equipment would have to be designed for good energy efficiency. We
expect that the types of equipment and process technologies that
refiners are likely to modify or add to meet the final Tier 3 standards
will generally be sufficient to satisfy BACT requirements for GHG
emissions in terms of achievability, cost-effectiveness, and energy-
efficiency even absent the requirement to obtain a permit, meaning that
having to demonstrate that BACT is in place would not necessitate any
shift in project design or cause increased 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, some of the
new or modified equipment expected to be involved in refinery projects
designed to meet the final 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.
    In 2010, EPA issued a white paper on available and emerging
technologies for reducing GHGs from the petroleum refining
industry.\471\ This white paper addresses the types of equipment
expected to be involved in projects designed to meet the final 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 for meeting BACT requirements, and we do
not expect that in the time frame associated with Tier 3-related
projects, add-on controls would be required.
---------------------------------------------------------------------------

    \471\ See ``Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from the Petroleum Refining Industry,''
October 2010, available at http://www.epa.gov/nsr/ghgpermitting.html.
---------------------------------------------------------------------------

    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 will also be required. Significantly, no air quality modeling
of GHGs will 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.
    On March 22, 2012, the President issued Executive Order 13604 (EO
13604), Improving Performance of Federal Permitting and Review of
Infrastructure Projects. EO 13604 states that federal permitting and
review processes must provide a transparent, consistent, and
predictable path for both project sponsors and affected communities,
and that a number of described elements must be incorporated into
routine agency practices to provide improvements in the performance of
federal permitting processes.
    Under the EO, EPA has adopted a plan identifying the permitting and
review processes that EPA views as most critical to significantly
reduce the aggregate time required to make permitting and review
decisions on infrastructure projects while improving outcomes for
communities and the environment, and describing specific and measurable
actions the agency will take to improve these processes.\472\ With
regard to permitting under the Clean Air Act, this plan stated EPA's
intention to issue a guidance memorandum by the end of 2012 to apply to
PSD permits issued by EPA and by state or local agencies with delegated
authority from EPA, aimed at clarifying expectations and
responsibilities regarding the timely processing of permit applications
by an EPA Regional Office or delegated agency. This memorandum was
subsequently issued on October 15, 2012.\473\ EPA Regional Offices
serving as the permitting authorities for refineries making
modifications as part of the Tier 3 program will be guided by the
memorandum. The memorandum also recommends that other permitting
authorities consider following the approaches outlined in the
memorandum where applicable.
---------------------------------------------------------------------------

    \472\ The U.S. EPA Plan for Modernizing Federal Permitting and
Review Pursuant to EO 13604, August 9, 2012. http://www.epa.gov/epainnov/pdf/eo-infrastructure-epa-final-plan.pdf
    \473\ Timely Processing of Prevention of Significant
Deterioration (PSD) Permits when EPA or a PSD-Delegated Air Agency
Issues the Permit, Stephen D. Page to Regional Air Division
Directors, October 15, 2012. http://www.epa.gov/region07/air/nsr/nsrmemos/timely.pdf
---------------------------------------------------------------------------

3. Comments and Responses
    Several oil industry commenters expressed doubt about whether EPA's
prediction of the small number of refineries that would need GHG
permits was realistic. Commenters generally stated that permits for the
modifications needed to comply with the Tier 3 requirements should be
issued expeditiously. Some industry commenters expressed doubt that
this would be the case, noting what they characterized as the slow pace
at which GHG permits have been issued since the requirement for GHG
permitting became effective. One oil industry commenter suggested that
Tier 3-related modifications be completely exempt from permitting if
they would not increase refinery capacity by more than 10 percent. No
other specific suggestions for streamlining were submitted.
Environmental groups commented that any efforts to streamline
permitting should not relax the substantive requirements to get a
permit.
    The final rule does not establish any new flexibilities or
exceptions to current permitting regulations. On an ongoing basis, EPA
continues to consider ways to streamline the permitting process
consistent with CAA requirements and goals. EPA has concluded that only
a small number of refineries appear to have the potential of triggering
major source permitting as a result of modifications needed to meet the
Tier 3 fuel program, given the flexibilities provided by the final
program in terms of when modifications must be in place in order to
achieve compliance. There were no industry comments that demonstrated a
specific reason for concern about permitting implications on a broad
scale.
    The Response to Comment Document includes a fuller summary of the
comments on refinery permitting implications and the EPA responses to
these comments.

L. Refinery Feasibility

    While evaluating the merits of a national gasoline sulfur program
to reduce emissions and enable future vehicle technologies, we also
considered the refining industry's ability to reduce sulfur to 10 ppm
on average by January 1, 2017 and the associated costs (for more on
fuel costs, refer to Section VII.B). Based on information gathered from
numerous stakeholder meetings and discussions with vendor companies
that provide the gasoline desulfurization technologies both before and
after the proposal, as well as the results from our refinery-by-
refinery modeling, we believe it is technologically feasible at a
reasonable cost for refiners to meet the sulfur standards in the lead
time provided. A summary of our feasibility analysis is presented
below. For more on our feasibility and cost assessments and the
refinery modeling that supports them, refer to Chapters 4 and 5 of the
RIA.
1. Comments Received
    We received a number of comments on the proposed rule regarding
feasibility and lead time. Commenters in the refining industry
generally stated that they believe that the amount of lead time
proposed is not sufficient. These commenters noted concerns that the
short lead time proposed would drive up costs as there would be
unscheduled shut-downs to install and/or revamp equipment to meet the
Tier 3 sulfur standard, and would not provide enough time for the
permitting process. These commenters requested at least five years of
lead time, and noted that EPA has historically provided at least four
years of lead time in previous fuels rulemakings. Commenters in the
auto industry, as well as states and non-governmental organizations
(NGOs), encouraged us to finalize the rule as soon as possible and to
retain the January 1, 2017 start date to harmonize our program with
California's LEVIII program and to enable Tier 3 benefits as soon as
possible. As discussed in more detail below, we believe the amount of
lead time provided is sufficient, especially given the flexibilities
being provided. A complete discussion on the comments received with
regard to lead time can be found in Chapter 5 of the Summary and
Analysis of Comments document.
2. Is it feasible for refiners to comply with a 10 ppm average sulfur
standard?
    Gasoline desulfurization technologies are well known and are
readily available. Many technologies were demonstrated under Tier 2 and
have been further demonstrated by current fuel programs in California,
Japan, and Europe. Under California's Phase 3 Reformulated Gasoline
program (CaRFG3), gasoline sulfur is limited to 15 ppm on average with
a 20 ppm per-gallon cap.\474\ California reduced their per-gallon cap
in phases from 60 ppm effective December 31, 2003, to 30 ppm effective
December 31, 2005, to 20 ppm effective December 31, 2011. Actual in-use
gasoline sulfur levels, however, have been largely constrained by the
Predictive Model that California refiners are using to demonstrate
compliance. As a result, gasoline sulfur levels are lower than the
CaRFG3 limits. Based on the

Predictive Model, California gasoline contained approximately 10 ppm
sulfur on average in 2010 (9 ppm in the summer and 11 ppm in the
winter).
---------------------------------------------------------------------------

    \474\ California Air Resources Board. (2008, August 29). The
California Reformulated Gasoline Regulations, Title 13, California
Code of Regulations, Sections 2250-2273.5. Retrieved from http://www.arb.ca.gov/fuels/gasoline/082908CaRFG_regs.pdf.
---------------------------------------------------------------------------

    Japan currently has a 10 ppm gasoline sulfur cap that took effect
in January 2008. Europe also has a 10 ppm sulfur cap that has been
adopted by the 30 Member States that comprise the European Union (EU)
and the European Free Trade Association (EFTA) as well as Albania and
Bosnia-Herzegovina.\475\ Beijing, China also recently introduced a 10
ppm sulfur limit for gasoline.\476\ These standards are considerably
more stringent than the 10 ppm annual average standard being finalized
today because each batch of gasoline produced at every refinery must
meet the 10 ppm cap. As a result, every refinery must be designed to
meet this cap regardless of changes in crude oil supply, operation
conditions, or product mix. We note, however, that many oil refineries
outside of the United States operate differently from their U.S.
counterparts. U.S. refiners have invested more heavily in fluidized
catalytic cracker (FCC) units than the rest of the world to maximize
gasoline production. Because the FCC unit is responsible for nearly all
the sulfur that ends up in gasoline, many U.S. refineries may face a
bigger challenge in achieving 10 ppm gasoline sulfur levels. Even in
the U.S., however, the picture is changing. The Annual Energy Outlook
for 2013 produced by the Energy Information Administration supports the
view that the U.S. demand for diesel fuel is increasing while the
demand for gasoline is decreasing, starting the process that will make
the U.S. more like Europe. Thus, U.S. refiners seem to be beginning to
move away from relying on the FCC unit as the most important refinery
unit. For this reason, the challenge of complying with more stringent
gasoline sulfur control will decrease over time, and we discuss this
more at the end of this section.
---------------------------------------------------------------------------

    \475\ Hart Energy Consulting. (2011). International Fuel Quality
Center: 2011 Worldwide Fuel Specifications
    \476\ Article from China.org.cn entitled ``Beijing to implement
stricter fuel standards'', May 19, 2012, retrieved from http://www.china.org.cn/environment/2012-05/19/content_25422404.htm
---------------------------------------------------------------------------

    The review of gasoline sulfur control in California and elsewhere
and the future trend for gasoline demand support that achieving 10 ppm
is feasible. The Tier 3 requirements are less demanding than those of
Europe or Japan. This is because the Tier 3 sulfur standard is an
average standard instead of a cap standard. The accompanying Tier 3 cap
standard is 80 ppm, which is much higher than the average standard,
allows individual gasoline batches to vary in sulfur level throughout
the year. Complying with Tier 3 is also made easier, as compared to
California, Europe and Japan, by the ABT program which allows
refineries with an easy path to compliance with Tier 3 to reduce their
gasoline sulfur to less than 10 ppm sulfur and generate and sell those
credits to refineries, which are more challenged by Tier 3.
3. Can refiners meet the January 1, 2017 start date?
    An adequate amount of lead time is required for the implementation
of any rulemaking. Depending on the level of effort required to comply,
more or less lead time is also required. In the case of Tier 3,
refiners need time to select the technology and the vendor that will
provide the technology needed for compliance with the fuels standard.
Next, they need time to arrange an engineering and construction (E & C)
contractor which will design and oversee the construction of the
refinery unit and the time needed to obtain the necessary permits and
procure the necessary hardware. Next, refiners need time to construct
the unit. Finally, the refiner needs time to make the necessary unit
tie-ins of the unit with the rest of the refinery and then startup the
unit.
    This section, along with detailed analysis provided in the RIA,
explains that when taking into account the time to revamp existing FCC
postreater units or build grassroots postreater units, tie-in the new
or revamped units with the rest of the refinery and considering the
flexibility offered by the ABT program, refiners will be able to comply
with the Tier 3 program within the lead time provided.
a. Time Required To Install Grassroots Units and Revamp Existing Units
    The technologies for complying with Tier 3 are well known and well
proven. Refiners which complied with Tier 2 using FCC naphtha
desulfurization technologies installed the following units: Axens Prime
G+, CDTech's CDHydro and CDHDS, UOP's ISAL Sinopec's S-Zorb and Exxon's
Scanfining. Refiners shopped around and chose among these various
technologies which were largely untested at the time, which required us
to provide more lead time for Tier 2. Since the Tier 2 sulfur standard
began to be phased in, nine years have elapsed, and we believe that
refiners now have direct experience with the installation and operation
of these technologies and the vendor companies that license them and
continue to support their installations onsite. We therefore believe
that refiners will be able to reach a decision very quickly when
complying with Tier 3, particularly, because in most cases the refiners
will be revamping the units already installed for Tier 2 when complying
with Tier 3.
    Based on our conversations with refiners, construction companies,
vendor companies and from published literature, we estimated the time
it takes to revamp existing postreaters and install grassroots
postreaters. To revamp an existing postreater it is expected to require
up to two years. Installing a grassroots postreater is estimated to
require three years. Figure A reflects these project completion times
showing the various major intermediate steps for completing the
projects.

[GRAPHIC] [TIFF OMITTED] TR28AP14.002

    Since many of the Tier 3 revamps are expected to be very modest
(e.g., change out a reboiler or heat exchanger), we believe that the
revamping of postreaters could take less time than what we estimate in
Figure V.L-1. Following EPA held discussions with many refiners in 2011
about EPA's plan to pursue additional sulfur control post-Tier 2 (Tier
3), refiners began the process of assessing how they would comply. The
Tier 3 proposal was delayed for about a year and it is our
understanding from recent discussions with vendor companies and some
refiners that, during this time, many refiners began assessing how they
intended to comply with Tier 3. Thus, many refiners likely have
completed the scoping studies, which involves technology selection, and
in the case of grassroots units, vendor selection as well (refiners
with a particular postreater technology in most cases are expected to
simply revamp the same vendor's technology, so there is no need to
select a vendor). If refiners have already completed their scoping
studies, we estimate that installation of the revamps or grassroots
units would be about 3 months shorter than the 2 and 3 years,
respectively, than we estimate in Figure V.L-1.
    We believe that these project timelines are reasonable in light of
past industry experiences which show FCC postreaters being installed in
refineries in less time than what we estimate. At the Motiva refinery
in Port Arthur, TX, a grassroots CDTech postreater was designed,
constructed and started up in less than 2 years. At two refineries in
Germany, two Prime G+ units were designed, constructed and started up--
one of them in two years, and the other in 18 months. As an extreme
example, the $3.6 billion dollar, 180 kbbl/day crude oil expansion at
Marathon's Garyville, LA refinery was designed, constructed and started
up in 4 years. This project involved construction of 10 major refinery
units. Since these may be best case examples, we continue to believe
the projections provided above in Figure V.L-1 are reasonable. In
contrast, EPA received comments and feedback during meetings from the
refining industry suggesting that many of the steps outlined in Figure
V.L-1 could take considerably longer. For example, they stated that
permits could take 2 years and procurement of vessels, pumps,
compressors and heaters could take 2 years as well, extending the time
needed to complete their projects. However, even if this may be true in
some situations, the examples above highlight that this is not true in
all situations. Furthermore, most refineries, as discussed in section
V.K. will not need to go through any extensive permitting process and
as discussed below, not all refineries will need to undertake extensive
revamps of existing units or installation of grassroots units. So once
again, we believe the timeline shown is reasonable for the vast
majority of refineries. Many can complete there actions faster. For
those that may require a longer timeline, the program flexibilities
discussed below allow for this within the lead time provided.
b. Program Flexibility That Extends Lead Time
    As discussed in Section V.D, the final Tier 3 program includes an
ABT program that significantly helps refiners comply with the January
1, 2017 start date. There are several provisions of the ABT program
that help with respect to any leadtime constraints.
    The ABT program allows for ongoing intra-company and inter-company
trading nationwide. This will allow some refineries to over-comply with
the 10 ppm gasoline sulfur standard (in our analysis, we modeled these
refineries

bringing their gasoline down to 5 ppm), allowing other refineries that
would otherwise need to install grassroots units to not invest and
purchase credits instead. This aspect of the ABT program is very
important because our analysis estimates that only one refinery would
need to install a grassroots hydrotreater whereas without the ABT
provisions, there could be as many as 20 grassroots units. This one
aspect has huge implications for leadtime because as discussed in the
previous subsection, revamps require two years or less whereas
grassroots FCC postreater units require approximately three years to
install. We are convinced that this aspect of the ABT program will be
utilized to the maximum extent possible because refineries revamping
their postreaters in lieu of installing grassroots postreaters results
in the most cost-effective mechanism for meeting the 10 ppm annual
average standard.
    An important issue to consider is that in order for refiners to opt
not to invest in a grassroots unit they would have to trust that
credits will be available to them. For the proposal, we conservatively
assumed that refiners would only rely on credits if they could generate
them internally. However, for the final rule analysis, we have assessed
how the sulfur credits were being traded under Tier 2 and found that
over half the sulfur credits were freely traded between companies (as
opposed to only being used within companies), and many single-refinery
companies had sulfur levels above 30 ppm (single-refinery companies
must purchase credits from other companies). Because credits have a 5-
year life, we also see in the Tier 2 data that refiners tend to sell
credits rather than let them simply expire. Refiners may hold them as a
contingency, but then sell them prior to their expiration. For example,
in 2012, 40 percent of the credits traded were generated in 2007 and
were set to expire at the end of 2012. This one quality of the Tier 2
program ensures the free access to credits. We designed the Tier 3
credit trading program to work just like the Tier 2 credit trading
program, thus we are confident that there will be widespread trading
within and between refining companies.
    A second aspect of the ABT program that helps with leadtime is the
provision for generating early sulfur credits and banking them for
later use. As discussed in Section V.D above, this provision allows
refineries to reduce their gasoline sulfur to less than 30 ppm prior to
January 1, 2017 and bank the credits for later use. Based on comments
that we received on the proposed rule, we are allowing Tier 2 credits
which are generated during the years 2012 and 2013 to also be used to
show compliance for Tier 3. This effectively extends the early credit
generation period for Tier 3 to encompass the years 2012 to 2016, which
is 5 years. Analyzing the 2012 gasoline quality data that refiners
reported to EPA, we found that gasoline sulfur levels in the U.S.
averaged about 26.7 ppm. Thus, refiners have already begun
overcomplying with Tier 2 by 3.3 ppm, and are therefore already
generating early credits that can be used for Tier 3. If refiners do
nothing more but continue to overcomply with Tier 2 by 3.3 ppm over the
5 years of early credit generation, refiners will have generated enough
credits to delay the completion of their capital projects by roughly a
year. Furthermore since those credits generated in 2012 and 2013 will
expire in 2017 and 2018 respectively, refiners will have an incentive
to either use them themselves or trade them in 2017 and 2018. Thus
refiners that may need to count on them to delay their capital
investment are likely to be able to have access to them.
    When the extent of the flexibility afforded by the final ABT
provisions is fully understood by refiners, we believe that refiners
will generate a lot more early credits with their existing gasoline
sulfur control units than the 3.3 ppm we observed in 2012. As we
discussed in our cost analysis, to produce more diesel fuel in response
to a greater demand for diesel fuel relative to gasoline, refiners are
undercutting the swingcut portion of FCC naphtha at their
refineries.\477\ This action to shift what historically was blended
into the gasoline pool to the diesel fuel pool, actually also
dramatically reduces the sulfur content of the gasoline pool. If the
entire swingcut portion of FCC naphtha is undercut to the diesel fuel
pool, the amount of sulfur in the gasoline pool is reduced by about 50
percent. Our cost analysis estimates that at almost one quarter of U.S.
refineries, refiners are fully undercutting the FCC naphtha to diesel
fuel today. At many other refineries, refiners are only partially
undercutting their FCC naphtha. These refineries will be able to reduce
the sulfur of their gasoline well below their current levels and
generate a large number of early credits for Tier 3. Even for the
subset of refineries at which the FCC naphtha is not being undercut,
refiners can assess how much activity or catalyst life is left in its
FCC postreater catalyst and compare this time with the time to the next
turnaround when the FCC postreater catalyst is scheduled to be
replaced. If there is spare catalyst life, the refiner could elect to
``turn up'' their postreaters to reduce their gasoline sulfur levels to
under 30 ppm. With this strategy, the refiner would generate early
sulfur credits. Also, when the refiner replaces the catalyst in its
Tier 2 postreater, it can elect to do so with a more active catalyst
which would allow the refinery to produce gasoline at sulfur levels
below 30 ppm and generate more early credits for Tier 3.
---------------------------------------------------------------------------

    \477\ The term swingcut means that this portion of the FCC
product pool can be blended into gasoline or diesel fuel while still
meeting the fuel quality specifications for either fuel regardless
of where this swingcut is blended.
---------------------------------------------------------------------------

    Based on the early actions refiners are already taking, or could
take, to reduce their gasoline sulfur levels, we believe that refiners
would be able to reduce their gasoline sulfur to as low as 20 ppm, on
average. By averaging 20 ppm for 2.5 years prior to 2017, refiners
would be able to delay completion of all capital investments for Tier 3
until mid 2019. If we add the 3.3 ppm of credits during 2012, 2013 and
first part of 2014, refiners would be able to delay completion of all
capital investments in Tier 3 until 2020. Thus, the early credit
provisions will, in-effect, provide nearly 6 years of leadtime for full
compliance with the fuels program. This will allow ample time for
refiners to complete their investment and schedule their tie-ins during
normal shutdown activities. It effectively provides even more lead time
than the 5 years that the refining industry requested in their
comments. The delay in the program implementation will also help to
distribute the demand on the E & C industry over more years ensuring
that the E & C industry won't be overwhelmed.
    We are also finalizing a compliance deadline of January 1, 2020 for
small refiners and small volume refineries (i.e., refineries processing
less than or equal to 75,000 net barrels per day of crude oil). This
will provide approximately 36 of the 108 affected refineries with
nearly 6 years of lead time; again more than the 5 years that the
refining industry requested in their comments. We believe that these
refiners and refineries are disproportionally impacted when it comes to
their cost of compliance and ability to rationalize investment costs in
today's gasoline market. Giving these refiners and refineries
additional lead time provides 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. Due to the January 1, 2020
compliance deadline for small refiners and small volume refineries we
estimate that of the 64 refineries that will ultimately need to revamp
(63) their existing hydrotreaters or add a grassroots hydrotreater (1)
over the course of implementing the Tier 3 program 15 refineries could
wait to take such actions until 2020. Further, as discussed in more
detail in Section V.E.1, small refiners and small volume refineries can
generate early credits (from January 1, 2017 through December 31, 2019)
relative to 30 ppm for sale to other small refiners/small volume
refineries, and relative to 10 ppm for sale to non-small refiners. This
could provide another pool of early credits for Tier 3 prior to January
1, 2017 and ongoing credits during the years of 2017, 2018 and 2019.
    Despite the flexibility afforded by the ABT program, some refiners
have expressed concern that should they want or need to rely on credits
for compliance, they may not be able to do so if they cannot be assured
that they will be able to acquire the necessary credits from other
parties when the time comes. This could force them into making
relatively costly investments that they would otherwise be able to
avoid. We recognize that this may be a concern, particularly prior to
2020 when the market will be in a state of transition. While we cannot
guarantee credit availability, and we are confident that the program as
designed provides ample opportunity for credit generation, we do
believe that providing the market with at least some basic information
on credit availability may provide some added assurance and aid in
credit market liquidity. Consequently, we pledge to work with the
refining industry on ways to make information on the sulfur credit
market more transparent over the period leading up to 2020, balancing
their need for information with the resource constraints of the Agency.
In doing so, to protect confidentiality, we will not be able to
identify individual company credit balances or deficits, but would
intend to provide an aggregated level of information, such as total
credit balances for each vintage year, on an annual basis leading up to
2020. Because industry has already shown the ability to identify and
establish the necessary trading relationships under the Tier 2 program,
we anticipate that they will be able to continue to do so under Tier 3.
    In summary, we believe that the ABT program we are finalizing today
provides ample flexibility for complying with Tier 3. The averaging
provisions will allow refiners that only need to revamp their Tier 2
postreaters to generate credits by overcomplying with the 10 ppm
standard, and in turn allow refineries that otherwise need to install
grassroots units to comply solely through the purchase of credits. The
banking provisions also allow refiners to generate early credits,
effectively delaying investments for compliance to potentially as late
as 2020. Finally, the small refiner and small refinery provisions delay
compliance for approximately 36 refineries until 2020, as well as
generate and trade early credits. We believe that all of these
provisions effectively address any leadtime concerns. Furthermore,
there are additional options available to refineries to avoid a
noncompliance situation should all these program flexibilities prove
insufficient. Refineries are permitted to carry a credit deficit for
one year as long as they make it up the following year, and the final
rule allows refiners to apply for hardship waivers if necessary. In
addition, refineries with access to export markets can always choose to
export fuel until such time as they can bring their desulfurization
capacity online. There is a large and growing gasoline export market
from the U.S. already. Such exports of higher sulfur gasoline could be
offset through imports of compliant gasoline such as historically
occurred from Europe, which has a 10 ppm sulfur cap on gasoline.
c. Impact of Turnaround Timing
    We received numerous comments on the proposed January 1, 2017
compliance deadline. In their comments to the proposed Tier 3
rulemaking, the oil industry stated that EPA must consider and include
the time it takes to tie-in the revamps and grassroots units in the
proposed leadtime. The oil industry urged EPA increase the leadtime for
Tier 3 to 5 years to allow for refiners to make their investments
needed to comply with Tier 3 and tie-in those new investments. In
today's action we are finalizing a compliance deadline of January 1,
2017. As previously explained above, various provisions of the ABT
program effectively provide nearly 6 years of leadtime to complete
capital projects. We also note that the capital projects do not have to
be completed prior to installing the necessary tie-ins. We do agree,
however, that the need to make tie-ins must be considered when
assessing the feasibility of leadtime, and in doing so, our analysis
shows that refiners can comply with Tier 3 within the leadtime
provided. This is true not only because the final rule effectively
provides nearly 6 years of leadtime to complete capital projects, as
described above, but also because the capital projects do not have to
be completed prior to installing the necessary tie-ins.
    When a refiner builds a grassroots unit or some sort of revamp
which involves new reactor volume or perhaps by adding a splitter, this
new capital must be ``tied-in'' to the rest of the refinery. The tie in
usually involves connecting a pipe from the existing unit to the new
capital installed for complying with Tier 3. However, a pipe cannot
simply be added while the refinery is operating. Instead, the refiner
will add the necessary pipe for making the tie-in when the refinery is
shutdown for regular maintenance. The revamp or grassroots unit does
not have to be started up at that time. Instead, the connection pipe
just needs to be added and blocked off with a sealing-type valve and a
blind flange (essentially a flat piece of steel) is bolted on as a
precaution against a leaky valve. Once this piping has been added, the
refiner can restart its refinery. Then when the refiner is ready to
complete the tie-in to the completed Tier 3 revamp or grassroots unit,
the refiner would remove the blind flange and connect a pipe which
connects the existing part of the refinery to the newly installed
grassroots postreater unit or revamp postreater subunit. This last step
can either occur when the refinery is shutdown or still operating. At
that point the refiner would only need to open the block valve to
complete the tie-in of the grassroots unit or revamp to the existing
refinery.
    On its Web page, the American Petroleum Institute (API) reports
that the average time between turnarounds is 4 years when the U.S.
refineries perform maintenance on the FCC unit.\478\ This means that on
average, 25% of U.S. refineries shutdown to perform maintenance on its
FCC units each year. Most often, refiners conduct maintenance
turnarounds on their refineries during the spring when the demand for
gasoline and diesel fuel is at their lowest. Thus, refiners will have
the years of 2014, 2015 and 2016 to make their tie-ins during a
regularly scheduled refinery turnaround to be able to comply by January
1, 2017, thus roughly three-quarters of the tie-ins could occur before
the January 1, 2017

compliance date.\479\ If we superimpose the tie-in issue with the types
of investments we project will be made for Tier 3, we project that for
three-quarters of the revamps, refiners will be able to make their tie-
ins prior to the January 1, 2017 start date, while the other refineries
will require until the spring of 2017 to make their tie-ins. As a
worse-case scenario, if refiners don't even try to begin making their
tie-ins until the spring of 2015, they would need the spring of 2015 to
the spring of 2018 to complete their tie-ins.
---------------------------------------------------------------------------

    \478\ Fact Sheet entitled ``Refinery Turnarounds,'' American
Petroleum Institute (API) Web page: http://www.api.org/oil-and-natural-gas-overview/fuels-and-refining/refineries/refinery-turnarounds; downloaded June 21, 2013.
    \479\ Since most refiners have already completed their scoping
studies with the vendor companies which license the desulfurization
technologies, they likely already understand what steps would need
to be taken to tie-in their revamps and grassroots units with their
existing refinery. For this reason, we believe that refiners can
begin making their tie-ins as soon as the spring of 2014, and
perhaps even earlier than that. One refiner who owns a number of
refineries shared with us that they prepared the tie-ins for Tier 3
when they installed their Tier 2 units.
---------------------------------------------------------------------------

    However, regardless of whether we assume that tie-ins begin to
occur in 2014 or 2015, the flexibility afforded by the ABT program will
readily enable refiners to complete their capital investments and tie-
ins and comply with Tier 3 within the lead time provided. A more
detailed discussion and analysis of Tier 3 compliance considering unit
construction time, the tie-ins of revamps and grassroots units and
availability of credits is contained in Chapter 4 of the RIA.
d. Hardship
    While we project that there will be plenty of credits available to
allow refiners to complete their capital investments and tie in the new
or revamped unit to the rest of their refinery, we are providing
another option to refiners as a safety valve in case there is a
shortfall of credits. Consistent with our proposal, today's rule
contains provisions for a refiner to apply for a hardship waiver. Thus,
where a refiner cannot complete its project by January 1, 2017 and
credits are not available or are prohibitively expensive, the refiner
may file a hardship waiver. Details of our hardship provisions can be
found in Section V.E.2.
e. Impact on the Engineering and Construction Industry
    As in prior rules, we also evaluated the capability of E&C
industries to design and build gasoline hydrotreaters as well as
performing routine maintenance. Two areas where it is important to
consider the impact of the fuel sulfur standards are: (1) Refiners'
ability to procure design and construction services, and (2) refiners'
ability to obtain the capital necessary for the construction of new
equipment required to meet the new gasoline quality specification. We
evaluated the requirement for engineering design and construction
personnel in a manner consistent with the Tier 2 analysis, particularly
for three types of workers needed to implement the refinery changes:
front-end designers, detailed designers, and construction workers. We
developed estimates of the maximum number of each of these types of
workers needed throughout the design and construction process and
compared those figures to the number of personnel currently employed in
these areas.
    The number of job hours necessary to design and build individual
pieces of refinery equipment and the job hours per piece of equipment
were taken from Moncrief and Ragsdale.\480\ Their paper summarizes
analyses performed in support of a National Petroleum Council study of
gasoline desulfurization, as well as other potential fuel quality
changes. The design and construction factors for desulfurization
equipment are summarized in Table V-1.
---------------------------------------------------------------------------

    \480\ Moncrief, Philip & Ragsdale, Ralph. (2000). Can the U.S.
E&C Industry Meet the EPA's Low Sulfur Timetable? Paper presented at
NPRA Annual Meeting, March 26-28, 2000. Paper No. AM-00-57.

               Table V-1--Design and Construction Factors
------------------------------------------------------------------------

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

    Refinery projects will differ in complexity and scope. Even if all
refiners desired to complete their project by the same date, their
projects would inevitably begin over a range of months. Thus, two
projects scheduled to start up at exactly the same time are not likely
to proceed through each step of the design and construction process at
the same time. Second, the design and construction industries will
likely provide refiners with economic incentives to avoid temporary
peaks in the demand for personnel.
    Applying the above factors, we projected the maximum number of
personnel needed in any given month for each type of job. The results
are shown in Table V-2. In addition to total personnel required, the
percentage of the U.S. workforce in these areas is also shown, assuming
that half of all projects occur in the Gulf Coast.

                                 Table V-2--Maximum Monthly Demand for Personnel
----------------------------------------------------------------------------------------------------------------
                                                                     Front-end       Detailed
                                                                      design        engineering    Construction
----------------------------------------------------------------------------------------------------------------
                                         Tier 3 Gasoline Sulfur Program
----------------------------------------------------------------------------------------------------------------
Number of Workers...............................................             202             809           6,012
Percentage of Current Workforce \a\.............................             11%              9%              4%
----------------------------------------------------------------------------------------------------------------
\a\ Based on current employment in the U.S. Gulf Coast assuming half of all projects occur in the Gulf Coast

    To meet the Tier 3 sulfur standards, refiners are expected to
invest $2.0 billion between 2014 and 2019 and utilize approximately 250
front-end design and engineering jobs and 1,500 construction jobs. The
number of estimated jobs required is small relative to overall number
available in the U.S. job market. As such, we believe that three years,
plus the additional flexibilities provided, is adequate lead time for
refineries to obtain necessary permits, secure E&C resources, install
new desulfurization equipment, and make all necessary retrofits to meet
the Tier 3 sulfur standards. For an in-depth assessment of stationary
source implications, refer to Section V.K. For more on our E&C
assessment, refer to Chapter 4 of the RIA.

M. Statutory Authority for Tier 3 Fuel Controls

    Consistent with our proposal, we are adopting 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)]. Consistent with our proposal, we are
finalizing controls on gasoline sulfur levels based on both of the
Clean Air Act criteria, as described in more detail below.
1. 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 149 million people
currently live in counties exceeding a NAAQS.\481\ 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.\482\ A more detailed discussion
of the health and environmental effects of these pollutants is included
in Section II.B. As discussed there, 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 reductions in
emissions of these pollutants, with the benefits to public health and
welfare significantly outweighing the costs.
---------------------------------------------------------------------------

    \481\ Data come from Summary Nonattainment Area Population
Exposure Report, current as of July 20, 2012 at: http://www.epa.gov/oar/oaqps/greenbk/popexp.html and contained in Docket EPA-HQ-OAR-
2011-0135.
    \482\ U.S. EPA. (2011) Summary of Results for the 2005 National-
Scale Assessment. www.epa.gov/ttn/atw/nata2005/05pdf/sum_results.pdf.
---------------------------------------------------------------------------

    EPA has evaluated the technical feasibility of achieving these
sulfur levels, including the cost of the reductions. We have concluded
that these reductions are feasible in the lead time provided. For more
on the feasibility of the fuel standards, refer to Section V.L above
and Chapter 4 of the RIA.
    As discussed in Section III, and further supported by the
discussion in Section IV.A.6, EPA also evaluated the emissions
reductions from pre-Tier 3 vehicles that will be achieved by
controlling gasoline sulfur level to 10 ppm on average. The 10 ppm
sulfur standard will provide significant reductions in harmful
emissions independent of the vehicle standards and these reductions are
significant and contribute to the total monetized health benefits.
Already in 2018, when the emission reductions are almost entirely due
to the sulfur standards, the Tier 3 program will provide significant
benefits. We continue to believe that the Tier 3 program will produce
benefits to public health and welfare whose value significantly
outweighs the costs. These reductions can be achieved in a manner that
is technologically feasible. 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 Tier 3 program, refer to Chapter 5 of the
RIA.
    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 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 adopting
Tier 3 emissions standards for motor vehicles under section 202. These
standards could not achieve any emission reductions for vehicles
already in use, while reducing fuel sulfur will achieve large emission
reductions for vehicles already in use. For new vehicles, the use of 10
ppm average sulfur fuel is an essential part of achieving Tier 3 levels
while applying an array of advancements in emissions control technology
to the light-duty fleet. As shown in Section IV.A, we believe that
achieving the Tier 3 exhaust emission standards will require
technological improvements such as very careful control of the exhaust
chemistry and exhaust temperatures to ensure high catalyst efficiency.
These technology improvements, which are described in greater detail in
the RIA (Chapter 1)--improving warm-up and catalyst light-off after
cold starts and maintaining very high catalyst efficiency--all rely on
10 ppm sulfur average fuel to achieve the very significant emissions
reductions required for the fleet to achieve Tier 3 emissions levels.
    Achieving Tier 3 emissions standards without a reduction in sulfur
to 10 ppm levels would only be possible if there were technology
improvements significantly above and beyond even those mentioned above.
EPA cannot identify technology improvements that could provide such a
large additional increase in emissions control effectiveness, across
the fleet, above and beyond that provided by the major improvements in
technology discussed above, without any additional gasoline sulfur
control. As discussed in Section IV.A.3, the Tier 3 fleet average
exhaust emissions standards of 30 mg/mi NMOG+NOX will
require large reductions of emissions across a broad range of light-
duty vehicles and trucks with differing degrees of utility.
Specifically, achieving Tier 3 emissions

standards as an average across the fleet will require fleet wide
reductions of approximately 80%. We believe this means significant
reductions from all sectors, with the result that there is a need for
major reductions from all types of vehicles in the light-duty fleet,
including those above as well as most vehicles that are already near,
at, or below the Tier 3 Bin 30 fleet average standard.
    Achieving these reductions presents a major technology challenge
and EPA is not aware of technology improvements that could provide such
large additional increases in emissions control effectiveness, across
the fleet, above and beyond that provided by the major improvements in
control technologies expected for use in meeting today's Tier 3
standards. Rather, as available test data indicates, in addition to
lower gasoline sulfur levels, the required reductions are of a
magnitude that EPA expects manufacturers to employ advances in
technology in all of the relevant areas of emissions control--exhaust
catalyst technologies, (such as reducing the time to catalyst light
off, improving exhaust catalyst durability at 120,000 or 150,000 miles
and improving efficiency of fully warmed up exhaust catalysts),
reducing engine out emissions, power train calibration primarily
focused on reducing cold-start NMOG emissions, and on reducing both
cold-start and warmed-up (running) NOX emissions.
    The impact of sulfur reduction on the effectiveness of the
available technology improvements plays such a large role in achieving
the Tier 3 emissions standards that it is clearly unrealistic to expect
that technology would be available, at the 30 ppm sulfur standard, to
fill the emission control gap left from no sulfur reduction, and still
achieve the very significant fleet wide reductions needed to meet the
Tier 3 fleet average. In effect reducing sulfur from 30 ppm to 10 ppm
has such a large impact on the ability of the technology improvements
to achieve Tier 3 emissions levels that absent these sulfur reductions
there is not a suite of technology advancements available to fill the
resulting gap in emissions reductions. As also discussed in Section
IV.A.6, testing of Tier 2 and Tier 3 type vehicles, as well as other
information, shows that sulfur has a very large impact on the
effectiveness of the control technologies expected to be used in Tier 3
vehicles. Without the reduction in sulfur to a 10 ppm average, the
major technology improvements projected under Tier 3 would only result
in a limited portion of the emissions reductions needed to achieve Tier
3 levels. For example, without the reduction in sulfur from a 30 ppm to
10 ppm average, the technology improvements would not come close to
achieving Tier 3 levels. In some cases this may result in the same
effectiveness as the current Tier 2 technology and achieve only
approximately Tier 2 levels of exhaust emissions control.
    As earlier explained, EPA has not identified technology that would
achieve the average Tier 3 emissions standards, across the fleet, with
sulfur at 30 ppm levels, and as a result Tier 3 emissions standards
would not be technically feasible and achievable. This is also the case
for levels in-between 30 and 10 ppm, e.g., 20 ppm. The required
emissions reductions are so large and widespread across the fleet, and
the technology challenges are high enough, especially for heavier
vehicles, that the large increase in emissions that would occur even
from a higher average sulfur level compared to 10 ppm average would
lead to an inability for the technology to widely achieve the Tier 3
fleet wide average emissions standards.
    Further, as also explained in Section IV.A.6, larger vehicles (the
largest LDVs and LDT3s, LDT4s and MDPVs) will have greater difficulty
achieving cold-start NMOG emissions control as a result of today's
emissions standards. (Certifying to a useful life of 150,000 miles
versus the current 120,000 miles will further add to manufacturers'
compliance challenge for large light trucks; see Section IV.A.7.c for
the useful life requirements.) This is based in part on the impact on
NMOG emissions of the larger engine surface-to-volume ratio and
resultant heat conduction from the combustion chamber during warm-up.
There are also tradeoffs between some cold-start NMOG controls and
cold-start NOX control. For example, secondary air injection
and/or leaner fueling strategies improve catalyst light-off for NMOG
after a cold-start but also place OSC components in an oxidation state
that limits potential for NOX reduction and thus often
result in higher cold-start NOX emissions. Some applications
achieve lower NMOG+NOX emissions without the use of
secondary air injection by careful calibration, changes to the catalyst
formulation and balancing of catalyst HC and NOX activity.
The EPA Prototype Silverado and the developmental Ford Explorer
discussed in Section IV.A.6.c are specific examples of this approach.
Thus, as a result of today's emissions standards these larger vehicles,
in addition to needing to reduce NOX emissions to near-zero
levels (as is generally the case for all Tier 3 vehicles, as discussed
below), these trucks may also have additional NMOG reduction challenge.
2. 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. The Tier 3 fuel sulfur standards will 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 vehicles.
    Section IV describes the substantial adverse effect of high
gasoline sulfur levels on the emission-control devices or systems for
vehicles and engines meeting the Tier 3 emission standards. As
discussed in Section IV.A.6, sulfur in gasoline inhibits the emissions
control performance of modern three-way exhaust catalyst systems by
selectively binding with, and in some instances reacting with active
sites and coating materials. The amount of sulfur retained by the
catalyst is primarily a function of its operating temperature, the
active materials and coatings used within the catalyst, the
concentration of sulfur oxides in the incoming exhaust gases, and air-
to-fuel ratio feedback and control by the engine management system. In
addition to its interaction with catalyst materials, sulfur can also
react with the wash-coating itself to form alumina sulfate, which in
turn can block coating pores and reduce gaseous diffusion to active
materials below the coating surface. Sulfur also interferes with the
ability of OSC components to reduce NOX emissions. Water-
gas-shift reactions, which are also important for NOX
reduction over catalysts combining Pd and ceria, can be blocked by
sulfur poisoning and may be responsible for observations of reduced
NOX activity over Pd/ceria catalysts even with exposure to
fairly low levels of sulfur (equivalent to 15 ppm in gasoline).
    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. As discussed in Section IV.A.6, however, it cannot
completely eliminate the effects of sulfur poisoning. In current
vehicles,

desulfurization conditions occur typically at high loads when there is
a degree of commanded enrichment (i.e., fuel enrichment commanded by
the engine management system primarily for protection of engine and/or
exhaust system components). 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 gasoline sulfur levels will bring emission
benefits unachievable by catalyst desulfurization procedures
alone.\483\ For example, if a vehicle operates on gasoline with less
than 10 ppm sulfur, exhaust emissions stabilize over repeat FTP tests
at emissions near those of the first FTP that follows the high speed/
load operation and catalyst desulfurization. Continued operation on
gasoline with 10 ppm average sulfur content or lower is necessary after
catalyst desulfurization in order to achieve emissions reductions with
the current in-use fleet.\484\ As also discussed in Section IV.A.6, the
emission effects study performed by SGS also suggests that negative
effects of exposure to a somewhat higher sulfur level (80 ppm in this
case) are largely reversible for Tier 2 vehicles, and thus, suggests
that reducing fuel sulfur levels nationwide will bring significant
immediate benefits by reducing emissions of the existing fleet.
Finally, to the extent such conditions do not occur today as part of
normal driving for vehicles in the in-use fleet, there is no practical
way to modify such existing vehicles to do so. 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 and is the only effective
means for the in-use fleet.
---------------------------------------------------------------------------

    \483\ The Effects of Ultra-Low Sulfur Gasoline on Emissions from
Tier 2 Vehicles in the In-Use Fleet, EPA-420-R-14-002.
    \484\ See Preamble Section IV.A.6.c and Chapter 1 of the RIA
(Section <IP_ADDRESS>) for more details on this study and its results.
---------------------------------------------------------------------------

    For Tier 3 vehicles, there are several reasons why regular
operation at the high exhaust temperatures and rich air-to-fuel ratios
necessary for catalyst desulfurization is not desirable and may not be
possible. The temperatures necessary to release sulfur oxides are high
enough to lead to thermal degradation of the catalyst over time through
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). Also, the rich
air-to-fuel ratios necessary for sulfur removal can result in increased
PM, NMOG and CO emissions.
    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 when
standards increase in stringency and emissions levels
decrease.485 486 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. As also shown in Section
IV.A.6, there are currently available data from various studies and
testing on Tier 2 vehicles that indicate that emissions performance is
sensitive to sulfur levels in gasoline. Specifically, the MSAT studies
of Tier 2 vehicles showed the emission reduction potential of lower
sulfur fuel on Tier 2 and later technology vehicles over the FTP cycle.
For instance, there was a 48 percent increase in NOX over
the FTP when gasoline sulfur was increased from 6 ppm to 32 ppm.
Further, emissions data from testing conducted by EPA on a
representative subset of vehicles (after clean-out procedures) on 28
ppm and 5 ppm fuel with accumulated mileage, showed Bag 2
NOX emissions were 47 percent lower on the 5 ppm fuel as
compared to 28 ppm fuel. The reductions found in these studies are also
consistent with the MSAT and Umicore studies on Tier 2 vehicles in
terms of the magnitude of NOX and HC reductions when
switching from 28 ppm to 5 ppm fuel. The results of the emission
effects study performed by SGS and included with API's comments on the
Tier 3 proposal are also consistent with the findings of EPA's Tier 2
in-use study, namely that emissions performance is sensitive to fuel
sulfur level. In sum, these studies confirm our view that reducing
sulfur levels in gasoline from current levels to levels in the range of
today's final gasoline sulfur standards will be expected to achieve
significant reductions in emissions of NOX, hydrocarbons,
and other pollutants of interest from the in-use fleet.
---------------------------------------------------------------------------

    \485\ Takei, Y., Kungasa, Y., Okada, M., Tanaka, T. Fujimoto, Y.
(2000). Fuel Property Requirement for Advanced Technology Engines.
SAE Technical Paper 2000-01-2019.
    \486\ Ball, D., Clark, D., Moser, D. (2011). Effects of Fuel
Sulfur on FTP NOX Emissions from a PZEV 4 Cylinder
Application. SAE Technical Paper 2011-01-0300.
---------------------------------------------------------------------------

    The importance of lower sulfur gasoline is also demonstrated by the
fact that vehicles certified to California SULEV typically certify to
higher bins for the federal Tier 2 program. Light-duty vehicles
certified to SULEV under LEV II are more typically certified federally
to Tier 2 Bin 3, Bin 4 or Bin 5. In particular, non-hybrid vehicles
certified to California SULEV are not certified to federal Tier 2 Bin 2
emissions standards even though the numeric limits for NOX
and NMOG are shared between the California LEV II and federal Tier 2
programs for SULEV and Bin 2. Confidential business information shared
by the auto companies indicate that the primary reason is an inability
to demonstrate compliance with SULEV/Bin 2 emission standards after
vehicles have operated in-use on gasoline with greater than 10 ppm
sulfur and with exposure to the higher sulfur gasoline sold nationwide.
While vehicles certified to the SULEV and Tier 2 Bin 2 standards both
demonstrate compliance using certification gasoline with 15-40 ppm
sulfur content, in-use compliance of SULEV vehicles in California
occurs after significant, sustained operation on gasoline with an
average of 10 ppm sulfur and a maximum cap of 20 ppm sulfur while
federally certified vehicles operate on gasoline with an average of 30
ppm sulfur and a maximum cap of 80 ppm sulfur. Although the SULEV and
Tier 2 Bin 2 standards are numerically equivalent, the increased sulfur
exposure of in-use vehicles certified under the federal Tier 2 program
results in a need for a higher emissions compliance margin to take into
account the impact of in-use gasoline sulfur on full useful life
vehicle emissions.
    As further discussed in Section IV.A.6.d, available studies and
testing also confirm that there is significantly increased sensitivity
of exhaust emissions to gasoline sulfur by vehicles with exhaust
emission control technologies that we expect to be used with vehicles
complying with today's Tier 3 emissions studies. Specifically,
available test data from the Ford Motor Company developmental heavy-
light-duty truck and the Umicore Autocat 2009 Chevrolet Malibu PZEV
show more increases in NOX and NMOG+NOX emissions
with increased gasoline sulfur

than was observed for Tier 2 vehicles. Similarly, test data from the
EPA Tier 3 prototype 2012 Chevrolet Silverado heavy-light duty pickup
also showed increased NMOG+NOX emissions and one exceedance
of today's final Bin 30 exhaust emissions standards. In sum, available
test data indicate that increasing gasoline sulfur levels from 10 ppm
to 30 ppm on vehicles meeting Tier 3 standards essentially negated the
entire benefit of the advances in emissions control technology that
were applied to meet Tier 3 developmental goals. Because of the
resulting need to reach near-zero NOX levels to offset NMOG
emissions, any significant degradation in NOX emissions
control over the useful life of the vehicle will likely prevent some if
not most larger vehicles from reaching a combined NMOG+NOX
level low enough to comply with the 30 mg/mi fleet-average standard.
Any degradation in catalyst performance due to gasoline sulfur will
also reduce or eliminate the margin necessary to ensure in-use
compliance with the Tier 3 emissions standards. Thus, the impact of
gasoline sulfur poisoning on exhaust catalyst performance and the
relative stringency of the Tier 3 exhaust emissions 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.B, the average 10 ppm gasoline sulfur
standard is feasible and is the level that appropriately balances costs
with the emission reductions that it provides and enables. Not only
will a 10 ppm sulfur standard enable vehicle manufacturers to certify
their entire product line of vehicles to the Tier 3 fleet average
standards, but reducing gasoline sulfur to 10 ppm will better enable
these vehicles to maintain their emission performance in-use over their
full useful life. Higher sulfur levels would make it impossible for
vehicle manufacturers to meet the Tier 3 standards, and would forego
the very large immediate reductions from the existing fleet. Reducing
the sulfur level below 10 ppm would further reduce vehicle emissions
and allow the Tier 3 vehicle standards to be achieved more easily.
However, we believe that a 10 ppm average standard is sufficient to
allow vehicles to meet the Tier 3 standards. Further, as discussed in
Sections V.B and IX.B there are significant challenges associated with
reducing sulfur below 10 ppm.
3. Section 211(c)(2)(B)
    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 above
and in the RIA (Chapter 1), 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 below in Section VII. The 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 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 emission
standards without the application of the kind of emissions control
technology discussed in this final rule.
4. Section 211(c)(2)(C)
    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
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 and pentane 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. This
action 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.

VI. Technical Amendments and Regulatory Streamlining

    In addition to adopting new Tier 3 vehicle standards and new
gasoline sulfur standards, we are also finalizing a range 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 Tier 3 vehicle and fuel standards, while others
deal with other aspects of EPA's existing fuel and vehicle regulations.
    EPA is also synchronizing several different reporting deadlines
under various regulations affecting transportation and motor vehicle
fuels and fuel additives. This action will reduce regulatory burdens by
aligning reporting deadlines across several programs and lays the
foundation for the overall goal of combining various fuels reports
together into a single, simplified electronic format in the near
future.

A. Fuel Program Amendments

    The following sections discuss the changes being finalized today to
the fuels regulations in 40 CFR parts 79 and 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
needed clarification and/or streamlining; still others are to provide
additional flexibility.
    With regard to regulatory streamlining, the majority of these items
involve providing additional clarity, removing or updating outdated
provisions, and decreasing the frequency and/or volume of reporting
burden where data are either no longer needed or are redundant in light
of other EPA fuels programs. In general, we believe that these changes
are straightforward and will reduce burden on industry with no expected
environmental impact.
    We are also finalizing regulations to adopt a performance-based
measurement systems approach to fuel parameter testing as discussed in
Section VI.A.2, to expand the downstream butane blending provisions to
allow for pentane blending as discussed in Section VI.A.3, and to
accept Top Tier test data under the gasoline deposit control program as
discussed in Section VI.A.4. We may undertake additional regulatory
streamlining in a future action following additional stakeholder
interactions, as discussed in Section VI.A.5.
    Below is a table listing the provisions that we are amending in
today's action. We have provided additional explanation for those
amendments that warrant additional explanation in the following
sections.

 Table VI-1--Summary of Regulatory Streamlining and Technical Amendments
------------------------------------------------------------------------
              Section                            Description
------------------------------------------------------------------------
Varied............................  Various sections amended to update
                                     references to test methods (see
                                     Section VI.A.1.a.iii).
79.5..............................  Revised periodic reporting
                                     requirements.
80.2..............................  Revised and added definitions.
80.8..............................  Amended to update sampling test
                                     methods, and to state to which
                                     fuels Sec.   80.8 applies.
80.46.............................  Revised measurement of RFG fuel
                                     parameters.
80.47.............................  Added Performance-Based Test Method
                                     Approach.
80.65.............................  Amended to reduce complex model test
                                     parameters and reporting and to
                                     accommodate RVP adjustment when
                                     blender grade pentane is blended
                                     into gasoline downstream of the
                                     refinery.
80.65(f)(5).......................  Added to allow for designation of an
                                     alternative lab.
80.66(f)..........................  Amended to delete references to
                                     appendices that no longer exist.
80.74.............................  Amended to reflect the recordkeeping
                                     requirements for entities in the
                                     blender grade pentane distribution
                                     system.
80.75.............................  Revised RFG reporting requirements.
                                     Added reporting requirements for
                                     produces and importers of blender
                                     grade pentane.
80.77.............................  Amended to reflect the product
                                     transfer document requirements for
                                     entities in the distribution system
                                     for blender grade pentane.
80.80.............................  Amended to reflect the potential
                                     penalties requirements for entities
                                     in the distribution system for
                                     blender grade pentane.
80.82.............................  Amended to apply butane blending
                                     provisions to entire part 80 and to
                                     revise RVP test method.
80.85.............................  Added the requirements for
                                     downstream pentane blending.
80.86.............................  Added the requirements for producers
                                     and importers of blender grade
                                     pentane.
80.87.............................  Added the controls and prohibitions
                                     for entities in the blender grade
                                     pentane distribution system.
80.101............................  Revised measurement of conventional
                                     gasoline fuel parameters.
80.105............................  Amended to require identification of
                                     test methods used in refiner
                                     reports, and to add reporting
                                     requirements for butane blenders.
80.161(b)(1)(ii)(A)(2)............  Amended to specify the requirements
                                     for certification of an additive
                                     under the new alternative gasoline
                                     deposit control certification
                                     option.
80.161(b)(1)(ii)(A)(3)............  Added to specify the requirements
                                     for certification of an additive
                                     under all gasoline deposit control
                                     options other than the alternative
                                     certification option.
80.161(b)(2)......................  Amended to address the submission of
                                     gasoline deposit control additive
                                     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 will be
                                     required under the alternative
                                     gasoline deposit control
                                     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 gasoline deposit
                                     control 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 deposit
                                     control certification option.
80.163(a)(1)(iii).................  Amended to specify that gasoline
                                     deposit control additives may be
                                     certified under the new alternative
                                     certification option.
80.164(a).........................  Amended to reference the test fuel
                                     requirements under the alternative
                                     gasoline deposit control
                                     certification option.
80.165............................  Amended to accommodate the
                                     alternative deposit control test
                                     procedures and standards under the
                                     alternative gasoline deposit
                                     control certification option.
80.167(a).........................  Amended to specify how confirmatory
                                     testing will be conducted for
                                     additives certified under the
                                     alternative gasoline deposit
                                     control certification option.
80.176............................  Added to specify the certification
                                     test procedures and standards under
                                     the alternative gasoline deposit
                                     control certification option.
80.177............................  Added to specify the certification
                                     test fuels under the alternative
                                     gasoline deposit control
                                     certification option.
80.178............................  Added to incorporate standards and
                                     test methods by reference.
80.330............................  Revised sampling and testing
                                     requirements.
80.340............................  Amended to add standards for
                                     gasoline produced by blending
                                     pentane into previously certified
                                     gasoline.

80.370............................  Amended to require identification of
                                     test method used and revises
                                     reporting requirements.
80.511............................  Revised per-gallon and marker
                                     requirements.
80.572............................  Revised labeling requirements.
                                     Amended to remove the requirement
                                     for 15 ppm highway diesel fuel pump
                                     labels beginning November 30, 2014,
                                     and to amend the title to reflect
                                     that the section includes labeling
                                     requirements for dispensers of
                                     motor vehicle diesel fuel.
80.573............................  Revised labeling requirements.
80.574............................  Revised labeling requirements.
80.580............................  Incorporated test methods by
                                     reference.
80.584(b)(3)(i)...................  Amended to correct typographical
                                     error (``notc'' to ``not'').
80.585............................  Revised test method approval
                                     process.
80.604............................  Revised 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
                                     Sec.   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 Sec.
                                     80.1238(b).
80.1238...........................  Revised 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 Sec.   80.65(i) when
                                     producing RBOB or RFG and Sec.
                                     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...........................  Revised 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...........................  Revised reporting requirements for
                                     gasoline benzene program.
80.1407...........................  Amended to reflect that pentane
                                     blenders incur a renewable volume
                                     obligation (RVO) for the blender
                                     grade pentane they add to
                                     previously certified gasoline
                                     (PCG).
80.1451...........................  Revised RFS reporting requirements.
80.1640(d)........................  Added to allow refiners who blend
                                     only blender-grade pentane into PCG
                                     to meet the sampling and testing
                                     requirements for sulfur by using
                                     sulfur test results pursuant to
                                     Sec.   80.85.
------------------------------------------------------------------------

1. Fuels Program Regulatory Streamlining
a. Amendments Related to Reduction of Testing and Reporting of Complex
Model Gasoline Parameters
    In Sec. Sec.  80.65 and 80.75, we are streamlining and reducing the
reformulated gasoline (RFG) and conventional gasoline (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 batch must
be tested for every parameter listed in Sec.  80.65. No monthly
compositing of batch samples is allowed for any parameter. For CG,
monthly compositing and batch reporting based on those monthly
composites is allowed for all parameters except sulfur and benzene.
With the phasing out of complex model standards \487\, 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 volatile organic compound (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 (and thus measure all complex model
parameters) until 2015 for CG MSAT1 compliance.\488\
---------------------------------------------------------------------------

    \487\ Per Sec.  80.41(e) and (f), and Sec.  80.101(c),
applicable NOX and toxics emissions requirements are
superseded by the Tier 2 gasoline sulfur standards and MSAT2 benzene
standards, respectively.
    \488\ 61 FR 17230 (March 29, 2001).
---------------------------------------------------------------------------

    Currently, there are 17 complex model parameters on the RFG/anti-
dumping batch report. We are reducing testing and reporting
requirements for some of these parameters for RFG, CG or both. For both
RFG and CG, we are eliminating testing and reporting of American
Petroleum Institute (API) gravity. In addition, we are finalizing that
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.
Commenters agreed with the elimination of testing of API gravity and
oxygenates.
    For winter RFG, we are eliminating the requirement to test and
report aromatics, distillations and olefins on an every batch basis and
instead will allow testing and reporting of monthly composites.
Commenters from the refining industry strongly suggested that we
eliminate testing of these parameters altogether, since they are not
needed, and their elimination would further reduce the burden on
regulated parties. While we agree that a reduction in burden would
occur if refiners were not required to test, even on a monthly
composite basis, for these parameters, the many interconnected aspects
of the RFG program make any seemingly innocuous change potentially
fraught with unintended consequences. Thus, we are deferring the
consideration of any action to completely eliminate the testing of
these parameters to any future

fuel program restructuring, as discussed in Section VI.A.5.
    Sulfur and benzene will continue to be tested and reported on an
every batch basis as these values are necessary for the Tier 2 and Tier
3 gasoline sulfur and MSAT2 benzene programs. All summer complex model
parameters will still be required to be tested and reported on an every
batch basis because of the summer VOC requirement for RFG. For CG, 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). In the proposal, we stated ``. . . values for
aromatics, olefins, and distillation terms may continue to be
determined from monthly composites.'' Some commenters thought the term
``may'' in that sentence meant that reporting on those parameters at
all is optional. That is an incorrect interpretation. In this final
rule, we are finalizing requirements for use of either monthly
composites or batch testing. The parameters must still be measured and
reported. Commenters in the refining industry do not think these
parameters need to be measured at all for parties subject to the MSAT2
benzene standard, as compliance with that standard is not dependent on
aromatic, olefin, or distillation values. As mentioned earlier, there
are several areas of the RFG and/or anti-dumping programs where testing
and reporting burden could likely be reduced; however, we have not
fully evaluated the implications of changing the current requirements,
and thus we are leaving consideration of such changes to the broader
program restructuring discussed in Section VI.A.5. Nonetheless, the
changes that are finalized today will substantially reduce the testing
and reporting burden on regulated parties.
b. Amendments Related to Reporting Dates
    EPA is amending 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. Currently under 40 CFR parts 79 and 80,
there are ten separate cyclical reporting dates each year (eleven in a
leap year). Streamlining reporting deadlines will allow EPA to develop
a single, user-friendly, electronic form that will collect all required
data, maximizing the capability of electronic reporting to provide
reuse of data and avoid duplicate data submission. EPA's goal is to
simplify reporting and reduce the number of hours parties spend
preparing and submitting reports while simultaneously improving data
received from stakeholders. 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.
    We are amending these deadlines so that all affected programs use
the same four reporting deadlines. Programs that will be affected by
this change 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);
     the Renewable Fuel Standard program (40 CFR part 80
subparts K and M); and
     the Tier 3 program being finalized today (40 CFR part 80
subpart O).
    We are finalizing that reporting deadlines will be standardized as
follows: June 1, for all reports covering quarter 1 of the compliance
year (January through March); September 1, for quarter 2 (April through
June); December 1, for quarter 3 (July through September); and March 31
for quarter 4 (October through December). End-of-year compliance
reports will also be due on March 31. These changes will either delay
or maintain current deadlines for nearly all required reports.
Deadlines for all other annual reports will either be maintained if
they matched the new quarterly deadline, or extended to match the new
quarterly deadline. It should be noted that even with the changes
finalized today, respondents will still have the option to report
earlier than any given deadline. Commenters generally agreed with the
proposed date changes. Some commenters in the refining industry
suggested eliminating all quarterly reporting for RFG if winter
aromatics, olefins and distillation are no longer required to be
reported as they suggested. These values are normally reported in the
1st and 4th quarters. As one commenter stated, ``In addition, there is
no point in splitting up summer RFG/RBOB reporting between the 2nd and
3rd quarters.'' As noted above, winter aromatics, olefins and
distillation are still required to be reported, albeit on a monthly
composite basis. Thus, the need for quarterly reporting remains.
However, we expect that the need for quarterly reports will be
evaluated as part of the broader program restructuring discussed in
Section VI.A.5.
    EPA proposed not to include ``Attest Engagements'' (currently due
May 31 of the following year) or reporting related to specific events
under the Fuels Program, such as trading Renewable Identification
Numbers (RINs) in EPA's Moderated Transaction System (EMTS), in the
reporting revisions described above. Rather, all reporting deadlines
for Attest Engagements and reporting specific events will remain the
same. Some commenters communicated that if the annual and fourth
quarter reporting deadlines were to be extended to March 31 of each
year, then the attest engagement date should also be shifted one month
from May 31 to June 30 to allow sufficient time for the significant
data-gathering and communications required to complete those
engagements. EPA is not changing the compliance period associated with
the new extended reporting date, but rather, is simply allowing
additional time for data review, preparation and reporting. EPA does
not believe that extending the attest engagement date is necessary
because companies have the flexibility to use the extra reporting time
to begin preparation for the attest engagement if they prefer. As
stated previously, the extension to reporting deadlines does not
preclude stakeholders from reporting before the deadline. EPA is not
extending the date for attest engagements from May 31 to June 30. That
said, EPA is streamlining reporting dates to aid in our development of
a single electronic reporting format and is updating the due date for
attest engagements found in part 80 from May 31 to June 1. This change
will not affect compliance or increase burden of reporting entities.
Rather, the purpose of streamlining various reporting deadlines is to
ease reporting burden and help aid EPA in the development and
implementation of a single electronic reporting format.
    We are also correcting a typographical error in 40 CFR
80.1451(f)(2) and clarifying that reports are to be signed by the
``responsible corporate officer.'' One commenter suggested that EPA
revise the instances when a ``responsible corporate officer'' signature
is required, and when perhaps someone else in the company can sign.

The example given in the comment was that a phone number change should
not require a ``responsible corporate officer'' signature, as getting
this level of signature can be burdensome, and the company can have
appropriate delegations in place when someone other than the
``responsible corporate officer'' is the signatory. While we understand
the concern expressed, EPA does not believe a regulatory action is
necessary to address this concern but rather believes this issue is
best addressed via administrative procedures. EPA plans to further
evaluate this specific concern and similar ``responsible corporate
officer'' issues and address the concerns in the future, outside of the
regulatory framework.
    Finally, we are addressing a typographical error in the regulatory
text. Specifically, incorrect references under 40 CFR 79.5(a)(2) and
79.5(b) are being addressed as well as clarification being added.
c. Amendments To Update Fuel Parameter 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. As stated in the proposal,
a number of relevant regulatory provisions had references to test
methods that have been revised and updated. Several comments were
received indicating that since the time of the proposal, some of the
proposed updates have been further revised and updated and the desire
was expressed for the regulated community to have the opportunity to
use the most current version of each of these test methods. Today, we
are updating 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, in gasoline
and diesel fuel at the 500 ppm sulfur standard. (Sec. Sec.
80.46(a)(1), 80.580(b)(2).) ASTM test methods D5453, D6920, D3120 and
D7039 are currently alternative test methods for measuring sulfur in
gasoline. (Sec. Sec.  80.46(a)(3)(i), 80.46(a)(3)(ii),
80.46(a)(3)(iii), 80.46(a)(3)(iv).) ASTM test method D5453 is also an
alternative test method for measuring sulfur in diesel fuel at the 500
ppm sulfur standard, as well as ASTM test method D4294. (Sec.
80.580(c)(2).) ASTM test method D6667 is currently the designated test
method for measuring sulfur in butane. (Sec.  80.46 (a)(2).) ASTM test
methods D4468 and D3246 are currently alternative test methods for
measuring the sulfur content in butane. (Sec. Sec.  80.46(a)(4)(i),
80.46(a)(4)(ii).) ASTM D1319 is currently the designated test method
for measuring olefins in gasoline and aromatics in diesel fuel and is
also allowed as an alternative test method for measuring aromatics in
gasoline. (Sec. Sec.  80.46(b), 80.2(z), and 80.46(f)(3),
respectively.) ASTM D6550 is currently an alternative test method for
measuring olefins in gasoline. (Sec.  80.46(b)(2)(i).) ASTM test method
D5599 is currently the designated test method for measuring oxygenates
in gasoline. (Sec.  80.46(g)(1).) ASTM test method D4815 is currently
an alternative test method for measuring oxygenates in gasoline. (Sec.
80.46(g)(2).) ASTM test method D5769 is currently the designated test
method for measuring aromatics in gasoline. (Sec.  80.46(f)(1).) ASTM
test method D3606 is currently the designated test method for measuring
benzene in gasoline. (Sec.  80.46(e).) ASTM test method D86 is
currently the designated test method for measuring the distillation of
gasoline. (Sec.  80.46(d).) ASTM test method D5191 is currently the
designated test method for measuring the RVP of gasoline. (Sec.
80.46(c).) ASTM test method D976 is currently the designated test
method for measuring the Cetane Index of diesel fuel. (Sec.  80.2(w).)
ASTM standard practice D4057 is currently the manual sampling standard
practice for petroleum and petroleum products. (Sec.  80.8(a).) ASTM
standard practice D4177 is currently the automatic sampling standard
practice for petroleum and petroleum products. (Sec.  80.8(b).) ASTM
standard practice D5842 is currently the RVP sampling standard practice
for fuels. (Sec.  80.8(c).) ASTM standard practice D5854 is currently
the composite sampling standard practice for petroleum and petroleum
products. (Sec.  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 updating 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 revisions to these
test methods will 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 so that improvements in the test method's procedures would
ensure better operation for the user of the test method. Thus, EPA is
today updating 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; (3) ASTM D4294-10, alternative test method for sulfur in
diesel fuel at the 500 ppm sulfur standard; (4) ASTM D5453-12,
alternative test method for sulfur in gasoline and diesel fuel at the
500 ppm sulfur standard; (5) ASTM D6667-10, designated test method for
sulfur in butane; (6) ASTM D4468-85(Reapproved 2011), alternative test
method for sulfur in butane; (7) ASTM D3246-11, alternative test method
for sulfur in butane; (8) ASTM D1319-13, 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; (9)
ASTM D6550-10, alternative test method for measuring olefin content in
gasoline; (10) ASTM D4815-13, alternative test method for measuring
oxygenate content in gasoline; (11) ASTM D5599-00 (2010), the
designated test method for measuring oxygen content in gasoline; (12)
ASTM D5769-10, the designated test method for measuring aromatics in
gasoline; (13) ASTM D3606-10, the designated test method for measuring
benzene in gasoline; (14) ASTM D86-12, the designated test method for
measuring distillation properties of gasoline; (15) ASTM D5191-12, the
designated test method for measuring the RVP of gasoline; (16) ASTM
D976-06(2011), the designated test method for measuring the Cetane
Index of diesel fuel; and (17) ASTM D7039-13, alternative test method
for measuring sulfur in gasoline.

 Table VI-2--Designated & Alternative ASTM International Analytical Test
       Methods Under RFG, CG & Diesel Motor Vehicle Fuel Programs
------------------------------------------------------------------------
        Fuel parameter                ASTM Analytical test method
------------------------------------------------------------------------
Sulfur (designated test        ASTM D2622-10, entitled ``Standard Test
 method for gasoline).          Method for Sulfur in Petroleum Products
                                by Wavelength Dispersive X-Ray
                                Fluorescence Spectrometry''.
Sulfur (designated test        ASTM D2622-10, entitled ``Standard Test
 method for 500 ppm sulfur      Method for Sulfur in Petroleum Products
 diesel).                       by Wavelength Dispersive X-Ray
                                Fluorescence Spectrometry''.
Sulfur (alternative test       ASTM D3120-08, entitled, ``Standard Test
 method for gasoline).          Method for Trace Quantities of Sulfur in
                                Light Petroleum Hydrocarbons by
                                Oxidative Microcoulometry''.
Sulfur (alternative test       ASTM D4294-10, entitled, ``Standard Test
 method for 500 ppm sulfur      Method for Sulfur in Petroleum Products
 diesel).                       by Energy Dispersive X-ray Fluorescence
                                Spectrometry''.
Sulfur (alternative test       ASTM D5453-12, entitled, ``Standard Test
 method for gasoline).          Method for Determination of Total Sulfur
                                in Light Hydrocarbons, Spark Ignition
                                Engine Fuel, Diesel Engine Fuel, and
                                Engine Oil by Ultraviolet
                                Fluorescence''.
Sulfur (alternative test       ASTM D5453-12, entitled, ``Standard Test
 method for 500 ppm sulfur      Method for Determination of Total Sulfur
 diesel).                       in Light Hydrocarbons, Spark Ignition
                                Engine Fuel, Diesel Engine Fuel, and
                                Engine Oil by Ultraviolet
                                Fluorescence''.
Sulfur (designated test        ASTM D6667-10, entitled, ``Standard Test
 method for butane).            Method for Determination of Total
                                Volatile Sulfur in Gaseous Hydrocarbons
                                and Liquefied Petroleum Gases by
                                Ultraviolet Fluorescence''.
Sulfur (alternative test       ASTM D4468-85(Reapproved 2011), entitled,
 method for butane).            ``Standard Test Method for Total Sulfur
                                in Gaseous Fuels by Hydrogenolysis and
                                Rateometric Colorimetry''.
Sulfur (alternative test       ASTM D3246-11, entitled, ``Standard Test
 method for butane).            Method for Sulfur in Petroleum Gas by
                                Oxidative Microcoulometry''.
Olefins (designated test       ASTM D1319-13, entitled ``Standard Test
 method for gasoline).          Method for Hydrocarbon Types in Liquid
                                Petroleum Products by Fluorescent
                                Indicator Adsorption''.
Aromatics (alternative test    ASTM D1319-13, entitled ``Standard Test
 method for gasoline and        Method for Hydrocarbon Types in Liquid
 designated test method for     Petroleum Products by Fluorescent
 diesel).                       Indicator Absorption,'' for diesel fuel,
                                this method is the designated test
                                method; for gasoline, this method is an
                                alternative test method and if used as
                                an alternative method, its results must
                                be correlated to ASTM D5769.
Olefins (alternative test      ASTM D6550-10, entitled, ``Standard Test
 method for gasoline).          Method for the Determination of Olefin
                                Content of Gasolines by Supercritical-
                                Fluid Chromatography''.
Oxygen content (designated     ASTM D5599-00 (2010), entitled,
 test method for gasoline).     ``Standard Test Method for Determination
                                of Oxygenates in Gasoline by Gas
                                Chromatography and Oxygen Selective
                                Flame Ionization Detection''.
Oxygen content (alternative    ASTM D4815-13, entitled ``Standard Test
 test method for gasoline).     Method for Determination of MTBE, ETBE,
                                TAME, DIPE, tertiary-Amyl Alcohol and C1
                                to C4 Alcohols in Gasoline by Gas
                                Chromatography''.
Aromatics (designated test     ASTM D5769-10, entitled, ``Standard Test
 method for gasoline).          Method for Determination of Benzene,
                                Toluene, and Total Aromatics in Finished
                                Gasolines by Gas Chromatography/Mass
                                Spectrometry''.
Benzene (designated test       ASTM D3606-10, entitled, ``Standard Test
 method for gasoline).          Method for Determination of Benzene and
                                Toluene in Finished Motor and Aviation
                                Gasoline by Gas Chromatography''.
Distillation (designated test  ASTM D86-12, entitled, ``Standard Test
 method for gasoline).          Method for Distillation of Petroleum
                                Products at Atmospheric Pressure''.
Reid Vapor Pressure            ASTM D5191-12, entitled, ``Standard Test
 (designated test method for    Method for Vapor Pressure of Petroleum
 gasoline).                     Products (Mini-Method)''.
Cetane Index (designated test  ASTM D976-06(2011), entitled, ``Standard
 method for diesel).            Test Method for Calculated Cetane Index
                                of Distillate Fuels''.
Sulfur (alternative test       ASTM D7039-13, entitled, ``Standard Test
 method for gasoline).          Method for Sulfur in Gasoline, Diesel
                                Fuel, Jet Fuel, Kerosine, Biodiesel,
                                Biodiesel Blends, and Gasoline Ethanol
                                Blends by Monochromatic Wavelength
                                Dispersive X-ray Fluorescence
                                Spectrometry''.
------------------------------------------------------------------------

d. Amendments Related to Downstream Blending and Upstream Refiner/
Importer Compliance Determination
    Today's rule also clarifies the list of products that are not to be
included in a refinery's or importer's compliance determination under
Sec.  80.1240. Refiners and importers are currently required under
Sec.  80.1235(b)(2) to exclude oxygenate added to finished gasoline,
RBOB or CBOB downstream of either the refinery that produced the
gasoline or the import facility where the gasoline was imported. This
conflicts with EPA's intended approach in Sec.  80.1238(b), which
allows refiners and importers to include oxygenate blended downstream
of a refinery or import facility in their annual average benzene
calculation, provided the refiner or importer meets certain
requirements. We are finalizing changes that will allow refiners and
importers to include oxygenate blended downstream of their facility and
that will make these related sections consistent. EPA received
significant support for this action from commenters.
e. Amendments Regarding Previously Certified Gasoline
    For compliance with the MSAT2 regulations, for blendstock that is
blended into previously certified gasoline (PCG), we are providing
flexibility for refiners and importers by providing an alternative
allowing them to directly sample and test each batch of blendstock, and
treat the blendstock as a produced batch. We are adding Sec.
80.1347(a)(6) to reflect this alternative. This practice is already
allowed under the Tier 2 sulfur program (at Sec.  80.340(a)(2)).
Refiners and importers are currently required to determine the benzene
content of the PCG before the addition of blendstock, determine the
benzene content of the combined blend of PCG and blendstock, and
calculate the properties of the blendstock by

treating the PCG as a negative volume batch and treating the blended
product as a positive batch. Due to variability in the benzene test
method, the PCG approach can sometimes result in calculated blendstock
benzene concentrations that are negative, which is physically
impossible. We are amending the regulations at Sec.  80.1235(a)(6) (and
adding Sec.  80.1347(a)(6), as mentioned) to allow refiners and
importers who blend blendstock into PCG to directly test the blendstock
for benzene. We expect that this method will improve accuracy and
ensure a positive benzene test result. Also, today's action will
clarify that regardless of the approach used, a negative sulfur or
benzene result cannot be reported; rather, any negative result must be
rounded to zero. Similarly, no negative annual average result can be
reported. We are also amending the regulations at Sec.  80.1235(a)(5)
to clarify that refiners and importers may use either approach for
blendstocks that are blended into either conventional gasoline or
reformulated gasoline.
    Lastly, we are allowing importers who import gasoline into the
United States by truck to use the sampling and testing requirements in
subpart E for truck importers as an alternative to the sampling and
testing requirements in subpart L. EPA provided these alternative
requirements in subpart E to eliminate the need to test every truckload
of imported conventional gasoline for all complex model parameters,
including benzene.\489\ Since subpart L also requires importers to test
every truckload of imported gasoline for benzene, EPA believes it is
appropriate to allow truck importers of gasoline to use the sampling
and testing requirements in subpart E as an alternative. We are
amending the regulations to provide this alternative by adding a new
Sec.  80.1349. EPA received significant support for this action from
commenters.
---------------------------------------------------------------------------

    \489\ 70 FR 74561 (December 15, 2005).
---------------------------------------------------------------------------

f. Amendments Related to Designation of an Alternative Lab
    Refiners have indicated to EPA that significant problems are
created when a facility's designated lab is nonoperational and testing
cannot be performed at the lab during that time period. We are thus
finalizing (at Sec.  80.65(f)(5)) that a facility will have the ability
to designate a back-up or alternative lab for testing during such
times. In no case could this alternative lab be used to select the best
test result, rather it may only be used on those occasions where
operational necessity causes a need for it (e.g., the normal lab is
closed, the apparatus for certain test methods are down, or independent
lab personnel are not available). EPA received significant support for
this action from commenters.
g. Amendments Related to De Minimis Reporting Changes
    We proposed that parties who submit batch reports would not be
required to correct inconsequential errors in reporting batch volumes
under certain conditions, the primary condition being that the
discrepancy met the definition of ``de minimis'', which as proposed,
was an amount no greater than the smaller of 500 gallons or one (1)
percent of the true batch volume. Under the proposal, regulated parties
would no longer be required to provide a complete resubmission of a
compliance report when a minor discrepancy of a few barrels was
uncovered. We proposed that this new provision would apply to reporting
for RFG, anti-dumping, gasoline and diesel sulfur, and MSAT2. We
proposed that it would also apply to the RFS renewable volume
obligation (RVO), but would only apply to the volume of fuels produced
or exported that result in a RVO for obligated parties.
    We received comments on this proposed change, many of which
generally agreed with our concept. However, commenters who agreed with
the concept stated that they believe the proposed levels are so small
that they are of little practical value, and that a de minimis volume
of 500 gallons will almost always be less than 1 percent of the true
batch volume. In examples provided, commenters stated that pipeline
batch volumes are approximately 25,000 barrels, and that a 500 gallon
difference equates to a 0.05% difference; 500 gallons on a 250,000
gallon refinery production batch equates to 0.005%. Thus, according to
the commenters, the 500 gallon limit--which is clearly less than 1% in
the two examples--would fail to provide the intended relief and would
not prevent a party from having to make inconsequential volume
corrections. These commenters suggested that a de minimis threshold
value of 0.5 percent be applied regardless of batch size. Several
commenters also recommended that we delete the proposed regulatory text
at Sec.  80.10 (c) and (d), as the application of a de minimis
threshold implies that small volume errors in batch reporting are truly
inconsequential and do not have an impact on compliance with fuel
standards, so no separate demonstration of material impact should be
required.
    One commenter stated that it opposes the de minimis provision with
respect to the RFS program. According to the commenter, EPA did not
provide sufficient legal or factual basis for the proposal in order for
the public to provide meaningful comment. In addition, according to the
commenter, the proposed de minimis change, if finalized, would allow
obligated parties to under report their volume, thereby reducing their
RVO. The commenter also stated that EPA cannot finalize the proposed
provision based on other comments it receives because, according to the
commenter, EPA would still not be satisfying notice and comment
requirements.
    We have decided not to finalize the proposed de minimis provisions
at this time. One of the primary motivations for proposing the de
minimis provision was to avoid the need for inconsequential corrections
to production volumes that would have no impact on compliance with
standards that rely on production volumes (e.g., average standards and
RFS). Late changes to production volumes for whatever reason can
necessitate simultaneous changes to compliance calculations that, if de
minimis, would have no meaningful impact on compliance. However, as
comments highlight, it is has proven difficult to come up with an
acceptable de minimis threshold that can apply across all potential
situations. Furthermore, the proposed provision focused only on volume
corrections, but in reality our experience suggests that corrections
often take place for other purposes such as data entry, coding,
formating or other typographical errors--not only minor corrections to
reported volume. We believe that adjusting reports for inconsistencies
will become less burdensome, as EPA intends to transition all reporting
to electronic reporting in the future. In addition, EPA received input
from the regulated community about a de minimis provision specifically
as it related to the RFS program. As discussed below in Section
VI.A.1.h, we are finalizing a one-month delay in the RFS reporting
deadline, which we believe will provide obligated parties with more
time to review and correct their records and reports, and help to
minimize the need for late corrections. We will revisit the need for a
de minimis threshold in the future if these changes prove insufficient.
h. Amendments Related to RFS2 Annual Report Date
    EPA is finalizing the proposed changes to the RFS2 annual report
date from the last day of February to March

31. EPA intended the change would 1) alleviate staffing problems for
regulated entities because the regulatory requirements are often
handled by the same personnel and 2) provide relief from the urgent
need to obtain RINs when small discrepancies in gasoline production or
import volumes are realized. Another reason for proposing a change to
the reporting deadline from the last day in February to March 31 was
described in Section VI.A.1.b. (Amendments Related to Reporting Dates).
Streamlining reporting dates will allow EPA to develop a single, user-
friendly, electronic form that will collect all required data,
maximizing the capability of electronic reporting to provide reuse of
data and avoid duplicate data submission. Commenters generally agreed
with the proposed date change. One commenter pointed out that the
staffing issue described would not be addressed by the change date
because EPA is changing both RFG and Anti-dumping compliance deadlines
to March 31--same as the RFS2 annual reporting. EPA understands the
point made but nonetheless, believes that delaying the RFS reporting
date will give reporting entities additional time and flexibility to
review data and will have no impact on emissions, air quality, or
compliance with the standard. EPA also believes that the overarching
goal of streamlining reporting dates to develop a single electronic
reporting format, in and of itself, will provide general relief to
regulated parties. Comments received generally support this view.
    EPA requested comment on whether or not the same date extension
from the last day of February to March 31 should apply to those
transferring RINs in EMTS for satisfying RVOs under the previous
compliance year. Some commenters wanted to have RIN trading through the
new deadline (March 31), while others wanted trading to end on the last
day of February to allow time for data cleanup which could improve
compliance and reporting accuracy. One commenter also pointed out that
changing the RIN trading deadline might have an unforeseen impact on
the RIN market and suggested EPA carefully consider this possibility
before making a decision on extending the RIN trading date. EPA agrees
that providing enough time for data cleanup is important to ensure
reporting accuracy and meet compliance goals. In addition, EPA
understands stakeholders' concerns about how such a change in RIN
trading could conceivably impact the RIN trading market dynamics. As
such, RIN transfers in EMTS for satisfying RVOs under the previous
compliance year will continue to end on the last day of February.
i. Amendments to the Highway Diesel Pump Label Requirements
    We are removing the requirement for diesel fuel pump labels for 15