small entities in meeting the proposed Tier 3 standards. This proposed
approach would allow the overall program to begin as early as possible;
achieving the air quality benefits of the program as soon as possible,
while helping to ensure that small entities have adequate time to make
any necessary modifications to their product lines. We believe that
small business regulatory flexibilities could provide these entities
with additional help and/or time to take advantage of technological
developments by other parties and to accumulate capital internally or
to secure capital financing from lenders, and could spread out the
availability of any needed engineering resources. We believe these
provisions will also reduce their overall compliance burden and allow
them to more easily transition to the new standards in a way that
matches their business practices.
    The provisions described below would be available to all small
businesses subject to the Tier 3 emission standards. The types of
companies subject to the Tier 3 emission standards include vehicle
manufacturers, and two additional categories of businesses that are
generally referred to as independent commercial importers (ICIs) and
alternative fuel vehicle converters. As discussed below, the proposed
set of flexibilities would also be available to manufacturers in these
three business categories that sell less than 5,000 vehicles per year
that are subject to the Tier 3 emission standards.

1. Lead Time for Exhaust and Evaporative Emission Standards
    As noted above, small businesses have limited resources available
for developing new designs to comply with new emission standards. In
addition, it is often necessary for these businesses to rely on vendor
companies for technology. Moreover, percentage phase-in requirements
and declining fleet average standards pose a dilemma for a small
manufacturer that has a limited product line (e.g., the manufacturer
certifies vehicles in only one or two test groups). Thus, similar to
the flexibility provisions implemented in previous vehicle rules, the
Panel recommended that EPA allow small businesses the following
flexibility option for meeting the proposed Tier 3 emissions standards.
    EPA is proposing that small businesses (and small volume
manufacturers, as discussed below) be given additional lead time to
comply with the proposed Tier 3 exhaust and evaporative emission
standards. Specifically, we propose to allow small manufacturers to
postpone compliance with the standards and other Tier 3 requirements,
including use of the proposed new certification test fuel, until model
year 2022. For model year 2022 and later, small manufacturers would be
subject to the same Tier 3 exhaust and evaporative requirements as
other manufacturers, including moving to the declining FTP fleet
average NMOG+NOX curve and complying with the fully phased-
in standard of 30 mg/mi, as well as certifying on E15 test fuel. (This
approach is similar to that in the Tier 2 rule where EPA allowed small
manufacturers to wait until the end of the phase-in to comply with the
Tier 2 standards.) As described earlier in this section, the proposed
Tier 3 rule has several different phase-in schedules; with the final
dates varying from model year 2021 for the new light-duty exhaust PM
standards to model year 2025 for the new light-duty exhaust gaseous
pollutant standards. Requiring all small businesses to comply with the
full slate of Tier 3 requirements in model year 2022 should provide
sufficient lead time for manufacturers to plan for and implement the
technology changes needed to comply with the Tier 3 standards.
    During the SBAR Panel process, one small entity representative
(SER) recommended that EPA adopt relaxed exhaust standards for small
manufacturers. The SER noted that the exhaust emission averaging
program being proposed by EPA would allow large manufacturers that have
many engine families to certify their small, niche products at emission
levels numerically higher than the standards. Small manufacturers that
typically do not have more than one or two emission families generally
cannot use averaging to the same extent because of their limited
product offerings. The SER was concerned that the high-performance
vehicles produced by large manufacturers which they compete against
would be able to certify at numerically higher levels at less cost than
the SER would incur. The SER-recommended relaxed NMOG+NOX
standards over the Federal Test Procedure (FTP) are 125 mg/mi in model
year 2020 and 70 mg/mi in model year 2025. This is the same general
approach that the CARB Board approved for small volume manufacturers in
LEV III (a relaxed standard NMOG+NOX of 125 mg/mi followed
by a fully phased-in standard of 70 mg/mi in model year 2025), except
that the CARB program introduces the relaxed standard and the change in
test fuel in model year 2022.
    As described above, although we are proposing a delay in the Tier 3
requirements, EPA is not proposing to relax the fully phased-in
standards for the small entities. We believe that these standards are
technologically feasible and can be readily achieved with the
additional lead time we are proposing as the technology would have
already been demonstrated by other manufacturers, in some cases on the
very same engines used by the small manufacturers. In addition, the
compliance costs for many of these vehicles, even if higher on an
absolute basis, may still be lower on a relative basis given the higher
average cost of the vehicles. Furthermore, EPA is proposing to allow
manufacturers to apply for hardship relief (discussed below) on a case-
by-case basis. EPA requests comment on our proposed approach and
whether there is an additional need for the final rule to allow small
manufacturers to meet relaxed NMOG+NOX exhaust emission
standards on the FTP over the long term, as suggested by the SER and as
reflected in action by CARB.
    In light of the CARB Board-approved implementation schedule for
small manufacturers described above, we also request comment on an
option that would not provide a permanent relaxed standard for small
manufacturers, but would provide a temporary relaxed standard matching
the California standard from model year 2022 through 2024. This option
would apply to the Tier 3 exhaust emission standards starting in 2022,
except that a relaxed NMOG+NOX standard of 125 mg/mi would
apply in model years 2020-2024 for FTP testing. For model years 2025
and later, the standard would be the same as for all other
manufacturers, or 30 mg/mi. Under this option, small manufacturers
would have to take some action to reduce emissions in 2022 and could
postpone meeting fully phased-in Tier 3 standards until 2025.
2. Assigned Deterioration Factors
    Under EPA's regulations, manufacturers must demonstrate that their
vehicles comply with the emission standards throughout the ``useful
life'' period. This is generally done by testing vehicles at low-
mileage and then applying a deterioration factor to these emission
levels. The deterioration factors are determined by aging new emission
control systems and then testing the aged systems again to determine
how much deterioration in emissions has occurred. In order to reduce
the testing burden in previous rulemaking, EPA has allowed small
manufacturers to use deterioration factor values assigned by EPA
instead of performing the extended testing. A manufacturer would apply
the assigned deterioration factors to its low-mileage emission level to
demonstrate whether it complied with the Tier 3 emission standards.
    With today's proposal, EPA proposes that small businesses be
allowed the option to use EPA-developed assigned deterioration factors
in demonstrating compliance with the Tier 3 exhaust and evaporative
emission standards. In the past, EPA has relied on deterioration factor
data from large manufacturers to develop the assigned deterioration
factors for small manufacturers. EPA would expect to follow a similar
procedure to determine the assigned deterioration factors for the Tier
3 standards once large manufacturers start certifying their Tier 3
designs. Given that larger manufacturers would begin phasing in to the
Tier 3 standards in model year 2017, EPA should have a significant set
of emissions deterioration data upon which to base the assigned
deterioration factors for small businesses within the first few years
of the Tier 3 program. EPA recognizes that assigned deterioration
factors need to be determined well in advance of model year 2022 in
order to provide sufficient time for small businesses to decide whether
or not to use the assigned deterioration factors for certification
purposes.
3. Reduced Testing Burden
    Under EPA's regulations, manufacturers must perform in-use

testing on their vehicles and demonstrate their in-use vehicles comply
with the emission standards. The current in-use testing regulations
provide for reduced levels of testing for small manufacturers,
including no testing in some cases. EPA is proposing to continue the
reduced levels of testing for small businesses under the Tier 3
program. Under the reduced testing provisions, manufacturers that sell
less than 5,000 units per year would not be required to do any testing
under the in-use program. Manufacturers that sell between 5,001 and
15,000 units per year would be required to test two vehicles per test
group, but only under the high-mileage conditions specified in the in-
use program.
    Under current regulations, manufacturers may waive testing for PM
emissions for light-duty vehicles and trucks, except for diesel-fueled
vehicles. Manufacturers are still subject to the standards and must
make a statement of compliance with the PM standards. As described in
Section IV.A, EPA is proposing new PM standards and will require
manufacturers to test for PM emissions for all fuels. Because PM
testing requires additional test equipment and facilities, the costs
incurred for PM testing can be substantial, especially for a company
selling small numbers of vehicles. Therefore, EPA is proposing to
continue the waiver for PM testing in the Tier 3 timeframe for small
businesses. Small businesses will not be required to measure PM
emissions when they certify to the Tier 3 emission standards. In lieu
of testing, small businesses will be required to make a statement of
compliance with the Tier 3 p.m. standards. We would retain the ability
to determine the PM emissions results in confirmatory or in-use
testing.
    As described in Section IV.C, EPA is proposing new OBD requirements
for vehicles certifying to the Tier 3 standards. The proposed OBD
requirements are the same as CARB's existing OBD requirements. The
proposed OBD provisions require additional amounts of testing and
information that can add significant cost for manufacturers if they are
not already meeting the CARB OBD requirements. Small business vehicle
manufacturers tend to comply with the CARB OBD requirements because
they want to sell in the California market. On the other hand,
alternative-fuel converters do not generally certify with CARB because
of the significant cost burden of complying with the CARB OBD
requirements. We are therefore proposing that small business
alternative-fuel converters may continue to comply with EPA's existing
OBD requirements (see 40 CFR 86.1806-05) when the Tier 3 standards
become effective. However, the proposed upgraded OBD requirements would
have to be met by small entities and ICI's by the 2022 MY.
    Alternative-fueled vehicles, MDPVs, FFVs, and HDVs do not have SFTP
emissions requirements under the current regulations. As described in
Section IV.A, EPA is proposing to apply the Tier 3 SFTP standards to
all vehicles, including alternative-fueled vehicles, MDPVs, FFVs, and
HDVs. Because SFTP testing includes emission measurement over the SC03
test cycle, which requires additional test facilities beyond those
needed to run the FTP, the costs incurred for SC03 testing can be
substantial, especially for companies like alternative fuel converters
that sell very low numbers of converted vehicles. We are proposing that
for the categories of vehicles newly subject to the SFTP standards,
including alternative-fueled vehicles, manufacturers have the option to
substitute the FTP emissions levels for the SC03 emissions results for
purposes of compliance when calculating the SFTP emissions. However, we
would retain the ability to determine the composite emissions using
SC03 test results in confirmatory or in-use testing. Because the
vehicles being converted to an alternative fuel will likely have been
tested for SFTP compliance, we expect the SFTP emissions should be
similarly low, and therefore the added SC03 testing burden is
unnecessary.
    During the SBAR process, one SER requested that EPA eliminate some
of the evaporative emission testing requirements for small businesses
based on its belief that some of the tests may be duplicative. While
EPA understands the reasons behind the SER's suggestion, we believe it
may be premature to consider such an option in the Tier 3 rule given
the potential impact of the CO2 emission standards on engine
and fuel system development. Currently, it is generally understood that
the 2-day diurnal test drives the purge characteristics of evaporative
control systems, while the refueling test, and to a lesser degree the
3-day test, drive the capacity requirement of evaporative canisters.
Prospectively, due to expected changes in engine and fuel system
designs in response to upcoming CO2 emission standard
requirements, this may not be the case. Therefore, EPA believes it is
appropriate to retain all of the evaporative test procedures. It can be
noted that under current regulations, EPA does allow manufacturers to
waive 2-day diurnal testing for certification purposes (see 40 CFR
86.1829-01(b)(2)(iii)) and perform only the 2-day diurnal test as part
of the in-use testing program (see 40 CFR 86.1845-04(c)(5)(ii)). These
provisions would continue in the Tier 3 program. In general, EPA is
open to changes that reduce test burden while maintaining the
environmental effectiveness of its programs and could consider changes
like those suggested by the SER in the future as the impacts of the
future regulations on engine and vehicle design become clearer.
Therefore, EPA requests comment on streamlining the current test
procedures for small businesses in ways that would still maintain the
overall effectiveness of the tests.
4. Hardship
    EPA is proposing hardship provisions for small businesses subject
to the Tier 3 exhaust and evaporative emission standards. Under the
hardship provisions, small businesses would be allowed to apply for
additional time to meet the 100 percent phase-in requirements for
exhaust and evaporative emissions. All hardship requests would be
subject to EPA review and approval. Appeals for such hardship relief
would need to be made in writing and must be submitted well before the
earliest date of potential noncompliance. The request would need to
identify how much time is being requested. It must also include
evidence that the noncompliance would occur despite the manufacturer's
best efforts to comply, and must contain evidence that severe economic
hardship would be faced by the company if the relief is not granted.
The hardship provision should effectively provide the opportunity for
small businesses to obtain more time to comply with the new Tier 3
standards. The existing hardship provisions limit the extra time that
can be requested to 1 year, but we are proposing that such a limit is
not needed as part of the Tier 3 hardship provisions.
5. Applicability of Flexibilities
    Under EPA's Tier 2 regulations, EPA provides a number of
flexibilities for small volume manufacturers (SVMs). The criteria for
determining if a company is a ``small volume manufacturer'' is based on
the annual production level of vehicles and is based on whether the
company produces less than 15,000 vehicles per year. Unlike EPA's
current small volume manufacturer criteria, the Small Business
Administration (SBA) defines which manufacturers are small businesses
based on the number of employees for vehicle manufacturers and annual
revenues for ICIs and

alternative fuel converters. For example, SBA defines a small business
vehicle manufacturer as those who have less than 1,000 employees.
    With today's notice, EPA proposes that all small businesses that
are subject to the Tier 3 standards and that meet the SBA criteria be
eligible for the flexibilities described above. Unless otherwise noted,
the proposed flexibilities would be available to all small business
vehicle manufacturers, ICIs, and alternative fuel converters subject to
the Tier 3 standards. In addition, EPA is proposing that manufacturers
subject to the Tier 3 standards which meet a specified sales-based
criterion be eligible for the flexibilities described above. It is
relatively easy for a manufacturer to project and ultimately determine
sales. Determining the annual revenues or number of employees is less
straightforward. In the recent rule setting the first light-duty
vehicle and truck CO2 emission standards, EPA adopted
provisions for small manufacturers based on a sales cutoff of 5,000
vehicles per year as opposed to the 15,000 level noted earlier that is
used in the Tier 2 program. EPA proposes that the small volume
manufacturer definition be based on the 5,000 vehicle per year level
for the Tier 3 program. For purposes of the Tier 3 rule, the 5,000
limit would be based on a running three-year average of the number of
light-duty vehicles, light-duty trucks, medium-duty passenger vehicles,
and complete heavy-duty trucks below 14,000 lbs GVWR. EPA believes the
5,000 unit cut-off for small volume manufacturers would include all of
the vehicle manufacturers, ICIs, and alternative fuel converters that
currently meet the applicable SBA definition as well as a few
additional companies that have similar concerns to small businesses.
    EPA requests comment on the issue of extending eligibility for the
Tier 3 small volume manufacturer provisions to very small manufacturers
that are owned by large manufacturers but are able to establish that
they are operationally independent. EPA has established such a
provision in the light-duty greenhouse gas (GHG) program.\336\ EPA
requests comment specifically on whether a manufacturer who meets the
criteria for establishing operational independence under 86.1838-01(d)
for eligibility for SVM provisions under the GHG program should be
considered to be operationally independent and similarly eligible for
SVM provisions under the Tier 3 program.
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    \336\ See 77 FR 62793-62794 and 40 CFR 86.1838-01(d)
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F. Compliance Provisions

1. Exhaust Emission Test Procedures
    We are proposing technical amendments to 40 CFR part 1066 as part
of the effort to migrate test requirements from 40 CFR part 86 for
light-duty vehicles and measurement of criteria pollutants. The
proposed procedures in part 1066 reference large portions of part 1065
to align test specifications that apply equally to engine-based and
vehicle-based testing, such as CVS and analyzer specifications,
calibrations, test fuels, calculations, and definitions of many terms.
The proposed part 1066, as amended, also incorporates most of the
detailed part 86 procedures.
    Current testing requirements related to chassis dynamometers rely
on a combination of regulatory provisions, EPA guidance documents, and
extensive learning from industry experience that has led to a good
understanding of best practices for operating a vehicle in the
laboratory to measure emissions. This proposal attempts to capture this
range of material, integrating and organizing these specifications and
procedures to include a complete set of provisions to ensure that
emission measurements are accurate and repeatable. We request comment
on the range of proposed requirements related to these chassis test
procedures.
    Proposed revisions to part 1066, and adjustments from part 86,
include the following:
     Clarification of regulatory requirements.
     Correction of typographical errors.
     Migration of mass-based emission calculations from part 86
to part 1066.
     Introduction of a new NMOG calculation.
     Revision of 40 CFR part 1066, subpart B, to increase the
specificity with which part 1065 references are made as they pertain to
testing equipment, test fluids, test gases, and calibration standards.
     Addition of coastdown procedures for light-duty vehicles.
     Reordering of the test sequence with respect to vehicle
preparation and running a test.
     Specifying part 1065 procedures for PM measurement,
including certain deviations from part 1065 for chassis testing.
     Insertion of detailed test specifications for vehicles
certified under 40 CFR part 86, subpart S.
    We are proposing the use of part 1065 for PM measurement with
slight adjustments to the dilution air temperature, minimum dilution
ratio, and background measurement requirements. By controlling the
parameters that affect PM formation (dilution air temperature, dilution
factor, sample residence time, filter face temperature, and filter face
velocity), the proposed procedures include improvements that will
reduce lab-to-lab and test-to-test variability.
    We are proposing to eliminate separate sampling of Bag 2 of the FTP
test cycle to allow for an increase in sampled PM mass. The proposed
alternative approach is to sample Bags 1 and 2 of the FTP on a single
filter, and sample Bags 2 and 3 of the FTP onto a second filter. This
will generally involve simultaneous sampling of Phase 2 onto two
separate filters. As an additional alternative, manufacturers may run
cold and hot UDDSs without simultaneous sampling of the cold UDDS Phase
2, or to sample Bag 1, Bag 2, and Bag 3 on a single filter.
Manufacturers choosing any of these options must still run a separate
three-bag test for evaporative emission testing. We request comment on
continuing to allow sampling under the traditional FTP methodology of a
bag or filter per test phase (3 phases in total) instead of these
proposed new methods. We also request comment on the appropriate
transition to using the new sampling and calculation methods.
    We are proposing to revise the chassis dynamometer specifications
in part 1066 by removing the maximum roll diameter and by requiring
speed and force measurements at a minimum frequency of 10 hertz (Hz).
Some manufacturers may be interested in testing with nonstandard
dynamometer configurations, such as new flat-track dynamometers or old
twin-roll dynamometers. We may approve the use of these and other
nonstandard dynamometer configurations as alternative procedures under
40 CFR 1065.10(c)(7).
    Part 1066 relies extensively on calculations involving physical
parameters to calculate emission rates and perform various calibrations
and verifications. As reflected in the current version of part 1066,
manufacturers have used a variety of units to perform these
calculations. We would expect that dynamometers and other laboratory
equipment are all capable of operating in SI units even if current
practice in some laboratories is to use other units. Moving toward
standardized units for calculations would allow us to more carefully
and appropriately specify precision values for various measured and
calculated parameters. This would also simplify calculations,
facilitate review of results from different

laboratories, and help with communications regarding any round-robin
testing that might occur. Note that we are not contemplating converting
emission standards to SI units. We request comment on completing the
migration toward SI units in part 1066. In particular, we request
comment on adding vehicle speed specifications in meters per second in
addition to the current specification in miles per hour (or kilometers
per hour for motorcycles). Specifying vehicle speeds to the nearest
0.01 m/s would allow for equivalent vehicle operation relative to
current drive schedules. The cycle validation criteria would be based
on a speed tolerance of 1.0 m/s rather than 2
mph (or rather than the proposed change to a 2.0 mph
tolerance). This is not a direct unit conversion, but is calculated
based on the stated precision and rounding allowance to provide a
comparable degree of variability in vehicle speeds.
    We are proposing to phase in the requirements to use part 1066 test
procedures for certifying all sizes of chassis-tested vehicles. For
this phase-in approach, all aspects of part 1066 related to PM testing
must be met at the start of MY 2017 for vehicles certifying to the PM
standards. All other aspects of part 1066 must be met starting with the
certification of all MY 2022 vehicles.
    As described in Section IV.D, we are proposing new test fuel
specifications for E15 gasoline test fuel in 40 CFR part 1065. The test
fuels specified for natural gas and liquefied petroleum gas, while not
used for very many engine families, are currently following different
specifications under 40 CFR part 86 and part 1065. We request comment
on further revising 40 CFR part 86 to refer to the test fuel
specifications in part 1065 for natural gas and liquefied petroleum
gas.
    The proposal also includes various technical amendments to 40 CFR
part 1065. The proposed technical amendments have no effect on the
stringency of the regulations. These revisions include several minor
changes to clarify regulatory requirements, align with chassis-testing
procedures where appropriate, and correct typographical errors.
2. Reduced Test Burden
    We are proposing to update the regulatory provisions that allow
manufacturers to omit testing for certification, in-use testing, and
selective enforcement audits in certain circumstances. Sections IV.A.3,
IV.B.6, and IV.E.3 describe how this applies for demonstrating that
vehicles meet the Tier 3 p.m. standards. We are also proposing to allow
manufacturers to omit PM measurements for fuel economy and GHG
emissions testing that goes beyond the testing needed for certifying
vehicles to the Tier 3 standards. Requiring such measurement would add
a significant burden with very limited additional assurance that
vehicles adequately control PM. We are also proposing to allow
manufacturers to ask us to omit PM and formaldehyde measurement for
selective enforcement audits. If there is a concern that any type of
vehicle would not meet the Tier 3 p.m. or formaldehyde standards, we
would not approve a manufacturer's request to omit measurement of these
emissions during a selective enforcement audit.
    The regulations currently allow for waived formaldehyde testing for
gasoline- and diesel-fueled vehicles. The Tier 3 NMOG+NOX
emission standards are stringent enough that it is unlikely that
vehicles would comply with the NMOG+NOX standards while
exceeding the formaldehyde standards. We are therefore proposing to
continue this waiver practice, such that manufacturers of Tier 3
vehicles do not need to submit formaldehyde data for certification.
    We are also requesting comment on rearranging the default testing
specification for certifying vehicles to evaporative emission
standards, as described in Section IV.C. This would involve requiring
manufacturers to perform testing with the two-day test sequence, while
making the three-day test sequence optional.
3. Miscellaneous Provisions
    The following additional certification and compliance provisions
are included in the proposed rule:
     The certification practice for assigned deterioration
factors which are available for both small volume manufacturers and
small volume test groups has matured significantly since it was first
adopted. We are proposing to revise Sec.  86.1826 to more carefully
reflect the current practice. For example, the regulations specify that
manufacturers with sales volumes between 300 and 15,000 units per year
should propose their own deterioration factors based on engineering
analysis of emission data from other families. We believe it is best
for EPA to develop a set of assigned deterioration factors that can
apply to all small volume manufacturers and small volume test groups.
     The regulations in 40 CFR part 86 rely on rounding
procedures specified in ASTM E29. This standard is revised
periodically. The newer versions are not likely to change in a way that
affects the regulation, but the updates make it difficult to maintain a
coordinated reference to the current protocol. We are proposing to
address this by specifying that the rounding protocol described in 40
CFR 1065.20(e) applies, unless specified otherwise. We are not
proposing to change all the references in part 86; rather, we are
proposing to define ``round'' in subparts A and S to have the meaning
given in 40 CFR part 1065 so that all new regulatory text would rely on
this new description. The rounding specifications in 40 CFR part 1065
are intended to be identical to those in the latest versions of ASTM
E29 and NIST SP811. For example, this now includes procedures for
nonstandard rounding, such as rounding to the nearest 25 units, or the
nearest 0.05, where that is appropriate.
     Independent Commercial Importers (ICIs) are companies that
import specialized vehicles into the U.S. and are subject to EPA
requirements specified in Part 85, Subpart P. The standards which apply
to the vehicles imported depend, in part, on the model year of the
vehicle being imported. Therefore, vehicles imported by ICIs in the
future could be subject to the proposed Tier 3 standards and the
proposed regulations reflect the application of the Tier 3 standards to
ICIs. Because all existing ICIs are small-volume manufacturers, the
Tier 3 standards would not apply until 2022 at the earliest. In
addition, the certification practices for ICIs have matured
significantly since they were first adopted. EPA is proposing two
changes to update the regulations affecting ICIs. First, the proposed
provisions would require ICIs to use electric dynamometers when running
exhaust emission tests. Electric dynamometers have been required for
many years for vehicle manufacturers and EPA believes it is time to
require such test equipment for ICIs in the future. In cases where an
ICI can demonstrate that they will incur a substantial increase in
compliance costs, the proposed regulations include a provision that
allows EPA to approve requests, on a case-by-case basis, to allow
testing on other types of dynamometers until the ICI is able to comply
with the proposed electric dynamometer requirements. Second, we are
proposing to incorporate into regulation that ICIs be allowed to use a
specific set of reduced testing requirements for up to 300 units each
year that have been modified to a U.S.-certified configuration. This
has been allowed for ICIs since 1999 and was approved under EPA's
authority to establish equivalent alternate test

procedures.\337\ Instead of running a full set of emission tests, the
reduced testing requirements would allow ICIs to run an FTP for exhaust
emissions, a highway fuel economy test, and a shortened one-hour
evaporative emission tests for hot-soak and diurnal emissions that
applied prior to the current enhanced evaporative emission test
procedures. We do not believe the proposed changes should have any
significant cost impacts on ICIs. Most of the ICIs have electric
dynamometers or can upgrade them for a relatively small cost. The
reduced testing burden provisions keep the cost of testing low,
compared to the cost of running a full set of emission tests that
otherwise could be required.
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    \337\ See 40 CFR 86.106-96(a) and Enclosure 2 to EPA Guidance
letter CCD-02-04, February 6, 2002.
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     We are proposing to adopt CARB's onboard diagnostic
requirements for all light-duty vehicles, light-duty trucks, and heavy-
duty vehicles, as described in Section IV.C.5.d. We currently allow for
this as an option, but almost all manufacturers do this already to
avoid certifying multiple systems. Now that we are adopting evaporative
provisions that depend on California's regulatory specifications and we
are making efforts to adopt a single, national regulatory program, we
believe this is an appropriate step. This proposal includes heavy-duty
vehicles above 14,000 lbs GVWR, though these vehicles would not need to
meet the new requirements related to leak testing. These changes would
apply starting in model year 2017 for vehicles subject to Tier 3
standards. The changes apply directly for heavy-duty vehicles above
14,000 lbs GVWR, since all those vehicles are already certified based
on CARB's regulations. In the case of alternative fuel conversions, we
are proposing to continue to apply the requirements of 40 CFR 86.1806-
05.
4. Manufacturer In-Use Verification Testing (IUVP) Requirements
    The fuel on which a vehicle will be operated in-use and tested is
considered an integral part of the vehicle emission control system
design. The Tier 2 program recognized that to achieve the desired
emission reductions, vehicles must operate on the same fuel that the
emission control system was originally designed to encounter in-use and
during testing. In the Tier 2 program, we acknowledged that during the
transition of the in-use fuel from sulfur levels of 300 ppm to the
required 30 ppm average level, vehicles designed for 30 ppm could
encounter in-use sulfur levels well above the level for which their
emission control systems were designed. To address this issue, we
allowed manufacturers, with agency approval, to perform specific
preconditioning test procedures during the IUVP testing to ensure that
potential exposure to high sulfur fuel in-use would not impact the
emission test results. These procedures included specific drive cycles
or maneuvers not regularly encountered during normal in-use operation
that would result in removal of sulfur contamination from the emission
control system.
    Consistent with the Tier 2 program, EPA continues to recognize the
importance of the fuel to the emission control system design,
particularly on Tier 3 vehicles designed to meet the most stringent
emission levels of the program (i.e., Bin 70 and cleaner). Under EPA's
proposal, in-use fuel would transition from an average sulfur level of
30 ppm required by Tier 2 to a new average level of 10 ppm under Tier
3. The proposed sulfur requirements would be average standards. Thus,
even after the transition to the 10 p.m. average sulfur level, vehicles
might still encounter sulfur levels during in-use operation above 10
ppm and as high as the 95 ppm cap, which could adversely impact the
emission control system. Tier 3 vehicles tested by manufacturers in
IUVP that have been exposed to such sulfur levels could experience
sulfur-related impacts, which in turn could cause the vehicle to
temporarily exceed emission standards.
    To address the potential emission impact on Tier 3 vehicles from
exposure to higher sulfur levels, we are proposing some modifications
to the IUVP testing process based in part on what was allowed under the
Tier 2 program. Tier 3 vehicles tested in the IUVP would be tested
initially without allowing any sulfur cleanout procedure, such as a
US06 test run prior to the FTP or Highway Fuel Economy (HFET) tests. If
a vehicle failed the NMOG+NOX standard for the FTP or HFET
cycle during the initial round of testing, manufacturers would be
allowed to perform a sulfur cleanout procedure before repeating the FTP
or HFET. For the sulfur cleanout, manufacturers would be allowed to
perform up to two US06 cycles. The measured US06 cycle and a
preconditioning US06 cycle, if performed as part of the initial
measured tests would serve as the cleanout procedure and therefore no
additional US06 cycles would be allowed. Alternative sulfur cleanout
procedures would require approval by EPA. Following the sulfur cleanout
procedure, the manufacturer would prep and soak the vehicles and then
repeat the FTP and HFET tests. If a manufacturer chose to perform the
sulfur cleanout procedure, it would be required to submit evidence that
the vehicle encountered high sulfur levels in the fuel just prior to
emission testing. This would include an analysis of a fuel sample from
the vehicle fuel system as received from in-use operation just prior to
testing. If the fuel sample indicated that the vehicle was operating on
fuel containing 15 ppm or higher sulfur levels in the recent past, only
the emission results of the tests following the cleanout procedure
would be used for purposes of determining emission compliance and
whether to enter the in-use compliance program (IUCP).
    The proposed rule includes the changes to the IUVP testing
described above for light-duty vehicles and MDPVs. The changes to IUVP
testing are not applicable to heavy-duty vehicles tested in the IUVP
program. Also, as described in Section IV.D, we are proposing to
incorporate leak testing into the IUVP test protocol. We are not
proposing additional changes to the overall IUVP test program.

V. Proposed Fuel Program

    Under today's Tier 3 program, we are proposing reductions in
gasoline sulfur levels nationwide. These standards would help prevent
the significant impairment of the emission control systems expected to
be used in Tier 3 technology, significantly improve the efficiency of
emissions control systems currently in use, and continue prevention of
the substantial adverse effects of sulfur levels on the performance of
vehicle emissions control systems. Section V.A provides an overview of
the fuel program and how we arrived at the proposed gasoline sulfur
standards. Section V.B presents our assessment of the impacts the
proposed fuel program would have on stationary source permitting and
our conclusion that the proposed refinery lead time is adequate.
Section V.C contains our proposed standards for denatured fuel ethanol.
In Section V.D, we introduce and seek comment on possible options for
regulating gasoline-ethanol blends intended for flexible fuel vehicles.
Section V.E presents the proposed program flexibilities including the
averaging, banking, and trading (ABT) program as well as small refiner
and small volume refinery provisions. Section V.F lays out the
compliance provisions for the proposed Tier 3 gasoline program.
Finally, Section V.G presents our statutory authorities for lowering
gasoline sulfur. As a result of these proposals, we have to amend
certain existing provisions in the current Tier 2 requirements at 40
CFR

part 80. We are not reopening Tier 2 and our proposed amendments should
not be construed as a reopener.

A. Proposed Tier 3 Gasoline Sulfur Standards

1. Overview
a. History of Sulfur Control
    Sulfur is naturally occurring in crude oil. Crude oil containing
higher concentrations of sulfur (i.e., greater than 0.5 percent) is
called ``sour'' and crude containing lower sulfur concentrations (e.g.,
West Texas Intermediate) is referred to as ``sweet.'' Regardless of the
concentration, because sulfur is naturally occurring in crude oil, it
is also naturally occurring in gasoline. As discussed in Section
IV.A.6, sulfur impairs the performance of today's vehicle emission
control technologies (i.e., precious metal catalytic converters),
reducing the emission benefits of current and advanced vehicles. As
explained below, in 2000 EPA took action to reduce gasoline sulfur
levels under what is known as the Tier 2 Program \338\ and is proposing
to take further action under the proposed Tier 3 Program.
---------------------------------------------------------------------------

    \338\ 67 FR 6698 (February 10, 2000).
---------------------------------------------------------------------------

    Tier 2 was a major, comprehensive program designed to reduce
emissions from passenger cars, light trucks, and large passenger
vehicles (including sport utility vehicles, minivans, vans, and pick-up
trucks) and the sulfur content of gasoline. Under this program,
automakers were required to manufacture low-emission vehicles when
operated on low-sulfur gasoline, and refiners were required to produce
low-sulfur gasoline nationwide.
    Required reductions in gasoline sulfur began in 2004 with refinery
and importer caps of 300 ppm and a corporate average cap of 120 ppm.
For most refiners and importers, compliance with the final sulfur
standards (30-ppm annual average and 80-ppm per gallon cap) was
required beginning in 2006. Due to extensions provided for some
refineries under the ultra-low sulfur diesel program, final compliance
for all U.S. refineries was January 1, 2011. The Tier 2 gasoline sulfur
program also had an ABT program that allowed companies to generate
credits for implementing the required changes earlier than required and
allowed ongoing flexibility to meet the 30-ppm average sulfur standard.
    At full implementation, the Tier 2 program (treating vehicles and
fuels as a system) required passenger vehicles to be over 77 percent
cleaner and gasoline sulfur to be reduced by up to 90 percent from pre-
program levels.
b. Need for Additional Gasoline Sulfur Control
    We are proposing to lower today's gasoline sulfur standards under
Clean Air Act section 211(c)(1). This is because emission products of
gasoline with current levels of sulfur cause or contribute to air
pollution which may reasonably be anticipated to endanger public health
or welfare and impair to a significant degree the emissions control
device or systems on the vehicles subject to the proposed Tier 3
standards. For more on our legal authority to set gasoline sulfur
standards, refer to Section V.G.
    As explained in Section IV.A.6, robust data from many sources shows
that gasoline sulfur at current levels (i.e., around 30 ppm on average)
continues to degrade vehicle catalytic converter performance during
normal operation. The most significant problem is for NOX.
Today's proposed NMOG+NOX vehicle emission standards, an 80
percent reduction from current Tier 2 standards, would not be possible
without the gasoline sulfur controls we are proposing today. Tier 3
vehicles must achieve essentially zero warmed-up NOX
emissions to comply and maintain this performance for up to 150,000
miles. An increase in emissions of only a few milligrams per mile due
to sulfur could make compliance impossible for some vehicles. The
standards are projected to be especially challenging for larger SUVs
and pick-up trucks.
    Reducing gasoline sulfur would also help reduce emissions of
pollutants that endanger public health and welfare from vehicles
already on the road today. For the Tier 2 rule, we had data that showed
benefits of reducing gasoline sulfur, but little to no data existed for
sulfur levels below 30 ppm that we could use to project continued
emission reductions. Since then, we have tested a wide range of Tier 2
vehicles to better understand the impact that even lower gasoline
sulfur could have on emissions. Our test data showed significant
NOX and VOC reductions when vehicles were tested on ultra-
low sulfur gasoline. As explained in more detail in Section III.B,
lowering average gasoline sulfur from 30 to 10 ppm would result in
approximately 280,000 less tons of NOX and 40,000 less tons
of VOC. The projected in-use emission benefits would occur almost
immediately in 2017 when the Tier 3 gasoline sulfur standards take
effect.
c. Summary of Proposed Tier 3 Fuel Program
    Under today's Tier 3 fuel program, we are proposing that gasoline
and any ethanol-gasoline blend contain no more than 10 ppm sulfur on an
annual average basis beginning January 1, 2017. Similar to the Tier 2
gasoline program, the proposed Tier 3 program would apply to gasoline
in the United States and the U.S. territories of Puerto Rico and the
Virgin Islands, excluding California. The program, when finalized,
would result in gasoline that contains an average of two-thirds less
sulfur than it does today. We are proposing a three-year delay for
small refiners and small volume refineries. Eligible small refining
entities, described in more detail in Section V.E.2, would have until
January 1, 2020 to comply with the new sulfur standards.
    We are proposing an ABT program that would allow refiners to
optimize their investment strategies to enable reduction in capital and
compliance costs. Refiners and importers overcomplying with the 10-ppm
standard beginning January 1, 2017 could generate standard credits that
could be used internally, banked, or traded to other companies. We are
also proposing an early credit program that would allow refiners and
importers to spread out their investments over time to allow for an
orderly transition. Starting January 1, 2014, refiners and importers
taking steps to reduce gasoline sulfur below the current 30-ppm
standard could generate early credits that could be used to postpone
final investments for up to three years. For a more detailed discussion
of the proposed ABT program, refer to Section V.E.1. As a result of the
early credit program and notwithstanding the proposed delay offered to
small refiners and small volume refineries, we anticipate considerable
reductions in gasoline sulfur levels prior to 2017, with final refinery
steps to get to 10 ppm occurring on or before January 1, 2020.
    We are proposing to either maintain the current 80-ppm refinery
gate per-gallon cap and 95-ppm downstream per-gallon cap or lower them
to 50 and 65 ppm, respectively. We also evaluated and are seeking
comment on the potential of lowering these caps to 20 ppm and 25 ppm,
respectively. There are advantages and disadvantages associated with
the various sulfur cap options (explained in more detail in Section
V.A.3), but under all the proposed options, we believe that the
stringency of the 10-ppm annual average

standard would result in reduced gasoline sulfur levels nationwide.
    A summary of the proposed Tier 3 gasoline sulfur standards is
presented below in Table V-1. Domestic refiners and gasoline importers
would be subject to both the 10-ppm annual average sulfur standard and
the refinery gate per-gallon cap, when finalized. Gasoline in the
distribution system (i.e., at terminals, retail stations, etc.) would
be subject to the downstream per-gallon cap. For more information on
how we arrived at the proposed sulfur standards, refer to Sections
V.A.2 and V.A.3.

                                                  Table V-1--Proposed Tier 3 Gasoline Sulfur Standards
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           Cap Option 1                                              Cap Option 2
                                     -------------------------------------------------------------------------------------------------------------------
                                                  Limit                    Effective                    Limit                        Effective
--------------------------------------------------------------------------------------------------------------------------------------------------------
Refinery annual average standard....  10 ppm......................  January 1, 2017 \a\....  10 ppm.....................  January 1, 2017.\a\
Refinery gate per-gallon cap........  80 ppm......................  Already................  50 ppm.....................  January 1, 2020.
Downstream per-gallon cap...........  95 ppm......................  Already................  65 ppm.....................  March 1, 2020.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Effective January 1, 2020 for eligible small refiners and small volume refineries.

d. Refinery Feasibility
    While evaluating the merits of a national gasoline sulfur program
to reduce emissions and enable future vehicle technologies, we also
considered the refining industry's ability to reduce sulfur to 10 ppm
on average by January 1, 2017 and the associated costs (for more on
fuel costs, refer to Section VII.A). Based on information gathered from
numerous stakeholder meetings, discussions with vendor companies that
provide the gasoline desulfurization technologies, as well as the
results from our refinery-by-refinery modeling, we believe it is
technologically feasible at a reasonable cost for refiners to meet the
proposed sulfur standards in the lead time provided. A summary of our
feasibility analysis is presented below. For more on our fuels
feasibility assessment and refinery modeling, refer to Chapters 4 and 5
of the draft RIA.
    Gasoline desulfurization technologies are well known and readily
available. Many technologies were demonstrated under Tier 2 and have
been further demonstrated by current fuel programs in California,
Japan, and Europe. Under California's Phase 3 Reformulated Gasoline
program (CaRFG3), gasoline sulfur is limited to 15 ppm on average with
a 20-ppm per-gallon cap.\339\ California reduced their per-gallon cap
in phases from 60 ppm effective December 31, 2003, to 30 ppm effective
December 31, 2005, to 20 ppm effective December 31, 2011. Actual in-use
gasoline sulfur levels, however, have been largely constrained by the
Predictive Model that California refiners are using to demonstrate
compliance. As a result, gasoline sulfur levels are lower than the
CaRFG3 limits. Based on the Predictive Model, California gasoline
contained approximately 10 ppm sulfur on average in 2010 (9 ppm in the
summer and 11 ppm in the winter).
---------------------------------------------------------------------------

    \339\ California Air Resources Board. (2008, August 29). The
California Reformulated Gasoline Regulations, Title 13, California
Code of Regulations, Sections 2250-2273.5. Retrieved from http://www.arb.ca.gov/fuels/gasoline/082908CaRFG_regs.pdf.
---------------------------------------------------------------------------

    Japan currently has a 10-ppm gasoline sulfur cap that took effect
in January 2008. Europe also has a 10-ppm sulfur cap that has been
adopted by the 30 Member States that comprise the European Union (EU)
and the European Free Trade Association (EFTA) as well as Albania and
Bosnia-Herzegovina.\340\ Beijing, China also recently introduced a 10-
ppm sulfur limit for gasoline.\341\ We note, however, that many oil
refineries outside of the United States operate differently from their
U.S. counterparts. U.S. refiners have invested more heavily in
fluidized catalytic cracker (FCC) units than the rest of the world in
order to maximize gasoline production. Because the FCC unit is
responsible for nearly all the sulfur that ends up in gasoline, many
U.S. refineries face a bigger challenge in achieving 10-ppm gasoline
sulfur levels. Nevertheless, these international fuel programs (along
with California) provide evidence that advanced gasoline
desulfurization technologies have been deployed and are readily
available to comply with the proposed Tier 3 fuel program.
---------------------------------------------------------------------------

    \340\ Hart Energy Consulting. (2011). International Fuel Quality
Center: 2011 Worldwide Fuel Specifications
    \341\ Article from China.org.cn entitled ``Beijing to implement
stricter fuel standards'', May 19, 2012, retrieved from http://www.china.org.cn/environment/2012-05/19/content_25422404.htm
---------------------------------------------------------------------------

    When considering the proposed Tier 3 sulfur standards, refineries
can be grouped into three general categories based on their current
post-Tier 2 refinery configurations: those without an FCC unit, those
hydrotreating the gasoline stream coming from their FCC unit (i.e.,
postreating) \342\, and those hydrotreating their FCC feed (i.e.,
pretreating). Most refineries without FCC units would not need to do
anything to meet the proposed Tier 3 sulfur standards. Refineries
equipped with FCC units that invested in an FCC postreater under Tier 2
would likely just need to revamp (i.e., renovate) their existing unit
for a modest cost. Refineries that only have an FCC pretreater would
meet the Tier 3 sulfur standards by either revamping their existing
pretreaters (perhaps also cutting the heavy portion of FCC naphtha into
the diesel pool) or invest in a grassroots FCC postreater. Our
refinery-by-refinery modeling suggests that 29 refineries would not
need to make any capital changes, 66 would need to revamp their
existing FCC postreaters, and 16 would need to add grassroots
postreaters (we did not model any undercutting of heavy FCC naphtha
into the distillate pool).\343\ Refiners that need to install a new
postreater would have to make the largest desulfurization investments
under Tier 3, typical of many of the refinery investments made under
Tier 2. For more on our estimated sulfur control costs, refer to
Section VII.B.
---------------------------------------------------------------------------

    \342\ Some of them may also have an FCC pretreater.
    \343\ Our in-house refinery modeling considers 111 operational
refineries producing non-California gasoline.
---------------------------------------------------------------------------

    We believe that the choice of technology for each refinery is
fairly insensitive to capital cost assumptions. Revamping an existing
FCC postreater will almost always be the preferred compliance path if
it is available. The majority of refineries only have an existing FCC
postreater, so revamping it will be the preferred choice, given the
much higher capital costs associated with adding grassroots FCC pre or
postreaters. The 16 refineries we project would add grassroots
postreaters do not have existing postreaters that could be revamped. As
a result, their choices are limited to revamping their existing
pretreater or installing a grassroots postreater. We believe based on
conversations with industry technology vendors and engineering firms
that

installing a grassroots postreater would be more likely for these
refineries, because revamping their pretreater would still incur a
significant capital cost and would reduce compliance flexibility. Thus,
in the refinery-by-refinery analysis performed by EPA for this
proposal, higher capital costs (either directly or thru a higher ROI)
would be unlikely to alter the selection of pretreater versus
postreater control technology. Higher capital costs would likely impact
both technology options proportionally with no overall effect.
    We have built in a number of flexibilities that will reduce the
compliance burden for refiners. In particular, coupling the proposed
10-ppm annual average sulfur standard with refinery gate and downstream
per-gallon caps should continue to allow for batch-to-batch
variability, refinery upsets, and turnarounds while still maintaining
the overall air quality benefits of the program. For more information
on the applicable per-gallon sulfur caps, refer to Section V.A.3.
    We are also proposing an ABT program that would allow refiners to
spread out their investments over time and achieve compliance in the
most cost-effective manner. If some refineries either comply with the
10-ppm standard earlier than required, or reduce sulfur partway toward
10 ppm early, this would allow other refineries to delay compliance for
a finite period through the use of early credits. The ABT program would
also allow for ongoing company averaging. This would allow some
refineries to stay slightly above the standard at the expense of other
refineries over complying, resulting in the most cost-effective
mechanism for meeting the 10-ppm annual average standard. For more
information on the proposed ABT program, refer to Section V.E.1.
Finally, our Tier 3 gasoline sulfur program, when final, would allow
three years of additional lead time for small refiners and small volume
refineries (i.e., refineries processing less than or equal to 75,000
net barrels per day of crude oil). As a group, we believe that these
refineries are disproportionally impacted when it comes to their cost
of compliance and ability to rationalize investment costs in today's
gasoline market. Giving these refineries additional lead time would
allow them more time to invest in desulfurization technology, take
advantage of advancements in technology, develop confidence in a Tier 3
credit market as a means of compliance, and avoid competition for
capital, engineering, and construction resources with the larger
refineries. For more on the proposed provisions for small refiners and
small volume refineries, refer to Section V.E.2.
    The proposed Tier 3 rulemaking should not adversely affect the
supply of gasoline in the U.S. This judgment is based on a review of
both gasoline and diesel fuel supply when the Tier 2 gasoline sulfur
and ultra-low sulfur highway and nonroad diesel rules were phasing in
between 2003 and 2011. At the end of this time period, the U.S.
gasoline and diesel fuel markets were increasingly being supplied by
U.S. refiners, instead of by imports, compared to the beginning of this
time period. Most striking is that the more stringent ultra-low sulfur
diesel fuel standards showed the largest shift as U.S. refiners not
only began to supply more of the U.S. diesel fuel market, but became
net exporters of diesel fuel. For more on our fuel supply assessment,
refer to Section 5.3 of the draft RIA.
2. Proposed Annual Average Sulfur Standard
    In the subsections that follow, we lay out our rationale for
proposing a 10-ppm average standard, our assessment of how the proposed
ABT program would help with compliance, and our conclusion that the
proposed lead time is adequate. In the following section, we explain
our rationale behind the proposed sulfur caps and seek comment on
potential alternatives.
a. Appropriateness of Proposed 10-ppm Sulfur Standard
    As explained in Section IV.A.6, sulfur in fuel oxidizes in the
exhaust and coats the sites where chemical reactions can take place on
the precious metal catalysts used in vehicles to reduce emissions of
VOC, NOX, PM, CO, and toxics. Accordingly, any sulfur in
gasoline causes vehicle emissions to increase. Sulfur can be burned off
the catalyst during high-temperature, rich operation of the vehicle
(i.e., aggressive driving conditions), but as long as there is any
sulfur in the fuel, exhaust emissions will increase. Because any amount
of sulfur in the fuel can have this effect, the lower the sulfur the
better.
    Refiners experience the same phenomenon with precious metal
catalysts used in the reformer and isomerization units at their
refineries.\344\ To protect the precious metal catalysts in these
units, refiners reduce the sulfur in the feed to these units to 1 ppm
or below. Thus, it is technically possible for refiners to reduce their
gasoline sulfur levels to virtually zero. While refiners did not have
reason to reduce the sulfur in FCC gasoline until Tier 2 required such
reductions, some refiners have achieved reductions in this stream at
some of their refineries for other reasons such as (1) Protecting the
FCC catalyst from the contaminants in the gas oil feed, (2) reducing
stack emissions from the regenerator of the FCC unit, and most
importantly (3) increasing gasoline yields from the FCC unit. For most
refineries, FCC gasoline accounts for about one-third of gasoline and
before Tier 2 was the source of over 95 percent of the sulfur in
gasoline. Under Tier 2, most refiners significantly desulfurized FCC
gasoline to around 70 to 80 ppm, yet FCC gasoline continues to
contribute the majority of sulfur in gasoline today.
---------------------------------------------------------------------------

    \344\ Together, the streams from the reformer and isomerization
units account for approximately one-third of gasoline.
---------------------------------------------------------------------------

    While further reducing sulfur in gasoline will continue to reduce
vehicle emissions, our emissions analysis shows that a 10-ppm annual
average is sufficient to enable vehicles to reach the proposed Tier 3
standards. Moreover, for the following reasons, reducing sulfur further
below 10 ppm becomes increasingly difficult and costly. First, FCC
naphtha is very rich in high-octane olefins. As the severity of
desulfurization increases, more olefins are saturated, further
sacrificing the octane value of this stream and further increasing
hydrogen consumption. Making up for this lost octane represents a
significant portion of the sulfur control costs. Second, as
desulfurization severity increases, there is an increase in the amount
of sulfur removed (in the form of hydrogen sulfide) which recombines
with the olefins in the FCC naphtha, thus offsetting the principal
desulfurization reactions. There are means to deal with the
recombination reactions, but they result in even greater capital
investments. Third, while FCC gasoline contributes the majority of
sulfur to the finished gasoline, as the sulfur level drops below 10
ppm, the sulfur level of the various other gasoline streams within the
refinery also become important. Any necessary treatment of these
additional streams increases both capital and operating costs.
    U.S. refineries are currently in different positions, both
technically and financially. In general, they are configured to handle
the different crude oils they process and turn it into a widely varying
product slate to match available markets. Those processing heavier,
sour crudes would have a more challenging time reducing gasoline sulfur
under the proposed Tier 3 program. As explained earlier, refineries
have different sulfur levels in their non-

FCC streams based on their feedstocks and configurations. Those with
higher sulfur levels in other refinery streams would have a more
difficult time desulfurizing gasoline. Perhaps most important, U.S.
refineries vary greatly in size (atmospheric crude capacities range
from less than 5,000 to more than 500,000 barrels per day) and thus
have different economies of scale for adding capital to their
refineries. As such, it can be less costly per gallon for some larger
refineries to get down to 10 ppm than for smaller refineries, as
discussed in Chapter 5 of the draft RIA. As a result, under a 10-ppm
average standard, the flexibility afforded by the ABT program helps
those refineries with very high costs. They have the option of staying
above 10 ppm if they can acquire credits from other refineries that
were able to lower their sulfur level below 10 ppm. However, if the
gasoline sulfur standard were to be 5 ppm, this would essentially end
the ability of refiners to average sulfur reductions across their
refineries. There simply would not be enough opportunity to generate
credits below 5 ppm. As discussed in Chapter 5 of the draft RIA, to
estimate the costs for a 10-ppm annual average standard where some
refineries stay above 10 ppm, we also estimated the costs for
refineries to get down to 5 ppm. To do so, we estimated that sulfur
control costs would increase by at least 50 percent compared to the
proposed 10-ppm standard, which is over two times more costly per ppm-
gallon of gasoline sulfur reduced. This 5-ppm cost assessment is
reasonable for those refineries that would likely generate credits
under a 10-ppm average standard as these refineries are most likely in
the best position for achieving such low sulfur levels. However, were
we to actually assess the costs of a 5-ppm standard, at least some of
these refineries would likely have additional costs for controlling the
sulfur in other gasoline blendstocks, and we would likely apply a
higher overdesign factor to account for industry-wide compliance at 5
ppm. More detailed refinery information may be needed for such an
analysis but, for the more challenged refineries, a 5-ppm standard
could potentially be cost prohibitive. A 5-ppm standard would also
introduce further costs to address the contribution to gasoline sulfur
from gasoline additives, transmix, ethanol denaturants, and
contamination in the distribution system. Therefore, a 10-ppm annual
average standard appears to be the point which properly balances
feasibility with costs. Also, for these reasons, EPA believes that a
viable ABT program is important to the success of the proposed Tier 3
fuels program (explained in more detail in Section V.A.2.b).
    Finally, as discussed in Section IV.A.6, reducing sulfur below 10
ppm would further reduce vehicle emissions and allow the proposed Tier
3 vehicle standards to be achieved more easily. However, we believe
that a 10-ppm average standard will be sufficient to allow vehicles to
meet the proposed Tier 3 standards. The level of the Tier 3 standards
was considered in light of a 10-ppm average sulfur level for gasoline.
If we were to consider lowering sulfur further, we would then also have
to consider reducing the vehicle standards further. Given the
challenges associated with sulfur reductions below 10 ppm as discussed
above, we do not believe this would be appropriate.
b. How Would the Proposed ABT Program Assist With Compliance?
    As described more fully in Section V.E.1, we are proposing an ABT
program that would reduce the average compliance burden for gasoline
producers and importers. This program would permit the generation of
credits by refineries that reduce their annual average sulfur level
below 10 ppm, and transfer of these credits to other refineries to
reduce or eliminate their need to make capital investments to meet the
10-ppm standard. The ABT program would thus provide refiners with
multiple approaches to compliance, and each could choose the approach
that minimizes their costs.
    We modeled an ABT program to estimate how it would affect
compliance. As described in more detail in Section VII.B.4, our
modeling determined the lowest cost approach on a refinery-by-refinery
basis under two scenarios: an idealized scenario in which every
refinery has the opportunity to make credit transfers with every other
refinery in the nation, and a more limited scenario in which credit
transfers would only occur within companies that own more than one
refinery. Today a significant fraction of Tier 2 sulfur credits are
transferred within companies, but there is still a considerable amount
of inter-company trading occurring.\345\ Thus, assuming no trading
between companies is a conservative assumption and the real impact is
likely to be somewhere in between the two scenarios. Table V-2
describes how compliance would be affected under these two scenarios.
---------------------------------------------------------------------------

    \345\ Based on Tier 2 sulfur compliance data, of the 26
companies that obtained sulfur credits in 2010, eight obtained
credits only from their own company, and another five obtained
credits both from their own company and from other companies. The
remainder obtained credits only from other companies.

                           Table V-2--Impacts of Nationwide ABT Program on Compliance
----------------------------------------------------------------------------------------------------------------
                                                                  ABT with nationwide     ABT with intra-company
                                                                    credit transfers         credit transfers
----------------------------------------------------------------------------------------------------------------
Number of refineries that generate credits....................                       46                       18
Number of refineries that consume credits.....................                       25                        8
Number of refineries that neither generate nor consume credits                       40                       85
                                                               -------------------------------------------------
    Total modeled refineries..................................                      111                      111
----------------------------------------------------------------------------------------------------------------

    Based on our ABT modeling, we believe that a significant number of
refineries would take advantage of the opportunity to generate or use
credits, thus lowering their compliance burden under the proposed 10-
ppm annual average standard. For a more complete discussion of our
analysis of the proposed ABT program, refer to Chapter 5 of the draft
RIA.
c. Adequacy of Proposed Refinery Lead Time
    Given the complexity of gasoline refining, numerous planning and
action steps would be required for refiners to complete the refinery
changes needed to comply with the proposed Tier 3 sulfur standards. The
steps required to implement these changes include: the completion of
scoping studies, financing, process design for new or revamped refinery
units or subunits, permitting, detailed engineering based

upon the process design, field construction of the gasoline sulfur
reduction facilities, and start-up and shakedown of the newly installed
desulfurization equipment.
    We conducted a thorough lead time analysis in which we sequenced
the estimated time to complete scoping studies, process design,
permitting, detailed engineering, field construction, and start-up and
shakedown in advance of production based upon the methodology used in
our recent gasoline and diesel rules.
    For the proposed Tier 3 gasoline sulfur program, we estimated
refinery lead times step-by-step for the construction of new grassroots
FCC postreaters and the revamp of existing pre and postreaters. For
each refinery project type, we estimated lead times for scoping
studies, process design, permitting, detailed engineering, field
construction, and start-up and shakedown. Estimated required lead times
for scoping studies are six months. Process design ranged from six
months for desulfurization equipment revamping to nine months for a
grassroots postreater. It is during the process of performing their
scoping studies and process design analysis that refiners would
complete their permit applications.
    Based on discussions with refiners, a review of the permitting
experience for Tier 2 and our current analysis, we estimated that
permitting for desulfurization equipment revamping and the construction
of a grassroots postreater would take 9 months. However, we estimated
the overall lead-times for Tier-3-related revamps to be considerably
shorter, as described below. The estimates for permitting time are
consistent with those of EPA's Office of Air Quality Planning and
Standards (OAQPS) and our regional offices, both of which have engaged
in extensive dialog with potentially affected parties. A discussion of
the permitting implications of Tier 3 is contained in Section V.B of
the preamble. Detailed engineering efforts were estimated to require
six months for desulfurization equipment revamping and nine months for
grassroots postreaters. Field construction was estimated to require six
months for revamped pre-and postreaters and 12 months for grassroots
postreaters. Start-up and shakedown processes were estimated to require
six months for revamped FCC treaters and 9 months for grassroots
postreaters. There is some degree of overlap among each of these steps
as shown in Table V-3.
    To allow refiners to complete all these different steps and comply
with the 10 ppm average gasoline sulfur standard, assuming the Tier 3
proposal were to be finalized by the end of 2013, we would be providing
three years of lead time. In addition to the three years of lead time,
the proposed rulemaking also provides additional flexibility provided
by the ABT program, small refinery delays, and hardship provisions. To
support this timeline, we conducted several analyses of the expected
refinery lead time requirements associated with the proposed Tier 3
standards and found that refinery operators would have more than
adequate time to implement the required refinery charges. A
justification for proposed timeline appears below.
    Complying with Tier 3 is expected to involve some grassroots FCC
postreaters, but mostly we believe that refiners will revamp existing
FCC postreaters. Revamping of existing FCC postreaters can be
accomplished in approximately 2 years, or less (See Table V-3).
Grassroots FCC postreaters are expected to require on average about
three-years to install and start-up (See Table V-3). In comparision to
FCC pretreaters, hydrocrackers and distillate hydrotreaters, FCC
postreaters are much less costly, low pressure units that take less
time to scope out, require shorter lead times for ordering the
equipment, and less time to install. Furthermore, the grassroots FCC
postreaters to be installed for Tier 3 are expected to be in a moderate
to light desulfurization service because the refineries they will be
installed in will already be complying with Tier 2 using an FCC
pretreater. FCC naphtha from a refinery with an FCC pretreater is
expected to only contain about 100 ppm sulfur. To comply with Tier 3,
refiners installing these grassroots FCC postreaters would only need to
desulfurize the FCC naphtha down to 25 ppm (about a 75% reduction). In
comparison, a single-stage FCC postreaters would have to desulfurize
FCC naphtha from as high as 2400 ppm sulfur down to 25 ppm, a 99%
sulfur reduction. The more moderate desulfurization service of the
grassroots FCC postreaters needed to comply with Tier 3 would be
expected to streamline the scoping and design work.

[GRAPHIC] [TIFF OMITTED] TP21MY13.002

    It is useful to compare the proposed lead time for Tier 3 to what
was provided for Tier 2. In the case of the Tier 2 standard, we
provided a three-year lead time along with an ABT program and other
flexibilities to ease compliance. Refiners, though, commented that the
three year timeline that we provided was not enough time. For the Tier
2 analysis, we assumed that refiners would solely install low-pressure
FCC postreaters, which we believe could be scoped out, designed,
installed and started up within a 3 year time period. However, many
refiners complied with Tier 2 by installing high-pressure FCC
pretreaters which require long lead times for the procurement of the
required equipment. Furthermore, those refiners that did not install
high-pressure FCC pretreaters instead installed grassroots FCC
postreaters, many of which were designed for severe desulfurization
service. An additional difference between Tier 3 and Tier 2 is that for
Tier 3 we expect the installation of only 16 grassroots units, along
with many revamps, but for Tier 2 virtually all refiners installed both
grassroots FCC pretreaters and postreaters. The demands on the
desulfurization vendors for scoping studies, and on the E & C industry
for design and construction, and on the refiners to train their
operations staff and start up the new units, was a lot greater for Tier
2 than what we would expect for Tier 3. The total estimated investment
cost for Tier 2 versus Tier 3 also highlights the difference in
investment demands.
    The total investment for Tier-2 desulfurization processing units
was estimated to be about $6.1 billion, while the total investment for
Tier-3 desulfurization processing units is estimated to be about $2.1
billion. This simple comparison helps to illustrate that the proposed
Tier 3 would be easier for refineries to obtain necessary permits,
secure engineering and construction (E&C) resources, install new
desulfurization equipment and make all necessary retrofits to meet the
proposed sulfur standards.
    We assessed the permitting situation in more detail working in
conjunction with the Office of Air Quality, Planning and Standards
(OAQPS). Since the permitting process has little impact on the overall
cost of compliance with Tier 3, it is an issue primarily in terms of
its potential impact on the time needed to complete the necessary
refinery modifications. On a refinery-by-refinery basis, we provided
OAQPS estimates of the additional heating demands for the new and
revamped units per the desulfurization vendor submissions. OAQPS was
able to project which refineries would likely trigger NOX,
particulate matter and greenhouse gas emission permitting limits, which
would likely lengthen the permitting process as refiners would need to
offset the projected emission increases. As it turns out, only 2 of the
16 refineries which are projected to install grassroots units were
projected to exceed particular permitting limits, and these solely did
so based on the most conservative assumption that each would produce
all the additional hydrogen on site using hydrogen plants (as opposed
to using existing reforming capacity) and produce the electricity on
site, to satisfy the needs of the new desulfurization equipment. When
we provided a second heat demand estimate to OAQPS which assumes that
refiners purchase their hydrogen and electricity from third parties,
none of the refineries which we projected would install grassroots
units was projected to have emission increases which would require
offsets. Thus, many of the grassroots units that we project would be
installed may end up with a streamlined permitting process. We seek
comment on our estimates of the number of refineries that may trigger
the need for new permits and the length of time necessary to obtain the
various

types of permits that may be required once the refiner applies for
them.
    The various flexibilities that the proposed Tier 3 rule provides to
refiners provide refiners additional time for complying. These
flexibilities include the ABT program, the small refiner delay
provisions and the hardship provisions. The ABT program allows a
refiner, either within its own company or by purchasing credits on the
open market, to delay higher investment cost investments, such as the
investments in grassroots FCC postreaters, which would provide
additional lead time for installing these units. This would occur if
refiners would reduce the sulfur levels of their gasoline through
operational changes or revamps of their existing FCC pretreaters and
postreaters when the ABT Program begins in 2014. Potentially every
refinery with either an FCC pretreater or an FCC postreater may be
capable of generating early credits. Furthermore, we project that 66
refineries would revamp their existing FCC postreaters to comply with
Tier 3. Since revamps can be completed within two years or less, these
refiners could potentially begin generating early credits during 2016,
or before if refiners begin each of these revamps in early 2014. During
the period between 2014 and 2017, these refineries which reduce their
gasoline sulfur levels below that required by Tier 2 would generate
credits. Refineries with higher cost capital investments, such as the
grassroots FCC postreaters, could then delay making those investments
through the purchase of credits. We estimate that sufficient credits
could be genereated early to allow many of these refineries to delay
compliance until as late as 2020. The quantitative early credit
analysis that we conducted showed that if refiners with an existing
pretreater or postreater would generate early credits by lowering their
gasoline sulfur down to 20 ppm starting in 2014 and if revamps were
started up in 2016, one year before the program start date, that almost
6 times more credits would be available to offset the early credit
demand by the refiners installing grassroots postreater units, assuming
that they start up those units in 2018. Even if all grassroots
postreaters were assumed to not start up until 2020, there would be
almost 4 times more early credits available to those refiners
installing grassroots postreaters assuming that the same early credit
generation scenario would occur.
    Additional flexibility is also provided by the small refineries
provisions which delays compliance by the refineries that refiner less
than a net of 75,000 barrels of crude oil per day until 2020. Three of
the 16 FCC postreater grassroots units that we project will be
installed would be by small refineries. However, small refineries could
also decide to comply early and generate credits starting as early as
2014.
    As in previous fuel programs, we are proposing hardship provisions
to accommodate a refiner's inability to comply with the proposed
standard at the start of the Tier 3 program, and to deal with
unforeseen circumstances that may occur at any point during the
program. These provisions would be available to all refiners, small and
non-small, though relief would be granted on a case-by-case basis
following a showing of certain requirements; primarily that compliance
through the use of credits was not feasible. We are proposing that any
hardship waiver would not be a total waiver of compliance; rather, a
hardship waiver would be short-term relief that would allow a refiner
facing a hardship situation to, for example, receive additional time to
comply. This hardship provision would allow a refiner to seek a delay
in the case that there was insufficient time to comply.
    Finally, we believe that in reality, less leadtime than shown in
Table V-3 would actually be necessary. We held discussions with many
refiners during 2011, and so they have been well aware of Tier 3 and
are familiar with the likely requirements. During our subsequent
discussions with technology vendors and engineering firms, they
explained to us that many refiners have already initiated, and by now,
likely completed their scoping studies. Thus, actual time needed for
designing, installing and starting of new desulfurization equipment for
Tier 3 times would be even less than what we projected because many
refineries may have already completed required scoping studies in
anticipation of the Tier-3 standards. Moreover, lead times for those
refineries that have yet to start the scoping process can also be
expected to decrease, since fewer refineries will be competing for the
services of the desulfurization vendors. We request comment on the
amount of lead time that we are providing refiners to scope, design,
permit, construct and start-up a grassroots desulfurization unit,
considering all the proposed flexibilities which allow refiners to
stagger their capital investments and ease compliance.
    As in prior rules, we also evaluated the capability of E&C
industries to design and build gasoline hydrotreaters as well as
performing routine maintenance. Two areas where it is important to
consider the impact of the fuel proposed sulfur standards are: (1)
Refiners' ability to procure design and construction services and (2)
refiners' ability to obtain the capital necessary for the construction
of new equipment required to meet the new gasoline quality
specification. We evaluated the requirement for engineering design and
construction personnel in a manner consistent with the Tier 2 analysis,
particularly for three types of workers needed to implement the
refinery changes: front-end designers, detailed designers, and
construction workers. We developed estimates of the maximum number of
each of these types of workers needed throughout the design and
construction process and compared those figures to the number of
personnel currently employed in these areas.
    The number of job hours necessary to design and build individual
pieces of refinery equipment and the job hours per piece of equipment
were taken from Moncrief and Ragsdale.\346\ Their paper summarizes
analyses performed in support of a National Petroleum Council study of
gasoline desulfurization, as well as other potential fuel quality
changes. The design and construction factors for desulfurization
equipment are summarized in Table V-4.
---------------------------------------------------------------------------

    \346\ Moncrief, Philip & Ragsdale, Ralph. (2000). Can the U.S.
E&C Industry Meet the EPA's Low Sulfur Timetable? Paper presented at
NPRA Annual Meeting, March 26-28, 2000. Paper No. AM-00-57.

               Table V-4--Design and Construction Factors
------------------------------------------------------------------------

------------------------------------------------------------------------
Gasoline Refiners:
  Number of New Pieces of Equipment per Refinery...............       60
  Number of Revamped Pieces of Equipment per Refinery..........       15
Job Hours Per Piece of New Equipment: \a\
  Front End Design.............................................      300
  Detailed Design..............................................    1,200
  Direct and Indirect Construction.............................    9,150
------------------------------------------------------------------------
\a\ Revamped equipment estimated to require half as many hours per piece
  of equipment.

    Refinery projects will differ in complexity and scope. Even if all
refiners desired to complete their project by the same date, their
projects would inevitably begin over a range of months. Thus, two
projects scheduled to start up at exactly the same time are not likely
to proceed through each step of the design and construction process at
the same time. Second, the design and construction industries will
likely provide refiners with economic incentives to avoid temporary
peaks in the demand for personnel.
    Applying the above factors, we projected the maximum number of
personnel needed in any given month

for each type of job. The results are shown in Table V-5. In addition
to total personnel required, the percentage of the U.S. workforce in
these areas is also shown, assuming that half of all projects occur in
the Gulf Coast

                                 Table V-5--Maximum Monthly Demand for Personnel
----------------------------------------------------------------------------------------------------------------
                                                                                Detailed
                                                            Front-end design     engineering      Construction
----------------------------------------------------------------------------------------------------------------
Tier 3 Gasoline Sulfur Program:
Number of Workers.........................................               202               809             6,012
Percentage of Current Workforce \a\.......................               11%                9%                4%
----------------------------------------------------------------------------------------------------------------
\a\ Based on current employment in the U.S. Gulf Coast assuming half of all projects occur in the Gulf Coast.

    To meet the proposed Tier 3 sulfur standards, refiners are expected
to invest $2.2 billion between 2014 and 2019 and utilize approximately
1,000 front-end design and engineering jobs and 6,000 construction
jobs. The number of estimated jobs required is small relative to
overall number available in the U.S. job market. As such, we believe
that three years, plus the additional flexibilities provided, is
adequate lead time for refineries to obtain necessary permits, secure
E&C resources, install new desulfurization equipment, and make all
necessary retrofits to meet the proposed sulfur standards. For an in
depth assessment of stationary source implications, refer to Section
V.B. For more on our E&C assessment, refer to Section 4.5 of the draft
RIA.
3. Per-Gallon Sulfur Caps
    In much of Europe and Japan, the gasoline sulfur level is capped at
10 ppm. We, however, are not considering a 10-ppm cap for the U.S. The
U.S. gasoline distribution system poses contamination challenges that
make it difficult to set and enforce such a tight downstream per-gallon
sulfur standard. In Europe, Japan, and California, finished petroleum
products are generally shipped short distances directly from the
refinery to the terminal with limited susceptibility to contamination.
The U.S. has the longest and most complex gasoline distribution system
in the world, making it harder to control sulfur contamination than in
other countries. Petroleum products are shipped long distances through
multi-product pipelines. Further, gasoline goes through the same
pipelines and terminals back-to-back with jet fuel (containing up to
3,000 ppm sulfur). Products are often in the custody of a number of
separate companies before reaching the terminal. This system is very
effective at delivering petroleum products to the bulk of the country,
but pipeline transport inevitably introduces the potential for sulfur
contamination of the gasoline being shipped through pipelines.
Additionally, gasoline additives needed to provide critical fuel
performance characteristics (e.g., corrosion control, demulsifiers)
also contain varying levels of sulfur which contribute to the overall
sulfur content of gasoline. Therefore, we are proposing a 10-ppm
refinery average sulfur standard (discussed in Section V.A.2) with
higher per gallon caps at both the refinery gate and at all points
downstream, which is similar to what currently exists under the Tier 2
program. We believe this is the most prudent approach for lowering in-
use sulfur while maintaining flexibility considering cost and other
factors. These per-gallon caps are important in the context of an
average sulfur standard to provide an upper limit on the sulfur
concentration that vehicles must be designed to tolerate. Since there
are many opportunities for sulfur to be introduced into gasoline
downstream of the refinery, these caps also limit downstream sulfur
contamination and enable the enforcement of the gasoline sulfur
standard in-use.
    We are proposing two options for the per-gallon sulfur caps. Under
the first option, we are proposing to maintain both the current 80-ppm
refinery gate sulfur cap and 95-ppm downstream sulfur cap.\347\ Because
this represents no change from current requirements, we believe there
would be no additional costs to refiners and downstream parties
associated with satisfying these caps on gasoline sulfur content beyond
those that were already incurred under the Tier 2 program. Compliance
for downstream parties could be even easier given that the average
refinery gate level would be lower. However, the high level of the caps
means that vehicles still have to be designed to operate on high sulfur
fuel, and there will be less attention paid to limiting contamination
downstream of the refinery gate.
---------------------------------------------------------------------------

    \347\ This approach is reflected in the draft regulatory text.
---------------------------------------------------------------------------

    Under the second approach, we are proposing that the refinery gate
cap would be reduced to 50 ppm and the downstream cap would be reduced
to 65 ppm, in other words, a 30-ppm reduction in the caps to go along
with a 20-ppm drop in the average standard. We are proposing that the
50-ppm refinery gate cap would take effect on January 1, 2020 when the
small refiner, small volume refinery, and early credit use provisions
would expire. The reason for the delay in the more stringent cap until
2020 is to avoid forcing additional refinery investments during the
early credit usage period. A more stringent per-gallon cap would also
be very difficult to enforce prior to the small refiner and small
volume refinery provisions taking effect. Until that time, the current
80-ppm refinery gate sulfur cap would apply. Additional time beyond
when the 50-ppm refinery gate sulfur cap is implemented would be
allowed for gasoline produced to an 80-ppm sulfur cap to clear the
distribution system before the 65-ppm downstream sulfur cap would
replace the current 95-ppm downstream sulfur cap. Beginning February 1,
2020, a 65-ppm downstream sulfur cap would apply at all locations
downstream of the refinery and importer gate with the exception of
retail and wholesale-purchaser-consumer facilities. Beginning March 1,
2020, a 65-ppm downstream sulfur cap would apply at all locations in
the gasoline distribution system downstream of the refinery and
importer gate. We note that the additional time for parties to comply
with a more stringent downstream sulfur cap mirrors the schedule for
compliance under the Tier 2 program.
    As discussed previously in Sections III and IV of today's preamble,
the vehicle emissions benefits associated with today's proposal are
driven by the proposed reduction in the average sulfur content of
gasoline from 30 to 10 ppm. However, vehicle manufacturers have
expressed concerns about the potential impacts on emissions performance
if individual vehicles are exposed to gasoline above the proposed 10-
ppm

refinery average.\348\ As discussed in Section V.A.2.b, our analysis of
the potential response to the proposed ABT provisions assessed three
options for refineries: remaining at their current sulfur levels and
using credits, reducing sulfur levels to 10 ppm and neither generating
or using credits, or reducing sulfur levels to 5 ppm and generating
credits. We did not have available information that would enable us to
assess refineries that might stay above 10 ppm and reduce their sulfur
levels part way (e.g., reduce sulfur from 50 ppm today to 20 ppm under
Tier 3). Nevertheless, we anticipate that in most cases refineries
would respond by making operational changes and/or minor investments in
order to reduce their credit burden and reduce their compliance costs.
This anticipation, along with the fact that a 10-ppm average standard
by definition limits the amount of gasoline that can remain at higher
sulfur levels, means that we anticipate most credit-using refineries
would still average less than 20 ppm in their physical gasoline
production, and either all or virtually all gasoline would be expected
to average at or below 30 ppm. Therefore, we believe that a 50-ppm per-
gallon cap at the refinery gate would not impose any additional cost or
burden beyond the current 80-ppm per-gallon cap. Our discussions with
refiners indicate that a 50-ppm sulfur cap would provide refiners with
sufficient flexibility to produce gasoline during temporary upsets and
turnarounds through the use of credits without necessitating the
installation of additional desulfurization equipment.\349\ However, it
would provide some additional assurance of in-use gasoline quality and
help to address vehicle manufacturer concerns.
---------------------------------------------------------------------------

    \348\ Alliance of Automobile Manufacturers (2011, October 6).
Letter to EPA Administrator, Lisa Jackson.
    \349\ Refer to Section <IP_ADDRESS> of the draft RIA for a more
detailed discussion of the impacts of lowering the refinery gate
sulfur cap.
---------------------------------------------------------------------------

    We also believe that implementing a 65-ppm downstream sulfur cap
would provide essentially the same flexibilities to downstream parties
as the existing sulfur caps. We believe that maintaining a 15-ppm
differential between the proposed refinery gate sulfur cap of 50 ppm
and the proposed 65-ppm downstream sulfur cap would provide pipeline
operators, transmix processors, and gasoline additive users the same
flexibility as provided under the current 80/95 ppm sulfur caps.
    Pipeline operators are currently allowed to blend limited volumes
of transmix into gasoline in their systems provided that the resulting
gasoline meets all fuel quality specifications and the endpoint of the
blended gasoline does not exceed 437 [deg]F.\350\ This enables pipeline
operators to avoid the installation of additional transmix storage and
loading equipment at a number of remote locations to facilitate
shipping small volumes of transmix to processing facilities by truck.
We believe that a 65-ppm sulfur cap would provide sufficient
flexibility to allow pipeline operators to continue this practice.
---------------------------------------------------------------------------

    \350\ The requirements for transmix blenders are contained in 40
CFR 80.84(d). 437 [deg]F is the maximum endpoint allowed for
gasoline in ASTM D4814.
---------------------------------------------------------------------------

    Currently transmix processors must produce gasoline sufficiently
below the 95-ppm downstream sulfur cap to accommodate any downstream
sulfur increases from the use of gasoline additives and contamination
from further distribution. The sulfur content of the gasoline produced
by transmix processors is determined by the sulfur content of the
transmix they receive, which in turn is primarily a function of the
sulfur content of gasoline and jet fuel components in the
transmix.\351\ Transmix processors do not handle sufficient volumes to
support the installation of currently available desulfurization
units.\352\ Data provided by the largest operator of transmix
processing facilities indicates that relatively few batches of the
gasoline they currently produce approach 80 ppm sulfur. Most batches
are approximately 10 ppm above the current 30-ppm refinery sulfur
average. Therefore, we believe that under a 10-ppm refinery average
standard and 50-ppm refinery sulfur cap, transmix processors would be
able to produce gasoline sufficiently under the proposed 65-ppm
downstream sulfur cap to accommodate the additional sulfur contribution
from the use of additives and contamination during further
distribution. Since the 65-ppm downstream cap would not take effect
until 2020, while the 10-ppm average standard would take effect in
2017, we would have three years of experience with which to verify this
and take corrective action if necessary.
---------------------------------------------------------------------------

    \351\ Transmix is a by-product of the multi-product pipeline
distribution system. 40 CFR 80.84(a) defines transmix pipeline
interface that does not meet the specifications for a fuel that can
be used or sold, and that is composed solely of any combination of:
previously certified gasoline (including previously certified
gasoline blendstocks that become gasoline solely upon the addition
of an oxygenate); distillate fuel; or gasoline blendstocks that are
suitable for use as a blendstock without further processing.
    \352\ Transmix processors produce ~0.1 percent of the gasoline
consumed in the U.S.
---------------------------------------------------------------------------

    In addition to proposing refinery gate and downstream per gallon
sulfur caps of either 80 ppm and 95 ppm or 50 ppm and 65 ppm, we are
also requesting comment on the potential implementation of a refinery
gate sulfur cap as low as 20 ppm and a downstream sulfur cap as low as
25 ppm. This would further constrain downstream contamination and limit
the temporary exposure of vehicles in-use to sulfur levels that would
significantly degrade their emission performance. This would serve to
provide added assurance that all parts of the country would receive the
full emission benefits of gasoline sulfur control. However, we are only
seeking comment on it and not proposing it due to the potential cost
increases resulting from further constraints on refinery and
distribution system operations. While a 50-ppm refinery gate cap may
not impact refinery costs, in order to meet a 20-ppm refinery gate cap
and downstream standard of 25 ppm we expect that essentially all
refineries would need to invest to meet the 10-ppm annual average
standard. Our modeling of a non-ABT scenario, discussed in Section
VII.B, shows that the sulfur control costs would increase by almost 10
percent, with no net change in average in-use sulfur levels. Similarly,
while a 65-ppm downstream cap may have little or no impact on
downstream operations, a 25-ppm downstream sulfur cap would likely
require changes in pipeline operations, treatment of gasoline transmix,
and formulation and use of sulfur containing gasoline additives (e.g.,
corrosion inhibitors, and demulsifiers) that could further increase the
costs of the standard. The extent of such impacts and associated costs,
however, are difficult to quantify. Consequently we seek comment on the
appropriateness, impacts, and costs of lowering the per-gallon caps to
20 ppm at the refinery gate, and 25 ppm downstream.
    Further, in order to facilitate the enforcement of the downstream
cap and prevent the potential dumping of high sulfur materials into
gasoline under the guise of adding gasoline additives, we are proposing
additional requirements to clarify the treatment of gasoline additives.
Parties that introduce additives to gasoline at over 1.0 volume percent
are required to satisfy all of the obligations of a fuel manufacturer
including demonstration that the finished blend meets the applicable
sulfur specification. A party other than a fuel refiner or importer who
adds a quantity of additive(s) amounting to less than 1.0 percent by
volume of the

resultant additive(s)/fuel mixture is not considered a fuel
manufacturer.\353\ Thus, the addition of sulfur to finished gasoline
from additives used at less than 1.0 volume percent is simply limited
by the current 95-ppm downstream sulfur cap. We are proposing to limit
the sulfur contribution from the use of a gasoline additive added
downstream of the refinery at less than 1.0 volume percent to 3 ppm
when added at the maximum recommended treatment rate. We believe that
this limitation would not constrain the use of gasoline additives or
result in significant additional costs to gasoline additive
manufacturers. This is because information received from additive
producers indicates that all current gasoline additives contribute less
than 3 ppm to the sulfur content of the finished fuel when used at the
maximum recommended treatment rate. The maximum treatment rate is
already stated on product transfer document or packaging for the
additive. We are proposing a requirement that additive manufacturers
maintain records of their additive production quality control
activities, which demonstrate that the sulfur content of additive
production batches complies with the proposed sulfur requirement, for
five years and to make these available to EPA upon request.
---------------------------------------------------------------------------

    \353\ 40 CFR 79.2(d)(1).
---------------------------------------------------------------------------

B. Refinery Air Permitting Interactions

    It is important to the success of the proposed Tier 3 fuel program
that refineries are able to obtain air permits, if needed, in time to
complete the modifications necessary to comply with the proposed
gasoline sulfur program. Accordingly, we have considered the
implications of permitting requirements with respect to the
implementation of the proposed gasoline sulfur program. This section
provides information on this topic. In summary, we believe that only a
small percentage of refineries would likely need to make modifications
that will trigger a requirement to apply for air permits, and we
anticipate that these permit applications would be processed quickly
enough that air permitting will not be a significant obstacle to timely
compliance with the gasoline sulfur program. In contrast to the Tier 2
program, where EPA expected the need for NAAQS-related New Source
Review (NSR) permits might be widespread among refineries, we believe
that under the proposed Tier 3 gasoline sulfur standard at most only
about 19 refineries would need NSR or Prevention of Significant
Deterioration (PSD) permits. This number--which equates to
approximately 17 percent of the 111 refineries projected to be affected
by the proposed Tier 3 standards--could be even lower if refineries
apply emission controls to reduce emissions increases below the
significance level or if they ``net out'' of NSR.
    If our final assessment of permitting prospects following analysis
of comments indicates it would be appropriate, we would form a special
team to monitor for permitting delays and assist in resolving
associated problems. We also anticipate that other new requirements
applicable to refineries that are being proposed for implementation in
approximately the same period as the gasoline sulfur program would not
interfere with the modifications needed to meet the new sulfur limits
and would not create a competition for air permitting agency resources.
    We invite public comment on air permitting issues, and on possible
actions we might be able to take to help make sure refineries can
obtain needed permits expeditiously. As described in further detail in
Sections V.B.4 and V.B.6, a number of mechanisms and resources are
already available to help mitigate and streamline NSR permitting
requirements associated with the proposed Tier 3 fuel program. For
example, EPA has issued guidance on Best Available Control Technology
(BACT) analysis for GHG emissions, including a white paper that
identifies specific technologies available for refinery process units.
As explained in greater detail below, we expect that the types of
equipment and process technologies that refiners would select to meet
the proposed Tier 3 standards would generally be consistent with BACT
for GHG emissions in terms of achievable, cost-effective, and energy-
efficient design even absent the requirement to obtain a permit,
meaning that such a requirement would not necessitate a shift in
project design or increase costs.
1. Background on New Source Review Programs
    The New Source Review (NSR) program, as it applies to existing
major sources of air pollution, requires that a permit be issued before
a source begins construction of any project to modify the source that
would result in a significant emissions increase and a significant net
emissions increase of a pollutant regulated under this program.\354\
The physical modifications and operational changes that we expect
refineries would make to comply with the proposed gasoline sulfur
standards (described in Section V.A.1.d) could result in emissions
increases in one or more pollutants that may trigger NSR requirements
for preconstruction air permits. NSR permits specify what emission
limits must be met by the new and modified equipment that is part of
the proposed project. They may contain conditions to make sure that the
modifications being made match parameters in the application that the
permit-issuing agency relied on in its analysis. Permits contain
emission limitations for new and modified units and also typically
specify some aspects of how, consistent with the permit application,
the project elements must be constructed and operated. For example, the
permit may identify important design and operational parameters that
are consistent with the established control technology determination(s)
and help assure compliance with associated emission limitations. To
assure that sources follow the permit requirements, permits also
contain monitoring, recordkeeping, and reporting requirements. NSR
permits are issued by a state or local air pollution control agency if
it has its own permit program that has been approved by EPA in the
State Implementation Plan (SIP) or if it has been delegated the
authority to issue federal Prevention of Significant Deterioration
(PSD) permits on behalf of EPA. An EPA Regional Office issues the
permit in other cases.
---------------------------------------------------------------------------

    \354\ Generally, a source is a major source if its ``potential
to emit'' a regulated NSR pollutant is greater than either 100 or
250 tons/year depending on the industrial type of the source and
whether the area is designated nonattainment for the particular
pollutant. All refineries in the U.S. are major sources for purposes
of NSR. A major modification is a physical change or a change in the
method of operation that causes a significant emissions increase and
a significant net emissions increase of any pollutant regulated
under the NSR program. (A net emissions increase differs from an
emissions increase in that a net increase takes into account
contemporaneous emissions changes from other projects at the
source.) Significant emission rates vary depending on the pollutant
and range from 0.6 to 100 tons/year for criteria (NAAQS) pollutants
and their precursors. See 40 CFR 52.21(b)(23). For GHGs,
modifications of existing sources trigger NSR permitting
requirements when there is an increase of GHG emissions of at least
75,000 tons/year of CO2 equivalent, as well as any
increase of GHG emissions on a mass basis. At the time refineries
are required to comply with the proposed fuel sulfur program, the
GHG threshold may be different, but will not be lower than 50,000
tons/year.
---------------------------------------------------------------------------

    There are two separate sets of major source permit requirements
that may apply to modifications at a refinery depending on the
attainment status of the area in which a refinery is located. Each set
of requirements is applied on a pollutant-specific basis, so that in
some cases both permit programs may

apply to the same modification project. The PSD permit program applies
to any major modification at a source located in a designated
attainment or unclassifiable area for any NAAQS pollutant.\355\ PSD
requires compliance with emission limitations achievable through
installation of BACT, an air quality analysis to show that the
modification will not cause or contribute to a violation of any NAAQS
or applicable PSD increment,\356\ an assessment of impact on visibility
and other conditions in national parks and similar federal lands, an
additional impacts analysis, and an opportunity for public involvement.
The second set of requirements is known as the Nonattainment NSR
program because it applies to major modifications at sources located in
areas designated as nonattainment for a specific NAAQS pollutant.\357\
The Nonattainment NSR requirements include, among other things, that a
proposed major modification meet the lowest achievable emission rate
(LAER) for each triggering nonattainment pollutant for which the source
is major and for which there will be a significant emissions increase,
obtain emission offsets for those nonattainment pollutants, and provide
an opportunity for public involvement. LAER is generally a more
stringent emission limitation than BACT. LAER is derived from either
the most stringent emission limitation contained in the implementation
plan of any state for the same type of source or the most stringent
emission limitation achieved in practice. Emission offsets are
emissions reductions, generally obtained from other existing stationary
sources located in the vicinity of a proposed source. Such offsets must
be equal to or larger than the emissions increase resulting from the
modification to ensure that the growth being allowed to occur does not
interfere with the ability of an area to continue making reasonable
further progress towards attainment of the NAAQS.
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    \355\ The PSD program stems from part C of Title I of the Clean
Air Act. The implementing regulations are contained in 40 CFR 51.166
and 52.21.
    \356\ A system of ``increments'' is the mechanism used in the
PSD program to define significant deterioration of ambient air
quality for a pollutant. An increment is the maximum allowable
increase in ambient concentrations of a pollutant in an area
relative to a specified baseline. Increases above that level are
considered to significantly deteriorate air quality and cannot be
allowed.
    \357\ The Nonattainment NSR program stems from part D of Title I
of the Clean Air Act. The implementing regulations are contained in
40 CFR 51.165 and 50 CFR part 51 appendix S. Under Nonattainment
NSR, a major source is generally any source with a potential to emit
of 100 tons/year or more of the nonattainment pollutant, regardless
of industrial type (lower thresholds apply for some pollutants/
classifications). The thresholds for a significant emissions
increase under Nonattainment NSR are generally the same as under PSD
but lower for certain pollutants/classifications.
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    As described previously in Section V.A.1.d, there are several types
of process changes refineries could make to meet the proposed gasoline
sulfur levels. To different degrees, all these technologies involve
process heat from fuel combustion and, thus, have the potential to
increase emissions of pollutants associated with combustion that are
regulated under NSR,\358\ such as NOX, VOCs,
PM2.5, PM10, CO, SO2, and GHGs. The
addition of certain technologies could also result in equipment leaks
of petroleum compounds, which could increase emissions of VOCs and
other pollutants. It is also possible that the removal of more sulfur
from the gasoline stream could require increased capacity or increased
utilization of other refinery processes, such as hydrogen plants and
sulfur recovery units (SRUs), which are sources of air emissions. The
emissions increases associated with a desulfurization project would
vary from refinery to refinery, depending on a number of refinery-
specific factors, such as the refinery output volume, refinery
configuration, feedstocks, choice of desulfurization technology, and
type of fuel used to operate affected process heaters.
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    \358\ Toxic air pollutants are excluded from the PSD program. 42
U.S.C. 7412(b)(6); 40 CFR 52.21(b)(50)(v).
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    As described in more detail in Section V.B.4, we anticipate that
the types of changes that would occur at most refineries would not
result in sufficient emissions increases to require major NSR permits
as a prerequisite for completing the needed changes. The major NSR
permitting requirements would not be triggered for several reasons:
because the emissions increase or the net emissions increase is
naturally less than the significant level, because the refinery
installs control technologies on project-affected units to further
limit the emissions increase, and/or because the refinery ``nets out''
all or part of the emissions increase.
    However, we anticipate that some refineries have the potential to
experience significant emissions increases and significant net
emissions increases as a result of process changes necessary to meet
the proposed gasoline sulfur standard and, therefore, may trigger major
NSR (Nonattainment NSR and/or PSD). These facilities would have to
obtain a major NSR preconstruction permit prior to making these
necessary process changes. For any required major NSR permits, the
associated control technology requirements (BACT and/or LAER) would
apply only to new or modified units associated with the project and not
to units at the refinery that are not affected by the project. We do
not anticipate that the time frames required for the small number of
affected refineries to obtain any needed NSR and/or PSD permits will
present an obstacle to timely compliance with the proposed Tier 3
gasoline sulfur requirements. We are proposing approximately 3 years of
lead time. However, as discussed in section V.E., this is extended to
up to 6 years of lead time for all small refineries, as well as for all
other refineries if they take advantage of the flexibility of the early
credit provisions. In comparison, as discussed in section V.A.2.c, 95
of the 111 refineries are anticipated to be able to comply within 2
years, and the remaining 16 within 3 years. For the 16 that may require
up to 3 years to comply due to the construction of grassroots
hydrotreaters, only 2 of these are projected to potentially trigger the
need for new permits, and even then only for PSD for greenhouse gases,
and only if they choose to produce their own hydrogen. As a result,
only two refineries may actually require the full 3 years to comply.
    For facilities subject to major NSR, the timing of permit issuance
could vary depending on a number of factors, including the clarity and
completeness of the application, the complexity of process changes, the
type of permit required, air quality impact, control technology
reviews, and the permitting agency's overall permit workload. The time
spent preparing a permit application is under the control of the
applicant. Once a permit application is complete, permitting
authorities operating under approved SIPs should be able to issue a
permit within 9 to 12 months if the permit applies to NAAQS pollutants.
Because EPA-issued permits and permits issued by states operating under
a delegation from EPA are subject to additional analysis and
interagency consultation steps specified in federal law, it can take a
few more months if, for example, there are endangered species or
historical preservation issues.\359\ For permits that apply only to
GHGs, we anticipate that less time will be necessary both to prepare
the

application and for the permitting authority to approve the permit. The
CAA requires that EPA take final action on a PSD permit within one year
of the filing with the agency of a complete application. 42 U.S.C.
7475(c). Refineries that are able to avoid major NSR may be required to
obtain a state-issued minor NSR permit. Generally, minor NSR permits
involve less extensive and/or stringent requirements and have shorter
processing times than major NSR permits.
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    \359\ These processing time periods assume that the refinery can
successfully show that the emission increases associated with the
modifications will not cause or contribute to a violation of any
NAAQS or increment (under PSD) or can obtain needed emissions
offsets for the emission increases (under Nonattainment NSR).
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2. Background on NSR Experience Under the Tier 2 Fuel Program
    Many of the modifications that refineries are projected to make in
order to comply with the proposed Tier 3 fuel program are similar in
type, although not necessarily in number or magnitude, to the changes
that were needed to comply with the Tier 2 fuel program finalized in
2000. Therefore, information on the Tier 2 experience may assist the
public in understanding the permitting issues for the Tier 3 fuel
program and in providing comment on possible actions we might undertake
to help refineries expeditiously obtain needed permits.
    The Tier 2 program was designed to reduce the average sulfur
content of gasoline from about 300 ppm to 30 ppm, a reduction of about
90 percent. Anticipating that many refineries would have to make
modifications that might trigger the need for NSR permits, we addressed
the permitting issue in the proposal for the Tier 2 program, in the
final rule, and during implementation. At proposal, we provided
background information on the NSR program and its relationship to the
types of changes likely to be required at refineries. We had not
estimated the number of refineries that might trigger NSR, but we
stated that the number could be substantial. We invited comment on a
number of actions that EPA, states, and/or refineries could pursue in
order to help refineries avoid the need for NSR permits or to obtain
permits more expeditiously than might otherwise be the case. These
actions included the following:
     Use of plantwide applicability limits, possibly
facilitated by new EPA guidance or rules addressing issues specific to
refineries.
     Issuance of new federal guidance on streamlining certain
major NSR permitting requirements such as control technology and
compliance parameters.
     Use of emissions reductions resulting from vehicles
operating on lower sulfur gasoline as offsets for refineries seeking
Nonattainment NSR permits.
     Use of model permits and permit applications.
     EPA refinery permitting teams.
    The Tier 2 proposal also addressed issues related to the Title V
permitting program,\360\ and requested comments on possible approaches
by which refineries might satisfy some NSR and Title V requirements at
the same time.
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    \360\ Title V of the 1990 CAA Amendments requires all major
sources and some minor sources of air pollution to obtain an
operating permit. A Title V permit contains all air pollution
requirements that apply to the source, including emissions limits
and monitoring, record keeping, and reporting requirements. It also
requires that the source report its compliance status to the
permitting authority annually. All existing refineries potentially
affected by the proposed Tier 3 fuel standards have Title V permits
and, because Title V permits by themselves generally do not
establish new applicable requirements, the only implication of the
proposed Tier 3 fuel standards would be the ``roll-in'' of any new
NSR permit requirements into existing refinery Title V permits.
Permitting agencies have efficient processes to accomplish this that
do not delay construction of proposed projects.
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    We received comments on refinery permitting issues from the
refining industry, the automobile manufacturing industry, state and
local agencies that administer air permitting programs, and
environmental and community groups. Based on these comments and
statutory constraints, we decided that it was not necessary or
appropriate to exempt Tier 2 projects from the normally applicable
preconstruction review process. We also decided not to pursue the
development of guidance on plantwide applicability limits for
refineries based on comments suggesting this would be an unproductive
effort because of the complexity of refineries. Nonetheless, we
concluded that it was useful to add certainty to the anticipated
permitting actions and schedules, and to minimize the possibility of
delay. Accordingly, EPA took two types of actions to promote these
objectives. First, as we are now proposing for Tier 3 (see proposed
program flexibilities discussion in V.E.1.-3.), we structured the Tier
2 gasoline sulfur program to allow additional lead time for many
refineries (i.e., certain refineries would be able to make
desulfurization changes later than the otherwise applicable compliance
date to meet Tier 2 requirements). This approach was expected to help
address the concerns over the availability of necessary new equipment
and permitting backlogs caused by many refineries acting to obtain
permits and order equipment within the same time period.Second, we
stated our intention to take several actions during implementation of
the Tier 2 rule to expedite and impart greater certainty in obtaining
necessary major NSR permits (described in more detail below). We also
stated our intention to assist states and refiners on a case-by-case
basis in their efforts to address any unique permitting problems that
might arise and, thus, remedy potential problems that could cause
unanticipated delays. We committed to work with refiners and the state/
local permitting agencies on a case-by-case basis, where a refinery had
unique circumstances that necessitated unique treatment. We clarified
that, in our efforts to provide greater certainty and to facilitate
more expeditious permitting, we were in no way shortcutting existing
opportunities for public participation in making permitting decisions.
We encouraged refineries to begin discussions with permitting
authorities and to submit permit applications as early as possible.
    The final Tier 2 rule identified three key actions that we intended
to take (and subsequently took) to provide assistance that would be
useful toward helping states issue timely permits to refineries. The
first such action was to organize a special EPA team, comprised of
Headquarters and Regional Office experts, to track the overall progress
in permit issuance and to be available to assist state and local
permitting authorities, refineries, and the public upon request to
resolve site-specific permitting issues. The team made special efforts
to be aware of state and local permitting actions that were underway
during the time between the finalization of the Tier 2 program and the
compliance time frame. Experience during this period suggested that
state and local permitting agencies, as predicted in their comments on
the proposed Tier 2 program, were able to process permit applications
in a timely manner, without much need for special troubleshooting help
from the EPA team. In many cases, the modifications to allow compliance
with Tier 2 requirements were subject to only minor NSR permitting
requirements rather than major NSR, or those modifications were rolled
into another permitting action that was needed for other modifications
or expansions due to other technical or market developments. We believe
it is reasonable to expect that similar outcomes (refineries not
needing major NSR permits) would result in connection with air
permitting for the modifications refineries would need to make under
the proposed Tier 3 gasoline sulfur program.
    The second action we took was to develop new guidance on emission
control technology requirements to meet BACT and LAER. We issued this
guidance in 2001. It addressed the levels of control that could be
reasonably

anticipated to represent BACT or LAER under the major NSR requirements.