[Federal Register: February 10, 2000 (Volume 65, Number 28)]
[Rules and Regulations]
[Page 6797-6846]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr10fe00-20]
[[pp. 6797-6846]] Control of Air Pollution From New Motor Vehicles: Tier 2 Motor
Vehicle Emissions Standards and Gasoline Sulfur Control Requirements
[[Continued from page 6796]]
[[Page 6797]]
4. Enforcement of the Tier 2 and Interim Corporate Average
NO<INF>X</INF> Standards
We are finalizing, as proposed, that manufacturers can either
report that they meet the relevant corporate average NO<INF>X</INF>
standard in their annual reports to the Agency or they can show via the
use of NO<INF>X</INF> credits that they have offset any exceedance of
the corporate average NO<INF>X</INF> standard. Manufacturers will also
have to report their NO<INF>X</INF> credit balances or deficits.
The averaging, banking and trading program will be enforced through
the certificate of conformity that the manufacturer must obtain in
order to introduce any regulated vehicles into commerce. The
certificate for each test group will require all vehicles to meet the
applicable Tier 2 emission standards from the applicable bin of the
Tier 2 program, and will be conditioned upon the manufacturer meeting
the corporate average NO<INF>X</INF> standard within the required time
frame. If a manufacturer fails to meet this condition, the vehicles
causing the corporate average NO<INF>X</INF> exceedance will be
considered to be not covered by the certificate of conformity for that
engine family. A manufacturer will be subject to penalties on an
individual vehicle basis for sale of vehicles not covered by a
certificate. These provisions will also apply to the interim corporate
average standards.
As outlined in detail in the preamble to the final NLEV rule, EPA
will review the manufacturer's sales to designate the vehicles that
caused the exceedance of the corporate average NO<INF>X</INF> standard.
We will designate as nonconforming those vehicles in those test groups
with the highest certification emission values first, continuing until
a number of vehicles equal to the calculated number of noncomplying
vehicles as determined above is reached. In a test group where only a
portion of vehicles are deemed nonconforming, we will determine the
actual nonconforming vehicles by counting backwards from the last
vehicle produced in that test group. Manufacturers will be liable for
penalties for each vehicle sold that is not covered by a certificate.
During phase in years, the certificates will also require
manufacturers to meet the applicable phase-in requirements. Compliance
with the phase-in requirements will be enforced in the same manner as
for the corporate average NO<INF>X</INF> standard. For the optional
phase-in requirement for HLDTs for model year 2004, manufacturers must
declare in their application for certification whether they intend to
comply with the interim requirements for all of their HLDTs and
initiate phase-in to the interim corporate average NO<INF>X</INF>
standard in 2004 and receive the benefits of that phase-in (less
stringent NMOG standards for certain LDT2s and LDT4s). Compliance with
this phase-in requirement and the fleet average NO<INF>X</INF> standard
will be enforced just like compliance with any other average
NO<INF>X</INF> standard and phase-in requirement of today's program.
We will also condition certificates to enforce the requirements
that manufacturers not sell NO<INF>X</INF> credits that they have not
generated. A manufacturer that transfers NO<INF>X</INF> credits it does
not have will create an equivalent number of debits that it must offset
by the reporting deadline for the same model year. Failure to cover
these debits with NO<INF>X</INF> credits by the reporting deadline will
be a violation of the conditions under which EPA issued the certificate
of conformity, and nonconforming vehicles will not be covered by the
certificate. EPA will identify the nonconforming vehicles in the same
manner described above.
In the case of a trade that results in a negative credit balance
that a manufacturer could not cover by the reporting deadline for the
model year in which the trade occurred, we proposed, and are
finalizing, to hold both the buyer and the seller liable. This is
consistent with other mobile source rules, except for the NLEV rule as
discussed below. We believe that holding both parties liable will
induce the buyer to exercise diligence in assuring that the seller has
or will be able to generate appropriate credits and will help to ensure
that inappropriate trades do not occur.
In the NLEV program we implemented a system in which only the
seller of credits would be liable. In the preamble to the final NLEV
rule (See 62 FR 31216), we explained that a multiple liability approach
would be unnecessary in the context of the NLEV program given that the
main benefit to a multiparty liability approach would be to ``protect
against a situation where one party sells invalid credits and then goes
bankrupt, leaving no one liable for either penalties or compensation
for the environmental harm.'' Our preamble stated further that EPA
would not necessarily take the same approach for ``other differently
situated trading programs.''
The NLEV program was implemented to be a relatively short duration
program, during which time we could expect relative stability in the
industry. Also, given that NLEV is a voluntary program of lower than
mandated standards, we did not expect that the smallest manufacturers
would opt in. These are the companies whose stability is most in
jeopardy in a dynamic and very competitive worldwide business.
We currently believe that the Tier 2 program and its framework will
remain for many years. We note that the program is not scheduled for
complete phase-in for almost nine years after the publication of
today's rule. All manufacturers, large and small, will ultimately have
to meet the Tier 2 standards. We cannot predict that in the Tier 2
timeframe there will not be companies that leave the market or are
divided between other companies in mergers and acquisitions. Thus we
believe it is prudent to implement a program to provide inducements to
the seller to assure the validity of any credits that it purchases or
contracts for.
J. Addressing Environmentally Beneficial Technologies Not Recognized by
Test Procedures
Compliance with the current and proposed EPA motor vehicle emission
standards is based on the emission performance of a vehicle over EPA's
prescribed test procedure. While this test procedure addresses many of
the aspects of a vehicle's impact on air quality, it does not address
all such impacts. EPA is aware of two developing technologies which
have potential to improve ozone-related air quality, but that would not
do so over the current EPA test procedure.
The first example is a device that removes ozone from the air as
the vehicle is driven. A major producer of automotive catalysts,
Englehard, has developed a catalytic coating for vehicle radiators
(called PremAir) that converts ambient ozone to oxygen. ARB has been
working with Englehard for some time to develop a procedure which would
grant PremAir and other direct ozone reducing technologies a NMOG
credit under its LEV I and LEV II programs. ARB issued on December 20,
1999 a Manufacturers Advisory Circular outlining procedures for
establishing such a NMOG credit.
Englehard submitted substantial comments to the Tier 2 NPRM,
including ozone modeling results for five cities (Los Angeles, Houston,
Atlanta, New York City, and Chicago). This ozone modeling compared the
ozone reductions from reduced exhaust VOC and NO<INF>X</INF> emissions
to that from using PremAir. As a result of this modeling, Englehard
requested that EPA grant a typical PremAir system a NMOG or
NO<INF>X</INF> emission credit of 0.015 g/mi. This credit would be
adjusted based the exact design and performance of the system and
vehicle being certified.
[[Page 6798]]
The second example is an insulated catalyst. The insulation retains
heat for extended periods of time, increasing the catalyst temperature
when the engine is started and reducing the time required for the
catalyst to reach an operational temperature. This technology can
reduce cold start emissions for engine off times (called soaks) of 24
hours or less. The vast majority of engine soaks in-use are less than
24 hours. However, EPA's test procedure only tests emissions at two
fairly extreme soak times: 10 minutes and 12-36 hours. The 10 minute
soak is so short that even an uninsulated catalyst is warm enough to
quickly begin working upon restart. The 36 hour soak is beyond the
practical limit of cost-effective insulating techniques. As a result of
the Tier 2 NPRM, EPA received a number of inquiries from potential
manufacturers of insulated catalysts, requesting further information
about emission credits, test procedures and certification requirements.
EPA believes that both of these technologies, as well as other
potential technologies, will reduce regulated emissions and/or ambient
ozone levels, as long as they operate as designed in-use. EPA will work
with the developers of such technologies to establish regulatory
procedures to determine whether it is appropriate to grant emission
credit for particular technologies. This process will involve the
opportunity for public notice and comment.
With regard to Englehard's PremAir technology, EPA specifically
requested comments on ARB's proposed approach to determining an NMOG
credit and received no adverse comment on granting this type of
technology a VOC emission credit. Thus, EPA is promulgating today
procedures very similar to ARB's for certifying such technologies and
determining the appropriate VOC emission credit. The only difference
between EPA's and ARB's procedures involve assessing the effectiveness
of VOC emission reductions and ozone reducing devices in areas outside
of California.
In summary, the ozone reductions associated by both the ozone
reducing technology, such as PremAir, and exhaust VOC emission
reductions will be estimated using urban airshed modeling, using up-to-
date chemical and meteorological simulation techniques. Four local
areas shall be modeled: New York City, Chicago, Atlanta and Houston.
The ozone episodes to be modeled shall be those selected by the states
for use in their most recent ozone SIPs. Emissions shall be projected
for calendar year 2007. Baseline emissions will include the benefits of
the Tier 2 and sulfur standards being promulgated today, as well as all
other emission controls assumed in EPA's ozone modeling of the benefits
of the Tier 2 and sulfur standards described above. The ozone benefit
of VOC emission reductions will be modeled by assuming that Tier 2 LDVs
and LDTs meet a 0.055 g/mi exhaust NMOG standard instead of a 0.09 g/mi
NMOG standard. The relationship between changes in exhaust NMOG
emission standards and in-use VOC emissions shall be determined by
modeling LDV+LDT emission in 2030 assuming that all Tier 2 vehicles
meet a 0.055 g/mi exhaust NMOG standard instead of a 0.09 g/mi NMOG
standard. All emission modeling shall utilize the updated Tier 2
emission model developed by EPA as part of this rule, or MOBILE6, once
it is available. The measure of ozone to be used in calculating VOC
emission equivalency will be the peak one-hour ozone level anywhere in
the modeled region on the day when ozone is at its highest. The NMOG
credit will be determined by averaging the NMOG credit determined in
each of the four local areas.
Simulation of the benefits of the direct ozone reducing device will
assume that ozone levels immediately around the roadway will be 40%
less than that existing in the broader grid. The performance aspects of
the direct ozone reducing device can be simulated by any reasonable
values, since the appropriate NMOG credit for any specific application
of this technology will be scaled to the performance of the specific
application.
The manufacturer wishing to obtain an NMOG credit for use of this
technology must demonstrate its effectiveness to EPA as part of the
certification process. This will involve demonstrating the air flow
through the device, its ozone destruction capability under conditions
analogous to those photochemically modeled, the durability of this
capability over the useful life of the vehicle and the method to be
used to diagnose its effectiveness in-use.
Regarding the insulated catalyst technology, less information has
been received to date on its performance. We are not promulgating
regulations for determining the appropriate credit for such technology
today. However, when we were developing our SFTP standards, EPA
developed a methodology to assess the emission benefits of insulated
catalysts or other techniques which reduced emissions after the vehicle
soaks between 10 minutes and 12-36 hours. Thus, EPA expects to use this
methodology as a starting point in assessing the benefit of insulated
catalysts and will continue to assess development of options in this
area. Because an insulated catalyst operates essentially like a typical
catalyst, we do not expect that the test procedures for its
certification would differ from those applicable to typical Tier 2
vehicles. The primary difference will be an assessment of its
effectiveness relative to conventional catalyst technology over a range
of vehicle soak times between 10 minutes and 36 hours. Then, it will be
necessary to estimate the average effectiveness in-use relative to
conventional technology using the in-use frequency of vehicle soak
times.
K. Adverse Effects of System Leaks
The standards set forth in today's final rule are very stringent.
They require extremely tight control of air/fuel ratios and also tight
control of the inputs to the catalyst(s). A sealed exhaust system is
crucial to the proper operation and emission control of current
vehicles and even more so to the expected Tier 2 vehicles. Because a
given point in the exhaust system intermittently sees negative
pressure, exhaust leaks can permit air to enter the exhaust system.
Even tiny amounts of air entering this way can have large impacts on
the output of the oxygen sensor. If the output of the oxygen sensor is
affected, then the exhaust output of the cylinders will be affected.
Consequently, an exhaust leak can lead to both excess NO<INF>X</INF>
and NMOG emissions. Air entering through exhaust leaks can also impact
the NO<INF>X</INF> conversion efficiency of catalysts.
In the preamble to the NPRM, we expressed our concerns about the
impact of small exhaust leaks and requested comment on design or on-
board monitoring measures we could finalize to ensure that exhaust
systems were manufactured and installed in such a way that leaks are
prevented. We also asked for comment on whether we should implement a
provision that would require manufacturers to demonstrate through
engineering analysis or design that the possibilities of exhaust leaks
have been addressed.
Manufacturers indicated in their comments that they believe
addressing exhaust leaks is unnecessary. We believe otherwise. Data we
have seen suggest that very large emission effects can occur due to
very small leaks. Consequently, we are finalizing a provision in
today's rule that will require, as part of the certification process,
for manufacturers to indicate that they have conducted an engineering
analysis of the exhaust system. This
[[Page 6799]]
analysis must cover the entire exhaust system, including air injection
systems, from the engine block exhaust manifold gasket surface to a
point beyond the last catalyst or oxygen sensor. This analysis must
determine whether the exhaust system has been designed to facilitate
leak-free assembly, installation, repair and operation for the full
useful life of the vehicle.
With regard to the concept of ``facilitating leak-free repair'', we
intend that manufacturers should ascertain that the exhaust system can
be removed in a dealership or repair shop for repairs to the exhaust
system itself or to other components of the vehicle and be able to be
reassembled and reinstalled in a leak free manner using commonly
available tools. It is not our intention that the concept of
``facilitating leak-free repair'' apply to situations of gross misuse,
tampering or serious vehicle damage.
L. The Future Development of Advanced Technology and the Role of Fuels
The EPA staff will continue to assess the emission control
potential of vehicles powered by technologies such as lean-burn and/or
fuel-efficient technologies, including diesel engines equipped with
advanced aftertreatment systems, gasoline direct injection engines, and
other technologies that show promise for significant advances in fuel
economy and meeting the Tier 2 standards in the post-2004 time frame.
In this assessment, we will maintain a ``systems'' perspective,
considering the progress of advanced vehicle technologies in the
context of the role that sulfur in fuels plays in enabling the
introduction of these advanced technologies or maximizing their
effectiveness.
M. Miscellaneous Provisions
We are finalizing, as proposed, to continue existing emission
standards from Tier 1 and NLEV that apply to cold CO, certification
short testing, refueling, running loss, and highway NO<INF>X</INF>. We
are discontinuing, as proposed, the 50 degree (F) standards and testing
included in the NLEV program. The 50 degree standards are a part of the
NLEV program because that national program adopted California
requirements virtually in their entirety. These standards had not
previously been part of any federal program. We are also discontinuing
idle CO standards for LDTs, based upon comment. These standards are
adequately covered by the certification short test standards.
VI. Gasoline Sulfur Program Compliance and Enforcement Provisions
A. Overview
The gasoline sulfur program promulgated today has many of the same
features as the reformulated gasoline/conventional gasoline (RFG/CG)
program, including refinery averaging, refinery and downstream level
caps, and the generation and use of credits. These features raise
similar compliance issues for both programs. As a result, the
enforcement mechanisms of the gasoline sulfur rule generally track
those of the RFG/CG rule, where applicable. Because low sulfur gasoline
is necessary to avoid significant impairment of Tier 2 motor vehicle
emissions technology, we believe measures are needed to assure that
gasoline meets the standards promulgated in today's rule at the time
the gasoline leaves the refinery gate or is imported, and to assure
that the quality of the gasoline is maintained downstream of the
refinery.
More specifically, today's rule includes the following provisions:
<bullet> Refiners and importers must test each batch of gasoline
produced or imported for sulfur content and maintain testing records
and retain test samples;
<bullet> Refiners and importers must submit reports regarding
compliance with the average standards and credit provisions;
<bullet> Attest procedures \125\ similar to those of the RFG/CG
rule will be applied to the sulfur standards and credit provisions;
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\125\ 40 CFR Part 80, subpart F.
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<bullet> Refiners and importers are prohibited from using, selling
or purchasing invalid sulfur credits, and are required to adjust
compliance calculations if invalid credits have been used, sold or
purchased;
<bullet> Small foreign refiners subject to the small refiner
standards described in section IV.C. above must comply with the rule's
small refiner compliance requirements and other requirements to ensure
the separation of such foreign gasoline from all other gasoline to the
U.S. port of entry; any foreign refiners participating in the early
credit generation program must also meet certain provisions concerning
credit generation, including reporting and recordkeeping;
<bullet> All regulated parties in the gasoline distribution system
who are downstream from the refiner or importer must comply with
downstream sulfur cap standards;
<bullet> Regulated parties are subject to presumptive liability for
violations at a party's own facility and for violations at other
facilities that could have been caused by the regulated party; branded
refiners are subject to liability for violations occurring at branded
facilities.
<bullet> Refiners and distributors may implement downstream quality
assurance testing to assure compliance and to establish an element of
defense against presumptive liability.
As in other fuels programs, the sulfur standards apply to all motor
vehicle fuel that meets the definition of gasoline, except for aviation
fuel and racing gasoline, as was proposed in the NPRM. See 40 CFR
80.2(c). Gasoline sulfur standards apply, however, to gasoline that is
ultimately used in nonroad equipment or marine engines.
As we noted in the NPRM, we are aware there are certain fuels, such
as aviation fuel and racing fuel, that are generally segregated from
gasoline throughout the distribution system. Where such fuels are
segregated from motor vehicle gasoline and not made available for use
in motor vehicles, the fuel is not subject to sulfur rule standards.
However, if such fuels are not segregated throughout the distribution
system, but are used as motor vehicle gasoline or are commingled with
motor vehicle gasoline, then any person who introduces such fuels into
the gasoline distribution system is a refiner, subject to all the
refiner requirements of today's regulations, including registration,
reporting, testing and meeting the national refiner average and cap
standards for the volume of gasoline that person added to the
distribution system. Today's rule adopts the provisions concerning fuel
used for racing vehicles as proposed.
One commenter suggested that racing gasoline or aviation gas should
be allowed to be used as motor vehicle gasoline by downstream parties
so long as the racing gasoline or aviation gas does not exceed the
applicable downstream cap standard. We disagree. Racing gas that meets
the applicable downstream sulfur cap would nevertheless not be subject
to the refinery gate cap or averaging standards, and may not meet such
standards. Allowing such fuels to be distributed for motor vehicle use
would thus circumvent the intent of the rule.
The rule promulgated today clarifies the definition of ``refinery''
at 40 CFR 80.2(h), as was proposed in the NPRM. We received no comments
on this clarifying change. Specifically, section 80.2(h) now provides
that ``refinery''
[[Page 6800]]
means any facility, including a plant, tanker truck or vessel where
gasoline or diesel fuel is produced, including any facility at which
blendstocks are combined to produce gasoline or diesel fuel, or at
which blendstock is added to gasoline or diesel fuel. This is
consistent with all current EPA fuels rules, interpretations, policies
and question and answer documents.
Oxygenate Blenders
In the NPRM we proposed that oxygenate blenders \126\ would not be
subject to the refiner sulfur standard like other blenders, because we
felt it unlikely that oxygenates will have sulfur levels that will
raise the sulfur content of the gasoline. This approach also was
proposed because gasoline is the denaturant normally used to produce
denatured ethanol. However, we received comments that denatured ethanol
may contain as much as 50 ppm sulfur, which could result in significant
increases in sulfur content from ethanol blending alone.
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\126\ The term ``oxygenate blenders'' includes ``ethanol
elnders.''
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While it is true that some of today's gasoline has a sulfur content
as high as 1,000 ppm which if used as an ethanol denaturant results in
ethanol having a sulfur content of 50 ppm, the average sulfur content
of gasoline is about 300 ppm which if used as an ethanol denaturant
results in ethanol with a sulfur content of 15 ppm. In addition, when
the gasoline sulfur standards being promulgated today are in effect,
the average sulfur levels of gasoline will be significantly reduced,
which will further reduce the sulfur content of denatured ethanol to
very low levels. For this reason, we are finalizing the regulation as
proposed that oxygenate blenders are not subject to refiner sulfur
standards.
However, if gasoline blendstock instead of finished gasoline is
used as a denaturant for ethanol the oxygenate blender who adds the
ethanol would become a ``refiner,'' who is required to demonstrate
compliance with the sulfur standards for the denatured ethanol added to
gasoline. This is because the oxygenate blender would be adding a
blendstock along with the ethanol, which subjects the blendstock
blender to refiner standards and requirements. Moreover, if the
blendstock has a high sulfur content the denatured ethanol could have a
sulfur content greater than 30 ppm, or even greater than 80 ppm, which
could make compliance by such a ``refiner'' difficult or impossible. In
addition, as discussed above, in certain cases ethanol is included in
the refinery compliance calculations of the refiner who produced the
gasoline or RBOB with which the ethanol is blended. Refiners assume
this ethanol has no sulfur content, an assumption that could be
incorrect if high sulfur blendstock is used as the denaturant.
For these reasons we believe it is important that ethanol blenders
use denatured ethanol with a sulfur content of 30 ppm or less, which
would occur if the current practice of using finished gasoline as
ethanol denaturant continues. In order to ensure this result, the
regulations include a provision that prohibits ethanol blenders from
using denatured ethanol with a sulfur content greater than 30 ppm. We
believe ethanol blenders can comply with this requirement through
commercial arrangements with their ethanol suppliers, that specify the
maximum sulfur content of denatured ethanol. In addition, ethanol
blenders can assure compliance with this requirement by testing to
determine the sulfur content of denatured ethanol received.
Gasoline Treated as Blendstock (GTAB)
One commenter suggested that the Agency policy under the RFG/CG
rule that allows certain imported gasoline to be treated as a
blendstock by importer-refiners should be applied to today's rule. The
GTAB policy was originally issued in the RFG Question and Answer
document, and was subsequently published as part of a proposed RFG
rulemaking in 1997.\127\ We intend to address GTAB issues in that RFG
rulemaking, including issues regarding compliance with today's rule.
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\127\ Reformulated Gasoline and Anti-dumping Questions and
Answers, (11/12/96); Proposed Rule for Modifications to Standards
and Requirements for Reformulated and Conventional Gasoline; 62 FR
37337 et seq. (July 11, 1997).
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Transmix
We are aware that when gasoline meeting the requirements finalized
in today's rule is transported through pipelines, there will be some
situations where adjacent distillate product in the pipeline will mix
with a portion of the gasoline to create an interface product, commonly
referred to as transmix. This transmix may not be blended into the
diesel fuel because the gasoline in the transmix may result in diesel
fuel performance problems. Historically, this type of transmix product
has either been blended into the gasoline, in limited concentrations,
or the transmix has been separated into its gasoline and distillate
components at a reprocessing plant. However, the practice of blending
the transmix into gasoline may result in violations of the downstream
standards for RFG, and such blending could violate the downstream
sulfur caps finalized in today's rule, because many distillates have a
very high sulfur content. Therefore, we believe regulatory provisions
are needed to resolve these issues. We have not addressed transmix
issues in today's rule because we have already proposed regulations
regarding transmix blending and processing in another rulemaking.\128\
We plan to address transmix issues, including issues regarding
compliance with today's rule, in that rulemaking, which we plan to
finalize in the near future.
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\128\ 62 FR 37337 et seq. (July 11, 1997) (proposed 40 CFR
80.84).
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Inability To Produce Conforming Gasoline in Extraordinary Circumstances
Several commenters suggested the rule should include a provision,
similar to the RFG rule provision at 40 CFR 80.73, to address
situations where, due to extraordinary circumstances, a refiner or
importer cannot produce or distribute conforming gasoline. Section
80.73 applies to refiners, importers and oxygenate blenders. Today's
rule has adopted the provisions of section 80.73 for RFG and CG, for
importers and refiners, but not for oxygenate blenders. This is because
the gasoline sulfur program does not include provisions that would be
expected to require oxygenate blender relief.
In the remainder of this section we discuss enforcement issues
regarding today's rule that are not covered in this Overview or in
section IV.C., above.
B. Requirements for Foreign Refiners and Importers
In the NPRM we proposed that standards for gasoline produced by
foreign refineries that are not subject to small refiner individual
refinery standards would be met by the importer. Standards for gasoline
produced by a foreign refinery subject to an individual sulfur rule
standard would be met by the foreign refinery, with certain limited
exceptions as provided in the foreign refinery provisions. The rule
promulgated today adopts the provisions as proposed, except for several
changes aimed at clarifying the proposed requirements, changes relating
to the temporary relief provision, and changes relating to foreign
refiners' participation in the early credit program. These provisions
are very similar to the foreign refinery provisions of the RFG/CG rule.
[[Page 6801]]
1. Requirements for Foreign Refiners With Individual Refinery Sulfur
Standards or Credit Generation Baselines
Under the RFG/CG rule, EPA promulgated regulations \129\ addressing
the establishment and implementation of individual baselines for CG
produced by certain foreign refiners. The purpose of these regulations
is to ensure the compliance of gasoline supplied from foreign
refineries with individual compliance baselines. It includes
comprehensive controls, requirements and enforcement mechanisms to
monitor the movement of gasoline from the foreign refinery to the U.S.,
to monitor gasoline quality and to provide for enforcement as
necessary.
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\129\ 40 CFR 80.94.
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In the NPRM, we proposed similar requirements for compliance with
the applicable sulfur standards that would apply to any foreign refiner
who demonstrates that it meets the sulfur program's small refiner
criteria. We proposed that foreign refinery baselines would be based on
annual average sulfur levels and the volume of gasoline imported to the
U.S. during the same baseline period as would be applicable to domestic
small refiners. In today's final rule we have also adopted provisions
for foreign refiners to establish baselines to participate in the early
credit generation program, and to request temporary relief. Any foreign
refiner who obtains a foreign refinery gasoline sulfur baseline would
be subject to the same requirements as domestic refiners with
individual refinery baselines under today's rule. Additionally,
provisions similar to the provisions at 40 CFR 80.94 would apply, which
include:
<bullet> Segregating gasoline produced at the small refinery until
it reaches the U.S.;
<bullet> Refinery registration;
<bullet> Controls on product designation;
<bullet> Load port and port of entry testing;
<bullet> Attest requirements; and
<bullet> Requirements regarding bonds and sovereign immunity.
The rationale for these enforcement provisions is discussed more
fully in the Agency's preamble to the final RFG/CG foreign refineries
rule (62 FR 45533 (Aug. 28, 1997)).
Several commenters suggested that the rule should have even
stronger enforcement provisions concerning foreign refiners, including
criminal provisions against foreign individuals who violate the
requirements of the rule. While we agree that the rule's enforcement
provisions pertaining to foreign refiners must be effective, we believe
the proposed enforcement provisions are sufficient, and that attempts
to further strengthen them would not significantly increase their
overall effectiveness. Today's rule imposes various requirements on
foreign refiners not required of domestic refiners, as noted above,
which we believe are more effective for ensuring environmental
compliance than criminal provisions would be for foreign individuals,
in light of the potential difficulties of enforcing sanctions against
foreign individuals. EPA's experience to date with the similar RFG/CG
requirements under section 80.94 of the RFG/CG rule does not indicate
the provisions are inadequate.
Therefore, today's rule generally retains these provisions as
proposed. The final rule makes several technical changes, including
changes regarding baselines for foreign refiners, to be consistent with
the requirements for domestic small refiners and refiners generating
early credits finalized in today's rule. The rule's foreign refiner
enforcement provisions now also apply to foreign refiners participating
in the early credits program, and to the use of credits by foreign
small refiners.
One commenter stated that the language of the proposed
Sec. 80.410(n) would be too broad in that prohibiting any ``person''
from combining certified small foreign refiner gasoline with non-
certified small foreign refiner gasoline or with certified small
foreign refinery gasoline produced at a different refinery would
prohibit even retail level commingling of such products. This was not
intended and today's rule clarifies that such commingling can occur
subsequent to importation.
Under the proposal, when the small refiner standards sunset (and
additionally under today's rule, when the temporary refiner relief
provisions sunset),\130\ all gasoline would be subject to a single
national averaged standard and one national refinery level cap.
Thereafter, standards for all imported gasoline would be met by U.S.
importers. We have retained this provision as proposed. With a single
national average standard and cap standard, gasoline sulfur content can
most readily be monitored at the U.S. importer level, since there will
no longer be a special class of gasoline with different standards that
would need to be monitored.
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\130\ Small refiner and temporary refiner hardship individual
refinery standards sunset January 1, 2008, except for any small
refineries that receive a hardship extension not to exceed two
years.
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2. Requirements for Truck Importers
Today's final rule adopts the proposed requirement for importers to
sample and test each batch of gasoline imported. However, as noted in
the preamble to the NPRM, for parties that import gasoline into the
U.S. by truck, the every-batch testing requirement would include
testing the gasoline in each truck compartment, or if the gasoline is
homogeneous, testing the gasoline in the truck.
In the NPRM we recognized that this every-batch testing requirement
may not be feasible for truckers hauling many small loads of gasoline,
and we therefore proposed a limited alternative approach for truck
importers in lieu of every-batch testing. The proposed alternative
approach is based on the importer meeting the 30 ppm sulfur standard on
a per-gallon basis. Under this alternative approach, the importer would
be allowed to rely on the sulfur results based on sampling and testing
conducted by the operator of the foreign truck loading terminal.
Because, in most cases, the terminal operator will not be subject to
United States laws, we also proposed safeguards intended to ensure that
the gasoline in fact meets the applicable standard. This includes the
requirement that the importer conduct a quality assurance sampling and
testing program independent from the sampling and testing conducted by
the terminal. Under this approach the reporting requirements would be
minimized since no averaging would be required. The environmental
consequences of this approach would be neutral, because by meeting the
30 ppm sulfur standard on an every-gallon basis the standard also would
be met on average.
One commenter stated that the 30 ppm per-gallon standard would be
difficult for truck importers to meet due to the fact that Canadian
terminals may not always have gasoline with a sulfur content no greater
than 30 ppm. The commenter suggested that truck importers be allowed to
rely on testing conducted by the foreign gasoline terminal, as
discussed above, to meet the average and cap standards like other
importers.
We agree that truck importers may have difficulty obtaining
gasoline that meets the 30 ppm sulfur standard on a per-gallon basis.
Under Canadian regulations, Canadian refiners will be subject to a 150
ppm average standard and a 300 ppm cap in 2004, and in 2005 Canadian
refiners will be subject to a 30 ppm average standard and an 80 ppm
[[Page 6802]]
cap.\131\ This means that truck importers should be able to meet the
standards applicable to other importers, including the ultimate average
standard and cap standard under today's rule (30 ppm average and 80 ppm
cap), without great difficulty. However, meeting a per-gallon cap of 30
ppm might be difficult since the sulfur content of gasoline in the
storage tanks of Canadian terminals, like those of U.S. terminals, will
likely exceed 30 ppm at times, even after the 30/80 standards are
implemented. We have concluded that we can address this concern by
providing additional flexibility to truck importers, and still assure
compliance.
---------------------------------------------------------------------------
\131\ Vol. 133 23/6/99 C. Gaz. II, 23 June 99 (pp. 1469 et seq.)
---------------------------------------------------------------------------
While today's rule retains the proposed alternative, with some
modifications, it also provides a second alternative approach. Under
this second approach, truckers are allowed to meet the national average
and cap applicable to other importers, and rely on testing conducted by
the foreign gasoline terminal so long as all the other requirements
applicable to the proposed alternative approach are complied with. In
addition, truckers using this second alternative approach will be
subject to more extensive reporting than required for the proposed
alternative, since the importer will have to demonstrate compliance
with the annual average sulfur standard applicable to other importers.
One commenter urged that truckers should be subject only to the
national downstream cap. We cannot agree to this approach as it is not
environmentally neutral relative to the national standards in effect
for other importers and refiners. If truck importers were required to
meet only the downstream cap, sulfur levels for their imported gasoline
could be substantially higher than for other importers, which could
have a detrimental environmental consequence.
One commenter stated that the 30 ppm per-gallon standard for truck
importers should not go into effect until the 30 ppm standard becomes
the national average standard for refineries and other importers. We
agree. Under today's rule, the per-gallon standards applicable to truck
importers under the proposed alternative will be the same sulfur level
as the sulfur average standard that applies to other importers (in 2004
there is no average standard; however, truck importers using this
alternative compliance approach must meet the corporate pool standard
on a per-gallon basis).\132\ Under the second alternative approach, the
truck importer will be subject to the same average standard and cap
standard applicable to other importers.\133\
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\132\ In 2004, a 120 ppm cap; In 2005 and beyond, a 30 ppm cap.
See Table IV.C.-1.
\133\ In 2004, a 120 ppm average standard and a 300 ppm cap; In
2005, a 30 ppm average standard, a corporate pool average no greater
than 90 ppm, and a 300 ppm cap; In 2006 and beyond, a 30 ppm average
standard and a 80 ppm cap. See Table IV.C.-1.
---------------------------------------------------------------------------
Similar provisions as provided above apply to truck importers for
gasoline subject to the geographic phase-in area (GPA) standards (see
section IV.C. of this preamble for a discussion of GPA standards).
However, because of the small volumes of truck-imported gasoline, and
the consequent difficulty in meeting corporate pool averages for a
trucker who imports gasoline into both the GPA and areas outside the
GPA, today's rule requires that for truck importers using the averaging
option, the corporate pool average does not have to be met. The 150 ppm
average standard and the 300 ppm cap standard apply to gasoline
imported by truck into the GPA in 2004 through 2006. For truck
importers meeting the per-gallon standard option for gasoline imported
into the GPA, the per-gallon standards are 150 ppm for 2004 through
2006.
Truck Import of Foreign Small Refiner Gasoline
The NPRM addressed issues associated with gasoline produced by a
foreign small refinery with an individual baseline and certified as
subject to the refinery's individual interim standard (S-FRGAS), and
imported by truck. The proposed requirements for S-FRGAS included
segregating the gasoline from all other gasoline from the refinery gate
to the U.S., so that compliance with standards can be tracked. For
ordinary, non-truck importers, each batch of certified S-FRGAS must be
tested at the load port and port of entry. Today's rule finalizes these
proposed requirements for S-FRGAS.
However, in the case of gasoline imported by truck, the NPRM
acknowledged that the testing and other procedures proposed for
certified S-FRGAS may not be feasible. As a result, we proposed an
alternative to the requirement for testing every truckload of imported
certified S-FRGAS, and to other importer requirements. This alternative
approach includes a requirement that small foreign refiners producing
any S-FRGAS that will be imported by truck submit a petition to EPA
that includes a plan which is designed to ensure that certified S-FRGAS
remains segregated from all other gasoline from the refinery to the
U.S. Rather than specifying the precise requirements of such a plan in
the regulations, we proposed to allow the refiner to develop its own
procedures for ensuring that S-FRGAS remains segregated. However, the
plan must contain certain elements, such as product transfer documents
which identify the origin of the gasoline and prohibit its commingling
with any product other than certified S-FRGAS from that refinery.
This approach also requires the refiner of such truck-imported
gasoline to receive and maintain all such product shipment documents,
including U.S. import documents, for five years and review these to
ensure that segregation is maintained until reaching the U.S. To ensure
that refiners conduct this review, we proposed to require the refiner's
plan to include attest audit procedures to be conducted annually by an
independent third party.
We received no comments on this proposal for ensuring the integrity
of S-FRGAS imported by truck. Today's final rule adopts the petitioning
provision to permit alternative segregation procedures for S-FRGAS
imported by truck as proposed since we continue to believe that it will
provide flexibility to foreign refiners and to importers and will
adequately assure enforceability.
C. What Standards and Requirements Apply Downstream?
We proposed per-gallon cap standards that would apply to all
parties in the distribution system downstream of the refinery and
importer level, including pipelines, terminals, oxygenate blenders,
distributors, carriers, retailers and wholesale purchaser-consumers. We
believe that downstream cap standards and compliance monitoring based
on downstream standards are needed to ensure that the sulfur level of
gasoline remains below the cap level when dispensed for use in motor
vehicles, to avoid adverse emissions consequences that would be caused
by the use of gasoline having a sulfur content above the cap level. The
following discussion addresses downstream standards generally,
downstream standards and requirements for gasoline produced by
refineries subject to standards under Sec. 80.240 and 80.270, and
downstream standards and requirements for gasoline produced or imported
for the geographic phase-in area (GPA).
[[Page 6803]]
Determination of Downstream Cap Standards
We proposed that the downstream standards would be more lenient
than the refinery-level cap standards so that refiners and importers
can produce gasoline that equals the refinery-level cap standard. We
did so because it has been EPA's experience that if a refiner produces
gasoline that equals, or almost equals a standard, that gasoline may be
shown to violate the standard when subsequently tested at a location
downstream of the refinery due to testing variability. As a result,
parties downstream of the refinery (primarily pipelines) set commercial
specifications for the quality of the gasoline they will accept that
are more stringent than the standard that applies to the downstream
party. This, in effect, forces refiners to produce gasoline that is
``cleaner'' than the refinery-level standard.
In other fuels programs (for example, the benzene per-gallon
standard for RFG) we resolved this concern by announcing enforcement
tolerances for fuels standards that apply downstream of the refinery-
level, thereby reducing the need for pipelines to set specifications
more stringent than the refinery level standards. We believe that
having more lenient downstream standards will have the same effect as
enforcement tolerances.
In the NPRM we proposed that the values of the downstream cap
standards would reflect the testing variability that could reasonably
be expected when different laboratories test gasoline for sulfur
content; that is, lab-to-lab variability, or reproducibility. Industry
commenters supported this approach, and today's rule adopts this
approach. For gasoline subject to the 80 ppm refinery-level sulfur cap,
the downstream maximum standard is 95 ppm. This difference reflects the
reproducibility established by the American Society for Testing and
Materials (ASTM).\134\ For gasoline subject to refinery-level sulfur
caps higher than 80 ppm, which will be the case for gasoline produced
before 2006 and for gasoline produced by certain small refineries
through 2007, the downstream cap is similarly established by using ASTM
reproducibility data. The national downstream cap is 378 in 2004, when
the refinery level cap can be as high as 350 ppm. The national
downstream cap in 326 in 2005, when the refinery level cap is 300.
---------------------------------------------------------------------------
\134\ ASTM standard method D 2622-98, entitled `Standard Test
Method for Sulfur in Petroleum Products by Wavelength Dispersive X-
ray Fluorescence Spectrometry.''
---------------------------------------------------------------------------
Because these downstream caps are based on sulfur test
reproducibility, we intend to amend the rule in the future if
improvements in test precision are made for the designated method. We
may also consider amending the rule to make some other method the
designated method if a more precise method is available in the future.
The Proposed Downstream Standards Compliance Scheme
Under the proposal, if gasoline produced by a small refiner with a
less stringent cap standard is mixed in the distribution system with
gasoline subject to the national cap standard, the entire mixture would
then be subject to the higher cap standard, even though most of the
gasoline, at the refinery level, would be subject to the more stringent
national cap standard. We proposed that during the period that small
refinery individual standards are in effect, for gasoline that is
comprised, in whole or in part, of small refiner gasoline with a higher
sulfur cap standard than the national cap standard, product transfer
documents (PTDs) would specify that the gasoline is small refiner
gasoline and the level of the downstream cap applicable to the
gasoline.
The purpose of the proposed provisions was to make it possible to
determine the standard that applies to any gasoline downstream of the
refinery. If the gasoline contains no small refiner gasoline, the
downstream standard would be based on the national cap. If the gasoline
is comprised, in whole or in part, of small refiner gasoline subject to
a less stringent cap standard, the downstream standard would be based
on this less stringent cap standard. As gasoline is mixed and remixed
in the fungible distribution system, the percentage of gasoline that is
small refinery gasoline will progressively diminish until the fungibly
mixed gasoline meets the national downstream cap. Therefore, we
proposed in the NPRM that a downstream party may no longer classify
gasoline as containing small refiner gasoline if a test result shows
the sulfur content of the gasoline is below the applicable national
(i.e., not small refiner) downstream cap.
Several commenters suggested that this tracking scheme would be
unworkable. Some of these comments were based on the belief that the
proposal intended to require segregation of the small refiner gasoline
through the distribution system. The proposal was not intended to
require that small refiner gasoline must be segregated, and under
today's final rule there is no requirement that small refiner gasoline
must be segregated from gasoline produced by other refiners. Some
commenters also believed that testing by downstream parties would be
required under the proposed rule. These commenters were concerned that
a downstream testing requirement could be costly and could delay
distribution of gasoline. This latter point is addressed later in this
discussion. Some commenters stated that the proposed PTD provisions of
the downstream enforcement scheme were too complex and that some means
other than changing PTD designations should be found to track small
refiner gasoline.
Other commenters, including automobile manufacturer trade
associations, stated they believed that EPA enforcement and testing
downstream of the refinery is necessary to assure that gasoline
complies with standards at the retail gasoline pump.
We have carefully considered the comments and we have concluded
that the tracking scheme as proposed would not be effective because
most pipeline shipments are expected to include some small refiner
gasoline (although the amount of small refiner gasoline may comprise
less than 1% of the shipment) and therefore, most of the gasoline in
the nation might be classified as small refiner gasoline, even though
only a small fraction of the supply will actually be small refiner
gasoline. Therefore, a downstream cap much less stringent than the
national downstream cap would attach to most gasoline produced to meet
the national refinery standards, and the scheme would not be effective
in monitoring whether the quality of most gasoline is maintained after
it enters the gasoline distribution system.
The proposed scheme could lead to other unintended results. The
gasolines contained in a fungible mixture in the distribution system
may not be fully mixed and homogenous. As a result, a distinct,
unmixed, portion of gasoline within a fungible mixture could be small
refiner gasoline with a sulfur content above the national downstream
cap, while other parts of the fungible mixture would meet the national
downstream cap. This is especially true for fungible mixtures in
pipelines and could also be true for gasoline in storage tanks. If a
test result for a sample collected from part of such a fungible mixture
in a pipeline shows compliance with the national downstream cap, under
the proposed rule the entire mixture would become subject to the
national downstream cap, and the pipeline PTDs could not classify the
gasoline as small refiner gasoline. Thus,
[[Page 6804]]
under the proposal, parties downstream of the pipeline could be subject
to liability because they might receive small refiner gasoline not
meeting the national standard even where a pipeline PTD does not
represent that the gasoline is small refiner gasoline. That was not
intended by the proposal.
Because of these difficulties, we concluded that the proposed
scheme must be modified to address these concerns, in order for there
to be effective enforcement of the downstream standards. We are
concerned that the quality of gasoline will be affected downstream of
the refinery. Gasoline may be contaminated with high sulfur blendstocks
or other high sulfur products such as distillates after it leaves the
refinery gate. There is likely to be an economic incentive for some
downstream parties to sell or use gasoline or blendstocks that have a
higher sulfur content than the national downstream standard. The
inability to monitor downstream compliance would result in
environmental degradation that is not intended by the rule, and in an
inability to assure a level playing field for all parties in the
gasoline distribution industry.
Tracking Gasoline Downstream of the Refinery
We believe that an effective downstream compliance and enforcement
scheme is necessary in order to achieve the full emissions reduction
benefits of the rule. Today's rule modifies the proposed tracking
scheme so that compliance with the program can be monitored.
Under today's rule, all gasoline downstream of the refiner or
importer is subject to the national downstream standard unless a
different downstream standard, based on the highest sulfur content of
any small refiner/temporary refiner relief gasoline in the gasoline
mixture (as determined by the small refiners' batch testing), is
supported by PTDs and a test result confirming the presence of small
refiner/temporary refiner relief gasoline. The test result must be for
gasoline sampled from the downstream facility classifying the gasoline
as small refiner gasoline, unless the facility is a trucker, retailer
or wholesale purchaser-consumer. We have concluded that this
requirement is necessary to monitor compliance with the downstream
standards during the period that small refiner/temporary refiner relief
standards are in effect, because the vast majority of the gasoline
transported by pipelines will be gasoline produced to comply with the
national cap,\135\ even though most of those pipeline shipments will be
classified as small refiner gasoline.\136\
---------------------------------------------------------------------------
\135\ For example, most pipeline shipments are expected to
contain small refiner gasoline in the two U.S. pipelines that carry
the highest volume of gasoline. However, in most shipments the small
refiner gasoline is expected to account for substantially less than
5% of the total volume of gasoline in the shipment.
\136\ For purposes of this discussion, ``small refiner gasolne''
includes any gasoline from a refiner to whom EPA grants relief based
on a showing of extreme hardship.
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We believe that the ability to track small refiner gasoline is made
even more important due to the geographic phase-in area (GPA) gasoline
provisions finalized today.\137\ GPA gasoline is subject to less
stringent refiner/importer standards than gasoline produced for use in
other parts of the country. Therefore, its use is limited to the GPA
states. However, it may be produced or imported at any location in the
country before it is transported for use in the GPA. EPA would have
little ability to assure GPA-designated gasoline is only being used in
the GPA if it cannot determine if gasoline at a downstream location
outside the GPA that exceeds the applicable downstream cap for non-
small refiner gasoline, is in fact small refiner gasoline or if it may
include gasoline that was designated for use in the GPA but has been
diverted for use elsewhere. The tracking requirements for small refiner
gasoline will help us to make that determination.
---------------------------------------------------------------------------
\137\ See section IV.C. of this preamble for refiner/importer
standards and the discussion below regarding downstream compliance
and enforcement provisions.
---------------------------------------------------------------------------
The only parties required to perform testing in order to
demonstrate that a shipment, or tank, of gasoline contains small
refiner gasoline are gasoline pipelines and terminals. Where a terminal
properly classifies gasoline in its storage tank as small refiner
gasoline, and subsequently receives a load of gasoline into that tank,
it may not continue to classify the gasoline as small refiner gasoline
unless the tank is sampled, and a test demonstrates that the tank still
contains small refiner gasoline and the gasoline sulfur content exceeds
the national refinery level cap. In 2004 the test result would have to
exceed 350 ppm; in 2005, 300 ppm; and starting with 2006, 80 ppm. In
the GPA, the test result would have to exceed 350 ppm in 2004, and 300
ppm in 2005 and 2006.
We have concluded that the pipeline and terminal testing provisions
are necessary for effective enforcement. We believe that terminals and
pipelines will be able to perform sampling and testing that will enable
them to identify the presence of small refiner gasoline in a cost-
effective manner. These parties have knowledge regarding the mixing of
gasoline as it moves from the pipeline and into the terminal tank, and
knowledge of the distribution system, that will enable them to make
judgments regarding the extent of testing that may be needed to
demonstrate whether gasoline meets the national downstream cap.
Further, a terminal operator may take additional tests if it believes a
tank may contain a stratified portion of small refiner gasoline,
despite a test result showing the tank complies with the national
downstream cap.
Many terminals may have sufficient reason to believe they are
receiving only gasoline meeting the national cap such that they will
not normally test each receipt of gasoline. Additionally, even for
terminals who receive small refiner gasoline, we do not believe the
sampling and testing will be burdensome. This is partly because many
terminals already conduct periodic sampling, or even sampling after
every delivery of gasoline into storage tanks, at least in the summer
VOC or RVP season, to test gasoline for various parameters, which may
already include sulfur testing in RFG areas. Field test instruments
already exist that are adequate for this testing in 2004 and 2005 when
the national downstream cap is 378 ppm and 326 ppm, respectively.
Moreover, we believe that because of today's rule, better field test
instruments for sulfur analysis at lower levels are likely to be
developed in the next few years. Therefore, it will not be necessary
for quality assurance samples to be sent to a laboratory for testing.
Thus, we do not believe shipments will be held up while terminals await
a test result. We also believe that it is likely that these instruments
will be available for a cost that will be far less than most laboratory
instruments available today.
Under today's rule, retailers are not required to conduct testing.
The retailer can demonstrate that the gasoline is properly designated
small refiner gasoline subject to a less stringent downstream standard
by maintaining PTDs from its suppliers that demonstrate a terminal
classified gasoline supplied to the retailer's storage tank as small
refiner gasoline.
Downstream Standards and Requirements for GPA Gasoline
Consistent with the way today's rule sets downstream sulfur
standards for other gasoline, the GPA program downstream standard is
determined by adding the ASTM reproducibility applicable to the
refinery level sulfur
[[Page 6805]]
cap to that refinery level cap, which for GPA gasoline is as high as
350 ppm in 2004, and 300 ppm in 2005 and 2006. This results in
downstream standards for GPA gasoline of 378 ppm in 2004, and 326 ppm
in 2005 and 2006.
Because GPA gasoline must be used only within the GPA states,\138\
today's rule requires that refiners and importers producing or
importing gasoline subject to the GPA standards must designate each
such batch of gasoline as GPA gasoline and segregate such batches from
all other gasoline. Product transfer documents must identify the
gasoline as GPA gasoline so that all downstream parties will be aware
that it must be sold or distributed for use only in the GPA.
---------------------------------------------------------------------------
\138\ As stated in section IV.C. of this preamble, the GPA
states are Alaska, Idaho, Montana, North Dakota, Wyoming, Utah,
Colorado and New Mexico.
---------------------------------------------------------------------------
Gasoline produced for use in all areas of the country outside the
GPA may be sold for use in the GPA, including gasoline subject to small
refiner standards under section 80.240 of today's rule.
Where GPA gasoline is commingled with other gasoline, the
commingled gasoline must be classified as GPA gasoline and used only in
the GPA states. Where GPA gasoline is commingled with S-RGAS, the
applicable downstream sulfur standard for that gasoline is the greater
of the GPA downstream standard or the applicable small refiner/
temporary refiner relief standard as determined under section 80.210 of
the rule.
Lead-Time for Downstream Compliance With New Standards
Some commenters stated that there should be a lead-time of several
months between the implementation date of a new refinery level sulfur
standard and the implementation date of the corresponding downstream
standard. Based on our experience with other fuels programs, we believe
that a one-month lead time will be adequate for gasoline at the
terminal level to meet new standards. An additional one month for
retailers will give them ample time to comply. Therefore, under today's
rule, the 378 ppm downstream sulfur standard (or any applicable small
refiner downstream cap standard) is effective February 1, 2004 at the
terminal level and March 1, 2004 at the retail level. The 326 ppm
downstream sulfur standard is effective February 1, 2005 at the
terminal level and March 1, 2005 at the retail level. The 95 ppm
downstream standard is effective February 1, 2006 at the terminal level
and March 1, 2006 at the retail level (or February 1, 2007, and March
1, 2007, respectively, in the case of gasoline at facilities in the
GPA).
Retail Gasoline Pump Labeling
EPA believes gasoline advertised as being ``low sulfur gasoline''
when sold at retail outlets should have a sulfur content of no more
than 95 ppm because this is the maximum sulfur level of gasoline at
retail outlets that would protect the emission controls of Tier 2
vehicles. We are stating this to inform refiners and other regulated
parties, when making advertisement decisions regarding gasoline, that
it is EPA's position that effective January 1, 2004, if any retailer
represents that gasoline is low sulfur gasoline, or representations to
the same effect, the gasoline sulfur content should be no greater than
95 ppm.
D. Testing and Sampling Methods and Requirements
1. Test Method for Sulfur in Gasoline
We proposed ASTM standard method D 2622-98, ``Standard Test Method
for Sulfur in Petroleum Products by Wavelength Dispersive X-ray
Fluorescence Spectrometry,'' as the primary method for testing sulfur
in gasoline by refiners and importers. This is the designated method
under the RFG/CG rule.\139\ We also requested comment on adopting other
methods as the primary method, in particular, ASTM method D 5453-93,
``Standard Test Method for Determination of Total Sulfur in Light
Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence,'' and
ASTM D 4045, ``Standard Test Method for Sulfur in Petroleum Products by
Hydrogenolysis and Rateometric Colorimetry,'' which is used under the
California fuels program for sulfur levels below 10 ppm. We also
proposed ASTM D 5453 as an alternative method for determining the
sulfur content of gasoline and we requested comment on this proposal.
---------------------------------------------------------------------------
\139\ See 40 CFR 80.46(a). Today's rule updates the former
designated test method, ASTM D 2622-94.
---------------------------------------------------------------------------
Most comments supported the continued use of ASTM D 2622 as the
designated method for testing sulfur in gasoline under the various
fuels rules, including today's rule. Commenters indicated that most
refineries outside of California are currently using ASTM D 2622. Under
the California fuels regulations, California refineries currently use
ASTM D 5453, as well as ASTM D 2622 and ASTM D 4045. Comments were
generally favorable to the proposed use of ASTM D 5453 as an alternate
method. However, one California refinery, an automobile manufacturers
association and a manufacturer of analytical equipment stated that ASTM
D 5453 should be the primary method, primarily due to its greater
precision at low sulfur levels. Favorable comments were received to the
use of ASTM D 4045, especially for gasoline sulfur content of 10 ppm or
less. One commenter suggested that ASTM D 5623-94 should be allowed;
one commenter suggested that ASTM D 3120 should be allowed, and one
commenter suggested that ASTM D 6428 should be allowed. Several
commenters stated that we should utilize a performance based criteria
system to determine what test methods can be used.
We have considered the comments carefully. We believe there are a
number of test methods for determining the sulfur content of gasoline
that may eventually be shown to be as good as, or better than, ASTM D
2622. We also considered that the Agency is likely to issue a proposed
rulemaking for a performance-based test method approach that would
apply to motor vehicle fuel parameters. This rule, once promulgated,
would set forth criteria for determining whether an alternative
analytical test method could be used instead of the designated
analytical test method for a given fuel parameter and would set forth
criteria for correlating alternative analytical test methods to the
designated analytical test method.
We believe it is appropriate that alternate analytical methods
should be qualified and correlated to the regulatory method according
to standardized criteria. Today's rule therefore provides that ASTM D
2622, the recognized standard analytical method for determining sulfur
in gasoline, is the sole regulatory method, anticipating that a
performance-based testing rule may be issued before 2004, and that
under its terms anyone will be able to qualify and correlate additional
testing methods. We do not believe this will result in undue hardship
for several reasons. First, our current fuels rules already provide
that ASTM D 2622 is the sole regulatory method for determining the
sulfur content of gasoline. Second, California refiners currently using
ASTM D 5453 or ASTM D 4045 will not face any hardship because today's
rule allows the use of approved California test methods by California
refiners.\140\ Third, today's rule allows continued use of composite
samples for sulfur testing for CG during the period of early credit
generation, and therefore refiners currently using outside labs to test
composite samples,
[[Page 6806]]
but who may elect to conduct testing in-house when the every-batch
sulfur testing requirement is implemented, will not need to determine
whether a less expensive alternative to ASTM D 2622 is available for
several years. Last, if a performance-based test method rule is not
issued by the Agency in the near future, then we may reconsider this
issue in a subsequent rulemaking.
---------------------------------------------------------------------------
\140\ See preamble discussion in section VI.E., below.
---------------------------------------------------------------------------
We also believe that a standardized approach for determining the
appropriateness of alternate test methods, correlation methodology and
quality control criteria for alternate test methods would be the most
fair approach to the test equipment manufacturers and to the purchasers
of testing equipment. It should result in a level playing field for
competition among manufacturers of test equipment. We already know that
ASTM D 5453 can be purchased for about half the price of ASTM D 2622
equipment, and competition may result in even less expensive equipment.
Some commenters suggested that where a refiner or importer uses
ASTM D 2622 to test gasoline, and where the test result is less than 10
ppm, the refiner or importer should be able to report a test result of
zero or perhaps use a default value of 5 ppm. This sort of approach has
been allowed under the RFG and Anti-dumping Question and Answer
Document. However, we disagree with the commenters that this practice
is appropriate under the sulfur rule. Under the sulfur rule, with a
refiner average standard of 30 ppm, it is important whether a bias is
consistently drawn in favor of zero ppm as opposed to 10 ppm. This
could artificially increase the number of credits earned or could allow
more batches to be produced by the refiner that are near the 80 ppm
cap. We believe that any imprecision of sulfur values derived from
analysis using ASTM D 2622, will, over the course of numerous batches,
average out to near zero. Further, we believe that the precision of
ASTM D 2622 is likely to be improved by 2004. Also, by 2004 there may
be other methods that will be shown to be precise at low sulfur levels
that may be made available for use under a performance-based test
method rule. Under today's rule the refiner or importer must report the
test result that the test method provides, so long as the result is not
less than zero (in which case a result of zero would be reported).
If alternative methods are ultimately made available for use under
a performance based rule, refiners and importers who are producing or
importing gasoline with low levels of sulfur may desire to use an
alternative test method for low sulfur levels, especially if ASTM D
2622 is less precise at such levels. Under today's rule, if any
approved alternative method is used for this purpose, a party could not
choose to use the test result from ASTM D 2622 when its result is
lower, and the test result from the alternative method when its result
is lower. For any alternative test method that is eventually approved,
if the party uses it for a certain range of sulfur concentrations, and
ASTM D 2622 for another range, it must be consistent in such use. For
example, if the alternate method were used for test results below 10
ppm, its result would always have to be used for sulfur levels below 10
ppm and ASTM D 2622 would always have to be used for sulfur levels
greater than 10 ppm.
2. Test Method for Sulfur in Butane
We proposed the use of ASTM standard test method D 5623-94 \141\ as
the designated method for testing the sulfur content of butane and
requested comment on whether this method should be the designated
method. Although some butane suppliers or refiners currently use this
method, several commenters stated that many refiners do not have ready
access to ASTM D 5623 and that it is not necessarily the most precise
method for determination of low levels of sulfur in butane. Commenters
suggested at least three other methods are equal to ASTM D 5623. These
are ASTM D 2784, ASTM D 4468, and ASTM D 3246.\142\ One commenter also
suggested that ASTM D 3227-92,\143\ should be allowed. Several
commenters requested that EPA at least allow alternative test methods
for quality assurance testing.
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\141\ ASTM D 5623, entitled ``Standard Test Method for Sulfur
Compounds in Light Petroleum Liquids by Gas Chromatography and
Sulfur Selective Detection.''
\142\ ASTM D 2784, entitled ``Standard Test Method for Sulfur in
liquefied Petroleum Gases''; ASTM D 4468-85(1995), entitled
``Standard Test Method for Total Sulfur in Gaseous Fuels by
Hydrogenolysis and Rateometric Colorimetry''; and ASTM D 3246-96,
entitled ``Standard Test Method for Sulfur in Petroleum Gas by
Oxidative Microcoulometry.''
\143\ ASTM D 3227, entitled ``Mercaptan sulfur in Gasoline,
Kerosine, Aviation Turbine, and Distillate Fuels''. The commenter
suggested it should be allowed with the use of the x-ray finish.
---------------------------------------------------------------------------
We have reviewed the suitability of ASTM D 5623 and agree that it
is not the best method for testing for sulfur content in butane. ASTM D
5623 measures sulfur compounds rather than total elemental sulfur, and
the current ASTM 5623 method is specified for liquid fuels, not gaseous
fuels.
ASTM D 2784 does not seem to be a better method than ASTM D 5623.
Commenters stated that ASTM D 2784 is not the most precise method and
that it is not widely used. We believe there may be some difficulty in
even obtaining the apparatus for ASTM D 2784. ASTM D 3227 is not
appropriate since it is designed for measuring a single sulfur
compound, and it is currently designated for testing liquid samples.
We believe that ASTM D 4468 appears to be a good method for testing
butane for sulfur levels below 20 ppm. However, dilution would be
necessary to test for sulfur levels above 20 ppm. This may be
problematical, since it may be difficult to dilute a gaseous fuel. We
expect that under today's rule, butane being tested will frequently
have sulfur content in excess of 20 ppm. Several other methods exist
that might work well for testing for sulfur content of gaseous fuels,
but their current scope does not include determination of sulfur in
gaseous fuels.
ASTM D 3246-96, which was suggested by API and NPRA as a suitable
method, is an appropriate method for measuring gaseous compounds and
provides test results for total elemental sulfur. Its range is 1.5 to
100 ppm, which is ideal for testing for the alternative 30 ppm butane
sulfur standard applicable to butane blenders promulgated in today's
rule.\144\
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\144\ Discussed in section VI.D.3.
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After considering the strengths and weaknesses of all the available
options we believe ASTM D 3246 is the best currently-available method.
Therefore, today's rule makes ASTM D 3246 the designated method for
testing the sulfur content of butane or other gaseous blendstocks. As
discussed above, we anticipate that a performance-based test method
rule for motor vehicle fuel parameters may be promulgated before 2004,
and that the efficacy of other methods would be demonstrable under that
rule. However, if that is not the case, the Agency may reconsider the
issue of appropriate alternate test methods in a future rulemaking.
3. Quality Assurance Testing
Several commenters urged that alternate test methods be allowed for
quality assurance test purposes. Under today's rule, the use of
alternate test methods for quality assurance testing for purposes of
establishing a defense to liability, for butane quality assurance
testing under section 80.340(b)(4), and for determination of whether
gasoline is small refiner gasoline, is allowed, so long as the
alternate test method is correlated to the regulatory test method, the
method is ASTM approved, and the
[[Page 6807]]
protocols under the method are followed. However, the regulatory method
is required for the truck importer quality assurance testing under
section 80.350(c).
4. Requirement To Test Every Batch of Gasoline Produced or Imported
We proposed in the NPRM that refiners and importers \145\ would be
required to sample each batch of gasoline produced or imported and
perform a test on each sample to determine the sulfur content prior to
the gasoline leaving the refinery gate or importer facility. We
received comments on several aspects of this proposed requirement.
---------------------------------------------------------------------------
\145\ Except for certain truck importers, as noted above.
---------------------------------------------------------------------------
Several commenters urged that we continue to allow composite
sampling and testing for sulfur. Some refiners commented that the
requirement to test each batch would raise testing costs. However, one
refiner commented that every-batch testing for sulfur would not be a
substantial burden so long as every-batch testing for other CG
parameters is not required.\146\ This commenter stated that testing for
sulfur content is much less complex than testing for certain other CG
parameters.
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\146\ As noted above, we are not requiring every batch testing
for CG parameters other than sulfur.
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We believe that with a refinery gate sulfur cap combined with
refinery averaged standards, there is no realistic alternative to
every-batch testing. The Agency has no way to know whether a composite
sample that is tested and found to meet the applicable refinery cap
included a sample from an individual batch of gasoline that was
introduced into commerce that exceeded the cap by a factor of 2 or 3.
Further, we believe that with averaged standards for refiners and
importers, and with multiple cap standards in effect during the phase-
in period, monitoring compliance without every-batch testing would be
impossible even if we could somehow be assured that no individual batch
significantly exceeded the applicable refinery level cap.
We realize that there will be an additional cost associated with
testing every batch of CG--for sulfur content (this is already required
for RFG). However, we believe less expensive test methods for sulfur
content already exist, and may continue to be developed, that will
likely be acceptable as alternative methods in the future, as discussed
above. Therefore, today's rule retains the requirement for every-batch
testing. Under today's final rule, the test results for each batch of
gasoline will be used to determine compliance with the applicable
refiner/importer cap standard and to calculate the refiner's or
importer's annual average sulfur level. Any batch of gasoline that
exceeds the applicable sulfur cap cannot be distributed or sold in the
U.S. (unless it is exempted from the standards under today's rule, as
described in section VI.G., below).
Refiners who use computerized in-line blending methods objected to
the proposed requirement for a batch test before the gasoline is
released from the refinery. These commenters stated that refiners using
the sophisticated in-line blending practice cannot produce a complete
batch test until a portion of the batch is already past the refinery
gate. These commenters did not urge that we eliminate the requirement
for every-batch testing, but urged that the sulfur rule adopt the RFG
rule provisions for in-line blending found at 40 CFR 80.65(f)(4), for
both RFG and CG.
We believe that the importance of assuring compliance with the
refinery level cap is such that the rule must generally require that
gasoline must be tested for sulfur content before it leaves the
refinery. Based on experience under the RFG rule, we do not believe
that the requirement to test each batch before it is released will
substantially increase the cost of testing or cause delays in
shipments.
However, today's rule recognizes the unique circumstances involved
in computerized in-line blending. We believe that with appropriate
safeguards, compliance with sulfur standards for gasoline produced by
refineries using in-line blending can be assured. Therefore, today's
rule incorporates the RFG rule provisions for in-line blending at 40
CFR 80.65(f)(4). Such provisions will be applicable to RFG and CG.
However, refineries presently having an in-line blending waiver will be
asked to submit additional information under the auditing procedures
included in approvals of in-line blending petitions already in place.
We will contact individual holders of in-line blending approvals to
request information on how sulfur is monitored and how streams of
gasoline are distributed in the in-line blending process. If we cannot
conclude that the monitoring procedures will assure compliance with
sulfur standards, we will revoke the in-line blending approval for that
purpose. We believe it is important to ensure that the in-line analyzer
technology and the refiner's methodology and procedures are sufficient
for the gasoline sulfur levels the refinery will have after this rule
is implemented, for both RFG and CG.
Several commenters stated that the proposed rule's requirement to
test every batch of CG for sulfur is unnecessary during the period of
early credit generation because there is no cap standard in effect
during this period, even for those refiners generating credits. We
agree that every-batch testing is not essential for CG until the
refinery gate per-gallon cap standards go into effect. Thus, today's
final rule allows composite sample testing for CG to continue during
the period of early credits generation, until January 1, 2004, when a
cap standard for sulfur is first imposed on gasoline.
5. Exceptions to the Every-Batch Testing Requirement
Under the RFG rule, refiners who blend butane or other blendstocks
to previously certified gasoline (PCG) must determine the volume and
parameter values of the blendstock, including sulfur content, by
testing the gasoline before and after blending, and calculating the
properties of the blendstock by subtracting the volume and parameter
values of the PCG. For CG only, under certain conditions, we have
allowed butane blenders to use the parameter specifications of butane
as tested by the butane producer. We have allowed this alternative to
every-batch testing because of the costs of testing each load of
butane. We proposed a similar alternative to every-batch testing for
butane blenders in the NPRM, which allows butane blenders to use the
sulfur test result of their suppliers, if the butane contains no more
than 30 ppm sulfur and if the butane blender undertakes a quality
assurance program of periodic sampling and testing to ensure that the
supplier's sampling and testing is accurate.
We also proposed to allow refiners that blend other blendstocks
into PCG to meet an alternative testing requirement in lieu of testing
every batch of gasoline. Provided that the refiner's test result for
the sulfur content of each of the blendstocks is less than the national
refinery level per-gallon cap standard, a refiner can sample and test
each blendstock when received at the refinery, and treat each
blendstock receipt as a separate batch for purposes of compliance
calculations for the annual average sulfur standard.
Today's rule adopts these provisions. Several commenters urged us
to delay the 30 ppm per-gallon cap standard until other refiners must
meet a 30 ppm average standard. The proposed 30 ppm per gallon standard
was intended to be environmentally neutral in relation to
[[Page 6808]]
the standard applicable to other refiners. Therefore, today's final
rule makes clear that for the alternative compliance approach for
butane blenders, the 30 ppm per-gallon cap is not applicable until
January 1, 2005. The per-gallon cap starting January 1, 2004 is 120
ppm.\147\ For GPA gasoline the per-gallon cap under this alternative
compliance option is 150 ppm in 2004 through 2006.
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\147\ See Table IV.C.-1.
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6. Sampling Methods
Sampling methods apply to all parties who conduct sampling and
testing under the rule. We proposed to require the use of sampling
methods that were proposed in the July 11, 1997 Federal Register notice
for the RFG/CG rule (62 FR 37338, at 37341-37342, 37375-37376). These
sampling methods include ASTM D 4057-95 (manual sampling), ASTM D 4177-
95 (automatic sampling from pipelines/in-line blending), and ASTM D
5842 (this sampling method is primarily concerned with sampling where
gasoline volatility is going to be tested, but it would also be an
appropriate sampling method to use when testing for sulfur). There were
no adverse comments to the proposed sampling provisions. Today's rule
adopts the methods as proposed.
7. Gasoline Sample Retention Requirements
In the NPRM, we proposed a refiner and importer (collectively
referred to in this section as ``refiner'') sampling and testing
program to establish the sulfur compliance of each batch of gasoline
produced or imported. We were aware that there were possible drawbacks
to a self-testing scheme. For example, a party might sample or test
gasoline in a manner that is inconsistent with the required procedures,
or employees might inaccurately record the test results by mistake or
otherwise. Parties might also attempt to conceal a discovered violation
or to save money by not correcting a violation.
To address our concerns about self-testing, we considered an
alternative option of requiring independent sampling and testing for
all gasoline, including conventional gasoline. We did not propose this
requirement for independent sampling and testing for all gasoline
because of the costs of such a requirement,\148\ and we are not
adopting such a program in today's final rule. Instead, we proposed in
the NPRM a different strategy to complement the self-testing program
that would help ensure refinery sulfur compliance. This strategy would
have required refiners to retain for thirty days a representative
sample from each batch of gasoline produced, and to provide such
samples to the Agency upon request. We believed that, by means of this
option, EPA could verify the refiner test results. We believe that this
would create an incentive for refiners to sample, test, and record
their sulfur results in an accurate and truthful manner. We also
proposed that refiners be required to certify annually that the samples
have been collected in the manner required under the sulfur rule. In
addition, we proposed that specific procedures be followed by refiners
to properly collect, retain, and ship the samples in a manner
consistent with requirements already imposed or proposed under the RFG
program. Under the proposal, a minimum representative sample of 330 ml
of each gasoline batch would need to be retained (and submitted to EPA
upon request).\149\
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\148\ See the discussion on this subject in the preamble to the
reformulated gasoline program's final rule, 59 FR 7765 (Feb. 16,
1994).
\149\ See 40 CFR 80.65(f)(3)(F)(ii), and the Proposed Rule for
Modifications to Standards and Requirements for Reformulated and
Conventional Gasoline, 62 FR 37337 et seq, proposed 40 CFR
80.101(i)(1)(i)(C)(iii).
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Although there were few comments on this proposal, one commenter,
the National Petrochemical & Refiners Association (``NPRA''), did
comment extensively on it, and strongly urged the Agency not to
finalize it. One of the points raised by the NPRA was that the RFG
regulations have their own sample retention and submission
requirements, (40 CFR 80.65), so that a sulfur rule provision for RFG
batches was not necessary. The Agency continues to believe that sample
and retention requirements are useful to ensure compliance with the
sulfur standards, but we agree with NPRA that the sample retention and
submission requirements found in the RFG rule will serve equally as
well for the sulfur rule. Therefore, the final sulfur rule requires all
refiners, including those producing RFG, to comply with the sulfur
rule's retention requirements. However, any refiner of RFG using an
independent laboratory pursuant to 40 CFR 80.65(f), either under the
100% Option or the 10% Option, will be considered to be in compliance
with the sulfur rule's retain requirements provided the refiner ensures
that the independent laboratory conducting the retain program for the
refiner, is in compliance with these requirements. In particular, the
refiner must ensure that its independent laboratory sends the
appropriate certificate of analysis along with any sample forwarded to
EPA. Under the RFG program's 100% Option, the refiner must ensure that
its independent laboratory sends the independent lab's certificate of
analysis; and under the 10% Option, the refiner must ensure that its
independent laboratory sends the refiner's certificate of analysis.
In addition to urging EPA not to finalize the sample retention and
submission requirements for RFG gasoline, NPRA urged us not to finalize
these requirements for CG as well. NPRA argued that these requirements
would not prove useful in deterring non-compliance with the sulfur
requirements for this product, primarily because false samples could be
forwarded to EPA. The Agency disagrees with NPRA's argument. First, the
goal of these requirements is not only to deter cheating but also to
reveal inadequacies that exist in refiners' sulfur testing procedures.
We do not expect that most non-compliance with the sulfur standards
will occur through cheating, but rather through operational problems.
Agency enforcement experience under the RFG rule reveals that some
refiners' testing procedures are not always accurate in measuring
parameters and thus detecting noncompliance. EPA verification testing
will expose such testing inaccuracy, enabling the refiner to improve
its testing procedures and thus improve its ability to detect, and
correct, its own compliance problems. To ensure the effectiveness of
these sulfur sample retention and submission requirements, the final
rule requires all refiners to provide EPA with the sulfur test result
the refiner has obtained for the sample, along with each sample the
refiner provides to the Agency under this rule.
EPA will use these retained samples in compliance determinations.
Gasoline samples that are forwarded to EPA under the sample retention
requirements that are found to be in violation of a refinery cap, will
be considered by EPA to be evidence of violations of the cap standard,
regardless of the refiner's own test result. In addition, EPA testing
of these samples may establish that the refiners' test results are
generally incorrect, i.e., are biased. EPA will evaluate whether such a
bias constitutes evidence of a violation of the sulfur average
standards applicable to the refiner, including whether the bias extends
to other sulfur tests conducted by the refiner during the current or
previous averaging periods. Further, evidence of testing bias could
constitute evidence a refiner has not met the requirement to conduct
sulfur testing in accordance with specified
[[Page 6809]]
procedures, and any reports submitted to EPA that reflect the bias
could be evidence a refiner has not met the requirement to properly
report the sulfur content of gasoline produced.
While it is true that a party can submit false samples to EPA in
order to prevent the Agency from discovering what in actuality is a
non-compliant batch of gasoline, we do not believe that there will be
many examples of such flagrant cheating. Our enforcement experience
indicates that the great majority of parties regulated under the fuels
programs work to comply with the regulatory requirements. We believe
that the potential penalties for the submission of false samples to the
government, and the potential criminal liability which such conduct
would subject parties to under to section 113 of the Clean Air Act,
will act as significant deterrents to this cheating. Last, to further
decrease perceived incentives for such cheating, the regulation
specifically requires that the refinery official signing and submitting
the refinery's annual sulfur report must make inquiries to verify the
correctness of the sampling collection and retention procedures and
include with the annual sulfur report a personal certification of the
correctness of the procedures used to collect the retained samples. If
such certification cannot be made, then the report cannot be timely
filed.
NPRA further commented that CG being counted to create early
credits under the sulfur rule's ABT program should not be subject to
the proposed sample retention and submission requirements. NPRA argues
that the lack of a sulfur cap during the early credit timeframe makes
such retention and submission unnecessary. The Agency disagrees. During
the early credit generation timeframe, refiners participating in the
credit program must comply with sulfur averaging requirements, even
though sulfur caps are not required to be met. Accurate determination
of compliance with the averaging requirements necessitates accurate
sulfur testing in the early credit period, just as it does during
implementation of the full sulfur program, even though sulfur testing
of CG composite samples will be permitted. Hence, the sample retention
and submission requirements, whose purpose is to ensure accurate
testing and compliance determination, continue to be necessary for the
early credit period. The final rule retains the sample retention
requirements for CG during the early credit time frame.
NPRA also suggested that in place of the proposed 30 day sample
retention requirement, EPA instead should require refiners to maintain
samples only from the last three batches of gasoline produced. NPRA
argued that this alternative requirement would prove more economical
for the refiners, yet would still provide EPA with the ability to test
some samples itself. Although the Agency believes that the proposed 30
day retention period would provide a valuable amount of samples to be
retained and thus available for testing by EPA, the Agency agrees that
a more limited sample retention requirement could provide an acceptable
means of confirming refiner testing accuracy and sulfur compliance,
while being less burdensome to refiners. We do not believe, however,
that retention of samples from only three batches of gasoline would be
effective in accomplishing the goal of producing greater testing
accuracy. Three samples would not be a great enough number to
realistically demonstrate if a pattern of testing irregularities exists
or to demonstrate that a significant volume of the refiner's production
is covered by the testing verification process. Consequently, instead
of the three batch sample retention requirement proposed by this
commenter, the Agency has instead required in the final rule that at
least the last 20 samples be retained, and that each sample be retained
for a minimum of 21 days. The Agency believes this amended requirement
addresses NPRA's concern that the amount of days of sample retention be
reduced from thirty days, while also providing the Agency with an
effective means of assuring a reasonable number of samples,
representing a significant period of refining activity, will be
available for accuracy testing. We believe the retention requirement is
not burdensome given the limited number of samples that must be
retained. Further, many refineries already retain samples.
A final comment by NPRA about the sample retention and submission
requirements is addressed in the final rule. NPRA raised a concern
about the required retention and submission of samples of pressurized
blendstock, particularly butane, which would require the use of
specialized high-pressure containers. The Agency agrees that there is
legitimate concern about the handling, storing and shipping of such
samples. We also believe that the final rule's quality assurance
testing requirements and the testing requirements for blendstock
suppliers provides adequate assurance of the compliance of these
blendstocks. Hence, the final sulfur rule does not contain a
requirement that samples of pressurized blendstock must be retained.
E. Federal Enforcement Provisions for California Gasoline and for Use
of California Test Methods To Determine Compliance
Requirements to Segregate Gasoline and to Use Product Transfer
Documents for Certain California gasoline; Definition of California
Gasoline
In the NPRM, the Agency proposed to generally exempt from the
requirements of the federal sulfur rule certain gasoline sold or
intended for sale in California. For the purpose of program
consistency, the gasoline to be exempt in the sulfur rule would meet
the same definition of California gasoline as found in the RFG rule (40
CFR 80.81(a)(2)). The exempt gasoline would include all gasoline sold,
intended for sale, or made available for sale in California that was
also either: produced within California; imported into California from
outside the U.S.; or imported into California from another state,
provided that the out-of-state refinery did not also produce federal
RFG.
Although the NPRM proposed to exempt California gasoline from
compliance with the proposed sulfur standards (for reasons discussed
elsewhere in this preamble), we did propose two requirements that would
apply to some exempt California gasoline. The first would require
exempt gasoline produced outside of California but intended for use in
California, to be segregated from non-exempt gasoline at all points in
the distribution system. The second would require out-of-state
producers of exempt gasoline intended for sale in California to create
PTDs identifying the product as California gasoline, and would require
such PTDs to be provided to all transferees of this gasoline in the
distribution system. Requiring such documentation is intended to
facilitate enforcement and compliance by identifying gasoline that is
not federally regulated. The same PTD requirements currently apply
under the RFG program.\150\
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\150\ See 40 CFR 80.81(g).
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One commenter expressed a reservation about the sulfur rule's
proposed segregation requirement. The commenter was concerned that the
segregation requirement for exempt California gasoline might interfere
with the ability of California importers to import into California,
non-exempt, federal RFG gasoline that happened to comply with
California Air Resources Board (ARB) sulfur requirements, but had not
been kept segregated by its out-
[[Page 6810]]
of-state refiner from the refiner's federal RFG product. Out of a
concern about potential gasoline supply problems in California, the
commenter asked for assurances from the Agency that such gasoline would
not be prohibited from sale in California because of the sulfur rule's
segregation requirement.
The Agency agrees that it would not be beneficial to restrict the
flow of complying gasoline into California. However, since the federal
and the ARB sulfur control programs provide for differing calculations
of standard compliance, and since the standards themselves are not
always consistent between the two programs, EPA does not believe that
the compliance of gasoline produced for federal purposes will
necessarily assure its compliance with ARB program requirements, and
vice-versa. Therefore, we believe it is necessary to require the
physical segregation of the gasolines produced for the different
programs in order to best ensure compliance with our uniquely
determined federal sulfur standards. To ensure segregation, it is
necessary that refiners and importers designate gasoline batches
destined for California as California gasoline and that PTDs identify
the gasoline as being for use only in California.
Further, one of the purposes of creating the California exemption
in the federal sulfur rule is to ensure the exclusion of California
gasoline from the refiner's compliance calculations under the federal
rule. This exclusion is necessary to prevent gasoline that is produced
to comply with the strict California standards from unfairly effecting
the refiner's compliance with the federal requirements, thereby
facilitating the production of higher sulfur gasoline for use in a
federal market supplied by the refiner. EPA believes that segregation
of the two gasolines is necessary because it facilitates accurate
identification of the product to be included solely in the federal
compliance calculations.
EPA does not believe that requiring the segregation of California
gasoline from gasoline produced for the federal market should create a
significant restriction in the flow of gasoline to California. The
Agency believes that if a California marketer needs to acquire ARB-
complying gasoline from out-of-state, the marketer should generally be
able to satisfy that need by ordering a batch of California gasoline to
be created for it by out-of-state producers. Under this circumstance of
the creation of a unique batch of California gasoline, segregation of
the gasoline will typically be assured.
In analyzing the above comment on segregation of California
gasoline, the Agency realized that the sulfur rule's proposed
definition of exempted California gasoline, which paralleled the
definition existing in the RFG rule, was not as complete as it should
be to properly address the unique needs of the sulfur program.
Specifically, the exclusion from the sulfur rule's exemption of out-of-
state gasoline sold or intended for sale in California solely because
it happens to be produced at a refinery that produces federal RFG
gasoline, is not appropriate. Basing an exemption on whether or not an
out-of-state refinery produces federal RFG is relevant to the RFG
program, but it has no relevance to the sulfur control program. To
ensure effective determination of compliance with federal sulfur
standards, the final sulfur rule deletes any reference to RFG
production in the rule's definition of exempt California gasoline.
Hence, the example presented in the comment, in which out-of-state
gasoline for sale in California could be considered non-exempt
gasoline, would not arise under the expanded definition of California
gasoline.
Use of California Test Methods and Off-Site Sampling Procedures for 49
State Gasoline
Under the NPRM and the final rule, refineries and importers located
in California would be required to meet the federal sulfur standards
and other requirements with regard to their ``federal'' gasoline to be
used outside of California. However, we proposed that gasoline produced
in California for sale outside of California could be tested for
compliance under the federal sulfur rule using the methodologies
approved by the ARB, provided that the producer complies with the
procedures for such testing as already required under 40 CFR 80.81(h),
which permits California test methods not identical to federal test
methods to be used for conventional gasoline. Today's rule adopts this
provision, as well as the corollary proposed provision that gasoline
produced by California refiners for use out-of-state may be tested at
off-site testing as already permitted pursuant to 40 CFR 80.81(h) for
CG purposes. Both provisions in today's rule should alleviate duplicate
testing burdens on California refiners subject to both the federal and
California programs, since the test methods acceptable under these
alternative provisions in today's rule are also currently used to
comply with California requirements. No comments were received on these
provisions.
F. Recordkeeping and Reporting Requirements
1. Product Transfer Documents
Small Refiner Gasoline Transfers
The NPRM proposed that the business practice PTDs that accompany
each transfer of custody or title of gasoline that includes gasoline
produced by any small refiner subject to sulfur rule individual
refinery standards would be required to identify the gasoline as such,
including the applicable downstream cap, as an aid to enforcing the
national downstream cap. Today's rule adopts the proposed PTD
requirement, with modifications regarding how the PTD requirement
relates to testing, as described in section VI.C. The requirement for
printing information on PTDs has been simplified in the final rule. All
parties may use brief codes to identify the small refiner status of the
gasoline and to identify the small refiner downstream standard it is
subject to. This small refiner gasoline PTD provision is also applied
to gasoline subject to individual refinery standards under the
temporary refiner relief provision of today's rule.
GPA Gasoline Transfers
Under the geographic phase-in program finalized today, gasoline
produced or imported for use in the GPA may be used only in the GPA
states. Therefore, it is necessary for PTDs for gasoline that is
comprised in whole, or in part, of GPA gasoline, to identify the
gasoline as such and state that the gasoline may not be distributed or
sold for use outside the GPA. Product codes may be used to provide this
information, except in the case of transfers to truck carriers,
retailers and wholesale purchaser-consumers.
2. Recordkeeping Requirements
Under today's rule, refiners and importers will be required to keep
and make available to EPA certain records that demonstrate compliance
with the sulfur program standards and requirements. This includes
records pertaining to the generation, use and transfer of credits and
allotments. The RFG/CG regulations currently require refiners and
importers to retain records that include much of the information
required in the sulfur rule. Where this is the case, there is no
requirement for duplication of records or information.
Under the final rule, all parties in the gasoline distribution
system, including refiners, importers, oxygenate blenders, retailers,
and all types of distributors will be required to retain PTDs and
records of quality assurance programs (including, where applicable,
sulfur test
[[Page 6811]]
results) that parties conduct to establish a defense to downstream
violations. All parties in the gasoline distribution system currently
are required to keep PTDs for RFG. However, since there are no
downstream CG standards under the anti-dumping regulations, only
refiners and importers are required to retain PTDs for conventional
gasoline under the current regulations. Because the sulfur rule, like
the RFG rule, includes downstream standards, we believe that a
requirement to retain PTDs for all parties in the gasoline distribution
system is appropriate under the sulfur rule. The PTD information will
help us identify the source of any gasoline found to be in violation of
the sulfur standards, and will provide downstream parties with
information regarding the applicable downstream standard.
Parties are required to keep records for a period of five
years,\151\ with additional requirements for records pertaining to
credits and allotments. Records pertaining to credits or allotments
that were banked and never transferred to another party are required to
be retained for five years after the credits or allotments are used for
compliance purposes. Records pertaining to credits or allotments that
were transferred are required to be retained by the transferor for five
years after the year the credits or allotments were transferred, and by
the transferee for five years after use.
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\151\ Five years is the applicable statute of limitations for
the RFG and other fuels programs. See 28 U.S.C. 2462.
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We received comment that the regulations should allow records to be
maintained in non-hard copy formats, such as photographic or electronic
means. We do not believe that the recordkeeping requirements, as
proposed, disallow the retention of records in electronic or
photographic form. However, parties that electronically generate and/or
maintain records must make available to EPA the hardware and software
necessary to review the records, or if requested by EPA, electronic
records shall be converted to paper documents.
The sulfur rule, like the RFG/CG rule, requires regulated parties
to keep the results of tests conducted on the gasoline. A number of
parties previously have asked EPA to clarify whether, under the RFG/CG
rule, this recordkeeping requirement requires parties to keep copies of
all documents that contain test results. To clarify what the
recordkeeping requirements require with regard to test data, we
proposed for the RFG/CG rule to add language which specifies that the
test result as originally printed by the testing apparatus is required
to be kept, or, where no printed result is generated by the testing
apparatus, the results as originally recorded by the person who
performed the tests. Today's action incorporates this clarification in
the sulfur rule. Under this provision, where the test data is initially
recorded into a database system and there are no prior written
recordings of the data, the information in the database system may
serve as the original record of the test data. The final rule also
specifies that any record that contains results for a test that are not
identical to the results as originally printed by the testing apparatus
or recorded by the person who performed the test must also be kept.
Although this language was not included in the NPRM, we have concluded
it is a logical outgrowth of the proposal regarding recordkeeping for
test data, and that it will make the regulation clearer with regard to
this requirement. As a result, it is appropriate to include this
language in the final rule.
3. Reporting Requirements
Refiners and importers will be required to submit an annual report
that demonstrates compliance with the applicable sulfur standards and
data on individual batches of gasoline, including batch volume and
sulfur content. The rule requires that refiners and importers report on
the generation, use and transfer of credits and allotments. The RFG/CG
programs contain similar reporting requirements. Based on our
experience with these programs, we believe that requiring an annual
sulfur report and batch information will provide an appropriate and
effective means of monitoring compliance with the average standards
under the sulfur program. The batch data also will serve to verify that
each batch of gasoline met the applicable sulfur cap standard when it
left the refinery or import facility. The batch data must also show
which batches were designated as GPA gasoline, as appropriate.
For the 2004 and 2005 annual averaging periods, refiners will be
required to submit a report for the refiner's gasoline production (RFG
and conventional gasoline) for all refineries during the averaging
period, which demonstrates compliance with the applicable corporate
average and per-gallon cap standards. For the 2005 annual averaging
period, refiners will also be required to submit a separate report for
each refinery, which demonstrates compliance with the refinery average
standard. For the 2004 and 2005 annual averaging periods, importers
will be required to submit a report for all of the gasoline they import
during the averaging period, which demonstrates compliance with the
applicable corporate average and per-gallon cap standards. The
importer's report for 2005 must also demonstrate compliance with the
refinery average (30 ppm) standard. Any refiner who is also an importer
must aggregate the refining and importing activities for the purpose of
demonstrating compliance with the applicable corporate average
standards. Importers of gasoline produced by foreign refiners with
individual baselines have additional reporting requirements. For the
2006 averaging period and beyond, corporate average reports are no
longer required for either refiners or importers. Refiners will be
required to submit an annual report for each refinery (importers for
the gasoline they import), which demonstrates compliance with the
refinery average and per-gallon cap standards. Refiners or importers
producing both GPA gasoline and gasoline for the remainder of the
country, must separately report compliance with the different
standards. Annual reports, on forms provided by the Agency, must be
received by EPA by the last day of February for the prior calendar
year.
The annual reports will also provide a vehicle for accounting for
any sulfur allotments or credits created, sold or used to achieve
compliance during the averaging period. (See Section IV.C. for a
discussion of the sulfur allotment and ABT credit programs.) Each
refiner or importer choosing to participate in the ABT program will be
required to report to the Agency on an annual basis (refiners for each
refinery, and importers for the gasoline they import) the applicable
sulfur baseline and the annual average gasoline sulfur level produced
at that refinery or by that importer (in ppm sulfur) during the
averaging period. Credit calculations will be reported, along with an
accounting of credits banked, used, traded, acquired or terminated. The
credits will be in units of ppm-gallons. The identity of the refiners/
refineries and importers involved in these transactions will be
reported, along with the registration numbers assigned to them by the
Agency under the RFG/CG program (40 CFR 80, subparts D, E, and F).
For years 2000 through 2003, parties who generate early ABT credits
will be required to report information relating to the generation of
these credits. These early credit reports will only cover credits
banked and traded. Beginning in 2004 and beyond, refiners and importers
[[Page 6812]]
who generate and/or use ABT credits will be required to submit
information relating to the generation and use of the credits as part
of their annual compliance reports, including any credit debit that is
carried over to the subsequent year. For each purchase of ABT credits,
as reported on the buyer's annual report, there must be a corresponding
entry on the seller's annual report. The annual report must also
indicate any credits that are used to achieve compliance with the
refinery average standard.
As discussed above, during the 2004 and 2005 annual averaging
periods, refiners for the combined production from all their
refineries, and importers for the gasoline they import, will also be
required to demonstrate compliance with the applicable corporate
average standard. In addition, refiners and importers must demonstrate
compliance with the requirements for the generation, use, transfer and
termination of allotments. Refiners and importers who trade sulfur
allotments to meet the corporate average standard will be required to
submit information relating to these transactions. All sulfur allotment
transactions must be concluded by the last day of February of the
calendar year following the year the allotments were used to meet the
corporate average. Information relating to such transactions, including
the identity of the refiners and importers involved in the transactions
and their EPA registration numbers, must be reported by both parties to
the transaction as part of their annual compliance reports.
As discussed in Section IV.C., above, parties that only blend
oxygenates into gasoline are not treated as refiners under the sulfur
rule, and, as a result, are not subject to the reporting requirements
under Sec. 80.370.
Refiners and importers are also required to arrange for a certified
public accountant or certified internal auditor to conduct an annual
review of the company's records that form the basis of the annual
sulfur compliance report (called an ``attest engagement''). The purpose
of the attest engagement is to determine whether representations by the
company are supported by the company's internal records. Attest
engagements are already required under the RFG/CG regulations. The
refiner's attest engagement under the RFG/CG rule partially encompasses
sulfur rule compliance since the attest auditors are already required
to verify sulfur results for both CG and RFG. However, the RFG/CG
attest engagements do not require the attest auditor to review sulfur
credit generation, credit purchases, credit trading or small refiner
issues. Because of the complexity of the sulfur credit program and
small refiner program, sulfur attest engagement provisions have been
adopted by today's rule that require the attest auditor to review
sulfur credit generation, credit trading, credit purchasing, credit
selling, corporate pool averaging, and small refiner issues. Consistent
with the RFG regulations, the attest reports for sulfur are to be
included in the presently required attest engagement submitted by May
31 of each year.
G. Exemptions for Research, Development, and Testing
The final rule provides for an exemption from the sulfur
requirements for gasoline used for research, development and testing
purposes. We recognize that there may be legitimate research programs
that require the use of gasoline with higher sulfur levels than those
allowed under the sulfur rule. As a result, the final rule includes
provisions for obtaining an exemption from the prohibitions for persons
distributing, transporting, storing, selling or dispensing gasoline
that exceeds the standards, where such gasoline is necessary to conduct
a research, development or testing program. Parties are required to
submit to EPA an application for exemption that describes the purpose
and scope of the program and the reasons why use of the higher sulfur
gasoline is necessary. In approving any application, EPA will impose
reasonable conditions such as recordkeeping, reporting, volume
limitations and possible requirements to repair vehicles.
We received comment that the regulations should clarify that
suppliers of gasoline used for R&D purposes are exempt from the
prohibitions and penalties under the sulfur rule. To clarify this
point, we have added a provision which explicitly states that gasoline
subject to an R&D exemption is exempt from the provisions of subpart H,
so long as the gasoline is used in a way that complies with the terms
of the memorandum of exemption. If the R&D exemption is shown to be
based on false information or is not properly maintained, parties will
be liable for violations of the provisions under subpart H regarding
any gasoline covered under the exemption.
We also received comment that the regulations should ensure that
vehicles which have been used for testing with high sulfur test fuels
are not later returned to the general fleet, or if they are, the
vehicles should be required to be restored to their original condition.
EPA agrees that it would be improper to permit such vehicles to be used
in general use if their emission controls have been rendered
inoperative through fueling with high sulfur gasoline. This issue may
be effectively addressed through the anti-tampering requirements of
section 203(a)(3) of the Clean Air Act, 42 U.S.C. Sec. 7522(a)(3), and
is also addressed in today's rule, which provides the Administrator
with the power to include appropriate conditions when granting R&D
exemptions.
H. Liability and Penalty Provisions for Noncompliance
The liability and penalty provisions under the sulfur rule are
similar to the liability and penalty provisions of the RFG and other
fuels regulations.\152\ Regulated parties will be liable for committing
certain prohibited acts, such as selling or distributing gasoline that
does not meet the sulfur standards, or causing others to commit
prohibited acts. In addition, parties will be liable for a failure to
meet certain affirmative requirements, such as the recordkeeping or PTD
requirements, or causing others to fail to meet such requirements.
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\152\ See section 80.5 (penalties for fuels violations); section
80.23 (liability for lead violations); section 80.28 (liability for
volatility violations); section 80.30 (liability for diesel
violations); section 80.79 (liability for violation of RFG
prohibited acts); section 80.80 (penalties for RFG/CG violations).
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The sulfur rule, like other EPA fuels regulations, includes a
presumptive liability scheme for violations of prohibited acts. Under
this approach, the party in the gasoline distribution system that
controls the facility where the violation occurred, and other parties
in that gasoline's distribution system (such as the refiner, reseller,
and distributor), are presumed liable for the violation.\153\ The
sulfur rule explicitly includes causing another person to commit a
prohibited act and causing the presence of non-conforming gasoline to
be in the distribution system as prohibitions. The final rule clarifies
that causing the presence of non-conforming gasoline to be in the
distribution system includes gasoline that does not conform to the
applicable average standard, as well as gasoline that does not conform
to the cap standard. Affirmative defenses are provided for each party
that is deemed presumptively liable for a violation, and all
presumptions of liability are refutable. The defenses under the sulfur
rule are similar to those
[[Page 6813]]
available to parties for violations of the RFG regulations.
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\153\ An additional type of liability, vicarious liability, is
also imposed on branded refiners under these fuels programs.
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The final sulfur rule, like the proposal, applies the provisions of
section 211(d)(1) of the Clean Air Act (Act) for the collection of
penalties. The penalty provisions subject any person who violates any
requirement or prohibition of the sulfur rule to a civil penalty of up
to $27,500 for every day of each such violation and the amount of
economic benefit or savings resulting from the violation. A violation
of the applicable average sulfur standard constitutes a separate day of
violation for each day in the averaging period. A violation of a sulfur
cap standard constitutes a separate day of violation for each day the
gasoline giving rise to the violation remained in the gasoline
distribution system. The length of time the gasoline in question
remained in the distribution system is deemed to be twenty-five days
unless there is evidence that the gasoline remained in the gasoline
distribution system for fewer than or more than twenty-five days. The
penalty provisions are similar to the penalty provisions for violations
of the RFG regulations.
After consideration of the comments received, the Agency is
adopting regulations that specify the regulated parties who may be
subject to liability for causing a violation of the sulfur rule. As
proposed, the regulation would have applied to any person, not limited
to the parties in the gasoline distribution system whose actions could
logically have caused the nonconformity. This provision would have
potentially broadened the range of liable parties under the sulfur rule
beyond the range established under other fuel programs. EPA believes
that the presumptive liability schemes of current fuels regulations
have generally been effective and finds no compelling reason to apply
the regulatory provision at issue to ``any person'' rather than to
specific parties. Therefore, in the final sulfur rule, the liability
sections for the causation violations will specify the regulated
parties subject to the liability, and will not encompass unspecified
parties. The final rule clarifies that oxygenate blenders are among the
specified parties potentially subject to liability. Today's final rule
also clarifies that parent corporations are liable for violations of
subsidiaries. This is consistent with our interpretation of the RFG
rule, as stated in the RFG and Anti-dumping Question and Answer
document. Finally, the final rule clarifies that each partner to a
joint venture will be jointly and severally liable for the violations
at a joint venture facility or by a joint venture operation.
We received several comments on the proposal. Some commenters
believe that the Act does not authorize EPA to establish prohibitions
against causing another person to commit a prohibited act or causing
the presence of non-conforming gasoline to be in the distribution
system. These commenters believe that these prohibitions are a
departure from the liability scheme under the existing fuels
regulations and that they constitute double jeopardy by imposing
liability for multiple violations for a single act. The commenters also
believe that imposing liability for causing another person to commit a
prohibited act extends the limits that Congress placed on liability
under section 211 of the Act, since sections 211(d) and 211(k)(5) do
not expressly mention imposing liability for causing another person to
violate regulations. The commenter also noted that, had Congress
intended for such actions to be prohibited, it could have expressly
included such a prohibition in section 211. This commenter cites
section 211(g) as an example of a statutory provision with such a
prohibition. One commenter said that, rather than clarify the
presumptive liability scheme, the rule provides no guidance regarding
what it means to cause someone to violate a prohibition or cause non-
conforming gasoline to be in the distribution system. A commenter also
stated that these proposed prohibitions are unnecessary, since EPA has
issued violations to multiple parties under current fuels regulations.
EPA disagrees with the comment that the sulfur rule's proposed
liability scheme is a marked departure from the liability schemes
typically found in the other fuels programs promulgated pursuant to
section 211 of the Act and with the comment that the regulations
constitute double jeopardy (the double jeopardy issue is addressed in
the Response to Comment document). The majority of these programs,
including the pr