RTC document.
1. Gasoline Sulfur Standards for Refiners and Importers
This section explains who must comply with the gasoline sulfur
control requirements, the standards and deadlines for compliance, and
how refiners can use the ABT program to meet the standards. The last
section discusses how individual state gasoline sulfur programs are
affected by today's action. Standards specific to eligible small
refiners are presented in Section IV.C.2.
a. Standards and Deadlines that Refiners/Importers Must Meet
Anyone who produces gasoline for sale in the U.S. must comply with
these regulations. This includes anyone meeting our definition of a
refiner (including blenders, in most instances) and importers. Certain
refiners may qualify for temporarily less stringent standards and
deadlines because these companies either (1) market gasoline in the
temporary geographic phase-in area (explained in section b below), or
(2) they qualify under our definition of small refiner (explained in
section IV.C.2 below). Foreign refiners may also have separate
requirements, if they qualify as small refiners.
These requirements will apply to all gasoline sold in the U.S.,
including Alaska, Hawaii, Puerto Rico, American Samoa, the Virgin
Islands, Guam, and

[[Page 6754]]

the Northern Mariana Islands. \78\ This national approach is
appropriate, based on our conclusions that vehicle emissions must be
reduced nationwide to adequately protect public health and the
environment and Tier 2 vehicles require protection from the harmful
impacts of gasoline sulfur regardless of where they are operated.
---------------------------------------------------------------------------

\78\ Gasoline sold in California is exempt from meeting these
Federal standards, due to our belief that California gasoline
already meets or exceeds these requirements. See Section VI for more
discussion on this issue.
---------------------------------------------------------------------------

Table IV.C.-1. summarizes the standards for gasoline refiners and
importers. There are three standards which refiners and importers must
meet. In 2004 and beyond, every gallon of gasoline produced is limited
by a per-gallon maximum or ``cap.'' The cap standard becomes effective
January 1, 2004 (and January 1 of subsequent years as the cap standard
changes). Also, in 2004 and 2005, each refiner must meet an annual-
average standard for its entire corporate gasoline pool. Finally, each
individual refinery is subject to a refinery average standard,
beginning in 2005. Refineries that do not take advantage of the sulfur
ABT program will have actual sulfur levels averaging 30 ppm beginning
in 2005. Additional details about the requirements for meeting these
standards is found in the following sections.

Table IV.C.-1.--Gasoline Sulfur Standards for Refiners, Importers, and
Individual Refineries
[Excluding Small Refiners and GPA Gasoline]
------------------------------------------------------------------------
Compliance as of-- 2004 a 2005 2006+
------------------------------------------------------------------------
Refinery Average, ppm \b\........ ........... 30 30
Corporate Pool Average, ppm ^c.... 120 90 ...........
Per-Gallon Cap,\d\ ppm........... 300 300 80
------------------------------------------------------------------------
NOTES:
\a\ We project that the pool averages will actually be below 120 ppm in
2004. For a discussion of how the program gets early sulfur reductions
before 2004, see section IV.C.1.c.
\b\ The refinery average standard can be met through the use of sulfur
credits or allotments from the sulfur ABT program, as long as the
applicable corporate pool average and per-gallon caps are not
exceeded, as explained in Section IV.C.1.c.viii.
^c. The corporate pool average standard can be met through the use of
corporate allotments obtained from other refiners, if necessary, as
explained in Section IV.C.1.c.iii.
\d\ In 2004, exceedances up to 50 ppm beyond the 300 ppm cap are
allowed. However, in 2005, the cap for all batches will be reduced by
the magnitude of the exceedance.

i. What Are the Per-Gallon Caps on Gasoline Sulfur Levels in 2004 and
Beyond?

To reduce the potential for permanent damage to the emission
controls of Tier 2 vehicles and later NLEV vehicles, we are
implementing caps on the sulfur content of every batch of gasoline
produced or imported into the country beginning in 2004. As shown in
Table IV.C.-1, a cap of 300 ppm is first implemented in 2004. This cap
remains in 2005. In 2006 and beyond, the cap is lowered to 80 ppm.
These caps apply at the refinery gate. Sulfur caps are also applied to
gasoline downstream of the refinery; see Section VI for additional
discussion of downstream cap standards. These downstream caps will
facilitate compliance and enforcement without changing the way the
distribution system currently functions.
Several commenters suggested the rule should also include a
provision to address the occasions when refiners must temporarily take
processing units out of operation so that planned, recurring
maintenance can be performed, commonly termed ``turnarounds,'' or if
processing units are unexpectedly taken out of operation due to
accident or malfunction, commonly termed ``upsets.'' These commenters
expressed particular concern that the gasoline produced at a refinery
may not meet the sulfur cap standards when a refinery's desulfurization
unit is not operating. These commenters contended that the regulations
should allow refiners to produce gasoline that exceeds the cap standard
for a limited time where the excess sulfur is due to a turnaround or
upset. However, they also suggested that the refiner should be required
to meet the refinery average standard with the high sulfur gasoline
included in its average calculation in order to create an incentive for
refiners to limit the volume and sulfur content of high sulfur
gasoline.
Today's rule does not grant relief to refiners because of
turnarounds or upsets. While the concern raised by the commenters is
reasonable, the solution they suggested would nevertheless result in
distribution of gasoline exceeding the cap standards. The cap standards
are necessary because gasoline with higher sulfur levels will
significantly harm or destroy the emission controls used in Tier 2
vehicles.
We believe there are strategies refiners can use to mitigate or
eliminate the difficulties associated with turnarounds and upsets. For
example, some refiners schedule turnarounds for a number of refinery
processing units at the same time when the refinery largely stops
producing gasoline, thereby avoiding the need to produce any high
sulfur gasoline. In other situations it may be possible for a refiner
to store high sulfur products until the desulfurization unit is
operating or to transfer high sulfur products to a neighboring refinery
for desulfurization.
We commit to continue evaluating the turnaround issue especially as
new technologies are introduced. Based on our evaluation, if a problem
is evident and if an appropriate solution can be devised, we will act
at that time.
In 2004, if any batch of gasoline \79\ exceeds the 300 ppm cap (up
to 350 ppm), then the cap for all batches produced by the refinery in
2005 will be reduced by the magnitude of the exceedance. For example,
if any given batch of gasoline has a cap of 325 ppm (a 25 ppm
exceedance) in 2004, then the cap becomes 275 ppm for all batches of
gasoline produced by that refinery in 2005. However, at no time in 2004
can a batch be higher than 350 ppm sulfur. We have made this adjustment
to accommodate those refiners who would have to invest in control
technologies to meet the 300 ppm cap in 2004 (perhaps at a higher cost
than they would incur if they could delay the investment a year) but
could otherwise meet a slightly higher cap through operational changes
which would not require new equipment.
---------------------------------------------------------------------------

\79\ Including gasoline produced for use in the geographic
phase-in area and small refiner gasoline.

---------------------------------------------------------------------------

[[Page 6755]]

ii. What Standards Must Refiners/Importers Meet on a Corporate Average
Basis?

Refiners and importers must meet annual-average, volume-weighted
sulfur standards for their entire corporate gasoline pool in 2004 and
2005. In 2004, this standard is 120 ppm; in 2005, it is reduced to 90
ppm. In 2006 and beyond, there will no longer be a corporate pool
average standard, since each refinery and importer will be held to its
own single refinery average standard, as discussed in the next section.
These standards represent the maximum allowable sulfur levels, on
an annual average basis, for each refiner/importer, volume-weighted
across all refineries owned and operated by that refiner (or all
gasoline imported by the importer in the calendar year), rather than at
each individual refinery or by each batch of gasoline. Thus, a
refiner's gasoline may exceed the average standard of 120 ppm at one
refinery, if sufficient gasoline below that standard is produced at its
other refinery(ies), such that its corporate, volume-weighted average
sulfur level does not exceed 120 ppm. Alternatively, allotments may be
used to meet this requirement. This requirement does not apply to small
entities or to corporations that do not have to meet the pool average
standard in the GPA program. For compliance with this corporate
averaging requirement, as well as with the other requirements of this
subpart, we consider a parent corporation owning wholly-owned
subsidiaries that also own refineries to be the refiner of these
facilities. Thus, the parent corporation must comply with refiner
corporate average requirements. In its compliance calculations, the
refiner must include the gasoline produced at the refineries it owns,
plus the gasoline produced at the refineries owned by its wholly-owned
subsidiaries.
For purposes of compliance, we proposed that a joint venture, in
which two or more refiners collectively own and operate one or more
refineries, be treated as a separate refining corporation under the
gasoline sulfur requirements. Hence, a refinery owned by a joint
venture would have been included in the corporate pool calculations of
the joint venture, and could not have been included in calculations
with other refineries solely owned by one of the parties to the joint
venture. Based on comments we received on this issue which argued that
a company with majority ownership in the joint venture should be
allowed to count the jointly held refinery in its corporate average, we
have revised our treatment of refineries owned by joint ventures. Each
joint venture must separately meet the corporate pool average standard,
whether the joint venture owns one or multiple refineries. If a joint
venture fails to meet the corporate pool average standard, then each
partner in the joint venture is jointly and severally liable for the
violation. However, if one partner to a joint venture refinery includes
the joint venture refinery in its corporate pool, and that corporate
pool meets the corporate pool average standard, then the joint venture
will be considered by EPA to be in compliance (if the joint venture
owns only the one refinery). If the joint venture owns multiple
refineries and only one or some of the refineries is included in the
corporate pool calculations of one partner, compliance by the joint
venture with the corporate pool average standard will be judged based
on the average sulfur levels of the remaining refinery(ies) owned by
the joint venture.
In meeting the corporate average stds in 2004 and 2005, refiners
and importers may use allotments as discussed in IV.C.1.c below.

iii. What Standards Must be Met by Individual Refineries/Importers?

Beginning in 2005, every refinery must meet an average standard of
30 ppm sulfur at the refinery gate on an annual, volume-weighted basis.
Similarly, every importer must meet the 30 ppm average standard
beginning in 2005. (These requirements do not apply to small entities
or to GPA gasoline). In meeting this standard, individual refineries
and importers may use credits generated or purchased under the
provisions of the sulfur ABT program discussed below in Section
IV.C.1.c, and/or, in 2005 (only), sulfur allotments (as described in
the previous section) obtained from a refiner who has excess allotments
to sell, if they are unable to comply based on their actual gasoline
sulfur levels. Hence, the actual average sulfur levels for gasoline
produced at some refineries can be higher than 30 ppm in 2005, but only
if refiners use (1) credits generated from cleaner gasoline produced
early and/or (2) allotments generated by a refiner which produces
gasoline averaging, on a corporate basis, lower than 90 ppm in 2005.
However, the corporate pool average standards and per-gallon caps will
limit the degree to which gasoline can exceed 30 ppm on average.
We allow refiners to use either sulfur allotments or ABT credits to
meet the 30 ppm standard in 2005 for several reasons. First, this is an
environmentally neutral approach because the national pool in 2005 will
still average no greater than 90 ppm, since every refiner must meet the
corporate average standard before applying allotments to the compliance
of any refineries with the 30 ppm standard. Second, it provides
refiners who have excess allotments in 2005 an additional market for
those allotments, thus giving refiners an incentive to exceed the 90
ppm corporate average standard in 2005. In either case, the reductions
will have occurred and thus the allotments and credits have very
similar purposes and thus should be interchangeable.
In 2006 and beyond, the 30 ppm refinery average standard continues
to be a requirement for every refinery or importer. The sulfur credits
generated in the ABT program may be used by refineries or importers to
comply with this requirement. However, because of the 80 ppm cap in
these years, we expect that the majority of refiners/importers will
average 30 ppm, although some individual refineries/importers could
average slightly more or less (if the refineries/importers bank, sell,
or purchase credits to meet this standard, as explained in the ABT
discussion below). Furthermore, the majority of credits will expire at
the end of 2006.
b. Standards and Deadlines for Refiners/Importers Which Provide
Gasoline to the Geographic Phase-In Area (GPA)
As indicated above, certain refiners may qualify for temporarily
less stringent standards and deadlines for some or all of their
gasoline because these companies either (1) produce gasoline to be sold
in the temporary geographic phase-in area (GPA) or (2) qualify under
our definition of small refiner. In this section, we explain the
geographic phase-in area of our program and the interim standards and
deadlines for compliance in that area. The provisions that apply to
qualifying small refiners are described in section IV.C.2., below.

i. Justification for Our Geographic Phase-In Approach

In addition to phasing in our national gasoline sulfur program
temporally from 2004-2006, we are phasing in our program
geographically. In response to our proposal, we received many comments
from the refining industry regarding timely implementation of our
proposed gasoline sulfur program. Commenters argued that not all
refineries would be able to concurrently comply with the proposed
standards in the time period provided, given the competition for
engineering resources and the time needed for construction of

[[Page 6756]]

desulfurization equipment. In consideration of these comments, we have
made some modifications to enhance the timing of our program without
compromising the environmental benefits we expected from our proposal.
As part of our assessment we also examined other phase-in
approaches which might enhance the orderly introduction of refining
technology without jeopardizing the environmental benefits of our
program. As a result of this assessment, we have concluded that many
states in the Great Plains and Rocky Mountain areas of the United
States have a somewhat less urgent environmental need for ozone
precursor reductions in the near term. Moreover, their gasoline supply
is dominated by that produced by small capacity, geographically-
isolated refineries located therein. As a general rule, refineries in
this area will have the most difficult time of all refineries
nationwide in competing for the vendor, supply, engineering, and
construction resources needed to modify their refineries to comply with
the standards. Based on 1998 Department of Energy data, over 80 percent
of the gasoline sold in this area is produced by the relatively small
refineries located within the region.\80\ Similarly, Alaska faces a
less urgent environmental need for reductions in ozone precursors and
has refineries which are challenged and geographically isolated.
---------------------------------------------------------------------------

\80\ Much of this gasoline is produced by small volume
refineries that are not owned by small businesses, and are therefore
not afforded the flexibility of the small refiner provisions
described in Section IV.C.2.
---------------------------------------------------------------------------

A more orderly and cost-efficient phase-in of the 30 ppm standard
could be achieved if all gasoline sold in this area was subject to
somewhat less stringent standards than those in the rest of the country
for a short time. This approach will allow the refineries producing
gasoline for use in this area more compliance flexibility, more time to
install and prove out the equipment needed for compliance, and thus a
greater opportunity to reduce their overall costs. As described below,
this approach results in only a minimal loss in emission reduction
benefits. By stretching out demand for design, engineering,
construction and other related services during the 2000-06 period,
these provisions should also help to reduce the overall costs of the
gasoline sulfur program.
The remainder of this section is divided into two parts. The first
describes the rationale for development of this approach and how we
identified the appropriate area, and the second provides a description
of the requirements for refiners and importers that produce fuel for
sale in the area.

ii. What Is the Geographic Phase-in Area (GPA) and How Was it
Established?

As we considered the geographic phase-in approach, we aimed to
minimize the environmental losses which could occur from exposing Tier
2, NLEV, (and other) vehicles to higher gasoline sulfur levels when the
gasoline sulfur standards are being phased in nationwide. We used two
criteria to develop and evaluate this approach: (1) relative
environmental need and (2) the ability of U.S. refiners and the
distribution system to provide compliant gasoline.
The states we have identified for the GPA are shown in Figure IV.C-
1.\81\
---------------------------------------------------------------------------

\81\ Alaska, Colorado, Idaho, Montana, New Mexico, North Dakota,
Utah, and Wyoming

BILLING CODE 6560-50-P
[GRAPHIC] [TIFF OMITTED] TR10FE00.005

BILLING CODE 6560-50-C
The first and primary criterion we considered in defining this area
was environmental need. In defining the GPA, we identified those states
that have somewhat less urgent environmental need in the near term for
reductions in ozone precursors and whose emissions are less important
in terms of ozone transport concerns. This area includes some states
that are located in the Great Plains and the Rocky Mountains, as well
as Alaska. Most states within the Rocky Mountains and Great Plains do
not have a compliance problem with the 1-hour ozone standard in the
near term, although they do have concerns in terms of maintaining
compliance with the particulate matter standard. However, there are two
states (Arizona and Nevada) in the Rocky Mountain vicinity that do have
ozone air quality concerns. These states have instituted local fuel
quality programs (in Phoenix, AZ and Las Vegas, NV) to reduce ozone
precursor emissions. In addition, as shown in Table III.C-2, Arizona
and Nevada are projected to have concerns with PM10 compliance in the
future. Given these factors, we excluded them

[[Page 6757]]

from the phase-in area and its temporarily less stringent standards
except as described below in Section IV.C.1.b.vii for counties and
tribal lands in adjacent states.
We also defined the phase-in area based on the relative difficulty
of producing or obtaining complying gasoline. The refining industry in
the GPA is dominated by relatively low capacity, geographically-
isolated refineries many of which are owned by independent companies.
Such refineries face special challenges in complying with the
requirements of the national program by 2004 because their crude
capacity, corporate size, and location make it difficult for them to
compete for the design, engineering, and construction resources needed
to comply by 2004.
Furthermore, an assessment of 1998 gasoline production and use data
and information on the products pipeline system shows that states in
the GPA and portions of several adjoining states are solely or
predominantly dependent on gasoline produced by these refineries and
have limited or no access to gasoline from other parts of the country.
Based on this analysis, we concluded that several states and portions
of other states meeting our first criterion (less urgent environmental
need for ozone precursor emission reductions) also face the likelihood
of a supply shortage of low sulfur gasoline. Providing low sulfur
gasoline to these states and adjoining areas is expected to be more
difficult and costly in the near term. Section IV.C.1.b.vii below,
discusses how the adjoining areas (counties/tribal lands) will be
identified.
Thus, we believe it is appropriate to phase in the 30 ppm average,
80 ppm cap standards in these areas by allowing an additional year
compared to the rest of the country, rather than delaying
implementation of the standards nationwide to accommodate these states.
Under this approach, the areas with the most urgent need for the ozone
reduction benefits associated with low sulfur gasoline will realize
them as soon as is feasible, and other areas will experience them
shortly thereafter.
On the other hand, much of the area in the adjoining states has
significant pipeline, rail, barge, and truck access to gasoline which
will be capable of meeting the standards in Table IV.C-1 beginning in
2004. Even if these states have less environmental need in the near
term, there are health benefits (particulate and air toxic emission
reductions) as well as performance benefits for vehicle emission
control systems (including avoidable irreversible sulfur effects) which
need not be foregone. Therefore, we concluded that since it will not be
more difficult to send gasoline to these adjoining areas through the
distribution system, the significant environmental benefits of
requiring low sulfur gasoline as early as is feasible justifies
excluding these states from the GPA.
Some might argue that there are other states which should be
considered under this program. However, based on our criteria of
environmental need (including ozone transport and irreversibility
concerns) challenged refineries, and limited access to complying
gasoline we could identify no other states or territories which to
include.

iii. Standards/Deadlines for Gasoline Sold in the Geographic Phase-in
Area

While the states in the GPA may have less of an environmental need
for ozone precursor reductions in the near term, there are significant
environmental reasons to make the program as stringent as possible,
still enabling a smooth transition to low sulfur gasoline nationwide.
Toward that end, we are establishing the following requirements for
gasoline sold in the GPA, which we view as the appropriate balance
between these two factors.
The GPA provision covers all gasoline produced or imported for use
in the GPA, whether refined there or brought in by pipeline, truck,
rail, etc.\82\ Foreign refiners are involved in this program through
the importers, who are, in fact, the regulated entities. Refineries and
importers must meet a 150 ppm average and a 300 ppm cap for all
gasoline produced or imported for the GPA under this program beginning
January 1, 2004. However, if a refinery's/importer's 1997-98 average
sulfur level is less than 150 ppm, then that refinery's/importers
gasoline has a standard of its baseline plus 30 ppm but in no case
greater than 150 ppm. For example, a refinery with a baseline of 100
ppm would have a sulfur standard of 130 ppm for its GPA gasoline, a
refinery with a baseline sulfur level of 140 ppm would have a standard
of 150 ppm for its GPA gasoline, and a refinery with a baseline of 200
ppm would have a standard of 150 ppm for its GPA gasoline. Furthermore,
if under the ABT provisions discussed below and in section IV.C.1.c, a
refinery/importer generates credits (in 2000-2003) and/or allotments
(in 2003) by dropping its refinery/imported gasoline average below 150
ppm then the baseline for that refinery is set at the new level and the
standard becomes baseline plus 30 ppm but not greater than 150 ppm.
This is to ensure that refineries and importers who already are lower
than the 150 ppm standard on average maintain current sulfur levels.
The 30 ppm factor is intended to allow some flexibility for refineries
and importers whose 1997 and 1998 levels are an aberration from normal
operations or who face changes in crude slates in future years.
---------------------------------------------------------------------------

\82\ As discussed below, refiners can supply gasoline not
designated as GPA gasoline to the GPA, provided it meets the
standards in Table IV.C.-2. Also, the GPA standards do not apply to
gasoline produced by small refiners that is used in the GPA.
---------------------------------------------------------------------------

Corporate pool average standards apply in the national gasoline
sulfur program for calendar years 2004 and 2005. Most refiners/
importers producing gasoline for use in the GPA market the majority of
their gasoline outside of the GPA where they compete with many other
refineries. Since the phase-in of the national program expects
compliance with the 120/90 ppm corporate pool average standards in 2004
and 2005, we are requiring that refiners/importers who market the
majority (greater than 50 percent of production volume) of their
gasoline outside of the GPA to account for the sulfur levels of their
GPA gasoline in their calculation for compliance with the corporate
pool average standards.
To provide additional flexibility during this phase-in, refiners
may use sulfur ABT credits and allotments (as explained in IV.C.1.c) to
meet these standards. Refineries producing GPA gasoline can generate
credits beginning in 2000 under the provisions of the national program
(described in section IV.C.1.c). Also, refineries/importers marketing
gasoline in the GPA may through extraordinary measures be able to
generate credits in 2004-2006. To qualify they must achieve levels
below 150 ppm or their more stringent baseline levels as discussed
above whichever is less. Under these circumstances, these refineries/
importers can earn credits for the GPA gasoline they produce during
2004-06. Credits generated under the GPA program are fully fungible
with national credits and are subject to the same regulatory
requirements.
The national program includes provisions which permit refiners/
importers to generate allotments for use in 2004 and 2005. Refiners and
importers marketing gasoline in the GPA may only generate sulfur
allotments in 2004 or 2005 if their corporate average sulfur level
meets the corporate pool average standards for each year (as indicated
in Table IV.C.1), including gasoline produced for the GPA, if
applicable. Refiners not compelled to meet the corporate pool

[[Page 6758]]

average standards under the GPA may not generate allotments.
The temporary provisions for the GPA apply for three years, 2004
through 2006. Since the low sulfur standards for the rest of the
country require compliance with a 30 ppm refinery average standard and
an 80 ppm gallon cap in 2006, the geographic phase-in provides an
additional year to reach those standards. This extra year and the
somewhat less stringent standards during the phase-in will provide the
refining industry the opportunity for more orderly transition to the
30/80 ppm standards by 2007.
Requirements for gasoline sold in the GPA are summarized in Table
IV.C.-2, below. Gasoline produced by refiners subject to the small
refiner standards described in Section IV.C.2. of this notice is not
subject to the provision of the geographic phase-in, since the small
refiner provisions apply to eligible refiners regardless of geographic
location. Gasoline produced by such refiners can be sold nationwide,
including in the GPA.

Table IV.C.-2.--Gasoline Sulfur Standards for the Geographic Phase-In Area
[Excludes Small Refiners]
----------------------------------------------------------------------------------------------------------------
Compliance as of-- 2004 2005 2006
----------------------------------------------------------------------------------------------------------------
Refinery GPA Gasoline Average \a\, ppm..... 150 150 150.
Corporate Pool Average \b\, ppm............ 120 90 Not Applicable.
Per-Gallon Cap \c\, ppm................... 300 300 300.
----------------------------------------------------------------------------------------------------------------
Notes:
\a\ The refinery average standard for GPA gasoline is the more stringent of: 150 ppm; the refinery 1997-1998
baseline plus 30 ppm; or the sulfur level from which early credits were generated plus 30 ppm. Refiners can
use credits or allotments to meet the average.
\b\ Applies only to refiners/importers which sell >50% of their gasoline outside the GPA.
\c\ As discussed above, in 2004 both GPA and Non-GPA gasoline may have a sulfur content as high as 350 in which
case the refinery or importer becomes subject to a correspondingly more stringent cap standard in 2005.

iv. What Are the Per-Gallon Caps on Gasoline Sulfur Levels in the
Phase-in Area?

The sulfur level caps for gasoline sold in the phase-in area and
the rest of the nation are the same in 2004 and 2005, but in 2006 the
cap remains at 300 ppm in this area while it declines to 80 ppm for the
rest of the country. To assure that compliance at the refinery gate is
correct regardless of where the gasoline is ultimately sold, as
gasoline intended for the GPA moves in the distribution system to or
through the geographic area it must be identified as phase-in area
gasoline in product transfer documents and must remain segregated from
gasoline intended for use outside this area. In addition, use of phase-
in area gasoline is prohibited outside the GPA, but the converse is
allowed, i.e., gasoline designated for use outside the GPA can be used
in this area. For all three years, refiners and importers must meet the
requirements described in Tables IV-C.1 and IV-C.2, as applicable, and
therefore must maintain refinery or import records as applicable as to
where a gasoline batch is sold. \83\
---------------------------------------------------------------------------

\83\ These segregation and designation requirements do not apply
to gasoline produced by refiners subject to the small refiner
standards described in Section IV.C.2. This is because small refiner
gasoline can be sold anywhere in the country, and is not subject to
different standards depending on where it is sold.
---------------------------------------------------------------------------

We recognize that this higher standard/cap for one year could
create the incentive for those not marketing gasoline in the GPA today
to seek a market to sell higher sulfur gasoline and for others to seek
to increase market share. While this is indeed allowable under our
program and is perhaps to be anticipated in a free market system, in
all likelihood the incentives are small. Such refiners/importers would
still have to meet the 150 ppm average and would perhaps face increased
shipping and marketing costs. Nonetheless, we plan to monitor market
developments to assess whether such a provision creates significant
market shifts or the potential for increases in average sulfur levels
in the GPA gasoline.

v. How Do Refiners/Importers Account for GPA Fuel in Their Corporate
Average Calculations?

Those refiners or importers that sell all of their gasoline to the
GPA (i.e., they produce no fuel for use outside the GPA), regardless of
whether they are located within or outside of the area, have refinery/
importer standards that are equal to the least of 1) 150 ppm, 2) the
refinery's or importer's 1997-98 average sulfur level plus 30 ppm or 3)
the refinery's or importer's lowest actual annual sulfur level plus 30
ppm in any year 2000-2003 if credits are generated. Because the
refiners produce all of their fuel for use in the GPA, they are exempt
from the corporate average standards in Table IV.C-1.
Furthermore, any refiner/importer which certifies 50 percent or
more of its gasoline production volume for sale as GPA gasoline in 2004
and 2005 is not required to meet the corporate pool average for that
year for its entire gasoline pool. Not only would it be difficult to
comply on average (if it were assumed that the GPA gasoline was 150 ppm
and non-GPA gasoline was 30 ppm), but also it would undermine the
achievement of the basic goal of a more orderly and efficient phase-in
of low sulfur gasoline since the flexibility afforded by the GPA could
be diminished.
Otherwise, those who produce less than 50 percent of their gasoline
for the GPA (which is the majority of those refiners which market in
both locations), must meet the corporate pool average standards in 2004
and 2005 for their entire gasoline pool. Thus, such refiners must
compensate for the higher sulfur levels of their GPA gasoline by
producing non-GPA gasoline that averages sufficiently less than 120 ppm
in 2004 and 90 ppm in 2005 to ensure that their corporate average meets
the corporate pool average standard for each year. Importers who
provide less than 50 percent of their gasoline to the GPA must also
include their GPA gasoline in their overall corporate pool average
calculation. Alternatively, the refiner can use sulfur allotments to
meet the corporate pool average standard for its total gasoline
production, including gasoline sold inside and outside the phase-in
area. Since most refiners which sell gasoline both in and outside the
GPA sell the vast majority outside the GPA the additional flexibility
provided for gasoline sold in the phase-in area should not
significantly affect compliance with the corporate pool average
standard for a refiner's nationwide production.

vi. How Do Refiners/Importers Apply for the Geographic Phase-in Area
Standards?

As part of program administration, we are requiring that any
refiner/importer

[[Page 6759]]

expecting to sell gasoline in this area during the phase-in period
(2004-2006) make application to EPA in writing by December 31, 2000.
This application would provide the minimum information needed by EPA to
characterize a refiner's/importer's participation, establish the
applicable standards if the 1997-98 average is less than 150 ppm, and
establish our enforcement program for refiners/importers in this area
for gasoline entering or leaving the area. Participation on the part of
any refinery or importer is voluntary. At any time, a refiner/importer
who previously opted into the GPA program may produce gasoline meeting
the standards in Table IV.C-1 in the GPA, or may cease producing
gasoline for the GPA (and produce gasoline meeting the standards in
Table IV.C-1 solely outside of the GPA). Such a decision would affect
the averages/caps which apply to the gasoline sold in the GPA. Gasoline
sold in the GPA that is not designated as GPA gasoline is considered
Non-GPA gasoline for purposes of compliance with the corporate pool
average requirement and refinery average requirements.

vii. How Will EPA Establish the GPA in Adjacent States?

EPA is establishing a geographic phase-in area that encompasses
eight states (MT, ND, ID WY, CO, UT, NM, AK). In addition, counties and
tribal lands in states immediately adjacent to these which received a
majority of their gasoline in calendar year 1999 from a refinery(ies)
located within the GPA will be covered by the phase-in area provisions.
The criteria to identify these additional counties and tribal areas are
designed to identify areas whose gasoline distribution system is
closely tied to the eight states such that they share the same
characteristics of gasoline supply. Therefore, dispensing outlets
(retail and private) in such areas will continue to have access to that
gasoline in most cases. Distribution and production of gasoline in
these additional areas will be subject to the same standards and
requirements as gasoline in the eight states identified above.
At this time, EPA is not able to identify all the counties and
tribal lands that would be included in the phase in area. In light of
the air quality benefits of introducing low sulfur gasoline as quickly
as possible, we want to ensure that the phase-in area is accurately
identified and that including any areas outside these eight states will
not have a significant adverse air quality impact on any counties or
tribal lands that are included in the phase-in area. EPA will be
working with interested stakeholders will to conduct an assessment to
determine which counties/tribal lands within the immediately adjacent
states meet the criteria as described in the regulatory text. EPA
expects to complete action on this assessment by December 31, 2000. c.
How Does the Sulfur Averaging, Banking, and Trading Program Work?
The sulfur ABT program provides flexibility to refiners by giving
them more time to bring all of their refineries into compliance with
the corporate averages in 2004 and 2005 as well as the 30 ppm
individual refinery standard in 2005 and beyond. ABT will provide the
opportunity for reduced costs by allowing the industry the flexibility
to average sulfur levels among different refineries, between companies,
and across time. With ABT, some refineries will be able to delay
installation of desulfurization equipment, because other refineries
will generate sulfur allotments and credits through early sulfur
reductions. In this way, installation of desulfurization technology
will be spread out over a longer period of time than would be the case
without ABT. Since, with the banking provisions, reductions in annual
average sulfur levels which occur as early as 2000 have a value during
program implementation, the ABT program provides an incentive for
technological innovation and the early implementation of refining
technology.
The ABT program also provides the opportunity for meaningful
emissions reductions in 2004 because it allows the Tier 2 standards to
be implemented earlier than might otherwise have been possible (if the
Tier 2 standards were delayed to provide the refining industry more
time to comply), and because it provides direct environmental benefits
even in the years before Tier 2 vehicles are introduced. One benefit is
related to the effect of gasoline sulfur on exhaust emissions, as
discussed in the Regulatory Impact Analysis. This benefit will result
both from older vehicles on the road (Tier 0 and Tier 1 emission
control technologies, which have some degree of sulfur sensitivity and
will benefit from sulfur reductions which occur prior to implementation
of the refiner and refinery standards summarized in Table IV.C-1) and
from NLEV vehicles (which are more sensitive to sulfur than earlier
technologies) which will continue to be sold while Tier 2 vehicles are
phased-in. Another environmental benefit is the reduction in
atmospheric sulfur loads as a direct result of reduced gasoline sulfur
levels, leading to reduced emissions of sulfur-containing compounds
from motor vehicles.
The following sections explain the requirements for participation
in the sulfur ABT program for allotments and credits.

Sulfur Allotment Program

i. Generating Allotments Prior to 2004

To provide additional incentive for early sulfur reductions and to
enhance the overall feasibility and cost effectiveness of the gasoline
sulfur control program, we are implementing a sulfur allotment program.
While few commenters supported the sulfur allotment concept in the
NPRM, a number suggested that greater flexibility for compliance in the
early years would be helpful. The program described below is in
addition to the early sulfur credit program described elsewhere.
For 2003, refineries can generate sulfur allotments (in ppm-
gallons) by producing gasoline containing less than 60 ppm sulfur on an
annual-average basis. This 60 ppm ``trigger'' was chosen to reward
refineries who demonstrate compliance using technology designed to meet
the 30 ppm standard before 2005. Once this 60 ppm trigger is reached,
allotments will be calculated based on the amount of reduction from 120
ppm. \84\ However, these allotments may be discounted depending on the
actual sulfur level. If a refinery fully demonstrates compliance by
producing gasoline with an annual average sulfur level of 0 to 30 ppm,
the allotments retain their full value--they are not discounted at all.
For actual sulfur levels of 31-60 ppm, which are indicative of a
partial demonstration of compliance with the ultimate low sulfur
standard, the allotments are discounted 20 percent. For example,
consider a refinery that has an average sulfur level of 50 ppm at the
end of 2003. That refinery would have generated 56 sulfur allotments
[(120 ppm - 50 ppm) x 0.8 x Volume (in gallons)] to be used or sold
in 2004. If that same refinery instead produced fuel with an average
sulfur level of 20 ppm at the end of 2003, then it would have generated
100 sulfur allotments [(120 ppm - 20 ppm) x volume (in gallons)] to
be used or sold in 2004.
---------------------------------------------------------------------------

\84\ If a refinery has a baseline sulfur level higher than 120
ppm (as described below in IV.C.1.c.v.), then credits are generated
from the baseline to 120 ppm and allotments from 120 ppm to the new
sulfur level (and discounted 20 percent if applicable).
---------------------------------------------------------------------------

ii. Generating Allotments in 2004 and 2005

For 2004 and 2005, refiners or importers (but not individual
refineries)

[[Page 6760]]

can generate allotments by producing gasoline that has a sulfur level
below the annual corporate average standard (120 ppm and 90 ppm). The
number of allotments generated is equal to the difference between 120
ppm (or 90 ppm) and the corporate average sulfur level. Allotments
generated by refiners or importers in 2004 and 2005 are not discounted,
unlike some of those that are generated by refineries in 2003. Refiners
that sell fuel to the GPA may also generate allotments by producing
fuel that is cleaner than the corporate average standards, regardless
of the volume of fuel that is produced for use in the GPA. On the other
hand, as explained in Section IV.C.2., gasoline produced by small
refiners who are complying with the standards in Table IV.C.-3 cannot
be used to generate sulfur allotments since these producers are not
required to meet a corporate average standard.

iii. Using Allotments in 2004 and 2005

Refiners and importers can use sulfur allotments that they generate
or purchase from other refiners/importers to demonstrate compliance
with the 120 ppm corporate standard in 2004 and the 90 ppm corporate
standard in 2005. Each refiner's sulfur allotment for 2004 and 2005
will be calculated based on the total volume of gasoline imported and
produced at their refineries (or only imported gasoline in the case of
companies that only import gasoline) and the corporate pool average
standard for that year. In anticipation of exceeding or falling short
of the standard for any one year, companies may trade sulfur
allotments, either in the compliance year or earlier (as early as the
year 2000). For example, a refiner that expects to produce a total of
2.5 billion gallons of gasoline in 2004 has a sulfur allotment of 300
billion ppm-gallons (120 ppm x 2.5 billion gallons). If its corporate
pool average is actually 200 ppm in 2004, it will exceed its 2004
allotment by 200 billion ppm-gallons (since 200 ppm x 2.5 billion
gallons = 500 ppm-gallons), and must obtain sulfur allotments from
another refiner to offset this increase. Similarly, if this refiner
expects to average 80 ppm in 2004, it has an excess of 100 billion ppm-
gallons to trade to other refiners. However, if a refiner trades away
part of its allotment, the refiner must still comply with the corporate
standard, just as another refiner has to do if it does not trade
allotments.
In 2005, refiners must comply both with the corporate average
standard and the refinery average standard for each of their
refineries. Once a refiner has established compliance with the 90 ppm
corporate average standard (with or without the use of allotments),
each of its refineries can then establish compliance with the 30 ppm
refinery standard through actual production of 30 ppm gasoline or
through the use of excess allotments and/or sulfur credits. Once
compliance with the 90 ppm corporate pool average standard is
established, the refiner would use 90 ppm as each of its refineries
actual sulfur level, then apply an appropriate number of credits or
allotments to meet the 30 ppm refinery average standard for each
refinery. (See discussion below for an explanation of how a refiner can
use both sulfur ABT credits and allotments to comply with the refinery
average standard in 2005.)

iv. How Long Do Allotments Last?

We expect most refiners will trade sulfur allotments well before
the end of each compliance year so they will have the needed certainty
of compliance with the corporate average standard. Our program allows
such trades to occur at any time during the year, although the refiner
is liable for any shortfall in compliance resulting from having traded
away too many allotments. A refiner may also carry over excess 2004
allotments (those generated in 2003 or 2004) for compliance with the 90
ppm corporate standard for 2005. However, those allotments must be
discounted by 50 percent. This 50 percent discount factor is needed to
equalize the emission impact of sulfur control between 2004 and 2005.
In 2005, there is an extra model year of NLEV/Tier 2 vehicles relative
to 2004. In addition, the NLEV/Tier 2 fleet is one year older in 2005
than 2004. This increased age translates into higher vehicle emissions
due to general deterioration. Since sulfur acts on a percentage basis,
the absolute emission increase due to sulfur impacts on vehicle
emission control systems in 2005 is higher than in 2004.
As discussed below in section IV.C.1.c.x, a refiner or importer may
convert allotments into credits in 2004 and 2005 for compliance with
the refinery average standards in 2005 and beyond. All transactions
between refiners involving sulfur allotments must conclude by the last
day of February in the calendar year following the compliance year in
which the allotments are to be used.\85\
---------------------------------------------------------------------------

\85\ Allotments used for GPA gasoline compliance may be retained
until February 2007. Allotments used for small refiner gasoline
compliance may be retained until February 2008.
---------------------------------------------------------------------------

Sulfur Credit Program

v. Establishing Individual Refinery Sulfur Baselines for Credit
Generation Purposes

The purpose of establishing a sulfur baseline for each refinery is
to provide a starting point for determining sulfur credits for
reductions in gasoline sulfur levels. We proposed that refiners would
have to establish a sulfur baseline for each individual refinery, by
submitting to us data establishing their annual average gasoline sulfur
level based on the average of their 1997 and 1998 operations. We would
review the data and, barring any discrepancies, approve a sulfur
baseline for each refinery. We received comments supporting this option
as well as comments stating that the time involved for this application
and approval process would delay the refiner's ability to plan for and
begin construction of gasoline desulfurization technology. Refiners
would want the certainty of an approved sulfur baseline before making
investment decisions, and thus would wait to obtain EPA's approval
before proceeding. We also received comments about what year(s) would
be most appropriate to use to establish a sulfur baseline. Some of
these comments argued for the use of existing, approved 1990 baselines,
or some adjusted version of 1990 baselines, rather than new data, to
expedite the process of establishing sulfur baselines.
We also proposed a different sulfur baseline for reformulated
gasoline (RFG) produced in the summer for those refineries which
produce reformulated gasoline. While the conventional gasoline sulfur
baseline (and the baseline for winter RFG) was proposed to be tied to
current sulfur levels, the baseline for summer reformulated gasoline
was proposed to be 150 ppm, the approximate level we expect summer
reformulated gasoline to contain in 2000 and beyond because of the
Phase II reformulated gasoline requirements, which take effect in 2000.
We argued that winter RFG did not have any de facto sulfur
restrictions, and thus winter RFG should be counted with conventional
gasoline for the purpose of credit generation relative to the
refinery's conventional gasoline sulfur baseline.
Since the proposal, we have learned that overall gasoline sulfur
levels (conventional plus reformulated) are significantly lower than
they were in 1990. As explained in the Regulatory Impact Analysis,
national average sulfur levels when both conventional and reformulated
gasolines are considered dropped to 306 ppm in 1997 and 268 ppm in
1998, compared to the 1990

[[Page 6761]]

national gasoline sulfur average of 339 ppm, decreases of 10 and 21
percent, respectively. The substantial drop between 1997 and 1998 seems
to be related to the mandatory use of the Complex Model, which began in
1998 and had implications for both reformulated and conventional
gasoline compliance. Thus, we have become convinced that the most
appropriate sulfur baseline would be based on data which establish
current sulfur levels, not on data which are nearly ten years old. We
considered reducing all 1990 baselines by 21 percent to reflect the
national average decrease since 1990, but determined that this approach
would be inappropriate because some refiners have reduced levels
substantially more than 10-21 percent since 1990, and would thus be
eligible to generate a very large number of credits for reductions that
have already been made.
Furthermore, as we proposed, and some commenters argued, we have
concluded that averaging data from two years is the most appropriate
approach, because averaging over two years will help to account for any
unusual variations in operations that may have occurred at individual
refineries in either of these years. We concluded that averaging data
from 1998 and 1999 is not feasible, because the 1999 data will not be
fully available to EPA until after the reporting deadline of May 2000.
Hence, we believe it is preferable to use 1997 and 1998 data, rather
than delaying the time baselines are established. We do not expect
significant changes in 1999 sulfur levels relative to 1998 levels, so
we believe the use of the 1997-1998 data provides a reasonable
representation of current sulfur levels.
We have also learned that summer reformulated gasoline is already
averaging close to our expected sulfur level for the year 2000. Winter
RFG does not show this same decrease, presumably because refiners are
shifting high sulfur blendstocks out of RFG in the summer but back into
RFG in the winter to maintain compliance with the conventional gasoline
antidumping requirements. Thus, it appears that if we held summer RFG
to a lower baseline, as proposed, we would have to raise the winter RFG
baseline commensurately to reflect actual refinery operations. The net
environmental impact would be no different than if we had a single
sulfur baseline applying to all RFG, or to all gasoline produced at the
refinery, since the annual pool sulfur levels are constant even while
there may be seasonal variations. Therefore, we are not finalizing a
separate sulfur baseline for summer RFG, but rather combined
conventional and reformulated gasoline sulfur levels.
Having considered the comments we received and the new data
available to us, we have concluded that refiner sulfur baselines should
be established from 1997 and 1998 operating data. Hence, we are
requiring refiners which wish to generate sulfur credits prior to 2004
to establish a 1997-98 sulfur baseline for each refinery at which they
intend to generate credits. We believe the process we have defined will
minimize the burden to the industry and the time it will take for us to
review and approve the sulfur baselines. Specifically, refiners which
plan to generate sulfur credits must submit to us information which
establishes the batch report numbers, sulfur levels, and volumes of
each batch of gasoline produced in 1997 and 1998, as well as the annual
average sulfur level calculated from these data. Within 60 days, we
will review the application and notify the refiner of approval or of
any discrepancies we find in the data submitted. If we do not respond
within 60 days, the baseline should be considered to be approved.
While we expect most refiners will apply for a sulfur baseline in
the near future (to maximize the time that they can generate credits
before 2004), there is no cut-off date for applying for a sulfur
baseline. However, if the refiner wishes to generate credits for a
given calendar year, we must receive his baseline application no later
than September 30 of that year to provide us adequate time to review
the baseline prior to the end of the year (at which time any credits
generated in that year would be assessed and reported by the refiner).
We believe that this approach for establishing sulfur baselines meets
our goal of providing a workable ABT program that refiners can take
advantage beginning in the year 2000, without sacrificing the
environmental benefits of the sulfur standards.
Foreign refiners which have already established an individual
refinery baseline with us, and thus have submitted reports on all
batches of gasoline sent to the U.S. in 1997 and 1998, may follow this
same procedure if they wish to generate sulfur credits prior to 2004.
Foreign refiners which have not reported 1997-98 gasoline qualities to
us must follow an alternate approach. Specifically, they must follow
the general requirements of our protocol for establishing individual
refinery baselines (see Secs. 80.91-94 and also Sec. 80.410) by
providing sufficient data to establish the volume of gasoline imported
to the U.S. from each refinery in 1997-98 and the annual average sulfur
level of that gasoline. If the test method used to identify the sulfur
level differs from the one specified in today's action, the refiner
must provide sufficient information about the test method to allow us
to evaluate the appropriateness of the alternative. Because this
information will be new to us, we may require more time to review and
approve their 1997-98 sulfur baseline. But, consistent with our
previous handling of foreign refiner submissions, once we have
determined that the submission is complete and the protocol has been
followed, they may use the baseline while waiting for our formal
approval. However, the refiner will be held to the baseline that is
ultimately approved. A foreign refiner who is unable to generate
adequate data to establish a 1997-98 sulfur baseline will not be
permitted to generate sulfur credits in 2000-2003.
Small refiners that plan to request small refiner standards (as
provided in Section IV.C.2 below) which also want to generate early
sulfur ABT credits will use the same data required to define their
small refiner baseline to determine their baseline for the ABT program.
In other words, if a refiner becomes a small refiner under our
definition and procedures, credits generated by that refinery would be
calculated relative to the refinery's actual 1997-98 sulfur average.
The trigger for generating sulfur credits under the ABT program
(discussed in the next section) would still apply for small refiners
generating credits prior to 2004 relative to their 1997-98 sulfur
average. In addition, the applicable interim sulfur standard for small
refiners who generate credits through sulfur reductions prior to 2004
will be calculated based on the reduced sulfur level, rather than the
1997-98 baseline level, as explained below in Section IV.C.2.
Importers and gasoline blenders will not be assigned a sulfur
baseline because they are not eligible to generate early credits (prior
to 2004) under the ABT program. This includes gasoline refiners who are
also importers; such parties cannot generate sulfur credits prior to
2004 on the basis of their imported gasoline but may only generate
credits based on the gasoline produced by their refinery(ies). It also
includes oxygenate blenders, who, as discussed in Section VI below, are
not subject to the sulfur standards but are responsible for compliance
with the downstream provisions.\86\ For importers

[[Page 6762]]

and most gasoline blenders, this represents a change from our proposal,
but one we believe is appropriate and necessary to ensure that the
environmental benefits of the ABT program are maintained. The ABT
program allows the refining industry to trade off early sulfur
reductions (2000-2003) for slight delays in complying with the 30 ppm
refinery average standard in 2005-2006.\87\ We have designed the ABT
program to ensure that sufficient credits can be generated by refiners
(domestic or foreign) to enable a smooth transition to the 30 ppm
standard. Importers and blenders do not have the same need for the ABT
program that refiners have because they will not have to make the same
level of investment in desulfurization technology and thus do not need
credits generated before 2004 to help their transition to the 30 ppm
average standard after 2004. Furthermore, credits could be generated by
importers without the overall pool of imported gasoline becoming
incrementally cleaner. For example, say that Importer A had a 1997/98
sulfur baseline of 600 ppm and Importer B had a sulfur baseline of 100
ppm. In 2002, Importer B could transfer/sell its 100 ppm gasoline to
Importer A prior to unloading the fuel at the port of entry. Once the
import transaction was completed, Importer A will have generated 500
ppm (multiplied by the fuel volume) credits without any fuel becoming
incrementally cleaner. We are concerned that if importers and blenders
were allowed to generate early credits, they would generate far more
credits than needed to make the ABT program work, without necessarily
achieving early environmental benefits--credits which either importers
or refiners would be able to use to delay compliance with the 30 ppm
standard in 2005 and beyond. This would delay the environmental
benefits of our program by prolonging the industry's transition to the
30 ppm standard.
---------------------------------------------------------------------------

\86\ Refiners may, however, include oxygen added downstream of
the refinery when determining compliance with the sulfur standards
and the provisions of the ABT program. This is consistent with
existing provisions for reformulated and conventional gasolines.
\87\ As explained in Section IV.C.1.c.ix, credits generated
before 2004 expire in 2006, except for small refiners and credits
used for GPA gasoline compliance.
---------------------------------------------------------------------------

In the proposal, we also discussed the need for a baseline gasoline
volume as well as a baseline sulfur level. This stemmed from the design
of our current conventional gasoline anti-dumping program, which
requires a baseline volume so that we can confirm that conventional
gasoline is no dirtier now than it was in 1990. However, for the
gasoline sulfur ABT program, we have determined that there is no need
to restrict refineries' sulfur baselines (against which they can
generate sulfur credits) to a specific volume of gasoline. The purpose
of the ABT program is to encourage early sulfur reductions by some
refineries, and we see no need to limit the amount of credits such a
refinery can generate on the basis of a historic volume of gasoline
production. In fact, additional volumes of cleaner gasoline should
achieve additional early environmental benefits.

vi. Generating Sulfur Credits Prior to 2004

In our proposal, we discussed a credit generation trigger of 150
ppm for early credit generation (2000-2003), arguing that we wanted to
encourage investment in desulfurization technologies that refineries
ultimately need to get to a 30 ppm average. Many comments we received
argued that the 150 ppm trigger was too restrictive, requiring capital
investments that most refiners could not make earlier than 2004 (due to
construction limitations, among other reasons). Thus, few credits would
be generated, and without sufficient certainty that credits would be
generated, refiners would not be able to count on the flexibility that
the ABT program was intended to provide when planning their compliance
strategies for 2004 and beyond.
Having considered these comments and reanalyzed the ability of the
industry to comply with the standards in 2004 (as we discussed above at
the introduction to section IV.C.1), we have concluded that the
proposed 150 ppm trigger would inappropriately limit the credits
available. While we want to encourage refiners to make reductions
early, we do not want to preclude refiners from making less capital
intensive sulfur reductions in the short term while they prepare to
reach the 30 ppm average in the long term. At the same time, we believe
that a refinery should be required to demonstrate that the sulfur
reduction was real and not just a consequence of national variations
from year to year. Hence, we are establishing a trigger which we
believe represents a sulfur reduction that requires action above and
beyond simple annual or even seasonal fluctuations in crude oil sulfur
level or product slate variations that could have a very small impact
on annual sulfur average.
During the period 2000-2003, credits can be generated annually by
any refinery that produces gasoline averaging at least 10 percent lower
than that refinery's baseline sulfur level. In other words, to generate
credits, the refinery's annual average sulfur level for all of its
gasoline on average must be 0.9 x (baseline sulfur level). Once this
``trigger'' is reached, credits will be calculated based on the amount
of reduction from the refinery's sulfur baseline. For example, if in
2002 a refinery reduced its annual average sulfur level from a baseline
of 450 ppm to 150 ppm (well below the trigger of 0.9 x 450=405 ppm),
its sulfur credits will be determined based on the difference in annual
sulfur level (450-150=300 ppm) multiplied by the volume of gasoline
produced in 2002. Similarly, foreign refineries with an individual
sulfur baseline can generate credits in these years as long as the
annual average sulfur level of the gasoline imported to the U.S. from
that refinery is lower than 90 percent of the baseline sulfur level.
Although by adopting a more modest trigger for credit generation we
are enabling more credits to be generated, the environment will still
benefit from our program. Although the use of a more modest trigger
keyed to each refinery's sulfur baseline may allow more credits to be
generated, we believe this will only occur because the credit program
is providing incentives to refineries to reduce sulfur levels earlier
than they would have otherwise, particularly with a strict 150 ppm
trigger. Thus, more lower sulfur gasoline will be in the marketplace
prior to 2004 than would otherwise have occurred, given our
understanding of the state of desulfurization technologies and the
likely pattern of investments by the industry. With our corporate
average and cap standards, sulfur levels will continue to decrease
after 2004, even if individual refineries take an added year or two to
meet the 30 ppm standard.
We had also proposed that credit generation prior to 2004 would be
different for reformulated gasoline than for conventional gasoline,
because reformulated gasoline's assigned sulfur baseline was proposed
to be 150 ppm. Thus, we proposed that credits could only be generated
from reformulated gasoline if the sulfur level averaged below 150 ppm,
and that the credits would be calculated based on the difference
between 150 ppm and the new, lower average. Since we have not finalized
a separate baseline for reformulated gasolines, we are not adopting a
different process for generating credits from reformulated gasoline.
All gasoline produced at the refinery in 2000 (and beyond) is
considered in calculating the annual average sulfur level, compliance
with the 90 percent trigger, and the sulfur credits earned, if any.

[[Page 6763]]

Several states have adopted or are considering adopting gasoline
sulfur control programs (see discussion at section IV.C.1.d below on
state sulfur programs). While we had proposed to exclude this gasoline
from sulfur credit generation, we have reconsidered our position.
Gasoline produced in response to state \88\ requirements can be
included in the refinery's calculation of sulfur credits generated in a
given year. However, this gasoline will be included in the total volume
of gasoline produced by that refinery, requiring the annual average
sulfur level for total gasoline produced at that refinery to exceed the
trigger specified above to generate any credits at all.
---------------------------------------------------------------------------

\88\ Excluding California.
---------------------------------------------------------------------------

vii. Generating Sulfur Credits in 2004 and Beyond

In 2004 and beyond, refineries, blenders, and importers can
generate credits, but only if the actual annual sulfur level of all
gasoline produced or imported averages below 30 ppm, and only for the
difference between the standard and the actual annual sulfur average.
(For example, a refinery producing gasoline in 2005 that averages 25
ppm can generate 30-25=5 ppm sulfur credits on the total volume of
gasoline produced at that refinery.) However, since in 2004 and beyond
importers are the regulated party responsible for ensuring that
imported gasoline meets the sulfur standards, foreign gasoline would in
effect generate sulfur credits through the importer beginning in 2004.
Foreign refineries which want to send gasoline containing less than 30
ppm sulfur to the U.S. would still benefit from doing so by making
appropriate arrangements with importers, which are subject to all of
our standards.

viii. Using Sulfur Credits

Refineries, blenders, and importers can use sulfur credits to
demonstrate compliance with the 30 ppm annual average refinery standard
in 2005 and beyond, if they are unable to meet the standard with actual
gasoline production. During 2005 and 2006 only, refineries may use
credits banked by that refinery in 2000-2003 as a result of early
sulfur reductions, or credits purchased from other refineries which
have banked early sulfur credits. Blenders and importers can purchase
credits from refiners (including any foreign refiners which generated
early credits), or use credits they generated in 2004 and beyond. All
transactions will have to be concluded by the last day of February
after the close of the annual compliance period (2005, 2006, etc.).
As discussed above, 2005 is the only year when averaging and
trading against the corporate average and averaging, banking, and
trading against the refinery average are both allowed. In that year,
sulfur credits may only be used against the 30 ppm standard for each
refinery once the refiner has demonstrated compliance with the
corporate pool average standard. The refiner must meet his corporate
average based on actual sulfur levels or through a trade for sulfur
allotments if it falls short of the 90 ppm corporate average standard.
At that point, each of his refineries is evaluated for compliance with
the 30 ppm refinery average standard. Those refineries that are not
producing gasoline averaging 30 ppm sulfur must obtain sulfur credits
generated in 2005 or earlier and/or sulfur allotments to bring the
refinery's sulfur average from the actual level (a maximum of 90 ppm
for each refinery, since by meeting the corporate average, even if in
part through the use of allotments, each refinery in the company will
be considered to average no more than 90 ppm) down to 30 ppm.
Refineries or importers which sell some or all of their gasoline in
the GPA (and which have elected to participate in the phase-in) may
also use sulfur credits to meet their refinery averages in 2004-2006.
However, because this gasoline must be designated for sale in the GPA,
they must account separately for compliance with the 150 ppm refinery
average for gasoline sold in the phase-in area and with the 30 ppm
refinery average for gasoline sold outside of that area. Thus, in 2004,
such refiners/importers may use sulfur credits to establish compliance
with the 150 ppm standard for gasoline sold in the phase-in area, if
required. In 2005 and 2006, they may use credits to meet the 150 ppm
standard for gasoline sold in the area and/or use credits to meet the
30 ppm standard for gasoline sold outside of the area.
As explained in section IV.C.1.b., some of the refiners
participating in the GPA are exempt from the corporate average
standards, but may use either sulfur credits or sulfur allotments in
2004-2006 to establish compliance with the 150 ppm refinery average
standard. Those that are not exempt from the corporate average
standards may use sulfur allotments only to meet the corporate average
standards. For such refiners, compliance with the corporate average
standard will be measured first (using allotments if needed), then
compliance with the refinery average standard (using credits and/or
allotments as needed) in the same manner as described above for
refiners who sell all of their gasoline outside of the GPA.
Foreign refineries are not required to comply with the 30 ppm
refinery standard in 2005 and beyond; instead, compliance for foreign
gasoline is required by the importer. Sulfur credits generated by
foreign refineries prior to 2004 will still have value, since these
refineries can sell sulfur credits to U.S. refineries, blenders, or
importers who need credits to meet the standard in 2005 or beyond. In
fact, foreign refiner's credits could simply be transferred to the
importer which is importing that refinery's gasoline into the U.S. For
example, a foreign refiner could send gasoline exceeding 30 ppm on
average to an importer and transfer the appropriate amount of sulfur
credits it generated prior to 2004 to allow the importer to meet the 30
ppm standard. Similarly, after 2004 a foreign refiner may send gasoline
containing less than 30 ppm to the U.S. through an importer, and the
importer would benefit from generating credits (and presumably would
include the value of these credits in the financial transaction with
the foreign refinery).
As explained in Section IV.C.3.b. above, in 2005 no batch of
domestically produced or imported gasoline can exceed 300 ppm, and a
refiner's/importer's annual corporate pool average sulfur level cannot
exceed 90 ppm, except for gasoline sold in the GPA or by small refiners
complying with the standards in Table IV.C.-3. In 2006 and beyond,
sulfur is capped at 80 ppm and there is no longer a corporate pool
average standard. These standards (as well as the 300 ppm cap and
corporate pool averages) cannot be met through the use of credits
generated under the ABT program. As described above, credits may only
be applied to demonstrate compliance with the 30 ppm refinery standard,
not to the corporate pool average or the cap. Given the limitations
that the 80 ppm cap places on sulfur levels in 2006 and beyond, we do
not expect many sulfur credits to be used in future years of this
program (since, even with the use of credits, no gasoline may exceed 80
ppm in these years).
We allow an individual refinery that does not meet the 30 ppm
standard in a particular year to carry forward the credit debt one
year. Under this provision, the refinery will have to make up the
credit deficit and come into compliance with the 30 ppm standard the
next calendar year, or face penalties. This provision will in no way
absolve the refiner from having to meet the

[[Page 6764]]

applicable per-gallon cap standard or, when applicable, the corporate
average standard. This provision will provide some relief for refiners
faced with an unexpected shutdown or that otherwise were unable to
obtain sufficient credits to meet the 30 ppm standard. This provision
is only available through 2010. After that time, we expect many
refineries to be able to consistently operate below 30 ppm, generating
a pool of credits which other refineries could purchase in the event of
an unforeseen upset. However, in no circumstances after 2005 can the
refinery produce gasoline exceeding the 80 ppm per-gallon cap standard
(with the exception of small refiners, as discussed in Section IV.C.2
below). The carry-forward provision does not apply to compliance with
the 150 ppm refinery average standard applicable in the GPA.
We have some concern that the potential exists for credits to be
generated by one party and subsequently purchased or used in good faith
by another, and later found to have been calculated or created
improperly or otherwise determined to be invalid. For this reason, we
proposed that both the seller and purchaser would have to adjust their
sulfur calculations to reflect the proper credits and either party (or
both) could be deemed in violation of the standards and other
requirements if the adjusted calculations demonstrate noncompliance
with an applicable standard. One commenter, representing a number of
refiners, objected to this approach.
Nevertheless, our strong preference is to hold the credit or
allotment seller liable for the violation, as opposed to the credit or
allotment purchaser. As a general matter we would expect to enforce a
shortfall in compliance calculations (caused by the good faith purchase
of invalid credits) against a good faith purchaser only in cases where
we are unable to recover valid credits from the seller to cover the
compliance shortfall. Moreover, in settlement of such cases we would
strongly encourage the seller to purchase credits to cover the good
faith purchaser's credit shortfall. Under the deficit provisions of
section 80.205(e), for compliance periods through 2010, a credit
shortfall may be corrected if the conditions of that section are met.
EPA will consider covering 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.
Some commenters stated that sulfur credits should be transferred
directly from the refiner or importer that generated them to the party
that will use them, as we had proposed. We believe that this helps to
ensure that parties purchasing credits will be better able to assess
the likelihood that the credits will be valid, and aids compliance
monitoring. Therefore, the final rule adopts this provision, with the
exception that where a credit generator transfers credits to a refiner
or importer who cannot use all the credits, that transferee may
transfer the credits to another refiner or importer. That second
transferee cannot again transfer the credits; they must either be used
or terminated by the second transferee. Nevertheless, there is nothing
in the final rule that would prevent a person who is not a refiner or
importer from facilitating the transfer of credits from parties that
have generated them to parties who need them for compliance, e.g., a
broker who would act like a real estate broker. Therefore, under
today's rule, any person may act as a credit or allotment broker,
whether or not such person is a refiner or importer, so long as the
title to the credits or allotments are transferred directly from the
generator to the user. Furthermore, any party (e.g., refiner, importer,
or blender) who can generate and hold credits may also resell them.

ix. How Long Do Credits Last?

The ABT program is designed to encourage sulfur reductions earlier
than the standards require, by providing a market for credit
generation. The emissions benefits of these early reductions are most
valuable in the early years of the ABT program when national average
levels remain substantially higher than the final 30 ppm average
standard. At the same time, these emissions reductions are offset in
time by higher emissions incurred by later vehicles which use gasoline
with a higher sulfur level. Because the overall intention of the
gasoline sulfur program is to enable and protect Tier 2 vehicles and
provide time for refiners to select and construct desulfurization
equipment, sulfur credits should have a limited life to limit the
degree to which later Tier 2 vehicles are exposed to higher sulfur
levels.
The ABT program is also designed to ease implementation of the new
standards, particularly the refinery average standard, and the credits
will be of their greatest value to refineries during the first few
years of the program. ABT is not intended to permit a refinery to
operate substantially above the standard for a protracted time period.
While limiting credit life may reduce the incentive to generate credits
for some refineries, the credit program will be of relatively small
value to any refinery/importer that held credits for a protracted
period of time and did not need to use them. This is particularly true
in 2006 and beyond, when the 80 ppm cap limits the need for and value
of any credits the refinery may possess.
Hence, we are finalizing limitations on the life of credits which
differ somewhat from our proposal. Credits generated prior to 2004 must
be used for compliance purposes and calculations with respect to
gasoline produced on or before December 31, 2006. These credits can be
used to meet the 30 ppm standard in 2005 or 2006. This expiration date
applies to credits used by the refinery which generated the credits, as
well as credits transferred to another refinery. While the proposal
presented a life through 2007 for credits generated early, we have
shortened this life span one year to reflect the fact that early
credits are intended to enable and ease compliance with the 30 ppm
standard in the first years of the program, allowing refiners to spread
out investments without compromising the environmental benefits of the
program. At the beginning of 2006, all gasoline (except that produced
by small refiners and that marketed in the GPA) will be capped at 80
ppm, and by the end of 2006, every refinery should be capable of
producing gasoline that meets the 30 ppm standard. Hence, the value of
the early credits diminishes greatly. It should be noted that early
credits can be used for GPA certified gasoline through 2006 and for
small refiner gasoline through 2007.
Credits generated in 2004 and beyond will have to be used within
five years of the year in which they were generated. If these credits
are traded to another party during that five year period, they will
have to be used by the new owner within that same five years,
regardless of when the transfer occurs. This is a change from our
proposal, which provided for a potential maximum ten-year life for
credits that were generated and then traded in the fifth year to
another party. However, we believe this approach is more consistent
with our environmental goals of keeping sulfur levels averaging 30 ppm
in 2006 and beyond. With the 80 ppm cap, refiners will be able to use
only very few credits if they are unable to meet the 30 ppm average in
2006 or beyond. Therefore, limiting credit life to five years will
likely have minimal impact on the actual use of credits. A longer
credit life will make tracking and enforcement difficult, and could
have negative environmental consequences. Hence, we have limited credit
life to

[[Page 6765]]

five years. Consistent with our other recordkeeping and reporting
requirements, the five-year expiration date will be assessed as of the
last day of February after the five year deadline. Hence, for example,
credits generated in 2005 will expire as of the last day of February,
2011. Again, no third-party transfers are allowed.

x. Conversion of Allotments Into Credits

A refiner or importer may convert allotments into credits for
compliance with the refinery average standards in 2005 and beyond.
Allotments that are generated by reducing gasoline sulfur levels to 30
ppm or higher (defined as Type ``A'' allotments) are equivalent to
credits generated in 2000-2003. These allotments may be (1) used as
allotments by a refiner for compliance with the corporate average
standard in 2004 and 2005 or (2) converted into credits to be used by
the refiner's refineries for compliance with the refinery average
standard in 2005 and 2006.
Allotments that are generated by reducing gasoline sulfur levels to
lower than 30 ppm (defined as Type ``B'' allotments) are equivalent to
credits generated in 2004 and beyond (by producing gasoline with less
than 30 ppm sulfur). Similar to Type ``A'' allotments, these allotments
may be (1) used as allotments by a refiner for compliance with the
corporate average standard in 2004 and 2005 or (2) converted into
credits to be used by the refiner's refineries for compliance with the
refinery average standard in 2005 and beyond.
Allotments or credits that are used by refiners for compliance with
the GPA gasoline standards must be used by the last day of February
2007. Allotments or credits used by small refiners for compliance with
the small refiner standards must be used by the last day of February
2008. Any allotments, whether Type ``A'' or ``B'', that are carried
over for compliance with the corporate and refinery average standards
for 2005 must be discounted by 50 percent as discussed in above. Any
allotments that are converted to credits (e.g., in 2004) and then
carried over to 2005 are not discounted. However, once the conversion
and carry-over has taken place (such that the allotments have become
credits), the conversion cannot be reversed without applying the
discount factor. That is to say, once a 2003 or 2004 allotment is
converted to a credit and carried over to 2005, the credit can only be
re-converted into an allotment that is discounted 50 percent.
d. How Are State Sulfur Programs Affected by EPA's Program?
Section 211(c)(4)(A) of the CAA prohibits states \89\ from
prescribing or attempting to enforce controls or prohibitions
respecting any fuel characteristic or component if EPA has prescribed a
control or prohibition applicable to such fuel characteristic or
component under section 211(c)(1). This preemption applies to all
states except California, as explained in section 211(c)(4)(B). For
states other than California, the Act provides two mechanisms for
avoiding preemption. First, section 211(c)(4)(A)(ii) creates an
exception to preemption for state prohibitions or controls that are
identical \90\ to the prohibition or control adopted by EPA. Second,
states may seek EPA approval of SIP revisions containing fuel control
measures, as described in section 211(c)(4)(C). EPA may approve such
SIP revisions, and thereby ``waive'' preemption, only if it finds the
state control or prohibition ``is necessary to achieve the national
primary or secondary ambient air quality standard which the plan
implements.''
---------------------------------------------------------------------------

\89\ The term ``state'' or ``states'' includes political
subdivisions thereof.
\90\ In evaluating whether a state fuel prohibition or control
is ``identical'' to a prohibition or control adopted by EPA, EPA
might consider but is not limited to the following factors in
comparing the measures: (1) The level of an emission reduction or
pollution control standard; (2) the use of ``per gallon'' or
``averaged'' amounts in setting that level; (3) the effect on that
level (if averaged) of the use of different averaging pools; (4) the
lead time allowed to the affected industry for compliance; and (5)
the test method(s) and sampling requirements used in determining
compliance.
---------------------------------------------------------------------------

We are adopting the sulfur standards pursuant to our authority
under section 211(c)(1). Thus, we believe that today's action results
in the clear preemption of future state actions to prescribe or enforce
fuel sulfur controls. \91\ States with fuel sulfur control programs not
already approved into their SIPs will therefore need to obtain a waiver
from us under the provisions described in section 211(c)(4)(C) for all
state fuel sulfur control measures, unless the state standard is
identical to our sulfur standard.
---------------------------------------------------------------------------

\91\ In addition, EPA notes that there are existing federal
NO_X performance standards which apply to RFG and
conventional gasoline and that state controls respecting
NO_X performance are also preempted under 211(c)(4)(A).
---------------------------------------------------------------------------

Section 211(c)(4)(A) preempts state fuel controls if EPA has
``prescribed'' federal controls. We read this language to preempt non-
identical state standards on the date of promulgation of the standards,
as opposed to the date the standards become enforceable. Thus, today's
action preempts state actions as of December 21, 1999, even though the
standards will not require sulfur reductions until 2004. This
interpretation is consistent with EPA actions applying other federal
fuel measures. See 54 Fed. Reg. 19173 (May 4, 1989) (noting preemption
of Massachusetts state RVP measure before start of first control period
for federal RVP). We also believe this interpretation is consistent
with the intent behind section 211(c)(4)(A). Though the standards are
not immediately enforceable, they will have an immediate impact on
refiners' investment decisions. We believe, by adopting 211(c)(4)(A),
Congress intended to limit state fuel controls that differ from the
federal programs, for example, in the judgments as to level of the
standard or its stringency. The lead time to implement a standard
should be treated the same way.
Aside from the explicit preemption in Section 211(c)(4)(A), a court
could also consider whether a state sulfur control 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 both federal and state requirements, or by standing as
an obstacle to accomplishment of Congressional objectives. A court
could thus consider whether a given state sulfur control is preempted,
notwithstanding waiver of preemption under 211(c)(4)(C), 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.
2. Hardship Provision for Qualifying Refiners
This section describes various provisions for certain qualifying
refiners who may face hardship circumstances.
a. Hardship Provision for Qualifying Small Refiners
In developing our gasoline sulfur program, we evaluated the need
and the ability of refiners to meet the 30/80 standards as
expeditiously as possible. This analysis is described in detail in the
RIA. As a part of this analysis, we found that while the majority of
refiners would be able to meet the needed air quality goals in the
2004-2006 time frame, there would be some refiners who would face
particularly difficult circumstances which would cause them to have
more difficulty, in comparison

[[Page 6766]]

to the industry as a whole, in meeting the standards.
In order to ensure that the vast majority of the program could be
implemented reasonably quickly in order to achieve the air quality
benefits sooner, rather than basing the time frame on the lowest common
denominator we have provided an extended phase-in for a small group of
refiners that represents less than four percent of the overall gasoline
volume, and a much smaller percentage in the areas of greatest
environmental need. As described in more detail below, and in Chapter
VIII of the RIA, we concluded that refineries owned by small businesses
face unique hardship circumstances, compared to larger companies.
The primary reason for this consideration is that small businesses
lack the resources available to large companies which enable the large
companies (including those large companies that own small volume
refineries) to raise capital for investing in desulfurization
equipment. The small businesses are also likely to have insufficient
time to secure loans, compete for engineering resources, and complete
construction of the needed desulfurization equipment in time to meet
the standards adopted today which begin in 2004.
The emissions benefits of low sulfur gasoline are needed as soon as
possible, for two primary reasons: (1) To reduce ozone and other
harmful air pollutants, and (2) to enable vehicle emissions control
technology for Tier 2 vehicles. Since our analysis showed that small
businesses in particular face hardship circumstances, we are adopting
temporary, interim standards that will provide refineries owned by
small businesses additional time to meet the ultimate 30 ppm refinery
average and 80 ppm per gallon cap standards. This approach allows us to
achieve the needed emission reductions in the 2004-2007 time frame
because hardship circumstances are expected to be faced by only a small
portion of the refining industry.
We believe that these temporary, interim standards are an effective
way to phase in the low sulfur standards as expeditiously as is
feasible thereby achieving significant air quality benefits in an
expeditious manner. This section describes the special provisions we
are offering small businesses to mitigate the impacts of our program on
them and generally explains the process we undertook to analyze those
impacts. Please refer to the RTC document for a detailed discussion of
comments received on these provisions, and to the RIA for a more
detailed discussion of our analysis of small refiner circumstances.
As explained in the regulatory flexibility analysis in Section
VIII.B. of this document and in Chapter 8 of the RIA, we considered the
impacts of our proposed regulations on small businesses. We have
historically, as a matter of practice, considered the potential impacts
of our regulations on small businesses, as discussed in more detail in
Section IV.C.2.a.ii., below. The analysis of small business impacts
conducted for this rulemaking was performed in conjunction with a Small
Business Advocacy Review (SBAR) Panel we convened, pursuant to the
Regulatory Flexibility Act as amended by the Small Business Regulatory
Enforcement Fairness Act of 1996 (SBREFA). We believe that the
temporary, interim standards we are adopting for small refiners
contributed to our development of a framework to achieve significant
environmental benefits from lower sulfur gasoline in the most
expeditious manner that is reasonably practicable. In the SBREFA
amendments, Congress stated that ``uniform Federal regulatory * * *
requirements have in numerous instances imposed unnecessary and
disproportionately burdensome demands including legal, accounting, and
consulting costs upon small businesses * * * with limited
resources[,]'' and directed agencies to consider the impacts of certain
actions on small entities. The final report of the Panel is available
in the docket. Through the SBREFA process, the Panel provided
information and recommendations regarding:
The significant economic impact of the proposed rule on
small entities;
Any significant alternatives to the proposed rule which
would ensure that the objectives of the proposal were accomplished
while minimizing the economic impact of the proposed rule on small
entities;
The projected reporting, recordkeeping, and other
compliance requirements of the proposed rule; and,
Other relevant federal rules that may duplicate, overlap,
or conflict with the proposed rule.
In addition to our participation in the SBREFA process, we
conducted our own outreach, fact-finding, and analysis of the potential
impacts of our regulations on small businesses. Many of the small
refiners with whom we and the Panel met indicated their belief that
their businesses may close due to the substantial costs, capital and
other, of meeting the 30/80 standard without additional time. Based on
these discussions and our data analysis, the Panel and we agree that
small refiners would likely experience a significant and
disproportionate economic hardship in reaching the objectives of our
gasoline sulfur reduction program. However, the Panel also noted that
the undue burden imposed upon the small refiners by our sulfur
requirements could be alleviated with additional time for compliance.
We agree with the Panel on both of these points.
For today's action, we have structured a temporary, interim
compliance flexibility for qualifying small refiners, both domestic and
foreign, based on the factors described below. Specifically, we
structured this provision to address small refiner hardship while
achieving air quality benefits expeditiously and ensuring that the
reductions needed in gasoline sulfur coincide with the introduction of
Tier 2 vehicles.
First, the compliance deadlines in the program, combined with
flexibility for small refiners, will achieve the air quality benefits
of the program quickly, while ensuring that small refiners will have
adequate time to raise capital for infrastructure changes. Many, if not
most, small refiners have limited, if any, additional sources of income
beyond their refinery for financing the equipment necessary to produce
low sulfur gasoline. Because these small refiners typically do not have
the financial backing that larger and generally more integrated
companies have, they need additional time to secure capital financing
from their lenders.
Second, we believe that allowing time for sulfur-reduction
technologies to be proven-out by larger refiners before small refiners
have to put them in place would reduce the risks incurred by small
refiners who utilize these technologies to meet the standards. The
added time would likely allow for costs of these desulfurization units
to decrease, thereby limiting the economic consequences for small
refiners. Small refiners are disadvantaged by the economies of scale
that exist for the larger refining companies--capital costs and per-
barrel fixed operating costs are generally higher for them.
Finally, providing small refiners more time to comply would ensure
that adequate engineering and construction resources would be
available. Since most large and small refiners will need to install
additional processing equipment to meet the sulfur requirements, there
will be a tremendous amount of competition for technology services,
engineering manpower, and construction management and labor. Our
analysis

[[Page 6767]]

shows that there are limitations to the elasticity of these resources.
In addition, vendors will be more likely to contract their services
with the major companies first, as their projects will offer larger
profits for the vendors.
Providing this flexibility to allow small refiners to deal with
hardship circumstances enables us to go forward with the phase-in of
the 30 ppm sulfur standard beginning in 2004. Without this flexibility,
it is possible that the benefits of the 30 ppm standard would not be
achieved as quickly. By providing temporary relief to those refiners
that need additional time, we are able to adopt a program that reduces
gasoline sulfur levels expeditiously and in a way that is feasible for
the industry as a whole.
In addition, we believe the volume of gasoline that will be
eligible for the interim standards is small. We estimate that small
refiners produce approximately four percent of all gasoline used in the
U.S., excluding California. In most cases, gasoline produced by
refiners is mixed with substantial amounts of other gasoline prior to
retail distribution (due to the nature of the gasoline distribution
system). This mixing generally results in only marginal increases in
overall sulfur levels. Thus, the sulfur level of gasoline actually used
by Tier 2 vehicles should generally be much lower than that produced by
individual small refineries under this provision.

i. How Are Small Refiners Defined?

How We Defined ``Small'' Refiner in the Proposal

In identifying the small refiners most susceptible to the economic
challenge of meeting the low-sulfur requirements, we closely examined
the Small Business Administration's (SBA) definition of small refiner
for the purposes of regulation. In that assessment we concluded that
the SBA definition provided a reasonable metric for identifying small
refiners that would be significantly impacted by the sulfur program
requirements. By adopting the SBA definition we could expeditiously
provide certainty of small refiner status to refiners who applied for
the temporary compliance flexibility. Specifically, we proposed a
definition where any petroleum refining company having no more than
1,500 employees throughout the corporation as of January 1, 1999 could
apply for the temporary compliance flexibilities. This proposed
employee limit included any subsidiaries, regardless of the number of
individual gasoline-producing refineries owned by the company or the
number of employees at any given refinery.
While we proposed a definition based on corporate employment, in
light of the SBA definition and the SBAR Panel's recommendations, we
also sought comment on alternative definitions of a small refiner. Such
alternatives included definitions based on volume of crude oil
processed (at a given refinery and/or corporate-wide) or volume of
gasoline produced, with the understanding that any relief offered to
refiners must not substantially reduce the program's environmental
benefits.

Our Revised Small Refiner Definition

Based on comments received on the proposal, we are making two
changes to our definition of a small refiner: we are (1) revising the
employee number criterion; and, (2) adopting a cap on the corporate
crude oil capacity for a refining company to qualify as a small
business under today's regulations.
In regard to the employee number criterion, we are modifying how
the employee number is determined, based on comments received from SBA.
As mentioned above, our proposed definition applied to any petroleum
refining company having no more than 1,500 employees throughout the
corporation as of January 1, 1999. We selected that date to prevent
companies from ``gaming'' the system. However, as SBA pointed out in
its comments, the Small Business Act regulations specify that, where
the number of employees is used as a size standard, as we proposed for
small refiners, size determination is based on the average number of
employees for all pay periods during the preceding 12 months.
Since we intended to use SBA's size standard in our proposal, we
are incorporating that definition correctly in today's action. It is
also worth mentioning that SBA shares our concerns about preventing
companies from gaming the system and that it solved this problem
specifically by using the average employment over 12 months. In effect,
this approach helps to prevent companies from applying for and
receiving small refiner status in bad faith. An example of an
inappropriate application for small refiner status would be a refiner
that temporarily reduced its workforce from 1600 employees to 1495
employees immediately before January 1, 1999 and then immediately
rehired those employees after that cutoff date. Furthermore, the
averaging concept was designed to properly address firms with seasonal
fluctuations, according to SBA.
Second, we're amending the small refiner definition to include a
corporate crude oil capacity cap. We believe such a corporate volume
limitation is necessary to ensure that only truly small businesses
benefit from the relaxed interim standards. Refineries that process
large amounts of crude are likely to be better able to install
desulfurization equipment to meet the national standards in 2004. In
addition to ensuring that the interim standards target the appropriate
group of refiners that need additional time, the volume limit also
serves to ensure that the volume of gasoline subject to such standards
is not significant. In addition, we received many comments that we
should adopt a threshold based on crude capacity as specified in the
Clean Air Act and used in past EPA fuel programs.
In the lead phase-down program for gasoline, we used a definition
of ``small refinery'' that Congress adopted in 1977 specifically for
the lead phase-down program. The definition was based on crude oil or
feedstock capacity at a particular refinery (less than or equal to
50,000 barrels per calendar day (bpcd)), combined with total crude oil
or feed stock capacity of the refiner that owned the refinery (less
than or equal to 137,500 bpcd). In 1990, the lead phase-down program
was complete and Congress removed this provision from the Act.
Shortly before the Act was amended in 1990, we set standards for
sulfur content in diesel fuel, including a two-year delay for small
refineries. We used the same definition of small refinery as we used in
the lead phase-down program. This two-year delay, like many of the
small business flexibilities in our gasoline sulfur proposal, was aimed
at problems that small refineries faced in raising capital and in
arranging for refinery construction.
In the 1990 amendments to the Clean Air Act, Congress rejected this
small refinery provision, and instead allocated allowances to small
diesel refineries under the Title IV Acid Rain program. (See CAA
Section 410(h).) This approach was also aimed at helping small
refineries solve the problem of raising the capital needed to make
investments to reduce diesel sulfur. Congress provided allowances to
small refineries that met criteria similar to that used in the lead
phase-down provision--based on the crude oil throughput at a particular
refinery, combined with the total crude oil throughput of the refiner
that owned the refinery.
As mentioned above, the CAA definition was based on crude oil or
feedstock capacity at a particular refinery, combined with total crude
oil

[[Page 6768]]

or feed stock capacity of the refiner that owned the refinery (less
than or equal to 137,500 bpcd). However, given the mergers,
acquisitions, and other changes that have transpired throughout the
refining industry in the past few years, we believe the appropriate
boundary today is a corresponding corporate crude capacity less than or
equal to 155,000 bpcd.
Therefore, in consideration of the above, a refiner must meet both
of the following criteria to qualify for the special small refiner
provisions described in the next section:
No more than 1500 employees corporate-wide, based on the
average number of employees for all pay periods from January 1, 1998 to
January 1, 1999; and
A corporate crude capacity less than or equal to 155,000
bpcd for 1998.

ii. Standards That Small Refiners Must Meet

Upon careful review of the comments received on the proposal as
well as the recommendations of the SBAR Panel, we have determined that
regulatory relief in the form of delayed compliance dates is
appropriate to allow small refiners, both foreign and domestic, to
comply with our regulations without disproportionate burdens. From 2004
to 2007, when U.S. refiners must meet the 30/80 standard or the
standards listed in Table IV.C-1 if they are participating in our ABT
program, refiners meeting the corporate employee and capacity limits
prescribed above are allowed to comply with somewhat less stringent
requirements. These interim annual-average standards for qualifying
small refiners are shown in Table IV.C-3 below.

Table IV.C-3.--Temporary Gasoline Sulfur Requirements for Small Refiners
in 2004-2007
------------------------------------------------------------------------
Temporary Sulfur Standards (ppm)
Refinery baseline sulfur -------------------------------------------
level (ppm) Average Cap
------------------------------------------------------------------------
0 to 30..................... 30 ppm.............. 300 ppm.
31 to 200................... Baseline Level...... 300 ppm.
201 to 400.................. 200 ppm............. 300 ppm.
401 to 600.................. 50% of baseline..... Factor of 1.5 times
the average
standard.
601 and above............... 300................. 450.
------------------------------------------------------------------------

The cap standards for the first two ``bins'' of refineries (that is
those with baseline sulfur levels from zero to 30 and 31 to 200) have
been relaxed somewhat from the proposal based on comments that the
proposed standards for these two bins were more stringent than the
options under discussion for all other refiners. We believe that these
small refiners should be able to meet the average standards without
much, if any, change to their operations but the more lenient cap will
give them some flexibility for turnarounds or unexpected equipment
``upsets''.
Compliance with the standards in Table IV.C-3 is based on a
refiner's demonstration that it meets our specific small refiner
criteria. Refiners who qualify as a small refiner under our definition
must establish a sulfur baseline for each of their participating
refineries. The following sections explain these requirements in more
detail to supplement the information presented above. We also explain
how small refiners can apply for an extension of up to two additional
years of the applicable small refiner standards, based on a variety of
factors such as technology availability or financial hardship.

iii. How Do Small Refiners Apply for Small Refiner Status?

Refiners seeking small refiner status under our gasoline sulfur
program must apply to us in writing no later than December 31, 2000,
requesting this status. This application for small refiner status must
contain the information described below.
Companies \92\ seeking small refiner status must provide us with
the following information:
---------------------------------------------------------------------------

\92\ Company means the business structure of the refinery
whether privately or publicly owned.
---------------------------------------------------------------------------

Employment Information

A listing of the name and address of each location where
any employee of the company worked during the 12 months preceding
January 1, 1999.
The average number of employees at each location based
upon the number of employees for each of the company's pay periods for
the 12 months preceding January 1, 1999.
The type of business activities carried out at each
location.

Crude Capacity Information

The total corporate crude oil capacity of the refiner as
reported to the Energy Information Administration (EIA) of the U.S.
Department of Energy (DOE).
For refineries owned by joint ventures, the total employment of
both (all) companies must be considered in determining whether the
1,500 employee limit is met. In addition, a refiner who reactivates a
refinery that was shut down or non-operational between January 1, 1998
and January 1, 1999, may apply for small refiner status no later than
June 1, 2002. In this case, we will consider the information provided
to determine the correct period for judging compliance with the 1500
threshold. Where appropriate we will look at the most recent 12 months
of employment information.
Refiners seeking small refiner status must also provide us with the
total crude capacity of their corporation (the sum of all individual
refinery capacities for multiple-refinery companies, including any and
all subsidiaries) as reported to EIA for 1998 (published by EIA in
1999). The information submitted to 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 the Agency with the
appropriate data to correct the record. For reactivated refineries
owned by a small refiner, we will consider the information provided to
determine the correct period for judging compliance with the corporate
capacity threshold. Where appropriate, we will look at the most recent
year of crude capacity information.
If a refiner with approved small refiner status later exceeds the
1,500 employee threshold without merger or acquisition or the corporate
capacity of 155,000 bpcd, its refineries could keep their individual
refinery standards. This is to avoid stifling normal company growth and
is subject to our finding that the company did not apply for and
receive the small refiner status in bad faith.

[[Page 6769]]

iv. How Do Small Refineries Apply for a Sulfur Baseline?

A qualifying small refiner, domestic or foreign, may apply for an
individual sulfur baseline by December 31, 2000 for any refinery owned
by the company by providing the following information:
A calculation of the refinery's sulfur baseline using its
average gasoline sulfur level based on 1997 and 1998 production data,
\93\ and
---------------------------------------------------------------------------

\93\ Includes batch number, volume, and sulfur content for each
batch of gasoline produced in 1997 and 1998.
---------------------------------------------------------------------------

The average volume of gasoline (including conventional and
reformulated) produced in these two years.
As we proposed, baseline sulfur levels and gasoline volumes are
averaged over two years (1997 and 1998) to account for any production-
related anomalies that may have occurred in 1997 or 1998. For the
overall program, however, we are only using 1997 and 1998 data for the
reasons described in Section IV.C.1, above. For any refiner who
reactivates a refinery that was shut down or non-operational between
January 1, 1998 and January 1, 1999, we will use the most recent
information available for baseline establishment purposes.
The regulations specify the information to be submitted to support
the baseline application. The baseline calculations should include any
oxygen added to the gasoline at the refinery. This application would be
submitted at the same time the refiner applies for small business
status; confirmation of small business status would not be required to
apply for an individual sulfur baseline. Pending refinery baseline
approval, we will assign standards to each of the company's refineries
in accordance with Table IV.C.-3.
Oxygenate blenders, regardless of their size, are not eligible for
the small refiner individual baselines and standards because they would
not experience circumstances similar to those of small refining
companies. That is, oxygenate blenders do not have the burden of
capital costs to install desulfurization equipment, which is the
primary reason for allowing small refiners to have a relaxed compliance
schedule.

v. Volume Limitation on Use of a Small Refinery Standard

Except as noted below, the volume of gasoline subject to a small
refinery's individual standards is limited to the average volume of
gasoline the refinery produced from crude oil during the baseline years
(1997 and 1998), excluding the volume of gasoline produced using
blendstocks produced at another refinery and exports.\94\ Under this
approach, the baseline volume for a small refinery would reflect only
the volume of gasoline produced from crude oil during the 1997 and 1998
baseline years.
---------------------------------------------------------------------------

\94\ In addition to gasoline produced from crude oil, a small
refinery's baseline volume would include gasoline produced from
purchased blendstocks where the blendstocks are substantially
transformed using a refinery processing unit.
---------------------------------------------------------------------------

However, to ensure that the overall sulfur in gasoline from small
refiners does not greatly increase under the terms of the small refiner
extension and result in overall gasoline pool sulfur levels higher than
anticipated, the volume would be limited beginning in 2004 to the
volume of gasoline that is the lesser of: (1) 105 percent of the
baseline volume, or (2) the volume of gasoline produced during the year
from crude oil. Any volume of gasoline produced during an averaging
period in excess of this limitation is subject to the corporate average
standards that apply to all other refiners (i.e., the corporate average
standards listed in Table IV.C.-1).
In 2006 and 2007, the refinery averages of Table IV.C.-1 will
apply. In this case, the small refinery's annual average standard will
be adjusted based on the excess volume in a manner similar to the
compliance baseline equation for conventional gasoline under Section
80.101(f) of Part 40 of the Code of Federal Regulations. However, the
small refinery's per-gallon cap standard will not be adjusted.
This limitation assures that small refineries receive relief only
for gasoline produced from crude oil, that is the portion of the
refinery operation requiring capital investment to meet lower sulfur
standards.

vi. Extensions Beyond 2007 for Small Refiners

Beginning January 1, 2008, all small companies' refineries must
meet the national sulfur standard of 30 ppm on average and the 80 ppm
cap, except small refineries under IV.C.2.i. that apply for and receive
an extension of their small refiner status and unique standards. An
extension will provide a given small refinery up to an additional two
years to comply with the national standards. An extension must be
requested in writing and must specify the factors that demonstrate a
significant economic hardship to qualify the refinery for such an
extension. Factors considered for an extension could include, but are
not limited to, the refinery's financial position; its efforts to
procure necessary equipment and to obtain design and engineering
services and construction contractors; the availability of
desulfurization equipment, and any other relevant factors.
In order for us to consider an extension, a refiner must submit a
detailed request for an extension by January 1, 2007, demonstrating
that it has made best efforts to obtain necessary financing, and must
provide detailed information regarding any lack of success in obtaining
financing. This information shall include, but may not be limited to
copies of loan applications for the necessary financing for the
construction of appropriate sulfur reduction technology as well as the
application of financing for other equipment procurements or
improvements in this time frame. If financing has been disapproved or
is otherwise unsuccessful, the refiner shall provide documents
supporting the basis for that disapproval and evidence of efforts to
pursue other means of financing. If we determine that the refiner has
made the best efforts possible to achieve compliance with the national
standards by January 1, 2008, but has been unsuccessful for reasons
beyond its control, we will consider granting the hardship extension
initially for the 2008 averaging period. If further relief is
appropriate for good reasons, we will consider a further extension
through the 2009 averaging period but in no case will this relief be
provided unless the refiner can demonstrate conclusively that it has
financing in place and that it will be able to complete construction
and meet the national gasoline sulfur standards no later than December
31, 2009.

Compliance Plans for Demonstrating a Commitment To Produce Low Sulfur
Gasoline

This final rule includes a compliance plan provision for those
refiners who may seek a hardship extension of their approved interim
standards. This provision requires that those refiners with approved
interim standards who seek a hardship extension must submit a series of
reports to EPA discussing and describing their progress toward
producing gasoline that meets the 30/80 ppm standards by January 1,
2008. We expect that small refiners will need to begin preparations to
meet the national standards in 2008 by 2004. However, we understand
that the potential exists for some small refiners to face additional
hardship circumstances that will warrant more time to meet the
standards. For this reason, we have adopted provisions (see above)
allowing

[[Page 6770]]

refiners subject to the interim standards to petition us and make a
showing that additional time is needed to meet the national standards.
To properly evaluate these hardship applications, we are requiring
demonstrations of good faith efforts towards assessing the economic
feasibility, along with the business and technical practicality of
ultimately producing low sulfur gasoline. Such progress reports must be
submitted for a refiner to receive consideration in any future
determinations regarding hardship extensions. However, these reports
are not required from refiners who will not be seeking a hardship
extension.
By June 1, 2004, such refiners would need to submit preliminary
information in the form of a report outlining its time line for
compliance and a project plan discussing areas such as permits,
engineering plans (e.g., design and construction), and capital
commitments for making the necessary modifications to produce low
sulfur gasoline. Documents showing activities and progress in these
areas should be provided if available.
By no later than June 1, 2005, these small refiners would need to
submit a report to us stating in detail progress to date based on their
time line and project plan. This should include copies of approved
permits for construction of the equipment, contracts for design and
construction, and any available evidence of having secured the
necessary financing to complete the required construction. If any
difficulties in meeting this requirement are anticipated, the refiner
must submit a detailed report of all efforts to date and the factors
that may cause delay, including costs, specification of engineering or
other design work still needed and reasons for delay, specification of
equipment needed and any reasons for delay, potential equipment
suppliers and history of negotiations, and any other relevant
information. If unavailability of equipment is a factor, the report
must include a discussion of other options considered, and the reasons
these other options are not feasible.
In addition, the small refiner would need to provide evidence by
June 1, 2006, that on-site construction has begun at its refinery(s)
and that absent unforeseen circumstances or problems, they will be
producing complying gasoline (30/80 ppm) by January 1, 2008. While the
submission of these progress reports is evidence of a refiner's good
faith efforts to comply by 2008, it does not bind the refiner to make
gasoline in 2008. There are several reasons why a refiner may choose to
exit the gasoline-production business in 2008 that go beyond the low
sulfur gasoline requirement.
As a result of a refiner's efforts in moving toward compliance with
the 2008 standards, for market, economic, business, or technical
reasons, the company could choose not to make gasoline in 2008.
Although we do not believe this will be the likely outcome for small
refiners, we cannot preclude it. Any refiner that makes such a
determination in its progress reports will have until 2008 to
transition out of gasoline production, but will not be considered for a
extension of hardship relief.

vii. Can Small Refiners Participate in the ABT Program?

As described in IV.C.1.c.i above, any refinery (including those
owned by small refiners) can generate sulfur allotments (in ppm-
gallons) in 2003 by producing gasoline containing less than 60 ppm
sulfur on an annual-average basis. Once this 60 ppm trigger is reached,
allotments will be calculated based on the amount of reduction from 120
ppm \95\. However, these allotments may be discounted depending on the
actual sulfur level. If a refinery fully demonstrates compliance by
producing gasoline with an annual average sulfur level of 0 to 30 ppm,
the allotments retain their full value--they are not discounted at all.
For actual sulfur levels of 31-60 ppm, which are indicative of a
partial demonstration, the allotments are discounted 20 percent.
---------------------------------------------------------------------------

\95\ If a refinery has a baseline sulfur level higher than 120
ppm (as described below in IV.C.1.c.v.), then credits are generated
from the baseline to 120 ppm and allotments from 120 ppm to the new
sulfur level (and discounted 20 percent if applicable).
---------------------------------------------------------------------------

During the period 2000-2003, refineries owned by small refiners can
also generate credits by producing gasoline averaging at least 10
percent lower than that refinery's baseline sulfur level. In other
words, to generate credits, the refinery's annual average sulfur level
for all of its gasoline on average must be 0.9 x (baseline sulfur
level). Once this ``trigger'' is reached, credits will be calculated
based on the amount of reduction from the refinery's sulfur baseline.
For example, if in 2002 a refinery reduced its annual average sulfur
level from a baseline of 450 ppm to 150 ppm (well below the trigger of
0.9 x 450 = 405 ppm), its sulfur credits would be determined based on
the difference in annual sulfur level (450--150 = 300 ppm) multiplied
by the volume of gasoline produced in 2002. Similarly, small foreign
refiner-owned refineries with an individual sulfur baseline can
generate credits in these years as long as the annual average sulfur
level of the gasoline exported to the U.S. from that refinery is lower
than 90 percent of the baseline sulfur level.
During the period 2004-2007, refineries owned by small refiners
will be permitted to generate credits but only if their actual annual
sulfur level of all gasoline produced or imported averages below their
refinery standard, and only for the difference between the standard and
the actual annual sulfur average.
A refinery (owned by a small refiner) wishing to participate in the
ABT program can sell credits beginning as soon as January 1, 2000 but
may wait until December 31, 2000 to apply for small refiner status.
However, the standards assigned to that refinery (as presented in Table
IV.C-3 above) will be based on the sulfur level from which credits were
generated, not the baseline sulfur level, since the refiner would have
already demonstrated the ability to meet the lower sulfur level. For
compliance purposes and to give refineries certainty regarding the
gasoline sulfur standards to which they will be held during 2004-2007,
the standards for a small refiner refinery participating in ABT will be
set based on the refinery's lowest sulfur average for any year between
1999 and 2003.
Using the example above, a refinery (owned by a refiner with small
refiner status) with a 1997-98 baseline sulfur level of 450 ppm would
have an interim average standard of 450/2 = 225 ppm and a cap of 225
x 1.5 = 338 ppm. If that refinery generated 300 sulfur credits in 2002
by producing gasoline with 150 ppm sulfur, then that refinery's average
sulfur standard for 2004-2007 would be ratcheted down to 150 ppm with a
cap of 300 ppm. However, that refinery would still be able to use the
300 credits that it had generated and banked in 2002 for compliance
with its 150 ppm standard.
Based on the comments received on our proposal, we are allowing
small refineries to use credits and/or allotments that they generated
and/or to purchase credits and/or allotments from another refinery to
meet their average standard during 2004-2007. We solicited comment on
whether small refiners subject to the interim standards should be
permitted to use credits towards meeting those standards, and several
small refiners who already produce very clean gasoline commented that
the special small refiner standards do not benefit them in any way.
These refiners argued that if they could generate sufficient sulfur
credits in 2000-2003, or could obtain such credits

[[Page 6771]]

through purchases from other refiners, they would not participate in
the small refiner program but would instead participate in the sulfur
ABT program. But since they are not positioned to generate credits (due
to their already low sulfur levels), and have little certainty of being
able to purchase credits, they need the relief provided by the small
refiner provisions. We concur with these concerns and thus permit small
refiners to use ABT credits and allotments. Small refiners may only use
ABT credits and/or allotments to comply with their refinery average
standard, not the per-gallon caps applied to their gasoline.
At any time, a small refiner can choose to ``opt out'' of the small
refiner program and, beginning the next calendar year, comply with the
standards in Table IV.C-2. The refiner would have to notify us of this
change in its compliance program. Once a small refiner leaves the small
refiner program, however, it would not be eligible to re-enter the
small refiner program.
b. Temporary Waivers From Low Sulfur Requirements in Extreme Unforeseen
Circumstances
In the final rule, EPA is adopting a provision permitting refiners
to seek a temporary waiver from the sulfur standards in certain
circumstances. Such waivers will be granted at EPA's discretion. Under
this provision a refiner may seek permission to distribute gasoline
that does not meet the applicable low sulfur standards for a brief time
period, based on the refiner's inability to produce complying gasoline
because of extreme and unusual circumstances outside the refiner's
control that could not have been avoided through the exercise of due
diligence. This provision is similar to a provision in EPA's RFG
regulations, and is intended to provide refiners short-term relief in
unanticipated circumstances such as an accidental refinery fire or a
natural disaster. The short-term waiver provision is intended to
address unanticipated circumstances that cannot be reasonably foreseen
at this time or in the near future
The conditions for obtaining such a waiver that are similar to
those in the RFG 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 must show that the waiver is in
the public interest, that the refiner was not able to avoid the
nonconformity, that it will make up the air quality detriment
associated with the waiver, as well as any economic benefit from the
waiver, and that it will meet the applicable sulfur standards as
expeditiously as possible.
c. Temporary Waivers Based on Extreme Hardship Circumstances
In addition to the provision for short-term relief in unanticipated
circumstances, we are adopting a provision for relief based on extreme
hardship circumstances. In developing our sulfur program, we considered
whether any refiners would face particular difficulty in complying with
the standards in the lead time provided. As described in Section
IV.C.2.a., we concluded that refineries owned by small businesses would
experience more difficulty in complying with the standards on time
because, as a group, they have less ability to raise capital necessary
for refinery investments, face proportionately higher costs because of
economies of scale, and are less able to successfully compete for
limited engineering and construction resources. However, it is possible
that other refiners who do not meet our criteria for the interim
standards also face particular difficulty in complying with the sulfur
standards on time. Therefore, we are including in the final rule a
provision allowing us, at our discretion, to grant temporary waivers
from the sulfur standards based on a showing of extreme hardship
circumstances. We do not anticipate, nor do we expect there is a need
for, granting temporary waivers that apply to more than approximately
one percent of the national gasoline pool in any given year. This
provision would allow refiners (domestic and foreign) to request a
waiver from the sulfur standards based on a showing of unusual
circumstances that result in extreme hardship and significantly affect
the ability to comply by the applicable date. As with the small refiner
interim standards, this provision furthers our overall environmental
goals of achieving low sulfur gasoline nationwide as soon as possible.
By providing short-term relief to those refiners that need additional
time because they face hardship circumstances, we can adopt a program
that reduces gasoline sulfur beginning in 2004 for the majority of the
industry that can comply by then.
As described above, EPA understands that this program will require
significant economic investments by the refining industry. We have
adopted a program with sufficient flexibilities (including an ABT
program, allotment trading, a geographic phase-in, and interim
standards for qualifying small refiners) to make these investments
reasonable and feasible over the time frame in which the standards are
phased in. Because the refining industry encompasses a wide variety of
individual circumstances, and our program phases in based on the lead
time we believe is reasonable for the industry as a whole, there may be
unusual circumstances that impose extreme hardship and significantly
affect an individual refinery's ability to comply in the lead time
provided. However, we do not intend for this waiver provision to
encourage refiners to delay planning and investments they would
otherwise make in anticipation of receiving relief from the applicable
requirements. In addition, we want to limit the environmental impact of
any hardship waivers from compliance with the standards. Thus, we
anticipate that hardship waivers will only be granted in rare
circumstances.
Because of the significant environmental benefits of lowering
sulfur in gasoline, we will administer this provision in a manner
consistent with continuing to ensure the environmental objectives of
the regulation. In our analysis of the interim small refiner standards,
we concluded that only a minimal portion of the national gasoline pool
would potentially be impacted by the less stringent interim standards,
due to the relatively small production volume of these facilities. To
limit the potential environmental impact of this hardship provision, we
reserve the discretion to deny applications where we find that granting
a waiver would result in an unacceptable environmental impact. While
this determination will be made on a case-by-case basis, we do not
expect there is a need for, nor do we anticipate, granting waivers that
apply to more than approximately one percent of the total national pool
of gasoline in any given year, or to more than a minimal percentage of
the gasoline supply of an area known to have significant air quality
problems.
There are several factors we will consider in evaluating a petition
for additional time to comply. This could include refinery
configuration, severe economic limitations, and other factors that
prevent compliance in the lead time provided. Applications for a waiver
must include information that will allow us to evaluate all appropriate
factors. EPA will consider whether the refinery configuration or
operation is unique or atypical, how much of a refinery's gasoline is
produced using an FCC unit, its hydrotreating capacity relative to its
total crude capacity, total reformer unit throughput capacity relative
to total production, gasoline

[[Page 6772]]

production in proportion to other refinery products, and other relevant
factors. A refiner may also face severe economic limitations that
result in a demonstrated inability to raise capital to make necessary
investments to comply in time, which can be shown by an unfavorable
bond rating, inadequate resources of the refiner and its parent and/or
subsidiaries, or other relevant factors. In addition, we will look at
the total crude capacity of the refinery and its parent corporation.
Finally, we will consider where the gasoline will be sold in evaluating
the environmental impacts of granting a waiver.
This provision is intended to address unusual circumstances that we
expect will be foreseeable now or in the immediate future, such as
unique and atypical gasoline refinery operations or a demonstrated
inability to raise capital. These kinds of circumstances should be
apparent at this time or in the near future, so refiners seeking
additional time under this provision must apply for relief by September
1, 2000. A refiner seeking a waiver must show that unusual
circumstances exist that impose extreme hardship and significantly
affect its ability to meet the standards on time, and that it has made
best efforts to comply with the standards, including efforts to obtain
credits and/or allotments towards compliance. Applicants for a hardship
waiver must also submit a plan demonstrating how the standards will be
achieved as expeditiously as possible. In submitting the plan, it must
include a timetable for obtaining the necessary capital, contracting
for engineering and construction resources, and obtaining permits. EPA
will review and act on applications, and, if a waiver is granted, will
specify a time period, not to extend beyond January 1, 2008 (the date
by which all gasoline is expected to meet the 30 ppm refinery average
and 80 ppm per gallon cap standards), for the waiver.
If a waiver is granted, EPA will impose as a condition of the
waiver other reasonable requirements, including antibacksliding
requirements to ensure no deterioration in the sulfur level of gasoline
and interim sulfur standards that the refiner must meet. This is
appropriate since some refiners who may qualify for a waiver can
achieve some sulfur reductions, and even reductions to levels above 30
ppm will result in some environmental benefits. While this provision
allows EPA to waive the per gallon standards as well as the average
standards, EPA would not allow gasoline sulfur to exceed the highest
per gallon cap applicable to a refiner under the interim small refiner
standards described in Section IV.C.2. Once all applications have been
received, EPA will consider the appropriate process to follow in
reviewing and acting on applications, including whether to conduct a
notice and comment decision-making process.
3. Streamlining of Refinery Air Pollution Permitting Process
a. Brief Summary of Proposal
Industry commenters expressed concern over the ability to obtain
permits to construct and operate the facility modifications needed to
meet the Tier 2 rule requirements by the end of 2004. As part of the
preamble to the proposed rule, we outlined possible approaches to
provide greater certainty and to expedite potentially applicable permit
processes. In general, we solicited comments on whether and how policy
options might be designed so as to exempt Tier 2 projects from major
New Source Review (NSR) and/or to expedite the processing of permits
where such requirements would apply. In particular, we solicited
comment on whether the major NSR process could be expedited if: (1) EPA
provided guidance on Lowest Achievable Emission Rate (LAER)
requirements or Best Available Control Technology (BACT)
determinations; (2) emissions reductions could be made available or
designated for offsetting Tier 2 activities; (3) EPA developed model
permits, or (4) EPA assisted the States in resolving source-specific
permitting issues as they would arise. The Agency also solicited
comments on how the title V operating permit requirements, where
applicable, might need to be integrated with the relevant NSR process.
In proposing various mechanisms to expedite the permitting of Tier
2 projects, we recognized that a combination of measures might be
needed, since the situations could vary widely among individual
refineries due to differences in such factors as available equipment
capacity, amount of sulfur in the crude oil, and applicable State
regulations. Source-specific analyses are also necessary to establish
what sulfur reduction techniques can be applied, to determine the
applicable permitting requirements, and to evaluate what controls will
be necessary as a result of these requirements. We indicated our intent
to offer assistance where needed.
b. Significant Comments Received
The most significant comments received on the proposal concerning
the timing impacts due to air permit requirements are presented below.
These commenters focused exclusively on the requirements to obtain a
preconstruction permit under the NSR program. Generally, commenters
only concerns regarding the title V operating permit program were that
the States' ongoing efforts to issue these permits might create a
backlog which could delay the issuance of NSR permits for Tier 2
projects. A more detailed discussion of comments received on the
proposal and EPA's response are contained in the Response To Comments
document and is filed in the Docket for this action.
We received written and oral comments from refineries about the
permit requirements associated with Tier 2 projects. Refiners
emphasized the need for certainty. They pointed out the need to secure
preconstruction permits within 18 months (e.g., 6 months to prepare and
file NSR applications and another 12 months to issue the permit) and
the need for permitting authorities to commit appropriate resources to
meet this time frame. State and local air pollution control agencies
did not support providing exemptions from emissions control and
permitting requirements. Rather, agency commenters stated that they
could accomplish the permitting requirements in the necessary time
frames, provided that complete permit applications were received in a
timely manner and refiners conferred with their regulatory agencies
soon after the Tier 2 requirements are promulgated. They also indicated
that the major NSR process could be expedited and have more certainty
(i.e., permits could be processed in 6 to 9 months) if EPA would
provide guidance on emissions controls, emissions monitoring, and
offsets. In general, environmental and community groups pointed out
that the remedies under traditional permitting practices should be
exhausted before additional flexibility is granted for Tier 2 projects.
c. Today's Action
Based on the comments and other information received in response to
the proposal, EPA believes that it is not necessary or appropriate to
explore further the development of possible options which would exempt
Tier 2 projects from the normally applicable preconstruction review
process. This position is supported by: (1) The comments of States that
industry can, in general, apply and receive NSR permits in time to
comply with Tier 2; and (2) the recognition of industry's potential
ability to use emissions reductions to net Tier 2 projects out of major
NSR which would otherwise be applicable. Nonetheless, we believe that
actions

[[Page 6773]]

should be taken to facilitate early compliance, to add certainty to the
anticipated permitting actions and schedules, and to minimize the
possibility of delay. Accordingly, EPA is taking two types of actions
to promote these objectives.
First, as previously discussed, we have structured the final
gasoline sulfur program to allow additional lead time for many refiners
(i.e., certain refineries would be able to make desulfurization changes
later than the proposed 2004 compliance date to meet Tier 2
requirements). This approach will help address the concerns over the
availability of necessary new equipment and permitting backlogs caused
by many refineries acting to obtain permits and order equipment within
relatively the same time period.
Second, we intend to take several actions (described in more detail
below) to expedite and impart greater certainty in obtaining necessary
major NSR permits. As a result of comments received on the proposal,
and the lead time provided in the final gasoline sulfur program, we
believe that the vast majority of permits can be issued within the
necessary time frames, provided that refineries submit their
preconstruction applications in a timely manner and regulatory
authorities prioritize the issuance of these permits. We also intend to
assist States and refiners on a case-by-case basis in their efforts to
address any unique permitting problems that might arise and, thus,
remedy potential problems that could cause unanticipated delays. In the
unlikely event permitting delays occur, EPA will work with refiners and
the state/local permitting agencies on a case-by-case basis, where a
refinery has unique circumstances that necessitate unique treatment.
While today's strategy will help expedite the permitting process,
refineries that trigger major NSR as a result of producing low sulfur
gasoline will still have to install the stringent level of emissions
control technology required by the Act. However, we intend to issue
guidance to assist states in making decisions about the levels of
control technology, as described more below. In addition, the Agency
wishes to clarify that, in our efforts to provide greater certainty and
to facilitate more expeditious permitting, we are in no way
shortcutting existing opportunities for public participation. We
recognize the importance of public participation in making permitting
decisions and intend that the measures adopted to address permitting
concerns will not diminish the opportunities for public participation.

i. Major New Source Review

The major NSR program, as it applies to existing major stationary
sources of air pollution, requires that a preconstruction permit be
issued before a source makes a physical change or change in its method
of operation of any project that would result in a significant net
emissions increase. As described in the proposal, the steps taken by
certain refineries to implement gasoline sulfur reductions to meet
today's rule could result in emissions increases in one or more
pollutants which may trigger the requirements for this type of
preconstruction permit. A number of the refineries are located in areas
designated as nonattainment for at least one pollutant. The
nonattainment NSR requirements pursuant to part D of the Act would
apply to any such refinery undergoing a major modification. For those
refineries located in attainment or unclassifiable areas, permit
requirements for the prevention of significant deterioration (PSD) of
air quality must be met for major modifications.
The EPA recognizes the importance of timely major NSR (as
applicable) permit actions for refineries to proceed with necessary
changes to meet the new low sulfur gasoline standard. We encourage
refineries to begin discussions with permitting authorities and to
submit permit applications--as early as possible. In addition, based on
comments received, we believe that there are a few key areas in which
assistance would be useful toward helping States issue timely permits
to the applicable refineries:
Federal guidance on emissions control technology
requirements.
Refineries subject to major NSR review will be required to undergo
a source-specific evaluation to apply either BACT or LAER, depending
upon the applicable program requirements. For example, the evaluation
for BACT is case-by-case and takes into account the alternative
technologies available to control pollution from a particular emissions
unit or process, and considers the energy, environmental, economic and
other costs associated with each technology. We intend to issue
guidance setting out a level of emissions that, in our view, would be
expected to satisfy the requirements for BACT for certain emissions
units associated with refinery desulfurization projects. While States
would not be required to use the results to establish BACT for a
particular refinery subject to review and EPA's guidance on a control
technology may not be appropriate where there exists unusual site-
specific circumstances, such guidance would add the certainty of EPA's
expectations.
Since negotiation of an appropriate BACT level often is one of the
most time consuming aspects of permitting, we believe this EPA guidance
will significantly expedite the process. The federal guidance on BACT,
by including an evaluation of the most stringent control levels
currently being achieved or required, will also provide federal
guidance on LAER. The EPA plans to make a draft of this guidance
available for public review and comment in January 2000. Final guidance
would then be prepared, after relevant comments are considered, in time
for States, refiners, and the public to consider in preparing and
reviewing permit applications and proposed permits.
Availability of offsets.
Refineries located in nonattainment areas must offset any proposed
significant emissions increases with an equal or greater amount of
emissions reductions from other sources, usually coming from within the
same nonattainment area. We believe that vehicle emissions reductions
resulting from the use of low sulfur gasoline can be used as offsets
for the refineries, as long as the statutory and regulatory criteria
for creditable offsets are satisfied and States decide to provide for
this opportunity in their SIP attainment demonstration. We believe
generally that this option should be available to States since only a
small fraction of the total vehicle emissions reductions in any county
would be needed to offset refinery emissions increases resulting from
implementation of gasoline desulfurization projects. Generally, the
reductions must also occur in the same nonattainment area as the
location of the refinery for which the offsets are required. The EPA
plans to issue the appropriate guidance early in the year 2000 to help
a State to determine whether and to what extent it may wish to use
vehicle emissions reductions as offsets for Tier 2 projects.
EPA refinery permitting teams.
We intend to assemble special EPA teams, comprised of Headquarters
and Regional Office experts, that will track the overall progress in
permit issuance and will be available to assist State and local
permitting authorities, refineries, and the public upon request to
resolve site-specific permitting issues. These teams will be comprised
of persons who are knowledgeable about permitting programs and refinery
operations and can provide expert assistance to troubleshoot permitting
issues that may arise. As appropriate, the teams will work with
stakeholders on a case-by-

[[Page 6774]]

case basis to evaluate site-specific approaches to regulatory
compliance within existing policy and regulations.

ii. Environmental Justice

The Tier 2/gasoline sulfur rule will help achieve significant
nationwide reductions in the emissions of nitrogen oxides (NOx),
volatile organic compounds (VOC), particulate matter (PM), and sulfur
dioxide (SO2). These reductions will improve air quality
across the country and will provide increased protection to the public
against a wide range of health effects, including chronic bronchitis,
respiratory illnesses, and aggravation of asthma symptoms. Furthermore,
the Tier 2/gasoline sulfur rule will achieve environmental benefits in
the local areas where refineries are located, due to reductions in tail
pipe emissions from vehicles driven in those areas. Although we expect
residual emissions increases at some refineries even after installing
the stringent level of emissions controls required under the Act, for
the vast majority of areas, we believe that these potential refinery
emissions increases will be very small compared to the Tier 2 benefits
in those same local areas.
We believe it is important to understand and address concerns
relating to potential localized emissions increases from refineries
that make significant process changes to meet the requirements of the
Tier 2 rule. We believe that, among other things, the keys to
addressing any potential concerns are as follows:
Providing meaningful community involvement early and
throughout the process;
Determining what information and actions would eliminate
concerns; and
Determining what EPA, States, and industry can do to make
the permitting process smoother by ensuring ongoing community
involvement in the decision making process and by building trust among
stakeholders.
To this end, the Agency has already taken some actions to try to
mitigate potential environmental justice concerns. First, EPA's Office
of Air and Radiation and the Alternative Dispute Resolution Team within
EPA's Office of the Administrator implemented a national convening
process which was designed to bring together a broad spectrum of
stakeholders to explore with them their perceptions and views of issues
associated with Tier 2 permitting and to assess the potential for a
collaborative process to address specific implementation issues at some
time in the future. The convening was carried out by an outside neutral
party who conducted interviews with representatives from selected EPA
offices, States, industry, environmental groups, and environmental
justice organizations. Second, EPA held informational briefings and
provided background materials to the National Environmental Justice
Advisory Council's (NEJAC) \96\ Air and Water Subcommittee and
Enforcement Subcommittee to provide an opportunity for them to provide
feedback and recommendations to the Agency. Finally, in October 1999,
we met with both national environmental groups and environmental
justice advocacy representatives, to discuss their views on the
permitting aspects of the proposed rule.
---------------------------------------------------------------------------

\96\ The NEJAC was chartered in 1993 expressly to give the EPA
Administrator independent advice, consultation, and recommendations
on environmental justice matters. NEJAC members come from state,
tribal, and local governments; tribal and indigenous citizen's
organizations; business and industry; academia; and environmental
advocacy and grassroots community groups.
---------------------------------------------------------------------------

The EPA is committed to continue working with all stakeholders to
resolve specific Environmental Justice issues if and when they arise.
To fulfill this commitment, we plan to undertake additional actions in
the future, including providing education and outreach about the rule
and its impacts in local communities, developing permitting guidance
through a public process and addressing Title VI petitions if they
arise.

D. What Are the Economic Impacts, Cost Effectiveness and Monetized
Benefits of the Tier 2 Program?

Consideration of the economic impacts of new standards for vehicles
and fuels has been an important part of our decision making process for
this final rule. The following sections describe first the costs
associated with meeting the new vehicle standards and the new fuel
standards. This will be followed with a discussion of the cost
effectiveness of the rule. Lastly, we will discuss the results of a
benefit-cost assessment that we have prepared.
Full details of our cost analyses, including information not
presented here, can be found in the RIA associated with this rule.
Also, our response to comments on the cost, cost effectiveness, and
monetized benefits analyses are contained in the Response to Comments
document for this rule.
1. What Are the Estimated Costs of the Vehicle Standards?
To perform a cost analysis for the standards, we first determined a
package of likely technologies that manufacturers could use to meet the
standards and then determined the costs of those technologies. In
making our estimates we have relied on our own technology assessment
which included publicly available information, such as that developed
by California, as well as confidential information supplied by
individual manufacturers, and the results of our own in-house testing.
In general, we expect that the Tier 2 standards will be met through
refinements of current emissions control components and systems rather
than through the widespread use of new technology. Furthermore, smaller
lighter-weight vehicles and trucks will generally require less
extensive improvements than larger vehicles and trucks. More
specifically, we anticipate a combination of technology upgrades such
as the following:
Improvements to the catalyst system design, structure, and
formulation plus in some cases an increase in average catalyst size and
loading;
Air and fuel system modifications including changes such
as improved microprocessors, improved oxygen sensors, leak free exhaust
systems, air assisted fuel injection, and calibration changes including
improved precision fuel control and individual cylinder fuel control;
Engine modifications, possibly including an additional
spark plug per cylinder, an additional swirl control valve, or other
hardware changes needed to achieve cold combustion stability;
Increased use of fully electronic exhaust gas
recirculation (EGR); and
Increased use of secondary air injection for 6 cylinder
and larger engines.
The costs for MDPVs have been included here with the LDT4 cost
estimates. We expect that the technologies needed to meet the Tier 2
standards for the MDPVs will be very similar to those for LDT4s.
However, the MDPVs cost estimates are somewhat higher than for LDT4s.
Vehicles over 8,500 pounds GVWR are currently certified to heavy-duty
engine emissions standards using the heavy-duty test procedures. This,
at least in part, has led to differences in baseline technologies
compared to current LDT4s. Vehicles above 8,500 pounds, for example,
are currently equipped with technologies such as close coupled
catalysts and secondary air injection to a lesser extent. Therefore, we
expect higher incremental costs for the MDPVs compared to LDT4s. There
is further information on the costs for MDPVs in the RIA.

[[Page 6775]]

Using a typical mix of changes for each group, we projected costs
separately for LDVs, the different LDT classes, and for different
engine sizes (4, 6, 8, 10-cylinder) within each class. For each group
we developed estimates of both variable costs (for hardware and
assembly time) and fixed costs (for R&D, retooling, and certification).
Cost estimates based on the current projected costs for our
estimated technology packages represent an expected incremental cost of
vehicles in the near-term. For the longer term, we have identified
factors that would cause cost impacts to decrease over time. First,
since fixed costs are assumed to be recovered over a five-year period,
these costs disappear from the analysis after the fifth model year of
production. Second, the analysis incorporates the expectation that
manufacturers and suppliers will apply ongoing research and
manufacturing innovation to making emission controls more effective and
less costly over time. Research in the costs of manufacturing has
consistently shown that as manufacturers gain experience in production
and use, they are able to apply innovations to simplify machining and
assembly operations, use lower cost materials, and reduce the number or
complexity of component parts.\97\ These reductions in production costs
are typically associated with every doubling of production volume. Our
analysis incorporates the effects of this ``learning curve'' by
projecting that the variable costs of producing the Tier 2 vehicles
decreases by 20 percent starting with the third year of production. We
applied the learning curve reduction only once since, with existing
technologies, there would be less opportunity for lowering production
costs than would be the case with the adoption of new technology.
---------------------------------------------------------------------------

\97\ ``Learning Curves in Manufacturing,'' Linda Argote and
Dennis Epple, Science, February 23, 1990, Vol. 247, pp. 920-924.
---------------------------------------------------------------------------

We have prepared our cost estimates for meeting the Tier 2
standards using a baseline of NLEV technologies for LDVs, LDT1s, and
LDT2s, and Tier 1, or current technologies for LDT3s, LDT4s and MDPVs.
These are the standards that vehicles would be meeting in 2003.\98\ We
have not specifically analyzed smaller incremental changes to
technologies that might occur due to the interim standards between the
baseline and Tier 2. In most cases, we believe these changes will not
be significant based on current certification levels and manufacturers
will maximize carry-over. For others, manufacturers can use averaging
and other program flexibilities to avoid redesigning vehicles twice
within a relatively short period of time. We believe this is likely to
be an attractive approach for manufacturers due to the savings in R&D
and other resources.
---------------------------------------------------------------------------

\98\ Even though the NLEV program ends in the Tier 2 timeframe,
we have not included the NLEV program costs or benefits in our
analysis, since EPA analyzed and adopted NLEV previously.
---------------------------------------------------------------------------

For the total annual cost estimates, we projected that
manufacturers will start the phase-in of Tier 2 vehicles with LDVs in
2004 and progress to heavier vehicles until all LDT2s meet Tier 2
standards in 2007. For LDT3s and LDT4s, we projected some sales of Tier
2 LDT3s prior to 2008 for purposes of averaging in the interim program
and that the phase-in of Tier 2 vehicles would end with LDT4s and MDPVs
in 2009.
Finally, we have incorporated what we believe to be a
conservatively high level of R&D spending at $5,000,000 per vehicle
line (with annual sales of 100,000 units per line). We have included
this large R&D effort because calibration and system optimization is
likely to be a critical part of the effort to meet Tier 2 standards.
However, we believe that the R&D costs may be generous because the
projection ignores the carryover of knowledge from the first vehicle
lines designed to meet the standard to others phased-in later.
The evaporative emissions standards we are finalizing today for
LDVs, LDTs and MDPVs are feasible with relatively small cost impacts.
We estimate the cost of system improvements to be about $4 per vehicle,
for all vehicle classes. This incremental cost reflects the cost of
moving to low permeability materials, improved designs or low-loss
connectors. R&D for the evaporative emissions standard is included in
the R&D estimates given above for the tailpipe standards. We have
included no projections of learning curve reductions for the
evaporative standard.
Table IV.D.-1 provides our estimates of the per vehicle increase in
purchase price for LDVs, LDTs, and MDPVs. The near-term cost estimates
in Table IV.D.-1 are for the first years that vehicles meeting the
standards are sold, prior to cost reductions due to lower productions
costs and the retirement of fixed costs. The long-term projections take
these cost reductions into account. We have sales weighted the cost
differences for the various engine sizes (4-, 6-, 8-, 10-cylinder)
within each category.

Table IV.D.-1.--Estimated Purchase Price Increases Due to Tier 2 Tailpipe Standards
----------------------------------------------------------------------------------------------------------------
LDT4/MDPVs
LDV LDT1 LDT2 LDT3 \a\
----------------------------------------------------------------------------------------------------------------
Tailpipe standards:
Near-term (year 1)......................... $78 $70 $125 $245 $258
Long-term (year 6 and beyond).............. 49 45 97 199 208
Evaporative Standard........................... 4 4 4 4 4
----------------------------------------------------------------------------------------------------------------
Notes:
\a\ Weighted average.

We did not receive comments disagreeing with the technology
projections or technology cost estimates contained in the proposal. We
have, however, revised our cost estimates somewhat based on new
information available since the proposal. We moderately lowered our
cost estimates due to adjustments we have made in our technology
projections. Based on the results of our vehicle testing program
described above in section IV.A.1., we now believe that a few of the
hardware changes we had anticipated are not likely to be needed to meet
the standards. Albeit there is always fluctuation, the spot prices of
precious metals have increased somewhat since the proposal and we have
adjusted our analysis to reflect those changes.
Overall, the cost estimates are within 5 percent of those in the
proposal for LDVs and LLDTs. The changes noted above moderately lowered
the costs for HLDTs compared to the proposal. The cost increase due to
the inclusion of MDPVs offsets most of the lowered costs

[[Page 6776]]

for the LDT4 category. The resulting cost estimate for the LDT4/MDPVs
tailpipe standards is also within 5 percent of the cost estimates for
LDT4s contained in the proposal. The detailed technology and cost
analyses are available in the RIA.
We are also finalizing OBD II requirements and onboard vapor
recovery (ORVR) requirements for MDPVs. We have estimated that OBD II
will cost about $80, which includes the costs of additional sensors and
system improvements. We have estimated ORVR system costs to be about
$10. The $10 cost for ORVR does not include any fuel cost savings over
the life of the vehicles due the recover of fuel vapor during
refueling. ORVR provides a fuel cost savings because the vapors are
captured, and burned in the engine, rather than escaping to the
atmosphere. We estimate the savings over the life of the vehicle to be
about $6. These costs are not reflected in Table IV.D.-1.
2. Estimated Costs of the Gasoline Sulfur Standards
As we explained at the beginning of Section IV.C, we expect that
most refiners will have to install capital equipment to meet the
gasoline sulfur standard. Presuming that refiners will want to minimize
the cost involved, the majority of refiners are expected to desulfurize
the gasoline blendstock produced by the fluidized catalytic cracker
(FCC) unit, although a few may choose to desulfurize the feed to the
FCC unit. Recent advances have led to significant improvements in the
hydrotreating technologies used for FCC gasoline desulfurization. Since
these improved technologies represent the lowest cost options and are
expected to be used by most refiners needing to install desulfurization
equipment, we have based our cost estimates primarily on their use.
However, in acknowledgment that some refiners, particularly those which
make investment decisions in the near term, are likely to select more
traditional approaches using proven technologies, we have included the
costs for currently proven desulfurization technologies in our
analysis, as well. This is different from the analysis we did in
support of our proposal, where we assumed that all refiners would take
advantage of the most improved technologies we were aware of at that
time.
For our analysis of the costs of controlling gasoline sulfur, we
estimated the costs in five different regions of the country (Petroleum
Administration Districts for Defense, or PADDs) for reductions from the
current PADD average gasoline sulfur level down to a 30 ppm average. We
then combined the regional costs to develop an average national
individual refinery cost, and used this figure to calculate national
aggregate capital and operating costs. In our proposal we estimated a
single cost for desulfurizing gasoline, using as an assumption for the
purpose of analysis that all refiners would upgrade their refineries by
2004 and that all would choose one of two improved technologies we knew
of at the time. We then reduced this cost over time to reflect expected
cost reductions due to further technology advancements and reduced
operating costs due to improved understanding of the technologies and
refinery debottlenecking. Based on improved information about the
availability of technologies, we have now analyzed the costs of
controlling sulfur on a year-by-year basis beginning with 2004, to be
consistent with our analysis of the rate at which the industry would
invest in desulfurization technologies over the first years of the
program and the changing technology selections (and costs) that would
accompany this phase-in (discussed in Section IV.C.1 above). A detailed
description of our calculations can be found in the Regulatory Impact
Analysis; the reader can refer to the draft RIA released with the
proposed rule for more information on our prior analysis.
We estimate that, on average, refineries which install equipment to
meet the 30 ppm average standard will invest about $44 million for
capital equipment and spend about $16 million per year for each
refinery to cover the operating costs associated with these
desulfurization units. Since this average represents many refineries
diverse in size and gasoline sulfur level as well as a mix of
desulfurization technologies, some refineries will pay more and others
less than the average costs. When the average per-refinery cost is
aggregated for all the gasoline expected to be produced in this country
in 2008 (the first year that all refiners will be required to meet the
30 ppm standard, unless any small refiners are granted a extension of
hardship relief), the total investment for desulfurization processing
units (spread between 2003 and 2007) is estimated to be about $4.3
billion, and operating costs for these units is expected to be about
$1.3 billion per year.
Using our estimated capital and operating costs for domestic
refineries, we calculated the average per-gallon cost of reducing
gasoline sulfur down to 30 ppm for each year as the program is
implemented. Using a capital cost amortization factor (based on a seven
percent rate of return on investment) and including no taxes, we
estimated the average national cost for desulfurizing gasoline to be
about 1.7-1.9 cents per gallon as the program is phased in. This cost
is the cost to society of reducing gasoline sulfur down to 30 ppm that
we used for estimating cost effectiveness. Table IV.D.-2 below
summarizes our estimates of per-gallon gasoline cost increases for
select years.

Table IV.D.-2.--Estimated Per-Gallon Cost for Desulfurizing Gasoline in
Future Years
------------------------------------------------------------------------
Cost (cents/
Year gallon)
------------------------------------------------------------------------
2004....................................................... 1.9
2005....................................................... 1.9
2006....................................................... 1.7
2007....................................................... 1.7
2008-2018.................................................. 1.7
2019+...................................................... 1.3
------------------------------------------------------------------------

Although the costs shown here are slightly higher than we projected
in the proposal, overall, we believe our revised costs are consistent
with those in the proposal and that our improved methodology and
information are the source of the differences. As stated earlier in
this section, we believe this analysis more accurately reflects the
actual investment decisions of individual refiners over the years in
which the industry is phasing down sulfur levels. Furthermore, we have
also made a number of other adjustments to our analysis of capital and
operating costs for each individual technology based on new information
received from the technology vendors and information we obtained during
the comment period. For example, we now include eight different
technologies in our analysis, including some more traditional
approaches, whereas in the proposal we only considered two new
technologies. Hence, the range of costs is broader. In addition, as
explained in the RIA, we now believe we underestimated the capital
costs of desulfurization slightly in the proposal based on our
calculation of the costs of providing hydrogen to the processes. We
believe our analysis now reflects the most up-to-date information about
the costs of installing and operating the various desulfurization
technologies included in our analysis. These adjustments are explained
in detail in the Regulatory Impact Analysis.
We still believe that over time, particularly in 2006-8 when the
last refineries will be making investments, the costs of gasoline
desulfurization equipment will be significantly lower

[[Page 6777]]

than it is today. Some of the technologies expected to be selected in
this time frame (specifically, the new adsorption technologies which we
didn't know about when we proposed these requirements) are projected to
cost about half of what the older technologies cost. Furthermore, with
time refiners will have to replace existing desulfurization equipment
(as equipment ages), and by then they will have a number of low cost
alternatives to choose from. Thus, as Table IV.D.-2 shows, the long
term estimated costs for gasoline desulfurization are lower than those
we projected in our proposal.\99\
---------------------------------------------------------------------------

\99\ For a sensitivity analysis of our cost estimates using
alternative assumptions, please see Chapter V of the RIA.
---------------------------------------------------------------------------

3. What Are the Aggregate Costs of the Tier 2/Gasoline Sulfur Final
Rule?
Using current data for the size and characteristics of the vehicle
fleet and making projections for the future, the per-vehicle and per-
gallon fuel costs described above can be used to estimate the total
cost to the nation for the emission standards in any year. Figure
IV.D.-1 portrays the results of these projections.\100\
---------------------------------------------------------------------------

\100\ Figure IV.D.-1 is based on the amortized costs from Tables
IV.D.-1 and IV.D.-2. Actual capital investments, particularly
important for fuels, would occur prior to and during the initial
years of the program, as described above in section IV.D.2.

BILLING CODE 6560-50-P
[GRAPHIC] [TIFF OMITTED] TR10FE00.006

BILLING CODE 6560-50-C
As can be seen from the figure, the annual cost starts out at about
$1.9 billion per year and increases over the phase-in period to about
$4.1 billion in 2008. Total annualized costs are projected to remain at
about $4 billion through 2018. After 2018, annualized fuel costs are
projected to decrease somewhat due to the use of new technologies which
would enable refiners to produce low sulfur fuel at a lower cost. The
gradual rise in costs long term is due to the effects of projected
growth in vehicle sales and fuel consumption. The RIA provides further
detail regarding these cost projections.
4. How Does the Cost-effectiveness of This Program Compare to Other
Programs?
This section summarizes the cost-effectiveness analysis conducted
by EPA and its results. The purpose of this analysis is to show that
the reductions from the vehicle and fuel controls being finalized today
are cost-effective in comparison to alternative means of attaining or
maintaining the NAAQS. This analysis involves a comparison of our
program not only to past measures, but also to other potential future
measures that might be employed to attain and maintain the NAAQS. Both
EPA and states have already adopted numerous control measures, and
remaining measures tend to be more expensive than those previously
employed. As we employ the most cost-effective available measures
first, more expensive ones tend to become necessary over time.
The emission reductions used to calculate the cost-effectiveness
levels reported here are based on those reductions used for our air
quality analysis modeling and benefits analysis. This was done to
maintain consistency in the analyses. As noted in Section III.B. above,
we have updated our inventory model since the air quality modeling
inventories were calculated. In Chapter III of our RIA, Table III.A.-3
compares the updated Tier 2 model with the air quality analysis
modeling and shows that the emission reductions expected from Tier 2/
gasoline sulfur will be substantially greater than the amounts
originally calculated. If the

[[Page 6778]]

updated numbers were incorporated into our cost-effectiveness we would
expect the results to be improved over those shown in this section.
We received a number of comments on our cost-effectiveness analysis
in response to our NPRM. Our responses to these comments can be found
in the Response To Comments document.
a. Cost-Effectiveness of This Program
We have calculated the cost-effectiveness of the exhaust emission/
gasoline sulfur standards and the evaporative emission standards, based
on two different approaches. The first considers the net present value
of all costs incurred and emission reductions generated over the life
of an average Tier 2 vehicle. This per-vehicle approach focuses on the
cost-effectiveness of the program from the point of view of the Tier 2
vehicles which will be used to meet the new requirements, and is the
method used in our proposal. However, the per-vehicle approach does not
capture all of the costs or emission reductions from the Tier 2/
gasoline sulfur program since it does not account for the use of low
sulfur gasoline in pre-Tier 2 vehicles. Therefore, we have also
calculated an aggregate cost-effectiveness using the net present value
of costs and emission reductions for all in-use vehicles over a 30-year
time frame.
As described earlier in the discussion of the cost of this program,
the cost of complying with the new standards will decline over time as
manufacturing costs are reduced and amortized capital investments are
recovered. To show the effect of declining cost in the per-vehicle
cost-effectiveness analysis, we have developed both near term and long
term cost-effectiveness values. More specifically, these correspond to
vehicles sold in years one and six of the vehicle and fuel programs.
Vehicle cost is constant from year six onward. Fuel costs per gallon
continue to decline slowly in the years past year six; however, the
overall impact of this decline is small and we have decided to use year
six results for our long term cost-effectiveness. Chapter VI of the RIA
contains a full description of this analysis, and you should look in
that document for more details of the results summarized here.
The aggregate approach to calculating the cost-effectiveness of our
program involves the net present value of all nationwide emission
reductions and costs for a 30-year period beginning with the start of
the program in 2004. This timeframe captures both the early period of
the program when very few Tier 2 vehicles will be in the fleet, and the
later period when essentially all vehicles in the fleet will meet Tier
2 standards. We have calculated the aggregate cost-effectiveness using
the net present value of the nationwide emission reductions and costs
for each calendar year. These emission reductions and costs are
summarized in Sections III.B, III.C, and IV.D.3, and are given for
every calendar year in the RIA. For more information on how the
aggregate cost-effectiveness was calculated please refer to the RIA.
Our per-vehicle and aggregate cost-effectiveness values are given
in Tables IV.D.-3 and IV.D.-4. Table IV.D.-3 summarizes the per-
vehicle, net present value lifetime costs, NMHC+NO_X emission
reductions, and resulting cost-effectiveness results for our Tier 2/
gasoline sulfur program using sales weighted averages of the costs
(both near term and long term) and emission reductions of the various
vehicle classes affected. Table IV.D.-4 provides the same information
from the program aggregate perspective. It includes the net present
value of the 30-year stream of vehicle and fuel costs,
NMHC+NO_X emission reductions, and the resulting aggregate
cost-effectiveness. For simplicity, we have used the midpoint of our
estimated range of 20 to 65 percent for the irreversibility effect. The
full range of irreversibility would only cause the cost-effectiveness
values to differ from those in Table IV.D-3, for example, by $60/ton to
$100/ton. Note that, even though we are setting new standards for PM,
those standards are already being met, so there is no cost associated
with the new PM standard and therefore no separate cost-effectiveness
analysis for PM.
Tables IV.D.-3 and IV.D.-4 also display cost-effectiveness values
based on two approaches to account for the reductions in SO2
and tailpipe emitted sulfate particulate matter (PM) associated with
the reduction in gasoline sulfur. While these reductions are not
central to the program and are therefore not displayed with their own
cost-effectiveness, they do represent real emission reductions due to
our program. The first set of cost-effectiveness numbers in the tables
simply ignores these reductions and bases the cost-effectiveness on
only the NMHC+NO_X reductions from Tier 2/gasoline sulfur.
The second set accounts for these ancillary reductions by crediting
some of the cost of the program to SO2 and PM reduction. The
amount of cost allocated to SO2 and PM is based on the cost-
effectiveness of SO2 and PM emission reductions that could
be obtained from alternative, potential future EPA programs.

Table IV.D-3.--Per-Vehicle Cost-Effectiveness of the Standards
----------------------------------------------------------------------------------------------------------------
Discounted
Discounted lifetime cost-
Discounted lifetime Discounted effectiveness
Cost basis lifetime NMHC + NO_X lifetime cost- per ton with
vehicle & reduction effectiveness SO2 and
fuel costs (tons) per ton direct PM
credit ^a
----------------------------------------------------------------------------------------------------------------
Near term cost (production year 1)...................... $243 0.110 $2,211 $1,717
Long term cost (production year 6)...................... 205 0.110 1,863 1,368
----------------------------------------------------------------------------------------------------------------
Notes:
\a\ $51 credited to SO2 ($4,800/ton), $4 to direct PM ($10,000/ton).

[[Page 6779]]

Table IV.D-4.--Aggregate Cost-Effectiveness of the Standards
------------------------------------------------------------------------
Discounted
Discounted Discounted Discounted aggregate cost-
aggregate aggregate NMHC + aggregate cost- effectiveness per
vehicle & fuel NO_X reduction effectiveness per ton with SO2 and
costs (tons) ton direct PM credit
(millions) \a\
------------------------------------------------------------------------
$48.1 billion 23.5 $2,047 $1,311
------------------------------------------------------------------------
Notes:
\a\ $13.8 billion credited to SO2 ($4,800/ton), $3.5 billion to direct
PM ($10,000/ton).

b. How Does the Cost-Effectiveness of This Program Compare With Other
Means of Obtaining Mobile Source NO_X + NMHC Reductions?
In comparison with other mobile source control programs, we believe
that our program represents the most cost-effective new mobile source
control strategy currently available that is capable of generating
substantial NO_X + NMHC reductions. This can be seen by
comparing the cost-effectiveness of today's program with a number of
mobile source standards that EPA has adopted in recent years. Table
IV.D.-5 summarizes the cost-effectiveness of several recent EPA
actions.

Table IV.D.-5.--Cost-Effectiveness of Previously Implemented Mobile
Source Programs
------------------------------------------------------------------------
$/ton ^a
Program NO_X+NMHC
------------------------------------------------------------------------
2004 Highway HD Diesel stds............................. 204-399
Nonroad Diesel engine stds.............................. 410-650
Tier 1 vehicle controls................................. 1,980-2,690
NLEV.................................................... 1,859
Marine SI engines....................................... 1,128-1,778
On-board diagnostics.................................... 2,228
------------------------------------------------------------------------
Notes: ^a Costs adjusted to 1997 dollars.

We can see from the table that the cost-effectiveness of the Tier
2/gasoline sulfur standards falls within the range of these other
programs. Engine-based standards (the 2004 highway heavy-duty diesel
standards, the nonroad diesel engine standards and the marine spark-
ignited engine standards) have generally been less costly than Tier 2/
gasoline sulfur. Vehicle standards, most similar to today's program,
have values comparable to or higher than Tier 2/gasoline sulfur.
The values in Table IV.D.-5 might imply that further reductions in
NO_X and VOC from heavy-duty engines could be more cost-
effective than the reductions that will be produced from our Tier 2/
gasoline sulfur program. However, we do not believe that to be the
case. While we are indeed developing a proposal for further control
from heavy-duty engines, we expect that substantial further emission
reductions will require advanced after-treatment devices. These devices
will be more costly than methods used to meet our past standards, and
will have difficulty functioning properly without changes to diesel
fuel. We therefore expect that the cost effectiveness of future heavy-
duty standards is not likely to be significantly less than the cost
effectiveness of today's rule.
On the light-duty vehicle side, the last two sets of standards were
Tier 1 and NLEV, which had cost-effectiveness comparable to or higher
than Tier 2/gasoline sulfur. Compared to engines, these levels reflect
the advanced (and more expensive) state of vehicle control technology,
where standards have been in effect for a much longer period than for
engines. Considering the increased stringency of the Tier 2 standards,
it is noteworthy that the cost-effectiveness of Tier 2/gasoline sulfur
is in the same range as these actions. Based on these results, Tier 2/
gasoline sulfur is a logical and consistent next step in vehicle
control.
In conclusion, we believe that the Tier 2/Gasoline Sulfur program
is a cost-effective program for mobile source NO_X + NMHC
control. We are unable to identify another mobile source control
program that would be more cost-effective than Tier 2/gasoline sulfur
while also producing equivalent reductions in NO_X and NMHC
emissions in the same timeframe as our program.
c. How Does the Cost-Effectiveness of This Program Compare With Other
Known Non-Mobile Source Technologies for Reducing NO_X +
NMHC?
In evaluating the cost-effectiveness of the Tier 2/Gasoline Sulfur
program, we also considered whether our program is cost-effective in
comparison with alternative means of attaining or maintaining the NAAQS
other than mobile source programs. As described below, we have
concluded that Tier 2/Gasoline Sulfur is cost-effective considering the
anticipated cost of other technologies that will be needed to help
attain and maintain the NAAQS.
In the context of the Agency's rulemaking to revise the ozone and
PM NAAQS, \101\ the Agency compiled a list of additional known
technologies that could be considered in devising new emission
reductions strategies.\102\ Through this broad review, over 50
technologies were identified that could reduce NO_X or VOC.
The cost-effectiveness of these technologies averaged approximately
$5,000/ton for VOC and $13,000/ton for NO_X. These values
clearly indicate that not only are future emission control strategies
likely to be more expensive (less cost-effective) than past strategies,
but the cost-effectiveness of our Tier 2/Gasoline Sulfur program falls
at the lower end of the range for potential future strategies.
---------------------------------------------------------------------------

\101\ This rulemaking was remanded by the D.C. Circuit Court on
May 14, 1999. However, the analyses completed in support of that
rulemaking are still relevant, since they were designed to
investigate the cost-effectiveness of a wide variety of potential
future emission control strategies.
\102\ ``Regulatory Impact Analyses for the Particulate Matter
and Ozone National Ambient Air Quality Standards and Proposed
Regional Haze Rule,'' Appendix B, ``Summary of control measures in
the PM, regional haze, and ozone partial attainment analyses,''
Innovative Strategies and Economics Group, Office of Air Quality
Planning and Standards, U.S. Environmental Protection Agency,
Research Triangle Park, NC, July 17, 1997.
---------------------------------------------------------------------------

In addition, our Tier 2/Gasoline Sulfur program will deliver
critical further reductions that are not readily obtainable by any
other means known to the Agency. If all of the technologies modeled in
the NAAQS analysis costing less than $10,000/ton were implemented
nationwide, they would produce NO_X emission reductions of
about 2.9 million tons per year. The Tier 2/Gasoline Sulfur program by
itself will generate about 2.8 million tons per year once fully
implemented. Given the continuing need for further emission reductions,
we believe that Tier 2/Gasoline Sulfur control is clearly a cost-
effective approach for attaining and maintaining the NAAQS.
We recognize that the cost-effectiveness calculated for Tier 2/
Gasoline Sulfur is not strictly comparable to a figure for measures
targeted at nonattainment areas, since Tier 2/Gasoline Sulfur is a
nationwide program. However, there are several additional
considerations that have led us to conclude that Tier 2/Gasoline Sulfur
is cost-effective considering

[[Page 6780]]

alternative means of attaining and maintaining the NAAQS.
First of all is the fact that the cost effectiveness of Tier 2/
Gasoline Sulfur is so much better than the numbers developed for the
NAAQS analysis. It is only 20 percent as costly per ton as the $10,000
per ton upper limit employed in that analysis for selecting suitable
strategies even though, as noted above, Tier 2/Gasoline Sulfur will
produce almost the same level of emission reduction. Furthermore, as a
national program, Tier 2/Gasoline Sulfur can be implemented as a single
unified rule without the need for individual action by each of the
states.
In dealing with the question of comparing local and national
programs, it is also relevant to point out that, because of air
transport, the need for NO_X control is a broad regional
issue not confined to non-attainment areas only. To reach attainment,
future controls will need to be applied over widespread areas of the
country. In the analyses supporting the recent NO_X standards
for highway diesel engines,\103\ we looked at this question in some
detail and concluded that the regions expected to impact ozone levels
in ozone nonattainment areas accounted for over 85% of total
NO_X emissions from a national heavy-duty engine control
program. Similarly, NO_X emissions in attainment areas also
contribute to particulate matter nonattainment problems in downwind
areas. Thus, the distinction between local and national control
programs for NO_X is less important than it might appear.
---------------------------------------------------------------------------

\103\ Final Regulatory Impact Analysis: Control of Emissions of
Air Pollution from Highway Heavy-Duty Engines, September 16, 1997.
---------------------------------------------------------------------------

Finally, the statute indicates that in considering the cost-
effectiveness of Tier 2/Gasoline Sulfur EPA should consider not only
attainment, but also maintenance of the standards. Tier 2/Gasoline
Sulfur--unlike nonattainment area measures--will achieve attainment
area reductions that, among other effects, will help to maintain air
quality that meets the NAAQS. These reductions relate not only to the
ozone and PM NAAQS, but also to SO2 and NO2, and
to CO.
In summary, given the array of controls that will have to be
implemented to make progress toward attaining and maintaining the
NAAQS, we believe that the weight of the evidence from alternative
means of providing substantial NO_X + NMHC emission
reductions indicates that the Tier 2/Gasoline Sulfur program is cost-
effective. This is true from the perspective of other mobile source
control programs or from the perspective of other stationary source
technologies that might be considered.
5. Does the Value of the Benefits Outweigh the Cost of the Standards?
While relative cost-effectiveness is the principal economic policy
criterion established for these standards in the Clean Air Act (see CAA
Sec. 202(i)), further insight regarding the merits of the standards can
be provided by benefit-cost analysis. The purpose of this section is to
summarize the methods we used and results we obtained in conducting an
analysis of the economic benefits of the Tier 2 program, and to compare
these economic benefits with the estimated costs of the rule. In
summary, the results of our analysis using the EPAs preferred approach
to valuing premature mortality indicate that the economic benefits of
the Tier 2/gasoline sulfur standards will likely exceed the costs of
meeting the standards by about $20 billion (1997$).
a. What Is the Purpose of This Benefit-Cost Comparison?
Benefit-cost analysis (BCA) is a useful tool for evaluating the
economic merits of proposed changes in environmental programs and
policies. In its traditional application, BCA estimates the economic
``efficiency'' of proposed changes in public policy by organizing the
various expected consequences and representing those changes in terms
of dollars. Expressing the effects of these policy changes in dollar
terms provides a common basis for measuring and comparing these various
effects. Because improvement in economic efficiency is typically
defined to mean maximization of total wealth spread among all members
of society, traditional BCA must be supplemented with other analyses in
order to gain a full appreciation of the potential merits of new
policies and programs. These other analyses may include such things as
examinations of legal and institutional constraints and effects;
engineering analyses of technology feasibility, performance and cost;
or assessment of the air quality need.
In addition to the narrow, economic efficiency focus of most BCAs,
the technique is also limited in its ability to project future economic
consequences of alternative policies in a definitive way. Critical
limitations on the availability, validity, or reliability of data;
limitations in the scope and capabilities of environmental and economic
effect models; and controversies and uncertainties surrounding key
underlying scientific and economic literature all contribute to an
inability to estimate the economic effects of environmental policy
changes in exact and unambiguous terms. Under these circumstances, we
consider it most appropriate to view BCA as a tool to inform, but not
dictate, regulatory decisions such as the ones reflected in today's
rule.
Despite the limitations inherent in BCA of environmental programs,
we consider it useful to estimate the potential benefits of today's
action both in terms of physical changes in human health and welfare
and environmental change, and in terms of the estimated economic value
of those physical changes.
b. What Was Our Overall Approach to the Benefit-Cost Analysis?
The basic question we sought to answer in the BCA was: ``What are
the net yearly economic benefits to society of the reduction in mobile
source emissions likely to be achieved by the final Tier 2 program?''
In designing an analysis to answer this question, we selected a future
year for analysis (2030) that is representative of full-implementation
of the program (i.e., when the U.S. car and light truck population is
virtually only Tier 2 vehicles). We also adopted an analytical
structure and sequence similar to that used in the ``section 812
studies'' \104\ to estimate the total benefits and costs of the entire
Clean Air Act. Moreover, we used many of the same models, and
assumptions actually used in the section 812 studies, and other
Regulatory Impact Analyses (RIA's) 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 RIA's, we
have largely relied on methods which have already received extensive
review by the independent Science Advisory Board, by the public, and by
other federal agencies.
---------------------------------------------------------------------------

\104\ The ``section 812 studies'' refers to (1) US 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);
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).
---------------------------------------------------------------------------

c. What Are the Significant Limitations of the Benefit-Cost Analysis?
Every BCA 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

[[Page 6781]]

studies used to configure the benefit and cost models. Deficiencies in
the scientific literature often result in the inability to estimate
changes in health and environmental effects, such as potential
increases in premature mortality associated with increased exposure to
carbon monoxide. Deficiencies in the economics literature often result
in the inability to assign economic values even to those health and
environmental outcomes which can be quantified, such as changes in
visibility in residential areas. While these general uncertainties in
the underlying scientific and economics literatures are discussed in
detail in the RIA and its supporting documents and references, the key
uncertainties which have a bearing on the results of the BCA of today's
action are:
The exclusion of potentially significant benefit
categories (e.g., health and ecological benefits of incidentally
controlled hazardous air pollutants),
Errors in measurement and projection for variables such as
population growth,
Variability in the estimated relationships of health and
welfare effects to changes in pollutant concentrations.
In addition to these uncertainties and shortcomings which pervade
all analyses of criteria air pollutant control programs, a number of
limitations apply specifically to the BCA of today's action. Though we
used the best data and models currently available, we were required to
adopt a number of simplifying assumptions and to use data sets which,
while reasonably close, did not match precisely the conditions and
effects expected to result from implementation of the standards. For
example, to estimate the effects of the program at full implementation
we projected vehicle miles traveled and populations in the year 2030.
These assumptions may play a significant role in determining the
magnitude of the benefits estimate. In addition, although the emissions
data sets used for this analysis have been updated from those used in
the proposal, they may not anticipate the emissions reductions realized
by other future actions and by expected near-future control programs.
For example, it is possible that the Tier 2/gasoline sulfur standards
will not be the governing vehicle emissions standards in 2030. In the
years before 2030, the benefits from the Tier 2 program will be less
than those estimated here (significantly less in the early years),
because the Tier 2 fleet will not be fully phased in.
Finally, the implementation period for phasing-in the rule
requirements is a critical period that deserves careful evaluation. The
benefit-cost analysis for 2030 is not significantly affected by
alternative phase-in decisions, the primary impact of which will occur
in the 2005-2015 time frame. As a result, the analysis of phase-in
alternatives must rely on other types of analysis (e.g., cost-
effectiveness analysis).
The key limitations and uncertainties unique to the BCA of the
final rule, therefore, include:
Uncertainties in the estimation of future year emissions
inventories and air quality,
Uncertainties associated with the extrapolation of air
quality monitoring data to some unmonitored areas required to better
capture the effects of the standards on affected populations, and
Uncertainties associated with the effect of potential
future actions to limit emissions.
Despite these uncertainties, which are discussed in more detail or
referenced in the RIA, we believe the BCA provide a reasonable
indication of the expected economic benefits of the Tier 2 program in
2030 under one set of assumptions. This is because the analysis focuses
on estimating the economic effects of the changes in air quality
conditions expected to result from today's action, rather than focusing
on developing a precise prediction of the absolute levels of air
quality likely to prevail in 2030. An analysis focusing on the changes
in air quality can give useful insights into the likely economic
effects of emission reductions of the magnitude expected to result from
today's rule.
d. How Has the Benefit-Cost Analysis Changed From Proposal?
We significantly improved the analysis that was presented at
proposal. For the final rule, EPA updated the emissions inventory from
1990 to 1996 using updated models, refined the projections of the
effects of the rule when it is fully implemented, and updated our air
quality modeling to reflect new programs issued since 1990. In
addition, we also updated our assumptions for estimating physical
effects and monetary benefits based on recommendations from the EPA's
Science Advisory Board (SAB) during the summer of 1999. Details on
these recommendations can be found in the advisory statements published
by the SAB.\105\ All of the changes made since the analysis at proposal
serve to update and improve the analysis.
---------------------------------------------------------------------------

\105\ Full documentation of the SAB recommendations can be found
at their website (www.epa.gov/sab) under the following references:
EPA-SAB-COUNCIL-ADV-98-003, 1998; EPA-SAB-COUNCIL-ADV-99-05, 1999;
EPA-SAB-COUNCIL-ADV-99-012, 1999; EPA-SAB-COUNCIL-ADV-00-001, 1999;
and EPA-SAB-COUNCIL-ADV-00-002, 1999.
---------------------------------------------------------------------------

e. How Did We Perform the Benefit-Cost Analysis?
The analytical sequence begins with a projection of the mix of
technologies likely to be deployed to comply with the new standards,
and the costs incurred and emissions reductions achieved by these
changes in technology. The Tier 2 program has various cost and emission
related components, as described earlier in this section. These
components would begin at various times and in some cases would phase
in over time. This means that during the early years of the program
there would not be a consistent match between cost and benefits. This
is especially true for the vehicle control portions of the program,
where the full vehicle cost would be incurred at the time of vehicle
purchase, while the fuel cost along with the emission reductions and
benefits would occur throughout the lifetime of the vehicle.
To develop a benefit-cost number that is representative of a fleet
of Tier 2 vehicles, we need to have a stable set of cost and emission
reductions to use. This means using a future year where the fleet is
fully turned over and there is a consistent annual cost and annual
emission reduction. For the Tier 2 program, this stability would not
occur until well into the future. For this analysis, we selected the
year 2030. The resulting analysis represents a snapshot of benefits and
costs in a future year in which the light-duty fleet consists almost
entirely of Tier 2 vehicles. As such, it depicts the maximum emission
reductions (and resultant benefits) and among the lowest costs that
would be achieved in any one year by the program on a ``per mile''
basis. (Note, however, that net benefits would continue to grow over
time beyond those resulting from this analysis, because of growth in
population and vehicle miles traveled.) Thus, based on the long-term
costs for a fully turned over fleet, the resulting benefit-cost ratio
will be close to its maximum point (for those benefits which we have
been able to value).
To present a BCA, we designed the cost estimate to reflect
conditions in the same year as the benefit valuation. Costs are,
therefore, developed for the year 2030 fleet. For this purpose we used
the long term cost once the capital costs have been recovered and the
manufacturing learning curve

[[Page 6782]]

reductions have been realized, since this will be the case in 2030.
We also made adjustments in the costs to account for the fact that
there is a time difference between when some of the costs are expended
and when the benefits are realized. The vehicle costs are expended when
the vehicle is sold, while the fuel related costs and the benefits are
distributed over the life of the vehicle. We resolved this difference
by using costs distributed over time such that there is a constant cost
per ton of emissions reduction and such that the net present value of
these distributed costs corresponds to the net present value of the
actual costs.
The resulting adjusted costs are somewhat greater than the expected
actual annual cost of the program, reflecting the time value
adjustment. Thus, the costs presented in this section do not represent
expected actual annual costs for 2030. Rather, they represent an
approximation of the steady-state cost per ton that would likely
prevail in that time period. The benefit cost ratio for the earlier
years of the program would be expected to be lower than that based on
these costs, since the per-vehicle costs are larger in the early years
of the program while the benefits are smaller.
In order to estimate the changes in air quality conditions which
would result from these emissions reductions, we developed two
separate, year 2030 emissions inventories to be used as inputs to the
air quality models. The first, baseline inventory, reflects the best
available approximation of the county-by-county emissions for
NO_X, VOC, and SO2 expected to prevail in the year
2030 in the absence of the standards. To generate the second, control
case inventory, we first estimated the change in vehicle emissions, by
pollutant and by county, expected to be achieved by the 2030 control
scenario described above. We then took the baseline emissions inventory
and subtracted the estimated reduction for each county-pollutant
combination to generate the second, control case emissions inventory.
Taken together, the two resulting emissions inventories reflect two
alternative states of the world and the differences between them
represent our best estimate of the reductions in emissions which would
result from our control scenario.
With these two emissions inventories in hand, the next step was to
``map'' the county-by-county and pollutant-by-pollutant emission
estimates to the input grid cells of two air quality models and one
deposition model. The first model, called the Urban Airshed Model
(UAM), is designed to estimate the tropospheric ozone concentrations
resulting from a specific inventory of emissions of ozone precursor
pollutants, particularly NO_X and NMHC. The second model,
called the Climatological Regional Dispersion Model Source-Receptor
Matrix model (S-R Matrix), is designed to estimate the changes in
ambient particulate matter and visibility which would result from a
specific set of changes in emissions of primary particulate matter and
secondary particulate matter precursors, such as SO2,
NO_X, and NMHC. Also, nitrogen loadings to watersheds were
estimated using factors derived from previous modeling from the
Regional Acid Deposition Model (RADM). By running both the baseline and
control case emissions inventories through these models, we were able
to estimate the expected 2030 air quality conditions and the changes in
air quality conditions which would result from the emissions reductions
expected to be achieved by the Tier 2 program.
After developing these two sets of year 2030 air quality profiles,
we used the same health and environmental effect models used in the
section 812 studies to calculate the differences in human health and
environmental outcomes projected to occur with and without the proposed
standards. Specifically, we used the Criteria Air Pollutant Modeling
System (CAPMS) to estimate changes in human health outcomes, and the
Agricultural Simulation Model (AGSIM) to estimate changes in yields of
a selected few agricultural crops. In addition, the impacts of reduced
visibility impairment and estimates of the effect of changes in
nitrogen deposition to a selection of sensitive estuaries were
estimated using slightly modified versions of the methods used in the
section 812 studies. Several air quality-related health and
environmental benefits, however, could not be calculated for the BCA of
today's proposed standards. Changes in human health and environmental
effects due to changes in ambient concentrations of carbon monoxide
(CO), gaseous sulfur dioxide (SO2), gaseous nitrogen dioxide
(NO2), and hazardous air pollutants could not be included.
In addition, some health and environmental benefits from changes in
ozone and PM could not be included in our analysis (i.e., commercial
forestry benefits).
To characterize the total economic value of the reductions in
adverse effects achieved across the lower 48 states,\106\ we used the
same set of economic valuation coefficients and models used in the
section 812 studies, as approved by the SAB. The net monetary benefits
of the Tier 2 program were then calculated by subtracting the estimated
costs of compliance from the estimated monetary benefits of the
reductions in adverse health and environmental effects.
---------------------------------------------------------------------------

\106\ Though California is included based on the expectation
that reductions in surrounding states will achieve some benefits in
California, this analysis does not assume additional reductions in
California emissions beyond those already achieved by prevailing
standards.
---------------------------------------------------------------------------

The last step of the analysis is to characterize the uncertainty
surrounding our estimate of benefits. Again, we follow the
recommendations of the SAB for the presentation of uncertainty. They
recommend that a primary estimate should be presented along with a
description of the uncertainty associated with each endpoint. At
proposal, our characterization of uncertainty was based on an estimated
range of benefits which might occur if important but uncertain
underlying factors were allowed to vary. This approach, however, is
criticized by the SAB because while the low- or high-end estimates
provided for individual endpoints was ``plausible,'' the probability of
all of the assumptions in these estimates occurring simultaneously was
likely to be small.
Therefore, for the final Tier 2/gasoline sulfur rule, the benefit
analysis adopts an approach similar to the section 812 study. Our
analysis first presents our estimate for a primary set of benefit
endpoints followed by a presentation of ``alternative calculations'' of
key health and welfare endpoints to characterize the uncertainty in
this primary set. However, the adoption of a value for the projected
reduction in the risk of premature mortality is the subject of
continuing discussion within the economic and public policy analysis
community within and outside the Administration. In response to the
sensitivity on this issue, we provide estimates reflecting two
alternative approaches for mortality benefits: the EPAs preferred
approach using the value of a statistical life, and an alternative
approach using the value of a statistical life years. These are
discussed further in section f. of this presentation. The presentation
of the alternative calculations for certain endpoints seeks to
demonstrate how much the overall benefit estimate might vary based on
the value EPA has given to a parameter (which has some uncertainty
associated with it) underlying the estimates for human health and
environmental effect incidence and the economic valuation

[[Page 6783]]

of those effects. These alternative calculations represent conditions
that are possible to occur, however, EPA has selected the best
supported values based on current scientific literature for use in the
primary estimate. The alternate calculations include:
Presentation of an estimated confidence interval around
the Primary estimate of benefits to characterize The standard error in
the C-R and valuation studies used in developing benefit estimates for
each endpoint;
Valuing PM-related premature mortality based on a
different C-R study;
Value of avoided premature mortality incidences based on
statistical life years;
Consideration of reversals in chronic bronchitis treated
as lowest severity cases;
Value of visibility changes in all Class I areas;
Value of visibility changes in Eastern U.S. residential
areas;
Value of visibility changes in Western U.S. residential
areas;
Value of reduced household soiling damage; and
Avoided costs of reducing nitrogen loadings in east coast
estuaries.
For instance, the study by Dockery, et al. estimates of the
relationship between PM exposure and premature mortality is a plausible
alternative to the Pope, et al. study used for the Primary estimate of
benefits. The SAB has noted that ``the study had better monitoring with
less measurement error than did most other studies'' (EPA-SAB-COUNCIL-
ADV-99-012, 1999). The Dockery study had a more limited geographic
scope (and a smaller study population) than the Pope, et al. study and
the Pope study appears more likely to mitigate a key source of
potential confounding. The Dockery study also covered a broader age
category (25 and older compared to 30 and older in the Pope study) and
followed the cohort for a longer period (15 years compared to 8 years
in the Pope study). For these reasons, the Dockery study is considered
to be a plausible alternative estimate of the avoided premature
mortality incidences associated with the final Tier 2/gasoline sulfur
rule. The alternative estimate for mortality can be substituted for the
valuation component in our primary estimate of mortality benefits to
observe how the net benefits of the program may be influenced by this
assumption. Unfortunately, it is not possible to combine all of the
assumptions used in the alternate calculations to arrive at different
total benefit estimates because, it is highly unlikely that the
selected combination of alternative values would all occur
simultaneously. Therefore, it is better to consider each alternative
calculation individually to assess the uncertainty in the estimate.
In addition to the estimate for the primary set of endpoints and
alternative calculations of benefits, our RIA also presents an appendix
with supplemental benefit estimates and sensitivity analyses of other
key parameters in the benefit analysis that have greater uncertainty
surrounding them due to limitations in the scientific literature.
Supplemental estimates are presented for premature mortality associated
with short-term exposures to PM and ozone, asthma attacks, occurrences
of moderate or worse asthma symptoms, and an estimate of the avoided
incidences of premature mortality in infants.
Even with our efforts to fully disclose the uncertainty in our
estimate, this uncertainty presentation method does not provide a
definitive or complete picture of the true range of monetized benefits
estimates. This approach, as implemented in this BCA, does not reflect
important uncertainties in earlier steps of the analysis, including
estimation of compliance technologies and strategies, emissions
reductions and costs associated with those technologies and strategies,
and air quality and deposition changes achieved by those emissions
reductions. Nor does this approach provide a full accounting of all
potential benefits associated with the Tier 2/gasoline sulfur
standards, due to data or methodological limitations. Therefore, the
uncertainty range is only representative of those benefits that we were
able to quantify and monetize.
f. What Were the Results of the Benefit-Cost Analysis?
The BCA for the Tier 2 program reflects a single year ``snapshot''
of the yearly benefits and costs expected to be realized once the
standards have been fully implemented and non-compliant vehicles have
all been retired. Near-term costs will be higher than long-run costs as
vehicle manufacturers and oil companies invest in new capital equipment
and develop and implement new technologies. In addition, near-term
benefits will be lower than long-run benefits because it will take a
number of years for Tier 2-compliant vehicles to fully displace older,
more polluting vehicles. However, as described earlier, we have
adjusted the cost estimates upward to compensate for some of this
discrepancy in the timing of benefits and costs and to ensure that the
long-term benefits and costs are calculated on a consistent basis. The
resulting adjusted long-term cost value is given in Table IV.D.-5a.
Because of the adjustment process, the cost estimates should not be
interpreted as reflecting the actual costs expected to be incurred in
the year 2030. Actual program costs can be found in Section IV.D.3.

Table IV.D.-5a.--Adjusted Cost of the Tier 2/Gasoline Sulfur Rule for
Comparison to Benefits
------------------------------------------------------------------------
Adjusted
cost
Cost basis (billions
of dollars)
------------------------------------------------------------------------
Long term ^a................................................ 5.3
------------------------------------------------------------------------
Notes:
^a Note that this estimate of cost is only for purposes of comparing with
our 2030 benefits estimate. See Figure IV.D.-1 for our portrayal of
total annualized cost of the rule.

With respect to the benefits, several different measures of
benefits can be useful to compare and contrast to the estimated
compliance costs. These benefit measures include (a) the tons of
emissions reductions achieved, (b) the reductions in incidences of
adverse health and environmental effects, and (c) the estimated
economic value of those reduced adverse effects. Calculating the cost
per ton of pollutant reduced is particularly useful for comparing the
cost-effectiveness of the new standards or programs against existing
programs or alternative new programs achieving reductions in the same
pollutant or combination of pollutants. The cost-effectiveness analysis
presented earlier in this preamble provides such calculations on a per-
vehicle basis. Considering the absolute numbers of avoided adverse
health and environmental effects can also provide valuable insights
into the nature of the health and environmental problem being addressed
by the rule as well as the magnitude of the total public health and
environmental gains potentially achieved by the rule. Finally, when
considered along with other important economic dimensions --including
environmental justice, small business financial effects, and other
outcomes related to the distribution of benefits and costs among
particular groups-- the direct comparison of quantified economic
benefits and economic costs can provide useful insights into the
potential magnitude of the estimated net economic effect of the rule,
keeping in mind the limited set of effects we are able to monetize.
Table IV.D.-6 presents the EPAs preferred approach to estimate the
benefits of both the estimated reductions in adverse effect incidences
and the estimated economic value of

[[Page 6784]]

those incidence reductions. Specifically, the table lists the avoided
incidences of individual health and environmental effects, the
pollutant associated with each of these endpoints, and the estimated
economic value of those avoided incidences. For several effects,
particularly environmental effects, direct calculation of economic
value in response to air quality conditions is performed, eliminating
the intermediate step of calculating incidences. As the table
indicates, we estimate that the Tier 2 program will produce 2300 fewer
cases of chronic bronchitis, and we also see significant improvements
in minor restricted activity days (with an estimated 6,255,500 fewer
cases). Our estimate also incorporates significant reductions in
impacts on children's health, showing reductions of 7,900 cases of
acute bronchitis, 87,200 fewer cases of lower respiratory symptoms, and
86,600 fewer cases of upper respiratory symptoms in asthmatic children.
Total monetized benefits, however, are driven primarily by the
estimated 4300 fewer premature fatalities. The adoption of a value for
the projected reduction in the risk of premature mortality is the
subject of continuing discussion within the economic and public policy
analysis community within and outside the Administration. In response
to the sensitivity on this issue, we provide estimates reflecting two
alternative approaches. The first approach--supported by some in the
above community and preferred by EPA--uses a Value of a Statistical
Life (VSL) approach developed for the Clean Air Act Section 812
benefit-cost studies. This VSL estimate of $5.9 million (1997$) was
derived from a set of 26 studies identified by EPA using criteria
established in Viscusi (1992), as those most appropriate for
environmental policy analysis applications.
An alternative, age-adjusted approach is preferred by some others
in the above community both within and outside the Administration. This
approach was also developed for the Section 812 studies and addresses
concerns with applying the VSL estimate--reflecting a valuation derived
mostly from labor market studies involving healthy working-age manual
laborers--to PM-related mortality risks that are primarily associated
with older populations and those with impaired health status. This
alternative approach leads to an estimate of the value of a statistical
life year (VSLY), which is derived directly from the VSL estimate. It
differs only in incorporating an explicit assumption about the number
of life years saved and an implicit assumption that the valuation of
each life year is not affected by age.\107\ The mean VSLY is $360,000
(1997$); combining this number with a mean life expectancy of 14 years
yields an age-adjusted VSL of $3.6 million (1997$).
---------------------------------------------------------------------------

\107\ Specifically, the VSLY estimate is calculated by
amortizing the $5.9 million mean VSL estimate over the 35 years of
life expectancy associated with subjects in the labor market
studies. The resulting estimate, using a 5 percent discount rate, is
$360,000 per life-year saved in 1997 dollars. This annual average
value of a life-year is then multiplied times the number of years of
remaining life expectancy for the affected population (in the case
of PM-related premature mortality, the average number of $ life-
years saved is 14.
---------------------------------------------------------------------------

Both approaches are imperfect, and raise difficult methodological
issues which are discussed in depth in the recently published Section
812 Prospective Study, the draft EPA Economic Guidelines, and the peer-
review commentaries prepared in support of each of these documents. For
example, both methodologies embed assumptions (explicit or implicit)
about which there is little or no definitive scientific guidance. In
particular, both methods adopt the assumption that the risk versus
dollars trade-offs revealed by available labor market studies are
applicable to the risk versus dollar trade-offs in an air pollution
context.
EPA currently prefers the VSL approach because, essentially, the
method reflects the direct, application of what EPA considers to be the
most reliable estimates for valuation of premature mortality available
in the current economic literature. While there are several differences
between the labor market studies EPA uses to derive a VSL estimate and
the particulate matter air pollution context addressed here, those
differences in the affected populations and the nature of the risks
imply both upward and downward adjustments. For example, adjusting for
age differences may imply the need to adjust the $5.9 million VSL
downward as would adjusting for health differences, but the involuntary
nature of air pollution-related risks and the lower level of risk-
aversion of the manual laborers in the labor market studies may imply
the need for upward adjustments. In the absence of a comprehensive and
balanced set of adjustment factors, EPA believes it is reasonable to
continue to use the $5.9 million value while acknowledging the
significant limitations and uncertainties in the available literature.
Furthermore, EPA prefers not to draw distinctions in the monetary value
assigned to the lives saved even if they differ in age, health status,
socioeconomic status, gender or other characteristic of the adult
population.
Those who favor the alternative, age-adjusted approach (i.e. the
VSLY approach) emphasize that the value of a statistical life is not a
single number relevant for all situations. Indeed, the VSL estimate of
$5.9 million (1997 dollars) is itself the central tendency of a number
of estimates of the VSL for some rather narrowly defined populations.
When there are significant differences between the population affected
by a particular health risk and the populations used in the labor
market studies--as is the case here--they prefer to adjust the VSL
estimate to reflect those differences. While acknowledging that the
VSLY approach provides an admittedly crude adjustment (for age though
not for other possible differences between the populations), they point
out that it has the advantage of yielding an estimate that is not
presumptively biased. Proponents of adjusting for age differences using
the VSLY approach fully concur that enormous uncertainty remains on
both sides of this estimate--upwards as well as downwards--and that the
populations differ in ways other than age (and therefore life
expectancy). But rather than waiting for all relevant questions to be
answered, they prefer a process of refining estimates by incorporating
new information and evidence as it becomes available.
In addition to the presentation of mortality valuation, this table
also indicates with a ``B'' those additional health and environmental
benefits which could not be expressed in quantitative incidence and/or
economic value terms. A full listing of the benefit categories that
could not be quantified or monetized in our estimate are provided in
Table IV.D.-8. For instance, visibility is expected to improve in all
areas of the country, with the largest improvements occurring in
heavily populated residential areas (e.g., 21% of the metropolitan
areas show an improvement of 0.5 deciviews or more). However, due to
limitations on sources to value these effects, we include a ``B'' in
the primary estimate table for this category. Likewise, the Tier 2/
gasoline sulfur rule will also provide progress for some estuaries to
meet their goals for reducing nitrogen deposition (e.g., nitrogen
loadings for the Albemarle/Pamlico Sound are reduced by 27% of their
reductions goal), however, this endpoint is also displayed with a ``B''
in the table. A full appreciation of the overall economic consequences
of the Tier 2/gasoline sulfur standards requires consideration of all
benefits and costs expected to result from the new standards, not just
those benefits and

[[Page 6785]]

costs which could be expressed here in dollar terms.
In summary, the VSL approach--the approach EPA prefers--yields a
monetized benefit estimate of $25.2 billion in 2030. The alternative,
age-adjusted VSLY approach (presented in Table IV.D.7) yields monetary
benefits of approximately $13.8 billion in 2030.

Table IV.D.-6.--EPA Preferred Estimate of the Annual Quantified and Monetized Benefits Associated With Improved
Air Quality Resulting From the Tier 2/Gasoline Sulfur Rule in 2030
----------------------------------------------------------------------------------------------------------------
Avoided incidence^c Monetary benefits^d
Endpoint Pollutant (cases/year) (millions 1997$)
----------------------------------------------------------------------------------------------------------------
Premature mortality ^a, ^b (adults, PM ^b................. 4,300.................... $23,380
30 and over).
Chronic asthma (adult males, 27 Ozone................ 400...................... 10
and over).
Chronic bronchitis................ PM................... 2,300.................... 730
Hospital Admissions from Ozone and PM......... 2,200.................... 20
Respiratory Causes.
Hospital Admissions from Ozone and PM......... 800...................... 10
Cardiovascular Causes.
Emergency Room Visits for Asthma.. Ozone and PM......... 1,200.................... 1
Acute bronchitis (children, 8-12). PM................... 7,900.................... 1
Lower respiratory symptoms (LRS) PM................... 87,100................... 5
(children, 7-14).
Upper respiratory symptoms (URS) PM................... 86,500................... 5
(asthmatic children, 9-11).
Shortness of breath (African PM................... 17,400................... 1
American asthmatics, 7-12).
Work loss days (WLD) (adults, 18- PM................... 682,900.................. 70
65).
Minor restricted activity days Ozone and PM......... 5,855,000................ 270
(MRAD)/Acute respiratory symptoms.
Other health effects ^c............ Ozone, PM, CO, HAPS.. U1+U2+U3+U4.............. B1+B2+B3+B4
Decreased worker productivity..... Ozone................ ......................... 140
Recreational visibility (86 Class PM................... ......................... 370
I Areas).
Residential visibility............ PM................... ......................... B5
Household soiling damage.......... PM................... ......................... B6
Materials damage.................. PM................... ......................... B7
Nitrogen Deposition to Estuaries.. Nitrogen............. ......................... B8
Agricultural crop damage (6 crops) Ozone................ ......................... 220
Commercial forest damage.......... Ozone................ ......................... B9
Other welfare effects ^e........... Ozone, PM, CO, HAPS.. ......................... B10+B11+B12+B13
Monetized Total ^f, ^g........ ..................... ......................... $25,220+B
----------------------------------------------------------------------------------------------------------------
Notes:
^a Premature mortality associated with ozone is not separately included in this analysis. It is assumed 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. Also note that the valuation assumes the 5 year distributed lag
structure described earlier.
^b PM reductions are due to reductions in NO_X and SO2 resulting from the Tier 2/Gasoline Sulfur rule.
^c Incidences are rounded to the nearest 100.
^d Dollar values are rounded to the nearest 10 million.
^e The Ui are the incidences and the Bi are the values for the unquantified category i. A detailed listing of
unquantified PM, ozone, CO, and HAPS related health and welfare effects is provided in Table IV.D.-8.
^f B is equal to the sum of all unmonetized categories, i.e. B1+B2+ * * * +B13.
^g These estimates are based on the EPA preferred approach for valuing reductions in premature mortality, the VSL
approach. This approach and an alternative, age-adjusted approach--the VSLY approach--are discussed more fully
in section f above.

Table IV.D.-7.--Tier 2/Gasoline Sulfur Rule: 2030 Monetized Benefits
Estimates for Alternative Premature Mortality Valuation Approaches
[Millions of 1997 dollars]
------------------------------------------------------------------------
Premature mortality valuation PM mortality
approach benefits Total benefits
------------------------------------------------------------------------
Value of statistical life (VSL) $23,380 $25,220 + B
($5.9 million per life saved) a.
Value of statistical life-years 11,900 13,790 + B
(VSLY) ($360,000 per life-year
saved, which implies $3.6
million per life saved, based on
the mean of 14 life years saved)
^a,b.
------------------------------------------------------------------------
Notes:
a Premature mortality estimates are determined assuming a 5 year
distributed lag, which applies 25 percent of the incidence in year 1
and 2, and then 16.7 percent of the incidence in years 3, 4, and 5.
b The VSLY estimate is calculated by amortizing the $5.9 million mean
VSL estimate over the 35 years of life expectancy associated with
subjects in the labor market studies used to obtain the VSL estimate.
The resulting estimate, using a 5 percent discount rate, is $360,000
per life-year saved in 1997 dollars. This approach is discussed more
fully in section f above.

[[Page 6786]]

Table IV.D.-8.--Additional, Non-monetized Benefits of the Tier 2/
Gasoline Sulfur Standards
------------------------------------------------------------------------
Pollutant Unquantified effects
------------------------------------------------------------------------
Ozone Health...................... Premature mortality.^a
Increased airway responsiveness to
stimuli.
Inflammation in the lung
Chronic respiratory damage
Premature aging of the lungs
Acute inflammation and respiratory
cell damage
Increased susceptibility to
respiratory infection
Non-asthma respiratory emergency
room visits
Reductions in screening of UV-b
radiation
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......................... Infant mortality
Low birth weight
Changes in pulmonary function
Chronic respiratory diseases other
than chronic bronchitis
Morphological changes
Altered host defense mechanisms
Nitrogen and Sulfate Deposition Impacts of acidic sulfate and
Welfare. 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
CO Health......................... Premature mortality ^a
Behavioral effects
Hospital admissions--respiratory,
cardiovascular, and other
Other cardiovascular effects
Developmental effects
Decreased time to onset of angina
Non-asthma respiratory ER visits
HAPS Health....................... 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)
HAPS Welfare...................... Direct toxic effects to animals
Bioaccumlation in the food chain
------------------------------------------------------------------------
^a Premature mortality associated with ozone and carbon monoxide is not
separately included in this analysis. It is assumed 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.

In addition, in analyzing the present rule, we recognized that the
benefits estimates were subject to a number of uncertainties with other
parameters. In Table IV D-9, we present alternative calculations
representing the effect of different assumptions on individual elements
of the benefits analysis and on the total benefits estimate. For
example, this table can be used to answer questions like ``What would
total benefits be if we were to use the Dockery, et al. C-R function to
estimate avoided premature mortality?'' This table also displays some
assumptions that can be made to value some of the categories that are
indicated with a ``B'' in the primary estimate. Overall, this table
provides alternative calculations both for valuation issues (e.g., the
correct value for a statistical life saved) and for physical effects
issues (e.g., how reversals in chronic illnesses are treated). We show
how the alternative assumption being valued would change the resulting
total primary estimate, and the percentage change from the primary
estimate associated with the alternative calculation. This table is not
meant to be comprehensive. Rather, it reflects some of the key issues
identified by EPA or commenters as likely to have a significant impact
on total benefits.

[[Page 6787]]

Table IV.D.-9.--Alternative Benefits Calculations for the Tier 2
Gasoline Sulfur Rule in 2030
------------------------------------------------------------------------
Impact on primary benefit estimate
Alternative calculation (million 1997$)
------------------------------------------------------------------------
5th percentile of -$20,300 (-81%)
``measurement'' uncertainty
distribution.
95th percentile of +33,900 (+134%)
``measurement'' uncertainty
distribution.
PM-related premature mortality +30,200 (+120%)
based on Dockery et al..
Value of avoided premature -11,500 (-46%)
mortality incidences based on
statistical life years..
Reversals in chronic bronchitis +280 (+1%)
treated as lowest severity
cases.
Value of visibility changes in +180 (+1%)
all class I areas.
Value of visibility changes in +420 (+2%)
eastern U.S. residential areas.
Value of visibility changes in +130 (+1%)
western U.S. residential areas.
Household soiling damage....... +110 (+1%)
Avoided costs of reducing +160 (+1%)
nitrogen loadings in east
coast estuaries.
------------------------------------------------------------------------

The estimated adjusted cost of implementing the final Tier 2
program is $5.3 billion (1997$), while the estimate of monetized
benefits using EPA's preferred approach for monetizing reductions in
PM-related premature mortality--the VSL approach--are $25.2 billion
(1997$). Monetized net benefits using EPA's preferred method for
valuing avoided incidences of premature mortality are approximately
$19.9 billion (1997$). Using the alternative, age-adjusted approach--
the VSLY approach--total monetized benefits are projected to be around
$13.8 billion (1997$). Monetized net benefits using this approach are
approximately $8.5 billion (1997$). Therefore, implementation of the
Tier 2 program will provide society with a net gain in social welfare.
Tables VI.D.-10a and IV.D.-10b summarize the costs, benefits, and net
benefits for the two alternative valuation approaches.

Table IV.D.-10a.--2030 Annual Monetized Costs, Benefits, and Net
Benefits for the Final Tier 2/Gasoline Sulfur Rule: EPA Preferred
Estimate Using the Value of Statistical Lives Saved Approach to Value
Reductions In Premature Mortality ^a
------------------------------------------------------------------------
Billion 1997 (dollars)
------------------------------------------------------------------------
Adjusted compliance costs................ $5.3
Monetized PM-related benefits ^b.......... 24.7+BPM
Monetized Ozone-related benefits^b........ 0.5+BOzone
Monetized net benefits ^c,d............... 19.9+B
------------------------------------------------------------------------
Notes:
^a For this section , all costs and benefits are rounded to the nearest
100 million. Thus, figures presented in this chapter may not exactly
equal benefit and cost numbers presented in earlier sections of the
chapter.
^b Not all possible benefits or disbenefits are quantified and monetized
in this analysis. Potential benefit categories that have not been
quantified and monetized are listed in Table IV.D.-8. Unmonetized PM-
and ozone-related benefits are indicated by BPM. And BOzone,
respectively.
^c B is equal to the sum of all unmonetized benefits, including those
associated with PM, ozone, CO, and HAPS.
^d These estimates are based on the EPA preferred approach for valuing
reductions in premature morality, the VSL approach. This approach and
an alternative, age-adjusted approach--the VSLY approach--are
discussed more fully in section f above.

Table IV.D.-10b.--2030 Annual Monetized Costs, Benefits, and Net
Benefits for the Final Tier 2/Gasoline Sulfur Rule: Alternative
Estimates Using the Value of Statistical Life Years Saved Approach to
Value Reductions in Premature Mortality ^a
------------------------------------------------------------------------
Billion 1997 (dollars)
------------------------------------------------------------------------
Adjusted compliance costs................ $5.3
Monetized PM-related benefits ^b.......... $13.3+B^PM
Monetized Ozone-related benefits ^b....... $0.5+B^Ozone
Monetized net benefits ^c, ^d.............. $8.5+B
------------------------------------------------------------------------
Notes:
^a For this section, all costs and benefits are rounded to the nearest
100 million. Thus, figures presented in this chapter may not exactly
equal benefit and cost numbers presented in earlier sections of the
chapter.
^b Not all possible benefits or disbenefits are quantified and monetized
in this analysis. Potential benefit categories that have not been
quantified and monetized are listed in Table IV.D.-8. Unmonetized PM-
and ozone-related benefits are indicated by BPM. And BOzone,
respectively.
^c B is equal to the sum of all unmonetized benefits, including those
associated with PM, ozone, CO, and HAPS.
^d The VSLY estimate is calculated by amortizing the $5.9 million mean
VSL estimate over the 35 years of life expectancy associated with
subjects in the labor market studies used to obtain the VSL estimate.
The resulting estimate, using a 5 percent discount rate, is $360,000
per life-year saved in 1997 dollars. This approach is discussed more
fully in section f above.

V. Other Vehicle-Related Provisions

The section describes several additional provisions of today's
final rule that were not previously discussed in this preamble.\108\
---------------------------------------------------------------------------

\108\ Generally the provisions of this section V that apply to
HLDTs also apply to MDPVs. See section IV.B.4.g for a thorough
discussion of the main program elements and how they impact MDPVs.
---------------------------------------------------------------------------

A. Final Tier 2 CO, HCHO and PM Standards

Tables IV.B.-4 and -5 in Section IV.B.4.a. above presented the Tier
2 standards for carbon monoxide (CO), formaldehyde (HCHO), and
particulate matter (PM). The following paragraphs discuss our selection
of these specific standards.
1. Carbon Monoxide (CO) Standards
Beyond aligning carbon monoxide (CO) standards for all LDVs and
LDTs, and harmonizing with California vehicle technology, reduction in
CO emissions is not a primary goal of the Tier 2 program. However, we
note that more than three-fourths of CO emissions in 1997 came from
mobile sources and that there are currently 20 officially designated CO
nonattainment areas in the U.S. These areas include 47 counties with a
combined population of 34 million. In addition, there are 23 officially
designated maintenance areas also with a combined population of 34
million. Further, CO is a deadly gas that leads to accidental poisoning
fatalities and injuries. Also, CO may play a role in ozone formation by
increasing the reactivities of VOCs in the atmosphere.
Although there remain many areas of nonattainment and maintenance
for the

[[Page 6788]]

CO NAAQS, and those areas include large populations, the broad trends
indicate that ambient levels are being reduced and the amount of
further reductions needed to meet the CO NAAQS will not be as
substantial as for the ozone NAAQS. The reductions in this program will
help ensure that emissions and ambient levels of CO continue to
decline, which will contribute to the attainment and maintenance of the
CO NAAQS in current nonattainment areas. These standards will also
ensure that CO levels do not increase in the future, which could
exacerbate any CO attainment and maintenance concerns. Our analysis
estimating of the tons of CO reduction due to the Tier 2/Gasoline
Sulfur program is found in Chapter III of the RIA.
Thus the CO standards we are finalizing for all Tier 2 LDVs and
LDTs are essentially the same as those from the NLEV program for LDV/
LLDTs. These standards will harmonize with CalLEV II CO standards
except at California's SULEV level (EPA Bin 2). This lone divergence
will not pose additional burden to manufacturers because the federal
Tier 2 CO standards for these vehicles will be less stringent than
California's. Bins applicable during the interim programs will include
CO values from the NLEV program for LDV/LLDTs and from the Cal LEV I
program for HLDTs.\109\ In our NPRM, we proposed tighter CO standards
than California for certain higher bins. Based upon comment, we are
aligning our CO standards with those of California to help ensure that
carry over between the two programs can occur.\110\ This alignment is
consistent with our goal of bringing all LDVs and all categories of
LDTs under common standards that allow for technology to be harmonized
to the extent possible with California. Despite these minor changes, we
still expect the standards in today's rule to lead to CO reductions.
---------------------------------------------------------------------------

\109\ We recognize that the standards we are finalizing for
interim LDT4s are more stringent than for equivalent vehicles
(MDV3s) under Cal LEV I. Still our interim HLDT standards harmonize
with Cal LEV I standards applicable to MDV2s.
\110\ Ibid.
---------------------------------------------------------------------------

2. Formaldehyde (HCHO) Standards
Similar to our approach to CO standards, we are aligning all Tier 2
LDVs and LDTs under the formaldehyde standards from the NLEV program or
CalLEV II program. HLDTs, which are not subject to the NLEV program,
will become subject to federal formaldehyde standards for the first
time under the provisions of this rulemaking.
Formaldehyde is a hazardous air pollutant and EPA is required to
regulate motor vehicle formaldehyde under section 202(l) of the Act.
The standards finalized today are primarily of concern for methanol and
methane (compressed natural gas or CNG)-fueled vehicles, because
formaldehyde is chemically similar to methanol and methane and is
likely to be produced when methanol or methane are not completely
burned in the engine. HLDTs are not included under the NLEV program and
will therefore not face formaldehyde standards as LDVs and LLDTs will
in 2001 (1999 in the northeast states). We believe it is appropriate to
bring HLDTs under HCHO standards in this rulemaking. Applying
formaldehyde standards to HLDTs will be consistent with our goals of
aligning standards for all LDVs and LDTs regardless of fuel type and
harmonizing technologically with California standards wherever possible
and reasonable and the burden will be minimal. Consequently, we are
including formaldehyde standards for HLDTs under the Tier 2 program as
well as under the interim programs.
3. Use of NMHC Data To Show Compliance with NMOG Standards; Alternate
Compliance With Formaldehyde Standards
In response to comments, we are finalizing a provision to allow
manufacturers to demonstrate compliance with the interim and Tier 2
NMOG standards using NMHC data (non-methane hydrocarbons) for gasoline
and diesel vehicles. For these vehicles, NMOG and NMHC emissions are
very similar and testing for NMHC is considerably simpler and cheaper
than measuring NMOG. Data available to us show that NMHC emissions at
levels expected from interim and Tier 2 LDVs and LDTs can be adjusted
to represent NMOG emissions by a small multiplicative factor. We are
finalizing to accept NMHC test results to demonstrate compliance with
the NMOG standards, but are requiring that the NMHC results be
multiplied by 1.04. We will permit the use of other adjustment factors
based upon comparative testing.
A drawback to NMHC testing is that NMHC testing does not yield
formaldehyde results as NMOG testing does. We noted in the NPRM that
HCHO is actually a component of NMOG and that we expect that all
vehicles able to meet the proposed Tier 2 or interim standards
(including methanol and CNG-fueled vehicles) will readily comply with
the HCHO standards. In fact, based upon a review of certification data,
we believe that gasoline and diesel vehicles will be far below the HCHO
standards, perhaps by as much as 90%. (See the Response to Comments
document for details)
To reduce testing costs while harmonizing with the CalLEV II
standards we are finalizing a provision that will permit manufacturers
of gasoline and diesel vehicles to demonstrate compliance with the
formaldehyde standards based on engineering judgement. This provision
will apply only to diesel and gasoline fueled vehicles and will require
manufacturers to make a demonstration in their certification
application that vehicles having similar engine and vehicle size and
engine and aftertreatment technologies have been shown to exhibit
compliance with the applicable formaldehyde standard for their full
useful life. This demonstration will be similar to that currently
required for gasoline vehicles to demonstrate compliance with the
particulate matter standard (see 40 CFR 86.1829(b)(1)), and should be
readily available from California vehicles where NMOG testing is
required and formaldehyde data is routinely generated.
4. Particulate Matter (PM) Standards
We proposed to adopt tighter PM standards. For Tier 2 vehicles, we
proposed PM bin values such that PM would consistently be 0.01 g/mi or
less. To provide manufacturers with flexibility, we proposed a 0.02 g/
mi PM standard for vehicles that certify to the highest Tier 2 bins. As
we have indicated elsewhere in this preamble, we anticipate that low
sulfur diesel fuel will be available by 2007 to enable diesel vehicles
to utilize advanced diesel technologies and meet these PM standards.
For the interim standards we proposed a PM standard of 0.06 g/mi
for the highest bins. We received considerable comment from
manufacturers and others about the PM standards we proposed. In the
final rule, we are raising the PM standard to 0.08 g/mi for bin 10. For
HLDTs, manufacturers would likely have had to use advanced diesel
technologies to attain our proposed interim standards and these
technologies require low sulfur diesel fuel. Since we do not expect
that fuel to be widely available until the 2006-2007 timeframe, we are
raising the PM standard so that diesels are not barred from the interim
program by a fuel situation beyond their manufacturers' control.
PM standards are primarily a concern for diesel-cycle vehicles, but
they also apply to gasoline and other otto-cycle

[[Page 6789]]

vehicles. We will continue to permit otto-cycle vehicles to certify to
PM standards based on representative test data from similar technology
vehicles.

B. Useful Life

The ``useful life'' of a vehicle is the period of time, in terms of
years and miles, during which a manufacturer is formally responsible
for the vehicle's emissions performance. For LDVs and LDTs, there have
historically been both ``full useful life'' values, approximating the
average life of the vehicle on the road, and ``intermediate useful
life'' values, representing about half of the vehicle's life. We
proposed and are finalizing several changes to the current useful life
provisions for LDVs and LDTs.
1. Mandatory 120,000 Mile Useful Life
We are finalizing our proposal to equalize full useful life values
for all Tier 2 LDVs and LDTs at 120,000 miles. Congress, in directing
EPA to perform the Tier 2 study, also directed EPA to consider changing
the useful lives of LDVs and LDTs. Manufacturers have made numerous
advances in quality, materials and engineering that have led to longer
actual vehicle lives and data show that each year of a vehicle's life,
people are driving more miles. Current data indicate that passenger
cars are driven approximately 120,000 miles in their first ten years of
life. Trucks are driven further. Current regulatory useful lives are 10
years/100,000 miles for LDV/LLDTs and 11 years/120,000 miles for HLDTs.
We project, based on our Tier 2 model, that approximately 13 percent of
light-duty NO_X and 11 percent of light-duty VOCs is produced
between 100,000 and 120,000 miles. Given the trend toward longer actual
vehicle lives and increases in annual mileage, we believe that it is
reasonable to extend the regulatory useful life requirements
California, in its LEV II program, has adopted full useful life
standards for all LDVs and LDTs of 10 years or 120,000 miles, whichever
occurs first. The time period for federal LDV/LLDTs will be 10 years,
but will remain at 11 years for HLDTs consistent with the Clean Air
Act. Intermediate useful life values, where applicable, will remain at
5 years or 50,000 miles, whichever occurs first. Where manufacturers
elect to certify Tier 2 vehicles for 150,000 miles to gain additional
NO_X credits, as discussed below, the useful life of those
vehicles will be 15 years and 150,000 miles. We are not harmonizing
with California on the mandatory useful life for evaporative emissions
of 15 years and 150,000 miles, but rather this useful life will be
mandatory for evaporative emissions only when a manufacturer elects
optional 150,000 mile exhaust emission certification.
We proposed to extend the useful life of interim LDV/LLDTs to 10
years/ 120,000 miles beginning in 2004. Based upon extensive comment,
we are not finalizing that provision and the useful lives of interim
LDV/LLDTs will remain unchanged to help facilitate their carryover from
the NLEV program into the interim program. Commenters provided
persuasive argument that the proposed provision, along with others,
would impose a large workload burden on manufacturers because they
would be unable to carry over certification data from 2003 and would
have to recertify virtually all of their LDV/LLDTs in 2004.
Manufacturers stressed that this would be an especially unproductive
use of their resources because these vehicles would all have to be
recertified again as they were phased into the Tier 2 standards between
2005 and 2007. This change in the final rule will have only minimal
impact on the benefits of our program.
2. 150,000 Mile Useful Life Certification Option
We are adopting as proposed a provision to provide additional
NO_X credit in the fleet average calculation for vehicles
certified to a useful life of 150,000 miles. A manufacturer certifying
a test group to a 150,000 mile useful life will incorporate those
vehicles into its corporate NO_X average as if they were
certified to a full useful life standard 0.85 times the applicable
120,000 mile NO_X standard. To use this option, the
manufacturer will have to agree to (1) certify the engine family to the
applicable 120,000 mile exhaust and evaporative standards at 150,000
miles for all pollutants; and (2) increase the mileage on the single
extra-high mileage in-use test vehicle from a minimum of 90,000 miles
to a minimum of 105,000 miles.
Today's vehicles are lasting longer and being driven farther than
those built in past years and we believe it is reasonable to encourage
the development of more durable emission control systems. Consequently
we believe it is appropriate to provide incentives to manufacturers to
certify their vehicles to extended useful lives beyond 120,000 miles.
This is why we proposed and are today finalizing additional
NO_X credits for Tier 2 vehicles certified to a useful life
of 150,000 miles.
In the final rule we are adding an option that, for a test group
certified to a 150,000 mile useful life, the manufacturer may choose
between the additional credits or a waiver of intermediate life
standards. Commenters suggested that some vehicles would be
discriminated against by our intermediate life standards, because they
might have flat deterioration curves, and could meet our full life
standards, but not the lower intermediate life standards. We are
reluctant to give up our intermediate life standards, because we
believe they provide an additional measure of certainty that vehicles
will meet standards. Nonetheless, we believe that certification to a
longer useful life is an important goal and that manufacturers who do
so will likely use technologies that have very flat deterioration
curves. This option provides manufacturers with the flexibility to
certify vehicles without having to comply with intermediate life
standards. In exchange they must comply with full life standards for
considerably longer mileage.

C. Supplemental Federal Test Procedure (SFTP) Standards \111\
---------------------------------------------------------------------------

\111\ SFTP requirements do not apply to MDPVs. We plan to
address the applicability of SFTP standards and test procedures to
MDPVs in a future rulemaking.
---------------------------------------------------------------------------

1. Background
Supplemental Federal Test Procedure (SFTP) standards require
manufacturers to control emissions from vehicles when operated at high
rates of speed and acceleration (the US06 test cycle) and when operated
under high ambient temperatures with air conditioning loads (the SC03
test cycle). The existing light duty SFTP requirements begin a three
year phase-in in model year 2000 for Tier 1 LDV/LLDTs.\112\ For HLDTs,
SFTP requirements begin a similar phase-in in 2002. Intermediate and
full useful life SFTP standards exist for all categories of Tier 1
vehicles except that SFTP standards do not apply to diesel fueled LDT2s
and HLDTs. Table V.A.-1 shows the full useful life federal SFTP
requirements applicable to Tier 1 vehicles.
---------------------------------------------------------------------------

\112\ For vehicles included in the NLEV program, this phase-in
becomes a four year phase-in beginning in 2001.

[[Page 6790]]

Table V.A.-1.--Full Useful Life Federal SFTP Standards Applicable to Tier 1 Vehicles
----------------------------------------------------------------------------------------------------------------
NMHC + NO_X CO (g/mi) ^b
Vehicle category (weighted g/ -----------------------------------------------
mi) ^a US06 SC03 Weighted
----------------------------------------------------------------------------------------------------------------
LDV/LDT1 (gasoline)............................. 0.91 11.1 3.7 4.2
LDV/LDT1 (diesel)............................... 2.07 11.1 -- 4.2
LDT2............................................ 1.37 14.6 5.6 5.5
LDT3............................................ 1.44 16.9 6.4 6.4
LDT4............................................ 2.09 19.3 7.3 7.3
----------------------------------------------------------------------------------------------------------------
Notes:
^a Weighting for NMHC+NO_X and optional weighting for CO is 0.35x(FTP)+0.28x(US06)+0.37x(SC03).
^b CO standards are stand alone for US06 and SC03 with option for a weighted standard.

2. SFTP Under the NLEV Program
The NLEV program includes SFTP requirements for LDVs, LDT1s and
LDT2s. These requirements impose the Tier 1 intermediate and full
useful life SFTP standards on Tier 1 and TLEV vehicles, but impose only
4000 mile standards adopted from California LEV I program on LEVs and
ULEVs.\113\
---------------------------------------------------------------------------

\113\ This disparity arose because neither EPA nor CARB had full
useful life SFTP standards for LEVs or ULEVs when the NLEV program
was adopted. Since a major requirement of the NLEV program was
harmony with California standards, EPA adopted the California SFTP
standards in place for the NLEV time frame (2001 and later).
---------------------------------------------------------------------------

NLEV SFTP standards for LEVs and ULEVs are shown in Table V.A.-2.
Table V.A.-2 also includes the California LEV I SFTP standards for
LDT3s and 4s. The standards in that table do not provide for a weighted
standard for NMHC+ NO_X or for CO, but rather employ separate
sets of standards for the US06 and SC03 tests. Also, while the NLEV and
CAL LEV I SFTP standards apply to gasoline and diesel vehicles, they do
not include a standard for diesel particulates (PM).

Table V.A.-2.--SFTP Standards for LEVs and ULEVs in the NLEV/Cal LEV I Program
[4000 Mile Standards]
----------------------------------------------------------------------------------------------------------------
US06 SC03
---------------------------------------------------------------
NMHC+NO_X (g/ NMHC+NO_X (g/
mi) CO (g/mi) mi) CO (g/mi)
----------------------------------------------------------------------------------------------------------------
LDV/LDT1........................................ 0.14 8.0 0.20 2.7
LDT2............................................ 0.25 10.5 0.27 3.5
LDT 3 (Calif MDV 2)............................. 0.4 10.5 0.31 3.5
LDT 4 (Calif MDV 3)............................. 0.6 11.8 0.44 4.0
----------------------------------------------------------------------------------------------------------------

3. SFTP Standards for Interim and Tier 2 LDVs and LDTs: As Proposed
Since no significant numbers of vehicles certified to SFTP
standards will enter the fleet until 2001, manufacturers raised
concerns during the development of the NPRM regarding significant
changes to the SFTP program before its implementation. We stated in the
NPRM that it was reasonable not to increase SFTP stringency beyond
NLEV/CalLEV I levels for the Tier 2 program, but we proposed to include
SFTP standards adjusted for intermediate and full useful life
deterioration where there are currently only 4000 mile standards.
Full useful life standards for Tier 2 vehicles are consistent with
our mandate under the Clean Air Act. We derived the full and
intermediate useful life standards in the NPRM by applying
deterioration allowances from our draft MOBILE 6 model to the existing
4000 mile standards for LDVs and LLDTs. For HLDTs we applied similarly
derived deterioration allowances to California's LEV I SFTP standards
for MDV2s and MDV3s, which are the corresponding categories to LDT3s
and LDT4s in the California LEV I program. The full and intermediate
useful life SFTP standards we proposed would have applied to all Tier 2
vehicles including Tier 2 LDT3s and LDT4s. Further, since our interim
standards are derived from NLEV and Cal LEV I standards, we proposed
that our full life SFTP standards would apply to all interim LDV/LLDTs
beginning in 2004.\114\
---------------------------------------------------------------------------

\114\ Except that, we proposed to permit TLEV vehicles (EPA
interim Bin 10 in Table IV.B.-4), which are not subject to new SFTP
standards under NLEV, to continue to meet Tier 1 SFTP standards, and
to permit HLDTs under the interim programs to continue to meet Tier
1 SFTP standards that do not fully phase in until the 2004 model
year.
---------------------------------------------------------------------------

4. Final SFTP Standards for Interim and Tier 2 LDVs and LDTs
Based upon extensive comment from manufacturers, we are persuaded
that our proposed intermediate and full life SFTP standards need more
review and should possibly be reexamined in a separate rulemaking.
Manufacturers were quite concerned that the technique we used to obtain
the intermediate and full life SFTP standards led to standards that
were overly stringent. They argued that they have little experience
with SFTP compliant vehicles given the current infancy of the program
and they do not know whether SFTP emissions can be reasonably be
expected to deteriorate like FTP emissions. Consequently, in today's
notice, we are finalizing a program that will adopt the existing NLEV/
Cal LEV I 4000 mile standards and utilize adjusted full life standards
from the Tier 1 program, instead of values derived by applying the
draft MOBILE 6 model.
These standards will apply to all Tier 2 vehicles and to all
interim LDV/LLDTs. We proposed and are finalizing that interim HLDTs
meet Tier 1 SFTP standards which do not finish their phase-in until the
2004 model year.
With regard to intermediate and full life SFTP standards, the
preamble to the final rule implementing the SFTP program for the Tier 1
SFTP emission standards (61 FR 54856) provided a formula for computing
SFTP standards to apply under more stringent future

[[Page 6791]]

FTP standards. In the Tier 1 program, SFTP standards represent a
weighted average of FTP, US06 and SC03 standards. The three components
are weighted by factors of 0.35, 0.28, and 0.37 respectively. The
formula simply adjusts the Tier 1 SFTP weighted average standards
downward to reflect the decrease in the component FTP standards. The
weighting factors remain the same and the US06 and SC03 standards
remain the same, but the SFTP standard becomes tighter because the FTP
component becomes smaller. These standards will take effect for all
LDV/LLDTs beginning in 2004 and will phase in with the Tier 2 standards
for HLDTs in 2008 and 2009. The formula is as follows:

New SFTP Standard = Old SFTP Standard - [0.35 x (Tier 1 FTP
standard - New FTP Standard)]

In today's final rule, we will employ this formula to compute full
useful life SFTP standards for all Tier 2 vehicles and for interim LDV/
LLDTs. Because we are also adopting the California 4000 mile SFTP
standards for these vehicles, we are not adopting intermediate life
SFTP standards, so as to avoid the burden of three sets of SFTP
standards.
LDT3 and LDT4 SFTP standards do not currently apply to diesels.
Further, the standards applicable to Tier 1 diesel LDVs and LDT1s are
less stringent than gasoline standards and do not apply to the SC03
cycle. There are no SFTP standards under Tier 1 for diesel LDT2s. In
this final rule, we are applying the same approach we are using with
other standards in this document to the Tier 2 and interim SFTP
standards. Consequently, we are finalizing that Tier 2 vehicles and
interim LDV/LLDTs with diesel or gasoline engines must comply with the
same NMHC+NO_X and CO SFTP limits. Thus, in computing Tier 2
SFTP full life standards for diesel LDVs and LDT1s from Tier 1 values,
the values for diesels must be determined from the standards applicable
to gasoline vehicles of the same category.
Because we lack certainty as to whether diesel vehicles can comply
with the 4,000 mile SFTP standards for gasoline vehicles that we are
adopting from the NLEV and Cal LEV I programs, we are providing an
option that diesel LDV/LLDTs may comply with intermediate life SFTP
standards instead.\115\ Manufacturers must calculate intermediate life
standards using the same approach described for full life standards,
but must substitute appropriate intermediate life values in the
equation above. This provision will only apply through model year 2006,
and thus will likely only impact interim non-Tier 2 vehicles, given the
very small market share that diesels occupy and given our expectation
that they will be the last LDV/LLDTs phased into Tier 2 standards. We
noted above that interim non-Tier 2 HLDTs will have the option of
meeting Tier 1 SFTP standards. Thus diesel HLDTs will not have to
comply with the 4,000 mile standards in the interim years and the
option we are providing for LDV/LLDTs is not needed for HLDTs.
---------------------------------------------------------------------------

\115\ The 4,000 mile standards under NLEV are phased-in in such
a way that diesels would not likely be subject to them until the
2004 model year, given their very small market share. Today's
rulemaking effectively supercedes the NLEV program beginning with
the 2004 model year. In other words, while NLEV contains 4,000 mile
SFTP standards for diesels, they are not likely to ever impact
diesel LDV/LLDTs.
---------------------------------------------------------------------------

5. Adding a PM Standard to the SFTP Standards
We requested comment on the appropriate SFTP PM standards for
diesel vehicles. We suggested it would be appropriate to establish a
margin above the applicable FTP PM standard to serve as the SFTP
standard. EPA has implemented such margins in recent consent decrees,
under which heavy-duty engine manufacturers have agreed not to exceed
emission levels 1.25 times the applicable exhaust standards (including
PM standards) when engines are operated over a wide range of operating
conditions. We received comments in favor of an SFTP PM standard of
1.25 times the FTP standard and we received many comments from
manufacturers against setting any SFTP PM standard until more data
become available.
We believe it is reasonable to include an SFTP standard for PM.
However, we are uncertain as to the technical appropriateness of the
1.25 value for passenger vehicles. Further, the 1.25 value would lead
to an SFTP standard for PM that would not match the stringency of the
other SFTP standards we are finalizing. Consequently, we are finalizing
a procedure for computing diesel PM standards that is nearly identical
to the procedure for computing weighted SFTP standards for
NMHC+NO_X and CO described above. We believe standards
computed in this way will be readily feasible for both gasoline and
diesel vehicles.
To compute the SFTP PM standards, manufacturers will use the same
formula described above for NMHC+NO_X and CO. Where that
formula calls for the Tier 1 SFTP standard to be inserted,
manufacturers must insert the Tier 1 FTP standard. This is because,
under Tier 1 standards, there is no SFTP standard for PM. However, the
Tier 1 weighted SFTP standards are equal to the Tier 1 FTP standards
(or the sum of the Tier 1 FTP standards in the case of
NMHC+NO_X). Using the Tier 1 FTP PM standards in this way
will lead to a Tier 2 SFTP PM standard whose stringency is
appropriately matched to the other pollutants.
For HLDTs , we proposed and are finalizing that Tier 1 SFTP
standards would apply through the interim program. because of the late
start of SFTP phase-in for Tier 1 vehicles. We see no reason to impose
SFTP PM standards on these vehicles during the interim period when
their manufacturers will be under pressure to develop diesel vehicles
to comply with the Tier 2 standards. Also, if we were to impose an FTP
PM standard on the interim vehicles, it would likely be matched to the
interim phase in for HLDTs and manufacturers would simply defer
compliance for diesels until the last phase-in year (2007). The
manufacturers would then have to recertify to the Tier 2 standards by
2009. Given the relatively small number of diesel vehicles, we believe
the most reasonable approach is to defer SFTP PM standards for HLDTs
until the Tier 2 phase-in. Consequently, we are finalizing that Tier 2
HLDTs will have to comply with an SFTP PM standard computed as
described above.
For LDV/LLDTs we are also including the SFTP PM standard for the
Tier 2 vehicles. There are only a few diesel LDV/LLDTs currently
produced and no large increase in their numbers is expected. We see
little environmental benefit in imposing the SFTP PM standard on
interim vehicles.
6. Future Efforts Relevant to SFTP Standards
We are very concerned about ``off cycle'' emissions, i.e. those
emissions that occur under vehicle operational modes that are not
captured in the FTP. SFTP standards help to address our concerns and we
believe that they should apply to all vehicles, regardless of fuel. Our
final rule essentially promulgates Tier 1 SFTP standards that are
reduced to represent the reduction in the FTP component standards. As
we indicate under our discussion of SFTP for medium duty passenger
vehicles (see section IV.B.4.g) we expect to conduct a rulemaking to
establish appropriate ``Tier 2'' SFTP standards for all Tier 2
vehicles. In that rule, we expect to reexamine the US06 and SC03 test
cycles and their applicability to vehicles using different fuels and
technologies,

[[Page 6792]]

including whether these cycles are the most appropriate ones for
diesels. We will also examine whether it is necessary to have different
sets of standards for different vehicle sizes or whether it is possible
to establish one set of standards for all vehicles.

D. LDT Test Weight

Historically, HLDTs (LDT3s and LDT4s) have been emission tested at
their adjusted loaded vehicle weight (ALVW), while LDVs, LDT1s, and
LDT2s have been tested at their loaded vehicle weight (LVW). ALVW is
equivalent to the curb weight of the truck plus half its maximum
payload, while LVW is equivalent to the curb weight of the truck plus a
driver and one adult passenger (300 pounds). As we are equalizing
standards and useful lives across LDVs and all categories of LDTs, we
believe it is appropriate to test all the vehicles under the same
conditions. Therefore, we are finalizing as proposed to test HLDTs at
their loaded vehicle weight. We believe this is appropriate because the
standards we are imposing on HLDTs under Tier 2 are considerably more
stringent than the Tier 1 standards. Further, one of our reasons for
bringing HLDTs under the same standards as passenger cars is that these
trucks include many vans and sport utility vehicles that are often used
as passenger cars with just one or two passengers. Lastly, we note that
testing HLDTs at LVW is consistent with the way they have been tested
for fuel economy purposes for many years. Consequently, we believe it
is appropriate to test them at LVW.
The NPRM proposed that all HLDTs would certify using LVW beginning
in the 2004 model year. Based upon comments, the final rule will allow
the certification of HLDTs based on ALVW until those vehicles are
phased into the Tier 2 standards in 2008 and 2009 at which time they
must be tested at LVW. This will enhance carryover of California
vehicles to the Federal interim program in cases where the California
vehicles meet our interim standards.

E. Test Fuels

As discussed elsewhere in this preamble, the NLEV program was
adopted virtually in its entirety from California's program. Because
California's standards were developed around the use of California
Phase II reformulated gasoline (RFG) as the exhaust emission test fuel,
we adopted California Phase II test fuel as the exhaust emission test
fuel for gasoline-fueled vehicles in the federal NLEV program, although
we recognized at the time that vehicles outside of California would be
unlikely to operate on that fuel in use. In the NPRM we proposed
interim programs that were derived from NLEV (for LDV/LLDTs) and the
CAL LEVI program (for HLDTs), and we proposed to accept certification
test results generated on California fuel, but indicated that we might
test or require in-use testing on federal fuel.
Based upon comment we are finalizing provisions to permit, for
interim vehicles, that if a test group has been certified to the
exhaust emission standards using California fuel and is being carried
into the interim program from NLEV or is being carried across from
California LEV I certification, then we will not test or require in-use
exhaust testing on federal fuel. This change is intended to help
address recertification workload concerns raised by manufacturers. For
new certification not carried across from California LEV I or carried
over from NLEV, and for any Tier 2 vehicles, we will accept exhaust
certification test results based on California fuel for 50 state
vehicles only, but we will reserve the right to perform or require
certification confirmatory testing and in-use testing on federal test
fuel.
We recognize that manufacturers may want to perform calibration
changes on vehicles carried across from the California LEV I program or
carried over from NLEV program. These calibration changes will likely
be aimed at certifying the test group to the lowest possible
NO_X value. We believe that these calibration changes would
be appropriate, provided they can still be covered by the existing
worst case durability data vehicle. We will perform or require
certification confirmatory testing and in-use emission testing on these
vehicles using California fuel.
Because differences exist between the California and federal
evaporative emission testing procedures, we proposed to continue to
require the use of federal certification fuel as the test fuel in
evaporative emission testing. Under current programs, where California
and federal evaporative emission standards are essentially the same,
California accepts evaporative results generated on the federal
procedure (using federal test fuel), because available data indicates
the federal procedure to be a ``worst case'' procedure. The evaporative
standards California has adopted for their LEV II program are more
stringent than those we are finalizing in this document. In the NPRM,
we requested comment and supporting emission test data on whether
vehicles certified to CalLEV II evaporative standards using California
fuels will necessarily comply with the federal Tier 2 evaporative
standards, including ORVR standards, when tested with federal test
fuel. While we got comments from manufacturers advocating that we
accept the results of California evaporative testing to demonstrate
compliance with the federal evaporative standards, we received no
supporting data. Still, given the fairly large difference between
California and federal evaporative standards, it seems reasonable that
a vehicle meeting the California standards under California fuels and
test conditions might also meet federal standards under federal fuels
and conditions. We believe it may be possible for manufacturers to
establish a relationship between the two sets of standards, fuels and
conditions that would enable us to grant federal certification based
upon data showing conformity with the California standards under
California fuels and conditions. Consequently, we are including a
provision in the certification regulations to enable manufacturers to
obtain federal evaporative certification based upon California results,
if they obtain advance approval from EPA. EPA will review test data
from manufacturers to establish whether it is appropriate to accept
California data to demonstrate compliance with federal standards.

F. Changes to Evaporative Certification Procedures To Address Impacts
of Alcohol Fuels

Current certification procedures, including regulations under the
new CAP2000 program,\116\ allow manufacturers to develop their own
durability process for calculating deterioration factors for
evaporative emissions. The regulations (Sec. 86.1824-01) permit
manufacturers to develop service accumulation (aging) methods based on
``good engineering judgement''. The manufacturer's durability process
must be designed to predict the expected evaporative emission
deterioration of in-use vehicles over their full useful lives. We
proposed and are finalizing requirements that these aging methods
include the use of alcohol fuels to address concerns that alcohol fuels
increase the permeability and thus the evaporative losses from hoses
and other evaporative components. Based upon comment, we are also
finalizing an option to the requirement that the manufacturer use the
alcohol fuel. Under this option, the manufacturer may demonstrate to
EPA using good engineering judgement

[[Page 6793]]

acceptable to EPA that its durability process for calculating
evaporative emission deterioration factors accurately predicts
deterioration under prolonged exposure to alcohol fuels.
---------------------------------------------------------------------------

\116\ The Compliance Assurance Program, (64 FR 23906) takes
effect in the 2000 model year.
---------------------------------------------------------------------------

We have reviewed data indicating that the permeability, and
therefore the evaporative losses, of hoses and other evaporative
components can be greatly increased by exposure to fuels containing
alcohols.\117\ Alcohols have been shown to promote the passage of
hydrocarbons through a variety of different materials commonly used in
evaporative emission systems. Data from component and fuel line
suppliers indicate that alcohols cause many elastomeric materials to
swell, which opens up pathways for hydrocarbon permeation and also can
lead to distortion and tearing of components like ``O'' ring seals.
Ethers such as MTBE and ETBE have a much smaller effect. Alcohol-
resistant materials such as fluoroelastomers are available and are
currently used by manufacturers to varying extents.
---------------------------------------------------------------------------

\117\ Numerous SAE papers examine the permeability of fuel and
evaporative system materials as well as the influence of alcohols on
permeability. See, for example SAE Paper #s 910104, 920163, 930992,
970307, 970309, 930992, and 981360, copies of which are in the
docket for this rulemaking.
---------------------------------------------------------------------------

Alcohols do not impact evaporative components and hoses
immediately, but rather it may take as long as one year of exposure to
alcohol fuels for permeation rates to stabilize. The end result is
higher permeation and increased in-use evaporative emissions.\118\
---------------------------------------------------------------------------

\118\ Ibid.
---------------------------------------------------------------------------

Today, roughly 10% of fuel sold in the U.S. contains alcohol,
mainly in the form of ethanol, and such fuels are often offered in
ozone nonattainment areas. We believe it is appropriate to ensure that
evaporative certification processes expose evaporative components to
alcohols and do so long enough to stabilize their permeability.
Therefore, we are finalizing our proposal to the evaporative
certification requirements to require manufacturers to develop their
deterioration factors using a fuel that contains the highest legal
quantity of ethanol available in the U.S.
To implement this change, we are modifying the Durability
Demonstration Procedures for Evaporative Emissions found at
Sec. 86.1824-01. The amendments will require manufacturers not using an
approved option, to age their systems using a fuel containing the
maximum concentration of alcohols allowed by EPA in the fuel on which
the vehicle is intended to operate, i.e., a ``worst case'' test fuel.
(Under current requirements, this fuel would be about 10% ethanol, by
volume.) We are also modifying the Durability Demonstration Procedures
to require manufacturers to ensure that their aging procedures are of
sufficient duration to stabilize the permeability of the fuel and
evaporative system materials. These modifications will take place as
vehicles are phased into the evaporative emission standards contained
in this final rule.
We requested comment on alternative ways by which manufacturers
could document or demonstrate that their components are made of
materials whose permeability is not significantly affected by alcohols.
We received no comments responsive to this request, but we did receive
comments that EPA should not change the CAP2000 provision allowing
manufacturers to develop their own durability process for calculating
evaporative emission deterioration factors ``using good engineering
judgement''. We do not wish to foreclose the possibility that an
alternative method may exist or may arise in the future. Consequently,
in the final rule we will permit manufacturers to use an optional
method based on good engineering judgement acceptable to EPA. As an
example, one method would be for the manufacturer to show that it is
exclusively using materials documented in the technical literature to
have low permeability in the presence of alcohols.

G. Other Test Procedure Issues

California's LEV II program implements a number of minor changes to
exhaust emissions test procedures. We have evaluated these changes and
found that, for tailpipe emissions, the California test procedures fall
within ranges and specifications permitted under the Federal Test
Procedure.
With regard to hybrid electric vehicles (HEVs) and zero emission
vehicles (ZEVs), we believe that these vehicles will be predominantly
available in California, or that they will typically be first offered
for sale in California, because of California's ZEV requirement, which
promotes the sale of HEVs and ZEVs. Where manufacturers market HEVs or
ZEVs outside of California, it is likely that they will market the same
vehicles in California. Consequently, we are finalizing our proposal to
incorporate by reference California's exhaust emission test procedures
for HEVs and ZEVs.\119\
---------------------------------------------------------------------------

\119\ California Exhaust Emission Standards and Test Procedures
for 2003 and Subsequent Model Zero-Emission Vehicles, and 2001 and
Subsequent Model Hybrid Electric Vehicles. In the Passenger Car,
Light-Duty Truck and Medium-Duty Vehicle Classes; adopted August 5,
1999.
---------------------------------------------------------------------------

In the NLEV program, we provided a specific formula used by
California that could be used to compute an HEV contribution factor to
NMOG emissions. This formula took into consideration the range without
engine operation of various types of HEVs and had the effect of
reducing the NMOG emission standard for a given emission bin (for HEV
vehicles only). This would have obvious beneficial effects on a
manufacturer's calculation of its corporate NMOG average.
The technology of HEVs is under rapid change and we do not believe
that we can design a formula now that will accurately predict the
impact of HEVs on corporate average NO_X emissions in the
Tier 2 time frame. Consequently, we are finalizing the proposed
provision by which manufacturers could propose HEV contribution factors
for NO_X to EPA. If approved, these factors can be used in
the calculation of a manufacturer's fleet average NOx emissions and
will provide a mechanism to credit an HEV for operating with no
emissions over some portion of its life.
These factors will be based on good engineering judgement and will
consider such vehicle parameters as vehicle weight, the portion of the
time during the test procedure that the vehicle operates with zero
emissions, the zero emission range of the vehicle, NO_X
emissions from fuel-fired heaters and any measurable NO_X
emissions from on-board electricity production and storage.
The final NLEV rule (See 62 FR pg 31219, June 6, 1997) incorporated
by reference California's NMOG measurement procedure and adopts
California's approach of using Reactivity Adjustment Factors (RAFs) to
adjust vehicle emission test results to reflect differences in the
impact on ozone formation between an alternative-fueled vehicle and a
vehicle fueled with conventional gasoline. As has been discussed
elsewhere in this preamble, the NLEV program is a special case in which
California standards and provisions were adopted virtually in their
entirety. In the preamble to the final NLEV rule (See 62 FR 31203), we
expressed our reservations about the use of RAFs. We also addressed our
reservations about the use of reactivity factors developed in
California in a program that spans a range of climates and geographic
locations across the United States in the final rule on reformulated
gasoline (RFG) (see 59 FR 7220). We continue to be concerned about the
validity of RAFs to predict ozone formation nationwide and asked the
National Academy of Sciences to

[[Page 6794]]

look at the scientific evidence in support of the use of these factors
nationwide. While we have recently received a report from NAS,\120\ we
have not yet developed a final position on how RAFs should be treated
in federal regulations. We are finalizing as proposed not to permit the
use of RAFs in the Tier 2 program.
---------------------------------------------------------------------------

\120\ Ozone-Forming Potential of Reformulated Gasoline, May
1999. National Academy of Sciences; National Academy Press.
Available from the NAS web site: http://www.nap.edu.
---------------------------------------------------------------------------

The issue of RAFs is relevant primarily to alcohol and CNG-fueled
vehicles. RAFs are not relevant at all if a manufacturer elects to use
NMHC data to show compliance with the NMOG standards. While, in our
final rule, alcohol and CNG vehicles will have to comply with NMOG
standards beginning in 2004 and while we desire to harmonize with
California when practical and reasonable, we will not permit the use of
RAFs for Tier 2 vehicles and interim non-Tier 2 vehicles. We note that
we are finalizing a provision from the NPRM that permits dual fueled
and flexible fueled vehicles to elect an NMOG value from the next
higher bin when they are tested on an alternative fuel. This provides
flexibility in compliance with applicable NMOG standards for these
vehicles. We do not believe that dedicated alcohol or CNG vehicles
should have any problems complying with the NMOG standards we are
finalizing and consequently the relief these vehicles might get when
RAFs are employed is unnecessary.
In its LEV II program, California is also implementing a number of
changes to evaporative emission test procedures.\121\ Many of these
changes address the evaporative emission testing of hybrid electric
vehicles. We proposed not to adopt California's changes, because
California uses different test temperatures and different test fuel in
its evaporative emission testing of gasoline vehicles than we use in
the federal program. The preamble to the final NLEV rule (See 62 FR
31227) explains that California and EPA are reviewing an industry
proposal to streamline and reconcile the California and federal
procedures. That work has not been completed. However, where California
adopts procedures specific to HEVs and ZEVs, we are adopting those
procedures, except that our testing will occur at lower temperatures,
and use a fuel determined by EPA to be representative of federal usage
(for HEVs only).
---------------------------------------------------------------------------

\121\ California Evaporative Emission Standards and Test
Procedures for 2001 and Subsequent Model Motor Vehicles. Adopted
August 5, 1999.
---------------------------------------------------------------------------

H. Small Volume Manufacturers

Our final rule includes the following flexibilities intended to
assist all manufacturers in complying with the stringent proposed
standards without harm to the program's environmental goals as
presented in the NPRM:
A four year phase-in of the standards for LDV/LLDTs;
A delayed phase-in for HLDTs;
The freedom to select from specific bins of standards;
A standard that can be met through averaging, banking and
trading of NO_X credits;
Provisions for NO_X credit deficit carryover;
and,
Provisions for alternative phase-in schedules.
These flexibilities apply to all manufacturers, regardless of size,
and in general we believe they eliminate the need for more specific
provisions for small volume manufacturers.\122\ However, we proposed
and are finalizing one additional flexibility for small volume
manufacturers. Today's rule exempts small volume manufacturers from the
25%, 50% and 75% Tier 2 phase-in requirements applicable to the 2004,
2005 and 2006 LDV/LLDTs and the 50% phase-in requirement applicable to
2008 HLDTs. Instead, small volume manufacturers will simply comply with
the appropriate Tier 2 100% requirement in the 2007 and 2009 model
year. In the phase-in years, small volume manufacturers will simply
comply with the appropriate interim standards for all of their
vehicles, except that we will also exempt small volume manufacturers
from the 25%, 50% and 75% phase-in requirements for the 0.20 g/mi
corporate average NO_X standard applicable to interim HLDTs
in 2004-2006. Small volume HLDT manufacturers must simply comply with
the interim standards, including the corporate average NO_X
standard, in 2007 for 100% of their vehicles. During model years 2004-
2006, these same small volume manufacturers must comply with any of the
applicable bins of standards for 100% of their HLDTs.\123, 124\
Provisions to deal with the leadtime issue related to HLDTs and
outlined in section IV.B. apply to small volume manufacturers.
Therefore unless the small volume manufacturer wants to use the
optional NMOG standards for interim LDT2s and LDT4s, it may optionally
meet the Tier 1 standards for its 2004 model year HLDTs, provided it
commences its model year for those vehicles before the fourth
anniversary date of today's rulemaking.
---------------------------------------------------------------------------

\122\ We define small volume manufacturers to be those with
total U.S. sales of less than 15,000 highway units per year.
Independent commercial importers (ICIs) with sales under 15,000 per
year are included under this term.
\123\ For a graphical illustration of the phase-ins through
time, see Table IV.B.-2.
\124\ 2005-2006 for vehicles where the small volume manufacturer
commences its 2004 model year for all its 2004 vehicles before the
fourth anniversary date of the signature of this rule.
---------------------------------------------------------------------------

As explained in the NPRM, we will continue to apply the federal
small volume manufacturer provisions, which provide relief from
emission data and durability showing and reduce the amount of
information required to be submitted to obtain a certificate of
conformity. In addition, the CAP2000 program contains reduced in-use
testing requirements for small volume manufacturers.
Exempting small volume manufacturers from the Tier 2 and interim
HLDT phase-in requirements eliminates a dilemma that phase-in
percentages can pose to a manufacturer that has a limited product line,
i.e., how to address percentage phase-in requirements if the
manufacturer makes vehicles in only one or two test groups. We have
implemented similar provisions for small entities in other rulemakings.
Approximately 15-20 manufacturers that currently certify vehicles, many
of which are independent commercial importers (ICIs), will qualify.
These manufacturers represent just a fraction of one percent of LDVs
and LDTs produced. We do not believe that this provision will have any
measurable impact on air quality.
1. Special Provisions for Independent Commercial Importers (ICIs)
We requested comment in the NPRM as to whether ICIs should be
exempted from the interim and Tier 2 fleet average NO_X
standards. We explained that ICIs may not be able to predict their
sales and control their fleet average emissions because they may be
dependent upon vehicles brought to them by individuals attempting to
import uncertified vehicles. We noted that the NLEV program is optional
for ICIs and that ICIs are specifically prohibited, under existing
regulations, from complying with the fleet average NMOG standard under
the NLEV program. (See 40 CFR 85.1515(c)). Also, the existing
regulations specifically bar ICIs from participating in any emission
related averaging, banking or trading program. (See 40 CFR 85.1515(d)).
We expressed our concern that if we do not amend this provision, ICIs
would likely just pick the least stringent bin available to certify
their vehicles. This would create an inequity for other manufacturers,

[[Page 6795]]

especially other small volume manufacturers that must comply with the
fleet average NO_X standards.
Since we do not believe it is wise to finalize a provision that
could lead to an inequity like this, and since averaging may not be
workable for ICIs, we are finalizing that ICIs must comply with the
standards from the bin that contains the relevant fleet average
NO_X standard, e.g., in model years 2007 and later an ICI
would have to use bin 5 or below for all of its LDV/LLDTs. However, if
an ICI is able to purchase credits or to certify to bins below the one
containing the fleet average NO_X standard, we will permit
the ICI to bank credits for future use. Where an ICI desires to certify
to bins above the fleet average standard, we will permit them to do so
if they have adequate and appropriate credits. Where an ICI desires to
certify to bins above the fleet average standard and does not have
adequate or appropriate credits to offset the vehicles, we will permit
the manufacturer to obtain a certificate for vehicles using those bins,
but will condition the certificate such that the manufacturer can only
produce vehicles if it first obtains credits from other manufacturers
or from other vehicles certified to lower bins during that model year.
We do not believe that ICIs can predict or estimate their sales of
various vehicles well enough to participate in a program that will
allow them leeway to produce some vehicles to higher bins now, knowing
that they will sell vehicles from lower bins later. We also do not
believe that we can reasonably assume that an ICI that certifies and
produces vehicles one year, will certify or even be in business the
next, consequently, we are also not permitting ICIs to utilize the
deficit carryforward provisions of the rule.
Essentially, ICIs will be allowed the major benefits of the
averaging, banking and trading program, but will be constrained from
getting into a situation where they can ever produce vehicles to higher
bins that they can not cover with credits at the time they produce the
vehicles.
2. Hardship Provision for Small Volume Manufacturers
The panel convened under the Small Business Regulatory Enforcement
Fairness Act recommended that we seek comment on the inclusion of a
hardship provision. We requested comment on whether we should include
such a provision in the NPRM. Based upon comment, we are including a
limited hardship provision in the final rule that will be applicable to
small volume manufacturers.
Small volume manufacturers include companies that independently
import motor vehicles (Independent Commercial Importers or ICIs),
companies that modify vehicles to operate on alternative fuels,
companies that produce specialty vehicles by modifying vehicles
produced by others, and companies that produce small quantities of
their own vehicles, but rely on major manufacturers for engines and
other vital emission related components. In these businesses,
predicting sales is difficult and it is often necessary to rely on
others for technology.
This provision will provide limited relief in the case where a
small volume manufacturer is unable to comply with the phase-in dates
or average NO_X standard. The manufacturer will need to
provide evidence that, despite its best efforts, it cannot meet
implementation dates or required NO_X averages.
Appeals for hardship relief must be made in writing, must be
submitted before the earliest date of noncompliance, must include
evidence that the noncompliance will occur despite the manufacturer's
best efforts to comply and must include evidence that severe economic
hardship will be faced by the company if the relief is not granted.
Hardship relief will only be granted for the first year after a new
standard is finally implemented. For small volume manufacturers, which
are already exempted from the phase-in schedules for the interim and
Tier 2 programs, this means that relief would be available for the
final phase-in year for the LDV/LLDT Tier 2 phase-in (2007), for the
final phase-in year for the interim HLDT phase-in (2007), and the final
phase-in year for the Tier 2 HLDT phase-in (2009). Relief will also be
available for manufacturers that did not opt into NLEV and must meet
our interim standards for all their LDV/LLDTs in 2004, and relief will
be available for HLDTs and MDPVs which must be brought under our
interim program in the 2004 model year.
We will work with the applicant to ensure that all other remedies
available under this rule, e.g., use of banked or purchased credits,
are exhausted before granting additional relief, and will limit the
period of relief to one year. Note that in our discussion of the credit
deficit carryforward provision in section IV.B.4.d.vi, we indicate that
we are not permitting small volume manufacturers to carry deficits
forward until they have demonstrated compliance with the NO_X
averaging provisions for one year. This is to prevent small volume
manufacturers, that have already received additional time due to the
waiver of the phase-in requirements, from gaining even more time to
finally comply through the credit deficit carryforward provisions.
To avoid this provision creating a self-implementing problem, by
which the very existence of the hardship provision prompts small volume
manufacturers to delay development, acquisition and application of new
technology, we want to make clear that we expect this provision to be
rarely used. Our final rule contains numerous flexibilities for all
manufacturers and it waives the phase-in steps for small volume
manufacturers, which effectively provides them more time. We expect
small manufacturers, to prepare for the applicable implementation dates
in today's rule.

I. Compliance Monitoring and Enforcement

1. Application of EPA's Compliance Assurance Program, CAP2000
The CAP2000 program (64 FR 23905, May 14, 1999) streamlines and
simplifies the procedures for certification of new vehicles and will
also require manufacturers to test in-use vehicles to monitor
compliance with emission standards. The CAP2000 program was developed
jointly with the State of California and involved considerable input
and support from manufacturers. As the name implies, it can be
implemented as early as the 2000 model year.
We are finalizing our proposal that the Tier 2 and the interim
requirements will be implemented subject to the requirements of the
CAP2000 program. Certain CAP2000 requirements are being slightly
modified to reflect changes to useful lives, standard structure and
other aspects of the Tier 2 program, but we proposed no major changes
to fundamental principles of the CAP2000 program, and we are not adding
any major changes with today's final rule.
Although we proposed changes to useful lives, we did not propose to
amend the 50,000 mile minimum mileage used in manufacturer in-use
verification testing or in-use confirmatory testing under the CAP2000
program at this time. The CAP2000 in-use program is not yet implemented
and we believe it is appropriate to allow manufacturers to gain
experience with procuring and testing vehicles at the 50,000 mile level
before making significant changes. However, where one vehicle from each
in-use test group would have a minimum mileage of 75,000 miles under
the CAP2000 program, we proposed and are finalizing, consistent with
California, to

[[Page 6796]]

change that figure to 90,000 miles for Tier 2 vehicles.
We may, in our own in-use program, procure and test vehicles at
mileages higher than 50,000 and pursue remedial actions (e.g., recalls)
based on that data. We may also use that data as the basis to initiate
a rulemaking to make changes in the CAP2000 in-use requirements, if the
data indicate significant non-conformity at higher mileages.
We are finalizing certification test fuel specifications consistent
with our final fuel sulfur requirements. Given the phase-in for low
sulfur fuel we are finalizing in this rulemaking, we recognize that
2004 to 2007 vehicles (and vehicles certified in earlier model years to
bank early NO_X credits) may be exposed to higher sulfur
levels early in their lives. Because of this sulfur exposure, these
vehicles could experience problems with OBD indicator light
illuminations.
Consistent with our approach under the NLEV program, we will
consider requests from manufacturers to permit OBD systems that
function properly on low sulfur fuel, but exhibit sulfur-induced passes
when operated on higher sulfur fuel. For OBD systems that exhibit
sulfur-induced indicator light illumination, we will consider requests
to modify such vehicles on a case-by-case basis.
2. Compliance Monitoring
We plan no new compliance monitoring activities or programs for
Tier 2 vehicles. These vehicles will be subject to the certification
and manufacturer in-use testing provisions of the CAP2000 rule. Also,
we expect to continue our own in-use testing program for exhaust and
evaporative emissions. We will pursue remedial actions when substantial
numbers of properly maintained and used vehicles fail any standard in
either in-use testing program.
Consistent with our approach under NLEV we will consider requests,
prior to manufacturer or EPA in-use testing to permit preconditioning
procedures designed solely to remove the effects of high sulfur
gasoline on vehicles produced through the 2007 model year.
We retain the right to conduct Selective Enforcement Auditing of
new vehicles at manufacturer's facilities. In recent years, we have
discontinued SEA testing of new LDVs and LDTs, because compliance rates
were routinely at 100%. We recognize that the need for SEA testing may
be reduced by the low mileage in-use testing requirements of the
CAP2000 program. However, we expect to re-examine the need for SEA
testing as standards tighten under the NLEV, interim, and Tier 2
programs.
We have established a data base to record and track manufacturers'
compliance with NLEV requirements including the corporate average NMOG
standards. We expect to monitor manufacturers' compliance with the Tier
2 and interim corporate average NO_X standards in a similar
fashion and also to monitor manufacturers' phase-in percentages for
Tier 2 vehicles.
3. Relaxed In-Use Standards for Vehicles Produced During the Phase-in
Period
The Tier 2 standards will be challenging for manufacturers to
achieve, and some vehicles will pose more of a challenge than others.
Not only will manufacturers be responsible for assuring that vehicles
can meet the standards at the time of certification, they will also
have to ensure that the vehicles comply when self-tested in-use under
the provisions of the CAP2000 program, and when tested by EPA under its
in-use (``Recall'') test program.
With any new technology, or even with new calibrations of existing
technology, there are risks of in-use compliance problems that may not
appear in the certification process. In-use compliance concerns may
discourage manufacturers from applying new technologies or new
calibrations. Thus, we proposed and are finalizing, relaxed in-use
standards for those bins most likely to require the greatest
applications of effort, to provide assurance to the manufacturers that
they will not face recall if they exceed standards by a specified
amount.
For the first two years after a test group meeting a new standard
is introduced, that test group will be subject to more lenient in-use
standards. These ``in-use standards'' will apply only to bin 5 and
below, only for the pollutants indicated, and only for the first two
model years that a test group is certified under that bin. The in-use
standards will not be applicable to any test group first certified to a
new standard after 2007 for LDV/LLDTs or after 2009 for HLDTs.
The temporary in-use standards are shown in Table V.A.-3 below.

Table V.A.-3.--In-use Compliance Standards (g/mi)
[Certification standards shown for reference purposes]
------------------------------------------------------------------------
Durability
Bin period NO_X In- NO_X NMOG in-use NMOG
(miles) use certification certification
------------------------------------------------------------------------
5....... 50,000 0.05 n/a 0.075
5....... 120,000 0.10 0.07 n/a 0.090
4....... 120,000 0.06 0.04 n/a 0.070
3....... 120,000 0.05 0.03 0.09 0.055
2....... 120,000 0.03 0.02 0.02 0.010
------------------------------------------------------------------------

Because we are concerned that diesel vehicles may require low
sulfur fuel to comply with our interim requirements and that such fuel
may not be widely available until the 2006-2007 timeframe, we are
providing in-use standards specifically for diesel vehicles certified
to bin 10 standards. These standards will be determined by multiplying
the applicable NO_X and PM certification standards by factors
of 1.2 and 1.35, respectively. These multipliers can be used only for
years during which bin 10 is viable, only for diesels and only for the
pollutants indicated.
We believe manufacturers should and will strive to meet
certification standards for the full useful lives of the vehicles, but
we recognize that the existence of such in-use standards poses some
risk that a manufacturer might aim for the in-use standard in its
design efforts rather than the certification standard, and thus market
less durable designs. We do not believe that risk to be significant. We
believe that such risks are more than balanced by the gains that can
result from earlier application of new technology or new calibration
techniques that might occur in a scenario where in-use liability is
slightly reduced. Further, we believe that the in-use standards will be
of short enough duration that any risks are minimal.

[[Continued on page 6797]]

Notices For
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994

[[pp. 6747-6796]] Control of Air Pollution From New Motor Vehicles: Tier 2 Motor

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