Another development since 2000 has been the establishment of several new and revised NAAQS and the designation of nonattainment areas under some of these NAAQS.  At the time of the final Tier 2 rule, the NAAQS of most relevance to Nonattainment NSR permitting for refineries were the 1-hour ozone NAAQS, the PM10 NAAQS, and the SO2 NAAQS, because these NAAQS accounted for the vast majority of the existing nonattainment areas.  The designation of new nonattainment areas under the 1997 NAAQS for 8-hour ozone became effective in 2004.  Designations under the 1997 NAAQS for PM2.5 became effective in 2005.  In 2008, we again revised the ozone NAAQS and designations under that standard became effective in July 2012. In 2006, we revised the 24-hour PM2.5 NAAQS and in 2009 (2011 for a few areas) we designated areas under the 2006 PM2.5 standard.  In December 2012 we revised the primary annual PM2.5 NAAQS and designations associated with that revised standard are expected to become effective in 2015.  One effect of this evolution of the NAAQS and associated attainment status for areas is that it has become more common over time for sources to be located in ozone or PM2.5  nonattainment areas and thus subject to Nonattainment NSR rather than to PSD for their VOC, NOX, and PM2.5 emissions increases.  However, over the same time period, some areas currently designated as nonattainment for ozone and/or PM2.5 are expected to be redesignated to attainment.  Therefore, we do not expect a dramatic shift on a national basis in one direction or the other.
In 2008, we issued a final rule specifying in detail how NSR applies to PM2.5.  In addition, in 2010 we supplemented this rule with additional provisions for the PSD program specifically.  The latest rule, among other things, established PM2.5 increments, and as of October 20, 2011, sources that trigger PSD for PM2.5 are required to show compliance with the applicable increment, in addition to showing that they do not cause or contribute to a violation of any of the PM2.5 NAAQS.
In 2010, EPA finalized new NAAQS for 1-hour NO2 and 1-hour SO2.  EPA has completed the initial round of mandatory designations for the 1-hour NO2 NAAQS and all areas have been designated unclassifiable/attainment.  The first round of designations for the 1-hour SO2 NAAQS will be made in June 2013, thus we do expect there to be nonattainment areas for the 1-hour SO2 NAAQS by the time that refineries might need to seek NSR permits to make the required facility modifications for the Tier 3 program.  However, we expect that no refinery would have increases in SO2 emissions that are large enough to trigger major NSR, so any change in attainment status for the SO2 NAAQS should have no effect on permitting issues.
In areas designated attainment or unclassifiable for the 1-hour NO2 or 1-hour SO2 NAAQS, the air quality impacts assessment required to obtain a PSD permit can present new challenges for permit applicants.  This is because demonstrating that a modification will not cause or contribute to a violation of these 1-hour standards may require more refined and data-intensive air quality modeling approaches than has previously been required to make this demonstration with respect to the pre-existing NAAQS for NO2 and SO2.  To assist permit applicants in performing the required analysis of 1-hour NO2 and SO2 air quality impacts, we have issued several guidance memos that describe available alternative approaches and flexibilities. In addition, EPA provides technical assistance with modeling issues upon request.
Assessment of Tier 3 Refinery Changes and Permitting Implications
EPA has performed a refinery-by-refinery assessment of the physical and operational changes that are likely to be needed to allow each active refinery in the U.S. to produce gasoline that complies with the proposed Tier 3 fuel specifications. We have also assessed the likely effects of those changes on refinery emissions.  This assessment is described in more detail in Section 5.4 of the draft RIA.  Using this assessment, we were able to gain a reasonable understanding of the potential scope of NSR permitting requirements refiners might face under the proposed Tier 3 program.  In general, our assessment indicates that only a small number of refineries will likely need to make modifications of a type and size that would trigger the need for a PSD or Nonattainment NSR permit.  The assessment and this conclusion take into account the changes in the NSR program and its context since 2000 described in Section V.B.3.  A technical memorandum describing in detail our analysis and results is in the public docket for this proposal.
In our analysis, we started with the estimates we have made regarding the physical and operational changes that would be required at each refinery (described in Section 5.4 of the draft RIA).  The modifications at a given refinery could include revamps to existing FCC pre- or post-treatment unit(s) or the installation of a new grassroots post-treatment unit for sulfur reduction. Based on the projected refinery-specific changes, we estimated the increased demand for energy (i.e., fuel to generate process heat, steam and electricity), hydrogen, and sulfur recovery associated with meeting the proposed Tier 3 standards. We selected representative industry emission factors for NAAQS pollutants, their precursors, and GHGs for each emitting process and combined them with estimates of incremental activity to estimate the emissions changes at each equipment unit (or group of similar units) at each refinery.
To determine upper and lower bounds for emissions increases resulting from changes necessary to meet the proposed Tier 3 gasoline sulfur specification, we evaluated two scenarios, a no ABT scenario (assuming no trading of sulfur credits) and the primary ABT scenario described in Section 5.4 of the draft RIA.  We did not have sufficient detailed information to predict which refineries would find it most profitable to generate additional electrical power, hydrogen and high octane blendstocks internally on site rather than purchasing these inputs from external suppliers.  If a refinery generates these additional inputs internally on site, the additional emissions would count towards the significant emissions rates and could affect the need for a major NSR permit.  To account for these variables, we evaluated a high and a low case for each identified scenario.  Under the high case, we assumed 100 percent internal generation of the additional electrical power, hydrogen, and high octane blendstocks and under the low case, 100 percent external generation of the same.  We expect refineries to actually be somewhere between these two extreme cases in the future.  For the identified scenarios and cases, we compared the emissions increase for each pollutant at each refinery to the significant emissions increase threshold for that pollutant, taking into consideration the current attainment status for each pollutant where the refinery is located.  We found that the no ABT scenario, low case had the lowest number of refineries estimated to trigger major NSR and the primary ABT scenario, high case had the highest, although the overall numbers did not vary greatly.
An important aspect of our analysis is that we assumed that refineries would not install new emission controls on affected units for the purpose of staying below the significant emissions increase threshold and thereby not triggering major NSR.  In particular, we did not assume that selective catalytic reduction (SCR) to control NOX emissions would be applied to new or modified fuel combustion units.  This is an important assumption that tends to result in overestimates of the number of major NSR permits needed for NAAQS-related pollutants.  In reality, applying new emission controls would be an option that refineries may employ to legally avoid major NSR permitting.  We also did not assume that refineries would "net out" of NSR by taking credit for any emissions reductions occurring within a contemporaneous timeframe, including any new emissions reduction projects initiated specifically for the purpose of "netting out."  This analysis resulted in a prediction of whether a PSD and/or a Nonattainment NSR permit would be needed for each refinery and the pollutants that would have to be addressed in those permits, under each of the two scenarios.  Only the results for the primary ABT scenario, high case are presented here.  The results for the no ABT scenario, which are not greatly different, are described in the previously referenced technical memo found in the docket for this rulemaking.
 We found that under the primary ABT scenario, high case, 19 refineries appeared likely to have significant emissions increases for one or more pollutants and thus would trigger major NSR.  This equates to approximately 17 percent of the 111 refineries projected to be affected by the proposed Tier 3 standards.  Of these 19 refineries, we predicted that 13 refineries would need permits for NAAQS-related pollutants and their precursors (PSD and/or Nonattainment NSR) and for GHGs (results for GHG are discussed below).  Thus, compared to the Tier 2 program where EPA expected the need for NAAQS-related NSR permits might be widespread among refineries, we believe that under the proposed Tier 3 program only about 13 refineries would need major NSR air permits to address NAAQS pollutants.  This number could be lower if those refineries apply pollution controls, such as SCR for NOX, to sufficiently reduce the emissions increases to levels that are below the applicable pollutant significance level, or if the refineries can achieve emissions reductions elsewhere at the facility to "net out" of major NSR.  For refineries that are required to obtain a major NSR permit for NAAQS pollutants, the permitting process is expected to normally take about 9 to 12 months once the permitting authority has received a complete application.
All 13 refineries just described as potentially needing NSR permits for NAAQS pollutants are also projected to need PSD permits for GHGs.  In addition to these 13 refineries, we estimated that 6 other refineries may require a PSD permit addressing only GHG emissions from new or modified equipment that is part of the project.  For these refineries, BACT must be applied for GHG emissions, which we expect in most cases would mean that new or modified fuel-burning equipment would have to be designed for good energy efficiency.  We expect that the types of equipment and process technologies that refiners would modify or add 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 any shift in project design or increase costs.  This expectation is based on the fact that there are strong economic incentives for refiners to design and purchase the most energy-efficient process equipment to minimize the cost of production.  For example, most of the new or modified units expected to be involved in refinery projects designed to meet the proposed Tier 3 standards are fuel combustion units (e.g., process heaters).  Because fuel cost (direct cost in the case of purchased natural gas and opportunity cost in the case of refinery-generated fuel gas) represents a significant component of total operating cost for such units, refineries will strive to maximize energy efficiency based on available technologies as part of their project design.  EPA requests comment on the likelihood that refineries' costs for equipment and process technology for compliance with Tier 3 would include any associated costs of compliance with NSR.
In 2010, EPA issued a white paper on available and emerging technologies for reducing GHGs from the petroleum refining industry.  This white paper addresses the types of equipment expected to be involved in projects designed to meet the proposed Tier 3 fuel standards, including process heaters/boilers, hydrogen plants, and sulfur recovery units.  The identified GHG control technologies for these types of units predominately involve opportunities for energy efficiency.  Consistent with the findings reported in the white paper, our experience to date with GHG permitting at refineries and other similar sources supports the application of energy efficient design and operation of affected units as BACT, and we do not expect that in the time frame associated with Tier 3-related projects, add-on controls would be required.
For EPA-issued permits and permits issued by state or local agencies under delegation, consultation with other federal agencies under the Endangered Species Act and consideration of environmental justice would also be required.  Significantly, no air quality modeling of GHGs would be required, and thus there would be no need to obtain extensive input information on meteorology and emissions from other nearby sources.  Given these differences, we expect that the timeline for obtaining a permit only for GHG emissions should be shorter by several months than the timeline for a permit that addresses NAAQS pollutants.
We invite public comment on our analysis including ways in which we might improve the assessment between now and the final rule.
      New Source Performance Standards and  National Emission Standards for Hazardous Air Pollutants for Refineries
In addition to the proposed Tier 3 rulemaking, we are also conducting other rulemakings to set new and revised limits for direct emissions from refineries of NAAQS-related pollutants and hazardous air pollutants (HAPs).  This section provides summary information on these rulemaking efforts, so that comments on the proposed Tier 3 program can be more fully informed.
We first regulated petroleum refineries in 1974 when the agency issued the New Source Performance Standards (NSPS) to control NAAQS-related air pollutants.  The NSPS applies to refinery process units that commenced construction, reconstruction, or modification after June 11, 1973, but before May 14, 2007.  On June 24, 2008, we amended the NSPS and issued new standards for most process units constructed, reconstructed, or modified after May 14, 2007 and for flares which commence construction, modification, or reconstruction after June 24, 2008.  We were petitioned to reconsider these final rules and on September 12, 2012, EPA finalized amendments and technical corrections to address issues related to flares and process heaters. There are two existing Maximum Achievable Control Technology (MACT) standards to control HAPs that apply specifically to petroleum refineries.  These standards are referred to as MACT 1 and 2 and were issued in 1995 and 2002, respectively.  EPA is required to perform risk and technology reviews (RTR) to assess residual risk for MACT standards for HAPs within eight years of the promulgation of the original MACT standards.  In addition, EPA is required to perform a technology review of advancement in processes, practices and control requirements every eight years after promulgation of the MACT. EPA is planning to issue a single rulemaking that will address the RTR analyses for both MACT 1 and 2.
Finally, on March 21, 2011 EPA published MACT standards for Industrial, Commercial, and Institutional Boilers and Process Heaters and on January 31, 2013 EPA finalized revisions to those standards based on reconsideration. These standards apply to boilers and process heaters at refineries. Because any changes that are made to meet new requirements of these rulemakings would likely reduce rather than increase refinery emissions, we do not expect these modifications to trigger NSR unless a refinery chooses to increase the capacity of one or more of its units at the same time.  This means that we expect the final rules would not themselves increase the major NSR workload for refinery environmental permitting staffs or for permitting agencies in the same period that these organizations need to prepare and process permit applications related to the proposed Tier 3 fuel program.  (Minor NSR permitting workload may be affected.)
Steps for Streamlining the Permitting Process
As we did for Tier 2, we could organize a Headquarters-Regional response team to monitor and address any delays in permitting by facilitating coordination among organizations where needed to resolve permitting issues.  The mission of this team would also include tracking the overall progress in permit issuance and assisting state and local permitting authorities, refineries, and the public upon request to resolve site-specific permitting issues.  The team would be comprised of EPA staff knowledgeable about permitting programs and refinery operations, so the team could provide expert assistance and troubleshoot permitting issues in a timely fashion.  We invite comment from refineries, permitting authorities, and others regarding the usefulness of such a team.
We will continue to maintain and refine the tools and resources that have proven useful to permit applicants and permitting authorities, such as the RACT/BACT/LAER clearinghouse, the Support Center for Regulatory Atmospheric Modeling, and our web-based resources on GHG permitting.  These GHG permitting resources include various materials on the topic of BACT for GHG, including white papers and copies of our comments on recent draft permits proposed by state and local permitting agencies.  One of the white papers, described previously in Section V.B.4, addresses petroleum refining, and provides information on control techniques and measures that are available to mitigate GHG emissions in order to assist states and local air pollution control agencies, tribal authorities, and regulated entities in implementing technologies or measures to reduce GHGs under the CAA, particularly in permitting under the PSD program and the assessment of BACT.
  We believe the guidance we provided on BACT and LAER for NOX and VOC shortly after the final Tier 2 rule was not widely utilized by either  refineries or permitting authorities.  Nevertheless, we invite comment on whether additional guidance on BACT and LAER for these and other NAAQS-related pollutants would be useful to support permitting for Tier 3-related modifications as well as the appropriate scope and substance of such guidance.  We anticipate that if we do develop any new BACT/LAER guidance, we would provide an opportunity for public comment on the draft guidance before finalizing it.
For Tier 3-related NSR permit applications submitted to EPA Regional Offices, we will assist members of the local communities in understanding the applications and our proposed permits, in offering comment, and participating in our decisions.  We also encourage similar assistance efforts by the state and local permitting authorities, and we invite comment on the specific forms that our and their support should take.
EPA received comments during the Tier 2 rulemaking that vehicle emissions reductions should be allowed to be used as part of "netting out" of NSR.  This concept is now relevant to GHG emissions, in addition to the NAAQS-related pollutants to which it was relevant at the time of the Tier 2 rulemaking.  At that time we responded to the comments by saying that the use of vehicle emissions reductions for netting purposes was not permitted by the NSR regulations, since the creditable emissions reductions used for netting purposes must result from reductions occurring at the modified source.  We noted, for example, that the definition of net emissions increase in 40 CFR 52.21(b)(3)(i) includes only increases and decreases occurring "at the source".  We believe this provision in the NSR rules is well founded in the CAA.  Setting aside the issue of whether we have authority to change this provision, the potential consequences of changing it to allow the use of non-source emissions reductions in "netting out" of NSR would be far reaching.  We are not proposing such a change as part of this rulemaking, and we believe that any proposal for such a change should be based on a much better assessment of its possible implications than can be accomplished as part of this rulemaking.  We also note that "netting out" of NSR could be a complex and often time-consuming process because all contemporaneous emissions increases and decreases within the refinery must be properly accounted for, so the ability to use vehicle emissions reductions in the netting analysis would not automatically make "netting out" a time-saving shortcut around the permitting process that would otherwise apply. Nevertheless, we invite comment regarding how critical such a change may be to successful permitting of the modifications needed to comply with the proposed Tier 3 program, possible legal rationales for such a change, and the possible implications beyond the Tier 3 rule including ways to limit such implications by making the change specific to vehicle emissions reductions that are closely linked to changes in fuel properties that result from the refinery modifications.
Finally, we invite comment on issues related to state and local minor source NSR programs and how they may relate to implementation of the proposed Tier 3 fuel program.  EPA rules give states wide latitude in the design and operation of their minor source programs, and we do not routinely require states to report their minor source permitting activity to us.  Therefore, focused comments on this issue would be helpful.
Standards for Denatured Fuel Ethanol and Other Oxygenates
Current gasoline requirements include the prohibition on blending gasoline with denatured fuel ethanol (DFE) that has sulfur content higher than 30 ppm.  This requirement reflects the current 30-ppm refinery average sulfur requirement.  Consistent with this requirement and our proposed introduction of a 10-ppm refinery average sulfur standard, we propose that manufacturers of DFE for use by oxygenate blenders would be required to meet a 10-ppm sulfur cap.
California's requirements for DFE, which became effective in December 2003, are as follows: maximum 10 ppm sulfur, maximum 0.06 volume percent benzene, maximum 0.5 volume percent olefins, and maximum 1.7 volume percent aromatics.  Denaturants used to manufacture DFE must also meet maximum benzene, olefins, and aromatics specifications that are based on the anticipated dilution ratio when blended with ethanol.  Additionally, in July 2002, the Renewable Fuel Association (RFA) recommended that all ethanol produced for use in the U.S. should be manufactured in accordance with the California specifications primarily because of logistical difficulties in segregating ethanol destined for California from other destinations.  RFA recently indicated that all ethanol producers are adhering to this recommendation.  Some DFE marketers have also adopted California's DFE requirements as part of their specifications.  Consequently, we believe that the implementation of a 10-ppm sulfur cap for DFE would not result in increased burden to ethanol producers.  We are proposing it to reduce emissions from motor vehicles, the same reason we are proposing a more stringent sulfur standard for gasoline into which it is blended.
Further, the ASTM International specification for DFE allows only natural gasoline, gasoline blendstocks, and gasoline as denaturants.  Similar to the ASTM specifications, we are proposing to require that only natural gasoline, gasoline, and gasoline blendstocks for oxygenate blending (BOB) be used as ethanol denaturants.  We believe that this limitation is needed to prevent the use of other denaturants that might adversely impact vehicle emissions performance.  We believe that the ASTM specifications are already in use by industry and, therefore, EPA's adoption of the same specifications would not result in an increased burden to DFE producers.  We further believe that limiting the type of gasoline blendstocks that can be used as denaturant to BOBs would not impose a new burden on DFE producers since other gasoline blendstocks would not typically be available to DFE producers.  We request comment on whether there should be an allowance for other gasoline blendstocks to be used as ethanol denaturants.
With regard to benzene, olefins, and aromatics, we believe that these proposed requirements along with Internal Revenue Service ethanol denaturant requirements would limit benzene, olefins, and aromatics content of DFE to very low levels.   Therefore, we are not proposing any limits on these parameters in DFE.  Nevertheless, we are requesting comments on whether we should adopt the State of California's benzene, olefin, and aromatics specifications for DFE.  We are also proposing to limit the maximum concentration of denaturant that can be used in DFE to 2 volume percent.  Under the RFS2 regulations, if the denaturant level is 2 volume percent or less (effectively less than 2.5 volume percent considering rounding) the entire volume of denatured fuel ethanol can be used for determining compliance with the RFS2 renewable fuel volume requirements.
We also request comment on whether to require manufacturers of denaturants for use in DFE to register with EPA, and demonstrate compliance with the maximum sulfur, benzene, olefins, and aromatics specifications enforced in the State of California based on the anticipated dilution with ethanol.  We believe that such additional requirements on the denaturants used to manufacture DFE would not be necessary given that DFE producers would be required to meet the proposed specifications and the proposed requirement that denaturant concentration in DFE be limited to a maximum of 2 volume percent.
We propose that producers of DFE would be required to meet the proposed fuel quality requirements for their product and provide batch reports to EPA.  This is similar to the requirements for gasoline refiners.  This approach would provide an appropriate level of assurance on the quality of DFE which has become such a large component in the gasoline fuel pool.  We believe that this approach would not result in additional burden to ethanol producers beyond the annual batch reports that they would need to submit to EPA and the information they provide on product transfer documents (PTDs).  Currently, under the fuel and fuel additives registration requirements at 40 CFR part 79, manufacturers of DFE are required to register their products with EPA prior to introducing DFE into commerce.  Also, DFE producers currently test each batch of their product in order to provide assurance to blenders that it meets the current fuel quality requirements.  This information is critical to ethanol blenders to avoid testing each batch of an ethanol blend that they manufacture.  The proposed requirements would facilitate unfettered downstream ethanol blending.
 We are also proposing that the proposed fuel quality specifications and requirements for DFE (except those related to the use of denaturants) would apply to other oxygenates used in gasoline.  We are proposing that the oxygenate quality requirements would become effective for oxygenate producers/importers on January 1, 2017.  We are proposing that oxygenate producers and importers would be required to register by December 1, 2016, or 30 days prior to the date when they produce/import oxygenate (which ever date is later).  Registration under the RFS program would be sufficient to fulfill this proposed requirement.  We are proposing that oxygenate blenders be required to begin using oxygenates that comply with the proposed requirements beginning March 1, 2017.  We also seek comment on the ability of these blenders to comply with the proposed requirements earlier, and appropriateness of such an earlier compliance date.
Standards for Fuel Used in Flexible Fueled Vehicles
FFVs are vehicles that are capable of operating on both gasoline and gasoline blends containing up to 85 volume percent denatured ethanol.  Whether FFVs are operating on clear gasoline (E0), E85, or any level of ethanol in between, to maintain emission performance the vehicles still need the fuel to meet certain quality specifications, such as the 10-ppm average gasoline sulfur standard proposed today.  We anticipate that the volume of higher level ethanol blends used in FFVs may increase substantially as the volume requirements of the RFS program increase.  Significant public and private initiatives are also currently underway to expand the use of ethanol blender pumps that dispense a variety of ethanol blends for use in FFVs.  Therefore it is becoming increasingly important that all fuels used in FFVs, not just gasoline, meet fuel quality standards.  A lack of clarity regarding the standards that apply to fuels used in FFVs could act to impede the further expansion of ethanol blended fuels, which is important to satisfying the requirements of the RFS program.  For these reasons, we believe it is important that our gasoline quality standards for not just sulfur, but also benzene, Reid Vapor Pressure (RVP), detergency, and compliance with the interpretive rule defining the phrase "substantially similar" in CAA section 211(f)(1) (i.e., contain only carbon, hydrogen, oxygen, nitrogen, and sulfur) apply to any fuel used in an FFV.  At the same time, it is not necessarily clear how we should implement such standards within the context of our existing regulations.  For this reason we are seeking comment on appropriate regulatory mechanisms for doing so.  The following sections discuss potential approaches for gasoline-ethanol blends both above and below 50 percent ethanol.  We have also developed a possible approach, along with draft regulations, that are included in the docket on which we specifically seek comment.
Standards for E51-83
Historically, "E85" has been used to describe fuel blends containing gasoline and ethanol with a minimum and maximum ethanol content of 68 volume percent and 83 volume percent, respectively.  The recent update to the ASTM International specification for "E85" included a reduction in the minimum ethanol concentration to 51 volume percent.  As part of the updated specification, ASTM retired the name "E85" in favor of "ethanol fuel blends for flexible-fuel automotive spark-ignition engines."  ASTM took this action because the term "E85" has caused confusion regarding the variability in the ethanol content depending upon seasonal climactic conditions and regional gasoline volatility specifications.  For the purposes of this discussion, "E51-83" refers to the fuel which meets the new ASTM D5798-11 specifications.
Currently, only reformulated gasoline blendstocks for oxygenate blending (RBOBs) and gasoline that has previously been demonstrated to comply with applicable EPA specifications (reformulated gasoline (RFG) and conventional gasoline (CG)) are used to manufacture E51-83.  The Agency believes that the use of these blendstocks prevents inappropriate blending components (e.g., chemical wastes) from being used in the production of E51-83.  Use of these blendstocks would also help ensure that E51-83 meets the necessary sulfur levels we are proposing today.  We note, however, that use of only these blendstocks is interfering with expansion of E51-83 into the marketplace by preventing blends at the upper range of the allowed ethanol content.  At higher ethanol concentrations, blenders often cannot meet the minimum volatility specifications set by ASTM for cold start performance when using only BOBs and gasoline.  Prior to the recent update of the ASTM specifications, it was frequently not possible to manufacture "E85" that met both the ASTM minimum volatility specification and the EPA requirements regarding the blendstocks that can be used.  As a result, some marketers discontinued distributing "E85."  Although the ASTM update provided a compliance method for manufacturing E51-83, the result is that less ethanol can be used in FFVs, because the ethanol concentration is forced down from 83 percent toward the 51 percent minimum.
To address this situation, we believe that we need to prescribe requirements for E51-83 that would enable the continued expansion into the marketplace.  We believe that such requirements could focus more on the product and less on how it is made.  We also believe that E51-83 should meet the same sulfur, RVP, and benzene standards otherwise applicable to gasoline as well as the "substantially similar" requirements.  We are therefore seeking comments on whether we could extend these requirements to E51-83.  We note that establishing such requirements could allow the use of butane and natural gasoline liquids (NGL) to manufacture E51-83 with sufficient volatility to meet the ASTM specifications.  Butane is commonly blended into gasoline and NGL is the denaturant specified by ASTM for the manufacture of DFE.  Additionally, because NGL and butane are less expensive than gasoline or BOBs, we anticipate that such a change could help to reduce the price of E51-83 relative to finished gasoline.
Further, we note that requiring E51-83 to meet the same standards as gasoline would subject E51-83 manufacturers to all the sampling, testing, and reporting obligations of refiners.  While this would provide maximum blending flexibility, it could also limit the parties that might choose to blend E51-83.  Currently oxygenate blenders are exempt from much of this regulatory burden.   For this reason, we are also seeking comments on whether we could establish requirements that would allow producers of E51-83 to avoid the compliance burdens of a refiner.  We are seeking comments on one such approach that would require the use of only blendstocks that meet certain specifications to produce E51-83.  We believe that use of only blendstocks (including butane and NGL) that meet these specifications would ensure the final blend would always meet the standards.  These approaches are discussed in greater detail in the docket for this rulemaking.  We seek comment on these approaches, and any other approaches that could be used to remove hurdles for blending of E51-83 while still ensuring the product meets the fuel quality requirements needed to maintain vehicle emission performance.
Standards for Mid-Level Ethanol Blends (E16-50)
As discussed earlier, whether FFVs are operating on clear gasoline (E0), E85, or any level of ethanol in between, to maintain emission performance these vehicles still need the fuel to meet certain quality specifications.  For this reason, we believe it is important that higher ethanol blends also meet the same standards that apply to gasoline.  Our various standards for gasoline already apply to any fuel sold for use in motor vehicles, which is commonly or commercially known or sold as gasoline.  In the fuel and fuel additive registration program, the gasoline family includes fuels composed of at least 50 percent clear gasoline by volume.  As a result, our gasoline standards already apply to E16-50 ethanol blends.  And yet, such fuels currently can only be used in FFVs.  Therefore, in addition to seeking comment on the need to have E16-50 blends comply with the gasoline sulfur, benzene, and RVP standards, we also seek comment on the means of doing so.  For example, can and should the Agency simply treat E16-50 as gasoline under our regulations and clarify that gasoline means any fuel that contains 50 percent or more gasoline?  Alternatively, should the Agency treat E16-50 as an alternative fuel used in FFVs?  In which case we seek comment on whether we should take the same approach for E16-50 as discussed above for E51-83 with respect to sulfur, benzene, RVP standards, and substantially similar requirements under section 211(f).
In the context of considering whether and how to apply gasoline standards and requirements to E16-50 we also seek comment on whether it might be an appropriate reading of our regulatory and statutory authority to allow E16 to E50 blends to have higher RVP levels than otherwise required by our regulations for gasoline.  As the ethanol level increases, the volatility increase caused by blending ethanol with gasoline begins to decline, such that at E30 there is only about a 0.5-psi RVP increase.  While still an increase compared to the standards that apply to gasoline other than E9-10, it is considerably less than the full 1-psi RVP increase that results at E10.  The evaporative emission increase caused by E30 would then be less than for E10.  Thus, we seek comment on whether it would be an appropriate reading of our regulatory and statutory authority to allow higher RVP levels for such blends, at least in some limited situations and time frames (e.g., using existing regulatory research exemptions for demonstration programs) where new efforts are being made to introduce such blends into the market.  We further seek comment on data that might help quantify both the evaporative and exhaust emission impacts necessary to support any such action.
Proposed Program Flexibilities
Averaging, Banking, and Trading Program
As mentioned in Section V.A.2.b, we are proposing an ABT program which reduces the cost and promotes the feasibility of the program by allowing refiners and importers to choose the most economical compliance strategy (investment in technology, credits, or both) to meet the proposed Tier 3 average gasoline sulfur standard.  The program allows refiners and importers to generate standard credits for overcompliance with the 10-ppm sulfur standard beginning in 2017.  These credits could be generated indefinitely and banked or transferred to others for compliance with the average sulfur standard.  The proposed program also permits refiners and importers to generate early credits for overcompliance with today's 30-ppm average sulfur standard from 2014 to 2016.  Early credits may be used towards compliance with the 10-ppm standard beginning in 2017, banked for use through 2019, and/or transferred to other refiners or importers subject to the sulfur standard.
Eligibility
Under the ABT program, we are proposing that U.S. refiners who produce gasoline by processing crude oil and/or intermediate feedstocks through refinery processing units are eligible to generate both early credits (2014-2016) and standard credits (2017 and later).  As proposed, importers are also eligible to generate both early and standard sulfur credits on gasoline imported into the United States.
We are proposing that sulfur credits may only be generated for gasoline that is subject to the proposed sulfur requirements as described at §80.1603.  This excludes gasoline designated for export.  It also excludes California gasoline (gasoline produced or imported for use in California) but includes gasoline produced by California refineries for use outside the state.  Although California gasoline is not covered by our proposed sulfur program, we seek comment on whether to include California gasoline in the ongoing ABT program under Tier 3 (not the early credit program).  The result would be a national 10-ppm average gasoline sulfur standard.  This approach could provide some additional compliance flexibility to refiners, but it would also require reporting of batch data to EPA for California gasoline.
We have received inquiries whether fuel ethanol producers or blenders should be eligible to generate credits under the proposed gasoline sulfur program.  Denatured fuel ethanol currently contains around 9 ppm sulfur on average, ranging anywhere from 2 to almost 30 ppm. While certain batches of ethanol could theoretically be low enough in sulfur to generate credits, it is our desire to limit credit generation to companies required to comply with the proposed Tier 3 sulfur standards, i.e., refiners and importers.  Experience in the unleaded gasoline program suggests widespread abuse and fraud when credits have been allowed to be generated or sold by non-obligated parties.  Thus, in order to allow ethanol producers (or blenders) to generate sulfur credits under Tier 3, they would need to be treated as refiners and subject to our batch testing, reporting, and recordkeeping requirements for the finished gasoline they produce.  Currently, downstream blenders are exempt from these regulations because the certification and compliance burden is being borne by the upstream refiners.  Furthermore, since many refiners currently comply with our standards taking into consideration the fuel property changes expected as a result of downstream ethanol blending, providing ethanol blenders with sulfur credit would result in double counting the effects of ethanol.  To avoid this, we would need to restructure our gasoline regulations to shift the point of compliance to the many terminals and bulk plants where ethanol is blended and finished gasoline is produced instead of the refinery gate.  While possible, this would significantly expand the amount of sampling, testing, recordkeeping, and reporting required to demonstrate compliance with our gasoline standards.  It would also considerably expand the amount of sampling, testing, recordkeeping, and reporting required of ethanol blenders.  As discussed in Section V.C, we are proposing a cap of 10 ppm on the sulfur content of denatured fuel ethanol (DFE).  Over compliance with the per-gallon cap would not be a valid basis for credit generation, as you would expect that in all cases the DFE would be below the cap.  To allow credit generation, we would need to propose an additional annual average sulfur standard for DFE at some level below 10 ppm, and allow credits to be generated for over compliance with that standard.  Accordingly, we do not believe it is appropriate to allow ethanol producers or blenders to generate sulfur credits under the proposed gasoline sulfur program.
Standard Credit Generation
Under the Tier 3 ABT program, we are proposing standard credit generation provisions similar to those offered under Tier 2 as well as the MSAT2 gasoline benzene program.  We are proposing an ongoing sulfur credit program that would allow refiners and importers to average within and across companies to meet the new 10-ppm average sulfur standard in the most cost-effective manner possible.  Refiners and importers could generate standard credits for overcomplying with the 10-ppm standard on a volume-weighted annual average basis beginning January 1, 2017.  Standard credit generation periods would be 12 months long and synchronized with compliance demonstration periods.
We are proposing that small refiners and small volume refineries could generate standard credits beginning with the start of their program on January 1, 2020.  Eligible small refining entities could also generate standard credits for over compliance with the 10-ppm standard from January 1, 2017 through December 31, 2019 by voluntarily opting in to the Tier 3 sulfur program during a time period when it would otherwise not apply.  Regardless of whether they were generated early or not, all standard credits generated by small refiners and small volume refineries would be subject to the credit life provisions described in Section V.E.1.d.  For a summary of the small refiner and small volume refinery ABT provisions, refer to Section V.E.1.f.
Early Credit Generation
To encourage early gasoline desulfurization and give the refining industry flexibility to stagger their investments over time, we are proposing that refiners and importers could also generate early credits for overcomplying with today's 30-ppm gasoline sulfur standard on a volume-weighted annual average basis from January 1, 2014 through December 31, 2016.  Under the ABT program, we are proposing that refiners and importers would not need to establish a gasoline sulfur baseline or meet a trigger point in order to generate early credits.  They would simply need to demonstrate that their average U.S. gasoline sulfur levels are below today's 30-ppm Tier 2 standard during the early credit generation period.  We believe this simple early credit approach is possible because U.S. gasoline is currently averaging around 30 ppm today based on compliance data.  Since during the proposed early credit generation period refiners and importers would need to continue to comply with the existing Tier 2 sulfur standards, absent Tier 3, they would need to maintain this level of performance on an industry average basis.  Accordingly, any additional gasoline sulfur reductions beyond 30 ppm could thus be attributed to the proposed Tier 3 program.
Refiners and importers supplying gasoline containing less than 30 ppm sulfur from January 1, 2014 through December 31, 2016 could choose from generating either standard credits under the existing Tier 2 program or early credits under the proposed Tier 3 program, but not both (at least not for the same volume of gasoline).  Sulfur credits would be generated on an annual average basis.  Refiners and importers could make the decision at the end of the year whether credits generated in 2014, 2015 or 2016 would be more valuable used/traded to comply with the Tier 2 program or banked for the Tier 3 program.  Some year-end credits could be designated as Tier 2 and some designated as Tier 3 provided the same volume of gasoline was only used to generate one type of credit.  We believe that the proposed early credit program structure is the simplest approach to giving refiners and importers incentive for doing more sulfur control earlier than required and providing additional lead time to meet the Tier 3 annual average standard.  We seek comments on alternative ways to structure the early credit program to help ease the transition from Tier 2 to Tier 3.
Under past fuel programs (e.g., MSAT2), we precluded importers from generating early credits under the premise that they did not need additional lead time to comply with our fuel standards because, most likely, they would not be investing in new refining technologies.  We also thought it would be difficult for them to establish representative baselines from which early credits could be generated.  Since we are not proposing early credit baselines under Tier 3, as discussed above, we are proposing to allow importers to generate early credits for sending over-compliant gasoline to the United States prior to the start of the program, but seek comment on the appropriateness of doing so.
Credit Life Provisions
Under the Tier 3 ABT program, we are proposing that early credits must be used towards compliance within three years from the start of the program; otherwise they would expire and become invalid.  In other words, early credits must be applied towards the 2017, 2018 or 2019 compliance years.  After February 29, 2020, all early credits would expire and become invalid.  The proposed three-year early credit life provision would offer considerable flexibility to refiners phasing in Tier 3 gasoline sulfur controls while still placing a 2020 end date at which point the intended sulfur program is fully implemented and enforceable.  It would provide a date certain by when auto manufacturers could have confidence for the design of their vehicles that all vehicles in-use are running on 10 ppm average fuel.  Otherwise, it is possible that the greater ease of generating early credits relative to 30 ppm sulfur (as opposed to 10 ppm in 2017 and beyond) could allow higher sulfur levels to continue well beyond 2019.  Refiners that are able to generate early credits may choose to hold onto them for later use, rather than trade them to other refiners who may need them sooner. The proposed three-year early credit life provision would also be consistent with the duration of the small volume refinery provisions described below.  We seek comment on the lifetime of early credits and the implications on in-use sulfur levels beyond 2019 should we allow them to have a longer credit life.
We are proposing that standard credits must be used within five years from the year they were generated (regardless of when/if they are traded); otherwise they would expire and become invalid.  For example, standard credits generated in 2017 could be applied towards 2018-2022 compliance, as well as 2017 compliance.  After February 28, 2023, standard credits generated in 2017 would expire and become invalid.  Similarly, standard credits generated in 2018 could be applied towards 2019-2023 compliance, as well as 2018 compliance.  After February 29, 2024, standard credits generated in 2018 would expire, and so on and so forth.
We believe the five-year standard credit life provision, when final, would give refiners and importers sufficient time to use credits generated in previous years while still placing limitations on credit life that would help with enforcement.  Five years is consistent with the proposed recordkeeping and reporting requirements (described in more detail in Section V.F.1) as well as the current Tier 2 and MSAT2 standard credit life provisions.
Credit Trading Provisions
It is possible that sulfur credits could be generated by one party, subsequently transferred or used in good faith by another, and later found to have been calculated or created improperly or otherwise determined to be invalid.  If this occurs, as in past fuel programs, we are proposing that both the seller and purchaser would have to adjust their sulfur calculations to reflect the proper credits and either party (or both) could be determined to be in violation of the standards and other requirements if the adjusted calculations demonstrate noncompliance with the 10-ppm standard.
Under the proposed Tier 3 ABT program, sulfur credits must be transferred directly from the refiner or importer generating them to the party using them for compliance purposes.  This ensures that the parties purchasing them are better able to assess the likelihood that the credits are valid.  An exception exists where a credit generator transfers credits to a refiner or importer who inadvertently cannot use all the credits.  In this case, the credits could be transferred a second time to another refiner or importer.  After the second trade, the credits must be used or they would be terminated.  Allowing a maximum of two trades is consistent with other recent fuel programs and we believe it is sufficiently flexible while still preserving adequate means for enforcement.  Nonetheless, we seek comment on the need for allowing more than two trades for sulfur credits under the proposed Tier 3 program.
There are currently no prohibitions against brokers facilitating the transfer of credits from one party to another.  Any person can act as a credit broker, regardless of whether such person is a refiner or importer, as long as the title to the credits is transferred directly from the generating refiner or importer to the using refiner or importer.  This prohibition on outside parties taking ownership of credits was promulgated in response to problems encountered during the unleaded gasoline program and has since appeared in subsequent fuels rulemakings.  Maintaining this prohibition would allow for maximum program enforceability and consistency with all of our other ABT programs for mobile sources and their fuels.  Nonetheless, we seek comment on the need for this restriction under the proposed Tier 3 program.
      Summary of ABT Provisions for Small Refiners and Small Volume Refineries
We are proposing that small refiners and small volume refineries would have an additional three years to comply with the 10-ppm annual average standard, or until January 1, 2020.  This is the primary form of relief offered to small refining entities under the proposed Tier 3 gasoline sulfur program.  The proposed credit provisions are similar to those offered to non-small refiners.  Eligible small refiners and small volume refineries would be able to generate early credits for overcomplying with the 30-ppm Tier 2 standard from January 1, 2014 through December 31, 2016.  Like non-small refiners, they would need to make the decision whether these credits would be more valuable under the Tier 2 program or the proposed Tier 3 program.  While early credits could help postpone investments by up to three years, they could not be used by small refiners or small refineries to postpone sulfur investments beyond their January 1, 2020 start date.  However, early credits generated by small entities from 2014-2016 could be traded/sold to non-small refiners subject to the January 1, 2017 standard and the credit revenues could be used to help offset their Tier 3 investments.
As explained above, small refiners and small volume refineries could generate standard credits relative to the 10-ppm standard beginning with the start of their program on January 1, 2020.  Eligible small refining entities could also generate standard credits for over compliance with the 10-ppm standard from January 1, 2017 through December 31, 2019 by voluntarily opting in to the Tier 3 sulfur program earlier than required.  Regulatory flexibility provisions offered to small refiners and small volume refineries are described in more detail below.
Regulatory Flexibility Provisions
Small Business Regulatory Flexibility Provisions
As in previous fuel 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 gasoline sulfur program, we evaluated the environmental need as well as the technical and financial ability of refiners and others in the fuel industry to meet the sulfur 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 refiners 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 regulatory flexibility provisions for small entities in the fuels industry to reduce the burden that our proposed program could have on them.
Small entities generally lack the resources that are available to larger companies, including those large companies that own small-capacity refineries, to raise capital for investing in a new regulatory program, such as shifting of internal funds, securing of financing, or selling of assets.  Small entities are also likely to have more difficulty in competing for any needed engineering and construction resources.  As such, we are proposing provisions that would provide assistance 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 raise capital for new fuel desulfurization equipment or to make any other needed changes.  We believe that small business regulatory flexibilities could provide these entities with additional help and/or time to accumulate capital internally or to secure capital financing from lenders, and could spread out the availability of any needed engineering and construction resources.
Delayed Standards for Small Refiners
As explained in Sections V.A.1.c and V.E.1.f, we are proposing an option that would allow small refiners to postpone compliance with the Tier 3 program for up to three years.  This delayed compliance schedule for small refiners is not intended as an opportunity for those refiners to greatly expand their production of >10 ppm sulfur gasoline, but rather would help small refiners with compliance with the program.  Since the compliance costs for their competitors would rise during these three years and since their gasoline would be sold into the same fungible market, this delay would not only provide them more lead time, but also financial support towards later compliance.  Small refiners choosing this option would have from January 1, 2017 through December 31, 2019 to continue production of gasoline with an average sulfur level of 30 ppm (per the Tier 2 gasoline sulfur program).  Compliance with the 10-ppm sulfur standard would begin on January 1, 2020.  Any small refiner choosing this option would be allowed to continue using Tier 2 gasoline sulfur credits through December 31, 2019 to meet their refinery average 30-ppm sulfur standard (however, these credits may not be used for compliance with the proposed Tier 3 10-ppm average sulfur standard).
Refinery Gate and Downstream Caps
During the Small Business Regulatory Enforcement Fairness Act (SBREFA) Panel process, small refiners raised the concern that a refinery gate cap of 20 ppm could cause problems during a refinery turnaround or an upset because a cap of this level could result in a refiner not being able to produce saleable gasoline.  The Panel likewise had concerns that a downstream cap of 25 ppm may cause problems for small downstream entities such as transmix processors because, as they noted in their comments during the Panel process, transmix processors may not be able to reprocess finished gasoline down to this level.  Thus, the Panel recommended that EPA assess and request comment on retaining the current Tier 2 refinery gate and downstream caps of 80 and 95 ppm, respectively, to help provide maximum flexibility and avoid system upsets for the entire refining and distribution system.  Further, the Small Business Administration (SBA) and Office of Management and Budget (OMB) Panel members recommended that EPA propose retaining the 80-ppm and 95-ppm caps.  The Panel also recommended that, if EPA were to propose caps lower than 80 and 95 ppm, the Agency request comment on additional refinery gate and downstream caps that are above 20/25 ppm but below 80/95 ppm.
As discussed in Section XI.C, we are proposing to either maintain the current 80/95 ppm caps or to lower them to 50/65 ppm.  Should we lower the caps to 50/65 ppm, given the stringency of the 10-ppm average standard, we anticipate that they would provide the same level of flexibility for refiners, pipelines, terminals, transmix processors, and gasoline additive manufacturers as the current 80/95 ppm caps.  Should we lower the caps to 50/65, we are proposing to allow the current Tier 2 80-ppm refinery gate cap to remain in place through December 31, 2019.  Compliance with the 50-ppm refinery gate cap would begin on January 1, 2020, when the 10-ppm average sulfur standard is required for all refiners.  Similarly, we are proposing to allow the Tier 2 95-ppm downstream cap to remain in effect through February 29, 2020.  Compliance with the 65-ppm downstream cap would begin on March 1, 2020.  For more information on the proposed cap provisions, refer to Section V.A.3.
Credit-related Flexibilities
As described above in Section V.E.1, we are proposing an ABT program.  Refiners and importers would be able to generate early sulfur credits from January 1, 2014 through December 31, 2016 relative to the current 30-ppm Tier 2 average sulfur standard (i.e., credits may be generated for any reductions below 30 ppm prior to the start of the general Tier 3 program).  Beginning January 1, 2017 standard credits may be generated for overcompliance with the proposed 10-ppm Tier 3 sulfur standard.  In addition, small refiners and small volume refineries would be able to generate standard credits from January 1, 2017 through December 31, 2019 for reductions below 10 ppm prior to their proposed program start date of January 1, 2020.
During the SBREFA Panel process, one Small Entity Representative (SER) commented that importers should be allowed to participate in the credit program.  In previous EPA fuel programs, importers have generally been treated as refiners, except for the purposes of early credit generation.  Refiners have historically been required to establish a baseline in order to generate early credits.  Importers generally do not have a specific baseline or amount of fuel that they import in a given year, so participation in the early credit market would not have been feasible under those programs.  However, under the proposed Tier 3 sulfur program, refiners and importers are not required to establish baselines; the existing 30-ppm Tier 2 standard serves as the "baseline."  Therefore, as discussed above in Section V.E.1.c, we are proposing to allow importers to participate in the early credit program as well as the ongoing standard credit program.
Gasoline Additive Manufacturers
During the SBREFA Panel process, some gasoline additive manufacturing SERs raised the concern that they would have difficulty meeting a 25-ppm per-gallon sulfur cap, and the Panel recommended that EPA request comment on whether or not gasoline additives should be allowed to remain at levels above 25 ppm sulfur, and on potential methods for ensuring that bulk additives do not increase the sulfur level of the resultant fuel blend.  However, as discussed above and in Section V.A.3, we are proposing to either retain the current 80/95 ppm caps or only go to 50/65 ppm.  Both of these options would have the same 15-ppm differential between the refinery gate and downstream caps, thus we are not proposing any additional provisions for gasoline additives beyond what already exists under the current Tier 2 program.
Small Volume Refinery Provisions
During the development of this proposal and throughout the SBREFA process, it became evident that some refineries may experience higher compliance costs on a per-gallon basis than other refineries, and in some cases considerably higher.  It also became apparent that in many of these cases it was not necessarily a refinery owned by a refiner/company that would meet the SBA definition of a small business (however, these refineries tend to be small volume refineries).  In an oversupplied gasoline market, these refineries may have difficulty justifying capital investments to comply with the proposed sulfur standard.  In recognition of this concern under the RFS program, Congress granted all small refineries with a crude oil throughput of less than or equal to 75,000 barrels per calendar day (bpcd) additional time to comply.  As such, we are also proposing delayed Tier 3 sulfur standards for approved small volume refineries.  Overall, we believe that these small refineries are disproportionally impacted when it comes to their cost of compliance and ability to rationalize the 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.  We are proposing that approved small volume refineries would receive a three-year delay (January 1, 2017 through December 31, 2019) in meeting the 10-ppm average gasoline sulfur standard, similar to the small refiner delay.  Credit generation opportunities for approved small volume refineries would be identical to those proposed for small refiners as described in Section V.E.1.f.
A refiner would need to apply and be approved for small volume refinery status.  We are proposing a small volume refinery net crude throughput of less than or equal to 75,000 bpcd, and we request comment on whether or not a different crude throughput would be more appropriate.  To determine compliance with this threshold, we propose to base the crude throughput on the highest crude throughput for either the 2010 or 2011 calendar years.
Provisions for Refiners Facing Hardship Situations
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.  EPA would determine appropriate hardship relief based on the nature and degree of the hardship, as presented by the refiner in their hardship application, and on our assessment of the credit market.
In addition to the unforeseen circumstances and extreme hardship circumstances waivers being proposed today and discussed in more detail below, the Panel also recommended that EPA request comment on the concept of long-term cap relief should we lower the sulfur caps below the current 80/95-ppm level if the circumstances both warrant it and can be structured in a way to allow for it.  Such a provision may require segregation of their fuel through to the retail station in order for it not to preclude enforcement on the gasoline supplied by other refiners serving the area.  Therefore, in providing comment on such a hardship provision, please also comment on potential compliance and enforcement mechanisms to account for such longer-term relief, e.g., fuel segregation, tracking, reporting and recordkeeping, etc.
Temporary Waivers Based on Unforeseen Circumstances
We are proposing a provision which, at our discretion, would permit any refiner to seek a temporary waiver from the Tier 3 sulfur standards under certain rare circumstances.  This waiver provision is similar to provisions in existing fuel regulations.  It is intended to provide refiners relief in unanticipated circumstances - such as a refinery fire or a natural disaster (i.e., force majeure) - that cannot be reasonably foreseen now or in the near future.  Under this provision, a refiner could seek a hardship waiver for relief if it could demonstrate that the magnitude of the impact was so severe as to require such an extension.  We are proposing that the refiner would be required to show that: (1) the waiver would be in the public interest; (2) the nonconformity was unavoidable; (3) it would meet the proposed Tier 3 standards as expeditiously as possible; (4) it would make up the air quality detriment associated with the nonconforming gasoline, where practicable; and (5) it would pay to the U.S. Treasury an amount equal to the economic benefit of the nonconformity less the amount expended to make up the air quality detriment.  These conditions are similar to those in previous fuels regulations, and are necessary and appropriate to ensure that any waivers granted would be limited in scope.
As discussed, such a request would be based on the refiner's inability to produce compliant gasoline at the affected facility due to extreme and unusual circumstances outside the refiner's control that could not have been avoided through the exercise of due diligence. The hardship request would also need to show that other avenues for mitigating the problem, such as the purchase of credits toward compliance under the proposed credit provisions, had been pursued and yet were insufficient or unavailable.  In light of the proposed flexibilities including the ABT program, we expect that the need for such requests would be rare.
Temporary Waivers Based on Extreme Hardship Circumstances
In addition to the provision for short-term relief in extreme unforeseen circumstances, we are also proposing a hardship provision where a refiner could receive a hardship waiver based on severe economic or physical lead time limitations of the refinery to comply with the Tier 3 standards at the start of the program.  A refiner seeking such hardship relief under this proposed rule would have to demonstrate that these criteria were met.  In addition to showing that unusual circumstances exist that impose extreme hardship in meeting the proposed standards, the refiner would have to show that: (1) it has made best efforts to comply, including through the purchase of credits; (2) the relief granted under this provision would be in the public interest; (3) the environmental impact would be acceptable; and (4) it has active plans to meet the requirements as expeditiously as possible.  We expect that hardship relief requests under this provision would mostly be applicable at the beginning of the Tier 3 program, when refiners are making their investments to comply.  If hardship relief under these circumstances was approved, we would expect to impose appropriate conditions to ensure that the refiner was making best efforts to achieve compliance offsetting any loss of emission control from the program.  We believe that providing short-term relief to those refiners that need additional time due to hardship circumstances would help to facilitate the adoption of the overall Tier 3 program for the majority of the industry.  However, we do not intend for hardship waiver provisions to encourage refiners to delay planning and investments they would otherwise make.  Again, because of the flexibilities of the proposed overall program, we expect that the need for additional relief would be rare.
Compliance Provisions
For the most part, the proposed Tier 3 sulfur standards simply reflect a lowering of the current Tier 2 sulfur standards.  Thus, we are proposing to retain most of the same compliance provisions as the current Tier 2 program, with exceptions as noted.  However, we are also proposing and seeking comment on several fuel program regulatory streamlining measures, including a broader program redesign to streamline the reformulated gasoline and anti-dumping regulations.  Some of these streamlining measures, if adopted, may also impact the Tier 3 sulfur compliance provisions proposed below.
Registration, Reporting, and Recordkeeping Requirements
Registration, recordkeeping, and reporting are necessary to track compliance with the Tier 3 standards and the ABT program.  This section describes the proposed compliance provisions of today's program.
Registration Requirements
We are proposing that refiners, importers, and anyone acting as a refiner (e.g., a terminal with blending or other refining operations) who expects to produce or import gasoline would be required to register each of its facilities with EPA by June 1, 2016, or six months prior to producing gasoline meeting the Tier 3 standards and/or participating in the credit program.  After the program begins on January 1, 2017, any non-registered parties must register at least three months prior to producing gasoline or participating in the credit market under the Tier 3 program.  Most refiners, importers, and ethanol producers are currently registered with EPA under other 40 CFR part 80 fuels programs.  We are proposing that those who are already registered would not have to register again.
For registration, we are proposing to use the same basic forms that previous fuels programs have used.  These forms are well known in the regulated community and are simple to fill out.  Upon receipt of a completed registration form, EPA would issue a unique 4-digit company identification number and a unique 5-digit facility identification number.  As with existing fuels programs, these numbers would be required for all reports sent to EPA and for PTDs.
Registrations would not expire and would not have to be renewed; however, we are proposing that registered parties would be responsible for notifying us of any change to their company or facility information.
An entity's registration must include a corporate name and address (including the name, telephone number, and e-mail address of a corporate contact); and, for each facility operated by the entity:
Type of facility (e.g., refinery, import facility, pipeline, terminal, transmix facility, etc.)
Facility name
Physical location
Contact name, telephone number, and e-mail address
Reporting Requirements
We are proposing to require refiners and importers to submit annual reports demonstrating their compliance with the Tier 3 standards and on the generation, use, and transfer of sulfur credits at each of its refineries or import facilities.  Similar to our other sulfur programs, we are also proposing to require refiners and importers to submit data on individual batches of gasoline (including batch volume and sulfur content).  Based on our experience with existing gasoline and sulfur-based programs, we believe that requiring annual reports and individual sulfur batch data would provide an effective means of monitoring compliance with the standards and the credit program.
We are proposing that manufacturers of DFE and other oxygenates would be required to submit an annual report that includes the total volume of DFE/oxygenate produced and an attestation that all batches met the proposed fuel quality requirements: sulfur content, composition (i.e., composed only of carbon, hydrogen, nitrogen, oxygen, and sulfur), and denaturant concentration as applicable.
We are proposing that reports would be due annually on March 31.
Recordkeeping Requirements
Similar to current EPA fuels programs, we are proposing that refiners and importers would be required to retain all records that demonstrate compliance with the Tier 3 program, including ABT program information.
We are proposing that manufacturers of DFE and other oxygenates would be required to keep records on individual batches of DFE/oxygenate (including batch volume, sulfur content, and denaturant concentration as applicable).
All parties in the gasoline production and distribution system subject to today's proposed rule would also be required to keep records of all PTDs and records of any quality assurance programs.  Records would need to be retained for five years.  For credit transactions, records would need to be retained for five years from the usage date.  Records would need to be made available to EPA on request.  We are also proposing that if electronic records are kept, hard copies should be made available upon request.
We are proposing to allow parties to claim information submitted to EPA as confidential business information (CBI).  Parties making such a claim would be required to follow all reporting guidance and clearly mark the information being claimed as proprietary.  EPA would treat information covered by such a claim in accordance with the regulations at 40 CFR part 2 and other Agency procedures for handling proprietary information.
Sampling and Testing Requirements
Under the Tier 2 program, a sulfur concentration must be determined for every batch of gasoline.  We are proposing to retain that requirement under Tier 3.  As with the Tier 2 program, this every batch testing requirement would be required to occur prior to the batch leaving the refinery.  We are proposing to retain the current sampling, testing, and sample retention requirements.  However, as discussed below in Section VI.A.3, we are proposing performance based measurement standards that would allow refiners to use alternate test methods for measuring sulfur.
We are proposing that manufacturers of DFE would be required to test each individual batch of DFE for its sulfur content.
We request comment on these elements related to sampling and testing, as well as the sampling and testing requirements in the proposed regulations.
Small Refiner Compliance
To qualify for small refiner status under the Tier 3 program, we are proposing that a refiner must apply by July 1, 2013.  As with our other EPA fuels programs, we are proposing to continue using the Small Business Administration definition of a small refiner: 1,500 employees (company-wide).  To qualify for small refiner status under Tier 3, we are also proposing that a small refiner must meet the following additional criteria:
The refiner must have produced gasoline from crude oil during the 2011 calendar year.
The refiner must have owned and operated the refinery during the period from January 1, 2011 through December 31, 2011.  New owners that purchased a refinery after that date would do so with full knowledge of the proposed regulations, and should have planned to comply along with their purchase decisions.  As with existing fuel programs, we are proposing that a refiner that restarts a refinery in the future may be eligible for small refiner status.  Thus, a refiner restarting a refinery that was shut down or non-operational during calendar year 2011 could apply for small refiner status.  In such cases, we would judge eligibility under the employment and crude oil capacity criteria based on the most recent 12 consecutive months prior to the application, unless we conclude from data provided by the refiner that another period of time is more appropriate.  However, we propose to limit this to a company that owned the refinery at the time that it was shut down.  New purchasers would not be eligible for small refiner status for the same reasons described above.
The refiner must have had 1,500 employees or less based on the average number of employees for all pay periods from January 1, 2011 through December 31, 2011 for all subsidiaries, parent companies (i.e., any company or companies with controlling interest), and joint ventures.
The refiner must have had a crude oil capacity less than or equal to 155,000 bpcd during the 2011 calendar year.
A refiner applying for status as a small refiner would be required to apply and provide EPA with several types of information, as specified in the regulations, by July 1, 2013.  All refiners seeking small refiner status under this program would need to apply for small refiner status, regardless of whether or not the refiner had been approved for small refiner status under another fuel program.  As with applications for relief under other rules, applications for small refiner status under this proposed rule that are later found to contain false or inaccurate information would be void ab initio.
Requirements for small refiner status applications:
The total crude oil capacity as reported to the Energy Information Administration (EIA) of the U.S. Department of Energy (DOE) for the most recent 12 months of operation.  This would include the capacity of all refineries controlled by a refiner and by all subsidiaries and parent companies and joint ventures. We would presume that the information submitted to EIA is correct. (In cases where a company disagreed with this information, the company could petition EPA with appropriate data to correct the record when the company submitted its application for small refiner status.  EPA could accept such alternate data at its discretion.)
The name and address of each location where employees worked during the 2011 calendar year; and the number of employees at each location during this time period.  This would include the employees of the refiner and all subsidiaries and parent companies and joint ventures.
In the case of a refiner who reactivates a refinery that was either shutdown or non-operational from January 1, 2011 through December 31, 2011, the name and address of each location where employees worked since the refiner reactivated the refinery and the average number of employees at each location for each calendar year since the refiner reactivated the refinery.
The type of business activities carried out at each location.
Contact information for a corporate contact person, including: name, mailing address, phone and fax numbers, e-mail address.
A letter signed by the president, chief operating officer, or chief executive officer of the company (or a designee) stating that the information contained in the application was true to the best of his/her knowledge and that the company owned the refinery as of January 1, 2011.
We are proposing that an approved small refiner that exceeds the employee count or crude capacity criteria due to merger with, acquisition by, or the acquisition of another entity will lose its small refiner status.  In situations where a small refiner loses its small refiner status due to merger with a non-small refiner, acquisition of another refiner, or acquisition by another refiner, we are proposing provisions which are similar to those in our existing fuels programs to allow an additional 30 months of lead time to comply with the Tier 3 program after the disqualifying event.    The proposed 30 months of additional lead time would only apply to refineries that had previously been subject to small refiner relief, as we believe there would be no adverse environmental impact because of the pre-existing relief provisions that applied to the small refiner.  We are also proposing that a refiner would lose its small refiner status if it ceases to process crude oil.
Our intent has been, and continues to be, limiting the small refiner relief provisions to a small subset of refiners that are challenged, as discussed above.  However, it is also our intent to avoid stifling normal business growth.  Therefore, we are proposing that an approved small refiner who exceeds the employee count or crude oil capacity criteria through normal business practices, may retain its small refiner status.  Further, in the sole case of a merger between two approved small refiners we are proposing to allow such refiners to retain their small refiner status.  Additional financial resources would not typically be provided in the case of a merger between two small refiners.  Small refiner status for the two entities of the merger would not be affected; hence the original compliance plans of the two refiners should not be impacted.  Moreover, no environmental detriment would result from the two small refiners maintaining their small refiner status within the merged entity as they would have likely maintained their small refiner status had the merger not occurred.
We request comment on whether or not these provisions remain appropriate.
Small Volume Refinery Compliance
In the case of small volume refineries, the application process for qualification is similar to that of a small refiner.  A refiner that is both a small refiner and owns a small volume refinery need not apply for small volume refinery status; the small refiner application is all that is needed.  We are proposing a net crude throughput threshold of no more than 75,000 bpcd based on the highest throughput in calendar years 2010 or 2011 as the basis for receiving small volume refinery status.  We request comment on whether or not another threshold would be more appropriate.
We are proposing that refiners would need to include the following in their applications:
Proof that the refiner produced gasoline from crude oil during the 2011 calendar year.
Proof that the refiner owned and operated the refinery during the period from January 1, 2011 through December 31, 2011.
The refinery's total crude throughput as reported to EIA for each of calendar years 2010 and 2011.  Again, we would presume that the information submitted to EIA is correct.  In cases where a refiner disagrees with this information, the refiner could petition EPA with appropriate data to correct the record when the refiner submits its application for small volume refinery status.  EPA could accept such alternate data at its discretion.
Contact information for a corporate contact person, including: name, mailing address, phone and fax numbers, e-mail address.
A letter signed by the president, chief operating officer, or chief executive officer of the company (or a designee) stating that the information contained in the application was true to the best of his/her knowledge and that the company owned the refinery as of January 1, 2011.
Attest Engagements, Violations, and Penalties
We are proposing to retain the Tier 2 requirements for attest engagements for generation of both early and standard credits, use of credits, and compliance with the proposed program, using the procedures used in other EPA fuels programs for attest engagements.  The violation and penalty provisions applicable to today's proposed program would be very similar to the provisions currently in effect in other gasoline programs as well.  We request comment on the need for additional attest engagement, violation, penalty, or any other compliance and enforcement related provisions specific to the proposed Tier 3 program.
Special Fuel Provisions and Exemptions
The following paragraphs discuss several provisions and exemptions for gasoline that we are proposing would apply in special circumstances.
Gasoline Used in Military Applications
In our diesel fuel program, we provided an exemption for diesel fuel used in tactical military vehicles and nonroad engines and equipment with a national security exemption (NSE) from the vehicle and engine emissions standards.  Due to national security considerations, some of EPA's existing regulations allow the military to request and receive NSEs for vehicles, engines, and equipment from emissions regulations if the operational requirements for such vehicles, engines, or equipment warrant such an exemption.  Fuel used in these applications would also be exempt if it is used in tactical military vehicles, engines, or equipment that are not covered by an NSE but, for national security reasons (such as the need to be ready for immediate deployment overseas), these  applications need to be fueled on the same fuel as  those with an NSE.  We are proposing this exemption under the proposed Tier 3 gasoline program.
Gasoline Used in Research, Development, and Testing
Similar to other EPA fuels programs, we are proposing to allow requests for an exemption from the Tier 3 standards for gasoline used for research, development, and testing purposes ("R & D exemption").  We recognize that there may be legitimate research programs that require the use of gasoline with sulfur levels greater than those allowed under the proposed Tier 3 program.  Thus, we are proposing provisions for obtaining an exemption from the prohibition against persons producing, distributing, transporting, storing, selling, or dispensing gasoline that does not meet the Tier 3 gasoline sulfur standards, where such fuel is necessary to conduct a research, development, or testing program.
Parties seeking an R & D exemption would be required to submit an application for exemption to EPA that describes the purpose and scope of the program, and the reasons why the noncompliant gasoline is necessary.  Upon presentation of the required information, an exemption could be granted at the discretion of EPA, with the condition that EPA could withdraw the exemption in the event the Agency determines the exemption is not justified.  In addition, an exemption based on false or inaccurate information would be considered void ab initio.  Gasoline subject to an exemption would be exempt from certain provisions of this rule, including the sulfur standards, provided certain requirements are met.  These requirements include the segregation of the exempt gasoline from non-exempt gasoline, identification of the exempt gasoline on PTDs, and pump labeling.
Gasoline for Export
Gasoline produced for export, and that is actually exported for use in a foreign country, would be considered exempt from the fuel content standards and other requirements of this proposed rule.  Such gasoline would be considered as intended for use in the U.S. and subject to the proposed standards unless it is designated by the refiner and the PTD states that the gasoline is for "export only".  Gasoline intended for export would be required to be segregated from all gasoline intended for use in the U.S.  Distributing or dispensing such fuel for domestic use would be illegal.
Other Special Provisions and Potential Exemptions
We are proposing provisions for Alaska that would allow the refinery gate and downstream caps to remain at the current Tier 2 80-ppm and 95-ppm levels, respectively, should the caps be lowered to 50 and 65 ppm (per Section V.A.3).
Additionally, in previous fuels programs we have included exemptions for racing fuel and for fuel used in the U.S. territories of Guam, American Samoa, and the Northern Mariana Islands.  We request comment on whether or not such exemptions would be needed for this program.
Statutory Authority for Proposed Tier 3 Fuel Controls
We are proposing gasoline sulfur controls under our authority in section 211(c)(1) of the Clean Air Act.  This section gives us the authority to "control or prohibit the manufacture, introduction into commerce, offering for sale, or sale" of any fuel or fuel additive for use in a motor vehicle, motor vehicle engine, or nonroad engine or nonroad vehicle (1) whose emission products, in the judgment of the Administrator, cause or contribute to air pollution which may reasonably be anticipated to endanger the public health or welfare [section 211(c)(1)(A)] or (2) whose emission products will impair to a significant degree the performance of any emission control device or system which is in general use, or which the Administrator finds has been developed to a point where in a reasonable time it would be in general use were the fuel control or prohibition adopted [section 211(c)(1)(B)].  We are proposing controls on gasoline sulfur levels based on both of the Clean Air Act criteria, as described in more detail below.
Section 211(c)(1)(A)
Under the first criterion, we believe that emission products of gasoline with current levels of sulfur contribute to ambient levels of ozone, particulate matter (PM), nitrogen dioxide (NO2), sulfur dioxide (SO2) and carbon monoxide (CO), which are all pollutants for which EPA has established National Ambient Air Quality Standards (NAAQS).  These pollutants are linked with respiratory and/or cardiovascular problems and other adverse health impacts leading to increased medication use, hospital admissions, emergency department visits, and premature mortality.  Approximately 159 million people currently live in counties exceeding a NAAQS.   Motor vehicles also emit air toxics, and the majority of Americans continue to be exposed to ambient concentrations of air toxics at levels which have the potential to cause adverse health effects, including cancer, immune system damage, and neurological, reproductive, developmental, respiratory, and other health problems.  A more detailed discussion of the health and environmental effects of these pollutants is included in Section II.B.  As discussed in this section, emissions of these pollutants cause or contribute to ambient levels of air pollution that are reasonably anticipated to endanger public health and welfare.  Control of gasoline sulfur to 10 ppm will lead to significant, cost-effective reductions in emissions of these pollutants, with the benefits to public health and welfare significantly outweighing the costs.
EPA has evaluated the technical feasibility of achieving these sulfur levels, including the cost of the reductions and the impact on fuel supply.  As discussed in Section V.A, we have concluded that these reductions are feasible in the lead time provided and should not have an adverse impact on the adequacy of gasoline fuel supply to meet demand.  For more on the feasibility of the proposed fuel program, refer to Chapter 4 of the draft RIA.
As discussed in Section III, EPA also evaluated the emissions reductions from pre-Tier 3 vehicles that would be achieved by controlling gasoline sulfur levels.  These reductions are significant and contribute to the total monetized health benefits.  EPA also evaluated the cost per ton of emissions reduced for the proposed program, of which the 10-ppm sulfur standard is a part.  As can be seen in Section VII.D, the program is very cost-effective in 2030.  Even in 2017, when the emission reductions are almost entirely due to the sulfur standards (and the costs are attributed to both the fuel and vehicle standards), the cost-effectiveness of the program is reasonable.  In sum, EPA concludes that the entire body of evidence strongly supports the view that controlling gasoline sulfur to 10 ppm is quite reasonable in light of the emissions reductions and benefits achieved, taking costs into consideration.  For more detail on the costs and benefits of the proposed standards, refer to Chapter 8 of the draft RIA.
The control of gasoline sulfur down to 10 ppm provides significant reductions in harmful emissions.  The fuel program is cost-effective and produces benefits to public health and welfare whose value significantly outweighs the costs.  These reductions can be achieved in a manner that is technologically feasible, and will not disrupt fuel supply.
Section 211(c)(2)(A) requires that, prior to adopting a fuel control based on a finding that the fuel's emission products contribute to air pollution that can reasonably be anticipated to endanger public health or welfare, EPA must consider "all relevant medical and scientific evidence available, including consideration of other technologically or economically feasible means of achieving emission standards under [section 202 of the Act]."  EPA's analysis of the medical and scientific evidence relating to the emissions impact from motor vehicle engines, which are impacted by gasoline sulfur, is described in more detail in Chapter 6 of the draft RIA.  EPA has also satisfied the statutory requirement to consider "other technologically or economically feasible means of achieving emission standards under section [202 of the Act]."  This provision has been interpreted as requiring consideration of establishing emission standards under section 202 prior to establishing controls or prohibitions on fuels or fuel additives under section 211(c)(1)(A).  See Ethyl Corp. v. EPA, 541 F.2d. 1, 31-32 (D.C. Cir. 1976).  In Ethyl, the court stated that section 211(c)(2)(A) calls for good faith consideration of the evidence and options, not for mandatory deference to regulation under section 202 compared to fuel controls. Id. at 32, n.66.  EPA is also proposing Tier 3 emissions standards for motor vehicles under section 202.  In order to meet these more stringent standards, the program requires a reduction in the sulfur content of gasoline to the 10-ppm annual average.
Section 211(c)(1)(B)
Under the second criterion, we believe that sulfur in gasoline will significantly impair the emission-control systems expected to be in general use in motor vehicle engines designed to meet the Tier 3 emission standards proposed in this rule.  EPA is proposing to restrict gasoline sulfur content to an annual average of 10 ppm beginning in 2017, to enable compliance with new emission standards based on the use of advanced emission control technology that will be available to Tier 3 engines and California's Low Emission Vehicle (LEV III) program.
Section IV describes the substantial adverse effect of high gasoline sulfur levels on the emission-control devices or systems for Tier 3 vehicles and engines meeting the proposed emission standards.  As discussed in Section IV.A.6, modern three-way catalytic exhaust systems utilize platinum group metals (PGM), metal oxides, and other active materials to selectively oxidize organic compounds and carbon monoxide in the exhaust gases.  These systems simultaneously reduce nitrogen oxides when air-to-fuel ratio control operates in a condition of relatively low amplitude/high frequency oscillation about the stoichiometric point.  Sulfur is a well-known catalyst poison.  There is a large body of work demonstrating sulfur inhibition of the emissions control performance of PGM three-way exhaust catalyst systems.  The nature of sulfur interactions with washcoat materials, active catalytic materials and catalyst substrates is complex and varies with catalyst composition and exhaust gas composition and exhaust temperature.  The variation of these interactions with exhaust gas composition and temperature means that the operational history of a vehicle is an important factor; continuous light-load operation, throttle tip-in events and enrichment under high-load conditions can all impact sulfur interactions with the catalyst.
Operating the catalyst at a sufficiently high temperature under net reducing conditions (e.g., air-to-fuel equivalence that is net fuel-rich of stoichiometry) can effectively release the sulfur oxides from the catalyst components.  Thus, regular operation at sufficiently high temperatures at rich air-to-fuel ratios can minimize the effects of fuel sulfur levels on catalyst active materials and catalyst efficiency.  However, it cannot completely eliminate the effects of sulfur poisoning.  A study of Tier 2 vehicles in the in-use fleet recently completed by EPA shows that emission levels immediately following high speed/load operation is still a function of fuel sulfur level, suggesting that lower fuel sulfur levels will bring emission benefits unachievable by catalyst regeneration procedures alone.  Furthermore, regular operation at these temperatures and at rich air-to-fuel ratios is not desirable, for several reasons.  The temperatures necessary to release sulfur oxides are high enough to lead to thermal degradation of the catalyst over time via thermal sintering of active materials.  Sintering reduces the surface area available to participate in reactions.  Additionally, it is not always possible to maintain these catalyst temperatures (because of cold weather, idle conditions, light load operation) and the rich air-to-fuel ratios necessary can result in increased PM, NMOG and CO emissions.  Thus, reducing fuel sulfur levels has been the primary regulatory mechanism to minimize sulfur contamination of the catalyst and ensure optimum emissions performance over the useful life of a vehicle.
The impact of gasoline sulfur has become even more important as vehicle emission standards have become more stringent.  Some studies have suggested an increase in catalyst sensitivity to sulfur (in terms of percent conversion efficiency) when standards increase in stringency and emissions levels decrease.  Emission standards under the programs that preceded the Tier 2 program (Tier 0, Tier 1 and National LEV, or NLEV) were high enough that the impact of sulfur was considered negligible.  The Tier 2 program recognized the importance of sulfur and reduced the sulfur levels in the fuel from around 300 ppm to 30 ppm in conjunction with the new emission standards.  At that time, very little work had been done to evaluate the effect of further reductions in fuel sulfur  -  especially on in-use vehicles that may have some degree of catalyst deterioration due to real-world operation.
In 2005, EPA and several automakers jointly conducted a program that examined the effects of sulfur and other gasoline properties, benzene, and volatility on emissions from a fleet of nine Tier 2 compliant vehicles.  Subsequently, EPA conducted a much more extensive study of the effects of sulfur on emissions from Tier 2 vehicles.  These studies demonstrate that emissions from Tier 2 vehicles continue to be very sensitive to gasoline sulfur levels below the current 30-ppm average standard.  For more on the estimated emission impacts, refer to Section III.B.
Furthermore, vehicles already capable of meeting the proposed Tier 3 standards have been found to be extremely sensitive to the effects of sulfur.  A Chevy Malibu was tested and found to be able to meet the proposed Tier 3 standards on low-sulfur gasoline, but following operation on higher-sulfur gasoline, its emission levels exceeded the standard.  As explained in Section IV.A, following operation over 2 FTP cycles on 33 ppm sulfur fuel, NOX emissions alone were more than double the proposed Tier 3 30 mg/mi NMOG+NOX standard.
Overall, the Tier 3 Program would reduce fleet average NMOG+NOX emissions by over 80 percent.  The feasibility of the proposed 30 mg/mi NMOG+NOX fleet average standard depends on a degree of emissions control from exhaust catalyst systems that will require gasoline at 10 ppm sulfur or lower.  The most likely control strategies would involve using exhaust catalyst technologies and powertrain calibration primarily focused on reducing cold-start emissions of NMOG and on both cold-start and warmed-up (running) emissions of NOX.  An important part of this strategy, particularly for larger vehicles having greater difficulty achieving cold-start NMOG emissions control, will be to reduce NOX emissions to near-zero levels.  This would allow sufficient NMOG compliance margin to allow vehicles to meet the combined NMOG+NOX emissions standards for the full useful life.
Achieving the proposed Tier 3 emission standards would require very careful control of the exhaust chemistry and exhaust temperatures to ensure high catalyst efficiency.  The impact of sulfur on oxygen storage components in the catalyst makes this a challenge even at relatively low (10 ppm) gasoline sulfur levels.
The negative impact of gasoline sulfur on NOX, NMOG and air toxic emissions occurs across all vehicle categories.  However, the impact of gasoline sulfur on NOX emissions control of catalysts in the fully-warmed-up condition is particularly of concern for larger vehicles.  Manufacturers face the most significant challenges in reducing cold-start NMOG emissions for these vehicles.  Because of the need to reach near-zero NOX levels, any significant degradation in NOX emissions control over the useful life of the vehicle would likely prevent some if not most larger vehicles from reaching a combined NMOG+NOX low enough to comply with the 30 mg/mi fleet-average standard.  These vehicles represent a sufficiently large segment of light-duty vehicle sales now and in the foreseeable future that their emissions could not be offset (and thus the fleet-average standard achieved) by certifying vehicles to bins below the fleet average.  Any degradation in catalyst performance due to gasoline sulfur would reduce or eliminate the margin necessary to ensure in-use compliance with the proposed Tier 3 emissions standards.  Certifying to a useful life of 150,000 miles vs. the current 120,000 miles would further add to manufacturers' compliance challenge for Tier 3 large light trucks (refer to Section IV.7.b for more on the useful life requirements).
The impact of gasoline sulfur poisoning on exhaust catalyst performance and the relative stringency of the Tier 3 standards, particularly for larger vehicles and trucks, when considered together make a compelling argument for the virtual elimination of sulfur from gasoline.  As discussed in Section V.A.2, the proposed 10-ppm standard for sulfur in gasoline represents the lowest practical limit from a standpoint of fuel production, handling and transport. While lowering gasoline sulfur to levels below 10 ppm would help ensure in-use vehicle compliance with the Tier 3 standards, the Agency believes that a gasoline sulfur standard of 10 ppm would allow compliance with a national fleet average of 30 mg/mi NMOG+NOX.  The level of the Tier 3 standards was considered in light of a 10-ppm average sulfur level for gasoline.  Not only should a 10-ppm sulfur standard enable vehicle manufacturers to certify their entire product line of vehicles to the Tier 3 fleet average standards, but based on the results of testing both Tier 2 vehicles and SULEV vehicles as discussed above, reducing gasoline sulfur to 10 ppm should enable these vehicles to maintain their emission performance in-use over their full useful life.
Section 211(c)(2)(B) requires that, prior to adopting a fuel control based on a significant impairment to vehicle emission-control systems, EPA consider available scientific and economic data, including a cost benefit analysis comparing emission-control devices or systems which are or will be in general use that require the proposed fuel control with such devices or systems which are or will be in general use that do not require the proposed fuel control.  As described below, we conclude that the emissions control technology expected to be used to meet Tier 3 standards would be significantly impaired by operation on gasoline with annual average sulfur levels greater than 10 ppm.  Our analysis of the available scientific and economic data can be found elsewhere in this document.  The draft RIA includes a detailed analysis of the environmental benefits of the emission standards (Chapters 6 and 8), an analysis of the technological feasibility and cost of controlling sulfur to the levels established in the final rule (Chapters 4 and 5), and a cost-effectiveness analysis of the sulfur control and motor vehicle and engine emission standards (Chapter 9).  Under section 211(c)(2)(B), as just noted, EPA is also required to compare the costs and benefits of achieving emission standards through emission-control systems that would not be sulfur-sensitive, if any such systems are or will be in general use.  We have determined that there are not (and will not be in the foreseeable future) emission control devices available for general use in motor vehicles that can meet the emission standards and would not be significantly impaired by gasoline with current gasoline sulfur levels.  Emissions cannot be reduced anywhere near the magnitude contemplated by the proposed emission standards without the application of the kind of emissions control technology discussed in this proposal.
Section 211(c)(2)(C) of the Clean Air Act requires that prior to prohibiting a fuel or fuel additive, EPA establish that such prohibition will not cause the use of another fuel or fuel additive "which will produce emissions which endanger the public health or welfare to the same or greater degree" than the prohibited fuel or additive.  This finding is required by the Act only prior to prohibiting a fuel or additive, not prior to controlling a fuel or additive.  Since EPA is not prohibiting use of gasoline sulfur, but rather is controlling the level of sulfur in these fuels, this finding is not required for this rulemaking.  However, EPA does not believe that the proposed gasoline sulfur controls will result in the use of any other fuel or additive that will produce emissions that will endanger public health or welfare to the same or greater degree as the emissions produced by gasoline with current sulfur levels.  Unlike the case of unleaded gasoline in the past, where lead performed a primary function by providing the necessary octane for the vehicles to function properly, sulfur does not serve any useful function in gasoline.  It is not added to gasoline, but occurs naturally in the crude oil into which gasoline is processed.  Were it not for the expense of sulfur removal, it would likely have been removed from gasoline years ago in order to improve the maintenance and durability characteristics of motor vehicle engines.
We are also adopting the various controls for DFE, other oxygenates, butane blended into gasoline, and gasoline additives, under our authority in section 211(c)(1).  As explained above, these controls are necessary to prevent emissions products that may endanger the public health or welfare or impair to a significant degree the performance of any emission control device or system.  The proposal basically extends various controls on gasoline to DFE, other oxygenates, butane, and gasoline additives.  The reasons for adopting the controls for gasoline apply as well to adopt the controls for DFE, other oxygenates, butane, and gasoline additives.
Technical Amendments and Regulatory Streamlining
In addition to proposing new Tier 3 vehicle standards and new gasoline sulfur standards, we are also proposing and seeking comment on a number of technical amendments and regulatory streamlining actions as part of the Regulatory Review initiative.  Some of these may have some bearing on implementation of the proposed Tier 3 vehicle and fuel standards, while others deal with other aspects of EPA's existing vehicle and fuel regulations.
EPA is also proposing to synchronize a number of different reporting deadlines under various regulations affecting transportation and motor vehicle fuels and fuel additives. This action would reduce regulatory burdens by aligning reporting deadlines across several programs and would lay the foundation for the overall goal of combining various fuels reports together into a single, simplified electronic format.
Amendments to 40 CFR Parts 79 and 80
The following sections discuss our proposed changes to regulations in 40 CFR part 79 and part 80.  Some of these changes are technical amendments to correct minor errors or inconsistencies in the regulations; others are to address areas in the regulations that could benefit from clarification and/or streamlining.
With regard to regulatory streamlining, the majority of these items involve clarifying vague or inconsistent language, removal or updating of outdated provisions, and decreasing the frequency and/or volume of reporting burden where data is either no longer needed or is redundant in light of other EPA fuels programs.  In general, we believe that these changes would reduce burden on industry with no expected environmental impact.  We believe that the regulatory streamlining items that we are proposing are changes that are straightforward and that should be made quickly.  There are also additional items that would need further consideration and discussion, such as a new fuels program compliance structure, as discussed below in Section VI.A.1.b.  We are also requesting comment on expanding the downstream butane blending provisions to allow for pentane blending, as discussed in Section VI.A.4.
Regulatory Streamlining
Summary of Proposed Amendments
Below is a table listing the provisions that we are proposing to amend in today's action.  We have provided additional explanation for those amendments that warrant additional explanation below.
Table VI-1 Summary of Proposed Regulatory Streamlining and Technical Amendments
Section
Description
Varied
Various sections amended to update references to test methods (see Section Section VI.A.1.a.iii).
79.5
Revises periodic reporting requirements.
80.2
Revises and adds definitions.
80.8
Amended to update sampling test methods, and to state to which fuels §80.8 applies.
80.10
Added to allow for de minimis changes in compliance reports that would not require a resubmission of compliance reports when a minor discrepancy of a few barrels is uncovered.
80.46
Revises measurement of RFG fuel parameters.
80.47
Revises Performance-Based Test Method Approach.
80.65
Amended to reduce complex model test parameters and reporting.
80.65(f)(5)
Added to allow for designation of an alternative lab.
80.75
Revises RFG reporting requirements.
80.82
Amended to apply butane blending provisions to entire part 80 and to revise RVP test method.
80.101
Revises measurement of conventional gasoline fuel parameters.
80.105
Amended to require identification of test methods used and revises reporting requirements.
80.161(b)(1)(ii)(A)(2)
Amended to allow an alternative gasoline detergent certification option.
80.161(b)(1)(ii)(A)(3)
Added to allow an alternative detergent certification option.
80.161(b)(2)
Amended to address the submission of gasoline detergent samples under the alternative gasoline detergent certification option.
80.161(b)(3)(ii)(C)
Amended to reflect that documentation of the fuel injector deposit demonstration test would be required under the alternative detergent certification option.
80.161(b)(3)(v)
Amended to state that the results of the intake valve and fuel injector deposit demonstration test must be submitted to EPA as part of the certification letter under the alternative detergent certification option.
80.161(b)(3)(viii)
Amended to change "PFID test" to "fuel injector test".
80.161(d)(1)
Amended to reflect the availability of the alternative gasoline detergent certification option.
80.163(a)(1)(iii)
Amended to allow use of the alternative gasoline detergent certification option.
80.164(a)
Amended to reference the test fuel requirements under the alternative gasoline detergent certification option.
80.165
Amended the introductory paragraph to accommodate the alternative deposit control test procedures and standards under the alternative gasoline detergent certification option.
80.167(a)
Amended the introductory paragraph to specify how confirmatory testing would be conducted for additives certified under the alternative gasoline detergent certification option.
80.176
Added to specify the certification test procedures and standards under the alternative gasoline detergent certification option.
80.177
Added to specify the certification test fuels under the alternative gasoline detergent certification option.
80.178
Incorporates standards and test methods by reference.
80.330
Revises sampling and testing requirements.
80.370
Amended to require identification of test method used and revises reporting requirements.
80.511
Revises per-gallon and marker requirements.
80.572
Revises labeling requirements.
80.573
Revises labeling requirements.
80.574
Revises labeling requirements.
80.580
Incorporates test methods by reference.
80.585
Revises test method approval process.
80.604
Revises reporting requirements.
80.1235(a)(6),
Amended to allow refiners and importers who are blending blendstock into previously certified gasoline (PCG) an alternative to directly test the blendstock for benzene.
80.1235(a)(5)
Amended to clarify that refiners and importers may use either approach for blendstocks that are blended into either conventional gasoline or reformulated gasoline.
80.1235(b)(2)
Amended to clarify EPA's intent (per §80.1238(b)) to allow refiners and importers to include oxygenate blended downstream of a refinery or import facility in their annual average benzene calculation, and to make the section consistent with §80.1238(b).
80.1238
Revises benzene determination.

80.1347(a)(5)
Amended to require that a negative annual average must be reported as zero, and that a refiner must comply with §80.65(i) when producing RBOB or RFG and §80.101(g)(9) when producing conventional gasoline.
80.1347(a)(6)
Added to allow refiners and importers who are blending blendstock into previously certified gasoline (PCG) an alternative to directly test the blendstock for benzene.
80.1348
Revises sample retention requirements.
80.1349
Added to allow importers who import gasoline into the U.S. by truck to use the sampling and testing requirements in 40 CFR part 80 subpart E as an alternative to the sampling and testing requirements in subpart L.
80.1354
Revises reporting requirements for gasoline benzene program.
80.1451
Revises RFS reporting requirements.

        Amendments Related to Reduction of Testing for Complex Model Fuel Parameters
In §§80.65 and 80.75, we are proposing to streamline and reduce the RFG and CG testing and reporting burden of gasoline refiners and importers by reducing the testing and reporting requirements of certain fuel parameters associated with the complex model.  Currently, for RFG, every parameter listed in §80.65 must be tested for every batch and each parameter must be reported for every batch.  No monthly compositing of batch samples is allowed for any parameter.  For conventional gasoline, monthly compositing and batch reporting based on those monthly composites is allowed for all parameters except sulfur and benzene.  However, with the phasing out of complex model standards, reduced testing and reporting is appropriate, particularly for RFG.   In cases where a refiner is subject to only benzene, RVP, and sulfur standards, certain parameters no longer need to be tested and reported on an every-batch basis.  However, the full slate of complex model parameters will still be needed in some cases.  Specifically, refiners producing RFG during the summer VOC control season will still need to use the complex model to determine VOC performance, and thus must still measure and report the relevant complex model fuel parameters.  In addition, small refiners that are subject to the delayed compliance option for the 0.62 volume percent benzene standard will have to use the complex model until 2015 for CG MSAT1 compliance. Currently, there are 17 complex model parameters on the RFG/anti-dumping batch report.  We are proposing to eliminate reporting for American Petroleum Institute (API) gravity.  In addition, oxygenates need not be reported unless the refiner's gasoline includes oxygenates or the refiner is including downstream added oxygenate in its compliance calculations.  Apart from being necessary for use in the complex model, these parameters have little use for program compliance.    In addition, we are proposing to reduce testing and reporting as follows:  For both RFG and conventional gasoline we propose to eliminate the requirement to test and report API gravity for batch certification purposes.  For winter RFG, we propose to eliminate the requirement to test and report the following parameters on an every batch basis and instead allow testing and reporting of monthly composites:  aromatics, distillations and olefins.  Winter sulfur and benzene would continue to be tested and reported on an every batch basis.  All summer complex model parameters would still be required to be tested and reported on an every batch basis.  For conventional gasoline, since the regulations already allow for testing and reporting most parameters on a monthly composite basis, the only significant change would be to eliminate the batch certification testing and reporting for API gravity.  Only benzene, sulfur, and any oxygenates that are actually included in the gasoline batch must be tested and reported on an every-batch basis (except for refiners that are still subject to a complex model toxics standard; they must test all parameters but may use monthly composite testing and reporting except for sulfur and benzene, and oxygenate, where applicable).  The values for aromatics, olefins, and distillation terms may continue to be determined from monthly composites.  These changes would substantially reduce the testing and reporting associated with each batch.  We request comment on this reduced testing scheme.
        Amendments Related to Reporting
EPA is proposing to amend various provisions in 40 CFR parts 79 and 80 to reduce the number of different reporting deadlines that regulated parties must meet and to enable the future use of a unified and simplified reporting form. EPA's goal is to simplify reporting and reduce the number of hours parties spend preparing and submitting reports.  This overall effort responds to Executive Orders 13563 and 13610, which direct government agencies to simplify rules and to achieve reductions in paperwork and reporting burdens, and is part of EPA's agency-wide effort to streamline regulatory reporting requirements.
Currently under 40 CFR parts 79 and 80, there are ten separate cyclical reporting dates each year (eleven in a leap year). This proposal would amend these deadlines so that all affected programs use the same four dates.  Programs that would be affected by this proposal include the fuels and fuel additives registration program (40 CFR part 79, subpart A), the Reformulated Gasoline and Anti-Dumping program (40 CFR part 80, subparts D and E), the Gasoline Sulfur program (40 CFR part 80 subpart H), the Motor Vehicle, Nonroad, Locomotive, and Marine Diesel program (40 CFR part 80 subpart I), the Gasoline Benzene program (40 CFR part 80 subpart L), and the Renewable Fuel Standard program (40 CFR part 80 subparts K and M).   We are proposing that reporting deadlines would be standardized as follows: June 1, for all reports covering quarter 1 of the compliance year; September 1, for quarter 2; December 1, for quarter 3; and March 31 for quarter 4. End of year compliance reports would also be due on March 31.
These proposed changes would either delay or maintain current deadlines for nearly all required reports. Deadlines for all other annual reports would either be maintained if they matched the new quarterly deadline, or extended to match the new quarterly deadline.
These proposed changes would not include "Attest Engagements" or reporting related to specific events under the Fuels Program, such as trading Renewable Identification Numbers (RINS) in EPA's Moderated Transaction System (EMTS).  All reporting deadlines for Attest Engagements and reporting specific events would remain the same.
Respondents would still have the option to report earlier than any given deadline.  Additionally, these deadline changes would allow EPA to develop a single electronic format that would collect all required data and maximize the capability of electronic reporting with data reuse, no duplicate fields, and a user-friendly interface.
We would also be correcting a typographical error in 40 CFR 80.1451(f)(2) and clarifying that reports are to be signed by the "responsible corporate officer." Additionally, we would remove an incorrect reference under 79.5(a)(2).
Amendments to Update Test Methods
Refiners, importers and oxygenate blenders producing gasoline and diesel motor vehicle fuel are required to test RFG, CG and diesel fuel for various fuel parameters including aromatics, benzene, distillation, olefins, oxygenate content, RVP, and sulfur.  A number of relevant regulatory provisions currently have references to test methods that have since been revised and updated.  We are proposing to update those test methods to reflect current test methods in order to ensure that all test methods are readily available to the regulated community.  ASTM International (ASTM) test method D2622 is currently the designated test method for measuring sulfur (§§80.46(a)(1), 80.580(b)(2)), in gasoline and diesel fuel at the 500 ppm sulfur standard.  ASTM test methods D5453, D6920, D3120 and D7039 are currently alternative test methods for measuring sulfur (§§80.46(a)(3)(i), 80.46(a)(3)(ii), 80.46(a)(3)(iii), 80.46(a)(3)(iv)) in gasoline.  ASTM test method D5453 is also alternative test method for measuring sulfur (§80.580(c)(2)) in diesel fuel at the 500 ppm sulfur standard, as well as ASTM test method D4294.  ASTM test method D6667 is currently the designated test method for measuring sulfur (§80.46 (a)(2)) in butane.  ASTM test methods D4468 and D3246 are currently alternative test methods for measuring the sulfur (§80.46(a)(4)(i), 80.46(a)(4)(ii)) content in butane.  ASTM D1319 is currently the designated test method for measuring olefins (§80.46(b)) in gasoline and aromatics (§80.2(z)) in diesel fuel and is also allowed as an alternative test method for measuring aromatics (§80.46(f)(3)) in gasoline.  ASTM D6550 is currently an alternative test method for measuring olefins (§80.46(b)(2)(i)) in gasoline.  ASTM test method D5599 is currently the designated test method for measuring oxygenates (§80.46(g)(1)) in gasoline.  ASTM test method D4815 is currently an alternative test method for measuring oxygenates (§80.46(g)(2)) in gasoline.  ASTM test method D5769 is currently the designated test method for measuring aromatics (§80.46(f)(1)) in gasoline.  ASTM test method D3606 is currently the designated test method for measuring benzene (§80.46(e)) in gasoline.  ASTM test method D86 is currently the designated test method for measuring the distillation (§80.46(d)) of gasoline.  ASTM test method D5191 is currently the designated test method for measuring the RVP (§80.46(c)) of gasoline.  ASTM test method D976 is currently the designated test method for measuring the Cetane Index (§80.2(w)) of diesel fuel.  ASTM standard practice D4057 is currently the manual sampling standard practice for petroleum and petroleum products (§80.8(a)).  ASTM standard practice D4177 is currently the automatic sampling standard practice for petroleum and petroleum products (§80.8(b)).  ASTM standard practice D5842 is currently the RVP sampling standard practice for fuels (§80.8(c)).  ASTM standard practice D5854 is currently the composite sampling standard practice for petroleum and petroleum products (§80.8(a)).
Table VI-2 lists the designated analytical test methods and alternative analytical test methods for RFG, CG and diesel fuel that we are proposing to update in today's action.  The Agency has reviewed these updated ASTM test methods and believes that the revisions contained in them will result in improvements in the utilization of these test methods for the regulated industry.  We also believe that our proposal to revise these test methods would not result in significant changes that would cause a user of an older version of the same method to incur increased compliance costs.  Moreover, all of the revisions were deemed necessary by ASTM International so that improvements in the test method's procedures would ensure better operation for the user of the test method.  Thus, EPA is proposing today to update the regulations for the following ASTM test methods: (1) ASTM D2622-10, the designated test method for measuring sulfur in RFG, CG, and alternative test method for diesel fuel at the 500 ppm sulfur standard; (2) ASTM D3120-08, alternative test method for sulfur in gasoline, ASTM D4294-10, alternative test method for sulfur in diesel fuel at the 500 ppm sulfur standard; (3) ASTM D5453-09, alternative test method for sulfur in gasoline and diesel fuel at the 500 ppm sulfur standard; (4) ASTM D6667-10, designated test method for sulfur in butane; (5) ASTM D4468-85(2006), alternative test method for sulfur in butane; (6) ASTM D3246-11, alternative test method for sulfur in butane; (7) ASTM D1319-10, designated test method for measuring olefins in gasoline and aromatics in diesel fuel, as well as the alternative test method for measuring aromatics in gasoline; (8) ASTM D6550-10, alternative test method for measuring olefin content in gasoline; (9) ASTM D4815-09, alternative test method for measuring oxygenate content in gasoline; (10) ASTM D5599-00(2010), the designated test method for measuring oxygen content in gasoline; (11) ASTM D5769-10, the designated test method for measuring aromatics in gasoline; (12) ASTM D3606-10, the designated test method for measuring benzene in gasoline; (13) ASTM D86-11a, the designated test method for measuring distillation properties of gasoline; (14) ASTM D5191-10b, the designated test method for measuring the RVP of gasoline; (15) ASTM D976-06(2011), the designated test method for measuring the Cetane Index of diesel fuel; (16) ASTM D4057-06(2011), the manual sampling standard practice for petroleum and petroleum products; (17) ASTM D4177-95(2010), the automatic sampling standard practice for petroleum and petroleum products; (18) ASTM D5842-04(2009), the sampling standard practice for RVP of fuels; and (19) ASTM D5854-96(2010), the composite sampling standard practice for petroleum and petroleum products.
Table VI-2 Proposed Designated & Alternative ASTM International Analytical Test Methods Under RFG, CG & Diesel Motor Vehicle Fuel Programs
Fuel Parameter
ASTM Analytical Test Method
Sulfur (gasoline)
ASTM D2622-10, entitled "Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry"
Sulfur (500 ppm diesel)