Finally, EPA will need to update the fuel economy labeling calculations in 40 CFR Part 600 to reflect the proposed E15 test fuel. The current methodology, which took effect with the 2008 model year, contains equations that, when applied to test results using current fuel (zero alcohol), adjust for an average national impact of ethanol in fuel on fuel economy.  These equations would need to be revised such that the adjustment remains consistent with the actual national use of ethanol in fuel.
     Useful Life for GHG Standards
As stated above, EPA is committed to retaining equivalent stringency for GHG emissions compliance beginning in MY 2017.  In contrast to the proposed Tier 3 test fuel, for which we are uncertain as to the effects on GHG emissions, we believe that certifying a vehicle to a longer useful life for any emission constituent would have only a beneficial effect on emissions.  To address potential concerns about changes in the stringency of the GHG standards resulting from a longer useful life, we are not proposing to require a longer useful life for GHG emission standards.  As this approach may result in additional testing burden, we are proposing that manufacturers could optionally certify GHG emissions to a 150,000 mile, 15 year useful life.
      Consideration of Nonroad, Motorcycle, and Heavy-Duty Engine Emissions Test Fuel
As described earlier in Section IV.D.1., we are proposing new specifications for the gasoline emissions test fuel used for testing highway vehicles subject to the proposed Tier 3 standards.  In developing today's proposal, EPA also considered proposing the change in test fuel specifications for other categories of engines, vehicles, equipment, and fuel system components that use gasoline.  This would include a wide range of applications, including small nonroad engines used in lawn and garden applications, recreational vehicles such as ATVs and snowmobiles, recreational marine applications, on-highway motorcycles, and larger heavy-duty gasoline engines.  While engines in some of these categories employ advanced technologies similar to light-duty vehicles and trucks, the vast majority of these engines employ much simpler designs, with many of the engines being carbureted with no electronic controls.  Because of lower level of technology, emissions from these engines are potentially much more sensitive to changes in fuel quality.
EPA is not proposing to apply the new emissions test fuel specifications to these other categories of engines, vehicles, equipment, and fuel system components.  In discussing the potential change in test fuel specifications with the large number of businesses potentially impacted by such a change, many companies supported such a change.  However, a number of manufacturers raised concerns about the level of ethanol in the new fuel, the cost of recertifying emission families on the new fuel, the impact on nationwide product offerings, and the cost impact of complying with the existing standards on the new test fuel.  EPA believes it is important that the emissions test fuel for these other categories reflect real-world fuel qualities but has elected to defer moving forward now pending additional analysis of the impacts of changing the test fuel specifications for the wide range of engines, vehicles, equipment and fuel system components that could be impacted.  These impacts include the impact on the emissions standards, as well as the other issues raised by the manufacturers.  EPA plans to explore such a change in a separate future action.  EPA requests comment on the implications of changing the test fuel for these other categories and whether a different test fuel would be more appropriate for these other categories.
      Consideration of CNG and LPG Emissions Test Fuel
There are currently no sulfur specifications for the test fuel used for certifying natural gas vehicles.  There is also no sulfur specification in §86.113 for the test fuel used for certifying liquefied petroleum gas (LPG) vehicles.  The corresponding LPG test fuel for heavy-duty highway engines and for nonroad engines in §1065.720 includes an 80 ppm maximum sulfur specification.
We request comment on the appropriateness of changing §86.113 to reference 40 CFR part 1065 for both natural gas and LPG test fuels.  We further request comment on amending these specifications to better reflect in-use fuel characteristics, and in particular on the appropriateness of aligning the sulfur specifications with those that apply for gasoline test fuel.  Changing the sulfur specifications would depend on establishing that the new specification is consistent with the range of properties expected from in-use fuels.
Small-Business Provisions
As in previous vehicle rulemakings, our justification for including provisions specific to small businesses is that these entities generally have a greater degree of difficulty in complying with the standards compared to other entities.
In developing the proposed Tier 3 vehicle program, we evaluated the environmental need as well as the technical and financial ability of manufacturers and others to meet the standards as expeditiously as possible.  We believe it is feasible and necessary for the vast majority of the program to be implemented in the established time frame to achieve the air quality benefits as soon as possible.  Based on information available from small manufacturers and others, we believe that entities classified as small generally face unique circumstances with regard to compliance with environmental programs, compared to larger entities.  Thus, as discussed below, we are proposing several flexibility provisions for small businesses in the vehicle industry to reduce the burden that this program could have on them.  These proposed provisions are based on the recommendations of the Small Business Advocacy Review (SBAR) Panel described in Section XIII.C of today's proposal and include a few additional provisions.
Small entities generally lack the resources that are available to larger companies to carry out necessary research and development and to raise capital for investing in a new regulatory program.  Small entities are also likely to have more difficulty in competing for any needed engineering and construction resources and lower production volume over which to spread their compliance costs.  Small entities also tend to have limited product lines, which limits their ability to take advantage of the phase-in and ABT flexibility provisions in the proposal.  As such, we are proposing regulatory flexibility provisions that would provide additional lead time and reduced testing burden for 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.
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.
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.
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 PM 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.
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.
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.  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.
Compliance Provisions
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 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.
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 PM 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 PM 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.
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 §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.   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.
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.
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 pm 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.
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.
Proposed Tier 3 Gasoline Sulfur Standards
Overview
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 and is proposing to take further action under the proposed Tier 3 Program.
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.
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.
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.

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.  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).
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.  Beijing, China also recently introduced a 10-ppm sulfur limit for gasoline.  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.
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), 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).  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.
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.
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.
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.  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.
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.
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.  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.
Table V-2 Impacts of Nationwide ABT Program on Compliance

                     ABT with nationwide credit transfers
                    ABT with intra-company 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.
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 desulfurze 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.
Table V-3 Anticipated Compliance Timelines

                                    Months

0-
3
3-
6
6-
9
9-12
12-15
15-18
18-21
21-24
24-27
27-30
30-33
33-36
36-39
39-42
42-45
                         Revamp Pre- & Postreaters
Scoping Studies

Process
Design

Permitting

Detailed Engineering

Field Construction

Start-up / Shakedown

                             Grassroots Postreater
Scoping Studies

Process
Design

Permitting

Detailed Engineering

Field Construction

Start-up / Shakedown

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 startup 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.  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.

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

Front-End Design
Detailed 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.
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.  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.
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.  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.  However, it would provide some additional assurance of in-use gasoline quality and help to address vehicle manufacturer concerns.
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 °F.  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.
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.  Transmix processors do not handle sufficient volumes to support the installation of currently available desulfurization units.  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.
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.  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.
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.
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.  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.
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.  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, 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.  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.
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, 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.
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.  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.
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, and requested comments on possible approaches by which refineries might satisfy some NSR and Title V requirements at the same time.
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.  Our general experience following the release of this BACT/LAER guidance was that it did not play a substantial role in the permitting of refinery projects for Tier 2.  That is, due to their own expertise and the need to consider refinery-specific factors, state and local permitting authorities generally did not find it necessary to rely on our guidance in their own permitting processes for refineries making changes to meet the Tier 2 requirements.  In addition, many of the refinery projects were able to avoid major NSR, so BACT and LAER were not requirements that had to be met.  Again, 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 to meet the proposed gasoline sulfur standard.
The third action we took was a fast-track effort to develop new guidance on the use of emissions reductions resulting from vehicles operating on lower sulfur gasoline as emission offsets for refineries seeking Nonattainment NSR permits.  We invited comment on a draft version of this guidance five months after the final Tier 2 rule.  The draft guidance discussed in depth how the use of such offsets could be made consistent with seven criteria given in the CAA for such offsets.  We received many comments from state and local air agencies and community groups opposing the proposed offset guidance on legal, fairness, and environmental justice grounds.  One refiner recommended that EPA set aside a portion of the Tier 2 reductions in each state as offsets, rather than leaving this decision to each state.  We did not finalize the draft guidance, and no state further pursued a system under which vehicle emissions reductions were made available to refineries as offsets for Nonattainment NSR permits.
Changes in the NSR Permitting Program since Tier 2 Final Rule
The Tier 2 fuel program was promulgated in early 2000, and most refiners were required to comply with those requirements by 2006.  During and since that period, there have been a number of changes to the major NSR programs.  These changes are summarized here to facilitate public comment as to how these changes may affect whether refinery modifications undertaken as a result of the proposed Tier 3 fuel program would trigger NSR and/or the requirements that refiners and permitting authorities would have to meet.
In 2002, we issued a final rule known as the NSR Reform Rule.  This rule revised the EPA-administered NSR programs and changed the minimum approvals required for SIP-approved NSR programs for NSR applicability.  Some of the provisions of the 2002 final rule have been vacated by the Court, subsequently amended by EPA, or are currently under reconsideration.  Two key components of the NSR Reform Rule that remain in place are a new applicability test for projects involving existing emissions units (the "actual-to-projected-actual" applicability test) and provisions that allow for the establishment of plantwide applicability limits (PALs).  The change in the applicability test since the Tier 2 experience means that fewer modifications may be found to have emissions increases that are above the significant emission levels, in which case fewer major NSR permits may need to be issued.  The PAL provisions offer a voluntary alternative for determining major NSR applicability that can provide sources with significant flexibility to manage facility-wide air emissions without triggering major NSR permitting.  Refineries that have established PALs or will establish one or more PALs prior to or as part of permitting associated with the Tier 3 fuel program will be far less likely to trigger major NSR permitting requirements.
We have also taken a series of actions that have had the effect of making emissions of GHGs a factor in determining whether a PSD permit is required for a refinery modification.  Under the applicable PSD provisions in the CAA, GHGs became regulated under the PSD program on January 2, 2011 after EPA adopted tailpipe emissions standards for these pollutants under Title II of the CAA.  Because the incorporation of GHGs into the PSD program had the potential to significantly expand the number of sources required to obtain PSD permits, EPA adopted the 2010 Tailoring Rule to phase in the PSD permitting requirements according to a series of steps based on different GHG emission thresholds.  At this time the Tailoring Rule requires that any modification at an existing refinery that increases GHG emissions by 75,000 tons per year or more of CO2 equivalent and also produces any mass increase in GHG emissions would trigger the need for a PSD permit that addresses GHG emissions.  Because there are no NAAQS for GHGs and, therefore no nonattainment areas, only PSD could potentially apply to a refinery modification with respect to increases in GHG emissions.    The analysis (described in Section V.B.4) indicates that only a small number of large refineries would be affected.  For the sources that would need a PSD permit for GHGs, the main substantive requirement for obtaining the permit is to apply BACT for GHG emissions from the new or modified unit(s) because an air quality analysis is not required.