[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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\153\ An additional type of liability, vicarious liability, is
also imposed on branded refiners under these fuels programs.
---------------------------------------------------------------------------
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 proposed sulfur rule, contain presumptive liability
enforcement structures which impose liability on parties who, through
their actions, could logically have caused the fuel nonconformity. The
sulfur rule's presumptive liability scheme is thus consistent with the
liability schemes of typical prior fuels programs. While EPA has issued
notices of violations to multiple parties for violations under current
fuels regulations, the Agency believes it is appropriate to clarify
that the act of causing another party to violate the regulations is a
prohibited act. Therefore, the regulatory language in the sulfur
regulations explicitly addresses this issue.
EPA also disagrees with the comment that this provision is
inconsistent with Section 211(d) of the Act because Section 211(d) does
not mention imposing liability for causing another person to violate
the regulations promulgated under Section 211(c). For the reasons
described above, EPA is adopting a provision in today's regulations
that prohibits causing another entity to violate the standards. This
prohibition is a reasonable exercise of EPA's discretion under Section
211(c), and the penalty provision of Section 211(d) apply to violations
of the prohibition. The fact that Section 211(d) does not specifically
mention causing another person to violate the regulations is therefore
irrelevant, such action is itself a violation of the regulations.
Moreover, Section 211(d) does not mention any specific violations for
which penalties may be assessed, but rather states generally that
violations shall result in penalties. Thus, the absence of specific
mention of causing another entity to violate the regulations is
irrelevant, since all other specific prohibitions in regulations
subject to Section 211(d) penalties are similarly not mentioned.
The Agency also disagrees with the comment that the Clean Air Act
does not give EPA the authority to establish causation violations under
the sulfur rule. We believe that the Act gives us ample authority to
categorize the sulfur rule's causative acts, i.e., the causing of
another party to commit a violation, and the causing of nonconforming
gasoline to be present in the distribution system, as prohibited acts.
Section 211(c) of the Act authorizes the Agency to promulgate
regulations for the purpose of prohibiting or controlling the
manufacture, introduction into commerce, sale, or offering for sale of
fuels or fuel additives where the fuel or additive causes or
contributes to air pollution which may reasonably be anticipated to
endanger public health or welfare, or where the fuel or additive will
impair to a significant degree the performance of emission control
devices that are or will be in general use. Today's gasoline sulfur
rule is promulgated pursuant to this authority.
Section 211(c) gives EPA broad discretion to fashion regulations to
control or prohibit the manufacture, introduction into commerce, sale,
or offering for sale of fuels once the Agency has made the requisite
findings regarding contribution to harmful air pollution or impairment
of vehicle emissions control system performance. This includes the
discretion to adopt
[[Page 6814]]
reasonable regulatory provisions that are necessary and appropriate to
ensure that the controls or prohibitions are effective. To effectively
regulate sulfur in gasoline under section 211, it is necessary for the
Agency to regulate the actions of those parties who do the
manufacturing, introducing into commerce, and selling of gasoline
subject to the sulfur requirements.
When one or several of these regulated parties causes another
regulated party to violate the rule (or causes nonconforming gasoline
to be present in the system), such an act could logically result in the
high sulfur gasoline contributing to harmful air pollution or to the
impairment of vehicle emission control device performance, which are
the adverse impacts that legislative authority under section 211(c) was
created to control. Examples of such upstream causative acts include
the scenario where a refiner produces high sulfur gasoline which it
sells to a distributor. That distributor then resells the nonconforming
product to a variety of retail outlets which, in their turn, also
violate the rule by selling the high sulfur gasoline to owners of motor
vehicles. Another example occurs where a distributor has created high
sulfur gasoline by blending high sulfur blendstock into his gasoline.
This distributor then makes several different sales of this
noncomplying product to a variety of retail outlets, which, in their
turn, also violate the rule by selling the product to numerous motor
vehicle owners. A third upstream causation scenario could occur if
several refiners happen to make nonconforming gasoline. Each then sells
its nonconforming product to a different distributor, and a retail
outlet which is a customer of both distributors, purchases some of the
noncomplying gasoline from both distributors. The retailer then commits
a violation by offering this product for sale to its customers.
In some cases, an upstream action has more severe environmental
impacts through causing a downstream violation than would occur if the
violation was corrected upstream. For example, a refiner may violate
the sulfur regulations by shipping gasoline that exceeds the applicable
standards when it leaves the refinery. If that violation is corrected
before the gasoline reaches the retail outlets, the adverse
environmental impacts could be mitigated or avoided. However, if the
refiner's violation is not corrected and ultimately causes a number of
violations of the standards at retail outlets, the environmental impact
would be more severe, since high sulfur gasoline would be introduced
into vehicles and impair catalyst performance. Therefore, it is
reasonable to consider causing a downstream violation by another party
to be a separate violation, since an upstream party's actions can have
more severe environmental consequences if they cause downstream parties
to violate applicable requirements. For these reasons, it is reasonable
to conclude that section 211(c) authorizes the Agency to prohibit and
control such causative acts in order to ensure that gasoline ultimately
introduced into vehicles meets the low sulfur standards.
Our approach is also reasonable under section 211(c) even though
section 211(c) does not expressly prohibit causing another party to
violate standards adopted under this subsection. In fact, section
211(c) itself does not contain any express prohibitions, but rather
provides EPA authority to regulate fuels and fuel additives, based on
certain findings. In contrast, other provisions of section 211, such as
section 211(g), do include express prohibitions against certain
actions. Thus, under section 211(g), the specified actions are
prohibited even in the absence of EPA adopting regulations to codify
the prohibitions. In section 211(g), Congress indicated a clear intent
to prohibit a specific action (misfueling), without requiring EPA to
adopt regulations to implement that prohibition. However, section
211(c) authorizes EPA to establish regulations with certain controls
and prohibitions, and, as described above, EPA has the discretion to
adopt reasonable measures to ensure that the requirements of such
regulations are met.
Moreover, the commenters' assertion that this provision is
inconsistent with other subsections of section 211 of the Act is
misplaced. First, while the sulfur standards do apply to all gasoline,
including gasoline subject to the reformulated gasoline requirements,
the sulfur standards are being adopted pursuant to EPA's authority
under section 211(c)(1), not under section 211(k). Therefore, section
211(k)(5)'s prohibitions, which describe actions that are violations of
section 211(k), are not relevant to the sulfur standards. In addition,
the enumeration of specific prohibitions in section 211(k) does not
mean that EPA may establish no other prohibited acts with respect to
reformulated gasoline; rather, it simply identifies certain actions
that ``shall be'' violations of section 211(k), but does not preclude
establishment of other appropriate prohibited acts pursuant to EPA's
authority under the Act.
The Agency also disagrees with the argument that the proposed
causation violations under the sulfur rule would impose unjustifiable,
multiple liability for the commission of a single prohibited act. The
Agency is generally not in the best position to know the exact cause of
a gasoline nonconformity since so many parties and actions are involved
with the sale and transfer of the gasoline. Therefore, for effective
enforcement, we must have the ability to assert the liability of all
the parties in the system who were connected with the nonconforming
gasoline because they each could have caused the violation. Similarly,
we must also have the ability to assert upstream liability for the full
number of downstream violations a party may be responsible for causing,
even if the multiple downstream violations may all ultimately be found
to stem from one gasoline sale or transfer on the part of the upstream
party. The enforcement possibility exists that the separate downstream
violations may each have stemmed from separate actions by that party.
Any party may rebut the presumption of liability for each asserted
violation by establishing through affirmative defenses that it did not
cause the violation. Moreover, any party against whom EPA institutes an
enforcement action may raise equitable factors about its own conduct as
part of settlement of the violation enforcement action. In settling
fuels matters, the Agency typically takes into account such matters as
the volume of nonconforming product that a party was connected with,
and the severity and the amount of proscribed activity that the party
was actually involved with in causing the violation. We do not believe
that either the sulfur rule's liability scheme or its future
implementation will be arbitrary or unjustified.
To further alleviate commenters' concern about potential liability
for multiple violations under the sulfur rule, we want to clarify that
the Agency does not ordinarily attempt to collect separate penalties
from an entity for the array of possible standard violations (e.g.,
both for the manufacturing and the selling of noncomplying product),
that a party might be liable for in respect to the same gasoline. In
addition, we do not intend to seek penalties from a single party for
violating regulatory standard requirements while also seeking penalties
for that party's causing of other entities to violate regulatory
standard requirements, where both violations involve the same gasoline,
unless very unusual circumstances exist which would warrant such
action, such as egregious conduct on the part of the party.
[[Page 6815]]
In a similar fashion, we do not expect to collect penalties from
one party for both types of causation violations for the same amount of
gasoline under normal circumstances. A primary Agency purpose in
defining the causation violations as two separate prohibited acts
(i.e., causing another to commit a violation, and causing the presence
of nonconforming product in the distribution system), was not to
collect a double penalty, but to address different scenarios of
evidence collection. For example, if the Agency finds a sulfur rule
standard violation in a sample from a retail outlet supplied by a
certain distributor, but we do not have a nonconforming sample from the
distributor, the evidence would most easily permit us to assert that
the distributor was responsible for causing the retailer violation that
we do have evidence for. It is reasonable for us to assert the
causation violation against the distributor in spite of our lack of a
sample from the distributor, because any distributor who transfers
gasoline to a retailer, which gasoline is found to be noncompliant,
could logically have caused the noncompliance of the gasoline when it
was under the distributor's control, such as by blending high sulfur
blendstock into the gasoline.
On the other hand, if we have a violation sample from a
distributor, but no samples from its downstream customers, we may
assert that the distributor caused the presence of nonconforming
gasoline in the distribution system, rather than assert that the
distributor caused another party to sell nonconforming product, since
we don't have a nonconforming sample from another party's facility. It
would be reasonable for us to assert that the distributor caused the
presence of nonconforming gasoline in the distribution system since we
do have a sample of nonconforming gasoline from the distributor, and
provided also that there is evidence that the distributor had sold,
transferred, etc. this product to downstream customers.
In summary, the Agency intends to enforce the liability scheme of
the sulfur rule in the same reasonable manner that we have enforced the
similar liability schemes in our prior fuels regulations. This does not
include attempting to penalize a party for multiple variations of
noncompliance in regard to the same gasoline unless unusual
circumstances make such action appropriate.
I. How Will Compliance With the Sulfur Standards Be Determined?
We have often used a variety of evidence to establish non-
compliance with the requirements imposed under our current fuels
regulations. Test results of the content of gasoline have been used to
establish violations, both in situations where the sample has been
taken from the facility at which the violation occurred, and where the
sample has been obtained from other parties' facilities when such test
results have had probative value of the gasoline's characteristics at
points upstream or downstream. The Agency has also commonly used
documentary evidence to establish non-compliance or a party's liability
for non-compliance. Typical documentary evidence has included PTDs
identifying the gasoline as inappropriate for the facility it is being
delivered to, or identifying parties having connection with the non-
complying gasoline.
EPA proposed that compliance with the sulfur standards would be
determined based on the sulfur level of the gasoline, as measured using
the regulatory testing methodologies. We further proposed that any
evidence from any source or location could be used to establish the
gasoline sulfur level, provided that such evidence is relevant to
whether the level would have been in compliance if the regulatory
sampling and testing methodology had been correctly performed. In
today's action, EPA is adopting the proposed regulatory provision.
Several commenters interpreted this proposed language as evidencing
the Agency's intent to make all evidence, including evidence not
derived from regulatory test methods, equal in probative value to that
from the regulatory test methods. One commenter also stated that the
proposed provision is inconsistent with other parts of the proposal
because it undercuts the benefits of having clearly defined regulatory
test methodologies. EPA disagrees that the regulatory language
indicates such an intent, or has such an effect. The regulations
provide that compliance with the standards is to be determined using
specified test methodologies. While other information may be used,
including test results using different test methods, such other
information may only be used if it is relevant to determining whether
the sulfur level would meet applicable standards had compliance been
properly measured using the specified test methodologies. Thus, the
regulation adopted today does not result in a situation where any and
all evidence carries equal weight in an enforcement action. In fact,
the regulation establishes the regulatory test method as the standard
against which other evidence is measured. Moreover, since any evidence
other than regulatory test results must be relevant to compliance using
the test method, EPA disagrees with the commenter who stated that the
validity of the sulfur standards can be challenged in any enforcement
action because neither EPA nor regulated entities will be able to rely
on measurements taken using the regulatory test methods. Rather than
causing more confusion regarding compliance with the standard, this
provision clarifies that the regulatory test method defines compliance,
since other evidence can only be used if it relates to compliance using
that test method.
The following is an example of how the Agency believes evidence of
standard non-compliance not based on regulatory test results might be
used for compliance purposes under today's rule provisions. Under a
first scenario, the Agency might not have sulfur results derived from
regulatory test methods for a certain amount of gasoline sold by a
terminal, yet the terminal's own test results, based on testing using
methods other than those specified in the regulations, show an
exceedance of the sulfur standard. Under the requirements of today's
rule, the evidence from the non-regulatory test method could only be
used to establish noncompliance if the terminal's test results are
relevant to the determination of the gasoline's sulfur level that would
have resulted if the regulatory test method had been used. Thus, the
Agency would have to present evidence to link the results of the
alternative test method to sulfur levels as measured using the
regulatory test method.
Another commenter has suggested that, if the Agency decides to
finalize a ``credible evidence'' provision, it use the language in the
current RFG regulations which establishes a presumption that the
regulatory testing methods prevail, except in exceptional
circumstances. Other commenters also opposed the proposed provision in
part because it differs from that in EPA's current fuels regulations.
As described above, EPA believes that the provision adopted today does
not undercut the importance of the regulatory testing methodologies,
since other evidence may be used only as relevant to compliance as
measured using the regulatory methods. In addition, as is consistent
with the RFG scheme, EPA believes it is appropriate to use such other
evidence even in some circumstances where test results using the
regulatory test methods do exist, and the provision adopted today
clarifies this. EPA also notes that it intends to undertake rulemaking
in the near future to revise the current fuels regulations to
[[Page 6816]]
include the same language for use of other evidence as adopted today in
the final sulfur rule.
The provision adopted today also clarifies that any probative
evidence obtained from any source or location may be used to establish
non-compliance with requirements other than the sulfur standards, such
as recordkeeping requirements and requirements to properly calculate
sulfur credits and averages, as well as to establish which parties have
facility control or some other basis for liability for sulfur rule non-
compliance. Since proof of these elements is not predicated on
establishing sulfur levels, whether or not regulatory test methods are
used is not significant. Therefore commenters' concern about the use of
other evidence undercutting the primacy of the regulatory test methods
is not germane to this part of the regulation which is not directed
toward standards. This provision is being included in the final sulfur
rule to clarify that this rule, as is consistent with our
interpretation of our other fuels rules, contemplates the full use of
all relevant evidence to establish non-standard violations and rule
liability.
EPA disagrees with the commenters who stated that EPA lacks
authority under the Clean Air Act to permit the use of any evidence of
non-compliance of the sulfur standards other than test results using
the regulatory test methods. One commenter notes that the only explicit
reference in the Act to the use of ``credible evidence'' is in section
113(e), which applies only to stationary sources, and that neither
section 211 nor section 205 mention ``credible evidence.'' Finally, the
commenter states that the proposed provision is inconsistent with the
directive of section 211(k) that EPA determine appropriate measures of
and methods for ascertaining the emissions of air pollutants.
EPA disagrees with the comments asserting that the Agency lacks
authority to promulgate this provision. While section 113(e) does refer
to ``credible evidence,'' that provision is not relevant to EPA's
action today. Moreover, the absence of the explicit use of the term
``credible evidence'' in sections 205 and 211 does not compel a
conclusion that EPA lacks authority to allow the consideration of
relevant evidence in determining compliance with the sulfur standards.
EPA believes that section 211(c) provides sufficient authority to adopt
such a provision. Section 211(c) authorizes the Agency to promulgate
regulations for the purpose of prohibiting or controlling the
manufacture, introduction into commerce, sale, or offering for sale of
fuels or fuel additives where the fuel or additive causes or
contributes to air pollution which may reasonably be anticipated to
endanger public health or welfare, or where the fuel or additive will
impair to a significant degree the performance of emission control
devices that are or will be in general use. As described in other
sections of this preamble and in the RIA, today's regulation is
promulgated pursuant to this authority. Section 211(c) gives EPA broad
discretion to fashion regulations to control or prohibit the
manufacture, introduction into commerce, sale, or offering for sale of
fuels once the Agency has made the requisite findings regarding
contribution to harmful air pollution or impairment of vehicle
emissions control system performance. This includes the discretion to
adopt reasonable regulatory provisions that are necessary and
appropriate to ensure that the controls or prohibitions are effective
and can be enforced.
To ensure the effectiveness and the ability to adequately enforce
the sulfur standards, it is reasonable for EPA to consider evidence
other than actual test results using the regulatory test method, where
such evidence can be related to the test results. As described above,
test results using the regulatory test method are often not available.
In such circumstances, it is reasonable to consider other evidence of
compliance, such as test results using other methods or commercial
documents, if such evidence can be shown to be relevant to determining
whether the gasoline would meet the standard if tested using the
regulatory methods. This provision would not permit the use of other
evidence that is not relevant to such a determination, and is therefore
reasonably limited to allow for effective enforcement, without creating
uncertainty about compliance.
Finally, EPA disagrees with the commenter's assertion that this
provision is inconsistent with section 211(k). First, while the sulfur
standards do apply to all gasoline, including gasoline subject to the
reformulated gasoline requirements, the sulfur standards are being
adopted pursuant to EPA's authority under section 211(c)(1), not under
section 211(k). In any case, the directive of section 211(k)(4) that
EPA determine through regulation appropriate measures of and methods
for ascertaining the emissions of air pollutants explicitly applies
only for purposes of section 211(k), and applies for determining the
emissions levels of VOCs and toxic air pollutants from baseline
vehicles when operating on baseline gasoline, as defined by section
211(k). Thus, the commenter's reference to section 211(k)(4) as
inconsistent with the provision adopted today is misplaced,
particularly in light of the limited applicability of the language in
section 211(k)(4).\154\
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\154\ The commenter references section 211(k)(5) as support for
its assertion, but quotes language from section 211(k)(4). EPA
assumes that the commenter intended to cite section 211(k)(4) rather
than section 211(k)(5).
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As described in the NPRM, the Agency frequently uses a variety of
evidence to establish compliance with fuel programs' regulatory
requirements and liability for non-compliance. Such evidence has
included test results obtained from a variety of sources, including
bills of lading, delivery records, manifests, and other commercial
documents. The compliance determination provisions included in today's
final rule are created to provide the most effective Agency capability
to enforce the rule's requirements.
VII. Public Participation
A wide variety of interested parties participated in the rulemaking
process that culminates with this final rule. The formal comment period
and four public hearings associated with the NPRM provided additional
opportunities for public input. EPA also met with a variety of
stakeholders, including environmental and public health organizations,
oil company representatives, auto company representatives, emission
control equipment manufacturers, and states at various points in the
process.
We have prepared a detailed Response to Comments document that
describes the comments received on the NPRM and presents our response
to each of these comments. The Response to Comments document is
available in the docket for this rule and on the Office of Mobile
Sources internet home page. Comments and our responses are also
included throughout this preamble for several key issues.
VIII. Administrative Requirements
A. Administrative Designation and Regulatory Analysis
Under Executive Order 12866 (58 FR 51735, Oct. 4, 1993), the Agency
is required to determine whether this regulatory action would be
``significant'' and therefore subject to review by the Office of
Management and Budget (OMB) and the requirements of the Executive
Order. The order defines a ``significant regulatory action'' as any
regulatory action that is likely to result in a rule that may:
[[Page 6817]]
<bullet> Have an annual effect on the economy of $100 million or
more or adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
<bullet> Create a serious inconsistency or otherwise interfere with
an action taken or planned by another agency;
<bullet> Materially alter the budgetary impact of entitlements,
grants, user fees, or loan programs or the rights and obligations of
recipients thereof; or,
<bullet> Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
Pursuant to the terms of Executive Order 12866, EPA has determined
that this final rule is a ``significant regulatory action'' because the
vehicle standards, gasoline sulfur standards, and other regulatory
provisions, if implemented, would have an annual effect on the economy
in excess of $100 million. Accordingly, we have prepared a Final
Regulatory Impact Analysis (RIA) which is available in the docket for
this rulemaking and at the internet address listed under ADDRESSES
above. This action was submitted to the Office of Management and Budget
(OMB) for review as required by Executive Order 12866. Any written
comments from OMB on today's action and any responses from EPA to OMB
comments are in the public docket for this rulemaking.
B. Regulatory Flexibility
The Regulatory Flexibility Act, 5 U.S.C. 601-612, was amended by
the Small Business Regulatory Enforcement Fairness Act of 1996
(SBREFA), Public Law 104-121, to ensure that concerns regarding small
entities are adequately considered during the development of new
regulations that affect them. EPA has identified industries subject to
this rule and has provided information to, and received comment from,
small entities and representatives of small entities in these
industries. We have prepared a Final Regulatory Flexibility Analysis
(RFA) to evaluate the economic impacts of today's proposal on small
entities.\155\ The key elements of the RFA include:
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\155\ The Final RFA is contained in Chapter 8 of the Regulatory
Impact Analysis.
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<bullet> The number of affected small entities;
<bullet> The projected reporting, record keeping, and other
compliance requirements of the proposed rule, including the classes of
small entities that would be affected and the type of professional
skills necessary for preparation of the report or record;
<bullet> Other federal rules that may duplicate, overlap, or
conflict with the proposed rule; and
<bullet> Any significant alternatives to the proposed rule that
accomplish the stated objectives of applicable statutes and that
minimize significant economic impacts of the proposed rule on small
entities.
The Agency convened a Small Business Advocacy Review Panel (the
Panel) under section 609(b) of the Regulatory Flexibility Act as added
by SBREFA. The purpose of the Panel was to collect the advice and
recommendations of representatives of small entities that could be
affected by today's proposed rule and to report on those comments and
the Panel's findings as to issues related to the key elements of the
Regulatory Flexibility Analysis under section 603 of the Regulatory
Flexibility Act. The report of the Panel has been placed in the docket
for this rulemaking.\156\
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\156\ Report of the Small Business Advocacy Panel on Tier 2
Light-Duty Vehicle and Light-Duty Truck Emission Standards, Heavy-
Duty Gasoline Engine Standards, and Gasoline Sulfur Standards,
October 1998.
---------------------------------------------------------------------------
The contents of today's final rule and the Final Regulatory
Flexibility Analysis reflect the recommendations in the Panel's report.
We summarize our outreach to small entities and our responses to the
recommendations of the Panel below.
1. Potentially Affected Small Businesses
The Regulatory Flexibility Analysis identifies small businesses
from the industries in the following table as subject to the provisions
of today's rule:
Table VIII.1.--Industries Containing Small Businesses Potentially Affected by Today's Rule
----------------------------------------------------------------------------------------------------------------
Defined by SBA as a small business
Industry NAICS <INF>a</INF> codes SIC <INF>b</INF> codes if: <INF>c</INF>
----------------------------------------------------------------------------------------------------------------
Motor Vehicle Manufacturers................ 336111 3711 1000 employees.
336112
336120
Alternative Fuel Vehicle Converters........ 336311 3592 500 employees.
541690 8931
336312 3714 750 employees.
422720 5172 100 employees.
454312 5984 7549 $5 million annual sales.
811198 8742
541514
Independent Commercial Importers of 811112 7533 $5 million annual sales.
Vehicles and Vehicle Components. 7549
811198 8742
541514
Petroleum Refiners......................... 324110 2911 1500 employees.
Petroleum Marketers and Distributors....... 422710 5171 5172 100 employees.
422720
----------------------------------------------------------------------------------------------------------------
<INF>a</INF> North American Industry Classification System.
<INF>b</INF> Standard Industrial Classification system.
<INF>c</INF> According to SBA's regulations (13 CFR 121), businesses with no more than the listed number of employees or
dollars in annual receipts are considered ``small entities'' for purposes of a regulatory flexibility
analysis.
The Final RFA identifies about 15 small petroleum refiners, several
hundred small petroleum marketers, and about 15 small certifiers of
covered vehicles (belonging to the other categories in the above table)
that would be subject to the rule.
[[Page 6818]]
2. Small Business Advocacy Review Panel and the Evaluation of
Regulatory Alternatives
The Small Business Advocacy Review Panel was convened by EPA on
August 27, 1998. The Panel consisted of representatives of the Small
Business Administration (SBA), the Office of Management and Budget
(OMB), and EPA. During the development of the proposal, EPA and the
Panel were in contact with representatives from the small businesses
that would be subject to the provisions of the rule. In addition to
verbal comments from industry noted by the Panel at meetings and
teleconferences, we received written comments from each of the affected
industry segments or their representatives. These comments,
alternatives suggested by the Panel to mitigate adverse impacts on
small businesses, and issues the Panel requested EPA take additional
comment on are contained in the report of the Panel and are summarized
below. Today's final rule incorporates the major recommendations of the
Panel.
Fuel-Related Small Business Issues
Most of the small refiners stated that if they were required to
achieve 30 ppm sulfur levels on average with an 80 ppm per-gallon cap
without some regulatory relief, they would be forced out of business.
Thus, the Panel devoted much attention to regulatory alternatives to
address this concern. Most small refiners strongly supported delaying
mandatory compliance for their facilities. On the other hand, most
small refiners stated that a phase-in of gasoline sulfur standards
would not be helpful because it would be more cost-effective for them
to install the maximum technology required for the most stringent
sulfur levels that would ultimately be imposed.
The Society of Independent Gasoline Marketers of America (SIGMA)
commented that EPA should consider giving relief not only to refiners
that meet the SBA definition of small refiner but also to refineries
with relatively small production capacity that are owned by large
refining companies. This was because a refinery with a small production
capacity would operate essentially as an SBA-defined small refiner
would. SIGMA also noted that small gasoline marketers would be affected
by the closure of any refinery with small production capacity, whether
it was owned by a large company or an SBA-defined small refining
company.
The Panel recommended that small refiners be given a four to six
year period of relief during which less stringent gasoline sulfur
requirements would apply. The Panel also advised that EPA specifically
request comment on an alternative duration of ten years for the relief
period. Small refiners would be assigned interim sulfur standards
during this relief period based on their current individual refinery
sulfur levels. Following this relief period, small refiners would be
required to meet the industry-wide standard, although temporary
hardship relief would be available on a case-by-case basis. The Panel
concluded that additional time provided to small refiners before
compliance with the industry-wide standard was required would allow (1)
new sulfur-reduction technologies to be proven-out by larger refiners,
(2) the costs of advanced technology units to drop as the volume of
their sales increases, (3) industry engineering and construction
resources to be freed-up, and (4) the acquisition of the necessary
capital by small refiners.
The Panel also concluded that adding gasoline sulfur to the fuel
parameters already being sampled and tested by gasoline marketers would
likely result in little, if any, additional burden. Therefore, the
Panel did not recommend any special provision for gasoline marketers.
EPA's final action on this issue closely follows the Panel's
recommendations. You can find a description of the small refiner
provisions of today's final rule in Section IV.C.2. above. Comments and
our responses on related issues are collected in the Response to
Comments document.
Vehicle-Related Small Business Issues
Independent commercial importers of vehicles (ICIs) suggested that
the new emissions standards be phased-in with the phase-in schedule
based on the small vehicle manufacturer's annual production volume.
Secondly, the ICIs requested that small testing laboratories be
permitted to use older technology dynamometers than proposed for use by
the Agency. Finally, the ICIs commented that the certification process
should be waived for certain foreign vehicles. Small-volume vehicle
manufacturers (SVMs) stated that a phase-in of Tier-2 emissions
standards is essential. They further stated that SVMs should not be
required to comply until the end of the phase-in period, which should
not be before model year 2007. The SVMs also stated that a case-by-case
hardship relief provision should be provided for their members. SVMs
requested that a credit program be established with incentives for
larger manufacturers to make credits available to SVMs in meeting their
compliance goals.
Based on the above comments, the Panel advised that EPA consider
several alternatives, individually or in combination, for the potential
relief that they might provide to small certifiers of vehicles.
The Final Regulatory Flexibility Analysis evaluates the financial
impacts of the proposed vehicle standards and fuel controls on small
entities. EPA believes that the regulatory alternatives incorporated in
today's final rule will provide substantial relief to small business
from the potential adverse economic impacts of complying with today's
proposed rule.
C. Paperwork Reduction Act
The information collection requirements (ICRs) associated with
today's rule belong to two distinct categories: (1) those that pertain
to amendments to the vehicle certification requirements, and (2) those
that pertain to requirements for the control of gasoline sulfur
content. These information collection requirements are contained in two
separate ICR documents according to the category to which they belong.
The ICR in this final rule that pertains to the amendments to the
vehicle certification requirements has been submitted for approval to
the Office of Management and Budget (OMB) under the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq. Copies of this ICR \157\ can be obtained
from Sandy Farmer, Office of Environmental Information, Collections
Strategy Division, U.S. Environmental Protection Agency (Mail Code
2822), 401 M Street, SW, Washington, D.C. 20460, or by calling (202)
260-2740. Please refer to ICR #783.40 in any correspondence. Copies may
also be downloaded from the internet at http://www.epa.gov/icr.
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\157\ The information collection requirements associated with
the amendments to the requirements for vehicle certification are
contained in the Information Collection Request entitled
``Amendments to the Reporting and Recordkeeping Requirements for
Motor Vehicle Certification Under the Tier 2 Rule'', OMB No. 2060-
0114, EPA ICR # 783.40.
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The ICR in this final rule that pertains to the requirements for
the control of gasoline sulfur will be submitted for approval to the
Office of Management and Budget (OMB) under the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq. The submission to OMB of the ICR document
that contains this ICR and its availability to the public will be
announced in a subsequent Federal Register notice.
[[Page 6819]]
The Agency may not conduct or sponsor an information collection,
and a person is not required to respond to a request for information
unless the information collection request displays a currently valid
OMB control number. The OMB control numbers for EPA's regulations are
listed in 40 CFR Part 9 and 48 CFR Chapter 15. The OMB control numbers
for the information collection requirements in this rule will be listed
in an amendment to 40 CFR part 9 in a subsequent Federal Register
notice after OMB approves the ICRs.
The Paperwork Reduction Act stipulates that ICR documents estimate
the burden of activities required of regulated parties within a three
year time period. Consequently, the ICR documents associated with
today's final rule contain burden estimates for the activities that
will be required under the first three years of the program.
ICRs Pertaining to the Amendments to Vehicle Certification
Requirements: The information collection burden to vehicle certifiers
associated with the amendments to the vehicle certification
requirements in today's notice pertain to the fleet-average
NO<INF>X</INF> standard and emission credits provisions. These
requirements are very similar to those under the voluntary National Low
Emission Vehicle (NLEV) program, which includes a fleet-average
standard for nonmethane hydrocarbon organic gases (NMOG) and associated
emission credits provisions. The hours spent annually by a given
vehicle certifier on the information collection activities associated
with the these recordkeeping and reporting requirements depends upon
certifier-specific variables, including: the scope/variety of their
product line as reflected in the number of test groups and strategy
used to comply with the fleet-average NO<INF>X</INF> standard, the
extent they utilize emissions credits provisions, and whether they
opted into the NLEV program. Vehicle certifiers that use the provisions
for early banking of emission credits will be subject to the associated
information collection requirements as early as September 1, 2000.\158\
All vehicle certifiers will be required to comply with the information
collection requirements associated with the amendments to the vehicle
certification program beginning September 1, 2003.\159\ The ICR
document for the amendments to the vehicle certification program in
this final rule provides burden estimates for all of the associated
information collection requirements. The total information collection
burden associated with the amendments to the vehicle certification
requirements is estimated at 8,406 hours and $567,217 annually for the
certifiers of light-duty vehicles, medium-duty passenger vehicles, and
light-duty trucks.
---------------------------------------------------------------------------
\158\ These ICRs will become effective on the date that model
year 2001 vehicles are introduced into commerce. EPA assumes that
September 1, 2000 is the earliest date that model year 2001 vehicles
will be marketed.
\159\ Assuming model year 2004 vehicles are introduced into
commerce on this date.
---------------------------------------------------------------------------
ICRs Pertaining to the Requirements for Gasoline Sulfur Control:
The information collection burden to gasoline refiners, importers,
marketers, distributors, retailers and wholesale purchaser-consumers
(WPCs), and users of research and development (R&D) gasoline pertain to
the gasoline sulfur control program in today's rule. The scope of the
recordkeeping and reporting requirements for each regulated party, and
therefore the cost to that party, reflects the party's opportunity to
create, control, or alter the sulfur content of gasoline. As a result,
refiners and importers have significant requirements, which are
necessary both for their own tracking, and that of downstream parties,
and for EPA enforcement. Parties downstream from the gasoline
production or import point, such as retailers, have minimal burdens
that are primarily associated with the transfer and retention of
product transfer documents. Many of the reporting and recordkeeping
requirements for refiners and importers regarding the sulfur content of
gasoline currently exist under EPA's Reformulated Gasoline (RFG) and
Anti-Dumping programs. The ICR for the RFG program covered start up
costs associated with reporting gasoline sulfur content under the RFG
program. Consequently, much of the cost of the information collection
requirements under the gasoline sulfur control program has already been
accounted for under the RFG program ICR. In addition, many of the
information collection burdens associated with the sulfur program are
the result of provisions designed to provide refiners with flexibility
in demonstrating compliance with the sulfur standards in the early
years of the program, such as the credit trading and small refiner
programs.
The information collection requirements under the sulfur control
program evolve over time as the program is phased-in. Beginning July 1,
2000, certain requirements apply to parties that voluntarily opt to
generate credits for early sulfur reduction under the average banking
and trading (ABT) provisions. Many of the requirements do not become
applicable until the beginning of the sulfur control program on October
1, 2003, when all refiners are required to meet the sulfur standards.
The information collection requirements under the sulfur control
program become stable after January 1, 2008, when the optional small
refiner provisions expire.\160\
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\160\ A refiner can petition EPA for an extension of the small
refiner provisions beyond January 1, 2008, based on hardship.
---------------------------------------------------------------------------
The ICR document for the sulfur control program in this final rule
will provide burden estimates for the activities required under the
first three years of the program, from July 1, 2000, through June 30,
2003. The burden associated with activities required after June 30,
2003, will be estimated in later ICRs. The initial ICR for the gasoline
sulfur control program, however, will provide a qualitative
characterization of all of the required activities and associated
burdens for the various regulated parties as they develop, and until
they become stable after January 1, 2008.
In the ICR associated with the NPRM for this final rule, we
estimated that the total burden of the information collection
requirements that would be applicable during the first three years of
the proposed gasoline sulfur control program would be 42,479 hours and
$2,149,865 annually.\161\ Annual burden estimates for the various
regulated entities under the initial three year period of the gasoline
sulfur control program were also provided in the NPRM ICR as follows:
---------------------------------------------------------------------------
\161\ The information collection requirements associated with
the proposed gasoline sulfur control program are contained in the
Information Collection Request that accompanied the Tier 2 NPRM
which is entitled ``Recordkeeping and Reporting Requirements
Regarding the Sulfur Content of Motor Vehicle Gasoline Under the
Tier 2 Proposed Rule'', ICR #1907.01. Copies of this ICR can be
obtained as discussed earlier in this section.
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<bullet> Refiners: 31,231 hours; $1,879,822.
<bullet> Importers: 40 hours; $2,067.
<bullet> Pipelines: 85 hours; $2,785.
<bullet> Terminals: 1,700 hours; $55,700.
<bullet> Truckers: 3,333 hours; $118,000.
<bullet> Retailers/WPCs: 6,087 hours; $91,298.
<bullet> R&D Gasoline Users: 3 hours; $193.
We received few comments on the ICR burden estimates in the
proposed sulfur rule. Most regulated parties have been fulfilling
reporting, recordkeeping and testing requirements under the
reformulated and conventional gasoline regulations. The only negative
comments we received related to the batch testing for sulfur content
and sample retention for conventional gasoline. We believe the
estimated cost of complying with these requirements is somewhat higher
than the actual
[[Page 6820]]
burdens industry will realize. The ICR for this final rule will be
adjusted accordingly.
We estimate that there will be some additional costs and hourly
burdens over those estimated in the NPRM associated with certain
changes made to the sulfur program from the NPRM to this final rule. In
particular, this final rule includes a program which provides for
relaxed standards in the early years of the program for refiners and
importers who produce or import gasoline for use in certain states in
the western U.S. This program requires some additional reporting and
recordkeeping burdens for those refiners and importers who participate
in the program, since they will be required to submit an application
for the program, including a baseline for purposes of establishing
their sulfur standard. This program requires gasoline intended for use
in the geographic area to be identified on product transfer documents
and segregated from other gasoline in the distribution system. This
final rule also includes provisions for trading sulfur allotments to
provide refiners and importers additional flexibility in meeting the
corporate pool average standards. This program requires additional
reporting and recordkeeping to track allotment trading activity. In
addition, the final rule requires small refiners to submit information
regarding their crude oil capacity in order to qualify for the small
refiner standards under the rule. Small refiners are also required to
submit reports of their progress toward compliance with the sulfur
standards. The additional total annual cost and hourly burden over the
first three years of the program, as a result of changes made to the
program in the final rule, are estimated to add less than one percent
to the overall burden estimates contained in the NPRM ICR for the
sulfur control program.
Total Burden of the ICRs: In the NPRM, we estimated that the total
burden of the recordkeeping and reporting requirements associated with
the proposed vehicle certification and gasoline sulfur control
requirements would be 50,840 hours and $2,714,037 annually over the
first three years that these requirements would be in effect. In the
ICR document for this final rule which covers the ICRs for the vehicle
certification program, the burden estimates were increased by 45 hours
and $3,045 over the burden estimates in the NPRM ICR. This increase
reflects changes from the NPRM in the final rule associated the
inclusion of the medium-duty passenger vehicles (MDPVs) under the
program. As discussed above, we anticipate that changes to the ICR
document for this final rule which covers the ICRs for the sulfur
control program will have burden estimates less than one percent higher
than the estimates contained in the NPRM. Adding these increased costs
to the burden estimates presented in the NPRM, we arrive at an estimate
of the total burden of the recordkeeping and reporting requirements
associated with the vehicle certification and gasoline sulfur control
requirements in this final rule of less than 51,350 hours and
$2,742,000 annually over the first three years that these requirements
will be in effect. These burden estimates will be more precisely stated
in the forthcoming Federal Register notice which announces the
submission to OMB of the ICR document for this final rule that covers
the ICRs for the sulfur control program and the availability of this
ICR document to the public.
D. Intergovernmental Relations
1. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L.
104-4, establishes requirements for federal agencies to assess the
effects of their regulatory actions on state, local, and tribal
governments, and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``federal mandates'' that
may result in expenditures to state, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more for
any single year. Before promulgating a rule for which a written
statement is needed, section 205 of the UMRA generally requires EPA to
identify and consider a reasonable number of regulatory alternatives
and adopt the least costly, most cost-effective, or least burdensome
alternative that achieves the objectives of the rule. The provisions of
section 205 do not apply when they are inconsistent with applicable
law. Moreover, section 205 allows EPA to adopt an alternative that is
not the least costly, most cost-effective, or least burdensome
alternative if EPA provides an explanation in the final rule of why
such an alternative was adopted.
Before we establish any regulatory requirement that may
significantly or uniquely affect small governments, including tribal
governments, we must develop a small government plan pursuant to
section 203 of the UMRA. Such a plan must provide for notifying
potentially affected small governments, and enabling officials of
affected small governments to have meaningful and timely input in the
development of our regulatory proposals with significant federal
intergovernmental mandates. The plan must also provide for informing,
educating, and advising small governments on compliance with the
regulatory requirements.
This rule contains no federal mandates for state, local, or tribal
governments as defined by the provisions of Title II of the UMRA. The
rule imposes no enforceable duties on any of these governmental
entities. Nothing in the rule would significantly or uniquely affect
small governments.
EPA has determined that this rule contains federal mandates that
may result in expenditures of more than $100 million to the private
sector in any single year. EPA believes that today's final rule
represents the least costly, most cost-effective approach to achieve
the air quality goals of the rule. The cost-benefit analysis required
by the UMRA is discussed in Section IV.D. above and in the Draft RIA.
See the ``Administrative Designation'' and Regulatory Analysis' section
in today's preamble (VIII.A.) for further information regarding these
analyses.
2. Executive Order 13084: Consultation and Coordination With Indian
Tribal Governments
Under Executive Order 13084, EPA may not issue a regulation that is
not required by statute, that significantly or uniquely affects the
communities of Indian Tribal governments, and that imposes substantial
direct compliance costs on those communities, unless the federal
government provides the funds necessary to pay the direct compliance
costs incurred by the tribal governments, or EPA consults with those
governments. If EPA complies by consulting, Executive Order 13084
requires EPA to provide to the Office of Management and Budget, in a
separately identified section of the preamble to the rule, a
description of the extent of EPA's prior consultation with
representatives of affected tribal governments, a summary of the nature
of their concerns, and a statement supporting the need to issue the
regulation. In addition, Executive Order 13084 requires EPA to develop
an effective process permitting elected officials and other
representatives of Indian tribal governments ``to provide meaningful
and timely input in the development of regulatory policies on matters
that significantly or uniquely affect their communities.''
Today's rule does not significantly or uniquely affect the
communities of Indian Tribal governments. The motor
[[Page 6821]]
vehicle emissions, motor vehicle fuel, and other related requirements
for private businesses in today's rule would have national
applicability, and thus would not uniquely affect the communities of
Indian Tribal Governments. Further, no circumstances specific to such
communities exist that would cause an impact on these communities
beyond those discussed in the other sections of today's document. Thus,
EPA's conclusions regarding the impacts from the implementation of
today's rule discussed in the other sections of this preamble are
equally applicable to the communities of Indian Tribal governments.
Accordingly, the requirements of section 3(b) of Executive Order 13084
do not apply to this rule.
3. Executive Order 13132 (Federalism)
Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.
Under Section 6 of Executive Order 13132, EPA may not issue a
regulation that has federalism implications, that imposes substantial
direct compliance costs, and that is not required by statute, unless
the Federal government provides the funds necessary to pay the direct
compliance costs incurred by State and local governments, or EPA
consults with State and local officials early in the process of
developing the proposed regulation. EPA also may not issue a regulation
that has federalism implications and that preempts State law, unless
the Agency consults with State and local officials early in the process
of developing the proposed regulation.
Section 4 of the Executive Order contains additional requirements
for rules that preempt State or local law, even if those rules do not
have federalism implications (i.e., the rules will not have substantial
direct effects on the States, on the relationship between the national
government and the states, or on the distribution of power and
responsibilities among the various levels of government). Those
requirements include providing all affected State and local officials
notice and an opportunity for appropriate participation in the
development of the regulation. If the preemption is not based on
express or implied statutory authority, EPA also must consult, to the
extent practicable, with appropriate State and local officials
regarding the conflict between State law and Federally protected
interests within the agency's area of regulatory responsibility.
This final rule does not have federalism implications. It will not
have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. This rule adopts national
emissions standards for certain categories of motor vehicles and
national standards to control gasoline sulfur. The requirements of the
rule will be enforced by the federal government at the national level.
Thus, the requirements of section 6 of the Executive Order do not apply
to this rule. Although section 6 of Executive Order 13132 does not
apply to this rule, EPA did consult with State and local officials in
developing this rule. In addition, EPA provided state and local
officials an opportunity to comment on the proposed regulations. A
summary of concerns raised by commenters, including state and local
commenters, and EPA's response to those concerns, is found in the
Response to Comments document for this rulemaking.
This final rule preempts State and local controls or prohibitions
respecting gasoline sulfur content, pursuant to Section 211(c)(4) of
the Clean Air Act. The basis and scope of preemption is described in
Section IV.C.1.d of this notice. Although this rule was proposed before
the November 2, 1999 effective date of Executive Order 13132, EPA
provided State and local officials notice and an opportunity for
appropriate participation when it published the proposed rule, as
described above. Thus, EPA has complied with the requirements of
section 4 of the Executive Order.
E. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Section 12(d) of Public Law 104-113, directs EPA
to use voluntary consensus standards in its regulatory activities
unless it would be inconsistent with applicable law or otherwise
impractical. Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) developed or adopted by voluntary consensus
standards bodies. The NTTAA directs EPA to provide Congress, through
OMB, explanations when the Agency decides not to use available and
applicable voluntary consensus standards.
This rule references technical standards adopted by the Agency
through previous rulemakings. No new technical standards are
established in today's rule. The standards referenced in today's rule
involve the measurement of gasoline fuel parameters and motor vehicle
emissions. The measurement standards for gasoline fuel parameters
referenced in today's proposal are all voluntary consensus standards.
The motor vehicle emissions measurement standards referenced in today's
rule are government-unique standards that were developed by the Agency
through previous rulemakings. These standards have served the Agency's
emissions control goals well since their implementation and have been
well accepted by industry. EPA is not aware of any voluntary consensus
standards for the measurement of motor vehicle emissions. Therefore,
the Agency is using the existing EPA-developed standards found in 40
CFR Part 86 for the measurement of motor vehicle emissions
F. Executive Order 13045: Children's Health Protection
Executive Order 13045, ``Protection of Children from Environmental
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies
to any rule that (1) is determined to be ``economically significant''
as defined under Executive Order 12866, and (2) concerns an
environmental health or safety risk that EPA has reason to believe may
have a disproportionate effect on children. If the regulatory action
meets both criteria, section 5-501 of the Order directs the Agency to
evaluate the environmental health or safety effects of the planned rule
on children, and explain why the planned regulation is preferable to
other potentially effective and reasonably feasible alternatives
considered by the Agency.
This rule is subject to the Executive Order because it is an
economically significant regulatory action as defined by Executive
Order 12866 and it concerns in part an environmental health or safety
risk that we have reason to believe may have a disproportionate effect
on children.
This rulemaking will achieve significant reductions of various
emissions from passenger cars and light trucks, primarily
NO<INF>X</INF>, but also NMOG
[[Page 6822]]
and PM. These pollutants raise concerns regarding environmental health
or safety risks that EPA has reason to believe may have a
disproportionate effect on children, such as impacts from ozone, PM and
certain toxic air pollutants. See Section III of this preamble and the
RIA for a further discussion of these issues.
The effects of ozone and PM on children's health were addressed in
detail in EPA's rulemaking to establish the NAAQS for these pollutants,
and we are not revisiting those issues here. We believe, however, that
the emission reductions from the strategies established in this
rulemaking will further reduce air toxics and the related adverse
impacts on children's health. We will be addressing the issues raised
by air toxics from motor vehicles and their fuels in a separate
rulemaking that we will initiate in the near future under section
202(l) of the Act. That rulemaking will address the emissions of
hazardous air pollutants from vehicles and fuels, and the appropriate
level of control of HAPs from these sources.
In this final rule, we have evaluated several regulatory strategies
for reductions in emissions from passenger cars and light trucks. (See
sections IV, V, and VI of this preamble as well as the RIA.) For the
reasons described there, we believe that these strategies are
preferable under the Clean Air Act to other potentially effective and
reasonably feasible alternatives that we considered for purposes of
reducing emissions from these sources (as a way of helping areas
achieve and maintain the NAAQS for ozone and PM). Moreover, we believe
that we have selected for proposal the most stringent and effective
control reasonably feasible at this time, in light of the technology
and cost requirements of the Act.
G. Congressional Review Act
The congressional review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the comptroller General of the
United States. EPA will submit a report containing this rule and other
required information to the U.S. Senate, the U.S. House of
representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. This rule is a
``major rule'' as defined by 5 U.S.C. 804(2).
IX. Statutory Provisions and Legal Authority
Statutory authority for the vehicle controls set in today's final
rule can be found in sections 202, 206, 207, 208, and 301 of the Clean
Air Act (CAA), as amended, 42 U.S.C. sections 7521, 7525, 7541, 7542
and 7601.
Statutory authority for the fuel controls set in today's final rule
comes from section 211(c) of the CAA (42 U.S.C., section 7545(c)),
which allows EPA to regulate fuels that either contribute to air
pollution which endangers public health or welfare or which impair
emission control equipment. Both criteria are satisfied for the
gasoline sulfur controls we are establishing today. Additional support
for the procedural and enforcement-related aspects of the fuel's
controls in today's final rule, including the record keeping
requirements, comes from sections 114(a) and 301(a) of the CAA.
List of Subjects
40 CFR Part 80
Environmental protection, Air pollution control, Fuel additives,
Gasoline, Imports, Incorporation by reference, Labeling, Motor vehicle
pollution, Penalties, Reporting and recordkeeping requirements.
40 CFR Part 85
Environmental protection, Administrative practice and procedure,
Confidential business information, Imports, Labeling, Motor vehicle
pollution, Penalties, Reporting and recordkeeping requirements,
Research, Warranties.
40 CFR Part 86
Environmental protection, Administrative practice and procedure,
Confidential business information, Incorporation by reference,
Labeling, Motor vehicle pollution, Penalties, Reporting and
recordkeeping requirements.
Dated: December 21, 1999.
Carol M. Browner,
Administrator.
For the reasons set forth in the preamble, parts 80, 85 and 86 of
title 40, of the Code of Federal Regulations are amended as follows:
PART 80--REGULATION OF FUELS AND FUEL ADDITIVES
1. The authority citation for part 80 continues to read as follows:
Authority: Secs. 114, 211, and 301(a) of the Clean Air Act, as
amended (42 U.S.C. 7414, 7545 and 7601(a)).
2. Section 80.2 is amended by removing and reserving paragraph
(aa), adding paragraph (d), and revising paragraphs (h), (s) and (gg)
to read as follows:
Sec. 80.2 Definitions.
* * * * *
(d) Previously certified gasoline means gasoline or RBOB that
previously has been included in a batch for purposes of complying with
the standards for reformulated gasoline, conventional gasoline or
gasoline sulfur, as appropriate.
* * * * *
(h) Refinery means any facility, including but not limited to, 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.
* * * * *
(s) Gasoline blending stock, blendstock, or component means any
liquid compound which is blended with other liquid compounds to produce
gasoline.
* * * * *
(gg) Batch of gasoline means a quantity of gasoline that is
homogeneous with regard to those properties that are specified for
conventional or reformulated gasoline.
* * * * *
3. Section 80.46 is amended by revising paragraphs (a) and (h) to
read as follows:
Sec. 80.46 Measurement of reformulated gasoline fuel parameters.
(a) Sulfur. Sulfur content of gasoline and butane must be
determined by use of the following methods:
(1) The sulfur content of gasoline must be determined by use of
American Society for Testing and Materials (ASTM) standard method D
2622-98, entitled ``Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-ray Fluorescence Spectrometry.''
(2) The sulfur content of butane must be determined by the use of
ASTM standard method D 3246-96, entitled ``Standard Test Method for
Sulfur in Petroleum Gas by Oxidative Microcoulometry.''
* * * * *
(h) Incorporations by reference. ASTM standard methods D 2622-98, D
3246-96, D 3606-92, D 1319-93, D 4815-93, and D 86-90 with the
exception of the degrees Fahrenheit figures in Table 9 of D 86-90, are
incorporated by reference. These
[[Page 6823]]
incorporations by reference were approved by the Director of the
Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51.
Copies may be obtained from the American Society for Testing and
Materials, 100 Barr Harbor Dr., West Conshohocken, PA 19428. Copies may
be inspected at the Air Docket Section (LE-131), room M-1500, U.S.
Environmental Protection Agency, Docket No. A-97-03, 401 M Street, SW.,
Washington, DC 20460, or at the Office of the Federal Register, 800
North Capitol Street, NW., Suite 700, Washington, DC.
4. Subpart H is added to part 80 to read as follows:
Subpart H--Gasoline Sulfur
General Information
Sec.
80.180 [Reserved]
80.185 [Reserved]
80.190 Who must register with EPA under the sulfur program?
Gasoline Sulfur Standards
80.195 What are the gasoline sulfur standards for refiners and
importers?
80.200 What gasoline is subject to the sulfur standards and
requirements?
80.205 How is the annual refinery or importer average and
corporate pool average sulfur level determined?
80.210 What sulfur standards apply to gasoline downstream from
refineries and importers?
80.211 [Reserved]
80.212 What requirements apply to oxygenate blenders?
80.213-80.214 [Reserved]
Geographic Phase-In Program
80.215 What is the scope of the geographic phase-in program?
80.216 What standards apply to gasoline produced or imported for
use in the GPA?
80.217 How does a refiner or importer apply for the GPA standards?
80.218 [Reserved]
80.219 Designation and downstream requirements for GPA gasoline.
80.220 What are the downstream standards for GPA gasoline?
Hardship Provisions
80.225 What is the definition of a small refiner?
80.230 Who is not eligible for the hardship provisions for small
refiners?
80.235 How does a refiner obtain approval as a small refiner?
80.240 What are the small refiner gasoline sulfur standards?
80.245 How does a small refiner apply for a sulfur baseline?
80.250 How is the small refiner sulfur baseline and volume
determined?
80.255 Compliance plans and demonstration of commitment to produce
low sulfur gasoline.
80.260 What are the procedures and requirements for obtaining a
hardship extension?
80.265 How will the EPA approve or disapprove a hardship extension
application?
80.270 Can a refiner seek temporary relief from the requirements
of this subpart?
Allotment Trading Program
80.275 How are allotments generated and used?
Averaging, Banking and Trading (ABT) Program--General Information
80.280 [Reserved]
80.285 Who may generate credits under the ABT program?
80.290 How does a refiner apply for a sulfur baseline?
ABT Program--Baseline Determination
80.295 How is a refinery sulfur baseline determined?
80.300 [Reserved]
ABT Program--Credit Generation
80.305 How are credits generated during the time period 2000
through 2003?
80.310 How are credits generated beginning in 2004?
ABT Program--Credit Use
80.315 How are credits used and what are the limitations on credit
use?
80.320 [Reserved]
80.325 [Reserved]
Sampling, Testing and Retention Requirements for Refiners and Importers
80.330 What are the sampling and testing requirements for refiners
and importers?
80.335 What gasoline sample retention requirements apply to
refiners and importers?
80.340 What standards and requirements apply to refiners producing
gasoline by blending blendstocks into previously certified gasoline
(PCG)?
80.345 [Reserved]
80.350 What alternative sulfur standards and requirements apply to
importers who transport gasoline by truck?
80.355 [Reserved]
Recordkeeping and Reporting Requirements
80.360 [Reserved]
80.365 What records must be kept?
80.370 What are the sulfur reporting requirements?
80.371-80.373 [Reserved]
Exemptions
80.374 What if a refiner or importer is unable to produce gasoline
conforming to the requirements of this subpart?
80.375 What requirements apply to California gasoline?
80.380 What are the requirements for obtaining an exemption for
gasoline used for research, development or testing purposes?
Violation Provisions
80.385 What acts are prohibited under the gasoline sulfur program?
80.390 What evidence may be used to determine compliance with the
prohibitions and requirements of this subpart and liability for
violations of this subpart?
80.395 Who is liable for violations under the gasoline sulfur
program?
80.400 What defenses apply to persons deemed liable for a
violation of a prohibited act?
80.405 What penalties apply under this subpart?
Provisions for Foreign Refiners With Individual Sulfur Baselines
80.410 What are the additional requirements for gasoline produced
at foreign refineries having individual small refiner sulfur
baselines, foreign refineries granted temporary relief under
Sec. 80.270, or baselines for generating credits during 2000 through
2003?
Attest Engagements
80.415 What are the attest engagement requirements for gasoline
sulfur compliance applicable to refiners and importers?
Subpart H--Gasoline Sulfur
General Information
Sec. 80.180 [Reserved]
Sec. 80.185 [Reserved]
Sec. 80.190 Who must register with EPA under the sulfur program?
(a) Refiners and importers who are registered by EPA under
Sec. 80.76 are deemed to be registered for purposes of this subpart.
(b) Refiners and importers subject to the standards in Sec. 80.195
who are not registered by EPA under Sec. 80.76 must provide to EPA the
information required by Sec. 80.76 by November 1, 2003, or not later
than three months in advance of the first date that such person
produces or imports gasoline, whichever is later.
(c) Refiners with any refinery subject to the small refiner
standards under Sec. 80.240, or refiners subject to the geographic
phase-in area (GPA) standards under Sec. 80.216, who are not registered
by EPA under Sec. 80.76 must provide to EPA the information required
under Sec. 80.76 by December 31, 2000.
(d) Any refiner who plans to generate credits or allotments under
Sec. 80.305 or Sec. 80.275 in any year prior to 2004 who is not
registered by EPA under Sec. 80.76 must register under Sec. 80.76 no
later than September 30 of the year prior to the first year of credit
generation. Any refiner who plans to generate credits in 2000 who is
not registered by EPA under Sec. 80.76 must register under Sec. 80.76
no later than May 10, 2000.
[[Page 6824]]
Gasoline Sulfur Standards
Sec. 80.195 What are the gasoline sulfur standards for refiners and
importers?
(a)(1) The gasoline produced by small refiners subject to the
standards at Sec. 80.240, and gasoline designated as GPA gasoline under
Sec. 80.219(a), are as follows:
----------------------------------------------------------------------------------------------------------------
Gasoline sulfur standards for the averaging
period beginning:
-----------------------------------------------
January 1,
January 1, January 1, 2006 and
2004 2005 subsequent
----------------------------------------------------------------------------------------------------------------
Refinery or Importer Average.................................... \(1)\ 30.00 30.00
Corporate Pool Average.......................................... 120.00 90.00 \(1)\
Per-Gallon Cap.................................................. 300 300 80
----------------------------------------------------------------------------------------------------------------
\1\ Not applicable.
(2) The sulfur standards and all compliance calculations for sulfur
under this subpart are in parts per million (ppm) and volumes are in
gallons.
(3) The averaging period is January 1 through December 31 of each
year.
(4) The standards under this paragraph (a) for all imported
gasoline shall be met by the importer.
(b)(1) The refinery or importer annual average gasoline sulfur
standard is the maximum average sulfur level allowed for gasoline
produced at a refinery or imported by an importer during each calendar
year starting January 1, 2005.
(2) The annual average sulfur level is calculated in accordance
with Sec. 80.205.
(3) The refinery or importer annual average gasoline sulfur
standard may be met using credits as provided under Sec. 80.275 or
Sec. 80.315.
(4) In 2005 only, the refinery or importer annual average sulfur
standard may be met using credits or allotments as provided under
Sec. 80.275 or credits as provided under Sec. 80.315.
(c)(1) The corporate pool average gasoline sulfur standards
applicable in 2004 and 2005 are the maximum average sulfur levels
allowed for a refiner's or importer's gasoline production from all of
the refiner's refineries or all gasoline imported by an importer in a
calendar year. The corporate pool average standards for a party that is
both a refiner and an importer are the maximum average sulfur levels
allowed for all the party's combined gasoline production from all
refineries and imported gasoline in a calendar year.
(2) The corporate pool average is calculated in accordance with the
provisions of Sec. 80.205.
(3) The corporate pool average standard may be met using sulfur
allotments under Sec. 80.275.
(4) The corporate pool average standards do not apply to approved
small refiners subject to the small refiner gasoline sulfur standards
under Sec. 80.240.
(5)(i) Joint ventures, in which two or more parties collectively
own and operate one or more refineries, will be treated as a separate
refiner under this section.
(ii) One partner to a joint venture may include one or more joint
venture refineries in its corporate pool for purposes of complying with
the corporate pool average standards. The joint venture will be in
compliance for such joint venture refinery(ies) if the partner's
corporate pool average meets the corporate pool average standards. The
joint venture entity must demonstrate compliance with the corporate
pool average standards for any refinery(ies) owned by the joint venture
that are not included in one partner's corporate pool.
(d)(1) The per-gallon cap standard is the maximum sulfur level
allowed for each batch of gasoline produced or imported starting
January 1, 2004.
(2) In 2004 only, a refiner or importer may produce or import
gasoline with a per-gallon sulfur content greater than 300 ppm, to a
maximum of 350 ppm, provided the following conditions are met:
(i) The refinery or importer becomes subject to an adjusted per-
gallon cap standard in 2005, calculated using the following formula:
ACS=300-(S<INF>max</INF>-300)
Where:
ACS=Adjusted cap standard.
S<INF>max</INF>=Maximum sulfur content of any gasoline produced at a
refinery or imported by an importer during 2004.
(ii) The adjusted cap standard calculated under paragraph (d)(2)(i)
of this section applies to all gasoline produced at a refinery or
imported by an importer during 2005.
(iii) The refinery or importer remains subject to the 30.00 average
standard under paragraph (a) of this section for 2005.
(iv) The provisions of this paragraph (d)(2) apply to gasoline
designated as GPA gasoline under Sec. 80.219(a).
(v) The provisions of this paragraph (d)(2) do not apply to small
refiners as defined in Sec. 80.225.
Sec. 80.200 What gasoline is subject to the sulfur standards and
requirements?
For the purpose of this subpart, all reformulated and conventional
gasoline and RBOB, collectively called ``gasoline'' unless otherwise
specified, is subject to the standards and requirements under this
subpart, with the following exceptions:
(a) Gasoline that is used to fuel aircraft, racing vehicles or
racing boats that are used only in sanctioned racing events, provided
that:
(1) Product transfer documents associated with such gasoline, and
any pump stand from which such gasoline is dispensed, identify the
gasoline either as gasoline that is restricted for use in aircraft, or
as gasoline that is restricted for use in racing motor vehicles or
racing boats that are used only in sanctioned racing events;
(2) The gasoline is completely segregated from all other gasoline
throughout production, distribution and sale to the ultimate consumer;
and
(3) The gasoline is not made available for use as motor vehicle
gasoline, or dispensed for use in motor vehicles, except for motor
vehicles used only in sanctioned racing events.
(b) California gasoline as defined in Sec. 80.375.
(c) Gasoline that is exported for sale outside the U.S.
[[Page 6825]]
Sec. 80.205 How is the annual refinery or importer average and
corporate pool average sulfur level determined?
(a) The annual refinery or importer average and corporate pool
average gasoline sulfur level is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR10FE00.007
Where:
S<INF>a</INF>=The refinery or importer annual average sulfur value, or
corporate pool average sulfur value, as applicable.
V<INF>i</INF>=The volume of gasoline produced or imported in batch i.
S<INF>i</INF>=The sulfur content of batch i determined under
Sec. 80.330.
n=The number of batches of gasoline produced or imported during the
averaging period.
i=Individual batch of gasoline produced or imported during the
averaging period.
(b) All annual refinery or importer average or corporate pool
average calculations shall be conducted to two decimal places.
(c) A refiner or importer may include oxygenate added downstream
from the refinery or import facility when calculating the sulfur
content, provided the following requirements are met:
(1) For oxygenate added to conventional gasoline, the refiner or
importer must comply with the requirements of Sec. 80.101(d)(4)(ii).
(2) For oxygenate added to RBOB, the refiner or importer must
comply with the requirements of Sec. 80.69(a).
(d) Refiners and importers must exclude from compliance
calculations all of the following:
(1) Gasoline that was not produced at the refinery;
(2) In the case of an importer, gasoline that was imported as
Certified Sulfur-FRGAS;
(3) Blending stocks transferred to others;
(4) Gasoline that has been included in the compliance calculations
for another refinery or importer; and
(5) Gasoline exempted from standards under Sec. 80.200.
(e)(1) A refiner or importer may exceed the refinery or importer
annual average sulfur standard specified in Sec. 80.195 for a given
averaging period for any calendar year through 2010, creating a
compliance deficit, provided that in the calendar year following the
year the standard is not met, the refinery or importer shall:
(i) Achieve compliance with the refinery or importer annual average
sulfur standard specified in Sec. 80.195; and
(ii) Use additional sulfur credits sufficient to offset the
compliance deficit of the previous year.
(2) No refiner or importer may have a compliance deficit in any
year after 2010. Any deficit that exists in 2010 must be made up in
2011.
(f) For refiners subject to the corporate pool average who produce
some GPA gasoline, the refinery average sulfur value for its GPA
gasoline shall be the average sulfur value after applying credits.
Sec. 80.210 What sulfur standards apply to gasoline downstream from
refineries and importers?
The sulfur standard for gasoline at any point in the gasoline
distribution system downstream from refineries and import facilities,
including gasoline at facilities of distributors, carriers, oxygenate
blenders, retailers and wholesale purchaser-consumers (``downstream
location''), shall be determined in accordance with the provisions of
this section.
(a) Definition. S-RGAS means gasoline that is subject to the
standards under Sec. 80.240 or Sec. 80.270, including Certified Sulfur-
FRGAS as defined in Sec. 80.410, except that no batch of gasoline may
be classified as S-RGAS if the actual sulfur content is less than the
applicable per-gallon refinery cap standard specified in Sec. 80.195.
(b) Standards for gasoline that does not qualify for S-RGAS
downstream standards. The following standards apply to any gasoline
that does not qualify for S-RGAS downstream standards under in
paragraph (d) of this section:
(1) Starting February 1, 2004 the sulfur content of gasoline at any
downstream location other than at a retail outlet or wholesale
purchaser-consumer facility, and starting March 1, 2004 the sulfur
content of gasoline at any downstream location, shall not exceed 378
ppm.
(2) Except as provided in Sec. 80.220(a), starting February 1, 2005
the sulfur content of gasoline at any downstream location other than at
a retail outlet or wholesale purchaser-consumer facility, and starting
March 1, 2005 the sulfur content of gasoline at any downstream
location, shall not exceed 326 ppm.
(3) Except as provided in Sec. 80.220(a), starting February 1, 2006
the sulfur content of gasoline at any downstream location other than at
a retail outlet or wholesale purchaser-consumer facility, and starting
March 1, 2006 the sulfur content of gasoline at any downstream
location, shall not exceed 95 ppm.
(c) Standards for gasoline that qualifies for S-RGAS downstream
standards. In the case of any gasoline that qualifies for S-RGAS
downstream standards under paragraph (d) of this section, the sulfur
standard shall be the downstream standard for the gasoline calculated
under paragraph (f) of this section. In the case of mixtures of
gasoline that qualify for different S-RGAS downstream standards, the
sulfur standard shall be the highest downstream standard applicable to
any of the S-RGAS in the mixture.
(d) Gasoline that qualifies for S-RGAS downstream standards.
Gasoline qualifies for S-RGAS downstream standards if all of the
following conditions are met:
(1) The gasoline must be comprised in whole or part of S-RGAS.
(2) Product transfer documents applicable to the gasoline when
received at that location must represent that the gasoline contains S-
RGAS.
(3) Except as provided in paragraph (d)(4) of this section, the
gasoline must have been sampled and tested at that location subsequent
to the most recent receipt of gasoline at that location, and the test
result must show a sulfur content greater than:
(i) 350 ppm starting February 1, 2004;
(ii) 300 ppm starting February 1, 2005; and
(iii) 80 ppm (or in the GPA, 300 ppm) starting February 1, 2006.
(4) This sampling and testing condition does not apply for gasoline
at any retail outlet, wholesale purchaser-consumer facility, or
contained in any transport truck.
(e) Product transfer document information for S-RGAS. (1) On each
occasion when any refiner or importer of S-RGAS transfers custody or
title to such gasoline, the refiner or importer shall provide to the
transferee documents that include the following information:
(i) Identification of the gasoline as being S-RGAS; and
(ii) The downstream standard applicable to the batch of gasoline
under paragraph (f) of this section.
(2) Where gasoline in whole or part is classified as S-RGAS when
received by the transferor, and where the gasoline transferred meets
the conditions under paragraph (d) of this section, the transferor
shall provide to the transferee, on each occasion when custody or title
to gasoline is transferred, documents that include the following
information:
(i) Identification of the gasoline as S-RGAS; and
[[Page 6826]]
(ii) The applicable downstream standard under paragraph (c) of this
section. This does not apply when gasoline is sold or dispensed for use
in motor vehicles at a retail outlet or wholesale purchaser-consumer
facility.
(3) No person shall classify gasoline as being S-RGAS except as
provided in paragraphs (e)(1) and (e)(2) of this section.
(4) Product codes may be used to convey the information required by
paragraphs (e)(1) and (e)(2) of this section if such codes are clearly
understood by each transferee.
(f) Downstream standards applicable to S-RGAS when produced or
imported. (1) The downstream standard applicable to any gasoline
classified as S-RGAS when produced or imported shall be calculated
using the following equation:
D=S+105 x ((S+2)/10<SUP>4</SUP>)<SUP>0.4</SUP>
Where:
D=Downstream sulfur standard.
S=The sulfur content of the refiner's batch determined under
Sec. 80.330.
(2) Where more than one S-RGAS batch is combined, prior to
shipment, at the refinery or import facility where the S-RGAS is
produced or imported, the downstream standard applicable to the mixture
shall be the highest downstream standard, calculated under paragraph
(f)(1) of this section, for any S-RGAS contained in the mixture.
Sec. 80.211 [Reserved]
Sec. 80.212 What requirements apply to oxygenate blenders?
Effective January 1, 2004, oxygenate blenders who blend oxygenate
into gasoline downstream of the refinery that produced the gasoline or
the import facility where the gasoline was imported, are not subject to
the requirements of this subpart applicable to refiners for this
gasoline, but are subject to the requirements and prohibitions
applicable to downstream parties and the prohibition specified in
Sec. 80.385(e).
Secs. 80.213-80.214 [Reserved]
Geographic Phase-In Program
Sec. 80.215 What is the scope of the geographic phase-in program?
(a) Geographic phase-in area. (1) The following states comprise the
geographic phase-in area (GPA) subject to the provisions of the
geographic phase-in program: North Dakota, Montana, Idaho, Wyoming,
Utah, Colorado, New Mexico, and Alaska.
(2) Additional counties or tribal lands in states adjacent to the
states identified in paragraph (a) of this section will be included in
the GPA if any of the following criteria is met:
(i) Approximately 50% or more of the total volume of gasoline in
the county or tribal land in 1999, as measured at the terminal(s) and
bulk station(s) in the county or tribal land, was received from a
refinery or refineries located in the area specified in paragraph
(a)(1) of this section; or
(ii) Approximately 50% or more of the total volume of gasoline
dispensed in the county or tribal land in 1999 was received from a
refinery or refineries located in the area specified in paragraph
(a)(1) of this section; or
(iii) Approximately 50% or more of the total commercial and private
dispensing outlets in the county or tribal land in 1999 were supplied
by gasoline produced by a refinery or refineries located in the area
specified in paragraph (a)(1) of this section.
(3) The criteria of paragraphs (a)(2)(i), (ii) and (iii) of this
section are without regard to the method of gasoline delivery (e.g,
pipeline, truck, rail or barge). The criteria of paragraphs (a)(2)(ii)
and (a)(2)(iii) of this section are without regard to whether the
gasoline was transported directly from the refinery to the dispensing
outlet or distributed through a terminal or bulk station.
(b) Duration of the program. The geographic phase-in program
applies to the 2004, 2005, and 2006 annual averaging periods.
(c) Persons eligible. Any refiner or importer who produces or
imports gasoline for use in the geographic area under paragraph (a) of
this section is eligible to apply for the geographic phase-in program.
The provisions of the geographic phase-in program shall apply to
imported gasoline through the importer.
Sec. 80.216 What standards apply to gasoline produced or imported for
use in the GPA?
(a)(1) The refinery or importer annual average sulfur standard for
gasoline produced or imported for use in the geographic area under
Sec. 80.215 shall be the lesser of:
(i) 150 ppm; or
(ii) The refinery's or importer's 1997/1998 average sulfur level,
calculated in accordance with Sec. 80.295, plus 30 ppm.
(2) In the case of any refinery whose actual annual sulfur average
decreases to a level lower than the refinery's annual average sulfur
standard established under paragraph (a)(1) of this section during the
period 2000 through 2003, the standard applicable to that refinery from
2004 through 2006 shall be the lowest average sulfur content for any
year in which the refinery generated allotments or credits under
Sec. 80.275(a) or Sec. 80.305 plus 30 ppm, not to exceed 150 ppm.
(b) The per-gallon cap standard for gasoline produced or imported
for use in the GPA under paragraph (a) of this section shall be 300
ppm, except as specified in Sec. 80.195(d).
(c) The refinery or importer annual average sulfur level is
calculated in accordance with the provisions of Sec. 80.205.
(d) The refinery or importer annual average standard under
paragraph (a) of this section may be met using sulfur allotments or
credits as provided under Secs. 80.275 and 80.315.
(e) Gasoline produced by approved small refiners subject to the
standards under Sec. 80.240 is not subject to the standards under
paragraphs (a) and (b) of this section.
(f)(1) A refiner or importer whose gasoline production or volume of
imported gasoline in 2004 or 2005 is comprised of <gr-thn-eq>50% of
gasoline designated as GPA gasoline under Sec. 80.219 shall not be
required to meet the corporate pool average standards under Sec. 80.195
for its gasoline production or imported gasoline during the applicable
averaging period.
(2) A refiner or importer whose gasoline production or volume of
imported gasoline in 2004 or 2005 is comprised of less than 50% of
gasoline designated as GPA gasoline under Sec. 80.219 must meet the
corporate pool average standards under Sec. 80.195 for all the
refiner's gasoline production or the importer's volume of imported
gasoline during the applicable averaging period.
(g) The provisions for compliance deficits under Sec. 80.205(e) do
not apply to gasoline subject to the standards under paragraphs (a) and
(b) of this section.
Sec. 80.217 How does a refiner or importer apply for the GPA
standards?
(a) To apply for the GPA standards under Sec. 80.216, a refiner or
importer must submit an application in accordance with the provisions
of Sec. 80.290.
(b) Applications under paragraph (a) of this section must be
submitted by December 31, 2000.
(c)(1) If approved, EPA will notify the refiner or importer of each
refinery's or the importer's annual average sulfur standard for
gasoline produced for use in the GPA for the 2004 through 2006 annual
averaging periods.
(2) If disapproved, the refiner or importer must comply with the
standards in Sec. 80.195 for gasoline produced for use in the GPA.
(d) If EPA finds that a refiner or importer provided false or
inaccurate
[[Page 6827]]
information on its application under this section, upon notice from
EPA, the refiner's or importer's application will be void ab initio.
Sec. 80.218 [Reserved]
Sec. 80.219 Designation and downstream requirements for GPA gasoline.
The requirements and prohibitions specified in this section apply
during the period January 1, 2004 through December 31, 2006.
(a) Designation. Any refiner or importer shall designate any
gasoline produced or imported that is subject to the standards under
Sec. 80.216 as ``GPA'' gasoline.
(b) Product transfer documents. (1) On each occasion that any
person transfers custody or title to gasoline designated as GPA
gasoline, other than when gasoline is sold or dispensed for use in
motor vehicles at a retail outlet or wholesale purchaser-consumer
facility, the transferor shall provide to the transferee documents that
include the following information:
(i) Identification of the gasoline as being GPA gasoline;
(ii) A statement that the gasoline may not be distributed or sold
for use outside the geographic phase-in area.
(2) Except for transfers to truck carriers, retailers and wholesale
purchaser-consumers, product codes may be used to convey the
information required by paragraph (b)(1) of this section if such codes
are clearly understood by each transferee.
(3) The requirements under paragraph (b)(1) of this section are in
addition to the requirement under Sec. 80.210(e), where appropriate, to
identify gasoline as being S-RGAS.
(c) GPA gasoline use prohibitions. (1) All parties in the
distribution system, including refiners, importers, distributors,
carriers, oxygenate blenders, retailers and wholesale purchaser-
consumers, are prohibited from:
(i) Selling, offering for sale, dispensing, distributing, storing
or transporting GPA gasoline for use outside the geographic phase-in
area; and
(ii) Commingling GPA gasoline with gasoline not designated as GPA
gasoline unless the mixture is classified as GPA gasoline.
(2) Gasoline not designated as GPA gasoline may be distributed or
sold for use in the geographic phase-in area.
Sec. 80.220 What are the downstream standards for GPA gasoline?
(a) GPA gasoline. (1) During the period February 1, 2004 through
January 31, 2005, the sulfur content of GPA gasoline at any downstream
location other than at a retail outlet or wholesale purchaser-consumer
facility, and during the period March 1, 2004 through February 28,
2005, the sulfur content of GPA gasoline at any downstream location
shall not exceed 378 ppm.
(2) During the period February 1, 2005 through January 31, 2007,
the sulfur content of GPA gasoline at any downstream location other
than at a retail outlet or wholesale purchaser-consumer facility, and
during the period March 1, 2005 through February 28, 2007, the sulfur
content of GPA gasoline at any downstream location shall not exceed 326
ppm.
(b) GPA gasoline mixed with S-RGAS. Notwithstanding the
requirements in paragraph (a) of this section, the sulfur standard
applicable to a mixture of GPA gasoline and S-RGAS gasoline at a
downstream location shall be the greater of the standard under
paragraph (a) of this section or the standard determined under
Sec. 80.210.
Hardship Provisions
Sec. 80.225 What is the definition of a small refiner?
(a) A small refiner is defined as any person, as defined by 42
U.S.C. 7602(e), who: (1)(i) Produces gasoline at a refinery by
processing crude oil through refinery processing units;
(ii) Employed an average of no more than 1,500 people, based on the
average number of employees for all pay periods from January 1, 1998,
to January 1, 1999; and
(iii) Had an average crude capacity less than or equal to 155,000
barrels per calendar day (bpcd) for 1998.
(2) For the purpose of determining the number of employees and
crude capacity under paragraph (a)(1) of this section, the refiner
shall include the employees and crude capacity of any subsidiary
companies, any parent company and subsidiaries of the parent company,
and any joint venture partners.
(b) The definition under paragraph (a) of this section applies to
domestic and foreign refiners. For any refiner owned by a governmental
entity, the number of employees as specified in paragraph (a) of this
section shall include all employees of the governmental entity.
(c) If, without merger with, or acquisition of, another business
unit, a company with approved small refiner status under Sec. 80.235
exceeds 1,500 employees, or a corporate crude capacity of 155,000 bpcd
after January 1, 1999, it will be considered a small refiner for the
duration of the small refiner program.
(d) Notwithstanding the definition in paragraph (a) of this
section, refiners who acquire a refinery after January 1, 1999, or
reactivate a refinery that was shutdown or was non-operational between
January 1, 1998, and January 1, 1999, may apply for small refiner
status in accordance with the provisions of Sec. 80.235.
Sec. 80.230 Who is not eligible for the hardship provisions for small
refiners?
(a) The following are not eligible for the hardship provisions for
small refiners:
(1) Refiners of refineries built after January 1, 1999;
(2) Refiners who exceed the employee or crude oil capacity criteria
under Sec. 80.225(a) on January 1, 1999, but who meet these criteria
after that date, regardless of whether the reduction in employees or
crude capacity is due to operational changes at the refinery or a
company sale or reorganization;
(3) Importers; and
(4) Refiners who produce gasoline other than by processing crude
oil through refinery processing units.
(b)(1) Refiners who qualify as small under Sec. 80.225, and
subsequently employ more than 1,500 people as a result of merger with
or acquisition of or by another entity, are disqualified as small
refiners. If this occurs the refiner shall notify EPA in writing no
later than 20 days following this disqualifying event.
(2) Any refiner who qualifies as small under Sec. 80.225 may elect
to meet the standards under Sec. 80.195 by notifying EPA in writing no
later than November 15 prior to the year the change will occur.
(3) Any refiner whose status changes under paragraph (b)(1) or (2)
of this section shall meet the standards under Sec. 80.195 beginning
with the first averaging period subsequent to the status change.
Sec. 80.235 How does a refiner obtain approval as a small refiner?
(a) Applications for small refiner status must be submitted to EPA
by December 31, 2000, except for applications submitted pursuant to
Sec. 80.225(d), which must be submitted by June 1, 2002.
(b) Applications for small refiner status must be sent to: U.S.
EPA, Attn: Sulfur Program (6406J), 401 M Street, SW, Washington, DC
20460. For commercial delivery: U.S. EPA, Attn: Sulfur Program (6406J),
501 3rd Street, NW, Washington, DC 20001.
(c) The small refiner status application must contain the following
information for the company seeking
[[Page 6828]]
small refiner status, plus any subsidiary companies, any parent company
and subsidiaries of the parent company, and any joint venture partners:
(1)(i) A listing of the name and address of each location where any
employee worked during the 12 months preceding January 1, 1999; the
average number of employees at each location based upon the number of
employees for each pay period for the 12 months preceding January 1,
1999; and the type of business activities carried out at each location;
or
(ii) In the case of a refiner who acquires a refinery after January
1, 1999, or reactivates a refinery that was shutdown between January 1,
1998, and January 1, 1999, a listing of the name and address of each
location where any employee of the refiner worked since the refiner
acquired or reactivated the refinery; the average number of employees
at any such acquired or reactivated refinery during each calendar year
since the refiner acquired or reactivated the refinery; and the type of
business activities carried out at each location.
(2) The total corporate crude capacity of each refinery as reported
to the Energy Information Administration (EIA) of the U.S. Department
of Energy (DOE). The information submitted to EIA is presumed to be
correct. In cases where a company disagrees with this information, the
company may petition EPA with appropriate data to correct the record
within 60 days after the company submits its application for small
refiner status.
(3) A letter signed by the president, chief operating or chief
executive officer of the company, or his/her designee, stating that the
information contained in the application is true to the best of his/her
knowledge.
(4) Name, address, phone number, facsimile number and E-mail
address (if available) of a corporate contact person.
(d) For joint ventures, the total number of employees includes the
combined employee count of all corporate entities in the venture.
(e) For government-owned refiners, the total employee count
includes all government employees.
(f) Approval of small refiner status for refiners who apply under
Sec. 80.225(d) will be based on all information submitted under
paragraph (c) of this section. Where appropriate, the employee and
crude oil capacity criteria for such refiners will be based on the most
recent 12 months of operation.
(g) EPA will notify a refiner of approval or disapproval of small
refiner status by letter.
(1) If approved, EPA will notify the refiner of each refinery's
applicable baseline standard and volume, and per-gallon cap under
Sec. 80.240.
(2) If disapproved, the refiner must comply with the standards in
Sec. 80.195.
(h) If EPA finds that a refiner provided false or inaccurate
information on its application for small refiner status, upon notice
from EPA the refiner's small refiner status will be void ab initio.
(i) Upon notification to EPA, an approved small refiner may
withdraw its status as a small refiner. Effective on January 1 of the
year following such notification, the small refiner will become subject
to the standards at Sec. 80.195.
Sec. 80.240 What are the small refiner gasoline sulfur standards?
(a) The gasoline sulfur standards for an approved small refiner are
as follows:
----------------------------------------------------------------------------------------------------------------
Temporary sulfur standards for small refiners applicable from January
1, 2004 through December 31, 2007
Refinery baseline sulfur level ------------------------------------------------------------------------
Annual average Per gallon cap
----------------------------------------------------------------------------------------------------------------
0 to 30................................ 30.00 300
31 to 200.............................. Baseline level 300
201 to 400............................. 200.00 300
401 to 600............................. 50% of baseline Factor of 1.5 times the average
standard.
601 and above.......................... 300.00 450
----------------------------------------------------------------------------------------------------------------
(b) The refinery annual average sulfur standards must be met on an
annual calendar year basis for each refinery owned by a small refiner.
The refinery annual average sulfur level is calculated in accordance
with the provisions of Sec. 80.205.
(c)(1) The refinery annual average standards specified in paragraph
(a) of this section apply to the volume of gasoline produced by a small
refiner's refinery up to the lesser of:
(i) 105% of the baseline gasoline volume as determined under
Sec. 80.250(a)(1); or
(ii) The volume of gasoline produced at that refinery during the
averaging period by processing crude oil.
(2) If a refiner exceeds the volume limitation in paragraph (c)(1)
of this section during any averaging period, the annual average sulfur
standard applicable to the refiner for that averaging period is
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR10FE00.008
Where:
S<INF>sr</INF>=Small refiner annual average sulfur standard.
V<INF>b</INF>=Applicable volume under paragraph (c)(1) of this section.
V<INF>a</INF>=Averaging period gasoline volume.
S<INF>b</INF>=Small refiner sulfur baseline as determined under
Sec. 80.250.
AF=Adjustment factor (120 in 2004; 90 in 2005; and 30 in 2006 and
thereafter).
(3) The small refiner average standards under paragraph (a) of this
section may be met using sulfur allotments or credits as provided under
Sec. 80.275 or Sec. 80.315.
(4) The provisions for compliance deficits under Sec. 80.205(e) do
not apply to small refiners subject to the standards under this
section.
(d) In the case of any refiner with small refiner status who
generates sulfur allotments or credits pursuant to Sec. 80.275(a) or
Sec. 80.305, the baseline applicable to that refiner's refinery for
purposes of establishing the standard for the refinery under paragraph
(a) of this section beginning in 2004 shall be the lowest annual
average sulfur content for any year during the period in which the
refiner generated allotments or credits.
Sec. 80.245 How does a small refiner apply for a sulfur baseline?
(a) Any refiner seeking small refiner status must apply for a
refinery sulfur baseline by the deadline under Sec. 80.235 for each of
the refiner's refineries by providing the following information:
[[Page 6829]]
(1) A sulfur baseline and baseline volume for every refinery
calculated in accordance with Sec. 80.250.
(2) The following information for each batch of gasoline produced
in 1997-1998:
(i) Batch number assigned to the batch under Sec. 80.65(d) or
Sec. 80.101(i);
(ii) Volume; and
(iii) Sulfur content.
(3) For any refiner who acquires a refinery after January 1, 1999,
or reactivates a refinery that was shut down or non-operational between
January 1, 1998, and January 1, 1999, the average sulfur level and
average volume of gasoline produced during each year the refinery was
in operation after the refinery was acquired or reactivated. Where
appropriate, the baseline sulfur level and volume for such refineries
will be determined based on the annual average for the most recent year
of operation.
(b) The sulfur baseline application must be submitted to the
address specified in Sec. 80.235(b).
Sec. 80.250 How is the small refiner sulfur baseline and volume
determined?
(a)(1) The small refiner baseline volume is determined for each
refinery as follows:
[GRAPHIC] [TIFF OMITTED] TR10FE00.009
Where:
V<INF>B</INF>=Baseline volume.
V<INF>I</INF>=Volume of gasoline batch i.
n=Total number of batches of gasoline produced from January 1, 1997,
through December 31, 1998.
i=Individual batch of gasoline produced from January 1, 1997, through
December 31, 1998.
(2) The small refiner sulfur baseline is determined for each
refinery as follows:
[GRAPHIC] [TIFF OMITTED] TR10FE00.010
Where:
S<INF>b</INF>=Small refiner sulfur baseline.
V<INF>i</INF>=Volume of gasoline batch i.
S<INF>i</INF>=Sulfur content of batch i.
n=Total number of batches of gasoline produced from January 1, 1997,
through December 31, 1998.
i=Individual batch of gasoline produced from January 1, 1997, through
December 31, 1998.
(b) Foreign refiners who do not have an approved refinery baseline
under Sec. 80.94 must follow the procedures specified in
Sec. 80.410(b).
(c) If at any time a small refinery baseline is determined to be
incorrect, the corrected baseline applies ab initio and the annual
average standards and cap standards are deemed to be those applicable
under the corrected information.
Sec. 80.255 Compliance plans and demonstration of commitment to
produce low sulfur gasoline.
The requirements of this section apply to any refiner approved for
small refiner standards who wishes to be eligible for a hardship
extension under Sec. 80.260.
(a) Compliance commitment. By no later than June 1, 2004, any
refiner who is approved for small refinery standards must submit a
preliminary report to EPA which outlines the refiner's timeline for
compliance and a project plan which discusses permits, capital
commitments and engineering plans for making the necessary
modifications to produce gasoline that meets the 30 ppm refinery
average and 80 ppm per-gallon cap sulfur standards under Sec. 80.195 on
or before January 1, 2008. Documents showing activities and progress in
these areas should be provided, if available.
(b) Demonstration of Progress. (1)(i) By no later than June 1,
2005, the small refiner must submit a report to EPA that states in
detail the progress toward compliance with the 30 ppm refinery average
and 80 ppm cap sulfur standards to date based on their timeline and
project plan. The report must include:
(A) Copies of approved permits for construction of the equipment,
or the permit application if approval is still pending;
(B) Copies of contracts for design and construction; and
(C) Any available evidence of having secured the necessary
financing to complete the required construction;
(ii) If the refiner anticipates any difficulties in meeting its
compliance commitments under this section, the refiner must submit a
detailed report of all efforts made to date and the factors that may
cause delay, including costs, specification of engineering or other
design work needed and reasons for delay, specification of equipment
needed and any reasons for delay, potential equipment suppliers and
history of negotiations, and any other relevant information. If
unavailability of equipment is a factor, the report must include a
discussion of other options considered and the reasons these other
options are not feasible.
(2) By no later than June 1, 2006, the small refiner must submit to
EPA evidence that on-site construction has begun and that, absent
unforeseen difficulties, the small refiner will be producing complying
gasoline by January 1, 2008. If construction has not begun, the refiner
must demonstrate that it has made all reasonable efforts to begin
construction, that substantial progress is being made to begin
construction as soon as possible, and that construction can be
completed in time to begin production of gasoline that complies with
the standards of Sec. 80.195 by January 1, 2008.
(c) Additional information. The Administrator may request any
additional information necessary to determine a refiner's commitment
and/or progress toward meeting the standards in Sec. 80.195 by 2008.
(d) Failure to comply with requirements. Any small refiner who
fails to submit the progress reports required under this section will
not be eligible for a hardship extension under Sec. 80.260.
Sec. 80.260 What are the procedures and requirements for obtaining a
hardship extension?
(a) An approved small refiner who has filed the reports specified
in Sec. 80.255 may apply to EPA for a hardship extension of the small
refiner standards for calendar years 2008 and 2009. The application
must be submitted in writing no later than January 1, 2007, to U.S.
EPA, Attn: Sulfur Program (6406J), 401 M Street, SW, Washington, DC
20460. For commercial (non-postal) delivery: U.S. EPA, Attn: Sulfur
Program, 501 3rd Street NW, Washington, DC 20001.
(b) The application must specify the factors that demonstrate a
significant economic hardship and must provide a detailed discussion
regarding the inability of the refinery to produce gasoline meeting the
requirements of Sec. 80.195. Such an application must include, at a
minimum, the following information:
(1) Documentation of efforts made to obtain necessary financing,
including:
(i) Copies of loan applications for the necessary financing of the
construction of appropriate sulfur reduction technology and other
equipment procurements or improvements; and
(ii) If financing has been disapproved or is otherwise
unsuccessful, documents supporting the basis for that disapproval and
evidence of efforts to pursue other means of financing;
(2) A detailed analysis of the reasons the refinery is unable to
produce gasoline meeting the standards of
[[Page 6830]]
Sec. 80.195 in 2008, including costs, specification of equipment still
needed, potential equipment suppliers, and efforts already completed to
obtain the necessary equipment;
(3) If unavailability of equipment is part of the reason for the
inability to comply, a discussion of other options considered, and the
reasons these other options are not feasible;
(4) If relevant, a demonstration that a needed or lower cost
technology is immediately unavailable, but will be available in the
near future, and full information regarding when and from what sources
it will be available;
(5) Schematic drawings of the refinery configuration as of January
1, 1999, and as of the date of the hardship extension application, and
any planned future additions or changes;
(6) If relevant, a demonstration that a temporary unavailability
exists of engineering or construction resources necessary for design or
installation of the needed equipment;
(7) If sources of crude oil lower in sulfur than what the refiner
is currently using are available, full information regarding the
availability of these different crude sources, the sulfur content of
those crude sources, the cost of the different crude sources over the
past five years, and an estimate of gasoline sulfur levels achievable
by the refinery if the lower sulfur crude sources were used;
(8) A discussion of any sulfur reductions that can be achieved from
current levels;
(9) The date the refiner anticipates compliance with the standards
in Sec. 80.195 can be achieved at its refinery;
(10) An analysis of the economic impact of compliance on the
refiner's business (including financial statements from the last 5
years, or for any time period up to 10 years, at EPA's request); and
(11) Any other information regarding other strategies considered,
including strategies or components of strategies that do not involve
installation of equipment, and why meeting the standards in Sec. 80.195
beginning in 2008 is infeasible.
(c) The hardship extension application must contain a letter signed
by the president or the chief operating or chief executive officer of
the company, or his/her designee, stating that the information
contained in the application is true to the best of his/her knowledge.
Sec. 80.265 How will the EPA approve or disapprove a hardship
extension application?
(a) EPA will evaluate each application for hardship extension on a
case-by-case basis. The factors considered for a hardship extension may
include: The refiner's financial position and efforts to obtain capital
funding; the refiner's efforts to procure necessary equipment, obtain
design and engineering services and construction contractors; the
availability of desulfurization equipment; and any other relevant
factor. An extension will be granted for a refinery for the 2008
averaging period if the small refiner who owns the refinery adequately
demonstrates that severe economic hardship would result if compliance
with the standards in Sec. 80.195 is required in 2008, or that
compliance with the standard in 2008 is not feasible for reasons beyond
the refiner's control, and that the refiner has made the best efforts
possible to achieve compliance with the national standards by January
1, 2008. Upon reapplication by the refiner, if EPA determines that
further relief is appropriate, EPA may grant a further extension
through the 2009 averaging period. In no case will a further extension
for the 2009 averaging period be granted unless the refiner
demonstrates conclusively that it has financing in place and that it
will be able to complete construction and meet the national gasoline
sulfur standards no later than December 31, 2009.
(b) EPA may request more information, if necessary, for evaluation
of the application. If requested information is not submitted within
the time specified in EPA's request, or any extensions granted, the
application may be denied.
(c) EPA will notify the refiner of approval or disapproval of
hardship extension by letter.
(1) If approved, EPA will also notify the refiner of the date that
full compliance with the standards specified at Sec. 80.195 must be
achieved or what interim sulfur levels or schedules apply, if any.
(2) If disapproved, beginning January 1, 2008, the refinery is
subject to the requirements in Sec. 80.195. Refiners who receive an
extension for the 2008 averaging period shall meet the standards in
Sec. 80.195 beginning on January 1, 2009, unless EPA grants an
extension of the hardship relief for an additional year. If such an
additional extension is granted, the refiner shall meet the standards
in Sec. 80.195 on January 1, 2010.
(d) Refiners who receive a hardship extension may be required to
meet more stringent standards than those which apply to them during
2007, and/or could be required to offset excess sulfur levels. EPA may
impose reasonable conditions on an extension, such as requiring
segregation of the small refiner's gasoline or requiring the gasoline
to be sold for use in older vehicles only.
Sec. 80.270 Can a refiner seek temporary relief from the requirements
of this subpart?
(a) EPA may permit a refiner to produce and distribute gasoline
which does not meet the requirements of this subpart if the refiner
demonstrates that:
(1) Unusual circumstances exist that impose extreme hardship and
significantly affect ability to comply by the applicable date; and
(2) It has made best efforts to comply with the requirements of
this subpart (including making efforts to obtain credits and/or
allotments).
(b) Applications must be submitted to EPA by September 1, 2000.
Relief may be granted from some or all of the requirements of this
subpart, at EPA's discretion; however, EPA reserves the right to deny
applications for appropriate reasons, including unacceptable
environmental impact. Approval to distribute gasoline which does not
meet the requirements of this subpart may be granted for such time
period as EPA determines is appropriate, but shall not extend beyond
January 1, 2008.
(c)(1) Applications must include a plan demonstrating how the
refiner will comply with the requirements of this subpart as
expeditiously as possible. The plan shall include a showing that
contracts are or will be in place for engineering and construction of
desulfurization equipment, a plan for applying for and obtaining any
permits necessary for construction, a description of plans to obtain
necessary capital, and a detailed estimate of when the requirements of
this subpart will be met.
(2) Applications must include a detailed description of the
refinery configuration and operations, including, at a minimum, the
following information:
(i) The portion of gasoline production that is produced using an
FCC unit;
(ii) The refinery's hydrotreating capacity;
(iii) The refinery's total reformer unit throughput capacity;
(iv) The refinery's total crude capacity;
(v) Total crude capacity of any other refineries owned by the same
entity;
(vi) Total volume of gasoline production at the refinery;
(vii) Total volume of other refinery products; and
(viii) Geographic location(s) in which gasoline will be sold.
(3) Applications must include, at a minimum, the following
information:
[[Page 6831]]
(i) Detailed description of efforts to obtain capital for refinery
investments;
(ii) Bond rating of entity that owns the refinery; and
(iii) Estimated capital investment needed to comply with the
requirements of this subpart by the applicable date.
(4) Applicants must also provide any other relevant information
requested by EPA.
(d) EPA may impose any reasonable conditions on waivers granted
under this section.
Allotment Trading Program
Sec. 80.275 How are allotments generated and used?
(a) Generation of allotments and credits in 2003. (1) During 2003
only, any domestic or foreign refiner may have the option to generate
credits in accordance with the provisions of Sec. 80.305 or generate
allotments and credits under paragraph (a)(2) of this section.
(2) If the average sulfur content of the gasoline produced at a
refinery is less than the refinery's baseline as determined under
Sec. 80.295 and is 60 ppm or less, allotments and credits may be
generated using the following procedures. This paragraph (a) does not
apply to importers.
(i) If the average sulfur content of the gasoline produced at a
refinery is less than or equal to 30, and the refinery's sulfur
baseline is greater than 120, the following procedures apply:
SA<INF>TypeB</INF> = (30 - Sa<INF>a</INF>) x V
SA<INF>TypeA</INF> = (V x 90) x 0.8
CR = (S<INF>Base</INF> - 120) x V
(ii) If the average sulfur content of the gasoline produced at a
refinery is less than or equal to 30, and the refinery's sulfur
baseline is greater than 30 but less than or equal to 120, the
following procedures apply:
SA<INF>TypeB</INF> = (30 - S<INF>a</INF>) x V
SA<INF>TypeA</INF> = ((S<INF>Base</INF> - 30) x V) x 0.8
(iii) If the average sulfur content of the gasoline produced at a
refinery is less than or equal to 30, and the refinery's sulfur
baseline is less than or equal to 30, the following procedures apply:
SA<INF>TypeB</INF> = ( S<INF>Base</INF> - S<INF>a</INF>) x V
(iv) If the average sulfur content of the gasoline produced at a
refinery is greater than 30, and the refinery's sulfur baseline is
greater than 120, the following procedures apply:
SA<INF>TypeA</INF> = ((120 - S<INF>a</INF>) x V) x 0.8
CR = (S<INF>Base</INF> - 120) x V
(v) If the average sulfur content of the gasoline produced at a
refinery is greater than 30, and the refinery's sulfur baseline is less
than or equal to 120, the following procedures apply:
SA<INF>TypeA</INF> = ((S<INF>Base</INF> - Sa) x V) x 0.8
(vi) For purposes of the equations under paragraphs (a)(2)(i)
through (v) of this section, the following definitions apply:
SA<INF>TypeB</INF> = Type B sulfur allotments generated.
SA<INF>TypeA</INF> = Type A sulfur allotments generated.
CR = Credits generated.
S<INF>Base</INF> = Refinery's sulfur baseline value under Sec. 80.295.
S<INF>a</INF> = Average sulfur content of the gasoline produced at the
refinery during 2003 (or for a foreign refinery, all gasoline produced
during 2003 that was imported into the U.S.).
V = Volume of gasoline produced at the refinery during 2003 (or for a
foreign refinery, all gasoline produced during 2003 that was imported
into the U.S.).
(b) Generation of allotments in 2004 and 2005. During 2004 and 2005
only, refiners and importers that have corporate pool average sulfur
levels below the corporate pool average standards under Sec. 80.195 may
generate sulfur allotments separately for each year using the following
procedures.
(1) If the average sulfur content of the gasoline produced or
imported is less than 30 the following procedures apply:
SA<INF>TypeB</INF> = (30 - S<INF>a</INF>) x V<INF>a</INF>
SA<INF>TypeA</INF> = (S<INF>PS</INF> - 30) x V<INF>a</INF>
(2) If the average sulfur content of the gasoline produced or
imported is equal to or greater than 30 the following procedures apply:
SA<INF>TypeA</INF> = (S<INF>PS</INF> - S<INF>a</INF>) x V<INF>a</INF>
(3) For purposes of the equations under paragraphs (b)(1) and (2)
of this section, the following definitions apply:
SA<INF>TypeB</INF> = Type B sulfur allotments generated.
SA<INF>TypeA</INF> = Type A sulfur allotments generated.
S<INF>a</INF> = Corporate pool average sulfur level for the year.
S<INF>PS</INF> = Corporate pool average standard (120 in 2004; 90 in
2005).
V<INF>a</INF> = Total volume of gasoline produced and/or imported
during the year.
(c) Use of sulfur allotments to meet standards. (1) Refiners and
importers may use Type A and Type B sulfur allotments to meet the
corporate pool average standards under Sec. 80.195, except that if
allotments generated in 2003 or 2004 are used to meet the corporate
pool standard in 2005 the allotments generated in 2003 or 2004 shall be
reduced in value by 50%.
(2) Small refiners subject to the standards under Sec. 80.240, and
refiners and importers of gasoline designated as GPA gasoline under
Sec. 80.219(a), may use sulfur allotments to meet their annual average
refinery or importer standards.
(d) Transfers of sulfur allotments. Sulfur allotments generated
under this section may be transferred, provided that:
(1) No allotment may be transferred more than twice: The first
transfer by the refiner or importer who generated the allotment may
only be made to a refiner or importer who intends to use the allotment;
if the transferee cannot use the allotment, it may make the second, and
final, transfer only to a refiner or importer who intends to use the
allotment. In no case may an allotment be transferred more than twice
before being used or terminated.
(2) The allotment transferor must apply any allotments necessary to
meet the transferor's corporate pool average standard before
transferring allotments to any other refiner or importer or before
converting allotments into credits.
(3) The transferor must supply to the transferee records indicating
the year of generation and type of the allotments, the identity of the
refiner or importer who generated the allotments, and the identity of
the transferring party, if it is not the same part that generated the
allotments.
(4) The transferor must inform the transferee whether any
transferred allotments are Type A allotments or Type B allotments, as
defined in paragraphs (a) and (b) of this section.
(5) In the case of allotments that have been calculated or created
improperly, or are otherwise determined to be invalid, the following
provisions apply:
(i) Invalid allotments cannot be used to achieve compliance with
the transferee's corporate pool average standard or be converted to
credits, regardless of the transferee's good faith belief that the
allotments were valid.
(ii) The refiner or importer who used the allotments, and any
transferor of the allotments, must adjust their allotment records and
reports and sulfur calculations as necessary to reflect the proper
allotments.
(iii) Any allotments remaining after correcting for the improperly
created allotments must first be applied to correct the invalid
transfers before the transferor may transfer any other allotments or
before converting allotments into credits.
(e) Conversion of allotments into credits. A refiner or importer
may convert allotments into credits using the following procedures:
(1) Type A allotments may be converted into credits with the same
requirements and limitations on use that
[[Page 6832]]
apply under Sec. 80.315 to credits generated in 2000 through 2003.
(2) Type B allotments may be converted into credits with the same
requirements and limitations on use that apply under Sec. 80.315 to
credits generated in 2004 and later, based on the year of creation of
the allotment.
(f) Small refiners. Small refiners subject to the standards under
Sec. 80.240 may not generate sulfur allotments under paragraph (b) of
this section.
(g) GPA gasoline. GPA gasoline that is included in the refiner's or
importer's corporate pool average under Sec. 80.216(f)(2) must be
included in the calculations under paragraph (b) of this section. No
refiner or importer may generate allotments in 2004 or 2005 who is not
required to meet the corporate pool average standards.
Averaging, Banking and Trading (ABT) Program--General Information
Sec. 80.280 [Reserved]
Sec. 80.285 Who may generate credits under the ABT program?
(a) Credit generation in 2000 through 2003. (1) Credits may be
generated in 2000 through 2003 under Sec. 80.305 by refiners who
produce gasoline from crude oil, and are:
(i) Refiners who establish a sulfur baseline under Sec. 80.295;
(ii) Foreign refiners with approved baselines under Sec. 80.94, or
baselines established in accordance with Sec. 80.410; or
(iii) Small refiners for any refinery subject to the standards
under Sec. 80.240, using their small refiner baseline established under
Sec. 80.250.
(2) Importers and oxygenate blenders may not generate credits under
Sec. 80.305.
(b) Credit generation beginning in 2004. (1) Credits may be
generated beginning in 2004 under Sec. 80.310 by:
(i) Refiners and importers subject to the standards under
Sec. 80.195;
(ii) Refiners and importers of gasoline designated as GPA gasoline
under Sec. 80.219, using the lesser of: 150 ppm; or the refiner's or
importer's baseline calculated under Sec. 80.295; or the refinery's
lowest annual average sulfur content for any year from 2000 through
2003 during which the refiner generated credits (for any party
generating credits under both paragraph (b)(1)(i) of this section and
this paragraph (b)(1)(ii), such credits must be calculated separately);
or
(iii) Small refiners for any refinery subject to the standards
under Sec. 80.240, using refinery's standard established under
Sec. 80.240.
(2) Generation of credits for all imported gasoline shall be
through the importer.
(3) Oxygenate blenders may not generate credits under Sec. 80.310.
Sec. 80.290 How does a refiner apply for a sulfur baseline?
(a) The refiner must submit an application to EPA which includes
the information required under paragraph (c) of this section no later
than September 30 of the year in which the refiner plans to begin
generating credits, or the refiner or an importer plans to sell
gasoline in the geographic phase-in area in accordance with
Sec. 80.217.
(b) The sulfur baseline request must be sent to: U.S. EPA, Attn:
Sulfur Program (6406J), 401 M Street SW., Washington, DC 20460. For
commercial (non-postal) delivery: U.S. EPA, Attn: Sulfur Program, 501
3rd Street NW., Washington, DC 20001.
(c) The sulfur baseline application must include the following
information:
(1) A listing of the names and addresses of all refineries owned by
the corporation for which the refiner is applying for a sulfur
baseline.
(2) The annual average gasoline sulfur baseline for gasoline
produced in 1997-1998, for each refinery for which the refiner is
applying for a sulfur baseline, calculated in accordance with
Sec. 80.295.
(3) A letter signed by the president, chief operating or chief
executive officer, of the company, or his/her delegate, stating that
the information contained in the sulfur baseline determination is true
to the best of his/her knowledge.
(4) Name, address, phone number, facsimile number and E-mail
address of a corporate contact person.
(5) The following information for each batch of gasoline produced
in 1997-1998:
(i) Batch number assigned to the batch under Sec. 80.65(d) or
Sec. 80.101(i);
(ii) Volume; and
(iii) Sulfur content.
(d) Foreign refiners who do not have an approved refinery baseline
under Sec. 80.94 must follow the procedures specified in
Sec. 80.410(b).
(e) Within 60 days of receipt of an application under this section,
EPA will notify the refiner of approval of the refinery's baseline or
of any deficiencies in the application.
(f) If at any time the baseline submitted in accordance with the
requirements of this section is determined to be incorrect, EPA will
notify the refiner of the corrected baseline.
(g) Any refiner that seeks temporary relief under Sec. 80.270 shall
apply for a refinery sulfur baseline in accordance with the provisions
of this section and Sec. 80.295, and if applicable, Sec. 80.410(b), no
later than September 1, 2000.
ABT Program--Baseline Determination
Sec. 80.295 How is a refinery sulfur baseline determined?
(a) A refinery's gasoline sulfur baseline for the purpose of
generating credits during years 2000 through 2003 is calculated using
the following equation:
[GRAPHIC] [TIFF OMITTED] TR10FE00.011
Where:
S<INF>Base</INF>=Sulfur baseline value.
V<INF>i</INF>=Volume of gasoline batch i.
S<INF>i</INF>=Sulfur content of gasoline batch i.
n=Total number of batches of gasoline produced during January 1, 1997
through December 31, 1998.
i=Individual batch of gasoline produced during January 1, 1997 through
December 31, 1998.
(b) Any refiner who, under Sec. 80.65 or Sec. 80.101(d)(4),
included oxygenate blended downstream in compliance calculations for
1997-1998 must include this oxygenate in the baseline calculations for
sulfur content under paragraph (a) of this section.
Sec. 80.300 [Reserved]
ABT Program--Credit Generation
Sec. 80.305 How are credits generated during the time period 2000
through 2003?
(a) Credits must be calculated as follows:
CR<INF>a</INF>=V<INF>a</INF> x (S<INF>Base</INF> - S<INF>a</INF>)
Where:
CR<INF>a</INF>=Credits generated for the averaging period.
V<INF>a</INF>=Total volume of gasoline produced during the averaging
period at the refinery.
S<INF>Base</INF>=Sulfur baseline value for the refinery established
under Sec. 80.250 or Sec. 80.295.
S<INF>a</INF>=Actual annual average sulfur level for gasoline produced
during the averaging period by the refinery exclusive of any credits.
(b) The refiner may include any oxygenates included in its RFG or
conventional gasoline volume under Secs. 80.65 and 80.101(d)(4),
respectively, for the purpose of generating credits.
(c) Credits under this program are in units of ``ppm-gallons''.
(d) Refiners may generate credits for gasoline produced during an
averaging period only if the annual average sulfur level for the
gasoline produced during the averaging period is less than 0.90 of the
refiners baseline under Sec. 80.250 or Sec. 80.295.
[[Page 6833]]
(e) Credits generated in accordance with paragraph (a) of this
section must be identified by the year of creation.
Sec. 80.310 How are credits generated beginning in 2004?
(a) A refiner for any refinery, or an importer, may generate
credits in 2004 and thereafter if the annual average sulfur level for
gasoline produced or imported for the averaging period is less than the
applicable refinery or importer annual average sulfur standard for that
refinery or importer in that year.
(b) Credits are calculated as follows:
CR<INF>a</INF>=V<INF>a</INF> x (S<INF>Std</INF> - S<INF>a</INF>)
Where:
CR<INF>a</INF>=Credits generated for the averaging period.
V<INF>a</INF>=Total annual volume gasoline produced at a refinery or
imported during the averaging period.
S<INF>std</INF>=30 ppm; or the sulfur standard for a small refinery
established under Sec. 80.240; or, for gasoline designated as GPA
gasoline under Sec. 80.219, the lesser of 150 ppm, the refinery's or
importer's baseline calculated under Sec. 80.295, or the refinery's
lowest annual average sulfur content for any year from 2000 through
2003 during which the refinery generated credits or allotments.
S<INF>a</INF>=Actual annual average sulfur level of gasoline produced
at a refinery or imported during the averaging period exclusive of any
credits.
(c) Credits generated in accordance with this section must be
identified by the year of creation.
ABT Program--Credit Use
Sec. 80.315 How are credits used and what are the limitations on
credit use?
(a) Credit use. Credits may be used to meet the applicable refinery
or importer annual average sulfur standards under Sec. 80.195,
Sec. 80.216, or Sec. 80.240, provided that:
(1) Sulfur credits used were generated pursuant to the requirements
of this subpart; and
(2) The requirements of paragraphs (b) and (c) of this section are
met.
(b) Credit transfers. (1) Credits obtained from other persons may
be used to meet the annual average standards specified in Sec. 80.195,
Sec. 80.216, or Sec. 80.240 if all the following conditions are met:
(i) The credits are generated and reported according to the
requirements of this subpart.
(ii) The credits are used in compliance with the limitations
regarding the appropriate periods for credit use in this subpart.
(iii) Any credit transfer takes place no later than the last day of
February following the calendar year averaging period when the credits
are used.
(iv) No credit may be transferred more than twice: The first
transfer by the refiner or importer who generated the credit may only
be made to a refiner or importer who intends to use the credit; if the
transferee cannot use the credit, it may make the second, and final,
transfer only to a refiner or importer who intends to use the credit.
In no case may a credit be transferred more than twice before being
used or terminated.
(v) The credit transferor must apply any credits necessary to meet
the transferor's applicable average standard before transferring
credits to any other refiner or importer.
(vi) No credits may be transferred that would result in the
transferor having a negative credit balance.
(vii) Each transferor must supply to the transferee records
indicating the years the credits were generated, the identity of the
refiner or importer who generated the credits, and the identity of the
transferring party, if it is not the same party that generated the
credits.
(2) In the case of credits that have been calculated or created
improperly, or are otherwise determined to be invalid, the following
provisions apply:
(i) Where a refiner's baseline has been determined to be incorrect
under Sec. 80.250(c) or Sec. 80.290(f), any credits generated, banked,
used or traded must be adjusted to reflect the corrected baseline.
(ii) Invalid credits cannot be used to achieve compliance with the
transferee's averaging standard, regardless of the transferee's good
faith belief that the credits were valid.
(iii) The refiner or importer who used the credits, and any
transferor of the credits, must adjust their credit records and reports
and sulfur calculations as necessary to reflect the proper credits.
(iv) Any properly created credits existing in the transferor's
credit balance after correcting the credit balance, and after the
transferor applies credits as needed to meet the average standard at
the end of the compliance year, must first be applied to correct the
invalid transfers before the transferor trades or banks the credits.
(c) Limitations on credit use. (1) Credits generated prior to 2004
may only be used for demonstrating compliance with the refinery or
importer annual average standards under Sec. 80.195 during the 2005 and
2006 averaging periods. Such credits may be used to demonstrate
compliance with the standards under Sec. 80.216 during the 2004 through
2006 averaging periods, and with the standards under Sec. 80.240 during
the 2004 through 2007 averaging periods, and the 2008 and 2009
averaging periods, if allowed under the terms of a hardship extension
under Sec. 80.265.
(2) Credits generated in 2004 or later may only be used for
demonstrating compliance with standards during an averaging period
within five years of the year of generation.
(3) A refiner or importer possessing credits must use all credits
prior to falling into compliance deficit under Sec. 80.205(e).
(4) Credits may not be used to meet corporate pool average
standards under Sec. 80.195.
Sec. 80.320 [Reserved]
Sec. 80.325 [Reserved]
Sampling, Testing and Retention Requirements for Refiners and
Importers
Sec. 80.330 What are the sampling and testing requirements for
refiners and importers?
(a) Sample and test each batch of gasoline. (1) Refiners and
importers shall collect a representative sample from each batch of
gasoline produced or imported and test each sample to determine its
sulfur content for compliance with requirements under this subpart
prior to the gasoline leaving the refinery or import facility, using
the sampling and testing methods provided in this section.
(2) Except as provided in paragraph (a)(3) of this section, the
requirements of this section apply beginning January 1, 2004, or
January 1 of the first year of allotment or credit generation under
Sec. 80.275 or Sec. 80.305, whichever is earlier.
(3) Prior to January 1, 2004, for purposes of meeting the sampling
and testing requirements of this section for conventional gasoline, any
refiner may, prior to analysis, combine samples of gasoline from more
than one batch of gasoline or blendstock and treat such composite
sample as one batch of gasoline or blendstock pursuant to the
requirements of Sec. 80.101(i)(2).
(4) Any refiner who produces reformulated gasoline or conventional
gasoline using computer-controlled in-line blending equipment may meet
the testing requirement of paragraph (a)(1) of this section under the
terms of an exemption granted under Sec. 80.65(f)(4).
(b) Sampling methods. For purposes of paragraph (a) of this
section, refiners and importers shall sample each batch of gasoline by
using one of the following methods:
[[Page 6834]]
(1) Manual sampling of tanks and pipelines shall be performed
according to the applicable procedures specified in one of the two
following methods:
(i) American Society for Testing and Materials (ASTM) method D
4057-95, entitled ``Standard Practice for Manual Sampling of Petroleum
and Petroleum Products.''
(ii) Samples collected under the applicable procedures in ASTM
method D 5842-95, entitled ``Standard Practice for Sampling and
Handling of Fuels for Volatility Measurement,'' may be used for
measuring sulfur content if there is no contamination present that
could affect the sulfur test result.
(2) Automatic sampling of petroleum products in pipelines shall be
performed according to the applicable procedures specified in ASTM
method D 4177-95, entitled ``Standard Practice for Automatic Sampling
of Petroleum and Petroleum Products.''
(c) Test method for measuring the sulfur content of gasoline. (1)
For purposes of paragraph (a) of this section, refiners and importers
shall use the method provided in Sec. 80.46(a)(1) to measure the sulfur
content of gasoline they produce or import.
(2) Except as provided in Sec. 80.350 and in paragraph (c)(1) of
this section, any ASTM sulfur test method for liquefied fuels may be
used for quality assurance testing under Sec. 80.400, or to determine
whether gasoline qualifies for a S-RGAS downstream standard, if the
protocols of the ASTM method are followed and the alternative method is
correlated to the method provided in Sec. 80.46(a)(1).
(d) Test method for sulfur in butane. (1) Refiners and importers
shall use the method provided in Sec. 80.46(a)(2) to measure the sulfur
content of butane when the butane constitutes a batch of gasoline.
(2) Except as provided in paragraph (d)(1) of this section, any
ASTM sulfur test method for gaseous fuels may be used for quality
assurance testing under Secs. 80.340(b)(4) and 80.400, if the protocols
of the ASTM method are followed and the alternative method is
correlated to the method provided in Sec. 80.46(a)(2).
(e) Incorporations by reference. ASTM standard practices D 4057-95,
D 4177-95 and D 5842-95 are incorporated by reference. These
incorporations by reference were approved by the Director of the
Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51.
Copies may be obtained from the American Society for Testing and
Materials, 100 Barr Harbor Dr., West Conshohocken, PA 19428. Copies may
be inspected at the Air Docket Section (LE-131), room M-1500, U.S.
Environmental Protection Agency, Docket No. A-97-03, 401 M Street, SW.,
Washington, DC 20460, or at the Office of the Federal Register, 800
North Capitol Street, NW., Suite 700, Washington, DC.
Sec. 80.335 What gasoline sample retention requirements apply to
refiners and importers?
(a) Sample retention requirements. Beginning January 1, 2004, or
January 1 of the first year allotments or credits are generated under
Secs. 80.275 and 80.305, whichever is earlier, any refiner or importer
shall:
(1) Collect a representative portion of each sample analyzed under
Sec. 80.330(a), of at least 330 ml in volume;
(2) Retain sample portions for the most recent 20 samples
collected, or for each sample collected during the most recent 21 day
period, whichever is greater;
(3) Comply with the gasoline sample handling and storage procedures
under Sec. 80.330(b) for each sample portion retained; and
(4) Comply with any request by EPA to:
(i) Provide a retained sample portion to the Administrator's
authorized representative; and
(ii) Ship a retained sample portion to EPA, within 2 working days
of the date of the request, by an overnight shipping service or
comparable means, to the address and following procedures specified by
EPA, and accompanied with the sulfur test result for the sample
determined under Sec. 80.330(a).
(b) Sample retention requirement for samples subject to independent
analysis requirements. (1) Any refiner or importer who meets the
independent analysis requirements under Sec. 80.65(f) for any batch of
reformulated gasoline or RBOB will have met the requirements of
paragraph (a) of this section, provided the independent laboratory
meets the requirements of paragraph (a) of this section for the
gasoline batch.
(2) For samples retained by an independent laboratory under
paragraph (b) of this section, the test results required to be
submitted under paragraph (a) of this section shall be the test results
determined under Sec. 80.65(e).
(c) Sampling compliance certification. Any refiner or importer
shall include with each annual report filed under Sec. 80.370, the
following statement, which must accurately reflect the facts and must
be signed and dated by the same person who signs the annual report:
I certify that I have made inquiries that are sufficient to give
me knowledge of the procedures to collect and store gasoline
samples, and I further certify that the procedures meet the
requirements of the ASTM procedures required under 40 CFR 80.330.
Sec. 80.340 What standards and requirements apply to refiners
producing gasoline by blending blendstocks into previously certified
gasoline (PCG)?
(a) Any refiner who produces gasoline by blending blendstock into
PCG must meet the requirements of Sec. 80.330 to sample and test every
batch of gasoline as follows:
(1)(i) Sample and test to determine the volume and sulfur content
of the PCG prior to blendstock blending.
(ii) Sample and test to determine the volume and sulfur content of
the gasoline subsequent to blendstock blending.
(iii) Calculate the volume and sulfur content of the blendstock, by
subtracting the volume and sulfur content of the PCG from the volume
and sulfur content of the gasoline subsequent to blendstock blending.
The blendstock is a batch for purposes of compliance calculations and
reporting. For purposes of this paragraph (a), compliance with the
applicable cap standard under Sec. 80.195(a) shall be determined based
on the sulfur content of the gasoline subsequent to blendstock
blending.
(2) In the alternative, a refiner may sample and test each batch of
blendstock when received at the refinery to determine the volume and
sulfur content, and treat each blendstock receipt as a separate batch
for purposes of compliance calculations for the annual average sulfur
standard and for reporting. This alternative applies only if every
batch of blendstock used at a refinery during an averaging period has a
sulfur content that is equal to, or less than, the applicable per-
gallon cap standard under Secs. 80.195 or 80.216.
(b) Refiners who blend only butane into PCG may meet the sampling
and testing requirements by using sulfur test results of the butane
supplier, provided that the following requirements are also met:
(1) The sulfur content of the butane received from the butane
supplier must not exceed the following sulfur standards on a per-gallon
basis as follows:
(i) 120 ppm in 2004, and 30 ppm for 2005 and any subsequent year;
(ii) Except that the per-gallon sulfur content of butane blended to
PCG that is designated as GPA gasoline shall not exceed 150 ppm from
January 1, 2004, through December 31, 2006.
(2) The refiner obtains test results from the butane supplier that
demonstrate that the sulfur content of
[[Page 6835]]
each load of butane supplied does not exceed the applicable per-gallon
sulfur standard under paragraph (b)(1) of this section through test
results of samples of the butane contained in the storage tank from
which the butane blender is supplied.
(i) Testing for the sulfur content of the butane by the supplier
must be subsequent to each receipt of butane into the supplier's
storage tank, or the testing must be immediately before transfer of
butane to the butane blender.
(ii) The testing must be performed by the method specified in
Sec. 80.46(a)(2).
(iii) The butane blender must obtain a copy of the butane
supplier's test results, at the time of each transfer of butane to the
butane blender, that reflect the sulfur content of each load of butane
supplied to the butane blender.
(3) The sulfur content and volume of each batch of gasoline
produced is that of the butane the refiner blends into gasoline for
purposes of calculating compliance with the standards in Secs. 80.195
and 80.216.
(4) The refiner must conduct a quality assurance program of
sampling and testing for each butane supplier that demonstrates the
butane sulfur content does not exceed the applicable per-gallon sulfur
standard in paragraph (b)(1) of this section. The frequency of butane
sampling and testing, for each butane supplier, must be one sample for
every 500,000 gallons of butane received, or one sample every 3 months,
whichever results in more frequent sampling.
(5) If any of the requirements of this section are not met, in
whole or in part, for any butane blended into gasoline, that butane is
deemed in violation of the gasoline sulfur standards in Sec. 80.195 or
Sec. 80.216, as applicable.
Sec. 80.345 [Reserved]
Sec. 80.350 What alternative sulfur standards and requirements apply
to importers who transport gasoline by truck?
Importers who import gasoline into the United States by truck may
comply with the following requirements instead of the requirements to
sample and test every batch of gasoline under Sec. 80.330, and the
annual sulfur average and per-gallon cap standards otherwise applicable
to importers under Secs. 80.195 and 80.216:
(a) Alternative standards. The imported gasoline must comply with
the standards in paragraph (a)(1) or (a)(2) of this section as follows:
(1) The applicable average standards, corporate average standards
and per-gallon standards under Sec. 80.195(a)(1), except that imported
gasoline designated for use in the geographic phase-in area from
January 1, 2004, through December 31, 2006 must comply with an average
standard of 150 ppm and a per-gallon standard of 300 ppm; or
(2) In 2004, a per-gallon standard of 120 ppm, and in 2005 and
subsequent years a per-gallon standard of 30 ppm, except that imported
gasoline designated for use in the geographic phase-in area from
January 1, 2004, through December 31, 2006 must comply with a per-
gallon standard of 150 ppm.
(b) Terminal testing. The importer may use test results for sulfur
content testing conducted by the terminal operator, for gasoline
contained in the storage tank from which trucks used to transport
gasoline into the United States are loaded, for purposes of
demonstrating compliance with the standards in paragraph (a) of this
section, provided the following conditions are met:
(1) The sampling and testing shall be performed after each receipt
of gasoline into the storage tank, or immediately before each transfer
of gasoline to the importer's truck.
(2) The sampling and testing shall be performed using the methods
specified in Sec. 80.330(b) and 80.46(a)(1), respectively.
(3) At the time of each transfer of gasoline to the importer's
truck for import to the U.S., the importer must obtain a copy of the
terminal test result that indicates the sulfur content of the truck
load.
(c) Quality assurance program. The importer must conduct a quality
assurance program, as specified in this paragraph, for each truck
loading terminal.
(1) Quality assurance samples must be obtained from the truck-
loading terminal and tested by the importer, or by an independent
laboratory, and the terminal operator must not know in advance when
samples are to be collected.
(2) The sampling and testing must be performed using the methods
specified in Secs. 80.330(b) and 80.46(a)(1), respectively.
(3) The quality assurance test results for sulfur must differ from
the terminal test result by no more than the ASTM reproducibility of
the terminal's test results, as determined by the following equation:
R = 105 x ((S+2)/10<SUP>4</SUP>)<SUP>0.4</SUP>
Where:
R = ASTM reproducibility.
S = Sulfur content based on the terminal's test result.
(4) The frequency of the quality assurance sampling and testing
must be at least one sample for each fifty of an importer's trucks that
are loaded at a terminal, or one sample per month, whichever is more
frequent.
(d) Party required to conduct quality assurance testing. The
quality assurance program under paragraph (c) of this section shall be
conducted by the importer. In the alternative, this testing may be
conducted by an independent laboratory that meets the criteria under
Sec. 80.65(f)(2)(iii), provided the importer receives, no later than 21
days after the sample was taken, copies of all results of tests
conducted.
(e) Assignment of batch numbers. The importer must treat each truck
load of imported gasoline as a separate batch for purposes of assigning
batch numbers and maintaining records under Sec. 80.365, and reporting
under Sec. 80.370.
(f) EPA inspections of terminals. EPA inspectors or auditors, and
auditors conducting attest engagements under Sec. 80.415, must be given
full and immediate access to the truck-loading terminal and any
laboratory at which samples of gasoline collected at the terminal are
analyzed, and must be allowed to conduct inspections, review records,
collect gasoline samples, and perform audits. These inspections or
audits may be either announced or unannounced.
(g) Certified Sulfur-FRGAS. This section does not apply to
Certified Sulfur-FRGAS.
(h) Reporting requirements. Any importer who elects to comply with
the alternative standards in paragraph (a) of this section shall comply
with the following requirements:
(1) All importer recordkeeping and reporting requirements under
Secs. 80.365 and 80.370, except as provided in paragraph (h)(2) of this
section.
(2) An importer who elects to comply with the alternative standards
in paragraph (a)(2) of this section must certify in the annual report
whether it is in compliance with the applicable per-gallon batch
standard set forth in paragraph (a)(2) of this section, in lieu of
providing the information required by Sec. 80.370(a) regarding annual
average sulfur content and compliance with the average standard under
Sec. 80.195.
(i) Effect of noncompliance. If any of the requirements of this
section are not met, all gasoline imported by the truck importer during
the time any requirements are not met is deemed in violation of the
gasoline sulfur average and per-gallon cap standards in Sec. 80.195 or
Sec. 80.216, as applicable. Additionally, if any requirement is not
met, EPA may notify the importer of the violation and,
[[Page 6836]]
if the requirement is not fulfilled within 10 days of notification, the
truck importer may not in the future use the sampling and testing
provisions in this section in lieu of the provisions in Sec. 80.330.
Sec. 80.355 [Reserved]
Recordkeeping and Reporting Requirements
Sec. 80.360 [Reserved]
Sec. 80.365 What records must be kept?
(a) Records that must be kept. Beginning January 1, 2004, any
person who produces, imports, sells, offers for sale, dispenses,
distributes, supplies, offers for supply, stores, or transports
gasoline, shall keep records that contain the following information:
(1) The product transfer document information required under
Secs. 80.77, 80.106, 80.210 and 80.219; and
(2) For any sampling and testing for sulfur content required under
this subpart:
(i) The location, date, time and storage tank or truck
identification for each sample collected;
(ii) The name and title of the person who collected the sample and
the person who performed the test;
(iii) The results of the test as originally printed by the testing
apparatus, or where no printed result is produced, the results as
originally recorded by the person who performed the test; and
(iv) Any record that contains a test result for the sample that is
not identical to the result recorded under paragraph (a)(2)(iii) of
this section.
(b) Additional records that refiners and importers must keep.
Beginning January 1, 2004, or January 1 of the first year allotments or
credits are generated under Sec. 80.275 or Sec. 80.305, whichever is
earlier, any refiner for each of its refineries, and any importer for
the gasoline it imports, shall keep records that include the following
information:
(1) For each batch of gasoline produced or imported:
(i) The batch volume;
(ii) The batch number assigned under Sec. 80.65(d)(3) and the
appropriate designation under paragraph (b)(1)(i) of this section;
except that if composite samples of conventional gasoline representing
multiple batches produced subsequent to December 31, 2003, are tested
under Sec. 80.101(i)(2) for anti-dumping compliance purposes, for
purposes of this subpart a separate batch number must be assigned to
each batch using the batch numbering procedures under Sec. 80.65(d)(3);
(iii) The date of production or importation; and
(iv) If appropriate, the designation of the batch as GPA gasoline
under Sec. 80.219, California gasoline under Sec. 80.375, exempt
gasoline for research and development under Sec. 80.380, or for export
outside the United States.
(2) Information regarding credits and allotments, separately kept
for credits and for allotments; separately kept according to the year
of creation for the credits and for the allotments; and for credit
generation or use starting in 2004, separately kept for GPA gasoline
and other gasoline. Information shall be kept separately for different
types of allotments and credits generated under Secs. 80.275(e)(1),
80.275(e)(2), 80.305 and 80.310:
(i) The number in the refiner's or importer's possession at the
beginning of the averaging period;
(ii) The number generated;
(iii) The number used;
(iv) If any were obtained from or transferred to other parties, for
each other party its name, its EPA refiner or importer registration
number, and the number obtained from, or transferred to, the other
party;
(v) The number that expired at the end of the averaging period;
(vi) The number of allotments, by type, that were converted into
credits under Sec. 80.275(e);
(vii) The number in the refiner's or importer's possession that
will carry over into the subsequent averaging period; and
(viii) Contracts or other commercial documents that establish each
transfer of credits and allotments from the transferor to the
transferee.
(3) The calculations used to determine the applicable refiner
baseline under Sec. 80.250 or Sec. 80.295.
(4) The calculations used to determine compliance with the
applicable sulfur average standards of Sec. 80.195, Sec. 80.216,
Sec. 80.240, or Sec. 80.270.
(5) The calculations used to determine the number of credits or
allotments generated under Sec. 80.305, Sec. 80.310 or Sec. 80.275.
(6) The calculations used to determine any applicable adjusted cap
standard under Sec. 80.195(d).
(7) A copy of all reports submitted to EPA under Sec. 80.370.
(c) Additional records importers must keep. Any importer shall keep
records that identify and verify the source of each batch of certified
Sulfur-FRGAS and non-certified Sulfur-FRGAS imported and demonstrate
compliance with the requirements for importers under Sec. 80.410(o).
(d) Length of time records must be kept. The records required in
this section shall be kept for five years from the date they were
created; except that:
(1) Transfers of credits and allotments. Records relating to credit
and allotment transfers, except as provided in paragraph (d)(2) of this
section, shall be kept by the transferor for 5 years from the date the
credits or allotments are transferred, and shall be kept by the
transferee for 5 years from the date the credits or allotments were
transferred, used or terminated, whichever is later.
(2) Early credits. (i) Where the party generating the credits does
not transfer the credits, records must be kept for 5 years from the
date of creation, use or termination whichever is later.
(ii) Where early credits are transferred, records relating to such
credits shall be kept by both parties for 5 years from the date the
credits were transferred, used or terminated, whichever is later.
(e) Make records available to EPA. On request by EPA the records
required in paragraphs (a), (b) and (c) of this section shall be
provided to the Administrator's authorized representative. For records
that are electronically generated or maintained the equipment and
software necessary to read the records shall be made available, or if
requested by EPA, electronic records shall be converted to paper
documents which shall be provided to the Administrator's authorized
representative.
Sec. 80.370 What are the sulfur reporting requirements?
Beginning with the 2004 averaging period, or the first year credits
or allotments are generated under Sec. 80.275 or Sec. 80.305, whichever
is earlier, and continuing for each averaging period thereafter, any
refiner or importer shall submit to EPA annual reports that contain the
information required in this section, and such other information as EPA
may require.
(a) Refiner and importer annual reports. Any refiner, for each of
its refineries, and any importer for the gasoline it imports, shall
submit a report for each calendar year averaging period that includes
the following information, and in the case of a refiner or importer
producing or importing both GPA gasoline and other gasoline, the
information shall be separately reported:
(1) The EPA importer, or refiner and refinery facility registration
numbers;
(2) The applicable baseline, average standard, and adjusted cap
standard as follows:
(i) For the years 2000 through 2003, the applicable baseline under
Sec. 80.250 or Sec. 80.295.
(ii) For the 2004 averaging period and subsequent averaging
periods:
[[Page 6837]]
(A) All applicable average standards under Sec. 80.195,
Sec. 80.216, Sec. 80.240 or Sec. 80.270;
(B) All applicable adjusted cap standards under Sec. 80.195(d),
with the 2005 report identifying both the 2004 and 2005 applicable
adjusted cap standards;
(3) The total volume of gasoline produced or imported;
(4) The annual average sulfur content of the gasoline produced or
imported;
(5) The annual average sulfur level after inclusion of any credits
and allotments;
(6) Information, separately provided, for credits and allotments,
and separately by year of creation, as follows:
(i) The number of credits and allotments at the beginning of the
averaging period;
(ii) The number of credits and allotments generated;
(iii) The number of credits and allotments used;
(iv) If any credits or allotments were obtained from or transferred
to other parties, for each other party its name and EPA refiner or
importer registration number, and the number of credits or allotments
obtained from or transferred to the other party;
(v) The number of credits and allotments that expired at the end of
the averaging period;
(vi) The number of credits and allotments that will carry over into
the subsequent averaging period; and
(vii) The number of each type of allotments converted to credits;
(7) For each batch of gasoline produced or imported during the
averaging period:
(i) The batch number assigned under Sec. 80.65(d)(3) and the
appropriate designation under Sec. 80.365; except that if composite
samples of conventional gasoline representing multiple batches produced
subsequent to December 31, 2003, are tested under Sec. 80.101(i)(2) for
anti-dumping compliance purposes, for purposes of this subpart a
separate batch number must be assigned to each batch using the batch
numbering procedures under Sec. 80.65(d)(3);
(ii) The date the batch was produced;
(iii) The volume of the batch; and
(iv) The sulfur content of the batch as determined under
Sec. 80.330; and
(8) When submitting reports under this paragraph (a), any importer
shall exclude certified Sulfur-FRGAS.
(b) Additional reporting requirements for importers. Any importer
shall report the following information for Sulfur-FRGAS imported during
the averaging period:
(1) The EPA refiner and refinery registration numbers of each
foreign refiner and refinery where the certified Sulfur-FRGAS was
produced; and
(2) The total gallons of certified Sulfur-FRGAS and non-certified
Sulfur-FRGAS imported from each foreign refiner and refinery.
(c) Corporate pool average reports. (1) Annual reports filed under
this section for the 2004 and 2005 averaging periods must include the
party's corporate pool average as determined under Sec. 80.205.
(2) If the party submitting the annual report under paragraph
(c)(1) of this section is a refiner with more than one refinery or is a
refiner who also imports gasoline, then for the purposes of this
paragraph, the party shall report the information required for
individual refineries and for importers under paragraph (a) of this
section, also in the aggregate for all the gasoline produced and
imported during the calendar year.
(3) Refiners and importers exempted from corporate pool standards
under Sec. 80.216 or Sec. 80.240 are exempt from reporting the
information required under paragraphs (c)(1) and (c)(2) of this
section.
(d) Report submission. Any annual report required under this
section shall be:
(1) Signed and certified as meeting all of the applicable
requirements of this subpart by the owner or a responsible corporate
officer of the refiner or importer; and
(2) Submitted to EPA no later than the last day of February for the
prior calendar year averaging period.
(f) Attest reports. Attest reports for refiner and importer attest
engagements required under Sec. 80.415 shall be submitted to the
Administrator by May 31 of each year for the prior calendar year
averaging period.
Secs. 80.371--80.373 [Reserved]
Exemptions
Sec. 80.374 What if a refiner or importer is unable to produce
gasoline conforming to the requirements of this subpart?
In appropriate extreme and unusual circumstances (e.g., natural
disaster or Act of God) which are clearly outside the control of the
refiner or importer and which could not have been avoided by the
exercise of prudence, diligence, and due care, EPA may permit a refiner
or importer, for a brief period, to distribute gasoline which does not
meet the requirements of this subpart provided the refiner or importer
meets all the criteria, requirements and conditions contained in
Sec. 80.73 (a) through (e).
Sec. 80.375 What requirements apply to California gasoline?
(a) Definition. For purposes of this subpart California gasoline
means any gasoline designated by the refiner as for use in California.
(b) California gasoline exemption. California gasoline that
complies with all the requirements of this section is exempt from all
other provisions of this subpart.
(c) Requirements for California gasoline. The requirements are:
(1) Each batch of California gasoline must be designated as such by
its refiner or importer;
(2) Designated California gasoline must be kept segregated from
gasoline that is not California gasoline, at all points in the
distribution system;
(3) Designated California gasoline must ultimately be used in the
State of California and not used elsewhere;
(4) In the case of California gasoline produced outside the State
of California, the transferors and transferees must meet the product
transfer document requirements under Sec. 80.81(g); and
(5) Gasoline that is ultimately used in any part of the United
States outside of the State of California must comply with the
standards and requirements of this subpart, regardless of any
designation as California gasoline.
(d) Use of California test methods and off site sampling
procedures. In the case of any gasoline that is not California gasoline
and that is either produced at a refinery located in the State of
California or is imported from outside the United States into the State
of California, the refiner or importer may, with regard to such
gasoline:
(1) Use the sampling and testing methods approved in Title 13 of
the California Code of Regulations instead of the sampling and testing
methods required under Sec. 80.330; and
(2) Determine the sulfur content of gasoline at off site tankage as
permitted in Sec. 80.81(h)(2).
Sec. 80.380 What are the requirements for obtaining an exemption for
gasoline used for research, development or testing purposes?
Any person may request an exemption from the provisions of this
subpart for gasoline used for research, development or testing
(``R&D'') purposes by submitting to EPA an application that includes
all the information listed in paragraph (b) of this section.
(a) Criteria for an R&D exemption. For an R&D exemption to be
granted, the proposed test program must:
(1) Have a purpose that constitutes an appropriate basis for
exemption;
[[Page 6838]]
(2) Necessitate the granting of an exemption;
(3) Be reasonable in scope; and
(4) Have a degree of control consistent with the purpose of the
program and EPA's monitoring requirements.
(b) Information required to be submitted. To demonstrate each of
the four elements in paragraphs (a)(1) through (4) of this section, the
application required under this section must include the following
information:
(1) A statement of the purpose of the program demonstrating that
the program has an appropriate R&D purpose.
(2) An explanation of why the stated purpose of the program cannot
be achieved in a practicable manner without performing one or more of
the prohibited acts under Sec. 80.385.
(3) To demonstrate the reasonableness of the scope of the program:
(i) An estimate of the program's beginning and ending dates;
(ii) An estimate of the maximum number of vehicles and engines
involved in the program, and the number of miles and engine hours that
will be accumulated on each;
(iii) The sulfur content of the gasoline expected to be used in the
program; and
(iv) The quantity of gasoline that exceeds the applicable sulfur
standard that is expected to be used in the program.
(4) With regard to control, a demonstration that the program
affords EPA a monitoring capability, including at a minimum:
(i) A description of the technical and operational aspects of the
program;
(ii) The site(s) of the program (including street address, city,
county, State, and ZIP code);
(iii) The manner in which information on vehicles and engines used
in the program will be recorded and made available to EPA;
(iv) The manner in which results of the program will be recorded
and made available to EPA;
(v) The manner in which information on the gasoline used in the
program (including quantity, sulfur content, name, address, telephone
number and contact person of the supplier, and the date received from
the supplier), will be recorded and made available to EPA;
(vi) The manner in which distribution pumps will be labeled to
insure proper use of the gasoline where appropriate;
(vii) The name, address, telephone number and title of the
person(s) in the organization requesting an exemption from whom further
information on the application may be obtained; and
(viii) The name, address, telephone number and title of the
person(s) in the organization requesting an exemption who is
responsible for recording and making available the information
specified in paragraphs (b)(4)(iii), (iv) and (v) of this section, and
the location in which such information will be maintained.
(c) Additional requirements. (1) The product transfer documents
associated with R&D gasoline must identify the gasoline as such, and
must state that the gasoline is to be used only for research,
development, or testing purposes.
(2) The R&D gasoline must be designated by the refiner or importer
as exempt R&D gasoline.
(3) The R&D gasoline must be kept segregated from non-exempt
gasoline at all points in the distribution system of the gasoline.
(4) The R&D gasoline must not be sold, distributed, offered for
sale or distribution, dispensed, supplied, offered for supply,
transported to or from, or stored by a gasoline retail outlet, or by a
wholesale purchaser-consumer facility, unless the wholesale purchaser-
consumer facility is associated with the R&D program that uses the
gasoline.
(d) Memorandum of exemption. The Administrator will grant an R&D
exemption upon a demonstration that the requirements of this section
have been met. The R&D exemption will be granted in the form of a
memorandum of exemption signed by the applicant and the Administrator
(or delegate), which may include such terms and conditions as the
Administrator determines necessary to monitor the exemption and to
carry out the purposes of this section, including restoration of motor
vehicle emissions control systems. Any violation of such a term or
condition of the exemption or any requirement under this section will
cause the exemption to be void ab initio.
(e) Effects of exemption. Gasoline that is subject to an R&D
exemption under this section is exempt from other provisions of this
subpart provided that the gasoline is used in a manner that complies
with the memorandum of exemption granted under paragraph (d) of this
section.
Violation Provisions
Sec. 80.385 What acts are prohibited under the gasoline sulfur
program?
No person shall:
(a) Averaging violation. Produce or import gasoline that does not
comply with the applicable sulfur average standard under Sec. 80.195,
Sec. 80.216 or Sec. 80.240.
(b) Cap standard violation. Produce, import, sell, offer for sale,
dispense, supply, offer for supply, store or transport gasoline that
does not comply with the applicable sulfur cap standard under
Sec. 80.195, Sec. 80.216, Sec. 80.210, Sec. 80.220 or Sec. 80.240.
(c) Causing an averaging, cap standard, or geographic phase-in area
(GPA) use violation. Cause another person to commit an act in violation
of paragraph (a), (b), or (f) of this section.
(d) Causing violating gasoline to be in the distribution system.
Cause gasoline to be in the distribution system which does not comply
with an applicable sulfur cap standard under Sec. 80.195, Sec. 80.210,
Sec. 80.216, Sec. 80.220 or Sec. 80.240; a sulfur average standard
under Sec. 80.195, Sec. 80.216 or Sec. 80.240; or a GPA use prohibition
under Sec. 80.219(c).
(e) Denatured ethanol violation. Blend into gasoline denatured
ethanol with a sulfur content higher than 30 ppm.
(f) GPA use violation. Produce, import, sell, offer for sale,
dispense, supply, offer for supply, store or transport gasoline that
does not comply with a GPA use prohibition under Sec. 80.219(c).
Sec. 80.390 What evidence may be used to determine compliance with the
prohibitions and requirements of this subpart and liability for
violations of this subpart?
(a) Compliance with the sulfur standards of this subpart shall be
determined based on the sulfur level of the gasoline, measured using
the methodologies specified in Secs. 80.330(b) and 80.46(a). Any
evidence or information, including the exclusive use of such evidence
or information, may be used to establish the sulfur level of gasoline
if the evidence or information is relevant to whether the sulfur level
of gasoline would have been in compliance with the standards if the
appropriate sampling and testing methodology had been correctly
performed. Such evidence may be obtained from any source or location
and may include, but is not limited to, test results using methods
other than those specified in Secs. 80.330(b) and 80.46(a), business
records, and commercial documents.
(b) Determinations of compliance with the requirements of this
subpart other than the sulfur standards, and determinations of
liability for any violation of this subpart, may be based on
information obtained from any source or location. Such information may
include, but is not limited to, business records and commercial
documents.
Sec. 80.395 Who is liable for violations under the gasoline sulfur
program?
(a) Persons liable for violations of prohibited acts. (1) Averaging
violation.
[[Page 6839]]
Any refiner or importer who violates Sec. 80.385(a) is liable for the
violation.
(2) Causing an averaging violation. Any refiner, importer,
distributor, reseller, carrier, retailer, wholesale purchaser-consumer,
or oxygenate blender who causes another party to violate
Sec. 80.385(a), is liable for a violation of Sec. 80.385(c).
(3) Cap standard violation. Any refiner, importer, distributor,
reseller, carrier, retailer, wholesale purchaser-consumer, or oxygenate
blender who owned, leased, operated, controlled or supervised a
facility where a violation of Sec. 80.385 (b) occurred, is deemed in
violation of Sec. 80.385(b).
(4) Causing a cap standard violation. Any refiner, importer,
distributor, reseller, carrier, retailer, wholesale purchaser-consumer,
or oxygenate blender who produced, imported, sold, offered for sale,
dispensed, supplied, offered for supply, stored, transported, or caused
the transportation or storage of gasoline that violates Sec. 80.385(b),
is deemed in violation of Sec. 80.385(c).
(5) GPA use violation. Any refiner, importer, distributor,
reseller, carrier, retailer, wholesale purchaser-consumer, or oxygenate
blender who produced, imported, sold, offered for sale, dispensed,
supplied, offer for supply, stored, transported, or caused the
transportation or storage of gasoline that violates Sec. 80.385(f), is
deemed in violation of Sec. 80.385(f).
(6) Causing a GPA use violation. Any refiner, importer,
distributor, reseller, carrier, retailer, wholesale purchaser-consumer,
or oxygenate blender who causes another party to violate
Sec. 80.385(f), is deemed liable for a violation of Sec. 80.385(c).
(7) Branded refiner/importer liability. Any refiner or importer
whose corporate, trade, or brand name, or whose marketing subsidiary's
corporate, trade, or brand name appeared at a facility where a
violation of Sec. 80.385(b) or (f) occurred, is deemed in violation of
Sec. 80.385(b) or (f), as applicable.
(8) Causing violating gasoline to be in the distribution system.
Any refiner, importer, distributor, reseller, carrier, or oxygenate
blender, who owned, leased, operated, controlled or supervised a
facility from which gasoline was released into the distribution system
which does not comply with an applicable sulfur cap standard, a sulfur
averaging standard, or a GPA use prohibition, is deemed in violation of
Sec. 80.385(d).
(9) Carrier causation. In order for a carrier to be liable under
paragraph (a)(2), (4), (6), or (8) of this section, EPA must
demonstrate, by reasonably specific showing by direct or circumstantial
evidence, that the carrier caused the violation.
(10) Denatured ethanol violation. Any oxygenate blender who
violates Sec. 80.385(e) is liable for the violation.
(11) Parent corporation liability. Any parent corporation is liable
for any violations of this subpart that are committed by any of its
wholly-owned subsidiaries.
(12) Joint venture liability. Each partner to a joint venture is
jointly and severally liable for any violation of this subpart that
occurs at the joint venture facility or is committed by the joint
venture operation.
(b) Persons liable for failure to meet other provisions of this
subpart. (1) Any refiner, importer, distributor, reseller, carrier,
wholesale purchaser-consumer, retailer, or oxygenate blender who fails
to meet a provision of this subpart not addressed in paragraph (a) of
this section is liable for a violation of that provision.
(2) Any refiner, importer, distributor, reseller, carrier,
wholesale purchaser-consumer, retailer, or oxygenate blender who caused
another person to fail to meet a requirement of this subpart not
addressed in paragraph (a) of this section, is liable for causing a
violation of that provision.
Sec. 80.400 What defenses apply to persons deemed liable for a
violation of a prohibited act?
(a) Any person deemed liable for a violation of a prohibition under
Sec. 80.395 (a)(3) through (8), will not be deemed in violation if the
person demonstrates that:
(1) The violation was not caused by the person or the person's
employee or agent; and
(2) The person conducted a quality assurance sampling and testing
program, as described in paragraph (d) of this section. A carrier may
rely on the quality assurance program carried out by another party,
including the party who owns the gasoline in question, provided that
the quality assurance program is carried out properly. Retailers and
wholesale purchaser-consumers are not required to conduct quality
assurance programs.
(b) In the case of a violation found at a facility operating under
the corporate, trade or brand name of a refiner or importer, or a
refiner's or importer's marketing subsidiary, the refiner or importer
must show, in addition to the defense elements required under
paragraphs (a)(1) and (2) of this section, that the violation was
caused by:
(1) An act in violation of law (other than the Clean Air Act or
this part 80), or an act of sabotage or vandalism;
(2) The action of any refiner, importer, retailer, distributor,
reseller, oxygenate blender, carrier, retailer or wholesale purchaser-
consumer in violation of a contractual agreement between the branded
refiner or importer and the person designed to prevent such action, and
despite periodic sampling and testing by the branded refiner or
importer to ensure compliance with such contractual obligation; or
(3) The action of any carrier or other distributor not subject to a
contract with the refiner or importer, but engaged for transportation
of gasoline, despite specifications or inspections of procedures and
equipment which are reasonably calculated to prevent such action.
(c) Under paragraph (a) of this section for any person to show that
a violation was not caused by that person, or under paragraph (b) of
this section to show that a violation was caused by any of the
specified actions, the person must demonstrate by reasonably specific
showing, by direct or circumstantial evidence, that the violation was
caused or must have been caused by another person and that the person
asserting the defense did not contribute to that other person's
causation.
(d) Quality assurance and testing program. To demonstrate an
acceptable quality assurance and testing program under paragraph (a)(2)
of this section, a person must present evidence of the following:
(1) A periodic sampling and testing program to ensure the gasoline
the person sold, dispensed, supplied, stored, or transported, meets the
applicable sulfur standard; and
(2) On each occasion when gasoline is found not in compliance with
the applicable sulfur standard:
(i) The person immediately ceases selling, offering for sale,
dispensing, supplying, offering for supply, storing or transporting the
non-complying product; and
(ii) The person promptly remedies the violation and the factors
that caused the violation (for example, by removing the non-complying
product from the distribution system until the applicable standard is
achieved and taking steps to prevent future violations of a similar
nature from occurring).
(3) For any carrier who transports gasoline in a tank truck, the
quality assurance program required under this paragraph (d) need not
include periodic sampling and testing of gasoline in the tank truck,
but in lieu of such tank truck sampling and testing, the carrier shall
demonstrate evidence of an oversight program for monitoring compliance
with the requirements of this subpart
[[Page 6840]]
relating to the transport or storage of gasoline by tank truck, such as
appropriate guidance to drivers regarding compliance with the
applicable sulfur standard and product transfer document requirements,
and the periodic review of records received in the ordinary course of
business concerning gasoline quality and delivery.
Sec. 80.405 What penalties apply under this subpart?
(a) Any person liable for a violation under Sec. 80.395 is subject
to civil penalties as specified in section 205 of the Clean Air Act for
every day of each such violation and the amount of economic benefit or
savings resulting from each violation.
(b) Any person liable under Sec. 80.395(a)(1) or (2) for a
violation of the applicable sulfur averaging standard or causing
another party to violate that standard during any averaging period, is
subject to a separate day of violation for each and every day in the
averaging period. Any person liable under Sec. 80.395(b) for a failure
to fulfill any requirement for credit or allotment generation,
transfer, use, banking, or deficit correction, is subject to a separate
day of violation for each and every day in the averaging period in
which invalid credits or allotments are generated or used.
(c)(1) Any person liable under Sec. 80.395(a)(3), (4), (5), or (6)
for a violation of an applicable sulfur per gallon cap standard under
Sec. 80.195, Sec. 80.210, Sec. 80.216, Sec. 80.220 or Sec. 80.240, a
GPA use prohibition under Sec. 80.219(c), or of causing another party
to violate a cap standard or a GPA use prohibition, is subject to a
separate day of violation for each and every day the non-complying
gasoline remains any place in the gasoline distribution system.
(2) Any person liable under Sec. 80.395(a)(8) for causing gasoline
to be in the distribution system which does not comply with an
applicable sulfur cap standard, a sulfur averaging standard, or a GPA
use prohibition, is subject to a separate day of violation for each and
every day that the non-complying gasoline remains any place in the
gasoline distribution system.
(3) For purposes of paragraph (c) of this section, the length of
time the gasoline in question remained in the gasoline distribution
system is deemed to be twenty-five days, unless a person subject to
liability or EPA demonstrates by reasonably specific showings, by
direct or circumstantial evidence, that the non-complying gasoline
remained in the gasoline distribution system for fewer than or more
than twenty-five days.
(d) Any person liable under Sec. 80.395(b) for failure to meet, or
causing a failure to meet, a provision of this subpart is liable for a
separate day of violation for each and every day such provision remains
unfulfilled.
Provisions for Foreign Refiners With Individual Sulfur Baselines
Sec. 80.410 What are the additional requirements for gasoline produced
at foreign refineries having individual small refiner sulfur baselines,
foreign refineries granted temporary relief under Sec. 80.270, or
baselines for generating credits during 2000 through 2003?
(a) Definitions. (1) A foreign refinery is a refinery that is
located outside the United States, the Commonwealth of Puerto Rico, the
Virgin Islands, Guam, American Samoa, and the Commonwealth of the
Northern Mariana Islands (collectively referred to in this section as
``the United States'').
(2) A foreign refiner is a person who meets the definition of
refiner under Sec. 80.2(i) for a foreign refinery.
(3) A small foreign refiner is a refiner that meets the definition
of a small refiner under Sec. 80.225.
(4) ``Sulfur-FRGAS'' means gasoline produced at a foreign refinery
that has been assigned an individual refinery sulfur baseline under
Secs. 80.250 or 80.295, or has been granted temporary relief under
Sec. 80.270, and that is imported into the United States.
(5) ``Non-Sulfur-FRGAS'' means gasoline that is produced at a
foreign refinery that has not been assigned an individual refinery
sulfur baseline, gasoline produced at a foreign refinery with an
individual refinery sulfur baseline that is not imported into the
United States, and gasoline produced at a foreign refinery with an
individual sulfur baseline during a year when the foreign refiner has
opted to not participate in the Sulfur-FRGAS program under paragraph
(c)(3) of this section.
(6) ``Certified Sulfur-FRGAS'' means Sulfur-FRGAS the foreign
refiner intends to include in the foreign refinery's sulfur compliance
calculations under Sec. 80.205 pursuant to Sec. 80.240 or Sec. 80.270
or credit calculations under Secs. 80.305 or 80.310 and allotment
calculations under Sec. 80.275(a), and does include in these compliance
calculations when reported to EPA.
(7) ``Non-Certified Sulfur-FRGAS'' means Sulfur-FRGAS that is not
Certified Sulfur-FRGAS.
(b) Baseline establishment. Any foreign refiner who does not have
an approved refinery baseline under Sec. 80.94 may submit a petition to
the Administrator for an individual refinery sulfur baseline pursuant
to Secs. 80.245 and 80.250, a baseline for generating credits or
allotments under Secs. 80.290 and 80.295, or a baseline for temporary
refinery relief under Secs. 80.270 and 80.295.
(1) The refiner shall follow the procedures specified in
Secs. 80.91 through 80.93 to establish the volume and sulfur content of
gasoline that was produced at the foreign refinery and imported into
the United States during 1997 and 1998 for purposes of establishing
baselines under Sec. 80.250 or Sec. 80.295.
(2) In making determinations for foreign refinery baselines EPA
will consider all information supplied by a foreign refiner, and in
addition may rely on any and all appropriate assumptions necessary to
make such determinations.
(3) Where a foreign refiner submits a petition that is incomplete
or inadequate to establish an accurate baseline, and the refiner fails
to cure this defect after a request for more information, EPA will not
assign an individual refinery sulfur baseline.
(c) General requirements for foreign refiners with individual
refinery sulfur baselines. A foreign refiner of a refinery that has
been assigned an individual sulfur baseline under Sec. 80.250 or
Sec. 80.295 must designate all gasoline produced at the foreign
refinery that is exported to the United States as either Certified
Sulfur-FRGAS or as Non-Certified Sulfur-FRGAS, except as provided in
paragraph (c)(3) of this section.
(1) In the case of Certified Sulfur-FRGAS, the foreign refiner must
meet all provisions that apply to refiners under this subpart H.
(2) In the case of Non-Certified Sulfur-FRGAS, the foreign refiner
shall meet all the following provisions, except the foreign refiner
shall substitute the name Non-Certified Sulfur-FRGAS for the names
``reformulated gasoline'' or ``RBOB'' wherever they appear in the
following provisions:
(i) The designation requirements in this section;
(ii) The recordkeeping requirements under Sec. 80.365;
(iii) The reporting requirements in Sec. 80.370 and this section;
(iv) The product transfer document requirements in this section;
(v) The prohibitions in this section and Sec. 80.385; and
(vi) The independent audit requirements under Sec. 80.415,
paragraph (h) of this section, Secs. 80.125 through
[[Page 6841]]
80.127, Sec. 80.128(a),(b),(c),(g) through (i), and Sec. 80.130.
(3)(i) Any foreign refiner that generates sulfur credits under
Sec. 80.305 during the period 2000 through 2003, or allotments under
Sec. 80.275(a) during 2003, and any small refiner generating credits
under Sec. 80.310, shall designate all Sulfur-FRGAS as Certified
Sulfur-FRGAS for any year that such credits are generated.
(ii) Any foreign refiner that has been assigned an individual
sulfur baseline for a foreign refinery under Sec. 80.250 or Sec. 80.295
may elect to classify no gasoline imported into the United States as
Sulfur-FRGAS, provided the foreign refiner notifies EPA of the election
no later than November 1 of the prior calendar year.
(iii) An election under paragraph (c)(3)(ii) of this section shall:
(A) Apply to an entire calendar year averaging period, and apply to
all gasoline produced during the calendar year at the foreign refinery
that is used in the United States; and
(B) Remain in effect for each succeeding calendar year averaging
period, unless and until the foreign refiner notifies EPA of a
termination of the election. The change in election shall take effect
at the beginning of the next calendar year.
(d) Designation, product transfer documents, and foreign refiner
certification. (1) Any foreign refiner of a foreign refinery that has
been assigned an individual sulfur baseline must designate each batch
of Sulfur-FRGAS as such at the time the gasoline is produced, unless
the refiner has elected to classify no gasoline exported to the United
States as Sulfur-FRGAS under paragraph (c)(3)(i) of this section.
(2) On each occasion when any person transfers custody or title to
any Sulfur-FRGAS prior to its being imported into the United States, it
must include the following information as part of the product transfer
document information in this section:
(i) Identification of the gasoline as Certified Sulfur-FRGAS or as
Non-Certified Sulfur-FRGAS; and
(ii) The name and EPA refinery registration number of the refinery
where the Sulfur-FRGAS was produced.
(3) On each occasion when Sulfur-FRGAS is loaded onto a vessel or
other transportation mode for transport to the United States, the
foreign refiner shall prepare a certification for each batch of the
Sulfur-FRGAS that meets the following requirements:
(i) The certification shall include the report of the independent
third party under paragraph (f) of this section, and the following
additional information:
(A) The name and EPA registration number of the refinery that
produced the Sulfur-FRGAS;
(B) The identification of the gasoline as Certified Sulfur-FRGAS or
Non-Certified Sulfur-FRGAS;
(C) The volume of Sulfur-FRGAS being transported, in gallons;
(D) In the case of Certified Sulfur-FRGAS:
(1) The sulfur content as determined under paragraph (f) of this
section; and
(2) A declaration that the Sulfur-FRGAS is being included in the
compliance calculations under Sec. 80.205 or credit calculations under
Sec. 80.305 or allotments under Sec. 80.275(a) for the refinery that
produced the Sulfur-FRGAS.
(ii) The certification shall be made part of the product transfer
documents for the Sulfur-FRGAS.
(e) Transfers of Sulfur-FRGAS to non-United States markets. The
foreign refiner is responsible to ensure that all gasoline classified
as Sulfur-FRGAS is imported into the United States. A foreign refiner
may remove the Sulfur-FRGAS classification, and the gasoline need not
be imported into the United States, but only if:
(1)(i) The foreign refiner excludes:
(A) The volume of gasoline from the refinery's compliance
calculations under Sec. 80.205; and
(B) In the case of Certified Sulfur-FRGAS, the volume and sulfur
content of the gasoline from the compliance calculations under
Sec. 80.205 or credit calculations under Sec. 80.305.
(ii) The exclusions under paragraph (e)(1)(i) of this section shall
be on the basis of the sulfur content and volumes determined under
paragraph (f) of this section; and
(2) The foreign refiner obtains sufficient evidence in the form of
documentation that the gasoline was not imported into the United
States.
(f) Load port independent sampling, testing and refinery
identification. (1) On each occasion Sulfur-FRGAS is loaded onto a
vessel for transport to the United States a foreign refiner shall have
an independent third party:
(i) Inspect the vessel prior to loading and determine the volume of
any tank bottoms;
(ii) Determine the volume of Sulfur-FRGAS loaded onto the vessel
(exclusive of any tank bottoms present before vessel loading);
(iii) Obtain the EPA-assigned registration number of the foreign
refinery;
(iv) Determine the name and country of registration of the vessel
used to transport the Sulfur-FRGAS to the United States; and
(v) Determine the date and time the vessel departs the port serving
the foreign refinery.
(2) On each occasion Certified Sulfur-FRGAS is loaded onto a vessel
for transport to the United States a foreign refiner shall have an
independent third party:
(i) Collect a representative sample of the Certified Sulfur-FRGAS
from each vessel compartment subsequent to loading on the vessel and
prior to departure of the vessel from the port serving the foreign
refinery;
(ii) Prepare a volume-weighted vessel composite sample from the
compartment samples, and determine the value for sulfur using the
methodology specified in Sec. 80.330 by:
(A) The third party analyzing the sample; or
(B) The third party observing the foreign refiner analyze the
sample;
(iii) Review original documents that reflect movement and storage
of the certified Sulfur-FRGAS from the refinery to the load port, and
from this review determine:
(A) The refinery at which the Sulfur-FRGAS was produced; and
(B) That the Sulfur-FRGAS remained segregated from:
(1) Non-Sulfur-FRGAS and Non-Certified Sulfur-FRGAS; and
(2) Other Certified Sulfur-FRGAS produced at a different refinery.
(3) The independent third party shall submit a report:
(i) To the foreign refiner containing the information required
under paragraphs (f)(1) and (2) of this section, to accompany the
product transfer documents for the vessel; and
(ii) To the Administrator containing the information required under
paragraphs (f)(1) and (2) of this section, within thirty days following
the date of the independent third party's inspection. This report shall
include a description of the method used to determine the identity of
the refinery at which the gasoline was produced, assurance that the
gasoline remained segregated as specified in paragraph (n)(1) of this
section, and a description of the gasoline's movement and storage
between production at the source refinery and vessel loading.
(4) The independent third party must:
(i) Be approved in advance by EPA, based on a demonstration of
ability to perform the procedures required in this paragraph (f);
(ii) Be independent under the criteria specified in
Sec. 80.65(e)(2)(iii); and
(iii) Sign a commitment that contains the provisions specified in
paragraph (i) of this section with regard to activities, facilities and
documents relevant to
[[Page 6842]]
compliance with the requirements of this paragraph (f).
(g) Comparison of load port and port of entry testing. (1)(i)
Except as described in paragraph (g)(1)(ii) of this section, any
foreign refiner and any United States importer of Certified Sulfur-
FRGAS shall compare the results from the load port testing under
paragraph (f) of this section, with the port of entry testing as
reported under paragraph (o) of this section, for the volume of
gasoline and the sulfur value.
(ii) Where a vessel transporting Certified Sulfur-FRGAS off loads
this gasoline at more than one United States port of entry, and the
conditions of paragraph (g)(2)(i) of this section are met at the first
United States port of entry, the requirements of paragraph (g)(2) of
this section do not apply at subsequent ports of entry if the United
States importer obtains a certification from the vessel owner, that
meets the requirements of paragraph (s) of this section, that the
vessel has not loaded any gasoline or blendstock between the first
United States port of entry and the subsequent port of entry.
(2)(i) The requirements of this paragraph (g)(2) apply if:
(A) The temperature-corrected volumes determined at the port of
entry and at the load port differ by more than one percent; or
(B) The sulfur value determined at the port of entry is higher than
the sulfur value determined at the load port, and the amount of this
difference is greater than the reproducibility amount specified for the
port of entry test result by the American Society of Testing and
Materials (ASTM).
(ii) The United States importer and the foreign refiner shall treat
the gasoline as Non-Certified Sulfur-FRGAS, and the foreign refiner
shall exclude the gasoline volume and properties from its gasoline
sulfur compliance calculations under Sec. 80.205.
(h) Attest requirements. The following additional procedures shall
be carried out by any foreign refiner of Sulfur-FRGAS as part of the
applicable attest engagement for each foreign refinery under
Sec. 80.415:
(1) The inventory reconciliation analysis under Sec. 80.128(b) and
the tender analysis under Sec. 80.128(c) shall include Non-Sulfur-FRGAS
in addition to the gasoline types listed in Sec. 80.128(b) and (c).
(2) Obtain separate listings of all tenders of Certified Sulfur-
FRGAS, and of Non-Certified Sulfur-FRGAS. Agree the total volume of
tenders from the listings to the gasoline inventory reconciliation
analysis in Sec. 80.128(b), and to the volumes determined by the third
party under paragraph (f)(1) of this section.
(3) For each tender under paragraph (h)(2) of this section where
the gasoline is loaded onto a marine vessel, report as a finding the
name and country of registration of each vessel, and the volumes of
Sulfur-FRGAS loaded onto each vessel.
(4) Select a sample from the list of vessels identified in
paragraph (h)(3) of this section used to transport Certified Sulfur-
FRGAS, in accordance with the guidelines in Sec. 80.127, and for each
vessel selected perform the following:
(i) Obtain the report of the independent third party, under
paragraph (f) of this section, and of the United States importer under
paragraph (o) of this section.
(A) Agree the information in these reports with regard to vessel
identification, gasoline volumes and test results.
(B) Identify, and report as a finding, each occasion the load port
and port of entry parameter and volume results differ by more than the
amounts allowed in paragraph (g) of this section, and determine whether
the foreign refiner adjusted its refinery calculations as required in
paragraph (g) of this section.
(ii) Obtain the documents used by the independent third party to
determine transportation and storage of the Certified Sulfur-FRGAS from
the refinery to the load port, under paragraph (f) of this section.
Obtain tank activity records for any storage tank where the Certified
Sulfur-FRGAS is stored, and pipeline activity records for any pipeline
used to transport the Certified Sulfur-FRGAS, prior to being loaded
onto the vessel. Use these records to determine whether the Certified
Sulfur-FRGAS was produced at the refinery that is the subject of the
attest engagement, and whether the Certified Sulfur-FRGAS was mixed
with any Non-Certified Sulfur-FRGAS, Non-Sulfur-FRGAS, or any Certified
Sulfur-FRGAS produced at a different refinery.
(5)(i) Select a sample from the list of vessels identified in
paragraph (h)(3) of this section used to transport certified and Non-
Certified Sulfur-FRGAS, in accordance with the guidelines in
Sec. 80.127, and for each vessel selected perform the following:
(ii) Obtain a commercial document of general circulation that lists
vessel arrivals and departures, and that includes the port and date of
departure of the vessel, and the port of entry and date of arrival of
the vessel. Agree the vessel's departure and arrival locations and
dates from the independent third party and United States importer
reports to the information contained in the commercial document.
(6) Obtain separate listings of all tenders of Non-Sulfur-FRGAS,
and perform the following:
(i) Agree the total volume of tenders from the listings to the
gasoline inventory reconciliation analysis in Sec. 80.128(b).
(ii) Obtain a separate listing of the tenders under paragraph
(h)(6) of this section where the gasoline is loaded onto a marine
vessel. Select a sample from this listing in accordance with the
guidelines in Sec. 80.127, and obtain a commercial document of general
circulation that lists vessel arrivals and departures, and that
includes the port and date of departure and the ports and dates where
the gasoline was off loaded for the selected vessels. Determine and
report as a finding the country where the gasoline was off loaded for
each vessel selected.
(7) In order to complete the requirements of this paragraph (h) an
auditor shall:
(i) Be independent of the foreign refiner;
(ii) Be licensed as a Certified Public Accountant in the United
States and a citizen of the United States, or be approved in advance by
EPA based on a demonstration of ability to perform the procedures
required in Secs. 80.125 through 80.130 and this paragraph (h); and
(iii) Sign a commitment that contains the provisions specified in
paragraph (i) of this section with regard to activities and documents
relevant to compliance with the requirements of Secs. 80.125 through
80.130, Sec. 80.415 and this paragraph (h).
(i) Foreign refiner commitments. Any foreign refiner shall commit
to and comply with the provisions contained in this paragraph (i) as a
condition to being assigned an individual refinery sulfur baseline.
(1) Any United States Environmental Protection Agency inspector or
auditor will be given full, complete and immediate access to conduct
inspections and audits of the foreign refinery.
(i) Inspections and audits may be either announced in advance by
EPA, or unannounced.
(ii) Access will be provided to any location where:
(A) Gasoline is produced;
(B) Documents related to refinery operations are kept;
(C) Gasoline or blendstock samples are tested or stored; and
(D) Sulfur-FRGAS is stored or transported between the foreign
refinery
[[Page 6843]]
and the United States, including storage tanks, vessels and pipelines.
(iii) Inspections and audits may be by EPA employees or contractors
to EPA.
(iv) Any documents requested that are related to matters covered by
inspections and audits will be provided to an EPA inspector or auditor
on request.
(v) Inspections and audits by EPA may include review and copying of
any documents related to:
(A) Refinery baseline establishment, including the volume and
sulfur content, and transfers of title or custody, of any gasoline or
blendstocks, whether Sulfur-FRGAS or Non-Sulfur-FRGAS, produced at the
foreign refinery during the period January 1, 1997 through the date of
the refinery baseline petition or through the date of the inspection or
audit if a baseline petition has not been approved, and any work papers
related to refinery baseline establishment;
(B) The volume and sulfur content of Sulfur-FRGAS;
(C) The proper classification of gasoline as being Sulfur-FRGAS or
as not being Sulfur-FRGAS, or as Certified Sulfur-FRGAS or as Non-
Certified Sulfur-FRGAS;
(D) Transfers of title or custody to Sulfur-FRGAS;
(E) Sampling and testing of Sulfur-FRGAS;
(F) Work performed and reports prepared by independent third
parties and by independent auditors under the requirements of this
section and Sec. 80.415 including work papers; and
(G) Reports prepared for submission to EPA, and any work papers
related to such reports.
(vi) Inspections and audits by EPA may include taking samples of
gasoline or blendstock, and interviewing employees.
(vii) Any employee of the foreign refiner will be made available
for interview by the EPA inspector or auditor, on request, within a
reasonable time period.
(viii) English language translations of any documents will be
provided to an EPA inspector or auditor, on request, within 10 working
days.
(ix) English language interpreters will be provided to accompany
EPA inspectors and auditors, on request.
(2) An agent for service of process located in the District of
Columbia will be named, and service on this agent constitutes service
on the foreign refiner or any employee of the foreign refiner for any
action by EPA or otherwise by the United States related to the
requirements of this subpart H.
(3) The forum for any civil or criminal enforcement action related
to the provisions of this section for violations of the Clean Air Act
or regulations promulgated thereunder shall be governed by the Clean
Air Act, including the EPA administrative forum where allowed under the
Clean Air Act.
(4) United States substantive and procedural laws shall apply to
any civil or criminal enforcement action against the foreign refiner or
any employee of the foreign refiner related to the provisions of this
section.
(5) Submitting a petition for an individual refinery sulfur
baseline, producing and exporting gasoline under an individual refinery
sulfur baseline, and all other actions to comply with the requirements
of this subpart H relating to the establishment and use of an
individual refinery sulfur baseline constitute actions or activities
that satisfy the provisions of 28 U.S.C. section 1605(a)(2), but solely
with respect to actions instituted against the foreign refiner, its
agents and employees in any court or other tribunal in the United
States for conduct that violates the requirements applicable to the
foreign refiner under this subpart H, including conduct that violates
Title 18 U.S.C. section 1001 and Clean Air Act section 113(c)(2).
(6) The foreign refiner, or its agents or employees, will not seek
to detain or to impose civil or criminal remedies against EPA
inspectors or auditors, whether EPA employees or EPA contractors, for
actions performed within the scope of EPA employment related to the
provisions of this section.
(7) The commitment required by this paragraph (i) shall be signed
by the owner or president of the foreign refiner business.
(8) In any case where Sulfur-FRGAS produced at a foreign refinery
is stored or transported by another company between the refinery and
the vessel that transports the Sulfur-FRGAS to the United States, the
foreign refiner shall obtain from each such other company a commitment
that meets the requirements specified in paragraphs (i)(1) through (7)
of this section, and these commitments shall be included in the foreign
refiner's baseline petition.
(j) Sovereign immunity. By submitting a petition for an individual
foreign refinery baseline under this section, or by producing and
exporting gasoline to the United States under an individual refinery
sulfur baseline under this section, the foreign refiner, its agents and
employees, without exception, become subject to the full operation of
the administrative and judicial enforcement powers and provisions of
the United States without limitation based on sovereign immunity, with
respect to actions instituted against the foreign refiner, its agents
and employees in any court or other tribunal in the United States for
conduct that violates the requirements applicable to the foreign
refiner under this subpart H, including conduct that violates Title 18
U.S.C. section 1001 and Clean Air Act section 113(c)(2).
(k) Bond posting. Any foreign refiner shall meet the requirements
of this paragraph (k) as a condition to being assigned an individual
refinery sulfur baseline.
(l) The foreign refiner shall post a bond of the amount calculated
using the following equation:
Bond=G x $ 0.01
where:
Bond=amount of the bond in U. S. dollars.
G=the largest volume of gasoline produced at the foreign refinery and
exported to the United States, in gallons, during a single calendar
year among the most recent of the following calendar years, up to a
maximum of five calendar years: the calendar year immediately preceding
the date the baseline petition is submitted, the calendar year the
baseline petition is submitted, and each succeeding calendar year.
(2) Bonds shall be posted by:
(i) Paying the amount of the bond to the Treasurer of the United
States;
(ii) Obtaining a bond in the proper amount from a third party
surety agent that is payable to satisfy United States administrative or
judicial judgments against the foreign refiner, provided EPA agrees in
advance as to the third party and the nature of the surety agreement;
or
(iii) An alternative commitment that results in assets of an
appropriate liquidity and value being readily available to the United
States, provided EPA agrees in advance as to the alternative
commitment.
(3) If the bond amount for a foreign refinery increases, the
foreign refiner shall increase the bond to cover the shortfall within
90 days of the date the bond amount changes. If the bond amount
decreases, the foreign refiner may reduce the amount of the bond
beginning 90 days after the date the bond amount changes.
(4) Bonds posted under this paragraph (k) shall:
(i) Be used to satisfy any judicial judgment that results from an
administrative or judicial enforcement action for conduct in violation
of this subpart H, including where such conduct violates Title 18
U.S.C. section
[[Page 6844]]
1001 and Clean Air Act section 113(c)(2);
(ii) Be provided by a corporate surety that is listed in the United
States Department of Treasury Circular 570 ``Companies Holding
Certificates of Authority as Acceptable Sureties on Federal Bonds and
Acceptable Reinsuring Companies'' (Available from the U.S. Department
of the Treasury, Financial Management Service, Surety Bond Branch, 3700
East-West Highway, Room 6A04, Hyattsville, Md. 20782. Also available on
the internet at http://www.fms.treas.gov/c570/c570.html); and
(iii) Include a commitment that the bond will remain in effect for
at least five (5) years following the end of latest averaging period
that the foreign refiner produces gasoline pursuant to the requirements
of this Subpart H.
(5) On any occasion a foreign refiner bond is used to satisfy any
judgment, the foreign refiner shall increase the bond to cover the
amount used within 90 days of the date the bond is used.
(l) [Reserved]
(m) English language reports. Any report or other document
submitted to EPA by an foreign refiner shall be in English language, or
shall include an English language translation.
(n) Prohibitions. (1) No person may combine Certified Sulfur-FRGAS
with any Non-Certified Sulfur-FRGAS or Non-Sulfur-FRGAS, and no person
may combine Certified Sulfur-FRGAS with any Certified Sulfur-FRGAS
produced at a different refinery, until the importer has met all the
requirements of paragraph (o) of this section, except as provided in
paragraph (e) of this section.
(2) No foreign refiner or other person may cause another person to
commit an action prohibited in paragraph (n)(1) of this section, or
that otherwise violates the requirements of this section.
(o) United States importer requirements. Any United States importer
shall meet the following requirements:
(1) Each batch of imported gasoline shall be classified by the
importer as being Sulfur-FRGAS or as Non-Sulfur-FRGAS, and each batch
classified as Sulfur-FRGAS shall be further classified as Certified
Sulfur-FRGAS or as Non-certified Sulfur-FRGAS.
(2) Gasoline shall be classified as Certified Sulfur-FRGAS or as
Non-Certified Sulfur-FRGAS according to the designation by the foreign
refiner if this designation is supported by product transfer documents
prepared by the foreign refiner as required in paragraph (d) of this
section, unless the gasoline is classified as Non-Certified Sulfur-
FRGAS under paragraph (g) of this section.
(3) For each gasoline batch classified as Sulfur-FRGAS, any United
States importer shall perform the following procedures:
(i) In the case of both Certified and Non-Certified Sulfur-FRGAS,
have an independent third party:
(A) Determine the volume of gasoline in the vessel;
(B) Use the foreign refiner's Sulfur-FRGAS certification to
determine the name and EPA-assigned registration number of the foreign
refinery that produced the Sulfur-FRGAS;
(C) Determine the name and country of registration of the vessel
used to transport the Sulfur-FRGAS to the United States; and
(D) Determine the date and time the vessel arrives at the United
States port of entry.
(ii) In the case of Certified Sulfur-FRGAS, have an independent
third party:
(A) Collect a representative sample from each vessel compartment
subsequent to the vessel's arrival at the United States port of entry
and prior to off loading any gasoline from the vessel;
(B) Prepare a volume-weighted vessel composite sample from the
compartment samples; and
(C) Determine the sulfur value using the methodologies specified in
Sec. 80.330, by:
(1) The third party analyzing the sample; or
(2) The third party observing the importer analyze the sample.
(4) Any importer shall submit reports within thirty days following
the date any vessel transporting Sulfur-FRGAS arrives at the United
States port of entry:
(i) To the Administrator containing the information determined
under paragraph (o)(3) of this section; and
(ii) To the foreign refiner containing the information determined
under paragraph (o)(3)(ii) of this section.
(5)(i) Any United States importer shall meet the requirements
specified in Sec. 80.195 for any imported gasoline that is not
classified as Certified Sulfur-FRGAS under paragraph (o)(2) of this
section.
(p) Truck imports of Certified Sulfur-FRGAS produced at a small
refinery. (1) Any refiner whose Certified Sulfur-FRGAS is transported
into the United States by truck may petition EPA to use alternative
procedures to meet the following requirements:
(i) Certification under paragraph (d)(5) of this section;
(ii) Load port and port of entry sampling and testing under
paragraphs (f) and (g) of this section;
(iii) Attest under paragraph (h) of this section; and
(iv) Importer testing under paragraph (o)(3) of this section.
(2) These alternative procedures must ensure Certified Sulfur-FRGAS
remains segregated from Non-Certified Sulfur-FRGAS and from Non-Sulfur-
FRGAS until it is imported into the United States. The petition will be
evaluated based on whether it adequately addresses the following:
(i) Provisions for monitoring pipeline shipments, if applicable,
from the refinery, that ensure segregation of Certified Sulfur-FRGAS
from that refinery from all other gasoline;
(ii) Contracts with any terminals and/or pipelines that receive
and/or transport Certified Sulfur-FRGAS, that prohibit the commingling
of Certified Sulfur-FRGAS with any of the following:
(A) Other Certified Sulfur-FRGAS from other refineries;
(B) All Non-Certified Sulfur-FRGAS; or
(C) All Non-Sulfur-FRGAS;
(iii) Procedures for obtaining and reviewing truck loading records
and United States import documents for Certified Sulfur-FRGAS to ensure
that such gasoline is only loaded into trucks making deliveries to the
United States; and
(iv) Attest procedures to be conducted annually by an independent
third party that review loading records and import documents based on
volume reconciliation, or other criteria, to confirm that all Certified
Sulfur-FRGAS remains segregated throughout the distribution system and
is only loaded into trucks for import into the United States.
(3) The petition required by this section must be submitted to EPA
along with the application for small refiner status and individual
refinery sulfur baseline and standards under Sec. 80.240 and this
section.
(q) Withdrawal or suspension of a foreign refinery's baseline. EPA
may withdraw or suspend a baseline that has been assigned to a foreign
refinery where:
(1) A foreign refiner fails to meet any requirement of this
section;
(2) A foreign government fails to allow EPA inspections as provided
in paragraph (i)(1) of this section;
(3) A foreign refiner asserts a claim of, or a right to claim,
sovereign immunity in an action to enforce the requirements in this
subpart H; or
(4) A foreign refiner fails to pay a civil or criminal penalty that
is not satisfied using the foreign refiner bond specified in paragraph
(k) of this section.
[[Page 6845]]
(r) Early use of a foreign refinery baseline. (1) A foreign refiner
may begin using an individual refinery baseline before EPA has approved
the baseline, provided that:
(i) A baseline petition has been submitted as required in paragraph
(b) of this section;
(ii) EPA has made a provisional finding that the baseline petition
is complete;
(iii) The foreign refiner has made the commitments required in
paragraph (i) of this section;
(iv) The persons who will meet the independent third party and
independent attest requirements for the foreign refinery have made the
commitments required in paragraphs (f)(3)(iii) and (h)(7)(iii) of this
section; and
(v) The foreign refiner has met the bond requirements of paragraph
(k) of this section.
(2) In any case where a foreign refiner uses an individual refinery
baseline before final approval under paragraph (r)(1) of this section,
and the foreign refinery baseline values that ultimately are approved
by EPA are more stringent than the early baseline values used by the
foreign refiner, the foreign refiner shall recalculate its compliance,
ab initio, using the baseline values approved by EPA, and the foreign
refiner shall be liable for any resulting violation of the conventional
gasoline requirements.
(s) Additional requirements for petitions, reports and
certificates. Any petition for a refinery baseline under Sec. 80.250 or
Sec. 80.295, any alternative procedures under paragraph (r) of this
section, any report or other submission required by paragraphs (c),
(f)(2), or (i) of this section, and any certification under paragraph
(d)(3) of this section shall be:
(1) Submitted in accordance with procedures specified by the
Administrator, including use of any forms that may be specified by the
Administrator; and
(2) Be signed by the president or owner of the foreign refiner
company, or by that person's immediate designee, and shall contain the
following declaration:
I hereby certify: (1) that I have actual authority to sign on
behalf of and to bind [insert name of foreign refiner] with regard
to all statements contained herein; (2) that I am aware that the
information contained herein is being certified, or submitted to the
United States Environmental Protection Agency, under the
requirements of 40 CFR. Part 80, subpart H, and that the information
is material for determining compliance under these regulations; and
(3) that I have read and understand the information being certified
or submitted, and this information is true, complete and correct to
the best of my knowledge and belief after I have taken reasonable
and appropriate steps to verify the accuracy thereof.
I affirm that I have read and understand the provisions of 40
CFR Part 80, subpart H, including 40 CFR 80.410 [insert name of
foreign refiner]. Pursuant to Clean Air Act section 113(c) and Title
18, United States Code, section 1001, the penalty for furnishing
false, incomplete or misleading information in this certification or
submission is a fine of up to $10,000, and/or imprisonment for up to
five years.
Attest Engagements
Sec. 80.415 What are the attest engagement requirements for gasoline
sulfur compliance applicable to refiners and importers?
In addition to the requirements for attest engagements that apply
to refiners and importers under Secs. 80.125 through 80.130, and
Sec. 80.410, the attest engagements for importers and refiners must
include the following procedures and requirements each year.
(a) Baseline. (1) Obtain the EPA sulfur baseline approval letter
for the refinery to determine the refinery's applicable sulfur baseline
and baseline volume under Secs. 80.250 or 80.295.
(2) If the year being reviewed is 2004 through 2006 (2007 for
refineries with small refiner status) and the refinery or importer
produced or imported any GPA gasoline under Sec. 80.216 or the refiner
has approved status for a small refinery:
(i) Obtain the refinery's annual sulfur reports for 2000 through
2003; and
(ii) Determine whether the annual average sulfur level for any year
credits were generated for 2000 through 2003 was less than the baseline
level under paragraph (a)(1) of this section.
(3) If the annual average sulfur content for any year credits were
created for 2000 through 2003 was less than the baseline level under
paragraph (a)(1) of this section, report as a finding the lowest annual
sulfur level as the new baseline value. For GPA gasoline add 30 ppm to
obtain the GPA standard, not to exceed 150 ppm.
(4) If the refinery being reviewed is a small refinery and the
annual volume under paragraph (b)(2) of this section is greater than
the baseline volume, calculate the applicable standard in accordance
with Sec. 80.240(c).
(5) Obtain a written representation from the company representative
stating the sulfur value that the company used as its baseline and
agree that number to paragraphs (a)(1) through (a)(4) of this section
and to the reports to EPA.
(b) EPA reports. (1) Obtain and read a copy of the refinery's or
importer's annual sulfur reports filed with EPA for the year.
(2) Agree the yearly volume of gasoline reported to EPA in the
sulfur reports with the inventory reconciliation analysis under
Sec. 80.128.
(3) For the years 2004 through 2006, calculate the annual volume
and average sulfur level for gasoline classified as GPA gasoline under
Secs. 80.216 and 80.219, and calculate the annual volume and average
sulfur level for gasoline not classified as GPA gasoline, and agree
these values with the values reported to EPA.
(4) Except as provided in paragraph (b)(3) of this section,
calculate the annual average sulfur level for all gasoline and agree
that value with the value reported to EPA.
(5) Obtain and read a copy of the refinery's or importer's sulfur
credit report.
(c) Credit generation before 2004. In the case of a refinery that
only generates credits during 2000 through 2003:
(1) Obtain a written representation from the company representative
stating the refinery produces gasoline from crude oil.
(2) Compute and report as a finding the sulfur baseline from
paragraph (a) of this section multiplied by 0.9.
(3) Obtain the annual average sulfur level from paragraph (b)(4) of
this section.
(4) If the sulfur value under paragraph (c)(3) of this section is
less than the sulfur value under paragraph (c)(2) of this section,
compute and report as a finding the difference between the annual
average sulfur level and the refinery's sulfur baseline from paragraph
(a) of this section.
(5) Compute and report as a finding the total number of sulfur
credits generated by multiplying the value in paragraph (c)(4) of this
section by the volume of gasoline in paragraph (b)(2) of this section,
and agree this value with the value reported to EPA.
(d) Credit generation in 2004 and thereafter. The following
procedures shall be completed for a refinery or importer that generates
credits in 2004 and thereafter:
(1) Obtain the annual average sulfur level for gasoline not
classified as GPA from paragraph (b)(3) of this section.
(2) If the sulfur value under paragraph (d)(1) of this section is
less than 30 ppm, compute and report as a finding the difference
between the sulfur level under paragraph (d)(1) of this section and 30
ppm.
(3) Compute and report as a finding the total number of sulfur
credits generated by multiplying the value calculated in paragraph
(d)(2) of this
[[Page 6846]]
section by the volume of gasoline not classified as GPA in paragraph
(b)(3) of this section, and agree this number with the number reported
to EPA.
(4) Obtain the annual average sulfur level for gasoline classified
as GPA from paragraph (b)(3) of this section.
(5) If the sulfur value under paragraph (d)(4) of this section is
less than the applicable level under Sec. 80.310, compute and report as
a finding the difference between the sulfur level under paragraph
(d)(4) of this section and the appropriate level in Sec. 80.310 .
(6) Compute and report as a finding the total number of sulfur
credits generated by multiplying the value calculated in paragraph
(d)(5) of this section by the volume of gasoline classified as GPA in
paragraph (b)(3) of this section, and agree this number with the number
reported to EPA.
(7) If the refiner has an approved status as a small refinery,
obtain the annual average sulfur level for gasoline from paragraph
(b)(4) of this section.
(8) If the sulfur value under paragraph (d)(7) of this section is
less than the applicable standard under Sec. 80.240, compute and report
as a finding the difference between the sulfur level under paragraph
(d)(7) of this section and the appropriate standard under Sec. 80.240.
(9) Compute and report as a finding the total number of sulfur
credits generated by multiplying the value calculated in paragraph
(d)(8) of this section by the volume of gasoline in paragraph (b)(4) of
this section, and agree this number with the number reported to EPA.
(e) Credit purchases and sales. The following attest procedures
shall be completed for a refinery or importer that is a transferor or
transferee of credits during an averaging period:
(1) Obtain contracts or other documents for all credits transferred
to another refinery or importer during the year being reviewed; compute
and report as a finding the number and year of creation of credits
represented in these documents as being transferred away; and agree
with the report to EPA.
(2) Obtain contracts or other documents for all credits received
during the year being reviewed; compute and report as a finding the
number and year of creation of credits represented in these documents
as being received; and agree with the report to EPA.
(f) Credits required for non-GPA gasoline. The following attest
procedures shall be completed for refineries and importers in 2005 and
thereafter (2004 and thereafter for refineries having standards under
Sec. 80.240):
(1) Obtain the annual average sulfur level for gasoline not
classified as GPA from paragraph (b)(3) of this section.
(2) If the value in paragraph (f)(1) of this section is greater
than 30 ppm (or greater than the small refinery standard), compute and
report as a finding the difference between 30 ppm (or the standard
under Sec. 80.240) and the value in paragraph (f)(1) of this section.
(3) Compute and report as a finding the total sulfur credits
required by multiplying the value in paragraph (f)(2) of this section
times the volume of gasoline not classified as GPA in paragraph (b)(3)
of this section, and agree with the report to EPA.
(4) Obtain the refiner's or importer's representation as to the
portion of the deficit under paragraph (f)(3) of this section that was
resolved with credits, the portion that was resolved with allotments in
2005 only or that was carried forward as a deficit under Sec. 80.205,
and agree with the report to EPA (refineries subject to standards under
Sec. 80.240 cannot carry deficits forward).
(g) Credits required for GPA gasoline. The following attest
procedures shall be completed in 2004 through 2006 for a refinery or
importer that produces gasoline subject to the geographic phase-in area
standards under Sec. 80.216:
(1) Obtain the annual average sulfur level for the refinery's or
importer's GPA gasoline from paragraph (b)(3) of this section.
(2) If the value in paragraph (g)(1) of this section is greater
than the refinery's or importer's baseline plus 30 ppm under
Sec. 80.216, as determined in paragraph (a) of this section or 150 ppm,
whichever is less, compute and report as a finding the difference
between the annual average sulfur level and the baseline level plus 30
ppm, or 150 ppm, whichever is less.
(3) Compute and report as a finding the total sulfur credits and/or
allotments required by multiplying the value in paragraph (g)(2) of
this section times the volume of GPA gasoline from paragraph (b)(3) of
this section.
(4) Obtain the refiner's or importer's representation as to the
portion of the deficit under paragraph (g)(3) of this section that was
resolved with credits, or the portion that was resolved with allotments
in 2004 or 2005 only (compliance deficits for GPA gasoline cannot be
carried forward.
(h) Credit expiration. The following attest procedures shall be
completed for a refinery or importer that possesses credits during an
averaging period:
(1) Obtain a list of all credits in the refiner's or importer's
possession at any time during the year being reviewed, identified by
the year of creation of the credits.
(2) If the year being reviewed is 2006 and thereafter, except in
the case of gasoline produced for use in the GPA and gasoline produced
by small refiners, determine whether any credits identified in
paragraph (h)(1) of this section or Type A sulfur allotments created
under paragraph (i) of this section and converted to credits were
created before 2004, and if so, report as a finding this number of
expired credits.
(3) If the year being reviewed is 2008 and thereafter, determine
whether any credits identified in paragraph (h)(1) of this section or
Type B sulfur allotments created under paragraph (i) of this section
and converted to credits were created more than 5 years before the year
being reviewed, and if so, report as a finding this number of expired
credits (for example, unused credits created during the 2004 averaging
period expire at the end of the 2009 averaging period).
(i) Optional credit and allotment generation in 2003. The following
requirements apply to any refinery that generates credits and
allotments in 2003 under Sec. 80.275(a):
(1) Obtain a written representation from the company representative
stating the refinery produces gasoline from crude oil.
(2) Obtain the refinery baseline value from paragraph (b)(1) of
this section, the annual volume from paragraph (b)(2) of this section
and the annual average sulfur level from paragraph (b)(4) of this
section.
(3) Based on the annual sulfur level and refinery baseline,
determine which equation under Sec. 80.275(a)(2) applies.
(4) Using the applicable equations under Sec. 80.275(a)(2),
recalculate the sulfur allotments, by type, and credits and report as a
finding.
(j) Credit reconciliation. The following attest procedures shall be
completed each year credits were in the refiner's or importer's
possession at any time during the year:
(1) Obtain the credits remaining or the credit deficit from the
previous year from the refiner's or importer's report to EPA for the
previous year.
(2) Compute and report as a finding the net credits remaining at
the conclusion of the year being reviewed by totaling:
(i) Credits remaining from the previous year; plus
(ii) Credits generated under paragraphs (c), (d) and (i) of this
section; plus
[[Continued on page 6847]]